(SPPC) 2019 Electric General Rate Case Volume 7
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
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1 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Sierra Pacific Power Company d/b/a NV Energy
3 2019 General Rate Case Docket No. 19-06___ 4 PREPARED DIRECT TESTIMONY OF 5 John S. Gremp 6 Revenue Requirement 7
8 I. INTRODUCTION 9 1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS ADDRESS,
10 AND THE PARTY FOR WHOM YOU ARE FILING TESTIMONY.
11 A. My name is John S. Gremp. I am the Manager, Transmission Project Delivery for
12 NV Energy, Inc. (“NV Energy”), Nevada Power Company d/b/a NV Energy 13 (“Nevada Power”), and Sierra Pacific Power Company d/b/a NV Energy (“Sierra”, 14 and together with Nevada Power, the “Companies”). I work primarily out of d/b/a NV Energy Nevada Power Company Company Power Nevada 15 Sierra’s corporate office, which is located at 6100 Neil Road in Reno, Nevada. I
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 am filing testimony in this proceeding on behalf of Sierra. 17 18 2. Q. PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND AND 19 EXPERIENCE. 20 A. I have a Bachelor of Science degree from the College of Business Administration 21 Fordham University Bronx, New York. I began my employment in the energy 22 industry as a financial planning and analysis intern with Nevada Power in 2006. I 23 have substantial experience in project management, financial controls and project 24 controls. In 2006, I was assigned to New Generation as a project controls engineer 25 during the development of the Ely Energy Center and was assigned to the project 26 management team for the Clark Peaker Project and the Harry Allen Combined 27
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1 Cycle Project. I transferred to Generation department in 2011 as a Senior 2 Consultant. I was promoted to Project Controls Supervisor in 2014. I transferred to 3 Sierra and the Transmission Department in 2014 as a project manager, then was 4 promoted to Manager of Project Delivery in 2017. I have attached as Exhibit 5 Gremp-Direct-1 a statement of qualifications that further details my background 6 and professional experience. 7 8 3. Q. MR. GREMP, HAVE YOU PREVIOUSLY SUBMITTED TESTIMONY
9 WITH THE PUBLIC UTILITIES COMMISSION OF NEVADA
10 (“COMMISSION”)?
11 A. No, I have not.
12 13 4. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS 14 PROCEEDING? d/b/a NV Energy Nevada Power Company Company Power Nevada 15 A. I support the prudence of several categories of investment in facilities that are
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 included in the calculation of Sierra’s revenue requirement. These assets are broken 17 down into two categories: compliance and transmission technology. Each of the 18 investments made by the Company in these two categories are used and useful and 19 providing benefit to customers. 20 21 5. Q. HOW IS YOUR TESTIMONY ORGANIZED? 22 A. My testimony is organized into the following sections: 23 24 Section II. Compliance Projects: In this section, I discuss Sierra’s investments in 25 facilities and equipment required to meet North American Electric Reliability 26 Corporation (“NERC”) standards. Specifically, Sierra is required by NERC to 27
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1 invest in a more robust cyber security and a physical hardening of key Bulk Electric 2 Systems (“BES”) assets.1 I describe one compliance project included in this general 3 rate review, why it was necessary, previous discussion of the project with the 4 Commission, the total cost of the project, and other information to demonstrate that 5 Sierra’s investment on behalf of customers was prudent. 6 7 Section III. Transmission Technology: In this section, I discuss Sierra’s 8 investment in two Electric System Control Center (“ESCC”) technology projects
9 since the end of the certification period in Sierra’s last general rate case, June 1,
10 2016 through the end of the current certification period on May 31, 2019. I describe
11 each ESCC technology project, why it was necessary, whether it was previously
12 presented to the Commission, the total cost of the project, and other information to 13 demonstrate that Sierra’s investment on behalf of customers was prudent. 14 d/b/a NV Energy Nevada Power Company Company Power Nevada 15 6. Q. ARE YOU SPONSORING ANY EXHIBITS TO YOUR PREPARED
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 DIRECT TESTIMONY? 17 A. Yes. I am sponsoring one exhibit:
18 • Exhibit Gremp-Direct-1 Statement of Qualifications 19 20 7. Q. WHY ARE ONLY MAJOR PROJECTS SPECIFICALLY DISCUSSED IN 21 YOUR TESTIMONY? 22 A. Testimony-style descriptions of each and every project completed by the 23 transmission project team since June 1, 2016 would take hundreds of pages, and 24 the documentation surrounding each project is so voluminous that its value at 25 hearing would be severely diminished. As I understand it, in general rate 26
27 1 The Federal Energy Regulatory Commission (“FERC”) issued an order approving CIP-01101. 28 Gremp-DIRECT 3
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1 proceedings the Commission wants to see prepared direct testimony addressing the 2 details of and supporting expenditures on major projects. In recent general rate 3 cases, the Commission has accepted the $1.0 million demarcation as appropriate 4 for determining whether a project is “major.” While not addressed in detail in my 5 prepared direct testimony, my group has prepared project “binders” for smaller 6 projects completed since June 1, 2016. As has been the Companies’ practice for 7 many rate case cycles, those binders (now in electronic form) are available for 8 review on the day this general rate review filing is made.
9
10 II. COMPLIANCE PROJECTS
11 8. Q. DESCRIBE THE PROJECTS INCLUDED IN THIS SECTION.
12 A. This section discusses investment in one major (over $1.0 million) compliance 13 initiative as required by NERC. This project has been placed in service since the 14 end of the certification period in Sierra’s last general rate case and before the close d/b/a NV Energy Nevada Power Company Company Power Nevada 15 of the test period for this general rate review, December 31, 2018.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 9. Q. PLEASE DESCRIBE THE PROJECT. 18 A. This project implements physical and cyber security measures for all designated 19 high-impact and medium-impact facilities across the Companies’ transmission 20 system. These Critical Infrastructure Protection (“CIP”) measures are put in place 21 to achieve a robust security posture in keeping with the enforceable requirements 22 of NERC CIP-002-5 through CIP-011-1. These ten standards are collectively
23 referred to as the “Version 5 Standards.”2 CIP facilities include four high-impact 24 25
26 2 FERC approved Version 5 of the CIP standards on November 22, 2013. See 145 FERC ¶ 61,160 (iss. Nov. 27 22, 2013). Many of the Version 5 standards became effective July 1, 2016. 28 Gremp-DIRECT 4
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1 control center facilities and 11 medium-impact substations. Full compliance with 2 the Version 5 Standards was achieved on July 1, 2016. 3 4 10. Q. WHY WAS THE PROJECT NECESSARY? 5 A. The Version 5 Standards are approved by FERC and administered by NERC. In 6 addition, the Version 5 Standards implement controls that harden the physical and 7 cyber security posture associated with Sierra’s BES assets. Failure to comply with 8 the standards results in compliance violations and potential monetary penalties.
9
10 11. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION?
11 A. Yes. This project was previously presented to the Commission in Docket No. 17-
12 06003, Nevada Power’s last electric general rate review case. Investments made to 13 comply with Version 5 Standards were discussed in the prepared direct testimony 14 of Jack M. Wickersham III, and can be found in Volume 2 of 6 of the certification d/b/a NV Energy Nevada Power Company Company Power Nevada 15 filing.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 12. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 18 A. This project was required to support both Nevada Power and Sierra. The project 19 contains some elements that are allocated 100 percent to one or the other utility 20 based on asset location, and as well as elements that are allocated between Nevada 21 Power and Sierra using the Common Product allocation methodology.3 The 22 estimated total cost of the project for both Companies’ was $2,800,890 (without 23 AFUDC), based on an estimated in-service date of April 1, 2016. The final cost of 24 the CIP Version 5 Standards (“CIPv5”) upgrades was $3,322,314 (without 25
26 3 Refer to the prepared direct testimony of Ms. Erika McLean for a description of this and other allocations 27 used. 28 Gremp-DIRECT 5
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1 AFUDC) with an actual in-service date of July 1, 2016. Sierra’s share of CIPv5 2 implementation costs as of December 31, 2018 is $1,456,010 (with AFUDC). No 3 additional costs have been incurred during the certification period. 4 5 III. TRANSMISSION TECHNOLOGY 6 13. Q. PLEASE DESCRIBE THE PROJECT. 7 A. This section discusses the investments in Sierra’s ESCC greater than $1.0 million. 8 These projects have been placed in service since the end of the certification period
9 in Sierra’s last general rate case and prior to the end of the current certification
10 period, May 31, 2019. These projects directly impact the operations of Sierra’s
11 transmission and distribution grids, and are used and useful in providing utility
12 service. 13
14 1. Distribution SCADA d/b/a NV Energy Nevada Power Company Company Power Nevada 15 14. Q. PLEASE DESCRIBE THE PROJECT.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 A. This project involved adding Distribution Supervisory Control and Data 17 Acquisition (“DSCADA”) function to Distribution Management System (“DMS”) 18 currently utilized by ESCC. This project also included upgrading DMS to new 19 software version as well as new hardware environment. 20 21 15. Q. WHY WAS THE PROJECT NECESSARY? 22 A. Adding automation to the DMS was necessary to increase distribution grid 23 reliability. Distribution Automation, Conservation Voltage Reduction, volt/VAR 24 optimization, Distribution Line Capacitor Control, and Substation Automation, all 25 require a modern, centralized DMS capable of automatic operation of controllable 26 devices in the field. This can only be accomplished through usage of DSCADA. 27
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1 16. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION 2 PREVIOUSLY? 3 A. Yes. This project was previously presented to the Commission in Docket No. 17- 4 06003, Nevada Power’s last general rate review proceeding. Investments in the 5 Distribution SCADA project were discussed in the prepared direct testimony of 6 Jack M. Wickersham III, and can be found in Volume 2 of 6 of the certification 7 filing. 8
9 17. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
10 A. This project supports both Nevada Power and Sierra, and the costs were allocated
11 between the Companies based on the Common Product Allocation Methodology.
12 The estimated total cost of the project was $2,808,232 (without AFUDC) with an 13 estimated in-service date of September 9, 2016. The final cost of DSCADA Project 14 was $3,322,314 (without AFUDC) with an actual in-service date of May 25, 2017. d/b/a NV Energy Nevada Power Company Company Power Nevada 15 The cost of Sierra’s portion of the DCSADA project included in the gross plant
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 additions at December 31, 2018 is $1,472,251 (with AFUDC). No additional cost 17 have been incurred during the certification period.
18
19 2. ESCC Video Wall Replacement 20 18. Q. PLEASE DESCRIBE THE PROJECT. 21 A. This project required the installation of a new video wall in the ESCC to improve 22 system operation through situational awareness. The video wall replaced the then- 23 existing one-line diagram taped onto wall board. 24 25 26 27
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1 19. Q. WHY WAS THE PROJECT NECESSARY? 2 A. The transmission wallboard in the ESCC was a taped one-line diagram of the 3 regional transmission system, to which power circuit breakers statuses for the 4 transmission substations in northern Nevada were manually marked. This 5 antiquated technology was limited in capacity, and did not provide situational 6 awareness to operators under either normal operations or emergency system 7 operations. The video wall provides the versatility needed for state-wide 8 transmission system operations, automated circuit breaker statusing, and improved
9 situational awareness. The video wall technology enables the ESCC to implement
10 digital and real-time visualizations of the system. This aids in decision support
11 which can improve reliability and safe operation of the transmission system
12 13 20. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 14 A. No, this is the first time the Commission has been asked to review and approve the d/b/a NV Energy Nevada Power Company Company Power Nevada 15 costs associated with this project.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 21. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 18 A. The estimated total cost of the project was $2,372,464 (without AFUDC), based on 19 an estimated in-service date of December 31, 2016. The final cost of the project 20 was $1,812,497 (without AFUDC), and the actual in-service date was March 16, 21 2017. The total cost of the project included in gross plant additions at December 22 31, 2016 is $1,855,468 (with AFUDC). No additional costs have been estimated 23 for the certification period. 24 25 26 27
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1 IV. CONCLUSION 2 22. Q. DOES THIS COMPLETE YOUR TESTIMONY? 3 A. Yes, it does. 4 5 6 7 8
9
10
11
12 13 14 d/b/a NV Energy Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 18 19 20 21 22 23 24 25 26 27
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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
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1 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Sierra Pacific Power Company d/b/a NV Energy
3 2019 General Rate Case Docket No. 19-06__ 4 PREPARED DIRECT TESTIMONY OF 5 Danyale Howard 6 Revenue Requirement 7 8 1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS
9 ADDRESS AND PARTY FOR WHOM YOU ARE FILING 10 TESTIMONY.
11 A. My name is Danyale Howard. I am the Director of Distribution Design 12 Services for the Northern Nevada Region, a department within the Electric 13 Delivery Division of Sierra Pacific Power Company d/b/a NV Energy
d/b/a NV Energy Energy NV d/b/a 14 (“Sierra” or the “Company”). My business address is 1 Ohm Place, Reno,
15 Nevada. I am filing testimony on behalf of Sierra. and Nevada Power Company and Power Nevada Sierra Pacific Power Company 16
17 2. Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE IN 18 THE UTILITY INDUSTRY. 19 A. I have 22 years of experience in the utility industry in a variety of positions. I 20 have been in my current position since April 2018. I have held various 21 positions within Distribution Design Services (“DDS”) and all roles have 22 included increased responsibilities including progressive leadership from 23 supervisor to my present role as Director. 24 25 26 27
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1 3. Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS DIRECTOR OF 2 DDS. 3 A. As Director of DDS, my responsibilities include overseeing the customer 4 service, engineering, and project coordination for line extensions, facility 5 relocation projects and services for Rule 9 and Company-sponsored reliability 6 projects. I am responsible for the business processes followed to bring any new 7 customer onto the northern Nevada system, whether governmental, 8 commercial, residential developers, or individual homeowners) from the
9 application to the delivery of the line extension agreement. 10
11 4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC 12 UTILITIES COMMISSION OF NEVADA (“COMMISSION”)? 13 A. No.
d/b/a NV Energy Energy NV d/b/a 14
15 5. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? and Nevada Power Company and Power Nevada Sierra Pacific Power Company 16 A. I support the investment made by Sierra in new line extension facilities 17 pursuant to Rule 9 of Sierra’s electric tariff. 18 19 6. Q. ARE YOU SPONSORING ANY EXHIBITS? 20 A. Yes. I am sponsoring the following Exhibits: 21 Exhibit Howard-Direct-1 Statement of Qualifications 22 23 7. Q. PLEASE DESCRIBE THE DDS DEPARTMENT AND ITS 24 RESPONSIBILITIES. 25 A. As I state in Q&A 3 above, the DDS department provides customer service, 26 engineering and project coordination for line extensions, facility relocation 27
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1 projects and Company-sponsored reliability projects. DDS endeavors to 2 provide excellent customer service to customers, the development community, 3 local governmental entities and permitting agencies such as the Nevada 4 Department of Transportation (“NDOT”). To facilitate these objectives, 5 members of DDS regularly participate in industry organization meetings and 6 conduct periodic planning meetings with governmental entities such as 7 NDOT. 8
9 DDS handles all sizes and types of electric residential projects, from a single 10 service, to custom homes, subdivisions, apartments and condominiums, and
11 all types and sizes of commercial and industrial projects. DDS maintains staff 12 in five district offices in northern Nevada, where customers requesting electric 13 distribution services can meet with design specialists and initiate their projects under Sierra’s Tariff Rule 9. The DDS coordinates or prepares all the
d/b/a NV Energy Energy NV d/b/a 14
15 requirements to provide the requested service including distribution planning, and Nevada Power Company and Power Nevada Sierra Pacific Power Company 16 the acquisition of governmental permits and land rights, the project design, 17 estimation of construction costs as well as the preparation of the required 18 agreements. 19
20 8. Q. PLEASE DESCRIBE THE DIFFERENT TYPES OF PROJECTS DDS 21 ADMINISTERS.
22 A. The projects the DDS department administers can be grouped into three major 23 categories:
24 (1) Line Extensions That Serve Increased Demand. These projects 25 normally involve new load and result in new distribution facilities, or in some 26 cases, the modification to the existing distribution facilities. Projects in this 27
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1 grouping include custom homes, residential apartments or condominiums, 2 residential subdivisions, small commercial, large commercial, master planned 3 communities, and government projects. Occasionally, a line extension 4 involves not just “normal” distribution facilities, but also the installation of 5 High Voltage Distribution (“HVD”) facilities and/or a substation. When a 6 project requires HVD facilities, the HVD portion is turned over to the 7 Customer Solutions – Delivery group who will prepare the costs and contracts 8 for the HVD. The distribution portion will remain with the DDS department.
9 In these cases, separate agreements are prepared and delivered to the customer. 10 The agreements are reviewed, signed and formally executed pursuant to the
11 established chart of authority for DDS and the Customer Solutions – Delivery 12 departments. 13 Depending on the circumstances, Rule 9 may require the collection from an
d/b/a NV Energy Energy NV d/b/a 14
15 applicant of a refundable advance and/or a non-refundable contribution in aid and Nevada Power Company and Power Nevada Sierra Pacific Power Company 16 of construction (“CIAC”) advance. Both types of advances are calculated 17 based on the estimated project cost, net of any allowance granted. An 18 allowance is a credit toward construction costs for new loads and is based on 19 the number of units, meters or kilovolt-ampere (“kVA”) load that will be 20 served by the line extension facilities. As the name implies, an “advance 21 subject to refund” may be refunded to the customer over time, depending on 22 the ultimate load served from the Rule 9 facilities. In cases where separate 23 agreements are required to address HVD and/or substation installations 24 separate than standard distribution line extensions, payment of advances are 25 made separately to the respective agreements satisfying total advances due. 26 27
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1 (2) Relocation and Modification of Existing Distribution Facilities. 2 These projects involve an alteration of existing distribution facilities, usually 3 at the request of governmental entities, but occasionally at the request of a 4 residential or commercial customer. For relocation and modification projects, 5 Rule 9 requires non-governmental applicants, and depending on who has prior 6 rights, NDOT, RTC and governmental applicants throughout Sierra’s territory, 7 to pay the entire cost through a non-refundable CIAC, with no allowance to 8 the applicant unless the alterations directly contribute to a net increase in
9 demand. 10
11 Pursuant to its franchise agreements with local governments and agency 12 permits (e.g., NDOT), Sierra is allowed to install electric facilities in public 13 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
d/b/a NV Energy Energy NV d/b/a 14
15 project schedule and cost by reducing the requirements to obtain third-party and Nevada Power Company and Power Nevada Sierra Pacific Power Company 16 easements. However, the franchise agreements and permits require that Sierra 17 relocate facilities installed in government rights of way if requested by the 18 franchisor or permit issuer, except in situations where Sierra holds a pre- 19 existing property right in the right of way. Relocation work must follow the 20 schedules described in the agreements or those dictated by the governmental 21 entity’s project timeline. The costs associated with these relocations are not 22 funded by CIACs, and are instead recovered from all customers through 23 general rates. 24 25 26 27
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1 (3) Distribution System Improvements for System Reliability. These 2 projects are usually initiated internally by the Distribution Planning 3 department to address distribution system improvements needed to maintain 4 safe and reliable service to customers under normal load growth from existing 5 customers. They are not performed under Rule 9 because they do not involve 6 an applicant. 7 8 9. Q. WHAT RULES GOVERN THE COST OF LINE EXTENSION PLANT
9 INVESTMENT? 10 A. Rule 9 projects that are expected to increase demand are eligible to receive an
11 Allowance against construction costs, with the amount dependent on the type 12 of service that will be provided to the new load and the number of units, 13 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
d/b/a NV Energy Energy NV d/b/a 14
15 of the project, where there is a reasonable expectation that the supporting and Nevada Power Company and Power Nevada Sierra Pacific Power Company 16 number of units, meters and/or kVA demand will be initiated within the 12- 17 month period following the completion of construction of the line extension 18 facilities. 19 20 Allowances that are not provided in advance of construction can be received 21 by the applicant after construction in the form of refunds, based on the actual 22 number of unit, meters or kVA demand that are initiated between the 23 completion of construction and the expiration of the Rule 9 agreement. The 24 amount of the refund is calculated through the performance of an allowance 25 true-up. 26 27
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1 If the estimated cost of the project exceeds the amount of the Allowance 2 granted to the applicant before construction, the applicant must advance or pay 3 the difference. There are two types of advances. The advance subject to refund 4 is the amount that the applicant may receive back in the form of refunds based 5 on the number of units, meters or amount of new kVA demand that is served 6 on the project. An advance not subject to refund is the portion of the project 7 cost that is not eligible for refund and is considered a CIAC. Under Rule 9, 8 certain types of costs are treated as CIAC and may not be offset by the
9 Allowance. 10
11 In basic terms, the Company’s investment is the amount of the project cost that 12 is not paid for by the applicant through either a CIAC or an advance subject to 13 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
d/b/a NV Energy Energy NV d/b/a 14
15 of an advance subject to refund that does not qualify for a refund by the and Nevada Power Company and Power Nevada Sierra Pacific Power Company 16 expiration of the Rule 9 agreement, become CIACs and are a permanent offset 17 to plant in service. If a project qualifies for a refund after it is constructed, the 18 amount refunded essentially becomes Sierra’s utility plant in service. 19
20 10. Q. HOW MUCH INVESTMENT IN DDS PROJECTS HAS SIERRA 21 MADE SINCE ITS LAST GENERAL RATE CASE? 22 A. The cost of DDS Rule 9 related projects including Street and Highway less 23 New Business expired advances booked to plant in service between June 1, 24 2016 and May 31, 2019 total $63,658,317.
25 26 27
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1 The residential and commercial line extension projects that serve increased 2 demand grew 46% or $20 million over the amounts filed in the 2016 GRC. 3 The residential projects increased 63% and the commercial projects increased 4 33%. The backbone facilities to serve several large residential Master Planned 5 Communities have been installed and design work is currently being done for 6 several more large projects that are in the Discovery and Planning stages. 7 8 The total cost for the relocations and modification of existing distribution
9 facilities booked to plant in service does not reflect the actual amount of work 10 performed. Payments received for project charges incurred in the previous
11 GRC amounted to $2.18 million and projects with current charges included in 12 this GRC amount to $2.29 million. 13 The above mentioned projects are included in the plant additions provided by
d/b/a NV Energy Energy NV d/b/a 14
15 Ms. Ellen Fincher in Exhibit Fincher-Direct-2. None of these projects involve and Nevada Power Company and Power Nevada Sierra Pacific Power Company 16 an expenditure of $1 million or more. Distribution system improvements for 17 system reliability projects that were designed by the DDS are included in the 18 plant additions provided by Mr. Ricardo Becerra. 19 20 11. Q. DOES THIS COMPLETE YOUR TESTIMONY? 21 A. Yes, it does. 22 23 24 25 26 27
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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 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA 2 Sierra Pacific Power Company d/b/a NV Energy 3 2019 General Rate Case Docket No. 19-06___ 4 PREPARED DIRECT TESTIMONY OF 5 Ricardo Becerra 6 Revenue Requirement 7 8 1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS ADDRESS
9 AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
10 A. My name is Ricardo Becerra. My current position is Manager, Delivery Assurance
11 Financial Reporting for Sierra Pacific Power Company d/b/a NV Energy (“Sierra
12 or the “Company”) and Nevada Power Company d/b/a NV Energy (“Nevada 13 Power,” and together with Sierra, the “Companies”). My business address is 6226 14 West Sahara Ave. in Las Vegas, Nevada. I am filing testimony on behalf of Sierra. d/b/a NV Energy Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 2. Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE IN THE 17 UTILITY INDUSTRY. 18 A. I joined the Companies 13 years ago, and have since worked in the areas of electric 19 operations, maintenance, capital planning, and financial reporting. In my time at 20 the Company, I have actively participated in the planning and execution of large 21 scale Transmission and Distribution major projects, capital maintenance programs, 22 and operations maintenance plans. I have a Bachelor of Science Degree in 23 Mechanical Engineering and a Master’s Degree in Business Administration, both 24 from the University of Nevada, Las Vegas. My background and experience are 25 more fully described in my statement of qualifications, attached as Exhibit Becerra 26 Direct-1. 27
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1 3. Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS MANAGER, 2 DELIVERY ASSURANCE FINANCIAL REPORTING. 3 A. I provide direct leadership and guidance to a team that: (1) develops, coordinates, 4 and administers capital maintenance, new business, and operation and maintenance 5 (“O&M”) budgeting activities for the Electric Delivery organization across the 6 Companies service territories; (2) monitors budget expenditures and identifies and 7 analyzes budget variances; (3) works closely with operations leadership to develop 8 capital and O&M plans across the Companies’ northern and southern electric
9 service territories; and (4) identifies and recommends opportunities to improve
10 operational efficiency and gain cost savings. I also lead cross-functional teams in
11 the implementation of improvement initiatives.
12 13 4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC 14 UTILITIES COMMISSION OF NEVADA (“COMMISSION”)? d/b/a NV Energy Nevada Power Company Company Power Nevada 15 A. No, I have not previously testified before the Commission.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 5. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 18 A. I support the prudence of the Company’s investments in capital maintenance 19 projects. For the period June 1, 2016 through December 31, 2018 (actuals), and the 20 period January 1, 2019 through May 31, 2019 (estimates), those investments are 21 identified in Table Becerra Direct-1 below. Certification period estimates will be 22 updated up as part of the Company’s certification filing. 23 24 25 26 27
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Table Becerra Direct-1 1 Capital Maintenance Investment $ in millions 2 3 Actuals Through Estimated Through Project Category December 31, 2018 May 31, 2019 Total 4 Equipment Failure Projects $ 26.7 $ 4.5 $ 31.2 Regional Overhead Rebuilds $ 16.9 $ 4.1 $ 20.9 5 4 kV to 25 kV Conversion Program $ 12.7 $ 4.3 $ 17.0 SAIDI Improvement Initiative Program $ 9.1 $ 7.8 $ 16.9 6 Regional Underground Rebuilds $ 9.6 $ 0.9 $ 10.5 Spare Equipment Program $ 6.3 $ 0.0 $ 6.3 7 Avian Protection Program $ 4.6 $ 0.4 $ 5.0 Substation Breaker Replacements $ 3.4 $ 0.1 $ 3.5 8 Tools Replacement Program $ 1.9 $ 0.6 $ 2.6 9 Telemetry/PI Addition Program $ 1.9 $ 0.0 $ 1.9 Pole Treatment Program $ 1.8 $ 0.0 $ 1.8
10 Line Sensor Program $ 0.3 $ 0.9 $ 1.2
Other $ 2.9 $ 1.5 $ 4.4 11 TOTAL $ 98.0 $ 25.2 $ 123.2
12 13 6. Q. WHY ARE THESE MAINTENANCE PROJECTS ACCOUNTED FOR AS 14 CAPITAL INVESTMENT? d/b/a NV Energy Nevada Power Company Company Power Nevada 15 A. These projects involve the replacement, retirement, and/or addition of
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Transmission, Distribution, or Substation assets. For this reason, the costs are 17 properly capitalized. 18 19 7. Q. PLEASE DESCRIBE THE CAPITAL MAINTENANCE PROJECTS THAT 20 WERE PERFORMED DUE TO EQUIPMENT FAILURE. 21 A. The Company separately accounts for equipment replacements that are necessitated 22 by equipment failure that results in, or imminent failure that could result in, a loss 23 of electrical service. These so-called “Failure” projects include:
24 • Transmission equipment, including transmission poles, overhead 25 conductor, and associated hardware;
26 • Substation equipment (transmission and distribution), including 27
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1 apparatuses, structures, and associated hardware;
2 • Overhead distribution equipment, including distribution poles, overhead 3 conductor, and associated hardware;
4 • Underground and pad mounted distribution equipment, including switches, 5 structures, cable, and associated hardware;
6 • Transformers, including overhead service transformers, pad mounted 7 service transformers, and associated hardware; and
8 • Services, including underground secondary/service cable, overhead 9 secondary/service conductors and associated hardware.
10
11 Since June 1, 2016, Sierra completed 2,696 Failure projects through December 31,
12 2018 at a total cost of $26,684,099. Estimated expenditures for this program for the 13 period January 1, 2019 through May 31, 2019 are $4,549,136. 14 d/b/a NV Energy Nevada Power Company Company Power Nevada 15 8. Q. WHY WERE THE FAILURE PROJECTS NECESSARY?
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 A. The capital maintenance projects performed on transmission facilities, substation 17 facilities, overhead distribution facilities, underground distribution facilities, and 18 transformers were required to effect immediate replacement to failed facilities 19 and/or restore electrical service to customers. Capital maintenance projects on 20 services (low voltage conductor or cable) were performed either (1) to restore 21 electrical service to customers; (2) because the cable or conductor had reached or 22 exceeded the end of its service life; or (3) to correct violations of various National 23 Electric Safety Code (“NESC”), Occupational Safety and Health Administration 24 (“OSHA”), and Company safety standards. 25 26 27
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1 9. Q. PLEASE DESCRIBE THE REGIONAL OVERHEAD REBUILD 2 PROGRAMS 3 A. These are projects that replace and/or retrofit existing overhead infrastructure and 4 include the replacement of transmission and distribution poles, the stubbing of 5 poles, capital replacements that were necessary to affect the installation of lateral 6 fusing and avian protection apparatuses, the replacement of overhead conductor, 7 installation and replacement of line capacitor banks, line upgrades, re-insulation of 8 overhead lines, voltage improvements, rectifying conditions where the overhead
9 facilities become non-compliant with NESC, OSHA, and/or Company safety
10 standards, and other reliability improvement projects.
11
12 Sierra completed 450 Regional Overhead Rebuild Program projects from June 1, 13 2016 through December 31, 2018 at a total cost of $16,850,964. The largest 14 overhead rebuild projects were: (1) the 634 Line Rebuild project ($1,921,369); (2) d/b/a NV Energy Nevada Power Company Company Power Nevada 15 the East Mt. Rose 210 Reconductor project ($1,510,860); (3) the 2302
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Transmission Line Uprating project ($740,103); (4) the Pinenut 1253 Rebuild 17 project ($652,748); and (5) the East Lovelock 7.2 Conversion project ($481,380). 18 Estimated expenditures for this program for the period January 1, 2019 through 19 May 31, 2019 are $4,050,965. 20 21 10. Q. WHY WERE THE REGIONAL OVERHEAD PROGRAM PROJECTS 22 COMPLETED BY THE COMPANY NECESSARY? 23 A. Projects performed under this program were necessary to address at least one of the 24 following concerns:
25 • Equipment that has reached or exceeded the end of its service life is replaced to 26 improve the reliability of the transmission and distribution system. 27
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1 • Equipment is replaced to provide for the acceptance of renewable energy 2 infrastructure upgrades and is needed to compensate for reverse power flow 3 situations. For example, reverse power flow can cause regulators and reclosers 4 to operate abnormally.
5 • Equipment is installed or replaced to maintain adequate system voltage. 6 • Replacements and improvements also bring facilities into compliance with new 7 NESC, OSHA, and Company safety manual rules. 8
9 11. Q. PLEASE DESCRIBE THE 4 KILOVOLT (“KV”) TO 25 KV CONVERSION
10 PROGRAM.
11 A. This budget category captures costs incurred to continue to convert portions of the
12 4 kV electric distribution system in Sierra’s service territory to northern Nevada’s 13 modern 25 kV standard. Last reviewed in Sierra’s 2016 general rate review 14 proceeding, these conversion projects involve replacing substation equipment, d/b/a NV Energy Nevada Power Company Company Power Nevada 15 distribution poles, overhead conductor, underground cable, overhead and pad
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 mounted service transformers, overhead and pad mounted switches, capacitor 17 banks, and associated hardware. 18 19 The Company completed 40 4 kV to 25 kV conversions projects through December 20 31, 2018 at a total cost of $12,742,870. The largest 4 kV conversion projects were: 21 (1) Sparks Industrial Sub 25 kV Conversion ($2,530,515); (2) University #1 22 Northwest project ($1,485,859); (3) Moana #2 North project ($1,153,619); (4) 23 Moana #2 South project ($964,526); (5) El Rancho #2 West A project ($834,564); 24 (6) Hunter Lake #6 Sharon West B project ($915,013); (7) El Rancho #1 West 25 project ($602,698); and (8) El Rancho #1 North A project ($478,571). Estimated 26 27
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1 expenditures for this program for the period January 1, 2019 through May 31, 2019 2 are $4,276,851. 3 4 12. Q. WHY ARE THE 4 KV TO 25 KV CONVERSION PROJECTS PERFORMED 5 BY THE COMPANY NECESSARY? 6 A. The 4 kV to 25 kV conversion program provides multiple benefits to customers and 7 employees in improved safety, reliability, and reduced operating costs: 8
9 Safety: The 4 kV conversion will improve the overall safety of the distribution
10 system as the deteriorating 4 kV equipment is removed from service.
11
12 Operations and Reliability: The 4 kV equipment is some of the oldest distribution 13 equipment in the Truckee Meadows system. Operational and safety issues are 14 expected to increase as it reaches and surpasses its normal operating life. d/b/a NV Energy Nevada Power Company Company Power Nevada 15 Additionally, the 4 kV system is essentially electrically “isolated” from the rest of
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 the distribution system, meaning back-up and service restoration options are 17 limited. Back-up and switching capability continues to deteriorate due to forced 18 conversions in different areas of the system to accommodate new customer 19 services. This creates increased labor and outage hours due to the complex 20 switching orders required to isolate and restore the 4 kV circuits. 21 22 Protection and Coordination: The conversion of the system to 25 kV allows for the 23 application of modern protective schemes in line with current standards. 24 25 Voltage Regulation: Voltage regulation normally becomes an issue on long feeders 26 with small conductor, high load, and low source voltage. Most of the Truckee 27
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1 Meadows distribution system is either 24.9 kV or 4.16 kV. Most of the transformers 2 are 22.9 kV / 4.36 kV, with 24.1 kV being the highest primary tap available. This 3 results in high voltages on the 4 kV system and low voltages on the 25 kV buses 4 that serve the 4 kV substations. Additionally, adjustments to 4 kV voltage is 5 impossible because the 4 kV load tap changers cannot be repaired or maintained 6 (14 out of 18 substations had voltage regulators blocked). 7 8 Capacity: There is the potential for additional load growth in areas that are
9 currently served at 4 kV. Some 4 kV transformers are loaded to their full nameplate
10 ratings during peaks, with no back-ups or replacements available. This impacts
11 system reliability.
12 13 Maintenance: The 4 kV system has reached or exceeded the end of its service life, 14 requiring increased regular inspection and maintenance to ensure its operability. d/b/a NV Energy Nevada Power Company Company Power Nevada 15 Newly installed assets require less frequent and less costly maintenance.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 Material: While the varieties of 4 kV materials that are currently stocked in the 18 warehouse can support the Northeast and Northwest districts, the quantities of these 19 materials could be reduced significantly, resulting in 4 kV inventory savings.
20
21 13. Q. PLEASE DESCRIBE THE SYSTEM AVERAGE INTERRUPTION 22 DURATION INDEX (“SAIDI”) IMPROVEMENT INITIATIVE 23 PROGRAM.1 24 A. The various projects under the SAIDI Improvement Initiative Program are projects 25 26
27 1 SAIDI is one of several industry standard measures that electric utilities use.
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1 that replace and/or retrofit overhead and underground infrastructure. This includes 2 the replacement of transmission and distribution poles, capital replacements that 3 were necessary to affect the installation of lateral fusing and avian protection 4 apparatuses, the replacement of overhead conductor and underground cable, 5 installation and replacement of line capacitor banks, line upgrades, re-insulation of 6 overhead lines, and the replacement of pad mounted or subsurface facilities. In 7 addition to the activities typical of overhead and underground rebuilds, the SAIDI 8 Improvement Initiative may include grid hardening, installation of sectionalizers
9 and/or reclosers and circuit ties.
10
11 Sierra completed 54 SAIDI Improvement Initiative projects through December 31,
12 2018 at a total cost of $9,107,390. The largest projects were: (1) the Spring Valley 13 Parkway UG Rebuild Phase 6 project ($1,288,464); (2) the Spring Valley Parkway 14 UG Rebuild Phase 5 project ($1,146,916); (3) the Avian protection –Anaconda 204 d/b/a NV Energy Nevada Power Company Company Power Nevada 15 project ($865,594); (4) the Avian protection – Anaconda 204-Grant View Dr.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 project ($636,634); and (5) the Last Chance 211 Rebuild Phase 5 project 17 ($529,576). Estimated expenditures for this program for the period January 1, 2019 18 through May 31, 2019 are $7,776,923. 19 20 14. Q. WHY WERE THE SAIDI INITIATIVE PROGRAM PROJECTS 21 COMPLETED BY THE COMPANY NECESSARY? 22 A. A study performed in April 2017 concluded that the top 25 high-risk feeders out of 23 317 feeders in the northern distribution network were contributing the most outage 24 hours and thus were the most unreliable circuits. These 25 high-risk feeders 25 constitute about 25 percent of total feeder length in the northern distribution system 26 and contributed 45 percent of the outage hours. As such, these projects will 27
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1 significantly improve reliability to customers on these worst performing circuits by 2 reducing the frequency and duration of outages. The scope of work is similar to the 3 replacement and/or retrofitting of overhead and underground infrastructure and 4 provide the following benefits:
5 • Equipment that has reached or exceeded the end of its service life is replaced 6 to improve the reliability of the transmission and distribution system.
7 • Equipment is installed or replaced to maintain adequate system voltage. 8 • Replacements and improvements also bring facilities into compliance with 9 new NESC, OSHA, and Company safety manual rules.
10 • Allows Sierra to quickly isolate electrical faults allowing for rapid
11 restoration to customers.
12 • Harden the electric system to better resist outage incidents. 13 14 15. Q. PLEASE DESCRIBE THE REGIONAL UNDERGROUND REBUILD. d/b/a NV Energy Nevada Power Company Company Power Nevada 15 A. The various Regional Underground Rebuild Program projects involve replacing
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 and/or retrofitting underground infrastructure. This includes the replacement of 17 underground cable, the replacement of switches, vaults, and secondary boxes prior 18 to failure or after temporary repair was affected to restore service and includes other 19 reliability improvement projects. 20 21 The Company completed 302 Regional Underground Rebuild Program projects 22 through December 31, 2018 at a total cost of $9,570,952. The largest underground 23 rebuild projects were: (1) the Long Street Submersible Transformer Change out 24 project ($802,391); (2) the Spring Valley Replacement project ($734,196); and (3) 25 the South Virginia Street – U.S. Bank project ($489,836). Estimated expenditures 26 for this program for the period January 1, 2019 through May 31, 2019 are $940,123. 27
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1 16. Q. WHY WERE THE REGIONAL UNDERGROUND REBUILD PROGRAM 2 PROJECTS NECESSARY? 3 A. The projects replacing and/or retrofitting underground infrastructure were 4 performed for a variety of reasons:
5 • Equipment that has reached or exceeded the end of its service life is replaced 6 to improve the reliability of the distribution system.
7 • Additional underground infrastructure is installed to create a “looped 8 system,” which provides greater operational flexibility through outage
9 restoration contingencies and decreases the duration of service disruptions.
10 • Equipment is installed or replaced to maintain adequate system voltage.
11 Typical projects include the replacement of cable with deteriorated
12 concentric neutral. This equipment corrects power factor and increases line 13 capacity.
14 • Replacement or construction of new vaults and boxes is required to replace d/b/a NV Energy Nevada Power Company Company Power Nevada 15 those that have structurally failed.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 • Replacements and improvements are required to bring facilities into 17 compliance with changes in NESC, OSHA, and Company safety standards. 18 19 17. Q. PLEASE DESCRIBE THE SPARE EQUIPMENT PROGRAM. 20 A. This program provides for the acquisition of system critical spare substation 21 apparatus to provide reliable electric service and mitigate the risk of extended 22 customer outages. This equipment either fills an existing vacancy in spare 23 equipment or directly replaces a spare that was installed as the result of a failure. 24 The Company completed five projects, totaling $6,279,739, which consist of the 25 purchase of:
26 • One 345/230 kV, 300 MVA system spare transformer $2,676,686; 27
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1 • One 280 MVA, 345 kV - 120 kV auto transformer $2,030,633; 2 • One 230 kV, 25 MVAR, reactor $937,260; 3 • One 345 kV breaker $579,423; and 4 • One 12.5/34.5kV, 2 MVA step up pad mount transformer $55,737. 5 Estimated expenditures for this program for the period January 1, 2019 through 6 May 31, 2019 are $0. 7 8 18. Q. WHY WAS THE SPARE EQUIPMENT PROGRAM NECESSARY?
9 A. Standard utility practice requires that the Company maintain sufficient quantities
10 of long-lead spare equipment such as large power autotransformers, medium power
11 transformers, and substation breakers for all common voltage and capacity classes.
12 The typical lead-time on delivery of medium power transformers is 12 to 18 months 13 after placement of an order (depending on factory loading); similarly, the lead-time 14 for high-voltage breakers is 6 to 8 months. The number of spares on hand varies d/b/a NV Energy Nevada Power Company Company Power Nevada 15 based on the number of devices operational in the field, access and/or availability
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 to acquiring new equipment, age of transformer fleet, and the reliability of critical 17 load. These units are called upon for an unforeseen or urgent project where the 18 project timeline is not adequate to order and procure replacement equipment. 19 Normally, the Company should maintain one or more spare units for each of these 20 assets. Additional justification for the acquisition of each spare is provided below: 21 22 D2416: 300 MVA 345/230 kV Autotransformer. Sierra did not have a spare 300 23 MVA 345/230 kV transformer to back up three transformers at Hilltop and Gonder 24 substations. An extended loss of the Gonder or Hilltop 345/230 kV transformers 25 could result in derating of interconnection path ratings, an increase in must run 26 generation, noneconomic dispatch and load curtailment. 27
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1 TM299: 280 MVA 345/120 kV Autotransformer. This purchase replaced the 2 spare 280 MVA 345/120 kV transformer that was used to replace the Humboldt 3 345/120 kV transformer, which failed catastrophically on July 6, 2014. After the 4 failure of the Humboldt transformer, Sierra did not have a spare 345/120 kV 280 5 MVA transformer to back up the 11 transformers at various substations. 6 7 TM265: 25 MVAR 230 kV Shunt Reactor. Sierra did not have a spare 25 MVAR 8 230 kV shunt reactor to back up six reactors at Anaconda Moly, Austin, Gonder,
9 and Osceola substations. An extended loss of the existing reactors could result in
10 voltage excursions, exceeding equipment ratings, and derating of interconnection
11 path ratings.
12 13 TM287: 345 kV Power Circuit Breaker. Sierra did not have a spare 345 kV power 14 circuit breaker to back up many similarly rated breakers. An extended loss of the d/b/a NV Energy Nevada Power Company Company Power Nevada 15 existing breakers would result in the significant degradation of reliable transmission
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 service. 17 18 D2417: 2 MVA 12.5/34.5 kV Transformer. Sierra did not have a spare 12.5/34.5 19 kV transformer to back up the existing Southside Substation feed to Fallon Naval 20 Air Station (“FNAS”). An extended loss of the existing transformer would result in 21 an extended loss of service to FNAS. 22 23 The Company’s older transformers are more susceptible to failure, even when 24 maintained pursuant to manufacturer recommendations. Additionally, catastrophic 25 damage caused by external forces such as weather and vandalism or other 26 unanticipated incidents poses risks to service reliability that are reduced or 27
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1 mitigated with essential spares. This practice provides the Company with the ability 2 to quickly respond when unexpected failures occur, avoiding extended service 3 interruptions. 4 5 19. Q. PLEASE DESCRIBE THE AVIAN PROTECTION PROGRAM PROJECTS. 6 A. The Avian Protection Program projects involve the installation of bird guard 7 apparatus and, where necessary, the design and rebuild of structures and associated 8 hardware such as cross arms and insulators to meet avian safe standards.
9
10 The Company completed 20 Avian Protection Program projects through December
11 31, 2018 at a total cost of $4,613,702. The largest Avian Protection Program
12 projects were: (1) the North 5th Street project ($527,867); (2) the Dutch Flat 208 13 project - 726868 ($516,715); (3) the Dutch Flat 208 project - 726234 ($492,553); 14 (4) the Bridge Street 206 project - 1023878 ($470,699); and (5) the Bridge Street d/b/a NV Energy Nevada Power Company Company Power Nevada 15 206 project – 3102 ($456,808). Estimated expenditures for this program for the
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 period January 1, 2019 through May 31, 2019 are $415,173. 17
18 20. Q. WHY WERE THE AVIAN PROTECTION PROGRAM PROJECTS 19 NECESSARY? 20 A. As a core corporate value, the Company practices responsible stewardship of the 21 environment. To this end, the Company has implemented an avian protection plan. 22 The Avian Protection Plan, also known as an APP, is a voluntary, utility-specific 23 plan for reducing risks to birds and system reliability that result from avian 24 interactions with power lines and electric utility facilities with the overall goal of 25 reducing avian mortality. 26 27
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1 Federal compliance and public safety are the primary drivers behind the Avian 2 Protection Plan; there are three primary laws in the United States that protect birds 3 from injury and death. They are:
4 • Migratory Bird Treaty Act of 1918 that currently protects 1,007 bird 5 species;
6 • Bald and Golden Eagle Protection Act of 1940; and 7 • Endangered Species Act of 1973. 8 In addition to these federal laws protecting birds, collisions and interactions with
9 power lines and distribution facilities can cause service interruptions.
10
11 The APP captures the costs incurred to affect the various engineering and field
12 modifications and replacements necessary to comply with the Company’s Avian 13 Protection Plan. 14 d/b/a NV Energy Nevada Power Company Company Power Nevada 15 21. Q. PLEASE DESCRIBE THE SUBSTATION BREAKER REPLACEMENT
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 PROGRAM. 17 A. The Substation Breaker Replacement Program projects involve the replacement of 18 breakers and disconnects that are unreliable, have reached or exceeded the end of 19 their service lives, are difficult and/or expensive to maintain due to the 20 unavailability of spare parts, or are potentially hazardous to operate due to slow or 21 non-clearing faults. 22 23 Through December 31, 2018, the largest Substation Breaker Replacement Program 24 project was the North Truckee Breaker Replacement project ($3,380,256). 25 Estimated expenditures for this program for the period January 1, 2019 through 26 May 31, 2019 are $0. 27
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1 22. Q. WHY WERE THE BREAKER REPLACEMENT PROGRAM PROJECTS 2 PERFORMED BY THE COMPANY NECESSARY? 3 A. Circuit breakers are devices that automatically operate to protect an electrical 4 circuit from damage caused by overcurrent/overload or short circuit. It 5 accomplishes this by interrupting current flow after protective relays detect a fault 6 condition. Circuit breakers can be reset (either manually or automatically) to 7 resume normal operation. These projects were necessary to avoid extended 8 disruptions to service, reduce future maintenance costs, and mitigate heightened
9 risks associated with obsolete equipment deemed unsafe to operate.
10
11 23. Q. PLEASE DESCRIBE THE TOOLS REPLACEMENT PROGRAM.
12 A. This program captures the costs associated with the acquisition, repair, or 13 replacement of tools that are properly unitized as assets in accordance with the 14 capitalization policy. Tools include items such as hot sticks, relay test equipment, d/b/a NV Energy Nevada Power Company Company Power Nevada 15 power system simulators, Panduit printers, mirrored bits testers, multi-meters, and
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 other items. 17 18 The Company completed 208 projects under the Tools Replacement Program 19 through December 31, 2018, at a total cost of $1,928,092. The largest project was 20 the Crimp Tool replacement project ($220,552). Estimated expenditures for this 21 program for the period January 1, 2019 through May 31, 2019 are $625,972. 22 23 24. Q. WHY ARE REGULAR TOOL REPLACEMENTS NECESSARY? 24 A. Regular replacement of tools ensures that operations and maintenance staff have 25 access to the proper tools to execute projects and programs. These tools are 26 typically acquired as a technician/crew safety improvement, to reduce expenses, 27
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1 increase work efficiency, and/or maintain compliance. For example, the crimp tool 2 replacement identified above is manufactured by AFL Telecommunications LLC 3 and includes the crimpers, bus gauge, and other accessories. Called a swage fitting, 4 it is the Companies’ current standard tool for bus connections. The connections 5 require a very specific kind of tooling for bus work at new substations. The tools 6 make up a hydraulic pump that compresses the connectors on to the bus. Every 7 crew assembling a bus will need access to these tools at some point in the 8 construction process. Currently, the three complete sets of crimpers purchased are
9 shared by six substation crews in northern Nevada.
10
11 25. Q. PLEASE DESCRIBE THE TELEMETRY/PI ADDITION PROGRAM.
12 A. The Telemetry/PI Addition Program involves the installation of 13 telecommunications and substation equipment necessary to monitor and report 14 voltage, current, and power, and to provide breaker or recloser status and control d/b/a NV Energy Nevada Power Company Company Power Nevada 15 for substations for system control operators.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 The Company completed 31 projects under the Telemetry/PI Addition Program 18 through December 31, 2018, at a total cost of $1,850,384. The largest single project 19 was the Antelope Valley PI Addition project ($249,232). Estimated expenditures 20 for this program for the period January 1, 2019 through May 31, 2019 are $9,947. 21 22 26. Q. WHAT ARE THE TELEMETRY/PI ADDITION PROGRAM PROJECTS? 23 A. Telemetry addition projects provide for automated communications through which 24 measurements are made and other data collected at remote locations and transmitted 25 to receiving equipment for monitoring and provide multiple benefits. 26 27
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1 Telemetry is a basic requirement for a functional Supervisory Control and Data 2 Acquisition (“SCADA”), a core utility system. SCADA systems allow operators in 3 control rooms to monitor the flows in the power system and to remotely control 4 substation equipment, issuing control commands via the utility’s communication 5 network. Other fundamental components of a SCADA system include functionality 6 to alarm abnormal conditions, tag devices for safety and information purposes, and 7 archive real-time data. 8
9 The SCADA system communicates with Remote Terminal Units (or substation data
10 concentrators fed by substation intelligent electronic devices) located within
11 substations. Currently, SCADA systems have been used to monitor and control
12 equipment on the transmission and sub-transmission network as well as distribution 13 transformers and feeder head devices located within the substations. 14 d/b/a NV Energy Nevada Power Company Company Power Nevada 15 27. Q. WHY WERE THE TELEMETRY/PI ADDITION PROGRAM PROJECTS
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 NECESSARY? 17 A. For several reasons, which are summarized below. 18 19 Operational Benefits and Cost Savings. Collecting power data from sites that lack 20 telemetry requires field resources to travel to the site to retrieve a chart. These charts 21 are not as reliable as real-time telemetry since they can become illegible, damaged 22 or lost. Simply put, it takes time and resources to collect data manually; 23 consequently, manually-gathered charts are sometimes severely dated and lose their 24 analytical value. 25 26 27
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1 Energy Management. The energy management system manages the operation of 2 the bulk power grid. It is considered a critical system since the potential 3 consequences of losing visibility and control of bulk power grid operations are so 4 severe. The SCADA system retrieves real-time measurements and status conditions 5 of the power system and power network applications such as state estimation, 6 power flow, and contingency analysis. 7 8 Distribution and Outage Management. Telemetry is required for advanced
9 distribution management system power applications such as unbalanced power
10 flow, distribution state estimation, integrated Volt/Var control, fault location,
11 isolation, and service restoration to manage, operate, optimize, and restore the grid
12 in real-time. 13 14 Future Utilization – Smart Grid Technologies. The addition of telemetry is d/b/a NV Energy Nevada Power Company Company Power Nevada 15 prerequisite for the introduction of smart grid technologies. The proliferation of
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 new technologies on the customer side of the meter (e.g., electric vehicles, 17 distributed generators, and energy storage technologies) make the distribution 18 network increasingly more complex to operate. Smart grid technologies allow the 19 Company to safely operate and better optimize its network assets with consideration 20 to these new customer technologies. 21 22 Telemetry provides for rapid response to service interruptions and the restoration 23 of service as electrical information pertaining to a device’s status is readily 24 available to System Control Operators. Further, smart grid technologies require 25 telemetry to automate field devices on distribution networks to pick up customers 26 on unfaulted sections of the feeders more quickly, thus minimizing customer 27
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1 outages in what is commonly referred to as Distribution Automation and ‘self- 2 healing’ systems. 3 4 28. Q. PLEASE DESCRIBE THE POLE TREATMENT PROGRAM. 5 A. This program treats and reinforces overhead line wood poles to extend the life of 6 the poles. Treatment includes the inspection, sounding, boring, and treatment of 7 deteriorated wood poles. A successful program includes:
8 • Identifying decay and measuring defects; 9 • Estimating the pole’s remaining strength to determine pass/fail; and
10 • Applying effective remedial treatments to extend the safe, reliable service-
11 life of the pole.
12 Additionally, pole reinforcements are included in this program when additional 13 load is added to the pole and the strength is no longer adequate (usually driven by 14 joint use attachments for telecommunications companies) or it is no longer deemed d/b/a NV Energy Nevada Power Company Company Power Nevada 15 to be structurally sound.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 The Company completed 91 Pole Treatment projects through December 31, 2018 18 at a total cost of $1,818,638. The largest project was the Grass Valley - 2517 project 19 ($94,115). Estimated expenditures for this program for the period January 1, 2019 20 through May 31, 2019 are $0. 21 22 29. Q. WHY WAS THE POLE TREATMENT PROGRAM NECESSARY? 23 A. Pole treatment programs are the cornerstone for overhead circuit reliability 24 programs. This program allows for optimized maintenance, life extension, and 25 replacement decisions that lower overall ownership costs. Furthermore, pole steel 26 reinforcement trusses are specifically designed, engineered, and manufactured to 27
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1 add decades of useful life to wood poles. When fully implemented, this program 2 provides a reduction in customer average interruption duration index minutes, 3 reduces pole failures, and reduces pole replacements. The treatment and reinforcing 4 of poles significantly improve the pole structure that supports overhead circuits and 5 improve the reliability of service to the customers who are served by overhead 6 distribution circuits. The data collected from this program is also used for pole 7 replacements, circuit inspections, and overhead rebuild activities associated with 8 poorly performing circuits.
9
10 30. Q. PLEASE DESCRIBE THE LINE SENSOR PROGRAM.
11 A. Initiated in 2014, the Intelligent Line Sensor program utilizes advanced technology
12 to measure and monitor voltage, current, power, and phase angle at critical points 13 on overhead conductors such as substation getaways, important sectionalizing 14 points, and line recloser locations. The Company selected Aclara (formerly d/b/a NV Energy Nevada Power Company Company Power Nevada 15 Tollgrade) to supply the sensors through a competitive bidding process, and now
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 has more than 600 sensors installed on single-phase and three-phase lines 17 throughout the Companies transmission and primary distribution systems. The 18 information provided by these sensors is transmitted mainly via cellular 19 communications and can be accessed via Aclara’s Sensor Management System 20 software. 21 22 The Company completed one Line Sensor Program project, the light House 23 Distribution Sensor project, by December 31, 2018 at a total cost of $313,363. The 24 estimated expenditures for this program for the period January 1, 2019 through May 25 31, 2019 are $856,174. 26 27
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1 31. Q. WHY WAS THE LINE SENSOR PROGRAM NECESSARY? 2 A. The Company was seeking effective alternatives to provide telemetry on many of 3 its transmissions lines and distribution feeders where no metering existed to 4 improve grid awareness at a cost lower than that of traditional telemetering 5 equipment. The sensors provide loading information for planning and operating 6 purposes, fault information to aid in service restoration, and, as the Companies’ 7 electric system transitions to a modern era with increased penetration of distributed 8 energy resources, will help facilitate the safe and reliable planning and operation of
9 the system going forward.
10
11 32. Q. DOES THIS CONCLUDE YOUR PREPARED TESTIMONY?
12 A. Yes. 13 14 d/b/a NV Energy Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 18 19 20 21 22 23 24 25 26 27
28 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 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Sierra Pacific Company d/b/a NV Energy
3 2019 General Rate Case Docket No. 19-06__ 4 PREPARED DIRECT TESTIMONY OF 5 Victor Figueredo 6 Revenue Requirement 7
8 I. INTRODUCTION
9 1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS ADDRESS,
10 AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
11 A. My name is Victor Figueredo. I am the Director of Electric Delivery Support for
12 NV Energy, Inc. (“NV Energy”), Sierra Pacific Power Company d/b/a NV d/b/a NV Energy 13 Energy (“Sierra” or the “Company”) and Nevada Power Company d/b/a NV Nevada Power Company Company Power Nevada Sierra Pacific Power Company Pacific PowerSierra Company
14 Energy (“Nevada Power” and, together with Sierra, the “Companies”). I work and
15 primarily out of NV Energy’s operating center complex office, which is located
16 at 7155 Lindell Road in Las Vegas, Nevada. I am filing testimony in this
17 proceeding on behalf of Sierra.
18
19 2. Q. PLEASE BRIEFLY DESCRIBE YOUR PROFESSIONAL
20 BACKGROUND AND EXPERIENCE.
21 A. I joined the Companies in May 1995 after spending 11 years in the automotive
22 manufacturing industry. As Director of Electric Delivery Support, I am currently
23 responsible for the functional areas of vehicle/equipment fleet management,
24 vegetation/tree trimming maintenance, and materials/logistics warehouse
25 Figueredo– DIRECT 1
Page 53 of 250
1 operations. I have attached as Exhibit Figueredo-Direct-1 a statement of
2 qualifications that further details my background and professional experience.
3
4 3. Q. HAVE YOU SUBMITTED PREPARED TESTIMONY WITH THE
5 PUBLIC UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
6 A. Yes, I have testified in a number of proceedings before the Public Utilities
7 Commission of Nevada (“Commission”). My most recent general rate case
8 (“GRC”) testimony was in Nevada Power’s 2017 GRC , Docket No. 17-06003.
9
10 4. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
11 A. My testimony addresses vehicle replacement investment costs completed since
12 Sierra’s 2016 GRC, Docket No. 16-06006. Specifically, I discuss investment in d/b/a NV Energy 13 vehicles since the close of the certification period in the 2016 GRC through the Nevada Power Company Company Power Nevada Sierra Pacific Power Company Pacific PowerSierra Company
14 end of the test period for this GRC (June 01, 2016 – December 31, 2018), as well and
15 as vehicle replacements completed in January and February of 2019, and
16 estimated through May 31, 2019, the close of the certification period. I provide
17 specific information regarding the largest categories of investments for the Fleet
18 Services department, the buyout of vehicle lease financial arrangements at the
19 point of lease contract expirations, and the acquisition of new vehicles to replace
20 units that have exceeded their life cycles. Combined, these expenditures represent
21 approximately $2.3 million in plant investment allocated to Sierra through May
22 31, 2019.
23
24
25 Figueredo– DIRECT 2
Page 54 of 250
1 Table Figueredo Direct-1below provides costs for the test period as of December
2 31, 2018 and costs for the certification period of January 1, 2019 through May
3 31, 2019.
4 TABLE FIGUEREDO DIRECT-1
Additions Additions 5 Total Fleet Division Jun-16 to Jan-19 to Additions 6 Dec-18 May-19
7 Fleet Investments $2,325,656 $0 $2,325,656
8
9 5. Q. ARE YOU SPONSORING ANY EXHIBITS TO YOUR PREPARED
10 DIRECT TESTIMONY?
11 A. Yes, I am sponsoring the following exhibit:
12 . Exhibit Figueredo-Direct-1–Statement of Qualifications d/b/a NV Energy 13 Nevada Power Company Company Power Nevada Sierra Pacific Power Company Pacific PowerSierra Company
14 II. TESTIMONY SUPPORTING STATEMENTS and
15 6. Q. WHY HAS SIERRA REPLACED ANY VEHICLE AND FLEET
16 EQUIPMENT SINCE JUNE 1, 2016?
17 A. Sierra’s Fleet Services annually performs vehicle lifecycle analysis to gauge the
18 optimal replacement plan for each vehicle class to achieve the lowest total cost to
19 own and maintain these assets over their useful lives. Fleet Services works to
20 limit its capital expenditures for vehicle replacement by retaining these assets
21 through their full useful lifecycle. The average age of a Sierra vehicle is 9.1 years,
22 which compares favorably to the utility industry average of 6.3 years.
23
24
25 Figueredo– DIRECT 3
Page 55 of 250
1 7. Q. PLEASE DESCRIBE THE FINANCIAL ANALYSIS PERFORMED TO
2 DETERMINE WHETHER TO PURCHASE OR LEASE REPLACEMENT
3 VEHICLES AND OTHER FLEET EQUIPMENT.
4 A. Sierra’s Finance department uses a present worth of revenue requirement
5 (“PWRR”) model to assess the economic impact of different alternatives
6 including vehicle analysis. The PWRR model allows the Company to compare
7 the economic impact to the customer from buying versus leasing the vehicles, and
8 relies on inputs such as vehicle values, depreciation rates, capital costs, tax rates,
9 and lease contract terms. Between June 1, 2016 and December 31, 2018, 21 units
10 were purchased at a total cost of approximately $1 million. During the
11 certification period, no additional vehicles were purchased.
12 d/b/a NV Energy 13 8. Q. PLEASE DESCRIBE THE FINANCIAL ANALYSIS PERFORMED TO Nevada Power Company Company Power Nevada Sierra Pacific Power Company Pacific PowerSierra Company
14 EVALUATE OPPORTUNITIES FOR BUYING VEHICLE AND FLEET and
15 EQUIPMENT ASSETS UPON EXPIRATION OF EXISTING LEASES?
16 A. The same PWRR analysis is used to evaluate end-of-lease vehicle decisions.
17 Current asset values, lease expiration terms, sales tax rates, and depreciable life
18 information is incorporated into this analysis. Vehicle buyouts at the end of the
19 lease term were determined to result in the most favorable PWRR, allowing the
20 Company to avoid the higher costs associated with newer vehicles. During the
21 test period, a total of 60 units previously leased were purchased for approximately
22 $1.3 million. During the certification period, no lease agreements were bought
23 out, and so no leased vehicles were purchases.
24
25 Figueredo– DIRECT 4
Page 56 of 250
1 9. Q. DOES THIS CONCLUDE YOUR DIRECT TESTIMONY?
2 A. Yes.
3
4
5
6
7
8
9
10
11
12 d/b/a NV Energy 13 Nevada Power Company Company Power Nevada Sierra Pacific Power Company Pacific PowerSierra Company
14 and
15
16
17
18
19
20
21
22
23
24
25 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 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Sierra Pacific Power Company d/b/a NV Energy
3 2019 General Rate Case Docket No. 19-06___ 4 PREPARED DIRECT TESTIMONY OF 5 Jim DeFrates 6 Revenue Requirement 7 8 I. INTRODUCTION
9 1. Q. PLEASE STATE YOUR NAME, JOB TITLE, EMPLOYER AND BUSINESS
10 ADDRESS.
11 A. My name is Jim DeFrates. I am the Claims Manager for Nevada Power Company
12 d/b/a NV Energy (“Nevada Power”) and Sierra Pacific Power Company d/b/a NV 13 Energy (“Sierra” or the “Company,” and together with Nevada Power, the 14 “Companies”). My business address is 6226 West Sahara Avenue in Las Vegas, d/b/a NV Energy Nevada Power Company Company Power Nevada 15 Nevada. I am filing testimony on behalf of Sierra.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16
17 2. Q. PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND AND 18 EXPERIENCE. 19 A. I have worked at the Company since 1995 and, in August 2013, I was named Claims 20 Manager. I have worked in the claims industry for more than 29 years. More details 21 regarding my professional background and experience are set forth in my Statement 22 of Qualifications, included as Exhibit DeFrates-Direct-1. 23
24 3. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC 25 UTILITIES COMMISSION OF NEVADA (“COMMISSION”)? 26 27
28 DeFrates-DIRECT 1
Page 61 of 250
1 A. Yes I have. I have testified in Sierra’s 2016 general rate case ( Docket No. 16- 2 06006) and Nevada Power’s 2017 general rate case (Docket No. 17-06003) before 3 the Commission. 4
5 4. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS 6 PROCEEDING?
7 A. I support the costs included in plant in service related to claims, as well as the 8 annualizations of test period costs for insurance premiums set forth on Schedule H-
9 CERT-22.
10
11 II. CLAIMS PLANT IN SERVICE
12 5. Q. WHAT COSTS ARE INCLUDED IN PLANT IN SERVICE FOR CLAIMS? 13 A. Since the close of the certification period in Sierra’s 2016 general rate case, the 14 Company experienced $2,189,250 in uncompensated costs to replace plant that was d/b/a NV Energy Nevada Power Company Company Power Nevada 15 damaged by third parties. The Company estimates that an additional $74,137 will
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 be expended during the certification period for this case, January 1, 2019 through 17 May 31, 2019. These costs reflect the costs incurred to replace damaged plant, over 18 and above the amounts collected from the individual(s) responsible for damaging 19 the plant. These costs are included in the plant additions provided by Ms. Ellen 20 Fincher in Exhibit Fincher-Direct-2. 21
22 6. Q. PLEASE PROVIDE AN EXAMPLE OF THE TYPES OF CLAIMS THAT 23 ARE INCLUDED IN THESE COSTS ASSOCIATED WITH CLAIMS 24 PROJECTS.
25 A. Any claim where the Company was unable to collect 100 percent of the repairs 26 from the responsible party is included in the cost. Some examples include: hit and 27
28 DeFrates-DIRECT 2
Page 62 of 250
1 run accidents (where the responsible party is never identified), car accidents where 2 the responsible party’s insurance is insufficient to cover the cost of repairing or 3 replacing damaged equipment, and incidents for which the responsible party is 4 uninsured and has no assets to pay the cost of repairing or replacing damaged 5 equipment. 6
7 7. Q. HOW DOES THE COMPANY PURSUE A RESPONSIBLE PARTY WHEN 8 COMPANY EQUIPMENT IS DAMAGED OR DESTROYED?
9 A. The Claims department is notified when a third party causes damage to Company
10 property and equipment. The cause of the damage is documented and the
11 responsible party identified. After the repair work is completed and the charges
12 make their way through accounting, an invoice is generated and sent to the 13 responsible party and/or their insurer. The claim is pursued with the responsible 14 party and/or their insurance company until a collection is made. Should collection d/b/a NV Energy Nevada Power Company Company Power Nevada 15 efforts fail, actions are filed against the responsible party in the appropriate court.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 The amounts reflected above represent the uncollected costs of repairing or 17 replacing damaged Company property or equipment, after the reasonable 18 exhaustion of these remedies. 19 20 III. INSURANCE PREMIUM COSTS, SCHEDULE H-CERT-22
21 8. Q. PLEASE DESCRIBE THE INFORMATION REFLECTED ON SCHEDULE 22 H-CERT-22. 23 A. Schedule H-CERT-22 shows test period expense for insurance premiums as well 24 as annualizations of test period expense used to calculate revenue requirement. H- 25 CERT-22 shows a reduction in annualized costs of insurance of $125,000. These 26 27
28 DeFrates-DIRECT 3
Page 63 of 250
1 reductions show the continued cost-savings impacts of combining the Companies’ 2 insurance coverage with Berkshire Hathaway Energy (“BHE”) coverage. 3 4 The most notable adjustment on Schedule H-CERT-22 is the removal of all costs 5 associated with Directors and Officers Liability Insurance from annualized 6 expense. This adjustment reflects the expiration of the “tail policy” that extended 7 coverage for the six years following the close of the BHE transaction. The end of 8 the residual period for the tail policy is December 19, 2019. Thus the costs
9 associated with this coverage have been removed from cost of service.
10
11 The decrease in the annualized cost of excess liability insurance is primarily due to
12 the post-acquisition consolidation of the Companies’ excess liability coverage 13 under BHE excess liability policies. BHE’s coverage is provided by the same 14 insurance carrier used by Nevada Power under the same policy form. Coverage is d/b/a NV Energy Nevada Power Company Company Power Nevada 15 identical with the exception of the amount of the self-insured retention, which
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 increased under BHE’s policy. 17
18 9. Q. DOES THIS COMPLETE YOUR TESTIMONY? 19 A. Yes, it does. 20 21 22 23 24 25 26 27
28 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 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA 2 Sierra Pacific Power Company d/b/a NV Energy 3 2019 General Rate Case Docket No. 19-06____ 4 PREPARED DIRECT TESTIMONY OF 5 William Olsen 6 Revenue Requirement 7 8 I. INTRODUCTION 9 1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS ADDRESS 10 AND PARTY FOR WHOM YOU ARE FILING TESTIMONY. 11 A. My name is William Olsen. My current position is Vice President of Information 12 Technology and Chief Information Officer for Sierra Pacific Power Company
c Power Company c Power Company 13 d/b/a/ NV Energy (“Sierra” or the “Company”) and Nevada Power Company d/b/a 14 NV Energy (“Nevada Power” and together with Sierra, the “Companies). My d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 business address is 6226 W Sahara Ave in Las Vegas, Nevada. I am filing testimony
and Sierra Pacifi 16 on behalf of Sierra. 17 18 2. Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE IN THE 19 UTILITY INDUSTRY. 20 A. I joined the Companies in June 1988 and have worked for the Company for 21 approximately 31 years in the Information Technology Department that entire time. 22 I hold a Bachelor’s Degree in Computer Information Systems from DeVry Institute 23 of Technology, now DeVry University. A more complete statement is set forth in 24 Exhibit Olsen-Direct-1. 25 26 27
28 Olsen-DIRECT 1
Page 68 of 250 1 3. Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS VICE PRESIDENT 2 OF INFORMATION TECHNOLOGY. 3 A. As Vice President of Information Technology, my responsibilities include 4 developing strategy and then executing that strategy for Information Technology, 5 Telecommunications, Cyber Security, and Physical security for Sierra and Nevada 6 Power. I oversee direct reports in each of the above listed areas and for the 7 Information Technology Project Management Office. I coordinate with the other 8 business units to ensure that their technological needs are met in a cost-efficient, 9 secure manner. I am also the designated North American Electric Reliability 10 Council (“NERC”) Critical Infrastructure Protection (“CIP”) Senior Manager 11 responsible for overseeing and administering the CIP program. 12
c Power Company c Power Company 13 4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC 14 UTILITIES COMMISSION OF NEVADA (“COMMISSION”)? d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 A. Yes.
and Sierra Pacifi 16
17 5. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY? 18 A. I provide support for information technology infrastructure and application 19 investment projects completed since Sierra’s last rate case (May 31, 2016) and 20 planned through the certification period (May 31, 2019). 21
22 I provide support for the technology infrastructure projects and processes with costs 23 greater than $1.0 million or where the aggregate of multiple similar projects or 24 programs exceed $1.0 million. These infrastructure projects include four 25 “Evergreen” projects and one other business operations support project. Sierra’s 26 share of the investments is $6,407,964, to the electric operations. The Table Olsen- 27
28 Olsen-DIRECT 2
Page 69 of 250 1 Direct-1 below provides the cost of each project, as of May 31, 2019 and the 2 allocated total costs to Sierra. Additional detail about the Evergreen concept is 3 provided in Exhibit Olsen-Direct-2. 4
5 TABLE OLSEN-DIRECT-1 6 PROJECT DESCRIPTION TOTAL ELECTRIC 7 Network Infrastructure Evergreen $1,907,504 $1,587,272 AIX Disk Evergreen 1,221,789 1,016,675 8 Exchange, e-Vault and Lync Upgrade 1,008,372 839,086 9 Firewall/Appliance Evergreen 2,214,453 1,842,691 Infrastructure – Laptop PC Evergreen 1,348,652 1,122,240 10 Total $7,700,770 $6,407,964 11
12 I also provide support for four information technology applications projects
c Power Company c Power Company 13 completed since the close of the certification period in Sierra’s last rate case through 14
d/b/a NV Energy Energy NV d/b/a the certification period (May 31, 2019). I provide descriptions of four significant
Nevada Power Company Company Power Nevada 15 information technology projects with costs of approximately $1.0 million or more,
and Sierra Pacifi 16 or where the aggregate of multiple similar projects or programs exceeds $1.0 17 million. These four projects total a combined $6,912,908 to the electric operations. 18
19 TABLE OLSEN-DIRECT-2 20 PROJECT DESCRIPTION TOTAL ELECTRIC 21 Banner Data Reduction & Purge $2,982,019 $2,481,397 22 Portal Operations 1,133,133 942,902 UI Planner Implementation 2,562,746 2,132,512 23 T&D Work & Asset Mgmt Enh 1,629,690 1,356,097 24 Total $8,307,588 $6,912,908 25 26 27
28 Olsen-DIRECT 3
Page 70 of 250 1 6. Q. ARE YOU SPONSORING ANY EXHIBITS? 2 A. Yes, I am sponsoring the following Exhibits: 3 Exhibit Olsen-Direct-1 Statement of Qualifications 4 Exhibit Olsen-Direct-2 White Paper “Evergreen Process Benefits.” 5
6 II. INFORMATION TECHNOLOGY INFRASTRUCTURE PROJECTS
7 INFRASTRUCTURE PROJECT 1: 8 NETWORK INFRASTRUCTURE EVERGREEN
9 7. Q. PLEASE DESCRIBE THE NETWORK INFRASTRUCTURE 10 EVERGREEN PROCESS. 11 A. The Network Infrastructure Evergreen process is a long-established ongoing 12 process addressing information technology growth in a structured and cost-
c Power Company c Power Company 13 effective manner. The Network Infrastructure project ensures adequate application 14 performance and reliability through a scheduled technology refresh cycle. Funding d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 for this process is also managed through the standard capital budgeting process.
and Sierra Pacifi 16 The costs identified here are an aggregate of three separate evergreen process 17 groupings. The share of the costs allocable to Sierra’s electric customers is 18 $1,587,272. 19 20 8. Q. WHAT WERE THE DRIVING FACTORS FOR ESTABLISHING THE 21 EVERGREEN PROCESS? 22 A. Prior to the creation of the Evergreen process, upgrades to accommodate 23 information technology needs and resources were handled reactively and on a case 24 by case-by-case basis. The degradation in application performance prior to 25 upgrades being suggested resulted in significant decreases in productivity and was 26 very disruptive to normal business operations and to the budgeting process. 27
28 Olsen-DIRECT 4
Page 71 of 250 1 Adoption of the Evergreen process has achieved significant benefits including 2 reduced costs, improved utilization of computing resources, budget predictability, 3 and an improved application performance life cycle. Specifically, the standardized 4 technology refresh cycle, as presented in the white paper entitled “Evergreen 5 Process Benefits,” attached hereto as Exhibit Olsen-Direct-2, produced the 6 following benefits: 7 • Improved energy efficiency 8 • Improved density/physical space utilization 9 • Virtualization functionality implementation 10 • Performance stability 11 • Predictable, simplified budgeting 12 • Maintenance savings
c Power Company c Power Company 13 • Improved reliability and availability 14 • Enable new application functionality d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 • Non-disruptive operating system upgrades
and Sierra Pacifi 16 • Address normal growth trends 17 Gartner, Inc., a leading information technology research and advisory firm, 18 advocates that infrastructure computing resources be replaced on a regular basis. 19 We continue to track research in this area to ensure that we are in harmony with 20 industry practices. In summary, the Evergreen process ensures an adequate 21 computing infrastructure to support all applications resulting in improved 22 productivity. 23 24 25 26 27
28 Olsen-DIRECT 5
Page 72 of 250 1 9. Q. HOW OFTEN DO YOU REVIEW THE RECOMMENDED REFRESH 2 SCHEDULE TO ENSURE EQUIPMENT IS NOT REPLACED PRIOR TO 3 THE END OF ITS USEFUL LIFE? 4 A. We review the refresh cycle schedule for these products approximately every three 5 years to ensure equipment is not being replaced prematurely. We have found our 6 current replacement schedule balances the cost of procurement and implementation 7 against that of operational effectiveness and loss of productivity through 8 performance degradation. 9
10 10. Q. WHEN WERE THE NETWORK INFRASTRUCTURE EVERGREEN 11 UPGRADES COMPLETED? 12 A. The network infrastructure evergreen process is managed in discrete, annual budget
c Power Company c Power Company 13 groupings/projects. Network infrastructure upgrades are performed and 14 implemented throughout the year. Only network infrastructure components d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 identified as “used and useful” as of May 31, 2019 are included in plant in service.
and Sierra Pacifi 16 17 INFRASTRUCTURE PROJECT 2: AIX DISK EVERGREEN 18
19 11. Q. PLEASE DESCRIBE THE AIX DISK EVERGREEN PROCESS.
20 A. Like the Network Infrastructure Evergreen projects, the AIX Disk Evergreen 21 process has been in place since 2000 to address information technology growth and 22 to ensure adequate application performance through a scheduled technology refresh 23 cycle. AIX disk is Tier 1 data storage for the Companies’ critical systems. Funding 24 for this process is managed through the standard capital budgeting process. The 25 costs identified here are the aggregate of four separate Evergreen process groupings 26 27
28 Olsen-DIRECT 6
Page 73 of 250 1 for disk technologies since the last rate cycle. The costs allocable to Sierra’s electric 2 operations are $1,016,675. 3
4 12. Q. WERE THE DRIVING FACTORS FOR ESTABLISHING THE AIX DISK 5 PROJECT THE SAME AS THE OTHER EVERGREEN PROJECTS? 6 A. Yes, the merits of the Evergreen process described in Q&A 8 above apply equally 7 to the AIX Disk Evergreen project. Prior to the creation of the Evergreen process, 8 upgrades to accommodate growth and ensure adequate application reliability and 9 performance were handled on a case-by-case basis, primarily in a reactive mode. 10 The degradation in performance prior to an upgrade being suggested resulted in 11 significant decreases in productivity and was very disruptive to normal business 12 operations and to the budgeting process.
c Power Company c Power Company 13
14 13. Q. HOW OFTEN DO YOU REVIEW THE RECOMMENDED REFRESH d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 SCHEDULE TO ENSURE EQUIPMENT IS NOT REPLACED PRIOR TO
and Sierra Pacifi 16 THE END OF ITS USEFUL LIFE? 17 A. The refresh cycle schedule for these products is reviewed approximately every three 18 years to ensure equipment is not being replaced prematurely. The most recent 19 recommendations and research from analysts and manufacturers is to accelerate 20 replacement schedules to reduce operating costs associated with electric usage. The 21 Company has found its current replacement schedule continues to appropriately 22 balance the cost of procurement and implementation against that of operation and 23 loss of productivity through performance degradation. 24 25 26 27
28 Olsen-DIRECT 7
Page 74 of 250 1 14. Q. WHEN WERE THE AIX DISK EVERGREEN UPGRADES COMPLETED? 2 A. The AIX Disk Evergreen process is managed in discrete, annual budget 3 groupings/projects based on separate disk storage technologies, high-end Storage 4 Area Network (“SAN”)-based storage and mid-range SAN and Network Attached 5 Storage-based storage to accommodate varying performance requirements. Disk 6 storage upgrades are performed and implemented throughout the year. Only disk 7 storage currently identified as “used and useful” is included in plant in service. 8
9 INFRASTRUCTURE PROJECT 3: EXCHANGE, e-VAULT AND LYNC UPGRADE 10 11 15. Q. PLEASE DESCRIBE THE EXCHANGE, e-VAULT AND LYNC UPGRADE. 12 A. Microsoft Exchange is the email system that the Companies use. As part of the
c Power Company c Power Company 13 system, the Companies have vaulting capabilities through Veritas e-Vault for 14 saving emails for long term archiving. In most cases, email vaulting is used for d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 legal or compliance reasons. Microsoft Exchange is also integrated with Microsoft
and Sierra Pacifi 16 Lync, which is used for internal messaging. Because the systems are interdependent 17 and closely tied, the scope of this project includes the software upgrade of these 18 three products and the underlining hardware. The Exchange environment was 19 upgraded from a 2010 to 2016 version, while e-Vault was upgraded from version 20 11 to version 12.3. Lync was upgraded to Skype for Business, version 2015, and 21 provided additional video conferencing functions. The project consisted of 22 hardware purchases, installation and configuration, as well as migrating internal 23 Sierra users to the upgraded platforms. The fax tool, Faxcom, was also upgraded to 24 comply with the Exchange 2016 environment, and minor upgrades to the phone 25 system were completed to integrate Skype for Business. The costs estimated 26 27
28 Olsen-DIRECT 8
Page 75 of 250 1 through the certification period allocable to Sierra’s electric operations are 2 $839,086. 3
4 16. Q. WHAT WERE THE DRIVING FACTORS FOR THE EXCHANGE, e- 5 VAULT AND LYNC UPGRADE PROJECT? 6 A. The driving factor for the Exchange, e-Vault and Lync upgrade project was 7 Microsoft’s decision to no longer support the then-current versions of Exchange, e- 8 Vault and Lync after January 2020. Upgrading the software to the newer versions 9 was necessary to ensure that cyber security patches are available upon release, to 10 improve capabilities and functionality associated with the new version, to continue 11 the tight integrations between Exchange and other desktop applications, and to 12 ensure support would be available to resolve problems should they arise.
c Power Company c Power Company 13
14 17. Q. HOW OFTEN DO YOU REVIEW THE UPGRADE SCHEDULE TO d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 ENSURE SOFTWARE IS NOT REPLACED PRIOR TO THE END OF ITS
and Sierra Pacifi 16 USEFUL LIFE? 17 A. The upgrade cycle for these products is reviewed approximately every five years to 18 ensure software is not being upgraded prematurely. Microsoft software lifecycle is 19 the driving factor for the timing of upgrades. To continue Microsoft support and 20 ensure system security, the next upgrade must be completed by October, 2025. 21
22 18. Q. WHEN WERE THE EXCHANGE, e-VAULT AND LYNC UPGRADES 23 COMPLETED? 24 A. The Exchange, e-Vault and Lync upgrades were completed on May 15, 2019. 25 26 27
28 Olsen-DIRECT 9
Page 76 of 250 INFRASTRUCTURE PROJECT 4: 1 FIREWALL/APPLIANCE EVERGREEN 2 19. Q. PLEASE DESCRIBE THE FIREWALL/APPLIANCE EVERGREEN 3 PROCESS.
4 A. The Firewall/Appliance Evergreen process was put in place in the early 2000s to 5 address growth in the information technology needs and to ensure adequate 6 application performance through a scheduled technology refresh cycle. Funding for 7 this process is managed through the standard capital budgeting process. The costs 8 identified here are the aggregate of five separate evergreen process groupings for 9 disk technologies since the last rate cycle. The cost of the project allocable to 10 Sierra’s electric operations through December 31, 2018 was $1,742,191, with 11 $100,499 estimated through the close of the certification period. 12
c Power Company c Power Company 13 20. Q. WERE THE DRIVING FACTORS FOR ESTABLISHING THE 14 EVERGREEN PROCESS FOR THIS PROJECT THE SAME AS FOR THE d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 OTHER EVERGREEN PROJECTS?
and Sierra Pacifi 16 A. Yes. 17
18 21. Q. HOW OFTEN DO YOU REVIEW THE RECOMMENDED REFRESH 19 SCHEDULE TO ENSURE EQUIPMENT IS NOT REPLACED PRIOR TO 20 THE END OF ITS USEFUL LIFE?
21 A. The refresh cycle schedule for these products is reviewed approximately every three 22 years to ensure equipment is not being replaced prematurely. The most recent 23 recommendations and research from analysts and manufacturers is to accelerate 24 replacement schedules to reduce operating costs associated with electric usage. Our 25 current replacement schedule balances the cost of procurement and implementation 26 27
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Page 77 of 250 1 against that of operational needs and loss of productivity through performance 2 degradation. 3
4 22. Q. WHEN WERE THE FIREWALL/APPLIANCE UPGRADES IDENTIFIED 5 COMPLETED? 6 A. The Firewall/Appliance Evergreen process is managed in discrete, annual budget 7 groupings/projects based on separate Firewall and Appliance upgrades to 8 accommodate new technologies. Firewall and Appliance upgrades are performed 9 and implemented throughout the year. Only Firewall and Appliances currently 10 identified as “used and useful” are included in plant in service. 11
12 INFRASTRUCTURE PROJECT 5: LAPTOP AND PC REPLACEMENT EVERGREEN c Power Company c Power Company 13 14 23. Q. PLEASE DESCRIBE THE LAPTOP PC EVERGREEN PROCESS. d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 A. The Laptop and PC Evergreen has been in place since 2000, and addresses growth
and Sierra Pacifi 16 in information technology needs through a scheduled technology refresh cycle. 17 Funding for this process is managed through the standard capital budgeting process. 18 The costs identified here are the aggregate of twelve separate evergreen process 19 groupings since the last rate cycle. The cost of the project allocable to Sierra’s 20 electric operations through December 31, 2018 was $964,101, with $158,139 21 estimated through the close of the certification period. 22 23 24 25 26 27
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Page 78 of 250 1 24. Q. WERE THE DRIVING FACTORS FOR ESTABLISHING THE 2 EVERGREEN PROCESS FOR THIS PROJECT THE SAME AS FOR THE 3 OTHER EVERGREEN PROJECTS? 4 A. Yes, the merits of the Evergreen process described in Q&A 8 above apply equally 5 to the Laptop and PC Evergreen project. Prior to the creation of the Evergreen 6 process, upgrades to accommodate growth and ensure adequate application 7 performance were handled on a case-by-case basis, primarily in a reactive mode. 8
9 25. Q. HOW OFTEN DO YOU REVIEW THE RECOMMENDED REFRESH 10 SCHEDULE TO ENSURE EQUIPMENT IS NOT REPLACED PRIOR TO 11 THE END OF ITS USEFUL LIFE? 12 A. The refresh cycle schedule for these products is reviewed approximately every three
c Power Company c Power Company 13 years to ensure equipment is not being replaced prematurely. We have found our 14 current replacement schedule to balance the cost of procurement and d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 implementation against that of operational needs and loss of productivity through
and Sierra Pacifi 16 performance degradation. 17
18 26. Q. WHEN WERE THE LAPTOP AND PC UPGRADES IDENTIFIED 19 COMPLETED? 20 A. The Evergreen process is managed in discrete, annual budget groupings/projects 21 based on separate laptop and PC upgrades to accommodate new technologies and 22 varying performance requirements. Laptop and PC upgrades are performed and 23 implemented throughout the year. Only laptops and PCs currently identified as 24 “used and useful” are included in plant in service. 25 26 27
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Page 79 of 250 1 III. INFORMATION TECHNOLOGY APPLICATIONS PROJECTS DESCRIPTIONS
2 APPLICATION PROJECT 1: 3 THE BANNER DATA REDUCTION AND PURGE 4 27. Q. PLEASE DESCRIBE THE BANNER DATA REDUCTION AND PURGE 5 PROJECT (PHASE I AND II) 6 A. This project allowed the Companies to remove aged data from the Companies’ 7 customer information system (“CIS”) in compliance with Company and legal 8 standards. The Banner CIS Application was put in place 18 years ago. Throughout
9 this time, it has accumulated over a billion rows of various forms of data. The 10 Banner CIS Application did not include an automated purge function. Due to the 11 volume of data stored within the system, a purge of obsolete data was needed to 12 satisfy a number of different business objectives including: compliance with
c Power Company c Power Company 13 corporate records and retention policies; increased system performance and 14 usability; assistance in achieving Service Level Agreement (“SLA”) deadlines; d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 improvements in Banner jobs performance run times; reduced disk storage needs
and Sierra Pacifi 16 and wait times to clone environments; and reduced exposure to data breaches and 17 tampering. The Banner Data Reduction project provided the engine and supporting 18 structure for the reduction in physical storage. It also provided the framework for 19 the successful completion of the Phases 1 and II of the Purge Process projects and 20 set the conditions for a rules-based support that defined the table hierarchy structure 21 that allows the purge process to occur. Banner Purge Phase I included the purge of 22 most of the financial transaction data and account-related data in addition to the 23 purge of some stand-alone table data. Banner Purge Phase II addressed the 24 requirements for purging data for customer-related records containing only a 25 customer code, accounts that have bad debt, and accounts in master summary 26 billing groups. Phase II also included mapping for the purge of several account- 27
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Page 80 of 250 1 based and standalone tables that were not included in Phase I. Actual expenditures 2 on this collection of projects allocable to Sierra’s electric operations were as 3 follows: Banner Data Reduction (PID 0010003592) $1,342,599; Phase I 4 (0010007781) $570,965; and Phase II (0010007145) $567,833. 5
6 28. Q. WHY WAS THE PROJECT NECESSARY? 7 A. Banner is the main repository for critical and operational data including billing and 8 customer information. Due to legal and corporate records and retention policies, 9 any records with no activity over a certain period of time (currently set at seven 10 years) need to be permanently removed from the system. This period of time needs 11 to be configurable such that the appropriate internal business stakeholders can 12 determine and modify the threshold for records retention. Implementing this
c Power Company c Power Company 13 compliance item will minimize the Company’s exposure to data breaches, potential 14 penalties and lawsuits. d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15
and Sierra Pacifi 16 The Banner CIS Application is operated and maintained with a set of guidelines 17 and SLAs to ensure optimal system performance. Among these SLAs are 18 performance standards around the time it takes to process the Banner batch jobs. 19 Batch jobs need to be completed in less than 24 hours each day. From a maintenance 20 and support perspective, the growth in data volume has resulted in a need to 21 regularly increase the disk storage capacity and has impacted the processing time 22 needed to clone the data from production to the testing and training environments. 23 Purging this data can reduce and maintain the disk storage needs at a constant level, 24 enable faster data cloning times, and increase the accessibility of the data through 25 Banner forms. 26 27
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Page 81 of 250 1 Due to the highly complex nature of the Banner CIS Application, this project was 2 needed to insure the integrity of the system and table relationships as data is being 3 removed and purged. There were tables that had in excess of over one billion rows. 4 This data needed to be removed and purged for better system performance and to 5 satisfy retention requirements associated with NV Energy’s Records Management 6 Policy. 7
8 Compliance/audit requirements - The necessity of this project was to review the 9 relationship of Banner CIS Application tables for legal/compliance data and purge 10 the current Banner Data which is older than the criteria defined by the Record 11 management policy. This project helps minimize exposure to data breaches and 12 tampering, which helps protect both our customers from identity theft and the
c Power Company c Power Company 13 Companies from potential penalties or lawsuits. 14 d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 29. Q. WHAT ARE THE ACTUAL BENEFITS RESULTING FROM THE
and Sierra Pacifi 16 PROJECT? 17 A. In addition to satisfying important compliance requirements, this project achieved 18 operational benefits, improving Banner batch job run time performance by reducing 19 the number of records and the overall database size. This project helped batch jobs 20 complete in less than 24 hours as a whole on a daily basis. Also, SLA processing 21 time was improved, disk space was reduced, and the demand of additional disk 22 space and the processing time for cloning production data to lower environments 23 was eased. As of April 11, 2019, 144.7 gigabytes of data have been purged from 24 the northern storage environment. Finally, the project has added functionality to 25 allow users to flag accounts that should be exempt from the data purging process. 26 This is necessary to maintain the data integrity for accounts that may be associated 27
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Page 82 of 250 1 with a legal hold, ongoing accounting analysis, billing investigations, or other 2 business activity that may still be pending. 3
4 30. Q. WHEN DID THE PROJECT GO INTO SERVICE? 5 A. The Phase I release was completed on June 8, 2018 and Phase II release was 6 completed on July 12, 2018. 7 APPLICATION PROJECT 2: 8 PORTAL OPERATIONS 9 31. Q. PLEASE DESCRIBE THE PORTAL OPERATIONS PROGRAM 10 A. The portal operations program is an annual project that develops and upgrades the 11 underlying digital solutions platform and Electric Delivery leadership dashboard as 12 part of the digital solution energy portal that provides operational metrics accessible
c Power Company c Power Company 13 to business units. The operational metrics within the application include safety, 14 financial, and operations specific to the business unit. This allows the operational d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 metrics to be available in one consolidated dashboard and with sufficient specificity
and Sierra Pacifi 16 that is easily drillable to analyze and view the information allowing for better data- 17 driven decisions. This platform allows the information to be mobile-accessible and 18 is fully scalable to accommodate growth. Migration of platform and application 19 upgrades are performed and implemented throughout the year. The costs of four 20 related projects have been aggregated, and the costs allocable to Sierra’s electric 21 division is $942,902. 22 23 32. Q. WHY WAS THE PROJECT NECESSARY? 24 A. Prior to this platform and application, the operational performance information was 25 gathered, formatted and stored in disparate places, requiring users to expend 26 significant manual effort to compile when needed. The data was not visible to the 27
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Page 83 of 250 1 electric delivery employees, and so was not usable as a measurement against 2 targets, or available to quickly identify areas needing improvement and target 3 corrective actions. The project integrates data from multiple sources and transforms 4 data into information that provides timely and relevant information so that 5 corrective actions and decisions can be acted upon both by managements and 6 employees. It allows for measurement and improvement in key areas like 7 operational safety using indicators such as OSHA recordable events, crew audits, 8 preventable vehicle accidents, and environmental metrics (e.g., avian fatalities or 9 transformer leaks), financial performance (e.g., actual spend compared to 10 commitments), and it shows the performance for an operational area against the 11 Business Plan. 12
c Power Company c Power Company 13 33. Q. WHAT ARE THE ACTUAL BENEFITS RESULTING FROM THE 14 PROJECT? d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 A. Benefits include a significant reduction in manual effort spent obtaining important
and Sierra Pacifi 16 operational data, increased accuracy of performance information, and the ability to 17 assess in real-time critical success measures, allowing for focus on key areas 18 requiring corrective action. Information is now available for analysis that was not 19 previously possible. Annual upgrades to the platform and application are needed to 20 remain current with technology direction, enable new application functionality and 21 to ensure no degradation in application availability and performance. 22 Enhancements are also necessary to remain compliant with all security-related 23 initiatives. 24 25 26 27
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Page 84 of 250 1 34. Q. WHEN DID THE PROJECT GO INTO SERVICE? 2 A. This program includes multiple projects with multiple release dates since June 1, 3 2016. The last release during the test period went into service December 31, 2018. 4 APPLICATION PROJECT 3: 5 UI PLANNER (UIRM NORTH) 6 35. Q. WHY WAS THE UIRM NORTH PROJECT NECESSARY? 7 A. With increased compliance requirements and focus on performance metrics, the 8 Companies identified a need to replace reliance on using personal applications (e.g., 9 Microsoft Excel-based application) for core budget development, financial 10 analysis, and forecasting business needs with a system-based solution that would 11 improve the integrity of results, enhance efficiency, support additional functionality 12 and allow for centralized adjustments. The solution that was selected to accomplish
c Power Company c Power Company 13 these goals was the Utilities International Responsibility Model or UIRM. 14 d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 The UIRM solution has allowed the Companies to no longer rely on Microsoft
and Sierra Pacifi 16 Excel for a significant portion of the budget development process. It provides a 17 uniform system with standardized calculation logic accessible to general users. The 18 solution reduced the likelihood of human errors more common to spreadsheet 19 applications such as formula inconsistencies, omitted cells, double counting of 20 cells, unintended user changes, etc. Moreover, by standardizing the process and 21 centrally handling all of the calculations separate from the user interface, the 22 integrity of results was improved. 23
24 The UIRM solution also helped to enhance efficiencies by reducing the amount of 25 manual labor required and automating the consolidation process. For example, the 26 system replaced our process of manually entering into Excel the labor budget at the 27
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Page 85 of 250 1 individual employee level. Instead, the system interfaces with the human resource 2 system database to directly provide information such as job description, wage rate, 3 employee name and other relevant data. This allows for the labor budget to be 4 centered on a less granular level such as each unique job code without losing the 5 individual data. As another example, the system can automatically consolidate the 6 budget across the business. This replaces the need for technical support personnel 7 to launch manual and much more time consuming processes each time budget 8 changes are made. 9
10 The UIRM project also provides additional functionality. It provides the ability to 11 leverage different system interfaces for different aspects of the budget and forecast 12 process (using the prior example, by headcount, labor by job code, and non-labor)
c Power Company c Power Company 13 separately using interfaces that are tailored for each aspect. It automatically creates 14
d/b/a NV Energy Energy NV d/b/a new rows to add the appropriate overheads and to allocate costs across Companies.
Nevada Power Company Company Power Nevada 15 It provides interactive reporting functionality to facilitate a wide variety of analysis.
and Sierra Pacifi 16 The project also allows for global adjustments to be made centrally and have the 17 effects of those adjustments automatically update throughout the budget and 18 forecast. Examples of this functionality include changing inflationary rate 19 assumptions, labor overhead rates, and labor merit increases. Each of these 20 assumptions can be changed centrally and automatically flow throughout the 21 budget. This provides greater flexibility and significantly improves efficiency in 22 the event assumptions change after the initial preparation and consolidation of 23 financial data. 24 25 26 27
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Page 86 of 250 1 36. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 2 A. The cost of the project allocable to Sierra’s electric operations was $2,132,512. The 3 project was placed in-service on January 1, 2017. 4
5 37. Q. WHAT WORK WAS COMPLETED FOR THE PROJECT? 6 A. The UIRM was implemented in 2016 and used in the development of the 7 Company’s annual budget and associated 10-year business planning since. 8
9 APPLICATION PROJECT 4: 10 T&D WORK AND ASSET MGMT ENH 11 38. Q. PLEASE DESCRIBE THE T&D WORK AND ASSET MANAGEMENT 12 ENHANCEMENT PROJECT.
c Power Company c Power Company 13 A. The Transmission and Distribution (“T&D”) Work and Asset Management 14 Enhancement project supported the technology needs for distribution capital and d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 maintenance work done by Electric Delivery. Additionally, the project served the
and Sierra Pacifi 16 needs of the maintenance work done by the gas delivery business unit. The project 17 implemented system improvements (capital enhancements) within the T&D Work 18 & Asset Management systems (Maximo, Ventyx, ESRI, Microstrategy). The costs 19 of four related projects have been aggregated, and the costs allocable to Sierra’s 20 electric division is $1,356,097. 21
22 39. Q. WHY WAS THE PROJECT NECESSARY? 23 A. The improvements implemented as part of the T&D Work and Asset Management 24 Enhancement project for both electric and gas delivery helped enhance the existing 25 software with additional functionality such that the software was able to perform 26 tasks which it was previously not designed to perform. In addition, the project 27
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Page 87 of 250 1 enabled both the electric and gas operations to launch new technology-based 2 initiatives that helped them keep pace with changing regulatory needs, safety 3 requirements and business processes. 4
5 40. Q. WHAT ARE THE ACTUAL BENEFITS RESULTING FROM THE 6 PROJECT? 7 A. The T&D Work and Asset Management Enhancement project provided both 8 electric and gas delivery businesses with better capabilities towards regulatory and 9 safety compliance by implementing identified initiatives in both these areas. The 10 project improved operational efficiency and customer satisfaction. New and 11 improved business process changes were also implemented that helped align 12 systems with the changing business environment. These improvements helped
c Power Company c Power Company 13 build better controls and risk mitigation strategies. 14 d/b/a NV Energy Energy NV d/b/a
Nevada Power Company Company Power Nevada 15 41. Q. WHEN DID THE PROJECT GO INTO SERVICE?
and Sierra Pacifi 16 A. The project included multiple releases between 2016 and 2018. 17
18 42. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY? 19 A. Yes. 20 21 22 23 24 25 26 27
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Page 88 of 250 džŚŝďŝƚKůƐĞŶͲŝƌĞĐƚͲϭ WĂŐĞϭŽĨϭ
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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.
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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.
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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.
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SCOTT TALBOT
Page 96 of 250 1 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA 2 Sierra Pacific Power Company d/b/a NV Energy 3 2019 General Rate Case Docket No. 19-06___ 4 PREPARED DIRECT TESTIMONY OF 5 Scott Talbot 6 Revenue Requirement 7
8 1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS ADDRESS 9 AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
10 A. My name is Scott Talbot. I am the Director of Telecommunications (“Telecom”)
11 for Sierra Pacific Power Company d/b/a NV Energy (“Sierra” or the “Company”)
12 and Nevada Power Company d/b/a NV Energy (“Nevada Power” and, together with 13 Sierra, the “Companies”). My business address is 6100 Neil Road in Reno, Nevada. 14 I am filing testimony in this proceeding on behalf of Sierra. d/b/a NV Energy Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 2. Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE IN THE 17 UTILITY INDUSTRY. 18 A. I have over six years of experience at Sierra and Nevada Power. A complete 19 description of my professional background and experience is included in my 20 Statement of Qualifications, Exhibit Talbot-Direct-1. 21
22 3. Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS DIRECTOR, 23 TELECOMMUNICATIONS. 24 A. As Director of Telecommunications, my responsibilities include managing a staff 25 of engineers, technicians and professional staff that design, build and operate the 26 Companies’ telecommunications network and facilities. Telecommunication 27
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1 facilities include telephone, fiber optic, microwave, power line carrier, wide area 2 networking, tele-protection and radio systems necessary to operate the Companies’ 3 utility business and to control the operations of the electric (and gas) infrastructure. 4 5 4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC 6 UTILITIES COMMISSION OF NEVADA (“COMMISSION”)? 7 A. No, I have not. 8
9 5. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
10 A. I support the reasonableness of Sierra’s investment in telecommunications
11 networks and facilities. My testimony specifically discusses the six individual
12 major projects under my responsibility listed in Table Talbot-Direct-1. Five of these 13 projects cost more than $1 million and one cost less than $1 million. The 14 telecommunications group has completed many capital projects less than $1 million d/b/a NV Energy Nevada Power Company Company Power Nevada 15 since May 31, 2016 that are not listed below.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Table Talbot-Direct-1 ELECTRIC 17 PROJECT DESCRIPTION TOTAL Multi-Protocol Label Switching (MPLS) $4,701,199 $3,911,962 18 Southwest Microwave Path Upgrade $2,868,203 $2,868,203 19 Telecom Work and Asset Management $3,055,061 $2,542,177 LV to Reno Dense Wave Division Multiplexing $1,338,361 $1,113,677 20 (DWDM) Comm Battery & Charger Replacement $1,070,248 $890,575 21 Call Center Expansion $911,497 $758,475 22 Total $13,944,569 $12,085,069 23 24 25
26 27
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1 6. Q. WHY ARE ONLY MAJOR PROJECTS SPECIFICALLY DISCUSSED IN 2 YOUR TESTIMONY? 3 A. Testimony-style descriptions of each and every project completed by the 4 telecommunications team since June 1, 2016, would take hundreds of pages, and 5 the documentation surrounding each project is so voluminous that its value at 6 hearing would be severely diminished. As I understand it, in general rate 7 proceedings the Commission wants to see prepared direct testimony addressing the 8 details of and supporting expenditures on major projects. In recent general rate
9 cases the Commission has accepted the $1.0 million demarcation as appropriate for
10 determining whether a project is “major.” While not addressed in detail in my
11 prepared direct testimony, my group has prepared project binders for smaller
12 projects completed since June 1, 2016. As has been the Companies’ practice for 13 many rate case cycles, those binders (now in electronic form) are available for 14 review on the day this general rate review filing is made. d/b/a NV Energy Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 7. Q. ARE YOU SPONSORING ANY EXHIBITS? 17 A. Yes. I am sponsoring the following Exhibits: 18 Exhibit Talbot-Direct-1 Statement of Qualifications 19
20 TELECOMMUNICATIONS PROJECT I: MULTI PROTOCOL LABEL SWITCHING CSY1094 AND CCO1048 21 22 8. Q. PLEASE DESCRIBE THE MULTI-PROTOCOL LABEL SWITCHING 23 PROJECT (“MPLS”). 24 A. This project involved the installation of a next-generation Ethernet/Internet 25 Protocol (IP)-based Wide Area Network (“WAN”) throughout Sierra’s service 26 territory. Upon completion of the northern project, the infrastructures in northern 27
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1 and southern systems are consistent with one another and are able to serve as the 2 platform for delivering services such as telephone over internet - also called Voice 3 over Internet Protocol (“VoIP”), video and access control for substation security, 4 mobile radio communications, automated metering infrastructure, distribution 5 automation, and remote relay management for fault protection of electric 6 transmission lines. This project is part of an overall strategy to move the network to 7 a standardized IP platform.
8
9 9. Q. WHY WAS THE PROJECT NECESSARY?
10 A. The former northern Ethernet network was built on legacy synchronous optical
11 networking or “SONET” equipment, which became limited in its ability to
12 accommodate new applications and increasing bandwidth requirements. It is also 13 obsolete and discontinued equipment. The new MPLS WAN serves as a platform 14 that provides System Control the ability to isolate networks for distribution d/b/a NV Energy Nevada Power Company Company Power Nevada 15 automation and remote substation equipment access and isolation necessary for
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 North American Electric Reliability Corporation (“NERC”) compliance. Initiatives 17 such as NERC Critical Infrastructure Protection (“CIP”) compliance and the Land 18 Mobile Radio System Replacement depend on a reliable, secure and flexible 19 network. It also aligns NV Energy’s current network to industry standards to ensure 20 criteria of scalability, reliability and modularity. Deploying MPLS has allowed the 21 Companies’ Telecom department to transport more data for all aforementioned 22 applications using existing communications pipes in accordance with IP-based 23 technology. 24 25 26 27
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1 10. Q. WHAT WAS THE TOTAL COST OF THIS PROJECT? 2 A. The total cost of the project was $4,701,199 (with AFUDC). The system was 3 completed December 31, 2018 and is used and useful in the provision of utility 4 service. 5
6 TELECOMMUNICATIONS PROJECT II: SOUTHWEST MICROWAVE PATH UPGRADE CCOA67 7 8 11. Q. PLEASE DESCRIBE THE SOUTHWEST MICROWAVE PATH
9 UPGRADE PROJECT.
10 A. The Southwest Microwave Path Upgrade project replaced and upgraded the
11 microwave and multiplexing equipment in Sierra’s southwest service territory
12 network, which includes Fort Churchill, Hawthorne and Tonopah, to increase 13 bandwidth, reliability and route redundancy of the communications network.
14 d/b/a NV Energy Nevada Power Company Company Power Nevada 15 12. Q. WHY WAS THE PROJECT NECESSARY?
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 A. The project was required to increase bandwidth and provide redundancy for the 17 reliability of this portion of the communications network. The project provided 18 communication links, status control and data acquisition (SCADA)/remote terminal
19 unit (RTU) traffic, communication-aided relaying protection, phones, network 20 access and land mobile radio backhaul at substations and communication sites. 21
22 13. Q. WHAT WAS THE TOTAL COST OF THIS PROJECT? 23 A. The total cost of the project was $2,868,203 (with AFUDC). The system was 24 completed on July 31, 2017 and is used and useful in the provision of utility service. 25 26 27
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1 TELECOMMUNICATIONS PROJECT III: TELECOM WORK AND ASSET MANAGEMENT CSY1097 AND CSY1479 2 3 14. Q. PLEASE DESCRIBE THE TELECOM WORK AND ASSET 4 MANAGEMENT (WAM) SYSTEM PROJECT. 5 A. The Telecom WAM project is a multi-year technology project divided into phases 6 to provide a strategic long-term solution for leveraging capital investments, 7 ensuring asset performance optimization through best practices, and provide 8 reductions in operational maintenance costs for the Telecom department.
9
10 Phase I laid the initial technology foundation by implementing the Trouble (outage)
11 related solution by establishing a Network Operations Center (“NOC”) for
12 centralized monitoring and diagnostics support. It provides for recording, tracking 13 and resolving trouble tickets. Asset data collection was also initiated to build a 14 Telecom asset repository database on the asset data model to provide tracking and d/b/a NV Energy Nevada Power Company Company Power Nevada 15 management of assets as well as serve as input to future WAM Telecom
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 implementations. 17 18 Phase II implements the capital construction business processes, and extends the 19 previously implemented IBM Maximo and Ventyx Service suite toolset to map all 20 aspects of Telecom’s capital business processes – from project initiation to design, 21 estimating, scheduling, construction, and closing on the already existing enterprise 22 WAM toolset of Maximo and Ventyx. The overarching goal of Phase II was to 23 develop consolidated capital processes which better serve internal customers, 24 improve workforce performance and streamline Telecom capital operations. 25 26 27
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1 15. Q. WHY WAS THE PROJECT NECESSARY? 2 A. This project provided a technology-based solution to a centralized operations center 3 for monitoring alarms and response activities to maintain established operational 4 levels of services, and provided a view across multiple event monitoring and 5 incident management systems to quickly assess the impact of faults and/or incidents 6 on customers, infrastructure and operations. In Phases I and II, Telecom continued 7 to work on improving outdated work procedures that were heavily reliant on 8 manual processes, hand offs, paper documentation, manual document routing and
9 white board scheduling, all of which did not provide the work management and
10 asset tracking features required to better manage the substantial Telecom capital
11 work and growing asset base. Telecom Asset Maintenance Phase II also evaluated
12 existing capital work management and scheduling processes and, where beneficial, 13 reengineered those processes for implementing a single work and asset 14 management software system and a single scheduling software system to be utilized d/b/a NV Energy Nevada Power Company Company Power Nevada 15 by Telecom.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 16. Q. WHAT WAS THE TOTAL COST OF THIS PROJECT? 18 A. Phase I was in service June 7, 2018 and the total cost at Sierra was $1,964,712 (with 19 AFUDC). Phase II appears in the plant schedules as a certification project and was 20 in service March 1, 2019 and the total cost at Sierra was $1,090,349 (with AFUDC). 21 All systems are used and useful and providing utility service.
22
23
24
25
26 27
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1 TELECOMMUNICATIONS PROJECT IV: LAS VEGAS TO RENO DENSE WAVE DIVISION MULTIPLEXING CSY1257 2 3 17. Q. PLEASE DESCRIBE THE LAS VEGAS TO RENO DENSE WAVE 4 DIVISION MULTIPLEXING (“DWDM”) PROJECT. 5 A. The project involved engineering, procurement, and construction of the DWDM 6 optical fiber electronic systems. The DWDM technology allows for the 7 transmission of high amounts of data across existing fiber optic cabling systems 8 from Las Vegas to Reno, Nevada.
9
10 18. Q. WHY WAS THE PROJECT NECESSARY?
11 A. This project was necessary to increase the bandwidth for transporting information
12 between Las Vegas and Reno to support corporate IT disaster recovery of data 13 centers, high-speed voice and data exchange between the northern and southern 14 corporate energy system control centers, the 5-digit corporate internal voice dialing d/b/a NV Energy Nevada Power Company Company Power Nevada 15 telephone system, and the high-speed wide area IT networking systems.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 19. Q. WHAT WAS THE TOTAL COST OF THIS PROJECT? 18 A. The total cost of the project was $1,338,361 (with AFUDC). The system was 19 installed on May 22, 2017 and is used and useful in the provision of utility service.
20
21 TELECOMMUNICATIONS PROJECT V: COMM BATTERY AND CHARGER REPLACEMENT CCO819 22 23 20. Q. PLEASE DESCRIBE THE COMM BATTERY AND CHARGER 24 REPLACEMENT ROJECT. 25 A. Batteries are utilized throughout the Telecom network to provide direct current 26 (“DC”) power to equipment and provide backup during electrical outages. The 27
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1 project involves identifying and replacing batteries and associated equipment at 2 Telecom sites that have exceeded their lifetime effectiveness. This project was 3 estimated to be in service by May 31, 2019, but has been delayed. Costs associated 4 with this project to be removed at time of certification. 5 TELECOMMUNICATIONS PROJECT VI: 6 CALL CENTER EXPANSION CSY918 7 21. Q. PLEASE DESCRIBE THE CALL CENTER EXPANSION PROJECT. 8 A. The Call Center Expansion project included three advanced applications to enhance
9 system features, functionality and performance. A multi-media application was
10 added to improve and streamline the processing of customer e-mail requests via the
11 call center agents. An application was installed to conduct surveys for key customer
12 feedback regarding satisfaction and caller experience. Lastly, a workforce 13 management (“WFM”) system was implemented. The WFM system is used to 14 create forecasts to plan appropriate staffing and for managing call center agent d/b/a NV Energy Nevada Power Company Company Power Nevada 15 work/schedules and performance. Ms. Follette discusses other aspects of the project
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 in her prepared direct testimony. 17 18 22 Q. WHAT WAS THE TOTAL COST OF THIS PROJECT? 19 A. The total cost of the project was $911,497 (with AFUDC). This project went into 20 service December 31, 2017 and is used and useful and providing utility service. 21 22 23. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY? 23 A. Yes. 24 25 26 27
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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 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Sierra Pacific Power Company d/b/a NV Energy
3 2019 General Rate Case Docket No. 19-06___ 4 PREPARED DIRECT TESTIMONY OF 5 Michelle Follette 6 Revenue Requirement 7 8 I. INTRODUCTION 9 1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS ADDRESS
10 AND PARTY FOR WHOM YOU ARE FILING TESTIMONY.
11 A. My name is Michelle Follette. I am Vice President, Customer Operations for NV
12 Energy, Inc. (“NV Energy”), Sierra Pacific Power Company d/b/a NV Energy 13 (“Sierra” the “Company”), and Nevada Power Company d/b/a NV Energy 14 (“Nevada Power” and, together with Sierra, the “Companies”). I work primarily d/b/a NV Energy Nevada Power Company Company Power Nevada 15 out of the corporate headquarters at 6226 W. Sahara Avenue in Las Vegas. I am
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 filing testimony in this proceeding on behalf of Sierra. 17
18 2. Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE IN THE 19 UTILITY INDUSTRY. 20 A. I earned a Bachelor of Science in Communications and a minor in Business 21 Management from Weber State University. Later I went on to earn a Master of 22 Business Administration from Westminster College. I have worked in customer- 23 focused organizations within the utility industry for 23 years supporting major 24 accounts, customer & community affairs, customer marketing & support services, 25 customer service, and I am currently the Vice President of Customer Operations for 26 NV Energy. Additional information is available in Exhibit Follette-Direct-1. 27
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1 3. Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS VICE PRESIDENT, 2 CUSTOMER OPERATIONS. 3 A. As Vice President, Customer Operations my responsibilities include overseeing 4 internal customer service functions and supporting other customer-facing services. 5 I manage budgetary, personnel, contract management, and resources for internal 6 functions including: billing, metering, customer contact centers, major account 7 management and customer programs and services. Customer-facing services 8 involve support and coordination with the government relations, corporate
9 communications, energy generation and delivery, and regulatory operations teams
10 to ensure customer service consistency and maintenance of constructive
11 relationships.
12 13 4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC 14 UTILITIES COMMISSION OF NEVADA (“COMMISSION”)? d/b/a NV Energy Nevada Power Company Company Power Nevada 15 A. No.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 5. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
18 A. My prepared direct testimony covers two topics. First, in Section II, I discuss the 19 cumulative customer service level metric, other customer satisfaction metrics and 20 customer satisfaction improvement plans. The cumulative customer service level 21 metric measures how quickly the customer contact center answers incoming phone 22 calls from customers. Next, in section III, I discuss the capital projects, with a cost 23 of approximately $1.0 million or where the aggregate of multiple similar projects 24 is approximately $1.0 million, related to customer operations projects completed 25 since the end of the certification period in Sierra’s last general rate case (June 1, 26 2016) and planned through the certification period for this general rate case (May 27
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1 31, 2019). Table 1 Follette Direct-1 below provides a summary of costs by 2 category as of December 31, 2018 and the forecasted cost thru May 31, 2019.
3 Table Follette Direct-1 Total as of Forecasted total 4 December 31, thru May 31, 2018 2019 5 Customer Applications 10,343,580 10,733,580 6 Advanced Service Metering Infrastructure 3,925,297 4,093,297 7 Total: 14,268,877 14,826,877 8
9 6. Q. ARE YOU SPONSORING ANY EXHIBITS?
10 A. Yes. I am sponsoring the following Exhibits:
11 Exhibit Follette-Direct-1 Statement of Qualifications
12 Exhibit Follette-Direct-2 NV Energy 2018 Service Quality & Metrics Report
13
14 II. CUMULATIVE CUSTOMER SERVICE LEVEL, OTHER CUSTOMER d/b/a NV Energy SERVICE METRICS, AND CUSTOMER SATISFACTION IMPROVEMENT Nevada Power Company Company Power Nevada 15 PLANS
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 7. Q. HISTORICALLY, THE COMPANIES HAVE REPORTED THE 17 CUMULATIVE SERVICE LEVEL IN REGULATORY RATE REVIEW 18 FILINGS. WHY DOES THE COMPANY MEASURE AND REPORT ON 19 THE CUMULATIVE SERVICE LEVEL IN REGULATORY RATE 20 REVIEW FILINGS? 21 A. In 2013, the Commission directed Sierra to submit as part of its next rate review 22 filing its results on the cumulative service level metric. This requirement was issued 23 in connection with Sierra’s request for approval of short-term incentive plan costs 24 tied to customer-service levels. The Commission focused on the cumulative service 25 metric stating that “[a]nswering customer calls on a timely basis is an obligation 26 27
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1 expected from any regulated utility.”1 The Commission continued, “The 2 [cumulative service level] metric is one important indication of [the Company’s] 3 performance regarding customer service and should be included in evaluating 4 employee performance for purposes of [short term incentive payments].”2 While 5 the cumulative service level was not a specific measure in Sierra’s 2018 corporate 6 scorecard,3 the Company recognizes that it is an important mark against which 7 customer service may be measured. Therefore, the Company is reporting the
8 cumulative service level in connection with this regulatory rate review proceeding.
9
10 8. Q. PLEASE DESCRIBE THE CUMULATIVE CUSTOMER SERVICE LEVEL
11 METRIC.
12 A. The cumulative customer service level measures the percentage of incoming phone 13 calls that the Company’s customer contact center answers within a specific period 14 of time. The numerator in the fraction is the number of phone calls answered within d/b/a NV Energy Nevada Power Company Company Power Nevada 15 the specific timeframe, and the denominator is the total number of incoming phone
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 calls to the customer contact center. The following formula depicts the calculation: 17 X (number of phone calls answered within z seconds) 18 Y (total number of incoming phone calls received by customer care) 19 20 Fundamentally, this metric addresses how quickly the Company answers incoming
21 phone calls. In 2013, Sierra and Nevada Power measured cumulative service level 22 as a percentage of all calls answered within 60 seconds. In 2014, this metric was
23 tightened to the percentage of all calls answered within 30 seconds. 24 25
26 1 Modified Final Order, Docket No. 13-06002, at ¶ 320 2 Id. at ¶ 321 27 3 See, Prepared Direct Testimony of Jennifer Oswald for a discussion of Sierra’s 2018 corporate scorecard. 28 Follette-DIRECT 4
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1 9. Q. WHAT WAS SIERRA’S PERFORMANCE ON THE CUMULATIVE 2 SERVICE LEVEL METRIC IN 2018? 3 A. In 2018, Sierra’s cumulative customer service level was 80.25 percent, which 4 exceeds the corporate target of 80.00 percent. The following table shows Sierra’s 5 (and Nevada Power’s) historical cumulative service level results for the past five 6 years. 7 Table Follette Direct-2 8 Combined Cumulative Service Level 9
10 (percentage of all calls answered within 30 seconds)
11 2014 2015 2016 2017 2018
12 Nevada Power 79.42% 81.39% 82.06% 80.51% 82.02%
13 Sierra Pacific 86.17% 82.46% 81.00% 81.15% 80.25%
14 d/b/a NV Energy Nevada Power Company Company Power Nevada 15 10. Q. WHAT OTHER METRICS DOES SIERRA USE TO ASSESS AND TRACK
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 CUSTOMER SERVICE PERFORMANCE? 17 A. In 2012, the Commission opened an investigation into Nevada Power’s “customer 18 service practices including, but not limited to, call center operations and compliance 19 with” Nevada’s utility consumer bill of rights.4 As the final order in that docket 20 notes, in 2004 the Commission ordered Nevada Power and Sierra to “utilize certain 21 data to measure the impact on quality of service . . . in each of their respective 22 general rate cases following the order.”5 In 2015, the Commission modified some 23 of those metrics. Recently, Sierra filed its 2018 Service Quality and Metrics Report 24 25
26 4 Notice of Investigation and Request for Comments, Docket No. 12-01005 at 1 (iss. Jan. 20, 2012). 27 5 Order, Docket No. 12-01005 at ¶ 2, fn. 1 (iss. Oct. 28, 2014). 28 Follette-DIRECT 5
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1 pursuant to the Commission’s 2015 order. A copy of that report is attached as 2 Exhibit Follette-Direct-2.
3
4 III. CUSTOMER OPERATIONS CAPITAL PROJECTS 5 11. Q. PLEASE LIST THE CUSTOMER OPERATIONS CAPITAL PROJECTS 6 THAT ARE INCLUDED IN PLANT IN SERVICE THROUGH DECEMBER 7 31, 2018, OR THAT WILL BE CLOSED TO PLANT IN SERVICE BY THE 8 END OF THE CERTIFICATION PERIOD, MAY 31, 2019.
9 A. Below I address the major capital projects that originated in the customer operations
10 area. These projects fall into two broad categories, but are all information
11 technology projects. Four projects fit within the first category, which I characterize
12 as “Customer Applications.” Those projects are: 13 • Customer Digital Experience (“CDX”) 14 • Customer Digital Enhancements d/b/a NV Energy
Nevada Power Company Company Power Nevada • 15 Call Center System Improvements
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 • Electronic Work Queue Back-Office Workforce Management 17 (“WFM”) 18 Second, I address three projects within the Advanced Metering Infrastructure 19 category. Those projects are: 20 • Advanced Metering Infrastructure – Communication Technology 21 • Regional Network Interface Upgrade 4.2 22 • Advanced Metering Infrastructure Optimization – Electric Meters 23 Below I describe each project or program, identify the cost of each project or 24 program, and explain how the Company uses the functionality provided by the 25 project or program to provide electric service to customers and why the Company 26 completed the project. 27
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1 12. Q. WHY ARE ONLY MAJOR PROJECTS SPECIFICALLY DISCUSSED IN 2 YOUR TESTIMONY? 3 A. Testimony-style descriptions of each and every project completed by or for the 4 customer service team since June 1, 2016 would be so voluminous that its value at 5 hearing would be severely diminished. As I understand it, in general rate 6 proceedings the Commission wants to see prepared direct testimony addressing the 7 details of and supporting expenditures on major projects. In recent general rate 8 cases the Commission has accepted the $1.0 million demarcation as appropriate for
9 determining whether a project is “major.” While not addressed in detail in my
10 prepared direct testimony, my group has prepared project “binders” for smaller
11 projects completed since June 1, 2016. As has been the Companies’ practice for
12 many rate case cycles, those binders (now in electronic form) are available for 13 review on the day this general rate review filing is made. 14 d/b/a NV Energy Nevada Power Company Company Power Nevada 15 A. Customer Digital Experience or CDX
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 13. Q. PLEASE DESCRIBE THE CDX PROJECT. 17 A. The purpose of the CDX is to be efficient, adaptive and proactive in the delivery of 18 digital experiences for customers, whose expectations have rapidly adapted to a 19 sophisticated digital retail and services marketplace. From 2014 – 2019, the 20 Companies experienced a 173 percent gain in unique customer monthly logins to 21 the customer interface MyAccount, where customers view and manage their energy 22 costs and perform services. Digital payments alone have reached 77 percent of all 23 payments received from customers on a monthly basis. In this same period, the 24 Companies’ corporate web site has experienced a threefold increase in website 25 usage, to 1.5 million sessions per month. The new CDX infrastructure implemented 26 within this project provides a single platform that delivers content and services in 27
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1 multiple digital channels: desktop, mobile, and app (Apple and Android), to enable 2 an energy services digital marketplace within the channels that customers are 3 accustomed to with other retail and service providers. The CDX project provides 4 the technical infrastructure and digital solutions that integrate people, processes, 5 and technology, thereby changing the way the Companies deliver digital energy 6 services for its customers. This project provides customers a state of the art digital 7 platform; enables an agile implementation of new or reinvented utility customer 8 experiences; proactively pushes personalized relevant and timely information;
9 becomes more predictive of our customers’ personalized needs and expectations;
10 and creates a dynamic and customer centric culture that fosters innovation and step
11 change improvement in the digital products and services expected by customers.
12 13 14. Q. WHAT TECHNOLOGY PLATFORMS ARE ASSOCIATED WITH THIS 14 PROJECT? d/b/a NV Energy Nevada Power Company Company Power Nevada 15 A. CDX includes the applications, infrastructure, and security necessary to implement
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 a new, responsive customer portal and mobile app. The ability to update the web, 17 MyAccount, and mobile experiences to the vision of CDX was limited due to the 18 age of the disparate, legacy technology stacks. The services, applications and 19 content in the three legacy technology stacks – Web, MyAccount, and Mobile – 20 have been redesigned and migrated to a new, consolidated technology architecture 21 that is an industry-standard portal framework stack that includes Adobe Experience 22 Manager and the Ionic platform infrastructure. 23 24 The new www.nvenergy.com is a responsive web mobile design configured on the 25 Adobe Experience Manager platform that enables customer facing desktop, mobile, 26 and app (Apple and Android) interfaces for digital end use. The communication 27 platform enables consistent and proactive communications across all channels (e.g.,
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1 text, email, outbound calling, and app push notification) through a single 2 communication gateway and provides tools for customers to sign up for and 3 manage proactive communication on various topics (e.g., payment notification, 4 billing notification, unusual usage, outage communication, energy management, 5 weekly energy summaries, etc.) through multiple channels (email, text, phone, 6 push, and social) through the communication gateway. The predictive analytics 7 model determines personalized next best actions and identifies program
8 opportunities for specific customers.
9
10 15. Q. DESCRIBE PROJECT IMPLEMENTATION PHASES AND THE KEY
11 VENDOR RESOURCES REQUIRED TO ASSIST WITH THE
12 COMPLETION OF EACH. 13 A. CDX was implemented in multiple phases consisting of discovery and design, build 14 and content migration, testing and promotion, and implementation. The Companies d/b/a NV Energy Nevada Power Company Company Power Nevada 15 worked with IBM to facilitate a discovery and design period during which insights
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 were drawn from customer research, workshops, and best practices/competitor 17 research including utilization of the JD Power - Utility Website Evaluation Study. 18 The new design was tested through focus groups in July 2016, after the initial 19 design and wireframes were completed. Adjustments were made based on this 20 customer research prior to the release of the design to the build stage of the project.
21 In June 2017, multi-day customer usability testing was executed that focused on 22 how customers could accomplish tasks commonly completed on energy utility 23 websites. Customer participants were asked to complete a series of tasks and 24 communicate their experiences. The feedback obtained from customers provided 25 an opportunity to make appropriate adjustments before product implementation. 26 27
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1 During the build and content migration phase, the Companies worked with Zilker 2 Technology to implement the user-interface (web and mobile), the back-office 3 processes, and the integrations necessary to realize the designed experiences. 4 Content migration and clean-up targeted approximately 1,000 existing 5 informational pages (e.g. Economic Development, Rates, and Energy Efficiency) 6 and 1,500 existing documents. Based on review with the various business unit 7 content owners, unneeded and outdated content was deleted and the remaining 8 content was refreshed. The final content was then transitioned into the look-and-
9 feel of the new CDX.
10
11 During the testing phase, the Companies worked with Cognizant to execute the
12 various stages of testing. System integration testing ensured that the build followed 13 the design. Testing validated that individual experiences delivered functionality 14 end-to-end. System testing validated that functionality was delivered across d/b/a NV Energy Nevada Power Company Company Power Nevada 15 multiple experiences end-to-end. User acceptance testing validated that users could
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 execute functionality across multiple experiences from the customer perspective. 17 Security testing validated that security vulnerabilities were identified and 18 addressed. Upon completion of the testing phase, the Companies made the CDX 19 experiences available to customers. The CDX experience was made available in an 20 initial go-live followed by agile promotions were incremental experiences and 21 enhancements were made available. 22 23 The Companies executed change management activities to ensure adoption of the 24 new digital capabilities. Employee training ensured customer facing employees 25 were properly trained and understood the customer impacts. Change leaders and 26 change champions served as advocates of the CDX program and helped promote 27
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1 the changes to the internal organization. Internal communications ensured the 2 remainder of the internal organization was aware of the CDX program and its 3 impact to the various departments and to customers. External communications 4 ensured that customers were aware of the new website and mobile app and the new
5 experiences. 6 7 16. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 8 A. The total cost of the CDX project was $6,256,368. Additional detail regarding the
9 costs of the project is set forth in Table Follette Direct-3 below.
10
Table Follette Direct-3 11 CDX Project
12 As of % of Cost Category Total Cost 13 December 31, 2018 Total Internal Labor $ 942,143 $ 942,143 15% 14
d/b/a NV Energy External Services $ 4,621,944 $ 4,621,994 74%
Nevada Power Company Company Power Nevada Zilker Technology LLC $ 1,995,934 $ 1,995,934 32% 15 IBM Corporation $ 1,053,336 $ 1,053,336 17% and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Cognizant Technology Solutions $ 1,036,849 $ 1,036,849 17% 17 Yoh Services LLC/DCR Workforce Inc. $ 308,355 $ 308,355 5% Subtotal of primary External Services 4,394,474 % of total: 95% 18 Materials $ 227,742 $ 227,742 4% 19 Internal Overheads $ 176,671 $ 176,671 3% Other Expense $ 71,102 $ 71,102 1% 20 AFUDC $ 216,767 $ 216,767 3% 21 Total $ 6,256,368 $ 6,256,368 100% 22 23 17. Q. DESCRIBE THE TYPE OF COSTS INCLUDED IN THE INTERNAL 24 LABOR, EXTERNAL SERVICES, AND MATERIALS CATEGORIES. 25 A. Internal labor includes direct (wages) and indirect (labor overheads) costs 26 associated with labor provided by Company employees. Internal labor costs are 27 comprised primarily of charges from the Information Technology group (60
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1 percent) and Customer Operations department (40 percent). These two 2 organizations worked collaboratively on project planning, design, implementation, 3 project management, and testing. Resources from Information Technology were 4 also involved in application development. 5 6 The external services cost category primarily includes vendor-provided 7 professional services and third party software related costs. Table Follette Direct-3 8 identifies the primary professional service vendors. Other professional service
9 vendors include Wipro and Kubra. Software related purchases account for three
10 percent of the external services category.
11
12 Project material costs primarily included servers and related equipment. 13 PowerEdge and Linux servers, and related hardware account for 82 percent of 14 material costs. d/b/a NV Energy Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 18. Q. WERE THE EXTERNAL SERVICE PROVIDERS SELECTED THROUGH 17 A COMPETITIVE PROCESS? 18 A. The primary external service providers, Zilker, IBM, Cognizant, Yoh Services and 19 DCR Workforce, were selected through a competitive selection process. Contracts 20 were awarded based on technical capabilities and pricing. Only the Kubra 21 relationship was not established through a competitive solicitation. Kubra has been 22 the Companies’ alert and notification provider since 2013. Due to the investment 23 of existing infrastructure and proprietary software, Kubra was the only provider 24 that could complete the required work. 25 26 27
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1 B. Customer Digital Enhancements 2 19. Q. PLEASE DESCRIBE THE CUSTOMER DIGITAL ENHANCEMENTS 3 PROGRAM. 4 A. The Customer Digital Enhancements Program was established after the 5 implementation of the CDX system/infrastructure. Akin to other large scale 6 systems like Banner, the Companies’ customer information system (CIS), the 7 Genesys Quality Management (“GQM”) call management system was initiated to 8 manage on-going enhancements to the CDX system. The 2018 and first quarter
9 2019 enhancements include security upgrades, content presentation changes, data
10 integrity administration, experience enhancements and the addition of new
11 experiences.
12 13 20. Q. PLEASE DESCRIBE THE CUSTOMER DIGITAL EXPERIENCE 14 IMPROVEMENTS CONTAINED WITHIN THE INITIAL LAUNCH OF d/b/a NV Energy Nevada Power Company Company Power Nevada 15 THE PROGRAM.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 A. The initial launch of CDX in 2017 delivered a unified customer experience via a 17 single responsive infrastructure that included redesign of over 30 customer 18 experiences including the top customer transactions, predictive projections, 19 important notices and next-best action recommendations in a personalized 20 MyDashboard presentation layer. CDX enabled the delivery of content that is 21 optimized and personalized with a data-driven account feed for customer 22 messaging, outage status, program promotions, predictive bill information, online 23 feedback functionality, geo-location services, important notification services, and 24 implementation of secure authentication and log-in services. CDX included a 25 redesigned outage communications and reporting capability, a move center, smart 26 thermostat and energy assessment program enrollments, automatic monthly 27
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1 payment, equal payment plan, selected due date, simplified bill payments, and 2 usage presentation. In addition, the corporate website was redesigned and content 3 was migrated to the new portal platform. 4 5 21. Q. WHAT FUNCTIONALITY WAS DELIVERED THROUGH THIS 6 ENHANCEMENT PROGRAM? 7 A. During Q1 2018, CDX was enhanced to support the Assembly Bill 405 experience, 8 synchronization of Account Summary information with the Bill Statement,
9 migration of the Customer Service Representative (“CSR”) registration experience,
10 representation of gas usage on the dashboard, and auto-enrollment of accounts in
11 Bill Reminder and Payment Notice alerts.
12 13 During Q2 2018, CDX was modified to support the new Equal Payment Plan option 14 enrollment, storage of 10-day and 48-hour notices in the Account History, the d/b/a NV Energy Nevada Power Company Company Power Nevada 15 addition of fingerprint authentication in the mobile app, enhancements to the Smart
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Thermostat enrollment process, outage/weather alerts, sign-up for and management 17 of payment arrangements, and communication of current and projected bill 18 amounts. 19 20 During Q3 2018, CDX was enhanced to support the Spanish language version of 21 the platform, Western Union credit card/debit card single payment sign-on, offering 22 the Equal Payment Plan to business accounts, introduction of the electric vehicle 23 comparison tool, and the addition of facial recognition authentication in the mobile 24 app.
25 26 27
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1 During Q4 2018, CDX was enhanced to support the My Energy Snapshot, 2 improved outage communications with decreased latency, a refreshed layout of 3 MyDashboard, a refreshed menu design for mobile app, introduction of an account 4 preferences tile, easy access to My Energy Snapshot from MyDashboard, and 5 refined layout for Profiles & Preferences. 6 7 During the first quarter of 2019, CDX was enhanced to support improvements in 8 the Projected Bill tile, representation of 7-day predictive bill forecast on the
9 dashboard, addition of a system performance reliability indicator, representation of
10 gas and net data on the My Energy Use by Appliance tile, messaging for the bill
11 forgiveness program, implementation of reCaptcha security service, and redesigned
12 homepage experience. 13 14 22. Q. WHAT WAS THE TOTAL COST OF THE ENHANCEMENT PROGRAM? d/b/a NV Energy Nevada Power Company Company Power Nevada 15 A. Through the end of the certification period, the total estimated cost of the Customer
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Digital Enhancements program is $2,231,976. Additional detail regarding the costs 17 of the project is set forth in Table Follette Direct-4 below.
18 Table Follette Direct-4 19 Customer Digital Enhancements As of January 1, 2019 - Estimated 20 Cost Category December 31, 2018 May 31, 2019 Total Cost 21 Internal Labor $ 172,041 $ 27,334 $ 199,375 External Services $ 1,565,795 $ 367,161 $ 1,932,956 22 Internal Overheads $ 53,292 $ 9,804 $ 63,095 23 Other Expense $ 20,554 $ 2,916 $ 23,470 AFUDC $ 8,990 $ 4,091 $ 13,081 24 Total $ 1,820,672 $ 411,304 $ 2,231,976 25 26 27
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1 23. Q. WHAT EXTERNAL SERVICES WERE REQUIRED TO SUPPORT THIS 2 PROGRAM? 3 A. External service costs included contributions from Zilker for design and build 4 related services, Yoh Services provided technical support and project management, 5 and Cognizant contributed testing resources. Zilker’s costs account for 82 percent 6 of the estimated external services cost, nearly $1.6 million. Technical support and 7 project management services provided by Yoh Services are estimated to be 8 $174,000 through May 31, 2019, and Cognizant’s testing services are estimated to
9 be less than $100,000.
10
11 24. Q. WERE THE EXTERNAL SERVICE PROVIDERS SELECTED THROUGH
12 A COMPETITIVE PROCESS? 13 A. Yes, all of the external service providers were selected through competitive 14 sourcing. d/b/a NV Energy Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 25. Q. WHAT MEASURES WERE TAKEN TO CONTROL COSTS? 17 A. The enhancement implementation approach employed under this program was 18 designed to reduce costs. Potential enhancements were evaluated frequently based 19 on customer satisfaction survey results, system performance, customer behavior, 20 and operational processes. Quarterly enhancement plans were established to 21 manage program work, individual enhancements were scheduled and placed into 22 productions in a manner that leverage resources and created efficiencies. 23 24 25 26 27
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1 C. Call Center System Initiatives
2 26. Q. PLEASE DESCRIBE THE CALL CENTER SYSTEM INITIATIVES
3 PROGRAM. 4 A. The Call Center System Initiatives program included several routing system 5 improvements during the course of a three year period from 2016-2018. These 6 collectively included upgrades and additions to the contact center telephone system. 7 The following work was performed under this program: 8 a) Call-back System Expansion included the implementation of the Virtual
9 Hold Technology LLC (“Virtual Hold”) customer call back system as part
10 of the Genesys Disaster Recovery system in Reno. Servers and application
11 software were purchased, configured, installed and tested as part of this
12 project. 13 b) Contact Center Recording System Replacement replaced the existing 14 voice and screen recording system with a new product, Genesys Interactive d/b/a NV Energy Nevada Power Company Company Power Nevada 15 Recorder (“GIR”). Servers were purchased, configured, installed and tested
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 with the new software. Desktop application software was also upgraded and 17 modified to work with the new recording system. 18 c) Agent License Expansion involved the addition of CSR answering 19 positions. Software was purchased and configured for use in processing 20 calls. 21 d) Technology Refresh expanded and upgraded the Genesys server 22 infrastructure to provide increased testing environment capability and to 23 maintain current operating system/application software support levels. 24 e) Genesys Audit Software included the purchase and installation of 25 management/auditing software for the Genesys system. 26 27
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1 f) Call Analytics Training included purchase of training for administrative 2 staff on the operation of the Call Miner analytics system. 3
4 27. Q. WHY WAS THE PROGRAM NECESSARY? 5 A. The work was necessary due to operational and business needs. Details related to 6 each element of the program are as follows:
7 a) Call-back System Expansion – the Virtual Hold system was expanded to 8 ensure that customer service levels could be maintained when using the Reno
9 Disaster Recovery system as the production environment. The call-back
10 system acts as a “load balancer” during heavy call volume periods to ensure
11 that customers don’t experience extended hold and queueing times while
12 trying to reach an agent.
13 b) Contact Center Recording System Replacement – the existing recording 14 system, GQM was discontinued as a supported product by Genesys. It was d/b/a NV Energy Nevada Power Company Company Power Nevada 15 then necessary to replace the recording software with the GIR application and,
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 in addition, upgrade the desktop telephony software to a higher version of 17 Workspace Desktop Edition. Compliance and audit requirements necessitate 18 that all voice calls and screen video is captured and archived for specific time 19 intervals. In addition, these recordings are required for call analytics and agent 20 monitoring in support of quality assurance and coaching.
21 c) Agent License Expansion – the purpose of adding agent answering positions 22 via license expansion was to provide a quicker response to customer calls 23 related to billing inquiries.
24 d) Technology Refresh – it was necessary to add a second staging and testing 25 environment in order to expedite implementing various types of software call 26 processing enhancements. Additional Genesys servers were also purchased for 27
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1 migration to a new virtual machine (VM) chassis environment, which was 2 required due to upgrades by the IT Operating Services group.
3 e) Genesys Audit Software - the addition of management and auditing software 4 was necessary in order to facilitate auditing and configuration changes within 5 the Genesys Contact Center system. These capabilities enhance the stability of 6 the system.
7 f) Call Analytics Training - formal system training was required for Workforce 8 Optimization & Quality Management staff in order for them to adequately
9 perform their support role relative to maintaining customer service levels
10
11 28. Q. WHAT WAS THE TOTAL COST OF THE PROGRAM?
12 A. The total cost of the Call Center System Initiatives program was $1,279,581. 13 Additional detail regarding the cost of the program is set forth in Table Follette 14 Direct-5 below. d/b/a NV Energy Table Follette Direct-5 Nevada Power Company Company Power Nevada 15 Call Center System Initiatives As of and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Cost Category Total Cost December 31, 2018 17 Internal Labor $ 189,956 $ 189,956 External Services $ 830,163 $ 773,587 18 Materials $ 161,580 $ 218,157 19 Internal Overheads $ 32,715 $ 32,715 Other Expenses $ 6,457 $ 6,457 20 AFUDC $ 58,709 $ 58,709 21 Total $ 1,279,581 $ 1,279,581 22
23 29. Q. WHAT COSTS ARE INCLUDED IN EXTERNAL SERVICES? 24 A. External services costs primarily include external professional services. This 25 program’s external services cost was divided between vendor professional services 26 and third party contractors. Aria Solutions, the Companies’ competitively selected 27
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1 call center system support vendor, and Virtual Hold account for 48.8 percent and 2 contractors used through the Companies’ competitively selected staffing providers 3 Yoh Services and DCR Workforce make up 41.7 percent of the total external 4 services costs. 5
6 30. Q. WHAT COSTS ARE INCLUDED IN MATERIALS? 7 A. Material costs include hardware and related charges. Material purchases were made 8 with competitively bid hardware suppliers including, Dell Marketing LP, Solutions
9 II Inc., SHI International Corp and CDW Direct.
10
11 D. Electronic Work Queue Back-Office WFM
12 31. Q. PLEASE DESCRIBE THE ELECTRONIC WORK QUEUE BACK-OFFICE 13 WFM PROJECT. 14 A. The Electronic Work Queue project provides the technical infrastructure to route d/b/a NV Energy Nevada Power Company Company Power Nevada 15 customer calls and back-office work tasks to both contact center and billing agents.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 The Genesys Intelligent Work Distribution system alleviates manual tasks and 17 automatically distributes back-office work to employees located in the contact 18 center, business solutions center and the billing and credit operations department 19 via the Banner Customer Information Systems Electronic Work Queue module. 20 The Genesys system assigns tasks based on agent availability, skills, call volume, 21 real-time priorities and real time analytics. The NICE Real-Time Application 22 Monitoring tool monitors individual team member’s activities, allowing for process 23 standardization and monitoring, and improves forecasting capabilities with new 24 reporting functionality. 25 26 27
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1 32. Q. WHY WAS THIS PROJECT NECESSARY? 2 A. Back-office work load dedicated to general account administration, customer 3 inquiries, and billing and program administration continues to increase. The 4 Electronic Work Queue project delivered the infrastructure and functionality to 5 intelligently automate and monitor the routing process of work between multiple 6 teams located in different areas. The Electronic Work Queue project allows for 7 back-office work to be completed during slow periods around the clock, enabling 8 the Company to increase productive without increasing staff. Through monitoring
9 and tracking of back office work, this project also contributes to process
10 standardization of work which will improve training curriculum and generate
11 efficiencies.
12 13 33. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 14 A. The total cost of the Electronic Work Queue project was $986,958. Additional d/b/a NV Energy Nevada Power Company Company Power Nevada 15 detail regarding the costs of the program is set forth in Table Follette Direct-6
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 below. 17 Table Follette Direct-6 18 Electronic Work Queue As of 19 Cost Category Total Cost December 31, 2018 20 Internal Labor $ 193,849 $ 193,849 External Services $ 685,989 $ 661,893 21 Materials $ 24,034 $ 48,130 22 Internal Overheads $ 27,217 $ 27,217 Other Expenses $ 1,195 $ 1,195 23 AFUDC $ 54,675 $ 54,675 24 Total $ 986,958 $ 986,958 25 26 27
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1 34. Q. WHAT COSTS ARE INCLUDED IN EXTERNAL SERVICES? 2 A. Software and external professional vendor services are included in this cost 3 category. Aria Solutions, the Companies’ competitively selected call center system 4 support vendor accounts for 51.9 percent of project costs, and Cognizant, also 5 selected through a competitive solicitation, accounts for 21.7 percent. Nice Systems 6 Inc. and PartnerSolve LLC make up the remaining 23.4 percent of the total external 7 services costs. 8
9 35. Q. WHAT BENEFITS DOES THE PROJECT DELIVER TO CUSTOMERS?
10 A. The Electronic Work Queue project delivered improved customer service at
11 reduced costs, mitigating future staffing increases through improved agent
12 utilization and departmental efficiencies. The system’s tracking and monitoring 13 capabilities will improve performance activity monitoring, and increase employee 14 accountability and coaching opportunities. Standardization for back-office work d/b/a NV Energy Nevada Power Company Company Power Nevada 15 improves processing times by reducing work task actions and will highlight training
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 opportunities that can be shared throughout the organization. The contact center 17 and back-office work forecasting and workforce optimization has improved as part 18 of the system automation. 19 20 E. Advanced Metering Infrastructure – Communication Technology 21 36. Q. PLEASE DESCRIBE THE ADVANCED METERING INFRASTRUCTURE 22 COMMUNICATION TECHNOLOGY PROJECT. 23 A. This project was implemented to fill identified communication gaps in the 24 Company’s Advanced Meter Infrastructure (“AMI”) network. These gaps were 25 primarily caused by terrain challenges and the resulting inability of existing tower- 26 gateway-based (“TGB”) infrastructure to communicate reliably with smart meters 27
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1 that were installed during the original meter deployment. Because some rural 2 customer meters could not effectively communicate with the TGBs, customer data 3 and meter reads were not being collected by the AMI network. Thus customer data 4 could not be made available for customer use on the Companies’ web portal, and 5 the billing meter reads continued to have to be collected manually. The project 6 included strategic installation of 25 compact TGBs throughout rural Nevada in 7 locations determined by a propagation study that optimized coverage of the AMI 8 radio frequency network. The new compact TGBs (also known as M400Bs) were
9 installed adjacent to Company-owned equipment on standard utility poles. The new
10 TGBs successfully enabled the Company to collect data, including meter readings,
11 from most of the customer meters that could not previously communicate with the
12 network. 13 14 37. Q. WHY WAS THIS PROJECT NECESSARY? d/b/a NV Energy Nevada Power Company Company Power Nevada 15 A. The need for this project became evident as customers in rural Nevada became more
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 familiar with the many benefits of the new smart meter system that were not 17 available because of communication issues. Company personnel were continuing 18 to drive to remote locations to read and service non-responsive AMI meters. 19 Therefore, to obtain additional operational savings, provide improved customer 20 service, and unlock the benefits of the AMI network, this project was budgeted, 21 planned and implemented. 22 23 38. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 24 A. The total actual cost of this project is $1,903,174. Additional detail regarding the 25 cost of the program is set forth in Table Follette Direct-7 below. 26
27
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Table Follette Direct-7 1 Advanced Metering Infrastructure As of 2 Cost Category Total Cost December 31, 2018 3 Internal Labor $ 287,346 $ 287,346 Materials $ 863,947 $ 863,947 4 External Services $ 491,191 $ 491,191 5 Internal Overheads $ 129,680 $ 129,680 Other Expenses $ 10,302 $ 10,302 6 AFUDC $ 120,708 $ 120,708 7 Total $ 1,903,174 $ 1,903,174 8
9 39. Q. WHAT WERE THE MAIN COST DRIVERS OF THE PROJECT?
10 A. The costs to deliver this project were relatively evenly distributed between
11 installation costs (internal labor, overheads and external service), and material
12 costs. Installation costs made up approximately 48 percent of total project costs and 13 included planning and design, construction, and project oversight from internal 14 labor and vendors. Project planning and design services included contributions d/b/a NV Energy Nevada Power Company Company Power Nevada 15 from Ascension Power Engineering and Sensus USA Inc. Installation of the units
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 was managed by internal crews and Titan Electrical Contracting, who completed 17 the pole replacements. Material costs account for 45 percent of the project total, 18 with the majority $702,650 spent on TGBs sourced through Sensus. Other material 19 costs included poles, transformers, cable and miscellaneous hardware to complete 20 the installation. 21
22 40. Q. WHAT EFFORTS WERE TAKEN TO REDUCE PROJECT COSTS? 23 A. Cost were avoided by leveraging the scalability of the Companies’ existing smart 24 meter network to expand the AMI coverage territory. Through software and radio 25 frequency compatibility, existing infrastructure and integrations were optimized, 26 which resulted in cost savings. Where possible, TGBs were located on existing 27
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1 poles or within owned facilities to avoid additional costs. Contractor services were 2 secured through a competitive solicitation, and work was coordinated to minimize 3 travel time and increase productivity levels. 4 5 41. Q. WHAT BENEFITS DOES THE PROJECT DELIVER TO CUSTOMERS? 6 A. The additional 25 TBGs deployed through this project have extended the 7 Company’s AMI coverage area. Customers within these areas can now fully utilize 8 the benefits of MyAccount including access or more timely access to real-time
9 consumption data, projected bill notifications, energy use by appliance, and remote
10 reconnection services. The larger coverage area eliminates the need to read meters
11 manually and reduces truck rolls required for routine and over-the-air work orders,
12 which translates into lower vehicle costs and the delivery of other customer services 13 more timely. 14 d/b/a NV Energy Nevada Power Company Company Power Nevada 15 F. Regional Network Interface (RNI) System Upgrade 4.2
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 42. Q. PLEASE DESCRIBE THE REGIONAL NETWORK INTERFACE (RNI) 17 SYSTEM UPGRADE 4.2 PROJECT. 18 A. The Regional Network Interface is the heart of the AMI network. It acts as the 19 primary control and head-end system for the data flow from and to all electric smart 20 meter and gas module endpoints. Alarms, meter readings, and control signals are 21 all sent and received by this operationally critical application. The Company 22 entered into a long term agreement with Sensus, the AMI network vendor, which 23 allows it to maintain all necessary operational and security updates for the system. 24 To accomplish this, the Company regularly applies patches and configuration 25 changes, and then every 18 to 24 months the system must undergo a version update 26 to replace any defective (bugs) or obsolete code and enhance functional ability 27
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1 (application improvements), including compatibility with new endpoint hardware 2 (meters) development (future proofing). Additionally, the updated version supports 3 newly released Sensus devices and technology, which are targeted to complement 4 the Companies’ energy conservation initiatives as well as supporting an integrated 5 gas meter/module device. This update project will replace RNI version 3.168 with 6 version 4.2. Just prior to filing this general rate review application, the in-service 7 date for the RNI System Upgrade slipped into June 2019. Therefore, the costs 8 associated with this project will be removed from revenue requirement when the
9 certification filing is made.
10
11 43. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
12 A. The total estimated cost of this project is $1,246,765. Additional detail regarding 13 the cost of the program is set forth in Table Follette Direct-8 below.
14 Table Follette Direct-8 d/b/a NV Energy Regional Network Interface Nevada Power Company Company Power Nevada 15 As of January 1, 2019 – Cost Category Total Cost December 31, 2018 May 31, 2019 and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Internal Labor $ 118,204 $ 58,976 $ 177,179 17 External Services $ 365,234 $ 230,182 $ 595,415 18 Materials $ 373,994 $ - $ 373,994 Internal Overheads $ 25,345 $ 5,778 $ 31,123 19 AFUDC $ 40,087 $ 28,966 $ 69,053 20 Total $ 922,863 $ 323,902 $ 1,246,765 21
22 44. Q. WHAT TYPE OF COSTS ARE INCLUDED IN THE EXTERNAL 23 SERVICES CATEGORY? 24 A. The majority, some 95.4 percent, of the estimated costs within the external services 25 category are associated with Sensus USA Inc., 54.5 percent, and Cognizant, 40.9 26 percent. The RNI system is a Sensus product, professional vendor services are 27
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1 required to complete the software upgrade. Cognizant supported the project with 2 project management and testing resources. 3 4 45. Q. WHAT MATERIAL PURCHASES WERE REQUIRED TO COMPLETE 5 THE UPGRADE? 6 A. Costs recorded in the material cost category include hardware and related software 7 and licenses. The upgrade from version 3.1 to 4.2 resulted in new database, 8 operating system, and storage requirements. Additional database, application, and
9 secondary storage servers were required to complete the project.
10
11 46. Q. WERE VENDOR SERVICES AND MATERIAL PURCHASES ACQUIRED
12 THROUGH COMPETITIVE MEANS? 13 A. Third party services and material purchases were acquired through competitive 14 sourcing events. The Sensus RNI system was selected as part of a competitive d/b/a NV Energy Nevada Power Company Company Power Nevada 15 request for proposal with the deployment of the AMI. Cognizant was awarded the
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 associated service contract in 2013 through a competitive bid. Material purchases 17 were placed through approved suppliers that were established competitively. 18 19 G. Advanced Metering Infrastructure Optimization – Electric Meters 20 47. Q. PLEASE DESCRIBE THE INVESTMENT IN ADVANCED METERING 21 INFRASTRUCTURE OPTIMIZATION – ELECTRIC METERS PROJECT. 22 A. In 2010, Sierra presented to the Commission, as part of its integrated resource plan, 23 a business case justifying a significant investment in the “smart grid.” Specifically, 24 the Company requested approval of an advanced metering infrastructure project 25 that all but eliminates the need to manually read meters, and manually initiate and 26 terminate service. The Commission approved the project, and the Company 27
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1 subsequently presented the costs associated with the project in regulatory rate 2 review proceedings. In consolidated Docket Nos. 14-05004 (involving Nevada 3 Power) and 14-05005 (involving Sierra), the Commission reviewed the costs 4 associated with the advanced service delivery project, as well as the operational 5 benefits captured for customers. After a thorough review of the costs by all 6 stakeholders, a stipulation was reached in which a small portion of the advanced 7 service delivery investment made by Sierra was reduced through a “one-time 8 permanent” adjustment. The balance of the investment was effectively determined
9 to be reasonable.
10
11 Since the close of the certification period in Sierra’s last general rate review
12 proceeding, the Company has continued to invest in AMI meters– approximately 13 $900,000 through the certification period in this general rate review proceeding. 14 These costs were managed following the same processes and procedures as the d/b/a NV Energy Nevada Power Company Company Power Nevada 15 project costs previously reviewed by the Commission.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 48. Q. WHY WAS THIS PROJECT NECESSARY? 18 A. With the Commission’s approval of the AMI program, the Company adopted smart 19 meters as the standard meter offering. It is incumbent on the Company to ensure 20 that every eligible legacy meter is exchanged with a smart meter. 21 22 23 24 25 26 27
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1 49. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 2 A. The table below shows the actual costs associated with this project. 3 Table Follette Direct-9 4 AMI Optimization June 1, 2016 - December 5 Cost Category Total Cost 31, 2018 6 Internal Labor $ 672,976 $ 672,976 External Services $ 63,724 $ 63,724 7 Materials $ 28,803 $ 28,803 8 Internal Overheads $ 132,946 $ 132,946 Other Expense $ 3,674 $ 3,674 9 Total $ 902,123 $ 902,123
10
11 50. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY?
12 A. Yes. 13 14 d/b/a NV Energy Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 18 19 20 21 22 23 24 25 26 27
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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
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EXHIBIT FOLLETTE-DIRECT- 2
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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-2 Ms. 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 0 0 0 FlexPay Program 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 8:44 6:26[1] 6:15[2] Before Reconnection (HH:MM) 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.
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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
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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 0 0 0 FlexPay Program 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 41 96 45 (days) 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 8:441 6:152 Days/Hours/Average Before Reconnection (HH:MM) Gas Service Reconnection Dollar Amount and Frequency N/A 0 0 Incurred
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
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1 CERTIFICATE OF SERVICE 2 I hereby certify that I have served the filing for NEVADA POWER COMPANY 3 D/B/A NV ENERGY AND SIERRA PACIFIC POWER COMPANY D/B/A NV 4 ENERGY in Docket 19-03040 upon the persons listed below by electronic mail:
5
6 Tammy Cordova Michael Saunders Staff Counsel Attorney General’s Office 7 Public Utilities Comm. of Nevada Bureau of Consumer Protection 1150 E. William Street 8945 W. Russell Road, Suite 204 8 Carson City, NV 89701-3109 Las Vegas, NV 89148 [email protected] [email protected]
9
10 Staff Counsel Division Attorney General’s Office Public Utilities Comm. of Nevada Bureau of Consumer Protection
11 9075 West Diablo Drive Suite 250 100 N. Carson St. 12 Las Vegas, NV 89148 Carson City, NV 89701 [email protected] [email protected] 13
d/b/a NV Energy 14 Nevada Power Company Company Power Nevada 15 and Sierra Pacific Power Company Pacific Power Sierra and Company 16 DATED this 3rd day of May, 2019.
17 /s/ Lynn D’Innocenti 18 Lynn D’Innocenti Sr. Legal Admin Assistant 19 Sierra Pacific Power Company Nevada Power Company 20 21 22 23 24 25 26 27 28
1 Page 144 of 250
Exhibit Follette-Direct-2
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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
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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 ge
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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 ge
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• 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 ge
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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.
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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
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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
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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 Cumulative Service Level within 60 seconds) (percentage of all calls answered within 30 seconds) 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%
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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.
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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%
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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%
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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.
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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.
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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%.
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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
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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.
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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%
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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%
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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
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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 0 0 0 FlexPay Program 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 41 96 45 (days) 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 6:265 6:156 Days/Hours/Average Before Reconnection (HH:MM) Gas Service Reconnection Dollar Amount and Frequency N/A 0 0 Incurred
5 Longest Duration: 4 days, 17 hrs. | Shortest Duration: 15 min. 6 Longest Duration: 15 hrs. 15 min. | Shortest Duration: 45 min.
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2018 NPC SPPC Overall MyAccount (Mobile Application) 168 21 189 Western Union Speed Pay 140 24 164 (Debit/Credit Card) MyAccount (Desktop) 89 14 103 FlexPay Customers Kiosk 54 0 54 Methods of Ready Pay 23 0 23 Payments Electronic Bank Bill Pay Payment 3 0 3 (transactions) Electronic Check Payment 2 0 2 Phone - Interactive Voice Response 0 1 1 Automated System Overall 479 60 539 Customer Started Application Process But Did Not Complete 377 30 407 Enrollment Enrollment Prerequisites Not 281 18 299 Completed Customer Requested 52 3 55 FlexPay Enrolled But Service Never Number of 10 0 10 Customers Who Activated At Address Transfer Back Other/Prefer Not To Answer 6 2 8 to Original Rate Non-Payment or Fraud 6 0 6 Schedule and Moved Out 5 0 5 Reasons New Customer Force Out 5 0 5 Unable To Manage Frequent 4 0 4 Payments 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 Deposit Reduction $8,150.00 $1,315.00 $9,465.00 Required Deposits and Past Due Past Due Balance Reduction $3,356.48 $480.41 $3,836.89 Balances At Program Enrollment January 0 0 0 February 0 0 0 March 0 0 0
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2018 NPC SPPC Overall April 0 0 0 Monthly Number of May 7 3 10 Calls Received June 2 1 3 by the Call July 5 0 5 Center August 7 1 8 Regarding the September 7 2 9 FlexPay October 6 6 12 Program November 6 1 7 December 15 4 19 Overall 55 18 73 January 0 0 0 February 0 0 0 March 0 0 0 April 0 0 0 May 0 0 0 Monthly June 1 0 1 Frequency of July 1 0 1 Disconnects August 2 0 2 September 4 1 5 October 2 1 3 November 2 0 0 December 10 2 12 Overall 22 4 26 89156 4 89118 3 89103 3 89031 3 89019 2 Geographic Breakdown of 89101 1 Disconnections 89052 1 for Non- 89139 1 Payment by Zip 89122 1 Code 89117 1 89108 1 89014 1 89512 3 89509 1
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2018 NPC SPPC Overall Number of Deposit Arrangements 1 1 2 Deposit Arrangements and Payment Arrangements Entered by Payment Arrangements 8 0 8 Participants Leaving FlexPay Program
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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).
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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.
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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
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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
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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
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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
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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
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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.
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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
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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
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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
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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
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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:
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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.
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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.
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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.
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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.
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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.
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The following two tables summarize the various MSI questions by company and the percentage of satisfied scores received by year.12
Percentage of Total Satisfied Responses (Scores 6-10)
Residential 2014 2015 2016 2017 2018 MSI Survey Question NPC SPPC NPC SPPC NPC SPPC NPC SPPC NPC SPPC • Overall Customer Overall 75% 85% 79% 88% 82% 87% 86% 93% 84% 90% Satisfaction (Question 1) Satisfaction
• Restoring Electric 85% 89% 87% 87% 83% 86% 82% 87% 81% 86% Service (Question 11) Reliability & Restoration • Providing Reliable 92% 92% 92% 93% 92% 92% 92% 92% 89% 91% Electric Service (Question 16) • Helping Customers Customer 74% 74% 74% 75% 70% 71% 64% 68% 65% 72% Use Energy Safely Safety (Question 20)
• Being Easy to do Service 81% 84% 83% 87% 81% 85% 84% 87% 81% 85% Business With (Question Reputation 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 ge
Page 191 of 250 Exhibit Follette-Direct-2
Percentage of Total Satisfied Responses (Scores 6-10)
Commercial 2014 2015 2016 2017 2018 MSI Survey Question NPC SPPC NPC SPPC NPC SPPC NPC SPPC NPC SPPC
• Overall Customer Overall Satisfaction 85% 84% 84% 89% 84% 89% 90% 89% 87% 87% Satisfaction (Question 1)
• Restoring Electric Service (Question 91% 88% 89% 93% 85% 90% 87% 90% 83% 87% 11) Reliability & Restoration • Providing Reliable Electric Service 95% 92% 96% 95% 93% 94% 94% 91% 91% 89% (Question 16)
• Helping Customers Use Customer Safety 82% 72% 80% 80% 72% 78% 68% 72% 67% 68% Energy Safely (Question 20)
• Being Easy to do Service Business With 87% 84% 88% 88% 83% 87% 85% 84% 85% 84% Reputation (Question 41)
NV Energy 2018 Service Quality & Metrics Report 42 | P a ge
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.
Satisfaction Index Score (0-100) MSI Survey Residential 2014 2015 2016 2017 2018 Question NPC SPPC NPC SPPC NPC SPPC NPC SPPC NPC SPPC • Being easy to do business with Service • Being responsive to 75 82 78 81 77 79 78 80 79 79 Reputation customer needs • Constantly improving the way they do business • Being a company you Management 74 81 76 82 70 74 71 76 76 77 can trust Reputation • Being well-managed • In general, considering the value you receive, Price and Value 69 78 72 77 69 76 68 75 72 75 would you describe NV Energy’s electric prices as…? • Helping customer understand the relationship between their Understanding 69 75 72 75 57 68 56 67 60 66 usage and what they are Rates charged • Reasonableness of Electric Rates • Offering assistance to customers who are having financial difficulties Financial 76 80 77 79 75 77 N/A N/A N/A N/A • Offering flexible bill Assistance13 payment plans to people who get behind paying their energy bills • Providing helpful tips on Energy 67 74 73 75 69 72 72 73 75 76 how to save money and Efficiency conserve energy • Involved in community activities Community 63 70 69 71 66 68 70 71 75 74 • Helping local economy Relations by retain and attract business and jobs • Keeping electric rates as low as possible Managing Rates 60 73 64 73 58 67 57 67 62 67 • Controlling costs while maintaining quality service • Informing customers about what the utility is Billing/Cost 70 78 74 75 82 85 82 85 82 83 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 ge
Page 193 of 250 Exhibit Follette-Direct-2
Satisfaction Index Score (0-100) MSI Survey Commercial 2014 2015 2016 2017 2018 Question NPC SPPC NPC SPPC NPC SPPC NPC SPPC NPC SPPC • In general, considering the value you receive, Price and Value 74 78 74 79 72 78 70 73 75 75 would you describe NV Energy’s electric prices as…? • Helping customer understand the relationship between Understanding 74 72 72 76 60 69 62 67 65 66 their usage and what Rates they are charged • Reasonableness of Electric Rates • Offering assistance to customers who are having financial Financial difficulties 78 75 79 80 76 79 N/A N/A N/A N/A Assistance14 • Offering flexible bill payment plans to people who get behind paying their energy bills • Providing helpful tips Energy 72 68 70 75 69 75 70 71 70 74 on how to save money Efficiency and conserve energy • Involved in community activities Community • Helping local 71 69 71 73 67 71 71 71 75 74 Relations economy by retain and attract business and jobs • Keeping electric rates as low as possible Managing 66 68 65 74 56 70 63 67 66 67 • Controlling costs Rates 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 ge
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 Exhibit Follette-Direct-2
1 CERTIFICATE OF SERVICE 2 I hereby certify that I have served the foregoing Annual Quality of Service Report
3 Informational Filing for NEVADA POWER COMPANY D/B/A NV ENERGY AND 4 SIERRA PACIFIC POWER COMPANY D/B/A NV ENERGY in Docket 19-03___ upon
5 the persons listed below by electronic mail: 6
7 Tammy Cordova Michael Saunders Staff Counsel Attorney General’s Office 8 Public Utilities Comm. of Nevada Bureau of Consumer Protection 1150 E. William Street 10791 W. Russell Road, Suite 204
9 Carson City, NV 89701-3109 Las Vegas, NV 89148 10 [email protected] [email protected]
11 Staff Counsel Division Attorney General’s Office Public Utilities Comm. of Nevada Bureau of Consumer Protection 12 9075 West Diablo Drive Suite 250 100 N. Carson St. 13 Las Vegas, NV 89148 Carson City, NV 89701 [email protected] [email protected] d/b/a NV Energy 14
Nevada Power Company Company Power Nevada 15 and Sierra Pacific Power Company Pacific Power Sierra and Company 16
17 DATED this 29th day of March, 2019.
18 /s/ Lynn D’Innocenti 19 Lynn D’Innocenti Sr. Legal Admin Assistant 20 Sierra Pacific Power Company Nevada Power Company 21 22 23 24 25 26 27 28
1 Page 198 of 250
Page 199 of 250
JENNIFER OSWALD
Page 200 of 250
1 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Sierra Pacific Power Company d/b/a NV Energy
3 2019 General Rate Case Docket No. 19-06___ 4
5 PREPARED DIRECT TESTIMONY OF
6 Jennifer Oswald
7 Revenue Requirement
8 I. INTRODUCTION
9 1. Q. PLEASE STATE YOUR NAME, OCCUPATION, AND BUSINESS
10 ADDRESS.
11 A. My name is Jennifer Oswald. I am Senior Vice President, Human Resources 12 and Corporate Services for NV Energy, Inc. and its two operating subsidiaries, 13 Nevada Power Company d/b/a NV Energy (“Nevada Power”) and Sierra d/b/a NV Energy 14 Pacific Power Company d/b/a NV Energy (“Sierra” or the “Company” and
Nevada Power Company Company Power Nevada 15 together with Nevada Power the “Companies”). My primary business address and Sierra Pacific Power Company Pacific Power Sierra and Company
16 is 6226 West Sahara Avenue in Las Vegas, Nevada. I am filing testimony on 17 behalf of Sierra. 18 19 2. Q. WHAT ARE YOUR PRIMARY RESPONSIBILITIES AS SENIOR 20 VICE PRESIDENT, HUMAN RESOURCES AND CORPORATE 21 SERVICES FOR NEVADA POWER AND SIERRA?
22 A. I am responsible for human resources and the corporate services functions, 23 which include procurement, corporate records, support services, property 24 management, interior services, and facilities maintenance. 25 26 27
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1 3. Q. PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND AND 2 EXPERIENCE. 3 A. I hold a Bachelor’s Degree in Business Administration from the University of 4 Delaware. I joined Nevada Power and Sierra in 2003, and have since held
5 various positions within the human resources area, which include management 6 of compensation and benefits programs as well as maintenance of human 7 resource systems and records. I assumed responsibility for the corporate 8 services functions in January 2015, and the procurement function in 2016. My
9 Statement of Qualifications is set forth in Exhibit Oswald-Direct-1.
10
11 4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC 12 UTILITIES COMMISSION OF NEVADA (“COMMISSION”)? 13 A. Yes, I have testified in a number of proceedings before the Commission. My most d/b/a NV Energy 14 recent general rate case (“GRC”) testimony was in Nevada Power’s 2017 GRC
Nevada Power Company Company Power Nevada 15 filing, consolidated Docket Nos. 17-06003 and 17-06004. and Sierra Pacific Power Company Pacific Power Sierra and Company
16 17 5. Q. WHAT IS THE PURPOSE OF YOUR PREPARED DIRECT 18 TESTIMONY? 19 A. I address test and certification period costs associated with the Company’s 20 employee compensation programs (including programs governing executive 21 compensation), benefits and retirement programs. When referring to the 22 combination of these programs, costs or expenses in my testimony, I use the 23 term “human resources” programs, costs or expenses. Sierra has included the 24 most recent cost information for human resources programs in the calculations 25 of revenue requirement for this filing. These costs and expenses include 26 incentive compensation not tied to performance against financial matrices. I 27
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1 also sponsor Schedule H-CERT-16, which documents the removal of the Long 2 Term Incentive Plan (“LTIP”) expense from cost of service. 3 4 I also support the category of investment in plant in service related to my
5 responsibility over the corporate services function. I describe in detail the one 6 major project undertaken by the organization since June 1, 2016, the extension 7 of Ampere Drive to improve large vehicle access and safety to the Ohm 8 Operations Center.
9
10 6. Q. DO OTHER WITNESSES PROVIDE PREPARED TESTIMONY
11 RELATING TO HUMAN RESOURCES EXPENSE? 12 A. Yes. Ms. Lisa Holder sponsors testimony addressing the reasonableness of test 13 and certification period costs associated with compensation programs, d/b/a NV Energy 14 including the 2.55 percent pay increase for non-represented employees
Nevada Power Company Company Power Nevada 15 (formerly known as management, professional, administrative, and technical and Sierra Pacific Power Company Pacific Power Sierra and Company
16 or “MPAT” employees) effective in December 2018. Ms. Michelle Follette 17 addresses information requested by the Commission in Sierra’s last general 18 rate review proceeding regarding cumulative customer service level metrics, 19 to assist in the evaluation of Short-Term Incentive Plan (“STIP”) benefits. Ms. 20 Mary Beth Collins and I co-sponsor the payroll proforma, Schedule H-CERT- 21 17 (Payroll, Benefits, and Pension Expense annualization). H-CERT-17 22 reflects the annualized benefits, pension and payroll costs including a portion 23 of STIP. Mr. Michael Behrens supports Schedule K-4 (“Analysis of Account 24 926 - Employee Pensions and Benefits for the Recorded Test Year Ended 25 December 31, 2018”). 26 27
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1 7. Q. ARE YOU SPONSORING ANY EXHIBITS WITH YOUR 2 TESTIMONY? 3 A. Yes. I am sponsoring the following exhibits:
4 • Exhibit Oswald-Direct-1 Statement of Qualifications
5 • Exhibit Oswald-Direct-2 Summary of Non-Cash Compensation 6 • Exhibit Oswald-Direct-3 2018 Short Term Incentive Plan Summary 7 • Exhibit Oswald-Direct-4 2018 Corporate Scorecard Third Quarter 8 • Exhibit Oswald-Direct-5 2018 Corporate Scorecard Fourth Quarter 9
10 II. SUMMARY OF SIERRA’S HUMAN RESOURCES COSTS
11 8. Q. PLEASE SUMMARIZE SIERRA’S APPROACH IN CALCULATING 12 REVENUE REQUIREMENT FOR HUMAN RESOURCES EXPENSES 13 IN A GENERAL RATE CASE. d/b/a NV Energy 14 A. As does Nevada Power, Sierra prepares its revenue requirement calculations
Nevada Power Company Company Power Nevada 15 using annualized human resources expense as of the certification date, in this and Sierra Pacific Power Company Pacific Power Sierra and Company
16 case May 31, 2019. The annualized Nevada jurisdictional amounts shown in 17 the revenue requirement calculation are $57.5 million (payroll), $9.9 million 18 (benefits), and $3.2 million (pension). These figures are as shown in Statement 19 H-CERT-17.1 A portion of jurisdictionalized STIP expense ($2.1 million) is 20 included in the revenue requirement calculation.2 21 22 23 24
25 1 The $57.5 million annualized payroll expense encompasses the $2.1 million of jurisdictionalized STIP 26 expense. 2 Sierra has not included the portion of STIP expense related to the financial matrices (16.7 percent) in 27 the calculation of revenue requirement.
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1 9. Q. GENERALLY, HOW ARE LABOR COSTS CHARGED AND 2 ALLOCATED? 3 A. As described in more detail by Ms. Collins, where possible, labor costs are 4 directly charged. Where appropriate (i.e., where an activity is performed on
5 behalf of one or more divisions), labor costs are allocated between Nevada 6 Power, the gas and electric divisions of Sierra, and NV Energy, Inc. Payroll 7 costs are also designated as capital expenditures or operation and maintenance 8 (“O&M”) expense. Payroll costs incurred to complete capital projects are
9 charged to those specific capital projects. Payroll costs not associated with
10 capital projects are charged to O&M and then are allocated between Nevada
11 jurisdictional expense and Federal Energy Regulatory Commission (“FERC”) 12 jurisdictional expense. While the compensation programs I address in my 13 prepared testimony apply to all payroll costs (capital and O&M, Nevada and d/b/a NV Energy 14 FERC jurisdictional), the payroll costs reflected in the payroll proforma (H-
Nevada Power Company Company Power Nevada 15 CERT-17) in this GRC represent the total O&M payroll allocable to Sierra’s and Sierra Pacific Power Company Pacific Power Sierra and Company
16 retail jurisdiction. 17 18 10. Q. FOR THE PURPOSE OF COMPENSATION DECISIONS, HOW ARE 19 EMPLOYEES CATEGORIZED? 20 A. For purposes of compensation, the Company groups its employees into the 21 following categories. 22 23 Represented employees (formerly referred to as Bargaining Unit employees) 24 are represented by the International Brotherhood of Electric Workers Local 25 Union 1245 (“Local 1245”) at Sierra and International Brotherhood of 26 27
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1 Electrical Workers Local Union 396 at Nevada Power. As of December 31, 2 2018, there were 507 Local 1245 regular employees at Sierra.3 3 4 Non-represented employees are not represented by a union. As of December
5 31, 2018, there were 1,195 non-represented regular employees at NV Energy, 6 Inc., Nevada Power and Sierra, which include non-exempt entry-level 7 employees to executive level employees and officers. As of December 31, 8 2018, NV Energy, Inc., Nevada Power and Sierra employed 21 officers.
9
10 11. Q. WHAT IS THE TOTAL O&M ELECTRIC PAYROLL, PENSION AND
11 BENEFITS EXPENSE IN THIS CASE AND HOW DOES THIS 12 AMOUNT COMPARE WITH THE AMOUNTS REFLECTED IN 13 PRIOR DOCKETS? d/b/a NV Energy 14 A. As reflected in Schedule H-CERT-17, the total annualized Nevada
Nevada Power Company Company Power Nevada 15 jurisdictional O&M payroll, benefits and pension expense estimate as of May and Sierra Pacific Power Company Pacific Power Sierra and Company
16 31, 2019, is $70.6 million (“2019 Total O&M Payroll”).4 This amount is $3.35 17 million greater than demonstrated in Sierra’s last GRC, Docket No. 16-06006. 18 As reflected in Schedule H-CERT-16, the portion of total annualized LTIP 19 expense estimate as of May 31, 2019 that has been removed from the revenue 20 requirement of retail electric customers is $994,000. Overall, the total costs 21 for O&M payroll, benefits and pension from H-CERT-17 and H-CERT-16 22 have increased just $1.673 million or 2.4 percent over total annualized O&M 23 payroll, benefits and pension expense demonstrated in 2016. The difference is 24 attributable to the portion of LTIP expense excluded in the calculation as well 25 as a slight increase in O&M payroll and benefits costs offset by a decrease in
26 3 A “regular” employee can be a full or part time employee. The term does not include temporary workers or student interns, for example. 27 4 This total does not include LTIP expense as represented on H-CERT-16.
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1 pension costs in H-CERT-17. Annualized payroll costs are estimated through 2 the certification period, May 31, 2019. 3 4 Figure Oswald-Direct-1 compares the 2019 Total O&M Payroll with total
5 O&M payroll, benefits, and pension costs requested for recovery in Sierra’s 6 most recent general rate cases. 7 FIGURE OSWALD-DIRECT-1 8 SIERRA’S O&M PAYROLL, PENSION, BENEFITS EXPENSE5 9
2019 2016 Variance 10 H-CERT-17 Payroll Expense $ 57,508 $ 54,620 $ 2,888 11 Benefits $ 9,920 $ 8,834 $ 1,086 12 Pension $ 3,185 $ 3,809 $ (624) Total $ 70,613 $ 67,263 $ 3,350 13
d/b/a NV Energy 14 H-CERT-16
Nevada Power Company Company Power Nevada LTIP $ - $ 1,677 $ (1,677) 15
and Sierra Pacific Power Company Pacific Power Sierra and Company
16 Total H-CERT-17 & H-CERT-16 $ 70,613 $ 68,940 $ 1,673 17 18 12. Q. HOW HAS SIERRA BEEN ABLE TO ACHIEVE THE TOTAL O&M 19 PAYROLL RESULTS INDICATED ABOVE? 20 A. The 2019 Total Payroll is a function of several variables: wages, benefits cost, 21 pension cost and headcount. As demonstrated above, Sierra has successfully 22 managed these variables to control total payroll, benefits and pension costs. 23 Although total payroll expense has increased slightly, cost increases have been 24 mitigated with careful management of salary and benefits expenses. This 25 shows that the salary increases for non-represented employees (necessitated to 26 keep pace with the market) and pay increases for represented employees
27 5 In Figure-Oswald-Direct-1, LTIP expense is not included in any of the annual cost calculations.
28 Oswald-DIRECT 7
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1 governed by the collective bargaining agreement with Local 1245, continue to 2 be offset through efficiency gains. The reasonableness of Sierra’s wage and 3 salary levels are supported by detailed benchmarking data and reflect 4 competitive market rates for utility employees as I describe below, and as Ms.
5 Holder addresses as well. 6 7 13. Q. GENERALLY, HOW DO LOCAL, REGIONAL AND NATIONAL 8 ECONOMIC CONDITIONS IMPACT SIERRA’S HUMAN
9 RESOURCES COSTS?
10 A. The Company competes for talent here, locally, as well as regionally and
11 nationally. Depending on the position, the primary employment market can be 12 local, regional or national. Managing human resources costs requires 13 understanding and tailoring compensation and benefits packages to the d/b/a NV Energy 14 relevant employment market. Positions requiring key skills continue to
Nevada Power Company Company Power Nevada 15 demand a market rate that is specific to each position, and market rates for and Sierra Pacific Power Company Pacific Power Sierra and Company
16 skilled positions have continued to increase, albeit modestly, over the past 17 three years. Moreover, attracting and retaining top talent remains a high 18 priority, and Sierra must maintain competitive pay levels, as determined by 19 the appropriate markets (local, regional and national), in order to do so. In 20 order to maintain competitive compensation levels for our employees without 21 increasing costs for our customers, we strive to capture efficiency gains. 22 23 While the Company recruits for experienced critical positions primarily from 24 regional and national markets, the Company is committed to supporting the 25 local employment market as well. In 2018, the Company hired 10 additional 26 temporary student interns at Sierra, for a total of 27, converted one existing 27
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1 intern to a full-time employee, and filled an additional 69 positions externally, 2 with 89 percent (or 62 new hires) from local northern Nevada markets. 3 4 14. Q. HAS THE COMPANY APPROPRIATELY MANAGED ITS HUMAN
5 RESOURCES COSTS? 6 A. Yes. Test period costs in this case reflect Sierra’s diligence in managing 7 human resources costs without compromising service quality or reliability. 8
9 Initiatives to control test period human resources costs include the following:
10 • As a result of attrition, the Company conducted reorganizations that
11 resulted in some position consolidation and headcount reduction. Total 12 headcount at Sierra, including NV Energy regular employees 13 (excluding Local 396) decreased from 1,765 in 2016 to 1,701 in 2018, d/b/a NV Energy 14 a reduction of 3.6 percent. Nevada Power Company Company Power Nevada 15 • The Company has lowered STIP costs for non-represented employees and Sierra Pacific Power Company Pacific Power Sierra and Company
16 from years prior by paying less than or equal to the payout target of 17 100 percent.
18 • Several retirees and terminations have been backfilled with lower-level 19 positions or less-experienced candidates resulting in a decrease in base 20 salaries.
21 • The Company continually reassesses staffing needs and analyzes 22 competitive compensation data for all new positions.
23 • A number of cost management measures related to employee benefits 24 have been taken to better align our expenses with our financial targets 25 and economic projections. The Company has: 26 27
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1 o Implemented consumer-driven health plans for Local 1245 2 employees effective January 1, 2015.
3 o Effective January 2015, replaced non-represented new hire 4 employees’ eligibility in the cash balance pension plan with a 4
5 percent contribution to the 401(k) program.
6 o Effective January 2017, replaced Local 1245 new hire employees’ 7 eligibility in the cash balance pension plan with a 4 percent 8 contribution to the 401(k) program.
9 Conducted a Request for Proposal (“RFP”) for dental plan
o 10 providers, which realized a cost savings from our current dental
11 care provider.
12 o Conducted an RFP for vision plan providers, which realized a cost 13 savings from our current vision care provider. d/b/a NV Energy 14 o Conducted an RFP for life insurance program administrators Nevada Power Company Company Power Nevada 15 resulting in a cost savings. and Sierra Pacific Power Company Pacific Power Sierra and Company
16 17 In short, the Company is continuing to reduce human resources costs while 18 maintaining the critical skills needed to continue to provide safe and reliable 19 service to our customers. 20 21 15. Q. HOW IS THE REMAINDER OF YOUR TESTIMONY ORGANIZED? 22 A. Part III provides an overview of Sierra’s overall compensation programs and 23 policies. In part IV, I support the prudence of the STIP program. In Part V, I 24 support the prudence of other cash compensation programs. In Part VI, I 25 support the prudence of Sierra’s non-cash compensation programs. In Part VII, 26 I address Sierra’s pension program, including the restoration plan. 27
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1 III. OVERVIEW OF COMPENSATION PROGRAMS AND POLICIES 2 16. Q. PLEASE DESCRIBE SIERRA’S OVERALL COMPENSATION 3 PHILOSOPHY. 4 A. Sierra strives to achieve a median position as compared to its competitors for
5 the total compensation program, which includes cash and non-cash benefits 6 provided to employees in return for their services. We offer competitive total 7 compensation that includes a market competitive base wage; competitive 8 variable pay for performance; a competitive package of employee benefits
9 (medical/dental/vision, wellness, educational reimbursement, service awards
10 and retirement programs); competitive programs to protect employees and
11 their families against catastrophic economic loss in the event of large health 12 care, disability, or death (life insurance, disability insurance, accidental death 13 and dismemberment insurance, business travel accident insurance); and post- d/b/a NV Energy 14 employment benefits. This combination of compensation and benefits targeted
Nevada Power Company Company Power Nevada 15 at median permits Sierra to attract and retain qualified and motivated and Sierra Pacific Power Company Pacific Power Sierra and Company
16 employees, and to provide safe, reliable and reasonably-priced service to our 17 customers. 18 19 Sierra’s compensation plan also takes into account the critical need to retain 20 top industry-specific talent. While efficiency and cost reduction measures are 21 always a priority, our compensation plan must continue to keep the future 22 needs of Sierra’s customers in mind. The Company uses a comprehensive 23 workforce planning approach across the business units. By combining the 24 forecast of workload needs with employee demographics, the business units 25 can effectively manage and mitigate risks to the organization and ensure that 26 we secure an adequate workforce to meet customer demands, maintain safety 27
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1 and deliver cost-effective, reliable electric and gas service. Maintaining a 2 competitive compensation program to retain the existing talent pool is a top 3 priority. 4
5 17. Q. HOW ARE TOTAL COMPENSATION LEVELS DETERMINED? 6 A. The Company’s philosophy is to fairly compensate its workforce for the value 7 of the work provided. Without a balanced compensation program, recruitment, 8 retention, motivation and productivity are jeopardized. The goal is to provide
9 a competitive compensation program at the median level of what an employee
10 could receive at another company.
11 12 To ensure competitive compensation, the Company starts with an evaluation 13 of the current market value of positions based on the knowledge, skills and d/b/a NV Energy 14 talents required of a fully competent incumbent. Sierra does this by using
Nevada Power Company Company Power Nevada 15 regional, national, and industry-specific benchmarking data, in order to and Sierra Pacific Power Company Pacific Power Sierra and Company
16 achieve what is termed “external equity” in the industry literature. In addition, 17 the Company evaluates internal equity – the relative worth of each job 18 category within Sierra when comparing the required level of job competencies, 19 training, experience, responsibilities and accountability of one job to another. 20 The compensation program is also designed to encourage collaboration and 21 focus on corporate goals, most importantly excellent customer service. 22 Further, the compensation program is designed to reward employees who 23 drive results through strong individual performance. 24 25 26 27
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1 18. Q. PLEASE SUMMARIZE THE COMPONENTS OF THE TOTAL 2 COMPENSATION PROGRAM THAT ARE AVAILABLE TO 3 SIERRA’S EMPLOYEES. 4 A. The elements of the total compensation package that are included in this case
5 are as follows: 6 Base Pay. All employees receive base pay. 7 STIP. All non-represented employees are eligible to participate in the 8 STIP. STIP payments are based on corporate goals target of 100 percent and
9 vary from year to year depending upon the achievement of Company-wide
10 goals and a combination of the achievement of business unit or departmental
11 goals and the individual employee’s performance. As I describe in some detail 12 below, Company-wide goals are aligned with the following six core principles: 13 Customer Service, Employee Commitment, Environmental Respect, d/b/a NV Energy 14 Regulatory Integrity, Operational Excellence, and Financial Strength. In 2018,
Nevada Power Company Company Power Nevada 15 all eligible employees were assigned an individual performance rating. STIP and Sierra Pacific Power Company Pacific Power Sierra and Company
16 payments were only paid to eligible employees with performance ratings of 17 “performing well” or higher. 18 LTIP. Most non-represented employees at the director-level and 19 above are eligible to participate in the LTIP. The LTIP payments are based on 20 a corporate goals target of 100 percent and vary from year to year depending 21 upon the achievement of Company-wide goals, which are aligned with the six 22 core principles. 23 Safety Bonus. All Local 1245 represented employees are eligible to 24 participant in the Safety Bonus program. If safety objectives are achieved, 25 employees can earn up to a 2 percent lump sum bonus. 26 27
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1 Retirement Plans. All employees hired prior to 2017 are eligible to 2 participate in Sierra’s pension and 401(k) programs. Sierra has a traditional 3 defined benefit pension program (for some legacy employees) but moved to a 4 cash balance pension program beginning in 2008 for non-represented
5 employees and in 2011 for Local 1245 employees. Effective January 1, 2015, 6 for non-represented new hires and January 1, 2017, for Local 1245 new hires, 7 the Company discontinued cash balance pension eligibility and instead offers 8 a defined contribution to the 401(k) plan. Certain key employees also
9 participate in supplemental retirement plans due to Internal Revenue Service
10 (“IRS”) limitations imposed upon tax qualified pension plans. The
11 supplemental programs include a “restoration plan” and a “supplemental 12 executive retirement program” or “SERP.” Benefit accruals under the SERP 13 were frozen as of December 31, 2014. SERP costs are not reflected in the d/b/a NV Energy 14 revenue requirement calculated in this case.
Nevada Power Company Company Power Nevada 15 Other Cash Compensation. Signing, retention, other bonuses, and Sierra Pacific Power Company Pacific Power Sierra and Company
16 severances and relocation are offered to individual employees based upon 17 unique circumstances. There were no severance costs for Sierra during the test 18 year. 19 Non-Cash Compensation. All employees receive non-cash 20 compensation, which is comprised of medical, dental, vision, life insurance, 21 accidental death and dismemberment insurance, business travel accident 22 insurance, disability insurance, and other benefit programs and recognition 23 available to employees. Exhibit Oswald-Direct-2 is a summary of the non- 24 cash compensation programs available to Sierra’s employees. 25 26 27
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1 IV. VARIABLE PAY PROGRAMS INCLUDING STIP, SAFETY BONUSES AND 2 LTIP PLANS 3 19. Q. WHY DO THE COMPANIES OFFER VARIABLE PAY TO 4 EMPLOYEES?
5 A. Variable pay or “pay for performance” programs differ from other forms of 6 compensation. With variable pay, each eligible employee and the Company as 7 a whole must re-earn this reward every year. Variable pay programs 8 incentivize individuals to drive positive results, have economic advantages,
9 and help with recruitment, retention, motivation, and communication of
10 important priorities. I discuss these advantages below.
11 Economics. One of the most significant advantages of variable pay is 12 the transfer of a portion of an employee’s fixed cost, in the form of a salary, to 13 a variable cost that is only incurred if the employee and the Company achieve d/b/a NV Energy 14 desired results. When variable costs are aligned with performance, they serve
Nevada Power Company Company Power Nevada 15 as a driver of desired results. The conversion of what would otherwise have and Sierra Pacific Power Company Pacific Power Sierra and Company
16 been fixed costs into variable costs is significant, because variable pay awards 17 do not compound like base pay adjustments do. If strong corporate and 18 individual performance is not sustained, variable pay can be reduced or 19 eliminated. Escalation rates can be better managed over time and quickly 20 adapted to changing market pressures. 21 Recruitment and Retention. Variable pay programs provide the 22 Companies with the flexibility to offer a fair and attractive individual 23 compensation packages, which is critical to attract, engage and retain talented 24 employees. Variable pay targets compensation dollars in the right way, 25 ensuring top performers that they will have the opportunity to be rewarded for 26 their performance. With variable pay among the types of compensation 27
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1 offered, the Companies are able to attract high performers who are confident 2 of their abilities. Retention of talent also is improved with variable pay 3 programs in that there is a clear communication of what is expected from 4 eligible employees—they know exactly where to target their efforts and
5 exactly what achievements will be rewarded. Gallup research has shown that 6 clear understanding of expectations and recognition for performance are 7 strongly linked to employee engagement. 8 Motivation and Business Goals. The motivational potential of
9 variable pay is stronger than that of other forms of compensation. Variable pay
10 that is tied to defined objectives and standards allows the organization to pay
11 for performance at every level by providing a sharp focus on its priorities. The 12 Companies’ variable pay programs focus non-represented employees on the 13 six core principles, including customer service, employee commitment, and d/b/a NV Energy 14 operational excellence while also rewarding them for strong individual
Nevada Power Company Company Power Nevada 15 performance results that impact Company goals. The Safety Bonus program and Sierra Pacific Power Company Pacific Power Sierra and Company
16 focuses our represented employees on essential Company and employee safety 17 objectives. When employees understand how their contributions impact the 18 organization’s success, and when they know that this is being measured, they 19 are more likely to see themselves as partners in reaching defined goals. 20 Variable pay reinforces successful employees and provides a scorecard to 21 enable individuals to continuously evaluate and improve results. By including 22 individual and organization-wide goals within the incentive system, variable 23 pay motivates employees to collaborate and achieve results. 24 Communication. Variable pay is one of the strongest signals an 25 organization can send to its employees about what is important. Programs like 26 the STIP and LTIP serve to cascade measures and goals from the top of the 27
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1 organization downward, to move individuals into alignment with and 2 commitment to the Company’s articulated priorities and strategy. Through the 3 balanced scorecard process, corporate and business unit strategies become 4 more focused and aligned. Targets are clear and uncompromised. Objectives
5 are fully understood and implemented. Key priorities can be identified, 6 optimized, and adequately funded. The variable pay plan provides a roadmap 7 to employees about what is expected of them. It communicates to employees 8 that their work is valued and that a high performance culture will be rewarded.
9 By continually measuring results, high quality feedback can be provided so
10 that employees know how they are doing and how they can impact results and
11 rewards. 12 13 20. Q. HAVE STUDIES CONFIRMED THAT VARIABLE PAY ACHIEVES d/b/a NV Energy 14 THESE OBJECTIVES?
Nevada Power Company Company Power Nevada 15 A. Yes. A wide body of research supports the view that variable pay works when and Sierra Pacific Power Company Pacific Power Sierra and Company
16 applied correctly. According to a recent study conducted by Salary.com, 17 Organizations Embracing Variable Pay (Salary.com January 8, 2019), 18 organizations with a formal pay-for-performance philosophy are more than 19 twice as likely to have above average or excellent employee engagement. A 20 pay-for-performance philosophy contributes to employee engagement by 21 clearly tying employee or company achievement of performance goals to 22 tangible financial rewards. These programs also enable employees to see a 23 clear connection between the work they do every day and the success of the 24 company as a whole. They can also facilitate more frequent conversations 25 about individual and company performance. 26 27
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1 In Designing and Managing Incentive Compensation Programs (Society for 2 Human Resources Management January 12, 2018) the author notes that when 3 applied to the corporate setting, incentive compensation programs enable 4 organizations to produce targeted results by rewarding employees who are
5 responsible for those results. The article also highlights that while incentive 6 compensation programs are primarily used to promote efficiency and 7 productivity of the workforce, organizations can also use them to enhance 8 employee recruitment, engagement, retention and employer branding.
9
10 21. Q. IS IT COMMON FOR EMPLOYERS IN TODAY’S MARKETPLACE
11 TO PUT A PORTION OF CASH COMPENSATION AT RISK? 12 A. Yes. Most organizations use variable pay as a significant element of their total 13 rewards package. According to World at Work’s 2018-2019 Salary Budget d/b/a NV Energy 14 Survey, the use of variable pay remained steady at 85 percent in 2018, with a
Nevada Power Company Company Power Nevada 15 combination of awards based on both organization and/or unit success and and Sierra Pacific Power Company Pacific Power Sierra and Company
16 individual performance continuing to be the most prevalent types of variable 17 pay program.
18 19 22. Q. ARE ALL OF SIERRA’S FULL TIME EMPLOYEES ELIGIBLE TO 20 PARTICIPATE IN THE STIP? 21 A. No. As discussed below, Sierra renegotiated the terms of its incentive program 22 with represented employees. Only Sierra’s non-represented employees are 23 eligible to participate in the STIP. Represented employees participate in the 24 Safety Bonus program, through which they are eligible to earn up to a 2 25 percent lump sum, which began in 2016. 26 27
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1 23. Q. PLEASE DESCRIBE THE STIP. 2 A. The Company’s STIP provides the opportunity for non-represented employees 3 to earn an incentive award based on achievement of Company-wide goals 4 related to the six core principles as well as individual performance.
5 6 Incentive awards are calculated using an eligible target percentage associated 7 with each job and salary band, ranging from 5 percent for non-exempt 8 employees to 20 percent for directors and increased percentages for officers.
9 Figure Oswald-Direct-2 provides the 2018 target STIP rates. For 2018, if
10 goals were met, the percentage is applied to the employee’s base pay to
11 determine the incentive compensation. STIP is not paid to an individual 12 employee unless corporate goals are achieved and the individual employee’s 13 performance is rated “performing well” or higher. STIP awards are determined d/b/a NV Energy 14 each year and do not increase an employee’s base pay.
Nevada Power Company Company Power Nevada 15 FIGURE OSWALD -DIRECT-2 and Sierra Pacific Power Company Pacific Power Sierra and Company
2018 TARGET STIP RATES 16 Non Exempt 5-10% 17 Exempt Individual Contributor 6-25% Team Leader 12.5-15% 18 Manager 15-25% Director 20% 19 Executives 20-35% (Level eliminated in 2019) 20 Vice Presidents 20-50% 21 Senior Vice Presidents 40-75% 22 CEO 100%
23
24
25
26 27
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1 24. Q. IS SIERRA SEEKING TO INCLUDE ANY PORTION OF LTIP COSTS 2 IN ITS CALCULATION OF REVENUE REQUIREMENT? 3 A. No. The Company is not seeking to include any portion of LTIP costs in its 4 revenue requirement calculation. This approach is consistent with the 5 Commission’s determination in Nevada Power’s last general rate review 6 proceeding, Docket No. 17-06003. 7 8 25. Q. WHAT WERE THE STIP GOALS DURING THE TEST PERIOD IN
9 THIS CASE? 10 A. The 2018 STIP Summary is provided as Exhibit Oswald-Direct-3. The STIP
11 goals for 2018 are reflected on the 2018 corporate scorecard, which is provided 12 as Exhibit Oswald-Direct-4. c Power Company c Power 13
d/b/a NV Energy NV Energy d/b/a 14 26. Q. DO THE COMPANIES RE-EVALUATE VARIABLE PAY GOALS
Nevada Power Company Power Nevada 15 EVERY YEAR? and Sierra Pacifi and Sierra 16 A. Yes. Even the best-designed plan must be continually evaluated and refreshed 17 for appropriateness. The Company’s STIP program requires continual 18 attention to ensure that corporate, departmental and individual goals remain 19 aligned. Our compensation organization is not bashful in proposing 20 improvements, responding to changing economic conditions, and focusing on 21 more effective organizational strategies. As I discussed above, the corporate 22 scorecard is focused on the six core principles: Customer Service, Employee 23 Commitment, Environmental Respect, Regulatory Integrity, Operational 24 Excellence and Financial Strength. The goals associated with each core 25 principle are cascaded down from the CEO to vice-president level scorecards 26 for each business unit which are then cascaded down to director or manager 27
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1 level scorecards at the department level. Leaders engage in quarterly 2 discussions with their non-represented employees at the individual contributor 3 level to ensure that individual employees see and are in alignment with overall 4 priorities, strategy, and how their individual performance will impact results.
5 As noted above, variable pay awards for individual contributors are earned 6 based on both business unit and/or department scorecard results, which align 7 with corporate goals and individual performance contributions. 8
9 27. Q. YOU EMPHASIZE THAT CORPORATE GOALS ALIGN WITH THE
10 COMPANIES’ CORE STRATEGIC OBJECTIVE – PROVIDING
11 IMPROVED CUSTOMER EXPERIENCE WHILE SAFELY AND 12 RELIABLY DELIVERING AFFORDABLE ENERGY PRODUCED IN 13 AN ENVIRONMENTALLY FRIENDLY AND SUSTAINABLE d/b/a NV Energy 14 MANNER. DOES ALIGNMENT OF INDIVIDUAL PERFORMANCE
Nevada Power Company Company Power Nevada 15 WITH THESE OBJECTIVES DRIVE PERFORMANCE THAT and Sierra Pacific Power Company Pacific Power Sierra and Company
16 BENEFITS CUSTOMERS? 17 A. Yes, the Companies’ corporate goals – and therefore its variable pay programs 18 – are designed to reward performance, both individually and Company-wide, 19 that benefit customers. All corporate goals support the six core principles and 20 are measured through key performance indicators that are designed to drive 21 performance that benefits customers.
22 • The customer service goals focus on delivering reliability, dependability, 23 fair prices and exceptional service to our customers and are measured 24 through J.D. Power residential/business survey results, Market Strategies 25 International survey results, and Mastio key account survey results. In 26 addition, a customer satisfaction improvement plan has been developed to 27
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1 maintain employee focused on continuous improvement of customer 2 focus/service.
3 • The employee commitment goals are measured through OSHA recordable 4 incidents, preventable vehicle accidents and employee training and
5 development. The primary focus of safety metrics is to ensure the health 6 and welfare of our employees. In addition, by reducing employee injuries 7 and preventable vehicle accidents, costs decrease for our customers in the 8 form of equipment repair, insurance premiums, medical claim costs and
9 non-productive time away from work. The employee training and
10 development metric ensures employees have the training and tools they
11 need to progress in their careers with the Company, deliver results and 12 improve business performance.
13 • The environmental respect goal focuses on reductions in CO2 emissions, d/b/a NV Energy 14 which keeps employees focused on greater efficiency, fewer
Nevada Power Company Company Power Nevada 15 environmental impacts and lower operating costs, all actions that benefit and Sierra Pacific Power Company Pacific Power Sierra and Company
16 customers.
17 • The regulatory integrity goals benefit our customers by ensuring 18 transparency and accountability regarding all regulatory matters including, 19 but not limited to, rate-setting and policy making.
20 • The operational excellence is measured by the system average interruption 21 duration for electric outages and generation fleet availability for gas and 22 coal plants. Both of these measures improve service and control costs for 23 our customers. Additional performance indicators have been added to 24 increase focus on physical and cyber security to ensure we protect our 25 customers and customer data and operating assets effectively. In addition, 26 27
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1 a grid resiliency plan has been developed to ensure we can effectively 2 deliver services to our customers. 3 4 28. Q. DID THE COMPANY ACHIEVE THE CORPORATE GOALS SET
5 DURING 2018? 6 A. The Company achieved 82.8 percent of the corporate scorecard goals. The 7 corporate scorecard results are provided as Exhibit Oswald-Direct-4. 8
9 29. Q. DESCRIBE THE FORECASTED PERFORMANCE RESULTS
10 REFLECTED ON THE 2018 CORPORATE SCORECARD.
11 A. The key performance indicators reflected on the corporate scorecard are 12 defined across the six core principles. Performance results for each core 13 principle are described below. d/b/a NV Energy 14 • Customer Service received a weight of 16.7 percent. The goals included Nevada Power Company Company Power Nevada 15 seven key performance indicators measuring customer satisfaction and Sierra Pacific Power Company Pacific Power Sierra and Company
16 through various residential and commercial customer surveys. Results for 17 the J.D. Power business, Market Strategies International commercial 18 south, Market Strategies International residential south, and Mastio key 19 accounts met or exceeded the targets established for 2018. J.D. Power 20 residential, Market Strategies International commercial north, and Market 21 Strategies International residential north did not meet the 2018 target 22 performance level. The customer satisfaction improvement plan was on 23 track for successful implementation. This performance resulted in a score 24 of 12.7 percent for customer service.
25 • Employee Commitment received a weight of 16.7 percent. The safety 26 goals included key metrics to improve the OSHA incident rate and number 27
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1 of preventable vehicle accidents. An additional target was set to enhance 2 employee training and development plans. The Company met or exceeded 3 performance related to each goal other than the improved OSHA incident 4 rate resulting in a score of 9.5 percent.
5 • Environmental Respect received a weight of 16.6 percent with a single
6 key performance indicator focused on CO2 emissions. The Company met 7 or exceeded its environmental respect goal at 16.6 percent. Again, more 8 efficient, environmentally friendly operations reduce operating costs.
9 • Regulatory Integrity received a weight of 16.7 percent. The goals
10 included achievement of allowed return on equity and delivery of balanced
11 outcomes in regulatory and legislative environments. The Company met 12 or exceeded its regulatory integrity goals and scored 16.7 percent. 13 Similarly, each of these key regulatory goals improves efficiency and d/b/a NV Energy 14 benefits customers. Nevada Power Company Company Power Nevada 15 • Operational Excellence received a weight of 16.6 percent. The goals and Sierra Pacific Power Company Pacific Power Sierra and Company
16 included system average interruption duration for electric outages and 17 generation fleet availability for gas and coal plants which are intended to 18 improve service and control costs for our customers. Key performance 19 indicators were also measured related to gas incidents, cybersecurity and 20 grid resilience plans. The Company successfully met its operational 21 excellence goals, with the exception of the System Average Interruption 22 Duration Index (SAIDI) and reportable gas incidents. This performance 23 resulted in a score of 10.6 percent for operational excellence.
24 • Financial Performance received a weight of 16.7 percent. The costs 25 associated with this metric are not included in the revenue requirement 26 calculated in this case. 27
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1 30. Q. PLEASE IDENTIFY THE O&M PORTION OF THE STIP COSTS 2 THAT ARE INCLUDED IN THE CALCULATION OF REVENUE 3 REQUIREMENT IN THIS CASE. 4 A. The revenue requirement calculations in this filing reflects 66.1 percent of
5 STIP costs paid in December 2018. 6 7 Sierra’s calculated annual revenue requirement includes the jurisdictional 8 component of $2.1 million for STIP expense. This request is a calculated
9 figure reflecting a portion of the STIP amount paid in December 2018.
10
11 31. Q. HOW IS THE STIP FUNDING LEVEL CALCULATED? 12 A. The STIP is funded at an aggregate payout of 100 percent of target assuming 13 achievement of incentive plan goals. The 100 percent target payout is then d/b/a NV Energy 14 modified based on forecasted corporate scorecard results. STIP was funded at
Nevada Power Company Company Power Nevada 15 82.8 percent for 2018. and Sierra Pacific Power Company Pacific Power Sierra and Company
16 17 32. Q. WHEN ARE PERFORMANCE RESULTS EVALUATED TO 18 DETERMINE FUNDING FOR THE STIP? 19 A. The evaluation of corporate scorecard results for determination of incentive 20 plan funding is completed using results as of September 30, 2018. The funding 21 level recommendation is based on year-end forecasted results. The forecasted 22 results and initial funding recommendations in early October allow time for 23 the preparation, review and analysis of STIP awards for eligible employees. 24 Monthly performance updates continue to be prepared and reviewed to ensure 25 that there are no significant deviations from the funding recommendation prior 26 to final approval on any STIP payments in early December. 27
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1 33. Q. HOW DO THE YEAR-END PERFORMANCE RESULTS COMPARE 2 TO THE SEPTEMBER FORECAST? 3 A. The fourth quarter and final scorecard for 2018 is provided as Exhibit 4 Oswald-Direct-5. With two exceptions, fourth quarter performance equaled
5 forecasted performance from the September scorecard. Results from J.D. 6 Power were lower than forecasted, and preventable vehicle accidents were 7 higher. 8
9 Although the J.D. Power business goal fell short of the 2018 target, the
10 Companies achieved a ranking in 57.6 percentile, a significant improvement
11 from 2017 performance. In 2017, the Company ranked 69th out of 86 total 12 companies resulting in a percentile ranking of 80.2 percent. In 2018, the 13 Company ranked 49th out of 85 total companies resulting in a percentile d/b/a NV Energy 14 ranking of 57.6 percent. Nevada Power Company Company Power Nevada 15 and Sierra Pacific Power Company Pacific Power Sierra and Company
16 Based on the favorable performance year-over-year related to the J.D. Power 17 business survey score and the sustained high-level performance year-over- 18 year related to preventable vehicle incidents there was no modification made 19 to the incentive plan funding level based on a review of the final 2018
20 corporate scorecard results. 21 22 34. Q. PLEASE COMPARE THE 2018 STIP PAYOUT WITH THE 23 AMOUNTS PAID IN PRIOR YEARS. 24 A. Figure Oswald-Direct-3 shows the STIP amounts paid in 2012-2018.
25
26
27
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1 Figure Oswald-Direct-3 STIP Payout Summary 2012-2018 (Total Company) 2 ($Millions)
3
4 STIP/Safety Total Bonus Represented Non-represented 5 STIP/Safety Plan Payout Total Total Bonus Payout 6 Year Year Employees Payout $ Employees Payout $
7 2012 2013 611 1.8 1,221 17.9 19.7
8 2013 2013 584 1.1 1,216 15.1 16.2 9 2014 2014 1,296 1.8 1,145 14.8 16.6 10 2015 2015 1,271 1.8 1,217 15.1 16.9
11 2016 2016 1,251 1.8 1,222 13.8 15.6 12 2017 2017 1,241 2.5 1,215 13.2 15.7 13 2018 2018 1,256 2.5 1,207 13.8 16.3 d/b/a NV Energy 14
Nevada Power Company Company Power Nevada 15 - Total Payout $ includes both STIP and Safety Bonuses. Employees who have transferred to/from represented positions may receive prorated STIP and Sierra Pacific Power Company Pacific Power Sierra and Company
- 16 payments. - Data includes any prorated STIP payouts made to retirees. 17 - 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 18 at 90% of target.
19 20 35. Q. IS THE LEVEL OF STIP COSTS INCLUDED IN THE REVENUE 21 REQUIREMENT CALCULATIONS IN THIS CASE REASONABLE, 22 AND DOES IT REPRESENT A RECURRING EXPENSE? 23 A. Yes. The payout under the STIP program is based on the Company’s 24 performance on the objective corporate scorecard metrics and, if goals are 25 achieved, would be funded and paid only up to the target of 100 percent. 26 Consistent with prior Commission orders, the Company is not requesting STIP 27
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1 payout related to the financial strength metrics. STIP and Safety Bonuses are 2 variable pay based on Company, business unit and/or department, and 3 individual performance, and are paid as a percentage of base salaries. Thus, 4 there will be variances in costs year over year. Nevertheless, total target
5 compensation levels are representative and competitive, as measured by the 6 benchmarking data reflected within Ms. Holder’s testimony. 7 8 V. OTHER CASH COMPENSATION PROGRAMS
9 36. Q. PLEASE DESCRIBE SIERRA’S OTHER CASH COMPENSATION
10 PROGRAMS.
11 A. Sierra pays signing, retention and other bonuses, and severances and 12 relocation expenses to its employees, based upon particular circumstances. 13 Severance expense is not included in the payroll proforma, Schedule H-CERT- d/b/a NV Energy 14 17. Relocation costs and retention payments for non-executives are included
Nevada Power Company Company Power Nevada 15 in the revenue requirement calculation for this case. and Sierra Pacific Power Company Pacific Power Sierra and Company
16 17 37. Q. WHAT IS THE RECORDED COST LEVEL THAT SIERRA IS 18 REQUESTING IN THIS CASE FOR THIS CATEGORY OF 19 EXPENSE? 20 A. Sierra is requesting the test year expense level of $44,000 which includes 21 $34,000 of relocation costs and $10,000 of retention payments for non- 22 executives. 23 24 25 26 27
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1 VI. NON-CASH COMPENSATION PROGRAMS 2 38. Q. PLEASE DESCRIBE THE NON-CASH COMPONENT OF THE 3 COMPENSATION PROGRAM. 4 A. Exhibit Oswald-Direct-2 lists the Company’s non-cash compensation
5 programs. 6 7 39. Q. WHAT ARE THE TOTAL NON-CASH COMPENSATION COSTS 8 FOR THE TEST PERIOD?
9 A. Test period costs associated with the major programs are summarized in
10 Figure Oswald-Direct-4, below.
11 FIGURE OSWALD-DIRECT-4 12 O&M NON-CASH COMPENSATION COSTS (OTHER THAN PENSION AND OPEB6) SIERRA’S RECORDED COSTS FOR THE PERIOD JANUARY 1 – DECEMBER 31, 2018 13 Long/Short Term Disability $458,493 d/b/a NV Energy 14 Educational Reimbursement $59,710 Nevada Power Company Company Power Nevada 15 Life and Accident Insurance $234,471
and Sierra Pacific Power Company Pacific Power Sierra and Company Medical / Dental / Vision* $11,743,352
16 401(k) $7,796,433 Executive Benefits $16,979 17 Service Awards $101,730 18 Wellness $114,051 *Medical / Dental / Vision insurance expense is annualized on Schedule H-CERT-17, page 5. 19
20 21 40. Q. ARE THE NON-CASH COMPENSATION COSTS REASONABLE? 22 A. Yes. Sierra has taken cost savings initiatives and carefully managed its benefit 23 program costs since the Company’s last general rate case (Docket No. 16- 24 06006) resulting in a decrease in non-cash compensation of $1,955,978. Major 25 drivers of this decrease are cost reductions associated with leveraging BHE 26
27 6 Defined in Part VII below.
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1 mass to achieve lower costs per plan, as well as the redesign of the medical 2 programs from traditional to consumer-driven plans. 3 4 VII. PENSION PROGRAM AND OTHER POST EMPLOYMENT BENEFITS
5 (“OPEB”) 6 41. Q. PLEASE GENERALLY DESCRIBE THE PENSION AND OPEB 7 PROGRAMS THAT ARE AVAILABLE TO NV ENERGY 8 EMPLOYEES.
9 A. Most employees serve under a defined benefit pension plan. Certain long-
10 tenured employees are covered under a traditional benefit formula based on
11 years of service and the employee’s highest compensation for a period prior to 12 retirement. The majority of employees are covered under a cash balance 13 formula. Beginning in January 2015 for non-represented employees, and d/b/a NV Energy 14 beginning in January 2017 for Local 1245 employees, new hires are no longer
Nevada Power Company Company Power Nevada 15 offered a defined benefit pension plan. For those new hires no longer offered and Sierra Pacific Power Company Pacific Power Sierra and Company
16 the defined benefit pension plan, they instead receive a defined Company 17 contribution of 4 percent in the Companies’ 401(k) plan. 18 19 The Company continues to offer a 401(k) plan to all employees. Some key 20 employees also participate in Restoration Plans due to IRS limitations imposed 21 upon tax qualified pension plans. As noted above, some officers also 22 participate in a SERP, although benefit accruals under the SERP were frozen 23 as of December 2015. SERP is not included in the revenue requirement 24 calculation in this case. Generally, all employees hired before April 1, 2008 25 who meet certain age and service criteria are eligible for retiree medical and 26 life insurance benefits. 27
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1 42. Q. WHAT COSTS DOES SIERRA PROPOSE TO INCLUDE IN ANNUAL 2 REVENUE REQUIREMENTS FOR PENSION AND OPEB EXPENSE? 3 A. Annualized jurisdictional pension and OPEB expense as of May 31, 2019, is 4 estimated at $3.0 million, as shown on Schedule H-CERT-17, page 5 of 5. The
5 actual amounts will be certified. 6 7 43. Q. HOW DO THESE PENSION AND OPEB COSTS COMPARE WITH 8 PRIOR YEARS?
9 A. As shown in Figure Oswald-Direct-1, this category of expense has decreased
10 by $0.7 million since Docket 16-06006.
11 12 44. Q. WHAT IS THE RESTORATION PLAN? 13 A. The Pension Restoration plan was adopted July 7, 1989, and was amended and d/b/a NV Energy 14 restated effective January 1, 2009. The Deferred Compensation Plan (formerly
Nevada Power Company Company Power Nevada 15 the 401(k) Restoration Plan) was adopted on January 1, 1996, and was and Sierra Pacific Power Company Pacific Power Sierra and Company
16 amended and restated effective June 30, 2009. Generally, the purpose of the 17 restoration plans is to restore retirement benefits that cannot be paid under the 18 qualified pension plans and 401(k) plans due to IRS limitations. The Pension 19 Restoration Plan was closed to new entrants in December 2015. 20 21 45. Q. WHAT ARE THE RESTORATION PLAN COSTS THAT THE 22 COMPANY IS REQUESTING FOR RECOVERY IN THIS CASE? 23 A. The annualized jurisdictionalized Restoration Plan costs that the Company is 24 requesting for recovery in this case are $219,000. 25 26 27
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1 46. Q. IS THE LEVEL OF RESTORATION PLAN EXPENSE INCLUDED IN 2 THE REVENUE REQUIREMENT CALCULATION REASONABLE, 3 AND DOES IT REPRESENT A RECURRING EXPENSE? 4 A. Yes, the costs of the Restoration Plan are reasonable, and are a recurring
5 expense that the Company will continue to incur in order to maintain 6 competitive pay packages for its employees. 7 8 47. Q. HAS THE COMMISSION PREVIOUSLY ALLOWED RECOVERY OF
9 RESTORATION PLAN COSTS IN RATES?
10 A. Yes. Restoration Plan costs were allowed recovery in rates in Sierra’s last
11 general rate case, Docket No. 16-06006. 12 13 VIII. AMPERE DRIVE EXTENSION d/b/a NV Energy 14 48. Q. IN ADDITION TO YOUR RESPONSIBILITIES OVER THE HUMAN
Nevada Power Company Company Power Nevada 15 RESOURCES AREA, ARE YOU ALSO RESPONSIBLE FOR THE and Sierra Pacific Power Company Pacific Power Sierra and Company
16 COSTS INCURRED BY THE CORPORATE SERVICES FUNCTION? 17 A. Yes, I am. My responsibility over the corporate services function includes 18 oversight over procurement, corporate records, support services, property 19 management, interior services, and facilities maintenance. 20 21 49. Q. DID THE CORPORATE SERVICES FUNCTION COMPLETE ANY 22 MAJOR CAPITAL PROJECTS SINCE JUNE 2016? 23 A. Yes, one project, involving the extension of Ampere Drive at the Ohm 24 Operations Center is considered a “major” capital project. I address this 25 project in some detail below. 26 27
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1 50. Q. WHY DO YOU ONLY ADDRESS “MAJOR” CAPITAL PROJECTS IN 2 YOUR PREPARED TESTIMONY? 3 A. Testimony-style descriptions of each and every project completed by the 4 corporate service organization since June 1, 2016, would take hundreds of
5 pages, and the documentation surrounding each project is so voluminous that 6 its value at hearing would be severely diminished. As I understand it, in 7 general rate proceedings the Commission wants to see prepared direct 8 testimony addressing the details of and supporting expenditures on major
9 projects. In recent general rate cases the Commission has accepted the $1
10 million demarcation as appropriate for determining whether a project is
11 “major.” While not addressed in detail in my prepared direct testimony, my 12 group has prepared project “binders” for smaller projects completed since June 13 1, 2016. As has been the Companies’ practice for many rate case cycles, those d/b/a NV Energy 14 binders (now in electronic form) are available for review on the day this
Nevada Power Company Company Power Nevada 15 general rate review filing is made. and Sierra Pacific Power Company Pacific Power Sierra and Company
16
17 51. Q. PLEASE DESCRIBE THE AMPERE DRIVE EXTENSION PROJECT.
18 A. Ampere Drive runs east-west on the southern edge of the Ohm Operations Center.
19 The Ohm Operations Center first went into service in the mid-1960s and houses
20 electric lines and substation construction and maintenance, the gas operations 21 group, design services, system protection, standards, and meter operations. 22 Anticipating that expansion of the Ohm Operations Center would eventually be 23 necessary, Sierra acquired 18.84 acres of land to the west of the existing Ohm 24 Operations Center in 2013. Sierra had been leasing five acres of this property for 25 many years, using it as an outdoor materials storage area. The purchase provided 26 27
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1 Sierra with long-term control of the property and flexibility to expand the Ohm
2 Operations Center in the future.
3 4 Prior to the completion of the Ampere Drive Extension Project, the portion of 5 Ampere Drive traversing the 18.84 acres acquired in 2013 was unimproved. Thus 6 all traffic seeking to access the commercial enterprises on Ampere Drive had to 7 enter and exit the area to the north on either Ohm Place or Edison Way. The 8 previous owner recognized the need to eventually finish Ampere Drive and 9 provide access to the area from Rock Boulevard to the west. A parcel map for 10 this property, recorded by the former owner in 2005, required that right of way 11 improvements to Ampere Drive must be completed prior to the issuance of a 12 building permit for any construction on any of the parcels making up the 18.84 13 acres. d/b/a NV Energy 14
Nevada Power Company Company Power Nevada 15 and Sierra Pacific Power Company Pacific Power Sierra and Company
16 In 2017, in preparation for the eventual redevelopment and expansion of the Ohm 17 Operations Center, Sierra undertook the design and construction of the Ampere 18 Drive extension. The design and construction of all Ampere Drive improvements, 19 to the City of Reno’s design standards, including all underground utilities, curb, 20 gutter, street lighting, landscaping, roadway and internal charges, cost $1,557,583 21 and required approximately one year to complete. The Ampere Drive extension 22 is used and useful in service providing utility service to customers. The extension 23 of Ampere Drive enhances both public and Company safety by allowing 24 Company vehicles improved access to the southern part of the Ohm campus and 25 reducing our reliance on the Mill Street access point, a very heavily trafficked 26 27
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1 roadway. The majority of the heavy vehicle parking and materials storage at Ohm 2 is on the south end of the campus and nearest to the Ampere Drive extension. 3 4 CONCLUSION
5 52. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY?
6 A. Yes. 7 8
9
10
11 12 13 d/b/a NV Energy 14
Nevada Power Company Company Power Nevada 15 and Sierra Pacific Power Company Pacific Power Sierra and Company
16 17 18 19 20 21 22 23 24 25 26 27
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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 Energy ‐ Non Cash Compensation Docket No. NPC 17‐xxxxx Program Summary Exhibit Oswald‐Direct‐2 Officer/Executive Non‐represented Local 396 Local 1245 Medical/Dental/Vision Same as non‐represented Coverage effective on Date of Hire. Coverage effective the first of the month Coverage effective the first of the Plan options include Health following Date of Hire. Plan options month following Date of Hire. Plan Reimbursement Account (HRA) Plan include Health Reimbursement Account options include Health Reimbursement and Health Savings Account (HSA) (HRA) Plan with Healthy Living, HRA Account (HRA) Plan and Health Savings Plan. without Healthy Living and Health Savings Account (HSA) Plan. Account (HSA) Plan with Healthy Living.
Basic Life Insurance Company ‐ paid Same as non‐represented; 1.5 times annual base pay up to a 1.4 times annual base pay up to a $50,000 grandfathered employees maximum of $1,500,000 (minimum maximum of $1,000,000 (minimum receive Up to 3.0 times annual benefit of $50,000). New hires as of benefit of $46,000) base pay (maximum January 2015, 1.0 times annual base $1,750,000; (minimum $50,000) pay.
Basic Accidental Death & Dismemberment (AD&D) Company ‐ paid Same as non‐represented 1.5 times annual base pay up to a 1.4 times annual base pay up to a No Coverage maximum of $1,500,000 (minimum maximum of $1,000,000 (minimum benefit of $50,000). New hires as of benefit of $46,000) January 2015, not covered.
Business Travel Accident Insurance Company ‐ paid Same as non‐represented; Death benefit of $500,000 in the Death benefit of $500,000 in the event of Death benefit of $500,000 in the event benefit is $1 million for Officers. event of accidental death while accidental death while traveling outside of accidental death while traveling traveling outside regularly assigned regularly assigned work location on outside regularly assigned work location work location on company business. company business. on company business.
Supplemental Life Insurance (Optional) Employee‐paid with after‐tax dollars; Gives the Same as non‐represented. Coverage available in increments of Coverage available in increments of 0.5 Coverage available in increments of 0.5 employee the opportunity to receive additional 0.5 up to 5 times annual base pay to up to 5 times annual base pay to a up to 5 times annual base pay to a insurance protection. a maximum of $1,250,000; Coverage maximum of $1,000,000; Coverage for maximum of $1,250,000; Coverage for for spouse and children also spouse and children also available. spouse and children also available. available.
Supplemental AD&D (Optional) Employee‐paid with pre‐tax dollars Same as non‐represented. Employee can choose a death benefit Not available. Not available. of $25,000 to $500,000 in the event of accidental death; family coverage Page 239 of250 is available.
Revised 04/2017 Page 1 of 4 NV Energy ‐ Non Cash Compensation Docket No. NPC 17‐xxxxx Program Summary Exhibit Oswald‐Direct‐2 Officer/Executive Non‐represented Local 396 Local 1245 Short‐Term Disability (STD) Designed to replace an employee's pay in the event that Same as non‐represented. The amount of benefits the employee The amount of benefit the employee The amount of benefits the employee serious injury or prolonged illness prevents them from receives is equal to 100% of pay for receives is 55%‐75% of base pay based on receives is equal to 100% of pay for up working. up to 8 weeks and 80% for up to the the employee's weeks of service at the to 4 weeks and 80% for up to the next next 18 weeks. time of disability. 22 weeks.
Long‐Term Disability (LTD) Company ‐ paid for non‐represented and Local 1245; Employees are eligible for 60% Employees are eligible for 60% of Employees are eligible for 60% of base Employees are eligible for 60% of base Employee paid by Local 396. of base pay plus bonus to a base pay to a maximum of pay to a maximum of $10,000/month less pay to a maximum of $10,000/month maximum of $14,000/month $10,000/month less other disability other disability payments they are eligible less other disability payments they are less other disability payments payments they are eligible to receive. to receive. eligible to receive. they are eligible to receive.
Health Care Flexible Spending Account (FSA) Allows employees to set aside tax‐free dollars to pay for Same as non‐represented. Up to $2,550 contribution annually. Up to $2,550 contribution annually. Up to $2,550 contribution annually. eligible health care expenses not covered by their health care plan. Dependent Care Flexible Spending Account (FSA) Allows employees to set aside tax‐free dollars to pay for Same as non‐represented. Up to $5,000 contribution annually. Up to $5,000 contribution annually. Up to $5,000 contribution annually. eligible dependent care expenses for qualified dependents to enable the employee and spouse to work (e.g. child or elder care). Retirement Plan Tax‐qualified, non‐contributory defined benefit pension Same as non‐represented. Depending on the date of Depending on the date of participation in Depending on the date of participation plan that covers eligible employees under all groups. participation in the plan, benefits are the plan, benefits are either calculated in the plan, benefits are either either calculated under a traditional under a traditional plan formula using calculated under a traditional plan plan formula using years of service years of service and final average formula using years of service and final and final average earnings or a cash earnings or a cash balance formula using average earnings or a cash balance balance formula using an earnings an earnings credit percentage plus formula using an earnings credit credit percentage plus interest interest accrual. Effective January 2016, percentage plus interest accrual. accrual. Effective January 2015, new new hires no longer eligible for Effective January 2017, new hires no hires no longer eligible for retirement retirement plan. longer eligible for retirement plan. plan.
Retirement Restoration Plan Not Applicable. Not Applicable. Provides a benefit substantially equal to the difference Employees whose compensation exceeds the IRS annual compensation between the amount that would have been payable limit, as well as those that participate in the 401(k) Restoration Plan Page 240 of250 under the Retirement Plan, in the absence of laws are eligible. Effective December 31, 2015, plan closed to new entrants. limiting pension benefits and earnings that must be Accruals ongoing for current participants. considered in calculating pension benefits, and the amount actually payable under the Retirement Plan.
Revised 04/2017 Page 2 of 4 NV Energy ‐ Non Cash Compensation Docket No. NPC 17‐xxxxx Program Summary Exhibit Oswald‐Direct‐2 Officer/Executive Non‐represented Local 396 Local 1245 Supplemental Executive Retirement Plan (SERP) Limited to key employees. Not Applicable. Not Applicable. Not Applicable. 4/1/08 frozen to new entrants. 12/31/2015, frozen accruals.
401(k) / (Voluntary Investment) Plan A tax‐deferred long‐term savings program which offers Same as non‐represented Employer match of 100% on the first Employer match of 100% on the first 6% Employer match of 100% on the first 6% an investment program with a substantial tax advantage. 6% of employee contributions. New of employee contributions. New hires as of employee contributions. (50% match hires as of 1/1/15 receive an of 1/1/16 receive an additional 4% on the first 6% for those with the utility additional 4% employer contribution employer contribution replacing cash discount). New hires as of 1/1/17 replacing cash balance participation. balance participation. receive an additional 4% employer contribution replacing cash balance participation.
401(k) Restoration Plan A deferred compensation plan supplementing benefits Not Applicable. Not Applicable. Directors and above in a salary grade 19 or higher are eligible. payable under the 401(k) Plan. Employee Assistance Program (EAP) Same for all groups. The Company provides an EAP service to help employees and their family members handle difficult situations. EAP counselors are experienced in dealing with personal issues such as finances, family relationships, stress, substance abuse, and care of family members
Adoption Assistance To support a decision to adopt a child under the age of Same as non‐represented. Company will provide up to $2,000 Not Available. Not Available. 12. per adopted child to mitigate expenses.
Worker's Compensation Same for all groups. Company is a self‐insured employer. Program provides employees who have job‐related injury or illness with medical care, disability benefits, and rehabilitation services.
LEARNING & DEVELOPMENT Opportunities to grow and develop through a combination of company‐sponsored training, development programs and educational reimbursement. Tuition Reimbursement Same as non‐represented. Employees receive 100% of tuition, Employees receive 100% of tuition. Employees receive 100% of tuition. lab fees & books. Annual limit for full‐ Books and lab fees at a combined Books are covered at 50% and lab fees time employees is $5,250; part‐time maximum of $50 per course. Annual limit at 100%. Annual limit for full‐time employees is $2,625. for full‐time employees is $2,000. ($4,000 employees is $2,500; part‐time for designers) employees is $1,250. Page 241 of 250
Revised 04/2017 Page 3 of 4 NV Energy ‐ Non Cash Compensation Docket No. NPC 17‐xxxxx Program Summary Exhibit Oswald‐Direct‐2 Officer/Executive Non‐represented Local 396 Local 1245 WORK ENVIRONMENT A work environment that supports high performance, bust also recognizes diverse personal needs through the following programs: Paid Time Off (PTO)* For vacation, sick leave, funeral leave, family illness or Same as non‐represented. Effective January 2016, employees Employees accrue annually includes a flat Employees accrue annually includes a personal appointments. accrue per pay period with an initial amount equal to 22 days , increasing flat amount equal to 21 days , increasing rate of 18 days (annually), plus 0.58 based on a years of service schedule. based on a years of service schedule. days for each year of service.
Holidays Same as non‐represented. 10 Holidays per year 11 Holidays per year 10 Holidays per year
*Other leave programs may be available under the provisions of the CBA (e.g. Family Sick Leave, Funeral Leave, etc.). Page 242 of250
Revised 04/2017 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-3 2018 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
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Page 246 of 250 NV Energy – Caudill/Cannon Third Quarter 2018 Scorecard Score by Core Weight Key Performance Indicator 2018 Target 2018 YTD Actual 2018 Forecast Status Principle Percentile Percentile Percentile 2.0% J.D. Power residential 35.0 35.6 35.6 Not Achieved 2.0% J.D. Power business 45.0 30.7 - On track 1.0% Market Strategies International commercial - north 20.0 44.6 - Not on track 1.0% Market Strategies International commercial - south 33.0 27.5 - On track 1 1.0% Market Strategies International residential - north 1.0 8.1 - Not on track 1.0% Market Strategies International residential - south 19.0 17.2 - On track 2.0% Mastio key account 2.0 2.0 2.0 Achieved 6.7% Execute customer satisfaction improvement plan Successful implementation Execution underway Achieve On track 12.70%
5.0% OSHA incident rate - outside electric delivery 0.30 0.54 0.41 Not on track 2.2% OSHA incident rate - electric delivery only 1.48 1.96 1.71 Not on track 2 7.2% Preventable vehicle accidents 15 11 ≤15 On track 2.3% Enhance frameworks and plans for employee engagement, training and development Demonstrate enhancement 100% Completed Achieved 9.50%
3 16.6% CO2 emissions (lbs/MWh) 870 868 870 On track 16.60%
8.4% Achieve allowed return on equity 9.6% - 10.4%** On track 8.3% Deliver balanced outcomes in regulatory and legislative environments* Balanced outcomes Tax rate reduction implemented; Achieve On track 4 alternative rate making declaratory order issued; integrated resource plan filed 16.70%
3.0% SAIDI (minutes) 62.0 54.6 72.0 Not on track 3.0% Generation equivalent availability factor – gas 92.5% 95.0% 92.5% On track 3.0% Generation equivalent availability factor – coal 92.9% 94.8% 92.9% On track 5 3.0% Zero reportable gas incidents 0 1 1 Not Achieved 1.6% No physical or cybersecurity events that impact operations 0 0 0 On track 1.5% Advance cybersecurity post certification and physical security of assets Achieve plans post certification ISO 27001 recertification audit achieved Achieve Achieved 1.5% Deliver grid resilience implementation plan milestones December 31, 2018 All required submittals completed; December 31, 2018 On track additional spare procurement underway 10.60%
10.0% Net income (NVE Holdings) $335.8m $311.1m $343.5m On track 6 3.3% Operations and maintenance expense (2018 excludes energy efficiency costs) $484.8m $360.6m $484.6m On track 1.7% Capital expenditure lower than depreciation expense excluding growth <1.0x 0.61x 0.81x On track 1.7% Achieve fall 2017 plan targets for operations and maintenance expense in fall 2018 plan $484.1m (2019) Round 1 $428.6m $428.6m (2019) On track 16.70% *Deliver on commitments made through NV Energy 2.0 and the Strategic Repositioning plan **Post earnings sharing at Nevada Power Company Year‐to‐date Scorecard Tota l 82.80% Page 247 of250 1 EXHIBIT OSWALD-DIRECT- 5
Page 248 of 250 NV Energy – Caudill/Cannon December 2018 Scorecard Score by Core Weight Key Performance Indicator 2018 Target 2018 Actual Status Principle Percentile Percentile 2.0% J.D. Power residential 35.0 35.6 Not Achieved 2.0% J.D. Power business 45.0 57.6 Not Achieved 1.0% Market Strategies International commercial - north 20.0 44.6 Not Achieved 1 1.0% Market Strategies International commercial - south 33.0 27.5 Achieved 1.0% Market Strategies International residential - north 1.0 8.1 Not Achieved 1.0% Market Strategies International residential - south 19.0 17.2 Achieved 2.0% Mastio key account 2.0 2.0 Achieved 6.7% Execute customer satisfaction improvement plan Successful implementation Successfully implemented Achieved 10.7%
5.0% OSHA incident rate - outside electric delivery 0.30 0.47 Not Achieved 2 2.2% OSHA incident rate - electric delivery only 1.48 1.71 Not Achieved 7.2% Preventable vehicle accidents 15 19 Not Achieved 2.3% Enhance frameworks and plans for employee engagement, training and development Demonstrate enhancement 100% Achieved 2.3%
3 16.6% CO 2 emissions (lbs/MWh) 870 862 Achieved 16.6%
8.4% Achieve allowed return on equity 9.6% 10.4% Achieved 4 8.3% Deliver balanced outcomes in regulatory and legislative environments* Balanced outcomes Tax rate rider implemented; declaratory Achieved order issued; integrated resource plan approved 16.7%
3.0% SAIDI (minutes) 62.0 71.2 Not Achieved 3.0% Generation equivalent availability factor – gas 92.5% 94.4% Achieved 3.0% Generation equivalent availability factor – coal 92.9% 95.4% Achieved 5 3.0% Zero reportable gas incidents 0 1 Not Achieved 1.6% No physical or cybersecurity events that impact operations 0 0 Achieved 1.5% Advance cybersecurity post certification and physical security of assets Achieve plans post certification ISO 27001 recertifi cation audit achieved Achieved 1.5% Deliver grid resilience implementation plan milestones December 31, 2018 Completed Achieved 10.6%
10.0% Net income (NVE Holdings) $335.8m $317.5m Not Achieved 3.3% Operations and maintenance expense (2018 excludes energy efficiency costs) $484.8m $483.8m Achieved 6 1.7% Capital expenditure lower than depreciation expense excluding growth <1.0x 0.75x Achieved 1.7% Achieve fall 2017 plan targets for operations and maintenance expense in fall 2018 plan $484.1m (2019) $464.0m Achieved 6.7%
*Deliver on commitments made through NV Energy 2.0 and the strategic repositioning plan Year-end Total 63.6%
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