NEVADA POWER COMPANY d/b/a NV Energy
BEFORE THE
PUBLIC UTILITIES COMMISSION OF NEVADA
IN THE MATTER of the Application of NEVADA ) POWER COMPANY, d/b/a NV Energy, filed ) pursuant to NRS 704.110 (3) and (4), addressing its ) annual revenue requirement for general rates ) charged to all classes of customers. ) ______) Docket No. 20- 06____
VOLUME 6 of 25
Prepared Direct Testimony of:
Plant In Service
Dariusz Rekoswski Vincent Veilleux Jennifer Kelly Larry Luna
Recorded Test Year ended December 31, 2019 Certification Period ended May 31, 2020 Expected Change in Circumstance Period ending December 31, 2020
Index
Page 2 of 278 Nevada Power Company d/b/a NV Energy
Volume 6 of 25 Testimony
Index Page 1 of 1
Description Page No. Prepared Direct Testimony Of:
Plant In Service:
Dariusz Rekowski (Redacted) 5 Vincent Veilleux (Redacted) 164 Jennifer Kelly 222 Larry Luna 251
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DARIUSZ REKOWSKI
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1 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Nevada Power Company d/b/a NV Energy Docket No. 20-06___ 3 2020 General Rate Case
4 Prepared Direct Testimony of
5 Dariusz Rekowski
6 Revenue Requirement 7 8 SECTION I: INTRODUCTION
9 1. Q. PLEASE STATE YOUR NAME, JOB TITLE, EMPLOYER AND 10 BUSINESS ADDRESS.
11 A. My name is Dariusz Rekowski. My current position is Vice President,
12 Generation, for Nevada Power Company d/b/a NV Energy (“Nevada
13 Power” or the “Company”) and Sierra Pacific Power Company d/b/a NV 14 Energy (“Sierra” and, together with Nevada Power, the “Companies”). My 15 business address is 6226 West Sahara Ave Las Vegas, Nevada. I am filing d/b/a Energy NV
16 testimony on behalf of Nevada Power. Nevada Power Company Company Power Nevada 17 and SierraCompany Pacific Power 18 2. Q. WHAT ARE YOUR PRIMARY RESPONSIBILITIES AS VICE 19 PRESIDENT, GENERATION, FOR THE COMPANIES? 20 A. I am responsible for providing corporate support to all of the Companies’ 21 generating plants. Responsibilities include providing management of 22 engineering and project management support, outage planning and 23 management, training, management of the Long-Term Service 24 Agreements (“LTSAs”) for gas and steam turbines, warehouse
25 management, and Generation Business. 26 27
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1 3. Q. PLEASE DESCRIBE YOUR EDUCATIONAL BACKGROUND 2 AND EMPLOYMENT EXPERIENCE. 3 A. My Statement of Qualifications is included as Exhibit Rekowski-Direct-1. 4
5 4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC 6 UTILITIES COMMISSION OF NEVADA (“COMMISSION”)? 7 A. Yes. I provided written testimony for the 2017, 2018 and 2019 deferred 8 energy proceedings, Docket Nos. 17-03001, 17-03002, 18-03002, 18-
9 03003, 19-03001 and 19-03002. I have also provided written testimony 10 for the 2019 Sierra general rate case (“GRC”), Docket No. 19-06002.
11
12 5. Q. ARE YOU SPONSORING ANY EXHIBITS WITH YOUR
13 TESTIMONY? 14 A. Yes, I am. In addition to my Statement of Qualifications (Exhibit 15 Rekowski-Direct-1), I sponsor Exhibit Rekowski-Direct-2, which d/b/a Energy NV
16 Nevada Power Company Company Power Nevada identifies major generation plant additions completed since the close of 17 the certification period in Nevada Power’s 2017 GRC (May 31, 2017). I and SierraCompany Pacific Power 18 also sponsor Exhibit Rekowski-Direct-3, which lists the proposed capital 19 projects listed as expected to be completed during the expected change in 20 circumstances period that will not be included in the plant in service in this 21 filing. 22
23 6. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS 24 PROCEEDING? 25 A. I am supporting the reasonableness of operations and maintenance 26 (“O&M”) expenditures at Nevada Power’s fleet of generating stations, as 27 well as its request to include in rate base the costs associated with
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1 generation-related capital additions that have gone into service since the 2 close of the certification period in the Company’s last GRC, Docket No. 3 17-06003. Nevada Power’s investment in generation assets since the 2017 4 GRC falls into five buckets. 5 6 The first is investment made and expenses saved or incurred pursuant to 7 the Commission-approved Emissions Reduction and Capacity 8 Replacement (“ERCR”) Plan.1 The Commission approved regulatory
9 asset treatment of the costs associated with the purchase of the ERCR 10 assets, as well as the operating expenses of the units, which Nevada Power
11 incurred before the 2018 rate effective period began.2 The ERCR Plan
3 12 was a result of legislation passed by the 2013 Nevada Legislature and
13 governs both the retirement of Nevada Power’s 812 megawatt (“MW”) 14 coal fleet over six years, and the phased-in replacement of retired coal 15 generation with a combination of conventional and renewable resources. d/b/a Energy NV
16 Nevada Power Company Company Power Nevada The treatment of costs and cost recovery mechanisms of the phase-out and 17 replacement of coal-fired generation at Nevada Power are also addressed and SierraCompany Pacific Power 18 in the ERCR statutes and regulations. Thus, together with Nevada Power 19 witness Mathew Johns, who is the Company’s primary witness in this 20 proceeding in relation to the decommissioning and remediation efforts at 21 the Reid Gardner Generating Station and the Navajo Generating Station, I 22 support the capital and operating expense impacts of phasing out the 23 Company’s coal facilities and replacing these coal resources according to 24 the ERCR Plan. I address the ERCR Plan’s costs in Section III below.
25 1 Nevada Power filed its ERCR Plan in May 2014 as part of Commission Docket No. 14-05003 and 26 two amendments, Docket Nos. 15-07003 and 16-08027. 2 Docket Nos. 17-06003 and 17-06004, Order Paragraph 344, Page 86 27 3 See, Nevada Revised Statute (“NRS”) §§ 704.7311 through 704.7322. 28 Rekowski-DIRECT 3
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1 The second topic of investment that I sponsor includes capital projects at 2 Nevada Power’s conventional generating stations that were completed 3 between the close of the certification period in Nevada Power’s 2017 GRC 4 and the close of the test period for this GRC. These projects are closed to 5 plant in service, and were in service and used and useful in providing 6 electric service to customers between June 1, 2017, and December 31, 7 2019. I address these projects in Section IV below. 8
9 Section V of my testimony specifically addresses the LTSA capital portion 10 of outage costs.
11
12 The third topic of investment that I support is capital projects that, at the
13 time this filing was prepared, were anticipated to be placed in service and 14 used and useful in providing electric service between January 1, 2020, and 15 May 31, 2020. The completion of these projects and their actual costs as d/b/a Energy NV
16 Nevada Power Company Company Power Nevada of May 31, 2020, will be “certified” in a later filing. I address these 17 projects in Section VI below. and SierraCompany Pacific Power 18 19 The fourth topic of investment I support is the capital projects that were 20 expected to be completed in the certification period, but were delayed due 21 to the COVID-19 pandemic. These projects are included in the Expected 22 Change in Circumstances (“ECIC”) portion of my testimony and will be 23 completed between June, 1, 2020, and December 31, 2020. I address 24 these projects in Section VII. 25 26 27
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1 Finally, in Section VIII, I discuss H-CERT-27 Higgins Transformer 2 Regulatory Asset. 3 4 However, before I discuss these investments, in Section II, I describe the 5 processes within my area of responsibility and Company-wide that govern 6 the expenditure of both O&M dollars and capital investment. 7
8 7. Q. DO YOU SPECIFICALLY DISCUSS IN YOUR TESTIMONY ALL 9 GENERATION PROJECTS CLOSED TO PLANT IN SERVICE 10 SINCE JUNE 1, 2017?
11 A. No. While I support all generation plant investment reflected in the
12 Company’s proposed calculations of rate base, my testimony specifically
13 discusses individual major projects, which generally cost $1 million or 14 more. Nevada Power’s generation team completed many projects under $1 15 million since May 31, 2017, and my testimony would be too voluminous d/b/a Energy NV
16 Nevada Power Company Company Power Nevada if I addressed each of these projects. This approach is consistent with past 17 GRC testimony prepared by the Company. and SierraCompany Pacific Power 18
19 8. Q. ARE THERE ANY GENERATION-RELATED PROJECTS 20 PROJECTED TO BE COMPLETED IN THE CERTIFICATION 21 OR EXPECTED CHANGE IN CIRCUMSTANCES PERIODS AND 22 INCLUDED IN THE COMPANY’S FINANCIAL PROJECTIONS 23 THAT SHOULD NOT BE INCLUDED IN PLANT IN SERVICE AT 24 THIS TIME? 25 A. Yes. There were a number of projects that were included in the financial 26 schedules that were intended to be completed during either the 27 Certification or ECIC periods that should not be included in plant in
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1 service in this filing. The schedules for the filing were required to be 2 completed in March and prior to the final decision to not complete these 3 projects during the Certification or ECIC periods. Because the schedules 4 flow through to other portions of the filing, it was too late in the 5 preparation of this filing to remove the projects from the already- 6 completed schedules. These projects are listed among other projects in 7 Exhibit Fincher-Direct-3 and Exhibit Fincher-Direct-4. These projects 8 will be removed from the schedules with the removals being reflected in
9 the I-Cert schedules filed during the Certification portion of this Docket. 10 The projects for the Certification period that will be removed are listed in
11 Table Rekowski-Direct-1, below. The projects for the ECIC period that
12 will be removed total approximately $12 million and are listed in Exhibit
13 Rekowski-Direct-3. 14 Table Rekowski-Direct-1 15 d/b/a Energy NV
16 CERT Period Projects Nevada Power Company Company Power Nevada DESCRIPTION BUDGET ID ESTIMATE 17 $514,079 and SierraCompany Pacific Power LZ Cathodic Protection System, Replace_CL CL2121
18 LZ RO Membranes, Replace_CL CL2157 $42,219 CK - U5-8 - Repl Generator Evap Cooling Control 19 System _CS CS2253 $45,147 HA Cathodic Protection System, Replace_HA HA2061 $584,497 20 SH Cathodic Protection System, Replace_SH SH2070 $719,098 21 SH Boiler Feed Pump Shaft and Seals, Replace_SH SH2165 $234,077 Chemical Engineering Software _SP SP5045 $17,312 22 23
24
25
26 27
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1 9. Q. ARE THERE ANY GENERATION-RELATED PROJECTS 2 PROJECTED TO BE COMPLETED IN THE EXPECTED 3 CHANGE IN CIRCUMSTANCES PERIOD AND INCLUDED IN 4 THE COMPANY’S FINANCIAL PROJECTIONS THAT WILL BE 5 COMPLETED IN THE CERTIFICAITON PERIOD AND 6 INCLUDED IN PLANT IN SERVICE? 7 A. Yes. There were nine projects that were included in the financial 8 schedules that were intended to be completed during the ECIC period that
9 were completed during the Certification period, during short-term forced 10 outages, and will be included in plant in service in this filing. The
11 schedules were completed prior to the decision to complete these projects
12 during the Certification period, and it was too late in the preparation of this
13 filing to remove the projects from the ECIC schedules and to add them to 14 the Certification schedules. These projects are listed among other projects 15 in Exhibit Fincher-Direct-4. These projects will be corrected on the d/b/a Energy NV
16 Nevada Power Company Company Power Nevada schedules and reflected in the Certification filing of this Docket. These 17 projects are listed in Table Rekowski-Direct-2, below. and SierraCompany Pacific Power 18 Table Rekowski-Direct-2 19 20 CERT Period Projects DESCRIPTION BUDGET ID ESTIMATE 21 CK - CWT - U 9 / 10 - Replace Fire Piping _CS CS2252 $80,783 PB2 Electrical Protection, Replace_LC LC2128 $332,040 22 LVGS Cathodic Protect. Install_LC LC2139 $524,421 23 PB3 Electrical Protection, Replace_LC LC2152 $332,037 LVG2 15KV Power Cable, Replace_LC LC2166 $603,284 24 LVG3 15KV Power Cable, Replace_LC LC2167 $633,079 25 Cathodic Protection Phase 2, Install_WH WH2105 $616,400 U1 Fuel Gas Block Valves, Replace_WH WH2096 $163,040 26 U2 Fuel Gas Block Valves, Replace_WH WH2097 $162,973 27
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1 10. Q. PLEASE SUMMARIZE THE TOTAL CHANGES IN 2 PROJECTIONS FOR PROJECTS THAT WERE ORIGINALLY 3 LISTED IN THE EXPECTED CHANGE IN CIRCUMSTANCES 4 SCHEDULE? 5 A. As noted in Q&A 8 above, approximately $12 million in projects were 6 removed from the ECIC period schedule. These projects will be requested 7 in a future rate case. As noted in Q&A 9 above, approximately $3.4 8 million in projects listed on the ECIC schedule were moved from the ECIC
9 period into the Certification period. And as described later beginning at 10 my Q&A 167, approximately $78 million in outage-related projects were
11 delayed from the spring of 2020 to the fall of 2020 due to the COVID-19
12 pandemic. These delayed, outage-specific projects will be included in the
13 ECIC period. 14
15 SECTION II: CAPITAL AND O&M COST CONTROL d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 11. Q. HOW DOES NEVADA POWER CONTROL THE EXPENSES 17
and SierraCompany Pacific Power ASSOCIATED WITH OPERATING AND MAINTAINING THE 18 FLEET OF GENERATING PLANTS? 19 A. Controlling O&M is important in keeping electric prices reasonable for 20 our customers. At both Nevada Power and Sierra, cost discipline begins 21 with a production schedule that forecasts the amount of energy that can be 22 expected from the facility over the next 10 years. Then each power plant 23 management team carefully reviews all expenditures associated with 24 running the power plants for which they are responsible. Plant managers 25 use the production schedule, equipment condition assessments and 26 original equipment manufacturer recommendations to create an 27
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1 expenditure plan for each facility. Each power plant’s expenditure plan is 2 then rolled up into one expenditure plan for the fleet. 3
4 12. Q. WHAT IS YOUR PROJECTION FOR FUTURE EXPENSES FOR 5 THE NEVADA POWER GENERATING FLEET? 6 A. The fixed costs to maintain generating units as reliable capacity resources 7 remain relatively flat year over year (subject to normal inflation). Variable 8 expenses are less predictable, as these costs depend on how units within
9 the fleet are used. Most variable expenses are related to chemicals and 10 other consumables, the costs of which increase with inflation, and the
11 consumption quantity of which vary according to each unit’s actual
12 operations during the year. Other variable expenses are related to wear and
13 tear. 14 15 On a daily basis, the generating fleet cycles on and off and from low load d/b/a Energy NV
16 Nevada Power Company Company Power Nevada to high load to provide the lowest cost energy supply for Nevada Power’s 17 customers. That cycling leads to wear and tear and as the facilities age, and SierraCompany Pacific Power 18 equipment and systems deteriorate, requiring increased maintenance 19 expense to maintain compliance with operating standards and reliability 20 for our customers. The last major addition of a new plant to the Nevada 21 Power fleet was the Harry Allen combined cycle plant, which was put in 22 service in 2011. Nevada Power’s fleet is aging, and as units age, the cost 23 of maintaining the units increases. 24 25 The Company continues to work diligently to achieve high reliability 26 levels while maintaining O&M cost discipline so that our customers can 27 enjoy reliable service at reasonable prices.
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1 13. Q. HOW DOES NEVADA POWER MANAGE CAPITAL 2 INVESTMENTS IN THE GENERATING FLEET? 3 A. The generation team focuses on delivering the best value from the capital 4 maintenance projects that are performed at the plants. At the same time the 5 expense plans I describe above are being developed for each plant, capital 6 investment plans also are being built. The starting point for the capital 7 investment plan is the same unit-by-unit 10-year production forecast. Key 8 assumptions are made concerning retirement, safety, risk management,
9 environmental and other compliance requirements. Each plant team 10 evaluates the current and expected performance of the units and makes
11 proposals for capital investments needed to deliver expected reliability for
12 our customers at a reasonable cost. The benefits of each capital investment
13 are analyzed based on the planned remaining life of the unit. 14 15 For each of the generation projects described in my testimony, Nevada d/b/a Energy NV
16 Nevada Power Company Company Power Nevada Power plant and project managers followed a rigorous capital budgeting 17 process, which guides the development of business cases and project and SierraCompany Pacific Power 18 estimates, and governs how projects are managed, including through 19 monthly reporting of schedule and budget status. 20
21 14. Q. WERE ALL OF THE CAPITAL PROJECTS COMPLETED SINCE 22 THE END OF THE CERTIFICATION PERIOD IN NEVADA 23 POWER’S 2017 GRC PRE-APPROVED BY THE COMMISSION? 24 A. No. The majority of the projects would be considered maintenance capital 25 to ensure the safe and reliable operation of the generating plants. These 26 projects are not presented to the Commission for pre-approval. However, 27 seven projects were presented to and approved by the Commission
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1 pursuant to ERCR Plan filings. Each of these projects received regulatory 2 asset treatment, as is further described in their individual project 3 descriptions later in my testimony. These projects are:
4 • Retirement of Reid Gardner 1-4 (H-CERT-30). The retirement, 5 decommissioning and remediation projects are described in 6 Company witness Mr. Johns’s testimony.
7 • Retirement of Navajo Generating Station (H-CERT-31). The 8 retirement, decommissioning and remediation projects are
9 described in Company witness Mr. Johns’s testimony. Company 10 witnesses Ms. Fincher and Mr. Cole also sponsor information in
11 H-CERT-31. Schedule H-CERT-43 removes the test period
12 Navajo Generation Station operations and maintenance expense
13 from the cost of service due to the early retirement in November, 14 2019.
15 • Las Vegas Cogen Regulatory Asset (H-CERT-32). d/b/a Energy NV
16 • Nevada Power Company Company Power Nevada Sun Peak Regulatory Asset (H-CERT-33). 17 • Nellis Solar Regulatory Asset (H-CERT-34).
and SierraCompany Pacific Power 18 • Silverhawk Regulatory Asset (H-CERT-35). 19 • Mohave Closure (Decommissioning) - The ongoing site costs are 20 described in Company witness Mr. Johns’s testimony (H-CERT- 21 28).
22
23 15. Q. PLEASE DESCRIBE THE PROCESS THAT NEVADA POWER 24 USES TO MANAGE ITS CAPITAL INVESTMENTS. 25 A. Nevada Power has put in place a robust business planning and project 26 management oversight process that the Generation business unit 27 participates in and follows.
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1 16. Q. PLEASE DESCRIBE THE BUSINESS PLANNING PROCESS. 2 A. Business planning begins with a 10-Year Generation Capital Plan 3 (“Capital Plan”), which includes a list of capital projects for each 4 generating plant. The Capital Plan is updated annually. During the annual 5 update process, each plant performs an assessment and identifies new 6 required projects, modifies existing projects and removes projects from 7 the Capital Plan. 8
9 A Business Case is then developed for every project that is included in the 10 Capital Plan. The Business Case documents the justification for the project
11 and includes the scope, schedule and an estimated cost as well as a cost-
12 benefit analysis. Because the Capital Plan covers a 10-year period of time
13 into the future, many of the initial project Business Cases are based on a 14 preliminary scope, schedule and utilize estimates of costs. As the project 15 is developed, preliminary engineering is performed, a detailed scope of d/b/a Energy NV
16 Nevada Power Company Company Power Nevada work and schedule are established and a detailed cost estimate is prepared. 17 The Business Case is updated with new information as it becomes and SierraCompany Pacific Power 18 available, and the cost-benefit analysis is reassessed to determine whether 19 the project should remain in the plan. 20 21 All Generation capital projects and the Business Cases are reviewed by the 22 Generation leadership team. The Generation leadership team prioritizes 23 the entire portfolio of capital projects as part of the 10-year business 24 planning process. Projects are prioritized with projects mandated by legal 25 or regulatory requirements, safety and environmental compliance 26 receiving top priority. Other factors such as improving or maintaining 27
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1 reliability, costs and efficiency are only considered after legal, regulatory, 2 safety and environmental projects are prioritized and funded. 3 4 All capital projects from each business unit within Nevada Power are 5 submitted for cross-department review and prioritization as part of the 6 company-wide 10-year business planning process. This step subjects 7 Generation’s capital project prioritization to peer review from other 8 business units and prioritization among the entire capital portfolio.
9 10 Capital projects that make it through both the Generation business unit and
11 the peer review and prioritization process are then submitted for funding
12 approval to executive management. Only approved projects are included
13 in the approved Capital Plan. 14
15 17. Q. PLEASE DESCRIBE THE PROJECT MANAGEMENT d/b/a Energy NV
16 Nevada Power Company Company Power Nevada OVERSIGHT PROCESS. 17 A. Inclusion of a project in the approved Capital Plan does not constitute and SierraCompany Pacific Power 18 internal project approval. Specific project approvals still must be obtained 19 as described below. This process begins with the assignment of a project 20 manager, who is responsible for executing a project or projects in the
21 Capital Plan. The project manager is required to submit an Authorization 22 for Expenditure (“AFE”) for approval prior to commencing a project. The 23 AFE includes the most current information regarding estimated project 24 cost, budget information and the Business Case. The AFE serves as a 25 business control to ensure construction projects, plant additions and 26 significant unbudgeted expenses are reviewed and approved by the 27 appropriate levels of management before funds are committed and spent.
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1 Project managers may submit a preliminary AFE requesting funds to 2 perform engineering in order to fully develop a capital project’s scope, 3 schedule and budget. In these situations, the project manager is then 4 required to update the Business Case and submit a supplemental AFE for 5 the full funding of the project prior to committing and spending additional 6 funds. 7 8 A Standard Project Proposal (“SPP”) is prepared for capital projects
9 exceeding $1 million and submitted with the AFE for management review 10 and approval. The SPP template has been designed to provide a consistent
11 collection of supporting information to management and regulators.
12 Depending on the size and complexity of the proposed project, business
13 units can append additional relevant information to the SPP template. 14 15 Project managers are responsible for monitoring actual and forecast d/b/a Energy NV
16 Nevada Power Company Company Power Nevada spending against the approved project funding amounts in the approved 17 AFE. Project managers provide monthly cost, schedule and scope updates and SierraCompany Pacific Power 18 for each project to Generation management. Each business unit performs 19 a thorough review and analysis of its capital portfolio each month. 20 Business units review project performance with project managers. 21 Business units forecast capital spending, analyze budget variances, 22 perform peer reviews and report results to Corporate Finance and to the 23 executive team monthly. 24 25 26 27
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1 18. Q. PLEASE ADDRESS DISCRETIONARY SPENDING AS IT 2 RELATES TO NEVADA POWER’S CAPITAL MANAGEMENT 3 PROCESS. 4 A. As explained above, capital is prioritized first by legal, regulatory, safety 5 and environmental requirements, then by financial considerations 6 including costs, reliability and efficiency. Discretion is used across the 7 prioritization process with the exception of projects designated as 8 mandated by legal or regulatory requirements. While safety and
9 environmental receive a high priority, these projects often cannot be 10 justified economically, and the number of requests for investment are
11 usually more than the entire capital budget. Management must use
12 discretion in selecting which safety and environmental projects (that are
13 not otherwise required by law) are given priority over others. These 14 decisions are typically based on the number of impacted employees, 15 severity of the risk and whether administrative controls are possible. d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 17 and SierraCompany Pacific Power 19. Q. HOW IS DISCRETION APPLIED TO FINANCIALLY JUSTIFIED 18 PROJECTS? 19 A. Again, far more requests are made for capital investment than can be 20 funded under the budget. While force ranking of projects by financial 21 metrics creates a prioritized listing, other points are considered. Some 22 capital projects are tied to planned outages or other customer requirements. 23 This may adjust the relative ranking or timing of an investment. 24 Additionally, an emerging risk, such as security enhancements may impact 25 the relative ranking. Finally, some projects may be marginally economic- 26 based on assumptions, such as retirement date and expected impacts on 27 expense or workforce, and discretion must be used in evaluating the
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1 financial analysis. An example could be a retirement date. No one can 2 predict a retirement date with exact certainty and this is especially true 3 when the date used for planning and depreciation is several years out. 4
5 SECTION III: ERCR INVESTMENT
6 20. Q. PLEASE DESCRIBE THE GENERATION PROJECTS THAT ARE 7 A PART OF NEVADA POWER’S ERCR PLAN. 8 A. Nevada Power’s ERCR Plan discusses two categories of investment: costs
9 incurred to retire approximately 812 MW of coal generation assets 10 according to a prescribed schedule, and costs incurred to replace the retired
11 coal generation. The costs associated with both categories of investment
12 are implicated in this 2020 GRC.
13
14 A. RETIREMENT OF NEVADA POWER’S COAL-FIRED GENERATING FLEET. 15 21. Q. PLEASE DESCRIBE THE FIRST CATEGORY OF ERCR d/b/a Energy NV
16 Nevada Power Company Company Power Nevada INVESTMENT: COSTS INCURRED TO RETIRE NEVADA 17
and SierraCompany Pacific Power POWER’S COAL-FIRED GENERATING FLEET. 18 A. In Nevada Power’s initial ERCR Plan filing, Docket No. 14-05003, the 19 Commission approved the “structured and orderly retirement” of Nevada 20 Power’s coal fleet according to the following schedule: 21 22 23 24
25 26 27
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1 Table Rekowski-Direct-3 2 3 4 5 6 7
8 9 Consistent with the approved ERCR Plan, Nevada Power retired Reid 10 Gardner Units 1, 2 and 3 (“RG123”) on December 31, 2014. In 2016,
11 Nevada Power filed, and the Commission approved, an amendment to its
12 ERCR Plan in which it sought approval to advance the retirement date for
13 Reid Gardner Unit 4 (“RG4”) from December 31, 2017, to February 28, 14 2017.4 The Navajo Generating Station (“NGS”) ceased operation and 15 began decommissioning and demolition activities on November 20, 2019. d/b/a Energy NV
16 The costs associated with these efforts are further addressed in the Nevada Power Company Company Power Nevada 17 testimony of Company witness, Mr. Johns. and SierraCompany Pacific Power 18 19 20 21 22 23 24
25
26 4 See, PUCN Docket No. 16-08027. Nevada Power demonstrated that, given current fuel prices, it was more economic to burn through the remaining Reid Gardner coal pile and decommission the plant in 27 advance of the December 31, 2017, scheduled retirement date. 28 Rekowski-DIRECT 17
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1 B. REPLACEMENT CAPACITY 2 22. Q. PLEASE DESCRIBE THE SECOND CATEGORY OF ERCR 3 COSTS, INVESTMENTS IN GENERATING CAPACITY TO 4 REPLACE THE CAPACITY THAT WAS BEING PROVIDED BY 5 NEVADA POWER’S COAL-FIRED GENERATING FLEET. 6 A. In Docket No. 14-05003, the Commission approved Nevada Power’s 7 acquisition of two existing power plants, the 272 MW Las Vegas 8 Cogeneration Station (renamed the Las Vegas Generating Station) and the
9 210 MW Sun Peak Generating Station (“Sun Peak”), as well as the 10 construction of the new Nellis Solar Array 2 (“Nellis Project”), a 15 MW
11 solar PV facility located at the Nellis Air Force Base. Additionally, in
12 Nevada Power’s 2015 triennial Integrated Resource Plan (“IRP”), Docket
13 No. 15-07004, the Commission approved Nevada Power’s purchase of the 14 Southern Nevada Water Authority’s (“SNWA”) 25 percent ownership 15 interest in the Silverhawk Generating Station (“Silverhawk”). In d/b/a Energy NV
16 Nevada Power Company Company Power Nevada approving the Silverhawk acquisition, the Commission ordered that 54 17 MW of the 130 MW of generating capacity being acquired be designated and SierraCompany Pacific Power 18 as ERCR capacity.5 Each of these four replacement facilities is addressed 19 in more detail below. 20 21 22 23 24 25 26
27 5 Commission Docket No. 15-07004, Modified Final Order, Paragraph 267 (February 12, 2016). 28 Rekowski-DIRECT 18
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1 23. Q. ARE THE COSTS INCURRED TO ACQUIRE AND BUILD 2 REPLACEMENT CAPACITY PURSUANT TO A COMMISSION- 3 APPROVED ERCR PLAN SUBJECT TO TYPICAL 4 REGULATORY AND ACCOUNTING TREATMENT? 5 A. No. The Las Vegas and Sun Peak generating stations, the Nellis solar 6 project and 54 MW of the 130 MW of Silverhawk capacity acquired from 7 SNWA are subject to special accounting and ratemaking treatment under 8 the ERCR statutes and regulations. The costs of the acquisition of the
9 facilities that are approved by the Commission to provide replacement 10 capacity under the ERCR “shall be deemed to be a prudent investment.”
11 The accounting for the purchase transaction and corresponding regulatory
12 assets are also addressed in the testimony of Michael Cole. Regarding
13 other costs of acquiring or constructing replacement capacity under the 14 ERCR Plan, such as return, depreciation and O&M costs incurred prior to 15 being recognized in revenue requirement, NRS § 704.7317 provides that: d/b/a Energy NV
16 Nevada Power Company Company Power Nevada An electric utility shall, upon the completion of construction 17 or acquisition of any electric generating plant or other facility and SierraCompany Pacific Power constructed or acquired pursuant to an emissions reduction 18 and capacity replacement plan accepted by the Commission pursuant to NRS 704.751, begin recording in a regulatory 19 asset, with carrying charges, an amount that reflects a return on the electric utility’s investment in the facility, depreciation 20 of the utility’s investment in the facility and the cost of operating and maintaining the facility. 21 22 I therefore sponsor portions of the information set forth in the following 23 schedules, which describe the costs that have been tracked in the 24 regulatory assets established pursuant to NRS § 704.7317.
25 • H-CERT-32 LV Cogen Regulatory Asset (Section V) 26 • H-CERT-33 Sun Peak Regulatory Asset (Section V) 27
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1 • H-CERT-34 Nellis Solar Regulatory Asset (Section V) 2 • H-CERT-35 Silverhawk Regulatory Asset (Section V) 3
4 24. Q. PLEASE EXPLAIN THE COSTS SHOWN IN THE ERCR 5 SCHEDULES. 6 A. Nevada Power is requesting recovery of the deferred depreciation expense, 7 return on its investment and O&M expenses, with associated carry 8 charges, incurred between June 1 and December 31 of 2017 and collected
9 in a regulatory asset as approved in Docket Nos. 14-05003, 15-07004 and 10 17-06003 be included in rate base.
11
12 25. Q. DO YOU SUPPORT ALL OF THE INFORMATION REFLECTED
13 ON THESE SCHEDULES? 14 A. No. I support deferred O&M expenses as well as the non-labor cost of 15 service adjustments for O&M expenses related to new and retiring ERCR d/b/a Energy NV
16 Nevada Power Company Company Power Nevada assets. Company witness Ellen Fincher provides support for the deferred 17 depreciation, return and carry that are included in the regulatory assets. and SierraCompany Pacific Power 18
19 26. Q. HOW ARE THE REGULATORY ASSETS’ DEFERRED O&M 20 EXPENSES SHOWN ON THE SCHEDULES DETERMINED? 21 A. The Company segregated all incremental O&M expenses into specified 22 departments with due care being taken to exclude any shifted and shared 23 costs that previously existed before the acquisition. For costs incurred 24 prior to the previous rate effective period (January 1, 2018), on a monthly 25 basis, all expenses posted to the new plant departments were reclassified 26 to the regulatory asset.
27
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1 C. LAS VEGAS GENERATING STATION AND SUN PEAK GENERATING STATION 2 27. Q. PLEASE DESCRIBE THE LAS VEGAS GENERATING STATION. 3 A. The Las Vegas Generating Station houses three natural gas fueled 4 generating units, a 1x1 combined cycle facility that commenced operation 5 in June 1994, and two 2x1 combined cycle facilities that went into 6 operation in January 2003. All of these facilities are located in an industrial 7 section of North Las Vegas. The purchase price for the Las Vegas 8 Generating Station was $130.82 million, and was included and approved
9 in Docket No. 14-05003. 10
11 28. Q. PLEASE DESCRIBE THE SUN PEAK GENERATING STATION.
12 A. Sun Peak houses three simple cycle combustion turbines, each with a
13 capacity of 74 MW. The three Sun Peak units went into service in June 14 1991. The Sun Peak units are located on the same property as the former 15 Sunrise Generating Station in Las Vegas. The capital cost of the d/b/a Energy NV
16 Nevada Power Company Company Power Nevada acquisition of the Sun Peak facility was $15.8 million: an $11.0 million 17 purchase price, $4.5 million in integration costs, and $300,000 in and SierraCompany Pacific Power 18 transaction costs. These costs were also approved in Docket No. 14- 19 05003. 20
21 29. Q. WHAT REASONS DID THE COMMISSION PROVIDE FOR 22 APPROVING THE ACQUISITION OF THE LAS VEGAS 23 GENERATING STATION AND THE SUN PEAK GENERATING 24 STATION? 25 A. The Commission considered the acquisition of the Las Vegas and Sun 26 Peak generating stations together, and based its decision on testimony 27 supporting the acquisitions provided by the Bureau of Consumer
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1 Protection (“BCP”) and the Regulatory Operations Staff (“Staff”). 2 Regarding the BCP’s conclusions of the attributes of the acquisitions the 3 Commission found:
4 168. Specifically, the Commission agrees with BCP that: (1) 5 "[b]oth facilities are located within the load pocket of the Las Vegas Valley which under Nevada Power ownership assures 6 an ongoing commitment to Nevada loads in lieu of the retirement of the Reid Gardner coal units of 550 MW 7 electrically within the Las Vegas Valley load pocket;" (2) "the location within the load center provides a unique value 8 to the system versus resources located outside;" (3) "[t]hese 9 acquisitions at prices noted earn high marks in regard to cost to customers and offers value benefits of being located in the 10 load pocket;" and (4) "the acquisition of the Las Vegas Cogen facility assures the sustainability of approximately 25 jobs 11 through 2036." (Ex. 66 at 7.)
12
13 The Commission also pronounced its agreement with the conclusions of 14 Staff regarding the attributes of the acquisition of the two Las Vegas 15 Generating Station units and the three Sun Peak combustion turbines: d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 169. Moreover, the Commission agrees with Staff that 17 "[t]hese three generating resources have been reliably serving and SierraCompany Pacific Power Nevada Power's load for more than 12 years," and that "they 18 provide very unique attributes that would be difficult to replace if Nevada Power were to look to capacity from other 19 generations options." (Ex. 79 at 30.) The Commission is persuaded by Staff's opinion that "Nevada Power appears to 20 have performed a reasonable due diligence review on these 21 resources," and that "Staff sees benefits in having these resources remain a part of Nevada Power's generating fleet 22 going forward." (Id.)
23 170. The Commission further agrees with Staff that "the capacity acquisition cost of these resources, $477 per kW for 24 the LV Co-Gen bundle and $71 per kW for Sun-Peak are 25 attractive when compared to the current cost of constructing new combined cycle and peaking capacity." (Id.) Staff states 26 that under Nevada Power's Alternate Plan, Case A, Nevada Power "assumed the new overnight cost of a combined cycle 27 28 Rekowski-DIRECT 22
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1 unit added in 2018 to be $699 million." (Id. at 19.) Indeed, based on the evidence in this Docket, the dollar per kW for 2 LV Cogen 1 and 2 and Sun-Peak should be considered a competitive price because it is significantly less than the cost 3 of a new combined cycle unit. The Commission's analysis 4 yields estimated capital costs of approximately $1,170 per kW for a new combined cycle resource and $1,100 per KW 5 for new peaking resources. (See generally Exhibit 11 and Exhibit 4.) Therefore, the acquisition of LV Cogen 1 and 2 6 and Sun-Peak should be considered good value for Nevada Power customers. 7 8 The Commission issued its unequivocal approval of the acquisitions of Las 9 Vegas Generating Station and the three Sun Peak units:
10
172. Consistent with the foregoing findings, the Commission 11 approves Nevada Power's request to acquire LV Cogen units 1 and 2, and the Sun-Peak facility. The Commission finds the
12 costs of these facilities reasonable when compared to the current cost of constructing new combined cycle and peaking 13 capacity units, and notes that all parties supported, or at least did not oppose, the acquisition of these three replacement 14 units. Therefore, given the evidence on this record, the 15 Commission agrees with Nevada Power that the proposed d/b/a Energy NV price for LV Cogen 1 and 2 and Sun-Peak are "extremely 16 favorable for customers” and fulfills the requirements of NRS Nevada Power Company Company Power Nevada 704.746(8). (Internal citation omitted.) 17 and SierraCompany Pacific Power 18
19 30. Q. WAS THE ACQUISITION OF THE THREE GENERATING UNITS 20 AT THE LAS VEGAS GENERATING STATION COMPLETED 21 ON TIME AND AT THE PRICE APPROVED BY THE 22 COMMISSION IN DOCKET NO. 14-05003? 23 A. Yes. Nevada Power was able to successfully negotiate a termination of the 24 purchase power agreement, so all of the units were closed to plant in
25 service on December 19, 2014, at a final cost of $130,199,023. All of the 26 generating units are used and continue to provide electric service.
27
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1 31. Q. WAS THE ACQUISITION OF THE THREE COMBUSTION 2 TURBINES AT THE SUN PEAK GENERATING STATION 3 COMPLETED ON TIME AND AT THE PRICE APPROVED BY 4 THE COMMISSION IN DOCKET NO. 14-05003? 5 A. Yes. Units 1, 2 and 3 closed to plant in service on December 19, 2014, at 6 a final cost of $11,312,998. Sun Peak is used and continues to provide 7 electric service. 8
9 D. NELLIS SOLAR ARRAY 2 10 32. Q. PLEASE DESCRIBE THE NELLIS PROJECT
11 A. The 15 MW Nellis Project is constructed on a closed landfill on the east
12 side of Nellis Air Force Base. The Nellis Project consisted of a 15 MW
13 single-axis tracking solar PV plant, the new Clinton Substation, and 14 interconnections to Nevada Power’s transmission and distribution systems 15 and to the Nellis Air Force Base’s distribution system. The Nellis Project d/b/a Energy NV
16 Nevada Power Company Company Power Nevada allows the energy produced by the solar plant to be provided directly to 17 the U.S. Air Force Base (Nevada Power’s customer), with any unused and SierraCompany Pacific Power 18 energy flowing back to Nevada Power’s system for other customer use. 19 The Clinton Substation allows the energy produced by the solar plant to 20 be provided directly to the Nevada Power system, as well as a providing a 21 backup source of energy to the Nellis Air Force Base. 22 23 24 25 26 27
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1 33. Q. WHAT WAS THE APPROVED PROJECT BUDGET FOR THE 2 NELLIS PROJECT AND WHAT WAS THE ACTUAL COST OF 3 THE PROJECT? 4 A. In Docket No. 14-05003, the Commission approved $54.5 million 5 (excluding AFUDC) for the Nellis Project. The total plant addition was 6 $52.9 million including AFUDC and the total project costs without 7 AFUDC was $53,906,749. The project was put into service on November 8 23, 2015, a month ahead of the original project schedule of December 31,
9 2015. 10
11 E. SNWA’S 25 PERCENT SHARE OF SILVERHAWK
12 34. Q. PLEASE DESCRIBE THE SILVERHAWK GENERATING
13 STATION PURCHASE. 14 A. Silverhawk is a 520 MW 2x1 combined cycle plant that was previously 15 co-owned by Nevada Power and SNWA. The facility went into service in d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 2004. The capital cost of the acquisition of SNWA’s 25 percent share of 17 Silverhawk was $77.3 million. While the Silverhawk acquisition was not and SierraCompany Pacific Power 18 proposed in an amendment to the ERCR Plan, the Southern Nevada Hotel 19 Group, BCP and Staff all proposed in Docket No. 15-07004 that 54 MW 20 of the 130 MW purchase go to fill the remaining 54 MW of ERCR capacity 21 specified in NRS § 704.7316(2)(d). 22 23 24 25 26 27
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1 35. Q. WHAT REASONS DID THE COMMISSION PROVIDE FOR 2 APPROVING THE ACQUISITION OF SNWA’S 130 MW SHARE 3 OF SILVERHAWK STATION? 4 A. The Commission considered the acquisition of SNWA’s 130 MW share of 5 Silverhawk in the context of all pending NRS Chapter 704B applications 6 and under all load scenarios. Specifically, the Commission found:
7 266. The 130 MW Silverhawk resource is needed under all 8 load forecast scenarios (including a low load scenario with all pending NRS Chapter 704B applicants leaving bundled 9 utility service) and the cost associated with acquiring SNWA's share is a good deal for NPC. The Commission 10 approves NPC's request to spend approximately $77.3
million in 2017 to acquire SNWA's 25 percent share of the 11
Silverhawk Generation Station.
12
13 The Commission also agreed with the parties that 54 MW of the 14 Silverhawk acquisition should be designated as ERCR capacity.
15 267. The Commission designates 54 MW of the 130 MW of d/b/a Energy NV the generation capacity gained from the Silverhawk 16 Nevada Power Company Company Power Nevada acquisition as ERCR capacity under NRS 704.7316(2)(d). 17 Pursuant to NAC 704.0027, the Commission finds that and SierraCompany Pacific Power deviation from NAC 704.9453(8) is in the public interest. 18 There is good cause to not require an RFP for this acquisition and the corresponding designation of 54 MW as ERCR 19 capacity because the costs for the acquisition are low when 20 compared to the high cost of constructing 54 MW of new generation replacement capacity. 21 22 23 24 25 26 27
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1 36. Q. WAS THE ACQUISITION OF SNWA’S SHARE OF THE 2 SILVERHAWK FACILITY COMPLETED ON TIME AND AT 3 THE PRICE APPROVED BY THE COMMISSION IN DOCKET 4 NO. 15-07004? 5 A. Yes. Nevada Power was successfully able to terminate the purchase power 6 agreement it had with Silverhawk, and the transaction with SNWA closed 7 to plant in service on March 31, 2017, at a final cost of $77,095,780. The 8 entire Silverhawk facility is used and useful and continues to provide
9 electric service to Nevada Power’s customers. 10
11 SECTION IV: GENERATION INVESTMENT BETWEEN JUNE 1, 2017, AND
12 DECEMBER 31, 2019
13 37. Q. HOW HAVE YOU ORGANIZED THIS SECTION OF YOUR 14 TESTIMONY, WHICH ADDRESSES NON-ERCR INVESTMENT 15 IN GENERATION ASSETS SINCE JUNE 1, 2017? d/b/a Energy NV
16 Nevada Power Company Company Power Nevada A. In the following pages, I address plant-by-plant, the major investment 17 Nevada Power has made in its generation fleet since the close of the and SierraCompany Pacific Power 18 certification period in the 2017 GRC. 19
20 A. CHUCK LENZIE 21 1. CL1099 Elevator for Air-Cooled Condenser 22 38. Q. PLEASE DESCRIBE THE CHUCK LENZIE ELEVATOR FOR 23 AIR-COOLED CONDENSER PROJECT. 24 A. The Chuck Lenzie Elevator for the Air-Cooled Condenser Project 25 encompasses the installation of a freight elevator that travels from ground 26 level to the operational deck of the Air-Cooled Condenser (“ACC”). The 27 ACC was originally constructed with access to all elevations through a
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1 single set of stairs and ladders. The operational deck is approximately 100 2 feet above the ground. Utilizing the elevator instead of climbing stairs 3 results in improved labor efficiencies by removing the time required for 4 employees to mobilize to their work location, as well as eliminating 5 physical stress related to carrying tools and materials up several flights of 6 stairs to perform required operations and maintenance activities on 7 equipment located on the ACC operational deck. Operators are required to 8 inspect ACC equipment twice per shift. Additionally, the elevator will
9 greatly enhance the safety of employees. A medical emergency occurred 10 at Chuck Lenzie that required transport of a patient from the ACC
11 operational deck to the ground utilizing stairs. This was a noted difficulty,
12 added time for the patient to receive the care they needed, and created a
13 safety concern for first responders. 14
15 39. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE d/b/a Energy NV
16 Nevada Power Company Company Power Nevada COMMISSION? 17 A. No, this project was not presented to the Commission for pre-approval. and SierraCompany Pacific Power 18
19 40. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 20 A. The original budgeted cost for the project was $708,700, which was based 21 upon an estimate from 2013. The project was competitively bid and the 22 cost was higher than estimated. The actual cost of the project was 23 $1,011,978 at completion. The total plant in service was $1,011,978 24 including AFUDC. All of the facilities installed are in service and used 25 and useful. 26 27
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1 B. CLARK 2 1. CS2036 Clark 21 B Power Turbine OEM Replacement – SN 80306 3 41. Q. PLEASE DESCRIBE THE CLARK UNIT 21 B POWER TURBINE 4 OEM REPLACEMENT PROJECT. 5 A. Clark Unit 21 B’s Power Turbine (“PT”) experienced a catastrophic failure 6 in October 2016. A thorough investigation determined that many design 7 factors contributed to the failure including the # 7 bearing support 8 connection weld joint cracking, lean back of the Row 1 vanes toward the
9 Row 1 blades/disks, and forward distortion of the Row 1 disk side plate 10 material toward the Row 1 Vanes.
11
12 The scope of this project was the purchase of a replacement Power Turbine
13 under the Terms and Conditions of the LTSA with PWPS. 14
15 42. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE d/b/a Energy NV
16 Nevada Power Company Company Power Nevada COMMISSION? 17 A. No. This is a normal capital replacement of worn plant equipment, which and SierraCompany Pacific Power 18 is not typically presented to the Commission for approval in advance. 19
20 43. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 21 A. The project was estimated at $1,591,048 (without AFUDC) and the total 22 project costs was $1,516,132 (without AFUDC). The total plant addition 23 was $1,985,495, including AFUDC. All of the facilities installed are in 24 service and used and useful. 25 26 27
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1 2. CS2019, CS2020, CS2021, CS2022, CS2023, CS2024, CS2028, 2 CS2029, CS2030, CS2031, CS2035 & CS2036 PWPS FT8-3 Power 3 Turbine OEM Upgrade and Overhaul
4 44. Q. PLEASE DESCRIBE THE CLARK PWPS FT8-3 POWER 5 TURBINE OEM UPGRADE AND OVERHAUL PROJECT. 6 A. As part of the failure of Clark Unit 21 B’s PT in October 2016, borescope 7 inspections of the remaining 23 peaking units were performed to identify 8 any at-risk units. Four units were identified as being at a high to very high
9 risk of similar failure as Unit 21 B. 10
11 To address these issues, PWPS recommended that the identified PTs be
12 sent to its shop for OEM service. PWPS also recommended an upgraded
13 design to all of the Clark PTs that would be better suited to last the 25,000- 14 hour major service interval. Based on discussions between Nevada Power 15 Generation Engineering, PWPS, other FT8 users, and a third-party turbine d/b/a Energy NV
16 Nevada Power Company Company Power Nevada service contractor, Nevada Power determined that Clark Generating 17 Station PWPS FT8 PTs should be upgraded in a program fashion over and SierraCompany Pacific Power 18 several years by priority based on annual borescope inspections. The 19 Company entered into an LTSA with PWPS to facilitate the repair 20 program. The LTSA contract was previously filed in Docket No. 19- 21 03004. 22 23 The benefits of repairing and upgrading all of the PWPS PTs include: 24 reduced risk of failure, reduced risk of exposure to costly 25 repairs/replacements, and reduced risk of long periods of downtime/unit 26 unavailability. 27
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1 The scope of this project was to repair and upgrade all Clark PWPS FT8- 2 3 Swiftpac Units’ PTs for continued service and availability. This project 3 encompassed 12 units, four more upgrades will occur during the 4 certification period and are discussed in Section V below. 5
6 45. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE 7 COMMISSION? 8 A. No. This is a normal capital replacement of worn plant equipment, which
9 is not typically presented to the Commission for approval in advance. 10
11 46. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
12 A. The total plant addition was approximately $10,660,000, including
13 AFUDC for the 12 projects completed through the test period. 14
15 3. CS2037, CS2038, CS2039, CS2040, CS2060, CS2064, CS2065, d/b/a Energy NV
16 Nevada Power Company Company Power Nevada CS2066, CS2069, CS2070, CS2072, CS2073, CS2074, CS2075, 17
and SierraCompany Pacific Power CS2076, CS2077 & CS2080 PWPS FT8-3 Turbine Exhaust Case 18 Upgrade
19 47. Q. PLEASE DESCRIBE THE CLARK FT8-3 TURBINE EXHAUST 20 CASE UPGRADE PROJECT. 21 A. The Clark peaking unit’s manufacturer, PWPS, identified several issues 22 with the turbine exhaust case (“TEC”). The TEC is located at the rear 23 portion of the Gas Generator (“GG”), and is the component that directs the 24 flow of hot combustion gases from the GG into the PT for the 25 transmission/coupling of power to the electrical generator. 26 27
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1 PWPS identified the following issues with the FT8-3 fleet: the inner duct 2 locating pins binding with the bushings in the inner duct of the case, 3 causing distortion and cracking on the inner duct area behind the strut 4 fairings; failure of GG positioning ring bolts; the hot gas path strut fairings 5 or vanes of the TEC eroding due to the non-adequate material for the actual 6 exhaust temperatures. 7 8 According to PWPS’s estimations, the present TEC design will not be able
9 to meet the expected designed major service interval of 25,000 hours. 10 Failure of the vanes/struts or other related parts will result in a catastrophic
11 failure of the PT due to foreign material damaging the hot gas path
12 components. Borescope inspections of the PTs and TECs of the Clark units
13 identified several units as high risk for TEC failure. 14 15 To address these problems, several service bulletins were issued by PWPS, d/b/a Energy NV
16 Nevada Power Company Company Power Nevada namely 01B15, 10B02 and 14B06. The proposed redesigned TEC 17 incorporates new vane material, change from Inconel to Haynes 188 alloy, and SierraCompany Pacific Power 18 upgrades the GG position ring bolts material and safety wire method, and 19 increases to the pin clearance to prevent pin binding. 20 21 Based on discussions between Nevada Power Generation Engineering, 22 PWPS and a third-party turbine service contractor, Nevada Power 23 determined that the Clark peaking units’ TECs should be 24 repaired/upgraded methodically, over several years on a priority basis 25 based on annual borescope inspections.
26 27
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1 The benefits of repairing and upgrading all of the Clark peaking units 2 include: mitigated risk of a catastrophic failure; reduced risk of exposure 3 to costly unplanned repairs or replacements; reduced unit unavailability 4 due to an unplanned failure or repair. 5 6 The scope of this project was to repair and upgrade all Clark FT8-3 7 peaking units’ TECs for continued service and availability. 8
9 48. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE 10 COMMISSION?
11 A. No. This is a normal capital replacement of worn plant equipment, which
12 is not typically presented to the Commission for approval in advance.
13
14 49. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 15 A. The total plant addition for the 17 projects was $5,306,815, including d/b/a Energy NV
16 Nevada Power Company Company Power Nevada AFUDC. All of the facilities installed are in service and used and useful 17 in the provision of utility. and SierraCompany Pacific Power 18
19 4. CS2041 Clark Peaker MeeFog System 20 50. Q. PLEASE DESCRIBE THE CLARK PEAKER MEEFOG SYSTEM 21 PROJECT. 22 A. The Clark peaking units utilize combustion turbine inlet water injection 23 systems, known as inlet fogging and under the trade name MeeFog, to 24 control inlet air temperature conditions during the summer to meet 25 demands during peak loads and serve customer needs. The original 26 fogging system utilized six motors and belt-driven splash-oil-lubricated 27 water pumps per peaking unit to inject water into the inlet of each unit and
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1 had a high maintenance cost and low reliability. The OEM upgrade to the 2 original fogging system skids greatly simplified skid equipment without 3 compromising system performance. The new fogging skid design 4 incorporates two direct-drive electric motors with an oil-free pump design 5 per peaking unit. This significantly reduced the complexity of the system 6 while fully maintaining system performance. 7 8 The scope of this project was to procure and install the recommended
9 OEM fogging upgrades to reduce maintenance costs while maintaining 10 performance and improving fogging system reliability.
11
12 51. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE
13 COMMISSION? 14 A. No, this was a normal maintenance capital project that is not typically 15 presented to the Commission in advance for approval in an IRP or other d/b/a Energy NV
16 Nevada Power Company Company Power Nevada docket. 17 and SierraCompany Pacific Power
18 52. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 19 A. The project was estimated at $1,518,957 (without AFUDC) and the total 20 project costs was $1,628,680 (without AFUDC). The total plant addition 21 was $1,668,544, including AFUDC. All of the facilities installed are in 22 service and used and useful in the provision of utility 23 24 25 26 27
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1 5. CS2045 & CS2046 Clark Units 9 & 10 – Cooling Tower Water 2 Dispersing Media Replacement and Structural Repairs
3 53. Q. PLEASE DESCRIBE THE CLARK UNITS 9 & 10 COOLING 4 TOWER MEDIA REPLACEMENT AND STRUCTURAL REPAIRS 5 PROJECTS. 6 A. The Clark Steam Turbine units 9 and 10 utilize evaporative cooling towers 7 to condense steam into condensate. The Company contracted two 8 independent and qualified cooling tower firms to inspect the Clark cooling
9 towers. They reported (1) deteriorated cooling tower fan supports, which 10 create a misalignment of the fans, motors and gearboxes, which in turn
11 causes the fans to cut through the cowls and erode the fan blades; and (2)
12 mineral build up on the water dispersing media, which induces excessive
13 weight and stress in the already compromised structure. These findings 14 represented a safety risk to plant personnel, equipment, and reliability. The 15 typical failure mechanism of structurally-deficient cooling towers is d/b/a Energy NV
16 Nevada Power Company Company Power Nevada structural collapse during operation. This would pose danger to plant 17 personnel and result in the Units 9 and 10 becoming unavailable to service and SierraCompany Pacific Power 18 native load during peak periods. 19 The scope of these projects was to replace the drift eliminators, water 20 dispersing media, and major structural components to extend the service 21 life of the both cooling towers. 22
23 54. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE 24 COMMISSION? 25 A. No. This is a normal capital replacement of worn plant equipment, which 26 is not typically presented to the Commission for approval in advance. 27
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1 55. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 2 A. The total plant addition was $1,342,823, including AFUDC. Project 3 CS2045 was $662,009 and project CS2046 was $680,814. All of the 4 facilities installed are in service and used and useful in the provision of 5 utility. 6
7 6. CS2115 Capital Spare GG8-3 Gas Generator 8 56. Q. PLEASE DESCRIBE THE CLARK SPARE GG8-3 GAS 9 GENERATOR PROJECT. 10 A. The Clark Generating Station has 12 PWPS FT8-3 Swift Pac Units, with
11 each Swift Pac having two gas generators which are aero derivative
12 combustion gas turbines that drive a single 54-MW generator. The average
13 rebuild turnaround time for a GG is 90 days, and therefore, it would be 14 prudent for Nevada Power to purchase a rotatable spare to mitigate the risk 15 of unit unavailability due to the typical repair turnaround time. d/b/a Energy NV
16 Nevada Power Company Company Power Nevada The scope of this project was to procure a single spare GG to mitigate risk 17 to Nevada Power’s customers by limiting Clark peaking unit and SierraCompany Pacific Power 18 unavailability to serve native load during peak periods. 19
20 57. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE 21 COMMISSION? 22 A. No. This is a purchase of capital spares that will be needed for a future 23 major outage. This type of purchase is not usually presented to the 24 Commission for approval in advance 25 26 27
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1 58. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 2 A. The project was estimated at $6,616,334 (without AFUDC) and the total 3 project costs was $6,203,683 (without AFUDC). The total plant addition 4 was $6,203,732. 5
6 7. CS2116 Spare FT8-3 Turbine Exhaust Case 7 59. Q. PLEASE DESCRIBE THE SPARE FT8-3 TURBINE EXHAUST 8 CASE PROJECT. 9 A. The Clark Generating Station has 12 PWPS FT8-3 Swift Pac Units, with 10 each Swift Pac having two TECs, for a total of 24 TECs in service. The
11 TECs are in the hot gas exhaust path of the turbine. Without a spare, the
12 average return to service from factory is 90 days. Therefore, it would be
13 prudent for Nevada Power to purchase a spare TEC to mitigate the down 14 time risk to Nevada Power’s customers, particularly during peak time. 15 The scope was to procure a single spare TEC to mitigate the down time d/b/a Energy NV
16 Nevada Power Company Company Power Nevada risk to Nevada Power’s customers. 17 and SierraCompany Pacific Power
18 60. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE 19 COMMISSION? 20 A. No. This is a purchase of capital spares that will be needed for a future 21 major outage. This type of purchase is not usually presented to the 22 Commission for approval in advance 23
24 61. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 25 A. The project was estimated at $1,618,320 (without AFUDC) and the total 26 project costs was $1,432,896 (without AFUDC). The total plant addition 27 was $1,432,896, including AFUDC.
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1 8. CS2136 & CS2137 Steam Turbine Units 9 & 10 Valve Upgrade 2 62. Q. PLEASE DESCRIBE THE CLARK STEAM TURBINE UNITS 9 & 3 10 VALVE UPGRADE PROJECT. 4 A. The Clark Steam Turbine Units 9 and 10 were commissioned in 1993. 5 There have been many material advances in the industry since the units 6 were commissioned. This project was undertaken to upgrade the Unit 9 7 and 10 Main Steam Stop Valves, Main Steam Control Valves, HP Steam 8 Bypass Valves, and the LP Steam Induction Control Valves with a modern
9 alloy material. The changing dispatch of these units has resulted in a 10 greatly increased thermal cycling, causing thermal fatigue to the original
11 alloys, which resulted in valve leakages causing costly emergency repairs
12 to several sections of piping due to internal erosion and eventual failure.
13 This posed safety concerns and loss of production, negatively impacting 14 Nevada Power’s customers. 15 d/b/a Energy NV
16 Nevada Power Company Company Power Nevada This upgrade increased the operational safety for our employees and 17 reliability for our customers and extended the valves’ service life to 2033. and SierraCompany Pacific Power 18 This material upgrade is from AISI 422 Stainless Steel to Incoloy 901 19 alloy for the valve stems, seats and bushings. 20 21 The scope was to procure and install the recommended upgraded alloy 22 material during the rebuild of the Unit 9 and 10 Main Steam Stop Valves, 23 Main Steam Control Valves, HP Steam Bypass Valves and the LP Steam 24 Induction Control Valves. 25 26 27
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1 63. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE 2 COMMISSION? 3 A. No. This is a normal capital replacement of worn plant equipment, which 4 is not typically presented to the Commission for approval in advance. 5
6 64. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 7 A. The total plant addition was $2,035,307, including AFUDC. Project 8 CS2136 was $1,002,073, and project CS2137 was $1,033,234. All of the
9 facilities installed are in service and used and useful in the provision of 10 utility.
11
12 9. CS2140 Clark Unit 19 A Gas Generator Rebuild – SN P743068
13 65. Q. PLEASE DESCRIBE THE CLARK UNIT 19 A GAS GENERATOR 14 REBUILD PROJECT. 15 A. On February 5, 2019, Nevada Power and PWPS determined that Unit 19 d/b/a Energy NV
16 Nevada Power Company Company Power Nevada A GG, Model GG8-3 – Serial Number P743068, was consuming lube oil 17 at a rate 10 times more than its sister Unit 19 B GG, Model GG8-3 – Serial and SierraCompany Pacific Power 18 Number P743069, for the same time period. This high oil consumption 19 suggested that there was an internal damage. 20 21 Upon further site evaluations and a borescope inspection, the GG lube oil 22 was determined to be entering the hot gas path around the # 4/5 GG shaft 23 bearing area, indicating a damaged bearing. This type of internal failure 24 could not be repaired on site. Unit 19 A GG was shipped to PWPS for 25 further inspections and repairs. 26 27
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1 The scope of the project was to investigate and repair the GG bearing 2 damage. 3
4 66. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE 5 COMMISSION? 6 A. No. This is a normal capital replacement of worn plant equipment, which 7 is not typically presented to the Commission for approval in advance. 8
9 67. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 10 A. The project was estimated at $1,677,649 (without AFUDC) and the total
11 project costs was $1,516,132 (without AFUDC). The total plant addition
12 was $1,343,706, including AFUDC. All of the facilities installed are in
13 service and used and useful in the provision of utility. 14
15 10. CS2145 Replace Underground Main Fuel Gas Pipe Line – Units 4-8 d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 68. Q. PLEASE DESCRIBE THE CLARK UNDERGROUND MAIN FUEL 17
and SierraCompany Pacific Power GAS PIPE LINE PROJECT. 18 A. Clark Station is fueled by natural gas, drawn from the Southwest Gas 19 distribution system. The underground piping was inspected following leak 20 issues experienced at Higgins Station in 2018. The original underground 21 fuel gas piping for Units 4 through 8 was installed from 1972 to 1979 and 22 made of carbon steel. 23 24 Inspection of the piping detected severe corrosion at test locations, with 25 the loss of almost 70 percent of the pipe wall thickness. In order to 26 completely eliminate safety hazard risks, it was recommended to 27 depressurize and replace all the underground fuel gas piping prior to
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1 putting the units back in service. In order to simplify the project and 2 mitigate future risk, avoid damaging underground installation in case of 3 excavation, the new gas piping was installed above grade to prevent future 4 corrosion, reduce costs as compared to underground installation, and 5 shorten installation time in order to have the units available for summer 6 native load. Above ground piping will eliminate future corrosion issues 7 caused by corrosive soil exacerbated by the presence of high underground 8 water levels onsite.
9 10 The scope of this project was to replace 3,200 feet of underground main
11 fuel gas piping that serves Units 4 through 8 at Clark Generating Station.
12
13 69. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE 14 COMMISSION? 15 A. No. This is a normal capital replacement of worn plant equipment, which d/b/a Energy NV
16 Nevada Power Company Company Power Nevada is not typically presented to the Commission for approval in advance. 17 and SierraCompany Pacific Power
18 70. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 19 A. The project was estimated at $5,367,920 (without AFUDC) and the total 20 project cost was $2,989,144 (with AFUDC). The original estimate was 21 based on the cost per foot experienced at the Higgins Station, but the work 22 at the Clark Station was completed at a considerably lower cost. The total 23 plant addition was $2,946,142, including AFUDC. All of the facilities 24 installed are in service and used and useful. 25 26 27
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1 11. CS2236 Unit 21A Gas Gen Rebuild 2 71. Q. PLEASE DESCRIBE THE CLARK UNIT 21A GAS GEN REBUILD 3 PROJECT. 4 A. On September 14, 2019, the Company and PWPS determined that Unit 5 21A GG (Model GG8-3 – Serial Number P743073) had an internal failure 6 causing the unit to trip off line due to high vibration on "K" Flange sensor 7 with a sudden excessive consumption of turbine lube oil (11.8 gallons) 8 through the hot gas path and excessive high bearing temperatures on the
9 #5 bearing. Based on the operational data, and later confirmed by PWPS 10 after shop inspection, the unit suffered a #5 bearing failure and the oil was
11 lost through a compromised #5 bearing housing as indicated from the
12 sudden rise in scavenge oil temperature. Since commissioning in 2008,
13 Unit 21A has 1,189 starts with 4,488 run hours. This type of failure on an 14 aero derivative gas generator/turbine (based on Pratt & Whitney's JT8D 15 aircraft engine) cannot be repaired on site. The Unit 21A gas generator d/b/a Energy NV
16 Nevada Power Company Company Power Nevada (SN P743073) was sent to PWPS for inspection and repairs. 17 and SierraCompany Pacific Power
18 72. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE 19 COMMISSION? 20 A. No. This was capital maintenance project that is not usually presented to 21 the Commission for approval in advance 22
23 73. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 24 A. The initial project was estimated at $1,500,000 (without AFUDC) and the 25 total project costs was $2,007,907 (without AFUDC). The increase above 26 the initial budget was due to the discoveries during the factory repairs. The 27 total plant addition was $1,468,520.
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1 C. HARRY ALLEN 2 1. HA1087 HA Elevator for Air-Cooled Condenser 3 74. Q. PLEASE DESCRIBE THE HARRY ALLEN ELEVATOR FOR AIR- 4 COOLED CONDENSER PROJECT. 5 A. The Harry Allen Elevator for the ACC Project encompasses the 6 installation of a freight elevator that travels from ground level to the 7 operational deck of the ACC. The Harry Allen ACC was originally 8 constructed with access to all elevations through a single set of stairs and
9 ladders, with the operational deck approximately 70 feet above the ground. 10 Utilizing the elevator instead of climbing stairs reduces the time required
11 for employees to mobilize to their work location, as well as eliminate
12 physical stress related to carrying tools and materials up several flights of
13 stairs to perform required operations and maintenance activities on 14 equipment located on the ACC operational deck. Operators are required to 15 inspect ACC equipment twice per shift. Additionally, the elevator will d/b/a Energy NV
16 Nevada Power Company Company Power Nevada also greatly enhance the safety of employees. As noted in discussion of 17 CL1099, medical emergencies have occurred at other generating facilities and SierraCompany Pacific Power 18 and transport of a patient from operational deck to the ground utilizing 19 stairs is difficult, adds time for the patient to receive the care they need 20 and also creates a safety concern for first responders. 21
22 75. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE 23 COMMISSION? 24 A. No, this is project was not presented to the Commission for pre-approval, 25 whether in an IRP or other application. 26 27
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1 76. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 2 B. The project was estimated at $999,342 (without AFUDC) and the total 3 project costs was $1,054,072 (without AFUDC). The actual cost of the 4 project was $1,089,878 including AFUDC at completion. 5
6 2. HA2024 HA3 Combustion System Capital Parts Replacement 7 77. Q. PLEASE DESCRIBE THE HARRY ALLEN UNIT 3 8 COMBUSTION SYSTEM PARTS PROJECT. 9 A. This project included a hot gas path inspection (“HGP”) and capital 10 replacement of HGP components for Harry Allen CT Unit 3. The unit had
11 exceeded the OEM recommended number of starts since the last overhaul
12 and the extended wear and degradation of the combustion parts has
13 resulted in the inability to maintain environmental compliance during 14 startups. 15 d/b/a Energy NV
16 Nevada Power Company Company Power Nevada In order to maintain reliability and be environmentally compliant, the 17 unit’s combustion system overhaul was prudent. The unit was and SierraCompany Pacific Power 18 disassembled, inspected, and reassembled with replacement parts as 19 necessary. The capital parts replacement included burner nozzles, 20 combustor baskets, turbine shroud, cross fire tubes, and associated 21 transition pieces. 22
23 78. Q. WERE THESE PROJECTS PREVIOUSLY APPROVED BY THE 24 COMMISSION? 25 A. No. This was a capital replacement of worn and damaged parts. This type 26 of project is not usually submitted to the Commission for approval in 27 advance.
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1 79. Q. WHAT WAS THE TOTAL COST OF THE PROJECTS? 2 A. The total project cost was $1,250,357 (excluding AFUDC) and was 3 estimated at $1,220,093 (excluding AFUDC). For HA2024, the total plant 4 addition was $1,243,614 including AFUDC. The equipment is in service 5 and used and useful. 6
7 D. LAS VEGAS GENERATING STATION 8 1. LC1039 LV1 Hot Gas Path Overhaul 9 80. Q. PLEASE DESCRIBE THE LAS VEGAS UNIT 1 HOT GAS PATH 10 PROJECT.
11 A. Las Vegas Generating Station Unit 1 Engine, serial number 185-160, had
12 exceeded the OEM recommended service hours and was due for an HGP
13 inspection. The work scope was based on the unit’s last routine borescope 14 inspection, on April 4, 2016, which showed (1) a loss of Thermal Barrier 15 Coating (“TBC”) and minor burns and discoloration in the combustors, (2) d/b/a Energy NV
16 Nevada Power Company Company Power Nevada a loss of TBC on the Stage 1 of the high-pressure turbine (“HPT”) 17 requiring blade replacement, and (3) Stage 2 HPT nozzle vanes outer and SierraCompany Pacific Power 18 platform being cracked or developing cracks on a number of vanes. 19 20 The project was necessary to ensure Unit 1 remains ready and available 21 for use to support native load. 22
23 81. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE 24 COMMISSION? 25 A. No. This project was the overhaul of an engine, which is capital 26 maintenance that is not usually presented to the Commission for approval 27 in advance.
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1 82. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 2 A. The project was estimated at $1,922,372 (without AFUDC) and the total 3 project costs was $1,420,875 (without AFUDC). The total plant addition 4 was $1,407,689 including AFUDC. All of the facilities installed are in 5 service and used and useful in the provision of utility service. 6
7 2. LC1040 LV2A Major Overhaul 8 83. Q. PLEASE DESCRIBE THE PROJECT. 9 A. Combustion turbine major inspection and repair requirements were 10 identified during the due diligence for the purchase of the Las Vegas
11 Generating Station. The LC1040 project was for a major overhaul of Unit
12 2A, serial number 191-324 per OEM recommendations.
13
14 84. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE 15 COMMISSION? d/b/a Energy NV
16 Nevada Power Company Company Power Nevada A. Yes, this project was completed prior to May 31, 2017, and approved by 17 the Commission in Docket No. 17-06003. However, following a project and SierraCompany Pacific Power 18 audit in late 2017, it was determined that the capital and maintenance 19 allocations of the project required adjustment. 20
21 85. Q. PLEASE DESCRIBE THE ADJUSTMENT. 22 A. The project was originally estimated and closed under a work scope in 23 which 40 percent of the work scope was allocated to capital expenses and 24 60 percent was allocated to maintenance expense. A project audit 25 determined that, due to changes in the work scope and project invoicing 26 details, the actual allocation to capital was 66 percent and the actual 27 allocation to maintenance was 34 percent.
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1 86. WHAT WAS THE TOTAL COST OF THE PROJECT? 2 A. The capital investment for the project included in rate base as a result of 3 the 2017 general rate case was a total plant addition of $2,146,070, 4 including AFUDC. The actual capital expense after reallocation was 5 $3,663,066, including AFUDC. This is an increase of $1,460,904 to be 6 added into rate base in this filing. 7
8 3. LC1041 LV3BA Major Overhaul 9 87. Q. PLEASE DESCRIBE THE PROJECT. 10 A. Based on Las Vegas Generating Station’s 3B engine (SN 185-163)
11 operating hours, in accordance to the manufactures (GE) recommended
12 maintenance cycle the unit required a major overhaul in 2017. Overhaul
13 of this engine provides a reliable unit to install when an operating engine 14 is found unserviceable. LM6000 engines are inspected (bore scoped) at 15 defined intervals and determined to be serviceable. An additional benefit d/b/a Energy NV
16 Nevada Power Company Company Power Nevada is an overhauled engine performance and heat rate normally will be 17 improved. An engine major overhaul will greatly reduce the odds a and SierraCompany Pacific Power 18 catastrophic failure or any other unplanned outage will occur. 19
20 88. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE 21 COMMISSION? 22 A. No. This project was a normal capital repair/replacement which is not 23 normally approved by the Commission in advance. 24 25 26 27
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1 89. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 2 A. The total project cost was $3,380,773, not including AFUDC. The total 3 plant in service was $3,403,326, including AFUDC. The engine is in 4 service and used and useful.
5
6 4. LC2033 & LC2034 PB 2 & PB 3 Underground Cooling Water Piping 7 90. Q. PLEASE DESCRIBE THE UNDERGROUND COOLING WATER 8 REHABILITATION PROJECTS. 9 A. Las Vegas Generating Station power blocks 2 and 3 utilize underground 10 circulating cooling water systems to provide a cooling medium to all major
11 equipment. The original construction only specified anti-corrosion coating
12 and wrapped carbon steel pipe, and did not include a cathodic protection
13 system. The underground piping was corroded to the point where leaks 14 could only be temporarily repaired by using band type patches as there 15 was not sufficient "good metal" available for permanent welded pipe d/b/a Energy NV
16 Nevada Power Company Company Power Nevada repair. Whenever a section of pipe failed, it required immediate action to 17 stop the leak, including shutting down the affected power block, in order and SierraCompany Pacific Power 18 to remain environmentally compliant. The pipe failures were increasing in 19 frequency as the plant aged. 20 21 The corrosion observed is localized, in areas where the original exterior 22 pipe coating and wrap had been compromised. Moreover, soil beneath Las 23 Vegas Generating Station has a high soluble salt content and a low 24 saturated soil resistivity making the soil very corrosive to carbon-steel 25 underground piping. The localized corrosion or pinpoint corrosion has 26 reduced pipe wall thickness by 66 percent on tested locations. 27
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1 These projects rehabilitated the existing below grade cooling water piping. 2 The project utilized carbon fiber liners to restore the structural integrity to 3 the underground piping system. This method was cost-effective, efficient, 4 and used a proven method to restore piping integrity. This repair 5 technology largely avoids the costly expense of digging, procuring and 6 replacing the hundreds of feet of large piping. Carbon fiber liners are 7 designed to take all the loads acting on the host pipe without reliance on 8 the host pipe for structural integrity. Additionally, the carbon fiber liners
9 are anti-corrosion and will not be subject to the same erosion issue the 10 original carbon steel piping experienced.
11
12 91. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE
13 COMMISSION? 14 A. No. This project is normal capital maintenance that is not normally 15 presented to the Commission for approval in advance. d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 17 and SierraCompany Pacific Power 92. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 18 A. The total plant addition for LC2033 was $1,311,124 including AFUDC. 19 The total project cost was estimated at $1,493,154 (excluding AFUDC). 20 For LC2034 the total plant addition was $1,412,286 (excluding AFUDC). 21 The total project cost was estimated at $1,436,154 (including AFUDC). 22
23 5. LC2064 PB2A Gas Turbine Repairs 24 93. Q. PLEASE DESCRIBE THE UNIT 2A GAS TURBINE REPAIR 25 PROJECT. 26 A. When the unit was installed after a turbine overhaul, it experienced a 27 compressor stall at baseload operations shortly after startup. The unit was
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1 borescoped and was found to have severe damage to the High Pressure 2 Compressor (“HPC”) blades and vanes, which is indicative of foreign 3 object ingestion. 4 5 The unit was removed and returned to the OEM for disassembly and 6 inspection. The OEM located a bolt inside the engine during disassembly 7 but could not verify the bolt’s origins. The Company hired a third party to 8 perform an independent Root Cause Analysis (“RCA”), which was also
9 inconclusive. 10 The Company put out a request for proposals (“RFP”) for repair of the unit
11 and a third party, ProEnergy Services LLC (“ProEnergy”), was selected.
12 The unit was shipped from the OEM facility in Houston, TX, to the
13 ProEnergy facility in Sedalia, MO, where the unit was overhauled. The 14 unit was returned to Las Vegas Generating Station and returned to service 15 without issue. d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 17 and SierraCompany Pacific Power 94. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE 18 COMMISSION? 19 A. No. This project was the capital repair of a combustion turbine that is not 20 normally presented to the Commission for approval in advance. 21
22 95. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 23 A. The total plant addition during the test period is $2,504,061, including 24 AFUDC. All of the facilities installed are in service and used and useful. 25 26 27
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1 6. LC2116 U1 Generator Stator Replacement 2 96. Q. PLEASE DESCRIBE THE UNIT 1 GENERATOR STATOR 3 PROJECT. 4 A. The Las Vegas Generating Station Unit 1 2018 outage work scope 5 included turbine generator in place inspection and electrical testing. Initial 6 results detected unfavorable results during stator electrical step voltage 7 testing and physical pole-to-pole crossover support blocking issues in the 8 rotor during visual inspection. In order to perform the necessary stator
9 repairs and further test and inspect the generator components, the rotor 10 was removed from the generator. Further visual inspection after rotor
11 removal indicated a significant amount of partial discharge activity on the
12 stator windings. The Company’s Subject Matter Expert (“SME”)
13 recommended performing a voltage step up test with all stator windings 14 shorted together. During this test, a higher than acceptable amount of 15 leakage current was measured. This leakage current indicates dry and d/b/a Energy NV
16 Nevada Power Company Company Power Nevada weakening insulation on the stator windings. Local partial discharge 17 activity was also noticed during the visual inspection of the stator. Higher and SierraCompany Pacific Power 18 partial discharge activity can lead to increase in eddy current losses and 19 localized overheating in the stator core which can in turn lead to localized 20 delamination of insulation and ultimately result in a generator failure while 21 in service. 22 23 The objective of the project was to repair the Unit 1 Combustion Turbine 24 Generator Stator due to the discovery of generator field shorts during the 25 inspection and testing. The repairs encompassed a rewind of Unit 1 26 Combustion Turbine Generator's stator in order to avoid catastrophic 27 failure of the unit and to maintain its reliability and availability.
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1 97. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE 2 COMMISSION? 3 A. No. This is normal capital maintenance that is not usually presented to the 4 Commission for approval in advance. 5
6 98. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 7 A. The project was estimated at $2,117,648 (without AFUDC) and the total 8 project costs was $2,081,280 (without AFUDC). The total plant addition
9 was $1,804,918 including AFUDC. All of the facilities installed are in 10 service and used and useful in the provision of utility service.
11
12 E. SILVERHAWK
13 1. SH1017 SCR Catalyst A Replacement 14 99. Q. PLEASE DESCRIBE THE SCR CATALYST PROJECT. 15 A. In 2004, Silverhawk Combustion Turbine A (“CTA”) was equipped with d/b/a Energy NV
16 Nevada Power Company Company Power Nevada a Selective Catalytic Reduction (“SCR”) equipment. The purpose of the 17 SCR is to reduce nitrogen oxide in the turbine exhaust gas for emissions and SierraCompany Pacific Power 18 compliance per environmental permit limits. 19 20 The Company has regularly had a testing company evaluate sections of the 21 SCR to estimate end of life. In March of 2017, the testing report indicated 22 that the SCR would be unable to satisfy operational emissions limits 23 beyond 2017. This project was executed to replace the SCR for CTA. 24 25 The scope of this project was the removal and replacement of the existing 26 catalyst material. 27
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1 100. Q. WAS THE PROJECT PREVIOUSLY APPROVED BY THE 2 COMMISSION? 3 A. No. This project is normal capital maintenance that is not normally 4 presented to the Commission for approval in advance. 5
6 101. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 7 A. The project was estimated at $1,300,000 (without AFUDC) and the total 8 project cost was $1,205,456 (without AFUDC). The total plant addition
9 was $1,154,321 including AFUDC. All of the facilities installed are in 10 service and used and useful in the provision of utility service.
11
12 2. SH2016 CT-A Exhaust System Replacement
13 102. Q. PLEASE DESCRIBE THE CT-A EXHAUST SYSTEM 14 REPLACEMENT PROJECT. 15 A. Silverhawk utilizes Siemens 501FD2 combustion turbines. Siemens has d/b/a Energy NV
16 Nevada Power Company Company Power Nevada documented exhaust system design flaws in the 501FD2 fleet through 17 multiple safety and technical alerts regarding issues with their exhaust and SierraCompany Pacific Power 18 system design. 19 20 The first major flaw was the exhaust cylinder. The exhaust cylinder is a 21 stationary section after the turbine blades that supports the turbine shaft 22 bearing assembly and protects it from hot exhaust gases as they flow into 23 the Heat Recovery Steam Generator (“HRSG”). Original 501FD2 exhaust 24 cylinders eventually develop severe cracks that result in hot exhaust gases 25 entering the bearing cavity during operation which causes the bearing to 26 overheat. Additionally, exhaust cylinder cracks can cause it to physically 27
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1 drop elevation resulting in misloading of the turbine bearing which can 2 cause vibration issues and result in inoperability. 3 4 The second flaw involved the turbine exhaust manifold. The exhaust 5 manifold is a stationary section of the exhaust duct that contains the 6 exhaust expansion joint and encloses the hot exhaust gasses exiting the 7 turbine as it flows into the HRSG. Exhaust gases overheat the exhaust 8 expansion joint causing it to crack. This results in exhaust gases leaking to
9 the outside of the exhaust system prior to entering the HRSG resulting in 10 extensive safety and environmental issues.
11
12 This project included the replacement of the turbine exhaust cylinder, the
13 turbine exhaust manifold, and the exhaust expansion joint on Silverhawk 14 CTA. The Company has previously replaced the exhaust systems on 15 Silverhawk CTB and Higgins CT2 in 2017 as preventive maintenance. d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 17 and SierraCompany Pacific Power 103. Q. WAS THE PROJECT PREVIOUSLY APPROVED BY THE 18 COMMISSION? 19 A. No. This project is normal capital maintenance that is not normally 20 presented to the Commission for approval in advance. 21
22 104. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 23 A. The total project was estimated at $4,000,000, without AFUDC and the 24 total project costs was $4,213,127. The total plant addition was 25 $4,113,127, including AFUDC. All of the facilities installed are in service 26 and used and useful in the provision of utility service. 27
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1 3. SH2035 SH “A” CT Rotor Replacement 2 105. Q. PLEASE DESCRIBE THE COMBUSTION TURBINE ROTOR 3 REPLACEMENT PROJECT. 4 A. Silverhawk CTA rotor and the compressor components reached their 5 design life of 100,000 hours and 3,600 starts. Per OEM guidelines, these 6 components required either replacement or major inspection and rebuild 7 by a qualified facility. Through the LTSA, the Company was able to 8 exchange the original CTA rotor for a rebuilt unit at a reduced cost. The
9 Company refurbished and replaced compressor blades as necessary. 10
11 106. Q. WAS THE PROJECT PREVIOUSLY APPROVED BY THE
12 COMMISSION?
13 A. No. This project is normal capital maintenance that is not normally 14 presented to the Commission for approval in advance. 15 d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 107. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 17 A. The total project cost was estimated at $5,000,369, excluding AFUDC and
and SierraCompany Pacific Power 18 the total project cost was $5,087,041, excluding AFUDC. The total plant 19 addition was $5,129,721 including AFUDC. All of the facilities installed 20 are in service and used and useful in the provision of utility service. 21
22 F. SUN PEAK 23 1. SK2004 Sun Peak Exciter Controls 24 108. Q. PLEASE DESCRIBE THE SUN PEAK EXCITER CONTROLS 25 PROJECT. 26 A. The existing generator excitation system was part of the original Sun Peak 27 combustion turbine control system and was obsolete and required
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1 replacement. Vendors no longer supported these systems. While some 2 third-party refurbished parts were available on a limited basis, quality and 3 reliability of options continues to degrade. These third-party parts are 4 salvaged from various projects, and availability and reliability of these 5 parts are dubious. Additionally, the exciter’s Automatic Voltage Regulator 6 (“AVR”) controls in place did not have Power System Stabilization 7 (“PSS”), which is used to support grid stability and is installed on all other 8 generation units in the NV Energy fleet. Thus, the Company determined
9 the most viable option was to replace all excitation equipment and 10 protective relays connecting to this equipment, with new vendor supported
11 static excitation system that included PSS technology.
12
13 109. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE 14 COMMISSION? 15 A. No, this project was a typical plant capital investment that is not normally d/b/a Energy NV
16 Nevada Power Company Company Power Nevada presented to the Commission for approval in advance. However, this 17 project was identified during the due diligence associated with the and SierraCompany Pacific Power 18 purchase of Sun Peak and the due diligence report was presented to and 19 reviewed by the Commission in Docket No. 14-05003. The Commission 20 specifically found that Nevada Power had performed a reasonable due 21 diligence review of the Sun Peak resource.6
22
23 110. Q. WHAT WERE THE COSTS OF THE PROJECT? 24 A. The total project cost was estimated at $1,563,636, excluding AFUDC and 25 the total project cost was $1,700,878, excluding AFUDC. The total plant 26
27 6 Docket No. 14-05003, Modified Final Order dated December 18, 2014, at Paragraph 169. 28 Rekowski-DIRECT 56
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1 addition was $1,706,289 including AFUDC. All of the facilities installed 2 are in service and used and useful in the provision of utility service. 3
4 G. HIGGINS 5 1. WH2109 Steam Turbine Transformer Replacement 6 111. Q. PLEASE DESCRIBE THE STEAM TURBINE TRANSFORMER 7 REPLACEMENT PROJECT. 8 A. On June 20, 2018, the Steam Turbine Generator Step-up (“GSU”) 9 transformer was removed from service due to high combustible gas levels 10 within the GSU oil. A high level of Acetylene gas was detected by a plant
11 employee locally reviewing the GSU oil using the online Dissolved Gas
12 Analysis (“DGA”) equipment installed on the transformer. Several
13 internal and external SMEs reviewed the DGA data and all parties agreed 14 that the gas levels warranted the transformer being removed from service. 15 The Higgins Steam Turbine was taken offline to isolate the GSU, diagnose d/b/a Energy NV
16 Nevada Power Company Company Power Nevada the issue, and ultimately replace the unit. 17 Review of historical data showed that the gassing was elevated and began and SierraCompany Pacific Power 18 to increase in April 2018 and a step change occurred on June 16, 2018. 19 After the GSU was removed from service, additional oil samples were 20 taken from the transformer and sent for third-party laboratory analysis. 21 The laboratory DGA results validated the online readings showing 22 elevated combustible gases in the transformer oil. Next, the transformer 23 and bushing were electrically tested for faults that would cause off gassing 24 in the transformer oil. Electrical testing ultimately detected a higher than 25 normal resistance in the high voltage H1 windings of the transformer. 26 Internal visual inspection of the GSU did not reveal any major findings in 27 the high voltage area and would require destructive inspection and testing
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1 to pinpoint exact fault details. A Key Decision Report (“KDR”) was 2 completed to analyze how to minimize risk of complete transformer failure 3 and financial impact. The KDR concluded procurement of a replacement 4 transformer and installation, a five-week endeavor, would minimize 5 outage duration and replacement energy costs. The Steam Turbine GSU 6 replacement effort was effectively performed in 34 calendar days. 7
8 112. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE 9 COMMISSION? 10 A. No. This work is normal capital maintenance that is not usually presented
11 to the Commission for approval in advance.
12
13 113. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 14 A. The project was estimated at $5,998,017 (without AFUDC) and the total 15 project costs was $5,391,303 (without AFUDC). The total plant addition d/b/a Energy NV
16 Nevada Power Company Company Power Nevada was $5,291,306, including AFUDC. All of the facilities installed are in 17 service and used and useful in the provision of utility service. and SierraCompany Pacific Power 18
19 2. WH2110 Underground Fuel Gas Line Replacement 20 114. Q. PLEASE DESCRIBE THE UNDERGROUND FUEL GAS LINE 21 REPLACEMENT PROJECT. 22 A. On October 4, 2018, plant personnel identified a gaseous odor within the 23 Administrative Building. By utilizing various monitoring and detection 24 devices it was determined the issue stemmed from an underground fuel 25 gas leak coming from the CT2 underground branch line. The CT2 26 underground fuel gas line is routed immediately adjacent to the 27
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1 Administrative Building. The plant entered a forced outage on October 8, 2 2018. 3 4 Instruments detected multiple locations where the underground pipe had 5 leaked and allowed pressurized fuel gas to egress into the soil and migrate 6 into the adjacent Administrative Building. Excavation of the pipeline 7 revealed failures and leaks in multiple locations. Several of the 8 deficiencies identified were attributed to either original construction
9 installation practices, the effects of long-term corrosion, or coating surface 10 failures. The original underground fuel gas pipe was constructed from
11 carbon steel piping that was coated/wrapped, but not protected by a
12 cathodic protection system.
13 14 The underground fuel gas piping was replaced between October 8, 2018, 15 and November 20, 2018, on an expedited schedule. The installation d/b/a Energy NV
16 Nevada Power Company Company Power Nevada required extensive excavation, backfilling, compaction, resurfacing, pipe 17 replacement, welding, X-ray testing of all welds, internal pipe cleaning, and SierraCompany Pacific Power 18 and pressure testing in order to return the station to a safe and reliable 19 operating condition. Cathodic protection was installed under project 20 WH2102. 21
22 115. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE 23 COMMISSION? 24 A. No. This is capital maintenance that is not usually presented to the 25 Commission for approval in advance. 26 27
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1 116. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 2 A. The project was estimated at $3,910,291 (without AFUDC) and the total 3 project costs was $3,703,436 (without AFUDC). The total plant addition 4 was $1,707,347, including AFUDC. The difference between the total 5 project cost and the plant addition was the cost of removal of the old 6 piping. All of the facilities installed are in service and used and useful in 7 the provision of utility service. 8
9 H. OTHER GENERATION PROJECTS 10 1. SP5033 Gen OT Security Center South
11 117. Q. PLEASE DESCRIBE THE OPERATIONAL TECHNOLOGY
12 (“OT”) SECURITY CENTER SOUTH PROJECT.
13 A. Nevada Power invested $1,366,631 for OT security improvements to 14 eliminate or lessen risks or weaknesses associated with industrial control 15 systems (“ICS”) at our generating locations. d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 17 Early in 2017, the Generation OT Group was asked to investigate the and SierraCompany Pacific Power 18 differences in the current ICS cyber security policies, practices and 19 systems as compared to the Top 20 Cyber Security Controls (“CSC”) 20 guideline released by the SANS Institute. The OT Group was tasked to 21 compare current practices with that standard, identify the gaps between 22 current practices and the standard, and then map the processes to move 23 from the current model of protection to a version of the Top 20 CSC. 24 An outside engineering resource was engaged to perform that analysis and 25 to help outline a three-year plan to move to compliance with the Top 20 26 CSC guidance. This was a multi‐million dollar plan to increase the cyber 27 security profile of each ICS network in every plant in the Companies’ fleet.
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1 In August of 2017, that plan was accepted and the OT Group was 2 instructed to complete all of the tasks in the three year plan by year’s end 3 2017. 4 5 Because of the immense size of the undertaking, and the shortened 6 timeline required, several outside engineering resources were engaged. 7 These resources included an engineering firm that could assist with the 8 many and varied system integrations and provide the technical resources
9 required to supply sufficient numbers of boots on the ground for physical 10 installations and commissioning.
11
12 The end goal of this initial deployment was to have a working Security
13 Center in every major ICS network in the fleet. That security center was 14 to be capable of performing all of the most notable functions of cyber 15 security as outlined in the Top 20 CSC Guideline. The key functions d/b/a Energy NV
16 Nevada Power Company Company Power Nevada initially deployed included system logging and log forwarding, application 17 whitelisting, rogue system detection, anti‐virus protection, and malware and SierraCompany Pacific Power 18 avoidance. 19 20 A very aggressive schedule of site preparation, infrastructure installation, 21 materials acquisition, materials distribution, equipment installation, 22 configuration, and commissioning activities was set in place for effective 23 completion. That schedule also now employed multiple contracting firms 24 to assist with preparation, infrastructure buildout and installation 25 activities. The project was completed mid December 2017 at every plant 26 in the fleet without a single major deviation in the outlined work plan. 27
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1 118. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 2 A. The project was estimated at $842,592 (without AFUDC) and the total 3 project cost was $1,352,745 (without AFUDC). The actual project cost 4 were higher than estimated due to the need to use outside engineering 5 services, which was not in the original plan. The total plant addition was 6 $856,478 including AFUDC. All of the facilities installed are in service 7 and used and useful. 8
9 SECTION V: LONG-TERM MAINTENANCE OR SERVICE AGREEMENTS 10 119. Q. PLEASE DESCRIBE THE LTSA OUTAGE CAPITAL COSTS.
11 A. The LTSAs were established to assure reliability of the large combined
12 cycle turbines and generators while levelizing maintenance expenses over
13 the term of the agreements. 14 15 The LTSAs provide for full inspection, replace and repair coverage of the d/b/a Energy NV
16 Nevada Power Company Company Power Nevada combustion turbines and inspections only for the compressors, generators 17 and steam turbines. Needed repairs to the compressors, generators and and SierraCompany Pacific Power 18 steam turbines are not covered in the LTSA hourly fee and are considered 19 extra work. 20 21 The LTSAs are multi-year agreements covering the Chuck Lenzie, Tracy, 22 Harry Allen, Silverhawk and Higgins F-class combined cycle units. These 23 agreements have been discussed in rate cases for both Companies, 24 specifically for Sierra in Docket Nos. 10-06001, 13-06002, and 16-06006, 25 and for Nevada Power in Dockets Nos. 11-06006 and 14-05004. All 26 quarterly, annual and milestone costs associated with LTSAs are allocated 27 between O&M expense and prepaid capital according to a contract-
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1 specific predetermined allocation. Journal entries are posted for each 2 outage to transfer the prepaid capital to construction work in 3 progress/plant in service based on a historical capital ratio (by outage type) 4 and overall prepaid capital expected for the agreements. 5
6 120. Q. WERE THE LTSAS AND SUBSEQUENT OUTAGE PROJECTS 7 PREVIOUSLY APPROVED BY THE COMMISSION? 8 A. Yes. The LTSA costs and accounting methodologies for these LTSA have
9 been reviewed and approved by the Commission in the above noted 10 dockets. There have been no changes to the current LTSAs or accounting
11 since the Commission orders in Docket Nos. 14-05004 and 16-06006.
12
13 121. Q. WHAT ARE THE COSTS OF THE LTSA OUTAGE PROJECTS? 14 A. Table Rekowski-Direct-4 below presents the total cost of the LTSA outage 15 projects for the period through the end of the test year, estimates through d/b/a Energy NV
16 Nevada Power Company Company Power Nevada the end of the certification period and costs for the ECIC period.
17 and SierraCompany Pacific Power 18 Table Rekowski-Direct-4 19 LTSA Outage Capital through the end of the Test Period Budget ID Plant Outage Type Plant in Service 20 HA2019 Harry Allen Major CT Inspections (2)/Minor ST Inspection $15,153,487 SH1080 Silverhawk CT Hot Gas Path Inspection $1,645,461 21 SH1081 Silverhawk CT Major Inspection $7,664,461 22 LTSA Outage Capital through the Expected Change in Circumstances period 23 Budget ID Plant Outage Type Plant in Service CL1104 Lenzie Major CT Inspections (2)/Minor ST Inspection $12,792,239 24 WH1059 Higgins Major Inspection 2 CTs $13,878,281 25
26 27
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1 122. Q. WHY SHOULD THE LTSA CAPITAL OUTAGES BE 2 CONSIDERED FOR ECIC? 3 A. The projects listed in the Expected Change in Circumstances period were 4 planned to be completed in the spring of 2020. However, due to the 5 COVID-19 pandemic, the projects have been delayed until the fall of 2020 6 since they require a large number or workers in a small confined area. The 7 projects are essential to maintain the reliability of the generating unit and 8 further delay of the project increases the risk of catastrophic failure.
9
10 123. Q. NRS 704.110(4) STATES THAT AN ITEM INCLUDED IN THE
11 ECIC PERIOD MUST BE “REASONABLY KNOWN AND
12 MEASUREABLE WITH REASONABLE ACCURACY.” ARE THE
13 EXPECTED COSTS OF THE LTSA OUTAGE CAPITAL 14 “REASONABLY KNOWN AND MEASURABLE WITH 15 REASONABLE ACCURACY” AS OF THE DATE YOUR d/b/a Energy NV
16 Nevada Power Company Company Power Nevada TESTIMONY IS BEING PREPARED? 17 A. The LTSA outages were planned to be completed in the spring of 2020.
and SierraCompany Pacific Power 18 Contracts were bid and executed to complete the work and the prepaid 19 capital expensed for the LTSA scope is well known. 20
21 124. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 22 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 23 AND MEASURABLE WITH REASONABLE ACCURACY IF, 24 AMONG OTHER THINGS, IT CONSISTS OF SPECIFIC AND 25 IDENTIFIABLE EVENTS OR PROGRAMS RATHER THAN 26 GENERAL TRENDS, PATTERNS OR DEVELOPMENTS. DOES 27 THE LTSA OUTAGE CAPITAL MEET THAT CRITERION?
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1 A. Yes. The project scopes are defined in the LTSA and include the purchase 2 and installation of equipment based on contract purchase orders and 3 detailed delivery schedules and cannot be characterized as a general trend, 4 pattern or development. 5
6 125. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 7 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 8 AND MEASURABLE WITH REASONABLE ACCURACY IF, 9 AMONG OTHER THINGS, IT HAS AN OBJECTIVELY HIGH 10 PROBABILITY OF OCCURRING TO THE DEGREE, IN THE
11 AMOUNT AND AT THE TIME EXPECTED. DOES THE LTSA
12 OUTAGE CAPITAL MEET THAT CRITERION?
13 A. Yes. Revised production and installation schedules provided by all 14 vendors demonstrate completion of the installation during the fall 2020 15 outage that will begin on October 3, 2020 and will end on November 11, d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 2020 for Lenzie Block 2 and will begin on October 1, 2020 and will end 17 on December 5, 2020 for the Higgins units. and SierraCompany Pacific Power
18
19 126. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 20 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 21 AND MEASURABLE WITH REASONABLE ACCURACY IF, 22 AMONG OTHER THINGS, IT IS PRIMARILY MEASUREABLE 23 BY RECORDED OR VERIFIABLE REVENUES AND EXPENSES 24 AND IS EASILY AND OBJECTIVELY CALCULATED, WITH 25 THE CALCULATION OF THE EXPECTED CHANGES RELYING 26 ONLY SECONDARILY ON ESTIMATES, FORECASTS, 27
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1 PROJECTIONS OR BUDGETS. DOES LTSA CAPITAL MEET 2 THAT CRITERION? 3 A. Yes. All of the project costs related to scope of the LTSA outages are 4 currently verifiable and recorded in the contracts and purchase orders, as 5 set forth above. 6
7 127. Q. PLEASE SUMMARIZE WHY THE LTSA CAPITAL MEETS THE 8 CRITERIA SPECIFIED IN NRS 704.110(4) AS AN EXPECTED 9 CHANGE THAT IS REASONABLY KNOWN AND 10 MEASURABLE WITH REASONABLE ACCURACY.
11 A. The LTSA capital constitutes specific and identifiable events, these events
12 have an objectively high probability of occurring to the degree, in the
13 amount and at the time expected, and their costs are currently measurable 14 by recorded and verifiable expenses that are easily and objectively 15 calculated. d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 17 and SierraCompany Pacific Power 128. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHOULD 18 CONSIDER “REASONABLE PROJECTED OR FORECASTED 19 OFFSETS IN REVENUE AND EXPENSES THAT ARE DIRECTLY
20 ATTRIBUTABLE TO OR ASSOCIATED WITH THE EXPECTED 21 CHANGES IN CIRCUMSTANCES UNDER CONSIDERATION.” 22 ARE THERE ANY OFFSETS ASSOCIATED WITH THE LTSA 23 OUTAGE CAPITAL? 24 A. The Company has not identified any reasonable projected or forecasted 25 offsets in revenues or expenses that are directly attributable to or 26 associated with these expected changes in circumstances. 27
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1 SECTION VI: GENERATION INVESTMENT BETWEEN JANUARY 1, 2020, 2 AND MAY 31, 2020.
3 A. CERTIFICATION -C HUCK LENZIE 4 1. CL2024 Spare GSU Transformer Purchase 5 129. Q. PLEASE DESCRIBE THE PROJECT. 6 A. The scope of this project is to procure a new spare GSU that has the 7 capability of connecting to multiple different units at various generation 8 facilities within the Company’s system. The GSU is primarily specified
9 for use with all Chuck Lenzie Units but it is also compatible with all 10 Silverhawk Units, and Harry Allen Units 5, 6, and 7. In the event of a GSU
11 failure at one of the compatible facilities, this unit can be deployed
12 expeditiously, greatly reducing the risk of an extended outage.
13
14 130. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 15 A. The initial estimated plant addition for the project was $3,133,456, d/b/a Energy NV
16 Nevada Power Company Company Power Nevada including AFUDC. Updated estimates were available after the schedules 17 were completed and, at the time, the current estimate for this project was and SierraCompany Pacific Power 18 $3,366,693 with AFUDC. This information will be updated in the 19 Certification filing in this Docket. 20
21 2. CL2067 PB1 Ammonia Heaters, Replace Project 22 131. Q. PLEASE DESCRIBE THE LENZIE POWER BLOCK 1 AMMONIA 23 HEATERS REPLACE PROJECT. 24 A. Aqueous ammonia vaporization systems are required to keep combustion 25 emissions (Nitrogen Oxides) below levels set forth by the Nevada Division 26 of Environmental Protection and U.S. Environmental Protection Agency 27 (“EPA”).
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1 Each HRSG has a set of two heaters for vaporizing aqueous ammonia. One 2 heater operates as the primary, which will typically run until a problem 3 occurs. The other heater is for backup. In the event the primary heater fails, 4 the backup will enter into service. If no heaters are available the unit must 5 be shut down to avoid a Title V Air Permit violation. 6 7 The control system, consisting of a 480 VAC feed, a circuit breaker and a 8 silicon controlled rectifier, was identified as a high risk single point failure.
9 Failure of the control system will render both heaters unavailable resulting 10 in a forced outage. Addition of separate control systems for each heater
11 eliminates a significant single point failure reducing the risk of a forced
12 outage as well as enabling maintenance of the system while the unit is
13 online. 14 15 Over time, heating elements fail through normal use. Due to these failures, d/b/a Energy NV
16 Nevada Power Company Company Power Nevada the facility is currently operating several units with only a single heater 17 and no backup. Replacement of the backup heaters is necessary to and SierraCompany Pacific Power 18 eliminate a single point of failure and avoid a forced outage should the 19 primary heater fail. 20 21 This project will replace failed heaters and install a new control system on 22 each unit in Power Block 1. A similar project for Power Block 2 (CL2074) 23 was also planned to be completed during the certification period, but the 24 outage was delayed due to the COVID-19 pandemic. CL2074 is described 25 in Section VI below. 26 27
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1 132. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 2 A. The original estimate for the project did not include redundant control 3 systems and was $124,705 per heater, without AFUDC. After the bid 4 process the estimate (not including redundant control systems) was 5 increased to $251,033 per heater (4 total). At the time the initial estimates 6 were competed for this filing, this project (heaters and redundant control 7 systems) is estimated with a total cost of $508,732, without AFUDC. 8 Updated estimates were available after the schedules were completed and
9 at time the current estimate for this project is $930,713, including AFUDC. 10 This will be corrected in the Certification filing in this Docket.
11
12 3. CL2068 & CL2069 PB Chiller Cooling Towers Replacement
13 133. Q. PLEASE DESCRIBE THE CHILLER COOLING TOWER 14 PROJECT. 15 A. The scope of this project is to replace the existing Power Block 1 and d/b/a Energy NV
16 Nevada Power Company Company Power Nevada Power Block 2 Chiller Cooling Tower modules with in-kind units. An 17 inspection completed by a third party documented physical deterioration and SierraCompany Pacific Power 18 of the cooling tower and its components. The identified issues in the report 19 include: the overall structural integrity of both towers is compromised, 20 presenting safety hazard to plant personnel; the hot water distribution 21 system is in poor condition; the riser pipes are rusted and brittle with a 22 high chance of failure that could result in an environmental spill; the air 23 inlet louvers are in poor condition which will continually impede cooling 24 tower performance; all drift eliminators have failed and are extremely 25 brittle; and 100 percent of the evaporation media has failed and is falling 26 apart. Associated work also includes replacing failed piping systems, 27 installing new electrical service and commissioning the new installation.
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1 134. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 2 A. The estimated plant addition for CL2068 is $6,124,476. The estimated 3 plant addition for CL2069 for Power Block 2 is $6,157,773. 4
5 4. CL257 & CL259 PB1 & PB2 Mod 3 Re-tube Chiller Condensers, 6 Replace
7 135. Q. PLEASE DESCRIBE THE LENZIE POWER BLOCK 1 MODULE 8 3 CHILLER RETUBE PROJECT. 9 A. The scope of this project is to procure and replace the condenser tubes on 10 Chiller Module 3 for both Power Block 1 and Power Block 2. Each Power
11 Block has three Chiller Modules that supply chilled water to the
12 combustion turbine inlets to cool the incoming air. Gas turbine maximum
13 power output is inversely proportional to inlet air temperature. As the 14 ambient air temperature rises, power output reduces during the most 15 critical, highest demand times. The purpose of the chiller system is to cool d/b/a Energy NV
16 Nevada Power Company Company Power Nevada the gas turbine inlet air during warm weather, thereby allowing the gas 17 turbine and its corresponding steam turbine to produce more electrical and SierraCompany Pacific Power 18 power. 19 20 The Chiller Modules use a vapor compression cycle to chill water. In that 21 process, heat is transferred from the chilled water to the refrigerant used 22 in the vapor compression cycle. The system uses chiller condensers to 23 remove the heat from the refrigerant and transfer it to the circulation water, 24 condensing the refrigerant in the process. The chiller condensers have 25 experienced tube failures which require plugging of the failed tubes. To 26 plug a condenser tube, the condenser water side must be drained, 27 refrigerant must be evacuated from the system, and the compressor must
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1 de-watered and dried out. Then, the leaking tubes can be identified and 2 plugged. Finally the fluid evacuations can be reversed and the system can 3 be restored. This entire process takes up to a month to repair a failed 4 condenser tube, when one fails. Module 3 chiller condenser tube bundles 5 on both Power Blocks had reached the maximum number of tubes that can 6 be plugged per design, resulting in reduced performance. This project 7 replaced each Module 3 chiller condenser tube bundle and restore the 8 condenser to its original performance specifications.
9
10 136. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT?
11 A. The estimated cost for project CL257 is $1,014,529. The estimated cost
12 for project CL259 is $1,033.251.
13
14 B. CERTIFICATION – CLARK 15 1. CS2025, CS2026, CS2032 & CS2033 -Clark Peaker Power Turbine d/b/a Energy NV
16 Nevada Power Company Company Power Nevada OEM Upgrade/Overhaul 17 and SierraCompany Pacific Power 137. Q. PLEASE DESCRIBE THE CLARK POWER TURBINE OEM 18 UPGRADE AND OVERHAUL PROJECTS: CS2025, CS2026, 19 CS2032, AND CS2033. 20 A. As discussed in Q&A 42, the scope of these projects is to repair and 21 upgrade Clark Generating Station PWPS FT8-3 Swiftpac Units’ PTs for 22 continued service and availability. The benefits of repairing and upgrading 23 all of the PWPS PTs include: reduced risk of failure, reduced risk of 24 exposure to costly repairs/replacements, reduced risk of long periods of 25 downtime/unit unavailability. 26 27
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1 138. Q. WHAT IS THE EXPECTED COST OF THESE PROJECTS? 2 A. The expected plant addition for the 4 projects, including AFUDC, is 3 $4,204,161. Two of these projects (CS2027 and CS2034) were originally 4 listed as a certification period projects. This will be corrected in the 5 Certification filing in this Docket 6
7 2. CS2078, CS2079 & CS2081 - Clark Peaker Turbine Exhaust Case 8 Upgrade
9 139. Q. PLEASE DESCRIBE THE CLARK PEAKER TURBINE EXHAUST 10 CASE UPGRADE PROJECTS: CS2078 AND CS2081.
11 A. As discussed in Q&A 45, the scope of these projects is to repair and
12 upgrade all Clark FT8-3 peaking units’ TECs for continued service and
13 availability. 14
15 140. Q. WHAT IS THE EXPECTED COST OF THESE PROJECTS? d/b/a Energy NV
16 Nevada Power Company Company Power Nevada A. The expected plant addition for these three projects, including AFUDC, is 17 $883,714. and SierraCompany Pacific Power 18
19 3. CS2121 Spare GSU 20 141. Q. PLEASE DESCRIBE THIS PROJECT. 21 A. The scope of this project is to procure a new spare GSU that has the 22 capability of connecting to multiple different grid voltages at various 23 generation facilities within the Company’s system. The GSU is primarily 24 specified for use with Clark Units 5 through 10 and all Sun Peak units, but 25 it is also compatible with multiple units that serve the Sierra service 26 territory. In the event of a GSU failure at one of the compatible facilities, 27
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1 this unit can be deployed expeditiously, greatly reducing the risk of an 2 extended outage. 3
4 142. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 5 A. The estimated plant addition for this project is $1,933,417 including 6 AFUDC. 7
8 4. CS2156 C Pond Liner Replacement 9 143. Q. PLEASE DESCRIBE THE C POND LINER REPLACEMENT 10 PROJECT.
11 A. Clark Generation Station is a zero-discharge facility and utilizes five High
12 Density Polyethylene (“HDPE”) lined retention ponds to evaporate waste
13 water generated by the plant. The HDPE material has been in service for 14 40 years and has reached the point where patching tears in the liner was 15 no longer sustainable. It is prudent to install a new liner system that meets d/b/a Energy NV
16 Nevada Power Company Company Power Nevada current regulatory requirements. 17 and SierraCompany Pacific Power
18 144. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 19 A. The initial estimated plant addition was $1,218,738 including AFUDC. 20 Updated estimates were available after the schedules were completed and, 21 at the time, the current estimate for this project was $1,766,897. This 22 information will be updated in the Certification filing in this Docket. 23
24 5. CS2255 Demin Tank Failure Project 25 145. Q. PLEASE DESCRIBE THE DEMIN TANK FAILURE PROJECT. 26 A. Clark Generating Station’s Peaking Units Project, which was completed 27 in 2007/2008, included a Demineralized (Demin) Water System to supply
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1 clean (salt and mineral free) water to the 24 PWPS FT8 Engines. This 2 Demin water is used on the Water Injection System and Inlet Misting 3 System. 4 5 On April 7, 2020, the Demin Tank was found to be leaking demineralized 6 water. Investigations revealed that the tank’s bottom plate had extensive 7 corrosion requiring a complete floor replacement. 8
9 This project restored the tank to its operating state and supplemented the 10 re-lining to maintain the reliability and safety of plant operation, while
11 eliminating any environmental risks associated with demineralized water
12 leaks.
13
14 146. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 15 A. The estimated plant addition is $1,596,113 including AFUDC. Since this d/b/a Energy NV
16 Nevada Power Company Company Power Nevada was an emergent project, estimates were not available when the schedules 17 were completed. This information will be updated in the Certification and SierraCompany Pacific Power 18 filing in this Docket. 19
20 C. CERTIFICATION – HARRY ALLEN 21 1. HA1103 WSAC Fluid Cooler Replacement 22 147. Q. PLEASE DESCRIBE THE WSAC FLUID COOLER 23 REPLACEMENT PROJECT. 24 A. The Harry Allen Combined Cycle Wet Surface Air Cooler (“WSAC”) 25 provides additional cooling for a number of plant systems during the hot 26 summer months when the closed cooling water system cannot meet the 27 required cooling demands. The WSAC commissioned with the plant is a
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1 modular design that does not homogenously mix cooling water and 2 treatment chemicals. As a result, the WSAC has suffered from a corrosive 3 environment, resulting in corroded walls and brittle drift eliminators as 4 well as fouling of nozzles and poor performance. The new WSAC will 5 consist of a single, larger basin, which will eliminate chemistry issues. 6
7 148. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 8 A. The estimated plant addition for this project is $3,536,676 including
9 AFUDC. 10
11 2. HA2052 Emerson DCS Controllers and Servers Replacement
12 149. Q. PLEASE DESCRIBE THE DCS REPLACEMENT PROJECT.
13 A. The Harry Allen Distributed Control System (“DCS”) project will upgrade 14 and replace the original DCS system controllers, servers, and operator 15 consoles with current generation technology. The existing equipment has d/b/a Energy NV
16 Nevada Power Company Company Power Nevada exceeded their useful lives and are no longer supported nor include the 17 cyber security features that are required by the industry. Both Emerson and SierraCompany Pacific Power 18 Process Management and Microsoft have announced they will no longer 19 support the hardware and software currently used. The project will replace 20 controllers, servers and upgrade the control room facilities for Human 21 Performance Improvement (“HPI”) considerations, with items such as 22 updated screen monitors, workstation computers, keyboards, and pointing 23 devices. 24
25 150. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 26 A. The estimated plant addition for this project is $1,519,577 including 27 AFUDC.
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1 3. HA2054 Harry Allen Unit 3 Generator Stator Rewind 2 151. Q. PLEASE DESCRIBE THE UNIT 3 GENERATOR STATOR 3 REWIND PROJECT. 4 A. This project is to rewind the Harry Allen Unit 3 generator stator and field. 5 The Company has worked with a third party to perform Partial Discharge 6 testing on a regular basis to monitor the generator for several years. In 7 August 2019, Partial Discharge results indicated “Very High” reading for 8 zero crossing, interphasal, and classic Partial Discharge, indicating weak
9 inner and outer layers of insulation around the copper conductor in the 10 generator stator. Continued operation of the unit would have resulted in
11 failure of the unit while in operation in the next couple years. This project
12 reduces the risk of the unit becoming unavailable to service native load
13 during peak periods. 14
15 152. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? d/b/a Energy NV
16 Nevada Power Company Company Power Nevada A. The expected plant addition for this project is $4,270,563 including 17 AFUDC. and SierraCompany Pacific Power 18
19 D. CERTIFICATION – SILVERHAWK 20 1. SH2074 Emergency Diesel Generator Installation 21 153. Q. PLEASE DESCRIBE THE EMERGENCY DIESEL GENERATOR 22 INSTALLATION PROJECT. 23 A. This project is to procure and install a standby emergency diesel generator 24 at Silverhawk Station. It is common industry practice for a generating 25 station to be equipped with a battery powered Uninterruptable Power 26 Supply (“UPS”) system to provide energy to critical equipment for four to 27 eight hours, and a standby diesel generator to provide energy to emergency
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1 equipment for extended duration. The critical equipment includes turbine 2 controls, turning gear motors, air compressors and lubricating oil pumps. 3 Silverhawk is equipped with a UPS system but not a diesel generator. This 4 is a plant design deficiency. 5 6 When a shutdown occurs, controlled or uncontrolled, this critical 7 equipment continues to operate until the plant is safely de-energized, 8 meaning all heat and pressure has been removed from the process and
9 equipment. Specifically, the lubricating oil pumps continue to provide oil 10 circulation to turbine bearings and the turning gear equipment
11 continuously rotate turbines to prevent differential cooling. Failure to
12 maintain these systems until a turbine is cool will lead to severe bearing
13 damage, shaft deformation and blade damage, all resulting in multi-million 14 dollar emergency repairs and outages. 15 d/b/a Energy NV
16 Nevada Power Company Company Power Nevada Silverhawk Station currently relies on the grid connection to provide 17 auxiliary power when the generators are offline. The plant experienced a and SierraCompany Pacific Power 18 black plant scenario in March of 2017 when the transmission line was 19 tripped due to external forces. Plant operators were able to stabilize plant 20 equipment temporarily using the UPS system until a rented diesel 21 generator was able to securely provide emergency power indefinitely 22 while the transmission line was inspected and restored.
23
24 154. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 25 A. The estimated plant addition for this project is $1,880,037 including
26 AFUDC. 27
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1 2. SH2112 & SH2128 Pond A & Pond B Liner Replacement 2 155. Q. PLEASE DESCRIBE THE POND A LINER REPLACEMENT 3 PROJECT. 4 A. Silverhawk is a zero-discharge facility and utilizes retention ponds to 5 evaporate waste water generated by the plant. The existing pond liners are 6 exhibiting delamination in several areas indicating material failure. This 7 represents a potential environmental permit violation associated with pond 8 water leakage. It was prudent to install new liners and remove risk
9 associated with environmental compliance. 10
11 156. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT?
12 A. The estimated plant addition for SH2112 is $1,284,782 including AFUDC.
13 The initial estimated plant addition for SH2128 was $945,866 including 14 AFUDC. Updated estimates were available after the schedules were 15 completed and, at the time, the current estimate for project SH2128 was d/b/a Energy NV
16 Nevada Power Company Company Power Nevada $1,281,900. This information will be updated in the Certification filing in 17 this Docket. and SierraCompany Pacific Power 18
19 E. CERTIFICATION –HIGGINS PROJECTS 20 1. WH2020 RO Skid and Demin Project 21 157. Q. PLEASE DESCRIBE THE RO SKID AND DEMIN PROJECT. 22 A. This project was to replace and upgrade the Higgins Station water 23 treatment equipment by replacing the original Reverse Osmosis (“RO”) 24 and upgrading Demineralization Water (“DW”) equipment. The station 25 requires an additional RO skid and several of its DW system components 26 replaced in order to provide the water volumes needed to meet the current 27 water balance requirements during its peak summer operating months.
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1 For the past several years, the station has been required to rent RO skids 2 to supplement the existing ones in order to produce the water volume 3 required to operate. In addition, the Demineralizer Forwarding Pump's 4 flow rate is being restricted by various components that are undersized and 5 restricting the system's capacity in providing water to the CT evaporative 6 coolers and the DW Storage Tank for system make up. The station's 7 original water balance design used a mixture of service water and 8 demineralized water for the CT's evaporative coolers. The plant has made
9 the operational decision to only use demineralized water for the 10 evaporative coolers to extend evaporative media life and to prevent the
11 coating of the turbine compressor blades from particulate carry over.
12
13 Advancements in RO and DW technology also allow the plant to select 14 new equipment that can meet the increased water demand while 15 significantly reducing handling of hazardous chemicals by plant d/b/a Energy NV
16 Nevada Power Company Company Power Nevada personnel. The original water treatment equipment utilizes numerous 17 hazardous chemicals in the water treatment process, including caustics and and SierraCompany Pacific Power 18 acids. As the station evolved in its operation, the station determined it was 19 prudent to minimize the use of as many chemicals as possible in order to 20 mitigate safety issues for personnel. This project will replace the old RO 21 and DW equipment with new equipment that meets plant demands and do 22 not require the use or handling of hazardous chemicals to generate 23 demineralized water. 24 25 26 27
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1 158. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 2 A. The estimated plant addition for this project is $2,732,953 including 3 AFUDC. This project was not initially planned to be completed in the 4 Certification period, however, to mitigate the potential deratings, it was 5 competed prior to the summer run. The project costs will be updated in 6 the Certification filing of this Docket. 7
8 2. WH2021 Spare GSU Transformer Purchase 9 159. Q. PLEASE DESCRIBE THE SPARE GSU TRANSFORMER 10 PURCHASE PROJECT.
11 The scope of this project is to procure a new spare GSU that has the
12 capability of connecting to multiple different grid voltages at various
13 generation facilities within the Company’s system. The GSU is primarily 14 specified for use with Higgins Units 1 through 3 but it is also compatible 15 with multiple units that serve the Sierra service territory. In the event of a d/b/a Energy NV
16 Nevada Power Company Company Power Nevada GSU failure at one of the compatible facilities, this unit can be deployed 17 expeditiously, greatly reducing the risk of an extended outage. and SierraCompany Pacific Power 18
19 160. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 20 A. The estimated plant addition for this project is $4,673,405 including 21 AFUDC. 22
23 3. WH2089 ACC Freight Elevator Installation 24 161. Q. PLEASE DESCRIBE THE PROJECT. 25 A. The Walter Higgins ACC Freight Elevator installation project 26 encompasses the installation of a freight elevator that travels from ground 27 level to the operational deck of the ACC. The Walter Higgins ACC was
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1 originally constructed with access to all elevations through a single set of 2 stairs and ladders, with the operational deck approximately sixty one feet 3 above the ground. Utilizing the elevator instead of climbing stairs will 4 result in improved labor efficiencies by removing the time required for 5 employees to mobilize to their work location, as well was eliminating 6 physical stress related to carrying tools and materials up several flights of 7 stairs to perform required operations and maintenance activities on 8 equipment located on the ACC operational deck. Operators are required to
9 inspect ACC equipment twice per shift. Additionally, the elevator will 10 also greatly enhance the safety of employees. As noted in discussion of
11 CL1099, medical emergencies have occurred at other generating facilities
12 and transport of a patient from operational deck to the ground utilizing
13 stairs is difficult, adds time for the patient to receive the care they need 14 and also creates a safety concern for first responders. 15 d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 162. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 17 A. The initial estimated plant addition for this project was $1,158,174
and SierraCompany Pacific Power 18 including AFUDC. Updated estimates were available after the schedules 19 were completed and, at the time, the current estimate for this project was 20 $1,219,799. The cost information will be updated in the Certification 21 filing in this Docket. 22
23 4. WH1064 Reclaim Sand Filter, Replace 24 163. Q. PLEASE DESCRIBE THE PROJECT. 25 A. The Higgins station utilizes a Reclaim Sand Filter as a prefilter for the 26 reclaim water the station receives from the Primm, NV water treatment 27 facility. In 2015 the Reclaim Sand Filter unit failed after eleven years of
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1 continuous service. A temporary replacement unit was obtained but it was 2 not designed for the flow rate and pressure that are required for the water 3 treatment system to operate as designed. This project is for a reliable 4 Reclaim Sand Filter to be engineered and installed that can prefiltrate the 5 reclaim water and remove the organic and inorganic suspended solids that 6 are being distributed to the station from the Primm, NV water treatment 7 facility. The Reclaim Sand Filter is the first in line component that filters 8 the suspended solids and must be sized to the flow rate, volume, and
9 operating pressures of the system in order to reduce fouling of downstream 10 components.
11
12 164. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT?
13 A. The estimated plant addition for this project is $963,449 including 14 AFUDC. 15 d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 5. WH2154 WH Steam Turbine HP and IP Valves, Replace 17 and SierraCompany Pacific Power 165. Q. PLEASE DESCRIBE THE PROJECT. 18 A. The Walter Higgins Steam Turbine’s operation is effectively controlled by 19 a series of eight valves consisting of High Pressure (“HP”) and 20 Intermediate Pressure (“IP”) Stop Valves and Control Valves. These 21 valves have been discharging excessive volumes of high temperature and 22 high pressure steam to the extent they are impeding the operation of the 23 station and affecting the station’s personnel’s safety. The condition of the 24 valves is affecting operation's ability to isolate and control the steam flow 25 as they are integral to the reliable startup, shutdown, and operation of the 26 station. The cycling of the station (and Steam Turbine) is causing 27 excessive wear within the valves’ internal components which causes the
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1 deformation of the internal components, thus being the consequence of the 2 cycling practice. The failure of these internal components are far beyond 3 normal wear and tear. 4 5 Since 2017, these valves have been discharging excessive volumes of high 6 temperature and high pressure steam. The steam leaks have progressively 7 gotten worse to the extent that the Steam Turbine has tripped offline on 8 numerous occasions, the startup of the Steam Turbine has been impeded,
9 adjoining electrical and mechanical components have been damaged, and 10 station personnel can no longer safely access the steam turbine area. In
11 addition, the continuous exposure of actuator solenoid valves to the
12 excessive temperatures will eventually degrade the hydraulic oil being
13 circulated to the extent that the valves would fail to operate upon 14 command; thus preventing the opening, closing, or otherwise positioning 15 of the Stop Valves and Control Valves. The hydraulic oil is circulated d/b/a Energy NV
16 Nevada Power Company Company Power Nevada through all the valves, and other components, through a common hydraulic 17 system that could fail due to its exposure to the high temperatures. and SierraCompany Pacific Power 18
19 166. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 20 A. The estimated plant addition for this project is $2,354,178 including 21 AFUDC. This project was inadvertently omitted from the list of projects 22 used to determine the proposed plant in service in this filing. This will be 23 corrected in the Certification filing in this Docket.
24
25 SECTION VII:EXPECTED CHANGE IN CIRCUMSTANCES 26 167. Q. WHY SHOULD THE COMMISSION CONSIDER THESE 27 PROJECTS IN THE ECIC PERIOD?
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1 A. Nevada Power had a planned outage scheduled for the spring of 2020; 2 however, due to the COVID-19 pandemic, the outage had to be 3 rescheduled to the fall 2020 since the outage work requires a large number 4 of workers in small confined areas. These projects are the suite of projects 5 planned to be completed in the original spring planned outage, but 6 rescheduled to the new fall planned outage. These outage related projects 7 are shown in Table Rekowski-Direct-5 and are described below.
8 TABLE REKOWSKI-DIRECT-5 9 Updated 10 Estimated Plant Budget ID Description Estimated Plant In-Service Costs 11 In-Service Costs
LTSA Projects 12 CL1104 LZ LTSA Capital Portion 2020 $16,792,239
13 WH1059 Higgins LTSA 2020 $13,878,281 $30,670,521 14 Chuck Lenzie Station Projects CL2074 LZ PB2 Ammonia Heaters, Replace $952,217 15
d/b/a Energy NV CL2089 LZ Gas Supply Piping System, Install $1,633,743
16 CL2147 PB2 Hydrogen Seals $1,133,785 Nevada Power Company Company Power Nevada Lenzie Other Outage Projects $1,646,421 17 and SierraCompany Pacific Power $5,366,166 18 Higgins Stations Projects WH1042 WHC Arc Flash Mitigation, Install $989,267 19 WH2024 WH CT1 Rotor Component, Replace $5,080,827 $5,682,252 WH2028 WH CT1 Exhaust System, Replace $2,661,884 20 WH2071 WH Steam Turbine Generator Winding, Purchase $6,314,332 21 WH2123 Underground Piping, Replace $1,867,880 WH2136 NP 17 MW 501F (Higgins CT1) $10,064,149 22 WH2137 NP 17 MW 501F (Higgins CT2) $10,064,149 23 WH2147 WHC CT Outage Components, Replace $2,311,491 $3,295,357 WH2149 WHC Cold Reheat Piping, Replace_WH $66,948 $931,187 24 WH2131 Main Steam Block Valve $445,622 WH2132 Main Steam Block Valve $448,927 25 Other Higgins Outage Projects $3,300,812 26 $43,616,288
27
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1 A. CL2074 PB2 AMMONIA HEATERS, REPLACE 2 168. Q. PLEASE DESCRIBE THE PB2 AMMONIA HEATER 3 REPLACEMENT PROJECT. 4 A. Aqueous ammonia vaporization systems are required to keep combustion 5 emissions (Nitrogen Oxides) below levels set forth by the Nevada Division 6 of Environmental Protection and the EPA. 7 8 Each HRSG has a set of two heaters for vaporizing aqueous ammonia. One
9 heater operates as the primary, which will typically run until a problem 10 occurs. The other heater is for backup. In the event the primary heater fails,
11 the backup will enter into service. If no heaters are available, the unit must
12 be shut down to avoid a Title V Air Permit violation.
13 14 The control system, consisting of a 480 VAC feed, circuit breaker and a 15 silicon controlled rectifier, was identified as a high-risk single point d/b/a Energy NV
16 Nevada Power Company Company Power Nevada failure. Failure of the control system will render both heaters unavailable 17 resulting in a forced outage. Addition of separate control systems for each and SierraCompany Pacific Power 18 heater eliminates a significant single point failure reducing the risk of a 19 forced outage as well as enabling maintenance of the system while the unit 20 is online. 21 22 Over time, heating elements fail through normal use. Due to these failures, 23 the facility is currently operating several units with only a single heater 24 and no backup. Replacement of the backup heaters is necessary to 25 eliminate a single point of failure and avoid a forced outage should the 26 primary heater fail. 27
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1 This project will replace failed heaters and install a new control system on 2 each unit in Power Block 2 of Lenzie. 3
4 169. Q. NRS 704.110(4) STATES THAT AN ITEM INCLUDED IN THE 5 EXPECTED CHANGE IN CIRCUMSTANCE PERIOD MUST BE 6 “REASONABLY KNOWN AND MEASUREABLE WITH 7 REASONABLE ACCURACY.” ARE THE EXPECTED COSTS OF 8 THE PB2 AMMONIA HEATER REPLACEMENT PROJECT 9 “REASONABLY KNOWN AND MEASURABLE WITH 10 REASONABLE ACCURACY” AS OF THE DATE YOUR
11 TESTIMONY IS BEING PREPARED?
12 A. Yes. The project was planned to be completed in the spring of 2020.
13 Contracts were bid and executed to complete the work. Additionally, a 14 similar project was completed on Lenzie PB1 during the certification 15 period. d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 17 and SierraCompany Pacific Power 170. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 18 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 19 AND MEASURABLE WITH REASONABLE ACCURACY IF,
20 AMONG OTHER THINGS, IT CONSISTS OF SPECIFIC AND 21 IDENTIFIABLE EVENTS OR PROGRAMS RATHER THAN 22 GENERAL TRENDS, PATTERNS OR DEVELOPMENTS. DOES 23 THE PB2 AMMONIA HEATER REPLACEMENT PROJECT 24 MEET THAT CRITERION? 25 A. Yes. The project scope to install the PB2 Ammonia Heater includes the 26 purchase and installation of equipment based on contract purchase orders 27
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1 and detailed delivery schedules and cannot be characterized as a general 2 trend, pattern or development. 3
4 171. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 5 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 6 AND MEASURABLE WITH REASONABLE ACCURACY IF, 7 AMONG OTHER THINGS, IT HAS AN OBJECTIVELY HIGH 8 PROBABILITY OF OCCURRING TO THE DEGREE, IN THE 9 AMOUNT AND AT THE TIME EXPECTED. DOES THE PB2 10 AMMONIA HEATER REPLACEMENT PROJECT MEET THAT
11 CRITERION?
12 A. Yes. Revised production and installation schedules provided by all
13 vendors demonstrate completion of the installation during the fall 2020 14 outage that will begin on October 3, 2020, and will end on November 11, 15 2020. d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 17 and SierraCompany Pacific Power 172. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 18 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 19 AND MEASURABLE WITH REASONABLE ACCURACY IF,
20 AMONG OTHER THINGS, IT IS PRIMARILY MEASUREABLE 21 BY RECORDED OR VERIFIABLE REVENUES AND EXPENSES 22 AND IS EASILY AND OBJECTIVELY CALCULATED, WITH 23 THE CALCULATION OF THE EXPECTED CHANGES RELYING 24 ONLY SECONDARILY ON ESTIMATES, FORECASTS, 25 PROJECTIONS OR BUDGETS. DOES THE PB2 AMMONIA 26 HEATER REPLACEMENT PROJECT MEET THAT 27 CRITERION?
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1 A. Yes. All of the project costs related to the installation of the PB2 2 Ammonia Heater are currently verifiable and recorded in the contracts and 3 purchase orders, as set forth above. Additionally, a similar project was 4 completed on Lenzie PB1 during the certification period. 5
6 173. Q. PLEASE SUMMARIZE WHY THE PB2 AMMONIA HEATER 7 REPLACEMENT PROJECT MEETS THE CRITERIA SPECIFIED 8 IN NRS 704.110(4) AS AN EXPECTED CHANGE THAT IS 9 REASONABLY KNOWN AND MEASURABLE WITH 10 REASONABLE ACCURACY.
11 A. The PB2 Ammonia Heater project constitutes a specific and identifiable
12 event, these events have an objectively high probability of occurring to the
13 degree, in the amount and at the time expected, and their costs are currently 14 measurable by recorded and verifiable expenses that are easily and 15 objectively calculated. d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 17 and SierraCompany Pacific Power 174. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHOULD 18 CONSIDER “REASONABLE PROJECTED OR FORECASTED 19 OFFSETS IN REVENUE AND EXPENSES THAT ARE DIRECTLY
20 ATTRIBUTABLE TO OR ASSOCIATED WITH THE EXPECTED 21 CHANGES IN CIRCUMSTANCES UNDER CONSIDERATION.” 22 ARE THERE ANY OFFSETS ASSOCIATED WITH THE PB2 23 AMMONIA HEATER REPLACEMENT PROJECT? 24 A. The Company has not identified any reasonable projected or forecasted 25 offsets in revenues or expenses that are directly attributable to or 26 associated with these expected changes in circumstances.
27
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1 175. Q. WHY SHOULD THIS PROJECT BE CONSIDERED FOR ECIC? 2 A. This project was planned for completion during the spring 2020 Power 3 Block 2 Major Overhaul at Chuck Lenzie Station. This project requires a 4 unit outage since the single controller that is being replaced operates both 5 the operating and failed heaters. Due to COVID-19 pandemic, the Major 6 Overhaul was postponed until to Fall of 2020 and this project will be 7 completed at that time.
8 176. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 9 A. The estimated cost for this project is $952,217. 10
11 B. CL2089 GAS SUPPLY PIPING SYSTEM INSTALL
12 177. Q. PLEASE DESCRIBE THE GAS SUPPLY PIPING PROJECT.
13 A. The scope of this project is the replacement of the single underground gas 14 fuel piping system at Chuck Lenzie Station with a dual piping system. 15 Inspection of sections of the existing underground piping found instances d/b/a Energy NV
16 Nevada Power Company Company Power Nevada of pipe coating failure and corrosion in the gas yard where cathodic 17 protection was not installed. Additionally, the inspections documented the and SierraCompany Pacific Power 18 risk of total plant unavailability in the event of a pipeline failure, 1,102 19 MW total summer peak net capacity, due to the original design of a single 20 pipeline feeding both power blocks. The existing pipeline will be 21 abandoned in place, and two new above-ground natural gas supply piping 22 systems, one to each power block, will be installed. Each piping systems 23 will be sized to supply fuel to each power block independently. Because 24 the new lines will be installed above ground, they will not be susceptible 25 to corrosion. The second line will eliminate the risk of total lost generation 26 when one supply piping system requires repair or maintenance. 27
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1 178. Q. NRS 704.110(4) STATES THAT AN ITEM INCLUDED IN THE 2 EXPECTED CHANGE IN CIRCUMSTANCE PERIOD MUST BE 3 “REASONABLY KNOWN AND MEASUREABLE WITH 4 REASONABLE ACCURACY.” ARE THE EXPECTED COSTS OF 5 THE LENZIE GAS SUPPLY PIPING SYSTEM PROJECT 6 “REASONABLY KNOWN AND MEASURABLE WITH 7 REASONABLE ACCURACY” AS OF THE DATE YOUR 8 TESTIMONY IS BEING PREPARED? 9 A. Yes. The project was planned to be completed in the spring of 2020. 10 Contracts were bid and executed to complete the work.
11
12 179. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND
13 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 14 AND MEASURABLE WITH REASONABLE ACCURACY IF, 15 AMONG OTHER THINGS, IT CONSISTS OF SPECIFIC AND d/b/a Energy NV
16 Nevada Power Company Company Power Nevada IDENTIFIABLE EVENTS OR PROGRAMS RATHER THAN 17
and SierraCompany Pacific Power GENERAL TRENDS, PATTERNS OR DEVELOPMENTS. DOES 18 THE GAS SUPPLY PIPING PROJECT MEET THAT 19 CRITERION? 20 A. Yes. The project scope to install the gas supply piping includes the 21 purchase and installation of equipment based on contract purchase orders 22 and detailed delivery schedules and cannot be characterized as a general 23 trend, pattern or development. 24 25 26 27
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1 180. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 2 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 3 AND MEASURABLE WITH REASONABLE ACCURACY IF, 4 AMONG OTHER THINGS, IT HAS AN OBJECTIVELY HIGH 5 PROBABILITY OF OCCURRING TO THE DEGREE IN THE 6 AMOUNT AND AT THE TIME EXPECTED. DOES THE GAS 7 SUPPLY SYSTEM PROJECT MEET THAT CRITERION? 8 A. Yes. Revised production and installation schedules provided by all 9 vendors demonstrate completion of the installation during the fall 2020 10 outage that will begin on October 3, 2020, and will end on November 11,
11 2020.
12
13 181. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 14 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 15 AND MEASURABLE WITH REASONABLE ACCURACY IF, d/b/a Energy NV
16 Nevada Power Company Company Power Nevada AMONG OTHER THINGS, IT IS PRIMARILY MEASUREABLE 17
and SierraCompany Pacific Power BY RECORDED OR VERIFIABLE REVENUES AND EXPENSES 18 AND IS EASILY AND OBJECTIVELY CALCULATED, WITH 19 THE CALCULATION OF THE EXPECTED CHANGES RELYING
20 ONLY SECONDARILY ON ESTIMATES, FORECASTS, 21 PROJECTIONS OR BUDGETS. DOES THE GAS SUPPLY PIPING 22 SYSTEM PROJECT MEET THAT CRITERION? 23 A. Yes. All of the project costs related to the installation of the gas supply 24 piping system are currently verifiable and recorded in the contracts and 25 purchase orders, as set forth above. 26 27
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1 182. Q. PLEASE SUMMARIZE WHY THE GAS SUPPLY PIPING 2 SYSTEM PROJECT MEETS THE CRITERIA SPECIFIED IN NRS 3 704.110(4) AS AN EXPECTED CHANGE THAT IS REASONABLY 4 KNOWN AND MEASURABLE WITH REASONABLE 5 ACCURACY. 6 A. The Gas Supply Piping System project constitutes a specific and 7 identifiable event, these events have an objectively high probability of 8 occurring to the degree, in the amount and at the time expected, and their
9 costs are currently measurable by recorded and verifiable expenses that 10 are easily and objectively calculated.
11
12 183. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHOULD
13 CONSIDER “REASONABLE PROJECTED OR FORECASTED 14 OFFSETS IN REVENUE AND EXPENSES THAT ARE DIRECTLY 15 ATTRIBUTABLE TO OR ASSOCIATED WITH THE EXPECTED d/b/a Energy NV
16 Nevada Power Company Company Power Nevada CHANGES IN CIRCUMSTANCES UNDER CONSIDERATION.” 17
and SierraCompany Pacific Power ARE THERE ANY OFFSETS ASSOCIATED WITH THE GAS 18 SUPPLY SYSTEM PROJECT? 19 A. The Company has not identified any reasonable projected or forecasted 20 offsets in revenues or expenses that are directly attributable to or 21 associated with these expected changes in circumstances. 22
23 184. WHY SHOULD THIS PROJECT BE CONSIDERED FOR ECIC? 24 A. The project was planned to be completed in the spring of 2020. However, 25 due to the COVID-19 pandemic, the project is delayed until the fall of 26 2020. The project is essential to maintain the reliability of the generating 27
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1 unit and further delay of the project increases the risk of catastrophic 2 failure. 3
4 185. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 5 A. The estimated cost for this project is $1,633,743. This project was 6 originally listed as a certification period project. This will be corrected in 7 the Certification filing in this Docket. 8
9 C. CL2147 PB2 STG HYDROGEN SEALS, REPLACE 10 186. Q. PLEASE DESCRIBE THE LENZIE POWER BLOCK 2 STEAM
11 TURBINE GENERATOR HYDROGEN SEALS PROJECT.
12 A. The scope of this project is to replace the Chuck Lenzie Power Block 2
13 steam turbine generator T5 hydrogen seal, repair the T5 bearing, repair the 14 T5 journal bearing, align the generator rotor, and replace the hydrogen oil 15 drain line following the guidance from a General Electric (“GE”) field d/b/a Energy NV
16 Nevada Power Company Company Power Nevada engineer assessment. On August 25, 2019, the unit experienced a 17 significant step increase, ten times normal, in hydrogen leak rate, and the and SierraCompany Pacific Power 18 generator developed a lube oil leak at the turbine end of the generator. This 19 project reduces the risk of the unit becoming unavailable to service native 20 load during peak periods. 21
22 187. Q. NRS 704.110(4) STATES THAT AN ITEM INCLUDED IN THE 23 EXPECTED CHANGE IN CIRCUMSTANCE PERIOD MUST BE 24 “REASONABLY KNOWN AND MEASUREABLE WITH 25 REASONABLE ACCURACY.” ARE THE EXPECTED COSTS OF 26 THE PB2 STG HYDROGEN SEALS REPLACEMENT PROJECT 27 “REASONABLY KNOWN AND MEASURABLE WITH
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1 REASONABLE ACCURACY” AS OF THE DATE YOUR 2 TESTIMONY IS BEING PREPARED? 3 A. Yes. The project was planned to be completed in the spring of 2020. 4 Contracts were bid and executed to complete the work. 5
6 188. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 7 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 8 AND MEASURABLE WITH REASONABLE ACCURACY IF, 9 AMONG OTHER THINGS, IT CONSISTS OF SPECIFIC AND 10 IDENTIFIABLE EVENTS OR PROGRAMS RATHER THAN
11 GENERAL TRENDS, PATTERNS OR DEVELOPMENTS. DOES
12 THE PB2 STG HYDROGEN SEALS REPLACEMENT PROJECT
13 MEET THAT CRITERION? 14 A. Yes. The project scope to replace the PB2 STG Hydrogen seals includes 15 the purchase and installation of equipment based on contract purchase d/b/a Energy NV
16 Nevada Power Company Company Power Nevada orders and detailed delivery schedules and cannot be characterized as a 17 general trend, pattern or development. and SierraCompany Pacific Power 18
19 189. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 20 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 21 AND MEASURABLE WITH REASONABLE ACCURACY IF, 22 AMONG OTHER THINGS, IT HAS AN OBJECTIVELY HIGH 23 PROBABILITY OF OCCURRING TO THE DEGREE, IN THE 24 AMOUNT AND AT THE TIME EXPECTED. DOES THE PB2 STG 25 HYDROGEN SEALS REPLACEMENT PROJECT MEET THAT 26 CRITERION? 27
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1 A. Yes. Revised replacement schedules provided by all vendors demonstrate 2 completion of the installation during the fall 2020 outage that will begin 3 on October 3, 2020, and will end on November 11, 2020. 4
5 190. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 6 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 7 AND MEASURABLE WITH REASONABLE ACCURACY IF, 8 AMONG OTHER THINGS, IT IS PRIMARILY MEASUREABLE 9 BY RECORDED OR VERIFIABLE REVENUES AND EXPENSES 10 AND IS EASILY AND OBJECTIVELY CALCULATED, WITH
11 THE CALCULATION OF THE EXPECTED CHANGES RELYING
12 ONLY SECONDARILY ON ESTIMATES, FORECASTS,
13 PROJECTIONS OR BUDGETS. DOES THE PB2 STG HYDROGEN 14 SEALS REPLACEMENT PROJECT MEET THAT CRITERION? 15 A. Yes. All of the project costs related to the installation of the PB2 STG d/b/a Energy NV
16 Nevada Power Company Company Power Nevada Hydrogen seals are currently verifiable and recorded in the contracts and 17 purchase orders, as set forth above. and SierraCompany Pacific Power 18
19 191. Q. PLEASE SUMMARIZE WHY THE PB2 STG HYDROGEN SEALS 20 REPLACEMENT PROJECT MEETS THE CRITERIA SPECIFIED 21 IN NRS 704.110(4) AS AN EXPECTED CHANGE THAT IS 22 REASONABLY KNOWN AND MEASURABLE WITH 23 REASONABLE ACCURACY. 24 A. The PB2 STG Hydrogen Seals Replacement project constitutes a specific 25 and identifiable event, these events have an objectively high probability of 26 occurring to the degree, in the amount and at the time expected, and their 27
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1 costs are currently measurable by recorded and verifiable expenses that 2 are easily and objectively calculated. 3
4 192. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHOULD 5 CONSIDER “REASONABLE PROJECTED OR FORECASTED 6 OFFSETS IN REVENUE AND EXPENSES THAT ARE DIRECTLY 7 ATTRIBUTABLE TO OR ASSOCIATED WITH THE EXPECTED 8 CHANGES IN CIRCUMSTANCES UNDER CONSIDERATION.” 9 ARE THERE ANY OFFSETS ASSOCIATED WITH THE PB2 STG 10 HYDROGEN SEALS REPLACEMENT PROJECT?
11 A. The Company has not identified any reasonable projected or forecasted
12 offsets in revenues or expenses that are directly attributable to or
13 associated with these expected changes in circumstances. 14
15 193. Q. WHY SHOULD THIS PROJECT BE CONSIDERED FOR ECIC? d/b/a Energy NV
16 Nevada Power Company Company Power Nevada A. The project was planned to be completed in the spring of 2020. However, 17 due to the COVID-19 pandemic, the project is delayed until the fall of and SierraCompany Pacific Power 18 2020. The project is essential to maintain the reliability of the generating 19 unit and further delay of the project increases the risk of catastrophic 20 failure. 21
22 194. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 23 A. The estimated cost for this project is $1,133,785. 24 25 26 27
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1 D. LENZIE – OTHER OUTAGE RELATED PROJECTS 2 195. Q. PLEASE DESCRIBE THE PROJECT. 3 A. The Lenzie Power Block 2 turbine outage work noted in the above are only 4 the large outage capital projects. There are another 13 projects that total 5 $1,646,421. These projects are essential and must be completed during 6 the planned outage. A list of these projects is shown in the Table 7 Rekowski-Direct-6.
8 9 TABLE REKOWSKI-DIRECT-6
10 Project ID Description Project Cost
CL1054 LZ Casing & Insulation 2020, Replacement 11 $235,679 CL1066 LZ ST2 to Condenser Expansion joint, Replace $244,500
12 CL2059 LZ PB2 CT3 CEMS Analyzers, Replace $227,169
13 CL2060 LZ PB2 CT4 CEMS Analyzers, Replace $227,169 CL2093 LZ PB2 Condensate Tank Level Control Valve, Replace $150,458 14 CL2130 LZ PB2 EHC Fluid, Replace $103,968 15 CL2140 LZ CT3 Flex Seal, Replace $52,178 d/b/a Energy NV CL2141 LZ CT4 Flex Seal, Replace $52,129 16 Nevada Power Company Company Power Nevada CL2148 LZ CT3 Gas Control Valve Servo, Replace $35,465 17 CL2149 LZ CT4 Gas Control Valve Servo, Replace $35,455 and SierraCompany Pacific Power CL2151 LZ ST2 ST Control Valve Servo, Replace $86,367 18 CL2161 LZ PB2 CT3 Bearing, Replace $95,860 19 CL2162 LZ PB2 CT4 Bearing, Replace $95,860 $
20 Total Other Lenzie PB2 Outage Projects $1,646,421
21
22
23 24
25 26 27
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1 196. Q. NRS 704.110(4) STATES THAT AN ITEM INCLUDED IN THE 2 EXPECTED CHANGE IN CIRCUMSTANCE PERIOD MUST BE 3 “REASONABLY KNOWN AND MEASUREABLE WITH 4 REASONABLE ACCURACY.” ARE THE EXPECTED COSTS OF 5 THE OTHER OUTAGE RELATED CAPITAL PROJECTS 6 “REASONABLY KNOWN AND MEASURABLE WITH 7 REASONABLE ACCURACY” AS OF THE DATE YOUR 8 TESTIMONY IS BEING PREPARED? 9 A. Yes. The projects were planned to be completed in the spring of 2020. 10 Contracts were bid and executed to complete the work.
11
12 197. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND
13 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 14 AND MEASURABLE WITH REASONABLE ACCURACY IF, 15 AMONG OTHER THINGS, IT CONSISTS OF SPECIFIC AND d/b/a Energy NV
16 Nevada Power Company Company Power Nevada IDENTIFIABLE EVENTS OR PROGRAMS RATHER THAN 17
and SierraCompany Pacific Power GENERAL TRENDS, PATTERNS OR DEVELOPMENTS. DO 18 THE LENZIE OUTAGE RELATED CAPITAL PROJECTS MEET 19 THAT CRITERION? 20 A. Yes. The projects’ scope to complete necessary equipment replacement 21 during the Lenzie PB2 turbine outage includes the purchase and 22 installation of equipment based on contract purchase orders and detailed 23 delivery schedules and cannot be characterized as a general trend, pattern 24 or development.
25
26 27
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1 198. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 2 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 3 AND MEASURABLE WITH REASONABLE ACCURACY IF, 4 AMONG OTHER THINGS, IT HAS AN OBJECTIVELY HIGH 5 PROBABILITY OF OCCURRING TO THE DEGREE, IN THE 6 AMOUNT AND AT THE TIME EXPECTED. DO THE LENZIE 7 PB2 OUTAGE RELATED CAPITAL PROJECTS MEET THAT 8 CRITERION? 9 A. Yes. Revised production and installation schedules provided by all 10 vendors demonstrate completion of the installation during the fall 2020
11 outage that will begin on October 3, 2020, and will end on November 11,
12 2020.
13
14
15 199. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND d/b/a Energy NV
16 Nevada Power Company Company Power Nevada THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 17
and SierraCompany Pacific Power AND MEASURABLE WITH REASONABLE ACCURACY IF, 18 AMONG OTHER THINGS, IT IS PRIMARILY MEASUREABLE 19 BY RECORDED OR VERIFIABLE REVENUES AND EXPENSES
20 AND IS EASILY AND OBJECTIVELY CALCULATED, WITH 21 THE CALCULATION OF THE EXPECTED CHANGES RELYING 22 ONLY SECONDARILY ON ESTIMATES, FORECASTS, 23 PROJECTIONS OR BUDGETS. DO THE LENZIE PB2 OUTAGE 24 RELATED CAPITAL PROJECTS MEET THAT CRITERION? 25 A. Yes. All of the project costs related to these outage related capital projects 26 are currently verifiable and recorded in the contracts and purchase orders, 27 as set forth above.
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1 200. Q. PLEASE SUMMARIZE WHY THE LENZIE PB2 OUTAGE 2 RELATED CAPITAL PROJECTS MEET THE CRITERIA 3 SPECIFIED IN NRS 704.110(4) AS AN EXPECTED CHANGE 4 THAT IS REASONABLY KNOWN AND MEASURABLE WITH 5 REASONABLE ACCURACY. 6 A. These Lenzie PB2 outage related capital projects constitutes a specific and 7 identifiable event, these events have an objectively high probability of 8 occurring to the degree, in the amount and at the time expected, and their
9 costs are currently measurable by recorded and verifiable expenses that 10 are easily and objectively calculated.
11
12 201. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHOULD
13 CONSIDER “REASONABLE PROJECTED OR FORECASTED 14 OFFSETS IN REVENUE AND EXPENSES THAT ARE DIRECTLY 15 ATTRIBUTABLE TO OR ASSOCIATED WITH THE EXPECTED d/b/a Energy NV
16 Nevada Power Company Company Power Nevada CHANGES IN CIRCUMSTANCES UNDER CONSIDERATION.” 17
and SierraCompany Pacific Power ARE THERE ANY OFFSETS ASSOCIATED WITH THE LENZIE 18 PB2 OUTAGE RELATED CAPITAL PROJECTS? 19 A. The Company has not identified any reasonable projected or forecasted 20 offsets in revenues or expenses that are directly attributable to or 21 associated with these expected changes in circumstances. 22
23 202. Q. WHAT IS THE EXPECTED COST OF THESE PROJECTS? 24 A. The individual project costs are included in the Table Rekowski-Direct-6. 25 The total for these 13 projects is $1,646,421, not including AFUDC. Four 26 of these projects (CL2059, CL2060, CL2093 and CL2130) were originally 27
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1 listed as a certification period projects. This will be corrected in the 2 Certification filing in this Docket.
3
4 E. WH1042 WHC ARC FLASH MITIGATION, INSTALL 5 203. Q. PLEASE DESCRIBE THE PROJECT. 6 A. The Higgins Station initiated the Arc Flash Mitigation project in order to 7 address preventable safety incidents that can adversely impact the safety 8 of station personnel. An Arc Flash analysis was performed by Zachary
9 Engineering in accordance with NFPA 70E, which identified numerous 10 and significant electrical hazards at the station. The equipment evaluated
11 included all of the station’s switchgear, Motor Control Centers (“MCCs”),
12 panels, and major transformer terminals. The study results showed the
13 electrical gear could not be worked on while energized since the incident 14 energy for each one exceeded 40 calories per cubic centimeter in one or 15 more of the study cases. The plant personal protective equipment (“PPE”) d/b/a Energy NV
16 Nevada Power Company Company Power Nevada is rated for 8 calories per cubic centimeter. These conditions represent an 17 unsafe work environment for station personnel to perform many activities and SierraCompany Pacific Power 18 such as locally operating breakers, racking breakers, and working within 19 the MCC buildings. Sargent & Lundy was contracted to review the 20 Zachary study and developed a detailed design for the arc flash mitigation. 21 22 The Arc Flash mitigation is addressed by replacing the existing relay 23 protection devices installed on the switchgear, buses and MCCs with 24 upgraded devices that can detect the fault faster and trip the breakers 25 quicker to prevent the fault from displacing its full energy and reduces the 26 arc flash energies to 8 calories per cubic centimeter or below. The 27
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1 components to be protected were determined from an Arc Flash Analysis 2 performed with resulting calculations. 3
4 204. Q. NRS 704.110(4) STATES THAT AN ITEM INCLUDED IN THE 5 EXPECTED CHANGE IN CIRCUMSTANCE PERIOD MUST BE 6 “REASONABLY KNOWN AND MEASUREABLE WITH 7 REASONABLE ACCURACY.” ARE THE EXPECTED COSTS OF 8 THE ARC FLASH MITIGATION INSTALLATION PROJECT 9 “REASONABLY KNOWN AND MEASURABLE WITH 10 REASONABLE ACCURACY” AS OF THE DATE YOUR
11 TESTIMONY IS BEING PREPARED?
12 A. Yes. The project was planned to be completed in the spring of 2020.
13 Contracts were bid and executed to complete the work. Additionally, 14 similar projects have been completed at other Company generating 15 stations. d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 17 and SierraCompany Pacific Power 205. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 18 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 19 AND MEASURABLE WITH REASONABLE ACCURACY IF,
20 AMONG OTHER THINGS, IT CONSISTS OF SPECIFIC AND 21 IDENTIFIABLE EVENTS OR PROGRAMS RATHER THAN 22 GENERAL TRENDS, PATTERNS OR DEVELOPMENTS. DOES 23 THE ARC FLASH MITIGATION INSTALLATION PROJECT 24 MEET THAT CRITERION? 25 A. Yes. The project scope to install the arc flash mitigation includes the 26 purchase and installation of equipment based on contract purchase orders 27
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1 and detailed delivery schedules and cannot be characterized as a general 2 trend, pattern or development. 3
4 206. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 5 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 6 AND MEASURABLE WITH REASONABLE ACCURACY IF, 7 AMONG OTHER THINGS, IT HAS AN OBJECTIVELY HIGH 8 PROBABILITY OF OCCURRING TO THE DEGREE, IN THE 9 AMOUNT AND AT THE TIME EXPECTED. DOES THE ARC 10 FLASH MITIGATION INSTALLATION PROJECT MEET THAT
11 CRITERION?
12 A. Yes. Revised production and installation schedules provided by all
13 vendors demonstrate completion of the installation during the fall 2020 14 outage that will begin on October 1, 2020, and will end on December 5, 15 2020. d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 17 and SierraCompany Pacific Power 207. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 18 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 19 AND MEASURABLE WITH REASONABLE ACCURACY IF,
20 AMONG OTHER THINGS, IT IS PRIMARILY MEASUREABLE 21 BY RECORDED OR VERIFIABLE REVENUES AND EXPENSES 22 AND IS EASILY AND OBJECTIVELY CALCULATED, WITH 23 THE CALCULATION OF THE EXPECTED CHANGES RELYING 24 ONLY SECONDARILY ON ESTIMATES, FORECASTS, 25 PROJECTIONS OR BUDGETS. DOES THE ARC FLASH 26 MITIGATION INSTALLATION PROJECT MEET THAT 27 CRITERION?
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1 A. Yes. All of the project costs related to the installation of the arc flash 2 mitigation installation project are currently verifiable and recorded in the 3 contracts and purchase orders, as set forth above. 4
5 208. Q. PLEASE SUMMARIZE WHY THE ARC FLASH MITIGATION 6 INSTALLATION PROJECT MEETS THE CRITERIA SPECIFIED 7 IN NRS 704.110(4) AS AN EXPECTED CHANGE THAT IS 8 REASONABLY KNOWN AND MEASURABLE WITH 9 REASONABLE ACCURACY. 10 A. The arc flash mitigation installation project constitutes a specific and
11 identifiable event, these events have an objectively high probability of
12 occurring to the degree, in the amount and at the time expected, and their
13 costs are currently measurable by recorded and verifiable expenses that 14 are easily and objectively calculated. 15 d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 209. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHOULD 17
and SierraCompany Pacific Power CONSIDER “REASONABLE PROJECTED OR FORECASTED 18 OFFSETS IN REVENUE AND EXPENSES THAT ARE DIRECTLY 19 ATTRIBUTABLE TO OR ASSOCIATED WITH THE EXPECTED
20 CHANGES IN CIRCUMSTANCES UNDER CONSIDERATION.” 21 ARE THERE ANY OFFSETS ASSOCIATED WITH THE ARC 22 FLASH MITIGATION INSTALLATION PROJECT? 23 A. The Company has not identified any reasonable projected or forecasted 24 offsets in revenues or expenses that are directly attributable to or 25 associated with these expected changes in circumstances. 26 27
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1 210. Q. WHY SHOULD THIS PROJECT BE CONSIDERED FOR ECIC? 2 A. The project was planned to be completed in the spring of 2020. However, 3 due to the COVID-19 pandemic, the project is delayed until the fall of 4 2020. The project is essential to maintain the reliability of the generating 5 unit and further delay of the project increases the risk of catastrophic 6 failure. 7
8 211. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 9 A. The estimated plant addition for this project is $989,267 including 10 AFUDC.
11
12 F. WH2024 WH CT1 ROTOR COMPONENT, REPLACE
13 212. Q. PLEASE DESCRIBE THE PROJECT. 14 A. The Walter Higgins Unit 1 rotor and the compressor components will 15 reach their design life of 100,000 hours and 3,600 starts by fall 2020. Per d/b/a Energy NV
16 Nevada Power Company Company Power Nevada OEM guidelines, these components require either replacement or major 17 inspection and rebuild by a qualified facility. Through the LTSA, the and SierraCompany Pacific Power 18 Company will exchange the original CT1 rotor for a rebuilt unit at a 19 reduced cost. The Company will refurbish and replace compressor blades 20 as necessary. The rotor replacement is scheduled in conjunction with other 21 combustion turbine capital projects (WH1059, WH2028, WH2136, and 22 WH2147) in order to integrate and cost effectively perform the work on 23 the unit. 24 25 26 27
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1 213. Q. NRS 704.110(4) STATES THAT AN ITEM INCLUDED IN THE 2 EXPECTED CHANGE IN CIRCUMSTANCE PERIOD MUST BE 3 “REASONABLY KNOWN AND MEASUREABLE WITH 4 REASONABLE ACCURACY.” ARE THE EXPECTED COSTS OF 5 THE CT1 ROTOR COMPONENT REPLACEMENT PROJECT 6 “REASONABLY KNOWN AND MEASURABLE WITH 7 REASONABLE ACCURACY” AS OF THE DATE YOUR 8 TESTIMONY IS BEING PREPARED? 9 A. Yes. The project was planned to be completed in the spring of 2020. 10 Contracts were bid and executed to complete the work.
11
12 214. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND
13 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 14 AND MEASURABLE WITH REASONABLE ACCURACY IF, 15 AMONG OTHER THINGS, IT CONSISTS OF SPECIFIC AND d/b/a Energy NV
16 Nevada Power Company Company Power Nevada IDENTIFIABLE EVENTS OR PROGRAMS RATHER THAN 17
and SierraCompany Pacific Power GENERAL TRENDS, PATTERNS OR DEVELOPMENTS. DOES 18 THE CT1 ROTOR COMPONENT REPLACEMENT PROJECT 19 MEET THAT CRITERION? 20 A. Yes. The project scope to replace the CT1 rotor components includes the 21 purchase and installation of equipment based on contract purchase orders 22 and detailed delivery schedules and cannot be characterized as a general 23 trend, pattern or development. 24 25 26 27
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1 215. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 2 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 3 AND MEASURABLE WITH REASONABLE ACCURACY IF, 4 AMONG OTHER THINGS, IT HAS AN OBJECTIVELY HIGH 5 PROBABILITY OF OCCURRING TO THE DEGREE, IN THE 6 AMOUNT AND AT THE TIME EXPECTED. DOES THE CT1 7 ROTOR COMPONENT REPLACEMENT PROJECT MEET THAT 8 CRITERION? 9 A. Yes. Revised production and installation schedules provided by all 10 vendors demonstrate completion of the installation during the fall 2020
11 outage that will begin on October 1, 2020, and will end on December 5,
12 2020.
13
14 216. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 15 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN d/b/a Energy NV
16 Nevada Power Company Company Power Nevada AND MEASURABLE WITH REASONABLE ACCURACY IF, 17
and SierraCompany Pacific Power AMONG OTHER THINGS, IT IS PRIMARILY MEASUREABLE 18 BY RECORDED OR VERIFIABLE REVENUES AND EXPENSES 19 AND IS EASILY AND OBJECTIVELY CALCULATED, WITH
20 THE CALCULATION OF THE EXPECTED CHANGES RELYING 21 ONLY SECONDARILY ON ESTIMATES, FORECASTS, 22 PROJECTIONS OR BUDGETS. DOES THE CT1 ROTOR 23 COMPONENT REPLACEMENT PROJECT MEET THAT 24 CRITERION? 25 A. Yes. All of the project costs related to the installation of the CT1 rotor 26 component replacement currently verifiable and recorded in the contracts 27 and purchase orders, as set forth above.
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1 217. Q. PLEASE SUMMARIZE WHY THE CT1 ROTOR COMPONENT 2 REPLACEMENT PROJECT MEETS THE CRITERIA SPECIFIED 3 IN NRS 704.110(4) AS AN EXPECTED CHANGE THAT IS 4 REASONABLY KNOWN AND MEASURABLE WITH 5 REASONABLE ACCURACY. 6 A. The CT1 rotor component replacement project constitutes a specific and 7 identifiable event, these events have an objectively high probability of 8 occurring to the degree, in the amount and at the time expected, and their
9 costs are currently measurable by recorded and verifiable expenses that 10 are easily and objectively calculated.
11
12 218. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHOULD
13 CONSIDER “REASONABLE PROJECTED OR FORECASTED 14 OFFSETS IN REVENUE AND EXPENSES THAT ARE DIRECTLY 15 ATTRIBUTABLE TO OR ASSOCIATED WITH THE EXPECTED d/b/a Energy NV
16 Nevada Power Company Company Power Nevada CHANGES IN CIRCUMSTANCES UNDER CONSIDERATION.” 17
and SierraCompany Pacific Power ARE THERE ANY OFFSETS ASSOCIATED WITH THE CT1 18 ROTOR COMPONENT REPLACEMENT PROJECT? 19 A. The Company has not identified any reasonable projected or forecasted 20 offsets in revenues or expenses that are directly attributable to or 21 associated with these expected changes in circumstances. 22
23 219. Q. WHY SHOULD THIS PROJECT BE CONSIDERED FOR ECIC? 24 A. The project was planned to be completed in the spring of 2020. However, 25 due to the COVID-19 pandemic, the project is delayed until the fall of 26 2020. The project is essential to maintain the reliability of the generating 27
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1 unit and further delay of the project increases the risk of catastrophic 2 failure. 3
4 220. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 5 A. The initial estimated plant addition for this project was $5,080,827 6 including AFUDC. Updated estimates were available after the schedules 7 were completed and, at the time, the current estimate for this project was 8 $5,682,252. The cost information will be updated in the Certification
9 filing in this Docket. 10
11 G. WH2028 CT1 EXHAUST SYSTEM, REPLACE
12 221. Q. PLEASE DESCRIBE THE PROJECT.
13 A. The Walter Higgins station utilizes Siemens 501FD2 combustion turbines. 14 As discussed in Q&A 94, Siemens has documented exhaust system design 15 flaws in the 501FD2 fleet through multiple safety and technical alerts d/b/a Energy NV
16 Nevada Power Company Company Power Nevada regarding issues with their exhaust system design. 17 and SierraCompany Pacific Power 18 The first major flaw is the exhaust cylinder. The exhaust cylinder is a 19 stationary section after the turbine blades that supports the turbine shaft 20 bearing assembly and protects it from hot exhaust gases as they flow into 21 the HRSG. Original 501FD2 exhaust cylinders eventually develop severe 22 cracks that result in hot exhaust gases entering the bearing cavity during 23 operation which causes the bearing to overheat. Additionally, exhaust 24 cylinder cracks can cause it to physically drop elevation resulting in 25 misloading of the turbine bearing which can cause vibration issues and 26 result in inoperability. 27
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1 The second flaw involves the turbine exhaust manifold. The exhaust 2 manifold is a stationary section of the exhaust duct that contains the 3 exhaust expansion joint and encloses the hot exhaust gasses exiting the 4 turbine as it flows into the HRSG. Exhaust gases overheat the exhaust 5 expansion joint causing it to crack. This results in exhaust gases leaking to 6 the outside of the exhaust system prior to entering the HRSG resulting in 7 extensive safety and environmental issues. 8
9 This project includes the replacement of the turbine exhaust cylinder, the 10 turbine exhaust manifold, and the exhaust expansion joint on Higgins CT1.
11 The Company has previously replaced the exhaust systems on Silverhawk
12 CTA, Silverhawk CTB, and Higgins CT2.
13
14 222. Q. NRS 704.110(4) STATES THAT AN ITEM INCLUDED IN THE 15 EXPECTED CHANGE IN CIRCUMSTANCE PERIOD MUST BE d/b/a Energy NV
16 Nevada Power Company Company Power Nevada “REASONABLY KNOWN AND MEASUREABLE WITH 17
and SierraCompany Pacific Power REASONABLE ACCURACY.” ARE THE EXPECTED COSTS OF 18 THE CT1 EXHAUST REPLACEMENT PROJECT 19 “REASONABLY KNOWN AND MEASURABLE WITH
20 REASONABLE ACCURACY” AS OF THE DATE YOUR 21 TESTIMONY IS BEING PREPARED? 22 A. Yes. The project was planned to be completed in the spring of 2020. 23 Contracts were bid and executed to complete the work. Additionally, the 24 Company has previously replaced the exhaust systems on Silverhawk 25 CTA, Silverhawk CTB, and Higgins CT2. 26 27
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1 223. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 2 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 3 AND MEASURABLE WITH REASONABLE ACCURACY IF, 4 AMONG OTHER THINGS, IT CONSISTS OF SPECIFIC AND 5 IDENTIFIABLE EVENTS OR PROGRAMS RATHER THAN 6 GENERAL TRENDS, PATTERNS OR DEVELOPMENTS. DOES 7 THE CT1 EXHAUST REPLACEMENT PROJECT MEET THAT 8 CRITERION? 9 A. Yes. The project scope to replace the CT1 Exhaust includes the purchase 10 and installation of equipment based on contract purchase orders and
11 detailed delivery schedules and cannot be characterized as a general trend,
12 pattern or development.
13
14 224. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 15 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN d/b/a Energy NV
16 Nevada Power Company Company Power Nevada AND MEASURABLE WITH REASONABLE ACCURACY IF, 17
and SierraCompany Pacific Power AMONG OTHER THINGS, IT HAS AN OBJECTIVELY HIGH 18 PROBABILITY OF OCCURRING TO THE DEGREE, IN THE 19 AMOUNT AND AT THE TIME EXPECTED. DOES THE CT1
20 EXHAUST REPLACEMENT PROJECT MEET THAT 21 CRITERION? 22 A. Yes. Revised production and installation schedules provided by all 23 vendors demonstrate completion of the installation during the fall 2020 24 outage that will begin on October 1, 2020, and will end on December 5, 25 2020. 26 27
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1 225. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 2 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 3 AND MEASURABLE WITH REASONABLE ACCURACY IF, 4 AMONG OTHER THINGS, IT IS PRIMARILY MEASUREABLE 5 BY RECORDED OR VERIFIABLE REVENUES AND EXPENSES 6 AND IS EASILY AND OBJECTIVELY CALCULATED, WITH 7 THE CALCULATION OF THE EXPECTED CHANGES RELYING 8 ONLY SECONDARILY ON ESTIMATES, FORECASTS, 9 PROJECTIONS OR BUDGETS. DOES THE CT1 EXHAUST 10 REPLACEMENT PROJECT MEET THAT CRITERION?
11 A. Yes. All of the project costs related to the installation of the CT1 Exhaust
12 System replacement currently verifiable and recorded in the contracts and
13 purchase orders, as set forth above. Additionally, the Company has 14 previously replaced the exhaust systems on Silverhawk CTA, Silverhawk 15 CTB, and Higgins CT2. d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 17 and SierraCompany Pacific Power 226. Q. PLEASE SUMMARIZE WHY THE CT1 EXHAUST 18 REPLACEMENT PROJECT MEETS THE CRITERIA SPECIFIED 19 IN NRS 704.110(4) AS AN EXPECTED CHANGE THAT IS
20 REASONABLY KNOWN AND MEASURABLE WITH 21 REASONABLE ACCURACY. 22 A. The CT1 Exhaust System replacement project constitutes a specific and 23 identifiable event, these events have an objectively high probability of 24 occurring to the degree, in the amount and at the time expected, and their 25 costs are currently measurable by recorded and verifiable expenses that 26 are easily and objectively calculated. 27
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1 227. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHOULD 2 CONSIDER “REASONABLE PROJECTED OR FORECASTED 3 OFFSETS IN REVENUE AND EXPENSES THAT ARE DIRECTLY 4 ATTRIBUTABLE TO OR ASSOCIATED WITH THE EXPECTED 5 CHANGES IN CIRCUMSTANCES UNDER CONSIDERATION.” 6 ARE THERE ANY OFFSETS ASSOCIATED WITH THE CT1 7 EXHAUST REPLACEMENT PROJECT? 8 A. The Company has not identified any reasonable projected or forecasted 9 offsets in revenues or expenses that are directly attributable to or 10 associated with these expected changes in circumstances.
11
12 228. Q. WHY SHOULD THIS PROJECT BE CONSIDERED FOR ECIC?
13 A. The project was planned to be completed in the spring of 2020. However, 14 due to the COVID-19 pandemic, the project is delayed until the fall of 15 2020. The project is essential to maintain the reliability of the generating d/b/a Energy NV
16 Nevada Power Company Company Power Nevada unit and further delay of the project increases the risk of catastrophic 17 failure. and SierraCompany Pacific Power 18
19 229. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 20 A. The estimated plant addition for this project is $2,661,884 including 21 AFUDC. 22
23 H. WH2071 STEAM TURBINE GENERATOR WINDING, PURCHASE 24 230. Q. PLEASE DESCRIBE THE PROJECT. 25 A. This project is to purchase the components for, and execute, a rewind of 26 the Steam Turbine generator at Walter Higgins. The station's Steam 27 Turbine generator has historically had continuous high frame vibrations
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1 since its commercial operation in February 2004. Due to these high 2 vibrations in the generator, the winding insulation systems are failing 3 sooner than expected. Capital project WH1066 was created to rewind the 4 generator in 2024. This project, WH2071, was initially started in March 5 2019 to procure all of the rewind components due to the long lead time 6 associated with replacement stator bars. The winding materials including 7 stator bars, rewind kit, and associated components required to perform a 8 generator rewind. The scope of this project has been updated to include
9 the execution of the rewind. 10
11 231. Q. NRS 704.110(4) STATES THAT AN ITEM INCLUDED IN THE
12 EXPECTED CHANGE IN CIRCUMSTANCE PERIOD MUST BE
13 “REASONABLY KNOWN AND MEASUREABLE WITH 14 REASONABLE ACCURACY.” ARE THE EXPECTED COSTS OF 15 THE STEAM TURBINE GENERATOR REWIND PROJECT d/b/a Energy NV
16 Nevada Power Company Company Power Nevada “REASONABLY KNOWN AND MEASURABLE WITH 17
and SierraCompany Pacific Power REASONABLE ACCURACY” AS OF THE DATE YOUR 18 TESTIMONY IS BEING PREPARED? 19 A. Yes. The project was planned to be completed in the spring of 2020. 20 Contracts were bid and executed to complete the work
21
22 232. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 23 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 24 AND MEASURABLE WITH REASONABLE ACCURACY IF, 25 AMONG OTHER THINGS, IT CONSISTS OF SPECIFIC AND 26 IDENTIFIABLE EVENTS OR PROGRAMS RATHER THAN 27 GENERAL TRENDS, PATTERNS OR DEVELOPMENTS. DOES
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1 THE STEAM TURBINE GENERATOR REWIND PROJECT 2 MEET THAT CRITERION? 3 A. Yes. The project scope to rewind the steam turbine generator includes the 4 purchase and installation of equipment based on contract purchase orders 5 and detailed delivery schedules and cannot be characterized as a general 6 trend, pattern or development. 7
8 233. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 9 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 10 AND MEASURABLE WITH REASONABLE ACCURACY IF,
11 AMONG OTHER THINGS, IT HAS AN OBJECTIVELY HIGH
12 PROBABILITY OF OCCURRING TO THE DEGREE, IN THE
13 AMOUNT AND AT THE TIME EXPECTED. DOES THE STEAM 14 TURBINE GENERATOR REWIND PROJECT MEET THAT 15 CRITERION? d/b/a Energy NV
16 Nevada Power Company Company Power Nevada A. Yes. Revised production and installation schedules provided by all 17 vendors demonstrate completion of the installation during the fall 2020 and SierraCompany Pacific Power 18 outage that will begin on October 1, 2020, and will end on December 5, 19 2020. 20
21 234. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 22 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 23 AND MEASURABLE WITH REASONABLE ACCURACY IF, 24 AMONG OTHER THINGS, IT IS PRIMARILY MEASUREABLE 25 BY RECORDED OR VERIFIABLE REVENUES AND EXPENSES 26 AND IS EASILY AND OBJECTIVELY CALCULATED, WITH 27 THE CALCULATION OF THE EXPECTED CHANGES RELYING
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1 ONLY SECONDARILY ON ESTIMATES, FORECASTS, 2 PROJECTIONS OR BUDGETS. DOES THE STEAM TURBINE 3 GENERATOR REWIND PROJECT MEET THAT CRITERION? 4 A. Yes. All of the project costs related to the rewind of the steam turbine 5 generator are currently verifiable and recorded in the contracts and 6 purchase orders, as set forth above. 7
8 235. Q. PLEASE SUMMARIZE WHY THE STEAM TURBINE 9 GENERATOR REWIND PROJECT MEETS THE CRITERIA 10 SPECIFIED IN NRS 704.110(4) AS AN EXPECTED CHANGE
11 THAT IS REASONABLY KNOWN AND MEASURABLE WITH
12 REASONABLE ACCURACY.
13 A. The steam turbine generator rewind project constitutes a specific and 14 identifiable event, these events have an objectively high probability of 15 occurring to the degree, in the amount and at the time expected, and their d/b/a Energy NV
16 Nevada Power Company Company Power Nevada costs are currently measurable by recorded and verifiable expenses that 17 are easily and objectively calculated. and SierraCompany Pacific Power 18
19 236. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHOULD 20 CONSIDER “REASONABLE PROJECTED OR FORECASTED 21 OFFSETS IN REVENUE AND EXPENSES THAT ARE DIRECTLY 22 ATTRIBUTABLE TO OR ASSOCIATED WITH THE EXPECTED 23 CHANGES IN CIRCUMSTANCES UNDER CONSIDERATION.” 24 ARE THERE ANY OFFSETS ASSOCIATED WITH THE STEAM 25 TURBINE GENERATOR REWIND PROJECT? 26 27
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1 A. The Company has not identified any reasonable projected or forecasted 2 offsets in revenues or expenses that are directly attributable to or 3 associated with these expected changes in circumstances. 4
5 237. Q. WHY SHOULD THIS PROJECT BE CONSIDERED FOR ECIC? 6 A. The project was planned to be completed in the spring of 2020. However, 7 due to the COVID-19 pandemic, the project is delayed until the fall of 8 2020. The project is essential to maintain the reliability of the generating
9 unit and further delay of the project increases the risk of catastrophic 10 failure.
11
12 238. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT?
13 A. The estimated plant addition for this project is $6,314,332 including 14 AFUDC. 15 d/b/a Energy NV
16 NDERGROUND IPING EPLACE Nevada Power Company Company Power Nevada I. WH2123 U P , R 17 and SierraCompany Pacific Power 239. Q. PLEASE DESCRIBE THE PROJECT. 18 The scope of this project is to replace the underground water piping routed 19 under the Water Treatment Building and between the two adjoining water 20 tanks at Walter Higgins. This piping system is comprised of metallic and 21 non-metallic piping. The station’s metallic underground utilities were not 22 installed with cathodic protection to mitigate their degradation upon the 23 direct burial in the native soil. The non-metallic underground utilities have 24 experienced multiple failures that are primarily attributed to seam failures 25 or poor backfill practices during original construction. The station has 26 been performing emergency repairs of the continuous leaking pipes for 27
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1 several years. This has disrupted the station's reliability and is regarded as 2 an environmental issue due to the underground process water leaks. 3 4 This project will abandon the underground piping under the Water 5 Treatment building and between the adjoining water tanks. The 6 replacement piping will be routed above grade within the Water Treatment 7 building, above grade in areas around the tanks, and reinstalled in a 8 subgrade concrete trench in traffic areas. The station replaced and
9 relocated the piping for the underground Service Air, Service Water, Fire 10 Protection, Demineralized Water, and Waste Water systems within this
11 area. This project will mitigate the continuous underground leaks that were
12 impacting the foundations of the Water Treatment’s building and
13 adjoining tanks, mitigate future underground failures from these pipes, and 14 provide station reliability. 15 d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 240. Q. NRS 704.110(4) STATES THAT AN ITEM INCLUDED IN THE 17
and SierraCompany Pacific Power EXPECTED CHANGE IN CIRCUMSTANCE PERIOD MUST BE 18 “REASONABLY KNOWN AND MEASUREABLE WITH 19 REASONABLE ACCURACY.” ARE THE EXPECTED COSTS OF
20 THE UNDERGROUND PIPING REPLACEMENT PROJECT 21 “REASONABLY KNOWN AND MEASURABLE WITH 22 REASONABLE ACCURACY” AS OF THE DATE YOUR 23 TESTIMONY IS BEING PREPARED? 24 A. Yes. The project was planned to be completed in the spring of 2020. 25 Contracts were bid and executed to complete the work. 26 27
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1 241. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 2 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 3 AND MEASURABLE WITH REASONABLE ACCURACY IF, 4 AMONG OTHER THINGS, IT CONSISTS OF SPECIFIC AND 5 IDENTIFIABLE EVENTS OR PROGRAMS RATHER THAN 6 GENERAL TRENDS, PATTERNS OR DEVELOPMENTS. DOES 7 THE UNDERGROUND PIPING REPLACEMENT PROJECT 8 MEET THAT CRITERION? 9 A. Yes. The project scope to replace the underground piping includes the 10 purchase and installation of equipment based on contract purchase orders
11 and detailed delivery schedules and cannot be characterized as a general
12 trend, pattern or development.
13
14 242. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 15 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN d/b/a Energy NV
16 Nevada Power Company Company Power Nevada AND MEASURABLE WITH REASONABLE ACCURACY IF, 17
and SierraCompany Pacific Power AMONG OTHER THINGS, IT HAS AN OBJECTIVELY HIGH 18 PROBABILITY OF OCCURRING TO THE DEGREE, IN THE 19 AMOUNT AND AT THE TIME EXPECTED. DOES THE
20 UNDERGROUND PIPING REPLACEMENT PROJECT MEET 21 THAT CRITERION? 22 A. Yes. Revised production and installation schedules provided by all 23 vendors demonstrate completion of the installation during the fall 2020 24 outage that will begin on October 1, 2020, and will end on December 5, 25 2020. 26 27
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1 243. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 2 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 3 AND MEASURABLE WITH REASONABLE ACCURACY IF, 4 AMONG OTHER THINGS, IT IS PRIMARILY MEASUREABLE 5 BY RECORDED OR VERIFIABLE REVENUES AND EXPENSES 6 AND IS EASILY AND OBJECTIVELY CALCULATED, WITH 7 THE CALCULATION OF THE EXPECTED CHANGES RELYING 8 ONLY SECONDARILY ON ESTIMATES, FORECASTS, 9 PROJECTIONS OR BUDGETS. DOES THE UNDERGROUND 10 PIPING REPLACEMENT PROJECT MEET THAT CRITERION?
11 A. Yes. All of the project costs related to the installation of the underground
12 piping replacement currently verifiable and recorded in the contracts and
13 purchase orders, as set forth above. 14
15 244. Q. PLEASE SUMMARIZE WHY THE UNDERGROUND PIPING d/b/a Energy NV
16 Nevada Power Company Company Power Nevada REPLACEMENT PROJECT MEETS THE CRITERIA SPECIFIED 17
and SierraCompany Pacific Power IN NRS 704.110(4) AS AN EXPECTED CHANGE THAT IS 18 REASONABLY KNOWN AND MEASURABLE WITH 19 REASONABLE ACCURACY. 20 A. The underground piping replacement project constitutes a specific and 21 identifiable event, these events have an objectively high probability of 22 occurring to the degree, in the amount and at the time expected, and their 23 costs are currently measurable by recorded and verifiable expenses that 24 are easily and objectively calculated. 25 26 27
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1 245. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHOULD 2 CONSIDER “REASONABLE PROJECTED OR FORECASTED 3 OFFSETS IN REVENUE AND EXPENSES THAT ARE DIRECTLY 4 ATTRIBUTABLE TO OR ASSOCIATED WITH THE EXPECTED 5 CHANGES IN CIRCUMSTANCES UNDER CONSIDERATION.” 6 ARE THERE ANY OFFSETS ASSOCIATED WITH THE 7 UNDERGROUND PIPING REPLACEMENT PROJECT? 8 A. The Company has not identified any reasonable projected or forecasted 9 offsets in revenues or expenses that are directly attributable to or 10 associated with these expected changes in circumstances.
11
12 246. Q. WHY SHOULD THIS PROJECT BE CONSIDERED FOR ECIC?
13 A. The project was planned to be completed in the spring of 2020. However, 14 due to the COVID-19 pandemic, the project is delayed until the fall of 15 2020. The project is essential to maintain the reliability of the generating d/b/a Energy NV
16 Nevada Power Company Company Power Nevada unit and further delay of the project increases the risk of catastrophic 17 failure. and SierraCompany Pacific Power 18
19 247. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 20 A. The estimated plant addition for this project is $1,867,880 including 21 AFUDC. 22
23 J. WH2136 & WH2137 NP 17 MW 501F 24 248. Q. PLEASE DESCRIBE THE PROJECT. 25 A. These projects are for the installation of upgrades to the two Walter 26 Higgins combustion turbines in order to increase the station’s overall 27 generating capacity, provide operational flexibility and improve plant
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1 efficiency. These upgrades replace turbine section components to increase 2 unit capacity, replace some compressor components to increase airflow 3 through the machine, and install inlet bleed heat to allow the units to turn 4 down further. As a result, these upgrades will allow the CTs to generate 5 additional megawatts during times of the peak summer operating months, 6 improve machine heat rates throughout the entire operating range, and 7 allow the unit to turn down further in support of renewable generation. 8 These components also allow the turbine maintenance intervals to be
9 extended from 25,000 operating hours to 32,000. 10
11 249. Q. NRS 704.110(4) STATES THAT AN ITEM INCLUDED IN THE
12 EXPECTED CHANGE IN CIRCUMSTANCE PERIOD MUST BE
13 “REASONABLY KNOWN AND MEASUREABLE WITH 14 REASONABLE ACCURACY.” ARE THE EXPECTED COSTS OF 15 THE CT UPGRADE PROJECT “REASONABLY KNOWN AND d/b/a Energy NV
16 Nevada Power Company Company Power Nevada MEASURABLE WITH REASONABLE ACCURACY” AS OF THE 17
and SierraCompany Pacific Power DATE YOUR TESTIMONY IS BEING PREPARED? 18 A. Yes. The project was planned to be completed in the spring of 2020. 19 Contracts were bid and executed to complete the work. 20
21 250. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 22 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 23 AND MEASURABLE WITH REASONABLE ACCURACY IF, 24 AMONG OTHER THINGS, IT CONSISTS OF SPECIFIC AND 25 IDENTIFIABLE EVENTS OR PROGRAMS RATHER THAN 26 GENERAL TRENDS, PATTERNS OR DEVELOPMENTS. DOES 27 THE CT UPGRADE PROJECT MEET THAT CRITERION?
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1 A. Yes. The project scope to upgrade the CTs includes the purchase and 2 installation of equipment based on contract purchase orders and detailed 3 delivery schedules and cannot be characterized as a general trend, pattern 4 or development. 5
6 251. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 7 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 8 AND MEASURABLE WITH REASONABLE ACCURACY IF, 9 AMONG OTHER THINGS, IT HAS AN OBJECTIVELY HIGH 10 PROBABILITY OF OCCURRING TO THE DEGREE, IN THE
11 AMOUNT AND AT THE TIME EXPECTED. DOES THE CT
12 UPGRADE PROJECT MEET THAT CRITERION?
13 A. Yes. Revised production and installation schedules provided by all 14 vendors demonstrate completion of the installation during the fall 2020 15 outage that will begin on October 1, 2020, and will end on December 5, d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 2020. 17 and SierraCompany Pacific Power
18 252. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 19 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN
20 AND MEASURABLE WITH REASONABLE ACCURACY IF, 21 AMONG OTHER THINGS, IT IS PRIMARILY MEASUREABLE 22 BY RECORDED OR VERIFIABLE REVENUES AND EXPENSES 23 AND IS EASILY AND OBJECTIVELY CALCULATED, WITH 24 THE CALCULATION OF THE EXPECTED CHANGES RELYING 25 ONLY SECONDARILY ON ESTIMATES, FORECASTS, 26 PROJECTIONS OR BUDGETS. DOES THE CT UPGRADE 27 PROJECT MEET THAT CRITERION?
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1 A. Yes. All of the project costs related to the installation of the CT upgrades 2 currently verifiable and recorded in the contracts and purchase orders, as 3 set forth above. 4
5 253. Q. PLEASE SUMMARIZE WHY THE CT UPGRADE PROJECT 6 MEETS THE CRITERIA SPECIFIED IN NRS 704.110(4) AS AN 7 EXPECTED CHANGE THAT IS REASONABLY KNOWN AND 8 MEASURABLE WITH REASONABLE ACCURACY. 9 A. The CT upgrade project constitutes a specific and identifiable event, these 10 events have an objectively high probability of occurring to the degree, in
11 the amount and at the time expected, and their costs are currently
12 measurable by recorded and verifiable expenses that are easily and
13 objectively calculated. 14
15 254. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHOULD d/b/a Energy NV
16 Nevada Power Company Company Power Nevada CONSIDER “REASONABLE PROJECTED OR FORECASTED 17
and SierraCompany Pacific Power OFFSETS IN REVENUE AND EXPENSES THAT ARE DIRECTLY 18 ATTRIBUTABLE TO OR ASSOCIATED WITH THE EXPECTED 19 CHANGES IN CIRCUMSTANCES UNDER CONSIDERATION.”
20 ARE THERE ANY OFFSETS ASSOCIATED WITH THE CT 21 UPGRADE PROJECT? 22 A. The Company has not identified any reasonable projected or forecasted 23 offsets in revenues or expenses that are directly attributable to or 24 associated with these expected changes in circumstances. 25 26 27
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1 255. Q. WHY SHOULD THIS PROJECT BE CONSIDERED FOR ECIC? 2 A. The project was planned to be completed in the spring of 2020. However, 3 due to the COVID-19 pandemic, the project is delayed until the fall of 4 2020. The project is essential to maintain the reliability of the generating 5 unit and further delay of the project increases the risk of catastrophic 6 failure. 7
8 256. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 9 A. The estimated plant addition for both projects is $20,128,297, including 10 AFUDC. The estimated plant addition for WH2136 is $10,064,149,
11 including AFUDC. The estimated plant addition for WH2137 is
12 $10,064,149, including AFUDC.
13
14 K. WH2147 CT COMPONENT PART, REPLACE 15 257. Q. PLEASE DESCRIBE THE PROJECT. d/b/a Energy NV
16 Nevada Power Company Company Power Nevada A. This project includes the replacement of row 7 compressor blades, 17 compressor diaphragms, belly bands and other associated parts in CT1 at and SierraCompany Pacific Power 18 Walter Higgins. During a routine borescope inspection in January 2018, 19 compressor damage was found in CT1. The root cause of this compressor 20 damage was found to be two liberated horizontal joint dowel pins. Interim 21 repairs were made at the time in order to enable the unit to be returned to 22 service. In order to mitigate a catastrophic combustion turbine failure, the 23 affected compressor blades, adjoining compressor diaphragms, and belly 24 bands will be replaced in this project. 25 26 27
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1 258. Q. NRS 704.110(4) STATES THAT AN ITEM INCLUDED IN THE 2 EXPECTED CHANGE IN CIRCUMSTANCE PERIOD MUST BE 3 “REASONABLY KNOWN AND MEASUREABLE WITH 4 REASONABLE ACCURACY.” ARE THE EXPECTED COSTS OF 5 THE CT COMPONENT REPLACEMENT PROJECT 6 “REASONABLY KNOWN AND MEASURABLE WITH 7 REASONABLE ACCURACY” AS OF THE DATE YOUR 8 TESTIMONY IS BEING PREPARED? 9 A. Yes. The project was planned to be completed in the spring of 2020. 10 Contracts were bid and executed to complete the work.
11
12 259. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND
13 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 14 AND MEASURABLE WITH REASONABLE ACCURACY IF, 15 AMONG OTHER THINGS, IT CONSISTS OF SPECIFIC AND d/b/a Energy NV
16 Nevada Power Company Company Power Nevada IDENTIFIABLE EVENTS OR PROGRAMS RATHER THAN 17
and SierraCompany Pacific Power GENERAL TRENDS, PATTERNS OR DEVELOPMENTS. DOES 18 THE CT COMPONENT REPLACEMENT PROJECT MEET 19 THAT CRITERION?
20
21 A. Yes. The project scope to replace the CT components includes the 22 purchase and installation of equipment based on contract purchase orders 23 and detailed delivery schedules and cannot be characterized as a general 24 trend, pattern or development.
25
26 27
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1 260. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 2 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 3 AND MEASURABLE WITH REASONABLE ACCURACY IF, 4 AMONG OTHER THINGS, IT HAS AN OBJECTIVELY HIGH 5 PROBABILITY OF OCCURRING TO THE DEGREE, IN THE 6 AMOUNT AND AT THE TIME EXPECTED. DOES THE CT 7 COMPONENT REPLACEMENT PROJECT MEET THAT 8 CRITERION? 9 A. Yes. Revised production and installation schedules provided by all 10 vendors demonstrate completion of the installation during the fall 2020
11 outage that will begin on October 1, 2020, and will end on December 5,
12 2020.
13
14 261. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 15 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN d/b/a Energy NV
16 Nevada Power Company Company Power Nevada AND MEASURABLE WITH REASONABLE ACCURACY IF, 17
and SierraCompany Pacific Power AMONG OTHER THINGS, IT IS PRIMARILY MEASUREABLE 18 BY RECORDED OR VERIFIABLE REVENUES AND EXPENSES 19 AND IS EASILY AND OBJECTIVELY CALCULATED, WITH
20 THE CALCULATION OF THE EXPECTED CHANGES RELYING 21 ONLY SECONDARILY ON ESTIMATES, FORECASTS, 22 PROJECTIONS OR BUDGETS. DOES THE CT COMPONENT 23 REPLACEMENT PROJECT MEET THAT CRITERION? 24 A. Yes. All of the project costs related to the replacement of the CT 25 components currently verifiable and recorded in the contracts and 26 purchase orders, as set forth above. 27
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1 262. Q. PLEASE SUMMARIZE WHY THE CT COMPONENT 2 REPLACEMENT PROJECT MEETS THE CRITERIA SPECIFIED 3 IN NRS 704.110(4) AS AN EXPECTED CHANGE THAT IS 4 REASONABLY KNOWN AND MEASURABLE WITH 5 REASONABLE ACCURACY. 6 A. The CT component replacement project constitutes a specific and 7 identifiable event, these events have an objectively high probability of 8 occurring to the degree, in the amount and at the time expected, and their
9 costs are currently measurable by recorded and verifiable expenses that 10 are easily and objectively calculated.
11
12 263. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHOULD
13 CONSIDER “REASONABLE PROJECTED OR FORECASTED 14 OFFSETS IN REVENUE AND EXPENSES THAT ARE DIRECTLY 15 ATTRIBUTABLE TO OR ASSOCIATED WITH THE EXPECTED d/b/a Energy NV
16 Nevada Power Company Company Power Nevada CHANGES IN CIRCUMSTANCES UNDER CONSIDERATION.” 17
and SierraCompany Pacific Power ARE THERE ANY OFFSETS ASSOCIATED WITH THE CT 18 COMPONENT REPLACEMENT PROJECT? 19 A. The Company has not identified any reasonable projected or forecasted 20 offsets in revenues or expenses that are directly attributable to or 21 associated with these expected changes in circumstances. 22
23 264. Q. WHY SHOULD THIS PROJECT BE CONSIDERED FOR ECIC? 24 A. The project was planned to be completed in the spring of 2020. However, 25 due to the COVID-19 pandemic, the project is delayed until the fall of 26 2020. The project is essential to maintain the reliability of the generating 27
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1 unit and further delay of the project increases the risk of catastrophic 2 failure. 3
4 265. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 5 A. The initial estimated plant addition for this project was $2,311,491 6 including AFUDC. Updated estimates were available after the schedules 7 were completed and, at the time, the current estimate for this project was 8 $3,295,357. The cost information will be updated in the Certification
9 filing in this Docket. 10
11 L. WH2149 WHC COLD REHEAT PIPING, REPLACE
12 266. Q. PLEASE DESCRIBE THE PROJECT.
13 A. The scope of this project is to replace the Unit 2 Cold Reheat (“CR”) steam 14 piping that directly interfaces with the Main Steam pipe and the Unit 2 15 HRSG. The Unit 2 CR steam piping has incurred multiple failures due to d/b/a Energy NV
16 Nevada Power Company Company Power Nevada wall cracks, fissures, and/or leaks since 2011. An engineering assessment 17 concluded that it would be prudent for the Company to have the entire Unit and SierraCompany Pacific Power 18 2 CR steam pipe replaced in order to preclude a catastrophic failure. The 19 CR piping is comprised of multiple large diameter piping sections, three 20 types of piping materials, and has a design pressure rating of 700 psig and 21 a design temperature rating of 932 degrees F. 22 The Company has contracted a Contractor to remove and replace 23 approximately 158 feet total of the Unit 2 CR piping; 128 feet that 24 connects to the Main Steam pipe to the common CR piping header; and 25 the 30-foot branch line to the Unit 2 HRSG. The Contractor is required to 26 ensure the pipe is sloped per the design, all instrumentation is reinstalled, 27
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1 the pipe supports are reinstalled, x-ray all welds made, and reset per the 2 design criteria, and the pipe is reinsulated. 3
4 267. Q. NRS 704.110(4) STATES THAT AN ITEM INCLUDED IN THE 5 EXPECTED CHANGE IN CIRCUMSTANCE PERIOD MUST BE 6 “REASONABLY KNOWN AND MEASUREABLE WITH 7 REASONABLE ACCURACY.” ARE THE EXPECTED COSTS OF 8 THE COLD REHEAT PIPING REPLACEMENT PROJECT 9 “REASONABLY KNOWN AND MEASURABLE WITH 10 REASONABLE ACCURACY” AS OF THE DATE YOUR
11 TESTIMONY IS BEING PREPARED?
12 A. Yes. The project was planned to be completed in the spring of 2020.
13 Contracts were bid and executed to complete the work. 14
15 268. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND d/b/a Energy NV
16 Nevada Power Company Company Power Nevada THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 17
and SierraCompany Pacific Power AND MEASURABLE WITH REASONABLE ACCURACY IF, 18 AMONG OTHER THINGS, IT CONSISTS OF SPECIFIC AND 19 IDENTIFIABLE EVENTS OR PROGRAMS RATHER THAN
20 GENERAL TRENDS, PATTERNS OR DEVELOPMENTS. DOES 21 THE COLD REHEAT PIPING REPLACEMENT PROJECT MEET 22 THAT CRITERION? 23 A. Yes. The project scope to replace the cold reheat piping includes the 24 purchase and installation of equipment based on contract purchase orders 25 and detailed delivery schedules and cannot be characterized as a general 26 trend, pattern or development.
27
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1 269. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 2 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 3 AND MEASURABLE WITH REASONABLE ACCURACY IF, 4 AMONG OTHER THINGS, IT HAS AN OBJECTIVELY HIGH 5 PROBABILITY OF OCCURRING TO THE DEGREE, IN THE 6 AMOUNT AND AT THE TIME EXPECTED. DOES THE COLD 7 REHEAT PIPING REPLACEMENT PROJECT MEET THAT 8 CRITERION? 9 A. Yes. Revised production and installation schedules provided by all 10 vendors demonstrate completion of the installation during the fall 2020
11 outage that will begin on October 1, 2020, and will end on December 5,
12 2020.
13
14 270. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 15 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN d/b/a Energy NV
16 Nevada Power Company Company Power Nevada AND MEASURABLE WITH REASONABLE ACCURACY IF, 17
and SierraCompany Pacific Power AMONG OTHER THINGS, IT IS PRIMARILY MEASUREABLE 18 BY RECORDED OR VERIFIABLE REVENUES AND EXPENSES 19 AND IS EASILY AND OBJECTIVELY CALCULATED, WITH
20 THE CALCULATION OF THE EXPECTED CHANGES RELYING 21 ONLY SECONDARILY ON ESTIMATES, FORECASTS, 22 PROJECTIONS OR BUDGETS. DOES THE COLD REHEAT 23 PIPING REPLACEMENT PROJECT MEET THAT CRITERION? 24 A. Yes. All of the project costs related to the installation of the cold reheat 25 piping replacement currently verifiable and recorded in the contracts and 26 purchase orders, as set forth above. 27
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1 271. Q. PLEASE SUMMARIZE WHY THE COLD REHEAT PIPING 2 REPLACEMENT PROJECT MEETS THE CRITERIA SPECIFIED 3 IN NRS 704.110(4) AS AN EXPECTED CHANGE THAT IS 4 REASONABLY KNOWN AND MEASURABLE WITH 5 REASONABLE ACCURACY. 6 A. The cold reheat piping replacement project constitutes a specific and 7 identifiable event, these events have an objectively high probability of 8 occurring to the degree, in the amount and at the time expected, and their
9 costs are currently measurable by recorded and verifiable expenses that 10 are easily and objectively calculated.
11
12 272. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHOULD
13 CONSIDER “REASONABLE PROJECTED OR FORECASTED 14 OFFSETS IN REVENUE AND EXPENSES THAT ARE DIRECTLY 15 ATTRIBUTABLE TO OR ASSOCIATED WITH THE EXPECTED d/b/a Energy NV
16 Nevada Power Company Company Power Nevada CHANGES IN CIRCUMSTANCES UNDER CONSIDERATION.” 17
and SierraCompany Pacific Power ARE THERE ANY OFFSETS ASSOCIATED WITH THE COLD 18 REHEAT PIPING REPLACEMENT PROJECT? 19 A. The Company has not identified any reasonable projected or forecasted 20 offsets in revenues or expenses that are directly attributable to or 21 associated with these expected changes in circumstances. 22
23 273. Q. WHY SHOULD THIS PROJECT BE CONSIDERED FOR ECIC? 24 A. The project was planned to be completed in the spring of 2020. However, 25 due to the COVID-19 pandemic, the project is delayed until the fall of 26 2020. The project is essential to maintain the reliability of the generating 27
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1 unit and further delay of the project increases the risk of catastrophic 2 failure. 3
4 274. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT? 5 A. The initial estimated plant addition for this project was $939,722 including 6 AFUDC. This estimate was an engineering-only estimate. Updated 7 estimates were available after the schedules were completed and, at the 8 time, the current estimate for this project was $927,536. The cost
9 information will be updated in the Certification filing in this Docket.
10
11 M. WH2131 AND WH2132 MAIN STEAM BLOCK VALVE REPLACEMENT
12 275. Q. PLEASE DESCRIBE THE MAIN STEAM BLOCK VALVE
13 REPLACEMENT PROJECTS. 14 The Main Steam Block valves are leaking through internally (leak by) and 15 are required to be replaced. The condition of the valve is affecting d/b/a Energy NV
16 Nevada Power Company Company Power Nevada operation's ability to isolate and control the steam flow from and to the 17 Heat Recovery Steam Generators. The station has been required to revise and SierraCompany Pacific Power 18 its operating sequence in order to operate the station because the valve 19 cannot operate. The valve is rated for a Design Pressure of 2549 psig, a 20 Design Temperature of 1065 ‘F, and is ANSI STD Class 2500 (Seat 21 Material: Stellite). The Main Steam pipe is 12” diameter, and of P91 22 material. The Main Steam Block valve is designed to isolate each Unit 23 from each other during the startup and shutdown operating sequence of 24 each unit in order to protect each HRSG’s internal components (boiler 25 tubes). The Main Steam Block valve is part of the station’s Turbine Water 26 Injection Protection (“TWIP”) system. 27
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1 276. Q. NRS 704.110(4) STATES THAT AN ITEM INCLUDED IN THE 2 EXPECTED CHANGE IN CIRCUMSTANCE PERIOD MUST BE 3 “REASONABLY KNOWN AND MEASUREABLE WITH 4 REASONABLE ACCURACY.” ARE THE EXPECTED COSTS OF 5 THE MAIN STEAM BLOCK VALVE REPLACEMENT 6 PROJECTS “REASONABLY KNOWN AND MEASURABLE 7 WITH REASONABLE ACCURACY” AS OF THE DATE YOUR 8 TESTIMONY IS BEING PREPARED? 9 A. Yes. The projects were planned to be completed in the spring of 2020. 10 Contracts were bid and executed to complete the work.
11
12 277. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND
13 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 14 AND MEASURABLE WITH REASONABLE ACCURACY IF, 15 AMONG OTHER THINGS, IT CONSISTS OF SPECIFIC AND d/b/a Energy NV
16 Nevada Power Company Company Power Nevada IDENTIFIABLE EVENTS OR PROGRAMS RATHER THAN 17
and SierraCompany Pacific Power GENERAL TRENDS, PATTERNS OR DEVELOPMENTS. DO 18 THE MAIN STEAM BLOCK VALVE REPLACEMENT 19 PROJECTS MEET THAT CRITERION? 20 A. Yes. The projects’ scope to replace the main steam shop valves during the 21 Higgins outage includes the purchase and installation of equipment based 22 on contract purchase orders and detailed delivery schedules and cannot be 23 characterized as a general trend, pattern or development.
24
25
26 27
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1 278. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 2 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 3 AND MEASURABLE WITH REASONABLE ACCURACY IF, 4 AMONG OTHER THINGS, IT HAS AN OBJECTIVELY HIGH 5 PROBABILITY OF OCCURRING TO THE DEGREE, IN THE 6 AMOUNT AND AT THE TIME EXPECTED. DO THE MAIN 7 STEAM BLOCK VALVE REPLACEMENT PROJECTS MEET 8 THAT CRITERION? 9 A. Yes. Revised production and installation schedules provided by all 10 vendors demonstrate completion of the installation during the fall 2020
11 outage that will begin on October 1, 2020, and will end on December 5,
12 2020.
13
14 279. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 15 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN d/b/a Energy NV
16 Nevada Power Company Company Power Nevada AND MEASURABLE WITH REASONABLE ACCURACY IF, 17
and SierraCompany Pacific Power AMONG OTHER THINGS, IT IS PRIMARILY MEASUREABLE 18 BY RECORDED OR VERIFIABLE REVENUES AND EXPENSES 19 AND IS EASILY AND OBJECTIVELY CALCULATED, WITH
20 THE CALCULATION OF THE EXPECTED CHANGES RELYING 21 ONLY SECONDARILY ON ESTIMATES, FORECASTS, 22 PROJECTIONS OR BUDGETS. DO THE MAIN STEAM BLOCK 23 VALVE REPLACEMENT PROJECTS MEET THAT 24 CRITERION? 25 A. Yes. Both of the projects’ costs are currently verifiable and recorded in 26 the contracts and purchase orders, as set forth above. 27
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1 280. Q. PLEASE SUMMARIZE WHY THE MAIN STEAM BLOCK 2 VALVE REPLACEMENT PROJECTS MEET THE CRITERIA 3 SPECIFIED IN NRS 704.110(4) AS AN EXPECTED CHANGE 4 THAT IS REASONABLY KNOWN AND MEASURABLE WITH 5 REASONABLE ACCURACY. 6 A. These outage related capital projects constitute a specific and identifiable 7 event, these events have an objectively high probability of occurring to the 8 degree, in the amount and at the time expected, and their costs are currently
9 measurable by recorded and verifiable expenses that are easily and 10 objectively calculated.
11 281. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHOULD
12 CONSIDER “REASONABLE PROJECTED OR FORECASTED
13 OFFSETS IN REVENUE AND EXPENSES THAT ARE DIRECTLY 14 ATTRIBUTABLE TO OR ASSOCIATED WITH THE EXPECTED 15 CHANGES IN CIRCUMSTANCES UNDER CONSIDERATION.” d/b/a Energy NV
16 Nevada Power Company Company Power Nevada ARE THERE ANY OFFSETS ASSOCIATED WITH THE MAIN 17
and SierraCompany Pacific Power STEAM BLOCK VALVE REPLACEMENT PROJECTS? 18 A. The Company has not identified any reasonable projected or forecasted 19 offsets in revenues or expenses that are directly attributable to or 20 associated with these expected changes in circumstances. 21
22 282. Q. WHAT IS THE EXPECTED COST OF THESE PROJECTS? 23 A. The total for these two projects is $894,549, not including AFUDC.
24
25
26
27
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1 N. HIGGINS – OTHER OUTAGE RELATED PROJECTS 2 283. Q. PLEASE DESCRIBE THE PROJECT. 3 A. The Walter Higgins Steam Turbine and combustion turbine outage work 4 noted above are only the large outage capital projects. There are another 5 20 projects that total $2,974,798. These projects are essential and must be 6 completed during the planned outage. A list of these projects is shown in 7 the Table Rekowski-Direct-7.
8 9 TABLE REKOWSKI-DIRECT-7
10 Project ID Description Project Cost
WH1046 WH U1 HRSG HP Valves, Replace $165,968 11 WH2076 WH U2 HRSG HP Valves, Replace $166,919
12 WH2087 WHC Unit 1 HP Feed Water Valves, Replace $280,467
WH2088 WHC Unit 2 HP Feed Water Valves, Replace $279,694 13 WH2090 WH Unit 1 HP IP Drum Continuous Blowdown Valves, Replace $140,703 14 WH2091 WH Unit 2 HP IP Drum Continuous Blowdown Valves, Replace $140,735 WH2092 WH Unit 1 HRSG Drain Valves, Replace $75,289 15 d/b/a Energy NV
WH2093 WH Unit 2 HRSG Drain Valves, Replace $71,007 16 WH2094 WH Unit 1 LP IP Drum Feedwater Flow Control Valves, Replace Nevada Power Company Company Power Nevada $144,014 WH Unit 2 LP IP Drum Feedwater Flow Control Valves, 17 WH2095 and SierraCompany Pacific Power Replace. $145,151 18 WH2098 U1 DeSuperheater Pwr Blk Vlvs, Replace. $124,753 WH2099 U2 DeSuperheater Pwr Blk Vlvs, Replace. $124,727 19 WH2100 WHC Cold Reheat FCV CR-007, Replace $66,261 20 WH2101 WH STG Drain Tank Valves, Replace $65,000 WH2114 WH ST Lube Oil Cooling Valve, Replace $34,015 21 WH2119 WHC General Circuit Breaker (4160v), Replace $53,238 22 WH2127 Vacuum Breaker $47,658 WH2130 HIG CT Upgrades - Environmental Consultant $260,924 23 WH2148 WHS ST Lube Oil, Replace $264,278 24 WH2150 WH2150 WH CT Blade and Support Ring, Replace $464,282 Total Other Outage Related Projects $2,974,798 25 26 27
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1 284. Q. NRS 704.110(4) STATES THAT AN ITEM INCLUDED IN THE 2 EXPECTED CHANGE IN CIRCUMSTANCE PERIOD MUST BE 3 “REASONABLY KNOWN AND MEASUREABLE WITH 4 REASONABLE ACCURACY.” ARE THE EXPECTED COSTS OF 5 THE OTHER OUTAGE RELATED CAPITAL PROJECTS 6 “REASONABLY KNOWN AND MEASURABLE WITH 7 REASONABLE ACCURACY” AS OF THE DATE YOUR 8 TESTIMONY IS BEING PREPARED? 9 A. Yes. The projects were planned to be completed in the spring of 2020. 10 Contracts were bid and executed to complete the work.
11
12 285. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND
13 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 14 AND MEASURABLE WITH REASONABLE ACCURACY IF, 15 AMONG OTHER THINGS, IT CONSISTS OF SPECIFIC AND d/b/a Energy NV
16 Nevada Power Company Company Power Nevada IDENTIFIABLE EVENTS OR PROGRAMS RATHER THAN 17
and SierraCompany Pacific Power GENERAL TRENDS, PATTERNS OR DEVELOPMENTS. DO 18 THE HIGGINS OUTAGE RELATED CAPITAL PROJECTS 19 MEET THAT CRITERION? 20 A. Yes. The projects’ scope to complete necessary equipment replacement 21 during the Higgins outage includes the purchase and installation of 22 equipment based on contract purchase orders and detailed delivery 23 schedules and cannot be characterized as a general trend, pattern or 24 development. 25 26 27
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1 286. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 2 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 3 AND MEASURABLE WITH REASONABLE ACCURACY IF, 4 AMONG OTHER THINGS, IT HAS AN OBJECTIVELY HIGH 5 PROBABILITY OF OCCURRING TO THE DEGREE, IN THE 6 AMOUNT AND AT THE TIME EXPECTED. DO THE HIGGINS 7 OUTAGE RELATED CAPITAL PROJECTS MEET THAT 8 CRITERION? 9 A. Yes. Revised production and installation schedules provided by all 10 vendors demonstrate completion of the installation during the fall 2020
11 outage that will begin on October 1, 2020, and will end on December 5,
12 2020.
13
14 287. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 15 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN d/b/a Energy NV
16 Nevada Power Company Company Power Nevada AND MEASURABLE WITH REASONABLE ACCURACY IF, 17
and SierraCompany Pacific Power AMONG OTHER THINGS, IT IS PRIMARILY MEASUREABLE 18 BY RECORDED OR VERIFIABLE REVENUES AND EXPENSES 19 AND IS EASILY AND OBJECTIVELY CALCULATED, WITH
20 THE CALCULATION OF THE EXPECTED CHANGES RELYING 21 ONLY SECONDARILY ON ESTIMATES, FORECASTS, 22 PROJECTIONS OR BUDGETS. DO THE HIGGINS OUTAGE 23 RELATED CAPITAL PROJECTS MEET THAT CRITERION? 24 A. Yes. All of the project costs related to these outage related capital projects 25 are currently verifiable and recorded in the contracts and purchase orders, 26 as set forth above. 27
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1 288. Q. PLEASE SUMMARIZE WHY THE HIGGINS OUTAGE 2 RELATED CAPITAL PROJECTS MEET THE CRITERIA 3 SPECIFIED IN NRS 704.110(4) AS AN EXPECTED CHANGE 4 THAT IS REASONABLY KNOWN AND MEASURABLE WITH 5 REASONABLE ACCURACY. 6 A. These Higgins outage related capital projects constitute specific and 7 identifiable events, these events have an objectively high probability of 8 occurring to the degree, in the amount and at the time expected, and their
9 costs are currently measurable by recorded and verifiable expenses that 10 are easily and objectively calculated.
11
12 289. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHOULD
13 CONSIDER “REASONABLE PROJECTED OR FORECASTED 14 OFFSETS IN REVENUE AND EXPENSES THAT ARE DIRECTLY 15 ATTRIBUTABLE TO OR ASSOCIATED WITH THE EXPECTED d/b/a Energy NV
16 Nevada Power Company Company Power Nevada CHANGES IN CIRCUMSTANCES UNDER CONSIDERATION.” 17
and SierraCompany Pacific Power ARE THERE ANY OFFSETS ASSOCIATED WITH THE HIGGINS 18 OUTAGE RELATED CAPITAL PROJECTS? 19 A. The Company has not identified any reasonable projected or forecasted 20 offsets in revenues or expenses that are directly attributable to or 21 associated with these expected changes in circumstances. 22
23 290. Q. WHAT IS THE EXPECTED COST OF THESE PROJECTS? 24 A. The individual project costs are included in the Table Rekowski-Direct-7. 25 The total for these 20 projects is $2,974,798, not including AFUDC. Two 26 of these projects (WH2150 and WH2130) were originally listed as a 27
28 Rekowski-DIRECT 140
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1 certification period projects. This will be corrected in the Certification 2 filing in this Docket. 3
4 O. SUN PEAK UNIT 4 OUTAGE 5 291. Q. PLEASE DESCRIBE THE SUN PEAK 4 OUTAGE. 6 A. On May 12, 2020, Sun Peak Unit 4 tripped off-line due to the “Overspeed 7 Protection Bolt” activating after being online for around 4 hours. The 8 turbine speed (RPM) telemetry did not indicate any increase in speed
9 above 3,600 RPM (normal speed). After the unit tripped, an oil leak 10 alongside the shaft seal to gear box was discovered. Following the trip and
11 discovery of the leak, a necessary investigation and inspection ensued.
12 A full borescope inspection and a lube oil analysis were conducted. The
13 results were the following: • The borescope inspection revealed a substantial amount of oil 14 residue in the aft compressor (stage 17 stator Vane, Exit Guide 15 Vanes 1 and 2). Unrelated to the trip there was other major damage d/b/a Energy NV observed within the compressor and combustion section. 16 • Nevada Power Company Company Power Nevada The lube oil analysis showed an elevated concentration of coarse metal iron (particles 20 to 70 microns) indicating gear, carrier or 17 and SierraCompany Pacific Power shaft wear. 18 A Hot Gas Path (HGP) inspection was planned for year 2021, but due to 19 the discovered damage, it was decided that the HGP work would be 20 performed concurrently with the expected repairs. The unit has exceeded 21 the 900 factored starts maintenance interval since the last combustion 22 inspection and the 1,200 factored starts maintenance interval since the last 23 major inspection (which includes the hot gas path (HGP) components) was 24 performed in March 2002. The unit was deemed due for a HGP inspection. 25 26 27
28 Rekowski-DIRECT 141
Page 145 of 278
1 The scope of this project is to re-establish full operation of Sun Peak Unit 2 and perform the scheduled Hot Gas Path Inspection. These project costs 3 will be included in the update to the schedules provided in the certification 4 filing. 5
6 292. Q. NRS 704.110(4) STATES THAT AN ITEM INCLUDED IN THE 7 EXPECTED CHANGE IN CIRCUMSTANCE PERIOD MUST BE 8 “REASONABLY KNOWN AND MEASUREABLE WITH 9 REASONABLE ACCURACY.” ARE THE EXPECTED COSTS OF 10 THE SUN PEAK UNIT 4 OUTAGE “REASONABLY KNOWN AND
11 MEASURABLE WITH REASONABLE ACCURACY” AS OF THE
12 DATE YOUR TESTIMONY IS BEING PREPARED?
13 A. Yes. The outage has already started pursuant to executed contracts and 14 will be completed by June 25, 2020. 15 d/b/a Energy NV
16 Nevada Power Company Company Power Nevada 293. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 17
and SierraCompany Pacific Power THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 18 AND MEASURABLE WITH REASONABLE ACCURACY IF, 19 AMONG OTHER THINGS, IT CONSISTS OF SPECIFIC AND
20 IDENTIFIABLE EVENTS OR PROGRAMS RATHER THAN 21 GENERAL TRENDS, PATTERNS OR DEVELOPMENTS. DO 22 THE MAIN STEAM BLOCK VALVE REPLACEMENT 23 PROJECTS MEET THAT CRITERION? 24 A. Yes. The outage’s scope is based on contract purchase orders and detailed 25 delivery schedules and cannot be characterized as a general trend, pattern 26 or development. 27 28 Rekowski-DIRECT 142
Page 146 of 278
1 294. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 2 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 3 AND MEASURABLE WITH REASONABLE ACCURACY IF, 4 AMONG OTHER THINGS, IT HAS AN OBJECTIVELY HIGH 5 PROBABILITY OF OCCURRING TO THE DEGREE, IN THE 6 AMOUNT AND AT THE TIME EXPECTED. DO THE MAIN 7 STEAM BLOCK VALVE REPLACEMENT PROJECTS MEET 8 THAT CRITERION? 9 A. Yes. The outage has already begun with work underway and will end on 10 June 25, 2020, these outage costs are highly certain. This work is also
11 similar to valve overhauls completed at other generating plants.
12
13 295. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHALL FIND 14 THAT AN EXPECTED CHANGE IS REASONABLY KNOWN 15 AND MEASURABLE WITH REASONABLE ACCURACY IF, d/b/a Energy NV
16 Nevada Power Company Company Power Nevada AMONG OTHER THINGS, IT IS PRIMARILY MEASUREABLE 17
and SierraCompany Pacific Power BY RECORDED OR VERIFIABLE REVENUES AND EXPENSES 18 AND IS EASILY AND OBJECTIVELY CALCULATED, WITH 19 THE CALCULATION OF THE EXPECTED CHANGES RELYING
20 ONLY SECONDARILY ON ESTIMATES, FORECASTS, 21 PROJECTIONS OR BUDGETS. DO THE MAIN STEAM BLOCK 22 VALVE REPLACEMENT PROJECTS MEET THAT 23 CRITERION? 24 A. Yes. The outage costs are currently verifiable and recorded in the 25 contracts and purchase orders associated with the repair work. 26 27
28 Rekowski-DIRECT 143
Page 147 of 278
1 296. Q. PLEASE SUMMARIZE WHY THE MAIN STEAM BLOCK 2 VALVE REPLACEMENT PROJECTS MEET THE CRITERIA 3 SPECIFIED IN NRS 704.110(4) AS AN EXPECTED CHANGE 4 THAT IS REASONABLY KNOWN AND MEASURABLE WITH 5 REASONABLE ACCURACY. 6 A. The outage related capital projects constitute a specific and identifiable 7 event, these events have an objectively high probability of occurring to the 8 degree, in the amount and at the time expected, and their costs are currently
9 measurable by recorded and verifiable expenses that are easily and 10 objectively calculated.
11
12 297. Q. NRS 704.110(4) STATES THAT THE COMMISSION SHOULD
13 CONSIDER “REASONABLE PROJECTED OR FORECASTED 14 OFFSETS IN REVENUE AND EXPENSES THAT ARE DIRECTLY 15 ATTRIBUTABLE TO OR ASSOCIATED WITH THE EXPECTED d/b/a Energy NV
16 Nevada Power Company Company Power Nevada CHANGES IN CIRCUMSTANCES UNDER CONSIDERATION.” 17
and SierraCompany Pacific Power ARE THERE ANY OFFSETS ASSOCIATED WITH THE MAIN 18 STEAM BLOCK VALVE REPLACEMENT PROJECTS? 19 A. The Company has not identified any reasonable projected or forecasted 20 offsets in revenues or expenses that are directly attributable to or 21 associated with these expected changes in circumstances. 22
23 298. Q. WHAT IS THE EXPECTED COST OF THESE PROJECTS? 24 A. The total for the Sun Peak outage project is $2,584,267, not including 25 AFUDC.
26
27
28 Rekowski-DIRECT 144
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1 SECTION VIII: OTHER GENERATION EXPENDITURES
2 A. SCHEDULE H-CERT-27 HIGGINS TRANSFORMER REGULATORY ASSET 3 299. Q. PLEASE DESCRIBE THE COSTS INCLUDED IN THE H-CERT- 4 27 RELATED TO THE HIGGINS TRANSFORMER 5 REPLACEMENT PROJECT. 6 A. In Nevada Power’s 2017 General Rate Case, Docket No. 17-06003, 7 Nevada Power requested rate base recovery of approximately $4.5 million 8 in expenses related to replacing the Higgins transformer. In the Order, the
9 Commission stated:
10
The PUCN accepts Nevada Power's request to place the 11 Higgins failed transformer costs into rate base. The transformer is installed and is used and useful. There is no
12 evidence in the record supporting a position that the cost for the transformer was not prudently incurred.7 13 14 300. Q. IF THE COMMISSION ACCEPTED NEVADA POWER’S 15 REQUEST, WHY WAS A REGULATORY ASSET ESTABLISHED d/b/a Energy NV
16 FOR THESE PROJECT COSTS? Nevada Power Company Company Power Nevada 17 A. In the same paragraph of the Order, the PUCN also required Nevada Power and SierraCompany Pacific Power 18 to establish a regulatory asset account for the net book value of the failed 19 Higgins transformer that will accrue carrying charges until the time of the 20 next general rate case.
21 However, addressing Staffs and BCP's concerns, the PUCN 22 requires Nevada Power to establish a regulatory asset account for the net book value of the failed Higgins 23 transformer that will accrue carrying charges until the time of the next general rate case. Any proceeds received from 24 litigation or from insurance claims should be credited against the regulatory asset.8 25
26 7 Docket No. 17-06003, December 19, 2018, Modified Final Order at 79, Paragraph 309. 27 28 Rekowski-DIRECT 145
Page 149 of 278 REDACTED PUBLIC VERSION
1 The Commission directed Nevada Power to credit against the regulatory 2 asset any proceeds received from litigation or from insurance claims
3 associated with the catastrophic failure of the transformer. 4
5 301. Q. WHAT IS NEVADA POWER REQUESTING FOR THESE COSTS 6 IN THIS CASE? 7 A. Nevada Power is requesting that the prudently incurred costs related to this 8 project and the carry costs associated with them be included in rate base.
9 As reflected in Schedule H-CERT-27, at the end of the test year, the 10 amount of the regulatory asset stood at $885,420, of which $491,137 was
11 the remaining amount of the transformer replacement costs and $394.282
12 in carry charges. The Company received a credit of $ and as
13 directed by the Commission has credited it against the regulatory asset. 14
15 302. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT d/b/a Energy NV
16 Nevada Power Company Company Power Nevada TESTIMONY? 17 A. Yes. and SierraCompany Pacific Power 18 19 20 21 22 23 24
25 26 27
28 Rekowski-DIRECT 146
Page 150 of 278 Exhibit Rekowski-Direct-1 Page 1 of 4
DARIUSZ REKOWSKI GENERATION EXECUTIVE NV Energy, Inc. 6226 West Sahara Avenue Las Vegas, NV 89146 (702) 402-5662
Mr. Rekowski joined NV Energy, Inc. (“NVE”) in February 2006 and is currently Generation Executive for NV Energy. He has over 25 years of experience in power generation with extensive knowledge of design, construction, operations, maintenance, and management of combustion and steam turbine facilities.
PROFESSIONAL EXPERIENCE 04/2019-Present Vice President of Generation, Generation, NV Energy. Responsible for providing corporate support to the generating plants. Provided services include engineering and project management support, outage planning and management, training, management of the Long Term Service Agreements for gas and steam turbines, warehouse management, and Generation Business. Manage various aspects of NV Energy Generation fleet reliability and availability improvement. Responsible for standardization of processes for NV Energy Generation fleet. Provide technical assistance and support to the plant O&M managers and regional directors. Develop Service Level Agreements with internal suppliers.
01/2013-04/2019 Generation Executive, Generation, NV Energy. Responsible for providing corporate support to the generating plants. Provided services include engineering and project management support, outage planning and management, training, management of the Long Term Service Agreements for gas and steam turbines, warehouse management, and Generation Business. Manage various aspects of NV Energy Generation fleet reliability and availability improvement. Responsible for standardization of processes for NV Energy Generation fleet. Provide technical assistance and support to the plant O&M managers and regional directors. Develop Service Level Agreements with internal suppliers.
01/2009-01/2013 Director, O&M, Generation, NV Energy.
Page 151 of 278 Exhibit Rekowski-Direct-1 Page 2 of 4
Responsible for various aspects of NV Energy Generation fleet reliability and availability improvement. Manage Work Management and Outage Management processes. Responsible for standardization of processes for NV Energy Generation fleet. Provide technical assistance and support to the plant O&M managers and regional directors. Develop Service Level Agreements with internal suppliers. Provide oversight to turbine/generator maintenance and overhaul programs.
02/2006-01/2009 Director, Clark/Sunrise Complex, Generation, NV Energy. Managed operation and maintenance of the Clark/Sunrise power complex. Responsible for PSM combustion turbine upgrade and exhaust emission reduction project. Provided startup & commissioning support and O&M interface during construction of Clark Peaking plant. Represented Generation in latest labor contract negotiation of the Collective Bargaining Agreement with Local 396
10/2000-02/2006 Plant Manager, Generation, Dynegy, Riverside/Foothills & Bluegrass Power Plants in Kentucky and Rolling Hills Power Plant in Ohio. Managed operation and maintenance of power peaking plants in Kentucky and Ohio region. Established O&M staff and provided O&M interface during construction. Managed 501FD2 combustion turbine startup reliability improvement project. Participated in the periodic and major inspections of gas turbines, generators and auxiliary equipment.
09/1999-10/2000 Plant Engineer & Maintenance Supervisor, Generation, Dynegy, Rockingham Power Plant in North Carolina. Provided engineering services and managed maintenance crew. Provided O&M interface during construction. Responsible for planning and coordinating all combustion inspections, hot gas path inspections and major overhauls on a 501FD2 gas turbine. Responsible for all engineering activities for power plant startup and commissioning.
Page 152 of 278 Exhibit Rekowski-Direct-1 Page 3 of 4
05/1996-09/1999 Plant Engineer, Generation, Dynegy, Cogen Lyondell Power Plant in Channelview, Texas. Responsible for combustion & steam turbine and major equipment upgrades and problem solving. Responsible for implementation of capital improvement projects. Managed turbine and equipment overhauls and parts repairs. Participated in troubleshooting, planning preventive maintenance and compiling statistical reports. Provided engineering services for process design modifications including: piping modifications, instrumentation and equipment specification, and control modifications.
04/1992-05/1996 Senior Mechanical Engineer & Performance Engineer, Generation, Destec Energy/Dynegy, Corporate Office in Houston, Texas. Provided engineering support during construction of the Oyster Creek Combined Cycle Power Plant in Freeport, Texas. Provided mechanical engineering services to Destec/Dynegy Generation fleet. Performed performance and acceptance testing of the Michigan Power Plant in Ludington, Michigan.
08/1988-04/1992 Design Drafter, Interkiln Corporation of America, Houston, Texas. Designed structural steel and gasifier components for coal gasification plants in China and Botswana. Designed various mechanical, pneumatic and hydraulic systems for commercial ceramic kilns.
09/1987-02/1988 Motorman, Polish Steamship Company, Gdansk, Poland. Operated and maintained mechanical equipment and engine room machinery on cargo ships as a seaman during ship voyages.
09/1986-06/1987 Procurement Agent, Polish Baltic Shipping Company, Kolobrzeg, Poland. Responsible for parts and material procurement for Polish Baltic Shipping ferryboats.
Page 153 of 278 Exhibit Rekowski-Direct-1 Page 4 of 4
EDUCATION Master of Science Degree in Mechanical Engineering, Power Systems. Maritime University of Gdynia, Poland, June 1986. Master of Business Administration, Morehead State University, Morehead, Kentucky, December 2005.
Page 154 of 278 EXHIBIT REKOWSKI-DIRECT-2
Page 155 of 278 Exhibit Rekowski-Direct-2 .5 Page 1 of 4
Test Period Projects
Budget ID Description Plant In‐Service Costs as Total Project Plant In‐ of 12/31/2019 Service Costs Lenzie Station Projects CL1099 LZ Elevator for Air Cooled Condenser $1,011,978 $1,011,978 CL1124 LZ ACC Leading Edge Fan Blade (year 2018), Replacement $839,054 $1,243,614 $1,851,032 $2,255,593
Clark Station Projects CS2036 Clark ‐ 21 B Power Turbine (PT ) OEM REPLACEMENT ‐ SN 80306 $1,468,520 $1,468,520
Clark Peaker Power Turbine Upgrade and Overhaul CS2019 CK ‐ 12B Power Turbine OEM UPGRADE AND OVERHAUL SN 80323 $936,160 $936,160 CS2020 Clark‐ 13B Power Turbine OEM UPGRADE AND OVERHAUL SN 80325 $954,493 $954,493 CS2021 Clark ‐ 14A Power Turbine OEM UPGRADE AND OVERHAUL SN 80320 $922,649 $922,649 CS2022 Clark ‐ 14B Power Turbine OEM UPGRADE AND OVERHAUL SN 80308 $885,166 $885,166 CS2023 CK ‐ 22A Power Turbine OEM UPGRADE AND OVERHAUL SN 80307 $944,089 $944,089 CS2024 CK ‐ 22B Power Turbine OEM UPGRADE AND OVERHAUL SN 80321 $963,422 $963,423 CS2028 Clark ‐ 15 A Power Turbine OEM UPGRADE AND OVERHAUL SN 80309 $1,040,907 $1,040,907 CS2029 Clark ‐ 15 B Power Turbine OEM UPGRADE AND OVERHAUL SN 80310 $1,028,810 $1,028,810 CS2030 Clark ‐ 16 A Power Turbine OEM UPGRADE AND OVERHAUL SN 80314 $913,633 $913,633 CS2031 Clark ‐ 17 A Power Turbine OEM UPGRADE AND OVERHAUL SN 80316 $1,036,573 $1,036,573 CS2035 Clark ‐ 21 A Power Turbine OEM UPGRADE AND OVERHAUL SN 80305 $1,034,787 $1,034,787 $10,660,688 $10,660,689 Clark Peaker ‐Turbine Exhaust Case Upgrade CS2037 Clark ‐ 12 A Turbine Exhaust Case Upgrade ‐ SN P743061 $306,083 $303,919 CS2038 Clark ‐ 13 A Turbine Exhaust Case Upgrade ‐ SN P743087 $450,153 $450,153 CS2039 CS 16B TEC OEM UPGRADE‐SN P743088 $453,328 $453,260 CS2040 CK ‐ 19 B Turbine Exhaust Case OEM UPGRADE AND OVERHAUL SN P74306 $322,405 $322,405 CS2060 CK Unit 21A Turbine Exhaust Case Upgrade ‐ SN P743073 $307,555 $314,339 CS2064 CK Unit 13B Turbine Exhaust Case Upgrade ‐ SN P743089 $275,677 $275,677 CS2065 CK Unit 12B Turbine Exhaust Case Upgrade ‐ SN P743086 $256,834 $256,834 CS2066 CK Unit 22A Turbine Exhaust Case Upgrade ‐ SN P743080 $259,555 $259,555 CS2069 CK Unit 22B Turbine Exhaust Case Upgrade ‐ SN P743081 $230,075 $230,075 CS2070 CK Unit 20A Turbine Exhaust Case Upgrade ‐ SN P743064 $332,870 $332,870 CS2072 CK Unit 14A Turbine Exhaust Case Upgrade ‐ SN P743094 $289,791 $289,791 CS2073 CK Unit 14B Turbine Exhaust Case Upgrade ‐ SN P743085 $278,777 $278,777 CS2074 CK Unit 15A Turbine Exhaust Case Upgrade ‐ SN P743075 $319,891 $319,891 CS2075 CK Unit 15B TEC Upgrade ‐ SN P743082 $390,272 $292,702 CS2076 CK Unit 16A Turbine Exhaust Case Upgrade ‐ SN P743076 $284,359 $284,359 CS2077 CK Unit 17A TEC Upgrade ‐ SN P743090 $292,658 $296,321 CS2080 CK Unit 19A Turbine Exhaust Case Upgrade ‐ SN P743068 $345,889 $345,889 $5,396,170 $5,306,815 Other Clark Station Projects CS2041 Clark Peakers ‐ Mee Fog Injection Skid Modifications $1,668,544 $1,668,544 CS2045 Clark ‐ Unit 9 ‐ Cooling Tower Fill Replacement and Structural Repairs $662,009 $662,009 CS2046 Clark ‐ Unit 10 ‐ Cooling Tower Fill Replacement and Structural Repairs $680,814 $680,814 CS2115 CK ‐ Capital Spare GG8‐3 Gas Generator $6,203,732 $6,203,732 CS2116 CK ‐ Capital Spare FT8‐3 Turbine Exhaust Case $1,432,896 $1,432,896 CS2136 CK ‐ Unit 9 ‐ Upgrade / Rebuild Steam Turbine Valves $1,002,073 $1,002,073 CS2137 CK ‐ Unit 10 ‐ Upgrade / Rebuild Steam Turbine Valves $1,033,234 $1,033,234 CS2140 CK ‐ Unit 19A Gas Generator Rebuild, SN P743068 $1,343,706 $1,343,706 CS2145 CK ‐ Replace Underground Main Fuel Gas Pipe Line ‐ Unit 4 ‐ 8 $2,946,142 $2,924,289 CS2236 $16,973,150 $16,951,298
Page 156 of 278 Exhibit Rekowski-Direct-2 .5 Page 2 of 4
Test Period Projects
Budget ID Description Plant In‐Service Costs as Total Project Plant In‐ of 12/31/2019 Service Costs
Harry Allen Station Projects HA1087 HA Elevator for Air Cooled Condenser $1,089,878 $1,089,878 HA2024 HA3 Combustion System Capital Parts Replacement $1,243,614 $1,243,614 $2,333,493 $2,333,493
LV Gen Projects LC1039 LVGS LV1 Hot Gas Path Overhaul $1,407,689 $1,407,689 LC1040 LVGS LV2A Major Overhaul SN 191‐324 $1,460,904 $3,633,006 LC2033 LVGS ‐ PB 2 UG Cooling Water Piping Replacement $1,311,124 $1,311,124 LC2034 LVGS ‐ PB 3 ‐ UG Cooling Water Piping Replacement $1,412,286 $1,412,286 LC2064 LVGS ‐ PB2A Gas Turbine Repairs ‐ SN 185‐163 $2,504,061 $2,504,061 LC2116 LVG U1 CT Generator Stator, Replace $1,804,918 $1,804,918 $9,900,983 $12,073,084
Sun Peak Projects SK2004 Sun Peak Exciter Controls (AVR) $1,706,289 $1,706,289
Silverhawk Projects SH1017 SH SCR catalyst A, Replace $1,154,321 $1,154,321 SH2016 SH CT‐A Exhaust System Replacement $4,113,127 $4,113,127 SH2035 SH "A" CT rotor replacement $5,129,721 $5,129,721 $10,397,169 $10,397,169 Higgins Station Projects WH2109 WH Steam Turbine Transformer, Replace $5,291,306 $5,291,306 WH2110 WHC Underground Fuel Gas Line Leak, Replace $1,707,347 $1,707,347 $6,998,653 $6,998,653
LTSA Projects HA2019 HA CC LTSA Capital PO $15,153,487 $15,153,487 SH1080 SH CTB HGP LTSA Capital Portion $1,645,965 $1,645,965 SH1081 SH A LTSA Major inspection 2019 $7,664,461 $7,664,461 $24,463,913 $24,463,913
Page 157 of 278 Exhibit Rekowski-Direct-2 .5 Page 3 of 4
Certification Period Projects
Budget ID Description Updated Plant Estimated Plant In‐ In‐Service Service Costs Costs Chuck Lenzie Station Projects CL2024 LZ Spare GSU Transformer, Purchase $3,133,456 $3,366,693 CL2067 LZ PB1 Ammonia Heaters, Replace $508,732 $930,713 CL2068 LZ PB1 Chiller Cooling Towers, Replace $6,124,476 CL2069 LZ PB2 Chiller Cooling Towers, Replace $6,157,773 CL257 LZ PB1 Mod 3 Re‐tube Chiller C $1,014,529 CL259 LZ PB2, Mod 3 Re‐tube Chiller condensers, Replace $1,033,251 $17,972,217
Clark Peaker ‐ Power Turbine Upgrade and Overhaul CS2025 Clark ‐ 20 A Power Turbine OEM UPGRADE AND OVERHAUL SN 80280 $1,046,128 CS2026 Clark ‐ 20 B Power Turbine OEM UPGRADE AND OVERHAUL SN 80281 $1,043,725 CS2032 Clark ‐ 18 A Power Turbine OEM UPGRADE AND OVERHAUL SN 80311 $1,052,777 CS2033 Clark ‐ 18 B Power Turbine OEM UPGRADE AND OVERHAUL SN 80312 $1,052,437 $4,195,066
Clark Peaker ‐ Turbine Exhaust Case Upgrades CS2078 CK Unit 18A Turbine Exhaust Case Upgrade ‐ SN P743084 $294,348 $296,923 CS2079 CK Unit 18B Turbine Exhaust Case Upgrade ‐ SN P743083 $292,446 $296,931 CS2081 CK Unit 20B Turbine Exhaust Case Upgrade ‐ SN P743065 $296,920 $296,925 $883,714
Other Clark Station Projects CS2121 CS Spare GSU $1,933,417 CS2156 CK ‐ C Pond Liner Replacement $1,218,738 $1,766,897 CS2255 CK ‐ Demin Tank Failure ‐ 4‐7‐2020 $1,596,113 $3,152,155
Harry Allen Station Projects HA1103 HA WSAC Fluid Coolers, Replace $3,536,676 HA2052 HAS Emerson DCS Controllers and Servers, Replace $1,519,577 HA2054 HA3 Generator Stator Rewind_HA $4,270,563 $9,326,817
Silverhawk Projects SH2074 SH Emergency Diesel Generator, Install $1,880,037 SH2112 SH Pond A Liner, Replace $1,284,783 SH2128 SH Pond B Liner, Replace $943,204 $1,281,900 $4,108,024
Higgins Stations Projects WH2020 RO Skid and Demin $2,725,953 WH2021 WH Spare GSU Transformer, Purchase $4,673,405 WH2089 ACC Freight Elevator, Install $1,158,174 $1,219,799 WH1064 WHC Reclaim Sand Filter, Replace $963,449 WH2154 ST HP & IP Valves $2,369,562 $6,795,028
Page 158 of 278 Exhibit Rekowski-Direct-2 .5 Page 4 of .54
Expected Change in Circumstances Projects
Updated Estimated Estimated Plant In‐ Budget ID Description Plant In‐Service Service Costs Costs
LTSA Projects CL1104 LZ LTSA Capital Portion 2020 $16,792,239 WH1059 Higgins LTSA 2020 $13,878,281 $30,670,521
Chuck Lenzie Station Projects CL2074 LZ PB2 Ammonia Heaters, Replace $952,217 CL2089 LZ Gas Supply Piping System, Install $1,633,743 CL2147 PB2 Hydrogen Seals $1,133,785 Lenzie Other Outage Projects $1,646,421 $5,366,166
Higgins Stations Projects WH1042 WHC Arc Flash Mitigation, Install $989,267 WH2024 WH CT1 Rotor Component, Replace $5,080,827 $5,682,252 WH2028 WH CT1 Exhaust System, Replace $2,661,884 WH2071 WH Steam Turbine Generator Winding, Purchase $6,314,332 WH2123 Underground Piping, Replace $1,867,880 WH2136 NP 17 MW 501F (Higgins CT1) $10,064,149 WH2137 NP 17 MW 501F (Higgins CT2) $10,064,149 WH2147 WHC CT Outage Components, Replace $2,311,491 $3,295,357 WH2149 WHC Cold Reheat Piping, Replace_WH $66,948 $931,187 WH2131 Main Steam Block Valve $445,622 WH2132 Main Steam Block Valve $448,927 Other Higgins Outage Projects $3,300,812 $43,616,288
Page 159 of 278 EXHIBIT REKOWSKI-DIRECT-3
Page 160 of 278 Exhibit Rekowski-Direct-3 Page 1 of 1 .5 .5
ECIC Project that will not be Included in Plant in Service ECIC PERIOD DESCRIPTION BUDGET ID ESTMATE LZ HVAC, Replace (2020)_CL CL2087 143,941 LZ Water Treatment RO Booster Pumps, Replace_CL CL2090 222,574 Clark ‐ 11 A Power Turbine OEM UPGRADE AND OVERHAUL SN 80318_CS CS2027 1,049,450 Clark ‐ 19 A Power Turbine OEM UPGRADE AND OVERHAUL SN 80301 _CS CS2034 1,049,450 CK Unit 11A Turbine Exhaust Case Upgrade ‐ SN P743092_CS CS2071 296,631 CK ‐ PKRS ‐ Purchase Capital Spare Generator ‐ Brush _CS CS2238 1,941,098 CK ‐ Repair 400K gals CT Demin Tank ‐ floor & coating_CS CS2247 301,014 CK ‐ PKRS ‐ Gen 2 Operating Software ‐ upgrade_CS CS2250 499,845 CK ‐ PKRS ‐ PB 2 ‐ Bus Duct ‐ Rebuild_CS CS2251 888,613 GS Pentane Evacuation System, Install_GS GS2019 255,207 Harry Allen GE ICS Security Update_HA HA2037 301,022 HA3 Plant Protective Relays, Replace_HA HA2119 143,198 HA4 Plant Protective Relays, Replace _HA HA2121 144,567 LVGS ‐ PB 2 ‐ GSU upgrades ‐ Replace Surge Arrestors_LC LC2040 12,291 LVGS ‐ PB 3 ‐ GSU upgrades ‐ Replace Surge Arrestors_LC LC2041 12,291 PB2 Refrig Monitoring Control Panel, Replace_LC LC2112 87,342 LVG 2A Automatic Voltage Regulators, Replace_LC LC2132 249,883 PB3 Refrig Monitoring Control Panel, Replace_LC LC2142 87,158 LVG 2B Automatic Voltage Regulators, Replace_LC LC2146 250,652 LVG 3A Automatic Voltage Regulators, Replace_LC LC2147 250,604 LVG 3B Automatic Voltage Regulator, Replace_LC LC2148 250,652 SH A Feed Water Strainer and Valves, Replace_SH SH2119 112,433 SH B Feed Water Strainer Valves, Replace _SH SH2120 113,438 SH CTA Battery Charger, Replace_SH SH2144 181,920 SH CTB Battery Charger, Replace_SH SH2145 182,095 SH BOP Battery Charger, Replace_SH SH2147 187,142 SH Air Cooled Condenser Gear Boxes, Replace_SH SH2148 332,850 SH Brine Concentrator Waste Seed Valve, Replacement_SH SH2151 74,304 SH Brine Concentrator Recirculating Pump, Spare_SH SH2168 79,936 Sun Peak Unit 4 GT ‐ Hot Gas Path Overhaul ‐ SN 295658_SK SK2023 857,792 CSC Top 20 ‐ ICS ‐ Network Security Equipment ‐ Pri 3 Locations (South)_SP SP5029 1,214,295 WHC Boiler Feed Pump Motor Starter (4160v), Purchase_WH WH2118 106,331 WHC Feeder Protection Relay, Replace_WH WH2152 55,997 WH ST Synchronizing System, Replace_WH WH2153 238,191 Total 12,174,208
Page 161 of 278
1 AFFIRMATION 2 3 Pursuant to the requirements of NRS 53.045 and NAC 703.710, DARIUSZ 4 REKOWSKI, states that he is the person identified in the foregoing prepared testimony and/or
5 exhibits; that such testimony and/or exhibits were prepared by or under the direction of said 6 person; that the answers and/or information appearing therein are true to the best of his 7 knowledge and belief; and that if asked the questions appearing therein, his answers thereto
8 would, under oath, be the same. 9
10 I declare under penalty of perjury that the foregoing is true and correct.
11
12 Date: ______May 22, 2020 ______DARIUSZ REKOWSKI
13
d/b/a d/b/a NV Energy 14 Nevada Power Company 15 andSierra Pacific Power Company 16 17 18 19 20 21
22 23 24
25 26 27
28
Page 162 of 278 Page 163 of 278 Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 II. I. OF CONTENTS TABLE III. Veilleux-DIRECT IV. CONCLUSION 1. 2. 4. 3. 6. 5. 24. 23. 22. 21. 20. 19. 18. 17. 16. 15. 14. 7. NEVADA 11. 10. 8. 13. 12. 9. 25. INTRODUCTION 26. INCIRCUMSTANCE CHANGES EXPECTED THE BEFORE Spare Substation Critical Magnolia (A5K) #1Addition Bank 230/138kV McDonald Mercury–Northwest (COK11) Modernization Communication Bank Capacitor Strip Transmission Relay Replacement Relay (A86) Transmission Strip (V1) Addition 138kVPCB Vegas Substation Elkhorn-Northwest ...... Switchyard (A5Z)37 230kV Substation Breeze Project Reid Gardner Telecommunications Microwave Replac36ement (6Q) Microwave Replac36ement Telecommunications GardnerReid Pecos Substation 138/12kV Bank #7 Addition (OH) Bank 138/12kV Substation Addition Pecos #7 Trenwa Replacement Cable Substation138kV Clark 138/12kV (XG) Addition Bank #2 Substation MYS (WS) Bank 138/12kV Substation Addition Swenson #3 Sparta Substation 138/12kV Bank #3 Addition (WU) Addition Bank 138/12kV #3 Substation Sparta Reactor 230kVShunt Substation Equestrian (WW) Substation 138/12kV MYS Critical Substation L Substation Perimeter Critical Program ( GridRuggedization AFT) Transmission Cable U/G Procyon Substation 138/12kV Bank #3 Addition (PV) Bank 138/12kV Addition Procyon #3 Substation MYS Substation 12kVBus #2(X6) Section Substation MYS MYS Substation 12kVBus #1(XF) Section Substation MYS Substation Spare Wound SpareCore Wound Substation U/G Cable Replacement Cable U/G
POWER
Substation C Substation
...... Substation 230/138kV Bank #6 Addition (AF8) #6Addition Bank 230/138kV Substation Nevada
Replacement
PUBLIC UTILITIES COMMISSION OFCOMMISSION NEVADA PUBLIC UTILITIES ...... T&D PROJECTS MAJOR PreparedDirect
Wound Equipment Core Wound
NV d/b/a Energy Company Power
Case 2020 General Rate 138 kV Line 138 kV
Revenue 138kV Line 138kV
Docket No.20-06___ Perimeter (A0Y) Wall Veilleux Vincent
FL-MGM & EX-MGM FL-MGM FL-MGM& EX-MGM 1 Requirement
Equipment
Wall (AFF)Wall
Of Testimony #2 (A09)38 #2 Rebuild I Rebuild ......
......
...... & ...... (A1W) ...... II (TM522/TM528) ...... (TM295) (TM295) ......
...... (AF2) ...... Page 164 of278 ...... 38 18 40 24 37 28 26 34 21 31 12 10 27 25 52 42 29 22 33 14 32 47 15 36 16 20 42 5 2 5 Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 1. 2. 3. Veilleux-DIRECT I. Q. A. Q. INTRODUCTION A. Q. A. My PLEASE FILING ARE TESTIMONY. FOR YOU AND PARTY WHOM Power I Pacific Power, the PLEASE located is which Masters EXPERIENCE. on behalf of onbehalf proceeding Nevada testimony this in Vegas. within e, I Yes, Project Senior role statement HAVE (“Commission”) PROCEEDING? experience. Energy NV hold
name as
Company
a
the Major Projects Manager. Projects Major I
Company Power
O PEIUL FLD ETMN I A IN TESTIMONY FILED PREVIOUSLY YOU
have n Business in Science of Bachelor my began
that qualifications of is STATE “Companies”).
DESCRIBE have and organization Projects Major Sierra and Vincent
Control etfe before testified
d/b/a part as at OR NAME, YOUR employment 6226 both Administration, elex I Veilleux. NV NV Energy Pacific Project Senior Consultant,
the of
d/b/a YOUR I W. Sahara W. work
2 degree Joint Company Power
NV
my details further primarily the Nevada with am (“Nevada I
PROFESSIONAL have Nevada of Application Energy
Computer in CUAIN BUSINESS OCCUPATION, Avenue the Public as attached Manager of Manager out Power” from (“Sierra,” tlte Cmiso of Commission Utilities
of Nevada n Las in in Power
d/b/a
Power. the
Engineering my now and Manager which positions held the or and background Exhibit Veilleux-Direct-1 Exhibit Vegas, University NV Energy NV Projects Major
and BACKGROUND Power’s Power’s corporate 2006
“Company”)
Power oehr ih Nevada with together Nevada. as a as REGULATORY an and Nevada, of d/b/a Company approval for Page 165 of278 student
ADDRESS, professional Nevada for I
and and Sierra Executive
am
Nevada include
current
office, intern AND filing Las
of a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 4. 5. Veilleux-DIRECT Q. Q. A. A. To My WHAT the Program, the and Docket No. 19-02001. Docket2019-2020 in No. Systems Demonstration Systems Program, Demonstration the annual HOW IS YOUR TESTIMONY ISYOUR ORGANIZED? HOW PROCEEDING? of Power’s Nevada calculation are the in included eto II Section facilities (“T&D”) distribution service placed general (December aggregated are identify relay metering, telecommunications, lines, including Major II. Section in For I reference,
demonstrate typically following the sections: into testimony organized is
in
the for plans to
Electric rate the
service customers. generally and THE IS .
or the and 2019), 31, scope I case
comprised of several of comprised Energy
demonstrate “linked”
provide the Vehicle (May since cost and prudence
Energy Solar My Storage T&D PURPOSE the orders work the through 2017) 31,
the
distribution lines, transmission substations, as identified Infrastructure testimony
that the of end
“link” the for projects 3 and Low Income Low and
several of the of end
Nevada was
number of number for each the
linked Incentive Systems type specifically in
OF Energy Waterpower rdn, s sd n useful and used is prudent, include can certification period in Nevada in period certification
excess of excess Program Demonstration asset of Power’s investment of categories (May period certification work
OR ETMN IN TESTIMONY YOUR environmental protection, and
end components addresses that orders required million. $1
investment revenue
investment the of
the Program,
major projects described major
the test
to Systems Demonstration Demonstration Systems requirement. the allow the of complete Major major and transmission in this in period multiple in
for
in
Solar Program, Program, Solar Page 166 of278 2020) 31, and providing providing and
T&D T&D facilities Program T&D Energy Wind
that facilities last Power’s Company the
permits, permits, projects project. assets,
THIS filing filing Year with to
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 Veilleux-DIRECT 6. Q. A. why project, regulatory Commission, Commission, the Nevada eto III. Section in provided projects These service in delayed as a result of the viral ofthe delayed as outbreak. result a major each Yes. “reasonably is of specific of degree ARE Nevada TESTIMONY? DIRECT Exhibit Exhibit I
projects projects commenced two sponsoring am
YOU YOU
the in Power’s investment Power’s nldd s part as included
before permits, and permits,
and Veilleux-Direct-2 Transmission and Distribution Major Projects Distribution and Transmission Veilleux-Direct-2 Statement Veilleux-Direct-1 ECIC Exhibit Veilleux-Direct-2. Exhibit
I
SPONSORING amount known and measureable and known it identifiable explain
investment total
was the T&D project, T&D the of end cost time and necessary, necessary,
Nevada land rights. land
exhibits: the of of the
prior
events, is is prudent. A of all listing prudent. is project this in 4
why Power’s project, and other information to demonstrate to ANY and expected, circumstances” in changes “expected on period certification if if the it if my In it it COVID-19 COVID-19 pandemic
necessary, was reasonable with
EXHIBITS has a has of Qualification In Section has has request
describe I testimony, previously high
other
to probability III of my recover investments of T&D T&D of investments recover
TO demonstrate to information T&D new the
accuracy,”
May
been total YOUR YOUR and testimony, I describe testimony,
31, 2020, 31, the to occurring of cost
presented presented were each plant Page 167 of278 it how the of PREPARED
major to to be additions is additions (“ECIC”) but
consists consists to placed it how
T&D
were why the
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 7. 8. II. 9. Veilleux-DIRECT . ARE Q. Q. A. A. Q. NEVADA 1. A. Yes. Public CONFIDENTIAL? discusses section This customers customers in future Power SECTION. IN INCLUDED PROJECTSTHIS THE DESCRIBE accepted transformer confidential provided provided to the under standardized protective agreements with them. them. agreements with protective under standardized listed SUBSTATION SPARE SUBSTATION end end of the project core equipment wound spare substation The and beforeand end the of the PLEASE DESCRIBE THE PROJECT. THE DESCRIBE PLEASE projectsThe are system mitigate directly or equipment, core wound forspare need increased an vacancy or existing
POWER
Q&A In in in
disclosure requests critical
ANY Exhibit the practice
certification certification period in
materials should be should materials pricing outages. customer extended of risk T&D PROJECTS MAJOR
the 120, Regulatory spare
OF cost. total order in ofdescending organized confidential
Veilleux-Direct-2. of the proceedings, Commission in
negotiations negotiations with suppliers
nomto fr o fewer no for information to apparatus substation pricing this
THE investments spare
this period general case rate in (May certification WOUND WOUND EQUIPMENT CORE Operations Operations Staff 5 treatment redacted. been has information pricing transformer MATERIALS
Nevada the to returned harm could information for These
T&D major Power’s last the of
and the were projects
provide
for favorable
confidential accordance In Company. at years, 5 than O ARE YOU
Bureau equipment This
the provides for million $1 than greater projects confidential general reliable
of Consumer placed
pricing the settlement rate electric
Company case
SPONSORING material in time which Page 168 of278
terms.
either fills an an fills either acquisition of acquisition service (May service
Protection Protection terms
the with
Nevada will 31, 2020). its and 31, 2017) after and and the be
the
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 10. Veilleux-DIRECT Q. A. units, totaling $6,855,571, which consist of the following: ofthe consist $6,855,571,which totaling 14units, received and replaces more in discussed As utility Standard appropriate WASTHE WHY civil below below grade the long-term storage of the spare the long-term storagethe of and capacity core wound substation other and transformers, of long-lead loading) and 6 to for8 months high-voltage spares transformers availability and/or
improvements
on hand varies based Four kV,37.4 138/12.4 One Three kV,22.4 69/12.4 One breakers power 138kV2000amp circuit Two One One One
a spare
location location to
kV,100MVA 525 spare kV 2000 amp power circuit breaker - $42,212 $42,212 breaker - kV2000ampcircuit power 69 $257,043 - kV,5.2MVAspare transformer 34.5/12.4/5.4 kV,5.25 138/34.5 $737,360 spare- kV,24.9MVA transformer 67/24.9
spare
cable classes. after months 18 to 12 is
practice that equipment
runways,
PROJECT NECESSARY? acquiring to
at was The store eo Sbtto, consisting Substation, Pecos
requires detail installed as a as installed typical
on on the station grounding grounding station associated and facilities the 6 such MVA spare $1,546,346 - MVA spare transformers MVA spare new equipment, age equipment, new Pecos below, lead-time
that number equipment as as large
eco $1,132,470 - reactor placement spare ses As a assets. the
result of of devices operational Company power power autotransformers, medium on
transformer –$383,246 transformer
transformers power power circuit listed above, totaling $3,450,387. $3,450,387. above,listed totaling of a of delivery
equipment was Substation of failure.
result, factory on (depending order an
sufficient maintain
of f 15 of $168,440 - of transformer $2,588,454 -
this medium breakers. The
The for all for conduit, foundations, project Company
in in the as identified voltage common and and large Page 169 of278 fleet, also also included field, to allow
number quantities quantities procured the and
access power power power power
for for an of
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 Veilleux-DIRECT urgent reliability replacement procure and Between or more depleting failures, transformer with long lead times to specify, procure and procure specify, to long lead with times Company.the Coupled projects outpacing the general transformer, during transformers MVA 37 It MVA transformers this when even failure, to catastrophic Additionally, service extended the with essential with mitigated or reduced vandalism
should also should be created
project
spare units for each of these assets. foreach units ofthese spare
ability
07 and 2017 critical of or other
a significant risk due of outages extended significant where
noted interruptions. quickly to unanticipated unanticipated incidents, 18months. ofapproximately period a during
These load.
the
08 Nevada 2018, long utilizing growth customer
that
anand pursuant maintained
project equipment. Normally, equipment.
the lead damage
epn when respond 7
Company’s Company’s older transformers a the times times to acquire timeline eid f2 mnh ad spare and months 20 of period spare current
by caused
prs Ti practice This spares. experienced Power units are units does pool poses
avoiding occur, failures unexpected
to not
Company the
external of spare of transformers, transformers, and
unforeseen an for upon called risks risks to service recommendations. manufacturer
the for allow available
lack lack to of transformers such forces
the provides a
are should capacity, customer customer capacity, incidence high
spare Company
reliability
more 230/12,4
supplier Page 170 of278
manufacture
maintain one maintain 138/12.4 kV 138/12.4 s weather, as available susceptible
Company to that delays, kV 37 37 kV order order
are
or of to a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 12. 11. Veilleux-DIRECT Q. Q. A. A. Due Based PLEASE WHAT UNIQUE VOLTAGE CLASS SPARES. CLASS VOLTAGE UNIQUE NUMBER SPARE OF types of voltage Company 138/34.5 of available service Power’s years
the to 34.5/12.4/5.4 in in age
on the kV 34.5/12.4 138/12.4 138/34.5 kV 34.5/5.4
67/24.9 69/12.4 22.4 MVA 37.4 MVA 100 DOES 1.6 5.2 1.6 kVA 150 20 34.5/12.4 kV,
KV 525 Total Type THE WHY EXPLAIN has
MVA ever
bythe spares and and have MVA MVA MVA MVA number number of units
voltage
kV kV kV kV kV classes
kV
THE territory. territory. increasing
kV
exceeded exceeded their life OPN PROPOSE COMPANY and and transformer ratings, the that classes 34.5/5.4 and kV, ASSETS? Installed
following: units
109 131 255 the example, For 4 3 0 1 4 3 age
8 in in operation and
the of
Existing Spares are OPN PURCHASES COMPANY 1 0 1 0 1 0 1 4 0
infrastructure, transformer substation expectancy, unique KV
Additions Proposed
to to adequately transformers Mount o specific to 11
0 1 0 1 3 4 1 1 TO
Company including area Charleston
BE
Count Spare APPROPRIATE AN Total account that areas 15 increased 1 1 1 1 4 4 2 1
the
are
on-hand on-hand spares. Page 171 of278 ihn Nevada within for the THE all the osss of consists nearing
MORE number various various
the 60
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 13. 14. Veilleux-DIRECT Q. A. Q. A. units region. is Substation Pecos transformer The WHY transformer kV this region. this it disruptive requirements, SPARE ASSETS? also is Substation seven Nevada No, facility. equipment large qipd with equipped Lastly, the site requiredLastly, site the a A TI PROJECT THIS HAS spare ANAPPROVAL IN INTEGRATED requirements. resource all to centrally-located is
purchase
are minutes), and transformers, WAS
more While filing. plan The The
event
mitigates
PECOS Power 67/24.9 Pecos ideal an is and than than 30 years
additional an of
redundant mitigates
allows which out and in at Nevada near located a excellent has also Substation has outages extended kV SUBSTATION key o ogr considered longer no
not smaller investment voltage extended TO PRESENTED BEEN bring to facility that communications high-speed ftesbtto. In substation. the of
NAC old old with no system key
9 storing for location sought for a for
138/34.5 facilities, unique is class contemplates 704 Chapter
ol not would outages response rapid security Commission CHOSEN PLANRESOURCE (“IRP”)? resulting from resulting
oe’ Ryan Power’s dual and kV but resulting
to prepare forto storage location this
line in affect
sufficiently Purchasing spares. a the addition,
to critical
THE AS “critical”
to points access approval the
the from a
transformer a the with disruptive THE
area Laughlin Service voltage spare storage a separate
SITE
failure transformer a
site project this of substation satisfy COMMISSION resource equipment
Center 34.5/12.4/5.4 for location. Resilience Grid event CIP-014 under TO Page 172 of278 a
that enough ease spare failure GRO-S-002.
all and STORE filing plan at than (less already is move to because key any 67/24.9 this in Pecos
in four kV
FOR THE of in in a a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 Veilleux-DIRECT 1 15. 17. 16. Pursuant Energy Q. Q. Q. A. A. A. 2.
identity the Information, Infrastructure
Security Homeland Nevada's to The CRITICAL SUBSTATION C PERIMETER WALL (A0Y) WALL CPERIMETER SUBSTATION CRITICAL at the determined A Januarycurrent audit facilities 2019WECC WASTHE WHAT This NRS 704.860. NRS project this construct, to that projects for masonry WASTHE WHY at bollards rated with arms lift AFUDC) PLEASE 014-2 R5 documentation accepted by appropriately Reliability $10,305,958 security wall block CMU a as a the in useful and anddelivered used Council Coordinating
actual project
plan. Such
unit
the and DESCRIBE THE PROJECT. THE DESCRIBE
Corporation cost
involved involved replacing
AFUDC). (with (“CMU”) block wall. block (“CMU”) address
the of require total estimated PROJECT NECESSARY? barriers
TOTAL COST OF THE PROJECT? OF THE COST TOTAL
at Act, codified “EC)designated (“WECC”) the project
key component (“NERC”) a
does the in identified vulnerabilities
Utility of provide 10 the substation cannot be disclosed publically. publically. disclosed be cannot substation the
2019, 31, December through each entry point.
All not the Environmental
NRS § NRS existing CIP-014-2 CIP-014-2 R4 documentation. The
the of cost meet delay the includes Installationalso provision of utility service. provision
WECC
of ofthe one the of Critical to Laws relating Federal and 239C.210 the and and deterrence aiiis are facilities chain chain link fence ‘C’ critical definition of definition to project address address these
Act Protection
ofthe layers defense-in-depth
May through substation spare with installed
measures
North “Utility
at was
vulnerabilities vulnerabilities places a Western Western Electricity
American Electric American
substation (“UEPA”)
$2,209,380 addition of crash of addition
1 when Facility” Page 173 of278 with with a
1 2020, 31, revised revised CIP-
employed employed
concrete not did permit
under (with (with units is
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 18. 19. Veilleux-DIRECT Q. Q. A. A. with with other identified identified during The plan. Nevada No, wall range shooting these The The A TI PROJECT THIS HAS WASTHE WHAT protect to method APPROVAL IN AN APPROVAL IN IRP? resource of“Utility Facility” definition for require that projects at actuals estimated $11,114,411 in-service and placed were installed facilities new substation
substation was also subject also was substation Company total estimated with
stray
While filing. plan crash-protected crash-protected entries was
security rounds can
AFUDC). (with Power contracted a contracted the in located
the
the measures
cost CIP-014-2 CIP-014-2 R1-R3 requirements.
TOTAL COST OF THE PROJECT? OF THE COST TOTAL has cost completion harm. personnel from and equipment substation be
UEPA a the of
found on the not TO PRESENTED BEEN
firm NAC 11
facilitate to open The sought under NRS 704.860. 704.860. under NRS project
stray to permit to construct, this project construct, to this permit to perform to
contemplates 704 Chapter planned desert
identified identified as a Commission
substation substation equipment the of was strong bullets as a as bullets than less in-service
$12,267,070 a trajectory project defensive
Damage yardsaway. 500
vital approval
For this project, a result date
May through THE component study (without capabilities capabilities for May was of
and and control
a by project this of COMMISSION a resource analyze to near-by
31,2020. May does not AFUDC). Page 174 of278
of the
1, 2020. 2020. 1, 1 2020, 31,
CMU CMU block filing plan enclosure. enclosure. makeshift
locations locations meet the security the
from
in best The The FOR is a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 20. 21. 22. Veilleux-DIRECT Q. A. Q. Q. A. 3. A. The PLEASE THAN THE PERIMETER WALL PERIMETER THAN THE as substation, near near 7,500 feet,linear MCDONALD 230/138KV BANK #1 ADDITION (A5K) #1ADDITION BANK 230/138KV MCDONALD the constructed to a to constructed This This transmission project personnel to the PLEASE The inside system equipment. additions. A additions. transformer, WASTHE WHY existing 954 Cardinal TPL-001-4 System element. approximately to up
stray
complexity difference project
the
protection, protection, control, telecommunication and associated substation equipment
Decatur - Arden The bullets
existing DESCRIBE DESCRIBE THE PROJECT. THE DESCRIBE
comply to required was
re-conductor a
ACSS was required ACSS also working Company compared in he-rae 20 kV 230 three-breaker
the of height from cost McDonald Substation. Construction Construction also included McDonald Substation. PROJECT NECESSARY? Performance
percent 120
the entering it project this of on
of WHY near-by triples triples the that calculated the to
involved line transmission 230kV
18 feet18 as site, the of 12 THIS THIS SITE project
shooting following following the Arden now some in well the of length potentially could which substation,
was
PROJECT 57. INQ&A NERC with capacity rated installation installation of a one bus, ring as partas addressed
the as
primarily of stop to ability the maximize to locations range, significant COST Avera wall being withconstructed. Coupled
– of this project. of this
loss of loss a line kV 230 McDonald 57. Q&A in the
– WAS SIGNIFICANTLY WECC and
the into a
Quail 3 k circuit kV 138 the for
result wall southern new damage single 230/138 230/138 kV large line kV 138 new McDonald 230kV 230kV McDonald new of N-1 the bulk electric system bulk electric With a With the to reliability os f Arden of loss size sheer Page 175 of278
edd o be to needed folding folding in the breaker, perimeter
large cause segment could load load could
standard
power power power of harm MORE new new the of to –
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 24. 23. 25. Veilleux-DIRECT Q. Q. Q. A. A. A. The WASTHE WHAT The Yes. by mitigated be can condition overload line. kV 138 Camero HAS THIS PROJECT THIS HAS and and 230/138 kV transformer at The 230-kV transmission line. transmission 230-kV actual the to support reliability The AFUDC). PLEASE approved in COSTS. PROJECT several materialize previously of million placed additional spare was
recorded recorded as total estimated transformer kV 230/138 McDonald
transformer utilized for this project. for utilized this transformer
in
cost years plant
the standard, mitigate
$3.7 million in new construction costs as well as costs construction new in million $3.7
rnmsin td, analysis study, transmission DESCRIBE in the of Nevada
surrounding system. the but 2014, to prior held for future new new facilities were
a asset regulatory time projected
project
cost Power’s IRP Power’s TOTAL COST OF THE PROJECT? OF THE COST TOTAL
expended funds, expended planning Transmission
BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN the of
THE This project This December through 13
use
McDonald McDonald Substation
project provide and condition overload (Docket delay This frame.
RADW FOR BREAKDOWN 3
(Docket No. (Docket 14-05004). In to addition the installed installed and was rd Amendment,
the was installing
the as delayed was and
No. 01-10001)
remainder project $13,544,006 necessary project
studies and analysis found analysis and studies
placed 1 2019, 31, a new Docket No.17-11004.
originally resulted to to fold in proposal of in to
230 kV three-breaker ring ring three-breaker kV 230 load and another $2.65 million the service (without comply
as $2.4 as was THE project in
the in the began and submitted was
$3.3 million to be to million $3.3
additional voltage $9,371,491 on May
Arden
the with AFUDC). Page 176 of278 the for million $9.4 an in resulted area construction construction – 30,
MILLION Decatur that i not did NERC
$5.95 2019. (with (with The the
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 26. 27. 28. Veilleux-DIRECT Q. Q. A. 4. A. Q. A. (AF8) #6ADDITION BANK KV 230/138 SUBSTATION MAGNOLIA project transmission This The the the total, In PLEASE apply PROJECT NECESSARY? WASTHE WHY million. transformer, Magnolia existing the inside associated equipment and substation control,protection, telecommunication TPL-001-4 System element. load load up to the of planning’s Nevada No, by was necessary HAS THIS PROJECT THIS HAS provide and condition resource
installing regulatory
project
directly
existing
While filing. plan The
DESCRIBE THE PROJECT. THE DESCRIBE approximately 98 percent
studies and studies
project
comply to required was two two 230 a Power
Company
to to the asset complyto with the at transformer kV 230/138 new Magnolia or Tolson Performance will cost project, resulting has kV
Substation.
transfer capability additional analysis found analysis
calculated BEEN be was circuit
not involved fully NAC 14 $12 million, however, million, $12 sought PRESENTED TO THE COMMISSION? TO THE PRESENTED breakers, breakers, two
following following the as amortized
NERC contemplates 704 Chapter that installation of installation
of of rated capacity for the
NERC with in in a
Commission that 230/138 the reliability reduced total reduced the Faulkner
138 kV circuit can condition overload
December of loss of loss a
Magnolia kV
a WECC and
standard, mitigate the to approval new 230/138 kV large kV 230/138 new the transformers. –
cost line kV 138 Wilson
single $2.65 system. surrounding project This Substation.
2020, 31,
of
N-1 of loss either breakers, a project this of bulk electric system bulk electric resource million approximately reliability Page 177 of278 Transmission Transmission
mitigated be the and new systemnew within held filing plan
overload standard
will
power power could
$9.4 in
one not a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 29. 30. 31. Veilleux-DIRECT Q. Q. A. Q. 5. A. A. The WASTHE WHAT “Utility of definition for require that projects CAPACITOR located is the within Substation actual estimated The The AFUDC). PLEASE The volt-ampere RTM II RTM the PROJECT NECESSARY? WASTHE WHY kits. devices integration and AMI/DA to to become the local would customers customers in southern Nevada. Local an
uoae VAR automated network. 2G communications modems on modems communications
Company’s Capacitor Bank Capacitor total estimated
control jeopardize
automate to devices
transceivers, 43 Cisco firewall Cisco 43 transceivers,
DESCRIBE THE PROJECT. THE DESCRIBE
obsolete
reactive using new new facilities were (COK11) MODERNIZATION COMMUNICATION BANK
distribution capacitor distribution bank 2G cellular radio configuration was set cost
Without voltage by
time
cost TOTAL COST OF THE PROJECT? OF THE COST TOTAL control (“VAR”) Modernization Communication
the of end end of 2016, as Facility”
UEPA a the of n temperature and
the power support,
15 remote project This mode. project upgrades, The flow.
city limits ofHenderson .. city limits project permit to construct, this project construct, to this permit ne NRS under 2,400
installed installed and placed in control
May through
control the
banks capacitor distribution $8,243,240 was
the cellular cellular providers were FlexNet 2,400 and installations, scope
ih voltage with
the of factor revert would banks capacitor mode
because 704.860(2)
consisted expanded
based sites is 1 2020, 31, reliability and quality, less project
override service (without reliable installing of the on
is real-time on involved upgrading involved
decommissioning does not $7,797,175 by
and
controls,
The AFUDC).
Page 178 of278 uo central Yukon May the FlexNet with optimal
43 M400D 43 Magnolia 31,
meet the
RTM II RTM back
system which all to 2020. (with than to
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 32. 33. 34. Veilleux-DIRECT Q. Q. A. A. Q. A. 6. Yes. HAS THIS PROJECT THIS HAS to own and maintain the communication technology. communication the maintain ownand to management bank capacitor The because However, 17-06003. No. operational WASTHE WHAT from removed period were certification MERCURY–NORTHWEST cost while Phase facilities were installed and in-service and installed were facilities PLEASE TM528) over poles Phase substations Mountain Snow Northwest The project.
reconductoring total estimated the of This This project
the II of the I the of
completion completion cost DESCRIBE THE PROJECT. THE DESCRIBE
138 five project before Mercury–Northwest project kV line miles
was was reviewed in
through December 31, 2019, 31, December through
May cost of TOTAL COST OF THE PROJECT? OF THE COST TOTAL of of 11miles the over woodpoles aged replaced 96 between Radar line of section this
the BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN the of of of the 1 2017, 31,
Mercury-Northwest poles. iron ductile with 16 system
138 project project
the
138 by LINE KV the 2017 Nevada
the
by May 1, 2020. 1, May by and and Cold Creek
leveraging through through May the was kV
network communication the of costs this in included also was 2017 Line (without $10,234,517
138
EUL I II & I REBUILD certification filing. certification Rebuild replaced 49 aged wood aged 49 replaced Rebuild was $3,799,420 was
Power the
31, 2020 was $5,275,797. line kV
AMI substations substations with steel
project general FlexNet between identified rate
(with Page 179 of278 The AFUDC). was infrastructure
case, phase and Canyon T52 & (TM522
Mercury- not AFUDC) Docket
the in the of poles. fully All
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 35. 36. 37. Veilleux-DIRECT Q. A. Q. Q. A. A. line This PROJECT NECESSARY? WASTHE WHY Nevada southern been kV line. Outages phase-ground flashovers, phase-ground poles were poles was several Nevada No. aeolian Additionally, the Corrections, HAS THIS PROJECT THIS HAS The Canyon, Silver WASTHE WHAT resource replacement “Utility of definition for require that projects The AFUDC). (with AFUDC). (with AFUDC).(with The
total estimated at used
least 19 least outages during vibration, vibration, lightning including customers,
While filing. plan
has
to used
to poles wouldpoles have been facility” “like considered and Power
been Flag, Cold Creek, Radar, and Indian substations. Springs Creek, and Radar, Flag, Cold cost The
provide
occur occur yearly conductor ontheseconductor with many grid-hardenthe
cost the of TOTAL COST OF THE PROJECT? OF THE COST TOTAL planning among rated has final
Facility” more
UEPA a BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN rural the of as well as not proper cost of the project ofthe cost
strikes, strikes, flashover, and firearm project NAC 17 than
due sought in-service
communities Creech the project and, 704.860(2) NRS under
permit to construct, this project construct, to this permit cascading as
to contemplates 704 Chapter
22,000 past and current and line, transmission the phase-phase hog Dcme 3, 2019, 31, December through high wind and storm line Commission few years few onthe Force Air worst (phase date segments There outages. of hours customer
connected through May $5,092,011 31,2020,is phase for
performing
pole I
and II) and clearances. phase-ground and
has experiencedhas to due damage Base, failures. approval
I
to Mercury $5,101,045 was
December was induced induced phase-phase damage. Nevada circuit transmission Snow
Ductile a
under NRS 704.865. NRS under project this of
resource it if even
does not standard – Kyle Mountain, was This This line Page 180 of278 Department Northwest iron
$1,114,623 filing plan
31, steel and meet the (without the did, framing serves
2018.
have
in
138 and and
of in a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 38. 39. 40. Veilleux-DIRECT Q. Q. A. 7. Q. A. A. UPDATE TO THE MYS KV138/12 THE TO UPDATE Phase This in-service PLEASE in-service and new This section, telecommunication, section, controltelecommunication, a line provide WASTHE WHY facilities. The Yes. Voltage the HAS THIS PROJECT THIS HAS total capacity. total 2017 ofthe inclusion e 181 k 33 kV 138/12 new
data 10 and 9B, 9A, NAP Switch new Procyon-Railroad 138kV existing ofthe fold
project
general I
facilities facilities were
service Distribution (“SHVD”) Agreement (“SHVD”) Distribution
substation project substation DESCRIBE THE PROJECT. THE DESCRIBE project date
involved
rate
by February for for time. that at revenue in requirement costs project’s was case PROJECT NECESSARY? Switch, Switch, Ltd. phase
installed installed and in-service the originally medium-power MVA in Docket in
BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN II construction of construction 10, 2020.
was April was 18 was communication communication facilities. presented required No. 17-06003. No.
and and other SUBSTATION (WW) SUBSTATION 30, 2020. 30,
the pursuant
the to requiring buildings center
provides and 15-00009 No.
by transformer, associated new December
Phase Commission transmission line, installation of installation line, transmission The 138/12 MYS the to
Commission approved Commission II substation substation equipment
The Rule were facilities 12 31, 2018.
project switchgear kV in Nevada in 9 kV Substation High Substation Page 181 of278
Substation to to Substation The
included the 80 MVA of MVA 80 service
planning installed installed Power’s
and bus the
to
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 41. 42. Veilleux-DIRECT Q. A. Q. A. Since WHAT GENERAL PROJECT? the The rjc. Based project. determined ok n progress in work in contributions TOTAL THE ARE WHAT should payments which doeswhich not SHVD base performed (with (with AFUDC), and is not additional 31, 2019, All 2016. 30, ofutility service. provision
Company
estimated estimated total and and used to provide
the Agreement
VNS HAVE EVENTS close was
net
audit an some
$4,735,449 RATE investment an performed has
the of
of the CWIP. actuals under offset project
the on aide
have the of
“WP) 000 account 107000 (“CWIP”) cost (without $9,777,282 was and certification period in the to transferred and (“CIAC”) construction of are facilities installed CASE as applied been Rule of the
service payments finalized
(with the for included included for
OCCURRED 19 SHVD 9 COSTS project
RELATED AFUDC). AFUDC). The
to project audit customers before the were based based on facility OF THE PROJECT?OF THE recovery
total the finalized and Agreement a June after incorrectly refundable
Nevada
SINCE in cost
TO
AFUDC). project
service in in this rate to true-up
Power’s offset THE 1, 2017, and through December December through and 2017, 1,
the 15-00009, No. NEVADA May classified advance
was designation designation and Rule used and
The total 31, 2017, was $5,347,537 project the for placed placed in MYS SUBSTATION SUBSTATION MYS case. case. After the 2017 general
total in account in cost non-refundable as POWER’S
useful and the project, These actuals. Page 182 of278 in included true-up service
construction
Company
rate
Company 252040,
on June 9 in the the of 2017 case, the in total rate
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 43. 44. Veilleux-DIRECT Q. Q. 8. A. A. U/G CABLE REPLACEMENT FL-MGM REPLACEMENT CABLE U/G project This PLEASE 69 Power These PROJECT NECESSARY? WASTHE WHY existing shooflyExcalibur. and between MGM transmission the and 2016 were 2016 and had had to be project crossarms could could be this may Nevada would would have was constructing constructing a removed and replaced. removed and
kV MGM – most
depending project, not able also
line underground
installed mitigated
had Power
recent have duct repaired
lowered lowered from
DESCRIBE THE PROJECT. THE DESCRIBE n triain t ter original their to terminations and
been involves
temporary ak. The banks. been
Excalibur Excalibur and 69 failure reliability maintain to without completed approximately nlne xeddotg. During unplanned an extended outage. that quickly to an
the by risk
install occurring
new and option their original the on
segments transmission transmission line, replacement by scope 20 moving new cable new
installing exact
1,900 on December kV MGM have
the includes also replacing
location of a of location the positions in positions order to facilitate feet the of
new cable new cable and as had a had crossarm part
while lmnotasiso ie. Nevada Flamingo lines. transmission - f e underground new of
service
existing cable, & EX-MGM would positions,
history 2, 2016. Prior the failure, unexpected an of both both underground
with adequate with and termination down. failure, but have
to with failures, termination of underground ntlain of installation the all in
that so the needed the lowering (TM295) by Substation MGM repairs in project, project, the cases
any to length cable be to
Page 183 of278 the sections segments the
future a
2008, 2014, repair. repair. This
in terminator terminator temporary pulled. crossarms Company
Without raise the failure
the of result were two two
all If
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 45. 46. 47. 48. 49. Veilleux-DIRECT Q. Q. Q. A. A. Q. A. Q. 9. A. A. Nevada No, The HAS THIS PROJECT THIS HAS WHAT IS THE IS WHAT The resource MYS SUBSTATION 12 SUBSTATION MYS of“Utility Facility” definition for require that projects WASTHE WHAT service 6,2020. onMarch the of portion project This the of PLEASE hs project This be will AFUDC). The PROJECT NECESSARY? WASTHE WHY facilities associatedand feeder to serve Switch’s NAP 10 feeder project. 10 feeder project. serve NAP feederconstruct to Switch’s MYS1206
estimated estimated total Company
project of the portion completed
period ECIC the presented in
While filing. plan
DESCRIBE THE PROJECT. THE DESCRIBE
involved necessary was Power
69 remaining is and completed has
COMPANY SEEKING segment underground kV
cost
TOTAL COST OF THE PROJECT? OF THE COST TOTAL has the
of of the
UEPA a at BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN segment not the of installation KV BUS SECTION #1(XF) KV SECTION BUS
kVsubstation.MYS 138/12
NAC to 21 project sought 704.860. under NRS provide permit to construct, this project construct, to this permit contemplates 704 Chapter will
and discussed in Section III Section in discussed and was seeking Commission
be May through service completed completed by $3,244,738
TIME? THIS AT
that third 12 third recovery via replaced was
approval a
kV switchgear bus section #1 section bus switchgear kV 31, 2020, 31, (without line
the the for extension agreement extension fourth
a
project this of restored and
AFUDC). AFUDC). The resource $1,400,000 is MGM – MGM
does not below. quarter 2020 and Page 184 of278 filing plan Flamingo meet the to back
(with costs in
to a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 50. 51. 52. 53. Veilleux-DIRECT Q. Q. A. Q. A. Q. A. 10. A. Nevada No, The HAS THIS PROJECT THIS HAS WASTHE WHAT resource PROGRAM GRID RUGGEDIZATION TRANSMISSION of“Utility Facility” definition for require that projects costs costs of the planning This This reliability and in-service installed PLEASE Between 2015 and 2015 Between poles. power distribution and transmission onan – Mountain on the WHY IS WHY critical system Nevada Power percent ofsevere mitigate impact and the
estimated estimated total
Harry
highway from
While filing. plan in-service
PROGRAM NECESSARY? THE DESCRIBE THE PROGRAM. THE DESCRIBE
project
Allen - Pecos Pecos #2 230 kV line Allen - Lincoln Power 35.01 minutes in 2015 to 43.8 minutes in 2018, in minutes 43.8 to 2015 in minutes 35.01
program and
through 2018, cost
date
TOTAL COST OF THE PROJECT? OF THE COST TOTAL
has transmission County
average
October by
of the UEPA a included included the BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN the for has Nevada Power not December NAC 22 line kV 69 sought project 704.860. under NRS interruption duration index ("SAIDI") increased 25 ("SAIDI")increased index duration interruption project permit to construct, this project construct, to this permit events. climate contemplates 704 Chapter crossing 15, 2018. removal was Commission 31, 2019, was
and four $4,088,219 were
locations to ruggedize to locations Seven
witnessed a witnessed October and and replacement is with replaced
$3,050,398
wooden wooden approval (without 1, 2018. degradation in reliability. reliability. in degradation transmission structures transmission structures structures on the
a
project this of (with (with AFUDC). The of existing
resource AFUDC). The (AFT) metal The
and storm-related and does not
the Page 185 of278 facilities structures electric filing plan overhead meet the
Sheep
were final in grid at a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 54. Veilleux-DIRECT Q. A. This This increase major2018, including event customer outage winds high 2018, Clark climate line transmission line transmission another the distribution To prevent To fail. woodpoles causing the events, wind to extreme that circuits distribution the of cases numerous Nevada No, analysis that lines transmission as part as these crossings line met that 20distribution and crossings HAS THIS PROJECT THIS HAS from wood to steel. wood from to resource for require that projects
safety
–
the of extreme conditions,
Equestrian While filing. plan dniid 12 identified the people, of
future
line is Power program due
hours increased
falling to fall to caused Henderson in instances
to 69 has a
Mercury–Northwest poles wood had ruggedize to
number
UEPA a line kV
BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN the onto line transmission Company crossed interstate onto not pole wood
NAC that days. 23 weather events, and events, weather sought of factors,
could cause could permit to construct, this project construct, to this permit from along over highway. contemplates 704 Chapter performed an analysis an performed system Commission
108,002
failure highways, Highway Boulder on eight
I-15. including
one
69 Similarly replacement through containing segments cascading wood transmission structures on the on structures transmission wood the on hours hours in 2015 kV or
The extreme the of sides both railroads,
line transmission approval aging
high 2018, in Company Jean failures
criteria infrastructure, on all on to wind.
12 roads major a to to 1,041,499 hours in al and fail, project this of resource line, kV or put or
does not
and transmission experienced has are and the of in example, For
Page 186 of278
The crossing. 29
winds caused winds failing jeopardy in caused filing plan individual
structures structures
changing the with included meet the other or due
in the to a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 55. 56. 57. 58. Veilleux-DIRECT Q. Q. Q. A. Q. A. A. 11. A. The WHAT IS THE IS WHAT (AFF) WALL PERIMETER L SUBSTATION CRITICAL The “like with poles existing “Utility of definition the for hs project This WASTHE WHAT 69 kV 69 County 2020. PLEASE January A The AFUDC). (with $2,656,000 total estimated May 31,2020. PROJECT NECESSARY? WASTHE WHY critical metal gates.metal address The documentation. R4 these address to
Company total estimated
Harry ‘L’ the
DESCRIBE THE PROJECT. THE DESCRIBE
WECC 2019 the by identified vulnerabilities Substation with a with Substation
novd replacing involved Allen segment two completed has
at
vulnerabilities COMPANY SEEKING the of costs completion
TOTAL COST OF THE PROJECT? OF THE COST TOTAL cost line kV 230 #2 Pecos - Facility”
that
revised CIP-014-2 R5 documentation accepted documentation R5 CIP-014-2 revised
facility” pursuantfacility” audit the of restored and replaced was 24
CMU under
determined places a places
project facilities the
the of
704.860 NRS wall block existing
$3,177,802 was line 12 block CMU
were to NRS 704.865. NRS to TIME? THIS AT current security
project the and hi ln fence link chain
installed and installed segments and anti-cut/anti-climb expanded anti-cut/anti-climb and replacement involves and/or aiiis o not do facilities team wall
May through Sheep Mountain – Mountain Sheep service to back (without the in
seeking is and as
placed a
key NERC at Page 187 of278 the The AFUDC).
component appropriately in 2020, 31,
on
designated CIP-014-2 by service
recovery recovery May Lincoln Lincoln WECC 31,
by of of is
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 59. 60. Veilleux-DIRECT 61. Q. Q. Q. A. A. A. 12. Nevada No, one strong when facilitate to deterrence employedand other measures, security with measure, The HAS THIS PROJECT THIS HAS requirements. For requirements. MYS SUBSTATION 12 KV BUS SECTION #2(X6) 12 KV SECTION BUS SUBSTATION MYS security fence WASTHE WHAT project This resource of“Utility Facility” definition for require that projects PLEASE The AFUDC). (with $2,617,115 total estimated service byMay substation. MYS138/12kV at facilities associated#2 and
of total estimated
barrier
the defensive
plan. While filing. plan
DESCRIBE THE PROJECT. THE DESCRIBE defense-in-depth layers defense-in-depth of the
the involved with Power
29, 2020. at capabilities
entry enhanced this project, a project, this the of costs completion
TOTAL COST OF THE PROJECT? OF THE COST TOTAL cost has
UEPA a BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN
not the of the of installation NAC 25 for locations identified during identified locations for sought 704.860. under NRS
permit to construct, this project construct, to this permit project CMU combined
contemplates 704 Chapter as identified was gates facilities Commission
security plan. Such plan. barriers security (without $3,895,077 was
are second 12 kV switchgear kV 12 second
project
scheduled
block
approval May through wall
a vital o be to
the a project this of expanded and resource
CIP-014-2 component does not ntle and installed
Page 188 of278 The AFUDC).
provide 2020, 31, section bus filing plan meet the R1-R3
the of metal
delay in
in is a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 62. 63. 64. 65. 66. Veilleux-DIRECT Q. Q. Q. Q. A. A. A. Q. 13. A. A. hs project This MYSSubstation project with This Yes. originally was submitted The PROJECT NECESSARY? WASTHE WHY KV 138/12 BANK SUBSTATION PROCYON HAS THIS PROJECT THIS HAS WASTHE WHAT 2017 feeder serve to construct MYS1207 Switch’s in in “Energized, Used and Useful” This This project the costs associated with this project were this associated costs with the PLEASE AFUDC). The $2,469,541 ofthe costs completion projectat (with 31,2019,is December through project customer-driven This power equipment PROJECT NECESSARY? WASTHE WHY equipment. telecommunication ntlain f a of installation Initiation and Purchase Initiation Apparatus
estimated estimated total general rate
circuit
DESCRIBE THE PROJECT. THE DESCRIBE
inside
involved necessary was facilities breakers,
case
the
cost
scheme protection and automation substation TOTAL COST OF THE PROJECT? OF THE COST TOTAL installing Docket in existing
of of the service in and were installed BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN one
to 26
project required was
bank kV 12 provide a This Substation. Procyon
status status during No. 17-06003, however, new new 138/12 kV transformer
Agreement was service
$4,228,922 base. ofrate out adjusted
pursuant
NAP 9feeder project. NAP that breaker #45227, Line #45227, via
#3 ADDITION #3 etfcto eid At certification period. a
on November
line (without to associated and executed it extension agreement extension
was was placedincorrectly
project Extension Agreement Extension
bank #3,
AFUDC). (WW) (PV) Page 189 of278 Rule 2017. 2, also included included also
two
during the substation substation new and 9 The that 138 138 kV Design time total
to
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 67. 68. 69. 70. Veilleux-DIRECT Q. Q. Q. Q. A. A. A. 14. A. Nevada No, The HAS THIS PROJECT THIS HAS EQUESTRIAN SUBSTATION 230KV SHUNT REACTOR (A1W) REACTOR 230KV SUBSTATION SHUNT EQUESTRIAN new customer’s and #18-00064 WASTHE WHAT project This On August On resource of“Utility Facility” definition PLEASE PROJECT NECESSARY? WASTHE WHY for require that projects at equipment. Megavolt-Ampere resulted AFUDC). The replacement department acceptable
cost completion
estimated estimated total
in While filing. plan
DESCRIBE THE PROJECT. THE DESCRIBE
limits. This project This limits. a 12, 2016, a 2016, 12, performed a performed
of of the the involved Power fire facilities
associated Large associated for request the and
Reactor Reactive the of cost
TOTAL COST OF THE PROJECT? OF THE COST TOTAL has
of of the UEPA a service in and were installed catastrophic BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN voltage
project not removal total was 30 MVAservice. NAC (“MVAR”) #R1 Shunt #R1 (“MVAR”) 27 sought project 704.860. under NRS was loss necessary
permit to construct, this project construct, to this permit control December through Project contemplates 704 Chapter replacement and necessary the of failure was Commission determined which analysis Line $2,891,332 to maintain to system maintain The reactor. the of restore to Extension Agreement Extension
Equestrian Shunt Equestrian
approval
station associated and Reactor the of 2019, 31,
by March 29,2019. by March (without the Electric Equestrian 230 Equestrian
Equestrian Substation Substation Equestrian
a voltage project this of
is $2,410,032 (with (with $2,410,032 is resource AFUDC).
does not System Page 190 of278
an
#56447 for a for #56447 levels within #R1 Reactor immediate filing plan The meet the Control kV 100 kV
total in a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 Veilleux-DIRECT 2 73. 71. 72. that payment settlement a received Company The Power Substation, and Substation, during certification. certification. during settlement the allocated then and Q. Q. A. 15. A. Q. A. catastrophic the for
ADDITION KV 138/12 #3 BANK SUBSTATION SPARTA This project involved the installation of installation the involved project This Nevada No. PLEASE HAS THIS PROJECT THIS HAS area. back inside equipment substation associated failed The replacement not WASTHE WHAT IRP forreview an in Commission The AFUDC). $1,342,990 ofthe costs completion projectat (with 31,2019,is December through The AFUDC). (with $2,234,548 November
it significant caused
estimated estimated total upgrade or expand
to unexpectedly original its
failures
DESCRIBE THE PROJECT. THE DESCRIBE
15, 2017.
did Power like of
settlement allocated The facilities. different the between proceeds total of fourof
settled the claims for all for claims the settled Company The transformer. the to damage
cost providing configuration,
and The TOTAL COST OF THE PROJECT? OF THE COST TOTAL at equipment. kind bushings the of One bushings. Trench completion costs completion not
of of the
BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN was facilities the submit
28 was
to necessary deemed the of capabilities
project Group the Trench from negotiated were or under the the planning was
project
the installed installed and in-service a new 138/12 kV transformer bank #3 and kV transformer bank 138/12 new a it Therefore,
the of $2,738,293 existing Sparta Substation.
reactive in-service
to regulations. and statutes UEPA
project
the existing replace Commission because Commission capability (without
failed that was
May through date kind. in
was and substation, not Nevada compensate to the for
by AFUDC). (WU) was the to umte t the to submitted August The Page 191 of278 Equestrian at
31, 2020, 31, surrounding project will be addressed addressed be will
project 9, 9, 2017. The
failures, four the
total
unit was did did
is a 2
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 74. 75. 76. 77. Veilleux-DIRECT Q. Q. A. Q. A. Q. A. 16. A. project This PROJECT NECESSARY? WASTHE WHY approximately increase Nevada No, nameplate percent as a as HAS THIS PROJECT THIS HAS the executed Summerlin Village Summerlin executed the 30, 2013. The SWENSON KV 138/12 SUBSTATION SWENSON WASTHE WHAT resource of“Utility Facility” definition for require that projects project This PLEASE AFUDC). The $1,998,994 ofthe costs completion at project (with 31,2019, is December through power kV equipment
estimated estimated total contingent The bysummer 2019. rating summer normal of
While filing. plan capacity
DESCRIBE THE PROJECT. THE DESCRIBE
rating inside circuit
installing involves was Power
facilities 37 V, r 90 or MVA, 33.7 required facility
of relieve to required the for
rae, one breaker, cost 37.33 37.33 MVA. Sparta
TOTAL COST OF THE PROJECT? OF THE COST TOTAL has existing The growth. customer-related
UEPA a of of the BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN service in and were installed not NAC 29
sought project 704.860. NRSunder
project This Substation. Swenson
the
to construct to 16A Addendum 16A permit to construct, this project construct, to this permit breaker bank kV 12 contemplates 704 Chapter new percent
loading was Commission
Substation Substation was forecasted load to 103.7 to 138/12 ADDITION #3 BANK $2,146,565 the loading the on kV transformer bank #3, bank transformer kV new Sparta new
December No contract, signed 1.
approval
existing
the of by May 31,2019. by May (without
summer 2017 loading was was loading 2017 summer
and associated substation substation associated and transformer was identified identified was transformer
1214 feeder as part as feeder 1214 a existing project this of Sparta
resource AFUDC).
does not (WS) Page 192 of278 also included included also
Bank
transformer filing plan The
meet the one #2 and #2
total in 138
of a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 78. 79. 80. Veilleux-DIRECT Q. Q. A. A. Q. A. This This project No. Due No. PROJECT NECESSARY? WASTHE WHY Agreement equipment. telecommunications of installation THE HAS Purchase Apparatus and ntlain f ak , and 3, bank of installation the improves experiencing. in in its AGREEMENT? construction for construction hi work their continue Swenson Substation through Substation Swenson Company Nevada No, at HAS THIS PROJECT THIS HAS Purchase Agreement and Initiation Apparatus resource
the supply time
While filing. plan the to
and prudently costs incurred
the
the of cessation Upon plan. for was
chain and has informed the
Power
hn will then current investment
reliability THE EXECUTED CUSTOMER three MSG customer-driven customer-driven and automation, substation has to the pandemic, Las
BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN solidify five not
at Agreement was made was
NAC LLC’s Vegas, 30
scheme, protection and automation associated
attempt an in months the sought the its the of execution contemplates 704 Chapter
the upon based usain wih utmr are customers which substation, commitment
required required pursuant customer Commission retained has and
Company 531 n ascae Line associated and #52311
the pandemic, request
to mitigateto risk. rtcin scheme protection experienced has
it
the for let to line
that information will approval service. MVA 26 for
to to Rule security The agreement. extension be
the project customer’s LINE temporarily contingent
project a project this of resource 9 Design
substantial the under Page 193 of278 EXTENSION
with catch-up was
aiiis at facilities suspending suspending and
filing plan Extension Extension Initiation currently available Design delays
in new new also also will The a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 81. 82. 83. 84. Veilleux-DIRECT Q. Q. Q. Q. A. A. 17. A. A. The 138/12 KV #2ADDITION BANK SUBSTATION MYS WASTHE WHAT hs project This of“Utility Facility” definition for require that projects hs project This PLEASE The AFUDC). $1,511,166 ofthe costs completion projectat (with 31,2019,is December through PROJECT NECESSARY? WASTHE WHY Nevada No, inside equipment substation associated $1,993,610 period. during certification the installed substation distribution increase the with 2019, 31, 112.8 HAS THIS PROJECT THIS HAS forecast resource
estimated estimated total percent
commercial and residential of increased capacity While filing. plan
DESCRIBE THE PROJECT. THE DESCRIBE The (with AFUDC).
relieve to required was Power novd installing involved
the of total
The growth. customer-related for
the of exception cost
TOTAL COST OF THE PROJECT? OF THE COST TOTAL
at has summer
completion costs completion at transformer
UEPA a of of the BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN not
NAC 31
sought project 704.860. NRSunder normal permit to construct, this project construct, to this permit facilities contemplates 704 Chapter a
replacement
new was
loading Commission rating
was substation MYS the
the of $2,914,443 were 138/12 kV transformer Bank #2 and and #2 Bank transformer kV 138/12 existing MYSSubstation. by the on
installed andinstalled service in
project considering 2019 of summer growth. spare
approval existing existing (without transformer, May through (XG)
a load to forecasted 138/12 kV 33 MVA 33 kV 138/12 project this of
Y Bn # and #2 Bank MYS resource AFUDC).
does not Page 194 of278 will which
31, 2020, 31,
by October filing plan The meet the
total in
the
be to to is a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 85. 86. 87. Veilleux-DIRECT Q. Q. A. Q. A. 18. A. The 138KV TRENWA CABLE SUBSTATION REPLACEMENT CLARK WASTHE WHAT of“Utility Facility” definition for require that projects project This AFUDC). The $1,936,438 ofthe costs completion projectat (with 31,2019,is December through PLEASE The Control Substation. and (“trenwa”) PROJECT NECESSARY? WASTHE WHY Site replaced. or used as partas when the table water many caused immersing the Additionally, equipment. exposed trench and Civil
estimated estimated total 138
improvements along improvements
of this projectof to this
kV Clark Generation Station was Station Clark Generation
DESCRIBE THE PROJECT. THE DESCRIBE
control substation
and the included
originally was Substation Clark of portion the of facilities
below-grade associated corrosive
existing old
cost trenwa
TOTAL COST OF THE PROJECT? OF THE COST TOTAL fiber telecommunications and grading
UEPA a of of the service in and were installed soil mitigate existing
removal
with to lids and sidewalls soil 32
project 704.860. NRSunder
and various civil various and iig and wiring trenwa kV 138 odtos culd with coupled conditions, removal permit to construct, this project construct, to this permit replacement and was
first
the in facilities and replacement and $1,938,516 optic fiber telecommunication ul. However, over built.
conditions and divert and runoff.conditions water
open leaving deteriorate, severely were improvements would
optic
the of
by July 1,2019. by July (without continually
cables Clark of section kV 138 the in constructed
cable underground of the these
AFUDC). site poor were
does not
the Page 195 of278 were facilities
flood also included included also re-routed, re re-routed, years, a The location, meet the thereby
(AF2) 1960s cable.
total high way -
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 88. 89. 90. 91. Veilleux-DIRECT Q. Q. A. Q. Q. A. A. 19. A. Nevada No, HAS THIS PROJECT THIS HAS mitigate a mitigate required The KV #7ADDITION BANK 138/12 SUBSTATION PECOS WASTHE WHAT resource of“Utility Facility” definition for require that projects This project involved the installation of installation the involved project This hs project This PLEASE at PROJECT NECESSARY? WASTHE WHY AFUDC). The inside equipment substation associated at transformer substation distribution 122 increase provides area. the in new the additions load
opein ot o the of costs completion
estimated estimated total percent
capacity While filing. plan relief to
DESCRIBE THE PROJECT. THE DESCRIBE hazard. safety potential
improve
summer of relieve to required was Power
to facilities the The growth. customer-related for
cost
TOTAL COST OF THE PROJECT? OF THE COST TOTAL existing has overall
UEPA a of of the BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN normal were
not
NAC project 33 Pecos bank and provides site
sought project service in and installed 704.860. NRSunder rating permit to construct, this project construct, to this permit odtos replace conditions, contemplates 704 Chapter through
was loading Commission Pecos
by the a new 138/12 kV transformer bank #7 and kVtransformer bank 138/12 new a $2,788,159 summer existing Pecos Substation. was Substation May the on
1 2020, 31, of approval
existing
existing by (without equipment deteriorated The 2018. the April
capacity
a load to forecasted 138/12 project this of (OH) is #6 Bank Pecos
resource 24, 2020. AFUDC).
$1,856,958 does not
new needed Page 196 of278 kV 33 MVA 33 kV transformer filing plan The meet the to
(with serve
total in and and
to to a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 92. 93. 94. 95. Veilleux-DIRECT Q. Q. A. Q. Q. A. 20. A. A. Nevada No, HAS THIS PROJECT THIS HAS The TELECOMMUNICATIONS GARDNER REID WASTHE WHAT resource of“Utility Facility” definition for require that projects hs project This Senate PLEASE PROJECT NECESSARY? WASTHE WHY AFUDC). The $1,830,228 ofthe costs completion projectat (with 31,2019,is December through equipment REPLACEMENT constructed part as the The Nevada. southern generation in Docket The included which burning
First estimated estimated total ERCR
No. Bill
units While filing. plan Amendment
DESCRIBE THE PROJECT. THE DESCRIBE
Unit Gardner Reid on located included plan
14-05003
required 123 the involved Power at facilities capacity and reduction emissions an the
of this project. of this cost (6Q)
Reid TOTAL COST OF THE PROJECT? OF THE COST TOTAL has
Nevada and to
UEPA a of of the service in and were installed BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN Generating Gardner Nevada not
relocation the Nevada NAC 34
sought project Under NRS 704.860. NRS Under decommissioning permit to construct, this project construct, to this permit contemplates 704 Chapter Power's
Power’s
approved Commission and the filed Company to Power and was Commission
$1,938,516
replacement resource integrated 2013-2032 4. Energy
Station. Located Station. new A eliminate all of demolition and
approval Supply
by May replacement MICROWAVE (without microwave of 800 the Plan Update Plan
a 8, 2019. project this of existing
resource AFUDC). MW the on
does not ("ERCR") plan. plan. ("ERCR") oe ws also was tower Page 197 of278 coal-fired of
Unit of roof
microwave
filing plan four
for 2015, for The meet the
plan
coal- total in in in a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 96. 97. Veilleux-DIRECT 98. Q. Q. Q. A. A. A. The Nevada No, PLEASE removed HAS THIS PROJECT THIS HAS ESTIMATED? were 4 Nevada begin January 1,2018. The sonnet telecommunications branch exchange the project WASTHE WHAT resource of“Utility Facility” definition for require that projects using internal AFUDC). The $1,820,626 ofthe costs completion projectat (with 31,2019,is December through
project
estimated estimated total scope
was underway. Construction Construction was was underway.
Power’s
While filing. plan to prior replaced and
microwave had estimate and DESCRIBE
Power rates. labor facilities originally estimated work estimated originally
(PBX) the in assets transmission
cost
TOTAL COST OF THE PROJECT? OF THE COST TOTAL has
UEPA a of of the service in and were installed
telephone BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN
equipment communications i not did not
H THE WHY NAC ring 35
sought project 704.860. NRSunder
the permit to construct, this project construct, to this permit and originally
contemplates 704 Chapter system demolition necessary supports was Commission
also also performed by
at to $1,046,918
include WERE COSTS the equipment This region. be Unit of using performed plant, plant, which was
approval the
by January 25, 2018. by January (without
4, replacement
that high-speed protection of protection high-speed was which
contract
a project this of
resource AFUDC). s part is
does not internal identified identified after the THAN HIGHER Page 198 of278 services, services, where
to needed the of to scheduled filing plan resources, The meet the the of private
total in be a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 99. 100. 101. 102. Veilleux-DIRECT Q. Q. Q. 21. A. Q. A. A. A. KV SUBSTATION SWITCHYARD 230KV SUBSTATION BREEZE PROJECT hs project This new This PROJECT NECESSARY? WASTHE WHY PLEASE Yes. HAS THIS PROJECT THIS HAS associated and communications feeders, distribution included acquisition of land and land of acquisition included metering, new 230 new metering, kV lines for the new Breeze Switching Station. Station. Breeze for Switching lines new the 230kV as overhead the as well site Voltage Nevada LLC. Development, WASTHE WHAT Confidentiality The While 9, 2019. require 10003 and and wasand total
total estimated at project This
NAC the of costs completion
a
granted deviation from NAC 704.9503(1)(a). NAC from granted deviation Distribution Agreement Distribution
switching UEPA DESCRIBE THE PROJECT. THE DESCRIBE Commission Commission granted a
involved hpe 74 otmlts a contemplates 704 Chapter
and Non-Reliance
permit was reviewed was double kV
project station cost COST TOTAL the
BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN Nevada construct, to the of
ntlain f a of installation 36
circuit
project
project under
Power land rights land provides and 18-00032
permit Agreement for this project. for this Agreement
pursuant required is
OF THE PROJECT?OF THE line the through was $12,669,396 was to to construct the and fold, 230 fold, provisions of UEPA in Docket in UEPA of provisions
resource 230 associated with associated
requested Power December 31, 2019, 31, December switching kV
double kV executed also customer
in in UEPA No. filing plan project This facilities.
Rule to
(without service new
the
circuit
9 Substation High Substation 9 side high station, its in station switching that projects for (A5Z)
Page 199 of278 451 on January The AFUDC). is $2,433,775 $2,433,775 is
voltage high application, Jasmine to
No. 18- No.
also
a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 104. 103. Veilleux-DIRECT Q. Q. A. A. 22. (A09) 138KV #2 LINE ELKHORN–NORTHWEST was Substation Elkhorn PROJECT NECESSARY? WASTHE WHY PLEASE Company to addition in AFUDC), (with associated installed. At Substation. Elkhorn existing the at equipment scheme protection and automation substation service in and were installed total from to the Northwest-Elkhorn 138 Northwest-Elkhorn the to AFUDC), arrangement usain n all and Substation without maintenance equipment This project This
Northwest
at Northwest completion
performed performed an audit DESCRIBE THE PROJECT. THE DESCRIBE in in addition to equipment substation and protection, telecommunication,
the involved os not does new two Substation, Under Substation. costs
the Additionally, loads. associated the capability bypass for allow
the of originally new two of installation
customer’s
37 by
and and finalized line kV project
May 30,2019. offloading the the
in constructed this radial this
circuit power kV 138 customer’s
in resulted adjusted adjusted CIAC 31, 2020, 31, May through
the
total an configuration, entire substation. substation. entire and associated telecommunication telecommunication associated and CIAC the
circuit power kV 138 2005 and was and 2005 cost
the of loss complete
of of $9,287,690. perform to
true-up f $8,405,454. of
breakers,
is $1,496,694 (with (with $1,496,694 is high-side
for the unplanned outage unplanned
sourced radially radially sourced normal Page 200 of278 switches The
project, the were
the After breakers,
facilities
Elkhorn breaker breaker routine also and and
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 105. 106. 107. Veilleux-DIRECT Q. Q. Q. A. A. A. 23. project This Nevada No, PROJECT THIS HAS source area. surrounding WASTHE WHAT VEGAS SUBSTATION 138 KV SUBSTATION VEGAS The resource of“Utility Facility” definition for require that projects This This project PLEASE total the of costs AFUDC). The facilities were installed and in were installed AFUDC). facilities The create associated equipment telecommunication and protection to Upgrades configuration. substation looped project. Cheyenne terminals,
estimated estimated total
at
a completion at
new While filing. plan
DESCRIBE THE PROJECT. THE DESCRIBE Elkhorn equipment telecommunication and protection
project
involved the involved necessary was terminal Power
the of costs cost provide and December through
COST TOTAL has and position and separate and position
UEPA a of of the BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN installation of installation one not Westside
eliminate to NAC 38
sought project 704.860 NRSunder project
permit to construct, this project construct, to this permit reliable
contemplates 704 Chapter PCB ADDITION were substations,
OF THE PROJECT?OF THE was Commission
31, 2020, 31, May through 31, the service $2,071,189 $2,071,189 (without 2019,
radial new the service single 138 kV 138 power circuit is $683,732 is the to provide configuration,
approval
(V1) by January included also tapped emerging
at
at a to Substation Vegas project this of The AFUDC). (with
resource is $1,337,745 is source AFUDC). The the
does not 1, 2020. Page 201 of278
remote in growth part as
into a into breaker breaker and filing plan
a meet the second of this this of source fully-
(with
total in the a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 Veilleux-DIRECT 108. 109. 110. Q. Q. A. Q. A. A. was Substation kV 138/12 Vegas PROJECT NECESSARY? WASTHE WHY Nevada No, PROJECT THIS HAS from resulted segments nlne outage unplanned project This customers. WASTHE WHAT Vegas Substation into the service to The resource of“Utility Facility” definition for require that projects at AFUDC).
opein ot o the of costs completion
estimated estimated total
the
While filing. plan Cheyenne The facilities were installed and in were installed facilities The
necessary was
Power surrounding area. surrounding
in
the either on cost
– COST TOTAL has
a the Westside
complete
UEPA a of of the BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN Cheyenne-Westside not
eliminate to NAC project 39
sought project 704.860. NRSunder 138 kV line. line. kV 138 permit to construct, this project construct, to this permit
outage Cheyenne contemplates 704 Chapter originally through
OF THE PROJECT?OF THE was Commission the to Vegas to $1,437,569 by configuration tapped constructed – May
line
service tapped this Under Vegas and and to provide
1 2020, 31, Substation approval
(without by April or as Vegas a
a tapped project this of is
its and resource AFUDC). 21, 2020.
$1,202,306 does not enhanced reliable
– arrangement, Page 202 of278 Westside
configuration configuration fully over 15,000 over filing plan The meet the looping looping
(with total in line
an a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 111. 112. Veilleux-DIRECT Q. 24. Q. A. A. REPLACEMENT RELAY TRANSMISSION STRIP reliability transmission This PLEASE devices line Transmission and business. resorts major corridor most for (mainly relays Line PROJECT NECESSARY? WASTHE WHY reliable ensuring relays protection The having 1) as having 2) or support, protection. protection. found to be to found January of As of useful life. spare for services since
criteria
protection protection relays within the that recommended
Loop Decatur-Caesars-Venetian-Strip-Claymont 3: Loop Sinatra-Bellagio-Polaris-Decatur 2: Loop Clark-Concourse-Suzanne-Sinatra 1: for 138 for
DESCRIBE THE PROJECT. THE DESCRIBE
either for replacement
the reached
2009, RFL-9300 relays RFL-9300 2009,
lines transmission kV were SEL-221F) and RFL-9300
parts have parts
inadequate panels
a
properly to limitation a
end of its useful its of end at plan migration
of a 40 has (RFL) manufacturer The discontinued. been also were substations to protect to
program
protection protection device Las Vegas Strip corridor have line
have loops. corridor along Strip three protection serving lines transmission replaced
for life been
the the on substations
the and with panels and assessed, identify taken out taken was replacement failing
line modern with replaced
when when a stopped vendor als ihn t zone its within faults (A86)
the reached have or production and support and production out-of-date
relay evaluated been evaluated and these of
Vegas Las Page 203 of278 was was identified
protection protection providing be relays
failing failing Strip Strip
end end
of
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 113. 114. Veilleux-DIRECT Q. Q. A. A. project implemented. implemented. sensitivity Nevada No, HAS THIS PROJECT THIS HAS provide inadequate protection orresult protection inadequate provide electrically The SIR high A relays. “SIR” WASTHE WHAT limitation of the step distance protection ability of the older older the ability distanceSEL-221F of step ofthe protection limitation in-zone an between The resource of“Utility Facility” definition for require that projects at The AFUDC). service and werein installed facilities The
the of costs completion
estimated estimated total impedance low
between method)
under also and
While filing. plan
see to short
Power
Due in-service planning within faults line
cost
may the of reconfiguration to
and
COST TOTAL has the of
certain using (classified lengths
UEPA a of of the BEEN PRESENTED TO THE COMMISSION? TO PRESENTED THE BEEN
out-of-zone result substations, not
project NAC 41 the with combined lines, transmission underground
sought project system 704.860 NRSunder
the in its permit to construct, this project construct, to this permit contemplates 704 Chapter December through primary
date
fault. fault. distance OF THE PROJECT?OF THE was the configuration, Commission distance for challenges protection presents
in a in the for
$1,498,325 15,2019. March by misoperation. misoperation. zone due exacerbated further is This
lines transmission relays
project the of protection and protection of
approval trouble having source-line (without 31, 2019, 31,
aging was
a December project this of
SEL resource AFUDC).
the with is does not impedance
$965,443 Page 204 of278
lack relays differentiating therefore
relays. filing plan 31, sky open The meet the
the to 2019.
(with ratio total may in the a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 Veilleux-DIRECT 115. III. 116. Q. A. INCIRCUMSTANCES CHANGES EXPECTED Q. 25. A. discusses section This THE DESCRIBE Veilleux-Direct-2 Spare Substation were 2020) but 2020) hs project This PLEASE transformer some impacted ability delaying thus China the in-service the spare to apparatus customer outages. This equipment This outages. customer result $3,350,033 following:
to be to
core wound
of a of prompted travel prompted appropriately to One $2,045,298 kV,37.4MVAspare 230/12.4 Two - transformers
DESCRIBE THE PROJECT. THE DESCRIBE
were failure. placed
–$1,304,735 spare transformer kV,56MVA 138/12.4 (including
units
provide date. provides to commitments
services contracted delayed as a as delayed
Wound Core service in equipment These oversees. constructed being that SECTION. IN INCLUDED PROJECTSTHIS The reliable
advisements monitor and witness and monitor the to prior commenced had the of consists which costs), overhead and installation the for investments Company 42 result before directly or electric Nevada
custo o system of acquisition Equipment
the of from procured fills
that restrictions and the for service
vacancy, existing an ongoing Power’s of end being
major pandemic. replaces a replaces
the will and able mitigate and the T&D projects listed in in listed projects T&D and manufacturing
(May period certification to travel to spare
The pandemic, COVID-19 receive
critical
the delayed travel outbreak COVID-19 projects and impacting impacting and projects that
need for need increased an the to the three was also restrictions risk spare
Page 205 of278 United States, States, United
testing totaling units, as installed Company’s extended of substation
Exhibit the of
and 31,
in a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 117. Veilleux-DIRECT Q. A. utility Standard PROJECT NECESSARY? WASTHE WHY and capacity core wound substation other and transformers, of long-lead loading) and 6 to for8 months high-voltage transformers spares project reliability equipment. Normally, equipment. availability and/or depleting failures, transformer ewe 21 ad 08 Nevada 2018, and 2017 Between assets. each ofthese with long lead times to specify, procure and procure specify, to long lead with times Company.the Coupled projects outpacing the general transformer, during transformers MVA 37 this MVA transformers
created
on hand varies based
where
critical of
a
spare
classes. after months 18 to 12 is significant risk due of outages extended significant the
practice project equipment
acquiring to 18months. ofapproximately period a during load. These load.
The
long utilizing growth customer the
requires timeline typical Company
lead on on the
43 such
a the new equipment, age equipment, new times times to acquire lead-time units eid f2 mnh ad spare and months 20 of period that is is not number as as large current
should maintain one maintain should placement the experienced Power are adequate of of devices operational Company an for upon called power power autotransformers, medium on pool
power power circuit delivery
equipment
of spare of order an of transformers, transformers, and to to order and procure
available
sufficient maintain
of lack lack to of of transformer
transformers available transformers medium breakers. The
for all for more or on factory factory on (depending a
unforeseen capacity, customer customer capacity, incidence high
spare in in the
voltage common 230/12.4
and and large supplier Page 206 of278
spare manufacture fleet,
138/12.4 kV 138/12.4 replacement field,
number quantities quantities or units for units the and delays, delays,
kV 37 37 kV urgent access power power power power
of of to to a
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 119. 118. 120. Veilleux-DIRECT Q. Q. Q. A. A. A. Based WASTHE WHAT WHAT The types of voltage NUMBER SPARES? OF of available NRS 704.110(4) STATES THAT (with AFUDC). (with delivered and used and useful in the provision ofutility provision the service. in useful and anddelivered used CHANGE MEASUREABLE AND KNOWN have ContractsYes. spare transformers forthe ARE CORE WITH TESTIMONY IS BEING IS TESTIMONY include:
total estimated
THE on the
138/12.4 230/12.4
37.4 MVA EQUIPMENT DOES 56 REASONABLE Total Type
MVA bythe spares EXPECTED CIRCUMSTANCE IN number number of units
classes kV kV All THE
cost
COST TOTAL the of OPN PROPOSE COMPANY and and transformer ratings, the
the of Installed
MEASURABLE AND KNOWN “REASONABLY following:
COSTS units
PREPARED? facilities 32 35 3 44
ACCURACY” in in operation and
project
AN ITEM
Existing OF Spares
are OF THE PROJECT?OF THE
2 0 2 EID MUST PERIOD WITH December through THE expected
Additions Proposed to to adequately INCLUDED INCLUDED IN THE SUBSTATION SPARE SUBSTATION OF AS
REASONABLE been executed and purchase orders andbeen purchase executed
3 2 1 TO
to Company be
BE installed with spare with installed
THE 31, 2020, 31, BE
Count Spare APPROPRIATE AN Total account increased 5 2 3 “REASONABLY “REASONABLY
DATE ACCURACY.” Page 207 of278 for the
is EXPECTED $3,350,033 the
WOUND WOUND
number various various YOUR YOUR
units
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 121. Veilleux-DIRECT Q. A. NRS 704.110(4) NRS AN These Yes. Yes. remaining The costs. balance MEASURABLE THINGS, THINGS, IT DEVELOPMENTS. PROGRAMS PROGRAMS EQUIPMENT purchase development. delivery
EXPECTED contracts The Hyundai 230/12.5kV Unit 2- Unit Hyundai 230/12.5kV 1- Unit Hyundai 230/12.5kV - 138/12.5kV Shenda
schedules and REDACTED VERSION PUBLIC project
delivery CONSISTS CRITERION? THAT MEET RATHER RATHER
total THAT STATES
WITH scope cannot and
of of these CHANGE DOES REASONABLE OF acquire to THAN THAN 45
of associated overheads. labor and consists units units based on contract SPECIFIC SPECIFIC AND IDENTIFIABLE THE be
THE characterized
and represent and GENERAL IS SPARE SUBSTATION the SHALL COMMISSION three
REASONABLY IF, ACCURACY
spare
as TRENDS, TRENDS,
purchase a percent includes transformers general
AMONG the of
orders PATTERNS KNOWN CORE WOUND pattern trend, Page 208 of278
EVENTS THAT FIND
total and and detailed OTHER OTHER
project
AND
OR OR OR OR
the or
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 122. 123. Veilleux-DIRECT Q. Q. A. A. NRS 704.110(4) NRS NRS 704.110(4) NRS CHANGE EXPECTED AN MEASURABLE delivery and production Revised Yes. HNS IT THINGS, OCCURRING All Yes. EXPECTED. CHANGE EXPECTED AN EQUIPMENT demonstrate MEASURABLE HNS IT THINGS, OBJECTIVELY VERIFIABLE SPARE SUBSTATION FORECASTS, ESTIMATES, CHANGES EXPECTED CRITERION? transformers 114above. Q&A in forth orders, as set
the of
completion completion of manufacturing, are
CRITERION? THAT MEET MEASUREABLE PRIMARILY IS
TO OBJECTIVELY AN HAS REVENUES THAT STATES THAT STATES currently
project
WITH WITH DOES WITH CALCULATED, THE costs REASONABLE REASONABLE
THE verifiable CORE WOUND THE IN DEGREE, 46
the to related
RELYING
PROJECTIONS AND
SPARE SUBSTATION
THE THE REASONABLY IS REASONABLY IS and XESS N IS AND EXPENSES SHALL COMMISSION SHALL COMMISSION
the in recorded testing
IF, ACCURACY IF, ACCURACY provided schedules
THE purchase ONLY
EQUIPMENT and and delivery HIGH
BUDGETS. OR AMOUNT OF CALCULATION
delivery and ON SECONDARILY BY RECORDED OR OR RECORDED BY
contracts OF PROBABILITY
to AMONG AMONG WOUND KNOWN KNOWN
AT
pad EASILY MEET by Page 209 of278
THAT FIND THAT FIND
purchase and
THE in THE DOES the of all June OTHER OTHER OTHER OTHER
vendors CORE THAT TIME
2020. AND AND AND THE spare
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 124. 125. 126. Veilleux-DIRECT Q. Q. A. Q. A. A. 26. PLEASE The the EQUIPMENT N EXPECTED AN MEASURABLE WITH REASONABLE ACCURACY. WITH REASONABLE MEASURABLE identifiable NRS 704.110(4) STATES THAT U/G CABLE REPLACEMENT FL-MGM REPLACEMENT CABLE U/G measurable The “REASONABLE calculated. project This PLEASE TO REVENUE CIRCUMSTANCES SUBSTATION SPARESUBSTATION WITH ASSOCIATED OFFSETS that expenses or revenues above 69kV MGM–Excalibur and 69kV MGM-Flamingo transmission lines, as discussed expected changes in circumstances. changes in expected
degree, Company Substation Spare Substation
WITH ASSOCIATED OR regarding Project regarding
SUMMARIZE DESCRIBE THE PROJECT. THE DESCRIBE
event, these the in
by involves THAT EXPENSES AND has not has recorded MEET
amount
CHANGE PROJECTED
the Core Wound any identified
UNDER events events have The No. 8. THE
WOUND WOUND EQUIPMENT? CORE verifiable and replacement
WHY WHY THE at and
are 47 CRITERIA directly
THAT the
OSDRTO. ARE CONSIDERATION.” THE
project
an Equipment
reasonable time
the of
FORECASTED OR SUBSTATION SUBSTATION SPARE objectively
COMMISSION COMMISSION SHOULD THE
expenses THE attributable ARE S ESNBY NW AND KNOWN REASONABLY IS expected, and expected, will SPECIFIED IN NRS 704.110(4) AS 704.110(4) NRS IN SPECIFIED
existing & EX-MGM (TM295) install ATTRIBUTABLE DIRECTLY EXPECTED project OSRCIN OF CONSTRUCTION forecasted or projected that high probability with associated or to underground
approximately
are constitutes a constitutes
their easily
costs
WOUND WOUND CORE HNE IN CHANGES IN OFFSETS THERE objectively and
Page 210 of278 of occurring sections
CONSIDER are 1,900 1,900 feet specific in offsets currently
the of ANY THE these and of to
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 127. 128. Veilleux-DIRECT Q. A. Q. A. These PROJECT NECESSARY? WASTHE WHY new new underground installation ofa installation the were the lowered from cable new unplanned unplanned extended ih adequate with Due PROJECT DELAYED? WASTHE WHY oiin so positions crossarm as well as travel requirements in order to maintain the acceptance the complete as originally planned. as complete originally
most exact cable
to to the
completed
to back line underground
the as recently
and termination down. and termination location of a of location terminations.
COVID-19 travel of the would
that original their underground cable underground
Las
to length temporary without
failure refurbished cable any ed o be to need ea ws niie and inhibited was Vegas
outage.
future failure, in in the
Without on December 2, 2016. The segments replacing raise and Excalibur. between shoofly MGM transmission
positions in positions order to facilitate
This 48 restrictions imposed conduits, witnessconduits, of the two failure
lowering uld Installing pulled. all
project the Nexans, supplier’s existing have cable, to terminations and crossarms
warranty ol be could
had a had mitigates the but, duct
travel own may terminator
in all in they history project of the The banks. repaired
by
cable new that repairs in 2008, 2014, and 2016 were cases, the new new conductor.
cable with failures, termination of was risk risk by policy United
unable the quickly the delayed scope pull
Depending repair. not had crossarms installing guidelines, result would States government States and completion of and completion to be also by
Page 211 of278
complete n cud not could and
an option and and option an This This included hi original their includes moving new new cable Nexans’
in an an in to their the the on on be
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 129. 130. Veilleux-DIRECT Q. A. Q. A. WASTHE WHAT The total remaining estimated $2,130,162 NRS 704.110(4) STATES THAT 31, 2020. 31, All Yes. CHANGE December by the completed be will segment remaining MGM–Excalibur MEASUREABLE AND KNOWN ARE MGM MEASURABLE PREPARED? ISBEING TESTIMONY YOUR segment MGM–Excalibur These purchase and orders include: major contracts executed The delivered.and the recorded within of the
total estimated
THE
project. Of Of which $1.4 project. contracts contracts total
EX-MGM & major labor and material and labor major The
contractor Electric$2.1 million –Construction PAR –UndergroundNexans EXPECTED (with (with AFUDC). CIRCUMSTANCE IN MGM–Flamingo
WITH
certification period. certification
COST TOTAL cost $2.94
(TM295) COSTS COSTS OF the of
REASONABLE
have million cost The 49 million
planning been facilities project the of PROJECT
AN ITEM and and represent cable supplier $840,000 supplier cable contracts
OF THE PROJECT?OF THE
was was already
all and executed, THE EID MUST PERIOD WITH project $3,244,738 was in-service were
U/G ACCURACY” the with associated
INCLUDED INCLUDED IN THE RAOAL KON AND KNOWN “REASONABLY
REASONABLE in
91 through CABLE
completed, completed, placed in service percent date
material for
December (without on REPLACEMENT BE of the
the OF AS March “REASONABLY “REASONABLY project
the of installation been has
total ACCURACY.”
Page 212 of278 The AFUDC).
2020. 6, EXPECTED THE 2020, 31,
project service was was March
2020. ordered DATE
cost FL The and is -
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 131. 132. Veilleux-DIRECT Q. A. Q. A. NRS 704.110(4) NRS CHANGE EXPECTED AN Yes. Yes. The MEASURABLE THINGS, IT THINGS, PROGRAMS PROGRAMS DEVELOPMENTS. MGM (TM295) a NRS 704.110(4) NRS the includes energization development. CHANGE EXPECTED AN MEASURABLE THINGS, THINGS, OCCURRING EXPECTED. MGM (TM295) on time, have permits construction are and conduits, progress and progress We Yes.
specific
the within
including including service
installation of installation the cable the witness have identifiable and IT
the of
onsite return to scheduled is Nexans cable CONSIST
DOES most achieved RATHER RATHER
TO HAS HAS THAT STATES THAT STATES
PROJECT MEET THAT CRITERION? THAT MEET PROJECT PROJECT WITH WITH project
line the of make-up pull,
THE
DOES THE and cannot and AN
REASONABLE REASONABLE OF and and material The secured. been budget
pull remaining event THAN THAN THE IN DEGREE, 50 U/G
U/G OBJECTIVELY IDENTIFIABLE AND SPECIFIC
MEET THAT CRITERION? THAT MEET the of by set where CABLE
CABLE There terminations. the complete and PAR, THE THE be GENERAL Q&A in forth complete to necessary milestones REASONABLY IS REASONABLY IS segment of segment underground transmission line
characterized as a as characterized contracting
the SHALL COMMISSION SHALL COMMISSION
REPLACEMENT emntos ad final and terminations, IF, ACCURACY IF, ACCURACY REPLACEMENT
scope the of costs
HIGH
and and procurement. All
TRENDS, TRENDS, AMOUNT in 122 that October above. to remains
are commitments general
PROBABILITY PROBABILITY
AMONG AMONG
2020 to accept to 2020
PATTERNS KNOWN KNOWN FL-MGM FL-MGM AT Construction is in in is Construction pattern trend,
Page 213 of278
EVENTS THAT FIND THAT FIND be and cutovers THE the completed completed
necessary OTHER OTHER OTHER OTHER
& EX & & - EX project known TIME
AND AND
OR OR OR
OF the are
or is -
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 133. 134. Veilleux-DIRECT Q. Q. A. A. NRS 704.110(4) NRS obstacles known no All Yes. 2020. CHANGE EXPECTED AN OBJECTIVELY VERIFIABLE MEASURABLE HNS IT THINGS, U/G FORECASTS, ESTIMATES, CHANGES EXPECTED MEET THAT CRITERION? THAT MEET Excalibur Excalibur 69kV line PLEASE orders. secondarily 123 above. Only The complete to and labor internal overheads MGM NRS IN SPECIFIED identifiable and ACCURACY? MEASURABLE AND KNOWN REASONABLY
Cable U/G CABLE
The EX-MGM &
the of SUMMARIZE
list REPLACEMENT
Replacement
major of party third REVENUES MEASUREABLE PRIMARILY IS THAT STATES
event,
WITH WITH CALCULATED,
are that
currently 0.1() S AN AS 704.110(4) these would REASONABLE services for contracts T25 PROJECT (TM295)
H THE WHY project 51
FL-MGM & FL-MGM are the
have events RELYING PROJECTIONS AND prevent
verifiable FL-MGM
THE the to related costs made costs remaining minor REASONABLY IS XESS N IS AND EXPENSES
the the of completion SHALL COMMISSION U/G
EX-MGM project EX-MGM
and recorded IF, ACCURACY
project. EXPECTED
& objectively an THE ONLY
CABLE set is materials and EX-MGM
BUDGETS. OR MEETS OF CALCULATION
the of installation
WITH
ON SECONDARILY in REPLACEMENT OR RECORDED BY
contracts and purchase
CHANGE (TM295)
project
constitutes a constitutes probability high
THE AMONG KNOWN
REASONABLE
EASILY up offorecasted Page 214 of278
THAT FIND
in forth by THE DOES CRITERIA PROJECT THAT December December OTHER OTHER
specific MGM–
Q&A AND AND THE
FL
IS of -
Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 135. Veilleux-DIRECT 136. IV. Q. Q. CONCLUSION A. A.
currently the occurring to NRS 704.110(4) STATES THAT The does. it Yes, CONCLUDE THIS DOES “REASONABLE calculated. objectively TO REVENUE that expenses or revenues REPLACEMENT CIRCUMSTANCES expected changes in circumstances. changes in expected WITH ASSOCIATED OFFSETS
Company WITH ASSOCIATED OR
measurable
THAT EXPENSES AND has not has
degree,
(TM295) & EX-MGM FL-MGM PROJECTED by any identified UNDER in the amount and at the time expected, and their costs are costs their and expected, time at the and amount the in verifiable and recorded
are 52 TESTIMONY? DIRECT YOUR PREPARED directly
OSDRTO. ARE CONSIDERATION.” THE
THE
reasonable
FORECASTED OR COMMISSION COMMISSION SHOULD THE
attributable ARE OF CONSTRUCTION ATTRIBUTABLE DIRECTLY EXPECTED forecasted or projected
expenses with associated or to PROJECT?
that
HNE IN CHANGES IN OFFSETS
THERE Page 215 of278 are
U/G
CONSIDER easily in offsets CABLE
ANY these and and
Exhibit Veilleux-Direct-1
VINCENT VEILLEUX
EDUCATION EXECUTIVE MASTERS IN BUSINESS ADMINISTRATION (EMBA) University of Nevada, Las Vegas – Dec 2018
ADVANCED MASTERS CERTIFICATE IN PROJECT MANAGEMENT Villanova University – 2014 MASTERS CERTIFICATE IN PROJECT MANAGEMENT Villanova University – 2013 BACHELOR OF SCIENCE, COMPUTER ENGINEERING University of Nevada, Las Vegas – 2007 - Minor: Mathematics
EXPERIENCE MANAGER, MAJOR PROJECTS – NV ENERGY Jan 2020 – Present
Manage and support the operations of the Electric Delivery project management team who are responsible for all aspects of project management, including leading teams of multi-discipline functional groups to execute utility projects to achieve scope, schedule & budget. Aspects include: routing & siting, permitting, design, procurement, construction and commissioning, scope & contract negotiation with external customers and governmental entities including Rule 9 and Rule 15, leading teams with members from T&D Planning, Rates and Regulatory, Lands services, Legal, Substation, Transmission, Civil, Telecommunication, Environmental, Operations and Distribution.
MANAGER, DISTRIBUTED ENERGY RESOURCES. – NV ENERGY Dec 2018 – Jan 2020
Develops, implements and manages strategies and ongoing operation of emerging and established distributed energy resource technologies and programs (including electric vehicles, energy storage, distributed generation assets and other customer sited technology). Develops and provides technical input and guidance in DER projects, customer systems, and renewable energy technologies through research, evaluation, customer trends and industry collaboration. Develops customer facing content related to renewable energy programs, transportation electrification, energy storage and other DER technologies, to improve brand awareness and program adoption.
PROJECT MANAGER, SR. – NV ENERGY April 2014 – Dec 2018
Responsible for all aspects of project management, including leading teams of multi-discipline functional groups to execute utility projects to achieve scope, schedule & budget. Aspects include: routing & siting, permitting, design, procurement, construction and commissioning, scope & contract negotiation with external customers and governmental entities including Rule 9 and Rule
Page 1 Page 216 of 278 Exhibit Veilleux-Direct-1
15, leading teams with members from T&D Planning, Rates and Regulatory, Lands services, Legal, Substation, Transmission, Civil, Telecommunication, Environmental, Operations and Distribution. Managing project budget estimate review, project budget presentation and scope justification to procure funding, authorization for expenditure creation, project scheduling utilizing Primavera Project Planner (P6) software, and monthly expenditure tracking, status and variance reporting.
PROJECT CONTROLS, SR. CONSULTANT – NV ENERGY Oct 2006 – March 2014 Supported multiple project managers by building and maintaining project schedules, analysis of cost reports, budgets and variances, new project requests, charge codes and project ID creation and status. Created and maintained cost and resource loaded Primavera schedules; analyze cash-flows, monitor progress using critical path method, export cost analysis reports, establish baseline projections, create annual forecasts for approval by Financial Planning & Analysis (FP&A) and the former Resource Allocation Committee (RAC) monthly meetings, as well as submit new project requests for approval.
Capital Program Development
Led the Project Controls team in developing multi-year budgets for the entire Major Projects capital program, for submittal to FP&A, RAC, and the Board of Directors. Performed cash-flow analysis of capital program, and coordinated efforts with project managers and project controls for rate case data requests, explanations, and/or alterations based on budget requirements. Created budget summary reports for upper management and senior directors. Created capital budget histograms for resource leveling, participated in meetings with team leaders and project management in reconciling project status, scope, and priority, and participated in annual forced ranking meetings for every proposed Energy Delivery project.
Page 2 Page 217 of 278 EXHIBIT VEILLEUX DIRECT- 2
Page 218 of 278 Page 219 of 278 Page 220 of 278 JENNIFER A. KELLY
Page 221 of 278
1 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Nevada Power Company d/b/a NV Energy Docket No. 20-06___ 3 2020 General Rate Case 4 Prepared Direct Testimony of 5 Jennifer A. Kelly 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 Jennifer A. Kelly. My current position is Director, Delivery Operations,
11 for Nevada Power Company d/b/a NV Energy (“Nevada Power” or the “Company”)
12 and Sierra Pacific Power Company d/b/a NV Energy (“Sierra” and together with 13 Nevada Power, the “Companies”). My business address is 6226 West Sahara Ave. 14 in Las Vegas, Nevada. I am filing testimony on behalf of Nevada Power. 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 Company 19 years ago and have since worked in the areas of substation 19 engineering. I led projects and managed teams to install smart meter, transmission, 20 distribution and generation projects. Prior to joining the Company, I worked as a 21 substation engineer at Central Hudson Gas and Electric in Poughkeepsie, New York. 22 I have a master’s degree in electrical engineering from Clarkson University in 23 Potsdam, New York, and a master’s in business administration from the University 24 of Nevada, Las Vegas. My background and experience are more fully described in
25 my statement of qualifications, attached as Exhibit Kelly-Direct-1. 26 27
28 Kelly-DIRECT 1
Page 222 of 278
1 3. Q. HAVE YOU PREVIOUSLY SUBMITTED PREPARED TESTIMONY WITH 2 THE PUBLIC UTILITIES COMMISSION OF NEVADA (“COMMISSION”)? 3 A. No, I have not previously prepared testimony in regulatory proceedings before the 4 Commission. 5
6 4. Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS DIRECTOR, 7 DELIVERY OPERATIONS. 8 A. As Director, Delivery Operations, I provide direct leadership and guidance to the
9 team that manages the Company’s reliability and capital maintenance programs. This
10 team: (1) develops, coordinates, and administers capital maintenance program
11 activities for the Electric Delivery organization for Nevada Power’s service territory;
12 (2) monitors budget expenditures and identifies and analyzes budget variances; and 13 (3) identifies and recommends opportunities to improve operational efficiency and 14 gain cost savings. I also lead cross-functional teams in the implementation of d/b/a NV Energy Nevada Power Company Company Power Nevada 15 improvement initiatives.
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 reasonableness of the Company’s investments in capital maintenance 19 projects. For the test period through December 31, 2019, and the certification period
20 of January 1, 2020, through May 31, 2020, those investments are identified in Table 21 Kelly-Direct-1 below. Certification period estimates will be updated to reflect actual 22 costs as part of the Company’s certification filing. 23 24 25 26 27
28 Kelly-DIRECT 2
Page 223 of 278
1 Table Kelly-Direct-1 – Capital Maintenance Investment Actuals Estimated 2 Through Through December 31, May 31, 3 2019, 2020, Total Project Category In Millions In Millions In Millions 4 Equipment Failure Projects $64.94 $15.46 $80.40 5 Cable Replacement Program $19.53 $24.83 $44.36 6 Cable Injection Program $27.28 $10.23 $37.51 7 Trench Bushing Replacement Program $7.66 $0.00 $7.66 8 4kV to 12kV Conversion Program $0.00 $6.02 $6.02 9
Joint Pole Attachment ‘JPA’ Facilities Repl Program $3.20 $0.43 $3.63 10
Telemetry Addition Program $2.39 $0.02 $2.41 11
Overhead Rebuild Program $0.57 $1.15 $1.72 12 13 Feeder Upgrade Program $1.40 $0.04 $1.44 14 Substation Automation $0.51 $0.83 $1.34 d/b/a NV Energy Tools Replacement Program $0.67 $0.56 $1.23 Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Substation Battery & Charger Replacement Program $0.65 $0.37 $1.02 17 Other $0.68 $0.1 $0.78 18 TOTAL $129.48 $60.04 $189.52 19 20 6. Q. WHY ARE THESE MAINTENANCE PROJECTS ACCOUNTED FOR AS 21 CAPITAL INVESTMENT? 22 A. These projects involve the replacement, retirement, and/or addition of Transmission, 23 Distribution, or Substation assets. For this reason, the costs are properly capitalized. 24 25 26 27
28 Kelly-DIRECT 3
Page 224 of 278
1 7. Q. PLEASE DESCRIBE THE CAPITAL MAINTENANCE PROJECTS THAT 2 WERE PERFORMED DUE TO EQUIPMENT FAILURE. 3 A. The Company separately accounts for equipment replacements that are necessitated 4 by equipment failure or imminent failure that result in a loss of electrical service. So 5 called “Failure Projects” include:
6 • Transmission equipment, including transmission poles, overhead conductor, 7 and associated hardware;
8 • Substation equipment (transmission and distribution), including apparatuses, 9 structures, and associated hardware;
10 • Overhead distribution equipment, including distribution poles, overhead
11 conductor, and associated hardware;
12 • Underground and pad-mounted distribution equipment, including switches, 13 structures, cable, and associated hardware;
14 • Switches, both overhead pole-mounted and pad-mounted varieties; d/b/a NV Energy Nevada Power Company Company Power Nevada 15 • Transformers, including overhead service transformers, pad-mounted service
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 transformers, and associated hardware; and
17 • Services, including underground secondary/service cable, overhead 18 secondary/service conductors and associated hardware. 19 20 The Company completed 3,956 Failure Projects through December 31, 2019, at a 21 total cost of $64,943,391. Estimated expenditures for this program for the period of 22 January 1, 2020, through May 31, 2020, are $15,461,856.
23
24
25
26 27
28 Kelly-DIRECT 4
Page 225 of 278
1 8. Q. WHY WERE THE FAILURE PROJECTS NECESSARY? 2 A. The capital maintenance projects performed on transmission facilities, substation 3 facilities, overhead distribution facilities, underground distribution facilities and 4 transformers were required to replace failed facilities and/or restore electrical service 5 to customers. Capital maintenance projects on services were performed either (1) to 6 restore electrical service to customers; (2) because the cable or conductor had 7 reached or exceeded the end of its service life and was replaced to improve the 8 reliability of the distribution system; or (3) to correct violations of various National
9 Electric Safety Code (“NESC”), Occupational Safety and Health Administration
10 (“OSHA”), and Company safety standards.
11
12 9. Q. PLEASE DESCRIBE THE CABLE REPLACEMENT PROGRAM 13 A. Most projects that fall into this category involve replacing direct-buried cable that is 14 more than 20 years old, and retrofitting the replaced segment of cable with a cable d/b/a NV Energy Nevada Power Company Company Power Nevada 15 placed in conduit. Underground cable scheduled for replacement under this program
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 is prone to failure and may have had multiple splices, a corroded concentric neutral 17 or otherwise did not meet the criteria for the Cable Injection Program. The Cable 18 Replacement Program also includes the replacement of service transformers, service 19 transformer pads, switches, vaults, and secondary boxes, which have failed or are 20 unsafe. 21 22 The Company completed 75 Cable Replacement Program projects through 23 December 31, 2019, at a total cost of $19,527,525. The largest Cable Replacement 24 Program projects were: (1) the Kell Cable Replacement project ($6,599,392); (2) the 25 Colorado Cable Replacement project ($3,045,568); (3) the Primary Retrench at 5212 26 Woodruff Place Cable Replacement project ($703,962); and (4) the Primary 27
28 Kelly-DIRECT 5
Page 226 of 278
1 Retrench 3PH at Alta Rise Cable Replacement project ($501,635). Estimated 2 expenditures for this program for the period January 1, 2020, through May 31, 2020, 3 are $24,833,367.1 4
5 10. Q. WHY WERE THE CABLE REPLACEMENT PROGRAM PROJECTS 6 NECESSARY? 7 A. The Cable Replacement Program projects were performed to improve system 8 reliability and resiliency and were necessitated for the following reasons:
9 • Cable replaced in this program has reached or exceeded the end of its projected
10 service life. It may be prone to failure and cannot be rejuvenated through the
11 Cable Injection Program. Identified cable must be replaced to maintain or
12 improve the reliability of the distribution system. Other equipment replaced 13 through this program has similarly reached or exceeded the end of its projected 14 service life and is replaced to improve the reliability of the distribution system. d/b/a NV Energy Nevada Power Company Company Power Nevada 15 • The replacement cable installed under this program are installed in conduit,
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 which both protects the cable and provides for efficient and cost-effective future 17 replacement without requiring retrenching.
18 • Additional underground infrastructure is installed to create “looped systems,” 19 which provide greater operational flexibility for outage restoration and decrease 20 the duration of service interruptions.
21 • When possible, replacement cable installed under this program is re-routed off 22 of customer property and onto a public right of way. Underground cable that runs 23 through a customer’s property is often difficult to access and maintain, and may 24
25 1 It should be noted that new plant addition is not recognized (closed to plant in service) until it is used and useful and serving customers. Some plant additions described in this testimony could be under construction for 3-4 years before 26 they are used and useful or closed to plant in service. Thus, in my testimony some certification period estimates appear large, however, these programs are not based on incremental costs during the certification period, but instead 27 account for when project is placed in service and designated as used and useful. 28 Kelly-DIRECT 6
Page 227 of 278
1 pass under and through tree roots, structures and other obstacles, which delays 2 restoration of service in the event of a failure. These conditions and future 3 impacts to customer landscaping and hardscape are avoided when replacement 4 underground cable can be re-routed to avoid the customer’s property.
5 • Equipment is installed or replaced to maintain adequate system voltage, power 6 factor, load balancing and increased line capacity.
7 • New vaults and pull boxes are replaced when it is apparent that they have lost 8 structural integrity.
9 • Replacements and improvements allow the Company to maintain compliance
10 with municipal agreements, ordinances and codes including NESC 2 regulations.
11
12 11. Q. PLEASE DESCRIBE THE CABLE INJECTION PROGRAM 13 A. The Cable Injection Program targets direct buried underground facilities, primarily 14 distribution cable, at risk of failing due to their age and location. Cables are injected d/b/a NV Energy Nevada Power Company Company Power Nevada 15 with a silicon-based fluid with insulation properties to mitigate future failure.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Maintenance program administrators conduct analysis utilizing reliability statistics 17 to identify areas in which cable failures are most often occurring in order to identify 18 areas that are more vulnerable to failure in the future, then assign cable injection 19 crews to treat the identified areas. 20 21 The Company completed 163 Cable Injection Program projects through December 22 31, 2019, at a total cost of $27,275,995. The highest cost injection projects were: (1) 23 the Laughlin Cable Injection project ($1,772,984); (2) the Teton Pines Cable 24 Injection project ($1,075,221); (3) the Big Timber Cable Injection project 25
26 2 NESC section 17 circuit breakers, reclosers, switches and fuses; 313.A5 remedying defects; 323 A manholes, handholes, and vaults - strength; 373 ANSI C84.1 American National Standard for Voltage Ratings for Electrical 27 Power Systems and Equipment; 351(3) Safety Rules for Underground Lines – Location and routing. 28 Kelly-DIRECT 7
Page 228 of 278
1 ($670,251); (4) the Swift River Cable Injection project ($654,670); (5) the Norway 2 Maple Cable Injection project ($648,114); (6) the Golden Sage Cable Injection 3 project ($646,083); (7) the Rancho Del Norte Cable Injection project ($604,883); (8) 4 the Calico Ridge Cable Injection project ($569,577); (9) the Chieftan Cable Injection 5 project ($530,469); and (10) the Spencer Cable Injection project 6 ($516,396). Estimated expenditures for this program for the period January 1, 2020, 7 through May 31, 2020, are $10,227,889. 8
9 12. Q. WHY IS IT NECESSARY TO CONTINUE TO INVEST IN THE CABLE
10 INJECTION PROGRAM?
11 A. Cable Injection Program projects are performed to improve system reliability and,
12 were necessitated, for the following reasons:
13 • Underground cable failures are a common cause of service interruptions, 14 especially for runs of non-jacketed direct-buried cable. A typical mode of failure d/b/a NV Energy 3 Nevada Power Company Company Power Nevada 15 for non-jacketed direct-buried cable is a phenomenon known as “water treeing.”
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Water trees form in the presence of a high electrical field and water, and run 17 parallel to the electric field, reducing the effective insulation of the direct buried 18 cable and causing failure. By injecting a silicon-based fluid into voids in the 19 insulation of direct buried cable, water treeing can be remediated. The Cable 20 Injection Program effectively extends the useful life of buried underground 21 cable, reduces the likelihood of service outages and avoids unnecessary reactive 22 repair expenses. This program addresses mostly direct-buried distribution cables 23 that were installed more than 22 years ago. 24 25
26 3 Twenty years ago, non-jacketed primary distribution cables were typically installed directly in a trench with the 27 copper neutral exposed to soil and ground moisture. 28 Kelly-DIRECT 8
Page 229 of 278
1 • This program is often the most viable and preferred alternative to replacing 2 underground cable, because injecting cable costs approximately 85 percent less 3 than the cost of replacing the cable and has less impact on the customers 4 compared to retrenching for cable replacement. Once successfully treated with 5 the silicon-based injection fluid, the cable’s failure rate falls dramatically. The 6 program has proven to be very successful for addressing failing aged direct- 7 buried cables with minimum disturbance to existing infrastructure. At Nevada 8 Power, less than one percent of injected cable have failed throughout the life of
9 this program. The Commission has authorized recovery of the costs of the
10 Companies’ Cable Injection Programs in Nevada Power’s general rate cases,
11 Docket Nos. 11-06006, 14-05004, and 17-06003 and Sierra’s general rate cases,
12 Docket Nos. 13-06002, 16-06006, and 19-06002. 13
14 13. Q. IS THE CAPITAL TREATMENT OF CABLE INJECTION PROCESS d/b/a NV Energy Nevada Power Company Company Power Nevada 15 APPROPRIATE?
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 A. Yes. In response to a letter sent to the Federal Energy Regulatory Commission 17 (“FERC”) on July 10, 2008, on behalf of Novinium, Inc. requesting “an accounting 18 ruling confirming that its public utility clients may properly account [for] the costs 19 of installing Novinium Brand injection rehabilitation products for underground 20 residential distribution (“URD”) cable as an addition to electric utility plant, i.e., a 21 capital expenditure, under the Commission’s Uniform System of Accounts,” FERC 22 ruled that “a company may capitalize the cost of installing injection rehabilitation 23 products provided that the product is used by the company to extend the useful life 24 of its segments of URD cables beyond their original estimated useful lives.” This 25 ruling has been documented as OE Document No. AC08-143-000 filed September 26 4, 2008. In addition, the costs for this program have been approved by the 27
28 Kelly-DIRECT 9
Page 230 of 278
1 Commission as recently as Nevada Power’s 2017 general rate case, Docket No. 17- 2 06003. 3
4 14. Q. PLEASE DESCRIBE THE TRENCH BUSHING REPLACEMENT 5 PROGRAM. 6 A. The Trench Bushing Replacement Program involves the procurement and 7 installation of replacement bushings for Trench Group’s COTA-type bushings. 8 Trench’s COTA-type bushing failures have been identified as the root cause for
9 catastrophic large power transformer fires at Sinatra and Crystal substations. In the
10 years since the catastrophic Sinatra and Crystal fires, Trench COTA-type bushing
11 failures have also caused catastrophic failures and fires on a total of seven different
12 transformers. The final failure and fire was at Cactus Substation in 2017. All events 13 resulted in complete destruction of the affected transformers and prolonged outages 14 to customers. d/b/a NV Energy Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 The Company completed 87 Trench COTA-type bushing replacements through 17 December 31, 2019, at a total cost of $7,663,650. The highest costs projects were: 18 (1) the Northwest Autotransformer Bushing Replacement project ($568,738); (2) the 19 Greenway 230/12kV Bushing Replacement project ($221,608); and (3) the Magnolia 20 Shunt Reactor Bushing Replacement project ($210,534). Estimated expenditures for 21 this program for the period January 1, 2020, through May 31, 2020, are $0.
22 23 15. Q. WHY IS THE TRENCH BUSHING REPLACEMENT PROGRAM 24 NECESSARY? 25 A. The Company initiated the Trench Bushing Replacement Program in response to two 26 catastrophic autotransformer failures, one on Bank 5 at Sinatra Substation in May 27
28 Kelly-DIRECT 10
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1 2011, and the other on Bank 3 at Crystal Substation in September 2011. Both 2 autotransformer failure events were traced to Trench COTA-type bushings. Initially, 3 the Company installed bushing monitor systems on 24 major autotransformers in 4 southern Nevada and purchased and installed replacement bushings for failed units. 5 The bushing monitor system detected that, out of the first 15 transformers on which 6 they were installed, 32 COTA-type bushings out of 118 were degraded. Some 7 bushings required replacement before the transformer could be returned to service, 8 while other bushings tested "borderline." Trench bushing failures and fires continued
9 unabated until a significant portion of the at-risk trench bushings were identified and
10 prioritized for replacement. The Commission authorized recovery of the costs of the
11 Company’s Trench Bushing Replacement Program in Nevada Power’s 2014 general
12 rate case Docket No. 14-05004 and in 2017 general rate case Docket No. 17-06003.
13 14 16. Q. PLEASE DESCRIBE THE 4-KILOVOLT (“KV”) TO 12 KV CONVERSION d/b/a NV Energy Nevada Power Company Company Power Nevada 15 PROGRAM.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 A. This budget category captures costs incurred to continue to convert portions of the 4 17 kV electric distribution system in the Company’s service territory to southern 18 Nevada’s modern 12 kV standard. These conversion projects involve replacing 19 substation equipment, distribution poles, overhead conductor, underground cable, 20 overhead and pad-mounted service transformers, overhead and pad-mounted 21 switches, capacitor banks, and associated hardware. 22 The Company completed no projects through December 31, 2019, at a total cost of 23 $0. The estimated expenditures for this program for the period January 1, 2020, 24 through May 31, 2020, are $6,019,506. See Table Kelly-Direct-1 – Capital 25 Maintenance Investment. 26
27
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1 17. Q. WHY ARE THE 4 kV TO 12 kV CONVERSION PROJECTS NECESSARY? 2 A. The 4 kV to 12 kV conversion program provides multiple benefits to customers and 3 employees in improved safety, reliability, and reduced operating costs:
4 • Safety: The 4 kV conversion will improve the overall safety of the distribution 5 system as the deteriorating 4 kV equipment is removed from service.
6 • Operations and Reliability: The 4 kV equipment is some of the oldest distribution 7 equipment in the Company’s system. Operational and safety issues are expected 8 to increase as it reaches and surpasses its normal operating life. Additionally, the
9 4 kV system is essentially electrically “isolated” from the rest of the distribution
10 system, meaning back-up and service restoration options are limited. Back-up
11 and switching capability continues to deteriorate due to forced conversions in
12 different areas of the system to accommodate new customer services. This 13 creates increased labor and outage hours due to the complex switching orders 14 required to isolate and restore the 4 kV circuits. d/b/a NV Energy Nevada Power Company Company Power Nevada 15 • Protection and Coordination: The conversion of the system to 12 kV allows for
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 the application of modern protective schemes in line with current standards.
17 • Voltage Regulation: Voltage regulation normally becomes an issue on long 18 feeders with small conductor, high load, and low source voltage. Most of the 19 Company’s distribution system is either 12.4 kV, 24.9 kV (Laughlin), 34.5 kV 20 (Mt Charleston) or 4.16 kV. Most of the transformers are 22.9 kV / 4.36 kV, with 21 24.1 kV being the highest primary tap available. This results in high voltages on 22 the 4 kV system and low voltages on the 12 kV buses that serve the 4 kV 23 substations. Additionally, adjustments to 4 kV voltage are impossible because 24 the 4 kV load tap changers cannot be repaired or maintained.
25 • Capacity: There is the potential for additional load growth in areas that are 26 currently served at 4 kV. Some 4 kV transformers are loaded to their full 27
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1 nameplate ratings during peaks, with no back-ups or replacements available. This 2 impacts system reliability.
3 • Maintenance: The 4 kV system has reached or exceeded the end of its service 4 life, requiring increased regular inspection and maintenance to ensure its 5 operability. Newly installed assets require less frequent and less costly 6 maintenance.
7 8 18. Q. PLEASE DESCRIBE THE JOINT POLE ATTACHMENT (“JPA”) 9 FACILITIES REPLACEMENT PROGRAM.
10 A. The JPA Facilities Replacement Program involves the redesign and replacement of
11 transmission and distribution structures that do not meet NESC strength and/or
12 clearance requirements. 13 14 Pole capacity and clearance studies initiated by JPA applications identify d/b/a NV Energy Nevada Power Company Company Power Nevada 15 transmission and distribution structures that show signs of deterioration and/or do
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 not meet the applicable NESC rule(s). Structures replaced as part of this program are 17 typically wooden, but occasionally steel or other pole material types may be included 18 as well. Structures deteriorate as a result of aging, damage from external forces such 19 as public and nature, or a combination thereof. Structures identified for replacement 20 are prioritized based on multiple factors including: the desire for the third-party 21 attachments, required permitting time, project schedule, resources, and percent of 22 strength overload or value of clearance violation. 23 24 The Company completed 22 JPA Facilities Replacement Program projects through 25 December 31, 2019, at a total cost of $3,201,163. The highest cost JPA Facilities 26 Replacement Program projects were: (1) Clark-Equestrian 69 kV JPA ($1,015,264); 27
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1 and (2) Winderwood-City of Henderson (WW-COH) 69 kV Wood Pole 2 Replacement ($804,724) . Estimated expenditures for this program for the period 3 January 1, 2020, through May 31, 2020, are $432,050. 4
5 19. Q. WHY IS THE JPA FACILITIES REPLACEMENT PROGRAM 6 NECESSARY? 7 A. The Federal Communication Commission’s Rules require electric utilities to 8 accommodate the joint attachment of communications cables and hardware in a
9 communications work space provided on electric power poles, wherever feasible
10 within the NESC rules and provisions of the joint use agreements. The utility incurs
11 incremental “make ready” costs when the make ready work is due to pre-existing
12 facility conditions that are not compliant with municipal agreements, ordinances and 13 codes, the NESC, OSHA regulations, and/or Company safety standards. 14 d/b/a NV Energy Nevada Power Company Company Power Nevada 15 Over-burdened structures are at a heightened risk of structural failure that can result
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 in property damage and lengthy service interruptions. Recent examples include 17 windstorm events in March 2018 in which multiple distribution structures failed near 18 Koval Lane and Rochelle Avenue, and again in May 2018 near Koval Lane and 19 Flamingo Road. 20 21 The NESC (ANSI C2-2017 NESC), rule 214.A.5, requires that, once violations to 22 any part of the code are identified including, but not limited to, section 23 for 23 clearances or section 26 for strength, the violations must be corrected. Additional 24 NESC rules governing structure strength include 260.B Application of Strength 25 Factors and NESC 261 Strength Requirements for Supporting Structures. 26 27
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1 Performing the identified structure replacements as a planned project prior to failure 2 is a less costly option compared to replacing structures that fail unexpectedly 3 resulting in emergency conditions. Finally, customers benefit from improved 4 reliability by avoiding lengthy unexpected service interruptions with planned 5 maintenance that may not require any type of service interruption. 6
7 20. Q. PLEASE DESCRIBE THE TELEMETRY ADDITION PROGRAM. 8 A. The Telemetry Addition Program involves the installation of telecommunications
9 and substation equipment necessary to monitor and report voltage, current and
10 power, breaker status, and control for substation breakers remotely via Supervisory
11 Control and Data Acquisition (“SCADA”) to system operators.
12 13 The Company completed seven Telemetry Addition Program projects through 14 December 31, 2019, at a total cost of $2,391,381. The highest cost telemetry addition d/b/a NV Energy Nevada Power Company Company Power Nevada 15 projects were: (1) the Distribution Power Quality Sensor Installation program
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 ($1,184,676); (2) the Cabana Telemetering project ($411,351); and (3) the Wigwam 17 project ($404,192). Estimated expenditures for this program for the period January 18 1, 2020, through May 31, 2020, are $18,927. 19
20 21. Q. WHAT ARE THE TELEMETRY ADDITION PROGRAM PROJECTS? 21 A. Telemetry Addition Program projects upgrade substations with intelligent electronic 22 devices gathering power system information from substation equipment and in some 23 cases control of devices in real time to system operators located in remote control 24 centers. The information gathered helps the operators to monitor critical asset 25 information, feeder loading, breaker control and alarms. Provided this information, 26 an operator can make well-informed decisions and act rapidly for system anomalies. 27
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1 Telemetry is a basic requirement for a functional SCADA system, a core utility 2 system. SCADA systems allow operators in control rooms to monitor power system 3 conditions and to remotely control substation equipment, issuing control commands 4 via the utility’s communication network. Other fundamental components of a 5 SCADA system include functionality to alarm abnormal conditions, tag devices for 6 safety and information purposes, and archive real-time data. The SCADA system 7 communicates with Remote Terminal Units (or substation data concentrators fed by 8 substation intelligent electronic devices) located within substations. Currently
9 SCADA systems have been used to monitor and control equipment on the
10 transmission and sub-transmission network as well as distribution transformers and
11 power circuit breakers located within the substations. Other added benefits of having
12 telemetering capabilities are the ability to monitor system loading and perform
13 accurate system planning based on historic data. 14 d/b/a NV Energy Nevada Power Company Company Power Nevada 15 Distribution power quality sensors are intelligent line sensors that have been installed
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 on targeted distribution feeders and sub-transmission lines to provide single-phase 17 current and voltage metering telemetry in locations where substation or line metering 18 telemetry did not exist. The sensors also provide waveform information for a variety 19 of faults and notification of events that can occur on the electric system. 20
21 22. Q. WHY IS THE TELEMETRY ADDITION PROGRAM NECESSARY? 22 A. The need for the program can be broken into the following categories:
23 • Operational Benefits and Cost Savings. Collecting power data from sites that 24 lack telemetry requires field resources to travel to the site to retrieve a paper disc 25 chart or to manually record real-time measurements (sometimes called “load 26 reads”). The field resources required to gather disc charts or to manually record 27
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1 real-time measurements on-site are limited, and the manual collection of this data 2 competes with other projects that typically are of higher priority. Moreover, disc 3 charts are not as reliable as real-time telemetry as they are sometimes severely 4 dated, become illegible, damaged or lost and lose their analytical value. 5 Similarly, manual real-time measurements introduce some margin of error 6 inherent to manual data collection.
7 • Energy Management. The energy management system manages the operation of 8 the bulk power grid. It is considered a critical system since the potential
9 consequences of losing visibility and control of bulk power grid operations are
10 severe. The SCADA system retrieves real-time measurements and status
11 conditions of the power system and power network applications such as state
12 estimation, power flow, and contingency analysis.
13 • Distribution and Outage Management. Telemetry is required for advanced 14 distribution management system power applications such as unbalanced power d/b/a NV Energy Nevada Power Company Company Power Nevada 15 flow, distribution state estimation, integrated volt/VAR control, and fault
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 location, isolation, and service restoration to manage, operate, optimize, and 17 restore the grid in real-time.
18 • Smart Grid Technologies. The addition of telemetry is a prerequisite for the 19 introduction of additional smart grid technologies within the distribution system. 20 The proliferation of new technologies on the customer side of the meter (e.g., 21 electric vehicles, distributed generators and energy storage technologies) make 22 the distribution network increasingly more complex to operate. Smart grid 23 technologies allow the Company to safely operate and better optimize its network 24 assets with consideration to these new customer technologies. 25 26 27
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1 In addition, telemetry provides for rapid response to service interruptions and the 2 restoration of service as electrical information pertaining to a device’s status is 3 readily available to System Control Operators. Further, smart grid technologies 4 require telemetry to automate field devices on distribution networks to pick up 5 customers on unfaulted sections of the feeders more quickly, thus minimizing 6 customer outages in what is commonly referred to as Distribution Automation and 7 ‘self-restoring’ systems. 8
9 The Commission has authorized recovery of the costs of the Companies’ Telemetry
10 Addition Programs in Nevada Power’s general rate cases, Docket Nos. 14-05004 and
11 17-06003, and Sierra’s general rate cases, Docket Nos. 16-06006 and 19-06002.
12
13 23. Q. PLEASE DESCRIBE THE OVERHEAD REBUILD PROGRAMS 14 A. Overhead Rebuild Program projects replace and/or retrofit overhead infrastructure. d/b/a NV Energy Nevada Power Company Company Power Nevada 15 This includes the replacement of distribution poles, the replacement of overhead
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 conductor, replacement of service transformers, the installation and replacement of 17 line capacitor banks, line upgrades, re-insulation of overhead lines, and associated 18 work that allows the Company to maintain compliance with municipal agreements, 19 ordinances and codes, the NESC, OSHA regulations, and/or Company safety 20 standards, and other reliability improvement projects. 21 22 The Company completed 20 Overhead Rebuild Program projects through December 23 31, 2019, at a total cost of $566,922. The highest cost overhead rebuild project was 24 the Pearl 1214 Rebuild project ($299,791). Estimated expenditures for this program 25 for the period January 1, 2020, through May 31, 2020, are $1,153,594. See Table 26 Kelly-Direct-1 – Capital Maintenance Investment. 27
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1 24. Q. WHY WERE THE OVERHEAD REBUILD PROGRAM PROJECTS 2 NECESSARY? 3 A. The projects replacing and/or retrofitting overhead infrastructure were performed to 4 improve system reliability and were necessitated for the following reasons:
5 • Equipment that has reached or exceeded the end of its service life is replaced 6 to improve the reliability and resiliency of the distribution system.
7 • Replacements and improvements allow the Company to maintain compliance 8 with municipal agreements, ordinances and codes, the NESC, OSHA
9 regulations, and the Companies’ safety manual rules.
10
11 25. Q. PLEASE DESCRIBE THE FEEDER UPGRADE PROGRAMS.
12 A. The Feeder Upgrade Program supports minor system improvement projects that are 13 proposed by various departments in order to improve the reliability and increase 14 capacity of the distribution system. This includes, but not limited to, installing d/b/a NV Energy Nevada Power Company Company Power Nevada 15 overhead or pad-mounted switches, reconductoring up to a few spans of overhead
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 conductors, and installing underground conductors in existing or new conduit. 17 18 The projects in the Feeder Upgrade Program are generated as the result of design or 19 engineering discovery following an outage event that took place, or a known 20 reliability issue. The projects provide immediate corrective action to mitigate future 21 events, and enable faster restoration of service. 22 23 The Company completed six Feeder Upgrade Program projects through December 24 31, 2019, at a total cost of $1,404,806. The highest cost feeder upgrade project was: 25 (1) the Lincoln 1210 to North Las Vegas 1204 Load Relief project ($791,653). 26 27
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1 Estimated expenditures for this program for the period January 1, 2020, through May 2 31, 2020, are $59,835.
3 4 26. Q. WHY WERE THE FEEDER UPGRADE PROGRAM PROJECTS 5 NECESSARY? 6 A. The projects in the Feeder Upgrade Program were necessitated for the following 7 reasons:
8 • Installing feeder upgrades allows faster service restoration by improving system 9 functionality, which decreases outage duration in the event of an equipment
10 failure.
11 • The feeder upgrades improve system reliability by relieving facilities that will be
12 overloaded and thereby decreasing the risk of equipment failure, which could 13 endanger Company employees and the general public.
14 • Upgrade to the existing feeders allows for the ability to switch load to another d/b/a NV Energy Nevada Power Company Company Power Nevada 15 feeder and provide capacity to accommodate new load growth in the area.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16
17 27. Q. PLEASE DESCRIBE THE SUBSTATION AUTOMATION PROGRAM. 18 A. The Substation Automation Program projects involve the procurement and 19 installation of equipment that enables substation distribution transformer restoration 20 scheme at critical substations. The installation includes equipment programming to 21 perform the switching sequences for several scenarios. The switching sequences 22 isolate a faulted distribution or transmission transformer and, where applicable and 23 to the extent possible, restore load on the remaining substation’s distribution 24 transformers. Infrastructure involved in the installation usually includes 25 communications equipment to enable SCADA visibility and functionality, motor- 26 27
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1 operated substation disconnect switches, breakers, electromechanical relays and/or 2 electric reset lockout. 3 4 The Company completed five Substation Automation Program projects through 5 December 31, 2019, at a total cost of $511,701. The highest cost substation 6 automation projects were the (1) Faulkner Substation Automation project 7 ($273,173); and (2) the McDonald Substation Automation project ($248,673). 8 Estimated expenditures for this program for the period January 1, 2020, through May
9 31, 2020, are $830,000.
10
11 28. Q. WHY IS THE SUBSTATION AUTOMATION PROGRAM NECESSARY?
12 A. Substation automation equipment provides significant benefits to customers by 13 dramatically reducing the duration of service interruptions in the event of a relay 14 operation event involving the distribution transformer and/or related substation d/b/a NV Energy Nevada Power Company Company Power Nevada 15 equipment. When an event of this type occurs, an outage that would otherwise result
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 in a service interruption lasting hours and requiring substation personnel dispatch 17 and intervention, is instead restored automatically within minutes. 18
19 29. Q. PLEASE DESCRIBE THE TOOLS REPLACEMENT PROGRAM. 20 A. This program captures the costs associated with the acquisition or replacement of 21 tools that are properly unitized as assets in accordance with the capitalization policy. 22 Tools include items such as relay test equipment, power tools specific to line work, 23 voltage detectors, and other items. 24 25 The Company completed 32 projects under the Tools Replacement Program through 26 December 31, 2019, at a total cost of $673,345. The largest tool purchase was the 27
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1 Voltage Detectors ($171,983). Estimated expenditures for this program for the 2 period January 1, 2020, through May 31, 2020, are $557,971. 3
4 30. Q. WHY ARE REGULAR TOOL ACQUISITIONS AND REPLACEMENTS 5 NECESSARY? 6 A. Acquiring new tools and the regular replacement of failing tools ensures that 7 operations staff have access to the proper means to execute projects and programs. 8 These tools are typically acquired for technician/line crew safety improvement, to
9 reduce expenses, increase work efficiency, and/or maintain compliance. For
10 example, the three largest expenditure projects were:
11 1. The F6150 Doble Relay Tester, which is used to test newly-installed relays
12 before they are placed in service. The relay tester is capable of providing voltage 13 and current through computer software to simulate various system fault 14 conditions. These tests are imperative prior to placing a new transmission or d/b/a NV Energy Nevada Power Company Company Power Nevada 15 distribution line in service to ensure the proper operation of protective devices
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 keeping the system reliable.
17 2. Greenlee Linemen tools, which are replacing old failing hydraulic crimpers and 18 cutters. The new line of tools allows the workforce to be much more effective 19 reducing task times and potential injuries than the previous generation of tools.
20 3. Voltage detectors, which are safety tools for linemen to detect the status of the 21 line when they are working in an energized environment. 22 23 24 25 26 27
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1 31. Q. PLEASE DESCRIBE THE SUBSTATION BATTERY AND CHARGER 2 REPLACEMENT PROGRAMS. 3 A. The Substation Battery and Charger Replacement Programs replace failing, aging, 4 and obsolete stationary batteries and chargers for all substations serving southern 5 Nevada. The maintenance of the substation DC supply is governed by the North
6 American Electric Reliability Corporation (“NERC”) Standard PRC-005-2
7 complemented with Institute of Electrical and Electronics Engineers (“IEEE”) 8 Standard 450 and manufacturer recommendations.
9
10 The criteria for a battery or charger replacement includes:
11 • Physical: Cracking jar, post seal breakdown, plate degradation;
12 • Electrical: Battery continuity, voltage and ohmic measurements, charger ripple 13 current;
14 • Aged and obsolete equipment. d/b/a NV Energy Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Substation battery banks and chargers are assessed, and failing equipment is replaced 17 ensuring a reliable substation DC supply. For transmission substations, the DC 18 supply may be reconfigured into primary and backup systems if the configuration 19 does not already exist further strengthening the DC system. 20 21 The Company completed 27 Substation Battery and Charger Replacement Programs 22 projects through December 31, 2019, at a total cost of $645,105. The highest cost 23 substation automation projects were (1) the Magnolia Sub Batt/Charger project 24 ($97,356); and (2) the Laughlin 500 kV Battery Replacement project ($63,736). 25 Estimated expenditures for this program for the period January 1, 2020, through May 26 31, 2020, are $369,768. 27
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1 32. Q. WHY ARE THE SUBSTATION BATTERY AND CHARGER 2 REPLACEMENT PROGRAMS NECESSARY? 3 A. The Substation Battery and Charger Replacement Programs meet the Company’s 4 obligations to adhere to NERC Standard PRC-005-2 by ensuring that substation DC 5 supply systems are adequately maintained using a documented methodology. The 6 substation DC system provides operational capability for SCADA, relay, and 7 tripping devices. Furthermore, it extends this capability for eight hours following 8 the outage of the substation AC system, by design per IEEE Standard 485. If the
9 substation DC system fails to hold voltage, then adjacent substations would be
10 required to clear prolonged faulted conditions forming significant safety,
11 operational, and equipment risk. Prior to NERC Standard PRC-005-2, the failure to
12 properly maintain substation battery banks and chargers has resulted in significant 13 outages in the United States. 14 d/b/a NV Energy Nevada Power Company Company Power Nevada 15 The lifespan of a DC battery could range from seven years to greater than 20 years
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 depending on a number of factors. NV Energy South has over 200 battery 17 installations with each installation ranging from four jars at 12 cells per jar to 60 jars 18 at one cell per jar. Over the last 10 years, Nevada Power has averaged about 13 19 replaced battery banks per year. With an overreaching goal of maximizing life 20 without sacrificing functionality, safety, and compliance, the most significant issues 21 in the fleet are a failed battery continuity test, cracked jars, weeping posts, and high 22 AC ripple. 23
24 33. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT TESTIMONY? 25 A. Yes. 26 27
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JENNIFER A. KELLY NV Energy 6226 W. Sahara Ave. Las Vegas, NV, 89131 (702) 402-5305
Ms. Kelly joined the Company nineteen years ago as a substation engineer, and has since led projects and project management teams to install smart meter, transmission, distribution and generation projects. Current responsibilities as Director, Delivery Operations include direct leadership and guidance to the team that manages the Company’s reliability and capital maintenance programs.
Prior to joining the Company, Ms. Kelly worked as a substation engineer at Central Hudson Gas and Electric in Poughkeepsie, New York. She has a master’s degree in electrical engineering from Clarkson University in Potsdam, New York, and a master’s in business administration from the University of Nevada, Las Vegas. PROFESSIONAL EXPERIENCE
Dec. 2018 – present NV Energy, Las Vegas, NV. Director, Delivery Operations-South, Electric Delivery. Managed three teams: (1) Contract Adminisatration responsible for post-procurement administration of contract terms, invoicing and vendor management for Electric Delivey; (2) Electric Inspection and Coordination responsible for electrical and underground inspection services, as well as all distribution project preparation activities (permitting, material ordering, traffic control, etc.) and scheduling Distribution Lines construction crews; (3) Reliability Programs responsible for the development, coordination, and administration of Electric Delivery capital maintenance planned and emergency program activities, including managing projects, monitoring budget expenditures, and identifying and recommending opportunities to improve operational efficiency and cost savings. I also lead cross-functional teams in the implementation of improvement initiatives.
Nov. 2017 – Dec. 2018 NV Energy, Las Vegas, NV. Director, Strategic Projects, Strategic Repositioning. Supported the NO on Question 3 campaign. Responsibilities included managing and coordinating volunteer training and outreach efforts, ordering and distributing campaign materials to volunteers, and supported employee communication and outreach.
Oct. 2014 – Nov. 2017 NV Energy, Las Vegas, NV. Manager, Capital Execution, Generation Engineering. Managed special project for the $8.2M Project Portfolio Management (PPM) Solution which integrated SharePoint, Primavera and MicroStrategy/Business Intelligence software solutions to initiate, plan, execute and close-out corporate capital projects across several disparate business units. Currently managing the on- going functional, defect and enhancement modifications to the systems. Presented project at industry conferences for Oracle’s OpenWorld conference (Sept 2016), Rocky Mountain Electric League (May 2017) and Oracle’s Western Utilities Conference (June 2017) .
April 2014 – Dec. 2014 Managed Generation PMO (project management, project controls and contract administration groups). Team consisted of 10 project managers, 4 project controls consultants and 1 contract admin, responsible for all aspects of capital projects across NV Energy’s fleet of twelve (12) generating plants, including ten-year plan budgetary coordination, evaluation and corporate submittals.
Sept. 2012 – Dec. 2014 Managed the Generation Project Management team of 10 project managers, responsible for all aspects of capital projects across NV Energy’s fleet of twelve (12) generating plants, including coal-fired and gas-fired units. PM team was responsible for approximately $135M annual capital budget in 2013; $120M in 2014.
Jan. 2010 – Aug. 2012 NV Energy, Las Vegas, NV. Manager, NV Energize. Managed the installation of the telecommunications infrastructure for the corporate smart grid project. The main project scope is to convert 1.45 million electric & gas meters to wireless communication. The project includes new Meter Data Management System (MDMS), new Demand Response Management System (DRMS), and Dynamic Pricing Trial to research various tariff structures. My primary role was managing the installation of 144 telecommunications sites across Nevada, including contract negotiation and administration, permitting/design/construction and coordinating contractor workforce schedules by releasing 1 of 3 Page 246 of 278 Exhibit Kelly-Direct-1 Page 2 of 3
routes for meter deployment based on telecom coverage. Overall project budget is $303M over a 3-year window & included $138M ARRA funding from DOE; the telecommunication portion I managed was $20M.
Oct. 2006 – Dec. 2009 NV Energy (fka Nevada Power Corp.), Las Vegas, NV. Manager, Major Projects-Resort Corridor. Managed a team of 4 senior project managers, responsible for all aspects of utility infrastructure projects within the Las Vegas "Strip" and Downtown metropolitan areas. PM team is responsible for $85M (49%) in 2008 and $54M (67%) in 2009 annual budgets, for only 0.64% of the LV Valley geography.
Jan. 2007 – Dec. 2009 Simultaneously personally responsible for the Sinatra Project: managed a 15 member core team to permit/design/construct the $104.5M utility infrastructure required for $9B CityCenter resort. Sinatra Project scope included 2 miles of overhead & underground 230kV transmission, 1 mile of underground 138kV transmission, a 230/138/12kV NPC-owned GIS substation & 138/12kV CityCenter-owned substation, and several adjacent substation modifications. Published in Transmission & Distribution World magazine in July 2009 and August 2009 (August issue was also the cover), and in PowerGrid International in November 2009.
Responsibilities included contract negotiation with customer and vendors, and all project requirements including lands (ROW, environmental & permitting), T&D planning, substation, transmission, telecommunication and distribution project component requirements. Approx. 30% coordination with large developers, Nevada DOT, other utilities and governmental entities. Facilitated and maintained design, procurement and construction schedules, monthly status, expenditure tracking, variance reporting, and project scheduling utilizing Primavera (P6) software.
April 2004 – Oct. 2006 Nevada Power Corporation, Las Vegas, NV. Senior Project Manager - Project Services. Responsible for all aspects of project management, including leading teams of multi-discipline functional groups to execute utility projects to achieve scope, schedule & budget. Project aspects included: Routing & siting, permitting, design, procurement construction and commissioning Scope & contract negotiation with large developers, utilities and governmental entities Leading teams with members from T&D Planning, Lands right-of-way & permitting, Legal, Substation, Transmission, Civil, Telecommunication, Environmental, Operations & Distribution Budget estimate review, project budget presentation and scope justification to procure funding Project scheduling utilizing Primavera Project Planner (P3) software; Monthly expenditure tracking, status and variance reporting.
Aug. 2000 – April 2004 Nevada Power Corporation, Las Vegas, NV. Senior Engineer - Substation Engineering. Completed physical and electrical designs of several substation projects, including: Two new 138/12kV Substations 138/12kV Transformer Bank Addition One new 230/138kV Substation Two 138kV Transmission Capacitor Banks Two 230kV Switchyard Additions Several 12kV Feeder Installations Project responsibilities included project estimating, project status reporting; equipment specification, bid evaluation, equipment procurement, all substation physical design drawings, bills of materials, all relay, control and RTU design (schematic) drawings, all wiring drawings, and field installation assistance.
Other responsibilities included training a new engineer; Peer design review; Lead team responsible for creating, updating and maintaining substation design standards; Reviewed and coordinated changes to the transformer specification with field crews; and traveled to transformer manufacturer’s facility in Portugal twice for design review and witnessed impulse testing of eight 138/12kV 33MVA units.
June 1995 – Aug. 2000 Central Hudson Gas & Electric Corporation, Poughkeepsie, NY. Assistant Engineer - Electric Substation Design. Designed several substation projects, including two new 115/13.8kV substations, relay and control upgrade projects, transformer cooling, circuit breaker replacement, and mobile and new transformer installations. Project responsibilities included project estimating and design, budget funding and justification, project status and budget tracking and reporting, equipment specification, bid evaluation and equipment procurement; all relay and control design (schematic) drawings, wiring verification, all substation physical design drawings, bills of materials and field installation assistance. Also justified and implemented a department LAN computer network and automated several design calculation standards using spreadsheets.
2 of 3 Page 247 of 278 Exhibit Kelly-Direct-1 Page 3 of 3
PROFESSIONAL LICENSE: Professional Engineer, New York State, 2000, License No. 077862-1.
EDUCATION Clarkson University, Potsdam, NY. Master of Science, Electrical Engineering - Power Engineering concentration, May 1995, 4.00/4.00 Thesis: Effects of Single-Phase Induction Motor Loads on Power System Dynamic Performance.
Clarkson University, Potsdam, NY. Bachelor of Science, Electrical Engineering - Power Engineering concentration, May 1993, 3.60/4.00
Rochester Institute of Technology, Rochester, NY. Electrical Engineering Department - Attended December 1989 to August 1991. Electrical Engineering Technology Department - Attended September 1988 to November 1989.
Niagara County Community College, Sanborn, NY. Associate in Applied Science, Electrical Engineering Technology, May 1988, 3.33/4.00
Trott Vocational High School, Niagara Falls, NY. Three Years of Electrical Shop, Graduated 6th of 141 students, June 1986, 3.89/4.00
3 of 3 Page 248 of 278 Nevada Power Company and Sierra Pacific Power Company d/b/a NV Energy 28 27 26 25 24 23 22 21 20 19 18 17 16 15 14 13 12 11 10 9 8 7 6 5 4 3 2 1 ae ______Date: ______thereto would,underoath,bethesame. and knowledge that states that states that re prepared by or by prepared were exhibits and/or testimony such ae re o h best the to true are therein appearing information and/or answers the I declareunderpenaltyof NRS 53.045 and NAC703.710,JENNIFERKELLY, Pursuant totherequirementsofNRS53.045and he is the person identified in the in identified person the is she eif ad ht f se te usin apaig hri, i answers his therein, appearing questions the asked if that and belief;
perjurythattheforegoingistrueandcorrect. AFFIRMATION AFFIRMATION foregoing prepared testimony and/or exhibits; and/or testimony prepared foregoing JENNIFER KELLY under the direction of direction the under said person; said Page 249 of278
f his of LARRY LUNA
Page 250 of 278
1 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Nevada Power Company d/b/a NV Energy Docket No. 20-06___ 3 2020 General Rate Case 4 Prepared Direct Testimony of 5 Larry Luna 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 Larry Luna. I am the Director of Distribution Design Services for
12 Nevada Power Company d/b/a NV Energy (“Nevada Power” or the “Company”). I 13 work primarily out of Nevada Power’s Beltway Operations Center which is located 14 at 7155 Lindell Road, Las Vegas, Nevada. I am filing testimony on behalf of d/b/a NV Energy Nevada Power Company Company Power Nevada 15 Nevada Power.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16
17 2. Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE IN THE 18 UTILITY INDUSTRY. 19 A. I have a Bachelor of Science Degree in Electrical Engineering, and I have more 20 than 33 years of experience in the electric utility industry. I have been in my current 21 position since July of 2012. Additional details regarding my professional
22 background and experience are set forth in Exhibit Luna-Direct-1. 23
24 3. Q. PLEASE DESCRIBE YOUR RESPONSIBILITIES AS DIRECTOR OF 25 DISTRIBUTION DESIGN SERVICES. 26 A. The Distribution Design Services (“DDS”) department provides design engineering 27
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1 and project coordination for distribution line extensions as well as facility 2 relocation projects subject to Rule 9 and local government franchise agreements. I 3 am responsible for all the business processes and deliverables the DDS department 4 provides for its customers in southern Nevada: government entities, 5 industrial/commercial/residential developers and individual custom home 6 builders/owners. 7
8 4. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC 9 UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
10 A. Yes, I have testified before the Commission. Most recently, I testified before the
11 Commission on behalf of Nevada Power in Docket No. 19-05027 (Undergrounding
12 Management Plan), Docket No. 19-04022 (Two Blackbirds NRS Chapter 704B 13 application), and Docket No. 17-06003 (Nevada Power 2017 General Rate Case) 14 d/b/a NV Energy Nevada Power Company Company Power Nevada 15 5. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 A. The purpose of my testimony is to address the following:
17 . In Section II, I provide an overview of the DDS department and the types 18 of projects administered by the department.
19 . In Section III, I describe and support the distribution plant investment 20 Nevada Power has committed to since the Company’s last general rate case 21 filing.
22 . In Section IV, I provide a description of and the purpose for major projects 23 with expenditures to plant of $1.0 million or greater.
24 . In Section V, I describe and support Nevada Power’s investment into the 25 New Business Portal project. 26 27
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1 6. Q. ARE YOU SPONSORING ANY EXHIBITS? 2 A. Yes. I am sponsoring the following Exhibits:
3 Exhibit Luna-Direct-1 - Statement of Qualifications 4 Exhibit Luna-Direct-2 - D1 Projects, Line Extensions Serving New or Increased 5 Demand
6 Exhibit Luna-Direct-3 - D5 Projects, Alterations to Existing Facilities 7
8 7. Q. ARE ANY OF THE MATERIALS YOU ARE SPONSORING 9 CONFIDENTIAL?
10 A. No.
11
12 II. DDS DEPARTMENT AND PROJECT TYPES 13 8. Q. PLEASE DESCRIBE THE DDS DEPARTMENT AND ITS FUNCTION. 14 A. The DDS department provides a single point of contact for the development d/b/a NV Energy Nevada Power Company Company Power Nevada 15 community and local governments to assist them as they plan for and request either
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 new electric service through an electric line extension or relocation of existing 17 electric distribution facilities. These projects, and responsibility for their costs, are 18 governed by Nevada Power’s Rule 9 tariff and Nevada Power’s franchise 19 agreements with local governments. For line extensions, a DDS department team 20 member initiates the project, works with Distribution Planning to identify the 21 distribution source feeder and, if necessary, any reinforcements, prepares the design 22 package for the developer’s review and approval, coordinates with Nevada Power’s 23 Lands team to identify easement and permitting requirements, obtains local 24 government approvals as required, prepares the applicable line extension contract 25 package, and coordinates with Nevada Power’s Scheduling and Construction teams 26 to ensure timely completion of the line extension scope of work. DDS is responsible 27
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1 not only for individual projects, but master planned communities as well, and 2 facilitates residential, commercial, industrial and government development activity. 3 4 In addition, DDS team members address new service requirements for local 5 government entities as described above, as well as conflicts between Nevada 6 Power’s existing distribution facilities and proposed government infrastructure 7 projects. These projects may require relocation of distribution facilities as required 8 under Rule 9 as well as government franchise agreements. Nevada Power’s various
9 franchise agreements require the Company to relocate facilities within these rights-
10 of-way with the cost obligation assigned to Nevada Power, unless the facilities are
11 covered by a prior land right. A prior land right is Nevada Power’s real property
12 interest that pre-dates the dedication of the government entity’s rights-of-way. 13 14 On occasion, a residential or commercial project may request the relocation or d/b/a NV Energy Nevada Power Company Company Power Nevada 15 modification of existing facilities. In those cases, the applicant pays the entire cost
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 through a non-refundable contribution in aid of construction (“CIAC”) advance 17 unless the alterations directly contribute to a net increase in demand. 18
19 III. TYPICAL DDS DISTRIBUTION PLANT INVESTMENT
20 9. Q. GENERALLY, HOW ARE THE COSTS OF INVESTMENT IN NEW 21 DISTRIBUTION PLANT TREATED UNDER RULE 9? 22 A. Under Rule 9, projects that are expected to produce an increase in demand qualify 23 to receive an allowance against applicable line extension costs. The amount of the 24 allowance depends on an applicant’s anticipated customer class, along with the 25 number of units or number of meters and/or demand associated with the 26 development. The allowance represents the Company’s investment in the line 27
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1 extension costs. The basis for the allowance, or at least the upfront amount that is 2 granted at the time the line extension agreement is executed, are the reasonable 3 expectations regarding the supporting number of units, meters and/or demand that 4 will be served within 12 months following completion of construction of the line 5 extension facilities. 6 7 Typically, a percentage of the allowance is credited up-front to the line extension 8 project cost, thereby reducing the amount of the advance the applicant must pay.
9 The remainder of the allowance, if any, is collected from the applicant in their
10 advance but may be subject to refund as unit/meters are installed or new demand
11 emerges. An advance that is not eligible for allowance offset is non-refundable and
12 considered a CIAC. For example, the replacement of an overhead line with an 13 underground line for aesthetic reasons is not eligible for an allowance offset, is not 14 refundable, and is classified as a CIAC. d/b/a NV Energy Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 In addition to the allowance, the applicant may also be eligible for subsequent 17 refunds offsetting the advance if a second developer attaches to the line extension 18 facilities installed for the first applicant. This is referred to as the proportionate 19 share refund, and is a cost pass through from the second developer to the first. The 20 total of the allowance and proportionate share refunds may not exceed the total 21 advance subject to potential refund under the line extension agreement. The 22 applicant is not eligible for any allowance or proportionate share refunds once the 23 term of the line extension agreement expires, which can be 5, 7 or 10 years 24 depending on the size and risk level of the project. 25 26 27
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1 In summary, the Company’s investment in distribution plant, which is booked to 2 plant in service and eventually included in rate base, is the difference between the 3 total cost of the line extension project and the total advance provided by the 4 applicant. 5
6 10. Q. WHAT IS THE AMOUNT OF THE COST OF INVESTMENT IN DDS 7 PROJECTS THAT HAS BEEN BOOKED TO PLANT SINCE NEVADA 8 POWER’S LAST GENERAL RATE CASE? 9 A. The costs of DDS projects booked into plant in service between June 1, 2017, and
10 December 31, 2019, totaled $159,527,832 (with Allowance for Funds Used During
11 Construction (“AFUDC”)) and the cost of DDS projects forecast to be booked to
12 plant in service during the certification period (January 1, 2020, through May 31, 13 2020) totals $23,037,024. 14 d/b/a NV Energy Nevada Power Company Company Power Nevada 15 11. Q. PLEASE BREAK OUT THE TOTAL DDS INVESTMENT INTO ITS
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 DIFFERENT PROJECT TYPES. 17 A. Nevada Power classifies projects into different budget identification numbers 18 (“IDs”) for tracking and reporting purposes. The largest budget ID, D1, tracks 19 distribution line extensions that serve new or increased demand. Through the end 20 of the test period, Nevada Power invested $140,304,385 (with AFUDC) in D1 21 projects. It is estimated that through the end of the certification period, Nevada 22 Power will invest an additional $20,614,285 in D1 projects. D1 projects include 23 line extensions to residential projects, commercial/industrial projects, master 24 planned communities and government projects such as new community centers and
25 parks. Please refer to Exhibit Luna-Direct-2 for additional details. 26 27
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1 The next largest budget ID, D5, tracks projects that involve alterations to existing 2 electric facilities, typically relocations. These projects are usually performed at the 3 request of government entities pursuant to Rule 9, franchise agreements or 4 revocable permits. Through the end of the test period, Nevada Power invested 5 $19,223,447 (with AFUDC) in D5 projects. It is estimated that through the end of 6 the certification period, Nevada Power will invest an additional $2,422,738 in D5
7 projects. Please refer to Exhibit Luna-Direct-3 for additional details regarding this 8 investment type.
9
10 The aforementioned D1 and D5 certification period estimates include facilities that
11 have been or are projected to be energized and used and useful on or before May
12 31, 2020. 13
14 12. Q. HOW DO THESE TOTAL INVESTMENT AMOUNTS COMPARE TO THE d/b/a NV Energy Nevada Power Company Company Power Nevada 15 INVESTMENT IN THE 2017 GENERAL RATE CASE FILING?
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 A. The comparison between 2020 (test period and estimated certification period) and 17 2017 (test period and actual certification period) is set forth in Table Luna Direct- 18 1 below:
19 Table Luna Direct-1 20 D1 and D5 Investment Comparisons
21 2017 GRC 2020 GRC
22 D1 Projects $106,424,310 $160,918,670
23 D5 Projects $22,018,524 $21,646,186
24 25 Table Luna Direct-1 comparisons between 2020 and 2017 rate cases demonstrate 26 that construction activity in the service territory has increased in all sectors. The 27
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1 continuation of the strong development climate and changes to allowance rates have 2 resulted in a 51 percent increase in D1 investment from the previous rate case. 3 Nevada Power has experienced an increase in projects initiated for master plans, 4 commercial/industrial and residential (subdivision and multi-family) projects of 46 5 percent, 15 percent and 7 percent, respectively, for the three year period of 2017 6 through 2019 compared to the preceding three year period from 2014 through 2016. 7 The investment in D5, government relocation projects, has remained fairly 8 consistent in this and the previous rate case period.
9
10 IV. MAJOR DDS DISTRIBUTION PROJECT INVESTMENT
11 13. Q. WAS DDS RESPONSIBLE FOR ANY PROJECTS WITH INDIVIDUAL
12 INVESTMENTS OVER $1.0 MILLION SINCE NEVADA POWER’S LAST 13 GENERAL RATE CASE? 14 A. Yes. These projects are listed below and each project is discussed in more detail d/b/a NV Energy Nevada Power Company Company Power Nevada 15 within my testimony that follows in this section. The projects include:
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 (1) Clark County Harmon and Valley View Railroad Grade Project 17 (2) Resorts World Las Vegas Project 18 (3) Nevada Department of Transportation US 95 Phase 2B 19 (4) Northgate Industrial Park Master Plan Feeder 20 (5) Valley Vista Master Plan Feeder 21 (6) Clark County Durango Improvement 22 (7) Blue Diamond West Master Plan Feeder 23 24 25 26 27
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1 14. Q. WHY HAVE YOU USED THE $1 MILLION THRESHOLD IN YOUR 2 TESTIMONY? 3 A. I understand that in a general rate case proceeding the Commission wants to see 4 prepared testimony addressing details of the major projects and that, in recent 5 general rate cases, has accepted the $1 million threshold as appropriate for 6 determining whether a project is “major.” 7
8 15. Q. WERE THESE PROJECTS PREVIOUSLY APPROVED BY THE 9 COMMISSION?
10 A. No, these projects represent normal investment in distribution system
11 improvements and are not usually presented to the Commission for pre-approval.
12
13 16. Q. IN ADDITION TO SOME OF THE PROJECTS LISTED ABOVE, EXHIBIT 14 LUNA-DIRECT-2 LISTS “BWO” PLANT ADDITIONS. PLEASE BRIEFLY d/b/a NV Energy Nevada Power Company Company Power Nevada 15 DESCRIBE THESE PLANT ADDITIONS.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 A. Blanket work orders (referred to as “BWO” in Exhibit Luna-Direct 2) are 17 established to capture costs of routine or recurring type work (e.g., setting meters) 18 for a specified amount of time (most frequently yearly). Setting up specific work 19 orders for routine type work such as meter sets is not economical or a benefit to the 20 Company and would create an enormous administrative burden to oversee. The 21 blanket work orders are closed to plant in service each month for the work that was 22 completed for that period. 23 24 Since the timing of services and meters for specific projects, especially those that 25 have multiple services and meters, can extend over a significant period of time after 26 the completion and energization of the plant additions (primary cable/conductor, 27
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1 poles, fuse cabinets and transformers) that provide capacity to the development, 2 blanket work orders provide a mechanism for capturing these recurring costs over 3 an extended period without delaying the close out and unitization of the other plant 4 additions. 5 6 There are two sets of distribution plant additions that are captured through blanket 7 work orders: service wire and meters. Previously, several blanket work orders 8 existed for services, but, in 2019, those blanket work orders were consolidated into
9 a single blanket work order to provide a simplified approach to capturing charges
10 in this category from year to year. Meter blanket work orders are separated into
11 two categories to distinguish from charges associated with net metering
12 installations. Two blanket work orders, 0000080002 and 0000080020, captured 13 smart meter installations during the test period. The 00008002 is a legacy blanket 14 work order that was still in use during the test period, but all smart meter charges d/b/a NV Energy Nevada Power Company Company Power Nevada 15 on a going forward basis are captured under the 0000080020 blanket work order
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 only. 17
18 (1) Clark County Harmon and Valley View Railroad Grade Project 19 17. Q. PLEASE DESCRIBE THE PROJECT. 20 A. Nevada Power removed two 12-kiloVolt (“kV”) overhead distribution feeders on a 21 single set of distribution poles (fourteen spans of double circuit 954 AA and a total 22 of 15 distribution poles). The Company replaced the two overhead feeders with 23 two underground 12-kV distribution feeders, approximately 0.6 miles in length, 24 along Valley View Boulevard and Harmon Avenue. In addition, existing 12 kV 25 underground distribution feeder, primary and service cable, was removed and 26 relocated at various project locations. 27
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1 18. Q. WHY WAS THE PROJECT REQUIRED? 2 A. Clark County has a flyover project connecting Valley View Boulevard and Harmon 3 Avenue over the Union Pacific Railroad tracks. This project is an integral 4 component for improving traffic flow for the resort corridor and the new Allegiant 5 Stadium. Nevada Power, as described previously, had existing overhead and 6 underground facilities in conflict with the public works project. 7
8 19. Q. WHAT WAS THE TOTAL COST OF THIS PROJECT? 9 A. The estimated total cost of the project was $4,385,961 (without AFUDC). The total
10 cost of the project upon completion was $5,827,865 with AFUDC and $5,811,539
11 (without AFUDC) and reflects some small additional charges incurred during the
12 certification period. The Company utilized a contract resource, PAR Electric, to 13 perform the line extension installation while the estimate assumed internal 14 resources would complete the work. Due to the “boom or bust” cycles of d/b/a NV Energy Nevada Power Company Company Power Nevada 15 development in Las Vegas, the Company has utilized contract line crew resources
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 to supplement internal crews in lieu of hiring permanent full-time employees. These 17 contract crew resources are invaluable to managing timelines for distribution line 18 extension projects, facility relocation projects and capital maintenance projects. 19 Nevada Power’s crews not only support the aforementioned project types, but they 20 also respond to system trouble and outages. The contract crews working in concert 21 with Nevada Power crews are essential to managing project timelines and customer 22 commitments given the increase in workload. In addition, changes in the scope or 23 work due to field conditions required completion of additional work by the 24 Company’s underground contractor, Rice Construction. These were the factors that 25 lead to the cost at project completion coming in higher than the estimated project 26 27
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1 cost. The project was completed and placed in service on May 21, 2019. All the 2 facilities are in service and useful in the provision of utility service. 3
4 (2) Resorts World Las Vegas Project 5 20. Q. PLEASE DESCRIBE THE PROJECT. 6 A. To serve the new Resorts Word Las Vegas hotel/casino project, Nevada Power 7 installed six 12 kV underground distribution feeders, approximately 0.8 miles in 8 length, from Highland Substation to a switch-yard site on the customer’s property.
9 Three of the distribution feeders provide primary service while the other three
10 provide back-up service to the project. Additionally, Nevada Power extended an
11 existing El Rancho Substation 12 kV feeder by approximately 0.2 miles to the
12 switchyard on the customer’s property. In total, seven distribution feeders serve 13 the project with three of the feeders providing back-up service. All of the primary 14 feeders with the exception of the El Rancho feeder are installed and energized, and d/b/a NV Energy Nevada Power Company Company Power Nevada 15 all three back-up feeders are installed and all but one are energized. The two feeders
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 that are not energized are expected to be so by May 31, 2020. 17
18 21. Q. WHY WAS THE PROJECT REQUIRED? 19 A. The project provides primary and back-up service for the Resorts World Las Vegas 20 project consisting of 3,500 rooms and over 700,000 square feet of casino, shopping, 21 restaurant and meeting space. The project is located on the west side of the resort 22 corridor across Las Vegas Boulevard from The Wynn and The Encore. 23 24 25 26 27
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1 22. Q. WHAT WAS THE TOTAL COST OF THIS PROJECT? 2 A. The estimated total cost of the project was $2,082,948 (without AFUDC). The total 3 cost of the project upon completion was $2,854,030 with AFUDC and $2,778,729 4 (without AFUDC) and reflects some additional ongoing charges incurred during 5 the certification period. Company utilized a contract resource, PAR Electric, along 6 with Nevada Power crews to complete the line extension installation work. The 7 original cost estimate assumed internal resources would complete the work and the 8 original cost estimate also underestimated the crew labor required to complete the
9 project. As indicated in a previous response, the contract crews working in concert
10 with Nevada Power crews are essential to managing project timelines and customer
11 commitments given the increase in workload. Additionally, a Nevada Power scope
12 change required the re-orientation of conduits between two manholes. The project 13 was substantially completed and placed in-service on July 7, 2019. All the facilities 14 are in service, with the exception of the two feeders referenced in response to d/b/a NV Energy Nevada Power Company Company Power Nevada 15 Question 20 that will be energized by May 31, 2020, and useful in the provision of
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 utility service. 17
18 (3) Nevada Department of Transportation US-95 Phase 2B 19 23. Q. PLEASE DESCRIBE THE PROJECT. 20 A. Nevada Power removed two 12 kV overhead distribution feeders on a single set of 21 distribution poles (eleven spans of double circuit 954 AA and a total of 10 22 distribution poles) in conflict with a proposed Nevada Department of 23 Transportation interchange project. The Company replaced the two overhead 24 feeders with two underground 12 kV distribution feeders, approximately 0.8 miles 25 in length, along Oso Blanco Road. 26 27
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1 24. Q. WHY WAS THE PROJECT REQUIRED? 2 A. The Nevada Department of Transportation completed a lane expansion on US-95 3 between Durango Road and Kyle Canyon Road and constructed a diverging 4 diamond interchange at US-95 and Kyle Canyon Road. Nevada Power overhead 5 distribution pole line was in conflict with the public works project. 6
7 25. Q. WHAT WAS THE TOTAL COST OF THIS PROJECT? 8 A. The estimated total cost of the project was $1,722,729 (without AFUDC). The total
9 cost of the project upon completion was $1,720,283 with AFUDC and $1,714,114
10 (without AFUDC). The project was completed and placed in service on December
11 7, 2017. All the facilities are in service and useful in the provision of utility service.
12
13 (4) Northgate Industrial Park Master Plan Addendum Feeder 14 26. Q. PLEASE DESCRIBE THE PROJECT. d/b/a NV Energy Nevada Power Company Company Power Nevada 15 A. Addendum agreements are line extension agreements that fall under the purview of
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 master planned development umbrella agreements. The umbrella agreement 17 defines the boundaries of the master plan development, outlines the capacity 18 reservation for the development and terms and conditions for subsequent refunds 19 to the developer during the term of the agreement. The addendum, on the other 20 hand, delineates the specific requirements for a particular line extension project, the 21 associated costs and the required applicant advance. In this particular case, the line 22 extension project required the installation of a new 12 kV distribution feeder, 23 approximately 3.75 miles in length, from Pecos Substation to the master plan 24 development. 25 26 27
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1 27. Q. WHY WAS THE PROJECT REQUIRED? 2 A. The project provides capacity for the Northgate Industrial Park master plan 3 development, located in the north-eastern part of the Las Vegas Valley, pursuant to 4 the Northgate Industrial Park Umbrella agreement entered into with Capital XI 5 LLC. 6
7 28. Q. WHAT WAS THE TOTAL COST OF THIS PROJECT? 8 A. The estimated total cost of the project was $1,591,117 (without AFUDC). The total
9 cost of the project upon completion was $1,503,307 with AFUDC and $1,468,182
10 (without AFUDC). The project was completed and placed in service on December
11 29, 2017. All the facilities are in service and useful in the provision of utility
12 service. 13
14 (5) Valley Vista Master Plan Addendum Feeder d/b/a NV Energy Nevada Power Company Company Power Nevada 15 29. Q. PLEASE DESCRIBE THE PROJECT.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 A. This was another master plan addendum project. In this particular case, the line 17 extension project required the installation of approximately 4 miles of 12 kV 18 distribution feeder, outside and within the master plan development, to provide 19 capacity from Grand Teton Substation to the master plan development. 20
21 30. Q. WHY WAS THE PROJECT REQUIRED? 22 A. The project provides capacity for the Valley Vista master plan development, 23 located in the northern part of the Las Vegas Valley, pursuant to the Valley Vista 24 Umbrella agreement entered into with DR Horton. 25 26 27
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1 31. Q. WHAT WAS THE TOTAL COST OF THIS PROJECT? 2 A. The estimated total cost of the project was $1,378,878 (without AFUDC). The total 3 cost of the project upon completion was $1,520,832 with AFUDC and $1,487,633 4 (without AFUDC). A February 2020 journal entry to capture Wasatch contract line 5 crew costs associated with the project increased the cost of the project from that 6 reflected during the test period. Use of contract crews, supplementing Nevada 7 Power line crews, as discussed previously, to manage project timelines and 8 customer commitments, resulted in higher costs than the original estimate. The
9 project was completed and placed in-service on September 3, 2019. All the
10 facilities are in service and useful in the provision of utility service.
11
12 (6) Clark County Durango Improvement 13 32. Q. PLEASE DESCRIBE THE PROJECT. 14 A. Nevada Power removed, relocated and replaced two 12 kV underground d/b/a NV Energy Nevada Power Company Company Power Nevada 15 distribution feeders along an approximate 0.7-mile stretch of Durango Drive
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 between Windmill and Blue Diamond Roads that were in conflict with the Clark 17 County public works project. 18
19 33. Q. WHY WAS THE PROJECT REQUIRED? 20 A. Clark County installed a storm drain along Durango Drive between Windmill Road 21 and Blue Diamond Road. As required per the franchise agreement with the County, 22 Nevada Power relocated 12 kV underground feeders that were in conflict with the 23 public works project. 24 25 26 27
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1 34. Q. WHAT WAS THE TOTAL COST OF THIS PROJECT? 2 A. The estimated total cost of the project was $1,570,935 (without AFUDC). The total 3 cost of the project upon completion was $1,466,040 with AFUDC and $1,415,122 4 (without AFUDC) and reflects some additional ongoing charges incurred during 5 the certification period. The project was completed and placed in service on June 6 5, 2018. All the facilities are in service and useful in the provision of utility service. 7
8 (7) Blue Diamond West Master Plan Addendum Feeder 9 35. Q. PLEASE DESCRIBE THE PROJECT.
10 A. For this master plan addendum agreement, the line extension project required the
11 installation of a new 12 kV distribution feeder, approximately 1.75 miles in length,
12 from Riley Substation to the master plan development. 13
14 36. Q. WHY WAS THE PROJECT REQUIRED? d/b/a NV Energy Nevada Power Company Company Power Nevada 15 A. The project provides capacity for the Blue Diamond West master plan
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 development, located in the southwest part of the Las Vegas Valley, pursuant to the 17 Blue Diamond West Umbrella agreement entered into with Lewis Investment 18 Company. 19
20 37. Q. WHAT WAS THE TOTAL COST OF THIS PROJECT? 21 A. The estimated total cost of the project was $865,673 (without AFUDC). The total 22 cost of the project upon completion was $1,106,753 with AFUDC and $1,086,632 23 (without AFUDC) and reflects some additional ongoing charges incurred during 24 the certification period. The Company utilized contract resource, Wasatch Electric, 25 to complete the line extension installation while the estimate assumed internal 26 resources would complete the installation work. As noted for other projects, the 27
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1 contract crews are essential to manage project timelines and customer 2 commitments. The project was completed and placed in service on March 4, 2019. 3 All the facilities are in service and useful in the provision of utility service. 4
5 V. THE NEW BUSINESS PORTAL PROJECT 6 38. Q. PLEASE DESCRIBE THE PROJECT 7 A. The purpose of New Business Portal is to improve the customer experience for 8 southern Nevada residential home builders. This project created a New Business
9 website and mobile application for southern Nevada residential builders. The result
10 will improve the New Business customer experience and enable Energy Delivery
11 to streamline its new service connection operations, customer communications, and
12 service levels through the implementation of online website and mobile application 13 services within each phase of the New Business utility lifecycle. 14 d/b/a NV Energy Nevada Power Company Company Power Nevada 15 Phase 1 - Discovery and Design was completed in October, 2019. Phase 1 defined
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 the redesign of the business process and technical requirements including 17 development of high-fidelity system designs for the New Business website and 18 mobile application. Phase 1 also produced a prototype that was tested with top 19 builders in Southern Nevada which enabled the completion of the final design, 20 statement of work and cost estimate for the build phase. Total cost for phase 1 was 21 $620,461. 22 23 Phase 2 - Build, Test and Deploy of the New Business website and mobile 24 application includes the physical technology build of the website and mobile 25 application including the integration of the source data, security, and technical and 26 user testing of the technology solution. Phase 2 also includes the physical process 27
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1 redesign and go-live of the technology enhancements for Southern Nevada 2 Residential Builders, by May 28, 2020. Phase 2 began December 2019 with an 3 estimated cost of $5,777,804. The New Business Portal can easily be expanded in 4 the future to support government public works relocations and new business 5 commercial projects.
6 7 39. Q. WHAT TECHNOLOGY PLATFORMS ARE ASSOCIATED WITH THE 8 PROJECT? 9 A. The New Business Portal includes the applications, infrastructure, and security
10 necessary to implement a new, responsive new business customer portal and mobile
11 app.
12
13 40. Q. WHY WAS THE PROJECT REQUIRED? 14 A. Customer preferences are changing, and customers are interacting with service d/b/a NV Energy Nevada Power Company Company Power Nevada 15 providers including utilities through digital channels at an increasing rate. The
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 development and maintenance of web and mobile platforms to communicate with 17 customers and deliver self-service options is expected by customers. 18
19 41. Q. WHAT WAS THE TOTAL COST OF THIS PROJECT? 20 A. The total cost of the New Business Portal through December 31, 2019, was 21 $1,598,505 and is projected to be $6,181,256 as of May 31, 2020. Additional detail 22 regarding the costs of the project are set forth in Table Luna Direct-2 below. 23 24 25 26 27
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1 Table Luna Direct-2 2 Project Costs as of 3 Cost Category % of Total 5/31/2020 4 Internal Labor (RT10, 11, 12) $194,340 3% External Services (RT40, 75, 70) $4,892,307 79% 5 Breakdown of External Services: 6 Cognizant Worldwide Limited $61,113 1% Wipro LLC $443,747 7% 7 Zilker Technology LLC $4,311,990 70% Optiv Security Testing $45,520 1% 8 World Wide Tech $29,937 >1% 9 Materials (RT 50, 51) $441,670 7%
Internal Overheads (RT 30,31,32,33,52,53) $540,460 9%
10 AFUDC (RT 80) $112,479 2% Total $6,181,256 100% 11
12 13 42. Q. DESCRIBE THE TYPE OF COSTS INCLUDED IN INTERNAL LABOR, 14 EXTERNAL SERVICES, AND MATERIALS? d/b/a NV Energy Nevada Power Company Company Power Nevada 15 A. Internal labor includes direct (wages) and indirect (labor overheads) associated with
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 labor provided by Company employees. Internal labor costs are comprised 17 primarily of charges from Information Technology and Energy Delivery business 18 units. The two organizations worked collaboratively on project planning, design, 19 implementation, project management, and testing. Resources from Information 20 Technology were also involved in application development and security testing. 21 22 The external services cost category primarily includes vendor provided 23 professional services including the design, build, test and deployment related costs. 24 Table Luna Direct-2 identifies the professional service vendors making up 79 25 percent of the total project costs. 26 27
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1 Project material costs primarily include servers and hardware related equipment 2 making up 7 percent of the overall project costs. 3
4 43. Q. WERE THE EXTERNAL SERVICE PROVIDERS SELECTED THROUGH 5 A COMPETITIVE PROCESS? 6 A. The external service providers, Zilker Technology LLC, Cognizant Worldwide 7 Limited, Wipro LLC, Optiv Security Testing, World Wide Tech, were selected 8 through a competitive selection process. Contracts were awarded based on
9 technical capabilities and pricing.
10
11 44. 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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Statement of Qualifications
Larry Luna
Professional Experience (NV Energy/Sierra Pacific Resources/Nevada Power)
2012 To Date Director, Distribution Design Services
2009 To 2012 Manager, Process Improvement
Responsible for identifying process improvement opportunities within the Energy Delivery organization; and forming, guiding and facilitating process improvement teams.
2007 To 2009 Manager, Distribution Design
Managed a team responsible for all phases of distribution line extension and facility relocation projects subject to the requirements of Rule 9 and local government franchise agreements.
2005 To 2007 Manager, Line Construction and Maintenance
Managed a team responsible for all facets of transmission and distribution line construction, maintenance and outage restoration.
2001 To 2005 Major Projects Manager
Responsible for the interconnection and regional coordination support for the Centennial 500 kV Transmission Project as well as the requirements development, permitting, and construction of segments of the Centennial 500 kV Transmission Project.
1995 To 2001 Manager, Transmission Planning
Managed a team responsible for developing transmission expansion and reinforcement plans required to meet load growth, network reliability requirements, resource plan requirements, and open access transmission requests. Represented the company in various regional planning and reliability work groups and subcommittees.
Page 272 of 278 Exhibit Luna-Direct-1 Page 2 of 2
1994 To 1995 Team Leader, Transmission Planning
Lead a team responsible for developing transmission expansion plans required to meet load growth, network reliability, and resource plan requirements.
1991 To 1994 Transmission Planning Engineer
Conducted transmission planning studies to develop and support transmission expansion plans for network additions and resource plan filings.
1987 To 1991 Distribution Planning Engineer
Responsible for identifying distribution requirements for new load additions and to maintain distribution system reliability.
1986 To 1987 Distribution Design Engineer
Developed distribution line extension designs and engineering calculations for new development projects.
Education
1986 Bachelor of Science, Electrical Engineering
University of Nevada, Reno
Page 273 of 278 EXHIBIT LUNA-DIRECT- 2
Page 274 of 278 Exhibit Luna-Direct-2 Page 1 of 1
Distribution Line Extension for New Load (D1)
Plant Additions - June 1, 2017, to December 31, 2019
(including AFUDC)
Work Orders Description Total (Dollars)
0000080020 BWO Smart Meters 16,561,963 0000080013 BWO Residential UG Services>5 7,858,420 0020000119 BWO 2019 Service Blanket 7,039,173 0010008201 BWO Net Meters 2018 3,285,157 0000080014 BWO Residential UG Services<5 2,993,063 0000080002 BWO Meters 2,975,817 0000165393 BWO Commercial UG Services 2,859,411 3000511564 Resorts World Las Vegas 2,843,425 0010009113 BWO Net Meters 2019 2,789,783 3001643555 Northgate Industrial Park 1,503,307 3002233908 Valley Vista 1,466,745 3001547554 Blue Diamond West 1,105,946 Various Projects below $1.0 million 87,022,175 Total D1: 140,304,385
Distribution Line Extension for New Load (D1)
Plant Additions - January 1, 2020, to May 31, 2020
(including AFUDC)
Work Orders Description Total (Dollars)
D1 Forecast (2-Year Historical Average) 14,504,388 Various Projects below $1.0 million 6,109,897 Total D1: 20,614,285
Page 275 of 278 EXHIBIT LUNA-DIRECT- 3
Page 276 of 278 Exhibit Luna-Direct-3 Page 1 of 1
Distribution Government Requests (D5)
Plant Additions - June 1, 2017, to December 31, 2019
(including AFUDC)
Work Orders Description Total (Dollars)
3001721291 CC Harmon and Valley View 5,815,953 3001321673 NDOT US 95 Phase 2B 1,720,283 3001282347 CC- Durango Improvement 1,464,267 Various Projects below $1.0 million 10,222,944 Total D5: 19,223,447
Government Requests (D5)
Plant Additions - January 1, 2020, to May 31, 2020
(including AFUDC)
Work Orders Description Total (Dollars)
D5 Forecast 2,153,129 Various Projects below $1.0 million 269,609 Total D5: 2,422,738
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