SIERRA PACIFIC POWER COMPANY d/b/a NV Energy
ELECTRIC DEPARTMENT
BEFORE THE
PUBLIC UTILITIES COMMISSION OF NEVADA
In the Matter of the Application by SIERRA PACIFIC ) POWER COMPANY D/B/A NV ENERGY, filed ) pursuant to NRS 704.110(3) and NRS 704.110(4), ) addressing its annual revenue requirement for ) general rates charged to all classes of electric ) customers. ) Docket No. 19-06______)
VOLUME 5 of 18
Prepared Direct Testimony of:
Plant In Service
Dariusz Rekowski John P. McGinley John S. Berdrow Part 1
Recorded Test Year ended December 31, 2018 Certification Period ended May 31, 2019
Index
Page 2 of 236 Sierra Pacific Power Company Electric Department d/b/a NV Energy
Volume 5 of 18
Index Page 1 of 1
Description Page No. Prepared Direct Testimony Of:
Plant In Service:
Dariusz Rekowski 4 John P. McGinley 38 John S.Berdrow Part 1 (Redacted) 53
Page 3 of 236
DARIUSZ REKOWSKI
Page 4 of 236 1 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Sierra Pacific Power Company d/b/a NV Energy
3 2019 General Rate Case Docket No. 19-06___ 4
5 PREPARED DIRECT TESTIMONY OF
6 Dariusz Rekowski
7 Revenue Requirement
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 Power”) d/b/a NV Energy 13 and Sierra Pacific Power Company d/b/a NV Energy (“Sierra” or the Nevada Power Company Company Power Nevada “Company” and, together with Nevada Power, the “Companies”). My
and Sierra Pacific Power Sierra and Company 14
15 business address is 6226 West Sahara Ave Las Vegas, Nevada. I am filing
16 testimony on behalf of Sierra.
17
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 Agreements
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25 Rekowski-DIRECT 1
Page 5 of 236 1 (“LTSAs”) for gas and steam turbines, warehouse management, and
2 Generation Business
3
4 3. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC
5 UTILITIES COMMISSION OF NEVADA (“COMMISSION”)?
6 A. Yes. I provided written testimony for the 2017 and 2018 deferred energy
7 proceedings, Docket Nos. 17-03001, 17-03002, 18-03002 and 18-03003.
8
9 4. Q. ARE YOU SPONSORING ANY EXHIBITS WITH YOUR
10 TESTIMONY?
11 A. Yes, I am. In addition to my Statement of Qualifications (Exhibit Rekowski-
12 Direct-1), I sponsor Exhibit Rekowski-Direct-2, which identifies major d/b/a NV Energy 13 generation plant additions completed since the close of the certification Nevada Power Company Company Power Nevada period in Sierra’s 2016 general rate review proceeding (May 31, 2016).
and Sierra Pacific Power Sierra and Company 14
15
16 5. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS
17 PROCEEDING?
18 A. I am supporting the reasonableness of test period operations and maintenance
19 expenditures at Sierra’s fleet of generating stations, as well as Sierra’s
20 request to include in rate base the costs associated with generation-related
21 capital additions that have gone into service since the close of the
22 certification period in the Company’s last general rate case (“GRC”), Docket
23 No. 16-06006.
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25 Rekowski-DIRECT 2
Page 6 of 236 1 In Section II, I describe the processes within my area of responsibility and
2 Company-wide that govern the expenditure of both operations and
3 maintenance (“O&M”) dollars and capital investment.
4
5 In Section III, I support Sierra’s investment in generation capital projects at
6 Sierra’s conventional generating stations that were completed between the
7 close of the certification period in Sierra’s 2016 GRC and the close of the
8 test period for this 2019 GRC. These projects closed to plant in service and
9 were in service and used and useful in providing electric service to customers
10 between June 1, 2016 and December 31, 2018.
11
12 In Section IV, I support capital projects anticipated to be placed in service d/b/a NV Energy 13 and used and useful in providing electric service between January 1, 2019 Nevada Power Company Company Power Nevada and May 31, 2019. The completion of these projects and their actual costs as
and Sierra Pacific Power Sierra and Company 14
15 of May 31, 2019 will be “certified” to in a later filing.
16
17 6. Q. DO YOU SPECIFICALLY DISCUSS IN YOUR TESTIMONY ALL
18 GENERATION PROJECTS CLOSED TO PLANT IN SERVICE
19 SINCE JUNE 1, 2016?
20 A. No. While I support all generation plant investment reflected in the
21 Company’s proposed calculations of rate base, my testimony specifically
22 discusses individual projects that cost $1.0 million or more. Sierra’s
23 generation team has completed many capital projects under $1.0 million
24
25 Rekowski-DIRECT 3
Page 7 of 236 1 since May 31, 2016. Testimony-style descriptions of each and every project
2 completed by the generation team since June 1, 2016, would take hundreds
3 of pages, and the documentation surrounding each project is so voluminous
4 that its value at hearing would be severely diminished. As I understand it, in
5 general rate proceedings the Commission wants to see prepared direct
6 testimony addressing the details of and supporting expenditures on major
7 projects. In recent general rate cases, the Commission has accepted the $1.0
8 million demarcation as appropriate for determining whether a project is
9 “major.” While not addressed in detail in my prepared direct testimony, my
10 group has prepared project “binders” for smaller projects completed since
11 June 1, 2016. As has been the Companies’ practice for many rate case cycles,
12 those binders (now in electronic form) are available for review on the day d/b/a NV Energy 13 this general rate review filing is made. Nevada Power Company Company Power Nevada
and Sierra Pacific Power Sierra and Company 14
15 7. Q. DO YOU ADDRESS THE CHANGES IN COSTS OF THE VALMY
16 UNITS WITH IDAHO POWER COMPANY EXITING THEIR
17 PARTICIPATION IN VALMY 1 IN YOUR TESTIMONY?
18 A. Yes. I address Valmy later in my testimony.
19
20
21
22
23
24
25 Rekowski-DIRECT 4
Page 8 of 236 1 SECTION II: CAPITAL AND O&M COST CONTROL
2 8. Q. HOW DOES SIERRA AND NEVADA POWER CONTROL THE
3 EXPENSES ASSOCIATED WITH OPERATING AND
4 MAINTAINING THE GENERATION FLEET?
5 A. Controlling O&M is important in keeping electric prices reasonable for our
6 customers. At both Nevada Power and Sierra, cost discipline begins with a
7 production schedule that forecasts the amount of energy that can be expected
8 from a generation facility over the next 10 years. Then each power plant
9 management team carefully reviews all expenditures associated with running
10 the power plants for which they are responsible. Plant managers use the
11 production schedule, equipment condition assessments and original
12 equipment manufacturer recommendations to create an expenditure plan for d/b/a NV Energy 13 each facility. Each power plant’s expenditure plan is then rolled up into one Nevada Power Company Company Power Nevada expenditure plan for the fleet.
and Sierra Pacific Power Sierra and Company 14
15
16 9. Q. WHAT IS THE COMPANY’S PROJECTION FOR FUTURE
17 EXPENSES FOR THE SIERRA GENERATING FLEET?
18 A. The fixed costs to maintain generating units as reliable capacity resources
19 remain relatively flat over the next three years (subject to normal inflation).
20 Variable expenses are less predictable, as these costs depend on how units
21 within the fleet are used. Most variable expenses are related to chemicals and
22 other consumables, the costs of which increase with inflation, and the
23 quantity of which vary according to each unit’s actual operations during the
24
25 Rekowski-DIRECT 5
Page 9 of 236 1 year. Other variable expenses are related to wear and tear on the generation
2 fleet.
3
4 On a daily basis, individual units within the generating fleet cycle on and off
5 and from low load to high load to provide the lowest cost energy supply for
6 Sierra’s customers. That cycling leads to wear and tear on the fleet and as
7 the facilities age, equipment and systems deteriorate, requiring increased
8 expense to maintain compliance with operating standards and reliability for
9 our customers. The last major addition of a new plant to the Sierra fleet was
10 the Tracy combined cycle plant, which was put in service in 2008. Sierra’s
11 generation fleet is aging, and as units age, the cost of maintaining the units
12 increases. d/b/a NV Energy 13 Nevada Power Company Company Power Nevada In this context, the Companies continue to work diligently to achieve high
and Sierra Pacific Power Sierra and Company 14
15 reliability levels while maintaining O&M cost discipline so that our
16 customers can enjoy reliable service at reasonable prices.
17
18 10. Q. HOW DOES SIERRA MANAGE CAPITAL MAINTENANCE
19 INVESTMENTS IN THE GENERATING FLEET?
20 A. The generation team focuses on delivering the best value from the capital
21 maintenance projects that are performed at the plants. At the same time the
22 expense plans I describe above are being developed for each plant, capital
23 maintenance investment plans also are being built. The starting point for the
24
25 Rekowski-DIRECT 6
Page 10 of 236 1 capital investment plan is the same unit-by-unit 10-year production forecast.
2 Key assumptions are made concerning retirement, safety, risk management,
3 environmental and other compliance requirements. Each plant team
4 evaluates the current and expected performance of the units and makes
5 proposals for capital investments needed to deliver expected reliability for
6 our customers at a reasonable cost. The benefits of each capital investment
7 are analyzed based on the planned remaining life of the unit.
8
9 For each of the generation projects described in my testimony, Sierra plant
10 and project managers followed a rigorous capital budgeting process, which
11 guides the development of business cases and project estimates, and governs
12 how projects are managed, including through monthly reporting of schedule d/b/a NV Energy 13 and budget status. Nevada Power Company Company Power Nevada
and Sierra Pacific Power Sierra and Company 14
15 11. Q. WERE ALL OF THE CAPITAL PROJECTS COMPLETED SINCE
16 THE END OF THE CERTIFICATION PERIOD IN SIERRA’S 2016
17 GENERAL RATE CASE PRE-APPROVED BY THE COMMISSION
18 IN A RESOURCE PLAN OR OTHER REGULATORY FILING?
19 A. No. The majority of the projects performed by the generation group would
20 be considered maintenance capital projects undertaken and completed to
21 ensure the safe and reliable operation of the generating plants. These projects
22 are not typically presented to the Commission for pre-approval in either
23 triennial integrated resource plans or amendments.
24
25 Rekowski-DIRECT 7
Page 11 of 236 1 12. Q. PLEASE DESCRIBE THE PROCESS THAT SIERRA USES TO
2 MANAGE ITS CAPITAL INVESTMENTS?
3 A. Sierra has put in place a robust business planning and project management
4 oversight process that the Generation business unit participates in and
5 follows.
6
7 13. Q. PLEASE DESCRIBE THE BUSINESS PLANNING PROCESS.
8 A. Business planning begins with a 10-Year Generation Capital Plan, which
9 includes a list of capital projects for each generating plant. The 10-Year
10 Generation Capital Plan is updated annually. During the annual update
11 process each plant performs a fresh assessment and may identify new
12 projects required, may modify existing projects and may even remove d/b/a NV Energy 13 projects from the plan. Nevada Power Company Company Power Nevada
and Sierra Pacific Power Sierra and Company 14
15 A business case is developed for every project that is included in the 10-Year
16 Generation Capital Plan. The business case documents the justification for
17 the project and includes the scope, schedule and an estimated cost as well as
18 a cost-benefit analysis. Because the capital plan covers a 10-year period of
19 time into the future, many of the initial project business cases are based on a
20 preliminary scope and schedule and utilize preliminary estimates of costs.
21 As the project is developed, preliminary engineering is performed, a detailed
22 scope of work and schedule are established and a detailed cost estimate is
23 prepared. The initial business case is updated with new information as it
24
25 Rekowski-DIRECT 8
Page 12 of 236 1 becomes available, and the cost-benefit analysis is reassessed to determine
2 if the project should remain in the plan.
3
4 All generation capital projects and the business cases are reviewed by the
5 Generation leadership team. The Generation leadership team prioritizes the
6 entire portfolio of capital projects as part of the 10-year business planning
7 process. Projects are prioritized. Those mandated by legal or regulatory
8 requirements, safety and environmental compliance receive top priority.
9 Other factors such as improving or maintaining reliability, costs and
10 efficiency are only considered after legal, regulatory, safety and
11 environmental projects are prioritized and funded.
12 d/b/a NV Energy 13 All capital projects from each business unit within the Companies are Nevada Power Company Company Power Nevada submitted for cross-department review and prioritization as part of the
and Sierra Pacific Power Sierra and Company 14
15 company-wide 10-year business planning process. This step subjects the
16 Generation business unit’s capital project prioritization to peer review from
17 other business units and prioritization among the entire capital portfolio.
18
19 Capital projects that make it through both the Generation business unit and
20 the peer review and prioritization process are then submitted for funding
21 approval by executive management. Only approved projects are included in
22 the approved 10-Year Generation Capital Plan.
23
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25 Rekowski-DIRECT 9
Page 13 of 236 1 14. Q. PLEASE DESCRIBE THE PROJECT MANAGEMENT OVERSIGHT
2 PROCESS.
3 A. Inclusion of a project in the approved 10-Year Generation Capital Plan does
4 not constitute project approval. Specific project approvals still must be
5 obtained. This process begins with the assignment of a project manager, who
6 is responsible for executing a project or projects in the 10-Year Generation
7 Capital Plan. The project manager is required to submit an “Authorization
8 for Expenditure” or “AFE” for approval prior to commencing a project. The
9 AFE includes the most current information regarding estimated project cost,
10 budget information, and the business case. The AFE serves as a business
11 control to ensure construction projects, plant additions and significant
12 unbudgeted expenses are reviewed and approved by the appropriate levels d/b/a NV Energy 13 of management before funds are committed and spent. Nevada Power Company Company Power Nevada
and Sierra Pacific Power Sierra and Company 14
15 Project managers may submit a preliminary AFE requesting funds to perform
16 engineering in order to fully develop a capital project’s scope, schedule and
17 budget. In these situations, the project manager is then required to update
18 the business case and submit a supplemental AFE for the full funding of the
19 project prior to committing and spending additional funds.
20
21 A Standard Project Proposal (“SPP”) is prepared for capital projects
22 exceeding $1.0 million and submitted with the AFE for management review
23 and approval. The SPP template has been designed to provide a consistent
24
25 Rekowski-DIRECT 10
Page 14 of 236 1 collection of supporting information to management and regulators.
2 Depending on the size and complexity of the proposed project, business units
3 can append additional relevant information to the SPP template.
4
5 Project managers are responsible for monitoring actual and forecast spending
6 against the approved project funding amounts in the approved AFE. Project
7 managers provide monthly cost, schedule and scope updates for each project
8 to Generation management. Each business unit performs a thorough review
9 and analysis of its capital portfolio each month. Business units review project
10 performance with project managers. Business units forecast capital
11 spending, analyze budget variances perform peer reviews and report results
12 to Corporate Finance and to the executive team monthly. d/b/a NV Energy 13 Nevada Power Company Company Power Nevada 15. Q. PLEASE ADDRESS DISCRETIONARY SPENDING AS IT RELATES
and Sierra Pacific Power Sierra and Company 14
15 TO SIERRA’S CAPITAL MANAGEMENT PROCESS.
16 A. As explained above, capital is prioritized first by legal, regulatory, safety and
17 environmental requirements, then by other considerations including costs,
18 reliability and efficiency. Discretion is used across the prioritization process
19 with the exception of projects designated as mandated by legal or regulatory
20 requirements. While safety and environmental receives the Company’s
21 highest priority, these projects sometimes cannot be justified economically,
22 and the number of requests for investment are usually more than the entire
23 capital budget. Management must use discretion in selecting which safety
24
25 Rekowski-DIRECT 11
Page 15 of 236 1 and environmental projects (that are not otherwise required by law) are given
2 priority over others. These decisions are typically based on the number of
3 impacted employees, severity of the risk and whether administrative controls
4 are possible.
5
6 16. Q. HOW IS DISCRETION APPLIED TO FINANCIALLY JUSTIFIED
7 PROJECTS?
8 A. Again, far more requests are made for capital investment than can be funded
9 under the budget. While forced ranking of projects by financial metrics
10 creates a prioritized listing, other points are considered. Some capital
11 projects are tied to planned outages or other customer requirements. This
12 may adjust the relative ranking or timing of an investment. Additionally, an d/b/a NV Energy 13 emerging risk (e.g., security enhancements) may impact the relative ranking. Nevada Power Company Company Power Nevada Finally, some projects may be marginally economic based on assumptions
and Sierra Pacific Power Sierra and Company 14
15 such as retirement date or expected impacts on expense or workforce. In
16 these circumstances, discretion must be used in evaluating the financial
17 analysis. An example could be a retirement date. No one can predict a
18 retirement date with exact certainty and this is especially true when the date
19 used for planning and depreciation is several years out.
20
21
22
23
24
25 Rekowski-DIRECT 12
Page 16 of 236 1 17. Q. HOW WILL THE COSTS FOR THE VALMY STATION BE
2 DIFFERENT DURING THE NEXT THREE YEARS THAN THEY
3 WERE IN THE TEST PERIOD AS A RESULT OF IDAHO POWER
4 ENDING ITS PARTICIPATION IN VALMY UNIT 1 IN 2019 AND
5 SIERRA POSSIBLY ENDING ITS PARTICIPATION IN UNIT 1 AT
6 THE END OF 2021?
7 A. As a result of the new Framework Agreement between Idaho Power
8 Company (“IPCo”) and Sierra, when one partner exits its participation in a
9 unit at the Valmy Station, it continues to pay its share of the fixed costs, so
10 the fixed expenses for Sierra will not change over the next three-year period.
11 However, Sierra will be responsible for all variable costs for running its share
12 of Unit 1 when IPCo exits its participation in the unit. Since Sierra has d/b/a NV Energy 13 historically paid half of the variable costs for Valmy Unit 1, and the unit will Nevada Power Company Company Power Nevada be run based on economic or system needs, Sierra will see similar costs to
and Sierra Pacific Power Sierra and Company 14
15 those experienced during the test year. In relation to capital, any capital
16 investments required specific to Valmy Unit 1 after IPCo exits participation
17 in the unit will be paid completely by Sierra.
18
19 18. Q. IS SIERRA PROPOSING ANY CHANGES TO REVENUE
20 REQUIREMENT AS A RESULT OF IDAHO POWER ENDING ITS
21 PARTICIPATION IN VALMY UNIT 1 IN 2019 AND SIERRA
22 POSSIBLY ENDING ITS PARTICIPATING IN UNIT 1 AT THE END
23 OF 2021?
24
25 Rekowski-DIRECT 13
Page 17 of 236 1 A. No, as noted previously, Sierra does not expect significant changes in O&M
2 for the Valmy Station for the next three year period.
3
4 SECTION III: GENERATION INVESTMENT BETWEEN JUNE 1, 2016 AND
5 DECEMBER 31, 2018
6 19. Q. HOW HAVE YOU ORGANIZED THIS SECTION OF YOUR
7 TESTIMONY, WHICH ADDRESSES INVESTMENT IN
8 GENERATION ASSETS SINCE JUNE 1, 2016?
9 A. Sierra has made a major investment in its generation fleet since the close of
10 the certification period in the 2016 GRC. In order, I discuss investment at:
11 A. Tracy Station
12 1. TR1028, TR1029 & TR1155 ACC Gear Box Replacement d/b/a NV Energy 13 2. TR1050 T45 Arc Flash Mitigation Project Nevada Power Company Company Power Nevada 3. TR1153 Tracy Fire and Potable Water Project
and Sierra Pacific Power Sierra and Company 14
15 4. TR1069 Tracy Units 4 Stage 1 Nozzle Replacement Project
16 B. Valmy Station
17 1. VA1108 V1 Soot Blower System, Replacement Upgrade Project
18
19 A. TRACY STATION
20 1. TR1028, TR1029 AND TR1155 ACC Gear Box
21 20. Q. PLEASE DESCRIBE THE TRACY AIR COOLED CONDENSER
22 GEARBOX REPLACEMENT PROJECT.
23
24
25 Rekowski-DIRECT 14
Page 18 of 236 1 A. The Tracy Unit 10 steam turbine has experienced reductions in unit output
2 as a result of failed gearboxes on the fan assemblies in the air cooled
3 condenser. The air cooled condenser utilizes 30 fan assemblies to condense
4 steam that is used in the power cycle. Gearbox failures are unpredictable and
5 have averaged approximately five times per year. Gearbox failures can lead
6 to insufficient cooling capacity, which results in the load on the unit being
7 reduced. A gearbox replacement project was initiated in January 2016 to
8 mitigate the output reductions associated with gearbox failures. The project
9 was completed in three phases (the first phase was completed in 2016, the
10 second phase in 2017 and the third phase in 2018) and resulted in
11 replacement of 20 of the original 30 gearboxes and procurement of two spare
12 gearboxes. After reviewing the failure data, it was determined that 10 of the d/b/a NV Energy 13 gearboxes were less susceptible to failure so they were not replaced. The Nevada Power Company Company Power Nevada failure mechanism is primarily related to starts and stops on the fans. The 10
and Sierra Pacific Power Sierra and Company 14
15 gear boxes that were not replaced as part of these projects experience fewer
16 start/stop cycles (based on the control logic) and are expected to account for
17 a much smaller percentage of the total gearbox failures on the ACC. Seven
18 gearboxes were replaced in 2016, 10 were replaced in 2017, and three were
19 replaced in 2018. Additionally, one spare gear box was procured in 2017 and
20 one in 2018.
21
22
23
24
25 Rekowski-DIRECT 15
Page 19 of 236 1 21. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE
2 COMMISSION?
3 A. No, this is a normal capital upgrade to the plant, which is not usually
4 presented to the Commission for pre-approval, whether in an IRP or other
5 application.
6
7 22. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
8 A. For TR1028 the total plant addition was $780,471, including AFUDC. The
9 total project cost was $748,642 (excluding AFUDC) and was estimated at
10 $583,417 (excluding AFUDC). The project was over budget primarily due
11 to unforeseen but significant modifications that were required to allow
12 delivery of the new gearboxes to each fan cell including widening access d/b/a NV Energy 13 doors, reinforcing lifting beams, stronger trolleys, and longer reach hoists. Nevada Power Company Company Power Nevada
and Sierra Pacific Power Sierra and Company 14
15 For TR1029 the total plant addition was $1,068,988, including AFUDC. The
16 total project cost was $1,034,871, excluding AFUDC and was estimated at
17 $983,417, excluding AFUDC. The project was over budget primarily due to
18 vendor charges being higher than estimated. Specifically, the cost for outside
19 services required for installation of the gearboxes was higher than estimated.
20
21 All of the facilities installed are in-service and used and useful in the
22 provision of utility service. The projects were prudently designed and
23 constructed, and the costs of the projects were prudently incurred.
24
25 Rekowski-DIRECT 16
Page 20 of 236 1 The third part of this project, TR1155, is estimated at $455,503, including
2 AFUDC, and will be completed in the certification period and is discussed
3 later in my testimony.
4
5 2. TR1050 T45 Arc Flash
6 23. Q. PLEASE DESCRIBE THE TRACY 4/5 ARC FLASH MITIGATION
7 PROJECT.
8 A. The arc flash mitigation project will improve electrical safety for plant
9 employees who work on or near electrical equipment. The results of an arc
10 flash study commissioned by Sierra identified several locations within the
11 plant at which maintenance and operating activities would have to be
12 restricted if no arc flash improvements were made. The mitigation project d/b/a NV Energy 13 included the installation of relays that detect high over current (and light Nevada Power Company Company Power Nevada from an arc flash incident) and will trip the main energy supply to the
and Sierra Pacific Power Sierra and Company 14
15 breaker. By doing so, the amount of energy available during the fault will be
16 reduced to levels that can be managed using standard personal protective
17 equipment and clothing.
18
19 24. Q. WAS THE PROJECT PREVIOUSLY APPROVED BY THE
20 COMMISSION?
21 A. No. This work was normal capital upgrades to allow the units to operate more
22 reliably. This type of project is not normally presented to the Commission in
23 advance for approval.
24
25 Rekowski-DIRECT 17
Page 21 of 236 1 25. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
2 A. The total plant addition was $1,300,023 including AFUDC. The total project
3 cost was $1,209,628 excluding AFUDC, and was estimated at $1,079,737
4 excluding AFUDC. The project was over budget primarily due to vendor
5 charges being higher than estimated. Specifically, the project estimate did
6 not include the costs of rental equipment (portable generators) that was
7 needed during the project. The project required sections of the plant be de-
8 energized during installation work. An alternative source of power was
9 required to minimize the impact on other projects that were proceeding at the
10 same time. Portable generators were rented to supply power to areas that
11 were affected. All of the facilities installed are in-service and used and useful
12 in the provision of utility service. The project was prudently designed and d/b/a NV Energy 13 constructed, and the costs of the project were prudently incurred. Nevada Power Company Company Power Nevada
and Sierra Pacific Power Sierra and Company 14
15 3. TR1153 Tracy Fire and Potable Water Project
16 26. Q. PLEASE DESCRIBE THE TRACY FIRE AND POTABLE WATER
17 PROJECT.
18 A. The Tracy Power Plant was originally designed to use Truckee River water
19 for equipment cooling and fire protection. Sierra has sufficient Truckee
20 River water rights to accommodate these uses. However, the Federal Water
21 Master can curtail the use of river water during periods of extended drought.
22 This happened for the first time in 2015 and again in 2016, as a result,
23 operation of Tracy Units 3, 4 and 5 were put at risk. Additionally, the fire
24
25 Rekowski-DIRECT 18
Page 22 of 236 1 protection system for the facility relies on the Tracy Cooling Pond as source
2 water for the system. The cooling pond is replenished with water from the
3 Truckee River and insufficient supply during periods of curtailment could
4 result in the fire system being disable. This would result in a shutdown of the
5 entire site since the facility cannot operate without fire protection.
6
7 During the curtailment event, well water was diverted to the cooling pond in
8 an attempt to maintain pond level so that the fire system could remain
9 functional. This resulted in a shortage of well water at the site. Domestic
10 water and combustion turbine inlet cooling water are both supplied by wells.
11 These were both affected during the curtailment event.
12 d/b/a NV Energy 13 To mitigate the risks associated with future droughts, interconnections to the Nevada Power Company Company Power Nevada local water utility were completed. The Tahoe Regional Industrial General
and Sierra Pacific Power Sierra and Company 14
15 Improvement District provides fire protection and domestic water to the
16 Tahoe Reno Industrial Center where the Tracy Power Plant in located. Both
17 fire protection and domestic water interties were completed. The fire system
18 interconnection required the addition of a diesel fire pump booster system.
19
20 27. Q. WAS THE PROJECT PREVIOUSLY APPROVED BY THE
21 COMMISSION?
22 A. No. This is normal capital maintenance that is not usually presented to the
23 Commission for approval in advance.
24
25 Rekowski-DIRECT 19
Page 23 of 236 1 28. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
2 A. The total plant addition was $4,166,811 including AFUDC. The total project
3 cost was $3,999,267 excluding AFUDC and was estimated at $3,035,902
4 excluding AFUDC. The project was over budget primarily due to vendor
5 charges being higher than estimated. Specifically, estimates to complete the
6 project did not include unforeseen costs associated with fire system
7 requirements specified by the local fire district, and abandoned piping and
8 active utilities discovered during the railroad crossing (boring) process.
9
10 All of the facilities installed are in-service and used and useful in the
11 provision of utility service. The project was prudently designed and
12 constructed, and the costs of the project were prudently incurred. d/b/a NV Energy 13 Nevada Power Company Company Power Nevada 4. TR1069 Tracy Units 4 Stage 1 Nozzle Replacement Project
and Sierra Pacific Power Sierra and Company 14
15 29. Q. PLEASE DESCRIBE THE TRACY UNITS 4 STAGE 1 NOZZLE
16 REPLACEMENT PROJECT.
17 A. The Tracy Unit 4 stage 1 nozzle reached the end of service life in 2017. The
18 service life is expected to be 72,000 total operating hours, which includes
19 repair of the parts at three 24,000 hour intervals. The repair and replacement
20 interval is based on General Electric guidelines. If the stage 1 nozzle was not
21 replaced, there would be a significant risk of a part breaking free and causing
22 downstream damage, up to and including catastrophic failure
23
24
25 Rekowski-DIRECT 20
Page 24 of 236 1 30. Q. WAS THE PROJECT PREVIOUSLY APPROVED BY THE
2 COMMISSION?
3 A. No. This is routine capital investment that is not normally submitted to the
4 Commission for approval in advance.
5
6 31. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
7 A. The total plant addition was $1,349,626 including AFUDC. All of the
8 facilities installed are in-service and used and useful in the provision of
9 utility service. The project was prudently designed and constructed, and the
10 costs of the project were prudently incurred. The total project cost was
11 $1,356,501 excluding AFUDC and was estimated at $1,894,122 excluding
12 AFUDC. The project was under budget primarily due to vendor charges d/b/a NV Energy 13 being lower than estimated. Specifically, the purchase price of the nozzle Nevada Power Company Company Power Nevada was reduced by the vendor after the cost estimate was prepared.
and Sierra Pacific Power Sierra and Company 14
15
16 B. VALMY
17 1. VA1108 V1 Soot Blower System, Replacement Upgrade Project
18 32. Q. PLEASE DESCRIBE THE VA1108 V1 SOOT BLOWER SYSTEM,
19 REPLACEMENT PROJECT.
20 A. As a result of several premature boiler tube failures, an engineering study
21 was completed to discover the cause. The study recommended the
22 replacement and enhancements of the Unit 1 soot blower system. A project
23 was submitted and approved to eliminate premature boiler tube failures and
24
25 Rekowski-DIRECT 21
Page 25 of 236 1 prevent excessive build up on tubes in the backpass and above burners to
2 prevent buildup of slag above the burners.
3
4 The project was undertaken in three steps. First was the replacement of 26
5 failed soot blowers. This work was completed and placed in service as of
6 December 2011 and included in Sierra’s 2013 GRC. It was during this work
7 that the cause of the failures was discovered to be excessive moisture in the
8 soot blowing steam as a result of the steam source being too low in
9 temperature. The second part of the project was initiated in 2012 to replace
10 the remaining components of the soot blower system, including a steam
11 supply system from a higher steam temperature source. The installation of
12 46 of the new soot blowers was completed during the 2014 Unit 1 outage d/b/a NV Energy 13 and reviewed and included in rate base in Sierra’s 2016 GRC. However, this Nevada Power Company Company Power Nevada project did not encompass the installation of the high temperature piping and
and Sierra Pacific Power Sierra and Company 14
15 16 additional soot blowers.
16
17 The last project was scheduled to be completed during the Unit 1 spring
18 outages in 2016 and 2018. The scope of this work included the demolition
19 and installation of the remaining 16 soot blowers, piping, valves,
20 hangers/pipe supports, insulation, electrical, and DCS controls and the final
21 interconnection to the higher temperature steam source. Eight of the 16 soot
22 blowers were installed in existing locations during the 2016 outage and
23 placed into service. The remaining eight soot blowers were installed during
24
25 Rekowski-DIRECT 22
Page 26 of 236 1 the 2016 outage in new locations, but required new connections to steam,
2 electric power, and DCS controls. This remaining work was intended to be
3 completed during the next outage opportunity. However, due to the reduced
4 operation of the unit and outage constraints, the scope of the project was
5 reassessed and the following actions were subsequently completed in 2017.
6 • The standard piping and valves that were purchased for the project
7 under VA401, but that were not installed and can be used for either
8 the existing system or other plant applications were reclassified and
9 placed into inventory.
10 • The remaining eight new soot blowers installed but not connected
11 and specialty pipe spools/piping purchased under VA401 were
12 placed into a separate project, VA2137 – V1 Soot Blower and Steam d/b/a NV Energy 13 Piping, and placed in suspense. This was done in the event that future Nevada Power Company Company Power Nevada
and Sierra Pacific Power Sierra and Company 14 operation of Unit 1 justified completing the remaining work on the
15 project.
16
17 33. Q. WAS THIS PROJECT PREVIOUSLY APPROVED BY THE
18 COMMISSION?
19 A. No, this was a normal maintenance capital project that is not typically
20 presented to the Commission in advance for approval in an IRP or other
21 docket.
22
23
24
25 Rekowski-DIRECT 23
Page 27 of 236 1 34. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
2 A. The total cost of eight installed and in-service soot blowers was $1,003,703
3 (Sierra’s share $513,111), including AFUDC. The total project cost was
4 $981,183 (Sierra’s share $490,591) excluding AFUDC. All of the facilities
5 installed are in-service and used and useful in the provision of utility service.
6 This project was prudently designed and constructed, and the costs of the
7 project were prudently incurred.
8
9 SECTION IV: GENERATION INVESTMENT BETWEEN JANUARY 1, 2019 AND
10 MAY 31, 2019.
11 A. CERTIFICATION
12 35. Q. WILL ANY GENERATION PROJECTS BE COMPLETED DURING d/b/a NV Energy 13 THE CERTIFICATION PERIOD THAT ARE GREATER THAN $1 Nevada Power Company Company Power Nevada MILLION?
and Sierra Pacific Power Sierra and Company 14
15 A. No. However, since one of the three portions of the Tracy Gearbox project
16 will be completed during the certification period, and the total for the three
17 Tracy Gearbox Projects exceeded $1 million, I chose to discuss it here.
18
19 36. Q. WILL OTHER GENERATION PROJECTS BE COMPLETED
20 DURING THE CERTIFICATION PERIOD THAT ARE LESS THAN
21 $1 MILLION?
22 A. Yes. The generation team expects to complete 41 other projects that
23 individually are less than $1.0 million, but as I mentioned previously,
24
25 Rekowski-DIRECT 24
Page 28 of 236 1 testimony-style descriptions of each and every project completed by the
2 generation team since June 1, 2016, would take hundreds of pages, and the
3 documentation surrounding each project is so voluminous that its value at
4 hearing would be severely diminished.
5
6 1. Tracy 10 ACC Gearbox Replacement
7 37. Q. PLEASE DESCRIBE THE PROJECT.
8 A. As I previously discussed, the Tracy Unit 10 steam turbine has experienced
9 reductions in unit output as a result of failed gearboxes on the fan assemblies
10 in the air cooled condenser. The air cooled condenser utilizes 30 fan
11 assemblies to condense steam that is used in the power cycle. Gearbox
12 failures are unpredictable and have averaged approximately five per year. d/b/a NV Energy 13 Gearbox failures can lead to insufficient cooling capacity which results in Nevada Power Company Company Power Nevada the load on the unit being reduced. A gearbox replacement project was
and Sierra Pacific Power Sierra and Company 14
15 initiated in January 2016 to mitigate the output reductions associated with
16 gearbox failures. Two projects were completed prior to December 31, 2018
17 and this project will be completed early in 2019. In all three phases, 20 of
18 the original 30 gearboxes were replaced and two spare gearboxes were
19 procured.
20
21
22
23
24
25 Rekowski-DIRECT 25
Page 29 of 236 1 38. Q. WHAT IS THE EXPECTED COST OF THIS PROJECT?
2 A. The total plant addition is expected to be $455,385, including AFUDC. The
3 project will be completed by April 15, 2019 with a total project cost
4 estimated at $455,625, excluding AFUDC. The project is expected to be on
5 budget and on schedule.
6
7 39. Q. DOES THIS COMPLETE YOUR TESTIMONY?
8 A. Yes, it does.
9
10
11
12 d/b/a NV Energy 13 Nevada Power Company Company Power Nevada
and Sierra Pacific Power Sierra and Company 14
15
16
17
18
19
20
21
22
23
24
25 Rekowski-DIRECT 26
Page 30 of 236 Exhibit Rekowski-Direct-1 Page 1 of 3
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 01/2013-Present 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. • 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
Page 31 of 236 Exhibit Rekowski-Direct-1 Page 2 of 3
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.
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.
Page 32 of 236 Exhibit Rekowski-Direct-1 Page 3 of 3
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.
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 33 of 236
EXHIBIT REKOWSKI-DIRECT- 2
Page 34 of 236
Exhibit Rekowski-Direct- 2 Page 1 of 2
Section II–Major Plant Additions
Total Estimated Number of Additions at Projects 5/31/19 (w/AFUDC) Fort Churchill
Projects under $1M 11 $ 746,790 Total Fort Churchill 11 $ 746,790
Tracy
Tracy Fire and Potable Water Project 1 $ 4,166,811
Tracy ACC Gear Box Replacement 2 $ 1,809,460 Tracy 4 Stage 1 Nozzle Replacement 1 $ 1,349,626 Project Tracy 4/5 Arc Flash Mitigation 1 $ 1,300,023
Projects under $1M 42 $ 4,386,467 Total Tracy 47 $ 13,012,387
North Valmy Valmy 1 Soot Blower System, 1 $ 513,111 Replacement Upgrade Project
Projects under $1M 70 $ 7,552,932 Total North Valmy 71 $ 8,066,043
Other Generation Projects
Projects under $1M 2 $ 234,988 Total Other Generation Projects 2 $ 234,988 Grand Total 131 $ 22,060,207
Page 35 of 236
Exhibit Rekowski-Direct- 2 Page 2 of 2
Section III–Certification Projects
Total Estimated Number Additions at of 5/31/19 Projects (w/AFUDC)
Certification Period Projects
Tracy Unit 10 ACC Gearbox Replacement 1 $ 453,385
Other Fleet Projects Under $1M 41 $ 4,001,833 Total Certification Period Projects 42 $ 4,455,218
Page 36 of 236 1 AFFIRMATION 2
3 STATE OF NEVADA ) ) ss. 4 COUNTYOF CLARK ) 5 6
7 I, DARIUSZ REKOWSK.l, do hereby swearunder penalty of perjurythe following: 8 That I am the person identified in the attached Prepared Testimony and that such testimony was prepared by me or under my direct supervision; that the answers and = 10 information set forththerein are true to the best of my knowledge and belief as of the date of =;,., e s' 11 s.. u � this affirmation; that I have reviewed and approved any modifications after the date of this es t �... U e� = 12 affirmation;and that if asked thequestions set forththerein, my answers thereto would, under �... �� > � e� ....-= Z 13 oath, be the same. �= � � -- OS 'C= =... � 14 zt . ...t r,.) 15 = 16 17 DARIUSZ REKOWSKI 18 19 Subscribed andsworn to beforeme
20 this 31st day of May, 2019. �-:-:-...... --r.,-. · -- .....,PuMlc.of ...... No. 0J-7"90-1 21 , •s..,_..l&.l.u.s . ..,... ,.._ --.,,am 22 23 NOTAR�J� 24 25 26 27 28
Page 37 of 236
JOHN P. McGINLEY
Page 38 of 236
1 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Sierra Pacific Power Company d/b/a NV Energy
3 2019 General Rate Case Docket No. 19-06___ 4 PREPARED DIRECT TESTIMONY OF 5 John (Jack) P. McGinley 6 Revenue Requirement 7
8 I. INTRODUCTION
9 1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS
10 ADDRESS AND PARTY FOR WHOM YOU ARE FILING
11 TESTIMONY.
12 A. My name is John (Jack) P. McGinley. I am the Vice President of Regulatory 13 for Nevada Power Company d/b/a NV Energy (“Nevada Power”) and Sierra 14 Pacific Power Company d/b/a NV Energy (“Sierra,” and together with
d/b/a NV Energy 15 Nevada Power, the “Companies” or “NV Energy”). My business address is Nevada Power Company Company Power Nevada
16 6100 Neil Road in Reno, Nevada. I am filing testimony on behalf of Sierra. and Sierra Pacific Power Company Pacific Power Sierra and Company 17
18 2. Q. PLEASE DESCRIBE YOUR BACKGROUND AND EXPERIENCE IN 19 THE UTILITY INDUSTRY. 20 A. I have been employed by the Companies since May 1984. I have held many 21 positions primarily focused on matters related to resource planning, 22 renewable energy development, power contracts and rates. I hold a Bachelor 23 of Science in Mechanical Engineering from the University of Nevada, Reno. 24 My statement of qualifications is attached as Exhibit McGinley-Direct-1. 25 26 27
28 McGinley-DIRECT 1
Page 39 of 236
1 3. Q. HAVE YOU PREVIOUSLY TESTIFIED BEFORE THE PUBLIC 2 UTILITIES COMMISSION OF NEVADA (“COMMISSION”)? 3 A. Yes. I have testified before this Commission many times during my 35 years 4 at the Company related to integrated resource planning (“IRP”), energy 5 supply plan (“ESP”), general rate cases (“GRC”), and various other Company 6 filings. Most recently, I provided testimony in the 2018 and 2019 deferred 7 energy cases, and the filing made in compliance with the Commission’s order 8 in Sierra and Nevada Power’s 2018 joint integrated resource plan (“2018 Joint
9 IRP”) addressing alternative allocations for the investment and lease costs for
10 the One Nevada Transmission Line (“ON Line”) between Sierra and Nevada
11 Power (Docket No. 19-05002). In addition, I have testified before the Nevada
12 Legislature on various energy matters. 13 14 4. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS
d/b/a NV Energy 15 GENERAL RATE REVIEW PROCEEDING? Nevada Power Company Company Power Nevada
16 A. At Paragraph 148 in its February 15, 2019 Modified Final Order in the 2018 and Sierra Pacific Power Company Pacific Power Sierra and Company 17 Joint IRP (Docket No. 18-06003), the Commission directed the Companies to 18 file “an application that directly and solely addresses ON Line cost 19 allocation.” That filing was made on May 1, 2019, and has been docketed by 20 the Commission as Docket No. 19-05002. The February 15, 2019 Modified 21 Final Order also required that the Companies reflect the impact of any 22 reallocation of ON Line costs in this filing, Sierra’s 2019 general rate case 23 application. My testimony addresses this directive. Further, I generally 24 support the tariff revisions included with the filing, and specifically address 25 the need to update the charges in Schedule MC (miscellaneous charges) to 26 reflect the current costs of performing the work described in the tariff. 27 28 McGinley-DIRECT 2
Page 40 of 236
1 II. COSTS OF CHANGING THE ALLOCATION OF ON LINE COSTS 2 5. Q. WHAT IS THE ONE NEVADA TRANSMISSION LINE OR “ON 3 LINE”?
4 A. The ON Line is a 500 kilovolt (“kV”) transmission line between the Robinson 5 Summit Substation in northern Nevada and the Harry Allen Substation in 6 southern Nevada. The ON Line provides a direct connection between what 7 were two separate transmission systems; namely, the transmission systems of 8 Nevada Power and Sierra.
9
10 6. Q. WHEN WAS ON LINE PLACED IN SERVICE?
11 A. The ON Line was energized at approximately midnight on December 31,
12 2013. At that time, the separate balancing authority areas operated by Nevada 13 Power and Sierra were consolidated into a single balancing authority area 14 operated by Nevada Power. A single, system-wide rate for network
d/b/a NV Energy 15 integration, point-to-point and ancillary services previously authorized by the Nevada Power Company Company Power Nevada
16 Federal Energy Regulatory Commission also became effective. Nevada and Sierra Pacific Power Company Pacific Power Sierra and Company 17 Power and Sierra also began operating the generating resources owned and 18 controlled by the two companies as network resources for the benefit of all of 19 their customers. Stated differently, when ON Line went into service the 20 generating resources owned and controlled by the two companies were 21 effectively pooled. Through Nevada Power, the two companies began 22 establishing operating plans designed to provide the lowest energy costs to all 23 customers, regardless of vestigial ownership or control of the generation 24 resources. 25 26 27
28 McGinley-DIRECT 3
Page 41 of 236
1 7. Q. PLEASE SUMMARIZE THE FILING THAT SIERRA AND NEVADA 2 POWER MADE ON MAY 1, 2019, REGARDING THE ON-LINE?
3 A. Pursuant to the Commission’s Modified Final Order in Docket No. 18-06003, 4 the Companies filed an application requesting that the Commission 5 permanently establish an allocation of ON Line capital and operation and 6 maintenance costs. The Companies asked that the Commission allocate 80 7 percent of ON Line capital and operations and maintenance expense to 8 Nevada Power and 20 percent to Sierra. If accepted, this proposal will change
9 the current allocation, which assigns 95 percent of ON Line capital and
10 operations and maintenance expense to Nevada Power and 5 percent to Sierra.
11
12 8. Q. WHAT WILL BE THE IMPACT OF THE CHANGE IN THE 13 ALLOCATION OF ON LINE CAPITAL AND OPERATIONS AND 14 MAINTENANCE COSTS ON SIERRA’S CUSTOMERS?
d/b/a NV Energy 15 A. If the Commission accepts the Companies’ proposal, Sierra’s base tariff Nevada Power Company Company Power Nevada
16 general revenue requirement will increase by just over $6 million.1 and Sierra Pacific Power Company Pacific Power Sierra and Company 17 18 9. Q. IS THE $6 MILLION INCREASE IN SIERRA’S REVENUE 19 REQUIREMENT REFLECTED IN THE SCHEDULES FILED IN 20 THIS PROCEEDING? 21 A. No. While calculated, the proposed change in the allocation of ON Line 22 capital and operations and maintenance expense is not yet known and 23 measurable with reasonable certainty at the time of the filing. Thus, the base 24 tariff general revenue requirement associated with an 80/20 reallocation of 25 ON Line costs could not be reflected in the statements and schedules. 26 Currently, the Companies’ proposal is pending before the Commission. As of
27 1 Nevada Power’s base tariff general revenue requirement will decrease. 28 McGinley-DIRECT 4
Page 42 of 236
1 the date of this general rate review filing, the intervention period for the 2 docket has not run, and a procedural schedule has not been issued. The 3 Companies’ proposal in Docket No. 19-05002 is the subject of a contested 4 case in which multiple stakeholders located in both northern and southern 5 Nevada likely have a direct and substantial interest. These stakeholders 6 include the Commission’s Regulatory Operations Staff, the Bureau of 7 Consumer Protection and customers. For instance, the Southern Nevada 8 Water Authority, the Northern Nevada Industrial Electric Users and
9 organizations representing gaming and hospitality companies have
10 recommended different allocation of ON Line capital and operations and
11 maintenance expense costs in the past. Moreover, while Nevada Power and
12 Sierra have filed an application and testimony in Docket No. 19-05002 13 supporting the reasonableness of the 80/20 allocation, the Companies also 14 recognize that the data supports a range of reasonable allocations, any of
d/b/a NV Energy 15 which the Commission may ultimately adopt. Nevada Power Company Company Power Nevada
16 and Sierra Pacific Power Company Pacific Power Sierra and Company 17 10. Q. WHAT IS SIERRA’S PROPOSAL IN THIS PROCEEDING AS IT 18 RELATES TO ON LINE CAPITAL AND LEASE EXPENSES? 19 A. The Company recommends that the Commission address the revenue 20 requirement impact of any change in the allocation of ON Line capital and 21 lease costs ultimately adopted by the Commission by authorizing Sierra to 22 establish a regulatory asset, subject to a carrying charge, for the base tariff 23 general revenue requirement amount associated with any reallocation of ON 24 Line costs coming from Docket No. 19-05002. Nevada Power would 25 simultaneously establish a corresponding regulatory liability, with carrying 26 charges, to be addressed in its next general rate filing. 27 28 McGinley-DIRECT 5
Page 43 of 236
1 III. CHANGES TO SCHEDULE MC (MISCELLANEOUS CHARGES) 2 11. Q. WHAT CHANGES ARE BEING PROPOSED FOR SCHEDULE MC - 3 MISCELLANEOUS CHARGES? 4 A. Sierra proposes the following changes to Schedule MC in this proceeding, all 5 of which address the structure and charges for dispatching Company 6 personnel at a customer’s request.
7 • First, Sierra proposes to keep the current charge of $40 per visit to 8 connect or reconnect following a service disconnection;
9 • Second, Sierra proposes to introduce a charge for more time
10 consuming and complex reconnection visits of $275.00 per visit;
• 11 Third, Sierra proposes to move the premium for same day or after-
12 hours service to a separate $20 charge that would be applied in 13 addition to the specific service being performed; and
14 • Fourth, for non-standard requests that are not covered by the fees
d/b/a NV Energy 15 discussed above, the Company proposes to establish a mechanism to Nevada Power Company Company Power Nevada
16 recover the actual expenses incurred for dispatching utility personnel and Sierra Pacific Power Company Pacific Power Sierra and Company 17 for the special requests of customers. The nature of these special 18 requests are outside of the normal disconnect and reconnect process, 19 and generally involve additional labor and other expenses to satisfy 20 the customer’s requirements. 21 22 12. Q. WHY IS SIERRA PROPOSING TO KEEP THE CURRENT CHARGE 23 OF $40 PER VISIT FOR A CONNECT OR RECONNECT VISIT 24 FOLLOWING A SERVICE DISCONNECTION? 25 A. The current cost to provide this service is in line with the cost analysis that 26 supported the current charge. As such, a modification to the current common 27 connect/reconnect rate is not required. 28 McGinley-DIRECT 6
Page 44 of 236
1 13. Q. WHY DOES THE COMPANY MAKE THE DISTINCTION 2 BETWEEN CONNECTING OR RECONNECTING SERVICE AND 3 PHYSICALLY DISCONNECTING OR RECONNECTING THE 4 CUSTOMER TO THE COMPANY’S ELECTRICAL SYSTEM? 5 A. Service disconnects and reconnects that require only the operation of a switch 6 or other device can be performed by Service Technicians. Service 7 Technicians are utility trained personnel, qualified to specifically perform 8 work on electric meter service panels rated at a maximum of 240 volts.
9 Service connects and reconnects on electric meter service panels rated above
10 240 volts are only able to be performed by a Meter Technician, Electric
11 Lineman, or an Electric Troubleman.
12 13 Only a Journeyman Lineman (Electric Troubleman) is able to physically 14 disconnect or reconnect the customer from the electrical system. Physical
d/b/a NV Energy 15 disconnects and reconnects are necessary when the customer’s electric panel Nevada Power Company Company Power Nevada
16 must be accessed or replaced. For example, when a customer adds a PV and Sierra Pacific Power Company Pacific Power Sierra and Company 17 system to their home, the customer’s electric service panel must be safely 18 accessed and potentially replaced to accommodate the additional electrical 19 connections for the on-site generation. 20 21 14. Q. HOW WAS THE NEW CHARGE FOR PHYSICAL DISCONNECTS 22 OR RECONNECTS SERVICE DEVELOPED? 23 A. A review was conducted to quantify the cost of dispatching utility personnel 24 to physically disconnect and reconnect a customer to the Company’s 25 electrical system – primarily the historic costs associated with sending a 26 troubleman to perform the required work at a customer’s premise. The labor 27 rate used was based on the straight-time cost per hour including overheads, 28 McGinley-DIRECT 7
Page 45 of 236
1 administrative and supervisory costs for a troubleman. The fully loaded 2 hourly rate for this type of work is $125.41. This includes the straight-time 3 hourly rate in the current labor agreement of $49.12, as well as labor 4 overheads and hourly transportation cost for the troubleman’s vehicle. An 5 average travel time per visit was included as part of the historical analysis for 6 the service provided. The average duration for this service is 2.35 hours. This 7 average was multiplied by the total hourly cost described above then added to 8 the cost of a customer service representative to schedule the visit to obtain an
9 average cost per visit of $297.77 for this service. Table McGinley Direct-1
10 shows the cost components that were included in the development of the
11 proposed charge.
12 Table McGinley Direct-1 – Complex Connect or Reconnect Service Cost 13 TROUBLEMAN 14
d/b/a NV Energy 15 Labor, per hour $ 49.12 Nevada Power Company Company Power Nevada
Labor Overhead 74.9% $ 36.79 16 Total Field Labor, per Hour $ 85.91 and Sierra Pacific Power Company Pacific Power Sierra and Company 17 Truck 18 Vehicle Costs per hour $ 25.87 Transportation Overhead 52.67% $ 13.63 19 Total Vehicle Costs, per Hour: $ 39.50 20 Total Hourly Cost $ 125.41 21 22 Average Time per Call: (hours) 2.35 Total Field Cost: $ 294.71 23 CSR Processing Cost $ 3.06 24 Total Cost: $ 297.77
25 Proposed Charge: $ 275.00
26 27
28 McGinley-DIRECT 8
Page 46 of 236
1 15. Q. WHY IS THE COMPANY PROPOSING TO REVISE THESE 2 CHARGES AT THIS TIME? 3 A. Demand for these services has increased in recent years, driven primarily by 4 the increase in number of customer-owned photovoltaic (“PV”) systems and 5 electric vehicle chargers. As described above, when a customer adds a PV 6 system to their home, the customer’s electric service panel must be safely 7 accessed and replaced to accommodate the additional electrical connections 8 for the on-site generation. In order to facilitate this work, the Company must
9 dispatch the appropriate personnel to the premise to disconnect the customer’s
10 service from the service transformer. Once this upgrade is complete, the
11 Company must dispatch the appropriate personnel back to the customer’s site
12 to reconnect the service to the service transformer. In all cases, the cost of this 13 service exceeds the rate established in the tariff. This service is also required 14 if the customer is upgrading their electrical panel for the addition of any new
d/b/a NV Energy 15 electrical connections. Nevada Power Company Company Power Nevada
16 and Sierra Pacific Power Company Pacific Power Sierra and Company 17 16. Q. WHY IS THE COMPANY PROPOSING A SEPARATE CHARGE 18 FOR SAME DAY OR AFTER HOURS SERVICE? 19 A. Currently, customers who request same day or after-hours service pay an 20 additional $20 per request. The Company is proposing to move the current 21 premium for this service to a separate charge for several reasons:
22 • The customer will be able to more clearly see the additional cost for 23 this service split out from the cost of the request;
24 • The separation of this charge will help the Company’s customer 25 service representatives that field these service requests to more easily 26 apply this charge when appropriate; and 27
28 McGinley-DIRECT 9
Page 47 of 236
1 • The charge for same day or after-hours service continues to be 2 supported by the additional labor costs to meet after hours requests 3 4 17. Q. HOW DOES THE COMPANY DEFINE THE DIFFERENCE 5 BETWEEN A STANDARD REQUEST AND A SPECIAL REQUEST 6 TO DISCONNECT OR RECONNECT THE CUSTOMER TO THE 7 COMPANY’S ELECTRICAL SYSTEM?
8 A. Standard requests are those made by the customer to disconnect their service
9 from the serving transformer, switch, utility room, etc. so the customer’s
10 electrical panel(s) is no longer energized. These requests would occur during
11 normal business hours (8:00 am to 5:00 pm). NV Energy’s personnel arrive
12 at the customer’s location, disconnect the service, leave that location and 13 return at the customer’s request to reconnect the service. All other service 14 requests would be considered a “special request” including but not limited to
d/b/a NV Energy 15 after-hours requests, keeping the NV Energy employees at the customer’s Nevada Power Company Company Power Nevada
16 location during the duration of their work, work requiring additional NV and Sierra Pacific Power Company Pacific Power Sierra and Company 17 Energy crew members or vehicles, etc. 18 19 18. Q. WHY IS THE COMPANY PROPOSING A PROCESS TO HANDLE 20 SPECIAL REQUESTS? 21 A. Special requests such as described above have increased in recent years and 22 the costs to perform them has grown far beyond the standard connect or 23 reconnect charge that is currently in place. A common request the Company 24 receives from larger customers is to have utility personnel stand-by while the 25 customer makes repairs or tests equipment such as their generators. Typically 26 for larger customers, this work is requested to be scheduled during the 27 evening so that it does not disrupt the customer’s normal business hours. To 28 McGinley-DIRECT 10
Page 48 of 236
1 perform this work and satisfy the customer’s request, actual expenses are 2 incurred in the form of overtime labor and other requirements laid out in the 3 current labor agreements. These actual expenses vary depending on the 4 specific request, time of day, and hours worked. 5 6 The cost of the special requests are unique to each individual request. The 7 intent of this proposed modification to Scheduled MC is to recover the actual 8 expenses incurred by utility personnel. The labor rate will be the actual labor
9 rate earned by the utility personnel at the time of the work, taking into
10 consideration any applicable over-time rates. Labor rates will include all
11 applicable overheads, administrative, and supervisory costs, as well as vehicle
12 transportation costs. If the work occurs outside of normal working hours, 13 other expenses may also apply depending on the situation.
14
d/b/a NV Energy 15 19. Q. HOW DOES THE COMPANY PROPOSE TO REVISE THE Nevada Power Company Company Power Nevada
16 MISCELLANEOUS CHARGES TARIFF TO INCLUDE THE and Sierra Pacific Power Company Pacific Power Sierra and Company 17 PROCESS FOR RECOVERING THE COST OF SPECIAL 18 REQUESTS? 19 A. The Company proposes to add a paragraph to Schedule MC, Special 20 Condition 1, Visits that reads, “(f)or customers that require custom services 21 beyond those services specifically outlined in this Tariff, the Company will 22 prepare an invoice and bill on actual charges.” 23 24 25 26 27
28 McGinley-DIRECT 11
Page 49 of 236
1 20. Q. DID THE DEPLOYMENT OF THE NV ENERGIZE (SMART 2 METER) PROJECT AND ITS REMOTE CAPABILITY ELIMINATE 3 THE NEED FOR VISITS TO DISCONNECT OR RECONNECT? 4 A. Not entirely. The NV Energize project allows for the meter to be remotely 5 disconnected so the energized connection between the serving transformer is 6 separated from the customer’s panel. This enables the customer’s side of the 7 panel to be safely serviced as needed. However this remote disconnection still 8 leaves the conductor between meter and the serving transformer energized.
9 When the customer changes out the entire panel to connect a solar panel or
10 other improvements, this conductor is required to be de-energized as well.
11
12 21. Q. WHERE IS THE PROPOSED SCHEDULE MC TARIFF INCLUDED 13 WITH THIS FILING? 14 A. The proposed Schedule MC tariff can be found in Application Exhibit A to
d/b/a NV Energy 15 this Application. Current tariffs, including the currently effective Schedule Nevada Power Company Company Power Nevada
16 MC, can be found in Application Exhibit B. and Sierra Pacific Power Company Pacific Power Sierra and Company 17 18 22. Q. DOES THIS CONCLUDE YOUR PREPARED DIRECT 19 TESTIMONY? 20 A. Yes, it does. 21 22 23 24
25 26 27
28 McGinley-DIRECT 12
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QUALIFICATIONS OF WITNESS JOHN (JACK) P. MCGINLEY SIERRA PACIFIC POWER & NEVADA POWER COMPANIES D/B/A NV ENERGY 6100 Neil Road Reno, Nevada 89511-1137
My name is John (“Jack”) P. McGinley. I am the Vice President, Regulatory for Sierra Pacific Power Company and Nevada Power Company. I graduated from the University of Nevada Reno in 1984 with a Bachelor of Science in Mechanical Engineering. Upon graduating from the University of Nevada, I have been employed full time by the Company for 35 years. I have held various technical and leadership positions primarily in Resource Planning, Power Contracts, Regulatory and Legislative Strategy. I have participated in and managed the preparation of many regulatory proceedings before the Public Utilities Commission of Nevada. I have provided testimony in numerous regulatory filings before the Commission. In the early 1990’s, I was responsible for the Company’s Resource Planning, Research and Development and Demonstration (“RD&D”) and Supply Engineering departments. In this position, I was responsible for the Company’s RD&D program planning, management, and technical review and evaluation of potential supply side options including conventional generation, renewable generation including private generation solar, storage technologies and electric vehicles. In 1998, I assumed the duties of Manager of New Product Development. This led to working with a team of individuals to establish two subsidiary companies; E-three and Simple Choice where I held the position of General Manager of Simple Choice. In 2000, I assumed the duties of Principal Consultant in the Strategic Planning Department. In 2001, I assumed the position of Principal Consultant in the Rates and Regulatory Department and was responsible for filing fuel and purchase power rider cases. Later in 2001, I assumed the duties of Manager of Long Term Resource Analysis and in 2005 I assumed the position of Regulatory Strategist. In 2007, I assumed the position of Development Director in the Renewable Energy department where my responsibilities included the formation of the department and development of renewable energy projects. In 2013, I was assigned as the project manager to lead a team of internal technical experts with the responsibility to evaluate the participation in the California Independent System Operator (“CAISO”) Energy Imbalance Market (“EIM”). The Company ultimately decided to join the EIM and received approval from the Commission in 2014. The Company went live in December 2015, with 2016 as the first full year of participation. In 2009, I served on the University of Nevada Chemical Engineering Advisory Board. From 2013 to 2016 I served on the Governor’s Workforce Investment Board on the Clean Energy Sector Council. For many years I served as a member of the Governor’s New Energy Industry Task Force and in 2016 I was appointed to the New Energy Industry Task Force Technical Advisory Committee on Distributed Generation and Storage.
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JOHN S. BERDROW
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1 BEFORE THE PUBLIC UTILITIES COMMISSION OF NEVADA
2 Sierra Pacific Power Company d/b/a NV Energy
3 2019 General Rate Case Docket No. 19-06______4
5 PREPARED DIRECT TESTIMONY OF
6 John S. Berdrow
7 REVENUE REQUIREMENT
8 TABLE OF CONTENTS PAGE 9 I. INTRODUCTION 3
10 II. SIERRA MAJOR T&D PROJECTS 7
11 1. Brunswick 120 kV Substation Rebuild (4P) 7
12 2. Smith Valley 120/25 kV Substation (WD) 9 13 3. Mason Valley 120/25 kV Substation (BS) 11 14 4. South Meadows 120/25 kV Substation (1W) 13 D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 5. Ormat Tungsten 2309 Line POR Substation (RC) 14
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 6. Lahontan – Lovelock 617 Line Rebuild (6B) 17 17 7. Round Hill 120/14 kV Substation Failure (A7B) 19 18 8. Foothill – Kingsbury 634 Line Rebuild (FZ) 20 19 9. North Red Rock 120/25 kV Substation (AC8) 22 20 10. Update to 230 kV Three Pole Structure Replacement (XN) 24 21 11. Mira Loma – Steamboat 127 Line Relocation (A0X) 26 22 12. Steamboat 215 Feeder Addition (9R) 28 23 13. Update to 345 kV PLC Replacement Program (AL) 29 24 14. Humboldt – Midpoint 345 kV Wave Trap Upgrade (3Y) 31 25 15. 345 kV Cap Bank Breaker Replacement (ZC) 33 26 16. Brunswick to Buckeye 635 Line Relocation (A0H) 35 27
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1 III. TRACY AREA MASTER PLAN 36 2 1. Chukar 120/25 kV Substation (P9) 38 3 2. Dove to Wild Horse 120 kV Line (A8) 39 4 3. Tesla Phase II (S5) 40 5 4. Update to Apple Data Center – Tracy Area (A5) 42
6 IV. NERC TRANSMISSION SYSTEM REQUIREMENTS 45 7 1. Update to 128 Line Capacity Upgrades (B3) 46 8 2. East Tracy Underrated Breaker Replacement (YR) 48 9 3. Winnemucca Area UVLS (E9) 50
10 4. Pah Rah – Tracy East 120 kV Line (M8) 51
11 5. Frontier Breaker Addition (A0I) 53
12 V. CONCLUSION 54 13 14 D/b/a NV Energy NV Energy D/b/a 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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1 I. INTRODUCTION 2 1. Q. PLEASE STATE YOUR NAME, OCCUPATION, BUSINESS ADDRESS, 3 AND PARTY FOR WHOM YOU ARE FILING TESTIMONY. 4 A. My name is John Berdrow. I am a Major Projects Manager for NV Energy, Inc. 5 (“NV Energy”), Nevada Power Company d/b/a NV Energy (“Nevada Power”), and 6 Sierra Pacific Power Company d/b/a NV Energy (“Sierra”, and together with 7 Nevada Power, the “Companies”). I work primarily out of Sierra’s corporate office, 8 which is located at 6100 Neil Road in Reno, Nevada. I am filing testimony in this
9 proceeding on behalf of Sierra.
10
11 2. Q. PLEASE DESCRIBE YOUR PROFESSIONAL BACKGROUND AND
12 EXPERIENCE. 13 A. I have a Bachelor of Science degree in Civil Engineering from the University of 14 Nevada, Reno. I am a registered Professional Engineer in the states of Nevada and D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 California. I began my employment in the energy industry as a student engineer
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 with Sierra in 1981. I have substantial experience in engineering and project 17 management and have performed services for utility projects throughout Nevada 18 and eastern California, including overhead and underground electric transmission 19 lines, electric substations, gas transmission pipelines and compression, 20 environmental and regulatory permitting, private land acquisition, material 21 procurement, contracts, and construction of the facilities described above. In 2014 22 and 2015, I was project manager to implement NV Energy’s participation in the 23 California Independent System Operator’s Energy Imbalance Market. I have 24 attached as Exhibit Berdrow-Direct-1 a statement of qualifications that further 25 details my background and professional experience. 26 27
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1 3. Q. HAVE YOU PREVIOUSLY SUBMITTED PRE-FILED TESTIMONY IN A 2 REGULATORY PROCEEDING? 3 A. Yes, I have testified in previous proceedings before the Public Utilities Commission 4 of Nevada (“Commission”). My most recent general rate case testimony was in 5 Nevada Power’s 2017 general rate case filing, Docket No. 17-06003. 6 7 4. Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY IN THIS 8 PROCEEDING?
9 A. I demonstrate the prudence of several categories of investment in transmission and
10 distribution facilities (“T&D”) that are included in the calculation of Sierra’s
11 revenue requirement.
12 13 5. Q. HOW IS YOUR TESTIMONY ORGANIZED? 14 A. My testimony is organized into the following sections: D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Section II. I demonstrate that Sierra’s investments in T&D facilities were prudent, 17 and that these T&D facilities are used and useful in providing service to customers. 18 My testimony specifically addresses the major T&D facilities placed in service 19 since the end of the certification period in Sierra’s last general rate case (June 1, 20 2016) through the end of the test period in this filing (December 31, 2018), and the 21 end of the certification period (May 31, 2019), whose aggregated or “linked” work 22 orders exceed $1 million. Major T&D projects are typically comprised of several 23 linked work orders that allow the Company to identify the scope and cost for the 24 type of asset required to complete the project. For reference, I provide the “linked” 25 amount for each of the major projects described in Section II. Major T&D projects 26 can include investment in multiple assets, including and generally identified as 27
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1 substations, transmission lines, distribution lines, telecommunications, metering, 2 relay and protection, environmental permits, regulatory permits, and land rights. In 3 my testimony, I describe each major T&D project, why it was necessary, if it has 4 previously been presented to the Commission, the total cost of the project, its actual 5 or estimated in-service date and other information to demonstrate Sierra’s 6 investment is prudent. A listing of all new T&D plant additions is provided in 7 Exhibit Berdrow-Direct-2. 8
9 Section III. Tracy Area Master Plan: I demonstrate that Sierra’s investment in
10 projects associated with the initial phases of the Tracy Area Master Plan is prudent,
11 and is used and useful and providing service to customers. Consistent with the
12 Tracy Area Master Plan presented to the Commission in Docket No. 17-11003 13 (please refer to Sierra’s Second Amendment to its 2017 Integrated Resource Plan, 14 Volume 1 of 4, Section 8 Transmission, B2 Tracy Area Master Plan), my testimony D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 describes the general project purpose, scope, and cost components to be included
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 for recovery in this general rate case. A copy of the Tracy Area Master Plan filed 17 in Docket No. 17-11003 is provided as Exhibit Berdrow-Direct-3. 18 19 Section IV. NERC Transmission System Requirements: I demonstrate the 20 prudence of Sierra’s investment in projects necessary to comply with North 21 American Electric Reliability Corporation (“NERC”) reliability standard TPL-001- 22 4 Transmission System Planning Performance Requirements that became effective 23 January 1, 2016. These projects were identified as part of the Company’s 24 Transmission Planning function to provide mitigation for system instabilities that 25 do not comply the mandated standard requirements. I describe the overall NERC 26 27
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1 compliance requirements as well as details of each project and costs to be included 2 for recovery in this rate case. 3 4 6. Q. ARE YOU SPONSORING ANY EXHIBITS TO YOUR PREPARED 5 DIRECT TESTIMONY? 6 A. Yes. I am sponsoring six exhibits:
7 • Exhibit Berdrow-Direct-1 Statement of Qualification 8 • Exhibit Berdrow-Direct-2 Transmission and Distribution Major Projects, total 9 cost between June 1, 2016 and May 31, 2019
10 • Exhibit Berdrow-Direct-3 Tracy Area Master Plan (Redacted)
11 • Exhibit Berdrow-Direct-4 Amended and Restated Rule 9, Section B.2 HVD
12 Agreement No. 16-00042 between Sierra and Switch, Ltd
13 • Exhibit Berdrow-Direct–5 HVD Amended and Restated Rule 9, Section B.2 14 HVD Agreement No. 15-00001 between Sierra and Tesla, Inc. D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 • Exhibit Berdrow-Direct-6 HVD Amended and Restated Rule 9, Section B.2
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 HVD Agreement No. 14-00046 between Sierra and Apple, Inc.
17 • Exhibit Berdrow-Direct-7 NERC TPL-001-4 – Transmission System Planning 18 Performance Requirements 19 20 7. Q. ARE ANY OF THE MATERIALS YOU ARE SPONSORING 21 CONFIDENTIAL? 22 A. The Tracy Area Master Plan, contains extensive detail regarding customer-specific 23 loads and system configurations. This customer-specific information was 24 designated as confidential when the Tracy Area Master Plan was originally filed in 25 2017, and remains as such today. To aid in the Commission’s review of the projects 26 27
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1 described below, I have provided in Exhibit Berdrow-Direct 3 a redacted version 2 of the Tracy Area Master Plan. 3 4 II. SIERRA MAJOR T&D PROJECTS 5 8. Q. DESCRIBE THE PROJECTS INCLUDED IN THIS SECTION. 6 A. This section discusses investments for major T&D projects greater than $1 million 7 listed in Exhibit Berdrow-Direct-2. These projects were placed in service since 8 the end of the certification period in Sierra’s last general rate case (May 31, 2016)
9 and the end of the certification period in this general rate case (May 31, 2019). The
10 projects are organized in order of descending total cost.
11
12 1. BRUNSWICK 120 kV SUBSTATION REBUILD (4P) 13 9. Q. PLEASE DESCRIBE THE PROJECT. 14 A. This project involved a rebuild of the existing Brunswick Substation adjacent to the D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 existing substation in Carson City. This rebuild project was similar to the Silver
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Peak Substation Rebuild in 2011, the Gabbs Substation Rebuild in 2012 and the 17 Lahontan Substation rebuild in 2015. The new design reconfigured the substation 18 from the then-existing radial bus scheme to a full breaker and one-half bus 19 arrangement. The existing eight transmission lines were re-aligned to connect to 20 the new substation terminals and both of the distribution transformers are now 21 being sourced from the stronger 120 kilovolt (“kV”) system. The substation project 22 included grading, fencing, installation of new transformers, circuit breakers, 23 switches and associated bus work. A new control enclosure was installed to 24 accommodate relay protection, control, and telecommunication equipment. 25 Removal and decommissioning of the existing Brunswick Substation was also 26 included as part of this project. 27
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1 10. Q. WHY WAS THE PROJECT NECESSARY? 2 A. Brunswick Substation is the primary source of electricity for some 40,000 3 customers in Carson City and northeast Lake Tahoe and is a major point of 4 interconnection to several important NV Energy power plants. The Brunswick 5 Substation provides approximately 150 MW of capacity to manufacturing, 6 commercial, and residential loads in Carson City and the surrounding area. 7 Brunswick Substation also includes black start generation facilities that can be used 8 to provide critical start-up power to Tracy Generation Station in the event of a
9 system-wide emergency outage.
10
11 The original lattice-style substation was constructed in the 1960s as a radial bus
12 configuration that could not be sectionalized. Under certain fault conditions, the 13 entire substation and associated connected facilities were susceptible to decreased 14 reliability and extended outages. NV Energy reliability reports ranked Brunswick D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 Substation second overall in customer outage hours and third overall in number of
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 customers affected in northern Nevada. The substation rebuild incorporated 17 updated design standards that provide immediate reliability improvements and 18 allow for future expansion as new growth develops in the area. 19 20 11. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION?
21 A. No. The Company did not submit the project to the Commission for approval 22 because it did not entail the construction of a “Utility Facility” in accordance with 23 NRS § 704.860. 24 25 12. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 26 A. The estimated total cost of the project was $22,180,528 (without AFUDC). The 27
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1 total cost of the project through December 31, 2018, was $25,769,060 (with 2 AFUDC), and the estimated total cost through May 31, 2019, is $27,096,755 (with 3 AFUDC). The $1,327,695 in estimated costs to be incurred between January 1, 4 2019, and May 31, 2019, include associated telecommunications plant placed in 5 service during this time period and post-construction costs to complete removals. 6 The project was placed in service on October 1, 2018. All of the facilities installed 7 are in service and used and useful in the provision of utility service. 8
9 2. SMITH VALLEY 120/25 kV SUBSTATION (WD)
10 13. Q. PLEASE DESCRIBE THE PROJECT.
11 A. This project involved the construction of the new Smith Valley 120x60/25 kV
12 Substation to improve reliable service in Smith Valley, Wellington, and Topaz 13 Ranch Estates areas in Lyon and Douglas counties. The project included grading, 14 fencing, installation of a new 120x60/25 kV 28 Mega Volt Amps (MVA) D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 transformer, circuit breakers, switches and associated bus work. A new control
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 enclosure was installed to accommodate relay protection, control, and 17 telecommunication equipment. Approximately 18 miles of new overhead 120x60 18 kV transmission line with telecommunications fiber optic cable was constructed 19 from Mason Valley Substation to this new Smith Valley Substation. The route 20 essentially followed an existing distribution line that originally fed the Smith 21 Valley area from Yerington. The existing distribution line was underbuilt on the 22 new transmission poles. Construction of the new substation in Smith Valley area 23 allowed the Company to connect to two existing long distribution lines that 24 originated in Yerington and sectionalize them into four shorter feeders sourced out 25 of the new Smith Valley Substation. Removal and decommissioning of the existing 26 Smith Valley switching station was also included as part of this project. 27
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1 14. Q. WHY WAS THE PROJECT NECESSARY? 2 A. Pursuant to Commission Inquiry Number 55-1206 regarding reliability issues in the 3 Yerington, Smith Valley, Wellington, and Topaz Ranch Estates areas, the Company 4 performed an analysis of the existing distribution system configuration as well as 5 the overall reliability statistics, operating data, and outage history for the area. 6 Existing distribution lines and facilities serving the Yerington, Smith Valley, 7 Wellington, and Topaz Ranch Estates areas were unable to adequately support 8 customer electric load requirements during certain periods of high electric usage.
9 The analysis reported voltage quality issues (i.e. low voltage) and frequent outages
10 for customers being served from the existing Anaconda 204/209 and Topaz 1261
11 distribution feeders. The Company permitted and constructed the new facilities to
12 address these customer reliability issues and accommodate future growth. 13 14 15. Q. HAS THIS PROJECT BEEN PREVIOUSLY REVIEWED? D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 A. Yes. Sierra recommended the addition of the Smith Valley Substation project as a
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 result of a recommendation by the Commission’s Regulatory Operations Staff in 17 its Inquiry Number 55-1206. 18 19 16. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 20 A. The estimated total cost of the project was $16,945,026 (without AFUDC). The 21 total cost of the project through December 31, 2018, was $17,676,964 (with 22 AFUDC), and the estimated total cost through May 31, 2019, is $17,674,440 (with 23 AFUDC). The estimated total cost decreased between December 31, 2018, and May 24 31, 2019, due to a credit for stock material returned to the Company’s warehouse. 25 The project was placed in service on June 14, 2018. All of the facilities installed 26 are in service and used and useful in the provision of utility service. 27
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1 3. MASON VALLEY 120/25 kV SUBSTATION (BS) 2 17. Q. PLEASE DESCRIBE THE PROJECT. 3 A. This project involved the consolidation of the existing Bridge Street and Anaconda 4 substations into the single new Mason Valley Substation located in Lyon County. 5 The substation project included grading, fencing, installation of two new 120x60/25 6 kV 47 MVA transformers, circuit breakers, switches and associated bus work. A 7 new control enclosure was installed to accommodate relay protection, control, and 8 telecommunication equipment. Existing transmission lines from Anaconda
9 Substation were re-routed into the new Mason Valley Substation terminals and four
10 new 25 kV underground distribution feeders were installed to tie into existing
11 feeders at both Bridge Street and Anaconda. Removal and decommissioning of the
12 existing Anaconda and Bridge Street substations was also included as part of this 13 project. 14 D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 18. Q. WHY WAS THE PROJECT NECESSARY?
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 A. Similar to the Millers Substation Rebuild in 2010, the Silver Peak Substation 17 Rebuild in 2011, and the Gabbs Substation Rebuild in 2012, the Mason Valley 18 Substation project was necessary to correct unsafe clearance issues pursuant to 19 National Electric Safety Code (“NESC”) Section 237.F Working Clearances from 20 Energized Equipment and NESC 441.A Clearance from Live Parts, and for the 21 other reasons described below. 22 23 Bridge Street Substation was built in the 1960s and provided service to customers 24 in the Yerington and Smith Valley area. The substation was constructed with 25 wooden box-style structures that had weathered and deteriorated over time, leaving 26 unsafe clearances for operations and repairs. Switch supports were cracked and 27
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1 warped, which caused air switches to be out of adjustment and, in some cases, 2 switches were completely inoperable. Existing records did not confirm the 3 adequacy of the ground grid and the substation likely had unsafe step and touch 4 potentials that could cause an electric shock to workers in the substation. Relocation 5 and consolidation to the new Mason Valley Substation was necessary to mitigate 6 the existing safety hazards, improve ability to operate and repair equipment, and 7 update the design and equipment to new modern design standards. 8
9 Anaconda Substation was constructed in the 1970s and was physically located on,
10 and surrounded by, the old Anaconda Mine, which was an open pit mining
11 operation from 1952 until 1982. Ground water contamination that had been
12 documented north of the mining site since the late 1970s, coupled with an 13 Environmental Protection Agency (“EPA”) superfund hazardous waste site 14 designation in 2009, made this entire area an ongoing safety concern. The D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 substation design and equipment was of 1970s vintage and needed to be brought up
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 to present standards. Relocation and consolidation to the Mason Valley Substation 17 moved the facilities away from the hazardous mining site and allowed upgrade to 18 new modern design standards. 19 20 19. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION?
21 A. No. The Company did not submit the project to the Commission for approval 22 because it did not entail the construction of a “Utility Facility” in accordance with 23 NRS § 704.860. 24 25 26 27
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1 20. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 2 A. The estimated total cost of the project was $18,228,953 (without AFUDC). The 3 total cost of the project through December 31, 2018, was $16,474,491 (with 4 AFUDC), and the estimated total cost through May 31, 2019, is $16,539,557 (with 5 AFUDC). The project was placed in service on June 21, 2018. Sierra started 6 removal and decommissioning of the Anaconda and Bridge Street substations in 7 2018 and this work is scheduled to be complete in mid-2019. All of the facilities 8 installed are in service and used and useful in the provision of utility service.
9
10 4. SOUTH MEADOWS 120/25 kV SUBSTATION (1W)
11 21. Q. PLEASE DESCRIBE THE PROJECT.
12 A. This project involved the construction of the new South Meadows 120/25 kV 13 Substation to provide load relief to the existing Mira Loma and Steamboat 14 substations in Washoe County. The substation project included land acquisition, D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 grading, a perimeter wall and gates, installation of a new 120/25 kV 60 MVA
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 transformer, 25 kV enclosed distribution switchgear, circuit breakers, switches and 17 associated bus work. A new control enclosure was installed to accommodate relay 18 protection, control, and telecommunication equipment. One new 25 kV distribution 19 underground feeder circuit was installed to tie into existing feeder circuits from the 20 Mira Loma and Steamboat substations. Replacement and upgrades to protection 21 equipment at the Mira Loma and Steamboat substations were also included as part 22 of this project. 23 24 22. Q. WHY WAS THE PROJECT NECESSARY? 25 A. This project was necessary to address capacity issues in the South Reno area. By 26 summer of 2019, the existing Mira Loma Substation transformer bank #3 was 27
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1 forecasted to exceed 105 percent of its normal nameplate rating, and existing 2 Steamboat Substation transformer bank #2 was forecasted to exceed 93 percent of 3 its normal nameplate rating. Installing this new substation in the South Meadows 4 area provided the needed additional capacity to reduce loading at the existing 5 substations and accommodate continued load growth in the south Reno area. 6 7 23. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 8 A. No. The Company did not submit the project to the Commission for approval
9 because it did not entail the construction of a “Utility Facility” in accordance with
10 NRS § 704.860.
11
12 24. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 13 A. The estimated total cost of the project was $12,713,942 (without AFUDC). The 14 total cost of the project through December 31, 2018, was $943,723 (with AFUDC), D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 and the estimated total cost through May 31, 2019, is $15,146,235 (with AFUDC).
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 The project is currently in construction and is planned to be in service before June 17 1, 2019. 18
19 5. ORMAT TUNGSTEN 2309 LINE POR SUBSTATION (RC) 20 25. Q. PLEASE DESCRIBE THE PROJECT. 21 A. This project involved interconnecting a new 38.5 MW net geothermal generating 22 station owned by ORNI 43 LLC, now known as the Tungsten Generating Facility, 23 to Sierra’s electric transmission system in Churchill County. The interconnection 24 required construction of the new Alpine 230 kV Switching Station on Sierra’s 25 existing 2309 line, approximately 42 miles west of Austin, Nevada. Components of 26 the project constituted a “Network Upgrade” in the parlance of the Federal Energy 27
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1 Regulatory Commission (“FERC”), while other components are defined as 2 Transmission Provider’s Interconnection Facilities or “TPIF”. The Network 3 Upgrades included grading, fencing, circuit breakers, switches and associated bus 4 work. A new control enclosure was installed to accommodate relay protection, 5 control, and telecommunication equipment. A 230 kV transmission line fold was 6 required to connect the switching station to Sierra’s existing 2309 line. The 7 Transmission Provider’s Interconnection Facilities, which are funded by the 8 interconnection customer but owned by Sierra, included 230 kV line
9 interconnection and switch structures, customer site telecommunications, metering,
10 and associated land rights and environmental permits. Sierra executed a standard
11 Large Generator Interconnection Agreement (“LGIA”) No. 14-00005 with ORNI
12 43 LLC on March 24, 2016. 13 14 26. Q. WHY WAS THE PROJECT NECESSARY? D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 A. The project was required pursuant to LGIA No. 14-00005 between Sierra and ORNI
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 43 LLC dated March 24, 2016. The current amended and restated revision is dated 17 June 29, 2017. 18 19 27. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 20 A. Yes. This project was previously presented to the Commission in Docket No. 16- 21 07001 (please see SPPC Triennial IRP, Volume 3 of 16, Testimony provided by 22 Sachin Verma). 23 24 28. Q. HOW DID SIERRA ARRIVE AT THE CUSTOMER AND COMPANY 25 COST RESPONSIBILITIES FOR THE ORMAT WILD ROSE PROJECT? 26 27
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1 A. The cost responsibilities for interconnecting the Ormat Tungsten project were 2 assigned in compliance with the requirements for interconnecting large generators 3 to the Company’s transmission system as established by FERC and provided for in 4 Attachment N of the Company’s Open Access Transmission Tariff (“OATT”). The 5 allocation of costs for facilities associated with the interconnection is provided in 6 Appendix A of the LGIA. 7 8 29. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
9 A. The estimated cost of the project was $9,770,000 (without AFUDC). This is
10 comprised of $9,150,000 for Network Upgrades and $620,000 for TPIFs. The total
11 cost of the project through December 31, 2018, and estimated total cost through
12 May 31, 2019 is $8,992,545 (with AFUDC). ORNI 43 LLC provided $491,000 in 13 Contributions In Aid of Construction (“CIAC”) to cover costs associated with the 14 TPIFs and $75,000 in CIAC for installation of a temporary T-1 communication D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 line. Sierra removed the temporary T-1 communication line on April 3, 2019, and
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 will complete the audit and true-up in accordance with the LGIA. The project was 17 placed in service on September 15, 2017. All of the facilities installed are in service 18 and used and useful in the provision of utility service. 19 20 30. Q. WHAT IS THE TOTAL INVESTMENT SIERRA IS SEEKING TO 21 RECOVER IN THIS GENERAL RATE CASE? 22 A. Sierra is seeking to recover the $8,992,545 investment (with AFUDC) in Network 23 Upgrades associated with the project. 24 25 26 27
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1 6. LAHONTAN – LOVELOCK 617 LINE REBUILD (6B) 2 31. Q. PLEASE DESCRIBE THE PROJECT. 3 A. This project involved phased and sectional rebuilding of approximately 65 percent 4 of the existing 63-mile 617 line (60 kV) from Lahontan Substation to Lovelock 5 Substation. Phase one of the project included the installation of new poles and 795 6 All Aluminum (“AA”) conductor built along approximately 29 miles, or 7 approximately 46 percent, of the existing line from Lahonton Substation to Parran. 8 The rebuild was constructed to 120 kV standard specifications for reliability and
9 avian protection, and incorporated overhead shield wire, new line switches, switch
10 motor operators, and associated telecommunications equipment. Environmental
11 permitting through the Bureau of Land Management was also included as part of
12 this project. 13 14 The second phase of this project will involve construction of an additional 13 miles D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 of rebuild, or approximately 21 percent of line from Lovelock Substation to Toulon.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Cost incurred to complete phase two of the project will be included in a future 17 general rate case filing. 18 19 The Company does not plan to rebuild the remaining approximate 21 miles, or 33 20 percent of the line from Parran to Toulon, because of the limited number of 21 customers served off these facilities and ability to switch and sectionalize this 22 portion of the line. 23 24 32. Q. WHY WAS THE PROJECT NECESSARY? 25 A. The 617 line from Lahontan Substation to Lovelock Substation was constructed 26 over one hundred years ago in 1914 and provides service to two important 27
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1 commercial customers: Kennametal Inc. and a communications site for the Fallon 2 Naval Air Station. The age and condition of the line results in frequent and extended 3 service interruptions (63 service interruptions within the past five years) and is 4 ranked the sixth worst performing circuit in Sierra’s system. The line has significant 5 deterioration issues, does not have shield wire, is under-insulated, lacks proper 6 grounding and bonding, the old poles are not safe to climb to perform maintenance, 7 and bird electrocutions have been recorded. Replacing and repairing the poles under 8 emergency conditions has not adequately mitigated the number and duration of
9 service interruptions. A phased and sectional rebuild of the 617 transmission line
10 with a new modern line design will improve reliability and customer satisfaction
11 by reducing service interruptions and outage durations.
12 13 33. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 14 A. No. The Company did not submit the project to the Commission for approval D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 because it did not entail the construction of a “Utility Facility” in accordance with
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 NRS § 704.860. 17 18 34. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 19 A. The estimated total cost of the project for phases 1 and 2 was $15,501,450 (without 20 AFUDC). The total cost of the project through December 31, 2018, for facilities 21 installed and placed in service was $0, and the estimated total cost through May 31, 22 2019, is $8,476,769 (with AFUDC). Phase 1 of the project (the rebuild from 23 Lahonton Substation to Parran) with the exception of completing 24 telecommunications to multiple motor-operated switches is planned to be in service 25 before June 1, 2019. Phase 2 of the project, the rebuild of approximately 21 percent 26 of line from Lovelock Substation to Toulon, is planned to be constructed in late 27
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1 2019 and early 2020. The costs associated with the phase 1 telecommunications 2 and phase 2 are not included in the revenue requirement in this general rate review. 3 Phase 1 will be placed in service before June 1, 2019, and will be used and useful 4 in the provision of utility service. 5
6 7. ROUND HILL 120/14 kV SUBSTATION FAILURE (A7B) 7 35. Q. PLEASE DESCRIBE THE PROJECT. 8 A. This project involved the removal and replacement of the failed 120/14.4 kV 25
9 MVA transformer, 2 MVA voltage regulator, 14.4 kV distribution circuit breakers,
10 station batteries and associated communication, protection and control equipment.
11 The project also included an evaluation of the substation grounding design, which
12 resulted in enhancements to the ground grid and replacement and installation of a 13 non-conductive perimeter fence. 14 D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 36. Q. WHY WAS THE PROJECT NECESSARY?
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 A. On August 28, 2017, a catastrophic failure of the 2301 feeder breaker resulted in 17 damage to the 120/14.4 kV 25 MVA transformer, the 2 MVA voltage regulator, the 18 feeder breaker and surrounding structure, as well as control cable and protection 19 system equipment within the control enclosure. 20 21 Round Hill Substation is sourced from the 120 kV transmission system and contains 22 a single 120/14.4 kV transformer. This project was necessary to restore Round Hill 23 Substation and provide needed service to the South Lake Tahoe area. 24 25 37. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 26 A. No. The Company did not submit the project to the Commission for approval 27
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1 because it did not entail the construction of a “Utility Facility” in accordance with 2 NRS § 704.860. 3 4 38. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 5 A. The estimated total cost of the project was $6,621,020 (without AFUDC). The total 6 cost of the project through December 31, 2018, for facilities installed and placed in 7 service was $1,618,704 (with AFUDC), and the estimated total cost through May 8 31, 2019, is $4,414,410 (with AFUDC). The estimated total cost through May 31,
9 2019, is $2,206,610 lower than the estimated total cost because the estimated total
10 cost of the replacement transformer and regulator was included twice in two
11 estimates, one estimate for the emergency restoration for the 2017 winter season,
12 and a second estimate to complete the rebuild in accordance with standards and the 13 final design drawings. The expected in-service date for all remaining facilities is 14 May 17, 2019. All of the facilities installed and placed in service before June 1, D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 2019, will be used and useful in the provision of utility service.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16
17 8. FOOTHILL – KINGSBURY 634 LINE REBUILD (FZ) 18 39. Q. PLEASE DESCRIBE THE PROJECT. 19 A. This project involved rebuilding approximately three miles of the existing 634 line 20 (60 kV) between Foothill Road and the Kingsbury Tap in Douglas County. Phase 21 1 of the project included the installation of new metal fire-resistant line structures 22 and 397.5 thousand circular mil (“kcmil”) Aluminum Conductor Steel Reinforced 23 conductor. The rebuild was constructed to 120 kV standard specifications for 24 reliability and avian protection, and incorporated overhead shield wire. 25 Environmental permitting through the United States Forest Service and various 26 lands rights were also included as part of this project. 27
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1 2 The second phase of this project will include resolution of a land right issue with a 3 private land owner and installation of new line switches, motor operators, and 4 associated telecommunications equipment. Construction access to the new line 5 switches and motor operators work location requires equipment to cross the private 6 land owner’s property that required resolution of a land right issue. Phase 2 will not 7 be completed prior to May 31, 2019, and so the costs of Phase 2 will be addressed 8 in a future general rate review proceeding.
9
10 40. Q. WHY WAS THE PROJECT NECESSARY?
11 A. The 634 line is a second feed from Buckeye Substation in Minden to Stateline
12 Substation in South Lake Tahoe. It also provides service to customers in and around 13 the Heavenly Ski Resort by way of a radial line tap for Kingsbury Substation. The 14 line was constructed in 1956 in a dense forest area with steep and difficult to access D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 terrain. The location limits the ability to perform maintenance and restoration
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 activities and the line has a record of frequent and extended outage durations, 17 especially during severe winter weather events. Inspections have recorded 18 deteriorated poles, signs of insulator tracking, and loose and unattached hardware 19 due to the age and condition of the line. Rebuilding this three mile section of the 20 line with a new modern line design will improve reliability and customer 21 satisfaction by reducing service interruptions and outage durations. 22 23 41. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 24 A. No. The Company did not submit the project to the Commission for approval 25 because it did not entail the construction of a “Utility Facility” in accordance with 26 NRS § 704.860. 27
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1 42. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 2 A. The estimated total cost of the project was $5,535,397 (without AFUDC) and the 3 total cost of the project through December 31, 2018, was $4,064,998 (with 4 AFUDC), and the estimated total cost through May 31, 2019, is $4,081,876 (with 5 AFUDC). Phase 1 of the project to permit and rebuild the line was placed in service 6 November 15, 2016. Phase 2 of the project, to resolve a land right issue with a 7 private land owner and install new line switches, motor operators, and associated 8 telecommunications equipment is planned to be completed in mid-2019 and Phase
9 2 costs are not included in the revenue requirement in this filing. All of the facilities
10 installed and placed in service before June 1, 2019, are used and useful in the
11 provision of utility service.
12
13 9. NORTH RED ROCK 120/25 kV SUBSTATION (AC8) 14 43. Q. PLEASE DESCRIBE THE PROJECT. D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 A. This project included installation of a new 120/25 kV 48 MVA transformer and
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 minimal and temporary substation equipment, bus work, and switches at the North 17 Red Rock site to reduce overloads, provide additional capacity, and increase 18 reliability to the rapidly growing North Valley area in Washoe County. A temporary 19 control enclosure was installed to accommodate relay protection, control, and 20 telecommunication equipment. Underground cable, duct bank, vaults, and other 21 electrical equipment for two new 25 kV distribution feeder circuits were also 22 included as part of this project. 23 24 Land rights for the North Red Rock Substation had been previously acquired, the 25 site was graded and enclosed with a perimeter wall, and distribution design and 26 construction services to install a portion of the below grade facilities for two 27
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1 underground distribution lines were previously completed as part of the Red Rock 2 Substation project (Link 6G) before the Company responded to the economic 3 downturn, suspended all work, and placed the project on hold on July 15, 2009. 4 5 In 2018, growth in the area increased dramatically, requiring minimal and 6 temporary substation facilities to quickly be installed at the existing site to provide 7 load relief. The Company is permitting an expanded site on which permanent 8 facilities will be constructed with a planning in service date in June 2022.
9
10 44. Q. WHY WAS THE PROJECT NECESSARY?
11 A. This project was necessary to reduce overloads, provide additional capacity, and
12 increase reliability to the rapidly growing North Valley area. Both the Stead and 13 Silver Lake substations are nearing capacity and will not be able to support the load 14 growth for the area. Silver Lake Bank 2 was loaded to 37.8 MVA or 81 percent of D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 its 46.7 MVA rating in 2017, and in 2019 it is forecast to overload beyond 100
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 percent of its nameplate rating. The Silver Lake 255 feeder was loaded to 557 amps 17 or 101 percent of its 550 amp rating in 2016. Stead Bank 1 was loaded to 12.3 MVA 18 or 92 percent of its 13.3 MVA nameplate rating in 2017. Construction of this project 19 will also provide additional capacity and increase reliability for all customers in the 20 North Valley area including manufacturing and logistics companies and a large 21 residential population. 22 23 45. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 24 A. Yes. This project was previously presented to the Commission in Docket No. 16- 25 06006 (please see SPPC Electric GRC, Volume 5 of 21, Testimony provided by 26 27
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1 John S. Berdrow, Section IV, Suspended and Cancelled Projects, Red Rock 2 Distribution Substation (6G)). 3 4 46. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 5 A. The estimated total cost of the project was $4,980,773 (without AFUDC). The total 6 cost of the project through December 31, 2018, for facilities installed and placed in 7 service was $0, and the estimated total cost through May 31, 2019, is $3,048,098 8 (with AFUDC). The two new 25 kV distribution feeder circuits included as part of
9 this project are planned to be placed in service before June 1, 2019, and are included
10 in the revenue requirement in this General Rate Case. The substation transformer
11 and associated equipment and ties to the 25 kV distribution feeders are planned to
12 be placed in service in June 2019 and are not included in the revenue requirement 13 in this General Rate Case. All of the facilities installed and placed in service before 14 June 1, 2019, will be used and useful in the provision of utility service. D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 10. UPDATE TO 230 KV THREE POLE STRUCTURE REPLACEMENTS (XN) 17 47. Q. PLEASE DESCRIBE THE PROJECT. 18 A. This project involves the programmatic replacement of approximately 110 wooden 19 three-pole dead end and line angle structures on Sierra’s 230 kV lines between the 20 Fort Churchill Substation in and the Nevada/Utah state line. Damaged or 21 deteriorated poles were replaced with new light duty direct buried steel poles to 22 improve reliability and harden this critical 302 mile line that is part of Sierra’s bulk 23 electric system. The project started in 2014 with line patrols and inspections, 24 survey, and design activities, and the first eleven structures were replaced in 2015. 25 Twenty-seven additional structures were replaced in 2017, 2018, and 2019. The 26 lines are located in Lyon, Churchill, Lander, Eureka, and White Pine counties. 27
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1 2 48. Q. WHY WAS THE PROJECT NECESSARY? 3 A. These 230 kV lines were constructed using wooden pole structures between 1970 4 and 1975 and the total line length is just over 302 miles. After more than 44 years 5 of service life, many of the wood pole structures on Sierra’s 230 kV lines need 6 replacement due to environmental deterioration (e.g., rot, drying, splitting, etc.), 7 historic fire damage, and damage caused by birds (wood peckers). Sierra prioritized 8 replacement of the three-pole dead end and line angle structures because they tend
9 to support heavy loads for long canyon spans and over ridge crossings. These
10 structures have had increased vulnerability to pole fires caused by loose bonding
11 and grounding hardware and a structure configuration that may place metallic
12 hardware near electrical jumpers. Sierra is currently experiencing one to two pole 13 fires per year on the 230 kV lines, and the resultant outages take days to repair and 14 are typically repaired with new wood poles. Proactively replacing damaged and D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 high-risk poles with steel poles that are not susceptible to rot, splitting, fire, and
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 birds will improve the availability and reliability of the 230 kV lines. The lines have 17 become increasingly important to Sierra’s bulk electric system as more renewable 18 energy generation interconnects to the system. 19 20 49. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 21 A. Yes. The first phases of the project were placed in service prior to May 31, 2016. 22 Consistent with the rules governing general rate applications, this investment was 23 included in Sierra’s 2016 General Rate Case (Docket No. 16-06006). The 24 Commission approved the inclusion of the revenue requirement at that time and 25 Sierra is not seeking to include this investment, or any investment incurred before 26 May 31, 2016, in rate base through this application. 27
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1 50. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 2 A. The estimated total cost of the project was $2,391,025 (without AFUDC). The total 3 cost of the project through December 31, 2018, was $1,943,338 (without AFUDC), 4 and the estimated total cost through May 31, 2019, is $2,707,942 (without 5 AFUDC). Eleven structures were replaced on the 2311 line between Osceola and 6 Gonder and placed in service on June 3, 2018. Five structures were replaced on the 7 2302 line between Machacek and Gonder and placed in service on October 24, 8 2018. Three structures were replaced on the 2306 line between Frontier and
9 Machacek and placed in service on November 20, 2018, and a fourth structure was
10 replaced and placed in service on April 4, 2019. Sierra transmission line
11 construction crews are currently replacing seven structures on the 2301 line
12 between the Utah/Nevada border and Osceola. The project is planned to be in 13 service before June 1, 2019. All of the facilities installed and placed in service 14 before June 1, 2019, will be used and useful in the provision of utility service. D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 11. MIRA LOMA – STEAMBOAT 127 LINE RELOCATION (A0X) 17 51. Q. PLEASE DESCRIBE THE PROJECT. 18 A. This project involved the relocation of transmission facilities to accommodate new 19 development in the southeast Reno area in Washoe County. Portions of the existing 20 127 Mira Loma to Steamboat 120 kV transmission line were removed, relocated, 21 and installed as new overhead or underground facilities. The relocation areas and 22 type of design were determined based on the applicant’s preference for their 23 proposed developments, the proposed 127 Line Rebuild project, and to provide 24 Sierra with a land parcel to facilitate development of the South Meadows 120/25 25 kV Substation (see Link 1W above). The acquisition of associated land rights were 26 also included as part of this project. 27
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1 52. Q. WHY WAS THE PROJECT NECESSARY? 2 A. This project was required pursuant to Rule 9 Facilities Relocation Agreement 16- 3 00082 and Substructure Installation Agreement 17-00013 between Sierra and Di 4 Loreto-Caramella Ranch, LLC, and Facilities Relocation Agreement #17-00014 5 and Substructure Installation Agreement 17-00015 between Sierra and Rilite, Inc. 6 7 53. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 8 A. No. The Company did not submit the project to the Commission for approval
9 because it did not entail the construction of a “Utility Facility” in accordance with
10 NRS § 704.860.
11
12 54. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 13 A. Sierra’s estimated cost for this project was $1,688,000 (includes CIAC and without 14 AFUDC). The total cost of the project through December 31, 2018, was $2,047,916 D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 (with AFUDC), and the estimated total cost through May 31, 2019, is $2,278,578
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 (with AFUDC). Di Loreto-Caramella Ranch, LLC, and Rilite, Inc. provided 17 payments totaling $3,233,420 to Sierra (includes Tax Gross-up and does not 18 include Project Cost Estimate for the Applicant Installed Duct Bank) to cover 19 applicant costs associated with the facilities relocation and substructure installation 20 agreements. Sierra’s net investment after CIAC for a number of betterments 21 completed as part of the line relocation project is $2,278,578. The project was 22 placed in service on June 6, 2018. All of the installed facilities are in service and 23 used and useful in the provision of utility service. 24 25 26 27
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1 55. Q. WHAT IS THE TOTAL INVESTMENT SIERRA IS SEEKING TO 2 RECOVER IN THIS GENERAL RATE CASE? 3 A. Sierra is seeking to recover the $2,278,578 in utility investment associated with the 4 project. 5
6 12. STEAMBOAT 215 FEEDER ADDITION (9R) 7 56. Q. PLEASE DESCRIBE THE PROJECT. 8 A. This project included installation of a new 25 kV distribution feeder circuit from
9 Steamboat Substation to the existing Mira Loma 291 circuit. The new feeder was
10 needed to provide load relief to the Mira Loma 291 circuit and transformer bank in
11 Washoe County. The project also required a new 25 kV circuit breaker, bus work,
12 switches, protection and communication equipment at Steamboat Substation. 13 14 57. Q. WHY WAS THE PROJECT NECESSARY? D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 A. The project was necessary to relieve the existing Mira Loma 291 feeder and provide
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 additional capacity to accommodate emerging commercial and residential growth 17 in the Mira Loma Substation area in southeast Reno. It addressed a capacity issue 18 with the then-existing Mira Loma distribution bank that was forecast to exceed 95 19 percent of its normal operating rating. Steamboat Substation was the closest source 20 with available capacity and had space available for the additional feeder position. 21 22 58. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 23 A. No. The Company did not submit the project to the Commission for approval 24 because it did not entail the construction of a “Utility Facility” in accordance with 25 NRS § 704.860. 26 27
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1 59. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 2 A. The estimated total cost of the project was $1,212,862 (without AFUDC). The total 3 cost of the project through December 31, 2018, was $1,697,269 (with AFUDC), 4 and the estimated total cost through May 31, 2019, is $1,695,193 (with AFUDC). 5 The estimated total cost decreased between December 31, 2018, and May 31, 2019, 6 due to a credit for stock material returned to the Company’s warehouse. The project 7 was placed in service January 20, 2017. All of the facilities installed are in service 8 and used and useful in the provision of utility service.
9
10 13. UPDATE TO 345 kV PLC REPLACEMENT PROGRAM (AL)
11 60. Q. PLEASE DESCRIBE THE PROJECT.
12 A. This project involved the phased removal and replacement of existing substation 13 programmable logic controllers (“PLCs”) on Sierra’s 345/120 kV transmission 14 system. The PLCs provide control, automation, and vital protection functions for D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 each substation. Sierra’s plan involves the removal and replacement of existing
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 PLCs with Sierra’s standard protective relay and lockout package in a multi-phase 17 and as a multi-year program. The program includes the four phases described 18 below. 19 20 Phase 1: 345 kV PLC replacements at the East Tracy and North Valley Road 21 substations. This project was placed in service on July 31, 2015, and a small amount 22 of post-construction close out costs are included for recovery in this rate case. 23 24 Phase 2: 345 kV PLC replacement at the Bordertown, Fort Sage, and North Valley 25 Road substations. This project was placed in service on June 14, 2016, and the 26 investment is the majority of costs included for recovery in this rate case. 27
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1 Phase 3: 345 kV PLC replacement at North Valley Road Substation. This project 2 is planned to be in service by December 31, 2019, and is not included for recovery 3 in this rate case. 4 5 Phase 4: 345 kV PLC replacement at Falcon Substation. This project is also 6 planned to be in service by December 31, 2019, and is not included for recovery in 7 this rate case. 8
9 61. Q. WHY WAS THE PROJECT NECESSARY?
10 A. The primary reasons Sierra replaced these relays are (1) compliance with rapidly
11 escalating testing and maintenance requirements from the agencies responsible for
12 the oversight of the western transmission grid, (2) reliability of Bulk Electric 13 System (“BES”) assets and major transfer paths, (3) to avoid possible long-term 14 outages for failures and repairs, and (4) additional benefits and functionality to D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 improve system operations and operate a modern high-performance transmission
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 grid. 17 18 62. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 19 A. Yes. The project was originally presented to the Commission in Docket No. 16- 20 06006. The Commission approved the inclusion of the costs for Phase I in the 21 revenue requirement at that time. 22 23 63. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 24 A. The estimated total cost for the second phase of the project was $2,645,681 (without 25 AFUDC). The total cost of the project through December 31, 2018, and estimated 26 total cost through May 31, 2019, is $1,474,037 (with AFUDC). The second phase 27
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1 of the project was placed in service on June 14, 2016, and is included for recovery 2 in this rate case. The investment for the future phases described above are not 3 complete and will be included for recovery in a future general rate cases after they 4 are placed in service. All of the facilities installed before June 1, 2019, are in service 5 and used and useful in the provision of utility service. 6
7 14. HUMBOLDT – MIDPOINT 345 kV WAVE TRAP UPGRADE (3Y) 8 64. Q. PLEASE DESCRIBE THE PROJECT.
9 A. This project is in accordance with an Addendum to Interconnection and
10 Transmission Services Agreement entered into by and between Idaho Power
11 Company and Sierra on March 7, 2017, to construct, own, operate and maintain
12 portions of the Midpoint-Hunt-Valmy Interconnection Line (Bulk Electric System 13 Path 16). Idaho Power and Sierra agreed to replace and upgrade the existing single 14 phase power line carrier system (rated at 800 amps) and install a power line carrier D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 system for two phases with wave traps rated for 2,000 amps. The current rating for
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 the line conductor is 1,076 MVA or 1,800 amps. The power line carrier system for 17 two phases provided primary and back up communications and met all technical 18 requirements for redundancy. Separate wave traps and electronic systems were 19 required. In relation to replacing and upgrading the power line carrier system, the 20 parties agreed to replace and upgrade existing system protection relays and other 21 appurtenant equipment. Pursuant to the agreement, Idaho Power will construct, 22 own, operate and maintain all facilities necessary for operating the 345 kV terminal 23 at its Midpoint Substation, and NV Energy will construct, own, operate and 24 maintain all facilities necessary for operating the 345 kV terminal at its Humboldt 25 Substation. 26 27
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1 65. Q. WHY WAS THE PROJECT NECESSARY? 2 A. Replacement and upgrade of the power line carrier system mitigated possible 3 overloads of the existing wave traps and risks for future North American Electric 4 Reliability Corporation TPL reliability criteria violations for times of stressed path 5 flow. It also removed the existing thermal rating constraint for wave traps rated 6 lower than the existing conductor. Installing the power line carrier system on two 7 phases of the line provided a redundant protection communication system and is 8 considered a best practice for protection of Extra High Voltage transmission lines
9 to avoid potential delayed clearing faults. Replacement and upgrade of the existing
10 system protection relays and other appurtenant equipment was required in
11 conjunction with replacement and upgrade of the power line carrier system. The
12 design was in accordance with the parties’ current standards for system protection 13 and control, provides information to aid in operational analysis, improves 14 efficiency and effectiveness as it pertains to troubleshooting, maintenance, testing, D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 and requirements for spare equipment, provides added functionality, and upgraded
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 systems to facilitate operation of a modern high-performance transmission grid. 17 18 66. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 19 A. No. Sierra did not submit this project to the Commission for approval in an IRP or 20 UEPA permit because the upgrades occurred within the confines of an existing 21 substation and involved like kind replacement of old equipment and controls with 22 new equipment and controls. 23 24 67. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 25 A. The estimated total project cost was $1,304,362 (without AFUDC). The total cost 26 of the project through December 31, 2018, and estimated cost through May 31, 27
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1 2019 is $1,278,420 (with AFUDC). The project was placed in service on April 30, 2 2018. All of the facilities installed are in service and used and useful in the provision 3 of utility service. 4
5 15. 345 kV CAPACITOR BANK BREAKER REPLACEMENT (ZC) 6 68. Q. PLEASE DESCRIBE THE PROJECT. 7 A. This project involved the replacement of existing 345 kV capacitor bank circuit 8 breakers at North Valley Road and Mira Loma substations in Washoe County. New
9 345 kV rated circuit breakers with pre-insertion resistors, lightning arrestors and
10 instrument rated metering equipment were installed as part of this project.
11
12 69. Q. WHY WAS THE PROJECT NECESSARY? 13 A. On July 25, 2014, a flashover occurred at Bordertown Substation that caused the 14 phase angle regulating transformer to trip off line. Investigation and analysis of the D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 incident revealed the transient voltage associated with 345 kV capacitor switching
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 events approximately 14 miles away at North Valley Road Substation exceeded the 17 capability of the nearby Bordertown transformer. Recommendations from the third 18 party electromagnetic transient simulation program study, performed by a 19 specialized technical consulting firm, confirmed the issue could be resolved by 20 replacing each capacitor’s existing circuit breaker with a circuit breaker equipped 21 with pre-insertion resistors. The study also supported the recommendation to 22 replace the existing 288 kV lightning arrestors at Bordertown Substation with 23 arresters with smaller corona rings to increase clearances. Replacing the circuit 24 breakers and associated equipment allowed the very beneficial 75 MVAR capacitor 25 banks at North Valley Road and Mira Loma substations to return to normal 26 operation. 27
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1 70. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 2 A. No. Link ZC the 345 kV Capacitor Bank Breaker Replacement project has not been 3 presented to the Commission. A previous project that involved installation of the 4 345 kV capacitor banks rated at 75 MVAR and associated circuit breakers, 5 switches, bus work, protection system modifications, and telecommunications 6 upgrades at both North Valley Road Substation and Mira Loma Substation was 7 presented to the Commission as Link 4C Mira Loma and North Valley Road 345 8 kV Capacitor Banks in the revenue requirement in Docket No. 16-06006. The
9 Commission approved the inclusion of the costs in the revenue requirement at that
10 time.
11
12 The project described in Link 4C was also presented to the Commission in Sierra’s
13 2007 Triennial IRP covering the period of 2008-2027,1 and Sierra’s 2010 Triennial 14 IRP covering the period of 2011-2030.2 A report on the project progress was D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 presented to the Commission in Sierra’s Report on Progress of Action Plan relative
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 to its 2014-2033 IRP in Docket No. 15-04001. 17
18 71. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 19 A. The estimated total cost of the project was $978,121 (without AFUDC). The total 20 cost of the project through December 31, 2018, and estimated cost through May 31, 21 2019 is $1,269,087 (with AFUDC). The project was placed in service on June 9, 22 2017. All of the facilities installed are in service and used and useful in the provision 23 of utility service.
24 1 Docket No. 07-06049; Supply Side Plan; Volume 6 of 19; page 121-124. The Commission approved the “345 25 kV Voltage Support Project,” which included the installation of 345 kV shunt capacity banks rated at 75 MVAR at the North Valley Road and Mira Loma substations. See Order at ¶ 184, Docket No. 07-06049 (is. Dec. 24, 2007). 26 2 Docket No. 10-07003; Summary – Supply Side, Economic, and Financial Plans, Volume 10 of 22, page 44-78, 27 and Transmission Technical Appendix; Volume 13 of 22; TRAN-4; page 67-78. 28 Berdrow-DIRECT 34
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1 16. BRUNSWICK TO BUCKEYE 635 LINE RELOCATION (A0H) 2 72. Q. PLEASE DESCRIBE THE PROJECT. 3 A. This project involved the relocation of approximately 0.7 miles of the existing 635 4 60 kV line between the Brunswick and Buckeye substations in Douglas County. 5 The project also included relocation and upgrade of the existing Buckeye 1278 12.5 6 kV circuit including approximately 0.7 mile of overhead 795 AA conductor, 0.1 7 mile of 1,000 thousand circular mils underground cable, associated duct bank and 8 vaults, and land rights and permits for the relocated facilities.
9
10 73. Q. WHY WAS THE PROJECT NECESSARY?
11 A. The project was required pursuant to Douglas County Ninth Judicial Court
12 Stipulation, Case Number 22100 between plaintiff Eastside Memorial Park, Inc. 13 (Eastside) and defendant Sierra dated October 9, 1989. In the stipulation, Eastside 14 agreed Sierra shall have full use for thirty years of its present easement including D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 the option of upgrading, re-construction, modifying, or other necessary activities,
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 and conveyance of a ten foot strip adjacent to the existing easement for use as road 17 access. Sierra agreed it would abandon the existing easement and the additional ten 18 foot road access and relocate at its sole expense and outside Eastside’s property its 19 transmission line thirty years from the date the temporary restraining order issued 20 in this case was lifted by the court, and the existing easement and additional road 21 access would terminate and revert to Eastside at the end of the thirty-year term. 22 23 74. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 24 A. No. The Company did not submit the project to the Commission for approval 25 because it did not entail the construction of a “Utility Facility” in accordance with 26 NRS § 704.860. 27
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1 75. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 2 A. The estimated total cost of the project was $784,480 (without AFUDC). The total 3 cost of the project through December 31, 2018, for facilities installed and placed in 4 service was $41,457 (with AFUDC), and the estimated total cost through May 31, 5 2019, is $1,017,773 (with AFUDC). The 60 kV line relocation was placed in service 6 December 31, 2018, and the 25 kV line relocation was placed in service February 7 1, 2019. All of the facilities installed are in service and used and useful in the 8 provision of utility service.
9
10 III. TRACY AREA MASTER PLAN
11 76. Q. PLEASE DESCRIBE THE PROJECTS THAT FALL WITHIN THE TRACY
12 AREA MASTER PLAN. 13 A. The most quickly emerging load pocket in northern Nevada is the Tracy Area, 14 located approximately 20 miles east of Reno and includes both the Reno D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 Technology Park (“RTP”) and the Tahoe Reno Industrial Center (“Tri-Center”).
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 The RTP is home to the fast-growing Apple Data Center and the Turquoise Solar 17 Generation Project. Tri-Center, with a footprint of over 107,000 acres, is the largest 18 regional commercial and industrial center in northern Nevada and is home to both 19 existing and developing customers. Prior to the development of the Tracy Master 20 Plan, most of the load in the area was served from a single distribution substation 21 with limited capacity, radial service feeders, and minimal ability to respond to 22 operational contingencies. As part of the transmission planning process, the 23 Company developed a master plan that will allow the system to accommodate the 24 emerging growth in the Tracy Area while continuing to provide reliable electric 25 service and future system adaptability. 26 27
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1 The initial phases of the Tracy Area Master Plan were to construct a 120 kV loop 2 that wraps around the load pocket to enable service for up to 500 MW of near-term 3 customer load requests. New substation facilities within the loop will provide 4 strategic hubs for transmission interconnection, distribution transformer sourcing 5 for proposed loads, as well as reactive support for the electric system. As load in 6 this area continues to grow, the Tracy Area Master Plan is designed to be 7 expandable to accommodate 345 kV sourcing as well. This will further increase the 8 system’s capability to serve future loads. Cost responsibility for customer specific
9 projects within the Tracy Area Master Plan are allocated pursuant to Exhibit
10 Berdrow-Direct-3. The following projects are included in this section:
11 • Chukar 120/25 kV Substation (P9)
12 • Dove to Wild Horse 120 kV line (A8) 13 • Tesla Phase II (S5) 14 • Update to Apple Data Center – Tracy Area (A5) D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 77. Q. HAS THE TRACY AREA MASTER PLAN BEEN PRESENTED TO THE 17 COMMISSION THROUGH A RECENT INTEGRATED RESOURCE 18 PLAN FILING? 19 A. Yes. The Tracy Area Master Plan was presented to the Commission in Docket No. 20 17-11003 (please see SPPC IRP 2nd Amendment, Volume 1 of 4, Section 8 21 Transmission, B2 Tracy Area Master Plan and in the Prepared Direct Testimony of 22 Sachin Verma, Q&A 13). The study and analysis was presented in Confidential 23 Technical Appendix TRAN 2: Tracy Area Master Plan. The appendix was deemed 24 confidential due to customer specific information and it contained non-public 25 transmission information subject to FERC Standards of Conduct. Accordingly, 26 confidential information is removed or redacted in the exhibit. 27
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1 1. CHUKAR 120/25 KV SUBSTATION (P9) 2 78. Q. PLEASE DESCRIBE THE PROJECT. 3 A. This project involved the construction of the new Chukar 120/25 kV Substation to 4 provide distribution load service and increased reliability to the Tri-Center area in 5 Storey County. The substation project included land acquisition, grading, a 6 perimeter fence and gates, installation of a new 120/25 kV 60 MVA transformer, 7 circuit breakers, switches and associated bus work. A new control enclosure was 8 installed to accommodate relay protection, control, and telecommunication
9 equipment. The project also included the reconfiguration of an existing 120 kV
10 overhead line and a one-mile overhead 25 kV distribution feeder circuit to tie to
11 existing feeders and accommodate new loads in the Tracy Area.
12 13 79. Q. WHY WAS THE PROJECT NECESSARY? 14 A. Most of the load in the Tri-Center area was previously served from Patrick D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 Substation through a single overhead 25 kV distribution feeder circuit (Patrick 225
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 circuit) that was not looped to any other circuit or source. Due to the radial 17 configuration of the Patrick feeder, alternative service options for contingencies 18 were extremely limited and loss of the feeder or Patrick Substation resulted in 19 significant outages to many customers in the Tri-Center area. The project provides 20 a much needed redundant substation source and distribution feeder looping 21 capability. The transformer installation provides service options for new and 22 emerging customers and enhances overall system reliability to the entire Tri-Center 23 area. 24 25 80. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 26 A. No. The Company did not submit the project to the Commission for approval 27
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1 because it did not entail the construction of a “Utility Facility” in accordance with 2 NRS § 704.860. Although not requested for approval, the project and design 3 approach was described in detail in the Tracy Area Master Plan presented to the 4 Commission. 5 6 81. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 7 A. The estimated total cost of the project was $11,376,476 (without AFUDC). The 8 total cost of the project through December 31, 2018, was $11,124,644 (with
9 AFUDC), and the estimated total cost through May 31, 2019, is $12,589,283 (with
10 AFUDC). The project was placed in service on May 9, 2018. All of the installed
11 facilities are in service and used and useful in the provision of utility service.
12
13 2. DOVE TO WILD HORSE 120 KV LINE(A8) 14 82. Q. PLEASE DESCRIBE THE PROJECT. D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 A. This project involved the construction of an approximate five-mile 120 kV line
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 from the existing Dove Substation to an Applicant-owned substation located near 17 Sierra’s proposed Wild Horse Substation, telecommunications, metering 18 equipment, and associated lands rights. The Dove to Wild Horse 120 kV line is a 19 planned segment of the 120 kV transmission loop described in the Tracy Area 20 Master Plan. Wild Horse substation is currently planned to serve as an 21 interconnection hub for three major transmission connected loads as well as act as 22 an isolation point along the planned 120 kV transmission loop. A new 120 kV 23 terminal addition at Dove Substation was also included as part of this project. 24 25 83. Q. WHY WAS THE PROJECT NECESSARY? 26 A. This project was required in accordance with Amended and Restated Rule 9, 27
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1 Section B.2 HVD Agreement No. 16-00042 between Sierra and Switch, Ltd., for 2 an Applicant requested 153.5 MVA of service. A copy of the agreement is provided 3 as Exhibit Berdrow-Direct-4. 4 5 84. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 6 A. No. The Company did not submit the project to the Commission for approval 7 because it did not entail the construction of a “Utility Facility” in accordance with 8 NRS § 704.860. Although not requested for approval, the project and design
9 approach was described in detail in the Tracy Area Master Plan presented to the
10 Commission.
11
12 85. Q. WHAT WAS THE TOTAL COST OF THE PROJECT AND WHEN WAS 13 THE PROJECT PLACED IN SERVICE? 14 A. The estimated total cost of the Utility-Owned Facilities based on Facility D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 Designation and Rule 9 in the HVD Agreement for the project was $7,329,500
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 (without AFUDC). The Applicant’s Rule 9 allocated cost and tax gross-up was 17 $587,204. Pursuant to the HVD agreement, the estimated net investment for the 18 Company was $6,824,400. The total net investment through December 31, 2018 19 was $6,565,128 (with AFUDC), and the estimated total cost through May 31, 2019, 20 is $6,799,211 (with AFUDC). The project was placed in service on November 7, 21 2018. All of the installed facilities are in service and used and useful in the provision 22 of utility service. 23
24 3. TESLA PHASE II (S5) 25 86. Q. PLEASE DESCRIBE THE PROJECT. 26 A. This project involved the phased installation of new facilities associated with a Rule 27
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1 9 Applicant’s request for service. Phase 1 of this project included reconfiguration 2 of the 190 transmission line (120 kV) between Dove and Fernley to feed Tesla from 3 the new Chukar Substation (see Link P9 Chukar Substation project above), a new 4 motor-operated overhead line switch, communications and metering equipment. 5 Phase 2 of this project included construction of an approximate five-mile 120 kV 6 transmission line from Dove Substation to Chukar Substation, overhead fiber optic 7 telecommunication equipment, and associated lands rights. The Dove to Chukar 8 120 kV line is a planned segment of the 120 kV transmission loop described in the
9 Tracy Area Master Plan. A new 120 kV terminal addition at Dove Substation was
10 also included as part of this project.
11
12 87. Q. WHY WAS THE PROJECT NECESSARY? 13 A. This project was required in accordance with Amended and Restated Rule 9, 14 Section B.2 HVD Agreement No.15-00001 between Sierra and Tesla, Inc. for an D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 Applicant requested 165 MW of service. A copy of the agreement is provided as
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Exhibit Berdrow-Direct-5. 17 18 88. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 19 A. No. The Company did not submit the project to the Commission for approval 20 because it did not entail the construction of a “Utility Facility” in accordance with 21 NRS § 704.860. Although pre-approval was not requested, the project and design 22 approach was described in detail in the Tracy Area Master Plan presented to the 23 Commission. 24 25 26 27
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1 89. Q. WHAT WAS THE TOTAL COST OF THE PROJECT AND WHEN WAS 2 THE PROJECT PLACED IN SERVICE? 3 A. The estimated total cost of the Utility-Owned Facilities based on Facility 4 Designation and Rule 9 in the HVD Agreement for Phase 1 of the project was 5 $1,669,572 (without AFUDC). The Applicant’s total cost for CIAC, HVD and Tax 6 Gross-up less the Applicant’s Up-front Allowance and previously invoiced amount 7 was $434,968. Pursuant to the HVD agreement, the estimated net investment for 8 the Company was $1,142,686.
9
10 The estimated total cost of the Utility-Owned Facilities based on Facility
11 Designation and Rule 9 in the HVD Agreement for Phase 2 of the project was
12 $6,846,200 (without AFUDC). The Applicant’s Rule 9 allocated cost and tax gross- 13 up was $784,098. Pursuant to the HVD agreement, the estimated net investment for 14 the Company was $6,160,200. D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 The total net investment for phases 1 and 2 through December 31, 2018 was 17 $5,371,823 (with AFUDC), and the estimated total cost through May 31, 2019, is 18 $5,439,291 (with AFUDC). Phase 1 of the project was placed in service on April 19 10, 2018, and Phase 2 of the project was placed in service on May 9, 2018. All of 20 the installed facilities are in service and used and useful in the provision of utility 21 service. 22
23 4. UPDATE TO APPLE DATA CENTER – TRACY AREA (A5) 24 90. Q. PLEASE DESCRIBE THE PROJECT. 25 A. This project involved construction of the new 120 kV Pah Rah switching station, a 26 fold of the existing 105 transmission line (120 kV) between the Spanish Springs 27
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1 and Tracy substations into the new switching station, and two 120 kV dead end and 2 switch structures to connect the new customer-owned substation to the switching 3 station. The project was located northwest of Sierra’s Tracy Generation Station in 4 Washoe County. The switching station was designed as a four breaker ring and 5 included grading, fencing, installation of circuit breakers, switches and associated 6 bus work. A new control enclosure was installed to accommodate relay protection, 7 control, and telecommunication equipment. The 120 kV line relocation and rebuild 8 occurred in an approximate 1.4 mile long corridor, included a 25 kV distribution
9 line extension for station service, and appropriate land rights and environmental
10 permits.
11
12 91. Q. WHY WAS THE PROJECT NECESSARY? 13 A. The project was required in accordance with an Amended and Restated Rule 9, 14 Section B.2 HVD Agreement No. 14-00046 between Sierra and Apple, Inc. D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 (“Apple”) for an estimated original requirement of 50 MW. After signing the
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 original agreement on April 14, 2015, the Applicant projected a revised build-out 17 schedule and electric load requirement and the parties signed an amended and 18 restated agreement for an estimated requirement of 100 MW on September 12, 19 2016. A copy of the amended and restated agreement is provided as Exhibit 20 Berdrow-Direct-6. 21 22 92. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 23 A. Yes. The project was originally presented to the Commission in Sierra’s 2016 GRC 24 in Docket No. 16-06006. The Commission approved the inclusion of the revenue 25 requirement at that time. 26 27
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1 93. Q. WHAT EVENTS HAVE OCCURRED SINCE SIERRA’S 2016 GRC RELATED 2 TO THE APPLE DATA CENTER PROJECT? 3 A. Since the close of the certification period in Sierra’s 2016 GRC, the Company has 4 performed an audit and finalized the Total Cost True-up of the project. Based on 5 the Facility Designation and Rule 9 in the HVD Agreement, the Company 6 determined some of the upgrades required to provide electric service for estimated 7 loads up to 100 MW that were originally identified as HVD should be reclassified 8 to Transmission (TRAN). This determination was due to the fact that the previously
9 identified HVD terminal at Pah Rah Substation would function as part of the
10 network Transmission system. The criteria the Company used to make this
11 determination was FERC Order 888 that provides seven distribution indicators that
12 have been traditionally used to classify distribution and transmission facilities. The 13 result in the audit was one 120 kV terminal in Pah Rah Substation was reclassified 14 from HVD to TRAN. This decreased the Applicant’s cost responsibility and D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 increased Sierra’s cost responsibility.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 17 94. Q. WHAT WAS THE TOTAL COST OF THE PROJECT AND WHEN WAS 18 THE PROJECT PLACED IN SERVICE? 19 A. The estimated total cost of the Utility-Owned Facilities based on Facility 20 Designation and Rule 9 in the Amended and Restated HVD Agreement for Phase 21 1 of the project was $8,246,812 (without AFUDC). The Applicant’s total cost for 22 CIAC, HVD and Tax Gross-up less the Applicant’s Up-front Allowance and 23 previously invoiced amount was $3,999,581. Pursuant to the HVD agreement, the 24 estimated net investment for the Company was $4,891,212 and the Up-front 25 Allowance was $143,500. The estimated total cost of the Utility-Owned Facilities 26 27
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1 based on Facility Designation and Rule 9 in the HVD Agreement for Phase 2 of the 2 project were $0. 3 4 The total Sierra included in rate base plant closed to service and used to provide 5 service to customers before May 31, 2016, is $4,117,230 (with AFUDC), and is not 6 included for recovery in this rate case. After the Company performed an audit and 7 finalized the Total Cost True-up for the project, the total net investment for phases 8 1 and 2 after May 31, 2016, and through December 31, 2018 and the estimated total
9 cost through May 31, 2019, is $1,448,432 (with AFUDC). The project was placed
10 in service on January 22, 2016. All of the installed facilities are in service and used
11 and useful in the provision of utility service.
12 13 IV. NERC TRANSMISSION SYSTEM REQUIREMENTS 14 95. Q. DESCRIBE THE PROJECTS INCLUDED IN THIS SECTION. D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 A. The projects in this section were necessary to comply with NERC reliability
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 standard TPL-001-4 Transmission System Planning Performance Requirements. A 17 copy of the standard is provided as Exhibit Berdrow-Direct-7. This NERC 18 reliability standard establishes transmission system planning requirements within 19 the planning horizon to develop a bulk electric system that will operate reliably 20 over a broad spectrum of system conditions and following a wide range of probable 21 contingencies. The Company identified the five projects listed below to provide 22 mitigation for contingencies that do not meet the NERC mandated transmission 23 planning standard.
24 • Update to #128 Line Capacity Upgrades (B3) 25 • East Tracy Underrated Breaker Replacement (YR) 26 • Winnemucca Area UVLS (E9) 27
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1 • Pah Rah – Tracy East 120 kV Line (M8) 2 • Frontier Breaker Addition (A0I) 3 4 96. Q. DESCRIBE THE PRUDENT PLANNING PROCESS USED TO DEVELOP 5 THESE PROJECTS. 6 A. NERC TPL-001-4 is a mandated transmission planning standard that became 7 effective January 1, 2016. This standard requires the Company to perform an annual 8 assessment of the transmission system through steady state and transient
9 contingency analysis. Several types of contingencies are analyzed to test the
10 systems stability. Where instability exists, a corrective action plan is required to
11 mitigate the instability. Examples of instability include equipment overloads, low
12 system voltage, and out of step generation. The projects listed in this section are 13 driven by the results of the analysis required by TPL-001-4. The completion of 14 these projects ensures system reliability as well as compliance with mandated D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 NERC standards.
and Sierra Pacific Power Company Pacific Power Sierra and Company 16
17 1. UPDATE TO 128 LINE UPGRADES (B3) 18 97. Q. PLEASE DESCRIBE THE PROJECT. 19 A. This transmission project involved replacing the conductor on the existing 3.5-mile 20 128 120 kV line between the Greg Street and Glendale substations in Washoe 21 County. The line re-conductor project required 120 kV capacity upgrades at the 22 existing Greg Street and Glendale substations, and included installation of a fiber 23 optic telecommunications cable between Glendale Substation and Sierra’s Ohm 24 Operations Center. The existing 954 kcmil AA conductors on the 128 line rated at 25 1,010 Amps were replaced with 1026 kcmil Aluminum Conductor Composite Core 26 conductor rated at 1,706 Amps at 180 degrees Celsius. The higher-rated and 27
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1 similar-sized conductor could be installed without replacing or modifying the 2 existing poles. Insulators and hardware mounted on the poles were replaced. The 3 associated substation upgrades include the installation of eight new 120 kV circuit 4 breakers, new control enclosures at both substations, and associated bus work, 5 protection system modifications, and telecommunication upgrades. 6 7 98. Q. WHY WAS THE PROJECT NECESSARY? 8 A. The project was required to comply with NERC and Western Electric Coordinating
9 Council reliability standard TPL-002 System Performance following loss of a
10 single bulk electric system element. The Company calculated that the 128 line could
11 load up to approximately 120 percent of rated capacity for the N-1 loss of either the
12 3425 345 kV line from West Tracy to East Tracy, or the 3426 345 kV line from 13 East Tracy to North Valley Road, followed by trigger of the Airport to Rusty Spike 14 120 kV line remedial action scheme. The Company analyzed and documented the D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 justification in a 2014 NERC System Performance and Reliability Standards Self-
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Assessment Audit Report. The overload was also observed in System Impact 17 Studies for Designated Network Resources for the McGinness II 38 MW 18 geothermal project, Apple Solar 19.89 MW project, and in system planning studies 19 for the ORNI 43 Transmission Service Agreement 09-00796 for 60 MW deliveries 20 to Hilltop Substation. Increasing the rated capacity of the 128 line and the 21 associated substation upgrades mitigate the potential to overload the line and 22 associated electrical facilities and improve reliability and availability for both retail 23 and wholesale transmission customers. 24 25 99. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 26 A. Yes. The conductor, insulators, and hardware were replaced and twelve steel poles 27
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1 on the 128 line were re-painted and placed in service on April 22, 2016. Consistent 2 with the rules governing general rate applications, this investment was included in 3 Sierra’s 2016 General Rate Case (Docket No. 16-06006). Sierra is not seeking to 4 include this investment, or any investment to replace the conductor incurred before 5 May 31, 2016, in rate base through this application. 6 7 100. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 8 A. The estimated total cost of the project (including the dollars invested prior May 31,
9 2016) was $6,195,248 (without AFUDC). The total cost of the project through May
10 31, 2019 is $6,951,838 (with AFUDC). From these total costs, Sierra was allowed
11 to include $1,473,827 (with AFUDC) in rate base in the 2016 general rate review
12 proceeding, and so these costs are not included for recovery in this rate case. The 13 total Sierra included in rate base plant closed to service and used to provide service 14 to customers after May 31, 2016, is $5,478,011. The Greg Street and Glendale D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 substation upgrades were placed in service on March 22, 2017. The eleven month
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 delay to complete the substation upgrades was due to a longer schedule duration 17 for engineering design, major materials, and a phased construction sequence 18 governed by outage constraints to transfer load to replace and upgrade individual 19 line terminals and major equipment in each substation. These facilities are used and 20 useful in the provision of utility service. 21
22 2. EAST TRACY UNDER-RATED BREAKER REPLACEMENT (YR) 23 101. Q. PLEASE DESCRIBE THE PROJECT. 24 A. The project involved replacement of existing underrated equipment comprised of 25 two breakers, one circuit switcher, and two switches at East Tracy Substation 26 located in Storey County. New equipment included four circuit breakers, two 27
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1 switches, control enclosure, potential transformers, primary and back up battery 2 banks, protective relays, critical infrastructure protection requirements, and 3 associated telecommunications equipment. The additional circuit breaker was 4 required to re-terminate the low side of transformer #1 inside the breaker-and-a- 5 half bus design. 6 7 102. Q. WHY WAS THIS PROJECT NECESSARY? 8 A. East Tracy Substation is located east of Reno near the Tracy and West Tracy
9 Generation stations and serves as a critical hub to both system load sourcing and
10 transmission obligations. During an annual Transmission Planning assessment,
11 short circuit studies identified significant increases in the fault duty on the 120 kV
12 bus at East Tracy Substation that exceeded existing equipment rating levels. East 13 Tracy 1004 and 1008 circuit breakers both reached 117.6 percent of their short 14 circuit interrupting ratings and the 1001 circuit switcher was found to be above its D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 short circuit interrupting rating by 107.8 percent. For high fault current events,
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 under-rated equipment can fail to operate correctly and create a significant safety 17 hazard to surrounding facilities, equipment, and personnel. The replacement of the 18 under-rated equipment was necessary to comply with NERC TPL standards and 19 associated NESC safety requirements. 20 21 103. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 22 A. No. The Company did not submit the project to the Commission for approval 23 because it did not entail the construction of a “Utility Facility” in accordance with 24 NRS § 704.860. 25 26 27
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1 104. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 2 A. The total estimated cost of the project was $3,721,572 (without AFUDC). The total 3 cost of the project through December 31, 2018, was $4,658,671 (with AFUDC), 4 and the estimated total cost through May 31, 2019, is $4,666,211 (with AFUDC). 5 The project was placed in service on June 5, 2018. All of the facilities installed are 6 in service and used and useful in the provision of utility service. 7
8 3. WINNEMUCCA AREA UVLS (E9) 9 105. Q. PLEASE DESCRIBE THE PROJECT.
10 A. This project involved the installation of equipment necessary to facilitate an under-
11 voltage load shedding remedial action scheme. Under-voltage protective relays and
12 associated telecommunication equipment were installed at the Winnemucca, 13 Oreana, North Valmy, Bannock and Imlay substations located in Pershing, 14 Humboldt, and Lander counties. A new control enclosure was installed at D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 Winnemucca to accommodate the additional system protection and
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 telecommunications equipment. 17 18 106. Q. WHY WAS THIS PROJECT NECESSARY? 19 A. The Winnemucca and Oreana transmission system is a 120 kV and 60 kV network 20 fed by two 120 kV lines strongly sourced out of the Valmy Substation from the 21 east, a single 120 kV source served radially from the west, and a net 49.5 MW 22 geothermal power plant interconnected at Dun Glen. It is a rural area and the 23 electric system serves approximately 130 MW of mining and distribution load. 24 Limited transmission sourcing coupled with the configuration of the Winnemucca 25 and Oreana substation busses can cause voltage collapse and cascading outages 26 following multiple contingencies. NERC-mandated planning criteria requires the 27
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1 installation of under voltage relaying on circuit breakers at the Winnemucca, 2 Oreana, North Valmy, Bannock, and Imlay substations to mitigate these issues and 3 comply with NERC standards. 4 5 107. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 6 A. No. The Company did not submit the project to the Commission for approval 7 because it did not entail the construction of a “Utility Facility” in accordance with 8 NRS § 704.860.
9
10 108. Q. WHAT WAS THE TOTAL COST OF THE PROJECT?
11 A. The estimated total cost of the project was $3,367,268 (without AFUDC) and the
12 total cost of the project through December 31, 2018, for facilities installed and 13 placed in service was $305,645 (with AFUDC), and the estimated total cost through 14 May 31, 2019, is $2,846,534 (with AFUDC). Several portions of the project were D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 placed in service and used and useful in the provision of utility service during the
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 test period (Bannock Substation completed May 31, 2018, Oreana Substation 17 completed June 20, 2018, and Imlay Substation completed July 3, 2018). All 18 remaining facilities are in construction and planned in service and should be used
19 and useful in the provision of utility service by May 31, 2019. 20
21 4. PAH RAH – TRACY EAST 120 KV LINE (M8) 22 109. Q. PLEASE DESCRIBE THE PROJECT. 23 A. This project involved the permitting and construction of a new approximate one- 24 mile 120 kV transmission line from Pah Rah Substation located in Washoe County 25 to East Tracy Substation located in Storey County. The line construction also 26 27
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1 required installation of circuit breakers, bus work, protection, and communication 2 equipment at both substations. 3 4 110. Q. WHY WAS THIS PROJECT NECESSARY? 5 A. On September 12, 2016, NV Energy executed an Amended and Restated Rule 9, 6 High Voltage Distribution Agreement 14-00046 with Apple, Inc. for 100 MW of 7 service. The project is described in Update to Apple Data Center – Tracy Area (A5) 8 above. Transmission planning and analysis demonstrated that this new contracted
9 load out of the Pah Rah Substation could cause the 103 line from North Valley
10 Road to Valley Road and the 104 line from Valley Road to Spanish Springs to
11 overload to 127 percent and 106 percent of their respective thermal ratings during
12 N-1 contingency events. Constructing the Pah Rah to East Tracy 120 kV line 13 provides a second transmission source from East Tracy and was required to mitigate 14 the possible overload condition and comply with NERC TPL standards. D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 111. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 17 A. No. The Company did not submit the project to the Commission for approval 18 because it did not entail the construction of a “Utility Facility” in accordance with 19 NRS § 704.860. 20 112. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 21 A. The estimated total cost of the project was $2,508,284 (without AFUDC). The total 22 cost of the project through December 31, 2018, and estimated cost through May 31, 23 2019 is $2,438,999 (with AFUDC). The project was placed in service on October 24 28, 2017. All of the facilities installed are in service and used and useful in the 25 provision of utility service. 26
27
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1 5. FRONTIER BREAKER ADDITION (A0I) 2 113. Q. PLEASE DESCRIBE THE PROJECT. 3 A. The project involved the addition of a 230 kV breaker and re-termination of the 4 existing 2308 Austin to Frontier 230 kV line at Austin Substation located in Lander 5 County. Equipment additions associated with the installation of the 230 kV breaker 6 included three capacitor voltage transformers, three lightning arrestors, rebuild of 7 a section of the existing bus work, power circuit breaker and line protection panels, 8 and telecommunications equipment.
9
10 114. Q. WHY WAS THIS PROJECT NECESSARY?
11 A. The addition of a 230 kV breaker at Frontier Substation and re-termination of the
12 existing 2308 line is required to mitigate thermal overloads following the loss of 13 the 2400 breaker at Frontier Substation and to meet NERC TPL requirements. The 14 2400 breaker at Frontier Substation is located between the line terminals for the D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15 2306 Frontier to Machacek 230 kV line on the east side and the 2308 Austin to
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 Frontier 230 kV line on the west side. If a fault were to occur on either line and the 17 2400 breaker failed to operate correctly, the breakers located adjacent to the 2400 18 breaker would be required to open causing a loss of both 230 kV lines. With the 19 existing substation configuration, this could cause loss of approximately 100 20 megawatts of load, 250 megawatts of generation, thermal overloads of the lower 21 120 kV loop connected to Anaconda Substation, overload of Path 52 at Silver Peak, 22 and possible NERC TPL violations. 23 24 115. Q. HAS THIS PROJECT BEEN PRESENTED TO THE COMMISSION? 25 A. Yes. This project was previously presented to the Commission in Docket No. 16- 26 07001 SPPC Triennial IRP, Volume 12 of 16, TRAN-2 Frontier #2400 Breaker 27
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1 Failure Mitigation of Thermal Overloads. 2 3 116. Q. WHAT WAS THE TOTAL COST OF THE PROJECT? 4 A. The estimated total cost of the project was $752,455 (without AFUDC). The total 5 cost of the project through December 31, 2018, was $1,259,633 (with AFUDC), 6 and the estimated total cost through May 31, 2019, is $1,278,739 (without 7 AFUDC). The estimated total cost through May 31, 2019, is $526,284 higher than 8 the estimated total cost because construction required significantly more labor and
9 equipment hours to rebuild approximately half of the existing substation and there
10 were unanticipated civil construction costs to upgrade and maintain an approximate
11 7-mile deteriorated dirt access road. Also travel time to the remote construction site
12 was not correctly estimated. The project was placed in service on November 20, 13 2018. All of the facilities installed are in service and used and useful in the provision 14 of utility service. D/b/a NV Energy NV Energy D/b/a Nevada Power Company Company Power Nevada 15
and Sierra Pacific Power Company Pacific Power Sierra and Company 16 V. CONCLUSION 17 117. Q. DOES THIS COMPLETE YOUR TESTIMONY? 18 A. Yes, it does. 19 20 21 22 23 24 25 26 27
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Exhibit Berdrow-Direct-1 Page 1 of 2 Statement of Qualifications of JOHN S. BERDROW NV Energy 6100 Neil Road Reno, NV 89511 (775) 834-3146 [email protected]
Mr. Berdrow has over 34 years of experience in management and supervision, project management, engineering, environmental and regulatory permitting, private lands, material procurement, construction, and business-related contracts for a wide variety of electric transmission, generation interconnection, and gas transmission projects throughout Nevada and Eastern California. Mr. Berdrow has project experience designing and developing overhead and underground electric transmission lines, electric substations, electric generation, gas transmission pipelines, and water facility improvements. In his current role as Manager Major Projects - Delivery for NV Energy, Mr. Berdrow is responsible for managing staff and providing project management services for multi-discipline projects driven by NV Energy’s Electric Delivery and Transmission departments and external major customers.
PROFESSIONAL EXPERIENCE
2015 to Present Sierra Pacific Power Company d/b/a NV Energy Manager, Major Projects - Delivery Manager position in the Electric Delivery Project Management and Construction Department responsible for managing employees and contract project managers responsible for the permitting, design, and construction of electric transmission line, substation, and power plant interconnection facilities. Project responsibilities include NV Energy capital improvements, Rule 9, and third party generator interconnection and relocation projects.
2014 to 2015 Sierra Pacific Power Company d/b/a NV Energy Manager, Major Projects - Transmission Project Delivery In August 2014, assigned as Project Manager for NV Energy’s implementation to participate in the California Independent System Operator’s (“CAISO’s”) Energy Imbalance Market. The position was the lead coordination point with the CAISO, a broad spectrum of company departments, and multiple vendors to develop and test software upgrades, complete implementation agreements, develop operating templates for system resources, construct generation and meter upgrades, implement operating procedures, and train the operating workforce. The Go-Live date was December 1, 2015.
2006 to 2014 Sierra Pacific Power Company d/b/a NV Energy Manager, Major Projects – One Nevada Transmission Line Project Manager responsible for the permitting, design, and construction of approximately $500 million in electric transmission facilities associated with the One Nevada Transmission Line (“ON Line”). The transmission scope included 231 miles of 500 kilovolt electric transmission line and associated electric substation and communication facilities. NV Energy was the managing party for construction of this project jointly owned by Great Basin Transmission South, LLC.
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Exhibit Berdrow-Direct-1 Page 2 of 2 2005 to 2006 Sierra Pacific Power Company Manager, Major Projects Manager position in Sierra’s Project Management Department with a staff of in-house and contract project managers responsible for the permitting, design, and construction of electric transmission line, substation, and power plant interconnection facilities. Direct project responsibilities included project management for $150 million in electric utility projects, including multiple 345 kilovolt and 120 kilovolt system improvement projects, interconnection of an owner-constructed 520 megawatt combined cycle natural gas power plant, and the interconnection of an Independent Power Producer’s 200 megawatt coal- fired power plant.
2004 to 2005 Tuscarora Gas Transmission Company Manager, Major Projects Managed Tuscarora’s 2005 and Gold Strike Expansion Projects. The project scope included construction of two green field 7,600 horsepower natural gas compressor stations, compressor additions to an existing utility interconnection, and a half-mile of pipeline lateral. The estimated project cost was $30 million. The project required FERC regulatory and State air quality permits, land purchases and easements, contract design, and contract construction services.
1999 to 2004 Sierra Pacific Power Company Manager, Major Projects Project Manager responsible for permitting, design, and construction of a 180-mile 345 kilovolt electric transmission line in northeastern Nevada. The Falcon to Gonder 345 kilovolt Project was the longest electric transmission line constructed in the United States in 2003/2004. It required completion of an Environmental Impact Statement permit process through three Bureau of Land Management districts, development of a Construction, Operation, and Maintenance Plan, acquisition of easements from private landowners, coordination of in- house design efforts, and the management of third-party construction contracts. The total project cost was $110 million.
1984-1999 Sierra Pacific Power Company Project Leader, Senior Design Engineer, Design Engineer, and Associate Design Engineer Provided project management and civil/structural design services for multiple electric transmission and substation projects to support customer growth within Sierra Pacific Power Company’s electric system.
EDUCATION
1984 University of Nevada, Reno Bachelor of Science Degree in Civil Engineering
PROFESSIONAL CERTIFICATIONS, LICENSES, AND MEMBERSHIPS
1987 Registered Professional Engineer in the State of California, Civil 41781 1991 Registered Professional Engineer in the State of Nevada, Civil 9465
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EXHIBIT BERDROW-DIRECT- 2
Page 110 of 236 SIERRA PACIFIC POWER COMPANY Exhibit Berdrow-Direct-2 d/b/a NV Energy PAGE 1 OF 1 ELECTRIC DEPARTMENT TRANSMISSION AND DISTRIBUTION MAJOR PROJECTS Plant Additions - June 1, 2016 to to May 31, 2019 (Account 101 including AFUDC)
(a) (b) (c) (d)
Ln Ln No Link Link Description As of 12/31/18 As of 05/31/19 No
1 4P Brunswick 120 kV Substation Rebuild $ 25,769,060 $ 27,096,755 1 2 WD Smith Valley 120/25 kV Substation 17,676,964 17,674,440 2 3 BS Mason Valley 120/25 kV Substation 16,474,491 16,539,557 3 4 1W South Meadows 120/25 kV Substation 943,723 15,146,235 4 5 P9 Chukar 120/25 kV Substation 11,124,644 12,589,283 5 6 RC Ormat Tungsten 2309 Line POR Substation 8,992,545 8,992,545 6 7 6B Lahontan – Lovelock 617 Line Rebuild - 8,476,769 7 8 A8 Dove to Wildhorse 120 kV Line 6,565,128 6,799,211 8 9 B3 Update to 128 Line Capacity Upgrades 5,478,011 5,478,011 9 10 S5 Tesla Phase II 5,371,823 5,439,291 10 11 YR East Tracy Underrated Breaker Replacement 4,658,671 4,666,211 11 12 A7B Round Hill 120/14 kV Substation Failure 1,618,704 4,414,410 12 13 FZ Foothill – Kingsbury 634 Line Rebuild 4,064,998 4,081,876 13 14 AC8 North Red Rock 120/25 kV Substation - 3,048,098 14 15 E9 Winnemucca Area UVLS 305,645 2,846,534 15 16 XN Update to 230 kV Three Pole Structure Repl 1,943,338 2,707,942 16 17 M8 Pah Rah – Tracy East 120 kV Line 2,438,999 2,438,999 17 18 A0X Mira Loma – Steamboat 127 Line Relocation 2,047,916 2,278,578 18 19 9R Steamboat 215 Feeder Addition 1,697,269 1,695,193 19 20 AL Update to 345 kV PLC Replacement Program 1,474,037 1,474,037 20 21 A5 Update to Apple Data Center 1,448,432 1,448,432 21 22 A0I Frontier Breaker Addition 1,259,633 1,278,739 22 23 3Y Humboldt – Midpoint 345 kV Wave Trap Upgrade 1,278,420 1,278,420 23 24 ZC 345 kV Cap Bank Breaker Replacement 1,269,087 1,269,087 24 25 A0H Brusnwick to Buckeye 635 Line Relocation 41,457 1,017,773 25 26 OTHER 3,860,013 5,659,936 26 27 27 28 $ 127,803,008 $ 165,836,361 28
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EXHIBIT BERDROW-DIRECT- 3
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May 2017 Master Transmission Service Plan Tracy Area Load Pocket Executive Summary The most quickly emerging load pocket in northern Nevada is the Tracy Area, approximately 20 miles east of Reno. Both the Reno Technology Park (“RTP”) and the Tahoe Regional Industrial Center (“TRI Center”) sit within the boundaries of this load center. A map showing the current geographic boundaries of the Tracy Area Load Pocket is displayed in Figure 1.
Reno Technology Park
Tahoe Regional Industrial Center
Figure 1: Tracy Area Load Pocket
As can be seen from the map above, the RTP is located across the Truckee River and Interstate 80 from the Tracy Power Station and is home to the fast-growing Apple Data Center and the proposed Turquoise Solar Generation project. Presently, the RTP is served out of the Patrick and Pah Rah Substations. The footprint for the RTP is approximately 2,200 acres, with up to 1.5 million square feet of data center space. Currently load at the RTP is 30 to 35 MW.
TRI Center is the largest regional commercial and industrial center in Northern Nevada, with a footprint at full buildout of over 107,000 acres. TRI Center is being built out and occupied in phases over several years. Currently the developers of the TRI Center have declared 30,000 acres as “open” to development. As of this date, most of the load in TRI Center is served from the Patrick Substation through single This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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overhead radial feeder, the Patrick 24.9 kV 225 line. The transformer at Patrick is rated at 60 MVA and has seen significant growth over the past few years as illustrated in Figure 2 below:
PATRICK SUBSTATION – HISTORICAL LOADING (MVA) Year 2010 2011 2012 2013 2014 2015 2016 Installed Transformer Capacity 28 28 28 28 60 60 60 Peak Loading n/a 18.5 14.9 18.1 19.9 26.6 34.1 Change - - -3.6 3.2 1.8 6.7 7.5 % Increase - - -19.5% 21.5% 9.9% 33.7% 28.2% Figure 2: Patrick Substation Historical Load Growth
The Patrick 225 line is rated at 900A and is approximately 6.5 miles long with over 32 miles of primary laterals that traverse the TRI Center area. Because the Patrick 225 feeder is not looped to any other circuit or source, operational responses to contingencies are extremely limited, and loss of the Patrick Substation or on any portion of the Patrick 225 will drop some or all of the load within TRI Center. Over 900 service addresses are currently served exclusively from the Patrick 225 line including: Walmart, James Hardie, Ardagh, Masterfoods/Kal-Kan, AquaMetals, Petsmart (all TQS customers), and a number of large eCommerce distribution centers including; Zulily, Jet.com, Chewy.com, Amazon, eBay, Tesla, Switch and others.
The Company has long recognized that as customers are attracted to the Tracy area, additional transmission sources will need to be constructed, not only to serve load growth, but to introduce redundancy, provide transmission service reliability and enable predictive maintenance. Thus NV Energy recently made the decision to construct a new 120 kV line out of the Dove Substation (near Tracy) and construct Chukar Substation in the Northeast corner of the TRI Center. When it goes into service in March 2018, the new 120 kV line and the Chukar Substation will back up the Patrick Substation and distribution feeder, as well as provide capacity to serve additional distribution loads.
Most recently, the plan for serving the Tracy Area Load Pocket has been impacted by announcements from several high-tech, high-usage customers that they are moving forward with major expansions and new projects located within the Tracy Area Load Pocket. These include Apple’s announced expansion of its data facility in the RTP, the next phase of construction at the Tesla Gigafactory, the new Project Meadows, which will be located on land purchased at the south east edge of the current footprint at TRI Center, and Switch’s data center at the south western edge of the current TRI Center footprint. In addition to load from these four individual customers, NV Energy has identified needs for future distribution system capacity within the load pocket. The chart in Figure 3 below shows the projected load growth at Tesla, Switch, Meadows and Apple, along with distribution system load growth in the Tesla and Meadows areas, within the next three and five years.
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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Tracy Area Load Additions MW Demand MW Demand Near Term 1-3 Years Long Term 3-5 Years Tesla Gigafactory Switch Data Center Meadows Apple Chukar Distribution Comstock Meadows Total 622 1737 Figure 3: Tracy Area Projected Load Growth
The peak load in northern Nevada’s system is approximately 2200 MW. The load growth represented in the table above is unprecedented in the Northern System. Each successful project will bring additional growth to Nevada and further build on the extensive economic development that has already occurred. Moreover, each time NV Energy successfully deploys cost-effective and reliable service to customers within the Tracy Area Load Pocket, the seed is planted for the next development project. Master Plan Overview As is set forth in detail below, based on the most recent information available to date, the following transmission infrastructure projects have been identified and are being proposed to serve up to the first 500 MW of near term load requests in the Tracy Area Load Pocket.
120 kV line from Dove to Chukar Substation, 5.21 miles, 3/31/2018 120 kV line from Dove to Switch Load Pocket, 4.8 miles, 5/31/18* Comstock Meadows Substation, initially four breakers, to serve Meadows and expandable for future distribution, 12/31/2019* Wild Horse Substation, initially four breakers, to serve Switch and expandable for future distribution, 12/31/2019* 120 kV line from Chukar Substation to Comstock Meadows Substation, 7 miles, 5/31/2019* 120 kV line from Wild Horse Substation to Comstock Meadows Substation, 3.8 miles, 12/31/2019* Installation of a second 345/120 kV transformer at East Tracy Substation, 5/31/2019 * Rebuild of the existing East Tracy to Dove 120 kV line from 954 ACSR to 1020 Drake ACCC, 0.5 miles, 5/31/2018* Fold of the existing East Tracy to Brunswick 120 kV line into Dove Substation and rebuild of the section of line between East Tracy and Dove Substation, 0.5 miles, 5/31/2018* Installation of 90 MVAR capacitor banks at Chukar, Wild Horse and Comstock Meadows. In service date depends on cumulative loads, no dates set. *Subject to change based on contractual agreements and load forecasts of proposed area load.
A map showing the above-identified projects at near-term buildout is set forth below in Figure 4.
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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Chukar Sub
Existing: 60 kV (Red) Wild Horse Sub 120 kV (Light Blue) 345kV (Light Green)
Proposed: 120 kV (Dark Blue) 345 kV (Dark Green)
Comstock Meadows Sub
Figure 4: Geographic Overview of Master Plan
Electrically, the Master Plan is illustrated in Figure 5.
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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Figure 5: Simplified Single Line Diagram of Tracy Area Master Plan
This transmission loop will wrap 120 kV transmission around the load pocket and create strategic hubs for interconnection of proposed large loads, required reactive support and distribution transformer sourcing. The phasing of each segment of the plan, which as proposed will be completed over the next several years, is set forth in the following pages as well. The plan is sufficiently flexible to be able to accommodate accelerations or delays in the identified needs upon which the plan is based, as well as further expansion of the RTP and TRI Center developments
Background: Planning Transmission Service to Load Pockets The Transmission Planning department at NV Energy is responsible for strategically planning the transmission system to reliably and cost-effectively meet identified near-term needs, as well as anticipated long-term future needs. The transmission system serves both load and supply, and Transmission Planning must identify and address system needs caused by both load growth (whether
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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“normal” residential and commercial growth or requests for large blocks of transmission capability in discrete locations from discrete load additions), and from requests by energy suppliers for generation interconnections and transmission service. Although only one factor impacting transmission planning, load growth tends to be the most demanding. While regional and even local forecasts and trends can assist with the planning exercise, as they impact the transmission system, the specific location, timing and size of load growth are not controllable by the transmission system provider. For this reason, transmission planning requires agility and adaptability to accommodate the unpredictable behavior of load growth.
Load growth tends to concentrate within geographic load pockets. Reno, Carson City and the Carlin Trend are presently the largest load pockets in northern Nevada. As these load pockets developed, Transmission Planning developed service plans that utilize looped high-voltage networks with redundant sources of supply feeding networked substations and feeders. By serving load centers with looped networks, the transmission provider is able to reliably serve all loads within the load pocket, even with the loss of a single element, such as a transformer, transmission line, or reactive device. For Bulk Electric System (“BES”) facilities of 100 kV or more, the North American Reliability Corporation (“NERC”) requires this level of redundancy under mandated system reliability requirements. In a properly designed networked system, all sources have the ability to offset parallel connections in order to ensure redundant reliability. A single weak link in a transmission system can limit its overall capability.
NERC reliability standards describe load loss under a contingency as either consequential or non- consequential. Consequential load loss occurs when a radial line is the only source to a certain load and the radial line lost. The load dropped under this scenario is considered consequential. Non-consequential load loss generally occurs in a networked system where load is dropped due to low voltage or system overloads. This typically occurs where a weak link in the network has been allowed to develop. With proper transmission planning, these situations are anticipated through simulations and studies and addressed before they actually occur. NV Energy prefers that the transmission system is configured so that all loads are categorized as non-consequential because this allows better performance. However, this requires that all loads be served from two or more sources. Transmission Planning recognizes that this is not always possible, especially in rural areas where long radial transmission and distribution is required to serve small and geographically dispersed loads. However, looped network service is essential for serving load pockets.
In Reno, Carson City and the Carlin Trend, NV Energy has planned for, designed and built looped and redundant networked service. This has been accomplished by creating sub-transmission loops around and inside the load pocket and by reinforcing these loops with Extra High Voltage (“EHV”) connections supporting the sub-transmission. The standard sub-transmission voltage in northern Nevada is 120 kV, although some legacy 55 kV and 60 kV sub-transmission systems are still in service. In southern Nevada, sub-transmission voltages are 69 kV and 138 kV. EHV in northern Nevada is 230 kV and 345 kV, with 345 kV being predominant. In southern Nevada EHV is 230 kV and 500 kV, with 230 kV being predominant.
Typically sub-transmission and EHV are planned so that they can be installed in phases as the load pocket grows. For example both the Reno and Carlin Trend systems have both sub-transmission and EHV
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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components, while the Carson load pocket is currently served mostly from the sub-transmission network. As the Carson load pocket grows, it will require additional strong sourcing through EHV connections. Developing Load Pockets
Currently in northern Nevada, existing load pockets, are expected to grow and new load pockets are emerging. The same approach to planning for, designing and building the strategic transmission infrastructure serving existing load pockets should and will be applied to emerging load pockets. The areas identified in Figure 6 are experiencing major and concentrated growth and will require additional Figure 6: Northern Nevada Load Pockets Experiencing Growth transmission infrastructure: North Valleys & Silver Lake Area Between planned residential developments and announcements of and applications from new commercial loads, the North Valleys and Silver Lake area is expected to grow significantly in the ten year planning horizon. Silver Lake, Sugarloaf and Spanish Springs Substations are all effectively within in the same electrical load pocket, which is sourced from Tracy and the North Valley Road Substation. At this time, there is very little additional sub-transmission capacity out of Silver Lake transformer. Sugar Loaf and Spanish Springs are nearly fully subscribed and the existing feeders have limited capability to back each other up under distribution outages. In addition to the lack of transformer capacity, transmission This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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capacity is also limited into this system pocket. At this time, an increase in transmission capacity in excess of 25 MW will require an additional transmission source into Silver Lake Substation.
While not the focus of this planning document or yet the subject of a request for approval of investment, Transmission Planning is reviewing alternatives for developing a phased three source network for serving the North Valleys load pocket. Transmission Planning has identified one alterative, a 120 kV line from Valley Road to Silver Lake, as a potential additional segment of the looped network. Additionally, the site for Red Rock substation is still a viable options for future distribution load growth. NV Energy’s Distribution Planning plans to resurrect this substation as well as propose a new substation, Lazy 5, which lies between Sugarloaf and Spanish Springs. Lazy 5 substation will offset loads from both Sugarloaf and Spanish Springs as well as create a third transmission source to each substation. As these loads continue to grow, an additional 120 kV source from Bordertown to Red Rock has also been identified. This plan reinforces the sub-transmission of this load pocket and surrounds it with supporting EHV connections. South Meadows Area The South Meadows area is electrically sourced by both Steamboat and Mira Loma Substation. Proposed load growth in this area has already subscribed the entire capability of these two substations. Distribution Planning has proposed to build South Meadows substation with sourcing from the 120 kV line between Steamboat and Mira Loma. This substation will initially have one 60 MVA transformer with the expansion capability for a second. It will initially be dual sourced, but have spare terminal capability for one or two additional 120 kV connections to meet possible future needs. Tracy Area From a transmission perspective, even though this load pocket surrounds the largest generation hub in northern Nevada, transmission capability into the specific load center is essentially non-existent. The Tracy transmission hub was originally built as a high voltage generation hub for transmission interconnections to remote load pockets (i.e. Reno and Carson City). The Tracy hub was not originally identified as a source for serving a major adjacent load pocket. Thus currently, the only transmission lines that run through the Tracy area load pocket are the Tracy to Silver Springs 60 kV line (the #603 line) and the Dove to Fernley 120 kV line (the #190 line). Neither of these transmission facilities is capable of providing networked service to the Tracy load pocket because any substation connected to either line is limited by the weak sourcing of the downstream interconnection: Silver Springs from the #603 line, or Fernley from the #190 line. Neither Silver Springs nor Fernley substations are sufficiently interconnected or served by sufficient resources that they can themselves support a major load pocket.
In preparation of serving the load pocket, NV Energy acquired land rights for the sub-transmission loop that would be needed to serve TRI Center. The land rights, originally acquired in 2003, included three potential substation sites (Canyon, Chukar and Quail Substations) along with the necessary 120kV lines to source each of the substations. In 2006, a portion of the land rights, including the Canyon Sub site, were expanded due to development in TRI Center. Additional modifications to the land rights to support the sub-transmission loop and construction of Tesla’s Gigafactory were made in 2014 and 2015. In early 2017, the sub-transmission loop land rights were once again expanded to the routes that are being proposed
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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for the Master Plan. The history of these land rights are indicated in Figure 7 and support NV Energy’s long-range service for the Tracy Area Load Pocket.
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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Comstock Comstock Meadows Sub
Chukar Sub Chukar
. : Geographic Representation of Easements of Term Long Master for Tracy Plan Area Representation : Geographic 7
Figure
Transmission - Includes Blackhawk Includes easement
Lines Lines Easement with
V and/or 345 kV (Yellow)V 345and/or
0 kV (Red) 0 120 k 6 kV (Dark120 Blue) Existing Existing Sub 2017 Easements 10
Page | This document contains non-public transmission information subject to FERC Standards of Conduct. of Conduct. Standards FERC to subject information transmission non-public contains This document with shared be must not it Accordingly, stakeholders external and employees function marketing
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As the Tracy Area Load Pocket has developed, Transmission Planning has continued to develop a plan to design and construct a sub-transmission network that will not only provide transmission capacity, but establish the needed reliability and redundancy to adequately serve both distribution and transmission loads. Over time the plan has been modified to reflect changes in the specific location, timing and size of load growth within the load pocket.
Study Plan/Approach NV Energy has executed Engineering Study Agreements with all four of the large customers listed on page 2 and has established individual transmission service solutions capable of serving each customer individually. In each of the individual transmission service plans, NV Energy has designed a “minimum to serve” solution in which the customer takes service at 120 kV, with a step down within a customer owned substation to provide distribution voltage throughout the individual customer’s campus. Each load addition was studied individually in additive sequence of request to ensure that service could be provided regardless of other applicant actions.
These individual service plans were then examined together with the identified needs for capacity and reliability of the distribution system customers located within the RTI and TRI Center. Therefore the Tracy Area Master Plan takes into account all of the currently identified load and load growth in the area. This exercise was performed in order to identify networked transmission solutions for serving not only the individual customers identified above, for the Tracy Area Load Pocket as a whole. Because the large loads being studied apply significant reactive loading to the system and would degrade the overall system voltage if not corrected, Transmission Planning identified the need for capacitors at new hubs around the network to provide reactive support near the large loads where they will be the most effective.
Once the most technically suitable and cost effective network solutions were identified, the individual service plans were re-evaluated, with each customer’s interconnection providing the foundation for the next. Using this approach, Transmission Planning was able to identify opportunities for eliminating redundant elements of the individual service plans, for increasing transmission system reliability, and providing expansion capability going forward. Phases were identified to ensure adaptability and flexibility in the event one or more of these customers accelerates or slows their individual project.
The result is a cohesive yet flexible cost-effective solution for providing networked transmission service within the fast-growing Tracy Area Load Pocket. The detailed phasing and explanation of this solution is provided in the Master Transmission Plan for Serving the Tracy Area Load Pocket.
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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Master Transmission Plan for Serving the Tracy Area Load Pocket In this section Transmission Planning describes each proposed phase of the Master Plan including scope and timing, as well as factors that impact the timing of each phase. Also included in each discussion is a description of cost and cost responsibility that is proposed based on the upgrade classification. The upgrades are represented in phases that build upon each other to complete the proposed 120 kV transmission loop. The analysis identifies the reduced facilities and increased reliability of the proposed plan, as well as the reduction in redundant facilities and costs associated with the Master Plan approach as compared to the individual buildout of facilities. Phase 1 – Dove to Chukar 120 kV Line Phase 1 of the Tracy Area Master Plan constructs a 5.0 mile 120 kV line from Dove Substation to the new Chukar Substation. As was described above, the Chukar Substation was justified based on increased distribution load growth in the TRI Center area, and to provide a much-needed backup to the Patrick 225 distribution feeder. Recall that the Patrick 225 is currently is the only source serving TRI Center.
Chukar Substation was initially planned to be connected on the existing 120 kV line between Dove and Fernley Substation, at a site just west of the existing Tesla Tap.1 The Tesla Tap provides service only to Tesla and supplies no support to TRI Center distribution system. Any fault on the Dove to Fernley 120 kV line results in dropping not only the entire line but also Tesla’s load as consequential load loss. The configuration of the existing temporary service to Tesla is illustrated below in Figure 8.
Figure 8: Existing Tesla Service
An alternative for the incorporation of Chukar to the preferred Phase 1 transmission system solution were examined. An alternative would be to fold the existing Dove to Fernley 120 kV line into Chukar Substation.
1 The Tesla Tap was completed in September 2015 to fulfill Tesla’s request for up to 53 MW of service pursuant to a High Voltage Distribution Agreement, executed July 2015. This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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This solution would provide additional capacity to serve distribution load within the Tracy Area Load Pocket, and Tesla would continue to be served exclusively from The Tesla Tap.
This alterative cannot provide a long-term transmission solution for meeting either distribution system loads or Tesla’s requirements, as it does not meet NERC Reliability standards. While the Chukar Substation would create a new isolation point within the system, any fault occurring between Dove and Chukar would require feeding both the Chukar distribution load and Tesla load off of the weak Fernley system. Under this contingency the combination of Tesla and Chukar Substation loads that could be served from Fernley would be limited to approximately 50 MW. Load in addition to this amount results in unacceptable voltage (below 0.90 per unit) and thermal overloading of the Fernley source from Tracy. Thus, due to unacceptable low voltage and system overloads under a contingency event on the Dove to Chukar leg of the 120 kV line, this option would not meet NERC Compliance standards; nor would it meet the contractual requirement to serve Tesla 53MW under the Rule 9 agreement.
Timing of a long-term solution has been driven by the timing of identified load growth. While Tesla’s load has been at only 5-10 MW, the above-described configuration has served as an interim solution for Tesla, while allowing the installation of Chukar Substation so that transmission support can be provided to the TRI Center distribution system. However, when the combined loads of Tesla and Chukar distribution load approach 50 MW, a second strong source from Dove will have to be constructed.
This alternative is illustrated below in Figure 9:
Figure 9: Chukar on Dove to Fernley with Existing Tesla Tap in Place
The alternative analyzed would provide transmission support to the TRI Center distribution system by still installing Chukar substation on the Dove to Fernley 120 kV. However, because of the limitations described above, the second strong source from Dove would be built not to Chukar but to Tesla. This interconnection configuration satisfies the criteria of an individual service plan for Tesla as contemplated in Rule 9. In this This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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configuration, Tesla would be served directly from Dove and the Tesla Tap would remain open in normal operations. Tesla would receive radial service from Dove and limited redundant service from Fernley in the event of a fault on Dove to Tesla line. However, the TRI Center distribution system would continue to be limited to a fault on the Dove to Chukar line from the relatively weak Fernley source. This alternative is illustrated below in Figure 10:
Figure 10: Radial Service to Tesla from Dove
While providing an acceptable service plan for meeting Tesla’s contracted load under Rule 9, this configuration does not satisfy the requirements of the distribution system load to be fed out of Chukar. Additionally, it sources 165 MW of load with no transmission redundancy. This solution does not strengthen the network of the load pocket. Thus Transmission Planning rejected this alternative.
A second alternative analyzed would continue to provide transmission support to the TRI Center distribution system by still installing the Chukar substation on the Dove to Fernley 120 kV. However, rather than constructing a second radial line from Dove to Tesla, a second strong source would be built from Dove to Chukar. Tesla’s primary service then would be transferred from the Tesla Tap to the Chukar Substation. The Tesla Tap would continue to function as an emergency second source into the Chukar substation, but the switch between Chukar and the Tesla Tap would normally operate in an open configuration. This alternative is illustrated below in Figure 11:
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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Figure 11: Tesla Served from Chukar with Additional 120 kV Source from Dove to Chukar
This configuration serves the needs for both Tesla and Chukar Substation, but results in parallel facilities between Dove and Chukar. Under maintenance conditions of one Dove to Chukar line and the loss of the other or the loss of both lines under fault conditions, load shedding protection would be required due to the weak Fernley source.
Simultaneous with the Chukar plans, Tesla requested up to 165 MW of load service under an Engineering Study Agreement. The solution for this load service, when considered as an individual system addition, was to build a radial line out of Dove Substation directly to Tesla. This line would pass by the Chukar substation. In the future, it could be folded in and provide the dual sourcing between Dove and Chukar. Doing this serves the same purpose as the second line described in the above section.
As both the Tesla analysis and the Chukar substation design progressed, it became clear that both of these projects require the same solution - a strong source out of Dove substation that is not impeded by the weak Fernley source under a contingency. Due to the amount of load Tesla was proposing and the proposed loads both south of Dove and south of Chukar, Transmission Planning identified the continued need for a master plan concept that incorporates all of these proposed loads in a phased approach. The plan would propose to loop additional sources around the TRI Center Park. This situation is described below in Figure 12:
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Figure 12: Chukar and Tesla Radially Served from Dove with Planned 120 kV Loop
The proposed Dove to Chukar line for both the Chukar Distribution Substation and Tesla’s 165 MW service creates the following initial phase savings: of:
- Eliminate need for the 190 OPGW addition, savings of $375,000 - Eliminate need for 190 fold Lands, savings of $170,000 - Eliminate need for a portion of the Environmental cost associated with the fold and single permitting application, savings of $186,500 - Eliminate need for 190 Line fold, savings of $595,000 - Initial Phase 1 Chukar savings is estimated to be $1,326,500
More important, the Master Plan phasing would either significantly delay or eliminate the need to build the future phase to Chukar (delineated with the dotted red line) by using the new, higher-capacity radial line to serve Chukar and Tesla. The estimated savings of eliminating the second strong source to Chukar from Dove is estimated to be $9.2 million. Additional benefits include a stronger source to serve future loads and preserving valuable terminal positions at both Chukar and Dove substations.
This configuration does result in Chukar and Tesla both initially being radial out of Dove Substation. Under this configuration, the loss of this line will drop both loads. This will be the case until the future phase of the Master Plan is built that loops a second source through TRI Center to Chukar. Under this scenario, the Company avoids the expense of folding the Dove to Fernley line into Chukar and limitations associated with the Fernley source.
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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Phase II – Dove to Switch 120 kV Line Switch has built a data center in the TRI-Center Park that is currently served out of the Patrick Substation and off the Patrick 225 via the 24.9 kV distribution system. Switch’s load will outgrow the distribution system’s service capability once it exceeds 14 MW. Transmission Planning has performed analysis of the addition of up to 153 MW load at the Switch Data Center.2 The minimum to serve solution for serving just the Switch load is a radial 4.8 mile 120 kV line from Dove Substation to the Switch Facility. This configuration, showing the results of designs that would only satisfy the individual service plans of Switch and Tesla, is shown below in Figure 13.
Figure 13: Individual Radial Service to Both Tesla and Switch
Transmission Planning is proposing an alternative to the individual service plan configuration shown above. Instead, Transmission Planning is proposing that the Dove to Switch line and terminus be reconfigured and constructed to serve three purposes: providing transmission service to Switch’s load, establishing new transmission support for the TRI Center distribution system, and functioning as a segment of the Master Plan 120 kV loop. A line route has been developed to run adjacent to a site that has been identified for a future substation called Wild Horse3. The Wild Horse substation will be
2 Load request, as determined by Switch. 3 Preliminary site has been identified but not finalized. Final siting will occur when Switch’s connection needs are finalized as well as the distribution service planned form Wild Horse Substation. This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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configured to meet identified needs on the distribution system, as well as Switch’s feeder requirements. The proposed configuration is displayed in Figure 14 below:
Figure 14: Incorporation of Switch 120 kV line into Tracy Area Master Plan
The 120 kV loop will continue from the Switch Site back to Chukar Substation as shown in Figure 15.
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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Figure 15: Completion of 120 kV Loop from Wild Horse Site to Chukar
The proposed Dove to Switch line does not have any cost savings until the Meadows project and/or looping occurs as described the next section. Phase III – Switch/Wild Horse to Comstock Meadows to Chukar 120 kV Lines Project Meadows has proposed a large data center southeast of the Switch Data Center. The customer executed an Engineering Service Agreement for NV Energy to study up to a 500 MW load addition. The load was studied from an initial 150 MW phase up to 500 MW. Meadows is currently not interconnected to NV Energy’s system.
Transmission Planning Study has specified the minimum to serve option to be a radial 10 mile 120 kV line out of Dove Substation. However, this customer has requested a minimum of two sources to their substation. In order to meet this level of reliability, Transmission Planning has identified the minimum to serve solution as an additional new 7 mile 120 kV line out of Chukar Substation that will connect to a new substation called Comstock Meadows. This solution requires that the radial line built for Tesla be folded into Chukar Substation and that the existing line from Dove to Chukar would be rebuilt to a larger
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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conductor size to accommodate the new loads at Tesla and Meadows. This configuration, along with the stand-alone solution for Switch, is displayed in Figure 16below.
Figure 16: Individual Service Plans for Tesla, Switch and Meadows
Under the Master Plan for this load pocket, Transmission Planning identified that the first 150 MW of Meadows load be served radially out of Chukar Substation with a 7 mile 120 kV line. This does not meet the redundancy required by the customer due to the single radial source. The configuration is shown in
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Figure 17 below:
Figure 17: Radial Service to Meadows under Master Plan Approach
This southern area of the TRI-Center Park has been specified as a potential site for a new distribution substation as well. The planned substation is named Comstock Meadows and would provide load service to several acres of developable land. This area is right off of USA Parkway and will see significantly increased traffic once the parkway has been built. An industrial park development has also been proposed in this area. Additionally, Meadows has requested a minimum of two sources for their reliability needs. The proposed plan for this interconnection is to complete the 120 kV loop by adding a four breaker Wild Horse Switching Station and the Comstock Meadows Substation. This configuration is shown in Figure 18 below:
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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Figure 18: Redundant Sourcing to Meadows Load under Master Plan Approach
This configuration will provide redundant sourcing to the distribution loads at Chukar, Wild Horse and Comstock Meadows Substation. The large 120 kV loads at Tesla, Switch and Meadows will also be redundant with two sources. This is important for not only reliability, but also for system stability.
The resource adaption required for dropping hundreds of MW simultaneously under a single contingency creates a large mismatch in the system. This will require the reduction of several generators to meet the balancing area interchange.
As the last applicant to be added to the proposed looped system, the Meadows project will require fewer upgrades given they have already been installed under the Master Plan. Specifically, the following upgrades are either eliminated or reduced that were proposed as part of the radial 150 MW service:
- Reduced 120kV line & OPGW due to Switch project, savings of $4,930,000 - Eliminate need for 120kV Dove Terminal, savings of $1,505,000
For the required second source to Meadows, the following upgrades are no longer required:
- Fold of the 191 line into Chukar, savings of $600,000 This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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- Chukar expansion for the 191 fold, savings of $1,340,000 - Total of $1,940,000 in savings
It should be noted that the addition of the Wild Horse Switching Station is not required to extend the Dove to Switch 120kV line to Comstock Meadows. As proposed, Wild Horse is primarily to allow multiple 120kv Feeders to Switch and the installation of a capacitor bank for reactive support. Absent this need by Switch, a three-way motor operated switch could be installed that would provide dual sourcing to Switch, reduce outage duration4 for faults on the Dove-Switch-Comstock Meadows line, minimize future outages to Switch when Wild Horse Switching Station is installed and Switch is re-terminated into Wild Horse. Additionally, the estimated cost for Wild Horse of $6,140,000 could be delayed until needed by either Switch or area distribution service.
Upstream Transmission System Upgrades As loads are added to the 120 kV system, upstream transmission upgrades are required to support the growth. Components of these upstream transmission system upgrades require 345 kV infrastructure. Approval for installation of these facilities will be identified in a future Integrated Resource Plan Filing. The following transmission upgrades have been identified along with the individual load additions.
Addition of a 345/120 kV transformer at East Tracy Substation – This upgrade is required to alleviate overloads on the existing 345/120 kV substation under system contingencies. Rebuild the .5 mile 120 kV East Tracy to Dove #179 line – This upgrade is require to alleviate overloads on the #179 line under system contingencies. Fold the existing East Tracy to Brunswick 120 kV line into Dove substation and rebuild .5 miles of line between East Tracy and Dove – This upgrade is required to alleviate overloads of the Greg St. to Dove line and low area voltage under system contingencies. Three 90 MVAR Capacitor Banks at Comstock Meadows, Chukar and Wild Horse Substations – The large load additions result in degradation to the area voltages. These capacitor banks are required to support the area voltage by providing reactive support to the 120 kV grid. Future 345/120kV transformers at either Comstock Meadows, Naniwa or Chukar depending upon where the loads materialize.
These upgrades are displayed in Figure 19 below:
4 Outages to Switch would still occur for a fault on the Dove to Comstock Meadows line but would be significantly reduced due to the 3-way motor-operated switch. This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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Figure 19: Inclusion of Upstream Transmission Upgrades in Master Plan
Comparison and Preferred Action Plan As shown in Figure 20 below, the individual plans for each load addition results in parallel facilities and upgrades that would not be required under a collaborative Master Plan for the entire Tracy Area. It also shifts cost responsibility to the Applicants given the individual plans are radial in nature and initially classified as High Voltage Distribution rather than Transmission. Below are the benefits provided by the Master Plan approach:
The rebuild of the Dove to Chukar line would not be required if the Dove to Fernley line is not folded into Chukar Substation. The 4.8 mile radial line to Switch could be extended to Comstock Meadows and eliminate the need for the 4.8 miles of the line between Dove and Comstock Meadows. It may also be a shorter route, reducing the overall line length and cost. In this configuration, redundant sourcing is provided to Comstock Meadows and Chukar Substation, but Switch is left radial out of Dove substation where a single contingency can drop up to 153 MW of load off the system.
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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Figure 20: Service to Tracy Area under Individual Service Options
The Master Plan approach follows the same methodology used in historical system planning. It creates a 120 kV sub-transmission loop around the load pocket with multiple hubs for sourcing pocket load. It also creates isolation between strong and weak areas of the system which reduces the quantity of facilities as well as provides redundant transmission sourcing to all substations within the network. This preferred action plan accomplishes the requirements of a networked system with increased transmission system reliability and the ability to analyze and perform predictive transmission maintenance. The Master Plan to the Tracy area load pocket with upstream transmission upgrades is displayed below in Figure 21.
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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Figure 21: Load Service to Tracy area under Master Plan for the Load Pocket
Incorporation of Reno Technology Park Load Growth in Tracy Area Master Plan Another consideration of master planning for the Tracy area is the growing Apple load in the RTP. The electrical connection north of Interstate 80 is stronger than the sourcing in the TRI-Center area. The electrical service to these loads is incorporated in the Tracy Area Master Plan, but are handled separately in some instances as the limitations are different. The overall 345 kV to 120 kV sourcing is shared by the two areas, but the 120 kV limitations are not due to the opposite directions of the loads from the Tracy generation hub.
Currently, the existing 100MW High Voltage Distribution Agreement with Apple is being amended to accommodate an additional 30 MW. No new facilities are required to provide the full 130 MW of service. In addition, Apple has proposed to construct a customer-owned substation to the west of their current substation capable of providing up to 250 MW of additional capacity. The service plans for Apple’s 250 MW have not yet been finalized. Consistent with this document, the RTP will be treated as a portion of the Tracy Area Load Pocket and the Master Plan will be modified for the future Apple phase. Figure 22 below illustrates a preliminary plan for the Apple Load growth within RTP.
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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Figure 22: Preliminary Load Service Plan for Apple Load Growth Cost Responsibility Summary Per NV Energy’s Tariff Rule 9 and internal policy, cost responsibility is determined for each project based on the classification of the proposed facilities and the minimum to serve requirement. Based on this, cost responsibility has been considered under both the Individual Service and the Master Transmission Plan scenarios.
In both scenarios, the Applicants are responsible for the costs of High Voltage Distribution facilities and the Utility is responsible for the costs of transmission facilities. The Master Plan assumes that a significant portion of the facilities supporting the 120kV looped network immediately will be classified as transmission investment, and funded by NV Energy. Under the Individual Service Option approach, while each Applicant would initially contribute the costs of constructing High Voltage Distribution facilities, when each buildout is complete these facilities will most likely be reclassified as transmission facilities. When this occurs, a refund mechanism will need to be devised to reimburse customers for investments later become classified as transmission infrastructure.5 This after-the-fact approach for each project results in inefficiency, confusion, and large and eventually unwarranted initial cost burdens on Applicants which together have the potential to hinder economic development in northern Nevada. The proposed Master Plan concept resolves these issues by classifying the proposed facilities as transmission facilities upfront.
5 Rule 9 does not provide a mechanism for this outside of a re-classification that is performed during the Cost True-up requirement. This has been done in the recent past for a capacitor bank that was initially paid for by a mine and a transmission terminal that was initially paid for by Apple at Pah Rah Substation that were later determined to be Transmission facilities. This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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Under the Master Plan, capital expenditures associated with the utility-funded transmission projects need to be planned for internally, financed and ultimately approved and included in the utility’s rates. The table in Figure 23 below shows the anticipated schedule of costs, including the savings potential, for the phases of the 120kV Master Plan.
In Service Date Project Phase Estimated Cost 2016 2017 2018 2019 2020 3/31/2018 Chukar Distribution Substation 11,132,000 2,100,000 5,692,400 3,339,600 3/31/2018 Dove to Chukar & Tesla Re-termination 6,063,700 1,819,110 4,244,590 5/31/2018 Dove to Switch site 6,824,400 1,706,100 5,118,300 5/31/2019 Switch/Wild Horse to Meadows Radial 10,608,600 3,713,010 6,895,590 12/31/2019 Chukar to Comstock Meadows & Meadows Re-termination 13,429,500 2,685,900 9,400,650 1,342,950 TOTAL 48,058,200 2,100,000 9,217,610 19,101,400 16,296,240 1,342,950
Figure 23: Schedule of Costs and Savings of Tracy Area Master Plan
The transmission revenues required to support this investment are shown in Figure 24 below by project. These revenues are based on the load requests from each of the customers. At full build out of the customer projects (468 MW), annual transmission revenues are estimated to be in excess of $13 million. The annual revenue requirement is estimated to be $5.2 million.
TRACY MASTER PLAN - TRANSMISSION VOLTAGE SERVICE (PRELIMINARY +/- 20% PLANNING ESTIMATES) Annual Estimated Applicant Transmission Annual Revenue Phase Description Load Service In Service Cost Share Utility Share Annual Margin Revenue Requirement TRI CENTER AREA 1 Tesla Service - Dove to Chukar, Chukar to Tesla Line 3/31/2018 6,749,700 686,000 6,063,700 21,336,775 4,600,000 848,918 2 Switch Radial Service - Dove to Switch 5/31/2018 7,344,500 520,100 6,824,400 19,839,727 4,270,000 955,416 3 Meadows Service - 120kV Radial 5/31/2019 11,108,700 500,100 10,608,600 19,404,194 4,180,000 1,485,204 4A Meadows Service - Comstock Meadows 120kV Substation, Loop 12/31/2019 13,804,500 375,000 13,429,500 - - 1,880,130 TRI CENTER AREA - SUBTOTAL 468 39,007,400 2,081,200 36,926,200 60,580,695 13,050,000 5,169,668
Figure 24: Potential Transmission Revenues
As indicated above, investment to serve the Tracy Area Load Pocket under the Master Plan approach provides a superior electrical solution for meeting the anticipated load growth in the next 1 to 3 years, results in absolute cost savings over the Individual Service Option approach and is supported by transmission revenues.
Schedule The proposed major load growth currently requires the installation of the first phase facilities in early 2018. It is expected that the entire 120kV transmission plan could be constructed in 24 to 36 months if the load materializes
This Master Plan does not face typical permitting timelines in its schedule. A significant benefit of this area is that the entire TRI Center Park has designated many of the transmission corridors that are planned for use. Additionally, NV Energy has identified and began the permitting process for many of the planned facilities that will make up the proposed Master Planned transmission network. As mentioned earlier, the majority of the outer loop easements have been acquired. A three year action plan is displayed in Figure 25. The timing of these project is based on the best information currently available. Schedule is subject to change based on customer schedules.
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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Figure 25: Three Year Action Plan for Tracy Area Master Transmission Plan Future Capacity Needs The Tracy Area 120 kV Master Plan is designed to meet the near term identified needs of the large load additions within the Tracy Area Load Pocket. NV Energy has also studied load requests in excess of the near term load requirements. Serving larger load amounts will required additional 345/120 kV transformation into the load pocket. East Tracy substation cannot accommodate more than two 345/120 kV transformers, so an alternative location is required. Transmission Planning has proposed installing one or more transformers at the Comstock Meadows site depending on the amount of additional load required. This would require a 345 kV line from East Tracy to Comstock Meadows as well as a possible 345 kV line from West Tracy to Comstock Meadows. These transmission upgrades are dynamic based on the needs of the customers in the loop. The key is that the transmission plan will be expandable to accommodate both the initial and future needs.
Another major factor is resource deficiency. The proposed transmission system has the capacity to deliver the energy to the load, but a lack of system generation and import capability is evident at additional load in excess of approximately 500 MW. For study purposes, Transmission Planning has simulated additional combustion turbines in the Tracy area as well as a new combined cycle plant at Valmy. Results in excess of the near term loading and the 120 kV loop are preliminary at this time and will require solutions from both transmission delivery and resource planning. These details will be analyzed if and when these customers pursue the increased load levels. At this time, these customers are pursuing the load amounts studied under the near term demand requirements.
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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Figure 26 displays a detailed single line diagram of the Tracy Area Master Transmission Plan as wells the potential 345 kV upgrades between West Tracy, Comstock Meadows and East Tracy. This design is also consistent with long term plans for Westside Tie that will provide additional sourcing to both the Carson City and Reno load pockets.
This document contains non-public transmission information subject to FERC Standards of Conduct. Accordingly, it must not be shared with marketing function employees and external stakeholders.
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. : Detailed Single Line Diagram of TracyPlan of Master Area Diagram Line 26: Detailed Single Figure
31
Page | This document contains non-public transmission information subject to FERC Standards of Conduct. of Conduct. Standards FERC to subject information transmission non-public contains This document with shared be must not it Accordingly, stakeholders external and employees function marketing
Page 143 of 236
EXHIBIT BERDROW-DIRECT- 4
Page 144 of 236 Exhibit-Berdrow-Direct-4
AMENDED AND RESTATED RULE 9, SECTION B.2 HIGH VOLTAGE DISTRIBUTION AGREEMENT AGREEMENT NO. 16-00042
Between
SIERRA PACIFIC POWER COMPANY D/B/A NV ENERGY
And
SWITCH, LTD.
Execution Copy Page 145 of 236 Amended and Restated Rule 9, Section B.2 High Voltage DistributionExhibit-Berdrow-Direct-4 Agreement
Table of Contents
Article 1 Service to the Development ...... 3 1.1 Identification of Facilities ...... 3 1.2 Project Scoping Document Based on Minimum Requirements to Serve ...... 3 1.3 Estimated Power To Be Used by the Development ...... 3 1.4 Risk of Single-Source Failure ...... 3 1.5 Change in the Development’s EFBPL ...... 4 1.6 Customer Specific Facilities Charge ...... 4 1.7 Other Services Provided by Utility ...... 5 1.8 Providing Service to Applicant ...... 5 1.9 Amendment and Restatement of Original Agreement ...... 5
Article 2 Scope of Work; Coordination of Activities; Design ...... 5 2.1 Utility’s Scope of Work ...... 5 2.2 Applicant’s Scope of Work ...... 6 2.3 Non-Interference with Utility's Construction and Operation ...... 6 2.4 [INTENTIONALLY OMITTED] ...... 7 2.5 Ownership of Facilities...... 7 2.6 Utility Design Development...... 7
Article 3 Property Rights ...... 8 3.1 Property Rights Applicant Must Grant to or Acquire for Utility ...... 8 3.2 Ongoing, Blanket Non-Exclusive Easement for Ingress, Egress and Access .... 9 3.3 Condition Precedent to Commence Construction ...... 9
Article 4 Identification and Resolution of Conflicts; Costs Associated with Conflicts ...... 9 4.1 Identification of Conflicts...... 9 4.2 Resolution of Conflicts with Utility’s Facilities and Payment of Costs ...... 9 4.3 Resolution of Conflicts with Utility’s Rights and Payment of Costs ...... 10 4.4 No Obligation to Perform Obligations ...... 10
Article 5 Acquisition and Support of Permits ...... 10 5.1 BLM Right-of-Way Grant(s)...... 10 5.2 Permits for the High Voltage Distribution...... 10 5.3 Applicant’s Support...... 10
Article 6 Target In-Service Date ...... 10 6.1 In-Service Date(s)...... 10 6.2 Schedule; Constraints...... 11
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014)
i Execution Copy Page 146 of 236 Amended and Restated Rule 9, Section B.2 High Voltage DistributionExhibit-Berdrow-Direct-4 Agreement
Article 7 Applicant’s Additional Obligations ...... 11 7.1 Load Schedule ...... 11 7.2 Compliance with Laws and Other Standards ...... 11 7.3 Obligation to Provide Documents and Information to Utility ...... 11 7.4 Disclosing the High Voltage Distribution Route ...... 12 7.5 Reduction of Service or Termination Charges; Security ...... 12 7.6 Information Provided by and Needed from Applicant ...... 12 7.7 Modification or Relocation of Electric Facilities ...... 13
Article 8 Total Costs; Initial Payment; Allowance; Invoicing; True-Ups; Interest ...... 13 8.1 Total Costs...... 13 8.2 Utility Betterment...... 13 8.3 HVD Allowance ...... 13 8.4 Proportionate Share...... 14 8.5 Initial Payment...... 14 8.6 Condition Precedent to Utility’s Obligation to Perform ...... 14 8.7 Performance of True-Ups; Refunds/Invoices...... 14 8.8 Payment Arrangement; Invoicing...... 15 8.9 Interest...... 16 8.10 [INTENTIONALLY OMITTED] ...... 16 8.11 Reassessment of Applicant Risk Profile...... 16 8.12 Audited Financial Statements...... 16 8.13 Right to Review Records...... 17
Article 9 Term and Termination ...... 17 9.1 Term of Agreement...... 17 9.2 Termination of Project by Applicant or Mutual Agreement ...... 17 9.3 Termination of Project by Utility ...... 17 9.4 Surviving Obligations ...... 17 9.5 Taking Reasonable Actions to Mitigate Total Costs ...... 18
Article 10 Default ...... 18 10.1 Procedure...... 18
Article 11 Force Majeure ...... 18 11.1 Notice of Force Majeure Event...... 18 11.2 Duty to Mitigate Effects of Delay ...... 18 11.3 Notice of Resumption of Performance...... 19 11.4 Liability; Termination Option ...... 19
Article 12 Hazardous Materials ...... 19 12.1 Work Suspension ...... 19
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014)
ii Execution Copy Page 147 of 236 Amended and Restated Rule 9, Section B.2 High Voltage DistributionExhibit-Berdrow-Direct-4 Agreement
12.2 Notifying Governmental Authority ...... 19 12.3 Remediation or Termination ...... 19 12.4 Remediation Requirements ...... 19
Article 13 Insurance and Indemnification ...... 20 13.1 Insurance...... 20 13.2 Indemnity...... 20
Article 14 Dispute Resolution ...... 21 14.1 Dispute Resolution Process...... 21 14.2 Exercising Rights after 10-Business-Day Period...... 21
Article 15 Representations ...... 21 15.1 Utility’s Standing in Nevada...... 21 15.2 Applicant’s Standing in Nevada...... 21 15.3 Authority...... 21
Article 16 Additional Provisions ...... 22 16.1 Notices...... 22 16.2 Utility’s Tariff Schedules; Commission ...... 22 16.3 Integration...... 23 16.4 Assignment...... 23 16.5 Limitation of Damages...... 23 16.6 [INTENTIONALLY OMITTED]...... 23 16.7 Choice of Law and Venue...... 23 16.8 No Waiver ...... 24 16.9 Independent Contractor...... 24 16.10Interpretation ...... 24 16.11Amendments...... 24 16.12No Third-Party Beneficiaries...... 24 16.13Remedies...... 24 16.14Headings; Exhibits; Cross References...... 24 16.15Discretion...... 25 16.16Severability...... 25 16.17Counterparts...... 25 16.18Performance of Acts on Business Days...... 25 16.19[INTENTIONALLY OMITTED]...... 25 16.20Jury Trial Waiver...... 25
Article 17 Definitions ...... 26 17.1 Terms Defined in Rule 1...... 26 17.2 Terms Defined in Rule 9...... 26
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014)
iii Execution Copy Page 148 of 236 Amended and Restated Rule 9, Section B.2 High Voltage DistributionExhibit-Berdrow-Direct-4 Agreement
17.3 Additional Definitions...... 26
Exhibit A Contact Information Exhibit B-1 Estimated Cost Exhibit B-2 Payment Schedule Exhibit B-3 Allowance Schedule Exhibit B-4 Customer Specific Facilities Charge Exhibit B-5 Example Calculation of RSTC Calculation Exhibit B-6 Load Schedule Exhibit C-1 One-line Exhibit C-2 [INTENTIONALLY OMITTED] Exhibit C-3 Utility-Owned Facilities Design Exhibit C-4 [INTENTIONALLY OMITTED] Exhibit D-1 Legal Description of Site Exhibit D-2 Form Grant of Easement Exhibit D-3 Form Right of Entry Exhibit D-4 Form Transmission Use Agreements Exhibit E Insurance Coverages Exhibit F Project Scoping Document Exhibit G Project Schedule
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014)
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This Rule 9, Section B.2 High Voltage Distribution Agreement (“Agreement”) is entered into by and between Sierra Pacific Power Company, a Nevada corporation, d/b/a NV Energy (“Utility”) and Switch, Ltd., a Nevada limited liability company (“Applicant”) (individually, a “Party” and, collectively, the “Parties”). RECITALS (A) Utility owns and operates electric transmission and distribution facilities and provides electric service to the public in accordance with Tariff Schedules filed with and approved by the Commission. (B) Applicant and Utility are parties to the Engineering Services Agreement, with an effective date of June 16, 2015, contract number 15-00018. Applicant and Utility are also parties to the Rule 9, Section B.2 High Voltage Distribution Agreement dated August 12, 2016 (the “Original Agreement”). (C) On August 15, 2016, Applicant asked Utility to cease work under the Original Agreement; Utility ceased work. (D) The Parties desire to amend and restate the Original Agreement in order to reflect a change in the In-Service Date request by Applicant, Applicant’s current status as a direct access customer and modifications to the design of the Project and the cost responsibilities of the Parties. (E) Applicant requests sufficient capacity be installed to meet its electric needs, and Utility has a need to measure both the capacity to be provided to Applicant and Applicant’s expected load in both megavoltampheres (“MVA”) and megawatts (“MW”). Applicant has projected a build-out schedule and electric capacity requirements for its Development (See, Load Schedule, attached hereto as Exhibit B-6). Applicant estimates that it will require a total of 153.5 MVA of capacity from the Electric System, at an assumed 95% lagging power factor, So that the Estimated Full Build-out Project Load (“EFBPL”) of the Development is 153.5 MVA, or otherwise stated, 145.8 MW. Applicant requests that Utility provide Service to the Development based on Applicant’s projected capacity requirements through High Voltage Distribution. (F) Applicant represents that the Project Scoping Document accurately identifies Applicant’s capacity requirements and the facilities required to adequately accommodate those capacity requirements. (G) Applicant acknowledges that it may be required to pay Reduction of Service or Termination Charges, if any, in accordance with Rule 9, Section A.25. (H) Applicant has requested, after conducting and relying upon its own independent analysis, which it has determined to be most favorable to its needs, the Service described in Recital (C) and will:
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(1) Initially take Service for the Development under the GS-3 rate schedule, transmission voltage. Applicant acknowledges that it may be required to enter into a service agreement pursuant to taking Service under such schedule; if Applicant later opts for an alternate rate schedule, the parties will comply with the cost savings or obligations in the applicable rate schedule and Utility will account for Applicant’s Allowances as appropriate. (2) pay the Total Costs (which may change from time to time) in accordance with Rule 9, Sections A.3, A.11 and B.2, as further detailed on Exhibit B- 1; and (3) pay the Tax Gross-up, as further detailed on Exhibit B-1, in accordance with Rule 9, Section A.18 (as amended), subject to refund, pursuant to Rule 9, Sections A.18.f and A.32.c.(1). (I) Also after conducting and relying upon its own independent analysis, which it has determined to be most favorable to its needs, Applicant has determined that it wishes: (1) Utility to design, procure, construct, maintain and own the Utility-Owned Facilities; and (2) Applicant to design, procure, construct, maintain and own the Applicant- Owned Facilities. (J) Applicant acknowledges that it must pay a Customer Specific Facilities Charge for Utility to operate, maintain, modify, repair, and remove to replace the Utility- Owned Facilities and that, notwithstanding Section 16.11, the charge will be revised by the Commission in each Utility general rate case or similar ratemaking proceeding, unless modified. (K) Applicant acknowledges that it must follow Utility’s procedures for identifying and resolving conflicts between its Development and the Electric System and that Utility will only waive or approve a particular conflict through Utility’s standard use agreement signed by the property owner(s) and Utility, duly notarized, and recorded. (L) The Commission issued an order on December 28, 2016 in Docket No. 16-09023 authorizing Applicant to purchase energy, capacity and/or ancillary services from a provider of new electric resources pursuant to Nevada Revised Statutes (“NRS”) Chapter 704B. (M) Applicant intends to exercise the authority granted under NRS 704B and procure energy, capacity and/or ancillary services, including renewable energy. from an entity or entities other than Utility.
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(N) Pursuant to the Commission’s order in Docket No. 16-09023, any load growth at or expansion of the Development will be treated as ordinary load growth under NRS 704B. (O) Applicant acknowledges that this Agreement involves the construction of electric transmission and distribution facilities required for Utility to delivery electricity to Applicant and does not govern the supply of electricity to Applicant. In accordance with Rule 9 and in consideration of the above recitals, the mutual covenants and the terms and conditions contained in this Agreement, the Parties agree as follows: AGREEMENT Article 1 Service to the Development 1.1 Identification of Facilities. The project scoping document dated May, 2017, which is based on information provided by Applicant, is attached hereto as Exhibit F (“Project Scoping Document”) and identifies those facilities required to adequately accommodate the EFBPL, based on the amount of capacity requested by Applicant, and certain facilities Applicant must install on its side of the Point of Delivery. The Project Scoping Document, however, does not reserve electrical capacity on Utility’s electric system for the Development. Additional facilities might be required for Service to the Development that the Project Scoping Document does not identify, including but not limited to additional substation facilities, communication facilities, High Voltage Distribution and distribution facilities, provided Applicant does not assume financial responsibility for such facilities unless required to do so under the Tariff Schedules. 1.2 Project Scoping Document Based on Minimum Requirements to Serve. The Project Scoping Document is based on the Minimum Requirements to provide Service to the Development. 1.3 Estimated Power To Be Used by the Development. Based on information provided by Applicant, Applicant and Utility agree that the EFBPL is 153.5 MVA of capacity, which is 145.8 MW of potential load at an assumed 95% lagging power factor. This requires Utility to modify and extend its existing Electric System to provide 153.5 MVA of electrical capacity (at an assumed 95% lagging power factor). 1.4 Risk of Single-Source Failure. Applicant acknowledges that, after conducting and relying upon its own independent analysis (which it has determined to be most favorable to its needs), it has decided that the HVD will provide all of the Service (including backup) to the Development. Applicant also acknowledges that the Development will not receive Service through any other Utility electric facilities and, as a result, a single-source failure might occur which could result in an outage of undeterminable length to the Development. Utility’s may expand transmission
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facilities in a manner that would avoid a single-source failure, however, such expansion is not guaranteed and the timing of any expansion is unknown. 1.5 Change in the Development’s EFBPL. To the extent actual build-out load varies from the expected EFBPL, the Parties agree as follows: (A) If the actual build-out load, or if Applicant’s alteration to the Project load requirements, exceeds 145.8 MW at an assumed 95% lagging power factor, or drops below twenty-five percent (25%) of the foregoing, this is considered a change (“Change”). (B) The Parties agree to meet within thirty (30) business days after Applicant provides Utility with written notice of a Change, or Utility determines (in its discretion) that a Change has occurred, to evaluate what impact the Change has, if any, on Utility’s electric system or the facilities required to provide Service to the Development and consequently on the Development’s actual Service requirements. Based on the Change, then- current EFBPL and then-current Load Schedule, the Parties agree to modify this Agreement so that it is mutually satisfactory to both Parties within thirty (30) business days of meeting or within thirty (30) business days of the Parties agreeing to amend this Agreement, whichever date is later. However, Utility reserves the right to determine that a new Rule 9 Agreement is required because the Change cannot be addressed adequately or in a timely manner by amending this Agreement. Utility is under no obligation under this Agreement or otherwise to provide Service to the Development of more than 153.5 MVA of capacity at an assumed 95% lagging power factor, until after the Parties sign the amendment(s) (or a new Rule 9 Agreement) and Applicant pays the Total Costs associated with the Change. Applicant must not use or take more than 153.5 MVA of capacity at an assumed 95% lagging power factor, from Utility’s electric system until after Utility’s electric system is modified in accordance with the amendment(s). The then-current Rule 9 will apply to any new Rule 9 Agreement signed by the Parties pursuant to this Subsection (B). 1.6 Customer Specific Facilities Charge. Applicant must pay a Customer Specific Facilities Charge (defined below) for Utility to operate, maintain, modify, repair, and remove to replace the Utility-Owned Facilities. After the Project is Construction Complete, Utility will add the initial CSFC identified in Exhibit B-4 to the periodic electric bill for the Development. Notwithstanding Section 16.11, the CSFC Applicant must pay will be modified by Utility when it performs the true- ups described in Section 8.6 and from time to time as approved by the Commission in each Utility general rate case or similar ratemaking proceeding. After Utility or the Commission modifies the CSFC, Utility will send Applicant a courtesy notice that the CSFC has changed. Applicant acknowledges that some or all of the CSFC is based on estimated Total Costs or estimated expenses, that such estimates do not
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constitute errors or omissions and that Utility will not retroactively adjust billings that contained a CSFC to account for a modification to the CFSC. A “Customer Specific Facilities Charge” or “CSFC” means a Tariff-Schedule-based, ongoing payment that Utility places on Applicant’s periodic electric utility bill (usually monthly) for the Development that enables Utility to recover its investment and ongoing operation, maintenance, modification, repair and remove to replace expenses associated with the Utility-Owned Facilities. 1.7 Other Services Provided by Utility. If Utility provides other services to Applicant, such as the delivery of temporary electric energy to the Development, the construction of additional electrical facilities, if required, will be performed in accordance with applicable Law, the Tariff Schedules, Rule 9 (as amended) and Utility’s procedures. Any other services that may be provided to Applicant are not within the scope of this Agreement. 1.8 Providing Service to Applicant. Utility will provide Service to the Development in accordance with the Project Scoping Document, this Agreement, applicable Laws and the Tariff Schedules. If this Agreement terminates and Applicant is not in default, Utility will make capacity available to the Development up to 153.5 MVA at an assumed 95% lagging power factor. However, if Applicant is not using all of that capacity after this Agreement terminates, Utility (in its discretion) may permanently reallocate the unused capacity, subject to Section 1.5. Notwithstanding this, Utility will give written notice to Applicant regarding Applicant’s capacity usage or lack thereof, and the parties will discuss alternatives to permanently reallocating the unused capacity, without limiting Utility’s right to reallocate unused capacity. If rule, regulation or law is amended during the term of this Agreement to permit the Utility to reserve electric system capacity or meet Switch’s capacity needs in amounts or for periods greater than currently permitted, the Parties will negotiate in good faith to amend this Agreement to be consistent with the amended rule, regulation or law in this respect. 1.9 Amendment and Restatement of Original Agreement. Upon full execution and delivery of this Agreement, the Original Agreement shall be deemed to be completely amended, restated and superseded by this Agreement. Article 2 Scope of Work; Coordination of Activities; Design 2.1 Utility’s Scope of Work. Utility will, at Applicant’s Total Cost, perform (or cause to be performed) the following in connection with this Agreement in accordance with Good Utility Practice: (A) Perform engineering, survey, right-of-way work, potholing, soil exploration, testing, and other work in order to prepare the UOF Design in accordance with Utility’s Standards, the Tariff Schedules and the One-line. (B) Prepare the UOF Design, identifying all known Contingent Facilities.
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(C) Research Property Rights and prepare Property Rights documents that Utility, in its discretion, determines are necessary in connection with the Project. (D) Procure equipment and materials for the Project. (E) Coordinate the acquisition of Permits required for the Project, including, but not limited to, those for dust control, grading, stormwater, special use and/or highway crossing and those for construction, operation and maintenance of the Utility-Owned Facilities. (F) Install the Utility Facilities in accordance with the UOF Design and One- line and perform construction work in connection with the Project. (G) Test and commission the Utility Facilities. (H) Perform other work Utility determines is necessary to complete the Project after Applicant agrees it is necessary, which agreement shall not be unreasonably withheld, conditioned or delayed. (I) Utility and Applicant will work together in good faith to identify the most efficient, cost effective and expeditious solutions. 2.2 Applicant’s Scope of Work. Applicant will, at Applicant’s expense, perform (or cause to be performed) the following in connection with the Project: (A) Support Utility in acquiring and comply with all Permits required for the Project, including, but not limited to, those for dust control, grading, stormwater, special use and/or highway crossing and those for construction, operation and maintenance of the Utility-Owned Facilities. (B) Acquire Permits required for improvements and facilities being constructed by Applicant. (C) Grant, convey and/or acquire and convey to Utility all Property Rights in accordance with Article 3. (D) Provide and maintain access roads to all electrical and communication facilities being installed in connection with this Agreement. (E) Design, procure and construct the Applicant-Owned Facilities (as shown generally in the One-line) in accordance with all Laws and the Tariff Schedules. (F) Perform the above described scope of work in accordance with the Schedule, which may change from time to time as necessary. 2.3 Non-Interference with Utility’s Construction and Operation. Subject to Applicant’s safety and security protocols, Applicant’s construction and installation of the Improvements and/or its Development must not interfere with Utility’s
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construction, operation and maintenance of the HVD or other facilities Utility is installing in connection with the Project. If Applicant’s activities do interfere, Applicant must take all steps necessary (at Applicant’s Total Cost) to stop the interference and remedy it so that Utility’s construction, operation and maintenance activities can continue without conflict. For example, if Applicant’s activities interfere with Utility’s ability to access the HVD, Applicant must provide a secure travel way with access for Utility. 2.4 [INTENTIONALLY OMITTED]. 2.5 Ownership of Facilities. (A) Ownership of Utility-Owned Facilities. All Utility-Owned Facilities are property owned and controlled by Utility. Utility (not Applicant) owns all material and equipment Utility ordered for the Project for use on Utility’s side of the Point of Delivery. (B) [INTENTIONALLY OMITTED]. (C) Use of Utility-Owned Facilities. Utility has the right to use the Utility- Owned Facilities for any purpose, including to provide electric service to any Customer. Utility may also allow third parties to use Utility-Owned Facilities if Utility is required to do so by the federal Telecommunications Act or other applicable Laws. (D) [INTENTIONALLY OMITTED]. 2.6 Utility Design Development. (A) Preparing the UOF Design. Based on information provided by Applicant and in accordance with Utility’s Standards and Good Utility Practice, Utility will prepare the UOF Design. Applicant must confirm in a writing reasonably acceptable to Utility that the UOF Design does not conflict with Applicant’s Development. After finalizing the UOF Design, Utility must notify Applicant in writing that the UOF Design is final and that Utility is attaching it to this Agreement as Exhibit C-3. (B) Updating Agreement Exhibits. Notwithstanding Section 2.6(A) or Section 16.11, Utility may (in its discretion) modify the UOF Design. However, if Utility must revise the UOF Design as a result of a Utility error or omission, Utility will bear the expense of revising the particular design. Utility must notify Applicant in writing that the UOF Design has changed, the reason for the change, provide Applicant with a copy of the updated UOF Design and must notify Applicant that the particular design replaces those attached previously to the Agreement as Exhibit C-2 and/or Exhibit C-3. (C) Ownership of Design of Utility-Owned Facilities. Applicant acknowledges and agrees that, if Utility produces (or causes to be produced) the UOF
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Design, Utility is and will be the sole and exclusive owner of all right, title and interest to, including all intellectual property rights in and to, that design (including that which may qualify as “works for hire”) under United States copyright law and comparable laws worldwide – whether or not that design was developed by Utility individually or jointly with Applicant. Any UOF Design is deemed Utility’s proprietary information and is subject to applicable confidentiality terms herein. (D) [INTENTIONALLY OMITTED]. (E) Disclaimer of Warranty(ies). With respect to the UOF Designs (and any modified UOF Designs) and unless expressly stated otherwise in this Agreement, UTILITY MAKES NO WARRANTIES, EXPRESS OR IMPLIED, AND EXPRESSLY DISCLAIMS ALL IMPLIED WARRANTIES, including any implied warranty of merchantability or fitness for a particular purpose. Article 3 Property Rights 3.1 Property Rights Applicant Must Grant to or Acquire for Utility. (A) Applicant’s Obligation to Grant and Convey Property Rights. Applicant must, without expense to Utility, grant and convey (or use Commercially Reasonable Efforts to obtain for Utility) all Property Rights that Utility deems it requires for the HVD components of the Project. The type, location and form of the Property Rights must be satisfactory to Utility (including, but not limited to, the dimensions of the Property Rights area and terms and conditions relating to the Property Rights). If Applicant cannot obtain one or more Property Rights, Utility (at Applicant’s Total Cost) will, if permitted by applicable Law, acquire those Property Rights so that the type, location and form are satisfactory to Utility (including, but not limited to, the dimensions of the Property Rights area and terms and conditions relating to the Property Rights). (B) Form of Easements. Applicant must grant and convey, and cause third parties to grant and convey, all easements required under Section 3.1 to Utility in the form attached as Exhibit D-2. (C) Form of Rights of Entry. Applicant must grant and convey, and cause third parties to grant and convey, all rights of entry required for the HVD components of the Project to Utility in the form attached as Exhibit D-3, if any. (D) Form of Use Agreements. Applicant must execute, and cause third parties to execute, Transmission Use Agreements and Distribution Encroachment Agreements to Utility in the form attached as Exhibit D-4.
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(E) Timing of Easements. The parties will work together to to obtain easements for Utility before any required street dedication(s), if any. (F) Appraisals. In Utility’s discretion and at Applicant’s Total Cost, Utility may obtain an appraisal(s) of the Property Rights. 3.2 Ongoing, Blanket Non-Exclusive Easement for Ingress, Egress and Access. Subject to the Access Plan, and Applicant’s safety and security protocols, Applicant grants to Utility and its employees, representatives, contractors and assigns that have been certified or are escorted (and will cause any Affiliate to grant to Utility and its employees, representatives, contractors and assigns) the right of access, ingress and egress over and across portions of the Site and any other property owned or controlled by Applicant (or any Affiliate) as necessary for Utility to carry out its obligations under this Agreement and to operate, add to, maintain and modify the Utility-Owned Facilities. Applicant must not obstruct or otherwise interfere with these rights. 3.3 Condition Precedent to Commence Construction or to Provide Service. Utility is not obligated to commence construction of any facilities, provide (or continue providing) Service to the Development or otherwise perform its obligations under this Agreement until Applicant signs the Agreement, pays the Initial Payment and after the required Property Rights are permanently granted to Utility in a manner that is satisfactory to Utility as to type, location and form (including but not limited to the dimensions of the Property Rights area and terms and conditions relating to the Property Rights). Article 4 Identification and Resolution of Conflicts; Costs Associated with Conflicts 4.1 Identification of Conflicts. Applicant must identify, in writing and in a manner satisfactory to Utility, all known conflicts, if any, between (A) the Development and the Electric System located within the Development, (B) the Development and the Electric System located within or adjacent to offsite improvements required for the Development, (C) the Development and the Electric System located adjacent to the Development, and (D) the Development and Utility’s Property Rights within and adjacent to the Development. 4.2 Resolution of Conflicts with Utility’s Facilities and Payment of Costs. If Applicant, its agents, its contractors, or its subcontractors damage, have damaged, render unsafe or have rendered unsafe the Electric System located within or adjacent to the Development or to the offsite improvements required for the Development, Applicant must (A) pay all costs to render those facilities safe, to relocate the facilities impacted, or to construct any new facilities needed and (B) provide Property Rights in Utility’s name for the relocated facilities and/or new facilities, at no cost to Utility and in a location and form satisfactory to Utility (including but not limited to the type of Property Rights, the dimensions of the Property Rights area, and terms and conditions of the Property Rights).
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4.3 Resolution of Conflicts with Utility’s Rights and Payment of Costs. If Applicant, its agents, its contractors, or its subcontractors interfered with Utility’s Property Rights, Applicant must (A) pay all costs incurred by Utility that are associated with the interference and (B) either remove the interference and return the Property Rights area to a condition that is usable by Utility or provide or obtain replacement Property Rights in Utility’s name, at no cost to Utility and in a location and form satisfactory to Utility (including but not limited to the type of Property Rights, the dimensions of the Property Rights area, and terms and conditions of the Property Rights). 4.4 No Obligation to Perform Obligations. Utility does not have an obligation to provide Service to the Development or perform its obligations under this Agreement until after Applicant meets its obligations under this Article to Utility’s reasonable satisfaction. Article 5 Acquisition and Support of Permits 5.1 BLM Right-of-Way Grant(s). If applicable, when necessary and at Applicant’s Total Cost, Utility will obtain any BLM Right-of-Way Grant(s), and any other federal-land Permits, required for the High Voltage Distribution, and perform work necessary to comply with conditions in these Permits, including but not limited to follow-up environmental work, obtaining federal-agency approval of work performed and preparing as-built survey plans. 5.2 Permits for the High Voltage Distribution. Utility, at Applicant’s Total Cost, will obtain all necessary Permits required for the construction, operation, modification and maintenance of the High Voltage Distribution and any other infrastructure Utility is installing and/or will own in connection with this Agreement, including but not limited to any land use permit(s) and any other required building or construction permits. 5.3 Applicant’s Support. Applicant, at its expense, must affirmatively use Commercially Reasonable Efforts to support all Utility’s Permit application(s). Applicant’s support may include writing letters of support to the applicable governmental authority, attending neighborhood meetings, executing documentation to support Utility’s request for the particular Permit, speaking on behalf of Utility at hearings at Utility’s request, and other actions reasonably requested to assist Utility in obtaining Permits Utility determines are required in connection with the Project. Article 6 Target In-Service Date 6.1 In-Service Date(s). Based on the load requirements provided by Applicant (including that Applicant will be ready to take Service on or before the date stated in Exhibit G, the In-Service Date(s) for the Utility Facilities is stated in Exhibit G.
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6.2 Schedule; Constraints. Except as otherwise provided in this Agreement, Utility will meet the In-Service Date for the HVD in accordance with the schedule attached to this Agreement as Exhibit G (“Schedule”). However, the Parties agree that the In- Service Date might not be achieved as a result of a delay caused by Applicant, a delay caused by a third party or a Force Majeure Event and, under such circumstances, Utility’s failure to meet the In-Service Date is not a Utility event of default. Applicant also acknowledges that completion of the Service to the Development is subject, without limitation, to (and the In-Service Date could be delayed by) the scheduling of required electrical outages (which may be limited by Electric System operational and maintenance requirements, as determined by Utility in accordance with Good Utility Practice), Utility’s obligations to its other Customers to ensure the reliability and safety of its Electric System and to adhere to applicable reliability criteria, all communications upgrades being completed and Applicant performing its obligations under this Agreement in a timely manner. Notwithstanding the foregoing, Utility will give Applicant as much written notice of such delay as soon as possible, but no less than three (3) business days written notice prior to the scheduled critical project milestones so that the parties may work together to expedite resolution of any delay causing issues. The three (3) business day deadline shall apply only if Utility has knowledge of the delay no less than three (3) business days prior to the critical project milestones. Article 7 Applicant’s Additional Obligations 7.1 Load Schedule. Not later than one month before the end of each calendar year, Applicant (or its successor) must deliver to Utility a forecast of anticipated capacity requirements in MVA for the Development for each of the succeeding five (5) calendar years, or time period appropriate to the Development’s known capacity utilization plan (“Load Schedule”). The Load Schedule must be in the form attached hereto as Exhibit B-6. This Agreement and the EFBPL may not and shall not be used as evidence of Applicant’s load to support any impact or exit fee as contemplated by NRS 704B or subsequent or federal law that permits Applicant to purchase power from an entity other than Utility. It will be Applicant’s burden to prevent this Agreement and the EFBPL from being used by any other entities for that purpose. 7.2 Compliance with Laws and Other Standards. Utility, Applicant and their respective contractors, employees and agents will comply with all applicable Laws, Permits, Tariff Schedules, Utility Standards, where applicable, and the National Electrical Safety Code. 7.3 Obligation to Provide Documents and Information to Utility. Within ten (10) business days of Utility’s written request, Applicant must provide information and documents reasonably required by Utility to fulfill its obligations under this Agreement. Applicant must also provide Utility with the information and documents more specifically identified below, subject to applicable Law.
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(A) Information Concerning Property on Which the High Voltage Distribution Will Be Located. Within ten (10) business days of Utility’s request, Applicant must provide Utility with copies of all relevant and necessary documents that are in Applicant’s possession or control relating to the property on which the Utility Facilities will be located, including but not limited to: current leases, contracts and permits, current or not; environmental reports; appraisal reports; plans, permits, maps, and approvals; boundaries and topographical surveys; soils and engineering reports; governmental zoning letters; and any other documents Utility reasonably deems necessary to evaluate the property. (B) Value of Property Rights. Within ten (10) business days of Utility’s request, Applicant must provide Utility with all relevant and necessary information and documentation relating to the value of the Property Rights, including but not limited to the value of the easements and the amount(s) Applicant paid, if any, for third-party Property Rights. 7.4 Disclosing the High Voltage Distribution Route. Applicant must disclose the route of the High Voltage Distribution to a subsequent purchaser of real property within the Site. 7.5 Reduction of Service or Termination Charges; Security. Within sixty (60) days of receiving written notice from Utility and in accordance with Rule 9, Section A.23 and Rule 9, Section A.25, Applicant must pay a Reduction of Service or Termination Charge and/or provide Security in a form acceptable to Utility. An example calculation of the RSTC calculation that drives the Security requirement is attached as Exhibit B-5. 7.6 Information Provided by and Needed from Applicant. Applicant acknowledges that Utility relies on information provided by Applicant when performing Utility’s obligations under this Agreement. Applicant acknowledges that it has a continuing obligation to provide the most current and accurate information concerning its Development to Utility and to notify Utility of any material inconsistencies between the UOF Design and facilities constructed (or being constructed) for the Project and/or the Property Rights for those facilities. Applicant also understands that neither Applicant nor Utility is aware of and cannot know all surface and subsurface field conditions. Notwithstanding anything to the contrary in this Agreement, Applicant agrees to assume all responsibilities, liabilities, and Total Costs for repair, replacement, redesign, modification, relocation or other work to the facilities constructed, or being constructed, for the Project: (A) Resulting from or arising out of incomplete, inaccurate or outdated data and other information supplied to Utility as created by Applicant; or
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(B) Resulting from or arising out of changes affecting the accuracy or completeness of data or information after it is supplied to Utility by Applicant; or (C) Resulting from or arising out of surface or subsurface field conditions; or (D) That were installed at the request of Applicant outside the Property Rights intended for such facilities. 7.7 Modification or Relocation of Electric Facilities. Where Applicant has requested that Utility install electric facilities before the establishment of final grade or the alignment of roads, streets, or alleys, or in unimproved areas and a conflict arises, Applicant must (A) pay all Total Costs associated with the relocation or modification of any electric facilities and (B) grant or obtain for Utility (at no expense to Utility) all Property Rights Utility deems it requires for the relocated/modified facilities, in accordance with Rule 9, Sections A.6 and A.10. The Property Rights must be granted to Utility in a manner that is satisfactory to Utility as to type, location and form (including but not limited to the dimensions of the Property Rights area and terms and conditions relating to the Property Rights). 7.8 [INTENTIONALLY OMITTED]. Article 8 Total Costs; Initial Payment; Allowance; Invoicing; True-Ups; Interest 8.1 Total Costs. Except as otherwise specifically provided in Rule 9, Applicant has Total Cost responsibility for the HVD portion of the Project. Rule 9, Section B.2.n requires Applicant to pay the Total Costs of the HVD, as shown on Exhibit B-1. The estimated Total Costs and associated Tax Gross-up are $587,204.00 (“Estimated Cost”). The actual Total Costs might be more or less than the Estimated Cost and it is possible that not all Total Costs are identified on Exhibit B-1; however, Applicant is required to pay the actual Total Costs and associated Tax Gross-up in accordance with Rule 9. The estimated total cost of the Project, including the portion of the cost allocated to Utility, is $7,411,604.00. 8.2 Utility Betterment. (A) Estimated Expense of Utility Betterment. The estimated expense for the Utility Betterment is $0 (“Betterment Expense”). Incremental Total Costs attributed to such utility Betterment shall be at the Utility’s cost. (B) Ownership of Betterment. The Design identifies any Utility Betterment. The Utility Betterment installed under this Agreement is property owned, maintained, and controlled by Utility. 8.3 HVD Allowance. The HVD being installed pursuant to this Agreement directly connects to Federal Energy Regulatory Commission jurisdictional transmission facilities and, therefore may qualify for a revenue-based HVD Allowance. Pursuant to Rule 9, Section B.2.g and Section B.2.h, the Maximum Allowance is $0. The
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Up-front Allowance being provided to Applicant is $0 as shown on Exhibit B-3. The allowances referenced here are based on the Load Schedule provided by Applicant per Rule 9, A.23.a.4 and the Total Costs as allocated to Applicant. 8.4 Proportionate Share. (A) Proportionate Share Refund. If a subsequent Rule 9 applicant attaches to the HVD facilities that are the subject of this Agreement, pursuant to Rule 9, Section A.16, Applicant shall be entitled to a Proportionate Share Refund, with the level of any Proportionate Share Refund dependent on several factors, including but not limited to the load and Point of Delivery of the subsequent Rule 9 applicant and the level of costs of the facilities that has been borne by Applicant, taking into account Allowances and Refunds. (B) Proportionate Share Allocation. If Applicant attaches to other line extensions, such as those identified in this Subsection, Applicant must pay a Proportionate Share Allocation: Contract No. Expiration Date Project Name None.
8.5 Initial Payment. When Applicant delivers the signed Agreement to Utility, Applicant must pay Utility Payment No. 1 as shown on Exhibit B-2, pursuant to Rule 9, Section A.17.b (“Initial Payment”). When calculating this payment, Utility applied any Up-front Allowance and any Proportionate Share Allocation. 8.6 Condition Precedent to Utility’s Obligation to Perform. Utility is not required to perform, or continue performing, its obligations under this Agreement until after it has received the Initial Payment. The Initial Payment will be deemed received upon wire or other digital confirmation of receipt from Utility’s bank. Even if Utility has performed or performs one or more of its obligations under this Agreement, Utility may stop performing (without liability to Applicant) and is not required to continue performing until after it receives the Initial Payment from Applicant. 8.7 Performance of True-Ups; Refunds/Invoices. (A) Allowance True-Up. Utility will perform an Allowance True-up in accordance with Rule 9, Sections A.31.b, A.31.c.1, A.32.b and B.2.g. (B) Total Cost True-Up. Utility will perform an initial Total Cost True-up and subsequent Total Cost True-ups in accordance with Rule 9, Sections A.31.b, A.31.c.2, A.32.b and B.2.e.2. (C) Refund or Invoice after Accounting Adjustments. After Utility performs the Allowance True-up and Total Cost True-up, Utility will either invoice Applicant or provide a Refund to Applicant in accordance with Rule 9, Sections A.24.c, A.31.b, A.31.c.1, A.32.b and B.2.g. In accordance with
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Rule 9, Sections A.31.b.2, A.31.c.1 and A.31.e, Utility will perform more than one Allowance True-up and/or send Applicant an invoice(s) or Refund for Total Cost items that were finalized or became known after the original Total Cost True-up. The maximum possible Refund that Applicant may receive is the lesser of the Advance Subject to Potential Refund or the portion of the Allowance supported by the EFBPL that materializes during the term of this Agreement. (D) No Refunds after Agreement Termination. Pursuant to Rule 9, Sections A.7.b, A.17.e, A.32.a.4 and B.3.g, Applicant will not be entitled to any Refunds for load that materializes after this Agreement terminates. 8.8 Payment Arrangement; Invoicing. (A) Payment Arrangement. In accordance with Rule 9, Section A.26, Applicant has requested and Utility has agreed to an alternative payment arrangement for payment of required Advances. (B) Invoicing and Applicant’s Obligation to Pay Invoices. After receiving the Initial Payment and in accordance with Rule 9, Section A.26, Utility will invoice Applicant in accordance with the payment schedule attached as Exhibit B-2 and may periodically invoice Applicant for its Total Cost obligations and associated Tax Gross-up under this Agreement. Applicant must pay all invoices, even if Utility sends Applicant an invoice after Utility performed a Total Cost True-up and even if Utility sent a refund or returned an overpayment, provided Utility complied with Rule 9, any applicable side letters or agreements, Section A.31.e.3 and subject to Applicant’s right to review records under Section 8.13. (C) Deadline to Pay Invoices. Except for the invoice for the Initial Payment which is due when Applicant delivers the signed Agreement to Utility, Applicant must pay Utility’s invoices within sixty (60) days of receipt. Utility must send all invoices to Applicant by email to [email protected], which invoices will be deemed received by Applicant three (3) days after the date of the email. When making a payment, Applicant must follow the instructions regarding payment process on the particular invoice. If Utility does not receive timely payment of its invoices, then Utility must provide Applicant with written notice and three (3) business days to cure. Subject to the dispute resolution process in Section 14.1, Utility, without liability to Applicant, may stop work on the Project, not provide Service to the Development or terminate Service to the Development until after Utility receives payment in full. Any delay in payment might result in a delay in completion of the Project or delay the In- Service Date(s). If Applicant disputes all or a portion of an invoice, Applicant must pay the invoice, including any disputed portion, when due
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and thereafter may file a complaint with the Commission in accordance with Rule 14 of the Tariff Schedules if the Parties have not resolved the disputed portion. (D) Suspending Performance Because of Non-Payment. If after the applicable written notice and cure period, Applicant does not pay an invoice within sixty (60) days after receiving it, Utility (without liability to Applicant) may suspend performance of its obligations. (E) Unilaterally Updating Certain Exhibits; Impact on Total Cost Obligations. Utility may unilaterally update the Estimated Cost identified in Section 8.1, Exhibit B-1, Exhibit B-2, Exhibit B-3 and Exhibit B-4 and must provide Applicant with a copy of the particular revised exhibit, subject to reasonable justification of such increase. The Parties agree that, notwithstanding Section 16.11, these revisions will not require Applicant’s signature for them to be incorporated into and amend this Agreement and have binding effect. Applicant acknowledges that changes to these exhibits will affect Applicant’s Total Cost obligations and could increase the Total Costs and associated Tax Gross-up. 8.9 Interest. Any amount unpaid and due by Applicant under this Agreement will accrue interest at the then current per annum simple prime rate, as published in the Market Data section of the Wall Street Journal, plus one percent (1%), from the original due date through the date of receipt of payment by Utility. However, Utility will not pay Applicant any interest on the amount of any payment made in connection with this Agreement. 8.10 [INTENTIONALLY OMITTED]. 8.11 Reassessment of Applicant Risk Profile. In accordance with Rule 9, Section A.23.a.3, Utility may upon its own initiative perform a reassessment of Applicant’s Risk Profile and increase or reduce Security Requirements to reflect changes in circumstances during the term of the Agreement to secure the Up-front Allowance being provided to Applicant and to ensure Applicant’s payment of any balance due resulting from RSTC. 8.12 Audited Financial Statements. Within ten (10) business days of Utility’s written request, Applicant must provide summary financial statements (in a form consistent with what Applicant provided previously to Utility) from the most recently completed fiscal year that have been audited within the last twelve (12) months and any following unaudited statements up to the time of Utility’s request. If Applicant fails to provide this information by the end of that 10-business-day period, its classification with the Utility will default to high credit risk and Utility may require Applicant secure payment of any potential RSTC.
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8.13 Right to Review Records. Applicant has the right to review documentation related to Project costs for which Applicant is responsible at Utility’s office during Utility’s regular business hours with at least five (5) business days prior written notice of a request to review such documentation. For Applicant to review confidential supplier or contractor information, the Parties have entered into a written agreement protecting the non-disclosure and confidentiality of such information dated December 21, 2016 (“NDA”). Applicant may review confidential supplier or contractor information at Utility’s office during Utility’s regular business hours with at least five (5) business days prior written notice of a request to review that information. Article 9 Term and Termination 9.1 Term of Agreement. This Agreement is effective on the Effective Date and will continue for a term of ten (10) years unless terminated earlier under this Agreement. 9.2 Termination of Project by Applicant or Mutual Agreement. Applicant may terminate the Project in a manner authorized in Rule 9, Section A.27. If Applicant terminates the Project, this Agreement will terminate thirty (30) days after Utility receives that termination notice unless Applicant identifies a later date in its written notice to Utility. If the Parties mutually agree to terminate the Project, the Parties will document that in writing and specify the date this Agreement terminates. 9.3 Termination of Project by Utility. Utility may terminate the Project in accordance with Rule 9, Section A.27.c or Section B.2.k.1. If Utility terminates the Project under Rule 9, Section A.27.c.2. or Rule 9, Section A.27.c.3, this Agreement will terminate after Utility provides Applicant with written confirmation that Utility met and conferred with Applicant, or made Commercially Reasonable Efforts to do so, and the termination will be effective on the date specified in that written confirmation. 9.4 Surviving Obligations. Any default or termination of this Agreement or excuse of performance for a Force Majeure Event or otherwise does not release Applicant from any liability or obligation to Utility for: (A) Obligations under Section 1.5, Section 1.6, Section 2.5(A), Section 7.5, Section 7.6, Section 8.10 and Section 12.3; (B) Obligations under Article 3; (C) Obligations under Article 4; (D) Obligations under Article 5; (E) Obligations under Article 12; (F) Obligations under Article 13; (G) Obligations under Article 14; and
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(H) Paying the Total Costs and associated Tax Gross-up, whether incurred before or after excuse of performance or a Party’s default or termination, and paying all Total Costs and associated Tax Gross-up that result from excuse of performance, termination or Applicant’s default. The provisions of Section 8.8, Section 8.9, Section 8.11, Section 8.12, Section 16.1, Section 16.2, Section 16.5, Section 16.6, and Section 16.19 continue to apply to this Section. 9.5 Taking Reasonable Actions to Mitigate Total Costs. At Applicant’s Total Cost, the Parties must take all reasonable actions to minimize the Total Costs associated with Agreement termination. These actions may include, but are not limited to, such things as stopping some or all Project work, completing the Project, cancelling material orders, stopping acquisition of Property Rights, completing the acquisition of Property Rights and dismissing condemnation lawsuits, if any. An action is not reasonable if it inhibits, prevents or otherwise negatively impacts Utility’s ability to provide electric service to its Customers – as determined by Utility in its discretion. Article 10 Default 10.1 Procedure. If a Party (“Defaulting Party”) fails to comply with the terms and conditions of this Agreement, within ten (10) days of receiving written notice of such failure from the other Party (“Non-Defaulting Party”), the Defaulting Party and Non-Defaulting Party must meet and cooperate in good faith to expedite a resolution of the breach in the manner forth in Article 14. If no resolution is reached and the failure continues for thirty (30) days after the meeting between the Defaulting Party and Non-Defaulting Party (or after this meeting was scheduled to occur), then the Non-Defaulting Party is entitled to declare the Defaulting Party in default and is entitled to all remedies authorized by law, with the exception that Utility’s failure to achieve any scheduled date that is dependent on Applicant’s or a third-party’s performance is not an event of default. However, Utility may only terminate or disrupt service to the Development in accordance with this Agreement, a Law, and/or the Tariff Schedules. Article 11 Force Majeure 11.1 Notice of Force Majeure Event. If a Force Majeure Event occurs or is anticipated, the affected Party must promptly notify the other Party in writing of the Force Majeure Event. This notice must include a description, cause and estimated duration of the Force Majeure Event. Regardless of the cause, Applicant’s failure or inability to pay some or all of the Total Costs is not a Force Majeure Event. 11.2 Duty to Mitigate Effects of Delay. The affected Party must exercise Commercially Reasonable Efforts to shorten, avoid, and mitigate the effects of the Force Majeure Event.
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11.3 Notice of Resumption of Performance. The affected Party must promptly notify the other Party in writing when the Force Majeure Event has ended and when performance will resume. 11.4 Liability; Termination Option. Utility is not liable to Applicant for Total Costs incurred as a result of any delay or failure to perform as a result of a Force Majeure Event. In accordance with Rule 9, Section A.27.c.4 and with prior written notice to Applicant, Utility may terminate this Agreement without liability to Applicant provided Utility, in consultation with Applicant, first determines the Force Majeure Event renders Project performance impossible or impractical. Article 12 Hazardous Materials 12.1 Work Suspension; Notifying Applicant. Upon discovery of a Hazardous Material or otherwise contaminated soil, water or environment at the work site, Utility will stop work and immediately notify Applicant’s Project Manager (“Section 12.1 Notice”) of the unacceptable site condition (“USC”). Utility will not continue work at that site, or continue with construction of the HVD, until after Applicant completes any remediation obligations in accordance with Section 12.4. 12.2 Notifying Governmental Authority. When required by Law as determined by Utility, Utility will notify the appropriate governmental authority(ies), such as but not limited to the Nevada Division of Environmental Protection, (collectively, “NDEP”) of the USC. 12.3 Remediation or Termination. At its option, Applicant may either remediate the USC at its Total Cost or terminate this Agreement. Within five (5) business days after the date identified on Utility’s Section 12.1 notice, Applicant must provide Utility with written notice of its decision to remediate or terminate (“Section 12.3 Notice”). If, following written notice to Applicant, Applicant does not provide Utility with this notice in a timely manner, then Utility (without liability to Applicant) may terminate this Agreement. Even if Applicant or Utility terminates this Agreement, Applicant is responsible for paying all Total Costs and expenses associated with the discovery of a USC and any required remediation so that Utility does not bear any Total Costs and expenses in connection with the foregoing. 12.4 Remediation Requirements. If Applicant decides to remediate the USC, Applicant must remediate the USC in accordance with Subsection (A) or Subsection (B), as applicable. (A) Remediation When NDEP Involvement Is Required. Within sixty (60) days after providing Utility with Section 12.3 Notice, Applicant must develop a corrective action plan (“Corrective Action Plan”), submit the Corrective Action plan to the NDEP, and provide a copy of the Corrective Action Plan to Utility. After receiving written approval of the Corrective Action Plan from the NDEP, Applicant must complete remediation the earlier of (1) the
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date specified in the Corrective Action Plan or (2) within thirty (30) days of the date specified on that written approval from the NDEP. Promptly after completing remediation of the USC, Applicant must notify Utility in writing that Applicant believes remediation is complete. Applicant’s obligation to remediate the USC is not complete until after Applicant obtains a “no further action letter,” “closure letter” or similar letter from the NDEP. (B) Remediation When NDEP Involvement Is Not Required. With respect to the USC that Utility has identified in its Section 12.1 Notice but that does not require notification to NDEP as determined by Utility and within thirty (30) days after providing Utility with the Section 12.3 Notice, Applicant must develop a remediation plan (“Remediation Plan”) and provide a copy of the Remediation Plan to Utility for review and concurrence. Applicant must complete remediation of the USC within sixty (60) days of developing the Remediation Plan. If the remediation work cannot be completed within the 60-day period and Applicant is using Commercially Reasonable Efforts to accomplish the remediation, the period for performing the remediation work will be extended until remediation is completed. But remediation must be completed within three (3) months of the date identified on the Section 12.3 Notice. Promptly after completing remediation, Applicant must notify Utility in writing that Applicant believes remediation is complete. Applicant’s obligation to remediate the USC is not complete until after Applicant obtains a “no further action letter,” “no further requirement letter” or similar correspondence from a State of Nevada Certified Environmental Manager, who is approved by Utility. Article 13 Insurance and Indemnification 13.1 Insurance. Applicant must cause its contractors and subcontractors who are performing work in the Work Area (defined below) to procure and maintain in effect, the insurance coverages set forth in Exhibit E until after Applicant’s contractors and subcontractors have completed their work in the Work Area. The “Work Area” means the areas where all improvements associated with the Project will be located. The requirements of this “Insurance and Indemnification” Section are not intended to and will not in any manner limit or qualify the liabilities and obligations of Applicant under this Agreement. 13.2 Indemnity. Except to the extent arising from the negligence or willful misconduct of Utility, Applicant will indemnify and hold harmless Utility and all of its affiliates and all of their respective directors, officers, employees, representatives and agents (collectively, “Indemnified Parties”) from and against any and all third-party claims, demands and lawsuits, including those for personal injury, death and property damage, against one or more Indemnified Parties (and all associated and payable judgments, damages, losses, liabilities, fines, penalties and attorney’s fees and expenses) to the extent based in whole or in part on (1) any violation or breach
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of any requirement of or obligation imposed by any Property Rights for the Project or by any agreements or instruments creating or evidencing any Property Rights for the Project by Applicant or any of its contractors or any of their respective subcontractors, directors, officers, employees, representatives or agents (“Responsible Parties”) or (2) any violation of applicable Law or of a Permit by one or more Responsible Parties in connection with the work performed by one or more Responsible Parties in connection with this Agreement (all of the foregoing being collectively, “Indemnified Claims”). Additionally, at Utility’s election, Applicant will defend an Indemnified Party(ies) against Indemnified Claims. Applicant agrees that it will not attempt to avoid its obligations of indemnification under this Section by relying upon any provision set forth in the workers’ compensation or other employee benefits Laws of any state or other jurisdiction. Article 14 Dispute Resolution 14.1 Dispute Resolution Process. At any time a dispute arises with respect to a payment or other obligation under this Agreement, at the written request of either Party, the Parties’ senior executives must meet and attempt to resolve such dispute within ten (10) business days of a Party receiving that written request; and, during that 10- business-day period, all consequences associated with any delay in payment will be forestalled pending resolution. Notwithstanding anything to the contrary in this Agreement, Utility will not stop work on the Project or fail to provide Service as a result of a dispute without first exerting Commercially Reasonable Efforts to comply with this Section 14.1 during that 10-business-day period. 14.2 Exercising Rights after 10-Business-Day Period. If the Parties’ senior executives are unable to resolve the dispute within the 10-business-day period provided for in Section 14.1, the Parties may exercise all remedies and rights available to them under this Agreement, under the Tariff Schedules, at law, in equity, or otherwise. Article 15 Representations 15.1 Utility’s Standing in Nevada. Utility represents that, as of the date of this Agreement, it is duly organized, validly existing and in good standing under the laws of the State of Nevada with the valid corporate power to enter into and perform all of its obligations under this Agreement. 15.2 Applicant’s Standing in Nevada. Applicant represents that, as of the date of this Agreement, it (A) is duly organized, validly existing and in good standing under the laws of the State of Nevada, (B) is licensed to do business in the State of Nevada, and (C) has valid corporate or limited liability company power to enter into and perform all of its obligations under this Agreement. 15.3 Authority. Each Party has taken all actions as may be necessary or advisable and proper to authorize this Agreement, the execution and delivery of it, and the performance contemplated in it. The individuals executing this Agreement state
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and acknowledge that they are authorized and empowered to do so on behalf of the Party so designated. Article 16 Additional Provisions 16.1 Notices. (A) Method of Delivery; Contacts. Each notice, consent, request, or other communication required or permitted under this Agreement must be (1) in writing (includes by email), (2) delivered personally, sent by email, by certified mail (postage prepaid, return receipt requested) or sent by a nationally recognized courier, (3) reference Agreement number 16-00042, and (4) addressed to the Project Manager as identified in Exhibit A. (B) Notice to Legal Counsel Department. For any notice given by a Party under Article 12, Article 13, Article 14, Article 15 or Rule 9, Section A.28, the Party providing notice must also send a copy to the other Party’s legal counsel at the following address: NV Energy Attn: Legal Department 6226 West Sahara Avenue, M/S 3A Las Vegas, Nevada 89146
Switch, Ltd. Attn: Office of General Counsel 7135 S Decatur Blvd. Las Vegas, NV 89118 (A) Receipt of Notice; Change of Information. Each notice, consent, request, or other communication required or permitted under this Agreement will be deemed to have been received by the Party to whom it was addressed (A) when it is delivered if it is delivered personally; (B) on the first business day after the facsimile transmission is sent if it is delivered by facsimile; (C) on the third business day after it is mailed if it is mailed by certified mail; or (D) on the date the courier officially records it as having been delivered if it is delivered by a courier. Each Party may change its contact information for purposes of the Agreement by giving written notice to the other Party in the manner set forth above. 16.2 Utility’s Tariff Schedules; Commission. This Agreement is made by the Parties pursuant to Utility’s Tariff Schedules. Those Tariff Schedules apply to this Agreement, are binding on the Parties and supersede any portion of this Agreement should a conflict arise. However, Rule 9 is the version in effect on the Effective Date unless otherwise specified in this Agreement. Notwithstanding Section 16.11, this Agreement is, at all times, subject to such changes or modifications by the
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Commission as the Commission may from time to time direct in the exercise of its jurisdiction. This Section survives default, expiration, or termination of this Agreement or excuse of performance. 16.3 Integration. This Agreement, together with all other written contracts executed with the same formality as this instrument directly in connection with the Project such as the ESA represent the entire and integrated agreement between Utility and Applicant and supersede all prior and contemporaneous oral and written communications, representations, and agreements relating to the subject matter of this Agreement. 16.4 Assignment. Except in the event of merger, acquisition, or transfer of all or nearly all of Applicant’s assets, Applicant may not assign this Agreement or any rights under it without Utility’s prior written consent, which Utility will not unreasonably withhold, condition, or delay and any attempted assignment without such consent will be void. However, no assignment is effective until after (A) the assignee agrees in a writing acceptable to Utility to assume all obligations and liabilities under this Agreement, whether arising before or after the assignment, and (B) all other requirements in Rule 9, Section A.19 are complied with, including but not limited to Applicant agreeing (in Utility’s discretion and in a writing acceptable to Utility) to continuing liability in connection with obligations identified by Utility. 16.5 Limitation of Damages. (A) Utility. Notwithstanding anything to the contrary, Utility is not liable to Applicant for any of Applicant’s consequential, indirect, exemplary or incidental damages in connection with this Agreement, including, but not limited to, damages based upon Applicant’s delay, lost revenues or profits. (B) Applicant. Notwithstanding anything to the contrary and except with respect to Applicant’s obligations under this Agreement, Applicant is not liable to Utility for any of Utility’s consequential, indirect, exemplary or incidental damages in connection with this Agreement, including, but not limited to, damages based upon Utility’s delay, lost revenues or profits. However, this Subsection (B) does not limit Applicant’s obligations or liability, and Utility does not waive its rights, under NRS 704.800 and 704.805 (as amended or supplemented). 16.6 [INTENTIONALLY OMITTED]. 16.7 Choice of Law and Venue. This Agreement is governed by and will be construed in accordance with the laws of the State of Nevada, without giving effect to its choice or conflicts of law provisions. All actions that are beyond the scope of the Commission’s jurisdiction must be initiated in the courts of Washoe County, Nevada or the federal district court with jurisdiction over Washoe County, Nevada.
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The Parties agree they will not initiate an action against each other in any other jurisdiction. 16.8 No Waiver. The failure of either Party to enforce any of the provisions of this Agreement at any time, or to require performance by the other Party of any of the provisions of this Agreement at any time, will not be a waiver of any provisions, nor in any way affect the validity of this Agreement, or the right of any Party to enforce each and every provision. Nothing in this Agreement is to be construed as affecting or limiting Utility’s right to ask the Commission for a change in rates or charges for Service or for any other relief applicable to its rate schedules or any successor rate schedules. 16.9 Independent Contractor. Neither Applicant nor Utility is, nor will they be deemed to be, for any purpose, the agent, representative, contractor, subcontractor or employee of the other by reason of this Agreement. Nothing in this Agreement or any contract or subcontract by Applicant will create any contractual relationship between Applicant’s employee, agent, contractor or subcontractor and Utility. 16.10 Interpretation. Each Party to this Agreement acknowledges that it has carefully reviewed this Agreement, that it has been represented by counsel in connection with negotiating and entering this Agreement and that each fully understands and has participated in drafting its provisions, and, accordingly, the normal rules of construction to the effect that any ambiguities are to be resolved against the drafting party are not to be employed or used in any interpretation of this Agreement. 16.11 Amendments. Any changes, modifications, or amendments to this Agreement are not enforceable unless consented to in writing by the Parties and executed with the same formality as this Agreement. 16.12 No Third-Party Beneficiaries. Nothing expressed or implied in this Agreement is intended, or should be construed, to confer upon or give any Person not a party to this Agreement, such as a Party’s contractors, any third-party beneficiary rights, interests, or remedies under or by reason of any term, provision, condition, undertaking, warranty, representation, or agreement contained in this Agreement. 16.13 Remedies. All rights and remedies of a Party provided for in this Agreement will be cumulative and in addition to, and not in lieu of, any other remedies available to a Party at law, in equity, or otherwise. 16.14 Headings; Exhibits; Cross References. The headings or section titles contained in this Agreement are used solely for convenience and do not constitute a part of this Agreement, nor should they be used to aid in any manner in the construction of this Agreement. All exhibits attached to this Agreement are incorporated into this Agreement by reference. All references in this Agreement to Sections, Subsections, and Exhibits are to Sections, Subsections, and Exhibits of or to this Agreement, unless otherwise specified. And, unless the context otherwise requires, the singular
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includes the plural and the plural includes the singular and the neuter includes feminine and masculine. 16.15 Discretion. Reference in this Agreement to the “discretion” of a Party means the Party's sole and absolute discretion. However, such discretion is subject to standards of custom and reasonableness. This Section will not be interpreted as limiting or qualifying Utility’s obligation to follow Good Utility Practice. 16.16 Severability. If any portion or provision of this Agreement is invalid, illegal, or unenforceable, or any event occurs that renders any portion or provision of this Agreement void, the other portions or provisions of this Agreement will remain valid and enforceable. Any void portion or provision will be deemed severed from this Agreement, and the balance of this Agreement will be construed and enforced as if this Agreement did not contain the particular portion or provision held to be void. The Parties further agree to amend this Agreement to replace any stricken portion or provision with a valid provision that comes as close as possible to the intent of the stricken portion or provision. 16.17 Counterparts. The Parties may execute this Agreement in counterparts. Each of these counterparts, when signed and delivered, is deemed an original and, taken together, constitutes one and the same instrument. A facsimile or email copy of a signature has the same legal effect as an originally-drawn signature. 16.18 Performance of Acts on Business Days. Any reference in this Agreement to time of day refers to local time in Nevada. All references to days in this Agreement refer to calendar days, unless stated otherwise. Any reference in this Agreement to a “business day” refers to a day that is not a Saturday, Sunday or legal holiday (or observed as a legal holiday) for Nevada state governmental offices under the Nevada Revised Statutes. If the final date for payment of any amount or performance of any act required by this Agreement falls on a Saturday, Sunday or legal holiday, that payment is required to be made or act is required to be performed on the next business day. 16.19 [INTENTIONALLY OMITTED]. 16.20 Jury Trial Waiver. TO THE FULLEST EXTENT PERMITTED BY LAW, EACH OF THE PARTIES HERETO WAIVES ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF LITIGATION DIRECTLY OR INDIRECTLY ARISING OUT OF, UNDER OR IN CONNECTION WITH THIS AGREEMENT. EACH PARTY FURTHER WAIVES ANY RIGHT TO CONSOLIDATE ANY ACTION IN WHICH A JURY TRIAL HAS BEEN WAIVED WITH ANY OTHER ACTION IN WHICH A JURY TRIAL CANNOT BE OR HAS NOT BEEN WAIVED.
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Article 17 Definitions 17.1 Terms Defined in Rule 1. As used in this Agreement, the following capitalized terms have the meanings ascribed to them in Rule 1: Abnormal Risk; Commission; Customer; Reduction of Service; Service; Standards. 17.2 Terms Defined in Rule 9. As used in this Agreement, the following capitalized terms have the meanings ascribed to them in Rule 9: Advance; Advance Subject to Potential Refund; Affiliate; Allowance; Allowance True-up; Commercially Reasonable Efforts; Construction Complete; Contingent Facilities; Estimated Full Build-out Project Load (“EFBPL”); Final Total Costs; High Voltage Distribution (“HVD”); Maximum Allowance; Minimum Requirements; Person; Project; Property Rights; Proportionate Share Allocation; Proportionate Share Refund; Reduction of Service or Termination Charges (“RSTC”); Refund; Risk Profile; Security Requirements; Tax Gross-up; Tests; Total Costs; Total Cost True-up; Up- front Allowance. 17.3 Additional Definitions. In addition to the terms defined elsewhere in this Agreement, as used in this Agreement, the capitalized terms below will have the following definitions: (A) Acceptance: Utility’s written acknowledgement that a particular component of applicable drawings or work is, to the best of its knowledge, compliant with applicable Utility Standards. (B) Advance Payments: The payments that Applicant will make pursuant to Section 8.5, Section 8.8(B) and Exhibit B-2. (C) [INTENTIONALLY OMITTED]. (D) [INTENTIONALLY OMITTED]. (E) Applicant-Owned Facilities: All facilities and equipment designed, procured, constructed, maintained and owned by Applicant as shown generally in the One-line and further detailed in Project Scoping Document, including any modifications, additions or upgrades to such facilities and equipment. (F) Contact: The individual appointed by each Party to serve as the single point of contact for all issues relating to the Agreement, as identified in Exhibit A. (G) [INTENTIONALLY OMITTED]. (H) Development: Applicant’s SUPERNAP Reno to which Applicant has requested that Utility provide Service through the Utility-Owned Facilities being designed and installed in connection with this Agreement. (I) Effective Date: The date this Agreement is last signed below.
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Page 175 of 236 Exhibit-Berdrow-Direct-4 Amended and Restated Rule 9, Section B.2 High Voltage Distribution Agreement
(J) Electric System: Utility’s underground and/or above-ground communication facilities and electric systems for the distribution and transmission of electricity. (K) Force Majeure Event: An event or condition that is beyond the affected Party’s control, occurs without the fault or negligence of the affected Party and renders Project performance impossible or impractical. Force Majeure may include, but is not limited to, government agency orders, war, riots, acts of terrorism, civil insurrection, fires, floods, earthquakes, epidemics, extreme weather, strikes, lock-outs, work stoppages and other labor difficulties. (L) Good Utility Practice: Any of the practices, methods and acts engaged in or approved by a significant portion of the electric utility industry during the relevant time period, or any of the practices, methods and acts which, in the exercise of reasonable judgment in light of the facts known at the time the decision was made, could have been expected to accomplish the desired result at a reasonable cost consistent with good business practices, reliability, safety and expedition. Good Utility Practice is not intended to be limited to the optimum practice, method, or act to the exclusion of all others, but rather to be acceptable practices, methods, or acts generally accepted as commensurate with the electric utility industry’s standard of care in the region. (M) Hazardous Material: Any product, substance, chemical, material or waste whose presence, nature, quantity or intensity of existence, use, manufacture, disposal, transportation, spill, release or effect, either by itself or in combination with other materials is either: (1) potentially injurious to the public health, safety or welfare, or the environment; (2) regulated or monitored by any governmental authority; or (3) a basis for potential liability to any governmental agency or third party under any applicable Permit or Law. (N) In-Service Date: The date on which the Utility-Owned Facilities are operational, having passed all required testing as part of Utility’s electric system, as determined by Utility in its discretion. (O) Law: Any federal, state, or local code, ordinance, rule, statute, enactment, regulation, or order. Any specific reference to a Law in this Agreement refers to the Law as amended from time to time unless otherwise specified. (P) One-line: Drawings showing the modifications to Utility’s electric system that generally identify the Utility Facilities and Applicant-Owned Facilities. The One-line approved by the Parties is attached to this Agreement as Exhibit C-1.
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) Page 27 of 29 Execution Copy
Page 176 of 236 Exhibit-Berdrow-Direct-4 Amended and Restated Rule 9, Section B.2 High Voltage Distribution Agreement
(Q) Permit: Any applicable approval, permit, consent, waiver, exemption, variance, franchise, order, authorization, right, action, or license required from any federal, state, or local governmental authority, agency, court or other governmental body having jurisdiction over the matter in question which is necessary for the Parties to perform their obligations under this Agreement and under the applicable Laws. Any specific reference to a Permit in this Agreement refers to the Permit as amended from time to time unless otherwise specified. (R) Project Manager: The authorized representative of Utility or Applicant for purposes of this Agreement, as identified in Exhibit A. (S) Rule 1: Utility’s Electric Service Rule No. 1, Definitions. Rule 1 is part of the Tariff Schedules. (T) Rule 9: Utility’s Electric Service Rule No. 9, Electric Line Extensions. Rule 9 is part of the Tariff Schedules. (U) Site: The real property currently within Assessor’s Parcel Number(s) (“APNs”) 005-011-48 that is legally described in Exhibit D-1 attached to this Agreement. (V) Tariff Schedules: The entire body of effective rates, charges, and rules, collectively, of Utility as set forth in its rate schedules and rules for electric Customers, as those rates, charges, and rules are amended from time to time. (W) [INTENTIONALLY OMITTED]. (X) UOF Design: The design Utility prepares for the Utility-Owned Facilities in connection with this Agreement and the Parties will attach to this Agreement as Exhibit C-3. (Y) Utility Betterment: A deviation or upgrade to the Project made at Utility’s voluntary election that involves facilities in excess of the Minimum Requirements necessary to meet the Applicant’s EFBPL in order to meet Utility’s requirements for capacity to serve future load. (Z) Utility Facilities: The Utility-Owned Facilities. (AA) [INTENTIONALLY OMITTED]. (BB) Utility-Owned Facilities: All facilities and equipment designed, procured and/or constructed by Utility that will be maintained and owned by Utility as shown generally in the One-line and further detailed in the UOF Design, including any modifications, additions or upgrades to such facilities and equipment. [signature page follows]
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) Page 28 of 29 Execution Copy
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Page 179 of 236 Exhibit-Berdrow-Direct-4 Amended and Restated Rule 9, Section B.2 High Voltage Distribution Agreement
Exhibit A Contact Information
Utility (Sierra Pacific Power Company d/b/a NV Energy) Address 6100 Neil Road, Reno, NV 89520 Mailing Address 6100 Neil Road, Reno, NV 89520 Project Manager Clyyne Cook Mail Stop S4B05 Telephone (775) 834-3291 Cellular Telephone (775) 848-3291 Facsimile No. (775) 834-3973 Email [email protected] Major Account Executive John Brown Mail Stop S2A41 Telephone (775) 834-5771 Cellular Telephone (775) 813-5771 Email [email protected]
Applicant (Switch, Ltd.) Address 7135 S Decatur Blvd., Las Vegas, NV 89118 Mailing Address 7135 S Decatur Blvd., Las Vegas, NV 89118 Contact Terri Borden, EVP, Operations Telephone (702) 860-6078 Cellular Telephone (702) 860-6078 Facsimile No. (866) 794-4461 Email [email protected] [email protected] Invoices [email protected]
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) A-1
Page 180 of 236 Exhibit-Berdrow-Direct-4 Amended and Restated Rule 9, Section B.2 High Voltage Distribution Agreement
Exhibit B-1 Estimated Cost
[attached separately]
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) B-1
Page 181 of 236 EXHIBITBͲ1 ESTIMATEDCOSTS(+/Ͳ20%) FacilitiesCosts AdvanceTax TOTAL
ProjectCost Rule9Allocated TaxTaxGross FacilitiesDescription Estimate Cost Rate Up
TOTAL APPLICANT APPLICANT APPLICANT UTILITY TOTAL ComponentsofHVDCostunderRule9SectionB.2.nͲPHASE1 100% CommunicationsforApplicantSubstation 140,000 140,000 14.3% 20,020 160,020 Ͳ 160,020 Landfor120kVFeeders 25,000 25,000 53.8% 13,450 38,450 Ͳ 38,450 One120kVfeederstoApplicantSub 250,000 250,000 14.3% 35,750 285,750 Ͳ 285,750 MeterforApplicant 105,000 90,100 14.3% 12,884 102,984 14,900 117,884 SUBTOTALͲAPPLICANT 520,000 505,100 82,104 587,204 14,900 602,104 ComponentsofTRANSMISSIONͲPHASE1 100% CommunicationsͲFiberon120kVLines 390,000 Ͳ 390,000 390,000 CommunicationsͲDove 100,000 Ͳ 100,000 100,000 Landfor120kVLine 60,000 Ͳ 60,000 60,000 Environmentalfor120kVLine 186,500 Ͳ 186,500 186,500 120kVLinefromDovetoWildHorse 4,400,000 Ͳ 4,400,000 4,400,000 120kVTerminalatDove 1,673,000 Ͳ 1,673,000 1,673,000
SUBTOTALͲUTILITYPHASE1 6,809,500 Ͳ Ͳ Ͳ 6,809,500 6,809,500 COSTESTIMATE 7,329,500 505,100 82,104 587,204 6,824,400 7,411,604 Phase1 120kVMasterPlanComponentsͲ120kVDovetoWildHorsearea Phase2 120kVMasterPlanComponentsͲNone Assumptions ͲTheApplicableTaxGrossͲupratesaresubjecttochangeanddeterminedondateofConstructionCompleteinaccordancewithRule9SectionA.18.b ͲAllCostandAllowanceEstimatesareSubjecttoTrueͲUpunderRule9 ͲEstimatedUtilitySystemCostsarenotshowninthisexhibitforthisproject. ͲCIACandCIACͲRelatedTaxesareNonͲRefundable;AdvanceTaxesarePotentiallyRefundableaccordingtoRule9,SectionA.32.c.1.CIACCostsincludeanestimateofRͲOͲWcosts. ͲUpfrontAllowanceEstimateunderGSͲ3TServicefromExhibitBͲ3. ͲAssumesServiceunderScheduleGSͲ3T;AllowancesandFacilitiesChargevarybyRateScheduleandaresubjecttochange.AllowanceisrevenuebasedandcalculatedbasedoncurrentRateSchedules. ͲMetercreditforaGSͲ3Tcustomer($14,900)hasbeenapplied,basedonTable9,page1oftheMarginalCostofServicestudyasproposedfortheSierra Exhibit-Berdrow-Direct-4 Page 182 of236
ExhibitBͲ1EstimatedCosts Exhibit-Berdrow-Direct-4 Amended and Restated Rule 9, Section B.2 High Voltage Distribution Agreement
Exhibit B-2 Payment Schedule
[attached separately]
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) B-2
Page 183 of 236 Exhibit-Berdrow-Direct-4 58,720 183,851 587,204 367,703 Payment Cumulative $ $ $ $ Ͳ Ͳ Ͳ Ͳ Ͳ Ͳ Ͳ Ͳ 3,845 27,438 27,438 54,875 15,380 27,438 54,875 58,720 27,438 82,313 19,225 54,875 Due 192,064 125,131 219,502 183,851 Amount Total $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ Ͳ Ͳ Ͳ Ͳ Ͳ Ͳ Ͳ Ͳ 3,433 3,433 1,345 6,865 5,380 3,433 6,865 8,210 3,433 6,725 6,865 24,029 19,111 27,462 10,298 27,321 Allowance Tax Gross Ͳ up Upfront After $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ Ͳ Ͳ Ͳ Ͳ Ͳ Ͳ Ͳ Ͳ 2,500 24,005 24,005 24,005 48,010 50,510 48,010 10,000 72,015 24,005 12,500 48,010 106,020 192,040 168,035 156,530 SCHEDULE Sch In Ͳ Service) Allowance Cost B Ͳ 2 2018 Total Upfront B Ͳ 2 Payment After May 31, Exhibit PAYMENT $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ EXHIBIT (Based on Lands Lands Lands Lands Design Design Design Design Materials Materials Materials Materials Description Construction Construction Construction Construction SWITCH Ͳ Payment Due Payment Due Payment Due Payment Due Environmental Environmental Environmental Environmental Due Date Execution 7/31/2017 1/31/2018 11/30/2017 Upon Payment (estimated 5/19/2017) 2 1 3 4 Payment No.
Page 184 of 236 Exhibit-Berdrow-Direct-4 Amended and Restated Rule 9, Section B.2 High Voltage Distribution Agreement
Exhibit B-3 Allowance Worksheet
[attached separately]
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) B-3
Page 185 of 236 Exhibit-Berdrow-Direct-4 other rates + C D E) $0 $0 $0 $0 $0 $0 $0 $0 $0 $0 Upfront should Maximum Allowance Allowance = (A)x(B F service. supported; is takes 9, §B.3 9, §B.3 E** $0.00 $0.00 ($/kVA) ($/kVA) Allowance Allowance Applicant Rule Rule Allowance HVD when no effect D** in 9, §B.2.g 9, §B.2.g $0.00 $0.00 ($/kVA) ($/kVA) Allowance Allowance therefore Case Specific Case Specific Rule Rule to be and expected Charge, C** 9, §B.2.g 9, §B.2.g rates $0.00 $0.00 ($/kVA) ($/kVA) Allowance Allowance Substation Substation Demand Rule Rule proposed Rate Schedule the HVD by using B Ͳ 3 Allowance B* 9, §B.2.g 9, §B.2.g $0.00 $0.00 vary ($/kVA) ($/kVA) Exhibit Rule Rule HVD Allowance HVD Allowance estimated exempt from Charges be 9 17,600 17,600 17,600 17,600 153,500 153,500 153,500 153,500 Facilities true Ͳ up. A Year Rule GS Ͳ 3T will EFBPL (kVA) (kVA) 1st Attachment 3 are A.24.c under and Ͳ Up Schedule at the time of corresponding B.2.g 9 Section under and to True Rule Section and service accordingly 9, Subject based allowance. Rule taking in Estimates adjusted Schedule, GS Ͳ 3T; Allowances Ͳ based and be revenue listed a will load Applicants Notes: GS Ͳ 3T GS Ͳ 3T B Ͳ 6, Load Schedule and rates support Rate Schedule Rate Schedule Exhibit Allowance not under do Estimates are the Ͳ based allowances A see B Ͳ 3 Allowance Allowance service Assumptions revenue Column Allowance approved, Exhibit Upfront Maximum Allowance *Under the proposed be For **GS Ͳ 3T rates The Assumes All Estimate No. 4 5 6 7 8 9 3 10 11 12 20 17 19 18 16 13 14 15 Line Page 186 of 236 Exhibit-Berdrow-Direct-4 Amended and Restated Rule 9, Section B.2 High Voltage Distribution Agreement
Exhibit B-4 Customer Specific Facilities Charge
[attached separately]
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) B-4
Page 187 of 236 Exhibit-Berdrow-Direct-4 A C B C Notes 4 0 $0 $ $403.28 $403.28 $480,100 $0.00448 $0.0008 Amount 1 Ͳ (6) B Line ("CSFC") + Exhibit in (3) Utility Charge T) Ͳ 4 Ͳ Line the = B CSFC identified to (GS3 4 Ͳ T) Ͳ B CSFC Facilities Utility Components (GS3 Facilities 3 Ͳ Exhibit B the EXHIBIT Initial Investment Contributed by Owned Specific Ͳ ("CSFC") Exhibit Investment in Utility the Charge Contributed Investment Utility Investments of Customer of of identified Cost Specific Specific dollar dollar Ͳ Ͳ Facilities Total per Allowance per Rates of Specific Customer Customer Line(2) Line(5) estimated Upfront Charge charge * * the the (1) (4) is is Statement Line Line Customer Estimated Estimated This Facilities Facilities This See C A B (4) (1) (2) (3) (5) (6) (7) Line Notes
Page 188 of 236 Exhibit-Berdrow-Direct-4 Amended and Restated Rule 9, Section B.2 High Voltage Distribution Agreement
Exhibit B-5 Example Calculation of RSTC Calculation
[attached separately]
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) B-5
Page 189 of 236 Exhibit-Berdrow-Direct-4 Upfront Allowance x investment. demand B Ͳ 5 ("RSTC") such the investment average Exhibit with in Charge to recover Actual Demand B Ͳ 3 listed Ͳ 12 Ͳ month Demand is B Ͳ 5 Exhibit designed in B Ͳ 5 RSTC Demand Demand Value Expected consecutive Termination listed termination is any or Deficiency) Exhibit Ͳ RR) is early EXHIBIT Present Expected Expected (REV Allowance the Net Service є the Revenue Received (Revenue the Revenue Requirement associated is is estimated the time of of T Ͳ 1 NPV NPV T is RR is REV Upfront The Actual Demand NPV n=1 = = e= B Ͳ 5 Reduction g where: where: Exhibit Charge Char see a.25 Service Demand of Section Termination 9, Expected Rule see Reduction RSTC estimated For For B A Notes
Page 190 of 236 Exhibit-Berdrow-Direct-4 Amended and Restated Rule 9, Section B.2 High Voltage Distribution Agreement
Exhibit B-6 Load Schedule
[attached separately]
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) B-6
Page 191 of 236 Exhibit-Berdrow-Direct-4
CONFIDENTIAL OR SENSITIVE INFORMATION
PAGE(S) REMOVED FROM THIS FILE
EXHIBIT B-6 LOAD SCHEDULE
1 Page 192 of 236 Exhibit-Berdrow-Direct-4 Amended and Restated Rule 9, Section B.2 High Voltage Distribution Agreement
Exhibit C-1 One-line
[attached separately]
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) C-1
Page 193 of 236 Exhibit-Berdrow-Direct-4
CONFIDENTIAL OR SENSITIVE INFORMATION
PAGE(S) REMOVED FROM THIS FILE
EXHIBIT C-1 ONE-LINE
1 Page 194 of 236 Exhibit-Berdrow-Direct-4 Amended and Restated Rule 9, Section B.2 High Voltage Distribution Agreement
Exhibit C-2 [INTENTIONALLY OMITTED]
[attached separately]
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) C-2
Page 195 of 236 Exhibit-Berdrow-Direct-4 Amended and Restated Rule 9, Section B.2 High Voltage Distribution Agreement
Exhibit C-3 UOF Design
[attached separately]
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) C-3
Page 196 of 236 Exhibit-Berdrow-Direct-4 ExhibitCͲ3 UtilityͲOwnedFacilities("UOF")Design
TobeincludedonceUOFDesigniscomplete
ExhibitCͲ3UOFDesign Page 197 of 236 Exhibit-Berdrow-Direct-4 Amended and Restated Rule 9, Section B.2 High Voltage Distribution Agreement
Exhibit C-4 [INTENTIONALLY OMITTED]
[attached separately]
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) C-4
Page 198 of 236 Exhibit-Berdrow-Direct-4 Amended and Restated Rule 9, Section B.2 High Voltage Distribution Agreement
Exhibit D-1 Legal Description of Site
[attached separately]
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) D-1
Page 199 of 236 Exhibit-Berdrow-Direct-4 ExhibitDͲ1 LegalDescription
TobeincludedonceUOFDesigniscompleteandLegalDocumentsprepared
ExhibitDͲ1LegalDescription Page 200 of 236 Exhibit-Berdrow-Direct-4 Amended and Restated Rule 9, Section B.2 High Voltage Distribution Agreement
Exhibit D-2 Form Grant of Easement
[attached separately]
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) D-2
Page 201 of 236 Exhibit-Berdrow-Direct-4
APN(s): 005-011-48
WHEN RECORDED MAIL TO: Property Services NV Energy P.O. Box 10100 MS S4B20 Reno, NV 89520 GRANT OF EASEMENT
SUPERNAP Reno, LLC, a Nevada limited liability company, (“Grantor”), for One Dollar ($1.00) and other good and valuable consideration – receipt of which is hereby acknowledged – and on behalf of itself and its successors and assigns, grants and conveys to Sierra Pacific Power Company, a Nevada corporation, d/b/a NV Energy (“Grantee”) and its successors and assigns a perpetual right and easement:
1. to construct, operate, add to, modify, maintain and remove aboveground and/or underground communication facilities and electric line systems for the distribution and transmission of electricity, consisting of poles, other structures, wires, cables, conduit, duct banks, manholes, vaults, transformers, service boxes/meter panels, cabinets, bollards, anchors, guys, and other equipment, fixtures, apparatus, and improvements (“Utility Facilities”) upon, over, under and through the property legally described and generally depicted in Exhibit A attached hereto and by this reference made a part of this Grant of Easement (“Easement Area”);
2. for the passage of authorized vehicles and pedestrians within, on, over and across the Easement Area and the property legally described in Exhibit B attached hereto and by this reference made a part of this Grant of Easement (the “Property”);
3. for the ingress of vehicles and pedestrians to and the egress of vehicles and pedestrians from, the Easement Area and the Property; and
4. to remove, clear, cut or trim any obstruction or material (including trees, other vegetation and structures) from the surface or subsurface of the Easement Area as Grantee may deem necessary or advisable for the safe and proper use and maintenance of the Utility Facilities in the Easement Area.
Grantee will be responsible for any damages, proximately caused by Grantee negligently constructing, operating, adding to, maintaining, or removing the Utility Facilities, to any tangible, personal property or improvements owned by Grantor. Grantee further agrees that, if Grantee performs work that damages the improvements or property within the Easement Area or Property, Grantee will restore the Easement Area and Property to its before condition, to the extent restorable. However, this paragraph does not apply to, and Grantee is not responsible for, any damages caused to obstructions or materials being removed, cleared, cut or trimmed when Grantee exercises its rights under numbered paragraph 4 above.
Grantor covenants for the benefit of Grantee, its successors and assigns, that no building, structure or other real property improvements—except for landscape coverings such as asphalt, pavement, gravel, grass, ground cover, shrubs, curbs, gutters and sidewalks that are compatible with the Utility Facilities—will be constructed or placed on or within the Easement Area without the prior written consent of Grantee, such
RW# ls6073 Proj. # Project Name: Reference Document: GOE 1 (Rev. 3/2014)
Page 202 of 236 Exhibit-Berdrow-Direct-4
structures and improvements to include, but not be limited to, drainage, trees, bridges, signage, roads, fencing, storage facilities, parking canopies, and other covered facilities. Grantee and Grantor must document Grantee’s consent by both signing a mutually agreeable recordable use agreement. Grantor retains, for its benefit, the right to maintain, use, secure, protect and otherwise landscape the Easement Area for its own purposes; provided, however, that all such purposes and uses do not interfere with Grantee’s rights herein and are in all respects consistent with the Grantee’s rights herein, Grantee’s electrical practices, and the National Electrical Safety Code.
If Grantee and Grantor agree in writing to Grantee transferring ownership of all or a portion of the then-existing Facilities to Grantor then, upon Grantor’s written request, Grantee will execute and record a relinquishment of this Agreement as to the transferred Facilities. If Grantor determines that the Premises are no longer needed for the Facilities, this Agreement will terminate after Grantor requests – and Grantee executes and records – a written relinquishment of this Agreement. Grantor agrees to cover itself or pay Grantee’s costs to relocate, adjust, or remove the Facilities in accordance with Grantee’s Tariff Schedules, if the removal is requested by Grantor. The term “Tariff Schedules” means the entire body of effective rates, charges, and rules, collectively, of Grantee as set forth in its rate schedules and rules for electric customers, as those rates, charges, and rules are amended from time to time, a copy of which can be found at: https://www.nvenergy.com/company/rates/index.cfm (location as of December 12, 2014).
To the fullest extent permitted by law, Grantor and Grantee waive any right each may have to a trial by jury in respect of litigation directly or indirectly arising out of, under or in connection with this Grant of Easement. Grantor and Grantee further waive any right to consolidate any action in which a jury trial has been waived with any other action in which a jury trial cannot be or has not been waived.
[signature page follows]
APN(s): RW# ls6073 Proj. # Project Name: Reference Document: GOE 2
Page 203 of 236 Exhibit-Berdrow-Direct-4
GRANTOR:
SUPERNAP Reno, LLC
______SIGNATURE
By: ______PRINT NAME
Title: ______
STATE OF ) ) ss. COUNTY OF )
This instrument was acknowledged before me on ______, ______by ______as
______of SUPERNAP Reno, LLC
______Signature of Notarial Officer
Notary Seal Area Æ
APN(s): RW# ls6073 Proj. # Project Name: Reference Document: GOE 3
Page 204 of 236 Exhibit-Berdrow-Direct-4
Exhibit A
{insert legal description for and drawing of Easement Area}.
APN(s): RW# Proj. # Project Name: Reference Document: GOE A-1
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Exhibit B
A portion of the North half of Section 14, Township 19 North, Range 22 East, M.D.M., Storey County, Nevada; situated within the parcel of land described as 2015-31 on the Amended Record of Survey for Tahoe – Reno Industrial Center, LLC., recorded as File No. 122563 on July 27, 2015, Official Records of Storey County, Nevada.
APN(s): RW# ls6073 Proj. # Project Name: Reference Document: GOE B-1
Page 206 of 236 Exhibit-Berdrow-Direct-4 Amended and Restated Rule 9, Section B.2 High Voltage Distribution Agreement
Exhibit D-3 Form Right of Entry
[attached separately]
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) D-3
Page 207 of 236 Exhibit-Berdrow-Direct-4
APN(s): {insert APN or APNs}
WHEN RECORDED MAIL TO: Land Resources NV Energy P.O. Box 10100 MS S4B20 Reno, NV 89520
Land Resources NV Energy P.O. Box 98910 MS 9 Las Vegas, NV 89151-0001
RIGHT OF ENTRY
{insert Grantor's legal name}, a {insert state} {insert type of entity}, (“Grantor”), for One Dollar ($1.00) and other good and valuable consideration – receipt of which is hereby acknowledged – and on behalf of itself and its successors and assigns, grants and conveys to {insert Nevada OR Sierra Pacific} Power Company, a Nevada corporation, d/b/a NV Energy (“Grantee”) and its successors and assigns a perpetual right:
1. to construct, operate, add to, modify, maintain and remove communication and electrical facilities as delineated and drawn on Nevada Power Company Project ID {insert number} (“Utility Facilities”) upon, over, under and through the property legally described and generally depicted in Exhibit A attached hereto and by this reference made a part of this Right of Entry (“Project Area”);
2. for the unrestricted passage of vehicles and Grantee’s employees, contractors and subcontractors within, on, over and across the Project Area;
3. for the ingress of vehicles and Grantee’s employees, contractors and subcontractors to and the egress of vehicles and Grantee’s employees, contractors and subcontractors from, the Project Area; and
4. to remove, clear, cut or trim any obstruction or material (including trees, other vegetation and structures) from the surface or subsurface of the Project Area as Grantee may deem necessary or advisable for the safe and proper use and maintenance of Utility Facilities in the Project Area.
Grantee will be responsible for any damages, proximately caused by Grantee negligently constructing, operating, adding to, maintaining, or removing the Utility Facilities, to any tangible, personal property or improvements owned by Grantor and located on the Project Area on the date Grantor signs this Right of Entry. However, this paragraph does not apply to, and Grantee is not responsible for, any damages caused when Grantee exercises its rights under numbered paragraph 4 above.
ROE# Proj. # Project Name: Reference Document: ROE 1 (Rev. 3/2014)
Page 208 of 236 Exhibit-Berdrow-Direct-4
Grantee may use this easement to provide service to any of its customers. Grantor covenants for the benefit of Grantee, its successors and assigns, that no building, structure or other real property improvements will be constructed or placed within five (5) feet of the Utility Facilities without the prior written consent of Grantee, such structures and improvements to include, but not be limited to, drainage, trees, bridges, and signage. Grantee and Grantor must document Grantee’s consent by both signing Grantee’s standard, recordable use agreement. Grantor retains, for its benefit, the right to maintain, use and otherwise landscape the Project Area for its own purposes; provided, however, that all such purposes and uses do not interfere with Grantee’s rights herein and are in all respects consistent with the Grantee’s rights herein, Grantee’s electrical practices, and the National Electrical Safety Code.
Upon completion of construction of the Utility Facilities and after Grantee provides its standard form Grant of Easement to Grantor, Grantor will immediately execute this Grant of Easement describing the perpetual easement to be retained over the Project Area.
To the fullest extent permitted by law, Grantor and Grantee waive any right each may have to a trial by jury in respect of litigation directly or indirectly arising out of, under or in connection with this Right of Entry. Grantor and Grantee further waive any right to consolidate any action in which a jury trial has been waived with any other action in which a jury trial cannot be or has not been waived.
[signature page follows]
APN: ROE# Proj. # Project Name: Reference Document: ROE 2
Page 209 of 236 Exhibit-Berdrow-Direct-4
GRANTOR:
{insert Grantor's legal name}
______By: Title:
STATE OF ) ) ss. COUNTY OF )
This instrument was acknowledged before me on ______, 20____ by ______as ______of ______.
______Signature of Notarial Officer
Notary Seal Area Æ
APN: ROE# Proj. # Project Name: Reference Document: ROE 3
Page 210 of 236 Exhibit-Berdrow-Direct-4
Exhibit A
{insert legal description for and drawing of Easement Area}.
APN: ROE# Proj. # Project Name: Reference Document: ROE A-1
Page 211 of 236 Exhibit-Berdrow-Direct-4 Amended and Restated Rule 9, Section B.2 High Voltage Distribution Agreement
Exhibit D-4 Form Transmission Use Agreements
[attached separately]
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) D-4
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Exhibit E Insurance Coverages
1. Types of Insurance Required. In accordance with the “Insurance” Section of this Agreement, Applicant must cause its contractors and subcontractors who are performing work in the Work Area to procure and maintain in effect the following (required limits can be met by use of primary, underlying, and umbrella/excess combinations) until after they have completed their work in the Work Area:
(A) Workers’ Compensation and Employer’s Liability Insurance. Workers’ compensation insurance in the form and manner required by the State of Nevada. Employer’s Liability insurance with the following limits: (1) one million dollars ($1,000,000.00) per each accident; (2) one million dollars ($1,000,000.00) per each employee disease; and (3) one million dollars ($1,000,000.00) in the annual aggregate per each occupational disease. (B) Commercial General Liability Insurance. Commercial general liability insurance providing bodily injury, property damage, personal injury/advertising injury, premises/operations, and products/completed operations coverage with a per occurrence limit of not less than two million dollars ($2,000,000.00) and an aggregate limit of not less than two million dollars ($2,000,000.00). (C) Automobile Liability Insurance. Commercial automobile liability insurance with a combined single limit of one million dollars ($1,000,000.00) for each person and one million dollars ($1,000,000.00) for each occurrence. (D) Excess or Umbrella Liability Insurance. Excess or umbrella liability with a combined single limit of not less than five million dollars ($5,000,000.00) per occurrence. Except with respect to workers’ compensation insurance, these limits must “follow-form” all terms and conditions excess of each of the above-mentioned underlying policies. 2. Insurer and Policy Requirements. Each contract of insurance must be with an insurer approved to do business in the State of Nevada, is “A” Rated or better by A.M. Best Company and must include the following provisions or endorsements:
(A) Primary Insurance. Stating that the insurance is primary insurance with respect to the interest of Utility and that any insurance maintained by Utility is excess and not contributory insurance. (B) Subrogation Waivers. Providing Utility with waivers of subrogation on all coverages. (C) Severability and Cross Liability. Providing severability of interest and cross liability coverage for general liability, automobile liability and the excess/umbrella liability insurance policies.
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) E
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(D) Claims-Made Form. If the policy is maintained on a “claims-made” form and is converted to an “occurrence” form, the new policy will be endorsed to provide coverage back to a retroactive date acceptable to Utility. 3. Notice Requirement. Applicant must provide Utility with 30-days prior written notice before the termination, expiration, or alteration of the coverage provided above.
4. Deductible and Retention Limits. Deductible or retention amounts under the policies described above must not exceed 5% of the per occurrence coverage limits, without the express written consent of Utility.
5. Certificate of Insurance. Applicant must provide Utility with certificates of insurance from Applicant’s contractors and subcontractors who will perform work in the Work Area, where the contractor and subcontractor, but not Applicant, name Utility as an additional insured and evidencing the coverage required above including additional insured endorsement numbers, before Applicant’s contractors or subcontractors commence any work in the Work Area. Applicant must provide Utility with a current copy of the certificate of insurance evidencing the coverage set forth above.
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) E
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Exhibit F Project Scoping Document
[attached separately]
HVD Agreement No. 16-00042 Switch SuperNAP Reno (rev. 9/2014) F-1
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CONFIDENTIAL OR SENSITIVE INFORMATION
PAGE(S) REMOVED FROM THIS FILE
EXHIBIT F
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