docket no. ue 374 exhibit pac/2700 witness: timothy j. … · 2020. 7. 1. · 20 and that these...

Docket No. UE 374 Exhibit PAC/2700 Witness: Timothy J. Hemstreet

BEFORE THE PUBLIC UTILITY COMMISSION

OF OREGON

PACIFICORP

___________________________________________________________

Reply Testimony of Timothy J. Hemstreet

June 2020

PAC/2700 Hemstreet/i


TABLE OF CONTENTS

I. PURPOSE AND SUMMARY OF TESTIMONY ............................................2

II. CONSTRUCTION STATUS OF NEW WIND PROJECTS AND FOOTE CREEK I REPOWERING PROJECT ...............................................................4

III. RESPONSE TO STAFF AND INTERVENOR RECOMMENDATIONS FOR NEW WIND PROJECTS AND FOOTE CREEK I REPOWERING PROJECT ...........................................................................................................7

IV. KLAMATH HYDROELECTRIC PROJECT CAPITAL ADDITIONS .........12

ATTACHED EXHIBITS

Confidential Exhibit PAC/2701—Klamath Hydroelectric Project Capital Additions

PAC/2700 Hemstreet/1


Q. Are you the same Timothy J. Hemstreet who previously provided direct 1

testimony in this case on behalf of PacifiCorp d/b/a Pacific Power (PacifiCorp or 2

the Company)? 3

A. Yes. 4

Q. Did you submit direct testimony in this proceeding? 5

A. Yes. I am also adopting certain portions of the direct testimony of Mr. Chad A. 6

Teply, Exhibit PAC/800, submitted on behalf of the Company that is related to the 7

Energy Vision 2020 wind projects including TB Flats I, TB Flats II, Ekola Flats, and 8

Cedar Springs II (collectively referred to as New Wind Projects). Specifically, I am 9

adopting the following from Exhibit PAC/800: 10

page 1, lines 18 through line 22 as follows: 11

I. PURPOSE OF TESTIMONY 12

Q. What is the purpose of your testimony in the case? 13

A. The purpose of my testimony is to address the new wind 14

projects that are included in Energy Vision 2020, the Pryor Mountain 15

Wind Project, certain major emissions controls retrofit projects, and 16

the naturals gas conversion of Naughton Unit 3. 17

page 2, lines 1 through 14; 18

page 4, lines 3 through 13; 19

page 5, line 1 through page 18, line 16; 20



page 54, lines 1 through 6 as follows: 1

VIII. CONCLUSIONS AND RECOMENDATIONS 2

Q. Please summarize your testimony. 3

A. The Company prudently managed the analysis, 4

implementation, and costs of the Energy Vision Wind Projects and the 5

Pryor Mountain Wind Project which provide benefits to Oregon 6

customers. These projects should be approved as prudent expenditures. 7

I am also adopting Exhibits PAC/801-819. 8

I. PURPOSE AND SUMMARY OF TESTIMONY 9

Q. What is the purpose of your reply testimony in this proceeding? 10

A. In my reply testimony, I provide an update with respect to the construction status for 11

the TB Flats I, TB Flats II, Ekola Flats, and Cedar Springs II (collectively, the New 12

Wind Projects), and the Foote Creek I repowering project. I also respond to 13

recommendations presented by Public Utility Commission of Oregon (Commission) 14

Staff witness Mr. Steve Storm regarding the inclusion in rates of costs related to the 15

New Wind Projects, and the recommendations of the Alliance of Western Energy 16

Consumers (AWEC) witness Mr. Bradley C. Mullins regarding cost recovery and 17

performance assumptions for the New Wind Projects. Finally, I respond to the 18

recommendations of Commission Staff witness Mr. Brian Fjeldheim regarding the 19

recovery of ongoing capital expenditures that are necessary for the continued 20

operation of the Klamath Hydroelectric Project developments. 21

Q. Please summarize your reply testimony. 22

A. In my reply testimony, I: 23



Provide an update regarding the cost and construction status of the New Wind 1

Projects and explain impacts that the COVID-19 pandemic may have on 2

construction. I explain that if delays can be appropriately mitigated, an in-3

service date of December 2020 continues to be achievable for these projects. 4

Further, if delays do push the in-service dates into 2021, the Company will 5

still qualify for 100 percent of Production Tax Credits (PTC). 6

Address why Commission Staff witness Mr. Storm’s recommendation to cap 7

the rate base additions for the New Wind Projects to amounts contained in 8

Staff’s Table 1, and AWEC witness Mr. Mullins’ similar recommendation, 9

should not preclude the Company from seeking recovery for prudently 10

incurred costs that may exceed those amounts in a future proceeding. I also 11

explain how Mr. Mullins’ recommendation on minimum capacity factors for 12

the New Wind Projects was already resolved by the Commission in Order No. 13

19-351 in the 2020 Transition Adjustment Mechanism (TAM), docket 14

UE 356. 15

Explain that the Company’s ongoing capital expenditures related to the 16

Klamath Hydroelectric Project facilities are necessary and prudent 17

expenditures to maintain safe and reliable operation of the project consistent 18

with the requirements of the Federal Energy Regulatory Commission (FERC), 19

and that these costs should be recoverable in rates so that customers can 20

continue to enjoy the low-cost, emissions-free energy from the facilities 21

before their potential transfer to the Klamath River Renewal Corporation for 22

removal pursuant to the Klamath Hydroelectric Settlement Agreement. 23



II. CONSTRUCTION STATUS OF NEW WIND PROJECTS AND FOOTE 1 CREEK I REPOWERING PROJECT 2

Q. What is the current expected completion date for the New Wind Projects and the 3

Foote Creek I repowering project? 4

A. The Company continues to work towards completion of the New Wind Projects by 5

late 2020, while anticipating a December 2020 transfer of the Cedar Springs II wind 6

project when that project achieves commercial operation. The Company also 7

continues to work towards a 2020 in-service date for the Foote Creek I repowering 8

project. 9

Q. What is the current construction status of the TB Flats I and TB Flats II wind 10

facilities? 11

A. For the TB Flats I and TB Flats II wind facilities, 122 of 132 wind turbine generator 12

(WTG) foundations have been constructed; access roads are complete; foundations 13

for both collector substations are complete; structural steel erection is nearly complete 14

at the TB Flats I and TB Flats II collector substations; underground collector cable 15

installation is complete at the TB Flats I area and proceeding at the TB Flats II area; 16

all of the five main power transformers have been delivered; and delivery of wind 17

turbine generator components and erection of turbines is proceeding. Turbine 18

deliveries to the sites have been delayed as a result of force majeure events claimed 19

by Vestas-American Wind Technology, Inc. (Vestas), the turbine supplier. As a 20

result, turbine erection activities are currently behind schedule and the Company is 21

working with both Vestas and M.A. Mortenson, Inc. (Mortenson), the balance of 22

plant contractor at TB Flats I, TB Flats II and Ekola Flats, to mitigate the impacts of 23

delivery delays on the overall project schedule. 24



Q. What is the current construction status of the Ekola Flats wind facility? 1

A. For the Ekola Flats wind facility, all of the 63 WTG foundations have been 2

completed; access roads are complete; foundations at the collector substation are 3

complete; certain directional borings have been completed in support of underground 4

collector cable installation; manufacturing, testing, and delivery of both main power 5

transformers to the site is complete; construction of the operations and maintenance 6

building is underway; all General Electric safe-harbor turbines have been delivered to 7

the site and are being erected, and the delivery and erection of Vestas wind turbine 8

equipment at the site is proceeding. Similar to the TB Flats I and TB Flats II projects, 9

wind turbine generator component deliveries to the site by Vestas have been delayed, 10

and the Company is working with both Vestas and Mortenson to mitigate the impacts 11

of those delivery delays. 12

Q. What is the current construction status of the Cedar Springs II wind facility? 13

A. For the Cedar Springs II wind facility, the project collector substation has been 14

completed and its grounding transformers are being installed. Construction of the 15

Cedar Springs II operations and maintenance (O&M) building is underway along 16

with road construction and foundation excavation, and work continues on the 17

transmission tie-line between the Cedar Springs II and the Cedar Springs I (NextEra 18

Power Purchase Agreement) collector substations. 19

Q. What is the current construction status of the Foote Creek I repowering project? 20

A. Scheduled generation from the facility ended on May 18, 2020, and 19 of the 68 21

original turbines at the site have been disassembled by the balance of plant contractor, 22

Thorstad Companies. All 13 new wind turbine foundations have been completed, the 23



new switchgear and controls building has been delivered to the site, and new fiber 1

and collector circuits continue to be installed. Deliveries of Vestas wind turbine 2

generator components to the site have not yet begun, but are currently forecast to be 3

on schedule, and the Company is taking steps to mitigate the potential impacts of 4

uncertain equipment delivery timing. 5

Q. Has the Company received force majeure notices from contractors that are 6

involved in the equipment supply and construction of the New Wind Projects 7

and Foote Creek I repowering project? 8

A. Yes. As a result of the COVID-19 pandemic, the Company has received force 9

majeure notices from all of the major contractors involved in these projects. 10

Q. Has the COVID-19 public health emergency had a material impact on the 11

Company’s construction schedule or costs for the New Wind Projects or Foote 12

Creek I repowering project? 13

A. First and foremost, the Company is working closely with its contractors and suppliers 14

to ensure that work on these projects proceeds in a manner that protects the safety of 15

the people working on the projects and the local public where the projects are located. 16

Work at all projects is proceeding under COVID-19 mitigation plans to address 17

worker safety. As mentioned above, the COVID-19 pandemic has resulted in force 18

majeure notices and claims by Vestas that the pandemic has disrupted their wind 19

turbine generator supply chain, resulting in delayed equipment deliveries. At the TB 20

Flats I, TB Flats II, and Ekola Flats projects, equipment delivery delays are impacting 21

turbine erection productivity and COVID-19 worker safety protocols have the 22



potential to decrease productivity—these impacts could result in increased project 1

costs, though it is not known how material these cost increases may be. 2

At the Foote Creek I repowering project, the COVID-19 pandemic has the 3

potential to impact equipment supply and transport logistics, but so far no impacts are 4

confirmed. Contractors involved in the project have also issued force majeure notices 5

of potential, but yet unknown, impacts. 6

Potential impacts of the COVID-19 public health emergency continue to 7

emerge and the Company continues to work closely with its contractors and 8

equipment suppliers to ensure that the people working on the projects and the public 9

in general are protected by complying with all governmental requirements, orders and 10

directives, while working to mitigate potential impacts to construction schedules. 11

The Company and its contractors and suppliers remain committed to deliver the New 12

Wind Projects and Foote Creek I repowering project by year-end 2020, and will work 13

to mitigate impacts to customers should construction delays result in later than 14

anticipated commissioning of these projects. Given the dynamic nature of the 15

impacts to the projects and the difficulty in assessing the impacts to the projects at 16

this time, I will provide an update on any potential projects delays in my surrebuttal 17

testimony. 18

III. RESPONSE TO STAFF AND INTERVENOR RECOMMENDATIONS FOR 19 NEW WIND PROJECTS AND FOOTE CREEK I REPOWERING PROJECT 20

Q. What did Staff witness Mr. Storm recommend in his opening testimony with 21

respect to the New Wind Projects and the Foote Creek I repowering project? 22

A. Mr. Storm recommended that the Commission find the Company’s decision to invest 23

in New Wind Projects to be prudent based on the analysis filed by the Company in 24



the various dockets that have evaluated these investments, assuming the projects 1

qualify for 100 percent of the PTCs. Similarly, Staff recommends that the 2

Commission find the Company’s decision to invest in the Foote Creek I repowering 3

project to be prudent, assuming the repowering project also qualifies for 100 percent 4

of the value of the PTCs. Mr. Storm also recommends that the Commission cap the 5

amount of rate base addition for each of the new wind projects and the Foote Creek I 6

repowering project to the amounts shown in Staff’s Table 1 for purposes of 7

ratemaking in this proceeding and that the Company refile for cost recovery if any of 8

these projects reach commercial operation after December 31, 2020. Mr. Storm also 9

states that a Vice President of the Company should be required to attest that the wind 10

facilities are placed in service prior to January 1, 2021. 11

Q. Please explain the Company’s position on Mr. Storm’s recommendations. 12

A. The Company accepts Mr. Storm’s recommendation that the prudence of the New 13

Wind Projects and Foote Creek I repowering project is contingent upon the facilities 14

qualifying for PTC benefits. As noted in data responses, the Internal Revenue 15

Service has recently issued a notice (Notice 2020-41) in response to the COVID-19 16

pandemic providing for a one-year extension in the Continuity Safe Harbor such that 17

wind projects must be in service prior to January 1, 2022, in order to qualify for the 18

full value of PTCs. Further, as discussed by Mr. Michael G. Wilding, the Company 19

believes that it should not be precluded from seeking cost recovery for prudently-20

incurred costs to construct the New Wind Projects or the Foote Creek I repowering 21

project should construction costs and schedules be impacted by the COVID-19 22

pandemic—though cost recovery over the amounts included in this case may be 23



considered in a later proceeding before the Commission. The Company also agrees to 1

provide an attestation from a Vice President affirming the New Wind Projects and 2

Foote Creek I repowering project have reached commercial operation before their 3

inclusion in rates. 4

Q. Similar to Staff, AWEC witness Mr. Mullins recommends that the Commission 5

impose a hard cap on capital and O&M costs for the New Wind Projects at the 6

level assumed in the request for proposal (RFP) bids.1 Do you agree with this 7

proposal? 8

A. No. The Company has prudently managed the development and construction of the 9

New Wind Projects. As noted in my direct testimony, the Company experienced a 10

price change for the wind turbine generator equipment used at the TB Flats I, TB 11

Flats II and Ekola Flats wind projects as a result of U.S. tariff impacts that were 12

outside the control of the Company. The Company should not be penalized for 13

actions that are outside of its control. Additionally, the Company’s subsequent 14

evaluation of the wind turbine generator cost increase—in light of lower than 15

previously assumed O&M costs for the projects—demonstrated no material impact to 16

the economic benefits for customers offered by the projects. Thus, it would be unfair 17

and punitive to the Company to impose a hard cap on capital costs when customers 18

are not adversely impacted by higher costs. 19

Additionally, the Company is managing the construction of the New Wind 20

Projects in the face of a global pandemic that has the likelihood to adversely impact 21

worker productivity at the projects, impacting costs and schedules, while observing 22

1 AWEC/100, Mullins/12.



best practices to mitigate potential public health risks and impacts to worker safety. It 1

would be unfair to impose a hard cap on capital costs that would not allow the 2

Company to recover prudently incurred costs that exceed the amounts submitted in 3

the RFP process. 4

Further, imposition of a hard cap on O&M costs is asymmetric and has the 5

potential to harm the Company in situations in which customers are not adversely 6

impacted. For example, the wind lease payments for the New Wind Projects are 7

based on the generation output of the facilities. If the New Wind Projects were to 8

exceed expectations regarding their assumed capacity factors, customers would 9

benefit from additional energy and PTC benefits, but the Company could be 10

precluded from recovering costs related to higher than anticipated wind lease 11

payments. Similarly, the Company could have the opportunity to undertake enhanced 12

maintenance activities that could increase the energy output of the wind facilities, or 13

otherwise increase their availability. The Company should not have its options 14

limited in this regard and should be free to pursue projects that could enhance the 15

value of the facilities for customers without concern that prudently incurred costs 16

would not be recoverable in rates. 17



Q. Mr. Mullins also recommends that the Commission impose a condition that 1

would require the Company to guarantee full PTCs and energy benefits 2

regardless of the in-service date and regardless of delays resulting from 3

contractors and impose a minimum capacity factor for the resources at the level 4

modeled in the bids.2 Do you find these recommendations reasonable? 5

A. No. While the PTC benefits of the projects are not at risk given the recent one-year 6

extension of the Continuity Safe Harbor, the recommendation still could be read to 7

require the Company to guarantee energy and PTC benefits that were previously 8

assumed to begin in December 2020, even if the projects are delayed as a result of 9

circumstances—such as the COVID-19 force majeure event—that are out of the 10

Company’s control. This recommendation is unreasonable, given the significant 11

benefits the New Wind Projects will deliver to customers. 12

Q. Has the Commission already resolved whether to impose a minimum capacity 13

factor for the Energy Vision 2020 projects? 14

A. Yes. In the 2020 TAM last year, Staff and AWEC raised the same issue regarding the 15

Energy Vision 2020 projects. PacifiCorp and the parties, including AWEC, resolved 16

this issue by an agreement that PacifiCorp would use the capacity factors assumed at 17

the time of Energy Vision 2020 project acquisition through 2025, and the parties 18

“expressly agree[d] not to propose any changes to wind capacity factors until 2024”.3 19

In Order No. 19-351, the Commission approved this stipulation, indicating that it met 20

the standard the Commission set in the 2017 Integrated Resource Plan Order.4 The 21

2 AWEC/100, Mullins/12. 3 In the Matter of PacifiCorp, dba Pacific Power 2020 Transition Adjustment Mechanism, Docket No. UE 356, Order No. 19-351, App. A at 8 (Oct. 30, 2019). 4 Id. at 5-6.



Company has adhered to the stipulation in its modeling in this case and the 2021 1

TAM. AWEC’s recommendation in this case should be rejected on this basis. 2

IV. KLAMATH HYDROELECTRIC PROJECT CAPITAL ADDITIONS 3

Q. Staff witness Mr. Brian Fjeldheim indicates that Staff is concerned about 4

whether ongoing capital additions planned by the Company at its Klamath 5

Hydroelectric Project facilities are prudent in light of the planned transfer of the 6

facilities to the Klamath River Renewal Corporation for removal pursuant to the 7

Klamath Hydroelectric Settlement Agreement. Can you clarify why these 8

ongoing capital additions are necessary? 9

A. Yes. The Company remains the FERC licensee for the Klamath Hydroelectric 10

Project facilities, and the ongoing operation of the facilities benefits customers as a 11

result of the low-cost, emissions-free energy generated by those facilities. PacifiCorp 12

is required by FERC’s regulations to maintain the Klamath facilities in a manner such 13

that they remain capable of safely generating electricity consistent with the purpose of 14

the project license. Additionally, the Company must maintain compliance with 15

applicable regulatory requirements that address dam safety, worker safety, and 16

environmental regulatory requirements applicable to the project developments. To be 17

in full compliance with FERC’s regulations, PacifiCorp, as the licensee of the 18

Klamath Hydroelectric Project, is responsible to ensure the project facilities are 19

suitable for continued operation until the project is transferred to another party that 20

has the financial and technical capabilities to ensure continued operations, or until the 21

project developments are decommissioned and fully removed. These requirements to 22

continue to prudently operate the project developments—and make necessary capital 23

additions to do so—are not alleviated or excused by the fact that there is a pending 24



license transfer application being considered by FERC, or because the hydroelectric 1

developments may be transferred to the Klamath River Renewal Corporation for 2

removal pursuant to the Klamath Hydroelectric Settlement Agreement. 3

In compliance with FERC’s dam safety regulations, found at 18 Code of 4

Federal Regulations Part 12(d), the Company must ensure that the project works of 5

each hydroelectric development are periodically inspected and evaluated by an 6

independent consultant. The purpose of these inspections is to identify any actual or 7

potential deficiencies—whether in the condition of those project works or in the 8

quality or adequacy of project maintenance, surveillance, or methods of operation—9

that might endanger public safety. Accordingly, the Klamath Hydroelectric Project 10

developments were inspected in 2019 and the associated Consultant Safety Inspection 11

Reports were submitted to FERC on October 31, 2019. The independent consultant 12

made a number of recommendations for enhancement of project safety which have 13

now become compliance requirements that PacifiCorp must complete. 14

The capital projects planned for the Klamath are required to ensure the project 15

is suitable for continued operation, is operated safely and efficiently, and complies 16

with FERC dam safety requirements until the transfer of the Project occurs. A list 17

and description of these capital projects is shown in Confidential Exhibit PAC/2701. 18

Failure to make these capital investments would not provide for the safe and reliable 19

continued operation of the project until its planned transfer and could result in the 20

Company being out of compliance with FERC’s dam safety requirements. 21

Q. Does this conclude your reply testimony? 22

A. Yes. 23

REDACTED Docket No. UE 374 Exhibit PAC/2701 Witness: Timothy J. Hemstreet

BEFORE THE PUBLIC UTILITY COMMISSION

OF OREGON

PACIFICORP

___________________________________________________________

Redacted Exhibit Accompanying Reply Testimony of Timothy J. Hemstreet

Klamath Hydroelectric Project Capital Additions

June 2020

Klamath Hydroelectric Project Capital Additions

WBS Element Project Project Purpose and NeedIn-Service Amount

HKOR/2019/C/005 Eastside Flowline RemovalThe purpose of this project is to address the collapse of the wood stave flowline consistent with FERC requirements, improve worker and public safety in the vicinity of the flow line, and restore water \delivery infrastructure necessary to preserve the East Side powerplant water rights.

HKOR/2017/C/004 JC Boyle 1 and 2 Refurbish Exciters

The purpose of this project is to replace a frequently failing analog excitation controller with a new digital excitation controller. An average of two 24-hour forced outage per year occurs due to instability of the exciter’s analog control circuitry. A complete failure of the excitation system on any of the two units will result in at least three months of unit outage and loss of generation. The new digital control system will eliminate this problem.

HKCA/2018/C/018 Copco 2 Install Spillway Chutes

The purpose of this project is to install spillway chutes that will avoid uncontrolled release of water from Copco 2 dam as a result of overtopping the existing spillgates. Overtopping of spillgates, as occurred on December 1, 2017, was the result of a surcharge of up to six inches over the spillway gates for a period of up to 20 minutes at Copco 2. The incident was classified as an “uncontrolled” release of water and was reported to the FERC consistent with FERC regulations. This incident, along with a number of other overtopping incidents at Copco 2, are potential compliance issues and must be mitigated to avoid potential dam safety compliance findings.

HKOR/2019/C/003 JC Boyle Red Barn Refurbishment

This project will refurbish the JC Boyle Red Barn to address safety and functionality requirements for this building which functions as an office, meeting and training location and shop. The refurbishment will help attract and retain a quality workforce and will include: address the undersized HVAC system, refurbishment of the existing overhead doors to install springs and openers for worker safety and improved operation, replacement of worn office furniture, building lighting efficiency upgrade, flooring replacement, and installation of double-pane insulating windows.

HKCA/2016/C/007Iron Gate Hatchery Replace Recirculation System

The Iron Gate Hatchery requires water supplied from the Iron Gate Dam for fish egg production. In the event of failure of this water supply, a recirculation pump and system normally would recirculate water in the hatchery facility until the water supply is returned to service. The recirculation pump has failed due to severe corrosion along with some of the piping system and requires replacement

APR 10025978 Iron Gate Intake Building Bat Mitigation

This project will install bat mitigation equipment at the Iron Gate penstock intake building. Every spring migrating bats take up residence in the Iron Gate penstock intake building. Their urine and feces covers the surfaces inside the building which creates an unhealthy working environment and a strong odor. The building is sealed from bat entry but there are openings through the building floor where the gate moves up and down.

HKOR/2019/C/006 JC Boyle Vibration Monitoring System

The purpose of this project is to purchase and install a new Vibration Monitoring System at the JC Boyle plant. A vibration monitoring system provides a real-time monitoring and protection of the generator and will issue an immediate stop when a high vibration is detected due to any mechanical anomalies. The existing vibration monitoring system was installed more than 10 years ago and has now failed. A replacement is needed to continue a safe operation of the generator.

HKCA/2019/C/002 Iron Gate Rebuild Mechanical Governor

The purpose of this project is to rebuild the mechanical governor at the Iron Gate plant. The Iron Gate turbine wicket gates and Howell Bunger valve is controlled by a unique mechanical governor. In order to address component wear, corrosion, oil leaks, etc., the governor is disassembled and moving parts, bearings, seals, pins, etc. are either refurbished or replaced. The required overhaul cycle for this governor is typically once every 5 years. The last time the governor was rebuilt was in 2012, which was 7 years ago. During this rebuild, over 20 different types of parts were replaced and over 80 new or rebuilt components were used in order to rebuild the governor to "as new" condition so that it can continue to work property and assure that Klamath River flows are maintained in the case of a plant trip or interruption of flows through the turbine.

APR 10028727 Westside Plant Retaining Wall Refurb

This project will refurbish and reinforce the lower access road retaining wall at the Westside Plant in Klamath Falls. The wall holding up the access road is deteriorating and failing. The project will consist of a steel reinforced concrete wall to go up against existing wall. Drainage solutions on top of the road are to be addressed, as this has aided in the failure of the wall over the years.

HKOR/2019/C/001 Keno Replace Fish Ladder Stop LogsThis project will design and fabricate a stop log for the Keno dam fish ladder inlet. There currently is no stop log for this location and this prevents dewatering and performing inspections and maintenance to the fish ladder.

APR 10028530 Copco 2 Mule Wheel Replacement

Existing cast wheels on the two moveable gate hoists at Copco No. 2 were observed to be cracked and are unrepairable. The movable gate hoists were fabricated in the 1920s and replacement wheels are not available. This project will fabricate and install new wheel assemblies (wheels, axles, and bearings) for the two hoists. Complete new wheel assemblies are required because the existing wheels are heat-fitted to the existing axles and cannot be removed. Replacement is necessary to ensure the Copco 2 spill gates can be reliably operated to pass flood flows and make water releases.

HKCA/2019/C/005 Copco Waterline Section Replacement

The COPCO 2 Domestic Water Line is fed from a well and pumping station and supplemented with water from the City of Yreka. There has been a leak (or leaks) that is consuming a significant portion of the domestic water make up to the domestic water storage tank. The well system has been unable to keep up and an unusually high Yreka City water bill has indicated the domestic water is being wasted thru the leaks. This project replaces approx. 1000 foot of domestic waterline.

APR 10025980 Iron Gate Tailrace Level IndicationThis project will install water level indication at the Iron Gate tailrace to allow for water level monitoring and ensure plant operations can be monitored and controlled consistent with ramp rate requirements.

HPOR/2018/C/001/027 BC - Keno, Replace Fish Ladder SensorThe level sensor controlling the Keno Dam Fish Ladder has failed. The sensor is non repairable. This project replaces the failed sensor with an ultrasonic sensor, installs a new mounting bracket and reroutes the electrical conduit. This installation will be consistent with other level sensor installations in Hydro South.

HPOR/2019/C/001/015 BC - Iron Gate, Replace HMI EquipmentThis project will replace the existing HMI extender equipment at the Iron Gate powerhouse. The HMI extender equipment allows the powerhouse to be monitored and operated from the office and the control room on the turbine deck. A recent lightning storm caused the existing HMI extender equipment to fail and the system is no longer operable.

HKCA/2019/C/006 Copco 11 Replace Governor ControllerThe purpose of this project is to replace the failed processor in the COPCO Unit 11 Governor. The COPCO Unit 11 Governor Hydro Turbine Controls uses a Woodward 505H processor as part of the control system. The 505H processor has failed and requires replacement to maintain safe and reliable operation.

HPOR/2019/C/001/012 BC - JC Boyle, Fish Screens Soft Starter

The purpose of this project is to replace the existing motor starter for the JC Boyle fish screen wash pump with a new soft-start motor starter. The existing fish screen wash pump motor starter recently failed and due to the critical nature of the fish screen system, another motor starter was taken from another part of the facility and placed into temporary service in the fish screen system. A new soft-start motor starter is required to maintain long term license compliance obligations with respect to fish passage and continued operation of the JC Boyle Hydroelectric Development.

Total 3,209,341$

Exhibit PAC/2701Hemstreet/1REDACTED

docket no. ue 374 exhibit pac/2700 witness: timothy j. … · 2020. 7. 1. · 20 and that these...

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