redacted docket no. 20000- -er-20 witness: timothy j ......page 5 – direct testimony of timothy j....

REDACTED Docket No. 20000-___-ER-20 Witness: Timothy J. Hemstreet

BEFORE THE WYOMING PUBLIC SERVICE

COMMISSION

ROCKY MOUNTAIN POWER

____________________________________________

REDACTED Direct Testimony of Timothy J. Hemstreet

March 2020

- Direct Testimony of Timothy J. Hemstreet

INTRODUCTION AND QUALIFICATIONS 1

Q. Please state your name, business address, and present position with PacifiCorp. 2

A. My name is Timothy J. Hemstreet. My business address is 825 NE Multnomah Street, 3

Suite 1800, Portland, Oregon 97232. My title is Managing Director of Renewable 4

Energy Development for PacifiCorp. I am testifying for PacifiCorp d/b/a Rocky 5

Mountain Power (“PacifiCorp” or the “Company”). 6

Q. Briefly describe your education and professional experience. 7

A. I hold a Bachelor of Science degree in Civil Engineering from the University of Notre 8

Dame in Indiana and a Master of Science degree in Civil Engineering from the 9

University of Texas at Austin. I am also a Registered Professional Engineer in the state 10

of Oregon. Before joining PacifiCorp in 2004, I held positions in engineering 11

consulting at CH2M HILL (now Jacobs Engineering, Inc.) and environmental 12

compliance at RR Donnelley Norwest, Inc. Since joining PacifiCorp, I have held 13

positions in environmental policy and compliance, engineering, project management, 14

and hydroelectric project licensing and program management. In 2016, I assumed a 15

role in renewable energy development, focusing on PacifiCorp’s wind repowering 16

effort, and assumed my current role in June 2019, in which I oversee the development 17

of renewable energy resources that enhance and complement PacifiCorp’s existing 18

renewable energy resource portfolio. 19

Q. Have you testified in previous regulatory proceedings? 20

A. Yes. I have previously sponsored testimony in California, Idaho, Oregon, Utah, 21

Washington, and Wyoming. 22


PURPOSE OF TESTIMONY 1

Q. What is the purpose of your testimony in this proceeding? 2

A. To provide an update on the Company’s wind repowering project, which was 3

previously approved by the Wyoming Public Service Commission (“Commission”) in 4

Docket No. 20000-519-EA-17, and to demonstrate that PacifiCorp’s upgrades to 5

“repower” the Leaning Juniper1 and Foote Creek I2 wind facilities—which were not 6

subject to the Commission’s prior order—are prudent and in the public interest. My 7

testimony provides the following information: 8

• The scope of the Foote Creek I and Leaning Juniper repowering projects; 9

• The financial benefits for customers of repowering resulting from the 10

qualification for federal production tax credits (“PTCs”); 11

• The increased energy benefits following repowering; 12

• The reduced ongoing operating costs following repowering; 13

• The extension of the wind facility asset life after repowering; 14

• Project implementation status and construction schedule; and 15

• The disposition of removed equipment. 16

1 In the Matter of the Application of Rocky Mountain Power for an Order Approving Nontraditional Ratemaking Related to Wind Repowering, Docket No. 20000-519-EA-17 (Record No. 14780), Memorandum Opinion, Findings and Order Approving Stipulation (Dec. 21, 2018). The 11 wind facilities approved for repowering from this docket are Glenrock I, Glenrock III, Rolling Hills, Seven Mile Hill I, Seven Mile Hill II, High Plains, McFadden Ridge, Dunlap I, Marengo I, Marengo II, and Goodnoe Hills and will be referred to collectively as the “Wind Repowering Project.” Leaning Juniper was removed from the Company’s request for pre-approval in Docket No. 20000-519-EA-17 and the Company is demonstrating that the benefits to repower this facility are prudent and in the public interest within this rate case. 2 In the Matter of the Application of Rocky Mountain Power for a Certificate of Public Convenience and Necessity to Remove Existing Wind Turbines, Construct New Wind Turbines and Update Collector Lines at Its Foote Creek I Wind Energy Site, Docket No. 20000-519-EN-19 (Record No. 15202), Memorandum Opinion, Findings and Order Approving Application (Sept. 12, 2019) (Company’s application requesting a certificate of public convenience and necessity to repower the Foote Creek I wind facility)


My testimony will demonstrate that the Company is prudently managing the 1

Wind Repowering Project and that the Company’s decision to repower the Leaning 2

Juniper and Foote Creek I facilities is reasonable and prudent, and should be included 3

in the Company’s revenue requirement in this case.34

SUMMARY OF TESTIMONY 5

Q. Please summarize your testimony. 6

A. Through its wind repowering efforts, PacifiCorp is leveraging past investments in its 7

wind fleet and enhancing the future value of these resources for the benefit of its 8

customers. The Company’s repowering efforts now include all of its owned wind 9

resources, including the Leaning Juniper and Foote Creek I facilities. Foote Creek I is 10

the oldest resource in the Company’s wind fleet. By taking advantage of the unique 11

opportunity to repower these facilities, the Company is able to deliver its customers 12

efficiency and reliability improvements in wind generation technology, and a wind fleet 13

that is returned to like-new condition, all while enhancing performance, reducing 14

ongoing maintenance expenditures, and reducing customer costs. 15

Repowering incorporates recent technical advances that allow for installation 16

of longer blades and nacelles with higher capacity generators, resulting in 17

814 additional gigawatt-hours (“GWh”) of low-cost energy for customers annually, or 18

an increase of 27 percent across the entire wind fleet. In addition to this significant 19

increase of energy, repowering will extend the asset lives of the wind facilities by at 20

3 Docket No. 20000-519-EA-17 (Record No. 14780), Memorandum Opinion, Findings and Order Approving Stipulation at 18 (expressly reserved determination of ratemaking issues related to the Company's Wind Repowering Project to further proceedings before the Commission); Docket No. 20000-519-EN-19 (Record No. 15202), Memorandum Opinion, Findings and Order Approving Application at 12 (expressly reserved determination of ratemaking treatment for the Foote Creek I repowering project to further proceedings before the Commission). The Company is requesting to include the cost of these projects along with the costs of repowering Leaning Juniper within the revenue requirement of this rate case.

– Direct Testimony of Timothy J. Hemstreet

least 10 years, allowing the wind facilities to continue serving customers well into the 1

future. 2

Finally, these repowering benefits can be delivered to customers while 3

reducing, rather than increasing, costs to customers, as further described in the 4

testimony of Mr. Rick T. Link. 5

In Docket No. 20000-519-EA-17, PacifiCorp received approval for the Wind 6

Repowering Project (excluding the Leaning Juniper and Foote Creek I facilities), which 7

included a cost cap.4 PacifiCorp’s request in this rate case is to establish rates that will 8

allow the Company to recover costs for wind repowering that were approved by the 9

Commission in Docket No. 20000-519-EA-17. The Company also requests a prudence 10

determination and cost recovery for repowering the Leaning Juniper and Foote Creek 11

I wind facilities. The Leaning Juniper facility was removed by the Commission from 12

the list of repowering projects approved in Docket No. 20000-519-EA-17. The 13

Company subsequently made the decision to repower the facility after improved cost 14

and performance for the project were obtained as compared to that previously 15

evaluated. The improved cost and performance rendered the customer benefits from 16

repowering the facility comparable to the benefits of the other projects that were 17

approved by the Commission in Docket No. 20000-519-EA-17. The Company filed 18

and received Commission approval for a certificate of public convenience and necessity 19

("CPCN") to repower the Foote Creek I facility in 2019 in Docket No. 20000-553-EN-20

4 The Company received all necessary regulatory pre-approvals for both the Wind Repowering Project in Docket No. 20000-519-EA-17 and the new wind/transmission project in Docket No. 20000-520-EA-17. The Commission approved the stipulations that were filed in both dockets. Paragraph 80.f. of the stipulation that was submitted in Docket No. 20000-520-EA-17 defines the combined cost cap as percent above the Company’s combined cost estimates for both the Wind Repowering Project and the new wind/transmission project.

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19. The Company proceeded to repower that project after finalizing necessary 1

commercial arrangements. 2

OVERVIEW OF WIND REPOWERING AND PROJECT SCOPE 3

Q. Please briefly describe what repowering a wind facility entails. 4

A. Repowering broadly describes the upgrade of an existing, operating wind facility with 5

new wind-turbine-generator (“WTG”) equipment that can increase a facility’s 6

generating capacity and the amount of electrical generation produced from the facility. 7

Specifically, PacifiCorp’s repowering effort involves replacing the nacelle, hub, and 8

rotor of the WTG at all facilities, except the Foote Creek I facility, where repowering 9

will involve replacement of the existing WTGs, including the foundations and towers. 10

Exhibit RMP___(TJH-1) includes a depiction of a wind turbine and its various 11

components. 12

Q. Which facilities have been or will be repowered? 13

A. PacifiCorp has or will repower the facilities known as Dunlap, Foote Creek I, Glenrock 14

I, Glenrock III, Goodnoe Hills, High Plains, Leaning Juniper, Marengo I, Marengo II, 15

McFadden Ridge, Rolling Hills, Seven Mile Hill I, and Seven Mile Hill II. At 11 of the 16

13 facilities – all facilities except for Dunlap and Foote Creek I5 – major construction 17

activities are complete and the repowered facilities are now in commercial operation. 18

Q. How many megawatts (“MWs”) of installed wind capacity is PacifiCorp 19

repowering? 20

A. PacifiCorp is repowering all of its 13 wind facilities, representing approximately 21

1,040 MW of installed wind capacity prior to repowering. After repowering, the 22

5 Repowering will occur in 2020 for Dunlap and Foote Creek I.


capacity of the repowered facilities will increase to approximately 1,064 MW due to 1

increased transmission interconnection capacity at the Marengo I and Marengo II 2

facilities, and full utilization of the 41.4 MW interconnection capacity at Foote Creek I. 3

Detailed information about the wind facilities that have been or remain to be repowered 4

is included in Exhibit RMP___(TJH-2). 5

Q. Please explain why repowering is feasible for these wind facilities. 6

A. The wind facilities PacifiCorp is repowering began commercial operations between 7

1999 and 2010. Aside from the Foote Creek I facility, the facilities in PacifiCorp’s wind 8

fleet can be economically repowered, or upgraded, with new technology that will 9

improve their efficiency and increase their generation output, without incurring the cost 10

to replace the existing towers, foundations, and energy collection systems, which are 11

of sufficient design to accommodate more modern equipment now available. The 12

existing foundations and towers, although more than 10 years old in some instances, 13

are adequately designed to accommodate larger, more modern WTG equipment and 14

still have a sufficient remaining useful life to economically justify the associated 15

investment. 16

Q. As you indicated above, the Commission excluded Leaning Juniper from the 17

repowering pre-approval docket. Why did the Company move forward with 18

repowering Leaning Juniper? 19

A. There were two major factors that changed, and resulted in the Leaning Juniper 20

repowering demonstrating more significant customer benefits. Following the 21

conclusion of the proceeding in Docket No. 20000-519-EA-17, the Company was able 22

to negotiate more favorable pricing for the Leaning Juniper repowering project and new 23


equipment specifications resulted in slightly improved performance for the repowered 1

project. This reduced cost and increased energy output improved the economics of 2

repowering the facility, resulting in customer benefits similar to those obtained from 3

the other repowering projects that were approved by the Commission. Given these 4

favorable changes, the Company elected to pursue repowering of the Leaning Juniper 5

project and seeks a prudence determination and cost recovery for this project through 6

this rate case proceeding. 7

Q. Is repowering at Leaning Juniper now complete? 8

A. Yes, the repowered Leaning Juniper facility achieved commercial operation on 9

September 13, 2019, although minor work to finalize the project continues. 10

Q. How did the cost and performance of the Leaning Juniper project change as 11

compared to the assumptions used by the Company when Leaning Juniper was 12

proposed for repowering in Docket No. 20000-519-EA-17? 13

A. Anticipated costs for the project were reduced by , and the incremental 14

generation from the project increased by approximately megawatt-hours. The 15

improved economics of the project are described in Mr. Link’s testimony. 16

Q. As you mentioned earlier, the scope of repowering at Foote Creek I is different 17

than repowering at the Company’s other wind facilities. Can you provide 18

additional background on the Company’s decision to repower Foote Creek I? 19

A. Foote Creek I, as the Company’s oldest wind facility, began commercial operation in 20

April 1999. The facility served as a demonstration project to evaluate the feasibility of 21

utility-scale wind energy. The facility was developed in partnership with the Eugene 22

Water & Electric Board (“EWEB”) and the Bonneville Power Administration (“BPA”). 23

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Redacted


As developed, Foote Creek I was co-owned by EWEB (21.21 percent ownership) and 1

PacifiCorp (78.79 percent ownership), with BPA taking 37 percent of the facility’s 2

output through a 25-year cost-based power purchase agreement (“PPA”). As the first 3

utility-scale wind energy project in Wyoming, Foote Creek I was sited at one of the 4

most favorable wind sites in the United States and enjoys the highest wind speeds of 5

any of the Company’s wind projects. Unlike the remainder of the facilities the 6

Company is repowering, the Foote Creek I project is unique in that it was co-owned 7

and also had a third-party PPA associated with the resource. 8

The Foote Creek I facility currently consists of 68 turbines with a 600-kilowatt 9

generating capacity, a rotor diameter of 42 meters, and towers that support a 40 meter 10

hub height. Although employing the latest technology when originally installed, the 11

existing turbines are costly to operate and maintain relative to the Company’s more 12

modern turbines that have a much higher nameplate capacity, larger rotor diameters, 13

and taller towers. Accordingly, the operations and maintenance costs of the Foote Creek 14

I facility are the highest of all of the Company-owned wind resources on a per-MW 15

basis since the maintenance requirements for these smaller turbines are similar to those 16

of larger turbines, but the capacity of the Foote Creek I turbines is much less. 17

The costs associated with continued operation of the existing turbines at Foote 18

Creek I for both the Company and EWEB would increase after the expiration of the 19

BPA PPA in April 2024 since 37 percent of these costs would no longer be covered 20

through the cost-based PPA. Similarly, BPA was required to take higher cost energy 21

from the project until the PPA expired. For these reasons, PacifiCorp, EWEB, and BPA 22

were all motivated to explore whether the existing Foote Creek I project could be 23


unwound in order to achieve an outcome more favorable to customers as compared to 1

continuing to operate the facility through its planned 30-year asset life. Repowering the 2

facility presented the opportunity to realize this outcome for customers. 3

Q. Please explain what repowering at the Foote Creek I wind facility involves. 4

A. The WTG equipment at Foote Creek I has a low generating capacity (600 kilowatts) 5

per turbine and the towers and foundations supporting the nacelle and rotor do not have 6

the necessary height or design strength to accommodate the installation of modern 7

larger nacelles and rotors capable of generating a much greater amount of electricity 8

per WTG. 9

Due to the limitations of the older facility, repowering Foote Creek I requires 10

complete removal and replacement of the old wind turbine equipment. The towers, 11

foundations and energy collection system must be replaced with new foundations to 12

support the larger towers and appropriately sized energy-collector circuits. Repowering 13

the Foote Creek I facility will result in the replacement of the current 68 small-capacity 14

wind turbines at the site with 13 modern wind turbines. 15

Q. What was necessary for the Company to repower the project? 16

A. Because of the very favorable wind conditions at the site, the Company was interested 17

in repowering the facility so that customers could benefit from the low-cost energy that 18

could be generated at the site with modern wind turbine equipment qualified at 19

100 percent of the value of the PTCs. To achieve that, however, it was necessary for 20

the Company to acquire EWEB’s ownership share of the facility and to terminate the 21

existing PPA with BPA. The Company negotiated a PPA termination agreement with 22

EWEB and BPA, and a purchase and sale agreement with EWEB for its interests in the 23


facility. The termination of the PPA was negotiated to be effective upon PacifiCorp’s 1

acquisition of EWEB’s interest in the project, and the closing of the purchase and sale 2

agreement with EWEB was contingent upon the Company obtaining necessary 3

regulatory and permitting approvals related to repowering as well as satisfactory 4

commercial arrangements for turbine supply and construction that ensured repowering 5

could occur. 6

Q. How much did the Company pay EWEB for its interests in the facility? 7

A. PacifiCorp paid EWEB approximately for its interests in the facility. 8

Q. Did the Company incur costs to terminate the Foote Creek I PPA with BPA? 9

A. No. Under the termination agreement, BPA paid an early termination payment for the 10

facility in the amount of , of which —the Company’s 11

78.79 percent ownership share of the facility--was paid to the Company. This payment 12

to the Company and EWEB reflected the fact that BPA realizes savings by terminating 13

the PPA early and replacing the power with lower cost energy resources. 14

Q. Were these amounts consistent with the Company’s expectations? 15

A. Yes, these payments were consistent with the Company’s economic analysis of the 16

Foote Creek I repowering project, which is described by Mr. Link. 17

Q. Did the Company enter other commercial arrangements related to repowering at 18

Foote Creek I? 19

A. Yes, the Company executed a turbine supply agreement with Vestas American Wind 20

Technology, Inc. (“Vestas”) and executed a balance of plant construction contract with 21

Thorstad Companies, Inc. Both contracts were awarded following competitive 22

solicitation processes. When these contracts were finalized, the Company proceeded to 23

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Redacted


close on the purchase of EWEB’s interest in the project and terminate the PPA. The 1

Company also purchased the wind energy lease rights for the Foote Creek I facility. 2

Q. Why did the Company purchase the wind energy lease rights for Foote Creek I? 3

A. The Company was operating the Foote Creek I facility under land rights that were 4

subleased from Chandar Energy Land Associates, Inc. (“CELA”), which held the 5

master wind energy lease rights with the ultimate property owners upon whose land the 6

Foote Creek I turbines are located. Taking into account the high-value wind energy 7

resource at the site, the wind energy production-based lease payments owed to CELA 8

under the sublease were still more costly than what the Company pays for similar 9

production-based wind energy leases. The Company was able to negotiate the purchase 10

of the master wind energy leases from CELA at a cost that improved the economics of 11

the Foote Creek I repowering project relative to continuing to operate under the existing 12

sublease. Additionally, the master wind energy lease rights can be renewed for a total 13

term of up to 99 years, providing potential future customer benefits beyond the asset 14

life of the repowered Foote Creek I facility. 15

Q. Were there unique permitting requirements related to Foote Creek I as compared 16

to the other repowering projects? 17

A. Yes. It was necessary for the Company to obtain approval of a new CPCN from the 18

Commission related to repowering the facility and a new Conditional Use Permit from 19

Carbon County, Wyoming. The Company also had to obtain concurrence from the 20

Bureau of Land Management (“BLM”) that repowering was consistent with the 21

existing right of way grant from BLM for the facility, and the Company worked with 22

the U.S. Fish and Wildlife Service to review the locations of the new turbines on the 23


existing project footprint to evaluate and minimize potential avian impacts associated 1

with the new turbine layout. 2

Q. When did the Company finally approve repowering the Foote Creek I facility? 3

A. The Company approved repowering the facility on June 25, 2019. The Company then 4

closed on the purchase of EWEB’s interest in the facility on July 24, 2019, after 5

commercial arrangements to repower the facility were finalized. Following approval of 6

the repowering project, the Company was able to negotiate the purchase of the master 7

wind leases and incorporated this change into the project scope. The Company 8

subsequently closed on the purchase of the master wind energy lease rights from CELA 9

on August 8, 2019. 10

Q. What repowering costs is the Company seeking to recover in this filing? 11

A. Given the Company’s previous filings related to repowering its wind fleet, the 12

Company is seeking to recover costs associated with the Wind Repowering Project, the 13

facilities previously determined by the Commission to be prudent to repower, as well 14

as the costs to repower the Leaning Juniper facility and the costs to acquire the wind 15

energy lease rights and repower the Foote Creek I wind facility. 16

Q. What benefits will customers realize from repowering Leaning Juniper and Foote 17

Creek I? 18

A. Repowering these facilities re-qualifies them for PTCs, which are benefits that are 19

passed through to customers. Additionally, repowering increases the amount of zero 20

fuel cost energy produced from the repowered facilities, as shown in Confidential 21

Exhibit RMP___(TJH-3). Further, by replacing older WTG equipment, which is 22

subject to more failure and maintenance issues than newer equipment, repowering will 23


reduce PacifiCorp’s ongoing operating costs. Finally, repowering the wind facilities 1

with new WTG equipment will extend the useful lives of the facilities by up to 21 years, 2

creating substantial energy and capacity benefits for customers in the future when this 3

wind facility would otherwise have been retired from service. 4

REQUALIFICATION FOR PTCS 5

Q. How do wind facilities qualify for the PTC extension enacted in 2015? 6

A. On December 18, 2015, Congress enacted changes to the federal Internal Revenue 7

Code extending the full value of the PTC for wind facilities that began construction in 8

2015 and 2016. The legislation also provided for a phase-out of the PTC over 9

three years, reducing the PTC value by 20 percent for wind facilities beginning 10

construction in 2017, 40 percent for wind facilities beginning construction in 2018, and 11

60 percent for wind facilities beginning construction in 2019. The Internal Revenue 12

Service (“IRS”) has issued guidance that establishes a “safe harbor” for taxpayers to 13

demonstrate the year a facility will be deemed to “begin construction,” thereby setting 14

the value of the PTC. If at least five percent of the total project costs were incurred in 15

2016, then the facility qualifies under the IRS safe harbor for the full value of the PTC, 16

provided the taxpayer can demonstrate “continuous efforts” to complete construction. 17

The IRS has issued additional guidance that establishes a safe harbor for satisfying this 18

continuous-efforts standard. Under the continuous-efforts safe harbor, the wind 19

facilities must be in service by the end of the fourth calendar year following the 20

calendar year in which construction began. Thus, wind facilities that began construction 21

in 2016 must be in service no later than December 31, 2020, to satisfy the continuous-22

efforts safe-harbor provisions. If the facilities are not placed in service by December 23


31, 2020, the projects must satisfy IRS requirements that continuous-efforts were 1

expended to repower the facilities, which may be a more challenging standard to meet. 2

Q. What is the full value of the PTC for wind facilities? 3

A. For 2019, wind facilities that are qualified for the PTC will receive 2.5 cents per 4

kilowatt-hour, or $25 per megawatt-hour. This PTC value is adjusted annually based 5

upon an inflation index, and the PTC is available for energy produced during the 6

10-year period after the wind facility begins commercial operation. 7

Q. Do the Leaning Juniper and Foote Creek I repowering projects qualify for the full 8

value of the PTC under these rules? 9

A. Yes. Consistent with IRS guidance, a facility owner can demonstrate that construction 10

of a facility has begun in the year in which at least five percent of the applicable project 11

costs are incurred. If wind turbine equipment is purchased and delivered in 2016, and 12

the equipment comprises at least five percent of the applicable project costs, a PTC 13

“safe harbor” is created for the wind facilities subsequently constructed. To meet this 14

requirement, PacifiCorp executed safe harbor equipment purchases with General 15

Electric International, Inc. and Vestas in December 2016, and took delivery of 16

equipment with a value sufficient to give the company the ability to repower its entire 17

wind fleet and qualify the repowered wind facilities for 100 percent of the PTC value. 18

For the Foote Creek I facility, PacifiCorp will use safe harbor equipment that will be 19

obtained from Berkshire Hathaway Energy Renewables, a Berkshire Hathaway Energy 20

subsidiary, which similarly made safe harbor equipment purchases from Vestas in 21

December 2016 of equipment that can be used to qualify the Foote Creek I project for 22

100 percent of the PTC value. 23


Q. What other requirements must repowered projects satisfy to qualify for the PTCs? 1

A. On May 5, 2016, the IRS issued Notice 2016-31, which provides guidance on various 2

aspects of qualifying for the PTCs and whether new tax credits can be claimed when 3

wind turbines are repowered or retrofitted. Notice 2016-31 generally provides that the 4

repowering costs must equal at least four times the fair market value of the equipment 5

that the owner retains from the original facility for the repowered turbines to qualify 6

for new PTCs. Thus, 80 percent of the fair market value of the repowered WTG must 7

result from repowering project costs while the value of the retained components cannot 8

exceed 20 percent of the fair market value of the new facility. This “80/20” test is 9

applied on a turbine-by-turbine basis. Each wind turbine-composed of a foundation, 10

tower, and machine head (including nacelle, hub and rotor), is considered a separate 11

facility. 12

Q. Does the Leaning Juniper facility pass this 80/20 test? 13

A. Yes, the Leaning Juniper project passes this 80/20 test, similar to PacifiCorp’s other 14

repowering projects. 15

Q. Is the Foote Creek I facility subject to this 80/20 test? 16

A. No, because the Foote Creek I facility will be repowered without using any retained 17

wind turbine components. The tower and foundations of the existing turbines at the site 18

will not be reused, unlike at PacifiCorp’s other repowering projects. In other words, the 19

applicable repowering costs at Foote Creek I, on a per-turbine basis, will equal 20

100 percent at this facility. 21


Q. Have recent changes to federal tax laws impacted the ability to qualify the 1

Company’s repowered facilities for PTCs? 2

A. No. Neither the Tax Cuts and Jobs Act, enacted into law in December 2017, nor the 3

Tax Extender and Disaster Relief Act of 2019 change the qualification requirements 4

that allow all of the Company’s repowered wind facilities to receive the full value of 5

PTCs. 6

INCREASED ENERGY BENEFITS FOLLOWING REPOWERING 7

Q. Once repowered, how do the energy benefits of the Leaning Juniper and Foote 8

Creek I wind facilities increase? 9

A. At Leaning Juniper, repowering will involve the replacement of the existing machine 10

heads, including the nacelle, hub and rotor, while the Foote Creek I facility will employ 11

entirely new wind turbines with new foundations and taller towers. The new nacelles 12

have generators that have a greater nameplate generating capacity than the removed 13

equipment. For example, the nameplate rating of the turbines at Leaning Juniper will 14

increase from 1.5 MW to 1.6 MW. At Foote Creek I, the new turbines installed at the 15

site will have generator nameplate ratings of 2.0 MW and 4.2 MW, replacing existing 16

turbines with a 0.6 MW nameplate rating. Details regarding the proposed wind turbine 17

upgrades, capital project costs, in-service dates, and resulting energy benefits are 18

shown in Confidential Exhibit RMP___(TJH-3). 19

In addition to the larger generators in the repowered turbines, the new turbines 20

also include larger blades, which will increase the rotor-swept area of the wind turbines. 21

A larger rotor-swept area allows more of the wind energy flowing past the wind turbine 22

to be captured and converted by the wind turbine into electricity. Because the size of 23


the rotors will increase, the repowered turbines will also include more robust hubs, 1

main shafts, bearings and couplings, and gearboxes suitable to handle the greater torque 2

exerted by the larger rotors. 3

Finally, the Foote Creek I repowering project will result in all of the facility’s 4

output serving the Company’s customers as compared to only approximately 47 percent 5

under the earlier co-ownership and PPA structure. With the entire output of Foote Creek 6

I directed to the Company’s customers, and with the increased generation from the 7

more efficient turbines, the amount of zero-fuel-cost energy provided to customers by 8

the facility will increase by more than percent. 9

Q. Will the larger blades installed with repowering increase the potential for avian 10

impacts at the wind facilities? 11

A. Not necessarily. Although the larger blades will increase the overall risk zone (rotor-12

swept area) of the repowered wind turbines, this does not necessarily correlate with an 13

increased risk of avian impacts at existing turbine sites. PacifiCorp performs monthly 14

monitoring at all of its wind facilities and reports all findings to state wildlife agencies 15

and the U.S. Fish and Wildlife Service. PacifiCorp will continue this monthly 16

monitoring to determine if the new turbine blades cause additional impacts to avian 17

species and will engage with the appropriate agency to discuss and, if prudent and 18

practicable, implement additional avoidance, minimization, or mitigation measures. 19

Q. Are there other ways that the Company has worked to minimize avian impacts? 20

A. Yes. At the Foote Creek I facility, the significant reduction in the number of turbines 21

possible with site repowering means that less of the overall project site area will be 22

covered by wind turbines. This has allowed the Company to adjust the layout of the 23

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wind turbines at the project site to avoid areas of higher avian use, such as the edges of 1

Foote Creek Rim, minimizing potential avian impacts. 2

Q. How did PacifiCorp determine the amount of additional generation that will be 3

produced from the repowered wind turbines? 4

A. For Leaning Juniper, where the turbine locations and turbine hub heights are not 5

changing, PacifiCorp worked with its consultant, Black & Veatch (“B&V”), to use the 6

extensive data history from PacifiCorp’s facilities to derive estimates of the energy 7

production expected from repowering. This analysis used millions of data points from 8

the operational record of the facility and incorporated additional modeled wake losses 9

anticipated from the new equipment. Wake losses are the reduction in generation at 10

turbines downwind of other turbines due to reduced wind speed and increased 11

turbulence in the airflow-or wake-behind a turbine. 12

Based on its analysis, PacifiCorp and B&V estimate that energy production at 13

Leaning Juniper following repowering will increase as shown in Confidential Exhibit 14

RMP___(TJH-3), and as further discussed below. These results reflect as accurately as 15

possible the energy production that would have occurred from the repowered turbines 16

under the same operational conditions and availability as the existing equipment. 17

However, these repowering energy estimates may be conservative. They are based 18

solely on the different equipment performance specifications of the newer equipment 19

and do not account for expected improvements in operational availability of the wind 20

facilities following repowering. Availability of the wind turbines likely will improve 21

after repowering given the additional sensors and condition monitoring systems in the 22

repowered turbines that should allow for improved diagnostics and implementation of 23


preventative maintenance measures that can reduce turbine down-time. Additionally, 1

PacifiCorp will operate the new turbines under service agreements with the turbine 2

suppliers with performance guarantees and incentives that are likely to result in more 3

availability and generation than PacifiCorp has achieved in the past under similar wind 4

conditions. These contracts are discussed in more detail later in this testimony. 5

Q. How did the energy estimate methodology differ for the Foote Creek I facility? 6

A. At the Foote Creek I facility, B&V evaluated historical project generation and 7

availability data from the existing Foote Creek I turbines, local and project-specific 8

meteorological information, and the new proposed turbine layout to model the 9

anticipated energy output of the repowered wind project, similar to the approach used 10

by the Company to estimate the energy output from its new wind projects now under 11

construction. 12

Q. Why was this approach most suitable for Foote Creek I? 13

A. This approach was most suitable because the turbine locations are changing at Foote 14

Creek I, as discussed above, and also because the turbine hub heights are increasing 15

from 40 meters to 80 meters. Thus, the wind conditions-wind speeds, turbulence 16

intensity, and inflow angle to the wind turbines-experienced by the existing turbines 17

may not be representative of what the new turbines will experience. For these reasons, 18

wind modeling was relied upon to develop the energy estimate for Foote Creek I. 19

Q. What are the major power production advantages of the new equipment? 20

A. The larger rotor size and improvements in blade design of the new equipment generate 21

more power at all ranges of wind speeds. Additionally, the new turbines begin 22

producing power at a lower wind speed than the existing equipment; thus, the turbines 23


can produce energy during lower wind conditions in which the current equipment may 1

sit idle. Additionally, the new 4.2 MW capacity wind turbines have a higher cut-out 2

wind speed than the existing turbines, meaning they can continue producing power at 3

higher wind speeds in which the existing equipment at the site would shut down. 4

Because the new turbines will have an increased generator capacity, the turbines will 5

also produce more energy when wind speeds are high and the turbines are at their 6

maximum output, allowing the facility to produce equivalent capacity with far fewer 7

turbines. Exhibit RMP___(TJH-4) illustrates these power production advantages and 8

compares the power curve of the existing wind turbines to that of the new wind turbines. 9

Q. Why was this larger equipment not installed when the wind facilities were initially 10

constructed? 11

A. Wind turbine technology has continued to advance since the facilities were first 12

constructed between 2006 and 2010. The use of new composite materials has allowed 13

blade lengths to increase without adding weight, allowing for the extraction of more 14

energy from the available wind resources at the facility sites. In addition, more 15

sophisticated sensor and control systems in the wind turbines, combined with improved 16

blade pitch control systems, increase the ability of the wind turbine control systems to 17

implement load mitigation strategies on the wind turbines to reduce the loading on the 18

power train, towers and foundations. For facilities employing entirely new wind 19

turbines, these technology improvements mean that longer blades and additional 20

generating capacity are possible without a commensurate increase in cost to strengthen 21

the turbine structural components (including the tower and foundation). For new wind 22

facilities, this is one of the drivers towards reduced energy costs. For existing wind 23


facilities where the tower and foundation can be re-used, these new load mitigation 1

technologies mean that the existing towers and foundations are suitable for the 2

installation of larger equipment through repowering. 3

Q. How much additional energy will the repowered wind facilities produce? 4

A. As shown in Confidential Exhibit RMP___(TJH-3), across the wind fleet, the 5

repowered wind facilities are estimated to increase generation by 814 GWh per year, 6

an increase of 27 percent. 7

Q. Given the higher nameplate capacity of the new turbines, has the company been 8

able to increase the output capacity of the wind facilities? 9

A. As I mentioned earlier, the Company has been able to increase the allowed generation 10

interconnection agreement for the Marengo facilities, increasing the capacity of the 11

Marengo facilities from a combined 210.6 MW to 234 MW. This increase in 12

interconnection capacity allows more energy to be delivered to customers from those 13

facilities. The Company has not pursued generation interconnection increases at the 14

Goodnoe Hills and Leaning Juniper facilities given transmission constraints and costs 15

for those facilities, which are interconnected to BPA’s transmission system. For the 16

Wyoming facilities, transmission studies are still ongoing related to the Company’s 17

requests to increase the generation interconnection limits for those facilities. Thus, no 18

increase in interconnection capacity for the Wyoming facilities has been realized, and 19

the Company has not pursued necessary improvements to the energy collector systems 20

at those projects that would be necessary if additional interconnection capacity was 21

available. 22


REDUCED ONGOING OPERATIONAL COSTS FOLLOWING REPOWERING 1

Q. Aside from increased generation and the associated PTC benefits, what other 2

benefits will be realized with the Leaning Juniper and Foote Creek I repowering 3

projects? 4

A. The repowering projects will lower the ongoing capital costs of operating the existing 5

wind facilities. PacifiCorp’s turbine-supply contracts for repowering, consistent with 6

wind industry standards for new equipment, will include a two-year warranty on the 7

new equipment. This will reduce capital costs associated with replacing or refurbishing 8

turbine components currently in service. 9

The repowering projects will also result in more certainty related to ongoing 10

operations and maintenance costs of the facility. PacifiCorp will operate the repowered 11

facilities under full service agreements with the turbine equipment suppliers who will 12

be responsible for operating and maintaining the new turbines for a fixed cost while 13

attaining a guaranteed availability of the turbines. Under these agreements, failure to 14

meet the guaranteed availability, if not the result of an excusable event defined in the 15

contract, will result in the payment of liquidated damages to the Company. Customers 16

will benefit by having operations and maintenance costs fixed for the term of the 17

agreement. Thus, there is greater cost certainty related to the run-rate capital 18

expenditures and operations and maintenance costs. 19

Q. Does the new equipment address any other operational issues? 20

A. Yes. In addition to the reduced capital run rate of the new equipment in the early years 21

after installation, repowering avoided costs from replacing certain models of gearboxes 22

found at the Leaning Juniper project. These gearboxes, which were original equipment 23


supplied by the turbine manufacturer, were experiencing high failure rates compared to 1

other models of gearboxes installed elsewhere within the wind fleet. Consequently, 2

PacifiCorp experienced increased capital costs in recent years to address the gearbox 3

failures, and these models were no longer being re-installed as long-term replacement 4

equipment after failure, given their poor historical performance. 5

Q. Why are these gearbox failures significant? 6

A. These gearbox failures generally cannot be repaired “up-tower.” This means that the 7

repair cannot be completed within the nacelle without removing the damaged 8

equipment by crane. These failures cost approximately $400,000 per occurrence, 9

including equipment and labor costs to purchase and install a replacement gearbox and 10

the costs of mobilizing a large crane to the site to remove and replace the equipment. 11

These costs also do not account for the lost generation from the time the turbine is down 12

until the repair is completed. 13

Q. How many gearbox failures of this type did PacifiCorp expect at Leaning Juniper 14

if there was no repowering? 15

A. There were 28 of these gearbox models at Leaning Juniper before repowering, and 16

PacifiCorp anticipated that all of these remaining gearboxes would have failed and 17

required replacement by 2031. 18

Q. Are there similar issues with gearboxes at the Foote Creek I facility? 19

A. Yes. Gearboxes at the Foote Creek I facility have also experienced high failure rates 20

relative to other gearboxes in the wind fleet. However, the impact to the Company of 21

these failures has been mitigated by an agreement that was set to expire in 2024, at 22

which point the cost of addressing failed gearboxes would be borne entirely by the 23


Company and EWEB. Given the short remaining life of the project in 2024, with just 1

5 years of operational life remaining, turbines that experienced a failed gearbox after 2

that time could not be economically returned to service given the limited remaining 3

generation anticipated from the existing turbines and the estimated cost to replace a 4

failed gearbox. Thus, repowering also addresses the likelihood of diminished 5

generation from the Foote Creek I facility after 2024. 6

Q. What is the current asset life of the Leaning Juniper and Foote Creek I wind 7

facilities? 8

A. All of the Company’s existing wind facilities are currently being depreciated assuming 9

a 30-year asset life. Given the 1999 commercial operation date of Foote Creek I, the 10

depreciable life approved by the Commission for Foote Creek I is 2029. Similarly, the 11

2006 commercial operation date for Leaning Juniper results in an anticipated 2036 12

retirement of the facility had it not been repowered.6 In anticipation of repowering the 13

facilities, the Company has proposed in the 2018 depreciation study in Docket No. 14

20000-539-18 a new 30-year depreciable life following repowering that would extend 15

the asset life of Foote Creek I by 21 years to 2050 and extend the asset life for Leaning 16

Juniper by 13 years to 2049, similar to the other facilities that have undergone 17

repowering. 18

7 In the Matter of the Application of Rocky Mountain Power for an Order Authorizing a Change in Depreciation Rates Applicable to Its Depreciable Electric Property, Docket No. 20000-427-EA-13 (Record No. 13436), Memorandum Opinion, Findings and Order Approving Stipulation (Dec. 2, 2013).


PROJECT PERMITTING, CONSTRUCTION AND BUDGET STATUS 1

Q. What is the status of permitting related to the Foote Creek I repowering project? 2

A. PacifiCorp received approval from the Federal Aviation Administration for the new 3

turbine locations in April 2018, indicating the new turbines location and heights would 4

not pose a hazard to air navigation. Carbon County, Wyoming issued a new Conditional 5

Use Permit for the repowered project in April 2019. The BLM, upon whose land 6

approximately half of the turbines at the site are located, accepted the Company’s 7

revised plan of development for the project in June 2019, reflecting the repowered 8

project. 9

Q. What is the status of contracting related to the Foote Creek I repowering project? 10

A. In July 2019, PacifiCorp executed contracts with Vestas for turbine supply and service 11

and maintenance of the new turbines that will be installed at the site. Shortly thereafter, 12

also in July 2019, PacifiCorp executed a construction contract with Thorstad 13

Companies, Inc. for construction of the project. 14

Q. Has construction commenced on the Foote Creek I repowering project? 15

A. Yes. Initial site work began in the fall of 2019 with the installation of construction 16

trailers, foundation excavation, and material deliveries. Site work was halted for the 17

winter and will resume in early March 2020 when weather conditions are more 18

favorable for construction. Turbine component manufacturing is currently underway, 19

with turbine deliveries anticipated to begin in July 2020. 20


Q. When does the Company anticipate that Foote Creek I will enter commercial 1

operation? 2

A. Commercial operation of the repowered Foote Creek I facility is anticipated to occur 3

by December 1, 2020. 4

Q. What is the construction status of the Wind Repowering Projects that were 5

approved by the Commission in Docket No. 20000-519-EA-17? 6

A. Except for Dunlap, which was always anticipated to be repowered in 2020, major 7

construction activities have been completed at all of the Company’s repowering 8

projects, and they have all achieved commercial operation. Minor activities to finish 9

the projects remain, including completion of punch list items, site reclamation, minor 10

electrical work, control system completion, and final operational programming. 11

Q. What is the budget status for the repowered facilities that were approved by the 12

Commission in Docket No. 20000-519-EA-17? 13

A. While major construction activities at Dunlap are still yet to occur this summer, and 14

minor project-related activities continue at the remaining sites, the Company has 15

diligently managed the repowering effort and the overall cost of repowering the 16

facilities that were approved by the Commission in 2018 will not exceed the established 17

cost cap. In Mr. Chad A. Teply’s testimony, he more specifically addresses how the 18

overall repowering costs are not expected to exceed the total amount approved by the 19

Commission. 20

Q. What is the budget status for the Leaning Juniper and Foote Creek I facilities? 21

A. Similarly, for the Leaning Juniper facility, final project costs will be less than what was 22

anticipated when the Company determined to move forward with the revised project. I 23


expect that the Foote Creek I project, which will be completed in December of this 1

year, will be delivered at or near the costs anticipated by the Company when the project 2

was approved. 3

DISPOSITION OF REPLACED EQUIPMENT 4

Q. What is PacifiCorp planning to do with the existing equipment that will be 5

removed from the repowered facilities? 6

A. PacifiCorp issued a request for proposals related to the disposition of the existing 7

equipment in which the Company sought proposals for the purchase or removal of the 8

equipment that will be replaced as part of repowering the entirety of its wind fleet. In 9

general, proposals received from this solicitation were not favorable as compared to the 10

equipment removal proposals offered by the construction contractors that are installing 11

the new equipment. 12

Q. Did PacifiCorp make efforts to maximize the salvage value of the equipment being 13

replaced at the repowered facilities? 14

A. Yes. Unfortunately, a significant number of turbines of all makes and models are 15

currently being repowered by PacifiCorp and other companies. This will likely 16

continue to be the case before the sunset of the PTCs available for wind energy projects 17

in 2024. As a result, there is very little market for used turbines and the salvage value 18

of the equipment is very low given the large number of repowered turbines and 19

associated spare parts that have become available as a result of the significant 20

repowering effort that the wind industry is now undertaking. While some individual 21

turbine component sales have resulted from PacifiCorp’s efforts to obtain the highest 22

salvage value from the removed equipment at other repowered projects, the lowest cost 23


alternative for the disposition of the old equipment is to allow the construction 1

contractors to retain the equipment so the scrap value offsets their equipment removal, 2

handling, and transportation costs. That is also the case at Leaning Juniper and Foote 3

Creek I, where no anticipated equipment sales are anticipated at this time. Given the 4

relative inefficiency of the replaced equipment compared to new equipment, it does not 5

make economic sense to redeploy the replaced equipment at other potential wind sites. 6

Q. Does the Company’s inability to achieve a salvage value for the replaced 7

equipment impact the Company’s economic analysis of the Leaning Juniper or 8

Foote Creek I repowering projects? 9

A. No. PacifiCorp did not assume any salvage value for the replaced equipment in its 10

economic analysis of these projects. Thus, project economics are not impacted by the 11

fact that very little of the old equipment will ultimately be re-sold by the Company 12

when it is removed. 13

CONCLUSION 14

Q. Please summarize your recommendations. 15

A. I recommend that the Commission allow the Company to recover the costs incurred for 16

the previously approved Wind Repowering Projects, determine that the Leaning 17

Juniper and Foote Creek I repowering projects provide benefits to Wyoming customers 18

and are therefore prudent and in the public interest, and that the Company should be 19

allowed to recover the costs of these projects in rates. 20

Q. Does this conclude your direct testimony? 21

A. Yes. 22

BEFORE THE PUBLIC SERVICE COMMISSION OF WYOMING

AFFIDAVIT, OATH AND VERIFICATION OF TESTIMONY

Timothy J. Hemstreet (Affiant) being of lawful age and being first duly sworn, hereby deposes and says that:

Affiant is the Managing Director of Renewable Energy Development for PacifiCorp d/b/a Rocky Mountain Power, which is a party in this matter.

Affiant prepared and caused to be filed the foregoing testimony. Affiant has, by all necessary action, been duly authorized to file this testimony and make this Oath and Verification.

Affiant hereby verifies that, based on Affiant's knowledge, all statements and information contained within the testimony and all of its associated attachments are true and complete and constitute the recommendations of the Affiant in his official capacity as Managing Director of Renewable Energy Development.

Further Affiant Sayeth Not. �

Dated this tL_ day of febn.A� c '( , 2020

STATE OF UNfj� ) ) SS:

COUNTY OF�\��

Timothy J. Hemstreet Managing Director of Renewable Energy Development 825 NE Multnomah, Suite 1800 Portland, Oregon 97232

The foregoing was acknowledged before me by Timothy J. Hemstreet on this \ 9 day of� . , 2020. Witness my hand and official sef1l.

-

My Commission Expires:

- OFFICW. SEAL IOIIBERLY L MCCUNE

NOTARY .PUBLIC -. OREGON COMMISSION NO. 957571

MY COMMIMION EXPIRES DECBEER 2' 2020

M (_YY\·�

Rocky Mountain Power Exhibit RMP___(TJH-1) Docket No. 20000-___-ER-20 Witness: Timothy J. Hemstreet


COMMISSION


____________________________________________

Exhibit Accompanying Direct Testimony of Timothy J. Hemstreet

Major Components of a Wind Turbine Generator

March 2020

Major Components of a Wind Turbine Generator

Rocky Mountain Power Exhibit RMP___(TJH-1) Page 2 of 2

Docket No. 20000-___-ER-20 Witness: Timothy J. Hemstreet



COMMISSION


____________________________________________


List of Repowering Projects

March 2020

Proj

ect #

Win

d P

roje

ctL

ocat

ion

Ori

gina

l C

omm

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al

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Dat

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Yea

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Ope

ratio

nN

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W

TG

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et C

apac

ity

(MW

)

Ret

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g

Ret

irem

ent y

ear

wit

h R

epow

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g

Add

itio

nal

Lif

e (Y

ears

)

[1]

[2]

[3]

[4]

[5]

[6]

[7]

[8]

[9]

[10]

1Fo

ote

Cre

ek I

*A

rlin

gton

, WY

4/22

/199

920

.8

68

40.8

20

2920

5021

2G

lenr

ock

IG

lenr

ock,

WY

12/3

1/20

0811

.1

66

99.0

20

3820

4911

3G

lenr

ock

III

Gle

nroc

k, W

Y1/

17/2

009

11.1

26

39

.0

2039

2049

10

4R

ollin

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ills

Gle

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Y1/

17/2

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11.1

66

99

.0

2039

2049

10

5Se

ven

Mile

Hill

IM

edic

ine

Bow

, WY

12/3

1/20

0811

.1

66

99.0

20

3820

4911

6Se

ven

Mile

Hill

II

Med

icin

e B

ow, W

Y12

/31/

2008

11.1

13

19

.5

2038

2049

11

7H

igh

Pla

ins

McF

adde

n, W

Y9/

13/2

009

10.4

66

99

.0

2039

2049

10

8M

cFad

den

Rid

geM

cFad

den,

WY

9/29

/200

910

.4

19

28.5

20

3920

4910

9D

unla

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ow, W

Y10

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9.4

74

111.

0 20

4020

5010

464

634.

8

10M

aren

go I

Day

ton,

WA

8/3/

2007

12.6

78

14

0.4

2037

2049

12

11M

aren

go II

Day

ton,

WA

6/26

/200

811

.7

39

70.2

20

3820

4911

12G

oodn

oe H

ills

Gol

dend

ale,

WA

5/31

/200

811

.7

47

94.0

20

3820

4911

164

304.

6

13L

eani

ng J

unip

erA

rlin

gton

, OR

9/14

/200

613

.4

67

100.

5 20

3620

4913

TO

TA

L69

5 1,

039.

9

Not

es:

* P

acif

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p ow

ned

78.7

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f th

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.8 M

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proj

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32.1

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) pr

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to a

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f th

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& E

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's 21

.21%

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rest

in th

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cilit

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19 in

or

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to r

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cilit

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Paci

fiC

orp

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win

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ojec

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eing

rep

ower

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Wyo

min

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Was

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ton

Proj

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Ore

gon

Proj

ect



REDACTED Rocky Mountain Power Exhibit RMP___(TJH-3) Docket No. 20000-___-ER-20 Witness: Timothy J. Hemstreet


COMMISSION


____________________________________________

REDACTED Exhibit Accompanying Direct Testimony of Timothy J. Hemstreet

Repowering Project Details

March 2020

THIS EXHIBIT IS CONFIDENTIAL IN ITS ENTIRETY AND IS PROVIDED UNDER

SEPARATE COVER.



COMMISSION


____________________________________________


Existing and Repowered Turbine Power Curve Comparison

March 2020

0

500

1,00

0

1,50

0

2,00

0

2,50

0

Wind Turbine Output (kilowatts)

Win

d Sp

eed

(met

ers

per s

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Exis

ting

and

Repo

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urbi

ne P

ower

Cur

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Exis

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urbi

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Repo

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at l

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at h

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For i

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ratio

n pu

rpos

es o

nly



redacted docket no. 20000- -er-20 witness: timothy j ......page 5 – direct testimony of timothy j....

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