20230601Direct Hackett_Redacted.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC SERVICE
IN THE STATE OF IDAHO AND FOR
ASSOCIATED REGULATORY ACCOUNTING
TREATMENT.
)
)
)
)
)
)
)
)

CASE NO. IPC-E-23-11

IDAHO POWER COMPANY

DIRECT TESTIMONY

OF

ERIC HACKETT
REDACTED
HACKETT, DI 1
Idaho Power Company
Q. Please state your name, business address, and 1
present position with Idaho Power Company (“Idaho Power” or 2
“Company”). 3
A. My name is Eric Hackett. My business address 4
is 1221 West Idaho Street, Boise, Idaho 83702. I am 5
employed by Idaho Power as the Projects and Design Senior 6
Manager. 7
Q. Please describe your educational background. 8
A. I graduated in 2003 from Boise State 9
University in Boise, Idaho, receiving a Bachelor of Science 10
degree in Civil Engineering. I am a registered professional 11
engineer in the state of Idaho. In 2010, I earned a Master 12
of Business Administration from Boise State University. 13
Q. Please describe your work experience with 14
Idaho Power. 15
A. From 2005 to 2007, I was employed as an 16
engineer in Idaho Power’s Transmission Engineering 17
group. In 2007, I became a Project Manager leading 18
transmission and distribution line and station 19
infrastructure projects. In 2012, I was promoted to 20
Engineering Leader where I managed the Cost and Controls 21
group supporting project management. In 2015, I changed 22
leadership roles and managed the Stations Engineering and 23
Design group as an Engineering Leader. In 2018, I was 24
promoted to Senior Manager of Projects overseeing Project 25
REDACTED
HACKETT, DI 2
Idaho Power Company
Management and Cost and Controls, which later became my 1
current role of Senior Manager of Projects and Design in 2
2021, adding Power Production Design and Project 3
Management. In addition, I am currently leading a team of 4
internal employees and consultants in development and 5
evaluation of Idaho Power’s Request for Proposals for Peak 6
Capacity and Energy Resources. 7
Q. What is the purpose of your testimony in this 8
matter? 9
A. The purpose of my testimony is to discuss the 10
growth in the Company’s generation-related rate base since 11
the completion of the Company’s last general rate case 12
(“GRC”), up to and including major projects expected to be 13
complete in the 2023 test year. In my testimony I will 14
discuss the prudent nature of these investments, detailing 15
why they are needed to ensure Idaho Power’s generation 16
fleet is robust and well-positioned to provide continued 17
safe, reliable service to customers. 18
Q. How is your testimony organized? 19
A. My testimony begins with a background of the 20
Company’s generation fleet and the factors that have led to 21
generation-related investment since the conclusion of the 22
Company’s last GRC in 2011, Case No. IPC-E-11-08. I will 23
then provide a discussion of proactive investments in Idaho 24
Power’s aging hydro fleet to ensure these facilities are 25
REDACTED
HACKETT, DI 3
Idaho Power Company
well-equipped to continue to provide safe, clean and 1
reliable energy to customers. My testimony will conclude 2
with detail on Idaho Power’s investment associated with the 3
addition of utility-scale battery projects included in the 4
2023 test year, and explain why the Company’s investment in 5
these facilities reflects the least-cost, least-risk option 6
to ensure sufficient capacity to meet customer demand in 7
2023 and beyond. 8
I. BACKGROUND 9
Q. Please describe Idaho Power’s current 10
generation fleet. 11
A. The backbone of Idaho Power’s current 12
generation fleet consists of the Company’s 17 hydroelectric 13
projects on the Snake River and its tributaries. Together, 14
these projects comprise the Company’s largest generation 15
source at approximately 1,800 megawatts (“MW”) of nameplate 16
capacity. Additionally, the Company is the sole owner of 17
three gas-fired generation facilities: the Danskin and 18
Bennett Mountain simple-cycle power plants located near 19
Mountain Home, Idaho, and the Langley Gulch combined-cycle 20
power plant located near New Plymouth, Idaho, which provide 21
approximately 762 MW of combined capacity. The Company also 22
holds a 33 percent ownership share in the coal-fired Jim 23
Bridger power plant (“Bridger”), which is expected to 24
undergo conversion to natural gas generation at two of four 25
REDACTED
HACKETT, DI 4
Idaho Power Company
units in the first half of 2024. Idaho Power’s share of 1
current coal-fired operations at Bridger provides 2
approximately 706 MW of combined net dependable capacity. 3
The Company also has access to 134 MW of net dependable 4
capacity at the coal-fired North Valmy power plant, 5
reflecting 50 percent of the nameplate capacity at Unit 2 6
of that facility. Lastly, the Company owns and operates a 5 7
MW diesel facility near Salmon, Idaho. 8
Q. How has Idaho Power’s generation-related rate 9
base grown since the last GRC in 2011? 10
A. As discussed in the Direct Testimony of 11
Company Witness Ms. Lisa Grow, over the last decade Idaho 12
Power has placed in service over $3.3 billion in 13
infrastructure. Of this $3.3 billion, approximately $1.3 14
billion reflects investment in the Company’s generation 15
facilities. This investment was largely driven by growth on 16
the Company’s system and a proactive approach to addressing 17
aging infrastructure. Because the Langley Gulch plant has 18
already been approved for recovery in customer rates, the 19
remainder of my discussion will focus on investments after 20
Langley Gulch came online in 2012.1 21
Q. How has growth driven investment in Idaho 22
Power’s generation fleet since Langley Gulch came online in 23
2012? 24

1 Order No. 32585
REDACTED
HACKETT, DI 5
Idaho Power Company
A. For the first time since Langley Gulch came 1
into service in 2012, Idaho Power is adding new Company-2
owned resources to its generation fleet in the 2023 test 3
year. As discussed in Ms. Grow’s testimony, the Company has 4
experienced unprecedented growth over the past decade, 5
adding approximately 117,000 new customers between 2012 and 6
2022. Over that same time period, normalized energy sales 7
have grown from 14,010,319 megawatt-hours (“MWh”) in 2012 8
to over 15,358,562 MWh in 2022. From a peak load 9
perspective, Idaho Power’s system peak load (approximately 10
95 percent of which is attributable to the state of Idaho) 11
has grown from 3,245 MW in 2012 to 3,568 MW in 2022. As I 12
will detail in the next section of my testimony, this 13
growing load resulted in the Company experiencing a 14
resource deficiency in 2023, thus necessitating the 15
addition of new resources. 16
Q. How has the age of the Company’s existing 17
generation fleet driven investment over the last decade? 18
A. In addition to growth, Ms. Grow also describes 19
how much of the Company’s infrastructure is aging to the 20
extent that replacement or refurbishment is required to 21
maintain safe, reliable operation of the electrical grid. 22
Much of the Company’s hydro facilities are decades old, 23
such as the Shoshone Falls power plant, which is over 100 24
years old, and the Hells Canyon Complex (“HCC”), which was 25
REDACTED
HACKETT, DI 6
Idaho Power Company
constructed in the 1950s and 1960s. To ensure the Company’s 1
generation fleet can continue to provide safe, reliable 2
service, the Company takes a proactive approach to ensuring 3
a robust and reliable generation fleet, resulting in 4
significant investment over the last decade. 5
II. HYDRO FACILITIES INVESTMENTS 6
Q. Please describe the major investments related 7
to the Company’s hydro fleet since the conclusion of the 8
2011 GRC. 9
A. Since the Company’s last GRC, Idaho Power has 10
made several major investments in its hydro fleet, notably 11
the refurbishment of all four turbines at the Brownlee 12
hydrogeneration facility (“Brownlee”), upgrades and 13
improvements at Shoshone Falls, and refurbishment of the 14
Lower Salmon Falls hydrogeneration facility (“LSF”). 15
Brownlee 16
Q. Please describe the Brownlee hydrogeneration 17
facility. 18
A. Brownlee is the most upriver dam in the HCC, 19
which is comprised of the largest and most operationally 20
flexible facilities in the Company’s hydro fleet. The HCC 21
consists of three dams: Brownlee, Oxbow, and Hells Canyon, 22
which, prior to the upgrades I will discuss, provided over 23
1,166.9 MW of nameplate generation capacity. Brownlee 24
consists of five turbines, four with a generating capacity 25
REDACTED
HACKETT, DI 7
Idaho Power Company
prior to refurbishment of 90.1 MW, for a total of 360.4 MW 1
and one (Unit 5) with a generating capacity of 225 MW. 2
Q. What drove the need for the turbine 3
refurbishment project at Brownlee? 4
A. At the time the refurbishment commenced, the 5
four turbines at Brownlee had been in service for over 57 6
years. The turbines were nearing the end of their useful 7
lives, cavitation damage had accumulated and deterioration 8
was observed on the turbines and wicket gates. To ensure 9
the reliable operation of the plant and the continued 10
availability of this source of low-cost, clean hydropower, 11
refurbishment of the turbines was absolutely necessary. 12
Q. Did Idaho Power gain any additional benefits 13
from the turbine refurbishment project in addition to 14
reliability? 15
A. Yes. In addition to improving reliability at 16
the plant, the refurbishment project increased the 17
nameplate capacity of Brownlee, resulting in an increase of 18
22.4 MW for each of units 1 through 4, or a cumulative 19
increase of 89.6 MW for the entire facility, elevating the 20
total nameplate capacity from 585.4 MW to 675 MW. 21
Additionally, the existing turbine runners were replaced 22
with new aerating runners, which added the ability to 23
aerate the water to meet expected dissolved oxygen 24
REDACTED
HACKETT, DI 8
Idaho Power Company
requirements associated with the Federal Energy Regulatory 1
Commission (“FERC”) license for the HCC. 2
Q. When was the Brownlee refurbishment project 3
completed? 4
A. Refurbished Units 1, 3, 2, and 4 went into 5
service in 2016, 2017, 2018, and 2019, respectively. 6
Shoshone Falls 7
Q. Please describe Shoshone Falls. 8
A. Shoshone Falls is a hydroelectric facility 9
outside Twin Falls, Idaho. Prior to the upgrade of this 10
facility, it consisted of three units at a combined 11
nameplate capacity of 12.5 MW. 12
Q. Please describe the scope of work Idaho Power 13
performed at Shoshone Falls since its last GRC. 14
A. Between 2018 and 2020, Idaho Power replaced 15
Units 1 and 2, replaced the exterior equipment conveyer, 16
made improvements to the intake structure, and completed 17
significant work to ensure the safe, reliable operation of 18
the plant. 19
Q. What drove the need for the replacement of 20
these units? 21
A. Prior to their replacement, both units were 22
over 85 years old. Unit 2 had become inoperable due to 23
cavitation damage and cracking of the turbine runner, while 24
Unit 1 was shut down in 2017 due to a thrust bearing 25
REDACTED
HACKETT, DI 9
Idaho Power Company
failure. Further, under the existing setup, both units 1
could only be operated manually from the powerhouse, 2
limiting the ability for dynamic dispatch. 3
Q. Please describe the work Idaho Power performed 4
at Shoshone Falls related to the generating units. 5
A. Idaho Power replaced Units 1 and 2 with a 6
single horizontal new turbine and generator with a 7
nameplate capacity of 3.2 MW, increasing the plant’s 8
overall nameplate capacity to 14.7 MW. New unit ancillary 9
equipment including a turbine inlet valve and turbine unit 10
controls were also installed. 11
Lower Salmon Falls 12
Q. Has Idaho Power performed any other major 13
upgrades or refurbishments at any of its other hydro 14
facilities over the last decade? 15
A. Yes. For the last eight years, Idaho Power has 16
been upgrading and refurbishing the hydrogeneration 17
facility at Lower Salmon Falls to ensure the safe and 18
reliable production of energy and to enhance the generation 19
capability of this aging plant. 20
REDACTED
HACKETT, DI 10
Idaho Power Company
Q. Please describe LSF. 1
A. LSF was first constructed in 1910 by the 2
Greater Shoshone and Twin Falls Power Company, then 3
acquired by Idaho Power in 1916 and rebuilt in 1946. LSF 4
consists of four generating units that provide a combined 5
60 MW of clean, reliable hydropower. 6
Q. What drove the need for investment in LSF? 7
A. Many components at LSF were aging and in need 8
of replacement. Annual condition-based testing of the coils 9
showed them to be deteriorated and in need of replacement. 10
Various components of the facility were aging and in need 11
of replacement, such as the coils (32 years), core (70 12
years), and turbine and mechanical components (70 years). 13
Q. Please describe the scope of work for the LSF 14
refurbishment project. 15
A. Idaho Power replaced the turbine runners for 16
Units 1, 2 and 3, and the Unit 2 Kaplan runner received new 17
blades and refurbished inner mechanical components. The 18
turbine unit was completely disassembled and mechanical 19
components of the units were refurbished or replaced as 20
necessary. The head cover was replaced on Units 1 and 3 due 21
to cracking. Generator work included a new stator core and 22
new coils for all units. 23
Q. What benefits will the LSF refurbishment 24
provide? 25
REDACTED
HACKETT, DI 11
Idaho Power Company
A. This project is expected to increase unit 1
efficiency by 2 to 5 percent and is anticipated to increase 2
unit operational flexibility. In addition to incremental 3
generation and flexibility, this project should reduce 4
long-term maintenance costs as well. As an added benefit, 5
the increased generation from the project is expected to 6
qualify for tax credits and renewable energy credits 7
(“REC”), which will be sold in accordance with the 8
Company’s REC Management Plan to offset net power supply 9
expenses for all customers. 10
Q. When is the LSF project expected to be 11
completed? 12
A. Refurbished Units 1, 2, and 4 went into 13
service in 2022, 2020, and 2015, respectively. Refurbished 14
Unit 3 is scheduled to go into service December 2023. 15
Q. Do the examples discussed in your testimony 16
reflect a prudent and proactive approach to managing the 17
Company’s hydro fleet? 18
A. Yes. Over the last decade Idaho Power has 19
completed numerous projects at its hydro facilities to 20
ensure they are able to provide safe, clean, and reliable 21
service to customers. 22
REDACTED
HACKETT, DI 12
Idaho Power Company
III. 2023 BATTERIES 1
Q. What drove the need for the addition of the 2
utility-scale battery projects for which the Company is 3
seeking a prudence determination in this case? 4
A. As discussed earlier in my testimony, Idaho 5
Power has experienced and expects sustained load growth and 6
transmission import constraints, thereby requiring the 7
addition of new dispatchable resources to meet peak summer 8
demand. As a result of this growth and import constraints, 9
in May 2021, the Company identified a near-term capacity 10
deficit in summer 2023. To meet its obligation to reliably 11
serve customer load and fill this capacity deficiency, in 12
June 2021, the Company issued a competitive solicitation 13
through a request for proposals (“RFP”) seeking to acquire 14
dispatchable resources to be online by June 2023. This 15
robust competitive bidding process resulted in the 16
procurement of 120 MW of dispatchable four-hour duration 17
battery energy storage as well as execution of a 20-year 18
Power Purchase Agreement (“PPA”) for 40 MW of photovoltaic 19
(“PV”) solar, all of which was necessary to adequately 20
address 2023 capacity deficits. 21
Q. Did the Company file a request for a 22
Certificate of Public Convenience and Necessity (“CPCN”) 23
for the 2023 resource procurement? 24
REDACTED
HACKETT, DI 13
Idaho Power Company
A. Yes. Idaho Power’s request for a CPCN 1
associated with a total of 120 MW of Company-owned battery 2
storage, the Hemingway 80-MW four-hour duration battery 3
energy storage system (“BESS”) and the Black Mesa 40-MW 4
four-hour duration BESS, was presented in Case No. IPC-E-5
22-13. At the conclusion of this case, the Commission 6
granted a CPCN with Order No. 35643, stating that “...the 7
evidence and the record ... demonstrates that the public 8
convenience and necessity requires the Company to acquire 9
120 MW of dispatchable energy storage.” The request for 10
approval of the 20-year PPA for 40 MW of solar was filed in 11
Case No. IPC-E-22-06, which was approved by the Commission 12
in Order No. 35482. 13
Q. Did the Company request binding ratemaking 14
treatment for the investments in the 120 MW of Company-15
owned battery storage facilities? 16
A. No. Due to the urgency of the 2023 capacity 17
deficiency and the issuance of the resulting RFP, Idaho 18
Power was still in the process of negotiating a number of 19
agreements necessary for the construction, installation, 20
and maintenance of the projects and, therefore, binding 21
ratemaking treatment was not requested. The Company’s 22
request was that the Commission find Idaho Power had met 23
the requirements of Idaho Code § 61-526 and issue a CPCN, 24
which was ultimately granted in Order No. 35643. 25
REDACTED
HACKETT, DI 14
Idaho Power Company
Q. Did Order No. 35643 impose any conditions on 1
recovery of costs associated with the procurement of the 2
120 MW of Company-owned battery storage? 3
A. Yes. Order No. 35643 approved the acquisition 4
of the 120 MW of energy storage resources but found that 5
“implementing a soft cap of up to $50,228,329 and 6
$100,456,659, for the 40 MW BESS and 80 MW BESS, 7
respectively, is reasonable.”2 This equates to a total soft 8
cap of $150,684,988. 9
Q. Why did the Commission impose a soft cap on 10
the 2023 battery storage investments? 11
A. In its Order, the Commission adopted 12
Commission Staff’s (“Staff”) recommendation to implement 13
the soft cap due to concerns regarding whether the selected 14
resources were least-cost. In comments, Staff expressed 15
concerns about the lead time and certain restrictions 16
associated with the resource procurement process, resulting 17
in its recommendation regarding the soft cap.3 The soft cap 18
did not foreclose future requests by Idaho Power for 19
recovery of costs above the soft cap, but rather indicated 20
the Company would have to provide justification for any 21
costs above the soft cap when requesting rate recovery. 22

2 Order No. 35643 pg. 12.
3 Order No. 35643 pg. 13.
REDACTED
HACKETT, DI 15
Idaho Power Company
Q. Was the procurement of the 120-MW Company-1
owned battery storage facilities least-cost? 2
A. Yes. The Company’s competitive solicitation 3
process was initiated as soon as feasibly possible once 4
the 2023 capacity deficiency was identified, and the 5
project that was ultimately selected was the direct result 6
of this process. 7
Q. What led to the rapid change in the 2023 8
capacity deficiency? 9
A. The Company’s rapid change in the 2023 10
capacity deficiency was the result of several dynamic and 11
evolving factors including: transmission availability, 12
planning reserve margin determinations and reliability 13
methodology modernization, an increasing population, new 14
large customers in the service area and associated emergent 15
load demands on the Company’s system, and the ability of 16
demand response programs and variable energy resources to 17
meet load during the Company’s highest-risk hours. The 18
updated load and resource balance analysis prepared in May 19
2021 first identified a 2023 capacity deficit, and the 20
Company immediately began to prepare an RFP, which was 21
issued on June 30, 2021, roughly one month after the load 22
and resource balance was updated. 23
REDACTED
HACKETT, DI 16
Idaho Power Company
Q. Was the RFP solicitation as expedient and 1
robust as possible given the urgency of the capacity need 2
in 2023? 3
A. Yes. Due to the urgency, the RFP solicitation 4
focused on the importance of having a project in service by 5
June 2023; given resource-specific permitting and 6
construction timelines, the RFP solicited energy storage 7
projects, solar PV projects, solar PV plus storage 8
projects, wind projects, and wind plus storage projects. 9
There was only one economic project bid into the RFP that 10
was able to meet the required commercial operation date of 11
June 2023 — the 20-year PPA associated with a 40-MW solar 12
PV facility - which was selected through the RFP process. 13
The initial proposal also envisioned a build-14
transfer agreement associated with a 40-MW battery storage 15
facility. However, during negotiations associated with the 16
PPA, the developer indicated they were no longer interested 17
in pursuing a build-transfer agreement and instead 18
coordinated on the Idaho Power-owned battery storage 19
project located at the developer’s solar PV site, 20
ultimately resulting in a self-build option that was lower 21
cost for customers. 22
Q. Aside from being the only economic project 23
able to meet the required commercial operation date of June 24
2023, does the Company have any additional support to 25
REDACTED
HACKETT, DI 17
Idaho Power Company
indicate the 120 MW of Company-owned battery storage 1
facilities were least-cost? 2
A. Yes. At the time, Idaho Power was performing a 3
parallel investigation into different configurations of 4
Company-owned and constructed BESS, and the indicative 5
pricing received was comparable to the lowest-cost 6
proposals for similar battery storage projects submitted 7
through the RFP process. In fact, pricing on the proposed 8
40-MW battery storage was based on a BESS from Powin Energy 9
Corporation (“Powin”), one of the suppliers for which the 10
indicative pricing was based. Procuring the BESS from Powin 11
directly resulted in lower BESS costs, further supporting 12
the acquisition of the least-cost, least-risk resource 13
necessary to fill the 2023 capacity deficiency. 14
Q. Does the Company believe the RFP process was 15
robust and that the resources procured were least-cost 16
resources? 17
A. Yes. The 40-MW solar facility plus 40 MW of 18
battery storage was identified through the RFP, resulting 19
in a PPA for the solar facility. The decision for Idaho 20
Power to procure the 40-MW battery storage facility 21
directly from Powin was the result of conversations with 22
the solar developer and Powin, ultimately resulting in a 23
self-build option that was lower cost for customers. The 24
remaining 80-MW project was identified through the 25
REDACTED
HACKETT, DI 18
Idaho Power Company
Company’s extensive analysis of other configurations to 1
complement the RFP process, ensuring the resulting projects 2
were least cost and least risk. 3
The lack of sufficient viable projects resulting 4
from the RFP was not an indication that the RFP was 5
inadequate, but rather the result of the requirement for a 6
commercial operation date of June 1, 2023, which other 7
bidding entities would not commit to achieving. During this 8
time, the United States and the rest of the world were also 9
experiencing significant supply chain disruptions and 10
constraints, which impacted in-service dates and costs. The 11
RFP was robust and sufficient, indicating prudent action 12
based on information known at the time. 13
Q. Did Idaho Power agree with Staff’s 14
quantification of the soft cap? 15
A. No. In Case No. IPC-E-22-13, the Company 16
expressed concern that the quantification of the soft cap, 17
presented in Staff’s Comments in that case, was flawed. 18
Because Idaho Power did not receive multiple bids through 19
the RFP process, Staff performed a benchmark analysis on 20
which the quantification of the soft cap was based. The 21
analysis, however, was based on a National Renewable Energy 22
Laboratory (“NREL”) study that is intended for long-term 23
planning purposes and ignores current market realities and 24
supply chain disruptions that impact the costs of lithium-25
REDACTED
HACKETT, DI 19
Idaho Power Company
ion battery systems, resulting in a flawed analysis. In 1
fact, the NREL study states in its disclaimer: the NREL 2
data is “prepared for reference purposes only,” “based upon 3
expectations of current and future conditions,” and 4
“subject to change without notice.”4 5
While NREL data may be valuable in developing long-6
term integrated resource plan (“IRP”) forecast cost 7
assumptions over a 20-year time horizon, market realities 8
can vary significantly when contracting near-term 9
resources. This was certainly the case between 2020 and 10
2022, as the COVID-19 pandemic, inflation, and other 11
factors disrupted markets across the world. As evidenced by 12
actual lithium-ion battery system costs, the downward 13
pricing trend anticipated by NREL reversed into an upward 14
trend starting in late 2021 and continued into 2022. This 15
increasing price trend is well documented by industry 16
reporting firms and will likely be incorporated into 17
upcoming NREL forecasts. 18
Q. Are there any additional factors that would 19
suggest the NREL study used by Staff is not appropriate for 20
use in a benchmark analysis? 21
A. Yes. In addition to not factoring in current 22
market realities, which include current real-world supply 23
chain constraints, pricing, and above-normal inflation, the 24

4 https://atb.nrel.gov/electricity/2022/disclaimer
REDACTED
HACKETT, DI 20
Idaho Power Company
NREL study referenced used 2020 as its base year or last 1
historical year, which, at the time, anticipated a decline 2
of 27 percent in costs from 2020 to 2023, as can be seen in 3
the table below. 4
Table 1 5
NREL Forecasted Utility-Scale Battery Storage – 4Hr – 6
Moderate 7
8
This stale NREL data did not consider recent market 9
realities and should not have been used as a basis for 10
Staff’s soft cap recommendation. Further, in the Annual 11
Technology Baseline: The 2022 Electricity Update,5 NREL 12
notes that it does not track near-term cost variability, 13
and further notes that the baseline is to help in 14
conducting scenario analysis for 5 to 30-year futures. 15
Q. Did the Company see a decline in battery 16
storage costs as indicated in the NREL study? 17
A. No, the opposite occurred. Demand for utility-18
scale BESS projects in the second half of 2021 and into 19
2022, coupled with supply chain constraints and above-20
normal inflation, resulted in an increase in pricing of 21

5 https://www.nrel.gov/docs/fy22osti/83064.pdf, slide 54.
REDACTED
HACKETT, DI 21
Idaho Power Company
battery storage. Industry information suggested a 10 to 20 1
percent increase or more from 2020 levels, driven by this 2
high demand, input prices for lithium carbonate, and 3
inflationary pressures on other materials and labor.6 4
Utility Dive noted in April 2022 that battery storage costs 5
rose more than 20 percent as compared to 2020 and 2021 6
installs, stating “crimped supply chains, rising demand for 7
batteries and higher costs of lithium used in ubiquitous 8
lithium-ion batteries make for a steep climb ahead ...”7 9
Nearly all battery material costs had increased over the 10
prior year and some major battery module inputs increased 11
significantly. 12
The index for nearly every commodity that 13
is required to manufacture lithium-ion 14
batteries, including aluminum, copper, 15
and nickel, has risen across the board. 16
The price of lithium-carbonate has 17
increased 500 percent in the last 12 18
months. Bloomberg New Energy Finance 19
calculates that each 20 percent increase 20
in the price of lithium-carbonate results 21
in a three percent increase in the total 22
cost of battery modules.8 23
24

6 IHS Markit: “Multiple factors halt downward trajectory of Li-ion
battery costs, with higher prices for energy storage systems set to
continue throughout 2022 and 2023” January 6th, 2022.
7 Utility Dive: “Battery storage costs rise more than 20% in New York as
state forges ahead with 6 GW goal”, April 12th, 2022.
8 Utility Dive: “Navigating the evolving state of the storage industry,”
April 4th, 2022.

REDACTED
HACKETT, DI 22
Idaho Power Company
Q. Does Idaho Power have an alternative source of 1
data that it believes would have been a more appropriate 2
basis for a benchmark analysis of battery storage costs? 3
A. Yes. The most appropriate market guide is 4
actual RFP responses. However, if a benchmark is desired, 5
as part of the IRP process, the Company utilizes Wood 6
Mackenzie, a global research and consultancy business that 7
provides quality data, analytics, and insights for energy, 8
chemicals, metals, mining, and the power and renewables 9
industries, as a data source for battery storage prices. In 10
Wood Mackenzie’s U.S. Energy Storage Monitor – 2021 Year in 11
Review Full Report, dated March 2022, average utility-scale 12
four-hour battery prices averaged per kilowatt 13
(“kW”) for the same time period, as compared to the NREL 14
data utilized by Staff that suggested battery storage costs 15
in 2021 would have been $1,475 per kW. 16
Q. How did the total estimated cost of the 17
battery storage projects compare? 18
A. Using the Company’s estimated project costs at 19
the time Case No. IPC-E-22-13 was filed, the total cost of 20
the 120 MW of battery storage projects, excluding 21
interconnection and transmission upgrade costs analogous to 22
the NREL and Wood Mackenzie cost estimates, was 23
approximately $1,650 per kW. Staff used the outdated NREL 24
data to benchmark Idaho Power’s battery storage costs, 25
REDACTED
HACKETT, DI 23
Idaho Power Company
suggesting that, based on the forecasted 2023 NREL battery 1
storage costs, the Company could have procured the BESS for 2
as little as $1,256 per kW, and therefore Idaho Power’s 3
selection of the products was not least cost. Yet, when 4
current market conditions and industry trends are factored 5
into battery storage costs, average costs for procurement 6
in 2022 would range from $1,966 per kW to as high as $2,144 7
per kW, evidence that the soft cap was inherently flawed 8
and punitive and should not have been imposed on Idaho 9
Power. 10
Q. Assuming the low range of Idaho Power’s 11
estimate of the average cost for procurement of battery 12
storage developed in 2022, what is the Company’s 13
quantification of a reasonable benchmark estimate? 14
A. Using the low end of the range, $1,966 per kW, 15
for average battery storage costs developed in 2022 would 16
suggest that a battery project costing $235.9 million 17
represents a more reasonable benchmark estimate, which is 18
$85.2 million greater than the soft cap imposed by the 19
Commission. 20
Q. Your discussion of the average battery storage 21
costs focuses on data available during the processing of 22
Case No. IPC-E-22-13, the point at which Staff presented 23
the benchmark analysis. Does Idaho Power have an updated 24
estimate of the average cost of battery storage? 25
REDACTED
HACKETT, DI 24
Idaho Power Company
A. Yes. As part of the modeling for the 2023 IRP, 1
Idaho Power is estimating average four-hour duration 2
battery storage costs of $1,600 per kW. 3
Q. What is the total investment in the 120 MW of 4
Company-owned battery storage included in the Company’s 5
2023 test year? 6
A. The Company is requesting in this case to 7
include $146.8 million for 120 MW of battery capacity plus 8
an additional $28 million investment to account for 9
performance degradation over time that will ensure the 10
batteries maintain the 120 MW of capacity. 11
Q. Does the Company’s request in this case 12
reflect a cost that is below an appropriately calculated 13
benchmark estimate? 14
A. Yes. The Company’s total request for $174.8 15
million in rate base for the 120 MW of batteries reflects a 16
cost of $1,457 per kW. Relative to available cost data at 17
the time Case No. IPC-E-22-13 was being processed, the 2023 18
test year amounts are well below the range of $1,966 per kW 19
to $2,144 per kW based on average costs for procurement in 20
2022. Further, the Company’s 2023 test year costs are 21
nearly 10 percent lower than current battery storage costs 22
based on the Company’s forthcoming IRP analysis. 23
Q. Does the information presented in your 24
testimony support the Company’s assertion that the 120 MW 25
REDACTED
HACKETT, DI 25
Idaho Power Company
of batteries procured by Idaho Power were the least-cost 1
option to meet the 2023 capacity deficiency? 2
A. Yes. Idaho Power identified a 2023 capacity 3
deficiency in May 2021 and issued an RFP as soon as 4
feasibly possible in June 2021. This robust competitive 5
process ultimately resulted in the procurement of the 120 6
MW of batteries included in the Company’s 2023 test year. 7
The final cost of these batteries is lower than Wood 8
Mackenzie-based pricing available at the time the 2023 CPCN 9
case was being processed and was even less than costs 10
available today. For all these reasons, the 120 MW of 11
batteries included in this case represent the least-cost, 12
least-risk option for customers. 13
IV. CONCLUSION 14
Q. Please summarize your testimony. 15
A. As mentioned in Ms. Grow’s testimony, Idaho 16
Power experienced unprecedented growth over the past 17
decade, resulting in the need for the Company to procure 18
its first utility-scale resources since Langley Gulch was 19
placed in service in 2012. The Company’s proactive approach 20
to refurbishing and upgrading its existing resource fleet 21
reflects a prudent approach to ensuring the continued 22
provision of safe, clean, and reliable energy to meet the 23
needs of Idaho Power’s customers. Idaho Power’s investment 24
in the 2023 batteries reflects the least-cost, least-risk 25
REDACTED
HACKETT, DI 26
Idaho Power Company
option to meet the Company’s resource need, as identified 1
in the 2023 CPCN case and affirmed in Commission Order No. 2
35643. 3
Q. Do you believe the inclusion in rates of the 4
generation-related rate base in the Company’s 2023 test 5
year would result in fair, just, and reasonable rates? 6
A. Yes. 7
Q. Does this conclude your direct testimony in 8
this case? 9
A. Yes, it does. 10
// 11
// 12
//13
REDACTED
HACKETT, DI 27
Idaho Power Company
DECLARATION OF ERIC HACKETT 1
I, Eric Hackett, declare under penalty of perjury 2
under the laws of the state of Idaho: 3
1. My name is Eric Hackett. I am employed by 4
Idaho Power Company as the Projects and Design Senior 5
Manager. 6
2. To the best of my knowledge, my pre-filed 7
direct testimony and exhibits are true and accurate. 8
I hereby declare that the above statement is true to 9
the best of my knowledge and belief, and that I understand 10
it is made for use as evidence before the Idaho Public 11
Utilities Commission and is subject to penalty for perjury. 12
SIGNED this 1st day of June 2023, at Boise, Idaho. 13
14 Signed: ___________________ 15
ERIC HACKETT 16
17
18
19
20
21
22
23
REDACTED