20200415Tatum Direct.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO IMPLEMENT POWER
COST ADJUSTMENT (“PCA”) RATES
FOR ELECTRIC SERVICE FROM JUNE
1, 2020, THROUGH MAY 31, 2021.

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CASE NO. IPC-E-20-21

IDAHO POWER COMPANY

DIRECT TESTIMONY

OF

Timothy E. Tatum
RECEIVED
2020 April 15,PM4:32
IDAHO PUBLIC
UTILITIES COMMISSION

TATUM, 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 Timothy E. Tatum. My business 4
address is 1221 West Idaho Street, Boise, Idaho 83702. I 5
am employed by Idaho Power as the Vice President of 6
Regulatory Affairs. 7
Q. Please describe your educational background. 8
A. I earned a Bachelor of Business Administration 9
degree in Economics and a Master of Business Administration 10
degree from Boise State University. I have also attended 11
electric utility ratemaking courses, including “Practical 12
Skills for The Changing Electrical Industry,” a course 13
offered through New Mexico State University’s Center for 14
Public Utilities, “Introduction to Rate Design and Cost of 15
Service Concepts and Techniques” presented by Electric 16
Utilities Consultants, Inc., and Edison Electric 17
Institute’s “Electric Rates Advanced Course.” In 2012, I 18
attended the Utility Executive Course (“UEC”) at the 19
University of Idaho, and subsequently became a member of 20
the UEC faculty in 2015. 21
Q. Please describe your work experience with 22
Idaho Power. 23
A. I began my employment with Idaho Power in 1996 24
in the Company’s Customer Service Center where I handled 25

TATUM, DI 2
Idaho Power Company
customer phone calls and other customer-related 1
transactions. In 1999, I began working in the Customer 2
Account Management Center where I was responsible for 3
customer account maintenance in the areas of billing and 4
metering. 5
In June of 2003, I began working as an Economic 6
Analyst on the Energy Efficiency Team. As an Economic 7
Analyst, I was responsible for ensuring that the demand-8
side management (“DSM”) expenses were accounted for 9
properly, preparing and reporting DSM program costs and 10
activities to management and various external stakeholders, 11
conducting cost-benefit analyses of DSM programs, and 12
providing DSM analysis support for the Company’s Integrated 13
Resource Plan. 14
In August of 2004, I accepted a position as a 15
Regulatory Analyst in the Regulatory Affairs Department. 16
As a Regulatory Analyst, I provided support for the 17
Company’s various regulatory activities, including tariff 18
administration, regulatory ratemaking and compliance 19
filings, and the development of various pricing strategies 20
and policies. 21
In August of 2006, I was promoted to Senior 22
Regulatory Analyst. As a Senior Regulatory Analyst, my 23
responsibilities expanded to include the development of 24
complex financial studies to determine revenue recovery and 25

TATUM, DI 3
Idaho Power Company
pricing strategies, including the preparation of the 1
Company’s cost-of-service studies. 2
In September of 2008, I was promoted to Manager of 3
Cost of Service and, in April of 2011, I was promoted to 4
Senior Manager of Cost of Service and oversaw the Company’s 5
cost-of-service activities, such as power supply modeling, 6
jurisdictional separation studies, class cost-of-service 7
studies, and marginal cost studies. 8
In March 2016, I was promoted to Vice President of 9
Regulatory Affairs. As Vice President of Regulatory 10
Affairs, I am responsible for the overall coordination and 11
direction of the Regulatory Affairs Department, including 12
development of jurisdictional revenue requirements and 13
class cost-of-service studies, preparation of rate design 14
analyses, and administration of tariffs and customer 15
contracts. 16
Q. What is the Company requesting in this case? 17
A. The Company is requesting approval of its 18
2020-2021 PCA rates to become effective June 1, 2020. If 19
approved, the 2020-2021 PCA 20
will result in an increase in total billed revenue of 21
approximately $58.7 million, or 5.21 percent. 22
Q. How is the Company’s case organized? 23
A. The Company’s case includes testimony from two 24
witnesses. My testimony consists of four sections. In the 25

TATUM, DI 4
Idaho Power Company
first section, I provide an overview of the PCA. In the 1
second section, I detail the 2020-2021 PCA amount in 2
comparison to last year’s PCA amount, and identify and 3
discuss the main factors contributing to this change. In 4
the third section of my testimony, I detail the net 5
customer impact of the 2020-2021 PCA rates if approved as 6
filed. In the final section, I describe Idaho Power’s 7
careful consideration of this request in light of the 8
financial challenges the Company and its customers are 9
currently facing as a result of the 2019 Novel Coronavirus 10
(“COVID-19”) health crisis. 11
Nicole A. Blackwell, a Regulatory Analyst in the 12
Regulatory Affairs Department, also provides testimony in 13
this case. Ms. Blackwell’s testimony provides 14
quantification of the 2020-2021 PCA forecast amount, 15
discusses additional PCA components related to revenue 16
sharing and tax reform benefits, and presents the 17
quantification of the 2020-2021 PCA rates to become 18
effective June 1, 2020. 19
I. PCA OVERVIEW 20
Q. What is the purpose of the PCA and how does 21
the mechanism function? 22
A. The PCA is a rate mechanism that quantifies 23
and tracks annual differences between actual net power 24
supply expenses (“NPSE”) and the normalized or “base level” 25

TATUM, DI 5
Idaho Power Company
of NPSE recovered in the Company’s base rates, resulting in 1
a credit or surcharge that is updated annually on June 1. 2
The PCA mechanism uses a 12-month test period of April 3
through March (“PCA Year”) and includes a forecast 4
component and a True-up component (“True-up”). The 5
forecast component represents the difference between the 6
Company’s NPSE forecast from the March Operating Plan and 7
base level NPSE recovered in the Company’s base rates. The 8
True-up component includes a backward-looking tracking of 9
differences between the prior PCA year’s forecast and 10
actual NPSE incurred by the Company. The True-up contains 11
a second component that tracks the collection of the prior 12
year’s True-up amount, referred to as the “True-up of the 13
True-up.” 14
With the exception of Public Utility Regulatory 15
Policies Act of 1978 (“PURPA”) expenses and demand response 16
incentive payments, the PCA allows the Company to pass 17
through to customers 95 percent of the annual differences 18
in actual NPSE as compared with base level NPSE, whether 19
positive or negative. With respect to PURPA expenses and 20
demand response incentive payments, as actual annual 21
expenses deviate from base level NPSE, the Company is 22
allowed to pass 100 percent of the difference for recovery 23
or credit through the PCA. The PCA is also the rate 24
mechanism used by the Company to provide customer benefits 25

TATUM, DI 6
Idaho Power Company
resulting from the revenue sharing mechanism approved by 1
the Idaho Public Utilities Commission (“Commission”) in 2
Order No. 33149. 3
Q. Does the revenue collected from customers 4
through the annual PCA rate contribute toward the Company’s 5
net income? 6
A. No. The PCA mechanism provides for the annual 7
collection or refund of net power supply cost differences 8
between actual costs incurred by the Company and the base 9
level NPSE component of base rates. Aside from the 95 10
percent to 5 percent sharing component I just described, 11
the PCA provides for a one-for-one collection or refund of 12
actual NPSE incurred, or to be incurred, to provide safe, 13
reliable electric service to customers. 14
Q. What are the components of the PCA base level 15
NPSE? 16
A. The PCA base level NPSE includes the following 17
Federal Energy Regulatory Commission (“FERC”) accounts: 18
Account 501, Fuel (coal); Account 536, Water for Power; 19
Account 547, Fuel (gas); Account 555, Purchased Power; 20
Account 565, Transmission of Electricity by Others; and 21
Account 447, Sales for Resale (typically referred to as 22
surplus sales). 23
The PCA base level expense component for FERC 24
Account 555 includes costs of both PURPA and non-PURPA 25

TATUM, DI 7
Idaho Power Company
(market) purchases. Per Order No. 32426, the Company 1
adjusts FERC Account 555 to also include demand response 2
incentive payments that the Company provides to customers 3
who participate in any of its three demand response 4
programs. 5
II. 2020-2021 PCA 6
Q. What is the total PCA collection that would 7
result under the 2020-2021 PCA rates proposed by the 8
Company in this case? 9
A. The 2020-2021 PCA rates, as quantified in Ms. 10
Blackwell’s testimony, would result in total PCA collection 11
of $69.8 million. This represents an increase in total 12
billed revenue of $58.7 million for the upcoming year, an 13
increase of 5.21 percent. 14
Q. Have you prepared a table that details the 15
$58.7 million revenue impact by component? 16
A. Yes. Table 1 below presents a separation of 17
the $58.7 million increase into each component included in 18
the Company’s proposed rates. 19
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TATUM, DI 8
Idaho Power Company
Table 1 Revenue Impact by Component

Line No. Rate Component 2019-2020 PCA1 2020-2021 PCA2 Difference
1 PCA forecast $ 83,775,043 $ 112,441,726 $ 28,666,683
2 PCA True-up $(64,855,320) $ (42,648,330) $ 22,206,990
3 PCA Total $ 18,919,723 $ 69,793,396 $ 50,873,673
4 Revenue Sharing $ (5,096,850) $ 0 $ 5,096,850
5 Tax Reform $ (2,715,902) $ 0 $ 2,715,902
6 PCA Total $ 11,214,205 $ 69,793,396 $ 58,686,425
Q. What are the main factors driving the revenue 1
change requested in this case? 2
A. The increase in this year’s PCA largely 3
reflects the return to a more normal level of NPSE as 4
market energy prices have come down from unusually high 5
levels reflected in last year’s PCA. While it may seem 6
counter-intuitive, NPSE expenses for Idaho Power tend to be 7
lower during periods of higher market energy prices as 8
resulting increased surplus sales revenues help to offset 9
power supply costs. 10
The increase in this year’s PCA forecast component 11
is mostly attributable to lower hydro generation and 12
significantly lower surplus sales revenues as compared to 13

1 Because Table 1 contains the expected billed revenue impact to
customers, the “2019-2020 PCA” column reflects approved 2019-2020 PCA
rates applied to the June 2020 through May 2021 sales forecast, and
will not tie to the specific dollar amounts approved in the 2019 PCA
filing.

2 The “2020-2021 PCA” column reflects the Company’s proposed rates
applied to the June 2020 through May 2021 forecast, and may not tie
exactly to the figures listed in the Company’s testimony due to the
rounding of rates to six digits.

TATUM, DI 9
Idaho Power Company
last year’s forecast. The PCA true-up component is also 1
increasing as a result of lower surplus sales revenue. 2
In addition to the changes in the PCA forecast and 3
True-up components, the currently effective PCA includes 4
$7.7 million in one-time customer benefits associated with 5
revenue sharing and tax reform, which will expire at the 6
end of the current PCA-year. These adjustments are more 7
fully described in Ms. Blackwell’s testimony. 8
Q. Why do you believe that this year’s proposed 9
PCA collection reflects a return to a more “normal” level? 10
A. Table 2 below includes this year’s proposed 11
PCA revenue collection compared to the prior four years, 12
inclusive of the forecast and True-up components. 13
14
Table 2 demonstrates that last year’s PCA stands out 15
as an anomaly as compared to the other four years 16
supporting the conclusion that the proposed increase in 17
billed revenue associated with this year’s PCA request 18
reflects a more normal level of NPSE. 19
A. PCA Forecast. 20
Q. How does the Company’s forecast of system-21
level NPSE for the 2020-2021 PCA compare to the system-22
level forecast included in last year’s PCA? 23
24
Table 2
2016-2017 PCA 2017-2018 PCA 2018-2019 PCA 2019-2020 PCA 2020-2021 PCA
86,358,618$ 103,129,716$ 69,415,883$ 18,679,456$ 69,793,396$
PCA Revenue Collection

TATUM, DI 10
Idaho Power Company
A. Table 3 below compares this year’s 2020-2021 1
PCA forecast of NPSE to last year’s PCA forecast by FERC 2
account. As detailed in this table, the PCA forecast on a 3
total system basis for the 2020-2021 PCA Year is 4
$426,904,721, which is $32,615,794 higher than last year’s 5
forecast amount of $394,288,927. 6
7
Q. What general conclusions can be drawn from the 8
information contained in Table 3? 9
A. When viewed by category, the 95 percent 10
sharing accounts have increased approximately $30.9 million 11
from last year’s forecast, while the 100 percent sharing 12
accounts have increased approximately $1.7 million over 13
last year’s forecast. 14
Q. What factors are contributing to the major 15
differences presented in Table 3? 16
Table 3
Line No.FERC Account
2019-2020
Forecast
2020-2021
Forecast Difference
95% Sharing Accounts
1 Account 501, Coal 146,631,692$ 102,534,012$ (44,097,680)$
2 Account 536, Water for Power 0$ 1,500,000$ 1,500,000$
3 Account 547, Other Fuel 44,723,759$ 42,599,268$ (2,124,490)$
4 Account 555, Purchased Power Non-PURPA 62,039,274$ 89,849,920$ 27,810,645$
5 Account 565, 3rd Party Transmission 5,319,681$ 5,058,450$ (261,230)$
6 Account 447, Surplus Sales (64,129,054)$ (16,076,860)$ 48,052,195$
194,585,351$ 225,464,790$ 30,879,439$
100% Sharing Accounts
7 Account 555, PURPA 192,301,878$ 193,826,319$ 1,524,441$
8 Account 555, Demand Response Incentives 7,401,698$ 7,613,612$ 211,914$
199,703,576$ 201,439,931$ 1,736,355$
9 Total PCA Forecast 394,288,927$ 426,904,721$ 32,615,794$
PCA Forecast Comparison Expenses (Total System)

TATUM, DI 11
Idaho Power Company
A. Due to a return to more normal market energy 1
price levels in this year’s PCA forecast, as well as a 2
reduction in forecast hydro generation, surplus sales 3
revenue is expected to decrease. The decrease in market 4
energy prices is also contributing to a reduction in 5
forecast coal-fired generation as it is less economic for 6
load service as well as off-system sales. Conversely, due 7
to the lower market energy prices, the Company is expected 8
to increase market power purchases. 9
Q. Please elaborate on the changes in the 95 10
percent sharing accounts for this year’s forecast as 11
compared with last year’s forecast. 12
A. The decrease in forecast market energy prices 13
is causing a $27,810,645 increase in non-PURPA purchased 14
power, a 45 percent increase over last year’s forecast. 15
Non-PURPA purchased power expense includes market power 16
purchases as well as power purchase agreements (“PPAs”). 17
The increase in forecast non-PURPA purchased power is 18
primarily related to market power purchases, which are 19
expected to increase from $14,898,672 in last year’s PCA 20
forecast to $41,404,266 in this year’s PCA forecast, a 178 21
percent increase. For the 2020-2021 PCA Year, the average 22
forecast market purchase price is $27.14 per megawatt-hour 23
(“MWh”), as compared with $36.73 in last year’s PCA 24
forecast, a 26 percent decrease. 25

TATUM, DI 12
Idaho Power Company
At the same time, surplus sales revenues are 1
expected to decrease 75 percent as compared to last year, 2
from $64,129,054 to $16,076,860. For the 2020-2021 PCA 3
year, the average forecast market sales price is $15.14 per 4
MWh compared with $35.84 last year. The reduction in 5
surplus sales is also driven by a reduction in hydro 6
generation, which will be discussed later. 7
Due to the decrease in market energy prices, the 8
Company’s use of coal-fired generation, both for serving 9
load as well as making economic surplus sales, is expected 10
to decrease. Coal fuel expense is expected to decrease 30 11
percent as compared to last year’s forecast, from 12
$146,631,692 to $102,534,012. 13
Forecast fuel expense at the Company’s natural gas 14
plants is expected to decrease $2,124,490, or approximately 15
5 percent, as compared to last year’s forecast due to lower 16
natural gas prices. The average per-unit cost of natural 17
gas generation in this year’s PCA forecast is $21.59 per 18
MWh compared to $23.04 per MWh last year, a 6 percent 19
decrease. 20
Finally, this year’s PCA forecast includes water 21
lease expense whereas last year’s PCA forecast did not. 22
While the Company has not yet procured the water lease, it 23
anticipates water will be available due to snowpack 24
conditions in the Upper Snake basin, which is discussed in 25

TATUM, DI 13
Idaho Power Company
more detail later. Idaho Power has estimated water lease 1
expense of $1,500,000 for this year’s PCA forecast. 2
Q. What factors are contributing to the change in 3
the 100 percent sharing accounts? 4
A. Forecast expenses included in the 100 percent 5
sharing accounts are expected to increase by less than 1 6
percent as compared to last year, from $199,703,576 to 7
$201,439,931. This change includes an increase in forecast 8
PURPA expense of $1,524,441 as compared to last year, which 9
is less than 1 percent, and a $211,914 increase, or 3 10
percent, in forecast demand response incentive payments. 11
Q. How does forecast generation for this year’s 12
PCA forecast compare to last year? 13
A. Table 4 below details changes between last 14
year’s PCA forecast and this year’s PCA forecast with 15
respect to forecasted generation in MWh. As shown in Table 16
4, the changes in total-system generation are related to 17
coal, non-PURPA purchased power and surplus sales, similar 18
to the changes in expense. 19
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TATUM, DI 14
Idaho Power Company
1
Q. Please elaborate on the changes in generation 2
for this year’s forecast as compared with last year’s 3
forecast. 4
A. Compared to last year’s forecast, coal-fired 5
generation is expected to decrease 1,505,023 MWh, or 34 6
percent. As discussed previously, the decrease in market 7
energy prices is contributing to the decrease in coal-fired 8
generation as it is less economic to dispatch for surplus 9
sales and to serve load. The retirement of one unit at the 10
North Valmy coal-fired plant (“Valmy”) in December 2019, as 11
well as the retirement of the Boardman coal-fired plant 12
(“Boardman”) in December 2020, are also contributing to the 13
decrease in coal-fired generation. This year’s PCA includes 14
generation of 167,912 MWh at Valmy and 104,191 MWh at 15
Table 4
Line No.FERC Account
2019-2020
Forecast
2020-2021
Forecast Difference
1 Hydro 7,542,353 7,341,717 (200,636)
-
95% Sharing Accounts -
2 Account 501, Coal 4,477,177 2,972,154 (1,505,023)
3 Account 547, Other Fuel 1,941,257 1,973,546 32,289
4 Account 555, Purchased Power Non-PURPA 974,474 2,095,454 1,120,980
95% Sharing Accounts 14,935,262 14,382,871 (552,391)
100% Sharing Accounts
5 Account 555, PURPA 2,962,728 2,976,554 13,826
100% Accounts 2,962,728 2,976,554 13,826
6 Total Generation 17,897,990 17,359,425 (538,565)
95% Sharing Accounts
7 Account 447, Surplus Sales 1,789,397 1,062,077 (727,320)
8 Total Load 16,108,593 16,297,348 188,755
PCA Forecast Comparison Generation (Total System-MWh)

TATUM, DI 15
Idaho Power Company
Boardman as compared to 618,539 MWh and 330,559 MWh, 1
respectively, for last year. The reduction in generation at 2
these plants as compared to last year is due in part to the 3
units no longer being available, but also due to economics. 4
The decrease in market energy prices is causing an 5
increase in non-PURPA purchased power of 1,120,980 MWh. As 6
mentioned previously, non-PURPA purchased power is 7
comprised of market power purchases and PPAs. The market 8
power purchases component is expected to increase 1,116,377 9
MWh, or 273 percent, while PPAs are expected to increase by 10
4,603 MWh, or less than 1 percent. The decrease in market 11
energy prices is also causing a 41 percent decrease in 12
surplus sales volumes as compared to last year, from 13
1,789,397 MWh to 1,062,077 MWh. 14
Finally, hydro generation is expected to decrease by 15
200,636 MWh, or 3 percent, from last year’s forecast. The 16
decrease in expected hydro generation is also contributing 17
to the reduction in surplus sales. 18
Q. What is causing the decrease in expected hydro 19
generation of 200,636 MWh? 20
A. The decrease in expected hydro generation is 21
mainly due to lower projected inflows into Brownlee 22
reservoir. The March Operating Plan used in this year’s 23
PCA forecast projects April through July inflows into 24
Brownlee of 4.6 million acre-feet (“MAF”) as compared with 25

TATUM, DI 16
Idaho Power Company
5.0 MAF used to determine last year’s PCA forecast, a 1
decrease of 8 percent. Expected inflows into Brownlee were 2
higher for last year’s PCA forecast as a result of better 3
snowpack conditions, which provide for sustained runoff and 4
increased hydro generation during the spring and summer 5
months. Although snowpack conditions in the Upper Snake 6
River Basin, which directly impact stream flows at Milner 7
Dam and, subsequently, through the majority of Idaho 8
Power’s hydroelectric plants, are above normal for this 9
year’s PCA forecast, snowpack conditions in the Boise and 10
Payette Basins are well below normal. Weaker snowpack 11
conditions in these basins are causing lower projected 12
inflows into Brownlee and a reduction in forecast hydro 13
generation for this year’s PCA forecast as compared to last 14
year. 15
Q. Why is the decrease in forecast hydro 16
generation not proportional to the decrease in expected 17
inflows at Brownlee as compared to last year? 18
A. Although forecasted inflows into Brownlee are 19
8 percent lower for the months of April through July as 20
compared to last year, total forecast generation is only 2 21
percent lower than last year. This is due to strong 22
carryover from last year. This year’s PCA forecast reflects 23
improved reservoir storage conditions, as compared to last 24
year’s forecast. The March Operating Plan used in this 25

TATUM, DI 17
Idaho Power Company
year’s PCA demonstrates that available storage in the 11 1
reservoirs above Brownlee is 125 percent of normal and at 2
82 percent of capacity, compared to last year’s 2019 March 3
Operating Plan, in which storage was 110 percent of normal 4
and at 74 percent of capacity. 5
B. True-up and True-up of the True-up. 6
Q. What is this year’s quantification of the 7
True-up? 8
A. The True-up portion of the PCA is detailed in 9
the deferral expense report, attached hereto as Exhibit No. 10
1. This report compares actual NPSE amounts to actual power 11
cost collections monthly, with the differences accumulated 12
as a deferral balance. The balance at the end of March 13
2020, with interest applied, was negative $31,869,646, as 14
shown on row 104 of Exhibit No. 1. The approximate 15
negative $31.9 million represents a refund due to customers 16
in this year’s PCA True-up. 17
Q. To what factors do you attribute the 18
accumulation of the approximate negative $31.9 million 19
deferral balance? 20
A. The approximate negative $31.9 million 21
deferral balance was primarily driven by unpredictable 22
changes in market energy prices and the resulting variation 23
in forecast prices and actual prices. Because actual market 24
energy prices were lower than expected, it resulted in 25

TATUM, DI 18
Idaho Power Company
higher than forecast market power purchases, and 1
alternatively, lower than forecast surplus sales revenue 2
and coal fuel expense. 3
Last year’s PCA forecast included an average market 4
purchase price of $36.73 per MWh. The actual average market 5
purchase price for the 2019-2020 PCA year was $19.60 per 6
MWh, a 47 percent decrease from the average forecast price. 7
Additionally, last year’s PCA forecast included an average 8
market sales price of $35.84 per MWh. The actual average 9
market sales price was $22.83 per MWh, a 36 percent 10
decrease from the average forecast price. As a result of 11
the difference in forecast and actual market energy prices, 12
market power purchases were higher than forecast while 13
surplus sales revenues were lower than forecast. 14
As a result of market purchase prices being lower 15
than expected, market power purchase volumes totaled 16
1,761,557 MWh, which was 1,352,332 MWh, or 330 percent, 17
more than forecast. Consequently, actual market power 18
purchase expense for the 2019-2020 PCA Year was $34,526,427 19
compared to $14,898,672 included in the forecast, 20
representing a 132 percent increase. 21
The decrease in actual market energy prices also 22
contributed to lower than forecast surplus sales revenues. 23
Actual surplus sales revenue totaled $50,014,065, which was 24
22 percent lower than forecast surplus sales revenues of 25

TATUM, DI 19
Idaho Power Company
$64,129,054. Although the value of surplus sales was not as 1
expected, actual surplus sales volumes were higher than 2
forecast. For the 2019-2020 PCA Year surplus sales totaled 3
2,189,829 MWh, which was 400,432 MWh more than last year’s 4
forecast of 1,789,397 MWh, reflecting a 22 percent 5
increase. The increase in surplus sales volumes was also 6
due in part to a 3 percent increase in actual hydro 7
generation compared to forecast. 8
Actual coal generation totaled 2,342,998 MWh, which 9
was 48 percent lower than forecast, and actual coal fuel 10
expense was $82,407,803, which was approximately 48 percent 11
lower than forecast. Coal-fired generation was displaced 12
with market purchased power as well as natural gas 13
generation. Natural gas generation totaled 2,325,102 MWh 14
for the 2019-2020 PCA Year, which was 383,845 MWh, or 20 15
percent, higher than forecast. Actual natural gas expense 16
totaled $52,280,833, which was 17 percent higher than 17
forecast. 18
Finally, the true-up also includes a $2,100,000 19
water lease expense for the 2019-2020 PCA Year that was not 20
reflected in last year’s PCA forecast. 21
Q. Please explain the water lease the Company 22
entered into in 2019. 23
A. In 2019, Idaho Power entered into an agreement 24
to purchase water from the Water District 1 supplemental 25

TATUM, DI 20
Idaho Power Company
rental pool. The agreement totaled 70,000 acre-feet at a 1
price of $30 per acre foot for a total cost of $2,100,000, 2
as shown on line 26 of Exhibit No. 1. The water flowed 3
through Idaho Power’s system beginning at Milner Dam from 4
August 1, 2019, through August 27, 2019. 5
Q. How did the water lease impact hydro 6
generation? 7
A. Based on the actual daily water flow, the 8
Company estimated that hydro generation from the water 9
lease totaled 65,937 MWh, resulting in a price of 10
approximately $31.85 per MWh. 11
Q. Did the water lease expense and associated 12
increase in hydro generation benefit customers? 13
A. Yes. During the period of flow, daily market 14
energy prices ranged from $25.24 per MWh to $39.55 per MWh 15
during light load hours and from $32.94 per MWh to $54.88 16
per MWh during heavy load hours. Idaho Power was able to 17
reduce market purchases during this time by using the 18
leased water and running additional water through the Hells 19
Canyon Complex. The purchase of leased water at $31.85 per 20
MWh compared favorably with the average price paid for 21
market purchases during the month, which was approximately 22
$35.79 per MWh. 23
This additional hydro generation also contributed to 24
Idaho Power’s ability to sell into high-priced hours to the 25

TATUM, DI 21
Idaho Power Company
benefit of customers. The average price for market sales 1
during the month was $60.70 per MWh, compared to the cost 2
of the leased water at $31.85 per MWh, resulting in net 3
revenue from surplus sales. 4
Q. Were there any items included in this year’s 5
True-up in addition to actual NPSE incurred during the 6
April 2019 through March 2020 period? 7
A. Yes. Per Commission Order No. 34100, Idaho 8
Power included its actual costs of Western Energy Imbalance 9
Market (“EIM”) participation for April 2019 through March 10
2020 in the True-up. Benefits associated with EIM 11
participation are embedded in actual NPSE experienced over 12
that same period. 13
Q. Please summarize the conditions of Order No. 14
34100 as they pertain to EIM cost recovery through the 2020 15
PCA. 16
A. Per the terms of the settlement stipulation 17
(“EIM Stipulation”) approved by Order No. 34100, Idaho 18
Power agreed to include an EIM-related monthly revenue 19
requirement in its monthly PCA deferral calculation based 20
on actual EIM participation costs commencing April 1, 2018. 21
The Company also agreed to apply a soft cap to EIM-related 22
revenue requirement included in the PCA deferral equal to 23
annual EIM benefits as reported by the California 24
25

TATUM, DI 22
Idaho Power Company
Independent System Operator (“CAISO”) for the corresponding 1
period. 2
Q. Is the EIM-related revenue requirement 3
included in the April 2019 through March 2020 PCA deferral 4
under the soft cap of annual CAISO-reported benefits for 5
that same period? 6
A. Yes. For the April 2019 through March 2020 7
period, the EIM-related revenue requirement totaled $3.2 8
million, while CAISO reported EIM benefits for Idaho Power 9
of $20 million from April through December (CAISO’s first 10
quarter 2020 report has not yet been published). Therefore, 11
the Company’s EIM-related revenue requirement is less than 12
the soft cap agreed to in the EIM Stipulation. 13
Q. Does Idaho Power believe the EIM has provided 14
net benefits to customers since joining in April 2018? 15
A. Yes. While Idaho Power believes the CAISO 16
benefit calculation overstates estimated benefits to Idaho 17
Power’s system, the Company believes customers have 18
realized significant net benefits since the Company’s entry 19
into the EIM in April 2018. As discussed in the Company’s 20
May 24, 2019, Report of EIM Benefits and Costs of 21
Participation, filed in Case No. IPC-E-16-19, Idaho Power 22
has developed a more precise methodology for determining 23
EIM benefits that uses inputs specific to the Company. 24
Based on this methodology, the Company believes benefits 25

TATUM, DI 23
Idaho Power Company
achieved between April 2019 and March 2020 range between 1
$14 and $18 million (benefits for March 2020 are not yet 2
available). This level of EIM benefits compared to the 3
Idaho-jurisdictional EIM costs of $3.2 million, 4
demonstrates a net benefit to the Company and, ultimately, 5
its customers. 6
Q. Did the Company calculate the Sales Based 7
Adjustment (“SBA”) per the terms of the settlement 8
stipulation approved in Order No. 33307 in Case No. 9
IPC-E-15-15? 10
A. Yes. The Company’s deferral report provided 11
as Exhibit No. 1 reflects the SBA per the methodology 12
approved in Case No. IPC-E-15-15. Beginning on line 10 of 13
Exhibit No. 1, the Company calculates the SBA using actual 14
Idaho jurisdictional billing month sales. 15
Q. What is this year’s True-up of the True-up? 16
A. This year’s True-up of the True-up balance is 17
a credit to customers of $10,778,801, as shown on row 124 18
of Exhibit No. 1. 19
Q. What is the combined effect of the True-up and 20
the True-up of the True-up in this year’s PCA? 21
A. The sum of the negative $31.9 million 22
associated with the True-up and the negative $10.8 million 23
associated with the True-up of the True-up represents an 24
approximate $42.7 million credit to customers. 25

TATUM, DI 24
Idaho Power Company
Q. How does this year’s combined True-up and the 1
True-up of the True-up compare to last year’s amount? 2
A. The combined True-up and the True-up of the 3
True-up for the last PCA Year was negative $64,031,080, as 4
compared with this year’s amount of negative $42,648,447. 5
While this year’s true-up reflects a credit to customers, 6
it is less than the credit customers are currently 7
receiving through last year’s true-up, and ultimately 8
reflects an increase in billed revenue of $21,382,633. 9
III. NET CUSTOMER IMPACT 10
Q. What is the revenue impact of the requested 11
PCA rate when compared with PCA rates currently in effect? 12
A. Attachment 2 to the Application filed 13
contemporaneously with my testimony provides a detailed 14
description of the overall revenue impact of this filing on 15
each customer class. As shown in Attachment 2, applying 16
the requested PCA rates, presented in Ms. Blackwell’s 17
testimony, to expected customer sales for the June 2020 18
through May 2021 test year results in a PCA increase of 19
$58.7 million. 20
IV. OTHER PCA IMPACT CONSIDERATIONS 21
Q. Has Idaho Power been monitoring the recent 22
impacts of the current coronavirus disease outbreak? 23
A. Yes. In February 2020, the World Health 24
Organization (”WHO”) designated the novel coronavirus disease 25

TATUM, DI 25
Idaho Power Company
outbreak that began in 2019 as COVID-19 (‘CO’ stands for 1
‘corona,’ ‘VI’ for ‘virus,’ and ‘D’ for disease). The 2
infectious disease causes respiratory illness such as fever, 3
cough, and shortness of breath 2-14 days after exposure from 4
another infected person. As of April 14, 2020, WHO reports 5
1,918,138 confirmed cases and 123,126 confirmed deaths in 213 6
countries, areas, or territories related to the COVID-19 7
pandemic.3 8
On March 25, 2020, Idaho Governor Little issued an 9
“extreme emergency declaration” over the COVID-19 outbreak. 10
As permitted by Idaho Code § 56-1003(7), on March 25, 2020, 11
Governor Little and the Director of Idaho Department of Health 12
and Welfare issued an Order to Self-Isolate for the State of 13
Idaho (“Stay-Home Order”) “to protect the public from the 14
spread of infectious or communicable diseases” through April 15
15, 2020 or until it is extended, rescinded, superseded, or 16
amended in writing by the Director.4 17
As a result of the impacts of COVID-19 and Idaho’s 18
state and local stay-home orders on Idaho businesses, Idaho 19
Power expects that there will be a new subset of its customers 20

3 World Health Organization, Coronavirus disease (COVID-19) pandemic
statistics available at https://www.who.int/emergencies/diseases/novel-
coronavirus-2019.

4 Idaho Department of Health & Welfare Director Dave Jeppesen to
All Citizens of the State of Idaho, Elected and Appointed Officials, Order
to Self-Isolate for the State of Idaho (March 25, 2020).

TATUM, DI 26
Idaho Power Company
that will have an inability, or will be challenged financially, 1
to pay their Idaho Power bills until they can return to work. 2
Q. What is Idaho Power doing to help its customers 3
who may be struggling financially during this difficult time? 4
A. On March 16, 2020, the Company temporarily 5
suspended service disconnections for non-payment applicable to 6
all Idaho and Oregon residential and small/medium business 7
customers. On the same date, Idaho Power also began a temporary 8
suspension of all late fees for applicable customer billings. 9
In addition, Idaho Power has launched an energy efficiency 10
educational campaign to further educate customers on ways to 11
help them better manage their energy costs. The Company hopes 12
that these measures will help contribute to the overall health 13
and safety of customers during this unprecedented crisis, as 14
well as to mitigate the short-term financial impact for 15
affected customers. 16
Q. Did Idaho Power consider recommending some form 17
of mitigation measures for this year’s PCA in light of this 18
ongoing COVID-19 event? 19
A. Yes. However, after thoughtful and careful 20
consideration, Idaho Power believes its customers would be best 21
served by implementing the full proposed PCA revenue increase 22
effective June 1, 2020. While the Company is sensitive to the 23
financial impact this proposed rate increase will have on its 24
customers during this challenging time, the potential longer-25

TATUM, DI 27
Idaho Power Company
term downside risks outweigh the near-term relief of deferring 1
a portion, or all, of the requested increase. 2
First, Idaho Power believes that postponing collection 3
of known costs to a future period could create more harm than 4
good by risking the compounding or “pancaking” of this current 5
revenue increase on top of possible future rate increases. 6
Secondly, the Company believes that revenue collection less 7
than the proposed collection in this case could have 8
significant negative financial impact on the Company. 9
A. Rate Pancaking Concerns 10
Q. Please explain the Company’s concern regarding 11
the risk of “rate pancaking” associated with the deferral of 12
the proposed PCA increase? 13
A. Idaho Power believes that customers interests 14
are generally best served by matching cost recovery as 15
closely as possible with the period in which power supply 16
costs are incurred. This matching minimizes compounding or 17
pancaking of rates that could harm customers more in the 18
future than a deferral would help those same customers 19
today. 20
Q. Are there certain aspects of this year’s PCA 21
request that should be considered when evaluating the rate 22
pancaking risk in this case? 23
A. Yes. As I mentioned earlier in my testimony, 24
this year’s PCA increase, if approved, would move the level 25

TATUM, DI 28
Idaho Power Company
of PCA cost recovery back to a level that reflects a more 1
normal expectation of NPSE. As can be seen in Table 2, PCA 2
collection in each of the years preceding last year’s PCA 3
were either near or above the level of collection proposed 4
in this case. Because the vast majority of this year’s PCA 5
increase is the result of removing non-recurring benefits 6
(i.e., relatively high market energy prices, revenue 7
sharing, and temporary tax reform benefits), the risk of 8
rate pancaking from deferred cost recovery is quite high. 9
It should also be noted that this year’s PCA 10
forecast includes a slightly above normal level of hydro 11
generation as compared to the 30-year median value. If 12
hydro conditions were to worsen next year, any deferred 13
collection from this PCA-year would add to the resulting 14
higher NPSE next year. Further, approximately 51 percent of 15
the proposed PCA forecast collection is related to recovery 16
of PURPA costs - costs that are known today and are under 17
contract. Deferral of known annual PURPA costs would surely 18
result in compounding with future known PURPA cost 19
collection. 20
Q. Has the Commission in the past expressed 21
concerns about deferring PCA recovery into future periods? 22
A. Yes. The Commission has, on a number of 23
occasions, expressed opposition to spreading the collection 24
of PCA amounts over multiple years. As part of its order 25

TATUM, DI 29
Idaho Power Company
regarding the 2001 PCA, the Commission made the following 1
statement: 2
While the Commission is sympathetic to 3
the request that the authorized rate 4
increase or some portion thereof be 5
amortized over time, the Commission 6
declines to adopt this recommendation. 7
8
Order No. 28722 at 26. As part of its order regarding the 9
2002 PCA, the Commission made the following statement: 10
The Commission is also concerned that 11
the longer the power supply cost 12
recovery is delayed, the greater the 13
risk that the customers taking service 14
when deferred costs were incurred will 15
not be the same customers that will 16
later pay for them. 17
18
Order No. 29026 at 15. As part of its order regarding the 19
2008 PCA, the Commission made the following statement: 20
It is simply too risky, and potentially 21
compounds the problem, to seek recovery 22
from ratepayers across three future 23
years. 24
25
Order No. 30563 at 7. As part of its order regarding the 26
2009 PCA, the Commission made the following statement: 27
Despite the significant amount included 28
for recovery in the PCA this year, the 29
Commission declines to spread recovery 30
of the amount into a subsequent year. 31
32
Order No. 30828 at 10. Most recently, as part of its order 33
regarding the 2013 PCA, the Commission made the following 34
statement: 35
The PCA was never intended for long 36
term recovery of costs that continue 37

TATUM, DI 30
Idaho Power Company
year to year. It was implemented to 1
properly recover the Company’s annual 2
fluctuation in power supply costs and 3
keep the customers from paying either 4
too little or too much of those costs. 5
6
Order No. 32821 at 11. 7
B. COVID-19 Financial Impacts 8
Q. If the Commission were to defer collection of 9
some, or all, of the requested PCA increase, would the 10
Company have financial concerns? 11
A. Yes. Under normal circumstances deferred PCA 12
collection of the amount requested in this case would not 13
likely have a material financial impact on the Company. 14
However, shortly following the announcement of the COVID-19 15
outbreak in the United States, the resulting negative 16
impacts on the financial markets have presented challenges 17
for companies like Idaho Power. Reduced cash from PCA-18
related sales would further challenge the Company’s ability 19
to cost-effectively fund its near-term operations. If PCA 20
collection were to be deferred, the Company may not be able 21
to cost-effectively access financial markets to offset the 22
lost cash in the near term. 23
Q. Please provide some examples of how the COVID-24
19 crisis has impacted the Company’s financing costs and 25
its ability to access cash to fund operations. 26
A. Idaho Power began 2020 with a solid short-term 27
cash investing position; its short-term investments were 28

TATUM, DI 31
Idaho Power Company
liquid and accessible. By the end of the first quarter of 1
2020 that all changed, despite efforts to conserve cash. 2
The uncertain economic impact of COVID-19 on the 3
cash forecast for the remainder of the year compelled Idaho 4
Power to explore the possibility of short-term borrowing in 5
March and April. 6
The Company typically issues commercial paper (“CP”) 7
for short-term borrowing; however, the market in March for 8
CP was negatively impacted by the current crisis and did 9
not represent a reliable option to finance short-term 10
debt. At the same time, economic concerns tied to COVID-19 11
caused a surge of investors exiting money market funds to 12
raise cash during mid to late March. This caused short-13
term rates to rise steeply as there were many sellers and 14
few buyers. 15
This unusual financial market turbulence had a 16
particularly troubling impact on two Idaho Power-issued 17
bonds with rates that reset weekly: the American Falls 18
guarantee and the Port of Morrow Pollution Control Revenue 19
Bonds. The aggregate principal amount outstanding for these 20
two bonds is over 24 million dollars. The interest rates on 21
these bonds went from 1.35 percent on March 11 to 4.2 22
percent on March 19, and then increased to 5.2 percent on 23
March 25. The financial market has recently stabilized 24
somewhat with rates coming down to 2.15 percent on April 25

TATUM, DI 32
Idaho Power Company
1. If rates were to stay at the 5 percent level, it would 1
cost the Company over $800,000 in additional annual 2
interest expense. There would also be a high risk that the 3
Company could be forced to buy back the bonds if there were 4
not buyers in the market. 5
Several of the Company’s banks had previously 6
expressed interest in providing an 18-month to three-year 7
loan to the Company at relatively favorable rates. The 8
Company had a call with one of those banks the morning of 9
March 23 to work through the details of the loan. By the 10
afternoon of March 23, the bank pulled back its offer. The 11
Company contacted all six banks that it normally transacts 12
with and none were willing to execute a similar loan. 13
Q. What measures has the Company taken to ensure 14
its ability to fund operations in response to these unique 15
financial circumstances? 16
A. During the last week of March, the investment 17
grade bond market presented some relatively favorable 18
financing opportunities. The Company quickly moved a 30-19
year debt issuance planned for later in the year up to 20
March 31st, to take advantage of favorable long-term 21
rates. Idaho Power also increased the size of the proceeds 22
received on its bonds to $260 million from the $220 million 23
that was originally planned, to provide extra security as 24
the Company continues to evaluate the unknown impacts of 25

TATUM, DI 33
Idaho Power Company
COVID-19, including reduced revenue collections from 1
customers. A large portion of the proceeds are earmarked 2
for redemption of $100 million of bonds that mature later 3
in the year. Additionally, the Company is currently making 4
best efforts to keep its $300 million credit line in 5
reserve for the future. On March 23, Idaho Power inquired 6
of the availability of the $300 million credit line and was 7
assured the Company would continue to be allowed to draw on 8
the credit line. 9
Q. Please summarize the Company’s concerns 10
regarding the financial impact to Idaho Power of deferring 11
the proposed PCA collection to a subsequent period. 12
A. The financial impact of the COVID-19 health 13
crisis on the CP market has already been felt by the 14
Company. While Idaho Power has been able to successfully 15
navigate financial market impacts to-date, further 16
financial stress caused by deferred PCA cost recovery would 17
likely exacerbate an already challenging operating 18
environment. 19
V. CONCLUSION 20
Q. Please summarize the Company’s request in this 21
case. 22
A. The PCA is a rate mechanism that quantifies 23
and tracks annual differences between actual NPSE and the 24
normalized level of NPSE recovered in the Company’s base 25

TATUM, DI 34
Idaho Power Company
rates, resulting in a credit or surcharge that is updated 1
annually on June 1. The calculation of the proposed 2020-2
2021 PCA rates complies with the methodology that was 3
approved in Order Nos. 30715, 33149, and 33307. If 4
approved, the 2020-2021 PCA will result in an increase in 5
total billed revenue of approximately $58.7 million, or 6
5.21 percent. 7
While the Company is sensitive to the financial 8
impact this proposed rate increase will have on its 9
customers during this challenging time, the potential 10
longer-term downside risks outweigh the near-term relief of 11
deferring a portion, or all, of the requested increase. 12
After thoughtful and careful consideration, Idaho Power 13
believes its customers would be best served by implementing 14
the full proposed PCA revenue increase effective June 1, 15
2020. 16
Q. Does this conclude your testimony? 17
A. Yes, it does. 18
19
20
21
22
23
24
25

TATUM, DI 35
Idaho Power Company
DECLARATION OF TIMOTHY E. TATUM 1
I, Timothy E. Tatum, declare under penalty of 2
perjury under the laws of the state of Idaho: 3
1. My name is Timothy E. Tatum. I am employed 4
by Idaho Power Company as the Vice President of the 5
Regulatory Affairs Department. 6
2. On behalf of Idaho Power, I present this 7
pre-filed direct testimony and Exhibit No. 1 in this 8
matter. 9
3. To the best of my knowledge, my pre-filed 10
direct testimony and exhibit are true and accurate. 11
I hereby declare that the above statement is true to 12
the best of my knowledge and belief, and that I understand 13
it is made for use as evidence before the Idaho Public 14
Utilities Commission and is subject to penalty for perjury. 15
SIGNED this 15th day of April 2020, at Boise, Idaho. 16
17
Signed: _________________________ 18
Timothy E. Tatum 19
20
21
22
23
24
25
26
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO.IPC-E-20-21
IDAHO POWER COMPANY
TATUM,Dl
TESTIMONY
EXHIBIT NO.1
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18
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$
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J
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0
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4
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7
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3
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59
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59
,
1
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3
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2
7
.
0
9
Exhibit No. 1 Case No. IPC-E-20-21 T. Tatum, IPC
Page 1 of 2
12 3
A
B
C
D
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-

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6
6
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8
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n

A
p
p
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d

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o

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a
l
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c
e
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0
3
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3
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3
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7
3
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2
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3
9
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d
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a
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c
e
$
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4
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4
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2
8
5
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3
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0
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7
6
4
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0
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6
8
8
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1
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6
2
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5
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7
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4
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8
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2
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6
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6
5
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1
3
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2
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7
3
9
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9
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3
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8
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7
7
8
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8
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0
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7
7
8
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0
8
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Id
a
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o

B
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l
l
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d

S
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Mw
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96
9
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1
3
3

1,
0
0
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1
7
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1,
0
8
7
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8
4
6

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5
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7

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8
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1
2
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3

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0
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5
2
5

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8
7
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2
3
5

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1
5
6
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5
4
3

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0
1
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7
5
8

1,0
2
4
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1
0
3

13
,
8
2
7
,
7
8
9

Or
e
g
o
n

B
i
l
l
e
d

S
a
l
e
s
Mw
h
49
,
1
1
1

49
,
3
0
5

52
,
5
6
6

67
,
0
2
7

68
,
4
3
5

60
,
2
3
9

47
,
6
4
2

53
,
6
8
0

57
,
8
6
0

57
,
5
5
5

46
,
9
6
6

48
,
7
1
9

65
9
,
1
0
5

T
o
t
a
l
Mw
h
1,
0
1
8
,
2
4
4

1,
0
5
8
,
4
8
0

1,
1
4
0
,
4
1
2

1,5
2
0
,
8
1
8

1,6
2
4
,
3
0
2

1,4
3
0
,
0
3
9

1,
0
5
9
,
6
5
5

1,0
5
4
,
2
0
5

1,
1
4
5
,
0
9
5

1,
2
1
4
,
0
9
8

1,1
4
8
,
7
2
4

1,0
7
2
,
8
2
2

14
,
4
8
6
,
8
9
4

Id
a
h
o

%

B
i
l
l
e
d

S
a
l
e
s
95
.
2
%
95
.
3
%
95
.
4
%
95
.
6
%
95
.
8
%
95
.
8
%
95
.
5
%
94
.
9
%
94
.
9
%
95
.
3
%
95
.
9
%
95
.
5
%
Or
e
g
o
n

%

B
i
l
l
e
d

S
a
l
e
s
4.8
%
4.
7
%
4.
6
%
4.
4
%
4.2
%
4.2
%
4.
5
%
5.1
%
5.1
%
4.7
%
4.1
%
4.5
%
Exhibit No. 1 Case No. IPC-E-20-21 T. Tatum, IPC
Page 2 of 2