HomeMy WebLinkAbout20230601Direct Tatum.pdf
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
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.
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CASE NO. IPC-E-23-11
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
TIMOTHY E. TATUM
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 am 5
employed by Idaho Power as Vice President of Regulatory 6
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 Electric Industry,” a course 13
offered through the New Mexico State University’s Center 14
for Public Utilities, “Introduction to Rate Design and Cost 15
of Service Concepts and Techniques” presented by Edison 16
Electric 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. 20
Q. Please describe your work experience with 21
Idaho Power. 22
A. I began my employment with Idaho Power in 1996 23
in the Company’s Customer Service Center where I handled 24
customer phone calls, customer-related transactions, and 25
TATUM, DI 2 Idaho Power Company
general customer account maintenance in the areas of 1
billing and metering. 2
In June of 2003, I began working as an Economic 3
Analyst on the Energy Efficiency Team. As an Economic 4
Analyst, I was responsible for ensuring that the demand-5
side management (“DSM”) expenses were accounted for 6
properly, preparing and reporting DSM program costs and 7
activities to management and various external stakeholders, 8
conducting cost-benefit analyses of DSM programs, and 9
providing DSM analysis support for the Company’s Integrated 10
Resource Plan. 11
In August 2004, I accepted a position as a 12
Regulatory Analyst and in August of 2006, I was promoted to 13
Senior Regulatory Analyst. As a Senior Regulatory Analyst, 14
my responsibilities included the development of complex 15
financial studies to determine revenue recovery and pricing 16
strategies, including preparation of the Company’s cost-of-17
service studies. 18
In September of 2008, I was promoted to Manager of 19
Cost of Service, and in 2011, I was promoted to Senior 20
Manager of Cost of Service and oversaw the Company’s cost-21
of-service activities, such as power supply modeling, 22
jurisdictional separation studies, class cost-of-service 23
studies, and marginal cost studies. 24
TATUM, DI 3 Idaho Power Company
In March 2016, I was promoted to Vice President of 1
Regulatory Affairs. As Vice President of Regulatory 2
Affairs, I am responsible for the overall coordination and 3
direction of the Regulatory Affairs Department, including 4
development of jurisdictional revenue requirements and 5
class cost-of-service studies, preparation of rate design 6
analyses, and administration of tariffs and customer 7
contracts. 8
I. CASE OVERVIEW 9
Q. What role did you play in the preparation of 10
the general rate case (“GRC”)? 11
A. My role in the preparation of the GRC was to 12
oversee, manage, and coordinate the filing and to make the 13
policy decisions related to regulatory matters in 14
consultation with Ms. Lisa Grow, our Company’s President 15
and Chief Executive Officer, along with other senior 16
officers within Idaho Power. 17
Q. What is Idaho Power’s requested revenue 18
increase this case? 19
A. The Company is requesting rate relief of 20
approximately $111.3 million, which is net of a 21
corresponding proposed Power Cost Adjustment (“PCA”) 22
decrease of $173.4 million and a reduction to annual Energy 23
Efficiency Rider collection of $3.5 million. If approved, 24
this request would result in an overall increase to 25
TATUM, DI 4 Idaho Power Company
adjusted base revenue of 8.61 percent effective January 1, 1
2024. The Company’s request is based on a proposed rate of 2
return of 7.702 percent, with a capital structure comprised 3
of 51 percent equity and 49 percent debt, a 4.895 percent 4
cost of debt, and a 10.40 percent return on equity (“ROE”). 5
Q. What is the Company’s test year? 6
A. The test year is the 12 months ending December 7
31, 2023. 8
Q. Why is Idaho Power requesting a corresponding 9
PCA decrease of $173.4 million in this case? 10
A. Idaho Power’s current Idaho base rates collect 11
approximately $300 million annually to fund normalized or 12
“base level” net power supply expense (“NPSE”). This level 13
of NPSE collection authorized by Order No. 33000 in Case 14
No. IPC-E-13-20 became effective June 1, 2014, based on a 15
2013 calendar year. Since that time, the Company’s 16
normalized NPSE has increased largely because of load 17
growth and changes in fuel costs, market energy prices, and 18
increased power purchase agreement costs. Currently, 19
incremental NPSE over the base level NPSE established in 20
2014 are collected annually through the PCA forecast 21
component. Because the Company’s requested Idaho-22
jurisdictional revenue requirement in this case reflects 23
updated base level NPSE based on the 2023 test year, the 24
Company is requesting a corresponding decrease in annual 25
TATUM, DI 5 Idaho Power Company
PCA collection to ensure customers do not pay twice for the 1
same NPSE. Simply put, this necessary PCA reduction will 2
facilitate the transfer of base level NPSE collection from 3
the PCA into base rates. 4
Q. How is energy efficiency currently funded at 5
Idaho Power? 6
A. The Company’s energy efficiency activities, 7
also referred to as DSM, are primarily funded through the 8
Energy Efficiency Rider, Schedule 91 (“Rider”), which is 9
applied as a fixed percentage of each customer’s billed 10
base revenue. Idaho Power is currently authorized to 11
collect 3.1 percent of base revenue annually through the 12
Rider. 13
Q. What is the Company’s proposal regarding 14
annual Rider collection? 15
A. Idaho Power is proposing to transfer 16
approximately $3.5 million in ongoing Rider-funded labor 17
costs into base rates, while otherwise maintaining the same 18
level of annual DSM funding as measured in dollars that 19
exists today. To achieve this goal, the Company is 20
proposing a decrease in Rider collection from the current 21
3.1 percent to 2.25 percent. 22
Q. Why is the Company proposing to transfer 23
approximately $3.5 million in ongoing DSM labor costs in 24
this rate filing? 25
TATUM, DI 6 Idaho Power Company
A. There are two reasons for this proposal. 1
First, energy efficiency has been a core business activity 2
at Idaho Power for over 20 years, since the Rider was 3
established in 2002. At the time the Rider was established, 4
the Company identified all incremental costs associated 5
with implementing and managing new DSM programs, including 6
incremental labor-related costs, to be funded through that 7
mechanism. Over time, DSM program management and 8
administration staffing has reached a relatively steady 9
state, both from a cost and head-count perspective. For 10
these reasons, it is appropriate to treat DSM labor the 11
same as any other Company labor costs for ratemaking 12
purposes. 13
Secondly, DSM labor costs have been a point of 14
concern for the Commission Staff (“Staff”) in past prudence 15
review cases. My understanding of Staff’s concern is that 16
Rider-funded labor, under the annual prudence review 17
process, has allowed for recovery of labor-related costs 18
annually without the rigorous, comprehensive review applied 19
in general rate cases. By treating DSM labor the same as 20
all other labor costs for cost recovery purposes, Idaho 21
Power believes this will address Staff’s concern. 22
Q. What is the implication of this proposal for 23
energy efficiency activities going forward? 24
A. The proposed reduction in energy efficiency 25
TATUM, DI 7 Idaho Power Company
Rider funding will have no impact on the Company’s pursuit 1
of cost-effective energy efficiency activities. This 2
adjustment is only intended to transfer the collection of 3
energy efficiency labor costs to base rates and to ensure 4
that the increase to base rate revenue requested in this 5
case does not result in an increase to the annual revenue 6
collected under the Rider. As always, Idaho Power will 7
monitor the need for energy efficiency funding and will 8
propose adjustments to funding levels as warranted to allow 9
for the Company’s continued pursuit of all cost-effective 10
energy efficiency. 11
Q. Is Company seeking any specific regulatory 12
treatment related to wildfire mitigation and insurance 13
costs as part of this case? 14
A. Yes. Idaho Power requests the Commission 15
continue to authorize the Company to defer incremental 16
wildfire mitigation and insurance costs as measured from a 17
new base level of costs established in this case. This 18
proposed treatment is consistent with the authority granted 19
by the Commission in Case Nos. IPC-E-21-02 and IPC-E-22-27, 20
with certain limited modifications. 21
In this case, the Company is only requesting 22
authority to defer incremental costs associated with two 23
previously authorized cost deferral categories of 24
vegetation management and insurance. 25
TATUM, DI 8 Idaho Power Company
Q. Why is Idaho Power requesting ongoing deferral 1
authority for incremental vegetation management and 2
insurance expenses above the baseline levels set in this 3
case? 4
A. As discussed in the Direct Testimony of 5
Company Witness Mr. Brian Buckham, insurance costs have 6
increased in recent years and continue to rise. Further, 7
insurance costs are increasingly difficult to forecast due 8
to price volatility. While Idaho Power undertakes 9
significant efforts to ensure it receives the greatest 10
insurance value possible for its customers, the Company is 11
largely a price-taker in the insurance market and must 12
absorb price increases as insurers raise premiums due to 13
losses. Therefore, the Company believes it is appropriate 14
to request a new baseline level of insurance in rates and 15
also to establish a new deferral to capture incremental 16
insurance premium costs above the new baseline. 17
Similarly, as addressed in detail in the Direct 18
Testimony of Company Witness Mr. Mitch Colburn, vegetation 19
management costs continue to rise. These costs constitute 20
the largest single expense associated with the Company’s 21
wildfire mitigation efforts. As such, the Company requests 22
the authority to continue to defer incremental vegetation 23
management above the new baseline established in this case 24
until such a time that these costs stabilize. 25
TATUM, DI 9 Idaho Power Company
Q. Is the Company requesting new deferral 1
authority for wildfire-mitigation related capital items? 2
A. No. Because the Company has already made the 3
majority of necessary incremental capital investments 4
related to the implementation of its Wildfire Mitigation 5
Plan, there is no longer a need to defer related 6
depreciation expense amounts. 7
Q. Is the Company requesting any other specific 8
regulatory treatment as part of this case? 9
A. Yes. The Company has several requests for 10
specific regulatory treatment and necessary regulatory 11
accounting as part of this case that I will cover in detail 12
later in my testimony. At the end of my testimony, I will 13
provide a summary listing each of those requests for 14
clarity and transparency. 15
II. TEST YEAR 16
Q. How did the Company prepare its test year in 17
this proceeding? 18
A. Idaho Power prepared its 2023 test year in 19
this case using the same general forecast methodology used 20
in the Company’s last two general rate cases, IPC-E-08-10 21
and IPC-E-11-08. The Company’s test year methodology starts 22
with actual 12-month financial results adjusted to include 23
typical and traditional ratemaking adjustments consistent 24
with a historical test year. The adjusted 2022 actual 25
TATUM, DI 10 Idaho Power Company
financial information was then further adjusted to reflect 1
2023 results through the use of known and measurable 2
adjustments appropriate for the particular revenue, 3
expense, or asset classification. 4
Q. What attributes should be considered when 5
selecting a test year? 6
A. In practice, in every rate case, a test year 7
must be selected. Whether the test year selected is 8
historical, future, or some hybrid, the most important 9
attribute of the selected test year should be that it 10
accurately reflects the best expectation of the cost of 11
service. 12
Regardless of which test year is adopted, the 13
ratemaking process is inherently prospective and requires 14
reliance upon projections. Whether the test year is 15
completely historical or based totally on future results, 16
the ratemaking process requires an informed determination 17
of what conditions will prevail in the future. As of the 18
date of filing, Idaho Power has used its best financial and 19
operational information to construct its forecast test 20
year. 21
Utility commissions and policy makers throughout the 22
country, and particularly in the West, are increasingly 23
recognizing that in times of high inflation and heavy 24
construction, future test years are necessary to allow 25
TATUM, DI 11 Idaho Power Company
utilities a reasonable opportunity to earn their authorized 1
rate of return. Utilities that operate in a period of rapid 2
expansion and rate base growth will chronically under-earn 3
if test years are historical in nature and fail to 4
synchronize the matching of expenses and revenues. 5
Ultimately, Idaho Power must apply a test year 6
approach that is both timely and reflective of the costs 7
that the Company can reasonably expect to incur going 8
forward. A historical test year is by definition not timely 9
and may not be a reflection of costs going forward. 10
Similarly, a test year based on a reasonable forecast may 11
be more indicative of the costs the Company will be 12
experiencing during the time rates are in place, thereby 13
reducing the effects of “regulatory lag”. 14
Q. Why is regulatory lag such a critical issue 15
to Idaho Power at this time? 16
A. During periods of escalating costs where 17
marginal costs are higher than average costs, new rates are 18
already inadequate by the time they go into place. If this 19
situation continues for a prolonged period of time, the 20
Company will be denied a reasonable opportunity to earn its 21
authorized rate of return. The effects of regulatory lag 22
are particularly pronounced in periods where the Company is 23
engaged in capital-intensive projects and where interest 24
rates to finance capital projects are rising. 25
TATUM, DI 12 Idaho Power Company
Q. Is regulatory lag always harmful to a 1
utility? 2
A. No. The impact of regulatory lag is 3
dependent upon the situation – if overall revenue growth is 4
keeping pace with cost escalation, and the Company is not 5
engaged in capital-intensive projects and procuring debt 6
and equity financing for those projects, then the Company 7
is not typically harmed by regulatory lag. Unfortunately, 8
Idaho Power is not in that situation currently, and will 9
not likely be for the foreseeable future. 10
III. REVENUE REQUIREMENT MITIGATION ADJUSTMENTS 11
Q. Did you receive any specific instructions from 12
Ms. Grow in preparing this general rate case filing? 13
A. Yes. In recognition of the broader economic 14
conditions and concern for the impact that any rate 15
increase has on customers, Ms. Grow asked me to identify 16
specific areas where the Company could reduce the requested 17
increase at this time. As a result, I identified the 18
following areas where the Company is not asking for 19
incremental increases or has otherwise taken action to 20
minimize the overall requested revenue increase: 21
• Reduce return on equity (“ROE”) from the 22
recommended level of 10.60 percent to 10.40 percent; 23
• Hold test year non-labor operations and 24
maintenance (“O&M”) expenses to the 2022 actual level with 25
TATUM, DI 13 Idaho Power Company
the exception of a limited number of known and measurable 1
adjustments; 2
• Maintain the North Valmy Power Plant 3
(“Valmy”) and the Jim Bridger Power Plant (“Bridger”) non-4
fuel coal-related cost recovery at current levels, with the 5
exception of collection related to previously deferred 6
revenue requirement amounts; 7
• Minimize the current revenue increase 8
related to wildfire mitigation and pension costs by 9
leveraging the existing cost recovery mechanisms; and 10
• Delay recovery of the revenue requirement 11
associated with the 120 megawatts (“MW”) of battery storage 12
resources to be online in 2023 with interim earnings 13
support from the associated investment tax credits 14
generated from the battery storage resources. 15
Q. How did the Company arrive at its recommended 16
mitigated ROE of 10.4 percent? 17
A. After discussions with Mr. Buckham, Senior 18
Vice President and Chief Financial Officer, regarding Ms. 19
Grow’s directive to mitigate our rate relief request, the 20
Company decided to apply an ROE that is at the lower end of 21
the range provided by our outside ROE expert. Mr. Buckham 22
believes this recommendation represents the minimum 23
required ROE necessary to not weaken the Company’s ability 24
to attract capital at favorable and customer-beneficial 25
TATUM, DI 14 Idaho Power Company
rates in the current uncertain and volatile financial 1
markets. 2
Q. What steps did the Company take to minimize 3
the level of non-labor O&M included in the test year and 4
what were the results? 5
A. The Company chose to hold test year non-labor 6
O&M expense to the 2022 actual level, with the exception of 7
a limited number of known and measurable adjustments. As 8
discussed by Ms. Grow in her testimony, the Company has a 9
strong track record of managing its O&M expenses, and as a 10
result has achieved an average annual O&M growth rate of 11
only one percent between 2012 and 2022. After applying all 12
known and measurable adjustments to the 2022 actual 13
financial results, Idaho Power’s proposed test year non-14
labor O&M is within approximately $340 thousand of the 2022 15
expense level. 16
Q. What is the Company’s recommendation regarding 17
the recovery of non-fuel coal-related revenue requirements 18
associated with the Valmy and Jim Bridger power plants? 19
A. Because the Commission has previously 20
established separate cost recovery mechanisms for these 21
components of the Valmy and Bridger plants in Order Nos. 22
33771 and 35423, respectively, the Company is proposing to 23
maintain the current level of recovery as previously 24
authorized by the Commission with one exception. In 25
TATUM, DI 15 Idaho Power Company
addition to maintaining recovery of the amounts already 1
included in customer rates, the Company is proposing to 2
increase collections only related to the Bridger plant to 3
include revenue requirement amounts that the Commission 4
chose to defer for later recovery in Order No. 35423. 5
Q. What incremental Bridger-related cost recovery 6
is the Company requesting in this case? 7
A. Idaho Power is requesting recovery of the full 8
annual levelized revenue requirement approved in Case No. 9
IPC-E-21-17 and amortization of previously deferred 10
levelized revenue requirement amounts. The total 11
incremental annual Bridger-related cost recovery included 12
in this case is approximately $10.7 million. 13
Q. What is the Company’s recommendation regarding 14
the test year level of wildfire mitigation costs? 15
A. Idaho Power is proposing to hold test year 16
levels of wildfire mitigation costs to 2022 actual cost. 17
Further, the Company is requesting amortization into rates 18
of previously deferred wildfire mitigation costs, excluding 19
deferred vegetation management costs, over a seven-year 20
amortization period. 21
Q. Why is the Company requesting to exclude 22
deferred vegetation management costs as part of its 23
amortization request in this case? 24
A. As introduced earlier, vegetation management 25
TATUM, DI 16 Idaho Power Company
costs represent the largest single cost component of the 1
Company’s overall wildfire mitigation costs. As a rate 2
mitigation measure, the Company chose to postpone the 3
recovery of deferred vegetation management costs and 4
instead continue to utilize the deferral account authorized 5
by the Commission in Order Nos. 35077 and 35717 issued in 6
Case Nos. IPC-E-21-02 and IPC-E-22-27, respectively. By 7
setting cost recovery at the 2022 level, the Company 8
anticipates that the need to defer incremental amounts over 9
time may diminish. 10
Further, the Company is hopeful that advances in new 11
vegetation monitoring technology may eventually reduce 12
annual vegetation management costs, allowing for deferred 13
amounts to be offset by future cost reductions, thereby 14
reducing the deferral balance. The Company will continue to 15
closely monitor its vegetation management costs and will 16
report back to the Commission in a future proceeding if an 17
adjustment to related cost recovery is warranted. 18
Q. How did the Company arrive at its recommended 19
test year pension cost recovery amount? 20
A. To arrive at its proposed test year pension 21
cost recovery amount, the Company considered several 22
factors, including its expected ongoing annual cash 23
contributions to the pension plan and the cost recovery 24
mechanism and balancing account approved by Commission 25
TATUM, DI 17 Idaho Power Company
Order No. 31003 issued in Case No. IPC-E-09-29. In recent 1
years, the Company has been contributing approximately $40 2
million annually to fund its pension plan. While the annual 3
minimum required funding level fluctuates, this annual 4
level of funding has represented a levelized or normal 5
level of required funding. The Company’s current rates 6
include recovery of approximately $17 million a year. 7
Annual differences between the $40 million in annual cash 8
contributions to the pension plan and the $17 million of 9
recovery through rates have been deferred as authorized by 10
Order No. 31003. Rather than request recovery of the full 11
$40 million of annual pension funding, as a rate mitigation 12
measure, the Company is proposing to increase the current 13
$17 million in annual pension cost recovery to 14
approximately $35 million, and to continue to defer any 15
differences between collection and plan contributions 16
through the pension balancing account. If interest rates 17
continue to stay at current elevated levels or higher, the 18
associated discount rates used to determine annual pension 19
funding requirements are more likely to drive required plan 20
contributions down. While not known at this time, the 21
Company is hopeful that the $35 million in annual pension 22
cost recovery may ultimately provide sufficient revenue to 23
cover the ongoing required cash contributions to the plan 24
while also serving to reduce the regulatory asset in the 25
TATUM, DI 18 Idaho Power Company
balancing account. 1
Q. What is the Company’s proposal regarding 2
deferred recovery of the 120 MW battery storage project to 3
be online in 2023? 4
A. As an additional rate increase mitigation 5
measure, the Company is proposing to delay recovery of the 6
revenue requirement associated with the 120 MW of battery 7
storage resources to be online in 2023, with interim 8
earnings support from the associated federal investment tax 9
credit (“ITC”) generated from the battery storage 10
resources. More specifically, the Company is requesting 11
authorization to 1) move to the Accumulated Deferred 12
Investment Tax Credits ("ADITC")/Revenue Sharing Mechanism 13
an additional amount of ITC equal to the incremental ITC 14
generated from the Company’s investment in the 2023 battery 15
storage projects, and 2) increase to the maximum allowed 16
annual accelerated amortization amount by a level of ADITC 17
equal to the actual revenue requirement of the battery 18
storage projects in any applicable year plus the current 19
annual $25 million cap authorized by Order No. 30978 issued 20
in Case No. IPC-E-09-30. 21
Q. Is the Company proposing to exclude the 120-MW 22
battery storage projects from rate base as part of this 23
proposal? 24
A. No. The Company is requesting a full prudence 25
TATUM, DI 19 Idaho Power Company
review of the 120-MW battery storage projects as part of 1
this case, with the goal of receiving Commission approval 2
to include the Idaho jurisdictional portion of the 3
investment in its Idaho rate base. As part of this rate 4
impact mitigation measure, the Company is proposing to 5
include in the final Idaho jurisdictional revenue 6
requirement a temporary credit adjustment equal to the 7
Idaho-jurisdictional share of the 120-MW battery revenue 8
requirement. This credit would remain in place until the 9
Company is authorized to recover the associated revenue 10
requirement in a future general rate case or other 11
applicable revenue requirement proceeding. 12
Q. Please provide an overview of the 13
ADITC/Revenue Sharing Mechanism. 14
A. Since 2009, the Company has been subject to an 15
ADITC/Revenue Sharing Mechanism that includes provisions 16
for the accelerated amortization of ADITC to help achieve a 17
minimum specified percent Idaho-jurisdiction return on 18
year-end equity (“Idaho ROE”), currently set at 9.4 19
percent. The mechanism also provides for the potential 20
sharing between Idaho Power and Idaho customers of Idaho-21
jurisdictional earnings in excess of a 10.0 percent Idaho 22
ROE. Under the current mechanism, the ADITC and sharing 23
thresholds are to be reset at a general rate case to align 24
the sharing threshold with the then-authorized ROE and the 25
TATUM, DI 20 Idaho Power Company
use of accelerated amortization of ADITC at 95 percent of 1
the authorized ROE. 2
Q. What is the expected dollar value of the ITC 3
generated by the 120-MW battery storage investment? 4
A. The Company expects the 120 MW of battery 5
storage projects will generate approximately $45 million of 6
new federal ITC based on an assumption that the ITC will be 7
equal to 30 percent of total project cost under Section 48 8
of the Internal Revenue Code. 9
Q. What is the annual revenue requirement 10
associated with the 120 MW battery storage projects? 11
A. The test year revenue requirement associated 12
with the 120 MW battery storage projects is $21,149,854. 13
When considering the approximately $45 million of new 14
federal ITC associated with the investment, the ITC 15
represents approximately two years of the annual revenue 16
requirements for the batteries. 17
Q. Under the Company’s proposal, what will happen 18
to the ITC generated from the 120-MW battery projects, if 19
they have not been amortized prior to the time the Company 20
is allowed to recover the cost of the batteries in customer 21
rates? 22
A. The Company proposes that the ITC remain 23
available for accelerated amortization under the provisions 24
of the ADITC/Revenue Sharing Mechanism until fully 25
TATUM, DI 21 Idaho Power Company
amortized - either on an accelerated basis or according to 1
the standard amortization schedule tied to the depreciable 2
life of the associated asset. Both maintain the Company’s 3
long-standing compliance with federal and state ITC 4
normalization rules. 5
Q. Does the $21,149,854 test year revenue 6
requirement include an offsetting annual benefit of the 7
amortization of associated ITC? 8
A. Yes. The $21,149,854 test year revenue 9
requirement includes the impacts of ITC using the standard 10
amortization schedule that ties to the depreciable life of 11
the associated asset. An ITC amortization benefit would 12
remain in future associated revenue requirement 13
calculations until the ITC are fully amortized. 14
Q. Aside from deferring the rate impact of the 15
battery projects, what other benefits will customers 16
receive? 17
A. Aside from deferring the rate impact of the 18
battery projects, customers will continue to receive the 19
benefits of the ITC for ratemaking purposes until the ITC 20
has been fully amortized as I previously described. As has 21
been the case since the ADITC/Revenue Sharing Mechanism was 22
first implemented, customer rates have continued to reflect 23
the offsetting benefit of ITC amortization and, as of 24
December 31, 2022, the Company has not utilized any of the 25
TATUM, DI 22 Idaho Power Company
currently available ADITC for accelerated amortization. In 1
this instance, customers are guaranteed to get the benefits 2
of service from the 120 MW of batteries at no cost in the 3
near-term, while preserving an opportunity to still benefit 4
from that ITC in future ratemaking proceedings. 5
IV. WITNESS LIST 6
Q. What was your level of involvement with the 7
preparation of the testimony and exhibits presented by the 8
other Company witnesses? 9
A. I discussed the content and preparation of 10
the witnesses’ testimony and exhibits with Ms. Connie 11
Aschenbrenner (Rate Design Senior Manager), Mr. Matthew 12
Larkin (Revenue Requirement Senior Manager), and Mr. 13
Donovan Walker (Lead Counsel), as well as Ms. Lisa 14
Nordstrom (Lead Counsel) and Ms. Megan Goicoechea Allen 15
(Corporate Counsel). 16
Q. Please provide an overview of the Company’s 17
general rate case filing. 18
A. The Company begins the presentation of its 19
case with Ms. Grow’s testimony, who provides a general 20
overview of the Company and addresses Idaho Power’s current 21
financial and operating situation and need for general rate 22
relief. My testimony is next and covers the regulatory 23
policy matters related to the development of the general 24
rate case. 25
TATUM, DI 23 Idaho Power Company
Mr. Eric Hackett, Projects and Design Senior 1
Manager, discusses the growth in the Company’s generation-2
related rate base since the completion of the Company’s 3
last general rate case, up to and including major projects 4
expected to be completed during the 2023 test year. He 5
presents the prudent nature of these investments, detailing 6
why they are needed to ensure Idaho Power’s generation 7
fleet is robust and well-positioned to provide continued 8
safe, reliable service to customers. Mr. Hackett is also 9
the witness who presents the costs associated with, and an 10
operation overview of, the 120-MW battery projects placed 11
into service in 2023. 12
Ms. Lindsay Barretto, 500 kV and Joint Projects 13
Senior Manager, discusses the prudent nature of investments 14
made at Bridger and Valmy since the Company’s last prudence 15
determinations before the Commission. 16
Mr. Mitch Colburn, Vice President of Planning, 17
Engineering and Construction, discusses investments the 18
Company has made in the electrical grid to ensure the 19
provision of safe, reliable service to customers. 20
Specifically, Mr. Colburn details Idaho Power’s recent 21
history of reliability and system performance that 22
demonstrates a thoughtful approach to grid construction and 23
maintenance. He also presents specific investments included 24
in the Company’s 2023 test year that demonstrate the 25
TATUM, DI 24 Idaho Power Company
Company’s prudent investment in the electrical grid at the 1
transmission and distribution levels. Finally, Mr. Colburn 2
reviews the Company’s wildfire mitigation efforts and 3
associated capital and O&M expenditures. 4
Mr. James “Bo” Hanchey, Vice President of Customer 5
Operations and Chief Safety Officer, describes the 6
Company’s Safety First culture and ongoing efforts to 7
enhance our customers’ overall experience with the Company. 8
Mr. Hanchey also describes the Company’s advancements in 9
energy efficiency as well as customer relations activities 10
and related technology upgrades. 11
Ms. Sarah Griffin, Vice President of Human 12
Resources, provides justification for the labor and total 13
compensation costs included in the Company’s test year. Ms. 14
Griffin also describes the Company’s overall compensation 15
philosophy and explains why the level of compensation 16
requested in this case is necessary to provide safe, 17
reliable, affordable electricity to customers. As part of 18
this discussion, she also provides the justification for 19
the requested increase in cost recovery related to the 20
Company’s pension plan, which serves as a key component of 21
Idaho Power’s overall compensation package. 22
The next witness is Mr. Adrien McKenzie, who has 23
been retained by the Company as its ROE expert. Mr. 24
McKenzie discusses risk factors relevant to Idaho Power, 25
TATUM, DI 25 Idaho Power Company
performs calculations of ROE appropriate for the Company 1
using standard financial methodologies, and recommends a 2
reasonable ROE range appropriate for Idaho Power. In this 3
proceeding, Mr. McKenzie’s ROE range is from 10.10 to 11.10 4
percent. 5
Mr. Brian Buckham, Idaho Power Company’s Senior Vice 6
President and Chief Financial Officer, builds on Mr. 7
McKenzie’s recommendations by more specifically addressing 8
the relevant risk factors impacting the Company. Mr. 9
Buckham selects a 10.40 percent ROE point estimate as the 10
appropriate cost of equity, supports the cost of Idaho 11
Power’s long-term debt, and includes the long-term debt and 12
the 10.40 percent ROE in the test year capital structure to 13
derive the Company’s proposed overall rate of return. 14
Ms. Paula Jeppsen, the Company’s Forecasting and 15
Planning Director, next testifies to the actual 2022 16
financial results with standard ratemaking adjustments. Ms. 17
Jeppsen describes the development and application of the 18
methodologies used to prepare the 2022 base financial 19
information and the adjustments to those data associated 20
with deductions to certain expenses not allowed in rates, 21
certain adjustments to expenses and rate base, and other 22
adjustments to revenues, expenses, and rate base related 23
primarily to past Commission orders. 24
Mr. Matthew Larkin, Revenue Requirement Senior 25
TATUM, DI 26 Idaho Power Company
Manager, describes how the Company utilized the 2022 1
financial data as presented by Ms. Jeppsen as a starting 2
point from which he made conservative adjustments to derive 3
similar data corresponding to the 2023 test year. Mr. 4
Larkin prepared an exhibit that details the method and 5
rationale for each adjustment he utilized in developing the 6
2023 test year data. Once he determined the 2023 test year 7
system-level data, Mr. Larkin supervised the preparation of 8
the jurisdictional separation study utilized to determine 9
the Idaho jurisdictional revenue requirement. 10
Ms. Jessica Brady, Regulatory Analyst, provides the 11
normalized net power supply expenses for the test year and 12
addresses the requisite changes to the Company’s PCA as a 13
result of changing the normalized net power supply expenses 14
in Idaho Power Company’s base rates. 15
Ms. Kelley Noe, Regulatory Consultant, incorporates 16
Ms. Jeppsen’s financial data, Mr. Larkin’s test year 17
adjustments, Mr. Buckham’s overall rate of return 18
recommendation, and Ms. Brady’s normalized net power supply 19
expenses, along with other necessary inputs, and prepares 20
the jurisdictional separation study (“JSS”). The JSS, as 21
its name states, separates system values for rate base, 22
revenues, and expenses for each state jurisdiction through 23
an assignment and allocation process that is described in 24
detail in Ms. Noe’s testimony. One result of the JSS is the 25
TATUM, DI 27 Idaho Power Company
Idaho retail jurisdictional revenue requirement, which is 1
the Company’s best representation of its expected annual 2
cost to serve its Idaho retail customers. The 2023 Idaho 3
jurisdictional revenue requirement is $1,404,314,821. In 4
order to obtain this amount, Idaho’s annual retail revenues 5
will need to increase by $111,304,981 or 8.61 percent. 6
Ms. Connie Aschenbrenner, Rate Design Senior 7
Manager, describes the Company’s approach to rate design 8
strategy as well as the policy basis for the rate design 9
proposals being made in this case. Ms. Aschenbrenner also 10
presents an overview of the Company’s approach to 11
developing pricing for its on-site generation customers, 12
specifically considering interdependencies between this 13
case and Case No. IPC-E-23-14, which is currently pending 14
before the Commission. 15
Mr. Pawel Goralski, Regulatory Consultant, uses the 16
Idaho retail jurisdictional output from the JSS as 17
developed by Ms. Noe and further separates costs by 18
customer class and special contract in preparing the 19
Company’s class cost-of-service study (“CCOS”). The study 20
prepared by Mr. Goralski in this case presents an approach 21
most similar to that used by the Company in its last 22
general rate case, with certain modifications and 23
additions. In the Company’s 2008 general rate case, IPC-E-24
08-10, the Commission approved a cost-of-service 25
TATUM, DI 28 Idaho Power Company
methodology termed “3CP/12CP” and the Company subsequently 1
used a similar methodology in its 2011 general rate case, 2
IPC-E-11-08, which was ultimately settled without a 3
Commission decision regarding the filed CCOS. Mr. Goralski 4
used that same CCOS method as the starting point for his 5
CCOS in this case and then applied modifications to the 6
seasonal definition for peak capacity allocation, the 7
classification of baseload resources between demand and 8
energy, and other changes described in his testimony. Mr. 9
Goralski recommends that his CCOS be used as the 10
appropriate starting point for rate spread (the process of 11
spreading the Idaho jurisdictional revenue requirement to 12
the customer classes and special contract customers) and 13
rate design (the ultimate calculation of rates for 14
customers). Mr. Goralski also presents the Company’s rate 15
recommendations for its special contract customers and 16
Schedule 20, Speculative High-Density Load as well as the 17
proposed Fixed Cost Adjustment rates and the corresponding 18
modifications to Schedule 54. 19
Mr. Grant Anderson, Regulatory Consultant, presents 20
the Company’s proposed rate design and resulting prices for 21
the residential classes, including standard service 22
(Schedule 1), time-of-use (Schedule 5), and residential on-23
site generation (Schedule 6) and explains the Company’s 24
Residential Price Modernization Plan. Mr. Anderson also 25
TATUM, DI 29 Idaho Power Company
presents the rate design proposals for Small General 1
Service On-Site Generation (Schedule 8), Large General 2
Service – Primary and Transmission (Schedule 9P/T) and 3
Large Power customers (Schedule 19). 4
Mr. Zack Thompson, Regulatory Analyst, presents the 5
rate design proposals for Small General Service (Schedule 6
7), Large General Service – Secondary (Schedule 9S), 7
Agricultural Irrigation Service (Schedule 24), Dusk to Dawn 8
Customer Lighting (Schedule 15), Street Lighting Service 9
(Schedule 41), Traffic Control Signal Lighting Service 10
(Schedule 42), and Non-Metered General Service (Schedule 11
40). 12
Finally, Riley Maloney describes the recommendation 13
for the Company’s Standby Service schedules (Schedules 31 14
and 45) and Alternate Distribution Service schedule 15
(Schedule 46). Mr. Maloney also presents several proposed 16
modifications to the Company’s tariff. 17
V. RATE SPREAD AND RATE DESIGN 18
Q. What has been Idaho Power’s policy with regard 19
to rate spread and rate design proposals? 20
A. Idaho Power has consistently advocated for the 21
principle that rate spread among the customer classes, and 22
for component pricing within the customer classes, should 23
be primarily cost-based. Accordingly, the Company’s 24
ratemaking proposals have traditionally advocated movement 25
TATUM, DI 30 Idaho Power Company
toward cost-of-service results that assign costs to those 1
customers that cause the Company to incur the costs. The 2
Company is also committed to providing customers cost-based 3
price signals, which encourage the wise and efficient use 4
of energy. As such, I have directed Ms. Aschenbrenner to 5
design cost-based rate proposals that also encourage 6
increased energy efficiency among the Company’s Residential 7
Service, Large General Service, Large Power Service and 8
Irrigation customer groups. 9
Q. Do the Company’s proposals in this case 10
strictly adhere to that objective? 11
A. No. The Company realizes that there are often 12
other ratemaking objectives, such as rate stability, 13
ability to pay, and mitigating rate shock, that the 14
Commission may consider in making its determination. 15
However, the Company believes that the best starting point 16
for Commission deliberations is an economic one. 17
Nevertheless, because some ratemaking situations may cause 18
abrupt change, Idaho Power has traditionally proposed some 19
limits to the movement toward cost-of-service. The 20
specifics of the Company’s proposed rate spread and an 21
exhibit delineating the target revenue requirement for each 22
customer class are contained in Mr. Goralski’s testimony. 23
Q. What guidance did you provide Mr. Goralski 24
regarding cost-of-service constraints applied to the rate 25
TATUM, DI 31 Idaho Power Company
spread ultimately recommended? 1
A. First, I discussed the CCOS prepared for this 2
case with Mr. Goralski and agreed that his recommended CCOS 3
methodology represented the preferred starting point in 4
this proceeding to develop the recommended rate spread. 5
However, this method when applied without constraints, does 6
show a larger impact to a number of customer classes 7
(relative to the overall average increase), most notably 8
Agricultural Irrigation, Schedule 24. Given recent rate 9
pressures and the somewhat subjective nature of cost 10
allocation and year-to-year cost components, I asked Mr. 11
Goralski to run several rate mitigation scenarios to look 12
at the impacts of constraining the rate increase at 13
different levels. 14
After this review, the Company chose to impose a cap 15
of one and a half times the average revenue change for any 16
customer class or special contract customer exceeding the 17
overall average increase. This level allowed for a 18
reasonable level of revenue movement, while not 19
dramatically impacting the remaining classes that had to 20
make up the shortfall. 21
Q. How has Idaho Power addressed the cost-based 22
objective in its rate design proposals? 23
A. This objective has been met by the 24
implementation of seasonal rates for all metered service 25
TATUM, DI 32 Idaho Power Company
schedules, and the implementation of rate structures that 1
reflect a greater emphasis on the demand and customer 2
components. The Company also proposes the continuation of 3
mandatory time-of-use pricing for Large Commercial 4
customers taking service at primary and transmission 5
voltages and all Large Power Service customers. In 6
addition, this objective has been met by offering optional 7
time-of-use pricing for Residential and Large General 8
service customers taking service at the secondary voltage 9
level. 10
Q. Please summarize the Company’s requested Price 11
Modernization Plan. 12
A. I directed Ms. Aschenbrenner to evaluate and 13
recommend a proposal that would move fixed cost collection 14
from volumetric rates into fixed charges, while mitigating 15
the bill impact to customers. In this case, the Company is 16
proposing the Commission authorize Idaho Power to implement 17
revenue neutral rate changes on January 1, 2025, and 18
January 1, 2026, to achieve this goal. The proposed three-19
year Price Modernization Plan appropriately mitigates 20
customer bill impacts while reducing reliance on the FCA. 21
VI. CONCLUSION 22
Q. Please summarize Idaho Power’s requested 23
revenue increase this case? 24
A. The Company is requesting rate relief of 25
TATUM, DI 33 Idaho Power Company
approximately $111.3 million, which is net of a 1
corresponding proposed PCA decrease of $173.4 million and a 2
reduction to annual Rider collection of $3.5 million. If 3
approved, this request would result in an overall increase 4
to adjusted base revenue of 8.61 percent effective January 5
1, 2024. The Company’s request is based on a proposed rate 6
of return of 7.702 percent, with a capital structure 7
comprised of 51 percent equity and 49 percent debt, a 4.895 8
percent cost of debt, and a 10.40 percent ROE. This request 9
was developed using a test year of 12 months ending 10
December 31, 2023. 11
Q. Will you please summarize the Company’s other 12
requests for specific regulatory treatment and/or necessary 13
accounting authority proposed in this case? 14
A. In addition to approval of the base revenue 15
increase presented in this case and each of the affected 16
tariff schedules, the Company requests the Commission issue 17
an order that includes the following: 18
1. Approval of a revised Schedule 55, Power Cost 19
Adjustment, reflecting the transfer of certain 20
base level NPSE from the PCA to base rates. 21
2. Approval of a revised Schedule 91, Energy 22
Efficiency Rider, reflecting the transfer of 23
DSM labor-related cost collection from the 24
Rider into base rates. 25
TATUM, DI 34 Idaho Power Company
3. Approval of a revised Schedule 54, Fixed Cost 1
Adjustment, reflecting the modifications 2
necessary to support the Company’s proposed 3
rate designs. 4
4. Authorization of the continued deferral of 5
incremental vegetation management and insurance 6
costs in 2024 and beyond as measured from a new 7
base level of costs established in this case. 8
5. In association with the rate increase 9
mitigation measure proposed in this case, 10
authorization to 1) move to the ADITC/Revenue 11
Sharing Mechanism an additional amount of ITC 12
equal to the incremental ITC generated from the 13
Company’s investment in the 2023 battery 14
storage projects and 2) increase the maximum 15
allowed annual accelerated amortization amount 16
by a level of ITC equal to the actual revenue 17
requirement of the battery storage projects in 18
any applicable year plus the current $25 19
million cap. 20
6. Authorization to defer and amortize annual 21
differences between certain periodic 22
maintenance costs at the Langley Gulch and 23
Bennett Mountain natural gas-fired power plants 24
(as described in Mr. Larkin’s testimony). 25
TATUM, DI 35 Idaho Power Company
7. Approval of the Company’s request for its 1
proposed Residential Price Modernization Plan. 2
Q. Is it your opinion that the granting of the 3
rate relief proposed by the Company is in the public 4
interest? 5
A. Yes. The proposed rates will allow Idaho Power 6
to continue providing safe, reliable service at reasonable 7
rates while maintaining its financial health. 8
Q. Does this conclude your testimony? 9
A. Yes, it does. 10
// 11
//12
TATUM, DI 36 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 Regulatory 5
Affairs. 6
2. On behalf of Idaho Power, I present this 7
pre-filed direct testimony. 8
3. To the best of my knowledge, my pre-filed 9
direct testimony is true and accurate. 10
I hereby declare that the above statement is true to 11
the best of my knowledge and belief, and that I understand 12
it is made for use as evidence before the Idaho Public 13
Utilities Commission and is subject to penalty for perjury. 14
SIGNED this 1st day of June 2023, at Boise, Idaho. 15
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Signed: ___________________ 17 Timothy E. Tatum 18
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