20250530Direct Tatum.pdf

RECEIVED
May 30, 2025
IDAHO PUBLIC
UTILITIES COMMISSION
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR ) CASE NO. IPC-E-25-16
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC SERVICE )
IN THE STATE OF IDAHO AND )
AUTHORITY TO IMPLEMENT CERTAIN )
MEASURES TO MITIGATE THE IMPACT )
OF REGULATORY LAG. )
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
TIMOTHY E . TATUM

1 Q. Please state your name, business address, and
2 present position with Idaho Power Company ("Idaho Power" or
3 "Company") .
4 A. My name is Timothy E . Tatum. My business
5 address is 1221 West Idaho Street, Boise, Idaho 83702 . I am
6 employed by Idaho Power as Vice President of Regulatory
7 Affairs .
8 Q. Please describe your educational background.
9 A. I earned a Bachelor of Business Administration
10 degree in Economics and a Master of Business Administration
11 degree from Boise State University. I have also attended
12 electric utility ratemaking courses, including "Practical
13 Skills for The Changing Electric Industry, " a course
14 offered through the New Mexico State University' s Center
15 for Public Utilities, "Introduction to Rate Design and Cost
16 of Service Concepts and Techniques" presented by Electric
17 Utilities Consultants, Inc. , and Edison Electric
18 Institute' s "Electric Rates Advanced Course. " In 2012, I
19 attended the Utility Executive Course ("UEC") at the
20 University of Idaho .
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 customer phone calls, customer-related transactions, and
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Idaho Power Company

1 general customer account maintenance in the areas of
2 billing and metering.
3 In June of 2003, I began working as an Economic
4 Analyst on the Energy Efficiency Team. As an Economic
5 Analyst, I was responsible for ensuring that the demand-
6 side management ("DSM") expenses were accounted for
7 properly, preparing and reporting DSM program costs and
8 activities to management and various external stakeholders,
9 conducting cost-benefit analyses of DSM programs, and
10 providing DSM analysis support for the Company' s Integrated
11 Resource Plan.
12 In August 2004, I accepted a position as a
13 Regulatory Analyst and in August of 2006, I was promoted to
14 Senior Regulatory Analyst . As a Senior Regulatory Analyst,
15 my responsibilities included the development of complex
16 financial studies to determine revenue recovery and pricing
17 strategies, including preparation of the Company' s cost-of-
18 service studies .
19 In September of 2008, I was promoted to Manager of
20 Cost of Service, and in 2011, I was promoted to Senior
21 Manager of Cost of Service and oversaw the Company' s cost-
22 of-service activities, such as power supply modeling,
23 jurisdictional separation studies, class cost-of-service
24 studies, and marginal cost studies .
25
TATUM, DI 2
Idaho Power Company

1 In March 2016, I was promoted to my current role of
2 Vice President of Regulatory Affairs . As Vice President of
3 Regulatory Affairs, I am responsible for the overall
4 coordination and direction of the Regulatory Affairs
5 Department, including development of jurisdictional revenue
6 requirements and class cost-of-service studies, preparation
7 of rate design analyses, and administration of tariffs and
8 customer contracts .
9 I . CASE OVERVIEW
10 Q. What role did you play in the preparation of
11 the General Rate Case ("GRC") ?
12 A. My role in the preparation of the GRC was to
13 oversee, manage, and coordinate the filing and to make the
14 policy decisions related to regulatory matters in
15 consultation with Ms . Lisa Grow, our Company' s President
16 and Chief Executive Officer, along with other senior
17 officers within Idaho Power.
18 Q. What is the purpose of your testimony?
19 A. The purpose of my testimony is to present the
20 Company' s case in support of the requested rate relief and
21 to inform the Idaho Public Utilities Commission
22 ("Commission") that the Company is currently in a period of
23 unprecedented capital investment necessary to maintain,
24 improve, and protect the electrical system, and as a
25 result, the application of a historical test year will not
TATUM, DI 3
Idaho Power Company

1 provide Idaho Power a reasonable opportunity to earn its
2 authorized rate of return without other supportive rate
3 mechanisms .
4 Idaho Power continues to make considerable ongoing
5 investments in response to rapid customer and load growth,
6 as well as aging infrastructure. The Company plans to
7 invest approximately $1 billion in new infrastructure
8 during 2025 with associated incremental
9 depreciation/amortization and interest expense of
10 approximately $52 . 5 million over 2024 levels . The 2025
11 incremental depreciation/amortization and interest expense
12 alone will exceed the total amount of the rate increase
13 granted by the Commission in the Company' s 2024 Limited
14 Scope Rate Case, Case No . IPC-E-24-07 ("2024 Limited Scope
15 Rate Case") , that became effective January 1, 2025, which
16 was based on a 2024 historical test year.
17 The Company also continues to grow and enhance its
18 wildfire mitigation efforts at an increasing cost. At the
19 same time, Idaho Power continues to experience increases in
20 its insurance costs driven by wildfire and other weather-
21 related events across the country.
22 The application of a historical test year in the
23 current rising cost environment has resulted in
24 unsustainable regulatory lag impacting the Company' s
25 ability to achieve reasonable rates of return and maintain
TATUM, DI 4
Idaho Power Company

1 sufficient credit metrics between rate cases . As a result,
2 in addition to the general rate relief requested in this
3 case, Idaho Power also requests approval to implement an
4 electric plant depreciation/amortization and interest
5 expense on long-term debt ("Depreciation and Interest
6 Expense") tracking mechanism and other earnings support
7 measures to help address some of the harmful regulatory lag
8 caused by using a historical test year.
9 Q. What is Idaho Power' s requested revenue
10 increase in this case?
11 A. The Company is requesting rate relief of
12 approximately $199 . 1 million, which is net of a
13 corresponding proposed Power Cost Adjustment ("PCA")
14 decrease of $46 . 8 million. If approved, this request would
15 result in an overall increase to Idaho jurisdictional
16 retail revenue of 13 . 09 percent effective January 1, 2026 .
17 The Company' s request is based on a proposed rate of return
18 of 7 . 818 percent, with a capital structure comprised of 51
19 percent equity and 49 percent debt, a 5 . 132 percent cost of
20 debt, and a 10 . 40 percent return on equity ("ROE") .
21 Q. What is the Company' s test year?
22 A. The test year is the 12 months ending December
23 31, 2025 . I will refer to this test period as a historical
24 test year throughout my testimony because the requested
25 rate effective period begins on January 1, 2026, and if
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Idaho Power Company

1 approved, the requested rates would be based on a 2025
2 revenue requirement.
3 Q. Why is Idaho Power requesting a corresponding
4 PCA decrease of $46 . 8 million in this case?
5 A. Idaho Power' s current Idaho base rates collect
6 approximately $484 . 9 million annually to fund normalized or
7 "base level" net power supply expense ("NPSE") . This level
8 of NPSE collection, authorized by Order No. 36042 in Case
9 No . IPC-E-23-11, became effective January 1, 2024, based on
10 a 2023 test year. Currently, incremental NPSE over the base
11 level NPSE established using a 2023 test year are collected
12 annually through the PCA forecast component. Because the
13 Company' s requested Idaho-jurisdictional revenue
14 requirement in this case reflects updated base level NPSE
15 based on the 2025 test year, the Company is requesting a
16 corresponding decrease in annual PCA collection of $46 . 8
17 million to ensure customers do not pay twice for the same
18 NPSE .
19 Q. What are the specific regulatory support
20 mechanisms the Company is requesting the Commission approve
21 in this case?
22 A. In addition to the rate relief requested in
23 this case, the Company is also seeking authorization to 1)
24 establish a tracking mechanism for incremental Depreciation
25 and Interest Expense effective January 1, 2026, 2) continue
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Idaho Power Company

1 deferring incremental wildfire mitigation and insurance
2 costs from a base level of cost recovery established in
3 this case, and 3) designate additional accumulated deferred
4 investment tax credits ("ADITC") as eligible for
5 accelerated amortization under the terms of the currently
6 approved ADITC/Revenue Sharing Mechanism', with the addition
7 of a $75 million annual amortization cap. I will describe
8 each of these requests in greater detail later in my
9 testimony.
10 II . TEST YEAR
11 Q. How did the Company prepare its test year in
12 this proceeding?
13 A. Idaho Power prepared its 2025 test year in
14 this case using the same general methodology used in the
15 Company' s last three full general rate cases, Case No. IPC-
16 E-08-10 ("2008 GRC") , Case No. IPC-E-11-08 ("2011 GRC") and
17 Case No . IPC-E-23-11 ("2023 GRC") . The Company' s test year
18 methodology starts with actual 12-month financial results
19 adjusted to include typical and traditional ratemaking
20 adjustments . The adjusted 2024 actual financial information
21 was then further adjusted to reflect 2025 results through
22 the use of known and measurable adjustments appropriate for
23 the particular revenue, expense, or asset classification.
1 The current terms of the ADITC/Revenue Sharing mechanism are detailed
in the Settlement Stipulation approved by Final Order No. 36042 in Case
No. IPC-E-23-11.
TATUM, DI 7
Idaho Power Company

1 Q. What attributes should be considered when
2 selecting a test year?
3 A. In practice, in every rate case, a test year
4 must be selected. Whether the test year selected is
5 historical, future, or a hybrid approach, the most
6 important attribute of the selected test year should be
7 that it accurately reflects the best expectation of the
8 cost of service when rates become effective.
9 Regardless of which test year is adopted, the
10 ratemaking process is inherently prospective and requires
11 reliance upon projections and/or known and measurable
12 adjustments . Whether the test year is completely historical
13 or based totally on future results, the ratemaking process
14 requires an informed determination of what conditions will
15 exist in the future. As of the date of filing, Idaho Power
16 has used its best financial and operational information to
17 construct its test year.
18 Ultimately, Idaho Power must apply a test year
19 approach that is both timely and reflective of the costs
20 that the Company can reasonably expect to incur going
21 forward. A historical test year is by definition not timely
22 and may not be a reflection of costs going forward.
23 Similarly, a test year based on a reasonable forecast may
24 be more indicative of the costs the Company will be
25 experiencing during the time rates are in place, thereby
TATUM, DI 8
Idaho Power Company

1 reducing the effects of "regulatory lag" .
2 Utility commissions and policy makers throughout the
3 country are increasingly recognizing that in times of high
4 inflation and heavy construction, future or forecast test
5 years are necessary to allow utilities a reasonable
6 opportunity to earn their authorized rate of return.
7 According to Edison Electric Institute, approximately
8 thirty jurisdictions allow for the use of a forward test
9 year and fully forecasted test years are widely used by the
10 Federal Energy Regulatory Commission and in Canada.'
11 Utilities that operate in a period of rapid expansion and
12 rate base growth will chronically under-earn if test years
13 are historical in nature and fail to synchronize the
14 matching of expenses and revenues . This is the situation
15 that Idaho Power currently faces .
16 Q. If the Company is unlikely to earn its
17 allowed rate of return under the use of a historical test
18 year in the near-term, why is the Company proposing the use
19 of a historical test year in this case?
20 A. In its Final Order3 in the Company' s 2024
21 Limited Scope Rate Case, the Commission stated the
' Innovative Regulatory Tools for Addressing an Increasingly Complex
Energy Landscape: 2023 Update, Prepared by: Pacific Economics Group
Research, LLC for Edison Electric Institute, February 2024.
3 Order No. 36438 page 5.
TATUM, DI 9
Idaho Power Company

1 following regarding its willingness to accept forecast
2 information:
3 With respect to the test year, while the Commission
4 does not adopt the August 31, 2024, cut-off
5 deadline recommended by Staff in this specific case
6 and based upon these specific circumstances, this
7 is not an invitation for public utilities to
8 present extensive forecasted data in future
9 proceedings, nor is it an indication of the
10 Commission' s willingness to accept forecasted data
11 in future proceedings . The Commission expects that
12 when any public utility appears before the
13 Commission in a recovery proceeding, that public
14 utility will present known and measurable data, for
15 used and useful projects, with sufficient time for
16 all parties to review that data and formulate any
17 necessary testimony.
18 The Company has interpreted this statement to indicate the
19 Commission opposes a forecast test year and has prepared a
20 historical test year with known and measurable adjustments
21 to comply with that understanding. However, as I will
22 explain later in my testimony, the Company is proposing a
23 number of methods of addressing regulatory lag resulting
24 from the use of a historical test year as part of this
25 case .
26 Q. How did the Company arrive at its recommended
27 ROE of 10 . 4 percent?
28 A. After discussions with Mr. Brian Buckham,
29 Senior Vice President, Chief Financial Officer, and
30 Treasurer, the Company decided to apply as a customer rate
31 mitigation measure an ROE that is at the lower end of the
32 range provided by our outside ROE expert. As explained in
TATUM, DI 10
Idaho Power Company

1 his testimony, Mr. Buckham believes this recommendation
2 represents the ROE necessary to not weaken the Company' s
3 ability to attract capital at favorable and customer-
4 beneficial rates in the current volatile financial markets,
5 particularly given the high volume of the Company' s and the
6 industry' s capital needs for the foreseeable future.
7 Q. Did the Company take any steps to minimize the
8 level of operations and maintenance expense ("O&M")
9 included in the test year, and if so, what were the
10 results?
11 A. Yes . The Company chose to hold test year non-
12 labor 0&M expense to the 2024 actual level, with the
13 exception of a limited number of known and measurable
14 adjustments . As discussed by Ms . Grow in her testimony, the
15 Company has a strong track record of managing its 0&M
16 expenses, and as a result, excluding non-deferred 2022-2024
17 wildfire mitigation costs, has achieved a compound annual
18 0&M growth rate of only 1 . 5 percent between 2012 and 2024 .
19 Q. What is the Company' s recommendation regarding
20 the recovery mechanisms for the North Valmy Power Plant
21 ("Valmy") and Jim Bridger Power Plant ("Bridger") ?
22 A. Idaho Power is requesting authorization to
23 update rate recovery associated with both the Valmy and
24 Bridger mechanisms as part of this case to reflect current
25 capital and 0&M expectations, and to true-up variances
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Idaho Power Company

1 between prior forecasts and actual costs . This request is
2 discussed in greater detail by Mr. Matthew T. Larkin,
3 Revenue Requirement Senior Manager, in his testimony.
4 Q. What is the Company' s recommendation regarding
5 the test year level of wildfire mitigation costs?
6 A. Idaho Power has included its expectation of
7 2025 wildfire mitigation costs based on applying known and
8 measurable adjustments to 2024 actual wildfire mitigation
9 costs . Further, the Company is requesting amortization into
10 rates of deferred wildfire mitigation costs through year-
11 end 2025 over a seven-year amortization period.
12 III . Regulatory Lag
13 Q. Please define your use of the term
14 regulatory lag.
15 A. I define regulatory lag as the difference
16 between the time when costs or benefits are realized by a
17 utility and the time when rates are implemented to reflect
18 those cost or benefits . The impact of regulatory lag is
19 dependent upon the situation and can either be financially
20 beneficial or harmful to a utility. For the foreseeable
21 future, the negative effects of regulatory lag will be
22 particularly pronounced for Idaho Power because the Company
23 is currently experiencing an unprecedented level of load
24 growth and a once in multiple generations level of capital
TATUM, DI 12
Idaho Power Company

1 spend necessary to provide safe, reliable service to its
2 customers .
3 Q. Why is regulatory lag such a critical issue
4 to Idaho Power at this time?
5 A. During periods of escalating costs where
6 marginal costs are higher than average costs, new rates are
7 already inadequate by the time they go into place. If this
8 situation continues for a prolonged period of time, the
9 Company will be denied a reasonable opportunity to earn its
10 authorized rate of return. The effects of regulatory lag
11 are particularly pronounced in periods where the Company is
12 engaged in capital-intensive projects and where interest
13 rates to finance capital projects are rising.
14 Q. Is regulatory lag always harmful to a
15 utility?
16 A. No . The impact of regulatory lag is
17 dependent upon the situation - if overall revenue growth is
18 keeping pace with cost escalation, and the Company is not
19 engaged in capital-intensive projects and procuring debt
20 and equity financing for those projects, then the Company
21 is not typically harmed by regulatory lag. Unfortunately,
22 Idaho Power is not in that situation currently, and based
23 on its projected load growth and capital plans will not
24 likely be for the foreseeable future.
25
TATUM, DI 13
Idaho Power Company

1 Q. What actions has Idaho Power taken in prior
2 general rate cases to address regulatory lag?
3 A. In both 2003 and 2005, Idaho Power filed for
4 general rate relief using test years that combined six
5 months of actual information with six months of forecast
6 information to reduce regulatory lag as compared to a fully
7 historical year. This approach is commonly referred to as
8 a "split test year. " Subsequently, the 2007 General Rate
9 Case, Case No . IPC-E-07-08 ("2007 GRC") was filed as a full
10 12-month forecasted test year.
11 Q. What was the resolution of the test year
12 issue in the 2007 General Rate Case?
13 A. The Company proposed a 2007 test year based
14 upon fully forecasted data, while Commission Staff
15 ("Staff") and others proposed a historical test year with
16 adjustments . The issue was not definitively resolved in
17 the 2007 GRC. However, the parties to the case did reach a
18 settlement and signed a Stipulation that addressed the test
19 year issue in a workshop.4 The Stipulation was ultimately
20 approved by the Commission in Order No. 30508 .
4 Case No. IPC-E-07-08, Motion for Approval of Stipulation, Stipulation
at 6 (c) (filed Jan. 3, 2008) .
TATUM, DI 14
Idaho Power Company

1 Q. Did the Company prepare its test year in the
2 subsequent rate case consistent with input received in the
3 workshop?
4 A. Yes, it did. For its 2008 GRC, the Company
5 started with actual 2007 results adjusted for typical and
6 traditional ratemaking adjustments and then adjusted the
7 data to 2008 levels based upon a number of methodologies
8 appropriate for each of the revenue, expense, or asset
9 classifications .
10 Q. In the 2008 GRC, did Staff support the use
11 of a test year with forecast plant amounts with certain
12 annualizing adjustments?
13 A. Yes . On page 11 of Staff witness Randy
14 Lobb' s direct testimony he stated the following:
15 Staff also supports the inclusion of major
16 plant additions (in excess of $2 million)
17 expected to be completed prior to December
18 31, 2008 and annualizing such plant as if
19 it were in service for the entire year.
20
21 Q. How did the 2008 GRC test year approach
22 address the past concerns raised by the Company, the
23 Commission Staff, and other parties to the Stipulation?
24 A. The Company' s proposed 2008 test year
25 utilized a 2007 foundation of actual financial information.
26 One primary concern expressed by the Commission Staff
27 regarding the Company' s test year in the 2007 GRC was that
28 there was no actual auditable information to review and
TATUM, DI 15
Idaho Power Company

1 there was discomfort in reviewing only forecasted data and
2 methods . The Company' s approach presented in the 2008 GRC
3 provided an actual auditable financial base for review,
4 while at the same time adjusting the historic financial
5 information into a more current time period. The Commission
6 ultimately approved the Company' s test year rate base
7 methodology used in the 2008 GRC, including annualizing
8 adjustments to plant additions over $2 million, in its
9 Order No 30722 .
10 In the Company' s 2011 GRC and its 2023 GRC, Idaho
11 Power applied a test year method that generally aligned
12 with the method applied in the 2008 GRC. Both of those
13 cases settled without agreement on the specific test year
14 methodology.
15 Finally, in the Company' s 2024 Limited Scope Rate
16 Case, the Company prepared its proposed incremental rate
17 base using a period-end rate base methodology. As I
18 mentioned earlier in my testimony, in its Final Order in
19 that case, the Commission utilized a historical test year
20 with rate base calculated under a historical plant
21 averaging approach with known and measurable adjustments .
22 IV. Regulatory Lag Mitigation Proposals
23 Q. Please summarize the Company' s recommendations
24 regarding necessary measures to address regulatory lag that
25 results from the use of a historical test year in today' s
TATUM, DI 16
Idaho Power Company

1 increasing cost environment .
2 A. In addition to the rate relief requested in
3 this case, the Company is also seeking authorization to 1)
4 establish a tracking mechanism for incremental Depreciation
5 and Interest Expense effective January 1, 2026, 2) continue
6 deferring incremental wildfire mitigation and insurance
7 costs from a base level of cost recovery established in
8 this case, and 3) designate additional ADITC as eligible
9 for accelerated amortization under the terms of the
10 currently approved ADITC/Revenue Sharing Mechanism, with
11 the addition of a $75 million annual amortization cap.
12 Q. Will you please provide an overview of the
13 Company' s proposed mechanism for tracking incremental
14 Depreciation and Interest Expense?
15 A. Idaho Power proposes to implement an electric
16 plant Depreciation and Interest Expense tracking mechanism
17 that, if approved, would measure the difference between
18 actual Depreciation and Interest Expense and a sales-
19 adjusted baseline level of Depreciation and Interest
20 Expense on a calendar-year basis effective January 1, 2026 .
21 This proposed tracking mechanism would include both
22 forecast and true-up components, with annual base rate
23 adjustments effective each June 1 through May 31 .
24 Q. How will the proposed mechanism be
25 administered?
TATUM, DI 17
Idaho Power Company

1 A. The base level of Depreciation and Interest
2 Expense from which variances will be tracked will be
3 calculated by multiplying the class-specific dollar per
4 kilowatt-hour ("kWh") rate of Depreciation and Interest
5 Expense embedded in base rates, as established in a GRC or
6 other applicable ratemaking proceeding where Depreciation
7 and Interest Expense are addressed, by actual class-
8 specific Idaho-jurisdictional sales . Based on the
9 Depreciation and Interest Expense included in this case, a
10 base level of $324, 559, 987 would be used to calculate base
11 level Depreciation and Interest Expense from which future
12 variances would be tracked. The derivation of the base
13 level Depreciation and Interest Expense included in this
14 case and the development of the class-specific dollar per
15 kWh rate of Depreciation and Interest Expense embedded in
16 base rates are included on Exhibit No. 1 .
17 Forecast and actual system Depreciation and Interest
18 Expense will be apportioned to the Company' s Idaho
19 jurisdiction, and subsequently to each customer class, in
20 the same proportions that those cost categories were
21 assigned jurisdictionally, and by class, in the general
22 rate case or revenue requirement proceeding that
23 established the cost baseline. Depreciation and interest
24 expense related to the Valmy and Bridger levelized revenue
25 requirement calculations would not be included in this
TATUM, DI 18
Idaho Power Company

1 proposed tracking mechanism.
2 The Company will determine forecast Depreciation and
3 Interest Expense by applying the applicable currently
4 approved depreciation rates and weighted average cost of
5 debt to a forecast of total electric plant which includes
6 additions and retirements for each calendar-year. Actual
7 depreciation/amortization expense will be what was recorded
8 for the applicable calendar year. Interest expense will be
9 determined by applying the approved weighted average cost
10 of long-term debt to actual plant balances for each
11 calendar year.
12 The amount of Depreciation and Interest Expense
13 credited or charged to customers will be calculated by
14 taking the difference between forecasted Idaho-
15 jurisdictional Depreciation and Interest Expense and base
16 level Depreciation and Interest Expense during each
17 calendar-year on a class-specific basis . True-up
18 adjustments between forecasted and actual Depreciation and
19 Interest Expense will be included in the following calendar
20 year mechanism filing.
21 Q. When would the Company file its annual request
22 to update rates under the proposed mechanism?
23 A. Under this mechanism, Idaho Power proposes
24 to file annually in the first quarter to present its
25 quantifications of tracked amounts and request a change to
TATUM, DI 19
Idaho Power Company

1 base rates effective June 1 of each year . The Company
2 further proposes that the annual rate adjustment would be
3 applied as a uniform percentage change to all base rate
4 components excluding the service charge.
5 Q. Is the Company proposing an end date for this
6 mechanism?
7 A. No, not at this time . Because this mechanism
8 is proposed to address the impacts of regulatory lag
9 resulting from the use of a historical test year in the
10 current high capital investment period, the Company
11 proposes that this mechanism remain in place until Idaho
12 Power' s next GRC, and the ongoing need for the mechanism be
13 evaluated at that time.
14 Q. What are the potential implications should the
15 Commission choose to reject the Company' s proposal to
16 implement this mechanism?
17 A. When costs are increasing annually as
18 significantly as they are today, even with annual general
19 rate cases, rates derived under a historical average rate
20 base method will inevitably be inadequate to cover the
21 costs that will exist in the rate effective period. For
22 example, the incremental Depreciation and Interest Expense
23 associated with the rate base growth between 2024 and 2028
24 will range between $52 . 5 million to $93 . 5 million annually.
25 Even with the filing of annual rate cases under the use of
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Idaho Power Company

1 a historical test year method, these incremental costs
2 would be borne by Idaho Power for at least a year, making
3 it unlikely, if not impossible, to earn a reasonable return
4 on investment .
5 Q. Why is Idaho Power requesting ongoing deferral
6 authority for incremental wildfire mitigation and insurance
7 expenses above the baseline levels set in this case?
8 A. As discussed in the Direct Testimony of
9 Company Witness Mr. Brian Buckham, insurance costs have
10 increased in recent years and continue to rise. Further,
11 insurance costs are increasingly difficult to forecast due
12 to price volatility. While Idaho Power undertakes
13 significant efforts to ensure it receives the greatest
14 insurance value possible for its customers, the Company is
15 largely a price-taker in the insurance market and must
16 absorb price increases as insurers raise premiums due to
17 losses . Therefore, the Company believes it is appropriate
18 to request a new baseline level of insurance in rates and
19 also to establish a new deferral to capture incremental
20 insurance premium costs above the new baseline.
21 Similarly, as addressed in detail in the Direct
22 Testimony of Company Witness Mr. Mitch Colburn, the Company
23 also continues to grow and enhance its wildfire mitigation
24 efforts at an increasing cost. Vegetation management
25 represents the largest single cost category in Idaho
TATUM, DI 21
Idaho Power Company

1 Power' s wildfire mitigation activities and those costs
2 continue to rise as demand exceeds supply for those
3 important services . The Company has also added staff,
4 analytical tools and targeted system hardening investments
5 as part of its implementation of a comprehensive wildfire
6 mitigation plan. As such, the Company requests the
7 authority to continue to defer incremental wildfire
8 mitigation and insurance costs above the new baseline
9 established in this case until such a time that these costs
10 stabilize . The cost categories requested for deferral in
11 this case are consistent with those cost categories
12 requested for deferral in pending Case No. IPC-E-25-05 .
13 Q. Will you please provide an overview of the
14 currently approved ADITC/Revenue Sharing Mechanism?
15 A. Since 2009, the Company has been subject to
16 an ADITC/Revenue Sharing Mechanism that includes provisions
17 for the accelerated amortization of ADITC to help achieve a
18 minimum specified percent Idaho-jurisdiction return on
19 year-end equity ("Idaho ROE") , currently set at 9 . 12
20 percent . The mechanism also provides for the potential
21 sharing between Idaho Power and Idaho customers of Idaho-
22 jurisdictional earnings in excess of a 9 . 60 percent Idaho
23 ROE . Since its inception, this mechanism has resulted in
24 earnings sharing or the sharing of beneficial regulatory
TATUM, DI 22
Idaho Power Company

1 lag with Idaho Power' s Idaho customers of approximately
2 $126 million.
3 Q. What is the Company' s recommendation regarding
4 the ADITC/Revenue Sharing Mechanism?
5 A. Idaho Power requests the Commission allow the
6 Company to add additional ADITC to the ADITC/Revenue
7 Sharing Mechanism equal to the total of existing ADITC not
8 currently eligible for accelerated amortization under the
9 mechanism and all available investment tax credits
10 generated through calendar-year 2028 . Further, the Company
11 requests the Commission implement an annual amortization
12 cap of $75 million to limit the amount of ADITC that are
13 utilized in a single year. Idaho Power requests that these
14 modifications to the ADITC/Revenue Sharing Mechanism become
15 effective January 1, 2026 .
16 Q. Why does the Company believe the additional
17 ADITC are necessary?
18 A. The Company anticipates accelerating
19 amortization of up to $77 million of ADITC under the
20 associated revenue sharing and earnings support mechanism
21 in 2025, which is the total amount of eligible ADITC
22 remaining in the mechanism. The relatively large amount of
23 ADITC the Company expects to use under the mechanism in
24 2025 is reflective of substantially underearning below the
25 Idaho ROE floor level specified in the mechanism (which is
TATUM, DI 23
Idaho Power Company

1 well below Idaho Power' s authorized Idaho ROE) . These
2 financial challenges are expected to continue in 2026 and
3 beyond. The rate relief requested in this case and the
4 proposed tracking mechanism will help support credit
5 metrics through cash flow in the near-term, and the
6 additional ADITC will help provide a non-cash earnings
7 support "bridge" until a future GRC. The cash and non-cash
8 benefits of the proposed tracking mechanism and
9 ADITC/Revenue Sharing Mechanism will be beneficial for
10 Idaho Power' s access to both debt and equity capital in the
11 capital markets, a benefit that will ultimately inure to
12 customers .
13 V. WITNESS LIST
14 Q. What was your level of involvement with the
15 preparation of the testimony and exhibits presented by the
16 other Company witnesses?
17 A. I discussed the content and preparation of
18 the witnesses' testimony and exhibits with Ms . Connie
19 Aschenbrenner (Regulatory Pricing and Policy Director) , Mr.
20 Larkin (Revenue Requirement Senior Manager) , and Mr.
21 Donovan Walker (Lead Counsel) , as well as Ms . Megan
22 Goicoechea Allen (Corporate Counsel) .
23 Q. Please provide an overview of the Company' s
24 general rate case filing.
25
TATUM, DI 24
Idaho Power Company

1 A. The Company begins the presentation of its
2 case with Ms . Grow' s testimony, who provides a general
3 overview of the Company and addresses Idaho Power' s current
4 financial and operating situation and need for general rate
5 relief as well as the current impacts of regulatory lag on
6 Idaho Power. My testimony is next and covers the regulatory
7 policy matters related to the development of the general
8 rate case and details proposed methods of mitigating the
9 impacts of regulatory lag.
10 Mr. Adam Richins, Senior Vice President and Chief
11 Operating Officer, discusses the Company' s recent history
12 of reliability and performance that demonstrates a
13 thoughtful approach to grid construction and maintenance
14 and provides an overview of the nearly $1 billion in
15 investments Idaho Power will be making in 2025 to ensure
16 the continued delivery of safe, reliable electric service.
17 He also describes the Company' s Safety First culture and
18 ongoing efforts to enhance our customers' overall
19 experience with Idaho Power and discusses the Company' s
20 advancements in energy efficiency as well as customer
21 relations activities and related technology upgrades .
22 Mr. Eric Hackett, Projects and Resource Development
23 Director, discusses the utility-scale battery project and
24 the major generator interconnection facilities projects
25 expected to be placed in service in 2025 and included in
TATUM, DI 25
Idaho Power Company

1 Idaho Power' s request in this case . He discusses the
2 prudent nature of these investments, detailing why they are
3 needed to ensure Idaho Power' s generation fleet is robust
4 and well-positioned to provide continued safe, reliable
5 service to customers .
6 Mr. Ryan Adelman, Vice President of Power Supply,
7 discusses the production plant-related investments the
8 Company has made to ensure Idaho Power can continue to
9 provide safe, reliable electric service to customers,
10 detailing the steam production, hydroelectric production,
11 and other production investments required since conclusion
12 of Idaho Power' s 2024 Limited Scope Rate Case.
13 Mr. Mitch Colburn, Vice President of Planning,
14 Engineering and Construction, discusses the transmission
15 and distribution investments expected to be placed in
16 service in 2025 and included in Idaho Power' s request in
17 this case . Mr. Colburn also discusses the Company' s
18 substantial efforts related to wildfire mitigation
19 referenced earlier in my testimony.
20 Ms . Sarah Griffin, Vice President of Human
21 Resources, provides justification for the labor and total
22 compensation costs included in the Company' s test year. Ms .
23 Griffin also describes the Company' s overall compensation
24 philosophy and explains why the level of compensation
25 requested in this case is necessary to provide safe,
TATUM, DI 26
Idaho Power Company

1 reliable, affordable electricity to customers .
2 The next witness is Dr. John Thompson, who has been
3 retained by the Company as its ROE expert. Dr. Thompson
4 discusses risk factors relevant to Idaho Power, performs
5 calculations of ROE appropriate for the Company using
6 standard financial methodologies, and recommends a
7 reasonable ROE range appropriate for Idaho Power. In this
8 proceeding, Dr. Thompson' s ROE range is from 10 . 2 to 11 . 2
9 percent .
10 Mr. Brian Buckham, Idaho Power Company' s Senior Vice
11 President, Chief Financial Officer, and Treasurer, builds
12 on Dr. Thompson' s recommendations by more specifically
13 addressing the relevant risk factors impacting the Company.
14 Mr. Buckham selects a 10 . 40 percent ROE point estimate as
15 the appropriate cost of equity, supports the cost of Idaho
16 Power' s long-term debt, and includes the long-term debt and
17 the 10 . 40 percent ROE in the test year capital structure to
18 derive the Company' s proposed overall rate of return.
19 Ms . Paula Jeppsen, the Company' s Controller,
20 Business Unit Finance and Strategy, next testifies to the
21 actual 2024 financial results with standard ratemaking
22 adjustments . Ms . Jeppsen describes the development and
23 application of the methodologies used to prepare the 2024
24 base financial information and the adjustments to those
25 data associated with deductions to certain expenses not
TATUM, DI 27
Idaho Power Company

1 allowed in rates, certain adjustments to expenses and rate
2 base, and other adjustments to revenues, expenses, and rate
3 base related primarily to past Commission orders .
4 Mr. Matthew Larkin, Revenue Requirement Senior
5 Manager, describes how the Company utilized the 2024
6 financial data as presented by Ms . Jeppsen as a starting
7 point from which he made conservative adjustments to derive
8 similar data corresponding to the 2025 test year. Mr.
9 Larkin prepared an exhibit that details the method and
10 rationale for each known and measurable adjustment he
11 utilized in developing the 2025 test year data. Once he
12 determined the 2025 test year system-level data, Mr. Larkin
13 supervised the preparation of the jurisdictional separation
14 study utilized to determine the Idaho jurisdictional
15 revenue requirement.
16 Ms . Jessica Brady, Senior Regulatory Analyst,
17 discusses the derivation of the Company' s 2025 retail
18 revenue forecast used for the 2025 test year, presents the
19 quantification of the 2025 normalized or "base level" net
20 power supply expenses, and addresses the requisite changes
21 to the Company' s PCA as a result of changing the normalized
22 net power supply expenses in Idaho Power Company' s base
23 rates .
24 Ms . Kelley Noe, Regulatory Consultant, incorporates
25 Ms . Jeppsen' s financial data, Mr. Larkin' s test year
TATUM, DI 28
Idaho Power Company

1 adjustments, Mr. Buckham' s overall rate of return
2 recommendation, and Ms . Brady' s normalized net power supply
3 expenses, along with other necessary inputs, and prepares
4 the jurisdictional separation study ("JSS") . The JSS, as
5 its name states, separates system values for rate base,
6 revenues, and expenses for each state jurisdiction through
7 an assignment and allocation process that is described in
8 detail in Ms . Noe' s testimony. One result of the JSS is the
9 Idaho retail jurisdictional revenue requirement, which is
10 the Company' s best representation of its expected annual
11 cost to serve its Idaho retail customers . The 2025 Idaho
12 jurisdictional revenue requirement is $1, 720, 122, 500 . In
13 order to obtain this amount, Idaho' s annual retail revenues
14 will need to increase by $199, 122, 685 or 13 . 09 percent.
15 Mr. Riley Maloney, Regulatory Policy and Strategy
16 Leader, uses the Idaho retail jurisdictional output from
17 the JSS, as developed by Ms . Noe, and further separates
18 costs by customer class through preparation of the
19 Company' s class cost-of-service study ("CCOS") . The study
20 prepared by Mr. Maloney in this case presents an approach
21 much like that used by the Company in its last general rate
22 case, with certain modifications and additions . In the
23 Company' s 2008 GRC, IPC-E-08-10, the Commission approved a
24 cost-of-service methodology termed "3CP/12CP" and the
25 Company subsequently used a similar "4CP/12CP" methodology
TATUM, DI 29
Idaho Power Company

1 in its 2023 GRC, IPC-E-23-11, which was ultimately settled
2 without a Commission decision regarding the filed COOS . Mr.
3 Maloney used the same CCOS method employed in the Company' s
4 2023 General Rate Case as the starting point for his CCOS
5 in this case and then applied modifications to the
6 allocation of demand-classified production costs . Mr.
7 Maloney recommends that his CCOS be used as the appropriate
8 starting point for rate spread (the process of spreading
9 the Idaho jurisdictional revenue requirement to the
10 customer classes and special contract customers) and rate
11 design (the ultimate calculation of rates for customers) .
12 Mr. Maloney also presents the Company' s computation of its
13 Sales Based Adjustment Rate, as well as its proposed Fixed
14 Cost Adjustment rates contained within Schedule 54 .
15 Finally, Mr. Grant Anderson, Pricing and Tariff
16 Administration Leader, describes the Company' s pricing
17 objectives and presents its proposed pricing for all
18 customer classes, including residential, general service,
19 large power, irrigation, lighting, and special contract
20 customers . Mr. Anderson also presents the Company' s
21 proposed modifications to its tariff, which are generally
22 intended to improve consistency, transparency, and
23 administration.
24
25
TATUM, DI 30
Idaho Power Company

1 VI . RATE SPREAD AND RATE DESIGN
2 Q. What has been Idaho Power' s policy with regard
3 to rate spread and rate design proposals?
4 A. Idaho Power has consistently advocated for the
5 principle that rate spread among the customer classes, and
6 component pricing within the customer classes, should be
7 primarily cost-based. Accordingly, the Company' s ratemaking
8 proposals have traditionally advocated movement toward
9 cost-of-service results that assign costs to those
10 customers that cause the Company to incur the costs . The
11 Company is also committed to providing customers cost-based
12 price signals, which encourage the wise and efficient use
13 of energy. As such, I have directed Mr. Anderson to design
14 cost-based rate proposals that also encourage increased
15 energy efficiency where feasible.
16 Q. Do the Company' s proposals in this case
17 strictly adhere to that objective?
18 A. No. The Company realizes that there are often
19 other ratemaking objectives, such as rate stability,
20 ability to pay, and mitigating rate shock, that the
21 Commission may consider in making its determination.
22 However, the Company believes that the best starting point
23 for Commission deliberations is an economic one.
24 Nevertheless, because some ratemaking situations may cause
25 abrupt change, Idaho Power has traditionally proposed some
TATUM, DI 31
Idaho Power Company

1 limits to the movement toward cost-of-service. The
2 specifics of the Company' s proposed rate spread and an
3 exhibit delineating the target revenue requirement for each
4 customer class are contained in Mr. Maloney' s testimony.
5 Q. What guidance did you provide Mr. Maloney
6 regarding cost-of-service constraints applied to the rate
7 spread ultimately recommended?
8 A. First, I discussed the CCOS prepared for this
9 case with Mr. Maloney and agreed that his recommended CCOS
10 methodology represented the preferred starting point in
11 this proceeding to develop the recommended rate spread.
12 However, this method when applied without constraints, does
13 show a larger impact to a number of customer classes
14 (relative to the overall average increase) , most notably
15 Residential Service, Schedule 1, and Agricultural
16 Irrigation Service, Schedule 24 . Given recent rate
17 pressures and the somewhat subjective nature of cost
18 allocation and year-to-year cost components, I asked Mr.
19 Maloney to run several rate mitigation scenarios to look at
20 the impacts of constraining the rate increase at different
21 levels .
22 After this review, the Company chose to recommend a
23 "cap" of 130 percent times the average revenue change for
24 any customer class or special contract customer exceeding
25 the overall average increase. In addition, Idaho Power
TATUM, DI 32
Idaho Power Company

1 recommends a revenue change "floor" of 30 percent of the
2 overall average revenue change. These cap and floor levels
3 strike a reasonable balance between revenue movement for
4 those classes exceeding the overall average, and the
5 necessary spread of the resulting revenue shortfall .
6 Q. How has Idaho Power addressed the cost-based
7 objective in its rate design proposals?
8 A. This objective has been met by the
9 implementation of seasonal rates for all metered service
10 schedules, and the implementation of rate structures that
11 reflect a greater emphasis on the demand and customer
12 components . The Company also proposes the continuation of
13 mandatory time-of-use pricing for Large Commercial
14 customers taking service at primary and transmission
15 voltages and all Large Power Service customers . In
16 addition, this objective has been met by offering optional
17 time-of-use pricing for Residential and Large General
18 service customers taking service at the secondary voltage
19 level .
20 VII . CONCLUSION
21 Q. Please summarize Idaho Power' s requested
22 revenue increase in this case?
23 A. The Company is requesting rate relief of
24 approximately $199 . 1 million, which is net of a
25 corresponding proposed PCA decrease of $46 . 8 million. If
TATUM, DI 33
Idaho Power Company

1 approved, this request would result in an overall increase
2 to adjusted retail revenue of 13 . 09 percent effective
3 January 1, 2026 . The Company' s request is based on a
4 proposed rate of return of 7 . 818 percent, with a capital
5 structure comprised of 51 percent equity and 49 percent
6 debt, a 5 . 132 percent cost of debt, and a 10 . 40 percent
7 ROE . This request was developed using a test year of 12
8 months ending December 31, 2025 .
9 Q. Will you please summarize the Company' s other
10 requests for specific regulatory treatment and/or necessary
11 accounting authority proposed in this case?
12 A. In addition to approval of the Idaho
13 jurisdictional revenue increase presented in this case and
14 each of the affected tariff schedules, the Company requests
15 the Commission issue an order that includes the following:
16 1 . Approval of a revised Schedule 55, Power Cost
17 Adjustment, reflecting the transfer of certain
18 base level NPSE from the PCA to base rates .
19 2 . Authorization to update rate recovery
20 associated with both the Valmy and Bridger
21 mechanisms to reflect current capital and 0&M
22 expectations, and to true-up variances between
23 prior forecasts and actual costs .
24 3 . Approval of a per-unit wheeling revenue
25 baseline of $3 . 39 per MWh, which reflects Idaho
TATUM, DI 34
Idaho Power Company

1 jurisdictional point-to-point wheeling revenues
2 of $52, 329, 358 divided by Idaho jurisdictional
3 retail sales of 15, 451, 410 MWh.
4 4 . Establishment of a tracking mechanism for
5 incremental Depreciation and Interest Expense
6 as measured from a sales-adjusted baseline of
7 $324, 559, 987 effective January 1, 2026 .
8 5 . Authorization of the continued deferral of
9 incremental wildfire mitigation and insurance
10 costs in 2026 and beyond as measured from a new
11 base level of costs established in this case.
12 6 . Designation of additional ADITC accumulated
13 through 2028 as eligible for accelerated
14 amortization under the terms of the currently
15 approved ADITC/Revenue Sharing Mechanism, with
16 the addition of a $75 million annual
17 amortization cap.
18 Q. Is it your opinion that the granting of the
19 rate relief and additional regulatory treatment proposed by
20 the Company is in the public interest?
21 A. Yes . The proposed rates, with support from the
22 additional proposed regulatory measures, will allow Idaho
23 Power to continue providing safe, reliable service at
24 reasonable rates while maintaining its financial health.
25
TATUM, DI 35
Idaho Power Company

1 Q. Does this conclude your testimony?
2 A. Yes, it does .
3
4
TATUM, DI 36
Idaho Power Company

1 DECLARATION OF TIMOTHY E. TATUM
2 I, Timothy E . Tatum, declare under penalty of
3 perjury under the laws of the state of Idaho:
4 1 . My name is Timothy E. Tatum. I am employed
5 by Idaho Power Company as the Vice President of Regulatory
6 Affairs .
7 2 . On behalf of Idaho Power, I present this
8 pre-filed direct testimony and Exhibit No. 1 in this
9 matter.
10 3 . To the best of my knowledge, my pre-filed
11 direct testimony and exhibit are true and accurate.
12 1 hereby declare that the above statement is true to
13 the best of my knowledge and belief, and that I understand
14 it is made for use as evidence before the Idaho Public
15 Utilities Commission and is subject to penalty for perjury.
16 SIGNED this 30th day of May 2025, at Boise, Idaho.
17
18 Signed:
19 Timothy E . Tatum
20
21
22
23
24
TATUM, DI 37
Idaho Power Company

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-16
IDAHO POWER COMPANY
TATUM , DI
TESTIMONY
EXHIBIT NO. 1

DEPRECIATION AND INTEREST TRACKING MECHANISM UNIT COST
On-Site Gen On-Site Gen Sec Sery Prim/Trans Sery Sec Sery
Factor Residential Residential Small General Small General Large General Large General Area Lighting Large Power Irrigation
Description Name Total Sch 1 Sch 6 Sch 7 Sch 8 Sch 9-S Sch 9-PIT Sch 15 Sch 19-SIPIT Sch 24-S
.......................................
Interest INT $ 129,722,140 $ 61,110,346 $ 2,976,866 $ 1,688,998 $ 11,975 $ 23,703,682 $ 4,294,912 $ 137,888 $ 12,107,775 $ 17,398,006
Depreciation Expense DEPR 185,236,719 87,604,622 4,100,741 2,492,257 15,393 34,103,610 6,177,528 61,486 17,734,656 24,163,424
.........................................
Amortization of Limited Term Plant ALTP 9,601,128 4,303,439 177,371 87,540 429 1,866,131 338,640 1,287 1,091,277 1,138,781
..............................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................
i
Mechanism Total $ 324,559,987 $ 153,018,407 $ 7,254,978 $ 4,268,795 $ 27,797 $ 59,673,423 $ 10,811,081 $ 200,660 $ 30,933,708 $ 42,700,211
_...............................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................
Test Year Energy Sales 15,451,409,934 5,615,604,402 250,351,173 139,846,139 699,023 3,405,141,928 658,101,374 1,937,298 2,196,091,802 1,770,164,055
.................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................
i Unit Cost $ 0.021005 $ 0.027249 $ 0.028979 $ 0.030525 $ 0.039765 $ 0.017525 $ 0.016428 $ 0.103577 $ 0.014086 $ 0.024122
................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................
Exhibit No.1
Case No.IPC-E-25-16
T.Tatum,IPC
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Non-Metered Traffic Control Lamb
Factor General Street Light Lighting Micron Simplot DOEIINL Simplot Brisbie Weston
Description Name Total Sch 40 Sch 41 Sch 42 Sch 26 Sch 29 Sch 30 Sch 32 Sch 33 Sch 34
.......................................
Interest INT $ 129,722,140 $ 107,099 $ 341,688 $ 33,746 $ 2,860,678 $ 841,711 $ 830,373 $ 648,497 $ - $ 627,901
Depreciation Expense DEPR 185,236,719 148,902 493,559 48,926 3,865,278 1,226,786 1,291,036 913,705 - 794,810
.........................................
Amortization of Limited Term Plant ALTP 9,601,128 7,239 12,583 1,679 279,611 77,158 96,480 66,303 55,181
.............................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................,
i
Mechanism Total $ 324,559,987 $ 263,240 $ 847,830 $ 84,351 $ 7,005,567 $ 2,145,654 $ 2,217,889 $ 1,628,505 $ - $ 1,477,892 i
Test Year Energy Sales 15,451,409,934 14,484,473 20,419,614 3,056,155 635,708,728 211,750,000 241,000,000 155,000,000 132,053,769
.................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................
i Unit Cost $ 0.021005 $ 0.018174 $ 0.041520 $ 0.027600 $ 0.011020 $ 0.010133 $ 0.009203 $ 0.010506 $ - $ 0.011192
................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................................
Exhibit No.1
Case No.IPC-E-25-16
T.Tatum,IPC
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