HomeMy WebLinkAbout20210528McDougal Direct.pdfBEFORE. THE II}ASO PUBLIC UNLITBS COMMISSIONI
INTHEMATTEROFTHE
APPLICATION OT ROCIff
MOT}NTAIN POWER FOR
AUTHORITY TO INC?EASE ITS
RATES ANI} CIIARGES IN IDAEO
AND APPROVAL OT PROBOSED
ELECTRIC SERVICE SCHEDULES
AND RE'GT'LATION,S
)) CASE NO. PAC-E 2147
)) Dir€ctTostimonyof Sterven R McDougal
)
)
)
)
ROCICY MOT}NTAIN FOWER
CASE NO. PAC.E-21{7
hfiry 2021
TABLE OF'CONTENTS
I. INTRODUCTION AND QUALrFrCATIONS.............
II. PURPOSE OF TESTIMONY
III. REVENUE REQUIREMENT SUMMARY
IV TEST PERIOD
V. INTER.JURISDICTIONALALLOCATIONS
VI. OTHERADJUSTMENTS AND ISSUES.
Federal lncome taxes .........
Cholla Plant Retirement..........
Carbon Plant ..........
Deer Creek Mine...
Klamath
20 I 8 Depreciation Study
Lake Side 2 .....................
Load Change Adjustment Rate ("LCAR")
VII.IDAHO RESTILTS OF OPERAJflONS
Tab 3 - Revenue Adjustnents ...................
Tab 4 - O&M Adj ustnents........................
Tab 5 - Net Power CostAdjustments........
Tab 6 - Depreciation and Amortization Expense Adjustments ................
TabT-Ta:rAdjustments
Tab 8 - Rate BaseAdjustments
VIII. SUMMARY ..........
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AITACHEI} M(HIBITS
Exhibit No. 39 - Revenue Requirement Summary
Exhibit No. 40 - Test Period Resule of Opemtions - Twelve Months ending December 2020
adjusted for I(nown and Measnrable Chaages
Confidential Exhibit No. 4l - Confidential Pages Test Perid Results of Operations
Confidential Exhibit No. 42 - Property Tax Estimation Pnocedure and Estimation
Exhibit No. 43 - TCJA Regulabry Liabiliry
Exhibit No. 44 - ECAM Base -Alooatsd and LCAR Calculetion
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I. INTRODUCTIONANDQUALIFICATIONS
Please state your name, business address, and present position with PacifiCorp,
d/b/a Rocky Mountain Power ("Rocky Mountain Power" or the "Company").
My name is Steven R. McDougal. My business address is 1407 W. North Temple, Suite
330, Salt Lake City, Utah 84116. My current position is the Director of Revenue
Requirement.
Please describe your education and professional background.
I received a Master ofAccountancy from Brigham Young University with an emphasis
in Management Advisory Services and a Bachelor of Science degree in Accounting
from Brigham Young University. In addition to my formal education, I have also
attended various educational, professional, and electric industry-related seminars. I
have been employed by PacifiCorp and its predecessor, Utah Power and Light
Company, since 1983. My experience includes various positions with regulation,
finance, resource planning, and internal audit.
What are your responsibilities with the Company?
My primary responsibilities include overseeing the calculation and reporting of the
Company's regulated eamings or revenue requirement, assuring that the inter-
jurisdictional cost allocation methodology is correctly applied, and explaining those
calculations to regulators in the jurisdictions in which the Company operates.
Have you testified in previous regulatory proceedings?
Yes. I have provided testimony in many cases before the Idaho Public Utilities
Commission ("Commission"). I have also testified on various regulatory matters in the
states of California, Oregon, Utah, Washington, and Wyoming.
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il. PURPOSEOF'TESTIMONY
What is the purpose of your testimony in this proceeding?
My direct testimony addresses the calculation of the Company's Idaho-allocated
revenue requirement and the revenue increase requested in the Company's filing.
Specifically, I provide testimony on the following:
. The calculation of the $19.0 million overall rate increase requested in this
general rate case (*GRC"), representing a total Idaho-allocated revenue
requirement of $290.5 million;
. A description of the Test Period proposed in this case;
. The 2O2O PacifrCorp Inter-Jurisdictional Allocation Protocol methodology
(*2020 Protocol') used to determine Idaho-allocated results, including
treatnent of irrigation demand side management ("DSM") costs,
. Other revenue requirement issues, including:
" Federal lncome Trures included in the case;
o The Resource Tiacking Mechanism;
" Cholla Unit 4 Plant closure;
. Carbon Plant recovery;
o Deer Creek Mine recovery;
. Klamath Hydroelectric Facility;
. 2018 Depreciation Study;
o Lake Side 2; and
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. Calculation of the Load ChangeAdjustment Rate ("LCAR") based on
costs in this filing for use in the Energy Cost Adjustment Mechanism
("ECAM'); and
. The Results of Operations supporting the Test Period revenue requirement and
a detailed explanation of the known and measurable adjustments made to the
unadjusted l2-month historical period ended December 31,2020 ("Base
Period") data to arrive at the Test Period.
My direct testimony is accompanied by supporting exhibits including the detailed
results of operations for the Test Period.
IU. REVENT]E REQUIREMENT SUMMARY
What price increase is required to achieve the requested return on equity ("ROE')
in this case?
The 10.20 percent ROE recommended by Ms. Ann E. Bulkley in this case produces an
overall Idaho revenue requirement of $290.5 million and an overall requested price
increase of $19.0 million. Exhibit No. 39 provides a summary of the Company's Idaho-
allocated results of operations for the Test Period. The Company estimates that under
existing rates the Company would earn an overall ROE of approximately 7.48 percent.
Details supporting tle revenue requirement by the Federal Energy Regulatory
Commission ("FERC") account and the allocation of the various revenue requirement
components to Idaho are provided in Exhibit No. 40.
What are the major drivers behind the revenue requirement in this case?
The major revenue requirement components that are driving the Company's general
rate case filing are the recovery of major new capital invesftnents and the impact of
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changes in depreciation rates. More detail on these drivers are provided below and in
the direct testimony of the other Company witnesses.
Please explain the new capital investments the Company is seeking to recover as
part ofthis case.
The Company expects to place into service a variety of new capital projects including
those related to the Pryor Mountain wind project, repowering of the Foote Creek wind
project, and the Energy Msion 2020 Projects. More specifically, the Energy Msion
2020 projects consist of: repowering existing wind resources ("Repowering Project"),
the construction or acquisition of new wind resources and associated network upgrades,
and the construction of the Aeolus-to-Bridger/Anticline transmission line ("New Wind
and Transmission Projects"). The Pryor Mountain, Foote Creek and Energy Vision
2020 wind projects account for approximately $2.8 billion, total-Company, of the total
projected plant additions. The calculation of Test Period electric plant-in-service
including other capital additions included in the case are located in Exhibit No. 40.
Please provide additional details regarding the major capital investments that
include the Enerry Vision 2020 Projects.
The Commission found the Energy Vision 2020 Projects to be prudent and in the public
interest and adopted the settlements that were reached in the following cases:
. Repowering twelve wind facilities identified in the Repowering Project, Case
No. PAC-E-17-06;tand
I In the Matter of the Application of Rocky Mouutain Power for Binding Raternaking Treatment for Wind
Repowering, Case No. PAC-E-I7-06, Order No. 33954 (Dec. 28,2017) hereinafter "Repowering Order".
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. The New Wind and Transmission Projects as described in Case No. PAC-E-
fi-07.2
In addition, the revenue requirement in this case includes the repowering of the
Foote Creek I wind facility and the new Pryor Mountain wind facility. Additional
details for these projects are described later in my testimony and in the testimonies of
Mr. Timothy J. Hemstreet, Mr. Robert Van Engelenhoven, Mr. fuchard A. Vail, and
Mr. Rick T. Link.
Does the revenue requirement in this case include any selective catalytic reduction
("SCR") retrolit projects that have not been included in prior cases?
Yes. The Base Period in this case includes the SCR projects atCraig, Hayden, and Jim
Bridger described in the testimony of Mr. James C. Owen.
Does the revenue requirement in this case include a change related to base net
power costs ("NPC'')?
Yes. NPC are included in the Test Period results to reset base NPC in customer rates.
The Company also utilizes the ECAM which provides for an annual deferral and
recovery of the difference between actual NPC, production tax credits ("PTCs") and
renewable energy credits ("RECs") and the base NPC, PTC, and REC included in rates.
The direct testimony of Mr. Michael G. Wilding provides the support forthe baseNPC
included in the Test Period in this case, which will be used as the base NPC included
in future ECAM filings. Further details of the calculation of base NPC, PTCs, and
RECs are included as Exhibit No. 44.
2 In the Matter of the Application of Rocky Mountain Power for a Certificate of Public Convenience and
Necessity and Binding Raternaking Treatment for New Wind and Transmission Facilities, Case No. PAC-E-I7-
07, Order No.34104 (July 20, 2018) hereinatter "New Wind and Transmission Order".
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ry. TEST PERIOD
What test period did the Company use to determine revenue requirement in this
case?
Revenue requirement in the Company's filing is based on the Base Period, the historical
twelve-month period ending December 31,2020, adjusted for known and measurable
changes through December 31,2021(the "Test Period").
Is the Test Period in this case consistent with test periods used by the Company in
previous general rate cases?
Yes. The Test Period is prepared in a manner consistent with the Company's general
rate cases filed previously in Idaho. Later in my testimony I provide additional support
for major decisions made in the Test Period preparation, including treatment of rate
base and treafrnent of depreciation rates. I also describe the process employed by the
Company to prepare revenue requirement and provide brief descriptions of each
normalizing adjustment made to revenue, operations and maintenance ("O&M")
expense, NPC, depreciation, taxes, and rate base.
What oven-riding principle guided the Company's development of the Test Period
in this case?
The primary objective in determining a test period is to develop normalized results of
operations that best reflect the operating conditions during the time the new rates will
be in effect ("rate effective period"). Multiple factors must be considered to determine
which test period best reflects these conditions, including prior rate case filings. This
case uses a historical test period adjusted for known and measurable changes that
coincides with the rate effective period. This is consistent with prior cases where the
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Company also relied on historical data with normalizing adjustments to reflect as
closely as possible the rate effective period.
When will a rate change become effective in this proceeding?
The Company is requesting that new rates become effective January l, 2022,
approximately seven months after filing, consistent with the Company's application.
Why is it important that the Test Period and the rate effective period be aligned
as closely as possible?
In an environment of significant capital investnent and changing resource utilization,
a test period that does not include capital additions in-service during the rate effective
period cannot adequately capture the conditions that the Company will experience
while rates are in effect. When a utility is in a significant investment cycle and
experiencing other krrown and measurable cost changes such as a change in
depreciation rates, a pure historical test period does not allow the utility to recover the
true cost of service on a timely basis. The Company will continue to place assets into
service during the test period. These assets will immediately provide benefits to the
Company's customers in Idaho, but the Company will no longer be able to defer the
cost of financing such assets in the form of allowance for funds used during
construction ("AFUDC") and will begin to incur depreciation expense as soon as the
asset is in service. The ECAM mitigates the under recovery on potential inueased fuel
costs, but it can also work against the Company by passing through the benefits of zero-
fuel-cost energy and PTCs from new wind facilities while the fixed costs of these same
facilities go uffecovered until they can be incorporated into a general rate case without
a separate mechanism like the Resource Tracking Mechanism ("RTM").
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What has the Company done in this case to better align the Test Period with the
rate effective period?
A significant cost driver in this application is the capital investment the Company has
incurred to serve its retail customers. The Company has calculated rate base using an
end-of-period basis for the Base Period.Ary major capital additions or known and
measurable changes to the Test Period rate base are reflected as of Decernber 31,2021.
This fieatment better aligrrs the case with the level of invesfinent that will be used and
useful during the rate effective period and sets the customer rates at a more appropriate
level.
V. INTER.JI]RISDICTIONALALLOCATIONS
What allocation methodolory did the Company use to calculate the Idaho revenue
requirement in this case?
The Company's requested price increase is based on the 2020 Protocol, as approved by
the Commission on Apil22,2O2O, in Case No. PAC-E-19-20.3 The most significant
change from the prior allocation methodology, the2017 Protocol, is the elimination of
the $150,000, Idaho-allocated, 2017 Protocol Equalization Adjustment. The fixed
embedded cost differential of $836,000 will continue and has been reflected in the
revenue requirement of this case.
What is the effective date for the 2020 Protocol?
The2020 Protocol was effective beginning January 1,2020.
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3 In the Matter of Rocky Mountain Power's Application for Approval of the 2020 PacifiCorp lnte{urisdictional
Allocation Protocol, Case No. PAC-E-19-20, Order No. 34640 (Aprll22,2020).
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a Is the Company treating Class I DSM programs in this case different from its past
cases in ldaho?
Yes. In the 2010 general rate case, the Commission ordered the Company to treat load
control, or Class l, DSM programs as system resources which impacted the way the
costs and benefits of these programs are reflected in the revenue requirement.a In the
subsequent general rate case, the Company continued with this ordered treatrnent. The
Company is now proposing to change the treatment of Class I DSM and include both
the costs and benefits of these programs as situs resources to their respective states.
This teafrnent would align Idaho with the methodology outlined in the 2020 Protocol.
Section 3.1.2-l within the 2020 Protocol agreement states:
Demand-Side Management ("DSM") Programs: Costs associated with
DSM Programs, including Class I DSM Programs, will be allocated
on a situs basis to the State in which the invesflnent is made. Benefits
from these programs, in the form of reduced consumption and
contribution to Coincident Peak, will be reflected in the Load-Based
Dynamic Allocation Factors.s
Do any other jurisdictions served by PacifiCorp have similar programs, and are
those programs treated in a similar manner in this case?
Yes. The Company operates similar progmms to control irrigation load in California,
Oregon, and Utah and central air conditioning load in its Utah service territory. These
programs are freated as situs resources, consistent with the 2020 Protocol where all
Class I DSM programs are situs assigned, including the Idaho irrigation program in
this filing.
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a In the Maffer of the Application of PacifiCorp dba Rocky Mountain Power lbr Approval of Changes to its
Electric Service Schedules, Case No. PAC-E- 10-07, Order No" 32 I 96 (Feb. 28,2011).
s In the Matter of Rocky Mountain Power's Application for Approval of the 2020 PacitiCorp Inte{urisdictional
Allocation Protocol, Case No. PAC-E-19-20, Testimony of Joelle Steward, Exhibit I at I I (Dec, 3, 2019).
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Where is the proposed treatment of Class 1 DSM programs reflected in the
Company's revenue requirement calculation?
There are two components of the Class I DSM programs that are reflected in the
Company's revenue requirement, the costs and the benefits of the programs. The costs
ofthe Class I DSM programs consist ofthe administrative costs ofrunning the program
and the credits paid to the participants of the program. The cost of the programs are
included on a situs basis in the Company's Base Period O&M data used in the revenue
requirement calculation. The benefits of the Class I DSM programs occur in the load
reductions by state as a result of program operations. The 2020 coincident peaks in the
filing were adjusted to reflect situs treafinent of Class I DSM load curtailrnent events.
The calculation of the coincident peals can be viewed in Exhibit No. 40 on page 9.13.
What is the impact as a result of the change from a system to situs resource for all
states Class I DSM programs?
The approximate impact after capturing both the change in costs and benefits have
reduced the Idaho revenue requirement in this case by $1.4 million.
VI. OTHERADJUSTMENTS AND ISSUES
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L7 Federal Income Taxes
184 How has federal income tax expense been calculated in this case?
Federal income tax expense for ratemaking is calculated using the same methodology
that the Company uses in preparing its filed income tax returns. On December22,20l7,
Congress passed and the president signed the Tax Cuts and Jobs Act ("TCJA") setting
a new corporate income tax rate of 21 percent compared to the previous rate of
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35 percent. Accordingly, the federal income tax rate has been updated in the Company's
revenue requirement model to 2l percent.
Has the Company deferred to a regulatory liability any balances associated with
the tax savings as a result of the TCJA?
Yes. On March 30, 2018, the Company filed an application with the Commission
requesting authorization to begin passing current tax savings back to customers and to
create a regulatory liability to defer the incremental tax savings associated with the
TCJA. The Commission consolidated the Company's application with those of the
other regulated utilities in Idaho under Case No. GNR-U-I8-01, ("TCJA Case"). After
working with the parties to the case the Company was able to negotiate a settlement,
approved by Commission Order No. 34331, that established a plan to return all the
TCJA benefits to customers.
IIow were the current tax savings from the TCJA returned to customers?
The Company began refunding to Idaho customers an annual credit of $6.2 million on
June 1,2018, through TaritrSchedule 197. Beginning June 1,2019, the credit was
increased to an annual amount of $7.6 million, or 100 percent of the calculated current
tax savings. Since the Company began realizing the current tax savings from the TCJA
January l, 2018, the Company accrued a current tax savings balance from January 1,
2018, through May 31, 2019, of $4.6 million. This amount was then reduced by
$3.4 million to offset the regulatory asset balance related to deferred depreciation
expense and resulted in a remaining regulatory liability balance for current tax of
approximately $1. I million.
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The stipulation reached in the TCJAcase further agreed to refund the remaining
current tax savings of $1.1 million over two years, beginning June 1, 2019, through
May 3 I ,2021. The amortizaion of the full current tax deferred balance was refunded
to customers as of May 31,2021, through the ECAM, TariffSchedule 94.
Under the stipulation, how were Excess Deferred Income Taxes ("EDIT')
amounts to be refunded to customers?
There are three different classifications of EDIT: protected property, non-protected
property, and non-protected non-property. The Commission order specified that the
EDIT savings based on the Average Rate Assumption Method ("ARAM") for calendar
years 2018, 2019, aroid 2020 would be returned to customers through the ECAM. The
protected property would be used to offset the deferred ECAM balance for the
respective years and the non-protected EDIT savings would be used to offset the
incremental depreciation expense from the 2013 depreciation study.
Is any EDIT included in the revenue requirement in this case?
Yes. The Company began amortizing all protected property balances using the Reverse
South Georgia Method ("RSGM") rather than the originally assumed ARAM.
Accordingly, the amortization of the protected property EDIT for the Test Period using
RSGM has been included in the revenue requirement of this case.
What is the total regulatory liability balance as a result of the TCJA and how was
this calculated?
Based on the RSGM amortization, approximately $ 19.5 million of protected property
amortization for calendar years 2018 through}OZl has been deferred to a regulatory
liability. Idaho customers have, or will have, received protected property amortization
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for calendar years 201 8 and 20 I 9 based on a preliminary estimated ARAM calculation
through Schedule 94 of $4.9 million, leaving a remaining deferred balance of $14.6
million. Although the settlement agreement in the TCJA case also agreed to refund
customers the preliminary calendar year 2020ARAM protected-property amortization
through Schedule 94,the Company reached a settlement in Case No. PAC-E-20-03 to
use that deferred balance toward the rate mitigation efflorts instead of refund through
the Schedule 94. Furthennore, non-protected properly and non-protected non-properly
('T.{on-Protected") EDIT regulatory liability balances were being amortized back to
customers over seven years beginning June 1,20L9, but have since discontinued for
use in rate mitigation efforts as part of the settlement reached in Case No. PAC-E-20-
03.
In total, the TCJAregulatory liability balance that was available for refund was
comprised of $14.6 million of deferred protected property amortization and $13.6
million of non-protected property EDIT, or $28.2 million. Table I below provides and
summary and references for this balance as firther detailed in ExhibitNo. 43.
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1 TABLE 1
EXnlDtt No. rtit
Description Reference Amount
Non-EDIT Tax Benefits
TCJA Schedule 197 Refund
TCJA Schedule 94 Retund
2013 Depreciation Reg Asset
813
H31
H32
H33
(30,3s4,500)
25,788,948
1,140,528
3.425.024
Remaining Non-EDIT Tax Benefits 0
Protected EDIT Defened Amortization
ECAM Offset - Defened Protected EDITAmoilization
F13
H34
(19,483,906)
4,916,718
Re ma i n i n g Protecte d EDIT Defe rre d Amortiza tion (14,s57,188)
Non-Protected EDIT - Property
Non-Protected EDIT - Non-Property
ECAM Offset - 7 Year Amortization
D18
E18
H35
(16,237,1s7)
(1,610,816)
4.252.430
Remaining NonProtected EDIT (13,595,54:!)
GRAND TOTAL (28,162,7311
What is the Company's Proposal to return the $28.2 million available for refund
to customers
Order No. 34384, Case. No. PAC-E-20-03, authorized the Company to use a portion of
the available EDIT balance to buy-down the remaining uffecovered plant balances at
the Cholla Unit 4 plant. After updating for actual plant balances upon closure, the
Company bought-down approximately $16.4 million, Idaho-allocated, of the
unrecovered plant balances. The Company is proposing to use the remaining
$11.8 million for the following additional rate mitigation efforts:
. Approximately $2.8 million of ldaho-allocated closure costs, net of savings,
and decommissioning costs related to Cholla Unit 4;
. Approximately $2 thousand to fully recovery Powerdale decommissioning
costs;
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. Approximately $88 thousand to buy-down the remaining balances of the
electric plant acquisition adjusunent for the Craig and Hayden plants that would
have otherwise amortized through A pil 2022;
o $300 thousand for the deferred balances due to the 2017 Protocol equalization
adjustment; and
. Approximately $103 thousand of defemed intervenor funding costs.
Assuming each of these balances would have otherwise been amortized over a
period of three years, buying them down using TCJA dollars reduces the revenue
requirement in this case by approximately $6.6 million. An exhibit supporting the
calculation of the remaining deferred tax balance is provided as Exhibit 43. The details
regarding the ffeatrnent for the remaining deferred tax balance of $8.5 million is
described in the testimony of Ms. Joelle R. Steward.
Are there any additional tax items you want to discuss?
Yes. Federal tax law changes are under consideration by Congress, including changes
to the federal corporate income taxrate.If a change in the federal corporate income tax
rate is enacted during the pendency of this proceeding, the Company will propose
updating the tax rate in the case and recovery of the Deficient Accumulated Deferred
Income Taxes ("DAD[T") in a manner consistent with the give back associated with
the tax change passed in the TCJA. If a change in the federal corporate income tax rate
is enacted after the pendency of this proceeding, or too late in the process to incorporate
the change in this filing, the Company will initiate a new filing to address the impact.
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1 Resource Tracking Mechanism
2 Q. Please describe the Resource Tracking Mechanism.
3 A. The RTM was established to track the revenue requirement for the Energy Vision 2020
4 Projects. More specifically, the RTM was calculated as the incremental impact on
5 revenue requirement from the costs and benefits of the Energy Vision 2020 Projects.
6 This difference was deferred and collected as part of the Company's annual ECAM
7 filings, with the amount in excess of benefits associated with the new wind and
8 tansmission deferred for recovery in this rate case (see adjustment 8.16 described
9 below).
l0 a. Why is the Company separately addressing the RTM in this case?
I I A. As part of stipulations in the Energy Vision 2020 cases, the parties agreed that the use
12 of the RTM would be re-evaluated as part of the next general rate case.6 The Company
13 has included ttre costs and benefits of each of the Energy Vision 2020 Projects in the
14 revenue requirement calculated as part of this case and proposes to discontinue the
t5 RTM deferral upon the rate effective date of this case.
16 a. Since the RTM would capture annual changes in revenue requirement as a result
17 of the Energy Vision 2020 Projects, why is the Company proposing to discontinue
18 this mechanism?
19 A. Although the Company is supportive of 100 percent recovery of the Idaho-allocated
20 revenue requirement, continuation of the RTM mechanism would result in on-going
2l recovery of the capital components of only the Energy Msion 2020 Projects while
2? excluding recovery of any other changes to capital components. For example, the
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6 Repowering Order at3: New Wind and Transmission Order at ll
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Company continually makes investment in generation, fansmission, and distribution
resources for system load and reliability. These new investrnents will more than offset
any declining balance of Energy Vision 2020 investments due to depreciation. Once
the Energy Vision 202O Projects are included in base rates the Company does not
believe they should be teated differently than other rate base items. If a tracking
method is implemented, it should be an annual tracking mechanism for full recovery of
all capital related costs.
Does the Company have any other concerns with continuing the RTM for Energy
Vision 2020 Projects?
Yes. The Energy Vision 2020 Projects are included in LCAR described later in my
testimony. Since they are included in the calculation of the LCA& the amount included
in rates will vary every year making any future calculations of the RTM unusually
complex.
Why did the Company seek to establish the RTM only for Energy Yision 2020
Projects and not all capital resources?
Energy Vision 2020 was an opportunity to construct zero-fuel cost resources to help
meet a system need while providing customers significant PTCs benefits. While the
benefits of the NPC and PTCs are considered variable costs and included in the
Company's ECAM mechanism, the substantial fixed capital costs associated with these
projects would have been left unrecovered. Due to the magnitude of investment
required in the Energy Vision 2020 Projects, leaving this capital cost unrecovered
would have resulted in a negative financial impact. Additionally, the timing of the
investments going into service over two years would have necessitated back-to-back
McDougal, Di - 17
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rates cases to incorporate them into base rates. The RTM matched the customer benefits
with the costs required to generate them and smoothed customer rate impacts by
allowing the Company to consolidate the key case drivers into one rate case.
More commonly, the Company makes inveshnent in capital resources at arate
that mimics depreciation expense. In other words, the investment in capital is being
largely offset by the accumulated depreciation balance. Table 2 below illusffates that
the growth in net plant has historically been around 1 percent annually, however, the
increase is much higher recently due to the investment in the Energy Vision 2020
projects.
TABLE 2
$ - Millions
Gross EPIS
Accum. Depr.
Net Plant
% Change from Prer,ious Year
GRC'
20t8 ROO 2017 ROO 2016 ROO 20t5 ROO 2014 ROO
Prc,hrma 2019 Pro-Forma 201 8 Pto-latma 2017 Pro-furma 201 6 Pro-Forma 201 5
1,741 $ 1,737$ 1,656S 1,605$ 1,552S 1,524
(s23) (s83) (554) (516) (480) (4651
1,218$ 1,155$ 1,102$ 1,089$ 1,073$ 1,059
5.2206 4.550h 1_19% 1.48Yo 1.30Yo
$
6
'The Companyprepared a general rate case filed in Prc-E-20-03 in lieu ottre 2019 Resulb otOperatjons
Would the continued use of the RTM impact the timing of future rate cases?
Yes. The RTM only captures a limited portion of the Company's net plant in service,
and the portion it captures is likely to decline over time rather than increase consistent
with the total Idaho net plant as shown in Table 2 above. This disparity, with total Idaho
net plant increasing and the RTM only capturing decreases would increase the impact
of lag on the Company and would force the Company to file more frequent rate cases,
which is in contrast to one of the reasons supporting the RTM-the ability to avoid
more frequent rate cases.
What is the Company's recommendation regarding the RTM?
The Company recommends that the RTM be discontinued with the rate effective date
of this case. Between rate cases the RTM is an important tool to balance the costs and
McDougal, Di - 18
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10 0.
11 A.
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I benefits of new resources. Without the RTM, customers would get the NPC benefrts of
2 low or zero cost resources along with the PTC benefits and any REC sales, without the
3 opportunity for the Company to get recovery of the costs necessary for customers to
4 receive those benefits without a rate case. Once new projects are included in a rate case,
5 they should be heated similar to all other existing resources.
6 Cholla Plant Retirement
7 Q. How is the retirement of Cholla Unit 4 reflected in the Test Period in this case?
8 A. Cholla Unit 4 was retired December 3l,zoz0.Accordingly, the Company has reflected
9 the removal of the on-going operations of the plant. The Company received
10 authorization in Case No. PAC-E-20-03 to defer to a regulatory asset balances
11 associated with the unrecovered plant investment, closure costs, and decommissioning
12 costs. Case No. PAC-E-20-03 approved use of deferred TCJA funds to offset the
13 remaining net plant investment, however, additional details regarding the Company's
14 proposed treatment, including the buy-down using the TCJA regulatory liability
15 balances for the remaining costs, are discussed elsewhere in my testimony.
l6 Carbon Plant
17 a. How is the Carbon plant closure treated in this case?
I 8 A. As described in the Company's application in Case No. PAC-E- 12-08, the Carbon plant
19 (a coal-fired generation facility located in Carbon County, Utah) was retired in
20 April2015, to comply with environmental and air quality regulations. The Company
2l requested a deferred accounting order to transfer the remaining net plant balance to a
22 regulatory asset and amortize through calendar year 2020. The Company further
23 requested to transfe,r the decommissioning costs to a regulatory asset for future
McDougal, Di - 19
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I recovery which was approved in Order No. 32701. The Company is, in this case,
2 seeking to recover the remaining deferred closure costs which include the final
3 decommissioning costs and material and supplies inventory. Further details of this
4 adjustment are described later in my testimony.
5 Deer Creek Mine
6 a. How is the2014 closure of the Deer Creek mine treated in this case?
7 A. In Case No. PAC-E-14-10, the Company filed a notice of closure and requested an
8 accounting order to defer costs associated with the closure of the Deer Creek Mine. The
9 Commission issued an order that allowed continued recovery of the undepreciated mine
10 investment at the then current depreciation rates through the ECAM. Ail other costs
11 associated with the closure of the mine were approved to be deferred to a regulatory
12 asset with recovery treafinent determined in the next general rate case. The Company
13 is proposing to recover the remaining Deer Creek costs that have been deferred to
14 regulatory assets. Additional details including the regulatory treatrnent proposed in this
15 case are provided later in my testimony.
16 Klamath
1,7 a. What changes are reflected in this case for the Klamath Hydroelectric Facilities?
18 A. PacifiCorp is a signatory to the Klamath Hydroelectric Settlement Agreement
19 ("KHSA"), which provides for the transfer PacifiCorp's license for four main-stem
20 Klamath Hydroelectric Project facilities to a third-parg dam removal entity.
21 Depreciation rates for the Klamath assets were approved by the Commission as part of
22 the depreciation study settlement in Case No. PAC-E-13-02 ("2013 Depreciation
23 Study") to provide for full depreciation of the Klamath assets by December 31, 2022.
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FERC is currently evaluating an application to transfer the license for the Lower
Klamath Project from PacifrCorp to the Klamath River Renewal Corporation and the
States of California and Oregon as co-licensees. FERC is also evaluating an application
by PacifiCorp and the Klamath River Renewal Corporation to surrender the license for
the Lower Klamath Project and remove the developments. The timing of when FERC
will transfer the license, when Paci{iCorp's operations would ultimately cease, and
when dam removal will begin remains uncertain.
As the current project licensee, PacifiCorp's obligations under the license and
FERC regulations continue to require capital investrnents to support ongoing project
operations, ensure compliance with dam safety and other regulatory requirements, and
to make other capital expenditures necessary to fuIfilI obligations under the KHSA to
mitigate impacts of ongoing project operations.
Because the timing of license ffansfer and the cessation of generation from the
Klamath assets remains uncertain, PacifiCorp has selected a depreciation rate of
20 percent per year for ongoing capital additions to the Klamath asset starting on
January l,2020- PacifiCorp will seek regulatory approval to update the depreciation
rate in the next depreciation study.
Are the costs of the Klamath facility considered final?
No. The Company has accrued an estimate for future decommissioning costs; however,
this amount was removed from this case as it is a high-level estimate. The Company
will seek to include decommissioning costs, likely in a future general rate case or other
regulatory proceeding, for recovery once more information is known.
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I 2018 Depreciation Study
2 Q. Were the results of the 2018 Depreciation Study included in the case?
3 A. Yes. The Company filed an application to update depreciation rates with a proposed
4 rate effective date of January 1,2021, in Case No. PAC-E-18-08 ("2018 Depreciation
5 Study").' On June 15, 2020, the Company filed a Stipulation for Phase I, new
6 depreciation rates, and requested that the Commission establish Phase II to facilitate
7 additional discussion on the treatment of the incremental costs identified in the 2020
S decommissioning studies.8 On August 18, 2020, the Commission approved the
9 depreciation rates as filed in the Stipulation and authorized Phase II.e This case includes
10 depreciation rates consistent with the settlement stipulation.
11 O. Are any other changes being proposed with regard to depreciation rates?
12 A. The Company is also proposing to include updated incremental decommissioning costs
13 which is discussed later in my testimony.
14 Lake Side 2
15 a. Is the Company currently recovering costs for Lake Side 2?
16 A. Yes. On March l, 2013, the Company filed an application requesting that the
17 Commission open a case to identifu interested parties that would like to participate in
18 settlement discussions regarding alternatives to the Company frling a general rate case.
19 One of the outcomes from that case was an all-party settlement that included a resource
20 adder for the Lake Side 2 generation facility recovered through the ECAM for the
7In the Matter of theApplication of Rocky Mountain Power forAuthorization to Change Depreciation Rates
Applicable to Electric Property, Case No. PAC-E- 18-08, Rocky Mountain Power's Application (Sept. I I , 201 8).
8 Case No. PAC-E-18-08, Stipulation on Depreciation Rate Changes (June 15, 2020).
e Case No. PAC-E-I8-08, Order No. 34754 (Aug. 18, 2020).
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I period that the investment in the facility is not reflected in rates as a component of rate
2 base, beginningJanuary 1,2015.
3 Q. How is Lake Side 2 treated in this frling?
4 A. Since Lake Side 2 was placed in-service in 2014, prior to the base period used in this
5 rate case, it is included in the unadjusted results of operations. The Lake Side 2 adder
6 will not be included in the ECAM deferrals after the rate effective date of this case.
7 Load ChangeAdjustment Rate ((LCAR')
8 Q. Has the Company updated the calculation of the LCAR that is applied to the
9 calculation of net power costs to be recovered through the ECAM?
10 A. Yes. Exhibit 44 provides the calculation of the LCAR. To calculate the LCAR I have
l l incorporated the applicable elements from this case, including production-related
12 retum on investment and non-NPC expenses, into the template approved by the
13 Commission in Case No. PAC-E-08-08. The LCAR itself does not affect revenue
14 requirement in this case but is applied to the difference of Idaho load in this case and
15 actual Idaho load with the result deferred and recovered through the ECAM. The LCAR
16 is to be updated each time base net power costs are updated in a general rate case. Using
L7 the revenue requirement in the Company's filing results in an increase in the LCAR
18 from $5.54 per MWh to $8.59 per MWh. The Company will also provide an updated
l9 calculation of this rate based on the Commission-approved outcome of this case.
20 VII. IDAHO RESULTS OF OPERATIONS
2l a. Please describe Exhibit No.40.
22 A. Exhibit No. 40, which was prepared under my direction, is Rocky Mountain Power's
23 Idaho results of operations report (the "Report"). The historical period for the Report
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is the 12 months ended December 31,2020, which has been adjusted for known and
measurable changes through December 31, 2021. The Report provides totals for
revenue, expenses, net power costs, depreciation, taxes, rate base and loads in the Test
Period. The Report presents operating results for the period in terms of both return on
rate base and ROE.
Please describe how Exhibit No. 40 is organized.
The Report is organized into sections marked with tabs as follows:
. Tab I Summary contains a sumrnary of normalized Idaho-allocated results
of operations.
. Tab 2 Results of Operations details the Company's overall revenue
requiranent, showing unadjusted costs for the year ended December 2020
and fully normalized results of operations for the Test Period by FERC
account.
. Thbs 3 through 8 provide supporting documentation for the normalizing
adjustments required to reflect on-going costs of the Company. Each of
these sections begins with a numerical sunmary that identifies each
adjustnent made to the 2A20 actual results and the adjustment's impact on
the case. Each column has a numerical reference to a corresponding page in
Exhibit No. 40, which contains a lead sheet showing the adjusted FERC
account(s), allocation factor, dollar amount and a brief description of the
adjustnent. The specific adjustments included in each of these tab sections
are described in more detail below.
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I o Tab 9 contains the calculation of the 2020 Protocol allocation factors as well
2 as the development of peak and energy loads.
3 Tab 3 - Revenue Adjustments
4 a. Please describe the adjustments made to revenue in Thb 3.
5 A. Temperature Normalization (page 3.1) - This adjustment recalculates Idaho revenue
6 based on temperature normalized historical load assuming average temperature
7 patterns.
8 Revenue Normalization (page 3.2) - This adjustrnent normalizes base year revenue
9 by removing items that should not be included to determine retail rates, such as ECAM
10 revenues, normalization of special contracts, etc. Full detail of each item excluded in
I 1 this adjustment can be found on page 3.1.3 and 3.1.4 of Exhibit No. 40.
12 Revenue Annualization (page 3.3) - This adjustment annualizes the revenues for the
13 differences betru,,een the actual revenues from the customer billing system and the
14 calculated revenue based on the billing determinants.
l5 REC Revenues (page 3.4) * RECs represent the environmenal attributes of electricity
16 produced from renewable energy facilities and can be detached from the electricity
L7 commodity and sold separately. RECs may also be used to meet renewable portfolio
18 standards ("RPS"; in various states. To comply with current or future year RPS
19 requirements in California, Oregon, and Washington, the Company does not sell RECs
20 that are eligible for RPS requirements in those states. This adjustnent ensures Base
2l Period REC revenues are correctly allocated among the Company's jurisdictions after
22 considering the banking of eligible RECs for RPS compliance purposes. Any
23 differences between the projected REC revenues in this adjustment and actual REC
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revenues, including any sales associated with the new wind projects, will be accounted
for in the Company's ECAM filings as ordered by the Idaho Commission in Order No.
32196, Case No. PAC-E-10-07.
In addition, this adjustrnent also removes REC deferrals reflected in the Base
Period results consistent with the treafrnent of NPC deferrals in the Net Power Cost
Adjustment, No. 5.1 and includes the retirement of RECs associated with the Bayer
contract. Bayer RECs are retired based on a ratio of the Idaho System Generation
allocation factor and a calculated Bayer specific System Generation allocation factor.
Wheeling Revenue (page 3.5) - During 2020, there were various transactions
regarding wheeling revenue that the Company does not expect to occur in the Test
Period. These transactions relate to various prior period adjustnents and contract
terminations. This adjustnent also includes pro forma wheeling revenue for the Test
Period.
Ancillary Services and Other Revenue (page 3.6) - This adjustment reflects ancillary
revenue changes that are consistent with the forecast NPC treatment reflected in
adjustment 5.1 discussed below. The ancillary revenue booked in the 12 months ended
December 2020 is adjusted to reflect the Test Period revenue expected per the terms of
contracts in effect during the Test Period. Ancillary revenue contracts expected to
terminate in the Test Period are normalized out to reflect appropriate revenues
consistent with the proposed rate effective date.
Joint Use Revenue Gage 3.7) - The Company entered into an agreement with ExteNet
and Cingular Wireless to attach wireless devices to Company owned assets. This
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1 adjustment adds into results the joint use revenues expected to be realized during the
2 Test Period.
3 Ash Sales Revenue (page 3.8) - In October 2020, the Company executed a new
4 contract to sale ash from the Jim Bridger plant. This adjustment reflects the revised
5 level of ash sales revenues consistent with the terms of the contract. In addition, this
6 adjustrnent also normalizes ash sale revenues on the Craig, Naughton, and Cholla plant
7 tfl the Test Period.
8 Tab4-O&MAdjustments
9 a. Please describe the adjustments made to O&M expense in Tab 4.
10 A. Miscellaneous General Expense & Revenue (page 4.1) - This adjustment removes
11 from the Base Period results certain miscellaneous expenses that should have been
l2 charged below-the-line to non-regulated accounts or were related to prior periods. It
13 also reallocates gains and losses on property sales to reflect the appropriate allocation.
14 Wages and Employee Benefits (page 4.2) - Labor related costs for the Test Period are
15 computed by adjusting salaries, incentives, health benefits, and costs associated with
16 pension, post-retirement benefits, post-employment benefits, and other benefits for
17 changes expected beyond the actual costs experienced in the Base Period.
18 Collective bargaining agreements are used to escalate union wages where
19 increases are specified, and other wage increases for non-union and exempt employees
20 are based on the Company's targets. Annual incentive plan compansation and bonuses
21 and awards for non-union employees is included in Test Period results using a three-
22 year average of the actual cash payout. Other employee benefit costs are adjusted to the
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planned expense levels for the Test Period, based on actuarial reports, where available,
or by escalating actual costs.
Page 4.2.1 of the Report provides ftrther description of the procedure used to
compute Test Period labor costs. Page 4.2.2 contains a numerical summary of actual
labor costs in the Base Period and summarizes the adjusfrnents made to project costs
through the Test Period. This summary is followed by detailed worksheets on pages
4.2.3 through 4.2.11.
Remove Non-Recurring Entries (page 4.3) - Two accounting entries were made to
an expense account during the Base Period that are non-recurring in nature. The first
entry relates to reliability coordinator fees and represent a refund that was for calendar
year 2Ol9 expenses. The second entry relates to a Klamath Settlement Obligation
expense which was described earlier in my testimony. These entries are removed to
normalize Test Period results.
Schedule 300 Fees and Paperless Billing (page 4.4) - This adjustment adds into the
Test Period results the pro forma reduction to revenues for the proposed paperless bill
credits. This adjustnent also adds into the Test Period results the pro-forma increase to
revenues for the changes to the returned check fees and temporary service charges. For
details on these proposals, please refer to the testimony of Ms. Melissa S. Nottingham.
Outside Services (page 4.5) - The Company adjusted the 2020 outside services
expense to a three-year historical average consistent with the Commission's Order No.
32196.
Generation Expense Normalization (page 4.6) - This adjustment normalizes
generation overhaul expense using a four-year historical average using the l2-month
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periods ending December 2017 through December 2020. Awrual expense is restated to
December 2020 dollars prior to averaging. A four-year average is consistent with the
normalized outages assumed in the GRID model to compute Test Period NPC.
Use of a four-year historical average to set overhaul costs in customer rates was
consistent with the treatment used in several of the Company's Idaho general rate cases.
However, the Company agreed in the rebuttal testimony in Case No. PAC-E-10-07 to
remove the restatement to constant dollars. The Company continues to believe that the
purpose of averaging is to adjust for uneven costs, and that without the restatement to
constant dollars in the average calculation, overhaul expenses reflected in rates will be
systematically understated. More specifically, averaging is intended to reduce year-to-
year variance in expense, but not adjust for the time value of money and the issue of
inflation.
A simple example below shows the impact of averaging, assuming a 2.5 percent
inflation rate, a $100 amount in year one, and a four-year average of years one through
four used to project costs in year five. Using this assumption, Example I shows the
impact without adjusting for inflation and Example 2 shows the impact when years one
through four are stated in real or constant dollars.
As shown in the first example, with no restatement to account for inflation, a
four-year average of costs is $103.8, much less than the projected costs in year five,
resulting in an expense level that is 2.5 years old compared to the current expenses. In
Example 2, the ayerage is equal to the year five amount resulting in an accurate
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I forecast.
Etarple I €xample 2
Ys*r fir*ount
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fnsurance Expense (page 4.7) - This adjustment normalizes insurance expeose related
to third-party liability, less amounts not requested, for injuries and damages as well as
damage to Company property. Injury and damages expense are set at the three-year
historical average using a cash paid method consistent with Idaho's ffeafinent of
pension expense. In the Company's previous general rate case, insurance expense was
normalized using accounting accruals. However, the Company recorded accruals
during the base period that were significantly above historical levels due to several
potential liabilities where the impact is still uncertain. Due to the significant impact
these potential expenses have on results, the Company is proposing to move from a
three-year average using accounting accruals to known cash payments. This change
will make sure that only the amounts above instrance are included in regulatory results,
and the amounts will be included after the amounts are known and actual cash payments
are recorded. This adjustment also removes the insurance reserve associated with the
accounting accruals booked in the Base Period since they are related to the difference
between the accounting accruals and acfual payments.
Insurance expense for damage to Company ffansmission, distribution, and non-
transmission and distribution property is currently accrued to a reserye account. This
ffeatment for property damage expense was included in Case No. PAC-E-I1-12. The
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balance of the reserve account at December 2020 was $1.0 million. This adjustment
updates the property damage accrual to a three-year average of actual losses.
This adjusrnent also addresses the premiums related to general liability and
property insurance which are anticipated to be incurred for coverage during the Test
Period. The current estimates were developed using Company forecasts and will be
updated in rebuttal as actual insurance premiums become known.
Uncollectible Expense (page 4.8) - Consistent with the Commission Order No. 32196,
uncollectible expense is adjusted to a three-year historical average. This adjustnent
also adjusts tansmission power delivery uncollectible expense to a three-year historical
average and normalizes regulatory commission expense consistent with the weather
normalized revenues.
Memberships and Subscriptions (page 4.9) - This adjustment removes expense in
excess of Commission policy as stated in OrderNo.29505. National and regional trade
organizations are recognized at 75 percent of above the line costs. Other membership
dues are removed.
Pension Non-Service Expense (page 4.10) - Pursuant to Idaho Commission Order
No. 32196, this adjustment removes the 2020 accrual basis pension expense for the
PacifiCorp Retirement Plan (PRP) and replaces it with a3-year average on a cash basis.
Also, this adjustment walks forward the Post-Retirement Welfare Plan (PRW) non-
service expense to the 2021 forecast and removes the Supplemental Executive
Retirement Plan (SERP) non-service expense.
Credit Facility F'ees (page 4.11) - The Company incurs banking fees consisting of the
upfront and quarterly commitment fees on revolving credit facilities which support the
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I Company's Commercial Paper issuances by providing a secondary source of repayment
2 for the Commercial Paper. This adjusfinent correctly accounts for these fees.
3 Tab 5 - Net Power Cost Adjustments
4 a. Please describe the adjustments included in Tab 5.
5 A. Net Power Costs (page 5.1) - The net power cost adjustrnent presents normalized Test
6 Period steam and hydro power generation, fuel, purchased powel wheeling expense
7 and sales for resale based on the Company's GRID model. It also normalizes hydro
8 power generation, weather conditions and plant availability as described in Mr.
9 Wilding's testimony.
10 Nodal Pricing (page 5.2) - This adjustrnent adds in pro forma capital and incremental
11 O&M expenses for the new Nodal Pricing Model, as agreed to in PacifiCorp's Nodal
12 Pricing Model Memorandum of Understanding as filed underAppendix D in the 2020
13 Protocol, Case No. PAC-E-I9-20.
14 Tab 6 - Depreciation and Amortization Expense Adjustments
15 O. Please describe the adjustments included in Tab 6.
16 A. Depreciation and Amortization Expense (page 6.1) - This adjustrnent adds into the
17 Test Period results depreciation and amortization expense for the major plant added to
18 rate base in adjustnent 8.5.
19 Depreciation andAmortization Reserve (page 6.2) - This adjustment adds into Test
20 Period results depreciation and amortization reserve for the major plant additions added
2l to rate base in adjustment 8.5.
22 Hydro Decommissioning (page 6.3) - Based on the Company's latest depreciation
23 study approved in Case No. PAC-E-18-08, the annual accrual required for the
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decommissioning of various hydro facilities is being reduced. The change in hydro
decommissioning expense is included in the Depreciation StudyAdjustment (6.5). This
adjustment includes the change in reserve and walks the reserve balance to the Test
Period.
Depreciation Allocation Correction (page 6.4) - The Company established a
regulatory asset to ffack and defer any aggregate net increase in allocated depreciation
expense in dockets in Wyoming, Utah, and Idaho, for depreciation rates that became
effective January l,20l4, in the 2013 depreciation study. The deferred amount and the
associated amortization is reflected in historical data on a system-allocated basis, but
should be situs-assigned to Wyoming, Utah, and Idaho. This adjustment corrects the
allocation of this historical data. Also, this adjustnent removes the steam plant give-
back reversal in Oregon established as part of the 2013 depreciation study.
New Depreciation Study (page 6.5) - This adjustment incorporates into Test Period
results the incremental impacts of the 2018 deprecation study as agreed in Case No.
PAC-E-18-08. Specifically, this adjustment calculates the incremental difference
between the approved depreciation rates from the last depreciation study and those
approved in the 2018 depreciation study. This incremental difference in the composite
depreciation rate is multiplied by the year-ending December 2020 gross plant balance
to calculate the incremental impact of depreciation expense. The depreciation reserve
associated with the incremental depreciation expense is adjusted for the Test Period. In
addition, this adjustment also incorporates into the Test Period results the amount
associated with the change in hydro decommissioning and vehicle depreciation.
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Ilecommissioning Costs (page 6.6) - On January 17, 2A20, pursuant to the 2020
Protocol, the Company filed a contactor-assisted engineering study of
decommissioning costs ("January 2020 Decommissioning Study") for the Hunter,
Huntington, Dave Johnston, Jim Bridgea Naughton, Wyodak, and Hayden generating
plants in Case No. PAC-E-18-08. On March 16,2020, the Company filed a contractor-
assisted engineering study of decommissioning costs for the Colstrip generating plant
in the same case. These decommissioning costs include plant demolition, ash pile and
ash pond abatement and closure, asbestos and other hazardous materials abatement and
remediation, and final site cleanup and restoration as applicable to each plant. This
adjustment includes the incremental costs by plant beginning with the rate effective
date of the 2018 deprecation study, or January 1,2021, and spread evenly overthe
remaining life of the last retired unit. Parties reached a settlement in Case No. PAC-E-
18-08 to defer the 2021 incremental decommissioning costs to a regulatory asset and
amortize this over 15 years beginning with the rate effective date of this general rate
case. Accordingly, the Company has included this amortization as well as the amount
proposed to be collected in the Test Period. The Company is proposing all amounts
collected will be deferred to a regulatory liability account and will be reduced for actual
decommissioning costs once known.
The studies also identified other plant closure costs that are necessary for the
Company to fully recover all costs associated with closing a plant. For example, each
generation plant has a certain level of materials and supplies inventory that is required
to operate the plant. In the event of a plant closure, those material and supplies will no
longer be required and often cannot be absorbed for use at a different generation facility.
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Given those circumstances, the Company would seek recovery of these unusable
material and supplies inventory in addition to all of the other incurred or expected plant
closure costs at the time a plant is closed. As identified in the decommissioning studies,
there are a significant amount of other plant closure oosts that will need to be addressed
in a future proceeding. No regulatory treatment for recovery of these costs have been
included in this filing.
TabT-TaxAdjustments
a. Please describe the adjustments included in Tab 7.
A. Interest True Up (page 7.1) - This adjustment details the true up to interest expense
required to synchronize the Test Period expense with rate base. This is done by
multiplying normalized net rate base by the Company's weighted cost of debt in this
case
Property Tax Expense (page 7.2\ - Property tax expense for the Test Period was
computed by adjusting calendar year 2020 property tax expense for known and
anticipated changes in assessment levels through the end of the Test Period. Please refer
to Confidential Exhibit No. 42 for details supporting the Test Period expense.
Production Tax Credit (page 7.3) - The Company is entitled to recognize certain tax
credits as a result of placing qualifring renewable generating plants into service. The
federal tax credit is based on the generation of a qualifuing facility during the facility's
first ten years of service. The Test Period renewable electricity production credit is
2.5 cents per kilowatt hour of the electricity produced from wind energy. This
adjustment reflects the credit based on the qualifying production as reflected in the net
power costs adjustment, page 5.1.
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1 PowerThx ADIT Balance (page 7.4\ - This adjustment reflects the accumulated
2 deferred income tax balances for property on a jurisdictional basis as maintained in the
3 PowerTax System.
4 Wyoming Wind Generation Tax (page 7.5) - This adjustment normalizes the
5 Wyoming Wind Generation Tax, which became effective January 1,2012, into Test
6 Period results. The Wyoming Wind Generation Tax is an excise tax levied upon
7 production of electricity from wind resources in the state of Wyoming. The tax is on
8 the production of any electricity produced from wind resources for sale or trade on or
9 after January 1,2012 and is to be paid by the entity producing the electricity. New wind
10 facilities are exempt from the tax for three years following the date the facility first
11 produces electricity for sale. The tax is one dollar for each megawatt-hour of electricity
12 produced from wind resources at the point of interconnection with an electric
13 transmission line.
14 TCJA Tax Deferrals (page 7,6) - This adjustrnent reflects the removal of the Non-
15 Protected tax deferral balances as a result of the TCJA that was enacted on December
16 22,2017. This adjusftnent also reflects the appropriate level of protected EDIT
17 amortization using the RSGM.
18 Thb 8 - Rate Base Adjustments
19 0. Please describe the adjustments included in Tab 8.
20 A. Update Cash Working Capital (page 8.1) - This adjusfrnent supports the calculation
2l of cash working capital based on the normalized results of operations for the Test
22 Period. Cash working capital is calculated by multiplying jurisdictional net lag days by
23 the average daily cost of service. Net lag days in this case are based on a lead lag study
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prepared by the Company using calendar year 2015 information. Based on the results
of the lead lag study the Company experiences 0.68 net lag days in Idaho and requires
a cash working capital balance of $0.4 million in rate base.
Trapper Mine Rate Base (page 8.2) - The Company owns a29.0 percent share of the
Trapper Mine, which provides coal to the Craig generating plant. This investment is
accounted for on the Company's books in account 123.1, investnent in subsidiary
company, which is not included as a rate base account. The normalized coal cost from
Trapper Mine in netpower costs includes operation and maintenance costs but does not
include a return on investment. This adjustrnent adds the Company's portion of the
Tiapper Mine net plant invesment to rate base in order for the Company to earn a return
on its investrnent.
Jim Bridger Mine Rate Base (page 8.3) - The Company owns a trvo-thirds interest
in the Bridger Coal Company which supplies coal to the Jim Bridger generating plant.
Due to the ownership arrangement, the mine invesftnent is not included in the
Company's unadjusted results of operations, and the normalized coal costs for Bridger
include all operating and maintenance costs but do not include a return on investment.
This adjustment adds the Company's portion of the Bridger Mine net plant investment
to rate base in order for the Company to eam a return on its investment.
Customer Advances for Construction (page 8.4) - Refundable customer advances
for construction are booked to FERC account 252.Base Period balances do not reflect
the proper allocation because amounts were recorded to a corporate cost center location
rather than state specific locations in the Company's accounting system. This
adjustment corrects the allocation of customer advances.
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Major Plant Additions (page 8.5) - To reasonably represent the cost of system
infrastnrcture required to serve our customers, the Company has identified capital
projects that will be completed by the end of the Test Period. The Company identified
capital projects with expenditures over $5 million that will be used and useful by
December 31,2A21. Additions by firnctional category are summarized on separate
sheets, indicating the in-service date and amount by project. The associated
depreciation expense and accumulated reserve impacts are accounted for in adjustrnent
6.1 and 6.2. Capital additions associated with the Energy Vision 2020, Pryor Mountain,
and Foote Creek projects are included under adjustment 8.15 discussed later in my
testimony.
Miscellaneous Rate Base (page 8.6) - This adjustnent reflects the Test Period level
of fuel stock balance in results based on projected inventory by plant, along with
offsetting working capital deposits. In addition, prepaid overhaul balances in FERC
Account 186 for Lake Side Units I and1, Chehalis, and Currant Creek gas plants are
walked forward to reflect the continued payments and the transfer of these costs into
plant in-service through the end of the Test Period.
Powerdale Hydro Decommission (page 8.7) - Powerdale is a hydroelectric
generating facility located on the Hood River in Oregon. This facility was scheduled to
be decommissioned in 2010; however, in 2006 a flash flood washed out a major section
of the flow line. The Company determined that the cost to repair this facility was not
economical and determined it was in the ratepayers'best interest to cease operation of
the facility.
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The Commission approvedl0 the Company to defer to a regulatory asset any
actual decommissioning costs and amortize these balances over ten years. Final
decommissioning costs were spent in December 2013. At the end of 2O?1, the
Company had an estimated Idaho-allocated balance of $2.4 thousand to be collected.
The Company has proposed to buy-down this remaining balance using deferred
balances from the Tax Cuts and Jobs Act. This adjustment removes any balances related
to remaining Powerdale Hydro decommissioning.
FERC 105 (PHFU) (page 8.8) - This adjustment removes all plant held for future use
("PHFLJ"') assets from FERC account 105. The Company is making this adjustment in
compliance with Idaho Code $61-5024.
Regulatory Asset and Liability Amortization (page 8.9) - This adjustment
incorporates known and measurable changes to regulatory assets and liabilities from
the Base Period to the Test Period. Impacted regulatory assets and liabilities include the
electic plant acquisition adjusftnent, Trojan decommissioning costs, and the balance
associated with the deferred depreciation from the 2013 depreciation study. This
adjustment also includes the Company's proposal to fully amortize the balances
associated with the electric plant acquisition adjustment specific to the Craig and
Hayden plants, 2017 Protocol equalization deferral, and deferred intervenor funding.
Lastly, the approved 2018 depreciation study included a change in depreciation rates
effective January l, 2021. In a settlement reached in that case, the Company was
approved to defer the costs associated with the change in depreciation expense and
elimination of the excess reserve amortizations, or approximately $13.9 million on an
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Idaho-allocated basis. This adjustment also adds into results a four-year amortization
of the 2018 Depreciation Study deferral balance.
Klamath Hydroelectric Settlement Agreement (Page 8.10) - This adjustment
reflects the appropriate treatment ofKlamathrelated items in the Test Period. Paragraph
24 of the stipulation in the 2013 depreciation study, specifies that the stipulating parties
agree to adjust Klamath accelerated depreciation to an end date of December 31, 2022.
This adjustment also adds in the expense and rate base amounts associated with on-
going capital additions based on the proposed treatment discussed previously in my
testimony.
Cholla 4 (page 8.11) - Consistent with the Company's 2019 Integrated Resource Plan,
Cholla Unit 4 (a coal-fired generation facility located in Joseph Ciry Arizona) ceased
operations December 31,2020. The Commission approved the Company's application
in Case No. PAC-E-20-03 to transfer the remaining balances to a regulatory ilsset and
buy-down, on December 31, 2020, the remaining net plant balance with the deferred
regulatory liability balances that were established with the TCJA. In addition to the
remaining plant balances, below are additional costs related to the Cholla Unit 4
closure. The Company is proposing to buy-down the remaining balances associated
with the closure of Cholla Unit 4 using TCJA amounts.
. Approximately $1.0 million, total-Company, of Construction Work in Progress
that are assumed no longer necessary given the revised retirement date of the
plant;
. Approximately $5.9 million, total-Company, of materials and supplies that are
deemed to be specific to the plant and unusable after retirement of the plant;
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. Approximately $19.6 million, total-Company, of liquidated damages as aresult
of issuing the 365-day notice to Peabody Energy for early termination of the
Coal SupplyAgreement;
. Approximately $2.1 million, total-Company, of severance pay;
. Approximately $47.3 million, total-Company, of decommissioning costs; and
. Approximately $0.8 million, total-Company, of a GE safe harbor lease
termination payment required due to early closure of the plant.
Per the terms of the stipulation, this adjustment has included an offset of approximately
$28.1 million, total-Company, related to the operations and maintenance expense that
was included in customer rates but no longer necessary. The Company agreed to include
an offset related to avoided depreciation expense, however, that has been accounted for
in the depreciation deferral as approved in Case No. PAC-E.18-08. This adjustment
removes from rate base the December 31,2020 plant balances related to Cholla Unit 4
and regulatory asset balances due to the proposed buy-downs. It also removes from
expense the cost related to the operations and maintenance and depreciation of this
generation resource. For additional details on the closure of the Cholla Unit 4 plant,
please refer to the testimony of Mr. Link.
Carbon Plant Closure (page 8.12) - As described earlier in my testimony, the Carbon
plant was retired in April 2015 to comply with environmental and air quality
regulations. A deferred accounting order was approved in which the Company could
seek recovery ofthese costs in the next general rate case. This adjusnnent adds in Test
Period results the associated impacts for recovery of the deferred balances associated
with decommissioning costs and obsolete materials and supplies. The Company is
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proposing, in this case, to amortize these balances over three years. Additionally, this
adjustment removes from the base period the expense associated with a regulatory asset
that was established to track and defer any aggregate net increase in allocated
depreciation expense in dockets in Wyoming, Utah, and Idaho for depreciation rates
that became effective January 1,2014-
Prepaid Pension Asset (page 8.13) - This adjustment removes from the Base Period
the rate base balances associated with the prepaid pension asset. Idaho currently
recovers pension costs using a cash basis method which is adjusted for on page 4.10.
Deer Creek Mine (page 8.14) - As described in the Company's filing in Case No.
PAC-E-14-10, the Deer Creek mine (a coal mine located in Emery County, Utah) was
closed at the end of 2014. The Company reached a settlement in which approval was
requested for the following:
. Transfer the remaining net book value, excluding CWIP, to a regulatory asset
and continue to recover the balance at an amortization rate equal to the then
current depreciation rates;
. Transfer the loss related to the sale of the Cottonwood Preparation Plant, the
Central Warehouse, and the Trail Mountain Mine to a regulatory asset and
continue to recover the balance at an amortizationrate equal to the then current
depreciation rate;
. lnclude an offset at the approved rate of return on rate base for the Fossil Rock
coal leases, fuel inventory savings, and the return on assets sold;
. Defer balances associated with the settlement of the Retiree Medical
Obligation; and
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. Defer to a regulatory asset amounts associated with the closure costs and CWIP
of the Deer Creek Mine.
This adjustment corrects the Base Period to reflect removal of amounts associated
with recovery of the Deer Creek Mine which should have been booked situs to other
states or have been recovered from Idaho customers. As described above, unrecovered
plant has been fully amortized. The Company is including in this case all other mine
closure costs and savings that have been deferred. The Company is proposing to include
all defened costs and savings as a result of the mine closure in rate base to be amortized
over three years.
New Wind and Repowering Capital Additions (Page 8.f0 - This adjustnoent adds
into the Test Period the capital additions, depreciation impacts, and changes in
operations and maintenance expense for the Energy Vision 2020 Projects and Pryor
Mountain, discussed previously in my testimony. The adjustrnent also adds into the Test
Period the capital addition and associated depreciation impacts for the Foote Creek I
wind repowering project which went in-service in March 2021. For additional details
on these projects, please refer to the testimonies of Mr. Hemsffeet, Mr. Van
Engelenhoven, and Mr. Vail.
RTM Adjustment (page 8.16) - Per Case No. PAC-E-17-06 and PAC-E-17-07, the
Commission approved deferral to a regulatory asset any costs related to the Repowering
and Energy Vision 2020 Projects above the cap, which was set not to exceed the project
benefits. Accordingly, the Company has calculated that all repowering projects will be
fully recovered in the ECAM. The Energy Vision 2020 Projects, notably due to the
necessary transmission investment, have costs more than the benefits included in the
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ECAM used to establish the cap, which the Company is seeking to recover in this case.
Using forecasted balances and generation data, the Company has calculated a total
regulatory asset balance of approximately $ 1.6 million, Idaho-allocated, as the end of
2021. This adjustnent adds into rate base the regulatory asset balance and a three-year
amortization. The Company will true-up any differences between the actual deferred
balances and estimated deferred balances in the next general rate case.
VtrI. STIMMARY
Do you have any linal comments regarding the revenue requirement requested by
the Company in this proceeding?
Yes. In my opinion, the revenue requirement requested in this proceeding is fair,
reasonable and in the public interest. I respectfully recommend that the Commission
approve the revenue requirement as proposed in this testimony.
Does this conclude your direct testimony?
Yes.
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