HomeMy WebLinkAbout20220216Larkin Supplemental Direct.pdf
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER
COMPANY’S APPLICATION FOR
AUTHORITY TO INCREASE ITS RATES
FOR ELECTRIC SERVICE TO RECOVER
COSTS ASSOCIATED WITH THE JIM
BRIDGER POWER PLANT.
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CASE NO. IPC-E-21-17
IDAHO POWER COMPANY
SUPPLEMENTAL DIRECT TESTIMONY
OF
MATTHEW T. LARKIN
LARKIN, SUPP DI 1
Idaho Power Company
Q. Please state your name, business address, and 1
present position with Idaho Power Company (“Idaho Power” or 2
“Company”). 3
A. My name is Matthew T. Larkin. My business 4
address is 1221 West Idaho Street, Boise, Idaho 83702. I 5
am employed by Idaho Power as the Revenue Requirement 6
Senior Manager in the Regulatory Affairs Department. 7
Q. Have you previously submitted direct testimony 8
before the Idaho Public Utilities Commission (“Commission”) 9
in this proceeding? 10
A. Yes, I submitted direct testimony on June 2, 11
2021, discussing why the depreciable date of 2030 for the 12
Jim Bridger Power Plant (“Bridger”) is appropriate and why 13
the Bridger depreciation schedule for ratemaking purposes 14
should be accelerated at this time. In addition, my direct 15
testimony detailed the proposed balancing account intended 16
to recover incremental costs and benefits associated with 17
Idaho Power’s assumed exit in participation of operations 18
at Bridger including a quantification of a proposed 19
increase to base rate revenue of approximately $30.83 20
million, or 2.53 percent, to become effective December 1, 21
2021. Finally, my testimony concluded with a summary of 22
why the Company’s request is in the public interest. 23
Q. What is the purpose of your supplemental 24
testimony in this matter? 25
LARKIN, SUPP DI 2
Idaho Power Company
A. The purpose of my supplemental testimony is to 1
address changes in the Company’s initial request made in 2
response to events that occurred after my direct testimony 3
was filed in June 2021. I present an amended 4
quantification of the Bridger levelized revenue requirement 5
that includes only coal-related assets, and removes from 6
the original request all natural gas-related assets and 7
associated costs according to the planned natural gas 8
conversion of Bridger Units 1 and 2 presented in the 9
Company’s 2021 Integrated Resource Plan (“IRP”). My 10
supplemental testimony also presents the Company’s proposed 11
amended base rate revenue increase of $27.13 million, or 12
2.12 percent, to become effective June 1, 2022. 13
Q. How is your supplemental testimony organized? 14
A. My supplemental direct testimony will describe 15
recent actions that affect future Bridger operations and 16
support a restart of the procedural schedule in this 17
proceeding. I will provide an update on the status of 18
ongoing Bridger Regional Haze compliance discussions and 19
the potential option of converting Units 1 and 2 to natural 20
gas generation. I will also detail the Company’s revised 21
quantification of the proposed increase to customer rates 22
resulting from improved clarity around future Bridger 23
operations. 24
LARKIN, SUPP DI 3
Idaho Power Company
Q. When did the Commission suspend the procedural 1
schedule in this case? 2
A. On October 1, 2021, Idaho Power and Commission 3
Staff filed a Joint Motion to Suspend Procedural Schedule 4
due to lack of clarity concerning Bridger emission limits 5
and possible coal-to-gas unit conversions. At the time, 6
the U.S. Environmental Protection Agency (“EPA”) had not 7
taken formal action responding to Wyoming’s proposed State 8
Implementation Plan (“SIP”) Revision, which would ensure 9
Regional Haze compliance of Units 1 and 2 effective January 10
1, 2022. 11
In addition, in September 2021, PacifiCorp submitted 12
to the Commission their 2021 IRP in Case No. IPC-E-21-19. 13
That IRP included an Action Plan envisioning the cessation 14
of coal-fired generation at Units 1 and 2 in 2023 with a 15
natural gas conversion of those units in 2024. On November 16
17, 2021, the Commission issued Order No. 35222, suspending 17
the procedural schedule until the Company filed an update 18
or requested to set the procedural schedule no later than 19
December 31, 2021. 20
Q. Did Idaho Power file a Bridger status update 21
with the Commission? 22
A. Yes. On December 30, 2021, the Company filed 23
an update with the Commission, notifying the parties that 24
the EPA had not yet formally acted on Wyoming’s SIP 25
LARKIN, SUPP DI 4
Idaho Power Company
Revision which otherwise would require emission controls to 1
be in place for Unit 2 by December 31, 2021, and for Unit 1 2
by December 31, 2022. In the status update, Idaho Power 3
explained that on December 27, 2021, Wyoming Governor Mark 4
Gordon issued a temporary emergency suspension, extending 5
the compliance date of Unit 2 through April 30, 2022, while 6
PacifiCorp awaits approval of the Wyoming SIP Revision. 7
Q. Did the Company address resuming the 8
procedural schedule in this proceeding in the status 9
update? 10
A. Yes. At the time, the EPA, Wyoming Department 11
of Environmental Quality, and PacifiCorp were actively 12
engaged in discussions and felt a potential near-term 13
resolution of the issues existed. Idaho Power requested 14
the Commission continue the current schedule suspension and 15
committed to convene a conference with parties to discuss 16
the reopening of the procedural schedule no later than 17
April 30, 2022. 18
Q. Was a conference held with parties to discuss 19
the reopening of the procedural schedule? 20
A. Yes. On February 7, 2022, the Company met 21
with parties, providing an update on EPA actions regarding 22
Bridger Regional Haze compliance and the results of Idaho 23
Power’s 2021 IRP regarding the potential conversion of 24
Units 1 and 2 to natural gas generation. My testimony will 25
LARKIN, SUPP DI 5
Idaho Power Company
explain in detail both updates and the impact they have on 1
Idaho Power’s request in this proceeding. 2
Q. Do the actions and findings impact the 3
Company’s initial request? 4
A. Yes, the Bridger coal-related investment 5
levelized revenue requirement is approximately $3.70 6
million less than the initial Bridger levelized revenue 7
requirement quantification. 8
Q. What is Idaho Power’s amended request 9
regarding costs associated with Bridger? 10
A. In accordance with the planned natural gas 11
conversion of Units 1 and 2, the Company has removed from 12
the original request all investments and the related 13
deferred taxes that will remain in service for natural gas 14
operations and associated natural-gas related costs. 15
Therefore, Idaho Power is requesting that the Commission 16
authorize Idaho Power to: (1) accelerate the depreciation 17
schedule for all coal-related Bridger investments to allow 18
for full depreciation and recovery by December 31, 2030, 19
(2) establish a balancing account, and the necessary 20
regulatory accounting, to track the incremental costs and 21
benefits associated with Idaho Power’s cessation of 22
participation in coal-fired operations at Bridger, and (3) 23
adjust customer rates to recover the associated incremental 24
annual levelized revenue requirement of $27.13 million with 25
LARKIN, SUPP DI 6
Idaho Power Company
an effective date of June 1, 2022, which equates to an 1
overall increase of 2.12 percent. 2
Q. Do you have any exhibits to your supplemental 3
direct testimony? 4
A. Yes. Exhibit No. 1 to my supplemental direct 5
testimony details the revised derivation of the levelized 6
revenue requirement calculations for coal-related Bridger 7
investments by cost category to be tracked in the balancing 8
account and the Idaho jurisdictional share of the revenue 9
requirement that the Company is proposing to include in 10
customer rates. Exhibit No. 2 details the revised 11
derivation of the Idaho jurisdictional share of the Bridger 12
coal-related investments revenue requirement currently 13
included in customer rates as approved in Case Nos. IPC-E-14
11-08 and GNR-U-18-01. 15
I. BRIDGER ENVIRONMENTAL COMPLIANCE UPDATE 16
Q. What was the status of Bridger’s compliance 17
with Regional Haze at the time the Company filed its 18
request in this proceeding? 19
A. As detailed in the direct testimony of Company 20
witness Ryan N. Adelman, under current environmental 21
regulations, Units 1 and 2 require Selective Catalytic 22
Reduction (“SCR”) controls to be installed and operational 23
by year-end 2022 and 2021, respectively. However, the 24
State of Wyoming had approved a revision to the Wyoming SIP 25
LARKIN, SUPP DI 7
Idaho Power Company
that established emission limitations as a whole in lieu of 1
installing SCR controls on Units 1 and 2. This revision 2
had been proposed to the EPA and submitted to the Office of 3
the Federal Register. At the time of the initial filing in 4
June 2021, Idaho Power and PacifiCorp, Bridger’s co-owners 5
(collectively, the “Co-Owners”) were awaiting action from 6
the EPA. 7
Q. Has the EPA acted upon the proposed revision 8
to the SIP? 9
A. Yes. On January 12, 2022, the EPA issued a 10
proposed rule that, if adopted, would disapprove the 11
proposed SIP Revision. The proposed rule was published in 12
the Federal Register on January 18, 2022. Comments on the 13
proposed disapproval are due by February 17, 2022. 14
Q. Have any additional actions been taken 15
pertaining to environmental compliance of Units 1 and 2? 16
A. Yes. On February 14, 2022, the State of 17
Wyoming filed a complaint against PacifiCorp as well as a 18
negotiated consent decree with PacifiCorp in Wyoming state 19
court for the threat of non-compliant operation of Bridger 20
Units 1 and 2. With respect to the natural gas conversion, 21
the consent decree requires that PacifiCorp submit a 22
revised permit application and request a SIP Revision that 23
would reflect a natural gas conversion of both Units 1 and 24
LARKIN, SUPP DI 8
Idaho Power Company
2, further supporting natural gas operations as a feasible 1
alternative for environmental compliance of Units 1 and 2. 2
Q. Has the Company taken any actions to evaluate 3
alternative solutions to operations of Units 1 and 2 in 4
lieu of emission limitations as a whole? 5
A. Yes. Similar to PacifiCorp, as part of Idaho 6
Power’s 2021 IRP, the Company used AURORA’s Long-Term 7
Capacity Expansion model to determine the best Bridger 8
operating options specific to Idaho Power’s system for all 9
Bridger units, including the cessation of coal-fired 10
generation in Units 1 and 2 in 2023 and conversion to 11
natural gas generation, running them through 2034. 12
II. BRIDGER IN IDAHO POWER’S GENERATION PORTFOLIO 13
Q. Did the position of any of Bridger’s units in 14
Idaho Power’s generation portfolio in the 2021 IRP change 15
as compared to the Second Amended 2019 IRP? 16
A. Yes. As detailed in Mr. Adelman’s direct 17
testimony filed June 2, 2021, the Second Amended 2019 IRP 18
identified a Preferred Portfolio that included early 19
Bridger unit exits in 2022, 2026, 2028, and 2030. The 2021 20
IRP Preferred Portfolio includes the conversion of Units 1 21
and 2 from coal to natural gas by the summer of 2024 with a 22
2034 exit date, and the exit of coal-fired operations in 23
Units 3 and 4 by year-end 2025 and 2028, respectively. 24
With a current depreciable life of 2034, the 2021 IRP 25
LARKIN, SUPP DI 9
Idaho Power Company
continues to indicate that an earlier exit from coal-fired 1
generation at Bridger would provide a more favorable 2
economic outcome as compared to the current end-of-life 3
assumption of 2034. 4
Q. Do the Bridger unit exit dates align with the 5
exit dates identified for PacifiCorp in their 2021 IRP? 6
A. No, not currently. Although the Action Plans 7
of the Co-Owners both include the cessation of coal-fired 8
generation of Units 1 and 2 in 2023 and the conversion to 9
natural gas generation in 2024, PacifiCorp’s 2021 IRP 10
continues to identify differing exit dates for each Bridger 11
unit. In addition, the Co-Owners have not yet developed 12
contractual terms that would be necessary to allow for the 13
potential earlier exit of a Bridger unit by one Co-Owner, 14
and not both Co-Owners. Idaho Power’s 2021 IRP has 15
identified the exit date of each Bridger unit that is the 16
least cost, least risk alternative for the Company’s 17
customers. The differing exit dates of the Co-Owners in 18
their respective 2021 IRPs further emphasizes the 19
importance of putting in place the proposed cost recovery 20
mechanism now to maintain a relatively stable level of 21
annual recovery, even as the underlying cost drivers may 22
change over time. 23
Q. How do the results of the 2021 IRP impact the 24
Company’s request in this proceeding? 25
LARKIN, SUPP DI 10
Idaho Power Company
A. The identification of cessation of coal-fired 1
operations in the Bridger units in 2023, 2025, and 2028, 2
continues to support the impact economic and regulatory 3
factors have on determining Bridger’s actual operating life 4
and the importance of establishing a cost recovery 5
mechanism that can mitigate the rate volatility that could 6
otherwise exist under a more traditional ratemaking 7
approach. With the identification in the 2021 IRP of a 8
conversion of Units 1 and 2 to natural gas in 2024 and 9
operations of those units through year-end 2034— the 10
current depreciable life of the Bridger plant for 11
ratemaking purposes— Idaho Power is proposing to remove 12
from its request in this proceeding the accelerated 13
depreciation associated with any investments that will 14
remain in service after 2028, or once coal-fired generation 15
ceases. Therefore, the Company’s revised request includes 16
the quantification of the levelized revenue requirement of 17
Bridger coal-related investments only. 18
III. REGULATORY ACCOUNTING AND RATEMAKING TREATMENT 19
Q. Is the Company proposing to modify the 20
depreciable life assumptions used in the Bridger levelized 21
revenue requirement calculations? 22
A. No, not from the original request. Idaho 23
Power is proposing to maintain the acceleration of coal-24
LARKIN, SUPP DI 11
Idaho Power Company
related investment depreciation to year-end 2030 for 1
ratemaking purposes, as initially proposed. 2
Q. Why is the Company maintaining a depreciable 3
life of 2030 for all Bridger coal-related investments when 4
cessation of coal-fired operations of all units is expected 5
to occur by 2028? 6
A. As I will describe later in my testimony, the 7
suspension of the procedural schedule in this case and the 8
revision of the requested effective date to June 1, 2022, 9
reduces the collection period for which recovery of Bridger 10
coal-related revenue requirement occurs. In an attempt to 11
minimize revenue requirement impacts to customers, Idaho 12
Power is proposing to maintain an accelerated depreciation 13
schedule for all Bridger coal-related investments by year-14
end 2030 as initially proposed. This schedule is similar 15
to the cost recovery treatment of Valmy, whereby 16
depreciation expense recovery goes through 2028, even 17
though Idaho Power’s participation in coal-fired operations 18
will have ceased by 2025. 1 19
Q. Please provide an overview of Idaho Power’s 20
proposed cost recovery approach. 21
A. There are four types of costs the Company 22
anticipates recording to the balancing account: (1) the 23
accelerated depreciation associated with existing Bridger 24
1 Case No. IPC-E-16-24, Order No. 33771.
LARKIN, SUPP DI 12
Idaho Power Company
coal-related investments, (2) the return on the 1
undepreciated coal-related investments at Bridger, (3) non-2
fuel operations and maintenance (“O&M”) expense reductions, 3
and (4) interim decommissioning costs related to the 4
Bridger shutdown. 5
Q. What components will change as a result of the 6
Bridger coal-related investments only revenue requirement? 7
A. All the components have been updated to 8
reflect Bridger coal-related costs and benefits only, with 9
the exception of the decommissioning costs, as the 10
Company’s initial proposal included a cost estimate based 11
on the decommissioning of only coal-related investments 12
through 2030. The Company is proposing to include in the 13
annual levelized revenue requirement all actual coal-14
related investments made at Bridger, as well as forecasted 15
coal-related investments, with an accelerated depreciable 16
life. Idaho Power has reduced the net book value of actual 17
investments made at Bridger through December 31, 2020, to 18
reflect an estimate of only coal-related investments. In 19
addition, the Company has revised the O&M expense savings 20
to reflect O&M expenses associated with coal-related 21
operations only. These updates along with the inclusion of 22
estimated interim decommissioning costs through 2030 result 23
in an increase in customer rates of $27,127,333. 24
LARKIN, SUPP DI 13
Idaho Power Company
Q. How did Idaho Power compute the existing plant 1
investment value of only Bridger coal-related investments? 2
A. The Company’s Bridger-related property 3
accounting records are not granular at a unit-specific 4
level. However, the plant operator, PacifiCorp, has more 5
detailed accounting records and identified, by unit and by 6
plant account, which portion of the investments will be 7
retired when coal operations cease, and which investments 8
will remain in service with natural gas operations. The 9
same methodology was used to determine the portion of 10
Bridger common facility and general plant investments that 11
would be retired when coal-operations cease. Idaho Power 12
used the percentage of coal-related investments derived by 13
PacifiCorp and applied those percentages to the Company’s 14
existing investment values at December 31, 2020, to compute 15
an estimated Bridger coal-related investment net book 16
value. 17
Q. Does the update to include only Bridger coal-18
related investments require revisions to Mr. Adelman’s 19
Exhibit No. 3, which presented the investments made at 20
Bridger since the last general rate case? 21
A. No. Mr. Adelman’s direct testimony discusses 22
all necessary actual investments made at the Bridger plant 23
that have added to the associated plant balances since 24
December 31, 2011, and are presented in Exhibit No. 3 at 25
LARKIN, SUPP DI 14
Idaho Power Company
the project level. Because the estimate of Bridger coal-1
related investments was performed at the plant account 2
level, Idaho Power cannot precisely determine the portion 3
of the additions presented in Exhibit No. 3 that are 4
included in the December 31, 2020, Bridger coal-related 5
investment estimate. This does not, however, impact the 6
intent of the exhibit which is to support a prudence review 7
by providing detailed project descriptions and 8
justification for the investments necessary to operate the 9
Bridger plant in a safe, efficient, and reliable manner, 10
including investments to ensure environmental compliance. 11
Q. Do the proposed changes based on a Bridger 12
coal-related investment levelized revenue requirement 13
mechanism change Idaho Power’s accounting order request 14
necessary to establish the Bridger balancing account? 15
A. No. Because the proposed levelized revenue 16
requirement collection period still remains beyond the 17
expected operational life of the Bridger units, Idaho Power 18
will still need an accounting order that allows the Company 19
to make the needed accounting entries to appropriately 20
match revenue collected with the timing of the non-21
levelized revenue requirements. 22
IV. THE BRIDGER LEVELIZED REVENUE REQUIREMENT MECHANISM 23
Q. Has Idaho Power determined the revised 24
levelized revenue requirement associated with just the 25
LARKIN, SUPP DI 15
Idaho Power Company
coal-related costs proposed to be tracked in the Bridger 1
balancing account? 2
A. Yes. Exhibit No. 1 to my supplemental direct 3
testimony details the development of the Bridger coal-4
related investment levelized revenue requirement. The 5
annual levelized revenue requirement associated with 6
recovery of Bridger coal-related investments on an 7
accelerated basis is $47.79 million on an Idaho 8
jurisdictional basis, a reduction of approximately $20.00 9
million from the original request. Exhibit No. 1, the 10
levelized revenue requirement, is presented in three 11
separate components: (1) Component A – the revenue 12
requirement on Bridger coal-related investments, (2) 13
Component B - the revenue requirement associated with 14
interim future decommissioning costs, and (3) Component C - 15
the revenue requirement associated with coal-related O&M 16
savings including non-fuel O&M reductions. 17
Q. Please summarize the changes to each of the 18
components of the annual levelized revenue requirement. 19
A. The following table presents the differences 20
between each component as quantified in the Company’s 21
initial request and the amounts that reflect a Bridger 22
coal-related investment levelized revenue requirement only: 23
24
25
LARKIN, SUPP DI 16
Idaho Power Company
Table 1. Bridger Levelized Revenue Requirement Changes 1
June 2021 Request February 2022
Amended Request % Change
Plant Investment $73,470,945 $52,121,340 (29.1)
Interim Decomm Costs $59,318 $64,449 8.6
O&M Savings ($5,736,719) ($4,391,349) (23.5)
Levelized Rev Req $67,793,544 $47,794,440 (29.5)
Rev Req in Rates ($36,967,815) ($20,667,107) (44.1)
Net Change $30,825,729 $27,127,333 (12.0)
2
While the majority of the components have decreased from 3
the Company’s initial request, it is important to note that 4
collection of the Bridger coal-related investment levelized 5
revenue requirement will occur over a shorter period 6
thereby minimizing the overall revenue requirement 7
decrease. I will now discuss in more detail the changes to 8
the individual components. 9
Revenue Requirement on Bridger Coal-Related Investments 10
(Component A) 11
Q. Please describe any updates to the 12
quantification of Component A – the revenue requirement on 13
Bridger coal-related investments. 14
A. Component A has been revised to include the 15
revenue requirement on the existing Bridger coal-related 16
investments only as of December 31, 2020, the 17
quantification of which was described earlier in my 18
supplemental direct testimony, as well as the revenue 19
requirement associated with forecasted incremental coal-20
related investments anticipated beginning January 1, 2021. 21
As of December 31, 2020, the Bridger coal-related net plant 22
LARKIN, SUPP DI 17
Idaho Power Company
investment is approximately $236.33 million as compared to 1
the $369.58 million included in the Company’s original 2
request. The forecasted incremental coal-related 3
investments are approximately $45.65 million, down from 4
$95.05 million. The result is a total levelized revenue 5
requirement associated with Component A of $52.12 million 6
on an Idaho jurisdictional basis down from the $73.47 7
million included in the Company’s original request. 8
Q. How were the total forecasted incremental 9
investments of $45.65 million determined? 10
A. Idaho Power first removed from PacifiCorp’s 11
revised Bridger forecast any plant investments after 12
December 31, 2023, for Units 1 and 2, when coal operations 13
cease, after December 31, 2025, for Unit 3, and after 14
December 31, 2028, for Unit 4 and common facilities, the 15
Company’s expected exit from coal-fired operations of those 16
units. The Company assumed that the cost responsibility of 17
the incremental investments ceased at the point that 18
participation of coal-fired operations in a Bridger unit 19
ended. Next, Idaho Power applied the estimated percentage 20
of coal-related investments, the quantification of which 21
was described earlier in my testimony, to these values for 22
a coal-specific investment forecast. Finally, the 23
Company’s one-third ownership share was applied to the 24
remaining balance. 25
LARKIN, SUPP DI 18
Idaho Power Company
Q. What dates did Idaho Power assume for ceasing 1
participation in operations at each of the Bridger units? 2
A. Idaho Power revised the end of participation 3
in each Bridger unit consistent with the date participation 4
in coal-fired operations cease as identified in the 5
Preferred Portfolio from its 2021 IRP. Therefore, the 6
Company excluded any forecasted investments in Units 1 and 7
2 after December 31, 2023, as those investments would be 8
associated with natural gas operations and excluded 9
forecasted investments in Units 3 and 4 in 2025 and 2028, 10
respectively. 11
Q. Based on these assumed exit dates, was the 12
forecast of common facility investments revised? 13
A. Yes. In addition to the removal of those 14
common facility investments that will continue to remain in 15
service during gas operations, Idaho Power has assumed 16
responsibility for its one-third share of common facility 17
investments will cease on December 31, 2028. 18
Revenue Requirement of Interim Future Decommissioning Costs 19
(Component B) 20
Q. Did the Company make changes to Component B - 21
the revenue requirement associated with interim future 22
decommissioning costs? 23
A. No. Idaho Power has continued to only include 24
in the levelized revenue requirement quantification amounts 25
LARKIN, SUPP DI 19
Idaho Power Company
associated with the decommissioning costs expected to be 1
incurred prior to year-end 2030, approximately $660,000. 2
However, because commencement of the inclusion of levelized 3
revenue requirement amounts in customer rates has shifted 4
to June 1, 2022, collection of the interim future 5
decommissioning costs will occur over a shorter time 6
period. Therefore, Component B has increased slightly from 7
$59,318 to $64,449 on an Idaho jurisdictional basis. 8
Q. Does the Company expect the annual collection 9
of $64,449 to fully-fund all plant decommissioning costs? 10
A. No. The annual collection of $64,449 is 11
intended to cover the current forecast of interim 12
decommissioning costs that are expected to be incurred 13
until 2030 as coal units are retired. Full decommissioning 14
of the plant is not expected to occur until well after 15
2030. The Company anticipates making a separate filing when 16
more information is known regarding decommissioning plans, 17
but no later than 2030 to address further collection of 18
future decommissioning costs once more information 19
regarding timing and better cost estimates is available. 20
Revenue Requirement of O&M Savings (Component C) 21
Q. Please describe any changes to the 22
quantification of Component C - the revenue requirement 23
associated with O&M savings including non-fuel O&M 24
reductions. 25
LARKIN, SUPP DI 20
Idaho Power Company
A. In the initial request, the Company computed 1
the estimated Bridger O&M savings by comparing estimated 2
Bridger 2011 test year non-fuel O&M amounts to the forecast 3
of non-fuel O&M expected at Bridger through 2030, when the 4
last coal unit was expected to cease operations. Idaho 5
Power assumed variable O&M ceases upon exit of a unit, but 6
that the Company would still be responsible for its share 7
of fixed O&M as long as PacifiCorp is operating the unit. 8
Idaho Power assumed fixed O&M ceased when the Company had 9
exited operations of all four Bridger units, or 2030. 10
Idaho Power received a revised non-fuel O&M forecast from 11
PacifiCorp that reflects an estimate of only those costs 12
associated with coal operations. The Company has applied 13
the same methodology to this forecast and now assumes that 14
all O&M cost responsibilities cease at the end of 2028, 15
when Idaho Power has ceased participation in coal-fired 16
operations. 17
Q. If PacifiCorp plans to operate Bridger Units 3 18
and 4 beyond 2028, why does the Company believe its O&M 19
cost responsibilities will go to zero at the end of 2028? 20
A. Idaho Power and PacifiCorp have yet to come to 21
agreement on the terms and conditions for each partner’s 22
exit of Bridger units. It is not known at this time 23
whether, and to what extent, there may be exit fees or 24
other costs that continue after Idaho Power ceases 25
LARKIN, SUPP DI 21
Idaho Power Company
participation in a unit. Further, unit exit plans of each 1
partner may better align over time reducing or eliminating 2
the need for exit fees or other similar contractual 3
provisions. As was the case with the Valmy cost recovery 4
mechanism, the Company proposes to update the Bridger 5
levelized revenue requirement once an exit agreement 6
between partners is reached or when more relevant 7
information is known. 8
Q. Was an adjustment made to the Bridger 2011 9
test year non-fuel O&M amounts? 10
A. Yes. To estimate the portion of Bridger 2011 11
test year non-fuel O&M amounts, which is used as the basis 12
for calculating O&M savings, Idaho Power reduced non-fuel 13
O&M amounts by an amount equivalent to the reduction 14
between the Bridger non-fuel O&M forecast and the Bridger 15
coal-related non-fuel O&M forecast, or approximately 42 16
percent. 17
Q. What is the total non-fuel O&M savings 18
included in the levelized revenue requirement computation? 19
A. Idaho Power is proposing to include in the 20
levelized revenue requirement Bridger coal-related non-fuel 21
O&M savings of approximately $4.39 million on an Idaho 22
jurisdictional basis. The removal of non-fuel O&M amounts 23
that will exist during gas operations results in a smaller 24
LARKIN, SUPP DI 22
Idaho Power Company
reduction in O&M costs, reducing the O&M savings 1
anticipated from coal operations only. 2
Q. What is the resulting total Bridger coal-3
related levelized revenue requirement? 4
A. The levelized revenue requirement associated 5
with Bridger coal-related investments includes $52.12 6
million associated with coal-related investments, $0.06 7
million in interim decommissioning costs, and $4.39 million 8
in non-fuel O&M savings, for a total annual Bridger coal-9
related levelized revenue requirement of $47,794,440 on an 10
Idaho jurisdictional basis, a decrease of $19,999,104 from 11
the $67,793,544 quantified in the Company’s original 12
request. 13
Q. Did Idaho Power compute an existing revenue 14
requirement associated with Bridger coal-related 15
investments that is currently included in the Company’s 16
base rates? 17
A. Yes. Exhibit No. 2 to my supplemental direct 18
testimony details the derivation of the Idaho 19
jurisdictional share of the Bridger coal-related 20
investments revenue requirement based on a 2011 test year, 21
as approved in Case No. IPC-E-11-08 with Order No. 32481, 22
the Company’s last general rate case. In addition, Idaho 23
Power has included an adjustment to reflect Bridger revenue 24
requirement amounts returned to customers in Case No. GNR-25
LARKIN, SUPP DI 23
Idaho Power Company
U-18-01 with Order No. 34071 as a result of the Tax Cuts 1
and Jobs Act of 2017. The existing revenue requirement 2
associated with Bridger coal-related investments only and 3
currently included in the Company’s base rates is 4
$20,667,107. If Idaho Power’s proposal is approved, this 5
amount will be replaced with the levelized revenue 6
requirement amount detailed in Exhibit No. 1 to my 7
supplemental direct testimony. 8
Q. How does the total levelized revenue 9
requirement compare to the revenue requirement currently in 10
customer rates? 11
A. The total Idaho jurisdictional levelized 12
revenue requirement of $47.79 million less the Idaho 13
jurisdictional share of the existing revenue requirement of 14
$20.67 million, results in an incremental annual levelized 15
revenue requirement of approximately $27.13 million on an 16
Idaho jurisdictional basis. 17
Q. How does this compare to the Company’s 18
quantification of the levelized revenue requirement of all 19
Bridger investments? 20
A. The Bridger coal-related investment levelized 21
revenue requirement is approximately $3.70 million less 22
than the initial Bridger levelized revenue requirement 23
quantification. 24
LARKIN, SUPP DI 24
Idaho Power Company
Q. You indicated the difference between total 1
Bridger investments and Bridger coal-related investments 2
was approximately $133.25 million and the capital forecast 3
decreased approximately 50 percent. Why wasn’t there a 4
greater decrease in the levelized revenue requirement? 5
A. While there were significant decreases in 6
plant values when reflecting only coal-related investments, 7
the revised plant-related current and deferred income taxes 8
resulted in an increase to net flow-through income tax 9
expense. 10
Q. What is driving the net increase in income 11
taxes? 12
A. Because cessation of all operations at the 13
Bridger plant is no longer occurring, the tax-plant 14
accounting system allocations will only reverse the 15
accumulated deferred income taxes associated with the 16
retired coal-related assets as opposed to a complete 17
reversal of the balance caused by the retirement of the 18
entire Bridger tax asset class. This system-generated 19
revision of deferred taxes is driven by book cost 20
allocations to the coal-related assets, timing of unit 21
retirements, and vintage tax basis and depreciation 22
differences in the Bridger tax asset class. 23
The decrease in current income tax expense is 24
directly related to the proposed reduction in the amount of 25
LARKIN, SUPP DI 25
Idaho Power Company
plant cost retired. Thus, overall, the lower current 1
income tax combined with the re-allocated deferred income 2
tax increased the net flow-through expense when compared to 3
the Company’s original request. Finally, the remaining 4
accumulated deferred income tax balance, which serves to 5
offset rate base and reduces cost of service as it 6
reverses, continues in Idaho Power’s tax-plant accounting 7
system and attaches to the Bridger Unit 1 and 2 plant 8
balances when the units are converted to natural gas 9
operations. This remaining Bridger deferred income tax 10
balance will reverse over time as the natural gas plant 11
balances depreciate and would be a component of the 12
Company’s income taxes in a future general rate case or 13
other rate proceeding specific to the plant. 14
V. PROPOSED RATEMAKING TREATMENT 15
Q. Is the Company proposing any changes to the 16
allocation of the incremental annual Bridger coal-related 17
levelized revenue requirement amount of approximately 18
$27.13 million to each class of customers? 19
A. No. Idaho Power requests that the incremental 20
revenue requirement of approximately $27.13 million be 21
recovered from all customer classes through a uniform 22
percentage increase to all base rate components except the 23
service charge as initially contemplated. Attachment No. 1 24
LARKIN, SUPP DI 26
Idaho Power Company
to the Amended Application presents a summary of the 1
proposed revenue impact for each customer class. 2
Q. Why does the Company believe the proposed June 3
1, 2022, effective date for the requested rate adjustment 4
is reasonable and appropriate? 5
A. As demonstrated even before a mechanism has 6
been established, unforeseen changes in economics or 7
regulatory policy associated with the Bridger plant can 8
occur. A balancing account will smooth recovery of 9
Bridger-related revenue requirements over its remaining 10
operating life and help to mitigate the rate impact over 11
the time during which Idaho Power participates in coal-12
fired operations, providing stability for customers. In 13
addition, an effective date of June 1, 2022, will coincide 14
with a change in rates associated with the Power Cost 15
Adjustment mechanism, minimizing rate changes for 16
customers. 17
VI. CONCLUSION 18
Q. Please summarize your testimony. 19
A. Actions by the EPA regarding environmental 20
compliance of Units 1 and 2, as well as the identification 21
in the Preferred Portfolio of the Company’s 2021 IRP of the 22
conversion to natural gas generation, necessitate an update 23
to the proposed levelized revenue requirement to reflect a 24
Bridger coal-related levelized revenue requirement only. 25
LARKIN, SUPP DI 27
Idaho Power Company
Idaho Power has updated the quantification of the 1
levelized revenue requirement, removing all amounts 2
associated with investments that will remain in service 3
while natural gas generation is occurring. The 4
establishment of a balancing account will allow flexibility 5
for the timing and recovery of the remaining Bridger coal-6
related investment revenue requirement. Under the proposed 7
methodology, Idaho Power seeks approval of an adjustment of 8
$27,127,333 to the Company’s Idaho jurisdictional revenue 9
requirement to take place on June 1, 2022, which equates to 10
an overall increase of 2.12 percent. 11
Q. Does this complete your testimony? 12
A. Yes, it does. 13
LARKIN, SUPP DI 28
Idaho Power Company
DECLARATION OF MATTHEW T. LARKIN 1
I, Matthew T. Larkin, declare under penalty of 2
perjury under the laws of the state of Idaho: 3
1. My name is Matthew T. Larkin. I am employed 4
by Idaho Power Company as the Revenue Requirement Senior 5
Manager. 6
2. On behalf of Idaho Power, I present this 7
pre-filed supplemental direct testimony and supplemental 8
Exhibit Nos. 1-2 in this matter. 9
3. To the best of my knowledge, my pre-filed 10
supplemental direct testimony and exhibits are true and 11
accurate. 12
I 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 16th day of February 2022, at Boise, 17
Idaho. 18
19
Signed: 20
21
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-21-17
IDAHO POWER COMPANY
LARKIN, SUPP DI
TESTIMONY
EXHIBIT NO. 1
Component A Component B Component C
Total System
Plant Investments Interim
Decommissioning Costs O&M Variance
Levelized Annual Revenue Requirement Effective June 1, 2022 $ 54,816,460 $ 67,781 $ (4,620,041) $ 50,264,200
Component A Component B Component C
Idaho Jurisdictional
Plant Investments Interim
Decommissioning Costs O&M Variance
Levelized Annual Revenue Requirement Effective June 1, 2022 $ 52,121,340 $ 64,449 $ (4,391,349) $ 47,794,440
Current Bridger Coal‐Related Revenue Requirement included in Rates 20,667,107
Net Change in Bridger Coal‐Related Levelized Revenue Requirement $ 27,127,333
Levelized Revenue Requirement for Bridger Coal‐Related Investment
at December 31, 2020
Total System
Total Idaho
Jurisdictional
Filed February 16, 2022
Exhibit No. 1
Case No. IPC-E-21-17 M. Larkin Supp DI
Page 1 of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-21-17
IDAHO POWER COMPANY
LARKIN, SUPP DI
TESTIMONY
EXHIBIT NO. 2
RATE BASE
Electric Plant in Service
Intangible Plant 302,533$
Production Plant 317,844,293
Transmission Plant 3,902,308
Distribution Plant 0
General Plant 1,233,930
Total Electric Plant in Service 323,283,064$
Less: Accumulated Depreciation 168,084,102
Less: Amortization of Other Plant 0
Net Electric Plant in Service 155,198,962$
Less: Accumulated Deferred Income Taxes 17,111,466
TOTAL COMBINED RATE BASE 138,087,496$
NET INCOME
Total Operating Revenues ‐$
Operating Expenses
Operation and Maintenance Expenses
Depreciation Expenses 7,775,078
Amortization of Limited Term Plant
Taxes Other Than Income 999,217
Regulatory Debits/Credits
Provision for Deferred Income Taxes 3,445,514
Investment Tax Credit Adjustment
Current Income Taxes (9,496,530)
Total Operating Expenses 2,723,279$
Consolidated Operating Income (2,723,279)$
Proposed Rate of Return 7.86%
Earnings Deficiency 13,576,957$
Net‐to‐Gross Tax Multiplier 1.642
Bridger Revenue Requirement (IPC‐E‐11‐08)22,293,363$
Bridger Revenue Requirement Reduction (GNR‐U‐18‐01)(1,626,256)$
Bridger Revenue Requirement Currently in Rates 20,667,107$
Idaho Power Company
Summary of Revenue Requirement ‐ Idaho
Bridger Coal‐Related Investments: 2011 Test Year
Exhibit No. 2
Case No. IPC-E-21-17 M. Larkin Supp DI
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