20220513IPC to ICIP 1-13.pdf

LISA D. NORDSTROM
Lead Counsel
[e-mail]

May 13, 2022

Jan Noriyuki, Secretary
Idaho Public Utilities Commission
11331 W. Chinden Boulevard
Building 8, Suite 201-A
Boise, Idaho 83714

Re: Case No. IPC-E-22-11
Application of Idaho Power Company for Authority to Implement Power Cost
Adjustment (“PCA”) Rates for Electric Service from June 1, 2022, through May
31, 2023

Dear Ms. Noriyuki:

Attached for electronic filing is Idaho Power Company’s Response to the First
Production Request of the Idaho Industrial Customers of Idaho Power in the above-
entitled matter.

The confidential attachments will be provided in a separate encrypted email to the
parties who sign the protective agreement.

If you have any questions about the attached documents, please do not hesitate to
contact me.

Sincerely,

Lisa D. Nordstrom
LDN:sg
Enclosures
RECEIVED
2022 May 13, PM 3:09
IDAHO PUBLIC
UTILITIES COMMISSION

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF IDAHO POWER - 1

LISA D. NORDSTROM (ISB No. 5733)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
[e-mail]

Attorney for Idaho Power Company

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO IMPLEMENT POWER
COST ADJUSTMENT (“PCA”) RATES
FOR ELECTRIC SERVICE FROM JUNE
1, 2022, THROUGH MAY 31, 2023.

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CASE NO. IPC-E-22-11

IDAHO POWER COMPANY’S
RESPONSE TO THE FIRST
PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF
IDAHO POWER

COMES NOW, Idaho Power Company (“Idaho Power” or “Company”), and in
response to the First Production Request of the Industrial Customers of Idaho Power
(“ICIP”) dated April 22, 2022, herewith submits the following information:

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF IDAHO POWER - 2

REQUEST FOR PRODUCTION NO. 1: Please provide, in electronic format with
all formulae intact where possible, all workpapers and other documents used in the
development of Idaho Power’s Application in this matter, specifically include tables one
through six of Ms. Brady’s direct testimony.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1: Please see Excel
Attachments 1 – 4.
Excel Attachment 1 was used in preparation of Exhibit No.1 (2022-2023 PCA
Forecast) as well as the tables found in the direct testimony of Jessica G. Brady. Excel
Attachment 2 contains the calculations for the PCA rate components. Excel Attachments
3 and 4 were used in preparation of Exhibit No. 3 (2022 ROE Determination Revenue
Sharing Benefits).
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF IDAHO POWER - 3

REQUEST FOR PRODUCTION NO. 2: Please provide copies of all
communications between Idaho Power and the Idaho Public Utilities Commission and/or
its Staff regarding Idaho Power’s Application in this matter.
RESPONSE TO REQUEST FOR PRODUCTION NO. 2: Please see the attached
files. Please note that certain communications related to the Idaho Public Utilities
Commission Staff’s (“Staff”) audit authority as granted by Idaho Code § 61-610 have been
redacted due to the sensitive and highly confidential nature of the related documents
provided on the referenced FTP site. To make arrangements to view the documentation
referenced in these communications on-site at the Company’s corporate headquarters,
please contact Tami White at [e-mail], or [phone], or Dave
Fewkes at [e-mail], or [phone].
The response to this Request is sponsored by Matthew Larkin, Revenue
Requirement Senior Manager, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF IDAHO POWER - 4

REQUEST FOR PRODUCTION NO. 3: Please provide copies of all responses to
production requests (both formal and informal) provided to any other party to this
proceeding.
RESPONSE TO REQUEST FOR PRODUCTION NO. 3: Please see the
attachments provided in Response to ICIP’s Request for Production No. 2.
The response to this Request is sponsored by Stacy Gust, Regulatory
Administrative Assistant, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF IDAHO POWER - 5

REQUEST FOR PRODUCTION NO. 4: Please identify the Company’s Idaho
jurisdictional return on equity (ROE) for each year the PCA has been in effect.
RESPONSE TO REQUEST FOR PRODUCTION NO. 4: The Idaho jurisdictional
ROE is not available for each year the PCA has been in effect, however, the following
table details the Idaho jurisdictional ROE since the inception of the Accumulated Deferred
Investment Tax Credits/Revenue Sharing mechanism in 2009.

Idaho
Jurisdictional
ROE
2009 9.75%
2010 10.37%
2011 12.55%
2012 11.18%
2013 11.22%
2014 11.19%
2015 10.13%
2016 9.53%
2017 9.94%
2018 10.21%
2019 9.80%
2020 9.98%
2021 10.02%

The response to this Request is sponsored by Matthew Larkin, Revenue
Requirement Senior Manager, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF IDAHO POWER - 6

REQUEST FOR PRODUCTION NO. 5: Please identify the rate change (year over
year) in the PCA for each year the PCA has been in effect.
RESPONSE TO REQUEST FOR PRODUCTION NO. 5: Below is a table showing
the traditional PCA rate applied to all rate classes and the rate change year over year
from 2014 through the proposed rate in 2022.
Year PCA Rate
$ per kWh
Rate Change
$ per kWh
2014 0.007305 N/
2015 0.005298 -0.002007
2016 0.006187 0.000889
2017 0.007361 0.001174
2018 0.004854 -0.002507
2019 0.001318 -0.003536
2020 0.004862 0.003544
2021 0.007571 0.002709
2022 0.014505 0.006934

To provide a consistent basis for comparison, the PCA rate provided in the table
excludes items such as revenue sharing, transfer of demand side management rider
funds, and tax reform credits that were also included in the overall PCA rates applied to
customers in various years. Additionally, in Case No. IPC-E-13-20, a new base level of
Net Power Supply Expense (“NPSE”) was ordered by the Commission to “(1) update base
rates effective June 1, 2014, and (2) quantify the 2014/2015 PCA rates to be effective
June 1, 2014.” Because the PCA rate reflects differences between NPSE recovered
through base rates and actual NPSE, the Company has provided all PCA rate changes
that reflect the current base assumptions from 2014 to present. A year-over-year
comparison of PCA rates in effect prior to the base NPSE update in Case No. IPC-E-13-
20 would not provide an accurate relative comparison due to the change in underlying
assumptions.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF IDAHO POWER - 7

The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF IDAHO POWER - 8

REQUEST FOR PRODUCTION NO. 6: Please explain, in detail, the meaning of
the phrase “financial return” when it is used in the Company’s public notice materials in
the context of: “Neither Idaho Power nor its shareholders receive any financial return from
this filing.”
RESPONSE TO REQUEST FOR PRODUCTION NO. 6: “Financial Return” refers
to return on investment as applied under the Regulatory Compact, in which Idaho Power
is afforded the opportunity to earn a fair return on investment made on behalf of
customers, reflecting the weighted cost of debt and equity financing. The Power Cost
Adjustment (“PCA”) provides for recovery or credit of variations in net power supply
expenses, which does not include a return component.
The response to this Request is sponsored by Matthew Larkin, Revenue
Requirement Senior Manager, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF IDAHO POWER - 9

REQUEST FOR PRODUCTION NO. 7: Does the Company expect to receive a
“financial return’ form its “requested price increase to collect the cost of an accelerated
depreciation schedule for all coal-related investments at the Jim Bridger Power Plant…”.
RESPONSE TO REQUEST FOR PRODUCTION NO. 7: Yes. If approved as filed,
the Company’s request related to the Jim Bridger Power Plant includes a fair return on
prudently-incurred, undepreciated investments at the plant.
The response to this Request is sponsored by Matthew Larkin, Revenue
Requirement Senior Manager, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF IDAHO POWER - 10

REQUEST FOR PRODUCTION NO. 8: Beginning on line 20 at page 30 of Ms.
Brady’s pre-filed direct testimony is a reference to her “discussions” in which she
“consulted with management” in order to “determine what rate mitigation, if any, the
Company should include in this filing.” Please identify the dates of all referenced
consultations and the identity of the management personnel who were consulted. For
each referenced consultation please provide copies of all notes, agenda, minutes, email
communications documentation (whether nor not contemporaneous) and/or all
documentation of said consultations.
RESPONSE TO REQUEST FOR PRODUCTION NO. 8: Discussions with
management occurred during the week of April 11, 2022, when the final PCA
quantification was known. Verbal consultations occurred with Tim Tatum, Vice President
of Regulatory Affairs, and Matthew Larkin, Revenue Requirement Senior Manager.
Because these were verbal consultations, no additional documentation exists.
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF IDAHO POWER - 11

REQUEST FOR PRODUCTION NO. 9: At the top of page 31 Ms. Brady states
that she was “advised by management to not propose any rate mitigation measures in
this case.” Please identify the “management” personnel who advised against proposing
any rate mitigation measures in this case. Please provide copies of all notes, agenda,
minutes, email communications and all other documentation (whether nor not
contemporaneous) of said management advise to not propose any rate mitigation
measures in this case.
RESPONSE TO REQUEST FOR PRODUCTION NO. 9: Please see the
Company’s Response to ICIP’s Request for Production No. 8.
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF IDAHO POWER - 12

REQUEST FOR PRODUCTION NO. 10: Does Idaho Power’s management
believe there is a threshold rate increase in terms of percentage increase such at a rate
mitigation measure would be warranted? What is that threshold?
RESPONSE TO REQUEST FOR PRODUCTION NO. 10: Idaho Power
management defers to Order No. 24806, issued March 29, 1993, where the Commission
indicated that a threshold of 7 percent of normalized base revenues was the appropriate
threshold at which to investigate deferral of a percentage of PCA-related net power supply
expense recovery.
The response to this Request is sponsored by Matthew Larkin, Revenue
Requirement Senior Manager, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF IDAHO POWER - 13

REQUEST FOR PRODUCTION NO. 11: At several places in Ms. Brady’s
testimony she discusses the possibility of rate mitigation “measures” and rate mitigation
“options” in the plural. Yet, her testimony only addresses the management’s rejection of
a single option or a single measure which is the possibility “spreading recovery over
multiple years.” (See page 31 line 12). What other options or measures were discussed
(and ultimately rejected) by Idaho Power’s management and/or Ms. Brady that would help
to mitigate the rate impact of the Company’s proposed rate increase? What other rate
mitigation measures is the company generally aware of?
RESPONSE TO REQUEST FOR PRODUCTION NO. 11: The use of the word
“rejected” in the premise of this question could be interpreted as Idaho Power being
opposed to rate mitigation with regard to this filing, which is not an accurate depiction of
Ms. Brady’s testimony. On the contrary, Ms. Brady discusses Idaho Power’s openness to
rate mitigation measures if determined to be appropriate by the Commission, as shown
on lines 1 through 11, page 32.
Notwithstanding the above clarification, discussions regarding potential PCA
mitigation options centered around spreading recovery over multiple years. The example
the Company provided in testimony was a relatively simple bifurcation of the requested
rate increase over a two-year period. The Company is also generally aware of other rate
mitigation measures; for example, in the 2002 PCA, Idaho Power proposed to securitize
a large portion of the PCA amount through the issuance of up to $172 million in bonds.
The Commission rejected this proposal, in part due to concerns over rate pancaking
(Order No. 29026 at 17). Instead of accepting the Company’s mitigation proposal, the
Commission chose to adjust rates to recover $244.4 million over a single year and

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF IDAHO POWER - 14

deferred the recovery of $11.5 million to be collected from Irrigation and Small General
Service customers in the following year, citing special circumstances that existed related
to those two classes of customers.
The response to this Request is sponsored by Matthew Larkin, Revenue
Requirement Senior Manager, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF IDAHO POWER - 15

REQUEST FOR PRODUCTION NO. 12: Please explain whether the Company
would support a rate mitigation measure that spreads this proposed rate increase over
several years if it were proposed by, and only applicable to, sophisticated customers who
understood the risks associated with deferred collection and “rate pancaking.”
RESPONSE TO REQUEST FOR PRODUCTION NO. 12: As discussed in the
testimony of Ms. Brady, the Company would be amenable to discussing rate mitigation
proposals if the Commission deems they are appropriate. With regard to a rate mitigation
measure “proposed by, and only to, sophisticated customers,” the Company cannot
indicate whether or not it would be supportive of such a proposal without understanding
the details of the proposal in its entirety.
The response to this Request is sponsored by Matthew Larkin, Revenue
Requirement Senior Manager, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF IDAHO POWER - 16

REQUEST FOR PRODUCTION NO. 13: For the time period beginning with Idaho
Power’s last general rate case, please provide copies of all references to the PCA made
by Idaho Power or IDACORP or their respective management in any discussions or
analysis of its financial condition, results of operations and business and/or regulatory
risks to potential or existing investors, regulators1, bankers and/or security and financial
analysists. Please provide copies of any comments made by the same entities/personnel
regarding Idaho Power’s PCA.
RESPONSE TO REQUEST FOR PRODUCTION NO. 13: Idaho Power objects to
this request as being overly broad in that it encompasses more than decade, is
burdensome, and is not reasonably calculated to lead to the discovery of evidence
relevant to this proceeding. Notwithstanding this objection, Idaho Power is including with
this request investor presentations from 2016 through 2020, which reflect available
historical materials in accordance with the Company’s document retention policy.
Materials encompassing 2021 and 2022 may be accessed publicly on the Investor
Relations portion of the IDACORP website at https://www.idacorpinc.com/investor-
relations/events-and-presentations/default.aspx.
The response to this Request is sponsored by Matthew Larkin, Revenue
Requirement Senior Manager, Idaho Power Company.

1 Other than the Idaho PUC in open proceedings.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF IDAHO POWER - 17

DATED at Boise, Idaho, this 13th day of May 2022.

________________________________
LISA D. NORDSTROM
Attorney for Idaho Power Company

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
INDUSTRIAL CUSTOMERS OF IDAHO POWER - 18

CERTIFICATE OF SERVICE

I HEREBY CERTIFY that on the 13th day of May 2022, I served a true and correct
copy of Idaho Power Company’s Response to the First Production Request of the
Industrial Customers of Idaho Power Company upon the following named parties by the
method indicated below, and addressed to the following:

Commission Staff
Dayn Hardie
Deputy Attorney General
Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg No. 8,
Suite 201-A (83714)
PO Box 83720
Boise, ID 83720-0074

Hand Delivered
U.S. Mail
Overnight Mail
FAX
_____ FTP Site
X Email: [e-mail]

Industrial Customers of Idaho Power
Peter J. Richardson
515 N. 27th Street
Boise, Idaho 83702
Hand Delivered
U.S. Mail
Overnight Mail
FAX
_____ FTP Site
X Email: [e-mail]

Dr. Don Reading
6070 Hill Road
Boise, Idaho 83703
Hand Delivered
U.S. Mail
Overnight Mail
FAX
_____ FTP Site
X Email: [e-mail]

________________________________
Stacy Gust, Regulatory Administrative
Assistant

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

REQUEST NO. 1

ATTACHMENT NO. 1
SEE ATTACHED SPREADSHEET

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

REQUEST NO. 1

ATTACHMENT NO. 2
SEE ATTACHED SPREADSHEET

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

REQUEST NO. 1

ATTACHMENT NO. 3

SEE ATTACHED SPREADSHEET

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

REQUEST NO. 1

ATTACHMENT NO. 4

SEE ATTACHED SPREADSHEET
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-22-11
IDAHO POWER COMPANY
REQUEST NO. 2
ATTACHMENT NO. 1
Archived: Monday, May 2, 2022 8:57:46 AMFrom: Kathy Stockton
Sent: Tuesday, January 4, 2022 11:27:36 AMTo: Fewkes, David
Subject: [EXTERNAL]RE: 2022 PCA AuditSensitivity: Normal
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the sender before proceeding, and check for additional warning messages below.
Funny you should ask… I am working on an audit request, and yes it will most likely be much like last year, although it has been a few years since I have been directly involved with the PCA audit. I would like to begin reviewing information in February, specifically electricity sales and purchases, coal and natural gas invoices, etc. for the March through December 2021 period. I will send you my audit request by the end of the week, and I will revisit the questions asked last year to see if there are any changes to the questions. Thanks! Kathy StocktonSenior AuditorIdaho Public Utilities [e-mail][phone]
From: Fewkes, David <[e-mail]> Sent: Tuesday, January 4, 2022 11:23 AMTo: Kathy Stockton <[e-mail]>Cc: White, Tami <[e-mail]>; Larkin, Matt <[e-mail]>Subject: 2022 PCA Audit Good morning Kathy, We have met in passing when Cam helped facilitate the PCA audit. A couple of years ago, Cam moved on to a new position and I have assumed the responsibility of helping facilitate the PCA audit. I understand the time for the PCA audit is compressed. Tohelp with this, I have tried to assign the questions to our employees earlier in the month. Will there be any changes to the questions from last year? I am wondering if you have a list of questions that you could send prior to the formal request? Let meknow how you would like to approach this. I am committed to working with you and helping to facilitate a smooth audit process. Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting (: (cell)
(: 208-388-2628 (work)
IDAHO POWER LEGAL DISCLAIMERThis transmission may contain information that is privileged, confidential and/or exempt from disclosure under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure, copying, distribution, oruse of the information contained herein (including any reliance thereon) is STRICTLY PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the material in its entirety, whether inelectronic or hard copy format. Thank you.
Archived: Monday, May 2, 2022 8:58:26 AMFrom: Kathy Stockton
Sent: Tuesday, January 18, 2022 9:00:49 AMTo: Fewkes, David
Subject: [EXTERNAL]RE: 2022 PCA AuditSensitivity: Normal
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the sender before proceeding, and check for additional warning messages below.
Our office has had absences as well, but so far, I have been healthy. I expect to have questions to you by the middle of this week, pending our internal review process. As you probably expected, the questions will mirror those asked in previous audit requests. I would like to meet virtually to discuss the process Idaho Power uses to bid into the EIM market. The last time I was assigned to the PCA, Idaho Power had just entered the EIM market, so I have yet to do an audit while the Idaho Power has been active inthat market. Kathy StocktonSenior AuditorIdaho Public Utilities [e-mail][phone]
From: Fewkes, David <[e-mail]> Sent: Tuesday, January 18, 2022 8:57 AMTo: Kathy Stockton <[e-mail]>Subject: RE: 2022 PCA Audit Good morning Kathy, I wanted to follow-up with you sooner, but my household has had a brush with Omicron, sigh. Have you had a chance to finalize the questions? I would like to get them assigned to folks internally so we can turn the information around and get it back to you as quickly as possible. I hope all is well with you. Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting
(: (cell)(: 208-388-2628 (work)
From: Kathy Stockton <[e-mail]> Sent: Tuesday, January 4, 2022 11:27 AMTo: Fewkes, David <[e-mail]>Subject: [EXTERNAL]RE: 2022 PCA Audit KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the sender before proceeding, and check for additional warning messages below.
Funny you should ask… I am working on an audit request, and yes it will most likely be much like last year, although it has been a few years since I have been directly involved with the PCA audit. I would like to begin reviewing information in February, specifically electricity sales and purchases, coal and natural gas invoices, etc. for the March through December 2021 period. I will send you my audit request by the end of the week, and I will revisit the questions asked last year to see if there are any changes to the questions. Thanks! Kathy StocktonSenior AuditorIdaho Public Utilities [e-mail][phone]
From: Fewkes, David <[e-mail]> Sent: Tuesday, January 4, 2022 11:23 AMTo: Kathy Stockton <[e-mail]>Cc: White, Tami <[e-mail]>; Larkin, Matt <[e-mail]>Subject: 2022 PCA Audit Good morning Kathy, We have met in passing when Cam helped facilitate the PCA audit. A couple of years ago, Cam moved on to a new position and I have assumed the responsibility of helping facilitate the PCA audit. I understand the time for the PCA audit is compressed. Tohelp with this, I have tried to assign the questions to our employees earlier in the month. Will there be any changes to the questions from last year? I am wondering if you have a list of questions that you could send prior to the formal request? Let meknow how you would like to approach this. I am committed to working with you and helping to facilitate a smooth audit process. Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting
(: (cell)
(: 208-388-2628 (work)
IDAHO POWER LEGAL DISCLAIMERThis transmission may contain information that is privileged, confidential and/or exempt from disclosure under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure, copying, distribution, oruse of the information contained herein (including any reliance thereon) is STRICTLY PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the material in its entirety, whether inelectronic or hard copy format. Thank you.
Archived: Monday, May 2, 2022 8:59:51 AMFrom: Fewkes, David
Sent: Monday, January 31, 2022 1:01:00 PMTo: 'Kathy Stockton'
Subject: RE: 2022 PCA AuditSensitivity: Normal
Excellent. Thank you. I will stay in touch. I hope your day is great. Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting (: 208-409-4671 (cell)
(: 208-388-2628 (work)
From: Kathy Stockton <[e-mail]> Sent: Monday, January 31, 2022 1:00 PMTo: Fewkes, David <[e-mail]>Subject: [EXTERNAL]RE: 2022 PCA Audit KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the sender before proceeding, and check for additional warning messages below.
That actually would be a very good date! Kathy StocktonSenior AuditorIdaho Public Utilities [e-mail][phone]
From: Fewkes, David <[e-mail]> Sent: Monday, January 31, 2022 12:59 PMTo: Kathy Stockton <[e-mail]>Subject: RE: 2022 PCA Audit That sounds good. I’ll get started on that. Is there a target date, that you’d like to have the information? Would later in the week of February 21 work? Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting
(: (cell)
(: 208-388-2628 (work)
From: Kathy Stockton <[e-mail]> Sent: Monday, January 31, 2022 12:57 PMTo: Fewkes, David <[e-mail]>Subject: [EXTERNAL]RE: 2022 PCA Audit KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the sender before proceeding, and check for additional warning messages below.
David, If you would like to start gathering information on last year’s questions, then I can get a head start on this year’s audit. There will be no changes to last year’s questions, other than the dates. I apologize for not getting back to you sooner with thisinformation. We are anticipating adding new staff, and I will be working with the new hire on the PCA audit. When we have added new staff, then I anticipate that we will be sending the formal audit request, but for now, it would be greatly appreciated if you can getstarted gathering the information. Thanks, Kathy StocktonSenior AuditorIdaho Public Utilities [e-mail][phone]
From: Fewkes, David <[e-mail]> Sent: Tuesday, January 4, 2022 11:23 AMTo: Kathy Stockton <[e-mail]>Cc: White, Tami <[e-mail]>; Larkin, Matt <[e-mail]>Subject: 2022 PCA Audit Good morning Kathy, We have met in passing when Cam helped facilitate the PCA audit. A couple of years ago, Cam moved on to a new position and I have assumed the responsibility of helping facilitate the PCA audit. I understand the time for the PCA audit is compressed. Tohelp with this, I have tried to assign the questions to our employees earlier in the month. Will there be any changes to the questions from last year? I am wondering if you have a list of questions that you could send prior to the formal request? Let meknow how you would like to approach this. I am committed to working with you and helping to facilitate a smooth audit process. Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting
(: (cell)
(: 208-388-2628 (work)
IDAHO POWER LEGAL DISCLAIMERThis transmission may contain information that is privileged, confidential and/or exempt from disclosure under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure, copying, distribution, oruse of the information contained herein (including any reliance thereon) is STRICTLY PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the material in its entirety, whether inelectronic or hard copy format. Thank you.
Archived: Monday, May 2, 2022 9:02:28 AMFrom: Reyna Quintero
Sent: Thursday, February 10, 2022 3:25:53 PMTo: Nordstrom, Lisa; Larkin, Matt; Tatum, Tim; Fewkes, David; IPCDockets
Cc: Kathy Stockton Subject: [EXTERNAL]First Audit Request of the Commission Staff to Idaho Power Company in the 2022 PCA
Sensitivity: NormalAttachments:
Idaho Power 2022 PCA Audit Request 1.pdf ;
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the sender before proceeding, and check for additional warning messages below.Good afternoon, Attached please find the First Audit Request of the Commission Staff to Idaho Power Company in the above-referenced matter. Regards, Reyna Quintero | Utilities Administrative AssistantIdaho Public Utilities Commission11331 W. Chinden Blvd., Building 8, Suite 201-AP.O. Box 83720Boise, Idaho 83720-0074Direct: [phone] | Fax: (208) [e-mail]
CONFIDENTIALITY NOTICE: This e-mail may be confidential, privileged, and exempt from public disclosure, and the sender intends that it be used only by the individual or entity named above. If you are not the intended recipient, then you may not use, disclose, copy, ordistribute the e-mail or its contents. If you believe you have received this e-mail in error, please immediately notify the sender and delete the copy you received.
Archived: Monday, May 2, 2022 9:05:00 AMFrom: Fewkes, David Fewkes, David
Sent: Thursday, February 24, 2022 4:29:00 PMTo: Kathy Stockton
Cc: Fewkes, David White, Tami; Larkin, Matt; Brady, Jessi; Nordstrom, Lisa; Davenport, Christy; Gust, Stacy; Fewkes, David Subject: ENCRYPT PCA Staff Audit Data Room
Sensitivity: Normal
SENT VIA ENCRYPTED E-MAIL Good afternoon, Staff members may access non-confidential documents submitted in response to the First Audit Request of the Commission Staff to Idaho Power Company for the 2022 PCA filing, in the Staff Audit Data Room using:
Staff members who have signed the Protective Agreement executed by Idaho Power and the Commission Staff for the First Audit Request of the Commission Staff to Idaho Power Company for the 2022 PCA filing may access the confidential documentsposted in the Staff Audit Data Room using:
If you have questions, please contact me at [phone]. Regards, David Fewkes Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting
(: (cell)
(: 208-388-2628 (work)
Archived: Monday, May 2, 2022 9:04:14 AMFrom: Fewkes, David Fewkes, David
Sent: Thursday, February 24, 2022 4:28:00 PMTo: Kathy Stockton
Cc: Fewkes, David White, Tami; Larkin, Matt; Brady, Jessi; Nordstrom, Lisa; Davenport, Christy; Gust, Stacy; Fewkes, David Subject: PCA Staff Audit Data Room
Sensitivity: NormalAttachments:
Certificate of Attorney - 2022-2023 PCA Audit Request.pdf ;
Good afternoon, To enable the Staff of the Idaho Public Utilities Commission to inspect Idaho Power documents under the authority granted by Idaho Code § 61-610, Idaho Power Company has posted its response to the First Audit Request of the Commission Staff toIdaho Power Company for the 2022 PCA filing on a secure FTP site, the Staff Audit Data Room. The Staff Audit Data Room FTP login screen can be accessed via https://fileexch.idahopower.com. USERNAMES: PASSWORDS: An e-mail with the passwords will be sent separately. As noted in Procedural Rule 227, the Commission’s statutory right to audit is independent of any right of discovery in formal proceedings. Idaho Power’s responses to discovery requests submitted by Staff and intervening parties will be posted to aseparate FTP site dedicated to that purpose. If you have questions, please contact me at [phone]. Regards, David Fewkes Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting (: (cell)
(: 208-388-2628 (work)
Archived: Monday, May 2, 2022 9:06:48 AMFrom: Larkin, Matt
Sent: Tuesday, March 22, 2022 2:05:38 PMTo: Kathy Stockton
Cc: Fewkes, David; Robin Maupin Subject: RE: EIM and the PCA Audit
Sensitivity: Normal
Hi Kathy, It’s looking like Wednesday at 10 a.m. is the most likely option, but I’m awaiting confirmation from a few internal folks. Would that time work for you and Robin? Thanks! Matt

From: Kathy Stockton <[e-mail]> Sent: Tuesday, March 22, 2022 10:09 AMTo: Larkin, Matt <[e-mail]>Cc: Fewkes, David <[e-mail]>; Robin Maupin <[e-mail]>Subject: [EXTERNAL]RE: EIM and the PCA Audit KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the sender before proceeding, and check for additional warning messages below.
Has a time been set up to discuss the EIM sales/purchases? Kathy StocktonSenior AuditorIdaho Public Utilities [e-mail][phone]
From: Kathy Stockton Sent: Tuesday, March 15, 2022 11:46 AMTo: Larkin, Matt <[e-mail]>Cc: Fewkes, David <[e-mail]>; Robin Maupin <[e-mail]>Subject: RE: EIM and the PCA Audit
Wednesday or Thursday would be fine, Robin has no availability on Friday, April 1st. Kathy StocktonSenior AuditorIdaho Public Utilities [e-mail][phone]
From: Larkin, Matt <[e-mail]> Sent: Tuesday, March 15, 2022 11:23 AMTo: Kathy Stockton <[e-mail]>Cc: Fewkes, David <[e-mail]>Subject: RE: EIM and the PCA Audit Hi Kathy,
Dave passed along your request to discuss the EIM as it pertains to the PCA. What’s your availability looking like Wednesday, March 30th to Friday, April 1st? Thanks, Matt

From: Kathy Stockton <[e-mail]> Sent: Tuesday, March 8, 2022 4:53 PMTo: Fewkes, David <[e-mail]>Subject: [EXTERNAL]EIM and the PCA Audit KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the sender before proceeding, and check for additional warning messages below.
Hello, I would like to set up a meeting to discuss how the EIM sales and purchases flow through the PCA, and how Idaho Power bids into the EIM market plus any standards, policies and procedures that are applicable to these sales and purchases that are notcovered or specifically addressed in the Energy Risk Management Policy and the Energy Risk Management Standards. Would it be possible to set up a meeting sometime towards the end of March to discuss this? Kathy StocktonSenior AuditorIdaho Public Utilities [e-mail][phone]
IDAHO POWER LEGAL DISCLAIMERThis transmission may contain information that is privileged, confidential and/or exempt from disclosure under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure, copying, distribution, oruse of the information contained herein (including any reliance thereon) is STRICTLY PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the material in its entirety, whether inelectronic or hard copy format. Thank you.
Archived: Monday, May 2, 2022 9:08:37 AMFrom: Fewkes, David
Sent: Wednesday, March 30, 2022 1:19:00 PMTo: Kathy Stockton
Cc: Robin Maupin Subject: RE: PCA Audit Follow up questions
Sensitivity: Normal
Thank you. I appreciate it. Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting
(: (cell)(: 208-388-2628 (work)
From: Kathy Stockton <[e-mail]> Sent: Wednesday, March 30, 2022 1:19 PMTo: Fewkes, David <[e-mail]>Cc: Robin Maupin <[e-mail]>Subject: [EXTERNAL]RE: PCA Audit Follow up questions KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the sender before proceeding, and check for additional warning messages below.
I have added the files for Audit Requests 26, 28, and 30 to the Staff Selections folder on the FTP site. The file names refer back to the first Audit Request number, but have the information in the file name pertaining to the request. Kathy StocktonSenior AuditorIdaho Public Utilities [e-mail][phone]
From: Fewkes, David <[e-mail]> Sent: Monday, March 28, 2022 3:08 PMTo: Kathy Stockton <[e-mail]>Cc: Robin Maupin <[e-mail]>Subject: RE: PCA Audit Follow up questions Excellent, thank you for working with me. I have created a folder on the site. You can navigate to the folder by using the drop-down menu on the left, as pictured below. If there are any issues at all, please let me know.
Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting
(: (cell)(: 208-388-2628 (work)
From: Kathy Stockton <[e-mail]> Sent: Monday, March 28, 2022 3:00 PMTo: Fewkes, David <[e-mail]>Cc: Robin Maupin <[e-mail]>Subject: [EXTERNAL]RE: PCA Audit Follow up questions KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the sender before proceeding, and check for additional warning messages below.
I think that could work. It probably has more confidentiality than email. Currently I have referenced selections in the draft of the second set of audit requests, and I will put something in the request about uploading the files to the FTP site. Kathy StocktonSenior AuditorIdaho Public Utilities [e-mail][phone]
From: Fewkes, David <[e-mail]> Sent: Monday, March 28, 2022 2:49 PMTo: Kathy Stockton <[e-mail]>Cc: White, Tami <[e-mail]>Subject: RE: PCA Audit Follow up questions Hi Kathy, I appreciate your point. I think, using the same credentials you have used to access the confidential response file, you could upload the selections to the FTP site. I could make a folder titled “Staff Selections” and you could upload the file(s). Is this astrategy that you would like to try? I believe it would satisfy the confidentiality concerns. Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting (:cell)
(: 208-388-2628 (work)
From: Kathy Stockton <[e-mail]> Sent: Monday, March 28, 2022 1:44 PM
To: Fewkes, David <[e-mail]>Subject: [EXTERNAL]RE: PCA Audit Follow up questions KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the sender before proceeding, and check for additional warning messages below.
We can add the counterparty and amount of the transaction, I just want to make sure that we are keeping the confidential information confidential. We have selected about 20 transactions from sales and purchases, as well as some transactions fortransmission expense and RECs, and Demand Response payments. We can always send our excel file with the selection outside of the audit request if clarification is needed. On a side note, we are looking at the response to Audit Request No. 19 which references page 4 of each Op Plan, yet that page has no information about the timing of generation fleet scheduled maintenance or other outages. Kathy StocktonSenior AuditorIdaho Public Utilities [e-mail][phone]
From: Fewkes, David <[e-mail]> Sent: Monday, March 28, 2022 1:33 PMTo: Kathy Stockton <[e-mail]>Cc: White, Tami <[e-mail]>Subject: RE: PCA Audit Follow up questions Good afternoon Kathy, Thank you for the question. Idaho Power could have multiple invoices/payments that have the same deal number. In addition to the fields you have recommended, it would be helpful if you would provide the counterparty and amount selected forfurther review in the follow-up audit request. Let me know if this works for you. Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting
(: (cell)
(: 208-388-2628 (work)
From: Kathy Stockton <[e-mail]> Sent: Monday, March 28, 2022 11:43 AMTo: Fewkes, David <[e-mail]>Subject: [EXTERNAL]PCA Audit Follow up questions KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the sender before proceeding, and check for additional warning messages below.
Robin and I are working on follow-up audit requests for the PCA. We have a selection of sales and purchases for further review, and in order to maintain confidentiality, we would like to know how to include the sales and purchases in our follow-up auditrequest. Will the month and deal number be sufficient for selection? For example: Month Deal Number4/30/2021 139999 Thanks, Kathy StocktonSenior AuditorIdaho Public Utilities [e-mail][phone]
IDAHO POWER LEGAL DISCLAIMERThis transmission may contain information that is privileged, confidential and/or exempt from disclosure under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure, copying, distribution, oruse of the information contained herein (including any reliance thereon) is STRICTLY PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the material in its entirety, whether inelectronic or hard copy format. Thank you.
Archived: Monday, May 2, 2022 9:09:30 AMFrom: Kathy Stockton
Sent: Friday, April 1, 2022 5:19:13 PMTo: Fewkes, David
Cc: Robin Maupin Subject: [EXTERNAL]EIM transactions added to Staff Selection File
Sensitivity: Normal
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the sender before proceeding, and check for additional warning messages below.
Good afternoon, Wednesday Robin and I met with IPC personnel to discuss the mechanics of the EIM market and how Idaho Power bids into the market. Now that we have a somewhat better understanding of how the market works, we have selected two months of EIMtransactions for further review. Since these transactions are included in the response to Audit Request No. 5, and since we already have a follow-up question, I would like to add our transaction selection to Audit Request No. 26. I have uploaded theselection file to the Staff Selection location on the FTP site. We would like to look at the invoices and accompanying documents for the EIM transactions for the months of August and October. I have highlighted our selection in orange on the selection file. It is our understanding that that the EIM invoices arerather complicated, so we may reach out for further help with that. I will be out of the office all next week and will be checking my emails periodically during the week. Thank you for your time, Kathy StocktonSenior AuditorIdaho Public Utilities [e-mail][phone]
Archived: Monday, May 2, 2022 9:10:33 AMFrom: Kathy Stockton
Sent: Tuesday, April 12, 2022 11:33:01 AMTo: Fewkes, David
Subject: [EXTERNAL]RE: PCA 1 - 24 UpdatesSensitivity: Normal
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the sender before proceeding, and check for additional warning messages below.
That sounds like it will work. Kathy StocktonSenior AuditorIdaho Public Utilities [e-mail][phone]
From: Fewkes, David <[e-mail]> Sent: Tuesday, April 12, 2022 11:32 AMTo: Kathy Stockton <[e-mail]>Subject: RE: PCA 1 - 24 Updates
I was hoping to be able to give the internal folks until Friday, the 22nd. Would Tuesday, the 26th work for you? I could cut that to internal folks by the 21st, and to you on Monday, the 25th, maybe? Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting
(: (cell)
(: 208-388-2628 (work)
From: Kathy Stockton <[e-mail]> Sent: Tuesday, April 12, 2022 11:29 AMTo: Fewkes, David <[e-mail]>Subject: [EXTERNAL]RE: PCA 1 - 24 Updates KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the sender before proceeding, and check for additional warning messages below.
It would be good to get the updated responses as soon as possible, although I know that monthly closings may impact response time. I expect the PCA case to be filed by Monday, April 18, 2022, so how about Friday April 22, 2022. Will that date work? Kathy StocktonSenior AuditorIdaho Public Utilities [e-mail][phone]
From: Fewkes, David <[e-mail]> Sent: Tuesday, April 12, 2022 8:28 AMTo: Kathy Stockton <[e-mail]>Subject: PCA 1 - 24 Updates Good morning, I’m about to circulate the request for updated responses for audit requests 1 – 24 (Jan – March). When were you hoping you would receive the updated responses? I want to put a deadline on the request that I circulate that is reasonable and aligns withyour expectations. Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting
(: (cell)
(: 208-388-2628 (work)
IDAHO POWER LEGAL DISCLAIMERThis transmission may contain information that is privileged, confidential and/or exempt from disclosure under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure, copying, distribution, oruse of the information contained herein (including any reliance thereon) is STRICTLY PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the material in its entirety, whether inelectronic or hard copy format. Thank you.
Archived: Monday, May 2, 2022 9:12:03 AMFrom: Fewkes, David Fewkes, David
Sent: Wednesday, April 13, 2022 10:44:00 AMTo: Kathy Stockton; Donn English
Cc: Fewkes, David White, Tami; Larkin, Matt; Brady, Jessi; Nordstrom, Lisa; Davenport, Christy; Gust, Stacy; Fewkes, David Subject: ENCRYPT PCA Staff Audit Data Room
Sensitivity: Normal
SENT VIA ENCRYPTED E-MAIL Good morning, Staff members may access non-confidential documents submitted in response to the Second Audit Request of the Commission Staff to Idaho Power Company for the 2022 PCA filing, in the Staff Audit Data Room using:
Staff members who have signed the Protective Agreement executed by Idaho Power and the Commission Staff for the First Audit Request of the Commission Staff to Idaho Power Company for the 2022 PCA filing may access the confidential documentsposted in the Staff Audit Data Room using:
If you have questions, please contact me at [phone]. Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting (:cell)
(: 208-388-2628 (work)
Archived: Monday, May 2, 2022 9:11:36 AMFrom: Fewkes, David Fewkes, David
Sent: Wednesday, April 13, 2022 10:44:00 AMTo: Kathy Stockton; Donn English
Cc: Fewkes, David White, Tami; Larkin, Matt; Brady, Jessi; Nordstrom, Lisa; Davenport, Christy; Gust, Stacy; Fewkes, David Subject: PCA Staff Audit Data Room
Sensitivity: NormalAttachments:
Certificate of Attorney - 2022-2023 PCA Audit Request.pdf ;
Good morning, To enable the Staff of the Idaho Public Utilities Commission to inspect Idaho Power documents under the authority granted by Idaho Code § 61-610, Idaho Power Company has posted its response to the Second Audit Request of the Commission Staff toIdaho Power Company for the 2022 PCA filing on a secure FTP site, the Staff Audit Data Room. The Staff Audit Data Room FTP login screen can be accessed via https://fileexch.idahopower.com. USERNAMES: PASSWORDS: An e-mail with the passwords will be sent separately. As noted in Procedural Rule 227, the Commission’s statutory right to audit is independent of any right of discovery in formal proceedings. Idaho Power’s responses to discovery requests submitted by Staff and intervening parties will be posted to aseparate FTP site dedicated to that purpose. If you have questions, please contact me at [phone]. Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting (: (cell)
(: 208-388-2628 (work)
Archived: Monday, May 2, 2022 9:10:57 AMFrom: Kathy Stockton
Sent: Wednesday, April 13, 2022 10:42:32 AMTo: Fewkes, David
Subject: [EXTERNAL]RE: Note regarding 2nd Audit Request responsesSensitivity: Normal
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the sender before proceeding, and check for additional warning messages below.
Thank you so much. I think the bookmark system will be excellent. Kathy StocktonSenior AuditorIdaho Public Utilities [e-mail][phone]
From: Fewkes, David <[e-mail]> Sent: Wednesday, April 13, 2022 10:41 AMTo: Kathy Stockton <[e-mail]>Subject: Note regarding 2nd Audit Request responses Good morning Kathy,
I’m about to send the 2nd Audit Request responses numbered 25 – 31. I want to touch bases with you before I send them. I did something a little different this time in hopes that it will make reviewing the selections easier than before. In short, rather than send dozens of files over, I have combined each question’s selections into one file, except for 26. With 26, there were the initial 19 selections which I have combined into one file, and then the subsequent EIM selections which Icombined into a second attachment in response to 26. When you open the PDFs, they include a Table of Contents, but probably more useful are the bookmarks I have included in each of the files. Please take a look at the bookmarks in the PDF files. You can click on the bookmark for each selection which willtake you right to the information you are looking for. The Table of Contents functions similarly, but in my experience, the bookmarks make the process more efficient. If you have any questions at all, or concerns regarding this approach, please let me know. Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting
(:(cell)
(: 208-388-2628 (work)
IDAHO POWER LEGAL DISCLAIMERThis transmission may contain information that is privileged, confidential and/or exempt from disclosure under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure, copying, distribution, oruse of the information contained herein (including any reliance thereon) is STRICTLY PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the material in its entirety, whether inelectronic or hard copy format. Thank you.
Archived: Monday, May 2, 2022 9:13:28 AMFrom: Fewkes, David Fewkes, David
Sent: Friday, April 22, 2022 10:24:00 AMTo: Kathy Stockton; Donn English
Cc: Fewkes, David White, Tami; Larkin, Matt; Brady, Jessi; Nordstrom, Lisa; Davenport, Christy; Gust, Stacy; Fewkes, David Subject: ENCRYPT Supplemental Responses - PCA Staff Audit Data Room
Sensitivity: Normal
SENT VIA ENCRYPTED E-MAIL Good morning, Staff members may access non-confidential documents submitted in the supplemental response to the First Audit Request of the Commission Staff to Idaho Power Company for the 2022 PCA filing, in the Staff Audit Data Room using:
Staff members who have signed the Protective Agreement executed by Idaho Power and the Commission Staff for the First Audit Request of the Commission Staff to Idaho Power Company for the 2022 PCA filing may access the confidential documentsposted in the Staff Audit Data Room using:
If you have questions, please contact me at [phone]. Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting (: (cell)
(: 208-388-2628 (work)
Archived: Monday, May 2, 2022 9:13:06 AMFrom: Fewkes, David Fewkes, David
Sent: Friday, April 22, 2022 10:24:00 AMTo: Kathy Stockton; Donn English
Cc: Fewkes, David White, Tami; Larkin, Matt; Brady, Jessi; Nordstrom, Lisa; Davenport, Christy; Gust, Stacy; Fewkes, David Subject: Supplemental Responses - PCA Staff Audit Data Room
Sensitivity: NormalAttachments:
Certificate of Attorney - IPC-E-22-11.pdf ;
Good morning, To enable the Staff of the Idaho Public Utilities Commission to inspect Idaho Power documents under the authority granted by Idaho Code § 61-610, Idaho Power Company has posted its supplemental response to the First Audit Request of theCommission Staff to Idaho Power Company for the 2022 PCA filing on a secure FTP site, the Staff Audit Data Room. The Staff Audit Data Room FTP login screen can be accessed via https://fileexch.idahopower.com. USERNAMES: PASSWORDS: An e-mail with the passwords will be sent separately. As noted in Procedural Rule 227, the Commission’s statutory right to audit is independent of any right of discovery in formal proceedings. Idaho Power’s responses to discovery requests submitted by Staff and intervening parties will be posted to aseparate FTP site dedicated to that purpose. If you have questions, please contact me at [phone]. Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting (: (cell)
(: 208-388-2628 (work)
Archived: Monday, May 2, 2022 9:14:17 AMFrom: Kathy Stockton
Sent: Friday, April 22, 2022 11:42:47 AMTo: Fewkes, David
Subject: [EXTERNAL]RE: Supplemental responses to First Audit RequestSensitivity: Normal
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify the sender before proceeding, and check for additional warning messages below.
Thank you! I may not review these today, but I will let you know Monday if there are any issues. Kathy StocktonSenior AuditorIdaho Public Utilities [e-mail][phone]
From: Fewkes, David <[e-mail]> Sent: Friday, April 22, 2022 10:30 AMTo: Kathy Stockton <[e-mail]>Subject: Supplemental responses to First Audit Request Good morning. I emailed the notification that I have posted the responses to the secure FTP site a few minutes ago. If you have questions about the organization of responses, or any questions at all, please feel free to contact me. In a prior email, you made a side note that suggested the requested information for AR 19 was not available where I had noted its availability. You are correct and I apologize for the confusion. In this supplemental response, I have provided a maintenancereport for the entire PCA period. I believe it will satisfactorily address the request, but let me know if you have additional questions, comments, or concerns. Take care, David FewkesBUDGET APPLICATION ANALYSTIdaho Power | Corporate Budgeting
(: (cell)
(: 208-388-2628 (work)
IDAHO POWER LEGAL DISCLAIMERThis transmission may contain information that is privileged, confidential and/or exempt from disclosure under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure, copying, distribution, oruse of the information contained herein (including any reliance thereon) is STRICTLY PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the material in its entirety, whether inelectronic or hard copy format. Thank you.
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-22-11
IDAHO POWER COMPANY
REQUEST NO. 2
ATTACHMENT NO. 2
1
From:Kathy Stockton <[e-mail]>
Sent:Wednesday, March 30, 2022 9:26 AM
To:Larkin, Matt
Subject:[EXTERNAL]Accepted: Idaho Power EIM Discussion
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify 
the sender before proceeding, and check for additional warning messages below. 

1
From:Larkin, Matt
Sent:Wednesday, March 30, 2022 10:02 AM
To:Kathy Stockton
Subject:RE: EIM and the PCA Audit
Ok I was afraid of that. We’ll send a WebEx link and switch over to that.  

From: Kathy Stockton <[e-mail]>  
Sent: Wednesday, March 30, 2022 10:00 AM 
To: Larkin, Matt <[e-mail]> 
Subject: [EXTERNAL]RE: EIM and the PCA Audit 

KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify 
the sender before proceeding, and check for additional warning messages below. 
Teams isn’t allow us to join 

Kathy Stockton 
Senior Auditor 
Idaho Public Utilities Commission 
[e-mail] 
(208) 334‐0360 

From: Larkin, Matt <[e-mail]>  
Sent: Wednesday, March 30, 2022 8:59 AM 
To: Kathy Stockton <[e-mail]> 
Subject: RE: EIM and the PCA Audit 

Nope! I’ll send it now. Thanks!  

From: Kathy Stockton <[e-mail]>  
Sent: Wednesday, March 30, 2022 8:58 AM 
To: Larkin, Matt <[e-mail]> 
Subject: [EXTERNAL]RE: EIM and the PCA Audit 

KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify 
the sender before proceeding, and check for additional warning messages below. 
Did you send a Webex link and I missed it? 

Kathy Stockton 
Senior Auditor 
Idaho Public Utilities Commission 
[e-mail] 
(208) 334‐0360 

2
From: Larkin, Matt <[e-mail]>  
Sent: Wednesday, March 23, 2022 3:03 PM 
To: Kathy Stockton <[e-mail]> 
Cc: Robin Maupin <[e-mail]> 
Subject: RE: EIM and the PCA Audit 

OK great. Let’s block out 10 a.m., Wednesday, March 30th. I’ll get an official invite sent over with a WebEx link. And I 
agree, the REC meeting will be different people, so I’ll get to work checking availability on that.  

Thanks! 
Matt 

From: Kathy Stockton <[e-mail]>  
Sent: Tuesday, March 22, 2022 2:11 PM 
To: Larkin, Matt <[e-mail]> 
Cc: Robin Maupin <[e-mail]> 
Subject: [EXTERNAL]RE: EIM and the PCA Audit 

KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify 
the sender before proceeding, and check for additional warning messages below. 
Wednesday at 10 AM next week will work for us. 

As we have been auditing, I find that I could use a refresher course on the RECs and how they are sold, whether bundled, 
etc. so perhaps someone to speak to that as well?  I realize that is probably someone from the Merchant side of the 
house rather than the Load Serving Entity so probably two separate meetings. 

Kathy Stockton 
Senior Auditor 
Idaho Public Utilities Commission 
[e-mail] 
(208) 334‐0360 

From: Larkin, Matt <[e-mail]>  
Sent: Tuesday, March 22, 2022 2:06 PM 
To: Kathy Stockton <[e-mail]> 
Cc: Fewkes, David <[e-mail]>; Robin Maupin <[e-mail]> 
Subject: RE: EIM and the PCA Audit 

Hi Kathy, 

It’s looking like Wednesday at 10 a.m. is the most likely option, but I’m awaiting confirmation from a few internal folks. 
Would that time work for you and Robin? 

Thanks! 

Matt 

3
From: Kathy Stockton <[e-mail]>  
Sent: Tuesday, March 22, 2022 10:09 AM 
To: Larkin, Matt <[e-mail]> 
Cc: Fewkes, David <[e-mail]>; Robin Maupin <[e-mail]> 
Subject: [EXTERNAL]RE: EIM and the PCA Audit 

KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify 
the sender before proceeding, and check for additional warning messages below. 
Has a time been set up to discuss the EIM sales/purchases? 

Kathy Stockton 
Senior Auditor 
Idaho Public Utilities Commission 
[e-mail] 
(208) 334‐0360 

From: Kathy Stockton  
Sent: Tuesday, March 15, 2022 11:46 AM 
To: Larkin, Matt <[e-mail]> 
Cc: Fewkes, David <[e-mail]>; Robin Maupin <[e-mail]> 
Subject: RE: EIM and the PCA Audit 

Wednesday or Thursday would be fine, Robin has no availability on Friday, April 1st. 

Kathy Stockton 
Senior Auditor 
Idaho Public Utilities Commission 
[e-mail] 
(208) 334‐0360 

From: Larkin, Matt <[e-mail]>  
Sent: Tuesday, March 15, 2022 11:23 AM 
To: Kathy Stockton <[e-mail]> 
Cc: Fewkes, David <[e-mail]> 
Subject: RE: EIM and the PCA Audit 

Hi Kathy,  

Dave passed along your request to discuss the EIM as it pertains to the PCA. What’s your availability looking like 
Wednesday, March 30th to Friday, April 1st?  

Thanks,  

Matt  

From: Kathy Stockton <[e-mail]>  
Sent: Tuesday, March 8, 2022 4:53 PM 
To: Fewkes, David <[e-mail]> 
Subject: [EXTERNAL]EIM and the PCA Audit 
4

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Hello, 

I would like to set up a meeting to discuss how the EIM sales and purchases flow through the PCA, and how Idaho Power 
bids into the EIM market plus any standards, policies and procedures that are applicable to these sales and purchases 
that are not covered or specifically addressed in the Energy Risk Management Policy and the Energy Risk Management 
Standards. 

Would it be possible to set up a meeting sometime towards the end of March to discuss this? 

Kathy Stockton 
Senior Auditor 
Idaho Public Utilities Commission 
[e-mail] 
(208) 334‐0360 

IDAHO POWER LEGAL DISCLAIMER 
This transmission may contain information that is privileged, confidential and/or exempt from disclosure 
under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure, 
copying, distribution, or use of the information contained herein (including any reliance thereon) is STRICTLY 
PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the 
material in its entirety, whether in electronic or hard copy format. Thank you. 
1
From:Kathy Stockton <[e-mail]>
Sent:Thursday, April 14, 2022 11:38 AM
To:Larkin, Matt
Cc:Robin Maupin; Travis Culbertson
Subject:[EXTERNAL]RE: REC discussion for the upcoming PCA
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify 
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Let me see what we already have for that week and get back to you.   
We will be joined by Travis Culbertson as he will be focusing on the RECs in the PCA.   
Since the case will be filed by then, all the attendees to the meeting will have signed a confidentiality agreement. 
Kathy Stockton 
Senior Auditor 
Idaho Public Utilities Commission 
[e-mail] 
(208)334‐0360
From: Larkin, Matt <[e-mail]>  
Sent: Thursday, April 14, 2022 11:33 AM 
To: Kathy Stockton <[e-mail]> 
Cc: Robin Maupin <[e-mail]> 
Subject: RE: REC discussion for the upcoming PCA 
Hi Kathy, 
Apologies for taking so long to get this set up. Would the afternoon of Monday, April 25th, or Tuesday, April 26th work? 
I’m out of the office all next week (taking the 4 year old nephew to Disneyland… wish me luck).  
We’re pretty open that whole week of April 25th, so if another day / time would work better let me know.  
Thanks! 
Matt 
From: Kathy Stockton <[e-mail]>  
Sent: Wednesday, April 13, 2022 4:30 PM 
To: Larkin, Matt <[e-mail]> 
Cc: Robin Maupin <[e-mail]> 
Subject: [EXTERNAL]REC discussion for the upcoming PCA 
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2
Any progress in setting up a meeting to go over RECs in general and how they flow through the PCA?  At this point, any 
time after the PCA is filed should work. 

Kathy Stockton 
Senior Auditor 
Idaho Public Utilities Commission 
[e-mail] 
(208) 334‐0360 

IDAHO POWER LEGAL DISCLAIMER 
This transmission may contain information that is privileged, confidential and/or exempt from disclosure 
under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure, 
copying, distribution, or use of the information contained herein (including any reliance thereon) is STRICTLY 
PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the 
material in its entirety, whether in electronic or hard copy format. Thank you. 
1
From:Taylor Thomas
Sent:Wednesday, April 27, 2022 3:41 PM
To:Larkin, Matt
Subject:[EXTERNAL]Accepted: REC / PCA Meeting with IPUC Staff
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1
From:Robin Maupin <[e-mail]>
Sent:Wednesday, April 27, 2022 5:07 PM
To:Larkin, Matt
Subject:[EXTERNAL]Accepted: REC / PCA Meeting with IPUC Staff
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1
From:Laura Conilogue <[e-mail]>
Sent:Wednesday, April 27, 2022 3:59 PM
To:Larkin, Matt
Subject:[EXTERNAL]Accepted: REC / PCA Meeting with IPUC Staff
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1
From:Kathy Stockton <[e-mail]>
Sent:Thursday, April 28, 2022 12:47 PM
To:Larkin, Matt
Subject:[EXTERNAL]RE: REC Questions and overview
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Thanks. 

The explanation about the timing of the transactions versus the actual execution and payment makes sense. 

Kathy Stockton 
Senior Auditor 
Idaho Public Utilities Commission 
[e-mail] 
(208) 334‐0360 

From: Larkin, Matt <[e-mail]>  
Sent: Thursday, April 28, 2022 12:46 PM 
To: Kathy Stockton <[e-mail]> 
Subject: RE: REC Questions and overview 

Ok sounds good. I’ll pass your question along and we’ll plan to chat at 3:00. Thanks!  

From: Kathy Stockton <[e-mail]>  
Sent: Thursday, April 28, 2022 12:45 PM 
To: Larkin, Matt <[e-mail]> 
Subject: [EXTERNAL]RE: REC Questions and overview 

KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify 
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That makes sense accounting‐wise.  I think our new people will still benefit from a REC discussion.  I am personally 
slightly confused about selling them in the different time periods and how the RECs are acquired.   

I also have a question about off‐system sales bundled with RECs.  Are those RECs that the Company has? Does the 
Company buy them to bundle?  

Kathy Stockton 
Senior Auditor 
Idaho Public Utilities Commission 
[e-mail] 
(208) 334‐0360 

2
From: Larkin, Matt <[e-mail]>  
Sent: Thursday, April 28, 2022 12:20 PM 
To: Kathy Stockton <[e-mail]> 
Cc: Robin Maupin <[e-mail]> 
Subject: RE: REC Questions and overview 

Hi Kathy! 

In preparation for today’s call, we chatted with our Op Plan and accounting folks about your question. The short answer 
is as follows: the REC transactions provided in Audit Request 10 will not reconcile to the REC transactions shown in the 
Op plan and the Appendix due to timing differences. The REC transactions in the Op plan are based on when the 
transactions are executed. The REC transactions in the audit request and PCA deferral report are based on when the 
RECs are actually transferred to the counterparty. We do not record the REC transactions in the PCA until they are 
transferred to the counterparty, which could be months or years after the transaction is initially executed.  

Does that answer your question? We’re happy to meet this afternoon and walk through that, but I didn’t know if that 
explanation would resolve the questions you had regarding the audit info.  

Thanks! 

Matt 

‐‐  
Matt Larkin 
REVENUE REQUIREMENT MANAGER 
Idaho Power | Regulatory Affairs 
1221 W. Idaho St. | Boise, ID | 83702 
Work 208‐388‐2461 
Fax 208‐388‐6449 
Email [e-mail] 

From: Kathy Stockton <[e-mail]>  
Sent: Wednesday, April 27, 2022 1:03 PM 
To: Larkin, Matt <[e-mail]> 
Cc: Robin Maupin <[e-mail]> 
Subject: [EXTERNAL]RE: REC Questions and overview 

KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify 
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I think tomorrow between 3 and 4 will work.  We may have other staff members attending and I will make sure they 
have signed the protective agreement. 

Nothing says party like RECs! 

Kathy Stockton 
Senior Auditor 
3
Idaho Public Utilities Commission 
[e-mail] 
(208) 334‐0360 

From: Larkin, Matt <[e-mail]>  
Sent: Wednesday, April 27, 2022 12:24 PM 
To: Kathy Stockton <[e-mail]> 
Subject: RE: REC Questions and overview 

Hi Kathy,  

Sounds good. Would you be available tomorrow between 3 and 4? Or Friday, 11 a.m. or after?  

Thanks, 

Matt 

From: Kathy Stockton <[e-mail]>  
Sent: Wednesday, April 27, 2022 12:19 PM 
To: Larkin, Matt <[e-mail]> 
Subject: [EXTERNAL]REC Questions and overview 

KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify 
the sender before proceeding, and check for additional warning messages below. 
Staff (Robin & I) would like to schedule a time to discuss the RECs and how they are handled in the PCA.  I am reviewing 
the Op Plan for March 2022 and I am wanting to reconcile these with the spreadsheet “Renewable Energy Credits 
Transaction Summary” in Supplemental Response to Staff’s AR 10. 

I know that RECs can be sold forwards and backwards, yet I am not able to tie together the amounts in AR 10 with what 
is in the Confidential Op Plans. 

Any help is greatly appreciated. 

Kathy Stockton 
Senior Auditor 
Idaho Public Utilities Commission 
[e-mail] 
(208) 334‐0360 

IDAHO POWER LEGAL DISCLAIMER 
This transmission may contain information that is privileged, confidential and/or exempt from disclosure 
under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure, 
copying, distribution, or use of the information contained herein (including any reliance thereon) is STRICTLY 
PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the 
material in its entirety, whether in electronic or hard copy format. Thank you. 

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

REQUEST NO. 2

ATTACHMENT NO. 3
1
From:Gust, Stacy
Sent:Friday, April 15, 2022 4:07 PM
To:Jan Noriyuki
Cc:Nordstrom, Lisa
Subject:IPC-E-22-11 Application of Idaho Power Company for Authority to Implement Power
Cost Adjustment (PCA) Rates for Electric Service from June 1, 2022 through May 31,
2023
Attachments:Application.pdf; Direct Testimony of Jessica Brady.pdf; BillInsert_PCA.pdf;
Postcard_PCA.pdf; PCA News Release.pdf; Exhibit No. 1 - 2022-2023 PCA Forecast.xlsx;
Exhibit No. 2 - 2022 PCA Deferral Report - Balancing Adjustment.xlsx; Exhibit No. 3 -
2022 ROE Determination Revenue Sharing Benefits.xlsx; Exhibit No. 4 - 2022 Earnings
Sharing Benefit.xlsx
Ms. Noriyuki,

Please find attached for electronic filing, pursuant to Order No. 35058, Idaho Power Company’s 2022-2023 Power Cost
Adjustment (PCA) Application, the Direct Testimony of Jessica Brady, PCA Bill Insert, PCA Postcard, and PCA News
Release.

Also provided as a courtesy to Staff are the Excel workpapers.

If you have any questions regarding this filing, please do not hesitate to contact me.

Thank you.

Stacy Gust
REGULATORY ADMINISTRATIVE ASSISTANT
Idaho Power | Regulatory Affairs
Office 208-388-5749

LISA D. NORDSTROM
Lead Counsel
[e-mail]

April 15, 2022

Jan Noriyuki, Secretary
Idaho Public Utilities Commission
11331 W. Chinden Boulevard
Building 8, Suite 201-A
Boise, Idaho 83714

Re: Case No. IPC-E-22-11
Application of Idaho Power Company for Authority to Implement Power Cost
Adjustment (“PCA”) Rates for Electric Service from June 1, 2022, through May
31, 2023

Dear Ms. Noriyuki:

Attached for electronic filing, pursuant to Order No. 35058, is Idaho Power Company’s
Application in the above-entitled matter.

In addition, please find attached the Direct Testimony of Jessica G. Brady filed in
support of the Application. A Word version of the testimony will also be sent in a separate
email for the convenience of the Reporter.

Accompanying this filing is the Company’s Press Release, Customer Notice, and
Direct Mail Postcard.

If you have any questions about the attached documents, please do not hesitate to
contact me.

Sincerely,

Lisa D. Nordstrom

LDN:sg
Enclosures

APPLICATION - 1
LISA D. NORDSTROM (ISB No. 5733)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
[e-mail]

Attorney for Idaho Power Company

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO IMPLEMENT POWER
COST ADJUSTMENT (“PCA”) RATES
FOR ELECTRIC SERVICE FROM JUNE
1, 2022, THROUGH MAY 31, 2023.

)
)
)
)
)
)

CASE NO. IPC-E-22-11

APPLICATION

Idaho Power Company (“Idaho Power” or “Company”), in accordance with Idaho
Code § 61-502 and RP 052, hereby respectfully requests the Idaho Public Utilities
Commission (“Commission”) approve an update to Schedule 55 based on the
quantification of the 2022-2023 Power Cost Adjustment (“PCA”) to become effective June
1, 2022, for the period June 1, 2022, through May 31, 2023. If the proposed rates and
charges for electric service in the state of Idaho included as Attachment 1 to this
Application are approved, the 2022-2023 PCA will result in an overall revenue increase
of approximately $103.4 million, or an 8.27 percent increase from current billed revenue.

APPLICATION - 2
In support of this Application, Idaho Power has filed the Direct Testimony of
Jessica G. Brady, Regulatory Analyst. Ms. Brady’s testimony details the 2022-2023 PCA
amount, explains the factors that impact this year’s PCA quantification, details the
calculation of the proposed 2022-2023 PCA rates, and discusses the additional PCA
component related to revenue sharing.
I. BACKGROUND
1. Idaho Power is an Idaho corporation whose principal place of business is
1221 West Idaho Street, Boise, Idaho 83702.
2. Idaho Power is a public utility supplying retail electric service to more than
600,000 customers in southern Idaho and eastern Oregon. Idaho Power is subject to the
jurisdiction of this Commission in Idaho and to the jurisdiction of the Public Utility
Commission of Oregon. Idaho Power is also subject to the jurisdiction of the Federal
Energy Regulatory Commission.
3. On March 29, 1993, by Order No. 24806 issued in Case No. IPC-E-92-25,
the Commission approved the implementation of an annual power cost adjustment
procedure in order to provide consistency and stability to rates. The PCA is a cost
recovery mechanism that passes on both the benefits and costs of supplying energy to
Idaho Power customers. Neither Idaho Power nor its shareholders receive any financial
return on this filing – money collected from the surcharge can be used only to pay power
supply expenses.
4. On January 9, 2009, by Order No. 30715 issued in Case No. IPC-E-08-19,
the Commission approved certain changes to the PCA mechanism, including a 95
percent/5 percent sharing mechanism between customers and the Company. Order No.

APPLICATION - 3
30715 also approved changes to the Load Growth Adjustment Rate (“LGAR”), third-party
transmission expense, the PCA forecast, and power supply expense distribution.
5. On January 13, 2010, the Commission issued Order No. 30978 in Case No.
IPC-E-09-30 approving the settlement stipulation filed in lieu of a general rate case.
Through this stipulation, a revenue sharing mechanism was established to allow the
Company to accelerate the amortization of accumulated deferred investment tax credits
if the Company’s actual Idaho jurisdictional year-end Return on Equity (“ROE”) fell below
9.5 percent in any fiscal year from 2009 through 2011. This mechanism also included a
provision for revenue sharing if the Company’s actual Idaho jurisdictional year-end ROE
exceeded 10.5 percent in any year during the same three-year period. Per the terms of
the stipulation, 50 percent of the Idaho jurisdictional year-end ROE in excess of 10.5
percent was to be shared with customers in the form of a rate reduction. The revenue
sharing percentages, thresholds, accounting, and duration were subsequently modified
by Order Nos. 32424, 33149 and 34071.
6. On March 15, 2011, the Commission issued Order No. 32206 in Case No.
GNR-E-10-03 adopting a revised LGAR methodology and changing the name of the
methodology to the Load Change Adjustment Rate (“LCAR”).
7. On May 28, 2015, the Commission issued Order No. 33307 in Case No.
IPC-E-15-15 converting the LCAR to a Sales Based Adjustment (“SBA”) rate, as well as
modifying the PCA deferral balance’s monthly interest calculation. Per Order No. 33307,
the SBA rate is calculated in the same manner as the LCAR, with the only modification
being the replacement of the load-based megawatt-hour (“MWh”) denominator with the
corresponding sales-based MWh denominator. Second, the Order required the Company

APPLICATION - 4
to calculate monthly interest on the deferral balance by assigning annual base Net Power
Supply Expense (“NPSE”) to each month according to expected base rate revenue
collection as set in the Company’s last general rate case, Case No. IPC-E-11-08.
8. On May 31, 2018, the Commission issued Order No. 34071 in Case No.
GNR-U-18-01 approving the current iteration of the revenue sharing mechanism. This
order accepted the settlement stipulation filed on April 12, 2018, extending the revenue
sharing mechanism indefinitely and modifying portions of the previous accounting order.
More specifically, Order No. 34071 approved modifications to the sharing portion of the
mechanism, which allowed for greater customer benefits. First, for actual year-end Idaho
jurisdictional earnings greater than 10 percent ROE, all amounts up to and including 10.5
percent ROE will be shared between customers and the Company on an 80 percent and
20 percent basis, respectively. The customer revenue sharing benefit will be in the form
of a reduction to rates at the time the subsequent year’s PCA becomes effective. Second,
Idaho earnings above a 10.5 percent ROE will also be shared, with customers receiving
55 percent of the earnings in the form of a reduction to rates at the time the subsequent
year’s PCA becomes effective, as well as 25 percent of the earnings applied as an offset
to the Company’s pension balancing account, with the Company retaining the remaining
20 percent.
9. On May 28, 2021, the Commission instructed Idaho Power “to initiate
discussions with interested parties and to file a case with the Commission to review
whether the PCA mechanism should be modified” before the Company files its PCA
application in April 2022. Order No. 35054. On January 10, 2022, the Commission issued
Order No. 35290 in Case No. IPC-E-21-18 approving a modification to the PCA filing to

APPLICATION - 5
replace the “true-up” and “true-up of the true-up” with a single balancing account referred
to below as the “Balancing Adjustment.” This modification does not materially affect the
overall cost recovery of the PCA.
II. 2022-2023 PCA CALCULATION
10. The PCA is a rate mechanism that quantifies and tracks annual differences
between actual NPSE and the normalized or “base level” of NPSE recovered in the
Company’s base rates for recovery or credit through an annual rate change on June 1.
The PCA is also the rate mechanism used by the Company to provide direct revenue
sharing benefits resulting from the revenue sharing mechanism approved in Order No.
34071.
11. The PCA mechanism utilizes a 12-month test period of April through March
(“PCA Year”) and consists of a forecast component and a Balancing Adjustment. The
PCA forecast component is based on the Company’s March Operating Plan and
represents the difference between the NPSE forecast in the March Operating Plan and
the base level NPSE recovered in the Company’s base rates. The Balancing Adjustment
includes a backward-looking tracking of differences between the prior PCA Year’s
forecast and actual NPSE incurred by the Company, and also tracks the collection of the
prior year’s Balancing Adjustment.
12. With the exception of Public Utility Regulatory Policies Act of 1978
(“PURPA”) expenses and demand response incentive costs, the PCA allows the
Company to pass through to Idaho customers 95 percent of the annual differences in
actual NPSE as compared to the base level NPSE, whether positive or negative.

APPLICATION - 6
13. Forecast. The testimony of Ms. Brady describes and computes the PCA
rate to be effective June 1, 2022, through May 31, 2023. The system-level forecast of
NPSE for the 2022-2023 PCA Year is $498,834,556, which is $193,149,687 higher than
the currently approved base level NPSE of $305,684,869. The 2022-2023 PCA forecast
component to be collected from Idaho customers is $178,795,145. As described in the
testimony of Ms. Brady, the system-level forecast of NPSE for the 2022-2023 PCA Year
is $56,477,149 higher than last year’s forecast amount of $442,357,407. This year, due
to an expected reduction in hydro generation and increase in both natural gas prices and
market energy prices, the Company expects to increase coal generation for load service
as well as off-system surplus sales.
14. Balancing Adjustment. Per Order 35290, the “true-up” and the “true-up of
the true-up” have been combined into a single Balancing Adjustment. In addition to the
NPSE incurred during the April 2021 through March 2022 period, Idaho Power included
its actual cost of Western Energy Imbalance Market (“EIM”) participation for April 2021
through March 2022 in the Balancing Adjustment as approved by Commission Order No.
34100. Benefits associated with EIM participation are embedded in actual NPSE
experienced over that same period.
15. The PCA Balancing Adjustment deferral balance at the end of March 2022,
with interest applied, was approximately $38.7 million. This balance was primarily driven
by a decrease in actual hydro generation from expected as well as higher than forecast
market purchases, offset by increased surplus sales.
16. Combined Uniform PCA Rate. The Company’s uniform PCA rate for the
2022-2023 PCA Year is comprised of (1) the 1.1926 cents per kilowatt-hour (“kWh”)

APPLICATION - 7
adjustment for the 2022-2023 projected power cost of serving firm loads under the current
PCA methodology and 95 percent sharing and (2) 0.2579 cents per kWh for the 2021-
2022 Balancing Adjustment. The sum of these two components results in an approximate
1.4505 cents per kWh charge for all rate classes.
III. REVENUE SHARING
17. The Company’s earnings in each year from 2011 through 2015, as well as
2018, resulted in revenue sharing with Idaho customers totaling $126.2 million, either as
a direct rate offset in the PCA or as an offset to amounts that would have otherwise been
collected in rates. The Company’s earnings in 2016, 2017, 2019, and 2020 were below
the revenue sharing threshold. As described in greater detail in the direct testimony of
Ms. Brady, the Company’s 2021 Idaho jurisdictional year-end ROE was 10.02 percent.
In accordance with the terms of the modified revenue sharing mechanism approved by
Order No. 34071, the Company’s Idaho jurisdictional year-end ROE was above the 10.0
percent ROE threshold for revenue sharing. Therefore, the 2022-2023 PCA will include
a revenue sharing component of $568,771.
IV. CUMULATIVE PROPOSED JUNE 1, 2022, RATE CHANGES
18. PCA. The 2022-2023 total PCA amount, as measured from the currently
approved base level NPSE, including the revenue sharing provision, is $216.9 million.
This represents an increase in total billed revenue of $103.4 million, an increase of 8.27
percent, for Idaho customers, effective June 2022 through May 2023.
19. Fixed Cost Adjustment (“FCA”). On March 15, 2022, Idaho Power filed its
annual FCA in Case No. IPC-E-22-07. The Company’s 2022 FCA filing proposes a $4.9
million decrease in current billed revenue, or a 0.81 percent decrease, for Idaho

APPLICATION - 8
Residential and Small General Service customers, effective June 2022 through May
2023.
20. Jim Bridger Power Plant (“Bridger”) Cost Recovery Request. On June 3,
2021, Idaho Power filed an application to increase rates to accelerate the depreciation
schedule for all coal-related investments at Bridger and establish a balancing account to
track the incremental costs and benefits associated with Idaho Power’s cessation of coal-
fired operations at the plant. On February 16, 2022, the Company filed an amended
request to reflect changes resulting from the expected conversion of Bridger Units 1 and
2 to natural gas in accordance with the results of the 2021 Integrated Resource Plan. If
the amended request is approved as filed, the filing would result in an increase of total
billed revenue of $27.1 million, an increase of 2.17 percent, for Idaho customers,
beginning June 1, 2022.
21. Combined Effect of the PCA, FCA, and Bridger Filings. If the proposed
PCA, FCA, and Bridger rate changes are approved as filed, the combined impact is an
overall increase in current billed revenue of $125.6 million, or 10.05 percent, for June
2022 through May 2023.
22. Attachment 1 to this Application is Idaho Power’s proposed IPUC No. 29,
Tariff No. 101, in both clean and legislative formats, which contains the tariff sheets
specifying the proposed Schedule 55 rates for providing retail electric service to its
customers in the state of Idaho for June 1, 2022, through May 31, 2023.
23. Attachment 2 to this Application contains a summary of revenue impact
showing the effect to each customer class of applying the Company’s proposed PCA

APPLICATION - 9
rates that collect $103.4 million more, from June 2022 through May 2023, than the PCA
rates currently in effect.
24. Rate Mitigation. Due to the magnitude of the requested increase, Idaho
Power considered proposing rate mitigation measures as part of this filing. As detailed in
the testimony of Ms. Brady, it has not done so for several reasons. The Company
believes that customer interests are generally best served by matching cost recovery as
closely as possible with the period in which power supply costs are incurred. Additionally,
mitigating rate impacts by spreading recovery over multiple years creates the possibility
that the deferred collection will result in “rate pancaking” with potential future rate
increases, essentially deferring an increase in the current year to create an even larger
increase in the future. The Company also considered prior Commission orders
concerning use of rate mitigation measures in the PCA. In orders from the 2008, 2009,
2013, and 2020 PCA cases in which rate mitigation was discussed, the Commission
declined to adopt any rate mitigation measures, primarily for the same concerns
surrounding rate pancaking, appropriate matching of costs and recovery, and the overall
intent of the PCA mechanism. Order Nos. 30563, 30828, 32821, and 34682.
25. While the Company is not proposing any rate mitigation measures in this
filing, it is open to discussing these measures if the Commission determines they may be
appropriate. A two-year recovery period, for example, would reduce the rate impact from
the proposed $103.4 million, or 8.27 percent increase, to an approximate $50 million, or
slightly more than 4 percent, annual increase in collection spread over two years.

APPLICATION - 10
V. MODIFIED PROCEDURE
26. Idaho Power believes that a technical hearing is not necessary to consider
the issues presented herein and respectfully requests that this Application be processed
under Modified Procedure, i.e., by written submissions rather than by hearing. RP 201,
et seq. If, however, the Commission determines that a technical hearing is required, the
Company stands ready to present its testimony and support the Application in such
hearing.
VI. COMMUNICATIONS AND SERVICE OF PLEADINGS
27. In conformance with RP 125, this Application will be brought to the attention
of Idaho Power’s customers by means of a press release to media in the Company’s
service area and a customer notice distributed in customers’ bills, both of which
accompany this filing. To ensure that all customers are notified in a timely manner and
have sufficient time to submit comments, Idaho Power is sending a direct mail postcard
to a subset of customers that receive their bill toward the end of the processing time for
this case. As such, a bill insert and/or the direct mail postcard will be mailed no later than
May 20, 2022.
28. The Company has also prominently displayed its intent to file the PCA on
its website since March 15, 2022. Upon filing of this Application, this web graphic will link
directly to the PCA press release and bill insert. Idaho Power will also keep its
Application, testimonies, and exhibits open for public inspection at its offices throughout
the state of Idaho. Idaho Power asserts that this notice procedure satisfies the Rules of
Procedure of this Commission; however, the Company will, in the alternative, bring the

APPLICATION - 11
Application to the attention of its affected customers through any other means directed by
this Commission.
29. Communications and service of pleadings with reference to this Application
should be sent to the following:
Lisa Nordstrom
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
[e-mail]
[e-mail]
Matthew T. Larkin
Timothy E. Tatum
Jessi Brady
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
[e-mail]
[e-mail]
brad idahopower.com

VII. REQUEST FOR RELIEF
30. As discussed in greater detail above, Idaho Power respectfully requests that
the Commission issue an order approving an update to Schedule 55 based on the
quantification of the 2022-2023 PCA, resulting in an overall increase to current billed
revenue of approximately $103.4 million to become effective June 1, 2022.
DATED at Boise, Idaho, this 15th day of April 2022.

________________________________
LISA D. NORDSTROM
Attorney for Idaho Power Company
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-22-11
IDAHO POWER COMPANY
ATTACHMENT 1
PROPOSED TARIFF
(Clean and legislative formats)
CLEAN FORMAT
Idaho Power Company Seventeenth Revised Sheet No. 55-1
Cancels
I.P.U.C. No. 29, Tariff No. 101 Sixteenth Revised Sheet No. 55-1
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective – June 1, 2022 1221 West Idaho Street, Boise, Idaho

SCHEDULE 55
POWER COST ADJUSTMENT

APPLICABILITY

This schedule is applicable to the electric energy delivered to all Idaho retail Customers served
under the Company’s schedules and Special Contracts. These loads are referred to as "firm" load for
purposes of this schedule.

BASE POWER COST AND PROJECTED POWER COST

The Base Power Cost of the Company's rates, expressed in cents per kWh, is computed by
dividing the sum of the Company's power cost components by firm kWh sales. The power cost
components are segmented into three categories as described in the table below:

The Projected Power Cost is the Company estimate, expressed in cents per kWh, of the power
cost components for the forecasted time period beginning April 1 each year and ending the following
March 31.

BALANCING ADJUSTMENT

The Balancing Adjustment is based upon the differences between previous Projected Power Cost
and the power costs actually incurred. The Balancing Adjustment is 0.2579 cents per kWh.

EARNINGS SHARING

Order Nos. 30978, 32424, 33149, and 34071 directed the Company to share a portion of its
earnings above a certain threshold with customers through the annual Power Cost Adjustment. The
Company’s 2021 earnings were above the prescribed threshold resulting in a credit of 0.0038 cents per
kWh.

Idaho Power Company Twelfth Revised Sheet No. 55-2
Cancels
I.P.U.C. No. 29, Tariff No. 101 Eleventh Revised Sheet No. 55-2
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective – June 1, 2022 1221 West Idaho Street, Boise, Idaho

SCHEDULE 55
POWER COST ADJUSTMENT
(Continued)

POWER COST ADJUSTMENT

The Power Cost Adjustment (PCA) is the sum of: 1) 95 percent of the difference between the
Projected Power Costs in Category 1 and the Base Power Costs in Category 1; 2) 100 percent of the
difference between the Projected Power Costs in Category 2 and the Base Power Costs in Category 2;
3) 100 percent of the difference between the Projected Power Costs in Category 3 and the Base Power
Costs in Category 3; 4) the Balancing Adjustment; and 5) Earnings Sharing. The following table calculates
the rates for Categories 1, 2 and 3.

The following table shows the determination of PCA rates for Categories 1, 2, and 3:

Category Description
Base Power
Cost
Projected
Power Cost Difference Sharing
% Rate
(¢ per kWh)
1
The sum of fuel
expense and
purchased power
expense
(excluding
purchases from
cogeneration and
small power
producers), less
the sum of off-
system surplus
sales revenue
and revenue from
market-based
special contract
pricing.
1.0234 1.7726 0.7492 95% 0.7117
2
Purchased power
expense from
cogeneration and
small power
producers.
0.8531 1.3549 0.5018 100% 0.5018
3
Demand
response
incentive
payments.
0.0751 0.0541 -0.0209 100% -0.0209
Total 1.9516 3.1816 1.2301 1.1926

Idaho Power Company Eleventh Revised Sheet No. 55-3
Cancels
I.P.U.C. No. 29, Tariff No. 101 Tenth Revised Sheet No. 55-3
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. Timothy E. Tatum, Vice President, Regulatory Affairs
Effective – June 1, 2022 1221 West Idaho Street, Boise, Idaho

SCHEDULE 55
POWER COST ADJUSTMENT
(Continued)

The monthly Power Cost Adjustment rates applied to the Energy rate of all metered schedules and
Special Contracts are shown below. The monthly Power Cost Adjustment applied to the per unit charges
of the nonmetered schedules is the monthly estimated usage times the cents per kWh rates shown below.

Schedule Category
Balancing
djustment
Earnings
Sharing
Total PCA
1 2 3
1 0.7117 0.5018 (0.0209) 0.2579 (0.0047) 1.4458
3 0.7117 0.5018 (0.0209) 0.2579 (0.0045) 1.4460
5 0.7117 0.5018 (0.0209) 0.2579 (0.0045) 1.4460
6 0.7117 0.5018 (0.0209) 0.2579 (0.0047) 1.4458
7 0.7117 0.5018 (0.0209) 0.2579 (0.0059) 1.4446
8 0.7117 0.5018 (0.0209) 0.2579 (0.0059) 1.4446
9S 0.7117 0.5018 (0.0209) 0.2579 (0.0035) 1.4470
9P 0.7117 0.5018 (0.0209) 0.2579 (0.0031) 1.4474
9T 0.7117 0.5018 (0.0209) 0.2579 (0.0035) 1.4470
15 0.7117 0.5018 (0.0209) 0.2579 (0.0122) 1.4383
19S 0.7117 0.5018 (0.0209) 0.2579 (0.0035) 1.4470
19P 0.7117 0.5018 (0.0209) 0.2579 (0.0027) 1.4478
19T 0.7117 0.5018 (0.0209) 0.2579 (0.0025) 1.4480
24 0.7117 0.5018 (0.0209) 0.2579 (0.0038) 1.4467
40 0.7117 0.5018 (0.0209) 0.2579 (0.0042) 1.4463
41 0.7117 0.5018 (0.0209) 0.2579 (0.0074) 1.4431
42 0.7117 0.5018 (0.0209) 0.2579 (0.0030) 1.4475
26 0.7117 0.5018 (0.0209) 0.2579 * 1.4505
29 0.7117 0.5018 (0.0209) 0.2579 * 1.4505
30 0.7117 0.5018 (0.0209) 0.2579 * 1.4505

* Earnings Sharing Credits are applied as monthly amounts per the table below.

Schedule Special Contract Monthly Credit
26 Micron ($1,307.24)
29 Simplot ($328.56)
30 DOE ($432.24)

EXPIRATION

The Power Cost Adjustment included on this schedule will expire May 31, 2023.
LEGISLATIVE FORMAT
Idaho Power CompanySixteenth Seventeenth Revised Sheet No. 55-1
Cancels
I.P.U.C. No. 29, Tariff No. 101 Fifteenth Sixteenth Revised Sheet No. 55-1
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. 35290 Timothy E. Tatum, Vice President, Regulatory Affairs
Effective – January 10, 2022June 1, 2022 1221 West Idaho Street, Boise, Idaho

SCHEDULE 55
POWER COST ADJUSTMENT

APPLICABILITY

This schedule is applicable to the electric energy delivered to all Idaho retail Customers served
under the Company’s schedules and Special Contracts. These loads are referred to as "firm" load for
purposes of this schedule.

BASE POWER COST AND PROJECTED POWER COST

The Base Power Cost of the Company's rates, expressed in cents per kWh, is computed by
dividing the sum of the Company's power cost components by firm kWh sales. The power cost
components are segmented into three categories as described in the table below:

The Projected Power Cost is the Company estimate, expressed in cents per kWh, of the power
cost components for the forecasted time period beginning April 1 each year and ending the following
March 31.

BALANCING ADJUSTMENT

The Balancing Adjustment is based upon the differences between previous Projected Power Cost
and the power costs actually incurred. The Balancing Adjustment is (0.21222579) cents per kWh.

EARNINGS SHARING

Order Nos. 30978, 32424, 33149, and 34071 directed the Company to share a portion of its
earnings above a certain threshold with customers through the annual Power Cost Adjustment. The
Company’s 20201 earnings were below above the prescribed threshold resulting in a credit of 0.0000
0038 cents per kWh.

Idaho Power Company Eleventh Twelfth Revised Sheet No. 55-2
Cancels
I.P.U.C. No. 29, Tariff No. 101Tenth Eleventh Revised Sheet No. 55-2
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. 35290 Timothy E. Tatum, Vice President, Regulatory Affairs
Effective – January 10, 2022June 1, 2022 1221 West Idaho Street, Boise, Idaho

SCHEDULE 55
POWER COST ADJUSTMENT
(Continued)

POWER COST ADJUSTMENT

The Power Cost Adjustment (PCA) is the sum of: 1) 95 percent of the difference between the
Projected Power Costs in Category 1 and the Base Power Costs in Category 1; 2) 100 percent of the
difference between the Projected Power Costs in Category 2 and the Base Power Costs in Category 2;
3) 100 percent of the difference between the Projected Power Costs in Category 3 and the Base Power
Costs in Category 3; 4) the Balancing Adjustment; and 5) Earnings Sharing. The following table calculates
the rates for Categories 1, 2 and 3.

The following table shows the determination of PCA rates for Categories 1, 2, and 3:

Category Description
Base Power
Cost
Projected
Power Cost Difference Sharing
% Rate
(¢ per kWh)
1
The sum of fuel
expense and
purchased power
expense
(excluding
purchases from
cogeneration and
small power
producers), less
the sum of off-
system surplus
sales revenue
and revenue from
market-based
special contract
pricing.
1.06120234 1.51747726 0.45627492 95% 0.43347117
2
Purchased power
expense from
cogeneration and
small power
producers.
0.88468531 1.355749 0.47115018 100% 0.47115018
3
Demand
response
incentive
payments.
0.077951 0.052741 -0.025209 100% -0.02520209
Total 2.02371.9516 2.92583.1816 0.90211.2301 0.87931.1926

Idaho Power Company TenthEleventh Revised Sheet No. 55-3
Cancels
I.P.U.C. No. 29, Tariff No. 101 Ninth Tenth Revised Sheet No. 55-3
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. 35290 Timothy E. Tatum, Vice President, Regulatory Affairs
Effective – January 10, 2022June 1, 2022 1221 West Idaho Street, Boise, Idaho

SCHEDULE 55
POWER COST ADJUSTMENT
(Continued)

The monthly Power Cost Adjustment rates applied to the Energy rate of all metered schedules and
Special Contracts are shown below. The monthly Power Cost Adjustment applied to the per unit charges
of the nonmetered schedules is the monthly estimated usage times the cents per kWh rates shown below.

Schedule Category
Balancing
djustment
Earnings
Sharing
Total PCA
1 2 3
1
0.43347117 0.47115018 (0.0252209) (0.12222579) (0.0047)-
0.75711.4458
3
0.43347117 0.47115018 (0.0252209) (0.12222579) (0.0045)-
0.75711.4460
5
0.43347117 0.47115018 (0.0252209) (0.12222579) (0.0045)-
01.75714460
6
0.43347117 0.47115018 (0.0252209) (0.12222579) (0.0047)-
01.75714458
7
0.43347117 0.47115018 (0.0252209) (0.12222579) (0.0059)-
01.75714446
8
0.43347117 0.47115018 (0.0252209) (0.12222579) (0.0059)-
01.75714446
9S
0.43347117 0.47115018 (0.0252209) (0.12222579) (0.0035)-
01.75714470
9P
0.43347117 0.47115018 (0.0252209) (0.12222579) (0.0031)-
01.75714474
9T
0.43347117 0.47115018 (0.0252209) (0.12222579) (0.0035)-
01.75714470
15
0.43347117 0.47115018 (0.0252209) (0.12222579) (0.0122)-
01.75714383
19S
0.43347117 0.47115018 (0.0252209) (0.12222579) (0.0035)-
01.75714470
19P
0.43347117 0.47115018 (0.0252209) (0.12222579) (0.0027)-
01.75714478
19T 0.43347117 0.47115018 (0.0252209) (0.12222579) (0.0025)- 01.75714480
24 0.43347117 0.47115018 (0.0252209) (0.12222579) (0.0038)- 01.75714467
40 0.43347117 0.47115018 (0.0252209) (0.12222579) (0.0042)- 10.75714463
41 0.43347117 0.47115018 (0.0252209) (0.12222579) (0.0074)- 01.75714431
42 0.43347117 0.47115018 (0.0252209) (0.12222579) (0.0030)- 01.75714475
26 0.43347117 0.47115018 (0.0252209) (0.12222579) * 01.75714505
29 0.43347117 0.47115018 (0.0252209) (0.12222579) * 01.75714505
30 0.43347117 0.47115018 (0.0252209) (0.12222579) * 01.75714505

* Earnings Sharing Credits are applied as monthly amounts per the table below., and are currently
$0.00 per month.

Schedule Special Contract Monthly Credit
26 Micron ($1,307.24)
Idaho Power Company TenthEleventh Revised Sheet No. 55-3
Cancels
I.P.U.C. No. 29, Tariff No. 101 Ninth Tenth Revised Sheet No. 55-3
IDAHO Issued by IDAHO POWER COMPANY
Issued per Order No. 35290 Timothy E. Tatum, Vice President, Regulatory Affairs
Effective – January 10, 2022June 1, 2022 1221 West Idaho Street, Boise, Idaho
29 Simplot ($328.56)
30 DOE ($432.24)

EXPIRATION

The Power Cost Adjustment included on this schedule will expire May 31, 20223.

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

ATTACHMENT 2

2022 PCA Revenue Impact Summary

Total Percent
Rate Average Normalized Current Adjustments Proposed Change
Line Sch. Number of Energy Billed Mills to Billed Total Billed Mills Billed to Billed
No Tariff Description No.Customers (kWh) Revenue Per kWh Revenue Revenue Per kWh Revenue

Uniform Tariff Rates:

1 Residential Service 1 490,293 5,458,972,074 $573,825,900 105.12 $37,595,977 $611,421,877 112.00 6.55%
2 Master Metered Mobile Home Park 3 21 4,521,955 $454,030 100.41 $31,154 $485,184 107.30 6.86%
3 Residential Service Energy Watch 4 0 0 $0 0.00 $0 $0 0.00 N/A
4 Residential Service Time-of-Day 5 988 17,662,331 $1,788,337 101.25 $121,677 $1,910,014 108.14 6.80%
5 Residential Service On-Site Generation 6 12,024 65,895,664 $7,342,186 111.42 $453,824 $7,796,010 118.31 6.18%
6 Small General Service 7 30,348 137,395,735 $18,011,465 131.09 $944,531 $18,955,996 137.97 5.24%
7 Small General Service On-Site Generation 8 80 190,425 $27,285 143.29 $1,309 $28,594 150.16 4.80%
8 Large General Service 9 37,919 3,900,728,491 $290,148,866 74.38 $26,912,491 $317,061,357 81.28 9.28%
9 Dusk to Dawn Lighting 15 0 5,267,423 $1,278,806 242.78 $35,882 $1,314,688 249.59 2.81%
10 Large Power Service 19 116 2,391,392,176 $141,697,963 59.25 $16,517,816 $158,215,779 66.16 11.66%
11 Agricultural Irrigation Service 24 19,120 1,897,512,119 $154,754,865 81.56 $13,084,541 $167,839,405 88.45 8.46%
12 Unmetered General Service 40 1,663 13,925,301 $1,229,632 88.30 $95,975 $1,325,607 95.19 7.81%
13 Street Lighting 41 2,980 23,760,014 $3,589,588 151.08 $162,984 $3,752,572 157.94 4.54%
14 Traffic Control Lighting 42 766 2,847,961 $184,266 64.70 $19,663 $203,929 71.61 10.67%
15 Total Uniform Tariffs 596,318 13,920,071,669 $1,194,333,190 85.80 $95,977,822 $1,290,311,012 92.69 8.04%

16 Total Special Contracts 3 1,071,974,663 $55,966,760 52.21 $7,408,256 $63,375,016 59.12 13.24%

17 Total Idaho Retail Sales 596,321 14,992,046,332 $1,250,299,949 83.40 $103,386,078 $1,353,686,028 90.29 8.27%
(1) June 01, 2022 - May 31, 2023 Forecasted Test Year (Spring 2022 Forecast)
(2) Percentage impact does not include components which are applied as percentages, Riders and Franchise Fees.

Idaho Power Company
Calculation of Revenue Impact 2022-2023
State of Idaho
Power Cost Adjustment & Revenue Sharing
Filed April 15, 2022
Summary of Revenue Impact
Current Billed Revenue to Proposed Billed Revenue

Percent
Rate Average Normalized Current Adjustments Proposed Change
Line Sch. Number of Energy Billed Mills to Billed Total Billed Mills Billed to Billed (2)
No Tariff Description No. Customers (1) (kWh) (1) Revenue Per kWh Revenue Revenue Per kWh Revenue

Uniform Tariff Rates:

1 Large General Secondary 9S 37,635 3,304,176,840 $250,044,987 75.68 $22,794,458 $272,839,444 82.57 9.12%
2 Large General Primary 9P 280 592,994,508 $39,836,749 67.18 $4,093,492 $43,930,241 74.08 10.28%
3 Large General Transmission 9T 4 3,557,143 $267,131 75.10 $24,541 $291,671 82.00 9.19%
4 Total Schedule 9 37,919 3,900,728,491 $290,148,866 74.38 $26,912,491 $317,061,357 81.28 9.28%

6 Large Power Secondary 19S 0 0 $0 0.00 $0 $0 0.00 0.00%
7 Large Power Primary 19P 114 2,358,498,546 $139,847,426 59.30 $16,290,562 $156,137,988 66.20 11.65%
8 Large Power Transmission 19T 2 32,893,630 $1,850,537 56.26 $227,254 $2,077,791 63.17 12.28%
9 Total Schedule 19 116 2,391,392,176 $141,697,963 59.25 $16,517,816 $158,215,779 66.16 11.66%

11 Irrigation Secondary 24S 19,120 1,897,512,119 $154,754,865 81.56 $13,084,541 $167,839,405 88.45 8.46%
12 Irrigation Transmission 24T 0 0 $0 0.00 $0 $0 0.00 0.00%
13 Total Schedule 24 19,120 1,897,512,119 $154,754,865 81.56 $13,084,541 $167,839,405 88.45 8.46%
(1) June 01, 2022 - May 31, 2023 Forecasted Test Year (Spring 2022 Forecast)
(2) Percentage impact does not include components which are applied as percentages, Riders and Franchise Fees.
Filed April 15, 2022

Summary of Revenue Impact - Rates 9, 19, and 24 Distribution Level Detail
Current Billed Revenue to Proposed Billed Revenue
Idaho Power Company
Calculation of Revenue Impact 2022-2023
State of Idaho
Power Cost Adjustment & Revenue Sharing
Thank you for reading this notice. We value your business.
©2022 Idaho Power
Printed on recycled paper.
XXXXX-I-XXXX
Oxbow Power PlantOxbow Power Plant
Opportunities for Public Review
Idaho Power’s proposal is subject to public review
and approval by the IPUC. Copies of the application
are available to the public at the IPUC offices (11331
W. Chinden Blvd. Building 8, Suite 201-A, Boise, ID
83714), Idaho Power offices, or at idahopower.com
or puc.idaho.gov. Customers also may subscribe to
the IPUC’s RSS feed to receive periodic updates via
email about the case. Written comments regarding
Idaho Power’s proposal may be filed with the IPUC.
Idaho Power Files Annual Power Cost Adjustment
Idaho Power has filed the final piece of its annual
spring cost adjustments with the Idaho Public Utilities
Commission (IPUC). This year’s Power Cost Adjustment
(PCA) calls for a price increase across all customer classes
as a result of higher power costs related to last summer’s
unprecedented heatwave and lower hydro generation
because of drought conditions.
Neither Idaho Power nor its shareholders receive any
financial return from this filing, which is a request for
$103.4 million. The money collected is used solely to
recover expenses associated with annual fluctuations in
power costs.
The overall impact to residential customer bills on June 1
depends on the outcome of three filings:
• The annual PCA, filed today, is a cost-recovery tool
that passes on both the benefits and costs of supplying
energy to Idaho Power customers. If the PCA proposal
is approved by the IPUC as filed, the typical Idaho
residential customer using 950 kilowatt-hours (kWh) of
energy per month will see a $6.54 increase on their bill
related to this request.
• The annual Fixed Cost Adjustment (FCA), filed in March
and applicable to only residential and small commercial
customers, adjusts prices based on changes in energy
use per customer during the previous year. If the FCA
proposal is approved as filed, a typical Idaho residential
customer will see a $0.81 decrease on their bill related
to this request.
• Idaho Power has requested a price increase to collect
the cost of an accelerated depreciation schedule for
all coal-related investments at the Jim Bridger Power
Plant in Wyoming. If approved as filed, a typical Idaho
residential customer will see a $2.07 increase on their
bill related to this request.
The impact of these three filings for all Idaho
customers is shown in the table below. A typical
Idaho residential customer will see an overall monthly
increase of $7.80. The actual percentage of change will
depend on a customer’s classification and the rate they pay.
The PCA has two main components: the forecast and the
backward-looking balancing adjustment. The forecast
reflects Idaho Power’s anticipated fuel costs, purchased
power costs and customer benefits from sales of surplus
energy for the coming April through March. The balancing
adjustment brings last year’s forecasted costs in balance
with costs actually incurred by Idaho Power by looking
back at what happened the previous April through March.
The increase in this year’s PCA is attributed to last year’s
actual power supply costs, which exceeded the forecast,
driven by lower-than-expected hydro generation, high
natural gas prices and high market prices. Idaho Power
experienced higher power costs than it has in the past due
to the record-setting heat wave of summer 2021, during
which the company exceeded its previous all-time peak
load for five consecutive days.
This year’s PCA forecast also reflects expected increases
to costs primarily due to continued drought conditions,
which would result in less low-cost hydro generation
available to serve customers, and higher costs associated
with power purchase agreements under the Public Utility
Regulatory Policies Act of 1978 (PURPA).
2022 RATE FILINGS
PERCENTAGE CHANGE FROM CURRENT BILLED REVENUE
Overall Percentage Impact Residential Small General Service
Large General Service1
Large Power2 Irrigation
POWER COST ADJUSMENT (PCA)3
8.27%6.55%5.24%9.18%12.10%8.46%
FIXED COST ADJUSMENT (FCA)
-0.39%-0.81%-0.82%N/A N/A N/A
BRIDGER
2.17%2.08%1.99%2.24%2.23%2.30%
COMBINED IMPACT4
10.05%7.82%6.41%11.43%14.33%10.75%
1 Includes lighting schedules; ² Includes special contracts; ³ Includes revenue sharing; 4 Totals may not sum due to rounding Oxbow Power Plant
Thank you for reading this notice. We value your business.
©2022 Idaho Power
Printed on recycled paper.
XXXXX-I-XXXX
Oxbow Power PlantOxbow Power Plant
Opportunities for Public Review
Idaho Power’s proposal is subject to public review
and approval by the IPUC. Copies of the application
are available to the public at the IPUC offices (11331
W. Chinden Blvd. Building 8, Suite 201-A, Boise, ID
83714), Idaho Power offices, or at idahopower.com
or puc.idaho.gov. Customers also may subscribe to
the IPUC’s RSS feed to receive periodic updates via
email about the case. Written comments regarding
Idaho Power’s proposal may be filed with the IPUC.
Idaho Power Files Annual Power Cost Adjustment
Idaho Power has filed the final piece of its annual
spring cost adjustments with the Idaho Public Utilities
Commission (IPUC). This year’s Power Cost Adjustment
(PCA) calls for a price increase across all customer classes
as a result of higher power costs related to last summer’s
unprecedented heatwave and lower hydro generation
because of drought conditions.
Neither Idaho Power nor its shareholders receive any
financial return from this filing, which is a request for
$103.4 million. The money collected is used solely to
recover expenses associated with annual fluctuations in
power costs.
The overall impact to residential customer bills on June 1
depends on the outcome of three filings:
• The annual PCA, filed today, is a cost-recovery tool
that passes on both the benefits and costs of supplying
energy to Idaho Power customers. If the PCA proposal
is approved by the IPUC as filed, the typical Idaho
residential customer using 950 kilowatt-hours (kWh) of
energy per month will see a $6.54 increase on their bill
related to this request.
• The annual Fixed Cost Adjustment (FCA), filed in March
and applicable to only residential and small commercial
customers, adjusts prices based on changes in energy
use per customer during the previous year. If the FCA
proposal is approved as filed, a typical Idaho residential
customer will see a $0.81 decrease on their bill related
to this request.
• Idaho Power has requested a price increase to collect
the cost of an accelerated depreciation schedule for
all coal-related investments at the Jim Bridger Power
Plant in Wyoming. If approved as filed, a typical Idaho
residential customer will see a $2.07 increase on their
bill related to this request.
The impact of these three filings for all Idaho
customers is shown in the table below. A typical
Idaho residential customer will see an overall monthly
increase of $7.80. The actual percentage of change will
depend on a customer’s classification and the rate they pay.
The PCA has two main components: the forecast and the
backward-looking balancing adjustment. The forecast
reflects Idaho Power’s anticipated fuel costs, purchased
power costs and customer benefits from sales of surplus
energy for the coming April through March. The balancing
adjustment brings last year’s forecasted costs in balance
with costs actually incurred by Idaho Power by looking
back at what happened the previous April through March.
The increase in this year’s PCA is attributed to last year’s
actual power supply costs, which exceeded the forecast,
driven by lower-than-expected hydro generation, high
natural gas prices and high market prices. Idaho Power
experienced higher power costs than it has in the past due
to the record-setting heat wave of summer 2021, during
which the company exceeded its previous all-time peak
load for five consecutive days.
This year’s PCA forecast also reflects expected increases
to costs primarily due to continued drought conditions,
which would result in less low-cost hydro generation
available to serve customers, and higher costs associated
with power purchase agreements under the Public Utilities
Regulatory Policy Act of 1978 (PURPA).
2022 RATE FILINGS
PERCENTAGE CHANGE FROM CURRENT BILLED REVENUE
Overall Percentage Impact Residential Small General Service
Large General Service1
Large Power2 Irrigation
POWER COST ADJUSMENT (PCA)3
8.27%6.55%5.24%9.18%12.10%8.46%
FIXED COST ADJUSMENT (FCA)
-0.39%-0.81%-0.82%N/A N/A N/A
BRIDGER
2.17%2.08%1.99%2.24%2.23%2.30%
COMBINED IMPACT4
10.05%7.82%6.41%11.43%14.33%10.75%
1 Includes lighting schedules; ² Includes special contracts; ³ Includes revenue sharing; 4 Totals may not sum due to rounding Oxbow Power Plant

Idaho Power Files Annual Power Cost Adjustment 
April 15, 2022 
BOISE, Idaho — Idaho Power has filed the final piece of its annual spring cost adjustments with the 
Idaho Public Utilities Commission (IPUC). This year’s Power Cost Adjustment (PCA) calls for a price 
increase across all customer classes as a result of higher power costs related to last summer’s 
unprecedented heatwave and lower hydro generation because of drought conditions.  
Neither Idaho Power nor its shareholders receive any financial return from this filing, which is a request 
for $103.4 million. The money collected is used solely to recover expenses associated with annual 
fluctuations in power costs.  
“We are sensitive to the impacts rate increases have on our customers and work hard to serve our 
growing number of customers with prices that remain 20% to 30% lower than the rest of the nation,” 
said Ryan Adelman, Vice President for Power Supply. “Unfortunately, the drought and last summer’s 
record heatwave resulted in higher‐than‐expected overall power supply costs. Recovering these costs 
helps us maintain the reliable service our customers depend on.”  
The overall impact to residential customer bills on June 1 depends on the outcome of three filings:  
 The annual PCA, filed today, is a cost‐recovery tool that passes on both the benefits and costs of 
supplying energy to Idaho Power customers. If the PCA proposal is approved by the IPUC as 
filed, the typical Idaho residential customer using 950 kilowatt‐hours (kWh) of energy per month 
will see a $6.54 increase on their bill related to this request.  

 The annual Fixed Cost Adjustment (FCA), filed in March and applicable to only residential and 
small commercial customers, adjusts prices based on changes in energy use per customer during 
the previous year. If the FCA proposal is approved as filed, a typical Idaho residential customer 
will see a $0.81 decrease on their bill related to this request. 

 Idaho Power has requested a price increase to collect the cost of an accelerated depreciation 
schedule for all coal‐related investments at the Jim Bridger Power Plant in Wyoming. If approved 
as filed, a typical Idaho residential customer will see a $2.07 increase on their bill related to this 
request. 
The impact of these three filings for all Idaho customers is shown in the table below. A typical Idaho 
residential customer will see an overall monthly increase of $7.80. The actual percentage of change will 
depend on a customer’s classification and the rate they pay. 

   2022 RATE FILINGS 
Percentage Change from Current Billed Revenue 
Filing Overall 
Percentage 
Impact   
Residential  Small 
General 
Service  
Large 
General 
Service 1 
Large Power 2 Irrigation  
PCA3 8.27% 6.55% 5.24% 9.18% 12.10% 8.46% 
FCA  ‐0.39%  ‐0.81%  ‐0.82% N/A N/A N/A 
Bridger  2.17% 2.08% 1.99% 2.24% 2.23% 2.30% 
Combined 
Impact 4 
10.05% 7.82% 6.41% 11.43% 14.33% 10.75% 
1 Includes lighting schedules; 2 Includes special contracts; 3 Includes revenue sharing; 4 Totals may not 
sum due to rounding  
The PCA has two main components: the forecast and the backward‐looking balancing adjustment. The 
forecast reflects Idaho Power’s anticipated fuel costs, purchased power costs and customer benefits 
from sales of surplus energy for the coming April through March. The balancing adjustment brings last 
year’s forecasted costs in balance with costs actually incurred by Idaho Power by looking back at what 
happened the previous April through March.  
The increase in this year’s PCA is attributed to last year’s actual power supply costs, which exceeded the 
forecast, driven by lower‐than‐expected hydro generation, high natural gas prices and high market 
prices. Idaho Power experienced higher power costs than it has in the past due to the record‐setting 
heat wave of summer 2021, during which the company exceeded its previous all‐time peak load for five 
consecutive days. 
This year’s PCA forecast also reflects expected increases to costs primarily due to continued drought 
conditions, which would result in less low‐cost hydro generation available to serve customers, and 
higher costs associated with power purchase agreements under the Public Utility Regulatory Policies Act 
of 1978 (PURPA). 
Opportunities for Public Review  
Idaho Power’s proposal is subject to public review and approval by the IPUC. Copies of the application 
are available to the public at the IPUC offices (11331 W. Chinden Blvd. Building 8, Suite 201‐A, Boise, ID 
83714), Idaho Power offices, or at idahopower.com or puc.idaho.gov. Customers also may subscribe to 
the IPUC’s RSS feed to receive periodic updates via email about the case. Written comments regarding 
Idaho Power’s proposal may be filed with the IPUC. 
About Idaho Power 
Idaho Power, headquartered in vibrant and fast‐growing Boise, Idaho, has been a locally operated 
energy company since 1916. Today, it serves a 24,000‐square‐mile area in Idaho and Oregon.  

The company’s goal to provide 100% clean energy by 2045 builds on its long history as a clean‐energy 
leader that provides reliable service at affordable prices. With 17 low‐cost hydroelectric projects at the 
core of its diverse energy mix, Idaho Power’s residential, business and agricultural customers pay among 
the nation’s lowest prices for electricity. Its 2,000 employees proudly serve more than 600,000 
customers with a culture of safety first, integrity always and respect for all. 
IDACORP Inc. (NYSE: IDA), Idaho Power’s independent publicly traded parent company, is also 
headquartered in Boise, Idaho. To learn more, visit idahopower.com or idacorpinc.com. 
Jordan Rodriguez 
Communications Specialist 
[e-mail] 
208‐388‐2460 

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO IMPLEMENT POWER
COST ADJUSTMENT (“PCA”) RATES
FOR ELECTRIC SERVICE FROM JUNE
1, 2022, THROUGH MAY 31, 2023.

)
)
)
)
)
)
)

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

DIRECT TESTIMONY

OF

JESSICA G. BRADY

BRADY, 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 Jessica G. Brady. My business 4
address is 1221 West Idaho Street, Boise, Idaho 83702. I 5
am employed by Idaho Power as a Regulatory Analyst in the 6
Regulatory Affairs Department. 7
Q. Please describe your educational background. 8
A. In May of 2016, I received a Bachelor of 9
Science degree in Economics and a Bachelor of Arts degree 10
in Spanish from the University of Idaho. I have also 11
attended “Electric Utility Fundamentals & Insights,” an 12
electric utility course offered through the Western Energy 13
Institute. 14
Q. Please describe your work experience. 15
A. In September 2021, I was hired as a Regulatory 16
Analyst in Idaho Power’s Regulatory Affairs Department. As 17
a Regulatory Analyst, I provide support for the Company’s 18
regulatory activities, including compliance reporting, 19
financial analysis, and the development of revenue 20
forecasts for regulatory filings. I am also responsible for 21
the Company’s power cost filings in both Idaho and Oregon. 22
Prior to Idaho Power, I worked for five years at 23
Clearwater Analytics, a provider of investment accounting 24
and reporting software. I held various roles at Clearwater 25

BRADY, DI 2
Idaho Power Company
Analytics but was primarily focused on customer success and 1
relationship management. I gained a breadth of knowledge in 2
investments and the use of proprietary software to 3
streamline the operations of a company’s finance and 4
accounting teams. I spent my last year at Clearwater 5
developing a training program focused on providing new 6
hires with the technical skills to be successful in an 7
operations role. 8
Q. What is the Company requesting in this case? 9
A. The Company is requesting approval of its 10
2022-2023 Power Cost Adjustment (“PCA”) rates to become 11
effective June 1, 2022. If approved, the 2022-2023 PCA 12
will result in an increase in total billed revenue of 13
approximately $103.4 million, or 8.27 percent. 14
Q. How is your testimony organized? 15
A. My testimony consists of four sections. In the 16
first section, I provide an overview of the PCA. In the 17
second section, I detail the 2022-2023 PCA amount in 18
comparison to last year’s PCA amount, identify and discuss 19
the main factors contributing to this change, and present 20
the quantification of the 2022-2023 PCA rates to become 21
effective June 1, 2022. In the third section, I discuss 22
the additional PCA component related to revenue sharing. In 23
the final section, I detail the net customer impact of the 24
2022-2023 PCA rates if approved as filed. 25

BRADY, DI 3
Idaho Power Company
I. PCA OVERVIEW 1
Q. What is the purpose of the PCA? 2
A. The PCA is a rate mechanism that quantifies 3
and tracks annual differences between actual Net Power 4
Supply Expenses (“NPSE”) and the normalized or “base level” 5
of NPSE recovered in the Company’s base rates, resulting in 6
a credit or surcharge that is updated annually on June 1. 7
The PCA mechanism uses a 12-month test period of April 8
through March (“PCA Year”) and includes a forecast 9
component and a Balancing Adjustment, formerly referred to 10
as the “true-up” and the “true-up of the true-up”. The 11
forecast component represents the difference between the 12
Company’s NPSE forecast from the March Operating Plan and 13
base level NPSE recovered in the Company’s base rates. The 14
Balancing Adjustment includes a backward-looking tracking 15
of differences between the prior PCA Year’s forecast and 16
actual NPSE incurred by the Company, and also tracks the 17
collection of the prior year’s Balancing Adjustment. 18
Q. Is the Balancing Adjustment new to this PCA 19
filing? 20
A. Yes. In Order No. 352901, the Idaho Public 21
Utilities Commission (“Commission”) approved a modification 22

1 In the Matter of the Application of Idaho Power Company for
Modification of the Power Cost Adjustment Mechanism, Case No. IPC-E-21-
38, Order No. 35290 (January 10, 2022).

BRADY, DI 4
Idaho Power Company
to the PCA filing to replace the “true-up” and “true-up of 1
the true-up” with a single Balancing Account. The two 2
“true-up” rates previously included in PCA filings are now 3
combined into one “Balancing Adjustment” rate. It should be 4
noted that this modification solely impacts the presentment 5
of the PCA but has no material impact on the rates charged 6
to customers. 7
Q. How does the PCA mechanism function? 8
A. With the exception of Public Utility 9
Regulatory Policies Act of 1978 (“PURPA”) expenses and 10
demand response incentive payments, the PCA allows the 11
Company to pass through to customers 95 percent of the 12
annual differences in actual NPSE as compared with base 13
level NPSE, whether positive or negative. With respect to 14
PURPA expenses and demand response incentive payments, as 15
actual annual expenses deviate from base level NPSE, the 16
Company is allowed to pass 100 percent of the difference 17
for recovery or credit through the PCA. The PCA is also 18
the rate mechanism used by the Company to provide customer 19
benefits resulting from the revenue sharing mechanism 20
approved by the Commission in Order No. 34071. 21
Q. Does the revenue collected from customers 22
through the annual PCA rate contribute toward the Company’s 23
earnings? 24

BRADY, DI 5
Idaho Power Company
A. No. The PCA mechanism provides for the annual 1
collection or refund of net power supply cost differences 2
between actual costs incurred by the Company and the base 3
level NPSE component of base rates. Aside from the 95 4
percent to 5 percent sharing component I just described, 5
the PCA provides for a one-for-one collection or refund of 6
actual net power supply expenses incurred, or to be 7
incurred, to provide safe, reliable electric service to 8
customers. 9
Q. What are the components of the PCA base level 10
NPSE? 11
A. The PCA base level NPSE includes the following 12
Federal Energy Regulatory Commission (“FERC”) accounts: 13
Account 501, Fuel (coal); Account 536, Water for Power; 14
Account 547, Fuel (gas); Account 555, Purchased Power; 15
Account 565, Transmission of Electricity by Others; and 16
Account 447, Sales for Resale (typically referred to as 17
surplus sales). 18
The PCA base level expense component for FERC 19
Account 555 includes costs of both PURPA and non-PURPA 20
(market) purchases. Per Order No. 32426, the Company 21
adjusts FERC Account 555 to also include demand response 22
incentive payments that the Company provides to customers 23
who participate in any of its three demand response 24
programs. 25

BRADY, DI 6
Idaho Power Company
II. 2022-2023 PCA 1
Q. What is the total PCA collection that would 2
result under the 2022-2023 PCA rates proposed by the 3
Company in this case? 4
A. The 2022-2023 PCA rates would result in total 5
PCA collection of $216.9 million. This represents an 6
increase in total billed revenue of $103.4 million for the 7
upcoming year, an increase of 8.27 percent. 8
Q. Have you prepared a table that details the 9
$103.4 million revenue impact by component? 10
A. Yes. Table 1 presents a separation of the 11
$103.4 million increase into each component included in the 12
Company’s proposed rates. 13
Table 1 Revenue Impact by Component 

Line No. Rate Component 2021‐2022 PCA 2022‐2023 PCA Difference 
1 PCA Forecast   $           131,825,063    $     178,795,145    $            46,970,081  
2 PCA Balancing Adjustment   $           (18,320,281)   $       38,664,487    $            56,984,768  
3 PCA Total   $           113,504,783    $     217,459,632    $          103,954,849  
4 Revenue Sharing   $                               0     $          (568,771)   $               (568,771) 
4 Total Revenue Impact   $           113,504,783    $     216,890,861    $          103,386,078  
14
Q. What are the main factors driving the revenue 15
change requested in this case? 16
A. The increase in this year’s PCA is attributed 17
to an increase in both the forecast component and the 18
Balancing Adjustment. The increase in this year’s forecast 19
component is attributed to lower expected hydro generation, 20

BRADY, DI 7
Idaho Power Company
higher market energy prices, and higher natural gas prices, 1
which will be discussed in detail later in this testimony. 2
This year’s PCA Balancing Adjustment is 3
approximately $38.7 million, which is $57.0 million higher 4
than last year’s Balancing Adjustment, which was a credit 5
of $18.3 million. This year’s Balancing Adjustment 6
demonstrates that actual power supply costs for the 2021-7
2022 PCA Year were higher than the forecast power supply 8
costs included in last year’s PCA forecast. 9
A. PCA Forecast. 10
Q. How is the PCA forecast amount determined? 11
A. As described previously, the PCA forecast 12
component represents the difference between the Company’s 13
forecast of NPSE for the upcoming April – March test year 14
and base level NPSE recovered in the Company’s base rates. 15
Q. What is the Company’s determination of the 16
system-level difference between currently approved base 17
level NPSE2 and the forecast of NPSE for the 2022-2023 PCA 18
Year? 19
A. The system-level forecast of NPSE for the 20
2022-2023 PCA Year is $498,834,556, which is $193,149,687 21
higher than the currently approved base level NPSE of 22
$305,684,869. Table 2 presents the system-level 23

2 In the Matter of the Application of Idaho Power Company for
Authority to Establish a New Base Level of Net Power Supply Expense,
Case No. IPC-E-13-20, Order No. 33000 (March 21, 2014).

BRADY, DI 8
Idaho Power Company
differences between currently approved base level NPSE and 1
the forecast of NPSE for the 2022-2023 PCA Year by FERC 2
account. 3
Table 2 2022 ‐ 2023 PCA FORECAST  (Total System) 

Line No. FERC Account Base NPSE Forecast Difference 
  95% Sharing Accounts     
1 Account 501, Coal   $           108,503,180    $     151,179,160    $            42,675,980  
2 Account 536, Water for Power   $               2,380,597    $                         0    $            (2,380,597) 
3 Account 547, Other Fuel   $             33,367,563    $       86,983,566    $            53,616,003  
4 Account 555, Purchased Power Non‐PURPA   $             62,606,593    $       99,906,480    $            37,299,887  
5 Account 565, 3rd Party Transmission    $               5,455,955    $         5,149,239    $               (306,716) 
6 Account 447, Surplus Sales    $         (51,735,153)   $    (65,085,848)   $         (13,350,695) 
      $          160,578,735    $    278,132,598    $         117,553,863             100% Sharing Accounts     
7 Account 555, PURPA   $          133,853,869    $    212,586,058    $           78,732,189  
8 Account 555, Demand Response Incentives   $            11,252,265    $        8,115,900    $          (3,136,365) 
9 Total   $          305,684,869    $   498,834,556    $        193,149,687  
4
Q. What is the basis for the forecast of NPSE for 5
the 2022-2023 PCA Year? 6
A. The forecast of NPSE for the 2022-2023 PCA 7
Year is based on the Company’s March 31, 2022, Operating 8
Plan. 9
Q. How is the NPSE forecast developed for the 10
Company’s Operating Plan? 11
A. The Operating Plan is prepared monthly and 12
represents a forecast of the Company’s monthly NPSE for the 13
following 18-month period; however, for the PCA, the 14
Company includes only the 12 months that correspond to the 15

BRADY, DI 9
Idaho Power Company
PCA Year. The Operating Plan is developed by simulating 1
the dispatch of the Company’s generation resources for each 2
month, segmented by heavy load and light load hours. The 3
dispatch considers a current forecast of forward market 4
energy prices, available hydro generation, coal and natural 5
gas prices, and any existing hedge transactions. The 6
system load forecast is then analyzed against the resulting 7
monthly heavy load and light load dispatch to determine a 8
monthly load and resource balance. Any identified resource 9
deficiency is assumed to be filled with market energy 10
purchases or natural gas to fuel the Langley Gulch power 11
plant (“Langley Gulch”), based on economics and available 12
generating capacity at Langley Gulch. Economically 13
dispatched generation above the system load forecast 14
represents surplus energy sales. The forecast of monthly 15
NPSE and generation for the 2022-2023 PCA Year, as 16
determined in the Company’s March 31, 2022, Operating Plan, 17
is provided in Exhibit No. 1. 18
Q. Please explain how the Company modeled Bridger 19
Units 1 and 2 in the March 31, 2022 Operating Plan, in 20
light of the ongoing Bridger Regional Haze compliance 21
discussions. 22
A. In light of ongoing discussions with the U.S. 23
Environmental Protection Agency regarding the Wyoming 24
Regional Haze State Implementation Plan (“SIP”), Idaho 25

BRADY, DI 10
Idaho Power Company
Power adjusted the availability of Bridger Units 1 and 2 1
within the March Operating Plan. Specifically, the Company 2
modeled Bridger Unit 2 to be available for dispatch at a 25 3
percent level from June – October 2022 to reflect ongoing 4
uncertainty related to these discussions. For the remaining 5
months within the PCA year, Unit 2 is modeled at 6
availability levels that meet the overall plant emissions 7
limits and annual emissions cap as required per the revised 8
SIP. Bridger Unit 1 operations were modeled as available 9
for dispatch at the revised approved SIP levels for the 10
entire 2022-2023 PCA year. 11
Q. How does the Company’s forecast of system-12
level NPSE for the 2022-2023 PCA compare to the system-13
level forecast included in last year’s PCA? 14
A. Table 3 below compares this year’s 2022-2023 15
PCA forecast of NPSE to last year’s PCA forecast by FERC 16
account. As detailed in this table, the PCA forecast on a 17
total system basis for the 2022-2023 PCA Year is 18
$498,834,556, which is $56,477,149 higher than last year’s 19
forecast amount of $442,357,407. 20
21
22
23
24
25
26

BRADY, DI 11
Idaho Power Company
1
Table 3 PCA Forecast Comparison Expenses  (Total System) 

Line No. FERC Account 
2021‐2022     
Forecast 
2022‐2023 
Forecast Difference 
  95% Sharing Accounts     
1 Account 501, Coal   $            118,562,796    $       151,179,160    $          32,616,365  
2 Account 536, Water for Power   $                                0    $                           0    $                            0  
3 Account 547, Other Fuel   $              57,235,044    $         86,983,566    $          29,748,522  
4 Account 555, Purchased Power Non‐PURPA   $              74,800,530    $         99,906,480    $          25,105,950  
5 Account 565, 3rd Party Transmission    $                4,853,909    $           5,149,239    $               295,331  
6 Account 447, Surplus Sales   $           (25,842,225)   $       (65,085,848)   $       (39,243,623) 
      $            229,610,054    $       278,132,598    $          48,522,544  

  100% Sharing Accounts     
7 Account 555, PURPA   $            205,133,741    $       212,586,058    $            7,452,317  
8 Account 555, Demand Response Incentives   $                7,613,612    $           8,115,900    $               502,288  
      $            212,747,353    $       220,701,958    $            7,954,605  

9 Total PCA Forecast   $            442,357,407    $       498,834,556    $          56,477,149  
2
Q. What general conclusions can be drawn from the 3
information contained in Table 3? 4
A. When viewed by category, the 95 percent 5
sharing accounts have increased approximately $48.5 million 6
from last year’s forecast, while the 100 percent sharing 7
accounts have increased approximately $8.0 million over 8
last year’s forecast. 9
Q. What factors are contributing to the major 10
differences presented in Table 3? 11
A. Forecast expenses included in the 95 percent 12
sharing accounts are expected to increase by 21 percent as 13
compared to last year, from $229,610,054 to $278,132,598. 14

BRADY, DI 12
Idaho Power Company
Due to a reduction in forecast hydro generation, higher 1
forecast market energy prices, and higher forecast natural 2
gas prices, the Company expects to rely more on coal 3
generation to serve load and is expected to increase off-4
system surplus sales. 5
Q. Please elaborate on the changes in the 95 6
percent sharing accounts for this year’s forecast as 7
compared with last year’s forecast. 8
A. In addition to lower forecast hydro 9
generation, which will be discussed in detail later in 10
testimony, higher forecast market energy prices and natural 11
gas prices are contributing to increased generation at the 12
Company’s coal plants, as well as increased off-system 13
surplus sales. 14
For the 2022-2023 PCA Year, the average forecast 15
market purchase price is $49.11 per megawatt-hour (“MWh”), 16
compared to $27.34 per MWh last year, an increase of 80 17
percent. In addition, the per-unit cost of natural gas for 18
the 2022-2023 PCA Year is $34.03 per MWh, an increase of 39 19
percent compared to last year. As a result of higher market 20
energy prices and natural gas prices, coal generation 21
becomes more economic. The average per-unit cost of coal-22
fired generation is $29.74 per MWh, which is a 10 percent 23
decrease from last year. Accordingly, expenses from market 24
purchases are expected to increase 91 percent as compared 25

BRADY, DI 13
Idaho Power Company
to last year’s forecast, natural gas expense is expected to 1
increase 52 percent, and coal fuel expense is expected to 2
increase 28 percent. 3
The increase in forecast market energy prices is 4
also resulting in higher surplus sales revenue. Surplus 5
sales revenue is expected to increase 152 percent compared 6
to last year, from $25,842,225 to $65,085,848. For the 7
2022-2023 PCA Year, the average forecast market sales price 8
is $51.73 per MWh compared with $34.23 last year, a 51 9
percent increase. 10
Q. What factors are contributing to the change in 11
the 100 percent sharing accounts? 12
A. Forecast expenses included in the 100 percent 13
sharing accounts are expected to increase by 4 percent as 14
compared to last year, from $212,747,353 to $220,701,958. 15
Forecast PURPA costs increased by $7.45 million as compared 16
to last year’s forecast and forecast demand response 17
incentive payments increased by $0.5 million as compared to 18
last year. 19
Q. Is the increase in forecast PURPA costs 20
related to increased generation output from PURPA projects? 21
A. In part. Table 4 details changes between last 22
year’s PCA forecast and this year’s PCA forecast with 23
respect to forecasted generation in MWh. As shown in Table 24
4, PURPA generation is anticipated to increase by 10,708 25

BRADY, DI 14
Idaho Power Company
MWh, or less than 1 percent. The 4 percent increase in 1
PURPA expense is largely the result of price escalation in 2
PURPA contracts, for which the average cost is $69.96 per 3
MWh, compared to $67.75 last year. 4
Table 4 PCA Forecast Comparison Generation (Total System‐MWh) 

Line No. FERC Account 2021‐2022 Forecast 
2022‐2023 
Forecast Difference 
1 Hydro                     6,690,890                 5,972,743                   (718,147) 

  95% Sharing Accounts     
2 Account 501, Coal                      3,599,219                 5,083,043                 1,483,825  
3 Account 547, Other Fuel                    2,340,994                 2,556,322                     215,328  
4 Account 555, Purchased Power Non‐PURPA                     1,478,696                 1,580,326                     101,630  
  95% Sharing Accounts                  14,109,799               15,192,435                  1,082,636  

  100% Sharing Accounts     
5 Account 555, PURPA                      3,027,905                 3,038,613                      10,708  
  100% Accounts                     3,027,905                 3,038,613                       10,708  

6 Total Generation                     17,137,704               18,231,048                  1,093,344  

  95% Sharing Accounts     
7 Account 447, Surplus Sales                        754,975                 1,258,195                     503,220  
8 Total Load                   16,382,729               16,972,853                      590,124  
5
Q. What other general conclusions can be drawn 6
from the information in Table 4? 7
A. Compared to last year’s forecast, hydro 8
generation is expected to decrease 718,147 MWh, or 11 9
percent. The decrease in hydro generation, combined with an 10
increase in market energy prices and natural gas prices, is 11
driving an increase in coal-fired generation and surplus-12
sales. Coal-fired generation is projected to increase 13
1,483,825 MWh compared to last year, or 41 percent and 14

BRADY, DI 15
Idaho Power Company
surplus-sales volumes are expected to increase 503,220 MWh, 1
or 67 percent. 2
Q. What is causing the decrease in expected hydro 3
generation of 718,147 MWh? 4
A. The decrease in expected hydro generation is 5
mainly due to lower projected inflows into Brownlee 6
reservoir. The March Operating Plan used in this year’s 7
PCA forecast projects April through July inflows into 8
Brownlee of 2.9 million acre-feet (“MAF”) as compared to 9
4.2 MAF used to determine last year’s PCA forecast, a 10
decrease of 31 percent. Expected inflows into Brownlee 11
were higher for last year’s PCA forecast as a result of 12
better snowpack conditions, which provide for sustained 13
runoff and increased hydro generation during the spring and 14
summer months. 15
Additionally, this year’s PCA forecast reflects 16
weaker reservoir storage conditions, as compared to last 17
year’s forecast. The March Operating Plan used in this 18
year’s PCA demonstrates that available storage in the 11 19
reservoirs above Brownlee is 76 percent of normal and at 51 20
percent of capacity, compared to last year’s 2021 March 21
Operating Plan, in which storage was 113 percent of normal 22
and at 75 percent of capacity. Together weaker snowpack 23
conditions and carryover as compared to the prior year are 24

BRADY, DI 16
Idaho Power Company
resulting in the 11 percent reduction in forecast hydro 1
generation for the 2022–2023 PCA Year. 2
Q. How are the forecasted NPSE differences 3
presented in Table 2 used to determine the 2022-2023 PCA 4
forecast component to be collected from Idaho customers? 5
A. The 2022-2023 PCA forecast component reflects 6
the Idaho jurisdictional share of the forecasted NPSE 7
differences presented in Table 2, adjusted for the PCA 8
sharing provisions. The Idaho jurisdictional share of the 9
forecast NPSE differences is determined by applying a ratio 10
of forecast firm Idaho jurisdictional sales to forecast 11
firm system-level sales to the system-level NPSE 12
differences. 13
Q. What is the Company’s forecast of system-level 14
firm sales and Idaho jurisdictional firm sales for the 15
2022-2023 PCA Year? 16
A. For the 2022-2023 PCA Year, Idaho Power has 17
forecast system-level firm sales to be 15,690,546 MWh and 18
Idaho jurisdictional firm sales to be 14,992,046 MWh, or 19
95.55 percent of the system level. 20
Q. What is the Company’s determination of the 21
2022-2023 PCA forecast component to be collected from Idaho 22
customers? 23
A. The 2022-2023 PCA forecast component to be 24
collected from Idaho customers is $178,795,544. Table 5 25

BRADY, DI 17
Idaho Power Company
presents the determination of the 2022-2023 PCA forecast 1
component by individual PCA expense and revenue category. 2
3
Table 5 2022‐2023 PCA FORECAST 

Line No. FERC Account Difference from Base 
Difference After 
Sharing Idaho Allocation 
  95% Sharing Accounts (From Table 1)    
1 Account 501, Coal   $              42,675,980    $           40,542,181    $           38,737,356  
2 Account 536, Water for Power   $              (2,380,597)   $           (2,261,567)   $           (2,160,888) 
3 Account 547, Other Fuel   $              53,616,003    $           50,935,202    $           48,667,709  
4 Account 555, Purchased Power Non‐PURPA   $              37,299,887    $           35,434,893    $           33,857,430  
5 Account 565, 3rd Party Transmission    $                 (306,716)   $              (291,380)   $              (278,408) 
6 Account 447, Surplus Sales   $           (13,350,695)   $        (12,683,160)   $        (12,118,541) 
      $            117,553,863    $        111,676,170    $        106,704,658  

  100% Sharing Accounts     
7 Account 555, PURPA   $              78,732,189    $          78,732,189    $          75,227,251  
8 Account 555, Demand Response Incentives   $              (3,136,365)   $          (3,136,365)   $          (3,136,365) 
9 Total   $            193,149,687    $        187,271,994    $        178,795,544  
4
B. Balancing Adjustment. 5
Q. What is this year’s quantification of the 6
Balancing Adjustment? 7
A. The Balancing Adjustment is detailed in the 8
PCA deferral report, attached hereto as Exhibit No. 2. This 9
report compares actual NPSE amounts to actual power cost 10
collections monthly, with the differences accumulated as a 11
deferral balance. The balance at the end of March 2022, 12
with interest applied, was $38,669,525 as shown on row 100 13
of Exhibit No. 2. The approximate $38.7 million represents 14

BRADY, DI 18
Idaho Power Company
an increase to customer rates in this year’s PCA Balancing 1
Adjustment. 2
Q. To what factors do you attribute the 3
accumulation of the approximate $38.7 million deferral 4
balance? 5
A. The approximate $38.7 million deferral balance 6
was primarily driven by a decrease in actual hydro 7
generation from expected as well as higher than forecast 8
market purchases, offset by higher surplus sales. 9
Actual hydro generation for the 2021-2022 PCA year 10
totaled 5,268,002 MWh, a 21 percent decrease from last 11
year’s forecast of 6,690,890 MWh. Actual purchased power 12
totaled 4,079,834 MWh, a 176 percent increase from last 13
year’s forecast. Actual surplus sales volumes totaled 14
1,373,630 MWh, an increase of 82 percent from 754,975 MWh. 15
Actual natural gas prices were also higher than 16
forecast, driving a 55 percent increase in natural gas fuel 17
expense. Although natural gas prices were higher than 18
forecast, the Company’s reliance on natural gas generation 19
did not decrease as it was needed to serve load due to 20
lower than expected hydro generation and higher than 21
expected temperatures during the 2021 summer season. 22
Q. Please elaborate on the changes in actual 23
versus forecast generation and expense for the 2021-2022 24
PCA Year. 25

BRADY, DI 19
Idaho Power Company
A. Last year’s PCA forecast included an average 1
market sales price of $34.23 per MWh. The actual average 2
market sales price for the 2021-2022 PCA year was $57.70 3
per MWh, a 69 percent increase. As a result of the 4
difference in forecast and actual market sales prices, as 5
well as economic opportunity during the spring and winter 6
months of the 2021-2022 PCA year, actual surplus sales 7
volumes were 82 percent higher than forecast. Surplus sales 8
revenue totaled $79,257,653, which was 207 percent higher 9
than forecast revenues of $25,842,225. 10
Coal-fired generation totaled 3,241,970 MWh, which 11
was 10 percent lower than forecast, and actual coal fuel 12
expense was $104.5 million, 12 percent lower than forecast. 13
Coal-fired generation was lower than forecast due to the 14
increase in market energy purchases and increase in natural 15
gas generation. 16
Natural gas generation totaled 2,719,869 MWh for the 17
2021-2022 PCA Year, which was 378,875 MWh, or 16 percent, 18
higher than forecast. Due to natural gas prices being 19
higher than expected, actual natural gas expense totaled 20
$88,941,596, which was 55 percent higher than forecast. 21
While natural gas prices were higher than forecast, the 22
Company’s reliance on natural gas generation increased 16 23
percent as it was needed to meet load, as well as make off-24
system sales when it was economic, as noted previously. 25

BRADY, DI 20
Idaho Power Company
While both purchased power and surplus sales 1
increased, surplus sale volumes were highest in off-peak 2
spring and winter months, and purchased power was highest 3
in summer months, where hot temperatures caused 4
continuously higher than forecast peak loads. 5
Q. Were there any items included in this year’s 6
Balancing Adjustment in addition to actual NPSE incurred 7
during the April 2021 through March 2022 period? 8
A. Yes. Per Commission Order No. 34100, Idaho 9
Power included its actual costs of Western Energy Imbalance 10
Market (“EIM”) participation for April 2021 through March 11
2022 in the Balancing Adjustment. Benefits associated with 12
EIM participation are embedded in actual NPSE experienced 13
over that same period. 14
Q. Please summarize the conditions of Order No. 15
34100 as they pertain to EIM cost recovery through the 2021 16
PCA. 17
A. Per the terms of the settlement stipulation 18
(“EIM Stipulation”) approved by Order No. 34100, Idaho 19
Power agreed to include an EIM-related monthly revenue 20
requirement in its monthly PCA deferral calculation based 21
on actual EIM participation costs commencing April 1, 2018. 22
The Company also agreed to apply a soft cap to EIM-related 23
revenue requirement included in the PCA deferral equal to 24
annual EIM benefits as reported by the California 25

BRADY, DI 21
Idaho Power Company
Independent System Operator (“CAISO”) for the corresponding 1
period. 2
Q. Is the EIM-related revenue requirement 3
included in the April 2021 through March 2022 PCA deferral 4
under the soft cap of annual CAISO-reported benefits for 5
that same period? 6
A. Yes. For the April 2021 through March 2022 7
period, the EIM-related revenue requirement totaled $2.9 8
million, while CAISO reported EIM benefits for Idaho Power 9
of approximately $40 million from April through December 10
(CAISO’s first quarter 2022 report has not yet been 11
published). Therefore, the Company’s EIM-related revenue 12
requirement is less than the soft cap agreed to in the EIM 13
Stipulation. 14
Q. Does Idaho Power believe the EIM has provided 15
net benefits to customers since joining in April 2018? 16
A. Yes. While Idaho Power believes the CAISO 17
benefit calculation overstates estimated benefits to Idaho 18
Power’s system, the Company believes customers have 19
realized significant net benefits since the Company’s entry 20
into the EIM in April 2018. As discussed in the Company’s 21
May 24, 2019, Report of EIM Benefits and Costs of 22
Participation, filed in Case No. IPC-E-16-19, Idaho Power 23
has developed a more precise methodology for determining 24
EIM benefits that uses inputs specific to the Company. 25

BRADY, DI 22
Idaho Power Company
Based on this methodology, the Company believes benefits 1
achieved between April 2021 and December 2021 are 2
approximately $16 million (benefits for the first quarter 3
of 2022 are not yet available). This level of EIM benefits 4
compared to the Idaho-jurisdictional EIM costs of $2.9 5
million, demonstrates a net benefit to the Company and, 6
ultimately, its customers. 7
C. PCA Rate Determination. 8
Q. How is the rate for the forecast portion of 9
the PCA for April 2022 through March 2023 determined? 10
A. The rate for the forecast portion of the PCA 11
is equal to the sum of (1) 95 percent of the difference 12
between the non-PURPA expenses quantified in the Operating 13
Plan and those quantified in the Company’s last approved 14
update of NPSE, divided by the Company’s forecast of system 15
firm sales for June 1, 2022, through May 31, 2023 (“System-16
level Sales Forecast”); and (2) 100 percent of the 17
difference between PURPA-related expenses quantified in the 18
Operating Plan and those quantified in the Company’s last 19
approved update of NPSE, divided by the Company’s System-20
level Sales Forecast; and (3) 100 percent of the difference 21
between the Idaho jurisdictional demand response incentive 22
payments quantified in the Operating Plan and those 23
quantified in the Company’s last approved update of NPSE, 24

BRADY, DI 23
Idaho Power Company
divided by the forecast of Idaho jurisdictional firm sales 1
for June 1, 2022, through May 31, 2023. 2
Q. What is the rate for the forecast portion of 3
the PCA for April 2022 through March 2023? 4
A. The rate for non-PURPA expenses is 0.7117 5
cents per kilowatt-hour (“kWh”), which is calculated by 6
multiplying $117,553,863 from Table 2 by 95 percent and 7
then dividing it by the System-level Sales Forecast of 8
15,690,546 MWh (($117,553,863 * 0.95) / 15,690,546) = 9
$7.117 /MWh = 0.7117 cents/kWh). The rate for PURPA 10
expenses is 0.5018 cents per kWh, which is calculated by 11
dividing $78,732,189 from Table 2 by the 15,690,546 MWh 12
($78,732,189 / 15,690,546 MWh = $5.018/MWh = 0.5018 13
cents/kWh). The rate for demand response incentive 14
payments is a negative 0.0209 cents per kWh, which is 15
calculated by dividing the negative $3,136,365 from Table 2 16
by the forecast of Idaho jurisdictional firm sales of 17
14,992,046 MWh (-$3,136,365 / 14,992,046 MWh = -$0.209/MWh 18
= -0.0209 cents/kWh). The forecast portion of the PCA rate 19
is 1.1926 cents per kWh, which is calculated by adding the 20
non-PURPA expense of 0.7117 cents per kWh to the PURPA 21
expense of 0.5018 cents per kWh to the demand response 22
incentive payment of negative 0.0209 cents per kWh (0. 7117 23
+ 0.5018 + -0.0209 = 1.1926 cents/kWh). 24

BRADY, DI 24
Idaho Power Company
Q. How did you compute this year’s Balancing 1
Account rate? 2
A. As shown in Exhibit No. 2, this year’s 3
Balancing Adjustment of the PCA is approximately $38.7 4
million, which, when divided by the Company’s forecast of 5
Idaho jurisdictional sales of 14,992,046 MWh, results in a 6
rate of 0.2579 cents per kWh ($38,669,526 / 14,992,046 = 7
$2.579/MWh = 0.2579 cents/kWh). 8
Q. What is the resulting PCA rate when you 9
combine all the PCA components described previously? 10
A. The uniform PCA rate comprises (1) the 1.1926 11
cents per kWh for the 2022-2023 projected power cost of 12
serving firm loads under the current PCA methodology and 95 13
percent sharing, and (2) the 0.2579 cents per kWh for the 14
2021-2022 Balancing Adjustment of the PCA. The sum of these 15
two components is a 1.4505 cents per kWh charge for all 16
rate classes. 17
III. ADDITIONAL PCA RATE ADJUSTMENTS 18
A. Revenue Sharing. 19
Q. When was the revenue sharing mechanism 20
originally established? 21
A. The revenue sharing mechanism was originally 22
established in Case No. IPC-E-09-30 and approved in Order 23
No. 30978, effective for the years 2009-2011. Since then, 24
the revenue sharing mechanism has been modified and 25

BRADY, DI 25
Idaho Power Company
extended three times.3 Most recently, the revenue sharing 1
mechanism was extended indefinitely, with modifications, in 2
Order No. 34071 in Case No. GNR-U-18-01. 3
Q. What are the provisions of the current revenue 4
sharing mechanism? 5
A. In Case No. GNR-U-18-01, the Company filed a 6
motion to approve a settlement stipulation (“2018 7
Stipulation”) extending the sharing mechanism indefinitely, 8
with modifications. The Commission approved the 2018 9
Stipulation in Order No. 34071. 10
Per the terms of the 2018 Stipulation, if the 11
Company’s actual year-end Return on Equity (“ROE”) for the 12
Idaho jurisdiction exceeds 10 percent, all amounts up to 13
and including a 10.5 percent ROE will be shared between 14
customers and the Company on an 80 percent and 20 percent 15
basis, respectively, to be provided as a rate reduction to 16
become effective at the time of the subsequent year’s PCA. 17
If the Company’s Idaho jurisdictional ROE exceeds 10.5 18
percent, all amounts in excess of 10.5 percent will be 19
shared 55 percent with Idaho customers as a rate reduction 20
to become effective with the subsequent year’s PCA, 25 21
percent will be shared with Idaho customers in the form of 22
an offset to amounts in the Company’s pension balancing 23
account, and 20 percent will be apportioned to the Company. 24

3 Order Nos. 32424, 33149 and 34071.

BRADY, DI 26
Idaho Power Company
With regard to the amortization of Accumulated 1
Deferred Investment Tax Credits (“ADITC”), the 2018 2
Stipulation allows the Company to accelerate the 3
amortization of ADITC, in an amount up to $45 million, to 4
achieve a maximum 9.4 percent Idaho jurisdictional ROE if 5
the Company’s year-end actual results fall below that 6
amount for any year beginning January 1, 2020. Idaho Power 7
may use up to $25 million of additional amortization of 8
ADITC per year, provided the total, cumulative amount of 9
ADITC does not exceed $45 million. Per the 2018 10
Stipulation, once the Company has fully amortized the $45 11
million of ADITC, revenue sharing will cease; however, 12
Idaho Power may at any time request to replenish the total 13
amount of ADITC it is permitted to amortize, and if 14
approved by the Commission, revenue sharing would continue. 15
Q. Did the revenue sharing mechanism result in 16
any action following the 2009-2020 fiscal years? 17
A. Yes. The Company’s earnings in each year from 18
2011 through 2015, as well as 2018, resulted in revenue 19
sharing with customers totaling $126.2 million, either as a 20
direct rate offset in the PCA or as an offset to amounts 21
that would have otherwise been collected in rates. The 22
Company’s earnings in 2016, 2017, 2019, and 2020 were below 23
the revenue sharing threshold. These amounts are detailed 24
in Table 6 below. 25

BRADY, DI 27
Idaho Power Company
Table 6 2009‐2020 Revenue Sharing 

Line No. Revenue Sharing Component 2009‐2011 2012‐2014 2015‐2020      
1 Available ADITC For Use $45 Million $45 Million $45 Million    
2 ROE Threshold 9.5% 9.5% 10.0%    
3 50‐50 Sharing Threshold 10.5% 10.0% N/A    
4 75‐25 Sharing Threshold N/A 10.5% 10.0%    
5 Customer Benefits ($ Millions):     
6 Reduction to Rates $27.1  $22.8  $8.2   Total 
7 Offset to Pension Balancing Account $20.3  $47.8  $0.0     2009‐2020 
8 Total $47.4  $70.6  $8.2     $126.2  
1
Q. Did the Company’s year-end 2021 financial 2
results warrant any action related to the existing sharing 3
agreement per the terms of the 2018 Stipulation? 4
A. Yes. The Company’s year-end 2021 financial 5
results yielded an actual Idaho jurisdictional ROE of 10.02 6
percent, above the 10 percent ROE threshold for revenue 7
sharing, and thus resulting in a revenue amount to be 8
shared with customers after tax gross-up of $568,771. 9
Q. Did the Company use the same methodology to 10
determine the Idaho jurisdictional 2021 year-end ROE that 11
was used in prior PCA filings? 12
A. Yes. The methodology used to determine the 13
Company’s Idaho jurisdictional 2021 year-end ROE is 14
consistent with the methodology used for the year-end ROE 15
determinations since the inception of the mechanism. 16
Q. Do you have an exhibit demonstrating the 17
application of this methodology? 18

BRADY, DI 28
Idaho Power Company
A. Yes. Exhibit No. 3 provides a step-by-step 1
calculation of the Idaho jurisdictional ROE based on year-2
end 2021 financial results utilizing the Commission-3
approved methodology from previous PCA filings. 4
Q. What is the revenue sharing amount to be 5
included in the 2022-2023 PCA? 6
A. As detailed in Exhibit No. 3, the 2021 Idaho 7
jurisdictional ROE was 10.02 percent. As quantified on line 8
63 of Exhibit No. 3, in 2021, the Company’s earnings 9
exceeded an Idaho jurisdictional ROE of 10 percent by 10
$527,962. Per the terms of the 2018 Stipulation, 80 percent 11
of the $527,962 should be shared with customers as a direct 12
reduction to PCA rates effective June 1, 2022. Applying the 13
80 percent sharing provision to the $527,962 yields a 14
customer-allocated sharing amount of $422,369. After tax 15
gross-up, the revenue sharing amount to be applied to 16
customer bills is $568,771. 17
Q. How does the Company propose to allocate the 18
$568,771 revenue sharing to customer classes? 19
A. The Company proposes to allocate the revenue 20
sharing benefit to customer classes utilizing the same 21
methodology as in past cases, i.e., based on each class’s 22
proportional share of forecasted base rate revenues for the 23
upcoming PCA rate effective year, which in this case is 24
June 1, 2022, through May 31, 2023. 25

BRADY, DI 29
Idaho Power Company
Q. Have you provided an exhibit detailing the 1
class allocation utilizing this methodology? 2
A. Yes. Exhibit No. 4 details the class 3
allocation of the $568,771 revenue sharing benefit. As 4
displayed in column G of Exhibit No. 4, each customer class 5
receives a decrease of approximately 0.05 percent relative 6
to current base revenues. 7
Q. How does the Company propose to include the 8
class-allocated revenue sharing benefits in rates? 9
A. Except for the special contracts for Micron 10
Technology, Inc., the U.S. Department of Energy, and the 11
J.R. Simplot Company – Pocatello, Idaho Power proposes to 12
include the class-allocated revenue sharing benefits on a 13
cents-per-kWh basis applied to the 2022 PCA rates effective 14
June 1, 2022, through May 31, 2023. Column F of Exhibit No. 15
4 contains the rates proposed for inclusion in each class’s 16
PCA rate. 17
Q. What is the Company’s proposal for providing 18
revenue sharing benefits to its special contract customers? 19
A. Consistent with the methodology used to share 20
2011-2015 and 2018 revenues, the Company proposes to 21
provide the special contract customers a flat dollar-per-22
month credit in 12 equal portions to serve as a reduction 23
to monthly invoices billed from June 2022 through May 2023. 24
The total revenue sharing benefit allocated to the special 25

BRADY, DI 30
Idaho Power Company
contract customers is displayed in column E of Exhibit No. 1
4. 2
Q. Is the Company’s rate design proposal for the 3
2022 revenue sharing benefits consistent with past-approved 4
proposals? 5
A. Yes. 6
IV. NET CUSTOMER IMPACT 7
Q. What is the revenue impact of the requested 8
PCA rate when compared with PCA rates currently in effect? 9
A. Attachment 2 to the Application filed 10
contemporaneously with my testimony provides a detailed 11
description of the overall revenue impact of this filing on 12
each customer class. As shown in Attachment 2, applying 13
the requested PCA rates to expected customer sales for the 14
June 2022 through May 2023 test year results in a PCA 15
increase of $103.4 million. 16
Q. Given the magnitude of the increase for the 17
2022-2023 PCA, did the Company consider proposing any rate 18
mitigation options? 19
A. Yes. Given the magnitude of the 2022-2023 PCA 20
increase, I consulted with management to determine what 21
mitigation, if any, the Company should include in this 22
year’s PCA filing. 23
Q. Following these discussions, is the Company 24
proposing to include any rate mitigation in this filing? 25

BRADY, DI 31
Idaho Power Company
A. No. After careful consideration, I was advised 1
by management to not propose any rate mitigation measures 2
in this case. However, the Company is open to rate 3
mitigation measures if the Commission deems them 4
appropriate. 5
Q. Why is the Company not proposing any rate 6
mitigation in this case? 7
A. First, the Company believes that customer 8
interests are generally best served by matching cost 9
recovery as closely as possible with the period in which 10
power supply costs are incurred. Additionally, mitigating 11
rate impacts by spreading recovery over multiple years 12
creates the possibility that the deferred collection will 13
result in “rate pancaking” with potential future rate 14
increases, essentially deferring an increase in the current 15
year to create an even larger increase in the future. The 16
Company also considered prior Commission orders with regard 17
to rate mitigation measures in the PCA. In orders from the 18
2008, 2009, 2013, and 2020 PCA cases4 in which rate 19
mitigation was discussed, the Commission declined to adopt 20
any rate mitigation measures, primarily for the same 21
concerns surrounding rate pancaking, appropriate matching 22
of costs and recovery, and the overall intent of the PCA 23
mechanism. 24

4 Order Nos. 30563, 30828, 32821, and 34682

BRADY, DI 32
Idaho Power Company
Q. Would Idaho Power be amenable to implementing 1
rate mitigation measures for the 2022-2023 PCA if the 2
Commission determines such measures are appropriate? 3
A. Yes. While both Idaho Power and the Commission 4
have expressed concerns with rate mitigation measures in 5
the past, the Company would be amenable to discussing such 6
measures in the current filing. A two-year recovery period, 7
for example, would reduce the rate impact from the proposed 8
$103.4 million, or 8.27 percent increase, to an approximate 9
$50 million, or slightly more than 4 percent, annual 10
increase in collection spread over two years. 11
Q. Have you prepared a revised Schedule 55 that 12
includes the proposed PCA rates? 13
A. Yes. Attachment 1 to the Application is a 14
revised Schedule 55 and includes the proposed PCA rates in 15
clean and legislative formats. 16
Q. Should the Commission approve the Company’s 17
computation of the PCA rates? 18
A. Yes. The Commission should approve the 19
Company’s computation of the PCA rates. The calculation of 20
the PCA rates follows the methodology that was approved in 21
Order Nos. 30715, 33307, and 34071. If approved, the 2022-22
2023 PCA will result in an increase in total billed revenue 23
of approximately $103.4 million, or 8.27 percent. 24
\\ 25

BRADY, DI 33
Idaho Power Company
Q. Does this conclude your testimony? 1
A. Yes, it does. 2
// 3
// 4
// 5
// 6
// 7
// 8
// 9
// 10
// 11
// 12
// 13
// 14
// 15
// 16
// 17
// 18
// 19
// 20
// 21
// 22
// 23
// 24
// 25

BRADY, DI 34
Idaho Power Company
DECLARATION OF JESSICA G. BRADY 1
I, Jessica G. Brady, declare under penalty of 2
perjury under the laws of the state of Idaho: 3
1. My name is Jessica G. Brady. I am employed 4
by Idaho Power Company as a Regulatory Analyst in the 5
Regulatory Affairs Department. 6
2. On behalf of Idaho Power, I present this 7
pre-filed direct testimony and Exhibit Nos. 1-4 in this 8
matter. 9
3. To the best of my knowledge, my pre-filed 10
direct testimony and exhibits are true and accurate. 11
I hereby declare that the above statement is true to 12
the best of my knowledge and belief, and that I understand 13
it is made for use as evidence before the Idaho Public 14
Utilities Commission and is subject to penalty for perjury. 15
SIGNED this 15th day of April 2022, at Boise, Idaho. 16
17
Signed: _________________________ 18

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

BRADY, DI
TESTIMONY

EXHIBIT NO. 1
Line No. FERC Accoun April May June Jul Augus Septembe Octobe Novembe Decembe January February March Annua
95% Sharing Account
1 Hydroelectric Generation (MWh 497,726 638,022 480,588 521,844 479,226 467,253 411,296 377,554 421,109 499,779 509,799 668,546 5,972,743
Account 536, Water for Power
2 Total Expense -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$
Account 501, Coa
Jim Bridge3 Energy (MWh)340,469 91,408 217,645 397,110 396,394 385,697 387,296 419,907 441,058 438,988 398,531 394,768 4,309,270
4 Total Expense 9,443,599$ 2,248,639$ 5,734,700$ 10,763,184$ 10,767,828$ 10,483,821$ 10,550,491$ 11,461,278$ 12,067,323$ 12,795,415$ 11,813,841$ 11,652,435$ 119,782,555$
North Valm
5 Energy (MWh)- (0) 49,680 92,374 92,374 89,394 92,374 89,394 92,374 92,374 83,435 (0) 773,773 6 Total Expense 253,916$ 253,916$ 2,055,223$ 3,588,576$ 3,598,821$ 3,491,852$ 3,602,724$ 3,499,879$ 3,614,433$ 3,730,360$ 3,445,374$ 261,533$ 31,396,605$
Account 547, Other Fuel
Langley Gulc
7 Energy (MWh)209,344 - 164,576 210,784 211,056 208,240 215,800 215,505 226,896 227,040 202,080 219,513 2,310,834 8 Total Expense 6,563,384$ 391,446$ 4,602,383$ 4,941,008$ 4,964,704$ 6,942,101$ 7,333,533$ 8,057,540$ 7,705,046$ 7,953,869$ 7,855,176$ 6,831,914$ 74,142,105$
Danskin
9 Energy (MWh)- - - 94,920 121,032 - - - - 2,752 - - 218,704
10 Total Expense 188,260$ 188,260$ 188,260$ 3,833,070$ 4,845,555$ 188,260$ 188,260$ 188,260$ 188,260$ 328,116$ 188,260$ 188,260$ 10,701,080$
Bennett Mountai11 Energy (MWh)- - - - 26,784 - - - - - - - 26,784.00
12 Total Expense 92,725$ 92,725$ 92,725$ 92,725$ 1,120,405$ 92,725$ 92,725$ 92,725$ 92,725$ 92,725$ 92,725$ 92,725$ 2,140,380$
Account 555, Purchased Power Non-PURP
13 Energy (MWh)40,254 279,203 366,794 289,780 172,321 41,195 31,697 56,268 114,743 75,148 53,545 59,379 1,580,326 14 Total Expense 4,157,980$ 9,534,941$ 11,968,170$ 17,449,226$ 18,381,020$ 4,286,045$ 4,053,608$ 4,883,331$ 9,440,738$ 6,207,751$ 4,714,385$ 4,829,284$ 99,906,480$
Account 565, 3rd Party Transmission15 Total Expense 322,260$ 284,758$ 630,748$ 842,719$ 784,043$ 478,164$ 524,429$ 294,591$ 231,318$ 250,501$ 247,157$ 258,551$ 5,149,239$
Account 447, Surplus Sale
16 Energy (MWh)243,770 - - - - 67,592 182,866 100,591 - 70,270 238,722 354,384 1,258,195
17 Total Expense (8,807,736)$ -$ -$ -$ -$ (5,618,895)$ (9,806,823)$ (5,227,868)$ (0)$ (5,477,413)$ (15,656,206)$ (14,490,907)$ (65,085,848)$
100% Sharing Account
Account 555, PURP
18 Energy (MWh)304,393 309,451 328,424 295,688 281,666 239,650 234,716 187,192 182,632 203,474 229,833 241,494 3,038,613 19 Total Expense 15,817,171$ 15,833,025$ 22,446,262$ 24,018,906$ 22,981,384$ 16,991,418$ 16,537,458$ 15,971,840$ 15,876,164$ 15,380,343$ 17,213,069$ 13,519,017$ 212,586,058$
Account 555, Demand Response Incentive
20 Total Expense -$ -$ 405,663$ 1,810,997$ 2,173,196$ 1,810,997$ 1,086,598$ 828,450$ -$ -$ -$ -$ 8,115,900$
21 Total Net Power Supply Expense 28,031,559$ 28,827,709$ 48,124,134$ 67,340,411$ 69,616,956$ 39,146,487$ 34,163,003$ 40,050,025$ 49,216,007$ 41,261,668$ 29,913,782$ 23,142,813$ 498,834,555$
22 Total Generation (MWh)1,392,185 1,318,084 1,607,707 1,902,500 1,780,853 1,431,430 1,373,179 1,345,819 1,478,812 1,539,556 1,477,222 1,583,700 18,231,048
23 Total Load (MWh)1,148,415 1,318,084 1,607,707 1,902,500 1,780,853 1,363,838 1,190,313 1,245,228 1,478,812 1,469,285 1,238,500 1,229,317 16,972,853
APRIL 1, 2022 - MARCH 31, 2023IDAHO POWER PCA FORECAS
Exhibit No. 1 Case No. IPC-E-22-11 J. Brady, IPC
Page 1 of 1

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

BRADY, DI
TESTIMONY

EXHIBIT NO. 2
Power Cost Adjustment Highlighted cells need to be updated prior to the June and July PCA entries
April 2021 thru March 2022
April May June July August September October November December January February March Totals
Idaho Jurisdiction Net Power Supply Expense (Non-QF)
Actual Non-QF
Fuel Expense-Coal 1,757,654.22 2,514,720.18 7,399,208.57 10,741,867.24 10,164,589.83 12,340,609.49 12,316,422.51 9,595,793.75 11,558,010.46 11,064,306.78 8,586,436.46 8,008,364.72 106,047,984.21
Fuel Expense-Gas 4,951,817.23 4,811,440.59 9,677,044.41 11,235,688.77 6,541,453.37 8,301,240.92 6,083,484.56 8,620,688.39 8,395,740.16 8,075,067.74 6,289,292.47 3,596,646.61 86,579,605.22
Non-Firm Purchases 3,493,642.85 5,088,468.04 31,400,383.66 34,713,710.07 20,241,393.06 14,739,423.21 11,093,208.55 11,275,274.53 18,479,986.77 15,990,136.63 17,785,197.15 8,774,306.18 193,075,130.70
Third Party Transmission 147,558.34 320,962.37 1,039,318.17 1,673,946.46 1,440,889.56 502,349.91 560,650.46 494,788.63 478,257.45 383,049.25 466,799.64 397,204.66 7,905,774.90
Surplus Sales 1,232,006.71 2,764,951.07 (9,915,940.56) (7,889,388.83) (5,147,668.33) (17,585,821.35) (10,333,780.36) (8,418,338.49) (8,094,574.26) (9,153,640.02) (4,647,258.89) (4,057,451.42) (81,246,904.73)
Water for Power (Leases)- - - - - - - - - - - - -
Total Actual NPSE $11,582,679.35 15,500,542.25 39,600,014.25 50,475,823.71 33,240,657.49 18,297,802.18 19,719,985.72 21,568,206.81 30,817,420.58 26,358,920.38 28,480,466.83 16,719,070.75 312,361,590.30
Idaho Allocation 95.1%95.5%95.8%95.9%95.9%95.8%95.7%95.0%95.2%95.3%95.4%95.7%
Net Idaho Jurisctional Actual Non-QF $11,015,128.06 14,803,017.85 37,936,813.65 48,406,314.94 31,877,790.53 17,529,294.49 18,872,026.33 20,489,796.47 29,338,184.39 25,120,051.12 27,170,365.36 16,000,150.71 298,558,933.90
Base Non-QF
Fuel Expense-Coal $7,525,242.00 7,487,643.00 9,019,153.00 11,385,255.00 12,185,412.00 10,796,845.00 7,781,442.00 7,302,324.00 8,455,019.00 9,553,773.00 8,912,994.00 8,098,078.00 108,503,180.00
Fuel Expense-Gas $2,314,209.00 2,302,646.00 2,773,625.00 3,501,263.00 3,747,333.00 3,320,312.00 2,392,997.00 2,245,656.00 2,600,139.00 2,938,035.00 2,740,979.00 2,490,369.00 33,367,563.00
Non-Firm Purchases $4,342,083.00 4,320,388.00 5,204,073.00 6,569,319.00 7,031,012.00 6,229,805.00 4,489,910.00 4,213,459.00 4,878,566.00 5,512,549.00 5,142,819.00 4,672,610.00 62,606,593.00
Third Party Transmission $378,398.00 376,507.00 453,517.00 572,494.00 612,729.00 542,907.00 391,281.00 367,189.00 425,151.00 480,400.00 448,179.00 407,203.00 5,455,955.00
Surplus Sales $(3,588,093.00) (3,570,166.00) (4,300,402.00) (5,428,577.00) (5,810,099.00) (5,148,019.00) (3,710,251.00) (3,481,805.00) (4,031,418.00) (4,555,312.00) (4,249,784.00) (3,861,227.00) (51,735,153.00)
Water for Power (Leases)$165,106.00 164,281.00 197,883.00 249,796.00 267,352.00 236,886.00 170,727.00 160,216.00 185,506.00 209,613.00 195,555.00 177,676.00 2,380,597.00
Idaho Base NPSE $11,136,945.00 11,081,299.00 13,347,849.00 16,849,550.00 18,033,739.00 15,978,736.00 11,516,106.00 10,807,039.00 12,512,963.00 14,139,058.00 13,190,742.00 11,984,709.00 160,578,735.00
Idaho Allocation 95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%
Net Idaho Jurisdiction 95% Items $10,580,097.75 10,527,234.05 12,680,456.55 16,007,072.50 17,132,052.05 15,179,799.20 10,940,300.70 10,266,687.05 11,887,314.85 13,432,105.10 12,531,204.90 11,385,473.55 152,549,798.25
Idaho Jurisdiction Change From Base $435,030.31 4,275,783.80 25,256,357.10 32,399,242.44 14,745,738.48 2,349,495.29 7,931,725.63 10,223,109.42 17,450,869.54 11,687,946.02 14,639,160.46 4,614,677.16 146,009,135.65
Sharing Percentage 95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%
Net Power Supply Expense Deferral ①$413,278.79 4,061,994.61 23,993,539.25 30,779,280.32 14,008,451.56 2,232,020.53 7,535,139.35 9,711,953.95 16,578,326.06 11,103,548.72 13,907,202.44 4,383,943.30 138,708,678.88
Idaho Jurisdictional Qualifying Facility NPSE
Actual QF (Includes Net Metering, Raft River 100% & Liquidated Damages)$14,914,964.00 16,814,327.42 21,562,454.29 20,857,476.76 22,001,656.24 16,148,827.73 16,039,245.65 15,134,743.71 18,257,040.00 12,014,614.09 14,654,191.67 13,776,760.43 202,176,301.99
Idaho Allocation 95.1%95.5%95.8%95.9%95.9%95.8%95.7%95.0%95.2%95.3%95.4%95.7%
Idaho Jurisctional Actual QF $14,184,130.76 16,057,682.69 20,656,831.21 20,002,320.21 21,099,588.33 15,470,576.97 15,349,558.09 14,378,006.52 17,380,702.08 11,449,927.23 13,980,098.85 13,184,359.73 193,193,782.67
Base QF $9,283,440.00 9,237,057.00 11,126,388.00 14,045,307.00 15,032,413.00 13,319,420.00 9,599,498.00 9,008,440.00 10,430,450.00 11,785,917.00 10,995,427.00 9,990,113.00 133,853,870.00
Idaho Allocation 95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%
Idaho Jurisdictional Base $8,819,268.00 8,775,204.15 10,570,068.60 13,343,041.65 14,280,792.35 12,653,449.00 9,119,523.10 8,558,018.00 9,908,927.50 11,196,621.15 10,445,655.65 9,490,607.35 127,161,176.50
Idaho Jurisdiction Change From Base $5,364,862.76 7,282,478.54 10,086,762.61 6,659,278.56 6,818,795.98 2,817,127.97 6,230,034.99 5,819,988.52 7,471,774.58 253,306.08 3,534,443.20 3,693,752.38 66,032,606.17
Sharing Percentage 100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%QF Deferral ②$5,364,862.76 7,282,478.54 10,086,762.61 6,659,278.56 6,818,795.98 2,817,127.97 6,230,034.99 5,819,988.52 7,471,774.58 253,306.08 3,534,443.20 3,693,752.38 66,032,606.17
Idaho Revenue Adjustment (SBAR
Actual Idaho Jurisdictional Billing Month Sales MWh 1,022,091 1,121,255 1,294,124 1,784,020 1,664,879 1,357,241 1,047,114 970,118 1,079,035 1,243,412 1,222,767 1,132,221 14,938,277
Normalized Idaho Jurisdictional Billing Month Sales MWh 947,192 953,286 1,131,686 1,370,142 1,428,766 1,300,608 1,045,495 957,864 1,081,014 1,177,663 1,101,149 1,004,027 13,498,892
Sales Change MWh 74,899 167,969 162,438 413,878 236,113 56,633 1,619 12,254 (1,979) 65,749 121,618 128,194 1,439,385
% of Prior Period Billings at Old Rate -$ 0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%
% of Current Period Billings at New Rate-effective 6/2015 26.72$ 100.000%100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000%
Sales Adjustment Prior To Sharing @ $(2,001,301.28) (4,488,131.68) (4,340,343.36) (11,058,820.16) (6,308,939.36) (1,513,233.76) (43,259.68) (327,426.88)52,878.88 (1,756,813.28) (3,249,632.96) (3,425,343.68) (38,460,367.20)
Sharing Percentage 95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%
Idaho Revenue Adjustment (SBAR) ③$(1,901,236.22) (4,263,725.10) (4,123,326.19) (10,505,879.15) (5,993,492.39) (1,437,572.07) (41,096.70) (311,055.54)50,234.94 (1,668,972.62) (3,087,151.31) (3,254,076.50) (36,537,348.85)
Idaho Jurisdcitional Demand Response Incentive Payments
Idaho Actual Demand Response $ - 15.00 215,509.60 2,837,603.74 2,830,335.20 918,876.18 339,283.73 (29,901.00) 338.82 - - - 7,112,061.27
Idaho Base Demand Response $ 780,401.00 776,502.00 935,327.00 1,180,702.00 1,263,682.00 1,119,681.00 806,970.00 757,284.00 876,823.00 990,769.00 924,317.00 839,807.00 11,252,265.00
Change From Base $(780,401.00) (776,487.00) (719,817.40) 1,656,901.74 1,566,653.20 (200,804.82) (467,686.27) (787,185.00) (876,484.18) (990,769.00) (924,317.00) (839,807.00) (4,140,203.73)
Sharing Percentage 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0% 100.0%
Change From Base ④$(780,401.00) (776,487.00) (719,817.40)1,656,901.74 1,566,653.20 (200,804.82) (467,686.27) (787,185.00) (876,484.18) (990,769.00) (924,317.00) (839,807.00) (4,140,203.73)
Idaho Miscellaneous Revenue
System Emission Allowance Sales Credit $ - - - - - - - - - - - - -
System Renewable Energy Credit Sales $(562,709.92) (2,514.98) (209,377.27) 306.63 248.05 204.28 (47,100.26) (957,856.00) 1,978.88 (15,162.75) (4,548,299.72) (8,460.92) (6,348,743.98)
Revenue Subtotal $(562,709.92) (2,514.98) (209,377.27)306.63 248.05 204.28 (47,100.26) (957,856.00)1,978.88 (15,162.75) (4,548,299.72) (8,460.92) (6,348,743.98)
Idaho Allocation 95.1% 95.5% 95.8% 95.9% 95.9% 95.8% 95.7% 95.0% 95.2% 95.3% 95.4% 95.7%
Sharing Percentage 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0%Miscellaneous Revenue Deferral ⑤$(508,380.28) (2,281.72) (190,554.25)279.36 225.99 185.92 (42,821.20) (864,465.04)1,789.70 (13,727.60) (4,122,124.04) (7,692.25) (5,749,565.41)
Exhibit No. 2
Case No. IPC-E-22-11 J. Brady, IPC
Page 1 of 2
Idaho EIM Participation Costs
Return on EIM Capital Investment $ 41,551.97 40,425.17 39,298.37 38,171.57 37,044.76 35,917.96 34,791.16 33,664.35 32,537.55 31,377.59 30,706.63 30,035.68 425,522.76
Operating Expenses $ 236,046.12 247,117.91 233,818.23 241,017.65 247,528.80 227,261.53 217,600.38 230,366.44 230,575.44 172,307.29 191,995.31 177,385.27 2,653,020.36
Revenue Subtotal $ 277,598.09 287,543.09 273,116.60 279,189.22 284,573.56 263,179.49 252,391.53 264,030.80 263,112.99 203,684.87 222,701.94 207,420.95 3,078,543.12
Sharing Percentage 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0% 95.0%
EIM Revenue Requirement ⑥$263,718.19 273,165.93 259,460.77 265,229.75 270,344.88 250,020.52 239,771.96 250,829.26 249,957.34 193,500.63 211,566.84 197,049.90 2,924,615.97
TOTAL DEFERRAL (Sum of ①-⑥) $2,851,842.24 6,575,145.26 29,306,064.79 28,855,090.58 16,670,979.22 3,660,978.05 13,453,342.13 13,820,066.15 23,475,598.44 8,876,886.21 9,519,620.13 4,173,169.83 161,238,783.03
PCA Forecasted Revenues
Actual Idaho Jurisdictional Billing Month Sales MWh 1,022,091 1,121,255 1,294,124 1,784,020 1,664,879 1,357,241 1,047,114 970,118 1,079,035 1,243,412 1,222,767 1,132,221 14,938,277
% of Prior Period Billings at Old Rate 6/1/2020 7.83$ 100.000%100.000% 59.416%1.049%0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%
% of Current Period Billings at New Rate - 6/1/2021 8.79$ 0.000%0.000% 40.600% 99.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000% 100.000%Forecast Rate Revenues ⑦(8,006,044.95) (8,782,797.58) (10,591,359.88) (15,672,159.87) (14,639,281.60) (11,934,224.01) (9,207,278.35) (8,530,253.86) (9,487,963.28) (10,933,325.62) (10,751,791.84) (9,955,623.02) (128,492,103.86)
PCA Balancing Account Balance
Monthly Interest Rate (Annual 1% for 2021-2022)%0.0833%0.0833% 0.0833% 0.0833%0.0833% 0.0833% 0.0833% 0.0833% 0.0833% 0.0833%0.0833%0.0833%1.0000%
2020-2021 PCA Ending Balance
True-up Ending Balance 4,519,614.31 4,519,614.31
True-up of the True-up Ending Balance (22,156,785.96) (22,156,785.96)
Beginning Balance (17,637,171.65)$ (19,769,421.03) (18,662,294.82) 2,995,202.48 18,384,016.20 22,468,617.64 15,872,975.72 21,413,705.95 27,906,822.00 43,235,933.07 42,735,093.69 43,032,551.71 (17,637,171.65)
2021-2022 Incremental Deferral (Sum of ①-⑥ above 2,851,842.24 6,575,145.26 29,306,064.79 28,855,090.58 16,670,979.22 3,660,978.05 13,453,342.13 13,820,066.15 23,475,598.44 8,876,886.21 9,519,620.13 4,173,169.83 161,238,783.03
2021-2022 PCA Forecast Revenues (Collections) ⑦ above (8,006,044.95) (8,782,797.58) (10,591,359.88) (15,672,159.87) (14,639,281.60) (11,934,224.01) (9,207,278.35) (8,530,253.86) (9,487,963.28) (10,933,325.62) (10,751,791.84) (9,955,623.02) (128,492,103.86)
2021-2022 PCA Prior Balance Revenues (Collections) 3,036,650.97 3,331,253.05 2,958,344.30 2,203,387.01 2,037,583.81 1,658,880.19 1,281,438.97 1,185,459.01 1,318,220.23 1,519,570.09 1,494,017.15 1,383,566.57 23,408,371.35
Revenue Sharing - Order No. - - - - - - - - - - - - -
DSM Rider Forecasted Surplus Funds - Order No. - - - - - - - - - - - - -
2021-2022 Ending Balance Without Current Month Interest (19,754,723.39) (18,645,820.30)3,010,754.39 18,381,520.20 22,453,297.63 15,854,251.87 21,400,478.47 27,888,977.25 43,212,677.39 42,699,063.75 42,996,939.13 38,633,665.09 38,517,878.87
Current Month Interest (14,697.64) (16,474.52) (15,551.91)2,496.00 15,320.01 18,723.85 13,227.48 17,844.75 23,255.68 36,029.94 35,612.58 35,860.46 151,646.68
2021-2022 Ending Deferral Balance (19,769,421.03)$ (18,662,294.82) 2,995,202.48 18,384,016.20 22,468,617.64 15,872,975.72 21,413,705.95 27,906,822.00 43,235,933.07 42,735,093.69 43,032,551.71 38,669,525.55 38,669,525.55
Tab is 100% locked down, with no manual inputs.
Idaho Billed Sales MWh 1,022,091 1,121,255 1,294,124 1,784,020 1,664,879 1,357,241 1,047,114 970,118 1,079,035 1,243,412 1,222,767 1,132,221 14,938,277
Oregon Billed Sales MWh 52,772 52,608 57,143 77,158 72,013 58,812 47,588 50,586 54,932 61,300 58,577 51,206 694,695
Total MWh 1,074,863 1,173,863 1,351,267 1,861,178 1,736,892 1,416,053 1,094,702 1,020,704 1,133,967 1,304,712 1,281,344 1,183,427 15,632,972
Idaho % Billed Sales 95.1%95.5%95.8%95.9%95.9%95.8%95.7%95.0%95.2%95.3%95.4%95.7%
Oregon % Billed Sales 4.9%4.5%4.2%4.1%4.1%4.2%4.3%5.0%4.8%4.7%4.6%4.3%
Exhibit No. 2
Case No. IPC-E-22-11 J. Brady, IPC
Page 2 of 2

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

BRADY, DI
TESTIMONY

EXHIBIT NO. 3

1
2
3
4
5
6
7 TOTAL TOTAL
8 SYSTEM IDAHO IDAHO %SYSTEM IDAHO IDAHO %
9 * * * SUMMARY OF RESULTS * * *
10 TOTAL COMBINED RATE BASE 3,697,810,735 3,552,703,864 96.076%
11
12 DEVELOPMENT OF NET INCOME
13 OPERATING REVENUES
14 RETAIL SALES REVENUES (Incl 449.1 Rev)974,391,283 932,709,732 Direct Assign 1,252,903,102 1,198,934,622 Direct Assign
15 OTHER OPERATING REVENUES 143,588,027 136,940,469 95.4%199,114,589 189,896,371 95.4%
16 TOTAL OPERATING REVENUES 1,117,979,310 1,069,650,202 1,452,017,691 1,388,830,993
17
18 OPERATING EXPENSES
19 OPERATION & MAINTENANCE EXPENSES 683,260,685 649,645,486 95.1%917,571,975 872,429,080 95.1%
20 DEPRECIATION EXPENSE 123,577,643 118,717,824 96.1%165,446,697 158,940,333 96.1%
21 AMORTIZATION OF LIMITED TERM PLANT 6,256,000 6,013,901 96.1%8,495,466 8,166,702 96.1%
22 TAXES OTHER THAN INCOME 26,188,106 24,462,684 93.4%30,947,260 28,908,278 93.4%
23 REGULATORY DEBITS/CREDITS 1,087,391 878,396 80.8%1,497,775 1,209,905 80.8%
24 PROVISION FOR DEFERRED INCOME TAXES (14,885,993) (14,382,662) 96.6%(21,559,910)(20,830,919)96.6%
25 INVESTMENT TAX CREDIT ADJUSTMENT 11,264,544 10,824,447 96.1%11,832,897 11,370,595 96.1%
26 FEDERAL INCOME TAXES 29,156,558 28,544,231 97.9%35,047,688 34,311,639 97.9%
27 STATE INCOME TAXES 11,411,459 11,163,398 97.8%13,298,956 13,009,865 97.8%
28 TOTAL OPERATING EXPENSES 877,316,394 835,867,704 1,162,578,803 1,107,515,477
29
30 OPERATING INCOME 240,662,916 233,782,498 289,438,888 281,315,516
31 ADD: IERCO OPERATING INCOME 6,715,053 6,414,821 95.5%8,991,347 8,589,341 95.5%
32
33 OPERATING INCOME BEFORE OTHER INCOME AND DEDUCTION 247,377,969 240,197,319 298,430,236 289,904,857 97.1%
34 ADD: AFUDC EQUITY 31,537,344 30,299,778 96.1% (L 10)
35 ADD: OTHER INCOME AND DEDUCTIONS 343,755 333,934 97.1% (L 33)
36
37 INCOME BEFORE INTEREST CHARGES 330,311,334 320,538,570
38 LESS: INTEREST CHARGES 86,663,666 83,262,872 96.1% (L 10)
39
40 NET INCOME 243,647,668 237,275,698
41
42 ACTUAL YEAR-END RESULTS - BEFORE ITC ADJUSTMENT
43 EARNINGS ON COMMON STOCK 243,647,668 237,275,698
44 COMMON EQUITY AT YEAR END 2,464,724,288 2,368,005,322 96.1% (L10)
45
46 RETURN ON YEAR-END COMMON EQUITY 9.89%10.02%
47
48 EARNINGS ON COMMON STOCK @ 9.40 ROE 234,148,807 222,592,500 (L44 * 9.4%)
49 EARNINGS ON COMMON STOCK @ 10 ROE 246,472,429 236,800,532 (L44 * 10%)
50 EARNINGS ON COMMON STOCK @ 10.50 ROE 258,796,050 248,640,559 (L44 * 10.5%)
51
52
53 ACTUAL YEAR-END RESULTS - AFTER ITC ADJUSTMENT:
54 INVESTMENT TAX CREDIT ADJUSTMENT (16,206,620) (L48-L43) / (1-9.4%)
55 ADJUSTED EARNINGS ON COMMON STOCK 221,069,078
56 ADJUSTED COMMON EQUITY AT YEAR-END 2,351,798,702
57 ADJUSTED RETURN ON YEAR-END COMMON EQUITY 9.40%
58
59 IF IDAHO RETURN ON COMMON EQUITY (Line 46) <9.4%
60 ADDITIONAL ITC ADJUSTMENT (Annualized) If L 54 is negative, then 0; if positive, then smaller of L54 or $25,000,000 0
61
62 IF IDAHO RETURN ON COMMON EQUITY (Line 46) >10%
63 IDAHO EARNINGS GREATER THAN 10% ROE BUT LESS THAN 10.5%527,962 (L43-L49)/(1-10%)
64
65 IF IDAHO RETURN ON COMMON EQUITY (Line 46) >10.5%
66 INCREMENTAL IDAHO EARNINGS GREATER THAN 10.50% ROE 0 (L43-L50)/(1-10.5%)
67
68 Per Order #34071:After Tax Tax Gross Up
69 ROE between 10%-10.5% --CUSTOMER SHARE - 80% (Reduction to rates)422,369 568,771
70 ROE between 10%-10.5% --COMPANY SHARE - 20% 105,592
71 ROE greater than 10.5% (Incremental) -- CUSTOMER SHARE - 55% (Reduction to rates)0 -
ROE greater than 10.5% (Incremental) -- CUSTOMER SHARE - 25% (Offset to Pension balance)0 -
72 ROE greater than 10.5% (Incremental) --COMPANY SHARE - 20% 0
73 527,962
74
Prepared by: Kelley Noe
Reviewed by:
September Allocations/Ratios
IDAHO POWER COMPANY
ADDITIONAL INVESTMENT TAX CREDIT ANALYSIS
For the Twelve Months Ended December 31, 2021
Actual September 30, 2021 Actual December 31, 2021
Exhibit No. 3 Case No. IPC-E-22-11 J. Brady, IPC
Page 1 of 1

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

BRADY, DI
TESTIMONY

EXHIBIT NO. 4

(A)(B)(C)(D)(E)(F) (G)
Line 
No Tariff Description
Rate 
Sch. 
No. 
Average 
Number of 
Customers
Normalized Energy 
(kWh)
Current Base 
Revenue
Percentage of 
Idaho Base 
Revenues
Allocated 
Revenue Sharing 
Benefit
Dollars per 
kWh Rate
Percent 
Revenue 
Change
Uniform Tariff Rates:
1 Residential Service 1 490,293 5,458,972,074 494,239,546 45.07% ($256,535) (0.000047) (0.05)%
2 Master Metered Mobile Home Park 3 21 4,521,955 388,104 0.04% ($201) (0.000045) (0.05)%
3 Residential Service Energy Watch 4 0 0 0 0.00%‐                        ‐                0.00%
4 Residential Service Time‐of‐Day 5 988 17,662,331 1,530,838 0.14% ($794) (0.000045) (0.05)%
5 Residential Service On‐Site Generation 6 12,024 65,895,664 6,381,494 0.58% ($3,097) (0.000047) (0.05)%
6 Small General Service 7 30,348 137,395,735 15,753,366 1.44% ($8,171) (0.000059) (0.05)%
7 Small General Service On‐Site Generation 8 80 190,425 24,155 0.00%($11) (0.000059) (0.05)%
8 Large General Service  ‐ Secondary 9S 37,635 3,304,176,840 225,029,064 20.52% ($116,704) (0.000035) (0.05)%
9 Large General Service  ‐ Primary 9P 280 592,994,508 35,347,188 3.22% ($18,332) (0.000031) (0.05)%
10 Large General Service  ‐ Transmission 9T 4 3,557,143 240,200 0.02% ($125) (0.000035) (0.05)%
11 Dusk to Dawn Lighting 15 0 5,267,423 1,238,927 0.11% ($643) (0.000122) (0.05)%
12 Large Power Service ‐ Secondary 19S 0 0 0 0.00%‐                        (0.000035) 0.00%
13 Large Power Service ‐ Primary 19P 114 2,358,498,546 121,991,234 11.12% ($63,267) (0.000027) (0.05)%
14 Large Power Service ‐ Transmission 19T 2 32,893,630 1,601,499 0.15% ($831) (0.000025) (0.05)%
15 Agricultural Irrigation Service 24 19,120 1,897,512,119 140,388,800 12.80% ($72,808) (0.000038) (0.05)%
16 Unmetered General Service 40 1,663 13,925,301 1,124,204 0.10% ($583) (0.000042) (0.05)%
17 Street Lighting 41 2,980 23,760,014 3,409,701 0.31% ($1,768) (0.000074) (0.05)%
18 Traffic Control Lighting 42 766 2,847,961 162,704 0.01%($84) (0.000030) (0.05)%
19 Total Uniform Tariffs 596,318 13,920,071,669 $1,048,851,023 95.64% ($543,955)(0.05)%
20 Total Special Contracts 3 1,071,974,663 $47,850,839 4.36% ($24,816)(0.05)%
21 Total Idaho Retail Sales 596,321 14,992,046,332 $1,096,701,862 100.00% ($568,771)(0.05)%
Note:
(1) June 01, 2022 ‐ May 31, 2023 Forecasted Test Year (Spring 2022 Forecast)
(2) 19S rate in column (F) set to match 9S rate due to single customer movement between classes.
Idaho Power Company
Calculation of Revenue Impact
Class Allocated Revenue Sharing 2022‐2023
State of Idaho
Filed April 15, 2022
Exhibit No. 4
Case No. IPC-E-22-11 Page 1 of 1
Idaho Power has filed the final piece of its annual spring cost adjustments
with the Idaho Public Utilities Commission (IPUC). This year’s Power Cost
Adjustment (PCA) calls for a price increase across all customer classes as a
result of higher power costs related to last summer’s unprecedented heatwave
and lower hydro generation because of drought conditions.
Neither Idaho Power nor its shareholders receive any financial return from this
filing, which is a request for $103.4 million. The money collected is used solely
to recover expenses associated with annual fluctuations in power costs.
The overall impact to residential customer bills on June 1 depends on the
outcome of three filings:
• The annual PCA, filed today, is a cost-recovery tool that passes on both the
benefits and costs of supplying energy to Idaho Power customers. If the
PCA proposal is approved by the IPUC as filed, the typical Idaho residential
customer using 950 kilowatt-hours (kWh) of energy per month will see a
$6.54 increase on their bill related to this request.
• The annual Fixed Cost Adjustment (FCA), filed in March and applicable to
only residential and small commercial customers, adjusts prices based on
changes in energy use per customer during the previous year. If the FCA
proposal is approved as filed, a typical Idaho residential customer will see a
$0.81 decrease on their bill related to this request.
• Idaho Power has requested a price increase to collect the cost of an
accelerated depreciation schedule for all coal-related investments at
the Jim Bridger Power Plant in Wyoming. If approved as filed, a typical
Idaho residential customer will see a $2.07 increase on their bill related
to this request.
Idaho Power
Files Annual
Power Cost
Adjustment
Oxbow Power Plant
Continued on reverse side
The impact of these three filings for all Idaho
customers is shown in the table below. A typical
Idaho residential customer will see an overall monthly
increase of $7.80. The actual percentage of change
will depend on a customer’s classification and the rate
they pay.
2022 RATE FILINGS
PERCENTAGE CHANGE FROM CURRENT BILLED REVENUE
Overall Percentage Impact Residential Small General Service
Large General Service1
Large Power2 Irrigation
POWER COST ADJUSMENT (PCA)3
8.27%6.55%5.24%9.18%12.10%8.46%
FIXED COST ADJUSMENT (FCA)
-0.39%-0.81%-0.82%N/A N/A N/A
BRIDGER
2.17%2.08%1.99%2.24%2.23%2.30%
COMBINED IMPACT4
10.05%7.82%6.41%11.43%14.33%10.75%
1 Includes lighting schedules; ² Includes special contracts; ³ Includes revenue
sharing; 4 Totals may not sum due to rounding
P.O. Box 70 (83707)
1221 W. Idaho St.
Boise, ID 83702
PRE-SORTED STANDARD
U.S. POSTAGE
PAID
BOISE, ID
PERMIT NO. 679
Important Information:Please Note: We want to ensure all of our customers
have sufficient time to submit comments to the IPUC.
Because your bill is processed toward the end of the
IPUC’s review of our request, you will receive this
notification twice: first in this postcard and then in
an insert in your bill later this month.
Idaho Power Files Annual Power Cost Adjustment
Continued from reverse side
The PCA has two main components:
the forecast and the backward-looking
balancing adjustment. The forecast reflects
Idaho Power’s anticipated fuel costs,
purchased power costs and customer
benefits from sales of surplus energy for the
coming April through March. The balancing
adjustment brings last year’s forecasted
costs in balance with costs actually incurred
by Idaho Power by looking back at what
happened the previous April through March.
The increase in this year’s PCA is attributed
to last year’s actual power supply costs,
which exceeded the forecast, driven by
lower-than-expected hydro generation, high
natural gas prices and high market prices.
Idaho Power experienced higher power costs
than it has in the past due to the record-
setting heat wave of summer 2021, during
which the company exceeded its previous
all-time peak load for five consecutive days.
Thank you for reading this notice.
We value your business.
Opportunities for Public Review
Idaho Power’s proposal is subject to public
review and approval by the IPUC. Copies of
the application are available to the public at
the IPUC offices (11331 W. Chinden Blvd.
Building 8, Suite 201-A, Boise, ID 83714),
Idaho Power offices, or at idahopower.com
or puc.idaho.gov. Customers also may
subscribe to the IPUC’s RSS feed to receive
periodic updates via email about the case.
Written comments regarding Idaho Power’s
proposal may be filed with the IPUC.
This year’s PCA forecast also reflects
expected increases to costs primarily due to
continued drought conditions, which would
result in less low-cost hydro generation
available to serve customers, and higher
costs associated with power purchase
agreements under the Public Utility
Regulatory Policies Act of 1978 (PURPA).
Line No. FERC Account April May June July August September October November December January February March Annual
95% Sharing Accounts
1 Hydroelectric Generation (MWh)497,726 638,022 480,588 521,844 479,226 467,253 411,296 377,554 421,109 499,779 509,799 668,546 5,972,743
Account 536, Water for Power
2 Total Expense -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$
Account 501, Coal
Jim Bridger
3 Energy (MWh)340,469 91,408 217,645 397,110 396,394 385,697 387,296 419,907 441,058 438,988 398,531 394,768 4,309,270
4 Total Expense 9,443,599$ 2,248,639$ 5,734,700$ 10,763,184$ 10,767,828$ 10,483,821$ 10,550,491$ 11,461,278$ 12,067,323$ 12,795,415$ 11,813,841$ 11,652,435$ 119,782,555$
North Valmy
5 Energy (MWh)- (0) 49,680 92,374 92,374 89,394 92,374 89,394 92,374 92,374 83,435 (0) 773,773
6 Total Expense 253,916$ 253,916$ 2,055,223$ 3,588,576$ 3,598,821$ 3,491,852$ 3,602,724$ 3,499,879$ 3,614,433$ 3,730,360$ 3,445,374$ 261,533$ 31,396,605$
Account 547, Other Fuel
Langley Gulch7 Energy (MWh)209,344 - 164,576 210,784 211,056 208,240 215,800 215,505 226,896 227,040 202,080 219,513 2,310,834 8 Total Expense 6,563,384$ 391,446$ 4,602,383$ 4,941,008$ 4,964,704$ 6,942,101$ 7,333,533$ 8,057,540$ 7,705,046$ 7,953,869$ 7,855,176$ 6,831,914$ 74,142,105$
Danskin
9 Energy (MWh)- - - 94,920 121,032 - - - - 2,752 - - 218,704
10 Total Expense 188,260$ 188,260$ 188,260$ 3,833,070$ 4,845,555$ 188,260$ 188,260$ 188,260$ 188,260$ 328,116$ 188,260$ 188,260$ 10,701,080$
Bennett Mountain
11 Energy (MWh)- - - - 26,784 - - - - - - - 26,784.00
12 Total Expense 92,725$ 92,725$ 92,725$ 92,725$ 1,120,405$ 92,725$ 92,725$ 92,725$ 92,725$ 92,725$ 92,725$ 92,725$ 2,140,380$
Account 555, Purchased Power Non-PURPA
13 Energy (MWh)40,254 279,203 366,794 289,780 172,321 41,195 31,697 56,268 114,743 75,148 53,545 59,379 1,580,326
14 Total Expense 4,157,980$ 9,534,941$ 11,968,170$ 17,449,226$ 18,381,020$ 4,286,045$ 4,053,608$ 4,883,331$ 9,440,738$ 6,207,751$ 4,714,385$ 4,829,284$ 99,906,480$
Account 565, 3rd Party Transmission
15 Total Expense 322,260$ 284,758$ 630,748$ 842,719$ 784,043$ 478,164$ 524,429$ 294,591$ 231,318$ 250,501$ 247,157$ 258,551$ 5,149,239$
Account 447, Surplus Sales
16 Energy (MWh)243,770 - - - - 67,592 182,866 100,591 - 70,270 238,722 354,384 1,258,195
17 Total Expense (8,807,736)$ -$ -$ -$ -$ (5,618,895)$ (9,806,823)$ (5,227,868)$ (0)$ (5,477,413)$ (15,656,206)$ (14,490,907)$ (65,085,848)$
100% Sharing Accounts
Account 555, PURPA18 Energy (MWh)304,393 309,451 328,424 295,688 281,666 239,650 234,716 187,192 182,632 203,474 229,833 241,494 3,038,613 19 Total Expense 15,817,171$ 15,833,025$ 22,446,262$ 24,018,906$ 22,981,384$ 16,991,418$ 16,537,458$ 15,971,840$ 15,876,164$ 15,380,343$ 17,213,069$ 13,519,017$ 212,586,058$
Account 555, Demand Response Incentives
20 Total Expense -$ -$ 405,663$ 1,810,997$ 2,173,196$ 1,810,997$ 1,086,598$ 828,450$ -$ -$ -$ -$ 8,115,900$
21 Total Net Power Supply Expense 28,031,559$ 28,827,709$ 48,124,134$ 67,340,411$ 69,616,956$ 39,146,487$ 34,163,003$ 40,050,025$ 49,216,007$ 41,261,668$ 29,913,782$ 23,142,813$ 498,834,555$
22 Total Generation (MWh)1,392,185 1,318,084 1,607,707 1,902,500 1,780,853 1,431,430 1,373,179 1,345,819 1,478,812 1,539,556 1,477,222 1,583,700 18,231,048
23 Total Load (MWh)1,148,415 1,318,084 1,607,707 1,902,500 1,780,853 1,363,838 1,190,313 1,245,228 1,478,812 1,469,285 1,238,500 1,229,317 16,972,853
APRIL 1, 2022 - MARCH 31, 2023
#Internal Use Only
Power Cost Adjustment Highlighted cells need to be updated prior to the June and July PCA entries
April 2021 thru March 2022
April May June July August September October November December January February March Totals
Idaho Jurisdiction Net Power Supply Expense (Non-QF)
Actual Non-QF
Fuel Expense-Coal 1,757,654.22 2,514,720.18 7,399,208.57 10,741,867.24 10,164,589.83 12,340,609.49 12,316,422.51 9,595,793.75 11,558,010.46 11,064,306.78 8,586,436.46 8,008,364.72 106,047,984.21
Fuel Expense-Gas 4,951,817.23 4,811,440.59 9,677,044.41 11,235,688.77 6,541,453.37 8,301,240.92 6,083,484.56 8,620,688.39 8,395,740.16 8,075,067.74 6,289,292.47 3,596,646.61 86,579,605.22
Non-Firm Purchases 3,493,642.85 5,088,468.04 31,400,383.66 34,713,710.07 20,241,393.06 14,739,423.21 11,093,208.55 11,275,274.53 18,479,986.77 15,990,136.63 17,785,197.15 8,774,306.18 193,075,130.70
Third Party Transmission 147,558.34 320,962.37 1,039,318.17 1,673,946.46 1,440,889.56 502,349.91 560,650.46 494,788.63 478,257.45 383,049.25 466,799.64 397,204.66 7,905,774.90
Surplus Sales 1,232,006.71 2,764,951.07 (9,915,940.56) (7,889,388.83) (5,147,668.33) (17,585,821.35) (10,333,780.36) (8,418,338.49) (8,094,574.26) (9,153,640.02) (4,647,258.89) (4,057,451.42) (81,246,904.73)
Water for Power (Leases)- - - - - - - - - - - - -
Total Actual NPSE $11,582,679.35 15,500,542.25 39,600,014.25 50,475,823.71 33,240,657.49 18,297,802.18 19,719,985.72 21,568,206.81 30,817,420.58 26,358,920.38 28,480,466.83 16,719,070.75 312,361,590.30
Idaho Allocation 95.1%95.5%95.8%95.9%95.9%95.8%95.7%95.0%95.2%95.3%95.4%95.7%
Net Idaho Jurisctional Actual Non-QF $11,015,128.06 14,803,017.85 37,936,813.65 48,406,314.94 31,877,790.53 17,529,294.49 18,872,026.33 20,489,796.47 29,338,184.39 25,120,051.12 27,170,365.36 16,000,150.71 298,558,933.90
Base Non-QF
Fuel Expense-Coal $7,525,242.00 7,487,643.00 9,019,153.00 11,385,255.00 12,185,412.00 10,796,845.00 7,781,442.00 7,302,324.00 8,455,019.00 9,553,773.00 8,912,994.00 8,098,078.00 108,503,180.00
Fuel Expense-Gas $2,314,209.00 2,302,646.00 2,773,625.00 3,501,263.00 3,747,333.00 3,320,312.00 2,392,997.00 2,245,656.00 2,600,139.00 2,938,035.00 2,740,979.00 2,490,369.00 33,367,563.00
Non-Firm Purchases $4,342,083.00 4,320,388.00 5,204,073.00 6,569,319.00 7,031,012.00 6,229,805.00 4,489,910.00 4,213,459.00 4,878,566.00 5,512,549.00 5,142,819.00 4,672,610.00 62,606,593.00
Third Party Transmission $378,398.00 376,507.00 453,517.00 572,494.00 612,729.00 542,907.00 391,281.00 367,189.00 425,151.00 480,400.00 448,179.00 407,203.00 5,455,955.00
Surplus Sales $(3,588,093.00)(3,570,166.00)(4,300,402.00)(5,428,577.00)(5,810,099.00)(5,148,019.00)(3,710,251.00)(3,481,805.00)(4,031,418.00)(4,555,312.00)(4,249,784.00)(3,861,227.00)(51,735,153.00)
Water for Power (Leases)$165,106.00 164,281.00 197,883.00 249,796.00 267,352.00 236,886.00 170,727.00 160,216.00 185,506.00 209,613.00 195,555.00 177,676.00 2,380,597.00
Idaho Base NPSE $ 11,136,945.00 11,081,299.00 13,347,849.00 16,849,550.00 18,033,739.00 15,978,736.00 11,516,106.00 10,807,039.00 12,512,963.00 14,139,058.00 13,190,742.00 11,984,709.00 160,578,735.00
Idaho Allocation 95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%
Net Idaho Jurisdiction 95% Items $ 10,580,097.75 10,527,234.05 12,680,456.55 16,007,072.50 17,132,052.05 15,179,799.20 10,940,300.70 10,266,687.05 11,887,314.85 13,432,105.10 12,531,204.90 11,385,473.55 152,549,798.25
Idaho Jurisdiction Change From Base
Net Power Supply Expense Deferral ①
Idaho Jurisdictional Qualifying Facility NPSE
Actual QF (Includes Net Metering, Raft River 100% & Liquidated Damages)
Base QF
QF Deferral ②
Idaho Revenue Adjustment (SBAR)
Idaho Revenue Adjustment (SBAR) ③
Idaho Jurisdcitional Demand Response Incentive Payments
Idaho Actual Demand Response $- 15.00 215,509.60 2,837,603.74 2,830,335.20 918,876.18 339,283.73 (29,901.00) 338.82 - - - 7,112,061.27
Idaho Base Demand Response $780,401.00 776,502.00 935,327.00 1,180,702.00 1,263,682.00 1,119,681.00 806,970.00 757,284.00 876,823.00 990,769.00 924,317.00 839,807.00 11,252,265.00
Change From Base $(780,401.00) (776,487.00) (719,817.40) 1,656,901.74 1,566,653.20 (200,804.82) (467,686.27) (787,185.00) (876,484.18) (990,769.00) (924,317.00) (839,807.00) (4,140,203.73)
Sharing Percentage 100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%
Change From Base ④$(780,401.00) (776,487.00) (719,817.40)1,656,901.74 1,566,653.20 (200,804.82) (467,686.27) (787,185.00) (876,484.18) (990,769.00) (924,317.00) (839,807.00) (4,140,203.73)
Idaho Miscellaneous Revenue
Miscellaneous Revenue Deferral ⑤
#Internal Use Only
Idaho EIM Participation Costs
Return on EIM Capital Investment $41,551.97 40,425.17 39,298.37 38,171.57 37,044.76 35,917.96 34,791.16 33,664.35 32,537.55 31,377.59 30,706.63 30,035.68 425,522.76
Operating Expenses $236,046.12 247,117.91 233,818.23 241,017.65 247,528.80 227,261.53 217,600.38 230,366.44 230,575.44 172,307.29 191,995.31 177,385.27 2,653,020.36
Revenue Subtotal $277,598.09 287,543.09 273,116.60 279,189.22 284,573.56 263,179.49 252,391.53 264,030.80 263,112.99 203,684.87 222,701.94 207,420.95 3,078,543.12
Sharing Percentage 95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%
EIM Revenue Requirement ⑥$263,718.19 273,165.93 259,460.77 265,229.75 270,344.88 250,020.52 239,771.96 250,829.26 249,957.34 193,500.63 211,566.84 197,049.90 2,924,615.97
TOTAL DEFERRAL (Sum of ①-⑥)$2,851,842.24 6,575,145.26 29,306,064.79 28,855,090.58 16,670,979.22 3,660,978.05 13,453,342.13 13,820,066.15 23,475,598.44 8,876,886.21 9,519,620.13 4,173,169.83 161,238,783.03
PCA Forecasted Revenues
Actual Idaho Jurisdictional Billing Month Sales MWh 1,022,091 1,121,255 1,294,124 1,784,020 1,664,879 1,357,241 1,047,114 970,118 1,079,035 1,243,412 1,222,767 1,132,221 14,938,277
% of Prior Period Billings at Old Rate 6/1/2020 7.83$ 100.000%100.000%59.416%1.049%0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%
% of Current Period Billings at New Rate - 6/1/2021 8.79$ 0.000%0.000%40.600%99.000%100.000%100.000%100.000%100.000%100.000%100.000%100.000%100.000%
Forecast Rate Revenues ⑦(8,006,044.95)(8,782,797.58)(10,591,359.88)(15,672,159.87)(14,639,281.60)(11,934,224.01)(9,207,278.35)(8,530,253.86)(9,487,963.28)(10,933,325.62)(10,751,791.84)(9,955,623.02)(128,492,103.86)
PCA Balancing Account Balance
Monthly Interest Rate (Annual 1% for 2021-2022)%0.0833%0.0833%0.0833%0.0833%0.0833%0.0833%0.0833%0.0833%0.0833%0.0833%0.0833%0.0833%1.0000%
2020-2021 PCA Ending Balance
True-up Ending Balance 4,519,614.31 4,519,614.31
True-up of the True-up Ending Balance (22,156,785.96) (22,156,785.96)
Beginning Balance (17,637,171.65)$ (19,769,421.03) (18,662,294.82) 2,995,202.48 18,384,016.20 22,468,617.64 15,872,975.72 21,413,705.95 27,906,822.00 43,235,933.07 42,735,093.69 43,032,551.71 (17,637,171.65)
2021-2022 Incremental Deferral (Sum of ①-⑥ above 2,851,842.24 6,575,145.26 29,306,064.79 28,855,090.58 16,670,979.22 3,660,978.05 13,453,342.13 13,820,066.15 23,475,598.44 8,876,886.21 9,519,620.13 4,173,169.83 161,238,783.03
2021-2022 PCA Forecast Revenues (Collections) ⑦ above (8,006,044.95)(8,782,797.58) (10,591,359.88) (15,672,159.87) (14,639,281.60) (11,934,224.01) (9,207,278.35) (8,530,253.86) (9,487,963.28) (10,933,325.62) (10,751,791.84) (9,955,623.02) (128,492,103.86)
2021-2022 PCA Prior Balance Revenues (Collections)3,036,650.97 3,331,253.05 2,958,344.30 2,203,387.01 2,037,583.81 1,658,880.19 1,281,438.97 1,185,459.01 1,318,220.23 1,519,570.09 1,494,017.15 1,383,566.57 23,408,371.35
Revenue Sharing - Order No. - - - - - - - - - - - - -
DSM Rider Forecasted Surplus Funds - Order No. - - - - - - - - - - - - -
2021-2022 Ending Balance Without Current Month Interest (19,754,723.39)(18,645,820.30)3,010,754.39 18,381,520.20 22,453,297.63 15,854,251.87 21,400,478.47 27,888,977.25 43,212,677.39 42,699,063.75 42,996,939.13 38,633,665.09 38,517,878.87
Current Month Interest (14,697.64)(16,474.52)(15,551.91)2,496.00 15,320.01 18,723.85 13,227.48 17,844.75 23,255.68 36,029.94 35,612.58 35,860.46 151,646.68
2021-2022 Ending Deferral Balance (19,769,421.03)$ (18,662,294.82) 2,995,202.48 18,384,016.20 22,468,617.64 15,872,975.72 21,413,705.95 27,906,822.00 43,235,933.07 42,735,093.69 43,032,551.71 38,669,525.55 38,669,525.55
Tab is 100% locked down, with no manual inputs.
Idaho Billed Sales MWh 1,022,091 1,121,255 1,294,124 1,784,020 1,664,879 1,357,241 1,047,114 970,118 1,079,035 1,243,412 1,222,767 1,132,221 14,938,277
Oregon Billed Sales MWh 52,772 52,608 57,143 77,158 72,013 58,812 47,588 50,586 54,932 61,300 58,577 51,206 694,695 Total MWh 1,074,863 1,173,863 1,351,267 1,861,178 1,736,892 1,416,053 1,094,702 1,020,704 1,133,967 1,304,712 1,281,344 1,183,427 15,632,972
Idaho % Billed Sales 95.1%95.5%95.8%95.9%95.9%95.8%95.7%95.0%95.2%95.3%95.4%95.7%
1
2
3
4
5
6
7 TOTAL TOTAL
8 SYSTEM IDAHO IDAHO %SYSTEM IDAHO IDAHO %
9 * * * SUMMARY OF RESULTS * * *
10 TOTAL COMBINED RATE BASE 3,697,810,735 3,552,703,864 96.076%
11
12 DEVELOPMENT OF NET INCOME
13 OPERATING REVENUES
14 RETAIL SALES REVENUES (Incl 449.1 Rev)974,391,283 932,709,732 Direct Assign 1,252,903,102 1,198,934,622 Direct Assign
15 OTHER OPERATING REVENUES 143,588,027 136,940,469 95.4%199,114,589 189,896,371 95.4%
16 TOTAL OPERATING REVENUES 1,117,979,310 1,069,650,202 1,452,017,691 1,388,830,993
17
18 OPERATING EXPENSES
19 OPERATION & MAINTENANCE EXPENSES 683,260,685 649,645,486 95.1%917,571,975 872,429,080 95.1%
20 DEPRECIATION EXPENSE 123,577,643 118,717,824 96.1%165,446,697 158,940,333 96.1%
21 AMORTIZATION OF LIMITED TERM PLANT 6,256,000 6,013,901 96.1%8,495,466 8,166,702 96.1%
22 TAXES OTHER THAN INCOME 26,188,106 24,462,684 93.4%30,947,260 28,908,278 93.4%
23 REGULATORY DEBITS/CREDITS 1,087,391 878,396 80.8%1,497,775 1,209,905 80.8%
24 PROVISION FOR DEFERRED INCOME TAXES (14,885,993) (14,382,662) 96.6%(21,559,910)(20,830,919)96.6%
25 INVESTMENT TAX CREDIT ADJUSTMENT 11,264,544 10,824,447 96.1%11,832,897 11,370,595 96.1%
26 FEDERAL INCOME TAXES 29,156,558 28,544,231 97.9%35,047,688 34,311,639 97.9%
27 STATE INCOME TAXES 11,411,459 11,163,398 97.8%13,298,956 13,009,865 97.8%
28 TOTAL OPERATING EXPENSES 877,316,394 835,867,704 1,162,578,803 1,107,515,477
29
30 OPERATING INCOME 240,662,916 233,782,498 289,438,888 281,315,516
31 ADD: IERCO OPERATING INCOME 6,715,053 6,414,821 95.5%8,991,347 8,589,341 95.5%
32
33 OPERATING INCOME BEFORE OTHER INCOME AND DEDUCTIONS 247,377,969 240,197,319 298,430,236 289,904,857 97.1%
34 ADD: AFUDC EQUITY 31,537,344 30,299,778 96.1% (L 10)
35 ADD: OTHER INCOME AND DEDUCTIONS 343,755 333,934 97.1% (L 33)
36
37 INCOME BEFORE INTEREST CHARGES 330,311,334 320,538,570
38 LESS: INTEREST CHARGES 86,663,666 83,262,872 96.1% (L 10)
39
40 NET INCOME 243,647,668 237,275,698
41
42 ACTUAL YEAR-END RESULTS - BEFORE ITC ADJUSTMENT
43 EARNINGS ON COMMON STOCK 243,647,668 237,275,698
44 COMMON EQUITY AT YEAR END 2,464,724,288 2,368,005,322 96.1% (L10)
45
46 RETURN ON YEAR-END COMMON EQUITY 9.89%10.02%
47
48 EARNINGS ON COMMON STOCK @ 9.40 ROE 234,148,807 222,592,500 (L44 * 9.4%)
49 EARNINGS ON COMMON STOCK @ 10 ROE 246,472,429 236,800,532 (L44 * 10%)
50 EARNINGS ON COMMON STOCK @ 10.50 ROE 258,796,050 248,640,559 (L44 * 10.5%)
51
52
53 ACTUAL YEAR-END RESULTS - AFTER ITC ADJUSTMENT:
54 INVESTMENT TAX CREDIT ADJUSTMENT (16,206,620) (L48-L43) / (1-9.4%)
55 ADJUSTED EARNINGS ON COMMON STOCK 221,069,078
56 ADJUSTED COMMON EQUITY AT YEAR-END 2,351,798,702
57 ADJUSTED RETURN ON YEAR-END COMMON EQUITY 9.40%
58
59 IF IDAHO RETURN ON COMMON EQUITY (Line 46) <9.4%
60 ADDITIONAL ITC ADJUSTMENT (Annualized)If L 54 is negative, then 0; if positive, then smaller of L54 or $25,000,000 0
61
62 IF IDAHO RETURN ON COMMON EQUITY (Line 46) >10%
63 IDAHO EARNINGS GREATER THAN 10% ROE BUT LESS THAN 10.5%527,962 (L43-L49)/(1-10%)
64
65 IF IDAHO RETURN ON COMMON EQUITY (Line 46) >10.5%
66 INCREMENTAL IDAHO EARNINGS GREATER THAN 10.50% ROE 0 (L43-L50)/(1-10.5%)
67
68 Per Order #34071:After Tax Tax Gross Up
69 ROE between 10%-10.5% --CUSTOMER SHARE - 80% (Reduction to rates)422,369 568,771
70 ROE between 10%-10.5% --COMPANY SHARE - 20% 105,592
71 ROE greater than 10.5% (Incremental) -- CUSTOMER SHARE - 55% (Reduction to rates)0 -
ROE greater than 10.5% (Incremental) -- CUSTOMER SHARE - 25% (Offset to Pension balance)0 -
72 ROE greater than 10.5% (Incremental) --COMPANY SHARE - 20% 0
73 527,962
74
Prepared by: Kelley Noe
Reviewed by:
September Allocations/Ratios
IDAHO POWER COMPANY
ADDITIONAL INVESTMENT TAX CREDIT ANALYSIS
For the Twelve Months Ended December 31, 2021
Actual September 30, 2021 Actual December 31, 2021
(A)(B)(C)(D)(E)(F) (G)
Line
No Tariff Description
Sch. Number of (kWh)
Current Base
Revenue Idaho Base Revenue Sharing Dollars per
kWh Rate Revenue
Uniform Tariff Rates:
1 Residential Service 1 490,293 5,458,972,074 494,239,546 45.07% ($256,535) (0.000047) (0.05)%
2 Master Metered Mobile Home Park 3 21 4,521,955 388,104 0.04% ($201) (0.000045) (0.05)%
3 Residential Service Energy Watch 4 0 0 0 0.00%- - 0.00%
4 Residential Service Time-of-Day 5 988 17,662,331 1,530,838 0.14% ($794) (0.000045) (0.05)%
5 Residential Service On-Site Generation 6 12,024 65,895,664 6,381,494 0.58% ($3,097) (0.000047) (0.05)%
6 Small General Service 7 30,348 137,395,735 15,753,366 1.44% ($8,171) (0.000059) (0.05)%
7 Small General Service On-Site Generation 8 80 190,425 24,155 0.00%($11) (0.000059) (0.05)%
8 Large General Service - Secondary 9S 37,635 3,304,176,840 225,029,064 20.52% ($116,704) (0.000035) (0.05)%
9 Large General Service - Primary 9P 280 592,994,508 35,347,188 3.22% ($18,332) (0.000031) (0.05)%
10 Large General Service - Transmission 9T 4 3,557,143 240,200 0.02% ($125) (0.000035) (0.05)%
11 Dusk to Dawn Lighting 15 0 5,267,423 1,238,927 0.11% ($643) (0.000122) (0.05)%
12 Large Power Service - Secondary 19S 0 0 0 0.00%- (0.000035) 0.00%
13 Large Power Service - Primary 19P 114 2,358,498,546 121,991,234 11.12% ($63,267) (0.000027) (0.05)%
14 Large Power Service - Transmission 19T 2 32,893,630 1,601,499 0.15% ($831) (0.000025) (0.05)%
15 Agricultural Irrigation Service 24 19,120 1,897,512,119 140,388,800 12.80% ($72,808) (0.000038) (0.05)%
16 Unmetered General Service 40 1,663 13,925,301 1,124,204 0.10% ($583) (0.000042) (0.05)%
17 Street Lighting 41 2,980 23,760,014 3,409,701 0.31% ($1,768) (0.000074) (0.05)%
18 Traffic Control Lighting 42 766 2,847,961 162,704 0.01%($84) (0.000030) (0.05)%
19 Total Uniform Tariffs 596,318 13,920,071,669 $1,048,851,023 95.64% ($543,955)(0.05)%
20 Total Special Contracts 3 1,071,974,663 $47,850,839 4.36% ($24,816)(0.05)%
Note:
(1) June 01, 2022 - May 31, 2023 Forecasted Test Year (Spring 2022 Forecast)
(2) 19S rate in column (F) set to match 9S rate due to single customer movement between classes.
Idaho Power Company
Calculation of Revenue Impact
Class Allocated Revenue Sharing 2022-2023
State of Idaho
Filed April 15, 2022
1
From:Gust, Stacy
Sent:Monday, April 18, 2022 9:09 AM
To:Jan Noriyuki
Subject:RE: IPC-E-22-11 Application of Idaho Power Company for Authority to Implement Power
Cost Adjustment (PCA) Rates for Electric Service from June 1, 2022 through May 31,
2023
Attachments:2022 PCA - Brady Testimony FINAL.docx
Ms. Noriyuki,

Please find attached the Word version of the Direct Testimony of Jessica Brady for the reporter.

Thank you.

Stacy Gust
REGULATORY ADMINISTRATIVE ASSISTANT
Idaho Power | Regulatory Affairs
Office 208-388-5749

From: Gust, Stacy
Sent: Friday, April 15, 2022 4:07 PM
To: Jan Noriyuki <[e-mail]>
Cc: Nordstrom, Lisa <[e-mail]>
Subject: IPC-E-22-11 Application of Idaho Power Company for Authority to Implement Power Cost Adjustment (PCA)
Rates for Electric Service from June 1, 2022 through May 31, 2023

Ms. Noriyuki,

Please find attached for electronic filing, pursuant to Order No. 35058, Idaho Power Company’s 2022-2023 Power Cost
Adjustment (PCA) Application, the Direct Testimony of Jessica Brady, PCA Bill Insert, PCA Postcard, and PCA News
Release.

Also provided as a courtesy to Staff are the Excel workpapers.

If you have any questions regarding this filing, please do not hesitate to contact me.

Thank you.

Stacy Gust
REGULATORY ADMINISTRATIVE ASSISTANT
Idaho Power | Regulatory Affairs
Office 208-388-5749

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO IMPLEMENT POWER
COST ADJUSTMENT (“PCA”) RATES
FOR ELECTRIC SERVICE FROM JUNE
1, 2022, THROUGH MAY 31, 2023.

)
)
)
)
)
)
)

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

DIRECT TESTIMONY

OF

JESSICA G. BRADY

BRADY, 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 Jessica G. Brady. My business 4
address is 1221 West Idaho Street, Boise, Idaho 83702. I 5
am employed by Idaho Power as a Regulatory Analyst in the 6
Regulatory Affairs Department. 7
Q. Please describe your educational background. 8
A. In May of 2016, I received a Bachelor of 9
Science degree in Economics and a Bachelor of Arts degree 10
in Spanish from the University of Idaho. I have also 11
attended “Electric Utility Fundamentals & Insights,” an 12
electric utility course offered through the Western Energy 13
Institute. 14
Q. Please describe your work experience. 15
A. In September 2021, I was hired as a Regulatory 16
Analyst in Idaho Power’s Regulatory Affairs Department. As 17
a Regulatory Analyst, I provide support for the Company’s 18
regulatory activities, including compliance reporting, 19
financial analysis, and the development of revenue 20
forecasts for regulatory filings. I am also responsible for 21
the Company’s power cost filings in both Idaho and Oregon. 22
Prior to Idaho Power, I worked for five years at 23
Clearwater Analytics, a provider of investment accounting 24
and reporting software. I held various roles at Clearwater 25

BRADY, DI 2
Idaho Power Company
Analytics but was primarily focused on customer success and 1
relationship management. I gained a breadth of knowledge in 2
investments and the use of proprietary software to 3
streamline the operations of a company’s finance and 4
accounting teams. I spent my last year at Clearwater 5
developing a training program focused on providing new 6
hires with the technical skills to be successful in an 7
operations role. 8
Q. What is the Company requesting in this case? 9
A. The Company is requesting approval of its 10
2022-2023 Power Cost Adjustment (“PCA”) rates to become 11
effective June 1, 2022. If approved, the 2022-2023 PCA 12
will result in an increase in total billed revenue of 13
approximately $103.4 million, or 8.27 percent. 14
Q. How is your testimony organized? 15
A. My testimony consists of four sections. In the 16
first section, I provide an overview of the PCA. In the 17
second section, I detail the 2022-2023 PCA amount in 18
comparison to last year’s PCA amount, identify and discuss 19
the main factors contributing to this change, and present 20
the quantification of the 2022-2023 PCA rates to become 21
effective June 1, 2022. In the third section, I discuss 22
the additional PCA component related to revenue sharing. In 23
the final section, I detail the net customer impact of the 24
2022-2023 PCA rates if approved as filed. 25

BRADY, DI 3
Idaho Power Company
I. PCA OVERVIEW 1
Q. What is the purpose of the PCA? 2
A. The PCA is a rate mechanism that quantifies 3
and tracks annual differences between actual Net Power 4
Supply Expenses (“NPSE”) and the normalized or “base level” 5
of NPSE recovered in the Company’s base rates, resulting in 6
a credit or surcharge that is updated annually on June 1. 7
The PCA mechanism uses a 12-month test period of April 8
through March (“PCA Year”) and includes a forecast 9
component and a Balancing Adjustment, formerly referred to 10
as the “true-up” and the “true-up of the true-up”. The 11
forecast component represents the difference between the 12
Company’s NPSE forecast from the March Operating Plan and 13
base level NPSE recovered in the Company’s base rates. The 14
Balancing Adjustment includes a backward-looking tracking 15
of differences between the prior PCA Year’s forecast and 16
actual NPSE incurred by the Company, and also tracks the 17
collection of the prior year’s Balancing Adjustment. 18
Q. Is the Balancing Adjustment new to this PCA 19
filing? 20
A. Yes. In Order No. 352901, the Idaho Public 21
Utilities Commission (“Commission”) approved a modification 22

1 In the Matter of the Application of Idaho Power Company for
Modification of the Power Cost Adjustment Mechanism, Case No. IPC-E-21-
38, Order No. 35290 (January 10, 2022).

BRADY, DI 4
Idaho Power Company
to the PCA filing to replace the “true-up” and “true-up of 1
the true-up” with a single Balancing Account. The two 2
“true-up” rates previously included in PCA filings are now 3
combined into one “Balancing Adjustment” rate. It should be 4
noted that this modification solely impacts the presentment 5
of the PCA but has no material impact on the rates charged 6
to customers. 7
Q. How does the PCA mechanism function? 8
A. With the exception of Public Utility 9
Regulatory Policies Act of 1978 (“PURPA”) expenses and 10
demand response incentive payments, the PCA allows the 11
Company to pass through to customers 95 percent of the 12
annual differences in actual NPSE as compared with base 13
level NPSE, whether positive or negative. With respect to 14
PURPA expenses and demand response incentive payments, as 15
actual annual expenses deviate from base level NPSE, the 16
Company is allowed to pass 100 percent of the difference 17
for recovery or credit through the PCA. The PCA is also 18
the rate mechanism used by the Company to provide customer 19
benefits resulting from the revenue sharing mechanism 20
approved by the Commission in Order No. 34071. 21
Q. Does the revenue collected from customers 22
through the annual PCA rate contribute toward the Company’s 23
earnings? 24

BRADY, DI 5
Idaho Power Company
A. No. The PCA mechanism provides for the annual 1
collection or refund of net power supply cost differences 2
between actual costs incurred by the Company and the base 3
level NPSE component of base rates. Aside from the 95 4
percent to 5 percent sharing component I just described, 5
the PCA provides for a one-for-one collection or refund of 6
actual net power supply expenses incurred, or to be 7
incurred, to provide safe, reliable electric service to 8
customers. 9
Q. What are the components of the PCA base level 10
NPSE? 11
A. The PCA base level NPSE includes the following 12
Federal Energy Regulatory Commission (“FERC”) accounts: 13
Account 501, Fuel (coal); Account 536, Water for Power; 14
Account 547, Fuel (gas); Account 555, Purchased Power; 15
Account 565, Transmission of Electricity by Others; and 16
Account 447, Sales for Resale (typically referred to as 17
surplus sales). 18
The PCA base level expense component for FERC 19
Account 555 includes costs of both PURPA and non-PURPA 20
(market) purchases. Per Order No. 32426, the Company 21
adjusts FERC Account 555 to also include demand response 22
incentive payments that the Company provides to customers 23
who participate in any of its three demand response 24
programs. 25

BRADY, DI 6
Idaho Power Company
II. 2022-2023 PCA 1
Q. What is the total PCA collection that would 2
result under the 2022-2023 PCA rates proposed by the 3
Company in this case? 4
A. The 2022-2023 PCA rates would result in total 5
PCA collection of $216.9 million. This represents an 6
increase in total billed revenue of $103.4 million for the 7
upcoming year, an increase of 8.27 percent. 8
Q. Have you prepared a table that details the 9
$103.4 million revenue impact by component? 10
A. Yes. Table 1 presents a separation of the 11
$103.4 million increase into each component included in the 12
Company’s proposed rates. 13
Table 1 Revenue Impact by Component

Line No. Rate Component 2021-2022 PCA 2022-2023 PCA Difference
1 PCA Forecast $ 131,825,063 $ 178,795,145 $ 46,970,081
2 PCA Balancing Adjustment $ (18,320,281) $ 38,664,487 $ 56,984,768
3 PCA Total $ 113,504,783 $ 217,459,632 $ 103,954,849
4 Revenue Sharing $ 0 $ (568,771) $ (568,771)
4 Total Revenue Impact $ 113,504,783 $ 216,890,861 $ 103,386,078
14
Q. What are the main factors driving the revenue 15
change requested in this case? 16
A. The increase in this year’s PCA is attributed 17
to an increase in both the forecast component and the 18
Balancing Adjustment. The increase in this year’s forecast 19
component is attributed to lower expected hydro generation, 20

BRADY, DI 7
Idaho Power Company
higher market energy prices, and higher natural gas prices, 1
which will be discussed in detail later in this testimony. 2
This year’s PCA Balancing Adjustment is 3
approximately $38.7 million, which is $57.0 million higher 4
than last year’s Balancing Adjustment, which was a credit 5
of $18.3 million. This year’s Balancing Adjustment 6
demonstrates that actual power supply costs for the 2021-7
2022 PCA Year were higher than the forecast power supply 8
costs included in last year’s PCA forecast. 9
A. PCA Forecast. 10
Q. How is the PCA forecast amount determined? 11
A. As described previously, the PCA forecast 12
component represents the difference between the Company’s 13
forecast of NPSE for the upcoming April – March test year 14
and base level NPSE recovered in the Company’s base rates. 15
Q. What is the Company’s determination of the 16
system-level difference between currently approved base 17
level NPSE2 and the forecast of NPSE for the 2022-2023 PCA 18
Year? 19
A. The system-level forecast of NPSE for the 20
2022-2023 PCA Year is $498,834,556, which is $193,149,687 21
higher than the currently approved base level NPSE of 22
$305,684,869. Table 2 presents the system-level 23

2 In the Matter of the Application of Idaho Power Company for
Authority to Establish a New Base Level of Net Power Supply Expense,
Case No. IPC-E-13-20, Order No. 33000 (March 21, 2014).

BRADY, DI 8
Idaho Power Company
differences between currently approved base level NPSE and 1
the forecast of NPSE for the 2022-2023 PCA Year by FERC 2
account. 3
Table 2 2022 - 2023 PCA FORECAST (Total System)

Line No. FERC Account Base NPSE Forecast Difference
95% Sharing Accounts
1 Account 501, Coal $ 108,503,180 $ 151,179,160 $ 42,675,980
2 Account 536, Water for Power $ 2,380,597 $ 0 $ (2,380,597)
3 Account 547, Other Fuel $ 33,367,563 $ 86,983,566 $ 53,616,003
4 Account 555, Purchased Power Non-PURPA $ 62,606,593 $ 99,906,480 $ 37,299,887
5 Account 565, 3rd Party Transmission $ 5,455,955 $ 5,149,239 $ (306,716)
6 Account 447, Surplus Sales $ (51,735,153) $ (65,085,848) $ (13,350,695)
$ 160,578,735 $ 278,132,598 $ 117,553,863

100% Sharing Accounts
7 Account 555, PURPA $ 133,853,869 $ 212,586,058 $ 78,732,189
8 Account 555, Demand Response Incentives $ 11,252,265 $ 8,115,900 $ (3,136,365)
9 Total $ 305,684,869 $ 498,834,556 $ 193,149,687
4
Q. What is the basis for the forecast of NPSE for 5
the 2022-2023 PCA Year? 6
A. The forecast of NPSE for the 2022-2023 PCA 7
Year is based on the Company’s March 31, 2022, Operating 8
Plan. 9
Q. How is the NPSE forecast developed for the 10
Company’s Operating Plan? 11
A. The Operating Plan is prepared monthly and 12
represents a forecast of the Company’s monthly NPSE for the 13
following 18-month period; however, for the PCA, the 14
Company includes only the 12 months that correspond to the 15

BRADY, DI 9
Idaho Power Company
PCA Year. The Operating Plan is developed by simulating 1
the dispatch of the Company’s generation resources for each 2
month, segmented by heavy load and light load hours. The 3
dispatch considers a current forecast of forward market 4
energy prices, available hydro generation, coal and natural 5
gas prices, and any existing hedge transactions. The 6
system load forecast is then analyzed against the resulting 7
monthly heavy load and light load dispatch to determine a 8
monthly load and resource balance. Any identified resource 9
deficiency is assumed to be filled with market energy 10
purchases or natural gas to fuel the Langley Gulch power 11
plant (“Langley Gulch”), based on economics and available 12
generating capacity at Langley Gulch. Economically 13
dispatched generation above the system load forecast 14
represents surplus energy sales. The forecast of monthly 15
NPSE and generation for the 2022-2023 PCA Year, as 16
determined in the Company’s March 31, 2022, Operating Plan, 17
is provided in Exhibit No. 1. 18
Q. Please explain how the Company modeled Bridger 19
Units 1 and 2 in the March 31, 2022 Operating Plan, in 20
light of the ongoing Bridger Regional Haze compliance 21
discussions. 22
A. In light of ongoing discussions with the U.S. 23
Environmental Protection Agency regarding the Wyoming 24
Regional Haze State Implementation Plan (“SIP”), Idaho 25

BRADY, DI 10
Idaho Power Company
Power adjusted the availability of Bridger Units 1 and 2 1
within the March Operating Plan. Specifically, the Company 2
modeled Bridger Unit 2 to be available for dispatch at a 25 3
percent level from June – October 2022 to reflect ongoing 4
uncertainty related to these discussions. For the remaining 5
months within the PCA year, Unit 2 is modeled at 6
availability levels that meet the overall plant emissions 7
limits and annual emissions cap as required per the revised 8
SIP. Bridger Unit 1 operations were modeled as available 9
for dispatch at the revised approved SIP levels for the 10
entire 2022-2023 PCA year. 11
Q. How does the Company’s forecast of system-12
level NPSE for the 2022-2023 PCA compare to the system-13
level forecast included in last year’s PCA? 14
A. Table 3 below compares this year’s 2022-2023 15
PCA forecast of NPSE to last year’s PCA forecast by FERC 16
account. As detailed in this table, the PCA forecast on a 17
total system basis for the 2022-2023 PCA Year is 18
$498,834,556, which is $56,477,149 higher than last year’s 19
forecast amount of $442,357,407. 20
21
22
23
24
25
26

BRADY, DI 11
Idaho Power Company
1
Table 3 PCA Forecast Comparison Expenses (Total System)

Line No. FERC Account
2021-2022
Forecast
2022-2023
Forecast Difference
95% Sharing Accounts
1 Account 501, Coal $ 118,562,796 $ 151,179,160 $ 32,616,365
2 Account 536, Water for Power $ 0 $ 0 $ 0
3 Account 547, Other Fuel $ 57,235,044 $ 86,983,566 $ 29,748,522
4 Account 555, Purchased Power Non-PURPA $ 74,800,530 $ 99,906,480 $ 25,105,950
5 Account 565, 3rd Party Transmission $ 4,853,909 $ 5,149,239 $ 295,331
6 Account 447, Surplus Sales $ (25,842,225) $ (65,085,848) $ (39,243,623)
$ 229,610,054 $ 278,132,598 $ 48,522,544

100% Sharing Accounts
7 Account 555, PURPA $ 205,133,741 $ 212,586,058 $ 7,452,317
8 Account 555, Demand Response Incentives $ 7,613,612 $ 8,115,900 $ 502,288
$ 212,747,353 $ 220,701,958 $ 7,954,605

9 Total PCA Forecast $ 442,357,407 $ 498,834,556 $ 56,477,149
2
Q. What general conclusions can be drawn from the 3
information contained in Table 3? 4
A. When viewed by category, the 95 percent 5
sharing accounts have increased approximately $48.5 million 6
from last year’s forecast, while the 100 percent sharing 7
accounts have increased approximately $8.0 million over 8
last year’s forecast. 9
Q. What factors are contributing to the major 10
differences presented in Table 3? 11
A. Forecast expenses included in the 95 percent 12
sharing accounts are expected to increase by 21 percent as 13
compared to last year, from $229,610,054 to $278,132,598. 14

BRADY, DI 12
Idaho Power Company
Due to a reduction in forecast hydro generation, higher 1
forecast market energy prices, and higher forecast natural 2
gas prices, the Company expects to rely more on coal 3
generation to serve load and is expected to increase off-4
system surplus sales. 5
Q. Please elaborate on the changes in the 95 6
percent sharing accounts for this year’s forecast as 7
compared with last year’s forecast. 8
A. In addition to lower forecast hydro 9
generation, which will be discussed in detail later in 10
testimony, higher forecast market energy prices and natural 11
gas prices are contributing to increased generation at the 12
Company’s coal plants, as well as increased off-system 13
surplus sales. 14
For the 2022-2023 PCA Year, the average forecast 15
market purchase price is $49.11 per megawatt-hour (“MWh”), 16
compared to $27.34 per MWh last year, an increase of 80 17
percent. In addition, the per-unit cost of natural gas for 18
the 2022-2023 PCA Year is $34.03 per MWh, an increase of 39 19
percent compared to last year. As a result of higher market 20
energy prices and natural gas prices, coal generation 21
becomes more economic. The average per-unit cost of coal-22
fired generation is $29.74 per MWh, which is a 10 percent 23
decrease from last year. Accordingly, expenses from market 24
purchases are expected to increase 91 percent as compared 25

BRADY, DI 13
Idaho Power Company
to last year’s forecast, natural gas expense is expected to 1
increase 52 percent, and coal fuel expense is expected to 2
increase 28 percent. 3
The increase in forecast market energy prices is 4
also resulting in higher surplus sales revenue. Surplus 5
sales revenue is expected to increase 152 percent compared 6
to last year, from $25,842,225 to $65,085,848. For the 7
2022-2023 PCA Year, the average forecast market sales price 8
is $51.73 per MWh compared with $34.23 last year, a 51 9
percent increase. 10
Q. What factors are contributing to the change in 11
the 100 percent sharing accounts? 12
A. Forecast expenses included in the 100 percent 13
sharing accounts are expected to increase by 4 percent as 14
compared to last year, from $212,747,353 to $220,701,958. 15
Forecast PURPA costs increased by $7.45 million as compared 16
to last year’s forecast and forecast demand response 17
incentive payments increased by $0.5 million as compared to 18
last year. 19
Q. Is the increase in forecast PURPA costs 20
related to increased generation output from PURPA projects? 21
A. In part. Table 4 details changes between last 22
year’s PCA forecast and this year’s PCA forecast with 23
respect to forecasted generation in MWh. As shown in Table 24
4, PURPA generation is anticipated to increase by 10,708 25

BRADY, DI 14
Idaho Power Company
MWh, or less than 1 percent. The 4 percent increase in 1
PURPA expense is largely the result of price escalation in 2
PURPA contracts, for which the average cost is $69.96 per 3
MWh, compared to $67.75 last year. 4
Table 4 PCA Forecast Comparison Generation (Total System-MWh)

Line No. FERC Account 2021-2022 Forecast
2022-2023
Forecast Difference
1 Hydro 6,690,890 5,972,743 (718,147)

95% Sharing Accounts
2 Account 501, Coal 3,599,219 5,083,043 1,483,825
3 Account 547, Other Fuel 2,340,994 2,556,322 215,328
4 Account 555, Purchased Power Non-PURPA 1,478,696 1,580,326 101,630
95% Sharing Accounts 14,109,799 15,192,435 1,082,636

100% Sharing Accounts
5 Account 555, PURPA 3,027,905 3,038,613 10,708
100% Accounts 3,027,905 3,038,613 10,708

6 Total Generation 17,137,704 18,231,048 1,093,344

95% Sharing Accounts
7 Account 447, Surplus Sales 754,975 1,258,195 503,220
8 Total Load 16,382,729 16,972,853 590,124
5
Q. What other general conclusions can be drawn 6
from the information in Table 4? 7
A. Compared to last year’s forecast, hydro 8
generation is expected to decrease 718,147 MWh, or 11 9
percent. The decrease in hydro generation, combined with an 10
increase in market energy prices and natural gas prices, is 11
driving an increase in coal-fired generation and surplus-12
sales. Coal-fired generation is projected to increase 13
1,483,825 MWh compared to last year, or 41 percent and 14

BRADY, DI 15
Idaho Power Company
surplus-sales volumes are expected to increase 503,220 MWh, 1
or 67 percent. 2
Q. What is causing the decrease in expected hydro 3
generation of 718,147 MWh? 4
A. The decrease in expected hydro generation is 5
mainly due to lower projected inflows into Brownlee 6
reservoir. The March Operating Plan used in this year’s 7
PCA forecast projects April through July inflows into 8
Brownlee of 2.9 million acre-feet (“MAF”) as compared to 9
4.2 MAF used to determine last year’s PCA forecast, a 10
decrease of 31 percent. Expected inflows into Brownlee 11
were higher for last year’s PCA forecast as a result of 12
better snowpack conditions, which provide for sustained 13
runoff and increased hydro generation during the spring and 14
summer months. 15
Additionally, this year’s PCA forecast reflects 16
weaker reservoir storage conditions, as compared to last 17
year’s forecast. The March Operating Plan used in this 18
year’s PCA demonstrates that available storage in the 11 19
reservoirs above Brownlee is 76 percent of normal and at 51 20
percent of capacity, compared to last year’s 2021 March 21
Operating Plan, in which storage was 113 percent of normal 22
and at 75 percent of capacity. Together weaker snowpack 23
conditions and carryover as compared to the prior year are 24

BRADY, DI 16
Idaho Power Company
resulting in the 11 percent reduction in forecast hydro 1
generation for the 2022–2023 PCA Year. 2
Q. How are the forecasted NPSE differences 3
presented in Table 2 used to determine the 2022-2023 PCA 4
forecast component to be collected from Idaho customers? 5
A. The 2022-2023 PCA forecast component reflects 6
the Idaho jurisdictional share of the forecasted NPSE 7
differences presented in Table 2, adjusted for the PCA 8
sharing provisions. The Idaho jurisdictional share of the 9
forecast NPSE differences is determined by applying a ratio 10
of forecast firm Idaho jurisdictional sales to forecast 11
firm system-level sales to the system-level NPSE 12
differences. 13
Q. What is the Company’s forecast of system-level 14
firm sales and Idaho jurisdictional firm sales for the 15
2022-2023 PCA Year? 16
A. For the 2022-2023 PCA Year, Idaho Power has 17
forecast system-level firm sales to be 15,690,546 MWh and 18
Idaho jurisdictional firm sales to be 14,992,046 MWh, or 19
95.55 percent of the system level. 20
Q. What is the Company’s determination of the 21
2022-2023 PCA forecast component to be collected from Idaho 22
customers? 23
A. The 2022-2023 PCA forecast component to be 24
collected from Idaho customers is $178,795,544. Table 5 25

BRADY, DI 17
Idaho Power Company
presents the determination of the 2022-2023 PCA forecast 1
component by individual PCA expense and revenue category. 2
3
Table 5 2022-2023 PCA FORECAST

Line No. FERC Account Difference from Base
Difference After
Sharing Idaho Allocation
95% Sharing Accounts (From Table 1)
1 Account 501, Coal $ 42,675,980 $ 40,542,181 $ 38,737,356
2 Account 536, Water for Power $ (2,380,597) $ (2,261,567) $ (2,160,888)
3 Account 547, Other Fuel $ 53,616,003 $ 50,935,202 $ 48,667,709
4 Account 555, Purchased Power Non-PURPA $ 37,299,887 $ 35,434,893 $ 33,857,430
5 Account 565, 3rd Party Transmission $ (306,716) $ (291,380) $ (278,408)
6 Account 447, Surplus Sales $ (13,350,695) $ (12,683,160) $ (12,118,541)
$ 117,553,863 $ 111,676,170 $ 106,704,658

100% Sharing Accounts
7 Account 555, PURPA $ 78,732,189 $ 78,732,189 $ 75,227,251
8 Account 555, Demand Response Incentives $ (3,136,365) $ (3,136,365) $ (3,136,365)
9 Total $ 193,149,687 $ 187,271,994 $ 178,795,544
4
B. Balancing Adjustment. 5
Q. What is this year’s quantification of the 6
Balancing Adjustment? 7
A. The Balancing Adjustment is detailed in the 8
PCA deferral report, attached hereto as Exhibit No. 2. This 9
report compares actual NPSE amounts to actual power cost 10
collections monthly, with the differences accumulated as a 11
deferral balance. The balance at the end of March 2022, 12
with interest applied, was $38,669,525 as shown on row 100 13
of Exhibit No. 2. The approximate $38.7 million represents 14

BRADY, DI 18
Idaho Power Company
an increase to customer rates in this year’s PCA Balancing 1
Adjustment. 2
Q. To what factors do you attribute the 3
accumulation of the approximate $38.7 million deferral 4
balance? 5
A. The approximate $38.7 million deferral balance 6
was primarily driven by a decrease in actual hydro 7
generation from expected as well as higher than forecast 8
market purchases, offset by higher surplus sales. 9
Actual hydro generation for the 2021-2022 PCA year 10
totaled 5,268,002 MWh, a 21 percent decrease from last 11
year’s forecast of 6,690,890 MWh. Actual purchased power 12
totaled 4,079,834 MWh, a 176 percent increase from last 13
year’s forecast. Actual surplus sales volumes totaled 14
1,373,630 MWh, an increase of 82 percent from 754,975 MWh. 15
Actual natural gas prices were also higher than 16
forecast, driving a 55 percent increase in natural gas fuel 17
expense. Although natural gas prices were higher than 18
forecast, the Company’s reliance on natural gas generation 19
did not decrease as it was needed to serve load due to 20
lower than expected hydro generation and higher than 21
expected temperatures during the 2021 summer season. 22
Q. Please elaborate on the changes in actual 23
versus forecast generation and expense for the 2021-2022 24
PCA Year. 25

BRADY, DI 19
Idaho Power Company
A. Last year’s PCA forecast included an average 1
market sales price of $34.23 per MWh. The actual average 2
market sales price for the 2021-2022 PCA year was $57.70 3
per MWh, a 69 percent increase. As a result of the 4
difference in forecast and actual market sales prices, as 5
well as economic opportunity during the spring and winter 6
months of the 2021-2022 PCA year, actual surplus sales 7
volumes were 82 percent higher than forecast. Surplus sales 8
revenue totaled $79,257,653, which was 207 percent higher 9
than forecast revenues of $25,842,225. 10
Coal-fired generation totaled 3,241,970 MWh, which 11
was 10 percent lower than forecast, and actual coal fuel 12
expense was $104.5 million, 12 percent lower than forecast. 13
Coal-fired generation was lower than forecast due to the 14
increase in market energy purchases and increase in natural 15
gas generation. 16
Natural gas generation totaled 2,719,869 MWh for the 17
2021-2022 PCA Year, which was 378,875 MWh, or 16 percent, 18
higher than forecast. Due to natural gas prices being 19
higher than expected, actual natural gas expense totaled 20
$88,941,596, which was 55 percent higher than forecast. 21
While natural gas prices were higher than forecast, the 22
Company’s reliance on natural gas generation increased 16 23
percent as it was needed to meet load, as well as make off-24
system sales when it was economic, as noted previously. 25

BRADY, DI 20
Idaho Power Company
While both purchased power and surplus sales 1
increased, surplus sale volumes were highest in off-peak 2
spring and winter months, and purchased power was highest 3
in summer months, where hot temperatures caused 4
continuously higher than forecast peak loads. 5
Q. Were there any items included in this year’s 6
Balancing Adjustment in addition to actual NPSE incurred 7
during the April 2021 through March 2022 period? 8
A. Yes. Per Commission Order No. 34100, Idaho 9
Power included its actual costs of Western Energy Imbalance 10
Market (“EIM”) participation for April 2021 through March 11
2022 in the Balancing Adjustment. Benefits associated with 12
EIM participation are embedded in actual NPSE experienced 13
over that same period. 14
Q. Please summarize the conditions of Order No. 15
34100 as they pertain to EIM cost recovery through the 2021 16
PCA. 17
A. Per the terms of the settlement stipulation 18
(“EIM Stipulation”) approved by Order No. 34100, Idaho 19
Power agreed to include an EIM-related monthly revenue 20
requirement in its monthly PCA deferral calculation based 21
on actual EIM participation costs commencing April 1, 2018. 22
The Company also agreed to apply a soft cap to EIM-related 23
revenue requirement included in the PCA deferral equal to 24
annual EIM benefits as reported by the California 25

BRADY, DI 21
Idaho Power Company
Independent System Operator (“CAISO”) for the corresponding 1
period. 2
Q. Is the EIM-related revenue requirement 3
included in the April 2021 through March 2022 PCA deferral 4
under the soft cap of annual CAISO-reported benefits for 5
that same period? 6
A. Yes. For the April 2021 through March 2022 7
period, the EIM-related revenue requirement totaled $2.9 8
million, while CAISO reported EIM benefits for Idaho Power 9
of approximately $40 million from April through December 10
(CAISO’s first quarter 2022 report has not yet been 11
published). Therefore, the Company’s EIM-related revenue 12
requirement is less than the soft cap agreed to in the EIM 13
Stipulation. 14
Q. Does Idaho Power believe the EIM has provided 15
net benefits to customers since joining in April 2018? 16
A. Yes. While Idaho Power believes the CAISO 17
benefit calculation overstates estimated benefits to Idaho 18
Power’s system, the Company believes customers have 19
realized significant net benefits since the Company’s entry 20
into the EIM in April 2018. As discussed in the Company’s 21
May 24, 2019, Report of EIM Benefits and Costs of 22
Participation, filed in Case No. IPC-E-16-19, Idaho Power 23
has developed a more precise methodology for determining 24
EIM benefits that uses inputs specific to the Company. 25

BRADY, DI 22
Idaho Power Company
Based on this methodology, the Company believes benefits 1
achieved between April 2021 and December 2021 are 2
approximately $16 million (benefits for the first quarter 3
of 2022 are not yet available). This level of EIM benefits 4
compared to the Idaho-jurisdictional EIM costs of $2.9 5
million, demonstrates a net benefit to the Company and, 6
ultimately, its customers. 7
C. PCA Rate Determination. 8
Q. How is the rate for the forecast portion of 9
the PCA for April 2022 through March 2023 determined? 10
A. The rate for the forecast portion of the PCA 11
is equal to the sum of (1) 95 percent of the difference 12
between the non-PURPA expenses quantified in the Operating 13
Plan and those quantified in the Company’s last approved 14
update of NPSE, divided by the Company’s forecast of system 15
firm sales for June 1, 2022, through May 31, 2023 (“System-16
level Sales Forecast”); and (2) 100 percent of the 17
difference between PURPA-related expenses quantified in the 18
Operating Plan and those quantified in the Company’s last 19
approved update of NPSE, divided by the Company’s System-20
level Sales Forecast; and (3) 100 percent of the difference 21
between the Idaho jurisdictional demand response incentive 22
payments quantified in the Operating Plan and those 23
quantified in the Company’s last approved update of NPSE, 24

BRADY, DI 23
Idaho Power Company
divided by the forecast of Idaho jurisdictional firm sales 1
for June 1, 2022, through May 31, 2023. 2
Q. What is the rate for the forecast portion of 3
the PCA for April 2022 through March 2023? 4
A. The rate for non-PURPA expenses is 0.7117 5
cents per kilowatt-hour (“kWh”), which is calculated by 6
multiplying $117,553,863 from Table 2 by 95 percent and 7
then dividing it by the System-level Sales Forecast of 8
15,690,546 MWh (($117,553,863 * 0.95) / 15,690,546) = 9
$7.117 /MWh = 0.7117 cents/kWh). The rate for PURPA 10
expenses is 0.5018 cents per kWh, which is calculated by 11
dividing $78,732,189 from Table 2 by the 15,690,546 MWh 12
($78,732,189 / 15,690,546 MWh = $5.018/MWh = 0.5018 13
cents/kWh). The rate for demand response incentive 14
payments is a negative 0.0209 cents per kWh, which is 15
calculated by dividing the negative $3,136,365 from Table 2 16
by the forecast of Idaho jurisdictional firm sales of 17
14,992,046 MWh (-$3,136,365 / 14,992,046 MWh = -$0.209/MWh 18
= -0.0209 cents/kWh). The forecast portion of the PCA rate 19
is 1.1926 cents per kWh, which is calculated by adding the 20
non-PURPA expense of 0.7117 cents per kWh to the PURPA 21
expense of 0.5018 cents per kWh to the demand response 22
incentive payment of negative 0.0209 cents per kWh (0. 7117 23
+ 0.5018 + -0.0209 = 1.1926 cents/kWh). 24

BRADY, DI 24
Idaho Power Company
Q. How did you compute this year’s Balancing 1
Account rate? 2
A. As shown in Exhibit No. 2, this year’s 3
Balancing Adjustment of the PCA is approximately $38.7 4
million, which, when divided by the Company’s forecast of 5
Idaho jurisdictional sales of 14,992,046 MWh, results in a 6
rate of 0.2579 cents per kWh ($38,669,526 / 14,992,046 = 7
$2.579/MWh = 0.2579 cents/kWh). 8
Q. What is the resulting PCA rate when you 9
combine all the PCA components described previously? 10
A. The uniform PCA rate comprises (1) the 1.1926 11
cents per kWh for the 2022-2023 projected power cost of 12
serving firm loads under the current PCA methodology and 95 13
percent sharing, and (2) the 0.2579 cents per kWh for the 14
2021-2022 Balancing Adjustment of the PCA. The sum of these 15
two components is a 1.4505 cents per kWh charge for all 16
rate classes. 17
III. ADDITIONAL PCA RATE ADJUSTMENTS 18
A. Revenue Sharing. 19
Q. When was the revenue sharing mechanism 20
originally established? 21
A. The revenue sharing mechanism was originally 22
established in Case No. IPC-E-09-30 and approved in Order 23
No. 30978, effective for the years 2009-2011. Since then, 24
the revenue sharing mechanism has been modified and 25

BRADY, DI 25
Idaho Power Company
extended three times.3 Most recently, the revenue sharing 1
mechanism was extended indefinitely, with modifications, in 2
Order No. 34071 in Case No. GNR-U-18-01. 3
Q. What are the provisions of the current revenue 4
sharing mechanism? 5
A. In Case No. GNR-U-18-01, the Company filed a 6
motion to approve a settlement stipulation (“2018 7
Stipulation”) extending the sharing mechanism indefinitely, 8
with modifications. The Commission approved the 2018 9
Stipulation in Order No. 34071. 10
Per the terms of the 2018 Stipulation, if the 11
Company’s actual year-end Return on Equity (“ROE”) for the 12
Idaho jurisdiction exceeds 10 percent, all amounts up to 13
and including a 10.5 percent ROE will be shared between 14
customers and the Company on an 80 percent and 20 percent 15
basis, respectively, to be provided as a rate reduction to 16
become effective at the time of the subsequent year’s PCA. 17
If the Company’s Idaho jurisdictional ROE exceeds 10.5 18
percent, all amounts in excess of 10.5 percent will be 19
shared 55 percent with Idaho customers as a rate reduction 20
to become effective with the subsequent year’s PCA, 25 21
percent will be shared with Idaho customers in the form of 22
an offset to amounts in the Company’s pension balancing 23
account, and 20 percent will be apportioned to the Company. 24

3 Order Nos. 32424, 33149 and 34071.

BRADY, DI 26
Idaho Power Company
With regard to the amortization of Accumulated 1
Deferred Investment Tax Credits (“ADITC”), the 2018 2
Stipulation allows the Company to accelerate the 3
amortization of ADITC, in an amount up to $45 million, to 4
achieve a maximum 9.4 percent Idaho jurisdictional ROE if 5
the Company’s year-end actual results fall below that 6
amount for any year beginning January 1, 2020. Idaho Power 7
may use up to $25 million of additional amortization of 8
ADITC per year, provided the total, cumulative amount of 9
ADITC does not exceed $45 million. Per the 2018 10
Stipulation, once the Company has fully amortized the $45 11
million of ADITC, revenue sharing will cease; however, 12
Idaho Power may at any time request to replenish the total 13
amount of ADITC it is permitted to amortize, and if 14
approved by the Commission, revenue sharing would continue. 15
Q. Did the revenue sharing mechanism result in 16
any action following the 2009-2020 fiscal years? 17
A. Yes. The Company’s earnings in each year from 18
2011 through 2015, as well as 2018, resulted in revenue 19
sharing with customers totaling $126.2 million, either as a 20
direct rate offset in the PCA or as an offset to amounts 21
that would have otherwise been collected in rates. The 22
Company’s earnings in 2016, 2017, 2019, and 2020 were below 23
the revenue sharing threshold. These amounts are detailed 24
in Table 6 below. 25

BRADY, DI 27
Idaho Power Company
Table 6 2009-2020 Revenue Sharing

Line No. Revenue Sharing Component 2009-2011 2012-2014 2015-2020
1 Available ADITC For Use $45 Million $45 Million $45 Million
2 ROE Threshold 9.5% 9.5% 10.0%
3 50-50 Sharing Threshold 10.5% 10.0% N/A
4 75-25 Sharing Threshold N/A 10.5% 10.0%
5 Customer Benefits ($ Millions):
6 Reduction to Rates $27.1 $22.8 $8.2 Total
7 Offset to Pension Balancing Account $20.3 $47.8 $0.0 2009-2020
8 Total $47.4 $70.6 $8.2 $126.2
1
Q. Did the Company’s year-end 2021 financial 2
results warrant any action related to the existing sharing 3
agreement per the terms of the 2018 Stipulation? 4
A. Yes. The Company’s year-end 2021 financial 5
results yielded an actual Idaho jurisdictional ROE of 10.02 6
percent, above the 10 percent ROE threshold for revenue 7
sharing, and thus resulting in a revenue amount to be 8
shared with customers after tax gross-up of $568,771. 9
Q. Did the Company use the same methodology to 10
determine the Idaho jurisdictional 2021 year-end ROE that 11
was used in prior PCA filings? 12
A. Yes. The methodology used to determine the 13
Company’s Idaho jurisdictional 2021 year-end ROE is 14
consistent with the methodology used for the year-end ROE 15
determinations since the inception of the mechanism. 16
Q. Do you have an exhibit demonstrating the 17
application of this methodology? 18

BRADY, DI 28
Idaho Power Company
A. Yes. Exhibit No. 3 provides a step-by-step 1
calculation of the Idaho jurisdictional ROE based on year-2
end 2021 financial results utilizing the Commission-3
approved methodology from previous PCA filings. 4
Q. What is the revenue sharing amount to be 5
included in the 2022-2023 PCA? 6
A. As detailed in Exhibit No. 3, the 2021 Idaho 7
jurisdictional ROE was 10.02 percent. As quantified on line 8
63 of Exhibit No. 3, in 2021, the Company’s earnings 9
exceeded an Idaho jurisdictional ROE of 10 percent by 10
$527,962. Per the terms of the 2018 Stipulation, 80 percent 11
of the $527,962 should be shared with customers as a direct 12
reduction to PCA rates effective June 1, 2022. Applying the 13
80 percent sharing provision to the $527,962 yields a 14
customer-allocated sharing amount of $422,369. After tax 15
gross-up, the revenue sharing amount to be applied to 16
customer bills is $568,771. 17
Q. How does the Company propose to allocate the 18
$568,771 revenue sharing to customer classes? 19
A. The Company proposes to allocate the revenue 20
sharing benefit to customer classes utilizing the same 21
methodology as in past cases, i.e., based on each class’s 22
proportional share of forecasted base rate revenues for the 23
upcoming PCA rate effective year, which in this case is 24
June 1, 2022, through May 31, 2023. 25

BRADY, DI 29
Idaho Power Company
Q. Have you provided an exhibit detailing the 1
class allocation utilizing this methodology? 2
A. Yes. Exhibit No. 4 details the class 3
allocation of the $568,771 revenue sharing benefit. As 4
displayed in column G of Exhibit No. 4, each customer class 5
receives a decrease of approximately 0.05 percent relative 6
to current base revenues. 7
Q. How does the Company propose to include the 8
class-allocated revenue sharing benefits in rates? 9
A. Except for the special contracts for Micron 10
Technology, Inc., the U.S. Department of Energy, and the 11
J.R. Simplot Company – Pocatello, Idaho Power proposes to 12
include the class-allocated revenue sharing benefits on a 13
cents-per-kWh basis applied to the 2022 PCA rates effective 14
June 1, 2022, through May 31, 2023. Column F of Exhibit No. 15
4 contains the rates proposed for inclusion in each class’s 16
PCA rate. 17
Q. What is the Company’s proposal for providing 18
revenue sharing benefits to its special contract customers? 19
A. Consistent with the methodology used to share 20
2011-2015 and 2018 revenues, the Company proposes to 21
provide the special contract customers a flat dollar-per-22
month credit in 12 equal portions to serve as a reduction 23
to monthly invoices billed from June 2022 through May 2023. 24
The total revenue sharing benefit allocated to the special 25

BRADY, DI 30
Idaho Power Company
contract customers is displayed in column E of Exhibit No. 1
4. 2
Q. Is the Company’s rate design proposal for the 3
2022 revenue sharing benefits consistent with past-approved 4
proposals? 5
A. Yes. 6
IV. NET CUSTOMER IMPACT 7
Q. What is the revenue impact of the requested 8
PCA rate when compared with PCA rates currently in effect? 9
A. Attachment 2 to the Application filed 10
contemporaneously with my testimony provides a detailed 11
description of the overall revenue impact of this filing on 12
each customer class. As shown in Attachment 2, applying 13
the requested PCA rates to expected customer sales for the 14
June 2022 through May 2023 test year results in a PCA 15
increase of $103.4 million. 16
Q. Given the magnitude of the increase for the 17
2022-2023 PCA, did the Company consider proposing any rate 18
mitigation options? 19
A. Yes. Given the magnitude of the 2022-2023 PCA 20
increase, I consulted with management to determine what 21
mitigation, if any, the Company should include in this 22
year’s PCA filing. 23
Q. Following these discussions, is the Company 24
proposing to include any rate mitigation in this filing? 25

BRADY, DI 31
Idaho Power Company
A. No. After careful consideration, I was advised 1
by management to not propose any rate mitigation measures 2
in this case. However, the Company is open to rate 3
mitigation measures if the Commission deems them 4
appropriate. 5
Q. Why is the Company not proposing any rate 6
mitigation in this case? 7
A. First, the Company believes that customer 8
interests are generally best served by matching cost 9
recovery as closely as possible with the period in which 10
power supply costs are incurred. Additionally, mitigating 11
rate impacts by spreading recovery over multiple years 12
creates the possibility that the deferred collection will 13
result in “rate pancaking” with potential future rate 14
increases, essentially deferring an increase in the current 15
year to create an even larger increase in the future. The 16
Company also considered prior Commission orders with regard 17
to rate mitigation measures in the PCA. In orders from the 18
2008, 2009, 2013, and 2020 PCA cases4 in which rate 19
mitigation was discussed, the Commission declined to adopt 20
any rate mitigation measures, primarily for the same 21
concerns surrounding rate pancaking, appropriate matching 22
of costs and recovery, and the overall intent of the PCA 23
mechanism. 24

4 Order Nos. 30563, 30828, 32821, and 34682

BRADY, DI 32
Idaho Power Company
Q. Would Idaho Power be amenable to implementing 1
rate mitigation measures for the 2022-2023 PCA if the 2
Commission determines such measures are appropriate? 3
A. Yes. While both Idaho Power and the Commission 4
have expressed concerns with rate mitigation measures in 5
the past, the Company would be amenable to discussing such 6
measures in the current filing. A two-year recovery period, 7
for example, would reduce the rate impact from the proposed 8
$103.4 million, or 8.27 percent increase, to an approximate 9
$50 million, or slightly more than 4 percent, annual 10
increase in collection spread over two years. 11
Q. Have you prepared a revised Schedule 55 that 12
includes the proposed PCA rates? 13
A. Yes. Attachment 1 to the Application is a 14
revised Schedule 55 and includes the proposed PCA rates in 15
clean and legislative formats. 16
Q. Should the Commission approve the Company’s 17
computation of the PCA rates? 18
A. Yes. The Commission should approve the 19
Company’s computation of the PCA rates. The calculation of 20
the PCA rates follows the methodology that was approved in 21
Order Nos. 30715, 33307, and 34071. If approved, the 2022-22
2023 PCA will result in an increase in total billed revenue 23
of approximately $103.4 million, or 8.27 percent. 24
\\ 25

BRADY, DI 33
Idaho Power Company
Q. Does this conclude your testimony? 1
A. Yes, it does. 2
// 3
// 4
// 5
// 6
// 7
// 8
// 9
// 10
// 11
// 12
// 13
// 14
// 15
// 16
// 17
// 18
// 19
// 20
// 21
// 22
// 23
// 24
// 25

BRADY, DI 34
Idaho Power Company
DECLARATION OF JESSICA G. BRADY 1
I, Jessica G. Brady, declare under penalty of 2
perjury under the laws of the state of Idaho: 3
1. My name is Jessica G. Brady. I am employed 4
by Idaho Power Company as a Regulatory Analyst in the 5
Regulatory Affairs Department. 6
2. On behalf of Idaho Power, I present this 7
pre-filed direct testimony and Exhibit Nos. 1-4 in this 8
matter. 9
3. To the best of my knowledge, my pre-filed 10
direct testimony and exhibits are true and accurate. 11
I hereby declare that the above statement is true to 12
the best of my knowledge and belief, and that I understand 13
it is made for use as evidence before the Idaho Public 14
Utilities Commission and is subject to penalty for perjury. 15
SIGNED this 15th day of April 2022, at Boise, Idaho. 16
17
Signed: _________________________ 18
1
From:Gust, Stacy
Sent:Monday, April 18, 2022 8:11 AM
To:Jan Noriyuki
Cc:Nordstrom, Lisa; Aschenbrenner, Connie
Subject:RE: IPC-E-22-11 Application of Idaho Power Company for Authority to Implement Power
Cost Adjustment (PCA) Rates for Electric Service from June 1, 2022 through May 31,
2023
Attachments:BillInsert_PCA_04-22_Print.pdf
Ms. Noriyuki,

Please find attached the corrected Bill Insert that was sent out regarding the above matter. Could you please replace it
with the Bill Insert that was filed on Friday?

Thank you.

Stacy Gust
REGULATORY ADMINISTRATIVE ASSISTANT
Idaho Power | Regulatory Affairs
Office 208-388-5749

From: Gust, Stacy
Sent: Friday, April 15, 2022 4:07 PM
To: Jan Noriyuki <[e-mail]>
Cc: Nordstrom, Lisa <[e-mail]>
Subject: IPC-E-22-11 Application of Idaho Power Company for Authority to Implement Power Cost Adjustment (PCA)
Rates for Electric Service from June 1, 2022 through May 31, 2023

Ms. Noriyuki,

Please find attached for electronic filing, pursuant to Order No. 35058, Idaho Power Company’s 2022-2023 Power Cost
Adjustment (PCA) Application, the Direct Testimony of Jessica Brady, PCA Bill Insert, PCA Postcard, and PCA News
Release.

Also provided as a courtesy to Staff are the Excel workpapers.

If you have any questions regarding this filing, please do not hesitate to contact me.

Thank you.

Stacy Gust
REGULATORY ADMINISTRATIVE ASSISTANT
Idaho Power | Regulatory Affairs
Office 208-388-5749

Thank you for reading this notice. We value your business.
©2022 Idaho Power
Printed on recycled paper.
31180-I-0178
Oxbow Power PlantOxbow Power Plant
Opportunities for Public Review
Idaho Power’s proposal is subject to public review
and approval by the IPUC. Copies of the application
are available to the public at the IPUC offices (11331
W. Chinden Blvd. Building 8, Suite 201-A, Boise, ID
83714), Idaho Power offices, or at idahopower.com
or puc.idaho.gov. Customers also may subscribe to
the IPUC’s RSS feed to receive periodic updates via
email about the case. Written comments regarding
Idaho Power’s proposal may be filed with the IPUC.
Idaho Power Files Annual Power Cost Adjustment
Idaho Power has filed the final piece of its annual
spring cost adjustments with the Idaho Public Utilities
Commission (IPUC). This year’s Power Cost Adjustment
(PCA) calls for a price increase across all customer classes
as a result of higher power costs related to last summer’s
unprecedented heatwave and lower hydro generation
because of drought conditions.
Neither Idaho Power nor its shareholders receive any
financial return from this filing, which is a request for
$103.4 million. The money collected is used solely to
recover expenses associated with annual fluctuations in
power costs.
The overall impact to residential customer bills on June 1
depends on the outcome of three filings:
• The annual PCA, filed today, is a cost-recovery tool
that passes on both the benefits and costs of supplying
energy to Idaho Power customers. If the PCA proposal
is approved by the IPUC as filed, the typical Idaho
residential customer using 950 kilowatt-hours (kWh) of
energy per month will see a $6.54 increase on their bill
related to this request.
• The annual Fixed Cost Adjustment (FCA), filed in March
and applicable to only residential and small commercial
customers, adjusts prices based on changes in energy
use per customer during the previous year. If the FCA
proposal is approved as filed, a typical Idaho residential
customer will see a $0.81 decrease on their bill related
to this request.
• Idaho Power has requested a price increase to collect
the cost of an accelerated depreciation schedule for
all coal-related investments at the Jim Bridger Power
Plant in Wyoming. If approved as filed, a typical Idaho
residential customer will see a $2.07 increase on their
bill related to this request.
The impact of these three filings for all Idaho
customers is shown in the table below. A typical
Idaho residential customer will see an overall monthly
increase of $7.80. The actual percentage of change will
depend on a customer’s classification and the rate they pay.
The PCA has two main components: the forecast and the
backward-looking balancing adjustment. The forecast
reflects Idaho Power’s anticipated fuel costs, purchased
power costs and customer benefits from sales of surplus
energy for the coming April through March. The balancing
adjustment brings last year’s forecasted costs in balance
with costs actually incurred by Idaho Power by looking
back at what happened the previous April through March.
The increase in this year’s PCA is attributed to last year’s
actual power supply costs, which exceeded the forecast,
driven by lower-than-expected hydro generation, high
natural gas prices and high market prices. Idaho Power
experienced higher power costs than it has in the past due
to the record-setting heat wave of summer 2021, during
which the company exceeded its previous all-time peak
load for five consecutive days.
This year’s PCA forecast also reflects expected increases
to costs primarily due to continued drought conditions,
which would result in less low-cost hydro generation
available to serve customers, and higher costs associated
with power purchase agreements under the Public Utility
Regulatory Policies Act of 1978 (PURPA).
2022 RATE FILINGS
PERCENTAGE CHANGE FROM CURRENT BILLED REVENUE
Overall Percentage Impact Residential Small General Service
Large General Service1
Large Power2 Irrigation
POWER COST ADJUSMENT (PCA)3
8.27%6.55%5.24%9.18%12.10%8.46%
FIXED COST ADJUSMENT (FCA)
-0.39%-0.81%-0.82%N/A N/A N/A
BRIDGER
2.17%2.08%1.99%2.24%2.23%2.30%
COMBINED IMPACT4
10.05%7.82%6.41%11.43%14.33%10.75%
1 Includes lighting schedules; ² Includes special contracts; ³ Includes revenue sharing; 4 Totals may not sum due to rounding Oxbow Power Plant
1
From:Gust, Stacy
Sent:Monday, April 18, 2022 8:53 AM
To:Jan Noriyuki
Cc:Naomi Carr
Subject:RE: IPC-E-22-11 Application of Idaho Power Company for Authority to Implement Power
Cost Adjustment (PCA) Rates for Electric Service from June 1, 2022 through May 31,
2023
Thank you!

Stacy Gust
REGULATORY ADMINISTRATIVE ASSISTANT
Idaho Power | Regulatory Affairs
Office 208-388-5749

From: Jan Noriyuki <[e-mail]>
Sent: Monday, April 18, 2022 8:52 AM
To: Gust, Stacy <[e-mail]>
Cc: Naomi Carr <[e-mail]>
Subject: [EXTERNAL]RE: IPC-E-22-11 Application of Idaho Power Company for Authority to Implement Power Cost
Adjustment (PCA) Rates for Electric Service from June 1, 2022 through May 31, 2023

KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify
the sender before proceeding, and check for additional warning messages below.
Thank you, Stacy. We will get it replaced.

Jan Noriyuki
Commission Secretary

Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg. 8, Ste. 201-A
Boise, ID 83714
208-334-0338
[e-mail]

Notice of Electronic Filing
Pursuant to Idaho Public Utilities Commission Order No. 35058, issued June 3, 2021, please accept this e-mail as confirmation of your
submittal being accepted for electronic filing.

From: Gust, Stacy <[e-mail]>
Sent: Monday, April 18, 2022 8:11 AM
To: Jan Noriyuki <[e-mail]>
Cc: Nordstrom, Lisa <[e-mail]>; Aschenbrenner, Connie <[e-mail]>
Subject: RE: IPC-E-22-11 Application of Idaho Power Company for Authority to Implement Power Cost Adjustment (PCA)
Rates for Electric Service from June 1, 2022 through May 31, 2023
2

Ms. Noriyuki,

Please find attached the corrected Bill Insert that was sent out regarding the above matter. Could you please replace it
with the Bill Insert that was filed on Friday?

Thank you.

Stacy Gust
REGULATORY ADMINISTRATIVE ASSISTANT
Idaho Power | Regulatory Affairs
Office 208-388-5749

From: Gust, Stacy
Sent: Friday, April 15, 2022 4:07 PM
To: Jan Noriyuki <[e-mail]>
Cc: Nordstrom, Lisa <[e-mail]>
Subject: IPC-E-22-11 Application of Idaho Power Company for Authority to Implement Power Cost Adjustment (PCA)
Rates for Electric Service from June 1, 2022 through May 31, 2023

Ms. Noriyuki,

Please find attached for electronic filing, pursuant to Order No. 35058, Idaho Power Company’s 2022-2023 Power Cost
Adjustment (PCA) Application, the Direct Testimony of Jessica Brady, PCA Bill Insert, PCA Postcard, and PCA News
Release.

Also provided as a courtesy to Staff are the Excel workpapers.

If you have any questions regarding this filing, please do not hesitate to contact me.

Thank you.

Stacy Gust
REGULATORY ADMINISTRATIVE ASSISTANT
Idaho Power | Regulatory Affairs
Office 208-388-5749

IDAHO POWER LEGAL DISCLAIMER
This transmission may contain information that is privileged, confidential and/or exempt from disclosure
under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure,
copying, distribution, or use of the information contained herein (including any reliance thereon) is STRICTLY
PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the
material in its entirety, whether in electronic or hard copy format. Thank you.
1
From:Goralski, Paul
Sent:Monday, April 18, 2022 9:35 AM
To:Jan Noriyuki
Cc:Naomi Carr; Gust, Stacy
Subject:RE: IPC-E-22-11 Application of Idaho Power Company for Authority to Implement Power
Cost Adjustment (PCA) Rates for Electric Service from June 1, 2022 through May 31,
2023
Thanks so much Jan for getting those files removed so quickly!

From: Jan Noriyuki <[e-mail]>
Sent: Monday, April 18, 2022 8:48 AM
To: Goralski, Paul <[e-mail]>
Cc: Naomi Carr <[e-mail]>
Subject: [EXTERNAL]RE: IPC-E-22-11 Application of Idaho Power Company for Authority to Implement Power Cost
Adjustment (PCA) Rates for Electric Service from June 1, 2022 through May 31, 2023

KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify
the sender before proceeding, and check for additional warning messages below.
Good morning, Paul.

We will get this corrected right away.

Thank you,

Jan Noriyuki
Commission Secretary

Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg. 8, Ste. 201-A
Boise, ID 83714
208-334-0338
[e-mail]

Notice of Electronic Filing
Pursuant to Idaho Public Utilities Commission Order No. 35058, issued June 3, 2021, please accept this e-mail as confirmation of your
submittal being accepted for electronic filing.

From: Goralski, Paul <[e-mail]>
Sent: Friday, April 15, 2022 4:54 PM
To: Jan Noriyuki <[e-mail]>
Subject: RE: IPC-E-22-11 Application of Idaho Power Company for Authority to Implement Power Cost Adjustment (PCA)
Rates for Electric Service from June 1, 2022 through May 31, 2023

2
Good Afternoon Ms. Noriyuki:

Thank you for uploading the filing to the PUC website so quickly this afternoon. I noticed when I was reviewing the Excel
versions of the files were also posted to the website. The PDF versions of the exhibits are included with the Brady
Testimony and we provide the Excel versions as a courtesy to Staff for their review. Would it be possible to remove the
Excel exhibits from the PUC website?

Thank you!

-Paul

Paul Goralski
REGULATORY CONSULTANT
Idaho Power | Regulatory Affairs
Office 208-388-2608 | Mobile [phone]

From: Gust, Stacy <[e-mail]>
Sent: Friday, April 15, 2022 4:49 PM
To: Goralski, Paul <[e-mail]>
Subject: FW: IPC-E-22-11 Application of Id
Rates for Electric Service from June 1, 2022 through May 31, 2023

From: Gust, Stacy
Sent: Friday, April 15, 2022 4:07 PM
To: 'Jan Noriyuki' <[e-mail]>
Cc: Nordstrom, Lisa <[e-mail]>
Subject: IPC-E-22-11 Application of Idaho Power Company for Authority to Implement Power Cost Adjustment (PCA)
Rates for Electric Service from June 1, 2022 through May 31, 2023

Ms. Noriyuki,
3

Please find attached for electronic filing, pursuant to Order No. 35058, Idaho Power Company’s 2022-2023 Power Cost
Adjustment (PCA) Application, the Direct Testimony of Jessica Brady, PCA Bill Insert, PCA Postcard, and PCA News
Release.

Also provided as a courtesy to Staff are the Excel workpapers.

If you have any questions regarding this filing, please do not hesitate to contact me.

Thank you.

Stacy Gust
REGULATORY ADMINISTRATIVE ASSISTANT
Idaho Power | Regulatory Affairs
Office 208-388-5749

IDAHO POWER LEGAL DISCLAIMER
This transmission may contain information that is privileged, confidential and/or exempt from disclosure
under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure,
copying, distribution, or use of the information contained herein (including any reliance thereon) is STRICTLY
PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the
material in its entirety, whether in electronic or hard copy format. Thank you.
1
From:Goralski, Paul
Sent:Thursday, April 21, 2022 10:58 AM
To:Kathy Stockton
Cc:Brady, Jessi; Gust, Stacy
Subject:FW: IPC-E-22-11 Application of Idaho Power Company for Authority to Implement
Power Cost Adjustment (PCA) Rates for Electric Service from June 1, 2022 through May
31, 2023
Attachments:Exhibit No. 1 - 2022-2023 PCA Forecast.xlsx; Exhibit No. 2 - 2022 PCA Deferral Report -
Balancing Adjustment.xlsx; Exhibit No. 3 - 2022 ROE Determination Revenue Sharing
Benefits.xlsx; Exhibit No. 4 - 2022 Earnings Sharing Benefit.xlsx
Hi Kathy:

Attached please find the Excel versions of Idaho Power’s PCA exhibits. We have tried to include these with the filing, but
we’re still working out the logistics to make sure they are not posted to PUC site, but getting passed along to the correct
Staff contacts.

Thanks for your patience, we’ll get there!

-Paul

From: Gust, Stacy <[e-mail]>
Sent: Friday, April 15, 2022 4:49 PM
To: Goralski, Paul <[e-mail]>
Subject: FW: IPC-E-22-11 Application of Idaho Power Company for Authorit
Rates for Electric Service from June 1, 2022 through May 31, 2023

From: Gust, Stacy
Sent: Friday, April 15, 2022 4:07 PM
To: 'Jan Noriyuki' <[e-mail]>
Cc: Nordstrom, Lisa <[e-mail]>
Subject: IPC-E-22-11 Application of Idaho Power Company for Authority to Implement Power Cost Adjustment (PCA)
Rates for Electric Service from June 1, 2022 through May 31, 2023

Ms. Noriyuki,

Please find attached for electronic filing, pursuant to Order No. 35058, Idaho Power Company’s 2022-2023 Power Cost
Adjustment (PCA) Application, the Direct Testimony of Jessica Brady, PCA Bill Insert, PCA Postcard, and PCA News
Release.

Also provided as a courtesy to Staff are the Excel workpapers.

If you have any questions regarding this filing, please do not hesitate to contact me.

Thank you.

Stacy Gust
2
REGULATORY ADMINISTRATIVE ASSISTANT
Idaho Power | Regulatory Affairs
Office 208-388-5749

Line No. FERC Account April May June July August September October November December January February March Annual
95% Sharing Accounts
1 Hydroelectric Generation (MWh)497,726 638,022 480,588 521,844 479,226 467,253 411,296 377,554 421,109 499,779 509,799 668,546 5,972,743
Account 536, Water for Power
2 Total Expense -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$ -$
Account 501, Coal
Jim Bridger
3 Energy (MWh)340,469 91,408 217,645 397,110 396,394 385,697 387,296 419,907 441,058 438,988 398,531 394,768 4,309,270
4 Total Expense 9,443,599$ 2,248,639$ 5,734,700$ 10,763,184$ 10,767,828$ 10,483,821$ 10,550,491$ 11,461,278$ 12,067,323$ 12,795,415$ 11,813,841$ 11,652,435$ 119,782,555$
North Valmy
5 Energy (MWh)- (0) 49,680 92,374 92,374 89,394 92,374 89,394 92,374 92,374 83,435 (0) 773,773
6 Total Expense 253,916$ 253,916$ 2,055,223$ 3,588,576$ 3,598,821$ 3,491,852$ 3,602,724$ 3,499,879$ 3,614,433$ 3,730,360$ 3,445,374$ 261,533$ 31,396,605$
Account 547, Other Fuel
Langley Gulch7 Energy (MWh)209,344 - 164,576 210,784 211,056 208,240 215,800 215,505 226,896 227,040 202,080 219,513 2,310,834 8 Total Expense 6,563,384$ 391,446$ 4,602,383$ 4,941,008$ 4,964,704$ 6,942,101$ 7,333,533$ 8,057,540$ 7,705,046$ 7,953,869$ 7,855,176$ 6,831,914$ 74,142,105$
Danskin
9 Energy (MWh)- - - 94,920 121,032 - - - - 2,752 - - 218,704
10 Total Expense 188,260$ 188,260$ 188,260$ 3,833,070$ 4,845,555$ 188,260$ 188,260$ 188,260$ 188,260$ 328,116$ 188,260$ 188,260$ 10,701,080$
Bennett Mountain
11 Energy (MWh)- - - - 26,784 - - - - - - - 26,784.00
12 Total Expense 92,725$ 92,725$ 92,725$ 92,725$ 1,120,405$ 92,725$ 92,725$ 92,725$ 92,725$ 92,725$ 92,725$ 92,725$ 2,140,380$
Account 555, Purchased Power Non-PURPA
13 Energy (MWh)40,254 279,203 366,794 289,780 172,321 41,195 31,697 56,268 114,743 75,148 53,545 59,379 1,580,326
14 Total Expense 4,157,980$ 9,534,941$ 11,968,170$ 17,449,226$ 18,381,020$ 4,286,045$ 4,053,608$ 4,883,331$ 9,440,738$ 6,207,751$ 4,714,385$ 4,829,284$ 99,906,480$
Account 565, 3rd Party Transmission
15 Total Expense 322,260$ 284,758$ 630,748$ 842,719$ 784,043$ 478,164$ 524,429$ 294,591$ 231,318$ 250,501$ 247,157$ 258,551$ 5,149,239$
Account 447, Surplus Sales
16 Energy (MWh)243,770 - - - - 67,592 182,866 100,591 - 70,270 238,722 354,384 1,258,195
17 Total Expense (8,807,736)$ -$ -$ -$ -$ (5,618,895)$ (9,806,823)$ (5,227,868)$ (0)$ (5,477,413)$ (15,656,206)$ (14,490,907)$ (65,085,848)$
100% Sharing Accounts
Account 555, PURPA18 Energy (MWh)304,393 309,451 328,424 295,688 281,666 239,650 234,716 187,192 182,632 203,474 229,833 241,494 3,038,613 19 Total Expense 15,817,171$ 15,833,025$ 22,446,262$ 24,018,906$ 22,981,384$ 16,991,418$ 16,537,458$ 15,971,840$ 15,876,164$ 15,380,343$ 17,213,069$ 13,519,017$ 212,586,058$
Account 555, Demand Response Incentives
20 Total Expense -$ -$ 405,663$ 1,810,997$ 2,173,196$ 1,810,997$ 1,086,598$ 828,450$ -$ -$ -$ -$ 8,115,900$
21 Total Net Power Supply Expense 28,031,559$ 28,827,709$ 48,124,134$ 67,340,411$ 69,616,956$ 39,146,487$ 34,163,003$ 40,050,025$ 49,216,007$ 41,261,668$ 29,913,782$ 23,142,813$ 498,834,555$
22 Total Generation (MWh)1,392,185 1,318,084 1,607,707 1,902,500 1,780,853 1,431,430 1,373,179 1,345,819 1,478,812 1,539,556 1,477,222 1,583,700 18,231,048
23 Total Load (MWh)1,148,415 1,318,084 1,607,707 1,902,500 1,780,853 1,363,838 1,190,313 1,245,228 1,478,812 1,469,285 1,238,500 1,229,317 16,972,853
APRIL 1, 2022 - MARCH 31, 2023
Power Cost Adjustment Highlighted cells need to be updated prior to the June and July PCA entries
April 2021 thru March 2022
April May June July August September October November December January February March Totals
Idaho Jurisdiction Net Power Supply Expense (Non-QF)
Actual Non-QF
Fuel Expense-Coal 1,757,654.22 2,514,720.18 7,399,208.57 10,741,867.24 10,164,589.83 12,340,609.49 12,316,422.51 9,595,793.75 11,558,010.46 11,064,306.78 8,586,436.46 8,008,364.72 106,047,984.21
Fuel Expense-Gas 4,951,817.23 4,811,440.59 9,677,044.41 11,235,688.77 6,541,453.37 8,301,240.92 6,083,484.56 8,620,688.39 8,395,740.16 8,075,067.74 6,289,292.47 3,596,646.61 86,579,605.22
Non-Firm Purchases 3,493,642.85 5,088,468.04 31,400,383.66 34,713,710.07 20,241,393.06 14,739,423.21 11,093,208.55 11,275,274.53 18,479,986.77 15,990,136.63 17,785,197.15 8,774,306.18 193,075,130.70
Third Party Transmission 147,558.34 320,962.37 1,039,318.17 1,673,946.46 1,440,889.56 502,349.91 560,650.46 494,788.63 478,257.45 383,049.25 466,799.64 397,204.66 7,905,774.90
Surplus Sales 1,232,006.71 2,764,951.07 (9,915,940.56) (7,889,388.83) (5,147,668.33) (17,585,821.35) (10,333,780.36) (8,418,338.49) (8,094,574.26) (9,153,640.02) (4,647,258.89) (4,057,451.42) (81,246,904.73)
Water for Power (Leases)- - - - - - - - - - - - -
Total Actual NPSE $11,582,679.35 15,500,542.25 39,600,014.25 50,475,823.71 33,240,657.49 18,297,802.18 19,719,985.72 21,568,206.81 30,817,420.58 26,358,920.38 28,480,466.83 16,719,070.75 312,361,590.30
Idaho Allocation 95.1%95.5%95.8%95.9%95.9%95.8%95.7%95.0%95.2%95.3%95.4%95.7%
Net Idaho Jurisctional Actual Non-QF $11,015,128.06 14,803,017.85 37,936,813.65 48,406,314.94 31,877,790.53 17,529,294.49 18,872,026.33 20,489,796.47 29,338,184.39 25,120,051.12 27,170,365.36 16,000,150.71 298,558,933.90
Base Non-QF
Fuel Expense-Coal $7,525,242.00 7,487,643.00 9,019,153.00 11,385,255.00 12,185,412.00 10,796,845.00 7,781,442.00 7,302,324.00 8,455,019.00 9,553,773.00 8,912,994.00 8,098,078.00 108,503,180.00
Fuel Expense-Gas $2,314,209.00 2,302,646.00 2,773,625.00 3,501,263.00 3,747,333.00 3,320,312.00 2,392,997.00 2,245,656.00 2,600,139.00 2,938,035.00 2,740,979.00 2,490,369.00 33,367,563.00
Non-Firm Purchases $4,342,083.00 4,320,388.00 5,204,073.00 6,569,319.00 7,031,012.00 6,229,805.00 4,489,910.00 4,213,459.00 4,878,566.00 5,512,549.00 5,142,819.00 4,672,610.00 62,606,593.00
Third Party Transmission $378,398.00 376,507.00 453,517.00 572,494.00 612,729.00 542,907.00 391,281.00 367,189.00 425,151.00 480,400.00 448,179.00 407,203.00 5,455,955.00
Surplus Sales $(3,588,093.00)(3,570,166.00)(4,300,402.00)(5,428,577.00)(5,810,099.00)(5,148,019.00)(3,710,251.00)(3,481,805.00)(4,031,418.00)(4,555,312.00)(4,249,784.00)(3,861,227.00)(51,735,153.00)
Water for Power (Leases)$165,106.00 164,281.00 197,883.00 249,796.00 267,352.00 236,886.00 170,727.00 160,216.00 185,506.00 209,613.00 195,555.00 177,676.00 2,380,597.00
Idaho Base NPSE $ 11,136,945.00 11,081,299.00 13,347,849.00 16,849,550.00 18,033,739.00 15,978,736.00 11,516,106.00 10,807,039.00 12,512,963.00 14,139,058.00 13,190,742.00 11,984,709.00 160,578,735.00
Idaho Allocation 95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%
Net Idaho Jurisdiction 95% Items $ 10,580,097.75 10,527,234.05 12,680,456.55 16,007,072.50 17,132,052.05 15,179,799.20 10,940,300.70 10,266,687.05 11,887,314.85 13,432,105.10 12,531,204.90 11,385,473.55 152,549,798.25
Idaho Jurisdiction Change From Base
Net Power Supply Expense Deferral ①
Idaho Jurisdictional Qualifying Facility NPSE
Actual QF (Includes Net Metering, Raft River 100% & Liquidated Damages)
Base QF
QF Deferral ②
Idaho Revenue Adjustment (SBAR)
Idaho Revenue Adjustment (SBAR) ③
Idaho Jurisdcitional Demand Response Incentive Payments
Idaho Actual Demand Response $- 15.00 215,509.60 2,837,603.74 2,830,335.20 918,876.18 339,283.73 (29,901.00) 338.82 - - - 7,112,061.27
Idaho Base Demand Response $780,401.00 776,502.00 935,327.00 1,180,702.00 1,263,682.00 1,119,681.00 806,970.00 757,284.00 876,823.00 990,769.00 924,317.00 839,807.00 11,252,265.00
Change From Base $(780,401.00) (776,487.00) (719,817.40) 1,656,901.74 1,566,653.20 (200,804.82) (467,686.27) (787,185.00) (876,484.18) (990,769.00) (924,317.00) (839,807.00) (4,140,203.73)
Sharing Percentage 100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%100.0%
Change From Base ④$(780,401.00) (776,487.00) (719,817.40)1,656,901.74 1,566,653.20 (200,804.82) (467,686.27) (787,185.00) (876,484.18) (990,769.00) (924,317.00) (839,807.00) (4,140,203.73)
Idaho Miscellaneous Revenue
Miscellaneous Revenue Deferral ⑤
Idaho EIM Participation Costs
Return on EIM Capital Investment $41,551.97 40,425.17 39,298.37 38,171.57 37,044.76 35,917.96 34,791.16 33,664.35 32,537.55 31,377.59 30,706.63 30,035.68 425,522.76
Operating Expenses $236,046.12 247,117.91 233,818.23 241,017.65 247,528.80 227,261.53 217,600.38 230,366.44 230,575.44 172,307.29 191,995.31 177,385.27 2,653,020.36
Revenue Subtotal $277,598.09 287,543.09 273,116.60 279,189.22 284,573.56 263,179.49 252,391.53 264,030.80 263,112.99 203,684.87 222,701.94 207,420.95 3,078,543.12
Sharing Percentage 95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%95.0%
EIM Revenue Requirement ⑥$263,718.19 273,165.93 259,460.77 265,229.75 270,344.88 250,020.52 239,771.96 250,829.26 249,957.34 193,500.63 211,566.84 197,049.90 2,924,615.97
TOTAL DEFERRAL (Sum of ①-⑥)$2,851,842.24 6,575,145.26 29,306,064.79 28,855,090.58 16,670,979.22 3,660,978.05 13,453,342.13 13,820,066.15 23,475,598.44 8,876,886.21 9,519,620.13 4,173,169.83 161,238,783.03
PCA Forecasted Revenues
Actual Idaho Jurisdictional Billing Month Sales MWh 1,022,091 1,121,255 1,294,124 1,784,020 1,664,879 1,357,241 1,047,114 970,118 1,079,035 1,243,412 1,222,767 1,132,221 14,938,277
% of Prior Period Billings at Old Rate 6/1/2020 7.83$ 100.000%100.000%59.416%1.049%0.000%0.000%0.000%0.000%0.000%0.000%0.000%0.000%
% of Current Period Billings at New Rate - 6/1/2021 8.79$ 0.000%0.000%40.600%99.000%100.000%100.000%100.000%100.000%100.000%100.000%100.000%100.000%
Forecast Rate Revenues ⑦(8,006,044.95)(8,782,797.58)(10,591,359.88)(15,672,159.87)(14,639,281.60)(11,934,224.01)(9,207,278.35)(8,530,253.86)(9,487,963.28)(10,933,325.62)(10,751,791.84)(9,955,623.02)(128,492,103.86)
PCA Balancing Account Balance
Monthly Interest Rate (Annual 1% for 2021-2022)%0.0833%0.0833%0.0833%0.0833%0.0833%0.0833%0.0833%0.0833%0.0833%0.0833%0.0833%0.0833%1.0000%
2020-2021 PCA Ending Balance
True-up Ending Balance 4,519,614.31 4,519,614.31
True-up of the True-up Ending Balance (22,156,785.96) (22,156,785.96)
Beginning Balance (17,637,171.65)$ (19,769,421.03) (18,662,294.82) 2,995,202.48 18,384,016.20 22,468,617.64 15,872,975.72 21,413,705.95 27,906,822.00 43,235,933.07 42,735,093.69 43,032,551.71 (17,637,171.65)
2021-2022 Incremental Deferral (Sum of ①-⑥ above 2,851,842.24 6,575,145.26 29,306,064.79 28,855,090.58 16,670,979.22 3,660,978.05 13,453,342.13 13,820,066.15 23,475,598.44 8,876,886.21 9,519,620.13 4,173,169.83 161,238,783.03
2021-2022 PCA Forecast Revenues (Collections) ⑦ above (8,006,044.95)(8,782,797.58) (10,591,359.88) (15,672,159.87) (14,639,281.60) (11,934,224.01) (9,207,278.35) (8,530,253.86) (9,487,963.28) (10,933,325.62) (10,751,791.84) (9,955,623.02) (128,492,103.86)
2021-2022 PCA Prior Balance Revenues (Collections)3,036,650.97 3,331,253.05 2,958,344.30 2,203,387.01 2,037,583.81 1,658,880.19 1,281,438.97 1,185,459.01 1,318,220.23 1,519,570.09 1,494,017.15 1,383,566.57 23,408,371.35
Revenue Sharing - Order No. - - - - - - - - - - - - -
DSM Rider Forecasted Surplus Funds - Order No. - - - - - - - - - - - - -
2021-2022 Ending Balance Without Current Month Interest (19,754,723.39)(18,645,820.30)3,010,754.39 18,381,520.20 22,453,297.63 15,854,251.87 21,400,478.47 27,888,977.25 43,212,677.39 42,699,063.75 42,996,939.13 38,633,665.09 38,517,878.87
Current Month Interest (14,697.64)(16,474.52)(15,551.91)2,496.00 15,320.01 18,723.85 13,227.48 17,844.75 23,255.68 36,029.94 35,612.58 35,860.46 151,646.68
2021-2022 Ending Deferral Balance (19,769,421.03)$ (18,662,294.82) 2,995,202.48 18,384,016.20 22,468,617.64 15,872,975.72 21,413,705.95 27,906,822.00 43,235,933.07 42,735,093.69 43,032,551.71 38,669,525.55 38,669,525.55
Tab is 100% locked down, with no manual inputs.
Idaho Billed Sales MWh 1,022,091 1,121,255 1,294,124 1,784,020 1,664,879 1,357,241 1,047,114 970,118 1,079,035 1,243,412 1,222,767 1,132,221 14,938,277
Oregon Billed Sales MWh 52,772 52,608 57,143 77,158 72,013 58,812 47,588 50,586 54,932 61,300 58,577 51,206 694,695 Total MWh 1,074,863 1,173,863 1,351,267 1,861,178 1,736,892 1,416,053 1,094,702 1,020,704 1,133,967 1,304,712 1,281,344 1,183,427 15,632,972
Idaho % Billed Sales 95.1%95.5%95.8%95.9%95.9%95.8%95.7%95.0%95.2%95.3%95.4%95.7%
#
1
2
3
4
5
6
7 TOTAL TOTAL
8 SYSTEM IDAHO IDAHO %SYSTEM IDAHO IDAHO %
9 * * * SUMMARY OF RESULTS * * *
10 TOTAL COMBINED RATE BASE 3,697,810,735 3,552,703,864 96.076%
11
12 DEVELOPMENT OF NET INCOME
13 OPERATING REVENUES
14 RETAIL SALES REVENUES (Incl 449.1 Rev)974,391,283 932,709,732 Direct Assign 1,252,903,102 1,198,934,622 Direct Assign
15 OTHER OPERATING REVENUES 143,588,027 136,940,469 95.4%199,114,589 189,896,371 95.4%
16 TOTAL OPERATING REVENUES 1,117,979,310 1,069,650,202 1,452,017,691 1,388,830,993
17
18 OPERATING EXPENSES
19 OPERATION & MAINTENANCE EXPENSES 683,260,685 649,645,486 95.1%917,571,975 872,429,080 95.1%
20 DEPRECIATION EXPENSE 123,577,643 118,717,824 96.1%165,446,697 158,940,333 96.1%
21 AMORTIZATION OF LIMITED TERM PLANT 6,256,000 6,013,901 96.1%8,495,466 8,166,702 96.1%
22 TAXES OTHER THAN INCOME 26,188,106 24,462,684 93.4%30,947,260 28,908,278 93.4%
23 REGULATORY DEBITS/CREDITS 1,087,391 878,396 80.8%1,497,775 1,209,905 80.8%
24 PROVISION FOR DEFERRED INCOME TAXES (14,885,993) (14,382,662) 96.6%(21,559,910)(20,830,919)96.6%
25 INVESTMENT TAX CREDIT ADJUSTMENT 11,264,544 10,824,447 96.1%11,832,897 11,370,595 96.1%
26 FEDERAL INCOME TAXES 29,156,558 28,544,231 97.9%35,047,688 34,311,639 97.9%
27 STATE INCOME TAXES 11,411,459 11,163,398 97.8%13,298,956 13,009,865 97.8%
28 TOTAL OPERATING EXPENSES 877,316,394 835,867,704 1,162,578,803 1,107,515,477
29
30 OPERATING INCOME 240,662,916 233,782,498 289,438,888 281,315,516
31 ADD: IERCO OPERATING INCOME 6,715,053 6,414,821 95.5%8,991,347 8,589,341 95.5%
32
33 OPERATING INCOME BEFORE OTHER INCOME AND DEDUCTIONS 247,377,969 240,197,319 298,430,236 289,904,857 97.1%
34 ADD: AFUDC EQUITY 31,537,344 30,299,778 96.1% (L 10)
35 ADD: OTHER INCOME AND DEDUCTIONS 343,755 333,934 97.1% (L 33)
36
37 INCOME BEFORE INTEREST CHARGES 330,311,334 320,538,570
38 LESS: INTEREST CHARGES 86,663,666 83,262,872 96.1% (L 10)
39
40 NET INCOME 243,647,668 237,275,698
41
42 ACTUAL YEAR-END RESULTS - BEFORE ITC ADJUSTMENT
43 EARNINGS ON COMMON STOCK 243,647,668 237,275,698
44 COMMON EQUITY AT YEAR END 2,464,724,288 2,368,005,322 96.1% (L10)
45
46 RETURN ON YEAR-END COMMON EQUITY 9.89%10.02%
47
48 EARNINGS ON COMMON STOCK @ 9.40 ROE 234,148,807 222,592,500 (L44 * 9.4%)
49 EARNINGS ON COMMON STOCK @ 10 ROE 246,472,429 236,800,532 (L44 * 10%)
50 EARNINGS ON COMMON STOCK @ 10.50 ROE 258,796,050 248,640,559 (L44 * 10.5%)
51
52
53 ACTUAL YEAR-END RESULTS - AFTER ITC ADJUSTMENT:
54 INVESTMENT TAX CREDIT ADJUSTMENT (16,206,620) (L48-L43) / (1-9.4%)
55 ADJUSTED EARNINGS ON COMMON STOCK 221,069,078
56 ADJUSTED COMMON EQUITY AT YEAR-END 2,351,798,702
57 ADJUSTED RETURN ON YEAR-END COMMON EQUITY 9.40%
58
59 IF IDAHO RETURN ON COMMON EQUITY (Line 46) <9.4%
60 ADDITIONAL ITC ADJUSTMENT (Annualized)If L 54 is negative, then 0; if positive, then smaller of L54 or $25,000,000 0
61
62 IF IDAHO RETURN ON COMMON EQUITY (Line 46) >10%
63 IDAHO EARNINGS GREATER THAN 10% ROE BUT LESS THAN 10.5%527,962 (L43-L49)/(1-10%)
64
65 IF IDAHO RETURN ON COMMON EQUITY (Line 46) >10.5%
66 INCREMENTAL IDAHO EARNINGS GREATER THAN 10.50% ROE 0 (L43-L50)/(1-10.5%)
67
68 Per Order #34071:After Tax Tax Gross Up
69 ROE between 10%-10.5% --CUSTOMER SHARE - 80% (Reduction to rates)422,369 568,771
70 ROE between 10%-10.5% --COMPANY SHARE - 20% 105,592
71 ROE greater than 10.5% (Incremental) -- CUSTOMER SHARE - 55% (Reduction to rates)0 -
ROE greater than 10.5% (Incremental) -- CUSTOMER SHARE - 25% (Offset to Pension balance)0 -
72 ROE greater than 10.5% (Incremental) --COMPANY SHARE - 20% 0
73 527,962
74
Prepared by: Kelley Noe
Reviewed by:
September Allocations/Ratios
IDAHO POWER COMPANY
ADDITIONAL INVESTMENT TAX CREDIT ANALYSIS
For the Twelve Months Ended December 31, 2021
Actual September 30, 2021 Actual December 31, 2021
(A)(B)(C)(D)(E)(F) (G)
Line
No Tariff Description
Sch. Number of (kWh)
Current Base
Revenue Idaho Base Revenue Sharing Dollars per
kWh Rate Revenue
Uniform Tariff Rates:
1 Residential Service 1 490,293 5,458,972,074 494,239,546 45.07% ($256,535) (0.000047) (0.05)%
2 Master Metered Mobile Home Park 3 21 4,521,955 388,104 0.04% ($201) (0.000045) (0.05)%
3 Residential Service Energy Watch 4 0 0 0 0.00%- - 0.00%
4 Residential Service Time-of-Day 5 988 17,662,331 1,530,838 0.14% ($794) (0.000045) (0.05)%
5 Residential Service On-Site Generation 6 12,024 65,895,664 6,381,494 0.58% ($3,097) (0.000047) (0.05)%
6 Small General Service 7 30,348 137,395,735 15,753,366 1.44% ($8,171) (0.000059) (0.05)%
7 Small General Service On-Site Generation 8 80 190,425 24,155 0.00%($11) (0.000059) (0.05)%
8 Large General Service - Secondary 9S 37,635 3,304,176,840 225,029,064 20.52% ($116,704) (0.000035) (0.05)%
9 Large General Service - Primary 9P 280 592,994,508 35,347,188 3.22% ($18,332) (0.000031) (0.05)%
10 Large General Service - Transmission 9T 4 3,557,143 240,200 0.02% ($125) (0.000035) (0.05)%
11 Dusk to Dawn Lighting 15 0 5,267,423 1,238,927 0.11% ($643) (0.000122) (0.05)%
12 Large Power Service - Secondary 19S 0 0 0 0.00%- (0.000035) 0.00%
13 Large Power Service - Primary 19P 114 2,358,498,546 121,991,234 11.12% ($63,267) (0.000027) (0.05)%
14 Large Power Service - Transmission 19T 2 32,893,630 1,601,499 0.15% ($831) (0.000025) (0.05)%
15 Agricultural Irrigation Service 24 19,120 1,897,512,119 140,388,800 12.80% ($72,808) (0.000038) (0.05)%
16 Unmetered General Service 40 1,663 13,925,301 1,124,204 0.10% ($583) (0.000042) (0.05)%
17 Street Lighting 41 2,980 23,760,014 3,409,701 0.31% ($1,768) (0.000074) (0.05)%
18 Traffic Control Lighting 42 766 2,847,961 162,704 0.01%($84) (0.000030) (0.05)%
19 Total Uniform Tariffs 596,318 13,920,071,669 $1,048,851,023 95.64% ($543,955)(0.05)%
20 Total Special Contracts 3 1,071,974,663 $47,850,839 4.36% ($24,816)(0.05)%
Note:
(1) June 01, 2022 - May 31, 2023 Forecasted Test Year (Spring 2022 Forecast)
(2) 19S rate in column (F) set to match 9S rate due to single customer movement between classes.
Idaho Power Company
Calculation of Revenue Impact
Class Allocated Revenue Sharing 2022-2023
State of Idaho
Filed April 15, 2022
1
From:Keri Hawker <[e-mail]>
Sent:Wednesday, April 27, 2022 4:08 PM
To:Gust, Stacy
Subject:[EXTERNAL]RE: Idaho Power Company's 2022-2023 PCA
Attachments:IPCE2211_Protective Agreement.pdf
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify
the sender before proceeding, and check for additional warning messages below.
Stacy,

The attached includes additional staff exhibit A’s.

Thank you,

Keri Hawker | Legal Administrative Assistant
Idaho Public Utilities Commission

From: Keri Hawker
Sent: Thursday, February 24, 2022 4:21 PM
To: Gust, Stacy <[e-mail]>
Subject: RE: Idaho Power Company's 2022-2023 PCA

Hi Stacy,

The attached is signed.

Keri Hawker | Legal Administrative Assistant
Idaho Public Utilities Commission

From: Gust, Stacy <[e-mail]>
Sent: Tuesday, February 22, 2022 2:57 PM
To: Keri Hawker <[e-mail]>
Subject: Idaho Power Company's 2022-2023 PCA

Hi Keri,

Could you please check on whether you have a signed copy of the attached Protective Agreement from John Hammond
attorney handling this matter in advance of Idaho Power Company’s response to the audit requests we received.

Thank you.

Stacy Gust
REGULATORY ADMINISTRATIVE ASSISTANT
2
Idaho Power | Regulatory Affairs
Office 208-388-5749

IDAHO POWER LEGAL DISCLAIMER
This transmission may contain information that is privileged, confidential and/or exempt from disclosure
under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure,
copying, distribution, or use of the information contained herein (including any reliance thereon) is STRICTLY
PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the
material in its entirety, whether in electronic or hard copy format. Thank you.
C
0
0
PROTECTIVE AGREEMENT BETWEEN IDAHO POWER COMPANY AND IDAHO PUBLIC UTILITIES COMMISSION STAFF (AND OTHER PARTIES AS APPLICABLE) 2022-2023 Power Cost Adjustment This Protective Agreement is entered into this 17th day of November 2021 by Idaho Power Company ("Idaho Power") and the Idaho Public Utilities Commission Staff, and other parties as applicable. Recitals:
1.WHEREAS, Idaho Power and the Idaho Public Utilities Commission Staff anticipatethat parties to this proceeding may make requests to provide, or make available for review, certain information, considered by its custodian to be of a trade secret, privileged or confidential nature (as defined in Idaho Code§§ 74-107 through 74-109 and 48-801). 2.WHEREAS, Idaho Power and the undersigned parties agree that entering into aProtective Agreement will expedite the production of documents; will afford the necessary protection to Idaho Power's and the undersigned parties' employees and/or representatives evaluating the 2022-2023 Power Cost Adjustment who might review the information and subsequently be requested to reveal its contents by setting forth clear cut parameters for use of Confidential Information, and will protect Confidential Information which might be provided during the course of the proceedings, now therefore. IT IS HEREBY STIPULATED AND AGREED AS FOLLOWS:
1.(a) Confidential InformationAll documents, data, information, studies and other materials furnished pursuant to any requests for information, subpoenas or other modes of discovery (formal or informal), and including depositions, that are claimed to be of trade secret, proprietary or confidential nature (herein referred to as "Confidential Information") shall be so marked by the party or entity providing the information by stamping the same with a designation indicating its trade secret, proprietary or confidential nature and printed on "yellow" paper. IDAPA 31.01.01.067. Any claim of confidentiality must be accompanied by an attorney's certificate that the material is protected by law from public disclosure and cite the specific legal authority to support the claim. IDAPA 31.01.01.233. 2022-2023 POWER COST ADJUSTMENT -PROTECTIVE AGREEMENT - 1
(b)Protection of Confidential Information
Access to and review of Confidential Information shall be strictly controlled by the terms
of this Agreement. Unless otherwise ordered, Confidential Information, including transcripts of
depositions containing information to which a claim of confidentiality is made, shall remain under
seal, shall continue to be subject to the protective requirements of this Agreement, and shall not
be disclosed to individuals who have not executed the nondisclosure agreement set forth in Exhibit
uA .. "
( c)Use of Confidential Information
All persons who may be entitled to review, or who are afforded access to any Confidential
Information by reason of this Agreement shall neither use nor disclose the Confidential
Information for purposes of business or competition, or any purpose other than the purpose of
preparation for and conduct of the proceedings, and then solely as contemplated herein, and shall
keep the Confidential Information secure as trade secret, confidential or proprietary information
and in accordance with the purposes and intent of this Agreement.
(d)Persons Entitled to Review
Access to Confidential Information shall be limited to counsel of the undersigned parties,
employees, experts, agents or representatives of the undersigned parties who have executed an
Exhibit "A" to this Agreement. Such information will be clearly marked and protected from
unauthorized public disclosure.
(e)Non-disclosure Agreement
Confidential Infonnation shall not be disclosed to any person who has not signed a non­
disclosure agreement on this form, which is attached hereto as Exhibit .. A,, and incorporated
herein. The non-disclosure agreement or Exhibit "A" shall require the person to whom disclosure
is to be made to read a copy of this Protective Agreement and to certify in writing that he or she
has reviewed the same and has consented to be bound by its terms. The Agreement shall contain
the signatory's full name, permanent address and employer. Such agreement shall be delivered to
counsel for the providing party, before disclosure is made.
2.Copies
No copies or transcriptions of the Confidential Information shall be made by the recipient
except as necessary to make the information available to individuals who have executed an Exhibit
"A" to this Protective Agreement.
2022-2023 POWER COST ADJUSTMENT-PROTECTIVE AGREEMENT� 2
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3.Non-waiver of Obiection to Admissibility
The furnishing of any document, information, data, study or other materials pursuant to
this Protective Agreement shall in no way limit or waive the right of the providing party to object
to its relevance or admissibility in any proceedings before this Commission.
4.Challenge to Confidentiality
(a)Initial Challen2e
This Protective Agreement establishes a procedure for the expeditious handling of
information that a party claims is confidential. Any party may challenge the characterization of
any information, document, data or study claimed by the providing party to be a trade secret,
proprietary or confidential information. A party seeking to challenge the confidentiality of any
information shall first contact counsel for the providing party and attempt to resolve any difference
by stipulation. Resolution may include removing the confidential classifications, creating a non­
confidential summary, reformatting the information, etc.
(b)Subsequent Challenge
In the event that the parties cannot agree as to the character of the information challenged,
any party challenging the confidentiality may petition the Commission to rule upon the disputed
information. The Petition shall be served upon the Commission and all parties to the case who
have signed an Exhibit "A" as provided in this Protective Agreement. The Petition shall designate
with specificity the document or material challenged and state the grounds upon which the subject
material are deemed to be non-confidential by the challenging party.
(c)Challen2e Hearin2
The challenging party shall request that the Commission conduct an in camera proceeding
where only those persons duly authorized to have access to such challenged materials under this
Protective Agreement shall be present. This hearing shall be commenced no earlier than five (5)
business days after serving the Petition on the providing party and the Commission. The record
of the in camera hearing shall be marked "CONFIDENTIAL -Subject to Protective
Agreement." To the extent necessary, the transcript of such hearing shall be separately bound,
segregated, sealed, and withheld from public inspection by any person not bound by the terms of
this Agreement.
2022-2023 POWER COST ADJUSTMENT -PROTECTIVE AGREEMENT - 3
(d)Determination
The parties will ask the Commission to issue an Order determining whether any challenged
information or material is not properly deemed to be exempt from public disclosure pursuant to
the
Idaho Public Records Act (Idaho Code§§ 74-101 through 74-126). If information is found
to be not exempt from disclosure, no party shall disclose such challenged material or use it in the
public record, or otherwise outside the proceedings for at least five (5) business days unless the
providing party consents to such conduct. This procedure enables the restrictions of this
Agreement from material claimed to be confidential. Such relief may be sought from the
Commission or a court of competent jurisdiction.
5.(a) Receipt Into Evidence
Provision is hereby made for receipt into evidence in this proceeding of materials claimed
to be confidential in the following manner:
(1)If the requesting party intends to use Confidential Information or to make
substantive reference to Confidential Information supplied to it under this Agreement, it shall give
reasonable prior notice of such intention to the providing party and shall provide copies of the used
Confidential Information or substantive reference to Confidential Information only to the
providing party, and such other parties, if any, who have executed an Exhibit "A" to this Protective
Agreement.
(2)One (I) copy of the used Confidential Information or substantive reference to
Confidential Information or substantive reference to Confidential Information described in
paragraph S(a)(l) shall be placed in the sealed record.
(3)The copy of the documents to be placed in the sealed record shall be tendered
by counsel for the providing party to the Commission, and shall be maintained in accordance with
the terms of this Protective Agreement.
(b)Seal
While in the custody of the Commission, materials containing Confidential Information
shall be marked "CONFIDENTIAL -SUBJECT TO ATTORNEY'S CERTIFICATE OF
CONFIDENTIALITY" and shall not be examined by any person except under the conditions set
forth in this Agreement, if applicable.
2022-2023 POWER COST ADJUSTMENT -PROTECTIVE AGREEMENT - 4
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(c)In Camera Hearing and Transcripts
Any Confidential Information that must be orally disclosed at a hearing in the proceedings
shall be offered at an in camera hearing, attended only by persons authorized to have access to the
information under this Protective Agreement. Similarly, any transcription of any examination or
other reference to Confidential Information ( or that portion of the record containing Confidential
Information) shall be marked and treated as provided herein for Confidential Information.
(d)Access to Record
Access to sealed testimony, records, and information shall be limited to the Commission
and persons who have signed an Exhibit "A" as provided in this Protective Agreement, unless such
information is released from the restrictions of this Agreement either through agreement of the
parties or after notice to the parties and hearing, pursuant to the order of the Commission and/or
the final order of a court having final jurisdiction.
(e)Appeal
Should an appeal from the proceeding be taken, sealed portions of the record may be
forwarded to any court of competent jurisdiction for purposes of an appeal, but under seal as
designated herein for the information and use of the court. If a portion of the record is forwarded
to a court under seal for the purposes of an appeal, the providing party shall be notified which
portion of the sealed record has been designated by the appealing party as necessary to the record
on appeal.
6.Use in Pleadings
Where references to Confidential Information in the sealed record or with the custodian is
required in pleadings, briefs, arguments, or motions ( except as provided in Paragraph 5), it shall
be by citation to title or exhibit number or some other description that will not disclose the
substantive Confidential Information contained therein. Any use of or substantive references to
Confidential Information shall be placed in a separate section of the pleading or brief and submitted
to the Commission pursuant to Paragraph 5. This sealed section shall be served only on counsel
of record who have signed the nondisclosure agreements set forth in Exhibit "A" attached to this
Protective Agreement, and may, in tum, be disclosed by them only to individuals who likewise
signed Exhibit "A". 2022-2023 POWER COST ADJUSTMENT -PROTECTIVE AGREEMENT - 5
7.Summary of Record
If deemed necessary by the Commission, the providing parties shall prepare a written
summary of the Confidential Information referred to in Orders to be issued to the public and the
parties.
8.Return or Destruction of Confidential Information
(a)Upon request of the providing party, aU original documents and copies of the
Confidential Information shall be: ( l) returned to the providing party; or (2) or at the option of the
recipient destroyed within thirty (30) days after the final settlement or conclusion of the
proceedings, including administrative or judicial review thereof. After return or destruction of
documents pursuant to this paragraph, and upon request, a written receipt verifying return or
destruction shall be provided by counsel.
(b)On a case-by-case basis and upon notification to the utility, the Commission Staff
may retain one copy of the Confidential Information under seal. Notwithstanding any other
provision in this Agreement, any member of Staff may review and use that copy of the Confidential
Information outside this proceeding while performing his or her duties as a Staff member. Staff's
use and disclosure of the Confidential Information in a later Commission proceeding shall be
subject to any protective agreement signed in the proceeding.
(c)Any notes maintained by a recipient of Confidential Information which embody
or reflect any of the Confidential Information provided under this Agreement shall, upon request
of the providing party, be either returned to the providing party or, at the option of the recipient,
destroyed.
Ill
/II
Ill
Ill
Ill
Ill
9.Effective Date
This Protective Agreement shall become effective on the date hereof.
2022-2023 POWER COST ADJUSTMENT -PROTECTIVE AGREEMENT -6
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DATED this 17th day of November 2021.
IDAHO POWER COMPANY
By: __________________ _ Lisa D. Nordstrom Idaho Power Company 1221 West Idaho Street Boise, Idaho 83702
Attorney Representing Idaho Power Company
IDAHO PUBLIC UTILITIES COMMISSION STAFF
By: .D� Dayn Hardie Deputy Attorney General Idaho Public Utilities Commission 11331 W. Chinden Blvd., Bldg 8, Suite 201-A (83714) PO Box 83720 Boise, Idaho 83720-0074
Attorney Representing the Idaho Public Utilities Commission Staff 2022-2023 POWER COST ADJUSTMENT -PROTECTIVE AGREEMENT - 7
0
0
0
EXHIBIT "A"
I have reviewed the foregoing Protective Agreement dated November 17, 2021, for the
2022-2023 Power Cost Adjustment and agree to be bound by the terms and conditions of such
Agreement.
EXHIBIT"A"
Public Utilities Commission
Employer or Firm
11331 W. Chinden Blvd., Building 8, Suite 201-A
Boise. Idaho 83714
Business Address
Commission Staff
Party
Date '
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EXHIBIT "A" I have reviewed the foregoing Protective Agreement dated November 17, 2021, for the 2022-2023 Power Cost Adjustment and agree to be bound by the terms and conditions of such Agreement. EXHIBIT "A" Public Utilities Commission Employer or Firm 11331 W. Chinden Blvd., Building 8, Suite 201-A Boise. Idaho 83714 Business Address Commission Staff Party date
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-22-11
IDAHO POWER COMPANY
REQUEST NO. 2
ATTACHMENT NO. 4
1
From:Daniel Klein <[e-mail]>
Sent:Wednesday, April 13, 2022 11:21 AM
To:Aschenbrenner, Connie
Cc:Terri Carlock
Subject:[EXTERNAL]RE: PCA News Release & Customer Insert
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify
the sender before proceeding, and check for additional warning messages below.
Connie,

We have taken a look at the press release and customer notice and didn’t find anything that we thought needed to be
changed. Thanks for running it by us. We will look for the filing later this week.

Daniel Klein
Program Manager
Compliance/Consumer Assistance
Telecom
208 334-0352 D
208 807-0451 C

From: Aschenbrenner, Connie <[e-mail]>
Sent: Tuesday, April 12, 2022 6:42 PM
To: Daniel Klein <[e-mail]>
Cc: Terri Carlock <[e-mail]>
Subject: PCA News Release & Customer Insert

Hi Daniel,

develop a direct mail post card with the same information that will be sent to those customers whose
to be mailed after May 20th so they receive the information in time to submit comments for the Commission’s
consideration.

If you have any concerns, suggested revisions, or would like to discuss, please let me know by Thursday at noon.

Thank you,
Connie

IDAHO POWER LEGAL DISCLAIMER
This transmission may contain information that is privileged, confidential and/or exempt from disclosure
under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure,
copying, distribution, or use of the information contained herein (including any reliance thereon) is STRICTLY
PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the
material in its entirety, whether in electronic or hard copy format. Thank you.
Thank you for reading this notice. We value your business.
©2022 Idaho Power
Printed on recycled paper.
XXXXX-I-XXXX
Oxbow Power PlantOxbow Power Plant
Opportunities for Public Review
Idaho Power’s proposal is subject to public review
and approval by the IPUC. Copies of the application
are available to the public at the IPUC offices (11331
W. Chinden Blvd. Building 8, Suite 201-A, Boise, ID
83714), Idaho Power offices, or at idahopower.com
or puc.idaho.gov. Customers also may subscribe to
the IPUC’s RSS feed to receive periodic updates via
email about the case. Written comments regarding
Idaho Power’s proposal may be filed with the IPUC.
Idaho Power Files Annual Power Cost Adjustment
Idaho Power has filed the final piece of its annual
spring cost adjustments with the Idaho Public Utilities
Commission (IPUC). This year’s Power Cost Adjustment
(PCA) calls for a price increase across all customer classes
as a result of higher power costs related to last summer’s
unprecedented heatwave and lower hydro generation
because of drought conditions.
Neither Idaho Power nor its shareholders receive any
financial return from this filing, which is a request for
$103.4 million. The money collected is used solely to
recover expenses associated with annual fluctuations in
power costs.
The overall impact to residential customer bills on June 1
depends on the outcome of three filings:
• The annual PCA, filed today, is a cost-recovery tool
that passes on both the benefits and costs of supplying
energy to Idaho Power customers. If the PCA proposal
is approved by the IPUC as filed, the typical Idaho
residential customer using 950 kilowatt-hours (kWh) of
energy per month will see a $6.54 increase on their bill
related to this request.
• The annual Fixed Cost Adjustment (FCA), filed in March
and applicable to only residential and small commercial
customers, adjusts prices based on changes in energy
use per customer during the previous year. If the FCA
proposal is approved as filed, a typical Idaho residential
customer will see a $0.81 decrease on their bill related
to this request.
• Idaho Power has requested a price increase to collect
the cost of an accelerated depreciation schedule for
all coal-related investments at the Jim Bridger Power
Plant in Wyoming. If approved as filed, a typical Idaho
residential customer will see a $2.07 increase on their
bill related to this request.
The impact of these three filings for all Idaho
customers is shown in the table below. A typical
Idaho residential customer will see an overall monthly
increase of $7.80. The actual percentage of change will
depend on a customer’s classification and the rate they pay.
The PCA has two main components: the forecast and the
backward-looking balancing adjustment. The forecast
reflects Idaho Power’s anticipated fuel costs, purchased
power costs and customer benefits from sales of surplus
energy for the coming April through March. The balancing
adjustment brings last year’s forecasted costs in balance
with costs actually incurred by Idaho Power by looking
back at what happened the previous April through March.
The increase in this year’s PCA is attributed to last year’s
actual power supply costs, which exceeded the forecast,
driven by lower-than-expected hydro generation, high
natural gas prices and high market prices. Idaho Power
experienced higher power costs than it has in the past due
to the record-setting heat wave of summer 2021, during
which the company exceeded its previous all-time peak
load for five consecutive days.
This year’s PCA forecast also reflects expected increases
to costs primarily due to continued drought conditions,
which would result in less low-cost hydro generation
available to serve customers, and higher costs associated
with power purchase agreements under the Public Utilities
Regulatory Policy Act of 1978 (PURPA).
2022 RATE FILINGS
PERCENTAGE CHANGE FROM CURRENT BILLED REVENUE
Overall Percentage Impact Residential Small General Service
Large General Service1
Large Power2 Irrigation
POWER COST ADJUSMENT (PCA)3
8.27%6.55%5.24%9.18%12.10%8.46%
FIXED COST ADJUSMENT (FCA)
-0.39%-0.81%-0.82%N/A N/A N/A
BRIDGER
2.17%2.08%1.99%2.24%2.23%2.30%
COMBINED IMPACT4
10.05%7.82%6.41%11.43%14.33%10.75%
1 Includes lighting schedules; ² Includes special contracts; ³ Includes revenue sharing; 4 Totals may not sum due to rounding Oxbow Power Plant

Idaho Power Files Annual Power Cost Adjustment
April 15, 2022
BOISE, Idaho — Idaho Power has filed the final piece of its annual spring cost adjustments with the
Idaho Public Utilities Commission (IPUC). This year’s Power Cost Adjustment (PCA) calls for a price
increase across all customer classes as a result of higher power costs related to last summer’s
unprecedented heatwave and lower hydro generation because of drought conditions.
Neither Idaho Power nor its shareholders receive any financial return from this filing, which is a request
for $103.4 million. The money collected is used solely to recover expenses associated with annual
fluctuations in power costs.
“We are sensitive to the impacts rate increases have on our customers and work hard to serve our
growing number of customers with prices that remain 20% to 30% lower than the rest of the nation,”
said XXX. “Unfortunately, the drought and last summer’s record heatwave resulted in higher-than-
expected overall power supply costs. We must recover these costs in order to maintain the reliable
service our customers depend on.”
The overall impact to residential customer bills on June 1 depends on the outcome of three filings:
 The annual PCA, filed today, is a cost-recovery tool that passes on both the benefits and costs of
supplying energy to Idaho Power customers. If the PCA proposal is approved by the IPUC as
filed, the typical Idaho residential customer using 950 kilowatt-hours (kWh) of energy per month
will see a $6.54 increase on their bill related to this request.

 The annual Fixed Cost Adjustment (FCA), filed in March and applicable to only residential and
small commercial customers, adjusts prices based on changes in energy use per customer during
the previous year. If the FCA proposal is approved as filed, a typical Idaho residential customer
will see a $0.81 decrease on their bill related to this request.

 Idaho Power has requested a price increase to collect the cost of an accelerated depreciation
schedule for all coal-related investments at the Jim Bridger Power Plant in Wyoming. If approved
as filed, a typical Idaho residential customer will see a $2.07 increase on their bill related to this
request.
The impact of these three filings for all Idaho customers is shown in the table below. A typical Idaho
residential customer will see an overall monthly increase of $7.80. The actual percentage of change will
depend on a customer’s classification and the rate they pay.

2022 RATE FILINGS
Percentage Change from Current Billed Revenue
Filing Overall
Percentage
Impact
General
Service
General
Service 1
2 Irrigation
PCA 8.27% 6.55% 5.24% 9.18% 12.10% 8.46%
FCA -0.39% -0.81% -0.82%% N/A N/A N/A
Bridger 2.17% 2.08% 1.99% 2.24% 2.23% 2.30%
Combined
Impact 4
1 Includes lighting schedules; 2 Includes special contracts; 3 Includes revenue sharing 4 Totals may not sum
due to rounding
The PCA has two main components: the forecast and the backward-looking balancing adjustment. The
forecast reflects Idaho Power’s anticipated fuel costs, purchased power costs and customer benefits
from sales of surplus energy for the coming April through March. The balancing adjustment brings last
year’s forecasted costs in balance with costs actually incurred by Idaho Power by looking back at what
happened the previous April through March.
The increase in this year’s PCA is attributed to last year’s actual power supply costs, which exceeded the
forecast, driven by lower-than-expected hydro generation, high natural gas prices and high market
prices. Idaho Power experienced higher power costs than it has in the past due to the record-setting
heat wave of summer 2021, during which the company exceeded its previous all-time peak load for five
consecutive days.
This year’s PCA forecast also reflects expected increases to costs primarily due to continued drought
conditions, which would result in less low-cost hydro generation available to serve customers, and
higher costs associated with power purchase agreements under the Public Utilities Regulatory Policy Act
of 1978 (PURPA).
Opportunities for Public Review
Idaho Power’s proposal is subject to public review and approval by the IPUC. Copies of the application
are available to the public at the IPUC offices (11331 W. Chinden Blvd. Building 8, Suite 201-A, Boise, ID
83714), Idaho Power offices, or at idahopower.com or puc.idaho.gov. Customers also may subscribe to
the IPUC’s RSS feed to receive periodic updates via email about the case. Written comments regarding
Idaho Power’s proposal may be filed with the IPUC.
About Idaho Power
Idaho Power, headquartered in vibrant and fast-growing Boise, Idaho, has been a locally operated
energy company since 1916. Today, it serves a 24,000-square-mile area in Idaho and Oregon.
The company’s goal to provide 100% clean energy by 2045 builds on its long history as a clean-energy
leader that provides reliable service at affordable prices. With 17 low-cost hydroelectric projects at the
core of its diverse energy mix, Idaho Power’s residential, business and agricultural customers pay among
the nation’s lowest prices for electricity. Its 2,000 employees proudly serve more than 600,000
customers with a culture of safety first, integrity always and respect for all.
IDACORP Inc. (NYSE: IDA), Idaho Power’s independent publicly traded parent company, is also
headquartered in Boise, Idaho. To learn more, visit idahopower.com or idacorpinc.com.
Jordan Rodriguez
Communications Specialist
[e-mail]
208-388-2460

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

REQUEST NO. 2

ATTACHMENT NO. 5
1
From:John Hammond <[e-mail]>
Sent:Wednesday, November 17, 2021 9:45 AM
To:Nordstrom, Lisa
Subject:[EXTERNAL]RE: IPC's 2022-2023 PCA Audit
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify
the sender before proceeding, and check for additional warning messages below.
Lisa,

Thank you. I will take a look at get back with you on this.

John R. Hammond Jr. | Office of the Attorney General
Lead Deputy Attorney General
Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg. 8, Suite 201-A
P.O. Box 83720
Boise, Idaho 83720-0074
Direct: [phone] | Fax: [phone]
[e-mail]

NOTICE: The e-mail may be confidential, privileged, and exempt from public disclosure, and the sender intends that it
be used only by the individual or entity named above. If you are not the intended recipient, then you may not use,
disclose, copy, or distribute the e-mail or its contents. If you believe you have received this e-mail in error, please
immediately notify the sender and delete the copy you received.

From: Nordstrom, Lisa <[e-mail]>
Sent: Wednesday, November 17, 2021 9:44 AM
To: John Hammond <[e-mail]>
Cc: Annis, Mark <[e-mail]>; Gust, Stacy <[e-mail]>
Subject: IPC's 2022-2023 PCA Audit

Good morning John,

After Idaho Power’s November 3rd Customer Advisory Group meeting, Kathy Stockton advised Idaho Power that she
would like to receive a copy of the power point presentation in anticipation of the spring PCA audit. Idaho Power is
amenable to sharing it with Staff and notes that it contains pricing triggers that dictate Idaho Power’s participation in
the wholesale market.

To protect this sensitive information from public disclosure, would Staff mind signing the 2022-2023 PCA Audit
Protective Agreement a little earlier than normal? I’ve attached the usual agreement for your review or assignment to
the appropriate attorney.

Thanks for helping to facilitate this,

Lisa Nordstrom
LEAD COUNSEL
Idaho Power | Legal
2
Office 208-388-5825 | Mobile [phone]

IDAHO POWER LEGAL DISCLAIMER
This transmission may contain information that is privileged, confidential and/or exempt from disclosure
under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure,
copying, distribution, or use of the information contained herein (including any reliance thereon) is STRICTLY
PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the
material in its entirety, whether in electronic or hard copy format. Thank you.
1
From:Reyna Quintero <[e-mail]>
Sent:Thursday, February 10, 2022 3:25 PM
To:Nordstrom, Lisa; Larkin, Matt; Tatum, Tim; Fewkes, David; IPCDockets
Cc:Kathy Stockton
Subject:[EXTERNAL]First Audit Request of the Commission Staff to Idaho Power Company in the
2022 PCA
Attachments:Idaho Power 2022 PCA Audit Request 1.pdf
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify
the sender before proceeding, and check for additional warning messages below.
Good afternoon,

Attached please find the First Audit Request of the Commission Staff to Idaho Power Company in the
above-referenced matter.

Regards,

Reyna Quintero | Utilities Administrative Assistant
Idaho Public Utilities Commission
11331 W. Chinden Blvd., Building 8, Suite 201-A
P.O. Box 83720
Boise, Idaho 83720-0074
Direct: [phone] | Fax: [phone]
[e-mail]

CONFIDENTIALITY NOTICE: This e-mail may be confidential, privileged, and exempt from public disclosure, and the
sender intends that it be used only by the individual or entity named above. If you are not the intended recipient, then you
may not use, disclose, copy, or distribute the e-mail or its contents. If you believe you have received this e-mail in error,
please immediately notify the sender and delete the copy you received.

Idaho Public Utilities Commission Bradt.ittle,Govemor
P.O. Box 83720,Bolse,ID 83720.0074 Eric Anderson,President
John Chatbum,Commissioner
John R.Hammond,)r.,Commissioner
February 10,2022
David Fewkes
Idaho Power Company
P.O.Box 70
Boise,Idaho 83707
Dear Mr.Fewkes,
Given the expeditednature of the PCA filing process, the Idaho Public Utilities
Commission Staff("Staff")will begin its review of the records associated with Idaho Power's
forthcomingApplication to change rates throughthe Power Cost Adjustment mechanism
("PCA").The scope of this initial review will be the months of April 2021 through December
2021 and the remaining months,January through March,will be reviewed when the PCA is filed
in April 2022.
Staffwould like to begin a virtual audit of the confidential materials,on a platform that is
mutually convenient.Staffrequests that written Audit Responses be provided as soon as
possible but no later than THURSDAY,FEBRUARY 24, 2022.Please mark confidential
informationas CONFIDENTIAL and provide it on yellowpaper.In addition to any written
responses, please provide CDs with any spreadsheets in their native Excel format with all
formulas intact.
Audit Request No.1:Please provide access to the PCA book and all supporting
documentation for the PCA deferral calculations.
Audit Request No.2: Please provide the Risk Management Committee Meeting
minutes that cover the entire PCA period.Please also provide a copy of the latest Risk
Management Policy and Guidelines.
Audit Request No.3: Please provide copies of the operating plans and other reports that
were presented to the Risk ManagementCommittee during the PCA period.
11331 W. Chinden Blvd., Building 8 5ulte 201-A, Bolse ID 83714
Telephone:[phone] Facsimile:[phone]
David Fewkes
February 10,2022
Page 2
Audit Request No.4: Please provide a copy of the latest natural gas procurement
guidelines that are used to procure natural gas for the Danskin,Bennett Mountain,and Langley
Gulch facilities.
Audit Request No.5:Staff would like to review the off-system sales and purchases
included in this year's PCA filing.Please provide a month-by-monthlisting of all the sales and
purchases,for all months in this PCA filing.Please provide this data in an electronic format with
all formulas intact.
Audit Request No.6:Staff would like to review the fuel expenses,specifically the
invoices supporting the purchases for coal and natural gas during this PCA period.Please
identify gas purchases for each facility at Danskin, Bennett Mountain,and Langley Gulch.
Please also provide coal purchases for each unit at Jim Bridger and Valmy.To facilitate this
review,please provide a listing of all the fuel expenses,listed by month, for this PCA filing.
Audit Request No.7:Please provide the total MWh produced by the Danskin plants,
the Bennett Mountain plant;and the Langley Gulch plant during the PCA period.Please show
the dates and times each plant operated.
Audit Request No.8:Please provide the total MWh produced by the Jim Bridger and
Valmy plants during the PCA period. Please show the dates and times each plant operated.
Audit Request No.9:Please provide all workpapers and documentation for actual
Third-Party Transmission expenses for the PCA period.
Audit Request No.10: Please provide all workpapers and documentation for the
Renewable Energy Credit sales for the PCA period.
Audit Request No. 11:Please provide all workpapers and documentation for the
Demand Response incentive payments for the PCA period.
Audit Request No.12: Please provide all workpapers and documentation for the actual
QualifyingFacilities payments for the PCA period.
Audit Request No.13: Please provide a list of the daily Mid-C prices for the PCA
period, including heavy load and light load hours.
Audit Request No.14: Please provide the workpapers showing the calculations for
actual Idaho Jurisdictional Billing Month Sales for the PCA period.
David Fewkes
February 10,2022
Page 3
Audit Request No.15:Please provide the workpapers showing the monthlycollections
for the PCA period.
Audit Request No.16: Please provide copies or access to workpapers, memoranda, and
reports that document any external and internal reviews performed on any PCA components for
the PCA period. Please include within your response any documentationprepared for Sarbanes-
Oxley("SOX"),internal audit, external audit,and other jurisdictional inquiries and
commumcations.
Audit Request No.17: To the extent not provided in Audit Request No.16,please
provide a list of all Internal Audit department audits and reviews that were performed within the
last three years or are planned to be performed associated with any components of the PCA.
Please include within your response a contact name to obtain copies and discuss the audits.
Audit Request No. 18:To the extent not already provided in Audit Request No.16,
please provide workpapers related to SOX and/or Internal Audit review of the actual power
costs,such as those identifyingand testing key controls. Please also include within your response
any issues that were identified,and the Company's response to the identified issues.
Audit Request No.19: Please provide a copy of all reports that discuss major
operational issues with any component of the Company's generationfleet during the PCA period.
Audit Request No.20: Please provide a list of all fuel hedge transactions completed
during the PCA period.
Audit Request No. 21:Please provide the monthlyrun rate dispatch prices for all fuel
plants included in the PCA period.
Audit Request No. 22:Please provide all supporting documentation for the Water for
Power expense incurred during the PCA period.
Audit Request No. 23:Please provide all workpapers and documentation for the Energy
ImbalanceMarket ("EIM")Participation costs for the PCA period.
Audit Request No.24:Please provide a list of all Company resources that are
participating in the EIM.Please also provide any limits on those resources that are participating
in the EIM.
David Fewkes
February 10,2022
Page 4
If it appears that a response will take longer,please call to work out any necessary timing
changes.Review of the requested documents may require additional written (e-mail)or verbal
inquiries. If you have any questions regarding the above audit requests, please do not hesitate to
contact me at [phone] or by e-mail at kathv.stockton puc.idaho.cov or Donn English at
[phone] or [e-mail] you for your cooperation and
assistance.
Sincerely,
Kathy Stockton
Senior Auditor
e-mail: Inordstrom idahopower.com
[e-mail]
ttatum idahopower.com
[e-mail]
From:Gust, Stacy
Sent:Thursday, February 24, 2022 4:22 PM
To:Nordstrom, Lisa; Fewkes, David; White, Tami
Subject:FW: Idaho Power Company's 2022-2023 PCA
Attachments:Protective Agreement - 22-23 PCA.pdf
FYI.

Stacy Gust
REGULATORY ADMINISTRATIVE ASSISTANT
Idaho Power | Regulatory Affairs
Office 208-388-5749

From: Keri Hawker <[e-mail]>
Sent: Thursday, February 24, 2022 4:21 PM
To: Gust, Stacy <[e-mail]>
Subject: [EXTERNAL]RE: Idaho Power Company's 2022-2023 PCA

KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify
the sender before proceeding, and check for additional warning messages below.
Hi Stacy,

The attached is signed.

Keri Hawker | Legal Administrative Assistant
Idaho Public Utilities Commission

From: Gust, Stacy <[e-mail]>
Sent: Tuesday, February 22, 2022 2:57 PM
To: Keri Hawker <[e-mail]>
Subject: Idaho Power Company's 2022-2023 PCA

Hi Keri,

Could you please check on whether you have a signed copy of the attached Protective Agreement from John Hammond
attorney handling this matter in advance of Idaho Power Company’s response to the audit requests we received.

Thank you.

Stacy Gust
REGULATORY ADMINISTRATIVE ASSISTANT
Idaho Power | Regulatory Affairs
Office 208-388-5749

2
IDAHO POWER LEGAL DISCLAIMER
This transmission may contain information that is privileged, confidential and/or exempt from disclosure
under applicable law. If you are not the intended recipient, you are hereby notified that any disclosure,
copying, distribution, or use of the information contained herein (including any reliance thereon) is STRICTLY
PROHIBITED. If you received this transmission in error, please immediately contact the sender and destroy the
material in its entirety, whether in electronic or hard copy format. Thank you.
2022-2023 POWER COST ADJUSTMENT – PROTECTIVE AGREEMENT - 1
PROTECTIVE AGREEMENT BETWEEN
IDAHO POWER COMPANY AND IDAHO PUBLIC UTILITIES COMMISSION STAFF (AND OTHER PARTIES AS APPLICABLE) 2022-2023 Power Cost Adjustment
This Protective Agreement is entered into this 17th day of November 2021 by Idaho Power
Company (“Idaho Power”) and the Idaho Public Utilities Commission Staff, and other parties as
applicable.
Recitals:
1. WHEREAS, Idaho Power and the Idaho Public Utilities Commission Staff anticipate
that parties to this proceeding may make requests to provide, or make available for review, certain
information, considered by its custodian to be of a trade secret, privileged or confidential nature
(as defined in Idaho Code §§ 74-107 through 74-109 and 48-801).
2. WHEREAS, Idaho Power and the undersigned parties agree that entering into a
Protective Agreement will expedite the production of documents; will afford the necessary
protection to Idaho Power’s and the undersigned parties’ employees and/or representatives
evaluating the 2022-2023 Power Cost Adjustment who might review the information and
subsequently be requested to reveal its contents by setting forth clear cut parameters for use of
Confidential Information, and will protect Confidential Information which might be provided
during the course of the proceedings, now therefore.
IT IS HEREBY STIPULATED AND AGREED AS FOLLOWS:
1. (a) Confidential Information
All documents, data, information, studies and other materials furnished pursuant to any
requests for information, subpoenas or other modes of discovery (formal or informal), and
including depositions, that are claimed to be of trade secret, proprietary or confidential nature
(herein referred to as “Confidential Information”) shall be so marked by the party or entity
providing the information by stamping the same with a designation indicating its trade secret,
proprietary or confidential nature and printed on “yellow” paper. IDAPA 31.01.01.067. Any
claim of confidentiality must be accompanied by an attorney’s certificate that the material is
protected by law from public disclosure and cite the specific legal authority to support the claim.
IDAPA 31.01.01.233.

2022-2023 POWER COST ADJUSTMENT – PROTECTIVE AGREEMENT - 2
(b) Protection of Confidential Information
Access to and review of Confidential Information shall be strictly controlled by the terms
of this Agreement. Unless otherwise ordered, Confidential Information, including transcripts of
depositions containing information to which a claim of confidentiality is made, shall remain under
seal, shall continue to be subject to the protective requirements of this Agreement, and shall not
be disclosed to individuals who have not executed the nondisclosure agreement set forth in Exhibit
“A.”
(c) Use of Confidential Information
All persons who may be entitled to review, or who are afforded access to any Confidential
Information by reason of this Agreement shall neither use nor disclose the Confidential
Information for purposes of business or competition, or any purpose other than the purpose of
preparation for and conduct of the proceedings, and then solely as contemplated herein, and shall
keep the Confidential Information secure as trade secret, confidential or proprietary information
and in accordance with the purposes and intent of this Agreement.
(d) Persons Entitled to Review
Access to Confidential Information shall be limited to counsel of the undersigned parties,
employees, experts, agents or representatives of the undersigned parties who have executed an
Exhibit “A” to this Agreement. Such information will be clearly marked and protected from
unauthorized public disclosure.
(e) Non-disclosure Agreement
Confidential Information shall not be disclosed to any person who has not signed a non-
disclosure agreement on this form, which is attached hereto as Exhibit “A” and incorporated
herein. The non-disclosure agreement or Exhibit “A” shall require the person to whom disclosure
is to be made to read a copy of this Protective Agreement and to certify in writing that he or she
has reviewed the same and has consented to be bound by its terms. The Agreement shall contain
the signatory’s full name, permanent address and employer. Such agreement shall be delivered to
counsel for the providing party, before disclosure is made.
2. Copies
No copies or transcriptions of the Confidential Information shall be made by the recipient
except as necessary to make the information available to individuals who have executed an Exhibit
“A” to this Protective Agreement.

2022-2023 POWER COST ADJUSTMENT – PROTECTIVE AGREEMENT - 3
3. Non-waiver of Objection to Admissibility
The furnishing of any document, information, data, study or other materials pursuant to
this Protective Agreement shall in no way limit or waive the right of the providing party to object
to its relevance or admissibility in any proceedings before this Commission.
4. Challenge to Confidentiality
(a) Initial Challenge
This Protective Agreement establishes a procedure for the expeditious handling of
information that a party claims is confidential. Any party may challenge the characterization of
any information, document, data or study claimed by the providing party to be a trade secret,
proprietary or confidential information. A party seeking to challenge the confidentiality of any
information shall first contact counsel for the providing party and attempt to resolve any difference
by stipulation. Resolution may include removing the confidential classifications, creating a non-
confidential summary, reformatting the information, etc.
(b) Subsequent Challenge
In the event that the parties cannot agree as to the character of the information challenged,
any party challenging the confidentiality may petition the Commission to rule upon the disputed
information. The Petition shall be served upon the Commission and all parties to the case who
have signed an Exhibit “A” as provided in this Protective Agreement. The Petition shall designate
with specificity the document or material challenged and state the grounds upon which the subject
material are deemed to be non-confidential by the challenging party.
(c) Challenge Hearing
The challenging party shall request that the Commission conduct an in camera proceeding
where only those persons duly authorized to have access to such challenged materials under this
Protective Agreement shall be present. This hearing shall be commenced no earlier than five (5)
business days after serving the Petition on the providing party and the Commission. The record
of the in camera hearing shall be marked “CONFIDENTIAL – Subject to Protective
Agreement.” To the extent necessary, the transcript of such hearing shall be separately bound,
segregated, sealed, and withheld from public inspection by any person not bound by the terms of
this Agreement.

2022-2023 POWER COST ADJUSTMENT – PROTECTIVE AGREEMENT - 4
(d) Determination
The parties will ask the Commission to issue an Order determining whether any challenged
information or material is not properly deemed to be exempt from public disclosure pursuant to
the
Idaho Public Records Act (Idaho Code §§ 74-101 through 74-126). If information is found
to be not exempt from disclosure, no party shall disclose such challenged material or use it in the
public record, or otherwise outside the proceedings for at least five (5) business days unless the
providing party consents to such conduct. This procedure enables the restrictions of this
Agreement from material claimed to be confidential. Such relief may be sought from the
Commission or a court of competent jurisdiction.
5. (a) Receipt Into Evidence
Provision is hereby made for receipt into evidence in this proceeding of materials claimed
to be confidential in the following manner:
(1) If the requesting party intends to use Confidential Information or to make
substantive reference to Confidential Information supplied to it under this Agreement, it shall give
reasonable prior notice of such intention to the providing party and shall provide copies of the used
Confidential Information or substantive reference to Confidential Information only to the
providing party, and such other parties, if any, who have executed an Exhibit “A” to this Protective
Agreement.
(2) One (1) copy of the used Confidential Information or substantive reference to
Confidential Information or substantive reference to Confidential Information described in
paragraph 5(a)(1) shall be placed in the sealed record.
(3) The copy of the documents to be placed in the sealed record shall be tendered
by counsel for the providing party to the Commission, and shall be maintained in accordance with
the terms of this Protective Agreement.
(b) Seal
While in the custody of the Commission, materials containing Confidential Information
shall be marked “CONFIDENTIAL – SUBJECT TO ATTORNEY’S CERTIFICATE OF
CONFIDENTIALITY” and shall not be examined by any person except under the conditions set
forth in this Agreement, if applicable.

2022-2023 POWER COST ADJUSTMENT – PROTECTIVE AGREEMENT - 5
(c) In Camera Hearing and Transcripts
Any Confidential Information that must be orally disclosed at a hearing in the proceedings
shall be offered at an in camera hearing, attended only by persons authorized to have access to the
information under this Protective Agreement. Similarly, any transcription of any examination or
other reference to Confidential Information (or that portion of the record containing Confidential
Information) shall be marked and treated as provided herein for Confidential Information.
(d) Access to Record
Access to sealed testimony, records, and information shall be limited to the Commission
and persons who have signed an Exhibit “A” as provided in this Protective Agreement, unless such
information is released from the restrictions of this Agreement either through agreement of the
parties or after notice to the parties and hearing, pursuant to the order of the Commission and/or
the final order of a court having final jurisdiction.
(e) Appeal
Should an appeal from the proceeding be taken, sealed portions of the record may be
forwarded to any court of competent jurisdiction for purposes of an appeal, but under seal as
designated herein for the information and use of the court. If a portion of the record is forwarded
to a court under seal for the purposes of an appeal, the providing party shall be notified which
portion of the sealed record has been designated by the appealing party as necessary to the record
on appeal.
6. Use in Pleadings
Where references to Confidential Information in the sealed record or with the custodian is
required in pleadings, briefs, arguments, or motions (except as provided in Paragraph 5), it shall
be by citation to title or exhibit number or some other description that will not disclose the
substantive Confidential Information contained therein. Any use of or substantive references to
Confidential Information shall be placed in a separate section of the pleading or brief and submitted
to the Commission pursuant to Paragraph 5. This sealed section shall be served only on counsel
of record who have signed the nondisclosure agreements set forth in Exhibit “A” attached to this
Protective Agreement, and may, in turn, be disclosed by them only to individuals who likewise
signed Exhibit “A”.

2022-2023 POWER COST ADJUSTMENT – PROTECTIVE AGREEMENT - 6
7. Summary of Record
If deemed necessary by the Commission, the providing parties shall prepare a written
summary of the Confidential Information referred to in Orders to be issued to the public and the
parties.
8. Return or Destruction of Confidential Information
(a) Upon request of the providing party, all original documents and copies of the
Confidential Information shall be: (1) returned to the providing party; or (2) or at the option of the
recipient destroyed within thirty (30) days after the final settlement or conclusion of the
proceedings, including administrative or judicial review thereof. After return or destruction of
documents pursuant to this paragraph, and upon request, a written receipt verifying return or
destruction shall be provided by counsel.
(b) On a case-by-case basis and upon notification to the utility, the Commission Staff
may retain one copy of the Confidential Information under seal. Notwithstanding any other
provision in this Agreement, any member of Staff may review and use that copy of the Confidential
Information outside this proceeding while performing his or her duties as a Staff member. Staff’s
use and disclosure of the Confidential Information in a later Commission proceeding shall be
subject to any protective agreement signed in the proceeding.
(c) Any notes maintained by a recipient of Confidential Information which embody
or reflect any of the Confidential Information provided under this Agreement shall, upon request
of the providing party, be either returned to the providing party or, at the option of the recipient,
destroyed.
9. Effective Date
This Protective Agreement shall become effective on the date hereof.

///
///
///
///
///
///
2022-2023 POWER COST ADJUSTMENT – PROTECTIVE AGREEMENT - 7

DATED this 17th day of November 2021.
IDAHO POWER COMPANY By: Lisa D. Nordstrom
Idaho Power Company
1221 West Idaho Street Boise, Idaho 83702 Attorney Representing Idaho Power Company
IDAHO PUBLIC UTILITIES COMMISSION STAFF By:
Dayn Hardie Deputy Attorney General Idaho Public Utilities Commission 11331 W. Chinden Blvd., Bldg 8, Suite 201-A (83714)
PO Box 83720 Boise, Idaho 83720-0074 Attorney Representing the Idaho Public Utilities Commission Staff

1
From:Reyna Quintero <[e-mail]>
Sent:Tuesday, March 29, 2022 5:31 PM
To:Nordstrom, Lisa; Larkin, Matt; Tatum, Tim; Fewkes, David; IPCDockets
Cc:Kathy Stockton
Subject:[EXTERNAL]Second Audit Request of the Commission Staff to Idaho Power Company in
the 2022 PCA
Attachments:Idaho Power 2022 PCA Audit Request 2.pdf
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify
the sender before proceeding, and check for additional warning messages below.
Good afternoon,

Attached please find the Second Audit Request of the Commission Staff to Idaho Power Company
above-referenced matter.

Regards,

Reyna Quintero | Utilities Administrative Assistant
Idaho Public Utilities Commission
11331 W. Chinden Blvd., Building 8, Suite 201-A
P.O. Box 83720
Boise, Idaho 83720-0074
Direct: [phone] | Fax: [phone]
[e-mail]

CONFIDENTIALITY NOTICE: This e-mail may be confidential, privileged, and exempt from public disclosure, and the
sender intends that it be used only by the individual or entity named above. If you are not the intended recipient, then you
may not use, disclose, copy, or distribute the e-mail or its contents. If you believe you have received this e-mail in error,
please immediately notify the sender and delete the copy you received.

Idaho Public Utilities Commission Brad Little,Govemor
P.O.Box 83720,Boise,ID 83720·0074 Eric Anderson,President
John Chatbum,Commissioner
John R.Hammond,Jr.,Commissioner
March 29, 2022
David Fewkes
Idaho Power Company
P.O.Box 70
Boise,Idaho 83707
Dear Mr.Fewkes,
Given the expedited nature of the PCA filing process, the Idaho Public Utilities
Commission Staff ("Staff")will begin its review of the records associated with Idaho Power's
forthcoming Application to change rates through the Power Cost Adjustment mechanism
("PCA").The scope of this initial review will be the months of April 2021 through December
2021 and the remaining months, January through March, will be reviewed when the PCA is filed
in April 2022.
Staff requests that written Audit Responses be provided as soon as possible but no later
than WEDNESDAY,APRIL 13,2022. Please mark confidential information as
CONFIDENTIAL and provide it on yellowpaper.In addition to any written responses, please
provide CDs with any spreadsheets in their native Excel format with all formulas intact.
Audit Request No.25:As a follow-up to Audit Request No.3,"Op Plans and
Supporting Docs," please define the terms and provide a narrative description for each item in
the strategy column in the Hedging Data for HL and LL.See pages 31-39 of 378 of
"CONFIDENTIAL Attachment -Response to Staffs AR 3 -Op Plans and Supporting Does.pdf"
as an example.
Audit Request No. 26: As a follow-up to Audit Request No.5,please provide the
supporting documentation and source documents for the off-system sales and purchases
transactions Staff has selected.Staff's selection will be uploaded to the secure FTP site,"Staff
Audit Data Room:"to the folder named "Staff Selections."
Audit Request No. 27:As a follow-up to Audit Request No.6,please provide the
journal entries and supporting documentation for the coal journals for the months of June 2021
and November 2021; and for the natural gas journalsfor the months of July2021 and October
2021.
11331W. Chinden Blvd.,Building 8 Suite 201.A,Bolse ID 83714
Telephone:[phone] Facsimile:[phone]
David Fewkes
March 29, 2022
Page 2
Audit Request No.28:As a follow-up to Audit Request No.9,Transmission Expense,
please provide the supporting documentation and source documents for the transactions Staff has
selected.Staff's selection will be uploaded to the secure FTP site,StaffAudit Data Room to the
folder named "Staff Selections."
Audit Request No. 29: As a follow-up to Audit Request No.10,Renewable Energy
Credit Sales,please provide supporting documentation,such as invoices,contracts,and/or
receipts,for the followingRenewable Energy Credit sales in 2021:
a.3Phases Renewables in April 2021(multiple purchases);
b.3PR Trading in June 2021;and
c.Green-e Certification Fees in December 2021.
Audit Request No. 30: As a follow-up to Audit Request No.11,Demand Response
IncentivePayments, please provide the supporting documentationand source documents for the
transactions Staffhas selected.Staffs selection will be uploaded to the secure FTP site,"Staff
Audit Data Room"to the folder named "Staff Selections."
Audit Request No. 31: As a follow-upto Audit Request No.12,please provide the
invoices,supporting documentation,and source documents for the followingtransactions:
Date Project Name
Dec 2021 Rockland Wind Farm
August 2021 Golden Valley Wind Park
July 2021 ID Solar 1
May 2021 Two Ponds Windfarm
April 2021 Fossil Gulch Wind
If it appears that a response will take longer,please call to work out any necessary timing
changes.Review of the requested documents may require additional written(e-mail)or verbal
inquiries.If you have any questions regarding the above audit requests, please do not hesitate to
contact me at [phone] or by e-mail at kathv.stocktongpuc.idaho.covor Donn English at
[phone] or donn.enalishgpuc.idaho.cov.Thank you for your cooperationand
assistance.
Kathy Stockton
Senior Auditor
E-mail:Inordstrom idahopower.com
pilgrhin idphopower.com
[e-mail]
DFewkegaldphopower.com
1
From:Jo Nelson <[e-mail]>
Sent:Friday, April 22, 2022 3:05 PM
To:Nordstrom, Lisa; Larkin, Matt; Tatum, Tim; Brady, Jessi; IPCDockets
Cc:Dayn Hardie
Subject:[EXTERNAL]First Production Request of the Commission Staff to Idaho Power Company
in Case No. IPC-E-22-11
Attachments:ipce22.11dhkls prod req 1.pdf
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify
the sender before proceeding, and check for additional warning messages below.

DAYN HARDIE
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE,IDAHO 83720-0074
[phone]
IDAHO BAR NO.9917
Street Address for Express Mail:
11331 W CHINDEN BVLD,BLDG 8,SUITE 201-ABOISE, ID 83714
Attorneyfor the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )OF IDAHO POWER COMPANY FOR )CASE NO.IPC-E-22-11AUTHORITYTOIMPLEMENTPOWER)COST ADJUSTMENT ("PCA")RATES FOR )FIRST PRODUCTIONELECTRICSERVICEFROMJUNE1,2022,)REQUESTOF THETHROUGHMAY31, 2023 )COMMISSION STAFF TO
)IDAHO POWER COMPANY
The Staff of the Idaho Public Utilities Commission,by and through its attorney of
record,Dayn Hardie,Deputy Attorney General, request that Idaho Power Company ("Company"
or "Idaho Power")provide the followingdocuments and information as soon as possible,or by
TUESDAY,MAY 3,2022.1
This Production Request is continuing,and the Company is requested to provide,by way
of supplementary responses,additional documents that it or any person acting on its behalf may
later obtain that will augment the documents produced.
Please provide answers to each question,supporting workpapers that provide detail or are
the source of information used in calculations.The Company is reminded that responses
*Staffis requesting an expedited response.If responding by this date will be problematic,please call Staff'sattorneyat(208)334-0312.
FIRST PRODUCTIONREQUEST
TO IDAHO POWER COMPANY l APRIL 22, 2022
pursuant to Commission Rules of Procedure must include the name and phone number of the
person preparing the document, and the name,location,and phone number of the record holder
and if different the witness who can sponsor the answer at hearing if need be. See IDAPA
31.01.01.228.
In addition to the written copies provided as response to the questions,please provide all
Excel and electronic files on CD with formulas activated.
REQUESTNO.1:Please provide a list of all Idaho Power customers who purchased
Company-owned Renewable Energy Credits ("RECs")that are being passed through the Power
Cost Adjustment ("PCA")Schedule 55.Please include in the response the fuel type for the
RECs, purchase price,quantityof RECs, and date purchased.
REQUESTNO.2:Please provide all workpapers used to derive the final figures
included in the exhibits in electronic format with all formulas intact.
REQUESTNO.3:Please provide the monthlynumber of megawatt-hours ("MWh")
associated with the system base and actual net power costs for all Net Power Supply Expense
("NPSE")Accounts includingFederal Energy Regulatory Commission ("FERC")accounts 501
(Coal),account 536 (Water for power),account 547 (Gas),account 555 (Non-PURPA),account
565 (3rd party transmission),account 447 (Surplus Sales),account 555,(PURPA),and account
555 (Demand Response Incentives).
REQUESTNO.4:Did the Company re-distribute or smooth base NPSE in this year's
filing?If so,please provide workpapers that reflect the calculations/method used to derive the
revenue-smoothed (redistributed)base NPSE included in Exhibit No.2 from the Aurora
generated NPSE that was last authorized by the Commission for the deferral period for all NPSE
accounts.Please include all workpapers in electronic format with calculations intact.
REQUESTNO.5:Please provide supporting data on the reservoir levels for the Upper
Snake River Basin for both current and 2023 forecasted amounts.
FIRST PRODUCTION REQUEST
TO IDAHO POWER COMPANY 2 APRIL 22,2022
REQUESTNO.6:Please provide the length of time and amount of production in MWhs
lost for forced downtime (unscheduled)that Company-owned generationfacilities/units
experienced each month during the deferral period.For each forced downtime,please explain the
cause and resolution of the downtime
REQUESTNO.7:Please provide all Company-owned facility/unit unforced downtime
(scheduled)including the date range,length of time,and reason that occurred during the deferral
period.
DATED at Boise,Idaho,this day of April 2022.
DEÿii'ÍIardi
Deputy Att ey General
i:umisc:prodreq/ipce22.11dhkls prod reql
FIRST PRODUCTIONREQUEST
TO IDAHO POWER COMPANY 3 APRIL 22, 2022
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 22ND DAY OF APRIL 2022,SERVED THE FOREGOING FIRST PRODUCTION REQUESTOF THECOMMISSIONSTAFFTOIDAHOPOWERCOMPANY,IN CASE NO.IPC-E-22-11,BY E-MAILING A COPY THEREOF,TO THE FOLLOWING:
LISA NORDSTROM MATTHEW LARKINIDAHOPOWERCOMPANYTIMOTHYTATUMPOBOX70JESSIBRADYBOISEID83707-0070 IDAHO POWER COMPANYE-MAIL:[e-mail] PO BOX [e-mail] BOISE ID 83707-0070
E-MAIL:[e-mail]
[e-mail]
[e-mail]
SECRETARY
CERTIFICATEOF SERVICE
1
From:Nordstrom, Lisa
Sent:Friday, April 29, 2022 3:02 PM
To:Dayn Hardie
Cc:Larkin, Matt; Brady, Jessi
Subject:FW: PCA Application/Testimony Numbers
Dayn,

In response to your question about how the forecast and balancing adjustment numbers reconcile between page 6 of
the Application and page 6 of Brady’s testimony, please see Jessi’s explanation below. If this doesn’t answer your
question, please let us know and we can set up a call.

Wishing you a great weekend,

Lisa Nordstrom
LEAD COUNSEL
Mobile

From: Brady, Jessi <[e-mail]>
Sent: Friday, April 29, 2022 2:56 PM
To: Nordstrom, Lisa <[e-mail]>
Subject: PCA Application/Testimony Numbers

Hi Lisa,

the application helps clear things up!

- “The system-level forecast of NPSE for the 2022-2023 PCA Year is $498,834,556, which is $193,149,687 higher
than the currently approved base level NPSE of $305,684,869.”
o This compares the total forecast amount with our approved base NPSE - table 2 on page 8 of testimony.

2
-
- “The 2022-2023 PCA forecast component to be collected from Idaho customers is $178,795,145.”
o This matches the number from Table 1, which is on page 6 of testimony

-
- “the system-level forecast of NPSE for the 2022-2023 PCA Year is $56,477,149 higher than last year’s forecast
amount of $442,357,407.”
o This is comparing the total forecast amount of 498,834,556 to last year’s total forecast of 442,357,407 –
table 3 on page 11 of testimony

3
-
- “The PCA Balancing Adjustment deferral balance at the end of March 2022, with interest applied, was
approximately $38.7 million”
o This matches the balancing adjustment number from Table 1 above (38,664,487)

Please let me know if I can help clarify further!

Thanks,
Jessi

Jessi Brady
Regulatory Analyst
Idaho Power | Regulatory Affairs
Work [phone]
Email [e-mail]

1
From:Angie Velasquez <[e-mail]>
Sent:Monday, May 2, 2022 2:52 PM
To:Dr. Don Reading; IPCDockets; Nordstrom, Lisa; Larkin, Matt; Peter J Richardson; Tatum,
Tim
Subject:[EXTERNAL]Idaho Power Co Case No. IPC-E-22-11
Attachments:Intervention Order No 35389.pdf
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify
the sender before proceeding, and check for additional warning messages below.
Attached is Intervention Order No. 35389 in Case No. IPC-E-22-11.

Thank you,

Angie Velasquez
Technical Records Specialist I

Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg. 8, Ste. 201-A
Boise, ID 83714
208-334-0341
E-mail: [e-mail]

CONFIDENTIALITY NOTICE: This e-mail may be confidential, privileged, and exempt from public disclosure, and the sender intends
that it be used only by the individual or entity named above. If you are not the intended recipient, then you may not use, disclose, copy,
or distribute the e-mail or its contents. If you believe you have received this e-mail in error, please immediately notify the sender and
delete the copy you received.

ORDER NO. 35389 1

Office of the Secretary Service Date
May 2, 2022
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
The Industrial Customers of Idaho Power (“ICIP”) petitioned to intervene in this case
on April 22, 2022, pursuant to Rules of Procedure 71 through 75 of the Idaho Public Utilities
Commission, IDAPA 31.01.01.071-.075.
FINDINGS OF FACT
We find that no party timely opposed this Petition to Intervene.
We further find that based on the pleadings and other documents filed in this case,
intervention by this party would serve the purposes of intervention as described by Rule 74 of the
Rules of Procedure and should be granted.
O R D E R
IT IS THEREFORE ORDERED that the Petition to Intervene filed by ICIP is granted.
IT IS FURTHER ORDERED that all parties comply with all rules of the Commission
including Rules of Procedure 71 through 75, and 222 through 223 of the Idaho Public Utilities
Commission, IDAPA 31.01.01.071-.075, .222-.223.
IT IS FURTHER ORDERED that all parties in this proceeding serve all papers
hereafter filed in this matter on all parties of record. This Intervenor is represented by the following
for purposes of service:
ICIP:
Peter J. Richardson
Richardson Adams, PLLC 515 N. 27th Street Boise, ID 83702 [e-mail]

Dr. Don Reading
6070 Hill Road Boise, ID 83703 [e-mail]

IT IS FURTHER ORDERED that parties comply with Order No. 35375, issued April
21, 2022. Generally, all pleadings should be filed with the Commission electronically and will be
deemed timely filed when received by the Commission Secretary. See Rule 14.02. Service
IN THE MATTER OF IDAHO POWER COMPANY’S APPLICATION FOR AUTHORITY TO IMPLEMENT POWER COST ADJUSTMENT (“PCA”) RATES FOR ELECTRIC SERVICE FROM JUNE 1, 2022,
THROUGH MAY 31, 2023
) ) ) ) )
)
CASE NO. IPC-E-22-11 ORDER NO. 35389
ORDER NO. 35389 2

between parties should continue to be accomplished electronically when possible. However,
voluminous discovery-related documents may be filed and served on CD-ROM or a USB flash
drive.
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 2nd day
of May 2022.

ERIC ANDERSON, PRESIDENT

JOHN CHATBURN, COMMISSIONER
JOHN R. HAMMOND JR., COMMISSIONER ATTEST:
Jan Noriyuki Commission Secretary

I:\Legal\ELECTRIC\IPC-E-22-11 PCA\orders\IPCE2211_ICIP_in_dh.docx
1
From:Jan Noriyuki <[e-mail]>
Sent:Tuesday, May 3, 2022 9:18 AM
To:Dr. Don Reading; IPCDockets; Brady, Jessi; Nordstrom, Lisa; Larkin, Matt; Peter J
Richardson; Tatum, Tim
Subject:[EXTERNAL]Idaho Power Company Case No. IPC-E-22-11
Attachments:Order No 35392.pdf
KEEP IDAHO POWER SECURE! External emails may request information or contain malicious links or attachments. Verify
the sender before proceeding, and check for additional warning messages below.
Please find attached a Notice of Application / Notice of Modified Procedure for Case No. IPC-E-22-11.

Thank you,

Jan Noriyuki
Commission Secretary

Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg. 8, Ste. 201-A
Boise, ID 83714
208-334-0338
[e-mail]

Notice of Electronic Filing
Pursuant to Idaho Public Utilities Commission Order No. 35375, issued April 21, 2022, please accept this e-mail as confirmation of
your submittal being accepted for electronic filing.

NOTICE OF APPLICATION NOTICE OF MODIFIED PROCEDURE
ORDER NO. 35392 1
Office of the Secretary Service Date May 3, 2022
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION IN THE MATTER OF IDAHO POWER COMPANY’S APPLICATION FOR AUTHORITY TO IMPLEMENT POWER COST ADJUSTMENT (PCA) RATES FOR ELECTRIC SERVICE FROM JUNE 1, 2022 THROUGH MAY 31, 2023
) ) ) ) ) ) ) )
CASE NO. IPC-E-22-11 NOTICE OF APPLICATION NOTICE OF MODIFIED PROCEDURE ORDER NO. 35392

On April 15, 2022, Idaho Power Company (“Company”) applied for Commission
authorization to implement its Power Cost Adjustment (“PCA”) rates effective June 1, 2022,
through May 31, 2023. The Company requests its Application be processed by Modified Procedure
with an effective date of June 1, 2022. If approved, the Company’s PCA would increase rates for
all customer classes via an overall revenue increase of approximately $103.4 million, or 8.27
percent. Residential rates would increase 6.55 percent if approved as filed. Application at 1; see
also Attachment 2 to the Application.
The Commission now provides this Notice of Application and establishes comment
deadlines for interested persons and the Company’s reply.
THE PCA MECHANISM
The PCA mechanism permits the Company to increase or decrease its PCA rates to
reflect the Company’s annual “power supply costs.” Due to its diverse generation portfolio, the
Company’s actual cost of providing electricity (its power supply cost) varies from year to year
depending on changes in such things as the river streamflow, the amount of purchased power, fuel
costs, the market price of power, and other factors. The annual PCA surcharge or credit is
combined with the Company’s “base rates” to produce a customer’s overall energy rate. The
Company states that neither it nor its shareholders receive any financial return from the PCA –
money collected from the surcharge can be used only to pay power supply expenses. Application
at 2.
The PCA quantifies and tracks annual differences between actual Net Power Supply
Expenses (“NPSE”) and the normalized or “base level” of NPSE recovered in the Company’s base
rates, resulting in a credit or surcharge that is updated annually on, June 1. The PCA mechanism
NOTICE OF APPLICATION NOTICE OF MODIFIED PROCEDURE
ORDER NO. 35392 2
uses a 12-month test period of April through March (“PCA Year”) and includes a forecast
component and a Balancing Adjustment (formerly referred to as the “true-up” and the “true-up of
the true-up”). The forecast component represents the difference between the Company’s NPSE
forecast from the March Operating Plan and base level NPSE recovered in the Company’s base
rates. The Balancing Adjustment includes a backward-looking tracking of differences between the
prior PCA Year’s forecast and actual NPSE incurred by the Company, and also tracks the
collection of the prior year’s Balancing Adjustment.
In Order No. 35290, the commission approved a modification to the PCA filing to
replace the “true-up” and “true-up of the true-up” with a single balancing account. The two “true-
up” rates previously included in PCA filings are now combined into one “Balancing Adjustment”
rate. The Balancing Adjustment modification solely impacts the presentment of the PCA but has
no material impact on the rates charged to customers.
Except for Public Utility Regulatory Policies Act of 1978 (“PURPA”) expenses and
demand response incentive payments, the PCA allows the Company to pass through to customers
95 percent of the annual differences in actual NPSE as compared with base level NPSE, whether
positive or negative. With respect to PURPA expenses and demand response incentive payments
and actual annual expenses deviate from base level NPSE, the Company is allowed to pass 100
percent of the difference for recovery or credit through the PCA. The PCA is also the rate
mechanism used by the Company to provide customer benefits resulting from the revenue sharing
mechanism, approved by the Commission in Order No. 34071.
NOTICE OF APPLICATION
YOU ARE HEREBY NOTIFIED that this year’s PCA Application requests to increase
revenue through Schedule 55 by $103.4 million for the 2022-2023 PCA year. Application at 1.
YOU ARE FURTHER NOTIFIED that the Company system-level forecast for NPSE
is approximately $56.5 million higher in the 2022-2023 PCA year than 2021-2022 PCA year. The
forecast is primarily driven by the expected reduction in hydro generation and increases in natural
gas prices and market energy prices. Id. at 6. The Company also forecasts an increase in coal
generation to serve its load and an increase in surplus sales. Id.
YOU ARE FURTHER NOTIFIED that the Balancing Adjustment at the end of March
2022, including interest, was approximately $38.7 million and was primarily driven by a decrease
NOTICE OF APPLICATION NOTICE OF MODIFIED PROCEDURE
ORDER NO. 35392 3
in actual hydro generation and higher than forecast market purchases, but offset partially by surplus
sales.1 Id.
YOU ARE FURTHER NOTIFIED that under Order No. 34071, the Commission
requires the Company to share revenue with its customers if its Idaho jurisdictional year-end return
on equity (“ROE”) is 10.0 percent or greater. The Company asserts its Idaho jurisdictional year-
end ROE in 2021 was 10.02 percent requiring the Company to include $568,771 as the revenue
sharing component of the 2022-2023 PCA. Id. at 7.
YOU ARE FURTHER NOTIFIED that the Company’s uniform PCA rate for the 2022-
2023 PCA Year is comprised of (1) the 1.1926 cents per kilowatt-hour (“kWh”) adjustment for the
2022-2023 forecasted power cost of serving firm loads under the current PCA methodology and 5
percent sharing and (2) 0.2579 cents per kWh for the 2021- 2022 Balancing Adjustment. Id. at 6-
7. Together these two components result in an approximate 1.4505 cents per kWh charge for all
rate classes. Id. at 7.
YOU ARE FURTHER NOTIFIED that on March 15, 2022, the Company filed its
annual FCA in Case No. IPC-E-22-07. Id. The Company’s 2022 FCA filing proposes a $4.9
million decrease in current billed revenue, or a 0.81 percent decrease, for Idaho Residential and
Small General Service customers, effective June 1, 2022 through May 31, 2023. Id.
YOU ARE FURTHER NOTIFIED that on June 3, 2021 the Company applied to
increase rates to accelerate the depreciation schedule of coal-related investments at Bridger and
establish a balancing account to track the incremental costs and benefits associated with the
Company ending operations there. Id. at 8. If approved, the request for cost-recovery from Bridger
would increase total billed revenue by $27.1 million—an average of 2.17 percent for affected
customers. Id.
YOU ARE FURTHER NOTIFIED that if the PCA, FCA, and Bridger cost-recovery
applications are approved as filed, the combined impact is an overall increase in current billed
revenue of $125.6 million, or 10.05 percent. The impact by revenue class is:

1 The PCA Balancing Account for the 2022-2023 PCA year is approximately $38.7 million, which is about $57.0 million higher the 2021-2022 PCA year.
NOTICE OF APPLICATION NOTICE OF MODIFIED PROCEDURE
ORDER NO. 35392 4
Proposed 2022-2023 Revenue Impact by Class: Percentage Increase from Current Billed Rates by Proposed Change
Power Cost Adjustment
Residential
Small General Service
Large General Service
Large Power
Irrigation
6.55% 5.24% 9.28% 11.66% 8.46%
Fixed Cost Adjustment
Residential
Small General Service
Large General Service
Large Power
Irrigation
(0.81)% (0.82)% N/A N/A N/A Bridger Cost-Recovery Residential
Small General Service
Large General Service
Large Power
Irrigation
2.08% 1.99% 2.24% 2.23% 2.30% Total Combined Impact Residential
Small General Service
Large General Service
Large Power
Irrigation
7.82% 6.41% 11.43% 14.33% 10.75%

See Application, Attachment 2; Case No IPC-E-22-07, Application, Attachment 1; and Case No.
IPC-E-21-17, Supplemental Attachment 1.
YOU ARE FURTHER NOTIFIED that the Company has proposed to implement the
PCA, FCA, and Bridger cost-recovery rates on June 1, 2022.
YOU ARE FURTHER NOTIFIED that the Application and Attachments are available
for public inspection during regular business hours at the Commission’s office. These documents
are also available on the Commission’s website at www.puc.idaho.gov. Click on the “ELECTRIC”
icon, select “Open Cases,” and click on the case number as shown on the front of this document.
YOU ARE FURTHER NOTIFIED that all proceedings in this case will be held
pursuant to the Commission’s jurisdiction under Title 61 of the Idaho Code.
NOTICE OF APPLICATION NOTICE OF MODIFIED PROCEDURE
ORDER NO. 35392 5
YOU ARE FURTHER NOTIFIED that all proceedings in this matter will be conducted
pursuant to the Commission’s Rules of Procedure, IDAPA 31.01.01.000 et seq.
NOTICE OF MODIFIED PROCEDURE
YOU ARE FURTHER NOTIFIED that the Commission has determined that the public
interest may not require a formal hearing in this matter, and it will review the case through written
submissions under the Commission’s Rules of Modified Procedure Rules 201-204 of the Idaho
Public Utilities Commission’s Rules of Procedure, IDAPA 31.01.01.201-204. The Commission
notes that Modified Procedure and written comments have proven to be an effective means for
obtaining public input and participation.
YOU ARE FURTHER NOTIFIED that persons desiring to state a position on this
Application may file a written comment explaining why they support or oppose the Application.
Persons who would like a hearing must specifically request a hearing in their written comments.
Persons shall have until May 16, 2022, to file written comments. Comments must be filed
through the Commission’s website or by e-mail unless computer access is unavailable. To
comment electronically, please access the Commission’s website at www.puc.idaho.gov. Click the
“Case Comment Form” and complete the form using the case number as it appears on the front of
this document. To file by e-mail, the customer must e-mail the comments to the Commission
Secretary and the Company at the e-mail addresses listed below. If computer access is unavailable,
then comments may be mailed to the Commission and Company at these addresses:

For the Idaho PUC: Commission Secretary Idaho Public Utilities Commission
P.O. Box 83720 Boise, ID 83720-0074 [e-mail] Street Address for Express Mail:
11331 W. Chinden Blvd. Building 8, Suite 201-A Boise, ID 83714
For Idaho Power Company: Lisa Nordstrom Matthew Larkin
Timothy Tatum Jessie Brady Idaho Power Company P.O. Box 70 Boise, ID 83707-0070
[e-mail] [e-mail] [e-mail] [e-mail] [e-mail]

NOTICE OF APPLICATION NOTICE OF MODIFIED PROCEDURE
ORDER NO. 35392 6
YOU ARE FURTHER NOTIFIED that the Company must file any reply comments by
May 19, 2022.
YOU ARE FURTHER NOTIFIED that if no written comments or protests are received
within the time limit set, the Commission will consider this matter on its merits and enter its order
without a formal hearing. If written comments are received within the time limit set, the
Commission will consider them and, in its discretion, may set the same for formal hearing.
O R D E R
IT IS HEREBY ORDERED that the Company’s Application be processed by Modified
Procedure, Rules 201-204 (IDAPA 31.01.01.201-.204). Persons interested in submitting written
comments must do so by May 16, 2022. The Company must file any reply comments by May 19,
2022.
IT IS FURTHER ORDERED that parties comply with Order No. 35375, issued
April 21, 2022. Generally, all pleadings should be filed with the Commission electronically and
will be deemed timely filed when received by the Commission Secretary. See Rule 14.02. Service
between parties should continue to be accomplished electronically when possible. However,
voluminous discovery-related documents may be filed and served on CD-ROM or a USB flash
drive.
///

NOTICE OF APPLICATION NOTICE OF MODIFIED PROCEDURE
ORDER NO. 35392 7

DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this 3rd day
of May 2022.

ERIC ANDERSON, PRESIDENT
JOHN CHATBURN, COMMISSIONER
JOHN R. HAMMOND JR., COMMISSIONER ATTEST:
Jan Noriyuki Commission Secretary

I:\Legal\ELECTRIC\IPC-E-22-11 PCA\orders\IPCE2211_NtcApp_Mod_dh.docx
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-22-11
IDAHO POWER COMPANY
REQUEST NO. 2
ATTACHMENT NO. 6
1
From:Gust, Stacy
Sent:Tuesday, May 3, 2022 1:18 PM
To:Jan Noriyuki
Cc:Dayn Hardie; [e-mail]; [e-mail]; Nordstrom, Lisa
Subject:IPC-E-22-11 Application for Authority to Implement Power Cost Adjustment Rates for
Electric Service from June 1, 2022 through May 31, 2023 - Idaho Power Company's
Response to the First Production Request of the Commission Staff
Attachments:Idaho Power Company's Response to the First Production Request of the Commission
Staff.pdf; Response to Staff's Request No. 2- Attachment 1 - PCA Tables.xlsx; Response
to Staff's Request No. 2 - Attachment 2 - PCA Rate Components.xlsx; Response to Staff's
Request No. 2 - Attachment 3 - FORM1S.xlsx; Response to Staff's Request No. 2 -
Attachment 4 -Net Income.xlsx; Response to Staff's Request No. 3 - Attachment 2 - Base
NPSE.xlsx; Response to Staff's Request No. 3 - Attachment 3 -Actual MWhs.xlsx;
Response to Staff's Request No. 4 - Attachment 1 - Revenue Shaping.xlsx; Response to
Staff's Request No. 6 - Attachment 1 -Forced Outages.xlsx; Response to Staff's Request
No. 7 - Attachment 1 - Scheduled Outages.xlsx
Ms. Noriyuki,
Please find attached Idaho Power Company’s Response to the First Production Request of the Commission Staff in the
above matter.
I will send the confidential attachments in a separate encrypted email to the parties who have signed the Protective
Agreement.
If you have any questions about this filing, please contact me.
Thank you.
Stacy Gust
REGULATORY ADMINISTRATIVE ASSISTANT
Idaho Power | Regulatory Affairs
Office 208-388-5749

LISA D. NORDSTROM
Lead Counsel
[e-mail]

May 3, 2022

Jan Noriyuki, Secretary
Idaho Public Utilities Commission
11331 W. Chinden Boulevard
Building 8, Suite 201-A
Boise, Idaho 83714

Re: Case No. IPC-E-22-11
Application of Idaho Power Company for Authority to Implement Power Cost
Adjustment (“PCA”) Rates for Electric Service from June 1, 2022, through May
31, 2023

Dear Ms. Noriyuki:

Attached for electronic filing is Idaho Power Company’s Response to the First
Production Request of the Commission Staff in the above-entitled matter.

The confidential attachments will be provided under separate cover to the parties who
sign the Protective Agreement in this matter.

If you have any questions about the attached documents, please do not hesitate to
contact me.

Sincerely,

Lisa D. Nordstrom

LDN:sg
Enclosures

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF - 1
LISA D. NORDSTROM (ISB No. 5733)
Idaho Power Company
1221 West Idaho Street (83702)
P.O. Box 70
Boise, Idaho 83707
Telephone: [phone]
Facsimile: [phone]
[e-mail]

Attorney for Idaho Power Company

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO IMPLEMENT POWER
COST ADJUSTMENT (“PCA”) RATES
FOR ELECTRIC SERVICE FROM JUNE
1, 2022, THROUGH MAY 31, 2023.

)
)
)
)
)
)
)
)

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY’S
RESPONSE TO THE FIRST
PRODUCTION REQUEST OF THE
COMMISSION STAFF

COMES NOW, Idaho Power Company (“Idaho Power” or “Company”), and in
response to the First Production Request of the Commission Staff dated April 22, 2022,
herewith submits the following information:

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF - 2

REQUEST FOR PRODUCTION NO. 1: Please provide a list of all Idaho Power
customers who purchased Company-owned Renewable Energy Credits (“RECs”) that are
being passed through the Power Cost Adjustment (“PCA”) Schedule 55. Please include
in the response the fuel type for the RECs, purchase price, quantity of RECs, and date
purchased.
RESPONSE TO REQUEST FOR PRODUCTION NO. 1: Please see Confidential
Attachment 1 for all Idaho Power customers who purchased Company-owned Renewable
Energy Credits (“RECs”) that are being passed through the Power Cost Adjustment.
The response to this Request is sponsored by Suzanne Smith, Senior Program
Specialist, Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF - 3
REQUEST FOR PRODUCTION NO. 2: Please provide all workpapers used to
derive the final figures included in the exhibits in electronic format with all formulas intact.
RESPONSE TO REQUEST FOR PRODUCTION NO. 2: Please see Excel
Attachments 1 – 4.
Excel Attachment 1 was used in preparation of Exhibit No.1 (2022-2023 PCA
Forecast) as well as the tables found in the direct testimony of Jessica G. Brady. Excel
Attachment 2 contains the calculations for the PCA rate components. Excel Attachments
3 and 4 were used in preparation of Exhibit No. 3 (2022 ROE Determination Revenue
Sharing Benefits).
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF - 4
REQUEST FOR PRODUCTION NO. 3: Please provide the monthly number of
megawatt-hours (“MWh”) associated with the system base and actual net power costs for
all Net Power Supply Expense (“NPSE”) Accounts including Federal Energy Regulatory
Commission (“FERC”) accounts 501 (Coal), account 536 (Water for power), account 547
(Gas), account 555 (Non-PURPA), account 565 (3rd party transmission), account 447
(Surplus Sales), account 555, (PURPA), and account 555 (Demand Response
Incentives).
RESPONSE TO REQUEST FOR PRODUCTION NO. 3: Please see Confidential
Attachment 1 for monthly PURPA generation in megawatt-hours (“MWh”) associated with
the system base net power costs. Please see Excel Attachment 2 for monthly generation
associated with system base net power costs for all non-PURPA Federal Energy
Regulatory Commission (“FERC”) accounts. Docket No. IPC-E-13-201 contains
additional detail regarding the Company’s base net power supply costs.
Please see Excel Attachment 3 for monthly generation associated with actual net
power supply costs for April 2021 – March 2022. There are no MWhs associated with
FERC accounts 536 (Water for Power), 565 (3rd Party Transmission) and 555 (Demand
Response Incentives).
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF - 5
REQUEST FOR PRODUCTION NO. 4: Did the Company re-distribute or smooth
base NPSE in this year’s filing? If so, please provide workpapers that reflect the
calculations/method used to derive the revenue-smoothed (redistributed) base NPSE
included in Exhibit No. 2 from the Aurora generated NPSE that was last authorized by the
Commission for the deferral period for all NPSE accounts. Please include all workpapers
in electronic format with calculations intact.
RESPONSE TO REQUEST FOR PRODUCTION NO. 4: Base NPSE in this filing
are shaped according to base rate revenues from the Company’s last general rate case,
in accordance with Commission Order No. 33307 issued in Case No. IPC-E-15-15. The
shaping of base NPSE has remained consistent with each PCA filed since the conclusion
of that case. Please see Excel Attachment 1, which details the shaping of base NPSE by
retail revenues.
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF - 6
REQUEST FOR PRODUCTION NO. 5: Please provide supporting data on the
reservoir levels for the Upper Snake River Basin for both current and 2023 forecasted
amounts.
RESPONSE TO REQUEST FOR PRODUCTION NO. 5: Following drought
conditions in 2021, reservoirs upstream of Brownlee had lower than normal storage at the
end of the irrigation season to carryover into the following year. On November 1, 2021,
which is the end of the irrigation year, storage in the major reservoirs above Brownlee
(which Idaho Power defines as the cumulative storage in Jackson Lake, Palisades, Island
Park, American Falls, Anderson Ranch, Arrowrock, Lucky Peak, Lake Lowell, Cascade,
Deadwood, and Owyhee Reservoir) was 53% of normal, or only 22% of the total capacity
of these reservoirs.
The winter of 2021/2022 began with storm cycles and snowpack building at an
above average rate in most of the basins above Brownlee. However, beginning in early
January, the Snake River Basin experienced dry conditions through approximately March,
which led to below normal snowpack conditions across all basins upstream of Brownlee
Reservoir. In the April 1, 2022 Idaho Water Supply Outlook Report
(https://www.wcc.nrcs.usda.gov/ftpref/support/states/ID/wy2022/wsor/borid422.pdf), the
Natural Resources Conservation Service listed snowpack in key basins above Brownlee
Reservoir as follows:
ꞏ Upper Snake Basins: 66 to 70% of median
ꞏ Wood and Lost Basins: 61 to 76% of median
ꞏ Southern Snake Basins: 50 to 78% of median
ꞏ West Central Basins: 60 to 70% of median

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF - 7
The low snowpack, coupled with the low carryover conditions from the prior
irrigation year, resulted in below normal water supply forecasts in the basins above
Brownlee, and subsequently in Idaho Power’s streamflow forecast at its hydropower
projects. At the March Water Supply Committee meeting, hosted by the Idaho Department
of Water Resources, regional water managers provided forecasts for water supplies and
reservoir operations. Materials from the U.S. Bureau of Reclamation provide supporting
data for the following paragraphs and can be found at the following link
(https://idwr.idaho.gov/water-data/water-supply/committee/).
In the Upper Snake, above Milner Dam, storage on March 8, 2022 was 72% of
normal, which corresponds to the 7th lowest storage amount in the last 46 years.
Forecasts for runoff in the Upper Snake ranged from 63 to 75% of normal. Reservoir
storage projections showed that the total system storage was likely to end the irrigation
season at less than 20% of capacity.
In the Boise Basin, storage on March 9, 2022 was 85% of average. Forecasts
called for runoff to be approximately 80% of average. The lower storage and runoff
projections resulted in forecasts that did not predict refill of the Boise system, yielding little
to no excess flow exiting the Boise Basin beyond minimum stream flows. Projections
showed Boise Basin reservoir content at approximately 40% of normal at the end of the
irrigation season.
In the Payette Basin, storage on March 9, 2022 was 88% of average. Forecasts
called for runoff to be approximately 81% of average. The lower storage and runoff
projections resulted in forecasts that predicted marginal refill of the Payette system,

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF - 8
yielding little to no excess flow exiting the Payette Basin due to reservoir releases for
flood risk management. Projections showed Payette Basin reservoir content at
approximately 60% of normal at the end of the irrigation season.
In the Owyhee Basin, storage on March 9, 2022 was 51% of average. Forecasts
called for runoff to be approximately 81% of average. Since the Owyhee Reservoir is a
multiyear system, this amount of runoff is insufficient to fill the system or lead to any
increases in streamflow downstream of Lake Owyhee.
Given current water supply and reservoir storage conditions, carryover in all major
reservoirs above Brownlee is expected to be below normal at the end of the 2022 irrigation
season and into the start of the 2023 water year. This reduces the likelihood of any
significant winter season or early flood risk management water releases through the end
of the PCA analysis period.
Idaho Power reviewed the available forecasts, along with internal hydrologic
modeling and reservoir operations models, and concurred that current and forecast
drought conditions coupled with low reservoir storage made it unlikely that any of the
regulated portions of the Snake River Basin upstream of Brownlee Reservoir would
significantly contribute to stream flows, and therefore hydropower generation, through
most of Idaho Power’s hydro system during the upcoming PCA year.
The response to this Request is sponsored by Frank Gariglio, Engineering Leader,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF - 9
REQUEST FOR PRODUCTION NO. 6: Please provide the length of time and
amount of production in MWhs lost for forced downtime (unscheduled) that Company-
owned generation facilities/units experienced each month during the deferral period. For
each forced downtime, please explain the cause and resolution of the downtime
RESPONSE TO REQUEST FOR PRODUCTION NO. 6: Please see Excel
Attachment 1.
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF - 10
REQUEST FOR PRODUCTION NO. 7: Please provide all Company-owned
facility/unit unforced downtime (scheduled) including the date range, length of time, and
reason that occurred during the deferral period.
RESPONSE TO REQUEST FOR PRODUCTION NO. 7: Please see Excel
Attachment 1.
The response to this Request is sponsored by Jessi Brady, Regulatory Analyst,
Idaho Power Company.

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF - 11

DATED at Boise, Idaho, this 3rd day of May 2022.

________________________________
LISA D. NORDSTROM
Attorney for Idaho Power Company

IDAHO POWER COMPANY’S RESPONSE TO THE FIRST PRODUCTION REQUEST OF THE
COMMISSION STAFF - 12
CERTIFICATE OF SERVICE

I HEREBY CERTIFY that on the 3rd day of May 2022, I served a true and correct
copy of Idaho Power Company’s Response to the First Production Request of the
Commission Staff to Idaho Power Company upon the following named parties by the
method indicated below, and addressed to the following:

Commission Staff
Dayn Hardie
Deputy Attorney General
Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg No. 8,
Suite 201-A (83714)
PO Box 83720
Boise, ID 83720-0074

Hand Delivered
U.S. Mail
Overnight Mail
FAX
_____ FTP Site
X Email: [e-mail]

Industrial Customers of Idaho Power
Peter J. Richardson
515 N. 27th Street
Boise, Idaho 83702
Hand Delivered
U.S. Mail
Overnight Mail
FAX
_____ FTP Site
X Email: [e-mail]

Dr. Don Reading
6070 Hill Road
Boise, Idaho 83703
Hand Delivered
U.S. Mail
Overnight Mail
FAX
_____ FTP Site
X Email: [e-mail]

________________________________
Stacy Gust, Regulatory Administrative
Assistant

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

CONFIDENTIAL
REQUEST NO. 1

ATTACHMENT NO. 1

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

REQUEST NO. 2

ATTACHMENT NO. 1
SEE ATTACHED SPREADSHEET

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

REQUEST NO. 2

ATTACHMENT NO. 2
SEE ATTACHED SPREADSHEET

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

REQUEST NO. 2

ATTACHMENT NO. 3
SEE ATTACHED SPREADSHEET

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

REQUEST NO. 2

ATTACHMENT NO. 4
SEE ATTACHED SPREADSHEET

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

CONFIDENTIAL
REQUEST NO. 3

ATTACHMENT NO. 1

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

REQUEST NO. 3

ATTACHMENT NO. 2
SEE ATTACHED SPREADSHEET

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

REQUEST NO. 3

ATTACHMENT NO. 3
SEE ATTACHED SPREADSHEET

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

REQUEST NO. 4

ATTACHMENT NO. 1
SEE ATTACHED SPREADSHEET

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

REQUEST NO. 6

ATTACHMENT NO. 1
SEE ATTACHED SPREADSHEET

BEFORE THE

IDAHO PUBLIC UTILITIES COMMISSION

CASE NO. IPC-E-22-11

IDAHO POWER COMPANY

REQUEST NO. 7

ATTACHMENT NO. 1
SEE ATTACHED SPREADSHEET
Table 2
Line No.FERC Account Base NPSE Forecast Difference FERC Account 2021-2022 Forecast Per Unit Actual Per Unit % Change
95% Sharing Accounts % Change from Base 95% Sharing Accounts % Change Expenses1 Account 501, Coal 108,503,180$ 151,179,160$ 42,675,980$ 39%Account 501, Coal 118,562,796$ 104,495,443$ (14,067,352)$ -12%32.94$ 32.23$ -2.15%Coal2 Account 536, Water for Power 2,380,597$ 0$ (2,380,597)$ -100%Account 536, Water for Power 0$ -$ (0)$
3 Account 547, Other Fuel 33,367,563$ 86,983,566$ 53,616,003$ 161%Account 547, Other Fuel 57,235,044$ 88,941,596$ 31,706,552$ 55%24.45$ 32.70$ 33.75%Gas462,606,593$ 99,906,480$ 37,299,887$ 60%Account 555, Purchased Power Non-PURPA 74,800,530$ 198,463,419$ 123,662,888$ 165%50.59$ 48.64$ -3.84%Non-PURPA5 Account 565, 3rd Party Transmission 5,455,955$ 5,149,239$ (306,716)$ -6%Account 565, 3rd Party Transmission 4,853,909$ 7,754,808$ 2,900,899$ 60%
6 Account 447, Surplus Sales (51,735,153)$ (65,085,848)$ (13,350,695)$ 26%Account 447, Surplus Sales (25,842,225)$ (79,257,653)$ (53,415,428)$ 207%34.23$ 57.70$ 69%Sales Price
160,578,735$ 278,132,598$ 117,553,863$ 73%229,610,054$ 320,397,612$ 90,787,559$
100% Sharing Accounts 100% Sharing Accounts
7 Account 555, PURPA 133,853,869$ 212,586,058$ 78,732,189$ 59%Account 555, PURPA 205,133,741$ 195,067,884$ (10,065,857)$ -5%67.75$ 66.29$ -2.15%PURPA811,252,265$ 8,115,900$ (3,136,365)$ -28%Account 555, Demand Response Incentives 7,613,612$ 7,112,062$ (501,550)$ -7%9 Total 305,684,869$ 498,834,556$ 193,149,687$ 63%212,747,353$ 202,179,946$ (10,567,407)$
PPAs 49,209.25 51,535.95 5%
Market Purchases 24,654.47 47,200.41 91%Total 442,357,407$ 522,577,558$ 80,220,152$ 18%27.34$ 41.52$ 52%Purchase PriceTable 3 Trans Losses 936.81 1,170.12 25%Total 74,800.53 99,906.48 34%24,654.47 144,203.39 Purchases - Expense
Line No.FERC Account 25,591.28 48,370.53 89%901.88 3,473.29 Purchases - MWh95% Sharing Accounts % Change Forecast ExpensesPY Forecast Per Unit CY Forecast Per Unit Per Unit % Change
1 Account 501, Coal 118,562,796$ 151,179,160$ 32,616,365$ 28%32.94 29.74 -10% Coal
2 Account 536, Water for Power 0$ 0$ -$ 0%FERC Account
3 Account 547, Other Fuel 57,235,044$ 86,983,566$ 29,748,522$ 52%24.45 34.03 39% Gas Hydro474,800,530$ 99,906,480$ 25,105,950$ 34%50.59 63.22 25% Purchases & PPAs5 Account 565, 3rd Party Transmission 4,853,909$ 5,149,239$ 295,331$ 6%95% Sharing Accounts
6 Account 447, Surplus Sales (25,842,225)$ (65,085,848)$ (39,243,623)$ 152%(34.23) (51.73) 51% Sales Account 501, Coal 3,599,219 3,241,970 (357,249) -10%
229,610,054$ 278,132,598$ 48,522,544$ 21%Account 547, Other Fuel 2,340,994 2,719,869 378,875 16%Account 555, Purchased Power Non-PURPA 1,478,696 4,079,834 2,601,138 176%100% Sharing Accounts 32.00 27.80 -13% Bridger 95% Sharing Accounts 14,109,799 15,309,676 1,199,877
7 Account 555, PURPA 205,133,741$ 212,586,058$ 7,452,317$ 4%40.39 40.58 0% Valmy87,613,612$ 8,115,900$ 502,288$ 7%100% Sharing Accounts212,747,353$ 220,701,958$ 7,954,605$ 4%85.31 83.24 -2% PPAs Account 555, PURPA 3,027,905 2,942,673 (85,231) -3%
27.34 49.11 80% Market Purchases 100% Accounts 3,027,905 2,942,673 (85,231)
9 Total PCA Forecast 442,357,407$ 498,834,556$ 56,477,149$ 13%Trans Losses67.75 69.96 Total Total Generation 17,137,704 18,252,350 1,114,646 7%
Table 4 95% Sharing AccountsAccount 447, Surplus Sales 754,975 1,373,630 618,655 82%
Line No.FERC Account Total Load 16,382,729 16,878,720 495,991 3.0%1 Hydro
95% Sharing Accounts
2 Account 501, Coal3 Account 547, Other Fuel4
95% Sharing Accounts 14,109,799 15,192,435 1,082,636 8%PPAs 576.81 619.14 100% Sharing Accounts Purchases 901.88 961.19
5 Account 555, PURPA 3,027,905 3,038,613 10,708 0.35%4%
100% Accounts 3,027,905 3,038,613 10,708
6 Total Generation 17,137,704 18,231,048 1,093,344 6%
95% Sharing Accounts7 Account 447, Surplus Sales 754,975 1,258,195 503,220 67%152%51%8 Total Load 16,382,729 16,972,853 590,124 4%
Table 5
Line No.FERC Account
95% Sharing Accounts (From Table 1)
1 Account 501, Coal 42,675,980$ 40,542,181$ 38,737,356$ 2 Account 536, Water for Power (2,380,597)$ (2,261,567)$ (2,160,888)$ 3 Account 547, Other Fuel 53,616,003$ 50,935,202$ 48,667,709$
4 37,299,887$ 35,434,893$ 33,857,430$ 5 Account 565, 3rd Party Transmission (306,716)$ (291,380)$ (278,408)$ 6 Account 447, Surplus Sales (13,350,695)$ (12,683,160)$ (12,118,541)$
117,553,863$ 111,676,170$ 106,704,658$ % Change in Sales
System Sales 15,131,418 15,690,546 -3.6%100% Sharing Accounts 14,436,951 14,992,046 -3.7%7 Account 555, PURPA 78,732,189$ 78,732,189$ 75,227,251$ 95.41%95.55%
8 (3,136,365)$ (3,136,365)$ (3,136,365)$
9 Total 193,149,687$ 187,271,994$ 178,795,544$
Table 6
Line No. Revenue Sharing Component 2009-2011 2012-2014 2015-2020
1 Available ADITC For Use $45 Million $45 Million $45 Million2 ROE Threshold 9.5%9.5%10.0%3 50-50 Sharing Threshold 10.5%10.0%N/A
4 75-25 Sharing Threshold N/A 10.5%10.0%
5 Customer Benefits ($ Millions):6 Reduction to Rates $27.1 $22.8 $8.2 Total7$20.3 $47.8 $0.0 2009-2020
8 Total $47.4 $70.6 $8.2 $126.2
Table 1
Line No. Rate Component 2021-2022 PCA 2022-2023 PCA Difference
1 PCA Forecast 131,825,063$ 178,795,145$ 46,970,081$ 2 PCA Balancing Adjustment (18,320,281)$ 38,664,487$ 56,984,768$ 3 PCA Total 113,504,783$ 217,459,632$ 103,954,849$
4 Revenue Sharing -$ (568,771)$ (568,771)$ 4 Total Revenue Impact 113,504,783$ 216,890,861$ 103,386,078$
Idaho Jurisdictional Sales 14,992,046,332
2021 PCA Rates 2022 PCA RatesPCA Forecast 0.008793 0.011926 PCA True-up -0.001222 0.002579Revenue Sharing
DSM Rider Ongoing TransferDSM Rider One Time Transfer 0.007571 0.014505
2009-2020 Revenue Sharing
Revenue Impact by Component
2022 - 2023 PCA FORECAST (Total System)Forecast vs Actuals
PCA Forecast Comparison Expenses (Total System)
Forecast vs Actuals (Generation)
PCA Forecast Comparison Generation (Total System-MWh)
2022-2023 PCA FORECAST
Net Power Supply Expense 2021-2022 2022-2023 2023-2024 a-Apr 2021 a-May 2021 a-Jun 2021 a-Jul 2021 a-Aug 2021 a-Sep 2021 a-Oct 2021 a-Nov 2021 a-Dec 2021 a-Jan 2022 a-Feb 2022 Mar 2022
Mar 31 2022 Bridger 83,080 119,783 131,370 1,597 2,204 5,688 8,434 7,643 10,106 10,141 7,094 9,372 7,488 7,063 6,250 Boardman 24 24 Valmy 21,392 31,397 31,015 161 287 1,711 2,308 2,522 2,235 2,175 2,501 2,186 3,576 1,524 206
Coal 104,495 151,179 162,385 1,758 2,515 7,399 10,742 10,165 12,341 12,316 9,596 11,558 11,064 8,586 6,456

Langley 66,610 74,142 66,505 28 3,852 4,563 4,994 5,947 7,370 4,008 7,270 8,051 9,358 5,492 5,678
Natural Gas Plants 22,331 12,841 76,457 4,924 959 5,114 6,242 594 931 2,076 1,351 345 (1,283)797 281
Natural Gas 88,942 86,984 142,962 4,952 4,811 9,677 11,236 6,541 8,301 6,083 8,621 8,396 8,075 6,289 5,959 CSPP 195,068 212,586 222,477 14,506 16,471 21,070 20,302 21,391 15,633 15,463 14,463 17,518 11,398 14,079 12,771 PPAs 52,569 51,536 57,869 3,171 3,320 3,639 4,235 4,476 3,366 4,861 5,758 5,764 5,091 4,388 4,500

Purchases 144,203 47,200 20,256 718 2,072 29,010 30,357 14,920 11,865 6,756 6,195 13,077 11,837 13,915 3,481

Demand Response Incentive 7,112 8,116 8,116 0 216 2,838 2,830 919 339 (30)0 Transmission Losses 1,691 1,170 1,229 13 40 363 838 176 24 52 14 48 13 57 54Third Party Transmission 7,755 5,149 5,407 148 321 1,039 1,674 1,441 502 561 495 478 383 467 246Water Leases 0 0 10 (10)
Surplus Sales (79,258) (65,086) (156,788)1,232 2,765 (10,452) (7,353) (5,148) (18,491) (9,428) (8,418) (7,865) (9,384) (4,647) (2,068)

PCA Defined Net Power Supply Expense 522,578 498,835 463,911 26,498 32,315 61,960 74,868 56,793 34,460 37,004 36,693 48,985 38,467 43,135 31,399

$/MWh
Market Purchases $4.54 $12.09 $59.12 $57.23 $44.36 $58.91 $43.64 $25.60 $37.65 $26.83 $43.77 $36.25Surplus Sales - Market ($78.26) ($48.00)$381.51 $99.50 $61.13 $78.30 $51.21 $62.73 $40.58 $44.95 $40.57 Bridger $26.08 $29.98 $29.85 $29.32 $30.67 $29.40 $32.20 $31.36 $33.40 $32.15 $31.67 $27.92Boardman Valmy $197.10 $38.03 $42.98 $33.27 $34.95 $36.60 $46.74 $34.32 $39.80 $51.01 ($119.11)
Langley $15.99 $23.35 $25.18 $26.96 $30.74 $39.88 $47.12 $40.52 $43.24 $49.96 $32.01 $25.86

Change
Net Power Supply Expense a-Apr 2021 a-May 2021 a-Jun 2021 a-Jul 2021 a-Aug 2021 a-Sep 2021 a-Oct 2021 a-Nov 2021 a-Dec 2021 a-Jan 2022 a-Feb 2022 Mar 2022
Bridger (19,165)21,169 34,584 254 182 3,738 (1,609) (8,963) (2,700)4,784 (1,712) (7,736) (5,866) (1,959)2,420 Boardman 24 24 Valmy 5,074 20,831 22,770 (87)39 (225) (153)100 (110)1,928 2,254 (1,085)1,190 1,270 (48)
Coal (14,067)42,001 57,354 167 245 3,513 (1,762) (8,862) (2,810)6,712 541 (8,820) (4,676) (689)2,372

Langley 15,460 28,365 21,140 (3,815)1,664 2,339 1,279 2,114 3,146 (259)2,439 1,683 3,351 466 1,052
Natural Gas Plants 16,247 (5,696)36,249 4,652 678 4,843 5,297 (1,775)660 1,795 1,080 64 (1,564)516
Natural Gas 31,707 22,670 57,388 837 2,343 7,183 6,576 339 3,806 1,536 3,518 1,747 1,787 983 1,052 CSPP (10,066)395 2,363 (175)2,247 186 (3,507) (877) (1,074) (935) (2,125)1,809 (3,637) (1,776) (201) PPAs 3,359 1,283 3,211 136 651 144 60 517 (59)714 148 (138)111 (134)1,211

Purchases 119,549 16,000 11,999 927 1,982 26,268 22,592 11,958 10,202 3,628 3,579 12,999 9,577 12,854 2,983

Demand Response Incentive (502)502 502 0 (65) (100) (238) (374)306 (30)0 Transmission Losses 755 161 169 (41) (1)333 773 14 (101) (43) (76) (29) (58) (15) (3)Third Party Transmission 2,901 53 55 (171)55 466 916 778 52 50 214 259 116 206 (41)Water Leases (0) 10 (10)
Surplus Sales (53,415) (32,103) (88,858)5,373 3,981 (10,452) (7,133) (5,148) (10,890) (9,428) (8,418) (4,603) (4,575) (3,955)1,835

PCA Defined Net Power Supply Expense 80,220 50,962 44,183 7,051 11,503 27,577 18,414 (1,519) (1,248)2,538 (2,648)3,234 (1,363)7,473 9,208
PCA Year NPSE (Apr‐Mar)
Net Power Supply Expense 2021-2022 2022-2023 2023-2024
Mar 31 2022 Bridger 83,080 119,783 131,370 Boardman 24 Valmy 21,392 31,397 31,015
Coal 104,495 151,179 162,385

Langley 66,610 74,142 66,505
Natural Gas Plants 22,331 12,841 76,457
Natural Gas 88,942 86,984 142,962 CSPP 195,068 212,586 222,477 PPAs 52,569 51,536 57,869

Purchases 144,203 47,200 20,256

Demand Response Incentive 7,112 8,116 8,116Transmission Losses 1,691 1,170 1,229Third Party Transmission 7,755 5,149 5,407Water Leases 0 0
Surplus Sales (79,258) (65,086) (156,788)

PCA Defined Net Power Supply Expense 522,578 498,835 463,911

$/MWh
Market PurchasesSurplus Sales - MarketBridgerBoardmanValmy
Langley

Change
Net Power Supply Expense
Bridger (19,165)21,169 34,584 Boardman 24 Valmy 5,074 20,831 22,770
Coal (14,067)42,001 57,354

Langley 15,460 28,365 21,140
Natural Gas Plants 16,247 (5,696)36,249
Natural Gas 31,707 22,670 57,388 CSPP (10,066)395 2,363 PPAs 3,359 1,283 3,211

Purchases 119,549 16,000 11,999

Demand Response Incentive (502)502 502Transmission Losses 755 161 169Third Party Transmission 2,901 53 55Water Leases (0)
Surplus Sales (53,415) (32,103) (88,858)

PCA Defined Net Power Supply Expense 80,220 50,962 44,183
Apr 2022 May 2022 Jun 2022 Jul 2022 Aug 2022 Sep 2022 Oct 2022 Nov 2022 Dec 2022 Jan 2023 Feb 2023 Mar 2023
9,444 2,249 5,735 10,763 10,768 10,484 10,550 11,461 12,067 12,795 11,814 11,652 254 254 2,055 3,589 3,599 3,492 3,603 3,500 3,614 3,730 3,445 262
9,698 2,503 7,790 14,352 14,367 13,976 14,153 14,961 15,682 16,526 15,259 11,914

6,563 391 4,602 4,941 4,965 6,942 7,334 8,058 7,705 7,954 7,855 6,832
281 281 281 3,926 5,966 281 281 281 281 421 281 281
6,844 672 4,883 8,867 10,931 7,223 7,615 8,339 7,986 8,375 8,136 7,113 15,817 15,833 22,446 24,019 22,981 16,991 16,537 15,972 15,876 15,380 17,213 13,519 4,317 3,836 3,636 3,572 3,499 3,496 4,356 4,723 4,962 5,189 4,909 5,041

(209)5,662 8,252 13,670 14,687 691 (388)60 4,362 949 (266) (269)

406 1,811 2,173 1,811 1,087 828 50 37 80 207 195 99 86 100 116 70 71 57322 285 631 843 784 478 524 295 231 251 247 259 0
(8,808) (5,619) (9,807) (5,228) (0) (5,477) (15,656) (14,491)

28,032 28,828 48,124 67,340 69,617 39,146 34,163 40,050 49,216 41,262 29,914 23,143

$24.09 $25.59 $69.76 $117.62 $65.57 $77.58 $70.04 $36.00 $89.80 $53.63 $49.31 $77.95 $65.58 $40.89$27.74 $24.60 $26.35 $27.10 $27.16 $27.18 $27.24 $27.29 $27.36 $29.15 $29.64 $29.52 ###########$41.37 $38.85 $38.96 $39.06 $39.00 $39.15 $39.13 $40.38 $41.29 ###########
$31.35 $27.97 $23.44 $23.52 $33.34 $33.98 $37.39 $33.96 $35.03 $38.87 $31.12
Apr 2022 May 2022 Jun 2022 Jul 2022 Aug 2022 Sep 2022 Oct 2022 Nov 2022 Dec 2022 Jan 2023 Feb 2023 Mar 2023
6,727 (543)1,999 2,327 (2,716) (1,227) (490)3,617 (1,040)1,519 3,627 7,370 0 0 275 1,358 1,292 1,294 3,349 3,246 3,361 3,470 3,185 1
6,727 (543)2,274 3,685 (1,424)67 2,858 6,863 2,320 4,989 6,812 7,371

4,532 (1,494)2,580 1,022 926 3,163 3,432 3,522 2,538 2,658 3,194 2,293
3,515 4,007 (2,398) (5,524) (5,296)
4,532 (1,494)2,580 4,536 4,933 3,163 3,432 1,124 (2,986) (2,638)3,194 2,293 84 344 355 (284)187 (189) (104) (817)48 (92)883 (19) 1,216 1,109 64 (698) (548) (2)122 (1,008) (1,065)109 296 1,688

(717)5,397 6,888 2,408 6,292 (859) (1,172)1,671 (2,567) (1,341)

125 (1,127) (895)518 1,053 828 7 6 12 37 65 (2) (8)20 34 (4) (4) (3)(13)6 29 47 88 5 (12) (0)1 (30) (26) (43)
(4,611)2,681 1,285 (211) (8,034) (5,228)4,018 (295) (15,656) (6,052)

7,226 7,507 13,612 8,605 8,697 2,490 (692)610 4,041 (528) (5,842)5,235
PCA Year NPSE (Apr‐Mar)
Net Power Supply Expense 2021-2022 2022-2023 2023-2024 a-Apr 2021 a-May 2021 a-Jun 2021 a-Jul 2021 a-Aug 2021 a-Sep 2021 a-Oct 2021 a-Nov 2021 a-Dec 2021 a-Jan 2022 a-Feb 2022 Mar 2022
Mar 31 2022 Bridger 83,080 119,783 131,370 1,597 2,204 5,688 8,434 7,643 10,106 10,141 7,094 9,372 7,488 7,063 6,250 Boardman 24 24 Valmy 21,392 31,397 31,015 161 287 1,711 2,308 2,522 2,235 2,175 2,501 2,186 3,576 1,524 206
Coal 104,495 151,179 162,385 1,758 2,515 7,399 10,742 10,165 12,341 12,316 9,596 11,558 11,064 8,586 6,456

Langley 66,610 74,142 66,505 28 3,852 4,563 4,994 5,947 7,370 4,008 7,270 8,051 9,358 5,492 5,678
Natural Gas Plants 22,331 12,841 76,457 4,924 959 5,114 6,242 594 931 2,076 1,351 345 (1,283)797 281
Natural Gas 88,942 86,984 142,962 4,952 4,811 9,677 11,236 6,541 8,301 6,083 8,621 8,396 8,075 6,289 5,959 CSPP 195,068 212,586 222,477 14,506 16,471 21,070 20,302 21,391 15,633 15,463 14,463 17,518 11,398 14,079 12,771 PPAs 52,569 51,536 57,869 3,171 3,320 3,639 4,235 4,476 3,366 4,861 5,758 5,764 5,091 4,388 4,500

Purchases 144,203 47,200 20,256 718 2,072 29,010 30,357 14,920 11,865 6,756 6,195 13,077 11,837 13,915 3,481

Demand Response Incentive 7,112 8,116 8,116 0 216 2,838 2,830 919 339 (30)0 Transmission Losses 1,691 1,170 1,229 13 40 363 838 176 24 52 14 48 13 57 54Third Party Transmission 7,755 5,149 5,407 148 321 1,039 1,674 1,441 502 561 495 478 383 467 246Water Leases 0 0 10 (10)
Surplus Sales (79,258) (65,086) (156,788)1,232 2,765 (10,452) (7,353) (5,148) (18,491) (9,428) (8,418) (7,865) (9,384) (4,647) (2,068)

PCA Defined Net Power Supply Expense 522,578 498,835 463,911 26,498 32,315 61,960 74,868 56,793 34,460 37,004 36,693 48,985 38,467 43,135 31,399

$/MWh
Market Purchases $4.54 $12.09 $59.12 $57.23 $44.36 $58.91 $43.64 $25.60 $37.65 $26.83 $43.77 $36.25Surplus Sales - Market ($78.26) ($48.00)$381.51 $99.50 $61.13 $78.30 $51.21 $62.73 $40.58 $44.95 $40.57 Bridger $26.08 $29.98 $29.85 $29.32 $30.67 $29.40 $32.20 $31.36 $33.40 $32.15 $31.67 $27.92Boardman Valmy $197.10 $38.03 $42.98 $33.27 $34.95 $36.60 $46.74 $34.32 $39.80 $51.01 ($119.11)
Langley $15.99 $23.35 $25.18 $26.96 $30.74 $39.88 $47.12 $40.52 $43.24 $49.96 $32.01 $25.86

Change
Net Power Supply Expense a-Apr 2021 a-May 2021 a-Jun 2021 a-Jul 2021 a-Aug 2021 a-Sep 2021 a-Oct 2021 a-Nov 2021 a-Dec 2021 a-Jan 2022 a-Feb 2022 Mar 2022
Bridger (19,165)21,169 34,584 254 182 3,738 (1,609) (8,963) (2,700)4,784 (1,712) (7,736) (5,866) (1,959)2,420 Boardman 24 24 Valmy 5,074 20,831 22,770 (87)39 (225) (153)100 (110)1,928 2,254 (1,085)1,190 1,270 (48)
Coal (14,067)42,001 57,354 167 245 3,513 (1,762) (8,862) (2,810)6,712 541 (8,820) (4,676) (689)2,372

Langley 15,460 28,365 21,140 (3,815)1,664 2,339 1,279 2,114 3,146 (259)2,439 1,683 3,351 466 1,052
Natural Gas Plants 16,247 (5,696)36,249 4,652 678 4,843 5,297 (1,775)660 1,795 1,080 64 (1,564)516
Natural Gas 31,707 22,670 57,388 837 2,343 7,183 6,576 339 3,806 1,536 3,518 1,747 1,787 983 1,052 CSPP (10,066)395 2,363 (175)2,247 186 (3,507) (877) (1,074) (935) (2,125)1,809 (3,637) (1,776) (201) PPAs 3,359 1,283 3,211 136 651 144 60 517 (59)714 148 (138)111 (134)1,211

Purchases 119,549 16,000 11,999 927 1,982 26,268 22,592 11,958 10,202 3,628 3,579 12,999 9,577 12,854 2,983

Demand Response Incentive (502)502 502 0 (65) (100) (238) (374)306 (30)0 Transmission Losses 755 161 169 (41) (1)333 773 14 (101) (43) (76) (29) (58) (15) (3)Third Party Transmission 2,901 53 55 (171)55 466 916 778 52 50 214 259 116 206 (41)Water Leases (0) 10 (10)
Surplus Sales (53,415) (32,103) (88,858)5,373 3,981 (10,452) (7,133) (5,148) (10,890) (9,428) (8,418) (4,603) (4,575) (3,955)1,835

PCA Defined Net Power Supply Expense 80,220 50,962 44,183 7,051 11,503 27,577 18,414 (1,519) (1,248)2,538 (2,648)3,234 (1,363)7,473 9,208
PCA Year NPSE (Apr‐Mar)
Net Power Supply Expense 2021-2022 2022-2023 2023-2024
Mar 31 2022 Bridger 83,080 119,783 131,370 Boardman 24 Valmy 21,392 31,397 31,015
Coal 104,495 151,179 162,385

Langley 66,610 74,142 66,505
Natural Gas Plants 22,331 12,841 76,457
Natural Gas 88,942 86,984 142,962 CSPP 195,068 212,586 222,477 PPAs 52,569 51,536 57,869

Purchases 144,203 47,200 20,256

Demand Response Incentive 7,112 8,116 8,116Transmission Losses 1,691 1,170 1,229Third Party Transmission 7,755 5,149 5,407Water Leases 0 0
Surplus Sales (79,258) (65,086) (156,788)

PCA Defined Net Power Supply Expense 522,578 498,835 463,911

$/MWh
Market PurchasesSurplus Sales - MarketBridgerBoardmanValmy
Langley

Change
Net Power Supply Expense
Bridger (19,165)21,169 34,584 Boardman 24 Valmy 5,074 20,831 22,770
Coal (14,067)42,001 57,354

Langley 15,460 28,365 21,140
Natural Gas Plants 16,247 (5,696)36,249
Natural Gas 31,707 22,670 57,388 CSPP (10,066)395 2,363 PPAs 3,359 1,283 3,211

Purchases 119,549 16,000 11,999

Demand Response Incentive (502)502 502Transmission Losses 755 161 169Third Party Transmission 2,901 53 55Water Leases (0)
Surplus Sales (53,415) (32,103) (88,858)

PCA Defined Net Power Supply Expense 80,220 50,962 44,183
Apr 2022 May 2022 Jun 2022 Jul 2022 Aug 2022 Sep 2022 Oct 2022 Nov 2022 Dec 2022 Jan 2023 Feb 2023 Mar 2023
9,444 2,249 5,735 10,763 10,768 10,484 10,550 11,461 12,067 12,795 11,814 11,652 254 254 2,055 3,589 3,599 3,492 3,603 3,500 3,614 3,730 3,445 262
9,698 2,503 7,790 14,352 14,367 13,976 14,153 14,961 15,682 16,526 15,259 11,914

6,563 391 4,602 4,941 4,965 6,942 7,334 8,058 7,705 7,954 7,855 6,832
281 281 281 3,926 5,966 281 281 281 281 421 281 281
6,844 672 4,883 8,867 10,931 7,223 7,615 8,339 7,986 8,375 8,136 7,113 15,817 15,833 22,446 24,019 22,981 16,991 16,537 15,972 15,876 15,380 17,213 13,519 4,317 3,836 3,636 3,572 3,499 3,496 4,356 4,723 4,962 5,189 4,909 5,041

(209)5,662 8,252 13,670 14,687 691 (388)60 4,362 949 (266) (269)

406 1,811 2,173 1,811 1,087 828 50 37 80 207 195 99 86 100 116 70 71 57322 285 631 843 784 478 524 295 231 251 247 259 0
(8,808) (5,619) (9,807) (5,228) (0) (5,477) (15,656) (14,491)

28,032 28,828 48,124 67,340 69,617 39,146 34,163 40,050 49,216 41,262 29,914 23,143

$24.09 $25.59 $69.76 $117.62 $65.57 $77.58 $70.04 $36.00 $89.80 $53.63 $49.31 $77.95 $65.58 $40.89$27.74 $24.60 $26.35 $27.10 $27.16 $27.18 $27.24 $27.29 $27.36 $29.15 $29.64 $29.52 ###########$41.37 $38.85 $38.96 $39.06 $39.00 $39.15 $39.13 $40.38 $41.29 ###########
$31.35 $27.97 $23.44 $23.52 $33.34 $33.98 $37.39 $33.96 $35.03 $38.87 $31.12
Apr 2022 May 2022 Jun 2022 Jul 2022 Aug 2022 Sep 2022 Oct 2022 Nov 2022 Dec 2022 Jan 2023 Feb 2023 Mar 2023
6,727 (543)1,999 2,327 (2,716) (1,227) (490)3,617 (1,040)1,519 3,627 7,370 0 0 275 1,358 1,292 1,294 3,349 3,246 3,361 3,470 3,185 1
6,727 (543)2,274 3,685 (1,424)67 2,858 6,863 2,320 4,989 6,812 7,371

4,532 (1,494)2,580 1,022 926 3,163 3,432 3,522 2,538 2,658 3,194 2,293
3,515 4,007 (2,398) (5,524) (5,296)
4,532 (1,494)2,580 4,536 4,933 3,163 3,432 1,124 (2,986) (2,638)3,194 2,293 84 344 355 (284)187 (189) (104) (817)48 (92)883 (19) 1,216 1,109 64 (698) (548) (2)122 (1,008) (1,065)109 296 1,688

(717)5,397 6,888 2,408 6,292 (859) (1,172)1,671 (2,567) (1,341)

125 (1,127) (895)518 1,053 828 7 6 12 37 65 (2) (8)20 34 (4) (4) (3)(13)6 29 47 88 5 (12) (0)1 (30) (26) (43)
(4,611)2,681 1,285 (211) (8,034) (5,228)4,018 (295) (15,656) (6,052)

7,226 7,507 13,612 8,605 8,697 2,490 (692)610 4,041 (528) (5,842)5,235
PCA Year NPSE (Apr‐Mar)
= Cells with Input
Coal 108,503,180$                     Coal 151,179,160$                   
Water for Powe 2,380,597                            Water for Powe 0                                          Forecast ‐ Base 95% Split
Gas 33,367,563                          Gas 86,983,566                        Base Forecast
Non‐PURPA 62,606,593                          Non‐PURPA 99,906,480                        1.0234 1.7726 0.7492 0.7117
3rd Party Transmission 5,455,955                            3rd Party Transmission 5,149,239                          
Surplus Sales (51,735,153)                        Surplus Sales (65,085,848)                       
Net 95% account 160,578,735$                     Net 95% account 278,132,598$                   0.8531 1.3549 0.5018 0.5018
difference of Net 95 % account 117,553,863$                     
0.0751 0.0541 ‐0.0209 ‐0.0209
(cents per kWh)
Net 95% rate 0.7117 1.9516 3.1816 1.2301 1.19260
PURPA 133,853,869$                     PURPA 212,586,058$                   
Net 100% account 133,853,869$                     Net 100% account 212,586,058$                   
difference of 100% accoun 78,732,189$                        
Recoverable Portion PCA Forecast (Idaho
(cents per kWh)106,704,658$             95% Accounts
Net 100% rate 0.5018 75,227,251                  PURPA
(3,136,365)                   Demand Response
178,795,544$             
Demand Response Incentiv 11,252,265$                        Demand Response Incentiv 8,115,900$                        
Net 100% account 11,252,265$                        Net 100% account 8,115,900$                        178,795,145$             
difference of 100% accoun (3,136,365)$                        1.1926$                        
(cents per kWh)
Net 100% rate ‐0.0209
TOTAL NPSE 305,684,869$                     TOTAL NPSE 498,834,556$                   
(cents per kWh)
Total Forecast Rate 1.1926 0.011926                           

Last Year's PCA 
Rate (Final Order)Net change
(cents per kWh)Total PC
True‐Up 38,669,526$                        0.2579 0.002579                           217,459,632$             113,504,783$      103,386,078$   
Reveue Sharin 568,771.00$                        0.7571
(cents per kWh)
Total PCA Rate 1.4505 91.59%
System Sales 15,690,546 Idaho Percentage
Idaho Jurisdictional Sales 14,992,046 95.55%
BASE 1
PCA CALCULATIONS
Base Forecast Tariff Calculation
(cents per kWh)
BASE 2
BASE 3
Base Forecast
Base Forecast
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
9 * * * SUMMARY OF RESULTS * * *
10
11 DEVELOPMENT OF RATE BASE COMPONENTS
12
13 ELECTRIC PLANT IN SERVICE 6,441,732,366 6,190,113,105 251,619,261
14 LESS: ACCUM PROVISION FOR DEPRECIATION 2,416,221,274 2,319,550,450 96,670,824
15 AMORT OF OTHER UTILITY PLANT 37,557,485 36,104,579 1,452,907
16 NET ELECTRIC PLANT IN SERVICE 3,987,953,607 3,834,458,077 153,495,530
17 LESS: CUSTOMER ADV FOR CONSTRUCTION 7,897,846 7,840,341 57,505
18 LESS: ACCUM DEFERRED INCOME TAXES 479,842,916 461,170,942 18,671,974
19 ADD : PLT HLD FOR FUTURE 4,095,344 3,959,068 136,276
20 ADD : WORKING CAPITAL 124,704,125 119,635,298 5,068,827
21 ADD : CONSERVATION+OTHER DFRD PROG.27,790,408 24,483,880 3,306,528
22 ADD : IERCO RATE BASE 40,345,976 38,542,096 1,803,880
23 ADD : ELECTRIC PLANT ACQUISITION ADJ.-114/5 662,038 636,729 25,309
24 TOTAL COMBINED RATE BASE 3,697,810,735 3,552,703,864 145,106,871
25
26 RATE OF RETURN UNDER PRESENT RATES
27 OPERATING REVENUES
28 SALES REVENUES 1,035,636,761 991,216,908 44,419,853
29 OTHER OPERATING REVENUES 82,342,549 78,433,294 3,909,255
30 TOTAL OPERATING REVENUES 1,117,979,310 1,069,650,202 48,329,108
31 OPERATING EXPENSES
32 OPERATION & MAINTENANCE EXPENSES 683,212,307 649,599,003 33,613,303
33 DEPRECIATION EXPENSE 123,577,643 118,717,824 4,859,819
34 AMORTIZATION OF LIMITED TERM PLANT 6,256,000 6,013,901 242,099
35 ACCRETION EXPENSE 48,379 46,482 1,896
36 TAXES OTHER THAN INCOME 26,188,106 24,462,684 1,725,422
37 REGULATORY DEBITS/CREDITS 1,087,391 878,396 208,995
38 PROVISION FOR DEFERRED INCOME TAXES (14,885,993)(14,382,662)(503,331)
39 INVESTMENT TAX CREDIT ADJUSTMENT 11,264,544 10,824,447 440,097
40 FEDERAL INCOME TAXES 29,156,558 28,544,231 612,327
41 STATE INCOME TAXES 11,411,459 11,163,398 248,061
42 TOTAL OPERATING EXPENSES 877,316,394 835,867,704 41,448,690
43 OPERATING INCOME 240,662,916 233,782,498 6,880,418
44 ADD: IERCO OPERATING INCOME E10 6,715,053 6,414,821 300,232
45 CONSOLIDATED OPERATING INCOME 247,377,969 240,197,319 7,180,650
46
47 RATE OF RETURN UNDER PRESENT RATES 6.690%6.761%4.949%
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 1 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
48 * * * SUMMARY OF RESULTS * * *
49
50 RATE OF RETURN UNDER PRESENT RATES
51 TOTAL COMBINED RATE BASE 3,697,810,735 3,552,703,864 145,106,871
52
53 SALES REVENUES 1,035,636,761 991,216,908 44,419,853
54 OTHER OPERATING REVENUES 82,342,549 78,433,294 3,909,255
55 TOTAL OPERATING REVENUES 1,117,979,310 1,069,650,202 48,329,108
56 OPERATING EXPENSES
57 OPERATION & MAINTENANCE EXPENSES 683,212,307 649,599,003 33,613,303
58 DEPRECIATION EXPENSE 123,577,643 118,717,824 4,859,819
59 AMORTIZATION OF LIMITED TERM PLANT 6,256,000 6,013,901 242,099
60 ACCRETION EXPENSE 48,379 46,482 1,896
61 TAXES OTHER THAN INCOME 26,188,106 24,462,684 1,725,422
62 REGULATORY DEBITS/CREDITS 1,087,391 878,396 208,995
63 PROVISION FOR DEFERRED INCOME TAXES (14,885,993)(14,382,662)(503,331)
64 INVESTMENT TAX CREDIT ADJUSTMENT 11,264,544 10,824,447 440,097
65 FEDERAL INCOME TAXES 29,156,558 28,544,231 612,327
66 STATE INCOME TAXES 11,411,459 11,163,398 248,061
67 TOTAL OPERATING EXPENSES 877,316,394 835,867,704 41,448,690
68 OPERATING INCOME 240,662,916 233,782,498 6,880,418
69 ADD: IERCO OPERATING INCOME 6,715,053 6,414,821 300,232
70 CONSOLIDATED OPERATING INCOME 247,377,969 240,197,319 7,180,650
71 RATE OF RETURN UNDER PRESENT RATES 6.690%6.761%4.949%
72
73 DEVELOPMENT OF REVENUE REQUIREMENTS
74 RATE OF RETURN REQUIRED @ No ROE Specified in IPC-11-08 7.860%7.860%7.860%
75
76 RETURN AT CLAIMED RATE OF RETURN 290,647,924 279,242,524 11,405,400
77 EARNINGS DEFICIENCY 43,269,955 39,045,205 4,224,750
78 NET-TO-GROSS TAX MULTIPLIER 1.347 1.347 1.347
79
80 REVENUE DEFICIENCY 58,284,629 52,593,891 5,690,738
81
82 FIRM JURISDICTIONAL REVENUES 981,573,769 939,617,644 41,956,125
83
84 PERCENT INCREASE REQUIRED 5.94%5.60%13.56%
85
86 SALES AND WHEELING REVENUES REQUIRED 1,039,858,398 992,211,535 47,646,863
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 2 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
87 * * * TABLE 1 - ELECTRIC PLANT IN SERVICE * * *
88
89 INTANGIBLE PLANT
90 301 - ORGANIZATION P101P 5,703 5,480 223
91 302 - FRANCHISES & CONSENTS D10 37,320,909 35,894,193 1,426,715
92 303 - MISCELLANEOUS P101P 44,325,821 42,594,045 1,731,776
93
94 TOTAL INTANGIBLE PLANT 81,652,433 78,493,719 3,158,714
95
96 PRODUCTION PLANT
97 310-316 / STEAM PRODUCTION D10 983,432,391 945,837,430 37,594,961
98 330-336 / HYDRAULIC PRODUCTION D10 1,027,294,147 988,022,425 39,271,722
99 340-346 / OTHER PRODUCTION D10 555,623,121 534,382,587 21,240,534
100
101 TOTAL PRODUCTION PLANT 2,566,349,659 2,468,242,442 98,107,217
102
103 TRANSMISSION PLANT
104 350 / LAND & LAND RIGHTS
105 TRANSMISSION SERVICE D11 39,264,322 37,763,313 1,501,009
106 DIRECT ASSIGNMENT DA350 0 0 0
107 TOTAL ACCOUNT 350 39,264,322 37,763,313 1,501,009
108
109 352 / STRUCTURES & IMPROVEMENTS
110 TRANSMISSION SERVICE D11 86,244,147 82,947,179 3,296,968
111 DIRECT ASSIGNMENT DA352 658 0 658
112 TOTAL ACCOUNT 352 86,244,805 82,947,179 3,297,626
113
114 353 / STATION EQUIPMENT
115 TRANSMISSION SERVICE D11 463,801,909 446,071,544 17,730,364
116 DIRECT ASSIGNMENT DA353 111,594 75,100 36,494
117 TOTAL ACCOUNT 353 463,913,503 446,146,644 17,766,858
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 3 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
118 * * * TABLE 1 - ELECTRIC PLANT IN SERVICE * * *
119
120 354 / TOWERS & FIXTURES
121 TRANSMISSION SERVICE D11 228,176,239 219,453,446 8,722,793
122 DIRECT ASSIGNMENT DA354 0 0 0
123 TOTAL ACCOUNT 354 228,176,239 219,453,446 8,722,793
124
125 355 / POLES & FIXTURES
126 TRANSMISSION SERVICE D11 217,872,554 209,543,654 8,328,900
127 DIRECT ASSIGNMENT DA355 33,842 0 33,842
128 TOTAL ACCOUNT 355 217,906,396 209,543,654 8,362,742
129
130 356 / OVERHEAD CONDUCTORS & DEVICES
131 TRANSMISSION SERVICE D11 253,438,674 243,750,141 9,688,533
132 DIRECT ASSIGNMENT DA356 26,495 1,189 25,306
133 TOTAL ACCOUNT 356 253,465,169 243,751,330 9,713,839
134
135 359 / ROADS & TRAILS
136 TRANSMISSION SERVICE D11 390,266 375,347 14,919
137 DIRECT ASSIGNMENT DA359 0 0 0
138 TOTAL ACCOUNT 359 390,266 375,347 14,919
139
140 TOTAL TRANSMISSION PLANT 1,289,360,700 1,239,980,914 49,379,786
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 4 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
141 * * * TABLE 1 - ELECTRIC PLANT IN SERVICE * * *
142
143 DISTRIBUTION PLANT
144 360 / LAND & LAND RIGHTS ACCT360 7,683,074 7,485,785 197,289
145 361 / STRUCTURES & IMPROVEMENTS ACCT361 51,698,404 49,873,701 1,824,703
146 362 / STATION EQUIPMENT ACCT362 299,139,312 288,099,654 11,039,658
147
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 5 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
148 * * * TABLE 1 - ELECTRIC PLANT IN SERVICE * * *
149
150 364 / POLES, TOWERS & FIXTURES DA364 297,915,726 274,478,511 23,437,215
151 365 / OVERHEAD CONDUCTORS & DEVICES DA365 148,963,270 139,411,142 9,552,128
152 366 / UNDERGROUND CONDUIT DA366 53,140,833 52,352,719 788,114
153 367 / UNDERGROUND CONDUCTORS & DEVICES DA367 309,064,375 304,359,251 4,705,124
154 368 / LINE TRANSFORMERS D60 670,064,383 646,481,949 23,582,434
155 369 / SERVICES DA369 65,815,991 62,899,539 2,916,452
156 370 / METERS ACCT370 112,004,367 108,284,989 3,719,378
157 371 / INSTALLATIONS ON CUSTOMER PREMISES DA371 4,773,845 4,482,463 291,382
158 373 / STREET LIGHTING SYSTEMS DA373 5,609,417 5,361,317 248,101
159
160 TOTAL DISTRIBUTION PLANT 2,025,872,997 1,943,571,020 82,301,978
161
162 GENERAL PLANT
163 389 / LAND & LAND RIGHTS PTD 20,911,506 20,094,509 816,997
164 390 / STRUCTURES & IMPROVEMENTS PTD 142,054,779 136,504,807 5,549,972
165 391 / OFFICE FURNITURE & EQUIPMENT PTD 40,958,240 39,358,033 1,600,207
166 392 / TRANSPORTATION EQUIPMENT PTD 107,643,497 103,437,948 4,205,549
167 393 / STORES EQUIPMENT PTD 4,279,317 4,112,127 167,190
168 394 / TOOLS, SHOP & GARAGE EQUIPMENT PTD 12,058,163 11,587,060 471,103
169 395 / LABORATORY EQUIPMENT PTD 14,889,449 14,307,729 581,719
170 396 / POWER OPERATED EQUIPMENT PTD 23,700,119 22,774,173 925,946
171 397 / COMMUNICATIONS EQUIPMENT PTD 74,643,039 71,726,792 2,916,247
172 398 / MISCELLANEOUS EQUIPMENT PTD 10,088,702 9,694,544 394,158
173
174 TOTAL GENERAL PLANT 451,226,810 433,597,722 17,629,088
175
176 TOTAL PLANT BEFORE FAS 143 ADJ 6,414,462,599 6,163,885,815 250,576,784
177
178 FAS 143 & OTHER ADJUSTMENTS D10 27,269,767 26,227,290 1,042,477
179 TOTAL ELECTRIC PLANT IN SERVICE 6,441,732,366 6,190,113,105 251,619,261
180
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 6 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
181 * * * TABLE 2 - ACCUMULATED PROVISION FOR DEPRECIATION * * *
182
183 PRODUCTION PLANT
184 310-316 / STEAM PRODUCTION L 97 569,898,891 548,112,618 21,786,273
185 330-336 / HYDRAULIC PRODUCTION L 98 475,256,339 457,088,091 18,168,248
186 340-346 / OTHER PRODUCTION L 99 147,554,412 141,913,656 5,640,756
187 TOTAL PRODUCTION PLANT 1,192,709,642 1,147,114,364 45,595,277
188
189 TRANSMISSION PLANT
190 350 / LAND & LAND RIGHTS L 107 9,510,667 9,147,090 363,577
191 352 / STRUCTURES & IMPROVEMENTS L 112 32,273,589 31,039,587 1,234,002
192 353 / STATION EQUIPMENT L 117 120,734,651 116,110,781 4,623,869
193 354 / TOWERS & FIXTURES L 123 75,766,058 72,869,649 2,896,409
194 355 / POLES & FIXTURES L 128 74,266,710 71,416,526 2,850,184
195 356 / OVERHEAD CONDUCTORS & DEVICES L 133 86,287,194 82,980,310 3,306,884
196 359 / ROADS & TRAILS L 138 292,474 281,293 11,181
197 TOTAL TRANSMISSION PLANT 399,131,342 383,845,237 15,286,105
198
199 DISTRIBUTION PLANT
200 360 / LAND & LAND RIGHTS L 144 187,786 182,964 4,822
201 361 / STRUCTURES & IMPROVEMENTS L 145 15,173,714 14,638,155 535,559
202 362 / STATION EQUIPMENT L 146 67,127,213 64,649,901 2,477,312
203 364 / POLES, TOWERS & FIXTURES L 150 147,533,649 135,927,086 11,606,564
204 365 / OVERHEAD CONDUCTORS & DEVICES L 151 56,807,230 53,164,520 3,642,710
205 366 / UNDERGROUND CONDUIT L 152 18,108,522 17,839,961 268,562
206 367 / UNDERGROUND CONDUCTORS & DEVICES L 153 99,103,297 97,594,572 1,508,725
207 368 / LINE TRANSFORMERS L 154 192,914,512 186,125,024 6,789,488
208 369 / SERVICES L 155 44,425,876 42,457,267 1,968,609
209 370 / METERS L 156 39,281,996 37,977,541 1,304,454
210 371 / INSTALLATIONS ON CUSTOMER PREMISES L 157 1,716,098 1,611,352 104,746
211 373 / STREET LIGHTING SYSTEMS L 158 2,630,426 2,514,084 116,342
212 TOTAL DISTRIBUTION PLANT 685,010,318 654,682,427 30,327,891
213
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 7 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
214 * * * TABLE 2 - ACCUMULATED PROVISION FOR DEPRECIATION * * *
215
216 GENERAL PLANT
217 389 / LAND & LAND RIGHTS L 163 0 0 0
218 390 / STRUCTURES & IMPROVEMENTS L 164 34,109,337 32,776,712 1,332,626
219 391 / OFFICE FURNITURE & EQUIPMENT L 165 16,503,445 15,858,668 644,777
220 392 / TRANSPORTATION EQUIPMENT L 166 23,297,167 22,386,965 910,203
221 393 / STORES EQUIPMENT L 167 1,148,548 1,103,675 44,873
222 394 / TOOLS, SHOP & GARAGE EQUIPMENT L 168 4,108,368 3,947,857 160,511
223 395 / LABORATORY EQUIPMENT L 169 6,495,290 6,241,524 253,766
224 396 / POWER OPERATED EQUIPMENT L 170 5,170,279 4,968,280 201,999
225 397 / COMMUNICATIONS EQUIPMENT L 171 27,205,063 26,142,182 1,062,881
226 398 / MISCELLANEOUS EQUIPMENT L 172 3,806,325 3,657,614 148,710
227 TOTAL GENERAL PLANT 121,843,823 117,083,478 4,760,345
228
229 UNDER- / OVERALLOCATED SALVAGE L P101P 0 0 0
230 ACCUM DEPR BEFORE FAS 143/OTHER ADJ 2,398,695,125 2,302,725,506 95,969,619
231
232 FAS 143 ADJ &/OR DISALLOWED COSTS L 230 17,526,149 16,824,944 701,205
233 TOTAL ACCUM PROVISION FOR DEPR 2,416,221,274 2,319,550,450 96,670,824
234
235 AMORTIZATION OF OTHER UTILITY PLANT
236 INTANGIBLE PLANT L 94 37,557,485 36,104,579 1,452,907
237 HYDRAULIC PRODUCTION L 98 0 0 0
238
239 TOTAL AMORT OF OTHER UTILITY PLANT 37,557,485 36,104,579 1,452,907
240
241 TOTAL ACCUM PROVISION FOR DEPR
242 & AMORTIZATION OF OTHER UTILITY PLANT 2,453,778,760 2,355,655,029 98,123,731
243
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 8 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
244 * * * TABLE 3 - ADDITIONS & DELETIONS TO RATE BASE * * *
245
246 NET ELECTRIC PLANT IN SERVICE 3,987,953,607 3,834,458,077 153,495,530
247 LESS:
248 252 CUSTOMER ADVANCES FOR CONSTRUCTION
249 POWER SUPPLY D10 0 0 0
250 OTHER DA252 7,897,846 7,840,341 57,505
251 TOTAL CUSTOMER ADV FOR CONSTRUCTION 7,897,846 7,840,341 57,505
253 ACCUMULATED DEFERRED INCOME TAXES
254 190 / ACCUMULATED DEFERRED INCOME TAXES
255 CUSTOMER ADVANCES FOR CONSTUCTION DA252 (1,658,547)(1,646,471)(12,076)
256 OTHER LABOR (18,406,387)(17,559,418)(846,969)
257 281 / ACCELERATED AMORTIZATION P101P 0 0 0
258 282 / OTHER PROPERTY P101P 442,010,948 424,741,917 17,269,031
259 283 / OTHER P101P 57,896,902 55,634,915 2,261,988
260 TOTAL ACCUM DEFERRED INCOME TAXES 479,842,916 461,170,942 18,671,974
262 NET ELECTRIC PLANT IN SERVICE 3,500,212,845 3,365,446,794 134,766,051
263 ADD:
264 WORKING CAPITAL
265 151 / FUEL INVENTORY E10 31,377,098 29,974,219 1,402,879
266 154 / PLANT MATERIALS & SUPPLIES
267 PRODUCTION - GENERAL L 101 19,033,303 18,305,692 727,611
268 TRANSMISSION - GENERAL L 140 13,891,238 13,359,233 532,005
269 DISTRIBUTION - GENERAL L 160 34,497,214 33,095,750 1,401,464
270 OTHER - UNCLASSIFIED L 176 4,378,844 4,207,788 171,057
271 TOTAL ACCOUNT 154 71,800,600 68,968,463 2,832,137
272 165 / PREPAID ITEMS
273 AD VALOREM TAXES L 708 2,421,662 2,326,883 94,780
274 OTHER PROD-RELATED PREPAYMENTS D10 4,165,057 4,005,834 159,223
275 INSURANCE L 101 4,607,578 4,431,438 176,140
276 PENSION EXPENSE LABOR 0 0 0
277 SOFTWARE CONTRACTS L 92 5,750,492 5,525,825 224,667
278 MISCELLANEOUS PREPAYMENTS L 1062 4,581,638 4,402,637 179,001
279 TOTAL ACCOUNT 165 21,526,427 20,692,616 833,811
280 WORKING CASH ALLOWANCE L 625 0 0 0
281
282 TOTAL WORKING CAPITAL 124,704,125 119,635,298 5,068,827
284 NET ELECTRIC PLANT IN SERVICE 3,624,916,970 3,485,082,091 139,834,878
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 9 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
285 * * * TABLE 3 - ADDITIONS & DELETIONS TO RATE BASE * * *
286
287 NET ELECTRIC PLANT IN SERVICE 3,624,916,970 3,485,082,091 139,834,878
288 ADD:
289 105 / PLANT HELD FOR FUTURE USE
290 HYDRAULIC PRODUCTION L 98 109,609 105,419 4,190
291 TRANS LAND & LAND RIGHTS L 107 1,235,716 1,188,477 47,239
292 TRANS STRUCTURES & IMPROVEMENTS L 112 383,232 368,579 14,653
293 TRANS STATION EQUIPMENT L 117 32,296 31,059 1,237
294 DIST LAND & LAND RIGHTS L 144 1,517,337 1,478,374 38,963
295 DIST STRUCTURES & IMPROVEMENTS L 145 511,838 493,773 18,065
296 DIST STATION EQUIPMENT L 146 0 0 0
297 GEN LAND & LAND RIGHTS L 163 305,317 293,388 11,928
298 GEN STRUCTURES & IMPROVEMENTS L 164 0 0 0
299 TRANSPORTATION EQUIPMENT L 166 0 0 0
300 TOTAL PLANT HELD FOR FUTURE USE 4,095,344 3,959,068 136,276
301
302 ELECTRIC PLANT ACQUISITION ADJ.-114/5 D10 662,038 636,729 25,309
303
304 DEFERRED PROGRAMS:
305 182 / CONSERVATION PROGRAMS
306 IDAHO DEFERRED CONSERVATION PROGRAMS CIDA 0 0 0
307 OREGON DEFERRED CONSERVATION PROGRAMS CODA 0 0 0
308 TOTAL CONSERVATION PROGRAMS 0 0 0
309 182 / MISC. OTHER REGULATORY ASSETS
310 CUB FUND INTEREST (OPUC 15-399)CODA 48,512 0 48,512
311 AM. FALLS BOND REFINANCING D10 213,718 205,548 8,170
312 SFAS 87 CAPITALIZED PENSION - OPUC ORDER 10-064 CODA 6,507,452 0 6,507,452
313 CLOUD COMPUTING - IPUC ORDER 34707 CIDA 1,459,174 1,459,174 0
314 LIDAR SURVEY - IPUC ORDER 32426 CIDA 10,901 10,901 0
315 PS&I - SHOSHONE FALLS EXPANSION (IPUC Order 29904) CIDA 0 0 0
316 SIEMENS LTP DEFERRED RATE BASE (IPUC Order 33420) CIDA 9,151,853 9,151,853 0
317 SIEMENS LTP RATE BASE (IPUC Order 33420)CIDA 13,656,404 13,656,404 0
318 SIEMENS LTP DEFERRED RATE BASE (OPUC ORDER 15-387) CODA 379,159 0 379,159
319 SIEMENS LTP RATE BASE (OPUC ORDER 15-387)CODA 560,250 0 560,250
320 TOTAL OTHER REGULATORY ASSETS 31,987,423 24,483,880 7,503,543
321 182 / OTHER DEFERRED PROGRAMS E10 0 0 0
322 254 / JIM BRIDGER PLANT END OF LIFE DEPR - OPUC ORDER 12-296 CODA (4,184,771)0 (4,184,771)
323 RECONNECT FEES - (OPUC ADV 16-09)CODA (12,244)0 (12,244)
324 TOTAL DEFERRED PROGRAMS 27,790,408 24,483,880 3,306,528
325
326 DEVELOPMENT OF IERCO RATE BASE
327 INVESTMENT IN IERCO E10 25,633,183 24,487,116 1,146,067
328 PREPAID COAL ROYALTIES E10 1,001,325 956,555 44,770
329 NOTES RECEIVABLE FROM SUBSIDIARY E10 13,711,468 13,098,424 613,044
330 TOTAL IERCO RATE BASE 40,345,976 38,542,096 1,803,880
331 3,697,810,735 3,552,703,864 145,106,871
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 10 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
333 * * * TABLE 4 - OPERATING REVENUES * * *
334 OPERATING REVENUES
335
336 FIRM ENERGY SALES & REFUNDS
337 440-448 / RETAIL RETREV 974,391,283 932,709,732 41,681,551
338 447 / FIRM SALES FOR RESALE E10 0 0 0
339 447 / OPPORTUNITY SALES E10 61,245,478 58,507,175 2,738,303
340
341 TOTAL SALES OF ELECTRICITY 1,035,636,761 991,216,908 44,419,853
342
343 OTHER OPERATING REVENUES
344
345 449 / OATT TARIFF REFUND
346 NETWORK D11 0 0 0
347 POINT-TO-POINT D11 0 0 0
348 TOTAL ACCOUNT 449 0 0 0
349
350 451 / MISCELLANEOUS SERVICE REVENUES DA451 3,545,766 3,510,094 35,672
351
352 454 / RENTS FROM ELECTRIC PROPERTY
353 SUBSTATION EQUIPMENT L 117 2,397,201 2,305,394 91,807
354 TRANSFORMER RENTALS L 154 14,854 14,331 523
355 LINE RENTALS D11 0 0 0
356 COGENERATION L 491 1,317,176 1,258,285 58,891
357 DARK FIBER PROJECT CIDA 300,000 300,000 0
358 POLE ATTACHMENTS L 150 1,082,105 996,975 85,130
359 FACILITIES CHARGES DA4547 7,537,256 7,218,487 318,769
360 OTHER RENTALS L 101 978,412 941,009 37,403
361 WATER LEASE E10 63,369 60,536 2,833
362 TOTAL ACCOUNT 454 13,690,373 13,095,016 595,357
363
364 456 / OTHER ELECTRIC REVENUES
365 TRANSMISSION NETWORK SERVICES - FIRM D11 7,182,486 6,907,912 274,574
366 TRANSMISSION NETWORK SERVICES - DIST FACILITIES D60 816,367 787,636 28,731
367 TRANSMISSION - POINT-TO-POINT & OTHER D11 33,926,238 32,629,295 1,296,943
368 FIBER OPTIC ATTACHMENT E10 0 0 0
369 ALTERNATE TRANSMISSION SERV. CHG.L 140 0 0 0
370 PHOTOVOLTAIC STATION SERVICE L 160 0 0 0
371 DSM RIDER FUNDS DARIDER 22,591,465 20,915,733 1,675,732
372 STANDBY SERVICE CHARGE CIDA 539,561 539,561 0
373 SIERRA PACIFIC USAGE CHARGE E10 49,775 47,550 2,225
374 BPA - OTHER REVENUE D10 0 0 0
375 ANTELOPE L 516 0 0 0
376 MISCELLANEOUS PTD 518 498 20
377 TOTAL ACCOUNT 456 65,106,410 61,828,183 3,278,227
378
379 TOTAL OTHER OPERATING REVENUES 82,342,549 78,433,294 3,909,255
380
381 TOTAL OPERATING REVENUES 1,117,979,310 1,069,650,202 48,329,108
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 11 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
382 * * * TABLE 5 - OPERATION & MAINTENANCE EXPENSES * * *
383
384 STEAM POWER GENERATION
385 OPERATION
386 500 / SUPERVISION & ENGINEERING D10 706,942 679,917 27,025
387 501 / FUEL E10 61,853,607 59,088,114 2,765,492
388
389 502 / STEAM EXPENSES
390 LABOR D10 0 0 0
391 OTHER E10 6,313,311 6,031,041 282,270
392 TOTAL ACCOUNT 502 6,313,311 6,031,041 282,270
393 505 / ELECTRIC EXPENSES
394 LABOR D10 0 0 0
395 OTHER E10 1,062,534 1,015,028 47,506
396 TOTAL ACCOUNT 505 1,062,534 1,015,028 47,506
397 506 / MISCELLANEOUS EXPENSES D10 6,106,307 5,872,873 233,434
398 507 / RENTS L 97 175,288 168,587 6,701
399 TOTAL STEAM OPERATION EXPENSES 76,217,990 72,855,562 3,362,429
400
401 MAINTENANCE
402 510 / SUPERVISION & ENGINEERING D10 (8,421)(8,099)(322)
403 511 / STRUCTURES D10 872,839 839,472 33,367
404 512 / BOILER PLANT
405 LABOR D10 0 0 0
406 OTHER E10 6,342,452 6,058,879 283,573
407 TOTAL ACCOUNT 512 6,342,452 6,058,879 283,573
408 513 / ELECTRIC PLANT
409 LABOR D10 0 0 0
410 OTHER E10 1,851,518 1,768,736 82,782
411 TOTAL ACCOUNT 513 1,851,518 1,768,736 82,782
412 514 / MISCELLANEOUS STEAM PLANT D10 7,110,247 6,838,434 271,813
413 TOTAL STEAM MAINTENANCE EXPENSES 16,168,635 15,497,422 671,213
414
415 TOTAL STEAM GENERATION EXPENSES 92,386,625 88,352,984 4,033,641
416
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 12 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
417 * * * TABLE 5 - OPERATION & MAINTENANCE EXPENSES * * *
418
419 HYDRAULIC POWER GENERATION
420 535 / SUPERVISION & ENGINEERING L 881 3,982,551 3,828,587 153,964
421 536 / WATER FOR POWER
422 WATER LEASE D10 0 0 0
423 OTHER D10 4,066,531 3,911,075 155,457
424 TOTAL ACCOUNT 536 4,066,531 3,911,075 155,457
425
426 537 / HYDRAULIC EXPENSES D10 11,237,146 10,807,569 429,577
427 538 / ELECTRIC EXPENSES
428 LABOR D10 1,033,465 993,957 39,508
429 OTHER E10 286,592 273,778 12,814
430 TOTAL ACCOUNT 538 1,320,056 1,267,735 52,321
431
432 539 / MISCELLANEOUS EXPENSES D10 3,629,708 3,490,951 138,758
433 540 / RENTS D10 232,421 223,535 8,885
434
435 TOTAL HYDRAULIC OPERATION EXPENSES 24,468,413 23,529,452 938,961
436
437 MAINTENANCE
438 541 / SUPERVISION & ENGINEERING L 887 98,606 94,836 3,770
439 542 / STRUCTURES D10 766,387 737,089 29,298
440 543 / RESERVOIRS, DAMS & WATERWAYS D10 441,812 424,922 16,890
441 544 / ELECTRIC PLANT
442 LABOR D10 1,045,678 1,005,703 39,974
443 OTHER E10 595,294 568,678 26,616
444 TOTAL ACCOUNT 544 1,640,972 1,574,381 66,590
445
446 545 / MISCELLANEOUS HYDRAULIC PLANT L 98 2,302,758 2,214,728 88,031
447
448 TOTAL HYDRAULIC MAINTENANCE EXPENSES 5,250,535 5,045,957 204,578
449
450 TOTAL HYDRAULIC GENERATION EXPENSES 29,718,948 28,575,409 1,143,539
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 13 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
451 * * * TABLE 5 - OPERATION & MAINTENANCE EXPENSES * * *
452 OTHER POWER GENERATION
453 OPERATION
454 546 / SUPERVISION & ENGINEERING L 894 444,646 427,648 16,998
455 547 / FUEL
456 SALMON DIESEL E10 5,549 5,301 248
457 OTHER E10 62,042,527 59,268,588 2,773,939
458 TOTAL ACCOUNT 547 62,048,076 59,273,888 2,774,187
459
460 548 / GENERATING EXPENSES
461 LABOR D10 2,188,368 2,104,710 83,658
462 OTHER E10 1,355,275 1,294,680 60,595
463 TOTAL ACCOUNT 548 3,543,642 3,399,390 144,252
465 549 / MISCELLANEOUS EXPENSES D10 906,903 872,234 34,669
466 550 / RENTS D10 0 0 0
468 TOTAL OTHER POWER OPER EXPENSES 66,943,267 63,973,160 2,970,107
470 MAINTENANCE
471 551 / SUPERVISION & ENGINEERING L 900 0 0 0
472 552 / STRUCTURES D10 137,226 131,980 5,246
473 553 / GENERATING & ELECTRIC PLANT
474 LABOR D10 30,759 29,583 1,176
475 OTHER E10 40,568 38,754 1,814
476 TOTAL ACCOUNT 553 71,326 68,337 2,990
478 554 / MISCELLANEOUS EXPENSES L 99 1,441,327 1,386,227 55,099
479 TOTAL OTHER POWER MAINT EXPENSES 1,649,879 1,586,544 63,335
480
481 TOTAL OTHER POWER GENERATION EXP 68,593,147 65,559,705 3,033,442
483 OTHER POWER SUPPLY EXPENSE
484 555.0 / PURCHASED POWER
485 PURCHASED POWER - TRANS LOSSES E10 1,481,513 1,415,274 66,239
486 OTHER PURCHASED POWER E10 142,511,126 136,139,413 6,371,713
487 TOTAL ACCOUNT 555.0 143,992,640 137,554,688 6,437,952
488 555.1 / COGENERATION & SMALL POWER PROD
489 CAPACITY RELATED D10 0 0 0
490 ENERGY RELATED E10 152,410,316 145,596,007 6,814,309
491 TOTAL COGEN & SMALL POWER PROD 152,410,316 145,596,007 6,814,309
493 TOTAL ACCOUNT 555 296,402,955 283,150,694 13,252,261
495 556 / LOAD CONTROL & DISPATCHING EXPENSES D10 355 341 14
496 557 / OTHER EXPENSES
497 IDAHO POWER COST-RELATED EXPENSES CIDA (24,852,847)(24,852,847)0
498 OREGON POWER COST-RELATED EXPENSES CODA (123,666)0 (123,666)
499 OTHER D10 3,917,491 3,767,732 149,759
500 TOTAL ACCOUNT 557 (21,059,022)(21,085,115)26,093
501
502 TOTAL OTHER POWER SUPPLY EXPENSES 275,344,288 262,065,921 13,278,367
504 TOTAL PRODUCTION EXPENSES 466,043,009 444,554,019 21,488,990
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 14 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
505 * * * TABLE 5 - OPERATION & MAINTENANCE EXPENSES * * *
506
507 TRANSMISSION EXPENSES
508
509 OPERATION
510 560 / SUPERVISION & ENGINEERING L 140 2,164,986 2,082,072 82,914
511 561 / LOAD DISPATCHING D12 3,913,915 3,764,292 149,622
512 562 / STATION EXPENSES L 117 2,228,143 2,142,810 85,333
513 563 / OVERHEAD LINE EXPENSES L 123+128+133 896,516 862,171 34,345
514 565 / TRANSMISSION OF ELECTRICITY BY OTHERS E10 5,488,859 5,243,451 245,408
515 566 / MISCELLANEOUS EXPENSES L 140 0 0 0
516 567 / RENTS L 140 3,438,724 3,307,028 131,696
517
518 TOTAL TRANSMISSION OPERATION 18,131,142 17,401,823 729,319
519
520 MAINTENANCE
521 568 / SUPERVISION & ENGINEERING L 140 139,055 133,730 5,326
522 569 / STRUCTURES L 112 1,021,777 982,709 39,068
523 570 / STATION EQUIPMENT L 117 1,317,637 1,267,174 50,463
524 571 / OVERHEAD LINES L 123+128+133 1,661,356 1,597,710 63,646
525 573 / MISCELLANEOUS PLANT L 140 1,794 1,725 69
526 575 / OPER TRANS MKT ADMIN - EIM L 140 574,296 552,302 21,994
527 TOTAL TRANSMISSION MAINTENANCE 4,715,915 4,535,350 180,565
528
529 TOTAL TRANSMISSION EXPENSES 22,847,058 21,937,173 909,884
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 15 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
530 * * * TABLE 5 - OPERATION & MAINTENANCE EXPENSES * * *
531
532 DISTRIBUTION EXPENSES
534 OPERATION
535 580 / SUPERVISION & ENGINEERING L 160 2,952,682 2,832,728 119,954
536 581 / LOAD DISPATCHING D60 3,645,635 3,517,329 128,305
537 582 / STATION EXPENSES L 146 1,125,351 1,083,820 41,531
538 583 / OVERHEAD LINE EXPENSES L 150+151 3,748,236 3,471,535 276,701
539 584 / UNDERGROUND LINE EXPENSES L 152+153 3,557,079 3,503,132 53,947
540 585 / STREET LIGHTING & SIGNAL SYSTEMS L 158 14 13 1
541 586 / METER EXPENSES L 156 3,698,908 3,576,077 122,831
542 587 / CUSTOMER INSTALLATIONS EXPENSE L 157 769,913 722,920 46,993
543 588 / MISCELLANEOUS EXPENSES L 160 3,025,283 2,902,380 122,903
544 589 / RENTS L 160 336,383 322,718 13,666
545 TOTAL DISTRIBUTION OPERATION 22,859,484 21,932,651 926,833
547 MAINTENANCE
548 590 / SUPERVISION & ENGINEERING L 160 7,835 7,517 318
549 591 / STRUCTURES L 145 0 0 0
550 592 / STATION EQUIPMENT L 146 3,105,950 2,991,326 114,624
551 593 / OVERHEAD LINES L 150+151 14,042,862 13,006,195 1,036,667
552 594 / UNDERGROUND LINES L 152+153 407,299 401,122 6,177
553 595 / LINE TRANSFORMERS L 154 47,709 46,030 1,679
554 596 / STREET LIGHTING & SIGNAL SYSTEMS L 158 201,671 192,751 8,920
555 597 / METERS L 156 612,889 592,536 20,352
556 598 / MISCELLANEOUS PLANT L 157 66,452 62,396 4,056
557 TOTAL DISTRIBUTION MAINTENANCE 18,492,667 17,299,873 1,192,794
559 TOTAL DISTRIBUTION EXPENSES 41,352,150 39,232,524 2,119,627
561 CUSTOMER ACCOUNTING EXPENSES
562 901 / SUPERVISION L 961 627,132 590,685 36,447
563 902 / METER READING CW902 1,410,005 1,063,114 346,891
564 903 / CUSTOMER RECORDS & COLLECTIONS CW903 10,319,486 9,975,804 343,681
565 904 / UNCOLLECTIBLE ACCOUNTS CW904 1,018,665 969,242 49,423
566 905 / MISC EXPENSES L 563+564+565 399 375 23
567 TOTAL CUSTOMER ACCOUNTING EXPENSES 13,375,687 12,599,221 776,466
568 CUSTOMER SERVICES & INFORMATION EXPENSES
569 907 / SUPERVISION L 968 580,656 540,118 40,539
570 908 / CUSTOMER ASSISTANCE
571 SYSTEM CONSERVATION E100 174,938 167,116 7,822
572 OTHER ACCT908 26,574,469 24,714,782 1,859,687
573 TOTAL ACCOUNT 908 26,749,407 24,881,898 1,867,509
574 909 / INFORMATION & INSTRUCTIONAL DA909 211,865 204,808 7,057
575 910 / MISCELLANEOUS EXPENSES L 573+574 666,742 620,385 46,357
576 TOTAL CUST SERV & INFORMATN EXPENSES 28,208,671 26,247,210 1,961,462
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 16 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
577 * * * TABLE 5 - OPERATION & MAINTENANCE EXPENSES * * *
578 SALES EXPENSES
0 0 0
580 TOTAL SALES EXPENSES 0 0 0
582 ADMINISTRATIVE & GENERAL EXPENSES
583 920 / ADMINISTRATIVE & GENERAL SALARIES LABOR 60,213,178 57,442,471 2,770,707
584 921 / OFFICE SUPPLIES LABOR 9,895,239 9,439,910 455,329
585 922 / ADMIN & GENERAL EXPENSES TRANSFERRED-CR LABOR (23,988,184)(22,884,368)(1,103,815)
586 923 / OUTSIDE SERVICES LABOR 5,428,720 5,178,918 249,802
587 924 / PROPERTY INSURANCE
588 PRODUCTION - STEAM L 97 246,200 236,788 9,412
589 ALL RISK & MISCELLANEOUS P110P 3,151,275 3,030,953 120,323
590 TOTAL ACCOUNT 924 3,397,475 3,267,741 129,735
592 925 / INJURIES & DAMAGES LABOR 5,178,953 4,940,644 238,309
593 926 / EMPLOYEE PENSIONS & BENEFITS
594 926 / EMP PENSIONS AND BENEFITS - GENERAL LABOR 24,223,935 23,109,272 1,114,663
595 926.203 / EMP PENSIONS AND BENEFITS - OREGON CODA 1,061,854 0 1,061,854
596 926.204 / EMP PENSIONS AND BENEFITS - IDAHO CIDA 12,865,285 12,865,285 0
597 926.205 / EMP PENSIONS AND BENEFITS - FERC D11 0 0 0
598 TOTAL ACCOUNT 926 38,151,074 35,974,556 2,176,517
599 927 / FRANCHISE REQUIREMENTS CIDA 0 0 0
600 928 / REGULATORY COMMISSION EXPENSES
601 FERC ADMIN ASSESS & SECURITIES
602 CAPACITY RELATED D10 1,981,579 1,905,827 75,752
603 ENERGY RELATED E10 897,433 857,309 40,124
604 FERC RATE CASE D11 0 0 0
605 FERC ORDER 472 E99 691,553 660,392 31,161
606 FERC OTHER D11 173,485 166,853 6,632
607 FERC - OREGON HYDRO FEE D11 118,550 114,018 4,532
608 SEC EXPENSES L 176 0 0 0
609 IDAHO PUC -RATE CASE CIDA 0 0 0
610 -OTHER CIDA 21,272 21,272 0
611 OREGON PUC -RATE CASE CODA 0 0 0
612 -OTHER CODA 934,856 0 934,856
613 TOTAL ACCOUNT 928 4,818,728 3,725,670 1,093,058
615 929 / DUPLICATE CHARGES LABOR 0 0 0
616 930.1 / GENERAL ADVERTISING LABOR 29,194 27,850 1,343
617 930.2 / MISCELLANEOUS EXPENSES LABOR 3,329,196 3,176,003 153,193
618 931 / RENTS L 174 0 0 0
619 TOTAL ADM & GEN OPERATION 106,453,573 100,289,394 6,164,179
621 935 / GENERAL PLANT MAINTENANCE L 174 4,932,159 4,739,463 192,696
622
623 TOTAL ADMIN & GENERAL EXPENSES 111,385,732 105,028,857 6,356,875
625 TOTAL OPER & MAINT EXPENSES 683,212,307 649,599,003 33,613,303
626
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 17 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
627 * * * TABLE 6 - DEPRECIATION & AMORTIZATION EXPENSE * * *
628
629 DEPRECIATION EXPENSE
630 310-316 / STEAM PRODUCTION L 97 32,768,426 31,515,744 1,252,682
631 330-336 / HYDRAULIC PRODUCTION L 98 14,287,073 13,740,902 546,171
632 340-346 / OTHER PRODUCTION L 99 12,051,648 11,590,934 460,714
633 TOTAL PRODUCTION PLANT 59,107,147 56,847,580 2,259,566
634
635 TRANSMISSION PLANT
636 350 / LAND & LAND RIGHTS L 107 240,677 231,476 9,201
637 352 / STRUCTURES & IMPROVEMENTS L 112 1,213,578 1,167,176 46,402
638 353 / STATION EQUIPMENT L 117 7,006,017 6,737,702 268,315
639 354 / TOWERS & FIXTURES L 123 1,790,975 1,722,509 68,466
640 355 / POLES & FIXTURES L 128 4,525,461 4,351,785 173,677
641 356 / OVERHEAD CONDUCTORS & DEVICES L 133 3,452,919 3,320,589 132,330
642 359 / ROADS & TRAILS L 138 2,664 2,562 102
643 TOTAL TRANSMISSION PLANT 18,232,292 17,533,799 698,492
644
645 DISTRIBUTION PLANT
646 360 / LAND & LAND RIGHTS L 144 21,818 21,257 560
647 361 / STRUCTURES & IMPROVEMENTS L 145 824,805 795,693 29,112
648 362 / STATION EQUIPMENT L 146 4,024,800 3,876,266 148,534
649 364 / POLES, TOWERS & FIXTURES L 150 5,368,030 4,945,724 422,306
650 365 / OVERHEAD CONDUCTORS & DEVICES L 151 2,942,903 2,754,192 188,711
651 366 / UNDERGROUND CONDUIT L 152 744,706 733,662 11,044
652 367 / UNDERGROUND CONDUCTORS & DEVICES L 153 4,321,543 4,255,753 65,790
653 368 / LINE TRANSFORMERS L 154 10,685,063 10,309,010 376,053
654 369 / SERVICES L 155 772,002 737,793 34,209
655 370 / METERS L 156 3,892,250 3,762,998 129,252
656 371 / INSTALLATIONS ON CUSTOMER PREMISES L 157 94,036 88,296 5,740
657 373 / STREET LIGHTING SYSTEMS L 158 64,719 61,856 2,862
658 TOTAL DISTRIBUTION PLANT 33,756,674 32,342,500 1,414,174
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 18 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
659 * * * TABLE 6 - DEPRECIATION & AMORTIZATION EXPENSE * * *
660
661 GENERAL PLANT
662 389 / LAND & LAND RIGHTS L 163 0 0 0
663 390 / STRUCTURES & IMPROVEMENTS L 164 2,207,235 2,121,000 86,235
664 391 / OFFICE FURNITURE & EQUIPMENT L 165 5,180,836 4,978,424 202,411
665 392 / TRANSPORTATION EQUIPMENT L 166 141,342 135,820 5,522
666 393 / STORES EQUIPMENT L 167 122,209 117,434 4,775
667 394 / TOOLS, SHOP & GARAGE EQUIPMENT L 168 440,516 423,306 17,211
668 395 / LABORATORY EQUIPMENT L 169 560,100 538,218 21,883
669 396 / POWER OPERATED EQUIPMENT L 170 0 0 0
670 397 / COMMUNICATIONS EQUIPMENT L 171 3,650,744 3,508,112 142,632
671 398 / MISCELLANEOUS EQUIPMENT L 172 400,774 385,116 15,658
672
673 TOTAL GENERAL PLANT 12,703,756 12,207,430 496,326
674
675 403/ BOARDMAN ARO DEPRECIATION EXP DAARO 0 0 0
676
677 DEPR EXP BEFORE DISALLOWED COSTS 123,799,868 118,931,309 4,868,559
678
679 DEPRECIATION ON DISALLOWED COSTS L 677 (222,224)(213,485)(8,739)
680 TOTAL DEPRECIATION EXPENSE 123,577,643 118,717,824 4,859,819
681
682 AMORTIZATION EXPENSE
683 INTANGIBLE PLANT L 94 6,446,175 6,196,806 249,369
684 HYDRAULIC PRODUCTION L 98 0 0 0
685 MISC. AMORTIZATION GAINS & LOSSES L 101 (190,175)(182,905)(7,270)
686 TOTAL AMORTIZATION EXPENSE 6,256,000 6,013,901 242,099
687
688 TOTAL DEPRECIATION & AMORTIZATION EXP 129,833,644 124,731,725 5,101,919
689
690 411.093/4 / ARO ACCRETION EXPENSE DAACCRETION 48,379 46,482 1,896
691
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 19 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
692 * * * TABLE 7 - TAXES OTHER THAN INCOME TAXES * * *
693
694 TAXES OTHER THAN INCOME
695 FEDERAL TAXES
696 FICA LABOR 13,030,349 12,430,758 599,591
697 FUTA LABOR 88,463 84,392 4,071
698 LESS: PAYROLL DEDUCTION & LOADING LABOR (13,329,131)(12,715,792)(613,339)
699 STATE TAXES
700 AD VALOREM TAXES
701 JIM BRIDGER STATION L 97 1,101,880 1,059,757 42,123
702 VALMY L 97 499,311 480,223 19,088
703 BOARDMAN L 97 77,862 74,886 2,977
704 OTHER-PRODUCTION PLANT L 101 6,190,320 5,953,675 236,646
705 OTHER-TRANSMISSION PLANT L 139 5,272,104 5,070,193 201,910
706 OTHER-DISTRIBUTION PLANT L 160 7,864,007 7,544,528 319,479
707 OTHER-GENERAL PLANT L 174 1,523,909 1,464,371 59,538
708 SUB-TOTAL 22,529,393 21,647,633 881,760
709
710 LICENSES - HYDRO PROJECTS L 98 3,150 3,030 120
711
712 REGULATORY COMMISSION FEES
713 STATE OF IDAHO CIDA 1,801,731 1,801,731 0
714 STATE OF OREGON CODA 164,843 0 164,843
715
716 FRANCHISE TAXES
717 STATE OF OREGON CODA 631,414 0 631,414
718
719 OTHER STATE TAXES
720 UNEMPLOYMENT TAXES LABOR 210,319 200,641 9,678
721 HYDRO GENERATION KWH TAX E10 1,057,575 1,010,291 47,284
722 IRRIGATION-PIC CIDA 0 0 0
723
724 CANADA SALES TAX E10 0 0 0
725
726 TOTAL TAXES OTHER THAN INCOME 26,188,106 24,462,684 1,725,422
727
728
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 20 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
729 * * * TABLE 8 - REGULATORY DEBITS/CREDITS * * *
730
731 REGULATORY DEBITS/CREDITS
732 STATE OF IDAHO CIDA 878,396 878,396 0
733 STATE OF OREGON CODA 208,995 0 208,995
734
735 TOTAL REGULATORY DEBITS/CREDITS 1,087,391 878,396 208,995
736
737
738 * * * TABLE 9 - INCOME TAXES * * *
739
740 410/411 NET PROVISION FOR DEFERRED INCOME TAXES
741 ACCOUNT #282 - RELATED P101P (8,029,567)(7,715,858)(313,709)
742 ACCOUNTS #190 & #283 - RELATED L 771 (6,856,426)(6,666,805)(189,621)
743 TOTAL NET PROVISION FOR DEFERRED INCOME TAXES (14,885,993)(14,382,662)(503,331)
744
745 411.4 - INVESTMENT TAX CREDIT ADJUSTMENT P101P 11,264,544 10,824,447 440,097
746
747 SUMMARY OF INCOME TAXES
748
749 TOTAL FEDERAL INCOME TAX L 797 29,156,558 28,544,231 612,327
750
751 STATE INCOME TAX
752 STATE OF IDAHO L 853 10,640,646 10,411,615 229,031
753 STATE OF OREGON L 827 754,861 736,665 18,196
754 OTHER STATES L 870 15,952 15,117 835
755 TOTAL STATE INCOME TAXES 11,411,459 11,163,398 248,061
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 21 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
756 * * * TABLE 10 - CALCULATION OF FEDERAL INCOME TAX * * *
757
758 OPERATING REVENUES 1,117,979,310 1,069,650,202 48,329,108
759
760 OPERATING EXPENSES
761 OPERATION & MAINTENANCE 683,212,307 649,599,003 33,613,303
762 DEPRECIATION EXPENSE 123,577,643 118,717,824 4,859,819
763 AMORTIZATION OF LIMITED TERM PLANT 6,256,000 6,013,901 242,099
764 ACCRETION EXPENSE 48,379 46,482 1,896
765 TAXES OTHER THAN INCOME 26,188,106 24,462,684 1,725,422
766 REGULATORY DEBITS/CREDITS 1,087,391 878,396 208,995
767 TOTAL OPERATING EXPENSES 840,369,826 799,718,291 40,651,535
768
769 OTHER OPERATING EXPENSES L 767 0 0 0
770
771 INCOME BEFORE TAX ADJUSTMENTS (NOI before Interest)277,609,484 269,931,911 7,677,573
772
773 INCOME STATEMENT ADJUSTMENTS
774 LONG TERM DEBT INTEREST EXPENSE L 24 63,108,673 60,632,207 2,476,466
775 OTHER INTEREST EXPENSE L 24 10,779,214 10,356,224 422,990
776 TOTAL INTEREST CHARGES 73,887,887 70,988,431 2,899,456
777
778 NET OPER INCOME BEFORE STATE INCOME TAXES 203,721,597 198,943,480 4,778,117
779
780 TOTAL STATE INCOME TAXES (ALLOWED)11,196,340 10,953,001 243,339
781
782 NET FEDERAL INCOME AFTER STATE INCOME TAXES 192,525,257 187,990,479 4,534,778
783
784 FEDERAL TAX AT 21 PERCENT 40,430,304 39,478,001 952,303
785 OTHER CURRENT TAX ADJUSTMENTS L 784 0 0 0
786 PRIOR YEARS' TAX ADJUSTMENT L 784 (8,546,188)(8,344,889)(201,299)
787
788 TOTAL FEDERAL INCOME TAX BEFORE OTHER ADJUSTMENTS 31,884,116 31,133,111 751,005
789
790 OTHER TAX ADJUSTMENTS
791 ALLOWANCE FOR AFUDC P101P 0 0 0
792 FEDERAL INCOME TAX ADJUSTMENTS - PLANT P101P (26,387,141)(25,356,216)(1,030,925)
793 FEDERAL INCOME TAX ADJUSTMENTS - OTHER L 771 13,398,770 13,028,213 370,557
794 SUM OF OTHER ADJUSTMENTS (12,988,371)(12,328,002)(660,369)
795 FEDERAL TAX ON OTHER TAX ADJ AT 21 PERCENT (2,727,558)(2,588,881)(138,677)
796
797 TOTAL FEDERAL INCOME TAX 29,156,558 28,544,231 612,327
798
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 22 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
799 * * * TABLE 11 - OREGON STATE INCOME TAXES * * *
800
801 NET OPERATING INCOME BEFORE TAXES - OREGON L 778 203,721,597 198,943,480 4,778,117
802
803 ALLOWANCE FOR AFUDC P101P 0 0 0
804 STATE INCOME TAX ADJUSTMENTS
805 STATE INCOME TAX ADJUSTMENTS - PLANT P101P (30,500,633)(29,308,997)(1,191,636)
806 STATE INCOME TAX ADJUSTMENTS - OTHER L 771 45,869,406 44,600,841 1,268,565
807 ADD: MFG DEDUCTION NOT ALLOWED L 771 0 0 0
808
809 TOTAL STATE INCOME TAX ADJUSTMENTS - OREGON 15,368,773 15,291,845 76,929
810
811 INCOME SUBJECT TO OREGON TAX 219,090,370 214,235,325 4,855,045
812
813 IERCO TAXABLE INCOME E10 20,675,939 19,751,512 924,427
814 BONUS DEPRECIATION ADJUSTMENT P101P 0 0 0
815 FEDERAL NOL L 771 0 0 0
816 TOTAL STATE TAXABLE INCOME - OREGON 239,766,309 233,986,836 5,779,473
817 APPORTIONMENT FACTOR (.045454550)10,898,470 10,635,766 262,703
818 POST APPORTIONMENT SCHEDULE M L 771
819 TAXABLE INCOME
820 OREGON TAX AT 6.6 PERCENT 719,299 701,961 17,338
821 LESS: INVESTMENT TAX CREDIT P101P 0 0 0
822
823 STATE INCOME TAX ALLOWED - OREGON 719,299 701,961 17,338
824 FIN 48 ADJUSTMENT L 820 0 0 0
825 PRIOR YEARS' TAX ADJUSTMENT L 820 35,562 34,705 857
826
827 STATE INCOME TAX PAID - OREGON 754,861 736,665 18,196
828
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 23 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
829 * * * TABLE 12 - IDAHO STATE INCOME TAXES * * *
830
831 NET OPERATING INCOME BEFORE TAXES - IDAHO L 778 203,721,597 198,943,480 4,778,117
832
833 ALLOWANCE FOR AFUDC P101P 0 0 0
834 STATE INCOME TAX ADJUSTMENTS
835 STATE INCOME TAX ADJUSTMENTS - PLANT P101P (54,381,959)(52,257,297)(2,124,662)
836 STATE INCOME TAX ADJUSTMENTS - OTHER L 771 13,301,030 12,933,177 367,854
837
838 INCOME SUBJECT TO IDAHO TAX 162,640,668 159,619,359 3,021,309
839
840 IERCO TAXABLE INCOME E10 20,675,939 19,751,512 924,427
841 BONUS DEPRECIATION ADJUSTMENT P101P 0 0 0
842 FEDERAL NOL L 771 0 0 0
843 TOTAL STATE TAXABLE INCOME - IDAHO 183,316,607 179,370,871 3,945,736
844 APPORTIONMENT FACTOR (0.80866426)148,241,588 145,050,813 3,190,775
845 POST APPORTIONMENT SCHEDULE M L 771 0 0 0
846 TAXABLE INCOME 148,241,588 145,050,813 3,190,775
847 IDAHO TAX AT 6.9250 PERCENT 10,265,730 10,044,769 220,961
848 LESS: INVESTMENT TAX CREDIT P101P 0 0 0
849
850 STATE INCOME TAX ALLOWED - IDAHO 10,265,730 10,044,769 220,961
851 FIN 48 ADJUSTMENT L 847 0 0 0
852 PRIOR YEARS' TAX ADJUSTMENT L 847 374,916 366,846 8,070
853 STATE INCOME TAX PAID - IDAHO 10,640,646 10,411,615 229,031
854
855
856
857 OTHER STATE INCOME TAX
858 INCOME SUBJECT TO TAX L 838 162,640,668 159,619,359 3,021,309
859
860 IERCO TAXABLE INCOME E10 20,675,939 19,751,512 924,427
861 BONUS DEPRECIATION ADJUSTMENT P101P 27,994,393 26,900,673 1,093,720
862 FEDERAL NOL L 771 0 0 0
863 TOTAL STATE TAXABLE INCOME - OTHER STATES 211,311,000 206,271,544 5,039,455
864 APPORTIONMENT FACTOR (1.0)211,311,000 206,271,544 5,039,455
865 POST APPORTIONMENT SCHEDULE M L 771 0 0 0
866 TAXABLE INCOME 211,311,000 206,271,544 5,039,455
867 OTHER TAX AT 0.1 PERCENT 211,311 206,272 5,039
868 ADD : CURRENT YEAR'S TAX DEFICIENCY L 853 0 0 0
869 PRIOR YEARS' TAX ADJUSTMENT L 853 (195,359)(191,154)(4,205)
870 OTHER STATES' INCOME TAX PAID 15,952 15,117 835
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 24 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
871 * * * TABLE 13 - DEVELOPMENT OF LABOR RELATED ALLOCATOR * * *
872 STEAM POWER GENERATION
873 500 - 514 / TOTAL STEAM GENERATION D10 267,964 257,720 10,244
874 HYDRAULIC POWER GENERATION
875 535 / SUPERVISION & ENGINEERING L 881 3,292,248 3,164,971 127,277
876 536 / WATER FOR POWER E10 566,061 540,753 25,309
877 537 / HYDRAULIC EXPENSES D10 4,504,895 4,332,681 172,215
878 538 / ELECTRIC EXPENSES D10 1,033,465 993,957 39,508
879 539 / MISCELLANEOUS EXPENSES D10 2,403,639 2,311,752 91,887
880 540 / RENTS D10 0 0 0
881 TOTAL HYDRAULIC OPERATION EXPENSES 11,800,309 11,344,114 456,195
882 541 / SUPERVISION & ENGINEERING L 887 81,433 78,320 3,113
883 542 / STRUCTURES D10 546,294 525,410 20,884
884 543 / RESERVOIRS, DAMS & WATERWAYS D10 280,707 269,976 10,731
885 544 / ELECTRIC PLANT D10 1,045,678 1,005,703 39,974
886 545 / MISCELLANEOUS HYDRAULIC PLANT D10 1,561,209 1,501,526 59,682
887 TOTAL HYDRAULIC MAINTENANCE EXPENSES 3,515,321 3,380,936 134,385
888 TOTAL HYDRAULIC GENERATION EXPENSES 15,315,630 14,725,050 590,580
889 OTHER POWER GENERATION
890 546 / SUPERVISION & ENGINEERING L 894 380,604 366,055 14,550
891 548 / GENERATING EXPENSES D10 2,188,368 2,104,710 83,658
892 549 / MISCELLANEOUS EXPENSES D10 344,732 331,554 13,179
893 550 / RENTS D10 0 0 0
894 TOTAL OTHER POWER OPER EXPENSES 2,913,705 2,802,319 111,386
895
896 551 / SUPERVISION & ENGINEERING L 900 0 0 0
897 552 / STRUCTURES D10 36,150 34,768 1,382
898 553 / GENERATING & ELECTRIC PLANT D10 30,759 29,583 1,176
899 554 / MISCELLANEOUS EXPENSES D10 369,863 355,724 14,139
900 TOTAL OTHER POWER MAINT EXPENSES 436,772 420,075 16,697
901 TOTAL OTHER POWER GENERATION EXP 3,350,477 3,222,394 128,083
902 555 / PURCHASE POWER E10 0 0 0
903 556 / LOAD CONTROL & DISPATCHING EXPENSES D10 64 62 2
904 557 / OTHER EXPENSES D10 3,026,486 2,910,789 115,697
905 TOTAL OTHER POWER SUPPLY EXPENSES 3,026,550 2,910,850 115,700
906
907 TOTAL PRODUCTION EXPENSES 21,960,621 21,116,015 844,607
908
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 25 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
909 * * * TABLE 13 - DEVELOPMENT OF LABOR RELATED ALLOCATOR * * *
910
911 TRANSMISSION EXPENSES
912 560 / SUPERVISION & ENGINEERING L 140 1,506,010 1,448,333 57,677
913 561 / LOAD DISPATCHING D12 2,334,515 2,245,270 89,245
914 562 / STATION EXPENSES L 117 1,627,786 1,565,445 62,341
915 563 / OVERHEAD LINE EXPENSES L 123+128+133 332,325 319,594 12,731
916 565 / TRANSMISSION OF ELECTRICITY BY OTHERS E10 0 0 0
917 566 / MISCELLANEOUS EXPENSES L 529 0 0 0
918 567 / RENTS L 140 0 0 0
919 TOTAL TRANSMISSION OPERATION 5,800,635 5,578,642 221,993
920 568 / SUPERVISION & ENGINEERING L 140 59,644 57,360 2,284
921 569 / STRUCTURES L 112 839,968 807,851 32,117
922 570 / STATION EQUIPMENT L 117 1,330,821 1,279,854 50,968
923 571 / OVERHEAD LINES L 123+128+133 561,160 539,663 21,498
924 573 / MISCELLANEOUS PLANT L 140 1,663 1,600 64
925 TOTAL TRANSMISSION MAINTENANCE 2,793,257 2,686,327 106,930
926 TOTAL TRANSMISSION EXPENSES 8,593,892 8,264,969 328,923
927
928 DISTRIBUTION EXPENESES
929 580 / SUPERVISION & ENGINEERING L 160 2,170,066 2,081,906 88,160
930 581 / LOAD DISPATCHING D60 2,986,180 2,881,083 105,096
931 582 / STATION EXPENSES L 146 648,311 624,385 23,926
932 583 / OVERHEAD LINE EXPENSES L 150+151 2,600,735 2,408,745 191,991
933 584 / UNDERGROUND LINE EXPENSES L 152+153 930,165 916,058 14,107
934 585 / STREET LIGHTING & SIGNAL SYSTEMS L 158 0 0 0
935 586 / METER EXPENSES L 156 2,650,147 2,562,143 88,005
936 587 / CUSTOMER INSTALLATIONS EXPENSE L 157 526,297 494,173 32,124
937 588 / MISCELLANEOUS EXPENSES L 559 1,845,029 1,750,457 94,572
938 589 / RENTS L 160 0 0 0
939 TOTAL DISTRIBUTION OPERATION 14,356,930 13,718,949 637,980
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 26 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
940 * * * TABLE 13 - DEVELOPMENT OF LABOR RELATED ALLOCATOR * * *
941
942
943 590 / SUPERVISION & ENGINEERING L 160 6,908 6,628 281
944 591 / STRUCTURES L 145 0 0 0
945 592 / STATION EQUIPMENT L 146 1,923,697 1,852,704 70,994
946 593 / OVERHEAD LINES L 150+151 3,513,964 3,254,557 259,407
947 594 / UNDERGROUND LINES L 152+153 192,981 190,055 2,927
948 595 / LINE TRANSFORMERS L 154 17,675 17,053 622
949 596 / STREET LIGHTING & SIGNAL SYSTEMS L 158 100,933 96,469 4,464
950 597 / METERS L 156 478,160 462,282 15,878
951 598 / MISCELLANEOUS PLANT L 160 47,790 45,849 1,942
952 TOTAL DISTRIBUTION MAINTENANCE 6,282,109 5,925,595 356,514
953 TOTAL DISTRIBUTION EXPENSES 20,639,039 19,644,545 994,494
954
955 CUSTOMER ACCOUNTING EXPENSES
956 901 / SUPERVISION L 961 527,861 497,183 30,678
957 902 / METER READING CW902 876,604 660,941 215,663
958 903 / CUSTOMER RECORDS & COLLECTIONS CW903 6,638,306 6,417,223 221,083
959 904 / UNCOLLECTIBLE ACCOUNTS DA909 0 0 0
960 905 / MISC EXPENSES L 957-959 0 0 0
961 TOTAL CUSTOMER ACCOUNTING EXPENSES 8,042,771 7,575,347 467,424
962
963 CUSTOMER SERVICES & INFORMATION EXPENSES
964 907 / SUPERVISION L 967 506,305 470,957 35,348
965 908 / CUSTOMER ASSISTANCE L 573 3,102,858 2,886,232 216,626
966 909 / INFORMATION & INSTRUCTIONAL L 574 0 0 0
967 910 / MISCELLANEOUS EXPENSES L 965+966 316,562 294,461 22,101
968 TOTAL CUST SERV & INFORMATN EXPENSES 3,925,725 3,651,651 274,074
969
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 27 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
970 * * * TABLE 13 - DEVELOPMENT OF LABOR RELATED ALLOCATOR * * *
971 SALES EXPENSES
972 912 / DEMO & SELLING EXPENSES L 579 0 0 0
973 TOTAL SALES EXPENSES 0 0 0
974
975 ADMINISTRATIVE & GENERAL EXPENSES
976 920 / ADMINISTRATIVE & GENERAL SALARIES PTDCAS 35,536,738 33,899,760 1,636,979
977 921 / OFFICE SUPPLIES PTDCAS 203,583 194,205 9,378
978 922 / ADMIN & GENERAL EXPENSES TRANSFERRED-CR SUBEX 0 0 0
979 923 / OUTSIDE SERVICES PTDCAS 0 0 0
980 924 / PROPERTY INSURANCE
981 PRODUCTION - STEAM L 97 0 0 0
982 ALL RISK & MISCELLANEOUS P101P 246,949 237,301 9,648
983 TOTAL ACCOUNT 924
984 925 / INJURIES & DAMAGES LABOR 90,130 85,983 4,147
985 0 LABOR 0 0 0
986 927 / FRANCHISE REQUIREMENTS CIDA 0 0 0
987 928 / REGULATORY COMMISSION EXPENSES
988 FERC ADMIN ASSESSMENTS L 176 0 0 0
989 FERC RATE CASE EXPENSE RESREV 0 0 0
990 SEC EXPENSES L 176 0 0 0
991 IDAHO PUC - RATE CASE CIDA 0 0 0
992 - OTHER CIDA 0 0 0
993 OREGON PUC - RATE CASE CODA 0 0 0
994 -OTHER CODA 0 0 0
995 TOTAL ACCOUNT 928
996 929 / DUPLICATE CHARGES SUBEX 0 0 0
997 930.1 / GENERAL ADVERTISING RELAB 0 0 0
998 930.2 / MISCELLANEOUS EXPENSES PTDCAS 117,204 111,805 5,399
999 931 / RENTS L 174 0 0 0
1000 935 / GENERAL PLANT MAINTENANCE P3908 704,861 677,323 27,538
1001 TOTAL ADMIN & GENERAL EXPENSES 36,899,466 35,206,377 1,693,089
1002 TOTAL OPER & MAINT EXPENSES 100,061,514 95,458,903 4,602,612
1003 TOTAL LABOR - RATIO (%)1 0.9540 0.0460
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 28 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
1004 * * * TABLE 14 - ALLOCATION FACTORS * * *
1005
1006 CAPACITY RELATED KW
1007 GENERATION LEVEL (PSP)D10 2,559,752 2,461,897 97,855
1008 POWER SUPPLY-TRANSMISSION (PST)D11 2,559,752 2,461,897 97,855
1009 RETAIL TRANSMISSION D12 2,559,752 2,461,897 97,855
1010 DISTRIBUTION - SUBSTATIONS D60 2,431,503 2,345,928 85,575
1011
1012 ENERGY RELATED MWH
1013 GENERATION LEVEL (PSP)E10 16,054,695 15,336,885 717,810
1014 RETAIL MWH AT GENERATION LVL E100 16,054,695 15,336,885 717,810
1015 CUSTOMER LEVEL E99 14,796,085 14,129,371 666,714
1016
1017 CUSTOMER RELATED FACTORS
1018 369-DIRECT ASSIGNMENT DA369 64,812,031 61,940,067 2,871,964
1019 370-METERS ACCT370 104,876,449 101,393,771 3,482,678
1020 902-CUSTOMER WEIGHTED CW902 1,962,900 1,479,985 482,915
1021 903-CUSTOMER WEIGHTED CW903 14,723,735 14,233,374 490,361
1022 904-CUSTOMER WEIGHTED CW904 1,877,187 1,786,110 91,077
1023 909-DIRECT ASSIGN-AVG.NO.CUST.DA909 578,745 559,468 19,277
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 29 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
1024 * * * TABLE 14 - ALLOCATION FACTORS * * *
1025
1026
1027 252-CUSTOMER ADVANCES DA252 5,115,964 5,078,714 37,250
1028 350-LAND & LAND RIGHTS DA350 0 0 0
1029 352-STRUCTURES & IMPROVEMENTS DA352 658 0 658
1030 353-STATION EQUIPMENT DA353 111,594 75,100 36,494
1031 354-TOWERS & FIXTURES DA354 0 0 0
1032 355-POLES & FIXTURES DA355 33,842 0 33,842
1033 356-OVERHEAD CONDUCTORS & DEVICES DA356 26,495 1,189 25,306
1034 359-ROADS & TRAILS DA359 0 0 0
1035 360LAND & LAND RIGHTS ACCT360 7,429,778 7,238,993 190,785
1036 361-STRUCTURES & IMPROVEMENTS ACCT361 50,879,274 49,083,482 1,795,792
1037 362-STATION EQUIPMENT ACCT362 287,263,363 276,661,984 10,601,379
1038 364-POLES, TOWERS & FIXTURES DA364 293,142,665 270,080,950 23,061,715
1039 365-OVERHEAD CONDUCTORS & DEVICES DA365 147,320,762 137,873,958 9,446,804
1040 366-UNDERGROUND CONDUIT DA366 53,566,219 52,771,796 794,423
1041 367-UNDERGROUND CONDUCTORS & DEVICES DA367 302,975,749 298,363,317 4,612,432
1042 371-INSTALLATIONS ON CUSTOMER PREMISES DA371 4,004,512 3,760,088 244,424
1043 373-STREET LIGHTING SYSTEMS DA373 4,848,521 4,634,074 214,447
1044 451-REVENUE - MISCELLANEOUS SERVICE DA451 4,352,130 4,308,346 43,784
1045 454-REVENUE - FACILITIES CHARGE DA4547 9,714,244 9,303,405 410,839
1046 908-OTHER CUSTOMER ASSISTANCE ACCT908 49,090,746 46,826,537 2,264,209
1047 440-RETAIL SALES REVENUE RETREV 974,391,283 932,709,733 41,681,551
1048 456 - DSM RIDER FUNDS DARIDER 22,591,465 20,915,733 1,675,732
1049 DAACCRETION 48,379 46,482 1,896
1050 DAARO 0 0 0
1051 447-WHOLESALE SALES REVENUE RESREV 0 0 0
1052 IDAHO CIDA 1 1 0
1053 OREGON CODA 1 0 1
1054 NET TO GROSS TAX MULTIPLIER DA990 1.347 1.347 1.347
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 30 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
1055 * * * TABLE 14 - ALLOCATION FACTORS * * *
1056
1057 INTERNALLY DEVELOPED ALLOCATION FACTORS
1058 PLANT - PROD,TRANS&DIST PTD 5,881,583,357 5,651,794,375 229,788,982
1059 LAB - PROD,TRANS,DIST,CUST ACCT&CSIS PTDCAS 63,162,048 60,252,526 2,909,522
1060 PLANT - HYDRO,OTHER,TSUBS,DSUBS&GP P110P 2,935,140,102 2,823,069,912 112,070,190
1061 PLANT - GEN PLT (390,391,397&398)P3908 267,744,759 257,284,175 10,460,584
1062 PLANT - PROD,TRANS,DIST&GEN P101P 6,332,810,166 6,085,392,097 247,418,069
1063 O&M - PROD,TRANS,DIST,CUST ACCT&CSIS SUBEX 571,826,575 544,570,146 27,256,429
1064 LAB - PROD,TRANS,DIST,CUST ACCT&CSIS RELAB 63,162,048 60,252,526 2,909,522
1065 LAB - ALL LABOR WITHOUT 925-6 "CIRC"LABOR 99,724,435 95,135,619 4,588,816
1066 REV - RETAIL, RESALE & WHEELING FMREV 981,928,539 939,928,220 42,000,319
1067 PLANT - 89%*HYD PROD + 11%*TRANS SURVEY 1,056,121,468 1,015,737,859 40,383,609
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 31 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
1068 * * * TABLE 15 - ALLOCATION FACTORS - RATIOS * * *
1069
1070 CAPACITY RELATED KW
1071 GENERATION LEVEL (PSP)D10 100.00%96.18%3.82%
1072 POWER SUPPLY-TRANSMISSION (PST)D11 100.00%96.18%3.82%
1073 TRANSMISSION RETAIL D12 100.00%96.18%3.82%
1074 DISTRIBUTION - SUBSTATIONS D60 100.00%96.48%3.52%
1075
1076 ENERGY RELATED MWH
1077 GENERATION LEVEL (PSP)E10 100.00%95.53%4.47%
1078 RETAIL MWH AT GENERATION LVL E100 100.00%95.53%4.47%
1079 CUSTOMER LEVEL E99 100.00%95.49%4.51%
1080
1081 CUSTOMER RELATED FACTORS
1082 369-DIRECT ASSIGNMENT DA369 100.00%95.57%4.43%
1083 370- METERS ACCT370 100.00%96.68%3.32%
1084 902-CUSTOMER WEIGHTED CW902 100.00%75.40%24.60%
1085 903-CUSTOMER WEIGHTED CW903 100.00%96.67%3.33%
1086 904-CUSTOMER WEIGHTED CW904 100.00%95.15%4.85%
1087 909-DIRECT ASSIGN-AVG.NO.CUST.DA909 100.00%96.67%3.33%
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 32 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
1088 * * * TABLE 15 - ALLOCATION FACTORS - RATIOS * * *
1089
1090 DIRECT ASSIGNMENTS (red font denotes allocator comes from Plant Book)
1091 252-CUSTOMER ADVANCES DA252 100.00%99.27%0.73%
1092 350-LAND & LAND RIGHTS DA350 #DIV/0!#DIV/0!#DIV/0!
1093 352-STRUCTURES & IMPROVEMENTS DA352 100.00%0.00%100.00%
1094 353-STATION EQUIPMENT DA353 100.00%67.30%32.70%
1095 354-TOWERS & FIXTURES DA354 #DIV/0!#DIV/0!#DIV/0!
1096 355-POLES & FIXTURES DA355 100.00%0.00%100.00%
1097 356-OVERHEAD CONDUCTORS & DEVICES DA356 100.00%4.49%95.51%
1098 359-ROADS & TRAILS DA359 #DIV/0!#DIV/0!#DIV/0!
1099 360LAND & LAND RIGHTS ACCT360 100.00%97.43%2.57%
1100 361-STRUCTURES & IMPROVEMENTS ACCT361 100.00%96.47%3.53%
1101 362-STATION EQUIPMENT ACCT362 100.00%96.31%3.69%
1102 364-POLES, TOWERS & FIXTURES DA364 100.00%92.13%7.87%
1103 365-OVERHEAD CONDUCTORS & DEVICES DA365 100.00%93.59%6.41%
1104 366-UNDERGROUND CONDUIT DA366 100.00%98.52%1.48%
1105 367-UNDERGROUND CONDUCTORS & DEVICES DA367 100.00%98.48%1.52%
1106 371-INSTALLATIONS ON CUSTOMER PREMISES DA371 100.00%93.90%6.10%
1107 373-STREET LIGHTING SYSTEMS DA373 100.00%95.58%4.42%
1108 451-REVENUE - MISCELLANEOUS SERVICE DA451 100.00%98.99%1.01%
1109 454-REVENUE - FACILITIES CHARGE DA4547 100.00%95.77%4.23%
1110 908-OTHER CUSTOMER ASSISTANCE ACCT908 100.00%95.39%4.61%
1111 440-RETAIL SALES REVENUE RETREV 100.00%95.72%4.28%
1112 456 - DSM RIDER FUNDS DARIDER 100.00%92.58%7.42%
1113 DAACCRETION 100.00%96.08%3.92%
1114 DAARO #DIV/0!#DIV/0!#DIV/0!
1115 447-WHOLESALE SALES REVENUE RESREV #DIV/0!#DIV/0!#DIV/0!
1116 IDAHO CIDA 100.00%100.00%0.00%
1117 OREGON CODA 100.00%0.00%100.00%
1118 NET TO GROSS TAX MULTIPLIER DA990 1.347 1.347 1.347
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 33 of 34
1 IDAHO POWER COMPANY
2 FERC FORM 1
3 JURISDICTIONAL SEPARATION STUDY
4 FOR THE NINE MONTHS ENDING SEPTEMBER 30, 2021
5
6
7 ALLOC/TOTAL IDAHO OREGON
8 DESCRIPTION SOURCE SYSTEM IPUC OPUC
1119 * * * TABLE 15 - ALLOCATION FACTORS - RATIOS * * *
1120
1121 INTERNALLY DEVELOPED ALLOCATION FACTORS
1122 PLANT - PROD,TRANS&DIST PTD 100.00%96.09%3.91%
1123 LAB - PROD,TRANS,DIST,CUST ACCT&CSIS PTDCAS 100.00%95.39%4.61%
1124 PLANT - HYDRO,OTHER,TSUBS,DSUBS&GP P110P 100.00%96.18%3.82%
1125 PLANT - GEN PLT (390,391,397&398)P3908 100.00%96.09%3.91%
1126 PLANT - PROD,TRANS,DIST&GEN P101P 100.00%96.09%3.91%
1127 O&M - PROD,TRANS,DIST,CUST ACCT&CSIS SUBEX 100.00%95.23%4.77%
1128 LAB - PROD,TRANS,DIST,CUST ACCT&CSIS RELAB 100.00%95.39%4.61%
1129 LAB - ALL LABOR WITHOUT 925-6 "CIRC"LABOR 100.00%95.40%4.60%
1130 REV - RETAIL, RESALE & WHEELING FMREV 100.00%95.72%4.28%
1131 PLANT - 89%*HYD PROD + 11%*TRANS SURVEY 100.00%96.18%3.82%
Response to Staff's Request No. 2 - Attachment 3 - FORM1S 5/11/2022 4:53 PM Page 34 of 34
Rate Case Net Income Analysis As of Dec 31, 2021
OPERATING REVENUES:
RETAIL SALES REVENUES (*See Below)........................................................................ 1,262,052,401
DEF REV HC RELICENSING AFUDC (Idaho Only).......................................................... (8,780,127)
TAX REFORM ADJUSTMENT...........................................................................................-
LANGLEY GULCH AMORTIZATION.................................................................................. (369,171)
REVENUE SHARING.........................................................................................................-
OTHER OPERATING REVENUES.................................................................................... 199,114,589
TOTAL OPERATING REVENUES..................................................................................... 1,452,017,691
OPERATING EXPENSES
OPERATION AND MAINTENANCE EXPENSES.............................................................. 917,571,975
DEPRECIATION EXPENSE............................................................................................... 165,446,697
AMORTIZATION OF LIMITED TERM PLANT................................................................... 8,495,466
TAXES OTHER THAN INCOME........................................................................................ 30,947,260
REGULATORY DEBITS/CREDITS.................................................................................... 1,497,775
PROVISION FOR DEFERRED INCOME TAXES.............................................................. (21,559,910)
INVESTMENT TAX CREDIT ADJUSTMENT..................................................................... 11,832,897
FEDERAL INCOME TAXES............................................................................................... 35,047,688
STATE INCOME TAXES.................................................................................................... 13,298,956
TOTAL OPERATION EXPENSES...................................................................................... 1,162,578,803
OPERATING INCOME........................................................................................................ 289,438,888
ADD: IERCO OPERATING INCOME (Net Income from Operations)............................. 8,991,347
OPERATING INCOME BEFORE OTHER INCOME AND DEDUCTIONS......................... 298,430,236
ADD: AFUDC EQUITY..................................................................................................... 31,537,344
ADD: OTHER INCOME AND DEDUCTIONS..................................................................343,755
INCOME BEFORE INTEREST CHARGES........................................................................ 330,311,334
LESS: INTEREST CHARGES......................................................................................... 86,663,666
COMMON EQUITY (Excludes APB 28).............................................................................. 2,464,724,288 (1)
*DETAIL BREAKOUT OF RETAIL SALES REVENUE ABOVE
IDAHO RETAIL SALES REVENUES W/O HC RELICENCING AFUDC DEFERRAL....... 1,207,714,749
OREGON RETAIL SALES REVENUES............................................................................. 54,337,652
TOTAL RETAIL SALES REVENUE.................................................................................... 1,262,052,401
IDAHO RETAIL SALES REVENUES W/ HCC AFUDC DEFERRAL & TAX REFORM 1,198,934,622
OREGON RETAIL SALES REVENUES W/ TAX REFORM & LANGLEY AMORT 53,968,480
(1) Excludes APB 28
Line No. FERC Account April May June July August September October November December January February March Annual
95% Sharing Accounts
1 Hydroelectric Generation (MWh)467,986 560,392 420,429 498,713 433,804 429,916 394,887 354,557 395,348 509,897 378,245 423,829 5,268,003
Account 501, Coal
Jim Bridger
2 Energy (MWh)61,226 73,515 190,560 287,646 249,170 343,720 314,985 226,251 280,617 232,924 222,977 223,835 2,707,426
North Valmy
3 Energy (MWh)- 1,457 44,990 53,690 75,794 63,943 59,436 53,517 63,711 89,860 29,874 (1,728) 534,544
Account 547, Other Fuel
Langley Gulch
4 Energy (MWh)1,771 164,945 181,190 185,250 193,479 184,787 85,061 179,405 186,194 187,323 171,566 219,513 1,940,484
Danskin
5 Energy (MWh)66,079 28,648 75,773 120,821 70,235 25,607 20,314 13,097 30,781 647 16,638 - 468,640
Bennett Mountain6 Energy (MWh)73,910 4,802 68,536 95,013 44,445 10,249 8,292 1,727 3,976 (93) (112) - 310,745.00
Account 555, Purchased Power Non-PURPA
7 Energy (MWh)208,395 225,999 535,863 575,743 382,330 240,332 212,691 297,978 402,806 498,273 366,818 132,606 4,079,834
Account 447, Surplus Sales
8 Energy (MWh)15,742 57,607 27,397 73,898 84,212 236,150 184,121 134,193 193,796 208,763 114,551 43,200 1,373,630
100% Sharing Accounts
Account 555, PURPA
9 Energy (MWh)299,823 344,590 334,036 256,117 273,879 227,277 226,874 175,506 205,081 159,917 198,077 241,497 2,942,673
10 Total Generation (MWh)1,179,190 1,404,348 1,851,377 2,072,993 1,723,136 1,525,831 1,322,540 1,302,038 1,568,514 1,678,748 1,384,083 1,239,552 18,252,350
11 Total Load (MWh)1,163,448 1,346,741 1,823,980 1,999,095 1,638,924 1,289,681 1,138,419 1,167,845 1,374,718 1,469,985 1,269,532 1,196,352 16,878,720
APRIL 1, 2021- MARCH 31, 2022
IPCO POWER SUPPLY EXPENSES FOR 2013 NORMALIZED LOADS OVER 85 WATER YEAR CONDITIONS
AVERAGE
January February March April May June July August September October November December Annual
Hydroelectric Generation (MWh)752,627.5 815,491.3 838,193.8 857,602.1 939,082.0 903,967.9 676,826.1 507,296.6 539,966.8 551,501.7 468,579.8 673,213.8 8,524,349.5
Bridger
Energy (MWh)388,320.4 222,117.4 248,591.9 235,340.8 294,123.6 270,536.3 477,666.4 484,535.9 407,010.7 479,444.7 457,104.8 483,159.2 4,447,952.1
Expense ($ x 1000)8,824.7$ 5,081.9$ 5,688.5$ 5,475.9$ 6,900.3$ 6,307.0$ 10,782.3$ 10,932.1$ 9,292.1$ 10,820.2$ 10,348.3$ 10,905.8$ 101,359.0$
Boardman
Energy (MWh)22,777.8 13,440.0 18,943.4 9,376.9 6,396.1 16,526.1 33,030.9 35,190.2 33,219.1 39,049.7 30,004.8 33,128.3 291,083.3
Expense ($ x 1000)515.3$ 318.4$ 432.9$ 224.3$ 148.4$ 386.0$ 709.5$ 749.9$ 709.3$ 822.0$ 650.0$ 711.4$ 6,377.4$
Valmy
Energy (MWh)2,343.6 - - - 1,754.2 108.6 7,166.8 - - 565.9 - 8,983.3 20,922.4
Expense ($ x 1000)88.5$ -$ -$ -$ 66.4$ 4.1$ 257.6$ -$ -$ 21.2$ -$ 329.0$ 766.8$
Langley Gulch
Energy (MWh)48,702.3 10,565.9 35,068.0 7,212.6 32,758.6 15,765.7 131,495.7 146,699.1 150,309.0 176,358.6 100,311.5 122,114.4 977,361.5
Expense ($ x 1000)1,269.6$ 276.3$ 888.3$ 208.3$ 946.4$ 453.2$ 3,301.9$ 3,492.9$ 3,238.4$ 4,001.0$ 2,607.8$ 3,467.7$ 24,151.7$
Danskin
Energy (MWh)146.2 33.8 52.5 4.3 1.0 23.5 3,056.1 5,708.9 3,871.3 1,772.4 72.5 173.1 14,915.6
Expense ($ x 1000)6.1$ 1.4$ 2.1$ 0.2$ 0.0$ 1.1$ 124.2$ 220.3$ 135.5$ 65.2$ 3.0$ 7.9$ 566.9$
Bennett Mountain
Energy (MWh)9.6 - 2.8 0.2 - 2.6 328.2 773.1 436.2 127.9 4.5 8.6 1,693.6
Expense ($ x 1000)0.4$ -$ 0.1$ 0.0$ -$ 0.1$ 13.5$ 30.3$ 15.5$ 4.8$ 0.2$ 0.4$ 65.3$
Fixed Capacity Charge - Gas Transportation ($ x 1000)722.7$ 654.6$ 722.7$ 700.0$ 722.7$ 709.0$ 741.3$ 741.3$ 718.0$ 722.7$ 703.0$ 725.8$ 8,583.5$
Purchased Power (Excluding PURPA)
Market Energy (MWh)48,844.2 10,270.8 4,720.1 3,094.5 11,963.6 100,243.3 217,407.6 204,492.7 39,606.3 586.4 7,923.4 18,240.2 667,393.1
Elkhorn Wind Energy (MWh)33,933.8 24,180.5 38,239.2 20,502.0 18,304.0 22,117.6 31,551.7 24,405.1 19,545.2 19,382.1 32,298.0 26,193.4 310,652.6
Neal Hot Springs Energy (MWh)7,825.8 14,810.1 16,396.9 15,867.9 16,396.9 15,867.9 15,867.9 16,396.9 15,867.9 16,396.9 15,867.9 16,396.9 183,959.8
Raft River Geothermal Energy (MWh)7,056.0 6,662.0 5,674.0 5,360.0 5,316.0 5,323.0 5,726.0 5,998.0 6,111.0 7,004.0 6,939.0 7,199.0 74,367.9
Total Energy Excl. PURPA (MWh)97,659.7 55,923.4 65,030.2 44,824.3 51,980.5 143,551.8 270,553.2 251,292.6 81,130.4 43,369.4 63,028.3 68,029.5 1,236,373.4
Market Expense ($ x 1000)1,407.6$ 266.3$ 133.7$ 97.0$ 388.5$ 3,017.5$ 7,778.8$ 6,898.4$ 1,294.6$ 18.7$ 285.7$ 627.5$ 22,214.3$
Elkhorn Wind Expense ($ x 1000)1,827.4$ 1,302.2$ 1,513.5$ 811.5$ 724.5$ 1,191.1$ 2,038.9$ 1,577.1$ 1,052.5$ 1,043.8$ 2,087.2$ 1,692.7$ 16,862.3$
Neal Hot Springs Expense ($ x 1000)774.8$ 1,466.2$ 1,189.9$ 1,151.5$ 1,189.9$ 1,570.9$ 1,885.1$ 1,947.9$ 1,570.9$ 1,623.3$ 1,885.1$ 1,947.9$ 18,203.4$
Raft River Geothermal Expense ($ x 1000)419.6$ 396.2$ 248.0$ 234.3$ 232.4$ 316.6$ 408.6$ 428.0$ 363.4$ 416.5$ 495.2$ 513.7$ 4,472.6$
Total Expense Excl. PURPA ( $ x 1000)4,429.4$ 3,430.8$ 3,085.1$ 2,294.3$ 2,535.2$ 6,096.0$ 12,111.4$ 10,851.5$ 4,281.5$ 3,102.3$ 4,753.2$ 4,781.8$ 61,752.7$
Surplus Sales
Energy (MWh)91,158.6 195,859.3 309,617.8 337,126.2 305,320.4 120,589.2 43,940.4 23,570.3 140,450.1 410,661.5 183,261.5 147,491.1 2,309,046.6
Revenue Including Transmission Expenses ($ x 1000)1,955.6$ 4,192.3$ 7,064.4$ 7,571.8$ 6,530.1$ 2,155.6$ 954.6$ 533.8$ 3,248.4$ 10,967.6$ 4,644.9$ 4,225.0$ 54,044.2$
Transmission Expenses ($ x 1000)91.2$ 195.9$ 309.6$ 337.1$ 305.3$ 120.6$ 43.9$ 23.6$ 140.5$ 410.7$ 183.3$ 147.5$ 2,309.0$
Revenue Excluding Transmission Expenses ($ x 1000)1,864.5$ 3,996.5$ 6,754.8$ 7,234.7$ 6,224.8$ 2,035.0$ 910.7$ 510.2$ 3,108.0$ 10,556.9$ 4,461.6$ 4,077.5$ 51,735.2$
Net Power Supply Expenses ($ x 1000)13,992.2$ 5,766.9$ 4,065.0$ 1,668.3$ 5,094.6$ 11,921.3$ 27,131.0$ 26,508.0$ 15,282.3$ 9,002.3$ 14,603.9$ 16,852.4$ 151,888.3$
January February March April May June July August September October November December Total
Idaho Retail Sales 87,892,715 81,997,690 74,500,623 69,230,657 68,884,758 82,974,327 104,741,972 112,103,253 99,328,721 71,587,640 67,179,862 77,784,408 998,206,626
January February March April May June July August September October November December Total System
Total Fuel Exp. Coal (501)9,553,773 8,912,994 8,098,077 7,525,242 7,487,643 9,019,153 11,385,255 12,185,412 10,796,845 7,781,442 7,302,324 8,455,019 108,503,180
Water for Power (536.002)209,613 195,554 177,675 165,106 164,281 197,883 249,796 267,352 236,886 170,727 160,216 185,506 2,380,597
Langley Gulch - Gas 2,126,575 1,983,944 1,802,552 1,675,044 1,666,675 2,007,574 2,534,245 2,712,352 2,403,271 1,732,072 1,625,425 1,882,004 24,151,735
Danskin-Gas 49,920 46,572 42,313 39,320 39,124 47,126 59,489 63,670 56,415 40,659 38,156 44,179 566,943
Bennett Mountain-Gas 5,754 5,368 4,877 4,532 4,509 5,432 6,857 7,338 6,502 4,686 4,398 5,092 65,344
Fixed Gas Capacity 755,786 705,095 640,628 595,312 592,337 713,493 900,672 963,972 854,124 615,579 577,677 668,865 8,583,542
Total Fuel Exp. Gas (547)2,938,035 2,740,979 2,490,370 2,314,209 2,302,646 2,773,625 3,501,263 3,747,333 3,320,312 2,392,997 2,245,656 2,600,139 33,367,563
Non-Firm Purchases (555.1)5,512,549 5,142,819 4,672,610 4,342,083 4,320,388 5,204,073 6,569,319 7,031,012 6,229,805 4,489,910 4,213,459 4,878,566 62,606,593
QF Purchases (555.2)11,785,917 10,995,427 9,990,113 9,283,440 9,237,057 11,126,388 14,045,307 15,032,413 13,319,420 9,599,498 9,008,440 10,430,450 133,853,869
Transmission By Others (565)480,400 448,179 407,202 378,398 376,507 453,517 572,494 612,729 542,907 391,281 367,189 425,151 5,455,955
Surplus Sales (447)4,555,312 4,249,784 3,861,226 3,588,093 3,570,166 4,300,402 5,428,577 5,810,099 5,148,019 3,710,251 3,481,805 4,031,418 51,735,153
100% Idaho Allocation
Demand Response Incentive 990,769 924,317 839,807 780,401 776,502 935,327 1,180,702 1,263,682 1,119,681 806,970 757,284 876,823 11,252,265
2013 Base Power Supply Expenses - Monthly Shaping According to Normalized Retail Sales Revenue
I D A H O P O W E R C O M P A N Y
SUMMARY OF PROFORMED NORMALIZED REVENUES
IDAHO JURISDICTION
BY MONTH BY RATE
12-MONTHS ENDING MAY 31, 2015
Forced Shutdowns
BES Units
Unit Code Unit Name Unit Type
Event 
Year Event Type Event Start Date Event End Date Event Duration
FAC‐008 Ratings 
(MW)
101 LANGLEY GULCH #2 852 ‐ CC steam units 2021 U1 ‐ Forced ‐ Immediate 07/05/2021 03:59 MPT 07/05/2021 13:44 MPT 9:45:00 131.45
2021 U1 ‐ Forced ‐ Immediate 07/12/2021 04:19 MP 07/12/2021 06:26 MP 2:07:00 131.45
2021 U1 ‐ Forced ‐ Immediate 07/27/2021 09:32 MP 07/27/2021 16:00 MP 6:28:00 131.45
302 BENNETT MOUNTAIN 300 ‐ Gas Turbine/Jet Engine (Simple Cycle Operation)2021 U1 ‐ Forced ‐ Immediate 07/26/2021 23:59 MP 07/27/2021 10:00 MP 10:01:00 172.80
2022 U1 ‐ Forced ‐ Immediate 03/17/2022 01:40 MP 03/17/2022 02:47 MP 1:07 172.80
2022 U1 ‐ Forced ‐ Immediate 03/17/2022 03:57 MP 03/17/2022 09:42 MP 5:45 172.80
2022 U1 ‐ Forced ‐ Immediate 03/17/2022 16:04 MP 04/01/2022 00:00 MP 343:56:00 172.80
304 DANSKIN #2 300 ‐ Gas Turbine/Jet Engine (Simple Cycle Operation)2022 U1 ‐ Forced ‐ Immediate 01/10/2022 11:46 MP 01/19/2022 15:00 MP 219:14:00 45.90
305 DANSKIN #3 300 ‐ Gas Turbine/Jet Engine (Simple Cycle Operation)2021 U1 ‐ Forced ‐ Immediate 07/04/2021 13:45 MP 07/04/2021 15:22 MP 1:37:00 45.90
2022 U1 ‐ Forced ‐ Immediate 02/23/2022 07:24 MP 02/23/2022 08:32 MP 1:08 45.90
306 LANGLEY GULCH #1 851 ‐ CC GT units 2021 U1 ‐ Forced ‐ Immediate 07/05/2021 03:59 MP 07/05/2021 13:44 MP 9:45:00 187.00
2021 U1 ‐ Forced ‐ Immediate 07/12/2021 04:19 MP 07/12/2021 06:26 MP 2:07:00 187.00
2021 U1 ‐ Forced ‐ Immediate 07/27/2021 09:32 MP 07/27/2021 16:00 MP 6:28:00 187.00
501 HELLS CANYON #1 500 ‐ Pumped Storage/Hydro 2022 U1 ‐ Forced ‐ Immediate 01/27/2022 15:06 MP 01/27/2022 15:08 MP 0:02 130.50
503 HELLS CANYON #3 500 ‐ Pumped Storage/Hydro 2021 U1 ‐ Forced ‐ Immediate 04/01/2021 00:00 MP 05/01/2021 00:00 MP 720:00:00 130.50
2021 U1 ‐ Forced ‐ Immediate 05/01/2021 00:00 MP 06/01/2021 00:00 MP 744:00:00 130.50
2021 U1 ‐ Forced ‐ Immediate 06/01/2021 00:00 MP 07/01/2021 00:00 MP 720:00:00 130.50
2021 U1 ‐ Forced ‐ Immediate 07/01/2021 00:00 MP 08/01/2021 00:00 MP 744:00:00 130.50
2021 U1 ‐ Forced ‐ Immediate 08/01/2021 00:00 MP 09/01/2021 00:00 MP 744:00:00 130.50
2021 U1 ‐ Forced ‐ Immediate 09/01/2021 00:00 MP 10/01/2021 00:00 MP 720:00:00 130.50
2021 U1 ‐ Forced ‐ Immediate 10/01/2021 00:01 MP 11/01/2021 00:00 MP 743:59:00 130.50
2021 U1 ‐ Forced ‐ Immediate 11/01/2021 00:00 MP 12/01/2021 00:00 MP 721:00:00 130.50
2021 U1 ‐ Forced ‐ Immediate 12/01/2021 00:00 MP 12/31/2021 23:59 MP 743:59:00 130.50
2022 U1 ‐ Forced ‐ Immediate 01/01/2022 00:00 MP 02/01/2022 00:00 MP 744:00:00 130.50
2022 U1 ‐ Forced ‐ Immediate 02/01/2022 00:00 MP 03/01/2022 00:00 MP 672:00:00 130.50
2022 U1 ‐ Forced ‐ Immediate 03/01/2022 00:00 MP 04/01/2022 00:00 MP 743:00:00 130.50
506 OXBOW #3 500 ‐ Pumped Storage/Hydro 2021 U1 ‐ Forced ‐ Immediate 05/04/2021 15:23 MP 05/04/2021 17:00 MP 1:37:00 47.50
508 BROWNLEE #1 500 ‐ Pumped Storage/Hydro 2021 U1 ‐ Forced ‐ Immediate 08/18/2021 05:02 MPT 08/19/2021 16:54 MPT 35:52:00 112.50
2021 U1 ‐ Forced ‐ Immediate 09/11/2021 07:33 MP 09/15/2021 15:20 MP 103:47:00 112.50
510 BROWNLEE #3 500 ‐ Pumped Storage/Hydro 2022 U1 ‐ Forced ‐ Immediate 01/01/2022 22:29 MP 01/03/2022 08:00 MP 33:31:00 112.50
515 STRIKE #3 500 ‐ Pumped Storage/Hydro 2021 U1 ‐ Forced ‐ Immediate 05/12/2021 22:17 MPT 05/13/2021 17:30 MPT 19:13:00 27.60
516 BLISS #1 500 ‐ Pumped Storage/Hydro 2021 U1 ‐ Forced ‐ Immediate 05/25/2021 13:20 MPT 06/01/2021 00:00 MPT 154:40:00 25.01
2021 U1 ‐ Forced ‐ Immediate 06/01/2021 00:00 MP 06/03/2021 12:07 MP 60:07:00 25.01
537 AMERICAN FALLS #1 500 ‐ Pumped Storage/Hydro 2021 U1 ‐ Forced ‐ Immediate 05/18/2021 08:51 MP 05/18/2021 09:08 MP 0:17:00 30.78
538 AMERICAN FALLS #2 500 ‐ Pumped Storage/Hydro 2021 U1 ‐ Forced ‐ Immediate 08/19/2021 09:25 MP 08/19/2021 11:28 MP 2:03:00 30.78
539 AMERICAN FALLS #3 500 ‐ Pumped Storage/Hydro 2021 U1 ‐ Forced ‐ Immediate 06/05/2021 06:52 MP 06/06/2021 06:57 MP 24:05:00 30.78
2021 U1 ‐ Forced ‐ Immediate 06/16/2021 03:28 MP 06/16/2021 04:09 MP 0:41:00 30.78
NON‐BES Units
Unit Code Unit Name Unit Type
Event 
Year Event Type Event Start Date Event End Date Event Duration
FAC‐008 Ratings 
(MW)
N/A CDPO G001 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 06/22/2021 20:31 06/22/2021 22:07 1:36:00 6.21
N/A CDPO G001 GN 500 ‐ Pumped Storage/Hydro 2022 Forced 03/29/2022 08:32 03/29/2022 15:08 6:36:00 6.21
N/A CLPR G001 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 07/05/2021 17:12 07/05/2021 23:10 5:58:00 2.50
N/A CLPR G001 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 07/31/2021 22:16 08/01/2021 23:59 25:43:00 2.50
N/A CLPR G001 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 08/16/2021 19:24 08/17/2021 23:59 28:35:00 2.50
N/A CLPR G001 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 08/31/2021 10:30 08/31/2021 10:36 0:06:00 2.50
N/A CLPR G001 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 09/01/2021 20:24 09/02/2021 09:23 12:59:00 2.50
N/A CLPR G001 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 09/02/2021 16:08 09/02/2021 17:27 1:19:00 2.50
N/A CLPR G001 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 09/06/2021 13:35 09/06/2021 21:30 7:55:00 2.50
N/A CLPR G001 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 09/15/2021 17:48 09/15/2021 19:45 1:57:00 2.50
N/A CLPR G001 GN 500 ‐ Pumped Storage/Hydro 2022 Forced 03/28/2022 08:00 03/31/2022 13:39 77:39:00 2.50
N/A CLPR G001 GN 500 ‐ Pumped Storage/Hydro 2022 Forced 03/28/2022 08:02 03/29/2022 23:59 39:57:00 2.50
N/A LMPR G001 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 10/27/2021 03:43 10/27/2021 19:35 15:52:00 13.50
N/A LMPR G001 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 10/27/2021 07:15 10/27/2021 19:30 12:15:00 13.50
N/A LMPR G001 GN 500 ‐ Pumped Storage/Hydro 2022 Forced 12/24/2021 16:11 12/24/2021 17:06 0:55:00 13.50
N/A LSPR G014 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 11/15/2021 07:30 11/17/2021 12:48 53:18:00 15.05
N/A LSPR G012 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 11/18/2021 12:21 12/07/2021 15:20 458:59:00 15.05
N/A LSPR G012 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 11/18/2021 12:34 12/07/2021 15:20 458:46:00 15.05
N/A LSPR G014 GN 500 ‐ Pumped Storage/Hydro 2022 Forced 01/04/2022 15:16 01/04/2022 16:20 1:04:00 15.05
N/A LSPR G012 GN 500 ‐ Pumped Storage/Hydro 2022 Forced 01/04/2022 17:45 01/05/2022 09:50 16:05:00 15.05
N/A MLPR G012 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 08/09/2021 08:00 08/30/2021 08:39 504:39:00 12.07
N/A MLPR G012 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 09/05/2021 13:30 09/09/2021 16:00 98:30:00 12.07
N/A SFPR G003 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 04/05/2021 09:06 04/07/2021 14:50 53:44:00 11.5
N/A SWPO G011 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 05/06/2021 17:58 05/06/2021 20:32 2:34:00 13.59
N/A SWPO G012 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 05/06/2021 17:58 05/06/2021 20:32 2:34:00 13.59
N/A SWPO G012 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 05/22/2021 03:42 05/22/2021 12:02 8:20:00 13.59
N/A SWPO G012 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 11/01/2021 13:53 11/01/2021 14:56 1:03:00 13.59
N/A SWPO G011 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 12/02/2021 08:00 12/02/2021 13:56 5:56:00 13.59
N/A SWPO G011 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 12/02/2021 15:57 12/08/2021 15:52 143:55:00 13.59
N/A SWPO G011 GN 500 ‐ Pumped Storage/Hydro 2022 Forced 12/09/2021 07:30 12/15/2021 14:20 150:50:00 13.59
N/A SWPO G012 GN 500 ‐ Pumped Storage/Hydro 2022 Forced 12/16/2021 07:00 02/01/2022 16:00 1137:00:00 13.59
N/A SWPO G012 GN 500 ‐ Pumped Storage/Hydro 2022 Forced 02/02/2022 16:26 02/03/2022 20:29 28:03:00 13.59
N/A SWPO G011 GN 500 ‐ Pumped Storage/Hydro 2022 Forced 02/03/2022 11:56 02/03/2022 14:54 2:58:00 13.59
N/A SWPO G012 GN 500 ‐ Pumped Storage/Hydro 2022 Forced 02/03/2022 20:30 02/07/2022 11:50 87:20:00 13.59
N/A TSPO G003 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 05/18/2021 19:07 05/19/2021 06:45 11:38:00 6.8
N/A TSPO G003 GN 500 ‐ Pumped Storage/Hydro 2022 Forced 02/07/2022 08:00 02/22/2022 18:00 370:00:00 6.8
N/A US12 G002 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 04/26/2021 16:30 04/30/2021 17:00 96:30:00 9
N/A US12 G001 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 05/04/2021 10:03 05/04/2021 14:00 3:57:00 9
N/A US12 G002 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 05/04/2021 10:03 05/04/2021 14:00 3:57:00 9
N/A US12 G002 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 05/06/2021 18:11 05/12/2021 21:16 147:05:00 9
N/A US12 G001 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 10/25/2021 10:05 10/27/2021 14:15 52:10:00 9
N/A US12 G002 GN 500 ‐ Pumped Storage/Hydro 2022 Forced 01/03/2022 08:30 01/06/2022 13:45 77:15:00 9
N/A US34 G003 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 06/07/2021 11:47 06/10/2021 16:21 76:34:00 8.25
N/A US34 G004 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 06/07/2021 15:19 06/07/2021 16:13 0:54:00 8.25
N/A US34 G003 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 4/1/2021 04/01/2021 17:00 17:00:00 8.25
N/A US34 G004 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 4/1/2021 04/01/2021 17:00 17:00:00 8.25
N/A US34 G004 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 4/1/2021 04/07/2021 23:59 167:59:00 8.25
N/A US34 G003 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 4/1/2021 04/01/2021 00:01 0:01:00 8.25
N/A US34 G003 GN 500 ‐ Pumped Storage/Hydro 2021 Forced 11/15/2021 09:30 11/18/2021 16:00 78:30:00 8.25
N/A US34 G003 GN 500 ‐ Pumped Storage/Hydro 2022 Forced 03/07/2022 08:00 03/18/2022 10:19 266:19:00 8.25
BES Facility Definition:  Generating resource(s) including the generator terminals through the high‐side of the stepup transformer(s) connected at a voltage 
of 100 kV or above with: a) Gross individual nameplate rating greater than 20 MVA. Or, b) Gross plant/facility aggregate nameplate rating greater than 75 
MVA
Estimated Lost 
MWHrs Event Description
1281.66 An analog input card on the Steam Package of the DCS failed.
278.67
850.48 The closed cooling water head tank transmitter reading went to 0 which shut off the closed cooling water pump
1729.73
3.46 5240 ‐ Fire detection and extinguishing system B
15.55 5074 ‐ Flashback including instruments
59431.10 5012 ‐ High pressure blades/buckets B
10063.58 5120 ‐ Hydraulic oil system A
74.36 Danskin, Unit 3 tripped offline during the startup sequence. A fuel pressure transmitter went open for a brief instant causing a startup fired abort.
0.92 5048 ‐ Gas fuel system B
1823.25 An analog input card on the Steam Package of the DCS failed.
396.44
1215.50 The closed cooling water head tank transmitter reading went to 0 which shut off the closed cooling water pump
0.00 9910 ‐ Maintenance personnel erro
93960.00 4500 ‐ Rotor windings (including damper windings and fan blades on hydro units)
97092.00 4500 ‐ Rotor windings (including damper windings and fan blades on hydro units)
93960.00 4500 ‐ Rotor windings (including damper windings and fan blades on hydro units)
97092.00 4500 ‐ Rotor windings (including damper windings and fan blades on hydro units)
97092.00 4500 ‐ Rotor windings (including damper windings and fan blades on hydro units)
93960.00 4500 ‐ Rotor windings (including damper windings and fan blades on hydro units)
97092.00 4500 ‐ Rotor windings (including damper windings and fan blades on hydro units)
94090.50 4500 ‐ Rotor windings (including damper windings and fan blades on hydro units)
97092.00 4500 ‐ Rotor windings (including damper windings and fan blades on hydro units)
97092.00 4500 ‐ Rotor windings (including damper windings and fan blades on hydro units)
87696.00 4500 ‐ Rotor windings (including damper windings and fan blades on hydro units)
96961.50 4500 ‐ Rotor windings (including damper windings and fan blades on hydro units)
76.95 OBPR Unit #3 tripped due to a failed thrust bearing metal RTD that went high. All relays operated as they should. 
4034.25
The fault was predicted to be between the high side of the generator terminals and the breaker bushing terminals. Crews in the field began working on the physical troubleshooting of the issue and soon found a defective area of the bushing on the breaker assembly where current had arced probably to the 
nearby structure support members. In summary the relays operated as they were intended to.
11675.25 Continued work on the differential trip caused by wildlife 
3768.75 4555 ‐ Bearing cooling system A
531.30
While preparing for MOD testing for unit 3, the AVR/PSS was rebooted. During the restart process, the PSS reverted to some default parameters that caused it to swing the field current quite a bit once the unit was online and testing signals were introduced to the PSS 
ocntrol loop. The unstable oscillations caused by the PSS response caused the rotor field fault detection to pick up and trip the unit.  
3868.68
1503.60
8.62
63.10 Plant offline due to dissolved oxygen
741.18
20.93 Turbine 3 tripped on turbine packing box cooling water low.
Estimated Lost 
MWHrs Event Description
9.94 Plant Trouble Automatically created based on PI event: CDPO_G001 GEN_STATE_OFF 6/22/2021 8:31 PM
40.99 Plant Maintenance Plant breaker testing   
15.00 Plant Trouble Automatically created based on PI event: CLPR_G011 GEN_STATE_OFF 7/5/2021 5:12 PM. Ended early because of PI event CLPR_G011 GEN_STATE_GEN 7/5/2021 11:10 PM
64.38 Plant Trouble Automatically created based on PI event: CLPR_G011 GEN_STATE_OFF 7/31/2021 10:16 PM
71.45 Plant Trouble Automatically created based on PI event: CLPR_G011 GEN_STATE_OFF 8/16/2021 7:24 PM
0.25 Plant Maintenance Unit off‐line to change belt on oil pump. Plant will be opening 001Z and doing a LOTO.
32.50 Plant Trouble Automatically created based on PI event: CLPR_G011 GEN_STATE_OFF 9/1/2021 8:24 PM. Ended early because of PI event CLPR_G011 GEN_STATE_GEN 9/2/2021 9:23 AM
3.33 Plant Trouble Automatically created based on PI event: CLPR_G011 GEN_STATE_OFF 9/2/2021 4:08 PM. Ended early because of PI event CLPR_G011 GEN_STATE_GEN 9/2/2021 5:27 PM
A snake managed to get into the cubicle that ties the generator leads to the GSU transformer and made contact with a conductor. The contact with the snake initiated a phase to ground fault that quickly developed into a 
phase to phase fault. The SEL‐300G tripped on both 87 & 21 target elements. 
19.80 Plant Trouble Automatically created based on PI event: CLPR_G011 GEN_STATE_OFF 9/6/2021 1:35 PM. Ended early because of PI event CLPR_G011 GEN_STATE_GEN 9/6/2021 9:30 PM
5.00 Plant Trouble Automatically created based on PI event: CLPR_G011 GEN_STATE_OFF 9/15/2021 5:48 PM. Ended early because of PI event CLPR_G011 GEN_STATE_GEN 9/15/2021 7:45 PM
194.18  Unit Inspection
100.00 Plant Trouble Automatically created based on PI event: CLPR_G011 GEN_STATE_OFF 3/28/2022 8:02 AM

214.25 Plant Trouble Automatically created based on PI event: LMPR_G001 GEN_STATE_OFF 10/27/2021 3:43 AM. Ended early because of PI event LMPR_G001 GEN_STATE_GEN 10/27/2021 7:35 PM
165.38 Plant Trouble 
12.42 Plant Trouble 

802.17 Plant Trouble Generator troubles
6907.95 Plant Trouble Automatically created based on PI event: LSPR_G012 GEN_STATE_OFF 11/18/2021 12:21 PM
6904.19 Plant Trouble Bearing Temperature
16.10 Plant Trouble Inadvertent by workman 86E‐Wiring Crew hit plunger.
242.00 Plant Trouble    
6088.72 Unit inspection & expansion joint leak
1188.40 Plant Trouble Water/Oil Issue
618.13 Inspection of  wicket gates

34.78 Plant Trouble Automatically created based on PI event: SWPO_G011 GEN_STATE_OFF 5/6/2021 5:58 PM
34.78 Plant Trouble Automatically created based on PI event: SWPO_G012 GEN_STATE_OFF 5/6/2021 5:58 PM
113.16 Plant Trouble Automatically created based on PI event: SWPO_G012 GEN_STATE_OFF 5/22/2021 3:42 AM
14.26 Plant Trouble Automatically created based on PI event: SWPO_G012 GEN_STATE_OFF 11/1/2021 1:53 PM
80.15 Trouble shooting of  voltage regulator system
1954.88 Plant Trouble Automatically created based on PI event: SWPO_G011 GEN_STATE_OFF 12/2/2021 3:57 PM
2049.03 Shaft seal leak, inspection assessment
15446.15 Control wiring,unit Inspection, wicket bonnet replacement,index testing?
381.06 Control wiring,unit Inspection, wicket bonnet replacement,index testing?
40.76 Plant Trouble Automatically created based on PI event: SWPO_G011 GEN_STATE_OFF 2/3/2022 11:56 AM
1186.38 Control wiring,unit Inspection, wicket bonnet replacement,index testing?

79.08 Plant Trouble Breaker failed‐ outage (RS) # 10636 should a close but field verified breaker never closed
2516.00 Unit inspection   
868.50 Plant Trouble moisture Ended early because of PI event US12_G002 GEN_STATE_GEN 4/29/2021 10:55 AM
36.00 Trash rack inspection
36.00 Trash rack inspection
1323.72 Plant Trouble Automatically created based on PI event: US12_G002 GEN_STATE_OFF 5/6/2021 6:11 PM
469.44 Plant Trouble Automa cally created based on PI event: US12_G001 GEN_STATE_OFF 10/25/2021 10:05 AM.Troubleshoo ng a noise and smell coming from the unit.
695.25 Bearing troubleshooting and repair wor

631.70 Plant Trouble water in governor oil
7.43 Plant Trouble Automatically created based on PI event: US34_G004 GEN_STATE_OFF 6/7/2021 3:19 PM. Ended early because of PI event US34_G004 GEN_STATE_GEN 6/7/2021 4:13 PM
140.25 Flume inspection and assessment  
140.25 Plant Trouble Automatically created based on PI event: US34_G004 GEN_STATE_OFF 9/9/2020 11:08 AM
1386.00 Plant Trouble clearance #21803unit IS on 4/1...told today so ended outage PE
0.17 Plant Trouble out per gen desk request
647.63 New air cooler ‐ delay while waiting for parts
2197.22 Unit Inspection and assessment
List of all forced outages for Jim Bridger from 4/1/2021 ‐ 3/31/2022
Unit Start End MW Restriction Duration (hrs) MWh Lost Reason
JB1 04/24/2021 01:0 04/27/2021 12:0 531 83.1 44,108.4 Unit offline for tube leak repair. 
JB1 04/27/2021 12:0 04/27/2021 14:4 531 2.6 1,380.6 Start up failure‐ High opacity
JB1 04/27/2021 14:4 04/27/2021 19:17 531 4.6 2,451.5 Unit offline to rap precipitator
JB1 11/21/2021 13:45 11/21/2021 16:05 531 2.3 1,239.0 SEDC Out of Service ‐ Tripped Relays
JB1 11/21/2021 16:45 11/21/2021 20:51 531 4.1 2,177.1 12 induced draft fan rotation backwards
JB2 04/04/2021 01:01 04/07/2021 17:07 539 88.1 47,485.9 Unit offline for tube leak repair. 
JB2 04/10/2021 19:5 04/10/2021 22:22 539 2.5 1,365.5 Unit trip‐ #1 & #2 control valves stuck
JB2 06/13/2021 18:23 06/15/2021 13:22 539 43.0 23,168.0 #1 main stop valve stuck closed causing unit trip
JB2 07/12/2021 07:56 07/12/2021 12:42 539 4.8 2,569.2 Unit trip ‐ Manually tripped unit to avoid SO2 exceedance as the south SO2 damper went 80% open and would not respond in ovation
JB2 08/04/2021 08:56 08/04/2021 14:13 539 5.3 2,847.7 Main Turbine Trip Solenoid Failur
JB2 08/23/2021 23:22 08/24/2021 03:18 539 3.9 2,120.1 Unit trip ‐ #22 and #24 boiler circulating pumps tripped
JB2 11/07/2021 11:35 11/07/2021 16:46 539 5.2 2,793.8 Unit offline ‐ Replace the servo valve on the main turbine #1 reheat intercept Valve
JB3 10/08/2021 21:5 10/09/2021 00:45 523 2.9 1,490.6 Unit Trip ‐ High Opacity ‐ 34E transformer‐rectifier tripping
JB3 10/22/2021 13:43 10/24/2021 02:32 523 36.8 19,255.1 Unit offline ‐ Repair waterwall tube lea
JB3 10/26/2021 00:48 10/28/2021 07:35 523 54.8 28,651.7 Unit offline ‐ Repair #32 boiler feedpump booster pump discharge valve
JB3 12/04/2021 17:06 12/06/2021 02:2 523 33.3 17,415.9 Unit offline ‐ economizer tube leak.
JB3 12/20/2021 03:0 12/21/2021 19:35 523 40.6 21,225.1 Unit trip ‐ #31 primary air fan motor failed
JB3 12/27/2021 19:42 12/27/2021 22:02 523 2.3 1,220.3 Unit trip ‐ 35 gas path didn't close when 321D fan tripped ‐ tripped until to avoid opacity exceedance
JB4 05/09/2021 04:46 05/09/2021 11:16 526 6.5 3,419.0 Start up failure ‐ air preheater soot blowers are not working 
JB4 05/09/2021 11:16 05/09/2021 22:5 526 11.6 6,084.1 Air preheater soot blowers have been repaired.  Resume start up coming out of overhaul.
JB4 05/09/2021 22:5 05/10/2021 13:46 526 14.9 7,854.9 Startup failure ‐ Exciter communication is not working
JB4 05/10/2021 13:46 05/11/2021 00:0 526 10.2 5,382.7 Boiler circulating water pump differential pressure sensing line cracked between root valve and the mud drum. 
JB4 05/11/2021 00:0 05/11/2021 12:1 526 12.2 6,399.7 Boiler circulating water pump differential pressure sensing line has been repaired. Begin startup and conduct whopper testing coming out of the overhaul. 
JB4 05/11/2021 12:1 05/11/2021 19:37 526 7.5 3,918.7 Low Pressure turbine outer casing leak
JB4 05/11/2021 19:37 05/11/2021 21:42 526 2.1 1,095.8 Whopper testing
JB4 05/11/2021 21:42 05/11/2021 22:2 526 0.6 333.1 High turbine lube oil temp ‐ isolation valve position indication was backwards
JB4 05/11/2021 22:2 05/12/2021 00:0 526 1.7 876.7 Whopper testing
JB4 05/12/2021 00:0 05/12/2021 09:31 526 9.5 5,005.8 Startup and whopper test coming out of the overhaul. 
JB4 05/12/2021 10:09 05/12/2021 12:49 526 2.7 1,402.7 Unit offline‐ No indication of Primary Air Fan airflow. 
JB4 05/12/2021 20:29 05/13/2021 00:0 526 3.5 1,849.8 Unit offline‐ economizer tube leak. 
JB4 05/13/2021 00:0 05/14/2021 00:0 526 24.0 12,624.0 Unit offline‐ economizer tube leak. 
JB4 05/14/2021 00:0 05/14/2021 16:3 526 16.6 8,714.1 Unit offline‐ economizer tube leak. 
JB4 05/22/2021 09:2 05/23/2021 15:52 526 30.5 16,060.5 Unit trip ‐ #41 feedwater heater drain leak tripped 41 7200 bu
JB4 10/06/2021 08:1 10/06/2021 10:13 526 2.0 1,043.2 Unit trip ‐ #43 absorber blowdown valve stuck open resulting in low level
JB4 10/06/2021 10:13 10/06/2021 16:16 526 6.1 3,182.3 Start up failure ‐ Relay problems 
JB4 10/20/2021 13:4 10/20/2021 15:2 526 1.7 876.7 Unit Trip ‐ Boiler feed booster pump lube oil pressure indication bad
JB4 12/07/2021 11:3 12/07/2021 12:53 526 1.3 692.6 Unit trip ‐ A loose connec on on the 24v power supply caused a bad T9 y‐axis vibra on reading.
JB4 12/10/2021 09:17 12/10/2021 13:38 526 4.4 2,288.1 Unit Trip ‐ False transformer water spray indication
JB2 01/07/2022 02:3 01/10/2022 17:21 539 86.9 46,812.2 Unit offline ‐ Repair cooling tower risers
JB2 01/10/2022 20:26 01/10/2022 21:49 539 1.4 745.6 Unit offline ‐ 22 induced draft fan tripped due to high temp.  21 ID Fan OOS
JB2 01/10/2022 21:49 01/10/2022 22:39 539 0.8 449.2 Startup Failure ‐ Exhaust hood temp
JB2 01/11/2022 08:28 01/11/2022 10:28 539 2.0 1,078.0 Unit trip ‐ Opacity was high while putting 21 induced draft fan back in service ‐tripped unit to avoid opacity exceedance 
JB3 01/26/2022 18:4 01/27/2022 00:46 523 6.0 3,155.4 Unit Trip ‐ Manually tripped unit to avoid opacity exceedance. #31 ID fan tripped causing the high opacit
JB1 02/21/2022 20:53 02/22/2022 01:12 531 4.3 2,292.2 Unit Trip ‐ Drum transmitters B and C falsely indicated low drum level
JB1 02/22/2022 01:12 02/22/2022 08:31 531 7.3 3,885.2 #11 PA fan motor outboard bearing temp below permissive limit
JB1 02/25/2022 19:53 02/25/2022 22:42 531 2.8 1,495.7 Unit Trip ‐ Manually tripped unit due to opacity.   Found an obstruction that was partially blocking the stack opacity monitor port.  
JB2 02/28/2022 15:59 02/28/2022 18:11 539 2.2 1,185.8 Unit trip ‐ #23 condensate pump tripped due to lower bearing failure
JB1 03/11/2022 17:31 03/11/2022 20:28 531 3.0 1,566.5 Unit Trip ‐ Manually tripped unit due to opacity. Appears there was an obstruction that was partially blocking the stack opacity monitor port.  
JB1 03/19/2022 01:0 03/21/2022 14:5 531 61.8 32,833.5 Unit Offline‐#12 boiler circulating pump repai
List of all forced outages for North Valmy Unit 2 from 4/1/2021 ‐ 3/31/2022
Unit Start End MW Restriction Duration (hrs) MWh Lost Reason
VALMY 2 05/24/2021 03:0 05/25/2021 21:2 268 42.3 11,345.3 Drain Reciever allowed air in leakage to condenser causing high backpressure trip.
VALMY 2 06/11/2021 02:09 06/11/2021 09:26 268 7.3 1,951.9 Lost communication with baghouse. Trip on high dp
VALMY 2 06/14/2021 20:2 06/21/2021 09:3 268 157.2 42,120.7 Generator tripped on generator protection
VALMY 2 06/27/2021 20:52 06/28/2021 13:49 268 17.0 4,542.6 Lost commuication with baghouse.  Baghouse closed all dampers.
VALMY 2 06/28/2021 13:58 06/28/2021 17:5 268 3.9 1,036.3 U2 right Main Stop Valve malfunction
VALMY 2 07/11/2021 13:21 07/17/2021 22:26 268 153.1 41,026.3 Main steam line gasket blew on left upper control valve steam lead
VALMY 2 08/06/2021 01:25 08/06/2021 02:36 268 1.2 317.1 Lost 2C pulverizer gearbox which tripped the mill and then tripped the unit
VALMY 2 08/14/2021 03:19 08/14/2021 19:5 268 16.6 4,444.3 B Main turbine lube oil pump failed
VALMY 2 11/09/2021 12:49 11/09/2021 20:08 268 7.3 1,960.9 Lost commuication with baghouse.  Baghouse closed all dampers, zero air flow through
VALMY 2 12/26/2021 17:37 12/27/2021 01:4 268 8.1 2,175.3 CST level indication froze due to cold weather.
VALMY 2 02/08/2022 23:17 02/09/2022 04:15 268 5.0 1,331.1 Unit tripped on High Opacity. Suspect Baghouse Compartment 2.
VALMY 2 02/11/2022 07:23 02/15/2022 23:59 268 112.6 30,176.8 Unit 2, we lost control of the raise/lower controls to the exciter and burnt electrica
VALMY 2 03/07/2022 16:08 03/07/2022 19:2 268 3.3 875.5 Both In Service Pulverizers (A&C) plugged with coal while trying to increase coal feed
VALMY 2 03/08/2022 00:5 03/09/2022 16:0 268 39.1 10,478.8 False Trisector Air Heater Zero Speed switch tripped MFT (Labeled as Baghouse OpacityT
VALMY 2 03/13/2022 17:32 03/13/2022 19:32 268 2.0 536.0 Unit Tripped on High Opacity Protective Trip during cleaning cycle of the baghouse
Unforced Shutdowns
Unit Code Unit Name Unit Type Event Year Event Type Event Start Date Event End Date Event Duration Event Cause Code
101 LANGLEY GULCH #2 852 ‐ CC steam units 2021 PO ‐ Planned 04/01/2021 08:06 MP 04/02/2021 08:00 MP 23:54:00 Spring plant maintenance outage
2021 PO ‐ Planned 04/02/2021 08:01 MP 04/30/2021 10:18 MP 674:17:00 Spring extended maintenance outage
2021 MO ‐ Maintenance 05/03/2021 11:29 MP 05/04/2021 08:00 MP 20:31:00 Spring extended maintenance outage
2021 PO ‐ Planned 10/01/2021 01:00 MP 10/17/2021 11:59 MP 394:59:00 Fall maintenace outage
2022 PO ‐ Planned 03/11/2022 08:00 MP 04/01/2022 00:00 MP 495:00:00 5274 ‐ General unit inspection during spring maintenance outage
302 BENNETT MOUNTAIN 300 ‐ Gas Turbine/Jet Engine (Simple Cycle Operation)2021 PO ‐ Planned 05/01/2021 17:55 MP 05/14/2021 17:30 MP 311:35:00 Spring plant maintenance outage
2021 MO ‐ Maintenance 09/04/2021 16:45 MP 09/05/2021 13:50 MP 21:05:00 Fall maintenance outage
2021 PO ‐ Planned 09/17/2021 08:00 MP 09/29/2021 11:48 MP 291:48:00 Fall extended maintenance outage
2022 MO ‐ Maintenance 01/24/2022 21:13 MP 01/26/2022 09:30 MP 36:17:00 5240 ‐ Fire detection and extinguishing system B
2022 PO ‐ Planned 02/18/2022 08:00 MP 03/01/2022 00:00 MP 256:00:00 5274 ‐ General unit inspection A
2022 PO ‐ Planned 03/01/2022 00:00 MP 03/07/2022 11:30 MP 155:30:00 5274 ‐ General unit inspection A
303 DANSKIN #1 300 ‐ Gas Turbine/Jet Engine (Simple Cycle Operation)2021 PO ‐ Planned 05/18/2021 08:00 MP 06/01/2021 00:00 MP 328:00:00 Spring plant maintenance outage
2021 PO ‐ Planned 06/01/2021 00:00 MP 06/11/2021 12:31 MP 252:31:00 Spring extended maintenance outage
2021 PO ‐ Planned 10/18/2021 08:00 MP 10/26/2021 16:25 MP 200:25:00 Fall maintenance outage
304 DANSKIN #2 300 ‐ Gas Turbine/Jet Engine (Simple Cycle Operation)2021 MO ‐ Maintenance 09/27/2021 06:30 MP 09/29/2021 00:59 MP 42:29:00 Fall maintenance outage
2021 PO ‐ Planned 10/18/2021 08:00 MP 10/27/2021 16:30 MP 224:30:00 Fall extended maintenance outage
305 DANSKIN #3 300 ‐ Gas Turbine/Jet Engine (Simple Cycle Operation)2021 PO ‐ Planned 04/01/2021 00:00 MP 04/01/2021 14:00 MP 14:00:00 Spring plant maintenance outage
2021 MO ‐ Maintenance 08/09/2021 07:58 MP 08/09/2021 16:43 MP 8:45:00 Fall maintenance outage
2021 PO ‐ Planned 10/18/2021 08:00 MP 10/27/2021 16:10 MP 224:10:00 Fall extended maintenance outage
306 LANGLEY GULCH #1 851 ‐ CC GT units 2021 PO ‐ Planned 04/01/2021 08:06 MP 04/02/2021 08:00 MP 23:54:00 Spring plant maintenance outage
2021 PO ‐ Planned 04/02/2021 08:01 MP 04/30/2021 10:18 MP 674:17:00 Spring extended maintenance outage
2021 MO ‐ Maintenance 05/03/2021 11:29 MP 05/04/2021 08:00 MP 20:31:00 Spring extended maintenance outage
2021 PO ‐ Planned 10/01/2021 01:00 MP 10/17/2021 11:59 MP 394:59:00 Fall maintenace outage
2022 PO ‐ Planned 03/11/2022 08:00 MP 04/01/2022 00:00 MP 495:00:00 5274 ‐ General unit inspection during spring maintenance outage
501 HELLS CANYON #1 500 ‐ Pumped Storage/Hydro 2021 PO ‐ Planned 04/27/2021 08:31 MP 04/27/2021 09:16 MP 0:45:00 Inspection outage
2021 PO ‐ Planned 04/27/2021 11:02 MP 04/27/2021 11:55 MP 0:53:00 Inspection outage
502 HELLS CANYON #2 500 ‐ Pumped Storage/Hydro 2021 PO ‐ Planned 04/27/2021 09:34 MP 04/27/2021 10:30 MP 0:56:00 Inspection outage
504 OXBOW #1 500 ‐ Pumped Storage/Hydro 2022 PO ‐ Planned 02/14/2022 08:00 MP 02/24/2022 18:45 MP 250:45:00 4840 ‐ Inspection E
505 OXBOW #2 500 ‐ Pumped Storage/Hydro 2022 PO ‐ Planned 02/28/2022 08:00 MP 03/01/2022 00:00 MP 16:00 4840 ‐ Inspection E
2022 PO ‐ Planned 03/01/2022 00:00 MP 03/10/2022 11:15 MP 227:15:00 4840 ‐ Inspection E
506 OXBOW #3 500 ‐ Pumped Storage/Hydro 2021 PO ‐ Planned 11/29/2021 08:00 MP 12/01/2021 00:00 MP 40:00:00 Condition assessment outage
2021 PO ‐ Planned 12/01/2021 00:00 MP 12/09/2021 18:10 MP 210:10:00 Condition assessment outage
507 OXBOW #4 500 ‐ Pumped Storage/Hydro 2021 PO ‐ Planned 11/29/2021 08:00 MP 12/01/2021 00:00 MP 40:00:00 Condition assessment outage
2021 PO ‐ Planned 12/01/2021 00:00 MP 12/21/2021 16:36 MP 496:36:00 Condition assessment outage
508 BROWNLEE #1 500 ‐ Pumped Storage/Hydro 2021 PO ‐ Planned 10/04/2021 08:00 MP 11/01/2021 00:00 MP 664:00:00 GSU major inspection and assessment
2021 PO ‐ Planned 11/01/2021 00:00 MP 12/01/2021 00:00 MP 721:00:00 GSU major inspection and assessment
2021 PO ‐ Planned 12/01/2021 00:00 MP 12/29/2021 17:07 MP 689:07:00 GSU major inspection and assessment
509 BROWNLEE #2 500 ‐ Pumped Storage/Hydro 2022 PO ‐ Planned 03/21/2022 08:00 MP 04/01/2022 00:00 MP 256:00:00 GSU major inspection and assessment
510 BROWNLEE #3 500 ‐ Pumped Storage/Hydro 2021 PO ‐ Planned 05/04/2021 08:04 MP 05/05/2021 11:20 MP 27:16:00 Inspection on rotor pole tightness
2022 PO ‐ Planned 01/03/2022 08:00 MP 02/01/2022 00:00 MP 688:00:00 Unit maintenance and inspection
2022 PO ‐ Planned 02/01/2022 00:00 MP 03/01/2022 00:00 MP 672:00:00 Unit maintenance and inspection
2022 PO ‐ Planned 03/01/2022 00:00 MP 03/16/2022 15:00 MP 374:00:00 Unit maintenance and inspection
511 BROWNLEE #4 500 ‐ Pumped Storage/Hydro 2021 PO ‐ Planned 05/26/2021 08:00 MP 05/26/2021 11:14 MP 3:14:00 4840 ‐ Inspection E
2021 PO ‐ Planned 09/27/2021 08:00 MP 10/01/2021 00:00 MP 88:00:00 Replacement of GSU transformer
2021 PO ‐ Planned 10/01/2021 00:00 MP 11/01/2021 00:00 MP 744:00:00 Replacement of GSU transformer
2021 PO ‐ Planned 11/01/2021 00:00 MP 12/01/2021 00:00 MP 721:00:00 Replacement of GSU transformer
2021 PO ‐ Planned 12/01/2021 00:00 MP 12/28/2021 13:35 MP 661:35:00 Replacement of GSU transformer
2022 MO ‐ Maintenance 02/01/2022 08:00 MP 02/01/2022 15:00 MP 7:00 4899 ‐ Other miscellaneous generator problems
2022 PO ‐ Planned 03/17/2022 11:00 MP 03/17/2022 13:59 MP 2:59 4840 ‐ Inspection E
512 BROWNLEE #5 500 ‐ Pumped Storage/Hydro 2021 PO ‐ Planned 04/01/2021 00:00 MP 05/01/2021 00:00 MP 720:00:00 Generator rewind project
2021 PO ‐ Planned 05/01/2021 00:00 MP 06/01/2021 00:00 MP 744:00:00 Generator rewind project
2021 PO ‐ Planned 06/01/2021 00:00 MP 06/09/2021 09:09 MP 201:09:00 Generator rewind project
513 STRIKE #1 500 ‐ Pumped Storage/Hydro 2021 PO ‐ Planned 10/26/2021 23:59 MP 10/29/2021 16:15 MP 64:16:00 GSU Transformer testing
2022 PO ‐ Planned 01/18/2022 07:00 MP 02/01/2022 00:00 MP 329:00:00 4840 ‐ Unit Inspection 
2022 PO ‐ Planned 02/01/2022 00:00 MP 02/15/2022 08:00 MP 344:00:00 4841 ‐ Unit Inspection 
514 STRIKE #2 500 ‐ Pumped Storage/Hydro 2021 PO ‐ Planned 10/11/2021 07:30 MP 10/18/2021 08:00 MP 168:30:00 Repair turbine bearing lea
2022 PO ‐ Planned 02/16/2022 07:00 MP 03/01/2022 00:00 MP 305:00:00 4840 ‐ Inspection E
2022 PO ‐ Planned 03/01/2022 00:00 MP 04/01/2022 00:00 MP 743:00:00 4840 ‐ Inspection E
515 STRIKE #3 500 ‐ Pumped Storage/Hydro 2021 PO ‐ Planned 09/27/2021 07:00 MP 10/01/2021 00:00 MP 89:00:00 4840 ‐ Unit Inspection 
2021 PO ‐ Planned 10/01/2021 00:00 MP 10/07/2021 12:52 MP 156:52:00 4840 ‐ Unit Inspection 
516 BLISS #1 500 ‐ Pumped Storage/Hydro 2021 PO ‐ Planned 09/20/2021 08:00 MP 09/30/2021 15:32 MP 247:32:00 4840 ‐ Unit Inspection 
517 BLISS #2 500 ‐ Pumped Storage/Hydro 2021 PO ‐ Planned 10/05/2021 08:00 MP 10/14/2021 16:00 MP 224:00:00 4840 ‐ Unit Inspection 
518 BLISS #3 500 ‐ Pumped Storage/Hydro 2021 PO ‐ Planned 10/18/2021 07:30 MP 10/28/2021 13:25 MP 245:55:00 4840 ‐ Unit Inspection 
537 AMERICAN FALLS #1 500 ‐ Pumped Storage/Hydro 2021 PO ‐ Planned 11/15/2021 08:00 MP 12/01/2021 00:00 MP 376:00:00 4840 ‐ Unit Inspection 
2021 PO ‐ Planned 12/01/2021 00:00 MP 12/15/2021 16:00 MP 352:00:00 Maintenance outage
2022 PO ‐ Planned 02/07/2022 08:30 MP 02/07/2022 14:15 MP 5:45 3620 ‐ Main transformer
2022 PO ‐ Planned 03/30/2022 07:00 MP 03/30/2022 15:00 MP 8:00 4840 ‐ Inspection E
538 AMERICAN FALLS #2 500 ‐ Pumped Storage/Hydro 2021 PO ‐ Planned 12/13/2021 08:00 MP 12/13/2021 08:40 MP 0:40:00 4840 ‐ Inspection E
2021 PO ‐ Planned 12/15/2021 14:30 MP 12/31/2021 23:59 MP 393:29:00 Maintenance outage
2022 PO ‐ Planned 01/01/2022 00:00 MP 01/13/2022 14:26 MP 302:26:00 4840 ‐ Inspection E
2022 PO ‐ Planned 02/07/2022 08:30 MP 02/07/2022 14:36 MP 6:06 3620 ‐ Main transformer
539 AMERICAN FALLS #3 500 ‐ Pumped Storage/Hydro 2022 PO ‐ Planned 01/18/2022 08:00 MP 02/01/2022 00:00 MP 328:00:00 4840 ‐ Inspection E
2022 PO ‐ Planned 02/01/2022 00:00 MP 02/07/2022 08:30 MP 152:30:00 4840 ‐ Inspection E
2022 PO ‐ Planned 02/07/2022 08:30 MP 02/07/2022 14:10 MP 5:40 3620 ‐ Main transformer
NON‐BES Units
Unit Code Unit Name Unit Type Event Year Event Type Event Start Date Event End Date Event Duration Event Description
CDPO G001 GN 500 ‐ Pumped Storage/Hydro 2022 Planned 03/14/2022 08:00 03/24/2022 10:48 242:48:00 Plant Maintenance Unit Inspection
CDPO G002 GN 500 ‐ Pumped Storage/Hydro 2022 Planned 03/28/2022 08:00 04/07/2022 09:13 241:13:00 Plant Maintenance Unit Inspection
CLPR G001 GN 500 ‐ Pumped Storage/Hydro 2021 Planned 05/24/2021 08:00 05/26/2021 15:26 55:26:00 Plant Maintenance unit inspec on
LMPR G001 GN 500 ‐ Pumped Storage/Hydro 2021 Planned 04/01/2021 08:01 05/05/2021 14:19 822:18:00 Plant Maintenance unit inspec on, valving on water driven governor‐upgrade gov., flume cover, ball valve penstock
LSPR G011 GN 500 ‐ Pumped Storage/Hydro 2021 Planned 04/01/21 03/31/2022 15:00 8751:00:00 Plant Maintenance Turbine replacement, rewind project, (check‐outs & commission unit)
LSPR G013 GN 500 ‐ Pumped Storage/Hydro 2021 Planned 04/05/2021 08:04 04/15/2021 08:57 240:53:00 Plant Maintenance Unit Inspection
LSPR G014 GN 500 ‐ Pumped Storage/Hydro 2021 Planned 04/19/2021 08:02 04/29/2021 14:05 246:03:00 Plant Maintenance unit inspec on, head gate refurb.
LSPR G012 GN 500 ‐ Pumped Storage/Hydro 2022 Planned 02/22/2022 08:00 03/15/2022 07:20 503:20:00 Plant Maintenance Unit inspection
LSPR G014 GN 500 ‐ Pumped Storage/Hydro 2022 Planned 03/15/2022 08:00 03/23/2022 09:20 193:20:00 Plant Maintenance Unit Inspection
MLPR G012 GN 500 ‐ Pumped Storage/Hydro 2022 Planned 02/11/2022 08:00 04/07/2022 11:05 1323:05:00 Plant Maintenance Gen. protection upgrade,unit inspection, cone repair, blow out cooler
 SFPR G004 GN 500 ‐ Pumped Storage/Hydro 2021 Planned 08/23/2021 07:09 09/03/2021 06:00 262:51:00 Plant Maintenance UI testing
SWPO G011 GN 500 ‐ Pumped Storage/Hydro 2021 Planned 10/18/2021 08:00 12/01/2021 15:44 1063:44:00 Plant Maintenance Control wiring,unit Inspec on, index tes ng?
SWPO G012 GN 500 ‐ Pumped Storage/Hydro 2021 Planned 11/22/2021 08:00 11/23/2021 16:00 32:00:00 Plant Maintenance Control wiring,unit Inspec on, wicket bonnet replacement,index tes ng
TFPR G001 GN 500 ‐ Pumped Storage/Hydro 2022 Planned 01/24/2022 08:00 02/02/2022 14:33 222:33:00 Plant Maintenance unit inspection,inspect runner, unwatering pump
TFPR G001 GN 500 ‐ Pumped Storage/Hydro 2022 Planned 03/12/2022 08:00 03/12/2022 18:07 10:07:00 Plant Maintenance Transmission Maintenance
TSPO G003 GN 500 ‐ Pumped Storage/Hydro 2021 Planned 05/10/2021 08:04 05/18/2021 17:13 201:09:00 Plant Maintenance Unit Inspection
UMPR G001 GN 500 ‐ Pumped Storage/Hydro 2021 Planned 10/18/2021 07:00 11/17/2021 14:20 727:20:00 Plant Maintenance unit inspection, head gate refurb.
US12 G001 GN 500 ‐ Pumped Storage/Hydro 2021 Planned 09/20/2021 08:00 10/14/2021 12:41 580:41:00 Plant Maintenance Work on Local Service
US12 G002 GN 500 ‐ Pumped Storage/Hydro 2021 Planned 09/20/2021 08:00 10/14/2021 12:39 580:39:00 Plant Maintenance Work on Local Service
US34 G004 GN 500 ‐ Pumped Storage/Hydro 2021 Planned 04/01/21 04/15/2021 11:42 347:42:00 Plant Maintenance Reject way replacement project.
US34 G003 GN 500 ‐ Pumped Storage/Hydro 2021 Planned 04/01/21 04/15/2021 10:45 346:45:00 Plant Maintenance Reject way replacement project.
US34 G004 GN 500 ‐ Pumped Storage/Hydro 2021 Planned 04/01/21 04/07/2021 17:00 161:00:00 Plant Maintenance 
US34 G004 GN 500 ‐ Pumped Storage/Hydro 2022 Planned 03/21/2022 08:30 03/24/2022 12:47 76:17:00 Plant Maintenance Unit Inspection
BES Facility Definition:  Generating resource(s) including the generator terminals through the high‐side of the stepup 
transformer(s) connected at a voltage of 100 kV or above with: a) Gross individual nameplate rating greater than 20 MVA. Or, b) 
Gross plant/facility aggregate nameplate rating greater than 75 MVA
List of all scheduled outages for Jim Bridger from 4/1/2021 ‐ 3/31/2022
Unit Start End Duration (hrs)
JB1 11/17/2021 02:22 11/21/2021 13:45 107.4
JB2 07/16/2021 00:47 07/17/2021 00:00 23.2
JB2 07/17/2021 00:00 07/18/2021 00:00 24.0
JB2 07/18/2021 00:00 07/18/2021 08:32 8.5
JB3 11/11/2021 00:59 11/16/2021 23:45 142.8
JB4 03/27/2021 01:15 05/01/2021 07:00 845.8
JB4 05/01/2021 07:00 05/09/2021 04:46 189.8
JB4 06/05/2021 01:49 06/08/2021 03:01 73.2
JB4 09/17/2021 01:00 09/20/2021 06:45 77.8
JB4 11/22/2021 00:51 11/24/2021 14:20 61.5
JB4 12/18/2021 01:01 12/19/2021 03:16 26.3
JB4 03/29/2022 01:01 04/01/2022 00:00 71.0
Reason
Unit offline ‐ Turbine foam clean
Unit offline ‐ Replace #22 Boiler Circ Pump
Unit offline ‐ Replace #22 Boiler Circ Pump
Unit offline ‐ Replace #22 Boiler Circ Pump
Unit offline ‐ Turbine foam clean
Unit offline for overhaul. 
Outage extension ‐ #2 MS valve actuator returned from the shop on 5/6/2021; installed; seal leakage test on 5/8/2021.
Unit off for fine screen removal.
Unit offline ‐ Repair waterwall tube leak
41 Boiler Circ Pump Check Valve Repairs
Unit offline ‐ economizer tube leak
Unit off ‐ Deslag Finishing Super Heat Section
List of all scheduled outages for North Valmy Unit 2 from 4/1/2021 ‐ 3/31/2022
Unit Start End Duration (hrs)
VALMY 2 02/16/2022 00:00 02/21/2022 23:59 144.0
Reason
Planned Maintenance Outage for mandatory Boiler Inspection, Ovation Upgrade
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-22-11
IDAHO POWER COMPANY
REQUEST NO. 2
ATTACHMENT NO. 7
1
Subject:Follow up to PR No. 6 in Case No. IPC-E-22-11
Location:WebEx
Start:Thu 5/12/2022 10:00 AM
End:Thu 5/12/2022 11:00 AM
Show Time As:Tentative
Recurrence:(none)
Meeting Status:Not yet responded
Organizer:Brady, Jessi
Required Attendees:Larkin, Matt; Tatum, Tim; Adelman, Ryan; Mike Louis; Terri Carlock; Michael Eldred; Kathy
Stockton; Jo Nelson
Meeting to discuss the below Production Request (as a follow up to Staff’s DR 6)

Please provide the following for Hells Canyon #3 relative to the forced downtime that started on 4/1/2021 through
4/1/2022 (according to the response).

1. Please provide a detailed explanation as to the cause of the downtime including the likely root cause(s).
2. Is the unit still offline? If so, when is it expected to come back on line?
3. Why
the unit back online?
4. Could the unit have been brought on line sooner? If so, please explain how and the associated cost.
5. According to the response, 1,143,180 Megawatt-hours during the PCA deferral period has been lost of zero-fuel
cost generation. Please calculate the additional cost of replacing the generation from that unit due to the
outage. Please provide workpapers in electronic format with formula intact.
6. Please provide any documentation showing the Company’s analysis of the downtime that address any or all of
the questions above.

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1
From:Brady, Jessi
Sent:Tuesday, May 10, 2022 1:22 PM
To:Mike Louis
Subject:RE: Follow up to PR No. 6 in Case No. IPC-E-22-11
Thank you! I will schedule with WebEx.

From: Mike Louis <[e-mail]>
Sent: Tuesday, May 10, 2022 1:02 PM
To: Brady, Jessi <[e-mail]>
Cc: Larkin, Matt <[e-mail]>; Tatum, Tim <[e-mail]>; Terri Carlock
<[e-mail]>; Michael Eldred <[e-mail]>; Kathy Stockton
<[e-mail]>; Jo Nelson <[e-mail]>
Subject: [EXTERNAL]RE: Follow up to PR No. 6 in Case No. IPC-E-22-11

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Hi Brady,

The best time for us is from 10 to 11. We have an all day meeting that day, but this part of the meeting is not critical for
those in attendance. Can you send us an invite via Webex? Teams does not work between the commission and IPC.

Thanks,

Mike

From: Brady, Jessi <[e-mail]>
Sent: Tuesday, May 10, 2022 12:16 PM
To: Mike Louis <[e-mail]>
Cc: Larkin, Matt <[e-mail]>; Tatum, Tim <[e-mail]>; Terri Carlock
<[e-mail]>; Michael Eldred <[e-mail]>; Kathy Stockton
<[e-mail]>; Jo Nelson <[e-mail]>
Subject: RE: Follow up to PR No. 6 in Case No. IPC-E-22-11

Hi Mike,

Thanks for sending these over! We will work on drafting responses to these. Can you confirm if any of the below times
will work for you all to discuss?

Thursday 5/12
10 – 11am
12 – 1pm
3 – 4pm

Thank you!
Jessi

2
Jessi Brady
Regulatory Analyst
Idaho Power | Regulatory Affairs
Work [phone]
Email [e-mail]

From: Mike Louis <[e-mail]>
Sent: Tuesday, May 10, 2022 9:40 AM
To: Brady, Jessi <[e-mail]>
Cc: Larkin, Matt <[e-mail]>; Tatum, Tim <[e-mail]>; Terri Carlock
<[e-mail]>; Michael Eldred <[e-mail]>; Kathy Stockton
<[e-mail]>; Jo Nelson <[e-mail]>
Subject: [EXTERNAL]Follow up to PR No. 6 in Case No. IPC-E-22-11

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the sender before proceeding, and check for additional warning messages below.
Hi Jessi,

You sponsored Production Request No. 6 in Case No. IPC-E-22-11. Staff has some follow up questions providing
clarification and additional information regarding the forced downtime on Hells Canyon #3.

Regarding Production Request No. 6, please provide the following for Hells Canyon #3 relative to the forced downtime
that started on 4/1/2021 through 4/1/2022 (according to the response).

1. Please provide a detailed explanation as to the cause of the downtime including the likely root cause(s).
2. Is the unit still offline? If so, when is it expected to come back on line?
3. Why
the unit back online?
4. Could the unit have been brought on line sooner? If so, please explain how and the associated cost.
5. According to the response, 1,143,180 Megawatt-hours during the PCA deferral period has been lost of zero-fuel
cost generation. Please calculate the additional cost of replacing the generation from that unit due to the
outage. Please provide workpapers in electronic format with formula intact.
6. Please provide any documentation showing the Company’s analysis of the downtime that address any or all of
the questions above.

Because of the expedited timeline for Staff’s comments, we would like to schedule a meeting as soon as possible with
those that can answer these questions. We will also send a formal production request, hopefully by the end of the day,
so we can get the response in writing.

Thank you.

Mike Louis
Engineering Program Manager
Idaho Public Utilities Commission
[e-mail]
208-334-0316 (work)
(cell)

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