20241206Settlement Stipulation.pdf

_ ROCKY MOUNTAIN 1407 W.North Temple,Suite 330
POWER. Salt Lake City,UT 84116
A DIVISION OF PACIFICORP
RECEIVED
Friday, December 6, 2024
December 6, 2024 IDAHO PUBLIC
UTILITIES COMMISSION
VIA ELECTRONIC DELIVERY
Commission Secretary
Idaho Public Utilities Commission
11331 W. Chinden Blvd
Building 8 Suite 201A
Boise, ID 83714
RE: CASE NO. PAC-E-24-04
IN THE MATTER OF ROCKY MOUNTAIN POWER'S APPLICATION FOR
AUTHORITY TO INCREASE ITS RATES AND CHARGES IN IDAHO
Attention: Commission Secretary
Rocky Mountain Power hereby submits for filing with the Idaho Public Utilities Commission a
settlement stipulation and attachments in the above-referenced matter.
Informal inquiries may be directed to Mark Alder, Idaho Regulatory Manager at(801) 220-2313.
Very truly yours,
a�"D
Joe Steward 9�3
Senior Vice President, Regulation

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF ROCKY MOUNTAIN ) CASE NO. PAC-E-24-04
POWER'S APPLICATION FOR )
AUTHORITY TO INCREASE ITS RATES ) SETTLEMENT STIPULATION
AND CHARGES IN IDAHO )
This Settlement Stipulation ("Stipulation") is entered into by and among PacifiCorp d/b/a
Rocky Mountain Power("PacifiCorp" or the "Company"), Staff for the Idaho Public Utilities
Commission("Staff'),PacifiCorp Idaho Industrial Customers ("PIIC"),P4 Production,L.L.C.
an affiliate of Bayer Corporation ("Bayer"), and Idaho Irrigation Pumpers Association, Inc.
("IIPA"), (collectively, the "Parties,"and individually"Party") in resolution of all outstanding
issues in this proceeding. Idaho Conservation League ("ICL") also intervened in the case. ICL
filed a Notice of Withdrawal on November 14, 2024.
INTRODUCTION
I. The Parties agree that this Stipulation represents a fair, just, and reasonable
compromise of the issues in this proceeding and that this Stipulation is in the public interest.
The Parties recommend that the Idaho Public Utilities Commission ("Commission") approve
the Stipulation pursuant to its authority under Commission Rules 272 and 274. The Parties
understand that the Stipulation is not binding on the Commission or any Party unless the
Commission approves it.
BACKGROUND
2. On May 31, 2024, the Company filed an Application with the Commission
requesting authority to increase its Idaho jurisdictional revenue requirement by $92.4 million,
SETTLEMENT STIPULATION PAGE 1

or approximately 26.8 percent. The Company also requested approval to mitigate the rate
increase by phasing in the base net power cost increase over two years.The Company proposed
the first increase of$66.7 million or 19.4 percent to take effect January 1, 2025, and a second
increase of$25.7 million or 7.4 percent to take effect on January 1, 2026, for a total increase
of $92.4 million or 26.8 percent. The overall increase varies by customer class and actual
usage. The proposed overall increase is based upon the historical twelve-month period ending
December 31, 2023, adjusted for known and measurable changes through December 31, 2024
("Test Period").
3. The Application reflected net power costs("NPC")for the Test Period of$2.382
billion on a total-Company basis, $136.7 million on an Idaho-allocated basis,which represents
a $1.015 billion, or 74 percent increase on a total-Company basis in net power costs compared
to the 2021 rate case, Docket No. PAC-E-21-07. The Application also requested recovery of
capital additions, including costs associated with its Gateway South and Gateway West
Segment D.1 transmission lines, Rock Creek 1 wind facility, and Foote Creek II, III, and IV
and Rock River I repowering projects.
4. In its Application,the Company requested approval for proposed modifications
to the Energy Cost Adjustment Mechanism (`SCAM"). The Company proposed including
modifying the sharing band for 95 percent of NPC variances to be passed through the
mechanism and the remaining five percent of the NPC variances would remain outside the
mechanism. The Company also requested to remove the Renewable Energy Credit ("REC")
SETTLEMENT STIPULATION PAGE 2

revenue adjustment from the annual ECAM calculation and instead provide a new voluntary
renewable energy credit option tariff and a new REC revenue adjustment tariff.
5. The Company also requested approval of two proposals to help position it to
respond to financial risk posed by the increasing frequency and severity of wildfires impacting
PacifiCorp's service territories. First, the Company proposed an Insurance Cost Adjustment
("ICA") to recover the costs for excess liability insurance through a separate surcharge.
Second, the Company proposed a Catastrophic Fire Fund to facilitate creation of a multi-state
risk pool for potential catastrophic events where third-party liabilities are in excess of the
Company's insurance coverage.
6. On October 9, 2024, the Commission suspended the proposed effective date of
January 1, 2025, for the statutory maximum period of 60 days pursuant to Idaho Code § 61-
622(4).
7. The Parties have conducted extensive discovery in this proceeding, held an
initial in-person settlement conference on October 21, 2024, and several virtual and in-person
subsequent meetings, and presented proposals and counter-proposals which culminated in this
settlement.
8. This settlement is a comprehensive resolution of this proceeding. The terms of
the settlement are set forth in this Stipulation, which the Parties have entered into voluntarily
to resolve matters in dispute in the interests of expediting the orderly disposition of this
SETTLEMENT STIPULATION PAGE 3

proceeding. The Parties intend to file the Stipulation with the Commission and request
Commission approval of the Stipulation.
AGREEMENT
9. Overall Agreement: The Parties agree to an overall base rate increase of
$57.94 million or 16.8 percent effective January 1, 2025. Unless specified within the
Stipulation,the Parties agree that this increase does not represent agreement or acceptance by
the Parties of any specific revenue requirement methodology. The Parties also agree to
mitigating the impacts of the overall base increase with extending the recovery of the ECAM
deferral balances as explained in Paragraphs 13.b and 13.c below, which reduces the impact
of the overall rate increase by$32.5 million. The net rate change effective January 1, 2025 is
$25.44 million or 7.4 percent. Appendix A to this Stipulation reflects the agreed-upon
calculation of the base rate change and the rate mitigation. The Parties agree that the rate
change attributable to the revenue requirement identified herein will be effective with service
on and after January 1, 2025.
As shown in Appendix A and detailed below, the Parties agree that the proposed total
overall $57.94 million increase reflects specific updates and adjustments to the Company's
filed case, as well as an additional non-specific adjustment related to a compromise of issues
on which resolution could not be reached.
10. Rate of Return: The Parties agree to a rate of return of 7.25 percent, based on
unspecified assumptions for capital structure costs and components.
11. Rate Base:
a. The Parties agree that the base rate increase includes the recovery of the
Gateway South and Gateway West transmission projects, as well as the
SETTLEMENT STIPULATION PAGE 4

Rock River I, Foot Creek II-IV, and Rock Creek I wind projects.
PacifiCorp will file an attestation that the transmission projects are in
service prior to the rate effective date.
b. The Parties reserve the right to review and provide recommendations to
the Commission in the Company's next general rate case on the recovery
of capital costs associated with the transmission level line extension for
Project Specialized (Oregon).
c. Suspended/Cancelled Projects: Parties agree to reduce the Idaho revenue
requirement by$700 thousand associated with suspended/cancelled
projects.
12. Non-Specific Adjustment: The Stipulating Parties agree to a $7.3 million
reduction to the Company's revenue requirement as resolution of all other revenue
requirement items for which specific settlement was not reached.
13. Net Power Costs:
a. The Parties agree to the following base amounts for the Energy Cost
Adjustment Mechanism included in Attachment A to this Stipulation:
• NPC - $2,228,403,177 or $36.66/MWh total-company, $128,240,000
or$36.91 Idaho-allocated. As shown in Attachment A, Parties agree to
three adjustments to NPC as reflected in the Company's initial filing.
First, an adjustment is made for emergency purchases. Second, an
adjustment is made to remove the Washington Climate Commitment
Act allowance costs consistent with the Commission's decision in
SETTLEMENT STIPULATION PAGE 5

Case No. PAC-E-24-05.1 Finally,NPC has been updated for the
September 2024 Official Forward Price Curve.
• Base Production Tax Credits - are equal to the amount filed in the
application at ($4.31)/MWh.
• Base Load Change Adjustment Revenue ("LCAR") - $6.29/MWh
b. The ECAM rates on Schedule 94 for recovery of the 2023 deferred costs
(Case No. PAC-E-24-05), will be reduced by 50 percent, effective January
1, 2025 (or rate effective date of this proceeding)with the remaining
balance as of June 1, 2025, to be recovered over two years with the costs
deferred in 2024.
c. The costs approved for recovery in the 2025 ECAM filing (for costs
deferred in 2024 and including the remaining balance from the 2024
ECAM filing)will be recovered over two years,beginning June 1, 2025.
d. The ECAM sharing band will remain at 90 percent customer/10 percent
company. The Parties agree to host workshops to evaluate the sharing
band in the ECAM and explore alternative risk sharing/incentive
mechanisms prior to the Company's next general rate case.
e. Beginning in 2025, the ECAM will include a true-up for Open Access
Transmission Tariff("OATT") wheeling revenues. The amount of
wheeling revenues in base rates is $188,219,298 total company,
'In the Matter of Rocky Mountain Power's Application for Approval of$62.4 Million ECAM Deferral, Case
No.PAC-E-24-05,Order No. 36207(May 31,2024);Order No 36367 on reconsideration(Oct. 18,2024).The
Company filed a notice of appeal on November 27,2024.
SETTLEMENT STIPULATION PAGE 6

$10,331,275 ($2.97/MWh) Idaho allocated. The wheeling revenue true-up
will be subject to the sharing band.
14. Catastrophic Fire Fund: The Company withdraws its proposal for a
Catastrophic Fire Fund but reserves the right to propose the fund in a future proceeding.
15. Excess Liability Insurance Premium Costs and the ICA: With respect to
Excess Liability Insurance Premium costs, the Parties agree to the following:
a. Excess liability insurance premium costs are set at $9,806,312 (Idaho
allocated).
b. Excess liability insurance premium costs above or below the amount in
base rates will be tracked separately in a deferral and prudently incurred
insurance costs above the amount in base rates will be amortized in the
Company's next general rate case.
c. The deferral will be reevaluated when the Company files its next rate case
in conjunction with any potential insurance mechanism.
d. Excess liability insurance premium costs of$9,806,312 and amortization
of$2,605,627 of annual deferred premium amortization($12,411,639 in
total) will be recovered through the ICA but the surcharge will not be a
line item on customer bills.
e. Beginning January 1, 2025, the ICA clause revenues will be spread in the
manner proposed in the Company's initial filing,based on a percentage of
overall revenues.
SETTLEMENT STIPULATION PAGE 7

16. Voluntary Renewable Energy Credit Option Tariff. The Parties agree to the
implementation of the Voluntary Renewable Energy Credit Option Tariff
subject to the following:
a. Future changes to the Renewable Energy Credit Option Program
Percentage, as defined in the Direct Testimony of Craig M. Eller, to be
approved by the Commission.
b. The Company will include its annual generation from hydro,wind, solar,
geothermal,biogas, and biomass as a percentage of total system
generation in its annual RRA filing.
c. REC revenues being held for return to non-participants will be held in a
deferral account earning the Commission approved customer deposit rate.
17. Rate Spread and Rate Design:
a. Parties agree that rate spread will be established using the Company's
proposed class cost of service study, subject to a cap of 110 percent of the
overall average base rate increase with a floor of zero percent price change
for all classes. The cap and floor percentage allocations will be applied to
the base rate increase prior to the application of the ICA and ECAM rate
changes identified above. The rate spread is set forth in more detail in
Attachment B to this Stipulation.
b. Parties agree that the Schedule 1 and Schedule 36 Customer Service
Charges will continue to increase according to the timing specified in the
Residential Rate Modernization Plan(Case No. PAC-E-22-15) with
SETTLEMENT STIPULATION PAGE 8

commensurate decreases in Energy Charges on June 1 each year of the
plan.
c. Parties agree that Schedule 1 Energy Charges will maintain the present 17
percent differential in tiers in both seasons.
d. Parties agree that the Company's proposed rate design will be used for rate
schedules other than Schedule 1 and Schedule 36.
e. The Parties agree that the Company's proposal to update time of use
periods and replace demand charges with time-varying seasonal energy
charges will apply to Schedules 35 and 35A.
f. The Parties agree to the elimination of Schedule 24.
g. The Parties agree that a 30,000 kW load limit will apply for Schedules 6,
6A, 23, and 23A.
18. Tariff Changes: The Parties agree that the Company's proposed tariff rule
changes as described in the Direct Testimony of Robert M. Meredith be approved. More
specifically the parties agree to the following changes and they should be approved:
a. The additional language,as shown on page 74 of Exhibit No. 58 attached to
the Direct Testimony of Robert M.Meredith,to the Rule 3 -Electric Service
Agreements tariff to clarify that Customers assume contract minimum bills
as a condition of service when assuming an existing point of delivery.
b. The revisions, as shown on pages 75 through 77 of Exhibit No. 58 attached
to the Direct Testimony of Robert M. Meredith, to the Rule 12 - Line
Extension tariff to change the Company's definition of extension Limits,
and require that customers requiring more than 1,000 kilovolt-amperes
SETTLEMENT STIPULATION PAGE 9

('WA") must pay their line extension advance prior to the start of
construction.
19. Additional Settlement Terms:
a. Rock Creek II is a 400 MW wind project selected as a build-transfer
agreement in the 2020 All-Source Request for Proposals and is in
construction by Invenergy with an expected in-service date in September
2025. In lieu of filing a general rate case in 2025 to incorporate the
resource in rates, Parties agree that PacifiCorp will be allowed to defer the
depreciation expense and return on Rock Creek II wind facility in a
regulatory asset account, with recovery and amortization to be determined
in the Company's next general rate case filing. During the deferral period
NPC and production tax credit benefits will flow through the ECAM but
will be tracked and subject to offset any disallowances on recovery of the
Rock Creek II deferral. Calculation of the NPC benefits can be addressed
at the time PacifiCorp seeks recovery of the deferral.
b. The Parties agree that Western Resource Adequacy Costs/Committee of
State Regulatory costs will be deferred for later recovery once benefits are
realized.
c. The Parties agree that Intervenor funding balance will be amortized over
four years at$10,000 per year.
d. The Company and interested parties will hold workshops on the
Company's risk management/hedging practices prior to the Company's
next general rate case.
SETTLEMENT STIPULATION PAGE 10

e. The Company will hold a workshop with Staff and other interested parties
to evaluate weather normalization methods of consumption before the next
general rate case.
f. The Company will perform a study,prior to filing its next general rate
case, on the costs and revenues associated with transmission level voltage
line extensions serving very large individual customers who signed
agreements with the Company (in 2020 or later) for a load request of 25
megawatts or greater. This should include both retail and wholesale
customers. The study should review FERC rules, state tariffs and
Company policies that govern how costs and revenues are situs assigned
or system allocated; analyze how those rules were applied to existing
projects; and analyze how costs and revenues might shift under different
allocation principles.
g. PIIC and IIPA will be allowed to have representation in the Wildfire
Insurance Working Group subject to executing the Wildfire Insurance
Working Group nondisclosure agreement.
h. The rate effective date of the overall rate increase is January 1, 2025.
i. The Company will not file a general rate case with new rates effective
before January 1, 2027.
GENERAL PROVISIONS
20. The Parties agree that this Stipulation represents a compromise among
competing interests and a resolution of the contested issues in this proceeding.Any adjustment
to PacifiCorp's Initial Filing on May 31, 2024 not incorporated into this Stipulation directly or
SETTLEMENT STIPULATION PAGE 11

by reference would be resolved without an adjustment or recommendation for the purposes of
this proceeding. Other than the above-referenced positions and any testimony filed in support
of the approval of this Stipulation, and except to the extent necessary for a Party to explain
before the Commission its own statements and positions with respect to the Stipulation, all
negotiations relating to this Stipulation shall not be admissible as evidence in this or any other
proceeding regarding this subject matter.
21. This Stipulation is not enforceable by any Party unless and until adopted by the
Commission in a final order. Each signatory to this Stipulation acknowledges that they are
signing this Stipulation in good faith and that they intend to abide by the terms of this
Stipulation unless and until the Stipulation is rejected or adopted only in part by the
Commission. The Parties agree that the Commission has exclusive jurisdiction to enforce or
modify the Stipulation.
22. The Parties submit this Stipulation to the Commission and recommend approval
of the Stipulation in its entirety pursuant to Rule 274 of the Commission's Rules of Procedure,
IDAPA 31.01.01.274.The Parties shall support this Stipulation before the Commission,and no
Party shall appeal any portion of this Stipulation or any subsequent Order approving the same.
If this Stipulation is challenged by any person not a party to the Stipulation,the Parties reserve
the right to cross-examine witnesses and put on such case as they deem appropriate to respond
fully to the issues presented, including the right to raise issues related to the challenge that are
incorporated in the settlement embodied in this Stipulation. Notwithstanding this reservation
of rights, the Parties agree that they will continue to support the Commission's adoption of the
terms of this Stipulation.
SETTLEMENT STIPULATION PAGE 12

23. In the event the Commission rejects any part or all of this Stipulation or imposes
any additional material conditions on approval of this Stipulation,each Party reserves the right,
upon written notice to the Commission and the other Parties,within 15 days of the date of such
action by the Commission, to withdraw from this Stipulation. In such case, no Party shall be
bound or prejudiced by the terms of this Stipulation, and each Party shall be entitled to seek
reconsideration of the Commission's order, file testimony as it chooses, cross-examine
witnesses, or otherwise present its case in a manner consistent with the Commission's Rules.
24. The Parties agree that this Stipulation is in the public interest and that all of its
terms and conditions are fair,just, and reasonable.
25. No Party shall be bound, benefited, or prejudiced by any position asserted in
the negotiation of this Stipulation, except to the extent expressly stated herein, nor shall this
Stipulation be construed as a waiver of the rights of any Party unless such rights are expressly
waived herein. This settlement and execution of this Stipulation shall not be deemed to
constitute an acknowledgement by any Party of the validity or invalidity of any particular
method, theory, or principle of regulation or cost recovery. No Party shall be deemed to have
agreed that any method,theory,or principle of regulation or cost recovery employed in arriving
at this Stipulation is appropriate for resolving any issues in any other proceeding in the future.
No findings of fact or conclusions of law other than those stated herein shall be deemed to be
implicit in this Stipulation.
26. The obligations of the Parties under this Stipulation are subject to the
Commission's approval of this Stipulation in accordance with its terms and conditions and, if
judicial review is sought, upon such approval being upheld on appeal by a court of competent
jurisdiction.
SETTLEMENT STIPULATION PAGE 13

27. This Stipulation may be executed in counterparts and each signed counterpart
shall constitute an original document. The Stipulating Parties further agree that any
electronically-generated signature of a Stipulating Party is valid and binding to the same extent
as an original signature.
28. This Stipulation may not be modified or amended except by written agreement
among all Stipulating Parties who have executed it.
BASED ON THE FOREGOING, the Parties request that the Commission issue an order
approving this Stipulation and adopting the terms and conditions of this Stipulation.
PACIFICORP D/B/A ROCKY MOUNTAIN STAFF FOR THE IDAHO PUBLIC
POWER UTILITIES COMMISSION
Joe Steward Adam Triplett
Senior Vice President, Regulation Deputy Attorney General
Rocky Mountain Power
Dated: , 2024
Dated: December 6, 2024
IDAHO IRRIGATION PUMPERS P4 PRODUCTION, L.L.C, an affiliate of
ASSOCIATION, INC. BAYER CORPORATION
Eric L. Olsen Thomas J. Budge
Echo Hawk& Olsen, PLLC Racine Olson, PLLP
Dated: , 2024 Dated: , 2024
PACIFICORP IDAHO INDUSTRIAL
CUSTOMERS
SETTLEMENT STIPULATION PAGE 14

27. This Stipulation may be executed in counterparts and each signed counterpart
shall constitute an original document. The Stipulating Parties further agree that any
electronically-generated signature of a Stipulating Party is valid and binding to the same extent
as an original signature.
28. This Stipulation may not be modified or amended except by written agreement
among all Stipulating Parties who have executed it.
BASED ON THE FOREGOING, the Parties request that the Commission issue an order
approving this Stipulation and adopting the terms and conditions of this Stipulation.
PACIFICORP D/B/A ROCKY MOUNTAIN STAFF FOR THE IDAHO PUBLIC
POWER UTILITIES COMMISSION
rx
Joelle Steward Adam Triplett
Senior Vice President, Regulation Deputy Attorney General
Rocky Mountain Power
Dated: DE c 2024
Dated: 12024
IDAHO IRRIGATION PUMPERS P4 PRODUCTION, L.L.C, an affiliate of
ASSOCIATION, INC. BAYER CORPORATION
Eric L. Olsen Thomas J. Budge
Echo Hawk & Olsen, PLLC Racine Olson, PLLP
Dated: , 2024 Dated: , 2024
PACIFICORP IDAHO INDUSTRIAL
CUSTOMERS
SETTLEMENT STIPULATION PAGE 14

27. This Stipulation may be executed in counterparts and each signed counterpart
shall constitute an original document. The Stipulating Parties further agree that any
electronically-generated signature of a Stipulating Party is valid and binding to the same extent
as an original signature.
28. This Stipulation may not be modified or amended except by written agreement
among all Stipulating Parties who have executed it.
BASED ON THE FOREGOING, the Parties request that the Commission issue an order
approving this Stipulation and adopting the terms and conditions of this Stipulation.
PACIFICORP D/B/A ROCKY MOUNTAIN STAFF FOR THE IDAHO PUBLIC
POWER UTILITIES COMMISSION
Joelle Steward Adam Triplett
Senior Vice President,Regulation Deputy Attorney General
Rocky Mountain Power
Dated: , 2024
Dated: 52024
IDAHO IRRIGATION PUMPERS P4 PRODUCTION,L.L.C, an affiliate of
AS ION, INC. BAYER CORPORATION
ric L. Olsen Thomas J. Budge
Echo Hawk& Olsen,PLLC Racine Olson,PLLP
Dated: 0�%(en � , 2024 Dated: , 2024
SETTLEMENT STIPULATION PAGE 14

27. This Stipulation may be executed in counterparts and each signed counterpart
shall constitute an original document. The Stipulating Parties further agree that any
electronically-generated signature of a Stipulating Party is valid and binding to the same extent
as an original signature.
28. This Stipulation may not be modified or amended except by written agreement
among all Stipulating Parties who have executed it.
BASED ON THE FOREGOING, the Parties request that the Commission issue an order
approving this Stipulation and adopting the terms and conditions of this Stipulation.
PACIFICORP D/B/A ROCKY MOUNTAIN STAFF FOR THE IDAHO PUBLIC
POWER UTILITIES COMMISSION
Joelle Steward Adam Triplett
Senior Vice President, Regulation Deputy Attorney General
Rocky Mountain Power
Dated: 32024
Dated: , 2024
IDAHO IRRIGATION PUMPERS P4 PRODUCTION, L.L.C, an affiliate of
ASSOCIATION, INC. BAYER CORPORATION
Eric L. Olsen Thomas J. Budge
Echo Hawk& Olsen, PLLC Racine Olson, PLLP
Dated: , 2024 Dated: December 5, 2024
PACIFICORP IDAHO INDUSTRIAL
CUSTOMERS
SETTLEMENT STIPULATION PAGE 14

4 LAJ - --
Ronald L. Williams
Hawley Troxell Ennis & Hawley LLP
Dated: Q e r f vAVpv S 12024
SETTLEMENT STIPULATION PAGE 15

ATTACHMENT A

Attachment A
Page 1 of 2
PAC-E-24-04
Settlement Revenue Requirement
Amount($
Description of Adjustments Millions)
GRC Overall Increase-Direct Filing $ 92.40
Change to Rate of Return-7.25% $ (6.90)
Remove Catastrophic Fire Fund $ (11.10)
Net Power Costs $ (8.46)
Remove Suspended/Cancelled Projects $ (0.70)
Unspecified Adjustment $ (7.30)
Total Adjustments $ (34.46)
Total Revenue Requirement Change after
Adjustments $ 57.94
Reduction to ECAM Recovery(estimated) $ (32.50)
Net Rate Change Jan 1,2025(estimated) $ 25.44

Attachment A
Page 2 of 2
PAC-E-24-04
Settlement NPC Adjustments
Total Company Idaho Allocated
NPC Dollars($) Load (MWh) Rate($/MWh) NPC Dollars($) Load(MWh) Rate($/MWh) Allocation Factor
Initial Filing $2,382,000,000 60,788,384 $39.19 $136,700,000 3,474,835 $39.34 5.74%
Remove WA CCA's (29,786,586) (1,757,409) 5.90%
Update Forward Price Curve (122,723,529) (6,643,761) 5.41%
Adjust Emergency Purchases (1,086,708) (58,830) 5.41%
Total Settlement Adjustment (153,596,823) - ($2.53) ($8,460,000) - ($2.43)
Stipulation Adjusted NPC $2,228,403,177 60,788,384 $36.66 $128,240,000 3,474,835 $36.91 5.75%

ATTACHMENT B

Attachment B
Page 1 of 12
TABLE A
ROCKY MOUNTAIN POWER
ESTIMATED IMPACT OF PROPOSED REVENUES ON PRESENT REVENUES
FROM ELECTRIC SALES TO ULTIMATE CONSUMERS
DISTRIBUTED BY RATE SCHEDULES IN IDAHO
HISTORICAL 12 MONTHS ENDED DECEMBER 2023
Present Proposed
Line Average Base ECAM' Net Base ECAMZ ICA Net Net Change Base Change
No. Description Sch. Customers MWH ($000) ($000) ($000) ($000) ($000) ($000) ($000) ($000) (%) ($000) (%)
(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13) (14) (15)
(11)-(7) (12)/(7) (8)+(10)-(7) (14)/(7)
Residential Sales
1 Residential Service 1 61,756 619,659 $70,766 $11,637 $82,403 $79,827 $5,718 $3,005 $88,550 $6,147 7.5% $12,066 14.6%
2 Residential Optional TOD 36 10,176 172,088 $17,121 $3,232 $20,353 $19,704 $1,588 $748 $22,040 $1,687 8.3% $3,331 16.4%
3 AGA Revenue $1 $1 $1 $1 $0 $0
4 Total Residential 71,933 791,748 $87,888 $14,869 $102,757 $99,532 $7,306 $3,753 $110,591 $7,834 7.6% $15,397 15.0%
5 Commercial&Industrial
6 General Service-Large Power 6 1,120 305,548 $24,441 $5,730 $30,170 $28,816 $2,815 $1,105 $32,736 $2,566 8.5% $5,480 18.2%
7 General Svc.-Lg.Power(R&F) 6A 186 22,162 $1,905 $416 $2,321 $2,242 $204 $86 $2,532 $211 9.1% $423 18.2%
8 Subtotal-Schedule 6 1,306 327,711 $26,346 $6,146 $32,492 $31,058 $3,020 $1,191 $35,268 $2,777 8.5% $5,903 18.2%
9 General Service-High Voltage 9 17 221,839 $13,181 $3,953 $17,134 $15,539 $1,942 $596 $18,077 $942 5.5% $2,953 17.2%
10 Irrigation 10 5,726 551,496 $50,093 $10,357 $60,450 $59,052 $5,089 $2,264 $66,405 $5,955 9.9% $11,223 18.6%
11 General Service 23 8,666 217,574 $20,470 $4,086 $24,556 $23,810 $2,007 $908 $26,726 $2,170 8.8% $4,248 17.3%
12 General Service(R&F) 23A 2,565 42,247 $4,127 $793 $4,920 $4,797 $390 $183 $5,370 $450 9.2% $854 17.4%
13 Subtotal-Schedule 2311,230 259,822 24,597 4,879 29,476 28,608 2,397 1,091 32,096 2,620 8.9% 5,102 17.3%
14 General Service Optional TOD 35 3 323 $28 $6 $34 $33 $3 $1 $37 $3 9.4% $6 18.4%
15 General Service Optional TOD(R&F) 35A 1 56 $8 $1 $9 $9 $1 $0 $10 $1 13.5% $2 19.6%
16 Subtotal-Schedule 35 4 379 36 7 43 42 3 2 47 4 10.2% 8 18.7%
17 Special Contract 1 400 1 1,314,200 $77,380 $23,629 $101,009 $91,220 $11,610 $3,498 $106,327 $5,318 5.3% $17,337 17.2%
18 AGA Revenue $520 $520 $520 $520 $0 $0
19 Total Commercial&Industrial 18,284 2,675,446 $192,153 $48,971 $241,124 $226,038 $24,062 $8,641 $258,741 $17,617 7.3% $42,527 17.6%
20 Public Street Liuhtinu
21 Security Area Lighting 7 174 230 $46 $4 $50 $46 $2 $2 $49 ($1) -1.2% $2 3.2%
22 Security Area Lighting(R&F) 7A 119 93 $22 $2 $24 $22 $1 $1 $24 ($0) -0.4% $1 3.3%
23 Street Lighting-Company 11 61 182 $81 $3 $85 $81 $2 $3 $86 $1 1.4% $3 3.4%
24 Street Lighting-Customer 12 266 2,360 $356 $44 $401 $356 $22 $13 $391 ($10) -2.5% $13 3.2%
25 AGA Revenue $0 $0 $0 $0 $0 $0
26 Total Public Street Lighting 620 2,866 $506 $54 $559 $506 $26 $18 $550 ($9) -1.7% $18 3.2%
27 Total Sales to Ultimate Customers 90,837 3,470,059 $280,546 $63,894 $344,440 $326,076 $31,394 $12,412 $369,882 $25,442 7.4% $57,942 16.8%
Note:
1-Deferred Energy Cost Adjustment Mechanism revenue set under rates that the Company had requested to be effective June 1,2024. See the Company's Application in Docket No.PAC-E-24-05.
2-Reduced by$32.5m from the present level according to the stipulation.

Attachment B
Page 2 of 12
RATE SPREAD AND CALCULATION OF ADJUSTMENT SCHEDULE PRICES
ROCKY MOUNTAIN POWER
FROM ELECTRIC SALES TO ULTIMATE CONSUMERS
DISTRIBUTED BY RATE SCHEDULES IN IDAHO
HISTORICAL 12 MONTHS ENDED DECEMBER 2023
Proposed Proposed
Line Average Present Base Revenue-Total COS Base Revenue ICA
Rate
No. Description Sch. Customers MWH ($000) ($000) Change (%) ($000) Change (%) ($000) (0/kWh)
(1) (2) (3) (4) (5) (6) (7) (8) (9) (10) (11) (12) (13)
(6)-(5) (7)/(5) (9)-(5) (10)/(5) (12)/(4)
Residential Sales
1 Residential Service 1 61,756 619,659 $70,766 $84,481 $13,715 19.4% $79,827 $9,061 12.8% $3,005 0.4850
2 Residential Optional TOD 36 10,176 172,088 $17,121 $21,031 $3,910 22.8% $19,704 $2,583 15.1% $748 0.4347
3 AGA Revenue $1 $1 $0 $1 $0
4 Total Residential 71,933 791,748 $87,888 $105,512 $17,624 20.05% $99,532 $11,644 13.25% $3,753
5 Commercial&Industrial
6 General Service-Large Power 6 1,120 305,548 $24,441 $31,057 $6,616 27.1% $28,812 $4,371 17.9% $1,105 0.3634
7 General Svc.-Lg.Power(R&F) 6A 186 22,162 $1,905 $2,421 $516 27.1% $2,246 $341 17.9% $86 0.3634
8 Subtotal-Schedule6 1,306 327,711 $26,346 $33,478 $7,132 27.1% $31,058 $4,712 17.9% $1,191
9 General Service-High Voltage 9 17 221,839 $13,181 $16,749 $3,568 27.1% $15,539 $2,357 17.9% $596 0.2686
10 Irrigation 10 5,726 551,496 $50,093 $63,653 $13,560 27.1% $59,052 $8,959 17.9% $2,264 0.4106
11 General Service 23 8,666 217,574 $20,470 $25,523 $5,052 24.7% $23,808 $3,338 16.3% $908 0.4199
12 General Service(R&F) 23A 2,565 42,247 $4,127 $5,145 $1,018 24.7% $4,800 $673 16.3% $183 0.4199
13 Subtotal-Schedule 2311,230 259,822 24,597 30,668 6,071 24.7% 28,608 4,011 16.3% 1,091
14 General Service Optional TOD 35 3 323 $28 $36 $8 27.1% $33 $5 17.9% $1.27 0.4264
15 General Service Optional TOD(R&F) 35A 1 56 $8 $10 $2 27.1% $9 $1 17.9% $0.34 0.4264
16 Subtotal-Schedule 35 4 379 36 45 10 27.1% 42 6 17.9% 2
17 Special Contract 1 400 1 1,314,200 $77,380 $98,327 $20,947 27.1% $91,220 $13,840 17.9% $3,498 0.2661
18 AGA Revenue $520 $520 $0 $520 $0
19 Total Commercial&Industrial 18,284 2,675,446 $192,153 $243,440 $51,287 26.7% $226,038 $33,886 17.6% $8,641
20 Public Street Lightinp
21 Security Area Lighting 7 174 230 $46 $46 $0 0.0% $46 $0 0.0% $1.62 0.7459
22 Security Area Lighting(R&F) 7A 119 93 $22 $22 $0 0.0% $22 $0 0.0% $0.79 0.7459
23 Street Lighting-Company 11 61 182 $81 $81 $0 0.0% $81 $0 0.0% $2.90 1.5920
24 Street Lighting-Customer 12 266 2,360 $356 $356 $0 0.0% $356 $0 0.0% $13 0.5371
25 AGA Revenue $0 $0 $0 $0 $0
26 Total Public Street Lighting 620 2,866 $506 $506 $0 0.0% $506 $0 0.0% $18
27 Total Sales to Ultimate Customers 90,837 3,470,059 $280,546 $349,458 $68,912 24.6% $326,076 $45,530 16.2% $12,412
Sch COS Spread% Adj Spread% $12,412
Revenue Requirement 1 17.85% 19.38% 0 12.80% 3.56%
Base $45,530 36 21.31% 22.84% 0 15.09% $0
ICA $12,412 6/35 27.77% 27.07% 0 17.89%
Total $57,942 9 31.25% 27.07% 0 17.89%
ECAM ($32,500) 10 29.75% 27.07% 0 17.89%
Net $25,442 7,11,12 -23.09% 0.00% 0 0.00%
ECAM Billing Ratio 50% 23 23.15% 24.68% 0 16.31%
400 26.76% 27.07% 0 17.89%
Total 24.61% 110.00%
$68,912 ($0) 1.53% $45,530 $0

Attachment B
Page 3of12
ROCKY MOUNTAIN POWER
STATE OF IDAHO
NORMALIZED BILLING DETERMINANTS AND PROPOSED STEP 1 PRICES
HISTORICAL 12 MONTHS ENDED DECEMBER 2023
Present Proposed
Present Revenue Proposed Revenue
Units Price Dollars Price Dollars
SCHEDULE NO.1-Residential Service
Customer Charge 741,077 $12.25 $9,078,198 $16.50 $12,227,777
Paperless Bill Credit 424,376 ($0.50) ($212,188) ($0.50) ($212,188)
Seasonal Service Charge 0 $147.00 $0 $198.00 $0
All kWh(Jun-Oct)
<=700 kWh 157,511,826 10.6118 0 $16,714,840 11.6263 0 $18,312,761
>700 kWh 65,439,582 12.4157 0 $8,124,782 13.6026 0 $8,901,503
All kWh(Nov-May)
<=1,000 kWh 282,201,244 8.8431 0 $24,955,338 9.6885 0 $27,341,042
>1,000 kWh 124,593,893 10.3464 0 $12,890,983 11.3355 0 $14,123,347
Subtotal 629,746,545 $71,551,953 $80,694,242
Temperature Adj.(Jun-Oct)<=700 kWh 2,575,536 10.6118 ¢ $273,311 11.6263 ¢ $299,439
Temperature Adj.(Jun-Oct)>700 kWh 1,070,028 12.4157 ¢ $132,851 13.6026 0 $145,552
Temperature Adj.(Nov-May)<=1,000 kWh (9,350,835) 8.8431 ¢ ($826,904) 9.6885 ¢ ($905,955)
Temperature Adj.(Nov-May)>1,000 kWh (4,128,461) 10.3464 ¢ ($427,147) 11.3355 ¢ ($467,982)
Subtotal (9,833,732) ($847,889) ($928,946)
Unbilled (253,605) $61,926 $61,926
Total 619,659,208 $70,765,990 $79,827,222
SCHEDULE NO.36-Residential Service Optional TOD
Customer Charge 122,117 $17.75 $2,167,570 $20.75 $2,533,920
Paperless Bill Credit 55,922 ($0.50) ($27,961) ($0.50) ($27,961)
Seasonal Service Charge 0 $213.00 $0 $249.00 $0
On-Peak kWh(May-Oct) 27,788,854 14.8656 ¢ $4,130,980 17.0675 ¢ $4,742,858
Off-Peak kWh(May-Oct) 34,822,117 5.2422 ¢ $1,825,445 6.0187 ¢ $2,095,829
On-Peak kWh(Nov-Apr) 48,357,719 12.7359 ¢ $6,158,791 14.6223 ¢ $7,071,027
Off-Peak kWh(Nov-Apr) 64,617,315 4.8196 ¢ $3,114,296 5.5335 ¢ $3,575,583
Subtotal 175,586,005 $17,369,121 $19,991,256
Temperature Adj.(May-Oct)-On-Peak 611,823 14.8656 ¢ $90,951 17.0675 ¢ $104,423
Temperature Adj.(May-Oct)-Off-Peak 766,674 5.2422 ¢ $40,191 6.0187 ¢ $46,144
Temperature Adj.(Nov-Apr)-On-Peak (2,056,905) 12.7359 ¢ ($261,965) 14.6223 ¢ ($300,767)
Temperature Adj.(Nov-Apr)-Off-Peak (2,748,510) 4.8196 ¢ ($132,467) 5.5335 ¢ ($152,088)
Subtotal (3,426,918) ($263,290) ($302,288)
On-Peak kWh(June-Oct) 21,039,678 0 $0 0 $0
Off-Peak kWh(June-Oct) 31,391,154 0 $0 0 $0
On-Peak kWh(Nov-May) 45,315,666 0 $0 0 $0
Off-Peak kWh(Nov-May) 77,839,507 0 $0 0 $0
Subtotal 175,586,005 $0 $0
Temperature Adj. (June-Oct)-On-Peak 412,787 0.0000 0 $0 0.0000 0 $0
Temperature Adj. (June-Oct)-Off-Peak 517,262 0.0000 0 $0 0.0000 0 $0
Temperature Adj. (Nov-May)-On-Peak (1,857,869) 0.0000 0 $0 0.0000 ¢ $0
Temperature Adj. (Nov-May)-Off-Peak (2,499,099) 0.0000 0 $0 0.0000 0 $0
Subtotal (3,426,918) $0 $0
Unbilled (70,710) $14,996 $14,996
Total 172,088,377 $17,120,927 $19,703,964

Attachment B
Page 4 of 12
ROCKY MOUNTAIN POWER
STATE OF IDAHO
NORMALIZED BILLING DETERMINANTS AND PROPOSED STEP 1 PRICES
HISTORICAL 12 MONTHS ENDED DECEMBER 2023
Present Proposed
Present Revenue Proposed Revenue
Units Price Dollars Price Dollars
Schedule 6-Total
Customer Charge(Secondary Voltage) 13,316 $38.00 $506,013 $45.00 $599,226
Customer Charge(Primary Voltage) 120 $114.00 $13,680 $134.00 $16,080
Total Customer Charges 13,436
Paperless Bill Credit 6,078 ($0.50) ($3,039) ($0.50) ($3,039)
All kW(Jun-Oct) 380,565 $13.62 $5,183,291 $16.00 $6,089,035
All kW(Nov-May) 489,804 $12.27 $6,009,890 $14.41 $7,058,070
All kWh 315,182,697 4.2506 ¢ $13,397,307 4.9898 ¢ $15,726,873
Seasonal Service Charge(Secondary) 0 $456.00 $0 $540.00 $0
Seasonal Service Charge(Primary) 0 $1,368.00 $0 $1,608.00 $0
Voltage Discount 58,418 ($0.65) ($37,972) ($0.65) ($37,972)
Subtotal 315,182,697 $25,069,170 $29,448,273
Temperature Adj.(Jun-Oct) 525,665 4.2506 ¢ $22,344 4.9898 $26,229
Temperature Adj.(Nov-May) (1,032,401) 4.2506 ¢ ($43,884) 4.9898 ($51,514)
Unbilled (9,127,739) ($607,105) ($607,105)
Total 305,548,221 $24,440,525 $28,815,883
Schedule 6A-Total
Customer Charge(Secondary Voltage) 2,220 $38.00 $84,370 $45.00 $99,912
Customer Charge(Primary Voltage) 12 $114.00 $1,368 $134.00 $1,608
Total Customer Charges 2,232
Paperless Bill Credit 613 ($0.50) ($307) ($0.50) ($307)
All kW(Jun-Oct) 28,896 $13.62 $393,562 $16.00 $462,334
All kW(Nov-May) 40,217 $12.27 $493,464 $14.41 $579,528
All kWh 22,467,114 4.2506 ¢ $954,998 4.9898 ¢ $1,121,056
Seasonal Service Charge(Secondary) 0 $456.00 $0 $540.00 $0
Seasonal Service Charge(Primary) 0 $1,368.00 $0 $1,608.00 $0
Voltage Discount 0 ($0.65) $0 ($0.65) $0
Subtotal 22,467,114 $1,927,455 $2,264,131
Unbilled (304,809) ($21,985) ($21,985)
Total 22,162,305 $1,905,470 $2,242,146
Schedule 7-Total
Charges Per Lamp
Level 1(0-5,500 LED Equivalent Lumens) 1,800 $12.96 $23,324 $12.96 $23,324
Level 2(5,501-12,000 LED Equivalent Lumens) 899 $14.72 $13,229 $14.72 $13,229
Level 3(12,001 and Greater LED Equivalent Lumens) 544 $17.48 $9,514 $17.48 $9,514
Avg Customers 174
Paperless Bill Credit 0 ($0.50) $0 ($0.50) $0
All kWh 233,102
Subtotal 233,102 $46,067 $46,067
Unbilled (2,803) -$476 -$476
Total 230,299 $45,591 $45,591

Attachment B
Page 5 of 12
ROCKY MOUNTAIN POWER
STATE OF IDAHO
NORMALIZED BILLING DETERMINANTS AND PROPOSED STEP 1 PRICES
HISTORICAL 12 MONTHS ENDED DECEMBER 2023
Present Proposed
Present Revenue Proposed Revenue
Units Price Dollars Price Dollars
Schedule 7A-Total
Charges Per Lamp
Level 1(0-5,500 LED Equivalent Lumens) 1,573 $12.96 $20,392 $12.96 $20,392
Level 2(5,501-12,000 LED Equivalent Lumens) 126 $14.72 $1,855 $14.72 $1,855
Level 3(12,001 and Greater LED Equivalent Lumens) 0 $17.48 $0 $17.48 $0
Avg Customers 119
Paperless Bill Credit 0 ($0.50) $0 ($0.50) $0
All kWh 93,326
Subtotal 93,326 $22,247 $22,247
Unbilled (111) $0 $0
Total 93,215 $22,247 $22,247
Schedule 9-Total
Customer Charge 204 $372.00 $75,888 $433.00 $88,332
Paperless Bill Credit 108 ($0.50) ($54) ($0.50) ($54)
All kW(Jun-Oct) 189,879 $10.31 $1,957,656 $12.01 $2,280,451
All kW(Nov-May) 264,909 $9.29 $2,461,002 $10.82 $2,866,312
On-peak kWh(Jun-Oct) 31,059,102 5.1115 ¢ $1,587,582 5.9547 ¢ $1,849,480
Off-peak kWh(Jun-Oct) 67,811,869 3.9086 ¢ $2,650,505 4.5534 ¢ $3,087,749
On-peak kWh(Nov-May) 45,369,568 4.6365 ¢ $2,103,540 5.4013 ¢ $2,450,554
Off-peak kWh(Nov-May) 98,247,389 3.5213 ¢ $3,459,560 4.1031 ¢ $4,031,174
Base Subtotal 242,487,928 $14,295,679 $16,653,998
Temperature Adj On-peak(Jun-Oct) 2,825 5.1115 ¢ $144 5.9547 ¢ $168
Temperature Adj Off-peak(Jun-Oct) 5,777 3.9086 ¢ $226 4.5534 ¢ $263
Temperature Adj On-peak(Nov-May) (46,315) 4.6365 ¢ ($2,147) 5.4013 ¢ ($2,502)
Temperature Adj Off-peak(Nov-May) (95,499) 3.5213 ¢ ($3,363) 4.1031 ¢ ($3,918)
Unbilled (20,515,993) ($1,109,418) ($1,109,418)
Total 221,838,723 $13,181,121 $15,538,591
Schedule 10-IRG
Small Customer Charge(Season) 3,481 $14.00 $48,727 $17.00 $59,169
Large Customer Charge(Season) 15,116 $41.00 $619,753 $49.00 $740,680
Post-Season Customer Charge 13,998 $23.00 $321,954 $27.00 $377,946
Total Customer Charges 32,594
Paperless Bill Credit 9,683 ($0.50) ($4,842) -$0.50 ($4,842)
All kW(June 1-Sept 15) 1,413,980 $5.96 $8,427,321 $7.05 $9,968,559
First 25,000 kWh(June 1-Sept 15) 191,013,514 8.8388 ¢ $16,883,238 10.4572 ¢ $19,974,714
Next 225,000 kWh(June 1-Sept 15) 235,358,285 6.6054 ¢ $15,546,441 7.8150 ¢ $18,393,138
All Add'l kWh(June 1-Sept 15) 28,182,215 4.9435 ¢ $1,393,192 5.8487 ¢ $1,648,299
All kWh(Sept 16-May 31) 82,704,115 7.5110 ¢ $6,211,906 8.8802 ¢ $7,344,292
Meters(AVG Customer) 5,726
Subtotal 537,258,129 $49,447,690 $58,501,955
Temperature Adj:First 25,000 kWh(June 1-Sept 15) 3,602,392 8.8388 ¢ $318,407 10.4572 ¢ $376,710
Temperature Adj:Next 225,000 kWh(June 1-Sept 15) 4,438,706 6.6054 ¢ $293,196 7.8150 ¢ $346,883
Temperature Adj:All Add'l kWh(June 1-Sept 15) 531,498 4.9435 ¢ $26,275 5.8487 ¢ $31,086
Temperature Adj:All kWh(Sept 16-May 31) (15,477,649) 7.5110 ¢ ($1,162,526) 8.8802 ¢ ($1,374,446)
Temp Subtotal (6,905,052) ($524,648) ($619,767)
Unbilled 21,142,697 $1,169,462 $1,169,462
Total 551,495,774 $50,092,504 $59,051,650

Attachment B
Page 6 of 12
ROCKY MOUNTAIN POWER
STATE OF IDAHO
NORMALIZED BILLING DETERMINANTS AND PROPOSED STEP 1 PRICES
HISTORICAL 12 MONTHS ENDED DECEMBER 2023
Present Proposed
Present Revenue Proposed Revenue
Units Price Dollars Price Dollars
Schedule 11-PSH
Level 1(0-3,500 LED Equivalent Lumens) 79 $16.24 $1,285 $16.24 $1,285
Level 2(3,501-5,500 LED Equivalent Lumens) 4,276 $17.32 $74,052 $17.32 $74,052
Level 3(5,501-8,000 LED Equivalent Lumens) 149 $17.84 $2,662 $17.84 $2,662
Level 4(8,001-12,000 LED Equivalent Lumens) 0 $18.44 $0 $18.44 $0
Level 5(12,001-15,500 LED Equivalent Lumens) 145 $19.48 $2,817 $19.48 $2,817
Level 6(15,501 and Greater LED Equivalent Lumens) 39 $23.21 $916 $23.21 $916
Avg Customers 61
Paperless Bill Credit 0 ($0.50) $0 ($0.50) $0
All kWh 182,858
Subtotal 182,858 $81,732 $81,732
Unbilled (1,015) ($345) ($345)
Total 181,843 $81,387 $81,387
Schedule 12E-PSH
Charges per Lamp
LPS-18OW 4 74 $8.07 $594 $8.07 $594
NM-175W 5 0 $6.21 $0 $6.21 $0
NM-250W 6 0 $8.50 $0 $8.50 $0
NM-40OW 7 34 $13.36 $455 $13.36 $455
NM-1000W 8 0 $31.99 $0 $31.99 $0
NM-100W 9 0 $3.54 $0 $3.54 $0
HPS-70W 10 144 $2.50 $360 $2.50 $360
HPS-100W 11 1,619 $3.50 $5,668 $3.50 $5,668
HPS-150W 12 718 $5.21 $3,742 $5.21 $3,742
HPS-250W 13 345 $8.90 $3,070 $8.90 $3,070
HPS-40OW 14 804 $13.67 $10,994 $13.67 $10,994
SVSA Flood Light-1 50W 33 0 $14.20 $0 $14.20 $0
Non-Listed Luminaire-Energy Only 219,591 9.0681 ¢ $19,913 9.0682 $19,913
Avg Customers 64
Paperless Bill Credit 0 ($0.50) $0 -$0.50 $0
All kWh 491,684
Subtotal 491,684 $44,796 $44,796
Unbilled (2,730) ($203) ($203)
Total 488,955 $44,593 $44,593
Schedule 12F-PSH
Charges per Lamp
HPS-70W 1 6,443 $5.84 $37,625 $5.84 $37,625
HPS-10OW 2 24,907 $7.45 $185,554 $7.45 $185,554
HPS-150W 3 1,875 $8.93 $16,740 $8.93 $16,740
HPS-250W 4 3,105 $11.70 $36,334 $11.70 $36,334
HPS-40OW 5 910 $15.60 $14,200 $15.60 $14,200
Avg Customers 187
Paperless Bill Credit 0 ($0.50) $0 -$0.50 $0
All kWh 1,695,195
Subtotal 1,695,195 $290,453 $290,453
Unbilled (9,411) ($1,273) ($1,273)
Total 1,685,784 $289,180 $289,180

Attachment B
Page 7 of 12
ROCKY MOUNTAIN POWER
STATE OF IDAHO
NORMALIZED BILLING DETERMINANTS AND PROPOSED STEP 1 PRICES
HISTORICAL 12 MONTHS ENDED DECEMBER 2023
Present Proposed
Present Revenue Proposed Revenue
Units Price Dollars Price Dollars
Schedule 12P-PSH
Charges per Lamp
MV-250W 2 144 $14.55 $2,095 $14.55 $2,095
MV-40OW 3 240 $19.47 $4,673 $19.47 $4,673
HPS-70W 5 67 $5.22 $349 $5.22 $349
HPS-100W 6 491 $6.72 $3,302 $6.72 $3,302
HPS-250W 8 595 $10.75 $6,397 $10.75 $6,397
HPS-40OW 9 408 $14.48 $5,908 $14.48 $5,908
Avg Customers 15
Paperless Bill Credit 0 ($0.50) $0 -$0.50 $0
All kWh 186,744
Subtotal 186,744 $22,724 $22,724
Unbilled (1,037) ($101) ($101)
Total 185,708 $22,623 $22,623
Schedule 23-Total
Customer Charge Secondary 103,451 $18.00 $1,862,122 $21.00 $2,172,476
Customer Charge Primary 187 $48.00 $8,971 $56.00 $10,466
Total Customer Charges 103,638
Paperless Bill Credit 41,831 ($0.50) ($20,916) ($0.50) ($20,916)
All kWh(Jun-Oct) 85,909,044 9.5136 ¢ $8,173,028 11.0458 ¢ $9,489,323
All kWh(Nov-May) 135,303,579 7.9280 ¢ $10,726,849 9.1964 ¢ $12,443,089
Seasonal Service Charge(Secondary) 0 $216.00 $0 $252.00 $0
Seasonal Service Charge(Primary) 0 $576.00 $0 $672.00 $0
Voltage Discount 552,410 (0.4397) ¢ ($2,429) (0.4397) 0 ($2,429)
Base Subtotal 221,212,623 $20,747,625 $24,092,009
Temperature Adj.(Jun-Oct) 419,647 9.5136 ¢ $39,923 11.0458 ¢ $46,353
Temperature Adj.(Nov-May) (1,092,633) 7.9280 ¢ ($86,624) 9.1964 ¢ ($100,483)
Unbilled (3,120,528) ($250,474) ($250,474)
Base Total 217,419,109 20,450,450 23,787,405
SCHEDULE NO.23F-General Service-Commercial
Customer Charge 48 $18.00 $864 $21.00 $1,008
Sprinkler Timer,32 kWh/MO 36 $2.86 $103 $3.32 $120
School Flashing Light,$7/MO 48 $9.29 $446 $10.79 $518
CTV,60V,12 AMPS,394 kWh/MO 12 $35.10 $421 $40.75 $489
All kWh 6,360
Base Subtotal 6,360 $1,834 $2,135
Unbilled (42) ($10) ($10)
Base Total 6,318 $1,824 $2,125
Schedule 23S-Total
Customer Charge 300 $18.00 $5,401 $21.00 $6,301
Paperless Bill Credit 65 ($0.50) ($33) ($0.50) ($33)
All kWh(Jun-Oct) 52,609 9.5136 ¢ $5,005 11.0458 ¢ $5,811
All kWh(Nov-May) 97,512 7.9280 ¢ $7,731 9.1964 ¢ $8,968
Base Subtotal 150,121 $18,104 $21,047
Unbilled (1,299) ($134) ($134)
Base Total 148,822 $17,970 $20,913

Attachment B
Page 8 of 12
ROCKY MOUNTAIN POWER
STATE OF IDAHO
NORMALIZED BILLING DETERMINANTS AND PROPOSED STEP 1 PRICES
HISTORICAL 12 MONTHS ENDED DECEMBER 2023
Present Proposed
Present Revenue Proposed Revenue
Units Price Dollars Price Dollars
Schedule 23A-Total
Customer Charge Secondary 30,778 $18.00 $553,997 $21.00 $646,330
Customer Charge Primary 1 $48.00 $48 $56.00 $56
Total Customer Charges 30,779
Paperless Bill Credit 10,521 ($0.50) ($5,261) ($0.50) ($5,261)
All kWh(Jun-Oct) 14,297,881 9.5136 0 $1,360,241 11.0458 0 $1,579,312
All kWh(Nov-May) 28,332,858 7.9280 0 $2,246,225 9.1964 0 $2,605,609
Seasonal Service Charge(Secondary) 0 $216.00 $0 $252.00 $0
Seasonal Service Charge(Primary) 0 $576.00 $0 $672.00 $0
Voltage Discount 0 (0.4397) ¢ $0 (0.4397) 0 $0
Base Subtotal 42,630,739 $4,155,250 $4,826,046
Unbilled (383,317) ($28,654) ($28,654)
Base Total 42,247,422 $4,126,596 $4,797,392
SCHEDULE NO.31-Partial Requirements Service--Large General Service-1,000 kW and Over
Customer Charge per month
Secondary $38.00 $45.00
Primary $114.00 $134.00
Transmission $372.00 $433.00
Facilities Charge,per kW month
June through October
Secondary $8.14 $9.56
Primary $7.77 $9.13
Transmission $5.73 $6.68
November through May
Secondary $6.65 $7.81
Primary $6.28 $7.38
Transmission $4.32 $5.03
Back-up Power Charge,Regular,per kW day
June through October
Secondary $0.27 $0.32
Primary $0.26 $0.31
Transmission $0.19 $0.22
November through May
Secondary $0.23 $0.27
Primary $0.22 $0.26
Transmission $0.14 $0.16
Back-up Power Charge,Maintenance,per kW day
June through October
Secondary $0.14 $0.16
Primary $0.13 $0.16
Transmission $0.10 $0.11
November through May
Secondary $0.12 $0.14
Primary $0.11 $0.13
Transmission $0.07 $0.08

Attachment B
Page 9 of 12
ROCKY MOUNTAIN POWER
STATE OF IDAHO
NORMALIZED BILLING DETERMINANTS AND PROPOSED STEP 1 PRICES
HISTORICAL 12 MONTHS ENDED DECEMBER 2023
Present Proposed
Present Revenue Proposed Revenue
Units Price Dollars Price Dollars
Excess Power Charge,per kW month
June through October
Secondary $29.44 $34.58
Primary $28.10 $33.01
Transmission $20.62 $24.02
November through May
Secondary $24.21 $28.44
Primary $22.88 $26.88
Transmission $15.55 $18.12
Subtotal
Supplementary Power Charge,per kW month
June through October
Secondary $13.62 $16.00
Primary $12.97 $15.35
Transmission $10.31 $12.01
November through May
Secondary $12.27 $14.41
Primary $11.62 $13.76
Transmission $9.29 $10.82
Supplementary and Back-Up Energy Charge,per kWh
June through October
Secondary 4.2506 ¢ 4.9898 ¢
Primary 4.2506 ¢ 4.9898 ¢
Transmission-On-Peak 5.1115 ¢ 5.9547 ¢
Transmission-Off-Peak 3.9086 ¢ 4.5534 ¢
November through May
Secondary 4.2506 ¢ 4.9898 ¢
Primary 4.2506 ¢ 4.9898 ¢
Transmission-On-Peak 4.6365 ¢ 5.4013 ¢
Transmission-Off-Peak 3.5213 ¢ 4.1031 ¢
Subtotal
Total
Schedule 35-COM
Customer Charge Secondary 36 $69.00 $2,479 $81.00 $2,911
Customer Charge Primary 0 $170.00 $0 $200.00 $0
Total Customer Charges 36
Paperless Bill Credit 36 ($0.50) ($18) ($0.50) ($18)
All On-Peak kW 493 $16.95 $8,351 $19.96 $9,834
All kWh 325,205 5.3792 ¢ $17,493 6.3390 ¢ $20,615
Seasonal Service Charge(Secondary) 0 $828.00 $0 $972.00 $0
Seasonal Service Charge(Primary) 0 $2,040.00 $0 $2,400.00 $0
Voltage Discount 0 ($0.84) $0 ($0.84) $0
Base Subtotal 325,205 $28,305 $33,342
On peak kWh(Jun-Oct) 43,627 ¢ $0 12.7229 ¢ $5,551
Off-peak kWh(Jun-Oct) 215,726 ¢ $0 9.7288 ¢ $20,988
On peak kWh(Nov-May) 22,109 ¢ $0 11.5405 ¢ $2,551
Off-peak kWh(Nov-May) 43,743 ¢ $0 8.8247 ¢ $3,860
Unbillcd (2,171) ($165) ($165)
Base Total 323,034 $28,140 $33,177

Attachment B
Page 10 of 12
ROCKY MOUNTAIN POWER
STATE OF IDAHO
NORMALIZED BILLING DETERMINANTS AND PROPOSED STEP 1 PRICES
HISTORICAL 12 MONTHS ENDED DECEMBER 2023
Present Proposed
Present Revenue Proposed Revenue
Units Price Dollars Price Dollars
Schedule 35A-COM
Customer Charge Secondary 12 $69.00 $826 $81.00 $969
Customer Charge Primary 0 $170.00 $0 $200.00 $0
Total Customer Charges 12
Paperless Bill Credit 0 ($0.50) $0 ($0.50) $0
All On-Peak kW 224 $16.95 $3,802 $19.96 $4,477
All kWh 56,414 5.3792 ¢ $3,035 6.3390 ¢ $3,576
Seasonal Service Charge(Secondary) 0 $828.00 $0 $972.00 $0
Seasonal Service Charge(Primary) 0 $2,040.00 $0 $2,400.00 $0
Voltage Discount 0 ($0.84) $0 ($0.84) $0
Base Subtotal 56,414 $7,663 $9,022
On peak kWh(Jun-Oct) 3,665 ¢ $0 12.7229 ¢ $466
Off-peak kWh(Jun-Oct) 10,803 ¢ $0 9.7288 ¢ $1,051
On peak kWh(Nov-May) 12,270 ¢ $0 11.5405 ¢ $1,416
Off-peak kWh(Nov-May) 29,676 ¢ $0 8.8247 ¢ $2,619
Unbilled (377) ($41) ($41)
Base Total 56,037 $7,622 $8,981
SCHEDULE 400
Firm Energy and Power
Customer Charges 12 $1,556.00 $18,672 $1,834.00 $22,008
kW 290,096 $15.61 $4,528,399 $18.40 $5,337,766
kWh 43,374,000 3.3260 ¢ $1,442,637 3.9220 $1,701,113
Excess kVar 57,200 $0.96 $54,912 $0.96 $54,912
Unbilled
Total-Normalized 43,374,000 $6,044,620 $7,115,799
Interruptible Energy and Power
Customer Charges
kW 1,862,096 $15.61 $29,067,319 $18.40 $34,262,566
kWh 1,270,826,000 3.3260 ¢ $42,268,189 3.9220 $49,841,355
Unbilled
Total-Normalized 1,270,826,000 $71,335,508 $84,103,921
Total Schedule 400 1,314,200,000 $77,380,128 $91,219,720
IDAHO JURISDICTIONAL TOTALS:
Subtotal 3,504,192,788 $282,507,996 $328,265,195
Temperature Adj (21,478,636) ($1,709,208) ($1,936,405)
Unbilled (12,655,000) ($774,000) ($774,000)
AGA Revenue $521,159 $521,159
Total 3,470,059,152 $280,545,947 $326,075,949

Attachment B
Page 11 of 12
ROCKY MOUNTAIN POWER
STATE OF IDAHO
NORMALIZED BILLING DETERMINANTS AND PROPOSED PERIOD-BY-PERIOD PRICES FOR RESIDENTIAL CUSTOMERS
HISTORICAL 12 MONTHS ENDED DECEMBER 2023
Rate Case Period
Residential Rate Modernization Period Year 2 Year 3 Year 4 Year 5
1/1/2025-5/31/2025 6/l/2025-5/31/2026 6/1/2026-5/31/2027 6/l/2027
2023 Revenue Revenue Revenue Revenue
Units Price Dollars Price Dollars Price Dollars Price Dollars
SCHEDULE NO.1-Residential Service
Customer charge 741,077 $16.50 $12,227,777 $20.75 $15,377,356 $25.00 $19,526,935 $29.25 $21,676,514
Paperless Bill Credit 424,376 ($0.50) ($212,188) ($0.50) ($212,188) ($0.50) ($212,188) ($0.50) ($212,188)
Seasonal Service charge 0 $198.00 $0 $249.00 $0 $300.00 $0 $351.00 $0
All kWh(Jun-Oct)
-700 kWh 157,511,826 11.6263 0 $18,312,761 11.0858 0 $17,461,429 10.5453 0 $16,610,097 10.0048 0 $15,758,765
>700 kWh 65,439,582 13.6026 0 $8,901,503 12.9703 0 $8,487,685 12.3379 0 $8,073,868 11.7055 0 $7,660,051
All kWh(Nov-May)
-1,000 kWh 282,201,244 9.6885 0 $27,341,042 9.2381 0 $26,069,999 8.7877 0 $24,798,956 8.3373 0 $23,527,913
>1,000 kWh 124,593,893 11.3355 0 $14,123,347 10.8085 0 $13,466,774 10.2816 0 $12,810,201 9.7546 0 $12,153,629
Subtotal 629,746,545 $90,694,242 $80,651,055 $90,607,969 $80,564,684
Temperature Adj.(Jun-Oct)r-700 kWh 2,575,536 11.6263 0 $299,439 11.0858 0 $285,519 10.5453 0 $271,598 10.0048 0 $257,678
Temperature Adj.(Jun-Oct)>700 kWh 1,070,028 13.6026 0 $145,552 12.9703 0 $138,785 12.3379 0 $132,019 11.7055 0 $125,252
Temperature Adj.(Nov-May)r 1,000 kWh (9,350,835) 9.6885 0 ($905,955) 9.2381 0 ($863,838) 8.7877 0 ($821,722) 8.3373 0 ($779,605)
Temperature Adj.(Nov-May)>1,000 kWh (4,128,461) 11.3355 0 ($467,982) 10.8085 0 ($446,226) 10.2816 0 ($424,470) 9.7546 0 ($402,715)
Subtotal (9,833,732) ($928,946) ($885,760) ($842,575) ($799,390)
Unbilled (253,605) $61,926 $61,926 $61,926 $61,926
Total 619,659,208 $79,827,222 $79,827,221 $79,827,220 $79,827,220
Tier ratio 117% 117% ($1) 117% ($1) 117% $0
Tier diff 1.9764 1.8845 1.7926 1.7007
Season dill 1.2 1.2 1.2 1.2
Decimal 8
SCHEDULE NO.36-Residential Service Optional TOD
Customer Charge 122,117 $20.75 $2,533,920 $23.50 $2,869,740 $26.50 $3,236,090 $29.25 $3,571,911
Paperless Bill Credit 55,922 ($0.50) ($27,961) ($0.50) ($27,961) ($0.50) ($27,961) ($0.50) ($27,961)
Seasonal Service Charge 0 $249.00 $0 $282.00 $0 $318.00 $0 $351.00 $0
On-Peak kWh(May-Oct) 27,788,854 17.0675 0 S4,742,858
Off-Peak kWh(May-Oct) 34,822,117 6.0187 0 $2,095,829
On-Peak kWh(Nov-Apr) 48,357,719 14.6223 0 $7,071,027
Off-Peak kWh(Nov-Apr) 64,617,315 5.5335 0 $3,575,583
Subtotal 175,586,005 $19,991,256
Temperature Adj.(May-Oct)-On-Peak 611,823 17.0675 0 $104,423
Temperature Adj.(May-Oct)-Off-Peak 766,674 6.0187 0 $46,144
Temperature Adj.(Nov-Apr)-On-Peak (2,056,905) 14.6223 0 ($300,767)
Temperature Adj.(Nov-Apr)-Off-Peak (2,748,510) 5.5335 0 ($152,088)
Subtotal (3,426,918) ($302,288)
On-Peak kn(June-Oct) 21,039,678 18.5344 0 $3,899,578 18.1314 0 $3,814,781 17.7619 0 $3,737,048
Off-Peak kWh(June-Oct) 31,391,154 5.9010 0 $1,852,406 5.7727 ¢ $1,812,124 5.6551 6 $1,775,200
On-Peak kn(Nov-May) 45,315,666 15.8791 0 $7,195,718 15.5338 0 $7,039,245 15.2173 0 $6,895,809
Off-Peak kn(Nov-May) 77,839,507 5.4253 0 $4,223,051 5.3074 0 $4,131,218 5.1992 6 $4,047,039
Subtotal 175,586,005 $0 $17,170,753 $16,797,368 $16,455,096
Temperature Adj.(June-Oct)-On-Peak 412,787 18.5344 6 $76,508 18.1314 ¢ $74,844 17.7619 6 $73,319
Temperature Adj.(June-Oct)-Off-Peak 517,262 5.9010 0 $30,524 5.7727 0 $29,860 5.6551 0 $29,252
Temperature Adj.(Nov-May)-On-Peak (1,857,869) 15.8791 6 ($295,013) 15.5338 ¢ ($288,598) 15.2173 6 ($282,717)
Temperature Adj.(Nov-May)-Off-Peak (2,499,099) 5.4253 6 ($135,584) 5.3074 ¢ ($132,636) 5.1992 6 ($129,933)
Subtotal (3,426,918) $0 ($323,565) ($316,530) ($310,079)
Unbilled (70,710) $14,996 $14,996 $14,996 $14,996
Total-Present TOU 172,088,377 $19,703,964 $19,703,963 $19,703,963 $19,703,961
Total-Proposed TOU 172,088,377 $19,703,963 $19,703,963 $19,703,963
On-Off Peak Ratio-Preset TOU-Summer Summer 284% 1.17 284% 1.17 284% 1.17 284% 1.17
On-Off Peak Ratio-Preset TOU-Winter Winter 264% 264% ($1) 264% $0 264% (S2)
On-Off Peak Ratio-Proposed TOU-Summer Summer 314% $0 314% $0 314% S2
On-Off Peak Ratio-Proposed TOU-Winter Winter 293% 293% 293%
Decimal 8

Attachment B
Page 12 of 12
Rocky Mountain Power - State of Idaho
Schedule 94 Settlement Rate
Present Rate 0/kWh Proposed Rate 0/kWh
Voltage S P T S P T
Tariff Customer Rate 1.809 1.776 1.717 0.905 0.888 0.859
Schedule 400 Rate 1.733 0.867

CERTIFICATE OF SERVICE
I hereby certify that on this day, I caused to be served, via email, a true and correct copy
of Settlement Stipulation in Case No. PAC-E-24-04 to the following:
Service List
Commission Staff
Adam Triplett(C)
Deputy Attorney General
Idaho Public Utilities Commission
11331 W. Chinden Blvd., Bldg No. 8,
Suite 201-A
Boise, ID 83720-0074
adam.triplettkpuc.idaho.gov
Idaho Irrigation Pumpers Association, Inc
Eric L. Olsen(C) Lance Kaufman, Ph.D. (C)
Echo Hawk& Olsen PLLC 2623 NW Bluebell Place
505 Pershing Ave., Suite 100 Corvallis, OR 97330
PO Box 6119 lance cgae isg insi h
Pocatello, ID 83205
elo&echohawk.com
Idaho Conservation League
Matthew Nykiel Brad Heusinkveld
Idaho Conservation League Idaho Conservation League
710 N. 6tn Street 710 N. 6tn Street
Boise, ID 83702 Boise, ID 83702
matthew.nykielkgmail.com bheusinkveld(&idahoconservation.org
Bayer Corporation
Thomas J. Budge (C) Brian C. Collins (C)
Racine, Olson PLLP Greg Meyer(C)
201 E. Center Brubaker&Associates
Pocatello, ID 83204-1391 16690 Swingley Ridge Rd., #140
tj&racineolson.com Chesterfield, MO 63017
bcollinskconsultbai.com
gme er&consultbai.com
Kevin Higgins (C)
Neal Townsend(C)
Energy Strategies LLC
khi ggins&energystrat.com
ntownsend&energystrat.com
Page 1 of 2

PacifiCorp Idaho Industrial Customers
Ronald L. Williams (C) Bradley Mullins (C)
Brandon Helgeson(C) MW Analytics
Hawley Troxell Ennis &Hawley LLP Teitotie 2, Suite 208
PO Box 1617 Oulunsalo Finland, FI 90460
Boise, ID 83701 brmullins@mwanal . ics.com
rwilliams(aD,hawleytroxell.com
bhel eg [e-mail]
Val Steiner Kyle Williams
Itafos Conda LLC BYU Idaho
val.steiner(a-)itafos.com [e-mail]
PacifiCor , dba Rocky Mountain Power
Mark Alder Joe Dallas
Michael Snow PacifiCorp/dba Rocky Mountain Power
PacifiCorp/dba Rocky Mountain Power 825 NE Multnomah Street, Suite 2000
1407 West North Temple, Suite 330 Portland, OR 97232
Salt Lake City,UT 84116 [e-mail]
mark.alder@pacificoi p.com
[e-mail]
Data Request Response Center
PacifiCorp
[e-mail]
Dated this 6th day of December, 2024.
J f ,
&ti /
Carrie Meyer
Adviser, Regulatory Operations
Page 2 of 2