20230127APPLICATION.pdf

January 27, 2023
VIA ELECTRONIC FILING
Jan Noriyuki
Commission Secretary
Idaho Public Utilities Commission
11331 W Chinden Blvd.
Building 8 Suite 201A
Boise, ID 83714
Re: CASE NO. PAC-E-23-01
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER
FOR A CERTIFICATE OF CONVENIENCE AND NECESSITY
AUTHORIZING CONSTRUCTION OF THE BOARDMAN-TO-
HEMMINGWAY 500-KV TRANSMISSION LINE PROJECT
Dear Ms. Noriyuki:
Rocky Mountain Power hereby submits for filing with the Idaho Public Utilities Commission
its application, direct testimony, and exhibits in the above-referenced matter.
Formal correspondence and requests for additional information regarding this matter
should be addressed to:
By e-mail (preferred): [e-mail]
By regular mail: Data Request Response Center PacifiCorp
825 NE Multnomah, Suite 2000
Portland, Oregon 97232
With copies to: Mark Alder
Idaho Regulatory Affairs Manager
Rocky Mountain Power
1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
Email: [e-mail]
RECEIVEDFriday, January 27, 2023 4:59:55 PM
IDAHO PUBLIC
UTILITIES COMMISSION
Idaho Public Utilities Commission
January 27, 2023
Page 2

John Hutchings
Carla Scarsella
Rocky Mountain Power
1407 West North Temple, Suite 320
Salt Lake City, Utah 84116
Email: [e-mail]
Email: [e-mail]

Katherine McDowell
Adam Lowney (ID #10456)
McDowell Rackner & Gibson PC
419 SW 11th Avenue, Suite 400
Portland, Oregon 97205
Email: [e-mail]
Email: [e-mail]

Informal inquiries related to this Application should be directed to Mark Alder, Idaho
Regulatory Affairs Manager, at [phone].

Very truly yours,

Joelle Steward
Senior Vice-President of Regulation and Customer Solutions

Enclosures

APPLICATION OF ROCKY MOUNTAIN POWER PAGE 1

John Hutchings
Carla Scarsella
Rocky Mountain Power
1407 West North Temple, Suite 320
Salt Lake City, Utah 84116
[e-mail]
[e-mail]

Katherine McDowell
Adam Lowney (ID #10456)
McDowell Rackner Gibson PC
419 SW 11th Avenue, Suite 400
Portland, Oregon 97205
Tel. [phone]
[e-mail]
[e-mail]

Attorneys for Rocky Mountain Power

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION )
OF ROCKY MOUNTAIN POWER FOR A ) CASE NO. PAC-E-23-01
CERTIFICATE OF CONVENIENCE AND )
NECESSITY AUTHORIZING ) APPLICATION
CONSTRUCTION OF THE BOARDMAN-TO )
-HEMINGWAY 500-KV TRANSMISSION )
LINE PROJECT )

Rocky Mountain Power, a division of PacifiCorp (“Rocky Mountain Power” or the
“Company”), in accordance with Idaho Code § 61-526 and Rule of Procedure (“RP”) 112 of the
Idaho Public Utilities Commission (“Commission”), respectfully applies to the Commission for
an order granting a certificate of public convenience and necessity (“CPCN”) for Energy
Gateway Segment H, the Boardman-to-Hemingway 500-kilovolt (“kV”) transmission line
(“B2H” or the “Project”). The Company will co-own B2H with Idaho Power Company (“IPC”),
which recently filed its own CPCN application for the Project in Case No. IPC-E-23-01.
APPLICATION OF ROCKY MOUNTAIN POWER PAGE 2

B2H is necessary to enable lower-cost and more reliable transmission service for the
Company’s growing customer load and to avoid acquisition of higher-cost generation and
transmission resources. The Company’s analysis of B2H demonstrates that the Project is
expected to result in approximately $1.713 billion in risk-adjusted net benefits, assuming
medium natural gas and carbon dioxide (“CO2”) prices. There are three principal factors that
produce these significant customer benefits.
First, B2H increases the ability to move resources across and between both PacifiCorp
balancing authority areas (“BAA”). There currently exists only one 500-kV transmission line
connecting the Company’s eastern BAA, PacifiCorp East (“PACE”) and its western BAA,
PacifiCorp West (“PACW”). Increasing connections between the Company’s BAAs allows the
Company to serve customers more efficiently in both areas using the most cost-effective
generation available. Additionally, construction of B2H will provide regional benefits by
strengthening the interconnected transmission grid in the west and enhancing resource adequacy.
Second, B2H enables lower-cost and more reliable transmission service to PacifiCorp’s
growing central Oregon loads. By constructing B2H and consolidating certain transmission
rights with the Bonneville Power Administration (“BPA”) (as part of the B2H transaction), the
Company can avoid constructing significant generation resources in southern Oregon that would
otherwise be required absent B2H.
Third, B2H allows for lower cost transmission service to PacifiCorp’s increasing loads in
the vicinity of BPA’s planned Longhorn substation, which is the western terminus of B2H near
Boardman, Oregon. B2H enables the Company to avoid significant third-party transmission
expenses that would otherwise be required to serve this retail customer load.
APPLICATION OF ROCKY MOUNTAIN POWER PAGE 3

The Company requests expedited review of this Application, and adoption of a
procedural schedule that aligns with the schedule in Case No. IPC-E-23-01. B2H has a projected
in-service date of 2026. To ensure completion of the Project by that date, construction must
begin in the summer of 2023. For that reason, the Company requests that the Commission issue
an order on this Application no later than June 30, 2023.
In support of this Application, Rocky Mountain Power states as follows:
I. NAME AND ADDRESS OF APPLICANT

PacifiCorp provides retail electric service under the name Rocky Mountain Power in the
states of Wyoming, Utah, and Idaho, and under the name Pacific Power in the states of Oregon,
Washington, and California. Rocky Mountain Power is a public utility in the state of Idaho subject
to the Commission’s jurisdiction with respect to its prices and terms of electric service to retail
customers in Idaho pursuant to Idaho Code § 61-129. Rocky Mountain Power is authorized to do
business in the state of Idaho providing retail electric service to approximately 88,000 customers
in the state.
Formal correspondence and requests for additional information regarding this matter
should be addressed to:
By e-mail (preferred): [e-mail]

By regular mail: Data Request Response Center PacifiCorp
825 NE Multnomah, Suite 2000
Portland, Oregon 97232

With copies to: Mark Alder
Idaho Regulatory Affairs Manager
Rocky Mountain Power
1407 West North Temple, Suite 330
Salt Lake City, Utah 84116
Email: [e-mail]

APPLICATION OF ROCKY MOUNTAIN POWER PAGE 4

John Hutchings
Carla Scarsella
Rocky Mountain Power
1407 West North Temple, Suite 320
Salt Lake City, Utah 84116
Email: [e-mail]
Email: [e-mail]

Katherine McDowell
Adam Lowney (ID #10456)
McDowell Rackner & Gibson PC
419 SW 11th Avenue, Suite 400
Portland, Oregon 97205
Email: [e-mail]
Email: [e-mail]

Informal inquiries related to this Application should be directed to Mark Alder, Idaho
Regulatory Affairs Manager, at [phone].
II. SUPPORTING TESTIMONY
This Application is supported by the pre-filed written direct testimony and exhibits of the
following Company witnesses:
 Mr. Rick T. Link, Senior Vice President of Resource Planning, Procurement, and
Optimization, demonstrates that the Project is necessary to enable lower-cost and
more reliable transmission service to serve customer load. Mr. Link explains in
detail the customer benefits that will result from the construction and acquisition
of the Project. Mr. Link also describes the transfer of transmission rights and
agreements between the Company, IPC, and BPA.
 Mr. Rick A. Vail, Vice President of Transmission, provides a description of the
Project and a cost estimate for its construction. Mr. Vail’s testimony describes
how the Project will increase both the interconnection capacity and the transfer
capability between PACE and PACW and demonstrates that the Project is
APPLICATION OF ROCKY MOUNTAIN POWER PAGE 5

necessary to improve the reliability of the transmission system. Mr. Vail also
explains the asset exchange that will occur between the Company and IPC in
relation to the Project and the agreements between the two companies.
III. OVERVIEW OF B2H
B2H is an approximately 300-mile-long, 500-kV electric transmission line that will
extend from a switching station proposed to be constructed near Boardman, Oregon to the
existing Hemingway Substation located in Owyhee County, Idaho. Approximately 274 miles of
the transmission line will be in five Oregon counties: Malheur, Baker, Union, Umatilla, and
Morrow Counties. A 24-mile segment of the Project will be in Owyhee County in Idaho.
Because of the length of B2H, the transmission line will also include ten communication
stations along the route. These communication stations will all be constructed within the right-of-
way of the transmission line. B2H will also include the installation of the B2H Midline Series
Capacitor Project and development of a remedial action scheme.1
The Project has long been recognized as an integral component of the Company’s and the
region’s long-term transmission plan. NorthernGrid—a planning association aiming to facilitate
regional transmission planning across the Pacific Northwest and Intermountain West—has
repeatedly identified B2H as a regionally significant project in its biennial regional transmission
plans.2
In addition to the Company, IPC and BPA are stakeholders in B2H. The initial B2H
agreement among the stakeholders was a Joint Permit Funding Agreement, executed
January 12, 2012, and amended several times, to jointly support the regulatory processes
associated with obtaining necessary permits and other project development work. On
January 18, 2022, the parties executed a non-binding term sheet (“Term Sheet”) as the

1 Direct Testimony of Rick T. Link, Exhibit No. 1 - Term Sheet at 17 [hereinafter “Term Sheet”].
2 See, e.g., NORTHERNGRID, Regional Transmission Plan for the 2020-2021 NorthernGrid Planning Cycle at 31
(Dec. 8, 2021) (available at https://www.northerngrid.net/private-media/documents/2020-
2021_Regional_Transmission_Plan.pdf) (last visited Jan. 24, 2023).
APPLICATION OF ROCKY MOUNTAIN POWER PAGE 6

framework for future agreements, which is included as Exhibit No. 1 to the testimony of
Mr. Link.
Prior to execution of the Term Sheet, BPA decided to transition out of its role as a joint
permit funding coparticipant and to instead take transmission service from IPC to serve its
customers. BPA’s decision leaves only the Company and IPC as owners of B2H. To account for
BPA’s decision to take transmission service from IPC, the Term Sheet stipulates that IPC will
acquire BPA’s B2H project capacity, which will increase IPC’s B2H project ownership share to
45.45 percent.3 The Company will own the remaining 54.55 percent of B2H. Because IPC
assumed the entirety of BPA’s ownership interest in B2H, BPA’s transition did not affect the
Company’s ownership interest. When B2H is completed, IPC and the Company will jointly own
as tenants in common the transmission line and all associated facilities and equipment.4
The Term Sheet also designates IPC as project manager for B2H. As project manager,
IPC is responsible for federal, state, and local permitting efforts and construction of the Project,
except that BPA will be responsible for designing, procuring, and constructing the Longhorn
substation and relocating and replacing an existing BPA 69-kV line.5
The Term Sheet summarizes the various agreements the B2H stakeholders have executed
to-date and those they intend to implement in the future relating to the Project.6 The agreements
identified in the Term Sheet include the following:
1. The Company and IPC will execute the B2H Project Joint Construction Funding
Agreement which will include definitive terms and conditions by which the parties will
jointly support and contribute funds for the procurement, construction, and

3 Exhibit No. 1 - Term Sheet at 24.
4 Id. at 26.
5 Id. at 25.
6 Although these agreements all relate to B2H and the stakeholders’ expectations in constructing the Project, the
Company does not seek approval of these agreements in this docket.
APPLICATION OF ROCKY MOUNTAIN POWER PAGE 7

commissioning of the B2H project, allowing for energization of the Project by the earliest
in-service date needed by the parties;
2. IPC and the Company will fund a portion of the proposed Longhorn substation near
Boardman, Oregon;7
3. As part of the asset exchanges discussed below, IPC and the Company may expand their
existing Joint Ownership and Operating Agreement, as amended, and restated
August 22, 2019, to include ownership, operation and maintenance provisions associated
with B2H and the revised capacity owned due to the exchanged assets;8
4. The Company and IPC will execute two additional construction agreements, the Midpoint
500/345-kV Transformer Project Construction Agreement and the Kinport – Midpoint
345-kV Series Capacitor Bank Project Construction Agreement, through which the
companies will make necessary capital upgrades to exchanged assets.
Additionally, the Company and IPC have agreed to exchange several transmission assets
as part of the agreement governing the joint-ownership of B2H. IPC has agreed to transfer to the
Company a percentage of the assets that make up the existing 500-kV and 345-kV transmission
lines between the Borah, Kinport, Adelaide, Midpoint and Hemingway substations.9 The
Company has agreed to transfer to IPC a percentage of the assets that make up the existing
345-kV transmission lines connecting the Populus substation to the Four Corners substation.10
Finally, the Company has agreed to transfer to IPC certain to-be-determined Goshen area
transmission assets, which would allow IPC to provide transmission service to all BPA

7 Exhibit No. 1 - Term Sheet at 11
8 Id. at 14.
9 Id. at 13-14.
10 Id. at 13.
APPLICATION OF ROCKY MOUNTAIN POWER PAGE 8

customers in southeast Idaho currently served by the Company.11 The agreements implementing
these asset exchanges will be completed consistent with the agreed-upon Term Sheet. Although
the Company and IPC intend to implement these asset exchanges in connection with B2H, these
asset exchanges will not take effect until energization of B2H—which is expected to occur in
2026. For that reason, the Company does not request approval of these asset exchanges at this
time.
IV. LEGAL STANDARD
Before constructing a transmission line, Idaho Code § 61-526 requires that a public utility
obtain a “certificate that the present or future public convenience and necessity require or will
require such construction[.]” When the Commission considers an application for a CPCN, the
“public interest is the paramount consideration[.]”12 To determine whether the proposed resource
is in the public interest, the “primary focus” of CPCN proceedings is the examination of two
questions: “Does the present or future public convenience and necessity require additional
resources, and is the [proposed resource] a reasonable means of meeting this need?”13
To answer the first question, the Commission often relies on the analysis in a utility’s
Integrated Resource Plan (“IRP”) to demonstrate that additional resources are necessary to serve
present or future customer needs.14 However, the Commission has also relied on analysis
completed after the most recent acknowledged IRP when that analysis is available and further

11 Id. at 14.
12 In the Matter of Idaho Power Co. & Application for a Certificate of Public Convenience and Necessity for the
Investment in Selective Catalytic Reduction Controls on Jim Bridger Units 3 and 4, Case No. I PC-E-13-16, Order
No. 32929 at 10 (Dec. 2, 2013) (quoting Application of Kootenai Natural Gas Co., 78 Idaho 621, 627, 308 P.2d 593,
596 (1957)).
13 In the Matter of Idaho Power Co. Application For a Certificate of Public Convenience and Necessity For the
Evander Andrews Power Plant, Case No. I PC-E-06-09, Order No. 30201 at 4 (Dec. 15, 2006).
14 See Order No. 30201 at 4; In the Matter of Idaho Power Company’s Application for a Certificate of Public
Convenience and Necessity for the Ratebasing of the Bennett Mountain Power Plant, Case No. IPC-E-03-12, Order
No. 29410 at 7 (Jan. 2, 2004).
APPLICATION OF ROCKY MOUNTAIN POWER PAGE 9

demonstrates the need for a proposed resource.15 As to the second question, the Commission may
determine that a proposed resource is reasonable if the applicant demonstrates that it is a
cost-effective means of meeting the applicant’s needs.16
Here, as explained in the testimonies of Mr. Link and Mr. Vail, B2H enables lower-cost
and more reliable transmission service to serve customer load and increases transmission
connectivity between PACE and PACW. Mr. Link demonstrates that B2H will enable the
Company to cost-effectively and reliably serve growing customer load. As explained in detail
below and in Mr. Link’s testimony, these benefits primarily result from cost savings in serving
load in central Oregon and near the proposed Longhorn substation. Mr. Vail’s testimony outlines
the reliability benefits to the transmission system resulting from B2H.
As to the reasonableness of B2H, Mr. Link’s analysis demonstrates that B2H is the most
cost-effective means of serving the Company’s load. Without B2H, the Company would be
required to acquire higher-cost generation resources and third-party transmission service, which
together would increase customer costs by approximately $1.713 billion through 2042.
The Commission has also previously provided expedited review of a CPCN application
when necessary to meet construction deadlines.17 The cost savings discussed above are all based
on an anticipated 2026 in-service date for B2H. To ensure that the Project can be energized in
time for a 2026 in-service date, construction must begin in the summer of 2023. For that reason,
the Company requests that the Commission issue an order on this Application no later than
June 30, 2023.

15 Order No. 30201 at 8 (considering analysis in the applicant’s 2006 IRP, which was filed more than five months
after the application for a CPCN and was not acknowledged until after the Commission granted the CPCN).
16 Order No. 29410 at 10 (finding that the proposed resource “is a reasonable response to meet the near-term needs
of the Company and its customers” because it is the “most cost-effective proposal in the RFP process and was the
winning project”).
17 Order No. 29410 at 5-6 (granting CPCN in just over three months because applicant’s contract with construction
company “contain[ed] a construction schedule that may require modification if the Commission has not made its
decision prior to” the applicant’s requested date).
APPLICATION OF ROCKY MOUNTAIN POWER PAGE 10

Finally, the Commission has also granted CPCNs even when one is not strictly required
by the statute.18 Here, it is unclear whether a CPCN is strictly required for B2H because IPC, not
the Company, is the entity actually constructing the transmission line. The Company has made
this request, however, due to the scope of B2H, the Company’s active role in overseeing the
Project, and to outline the distinct and substantial benefits the Project provides to the Company’s
customers.
V. REQUIREMENTS OF RP 112
A. Statement and Explanation. A statement or prepared testimony and
exhibits explaining why the proposed construction or expansion is
or will be in the public convenience and necessity.

This Application, along with the attached testimony, explain that B2H is in the public
convenience and necessity and serves the public interest by providing significant net benefits to
customers in a wide range of price-policy scenarios.
The Project is necessary because it enables lower-cost and more reliable transmission
service to serve the Company’s increasing retail customer load, particularly in central Oregon
and near B2H’s western terminus at the proposed Longhorn substation. In central Oregon, the
Company seeks to double its transmission rights from 340 megawatts (“MW”) to 680 MW to
meet growing customer needs. B2H will enable the Company to secure this capacity increase
without any additional transmission upgrades. Additionally, after acquiring B2H the Company
will reduce its BPA wheeling expenses by consolidating certain point-to-point (“PTP”)
reservations on BPA’s system that are used to reach central Oregon loads. In the absence of
B2H, the Company will still need increased transmission into the central Oregon load area and
serving that load would require dispatchable generation in southern Oregon ranging from

18 In the Matter of the Application of Rocky Mountain Power for a Certificate of Public Convenience and Necessity
Authorizing Construction of the Populus-to-Terminal 345 kV Transmission Line Project, Case No. PAC-E-08-03,
Order No. 30657 at 5 (Oct. 10, 2008) (granting CPCN for Populus-to-Terminal transmission line even though the
Company was “not required to apply for a CPCN . . .”).
APPLICATION OF ROCKY MOUNTAIN POWER PAGE 11

725 MW to 1,450 MW to prevent impacts to other existing rated paths. Without B2H, ensuring
this dispatchable generation would require substantial investment in generation and in four-hour
battery storage.
In the Longhorn area, customer load near the proposed western terminus of B2H is also
growing substantially. Because of those customers’ proximity to B2H, the Company can serve
those customers via a connection to the B2H line. Without B2H, serving this growing load will
require PTP transmission service from various other utilities in the region, the cost of which will
be attributed to the Company’s retail customers as net power costs.
To evaluate the cost-effectiveness of B2H, the Company analyzed the change in expected
revenue requirement between two resource portfolios—one with B2H and one without. To
ensure a robust evaluation, the Company calculated the present value revenue requirement
differential (“PVRR(d)”) between the two portfolios under a range of future natural gas price and
CO2 policy assumptions (“price-policy scenarios”). B2H results in significant cost savings in all
scenarios compared to a non-B2H portfolio. The risk-adjusted PVRR(d) customer benefits for
B2H range from $1.487 billion in a price-policy scenario assuming high natural gas and CO2
prices to $1.786 billion assuming medium natural gas and no CO2 price. In the price-policy
scenario that assumed medium natural gas and medium CO2 prices, the portfolio with B2H is
$1.713 billion lower cost, demonstrating the robust customer benefits resulting from B2H.
Finally, the Project will improve grid reliability by providing better operational control of
the backbone transmission system by interconnecting PACE and PACW on the PacifiCorp
transmission system. As explained in the testimonies of Mr. Link and Mr. Vail, through B2H the
Company will secure an additional 300 MW of west-to-east transmission capacity and an
additional 818 MW of east-to-west transmission capacity, which will enable the Company to
efficiently deploy new generating facilities and better utilize existing resources to meet
anticipated resource needs. Moreover, the Project has long been recognized as an integral
component of the Company’s and the region’s long-term transmission plan. The Company has
partnered with IPC in a non-binding agreement to fund and own B2H to improve transmission
APPLICATION OF ROCKY MOUNTAIN POWER PAGE 12

service to customers in both utilities’ service territories. BPA will also enter into wheeling
agreements to deliver energy across IPC-owned equipment to BPA customers in eastern Idaho.
The Company, IPC and BPA are moving forward with B2H at this time because current
circumstances make it necessary and economic for their customers throughout the region.
The Company requests approval of a CPCN by June 2023 so construction may begin in
July 2023 to ensure an in-service date in 2026.
B. Description of Construction or Expansion. A full description of the
proposed construction or expansion, including the manner of
construction or expansion, and if an expansion, the names of all
public utilities, corporations, or persons with whom the expanded
utility is likely to compete.
A description of the project is included above in Section III of this Application.
Additional details related to the Project are provided in the testimony of Mr. Vail.
The Project will not conflict with or adversely affect the operations of any existing
certificated fixed public utility providing retail electric service to the public. The Project does
not constitute an extension into the certificated service territory of any existing public electric
utilities.
C. Map. A map of suitable scale showing the location of the
construction or expansion and its relation to other public utilities in
the area(s) that offer or provide similar utility service.

A map of the proposed route for the Project is provided in Mr. Vail’s testimony.
D. Financial Statement and Construction Timelines. A statement of the
manner in which the applicant proposes to finance the construction
or expansion, the time when the applicant proposes to begin the
construction or expansion, and the time when the applicant
proposes to complete the construction or expansion.

The Company intends to finance the Project through its normal sources of capital, both
internal and external, including net cash flow from operating activities, public and private debt
offerings, the issuance of commercial paper, the use of unsecured revolving credit facilities,
APPLICATION OF ROCKY MOUNTAIN POWER PAGE 13

capital contributions and other sources. Although the Project is a significant investment on the part
of the Company, the financial impact will not impair the Company’s ability to continue to provide
safe and reliable electricity service at reasonable rates. In addition, approval of the Company’s
resource decision provides important regulatory support for the Company’s current credit rating.
The Company anticipates the following timeline. IPC secured a site certificate from the
Oregon Energy Facility Siting Council (“EFSC”) for B2H in October 2022.19 Several intervenors
in the proceedings before EFSC have appealed the order issuing that site certificate. A ruling
from the Oregon Supreme Court on those appeals is expected no later than June 6, 2023.20
IPC has requested issuance of CPCNs from the Commission and the Public Utility
Commission of Oregon by June 30, 2023.21 Similarly, the Company in this Application requests
a CPCN from the Commission by June 30, 2023. Additionally, the Company will request a
non-situs CPCN from the Wyoming Public Services Commission to be issued by June 30, 2023.
IPC anticipates issuing Requests for Proposals for materials and contractors during the
first quarter of 2023.22 IPC anticipates selecting a construction manager in the second quarter of
2023.23 Construction is expected to begin in summer of 2023 and the Company expects B2H to
be placed in-service in 2026.

19 In the Matter of the Application for Site Certificate for the Boardman to Hemingway Transmission Line, Site
Certificate (Sept. 7, 2022) (available at https://www.oregon.gov/energy/facilities-
safety/facilities/Facilities%20library/2022-09-27-B2H-APP-Doc32-Site-Certificate.pdf) (last visited Jan. 24, 2023)
(EFSC unanimously voted to approve the Final Order and Site Certificate on September 27, and the Final Order and
Site Certificate were executed on October 6, 2022).
20 See Oregon Revised Statute 469.403(6) (requiring the Oregon Supreme Court to “give priority” to appeals of
orders issuing site certificates and “render a decision within six months of the filing of the petition for review”). The
intervenors filed their appeals on December 6, 2022.
21 In the Matter of Idaho Power Company’s Application for a Certificate of Public Convenience and Necessity for
the Boardman to Hemingway 500-kV Transmission Line, Case No. IPC-E-23-01; In the Matter of Idaho Power
Company’s Petition for Certificate of Public Convenience and Necessity, OPUC Docket PCN 5.
22 Case No. IPC-E-23-01, Application at 15 (Jan. 9, 2023).
23 Id.
APPLICATION OF ROCKY MOUNTAIN POWER PAGE 14

E. Cost Estimates and Revenue Requirements. Estimates of the cost of
the construction or expansion, the number of additional customers to
be served by the construction or expansion, the revenues to be
derived from the construction or expansion, and of the effects of the
construction or expansion on revenue requirements.
Mr. Vail’s testimony includes the Company’s confidential estimate for its in-service cost
of B2H. Mr. Link’s testimony includes the Company’s economic analysis of the Project, which
includes both its estimated costs and revenues. PacifiCorp has the capability to finance the
Project using the Company’s internally generated funds and access to external capital markets.
While the Company is not seeking ratemaking treatment for B2H at this time, Mr. Link’s
testimony includes a forecast of the change in nominal revenue requirement due to B2H. This
forecast demonstrates a lower overall revenue requirement through the end of the study horizon
in 2042.
VI. REQUEST FOR RELIEF
Rocky Mountain Power requests that the Commission issue an Order: (1) authorizing that
this proceeding be processed under an expedited procedure to issue an order no later than
June 30, 2023, aligning with IPC’s CPCN application in Case No. IPC-E-23-01, (2) authorizing
Rocky Mountain Power a CPCN to construct the Project as described in this Application, and (3)
granting such other authority and authorizations as may be necessary to facilitate the
construction of the Project.

APPLICATION OF ROCKY MOUNTAIN POWER PAGE 15

Respectfully submitted this 27th day of January, 2023.

Katherine McDowell
Adam Lowney (ID #10456)
McDowell Rackner Gibson PC
419 SW 11th Avenue, Suite 400
Portland, Oregon 97205
Tel. [phone]
[e-mail]
[e-mail]

Attorneys for Rocky Mountain Power

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
OF ROCKY MOUNTAIN POWER FOR A CERTIFICATE OF CONVENIENCE AND NECESSITY AUTHORIZING
CONSTRUCTION OF THE BOARDMAN-TO-HEMINGWAY 500-KV
) CASE NO. PAC-E-23-01 ) ) DIRECT TESTIMONY OF ) RICK T. LINK ) ) )
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-23-01
January 2023
Link, Di - i
Rocky Mountain Power

TABLE OF CONTENTS

I. INTRODUCTION AND QUALIFICATIONS ............................................................. 1
II. PURPOSE AND SUMMARY OF TESTIMONY ........................................................ 2
III. OVERVIEW OF B2H.................................................................................................... 5
IV. 2021 INTEGRATED RESOURCE PLAN .................................................................... 6
V. 2021 IRP UPDATE........................................................................................................ 9
VI. MODELING ASSUMPTIONS ................................................................................... 11
VII. MODELING METHODOLOGY ................................................................................ 21
VII. PRICE-POLICY SCENARIO RESULTS ................................................................... 33
IX. ANNUAL REVENUE REQUIREMENT ................................................................... 34
X. AGREEMENTS RELATED TO B2H......................................................................... 37
XI. CONCLUSION ............................................................................................................ 38

ATTACHED EXHIBITS
Exhibit No. 1— B2H Term Sheet Dated January 18, 2022
Confidential Exhibit No. 2— PVRR(d) Calculations

Link, Di - 1
Rocky Mountain Power

I. INTRODUCTION AND QUALIFICATIONS 1
Q. Please state your name, business address, and present position with PacifiCorp 2
d/b/a Rocky Mountain Power (“PacifiCorp” or the “Company”). 3
A. My name is Rick T. Link. My business address is 825 NE Multnomah Street, Suite 600, 4
Portland, Oregon 97232. My position is Senior Vice President, Resource Planning, 5
Procurement and Optimization. 6
Q. Please describe the responsibilities of your current position. 7
A. I am responsible for PacifiCorp’s energy supply management and resource planning 8
and procurement functions, which includes the integrated resource plan (“IRP”), 9
structured commercial business and valuation activities, and long-term load forecasts. 10
Most relevant to this docket, in coordination with Company witness Mr. Rick Vail, I 11
am responsible for contract negotiations required for PacifiCorp’s participation in the 12
Boardman-to-Hemingway project (“B2H” or the “Project”). I am also responsible for 13
the economic analysis of B2H. 14
Q. Please describe your professional experience and education. 15
A. I joined PacifiCorp in December 2003 and assumed the responsibilities of my current 16
position in September 2021. Over this period, I held several analytical and leadership 17
positions responsible for developing long-term commodity price forecasts, pricing 18
structured commercial contract opportunities, developing financial models to evaluate 19
resource and transmission investment opportunities, negotiating commercial contract 20
terms, and overseeing development of PacifiCorp’s resource plans. I was responsible 21
for delivering PacifiCorp’s 2013, 2015, 2017, 2019, and 2021 IRPs; have been directly 22
involved in implementing and overseeing resource RFP processes; and performed 23
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economic analysis supporting a range of resource and transmission investment 1
opportunities. Before joining PacifiCorp, I was an energy and environmental 2
economics consultant with ICF Consulting (now ICF International) from 1999 to 2003, 3
where I performed electric sector financial modeling of environmental policies and 4
resource investment opportunities for utility clients. I received a Bachelor of Science 5
degree in Environmental Science from the Ohio State University in 1996 and a Master 6
of Environmental Management degree from Duke University in 1999. 7
Q. Have you testified in previous regulatory proceedings? 8
A. Yes. I have testified in proceedings before the Idaho Public Utilities Commission 9
(“Commission”), the Utah Public Service Commission, the Wyoming Public Service 10
Commission, the Public Utility Commission of Oregon, the Washington Utilities and 11
Transportation Commission, and the California Public Utilities Commission. 12
II. PURPOSE AND SUMMARY OF TESTIMONY 13
Q. What is the purpose of your direct testimony? 14
A. I present and explain the economic analysis that supports PacifiCorp’s request for a 15
certificate of public convenience and necessity (“CPCN”) for B2H. I explain how B2H 16
and related changes to PacifiCorp’s transmission system and operations were analyzed 17
and shown to be cost effective in PacifiCorp’s 2021 IRP and 2021 IRP Update, and 18
provide current economic analysis demonstrating customer benefits associated with the 19
Project. 20
Q. Please summarize your direct testimony regarding B2H. 21
A. The 2021 IRP and 2021 IRP Update showed that B2H is necessary to meet the 22
Company’s need to reliably and cost effectively serve customers, and it was part of the 23
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preferred portfolio in both plans. Both the 2021 IRP and 2021 IRP Update specifically 1
examined the portfolio impacts and system cost implications of not participating in 2
B2H relative to the preferred portfolio outcome that included it. Both analyses showed 3
that building B2H was the least-cost, least-risk outcome. In the 2021 IRP, B2H was 4
projected to result in $453 million in risk-adjusted net benefits during the study horizon 5
of 2021 through 2040.1 Similarly, the 2021 IRP Update projected risk-adjusted net 6
benefits of $439 million during the same period.2 7
Since the 2021 IRP Update was prepared, several key changes have occurred. First, 8
the Company’s most recent load forecast has significantly increased, reflecting both 9
new load and the impact of climate change. Second, the United States Environmental 10
Protection Agency (“EPA”) proposed its “Ozone Transport Rule” (also called the 11
“Good Neighbor Rule” or “Cross-State Air Pollution Rule”) to establish allowance-12
based emissions limits for nitrogen oxides (“NOx”) that will impact PacifiCorp’s 13
thermal resources in Utah and Wyoming. Third, the enactment of the federal Inflation 14
Reduction Act (“IRA”) has extended and expanded tax incentives for clean generation 15
and energy storage resources. Finally, PacifiCorp’s transmission service requirements 16
have evolved considering that the Bonneville Power Administration (“BPA”) may be 17
unable to reasonably accommodate some of the modifications to PacifiCorp’s existing 18
transmission service arrangements contemplated in the non-binding B2H Term Sheet, 19

1 PacifiCorp’s 2021 Integrated Resource Plan. Volume I. September 1, 2021. Pg. 271-272. Available at:
https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/integrated-resource-plan/2021-
irp/Volume%20I%20-%209.15.2021%20Final.pdf
2 PacifiCorp’s 2021 Integrated Resource Plan Update. March 31, 2022. Pg. 89-91. Available at:
https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/integrated-resource-
plan/2021_IRP_Update.pdf
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dated January 18, 2022, attached as Exhibit No. 1.3 After incorporating these and other 1
associated changes, B2H is now projected to result in $1.713 billion in risk-adjusted 2
net benefits during a study horizon of 2023 through 2042, assuming medium natural 3
gas and carbon prices. 4
The Project significantly enhances the capability of the regional electric grid, 5
and the current B2H benefit estimate has three distinct aspects. First, B2H will increase 6
the bidirectional transfer capability between PacifiCorp’s east and west balancing 7
authority areas (“BAA”). Second, B2H enables lower-cost and more reliable 8
transmission service to PacifiCorp’s central Oregon loads. Third, B2H allows for lower 9
cost transmission service to PacifiCorp loads in the vicinity of BPA’s planned 10
Longhorn substation, which is the western terminus of B2H.4 11
In the Company’s economic analysis, PacifiCorp evaluated the change in revenue 12
requirement associated with B2H using the PLEXOS model under a range of natural 13
gas price and CO2 policy assumptions (“price-policy scenarios”). PacifiCorp calculated 14
the change in system revenue requirement between cases with and without B2H, where 15
capital revenue requirement is levelized. 16
The change in annual nominal revenue requirement through 2042 was also 17
calculated to provide some perspective around potential rate pressures relative to a case 18
that does not include B2H. 19

3 The Term Sheet is also available at: https://docs.idahopower.com/pdfs/B2H/B2H-termsheet-
bpapacIPCSigned-IP.pdf
4 The Longhorn substation is approximately four miles east of the city of Boardman, Oregon.
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PacifiCorp requests that the Commission grant a CPCN for B2H no later than 1
the end of June 2023 to ensure timely energization for this critical transmission system 2
upgrade. 3
III. OVERVIEW OF B2H 4
Q. Please describe B2H. 5
A. B2H is a high voltage single-circuit 500-kV alternating current transmission line that 6
extends approximately 300 miles from north-central Oregon to southwest Idaho. In the 7
context of PacifiCorp’s long-term transmission plan, B2H is also referred to as Segment 8
H of Energy Gateway. 9
Q. Is the Company the only party involved in B2H? 10
A. No. Idaho Power Company (“IPC”) is the overall project manager, responsible for all 11
B2H permitting, design, procurement, and construction. IPC will fund and own 12
45.45 percent of B2H and the Company will fund and own 54.55 percent of B2H. BPA 13
has also partnered with IPC and the Company in the development of B2H. However, 14
BPA will not have an ownership interest in B2H and instead intends to acquire B2H 15
capacity from IPC through transmission service agreements. 16
Q. Has IPC filed a CPCN application in Idaho for B2H? 17
A. Yes. IPC filed a CPCN application for B2H on January 9, 2023, in 18
Case No. IPC-E-23-01. 19

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IV. 2021 INTEGRATED RESOURCE PLAN 1
Q. Does the 2021 IRP identify a need for additional resources and transmission to 2
serve PacifiCorp’s customers? 3
A. Yes. The primary focus of any IRP is to forecast customer demand and to evaluate 4
different combinations of resources and transmission to meet that customer demand 5
over time. In the 2021 IRP, the preferred portfolio represents the least-cost, least-risk 6
portfolio of resources and transmission options, as presented in Tables 9.16 and 7
9.17 in Chapter 9 of Volume I. Consistent with prior IRPs, in the 2021 IRP, all resource 8
portfolios that were considered as candidates for the preferred portfolio contain new 9
supply-side, demand-side, market resources, and transmission upgrades necessary to 10
meet customer demand. 11
Q. Was B2H included in the 2021 IRP preferred portfolio? 12
A. Yes. In the 2021 IRP, after a variety of price-policy and coal retirement scenarios were 13
considered, the P02-MM5 portfolio was identified as top-performing and B2H was 14
included in that portfolio. At that point, eight variants of P02-MM were prepared to 15
analyze key resource and transmission decisions. As B2H was already part of the 16
P02-MM portfolio, a “No B2H” portfolio was prepared that excluded B2H. The 17
P02-MM portfolio, which includes B2H, was identified as the top-performing portfolio 18
among all variants, including the variant that removed B2H.6 19

5 In the 2021 IRP, the P02 series of portfolios reflect fully optimized coal unit retirements using the best
available input data and assumptions regarding requirements and constraints. The P02-MM portfolio was
selected assuming medium gas prices and a medium CO2 price proxy for future federal policy.
6 The 2021 IRP also identified additional resources related to compliance with Washington’s Clean Energy
Transformation Act (“CETA”) that were added to establish the 2021 IRP preferred portfolio (P02-MM-CETA).
The additional resources necessary to comply with CETA, however, are not treated as system resources for
purpose of the IRP and had no impact on the need for B2H.
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Q. Did the 2021 IRP modeling account for the interdependence of resources and 1
transmission, like B2H? 2
A. Yes. The PLEXOS model used to develop the 2021 IRP, which I discuss in more detail 3
below, has the ability to endogenously view costs and transmission capability 4
associated with transmission upgrades and allows for selection of specific transmission 5
investments that coincide with new resource options. Endogenous transmission 6
modeling capabilities in the PLEXOS model include the consideration of 1) new 7
incremental transmission options tied to resource options; 2) existing transmission 8
rights tied to the use of post-retirement brownfield sites; 3) estimated costs associated 9
with these transmission options; and 4) transmission options that interact with multiple 10
or complex elements of the IRP transmission topology. When the 2021 IRP modeling 11
evaluated transmission investments, it accounted for the assumed cost for those 12
investments and the value generated by those investments by enabling low-cost 13
resource options and better optimization of resources needed to serve load or to lower 14
system costs. 15
Q. Please describe the reliability benefits from B2H that were identified in the 16
2021 IRP. 17
A. The 2021 IRP indicated that energy not served (“ENS”) would be slightly higher in the 18
absence of B2H. ENS is reported as an output of the PLEXOS model and it indicates 19
the volume of load that could not be met do to a shortfall of supply in modeled load 20
areas across PacifiCorp’s system. 21

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Q. Does the 2021 IRP fully capture the expected system reliability benefit associated 1
with B2H? 2
A. No. The 2021 IRP reflects PacifiCorp’s load, resources, and transmission rights, plus 3
limited access to market purchases. In light of regional reliability concerns, discussed 4
in Chapter 5 of the 2021 IRP, the maximum amount of market purchases available was 5
reduced significantly from the level in the 2019 IRP. These reductions were applied in 6
the summer season for the California-Oregon Border (“COB”), Nevada-Oregon Border 7
(“NOB”), and Mona markets whose participants typically experience peak demand in 8
the summer. For the Mid-Columbia (“Mid-C”) market, the maximum amount of market 9
purchases was reduced in both seasons, but by a larger amount in the winter season, as 10
the Pacific Northwest is generally winter peaking. By enhancing the connection 11
between the summer and winter-peaking areas of PacifiCorp’s system, B2H will make 12
it more likely that purchases can be procured from markets that are not experiencing 13
peak conditions and delivered where they are needed (i.e., purchases imported to 14
PacifiCorp’s East BAA in the winter and purchases imported into PacifiCorp’s West 15
BAA in the summer). While modeled market purchase limits are representative of what 16
might be available during peak demand conditions, there are many hours within 17
summer and winter seasons in which regional demand is likely to support market 18
transactions well in excess of those limits. Due to the market purchase limits, the 19
reported results do not account for the entire improvement in reliability that B2H is 20
likely to facilitate by providing additional access to distant markets. 21

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Q. Will B2H increase PacifiCorp’s reliance on market purchases? 1
A. No. Access to market purchases is not the same as reliance on market purchases. The 2
P02-MM portfolio, which includes B2H has more resources as a result of higher 3
interconnection capability provided by the Project. The addition of more resources 4
generally reduces the need to rely on market purchases to serve customer load. This 5
does not mean that market purchases will necessarily decline, as reduced congestion 6
allows for more cost-effective market purchases to support customer load rather than 7
more expensive dispatchable resources. To the extent dispatchable resources are called 8
upon less often, but remain available as indicated by the increase in resources in the 9
portfolio that includes B2H, PacifiCorp would not be reliant upon such purchases to 10
meet its peak loads and reliability requirements. 11
V. 2021 IRP UPDATE 12
Q. Has the Company prepared an update to the 2021 IRP? 13
A. Yes. On March 31, 2022, the Company issued its 2021 IRP Update. 14
Q. What is the purpose of the 2021 IRP Update? 15
A. The 2021 IRP Update serves as a checkpoint to the action plan contained in the 16
2021 IRP to ensure that changes in the planning environment are considered in between 17
the full IRP planning process, which is completed every two years. The 2021 IRP 18
Update assesses whether evolving trends and events that may ultimately impact 19
customers merit a shift in the action plan to deliver resources and transmission 20
investments that might be needed to reliably serve customers. As relevant here, the 21
2021 IRP Update reflects resource planning and procurement activities that have 22
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occurred since the 2021 IRP and presents an updated load-and-resource balance and an 1
updated resource portfolio consistent with changes in the planning environment. 2
Q. Was B2H considered in the Company’s 2021 IRP Update? 3
A. Yes. B2H and associated resource interconnections it will enable were included in the 4
preferred portfolio identified in the 2021 IRP Update. 5
Q. Did the 2021 IRP Update continue to show a need for additional transmission 6
resources? 7
A. Yes. In fact, the need increased relative to the 2021 IRP, primarily due to an increase 8
in forecasted load. While the same transmission options were available in the 2021 IRP 9
Update as the 2021 IRP, the 2021 IRP Update included two new options and 10
accelerated four others from the 2021 IRP.7 This was partially offset by one delay and 11
the removal of one option from the final year of the study horizon. There were no 12
changes in the timing and need for B2H. 13
Q. Did the 2021 IRP Update continue to show a need for additional generation 14
resources? 15
A. Yes. The resource need also increased due to an increase in forecasted load. The 16
2021 IRP Update shows a resource need in all years of the planning horizon—starting 17
at 1,584 MW in 2022 and increasing to 6,755 MW in 2040.8 In 2027, the first full year 18
that B2H will be in service, the resource need is 2,403 MW, an increase of 273 MW, 19
or approximately 13 percent, relative to the resource need identified in the 2021 IRP. 20
The higher load reflected in the 2021 IRP Update approaches the level analyzed in the 21

7 See 2021 IRP Update, Table 6.2
8 See 2021 IRP Update, Table 4.2.
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high-load sensitivity conducted in the 2021 IRP.9 And, as discussed later in my 1
testimony, the most recent load forecast is even higher than what was assumed in the 2
2021 IRP Update. 3
Q. What other important updates were included in the 2021 IRP Update modeling? 4
A. As discussed in Chapter 5 – Modeling and Assumptions Updates of the 2021 IRP 5
Update, key updates in addition to the load-and-resource balance include the resource 6
changes due to activity resulting from the 2020 All Source RFP. Importantly, the EPA’s 7
pre-publication version of its Ozone Transport Rule, which was released on 8
March 11, 2022, was not modeled in the 2021 IRP Update. 9
Q. Did the 2021 IRP Update include the same with-and-without B2H analysis that 10
you describe for the 2021 IRP? 11
A. Yes. Through 2040, the resource portfolio with B2H was $439 million lower cost on a 12
risk-adjusted basis as compared to the portfolio without B2H. 13
VI. MODELING ASSUMPTIONS 14
Q. Please summarize the natural gas and CO2 price assumptions used in the updated 15
economic analysis of B2H in this case. 16
A. The updated economic analysis of B2H includes four price-policy scenarios, as 17
summarized in Table 1: 18
• Medium natural gas prices paired with medium CO2 prices, which I 19
refer to as the “MM” price-policy scenario; 20
• Medium natural gas prices without a CO2 price, which I refer to as the 21
“MN” price-policy scenario; 22

9 See 2021 IRP Update, Pg. 2.
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• Low natural gas prices without a CO2 price, which I refer to as the 1
“LN” price-policy scenario; and 2
• High natural gas prices with a high CO2 price, which I refer to as the 3
“HH” price-policy scenario. 4
These assumptions can influence the value of system energy, the dispatch of system 5
resources, and PacifiCorp’s resource mix. Consequently, wholesale-power prices and 6
CO2 policy assumptions affect net power cost (“NPC”) benefits, non-NPC 7
variable-cost benefits, and system fixed-cost benefits associated with B2H. Because 8
wholesale-power prices and CO2 policy outcomes are both uncertain and important 9
drivers to the economic analysis, it is important to evaluate a range of assumptions for 10
these variables. Table 1 summarizes the price-policy scenarios used to analyze B2H. 11
Table 1. Price-Policy Scenario Assumption Overview 12
Price-Policy
Scenario
Henry Hub Natural Gas Price
(Levelized $/MMBtu)* CO2 Price Description
MM Medium Gas: $5.67 $12.10/ton startin 2025 risin to $51.40/ton in 2040
MN Low Gas: $3.67 one
LN Medium Gas: $5.67 one
HH High Gas: $8.94 $44.34/ton starting 2025 rising to $120.48/ton in 2040
*Nominal levelized Henry Hub natural gas price from 2025 through 2040.

Q. Please describe the natural gas price assumptions used in the price-policy 13
scenarios. 14
A. The medium natural gas price assumptions are from PacifiCorp’s official forward price 15
curve (“OFPC”) dated September 30, 2022, which was the most current OFPC 16
available when PacifiCorp prepared its modeling inputs. The first 36 months of the 17
OFPC reflect market forwards at the close of a given trading day (September 30, 2022, 18
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in this case). As such, these 36 months represent market forwards as of September 1
2022. The blending period (months 37 through 48) is calculated by averaging the 2
month-on-month market forwards from the prior year with the month-on-month 3
fundamentals-based price from the subsequent year. The fundamentals portion of the 4
natural gas OFPC reflects an expert third-party price forecast. The fundamentals 5
portion of the electricity OFPC reflects prices as forecast by a third-party using 6
AURORAXMP (“Aurora”), a WECC-wide market model. Aurora uses the expert 7
third-party natural gas price forecast to produce a consistent electricity price forecast 8
for market hubs in which PacifiCorp participates. Figure 1 shows Henry Hub 9
natural-gas price assumptions for the medium, high, and low natural gas price scenarios 10
compared to the medium price used in the 2021 IRP forecast from March 2021. The 11
electric prices comparison is also shown. The September 2022 price forecast reflects 12
updates to natural gas prices that are higher in the near term from recent market price 13
trends. The updated gas prices also account for limitations in west coast states to add 14
new natural gas. 15
Figure 1. Nominal Electric and Natural Gas Price Assumptions 16

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Q. Please describe the CO2 price assumptions used in the price-policy scenarios. 1
A. PacifiCorp used three different system-wide CO2 price scenarios—zero, medium, and 2
high. The medium and high scenarios are derived from a survey of third-party industry 3
experts, including IHS CERA, and Wood Mackenzie and the Energy Information 4
Administration as well as CO2 price assumptions used by peer utilities. The resulting 5
CO2 price is applied as a tax beginning in 2025, as shown in Figure 2.10 In addition, the 6
Company’s Chehalis natural gas-fired plant is located in Washington and is subject to 7
Washington’s cap-and-invest program established in the Climate Commitment Act, 8
which became effective January 1, 2023. As a proxy for the auction and trading process 9
in this program, in all CO2 scenarios the cost of emissions from the Chehalis plant 10
reflect the social cost of greenhouse gases used for compliance with RCW 19.280.030 11
and incorporates the updated inflation forecast in the Washington Utility and 12
Transportation Commission’s August 24, 2022, order in docket U-190730. 13

10 While the CO2 price assumptions are applied as a tax, the inclusion of CO2 prices in this way does not
necessarily mean that future policies will specifically be implemented via a tax. Inclusion of a CO2 price
represents that there is a high likelihood that future policies will impute a cost on fossil-fired generation that is
incremental to the cost of existing policies known today. Considering the difficulties in projecting future policy
mechanisms, this incremental cost is applied for modeling purposes as a tax.
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Figure 2. CO2 Price Assumptions 1

Q. Does inclusion of potential future CO2 costs reflect prudent utility planning? 2
A. Yes. The Company’s price-policy scenarios include varying levels of assumed 3
CO2 costs to reflect the fact it is more likely than not that some policy will exist that 4
will drive reduced emissions over the life of B2H and that these policies will introduce 5
an incremental cost to fossil-fired generation. When determining CO2 costs used for 6
planning purposes, the Company strives to ensure that it is not an outlier. As discussed 7
above, the medium price is within a reasonable range used by the industry to assess risk 8
and conduct sound resource planning. The most recent example of this trend is the 9
EPA’s proposed Ozone Transport Rule restricting NOx emissions from power plants 10
and other industrial sources.11 This rule could impose new and significant 11
environmental compliance obligations, resulting in upward pressure on system costs, 12
by 2026 on PacifiCorp’s coal units in Wyoming and Utah. 13

11 See https://www.epa.gov/csapr/good-neighbor-plan-2015-ozone-naaqs.
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Q. Are the modeled CO2 costs intended to represent a literal carbon tax? 1
A. No. The modeled CO2 costs are not intended to explicitly account for a future tax on 2
CO2 emissions. Rather, these costs capture the effect of policies incentivizing reduced 3
emissions through benefits or imposing costs through penalties or other costs resulting 4
from market dynamics driving the need for reduced emissions from fossil-fired 5
generation. 6
Q. Did PacifiCorp update its load forecast in its economic analysis of B2H? 7
A. Yes. The sales and load forecast used in preparation of this filing was completed in 8
September 2022. It is the same load forecast that was presented at the October 13, 2022, 9
public-input meeting for the 2023 IRP. 10
Q. How does this load forecast compare to the load forecast used in the 2021 IRP? 11
A. Figure 3 and Figure 4 show the load and peak forecast relative to the 2021 IRP forecast, 12
both before accounting for incremental energy efficiency savings. The higher load 13
forecast is being driven by new industrial and commercial customer growth, increased 14
air conditioning saturations and miscellaneous devices and electric vehicle adoption 15
expectations. The updated load forecast also includes updates to weather, temperature, 16
and line losses to account for the progression of historical data since the load forecast 17
that informed the 2021 IRP. The updated load forecast also incorporates certain tax 18
changes resulting from the passage of the IRA. 19
On average, over the 2023 through 2040 timeframe, forecasted system load is 20
up 12.9 percent per year and forecasted coincident system peak is up 13.6 percent per 21
year when compared to the 2021 IRP. Over that same timeframe, the average annual 22
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growth rate for the September 2022 forecast, before accounting for incremental energy 1
efficiency improvements, is 2.00 percent for load and 1.6 percent for peak. 2
Figure 3. Forecasted Annual System Load 3

Figure 4. Forecasted Annual System Coincident Peak 4

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Q. Has PacifiCorp incorporated EPA’s proposed Ozone Transport Rule in its 1
analysis of B2H? 2
A. Yes. PacifiCorp modeled two primary components to reflect the Ozone Transport Rule: 3
NOx allowance requirements for each of its units including penalties for units with high 4
emissions rates, and a market price for NOx allowances, based on the allowance price 5
used in the third-party forecast to develop the September 2022 OFPC. After running 6
the model, PacifiCorp compared the results to a forecast of its dynamic annual 7
allocation of NOx allowances for Utah and Wyoming based on operations in earlier 8
years. 9
Q. Please describe how the annual allocation of NOx allowances would work under 10
the proposed rule. 11
A. The proposed rule calls for dynamic budgeting of NOx allowances in 2025 and beyond, 12
with available allowances allocated among resources within a state based on the recent 13
historical heat input and emissions rates of each resource. Under EPA’s proposed rule, 14
the forecasted allocation of NOx allowances drops significantly in 2026, as EPA 15
assumed that selective catalytic reduction (“SCR”) installations at eligible facilities 16
would significantly reduce emissions by that year. PacifiCorp’s thermal facilities in 17
Utah and Wyoming would be covered by the rule. 18
While trading of NOx allowances among participating states is allowed, the 19
proposed Ozone Transport Rule includes significant penalties if a state’s emissions 20
exceed 121 percent of its annual allocation, including three-for-one allowance 21
surrender for emissions in excess of 121 percent. Limited banking of NOx allowances 22
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is also allowed, but emissions met via banked allowances may also be subject to 1
penalties if a state’s emissions exceed 121 percent of its annual allocation. To avoid 2
such penalties, PacifiCorp’s NOx emissions during the ozone season (May-September) 3
in each state cannot exceed 121 percent of PacifiCorp’s forecasted allocation of NOx 4
allowances for that state. 5
Q. Please describe how PacifiCorp developed NOx allowance requirements for each 6
of its units. 7
A. In general, an allowance for one ton of NOx emissions would allow the holder of the 8
allowance to emit one ton of NOx. However, starting in 2027,12 the proposed Ozone 9
Transport Rule also imposes a daily NOx emissions rate limit of 0.14 lb/MMBtu for 10
each coal-fired facility, and requires emitters to provide an equivalent of triple 11
allowances for any emissions that exceed that rate. For example, a resource with an 12
emissions rate of 0.20 lb/MMBtu would have an effective allowance requirement 13
equivalent to an emissions rate of 0.32 lb/MMBtu.13 In order to calculate PacifiCorp’s 14
NOx allowance requirements under the Ozone Transport Rule, starting in 2027 the 15
modeled emission rates for coal resources whose emissions exceed 0.14 lb/MMBTU 16
were grossed up to account for the additional surrender of allowances. Note that 17
incremental allowances do not count toward the 121 percent state emissions limit, 18
which is based on actual emissions, and not allowance requirements. 19

12 Coal units that currently have SCR installed must meet the daily backstop limit in 2024. Coal units that do not
currently have SCR installed must meet the daily backstop limit in 2027.
13 Effective allowance requirement for resource with emissions rate of 0.20 lb/MMBTU: 100% * 0.20 lb/MMBtu
+ 200% * (0.20 – 0.14) lb/MMBtu = 100% *0.20 + 200% * 0.06 = 0.32 lb/MMBtu.
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Q. Please describe how PacifiCorp’s modeling represents its NOx allowance 1
requirements. 2
A. PacifiCorp’s September 2022 market price forecasts incorporate a regional NOx 3
allowance price, and this price is incorporated in several ways. First, PacifiCorp 4
calculated its share of EPA’s proposed allowance allocation for Utah and Wyoming in 5
2023 and 2024, and a projection of its share thereafter. To the extent emissions in a 6
state are projected to exceed 121 percent of its estimated allocation, any incremental 7
emissions are assumed to be subject to the three-for-one allowance surrender 8
requirement, which is reflected in a cost per ton that is three times the 9
September 2022 allowance price forecast. Because the state limits are based on 10
emissions, the modeled emissions rates are not grossed-up starting in 2027 as described 11
above. In addition, to the extent that overall allowances (not emissions) exceed 12
100 percent of PacifiCorp’s projected allocation, then any incremental allowances are 13
assumed to have a cost per ton that is equal to the September 2022 allowance price 14
forecast. Because the PacifiCorp total requirement is based on allowances (not 15
emissions), a distinct emissions rate is modeled which is grossed-up for emissions over 16
0.14 lb/MMBtu starting in 2027 as described above. 17
Under EPA’s proposed rule, PacifiCorp will receive specified free allowances in 18
2023 and 2024. Starting in 2025 PacifiCorp will receive free allowances that are 19
dynamically calculated based on heat input and emissions rates two years prior. Said 20
another way, heat input and emissions that require an allowance today will result in a 21
share of future allowances two calendar years later. The net present value of each unit’s 22
current year allowance requirement and its share of future year allowances is translated 23
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into an effective emissions rate for dispatch, ensuring that resources that will yield 1
higher future benefits are dispatched ahead of those with lower future benefits, to the 2
extent that those benefits outweigh any difference in fuel and variable costs. 3
Q. Please describe how PacifiCorp’s NOx allowance requirements are incorporated 4
in the reported system cost results. 5
A. The dynamic nature of the proposed Ozone Transport Rule complicates the modeling, 6
because the feedback from prior year dispatch decisions is difficult to incorporate. 7
However, after a study is complete, it is possible to calculate allowance needs and 8
future year allowance allocations that are specific to the dispatch and emissions results 9
in that study. Allowance requirements (inclusive of the gross-up for emissions over 10
0.14 lb/MMBTU starting in 2027) are summed up, and two additional allowances are 11
added for any emissions in excess of 121 percent of the dynamically calculated 12
emissions requirement for each state. After subtracting off the allowance allocation, 13
unused allowances are banked up to the specified limits, and any remaining allowances 14
are assumed to be sold at the September 2022 forecast of the allowance price. If the 15
allowance allocation is lower than the allowance requirement, banked allowances are 16
used and the remaining balance is assumed to be purchased at the September 2022 17
forecast of the allowance price. 18
VII. MODELING METHODOLOGY 19
Q. Please describe the modeling methodology PacifiCorp used in its analysis of B2H. 20
A. PacifiCorp calculated a system present-value revenue requirement (“PVRR”) by 21
identifying least-cost resource portfolios and dispatching system resources through 22
2042, which aligns with the 20-year forecast period used in PacifiCorp’s forthcoming 23
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2023 IRP. Net customer benefits are calculated as the present-value revenue 1
requirement differential (“PVRR(d)”) between different simulations of PacifiCorp’s 2
system. One simulation includes B2H and the other simulation excludes it, and the 3
resulting differences in PacifiCorp’s modeled transmission rights between the two 4
simulations are summarized in Table 2 below. 5
Table 2. Modeled Transmission Associated with B2H 6
Maximum Transfer Capability (MW) No B2H With B2H 
B2H Transfers     
Existing PAC Westbound 1090 1090 
IPC PTP Westbound 510 510 
B2H Westbound 0 818 
Total Westbound 1600 2418 

IPC PTP Eastbound 100 300 
B2H Eastbound 0 300 
Total Eastbound 100 600 
IPC Asset Transfer     
Borah to Hemingway Westbound n/a To PacifiCorp 
Borah to Hemingway Eastbound n/a To PacifiCorp 
To Goshen (BPA load service) n/a To IPC 
Borah to Four Corners Southbound n/a To IPC 
Borah to Four Corners Northbound n/a To IPC  
Central Oregon Load Service     
Southbound to Central Oregon load 340 340 
Northbound to Central Oregon load 340 340 
Enabled by: 
Southern Oregon 
Battery & 
implementation of 
flow‐based 
scheduling 
B2H 
Total Central Oregon 680 680 

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Longhorn Area Load Service     
West to Longhorn area load 100%* 300 
East to Longhorn area load 0 818 
*Longhorn load is confidential.  The associated costs are identified in Confidential 
Exhibit 2.  

Q. Why is PacifiCorp’s share of B2H westbound capacity higher than its subscribed 1
allocation of 600 MW? 2
A. The unsubscribed portion of B2H westbound capacity will be allocated between 3
PacifiCorp and IPC based on their respective shares of the overall project. The value 4
of 818 MW in Table 2 includes PacifiCorp’s share of that unsubscribed capacity. 5
Q. Please describe the costs associated with the B2H transfer capability summarized 6
above. 7
A. The cost of B2H, including associated equipment such as the Midline series 8
compensation, is the largest element. While this cost will be included in PacifiCorp’s 9
rate base, it will also be recovered from third-party transmission customers of 10
PacifiCorp Transmission, as part of its Open Access Transmission Tariff (“OATT”) 11
and annual formula rate update. As a result, approximately 80 percent of these costs 12
are expected to be recovered from PacifiCorp’s retail customers. This same percentage 13
applies to all transmission upgrade options evaluated in PacifiCorp’s IRP modeling. In 14
the same way, because PacifiCorp uses IPC point-to-point (“PTP”) transmission 15
service to serve its retail customers, it will also pay for a portion of IPC’s costs for the 16
B2H project, through IPC’s OATT rates and annual formula rate update process. This 17
will be reflected in the rates for PacifiCorp’s existing PTP reservations, and in the 18
pending reservations that will be granted contingent upon B2H going into service. 19
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Unlike transmission capital costs for PacifiCorp-owned assets, which are partly 1
recovered through OATT rates, the expense for third-party wheeling reservations is 2
part of NPC and is recovered from PacifiCorp’s retail customers only. 3
Q. Please describe the costs associated with the IPC asset transfers summarized 4
above. 5
A. PacifiCorp does not have sufficient available transfer capability from its PacifiCorp 6
East BAA at Borah to the southern terminus of B2H at Hemingway. To access the 7
incremental transfer capability associated with B2H, PacifiCorp is negotiating an asset 8
transfer with IPC. Many of the associated transmission assets between Borah and 9
Hemingway are already jointly owned by PacifiCorp and IPC, and PacifiCorp would 10
receive a greater share both eastbound and westbound that is in line with its share of 11
the transfer capability associated with the Project itself. In return, IPC would receive 12
a share of transmission assets to provide bidirectional rights between Borah and Four 13
Corners, as well as to reach BPA loads in the Goshen area. As a result of the transfer, 14
BPA would take transmission service from IPC, rather than PacifiCorp, which would 15
result in a loss of OATT transmission revenue for the Company. The associated change 16
in long-term transmission reservations would flow through PacifiCorp’s annual 17
formula rate update and result in higher OATT rates. While PacifiCorp’s retail 18
customers would be a larger share of the remaining long-term reservations, it is still 19
projected to be approximately 80 percent of the total. As a result, 80 percent of the lost 20
revenue from BPA would be attributable to PacifiCorp retail customers, and the 21
remainder would be collected from remaining OATT customers. 22

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Q. Please describe the costs associated with the central Oregon load service as 1
summarized above. 2
A. PacifiCorp currently has rights to serve up to 340 MW of central Oregon load via 3
transfers on the Buckley-Summerlake 500-kV line either northbound or southbound. 4
Because of growing loads in central Oregon, PacifiCorp is seeking to serve up to 5
680 MW of central Oregon load by scheduling both northbound and southbound 6
concurrently, each at up to 340 MW. To provide this service, a series capacitor bank 7
will be required at the Meridian substation, either with or without B2H being placed in 8
service. 9
With B2H in service, no additional transmission upgrades would be required; 10
however, PacifiCorp would be able to consolidate certain PTP reservations on BPA’s 11
system that are used to reach central Oregon loads, resulting in a reduction in its BPA 12
wheeling expense. Because the expense for third-party wheeling reservations is part of 13
NPC, one hundred percent of these savings would be attributed to PacifiCorp’s retail 14
customers. 15
In the absence of B2H, providing this level of central Oregon load service 16
would require at least 725 MW of dispatchable generation in southern Oregon.14 This 17
dispatchable generation in southern Oregon would need to be deployed when power 18
flows from PacifiCorp to central Oregon loads across paths operated by BPA exceeded 19
specified levels. As this is based on regional load and resource conditions, which are 20

14 A non-wires analysis performed by BPA, IPC, and PacifiCorp indicated that obtaining 680 MW of central
Oregon load service capability in the absence of B2H would require dispatchable generation in Southern
Oregon ranging from 725 MW to 1,450 MW to prevent impacts to other existing rated paths.
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likely to evolve over time, there is no specific duration that can be assured of 1
maintaining central Oregon load service at 680 MW. For this analysis, the No B2H 2
case included an additional 725 MW of eight-hour battery storage with estimated 3
annual fixed costs of $230 million in 2027, after accounting for the 30 percent 4
investment tax credit available to energy storage resources in the IRA. Because the 5
IRP analysis only includes PacifiCorp’s transmission rights and forecasted usage, it 6
cannot identify periods in which dispatchable southern Oregon generation would need 7
to be deployed to address flows on regional transmission paths. Given this uncertainty, 8
the battery storage duration was increased to eight hours from the four-hour assumption 9
used for this element of the analysis in the 2021 IRP and the 2021 IRP Update. 10
Considering these uncertainties, the 725 MW storage resource was not assumed to be 11
available for economic dispatch within the PLEXOS model. 12
Q. Please describe the costs associated with the Longhorn area load service 13
summarized above. 14
A. PacifiCorp’s load in the vicinity of the Longhorn substation is anticipated to grow 15
significantly. Serving this load will require PTP transmission service with BPA, 16
Portland General Electric (“PGE”), and/or Umatilla Electric Cooperative (“UEC”). 17
The expense for such third-party wheeling reservations is part of NPC, so one hundred 18
percent of these costs would be attributed to PacifiCorp’s retail customers. Because of 19
their location in proximity to B2H, these loads could instead be served via a connection 20
to B2H. Once B2H is completed, such a connection is forecasted to be in service in 21
May 2027, and when it is in place, third-party PTP transmission service would no 22
longer be required. Because the transmission system costs would be recovered as part 23
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of PacifiCorp’s OATT and annual formula rate update, approximately 80 percent of 1
these costs are expected to be recovered from PacifiCorp’s retail customers. 2
Q. Please describe how third-party transmission expenses and revenues are 3
calculated. 4
A. Table 3 below summarizes the assumptions used for each of the third-party 5
transmission providers as well as PacifiCorp’s revenue from BPA, under its OATT. 6
The rates for PGE and UEC are relatively straightforward, reflecting escalation of the 7
current rates at inflation. The rates for BPA reflect escalation of its current PTP and 8
Schedule 1 rates (Scheduling, System Control and Dispatch) at 3.75 percent per year 9
(7.5 percent over each two-year rate-effective period). The cost for BPA reservations 10
is reduced by applicable short-distance discounts. For IPC and PacifiCorp, formula 11
rate calculations also incorporate adjustments to include the cost of B2H (for both) and 12
Gateway South (“GWS”) for PacifiCorp, as these major transmission investments 13
appreciably increase these rates. In addition, the formula rate calculations for both IPC 14
and PacifiCorp are also adjusted for changes in long-term contractual demand, adding 15
PacifiCorp’s additional PTP reservations to IPC’s calculation and removing BPA’s 16
load from PacifiCorp’s calculation. 17
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Table 3: Third-party Transmission Service Assumptions 1
Provider Service Schedules Escalation  
Adjusted 
Rate Base Adjusted Demand 
BPA PTP+SCHED PTP+ACS 3.75% n/a n/a 
PGE PTP 7 2.27% n/a n/a 
UEC PTP 11 2.27% n/a n/a 
IPC No B2H PTP 7 2.27% n/a +100 MW 
IPC w/ B2H PTP 7 2.27% +B2H +100 MW 
PAC No B2H NITS NITS 2.27% +GWS n/a 
PAC w/ B2H NITS NITS 2.27% +GWS+B2H ‐314 MW 

Q. What modeling tool did PacifiCorp use to evaluate the B2H project? 2
A. Consistent with the 2021 IRP modeling, PacifiCorp used the PLEXOS model. 3
Q. Please describe the PLEXOS model. 4
A. The PLEXOS model provides three platforms of the PLEXOS tool (referred to as 5
long-term (“LT”), medium-term (“MT”) and short-term (“ST”)), which work on an 6
integrated basis to inform the optimal combination of resources by type, timing, size, 7
and location over PacifiCorp’s 20-year planning horizon. The PLEXOS tool also 8
allows for endogenous modeling of resource options simultaneously, greatly reducing 9
the volume of individual portfolios needed to evaluate impacts of varying resource 10
decisions. 11
Q. Please describe how PacifiCorp used the LT model. 12
A. PacifiCorp used the LT model to produce a unique resource portfolio under MM 13
price-policy conditions. The LT model portfolio is informed by an hourly review of 14
reliability based on ST model simulations (described below). This ensures that each 15
portfolio meets minimum reliability criteria in all hours. While the 2021 IRP and 16
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2021 IRP Update both assumed that B2H would enable 600 MW of generator 1
interconnection capability, recent generator interconnection study results do not 2
indicate that the B2H project is directly required for pending interconnection requests. 3
Therefore, PacifiCorp did not assume any generating resources would be enabled by 4
B2H and did not make any resource changes between cases that included B2H and 5
cases without it. While there are currently no pending interconnection requests that 6
require B2H, future interconnection requests in the vicinity of B2H could still be 7
contingent upon its completion. 8
Q. Please describe how PacifiCorp used the MT model. 9
A. PacifiCorp used the MT model to perform stochastic risk analysis of the portfolios. 10
Each portfolio was evaluated for cost and risk for each price-policy scenario. A primary 11
function of the MT model is to calculate an optimized risk-adjustment, representing the 12
relative risk of a portfolio under unfavorable stochastic conditions for that portfolio. 13
Q. Please describe how PacifiCorp used the ST model. 14
A. PacifiCorp used the ST model to evaluate each portfolio to establish system costs over 15
the entire 20-year planning period. The ST model accounts for resource availability and 16
system requirements at an hourly level, producing reliability and resource value 17
outcomes as well as a PVRR, which serves as the basis for selecting least-cost, least-18
risk portfolios. As noted above, ST model simulations were also used to identify the 19
potential need for resources in the portfolio to maintain system reliability. 20

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Q. How did each of the three PLEXOS models work together to inform the economic
analysis presented here?
A. In the first step, a resource portfolio without B2H was developed using the LT model. 1
The LT model operates by minimizing operating costs for existing and prospective new 2
resources, subject to system load balance, reliability, and other constraints. Over the 3
20-year planning horizon, the model optimizes resource additions subject to resource 4
costs and load constraints. These constraints include seasonal loads, operating reserves, 5
and regulation reserves plus a minimum capacity reserve margin for each load area 6
represented in the model. 7
To accomplish these optimization objectives, the LT model performs a 8
least-cost dispatch for existing and potential planned generation, while considering cost 9
and performance of existing contracts and new demand-side management (“DSM”) 10
alternatives within PacifiCorp’s transmission system. Resource dispatch is based on 11
representative data blocks for each of the 12 months of every year. Dispatch also 12
determines optimal electricity flows between zones and includes spot market 13
transactions for system balancing. The model minimizes the system PVRR, which 14
includes the net present-value cost of existing contracts, market purchase costs, market 15
sale revenues, generation costs (fuel, fixed and variable operation and maintenance, 16
decommissioning, emissions, unserved energy, and unmet capacity), costs of DSM 17
resources, amortized capital costs for existing coal resources and potential new 18
resources, and costs for potential transmission upgrades. 19
Each portfolio developed by the LT model must have sufficient capacity to be 20
reliable over the IRP’s 20-year planning horizon. The resource portfolios reflect a 21
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combination of planning assumptions such as resource retirements, CO2 prices, 1
wholesale power and natural gas prices, load growth net of assumed private generation 2
penetration levels, cost and performance attributes of potential transmission upgrades, 3
and new and existing resource cost and performance data, including assumptions for 4
new supply-side resources and incremental DSM resources. 5
Q. What is the next step in the modeling process? 6
A. In the second step, the Company conducted a reliability assessment using the ST model. 7
The ST model begins with a portfolio of resources and transmission from the LT model 8
that has not yet benefited from a reliability assessment conducted at an hourly level. 9
The ST model is first run at an hourly level for 20 years in order to retrieve two critical 10
pieces of data: 1) shortfalls by hour; and 2) the value of every potential resource to the 11
system. This information is then used to determine the most cost-effective resource 12
additions needed to meet reliability shortfalls, leading to a reliability-modified 13
portfolio. The ST model is then run again with the modified portfolio to calculate an 14
initial PVRR, which is risk-adjusted by outcomes of MT model stochastics that occurs 15
in the third step of the process. 16
Q. Please describe how the MT model is used to conduct cost and risk analysis. 17
A. In the third step, the resource portfolios developed by the LT model and adjusted for 18
reliability by the ST model are simulated in the MT model to produce metrics that 19
support comparative cost and risk analysis among the different resource portfolio 20
alternatives. The stochastic simulation in the MT model produces a dispatch solution 21
that accounts for chronological commitment and dispatch constraints. The MT 22
simulation incorporates stochastic risk in its production cost estimates by using the 23
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Monte Carlo sampling of stochastic variables, which include load, wholesale electricity 1
and natural gas prices, hydro generation, and thermal unit outages. The MT results are 2
used to calculate a risk adjustment which is combined with ST model system costs to 3
achieve a final risk-adjusted PVRR. 4
Q. Is the PLEXOS model appropriate for analyzing the customer benefits of B2H? 5
A. Yes. The PLEXOS model is the appropriate modeling tool when evaluating significant 6
capital investments that influence PacifiCorp’s portfolio and affect least-cost dispatch 7
of system resources. The LT model is needed to understand how the type, timing, and 8
location of future resources might be coordinated to cost-effectively serve customer 9
load. The ST and MT models provide additional granularity on how B2H is projected 10
to affect system operations, including its impact on stochastic risks. Together, the LT, 11
MT, and ST models are well suited to perform a benefit analysis for B2H that is 12
consistent with long-standing least-cost, least-risk planning principles applied in 13
PacifiCorp’s IRP and resource procurement activities. 14
Q. When developing resource portfolios with the PLEXOS model, did you perform 15
a reliability assessment? 16
A. Yes. As described above, the ST model was used to establish system costs for the entire 17
20-year planning period. The ST model accounts for resource availability and system 18
requirements at an hourly level, producing reliability and resource value outcomes that 19
will reveal whether an initially reliable portfolio selected by the LT model leaves 20
shortfalls at an hourly level, which can then be addressed. 21
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Q. Did PacifiCorp analyze how other assumptions affect its economic analysis of the 1
B2H project? 2
A. Yes. PacifiCorp analyzed the B2H project under four price-policy scenarios. 3
VII. PRICE-POLICY SCENARIO RESULTS 4
Q. Please summarize the PVRR(d) results calculated from the PLEXOS model. 5
A. Table 4 summarizes the risk-adjusted PVRR(d) results for each price-policy scenario. 6
The data that was used to calculate the PVRR(d) results shown in the table are provided 7
as Confidential Exhibit No. 2 8
Table 4. PVRR(d) Cost/(Benefit) of B2H ($ million), 2023-2042 9
Price-
Policy
Scenario
B2H
Asset and
Reservation
Exchange
System
Dispatch
Impacts
Central
Oregon Load
Service
Longhorn
Area Load
Service
Total
MM $454 $308 ($520) ($1,811) ($143) ($1,713)
MN $454 $308 ($594) ($1,811) ($143) ($1,786)
LN $454 $308 ($488) ($1,811) ($143) ($1,680)
HH $454 $308 ($295) ($1,811) ($143) ($1,487)

As shown above, system costs are lower when B2H is included in the portfolio 10
in all price-policy scenarios. The majority of the benefits are derived from the fixed 11
cost of providing central Oregon load service, which are substantially lower as a result 12
of B2H being placed into service. Both central Oregon load service and Longhorn area 13
load service are solely comprised of fixed costs that are not impacted by system 14
dispatch or the price-policy scenario assumptions. 15
Q. How do system costs change with and without B2H over time? 16
A. Figure 5 summarizes changes in system costs, based on ST model results using MM 17
price-policy assumptions, when B2H is eliminated from the portfolio. The graph shows 18
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annual net changes in fixed and variable costs and the cumulative PVRR(d) of changes 1
to net system costs over time (the dashed black line). Through 2042, the PVRR(d) 2
shows that the portfolio that includes B2H is $1,649 million lower cost than the 3
portfolio without B2H, before accounting for risk. 4
Figure 5. Increase/(Decrease) in System Costs when B2H is Included in the Portfolio 5
($ millions) Medium Gas/Medium CO2 6

IX. ANNUAL REVENUE REQUIREMENT 7
Q. In addition to the modeling used to calculate present-value net benefits over a 8
20-year planning period, has PacifiCorp forecasted the change in nominal revenue 9
requirement due to B2H? 10
A. Yes. The system PVRR from the PLEXOS model was calculated from an annual stream 11
of forecasted revenue requirement over the period 2023 through 2042. The annual 12
stream of forecasted revenue requirement captures nominal revenue requirement for 13
non-capital items (i.e., NPC, fixed operations and maintenance, PTCs, etc.) and 14
levelized revenue requirement for capital expenditures. To estimate the annual revenue-15
($1,649)
($1,800)
($1,600)
($1,400)
($1,200)
($1,000)
($800)
($600)
($400)
($200)
$0
$200
20
2
3
20
2
4
20
2
5
20
2
6
20
2
7
20
2
8
20
2
9
20
3
0
20
3
1
20
3
2
20
3
3
20
3
4
20
3
5
20
3
6
20
3
7
20
3
8
20
3
9
20
4
0
20
4
1
20
4
2
Net Difference In Total System Cost
Variable Fixed Cumulative PVRR(d)
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requirement impacts of B2H, capital costs need to be considered in nominal terms (i.e., 1
not levelized). 2

Q. Why is the capital revenue requirement used in the calculation of the system 3
PVRR from the PLEXOS model levelized? 4
A. Levelization of capital revenue requirement is necessary in these models to avoid 5
potential distortions in the economic analysis of capital-intensive assets that have 6
different lives and in-service dates. Without levelization, this potential distortion is 7
driven by how capital costs are included in rate base over time. Capital revenue 8
requirement is generally highest in the first year an asset is placed in service and 9
declines over time as the asset depreciates. In the context of long-term resource 10
planning that is conducted over a finite planning horizon, this can inappropriately favor 11
less capital-intensive assets or assets with longer lives even if those assets might 12
increase system costs over their remaining life. 13
Q. How did PacifiCorp forecast the annual revenue-requirement impacts of B2H? 14
A. For each simulation, the annual stream of levelized revenue requirement associated 15
with the initial capital for each resource and transmission addition, including B2H, is 16
recalculated as a nominal revenue requirement through 2042, which aligns with the 17
modeled study horizon. Since this change only applies to the cost stream associated 18
with initial capital, all other costs that are part of the annual revenue requirement (e.g. 19
fuel, market transactions, emissions), are unchanged from the modeled results. 20
Q. Please describe the change in annual nominal revenue requirement from B2H. 21
A. Figure 6 shows the estimated change in annual nominal-revenue requirement due to 22
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B2H for the MM price-policy scenario on a total-system basis. The annual revenue 1
requirement shown in the figure reflects all costs for B2H, including capital revenue 2
requirement (i.e., depreciation, return, income taxes, and property taxes), operations 3
and maintenance expenses, net of avoided transmission costs, changes to wheeling 4
expenses and revenues, and transmission revenue credits. The project costs are netted 5
against system impacts of B2H, reflecting the change in NPC, emissions, non-NPC 6
variable costs, and system fixed costs that are enabled by, but not directly associated 7
with, the incremental transfer capability from B2H. 8
Figure 6. Total-System Change in Annual Revenue Requirement 9
Due to B2H ($ million) 10

In 2027, the first full year that B2H is in service, the total-system nominal 11
revenue requirement decreases by $254 million. Thereafter, while the net change in 12
revenue requirement from year to year shows modest variation, B2H continues to 13
enable a lower overall revenue requirement through the end of the study horizon. 14

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Rocky Mountain Power

X. AGREEMENTS RELATED TO B2H 1
Q. Do agreements relating to B2H remain outstanding? 2
A. Yes. As relevant to my testimony, there are several agreements between PacifiCorp’s 3
merchant function and IPC and BPA. First, the following transmission service requests 4
will be executed or changes to existing transmission services agreements will be made: 5
 IPC will acquire from BPA 500 MW of PTP transmission service from 6
Mid-C to Longhorn, 7
 PacifiCorp will renew its 510 MW of PTP transmission service from IPC, 8
as shown in the line-item Idaho Power PTP Westbound in Table 2, 9
Second, BPA will redirect and then assign to PacifiCorp 200 MW of PTP 10
transmission rights it holds on IPC’s system. In particular, upon B2H energization, 11
BPA has agreed to submit redirect requests to IPC for BPA’s two existing 100 MW 12
conditional firm PTP service agreements on IPC’s system, with each having a new 13
point of receipt of Walla Walla and a new point of delivery of Borah. Once the redirects 14
have been approved and granted by IPC, BPA will assign the redirected service 15
agreements to PacifiCorp. This is reflected in Table 2 in the 200 MW increase in the 16
line-item IPC PTP eastbound. 17
Third, PacifiCorp and BPA will amend the Midpoint-Meridian Agreement to 18
remove PacifiCorp’s legacy scheduling rights over Buckley-Summerlake 500-kV line 19
(North-to-South or South-to-North for up to 340 MW), thereby facilitating the revisions 20
to the PTP service discussed below. This is reflected in Table 2 in the central Oregon 21
load service section. 22
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Rocky Mountain Power

Fourth, PacifiCorp will update multiple PTP service agreements with BPA to 1
reflect expansion of its central Oregon load service. The revisions will accommodate, 2
upon B2H energization, 680 MW of firm PTP transmission rights into PacifiCorp’s 3
230-kV system at points of delivery at Ponderosa 230-kV and Pilot Butte 230-kV. This 4
is reflected in Table 2 in the central Oregon load service section. 5
XI. CONCLUSION 6
Q. Please summarize the conclusions of your direct testimony. 7
A. PacifiCorp’s analysis shows that B2H is necessary and in the public interest, supporting 8
the issuance of the requested CPCN. 9
Q. Does this conclude your direct testimony? 10
A. Yes. 11
Exhibit No. 1
Contract No. 22TX-17207
TERM SHEET
THIS TERM SHEET IS INTENDED SOLELY TO FACILITATE DISCUSSIONS
AMONG IDAHO POWER COMPANY (“IDAHO POWER” or “IPC”), PACIFICORP
(“PACIFICORP” or “PAC”), AND THE BONNEVILLE POWER ADMINISTRATION
(“BPA”) (EACH REFERRED TO HEREIN AS A “PARTY” AND COLLECTIVELY
REFERRED TO HEREIN AS THE “PARTIES”) RELATED TO THE
CONSTRUCTION, OWNERSHIP, OPERATION, ASSET EXCHANGES, AND
SERVICE AGREEMENTS REGARDING THE BOARDMAN TO HEMINGWAY
TRANSMISSION LINE PROJECT (“B2H PROJECT” OR “PROJECT”) AND OTHER
TRANSMISSION FACILITIES. EXCEPT FOR SECTION 5 OF THIS TERM SHEET
WHICH SHALL BE LEGALLY BINDING UPON THE PARTIES UPON THE
EXECUTION AND DELIVERY OF THIS TERM SHEET BY ALL OF THE PARTIES
(THE “EFFECTIVE DATE”), (I) THIS TERM SHEET IS NOT INTENDED TO
CREATE, NOR SHALL IT BE DEEMED TO CREATE, A LEGALLY BINDING OR
ENFORCEABLE AGREEMENT OR OFFER, AND (II) NO PARTY SHALL HAVE
ANY LEGAL OBLIGATION WHATSOEVER PURSUANT TO THIS TERM SHEET.
1. BPA Requirements. The Parties acknowledge and agree that in order to
negotiate the Agreements (as defined below) and before BPA can make a
definitive final decision regarding whether to enter into the Agreements, BPA
must (1) engage in customer and stakeholder outreach, share information about
this Term Sheet during the outreach, and solicit feedback; (2) fulfill all
requirements under the National Environmental Policy Act (NEPA), the
National Historic Preservation Act (NHPA) and other applicable environmental
laws, and (3) make a definitive decision in an Administrator’s final record of
decision. Nothing in this Term Sheet shall be construed as indicating that BPA
has engaged in customer and stakeholder outreach; completed its NEPA and
other environmental review processes or made a decision regarding how to
proceed.
2. Term.This Term Sheet shall terminate the earlier of (a) energization of the
B2H Project, or (b) execution of all agreements identified in the Term Sheet, or
(c) mutual written agreement of all Parties. This Term Sheet may be extended
by mutual written agreement of all Parties.
3. Agreements. Upon execution of this Term Sheet, the Parties intend to
negotiate in good faith toward the execution of the definitive, binding
agreements and amendments between or among the Parties described below
consistent with the terms and conditions described below (“Agreements”).
Each of the Parties intends to prepare and deliver to the other Parties initial
drafts of the Agreements it is designated as responsible for below by no later
than the date identified for each agreement. The Parties further intend, subject
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to the BPA requirements in Section 1, that they will endeavor to complete
negotiation of and execute the Agreements by no later than the date identified
for each agreement;provided, however, that the effectiveness of any such
Agreement may be subject to one or more conditions precedent, including state
or federal regulatory approvals.
a) Asset Exchanges, Transmission Service Agreements, and Amended and
Restated Existing and Future Agreements: The table below defines the transactions
contingent on completion of the B2H Project including, without limitation, regulatory
approval associated with IPC’s acquisition of BPA’s interest in the Amended and Restated
Boardman to Hemingway Transmission Project Joint Permit Funding Agreement (“Joint
Permitting Agreement”), asset exchanges, transmission service agreements, and amended
and restated existing and future agreements. Each of the Parties will prepare an initial draft
of the Agreements and Amendments below for which it is designated as the Primary
Drafter, consistent with the following terms:
Parties / Agreement /
Action / Primary Drafter
General Terms / Details
1. PAC, BPA
Agreement on Principles
and Timelines
Prepare First Draft –
BPA: Quarter 2 of
Calendar Year 2022
Target Execution Date:
Quarter 3 of Calendar
Year 2022
PAC and BPA are parties to the Amended and
Restated Midpoint-Meridian Agreement, originally
executed June 1, 1994 (the “Midpoint-Meridian
Agreement”), which provides PAC with 340 MW of
bidirectional scheduling rights over the Buckley-
Summer Lake 500kV line (the “Buckley-
Summer Lake Line”). In connection with the Goshen
Area Asset Exchange (as referenced in Section
3(a)(7) of this table) and the B2H Midline Series
Capacitor Project (as referenced in Section 3(a)(12)
of this table), PAC and BPA are discussing options to
allow PAC the ability to schedule 340 MW from the
Buckley substation to the 500kV side of the
Ponderosa Transformer Bank 500/230 kV #1
(“Ponderosa 500”) and to concurrently schedule 340
MW from the Summer Lake substation to Ponderosa
500 upon energization of the B2H line and the B2H
Midline Series Capacitor Project.
I. Contingent upon the conditions set forth
below, PAC and BPA desire for the
concurrent bidirectional scheduling rights
over the Buckley-Summer Lake line to be
provided as firm point-to-point transmission
service (“PTP service”) pursuant to the terms
and conditions in BPA’s Tariff and rate
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and the B2H Midline Series Capacitor
Project. As of the Effective Date, the PAC
and BPA understand that such PTP service
remains subject to further BPA evaluation.
a. BPA’s offer of PTP service may include
conditions if such conditions are
identified during BPA’s evaluation.
Conditions for PTP service are at BPA’s
sole discretion and, if required, will be
developed consistent with the principles
set forth in Section 3(a)(1)(II)(b) so that
flows associated with the PTP service
over the Buckley-Summer Lake line do
not exceed 340 MW in the north-to-south
direction and concurrently does not
exceed 340 MW in the south-to-north
direction during all lines in service.
b. As part of the PTP service evaluation,
PAC and BPA will also explore options to
combine an offer of PTP service with the
modification to points of receipt and
points of delivery in PAC’s existing PTP
service tables (“redirect”) within the Long
Term Firm Point-to-Point Service
Agreement (No. 04TX-11722) between
PAC and BPA, subject to BPA’s Tariff
and related business practices including
available transfer capability (“ATC”),
with a goal to optimize PAC’s
transmission service over the Federal
transmission system to serve its central
Oregon loads (e.g., using a single wheel
from a network point of receipt to PAC’s
load at Ponderosa 230 or Pilot Butte 230).
BPA will apply its long-standing practice
to evaluate the ATC impacts of the new
PTP service against the ATC impacts of
existing service, to include the
bidirectional scheduling rights and
redirected service.
c. BPA may request additional information
from PAC. PAC will make good faith
efforts to provide such information within
30 days of BPA’s request.
d. PAC will submit applicable transmission
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of BPA’s notice to PAC that such requests
should be submitted.
e. If BPA determines, in its sole discretion,
that BPA can convert the bidirectional
scheduling rights to PTP service, BPA
agrees to offer PTP service pursuant to
BPA’s Tariff and rate schedules.
i. The PTP service will be contingent
upon and will not be effective before
(A) the energization of the B2H line
and the installation of the B2H
Midline Series Capacitor Project; (B)
approval by the Federal Energy
Regulatory Commission (“FERC”) of
the proposed amendments to the
Midpoint-Meridian Agreement
discussed in this Section 3(a)(1), per
subpart (iii below; and (C) the Goshen
Area Asset Exchange set forth in
Section 3(a)(7) of this table is
completed and all associated
agreements are in effect.
ii. PAC and BPA will adhere to the
applicable requirements set forth in
BPA’s Tariff and related business
practices, including timelines for
execution or amendment of a service
agreement.
iii. Concurrent with the execution of the
PTP service agreements contemplated
in this Section 3(a)(1)(I), PAC and
BPA will amend Section 4(a) of the
Midpoint-Meridian Agreement to
remove and otherwise terminate
PAC’s bidirectional scheduling rights
over the Buckley-Summer Lake Line.
f. If BPA offers PTP service that satisfies
PAC’s objectives as expressed in this
Term Sheet, PAC intends to accept such
service subject to the condition regarding
FERC approval described below. If
following FERC acceptance without
material conditions of the arrangements
negotiated between BPA and PAC in this
Section 3(a)(1)(I), PAC nonetheless fails
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declines to accept the PTP service or
execute a PTP service agreement, then
BPA will have no further obligations to
provide PAC with the PTP service
described in this Section 3(a)(1)(I) or the
scheduling rights described in Section
3(a)(1)(II) below.
g. PAC and BPA will negotiate in good faith
to complete and enter into agreements
needed to complete the other conditions
set forth in Sections 3(a)(2) through (14)
and 3(c) of this Term Sheet, as such
conditions are applicable to either Party.
h. PAC will seek FERC guidance as
necessary and file the proposed
amendment to the Midpoint-Meridian
Agreement with FERC for acceptance.
BPA will reasonably coordinate with PAC
to prepare for FERC meetings and
submissions. FERC’s unconditioned
acceptance shall be a condition to PAC’s
obligations as contemplated under this
Term Sheet.
II. Following either (1) BPA’s determination that
it is unable to provide the PTP service to PAC
consistent with Section 3(a)(1)(I) above, or
(2) FERC’s failure to accept without material
conditions the arrangements negotiated
between PAC and BPA under Section
3(a)(1)(I) above, BPA will, effective upon
energization of the B2H line and the B2H
Midline Series Capacitor Project provided
that all conditions described below are met,
provide PAC with bidirectional scheduling
rights over the Buckley-Summer Lake line
which give PAC the ability to (A) schedule
340 MW from the Buckley substation to
Ponderosa 500 (“North to South schedules”)
and (B) concurrently schedule 340 MW from
the Summer Lake substation to Ponderosa
500 (“South to North schedules”)
(collectively referred to as “scheduling
limits”). The concurrent, bidirectional
scheduling rights described in the
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provided pursuant to an amendment to the
Midpoint-Meridian Agreement and one or
more separately negotiated agreements, that
will be effective upon acceptance by FERC
and after all conditions set forth in this
Section 3(a)(1)(II) are met and will remain in
effect until BPA offers PTP service as set
forth in Section 3(a)(1)(I). PAC and BPA
will work in good faith to satisfy all such
conditions consistent with the principles
articulated in Section 3(a)(1)(II)(b) below by
energization of the B2H line.
a. Transmission service to move from the
Ponderosa 500 substation. The utilization
of the concurrent bidirectional scheduling
rights at the Ponderosa substation
described in this Section 3(a)(1)(II) is
limited to Ponderosa 500. PAC must
reserve PTP service from BPA pursuant to
BPA’s Open Access Transmission Tariff
(“OATT”), business practices, and rate
schedules in effect at the time of such
reservation to move from Ponderosa 500
to the 230 kV side of Ponderosa
transformer bank #1 for delivery to PAC
load in central Oregon.
b. Principles to guide satisfaction of
conditions.
i. North to South schedules, South to
North schedules, and the associated
directional power flows may not
exceed the scheduling limits (e.g., 340
MW North to South and, concurrently,
340 MW South to North, under all
lines in service). A Power Transfer
Distribution Factor (“PTDF”) based
methodology (“PTDF algorithm”) and
calculator will be used to determine
directional power flow. The PTDF
algorithm will sum positive flows in
the North to South and South to North
directions (i.e., schedules and flows
are not netted).
ii. If, at any time, North to South
schedules, South to North schedules,
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flows exceed the scheduling limits,
PAC shall reduce the schedules so that
the schedules and directional power
flows are within the scheduling limits.
BPA can, at BPA’s sole discretion,
curtail the schedules in whole or in
part to maintain the scheduling limits
and to mitigate congestion, such as
during outages.
iii. Schedules (E-Tags) must contain a
single granular source and sink.
Sources and sinks (1) cannot be
consolidated on a single E-Tag; and
(2) must be granular enough to
determine the PTDF impact. Sources
and sinks that are scheduling points,
hubs, or nodes are not sufficiently
granular to determine the PTDF
impact.
iv. PAC may not schedule from sources
and sinks for which the PTDF impact
has not been determined. PAC will
provide BPA with advance notice of
sources and sinks with sufficient time
for BPA to determine the PTDF
impact and, if necessary, to
accommodate modifications to tools,
systems, and contracts.
v. The terms, tools, and protocols
associated with the concurrent
bidirectional scheduling rights will be
structured to minimize to the
maximum extent possible any impacts
exceeding the scheduling limits (e.g.,
340 MW North to South and,
concurrently, 340 MW South to North,
under all lines in service) that the
physical flows associated with the
concurrent bidirectional scheduling
rights have on the Pacific Northwest
AC Intertie (as such transmission
facilities are defined in the various
PNW AC Intertie-related agreements
among PAC, BPA and the other PNW
AC Intertie owners, the “NW AC
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system, as reasonably determined by
BPA.
c. Conditions to Effectiveness of 3(a)(1)(II)
Scheduling Rights
i. PTDF calculator. BPA will develop a
PTDF algorithm to calculate the
directional power flow associated with
each source and sink that PAC intends
to schedule. PAC and BPA will
coordinate to develop, at PAC’s
expense, a PTDF calculator that uses
the PTDF algorithm and related
communication equipment.
ii. Agreement on operational terms.
After the PTDF calculator is
developed, PAC and BPA will work in
good faith to develop operational
terms, to include the protocols and
requirements for monitoring, dispatch,
curtailment, reduction of scheduling
limits due to outages, and future
modifications to stay current with
reliability standards, automation, and
technological abilities. The
operational terms will remain in effect
for the duration of the concurrent
bidirectional scheduling rights
described in this Section 3(a)(1)(II)
and will be incorporated into the
proposed amendments to the
Midpoint-Meridian Agreement or such
other agreement as mutually agreed by
PAC and BPA.
iii. Energization of the B2H Project,
including the B2H Midline Series
Capacitor Project.
iv. The agreements set forth in Section
3(a)(1)(III) below are, to the extent
required, accepted for filing at FERC
without material conditions.
v. The Goshen Area Asset Exchange set
forth in Section 3(a)(7) of this table is
completed and all associated
agreements are in effect.
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a. Agreement on Principles and Timelines.
Following execution of the Term Sheet,
PAC and BPA will negotiate and execute
an agreement to reflect the objectives,
commitments, principles, conditions, and
timelines, including negotiation of
applicable follow-on agreements for the
PTP service described in Section
3(a)(1)(I), and the concurrent,
bidirectional scheduling rights described
in Section 3(a)(1)(II). With regard to the
concurrent, bidirectional scheduling rights
described in Section 3(a)(1)(II), the
Agreement on Principles and Timelines
would include the principles and
conditions set forth in Section 3(a)(1)(II)
above, and the timelines for development
of the PTDF calculator and negotiation of
operational terms and protocols.
b. Follow-on Agreements. Before
energization of B2H and subject to the
conditions described above in this Section
3(a)(1) being met, PAC and BPA will
negotiate and execute (1) the agreements
and amendments referenced in Section
3(a)(1)(I) above, or (2) if BPA is not yet
providing PTP service upon B2H
energization consistent with Section
3(a)(1)(I) above, then an amendment to
the Midpoint-Meridian Agreement to
reflect the addition of the concurrent
bidirectional scheduling rights, including
term, scheduling and directional power
flow requirements, usage of the PTDF
calculator, and operational terms, all as
consistent with Section 3(a)(1)(II) above.
PAC and BPA understand that PAC may
be required to file amendments to the
Midpoint-Meridian Agreement with
FERC for acceptance and that the
effective date for the agreements
referenced above will be upon FERC
acceptance without material conditions.
IV. Consistent with the “Phase II Joint Study
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Hemingway (B2H) and Incremental Central
Oregon Load” completed on March 23, 2021,
upon notice from BPA, PAC will upgrade the
existing Meridian Series Capacitor on the 500
kilovolt bus or install an electrically
equivalent series capacitor on the PAC
section of the Dixonville-Meridian-Klamath
Falls-Captain Jack lines in southern Oregon
within a reasonable time after receiving the
notice. PAC shall be responsible for all costs
associated with the upgrade.
V. PAC and BPA agree that the proposed
modifications to the Midpoint-Meridian
Agreement described above are limited in
scope to PAC’s bidirectional scheduling
rights over the Buckley-Summer Lake line
under Section 4 of the Midpoint-Meridian
Agreement and do not include BPA’s
bidirectional scheduling rights over the
Summer-Lake Malin line under Section 4 of
the Midpoint-Meridian Agreement. PAC and
BPA do not intend to modify, change, alter,
or terminate BPA’s bidirectional scheduling
rights over the Summer Lake-Malin line set
forth in Section 4 of the Midpoint-Meridian
Agreement or the General Transfer
Agreement between PAC and BPA, originally
executed May 4, 1982, as amended.
2. IPC & PAC & BPA
New operational
agreement between IPC,
PAC & BPA
Prepare First Draft –
BPA: Quarter 3 of
Calendar Year 2022
Target Execution Date:
Quarter 4 of Calendar
Year 2022
IPC, PAC and BPA agree to negotiate in good faith
and draft a tri-party operational agreement that will:
a. Consider Midpoint-Meridian Agreement
Section 5(f); and
b. Define the curtailment procedures
between NW AC Intertie, Western
Electricity Coordinating Council (WECC)
Path 14 (Idaho to Northwest), and WECC
Path 75 (Hemingway – Summer Lake);
and
c. Identify conditions for revising the tri-
party operational agreement including, but
not limited to:
i. Engagement with NW AC Intertie
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ii. In the event the B2H Project and the
B2H Midline Series Capacitor Project
are not complete and energized by
2027.
The Parties will make best efforts to negotiate and
target execution of the tri-party operational
agreement within one year of the Effective Date of
this Term Sheet, with an effective date for the tri-
party operational agreement a reasonable time
thereafter.
3. PAC & BPA
Termination of Existing
NITSAs:
PAC Trans – BPA
Merchant NITSAs (SA
Nos. 746, 747)
Incorporate into
Agreement on Principles
and Timelines under
3(a)(1)
BPA Network Integration Transmission Service
Agreements (“NITSAs”) (PacifiCorp Service
Agreement No. 746 and No. 747): BPA and PAC
agree to terminate the aforementioned NITSAs upon
(1) the completion of the asset purchase and sale
between IPC and PAC as detailed in Section 3(a)(5)
through Section 3(a)(7) of this table – the Goshen
Area Asset Exchange, and (2) the commencement of
network service as described in Section 3(b)(1).
4. IPC & BPA & PAC
New Agreement:
Longhorn Substation
Agreements
Prepare First Draft –
BPA: Quarter 2 of
Calendar Year 2022
Target Execution Date:
Quarter 3 of Calendar
Year 2022
IPC and PAC will fund a portion of the proposed
Longhorn substation near Boardman, Oregon, if B2H
interconnects at Longhorn. This funding will occur as
specified in one or more negotiated Longhorn
Substation Agreements between the Parties that is
consistent with BPA’s Line and Load
Interconnection Business practices and allows for
recovery of the network portion of these funds
through incremental transmission wheeling revenue.
The agreement will:
a. include provisions for IPC and PAC to
pay a use of facilities charge or other
charge pursuant to BPA’s OATT and
applicable rate schedules to transact across
the Longhorn bus in the future;
b. include provisions for IPC and PAC to
potentially own, operate and maintain
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B2H series capacitor at Longhorn, the
B2H shunt line reactors at Longhorn, any
ancillary equipment required to support
those devices, such as switches, bypass
breakers (series cap), and insertion
breakers (shunt reactor); and
c. be contingent upon BPA completing its
obligations and responsibilities under
NEPA, NHPA, and other requisite
environmental compliance laws and
making a decision regarding how to
proceed (including provisions for IPC and
PAC funding upfront at a prorated amount
based on cost allocation of Longhorn,
BPA’s NEPA, NHPA, and environmental
compliance costs).
Non-binding cost estimates identified for the
potential Longhorn aspects of the B2H Project as of
the Effective Date of this Term Sheet are as follows,
which all Parties acknowledge and agree are
preliminary and may be modified and revised prior to
and upon B2H energization:
These are estimated costs, charges to be trued up
with actual costs.
a. Longhorn (base substation) network costs
~$59M. Costs subject to transmission
credit.
i. IPC 21% ~ $12M (BPA to cover up to
$14M of IPC cost)
ii. PAC 55% ~ $33M
iii. BPA 24% ~ $14M (plus IPC ~ $12M,
for total ~ $26M)
b. B2H connection to Longhorn Network
Bay~$11M.
Constructed/Owned/Maintained by BPA.
Develop bay 3 with (2) 500kV circuit
breakers & (5) 500kV disconnects. Costs
subject to transmission credits.
i. IPC & PAC 100%
c. Customer built (not subject to
transmission credits). Including civil work
with the reactor and cap costs.
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5. IPC & PAC
New Agreement:
Purchase and Sale
Agreement for Asset
Exchange -potentially
utilize the previously
developed Joint
Purchase and Sale
Agreement
Prepare First Draft –
IPC: Quarter 2 of
Calendar Year 2022
Target Execution Date:
Quarter 4 of Calendar
Year 2022
PAC and IPC would purchase and sell to each other
various assets to achieve the objectives identified in
Section 3(a)(6) and Section 3(a)(7) of this table. PAC
and IPC will seek to first balance the purchase and
sale of the transferred assets through the depreciated
net book value of such assets and allocation of
upgrade costs and, finally, if necessary, will be
balanced between IPC and PAC through cash
considerations.
Details related to Populus – Four Corners assets:
These assets will provide IPC ownership on the
existing PAC transmission system from Four Corners
substation in New Mexico to Populus substation in
Idaho. This will include 345 kV transmission lines
between the following substations and assets to
create a path through each substation:
Four Corners, Pinto, Huntington, Camp Williams,
Mona, Terminal, 90th South, Ben Lomond and
Populus.
Consistent with federal processes, IPC and PAC will
complete required studies to determine if recent
system upgrades result in a possible increase in
existing transmission capacity between Borah and
Populus to facilitate IPC’s incremental transfer needs
associated with this exchange. If determined
necessary, IPC and PAC will identify revisions to the
JOOA (as defined in Section 3(a)(6) of this table),
upgrades, modifications, or other options to meet
each party’s commercial needs between Borah and
Populus.
Details related to Borah/Kinport to Hemingway and
Midpoint to Borah/Kinport assets:
These assets will provide PAC ownership on the
existing IPC transmission system from
Borah/Kinport to Hemingway and from Midpoint
500 to Borah/Kinport. This will include 500 kV and
345 kV transmission lines between the following
substations and assets to create a path through each
substation:
Borah, Kinport, Adelaide, Midpoint and Hemingway.
Upgrades are required across the Borah West and
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proposed asset exchange transaction. The cost of
these upgrades will be determined in the course of
negotiating the proposed asset exchange transaction
described in this Section 3(a)(5).
Details related to Goshen Area assets:
As described in more detail in Section 3(a)(7) of this
table, PAC will transfer to IPC certain to-be-
determined Goshen areas transmission assets that
would allow IPC to provide transmission service to
all BPA customers in southeast Idaho currently
served by PAC. These assets are being transferred to
IPC, from PAC, as part of the negotiations between
PAC and BPA as described in Section 3(a)(1) of this
table, with the consideration for these assets being
the transmission service provided by BPA to PAC as
detailed in Section 3(a)(1) of this table. IPC and PAC
intend for these Goshen assets to be incorporated into
the broader purchase and sale agreement described in
this Section 3(a)(5) with a goal of minimizing
changes to each company’s transmission rate base.
This goal is intended to be facilitated through the
allocation of the costs associated with the Borah
West and Midpoint West upgrades.
6. IPC & PAC
Amendment to Existing
Agreement:
IPC – PAC Joint
Ownership and
Operating Agreement
(“JOOA”)
Prepare First Draft –
IPC: Quarter 2 of
Calendar Year 2022
Target Execution Date:
Quarter 4 of Calendar
Year 2022
As part of a transaction transferring assets described
in Section 3(a)(5) of this table, IPC and PAC may
expand their existing Joint Ownership and Operating
Agreement, as amended and restated August 22,
2019 (“JOOA”), to include the following:
I. PAC owning 300 MW of west-to-east
transmission assets between Midpoint 500 and
Borah (transferred from IPC); and
II. PAC owning an additional 600 MW of east-to-
west transmission assets between Borah and
Hemingway (transferred from IPC) - total
increases from the current 1,090 MW to 1,690
MW; and
III. IPC owning 200 MW of bi-directional
transmission assets between Populus, Mona and
Four Corners (transferred from PAC); and
IV. Other revisions as necessary to facilitate other
asset exchanges (e.g., for Goshen area, as
Rocky Mountain Power Exhibit No. 1 Page 14 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Contract No. 22TX-17207 B2H Term Sheet
Page 15 of 32
described in Section 3(a)(5) and Section 3(a)(7)
of this table).
7. IPC & PAC
Goshen Area Asset
Exchange
Part of 3(a)(5)
As referenced in Section 3(a)(5) and Section 3(a)(6)
of this table, IPC and PAC would negotiate an asset
exchange to be effective no later than (i) energization
of the B2H line and (ii) commencement of the
NITSA between BPA and IPC, as referenced in
Section 3(b)(1), that enables BPA to to serve its
loads currently in PAC’s East transmission system
(Lower Valley Elec., Idaho Falls, Fall River Rural
Elec., Lost River Electric, Salmon River Electric,
Soda Springs,) (“Southeast Idaho Load Service
(SILS) Customers”) with one leg of firm IPC
network transmission service.
As referenced in Section 3(a)(6) of this table, the
Goshen area asset exchange may be wrapped into the
existing JOOA framework.
IPC, PAC, and BPA agree to make best efforts to
plan for service to Idaho Falls that requires only one
leg of network transmission from the BPA
transmission system, provided such best efforts
among the Parties must (1) respect and retain the
existing services arranged for Idaho Falls load
service between BPA and Utah Associated Municipal
Power Systems (UAMPS); and (2) be in line with
FERC orders in similar circumstances and accepted
by FERC.
8. IPC & BPA
New Agreement:
Point to Point TSA
Prepare First Draft –
BPA: Quarter 2 of
Calendar Year 2022
Target Execution Date:
Quarter 3 of Calendar
Year 2022
IPC will acquire up to 500 MW of PTP transmission
service from Mid-C to Longhorn subject to the terms
of BPA’s OATT, business practices and applicable
rate schedules. The duration of the new service must
be for an initial service duration of at least 5 years,
and sufficient to compensate BPA for BPA’s revenue
requirement associated with BPA capital investments
to facilitate the transmission service, with the right to
rollover service in accordance with the BPA’s OATT
and business practices in effect at the conclusion of
the initial term.
Rocky Mountain Power Exhibit No. 1 Page 15 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Contract No. 22TX-17207 B2H Term Sheet
Page 16 of 32
9. IPC & PAC Upon energization of the B2H Project, PAC would
not renew its current 510 MW of east-to-west rights
on the IPC system (which rights are found in IPC 1st
Revised Service Agreement (SA) Nos. SAs 344-346
and 383-384).
Consistent with and pursuant to IPC’s OATT, PAC
and IPC will coordinate to extend any remaining IPC
SAs, enter into new SAs, or take other action as
necessary to bridge any SA expiration dates until
such time as the B2H project is in-service.
10. IPC & PAC
B2H Construction
Funding Agreement-
related Commitments
The B2H Construction Funding Agreement, between
IPC and PAC as referenced in Section 3(d) below,
and any additional agreements as the Parties
determine necessary, will include terms necessary to
implement the Agreement to Reimburse BPA’s
Removal and Replacement Related Transaction
Costs, among IPC, PAC and BPA, dated March 18,
2020 (BPA Contract No. 20TX-16835).
IPC, on behalf of the B2H Project, will assure that it
coordinates construction of the B2H Project with
BPA in a manner consistent with the terms of BPA’s
Use Agreement, as amended by Amendment Two (2)
to NF(R)-9617, including Exhibits A, B and C,
between the United States of America, Dept. of the
Navy and the United States of America, Bonneville
Power Administration Ptn Secs 13, 23 and 24-T2N-
R25E, W.M.
IPC and PAC acknowledge that the Removal and
Replacement Related Transactions described in
Contract No. 20TX-16835 are contingent upon (1)
BPA obtaining acceptable service from Umatilla
Electric so that BPA may continue to serve Columbia
Basin Electric’s load; (2) BPA completing its
obligations and responsibilities under NEPA, NHPA,
or other requisite environmental compliance laws and
making a decision regarding how to proceed; and (3)
IPC and PAC moving forward with construction of
the B2H Project.
11. IPC & PAC & BPA In conjunction with the termination of the NITSAs
i.e
Rocky Mountain Power Exhibit No. 1 Page 16 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Contract No. 22TX-17207 B2H Term Sheet
Page 17 of 32
BPA Redirect and
Assignment of existing
PTP transmission
service
Incorporate into
Agreement on Principles
and Timelines under
3(a)(1)
SAs 746 & 747), following the energization of B2H,
BPA will redirect its two 100 MW PTP transmission
service agreements (91629850 and 91629500, or any
applicable AREFs that supersede or replace them)
that it takes from IPC (i.e., IPC 1st Revised SAs 324
& 342) such that the new POR of each SA will be
Walla Walla and the new POD for each SA will be
Borah. Consistent with and pursuant to IPC OATT,
following approval of such redirects by IPC as
described above, BPA will assign those redirected
reservations to PAC. This redirect and assignment
will be delayed by BPA if B2H energization is
delayed past 07/01/2026. PAC shall be responsible
to pay for all costs associated with 91629850 and
91629500, or any applicable AREFs that supersede
or replace them, upon approval of such redirect by
IPC and assignment by BPA.
12. IPC & PAC & BPA,
with respect to B2H Plus
Facilities Expectations
IPC & PAC, with
respect to B2H
Construction Funding
Agreement
The B2H Project will include the installation of the
B2H Midline Series Capacitor Project and
development of a remedial action scheme ("RAS").
When considering BPA’s study methodology, the
B2H midline series capacitor reduces simultaneous
interactions between the NW AC Intertie, central and
southern Oregon load service, and WECC Path 14
(Idaho to Northwest). The Parties agree to funding of
the B2H Midline Series Capacitor Project as follows:
a. IPC: funding 45% of the cost.
b. PAC: funding 55% of the cost
c. BPA: funding 0% of the cost
The Parties will work in good faith to have the B2H
Midline Series Capacitor Project in-service when the
B2H Project is energized and to document
expectations of operation, maintenance, and future
reinforcements and upgrades.
13. IPC & PAC
B2H Grant or
Additional Funding
Under IPC and PAC’s existing OATT rate
procedures, IPC and PAC will include any United
States Department of Energy (“DOE”) grant or
additional funding received for the B2H project in
the appropriate FERC account provided such account
is allocated 100% to Transmission. Nothing in this
Term Sheet limits or waives any party’s right to
Rocky Mountain Power Exhibit No. 1 Page 17 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Contract No. 22TX-17207 B2H Term Sheet
Page 18 of 32
party’s rate case or formula rate inputs through their
respective update processes.
14. IPC & PAC & BPA
Permit Funding
Agreement Amendment
Upon transfer of BPA’s Permitting Interest to IPC
identified in 3(b)(3) below, the Permit Funding
Agreement will be amended to recognize the re-
allocation of the Parties’ Permiting Interests and
related funding obligations.
b) NITSA Terms and Conditions, NITSA Security Agreement, NITSA
Backstop
1. IPC & BPA
New Agreements:
Network Integration
Transmission Service
Agreement to serve BPA
customers at Goshen
Network Integration
Transmission Service
Agreement to service
BPA’s customer at
Burley
Amendment to currently
effective Network
Integration
Transmission Service
Agreements
Prepare First Draft –
IPC: Quarter 2 of
Calendar Year 2022
IPC and BPA will enter into two NITSAs for IPC to
provide firm network transmission service to BPA.
One NITSA will serve BPA customers at Goshen
(replacing what is, as of the Effective Date of this
Term Sheet, provided under PAC Service Agreement
746) and one NITSA will serve Idaho Falls (replacing
what is, as of the Effective Date of this Term Sheet,
provided under PAC Service Agreement 747) (“New
NITSAs”). The New NITSAs will be in addition to the
existing NITSAs BPA currently holds with IPC for
service to BPA’s customers located on IPC’s system
(“Existing NITSAs”).
The term of BPA’s New NITSAs will be 20-years
from energization of the B2H Project, with a renewal
or rollover option at BPA’s discretion as required and
permitted by FERC
a. The NITSA Security Agreement (as referenced
in Section 3(b)(2) of this table), and any related
other agreements necessary, between BPA and
IPC will be updated once the energization of
B2H has occurred to document the term and the
repayment periods with the actual energization
date.
b. The New NITSAs, NITSA Security Agreement,
and any related other agreements necessary, are
conditioned on the Goshen Area Asset
Exchange set forth in Section 3(a)(7) being
completed and all associated agreements being
Rocky Mountain Power Exhibit No. 1 Page 18 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Contract No. 22TX-17207 B2H Term Sheet
Page 19 of 32
Target Execution Date:
Quarter 3 of Calendar
Year 2022 The New NITSAs and the Existing NITSAs will be
updated to include three Points of Receipt (PORs) over
which BPA can deliver energy to its customers located
AMPS POR, LaGrande POR, and Longhorn POR.
The New NITSAs
provisions:
a. Under the New NITSAs, IPC will plan for
continued network service to BPA’s SILS
Customers’
service agreements to PAC
Section 3(a)(11) above.
b. The New NITSAs between BPA and IPC
PODs will be served by a separate NITSA
customer and IPC
Notwithstanding assignment of the NITS
Funded Amounts
3(b)(2) below) as long as BPA continues to
be a NITS customer.
c.
loads. The current PODs include LaGrande
PODs will include
and AMPS.
d. BPA would pay the NT rate as established
Rocky Mountain Power Exhibit No. 1 Page 19 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Contract No. 22TX-17207 B2H Term Sheet
Page 20 of 32
like actions which result in a rate above the
NT rate and the amount BPA pays to IPC
under the NT serv
reduced as discussed in the NITSA
Security Agreement.
e.
resource used to serve load behind Goshen.
2. IPC & BPA
New Agreement:
NITSA Security and
Risk Backstop
Agreement
Prepare First Draft –
IPC: Quarter 2 of
Calendar Year 2022
Target Execution Date:
Quarter 3 of Calendar
Year 2022
IPC and BPA will enter into an NITSA security and
risk backstop agreement (“NITSA Security
Agreement”), concurrently with the New NITSA and
the purchase and sale agreement referenced in Section
3(b)(3) of this table.
Reimbursement If IPC Receives all Permits and
Certificates of Public Convenience and Necessity
(CPCN) for Construction of B2H
IPC will reimburse BPA for the transfer of BPA’s
Permitting Interest under the Joint Permitting
Agreement in an amount consisting of BPA’s
investment in B2H prior to the transfer date (~$25m).
BPA will also pay to IPC an additional $10 million
upon execution of the New NITSAs and the NITSA
Security Agreement with the intent of offsetting
overall B2H project costs in IPC’s rate base. The
additional $10 million plus BPA’s investment in B2H
will be collectively referred to as the “Funded
Amount.”
IPC will retain the Funded Amount as follows:
If and when IPC obtains all necessary CPCNs and
permits for the B2H Project (and all appeals, if any,
have been resolved), IPC shall have until January 1,
2026 (“Commencement Date”) to commence
construction of B2H or to inform BPA of its intent
to not pursue construction of B2H.
(1) If IPC commences construction of B2H
before the Commencement Date, then:
a. Interest on the Funded Amount (~$35m)
payable by IPC to BPA will accrue from
Rocky Mountain Power Exhibit No. 1 Page 20 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Contract No. 22TX-17207 B2H Term Sheet
Page 21 of 32
established in the applicable IPC tariff for
customer funded projects;
b. The Funded Amount and all accrued
interest will be repaid to BPA starting year
11 following the energization date (the
“Refund Commencement Date”), with
repayment amortized over the remaining
10 years of the New NITSAs.
i. IPC and BPA will incorporate
the interest schedule and
payment amortization as an
exhibit to the NITSA Security
Agreement;
ii. If during the term of the New
NITSAs BPA defaults on its
payment obligations under the
New NITSAs, IPC will be
entitled to retain for its own
account an amount equal to the
defaulted payment obligation not
to exceed the amount not
reimbursed to BPA as of the
default date;
iii. BPA will not be considered in
default for any amount not paid
subject to a billing dispute; and
iv. IPC may prepay the Funded
Amount and interest thereon at
any time without penalty.
(2) If IPC does not commence construction of B2H
by or before the Commencement Date or if IPC
informs BPA before the Commencement Date
of its intent to not proceed with B2H, then:
a.
Commencement Date
whichever is earlier) to sell its
Permitting Interests in the B2H Project;
b. No later than the close of the above
mentioned 180 days, IPC shall
i.
from the sale of its Permitting
Interest in the B2H Project (if
Rocky Mountain Power Exhibit No. 1 Page 21 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Contract No. 22TX-17207 B2H Term Sheet
Page 22 of 32
ii. Pay to BPA the $10 million BPA
provided to IPC upon execution
of the New NITSAs.
Risk Backstop if IPC does not Receive all Permits or
CPCNs Necessary for constructing B2H.
If IPC does not obtain all necessary CPCNs and
permits for the B2H Project, or any such CPCNs or
permits are overturned on appeal, then (a) IPC will
return to BPA the $10 million BPA provided to IPC
upon execution of the New NITSAs; and (b) BPA will
reimburse IPC for funding the additional 24.24% share
of all B2H Permitting and Preconstruction Costs
incurred after BPA transfers its 24.24% Permitting
Interest to IPC.
The reimbursement obligation will not include any
costs related to Right of Way option acquisition or
exercising Right of Way Options.
The risk backstop commitment will remain in place
until IPC obtains all necessary CPCNs and permits for
the Project (and all appeals, if any, have been
resolved). The intent of the backstop is only to assist
IPC in mitigating the risk associated with receiving the
approvals for the B2H Project; not to assist in
mitigating business risk.
The risk backstop commitment will be as follows:
a. IPC will not compensate or reimburse
BPA for costs expended by BPA on B2H
prior to the transfer of the Permitting
Interest to IPC (i.e., ~$25m BPA has
expended to date);
b. BPA will reimburse 24.24% of actual
B2H Project Permitting Costs incurred
after IPC takes over funding 45% of the
project. (Current estimates for 2021-2024
– Total B2H Project estimated at
$9,125,466 with 24.24% of these costs
estimated at $2,212,234); and
c. BPA will reimburse 24.24% of actual
B2H Project Pre-Construction Costs
incurred after IPC assumes funding 45%
Rocky Mountain Power Exhibit No. 1 Page 22 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Contract No. 22TX-17207 B2H Term Sheet
Page 23 of 32
2021-2024 – Total B2H Project estimated
at $9,403,564 with 24.24% of these costs
estimated at $2,279,652).
Collectively, these amounts set forth in a. through c.
above will be the “Risk Backstop Amount.”
The Risk Backstop Amount will be adjusted, as
necessary, to the extent that IPC receives grants or
forms of other financial assistance from sources other
than BPA or PAC. For example, if IPC received a
government grant that defrayed the pre-construction
costs of B2H, BPA’s 24.24 % share of the pre-
construction costs would be reduced accordingly.
3. Transfer of Interest in
Joint Permitting
Agreement:
Prepare First Draft –
IPC: Quarter 2 of
Calendar Year 2022
Target Execution Date:
Quarter 3 of Calendar
Year 2022
IPC and BPA will execute a purchase and sale
agreement, assignment, and other applicable transfer
documents, concurrently with the New NITSAs,
NITSA Security Agreement, and any related other
agreements necessary, to transfer all of BPA’s
Permitting Interest under the Joint Permitting
Agreement (and all of BPA’s interest in the assets
associated therewith) to IPC in exchange for IPC’s
agreement for repayment to BPA of BPA’s investment
in B2H through the Joint Permitting Agreement
through the effective date of the definitive purchase
and sale agreement contemplated in this Section 3(b)
(or other date specified therein). The proposed
purchase and sale agreement contemplated in this
Section 3(b)(3) will contain representations,
warranties, and covenants typical of a transaction of
the nature contemplated by these proposed terms. The
definitive agreements transferring BPA’s Permitting
Interest under the Joint Permitting Agreement and
related assets will be executed prior to any activities
BPA has indicated could impact federal environmental
regulatory requirements under NEPA, so as to prevent
additional delay in the development of B2H.
Following the transfer of BPA’s Permitting Interest
(and associated assets) under the Joint Permitting
Agreement to IPC, IPC will be solely responsible for
funding an additional 24.24% share of all B2H Project
Costs thereafter under Joint Permitting Agreement
Rocky Mountain Power Exhibit No. 1 Page 23 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Contract No. 22TX-17207 B2H Term Sheet
Page 24 of 32
(which includes permitting and preconstruction costs),
and IPC will be entitled to all rights, title, and interests
and assets that BPA would otherwise obtain under the
Joint Permitting Agreement if it were a remaining
funding party thereto.
c) Ownership, Operation, and Maintenance Agreement: Defines IPC’s and
PAC’s capacity and property ownership, and their roles and responsibilities for operating
and maintaining the B2H Project (“Ownership and Operation Agreement”). IPC will
prepare an initial draft of the Ownership and Operation Agreement based on the ownership
interests below and otherwise consistent with the terms of the JOOA between IPC and
PAC. Alternatively, in lieu of a new agreement, IPC and PAC may decide to amend the
existing JOOA to cover the B2H Project assets.
Idaho Power PacifiCorp BPA
Project ownership: 45.45% Project ownership: 54.55% Project ownership: 0%
d) Construction Funding Agreement: Defines IPC’s and PAC’s roles and
responsibilities in construction of the B2H Project (“Construction Funding Agreement”).
IPC will prepare an initial draft of the Construction Funding Agreement consistent with
the following terms:
1. Project In-Service Date June 1, 2026
2. Scope The Construction Funding Agreement covers all work
necessary to construct the B2H Project by the Project
In-
work after the Project In-Service Date, but excluding
any work already covered by the Joint Permitting
Agreement.
3. Project Delivery System A
(“CM”) for the B2H Project in 2022 to: (1) provide
constructability feedback to the design engineer; and
(2) collaborate with PAC and IPC to
BLM Construction
Oregon Energy Facility Siting Council’s Site
Certificate amendments. The hiring process of the CM
will be structured such that the CM may be retained to
construct the B2H Project.
Rocky Mountain Power Exhibit No. 1 Page 24 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Contract No. 22TX-17207 B2H Term Sheet
Page 25 of 32
IPC and PAC may mutually agree to modify the
role through the Construction Funding Committee (as
defined in Section 10 below -Project
Committee) without amending the Construction
Funding Agreement.
4. Project Manager IPC is the overall Project Manager for all B2H Project
permitting, design, procurement, construction, except
that BPA will be responsible for designing, procuring,
and constructing the Longhorn substation as described
in Section 3(a)(4)
BPA 69 kV line off Navy property
Section 3(a)(10).
precluded from taking project management
responsibilities for all or selected tasks associated with
the B2H Project; provided that these delegations must
be made by the Construction Funding Committee.
5. Construction Project
Manager
IPC’s role as Construction
generally consistent with the roles and responsibilities
of the Permitting Project Manager set forth in Article
IV of the Joint Permitting Agreement, provided that
construction will be removed.
IPC, as the Construction Project Manager, will provide
monthly project updates, including updates on project
activities, financials, forecasts, and invoices detailing
Parties’ cost responsibilities based on their percentage
shares.
approved budget, schedule and scope, and also have
authority to approve any non-material changes to the
B2H Project resulting in a price difference of less than
$500k, so long as the overall B2H Project costs remain
within the approved budget with the price change. All
changes to the B2H Project resulting in a change in the
Construction Funding Committee.
Rocky Mountain Power Exhibit No. 1 Page 25 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Contract No. 22TX-17207 B2H Term Sheet
Page 26 of 32
6. Component Specifications All B2H
Funding Committee so long as the p
with all a
requirements and standards.
7. Real Property Ownership B2H real property, except Longhorn substation
will acquire rights of way, grants, easements, or other
interests in real property necessary to construct,
operate and maintain
grant to PAC perpetual and sufficient rights of access,
Agreement.
Longhorn Substation
obligations and responsibilities under NEPA, NHPA,
and if BPA decides to proceed with construction of
Longhorn substation, BPA will continue to own all
real property associated with the Longhorn substation,
and in relation to the B2H Project equipment BPA
rights of access, to be set forth in one or more
Longhorn Substation Agreements
Section 3(a)(4).
8. Equipment and Facilities
Ownership
Equipment and facilities ownership will be
with the Ownership and Operation Agreement.
substation: IPC and PAC will jointly own as tenants
facilities located in Hemingway Substation as well as
supporting communication facilities and B2H Project
substation equipment.
Longhorn Substation
obligations and responsibilities under NEPA, NHPA,
and other requisite environmental
and if BPA decides to proceed with construction of
Longhorn substation, BPA will own all equipment and
facilities in the Longhorn substation, except the B2H
specific equipment and facilities which will be jointly
owned by IPC and PAC as tenants in common. BPA
Rocky Mountain Power Exhibit No. 1 Page 26 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Contract No. 22TX-17207 B2H Term Sheet
Page 27 of 32
and facilities in Longhorn substation that are
constructed as part of and necessary to the operation of
the B2H transmission line facilities, to be set forth in
one or more Longhorn Substation Agreements as
described in Section 3(a)(4).
9. Material Procurement All material specifications shall be in accordance with
IPC’s procurement policies and standards, unless
otherwise agreed by the Construction Funding
Committee to exceed the same.
10. Project Funding and
Committee
Funding: IPC and PAC will fund the B2H
consistent with their respective ownership shares.
Construction Funding Committee
Funding Committee consistent with IPC and PAC’s
ownership interests in the B2H Project, and generally
consistent with the Permit Funding Committee created
by the Joint Permitting Agreement (Article III).
forth in the above Section 5 (Construction Project
Manager)will be delivered to all members of the
Construction Funding Committee prior to, and
discussed during, each of the Committee’s regularly-
scheduled monthly meetings.
Obligations, disputed amounts, and audit rights will be
generally consistent with Article III of the Joint
Permitting Agreement.
The Project Manager will have flexibility to make day-
to-day decisio
Project but will be required to seek resolution/approval
from the Construction Funding Committee on larger
dollar/impact decisions, consistent with that set forth
in the above Section 5 (Construction Project
Manager).
BPA will be responsible for designing, procuring, and
constructing the Longhorn substation as described in
Section 3(a)(4) and relocating and replacing the BPA
69 kV line off Navy property, as described in Section
3(a)(10).
11. Payment Schedule Costs Accrued Prior to Agreement Execution
Rocky Mountain Power Exhibit No. 1 Page 27 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Contract No. 22TX-17207 B2H Term Sheet
Page 28 of 32
and PAC
construction-related expenses included therein that
have not otherwise been funded under the Joint
Permitting Agreement. IPC and PAC
respective portions of accrued expenses within 30 days
of the effec
Agreement. Until which time BPA fully divests its
ownership interest in the B2H
acknowledge that the B2H
environmental laws associated with
action.
Costs Incurred After Execution: Following execution
of the Construction Funding Agreement, the Project
Manager will invoice the
Agreement participants
within 30 days of the invoice date.
12. Transfer/Assignment of
Rights/Interests (Some or
all of these terms may be
instead placed in the
Ownership Agreement)
IPC and
ownership interests in the B2H Project, together with
associated capacity, subjec
Funding Committee’s agreement and approval of the
terms of any such transaction;
approval will not be unreasonably withheld.
IPC will not transfer or assign rights or interests in the
B2H Project that would materially impact the BPA
load service commitments set forth in Section 3(b) of
this Term Sheet.
13. Term
Early Termination
Withdrawal
Term: The term of the Construction Funding
Agreement will extend through completion of B2H
expenses, unless otherwise agreed by the Construction
Funding Committee.
Early Termination/Withdrawal:
the Construction Funding Committee, no Party shall
awarding the B2H Project construction contract, or (2)
commencing procurement of long-
equipment.
Rocky Mountain Power Exhibit No. 1 Page 28 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Contract No. 22TX-17207 B2H Term Sheet
Page 29 of 32
Assignments of IPC’s or
under the Construction Funding Agreement shall be
(Transfer/Assignment of Rights/Interests).
14. Event of Default Generally consistent with Article VIII of the
Permitting Agreement.
15. Force Majeure Generally consistent with Article IX of the
Permitting Agreement.
16. Reps and Warranties Generally consistent with Article X of the
Permitting Agreement.
17. Common Defense &
Limitation of Liability
Generally consistent with Article XI of the
Permitting Agreement, except that the Article will be
expanded to address construction claims.
18. Proprietary
Information/Confidentiality
Generally consistent with Article XII of the
provide IPC
engineers and contractors.
19. Dispute Resolution Generally consistent with Article XIII of the
Permitting Agreement.
20. Miscellaneous Generally consistent with Article XIV of the
assignment and jury trial waiver provisions).
4. Additional Agreements.The Parties agree that they may consolidate any or all of
the above-described Agreements and are not precluded from pursuing additional
agreements, or amending existing agreements as needed, related to the B2H Project besides
those discussed herein.
5. Expenses.Each Party will bear its own expenses (including attorneys’ fees)
incurred in connection with preparation, negotiation, and execution of this Term Sheet,
including preparation, negotiation and execution of the Agreements described herein.
ACKNOWLEDGED AND AGREED TO BY THE PARTIES:
Rocky Mountain Power Exhibit No. 1 Page 29 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Rocky Mountain Power Exhibit No. 1 Page 30 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Contract No. 22TX-17207 B2H Term Sheet
Page 31 of 32
PACIFICORP
Signature: _________________________________
Printed Name: Rick Link
Title: Senior Vice President, Resource Planning, Procurement and Optimization
Date: _________________________________
Signature: _________________________________
Printed Name: Rick Vail
Title: Vice President, Transmission
Date: _________________________________
Rocky Mountain Power Exhibit No. 1 Page 31 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Contract No. 22TX-17207 B2H Term Sheet
Page 32 of 32
BONNEVILLE POWER ADMINISTRATION
Signature: _________________________________
Printed Name: _________________________________
Title: _________________________________
Date: _________________________________
Signature: _________________________________
Printed Name: _________________________________
Title: _________________________________
Date: _________________________________
Tina Ko
Vice President, Transmission Marketing
1/18/2022
Kim Thompson
Vice President, Requirements
1/18/2022
Rocky Mountain Power Exhibit No. 1 Page 32 of 32 Case No. PAC-E-23-01 Witness: Rick T. Link
Exhibit No. 2
THIS EXHIBIT NO. 2 IS CONFIDENTIAL AND
HAS BEEN PROVIDED IN EXCEL FORMAT
ONLY

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF ROCKY MOUNTAIN POWER FOR A CERTIFICATE OF CONVENIENCE AND NECESSITY AUTHORIZING
CONSTRUCTION OF THE BOARDMAN-TO-HEMINGWAY 500-KV
) ) DIRECT TESTIMONY OF ) RICK A. VAIL
) REDACTED )

ROCKY MOUNTAIN POWER
CASE NO. PAC-E-23-01

January 2023
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TABLE OF CONTENTS
I. INTRODUCTION AND QUALIFICATIONS .......................................................... 1
II. PURPOSE AND SUMMARY OF TESTIMONY ...................................................... 1
III. DESCRIPTION OF B2H .......................................................................................... 5
IV. NECESSITY OF B2H ............................................................................................ 12
V. BENEFITS OF B2H ............................................................................................... 16
VI. ASSET EXCHANGES ........................................................................................... 21
VII. AGREEMENTS RELATING TO B2H ................................................................... 24
VIII. RECOMMENDATION AND CONCLUSION ....................................................... 30

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I. INTRODUCTION AND QUALIFICATIONS 1
Q. Please state your name, business address, and present position with PacifiCorp. 2
A. My name is Rick A. Vail. My business address is 825 NE Multnomah Street, Suite 3
1600, Portland, Oregon 97232. My present position is Vice President of Transmission. 4
I am responsible for transmission system planning, customer generator interconnection 5
requests and transmission service requests, regional transmission initiatives, asset 6
management, capital budgeting for transmission, and administration of the Company’s 7
Open Access Transmission Tariff (“OATT”). I am testifying on behalf of PacifiCorp 8
d/b/a Rocky Mountain Power (the “Company”). 9
Q. Please describe your education and professional experience. 10
A. I have a Bachelor of Science Degree with Honors in Electrical Engineering with a focus 11
in electric power systems from Portland State University. I have been employed at the 12
Company since 2001, and have had a range of management responsibility within the 13
asset management group, including capital planning, maintenance policy, maintenance 14
planning, and investment planning. I served as Director of Asset Management from 15
2007 to 2012. I became Vice President of Transmission in December 2012. 16
II. PURPOSE AND SUMMARY OF TESTIMONY 17
Q. What is the purpose of your testimony? 18
A. My testimony supports the Company’s application for a certificate of public 19
convenience and necessity (“CPCN”) for Energy Gateway Segment H, the Boardman 20
to Hemingway 500-kilovolt (“kV”) transmission line (“B2H” or the “Project”). B2H is 21
an approximately 300-mile-long 500-kV electric transmission line with a western 22
terminal at a proposed new switching station near Boardman in north-central Oregon 23
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and an eastern terminal at the existing Hemingway substation in southwest Idaho. 1
Twenty-four miles of B2H will be located in Owyhee County in Idaho with an 2
additional 274 miles located in five Oregon counties: Malheur, Baker, Union, Umatilla, 3
and Morrow Counties. The Project consists of: 4
1. Construction of approximately 271 miles of single-circuit 500-kV transmission 5
line in Oregon; 6
2. Construction of approximately 24 miles of single-circuit 500-kV transmission 7
line in Idaho; and 8
3. Removal of 12 miles of existing 69-kV transmission line. 9
Additionally, construction of B2H will require the following ancillary facilities: 10
1. A newly constructed switching station proposed to be constructed near 11
Boardman, Oregon; 12
2. Construction of the Midline Series Capacitor substation; 13
3. Ten communication stations constructed within the right-of-way of the 14
transmission line; 15
4. Construction of approximately 206 miles of new access roads; and 16
5. Substantial modification of approximately 223 miles of existing roads. 17
The following graphic, which Idaho Power Company (“IPC”) prepared in its 18
application for a site certificate from Oregon’s Energy Facility Siting Council 19
(“EFSC”), shows the general location of B2H, including the alternative route segments 20
approved by EFSC: 21
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Rocky Mountain Power

My testimony and exhibits provide information required by Idaho Public 1
Utilities Commission (“Commission”) Rules of Procedure 52 and 112 and Idaho Code 2
§ 61-526, related to applications for CPCNs, for B2H. 3

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Q. Please summarize your testimony. 1
A. B2H is necessary for the Company to meet its customers’ short- and long-term energy 2
demand and will strengthen the overall reliability of the existing transmission system. 3
While B2H has long been recognized as an integral component of the Company’s long-4
term transmission planning, its construction by 2026 is both necessary and beneficial 5
for customers, as B2H will enable the Company to efficiently deploy new generating 6
facilities and better utilize existing resources to meet projected resource needs. The 7
Company expects generation shortfalls beginning in 2026 and B2H is the most cost-8
effective means of securing sufficient generation to reliably serve customers. 9
B2H will provide a much-needed transmission connection between the 10
Company’s eastern balancing authority area (“BAA”), PacifiCorp East (“PACE”), and 11
its western BAA, PacifiCorp West (“PACW”). This connection is vital because 12
currently the Midpoint-to-Summer Lake 500-kV transmission line is the only line 13
connecting PACE and PACW. Increasing connections between the Company’s BAAs 14
will enable the Company to more efficiently serve customers in both areas using the 15
most cost-effective generation available. Additionally, construction of B2H will 16
provide regional benefits by strengthening the interconnected transmission grid in the 17
West and enhancing resource adequacy. 18
In addition to construction of B2H, IPC and the Company have agreed to 19
exchange several existing transmission assets. These asset exchanges will enable both 20
the Company and IPC to develop more interconnected transmission systems to serve 21
their respective customers. I discuss the asset exchanges and the agreements that the 22
parties intend to execute to implement these exchanges below. 23
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III. DESCRIPTION OF B2H 1
Q. Please briefly describe PacifiCorp’s transmission system. 2
A. PacifiCorp owns and operates approximately 17,000 miles of transmission lines 3
ranging from 46 kV to 500 kV across multiple western states. PacifiCorp has over 2 4
million customers with approximately 88,000 customers located in Idaho. Idaho is 5
located (along with Wyoming and Utah) in PacifiCorp’s eastern BAA, PACE, which 6
has over 12,640 circuit-miles of transmission lines and a record peak demand of 9,700 7
megawatts (“MW”). A new record peak was reached in PacifiCorp’s overall system on 8
July 28, 2022 at 13,195 MW. The PACE peak at that time was 9,290 MW. 9
Q. Is PacifiCorp’s transmission system interconnected with any third-party systems? 10
A. Yes. PACE alone is interconnected with 17 other systems, including Arizona Public 11
Service, Bonneville Power Administration (“BPA”), NV Energy, Los Angeles 12
Department of Water & Power, NorthWestern Energy, Western Area Lower Colorado-13
Phoenix, IPC, Western Area Colorado Missouri-Loveland, Western Area Power 14
Administration, Black Hills Power, Utah Associated Municipal Power Systems, Utah 15
Municipal Power Agency, Deseret Power Electric Cooperative, Basin Electric Power 16
Cooperative, Intermountain Power Agency, Tri-State Generation & Transmission 17
Association, and Public Service Company of New Mexico. 18
Q. Please describe B2H. 19
A. B2H is a high voltage single-circuit 500-kV alternating current transmission line that 20
extends approximately 300 miles from north-central Oregon to southwest Idaho. B2H 21
is also referred to as Segment H of Energy Gateway. 22
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Q. Please summarize the agreements between stakeholders regarding funding and 1
construction of B2H. 2
A. The initial B2H agreement among IPC, BPA, and the Company was a Joint Permit 3
Funding Agreement, executed January 12, 2012, and amended several times, to jointly 4
support the regulatory processes associated with obtaining necessary permits and other 5
project development work. On January 18, 2022, the parties executed a non-binding 6
Term Sheet as the framework for future agreements, which is included as Exhibit No. 1 7
to Mr. Rick Link’s testimony. I discuss several of the agreements identified in the Term 8
Sheet in detail below. 9
Prior to execution of the Term Sheet, BPA decided to transition out of its role 10
as a joint permit funding coparticipant and to instead rely on B2H by taking 11
transmission service from IPC to serve its customers, leaving only the Company and 12
IPC as owners of B2H. As a result of BPA’s decision to take transmission service from 13
IPC, the Term Sheet stipulates that IPC will acquire BPA’s B2H project capacity, 14
which increased IPC’s B2H project ownership share to 45.45 percent.1 Because IPC 15
assumed the entirety of BPA’s ownership interest in B2H, BPA’s transition did not 16
affect the Company’s ownership interest. When B2H is completed, IPC and the 17
Company will jointly own as tenants in common the transmission line and all associated 18
facilities and equipment.2 Per the Term Sheet, IPC is responsible for federal, state, and 19
local permitting efforts and construction of the Project, except that BPA will be 20
1 Exhibit No. 1 - Term Sheet at 24 (Jan. 18, 2022) [hereinafter “Term Sheet”]. 2 Id. at 26.
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responsible for designing, procuring, and constructing the Longhorn substation and 1
relocating and replacing an existing BPA 69-kV line.3 2
Q. Where does B2H begin and end? 3
A. B2H begins at the proposed Longhorn substation near Boardman, Oregon. From there 4
B2H extends south and east through Morrow and Umatilla Counties before entering 5
Union County. B2H parallels the corridor for Interstate 84 (“I-84”) through Union and 6
Baker Counties. In Malheur County, the route briefly turns to the southwest before 7
finally returning southeast and eventually terminating at the existing Hemingway 8
substation in Owyhee County, Idaho. 9
Q. Please describe B2H’s proposed route. 10
A. After leaving the proposed Longhorn substation, the transmission line runs south for 11
approximately 19 miles, paralleling existing transmission and pipeline rights-of-way 12
for the first 13 of those miles. At that point, B2H turns east-by-southeast through 13
Morrow and Umatilla Counties and enters Union County. 14
Beginning at approximately milepoint 90, B2H begins to parallel the I-84 as it 15
approaches the city of La Grande, Oregon. B2H roughly parallels I-84 for the next 110 16
miles through Union and Baker Counties. 17
Shortly after entering Malheur County, B2H turns south for approximately 12 18
miles primarily through land that is managed by the Bureau of Land Management 19
(“BLM”). At approximately milepoint 212 the transmission line turns to the southwest 20
through agricultural and BLM land for approximately 14 miles. Finally, the 21
transmission line turns to the southeast and continues primarily through BLM-managed 22
3 Id. at 25.
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lands. At approximately milepoint 253, B2H enters the BLM’s Vale District Utility 1
Corridor, which the transmission line then follows for much of its remaining path 2
through Malheur County as it approaches the Oregon-Idaho state line. 3
After crossing into Owyhee County, Idaho, the transmission line continues in a 4
southeastern direction until finally terminating at the existing Hemingway substation. 5
Q. What types of towers and conductors will be used to construct B2H? 6
A. For the B2H project, structures will primarily be steel lattice tower structures, which 7
provide an economical means to support large conductors for long spans over long 8
distances. These lattice towers will range in height from 109 to 200 feet, with a typical 9
structure height of 160 feet. In select areas tubular steel H-frame towers will be 10
deployed with a height range of about 65 to 105 feet to mitigate potential impacts to 11
visual resources. A structure will be located roughly every 1,400 feet on average. 12
For a single-circuit transmission line, such as B2H, power is transmitted via 13
three phase conductors (a phase can also have multiple conductors, called a bundle 14
configuration). These conductors are typically comprised of a steel core to give the 15
conductor tensile strength and reduce sag of the aluminum outer strands. Aluminum is 16
used because of its high conductivity to weight ratio. The conductors will have a non-17
specular finish to reduce visual impacts. Shield wires, typically either steel or 18
aluminum and occasionally including fiber optic cables inside for communication, are 19
the highest wires on the structure. Their main purpose is to protect the phase conductors 20
from a lightning strike. 21
Q. Will B2H require modifications to any substations? 22
A. Yes. B2H will require construction of the proposed Longhorn substation near 23
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Boardman, Oregon. The existing Hemingway substation in Owyhee County, Idaho will 1
also require upgrades. Finally, B2H will require construction of a Midline Series 2
Capacitor substation. 3
Q. Please describe the proposed work at the Longhorn substation. 4
A. The western terminus for B2H requires the new Longhorn substation to tap into the 5
existing BPA 500-kV transmission network. BPA owns the land for the Longhorn 6
substation and intends to construct the substation to integrate certain wind projects in 7
the immediate area once all environmental compliance laws are met. As agreed under 8
the Term Sheet, BPA will own all equipment and facilities in the Longhorn substation, 9
except B2H-specific equipment and facilities, which will be jointly owned by IPC and 10
the Company. 11
Q. Please describe the proposed work at the Hemingway substation. 12
A. The IPC-owned existing Hemingway substation is designed to accommodate the B2H 13
line terminal but will require the addition of new equipment. IPC, as project manager 14
for construction of B2H, is responsible for these upgrades. 15
Q. Please describe the proposed work at the Midline Series Capacitor substation. 16
A. The Midline Series Capacitor substation is necessary to reduce simultaneous 17
interactions between the Northwest (“NW”) Alternating Current (“AC”) Intertie, 18
central and southern Oregon load service, and Path 14 (Idaho to Northwest). The 19
Midline Series Capacitor station was added to the project scope between the 2019 20
Integrated Resource Plan (“IRP”) and 2021 IRP to facilitate the operational needs of 21
the parties, and at this time consists of only a fenced yard and series capacitor. 22

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Q.Will any other stations be constructed as part of B2H? 1
A.Yes. Ten communication stations will be constructed along the route of B2H. These 2
stations will be built within the right-of-way of the transmission line itself. The typical 3
communication station site will be 100 feet by 100 feet, with a fenced area of 75 feet 4
by 75 feet. A prefabricated concrete communications structure with dimensions of 5
approximately 11.5 feet by 32 feet by 12 feet tall will be placed on the site and access 6
roads to the site and power from the local electric distribution circuits will be required. 7
A standby generator with a liquefied propane gas tank will be installed at the site inside 8
the fenced area. Two separate conduit (underground) or aerial cable routes will be used 9
for each fiber optic cable bundle between the transmission line and communication 10
station. Conduits will be 2-inch-diameter polyvinyl chloride and will be buried three 11
feet below the surface extending from the communication shelter to two different legs 12
of the transmission structure maintaining a 10-foot separation between the cables. All 13
work will occur within the disturbance footprint for either the communication station 14
or the transmission structure to which the cables will attach. 15
Q.What is the total cost estimate for the Company’s share of B2H? 16
A.The Company estimates that its in-service cost of B2H will be , including 17
AFUDC. This is the cost estimate used in the Company’s economic analysis sponsored 18
by Mr. Rick T. Link. 19
Q.Has the Company put in place any cost controls for B2H? 20
A.While the Company and IPC have not yet finalized the definitive terms of the B2H 21
construction funding agreements, the Company is working with IPC, the B2H project 22
manager, to ensure provisions are put in place to control costs. 23
REDACTED
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As explained in testimony IPC filed in support of its own application for a 1
CPCN, IPC has strict project cost controls for internal and external personnel. Regular 2
monthly forecast updates, including the tracking of budgets and schedules, are part of 3
the project controls suite that the project management team employs. During the current 4
preconstruction phase, IPC constructability consultant, Quanta Infrastructure Solutions 5
Group, aided in certain preconstruction reviews and tasks. This early integration of the 6
construction team allows for constructability feedback, identification of risks, and 7
opportunities to economize the design. As the B2H project transitions into the 8
construction phase, all material and construction services will be competitively bid and 9
be pulled into a guaranteed maximum price (“GMP”) that will serve as the construction 10
pricing if awarded. This GMP is tied to a schedule that IPC and the construction 11
manager will have developed together that IPC, in consultation with the Company, and 12
as a result of the contract, the construction manager will be responsible for meeting that 13
schedule. Milestone dates will be tied to monetary penalties for the construction 14
manager if key dates slip.4 15
Q.Will the cost of B2H be included in PacifiCorp’s transmission rates? 16
A.Yes. B2H will be considered a network transmission asset under the Company’s 17
OATT, and Federal Energy Regulatory Commission (“FERC”) precedent for 18
ratemaking supports rolling in the costs of these assets into the Company’s transmission 19
rates. Through inclusion in the Company’s OATT, part of the costs of B2H will be 20
4 In re Idaho Power Company’s Application for a Certificate of Public Convenience and Necessity for the
Boardman to Hemingway 500-kV Transmission Line, Case No. IPC-E-23-01, Direct Testimony of Lindsay Barretto at 40-41 (Jan. 10, 2023).
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recovered from third-party transmission customers and included as an offset to the 1
benefit of retail customers. 2
Q. How will the Company finance the costs of B2H? 3
A. The Company intends to finance the Project through its normal sources of capital, both 4
internal and external, including net cash flow from operating activities, public and 5
private debt offerings, the issuance of commercial paper, the use of unsecured 6
revolving credit facilities, capital contributions, and other sources. 7
Q. Will the costs of B2H affect the Company’s ability to provide reliable service to 8
its Idaho customers? 9
A. No. Although the Project will be a significant investment on the part of the Company, 10
the financial impact will not impair the Company’s ability to continue to provide safe 11
and reliable electricity service at reasonable rates. 12
Q. When does the Company expect construction of B2H to be complete? 13
A. As mentioned above, IPC is responsible for constructing B2H. IPC has informed the 14
Company that it expects to complete construction by 2026. 15
IV. NECESSITY OF B2H 16
Q. What is the standard for issuing a CPCN in Idaho? 17
A. I am not an attorney, but my understanding is that the Commission may issue a CPCN 18
if an applicant demonstrates that the present or future public convenience and necessity 19
require construction of the proposed facility.5 20

5 Idaho Code Section 61-526.
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Q. Does the Company have an identified need for the construction of B2H? 1
A. Yes. B2H is necessary for the Company to cost-effectively serve its growing Oregon 2
loads. Additionally, B2H will increase grid reliability and increase transferability 3
between PACE and PACW. 4
Q. Has the Company addressed the benefits of B2H in prior filings with the 5
Commission? 6
A. Yes, the Company has identified the expected benefits of B2H in its IRPs, which are 7
discussed in more detail in the testimony of Mr. Link. To continue to provide reliable 8
and cost-effective service, the Company must invest in a robust transmission system to 9
move resources across and between both PacifiCorp balancing areas. As Mr. Link 10
explains in his testimony, B2H has repeatedly been identified as the most cost-effective 11
means to serve customer demand. 12
Q. Has the Company further analyzed the cost benefits of B2H since the 2021 IRP? 13
A. Yes. The Company conducted extensive economic analysis of B2H in preparation for 14
this CPCN filing. That analysis is summarized in the testimony of Mr. Link. As 15
Mr. Link explains, the Company’s recent economic analysis further supports the cost-16
effectiveness of B2H. 17
Q. How does B2H enhance grid reliability? 18
A. The Hemingway-to-Summer Lake 500-kV transmission line currently is the only line 19
connecting PACE and PACW.6 The loss of the Hemingway-to-Summer Lake line has 20
the potential to reduce transfers between the Company’s BAAs by 1,090 MW. B2H 21
6 PacifiCorp, 2021 IRP, Volume 1 at 90 (Sept. 1, 2021) (available at https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/energy/integrated-resource-plan/2021-irp/Volume%20I%20-%209.15.2021%20Final.pdf) (last visited Jan. 25, 2023) [hereinafter “2021 IRP”].
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will provide redundancy by adding an additional 1,000 MW of capacity between the 1
Hemingway substation and the Pacific Northwest. 2
Because it is the only 500-kV connection between the Pacific Northwest and 3
Idaho Power, the loss of the Hemingway-to-Summer Lake 500-kV transmission line 4
during peak summer load is one of the most severe possible contingencies the Idaho 5
Power transmission system can experience. Once Hemingway-to-Summer Lake 500-6
kV disconnects, the transfer capability of the Idaho to Northwest path is reduced by 7
over 700 MW in the west-to-east direction. After the addition of B2H, there will be two 8
major 500-kV connections between the Pacific Northwest and Idaho Power and as a 9
result the Hemingway-to-Summer Lake 500-kV outage would become much less 10
severe to Idaho Power’s transmission system. 11
Additionally, under current conditions the loss of the Hemingway-to-Summer 12
Lake 500-kV line with heavy east-to-west power transfer out of Idaho to the Pacific 13
Northwest would result in significant system impacts. In this disturbance, an existing 14
remedial action scheme (power system logic used to protect power system equipment) 15
would disconnect over 1,000 MW of generation at the Jim Bridger Power Plant to 16
reduce path transfers and protect bulk transmission lines and apparatus. Due to the 17
magnitude of the generation loss, recovery from this disturbance can be extremely 18
difficult. After the addition of B2H, this enormous amount of generation shedding will 19
no longer be required. 20

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Q. If a transmission line connecting PACE and PACW already exists, is B2H 1
proposed merely as redundancy for that line? 2
A. No. As I stated above, in addition to the extremely important redundancy benefits, B2H 3
will also provide the Company additional transmission capacity to serve customers. 4
The Project will provide the Company 300 MW of additional west-to-east capacity and 5
600 MW of east-to-west capacity.7 Additionally, the original permit funding agreement 6
between B2H stakeholders left 400 MW of east-to-west capacity unassigned. The 7
Company and IPC have agreed to divide this unassigned capacity consistent with each 8
company’s respective ownership share of B2H. As discussed above, the Company will 9
own 54.55 percent of B2H. As a result, the Company will obtain 218 MW of the 10
unallocated east-to-west capacity. This increases the Company’s total east-to-west 11
capacity in B2H to 818 MW. 12
Q. Are there any other reasons that B2H is necessary? 13
A. Yes. In addition to the benefits the Company and its customers will receive, B2H will 14
enhance regional reliability by improving the Western transmission grid. 15
NorthernGrid—a planning association aiming to facilitate regional transmission 16
planning across the Pacific Northwest and Intermountain West—has repeatedly 17
identified B2H as a regionally significant project in its biennial regional transmission 18
plans.8 From a regional perspective, the Project resolves possible system issues as 19
identified in the NorthernGrid 2021 draft regional plan. 20
7 2021 IRP at 89. 8 See NORTHERNGRID, Regional Transmission Plan for the 2020-2021 NorthernGrid Planning Cycle at 31 (Dec. 8, 2021) (available at https://www.northerngrid.net/private-media/documents/2020-2021_Regional_Transmission_Plan.pdf) (last visited Jan. 25, 2023).
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Relatedly, the Company is participating in the ongoing effort to evaluate and 1
develop a regional resource adequacy program with other utilities that are members of 2
the Northwest Power Pool. B2H is anticipated to provide incremental transmission 3
infrastructure that will broaden access to a more diverse resource base, which will 4
provide opportunities to reduce the cost of maintaining adequate resource supplies in 5
the region. 6
V. BENEFITS OF B2H 7
Q. Please describe the benefits associated with construction of B2H. 8
A. As explained by Mr. Link in his testimony, B2H is the most cost-effective means of 9
serving PacifiCorp’s customers. In addition, B2H will provide several benefits to the 10
Company’s existing transmission system. These benefits include improved system 11
reliability, redundancy between PACE and PACW, and improved economic dispatch 12
of generation resources. 13
Q. Please summarize the benefits of a robust transmission system. 14
A. PacifiCorp’s bulk transmission network is designed to reliably transport electric energy 15
from a broad array of generation resources to load centers. There are many benefits 16
associated with a robust transmission network, including: 17
• Reliable delivery of a diverse energy supply to continuously changing customer 18
demands under a wide variety of system operating conditions; 19
• Access to some of the nation’s best wind and solar resources, which provides 20
opportunities to develop geographically diverse low-cost renewable assets; and 21
• Protection against market disruptions where limited transmission can otherwise 22
constrain energy supply. 23
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Q. Please describe in more detail how B2H will improve overall system reliability. 1
A. The transmission grid can be affected in its entirety by what happens on an individual 2
transmission line or path. A single outage on any individual line or line segment due to 3
storm, fire, or other interference can and does cause significant reductions in 4
transmission capacity and can negatively impact the Company’s ability to serve 5
customers. Line outages require the Company to significantly curtail generation 6
resources to stabilize system voltages and require less efficient re-dispatch of system 7
resources to meet network load requirements. 8
In the event of a line outage, particularly an outage on the Hemingway–Summer 9
Lake 500-kV line discussed above, the redundancy provided by B2H will allow the 10
Company to continue to meet native load service obligations and continue to meet other 11
contractual obligations to third parties. Strengthening this transmission and increasing 12
system redundancy with B2H will benefit all customers by reducing the risk of outages 13
and inefficient dispatch resulting from those outages. 14
In addition, B2H will improve the Company’s ability to perform required 15
maintenance without significant operational impacts to the system and will reduce 16
impacts to customers during planned and forced system outages. Transmission line and 17
substation maintenance windows are currently limited because the system is highly 18
used. By relieving congestion and providing additional transmission paths, B2H will 19
allow greater flexibility for the Company. 20
Moreover, as discussed in a recent paper from Grid Strategies titled 21
“Transmission Makes the Power System Resilient to Extreme Weather,” transmission 22
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lines can provide extraordinary benefits to regions experiencing extreme weather.9 1
During Winter Storm Uri alone, the paper identifies seven different transmission 2
connections that each could have provided over $80 million of benefits per 1,000 MW 3
of transmission capacity for that single event, with one specific connection that would 4
have provided nearly $1 billion in benefits per 1,000 MW.10 Extreme events, such as 5
the 2021 Pacific Northwest heat dome, are increasing in frequency, and transmission 6
lines provide a significant regional diversity, reliability, and resilience benefit. 7
Finally, through the asset exchanges discussed below, the Company will 8
achieve additional capacity to southeast Idaho by receiving from IPC a percentage of 9
the assets that make up the existing 500-kV and 345-kV transmission lines between the 10
Borah, Kinport, Adelaide, Midpoint and Hemingway substations. 11
Q. Please describe the reliability benefits specific to B2H. 12
A. Construction of B2H will provide a parallel transmission path from southwest Idaho to 13
the Pacific Northwest connecting generation resources to be transferred to PacifiCorp 14
customers throughout the Company’s service area. If one path is out of service, the 15
other path will provide backup transmission service capability, within the limits of the 16
remaining path. This is particularly important in the case of B2H, because currently the 17
Hemingway–Summer Lake 500-kV line is the only 500-kV transmission path 18
connecting Idaho and the Pacific Northwest. Adding a parallel path will improve 19
system reliability by reducing the number and magnitude of transmission schedule 20
reductions during line outage conditions. 21
9 Michael Goggin, GRID STRATEGIES, LLC, Transmission Makes the Power System Resilient to Extreme Weather (July 2021) (available at https://acore.org/wp-content/uploads/2021/07/GS_Resilient-Transmission_proof.pdf) (last visited Jan. 25, 2023). 10 Id. at 11.
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Q. Please describe how B2H can provide cost savings in the form of reduced energy 1
and capacity losses. 2
A. Reduced energy and capacity losses on the transmission system have the potential to 3
provide significant cost savings over time. Generally, the addition of a new 4
transmission path in parallel with existing lines, like B2H, will reduce the energy and 5
capacity losses by reducing the impedance of the transmission system. Reduced line 6
losses mean more efficient delivery of energy and capacity at reduced costs. 7
Additionally, B2H will reduce electrical losses. Losses on the power system are 8
caused by electrical current flowing through energized conductors, which in turn 9
creates heat. By constructing B2H, the Company may relieve less efficient, lower 10
voltage transmission lines with very large transfers, which will reduce the electrical 11
current through these lines and dramatically reduce the losses due to heat. 12
Q. Has B2H been recognized as providing reliability benefits to the broader Western 13
Interconnection? 14
A. Yes. B2H has undergone an extensive process to be formally included in Western 15
Electricity Coordinating Council (“WECC”) path rating studies, which was a critical 16
milestone for the projects, and one that can only occur if a new transmission facility 17
can, at a minimum, reliably operate at its approved rating without negatively impacting 18
other neighboring systems. B2H is not only considered minimally reliable, but regarded 19
as an important transmission project that is necessary to support the long-term 20
transmission expansion planning established in the Western Interconnection plans and 21
in the most recent NorthernGrid regional transmission plan.11 22
11 Regional Transmission Plan for the 2020-2021 NorthernGrid Planning Cycle at 31.
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Q. What is involved in the WECC path rating study process? 1
A. The WECC path rating studies follow a three-phase process established by the Planning 2
Coordination Committee, the predecessor to the existing Reliability Assessment 3
Committee, which uses peer review study groups, made up of the project sponsor and 4
other interested WECC members, to establish a path rating for a given transmission 5
path or set of transmission paths, which may exhibit simultaneous interactions with 6
each other. Path rating studies use a transmission model of the Western Interconnection 7
and will take multiple months to evaluate the performance of the new transmission 8
facilities and to demonstrate that the proposed transmission project will have no 9
negative impacts on previously established transmission path ratings. The path ratings 10
that are established following this process represent the “Maximum Path Transfer 11
Capability” of a transmission path. 12
Once projects complete the second phase of the path rating studies, they are 13
granted an “Accepted” rating and placed in Phase 3 (construction phase) status. After 14
the Accepted status is granted, other projects currently going through the WECC path 15
rating process must recognize the project in their studies and cannot negatively impact 16
the path rating for the project. 17
Q. Please describe the WECC path rating study process for B2H. 18
A. As project manager for B2H, IPC led B2H through the WECC path rating study 19
process. Early in the B2H project development, IPC coordinated with other utilities in 20
the Western Interconnection via the WECC Path Rating Process. IPC worked with 21
other western utilities to determine the maximum rating (power flow limit) across the 22
transmission line under various stresses, and system flow conditions on the bulk power 23
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system. Based on industry standards to test reliability and resilience, IPC simulated 1
various outages, including the outage of B2H, while modeling these various stresses to 2
ensure the power grid was capable of reliably operating with increased power flow. 3
Through this process, IPC also ensured the B2H project did not negatively impact the 4
ratings of other transmission projects in the Western Interconnection. IPC completed 5
the WECC Path Rating Process in November 2012 and achieved a WECC Accepted 6
Rating of 1,050 MW in the west-to-east direction and 1,000 MW in the east-to-west 7
direction. It was determined that the B2H project would add significant reliability, 8
resilience, and flexibility to the Northwest power grid. 9
VI. ASSET EXCHANGES 10
Q. Will there be additional modifications to the Company’s transmission system 11
relating to B2H? 12
A. Yes. In addition to the transmission capacity added through the construction of B2H, 13
the Company’s transmission system will be modified due to agreed upon asset 14
exchanges with IPC. 15
Q. What are these asset exchanges? 16
A. As defined in the Joint Purchase and Sale Agreement (“JPSA”), IPC has agreed to 17
transfer to the Company a percentage of the assets that make up the existing 500-kV 18
and 345-kV transmission lines between the Borah, Kinport, Adelaide, Midpoint and 19
Hemingway substations.12 Similarly, as defined in the JPSA, the Company has agreed 20
to transfer to IPC a percentage of the assets that make up the existing 345-kV 21
transmission lines connecting the Populus substation to the Four Corners substation.13 22
12 Term Sheet at 13-14. 13 Id. at 13.
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Finally, the Company has agreed to transfer to IPC certain Goshen area transmission 1
assets, which would allow IPC to provide transmission service to all BPA customers in 2
southeast Idaho currently served by the Company.14 3
Q. Has the Company executed agreements for these asset exchanges? 4
A. No, the Company is finalizing the terms of the agreement with IPC that will 5
memorialize this asset exchange, which is referred to as the Joint Purchase and Sale 6
Agreement. The parties anticipate finalizing and executing this agreement in March 7
2023. 8
Q. Is the Company requesting approval of these asset exchanges in this case? 9
A. No. The asset exchanges will not take effect until energization of the B2H Project 10
which is expected to occur in 2026. The Company does not request approval of these 11
asset exchanges at this time. 12
Q. Please summarize the asset exchanges between Borah/Kinport, Hemingway, 13
Midpoint, and Borah/Kinport. 14
A. The transfer by IPC to the Company of Borah/Midpoint West assets will provide 15
ownership to PacifiCorp on the Company’s existing transmission system from 16
Borah/Kinport to Hemingway (east-to-west) and from Midpoint 500 to Borah/Kinport 17
(west-to-east), including 500-kV and 345-kV transmission lines creating a path 18
between the Borah, Kinport, Adelaide, Midpoint and Hemingway substations. 19
Q. Will the Company be responsible for upgrading those transmission facilities? 20
A. Upgrades will be required across the Borah West and Midpoint West paths to facilitate 21
this portion of the proposed asset exchange. This includes the installation of a series 22
14 Id. at 14.
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capacitor bank on the Kinport-Midpoint 345-kV transmission line. However, IPC will 1
be responsible for these upgrades under the to-be-executed Kinport Capacitor Bank 2
Construction Agreement. I discuss this agreement in greater detail below. 3
Q. Please summarize the Populus to Four Corners asset exchanges. 4
A. The Company will assign to IPC ownership of a percentage of the assets that make up 5
the existing PacifiCorp transmission system from Four Corners substation in New 6
Mexico to Populus substation in Idaho. This will include 345 kV transmission lines 7
between the following substations and assets to create a path through each substation: 8
Four Corners, Pinto, Huntington, Camp Williams, Mona, Terminal, 90th South, Ben 9
Lomond and Populus.15 10
Q. Will the Populus to Four Corners asset exchange require upgrades? 11
A. The Company has not yet determined whether upgrades will be necessary. Consistent 12
with federal processes, the Company and IPC will complete required studies to 13
determine whether recent system upgrades result in a possible increase in existing 14
transmission capacity between Borah and Populus to facilitate IPC’s incremental 15
transfer needs associated with this exchange. If determined necessary, the parties will 16
identify revisions to existing agreements, upgrades, modifications, or other options to 17
meet each party’s commercial needs between Borah and Populus. 18
Q. Please summarize the Goshen area asset exchange. 19
A. The Company will transfer to IPC certain Goshen area transmission assets that will 20
allow IPC to provide transmission service to all BPA customers in southeast Idaho 21
currently served by the Company. The Company and IPC will make best efforts to 22
15 Id. at 13.
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allow IPC to serve these customers with only one leg of firm IPC network transmission 1
service.16 2
Q. Will the Company implement an agreement for the Goshen area asset exchange? 3
A. The Goshen area assets to be exchanged are part of the Joint Purchase and Sale 4
Agreement discussed above that is being finalized for execution in March 2023. 5
VII. AGREEMENTS RELATING TO B2H 6
Q. Do agreements relating to B2H remain outstanding? 7
A. Yes. The Term Sheet identifies the remaining agreements between the Company, IPC, 8
and BPA. In my testimony, I will discuss eight of these agreements. Four additional 9
agreements are discussed in Mr. Link’s testimony. 10
Q. Which agreements will you be discussing in your testimony? 11
A. I will discuss the Second Amended and Restated B2H Joint Permit Funding 12
Agreement; the JPSA; the Second Amended and Restated Joint Ownership and 13
Operating Agreement (“JOOA”); the B2H Joint Construction Funding Agreement; the 14
Longhorn Substation Funding Agreement; the Midpoint 500/345-kV Transformer 15
Project Construction Agreement (“Midpoint Transformer Construction Agreement”); 16
the Kinport – Midpoint 345-kV Series Capacitor Bank Project Construction Agreement 17
(“Kinport Capacitor Bank Construction Agreement”); and the Coordination Agreement 18
for the Meridian Series Capacitor Bank Project. 19
Q. Are there any agreements relating to B2H that neither you nor Mr. Link address 20
in your testimonies? 21
A. Yes. Neither Mr. Link nor I discuss the agreements to which only BPA and IPC are 22
16 Id. at 15.
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parties. These agreements include: Network Integration Transmission Service 1
Agreement (“NITSA”) for Goshen Load; NITSA for Idaho Falls Load; and the 2
Purchase, Sale, and Security Agreement. 3
Q. Please summarize the Second Amended and Restated B2H Joint Permit Funding 4
Agreement. 5
A. The Second Amended and Restated Joint Permit Funding Agreement provides 6
definitive terms and conditions by which the Company, IPC, and BPA will jointly 7
support and contribute funds to the processes associated with obtaining necessary 8
governmental authorizations and completing other necessary work to permit, site, and 9
acquire rights-of-way for B2H. 10
The parties executed the initial Joint Permit Funding Agreement on January 12, 11
2012. The second amendment recognizes the reallocation of the parties’ permitting 12
interest and related funding obligations following the transfer of BPA’s permitting 13
interest to IPC. As discussed above, IPC’s interest will increase because IPC will 14
assume the ownership interest that had previously been assigned to BPA. Upon 15
execution, IPC’s permitting interest will increase to 45.45 percent and PacifiCorp’s 16
permitting interest will remain at 54.55 percent. 17
Q. When does the Company expect to execute the Second Amended and Restated 18
B2H Joint Permit Funding Agreement? 19
A. Because BPA is a party to the Second Amended and Restated B2H Joint Permit 20
Funding Agreement, the agreement must be submitted through BPA’s public notice 21
process. BPA’s public process typically concludes within three months of BPA’s 22
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provision of notice to the region, and the public process for B2H is expected to be 1
complete by March 2023, and the parties will execute the agreement shortly thereafter. 2
Q. Has BPA begun the public process for their proposed new role in the B2H project? 3
A. Yes. On January 3, 2023, BPA provided public notice via their Tech Forum platform 4
to customers and stakeholders announcing their completion of B2H project 5
negotiations and releasing the customer engagement schedule, identifying dates for the 6
comment period, customer workshop, and an expected final decision in March 2023. 7
BPA released its letter to the region formally opening the comment period on January 9, 8
2023. 9
Q. Please summarize the JPSA. 10
A. The JPSA implements the asset exchanges discussed above. The Company and IPC 11
desired to exchange undivided ownership interests in certain transmission assets to 12
provide transmission capacity that better aligns with the current configuration of the 13
parties’ respective future needs following the addition of B2H. The JPSA facilitates 14
these asset exchanges and is contingent upon regulatory approvals for both parties. 15
Q. Which sale provisions are governed by the JPSA? 16
A. Under the proposed JPSA: 17
1. The Company will convey to IPC an ownership interest in identified Four 18
Corners/Populus assets; 19
2. The Company will convey to IPC an ownership interest in identified 20
Goshen area assets, 21
3. IPC will convey to the Company an ownership interest in identified 22
Borah/Midpoint West assets, and 23
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4. The purchase price of the assets being conveyed will be equal to the 1
conveying party’s net book value. 2
Q. When does the Company expect to execute the JPSA? 3
A. Although BPA is not a party to the JPSA, the JPSA reflects BPA’s decision to remove 4
its ownership interest of B2H. For that reason, the Company and IPC expect to execute 5
the JPSA following the completion of BPA’s notice proceedings in March 2023. 6
Q. Please summarize the Second Amended and Restated JOOA. 7
A. The Company and IPC will expand the existing JOOA, as amended and restated August 8
22, 2019, to include ownership, operation and maintenance provisions associated with 9
the B2H project. In addition, the Second Amended and Restated JOOA will include: 10
1. Operation and maintenance provisions associated with the assets acquired 11
by both parties under the JPSA; 12
2. The transfer of ownership by IPC to the Company for 300 MW of west-to-13
east transmission assets between Midpoint and Borah; 14
3. The transfer of ownership by IPC to the Company for an additional 600 15
MW of east-to-west transmission assets between Borah and Hemingway; 16
and 17
4. The transfer of ownership by the Company of 200 MW of bi-directional 18
transmission assets between Populus, Mona and Four Corners. 19
Q. What will be the expected effective date of the Second Amended and Restated 20
JOOA? 21
A. The Company and IPC expect the Second Amended and Restated JOOA to take effect 22
upon energization of B2H. 23
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Q. Please summarize the B2H Joint Construction Funding Agreement. 1
A. This agreement will provide definitive terms and conditions by which IPC and the 2
Company will jointly support and contribute funds for the procurement, construction, 3
and commissioning of B2H to allow for energization of the project by the earliest in-4
service date needed by the parties. In addition, it appoints IPC as the construction 5
project manager for development and construction of the B2H project. 6
Q. Which B2H stakeholders are parties to the B2H Joint Construction Funding 7
Agreement? 8
A. The Company and IPC will execute the B2H Joint Construction Funding Agreement. 9
Q. Has the scope of the B2H Joint Construction Funding Agreement expanded? 10
A. Yes. The Midline Series Capacitor Project Funding Agreement identified in § 3(a)(12) 11
of the Term Sheet was initially identified as a separate agreement but construction of 12
the Midline Series Capacity was subsequently incorporated into the overall 13
construction plan for B2H. The work will include installation of the Midline Series 14
Capacitor substation, which is necessary to reduce simultaneous interactions between 15
the NW AC Intertie, central and southern Oregon load service, and Path 14 (Idaho to 16
Northwest). 17
Q. What will be the expected execution date of the B2H Joint Construction Funding 18
Agreement? 19
A. The Company and IPC expect to execute this agreement in July 2023, prior to 20
construction of B2H. 21
Q. Please summarize the Longhorn Substation Funding Agreement. 22
A. The Longhorn Substation Funding Agreement is an agreement between the Company, 23
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IPC, and BPA detailing the conditions for construction of the proposed Longhorn 1
substation, which is the expected western terminal of B2H. The substation will be 2
constructed on land currently owned by BPA. 3
Provisions will include: 4
1. A use-of-facilities charge or other charge pursuant to BPA’s OATT to be 5
paid by IPC and the Company to allow the parties to transact across the 6
Longhorn bus in the future; and 7
2. Ownership, operation, and maintenance of B2H equipment by IPC and the 8
Company, including: 9
a. A B2H project-related series capacitor at the Longhorn substation; 10
b. The B2H project shunt line reactors at Longhorn; and 11
c. Any ancillary equipment required to support the B2H project series 12
capacitor and shunt line reactors. 13
The agreement will be contingent upon BPA completing its obligations and 14
responsibilities under various environmental compliance laws. 15
Q. Please summarize the Midpoint Transformer Construction Agreement. 16
A. The Midpoint Transformer Construction Agreement is an agreement between IPC and 17
the Company detailing the terms for upgrading the Midpoint transmission assets. As 18
discussed above, IPC will transfer to the Company a percentage of the assets that make 19
up the existing Midpoint transmission lines. Under the Midpoint Transformer 20
Construction Agreement, IPC will make capital upgrades to the Midpoint 500-kV and 21
345-kV transmission substations, including a second 500/345-kV transformer bank and 22
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345-kV tie line. The parties will jointly own the assets as illustrated in Exhibit A of the 1
JPSA and in accordance with the Second Amended and Restated JOOA. 2
Q. Please summarize the Kinport Capacitor Bank Construction Agreement. 3
A. The Kinport Capacitor Bank Construction Agreement will be a contract between the 4
Company and IPC detailing improvements to the Kinport transmission assets. As 5
discussed above, IPC will transfer these assets to the Company. 6
Under the Kinport Capacitor Bank Construction Agreement, IPC will make 7
capital upgrades to the Midpoint 345-kV transmission line, by installing the Kinport-8
Midpoint 345-kV Series Capacitor Bank. The parties will jointly own the assets as 9
illustrated in Exhibit A of the JPSA and in accordance with the Second Amended and 10
Restated JOOA. 11
Q. Please summarize the Coordination Agreement for the Meridian Series Capacitor 12
Bank Project. 13
A. This is an agreement between the Company and BPA. The Company and BPA will 14
draft a coordination agreement that sets forth the agreed process for the Company’s 15
intended upgrade, upon BPA notice, of the existing Meridian series capacitor banks on 16
the Company’s segment of the Dixonville-Meridian-Klamath Falls-Captain Jack lines 17
in southern Oregon, as detailed in March 2021 report titled “Phase II Joint Study Report 18
(2020-2021), Boardman to Hemingway (B2H) and Incremental Central Oregon Load.” 19
VIII. RECOMMENDATION AND CONCLUSION 20
Q. Please summarize your recommendation to the Commission. 21
A. I recommend that the Commission approve the Company's Application. B2H will 22
provide substantial benefits to its customers and the construction of B2H is necessary 23
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and in the public interest. Based on this conclusion, I recommend that the Commission 1
grant the Company a CPCN for B2H no later than June 30, 2023, to ensure IPC may 2
begin timely construction of B2H in time to complete the Project by the expected 2026 3
in-service date. 4
Q. Does this conclude your direct testimony? 5
A. Yes. 6