20230127Application_Exhibits.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

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
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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.
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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
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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
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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
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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
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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