20250307Direct Testimony J. Ellsworth - Redacted.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF IDAHO POWER )
COMPANY' S APPLICATION FOR A ) CASE NO. IPC-E-25-08
CERTIFICATE OF PUBLIC )
CONVENIENCE AND NECESSITY FOR AN )
OWNERSHIP INTEREST IN THE )
SOUTHWEST INTERTIE PROJECT - )
NORTH 500-KV TRANSMISSION LINE )
AND APPROVAL OF THE UTILIZATION )
OF CAPACITY ON THE LINE. )
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
JARED L. ELLSWORTH

1 Q. Please state your name, business address, and
2 present position with Idaho Power Company ("Idaho Power" or
3 "Company") .
4 A. My name is Jared L. Ellsworth and my business
5 address is 1221 West Idaho Street, Boise, Idaho 83702 . I
6 am employed by Idaho Power as the Transmission,
7 Distribution & Resource Planning Director for the Planning,
8 Engineering & Construction Department.
9 Q. Please describe your educational background.
10 A. I graduated in 2004 and 2010 from the
11 University of Idaho in Moscow, Idaho, receiving a Bachelor
12 of Science Degree and Master of Engineering Degree in
13 Electrical Engineering, respectively. I am a licensed
14 professional engineer in the State of Idaho.
15 Q. Please describe your work experience with
16 Idaho Power.
17 A. In 2004, I was hired as a Distribution
18 Planning engineer in the Company' s Delivery Planning
19 department. In 2007, I moved into the System Planning
20 department, where my principal responsibilities included
21 planning for bulk high-voltage transmission and substation
22 projects, generation interconnection projects, and North
23 American Electric Reliability Corporation' s ("NERC")
24 reliability compliance standards . I transitioned into the
25 Transmission Policy & Development group with a similar
ELLSWORTH, DI 1
Idaho Power Company

1 role, and in 2013, I spent a year cross-training with the
2 Company' s Load Serving Operations group. In 2014, I was
3 promoted to Engineering Leader of the Transmission Policy &
4 Development department and assumed leadership of the System
5 Planning group in 2018 . In early 2020, I was promoted into
6 my current role as the Transmission, Distribution and
7 Resource Planning Director. I am currently responsible for
8 the planning of the Company' s wires and resources to
9 continue to provide customers with cost-effective and
10 reliable electrical service.
11 Q. What is Idaho Power' s request in this case?
12 A. The Company is requesting the Idaho Public
13 Utilities Commission ("Commission") issue an order: (1)
14 granting a Certificate of Public Convenience and Necessity
15 ("CPCN") for Idaho Power' s ownership interest in the
16 Southwest Intertie Project - North 500-kilovolt ("kV")
17 transmission line ("SWIP-North" or "Project") , including
18 the rights to 250 megawatts ("MW") of the northbound
19 capacity, and (2) approving the Company' s utilization of an
20 additional 250 MW of GBT Northbound, LLC ("GBT Northbound")
21 rights to the northbound capacity, both via the SWIP-North
22 agreements described herein. In total, the Company will
23 gain 500 MW of south-to-north capacity on the total
24 Southwest Intertie Project transmission line ("Total
ELLSWORTH, DI 2
Idaho Power Company

1 SWIP") , ' providing a cost-effective resource addition
2 necessary to meet identified capacity deficiencies .
3 Q. What is the purpose of your testimony in this
4 case?
5 A. The purpose of my testimony is to present the
6 need and justification for the Company' s participation in
7 the Project and the associated SWIP-North agreements the
8 Company entered into with the Project developer Great Basin
9 Transmission, LLC ("GBT") and its subsidiary, GBT
10 Northbound, including the: (1) Participation and Joint
11 Ownership Agreement by and among Great Basin Transmission,
12 LLC, GBT Northbound, LLC, and Idaho Power Company dated as
13 of February 13, 2025 ("Participation and Ownership
14 Agreement") , (2) Capacity Entitlement Agreement by and
15 between GBT Northbound, LLC and Idaho Power Company dated
16 as of February 13, 2025, (3) Purchase and Sale Agreement by
17 and between GBT Northbound, LLC and Idaho Power Company
18 dated as of February 13, 2025, and (4) Purchase Option
19 Agreement by and between GBT Northbound, LLC and Idaho
20 Power Company dated as of February 13, 2025, (collectively,
21 the "Definitive Agreements") . The following is a summary of
22 the items I will discuss at length in my testimony:
23
24
1 Inclusive of SWIP-North and SWIP-South.
ELLSWORTH, DI 3
Idaho Power Company

1 0 Project Overview: SWIP-North is an
2 approximately 285 mile, near shovel ready, 500-kV line
3 that will connect the Midpoint substation, near Shoshone,
4 Idaho, to the Robinson Summit substation, near Ely,
5 Nevada. SWIP-North will connect to the existing Southwest
6 Intertie Project - South 500-kV line ("SWIP-South") , an
7 existing 231 mile 500-kV line that extends between the
8 Robinson Summit substation and the Harry Allen substation,
9 northeast of Las Vegas . When combined, SWIP-North and
10 SWIP-South form the Total SWIP.
11 0 Project Load Serving Capacity: Once
12 constructed, SWIP-North unlocks 1, 117 . 5 MW of north-to-
13 south capacity and 1, 072 . 5 MW of south-to-north capacity
14 across the Total SWIP, providing the Company access to a
15 geographically diverse region within the Western
16 Interconnection. Idaho Power will gain 500 MW of access to
17 the Desert Southwest ("DSW") markets via the south-to-
18 north capacity on SWIP-North, enabling access to surplus
19 power from the DSW markets all year around, but especially
20 in the winter months .
21 0 Project Economics : The Company first
22 identified the Project as providing potential value during
23 development of the Company' s 2021 Integrated Resource Plan
24 ("IRP") . After engaging with the Project developer in
25 2022, Idaho Power evaluated SWIP-North as a resource
ELLSWORTH, DI 4
Idaho Power Company

1 coincident with modeling of the Company' s 2023 IRP,
2 assuming an approximate 23 percent Idaho Power interest in
3 the Project.
4 • Project Evaluation: The initial modeling
5 results indicate a portfolio inclusive of SWIP-North
6 minimizes both cost and risk, with total portfolio costs
7 to lower on a net present value
8 ("NPV") basis when compared to non-SWIP portfolio costs,
9 showing that SWIP-North is a valuable component of the
10 Company' s future resource portfolio . Idaho Power did not
11 publish SWIP-North related benefits in its 2023 IRP to
12 preserve its negotiating position and to achieve the best
13 agreement for Idaho Power' s customers and is doing so now
14 as a result of the execution of the Definitive Agreements .
15 0 Unique Project Attributes : Idaho Power' s
16 participation in SWIP-North is a unique and time-limited
17 opportunity. Due to the Project' s late stage in
18 development, it has been significantly de-risked by the
19 Project developer, with: (1) major federal permits
20 secured, (2) nearly all right-of-way easements secured,
21 (3) procurement underway for project materials, and (4) a
22 construction contractor for the transmission line secured.
23 Additionally, on January 21, 2025, the Federal Energy
24 Regulatory Commission ("FERC") approved the project
25 development agreement between the California Independent
ELLSWORTH, DI 5
Idaho Power Company

1 System Operator ("'CAISO") and GBT, allocating
2 approximately 77 percent of the costs associated with the
3 Project to CAISO, which, with GBT' s 77 percent majority
4 ownership in the Project, makes CAISO the key anchor
5 tenant of the Project .
6 0 Other Project Benefits : The Project also
7 offers other financial, risk, and reliability benefits
8 such as : (1) grid reliability/resiliency, (2) economic
9 efficiency, (3) improved resource reliability for existing
10 Idaho Power resources, (4) support of contingency
11 reserves, (5) the indefinite deferral of two planned
12 transmission facilities, and (6) cost controls inherent
13 with facility ownership.
14 Q. Have you prepared any Exhibits?
15 A. Yes . Exhibit No. 1 is a map of the proposed
16 SWIP-North transmission line. Exhibit No. 2 is the Second
17 Amended and Restated Transmission Use and Capacity Exchange
18 Agreement by and among Nevada Power Company, Sierra Pacific
19 Power Company, Great Basin Transmission South, LLC, and
20 Great Basin Transmission, LLC, dated as of June 30, 2020
21 ("TUA") . Exhibit No. 3 details capacity allocations across
22 SWIP-North, SWIP-South, and Total SWIP. Exhibit No. 4 is
23 the SWIP-North Phase 2 Study Report - Western Electricity
24 Coordinating Council ("WECC") Rating Process . Confidential
25 Exhibit No. 5 are the Definitive Agreements that detail the
ELLSWORTH, DI 6
Idaho Power Company

1 Company' s participation and ownership in SWIP-North.
2 Exhibit No . 6 presents Idaho Power' s transmission system.
3 Exhibit No . 7 details the depth of the DSW market in the
4 summer and winter. Exhibit No. 8 includes a dynamic
5 illustration of real time wholesale electricity prices
6 across the United States during the January 12-14, 2024,
7 time period. Exhibit No. 9 illustrates the regional net
8 imports and exports that occurred during the January 2024
9 winter event.
10 I . THE SOUTHWEST INTERTIE PROJECT
11 Q. Please describe the Total SWIP.
12 A. The Total SWIP is comprised of two individual
13 projects, SWIP-South and SWIP-North. SWIP-South, also
14 known as the ON Line, is a 231 mile 500-kV line between
15 the Robinson Summit substation and the Harry Allen
16 substation, northeast of Las Vegas, Nevada. SWIP-South was
17 placed in service in 2014 and is jointly owned by Great
18 Basin Transmission South, LLC ("GBT South") (75 percent)
19 and NV Energy (25 percent) . NV Energy currently has rights
20 to 100 percent of the capacity benefits associated with
21 SWIP-South while also compensating GBT South for GBT
22 South' s 75 percent ownership via TUA payments .
23 The SWIP-North line is a planned 285-mile, near-
24 shovel-ready, 500-kV transmission line being developed by
ELLSWORTH, DI 7
Idaho Power Company

1 GBT, a wholly owned affiliate of LS Power Development2.
2 Once constructed, SWIP-North will provide a connection
3 between Idaho Power' s Midpoint substation near Shoshone,
4 Idaho, and the Robinson Summit substation near Ely,
5 Nevada, owned by NV Energy and GBT South. Robinson Summit
6 connects to the existing and in-service SWIP-South 500-kV
7 line . Exhibit No. 1 is a map of Total SWIP, including both
8 SWIP-South and the proposed SWIP-North line .
9 Q. Is there an agreement that governs the
10 ownership and capacity associated with any of the SWIP
11 segments?
12 A. Yes . The ownership and capacity entitlements
13 associated with SWIP-South, as well as SWIP-North and
14 Total SWIP once completed, are all governed by the TUA
15 between GBT, GBT South, Nevada Power Company, and Sierra
16 Pacific Power Company. Both Nevada Power Company and
17 Sierra Pacific Power Company conduct business as NV Energy
18 so are collectively referred to as NV Energy. The TUA is
19 included as Exhibit No. 2 to my testimony. It is important
20 to note that the capacity entitlements defined by the TUA
21 are separate and not dependent on the ownership of the
2 LS Power Development is a major energy development company. Magic Valley
Energy, LLC, a subsidiary of LS Power, is developing the Lava Ridge and Salmon
Falls wind generation projects in southern Idaho. SWIP-North is a transmission-
only project that is entirely independent of the Lava Ridge and Salmon Falls
projects.
3 In February 2011 GBT assigned all of its ownership interest in SWIP-South to
GBT South but retained its obligations under the original Transmission Use and
Capacity Agreement dated August 20, 2010 ("Original TUA") , on a joint and
several basis with GBT South.
ELLSWORTH, DI 8
Idaho Power Company

1 physical transmission assets . Under the TUA, GBT South and
2 NV Energy agreed to build the southern half of the Total
3 SWIP project, SWIP-South, as the first phase of the
4 project, which has been providing NV Energy benefits over
5 the prior decade . In addition, the TUA contemplated SWIP-
E North and the Total SWIP as a whole and therefore contains
7 definitive provisions for both.3
8 Q. What are the pertinent provisions in the TUA
9 related to SWIP-South?
10 A. Immediately following completion of SWIP-
11 South, NV Energy owned 25 percent of SWIP-South, which was
12 obtained through payment of 25 percent of the SWIP-South
13 costs . GBT South funded the remaining 75 percent of the
14 costs but is receiving recovery of those costs through TUA
15 payments from NV Energy. Given NV Energy customers are
16 ultimately paying for all SWIP-South costs, all rights
17 associated with SWIP-South are currently allocated to NV
18 Energy and NV Energy controls all capacity associated with
19 SWIP-South.
20 Q. What definitive provisions between GBT/GBT
21 South and NV Energy does the TUA include with respect to
22 SWIP-North once the line is energized and the resulting
3 In February 2011 GBT assigned all of its ownership interest in SWIP-South to
GBT South but retained its obligations under the original Transmission Use and
Capacity Agreement dated August 20, 2010 ("Original TUA") , on a joint and
several basis with GBT South.
ELLSWORTH, DI 9
Idaho Power Company

1 Total SWIP is entered in-service?
2 A. In terms of payments and costs, nothing
3 changes between GBT South and NV Energy. NV Energy will
4 continue to fund all costs associated with SWIP-South
5 through the TUA payments to GBT South and GBT South will
6 continue to own its share of SWIP-South assets . However,
7 pursuant to the TUA, the transmission capacity allocations
8 across SWIP-South will change upon installation of SWIP-
9 North. As the owner and developer of SWIP-North, and an
10 affiliate of GBT South, GBT will receive a portion of the
11 capacity across SWIP-South, and NV Energy gains capacity
12 across SWIP-North. These capacity allocations are detailed
13 in Exhibit No. 3 . Table 1 summarizes the capacity
14 allocations prior to SWIP-North energization.
15 Table 1 . Capacity Prior to SWIP-North Energization
SWIP-South SWIP-North
North-to- South-to- North-to- South-to-
South North South North
NV Energy 900 MW 600 MW N/A N/A
GBT 0 MW 0 MW N/A N/A
16 As can be seen, NV Energy has the rights to 100 percent of
17 the capacity on SWIP-South prior to energization of SWIP-
18 North, which is limited to about 900 MW north-to-south
19 capacity, and 600 MW south-to-north capacity. Table 2
20 summarizes the capacity allocations following SWIP-North
21 energization.
ELLSWORTH, DI 10
Idaho Power Company

1 Table 2 . Capacity Following SWIP-North Energization
SWIP-South SWIP-North
North-to- South-to- North-to- South-to-
South North South North
NV Energy 1, 217 . 5 MW 1, 172 . 5 MW 952 . 5 MW 847 . 5 MW
GBT 1, 117 . 5 MW 1, 072 . 5 MW 1, 117 . 5 MW 1, 072 . 5 MW
2 Following the addition of SWIP-North, NV Energy' s SWIP-
3 South capacity increases to 1, 217 . 5 MW north-to-south and
4 1, 172 . 5 MW south-to-north. NV Energy also gains 952 . 5 MW
5 of north-to-south capacity and 847 . 5 MW of south-to-north
6 capacity in SWIP-North. Further, GBT gains 1, 117 . 5 MW of
7 north-to-south and 1, 072 . 5 MW of south-to-north capacity
8 across the Total SWIP project . In total, GBT will gain
9 2, 190 MW of capacity (1, 117 . 5 MW (north-to-south) +
10 1, 072 . 5 MW (south-to-north) = 2, 190 MW) .
11 Q. Has the capacity the parties will gain with
12 the addition of SWIP-North been confirmed?
13 A. Yes . The transfer capability gains have been
14 confirmed through the WECC Path Rating Process as detailed
15 in the SWIP-North Phase 2 Study Report, included as
16 Exhibit No . 4, and allocated in accordance with the TUA
17 which is Exhibit No . 2 .
18 Q. You indicated that post SWIP-North
19 energization NV Energy will continue to pay for all of the
20 construction and maintenance costs of SWIP-South and GBT
21 will pay for all of the construction and maintenance costs
ELLSWORTH, DI 11
Idaho Power Company

1 of SWIP-North. Does the TUA consider ownership changes
2 associated with any of the SWIP segments that align with
3 the change in the capacity allocations you described once
4 SWIP-North is energized?
5 A. No. Ownership interests and transmission
6 capacity entitlements are separate and distinct items in
7 the TUA. Under the current TUA, NV Energy only has an
8 ownership interest in SWIP-South. GBT only has an
9 ownership interest in SWIP-North. However, both parties
10 will have capacity entitlements across the Total SWIP - in
11 perpetuity - regardless of any potential future changes in
12 ownership interests in the Total SWIP segments . Idaho
13 Power' s interest will be derived from GBT' s rights under
14 the TUA, and Idaho Power will own a portion of SWIP-North
15 and gain 500 MW of capacity entitlements across the Total
16 SWIP.
17 Q. When does GBT expect SWIP-North will be
18 energized?
19 A. SWIP-North is nearly construction ready and
20 planned to be online in 2028 . As such, GBT began
21 negotiations to contract the additional capacity
22 entitlements gained along Total SWIP once SWIP-North is
23 energized, including dedicating all its capacity
24 entitlements to CAISO except for 500 MW of south-to-north
25 capacity entitlements which will be dedicated to Idaho
ELLSWORTH, DI 12
Idaho Power Company

1 Power. On January 21, 2025, FERC approved the project
2 development agreement between CAISO and GBT . The Company' s
3 participation in, and joint ownership of, SWIP-North has
4 been memorialized in the Definitive Agreements for which
5 Idaho Power is requesting approval in this case .
6 Q. What SWIP-North permitting activities remain?
7 A. Aside from a Utility Environmental Protection
8 Act permit from the Public Utilities Commission of Nevada,
9 SWIP-North is awaiting certain routine state and local
10 permits and a final Notice to Proceed from the Bureau of
11 Land Management ("BLM") , which is pending cultural studies
12 that are expected to be completed in 2025 . Construction of
13 SWIP-North cannot begin until the Notice to Proceed is
14 received. In addition, the BLM is processing an
15 application from GBT South and NV Energy for expansion of
16 Robinson Summit substation in White Pine County, Nevada,
17 which is expected to be authorized by early 2026 .
18 II . THE DEFINITIVE AGREEMENTS
19 Q. Please describe the provisions of the
20 Definitive Agreements associated with Idaho Power' s
21 interest in SWIP-North.
22 A. The Definitive Agreements, included as
23 Confidential Exhibit No . 5 to my testimony, address SWIP-
24 North ownership, the Company' s entitlement rights to
25 utilize SWIP-South capacity and transact across the Total
ELLSWORTH, DI 13
Idaho Power Company

1 SWIP, conditions precedent to construction, rights during
2 construction, and Project upgrade rights, among other
3 general contract provisions . Under the Definitive
4 Agreements, the Company will secure a capacity entitlement
5 in SWIP-North to utilize 500 MW of south-to-north
6 capacity, representing 46 . 62 percent of GBT' s 1, 072 . 5 MW
7 of south-to-north capacity, and 22 . 83 percent of GBT' s
8 2, 190 MW of Total SWIP capacity.
9 Q. Will GBT retain the remaining capacity
10 entitlement interest in SWIP-North?
11 A. Yes, but GBT will not be the entity that
12 utilizes the capacity. Though not a party to the
13 Definitive Agreements, GBT and Idaho Power acknowledge
14 that CAISO will be entitled to all remaining GBT capacity
15 in the project, the remaining 572 . 5 MW of south-to-north
16 capacity as well as the 1, 117 . 5 MW of north-to-south
17 capacity. This capacity arrangement is outlined in the
18 development agreement between GBT and CAISO.
19 Q. Does Idaho Power' s 22 . 83 percent capacity
20 entitlement in SWIP-North equate to an equivalent
21 ownership structure?
22 A. No. Once energized, Idaho Power will acquire
23 an undivided ownership interest in approximately 11 . 4
24 percent, providing 250 MW of northbound capacity, of SWIP-
25 North, fully funding the capital requirements of this
ELLSWORTH, DI 14
Idaho Power Company

1 portion of the Project . GBT Northbound will own the
2 remaining approximately 11 . 4 percent interest in SWIP-
3 North, and will provide the asset, and its additional 250
4 MW of northbound capacity, to Idaho Power to utilize via
5 the Capacity Entitlement Agreement, which is included
6 within the Definitive Agreements provided as Confidential
7 Exhibit No. 5 to my testimony.
8 Q. Please explain the Capacity Entitlement
9 Agreement.
10 A. Under the Capacity Entitlement Agreement, the
11 Company will be given the entitlement right to utilize the
12 approximately 250 MW of capacity for 40 years, with the
13 potential for a 12-year extension. Following the 40-year
14 term, Idaho Power will have the option to purchase the
15 asset from GBT Northbound.
16 Q. Please explain the Company' s purchase option.
17 A. On the year prior to the completion of the 40-
18 year capacity entitlement term, the Company has an option
19 to purchase the full ownership interest associated with
20 the capacity entitlement from GBT Northbound. The purchase
21 price will be the fair market value of the asset,
22 predetermined at this time to be : (1) 44 . 4 percent of the
23 initial installation value, plus (2) the net book value,
24 with an inflation index, of any additional investments
25 made to the line over the 40-years following energization
ELLSWORTH, DI 15
Idaho Power Company

1 of the Project.
2 Q. Is the ownership structure of SWIP-North under
3 the Capacity Entitlement Agreement between GBT and Idaho
4 Power similar to the ownership structure of SWIP-South
5 under the TUA between GBT South and NV Energy?
6 A. Yes . Similar to GBT South and NV Energy' s
7 existing ownership structure of SWIP-South, initially the
8 Company, GBT, and GBT Northbound will jointly own SWIP-
9 North, with Idaho Power making TUA payments to GBT
10 Northbound for the capacity entitlement of approximately
11 250 MW.
12 Q. What rights differentiate Idaho Power' s
13 ownership interest in SWIP-North compared to the Company' s
14 capacity entitlement interest in SWIP-North?
15 A. Idaho Power' s rights associated with its
16 ownership interest and capacity entitlement interest in
17 the Project are functionally equivalent . Capacity
18 associated with each interest will not be differentiated
19 from a transmission usage perspective, similar transfer
20 rights exist between each interest, and Idaho Power will
21 enjoy any upgrade capacity associated with each interest
22 as the Company will gain a proportional share of that
23 rating increase .
24 Q. If the rights associated with the ownership
25 interest are functionally equivalent to the rights
ELLSWORTH, DI 16
Idaho Power Company

1 associated with the capacity entitlement interest, could
2 the Company have instead obtained an ownership interest in
3 100 percent of the 500 MW capacity entitlement in SWIP-
4 North?
5 A. No. GBT was not interested in an ownership
6 structure in which Idaho Power obtained 100 percent of the
7 500 MW capacity entitlement upon energization of SWIP-
8 North. However, a 50/50 ownership structure is not
9 uncommon in the industry given GBT' s primary financial
10 incentive stems from direct ownership of the assets .
11 Further, the costs to Idaho Power' s customers for the
12 ownership interest are estimated to be slightly lower than
13 the capacity entitlement interest . The Company' s ownership
14 interest will be a component of Idaho Power' s rate base,
15 and the capacity entitlement component, which incorporates
16 GBT' s return on their asset, will be an operating expense.
17 Q. Are there any additional provisions of either
18 the TUA or Definitive Agreements you would like to
19 discuss?
20 A. Yes . Under the Definitive Agreements, the
21 Company is responsible for its ownership share of the 0&M
22 costs associated with the Project . Idaho Power will
23 maintain all assets at the Midpoint substation, and it is
24 anticipated that the parties will negotiate an agreement
25 for Idaho Power to also maintain the SWIP-North
ELLSWORTH, DI 17
Idaho Power Company

1 transmission line assets physically within the State of
2 Idaho, although the Company will only be financially
3 responsible for the pro-rata share of the costs . In
4 addition, it is worth noting that NV Energy has existing
5 buy-out rights associated with SWIP-South under the TUA,
6 allowing for the purchase by NV Energy of 100 percent of
7 GBT South' s ownership interest in SWIP-South at certain
8 dates in the future .
9 Q. If NV Energy exercises their buy-out rights,
10 does anything happen to Idaho Power' s capacity rights
11 across SWIP-South and the Total SWIP?
12 A. No. Idaho Power' s capacity entitlement rights
13 across SWIP-South and the Total SWIP will not change if NV
14 Energy exercises its buy-out rights . Once Idaho Power has
15 an ownership interest in SWIP-North, the Company will have
16 a capacity entitlement across the Total SWIP - which the
17 Company has rights to continue in perpetuity - for as long
18 as the project remains in-service . Physical ownership of
19 SWIP-South or SWIP-North may change, but the usefulness of
20 Idaho Power' s capacity across the Total SWIP will remain
21 in place .
22 III . SWIP-NORTH UNIQUE AND TIME LIMITED OPPORTUNITY
23 Q. When did discussions between Idaho Power and
24 GBT regarding the Company' s participation in SWIP-North
25 commence?
ELLSWORTH, DI 18
Idaho Power Company

1 A. Idaho Power first began discussions with GBT
2 in 2022 following an evaluation of a hypothetical SWIP-
3 North scenario as part of the 2021 IRP which identified
4 potential benefits associated with the Project.
5 Q. Please describe the hypothetical study
6 performed as part of the 2021 IRP.
7 A. The SWIP-North Opportunity Study tested
8 whether Idaho Power customers could benefit from the
9 Company' s involvement in the Project assuming a pre-summer
10 2025 in-service date. To determine a cost-estimate for
11 SWIP-North, Idaho Power used publicly available cost data
12 for similar lines recently constructed in Nevada and
13 assumed that the Company would own a 200 MW share of the
14 south-to-north capacity. It was not however considered for
15 inclusion in Idaho Power' s Preferred Portfolio in the 2021
16 IRP due to uncertainty related to total project viability
17 and available partners . The intent of the evaluation was to
18 determine whether further exploration was warranted.
19 Q. What did the SWIP-North Opportunity Study
20 conclude?
21 A. Based on the NPV cost results, the SWIP-North
22 project analyzed in the study indicated further exploration
23 was warranted. As a result, the 2021 IRP, acknowledged by
24 the Commission with Order No. 35603,4 included the following
4 Case No. IPC-E-21-43.
ELLSWORTH, DI 19
Idaho Power Company

1 Action Plan item to occur in 2022 : Discuss partnership
2 opportunities related to SWIP-North with the project
3 developer for more detailed evaluation in future IRPs. As a
4 result, the Company began discussions with GBT and acquired
5 sufficient information to perform a thorough and detailed
6 analysis coincident with the modeling of the 2023 IRP.
7 However, while developing the 2023 IRP, the Company
8 determined that it may undermine negotiations to publish
9 SWIP-North-related benefits in its 2023 IRP while in active
10 negotiations with the Project developer. Participation in
11 SWIP-North is a unique and time-limited opportunity for the
12 Company to pursue. As I will discuss in more detail, SWIP-
13 North provides the Company with a cost-effective resource
14 and is necessary for reliability.
15 SWIP-North, A Unique Opportunity for Idaho Power
16 Q. What makes SWIP-North unique?
17 A. There are three primary items that make the
18 Project unique : (1) the opportunity enabled by the TUA, as
19 discussed earlier in my testimony, that allows the Company
20 to contribute to the 285-mile SWIP-North and gain capacity
21 across the entire 516-mile Total SWIP path; (2) SWIP-North
22 is a rare near-shovel-ready transmission project,
23 eliminating many risks and timelines around extensive
24 permitting requirements, and will connect Idaho Power to
25 the DSW markets; and (3) a cost sharing arrangement (i .e .
ELLSWORTH, DI 20
Idaho Power Company

I partners) is already in place for 100 percent of the
2 Project' s costs and capacity.
3 Q. What opportunity does the TUA provide the
4 Company?
5 A. To understand the opportunity enabled by the
6 TUA, let' s compare it to the alternative. Absent SWIP-
7 North, to provide Idaho Power a transmission connection to
8 the DSW markets and gain similar access, the Company would
9 have to build a new 516-mile transmission line . The TUA
10 reduces that distance by 231 miles due to the existing
11 SWIP-South segment. Additionally, given SWIP-South is
12 already in-service, the risk associated with those 231
13 miles is fully eliminated. The TUA allows Idaho Power to
14 invest in the 285-mile SWIP-North, while gaining capacity
15 across the entire 516-mile Total SWIP.
16 Q. What is the importance of SWIP-North being a
17 near-shovel-ready project?
18 A. Transmission capacity across the Western
19 Interconnection is in very high demand, and entities
20 surrounding Idaho Power are considering transmission
21 projects to reliably serve customers . As explained in the
22 Company' s request in Case No. IPC-E-23-01, Idaho Power' s
23 Application for a Certificate of Public Convenience and
24 Necessity for the Boardman to Hemingway 500-kV Transmission
25 Line, in 2007 the Company began siting and permitting
ELLSWORTH, DI 21
Idaho Power Company

1 activities associated with the Boardman to Hemingway
2 ("B2H") line and after nearly two decades, Idaho Power
3 still does not have B2H in-service due to permitting
4 delays . Similarly, with the Gateway West transmission line
5 project ("Gateway West") , siting and permitting activities
6 for all segments began in 2007 and Gateway West received
7 its record of decision from the Bureau of Land Management
8 for the final segments of the project in 2018, nearly 11
9 years after siting and permitting activities began.
10 Fortunately, the Company is close to the construction of
11 B2H and Gateway West, while many other utilities are just
12 getting started developing transmission projects . Projects
13 being started today likely will not see the fruits of their
14 efforts for more than 10 years . The Company' s participation
15 in SWIP-North allows Idaho Power to largely bypass what
16 would alternatively be a lengthy permitting process, with
17 major uncertainty, and move to construction with reduced
18 potential for delays .
19 Q. What is the significance of SWIP-North already
20 having alignment on cost and capacity partnerships?
21 A. As I discussed, the time between starting
22 development of a major transmission project, and project
23 in-service, often takes well over a decade . Major
24 transmission projects often provide many hundreds or even
25 thousands of MWs of capacity, and for a utility the size of
ELLSWORTH, DI 22
Idaho Power Company

1 Idaho Power, it is often more cost-effective to build these
2 larger projects with partners as it helps reduce costs,
3 while also helping reduce risk.
4 Further, for projects with over a decade between
5 project initiation and project in-service, it is common for
6 partner needs to morph over time. Ten years represents five
7 IRP cycles, multiple election cycles, and varying
8 technology waves . There are no guarantees that by the time
9 the project is ready to be constructed all partners will
10 continue to have a need, or the timing of their need will
11 align. In the case of SWIP-North, CAISO is ready to move
12 forward, and in the case of the Total SWIP, NV Energy is
13 already funding and operating SWIP-South. With alignment on
14 cost and capacity partnerships, SWIP-North partner risks
15 have been addressed.
16 Q. Are there any additional unique opportunities
17 the Project will provide that you would like to discuss?
18 A. Yes . SWIP-North will connect to the Midpoint
19 substation in central Idaho. As shown in the Figure 1
20 below, once SWIP-North, Gateway West, and B2H are
21 constructed, the Midpoint substation will become an
22 important trading hub in the Northwest, increasing energy
23 liquidity in Idaho, providing additional opportunities for
24 the Company to cost-effectively purchase energy for its
25 customers .
ELLSWORTH, DI 23
Idaho Power Company

1 Figure 1 . Future Midpoint Substation Trading Hub
Longhorn
b Midpoint
Hemingway oft low no
am Aeolus
Robinson
El Dorado
2
3 SWIP-North, A Time-Limited Opportunity for Idaho Power
4 Q. Why is SWIP-North a time-limited opportunity?
5 A. To illustrate the time-limited opportunity
6 SWIP-North provides, I am going to discuss the evaluation
7 of three scenarios to consider around timing:
8 • Scenario 1 : Idaho Power is participating in
9 SWIP-North and the Project is moving forward,
10 the Company' s proposal in this case .
11 • Scenario 2 : Idaho Power does not participate in
12 SWIP-North, but the Project still moves
13 forward.
14 • Scenario 3 : Idaho Power does not participate in
15 SWIP-North and the Project fails to move into
ELLSWORTH, DI 24
Idaho Power Company

1 the construction phase by approximately early
2 2029 .
3 Q. If the Company does not participate in SWIP-
4 North, whose participation does Scenario 2 consider?
5 A. Under Scenario 2' s hypothetical future, there
6 are two likely scenarios : (1) CAISO funding 100 percent of
7 the costs and gaining 100 percent of the capacity rather
8 than their current interest in 77 percent of the Project,
9 or (2) the Department of Energy ("DOE") taking on 500 MW of
10 the Project and ultimately transferring their interest to
11 another entity.5
12 Q. Would the Company still benefit from SWIP-
13 North if CAISO funded 100 percent of the Project' s costs?
14 A. Without capacity entitlements, Idaho Power
15 would be able to utilize the Total SWIP capacity as a
16 "wheel-through" across CAISO, but only on an as-available
17 basis . The Company would not be able to plan and rely on a
18 specific amount of capacity availability, because CAISO
19 would fully allocate the transmission capacity to the CAISO
20 market, which will always have priority over Idaho Power.
21 Q. Has the DOE indicated interest in SWIP-North
22 capacity?
23 A. Yes . On April 25, 2024, the DOE announced that
24 they were interested in off taking 500 MW of south-to-north
5 SWIP-N Transmission Facilitation Program (TFP) fact sheet GDO (energy.gov)
ELLSWORTH, DI 25
Idaho Power Company

1 capacity on SWIP-North, the same capacity entitlement Idaho
2 Power would gain under the Definitive Agreements . This is a
3 "back-stop" for GBT in case Idaho Power does not ultimately
4 move forward with SWIP-North. This "back stop" allows GBT
5 to continue to move the Project forward expeditiously, in a
6 reduced-risk manner, until Idaho Power has the appropriate
7 approvals . If a CPCN is issued by the Commission, Idaho
8 Power is committed to the 500 MW of south-to-north capacity
9 and DOE would step away. Absent approval, Idaho Power is
10 not committed to the 500 MW of south-to-north capacity, and
11 the DOE agreement would not be terminated. Idaho Power
12 understands that DOE would attempt to sell the capacity to
13 others, which would make it unavailable to Idaho Power.
14 Q. Under this scenario, could the Company utilize
15 any of NV Energy' s capacity it will gain once the Project
16 is energized?
17 A. NV Energy will gain Total SWIP south-to-north
18 capacity and the Company could potentially secure a long-
19 term point-to-point ("PTP") transmission reservation.
20 However, Idaho Power has concerns with this approach.
21 First, it is not clear if any transmission capacity would
22 be available. NV Energy currently fully allocates south-to-
23 north capacity across SWIP-South for their own needs, and
24 there is zero capacity availability. Second, even if
25 transmission became available, the cost to secure 500 MW of
ELLSWORTH, DI 26
Idaho Power Company

1 PTP capacity is greater than the cost of capacity under the
2 Company' s proposal in this case. Further, NV Energy has
3 major transmission expansion plans associated with their
4 Green Link West and Green Link North projects, so it is
5 highly likely their PTP transmission rate will increase
6 over time, making that option even more costly. Finally, if
7 transmission capacity is available, a third party could
8 pick up the 500 MW PTP reservation before Idaho Power,
9 leaving the Company with no available capacity. Scenario 2
10 is both higher risk and higher cost compared to Scenario 1 .
11 Q. You indicated Scenario 3 considers SWIP-North
12 absent Idaho Power' s participation but then the Project
13 fails to move to construction by approximately early 2029 .
14 Why did the Company evaluate this scenario?
15 A. It is important to evaluate Scenario 3 because
16 it is Idaho Power' s understanding that if SWIP-North does
17 not advance to construction by approximately early 2029, NV
18 Energy has an option to acquire GBT South' s interest in
19 SWIP-South and then could claim all the SWIP-South capacity
20 and effectively terminate the Total SWIP capacity
21 entitlements that benefit GBT and SWIP-North. SWIP-North
22 could still be constructed, but GBT, as the owner of SWIP-
23 North in the TUA, would have no rights beyond the Robinson
24 Summit substation (on SWIP-South) . This makes any value
25 associated with the SWIP-North Project highly uncertain
ELLSWORTH, DI 27
Idaho Power Company

1 beginning in 2029 unless GBT has commenced construction of
2 SWIP-North prior to that time.
3 Q. What did Idaho Power conclude from the
4 scenario evaluations?
5 A. While there is no guarantee the Project would
6 even move forward without the Company, Scenario 2
7 illustrates the urgency behind Idaho Power' s participation
8 in the Project. Absent participation, worst case the
9 Company will gain no value associated with the Project, and
10 best case, will only gain uncertain or more expensive
11 capacity, assuming utilization of the Total SWIP path.
12 Further, Scenario 3 illustrates the urgency behind the
13 Project . As I will discuss in the next section of my
14 testimony, participation in SWIP-North is a cost-effective
15 resource alternative providing benefits to Idaho Power and
16 therefore it is crucial the Company takes advantage of this
17 time-limited opportunity.
18 IV. TRANSMISSION PLANNING AND THE IRP PROCESS
19 Q. You indicated Idaho Power evaluated SWIP-North
20 as a resource within the Company' s 2023 IRP but did not
21 publish the results to preserve its negotiating position.
22 Is the Company able to share the results now that the
23 parties have executed Definitive Agreements?
24 A. Yes . To provide context supporting the
25 evaluation performed as part of the 2023 IRP, I will first
ELLSWORTH, DI 28
Idaho Power Company

1 describe the IRP process that is the basis for the analysis
2 of the Company' s participation in SWIP-North. The goal of
3 the IRP is to ensure: (1) Idaho Power' s system has
4 sufficient resources to reliably serve customer demand and
5 flexible capacity needs over a 20-year planning period, (2)
6 the selected resource portfolio balances cost, risk, and
7 environmental concerns, (3) balanced treatment is given to
8 both supply-side resources and demand-side measures, and
9 (4) the public is involved in the planning process in a
10 meaningful way. Idaho Power uses AURORA, Energy Exemplar' s
11 Long Term Capacity Expansion ("LTCE") modeling platform, to
12 develop portfolios, through the selection of a variety of
13 supply- and demand-side resource options, that are least-
14 cost for a variety of alternative future scenarios while
15 meeting reliability criteria. To verify the top performing
16 portfolios meet the Company' s reliability requirements,
17 Idaho Power uses a Loss of Load Expectation ("LOLE")
18 methodology.
19 Q. Please explain the Loss of Load Expectation.
20 A. The LOLE is a statistical measure of a
21 system' s resource adequacy, describing the expected number
22 of event-days per year that a system would be unable to
23 meet demand. As utilities continue to add more renewable
24 energy to the electric grid, analyzing the effect variable
25 energy resources have on system reliability has become more
ELLSWORTH, DI 29
Idaho Power Company

1 critical . The LOLE methodology recognizes that the output
2 of variable energy resources, such as wind and solar,
3 change with time (with their hourly output being dependent
4 on a multitude of factors like weather and environmental
5 conditions) ; it is essential to capture and value that
6 variability.
7 Q. What inputs are derived from the LOLE
8 methodology that are utilized in the AURORA LTCE model?
9 A. Idaho Power implements the LOLE methodology
10 through an internally developed Reliability and Capacity
11 Assessment Tool ("RCAT") which is capable of producing
12 inputs such as a Planning Reserve Margin ("PRM") and
13 resource Effective Load Carrying Capability ("ELCC")
14 values . The PRM metric can be defined as the percentage of
15 expected capacity resources above forecasted peak demand.
16 The ELCC calculation is a reliability-based metric used to
17 assess the capacity contribution of variable and energy-
18 limited resources . The PRM and ELCC values that are
19 calculated using the LOLE methodology are a direct input to
20 the AURORA LTCE model .
21 Q. How are the PRM and ELCC values utilized?
22 A. Because the AURORA LTCE model and the RCAT are
23 two separate tools, a translation is required between the
24 probabilistic LOLE analysis performed in RCAT and the
25 portfolios produced by the AURORA LTCE model . First, PRM
ELLSWORTH, DI 30
Idaho Power Company

1 and ELCC values are calculated using the LOLE methodology,
2 which serve as direct inputs to the AURORA LTCE model .
3 After AURORA solves for and produces portfolios, select
4 resource buildouts and their corresponding data are
5 analyzed with the LOLE methodology and tested to ensure
6 they meet the pre-designated reliability hurdle through the
7 calculation of annual capacity positions . It is critical
8 when comparing future resource portfolios that each plan
9 achieves at least a base reliability threshold. Figure 2
10 below illustrates the model consolidation process .
11 Figure 2 . Idaho Power Reliability Flowchart
_ T
Generation El
era _c�r�nr+�r •
RCAT LOLE n"c
(Reliability
Portfolio
R,1.b,h1y A cape[,', EUSs dl Ldad E.pMJEidn lmr Tw cav>1�1v E."n_ IRP
bSHuntnt Tool Hurdle _
AURORA '� f K
� Lo
MR
13 Q. You indicated the RCAT and AURORA serve
14 different purposes in Idaho Power' s planning process . How
15 is the data exchanged between the two models translated and
16 aligned?
17 A. To better assess the dynamic diversity benefit
18 caused by a changing resource mix, and to synchronize the
ELLSWORTH, DI 31
Idaho Power Company

1 models, beginning with the 2023 IRP a feedback process was
2 implemented between the AURORA LTCE model and the RCAT.
3 Under the feedback process, the annual capacity positions
4 for an AURORA LTCE main case portfolio buildout were
5 calculated using the RCAT. Once the annual capacity
6 positions were known, the PRM in the AURORA LTCE model was
7 modified in years that had significant resource changes so
8 that both models identified a similar annual capacity
9 position. The feedback loop continued until the main case
10 portfolio was reliable under the LOLE threshold. The
11 resulting AURORA-produced optimized main case portfolios
12 provide the least-cost, least-risk future resource
13 buildouts .
14 Q. How does AURORA select resources to produce
15 the least-cost, least-risk portfolios?
16 A. Deficits determined through the annual
17 capacity position identification are used by AURORA to
18 develop resource portfolios through potential combinations
19 of supply-side resources, such as solar plus storage
20 generation facilities, demand-side resources like energy
21 efficiency measures, and transmission projects that
22 increase access to energy markets . When evaluating and
23 comparing the alternative resources, two major cost
24 considerations exist: the capital cost of the project, or
25 fixed costs, and the energy cost of the project, or
ELLSWORTH, DI 32
Idaho Power Company

1 variable costs . Capital costs are derived through cost
2 estimates to install the various projects and energy costs
3 are calculated through a detailed modeling analysis, using
4 the AURORA software, for both transmission capacity and
5 supply-side resource additions . Energy prices are based on
6 forecasted gas prices, coal prices, nuclear prices, hydro
7 conditions, and variable operations and maintenance
8 expenses . Portfolios that include transmission capacity as
9 a resource addition include costs associated with market
10 purchases, as forecasted in the AURORA model .
11 Q. Does the Company' s existing transmission
12 system play a role in resource planning?
13 A. Yes . The Company' s transmission system is a
14 critical component of Idaho Power' s ability to provide
15 reliable and fair-priced energy services . Transmission
16 lines facilitate the delivery of economic resources and
17 allow resources to be sited where most cost effective .
18 Furthermore, geographic diversity of resources and robust
19 connections to neighboring systems facilitate system
20 resiliency and minimize impacts from localized weather
21 events . For much of its history, Idaho Power has relied
22 upon resources outside of its major load pockets to
23 economically serve its customers . The existing transmission
24 lines between Idaho Power and its neighboring utilities
25 have been particularly valuable. The Company started
ELLSWORTH, DI 33
Idaho Power Company

1 experiencing transmission constraints, coupled with
2 expected renewable resource development in the region and
3 therefore began analyzing transmission adequacy beginning
4 with the 2000 IRP. Exhibit No. 6 shows an overview of the
5 Company' s high-voltage transmission system.
6 Transmission lines are constructed and operated at
7 different operating voltages depending on purpose, location
8 and distance. Idaho Power operates transmission lines at
9 138-kV, 161-kV, 230-kV, 345-kV, and 500-kV. Idaho Power
10 also operates sub-transmission lines at 46-kV and 69-kV.
11 The higher the voltage, the greater the capacity of the
12 line and the lower the relative losses, but higher voltages
13 come with increased construction costs and increased
14 physical size requirements . Therefore, depending on the
15 capacity needs, economics, distance, and intermediate
16 substation requirements, either 230-kV, 345-kV, or 500-kV
17 transmission lines may be chosen as a resource to
18 facilitate the delivery of economic resources . The 2006 IRP
19 first considered transmission capacity as a supply-side
20 resource addition.
21 Q. What occurs once the LICE modeling is
22 complete?
23 A. Once the portfolios are created using the LTCE
24 model, Idaho Power performs the portfolio cost analysis
25 using the AURORA electric market model, determining
ELLSWORTH, DI 34
Idaho Power Company

1 operating costs for the 20-year planning horizon for each
2 of the resource portfolios . The AURORA software applies
3 economic principles and dispatch simulations to model the
4 relationships between generation, transmission, and demand
5 to forecast market prices . Various mathematical algorithms
6 simulate the regional electrical system to determine how
7 utility generation and transmission resources operate to
8 serve load. Portfolio costs are calculated as the NPV of
9 the 20-year stream of annualized costs, fixed and variable,
10 for each portfolio. The resulting portfolios are then
11 compared and the portfolio that best minimizes cost and
12 risk, and meets the LOLE, is selected in the plan as the
13 preferred portfolio .
14 V. THE SWIP-NORTH PROJECT AND THE 2023 IRP
15 Q. Was SWIP-North modeled as part of the 2023
16 IRP?
17 A. Yes . However, as I noted earlier in my
18 testimony, because the Company' s involvement in the Project
19 remained uncertain at the time modeling for the 2023 IRP
20 occurred, the SWIP-North project was not a resource option
21 for selection in the 2023 IRP Preferred Portfolio.
22 Q. How did Idaho Power model the capacity
23 associated with the SWIP-North project as part of the 2023
24 IRP?
25
ELLSWORTH, DI 35
Idaho Power Company

1 A. As part of the 2023 IRP, Idaho Power analyzed
2 SWIP-North as providing a 500 MW resource equivalent
3 capacity, from the DSW market, in the winter months
4 beginning in 2028 .
5 Q. What assumptions were modeled regarding Idaho
6 Power' s participation in and ownership of SWIP-North?
7 A. For the portfolios that include SWIP-North
8 that were analyzed as part of the 2023 IRP, the Company
9 modeled costs to reflect a 22 . 83 percent interest for
10 Idaho Power.
11 Q. What were the SWIP-North costs included for
12 modeling in the 2023 IRP?
13 A. GBT prepared the cost estimate in early 2024,
14 based on a 90 percent detailed design of the transmission
15 line, the best available information at the time, and
16 reaffirmed it in early 2025 based on firm contract prices
17 for a significant portion of the project scope . The total
18 cost estimate for SWIP-North, including Allowance for
19 Funds Used During Construction and contingency amounts,
20 utilized for modeling was estimated at $1, 493 . 6 million.
21 Of this total estimate, Idaho Power' s interest represents
22 22 . 83 percent of the cost with 50 percent ownership and 50
23 percent capacity entitlement .
24 Q. How were the SWIP-North costs determined?
25 A. GBT developed the cost estimate utilizing
ELLSWORTH, DI 36
Idaho Power Company

1 their experience building SWIP-South, Desert Link, and
2 other major transmission projects, while also leveraging
3 Power Engineers as their third-party owners' engineer.
4 Q. Were substation costs included in the SWIP-
5 North cost estimate?
6 A. Yes . There are costs associated with Midpoint
7 substation, Robinson Summit substation, Burnt Springs
8 substation, and Harry Allen substation. As can be seen in
9 Exhibit No . 1, the Midpoint substation is the northern
10 terminus of SWIP-North, providing a connection to the
11 existing Idaho Power transmission network. Costs associated
12 with the Midpoint station include station expansion, 500-kV
13 breakers and ancillary equipment, a series capacitor, and
14 shunt line reactors .
15 The Robinson Summit substation is the southern
16 terminus of SWIP-North providing a connection to the
17 existing SWIP-South project, and NV Energy' s transmission
18 network. Costs associated with the Robinson Summit
19 substation include station expansion, 500-kV breakers and
20 ancillary equipment, 345-kV phase-shifting transformers and
21 ancillary equipment, a series capacitor, and shunt line
22 reactors . Under the TUA, the SWIP-North project is also
23 responsible for installing three series capacitors on the
24 SWIP-South line. An additional series capacitor will be
25 located at the Robinson Summit substation, meaning one
ELLSWORTH, DI 37
Idaho Power Company

1 Robinson Summit series capacitor will be connected to SWIP-
2 North, and one series capacitor will be connected to SWIP-
3 South. The second series capacitor on SWIP-South will be
4 installed at a new Burnt Springs substation between the
5 Robinson Summit substation and Harry Allen substation. The
6 third series capacitor will be installed at the Harry Allen
7 substation.
8 Q. Did the Company calibrate GBT' s SWIP-North
9 project costs for reasonableness?
10 A. Yes . Idaho Power calibrated the cost estimate
11 provided by GBT against its most recent cost estimates for
12 transmission projects such as B2H and found GBT' s estimate
13 to be both thorough and reasonable for a 500-kV
14 transmission line.
15 Q. You indicated the cost of a resource is based
16 on the capacity cost, or fixed costs, and the energy cost,
17 or variable costs of that resource. How does the capacity
18 cost of SWIP-North compare to the capacity costs of the
19 alternative resources utilized when evaluated in the 2023
20 IRP?
21 A. Table 3 below provides the capital costs for
22 the resource options found that have the lowest cost from a
23 capacity perspective as analyzed in the 2023 IRP:s
24
6 See Idaho Power's 2023 IRP, Appendix C, page 21.
ELLSWORTH, DI 38
Idaho Power Company

1 Table 3 . Total capital dollars ($/kW) for select resources
2 considered in the 2023 IRP (2024$)
Resource Type Total Capital Depreciable
$/kW Life
SWIP-North 55 years
Baseload Gas - Combined-Cycle $1,590 30 years
Combustion Turbine
Peaking Gas - Simple Cycle $991 35 years
Combustion Turbine
Nuclear - Small Modular Reactor $8,134 60 years
Medium-Duration Storage - $2,537 20 years
Li Battery (8 Hr)
3 The capital costs for SWIP-North are approximately
4 70 percent of the cost of the next lowest-cost resource .
5 Additionally, transmission lines, have a longer depreciable
6 life when compared to a gas plant or medium-duration
7 battery storage, and a portion of the costs associated with
8 the lines are recovered from the Company' s third-party
9 transmission customers . The low up-front cost, longer
10 depreciable life, and allocation of a portion of the costs
11 to transmission customers, further reduces the revenue
12 requirement impact to Idaho Power' s retail customers . The
13 summation of these factors demonstrates the SWIP-North
14 project is the lowest capital-cost resource by a
15 substantial margin.
16 Q. Given recent supply-chain issues, did Idaho
17 Power analyze the impact of potential cost escalations
18 associated with the Project and at what point cost
19 escalations indicate SWIP-North is no longer economic?
ELLSWORTH, DI 39
Idaho Power Company

1 A. Yes .
2
3
4
5
6
7
8
9
10 Q. Transmission capacity can be sold to third
11 parties when not being utilized by the Company. Did Idaho
12 Power model any potential transmission wheeling revenue
13 benefits associated with SWIP-North?
14 A. Yes . The SWIP-North project is modeled in
15 AURORA as additional transmission capacity available for
16 the Company' s energy purchases from the DSW market. In
17 general, for new supply-side resources modeled in the IRP
18 process, surplus sales of generation are included as a cost
19 offset in the AURORA portfolio modeling. Transmission
20 wheeling revenues, however, are not included in AURORA
21 calculations . To account for this, Idaho Power modeled
22 incremental transmission wheeling revenue from non-native
23 load customers outside of AURORA as an annual revenue
24 credit . Therefore, portfolios which include SWIP-North
25 include a reduction in project costs associated with
ELLSWORTH, DI 40
Idaho Power Company

1 incremental transmission revenues, ultimately benefiting
2 the Company' s retail customers .
3 Q. Did the Company make any assumptions
4 associated with increased third-party transmission usage
5 associated with SWIP-North?
6 A. Yes . There is significant interest from the
7 market along the nearly 1, 000-mile transmission path from
8 the Harry Allen station, near Las Vegas, Nevada, to the
9 Longhorn station, near Boardman, Oregon (the northern
10 terminus of B2H) that Idaho Power will control . When not
11 being used by the Company to serve retail customers, SWIP-
12 North capacity will be made available to third parties at
13 the Company' s FERC-approved Open Access Transmission
14 Tariff ("OATT") transmission rate . Idaho Power expects
15 this transmission capacity to be highly utilized as it
16 will provide a connection between the Palo Verde and Mid-
17 Columbia ("Mid-C") markets; the Company has already
18 received 100' s of MW of requests to utilize SWIP-North
19 capacity. As such, the Company assumed that SWIP-North
20 would result in an average of 200 MW of incremental
21 transmission wheeling by third parties, with third-party
22 wheeling revenues modeled as an offset to customer rates .
23 Further, although not modeled, SWIP-North will increase
24 the Idaho to Northwest west-to-east capacity by 200 MW,
25 and it is expected the Company will have increased third-
ELLSWORTH, DI 41
Idaho Power Company

1 party wheeling revenues from the increased capacity when
2 not in use .
3 Q. You indicated that the portfolios resulting
4 from the LTCE modeling are analyzed and ultimately the
5 portfolio that best minimizes cost and risk, and meets the
6 LOLE, is selected in the plan as the preferred portfolio.
7 What further analysis was performed on the portfolios that
8 resulted from the LTCE modeling as part of the 2023 IRP?
9 A. As I've described, resource portfolios were
10 developed under varying transmission options, future
11 scenarios, and sensitivities . Available future resources
12 possess a wide range of operating, development, and
13 environmental attributes . Impacts to system reliability
14 and portfolio costs of these resources depend on future
15 assumptions . Each portfolio consists of a combination of
16 resources derived from the LTCE process that will enable
17 Idaho Power to supply cost-effective electricity to
18 customers over the 20-year planning period.
19 The Company developed a scenario analysis
20 evaluation to ensure that the resulting portfolios
21 reasonably identified an optimal solution specific to its
22 customers . Idaho Power compared AURORA-optimized
23 portfolios with varying transmission and load growth
24 assumptions . Each of these portfolios were then optimized
25 by the AURORA LTCE model and validation and verification
ELLSWORTH, DI 42
Idaho Power Company

1 runs were performed to ensure portfolios were optimal and
2 reliable . Each of these portfolios was fully optimized by
3 the LTCE model : (1) July 2026 B2H, All Gateway West
4 ("GWW") Segments', (2) July 2026 B2H, Gateway West Phase 1
5 & 2 Only8, (3) July 2026 B2H, GWW Phase 1 Only9, (4) July
6 2026 B2H, Without GWW10, (5) July 2026 B2H, All GWW, 200 MW
7 Large Load11, and (6) - (10) are repeat portfolios with a
8 November 2026 B2H in-service date rather than July 202612.
9 I will refer to these ten portfolios as the "Without SWIP"
10 portfolios .
11 Q. Did the Company consider the inclusion of
12 SWIP-North in the portfolios evaluated as part of the
13 scenario analysis?
14 A. Yes . The results of the evaluation of the
15 portfolios with the inclusion of SWIP-North in the scenario
16 analysis however were not presented in the 2023 IRP to
17 preserve Idaho Power' s negotiating position. Now that the
18 Company' s participation in the project has been agreed upon
19 in the Definitive Agreements, Idaho Power is providing
20 those results .
' Preferred Portfolio, 2023 IRP Table 10.2, Page 136.
8 GWW Phases 1 & 2 Only, 2023 IRP Table 10.2, Page 136.
9 GWW Phase 1 Only, 2023 IRP Table 10.2, Page 136.
10 Without GWW Phases, 2023 IRP Table 10.2, Page 136.
11 Additional Large Load (200 MW) , 2023 IRP Table 10.3, Page 137.
12 Only Portfolio 6: November 2026 B2H, All Gateway West Segments (aka Nov2026
B2H Valmy 1 & 2, 2023 IRP Table 10.2, Page 136) was reported in the published
2023 IRP.
ELLSWORTH, DI 43
Idaho Power Company

1 Q. Please describe how the evaluation of SWIP-
2 North was performed as part of the scenario analysis .
3 A. The best way to identify a transmission
4 project' s financial benefits is to consider the optimal
5 portfolio of transmission and generation projects (i .e . ,
6 the least-cost and least-risk portfolio) both with the
7 transmission project and without the transmission project.
8 For each of the ten portfolio topologies I discussed
9 earlier, the "Without-SWIP" portfolio topologies, the
10 Company added SWIP-North, with a November 2028 in-service
11 date, and performed an additional LTCE analysis using the
12 AURORA electric market model to calculate the portfolio
13 costs . Therefore, to thoroughly evaluate SWIP-North, the
14 Company developed 20 different resource portfolios under
15 the 2023 IRP scenario analysis - ten "Without SWIP"
16 portfolios, and ten "With SWIP" portfolios .
17 Q. What were the resulting portfolio costs as
18 determined by the AURORA electric market modeling of the 20
19 different portfolios?
20 A. Table 3 summarizes the cost information for
21 the different 2023 IRP portfolios, the "Without SWIP"
22 column presenting the total portfolio costs of those
23 portfolios analyzed as part of the 2023 IRP, and the "With
24 SWIP" column showing the total portfolio costs for the 10
25 portfolios analyzed.
ELLSWORTH, DI 44
Idaho Power Company

1 Table 3 . 2023 IRP With / Without SWIP Portfolio Cost
2 Comparison (in millions$)
Portfolio Without With Difference
SWIP SWIP
1 July 2026 B2H, All GWW _
(*Preferred Portfolio*)
2 July 2026 B2H, _
GWW Phases 1&2 Only
3 July 2026 B2H, _
GWW Phase 1 Only
4 July 2026 B2H, _
Without GWW
5 July 2026 B2H _
+ 200 MW Large Load
6 November 2026 B2H, _
All GWW
7 November 2026 B2H, _
GWW Phases 1&2 Only
8 November 2026 B2H, _
GWW Phase 1 Only
9 November 2026 B2H, _
Without GWW
10 November 2026 B2H _
+ 200 MW Large Load
3 As can be seen in the Difference column in Table 3,
4 for each of the ten cases, a portfolio inclusive of SWIP-
5 North was lower cost than its complementary "Without SWIP"
6 portfolio . The portfolio presented on row one, ultimately
7 selected as the 2023 IRP Preferred Portfolio, with the
8 inclusion of SWIP-North is estimated to be $
9 lower cost on a NPV basis than the 2023 Preferred Portfolio
10 that does not include SWIP-North.
11 Q. Does Idaho Power believe the 2023 IRP
12 Preferred Portfolio reflects the most likely scenario of
13 resource additions?
ELLSWORTH, DI 45
Idaho Power Company

1 A. No . As described in the notice submitted to
2 the Commission on April 19, 2024, in Case No. IPC-E-23-23,
3 the Company believes the most likely scenario is that B2H' s
4 in-service date will be after July 2026 and therefore, the
5 November 2026 B2H, All GWW portfolio reflected on row six
6 of Table 3 would be the least-cost, least risk portfolio
7 with an online date of B2H in November 2026 . As reflected
8 in the Difference column, the "With SWIP" portfolio is _
9 - more cost-effective on a NPV basis than the
10 complementary "Without SWIP" portfolio. This cost
11 difference shows the value of SWIP-North to Idaho Power
12 customers, and that SWIP-North should be a necessary
13 component of the Company' s preferred portfolio.
14 Q. How would the results of the scenario analysis
15 change if the 200 MW of assumed incremental transmission
16 wheeling by third parties did not materialize?
17 A. The Company believes the incremental wheeling
18 is more likely to be greater than 200 MW than less than 200
19 MW. However, in the unlikely event the entire 200 MW of
20 incremental wheeling revenue did not materialize, the NPV
21 cost of the portfolios that included SWIP-North would
22 increase by approximately . With the NPV benefit
23 of the SWIP-North portfolios between and _
24 -, the incremental wheeling assumption is not
25 critical to the overall economics of the project.
ELLSWORTH, DI 46
Idaho Power Company

1 SWIP-North Financial Benefits - New Large Load
2 Q. Did the Company evaluate any additional
3 portfolio topologies?
4 A. Yes . The Company continues to see high volumes
5 of large industrial load service requests, therefore the
6 large load portfolio case shown on row 10 in Table 3
7 includes an important cost-based reference. The "November
8 2026 B2H + 200 MW Large Load" is a likely scenario that a
9 new large industrial load, not already part of the
10 Company' s load forecast, connects to the Idaho Power
11 system. As can be seen in the Difference column of row 10,
12 SWIP-North becomes even more valuable, with a NPV savings
13 of
14 Q. You indicated the large industrial load
15 service requests were not included in the load forecast
16 utilized in the 2023 IRP modeling. What is the likelihood a
17 large load would materialize and the added benefits of
18 SWIP-North potentially realized?
19 A. There is a compelling likelihood the large
20 industrial service requests will materialize . The Company
21 has signed construction agreements with a
22
23
24 Each of these
25 ramps are included in the forthcoming 2025 IRP. These loads
ELLSWORTH, DI 47
Idaho Power Company

1 were not included in the 2023 IRP load forecast, indicating
2 the 200 MW large load scenario is already fully showing its
3 relevance.
4
5
6
7 Beyond those
8 projects, there are gigawatts of additional interest from
9 large customers looking to site in Idaho Power' s service
10 territory in various stages of development, from highly
11 speculative, to entities that have already secured land.
12 The Company believes additional large loads siting in
13 southern Idaho is a matter of when, not if .
14 SWIP-North Financial Benefits — RFP Resources Update
15 Q. Did Idaho Power perform any additional testing
16 of SWIP-North within AURORA?
17 A. Yes . Since the 2023 IRP was filed in September
18 2023, the Company has continued its resource acquisition
19 process, issuing the 2026-2027 All Source Request for
20 Proposals (RFP) for Peak Capacity and Energy Resources
21 ("2026 RFP") . To date, Idaho Power has executed contracts
22 associated with the acquisition of two resources for which
23 Idaho Power received approval from the Commission for those
ELLSWORTH, DI 48
Idaho Power Company

1 acquisitionS13 as well as two resources for which approval
2 from the Commission is pending14 (collectively, the
3 "2026/2027 resources") . The Company, therefore, believes
4 some additional analysis inclusive of the resources
5 acquired is prudent.
6 Q. Do the 2026/2027 resources differ from
7 resources that were identified in the 2023 IRP Preferred
8 Portfolio?
9 A. Yes, the resources procured were selected
10 through an extensive competitive bidding process in which
11 the 2026 RFP was issued, whereas the 2023 IRP was based on
12 the addition of hypothetical resources .
13 Q. Given the different resources selected via the
14 2026 RFP, what is the impact on the SWIP-North analysis?
15 A. The benefits expected to be provided by SWIP-
16 North remain highly robust. To evaluate SWIP-North while
17 considering the RFP-related resource procurements, the
18 Company completed a supplemental analysis utilizing all
19 resources that made the Company' s RFP final shortlist,
20 including the 2026/2027 resources . Given the uncertainties
21 around the timing of B2H, the Company evaluated a pre-
13 Case No. IPC-E-24-12, Idaho Power Company's Application for Approval of a
Market Purchase Agreement and Case No. IPC-E-24-16, Idaho Power Company's
Application for a Certificate of Public Convenience and Necessity for the Boise
Bench Battery Storage Facility.
14 Case No. IPC-E-24-45, Idaho Power Company's Application for a Certificate of
Public Convenience and Necessity for Two Battery Storage Facilities and Case
No. IPC-E-24-46, Idaho Power Company's Application for Approval of a Power
Purchase Agreement with Jackalope Wind, LLC, and for a Certificate of Public
Convenience and Necessity for the Jackalope Wind Project.
ELLSWORTH, DI 49
Idaho Power Company

1 summer 2027 B2H scenario, and a post-summer 2027 B2H
2 scenario . Table 4 summarizes the differences in the
3 portfolio costs under the additional two scenarios
4 analyzed.
5 Table 4 . 2023 IRP With / Without SWIP Portfolio Cost
6 Comparison Supplemental Analysis (in millions$)
Portfolio Without With Difference
SWIP SWIP
July 2027 B2H _
November 2027 B2H _
7 Independent of B2H timing, the "With SWIP" portfolios far
8 outperform the complimentary "Without SWIP" portfolios by a
9 margin of approximately on a NPV basis, which
10 is consistent with the 2023 IRP resources-based analysis .
11 Q. Did you include any additional large loads
12 mentioned earlier in this supplemental analysis?
13 A. No. As I discussed earlier, SWIP-North becomes
14 even more valuable if the additional large loads
15 materialize which would likely increase the portfolio cost
16 differences between the two portfolios analyzed.
17 Q. Why does the RFP resource-based analysis
18 result in higher portfolio costs relative to the 2023 IRP
19 resource-based analysis?
20 A. For the RFP resource-based analysis, the
21 Company updated the future resource cost inputs in AURORA
22 to be consistent with the bids received in the 2026 RFP.
ELLSWORTH, DI 50
Idaho Power Company

1 Almost all of the cost increase between the 2023 IRP
2 resource-based portfolios and the RFP resource-based
3 portfolios can be attributed to higher wind and solar
4 pricing than estimated when modeling for the 2023 IRP. This
5 resulted in higher resource costs within AURORA, and
6 therefore, higher total portfolio costs in the RFP
7 resource-based analysis . While the cost increases are
8 unconnected because their underlying foundations are
9 different, SWIP-North still proves to be highly cost
10 effective .
11 VI . SWIP-NORTH PROJECT MODELING AND THE DSW MARKET
12 Q. You explained at a high level how the capacity
13 of SWIP-North was modeled. Can you provide more detail
14 about how the Project was modeled for resource adequacy and
15 capacity planning purposes?
16 A. Yes . The Company modeled SWIP-North' s DSW
17 market connection as providing 500 MW of non-summer
18 resource adequacy capacity starting November 1, 2028,
19 through the remainder of the 20-year IRP planning horizon.
20 Non-summer months, in this context, are considered all
21 months other than June, July, August, and September. Given
22 the surge in solar growth in the DSW area, the Company also
23 modeled SWIP-North as providing 50 MW of summer resource
24 adequacy capacity in 2034 and 100 MW in 2035 through the
ELLSWORTH, DI 51
Idaho Power Company

I remainder of the plan . In short, Idaho Power primarily
2 considers SWIP-North to provide non-summer benefits .
3 Q. What happens to unutilized SWIP-North capacity
4 in the summer months?
5 A. The SWIP-North summer capacity will not go
6 unutilized. To be clear, the Company will have 500 MW of
7 SWIP-North (and Total SWIP) capacity year-round, but Idaho
8 Power is not planning to rely on the DSW market to meet its
9 summer needs during the June to September time period,
10 because the DSW market peaks in the summer. This is akin to
11 the Company' s plan not to rely on B2H and the Pacific
12 Northwest to provide capacity to Idaho Power in the winter
13 months because the Pacific Northwest is a winter-peaking
14 region. The Company instead plans to rely on the DSW market
15 in the winter for up to 500 MW of capacity and take
16 advantage of any economic opportunities during the non-
17 winter months .
18 The Desert Southwest Market
19 Q. Does the Company have any existing
20 transmission capacity between the DSW market and Idaho
21 Power' s system that could be utilized?
22 A. Yes . Idaho Power has limited ownership in
23 transmission facilities to the south, providing some
24 transmission capacity. The Company owns 360 MW of
25 northbound capacity associated with the Idaho-Sierra path
ELLSWORTH, DI 52
Idaho Power Company

1 (WECC Path 16) however 260 MW of the capacity is allocated
2 to the Company' s North Valmy Power Plant ("Valmy") . The
3 remaining 100 MW is reserved by a third-party, therefore,
4 the Idaho-Sierra path is fully allocated. The Company also
5 has a 50 MW transmission reservation on PacifiCorp' s system
6 from RedButte to Borah that is effective seasonally each
7 year, June through October.
8 Other transmission between Idaho Power and the DSW
9 markets is reserved. The planned asset exchange with
10 PacifiCorp that will occur upon the energization of B2H
11 will result in Idaho Power' s acquisition of 200 MW of
12 bidirectional transmission capacity from the Four Corners
13 substation in northwest New Mexico, through Utah, and
14 connecting to the Populus substation in southeast Idaho.
15 Four Corners capacity is factored into all analyses
16 performed for the 2023 IRP.
17 Q. Can the DSW market be relied upon to provide
18 the Company 500 MW of winter resource adequacy capacity via
19 SWIP-North?
20 A. Yes . SWIP-North provides an opportunity for
21 the Company to leverage the geographical load and resource
22 diversity of the WECC. Historically, the market in southern
23 Nevada, Arizona, and California has not been stressed when
24 Idaho Power is experiencing cold weather extremes, meaning
25 those areas have excess resources to sell, as evidenced by
ELLSWORTH, DI 53
Idaho Power Company

1 the historical high temperatures presented in the table
2 below. As can be seen in Table 5, when Idaho Power is
3 experiencing winter peak days, the time in which
4 temperatures in Boise are low, temperatures in Las Vegas,
5 Phoenix, Tucson, and San Diego are mild, indicating lower
6 energy use periods .
7 Table 5 . Historical Winter Temperatures (in degrees) 15
Date Boise Las Phoenix Tucson San
Vegas Diego
12/17/19 36 49 62 57 67
12/29/20 27 56 60 57 62
1/20/21 43 62 74 71 73
12/22/22 17 59 64 68 66
1/30/23* 23 48 62 62 58
1/16/24** 14 59 68 69 64
8 *Idaho Power' s Second-Highest Winter Peak
9 **Idaho Power' s All Time Winter Peak
10 Additionally, as can be seen in Exhibit No. 7, the
11 peak load in the DSW (excluding California) is
12 dramatically more in the summer season compared with the
13 winter season, with the max summer peak of approximately
14 31, 000 MW, exceeding the maximum winter peak of
15 approximately 17, 000 MW, by over 80 percent. The large gap
16 that exists between the seasonal summer and winter peaks
17 indicates potential for excess capacity in the winter
is See www.wunderground.com
ELLSWORTH, DI 54
Idaho Power Company

1 season from the southwest markets to help meet future peak
2 demand needs for Idaho Power during winter.
3 Q. You indicated the gap in the peak loads did
4 not include summer and winter peak loads from California.
5 Would the Company be competing with California for the
6 excess capacity in the DSW markets?
7 A. Yes, however there is enough excess capacity
8 in the DSW markets to meet the needs of both Idaho Power
9 and customers in California. The CAISO area, a subset of
10 the state of California load, had an all-time peak on
11 September 6, 2022, of approximately 52, 000 MW and its peak
12 load in December 2022, the same month the Pacific Northwest
13 experienced an all-time peak, was only approximately 30, 000
14 MW.
15 Q. Are there any additional factors that indicate
16 the DSW market can be relied upon to provide winter
17 capacity?
18 A. Yes . Focusing only on the dispatchable
19 resources, primarily natural gas in the DSW, there is more
20 installed capacity in Arizona and Southern Nevada, 8, 500
21 MW, than forecast maximum winter load for the area. This
22 does not account for expected solar capability, wind
23 capacity, and dispatchable battery storage, which will only
24 further increase surplus resources .
25
ELLSWORTH, DI 55
Idaho Power Company

1
2
3
4 Q. Where will Idaho Power access the DSW market?
5 A. The Company will have direct access to the DSW
6 market at the southern terminus of the Total SWIP line, the
7 Harry Allen substation. However, the DSW market is
8 extensive . The Company may be able to acquire resources
9 directly at Harry Allen or could potentially have the
10 selling entity deliver power directly to Idaho Power at
11 that substation. Alternatively, the Company may acquire
12 short-term transmission service between the power provider
13 and Harry Allen substation. El Dorado and Mead are two
14 major transmission and market hubs southeast of Las Vegas .
15 Transmission between those market hubs, and the Harry Allen
16 substation, is generally unconstrained in the south-to-
17 north direction in the winter months . Palo Verde is a major
18 market hub west of Phoenix, and transmission between Palo
19 Verde and the Las Vegas area where Mead and Harry Allen are
20 located is often available in the winter months, depending
21 on the specific points of receipt and delivery involved.
22 Q. Acquisition of short-term transmission service
23 is an added cost to the power purchase. Was this added cost
24 included in the IRP modeling of the Project?
ELLSWORTH, DI 56
Idaho Power Company

1 A. Yes . The Company conservatively modeled the
2 need for a wheeling charge in its IRP-based analysis .
3 Q. Who are the entities Idaho Power could
4 purchase power from near the Harry Allen substation, El
5 Dorado, Mead, and Palo Verde?
6 A. The list of entities with a presence in that
7 DSW area is long and includes, but is not limited to: NV
8 Energy, Arizona Public Service, Tucson Electric, Salt River
9 Project, Western Area Power Administration, Pacific Gas &
10 Electric, Southern California Edison, San Diego Gas and
11 Electric, Los Angeles Department of Water and Power, Public
12 Service Company of New Mexico, and El Paso Electric
13 Company. In addition, there are independent power producers
14 with generating facilities, including gas plants such as :
15 Harquahala with approximately 1, 100 MW of generation,
16 Arlington Valley with 600 MW, Mesquite Block 2 with
17 approximately 700 MW, the Griffith Energy Facility with
18 approximately 650 MW, and the South Point Energy Center
19 with 530 MW of generation. With peak loads in the summer,
20 the Company anticipates many of these entities will have
21 surplus capacity available in the winter months in the
22 future .
23 Independent Value of Transmission Capacity
24 Q. Lately, the power markets have been volatile .
25 Has Idaho Power considered a scenario in which there is not
ELLSWORTH, DI 57
Idaho Power Company

I a market in the DSW to access power in the winter?
2 A. Yes . The Company considered the consequences
3 of limited DSW market access from both a financial aspect
4 and a reliability aspect. First, if the Company does not
5 utilize a portion of the SWIP-North capacity, any unused
6 capacity can be sold as transmission service to a third-
7 party. Idaho Power would be able to offer transmission
8 service from the Harry Allen substation in Las Vegas to
9 Longhorn, the Pacific Northwest terminus of B2H, with a
10 single wheeling rate. A nearly 1, 000-mile offering of
11 continuous transmission would likely be highly sought after
12 and desirable. Indeed, the Company has already had
13 potential third-party transmission customers inquire, and
14 request, whether they could acquire this transmission
15 capacity from Idaho Power.
16 With respect to the impact to reliability, the
17 Company' s intention is to work with entities in the DSW
18 market to manage this risk. Additionally, there has not
19 been a WECC-wide winter-shortage event, so this problem is
20 not highly credible in the near-term. The Pacific Northwest
21 region has seen very high peak winter pricing in the past,
22 indicating the region was approaching a resource adequacy
23 problem, but there have always been plenty of resources
24 available in the DSW in the winter. The DSW market
25 resources have been bottlenecked behind the finite amount
ELLSWORTH, DI 58
Idaho Power Company

1 of existing transmission available to bring power from
2 south-to-north. SWIP-North will add to this capability.
3 Q. Do you have evidence of a time the Pacific
4 Northwest region struggled with resource adequacy while the
5 DSW had surplus resources?
6 A. Yes, this exact event occurred last year, on
7 January 13-16, 2024 . Day ahead prices during this time
8 period were $600-$930 per MWh at Mid-C, in the Pacific
9 Northwest, but were a much more reasonable $120-$180 per
10 MWh in the DSW market. On the highest-priced days, day-
11 ahead Mid-C prices were nearly seven times the prices in
12 the DSW. In the real time bilateral market, prices in the
13 Pacific Northwest rose higher than even the day-ahead price
14 posted on the Intercontinental Exchange ("ICE") . At certain
15 times over the long weekend, it was hard to find energy
16 that could be delivered to Idaho Power. Exhibit No. 8
17 includes a dynamic illustration of real time wholesale
18 electricity prices across the United States during the
19 January 12-16, 2024, time period, demonstrating the high
20 prices experienced in the Pacific Northwest while the
21 prices elsewhere were considerably lower. The Energy
22 Imbalance Market ("EIM") hourly pricing validated these
23 trends seen in the bilateral markets, with average hourly
24 locational marginal prices for the Company nearly eight
ELLSWORTH, DI 59
Idaho Power Company

1 times greater than average locational marginal prices in
2 the DSW over the highest-priced days in January 2024 .
3 As an example, if an entity had bought 100 MW at the
4 Mid-C day-ahead price for every hour during the January 13-
5 14, 2024, timeframe, the total cost of those purchases
6 would have been over $4 million (excluding transmission
7 costs) . In contrast, if those same purchases could have
8 been made from the DSW market, the total cost is estimated
9 to have been in the range of $600, 000 - $700, 000, a savings
10 of over $3 million over the course of those two days .
11 Because the transmission market from the DSW to the Pacific
12 Northwest can be constrained, it was not possible to access
13 the DSW market for those volumes over those days .
14 The availability of surplus resources in the DSW is
15 further supported by the regional net imports and exports
16 that occurred during the January 2024 event. Western market
17 stakeholders have provided analysis of the January 2024
18 event, including the volume of energy transfers into the
19 Pacific Northwest from other regions . A report from CAISO' s
20 Department of Market Monitoring illustrates that while
21 transmission constraints existed that limited transfers to
22 an extent, surplus energy from the DSW, California, and
23 other regions flowed to the Pacific Northwest.16 The report
24 from Powerex identified nearly 5, 000 MW of hourly net
16 CAISO Winter Conditions Report for January 2024, pgs. 8-9.
ELLSWORTH, DI 60
Idaho Power Company

1 exports from the Southwest and Rockies region, with an
2 average of 4, 745 MW imported in the Northwest region. 17
3 Exhibit No. 9 to my testimony provides a figure from the
4 analysis published by Powerex that illustrates the regional
5 net imports and exports that occurred during the January
6 2024 winter event.
7 VII . ADDITIONAL JUSTIFICATION FOR THE SWIP-NORTH PROJECT
8 Q. Aside from the SWIP-North Project being a
9 least-cost resource addition to the preferred portfolio,
10 what other benefits does the line provide?
11 A. Geographical diversity of wind and solar, as
12 well as regional utility loads, is a vital component of
13 reliability and affordability, and transmission is the
14 enabler of geographical diversity. In-depth studies, such
15 as the one performed by the American Clean Power
16 Association, cite the need for an expanded and robust
17 transmission system in a decarbonized future.18 This study
18 is not alone in identifying the urgent need for
19 transmission, as there is general consensus on this need
20 industry-wide among experts, utilities, and agencies . In
21 addition, a variety of other benefits are expected:
22 improved economic efficiency, renewable integration, grid
17 Powerex: Analysis of the January 2024 Winter Weather Event, pg 12.
18 https://cleanpower.org/wp-content/uploads/2021/01/June-2021 Transmission-
Fact-Sheet.pdf
https://www.utilitydive.com/news/as-operators-update-grid-planning-for-
renewables-transmission-remains-key/505065/
ELLSWORTH, DI 61
Idaho Power Company

I reliability/resiliency, resource reliability, contingency
2 reserves, avoidance of other high-cost projects,
3 flexibility, and Energy Imbalance Market ("EIM") value .
4 Improved Economic Efficiency and Renewable Integration
5 Q. How does the SWIP-North improve economic
6 efficiency and the integration of renewable resources?
7 A. Transmission congestion causes power prices on
8 opposite sides of the congestion to diverge as higher cost,
9 less efficient resources are dispatched to ensure the
10 transmission system is operating securely and reliably.
11 Congestion can have a significant cost. Historically,
12 during peak winter conditions, transmission between the DSW
13 and Idaho in the south-to-north direction has often been
14 fully constrained with zero firm transmission available
15 between the regions . At these times, power prices in Idaho
16 and to the north and west are generally higher than power
17 prices in the DSW, a market inefficiency caused by
18 inadequate transmission capacity to economically move power
19 between regions . The SWIP-North will help alleviate this
20 constraint and enable generators in the DSW to gain further
21 value from their existing resources, and Idaho Power and
22 the Pacific Northwest region will be able to meet load
23 service needs at a lower cost. At other times, such as the
24 summer peak, the roles may reverse with the DSW benefiting
ELLSWORTH, DI 62
Idaho Power Company

1 from economical resources from the Pacific Northwest
2 region.
3 Similarly, the lack of transmission capacity, at
4 times, prevents the energy from existing renewable
5 generation to move to load, which in turn requires
6 renewable resources to be curtailed. SWIP-North will help
7 to integrate and balance variable energy resources like
8 wind and solar as it will facilitate the transfer of
9 geographically diverse renewable resources across the
10 western grid and help ensure the clean energy grid of the
11 future is robust and reliable.
12 Q. Do you have evidence to support the lack of
13 transmission capacity is hindering the ability to move
14 generation to load?
15 A. Lawrence Berkley National Laboratory recently
16 published a study titled "Empirical Estimates of
17 Transmission Value using Locational Marginal Prices . "19 In
18 the study, the difference between the CAISO DesertHub node
19 and the EIM UT node (the EIM Utah node is a close surrogate
20 for Idaho Power) , has an approximately $13 . 50 per MWh mean
21 power spread between 2012 and 2022, resulting in
22 approximately $125 million per year in potential energy
23 arbitrage related value . This value, or a subset, was not
19 Empirical Estimates of Transmission Value using Locational Marginal Prices,
Slide 20.
ELLSWORTH, DI 63
Idaho Power Company

1 factored into the 2023 IRP analysis but would represent a
2 real benefit to Idaho Power' s customers .
3 In addition, in their Analysis of the January 2024
4 Winter Weather Event, Powerex acknowledged that the event
5 "demonstrated the substantial value of expanding
6 transmission service to deliver additional supply from the
7 Southwest and Rockies to the U. S . Northwest. 1120 With an
8 average day-ahead market prices in the Southwest of
9 approximately $150/MWh and an average day-ahead market
10 prices in the Northwest of approximately $800/MWh, and
11 assuming transmission losses of approximately $50/MWh, an
12 additional 2, 000 MW of direct transfer capability between
13 the regions could have provided up to $140 million in
14 additional economic benefit in just five days .21
15 Grid Reliability/Resiliency
16 Q. Please explain how the SWIP-North Project will
17 contribute to the reliability and resiliency of the grid.
18 A. The SWIP-North will increase the robustness
19 and reliability of the regional transmission system by
20 adding high-capacity bulk electric facilities designed with
21 the most up-to-date engineering standards . Major 500-kV
22 transmission lines, such as SWIP-North, substantially
20 Powerex Study.
21 Id.
ELLSWORTH, DI 64
Idaho Power Company

1 increase the grid' s ability to recover from unexpected
2 disturbances .
3 Q. What are some examples of unexpected
4 disturbances whose impacts would be reduced with the
5 addition of SWIP-North?
6 A. While unexpected disturbances are difficult to
7 predict, I will provide two examples of disturbances whose
8 impacts would be reduced with the addition of SWIP-North.
9 First, the loss of any natural gas resource, or a natural
10 gas pipeline limitation, in the winter. Loss of a
11 dispatchable natural gas facility during winter peak is
12 challenging when the Company' s primary transmission
13 connections (especially post-B2H) are to the Pacific
14 Northwest, which may also be experiencing a winter peak.
15 Additionally, a natural gas restriction impacting the
16 Company will likely be impacting other Pacific Northwest
17 entities with natural gas resources connected to the same
18 pipeline, exacerbating the problem. SWIP-North will provide
19 a major alternative connection to a diverse market in the
20 DSW.
21 Second, a more general example is discussed in a
22 recent paper titled "Transmission Makes the Power System
23 Resilient to Extreme Weather" by Grid Strategies22 which
22 https://acore.org/wp-content/uploads/2021/07/GS Resilient-
Transmission proof.pdf
ELLSWORTH, DI 65
Idaho Power Company

1 explored the benefits that transmission can provide to
2 regions experiencing extreme weather. The paper identifies
3 seven different transmission connections that could have
4 provided over $80 million of benefits per 1, 000 MW of
5 transmission capacity during Winter Storm Uri alone, with
6 one specific connection that would have provided nearly $1
7 billion in benefits per 1, 000 MW. Extreme events, such as
8 the 2021 Pacific Northwest heat dome and the January 2024
9 winter weather event, are seemingly increasing in
10 frequency, and transmission lines provide a significant
11 regional diversity, reliability, and resilience benefit.
12 Resource Reliability
13 Q. How does the reliability of a transmission
14 line compare to that of a generation resource?
15 A. The forced outage rate of a resource is the
16 best measure of its reliability, and, in general, the
17 forced outage rate of transmission lines has historically
18 been lower than traditional generation resources . NERC has
19 tracked the forced outage rate for transmission
20 availability through a Transmission Availability Data
21 System ("TADS") and generation availability through a
22 Generation Availability Data System ("GADS") .
23 Q. What are the comparable NERC forced-outage
24 rates of the various resources?
ELLSWORTH, DI 66
Idaho Power Company

1 A. The NERC forced-outage rates used in the
2 modeling of the 2023 IRP were approximately 9 to 10 percent
3 for coal generation, 4 . 55 percent for hydro generation,
4 approximately 9 to 10 percent for simple cycle gas
5 generation, 4 percent for combined cycle gas generation and
6 one-quarter of one percent for transmission resources . A
7 transmission line with a forced outage rate of less than 1
8 percent is significantly more reliable than a power plant -
9 SWIP-North is expected to have over 99 percent
10 availability.
11 Of course, a transmission line requires generating
12 resources to provide energy to the line to serve load.
13 However, energy sold as "firm" must be backed up and
14 delivered even if a source generator fails . Therefore, firm
15 energy purchases would have an equivalent forced outage
16 rate demand - or EFORd - consistent with the transmission
17 line, which is more reliable than traditional supply-side
18 generation. In the management of cost and risk, SWIP-North
19 will provide Idaho Power' s operators additional flexibility
20 when managing the Idaho Power resource portfolio.
21 Contingency Reserves
22 Q. How will SWIP-North support the Company' s
23 contingency reserve obligations?
24 A. During real-time operations, Idaho Power holds
25 generation in reserve to meet its NERC contingency reserve
ELLSWORTH, DI 67
Idaho Power Company

1 obligation, or generation in reserve equaling at least
2 three percent of network demand plus three percent of
3 internal generation. For market purchase imports, the three
4 percent contingency requirement for the generation is not
5 borne by the Company but rather the producer in the
6 external balancing area is required to meet the reserve
7 obligation associated with its resource, reducing Idaho
8 Power' s reserve obligation. The Company plans to make
9 additional market purchases with SWIP-North and therefore
10 the selling entity will carry the contingency reserve
11 obligation. Idaho Power' s reserve obligation during winter
12 peak will be reduced with the addition of SWIP-North as
13 compared to a replacement internal resource .
14 SWIP-North Impact on Other Planned Company Projects
15 Q. Does SWIP-North allow the Company to adjust
16 any other plans or future projects?
17 A. Yes, with the addition of SWIP-North, the
18 Company believes it can indefinitely defer the Midpoint to
19 Cedar Hill 500-kV line that is planned as part of the
20 Gateway West project, and that it can indefinitely defer
21 necessary reinforcement transmission facilities in the
22 Magic Valley area between Rogerson and Twin Falls .
23 Q. Why does the Company believe it can
24 indefinitely defer the Midpoint to Cedar Hill 500-kV line?
ELLSWORTH, DI 68
Idaho Power Company

1 A. The Midpoint to Cedar Hill 500-kV line will
2 extend from the Midpoint substation to a new Cedar Hill
3 substation south of Twin Falls . This transmission line is
4 necessary as one component of the first phase of Gateway
5 West as detailed in the Company' s 2023 IRP. The first phase
6 of Gateway West enables the construction of additional
7 resources, necessary to meet Idaho Power' s significant
8 forecasted load growth, in the most cost-effective manner.
9 SWIP-North will transverse the same transmission corridor
10 between Midpoint and Cedar Hill . The SWIP-North
11 transmission line between Midpoint and Cedar Hill will have
12 a facility rating exceeding 3, 000 MW, however, the capacity
13 utilization across the SWIP-North line only totals 2, 070 MW
14 north-to-south and 1, 920 MW south-to-north. This results in
15 at least 1, 000 MW of bidirectional capacity between
16 Midpoint and Cedar Hill that will be unutilized by other
17 SWIP parties . In an effort to reduce the costs of the
18 Gateway West project, the Company negotiated the rights to
19 all of this bidirectional capacity as defined in Section
20 4 . 06 (c) of the Participation and Ownership Agreement . Given
21 access to capacity between Midpoint and Cedar Hill, Idaho
22 Power believes the Midpoint to Cedar Hill 500-kV segment of
23 the first phase of Gateway West can be indefinitely
24 delayed.
ELLSWORTH, DI 69
Idaho Power Company

1 Q. Please describe the necessary reinforcement
2 transmission facilities in the Magic Valley area between
3 Rogerson and Twin Falls .
4 A. Prior to the 2023 IRP, the Company was
5 planning to exit ownership of Valmy due to cessation of
6 coal-fired operations at Unit 1 and a future cessation at
7 Unit 2 . Due to identification in the Preferred Portfolio of
8 the 2023 IRP of the conversion of Valmy to natural gas, if
9 approved by the Commission, the Company will participate in
10 the conversion of and natural gas operations at Valmy.23
11 Following the Valmy natural gas conversion, the Company
12 will have 480 MW of generation connected to the Midpoint to
13 Rogerson to Valmy 345-kV transmission line (Idaho-Sierra
14 Line) , approximately 260 MW at Valmy, 120 MW at Jackpot
15 Solar, and 100 MW at Franklin Solar, inclusive of 60 MW of
16 storage. Considering transmission reliability, an unplanned
17 outage of the Idaho-Sierra Line would result in the Company
18 losing access to as much as 480 MW of resources . The
19 solution identified to address this issue was a new
20 transmission line from Rogerson substation, where Jackpot
21 Solar and Franklin Solar connect to the Idaho-Sierra Line
22 near Rogerson, Idaho, to the Twin Falls area, with an
23 estimated cost of
23 See Case No. IPC-E-25-03, Idaho Power Company's Application for Approval of
the North Valmy Power Plant Natural Gas Conversion Agreement with NV Energy.
ELLSWORTH, DI 70
Idaho Power Company

1 Q. How does SWIP-North allow for the indefinite
2 deferral of a new transmission line between Rogerson and
3 Twin Falls?
4 A. The worst outage that could occur is loss of
5 the Midpoint to Rogerson section of the Idaho-Sierra line,
6 stranding up to 480 MW of generation outside of the Idaho
7 Power balancing area. Currently, the northern NV Energy
8 system has limited transmission connections to take this
9 480 MW of generation during an outage and wheel it through
10 the northern NV Energy system to its border, and then
11 through another transmission system, such as Utah, to get
12 back to Idaho. With the addition of SWIP-North, a large
13 portion of the 480 MW could be wheeled through the northern
14 NV Energy system to the Robinson Summit substation, and
15 then across SWIP-North to the Company' s balancing area.
16 SWIP-North would eliminate the near-term need for a new
17 transmission line between Rogerson and Twin Falls .
18 Additional SWIP-North Benefits and Value
19 Q. Are there any additional expected benefits and
20 value of the SWIP-North Project you have not yet discussed
21 in your testimony?
22 A. Yes . The Project provides Idaho Power with
23 flexibility in the acquisition and transfer of generation
24 resources . As advances in technology are driving some
25 generation resources, such as coal plants, toward economic
ELLSWORTH, DI 71
Idaho Power Company

1 obsolescence, SWIP-North serves as an alternative to
2 constructing a new supply-side resource. In this way, SWIP-
3 North reduces the risk of technological obsolescence by
4 ensuring Idaho Power customers always have access to the
5 most economic resources, regardless of the resource type .
6 In addition, because the existing electrical system is so
7 heavily used, new transmission line infrastructure like
8 SWIP-North will create additional operational flexibility.
9 The Project will increase the ability to take other system
10 elements out of service to conduct maintenance and will
11 provide additional flexibility to move needed resources to
12 load when outages occur on equipment. This additional
13 transmission capacity and operational and resource
14 flexibility also provides value in the EIM.
15 Q. How will SWIP-North provide additional value
16 in the energy imbalance market, or EIM?
17 A. The expansion of the transmission system,
18 through the addition of SWIP-North, will facilitate further
19 benefits by increasing transmission capacity between Idaho
20 Power and other EIM participants . As fluctuations in supply
21 and demand occur for EIM participants, the market system
22 will automatically find the best resources from across the
23 large-footprint EIM region to meet immediate power needs .
24 This activity optimizes the interconnected high-voltage
25 system as market systems automatically manage congestion,
ELLSWORTH, DI 72
Idaho Power Company

1 helping maintain reliability while also supporting the
2 integration of variable energy resources and avoiding
3 curtailing excess supply by sending it to where demand can
4 use it . Greater transmission transfer capacity between
5 participants in a market reduces congestion costs and
6 allows the lowest cost energy to reach a wider load
7 footprint. Idaho Power views SWIP-North as a complement to
8 any resource type. The project will enhance access to the
9 least-cost and most efficient resources and unlock
10 additional regional diversity to benefit customers .
11 Alternatives to the Definitive Agreements
12 Q. Did the Company evaluate whether alternative
13 transmission arrangements to SWIP-North might better serve
14 Idaho Power' s need for transmission capacity?
15 A. Yes . Idaho Power considered taking PTP
16 transmission service from CAISO or NV Energy rather than
17 the Company' s proposed ownership envisioned in the
18 Definitive Agreements . However, as I discussed earlier in
19 my testimony, assuming SWIP-North moves forward without
20 Idaho Power' s participation, given the information
21 available at this time, the availability of PTP
22 transmission across either CAISO or NV Energy would be both
23 highly uncertain and higher cost. Recall, if the Company
24 acquires a resource in the south, and attempts to wheel it
25 across CAISO transmission through the CAISO market, there
ELLSWORTH, DI 73
Idaho Power Company

1 is uncertainty related to deliverability. Additionally, the
2 CAISO wheel through rate is very high, at about $14 . 00 per
3 MWh. As a comparison, Idaho Power' s current long-term PTP
4 wheeling rate is about $3 . 60 per MWh. Further, as I
5 described earlier, NV Energy is fully utilizing 100 percent
6 of its south-to-north capacity across SWIP-South, and it is
7 unclear if they would have capacity for the Company to
8 acquire across the Total SWIP following construction of
9 SWIP-North.
10 With the Company' s investment in SWIP flowing
11 directly into Idaho Power' s FERC-approved OATT transmission
12 formula rates, the Project will partially be funded by the
13 Company' s other transmission customers . Therefore, Idaho
14 Power' s proposed arrangement with GBT is both least-risk
15 when compared to the uncertainty of acquiring PTP
16 transmission service from CAISO or NV Energy, and least-
17 cost when compared to paying a PTP rate that would increase
18 over time .
19 VIII . CONCLUSION
20 Q. Please summarize your testimony.
21 A. SWIP-North was analyzed as part of the 2023
22 IRP as providing a 500 MW resource equivalent capacity from
23 the DSW market in the winter months beginning in 2028 .
24 However, because Idaho Power' s involvement in the Project
25 remained uncertain at the time of modeling for the 2023
ELLSWORTH, DI 74
Idaho Power Company

1 IRP, SWIP-North was not included as a resource option for
2 selection in the 2023 IRP Preferred Portfolio. Given the
3 recent execution of the Definitive Agreements, the results
4 of the analysis have been finalized. The results indicate a
5 portfolio inclusive of SWIP-North is estimated to be about
6 lower cost on an NPV basis than the 2023
7 Preferred Portfolio that does not include SWIP-North,
8 definitively showing that SWIP-North is a necessary
9 component of the Company' s future resource portfolio.
10 Idaho Power' s participation in SWIP-North is a
11 unique and time-limited opportunity. Due to the Project' s
12 late stage in development, it has been significantly de-
13 risked by the Project developer, with: (1) major federal
14 permits secured, (2) nearly all right-of-way easements
15 secured, (3) major project materials secured or in late-
16 state procurement, and (4) a construction contract to
17 build the Project executed and in progress . Additionally,
18 on January 21, 2025, FERC approved the project development
19 agreement between CAISO and GBT, which allocates
20 approximately 77 percent of the costs associated with the
21 Project to CAISO, making CAISO the key anchor tenant .
22 The Company has extensively evaluated SWIP-North as
23 a supply-side resource, explored many ancillary benefits
24 offered by the transmission line, and considered the risks
25 and benefits of owning a transmission line connected to a
ELLSWORTH, DI 75
Idaho Power Company

1 market hub in contrast to direct ownership of traditional
2 generation resources . Once operational, SWIP-North will
3 provide Idaho Power increased access to reliable, clean,
4 low-cost market energy purchases from the DSW market. In
5 addition, the Project will increase the efficiency,
6 reliability, and resiliency of the electric system by
7 creating an additional pathway for energy to move between
8 the Pacific Northwest and the DSW. The benefits in
9 aggregate reflect SWIP-North' s importance to the Company' s
10 commitment to reliability and affordability.
11 Q. Does this complete your testimony?
12 A. Yes, it does .
13
ELLSWORTH, DI 76
Idaho Power Company

1 DECLARATION OF JARED L. ELLSWORTH
2 I, Jared L. Ellsworth, declare under penalty of
3 perjury under the laws of the state of Idaho:
4 1 . My name is Jared L. Ellsworth. I am employed
5 by Idaho Power Company as the Transmission, Distribution &
6 Resource Planning Director for the Planning, Engineering &
7 Construction Department.
8 2 . On behalf of Idaho Power, I present this
9 pre-filed direct testimony and Exhibit Nos . 1-4,
10 Confidential Exhibit No. 5, and Exhibit Nos . 6 through 9 in
11 this matter.
12 3 . To the best of my knowledge, my pre-filed
13 direct testimony and exhibits are true and accurate .
14 I hereby declare that the above statement is true to
15 the best of my knowledge and belief, and that I understand
16 it is made for use as evidence before the Idaho Public
17 Utilities Commission and is subject to penalty for perjury.
18 SIGNED this 7th day of March 2025, at Boise, Idaho .
19
20 `
21 Signed:
22 Jared L. Ellsworth
23
ELLSWORTH, DI 77
Idaho Power Company

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-08
IDAHO POWER COMPANY
ELLSWORTH, DI
TESTIMONY
EXHIBIT NO. 1

Southwest Intertie Project (SWIP) Map
OR I ID
Midpoint
Twin Fab
ISWIP North
I
I
Total
SWIP Robinson I U r
N V summd •Ely
I
ISWIP South
(ON Line)
I Burnt
l\ Springs
Harry Allen
CA Las Veyaa. Desert ink
E do A Z
Exhibit No. 1
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 1 of 1

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-08
IDAHO POWER COMPANY
ELLSWORTH, DI
TESTIMONY
EXHIBIT NO. 2

SECOND AMENDED AND RESTATED
TRANSMISSION USE AND CAPACITY
EXCHANGE AGREEMENT
by and among
NEVADA POWER COMPANY
(d/b/a NV Energy)
SIERRA PACIFIC POWER COMPANY
(d/b/a NV Energy)
GREAT BASIN TRANSMISSION SOUTH, LLC
and
GREAT BASIN TRANSMISSION, LLC
Dated as of
June 30, 2020
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 1 of 198

TABLE OF CONTENTS
ARTICLE I DEFINITIONS ............................................................................................................3
1.01 Definitions................................................................................................................3
1.02 Interpretations........................................................................................................33
ARTICLE II ACQUISITION OF ON LINE.................................................................................34
2.01 Acquisition; Purchase Price...................................................................................34
2.02 Closing Payments; Closing Payment Adjustments................................................34
2.03 Conditions Precedent to Acquisition Closing........................................................36
2.04 Acquisition Closing Deliverables..........................................................................37
2.05 Timing and Location of Acquisition Closing........................................................38
2.06 Efforts to Close......................................................................................................38
2.07 Disclosure Schedule Update..................................................................................38
2.08 Allocation of Purchase Price..................................................................................39
ARTICLE III OWNERSHIP AND CAPACITY RIGHTS; MONTHLY PAYMENT.................40
3.01 Ownership Rights...................................................................................................40
3.02 Electrical Capacity Rights......................................................................................41
3.03 Microwave and Fiber Optic Capacity Rights.........................................................45
3.04 Revenue Rights......................................................................................................46
3.05 Relationship of the Parties.....................................................................................46
3.06 Monthly Payment...................................................................................................46
3.07 Great Basin Segment Abandonment or Delay Buyout Right................................48
3.08 30th Anniversary Buyout Right.............................................................................49
3.09 41 st Anniversary Buyout Right or Renewal Term ................................................49
3.10 Force Majeure........................................................................................................50
3.11 Transmission Systems............................................................................................50
3.12 Additional Uses......................................................................................................51
ARTICLE IV DEVELOPMENT AND CONSTRUCTION OF ON LINE ..................................51
4.01 Pursuit and Management of ON Line....................................................................51
4.02 ON Line Managers.................................................................................................52
4.03 Access to ON Line and ON Line ROW.................................................................52
4.04 Standard of Performance........................................................................................52
4.05 Government Approvals; Cooperation....................................................................53
4.06 Interconnection and Construction..........................................................................54
4.07 Consultants.............................................................................................................54
4.08 Change of Name ....................................................................................................54
4.09 [intentionally deleted] ............................................................................................55
ARTICLE V PROJECT BUDGET AND PAYMENT OF COSTS..............................................55
5.01 Project Budget........................................................................................................55
5.02 Compliance with Project Budget; Amendments....................................................56
5.03 Funding ON Line Costs. ........................................................................................56
5.04 Funding of Capital Repair Costs............................................................................58
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Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 2 of 198

5.05 Cost Reductions.....................................................................................................60
5.06 Invoicing and Payment ..........................................................................................60
5.07 Defaulted Contributions.........................................................................................60
5.08 Payment on Non-Business Day .............................................................................61
5.09 [intentionally deleted] ............................................................................................61
ARTICLE VI DEVELOPMENT AND CONSTRUCTION OF GREAT BASIN
SEGMENTS ......................................................................................................................61
6.01 Transmission Improvements..................................................................................61
6.02 Development and Construction..............................................................................62
6.03 Compliance with Laws and Conduct.....................................................................62
6.04 Quarterly Reports...................................................................................................62
6.05 SNIP Option...........................................................................................................62
ARTICLE VII OPERATION OF THE TRANSMISSION LINE.................................................65
7.01 Transmission Line Operation; ON Line Maintenance...........................................65
7.02 Great Basin Segment Maintenance........................................................................66
7.03 Operational and Maintenance Standards ...............................................................66
7.04 Balancing Authority; Balancing Authority Area...................................................67
7.05 Ancillary Services..................................................................................................67
7.06 Transmission Losses..............................................................................................67
7.07 Dynamic Transfers.................................................................................................68
ARTICLE VIII MANAGEMENT COMMITTEE; PROJECT COMPANY................................68
8.01 Management Committee........................................................................................68
8.02 Non-Delegable Actions..........................................................................................70
8.03 Project Company....................................................................................................72
8.04 Time is of the Essence ...........................................................................................72
ARTICLE IX REPORTING; RECORDKEEPING.......................................................................72
9.01 Monthly/Quarterly Report .....................................................................................72
9.02 Notification of ON Line Events.............................................................................73
9.03 Recordkeeping .......................................................................................................73
9.04 Inspection and Audit Rights...................................................................................73
9.05 Information ............................................................................................................74
9.06 Access to Financial Information............................................................................74
ARTICLE X TAXES AND ASSESSMENTS ..............................................................................74
10.01 Management of Tax Matters..................................................................................74
10.02 Sharing of Taxes and Related Payments................................................................75
10.03 Payment of Taxes...................................................................................................75
10.04 Non-Creation of Taxable Entity.............................................................................75
10.05 Transfer Taxes .......................................................................................................76
10.06 Duties Regarding Assessments..............................................................................76
10.07 Periodic Payments..................................................................................................76
ARTICLE XI TERM AND TERMINATION...............................................................................77
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Page 3 of 198

11.01 Term ....................................................................................................................77
11.02 Winding-Up ...........................................................................................................77
11.03 Termination............................................................................................................78
ARTICLE XII INDEMNIFICATION; LIMITATION OF LIABILITY.......................................80
12.01 Indemnification......................................................................................................80
12.02 Contribution of Parties...........................................................................................81
12.03 Waiver of Damages................................................................................................82
12.04 Survival of Representations and Warranties..........................................................84
ARTICLE XIII INSURANCE AND EVENTS OF LOSS............................................................85
13.01 Insurance................................................................................................................85
13.02 Damage or Destruction..........................................................................................85
13.03 Distribution of Insurance Proceeds........................................................................85
13.04 Payment of Restoration Costs................................................................................86
13.05 Rebuild or Repair by a Single Party; Fair Market Value.......................................87
13.06 Great Basin Segment Event of Loss ......................................................................88
13.07 Event of Loss Threshold Deadlock........................................................................88
ARTICLE XIV CONDEMNATION.............................................................................................88
14.01 Participation in Condemnation Action...................................................................88
14.02 Taking....................................................................................................................88
14.03 Distribution of Condemnation Awards..................................................................89
14.04 Payment of Restoration Costs................................................................................89
14.05 Rebuild or Repair by a Single Party ......................................................................90
14.06 Great Basin Segment Condemnation.....................................................................90
14.07 Condemnation Action Threshold Deadlock...........................................................91
ARTICLE XV TRANSFERS AND CHANGES OF CONTROL.................................................91
15.01 Transfers ................................................................................................................91
15.02 Right of First Refusal and Right of First Offer......................................................92
15.03 Permitted Transfers................................................................................................94
15.04 Other Transfer Restrictions....................................................................................95
15.05 Change of Control..................................................................................................97
ARTICLE XVI DEFAULT AND REMEDIES.............................................................................98
16.01 Events of Default...................................................................................................98
16.02 Remedies................................................................................................................98
16.03 Additional Obligations.........................................................................................104
16.04 Interest on Overdue Payments and Contributions; Setoff...................................105
16.05 Mitigation.............................................................................................................105
ARTICLE XVII REPRESENTATIONS AND WARRANTIES ................................................105
17.01 Representations and Warranties...........................................................................105
17.02 Special Representations and Warranties of Great Basin......................................106
17.03 MOU ..................................................................................................................107
17.04 Non-Severable Improvements .............................................................................109
iii
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
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Page 4 of 198

17.05 Knowledge...........................................................................................................109
17.06 Exclusivity of Representations ............................................................................109
ARTICLE XVIII LIENS; FINANCING MATTERS..................................................................109
18.01 Liens ..................................................................................................................109
18.02 Financing..............................................................................................................III
18.03 Non-Disturbance Agreement...............................................................................111
18.04 Security Interest...................................................................................................113
ARTICLE XIX GOVERNING LAW; DISPUTE RESOLUTION.............................................118
19.01 Governing Law....................................................................................................118
19.02 Dispute Resolution; Binding Arbitration.............................................................118
ARTICLE XX MISCELLANEOUS............................................................................................120
20.01 Notices .................................................................................................................120
20.02 Waivers................................................................................................................122
20.03 No Third-Person Beneficiaries ............................................................................122
20.04 Severability..........................................................................................................122
20.05 Independent Counsel............................................................................................122
20.06 Further Assurances...............................................................................................122
20.07 No Fiduciary Relationship...................................................................................122
20.08 Confidential Information .....................................................................................123
20.09 Other Transmission Lines and Exclusivity..........................................................124
20.10 Survival of Obligations........................................................................................125
20.11 Construction.........................................................................................................125
20.12 Amendment; Effectiveness of Agreement; Effect of commercial operation
ofHAE Project.....................................................................................................125
20.13 Entire Agreement.................................................................................................126
20.14 Successors and Assigns........................................................................................126
20.15 Headings ..............................................................................................................126
20.16 Counterparts.........................................................................................................126
20.17 Running with the Land; Memorandums of this Agreement................................126
20.18 Dedication............................................................................................................127
20.19 Integrity Clause; Gratuity ....................................................................................127
20.20 Expiration of Options...........................................................................................128
20.21 Mobile Sierra .......................................................................................................128
EXHIBITS
Exhibit A ON Line Budget
Exhibit B Delegated Responsibilities
Exhibit C ON Line Schedule
Exhibit D Insurance Plan
Exhibit E Form of Bill of Sale and Assignment and Assumption Agreement
Exhibit F Form of Assignment and Consent Agreement
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Exhibit G Form of Grant, Bargain and Sale Deed
Exhibit H Applicable Transfer Representations and Warranties
Exhibit I Legal Opinion Provisions
SCHEDULES
Schedule I Description of Transmission Line
Schedule 2 Monthly Payment Factors
Schedule 3 Operating Activities
Schedule 4 Primary ON Line Agreements
Schedule 5 Buyout Prices
Schedule 6 Governmental Approval Status
Schedule 7 Great Basin Segments Specification Deviations
ANNEXES
Annex A Ownership Percentages of the Parties
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41317598v1 Exhibit No.2
Case No. IPC-E-25-08
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Page 6 of 198

SECOND AMENDED AND RESTATED
TRANSMISSION USE AND CAPACITY
EXCHANGE AGREEMENT
THIS SECOND AMENDED AND RESTATED TRANSMISSION USE AND
CAPACITY EXCHANGE AGREEMENT, dated as of June 30, 2020 (the "2020 Effective
Date"), is made and entered into by and among NEVADA POWER COMPANY, a Nevada
corporation, d/b/a NV Energy ("NPC"), SIERRA PACIFIC POWER COMPANY, a Nevada
corporation, d/b/a NV Energy ("SPPC" and, collectively with NPC, the "NVE Parties"), and
GREAT BASIN TRANSMISSION, LLC, a Delaware limited liability company ("GBT"), and
GREAT BASIN TRANSMISSION SOUTH, LLC, a Delaware limited liability company("GBT-
South"). NPC, SPPC, GBT and GBT-South are sometimes referred to herein individually as a
"Party" and collectively as the "Parties." GBT and GBT-South are sometimes referred to herein
individually or collectively as "Great Basin", as the context requires, in accordance with the TUA
Assignment(defined below) and the Joinder Agreement(defined below).
RECITALS
WHEREAS, the NVE Parties are investor-owned electric utilities serving customers in
both northern and southern Nevada and have previously engaged in various development activities
with respect to a major transmission project in eastern Nevada to interconnect the two utilities
known, as of the Effective Date, as the "One Nevada Transmission Line Project" or "ON Line",
which is an above-ground 500 kV AC transmission line from a substation to be located at the
Robinson Summit Location to the Harry Allen Substation(the "NVE Project");
WHEREAS, GBT previously owned and engaged in various development activities with
respect to the Transmission Line, which is an above-ground 500 kV AC transmission line
comprising three segments extending from the Midpoint Substation to the Eldorado Substation;
WHEREAS, the northernmost and central segments of the Transmission Line are
collectively known as the Southwest Intertie Project, with the northernmost segment being a
segment from Idaho extending to the Robinson Summit Substation in Northern Nevada (which
segment is expected to have Electrical Capacity of no less than 1,600 MW) that is developed and
constructed by LSP(as defined below)or any of its direct or indirect subsidiaries(which the Parties
currently contemplate shall be a segment extending from the Midpoint Substation to the Robinson
Summit Substation) (any such segment being "SWIP-N"), the central segment extending from
the Robinson Summit Substation to the Harry Allen Substation ("SWIP-S"), and the
southernmost segment of the Transmission Line, which is known as the Southern Nevada Intertie
Project, extending from the Harry Allen Substation to the Eldorado Substation(which segment is
expected to have Electrical Capacity of no less than 1,400 MW)("SNIP"),it being understood that
the term"SNIP" shall not include the HAE Project(as defined below);
WHEREAS, pursuant to the Transmission Use and Capacity Exchange Agreement (the
"Original_ Agreement"), dated as of August 20, 2010 (the "Effective Date"), by and among the
NVE Parties and GBT, (i)the NVE Parties purchased from GBT and GBT sold to the NVE Parties
certain undivided ownership interests in SWIP-S, (ii) SWIP-S was renamed the "One Nevada
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 7 of 198

Transmission Line" (or"ON Line"), and(iii)the NVE Parties and GBT agreed to jointly develop,
construct, own, manage and use ON Line and jointly use SWIP-N and SNIP, in each case, upon
the terms and conditions set forth in the Original Agreement;
WHEREAS, pursuant to the Assignment and Assumption Agreement (TUA) (the "TUA
Assignment"), dated as of February 9, 2011, by and between GBT and GBT-South, GBT
transferred,assigned,conveyed and delivered to GBT-South,and GBT-South accepted the transfer
and assignment of, the benefit of all of GBT's right, title, benefit and interest to, in and under (i)
the Original Agreement as it relates to ON Line,the Ownership Interests(as defined in the Original
Agreement) owned by GBT and the portion of the Transmission Line comprised of ON Line, and
(ii) the IP License Agreement (as defined in the Original Agreement) and the Interconnection
Agreements (as defined in the TUA Assignment), and GBT-South assumed, on a joint and several
basis with GBT, all of GBT's obligations under the Original Agreement, the Security Documents
(as defined in the Original Agreement), the IP License Agreement, the Interconnection
Agreements and any other agreements in connection with the Original Agreement; provided that,
for the avoidance of doubt, GBT did not assign to GBT-South any right, title or interest in, to or
under the Great Basin Segments or the Excluded TUA Provisions (as defined in the TUA
Assignment);
WHEREAS, GBT, GBT-South and the NVE Parties are parties to the Joinder Agreement
(the "Joinder Agreement"), dated as of February 9, 2011, pursuant to which, among other things,
GBT-South became a party to the Original Agreement;
WHEREAS, ON Line achieved ON Line COD effective as of January 1, 2014;
WHEREAS, SNIP and SWIP-N comprise the Great Basin Segments, as further described
in this Agreement;
WHEREAS,GBT and GBT-South are indirect subsidiaries of LS Power Associates,L.P.,
a Delaware limited partnership ("LSP");
WHEREAS, LSP has formed a wholly-owned indirect subsidiary, DesertLink, LLC, a
Delaware limited liability company ("DesertLink OpCo"), to submit one or more bids
(collectively,the"OpCo Bids") into a solicitation by CAISO corresponding to the 4th sequence of
Phase 3 of CAISO's 2013-2014 Planning Process (the "HAE Solicitation") to develop, construct,
own and operate a 500 kV transmission line between the Harry Allen Substation and the Eldorado
Substation (any such transmission line pursued by DesertLink OpCo or another Person in
connection with the HAE Solicitation being referred to herein as the "HAE Project");
WHEREAS, LSP and the Parties have agreed that the HAE Project shall be treated as
separate and distinct from SNIP;
WHEREAS, the Parties previously executed that certain First Amended and Restated
Transmission Use and Capacity Exchange Agreement, dated as of April 30, 2015 (the "Prior
Restatement Agreement"), which Prior Restatement Agreement was intended by the Parties to
amend and restate in its entirety the Original Agreement upon satisfaction of the conditions to
effectiveness set forth in the Prior Restatement Agreement;
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WHEREAS, the Parties acknowledge that the conditions to the effectiveness of the Prior
Restatement Agreement were not satisfied and,therefore,the Prior Restatement Agreement never
went into effect;
WHEREAS, on January 11, 2016, CAISO selected DesertLink OpCo as the approved
project sponsor to finance, construct, own, operate and maintain the HAE Project;
WHEREAS, the Parties previously executed that certain First Amended and Restated
Transmission Use and Capacity Exchange Agreement, dated as of April 8, 2016 (the "2016 First
A&R TUA"), which 2016 First A&R TUA amended and restated in their entirety the Original
Agreement and the Prior Restatement Agreement to, among other things, reflect (i) CAISO's
selection of DesertLink OpCo as the approved project sponsor to finance, construct, own, operate
and maintain the HAE Project and(ii) certain understandings and agreements between the Parties
with respect to the HAE Project and SNIP, including the effect of the commercial operation of the
HAE Project on the rights and obligations of the Parties, including the respective Capacity
Entitlements of the NVE Parties and Great Basin,under the 2016 First A&R TUA;
WHEREAS, on December 24,2019,the Public Utilities Commission of Nevada approved
a cost reallocation with respect to the NVE Parties to better reflect SPPC's benefits from ON Line;
WHEREAS, contemporaneously with the execution of this Agreement, the Parties have
entered into that Consent and Waiver Agreement dated as of the 2020 Effective Date,and the NVE
Parties have entered into that Assignment and Assumption Agreement dated as of the 2020
Effective Date, in each case, to address the reallocation of Ownership Percentages of NPC and
SPPC; and
WHEREAS,the Parties now desire to amend and restate in its entirety the 2016 First A&R
TUA to reflect a Transfer by NPC to SPPC of twenty percent(20%) of NPC's Ownership Interest
in ON Line (i.e., a five percent (5%) Ownership Percentage), resulting in NPC having an
Ownership Percentage of eighteen and seventy-five hundredths percent (18.75%) and SPPC
having an Ownership Percentage of six and twenty-five hundredths percent (6.25%), under this
Agreement.
NOW THEREFORE, in consideration of the premises and mutual covenants and
agreements set forth in this Agreement, and for other good and valuable consideration,the receipt
and sufficiency of which are hereby acknowledged, the Parties hereby amend and restate in its
entirety the 2016 First A&R TUA and agree as follows, effective as of the 2020 Effective Date.
AGREEMENT
ARTICLE I
DEFINITIONS
1.01 Definitions. As used in this Agreement, the following terms shall have the
following meanings:
"2016 First A&R TUA"has the meaning set forth in the recitals to this Agreement.
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"2020 Effective Date"has the meaning set forth in the preface to this Agreement.
"AAA" has the meaning set forth in Section 19.02(b)(i).
"AC"means alternating current.
"Acquiring Party"has the meaning set forth in Section 15.02(c).
"Acquisition Closing"means the sale by Great Basin and the purchase by the NVE
Parties of Ownership Interests in the amount of their respective Ownership Percentages.
"Acquisition Closing" means the date upon which the Acquisition Closing
occurs, which shall be the day before the Acquisition Closing is effective in accordance with
Section 2.05.
"Acquisition Closing Deadline"has the meaning set forth in Section 2.06.
"Advance"has the meaning set forth in Section 5.07(a).
"Affiliate"means any Person that, directly or indirectly through one or more other
Persons, Controls, is Controlled by or is under common Control with the Person specified. For
the purposes of this Agreement(except Sections 12.01(c) and 20.08),the NVE Parties shall not be
considered Affiliates of one another.
"Affiliated Assignee"has the meaning set forth in Section 15.03(e).
"Affiliated Lender" means any Person that is an Affiliate of Great Basin or holds
greater than a ten percent (10%) direct or indirect equity interest in Great Basin other than any
agency or other instrumentality of the United States of America in its capacity as an ON Line
Lender or GB Segment Lender that becomes an Affiliate of Great Basin as a result of a foreclosure
or other exercise of its remedies under the ON Line Financing Agreements or the GB Segment
Financing Agreements, as applicable.
"Agreed Rate"means the lesser of(a) the "Prime rate" for the "U.S." as published
in the "Money Rates" table of The Wall Street Journal from time to time and (b) the maximum
rate of interest permitted by Applicable Law.
"Agreement" means this Second Amended and Restated Transmission Use and
Capacity Exchange Agreement.
"Allocation"has the meaning set forth in Section 2.08.
"Alternate Representative"has the meaning set forth in Section 8.01(a).
"Amortization Period" means (a) with respect to Capital Repairs, Event of Loss
Costs and Condemnation Action Costs, the useful life (in months) of the applicable reconstructed
or restored asset (consistent with a depreciation schedule approved by the PUCN and used by the
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NVE Parties for similar assets) depreciated on a straight line basis and (b) with respect to any
Incremental Cost Differential, six hundred twenty-four(624) months on a straight line basis.
"Ancillary Services" means any of the services that are necessary to support the
transmission of capacity and energy from resources to loads while maintaining reliable operation
of the transmission system in accordance with Prudent Utility Practices, including scheduling,
system control and dispatch service,reactive supply and voltage control,regulation and frequency
response, energy imbalance, generator imbalance, operating reserve-spinning, operating reserve-
supplemental and loss compensation.
"Anticipated Investment" means (a) with respect to SWIP-N, six hundred sixteen
million nine hundred ten thousand Dollars ($616,910,000), (b) with respect to ON Line, five
hundred nine million six hundred twenty-one thousand Dollars($509,621,000)and(c)with respect
to SNIP, two hundred fourteen million five hundred seventy-seven thousand Dollars
($214,577,000). For the avoidance of doubt, the foregoing Anticipated Investment amounts shall
not be subject to adjustment for any reason, including in respect of any Carrying Costs, interest or
allowance for funds used during construction.
"Applicable Centennial Phase 3 Facilities" has the meaning set forth in the SNIP
Agreement.
"Applicable Centennial Phase 3 Rights" has the meaning set forth in Section
6.05(a).
"Applicable Law" means any law, statute, common law, treaty, code, rule,
ordinance, binding directive, regulation, order, judgment, decree, ruling, determination or
Governmental Approval of any Governmental Authority, including Environmental Laws, in each
case, which is binding on the Transmission Line (any portion thereof), any Party or any Project
Company, as applicable.
"Applicable Transfer Representations and Warranties" means, with respect to a
Transfer, the representations and warranties and related limits on liability in form and substance
similar to those set out in Exhibit H.
"Assignment and Assumption Agreement" has the meaning set forth in Section
15.04(b).
"Authorized Representative"has the meaning set forth in Section 8.01(a).
`Balancing Authority" means the responsible entity that integrates resource plans
ahead of time, maintains load-interchange-generation balance within the Balancing Authority Area
and supports interconnection frequency in real time.
"Balancing Authority Area" means the collection of generation, transmission and
loads within the metered boundaries of the NVE Parties.
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"Balancing Authority Area Services Agreement"means a Balancing Authority Area
Services Agreement entered into by and between Great Basin and one or both of the NVE Parties
for the provision of certain Ancillary Services; provided, however, that such Balancing Authority
Area Services Agreement shall not provide for any (a) generator imbalance service for generators
directly interconnected to the Great Basin Segments within the Balancing Authority Area outside
of a bandwidth of. (i)plus or minus one and one-half percent (1.5%) of such generator's capacity
or (ii) a maximum of plus or minus two (2) MWs, (b) energy imbalance services or (c) operating
reserves(either spinning or supplemental)or back-up for resources associated with schedules from
generators delivering their output from or outside of the NVE Parties' Balancing Authority Area.
"Bankruptcy Event" means, with respect to any Person, if such Person (a)
voluntarily files a petition or otherwise commences, authorizes or acquiesces in the
commencement of a proceeding or cause of action under any bankruptcy, insolvency,
reorganization or similar law, (b) has any such petition filed or proceeding or action commenced
against it by its creditors and such petition,proceeding or action is not dismissed within sixty(60)
days after the filing or commencement; (c) makes an assignment or any general arrangement for
the benefit of creditors; (d)has a liquidator, administrator, receiver, trustee, conservator or similar
official appointed with respect to it or any substantial portion of its property or assets; or (e) is
generally unable to pay its debts as they fall due.
"BLM" means the United States Department of Interior's Bureau of Land
Management.
"BLM SNIP License Consent" means a final decision issued by the BLM, not
subject to rehearing or administrative appeal, providing any and all BLM approvals necessary to
provide the license and transfer of assets by NPC to Great Basin as contemplated by the SNIP
Agreement, on terms and conditions reasonably acceptable to the NVE Parties and Great Basin.
"Books and Records"has the meaning set forth in Section 9.03(a).
"Business Day"means any day other than Saturday, Sunday and any day that banks
are required to close in the State of Nevada or the State of New York.
"CA" means the Confidentiality Agreement, dated May 18, 2009, by and between
Great Basin and NVE Parent.
"CAISO"means the California Independent System Operator Corporation.
"CAISO Tariff'means the CAISO FERC Electric Tariff on file with the FERC, as
modified from time to time.
"Capacity Entitlement"means,with respect to a Party,the portion of the Electrical
Capacity to which such Party is entitled pursuant to Section 3.02, as may be adjusted pursuant to
Sections 16.02(f),W or Lh).
"Capital Repair" means (a) any and all work reasonably necessary or appropriate
to repair,restore,refurbish or replace any equipment, structure or any other component of ON Line
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(or any portion thereof) after ON Line COD necessitated by(i) any defect in design, construction
or installation, (ii) physical or functional obsolescence or (iii) modifications required by any
Applicable Law or(b)the substitution,replacement,enlargement or improvement of any structure,
facility, equipment,property, land or land rights constituting part of ON Line after ON Line COD
(including, for the avoidance of doubt, the addition of any transformers at the Robinson Summit
Substation), in each case with respect to clauses (a) and (b), the associated costs of which would
be capitalized in accordance with GAAP; provided, however, that Capital Repairs do not include
any Operating Activities or work resulting from any Event of Loss or any Condemnation Action,
or any work to repair, restore, refurbish or replace, or the substitution, replacement, enlargement
or improvement of, the Harry Allen Transformers.
"Capital Repair Budget" means each budget for Capital Repairs approved by the
Management Committee, which shall include line item estimates of the cost of all Capital Repairs
expected for the five-year operation period immediately following its preparation.
"Capital Repair Costs"means costs and expenses incurred to complete any Capital
Repairs, including each Party's (a) direct internal labor costs for employees directly engaged in
completing Capital Repairs insofar as such costs are subject to reimbursement pursuant to Section
5.01 d , (b) all direct costs for supplies, materials, equipment property, land and land rights and
the cost of removal, salvage, or disposal of any structure, facility, equipment or property, (c)third-
Person costs, directly incurred for permitting and licensing activities, engineering, surveying,
project management, legal, and other professional services incurred in respect of the completion
of Capital Repairs, (d) costs and expenses directly incurred pursuant to ON Line Agreements
entered into in respect of Capital Repairs and(e)costs and expenses required during an emergency
to protect human life in connection with ON Line, protect against or mitigate serious loss or
damage to ON Line, comply with Applicable Law for ON Line and prevent or mitigate damage to
the environment or to the property of others caused by ON Line, which, in the case of clauses (a)
through (e) above, would be capitalized in accordance with GAAP; provided, however, that
Capital Repair Costs shall not include the following: (n) any costs or expenses incurred under the
Balancing Authority Area Services Agreement or in providing Balancing Area Authority services
thereunder, (o) Event of Loss Costs or Condemnation Action Costs, (p) any lobbying costs, (q)
any legal fees associated with Great Basin's participation in regulatory proceedings where such
participation has not been approved in advance by the Management Committee or the NVE
Parties' participation in regulatory proceedings where the NVE Parties are not the
applicant/petitioner or are not required to participate, (r) any gift of items, money or entertainment
in connection with ON Line, including political or campaign contributions, (s) Personal Taxes or
Transfer Taxes, (t) third-Person costs, expenses and fees for lawyers, other consultants, financing
parties and agents (including application and other fees and expenses in connection with any loan
guarantee or other program provided by the U.S. Department of Energy), in each case, incurred by
any Party in connection with the ON Line Financing, its financing of Capital Repair Costs, all
other Excluded Agreements and the costs associated with any Party's auditing and reporting
requirements under this Agreement, the ON Line Financing Agreements and its other financing
agreements, including all Up-Front GBT Costs and On-Going GBT Costs, (u) costs and expenses
incurred in the preparation, negotiation, execution or delivery of this Agreement, (v) any amounts
attributable to general administrative costs or overhead costs not associated with direct internal
labor for employees directly engaged in the completion of Capital Repairs, (w) any amounts
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incurred by Great Basin in connection with the Great Basin Segments, (x) any interest or penalty
imposed by any Governmental Authority, (y) any interest or costs associated with carrying such
costs and expenses, including Carrying Costs and (z) other than as described in clause (d) above,
any costs or expenses arising, incurred or committed to by a Party without the consent of the
Management Committee and not in accordance with the Capital Repair Budget.
"Capitalized Costs" means an amount equal to the aggregate sum of the (a) lesser
of Net Actual Costs and the aggregate amount of ON Line Costs set forth in the ON Line Budget,
plus Carrying Costs in respect of such costs, (b) Initial Cost Differential, plus Carrying Costs in
respect of such costs and(c) Carrying Cost up to ON Line COD in respect of any Incremental Cost
Differential,Net Event of Loss Costs and Net Condemnation Action Costs.
"Ca . irr ing Cost"means the cost of carrying any ON Line Costs,Event of Loss Costs
and Condemnation Action Costs less any applicable Cost Reductions, in each case, from the date
such costs were incurred to ON Line COD at a rate equal to (a) eight and fifty-eight hundredths
percent (8.58%) per annum, compounded semi-annually, prior to ON Line Financial Closing and
(b)eight and eight hundredths percent(8.08%)per annum, compounded semi-annually,thereafter;
provided, however, that(x) Carrying Costs on Great Basin's Development Costs from January 1,
2010 to Acquisition Closing shall not exceed an amount equal to,when added to such Development
Costs and Carrying Costs of Great Basin through December 31,2009,fifteen million eight hundred
thousand Dollars ($15,800,000) and (y) Carrying Costs on the Development Costs of the NVE
Parties from January 1, 2010 to Acquisition Closing shall not exceed an amount equal to, when
added to such Development Costs and Carrying Costs of the NVE Parties through December 31,
2009, fifteen million eight hundred thousand Dollars ($15,800,000). For the avoidance of doubt,
any Development Costs and Pre-Closing Costs incurred prior to ON Line Financial Closing shall
be carried at a rate of eight and fifty-eight hundredths percent (8.58%) per annum, compounded
semi-annually, from the date such costs were incurred to the date of ON Line Financial Closing
and then at a rate of eight and eight hundredths percent (8.08%) per annum, compounded semi-
annually, from the date of ON Line Financial Closing to the ON Line COD. For purposes of
calculating Carrying Costs hereunder, all ON Line Costs, Event of Loss Costs and Condemnation
Action Costs, in each case, shall be deemed incurred, and Cost Reductions, Insurance Proceeds
and Condemnation Awards shall be deemed received, on the last day of the month in which such
costs are incurred or reductions are received.
"Chair"has the meaning set forth in Section 8.01(e).
"Claiming Party"has the meaning set forth in Section 3.10.
"Claims" means any and all claims, demands, suits, obligations, payments,
liabilities, costs, fines, penalties, sanctions, taxes, judgments, damages, losses and expenses,
including reasonable attorneys' fees and expenses.
"Closing Payment"has the meaning set forth in Section 2.02(b).
"Closing Statement"has the meaning set forth in Section 2.02(b).
"Code"means the Internal Revenue Code of 1986.
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"Complete Taking"has the meaning set forth in Section 14.02.
"Condemnation Action"means the taking of all or any portion of the Transmission
Line as a result of the exercise of the power of eminent domain or condemnation for public or
quasi-public use or the sale or conveyance of all or any portion of the Transmission Line under the
threat or in lieu of condemnation.
"Condemnation Action Budget"has the meaning set forth in Section 14.04.
"Condemnation Action Costs"has the meaning set forth in Section 14.04.
"Condemnation Award" means any compensation received in respect of a
Condemnation Action.
"Confidential Information"has the meaning set forth in Section 20.08(a).
"Contributing Party"has the meaning set forth in Section 5.07(a).
"Contribution"has the meaning set forth in Section 5.07(a).
"Control" means the ownership, directly or indirectly, of fifty percent (50%) or
more of the voting securities of a Person or the power to direct the management or policies of such
Person, whether by operation of law, by contract or otherwise.
"Cost Detail Reconciliation Statement" has the meaning set forth in Section
2.02(d).
"Cost Detail Statement"has the meaning set forth in Section 2.02(a).
"Cost Reduction" means any (a) damages, liquidated damages, indemnity
payments or other amounts recovered pursuant to any ON Line Agreement or in settlement of any
claim or dispute arising under any ON Line Agreement, (b)Insurance Proceeds(other than Excess
Insurance Proceeds) and Condemnation Awards (other than Excess Condemnation Awards)
recovered in respect of ON Line (including for delay-in-start up) and (c) proceeds received in
respect of the disposition of any assets of ON Line.
"Counterparty Code of Conduct" means the Counterparty Code of Conduct
promulgated by the NVE Parties and as in effect on(and disclosed in writing to Great Basin prior
to) the Effective Date, setting forth requirements for Persons engaging in business transactions
with the NVE Parties.
"Critical Capital Repairs" means Capital Repairs that NPC reasonably deems are
required in order to operate ON Line in a safe and reliable manner in accordance with Prudent
Utility Practices.
"Critical Change Orders" means change orders under Material Construction
Contracts that the Managing Party reasonably deems are required in order for ON Line to operate
in a safe and reliable manner in accordance with Prudent Utility Practices.
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"Deadlock"has the meaning set forth in Section 8.01(h).
"Default Purchase Notice"has the meaning set forth in Section 16.02(d).
"Default Rate" means the lesser of (a) four percent (4%) per annum above the
Agreed Rate and(b) the maximum rate of interest permitted by Applicable Law.
"Demand"has the meaning set forth in Section 19.02(b)(i).
"DesertLink OpCo"has the meaning set forth in the recitals to this Agreement.
"Development Costs"means all ON Line Costs incurred by a Party prior to January
1, 2010, which are, with respect to (a) NPC, twelve million four hundred thirty-six thousand two
hundred seventy-one Dollars ($12,436,271), (b) SPPC, six hundred fifty-four thousand five
hundred forty Dollars ($654,540) and(c) Great Basin, fifteen million Dollars ($15,000,000).
"Direct Pay Amounts"means Post-Closing Costs due under Material Construction
Contracts that are to be invoiced directly to, and paid directly by, NPC and Great Basin in
accordance with this Agreement.
"Disclosing PartX" has the meaning set forth in Section 20.08(a).
"Disclosure Schedules"has the meaning set forth in Section 17.01.
"Disclosure Schedule Update"has the meaning set forth in Section 2.07.
"Dispute"has the meaning set forth in Section 19.02(a).
"Dollars"means the lawful currency of the United States of America.
"Double Circuit Towers" means the ON Line double circuit transmission towers
and associated appurtenances designed and constructed to support two (2) 500kV 3-phase AC
circuits located between (and including) that certain HMD3 double circuit dead end structure
number 617 located at latitude 37' 15' 20.99" North, longitude 114' 57' 45.87" West and that
certain HMD3 double circuit dead end structure number 627 located at latitude 37' 14' 11.95"
North, longitude 114' 58' 37.03 West.
"Effective Date"has the meaning set forth in the recitals to this Agreement.
"Effective Tax Rate"means (a)the then current Federal corporate statutory income
tax rate plus (b)the product of(i) the then current State of Nevada corporate statutory income tax
rate times (ii) an amount equal to one (1) minus the Federal corporate statutory income tax rate.
"Eldorado Substation"means the substation jointly owned by Southern California
Edison, NPC, Salt River Project and Los Angeles Department of Water and Power located south
of Las Vegas in Clark County,Nevada and commonly known as the "Eldorado Substation."
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"Electrical CapacitX" means the maximum electrical rating of the Transmission
Line(or applicable portion thereof) expressed in MWs, as such rating is determined and approved
by WECC (or such other regulatory authority responsible for rating the Transmission Line) from
time to time.
`Electric Reliability Organization" means the organization certified by FERC to
propose and enforce mandatory standards for the reliable operation and planning of the bulk power
system throughout the United States of America.
"Eligible Assignee" means any Person that (a) has (or is Affiliated with a Person
that has) at least four (4) years' experience owning and operating transmission lines comparable
to the Transmission Line, (b) is (or is Affiliated with a Person that is) subject to regulation by
FERC at the time the applicable Transfer is first proposed and (c) has (or its parent has) a credit
rating at the time of the applicable Transfer equal to or better than an Investment Grade Credit
Rating or, if such Person does not have an Investment Grade Credit Rating, a net worth at the time
of the applicable Transfer equal to or greater than three hundred fifty million Dollars
($350,000,000).
"Eligible Control Party" means (a) any Eligible Assignee, (b) following ON Line
COD and provided that Great Basin holds no material assets other than Ownership Interests, any
Experienced Operator and(c) following ON Line COD and the occurrence of the earlier of(i) GB
Segment COD and (ii) the GB Segment Financial Closing Deadline without achieving GB
Segment Financial Closing, any Experienced Operator.
"Environmental Law" means any federal, state, local or other law, common law,
regulation,rule, ordinance, code, decree,judgment,binding directive, or judicial or administrative
order relating to the protection, preservation or restoration of human health, the environment,
wildfire, natural resources or cultural, archaeological or historic resources, including (a) any law
relating to the releases or threatened releases of Hazardous Substances into any medium(including
ambient air, surface water, groundwater, land, surface and subsurface strata) or otherwise relating
to the manufacture,processing,distribution,use,treatment,storage,release,transport and handling
of Hazardous Substances; (b) the Comprehensive Environmental Response, Compensation and
Liability Act, 42 U.S.C. § 9601 et seq.; the Resource Conservation and Recovery Act, 42 U.S.C.
§ 6901 et seq.; the Federal Water Pollution Control Act, 33 U.S.C. § 1251 et seq.; the Clean Air
Act, 42 U.S.C. § 7401 et seq.; the Hazardous Materials Transportation Act, 49 U.S.C. § 1471 et
seq.; the Toxic Substances Control Act, 15 U.S.C. §§ 2601 through 2629; the Oil Pollution Act,
33 U.S.C. § 2701 et seq.;the Emergency Planning and Community Right-to-Know Act,42 U.S.C.
§ 11001 et seq.;the National Environmental Policy Act,42 U.S.C. §4321 et seq.;the Safe Drinking
Water Act,42 U.S.C. §§ 300f through 300j; and(c)all other Applicable Laws addressing pollution
or protection of human health, safety or the environment.
"Event of Default"has the meaning set forth in Section 16.01.
"Event of Loss"means damage to, destruction of, or other property casualty to the
Transmission Line (or any part thereof), whether or not covered by insurance.
"Event of Loss Budget"has the meaning set forth in Section 13.04.
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"Event of Loss Costs"has the meaning set forth in Section 13.04.
"Excess Condemnation Award"has the meaning set forth in Section 14.03.
"Excess Insurance Proceeds"has the meaning set forth in Section 13.03.
"Excluded Agreements"means(a)agreements between a Party and its transmission
and other customers regarding such customers' rights to transmit electricity on or otherwise utilize
such Party's Capacity Entitlement, Microwave Capacity or Fiber Optic Capacity, (b) agreements
only between NPC and SPPC, (c) the ON Line Financing Agreements, (d) the financing
agreements with the NVE Lenders and(e) any Balancing Authority Area Services Agreement.
"Excluded Lien"means any of the following:
(a) a Permitted Lien;
(b) provided that Sections 18.03 and 18.04 are satisfied, a Lien granted
on the Ownership Interests or other assets of a Party(excluding the Great Basin Segments prior to
GB Segment COD,except if the Parties agree in writing otherwise),given by such Party as security
for the obligations of such Party to the ON Line Lenders or the NVE Lenders, as applicable, and
enforceable only against the Ownership Interests or such other assets of such Party;
(c) provided that Sections 18.03 and 18.04 are satisfied, a Lien granted
on the ownership interests of Great Basin in the Great Basin Segments or other assets of Great
Basin (excluding ON Line prior to GB Segment COD, except if the Parties agree in writing
otherwise), given by Great Basin as security for its obligations to the GB Segment Lenders;
(d) (i) with respect to Liens on ON Line, Liens for any tax, assessment
or other governmental charge (including Liens in favor of customs and revenue authorities arising
as a matter of law to secure payment of customs duties in connection with the importation of goods
for ON Line) arising in the ordinary course of business for ON Line, and(ii)with respect to Liens
on the Great Basin Segments, Liens for any tax, assessment or other governmental charge
(including Liens in favor of customs and revenue authorities arising as a matter of law to secure
payment of customs duties in connection with the importation of goods for the Great Basin
Segments) arising in the ordinary course of business for the Great Basin Segments, in each case
(A) which are for amounts not yet due or amounts being contested in good faith by appropriate
proceedings and reserved against in accordance with GAAP and (B) so long as such Liens shall
not involve any reasonable likelihood of the sale, forfeiture or loss of any material interest in the
Transmission Line and shall not interfere in any material respect with the use or disposition of any
material part of the Transmission Line,the GB Segment Security Interest or the ON Line Security
Interest;
(e) (i) with respect to ON Line, materialmen's, mechanics', workers,
repairmen's, employees' or other like Liens on ON Line and any statutory lien, rights of setoff or
similar rights on ON Line arising in the ordinary course of business of ON Line or in connection
with the construction, operation or maintenance of ON Line, and (ii) with respect to the Great
Basin Segments, materialmen's, mechanics', workers', repairmen's, employees' or other like
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Liens on the Great Basin Segments and any statutory lien, rights of setoff or similar rights on the
Great Basin Segments arising in the ordinary course of business of the Great Basin Segments or
in connection with the construction, operation or maintenance of the Great Basin Segments, in
each case (A) which (in the aggregate) do not materially detract from the value of the property or
assets to which they are attached,or which are for amounts not yet due or amounts which are being
contested in good faith by appropriate proceedings and are reserved against in accordance with
GAAP or bonded over, and(B) so long as such Liens shall not involve any reasonable likelihood
of the sale,forfeiture or loss of any material interest in the Transmission Line and shall not interfere
in any material respect with the use or disposition of any material part of the Transmission Line,
the GB Segment Security Interest or the ON Line Security Interest;
(f) Liens arising out of judgments or awards so long as enforcement of
such Liens have been stayed and an appeal or proceeding for review is being prosecuted in good
faith by appropriate proceedings and are reserved against in accordance with GAAP or are fully
covered by insurance;
(g) (i) with respect to ON Line, Liens on ON Line to secure (A)
mandatory statutory obligations or(B)provided that Section 18.03 is satisfied with respect to Liens
securing amounts in excess of two hundred fifty thousand Dollars ($250,000), performance of
bids, tenders, contracts (other than for the repayment of indebtedness for borrowed money) or
leases, or for purposes of like general nature, in the ordinary course of business for ON Line, and
having an aggregate value with respect to all Liens contemplated by this clause (g)(i)(B) at any
one time outstanding not greater than one million Dollars($1,000,000), and(ii)with respect to the
Great Basin Segments, Liens on the Great Basin Segments to secure (A) mandatory statutory
obligations or(B) provided that Section 18.03 is satisfied with respect to Liens securing amounts
in excess of two hundred fifty thousand Dollars($250,000),performance of bids,tenders,contracts
(other than for the repayment of indebtedness for borrowed money) or leases, or for purposes of
like general nature, in the ordinary course of business for the Great Basin Segments, and having
an aggregate value with respect to all Liens contemplated by this clause (g)(ii)(B) at any one time
outstanding not greater than one million Dollars ($1,000,000), in each case, so long as such Liens
shall not involve any reasonable likelihood of the sale, forfeiture or loss of any material interest in
the Transmission Line and shall not interfere in any material respect with the use or disposition of
any material part of the Transmission Line, the GB Segment Security Interest or the ON Line
Security Interest;
(h) (i) with respect to ON Line, involuntary Liens (including a lien of
an attachment, judgment or execution) not existing for more than thirty (30) days on ON Line
securing a charge or obligation for ON Line on any of ON Line's property, either real or personal,
in the aggregate sum of less than two hundred thousand Dollars ($200,000) at any one time
outstanding, and(ii)with respect to the Great Basin Segments, involuntary Liens (including a lien
of an attachment,judgment or execution) not existing for more than thirty(30) days on the Great
Basin Segments securing a charge or obligation for the Great Basin Segments on any of the Great
Basin Segments' property, either real or personal, in the aggregate sum of less than two hundred
thousand Dollars ($200,000) at any one time outstanding, in each case, so long as such Liens shall
not involve any reasonable likelihood of the sale, forfeiture or loss of any material interest in the
Transmission Line and shall not interfere in any material respect with the use or disposition of any
13
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 19 of 198

material part of the Transmission Line,the GB Segment Security Interest or the ON Line Security
Interest;
(i) any other Liens approved by the Parties;
0) with respect to (i) Great Basin, any Lien on the Ownership Interests
of Great Basin or the Great Basin Segments arising as a result of a breach by one or both of the
NVE Parties of any of their respective obligations under this Agreement or any agreement executed
in connection herewith and (ii) the NVE Parties, any Lien on the Ownership Interests of such
Parties arising as a result of a breach by Great Basin of any of its obligations under this Agreement
or any agreement executed in connection herewith;
(k) with respect to Great Basin, Liens that are subordinated to the ON
Line Security Interest or the GB Segment Security Interest pursuant to a subordination agreement
acceptable to the NVE Parties in their sole discretion; and
(1) provided that Section 18.03 is satisfied with respect to Liens
securing amounts in excess of(i) two hundred fifty thousand Dollars ($250,000) individually or
(ii) when added to the aggregate amount secured by other Liens permitted by this subsection (1)
and not subject to a Non-Disturbance Agreement,one million Dollars($1,000,000),Liens existing
only on the Great Basin Segments prior to GB Segment Financial Closing in favor of unaffiliated
lenders, construction contractors, equipment providers or any other unaffiliated Persons providing
financing for the development, engineering, procurement or construction of the Great Basin
Segments.
"Experienced Operator" means any Person that has (or is Affiliated with a Person
that has) at least four (4) years' experience owning and operating transmission lines comparable
to the Transmission Line or hires a project manager that has such experience.
"Extended Payment Default"has the meaning set forth in Section 16.02(h).
"Fair Market Value"has the meaning set forth in Section 13.05(b).
"FERC"means the Federal Energy Regulatory Commission.
"FERC Approval" means one or more final orders issued by FERC under Section
205 of the Federal Power Act,without substantial condition or modification and that is not subject
to rehearing or appeal, accepting this Agreement and each Interconnection Agreement for filing
(including a determination by FERC that no further filing of the SNIP Agreement is required), in
each case, on terms reasonably acceptable to the NVE Parties and Great Basin.
"Fiber Optic Capacity" means the maximum fiber optic line capacity of the
Transmission Line (or applicable portion thereof).
"Final NVE Capacity Entitlement" means (a) the NVE Parties' total Capacity
Entitlement expressed as MWs, divided by(b) the Electrical Capacity.
14
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 20 of 198

"Force Majeure" means any of the following enumerated events that occur
subsequent to the Effective Date that delays or prevents a Party's performance of its obligations
under this Agreement, but only to the extent that (a) such event is not attributable to the fault or
negligence on the part of such Party, (b) such event is caused by factors beyond such Party's
reasonable control and(c) despite taking all reasonable technical and commercial precautions and
measures to prevent, avoid, mitigate or overcome such event and the consequences thereof, such
Party has been unable to prevent, avoid, mitigate or overcome such event or consequences:
(i) Acts of God, such as storms, hurricanes, droughts, tornados,
avalanches, epidemics, land slides, floods, lightning, fire, explosion, quarantine, earthquakes, and
other natural disasters;
(ii) Sabotage or destruction by a third Person of facilities and equipment
relating to the performance by the affected Party of its obligations under this Agreement;
(iii) War (declared or undeclared), insurrection, acts of terrorism,
rebellion, blockades, embargoes, fires, explosions, adverse geological or underground conditions,
riot, acts of a public enemy or other civil disturbance;
(iv) Strike, walkout, lockout or other significant labor dispute;
(v) (A) Loss or damage of materials or equipment in transit or inability
to procure materials or equipment, (B) chemical or radioactive contamination of materials,
equipment or sites or(C) inability to conduct studies or interconnect or test facilities due to delay
by any third Person;
(vi) (A) Action or inaction of a Governmental Authority (including a
Party's failure or delay in receiving or renewing any Governmental Approval), (B) changes in any
Governmental Approval or the conditions imposed thereunder or (C) any material legislative,
judicial or administrative change in any Applicable Law existing as of the Effective Date, any
material change in the enforcement, interpretation or application of any Applicable Law existing
as of the Effective Date by the relevant Governmental Authority, or the enactment of any
Applicable Law on or after the Effective Date;
(vii) A material adverse change or effect in the banking, institutional or
capital markets in general; and
(viii) Action or inaction in connection with requirements from an Electric
Reliability Organization applicable to the Transmission Line.
Notwithstanding anything to the contrary in this definition, (x) Force Majeure shall not include
economic hardship of a Party unless such hardship is a direct result of the event described in clause
(vii)above and(y)no Party shall be prevented from claiming Force Majeure to the extent that such
Party's performance is delayed or prevented by its unwillingness to settle or otherwise resolve a
strike,walkout, lockout or other significant labor dispute of its own workforce, and the settlement
or resolution of such strike, walkout, lockout or significant labor dispute shall be in such Party's
sole discretion.
15
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 21 of 198

"GAAP"means generally accepted accounting principles for financial reporting in
the United States of America, applied on a consistent basis.
"GB Segment COD"means the date that(a)both of the Great Basin Segments have
commenced commercial operations and satisfied the requirements for"substantial completion"(or
words of similar import) as defined in and in accordance with the requirements of the applicable
material construction agreements, (b) all transmission upgrades and interconnection facilities
necessary to interconnect SWIP-N with the applicable substations have been completed and
successfully tested in accordance with Prudent Utility Practices, (c) all transmission upgrades and
interconnection facilities necessary to interconnect SNIP with the Harry Allen Substation and
Eldorado Substation have been completed and successfully tested in accordance with Prudent
Utility Practices and(d)both of the Great Basin Segments have been safely and reliably energized
and energy may be delivered across the interconnection facilities to the interconnection providers'
transmission systems in accordance with the applicable interconnection agreements.
"GB Segment COD Deadline" means the sixth (6th) anniversary of the GB
Segment Financial Closing or such later date as may be determined in accordance with Section
3.07(b).
"GB Segment Development Costs" means (a) the aggregate sum of costs and
expenses incurred by Great Basin to complete the development of the Great Basin Segments,
including (i) Great Basin's direct internal labor costs for employees directly engaged in
development efforts associated with the Great Basin Segments, (ii) third-Person costs for
permitting and licensing activities, engineering, surveying,project management, legal, accounting
and other professional services incurred in respect of development efforts associated with the Great
Basin Segments, (iii) interest on all such costs at a rate equal to eight and fifty-eight hundredths
percent (8.58%) per annum, compounded semi-annually, calculated from when such costs were
incurred to GB Segment Financial Closing and (iv) the use of any liquidated damages, proceeds,
awards or payments described in clause (b) below to pay any costs or expenses incurred by Great
Basin to complete the development of the Great Basin Segments,minus(b)any liquidated damages
recovered as a result of a failure of the Great Basin Segments to achieve their performance or
schedule guarantees, any Insurance Proceeds, Condemnation Awards or damage or indemnity
payments received in respect of the Great Basin Segments, and any proceeds for the disposition of
any assets of the Great Basin Segments (together with the reduction in carrying costs resulting
from the receipt of such liquidated damages, Insurance Proceeds, Condemnation Awards, damage
or indemnity payments or other proceeds, as applicable); provided, however, that GB Segment
Development Costs shall not include the following: (q) any lobbying costs, (r) any legal fees
associated with Great Basin's participation in regulatory proceedings where Great Basin is not the
applicant or petitioner, (s) any gift of items, money or entertainment in connection with the Great
Basin Segments, including political or campaign contributions, (t) Personal Taxes or Transfer
Taxes, (u) third-Person costs, expenses and fees for lawyers, other consultants, financing parties
and agents (including application and other fees and expenses in connection with any loan
guarantee or other program provided by the U.S. Department of Energy), in each case,incurred by
Great Basin in connection with the GB Segment Financing and the costs associated with Great
Basin's auditing and reporting requirements under this Agreement and the GB Segment Financing
Agreements, (v) costs and expenses incurred in the preparation,negotiation, execution or delivery
16
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 22 of 198

of this Agreement, (w) any amounts attributable to general administrative costs or overhead costs
not associated with direct internal labor for employees directly engaged in development efforts
associated with Great Basin Segments, (x) any interest or penalty imposed by any Governmental
Authority, (y) any amounts incurred by Great Basin in connection with ON Line or (z) costs or
expenses incurred pursuant to procurement or construction agreements or other agreements for the
purchase of equipment or materials for any of the Great Basin Segments.
"GB Segment Financial Closing" means the occurrence of each of the following:
(a) the GB Segment Security Interest has been granted to the NVE Parties and is valid, legal,
perfected,in full force and effect and has the priority contemplated by Section 18.04,each Security
Document for the GB Segment Security Interest has been properly executed and delivered, and
has been duly filed, registered and recorded, and Uniform Commercial Code financing statements
have been duly filed, in each case in each jurisdiction as required by Applicable Law or as
reasonably requested by the NVE Parties in order to grant and maintain a valid,legal and perfected
Lien with the priority contemplated by Section 18.04 in respect of the GB Segment Security
Interest, and each such Security Document is in full force and effect, (b) a Non-Disturbance
Agreement has been delivered by each GB Segment Lender (or an agent thereof) in favor of the
NVE Parties, (c) legal opinions addressing the matters set forth on Exhibit I attached hereto and
otherwise in form and substance reasonably acceptable to the NVE Parties have been delivered to
the NVE Parties regarding the GB Segment Security Interest and the associated Security
Documents, (d) Great Basin has obtained financing for the expected full cost of the Great Basin
Segments plus a reasonable contingency, (e) all GB Segment Financing Agreements required in
order to obtain the financing referred to in clause (d) above have been executed and delivered by
all parties thereto to each other and are in full force and effect, (f) all conditions precedent (other
than customary draw conditions) under such GB Segment Financing Agreements have been
satisfied or permanently waived necessary to allow Great Basin to fund the expected full cost of
the Great Basin Segments,(g)the first drawdown of loans pursuant to such GB Segment Financing
Agreements has occurred, (h) the GB Segment Lenders (other than any Affiliated Lender) have
delivered a certificate stating or Great Basin has delivered such other evidence demonstrating, in
each case that is reasonably satisfactory to the NVE Parties, that each of clauses (d)-(g) above has
occurred, and(i) full notice to proceed has been issued under all critical construction contracts for
either Great Basin Segment.
"GB Segment Financial Closing Deadline" means March 31, 2014 or such later
date as may be determined in accordance with the terms set forth in this Agreement.
"GB Segment Financing" means the financing or refinancing (including working
capital facilities not to exceed fifteen million Dollars ($15,000,000) and interest rate hedging
facilities and related letters of credit) for the construction, operation or capital repairs of the Great
Basin Segments.
"GB Segment Financing Agreements"means all financing and equity contribution
agreements for the GB Segment Financing.
"GB Segment Intercreditor Agreement" means an intercreditor agreement to be
executed and delivered by the NVE Parties, Great Basin and the GB Segment Lenders (or an agent
thereof).
17
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 23 of 198

"GB Segment Lenders" means the Persons providing loans or other credit or
interest rate hedging facilities under the GB Segment Financing Agreements; provided, however,
that no Affiliated Lender shall be a GB Segment Lender, unless (for so long as such GB Segment
Lender is an Affiliated Lender) (a) such Affiliated Lender (i) has no voting, approval or consent
rights with respect to any provision of this Agreement that is subject to the GB Segment Lenders'
vote,approval or consent under the terms of this Agreement,(ii)has no voting,approval or consent
rights with respect to the exercising of any remedy under any security document in connection
with the GB Segment Financing, and (iii) has no voting, approval or consent rights, and does not
participate, with respect to any decision to issue any certificate contemplated by clause (h) of the
definition GB Segment Financial Closing, and (b) the aggregate amount of the GB Segment
Financing held directly or indirectly by all Affiliated Lenders is equal to or less than one-third
(1/3) of the principal amount of the GB Segment Financing; provided, further, however, that any
Affiliated Lender that is a GB Segment Lender shall be entitled to benefit from any and all waivers,
consents, amendments and remedies granted or exercised by the other GB Segment Lenders on a
pro rata and pari passu basis.
"GB Segment Security Interest"has the meaning set forth in Section 18.04(a).
"GB Segment Security Interest Cap"has the meaning set forth in Section 18.04(a).
"GBT"has the meaning set forth in the preface to this Agreement.
"GBT-South"has the meaning set forth in the preface to this Agreement.
"Governmental Approvals" means any licenses, approvals, consents, exemptions,
agreements, authorizations or permits of, notifications to or filings or registrations with, any
Governmental Authority relating to the Transmission Line (or any portion thereof).
"Governmental Authority"means any executive branch,legislature,court,tribunal,
arbitrator, authority, agency, commission, official or other instrumentality of the United States of
America or other country or any domestic state, county, city or other political subdivision or
similar governing entity.
"Gratuity"means any gift of items,money or entertainment intended to improperly
influence the award of a contract or to improperly obtain favorable treatment under a contract in a
manner that violates Applicable Law.
"Great Basin"has the meaning set forth in the preface to this Agreement.
"Great Basin Manager"has the meaning set forth in Section 4.02(a).
"Great Basin O&M Costs" means all costs and expenses under the Balancing
Authority Area Services Agreement and the aggregate sum of all costs and expenses for all
Operating Activities,maintenance, capital repairs,BLM lease payments,property taxes,payments
for utilities, costs of obtaining and maintaining any required Governmental Approvals, insurance
premiums, licensing fees and other fees, consulting and professional fees and expenses necessary
for management and operation, in each case, in respect of any Great Basin Segment.
18
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 24 of 198

"Great Basin Segments" means (a) if HAE COD does not occur on or prior to the
HAE COD Outside Date, SWIP-N and SNIP collectively, including, in each case, any fiber optic
line comprising SWIP-N and SNIP, any microwave communication system comprising SWIP-N
and SNIP and any and all assets, interests and property rights (real and personal and tangible and
intangible) comprising SWIP-N and SNIP and any and all leasehold and other possessory interest
in the rights-of-way, agreements, Governmental Approvals for the Great Basin Segments, and
books and records, work product, depreciation and other tax benefits, in each case, comprising
SWIP-N and SNIP, as further described in Schedule 1, and(b) if HAE COD occurs on or prior to
the HAE COD Outside Date, SWIP-N, any fiber optic line comprising SWIP-N, any microwave
communication system comprising SWIP-N and any and all assets, interests and property rights
(real and personal and tangible and intangible) comprising SWIP-N and any and all leasehold and
other possessory interest in the rights-of-way, agreements, Governmental Approvals for SWIP-N,
and books and records,work product, depreciation and other tax benefits, in each case, comprising
SWIP-N, as further described in Schedule 1. For the avoidance of doubt, if HAE COD occurs on
or prior to the HAE COD Outside Date, any references in this Agreement to "any" or "both" (or
words of similar meaning) of the Great Basin Segments shall be deemed to refer only to SWIP-N
(and the associated assets, interests and property rights described in clause (b) above).
"HAE COD" means the date that the HAE Project is placed under CAISO
"Operational Control", as defined in the CAISO Tariff, pursuant to a Transmission Control
Agreement between CAISO and DesertLink OpCo.
"HAE COD Outside Date"means June 1, 2023.
"HAE Project"has the meaning set forth in the recitals to this Agreement.
"HAE Solicitation"has the meaning set forth in the recitals to this Agreement.
"Harry Allen Substation" means the substation owned by NPC located just north
of Las Vegas in Clark County,Nevada and commonly known as the "Harry Allen Substation."
"Harry Allen Transformers" means any existing or future power or phase angle
regulating transformer, including all associated equipment, located at the existing or future
expanded Harry Allen transmission switchyards.
"Hazardous Substance" means: (a) any petroleum or petroleum products,
flammable materials, explosives, radioactive materials, friable asbestos, urea formaldehyde foam
insulation and transformers or other equipment that contain dielectric fluid containing
polychlorinated biphenyls(PCBs)in regulated concentrations;(b)any chemicals or other materials
or substances which are now or hereafter become defined as or included in the definition of
"hazardous substances," "hazardous wastes," "hazardous materials," "extremely hazardous
wastes," "restricted hazardous wastes," "toxic substances," "toxic pollutants," "contaminants,"
"pollutants"or words of similar import under any Environmental Law; and(c) any other chemical
or other material or substance, exposure to which is now or hereafter prohibited, limited or
regulated as such under any Environmental Law, including the Resource Conservation and
Recovery Act, 42 U.S.C. Section 6901 et seq., the Comprehensive Environmental Response
Compensation and Liability Act, 42 U.S.C. Section 9601 et seq, or any similar state statute.
19
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 25 of 198

"Incremental Cost Differential"means an amount (if any) equal to any Net Actual
Costs in excess of the greater of(a) the ON Line Budget and (b) the Anticipated Investment for
ON Line.
"Indemnified Persons"has the meaning set forth in Section 12.01(a).
"Indemnifying Party"has the meaning set forth in Section 12.01(b).
"Independent Auditor"has the meaning set forth in Section 2.02(e).
"Independent Contractor"means any independent contractor retained pursuant to a
Maintenance Agreement to maintain the Transmission Line (or any portion thereof).
"Initial Cost Differential" means the lesser of (a) any amount by which the
Anticipated Investment for ON Line exceeds the ON Line Budget and (b) any amount by which
the Net Actual Costs exceed the ON Line Budget.
"Insurance Plan"means the insurance plan set forth as Exhibit D, as such plan may
be amended from time to time and approved by the Management Committee.
"Insurance Proceeds" means any insurance proceeds paid pursuant to insurance
policies maintained in accordance with the Insurance Plan.
"Interconnection Agreements" means the Robinson Summit Substation
Transmission Interconnection Agreement, effective as of the date approved by FERC, entered into
by and among SPPC (in its capacity as the interconnection provider), Great Basin, SPPC (in its
capacity as an owner of ON Line) and NPC (in its capacity as an owner of ON Line) and the Harry
Allen Transmission Interconnection Agreement, effective as of the date approved by FERC,
entered into by and among NPC (in its capacity as the interconnection provider), Great Basin and
NPC (in its capacity as an owner of ON Line) and SPPC (in its capacity as an owner of ON Line),
in each case, as approved by FERC.
"Intercreditor Agreements" means the ON Line Intercreditor Agreement and the
GB Segment Intercreditor Agreement.
"Investment Grade Credit Rating"means,with respect to a Person, a then assigned
credit rating of such Person based on its long-term, senior, secured or unsecured non-credit-
enhanced, indebtedness equal to "BaaY or above from Moody's Investor Services, Inc. (or any
successor) or "BBB-" or above from Standard & Poor's Ratings Group, a division of McGraw
Hill, Inc. (or any successor); provided, however, that if neither of such credit ratings is published
for such Person, then the Investment Grade Credit Rating for such Person means a then assigned
credit rating of such Person based on its long-term, senior, secured or unsecured non-credit-
enhanced, indebtedness equal to "BBB-" or above as determined by, in the case of an Eligible
Assignee, the NVE Parties and, in the case of Section 11.02(c), each other Party, in each case, in
accordance with its internal policies and procedures for determining implied credit ratings.
20
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 26 of 198

"IP License Agreement"means the Intellectual Property License Agreement, dated
as of the date hereof,by and among the NVE Parties and Great Basin.
"Joinder Agreement"has the meaning set forth in the recitals to this Agreement.
"kV"means kilovolt.
"Land Contracts" means the easements, leases, licenses, instruments, agreements,
and documents that grant rights in the ON Line ROW necessary or desirable for the development,
construction, ownership and management of ON Line, including ingress to and egress from the
ON Line ROW.
"Las Vegas Courts"has the meaning set forth in Section 19.02(b)(v).
"Lien" means any mortgage, lien, pledge, charge, claim, security interest or other
encumbrance, including any liens for taxes and assessments, builder, mechanic, warehouseman,
materialman, contractor, workman, repairman or carrier liens or other similar liens or claims.
"Loss Threshold" means any Event of Loss or Condemnation Action occurring in
respect of (a) ON Line (or any portion thereof) with an estimated cost to repair or replace the
affected portion of eighty million Dollars($80,000,000)or,if the estimated cost to repair or replace
exceeds twenty million Dollars ($20,000,000), with an estimated period of time required to repair
or replace the affected portion of three (3) years, (b) SNIP (or any portion thereof) with an
estimated cost to repair or replace the affected portion of thirty-two million Dollars ($32,000,000)
or, if the estimated cost to repair or replace exceeds eight million Dollars ($8,000,000), with an
estimated period of time required to repair or replace the affected portion of three (3) years or (c)
SWIP-N(or any portion thereof)with an estimated cost to repair or replace the affected portion of
eighty million Dollars ($80,000,000) or, if the estimated cost to repair or replace exceeds twenty
million Dollars ($20,000,000), with an estimated period of time required to repair or replace the
affected portion of three (3) years (such Dollar thresholds to be adjusted upward annually by a
factor of two percent(2%)per annum from and after the first(I st) anniversary of ON Line COD).
"Loss Threshold Deadlock" means the Parties are unable to reach agreement
regarding any determination of whether an Event of Loss or Condemnation Action exceeded a
Loss Threshold.
"LSP"has the meaning set forth in the recitals to this Agreement.
"Maintenance Agreement" means any separate agreement between a Party and an
Independent Contractor, relating to the maintenance of the Transmission Line (or any portion
thereof) as may be in effect from time to time.
"Management Committee"means the management committee established pursuant
to Section 8.01(a).
"Managing Party" means, subject to Section 16.02(e), (a) through the Acquisition
Closing Date, Great Basin and(b) after the Acquisition Closing Date to ON Line COD,NPC.
21
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 27 of 198

"Material Adverse Effect" means a material adverse effect on (a) ON Line or the
development, construction, ownership, management, operation, maintenance, use or economic
viability thereof, (b)the ability of the Parties to perform their respective material obligations under
this Agreement, (c) the ability of any party to enter into any ON Line Agreement or perform its
material obligations under any ON Line Agreement, (d) the ability to obtain, maintain or comply
in any material respect with any material Governmental Approval for ON Line or (e) the validity
or enforceability of this Agreement or any of the ON Line Agreements, or the rights or remedies
of the parties hereunder or thereunder.
"Material Construction Contract" means each of the Substation Construction
Contract, the Transmission Line Construction Contract, the Tower Supply Agreements and the
Other Supply Agreements.
"Material Construction Contractor" means each of the Substation Construction
Contractor, the Transmission Line Construction Contractor, the Tower Suppliers and the Other
Suppliers.
"Material Event"means any breach of or default under, or notice of force majeure
or other material communication with respect to, any ON Line Agreement, any litigation pending
or threatened in writing or proceeding of a Governmental Authority pending or threatened in
writing affecting the Transmission Line, any material Condemnation Action or Event of Loss and
any citation or notice of material noncompliance with Applicable Law.
"Microwave Capacity" means the maximum microwave communication system
capacity of the Transmission Line (or applicable portion thereof).
"Midpoint Substation" means the substation owned by Idaho Power Company
located north of Twin Falls in Jerome County, Idaho and commonly known as the "Midpoint
Substation."
"Monthly Payment"has the meaning set forth in Section 3.06(a).
"Monthly Payment Period"has the meaning set forth in Section 3.06(a).
"Monthly/Quarterly Report"has the meaning set forth in Section 9.01.
"MOU" means the Memorandum of Understanding Regarding Potential
Transmission Use Agreement, dated as of December 30, 2009,by and among the Parties.
"MW"means megawatt.
"NERC"means the North American Electric Reliability Corporation.
"Net Actual Costs" means an amount equal to the aggregate of all Development
Costs, all Pre-Closing Costs and all Post-Closing Costs, minus an aggregate amount equal to all
Cost Reductions received by a Party in respect of ON Line Activities.
22
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 28 of 198

"Net Capital Repair Costs" means all Capital Repair Costs incurred by a Party,
minus an aggregate amount equal to all Cost Reductions received by a Party in respect of Capital
Repairs.
"Net Condemnation Action Costs"means all Condemnation Action Costs incurred
by a Party, minus an aggregate amount equal to all Cost Reductions received by a Party in respect
of any Condemnation Action.
"Net Event of Loss Costs"means all Event of Loss Costs incurred by a Party,minus
an aggregate amount equal to all Cost Reductions received by a Party in respect of any Event of
Loss.
"Non-Contributing Party"has the meaning set forth in Section 5.07(a).
"Non-Disturbance Agreement"has the meaning set forth in Section 18.03.
"Notice"has the meaning set forth in Section 19.02(a).
"NPC"has the meaning set forth in the preface to this Agreement.
"NPC Manager"has the meaning set forth in Section 4.02(b).
"NPC Purchase Price"has the meaning set forth in Section 2.01(b).
"NVE Lenders"means the Persons making available funds to the NVE Parties (or
any one of them individually) or any of their respective Affiliates through loans, debt securities or
other credit facilities before or after the Effective Date,including holders of securities issued under
their respective General and Refunding Mortgage Indentures, dated as of May 1, 2001.
"NVE Parent"means NV Energy, Inc., a Nevada corporation.
"NVE Parties"has the meaning set forth in the preface to this Agreement.
"NVE Project"has the meaning set forth in the recitals of this Agreement.
"NVE WACC" means the weighted average cost of capital for NPC as of the first
day of the calendar year in which the relevant expenditure occurred, as determined in NPC's
regulatory case that sets such cost for the first day of the applicable year,with the return on equity
component grossed up for income taxes by dividing the return on equity component by an amount
equal to one (1) minus the Effective Tax Rate.
"Offer Notice" means any ROFR Offer Notice or ROFO Offer Notice, as
applicable.
"Offered Interest"means any ROFR Offered Interest or ROFO Offered Interest, as
applicable.
23
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 29 of 198

"On-Going GBT Costs"means costs, expenses and fees paid to unaffiliated third-
Persons reasonably incurred by Great Basin after ON Line COD associated with (i) Great Basin's
auditing and reporting requirements under this Agreement or (ii) the ON Line Financing
Agreements,which are, in each case, actual, verifiable costs paid to unaffiliated third-Persons in a
single fiscal year, but shall not include any costs of carrying such third-Person costs; provided,
however, that On-Going GBT Costs shall not include any costs that, in the aggregate, exceed in a
single fiscal year an amount equal to the product of(a) one hundred twenty-five thousand Dollars
($125,000) and(b)the Price Index.
"ON Line"means any and all assets, interests and property rights(real and personal
and tangible and intangible) comprising SWIP-S (to be renamed the "One Nevada Transmission
Line"pursuant to Section 4.08),including any fiber optic line comprising SWIP-S,any microwave
communication system comprising SWIP-S and any and all leasehold or other possessory interest
in the ON Line ROW, ON Line Agreements, Governmental Approvals for ON Line, Books and
Records, Work Product and depreciation and other tax benefits, as further described in Schedule
1. For the avoidance of doubt, ON Line does not include the NVE Project, Excluded Agreements
or any information licensed to Great Basin under the IP License Agreement.
"ON Line Activities" means all activities undertaken in connection with (a) the
development, construction, testing and starting up of ON Line prior to the commencement of the
Operating Period and (b) the development of the NVE Project through the Acquisition Closing;
provided, however, that ON Line Activities shall not include any activities contemplated by the
Excluded Agreements or any activities undertaken in connection with Capital Repairs, an Event
of Loss or Condemnation Action.
"ON Line Agreement" means an agreement (other than this Agreement) entered
into by a Party in connection with the ON Line Activities (excluding development of the NVE
Project), Capital Repairs or work resulting from any Event of Loss or Condemnation Action on
ON Line, including each Material Construction Contract, Interconnection Agreement, Land
Contract and the IP License Agreement; provided, however, that ON Line Agreements do not
include any Excluded Agreements.
"ON Line Budget" means the budget attached hereto as Exhibit A (as amended
from time to time in accordance with the provisions hereof)consisting of line item estimates of all
ON Line Costs required to be funded by the Parties hereunder, including allowances for escalation
(where applicable) and contingency, in each case, that are calculated in accordance with prudent
estimating practices,but shall not include any Carrying Costs.
"ON Line COD" means the date that (a) ON Line commences commercial
operation and satisfies the requirements for"substantial completion" (or words of similar import)
as defined in and in accordance with each Material Construction Contract, (b) all additions,
modifications and changes to the NVE Parties'transmission systems necessary to interconnect ON
Line with the Robinson Summit Substation and the Harry Allen Substation have been completed
and successfully tested in accordance with Prudent Utility Practices and(c) ON Line is safely and
reliably energized and energy may be delivered across such interconnection facilities to the NVE
Parties' transmission systems in accordance with the Interconnection Agreements.
24
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 30 of 198

"ON Line Costs" means costs and expenses incurred to complete the ON Line
Activities, including each Party's (a) direct internal labor costs for employees directly engaged in
performing the ON Line Activities insofar as such costs are subject to reimbursement pursuant to
Section 5.01(d), (b) third-Person costs for permitting and licensing activities, engineering,
surveying, project management, legal, accounting and other professional services incurred in
respect of the performance of ON Line Activities, (c) costs and expenses incurred pursuant to ON
Line Agreements entered into in respect of ON Line Activities, (d) costs and expenses required
during an emergency to protect human life in connection with ON Line,protect against or mitigate
serious loss or damage to ON Line, comply with Applicable Law for ON Line and prevent or
mitigate damage to the environment or to the property of others caused by ON Line and (e)
amounts payable prior to ON Line COD for BLM lease payments,property Taxes and sales Taxes;
provided, however, that ON Line Costs shall not include the following: (n) any costs or expenses
incurred under the Balancing Authority Area Services Agreement or in providing Balancing Area
services thereunder, (o) Event of Loss Costs or Condemnation Action Costs, (p) any costs or
expenses incurred to complete the ON Line Activities prior to January 1, 2010 other than
Development Costs, (q) any lobbying costs, (r) any legal fees associated with Great Basin's
participation in regulatory proceedings where such participation has not been approved in advance
by the Management Committee or the NVE Parties' participation in regulatory proceedings where
the NVE Parties are not the applicant/petitioner or are not required to participate, (s) any gift of
items, money or entertainment in connection with ON Line, including political or campaign
contributions, (t) Personal Taxes or Transfer Taxes, (u) third-Person costs, expenses and fees for
lawyers, other consultants, financing parties and agents (including application and other fees and
expenses in connection with any loan guarantee or other program provided by the U.S.Department
of Energy), in each case, incurred by any Party in connection with the ON Line Financing, its
financing of Capital Repair Costs, all other Excluded Agreements and the costs associated with
any Party's auditing and reporting requirements under this Agreement, the ON Line Financing
Agreements and its other financing agreements, including all Up-Front GBT Costs and On-Going
GBT Costs, (v) costs and expenses incurred in the preparation, negotiation, execution or delivery
of this Agreement, (w) any amounts attributable to general administrative costs or overhead costs
not associated with direct internal labor for employees directly engaged in the performance of ON
Line Activities, (x) any amounts incurred by Great Basin in connection with the Great Basin
Segments, (y) any interest or penalty imposed by any Governmental Authority and(z) any interest
or costs associated with carrying such costs and expenses, including Carrying Costs.
"ON Line Financial Closing" means the occurrence of the following: (a) Great
Basin has obtained debt and equity financing in an amount equal to at least seventy-five percent
(75%) of the expected Post-Closing Costs as set forth in the ON Line Budget, (b) all ON Line
Financing Agreements required in order to obtain the financing referred to in clause (a)above have
been executed and delivered by all parties thereto to each other and are in full force and effect, (c)
all conditions precedent (other than customary draw conditions) under such ON Line Financing
Agreements have been satisfied or permanently waived necessary to allow Great Basin to fund at
least seventy-five percent (75%) of the expected Post-Closing Costs as set forth in the ON Line
Budget, (d) the first drawdown of loans pursuant to such ON Line Financing Agreements has
occurred and (e) the ON Line Lenders (other than any Affiliated Lender) have delivered a
certificate stating or Great Basin has delivered such other evidence demonstrating, in each case
reasonably satisfactory to the NVE Parties, that each of the foregoing has occurred.
25
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 31 of 198

"ON Line Financing" means the financing or refinancing (including working
capital facilities not to exceed five million Dollars ($5,000,000)and interest rate hedging facilities
and related letters of credit) obtained by Great Basin for the construction of ON Line or Capital
Repairs or the working capital needs of Great Basin in respect of ON Line.
"ON Line Financing Agreements" means all financing and equity contribution
agreements for the ON Line Financing.
"ON Line Intercreditor Agreement" means an intercreditor agreement to be
executed and delivered by the NVE Parties, Great Basin and the ON Line Lenders (or an agent
thereof).
"ON Line Lenders" means the Persons (including the U.S. Department of Energy,
as a loan guarantor)providing loans, other credit facilities or interest rate hedging facilities under
the ON Line Financing Agreements; provided, however, that no Affiliated Lender shall be an ON
Line Lender, unless (for so long as such ON Line Lender is an Affiliated Lender) (a) such
Affiliated Lender(i)has no voting, approval or consent rights with respect to any provision of this
Agreement that is subject to the ON Line Lenders' vote, approval, or consent under the terms of
this Agreement, (ii)has no voting, approval or consent rights with respect to the exercising of any
remedy under any security document in connection with the ON Line Financing, and (iii) has no
voting, approval or consent rights, and does not participate, with respect to any decision to issue
any certificate contemplated by clause (e) of the definition of ON Line Financial Closing, and (b)
the amount of the ON Line Financing held directly or indirectly by such Affiliated Lender is used
only for funding Capital Repair Costs, Initial Cost Differentials or Incremental Cost Differentials;
provided, further, however, that any Affiliated Lender that is an ON Line Lender shall be entitled
to benefit from any and all waivers, consents, amendments and remedies granted or exercised by
the other ON Line Lenders on a pro rata and pari passu basis.
"ON Line Manager" means the Great Basin Manager or the NPC Manager, as
applicable.
"ON Line ROW" means the parcel(s) of real estate on which ON Line will be
constructed and situated, including that which is more fully described in Schedule 1.
"ON Line Schedule"means that certain detailed Level II schedule for the ON Line
Activities, attached hereto as Exhibit C (as amended from time to time in accordance with the
provisions hereof), which shall include the expected sequence of activities, durations and
milestones for the construction of ON Line and incorporate the Level II critical path method
schedules that represent the schedules for accomplishing, and that is the baseline schedule that
forms the basis of progress for, the work to be performed under each Material Construction
Contract.
"ON Line Security Interest"has the meaning set forth in Section 18.04(a).
"OpCo Bids"has the meaning set forth in the recitals to this Agreement.
26
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 32 of 198

"Operating Activities" means all activities reasonably necessary or advisable in
connection with the day-to-day(a)management,operation,inspection, cleaning and upkeep of ON
Line (or any portion thereof) during the Operating Period and (b) operation of the Great Basin
Segments, as further specified, but not limited to the activities set forth, in Schedule 3; provided,
however, that Operating Activities do not include any Ancillary Services or any work resulting
from any Capital Repair, Event of Loss or any Condemnation Action.
"Operating Costs" means the aggregate sum of all costs and expenses for all
Operating Activities, BLM lease payments, property Taxes, payments for utilities, costs of
obtaining and maintaining any required Governmental Approvals, insurance premiums, licensing
fees and other fees, consulting and professional fees, and expenses necessary for the day-to-day
management and operation,in each case,in respect of ON Line;provided,however,that Operating
Costs shall not include(a)any amounts owing pursuant to Sections 12.01 or 12.02,(b)any amounts
paid under any Monthly Payment, (c) with regard to Great Basin, any costs that would not have
been reimbursed under Section 5.01(d), (d) any costs incurred by any Party in connection with its
individual (as opposed to common) ownership or use (as opposed to operation and maintenance)
of ON Line, including any costs associated with Great Basin's Open Access Transmission Tariff,
(e) any Capital Repair Costs, Event of Loss Cost or Condemnation Action Cost, (f) On-Going
GBT Costs, (g) Personal Taxes or Transfer Taxes, (h) any interest or penalty imposed by any
Governmental Authority and caused by Great Basin or (i) any costs incurred in connection with
the operation of any Great Basin Segment.
"Operating Period" means the period of time commencing on the ON Line COD
and ending on the date the Transmission Line is retired in accordance with this Agreement.
"Operating Plan"means a plan submitted to the Management Committee for review
and discussion, but not approval, covering the following activities: (a) with respect to ON Line,
activities related to operations and maintenance of ON Line, in accordance with Prudent Utility
Practices,the NVE Parties' transmission operating procedures and policies, and applicable NERC
and/or WECC requirements, such as line patrols, vegetation management, equipment testing and
inspection, insulator washing, and electric system control center coordinated operating protocols;
and(b)with respect to the Great Basin Segments, activities related to operation of the Great Basin
Segments, in accordance with Prudent Utility Practices, the NVE Parties' transmission operating
procedures and policies, and applicable NERC and/or WECC requirements, including electric
system control center coordinated operating protocols, outage coordination, and line monitoring.
"Operator" means the entity responsible for operating the Transmission Line in
accordance with the requirements of the Balancing Authority.
"Option Exercise Price"has the meaning set forth in Section 6.05(a).
"original Agreement"has the meaning set forth in the recitals to this Agreement.
"Other Supply Agreements" means the agreements among NPC, Great Basin and
the Other Suppliers pursuant to which the Other Suppliers will supply the balance of plant supplies,
equipment and materials for ON Line.
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Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 33 of 198

"Other Suppliers"means the suppliers under the Other Supply Agreements.
"Owners' En ig neer" means an independent engineer selected by the Management
Committee to provide assistance to any Party in connection with ON Line, including the design,
engineering, construction, commissioning and start-up of ON Line.
"Ownership Interest"means an undivided ownership interest in ON Line.
"Ownership Percentage" means (a) with respect to Great Basin, seventy-five
percent (75%), (b) with respect to NPC, eighteen and seventy-five hundredths percent (18.75%)
and (c) with respect to SPPC, six and twenty-five hundredths percent (6.25%), in each case, as
such Ownership Percentage may be adjusted from time to time in accordance with Sections
5.03 d , 5.04 c , 13.04, 14.04, and 16.02 and set forth opposite each Party's name on Annex A.
For the avoidance of doubt, in the event one Party (or the NVE Parties) acquires all of the
Ownership Interests of the other Party(ies) pursuant to this Agreement, then such Party's (or the
NVE Parties') aggregate Ownership Percentage shall be one hundred percent(100%).
"Partial Taking"has the meaning set forth in Section 14.02.
"Party" and"Parties"have the meaning set forth in the preface to this Agreement.
"Permitted Liens" means (a) all matters filed of record, validly existing and
affecting a particular asset or property as of the Effective Date (together with such other Liens as
are (i) acceptable to the NVE Parties in their sole discretion as of Acquisition Closing in the case
of ON Line, and(ii)reasonably acceptable to the NVE Parties as of GB Segment Financial Closing
in the case of the Great Basin Segments), (b) any Lien for Taxes not yet due or delinquent, (c) any
statutory Lien(including any Liens of carriers,warehousemen,mechanics and materialmen arising
in the ordinary course of business by operation of law) with respect to a liability not yet due or
delinquent, (d) zoning, entitlement, conservation restriction and other land use and environmental
regulations by any Governmental Authority, (e) any minor imperfection of title or other Lien
which, individually or in the aggregate, would not be reasonably expected to be material, and (f)
the ON Line Security Interest and the GB Segment Security Interest.
"Permitted Transfer"has the meaning set forth in Section 15.03.
"Person" means any natural person, corporation, general partnership, limited
partnership, proprietorship, limited liability company, other business organization, trust, union,
association or Governmental Authority.
"Personal Taxes"has the meaning set forth in Section 10.01.
"Post-Closing Costs" means all ON Line Costs incurred by a Party after the
Acquisition Closing Date (a) in accordance with the ON Line Budget, (b) with the consent of the
Management Committee or (c) that are required during an emergency to protect human life in
connection with ON Line, protect against or mitigate serious loss or damage to ON Line, comply
with Applicable Law for ON Line and prevent or mitigate damage to the environment or to the
property of others caused by ON Line.
28
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 34 of 198

"Pre-Closing Costs"means all ON Line Costs incurred by a Party from January 1,
2010 through the Acquisition Closing Date (a) in accordance with the ON Line Budget, (b) with
the consent of the Management Committee or(c)that are required during an emergency to protect
human life in connection with ON Line, protect against or mitigate serious loss or damage to ON
Line,comply with Applicable Law for ON Line and prevent or mitigate damage to the environment
or to the property of others caused by ON Line.
"Price Index" means the ratio of the Gross Domestic Product — Implicit Price
Deflator published in the National Income and Product Account by the U.S. Department of
Commerce on the date of determination relative to such Gross Domestic Product—Implicit Price
Deflator value on January 1, 2013.
"Prior Restatement Agreement" has the meaning set forth in the recitals to this
Agreement.
"Project Budget" means the ON Line Budget, each Capital Repair Budget, any
Event of Loss Budget and any Condemnation Action Budget.
"Project CompanX"has the meaning set forth in Section 8.03(a).
"Prudent Utility Practices" shall mean any of the acts, practices, methods,
equipment, materials, specifications and standards engaged in or approved in connection with a
significant portion of the electric utility industry which, as applicable, in the exercise of
professional judgment in light of the facts known at the time a decision was made,could have been
expected to accomplish the desired result in a manner consistent with Applicable Laws, Electric
Reliability Organization requirements, reliability, safety, performance, dependability, efficiency,
environmental protection, economy and expedition. Prudent Utility Practices are not intended to
be limited to the optimum practice or method to the exclusion of other practices or methods, but
rather to be a spectrum of possible but reasonable practices and methods.
"PUCN"means the Public Utilities Commission of Nevada.
"PUCN Approval" means that the PUCN has issued an order on terms that are
acceptable to the NVE Parties in their sole discretion approving(a) in the case of the initial PUCN
approval, this Agreement and all transactions and payments contemplated herein and (b) in the
case of any PUCN approval associated with any subsequent Transfer to or by the NVE Parties (or
any one of them individually) of Ownership Interests pursuant to the terms of this Agreement, the
acquisition of, and purchase price paid for, such Ownership Interests and the NVE Parties', as
applicable, additional investment in ON Line.
"Receiving Party"has the meaning set forth in Section 20.08(a).
"Reconciliation Statement"has the meaning set forth in Section 2.02(d).
"Representative"has the meaning set forth in Section 8.01(a).
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Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, [PC
Page 35 of 198

"Required Consents" means any consents required to assign to NPC an interest in
any ON Line Agreement, as contemplated hereby, which are set forth in the Disclosure Schedules.
"Robinson Summit Location" means the location for the construction of the
Robinson Summit Substation, which is generally described as Section 12, Township 17 North,
Range 60 East, MDB&M, White Pine County, Nevada, and more specifically described in BLM
right-of-way grant N-89507.
"Robinson Summit Substation" means the substation located near Ely in White
Pine County, Nevada, which was originally constructed as part of ON Line and will be upgraded
as part of the Great Basin Segments, as further described in Schedule 1.
"ROFO Offer Deadline"has the meaning set forth in Section 15.02(b)(ii).
"ROFO Offer Notice"has the meaning set forth in Section 15.02(b)(i).
"ROFO Offered Interest"has the meaning set forth in Section 15.02(b)(i).
"ROFO Return Notice"has the meaning set forth in Section 15.02(b)(ii).
"ROFR Offer Deadline" has the meaning set forth in Section 15.02(a)(i).
"ROFR Offer Notice"has the meaning set forth in Section 15.02(a)(i).
"ROFR Offered Interest"has the meaning set forth in Section 15.02(a)(i).
"ROFR Return Notice"has the meaning set forth in Section 15.02(a)(ii).
"Rules"has the meaning set forth in Section 19.02(b)(i).
"SEC"means the United States Securities and Exchange Commission.
"Security Documents"has the meaning set forth in Section 18.04(f).
"Shared Liability'has the meaning set forth in Section 12.02.
"SNIP"has the meaning set forth in the recitals to this Agreement.
"SNIP Agreement"has the meaning set forth in Section 6.05(b (iv)w.
"SNIP Option"has the meaning set forth in Section 6.05(a).
"SNIP Option Closing" means the Transfer by NPC and the purchase by Great
Basin of the Applicable Centennial Phase 3 Rights.
"SNIP Option Closing Date"means the date upon which the SNIP Option Closing
occurs.
30
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 36 of 198

"SNIP Option Right Transfer"has the meaning set forth in Section 6.05(d).
"SPPC"has the meaning set forth in the preface to this Agreement.
"SPPC Purchase Price"has the meaning set forth in Section 2.01(b).
"Step-In Party"means either Great Basin or NPC,whichever is stepping-in to take
over the responsibilities of the non-performing Party at the applicable time.
"Substation Construction Contract"means the agreement among NPC, Great Basin
and the Substation Construction Contractor pursuant to which the Substation Construction
Contractor will perform procurement and construction services for the Robinson Summit
Substation and pursuant to the Interconnection Agreement for the Robinson Summit Substation.
"Substation Construction Contractor" means the contractor under the Substation
Construction Contract.
"SWIP-N"has the meaning set forth in the recitals to this Agreement.
"SWIP-S"has the meaning set forth in the recitals to this Agreement.
"Taxes"has the meaning set forth in Section 10.01.
"Term"has the meaning set forth in Section 11.01.
"Terminated Capacity"has the meaning set forth in Section 16.02(h).
"Termination Date"has the meaning set forth in Section 11.01.
"Termination Payment" has the meaning set forth in Section 16.02(h).
"Total Costs"means an amount equal to the sum of Net Actual Costs,Net Capital
Repair Costs,Net Event of Loss Costs and Net Condemnation Action Costs.
"Tower Suppliers"means the tower suppliers under the Tower Supply Agreements.
"Tower Supply Agreements"means the agreements among NPC, Great Basin and
the Tower Suppliers pursuant to which the Tower Suppliers will supply the towers for ON Line.
"Transfer" means to offer, sell, transfer, assign or dispose of(by operation of law
or otherwise), or make any exchange, gift, assignment or pledge of, or grant any Lien on, all or
any part of (a) with respect to a Party, such Party's Ownership Interests or the Applicable
Centennial Phase 3 Rights or any of such Party's rights or obligations under this Agreement or any
ON Line Agreement and(b)with respect to Great Basin, Great Basin's ownership interests in the
Great Basin Segments; provided, however, that a Transfer shall not include any transaction
contemplated by Section 15.01(c).
"Transfer Taxes"has the meaning set forth in Section 10.05.
31
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 37 of 198

"Transferring Party"means a Party making or contemplating making a Transfer in
accordance with this Agreement.
"Transmission Improvement"has the meaning set forth in Section 6.01.
"Transmission Line"means ON Line and the Great Basin Segments, collectively.
"Transmission Line Construction Contract" means the agreement among NPC,
Great Basin and the Transmission Line Construction Contractor pursuant to which the
Transmission Line Construction Contractor will provide all procurement and construction services
for ON Line (except to the extent that such services will be provided by the Substation
Construction Contractor, the Tower Suppliers or the Other Suppliers).
"Transmission Line Construction Contractor"means the contractor under the
Transmission Line Construction Contract.
"Transmission Losses"has the meaning set forth in Section 7.06.
"TUA Assigm-nent"has the meaning set forth in the recitals to this Agreement.
"Uniform System of Accounts" means the uniform system of accounts as adopted
by FERC for electric utilities.
"Unpaid Contribution"has the meaning set forth in Section 5.07(a).
"Up-Front GBT Costs" means third-Person costs, expenses and fees for lawyers,
other consultants, financing parties and agents reasonably incurred by Great Basin in connection
with closing the ON Line Financing that are actual, verifiable costs paid to unaffiliated, third-
Persons in respect of the ON Line Financing (in each case, other than any costs (i) included in
Development Costs or (ii) incurred prior to January 1, 2010 in excess of one million Dollars
($1,000,000)in the aggregate)plus Great Basin's cost of carrying such costs from the date incurred
through ON Line COD at a rate equal to eight and eight hundredths percent (8.08%) per annum,
compounded semi-annually; provided, that such Up-Front GBT Costs shall be no greater than the
lesser of(a) the amount (if any) by which the Anticipated Investment for ON Line is greater than
the Net Actual Costs and (b) seven million Dollars ($7,000,000). For the avoidance of doubt, if
the Net Actual Costs are equal to or greater than the Anticipated Investment for ON Line,then Up-
Front GBT Costs shall equal zero.
"WECC"means Western Electricity Coordinating Council.
"Willful Misconduct/Gross Negligence"means any action taken or not taken by the
Managing Party, either NVE Party or Great Basin in its performance or non-performance of its
obligation as the Managing Party, as the Operator of the Transmission Line or maintainer of ON
Line or in connection with its obligations under Sections 13.04 and 14.04 and as maintainer of the
Great Basin Segments, respectively, under this Agreement or any ON Line Agreement, which
action:
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Second Amended and Restated Transmission Use and Capacity Exchange Agreement
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Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 38 of 198

(a) (i) is knowingly or intentionally taken or not taken with conscious
indifference to the consequences thereof or with intent that injury or damage would result or would
probably result therefrom or(ii) constitutes gross negligence; and
(b) has been determined by final arbitration award or final judgment or
judicial decree to be a default under this Agreement or any ON Line Agreement and which action
occurs or continues beyond the time specified in such arbitration award or judgment or judicial
decree for curing such default.
For the avoidance of doubt, the phrase "Willful Misconduct/Gross Negligence"
does not include any act or failure to act which is merely involuntary, accidental or negligent or
which is caused by Force Majeure.
"Wind-Up Events"has the meaning set forth in Section 11.02(b).
"Wind-Up Reserve Account"has the meaning set forth in Section 11.02(c).
"Withdrawing Party"has the meaning set forth in Section 13.05(a).
"Work Product"means all the plans, drawings, designs, data, information, studies,
analyses, work product and reports (in any form) developed by any Party or its Affiliates in
connection with ON Line and developed under any ON Line Agreement (subject to the terms
thereof), other than studies, reports, analyses, models, internal projections and other similar
documentation licensed to Great Basin pursuant to the IP License Agreement or that is solely for
a Party's internal analysis, reporting or management purposes or that is prepared in connection
with the role of the NVE Parties as transmission providers or as generation owners.
1.02 Interpretations. In this Agreement, unless a clearly contrary intention
appears (a) the singular number includes the plural number and vice versa; (b) reference to any
Person includes such Person's successors and assigns but, if applicable, only if such successors
and assigns are permitted by this Agreement, and reference to a Person in a particular capacity
excludes such Person in any other capacity; (c)reference to any gender includes each other gender;
(d) reference to any agreement (including this Agreement), document or instrument means such
agreement, document or instrument as amended or modified and in effect from time to time in
accordance with the terms thereof and, if applicable,the terms hereof; (e)reference to any Article,
Section, Schedule, Annex or Exhibit means such Article, Section, Schedule, Annex or Exhibit to
this Agreement and references in any Article, Section, Schedule, Annex, Exhibit or definition to
any clause means such clause of such Article, Section, Schedule, Annex, Exhibit or definition; (f)
"hereunder", "hereof', "hereto", "herein", "herefrom" and words of similar import are reference
to this Agreement as a whole and not to any particular Article, Section, Schedule,Annex or Exhibit
or other provision hereof; (g) relative to the determination of any period of time, "from" means
"from and including," "to" means "to but excluding" and "through" means "through and
including"; (h) "including" (and with correlative meaning "include") means including without
limiting the generality of any description preceding such term; (i)reference to any Applicable Law
means such Applicable Law as amended, modified, codified or reenacted, in whole or in part, and
in effect from time to time, and includes any rules and regulations promulgated thereunder; and 0)
Total Costs, Net Actual Costs, Net Capital Repair Costs, Net Event of Loss Costs and Net
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Condemnation Action Costs, as applicable, paid or funded by a Party shall mean such costs as
reduced by Cost Reductions received by such Party(but without duplication,in the event any such
Cost Reductions have already been taken into account by virtue of the definition thereof or any of
the subcomponents thereof) and after giving effect to the Closing Payments and any related
adjustment received pursuant to Section 2.02(d).
ARTICLE II
ACQUISITION OF ON LINE
2.01 Acquisition; Purchase Price.
(a) On the Acquisition Closing Date and on the terms and subject to the
conditions set forth in this Agreement, NPC shall purchase from Great Basin, and Great Basin
shall sell to NPC, an Ownership Interest in the amount of NPC's Ownership Percentage and SPPC
shall purchase from Great Basin, and Great Basin shall sell to SPPC, an Ownership Interest in the
amount of SPPC's Ownership Percentage, in each case free and clear of all Liens (other than
Permitted Liens).
(b) The purchase price of the Ownership Interest acquired at Acquisition
Closing by (i) NPC shall be equal to the aggregate of all costs set forth on the Cost Detail
Statements (as adjusted by the Cost Detail Reconciliation Statements) of the Parties multiplied by
NPC's Ownership Percentage (the "NPC Purchase Price") and (ii) SPPC shall be equal to the
aggregate of all costs set forth on the Cost Detail Statements (as adjusted by the Cost Detail
Reconciliation Statements)of the Parties multiplied by SPPC's Ownership Percentage(the"SPPC
Purchase Price").
2.02 Closing Payments; Closing Payment Adjustments.
(a) Cost Detail Statements. No less than twenty (20) Business Days
before the anticipated Acquisition Closing Date, each Party shall deliver to the other Parties a
detailed statement (each, a "Cost Detail Statement") setting forth all of such Party's (i)
Development Costs, (ii)Pre-Closing Costs incurred prior to the date of such Cost Detail Statement
(which shall be no more than five (5) days prior to the date of delivery), (iii) good faith estimate
of the Pre-Closing Costs that will be incurred by such Party from the date of such Cost Detail
Statement through the Acquisition Closing Date and (iv) Carrying Costs associated with all such
Development Costs and Pre-Closing Costs through the Acquisition Closing Date; provided,
however, that the aggregate amount of such costs set forth on the Cost Detail Statement shall be
reduced by the amount of any Cost Reductions received (or expected to be received) by a Party
prior to Acquisition Closing. Each Party shall promptly provide the other Parties with access to,
and copies of, all reasonably requested documentation in support of such Party's Cost Detail
Statement. The Parties shall work in good faith to promptly resolve any Dispute concerning any
Cost Detail Statement, and shall revise any disputed Cost Detail Statement to account for the
resolution of the applicable Dispute.
(b) Closing Statement. No less than the later of(i)five(5)Business Days
before the anticipated Acquisition Closing Date and (ii) ten (10) Business Days after receipt of
Great Basin's Cost Detail Statement and resolution of any timely made Disputes regarding any
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Cost Detail Statement, NPC shall deliver a statement (the "Closing Statement") to the Parties
setting forth the aggregate of all costs and Cost Reductions set forth on the Cost Detail Statements
of the Parties and each payment (each, a"Closing Payment") to be made by a Party(if any) such
that, after the making of each such payment, each Party will have borne an amount equal to the
aggregate of all costs set forth on the Cost Detail Statements of the Parties (after accounting for
the effect of any Cost Reductions) multiplied by such Party's Ownership Percentage.
(c) Closing Payments. At the Acquisition Closing, and in consideration
for consummating the Acquisition Closing, each Party shall make any Closing Payment required
by it on the Closing Statement (if any) to the Parties required by the Closing Statement.
(d) Reconciliation. No more than fifteen (15) Business Days following
the Acquisition Closing Date, each Party shall deliver to the other Parties a detailed statement of
the Pre-Closing Costs,Carrying Costs associated with such Pre-Closing Costs and Cost Reductions
that it incurred or received from the date of such Party's Cost Detail Statement through the
Acquisition Closing Date (each, a "Cost Detail Reconciliation Statement"). Each Party shall
promptly provide the other Parties with access to, and copies of, all reasonably requested
documentation in support of such Party's Cost Detail Reconciliation Statement. No more than
fifteen(15) Business Days after the receipt of the last Cost Detail Reconciliation Statement,NPC
shall deliver a statement (the "Reconciliation Statement") to the Parties setting forth the amount
that any Party owes to any other Party so that each Party will have borne an amount equal to the
aggregate of all costs set forth on the Cost Detail Statements (after accounting for the effect of any
Cost Reductions) of the Parties(adjusted by the difference in the amounts set forth in each Party's
Cost Detail Reconciliation Statement and the corresponding amount set forth in such Party's Cost
Detail Statement) multiplied by such Party's Ownership Percentage. The Parties shall work in
good faith to promptly resolve any Dispute concerning any Cost Detail Reconciliation Statement
or the Reconciliation Statement. All portions of the Reconciliation Statement(other than portions
being disputed by a Party in good faith) shall be paid within twenty(20) Business Days following
receipt of the Reconciliation Statement. Any disputed portion of the Reconciliation Statement that
is later resolved shall be paid within five (5) Business Days after the resolution of such Dispute or
within twenty (20) Business Days following receipt of the Reconciliation Statement, whichever
occurs later.
(e) Audit Rights. Each Party shall keep reasonably detailed records of its
Pre-Closing Costs, the Carrying Costs associated with the Development Costs and Pre-Closing
Costs and any Cost Reductions and shall provide such records to the other Parties upon request.
All such costs and reductions giving rise to any amounts paid under this Section 2.02 shall be
subject to audit by internal auditors or an independent third-Person expert payable by the
requesting Party at reasonable times and upon reasonable prior written notice to the other Parties
at any time prior to the eighth (8th) anniversary of ON Line COD; provided, however, that if the
amount owed by the audited Party exceeds one hundred thousand Dollars ($100,000), the audited
Party shall pay all reasonable audit costs. If a Dispute arises in connection with any audit
conducted pursuant to this Section 2.02(e) and such Dispute remains outstanding for thirty (30)
days following the conclusion of such audit, such Dispute may be referred to Ernst&Young LLP,
or, if Ernst & Young LLP is unable or unwilling to act or is providing services to a Party and/or
its Affiliates at such time or during the three(3)years immediately preceding such time, such other
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independent auditing firm agreeable by all Parties (in either case, the "Independent Auditor") by
any Party and the Party requesting the Independent Auditor shall bear the costs of the Independent
Auditor; provided, however, that if the amount owed by the audited Party exceeds one hundred
thousand Dollars($100,000),the audited Party shall pay all costs of the Independent Auditor. The
Parties shall reasonably cooperate with the Independent Auditor, and their agreement to submit
Disputes under this Section 2.02(e)to an Independent Auditor shall be enforceable as an agreement
to arbitrate. The decision of the Independent Auditor shall be final, binding and conclusive upon
the Parties, shall not be subject to challenge or appeal, and may be enforced in any court having
jurisdiction in the same manner as an arbitral award. If it is determined at any time pursuant to
such audit or Independent Auditor that an amount previously paid by a Party under this Section
2.02 did not constitute a due and payable item, such Party may recover such amount plus interest
at the Agreed Rate from any other Party that received such payment or deduct, or cause to be
deducted, such amount from any payment that may be due to such receiving Party, and the Parties
shall revise the Cost Detail Statements and the Cost Detail Reconciliation Statements to account
for the overpayment. Each Party acknowledges and agrees that the making of any payment under
this Section 2.02 shall be without prejudice to the audit rights of each Party under this Section
2.02(e).
2.03 Conditions Precedent to Acquisition Closing. At Acquisition Closing,
Great Basin's obligation to sell Ownership Interests to the NVE Parties, and the NVE Parties'
obligation to purchase such Ownership Interests from Great Basin, are each subject to satisfaction
of the following conditions, except to the extent waived in writing by the NVE Parties with respect
to the conditions set forth in Sections 2.03(a)-(n) and by Great Basin with respect to the conditions
set forth in Sections 2.03(a)-(g), (i)-(k) and m - n :
(a) The initial PUCN Approval has been duly obtained, made or given
and shall be in full force and effect.
(b) ON Line Financial Closing has occurred or shall occur
simultaneously with the Acquisition Closing.
(c) The FERC Approval has been duly obtained,made or given and shall
be in full force and effect.
(d) Each other Party shall have paid or executed and delivered, or caused
to be executed and delivered to the other Parties, as applicable,the items set forth in Section 2.04.
(e) Each of the representations and warranties made by each other Party
in this Agreement shall be true and correct in all material respects on and as of the Acquisition
Closing Date as though made on and as of the Acquisition Closing Date or, in the case of
representations and warranties expressly made as of a specified date,on and as of such date,except
to the extent that such representations and warranties contain a materiality qualifier, in which case
they shall be true and correct in all respects.
(f) Each other Party shall have performed and complied in all material
respects with the agreements, covenants and obligations required by this Agreement to be so
performed or complied with by it at or before the Acquisition Closing.
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(g) (i) Each agreement listed in Schedule 4 has been executed and
delivered and is in full force and effect, (ii) Great Basin has obtained all non-ministerial
Governmental Approvals required for the construction and operation of ON Line (other than
Governmental Approvals customarily obtained at a later point in time in light of the then current
stage of construction of ON Line and related to the construction of the Robinson Summit
Substation at the Robinson Summit Location) and such Governmental Approvals are in full force
and effect and shall not be subject to any pending or threatened challenge and (iii) full notice to
proceed has been issued under each Material Construction Contract.
(h) (i)The ON Line Security Interest has been granted to the NVE Parties
and is valid, legal, perfected, in full force and effect and has the priority contemplated by Section
18.04, each Security Document for the ON Line Security Interest has been (A)properly executed
and delivered by Great Basin and(B)duly filed,registered and recorded and Uniform Commercial
Code financing statements have been duly filed, in each case, in each jurisdiction as required by
Applicable Law or as reasonably requested by the NVE Parties in order to grant and maintain a
valid, legal and perfected Lien that has the priority contemplated by Section 18.04, contemplated
hereby in respect of the ON Line Security Interest, and each such Security Document is in full
force and effect and (ii) legal opinions addressing the matters set forth on Exhibit I and in form
and substance reasonably acceptable to the NVE Parties have been delivered to the NVE Parties
regarding the ON Line Security Interest and the associated Security Documents.
(i) A Non-Disturbance Agreement has been executed and delivered by
each ON Line Lender and the NVE Parties.
0) The ON Line Intercreditor Agreement has been executed and
delivered by the NVE Parties, Great Basin and each ON Line Lender(or an agent thereof).
(k) The Interconnection Agreements have been executed and delivered
by the Parties (in their capacities as owners of ON Line), NPC (in its capacity as the
interconnection provider)and SPPC(in its capacity as the interconnection provider), as applicable.
(1) Great Basin has delivered to the NVE Parties fully executed releases
for any Liens on the Ownership Interests being transferred to NPC and SPPC that are not Permitted
Liens, in a form reasonably acceptable to the NVE Parties.
(m) The Parties have executed an amendment to this Agreement to
incorporate a form of consent to collateral assignment to be in favor of ON Line Lenders, GB
Segment Lenders and NVE Lenders (if required) and a form of SNIP Agreement.
(n) The Parties have agreed on a revised ON Line Budget reflecting all
anticipated ON Line Costs necessary to achieve ON Line COD.
2.04 Acquisition Closing Deliverables. On the Acquisition Closing Date, the
Parties shall take the following actions:
(a) Each Party shall pay the Closing Payments required by Section
2.02(c).
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(b) The Parties shall execute and deliver a bill of sale and assignment and
assumption agreement for NPC's undivided ownership interest in ON Line in the amount of NPC's
Ownership Percentage and SPPC's undivided ownership interest in ON Line in the amount of
SPPC's Ownership Percentage, in each case substantially in the form of Exhibit E.
(c) Great Basin shall deliver to NPC the Required Consents substantially
in the form of Exhibit F or such other form as is reasonably acceptable to NPC.
(d) Great Basin shall cause the entity for which Great Basin is treated as
a disregarded entity separate from its owner pursuant to Treasury Regulations Section 301.7701-
3 to execute and deliver to each of the NVE Parties a certificate under Section 1445(b)(2) of the
Code, in form and substance reasonably satisfactory to the NVE Parties,providing that such entity
is not a foreign Person.
(e) Great Basin shall execute and deliver to the NVE Parties (i)a State of
Nevada Declaration of Value in the form required by Nevada Revised Statutes Section 375.060,
(ii) a grant, bargain and sale deed substantially in the form of Exhibit G, (iii) any other
documentation necessary or appropriate to convey and record title to the ON Line ROW and any
other real property comprising ON Line to the extent that Great Basin holds record title to interests
in the ON Line ROW or any such other real property and (iv) any documentation necessary or
appropriate to record any other real property interests in the ON Line ROW.
2.05 Timing and Location of Acquisition Closing. The Acquisition Closing shall
take place on a date within ten(10)Business Days after satisfaction or waiver of the conditions set
forth in Section 2.03. The Acquisition Closing shall take place at NPC's offices in Las Vegas,
Nevada at a time mutually acceptable to the Parties. The Acquisition Closing shall be deemed
effective as of 12:01 A.M. Las Vegas time on the day after the Acquisition Closing Date.
2.06 Efforts to Close. Between the Effective Date and the Acquisition Closing,
each Party shall use its reasonable efforts to take all actions and to do all things necessary,proper
or advisable to satisfy the conditions set forth in Section 2.03 and consummate the Acquisition
Closing. Each Party shall promptly notify the other Parties of any event arising after the Effective
Date that could reasonably be expected to result in the Acquisition Closing occurring after
December 31, 2010 (the "Acquisition Closing Deadline").
2.07 Disclosure Schedule Update. From time to time prior to the Acquisition
Closing Date, any Party, as applicable, may amend or supplement the Disclosure Schedules
attached to this Agreement relating to any representation or warranty contained in Article XVII,
with respect to any fact, event or circumstance occurring after the Effective Date that, if existing
or occurring at or prior to the Acquisition Closing Date, would have been required to be set forth
or described on such a Disclosure Schedule or that is necessary to complete or correct any
information in any representation or warranty contained in Article XVII (a "Disclosure Schedule
Update"); provided, that (a) the facts, events or circumstances disclosed in such amendment or
supplement could not reasonably be expected to have a Material Adverse Effect and (b) if such
facts, events or circumstances result from a breach of this Agreement by the amending or
supplementing Party or its negligence,willful misconduct or fraud, such Party shall indemnify the
other Parties and their respective Indemnified Persons for all Claims in connection with such facts,
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Second Amended and Restated Transmission Use and Capacity Exchange Agreement
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events or circumstances. The Parties acknowledge that no such indemnification obligation shall
be deemed waived by the consummation of the Acquisition Closing. Each Disclosure Schedule
Update delivered to the Parties shall be deemed to modify the representations and warranties herein
for all purposes hereunder (except for purposes described in clause (b) above), and as modified
and updated shall constitute the applicable Disclosure Schedule for purposes of Article XVII.
2.08 Allocation of Purchase Price. Within sixty (60) days after the Acquisition
Closing Date,NPC shall deliver to Great Basin for its review and approval a draft allocation of the
NPC Purchase Price and SPPC Purchase Price(and all other capitalized costs)among the ON Line
assets(based on the final Cost Detail Statement and the Cost Detail Reconciliation Statement)and
in accordance with section 1060 of the Code(and treasury regulations thereunder) and any similar
provisions of Applicable Law. Within twenty(20) Business Days after its receipt of NPC's draft
allocation of the NPC Purchase Price and SPPC Purchase Price, Great Basin shall propose to NPC
any changes thereto or otherwise NPC's draft allocation shall be deemed to have agreed thereto.
If Great Basin proposes changes to NPC's proposed allocation of the NPC Purchase Price or SPPC
Purchase Price within such twenty (20) Business Day period described above, NPC and Great
Basin shall cooperate in good faith to mutually agree upon a revised allocation as soon as
practicable (such allocation of the NPC Purchase Price and the SPPC Purchase Price, as finally
agreed to by the Parties, the "Allocation"). If the Parties cannot agree upon the legal basis on
which NPC has made the Allocation within sixty(60)days after delivery of such proposed changes
(if any), NPC shall secure a legal opinion of a nationally recognized tax counsel that the basis on
which NPC made such proposed Allocation is more likely than not correct. If NPC secures such
opinion, then the Allocation shall be made on the legal basis proposed by NPC, and Great Basin
shall pay all reasonable costs associated with such legal opinion. If NPC fails to secure such
opinion, then NPC shall be responsible for the costs of such opinion, and Great Basin shall then
secure a legal opinion of a nationally recognized tax counsel that the basis on which Great Basin
made such proposed Allocation is more likely than not correct. If Great Basin secures such
opinion, then the Allocation shall be made on the legal basis proposed by Great Basin, and NPC
shall pay all reasonable costs associated with such legal opinion. If Great Basin fails to secure
such opinion, then Great Basin shall be responsible for the costs of such opinion, and then the
Parties shall work together to secure a tax opinion that supports a proposed Allocation. If the
Parties cannot agree upon the valuations in the Allocation within thirty(30) days after delivery of
such proposed changes (if any), the Parties shall mutually select the Independent Auditor or
another external auditor or appraiser, as determined based on the nature of the valuation dispute,
which shall be instructed to resolve such disagreement within thirty (30) days after such
disagreement is submitted to it for resolution and shall notify Great Basin and NPC in writing of
its resolution. Such auditor's or appraiser's resolution of the disagreement shall be final and
binding on the Parties. Each Party shall, and each Party shall cause their Affiliates to, report, act,
and file all Tax returns, forms or reports in all respects and for all purposes consistent with the
Allocation. No Party shall take any position (whether in audit, Tax returns, or otherwise or with
any Governmental Authority) that is inconsistent with the Allocation except as may be adjusted
by subsequent written agreement following an audit by the Internal Revenue Service or by court
decision.
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Second Amended and Restated Transmission Use and Capacity Exchange Agreement
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Case No. IPC-E-25-08
J. Ellsworth, IPC
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ARTICLE III
OWNERSHIP AND CAPACITY RIGHTS; MONTHLY PAYMENT
3.01 Ownership Rights.
(a) ON Line Ownership; Waiver of Partition Rights. After the
Acquisition Closing Date, the Parties shall own ON Line as tenants-in-common with each Party
owning an Ownership Interest in the amount of its Ownership Percentage. The Parties recognize
that the physical partition of ON Line or any part thereof, whether by partition in kind or sale and
division of the proceeds thereof,would be impossible and impractical and wholly inconsistent with
the purposes for which this Agreement is made. As such, each Party agrees that it shall not take
any action at any time by judicial proceedings, arbitration or otherwise, to partition ON Line or
any part thereof, in any way, whether by partition in kind or by sale and division of the proceeds
thereof. Each Party further irrevocably waives the right of partition and the benefit of all statutory
or common law that may now or hereafter authorize such partition of ON Line or any part thereof.
In the event any such right of partition shall hereafter accrue, each Party shall from time to time
upon the written request of any other Party execute and deliver such further instruments as may be
necessary to confirm the foregoing waiver and release of its right to partition. The Parties shall
amend this Agreement to update Annex A upon any change in Ownership Percentages pursuant to
the terms hereof such that, at any time, Annex A accurately reflects each Party's Ownership
Percentage.
(b) After-Acquired ON Line Property and Rights. Unless otherwise
determined by the Parties, any Party which acquires in its own name, or an Affiliate's name, an
interest in any real or personal property (whether tangible or intangible), contractual right or any
other asset that is part of ON Line shall acquire and hold the same subject in all respects to this
Agreement and for the benefit of the Parties in proportion to their respective Ownership
Percentages, and subject to Section 3.01(c), any such Party shall transfer and assign an ownership
interest therein to the other Parties equal to such other Parties' respective Ownership Percentages
(a) within fifteen (15) days after such acquisition and (b) at the Acquisition Closing, whichever
occurs later, and do all things necessary or appropriate to register or record on any appropriate
register the property in the names of the Parties.
(c) ON Line Agreements and Governmental Approvals. Except as
otherwise agreed by the Management Committee, all ON Line Agreements entered into after the
Acquisition Closing Date shall be in the name of Great Basin and NPC and Governmental
Approvals for ON Line applied for after the Acquisition Closing Date shall be in the name of the
Parties and the Parties shall use their commercially reasonable efforts to ensure that all ON Line
Agreements shall allow for assignment,without consent,to Persons holding an Ownership Interest.
Unless otherwise agreed by the Parties, each ON Line Agreement shall expressly provide that,
after the Acquisition Closing Date, the obligations and undertakings of the Parties thereunder are
several and not joint and that each Party is and shall be liable and responsible only for its
Ownership Percentage of such obligations and undertakings;provided,however,that,with respect
to any ON Line Agreement to which SPPC is not a party and, as between NPC and SPPC, NPC
shall be liable to any counterparty (other than Great Basin) under any such ON Line Agreement
for SPPC's Ownership Percentage of obligations and undertakings under any such ON Line
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Second Amended and Restated Transmission Use and Capacity Exchange Agreement
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Case No. IPC-E-25-08
J. Ellsworth, [PC
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Agreement,and NPC shall provide SPPC with the benefit of twenty-five percent(25%)of its rights
under any such ON Line Agreement and SPPC shall promptly reimburse NPC for twenty-five
percent(25%) of any liability or obligation incurred by NPC under any such ON Line Agreement.
If required by a counterparty (other than a Party) under an ON Line Agreement, the Parties shall
use commercially reasonable efforts to provide credit support in a form acceptable to such
counterparty, such that the Parties' obligations under such ON Line Agreement are several and not
joint.
(d) Great Basin Segment Ownership. Great Basin shall (i) own one
hundred percent (100%) of the ownership interests in the Great Basin Segments and(ii)be solely
responsible for the development, construction, ownership, management and maintenance of the
Great Basin Segments and all costs and liabilities related to development,construction, ownership,
management, operation and maintenance of the Great Basin Segments, including all Great Basin
O&M Costs and the costs of any Transmission Improvements as provided in Section 6.01;
provided, however, that, while the Parties, as of the Effective Date, expect that the Great Basin
Segments will be fully developed and constructed,nothing contained in this Agreement(other than
Great Basin's obligation set forth in Section 3.02(b)) shall be construed to obligate Great Basin or
any of its Affiliates to complete the development and/or construction of the Great Basin Segments
(or any portion thereof), such decision being in the sole discretion of Great Basin and its Affiliates.
3.02 Electrical Capacity Rights.
(a) Prior to the commercial operation of either Great Basin Segment.
During the period commencing immediately after the Acquisition Closing Date to the date of
commercial operation of the first Great Basin Segment to achieve commercial operation,the NVE
Parties' Capacity Entitlement with respect to ON Line shall be one hundred percent (100%). For
the avoidance of doubt, Great Basin shall not be entitled to any Electrical Capacity with respect to
ON Line after the Acquisition Closing Date and prior to the date of commercial operation of the
first Great Basin Segment to achieve commercial operation.
(b) Following commercial operation of first Great Basin Segment.
Subject to Section 3.02(c), from and after the date of commercial operation of the first Great Basin
Segment to achieve commercial operation, the Parties shall be entitled to Electrical Capacity as
follows:
(i) ON Line Capacity Entitlement.
(1) The NVE Parties' Capacity Entitlement shall be an amount
equal to the first 900 MW of the Electrical Capacity for ON Line,
(2)(A) if SNIP is the first Great Basin Segment to achieve
commercial operation, then, to the extent the Electrical Capacity for ON Line is greater than 900
MW, Great Basin's Capacity Entitlement shall be an amount equal to the next 500 MW of the
Electrical Capacity for ON Line, or (B) if SWIP-N is the first Great Basin Segment to achieve
commercial operation, then, to the extent the Electrical Capacity for ON Line is greater than 900
MW, Great Basin's Capacity Entitlement shall be an amount equal to the next the next 800 MW
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Second Amended and Restated Transmission Use and Capacity Exchange Agreement
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of the Electrical Capacity for ON Line, in each case, after giving effect to the Electrical Capacity
for ON Line to which the NVE Parties are entitled pursuant to Section 3.02(b)(i)(1) above,
(3)(A) if SNIP is the first Great Basin Segment to achieve
commercial operation,then,to the extent the Electrical Capacity for ON Line is in excess of 1,400
MW, the NVE Parties' Capacity Entitlement shall be an amount equal to eighty percent (80%) of
any such excess Electrical Capacity and Great Basin's Capacity Entitlement shall be an amount
equal to twenty percent(20%)of any such excess Electrical Capacity,up to 2,190 MW of Electrical
Capacity for ON Line, or (B) if SWIP-N is the first Great Basin Segment to achieve commercial
operation, then, to the extent the Electrical Capacity for ON Line is in excess of 1,700 MW, the
NVE Parties' Capacity Entitlement shall be an amount equal to fifty percent (50%) of any such
excess Electrical Capacity and Great Basin's Capacity Entitlement shall be an amount equal to
fifty percent(50%) of any such excess Electrical Capacity,up to 2,190 MW of Electrical Capacity
for ON Line, and
(4)(A) if SNIP is the first Great Basin Segment to achieve
commercial operation,then,to the extent the Electrical Capacity for ON Line is in excess of 2,190
MW, the NVE Parties' Capacity Entitlement shall be an amount equal to eighty percent (80%) of
any such excess Electrical Capacity and Great Basin's Capacity Entitlement shall be an amount
equal to twenty percent(20%)of any such excess Electrical Capacity, or(B)if SWIP-N is the first
Great Basin Segment to achieve commercial operation, then, to the extent the Electrical Capacity
for ON Line is in excess of 2,190 MW,the NVE Parties' Capacity Entitlement shall be an amount
equal to fifty percent (50%) of any such excess Electrical Capacity and Great Basin's Capacity
Entitlement shall be an amount equal to fifty percent(50%)of any such excess Electrical Capacity;
provided, however, that, to the extent that the NVE Parties reasonably demonstrate that the
installation of the Harry Allen Transformers has created an incremental increase in the Electrical
Capacity of ON Line in excess of 2,190 MW, the NVE Parties' Capacity Entitlement shall be an
amount equal to one hundred percent(100%) of any such excess Electrical Capacity.
(ii) SWIP-N Capacity Entitlement. If SWIP-N is the first Great
Basin Segment to achieve commercial operation, (1) Great Basin's Capacity Entitlement shall be
an amount equal to the first 900 MW of the Electrical Capacity for SWIP-N, (2) to the extent the
Electrical Capacity for SWIP-N is greater than 900 MW, the NVE Parties' Capacity Entitlement
shall be an amount equal to the next 700 MW of the Electrical Capacity for SWIP-N, after giving
effect to the Electrical Capacity for SWIP-N to which Great Basin is entitled pursuant to Section
3.02(b)(ii)(1) above, (3) to the extent the Electrical Capacity for SWIP-N is in excess of 1,600
MW, Great Basin shall be entitled to one hundred percent (100%) of any such excess Electrical
Capacity up to the total amount of Great Basin's Capacity Entitlement of the Electrical Capacity
for ON Line pursuant to Section 3.02(b)(i), and (4) to the extent there is any excess Electrical
Capacity for SWIP-N after giving effect to Sections 3.02(b)(ii)(1), Q and M above, the NVE
Parties shall be entitled to one hundred percent(100%) of any such excess Electrical Capacity.
(iii) SNIP Capacity Entitlement. If SNIP is the first Great Basin
Segment to achieve commercial operation, (1)the NVE Parties' Capacity Entitlement shall be an
amount equal to the first 900 MW of the Electrical Capacity for SNIP, (2) to the extent the
Electrical Capacity for SNIP is greater than 900 MW, Great Basin's Capacity Entitlement shall be
42
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 48 of 198

an amount equal to the next 500 MW of the Electrical Capacity for SNIP, after giving effect to the
Electrical Capacity for SNIP to which the NVE Parties are entitled pursuant to Section
3.02(b)(iii)(1) above, and (3) to the extent the Electrical Capacity for SNIP is in excess of 1,400
MW, the NVE Parties' Capacity Entitlement shall be an amount equal to eighty percent (80%) of
any such excess Electrical Capacity, and Great Basin's Capacity Entitlement shall be an amount
equal to twenty percent(20%) of any such excess Electrical Capacity.
(c) Following commercial operation of second Great Basin Segment. If
HAE COD does not occur on or prior to the HAE COD Outside Date,then, from and after the date
of commercial operation of the second Great Basin Segment to achieve commercial operation, the
Parties shall be entitled to Electrical Capacity as follows (which Capacity Entitlements shall be in
lieu of the Capacity Entitlements set forth in Section 3.02(b) above):
(i) ON Line Capacity Entitlement. (1) The NVE Parties'
Capacity Entitlement shall be an amount equal to the first 950 MW of the Electrical Capacity for
ON Line, (2) to the extent the Electrical Capacity for ON Line is greater than 950 MW, Great
Basin's Capacity Entitlement shall be an amount equal to the next 1,240 MW of the Electrical
Capacity for ON Line, after giving effect to the Electrical Capacity for ON Line to which the NVE
Parties are entitled pursuant to Section 3.02(c)(i)(1) above, and (3) to the extent the Electrical
Capacity for ON Line is in excess of 2,190 MW, the NVE Parties' Capacity Entitlement shall be
an amount equal to fifty percent (50%) of any such excess Electrical Capacity and Great Basin's
Capacity Entitlement shall be an amount equal to fifty percent(50%)of any such excess Electrical
Capacity; provided, however, that to the extent that the NVE Parties reasonably demonstrate that
the installation of the Harry Allen Transformers has created an incremental increase in the
Electrical Capacity of ON Line in excess of 2,190 MW, the NVE Parties' Capacity Entitlement
shall be an amount equal to one hundred percent(100%) of any such excess Electrical Capacity.
(ii) SWIP-N Capacity Entitlement. (1) Great Basin's Capacity
Entitlement shall be an amount equal to the first 1,240 MW of the Electrical Capacity for SWIP-
N,(2)to the extent the Electrical Capacity for SWIP-N is greater than 1,240 MW,the NVE Parties'
Capacity Entitlement shall be an amount equal to the next 950 MW of the Electrical Capacity for
SWIP-N, after giving effect to the Electrical Capacity for SWIP-N to which Great Basin is entitled
pursuant to Section 3.02(c)(ii)(1) above, and (3) to the extent the Electrical Capacity for SWIP-N
is in excess of 2,190 MW,the NVE Parties' Capacity Entitlement shall be an amount equal to fifty
percent (50%) of any such excess Electrical Capacity, and Great Basin's Capacity Entitlement
shall be an amount equal to fifty percent (50%) of any such excess Electrical Capacity.
(iii) SNIP Capacity Entitlement. (1) Great Basin's Capacity
Entitlement shall be an amount equal to the first 1,240 MW of the Electrical Capacity for SNIP,
(2) to the extent the Electrical Capacity for SNIP is greater than 1,240 MW, the NVE Parties'
Capacity Entitlement shall be an amount equal to the next 950 MW of the Electrical Capacity for
SNIP, after giving effect to the Electrical Capacity for SNIP to which Great Basin is entitled
pursuant to Section 3.02(c)(iii)(1) above, and (3) to the extent the Electrical Capacity for SNIP is
in excess of 2,190 MW, the NVE Parties' Capacity Entitlement shall be an amount equal to fifty
percent (50%) of any such excess Electrical Capacity, and Great Basin's Capacity Entitlement
shall be an amount equal to fifty percent (50%) of any such excess Electrical Capacity.
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Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, [PC
Page 49 of 198

(d) Unavailability of Transmission Line. Notwithstanding Sections
3.02(b) or O:
(i) Unavailability of a Great Basin Segment following
commercial operation of first Great Basin Se lg Went. If after commercial operation of the first
Great Basin Segment to achieve commercial operation, such Great Basin Segment becomes
unavailable(A) for a period in excess of one hundred twenty(120) consecutive days, due to Force
Majeure, an Event of Loss, Condemnation Action or any change in Applicable Law commencing
after such one hundred twentieth (120th) day, and (B) commencing immediately, due to any
negligent act or omission or any Willful Misconduct/Gross Negligence of or breach of this
Agreement by Great Basin, then from such date to the date the unavailable Great Basin Segment
again becomes available, the NVE Parties' Capacity Entitlement shall be one-hundred percent
(100%) of the Electrical Capacity for ON Line.
(ii) Unavailability of ON Line following commercial operation
of first Great Basin Segment. If after commercial operation of the first Great Basin Segment to
achieve commercial operation, ON Line becomes unavailable (A) for a period in excess of one
hundred twenty (120) consecutive days, due to Force Majeure, an Event of Loss, Condemnation
Action or any change in Applicable Law commencing after such one hundred twentieth (120th)
day, and (B) commencing immediately, due to any negligent act or omission or any Willful
Misconduct/Gross Negligence of or breach of this Agreement by the NVE Parties, in each case,
unless such availability is caused by the withholding by Great Basin (including any of Great
Basin's Authorized Representatives) of any consent to any action proposed by NPC in good faith,
consistent with Prudent Utility Practices and not in violation of any Applicable Law and for which
the NVE Parties are obligated to fund all costs thereof under this Agreement directly or through
an adjustment to the Monthly Payment, then from such date to the date ON Line again becomes
available, Great Basin's Capacity Entitlement with respect to the Great Basin Segment shall be
one hundred percent(100%) of the Electrical Capacity of the Great Basin Segment.
(iii) Unavailability of a Great Basin Segment following
commercial operation of second Great Basin Segment. If(A) HAE COD does not occur on or
prior to the HAE COD Outside Date and(B) after the date of commercial operation of the second
Great Basin Segment to achieve commercial operation SWIP-N or SNIP becomes unavailable (1)
for a period in excess of one hundred twenty (120) consecutive days, due to Force Majeure, an
Event of Loss, Condemnation Action or any change in Applicable Law commencing after such
one hundred twentieth (120th) day, and(2) commencing immediately, due to any negligent act or
omission or any Willful Misconduct/Gross Negligence of or breach of this Agreement by Great
Basin, then from such date to the date the unavailable Great Basin Segment again becomes
available,the Parties respective Capacity Entitlements with respect to ON Line and the Great Basin
Segments shall be as set forth in Section 3.02(c); provided, however, that while both SNIP and
SWIP-N are unavailable, the NVE Parties' Capacity Entitlement shall be one hundred percent
(100%) of the Electrical Capacity for ON Line.
(e) From and After the 41 st Anniversary of the ON Line COD.
Notwithstanding anything to the contrary in Sections 3.02(a) through (dj, in the event the NVE
Parties do not (i) purchase all of Great Basin's Ownership Interests or (ii) renew their Capacity
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Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 50 of 198

Entitlements pursuant to Section 3.09(b), from and after the forty-first (41 st) anniversary of the
ON Line COD, the NVE Parties' Capacity Entitlement with respect to Electrical Capacity on ON
Line shall be equal to the NVE Parties' Ownership Percentage, as adjusted pursuant to the terms
of this Agreement,and the NVE Parties shall not be entitled to any Electrical Capacity on the Great
Basin Segments. In the event the NVE Parties renew their Capacity Entitlements pursuant to
Section 3.09(b), then during the period commencing on the date of such renewal and ending upon
the expiration of such renewal,the Parties shall have the Capacity Entitlements set forth in Sections
3.02 a through(d), subject to Sections 16.02(f),W and(h). Upon expiration of any such renewal,
the NVE Parties' Capacity Entitlement with respect to Electrical Capacity on ON Line shall be
equal to the NVE Parties' Ownership Percentage, and the NVE Parties shall not be entitled to any
Electrical Capacity on the Great Basin Segments.
(f) From and After Exercise of Buyout of Ownership Interests. Subject
to Section 11.03(b), the Parties shall have the Capacity Entitlements set forth in Sections 3.02(a)
through (d) in the event the NVE Parties purchase all of Great Basin's Ownership Interests;
provided, however, if such purchase occurs prior to GB Segment Financial Closing, the NVE
Parties' Capacity Entitlement on ON Line shall be one hundred percent (100%) of the Electrical
Capacity of ON Line and the NVE Parties shall have no Capacity Entitlement on the Great Basin
Segments. In the event Great Basin purchases all of the NVE Parties' Ownership Interests and
unless and until the NVE Parties do not renew their Capacity Entitlements pursuant to Section
3.09 b , the Parties shall have the Capacity Entitlements on the Great Basin Segments set forth in
Sections 3.02(a) through (d), and notwithstanding Sections 3.02(a) through (d), the NVE Parties
shall have a Capacity Entitlement on ON Line equal to its ON Line Capacity Entitlement
immediately prior to such buyout minus its Ownership Percentage immediately prior to such
buyout (and Great Basin's Capacity Entitlement with respect to ON Line shall be all remaining
Electrical Capacity).
(g) For the avoidance of doubt, in consideration for the Parties'
investments and Ownership Interests under this Agreement, which include the interconnection
facilities required at the existing Harry Allen 500 kV Substation,to the extent that the HAE Project
establishes an interconnection point between the balancing authority area of the California
Independent System Operator Corporation(the"CAISO BAA")and the Balancing Authority Area
at the Harry Allen 500 kV Substation (the "HAE Interconnection Point"), then, the Parties'
Capacity Entitlements at the date of commercial operation of SWIP-N shall be deemed to provide
a contract path over ON Line to the HAE Interconnection Point. Except as expressly provided
herein, this Section 3.02(g) is not intended to provide additional rights over buswork at the Harry
Allen 500 kV Substation.
3.03 Microwave and Fiber Optic Capacity Rights. Commencing immediately
after the Acquisition Closing Date, the NVE Parties shall be entitled to one hundred percent
(100%) of the Microwave Capacity and Fiber Optic Capacity on ON Line and Great Basin shall
be entitled to one hundred percent (100%) of the Microwave Capacity and Fiber Optic Capacity
on the Great Basin Segments; provided that (a) Great Basin shall provide the NVE Parties access
to the Microwave Capacity and Fiber Optic Capacity on the Great Basin Segments to the extent
necessary for the NVE Parties to operate the Great Basin Segments and (b) in the event Great
Basin exercises its step-in rights under Section 16.02(e)(iii), the NVE Parties shall provide Great
45
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 51 of 198

Basin access to the Microwave Capacity and Fiber Optic Capacity on ON Line to the extent
necessary for Great Basin to operate the Transmission Line.
3.04 Revenue Rights. The NVE Parties and Great Basin shall be entitled to the
revenue associated with (a) their respective Capacity Entitlements, as provided under the
provisions of each Parties' respective FERC-approved open access transmission tariff and (b) all
of their respective rights to Microwave Capacity and Fiber Optic Capacity as set forth in Section
3.03.
3.05 Relationship of the Parties. Except as otherwise expressly provided herein,
each Party shall bear only its Ownership Percentage of all obligations and liabilities of ON Line
arising after the Acquisition Closing Date. The covenants, obligations and liabilities of the Parties
in connection with this Agreement are several and not joint. Neither the execution nor delivery of
this Agreement,nor the consummation of the transactions contemplated hereunder, shall create or
constitute a partnership,joint venture,trust, limited liability company, corporate or any other form
of business organization or arrangement among the Parties.
3.06 Monthly Payment.
(a) Subject to Sections 3.06(b) and Lc,), commencing in the month in
which the ON Line COD occurs but terminating in the month during which the forty-first (41 st)
anniversary of the ON Line COD occurs (the "Monthly Payment Period"), a monthly amount in
Dollars equal to the following (the "Monthly Payment") shall be due and payable to Great Basin;
provided,however,that the first Monthly Payment and the last Monthly Payment shall be adjusted
on a pro rata basis based on the number of days between ON Line COD and the end of the first
month in the Monthly Payment Period and the beginning of the last month in the Monthly Payment
Period through the forty-first (41 st) anniversary of ON Line COD, respectively:
Monthly Payment = Capitalized Component + On-Going GBT Costs incurred in
such month + Incremental Cost Differential Component + Capital Repair
Component+Event of Loss Component+Condemnation Action Component+any
Operating Costs incurred by Great Basin in accordance with Section 7.01(a)
Where:
Capitalized Component = (Capitalized Costs funded by Great Basin + Up-Front
GBT Costs) * the factor set forth on Schedule 2 corresponding to the period of
which such month is a part;
Incremental Cost Differential Component = (the Incremental Cost Differential
funded by Great Basin/applicable Amortization Period)+interest accruing during
such month on any unamortized portion of the Incremental Cost Differential at a
rate equal to the NVE WACC as of ON Line COD with the return on equity
component discounted by seventy-five (75)basis points;
Capital Repair Component = the aggregate sum of the following calculated in
respect of each Capital Repair: (the applicable Net Capital Repair Cost funded by
46
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 52 of 198

Great Basin / applicable Amortization Period) + interest accruing during such
month on any unamortized portion of such Net Capital Repair Cost at a rate equal
to the NVE WACC as of the time of the relevant Capital Repair Cost was incurred
with the return on equity component discounted by fifty(50)basis points;
Event of Loss Component = the aggregate sum of the following calculated in
respect of each Event of Loss: (the applicable Net Event of Loss Cost funded by
Great Basin / applicable Amortization Period) + interest accruing during such
month on any unamortized portion of such Net Event of Loss Costs at a rate equal
to the NVE WACC as of the time of the relevant Event of Loss Cost was incurred
with the return on equity component discounted by fifty(50)basis points; and
Condemnation Action Component=the aggregate sum of the following calculated
in respect of each Condemnation Action: (the applicable Net Condemnation Action
Cost funded by Great Basin / applicable Amortization Period) + interest accruing
during such month on any unamortized portion of such Net Condemnation Action
Cost at a rate equal to the NVE WACC as of the time of the relevant Condemnation
Action Cost was incurred with the return on equity component discounted by fifty
(50)basis points.
Great Basin shall deliver an invoice by the tenth (I01h) day of each month during the Monthly
Payment Period setting the Monthly Payment owed for such month along with reasonable
supporting documentation, and on the last Business Day of each month(but extended by a day for
each day that the invoice is late) during the Monthly Payment Period,NPC shall pay seventy-five
percent (75%) of the undisputed portions of the Monthly Payment to Great Basin and SPPC shall
pay twenty-five percent(25%) of the undisputed portions of the Monthly Payment to Great Basin.
(b) The Monthly Payment shall be proportionally reduced: (i) to the
extent ON Line becomes unavailable to one or both of the NVE Parties for a period in excess of
one hundred twenty (120) consecutive days due to Force Majeure, an Event of Loss,
Condemnation Action or any change in Applicable Law commencing after such one hundred
twentieth (120th) day, and (ii) commencing immediately, to the extent that ON Line becomes
unavailable to one or both of the NVE Parties due to (A) any negligent act or omission or any
Willful Misconduct/Gross Negligence of, or breach of this Agreement by, Great Basin or (B)
unless the Management Committees agrees to alternative action, the withholding by Great Basin
(including any of Great Basin's Authorized Representatives)of any consent to any action proposed
by NPC in good faith, consistent with Prudent Utility Practices and not in violation of any
Applicable Law and for which the NVE Parties are obligated to fund all costs thereof under this
Agreement directly or through an adjustment to the Monthly Payment. In the event, during any
calendar month, ON Line has become unavailable to one or both of the NVE Parties under the
circumstances described in clauses (i) and (ii) above, the Monthly Payment payable at the end of
such month shall be adjusted to reflect the number of hours during which ON Line was so
unavailable to one or both of the NVE Parties as compared to the number of hours in such month
(it being understood that, if ON Line becomes unavailable to only one of the NVE Parties, the
other NVE Party shall continue to be obligated to pay its portion of the Monthly Payment). For
the avoidance of doubt, for any given calendar month, the Monthly Payment in respect of such
47
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 53 of 198

month shall not be due and payable, and shall be forever waived in its entirety, if ON Line is
completely unavailable for the entire month for any reason described in clauses (i) or(ii) above.
(c) NPC's and SPPC's obligation to pay its portion of the Monthly
Payment shall cease upon (i) consummation of any purchase by the NVE Parties (or any one of
them individually) of all of Great Basin's Ownership Interests or(ii) the effectiveness of a notice
terminating the Terminated Capacity as set forth in Section 16.02(h). The Monthly Payment shall
not be subject to escalation or other adjustment (including following GB Segment COD), except
as expressly set forth herein.
3.07 Great Basin Segment Abandonment or Delay Buyout Right.
(a) If Great Basin(i)has not achieved GB Segment Financial Closing on
or before the GB Segment Financial Closing Deadline, (ii) ceases development or construction of
any Great Basin Segment for a period of ninety (90) consecutive days at any time and expresses
its intent in writing or makes a public announcement of its intent not to complete development or
construction of any Great Basin Segment or (iii) has not achieved GB Segment COD before GB
Segment COD Deadline, and,as of the GB Segment COD Deadline,either of the following is true:
Great Basin(A)does not have financing arrangements available to achieve GB Segment COD and
complete construction of the Great Basin Segments or (B) is not actively constructing the Great
Basin Segments, in each case, for reasons other than a pending formal proceeding challenging the
Great Basin Segments or any Governmental Approvals for the Great Basin Segments,for any other
event of Force Majeure or as a result of an Event of Default by a NVE Party,then the NVE Parties
shall have the right to purchase all (but not less than all) of Great Basin's Ownership Interests for
a price determined in accordance with Schedule 5; provided that written notice of their election to
exercise such right is provided to Great Basin by the fourteenth(14th) anniversary of the ON Line
COD. If such purchase right arises and the NVE Parties timely elect to exercise such right, then
Great Basin shall Transfer all of its Ownership Interests to the NVE Parties free and clear of any
Liens other than Permitted Liens upon the latest to occur of(i) the fifteenth (15th) anniversary of
the ON Line COD, (ii) fifteen (15) days after receipt of PUCN Approval and all required
Governmental Approvals on terms acceptable to the NVE Parties and(iii)the date set forth in such
notice (which shall not be more than one hundred eighty (180) days after the fifteenth (15th)
anniversary of the ON Line COD). Great Basin shall make Applicable Transfer Representations
and Warranties to the NVE Parties in connection with such Transfer. At any time after the sixth
(6th) anniversary of GB Segment Financial Closing, upon Great Basin's request, the NVE Parties
shall state in writing whether in their view the circumstances described in Section 3.07(a)(iii)
existed as of the GB Segment COD Deadline (such that, in the NVE Parties' view, the NVE
Parties' right to elect to so purchase all of Great Basin's Ownership Interests had been triggered)
and Great Basin shall be entitled to rely on such written statement(but shall not be bound by such
statement in the event of a Dispute among the Parties), it being understood that such a written
statement by the NVE Parties shall under no circumstances operate as a notice of the NVE Parties'
election to exercise any purchase right that may have been triggered (such election by the NVE
Parties requiring a separate written notice, timely delivered as provided in this Section 3.07(a)).
(b) The GB Segment Financial Closing Deadline and the GB Segment
COD Deadline shall be subject to extension for any event of Force Majeure to the extent that such
48
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 54 of 198

event causes a delay in an activity required for Great Basin to achieve GB Segment Financial
Closing or for GB Segment COD to occur which activity cannot, despite the exercise of
commercially reasonable efforts, be delayed without extending the day on which GB Segment
Financial Closing or GB Segment COD, as applicable, will occur.
3.08 30th Anniversary Buyout Right. The NVE Parties shall have the right to
purchase all (but not less than all) of Great Basin's Ownership Interests for a price determined in
accordance with Schedule 5; provided that written notice of their election to exercise such right is
provided to Great Basin by the twenty-ninth (29th) anniversary of the ON Line COD (but not
earlier than the twenty-seventh(27th)anniversary of the ON Line COD). If the NVE Parties timely
elect to exercise such right, then Great Basin shall Transfer all of its Ownership Interests to the
NVE Parties free and clear of any Liens other than Permitted Liens upon the latest to occur of(a)
the thirtieth (30th) anniversary of the ON Line COD, (b) fifteen (15) days after receipt of PUCN
Approval and all required Governmental Approvals on terms acceptable to the NVE Parties and
(c) the date set forth in such notice (which shall not be after the thirty-third (33rd) anniversary of
the ON Line COD). Great Basin shall make Applicable Transfer Representations and Warranties
to the NVE Parties in connection with such Transfer.
3.09 41 st Anniversary Buyout Right or Renewal Term.
(a) The NVE Parties shall have the right to purchase all (but not less
than all) of Great Basin's Ownership Interests for a price determined in accordance with Schedule
5; provided, that written notice of their election to exercise such right is provided to Great Basin
by the fortieth(40th) anniversary of the ON Line COD(but not earlier than the thirty-eighth(38th)
anniversary of the ON Line COD). If the NVE Parties timely elect to exercise such right, subject
to obtaining PUCN Approval and all required Governmental Approvals on terms acceptable to the
NVE Parties (which approvals the NVE Parties will timely seek prior to or upon their election to
exercise such right), then Great Basin shall Transfer all of its Ownership Interests to the NVE
Parties free and clear of any Liens other than Permitted Liens on the forty-first (41 st) anniversary
of the ON Line COD. If such PUCN Approval and Governmental Approvals are not received by
the date that is six(6)months prior to the forty-first(41 st) anniversary of the ON Line COD,then,
unless the parties otherwise agree in writing, the NVE Parties shall be deemed to have withdrawn
their election to exercise such right; provided, that on or prior to such date, the NVE Parties may
elect (such election being irrevocable) to renew their Capacity Entitlements pursuant to Section
3.09 b ; and,provided, further,that it is understood and agreed that(i)neither Great Basin nor any
of its Affiliates will intervene in any regulatory proceeding of the NVE Parties relating to the
PUCN Approval or any Governmental Approvals (notwithstanding Section 4.05(a)) unless
requested to do so by the NVE Parties and if the NVE Parties so request, Great Basin or its
Affiliate, as applicable, will support the NVE Parties' request to acquire Great Basin's Ownership
Interests pursuant to this Section 3.09(a) in such proceeding and(ii) in no event shall the Transfer
of all of Great Basin's Ownership Interests to the NVE Parties occur after the forty-first (41 st)
anniversary of the ON Line COD. In the event the NVE Parties do not make such renewal election,
then the NVE Parties shall permanently revoke their election to acquire Great Basin's Ownership
Interests and forever waive all of their rights under this Section 3.09. Great Basin shall make
Applicable Transfer Representations and Warranties to the NVE Parties in connection with such
Transfer.
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Second Amended and Restated Transmission Use and Capacity Exchange Agreement
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Case No. IPC-E-25-08
J. Ellsworth, [PC
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(b) The NVE Parties shall have the right to renew all (but not less than
all) of each Party's Capacity Entitlements for a period of one year or more commencing as of the
forty-first(41 st) anniversary of ON Line COD for a fixed rental payment calculated in accordance
with Schedule 5;provided that(i)such renewal period when added to the forty-one(41)year initial
term commencing on the ON Line COD does not extend for more than eighty percent (80%) of
the then re-estimated useful life of Great Basin's Ownership Interest subject to such renewal
measured from the ON Line COD and (ii) Great Basin's Ownership Interest subject to such
renewal will have a value at the termination of such renewal equal to at least twenty percent(20%)
of the initial value of such interests measured as of the ON Line COD (without giving effect to
inflation or deflation), in each case determined at the time of such renewal. If Great Basin and the
NVE Parties cannot agree as to the calculations of the estimated value or useful life of Great
Basin's Ownership Interest subject to such renewal, then the Parties shall mutually select the
Independent Auditor or another external auditor or appraiser, as determined based on the nature of
the dispute, which shall be instructed to resolve such disagreement within thirty (30) days after
such disagreement is submitted to it for resolution and shall notify Great Basin and NPC in writing
of its resolution. Such auditor's or appraiser's resolution of the disagreement shall be final and
binding on the Parties.
(c) Notwithstanding anything herein to the contrary, in the event the
NVE Parties do not (i) purchase all of Great Basin's Ownership Interests or (ii) renew their
Capacity Entitlements pursuant to Section 3.09(b), then from and after the forty-first (41st)
anniversary of ON Line COD,the Parties shall have the Capacity Entitlements set forth in the first
sentence of Section 3.02(e) and all Operating Costs, Event of Loss Costs, Condemnation Action
Costs and Capital Repair Costs, in each case, in respect of ON Line shall be funded by the Parties
in accordance with their respective Ownership Percentages and Great Basin shall have no right to
recover Great Basin's Ownership Percentage of any such costs from the NVE Parties.
3.10 Force Majeure. To the extent a Party is prevented or delayed by Force
Majeure from performing, in whole or in part, its obligations under this Agreement and such Party
(a"Claiming Party") gives written notice and details of such Force Majeure to the other Parties as
soon as reasonably practicable after such Party becomes aware of the occurrence of such Force
Majeure, then the Claiming Party shall be excused from the performance of its obligations under
this Agreement (other than Great Basin's obligation to use commercially reasonable efforts to
achieve GB Segment COD as set forth in Sections 3.02(b) and the obligation to make payments,
except as otherwise provided in this Agreement where such Force Majeure event causes ON Line
to become unavailable to one or both of the NVE Parties) during such Force Majeure but for no
longer period and only to the extent performance of such obligations are prevented or delayed by
such Force Majeure. The Claiming Party shall exercise due diligence to remedy the Force Majeure
within a reasonable period. Force Majeure shall not entitle any Party to terminate this Agreement.
3.11 Transmission Systems. Nothing in this Agreement shall prevent a Party
from making any additions, modifications or changes to its respective transmission system. Each
Party shall provide reasonable notice to the other Parties, to the extent required by the PUCN,
FERC,NERC, WECC, or their successors in interest, of such additions, modifications or changes
to its transmission systems.
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Second Amended and Restated Transmission Use and Capacity Exchange Agreement
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Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 56 of 198

3.12 Additional Uses. Notwithstanding anything to the contrary in this
Agreement, (a) the NVE Parties shall have all of the rights associated with any additional uses
arising with respect to ON Line, and Great Basin shall have all of the rights associated with any
additional uses of the Great Basin Segments, in each case,prior to the adjustment of Great Basin's
Capacity Entitlement pursuant to Section 3.02(b) or 3.02 e (and any rights arising prior to such
adjustment shall not be impacted thereby) and(b)the Parties shall share all of the rights associated
with any additional uses arising with respect to the Transmission Line thereafter in proportion to
their respective Capacity Entitlements; provided, however, that the NVE Parties shall be entitled
to the exclusive rights associated with any additional uses of the Double Circuit Towers regardless
of whether arising before or after the adjustment of Great Basin's Capacity Entitlement pursuant
to Section 3.02(b) or 3.02(e). Notwithstanding anything herein to the contrary (other than as
provided hereunder in respect of the NVE Parties' exclusive rights associated with any additional
uses of the Double Circuit Towers), in the event the NVE Parties do not (i) purchase all of Great
Basin's Ownership Interests or(ii)renew their Capacity Entitlements pursuant to Section 3.09(b),
from and after the forty-first (41 st) anniversary of the ON Line COD, the Parties shall share all of
the rights associated with any additional uses with respect to ON Line in proportion to their
respective Ownership Percentages and Great Basin shall have all of the rights associated with any
additional uses arising with respect to the Great Basin Segments; provided, however, that if,prior
to the forty-first(41 st) anniversary of the ON Line COD,the NVE Parties shall have committed all
or any part of the rights associated with any additional uses to one or more third parties in one or
more transactions having a term that extends beyond such anniversary, then(x)the rights of Great
Basin with respect to such additional uses shall be subject to the rights of such third parties and
(y) from and after such anniversary, any revenues payable to the NVE Parties under such
transactions shall be shared between the NVE Parties and Great Basin in proportion to their
respective Ownership Interests.
ARTICLE IV
DEVELOPMENT AND CONSTRUCTION OF ON LINE
4.01 Pursuit and Management of ON Line. Subject to the control and oversight
of the Management Committee and through the Acquisition Closing Date, Great Basin shall have
primary responsibility for the overall pursuit and management of all aspects of ON Line,including
the day-to-day management of ON Line, the administration of all ON Line Agreements and the
performance of all ON Line Activities not set forth on Exhibit B or specifically delegated to the
NVE Parties by the Management Committee. Subject to the control and oversight of the
Management Committee and after the Acquisition Closing Date, NPC shall have primary
responsibility for the overall pursuit and management of all aspects of ON Line, including the day-
to-day management of ON Line, the administration of the ON Line Agreements and the
performance of all ON Line Activities not specifically delegated to Great Basin or SPPC by the
Management Committee. Each of NPC and Great Basin shall cooperate with each other in
transitioning primary responsibility for the overall pursuit and management of ON Line to NPC as
contemplated by this Section 4.01. It is the intent of the Parties to develop ON Line for the lowest
reasonable cost(taking into account safety, quality and schedule).
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4.02 ON Line Managers.
(a) On the Effective Date, Great Basin shall appoint one of its (or its
Affiliates') employees (the"Great Basin Manager")to be responsible for the day-to-day oversight
and coordination of Great Basin's responsibilities in respect of ON Line, including managing and
directing construction of ON Line through the Acquisition Closing Date and issuing and receiving
communications regarding ON Line. The Great Basin Manager must be approved by the
Management Committee. Great Basin may remove the Great Basin Manager at any time,but shall
promptly appoint a replacement subject to Management Committee approval.
(b) On the Effective Date, NPC shall appoint an employee of NPC or
SPPC (the "NPC Manager") to be responsible for the day-to-day oversight and coordination of
NPC's responsibilities in respect of ON Line, including managing and directing construction of
ON Line after the Acquisition Closing Date, managing and directing the operation and
maintenance of ON Line, and issuing and receiving communications regarding ON Line. The
NPC Manager must be approved by the Management Committee. NPC may remove the NPC
Manager at any time,but shall promptly appoint a replacement subject to Management Committee
approval.
4.03 Access to ON Line and ON Line ROW.
(a) Except with respect to Great Basin's financial information, which is
addressed by Section 9.06,each Party and its representatives and consultants shall have(i)physical
access to ON Line (including the ON Line ROW) to the extent that such access does not
unreasonably interfere with ON Line, subject to reasonable safety and security requirements of
which such Party has been provided advance written notice, (ii) the independent right to (A)
monitor the development, construction, management, operation, maintenance and use of ON Line
and (B) review and comment on draft copies of ON Line Agreements, applications for
Governmental Approvals for ON Line and material communications regarding ON Line and (iii)
if requested by a Party, copies of all Governmental Approvals for ON Line(including applications
therefor), ON Line Agreements(including drafts thereof),material communications regarding ON
Line and all information related to land rights, expected development, construction, management,
operation, maintenance or use costs, constructability, creditworthiness, records, operating data,
accounts, organizational documents, copies of studies, reports and data and any other information
regarding ON Line, in each case as reasonably requested by the requesting Party.
(b) No Party(or any of its agents,officers or employees)shall be an agent
or employee of any other Party, nor shall any Party (or any of its agents, officers or employees)
have any power to bind, assume or create any obligation on behalf of any other Party, except as
provided in the ON Line Agreements and in separate agreements between the NVE Parties.
4.04 Standard of Performance. The Parties shall comply with all Applicable
Laws, all Governmental Approvals for ON Line and all ON Line Agreements. ON Line shall be
developed, designed, constructed and managed to comply with all Applicable Laws, all
Governmental Approvals for ON Line and all ON Line Agreements and in accordance with
Prudent Utility Practices, and each Party shall own and use ON Line in accordance with Prudent
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Utility Practices, all Applicable Laws, all Governmental Approvals for ON Line and all ON Line
Agreements.
4.05 Government Approvals; Cooperation.
(a) Great Basin shall provide such information and assistance in the
preparation of the application for any PUCN Approval as is reasonably requested by the NVE
Parties and is within the reasonable control of Great Basin or its Affiliates. The NVE Parties shall
provide Great Basin with (i) notice as promptly as practicable to allow Great Basin to request
confidential treatment from the PUCN for such information and(ii) such assistance as Great Basin
may reasonably request in connection with attaining confidential treatment from the PUCN for
such information. Great Basin shall participate as reasonably requested from time to time in
connection with obtaining any PUCN Approval. Great Basin shall timely file a petition for leave
to intervene in the PUCN proceeding(s) related to obtaining any PUCN Approval, retain counsel
to represent Great Basin in such proceeding(s) in accordance with NAC 703.510, and actively
support the regulatory approval process. No costs incurred by Great Basin in connection with such
filing, retaining and support shall be included in the Pre-Closing Costs incurred by Great Basin.
(b) The Parties shall use commercially reasonable efforts to file for the
FERC Approval as soon as reasonably practicable after the Effective Date. Each Party shall
participate as reasonably required from time to time in connection with the FERC Approval, and
actively support the regulatory approval process.
(c) Each Party shall coordinate and cooperate in good faith with the other
Parties on all material ON Line-related matters, in order to facilitate development, construction,
ownership, management, operation, maintenance and use of ON Line in an effective and cost-
efficient manner. Not limiting the generality of the foregoing sentence, the Parties shall cooperate
with each other by providing documents and information, participating in meetings and hearings,
and performing such other acts, in each case as may be reasonably requested by any other Party in
connection with any Governmental Approvals for ON Line, including maximizing ON Line's
Electrical Capacity, Microwave Capacity and Fiber Optic Capacity.
(d) To the extent practicable in the NVE Parties' sole discretion and as
reasonably requested by Great Basin,the NVE Parties will coordinate and cooperate in good faith
with Great Basin on Great Basin Segment-related matters; provided that such cooperation and
coordination shall be at Great Basin's sole cost and expense (and shall not in any event require
either NVE Party to hire additional staff) and could not be expected to burden or adversely impact
the NVE Parties or the operation of their businesses or transmission systems, in each case as
determined by the NVE Parties in their sole discretion.
(e) Subject to Sections 3.09(a) and 4.05 a , nothing in this Agreement
shall prohibit a Party from intervening in any regulatory proceeding, and taking any position in
such proceeding, that it deems appropriate in its sole discretion; provided, however, that to the
extent reasonably practicable, each Party will provide the other Parties written notice of its
intention to seek to intervene in any proceeding initiated by a Party in connection with this
Agreement no less than five (5) days prior to filing its request to intervene.
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(f) Each Party shall provide any other Party with information related to
ON Line and copies of any Work Product reasonably requested by any such other Party.
(g) Each Party agrees that, in carrying out its obligations under this
Agreement, it shall:
(i) appoint qualified personnel (including a qualified person as
its ON Line Manager, who may or may not be an Authorized Representative of such
Party), as necessary, that have the time and requisite skills to devote to such Party's
assigned responsibilities, in order to perform its responsibilities hereunder;
(ii) use commercially reasonable efforts to perform its
respective obligations in order to meet the ON Line Schedule, in accomplishing its
assigned tasks, and to provide updated information regarding its progress in respect
thereof upon request of the other Parties or as circumstances warrant; and
(iii) act as the interface with,and supervise,all third Persons with
which such Party has directly contracted to perform work related to its assigned
responsibilities.
4.06 Interconnection and Construction.
(a) ON Line shall be interconnected to the electric transmission systems
of the NVE Parties pursuant to the Interconnection Agreements. Each Interconnection Agreement
shall contain terms consistent with this Agreement. The Parties shall cooperate and work
expeditiously to complete the Interconnection Agreements on a schedule that supports the ON
Line Schedule.
(b) Following the Effective Date, the Parties shall discuss and approve
the terms and conditions upon which each Material Construction Contract shall be let, it being
understood that, unless the Parties otherwise agree, each Material Construction Contract shall, to
the extent customary, (i) be lump sum, fixed price contracts, (ii) contain provisions relating to
guaranteed performance levels, if applicable, and guaranteed completion dates and, in each case,
corresponding liquidated damages and (iii) require each Material Construction Contractor to
provide credit support for its obligations under the applicable Material Construction Contract in
the form of a parent guarantee, bonds, letter of credit or retainage.
4.07 Consultants. Each Project Budget will allow for NPC to engage one or more
engineering and other consultants to advise it in the review of all matters relating to ON Line,
acceptable to the Management Committee. Additionally, each Party shall have the right to engage
one or more Owners' Engineers and other consultants to advise it with respect to any matters in
connection with ON Line, and the cost of such Owners' Engineers and other consultants shall be
borne by such Party, except to the extent such costs are expressly included in a Project Budget or
consented to by the Management Committee.
4.08 Change of Name. The Parties shall take such actions required to rename
SWIP-S as the "One Nevada Transmission Line" or "ON Line" effective as of the Acquisition
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Closing Date, and following the Acquisition Closing Date through the Term, the NVE Parties
hereby grant a royalty free, irrevocable license in such names to Great Basin only to be used in
connection with ON Line; provided, however, that if the NVE Parties do not own an Ownership
Interest, then the NVE Parties may revoke such license at no cost.
4.09 f intentionally deleted]
ARTICLE V
PROJECT BUDGET AND PAYMENT OF COSTS
5.01 Project Budget.
(a) Submission of Proposed Project Budget. The Managing Party or
NPC, as applicable, shall use reasonable efforts to prepare any new or revised Project Budget on
the basis of firm pricing obtained from vendors, suppliers and contractors and shall submit such
Project Budget to the Management Committee from time to time for its prompt review. If a Party
so requests, the Managing Party or NPC, as applicable, shall provide to the Management
Committee copies of the data, invoices, price sheets and other information utilized in the
preparation of any such Project Budget and shall make the personnel responsible for preparing
such Project Budget available to discuss the proposed Project Budget with the Management
Committee.
(b) Management Committee Review and Approval. The Management
Committee shall promptly review any new or revised Project Budget proposed by the Managing
Party or NPC, as applicable, and shall complete its review,taking into account any comments and
revisions as it may request of the Managing Party or NPC, as applicable. The Management
Committee may approve a proposed Project Budget in whole or in part. Each Party acknowledges
and agrees that the approval of any new or revised Project Budget and the making of any payment
hereunder shall be without prejudice to the audit rights of each Party hereunder. Prior to the
Operating Period, the Management Committee shall periodically, but no less frequently than
monthly, review(i)the status of the ON Line Activities against the ON Line Budget and ON Line
Schedule, (ii)the anticipated, committed and incurred ON Line Costs from and after the Effective
Date against the ON Line Budget and (iii) the funding requirements for ON Line Costs forecast
for the following month. During the Operating Period, the Management Committee shall
periodically, but no less frequently than quarterly, review (i) the status of the Capital Repairs
against the applicable Capital Repair Budget, (ii) the anticipated, committed and incurred Capital
Repair Costs against the applicable Capital Repair Budget and (iii) the funding requirements for
Capital Repair Costs forecast for the following quarter.
(c) Failure to Approve a Proposed Project Budget. If the Management
Committee fails to approve a proposed Project Budget or any part thereof, then until the
Management Committee approves the proposed Project Budget or disputed part thereof, the
unapproved Project Budget or part thereof proposed shall not be implemented; provided that the
Project Budget or part thereof most recently approved by the Management Committee shall remain
in full force and effect until a new Project Budget or the applicable part thereof is approved, subject
to Section 8.01(h)(ii), and NPC shall be entitled to incur costs for Critical Capital Repairs and the
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other Parties shall pay their Ownership Percentage share thereof to the extent required by Section
5.04.
(d) Internal Labor Cost. Each Project Budget may include amounts for
the reimbursement of direct internal labor costs incurred by any Parry or its Affiliates for
employees directly engaged in the performance of ON Line Activities or Capital Repairs, as
applicable (other than any costs of either Party with respect to its Authorized Representatives);
provided, however, that such internal labor costs shall: (i)not include any amounts attributable to
general administrative costs or overhead costs not associated with direct internal labor for
employees directly engaged in the performance of ON Line Activities or Capital Repairs, as
applicable, and (ii) only include internal labor costs directly attributable to ON Line that would
not have been incurred if work was not being performed for ON Line Activities or Capital Repairs,
as applicable. A Party seeking reimbursement for direct internal labor costs incurred in accordance
with the applicable Project Budget and this Section 5.01(d) shall keep reasonably detailed records
of such costs and shall provide such records to the other Parties upon request.
5.02 Compliance with Project Budget; Amendments. The Managing Party and
NPC, as applicable, shall use commercially reasonable efforts to manage, or cause to be managed,
the commitment of funds so that costs will not exceed funds committed or to be committed by the
Parties pursuant to the applicable Project Budget. If, in the reasonable judgment of the Managing
Party or NPC, as applicable, any Project Budget, or any material expense category or line item
therein, is determined to be materially greater or less than the actual costs of performing the ON
Line Activities or Capital Repairs, as applicable, or any material expense category or line item
therein, the Managing Party or NPC, as applicable, shall prepare an amended Project Budget for
approval by the Management Committee at the next regular meeting or at a special meeting called
by a Party for such purpose as soon as reasonably practicable following such determination.
5.03 Funding ON Line Costs.
(a) Each Party shall be solely responsible for funding, and shall timely
fund, all of its own Development Costs and all of its own Pre-Closing Costs, in each case subject
to Section 2.02, and Great Basin shall be solely responsible for funding, and shall timely fund, all
other liabilities and obligations in respect of ON Line arising through the Acquisition Closing
Date. Commencing after the Acquisition Closing Date, each Party shall pay for its Ownership
Percentage of all Post-Closing Costs arising thereafter in accordance with this Agreement to the
extent that, when added to any Development Costs and Pre-Closing Costs funded by such Party
(as adjusted by any Closing Payments), such Party has funded up to its respective Ownership
Percentage of the ON Line Budget. No Party shall charge a fee to any other Party for performance
of its responsibilities as the Managing Party under this Agreement. Subject to Section 16.02(e)(i)
and ii), respectively, (i) Great Basin, in its capacity as the Managing Party, shall be responsible
for reviewing invoices for Pre-Closing Costs (other than costs incurred in respect of the NVE
Project) and, from and after the Effective Date, reconciling the payments for such costs to the ON
Line Budget on a monthly basis and (ii) NPC, in its capacity as the Managing Party, shall be
responsible for reviewing invoices for Post-Closing Costs (including invoices for Direct Pay
Amounts) and reconciling the payments for such costs to the ON Line Budget on a monthly basis.
Great Basin shall be responsible for timely paying amounts payable in respect of Pre-Closing Costs
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(other than costs incurred in respect of the NVE Project). NPC shall be responsible for timely
paying amounts payable by the Parties in respect of Post-Closing Costs (other than Direct Pay
Amounts).
(b) [intentionally deleted]
(c) After the Acquisition Closing Date:
(i) Subject to Section 5.03(d), NPC and Great Basin shall pay
their respective Ownership Percentages (and, in the case of NPC, SPPC's Ownership
Percentage) of all Direct Pay Amounts when due in accordance with the ON Line Budget
and the applicable Material Construction Contract and each Party shall pay their
respective Ownership Percentages (and, in the case of NPC, SPPC's Ownership
Percentage)of all Post-Closing Costs(other than Direct Pay Amounts) in accordance with
Section 5.03(c)(ii).
(ii) On a monthly basis but in any event no later than the fifth
(5th) Business Day of each month, the Managing Party shall submit to the other Parties
(A) an invoice of funds that each Party is liable for under this Agreement for the previous
month and(B) a statement reconciling the prior invoice or invoices in the event the actual
amount(s) for which each Party was liable during such month changed as a result of
refunds, credits, change orders or other adjustments made to such invoices by the
counterparty to the underlying contract. Each invoice and reconciliation statement shall
be accompanied by reasonable supporting documentation showing the amounts properly
due and payable, a breakdown of the Post-Closing Costs (other than Direct Pay Amounts)
represented in such invoice or reconciliation statement, copies of the underlying invoices
and supporting materials, and such other supporting documentation as may be reasonably
requested by Great Basin in order to submit requisitions and obtain funds under the ON
Line Financing Agreements. Any amounts due pursuant to an invoice or reconciliation
statement shall be due and payable two (2) Business Days prior to the current month end,
or on such later date as may be otherwise set forth in the invoice or reconciliation
statement. If a reconciliation statement shows that prior payments by a Party exceeded
the actual amount for which such Party was liable, such excess amount shall be credited
against the amounts due by such Party in the invoice accompanying such reconciliation
statement, or in the event that such excess amount exceeds such Party's payment
obligations under such invoice, the difference between the excess amount determined by
such reconciliation statement and the payment obligations of such Party under such
invoice shall be paid to such Party no later than two(2)Business Days prior to the current
month end.
(d) The Managing Party shall provide the other Parties written notice of
any expected Initial Cost Differential or Incremental Cost Differential as soon as reasonably
practicable upon receiving notice of any such costs. If, within ten (10) days after receipt of such
notice, Great Basin does not elect to fund any such Initial Cost Differential or Incremental Cost
Differential, Great Basin shall have no right or obligation to fund its Ownership Percentage of any
such Initial Cost Differential or Incremental Cost Differential. If Great Basin does timely elect
(such election being irrevocable) to fund its Ownership Percentage (and, in the circumstances
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described in Section 5.03(e), the NVE Parties' Ownership Percentage) of any such Initial Cost
Differential or Incremental Cost Differential, then Great Basin shall timely fund any such Initial
Cost Differential or Incremental Cost Differential,as applicable,and the amount of any such Initial
Cost Differential or Incremental Cost Differential funded by Great Basin shall be reflected in the
Monthly Payment as provided in Section 3.06. To the extent that Great Basin does not timely fund
its Ownership Percentage of any Initial Cost Differential or Incremental Cost Differential,the NVE
Parties may fund any such portion, and upon(i)the earliest to occur of(A) ON Line COD, (B) an
Event of Default by Great Basin, (C) a Condemnation Action or Event of Loss related to ON Line,
(D) an election of a right to purchase Ownership Interests under this Agreement and(E) any other
material event regarding ON Line as reasonably determined by the NVE Parties and (ii) fifteen
(15) days after such earliest date and receipt of PUCN Approval and all required Governmental
Approvals on terms acceptable to the NVE Parties, each Party's Ownership Percentage shall be
adjusted such that,following the adjustment,such Party's Ownership Percentage shall equal a ratio
(A) the numerator of which is equal to the portion of the Total Costs paid by such Party and (B)
the denominator of which equals the aggregate amount of the Total Costs, and Great Basin shall
Transfer the portion of its Ownership Interest corresponding to its excess above its revised
Ownership Percentage to the NVE Parties free and clear of any Liens other than Permitted Liens.
Great Basin shall execute and record any bills of sale, deeds, certificates, memorandum and other
documentation as reasonably requested by the NVE Parties to evidence the re-allocation of such
interests. Great Basin shall make Applicable Transfer Representations and Warranties in
connection with such Transfer.
(e) Notwithstanding anything herein to the contrary,to the extent that the
NVE Parties do not timely fund their aggregate Ownership Percentage of any Initial Cost
Differential or Incremental Cost Differential, Great Basin shall have the right, but not the
obligation, to (A) fund the entire amount of such Initial Cost Differential or Incremental Cost
Differential and (B) take over primary responsibility for managing and directing the completion
of construction of ON Line as provided in Section 16.02(e)(i).
5.04 Fundingof f Capital Repair Costs.
(a) [intentionally deleted]
(b) After ON Line COD:
(i) Subject to Sections 5.04(c) and fdd), NPC and Great Basin
shall pay their respective Ownership Percentages (and, in the case of NPC, SPPC's
Ownership Percentage) of all Capital Repair Costs when due (other than Direct Pay
Amounts) in accordance with Section 5.04(b)(ii).
(ii) On a monthly basis but in any event no later than the fifth
(5th) Business Day of each month, NPC shall submit to the other Parties (A) an invoice
of funds that each Party is liable for under this Agreement for the previous month and(B)
a statement reconciling the prior invoice or invoices in the event the actual amount(s) for
which each Party was liable during such month changed as a result of refunds, credits,
change orders or other adjustments made to such invoices by the counterparty to the
underlying contract. Each invoice may also include any actual costs for which a Party is
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liable under this Agreement arising prior to the time such invoice is issued in respect of
prior month(s). Each invoice and reconciliation statement shall be accompanied by
reasonable supporting documentation showing the amounts properly due and payable, a
breakdown of the Capital Repair Costs represented in such invoice or reconciliation
statement, copies of the underlying invoices and supporting materials, and such other
supporting documentation as may be reasonably requested by Great Basin in order to
submit requisitions and obtain funds under the ON Line Financing Agreements. Any
amounts due pursuant to an invoice or reconciliation statement shall be due and payable
two (2) Business Days prior to the current month end, or on such later date as may be
otherwise set forth in the invoice or reconciliation statement. If a reconciliation statement
shows that prior payments by a Party exceeded the actual amount for which such Party
was liable, such excess amount shall be credited against the amounts due by such Party in
the invoice accompanying such reconciliation statement, or in the event that such excess
amount exceeds such Party's payment obligations under such invoice, the difference
between the excess amount determined by such reconciliation statement and the payment
obligations of such Party under such invoice shall be paid to such Party two (2) Business
Days prior to the current month end.
(iii) NPC shall be responsible for reviewing invoices for Capital
Repair Costs. NPC shall be responsible for reconciling the payments for Capital Repair
Costs to the applicable Capital Repair Budget on a monthly basis.
(c) NPC shall provide the other Parties written notice of any Capital
Repair Costs as soon as reasonably practicable upon receiving notice of any such costs, and such
notice shall include (i) an invoice forecast projecting the amounts required on a monthly basis to
fund such Capital Repair Costs, and (ii) a description of the nature of the Capital Repair Costs,
reasonably satisfactory to Great Basin. If, within ten (10) days after receipt of such notice, Great
Basin does not elect to fund any such Capital Repair Costs, Great Basin shall have no right or
obligation to fund its Ownership Percentage of any such Capital Repair Costs. If Great Basin does
timely elect(such election being irrevocable)to fund its Ownership Percentage of any such Capital
Repair Costs, then Great Basin shall timely, in accordance with Section 5.04(b)(ii), fund its
Ownership Percentage of any such Capital Repair Costs, and the amount funded by Great Basin
in respect of Capital Repair Costs be reflected in the Monthly Payment as provided in Section 3.06.
To the extent that Great Basin does not timely fund its Ownership Percentage of any Capital Repair
Costs, in accordance with Section 5.04(b)(ii),but subject to Section 5.04(d),the NVE Parties shall
fund any such portion, and upon (i) the earliest to occur of(A) any anniversary of the ON Line
COD,(B)an Event of Default by Great Basin,(C)a Condemnation Action or Event of Loss related
to ON Line, (D) an election of a right to purchase Ownership Interests under this Agreement, and
(E) any other material event regarding ON Line as reasonably determined by the NVE Parties and
(ii) fifteen (15) days after such earliest date and receipt of PUCN Approval and all required
Governmental Approvals on terms acceptable to the NVE Parties, each Party's Ownership
Percentage shall be adjusted such that, following the adjustment, such Party's Ownership
Percentage shall equal a ratio (x)the numerator of which is equal to the portion of the Total Costs
paid by such Party and(y)the denominator equals the Total Costs, and Great Basin shall Transfer
the portion of its Ownership Interest corresponding to its excess above its revised Ownership
Percentage to the NVE Parties free and clear of any Liens other than Permitted Liens. Great Basin
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shall execute and record any bills of sale, deeds, certificates, memorandum and other
documentation as reasonably requested by the NVE Parties to evidence the re-allocation of such
interests. Great Basin shall make Applicable Transfer Representations and Warranties in
connection with such Transfer.
(d) Notwithstanding anything to the contrary in this Agreement,no Party
shall be required to pay for any Capital Repair Costs that are not in accordance with the applicable
Capital Repair Budget.
5.05 Cost Reductions. Except as set forth in Section 13.03 or Section 14.03, all
Cost Reductions shall be applied to the particular ON Line Cost, Capital Repair Cost, Event of
Loss Cost or Condemnation Action Cost that gave rise to such Cost Reduction and shall be shared
among the Parties in proportion to the amounts funded by the Parties in respect of the costs giving
rise to such Cost Reduction (it being understood for the avoidance of doubt that such Cost
Reductions shall be paid solely to, and for the account of,the NVE Parties to the extent they were
received in respect of Capital Repairs, an Event of Loss in respect of ON Line or Condemnation
Action in respect of ON Line, in each case, not funded by Great Basin).
5.06 Invoicin and nd Payment.
(a) All payments made by a Party under Sections 5.03(c)(ii) and
5.04 b ii shall be made in Dollars by electronic funds transfer or wire transfer in immediately
available funds for receipt by the due date to such Person(s) as the Management Committee may
determine.
(b) Each Party shall make all Contributions required hereunder as and
when due, without demand, counterclaim, setoff, deduction or defense, and each Party waives, to
the extent permitted by Applicable Law, all rights now or hereafter conferred by statute or
otherwise with respect to any such demand, counterclaim, setoff, deduction or defense to the
applicable account or accounts.
5.07 Defaulted Contributions.
(a) If a Party fails to pay the full amount of any payments when required
to do so pursuant to Sections 5.03(c) or 5.04 b (each, a"Contribution"and such Party,the "Non-
Contributing Party"),then any Party that has paid its Contribution(the"Contributing PAX") shall
have the right, but not the obligation, to make an advance (an "Advance") on behalf of the Non-
Contributing Party in respect of the unpaid Contribution of the Non-Contributing Party (the
"Unpaid Contribution"). Such Advance shall bear interest at a rate equal to the Default Rate from
the date such Advance was made until the date such Advance is fully repaid in cash by the Non-
Contributing Party. Advances shall be repaid, with interest at the Default Rate, by the Non-
Contributing Party at any time after the date the Advance is made upon written demand therefor
by the Contributing Party. Each Advance shall be an obligation of the Non-Contributing Party to
the Contributing Party and the Contributing Party may enforce and recover from the Non-
Contributing Party the Advance in accordance with any of its remedies hereunder or at equity or
in law. If either of the NVE Parties is the Non-Contributing Party, then the other NVE Party, as
applicable, shall have the first right to be the Contributing Party, which right must be exercised
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within five (5) Business Days after the date the Unpaid Contribution was required to be made.
Each Advance for an Unpaid Obligation shall cure any Event of Default therefor with respect to
the Party that is not the Contributing Party or the Non-Contributing Party.
(b) The election by a Party to make or not to make an Advance in respect
of an Unpaid Contribution shall not operate as waiver of the rights of such Party under this
Agreement or at law or in equity, including the right to claim damages as a result of such Unpaid
Contribution, and Advances made in respect of an Unpaid Contribution shall not relieve the Non-
Contributing Party of its obligations hereunder.
5.08 Payment on Non-Business DaX. If any Contribution under this Agreement
is required to be made on a day other than a Business Day,the due date for such Contribution shall
be extended to the next Business Day, unless provided otherwise in the Material Construction
Contracts.
5.09 [intentionally deleted]
ARTICLE VI
DEVELOPMENT AND CONSTRUCTION OF GREAT BASIN SEGMENTS
6.01 Transmission Improvements. If any improvements on the transmission
systems of the NVE Parties (other than the Harry Allen Transformers) are undertaken for any
reason prior to GB Segment Financial Closing (including as specified in Schedule 1) that would
otherwise be made as part of the construction of the Great Basin Segments (each, a"Transmission
Improvement"), then NPC or SPPC, as applicable, shall initially bear the full cost of any such
Transmission Improvement and Great Basin shall pay to NPC or SPPC, as applicable, at GB
Segment Financial Closing an amount for any such Transmission Improvement equal to the lesser
of(a) the actual cost (adjusted for depreciation) incurred by NPC or SPPC, as applicable, for any
such Transmission Improvement and (b) any avoided cost to the Great Basin Segments by reason
of any such Transmission Improvement. If Great Basin pays to NPC or SPPC, as applicable, at
GB Segment Financial Closing for any such Transmission Improvement, then, NPC or SPPC, as
applicable, shall transfer title to such Transmission Improvement(to the extent owned by the NVE
Parties) to Great Basin at GB Segment Financial Closing pursuant to documentation reasonably
satisfactory to Great Basin, and NPC or SPPC, as applicable, shall make the Applicable Transfer
Representations and Warranties to Great Basin in connection with such transfer. Notwithstanding
anything herein to the contrary, the NVE Parties shall have the right to operate and maintain the
Transmission Improvements prior to GB Segment Financial Closing, which operation and
maintenance shall be in accordance with Prudent Utility Practices (including any Electric
Reliability Organization requirements), Governmental Approvals for the Transmission Line (or
applicable portion thereof) and Applicable Law; provided, that Great Basin shall be solely
responsible for, and shall pay, all costs and expenses associated with capital repairs, replacements
and maintenance of the Transmission Improvements after GB Segment Financial Closing. NPC
or SPPC, as applicable, shall provide Great Basin with such information and documentation as
may be within its reasonable control and as may be reasonably requested by Great Basin in order
for Great Basin to determine or verify the actual cost of any such Transmission Improvement.
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6.02 Development and Construction. Great Basin shall be solely responsible for
the development and construction of the Great Basin Segments and any costs or liabilities in
respect thereof; provided, however, that the following shall be subject to the prior review and
written consent, not to be unreasonably withheld, conditioned or delayed, of the NVE Parties: (a)
the design of the Great Basin Segments (it being understood that the design and planned
construction activities for SWIP-N shall be reasonably expected to result in SWIP-N having
Electrical Capacity of no less than 1,600 MW), (b)the design and construction activities related to
the Great Basin Segments interconnection upgrades insofar as such activities involve the Robinson
Summit Substation or the Harry Allen Substation and (c) the use or crossing of any of the NVE
Parties' facilities or rights-of-way (other than as permitted in Section 6.05 and the SNIP
Agreement); provided, further, that (i) with respect to clause (a) above, no approval of the NVE
Parties shall be required if the design of the Great Basin Segments is consistent with the design of
ON Line,with such deviations as set forth in Schedule 7, and the requirements of the NVE Parties'
transmission systems, (ii) the NVE Parties shall have the right to review the Great Basin Segment
design to ensure consistency with the ON Line design and the requirements of the NVE Parties'
transmission systems and (iii) nothing in this Agreement shall limit the review of the Great Basin
Segment design by any NVE Party in connection with the negotiation or administration of the
Interconnection Agreements or in such Party's role as Balancing Authority. Notwithstanding the
foregoing, no review of, or comments about, any information provided to the NVE Parties in
respect of the Great Basin Segments, and no failure by the NVE Parties to review or comment on
any such information, shall cause a transfer of responsibility for such information to the NVE
Parties,nor imply the NVE Parties' agreement with any assumption upon which such information
is based or any matter underlying or contained therein.
6.03 Compliance with Laws and Conduct. Great Basin shall comply with all
Applicable Laws, all Governmental Approvals for the Great Basin Segments and all agreements
for the Great Basin Segments. Great Basin shall cause the Great Basin Segments to be developed,
designed, constructed and managed to comply with all Applicable Laws, all Governmental
Approvals for the Great Basin Segments, all agreements for the Great Basin Segments and in
accordance with Prudent Utility Practices.
6.04 Quarterlyports. Great Basin shall provide the NVE Parties with
quarterly progress reports detailing all material issues relating to the Great Basin Segments'
development, construction, management, operating and maintenance activities and will promptly
notify the NVE Parties of any Material Event that occurs regarding the Great Basin Segments,
subject in each case to compliance by Great Basin with any applicable confidentiality restrictions
and Applicable Law; provided, that Great Basin shall use commercially reasonable efforts to
ensure that any agreements entered into by Great Basin in connection with development,
construction, management, operating and maintenance activities in respect of the Great Basin
Segments shall allow the disclosure of information by Great Basin to the NVE Parties under this
Section 6.04.
6.05 SNIP Option.
(a) NPC hereby grants Great Basin the option (the "SNIP Option") to
acquire certain rights with respect to the Applicable Centennial Phase 3 Facilities as described in
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the SNIP Agreement(the"Applicable Centennial Phase 3 Rights") for a payment to NPC equal to
thirty-eight million eight-hundred thousand Dollars ($38,800,000) (the "Option Exercise Price"),
provided,that(i)Great Basin shall provide NPC with at least ninety(90)days' prior written notice
of its election to exercise the SNIP Option, and (ii) in exercising the Applicable Centennial Phase
3 Rights (A) Great Basin shall not interfere with the operation of any NPC facilities (except as
may be agreed to by NPC in writing in connection with the construction of the SNIP) and (B) all
material aspects of the design and construction of any elements to be constructed on NPC's
facilities or in its right-of-way shall be subject to NPC's prior review and written approval,
including with respect to the impact on the operation or any potential expansion (other than any
potential expansion to the extent that it is mutually exclusive with Great Basin's construction of a
portion of the SNIP on the Applicable Centennial Phase 3 Facilities to the extent provided in the
SNIP Agreement) or modification of NPC's facilities or use of its rights-of-way, not to be
unreasonably withheld, conditioned or delayed. Notwithstanding the foregoing in this Section
6.05 a , including the provision of such exercise notice,the SNIP Option shall expire, and shall no
longer be exercisable, if any of the following occur: (1) the Environmental Assessment for the
SNIP has not been issued for public review on or before June 1, 2012, (2) the Decision
Record/Finding of No Significant Impact for the SNIP has not been issued on or before February
1, 2013 or(3) GB Segment Financial Closing has not occurred prior to the GB Segment Financial
Closing Deadline; provided, however, that (A) the foregoing dates under clauses (1)-(3) above
shall be extended to the extent that the applicable events did not occur due to Force Majeure (but
in no event shall the date set forth in clause (3) above be extended beyond March 31, 2019) and
(B) the foregoing dates under clauses (1) and (2) above shall be extended so long as Great Basin
has previously provided NPC with a reasonably detailed cure plan that demonstrates to NPC's
reasonable satisfaction that the GB Segment Financial Closing will occur by the GB Segment
Financial Closing Deadline and Great Basin diligently pursues such cure plan.
(b) If the SNIP Option is exercised in accordance with Section 6.05(a),
NPC and Great Basin shall take the actions set forth in Section 6.05(b)(i ) on the SNIP Option
Closing Date. NPC's obligation to Transfer the Applicable Centennial Phase 3 Rights to Great
Basin, and the Great Basin's obligation to purchase the Applicable Centennial Phase 3 Rights from
NPC, are each subject to satisfaction of the following conditions, except to the extent waived in
writing by NPC with respect to the conditions set forth in Sections 6.05(b)(i)-(viii) and by Great
Basin with respect to the conditions set forth in Sections 6.05(b)(ii)-(v) and vii - viii :
(i) Great Basin shall be in compliance with Sections 6.05(a)(i)-
tiD and each of the deadlines in Sections 6.05(a)(1)-(2) has been satisfied.
(ii) GB Segment Financial Closing has occurred or shall occur
simultaneously with the SNIP Option Closing.
(iii) The FERC Approval and the BLM SNIP License Consent has
been duly obtained, made or given and shall be in full force and effect and no change to
the form of SNIP Agreement agreed by the Parties has been made as to require further
FERC approval of the SNIP Option Closing.
(iv) The other Party shall have paid or executed and delivered, or
caused to be executed and delivered to it, as applicable, the items set forth below:
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(1) Great Basin and NPC shall execute the SNIP License and
Sale Agreement substantially in the form attached hereto pursuant to Section 2.03(m) (the
"SNIP Agreement").
(2) Great Basin shall pay NPC an amount equal (A) to the
Option Exercise Price, minus (B) one-seventh (1/7) of up to fifteen million Dollars
($15,000,000) of the GB Segment Development Costs incurred prior to GB Segment
Financial Closing;
(3) NPC and Great Basin shall execute and deliver any
documentation reasonably requested by the other that is necessary or appropriate to record
the SNIP Agreement.
(v) Each of the representations and warranties made by the other
Party in the SNIP Agreement shall be true and correct in all material respects on and as of
the SNIP Option Closing Date as though made on and as of the SNIP Option Closing Date
except to the extent that such representations and warranties contain a materiality
qualifier, in which case they shall be true and correct in all respects.
(vi) There shall not be an Event of Default by Great Basin
continuing unless Great Basin has presented a plan for remedying such Event of Default
that is reasonably acceptable to NPC.
(vii) No Governmental Authority has issued a final, non-
appealable order preventing the consummation of the SNIP Option Closing.
(viii) The Parties have agreed upon the disclosure schedules to be
attached to the SNIP Agreement for purposes of Section 8 of the SNIP Agreement.
(c) Great Basin shall keep reasonably detailed records of its GB Segment
Development Costs and shall promptly provide such records to NPC upon request.
(d) If (i) NPC Transfers the Applicable Centennial Phase 3 Rights to
Great Basin and (ii) prior to GB Segment COD, Great Basin seeks to Transfer any SNIP Option
Right or any right, interest or asset associated with SNIP construction on or in the Applicable
Centennial Phase 3 Facilities (such Transfer to be subject to Article XV) (a "SNIP Option Right
Transfer"), NPC shall have the right to repurchase the Applicable Centennial Phase 3 Rights and
the improvements on the Applicable Centennial Phase 3 Facilities for an amount equal to (i) the
sum of(A) the Option Exercise Price and (B) the fair market value of any improvements to the
Applicable Centennial Phase 3 Facilities made by Great Basin, minus (ii) the amount set forth in
Section 6.05(b)(iv)(2)(B) (for the avoidance of doubt, the Option Exercise Price and GB Segment
Development Costs used to calculate the amount to be paid by NPC under this Section 6.05(d)
shall not be subject to escalation or other adjustment notwithstanding the date on which it is paid);
provided, however, that the provisions of this Section 6.05(d) shall not apply to any SNIP Option
Right Transfer made in connection with a Transfer of all of the assets of both Great Basin Segments
pursuant to Article XV, any Transfer pursuant to Section 15.03(f) or a one-time Transfer of an
undivided interest in all of the assets of both Great Basin Segments to the Western Area Power
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Administration pursuant to Article XV. Great Basin shall give NPC prior written notice of such
Transfer,and NPC shall have thirty(30)days after the receipt of such notice to exercise such right,
after which such right shall terminate; provided, however, that such termination shall only apply
with respect to the proposed Transfer (and not subsequent Transfers) and if such Transfer is not
consummated within ninety(90) days after delivery of such notice,NPC's purchase right shall be
reinstated, and Great Basin shall be required to again give NPC prior written notice of such
Transfer. Subject to the approval of any GB Segment Lender then foreclosing on Great Basin's
assets (including any deed-in-lieu of foreclosure) under the GB Segment Financing Agreements
with the Great Basin Lenders, Great Basin shall Transfer all of the Applicable Centennial Phase 3
Rights to NPC free and clear of any Liens other than Permitted Liens within fifteen(15)days after
the later of the receipt of such notice and receipt of PUCN Approval and all required Governmental
Approvals on terms acceptable to NPC, and Great Basin shall make Applicable Transfer
Representations and Warranties in connection with such Transfer.
ARTICLE VII
OPERATION OF THE TRANSMISSION LINE
7.01 Transmission Line Operation; ON Line Maintenance.
(a) One or both of the NVE Parties shall be the Operator of the
Transmission Line and have sole responsibility for the performance of all Operating Activities and
Capital Repairs, including all activities reasonably necessary or advisable in connection with the
management, operation and maintenance of ON Line, the administration of the ON Line
Agreements and the operation of the Great Basin Segments. Notwithstanding anything in this
Agreement to the contrary, the NVE Parties shall have sole discretion over the performance of the
Operating Activities, subject to (i) Prudent Utility Practices (including any Electric Reliability
Organization requirements),(ii)Governmental Approvals for the Transmission Line(or applicable
portion thereof) and(iii) Applicable Law. Subject to Sections 3.09(c) and 10.02, the NVE Parties
are solely responsible for Operating Costs,and the NVE Parties shall reimburse Great Basin within
thirty(30) days after receipt of an invoice from Great Basin for Operating Costs that Great Basin
incurs in the performance of Operating Activities for ON Line undertaken in response to a request
from NPC or the Management Committee; provided, however, that Great Basin shall not be
entitled to be reimbursed for any of the following: (i) any lobbying costs, (ii) any legal fees
associated with Great Basin's participation in regulatory proceedings where such participation has
not been approved in advance by the Management Committee, (iii) any gift of items, money or
entertainment in connection with ON Line, including political or campaign contributions, (iv)
third-Person costs, expenses and fees for lawyers, other consultants, financing parties and agents
incurred by Great Basin in connection with the ON Line Financing (including application and
other fees and expenses in connection with any loan guarantee or other program provided by the
U.S. Department of Energy) and the costs associated with Great Basin's auditing and reporting
requirements under this Agreement and the ON Line Financing Agreements, (v) costs and
expenses incurred in the preparation, negotiation, execution or delivery of this Agreement, (vi)
any amounts attributable to general administrative costs or overhead costs not associated with
direct internal labor for employees directly engaged in the performance of Operating Activities,
(vii) any amounts incurred by Great Basin in connection with the Great Basin Segments or (viii)
any interest or costs associated with carrying such costs and expenses. Great Basin shall be solely
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responsible for Great Basin O&M Costs, including any such costs incurred by any NVE Party in
its role as Operator of the Great Basin Segments, and Great Basin shall reimburse the NVE Parties
within thirty(30) days after receipt of an invoice from the NVE Parties for any costs incurred by
any NVE Party in performing its duties as Operator of the Great Basin Segments.
(b) At least six(6)months prior to the anticipated ON Line COD, as set
forth in the ON Line Schedule, and thereafter at least ninety(90)days prior to each anniversary of
the ON Line COD,the NVE Parties shall prepare and submit an annual Operating Plan and Capital
Repair Budget for the Management Committee's review and discussion,but(only with respect to
the Operating Plan) not approval. Within two (2) months after receipt of such proposed initial
Capital Repair Budget, and within thirty(30) days after receipt of each subsequent Capital Repair
Budget, the Management Committee shall adopt or reject such Capital Repair Budget. If the
Management Committee rejects the proposed Capital Repair Budget, then the Management
Committee and the NVE Parties will work together in good faith to seek to adopt an agreed Capital
Repair Budget, as applicable,within four(4)months after the original receipt of the initial Capital
Repair Budget, and within sixty (60) days after the original receipt of each subsequent Capital
Repair Budget.
(c) At least six (6) months prior to the anticipated GB Segment
Financial Closing,the NVE Parties shall submit to Great Basin an indicative estimate of the annual
costs and expenses to be incurred by the NVE Parties to operate the Great Basin Segments. At
least six (6) months prior to the anticipated date of commercial operation of each Great Basin
Segment, and thereafter at least ninety (90) days prior to each anniversary of the commercial
operation date of each Great Basin Segment, the NVE Parties shall prepare and submit an annual
Operating Plan for the Management Committee's review and discussion,but not approval.
7.02 Great Basin Segment Maintenance. Great Basin shall be solely responsible
for the maintenance of the Great Basin Segments and shall cause such Great Basin Segments to be
maintained and used in accordance with (a) Prudent Utility Practices (including any Electric
Reliability Organization requirements), (b) Governmental Approvals for the Transmission Line
(or applicable portion thereof)and(c)Applicable Law,and Great Basin shall be solely responsible
for any Great Basin O&M Costs. In order to enable the NVE Parties to monitor and operate the
Great Basin Segments, Great Basin shall provide, at the request of the NVE Parties, its annual
maintenance and proposed outage schedules for its facilities; provided, that Great Basin's
provision of such schedules shall not constitute acceptance or approval by the NVE Parties of such
schedules.
7.03 Operational and Maintenance Standards.
(a) The NVE Parties shall cause the Transmission Line to be operated,
and ON Line to be maintained, in accordance with (i) Prudent Utility Practices (including any
Electric Reliability Organization requirements),(ii)Governmental Approvals for the Transmission
Line (or applicable portion thereof) and(iii)Applicable Law.
(b) The NVE Parties may, in accordance with the following provisions,
direct the other Parties to interrupt or reduce deliveries of electrical power on the Transmission
Line (i) when necessary in order to maintain, repair, replace, remove, investigate, inspect or test
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any part of the Transmission Line or any meters for the Transmission Line, (ii) if the NVE Parties
determine, in their sole discretion, that interruption or reduction is necessary for safety or
emergencies or reasonably conclude that the energy delivered to or transmitting on the
Transmission Line does not conform to Prudent Utility Practices or this Agreement or jeopardizes
the integrity or use of the transmissions system or Transmission Line or (iii) if it is otherwise
required to do so in accordance with Electric Reliability Organization requirements. With respect
to any interruption or reduction of deliveries of electrical power pursuant to clauses (i)-(iii) of the
preceding sentence,the NVE Parties shall limit the length of any such interruption or reduction to
that time reasonably necessary to correct the problem or comply with the Electric Reliability
Organization requirements, as applicable. In any of these events, the curtailment shall be
accomplished in proportion to each Party's Capacity Entitlement and/or use, as applicable, on the
Transmission Line, except where curtailing in such a manner is not consistent with Prudent Utility
Practices. Each Party shall promptly effect such interruption in, or reduction of, delivery as the
NVE Parties shall direct pursuant to this Section 7.03(b)upon notice from the NVE Parties. In the
event notice is impracticable or a Party fails to promptly comply therewith, the NVE Parties may
effect the same by direct action. If any NVE Party becomes aware that a Party is using the
Transmission Line in excess of its Capacity Entitlement or its rights to Fiber Optic Capacity or
Microwave Capacity as set forth in Section 3.03, then the NVE Parties shall have the authority to
cause the excess usage to be curtailed.
(c) Notwithstanding anything to the contrary in this Agreement, any
Party may subcontract any or all of its maintenance obligations under this Article VII to an
Independent Contractor pursuant to a Maintenance Agreement;provided,however,that(i)no such
agreement shall relieve such Party from its obligations under any related provisions of this
Agreement and(ii) such Independent Contractor is reasonably acceptable to the other Parties.
7.04 Balancing Authority; Balancing Authority Area. Subject to Section
16.02(e)(iii), the Transmission Line shall be within one or both of the NVE Parties' Balancing
Authority Area and one or both of the NVE Parties shall be the Balancing Authority for the
Transmission Line. Great Basin shall negotiate balancing area agreements with the NVE Parties
for the Great Basin Segments on terms and conditions reasonably acceptable to the Parties. Great
Basin shall reimburse the NVE Parties for any services provided pursuant to the Balancing
Authority Area Services Agreement in accordance with the requirements of such agreement.
7.05 Ancillary Services. Neither of the NVE Parties shall be required to provide
any Ancillary Services to Great Basin, except to the extent set forth in a separate agreement
(including any Balancing Authority Area Services Agreement) for the provision of such Ancillary
Services (if any)between NPC and Great Basin or SPPC and Great Basin, as applicable.
7.06 Transmission Losses. On and after the date of commercial operation of the
first Great Basin Segment to achieve commercial operation, losses on the Transmission Line
("Transmission Losses") shall be allocated as follows: (a) Transmission Losses on ON Line
associated with the NVE Parties' Capacity Entitlement on ON Line shall be calculated first, as if
the Great Basin Segments had not been built(i.e., line loading will be at a minimum 600MW) and
such losses will be borne solely by the NVE Parties; and (b) all subsequent or additional
Transmission Losses associated with the remaining Electrical Capacity over ON Line and over
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each of the Great Basin Segments, calculated individually, shall be borne on a pro rata basis by
the Parties based on their usage.
7.07 Dynamic Transfers. The NVE Parties shall consider, on a case-by-case
basis and in good faith, the implementation of dynamic schedules and pseudo-tie services that are
reasonably requested by Great Basin on behalf of generation interconnection customers directly
interconnecting to the Transmission Line that are utilizing some portion or all of Great Basin's
Capacity Entitlement.
ARTICLE VIII
MANAGEMENT COMMITTEE, PROJECT COMPANY
8.01 Management Committee.
(a) Composition. The Parties hereby establish the Management
Committee, which is and shall be composed of one (1) representative from the NVE Parties and
one(1)representative from Great Basin(each, a"Representative"). The Management Committee
will have general oversight over the development, construction, ownership and management of
ON Line. Each Representative shall have the right and authority to bind the Party or Parties it
represents. In addition, Great Basin shall designate an alternate to its Representative and the NVE
Parties shall designate an alternate to their Representative (each, an "Alternate Representative")
with the authority to serve in place of, and with the authority of, such Representative if such
Representative is absent from or not available to attend a Management Committee meeting. The
NVE Parties and Great Basin shall notify the other in writing of its Representative and Alternative
Representative within fifteen(15)days after the Effective Date. Each of Great Basin and the NVE
Parties may remove and replace its or their Representative or Alternate Representative
(collectively, its "Authorized Representatives") at any time,with or without cause and without the
approval of the other Parties,upon written notice to the other Parties. Each of Great Basin and the
NVE Parties shall promptly give written notice to the other Parties of any change in the business
address or business telephone of either of its or their Authorized Representatives. Each Authorized
Representative shall be an agent of the Party or Parties that designated such Authorized
Representative. Accordingly, (i) each Authorized Representative shall have power to act (or
refrain from acting) solely in accordance with the wishes of the Party or Parties that designated
such Authorized Representative, (ii) the acts of an Authorized Representative in respect of any
matter shall be deemed to be the acts of the Party or Parties that designated such Authorized
Representative and (iii)no Authorized Representative shall owe (or be deemed to owe) any duty
(fiduciary or otherwise)to any Party other than the Party or Parties that designated such Authorized
Representative. Each of Great Basin and the NVE Parties shall be responsible for the
compensation and expenses of its or their Authorized Representatives. Notwithstanding the
foregoing, no Authorized Representative, in such capacity, shall have the authority to amend,
waive,revise,modify or terminate this Agreement or any portion thereof, serve any notice alleging
breach of this Agreement, enter into, settle or otherwise dismiss any arbitration proceeding under
Section 19.02 or claim or accept a claim of Force Majeure as an excuse to performance under this
Agreement.
(b) Attendance. Each Party shall use reasonable efforts to cause its
Representative or Alternate Representative to attend each meeting of the Management Committee,
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and no Party shall withhold the presence or participation of its Representative or Alternate
Representative to prevent, delay or forestall decisions on matters under consideration by the
Management Committee. The Parties shall cause their respective Authorized Representatives not
to unreasonably withhold, condition or delay any actions of the Management Committee. A
reasonable number of other employees or agents of the Parties may attend meetings of the
Management Committee. Meetings may be conducted in person,by telephone or video conference
call, or by other means which permit an Authorized Representative of each Party to be verified
and to hear and be heard by the other Authorized Representative and which are acceptable to both
Authorized Representatives. Attendees who are not Representatives, or in the case that a
Representative is not in attendance, who are not the applicable Alternate Representative, shall be
identified at the commencement of such meeting and shall have no power to vote on any matters,
but may participate in discussions in accordance with the Management Committee's rules of order,
which may limit the amount of time that the employees or other agents may participate.
(c) Meeting; Notice. Unless the Parties agree otherwise, the
Management Committee shall meet as necessary or appropriate (i) but no less frequently than
monthly from the Effective Date until the commencement of the Operating Period and quarterly
thereafter and (ii) at special meetings called by any Party following five (5) Business Days' prior
written notice of such a special meeting to the other Party's Representative and so long as such
meeting is reasonable under the circumstances. The Chair of the Management Committee shall
provide written notice to the other Authorized Representatives stating the place (or means if by
telephone conference or other means), date and hour of each meeting of the Management
Committee, together with a detailed agenda for the meeting, not less than five (5) days before the
date of the meeting (unless such notice is waived by an Authorized Representative of each Party
either at the meeting or by written consent before or after the meeting). Any Party may submit an
item for inclusion on the agenda of any Management Committee meeting. Attendance of an
Authorized Representative of a Party at a meeting of the Management Committee shall constitute
a waiver of notification of the meeting by such Party.
(d) Rules. The Management Committee may adopt such rules of order,
policy statements and directives as it considers necessary or appropriate for the conduct of its
business and the exercise of its powers, none of which shall conflict with this Agreement or any
ON Line Agreement.
(e) Chair. The Representative of the NVE Parties shall serve as the initial
chairperson of the Management Committee (the "Chair"). Unless the Management Committee
decides otherwise,commencing on the first day of each calendar year following the Effective Date,
the Chair of the Management Committee shall rotate between (i) the Representative for the NVE
Parties and (ii) the Representative for Great Basin. The Chair shall be responsible for the
maintenance of minutes of each Management Committee meeting and the recordation of the results
of each vote taken and shall promptly provide a copy of such minutes and voting records to the
other Authorized Representatives. The Chair shall have no powers or duties other than those
specifically conferred by this Agreement, and shall have no voting or veto power in addition to the
right to vote as a Representative. In the absence of the Chair at any Management Committee
meeting, the applicable Alternative Representative shall be the Chair for such meeting.
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(f) Quorum and Voting. Except as provided in Section 16.02(c),
meetings of the Management Committee shall require a quorum consisting of(i) an Authorized
Representative of the NVE Parties and (ii) an Authorized Representative of Great Basin. If a
quorum is not present at the commencement of any meeting,the Chair will reschedule the meeting
to take place within the following ten (10) days and will give notice of such rescheduled meeting
to the Representatives and Alternate Representatives. If at two successive meetings following the
originally scheduled meeting a quorum is not present due to the same Party's Authorized
Representative not being present at such meetings,then,if such Party's Authorized Representative
is not present for the last such meeting, the attendance of the other Party's Authorized
Representative at such meeting shall constitute a quorum. Subject to Sections 8.01(f)and 16.02 c ,
all decisions of the Management Committee shall require the affirmative vote of(i) an Authorized
Representative of the NVE Parties and(ii) an Authorized Representative of Great Basin.
(g) Action by Written Consent. Any action which may be taken by the
Management Committee under this Agreement may be taken without a meeting if each
Representative and Alternate Representative is given prior notice in writing or by telephone or
facsimile transmission and a copy of the proposed consent, and a consent setting forth the action
taken is executed by (i) an Authorized Representative of the NVE Parties and (ii) an Authorized
Representative of Great Basin.
(h) Deadlocks. If the Authorized Representatives participating in a
meeting of the Management Committee are unable to reach agreement on a matter put to vote (a
"Deadlock"), the Parties shall attempt to resolve such Deadlock through negotiations of the
Authorized Representatives. If such Deadlock is not resolved within seven(7)days,the Deadlock
shall be referred to a panel consisting of a senior executive (President or Vice President) of each
Party with the authority to resolve the matter causing such Deadlock. Such panel shall convene
within seven (7) days after the expiration of the aforementioned seven (7)- day period and the
members of such panel shall attempt in good faith to promptly resolve such Deadlock.
Notwithstanding a Deadlock regarding the use of contingency in the ON Line Budget, the
Managing Party may utilize contingency in the ON Line Budget to fund any Critical Change Order.
(i) If a Deadlock occurs prior to ON Line Financial Closing and
the Parties are unable to achieve a resolution of such Deadlock within seventy-five (75)
days after the panel of senior executives has convened or ninety (90) days after the
Deadlock occurred, whichever occurs sooner, then any Party may elect to terminate this
Agreement pursuant to Section 11.03(a)(v).
(ii) If a Deadlock arises regarding the approval of any amount in
a Capital Repair Budget or any Capital Repair,the remainder of the Capital Repair Budget
approved shall take effect. Notwithstanding such Deadlock, the NPC may carry out
Critical Capital Repairs.
8.02 Non-Delegable Actions. Notwithstanding the delegation of authority
granted to the Parties in this Agreement, but subject to Sections 7.01(a) and 8.01 h ii , the
following actions shall be performed by, and shall require the affirmative approval of, the
Management Committee in accordance with the requirements of Section 8.01:
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(a) The adoption of, and modifications to, any Project Budget, including
the establishment of any reserve accounts;
(b) The submission of any initial application for any non-ministerial
Governmental Approval for ON Line, the application for renewal or material modification of any
such Governmental Approval or the acceptance of any such Governmental Approval or material
modification thereof;
(c) The selection of any Material Construction Contractor and any other
major contractor or vendor or any subcontractor to any major contractor or vendor (to the extent
the right to approve subcontractors of any such major contractor or vendor is granted to any Party
in the relevant ON Line Agreement);
(d) Finalization of the detailed design for ON Line, material
modifications to such design, modifications to such design that could be reasonably expected to
adversely affect the Electrical Capacity, Microwave Capacity or Fiber Optic Capacity or WECC
rating of the Transmission Line;
(e) The approval of, or modifications to, the ON Line Schedule;
(f) The execution, termination of, material amendment to, issuing a
material change order under, or waiver of a material provision of any ON Line Agreement or the
exercise of remedies under any ON Line Agreement;
(g) The initiation of litigation, arbitration or other dispute resolution
mechanism relating to ON Line under any ON Line Agreement or otherwise;
(h) The settlement of any litigation, arbitration or other dispute relating
to ON Line under any ON Line Agreement or otherwise or any insurance or warranty claims
relating to ON Line;
(i) The disposition of any ON Line assets (other than dispositions in the
ordinary course of business to Persons not Affiliated with the Parties of surplus or obsolete assets
having a value of less than one hundred thousand Dollars ($100,000));
0) The approval of any public announcements relating to ON Line,
except as set forth in Section 20.08(d);
(k) The adoption and implementation of the Insurance Plan and any
modifications thereto;
(1) The approval of the appointment of any ON Line Manager and any
replacement thereof,
(m) The determination to commence Wind-Up Events;
(n) The issuance of a notice to proceed or any completion or similar
certificate or the acceptance of any performance tests under any Material Construction Contract;
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(o) The decision to form or dissolve a Project Company and all decisions
with respect to the ownership and governance of such Project Company, except to the extent
governance is otherwise provided for in such Project Company's organizational documents; and
(p) The approval of community outreach and government relations
programs for ON Line.
8.03 Project Company.
(a) Organization. The Management Committee may cause the formation
of one or more limited liability companies (each, a "Project Company") in connection with the
development, construction or maintenance of ON Line. The organizational documents of any
Project Company shall be approved by the Management Committee. Any Project Company shall
be owned by the Parties in proportion to their respective Ownership Percentages.
(b) Duties. If so determined by the Management Committee, a Project
Company may, as agent for and on behalf of the Parties, (i) apply for or accept one or more
Governmental Approvals for ON Line, (ii) enter into one or more ON Line Agreements and (iii)
conduct such other activities as agent for, and on behalf of, the Parties, as the Management
Committee may determine.
(c) Disposition. Any disposition or acquisition of a Party's Ownership
Interests shall proportionally include such Party's interests in each Project Company.
8.04 Time is of the Essence. Time is of the essence with respect to all actions to
be taken by the Management Committee hereunder.
ARTICLE IX
REPORTING; RECORDKEEPING
9.01 Monthly/Quarterly Report. Once a month prior to the commencement of
the Operating Period and quarterly thereafter, on a schedule to be determined by the Management
Committee, the Managing Party prior to the Operating Period and NPC during the Operating
Period shall provide the Management Committee with a report(the"Monthly/Quarterly Report").
Each Monthly/Quarterly Report shall contain updates and all material issues with respect to ON
Line, except that the Managing Party or NPC, as applicable, shall not be required to include in any
Monthly/Quarterly report any information (i) the disclosure of which is prohibited by any
contractual agreement or legal or ethical obligation or company policy, (ii) about the finances or
business plans of any Party, that is publicly available, or that is proprietary or (iii) that is not
obtained by the Authorized Representatives of the relevant Parties in the performance of the ON
Line Activities or Operating Activities. Subject to the immediately preceding sentence, each
Monthly/Quarterly Report shall contain(a)prior to the Operating Period,updates and all material
issues with respect to the ON Line Activities, the status of the ON Line Schedule, ON Line Costs
compared to the ON Line Budget and any anticipated changes to or cost overruns with respect to
the ON Line Budget, and the progress of all ON Line Activities (including the negotiation of ON
Line Agreements, land rights acquisition, permitting, design, engineering and procurement, and
all other material issues related to the ON Line Activities),(b)during the Operating Period,updates
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and all material issues with respect to the Operating Activities, the status of the Operating Plan
and the operating status of ON Line (including Electrical Capacity, availability, forced outages,
safety statistics and outage status for planned outages) and(c) at any time, such other information
reasonably requested by any Party.
9.02 Notification of ON Line Events. Each Party shall promptly notify the
Management Committee and the other Parties of any Material Events that occur regarding ON
Line of which such Party has knowledge acquired by such Party in the performance of the ON
Line Activities or Operating Activities assigned to such Party under this Agreement(including any
event that could reasonably be expected to result in a milestone set forth in the ON Line Schedule
not being met); provided, however, that (a) such notification obligation shall not apply to
information (i) disclosure of which is prohibited by any contractual agreement or legal or ethical
obligation or company policy or (ii) about the finances or business plans of any Party, that is
publicly available,or that is proprietary and(b)for purposes of this Section 9.02,knowledge means
the actual knowledge of any of the Authorized Representatives of the relevant Parties obtained in
the performance of the ON Line Activities or Operating Activities.
9.03 Recordkeeping.
(a) Each Party shall keep and maintain proper books, records, accounts,
ledgers, estimates, invoices, schedules, correspondence and other documents (whether in physical
or electronic form) related to ON Line (collectively, the "Books and Records"), including
reasonably detailed records of ON Line Costs, each in conformity with any Applicable Laws and
GAAP. Each Party shall ensure that a Person with appropriate accounting experience is
responsible for maintaining its Books and Records. Each Party shall maintain its Books and
Records for at least seven(7) years, or such longer period required by Applicable Law, following
the creation thereof.
(b) Great Basin shall provide, and the ON Line Agreements shall require,
that ON Line contractors provide NPC with cost and accounting information in accordance with
GAAP with detail sufficient to allow the NVE Parties to comply with the Uniform System of
Accounts.
9.04 Inspection and Audit Rights. Each Party and its consultants shall have the
right,from time to time during the Term,to inspect and audit any other Party's Books and Records,
insofar as such Books and Records pertain to ON Line Costs. Each Party may undertake such
inspection or audit directly or through independent certified public accountants of its choice. Any
audit or inspection conducted by a Party shall be subject to reasonable notice, and shall be
conducted at reasonable times during the normal business hours of the applicable other Party and
unless otherwise agreed, at the offices of the applicable other Party. The costs of any such audit
shall be borne by the Party conducting the audit. Each Party acknowledges and agrees that the
making of any payment hereunder, including payments by a Party in respect of the Closing
Payment and the Monthly Payment, shall be without prejudice to the audit rights of each Party
hereunder.
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9.05 Information. Upon request from a Party, the other Parties, as applicable,
shall furnish information,data,records, certificates or documents related to the Transmission Line
as are required in order to comply with the requirements of any Governmental Authority.
9.06 Access to Financial Information. The Parties agree that GAAP and the rules
of the SEC require the NVE Parties to evaluate if they must consolidate Great Basin's financial
information. The NVE Parties shall have the right to request, access and copy Great Basin's
financial records and to access Great Basin's personnel, in each case, upon reasonable advance
notice and during regular business hours, in order to determine if consolidated financial reporting
is required. If the NVE Parties and their independent auditor reasonably determine that such
consolidation is required (as confirmed in a letter provided to Great Basin by the NVE Parties),
the NVE Parties may require that Great Basin deliver within a reasonable period of time the
following during each applicable fiscal quarter for the Term: (a) either (i) unaudited financial
statements of Great Basin on an interim quarterly basis and audited financial statements of Great
Basin on an annual basis, including notes with respect to annual audited financial statements or
(ii) unaudited financial statements of Great Basin on an interim quarterly basis and annually if
annual audited financial statements are not otherwise available, (b) financial schedules underlying
the financial statements needed to comply with GAAP disclosure requirements and (c) a
certificate, duly executed by an authorized officer of Great Basin, stating that the financial
statements provided hereunder are materially true and correct representations of Great Basin for
the relevant period and have been prepared in accordance with GAAP, as applicable to Great
Basin. It is understood that Great Basin shall not under any circumstances, solely as a result of this
Agreement, be required by the NVE Parties to comply with SEC rules or the Sarbanes Oxley Act
of 2002 or any successor legislation, in each case, beyond the express obligations of Great Basin
set forth in this Agreement.
ARTICLE X
TAXES AND ASSESSMENTS
10.01 Management of Tax Matters. Except for any payments of Personal Taxes
or payments in lieu thereof which are directly billed to a Party by any taxing authority and which
a Party shall pay directly, and subject to the oversight of the Management Committee, the
Managing Party prior to the Operating Period and NPC during the Operating Period shall have the
authority and responsibility for administering, coordinating, filing returns, making property tax
declarations, paying, seeking official tax rulings or determinations, and other related functions
pertaining to all taxes, payments in lieu of taxes, assessments, impositions, charges, and related
costs of every kind and nature, ordinary, or extraordinary, general or special, foreseen or
unforeseen, settled or pending settlement connected with or arising out of the development,
construction, ownership, operation, maintenance, alteration, repair, rebuilding, use or retirement
of ON Line or any part thereof,including sales taxes and excise taxes(collectively"Taxes")which
are or may be imposed by any Governmental Authority;provided,however,that unless specifically
authorized in writing by the Parties, such authority shall not extend to any act or action affecting
any exemption from Taxes or special tax treatment arising out of ON Line to which one Party may
be entitled on a basis that is different from the other Parties. As used herein, the term "Taxes"
shall not include any taxes associated with the Great Basin Segments or net income taxes or
franchise taxes relating to ON Line that are assessed or imposed against any Party (collectively,
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"Personal Taxes"), the payment of which is and shall remain the responsibility of any such Party
so assessed or on whom imposed. Each Party may contest the validity or amount of any Personal
Taxes, in each case provided that the contested Personal Taxes shall not remain unpaid for such
length of time as shall permit any part or all of ON Line to be sold or foreclosed or any interest of
any Party therein to be subject to a Lien for the nonpayment of the same.
10.02 Sharing of Taxes and Related Payments. All Taxes whether Pre-Closing
Costs, Post-Closing Costs or Operating Costs, as applicable, after the Acquisition Closing Date,
shall be shared and borne by the Parties in proportion to their respective Ownership Percentages;
provided, however, that to the extent that the aggregate amount of the Taxes are reduced because
a Party is entitled to specific tax benefits resulting from its status apart from ON Line, such Party
shall be entitled to the entire benefit, to the extent of actual realization, of any exemptions from
and reductions of Taxes connected with or arising out of the ownership, operation, maintenance,
alteration,repair,rebuilding,use or retirement of ON Line or any part thereof. Unless agreed upon
by the Parties, in no event shall a Party entitled to any exemption or reduction in Taxes be liable,
directly or indirectly, for any payment in lieu of taxes that any other Party has agreed to make.
Further, it is the express intention of the Parties that, for Federal income tax purposes, (a) Great
Basin be treated as the owner of an undivided ownership interest in ON Line equal to its Ownership
Percentage, (b)NPC be treated as the owner of an undivided ownership interest in ON Line equal
to its Ownership Percentage and (c) SPPC be treated as the owner of an undivided ownership
interest in ON Line equal to its Ownership Percentage, with each Party entitled to the respective
tax benefits attributable thereto.
10.03 Payment of Taxes. Subject to Section 10.02, the Managing Party prior to
the Operating Period and NPC during the Operating Period shall be responsible for paying and
discharging all Taxes imposed by any Governmental Authority before the same become
delinquent, except (a)those that are directly billed to a Party by any taxing authority and which
such Party is responsible to pay directly and(b) those subject to a good faith contest and for which
appropriate reserves have been established in accordance with GAAP.
10.04 Non-Creation of Taxable Entity. Notwithstanding any other provision of
this Agreement, the Parties do not intend to create hereby at law any joint venture, partnership,
association taxable as a corporation,trust, limited liability company or other entity for the conduct
of any business for profit. The Parties agree to timely elect under Section 761(a) of the Code to
exclude the transactions created by this Agreement from the application of Subchapter K,
Chapter 1 of the Code, and the Parties agree to revise the terms of this Agreement to the extent
and in a manner necessary to permit such election. If it is ultimately determined by an appropriate
taxing authority that this Agreement is not eligible for an election out of Subchapter K, Chapter 1
of the Code, then the Management Committee shall make all Federal and state income Tax
elections. Each Party agrees to report on such Party's separate return in a manner consistent with
such exclusion election any items of revenue and expenditure attributable to such Party's share of
any revenue received and any expenditures made under this Agreement.Nothing in this Agreement
will be construed as an undertaking by any Party to jointly sell any electrical transmission or other
services or property. Each Party agrees to execute and deliver such additional documentation,
including the statement required by Treasury Regulation 1.761-2(b)(2), as may be required from
time to time to effect such exclusion to the extent permitted by law.
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10.05 Transfer Taxes. Each Party shall be responsible for the timely payment of,
and shall indemnify and hold harmless each other Party from and against,its respective Ownership
Percentage (as existing immediately prior to such Transfer) of all transfer taxes (excluding taxes
measured in whole or in part by net income), including sales, use, excise, stock, stamp,
documentary, filing,recording,permit,license,authorization and similar taxes, fees,duties,levies,
customs,tariffs, imposts, assessments, obligations and charges (collectively, "Transfer Taxes") (if
any) arising out of or in connection with the transactions contemplated by this Agreement related
to ON Line;provided,however,that in connection with a Transfer(a)pursuant to Section 16.02(d)
or ft then the defaulting Party shall be responsible for one hundred percent (100%) of any
Transfer Taxes resulting therefrom, (b) pursuant to Section 15.02(a), then each Party shall be
responsible for Transfer Taxes in accordance with the terms of the ROFR Offer Notice, (c) to a
third Person, such Transfer Taxes shall be borne one hundred percent(100%)by the Transferring
Party, (d) pursuant to Sections 15.03(e) or ft such Transfer Taxes shall be borne one hundred
percent (100%) by Great Basin, (e) pursuant to Section 15.03(g) between Great Basin and its
Affiliates or among the Affiliates of Great Basin, such Transfer Taxes shall be borne one hundred
percent(100%)by Great Basin, (f)pursuant to Sections 15.03(a)or(d), such Transfer Taxes shall
be borne one hundred percent (100%) by the NVE Parties and (g) pursuant to Section 15.03(g)
(but only with respect to a Transfer to the NVE Parties), such Transfer Taxes shall be shared
equally by Great Basin, on the one hand, and the NVE Parties, on the other hand. Each Party shall
prepare and file all necessary documentation and tax returns with respect to such Transfer Taxes,
and each Party shall cooperate with each other Party and take any action reasonably requested by
each other Party,which does not cause the non-requesting Party to incur any cost or inconvenience,
in order to minimize such Transfer Taxes. For the avoidance of doubt, any Taxes (including
Transfer Taxes) payable in connection with the procurement of assets from third parties in
connection with the construction, maintenance, repair and/or replacement of ON Line (or any
portion thereof) shall be treated as Development Costs, Pre-Closing Costs, Post-Closing Costs
and/or Capital Repair Costs, as applicable, and shall not be subject to this Section 10.05.
10.06 Duties Regarding Assessments. With respect to property Taxes,the Parties
will use their reasonable best efforts to have any taxing or other Governmental Authority levying
any such Taxes or payments in lieu thereof, or making any valuations of ON Line (or any portion
thereof) for the purpose of levying any such Taxes or payments in lieu thereof or any beneficial
interest or rights therein, assess and levy such Taxes or payments in lieu thereof directly against
the Ownership Interest of each Party. All such Taxes or payments in lieu thereof levied against
each Party's Ownership Interest, excepting those Taxes or payments in lieu thereof levied against
an individual Party on behalf of any other Party, will be the sole responsibility of the Party upon
whose Ownership Interest such Taxes or payments in lieu thereof are levied. If any property Taxes
or payments in lieu thereof,are levied or assessed in a manner other than as specified in this Section
10.06, or if an individual Party is levied or assessed on behalf of ON Line or any other Party, the
Management Committee will establish equitable practices and procedures for the apportionment
among the Parties of such Taxes or payments in lieu thereof.
10.07 Periodic Payments. The Parties shall account for Monthly Payments for
Federal income tax purposes in accordance with the allocation of such payments in Section 3.06.
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ARTICLE XI
TERM AND TERMINATION
11.01 Term. Unless the Parties agree otherwise, the term of this Agreement (the
"Term") shall commence on the Effective Date and, unless earlier terminated in accordance with
the provisions of this Agreement, continue until the retirement from service of the Transmission
Line and the Wind-Up Events have been completed, including the payment of all costs associated
with the Wind-Up Events and the distribution of any proceeds of the sale of ON Line's assets in
accordance herewith (the date of such retirement and completion or earlier termination being
referred to herein as the "Termination Date").
11.02 Winding-Up. On the retirement of ON Line from service, the Parties shall
promptly wind-up ON Line in accordance with this Section 11.02 and termination of this
Agreement shall not be effective until the provisions of this Section 11.02 have been satisfied.
(a) All costs and payments (less salvage credits, if any) associated with
the retirement of ON Line (including the Wind-Up Events) shall be shared by the Parties in
proportion to their respective Ownership Percentages.
(b) In connection with winding-up ON Line,the Parties shall perform the
following actions (the "Wind-Up Events"):
(i) Dismantling, demolishing and removing ON Line
equipment, facilities and structures (including the cost of transportation and handling
incidental thereto);
(11) Terminating any ON Line Agreement in accordance with the
terms thereof;
(iii) Securing, maintaining and disposing of debris with respect
to ON Line;
(iv) Performing any activities necessary to comply with
Applicable Law and Prudent Utility Practices and that are otherwise prudent to retire ON
Line and protect the Parties from liability;
(v) Remedying and restoring the ON Line ROW; and
(vi) Directly or through agents,brokers or other Persons selected
by the Management Committee (A) timely disposing of any remaining assets of ON Line
by sale, auction, partition or otherwise, (B) depositing any proceeds of the disposition of
assets of ON Line in a new bank account, and (C) undertaking other necessary steps for
the winding-up of ON Line, including disbursing of any balance remaining in the account
referenced in clause (B) above, to the Parties in proportion to their respective Ownership
Percentages.
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(c) Commencing thirty-five (35) years after the Effective Date, each
Party shall establish and maintain a depositary account on terms reasonably acceptable to the other
Parties (each, a "Wind-Up Reserve Account"); provided, that if, on the thirty-fifth (35th)
anniversary of the Effective Date, the remaining useful life of ON Line is reasonably estimated to
be in excess of seventeen (17) years, the Parties shall delay the establishment of the Wind-Up
Reserve Account until a date that is reasonably estimated to be seventeen (17) years prior to the
expiration of the useful life of ON Line. Simultaneously with the establishment of each Wind-Up
Reserve Account, and each subsequent year thereafter, the Party establishing such account shall
deposit an amount in its Wind-Up Reserve Account equal to (i) (A) such Party's Ownership
Percentage of the current estimated costs to implement the Wind-Up Events, as determined by the
Management Committee (on an annual basis) less (B) the amount on deposit in the Wind-Up
Reserve Account;divided by(ii)the estimated number of years,as determined by the Management
Committee (on an annual basis), until commencement of the Wind-Up Events. Each Party may
draw on the amounts deposited in its Wind-Up Reserve Account to fund its Ownership Percentage
of the costs to implement the Wind-Up Events. Each Party may draw on the amounts deposited
in the Wind-Up Reserve Accounts set up by any other Party to fund any such other Party's share
of costs incurred in respect of the Wind-Up Events to the extent such costs are not paid by any
such other Party. After completion of the Wind-Up Events, any amounts remaining in a Wind-Up
Reserve Account shall be paid to the Party establishing such account. If a Party does not have an
Investment Grade Credit Rating on or at anytime after the later of (x) the thirty-fifth (35th)
anniversary of the Effective Date, and (y) the date that is seventeen (17) years prior to the
expiration of the useful life of ON Line,such Party shall grant a security interest to the other Parties
in all of the right, title and interest in, to and under such Party's Wind-Up Reserve Account, in
form and substance acceptable to the other Parties, which security interest shall be maintained in
full force and effect at all times thereafter until such Party obtains an Investment Grade Credit
Rating;provided,however,that(1) any such security requirements impacting Great Basin shall be
subject to the rights of the GB Segment Lenders and (2) in the case of Great Basin's Wind-Up
Reserve Account, such security interest may only be subordinated to (i) any ON Line Lender and
(ii) Excluded Liens arising by operation of law after such security interest is granted and required
by Applicable Law to be senior to such security interest and, in the case of the Wind-Up Reserve
Accounts of the NVE Parties, such security interest may only be subordinated to (A) any NVE
Lender and (B) Excluded Liens arising by operation of law after such security interest is granted
and required by Applicable Law to be senior to such security interest.
11.03 Termination.
(a) Prior to the Acquisition Closing, this Agreement may only be
terminated by(i)mutual written agreement of the Parties, (ii)any Party, if Acquisition Closing has
not occurred by or on the Acquisition Closing Deadline; provided, however, that a Party may not
terminate this Agreement pursuant to this Section 11.03(a)(ii) if such Party has failed to comply
with its obligations hereunder and such failure resulted in the Acquisition Closing not occurring
on or by the Acquisition Closing Deadline, (iii) any Party, if any Governmental Authority shall
have issued a final, non-appealable order preventing the consummation of Acquisition Closing,
(iv)any non-defaulting Party, in the event of an Event of Default under Section 16.01(f)or, if such
termination occurs prior to ON Line Financial Closing, any other Event of Default, in each case,
if such Event of Default is continuing at the time notice to terminate is provided to the defaulting
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Party, (v) any Party, upon the occurrence of the event described in Section 8.01(h)(i) if such
termination occurs prior to ON Line Financial Closing, (vi) any Party, upon the occurrence of an
event that could reasonably be expected to have a Material Adverse Effect if such termination
occurs prior to ON Line Financial Closing, and(vii) Great Basin, if it has not received acceptable
terms for the ON Line Financial Closing by the Acquisition Closing Deadline. If this Agreement
is terminated pursuant to this Section 11.03(a), without prejudice to any other rights or remedies
any Party may have under this Agreement or Applicable Law or in equity as a result of such
termination or the underlying facts thereof and subject to Section 20.10, (1) neither of the NVE
Parties shall have any further interest in the Transmission Line, (2)this Agreement shall forthwith
become of no further force or effect and become void and(3)there shall be no liability or obligation
hereunder on the part of any Party or any of their respective Affiliates.
(b) After the Acquisition Closing, no Party may terminate this
Agreement, except that upon consummation of an acquisition by one Party(or by the NVE Parties
together) of all of the Ownership Interests prior to GB Segment Financial Closing or the
consummation of an acquisition prior to the Capacity Entitlement adjustment contemplated by
Section 3.02(b) by the NVE Parties of all of Great Basin's Ownership Interests under Section
3.07(a) as a result of Great Basin not achieving GB Segment COD before the GB Segment COD
Deadline, without prejudice to any other rights or remedies any Party may have under this
Agreement or Applicable Law or in equity as a result of such termination or the underlying facts
thereof and subject to Section 20.10, this Agreement may be terminated by any Party and upon
such termination this Agreement shall forthwith become of no further force or effect and become
void, and there shall be no liability or obligation hereunder on the part of any Party or any of their
respective Affiliates.
(c) Except as provided in Section 11.03(b), if-
(i) the NVE Parties purchase all of Great Basin's Ownership
Interests, then, unless agreed otherwise by the Parties, upon consummation of such
purchase (A) the following provisions shall cease to be of further force or effect: (1)
Sections 3.01(c), 3.06, 3.07, 3.08, 3.09, 11.02, 16.02 c , 16.02 e i and 16.02 and (2)
except as provided in clause (B) below, Articles II, IV, V VIII, IX (other than Section
9.05),XIII and XIV and(B) Sections 6.04, 7.02, 13.06 and 14.06 shall be hereby amended
such that the NVE Parties have reciprocal obligations regarding ON Line as Great Basin
has with respect to the Great Basin Segments (it being understood that any notice under
such Sections will be given to the Parties and not the Management Committee).
(ii) Great Basin purchases all of the NVE Parties' Ownership
Interests, then, unless agreed otherwise by the Parties, upon consummation of such
purchase (A) the following provisions shall cease to be of further force or effect: (1)
Sections 3.01(c), 3.07, 3.08, 3.09, 11.02, 16.02 c , 16.02 e i and 16.02 and(2) except
as provided in clause(B)below,Articles II,IV,V,VIII, IX(other than Section 9.05),XIII
and XIV, (B) Sections 6.04, 7.02, 13.06 and 14.06 shall be hereby amended such that
Great Basin has the same obligations with respect to ON Line as it has with respect to the
Great Basin Segments in such sections (it being understood that any notice under such
Sections will be given to the Parties and not the Management Committee) and (C) Great
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Basin shall be responsible for all Operating Costs and Capital Repair Costs arising after
the consummation of such purchase.
(d) Nothing in this Section 11.03 shall (i) relieve or release any Party of
any liability or damages arising out of such Party's breach of any provision of this Agreement
prior to the effectiveness of the termination or(ii) impair the right of any Party to compel specific
performance by another Party or the other Parties, as the case may be, of such Party's obligations
under this Agreement to the extent that such obligations have not become void and of no further
force or effect as a result of the termination.
ARTICLE XII
INDEMNIFICATION; LIMITATION OF LIABILITY
12.01 Indemnification.
(a) Agreements to Indemnify. Subject to Sections 12.03 and 12.04, each
Party, to the maximum extent permitted by Applicable Law, shall defend, protect, indemnify and
hold each other Party, its Affiliates and their respective officers, directors, employees and agents
("Indemnified Persons") harmless from and against any and all Claims resulting from, arising out
of or in connection with(i)the gross negligence, intentional misconduct or fraudulent acts of such
Party, its Affiliates or its or their respective officers, directors, employees or agents, arising in
connection with this Agreement or the Transmission Line,(ii)such Party's breach of any provision
of this Agreement, (iii)the Personal Taxes of such Party and(iv)subject to Section 18.01(a), Liens
in respect of an obligation of such Party that are placed on the Ownership Interests or other
property of an Indemnified Person. Each Party shall use reasonable efforts to include in its Open
Access Transmission Tariff an indemnity from such Party's customers for the benefit of the Parties
that is consistent with the indemnity provided by such Party's customer to such Party; provided,
however, that to the extent that such an indemnity has not been included or is ineffective (and
except for Claims resulting from Willful Misconduct/Gross Negligence of a Party),NPC and Great
Basin shall, to the maximum extent permitted by Applicable Law, defend, protect, indemnify and
hold, in the case of NPC, Great Basin and, in the case of Great Basin,the NVE Parties and, in each
case their respective Indemnified Persons harmless from and against any Claims by such non-
indemnifying Party's electric, transmission and other customers resulting from, arising out of or
in connection with the delivery of, interruption to or curtailment of electric, transmission or other
service caused by the failure of the indemnifying Party to properly, in the case of NPC, operate
the Transmission Line and maintain ON Line and, in the case of Great Basin, maintain the Great
Basin Segments; provided, further, however, that in no event shall the liability of Great Basin, or
the liability of the NVE Parties collectively, pursuant to this sentence exceed ten million Dollars
($10,000,000) in the aggregate for any Claims arising in any three-year period.
(b) Conduct of Claims. Each Indemnified Person shall, promptly after
the receipt of notice of any Claim against such Indemnified Person in respect of which
indemnification may be sought pursuant to this Section 12.01, notify any other Party from whom
it seeks indemnity ("Indemnifyin PgartX") of any such Claim. No Indemnifying Party shall be
obligated to indemnify such Indemnified Person with respect to any such Claim if such
Indemnified Person fails to notify the Indemnifying Party thereof in accordance with the provisions
of this Section 12.01(b) in sufficient time to permit the Indemnifying Party to defend against any
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such Claim and to make a timely response thereto, including any responsive motion or answer to
a complaint,petition,notice or other legal, equitable or administrative process relating to any such
Claim, but only insofar as such failure to notify the Indemnifying Party has actually resulted in
material prejudice or damage to the Indemnifying Party. In case any Claim shall be made or
brought against an Indemnified Person, the Indemnifying Party may, or if so requested by such
Indemnified Person shall, assume the defense thereof with competent counsel of its selection to
defend such Indemnified Person. In such circumstances, such Indemnified Person shall (i) at no
cost or expense to such Indemnified Person, cooperate with the Indemnifying Party and provide
the Indemnifying Party with such information and assistance as the Indemnifying Party shall
reasonably request in connection with any such Claim and(ii) at its own cost and expense (unless
a conflict would exist if the same counsel represented both the Indemnifying Party and the
Indemnified Party or the Indemnified Party is or may be reasonably expected to be exposed to
criminal liability, in which case the Indemnifying Party shall pay the cost and expense of separate
counsel for the Indemnified Party), have the right to participate and be represented by counsel of
its own choice with respect to any such Claim.
(c) Defense of Claims. If the Indemnifying Party assumes the defense of
the relevant Claim, (i) the Indemnifying Party shall not be liable for any settlement thereof that is
made without its written consent and (ii)the Indemnifying Party shall control the settlement of
such Claim;provided,however,that the Indemnifying Party shall not conclude any settlement that
requires any action or forbearance from action or payment or admission by the Indemnified Person
or any of its Affiliates without the prior written approval of the Indemnified Person. The
obligations of an Indemnifying Party shall not extend to any loss, damage or expense of whatever
kind and nature (including all related costs and expenses)to the extent the same results from, after
the receipt of notice of a Claim against an Indemnified Person, the taking by the Indemnified
Person of any action (unless required by Applicable Law or applicable legal process) which
prejudices the successful defense of such Claim, without, in any such case, the prior written
consent of the Indemnifying Party (such consent not to be required in a case where the
Indemnifying Party has not assumed the defense of such Claim). The Indemnified Person shall
afford the Indemnifying Party and its counsel the opportunity to be present at, and to participate
in, conferences with all Persons, including Governmental Authorities, asserting any Claim against
the Indemnified Person covered by the indemnities contained in this Section 12.01 or conferences
with representatives of, or counsel for, such Indemnified Person held in connection with such
indemnities.
(d) Any Claim indemnified against pursuant to this Section 12.01 shall
be net of,but not limited to, any tax benefit actually recognized by an Indemnified Person and any
Insurance Proceeds.
12.02 Contribution of Parties. Except as otherwise expressly set forth herein, if,
after the Acquisition Closing Date, a Party bears more than its Ownership Percentage of any
liability or obligation arising in connection with ON Line (other than any liability or obligation
arising (a) under an Excluded Agreement, (b) from a Party's business activities that are
independent of ON Line and not attributable to ON Line or(c)that is to be borne in a manner other
than in accordance with Ownership Percentages by the express terms of this Agreement) and such
Party would not be required to indemnify any other Party under this Agreement for any Claim
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related to such liability or obligation(a"Shared Liability"),the other Parties(proportionally based
on their respective Ownership Percentages) shall reimburse the Party that incurred the Shared
Liability within ten(10) Business Days after written demand therefor, to the extent of such excess
so that the Parties bear that liability or obligation in proportion to their respective Ownership
Percentages. No Party shall have the right to settle or compromise any Claim with respect to a
Shared Liability without the written approval of each other Party. For the avoidance of doubt,this
Section 12.02 shall not require the NVE Parties to make payments for costs or expenses attributable
to the Great Basin Segments.
12.03 Waiver of Damages.
(a) EXCEPT FOR DAMAGES PAID TO THIRD PERSONS TO
WHICH AN INDEMNITY OR CONTRIBUTION OBLIGATION UNDER SECTIONS
12.01 OR 12.02 APPLIES, IN NO EVENT, WHETHER BASED ON CONTRACT,
INDEMNITY,WARRANTY, STATUTE, TORT (INCLUDING NEGLIGENCE), STRICT
LIABILITY OR OTHERWISE, SHALL ANY PARTY BE LIABLE FOR SPECIAL,
INCIDENTAL, EXEMPLARY, INDIRECT, PUNITIVE, OR CONSEQUENTIAL
DAMAGES, INCLUDING LOSS OF PROFITS OR REVENUE, LOSS OF USE OF THE
TRANSMISSION LINE OR ANY ASSOCIATED EQUIPMENT, COST OF CAPITAL,
COSTS IN EXCESS OF ESTIMATES, COST OF PURCHASED POWER OR
TRANSMISSION, COST OF SUBSTITUTE EQUIPMENT,FACILITIES OR SERVICES,
DOWNTIME COSTS OR CLAIMS OF CUSTOMERS OR LENDERS. THE
LIMITATIONS HEREIN IMPOSED ON REMEDIES AND THE MEASURE OF
DAMAGES SHALL BE WITHOUT REGARD TO THE CAUSE OR CAUSES RELATED
THERETO, INCLUDING THE NEGLIGENCE OF ANY PARTY. FOR THE
AVOIDANCE OF DOUBT, NOTHING IN THIS SECTION 12.03(a) SHALL IN ANY
MANNER LIMIT OR OTHERWISE RESTRICT (i) THE OBLIGATION OF THE NVE
PARTIES TO PAY THE MONTHLY PAYMENT IN ACCORDANCE WITH SECTION
3.06 OR (ii) A PARTY FROM COLLECTING ANY AMOUNT VALIDLY OWING
UNDER AND CALCULATED IN ACCORDANCE WITH SECTIONS 2.02(e), 5.07,
16.02(d),Lej,W AND (h),AND 16.04.
(b) IN NO EVENT SHALL THE MANAGING PARTY (IN
RESPECT OF ON LINE), EITHER NVE PARTY (IN RESPECT OF THE
TRANSMISSION LINE) OR GREAT BASIN (IN RESPECT OF THE GREAT BASIN
SEGMENTS) BE LIABLE UNDER THIS AGREEMENT FOR ANY LOSS OR DAMAGE
WHATSOEVER ARISING FROM THE FAILURE TO DISCOVER DEFECTS
INHERENT IN THE DESIGN OF ON LINE OR THE EQUIPMENT COMPRISING ON
LINE(IN THE CASE OF THE MANAGING PARTY OR EITHER NVE PARTY)OR THE
GREAT BASIN SEGMENTS OR THE EQUIPMENT COMPRISING THE GREAT BASIN
SEGMENTS (IN THE CASE OF GREAT BASIN OR EITHER NVE PARTY).
(c) EXCEPT FOR ANY JUDGMENT DEBT FOR DAMAGE
RESULTING FROM WILLFUL MISCONDUCT/GROSS NEGLIGENCE OR EXCEPT
TO THE EXTENT ANY JUDGMENT DEBT IS COLLECTIBLE FROM INSURANCE
PROCEEDS, NONE OF THE MANAGING PARTY (IN ITS CAPACITY AS SUCH),
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EITHER NVE PARTY (IN ITS CAPACITY AS OPERATOR OF THE TRANSMISSION
LINE, MAINTAINER OF ON LINE OR IN CONNECTION WITH ITS OBLIGATIONS
UNDER SECTIONS 13.04 AND 14.04) AND GREAT BASIN (IN ITS CAPACITY AS
MAINTAINER OF THE GREAT BASIN SEGMENTS OR IN CONNECTION WITH ITS
OBLIGATIONS UNDER SECTIONS 13.06 AND 14.06) SHALL BE LIABLE FOR ANY
CLAIMS WHETHER OR NOT RESULTING FROM SUCH PERSON'S NEGLIGENCE,
OR THE NEGLIGENCE OF ITS OFFICERS,DIRECTORS,EMPLOYEES OR AGENTS,
OR ANY PERSON OR ENTITY WHOSE NEGLIGENCE WOULD BE IMPUTED TO
SUCH PERSON, ARISING IN CONNECTION WITH THE PERFORMANCE OR NON-
PERFORMANCE OF ANY OF ITS OBLIGATIONS AS THE MANAGING PARTY, AS
THE OPERATOR OF THE TRANSMISSION LINE OR AS MAINTAINER OF ON LINE
OR UNDER SECTIONS 13.04 OR 14.049 OR AS THE MAINTAINER OF THE GREAT
BASIN SEGMENTS OR UNDER SECTIONS 13.06 OR 14.06(AS APPLICABLE)UNDER
THIS AGREEMENT OR ANY ON LINE AGREEMENT OR ANY MAINTENANCE
AGREEMENT IN RESPECT OF THE GREAT BASIN SEGMENTS, EXCEPT THE
OBLIGATION TO PROVIDE EACH PARTY WITH ITS CAPACITY ENTITLEMENT
(SUBJECT TO THE TERMS OF THIS AGREEMENT) FOLLOWING THE
RESOLUTION OF ANY DISPUTE UNDER SECTION 19.02 REGARDING SUCH
OBLIGATION.
(d) A CLAIM BASED ON WILLFUL MISCONDUCT/GROSS
NEGLIGENCE MUST BE PERFECTED BY SUBMITTING A NOTICE UNDER
SECTION 19.02(a) WITHIN TWO (2) YEARS AFTER THE LATER OF (A) THE DATE
ON WHICH THE WILLFUL MISCONDUCT/GROSS NEGLIGENCE OCCURS,AND(B)
THE DATE ON WHICH THE CLAIMING PARTY FIRST DISCOVERS OR OUGHT
REASONABLY TO HAVE FIRST DISCOVERED THE OCCURRENCE OF THE
WILLFUL MISCONDUCT/GROSS NEGLIGENCE. ALL CLAIMS MADE AFTER
SUCH TIME RELATING TO THE SAME WILLFUL MISCONDUCT/GROSS
NEGLIGENCE WILL BE BARRED BY THIS SECTION 12.03(d). IF A JUDGMENT
DEBT AGAINST THE MANAGING PARTY (IN ITS CAPACITY AS SUCH), EITHER
NVE PARTY (IN ITS CAPACITY AS OPERATOR OF THE TRANSMISSION LINE,
MAINTAINER OF ON LINE OR IN CONNECTION WITH ITS OBLIGATIONS UNDER
SECTIONS 13.04 AND 14.04)OR GREAT BASIN(IN ITS CAPACITY AS MAINTAINER
OF THE GREAT BASIN SEGMENTS OR IN CONNECTION WITH ITS OBLIGATIONS
UNDER SECTIONS 13.06 AND 14.06) IS OBTAINED BY A PARTY AND IS
COLLECTIBLE FROM INSURANCE PROCEEDS, SUCH PARTY SHALL NOT
EXECUTE, LEVY OR OTHERWISE ENFORCE THE JUDGMENT (INCLUDING
RECORDING OR EFFECTING A JUDGMENT LIEN) AGAINST SUCH PERSON (IN
SUCH CAPACITY) OR ITS OFFICERS, DIRECTORS, EMPLOYEES, AND AGENTS
AGAINST WHOM THE JUDGMENT WAS OBTAINED TO THE EXTENT OF SUCH
COLLECTABILITY.
(e) NOTWITHSTANDING ANYTHING TO THE CONTRARY
HEREIN, IN NO EVENT SHALL ANY NVE PARTY BE LIABLE OR IN DEFAULT
UNDER THIS AGREEMENT FOR ANY ACT OR OMISSION UNDERTAKEN IN ITS
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CAPACITY AS A TRANSMISSION OR INTERCONNECTION PROVIDER OR A
GENERATION OWNER.
(f) NONE OF THE MANAGING PARTY (IN ITS CAPACITY AS
SUCH), EITHER NVE PARTY (IN ITS CAPACITY AS OPERATOR OF THE
TRANSMISSION LINE, MAINTAINER OF ON LINE OR IN CONNECTION WITH ITS
OBLIGATIONS UNDER SECTIONS 13.04 AND 14.04) AND GREAT BASIN (IN ITS
CAPACITY AS MAINTAINER OF THE GREAT BASIN SEGMENTS OR IN
CONNECTION WITH ITS OBLIGATIONS UNDER SECTIONS 13.06 AND 14.06)
SHALL BE IN BREACH OF THIS AGREEMENT TO THE EXTENT IT RESULTS
FROM ANOTHER PARTY'S BREACH OF THIS AGREEMENT.
(g) NO IMPLIED WARRANTY OF MERCHANTABILITY OR OF
FITNESS FOR A PARTICULAR PURPOSE OR ANY OTHER WARRANTY SHALL
APPLY IN CONNECTION WITH THE MANAGING PARTY'S (IN ITS CAPACITY AS
SUCH), EITHER NVE PARTY'S (IN ITS CAPACITY AS OPERATOR OF THE
TRANSMISSION LINE, MAINTAINER OF ON LINE OR IN CONNECTION WITH ITS
OBLIGATIONS UNDER SECTIONS 13.04 AND 14.04) OR GREAT BASIN'S (IN ITS
CAPACITY AS MAINTAINER OF THE GREAT BASIN SEGMENTS OR IN
CONNECTION WITH ITS OBLIGATIONS UNDER SECTIONS 13.06 AND 14.06)
PERFORMANCE OR NON-PERFORMANCE OF ITS OBLIGATIONS AS MANAGING
PARTY,AS OPERATOR OF THE TRANSMISSION LINE OR AS MAINTAINER OF ON
LINE OR UNDER SECTIONS 13.04 OR 14.04, OR AS MAINTAINER OF THE GREAT
BASIN SEGMENTS OR UNDER SECTIONS 13.06 OR 14.06, RESPECTIVELY, UNDER
THIS AGREEMENT OR ANY ON LINE AGREEMENT OR ANY MAINTENANCE
AGREEMENT IN RESPECT OF THE GREAT BASIN SEGMENTS AND ARE
EXPRESSLY WAIVED BY THE OTHER PARTIES. IT IS UNDERSTOOD AND
AGREED THAT NONE OF THE MANAGING PARTY (IN ITS CAPACITY AS SUCH),
EITHER NVE PARTY (IN ITS CAPACITY AS OPERATOR OF THE TRANSMISSION
LINE, MAINTAINER OF ON LINE OR IN CONNECTION WITH ITS OBLIGATIONS
UNDER SECTIONS 13.04 AND 14.04) AND GREAT BASIN (IN ITS CAPACITY AS
MAINTAINER OF THE GREAT BASIN SEGMENTS OR IN CONNECTION WITH ITS
OBLIGATIONS UNDER SECTIONS 13.06 AND 14.06) IS GUARANTEEING OR
UNDERTAKING TO PROCURE ANY FINANCIAL OR OTHER OUTCOME WITH
RESPECT TO ON LINE OR THE GREAT BASIN SEGMENTS.
12.04 Survival of Representations and Warranties.
(a) Except as otherwise set forth in the Security Documents, the SNIP
Agreement, the Intercreditor Agreements and any consent to assignment executed pursuant to
Section 18.02(b), the respective representations and warranties of the Parties contained in this
Agreement or in any schedule, exhibit or certificate attached hereto or delivered pursuant to
Section 2.04 shall survive the Acquisition Closing as follows: (a) the representations and
warranties in Sections 17.01(a)-(g) and 17.02 a shall survive forever, (b) the representations and
warranties in Section 17.02(d)(vi) shall survive for five (5) years after the Acquisition Closing,
and (c) all other representations and warranties shall survive for three (3) years after the
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Acquisition Closing. No Party shall have any liability whatsoever with respect to any
representation and warranty unless a claim is made hereunder prior to the expiration of the
applicable survival period for such representation and warranty, in which case such representation
and warranty shall survive as to such claim until such claim has been finally resolved.
(b) Notwithstanding anything to the contrary contained in this
Agreement, Great Basin's maximum aggregate liability for Claims which may be recovered for
breaches of representations or warranties contained in Sections 17.02(b)-(d) pursuant to Section
12.01(a)(ii) shall be an amount equal to the net amount set forth on the Closing Statement;
provided, however, that there shall be no maximum aggregate liability in connection with Claims
for gross negligence, willful misconduct or fraud.
ARTICLE XIII
INSURANCE AND EVENTS OF LOSS
13.01 Insurance. Each Party shall maintain or cause to be maintained insurance
of the types, in the amounts and with the deductibles specified in the Insurance Plan, as it may be
amended by the Management Committee from time to time.
13.02 Damage or Destruction. The Parties shall,promptly after any Event of Loss,
determine whether the Event of Loss exceeds the applicable Loss Threshold. If the Parties
reasonably determine that the estimated cost or cost and time, as applicable, to repair or replace
the Transmission Line (or the applicable portion thereof) following an Event of Loss will exceed
any applicable Loss Threshold, then, with respect to an Event of Loss affecting ON Line, the
Parties shall initiate the Wind-Up Events unless the Parties decide to repair or replace ON Line(or
the applicable portion thereof).
13.03 Distribution of Insurance Proceeds. If the Parties reasonably determine that
the estimated cost or cost and time to repair or replace ON Line(or any portion thereof) following
an Event of Loss will not exceed any applicable Loss Threshold, or if the Parties reasonably
determine that the estimated cost or cost and time to repair or replace ON Line (or the applicable
portion thereof) following an Event of Loss will exceed an applicable Loss Threshold but the
Parties agree to repair or replace ON Line (or the applicable portion thereof), then any Insurance
Proceeds received by a Party in respect of such Event of Loss with respect to ON Line, to the
extent there are any, shall be used to repair or replace ON Line(or the applicable portion thereof);
provided that in the event the Insurance Proceeds exceed the actual repair and replacement costs
(the "Excess Insurance Proceeds"), such Excess Insurance Proceeds shall be distributed to the
NVE Parties. If(a) the Parties initiate the Wind-Up Events under Section 13.02 or (b) one Party
purchases the Ownership Interests of any other Party under Section 13.05(a), any Insurance
Proceeds shall be distributed to each Party in proportion to the aggregate percentage of Total Costs
paid by such Party as of the time such Insurance Proceeds are received (prior to giving effect to
any Transfer contemplated by Section 13.05(a)) to the extent (if applicable) any such Insurance
Proceeds are not needed to pay any costs incurred in connection with the retirement of ON Line.
If any Insurance Proceeds related to ON Line are received by a Party after termination of this
Agreement, then any such Insurance Proceeds shall be promptly paid to the other Parties to the
extent contemplated by this Section 13.03; provided, however, that (a) if this Agreement is
terminated following consummation of a transaction whereby the NVE Parties have purchased
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Great Basin's Ownership Interests for a price determined in accordance with Section 16.02(d) or
Schedule 5, Great Basin shall promptly pay any Insurance Proceeds it receives following such
termination to the NVE Parties, and (b) if this Agreement is terminated following consummation
of any other transaction involving the purchase by Great Basin of all of the NVE Parties'
Ownership Interests or the purchase by one or both of the NVE Parties of all of Great Basin's
Ownership Interests, and the Insurance Proceeds in question are reflected in the purchase price,
then the selling Party or Parties shall promptly pay any such Insurance Proceeds received following
such termination to the acquiring Party or Parties.
13.04 Payment of Restoration Costs. If the Parties reasonably determine that the
estimated cost or cost and time, as applicable,to repair or replace ON Line(or any portion thereof)
following an Event of Loss will not exceed any applicable Loss Threshold, or if the Parties
reasonably determine that the estimated cost or cost and time, as applicable, to repair or replace
ON Line (or the applicable portion thereof) following an Event of Loss will exceed an applicable
Loss Threshold but the Parties agree to repair or replace ON Line (or the applicable portion
thereof), then (a) NPC shall promptly create a new budget for the reconstruction of ON Line
consistent with the determination by the Parties of the estimated cost or time to repair or replace
ON Line (or any portion thereof), subject to the approval of the Management Committee (the
"Event of Loss Budget"), (b)NPC shall proceed under the Management Committee's supervision
to cause the repair and replacement of ON Line(or the applicable portion thereof)and(c)the NVE
Parties shall pay for any repair and replacement costs not otherwise paid for by Insurance Proceeds
("Event of Loss Costs") in accordance with the Event of Loss Budget. Great Basin shall elect or
not elect to fund the Event of Loss Costs at or before Management Committee approval of the
Event of Loss Budget. If Great Basin does not timely elect to fund any such Event of Loss Costs,
Great Basin shall have no right or obligation to fund its Ownership Percentage of any such Event
of Loss Costs. If Great Basin does timely elect (such election being irrevocable) to fund its
Ownership Percentage of any such Event of Loss Costs, then Great Basin shall timely fund its
Ownership Percentage of any such Event of Loss Costs, and the amount funded by Great Basin in
respect of Event of Loss Costs shall be reflected in the Monthly Payment, as provided in Section
3.06. To the extent that Great Basin does not timely fund its Ownership Percentage of any Event
of Loss Costs, the NVE Parties may fund any such portion, and, within fifteen (15) days after
receipt of PUCN Approval and all required Governmental Approvals on terms acceptable to the
NVE Parties, each Party's Ownership Percentage shall be adjusted such that, following the
adjustment, such Party's Ownership Percentage shall equal a ratio (x) the numerator of which is
equal to the portion of the Total Costs paid by such Party and(y)the denominator of which equals
the Total Costs,and Great Basin shall Transfer the portion of its Ownership Interest corresponding
to its excess above its revised Ownership Percentage to the NVE Parties free and clear of any Liens
other than Permitted Liens. Great Basin shall execute and record any bills of sale, deeds,
certificates, memorandum and other documentation as reasonably requested by the NVE Parties
to evidence the re-allocation of such interests. Great Basin shall make Applicable Transfer
Representations and Warranties in connection with such Transfer. Notwithstanding anything to
the contrary in this Agreement, neither NPC nor SPPC shall be required to pay for any Event of
Loss Costs that are not in accordance with the applicable Event of Loss Budget.
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13.05 Rebuild or Repair by a Singley; Fair Market Value.
(a) If,following an Event of Loss with respect to ON Line that the Parties
reasonably determine will exceed any applicable Loss Threshold, any Party (a "Withdrawing
Party") desires to retire ON Line (or the applicable portion thereof) and any other Party desires to
rebuild, repair or replace ON Line (or the applicable portion thereof), then any Party desiring to
rebuild, repair or replace ON Line (or the applicable portion thereof) shall have the right to
purchase any Withdrawing Party's Ownership Interests by delivery to the Parties of written notice
within thirty(30) days after such determination. Upon receiving such written notice from a Party,
each Withdrawing Party shall Transfer its Ownership Interests to such continuing Party free and
clear of any Liens other than Permitted Liens on a date no later than fifteen (15) days from receipt
of such written notice and receipt of PUCN Approval and all required Governmental Approvals
on terms acceptable to the NVE Parties, and such continuing Party shall pay to each Withdrawing
Party an amount equal to the Fair Market Value of such Withdrawing Party's Ownership Interest.
Each Withdrawing Party shall make Applicable Transfer Representations and Warranties to each
continuing Party in connection with such Transfer.
(b) For the purposes of this Agreement, "Fair Market Value" means the
cash price at which a willing seller would sell and a willing buyer would buy the applicable
Ownership Interests, each being apprised of all relevant facts, as determined pursuant to the
provisions of this Section 13.05(b). In order to determine the Fair Market Value, the NVE Parties
and Great Basin shall each, within fifteen(15) Business Days after the transferring Party's receipt
of the notice of the acquisition, designate a qualified appraiser. A qualified appraiser shall be an
appraiser with at least five(5)years of experience in the appraisal of properties similar to ON Line.
If the NVE Parties or Great Basin fails to select an appraiser within such fifteen(15)-Business Day
period, then the selected appraiser shall, within fifteen (15) days thereafter, appoint a second
appraiser with similar qualifications (who shall not have performed any work for the Party having
selected the selected appraiser or its Affiliates within the five(5)-year period immediately prior to
his or her appointment) who shall be deemed to have been appointed by the Party that failed to
select an appraiser. Each of the two (2) appraisers shall be directed to determine the Fair Market
Value of the transferring Party's Ownership Interests within thirty(30) days of the appointment of
the second appraiser and to notify each Party of his or her determination. If the lower of the two
(2) determinations is not less than ninety-five percent (95%) of the higher of the two (2)
determinations, then the Fair Market Value shall be the average of the two (2) determinations and
such amount shall be binding upon the Parties. If the lower of the two (2) determinations is less
than ninety-five percent (95%) of the higher of the two (2) determinations, then the two (2)
appraisers shall, within fifteen (15) days thereafter, appoint a third appraiser with similar
qualifications (who shall not have performed any work for any Party or its Affiliates within the
five (5)-year period immediately prior to his or her appointment) and shall each furnish to such
third appraiser a written report of his or her respective determination. Within thirty (30) days of
his or her appointment,the third appraiser shall select the Fair Market Value of one or the other of
the original appraisers and shall notify each Party of his or her determination, which shall be
binding upon the Parties. The third appraiser must select one(1)of the two(2)appraisals and shall
not have the right to establish a different Fair Market Value determination. The NVE Parties and
Great Basin shall bear the cost of the appraiser appointed by each such Party(or deemed appointed
by each such Party), and the NVE Parties and Great Basin shall each bear fifty percent (50%) of
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the cost of the third appraiser(if any). Notwithstanding anything to the contrary herein, the NVE
Parties or Great Basin may request a new determination for Fair Market Value if the Transfer of
Ownership Interest occurs nine (9) months or more after the completion of any appraisal
previously used by the Parties to determine Fair Market Value.
13.06 Great Basin Segment Event of Loss. Great Basin shall promptly after any
Event of Loss affecting all or any portion of the Great Basin Segments notify the Management
Committee of such Event of Loss. If such Event of Loss does not exceed a Loss Threshold for the
Great Basin Segments, then Great Basin shall promptly repair and replace the Great Basin
Segments (or the applicable portion thereof) at its own cost. If such Event of Loss does exceed a
Loss Threshold for the Great Basin Segments, as reasonably determined by the Parties,then Great
Basin may rebuild and replace the Great Basin Segments (or any applicable portion thereof) at its
own expense. Any Insurance Proceeds paid in respect of the Great Basin Segments shall be paid
to Great Basin.
13.07 Event of Loss Threshold Deadlock. If a Loss Threshold Deadlock arises
regarding any Event of Loss, such Loss Threshold Deadlock shall be referred to a panel consisting
of a senior executive (President or Vice President) of each Party with the authority to resolve the
Loss Threshold Deadlock. If such Loss Threshold Deadlock is not resolved for any reason within
fifteen (15) days after the panel of senior executives has convened or within thirty(30) days after
the Loss Threshold Deadlock occurred, whichever occurs sooner, then resolution of such Loss
Threshold Deadlock shall be determined using the procedures in this Section 13.07. The Loss
Threshold Deadlock shall be determined by a qualified independent engineer selected by the
Parties. If the Parties are unable to select a qualified independent engineer within fifteen(15)days
after any Party has proposed a qualified independent engineer, any Party may submit the selection
of such qualified independent engineer to the AAA. The qualified independent engineer shall have
significant experience regarding the Loss Threshold Deadlock matter and shall not have worked
for any Party or an Affiliate thereof within five (5) years preceding appointment thereof and shall
make the determination within thirty (30) days after appointment, or as soon thereafter as is
practicable. The Parties shall reasonably cooperate with the qualified independent engineer, and
their agreement to submit Loss Threshold Deadlocks under this Section 13.07 to the qualified
independent engineer shall be enforceable as an agreement to arbitrate. The decision of the
qualified independent engineer shall be final,binding and conclusive upon the Parties, shall not be
subject to challenge or appeal, and may be enforced in any court having jurisdiction in the same
manner as an arbitral award.
ARTICLE XIV
CONDEMNATION
14.01 Participation in Condemnation Action. Each Party shall have the right, at
its own cost and expense, to appear in any Condemnation Action and to participate in any and all
hearings, trials and appeals therein. No Party shall accept or agree to any conveyance in lieu of
any Condemnation Action unless agreed upon by the Parties.
14.02 Taking. If title to all or any part of the Transmission Line shall be taken in
any Condemnation Action,other than for a temporary use or occupancy,the Parties shall,promptly
after such Condemnation Action, determine whether the Condemnation Action exceeds the
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applicable Loss Threshold. If the Parties reasonably determine that the estimated cost or cost and
time, as applicable, to replace the Transmission Line (or any portion thereof) following a
Condemnation Action will exceed any applicable Loss Threshold (a "Complete Taking"), then,
with respect to a Condemnation Action affecting ON Line, the Parties shall initiate the Wind-Up
Events unless the Parties decide to replace the affected ON Line assets. ON Line shall not be
wound-up as a result of a Condemnation Action that does not give rise to a Complete Taking (a
"Partial Taking").
14.03 Distribution of Condemnation Awards. Upon the occurrence of a Partial
Taking or upon the occurrence of a Complete Taking and the agreement of the Parties to continue
ON Line activities, then any Condemnation Awards received by a Party in respect of such Partial
Taking or Complete Taking, as applicable, shall be used to replace ON Line (or the applicable
portion thereof);provided that in the event the Condemnation Award exceeds the actual restoration
cost(the"Excess Condemnation Award"), such Excess Condemnation Award shall be distributed
to the NVE Parties. If(a) the Parties initiate the Wind-Up Events under Section 14.02 or(b) one
Party elects to purchase the Ownership Interests of any other Party under Section 14.05, any
Condemnation Award shall be distributed to each Party in proportion to the aggregate percentage
of Total Costs paid by such Party as of the time such Condemnation Award is received (prior to
giving effect to any Transfer contemplated by Section 14.05)to the extent(if applicable)any such
Condemnation Award is not needed to pay any costs incurred in connection with the retirement of
ON Line. If any Condemnation Award with respect to ON Line is received by a Party after
termination of this Agreement, then any such Condemnation Award shall be promptly paid to the
other Parties to the extent contemplated by this Section 14.03; provided, however, that (a) if this
Agreement is terminated following consummation of a transaction whereby the NVE Parties have
purchased Great Basin's Ownership Interests for a price determined in accordance with Section
16.02 d or Schedule 5, Great Basin shall promptly pay any Condemnation Award it receives
following such termination to the NVE Parties, and (b) if this Agreement is terminated following
consummation of any other transaction involving the purchase by Great Basin of all of the NVE
Parties' Ownership Interests or the purchase by one or both of the NVE Parties of all of Great
Basin's Ownership Interests, and the Condemnation Award in question is reflected in the purchase
price,then the selling Party or Parties shall promptly pay any such Condemnation Award received
following such termination to the acquiring Party or Parties.
14.04 Payment of Restoration Costs. Upon the occurrence of a Partial Taking or
upon the occurrence of a Complete Taking and the agreement of the Parties to continue ON Line
activities, then (a) NPC shall promptly create a new budget for the reconstruction of ON Line
consistent with the determination by the Parties of the estimated cost or cost and time to replace
ON Line (or any portion thereof), subject to the approval of the Management Committee (the
"Condemnation Action Budget"), (b) NPC shall proceed under the Management Committee's
supervision to cause the replacement of the affected portion of ON Line and (c) the NVE Parties
shall pay for any replacement costs not otherwise paid for by Condemnation Award
("Condemnation Action Costs") in accordance with the Condemnation Action Budget. Great
Basin shall elect or not elect to fund the Condemnation Action Costs at or before Management
Committee approval of the Condemnation Action Budget. If Great Basin does not timely elect to
fund any such Condemnation Action Costs, Great Basin shall have no right or obligation to fund
its Ownership Percentage of any such Condemnation Action Costs. If Great Basin does timely
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elect (such election being irrevocable) to fund its Ownership Percentage of any such
Condemnation Action Costs, then Great Basin shall timely fund its Ownership Percentage of any
such Condemnation Action Costs, and the amount funded by Great Basin in respect of
Condemnation Action Costs shall be reflected in the Monthly Payment, as provided in Section
3.06. To the extent that Great Basin does not timely fund its Ownership Percentage of any
Condemnation Action Costs, the NVE Parties may fund any such portion, and, within fifteen(15)
days after receipt of PUCN Approval and all required Governmental Approvals on terms
acceptable to the NVE Parties, each Party's Ownership Percentage shall be adjusted such that,
following the adjustment, such Party's Ownership Percentage shall equal a ratio (x)the numerator
of which is equal to the portion of the Total Costs paid by such Party and (y) the denominator of
which equals the Total Costs, and Great Basin shall Transfer the portion of its Ownership Interest
corresponding to its excess above its revised Ownership Percentage to the NVE Parties free and
clear of any Liens other than Permitted Liens. Great Basin shall execute and record any bills of
sale, deeds, certificates, memorandum and other documentation as reasonably requested by the
NVE Parties to evidence the re-allocation of such interests. Great Basin shall make Applicable
Transfer Representations and Warranties in connection with such Transfer. Notwithstanding
anything to the contrary in this Agreement,neither NPC nor SPPC shall be required to pay for any
Condemnation Action Costs that are not in accordance with the applicable Condemnation Action
Budget.
14.05 Rebuild or Repair by a Single Party. If, following a Complete Taking as
reasonably determined by the Parties, any Party desires to retire ON Line and any other Party
desires to rebuild or replace the condemned portion of ON Line, then the Party desiring to rebuild
or replace the condemned portion of ON Line shall have the right to purchase any Withdrawing
Party's Ownership Interests by delivery to the other Parties of written notice within thirty (30)
days after such Management Committee determination. Upon receiving written notice from any
Party desiring to rebuild or replace the condemned portion of ON Line exercising such right, each
Withdrawing Party shall Transfer its Ownership Interests to such continuing Party free and clear
of any Liens other than Permitted Liens on a date no later than fifteen (15) days from receipt of
such written notice and receipt of PUCN Approval and all required Governmental Approvals on
terms acceptable to the NVE Parties, and such continuing Party shall pay to each Withdrawing
Party an amount equal to the Fair Market Value of such Withdrawing Party's Ownership Interest.
Each Withdrawing Party shall make Applicable Transfer Representations and Warranties to each
continuing Party in connection with such Transfer.
14.06 Great Basin Segment Condemnation. Great Basin shall promptly after any
Condemnation Action affecting all or any portion of the Great Basin Segments notify the
Management Committee of such Condemnation Action. If such Condemnation Action does not
exceed a Loss Threshold for the Great Basin Segments, then Great Basin shall promptly rebuild
and replace the Great Basin Segments (or the applicable portion thereof) at its own cost. If such
Condemnation Action does exceed a Loss Threshold for the Great Basin Segments, as reasonably
determined by the Parties,then Great Basin may rebuild and replace the Great Basin Segments (or
any applicable portion thereof) at its own expense. Any Condemnation Awards paid in respect of
the Great Basin Segments shall be paid to Great Basin.
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14.07 Condemnation Action Threshold Deadlock. If a Loss Threshold Deadlock
arises regarding any Condemnation Action, such Loss Threshold Deadlock shall be referred to a
panel consisting of a senior executive(President or Vice President)of each Party with the authority
to resolve the Loss Threshold Deadlock. If such Loss Threshold Deadlock is not resolved for any
reason within fifteen (15) days after the panel of senior executives has convened or within thirty
(30) days after the Loss Threshold Deadlock occurred, whichever occurs sooner, then resolution
of such Loss Threshold Deadlock shall be determined using the procedures in this Section 14.07.
The Loss Threshold Deadlock shall be determined by a qualified independent engineer selected
by the Parties. If the Parties are unable to select a qualified independent engineer within fifteen
(15)days after any Party has proposed a qualified independent engineer, any Party may submit the
selection of such qualified independent engineer to the AAA. The qualified independent engineer
shall have significant experience regarding the Loss Threshold Deadlock matter and shall not have
worked for any Party or an Affiliate thereof within five (5) years preceding appointment thereof
and shall make the determination within thirty (30) days after appointment, or as soon thereafter
as is practicable. The Parties shall reasonably cooperate with the qualified independent engineer,
and their agreement to submit Loss Threshold Deadlocks under this Section 14.07 to the qualified
independent engineer shall be enforceable as an agreement to arbitrate. The decision of the
qualified independent engineer shall be final,binding and conclusive upon the Parties, shall not be
subject to challenge or appeal, and may be enforced in any court having jurisdiction in the same
manner as an arbitral award.
ARTICLE XV
TRANSFERS AND CHANGES OF CONTROL
15.01 Transfers.
(a) Except for Permitted Transfers, no Party may Transfer all or any
portion of its Ownership Interests or its rights or obligations under this Agreement without the
prior written approval of the other Parties, which approval shall not be unreasonably withheld,
conditioned or delayed. Except for Permitted Transfers, Great Basin shall not Transfer any
ownership interest in the Great Basin Segments without the prior written approval of the other
Parties,which approval shall not be unreasonably withheld, conditioned or delayed. For purposes
of this Section 15.01, any grounds that are reasonably likely to have a material adverse effect on a
non-Transferring Party,any proposed Transfer of less than all of a Party's Ownership Interests and
any proposed Transfer of less than all of Great Basin's ownership interests in the Great Basin
Segments, in each case shall constitute reasonable grounds for withholding or conditioning
approval and shall be described to the Transferring Party in reasonable detail if such approval is
withheld or conditioned.
(b) No Transfer of Ownership Interests or any rights or obligations under
this Agreement shall be permitted, or shall become effective, unless such Transfer includes a
corresponding and equivalent Transfer of all associated rights and obligations of the Transferring
Party in its Ownership Interests and this Agreement. No Transfer of ownership interests in the
Great Basin Segments or any rights or obligations under this Agreement with respect thereto shall
be permitted, or shall become effective, unless such Transfer includes a corresponding and
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equivalent Transfer of all associated rights and obligations of Great Basin in its ownership interests
in the Great Basin Segments and this Agreement.
(c) Any Party may allow any of its transmission or other customers to
transmit electricity on or otherwise utilize its Electrical Capacity, Fiber Optic Capacity or
Microwave Capacity pursuant to ordinary course transactions entered into in accordance with such
Party's Open Access Transmission Tariff without the prior written consent of the other Parties;
provided,that such customers utilize such capacity in accordance with the terms of this Agreement.
Any exercise by a Party of its rights under this Section 15.01(c) shall not relieve such Party of its
obligations under this Agreement.
(d) Any Transfer that is made in violation of this Agreement shall be void
ab initio.
15.02 Right of First Refusal and Right of First Offer.
(a) ROFR.
(i) If any Party receives an unsolicited offer(other than an offer
that, if consummated, would constitute a Permitted Transfer pursuant to Sections
15.03(a)-(g)) from a non-Affiliated third-Person to Transfer all or part of its Ownership
Interests, the Transferring Party may make such Transfer only if it has complied with the
provisions of this Section 15.02 and such Transfer is made in accordance with the other
requirements of this Article XV. Prior to making such Transfer, the Transferring Party
shall give to the other Parties written notice (except a Party that, at the time, is in default
under Sections 16.01(a),(D or(g))of the proposed transaction(the"ROFR Offer Notice"),
which notice shall fully disclose (A)the terms of the proposed transaction, (B)the
Ownership Interests subject to the ROFR Offer Notice (the "ROFR Offered Interest"),
(C) the identity of the proposed transferee and(D) the date on which the offer shall expire
if not accepted, which shall be at least thirty(30) days after each other Party has received
the ROFR Offer Notice (the "ROFR Offer Deadline").
(ii) Upon receipt of a ROFR Offer Notice, any Party receiving
such notice shall have a right to acquire all (but not less than all) of the ROFR Offered
Interest, upon the same terms and conditions that are set forth in the ROFR Offer Notice,
by giving written notice to the Transferring Party on or prior to the ROFR Offer Deadline
stating that it elects to acquire the ROFR Offered Interest (the "ROFR Return Notice"),
which election may be subject to receipt of PUCN Approval and any required
Governmental Approvals on terms acceptable to the NVE Parties. A failure to give the
ROFR Return Notice by the ROFR Offer Deadline shall be deemed to be an election not
to acquire the ROFR Offered Interest and, if both other Parties elect not to acquire the
ROFR Offered Interest,subject to the Transferring Party's compliance with the provisions
of Section 15.01, Sections 15.02(a) and fd)and Section 15.04,the ROFR Offered Interest
may be thereafter Transferred to the non-Affiliated third-Person as long as the terms of
such Transfer are the same as, or more favorable to the Transferring Party than, those
described in the ROFR Offer Notice.
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(b) ROFO.
(i) Except with respect to any Transfer that, if consummated,
would constitute a Permitted Transfer pursuant to Sections 15.03(a)-(R) and any Transfer
subject to Section 15.02(a), a Transferring Party may make a Transfer of any Ownership
Interests only if it has complied with the requirements of this Section 15.02 and such
Transfer is made in accordance with the other requirements of this Article XV. Prior to
initiating any auction or sales process,the Transferring Party shall give to the other Parties
written notice (except a Party that, at the time, is in default under Sections 16.01(a),(f or
(0) of the proposed transaction (the "ROFO Offer Notice") setting forth the Ownership
Interests the Transferring Party proposes to Transfer(the "ROFO Offered Interest").
(ii) Upon receipt of an ROFO Offer Notice, any Party receiving
such notice shall have a right to negotiate with the Transferring Party for the purchase of
the ROFO Offered Interests by giving written notice to the Transferring Party within thirty
(30) days after receipt of the ROFO Offer Notice (the "ROFO Offer Deadline") stating
that it elects to negotiate to acquire the ROFO Offered Interest (the "ROFO Return
Notice"). Upon any timely delivery of a ROFO Return Notice by any Party, such Party
and the Transferring Party shall negotiate exclusively and in good faith for forty-five(45)
days, unless otherwise agreed by those Parties, the terms of the Transfer of the ROFO
Offered Interests. A failure to give the ROFO Return Notice by the ROFO Offer Deadline
shall be deemed to be an election not to negotiate to acquire the ROFO Offered Interest
and, if both other Parties elect not to negotiate to acquire the ROFO Offered Interest or
the applicable Parties do not agree on the Transfer of the ROFO Offered Interests within
such forty-five (45) day period, subject to the Transferring Party's compliance with the
provisions of Section 15.01, Sections 15.02(b) and (d) and Section 15.04, the ROFO
Offered Interest may be thereafter Transferred.
(c) Acquisition. If a Party elects to exercise its right to acquire any ROFR
Offered Interest or the Transferring Party and any other Party agree to a Transfer of any ROFO
Offered Interest to any such other Party, then the acquiring Party(the "Acquiring Party") and the
Transferring Party shall execute such instruments as may be necessary and appropriate to
effectuate the Transfer of the applicable Offered Interests as soon as practicable to the Acquiring
Party, free and clear of all Liens (i) in the case of ROFR Offered Interests, which are not by the
terms of the ROFR Offer Notice specifically identified as surviving the Transfer of the ROFR
Offered Interest and (ii) in the case of ROFO Offered Interest, other than Permitted Liens. The
Acquiring Party shall close on the acquisition of the applicable Offered Interests within fifteen
(15) days after (i) in the case of ROFR Offered Interests, the Transferring Party has satisfied all
conditions precedent contained in the ROFR Offer Notice and(ii)the Acquiring Party has received
PUCN Approval and all required Governmental Approvals on terms acceptable to the NVE
Parties. The Transferring Party shall make the following representations and warranties to the
Acquiring Party in connection with such Transfer: (i) in the case of ROFR Offered Interests, the
representations and warranties set forth in the applicable ROFR Offer Notice, and (ii) in the case
of ROFO Offered Interests, Applicable Transfer Representations and Warranties. Failure to close
on the acquisition of the applicable Offered Interests within such time period shall be deemed to
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be a rejection of the ROFR Offer Notice or ROFO Offer Notice, as applicable, if such failure is
solely attributable to the Acquiring Party.
(d) Reattachment of Transfer Restrictions. The right of the Transferring
Party to Transfer Offered Interests shall once again be subject to the requirements of this Section
15.02 as if the Transferring Party had never offered the Offered Interests to any non-Transferring
Party if the Transferring Party (i) fails to consummate the Transfer of the Offered Interests to a
third Person within(A) one hundred eighty(180) days after the date of the applicable Offer Notice
or(B) if both Parties elect not to acquire the applicable Offered Interest, ninety(90) days after the
later of such election or(ii) in the case of the ROFR Offered Interests, undertakes to, without the
written consent of each other Party, Transfer such ROFR Offered Interests to Persons other than
those Persons whose identity was disclosed in the ROFR Offer Notice, which consent will not be
unreasonably withheld, conditioned or delayed, or upon terms and conditions less favorable to the
Transferring Party than the terms and conditions than were contained in the ROFR Offer Notice.
15.03 Permitted Transfers. Although the following shall constitute a Transfer
under this Agreement, no consent of any other Party shall be required for any of the following
Transfers or corresponding and equivalent Transfers of this Agreement (each, a "Permitted
Transfer"):
(a) A Transfer by SPPC to NPC of all or part of its Ownership Interests,
or any Transfer by SPPC or NPC by way of a merger or consolidation with each other, an Affiliate
or any other Person;
(b) Subject to Article XVIII, (i) a Party's collateral assignment,
mortgage, hypothecation, pledge or other encumbrance of its Ownership Interests in favor of the
ON Line Lenders or NVE Lenders, as applicable and (ii) any such lender(s)' foreclosure on such
Ownership Interests, or assignment of such Ownership Interests to any subsequent assignee in
connection with the sale, transfer or exchange of its rights, in connection with the exercise of its
rights and enforcement of its remedies under the applicable financing and security instruments;
(c) Subject to Article XVIII, (i) Great Basin's collateral assignment,
mortgage, hypothecation, pledge or other encumbrance of its ownership interests in the Great
Basin Segments in favor of the GB Segment Lenders and (ii) any such lender(s)' foreclosure on
such ownership interests, or assignment of such ownership interests to any subsequent assignee in
connection with the sale, transfer or exchange of its rights, in connection with the exercise of its
rights and enforcement of its remedies under the applicable financing and security instruments;
(d) A Transfer (other than by operation of law) by NPC or SPPC of its
Ownership Interests to any successor to NPC or SPPC if such successor is a public utility holding
a certificate of public convenience and necessity granted by the PUCN pursuant to Chapter 704 of
the Nevada Revised Statutes;
(e) A one-time Transfer by Great Basin of either all of its Ownership
Interests or all of its ownership interests in the Great Basin Segments to one Affiliate which is
controlled by or under Common Control with Great Basin (the "Affiliated Assignee") prior to or
concurrently with GB Segment Financial Closing; provided, that, except with the NVE Parties'
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prior written consent: (i) such Transfer has no effect on the NVE Parties' rights nor increases the
NVE Parties' obligations under this Agreement, the Security Documents, any other agreement in
connection herewith or otherwise and (ii) Great Basin and any such Affiliated Assignee remain
jointly and severally liable for all of their obligations under this Agreement, the Security
Documents and any other agreement in connection herewith;
(f) One-time, simultaneous Transfers (or capacity right exchanges)
between Great Basin and the Affiliated Assignee at the achievement of GB Segment COD such
that,upon consummation of such Transfers, (or capacity right exchanges) either:
(i) Great Basin or the Affiliated Assignee will own sixty-two
percent (62%) of all Ownership Interests and an undivided sixty-two percent (62%)
ownership interest in the Great Basin Segments and the other party will own thirteen
percent (13%) of all Ownership Interests and an undivided thirty-eight percent (38%)
ownership interest in the Great Basin Segments; provided that such percentages may be
subject to adjustment as determined by Great Basin in proportion to any adjustment of a
Party's Capacity Entitlement pursuant to Section 16.02(f) or Ownership Percentages
pursuant to this Agreement so long as the ON Line Security Interest and GB Segment
Security Interest are not affected by such adjustment; or
(ii) Great Basin or the Affiliated Assignee will own seventy-five
percent (75%) of all Ownership Interests (subject to the capacity rights in favor of the
other party and adjusted in connection with any adjustment of Ownership Percentages
pursuant to this Agreement) and the other party will own one hundred percent (100%) of
the Great Basin Segments (subject to capacity rights in favor of the first party);
provided,that(x) such Transfers have no effect on the NVE Parties' rights or increase the
NVE Parties' obligations under this Agreement, the Security Documents, any other
agreement in connection herewith or otherwise and (y) Great Basin and the Affiliated
Assignee remain jointly and severally liable for all of their obligations under this
Agreement,the Security Documents and any other agreement in connection herewith; and
(g) Transfers of Great Basin's Ownership Interests to its Affiliates and
the NVE Parties solely for the purpose of satisfying Great Basin's obligation to the NVE Parties
in connection with the NVE Parties' exercise of a purchase option pursuant to this Agreement; and
(h) A Transfer by Great Basin of all of its Ownership Interests and/or all
of its ownership interests in the Great Basin Segments to an Eligible Assignee.
15.04 Other Transfer Restrictions. Notwithstanding anything to the contrary, no
Transfer(except Transfers under Sections 15.03(b)(i) or 15.03 c i ) shall be valid unless:
(a) The Transferring Party has notified the other Parties of the name,
address, phone number, tax identification number and contact person of the transferee;
(b) The proposed transferee has assumed responsibility for performance
of all of the liabilities and obligations of the Transferring Party under this Agreement, each ON
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Line Agreement, each Security Document,the Balancing Authority Area Services Agreement and
otherwise relating to the Ownership Interests that the transferee acquires arising on and after the
date of the Transfer pursuant to a written instrument of assignment and assumption in a form
approved by the other Parties acting reasonably,which approval shall be limited to the question of
whether such instrument, when duly executed, will accomplish the purposes intended under this
Agreement (an "Assignment and Assumption Agreement"). Each Assignment and Assumption
Agreement shall (i) provide that the other Parties are each a third-Person beneficiary thereof, (ii)
require that the transferee becomes a party to this Agreement, each ON Line Agreement (with
respect to a Transfer of Ownership Interests) and each Security Document and agrees to be bound
by the terms hereof and,if applicable,thereof, (iii)reflect, among other things,that the transferee's
Ownership Interests or ownership interests in the Great Basin Segments, as applicable, are subject
to the terms and provisions of this Agreement,each ON Line Agreement(with respect to a Transfer
of Ownership Interests)and each Security Document and that such transferee has no greater rights
in ON Line or the Great Basin Segments, as applicable, than the Transferring Party prior to the
Transfer and (iv) contain representations and warranties from the transferee substantially similar
to those set forth in Section 17.01. The Transferring Party's obligations under this Agreement,
each ON Line Agreement (with respect to a Transfer of Ownership Interests) and each Security
Document shall be valid and binding obligations of the transferee enforceable in accordance with
the terms hereof and, if applicable, thereof,
(c) Except as otherwise agreed in the consent to collateral assignment
between the NVE Parties and the ON Line Lenders,all amounts due and owing by the Transferring
Party under this Agreement shall have been paid in full;
(d) Such Transfer shall not result in(i) a breach or event of default under
any ON Line Agreement or any Security Document or an Event of Default or breach of this
Agreement, or(ii) this Agreement, any ON Line Agreement or any Security Document not being
in full force and effect;
(e) After such Transfer, the GB Segment Security Interest and the ON
Line Security Interest shall be valid, legal, perfected, in full force and effect and have the priority
contemplated by Section 18.04;
(f) Such Transfer shall not cause ON Line or a Party to be subject to any
Applicable Law to which it was not previously subject and which constitutes a Material Adverse
Effect;
(g) Such Transfer complies with all Applicable Laws, the transferee has
all necessary Governmental Approvals to comply with its obligations under this Agreement and
such Transfer complies with Section 15.01(b);
(h) Such Transfer will not cause any portion of a non-Transferring Party's
Ownership Interests or ownership interests in the Great Basin Segments to be "tax-exempt use
property" as defined in Section 168(h) of the Code(without giving effect to paragraphs (1)(c) and
(3) thereof) based on an opinion from nationally-recognized tax counsel selected by the
Transferring Party and reasonably acceptable to the non-Transferring Parties, delivered to each of
the Parties on or prior to such Transfer, stating that such Transfer will, more likely than not, not
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cause the Ownership Interest of a non-Transferring Party in any portion of ON Line or the
ownership interest of any non-Transferring Party in any of the Great Basin Segments to be "tax-
exempt use property"as defined in Section 168(h)of the Code(without giving effect to paragraphs
(1)(c) and(3)thereof);
(i) If the Transferee relied on its parent to satisfy the creditworthiness
requirements(as set forth in the definition of Eligible Assignee),then the Transferee's parent shall,
as a condition to the effectiveness of the Transfer, deliver a guaranty in favor of the non-
Transferring Parties guaranteeing all of the Transferee's obligations under this Agreement on
terms reasonably acceptable to the NVE Parties; and
0) If the Transferee relied on its Affiliate to satisfy the requirement to
have sufficient experience (as set forth in the definitions of Eligible Assignee and Experienced
Operator)and/or to be regulated by FERC(as set forth in the definition of Eligible Assignee),then,
as a condition to the effectiveness of the Transfer, the Transferee and its applicable Affiliate shall
agree in writing, in a form reasonably acceptable to the NVE Parties, to remain under common
Control for a period of no less than four(4) years following the date of such Transfer.
15.05 Change of Control. Prior to undertaking any transaction or series of
transactions that will result in a direct or indirect change of Control of Great Basin (other than(i)
a change in Control of any parent of Great Basin which has material assets other than its direct or
indirect ownership interest in the Transmission Line, (ii) a change in the direct or indirect
ownership of Great Basin that does not result in the change in the Person that ultimately Controls
Great Basin,or(iii)any transaction or series of transactions that results in an Eligible Control Party
assuming Control of Great Basin), Great Basin shall promptly provide the NVE Parties with
information about such transaction or transactions and the parties thereto (subject to the NVE
Parties executing a confidentiality agreement with respect thereto containing customary terms)and
shall cause its applicable parent company to obtain the written consent of the NVE Parties prior to
consummating such transaction or transactions, not to be unreasonably withheld, conditioned or
delayed;provided,however,that the consent of the NVE Parties is not required under this Section
15.05 with respect to the exercise of remedies by the ON Line Lenders under the ON Line
Financing Agreements or the GB Segment Lenders under the GB Segment Financing Agreements.
As a condition to the effectiveness of any transaction or series of transactions that results in an
Eligible Control Party assuming Control of Great Basin, if the Eligible Control Party relied on its
parent to satisfy the creditworthiness requirements (as set forth in the definition of Eligible
Assignee), then the Eligible Control Party's parent shall, as a condition to the effectiveness of the
change of Control, deliver a guaranty in favor of the NVE Parties guaranteeing all of the Eligible
Control Party's obligations under this Agreement on terms reasonably acceptable to the NVE
Parties, and if the Eligible Control Party relied on its Affiliate to satisfy the requirement to have
sufficient experience (as set forth in the definitions of Eligible Assignee and Experienced
Operator)and/or to be regulated by FERC(as set forth in the definition of Eligible Assignee),then,
as a condition to the effectiveness of the change of Control, the Eligible Control Party and its
applicable Affiliate shall agree in writing, in a form reasonably acceptable to the NVE Parties, to
remain under common Control for a period of no less than four(4)years following the date of such
change of Control.
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ARTICLE XVI
DEFAULT AND REMEDIES
16.01 Events of Default. Each of the following events shall be an "Event of
Default"under this Agreement:
(a) Failure to Make Payment. Failure by a Party to make any
Contribution or payment required under this Agreement that is not being disputed in good faith
within the later of (i) thirty (30) days after the date on which such Contribution or payment
becomes due (or for disputed payments, the date on which it is determined that the amount is
owing) and (ii) three (3) Business Days after receipt of written notice of the failure to pay is
provided to such Party.
(b) Failure to Perform. Failure by a Party to perform, in any material
respect not otherwise identified as an Event of Default, any material obligation, duty or
responsibility in accordance with the provisions of this Agreement where such failure is not
remedied within thirty (30) days after written notice thereof is provided to such Party or such
longer period if the failure to perform is not susceptible to cure within such thirty(30)-day period
and such Party diligently pursues the cure of such default to completion within such additional
period as may be reasonably required to cure such failure to perform;provided,however,that such
default, if not cured within ninety (90) days after such written notice is provided to such Party,
shall constitute an Event of Default.
(c) Breach of a Representation and WarrantX. A Party breaches a
representation or warranty it has made hereunder in any material respect and such breach is not
remedied within thirty(30) days after written notice thereof is provided to such Party.
(d) Insurance. A Party fails to obtain and maintain the insurance required
by the Insurance Plan and such failure is not remedied within thirty (30) days after written notice
thereof is provided to such Party.
(e) Great Basin Change in Control. A breach by Great Basin of
Section 15.05.
(f) Bankruptcy Event. The occurrence of a Bankruptcy Event with
respect to a Party.
(g) Failure of Security Interests, Security Documents and Non-
Disturbance Agreements. (i) Failure of the ON Line Security Interest or GB Segment Security
Interest to (A) be valid, legal, perfected, in full force and effect or (B) have the priority
contemplated by Section 18.04 for fifteen (15) days, (ii) failure of any associated Security
Document to be in full force and effect, (iii) any breach of Section 18.03 or (iv) any breach by
Great Basin under any Security Document (accounting for any notice requirement and/or cure
period provided in the applicable Security Document). Each such event shall constitute an Event
of Default by Great Basin.
16.02 Remedies.
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(a) Remedies Not Exclusive. Except as provided in Section 11.03(b) or
any other provision of this Agreement that expressly provides for a specific remedy in the event
of a breach of such provision, upon the occurrence of an Event of Default by a Party, the non-
defaulting Parties shall have available all remedies hereunder, as well as all legal and equitable
remedies, including those available in order to enforce payment of any amounts or performance of
any obligations, and no remedy conferred upon or reserved by a Party is intended to be exclusive
of any other remedy or remedies available hereunder or that now or hereafter exists at law or in
equity, each and every such remedy shall be cumulative and shall be in addition to every other
such remedy.
(b) Injunctive Relief and Specific Performance. Each Party
acknowledges and agrees that the failure to perform any of its respective obligations under this
Agreement would cause irreparable harm to the other Parties and that the remedy at law for any
violation or threatened violation thereof would be inadequate, and further agrees that the other
Parties shall be entitled to a temporary or permanent injunction, specific performance or other
equitable relief specifically to enforce such obligations without the necessity of proving the
inadequacy of its legal remedies. No Party shall be required to post any guaranty, letter of credit,
bond or other security to obtain an order or decree of specific performance.
(c) Loss of Voting Rights. If an Event of Default by a Party has occurred
under Section 16.01(a), Section 16.01(>;) due to the failure of the ON Line Security Interest or GB
Segment Security Interest to be valid, legal, perfected and in full force and effect, or Section
16.01 b with respect to the failure to provide the other Parties with their respective Capacity
Entitlements, without limiting any other rights that the non-defaulting Parties might have, for so
long as such Event of Default remains outstanding (i) the defaulting Party's Authorized
Representatives shall not have any right to decide,approve,authorize or vote on any matters before
the Management Committee and(ii)the other Party's Authorized Representatives shall be entitled
to represent the defaulting Party with respect to all matters before the Management Committee and
the quorum requirements under Section 8.01(f) shall be deemed satisfied.
(d) Purchase Right Upon Default. If(i) an Event of Default by a Party
has occurred under Section 16.01(a) and the aggregate amount that remains unpaid by such Party
exceeds five million Dollars ($5,000,000), (ii) an Event of Default has occurred by a Party under
Section 16.01(b) with respect to the failure to provide the other Parties' their respective Capacity
Entitlements, (iii) an Event of Default has occurred under Section 16.01(O due to the failure of
the ON Line Security Interest or GB Segment Security Interest to be valid, legal,perfected and in
full force and effect, in either case, and such event has occurred after the Acquisition Closing Date
and is continuing, then, without limiting any other rights that the non-defaulting Parties might
have, a non-defaulting Party may, upon written notice to the defaulting Party (the "Default
Purchase Notice") delivered while such Event of Default remains outstanding, purchase all of the
Ownership Interests of the defaulting Party. Upon a non-defaulting Party providing the defaulting
Party with the Default Purchase Notice, and, as the case may be, subject to the consent of the NVE
Lenders to the extent required under the NVE Lenders' financing and security agreements or the
consent of the ON Line Lenders if the proceeds of the Transfer are less than the obligations owed
by Great Basin to the ON Line Lenders, then the defaulting Party shall Transfer its Ownership
Interest to such non-defaulting Party free and clear of any Liens other than Permitted Liens within
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fifteen (15) days after receipt of such notice and receipt of PUCN Approval and all required
Governmental Approvals on terms acceptable to the NVE Parties. At the time such Transfer
occurs, such non-defaulting Party shall pay to the defaulting Party an amount equal to the lower
of(A)book value of the defaulting Party's Ownership Interest on the date of the Default Purchase
Notice and (B) the Fair Market Value of the defaulting Party's Ownership Interest on the date of
the Default Purchase Notice. The defaulting Party shall make Applicable Transfer Representations
and Warranties in connection with such Transfer.
(e) Step-In Rights.
(i) Construction Step-In. If an action by the Managing Party
undertaken in connection with its management responsibilities results in an Event of
Default or, upon the occurrence of the circumstances described in Section 5.03(e), then,
without limiting any other rights that the Step-In Party might otherwise have, the Step-In
Party may, upon written notice to the Managing Party delivered at any time prior to the
Managing Party having cured such default or, in the case of Section 5.03(e), at any time
prior to the NVE Parties committing to fund their Ownership Percentage of such Initial
Cost Differential or Incremental Cost Differential, assume the management of all ON Line
Activities. If the Step-In Party exercises its rights provided in this Section 16.02(e)(i),the
Step-In Party shall appoint its ON Line Manager in charge of the Managing Party's
responsibilities hereunder, and may retain such managerial responsibilities until ON Line
COD or relinquish all or any part thereof from time to time to the Managing Party;
provided, however, that the Managing Party may elect to reacquire management of the
ON Line Activities, to the extent such management was the Managing Party's
responsibility prior to the exercise of the Step-In Party's rights under this Section
16.02(e)(i), once the Managing Party has no Events of Default outstanding or commits to
fund its Ownership Percentage of the Initial Cost Differential or Incremental Cost
Differential, as applicable. Notwithstanding anything herein to the contrary, (A) any
reasonable costs and expenses related to the Step-In Party's exercise of its rights provided
in this Section 16.02(e)(i) and(B) any reasonable incremental costs and expenses related
to the Step-In Party's assumption of the Managing Party's responsibilities hereunder,shall
be borne by the Managing Party.
(ii) Maintenance Step-In. If(A) after ON Line COD, ON Line
(or a portion thereof)or(B) after the commercial operation of a Great Basin Segment, any
Great Basin Segment (or a portion thereof), in either case, is materially impaired due to
an Event of Default under Section 16.01(b) constituting Willful Misconduct/Gross
Negligence by NPC or Great Basin in its role as maintainer of ON Line or the Great Basin
Segments, as applicable, then, without limiting any other rights that the Step-In Party
might otherwise have, the Step-In Party may, upon written notice to the defaulting Party
delivered at any time prior to the defaulting Party having cured such Event of Default,
assume management of the maintenance responsibilities on any portion of the
Transmission Line for which the defaulting Party has maintenance responsibility and all
responsibilities set forth in this Agreement related thereto. If the Step-In Party exercises
its rights provided in this Section 16.02(e)(ii), the Step-In Party may retain such
managerial responsibilities throughout the Term or relinquish all or any part thereof from
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time to time to the defaulting Party;provided,however,that the defaulting Party may elect
to reacquire such management responsibility, to the extent such management was the
defaulting Party's responsibility prior to the exercise of the Step-In Party's rights under
this Section 16.02(e)(ii), once the defaulting Party has corrected the material impairment.
Notwithstanding anything herein to the contrary, (X) any reasonable costs and expenses
related to the Step-In Party's exercise of its rights provided in this Section 16.02(e)(ii) and
(Y) any reasonable incremental costs and expenses related to the Step-In Party's
assumption of the defaulting Party's responsibilities hereunder, shall be borne by the
defaulting Party; provided, that, in the event the Step-In Party retains an Independent
Contractor or other third party to assume management of the maintenance responsibilities
on any portion of the Transmission Line for which the defaulting Party has maintenance
responsibility, such Independent Contractor or other third party shall be reasonably
acceptable to the defaulting Party (such acceptance being without prejudice to the
defaulting Party's right to dispute the amounts charged by such Independent Contractor
or other third party). If a Step-In Party takes over the management of maintenance
obligations from the defaulting Party pursuant to this Section 16.02(e)(ii), the Step-In
Party shall indemnify the defaulting Party and its Affiliates for any fines,penalties or other
charges levied against the defaulting Party and its Affiliates as a result of a failure to
properly maintain the portion of the Transmission Line for which the Step-In Party
assumed maintenance responsibility pursuant to this Section 16.02(e)(ii)during the period
the Step-In Party has taken over the management of such maintenance(except to the extent
such fines, penalties or other charges arise as a result of the Willful Misconduct/Gross
Negligence of the defaulting Party and/or any of its Affiliates).
(iii) Operations Step-In. If, at any time after ON Line COD, the
NVE Parties no longer qualify as public utilities under Nevada law and ON Line is
materially impaired due to an Event of Default under Section 16.01(b)constituting Willful
Misconduct/Gross Negligence by NPC, then, without limiting any other rights that Great
Basin might otherwise have, Great Basin may, upon written notice to the NVE Parties
delivered at any time prior to the defaulting Party having cured such Event of Default,
assume management of the operation of the Transmission Line, including all Operating
Activities, and all responsibilities set forth in this Agreement related thereto. If Great
Basin exercises its rights provided in this Section 16.02(e)(iii), Great Basin may retain
such managerial responsibilities throughout the Term or relinquish all or any part thereof
from time to time to the NVE Parties. Notwithstanding anything herein to the contrary,
(X) any reasonable costs and expenses related to Great Basin's exercise of its rights
provided in this Section 16.02(e)(ii) and (Y) any reasonable incremental costs and
expenses related to the Great Basin's assumption of the NVE Party's responsibilities
hereunder, shall be borne by the NVE Party; provided, that, in the event Great Basin
retains a third party to assume management of the operation of the Transmission Line,
such third party shall be reasonably acceptable to the defaulting Party (such acceptance
being without prejudice to the defaulting Party's right to dispute the amounts charged by
such third party).
(f) Ownership Adjustment. If an Event of Default has occurred under
Section 16.01(a),then,without limiting any other rights that the non-defaulting Parties might have,
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to the extent such Event of Default has not otherwise been satisfied in full upon the exercise by
the non-defaulting Party of its rights under Section 16.02W, a non-defaulting Party may, after the
Acquisition Closing, upon written notice to the Parties delivered while such Event of Default
remains outstanding, cause a reduction in the defaulting Party's Ownership Percentage within
fifteen (15) days after receipt of such notice and receipt of PUCN Approval and all required
Governmental Approvals on terms acceptable to the NVE Parties, such that the defaulting Party's
Ownership Percentage equals a ratio(i)the numerator of which is equal to the portion of the Total
Costs paid by the defaulting Party and (ii) the denominator of which equals the Total Costs, and
the defaulting Party shall Transfer the portion of its Ownership Interest corresponding to its excess
above its revised Ownership Percentage to each non-defaulting Party free and clear of any Liens
other than Permitted Liens. Thereafter, each Party's Capacity Entitlement shall automatically and
proportionately increase or decrease, as applicable, with such Party's increase or decrease of
Ownership Interest. The defaulting Party shall execute and record any bills of sale, deeds,
certificates or other documentation as reasonably requested by any non-defaulting Party to
evidence the re-allocation of such interests. The defaulting Party shall make Applicable Transfer
Representations and Warranties in connection with such Transfer.
(g) Loss of Right to Revenue or Electrical Capacity. If an Event of
Default has occurred under Section 16.01(a), then, without limiting any other rights that the non-
defaulting Parties might have, to the extent such Event of Default has not otherwise been satisfied
in full upon the exercise by the non-defaulting Party of its rights under Section 16.02(f), a non-
defaulting Party may,upon fifteen(15) days' prior written notice to the defaulting Party delivered
while such Event of Default remains outstanding, recover the defaulted payments by temporarily
receiving all or any part of the defaulting Party's Capacity Entitlement. Receipt of the defaulting
Party's Capacity Entitlement shall continue until such time as the non-defaulting Party has
received an amount equal to the payment default plus interest at the Default Rate,determined based
on amounts that would otherwise be payable for such Capacity Entitlement under the applicable
open access transmission tariff of the non-defaulting Party. Once such non-defaulting Party has
received such additional amount,the defaulting Party shall immediately,and without further action
by the Parties, be entitled to fully receive its Capacity Entitlement. In the event receipt of the
defaulting Party's Capacity Entitlement is not practicable due to regulatory requirements or the
rights of third Persons,the defaulting Party shall pay over to the non-defaulting Party all proceeds,
promptly upon the defaulting Party's receipt of such proceeds, of the defaulting Party's Capacity
Entitlement until such time as the non-defaulting Party has received an amount equal to the
payment default plus interest at the Default Rate.
(h) If an Event of Default of NPC has occurred under Section 16.01(a) in
respect of one or more Contributions or payments and has continued for a period of one hundred
twenty(120) days and the aggregate amount due and payable from NPC to Great Basin in respect
of such Contributions or payments exceeds (x) from ON Line COD to the thirtieth (30th)
anniversary of such date, five million Dollars ($5,000,000) and (y) from the thirtieth (30th)
anniversary of ON Line COD to the forty-first (41 st) anniversary of ON Line COD, one million
Dollars ($1,000,000) (an "Extended Payment Default"), Great Basin shall possess the right to
terminate the NVE Parties' Capacity Entitlement other than the portion of their Capacity
Entitlement on ON Line corresponding to their aggregate Ownership Interest (the "Terminated
Capacity") by sending written notice (by facsimile or other reasonable means) to NPC, which
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notice of termination shall become effective thirty(30) days after receipt if the NVE Parties fail to
cure the Extended Payment Default prior to such thirtieth (30th) day. If Great Basin fails to
exercise this right of termination within thirty (30) days following the time when the Extended
Payment Default first accrues (or more than thirty (30) days if the Parties agree to an extension),
then such right of termination shall no longer be available to Great Basin as a remedy for the
defaulted Contributions and payments constituting such Extended Payment Default, but shall be
available for subsequent defaulted Contributions and payments to the extent they satisfy the
requirements for an Extended Payment Default. The termination of the Terminated Capacity and
payment of the Termination Payment (if any) shall be the sole and exclusive remedy for Great
Basin for the Extended Payment Default for the time period beginning at the time notice of
termination under this Section 16.02(h) is transmitted; provided, however, that Great Basin may
exercise any remedies available to it under this Section 16.02 prior to its transmittal of such notice
of termination. Great Basin shall calculate the payment associated with termination("Termination
Pae") as follows:
(i) Any Loss shall be determined by comparing the value of the
Terminated Capacity had it not been terminated plus Costs to the equivalent quantities
and relevant market prices for the remaining term of the Monthly Payment Period either
quoted by a bona fide third-party offer or which are reasonably expected to be available
in the market under a replacement contract or contracts for such Terminated Capacity. To
ascertain the market prices of a replacement contracts, Great Basin may consider, among
other valuations, quotations from dealers in transmission capacity and other bona fide
third party offers, all adjusted for the length of the remaining term. It is expressly agreed
that Great Basin shall not be required to enter into replacement transactions in order to
determine the Termination Payment.
(ii) Any Loss calculated under clause (i) shall be discounted to
present value using the Present Value Rate as of the time of termination (to take account
to the period between the time the termination was effective and when such amount would
have otherwise been due pursuant to this Agreement). The "Present Value Rate" shall
mean the sum of 0.50%plus the yield reported on page"USD"of the Bloomberg Financial
Markets Services Screen (or, if not available, any other nationally recognized trading
screen reporting on-line intraday trading in United States government securities) at 11:00
a.m. (New York City,New York time) for the United States government securities having
a maturity that matches the average remaining term of the Monthly Payment Period; and
(iii) Great Basin shall aggregate any Loss with Outstanding
Payments and notify NPC of such amount and the NVE Parties shall, within three (3)
Business Days of receipt of such notice, pay to Great Basin an amount equal to the
aggregate sum of the Loss(if any)and Outstanding Payments as the Termination Payment.
The Termination Payment shall bear interest at the Present Value Rate from the time
notice of termination was received until paid.
(iv) For purposes of this Section 16.02(h):
(A) "Loss" means the economic loss (inclusive of
Costs), if any, resulting from the termination of the Terminated Capacity,
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determined in a commercially reasonable manner as calculated in accordance with
this Section 16.02(h);
(B) "Costs" means brokerage fees, commissions and
other similar transaction costs and expenses reasonably incurred in terminating any
specifically related arrangements which replace the Terminated Capacity and
reasonable attorneys' fees, if any, incurred in connection with Great Basin
enforcing its rights under this Section 16.02(12). Great Basin shall use reasonable
efforts to mitigate or eliminate these Costs.
(C) "Outstanding Payments" means the aggregate
amount of payments due and owing under this Agreement(and not otherwise paid)
by the NVE Parties to Great Basin as of the date on which the termination of the
Terminated Capacity becomes effective (it being understood that payment of the
Outstanding Payments to Great Basin shall be in satisfaction of the NVE Parties'
obligation to make such payments under this Agreement);
(D) In no event,however, shall a Party's Loss,Costs or
Outstanding Payments include any penalties or similar charges imposed by Great
Basin.
(v) Notwithstanding anything in this Agreement to the contrary,
upon the effectiveness of the notice terminating the Terminated Capacity (A) the NVE
Parties' Capacity Entitlement with respect to Electrical Capacity on ON Line shall be
equal to the NVE Parties' Ownership Percentage and the NVE Parties shall not be entitled
to any Electrical Capacity on the Great Basin Segments, (B) all Operating Costs, Event of
Loss Costs, Condemnation Action Costs and Capital Repair Costs shall be funded by the
Parties in accordance with their respective Ownership Percentages and Great Basin shall
have no right to recover Great Basin's Ownership Percentage of any such costs from the
NVE Parties and(C)the NVE Parties' obligation to pay the Monthly Payment shall cease
as provided in Section 3.06(c). Payment of the Termination Payment pursuant to this
Section 16.02(h) shall cure any Event of Default and Extended Payment Default giving
rise to Great Basin's rights under this Section 16.02(h).
(i) Other Remedies. Prior to the Acquisition Closing Date and in the
event the Acquisition Closing does not occur, breaches of representations and warranties and
covenants shall be exclusively governed by Section 11.03. After the Acquisition Closing Date,
breaches of representations and warranties shall be exclusively governed by Article XI I, subject
to the limitations set forth therein.
16.03 Additional Obligations._ With respect to a Party as to which an Event of
Default has occurred, such Party shall take any and all such further actions and shall execute and
file where appropriate any and all such further legal documents and papers as may be reasonable
under the circumstances resulting from such Event of Default in order to facilitate the carrying out
of this Agreement or otherwise effectuate its purpose, including action to seek any required
Governmental Approval and to obtain any other required consent, release, amendment or other
similar document.
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16.04 Interest on Overdue Payments and Contributions; Setoff. If any sum due
hereunder is not paid or contributed by the due date thereof, the Party owing such obligation shall
pay to the other Parties interest thereon at the Default Rate concurrently with the payment of the
amount, such interest to begin to accrue as of the due date of such payment or Contribution.
Further, each non-defaulting Party shall have the right to setoff any amount owed to it by a
defaulting Party hereunder against any amounts owed by it to such defaulting Party hereunder.
16.05 Mitigation. Each Party shall use commercially reasonable efforts to
mitigate all of its damages and losses resulting from an Event of Default by any other Party.
ARTICLE XVII
REPRESENTATIONS AND WARRANTIES
17.01 Representations and Warranties. Each Party represents and warrants to
each other Party, as of the Effective Date and again as of the Acquisition Closing Date (as though
made on and as of such date), except as set forth in the disclosure schedules delivered among the
Parties prior to the Effective Date (the "Disclosure Schedules") and the Disclosure Schedule
Update:
(a) Due Organization. Such Party is a duly organized, validly existing
entity of the type described in the preface to this Agreement and is in good standing under the laws
of the jurisdiction of its formation and is duly qualified to do business and in good standing as a
foreign entity in the jurisdiction of its principal place of business(if not formed in that jurisdiction).
(b) Power and Authority. Such Party has the full corporate or limited
liability company, as applicable, legal right, power and authority to enter into this Agreement and
perform its obligations under this Agreement.
(c) Due Authorization. Such Party has taken all appropriate and
necessary corporate or limited liability company, as applicable, action to authorize its execution,
delivery and performance of this Agreement and the transactions contemplated hereunder.
(d) Consents. Except for, in the case of Great Basin, the Required
Consents, such Party has obtained all consents, approvals, permits and other authorizations in
connection with the execution,delivery and performance of this Agreement required to be obtained
by it; provided, however, that no Party makes any representation or warranty under this Section
17.01 d with respect to any consents, approvals,permits or other authorizations necessary for the
development, construction, operation or maintenance of the Transmission Line or, except with
respect to the Acquisition Closing, any consents, approvals, permits or other authorizations
necessary in connection with the acquisition by one Party of any other Party's Ownership Interests
pursuant to the terms of this Agreement.
(e) Binding Obligation._ This Agreement constitutes a legal, valid and
binding obligation of such Party, enforceable against such Party in accordance with its terms
(subject to the effects of bankruptcy, insolvency, reorganization, moratorium, fraudulent
conveyance or other Applicable Laws now or hereafter in effect relating to creditors' rights
generally and general principles of equity).
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(f) No Violation. The execution,delivery and performance by such Party
of this Agreement, the compliance with the terms and provisions hereof and the carrying out of
the transactions contemplated hereby, (i) do not conflict with and will not result in a breach or
violation of any of the terms or provisions of the organizational documents of such Party, (ii) do
not conflict with and will not result in a material breach or violation of any of the terms or
provisions of any existing Applicable Law to which such Party is subject or by which it or any of
its material property is bound, or any material agreement or instrument to which such Party is a
party or by which it or any of its material property is bound, or constitutes or will constitute a
default thereunder or (iii) in the case of Great Basin, will not result in the imposition of any Lien
(other than under any financing or security agreements with the NVE Lenders or a Permitted Lien)
upon any of the Ownership Interests being Transferred to NPC and SPPC at the Acquisition
Closing.
(g) Brokers. All negotiations relative to this Agreement and the
transactions contemplated hereby have been carried out by each Party directly with each other
Party without the intervention of any Person on behalf of such Party in such manner as to give rise
to any valid claim by any Person against each other Party for a finder's fee,brokerage commission
or similar payment.
(h) No Litigation and Compliance with Law. There is no litigation
pending or, to such Party's knowledge, threatened to which such Party or any of its Affiliates is a
party that could reasonably be expected to have a Material Adverse Effect. Such Party is not in
violation of any Applicable Law where the effect of which to such Party, individually or in the
aggregate, could be reasonably expected to have a Material Adverse Effect.
17.02 Special Representations and Warranties of Great Basin. On and as of the
Acquisition Closing Date (as though made on and as of such date), Great Basin represents and
warrants to each of the NVE Parties as follows, except as set forth in the Disclosure Schedules
attached to this Agreement and the Disclosure Schedule Update:
(a) Title to ON Line. Great Basin possesses good, valid and marketable
title to all of the personal property comprising ON Line (tangible and intangible assets) and good,
valid, marketable and indefeasible title to the rights granted to Great Basin pursuant to the ON
Line ROW (subject to the BLM restrictions in the ON Line ROW) and Land Contracts, in each
case, free and clear of all Liens except Excluded Liens, and, effective upon the Acquisition
Closing, (i) upon payment of the NVE Parties' Closing Payment (if any), NPC and SPPC shall
own and hold good, valid and marketable title to an undivided ownership interest equal to their
respective Ownership Percentages in all of ON Line constituting personal property (tangible and
intangible assets) and (ii) NPC and SPPC shall own and hold good, valid, marketable and
indefeasible title to an undivided ownership interest equal to their respective Ownership
Percentages in the real property comprising ON Line (including the ON Line ROW and Land
Contracts) or a good, valid and marketable leasehold interest in the real property comprising ON
Line (including the ON Line ROW and Land Contracts) equal to their respective Ownership
Percentages, in each case, free and clear of all Liens except Permitted Liens.
(b) Agreements. Great Basin is a party to all ON Line Agreements and it
has delivered true, correct and complete copies of each ON Line Agreement (including any
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amendment thereto) to the NVE Parties as of the Acquisition Closing Date and any other
agreement to which ON Line may be subject. Each ON Line Agreement is in full force and effect
against Great Basin and, to Great Basin's knowledge, the other parties thereto and(i) Great Basin
is not in material breach of its obligations under any such agreement, (ii) to Great Basin's
knowledge, no counterparty to any such agreement is in material default of its obligations under
any such agreement and(iii)each such agreement is an enforceable and binding obligation of Great
Basin and, to Great Basin's knowledge, the other parties thereto (subject to the effects of
bankruptcy, insolvency, reorganization, moratorium, fraudulent conveyance or other Applicable
Laws now or hereafter in effect relating to creditors' rights generally and general principles of
equity).
(c) Real Property.
(i) Neither the whole nor any portion of the real property
comprising ON Line (including the ON Line ROW and Land Contracts) is subject to any
governmental decree or order to be sold or is being condemned, expropriated or otherwise
taken by any public authority with or without payment of compensation therefor, nor, to
Great Basin's knowledge, has any such condemnation, expropriation or taking been
proposed.
(ii) Great Basin has not received any written notice of, or has
any knowledge of, any action, proceeding or litigation pending or threatened to modify
the zoning of, or other governmental rules or restrictions applicable to, the real property
comprising ON Line (including the ON Line ROW and Land Contracts) or the use or
development thereof.
(iii) There are no agreements with any Governmental Authority
affecting the use or ownership of the real property comprising ON Line(including the ON
Line ROW and Land Contracts), true, correct and complete copies of which (including
any amendment thereto) have not been provided to the NVE Parties.
(d) Governmental Approvals; Compliance with Laws; Hazardous
Substances.
(i) Great Basin has obtained all Governmental Approvals that
are necessary or customarily obtained for the current stage of ON Line and necessary or
customarily obtained for Great Basin to perform its obligations under this Agreement and
each ON Line Agreement as of Acquisition Closing Date (other than any Governmental
Approvals related to the construction of the Robinson Summit Substation at the Robinson
Summit Location).
(ii) Great Basin has provided true, correct and complete copies
of each Governmental Approval for ON Line that has been obtained by Great Basin, and
all applications for any pending Governmental Approval,to the NVE Parties and the status
of each Governmental Approval for ON Line is set forth in Schedule 6 (it being
understood that Schedule 6: (A) includes some Governmental Approvals that would not
be customarily obtained as of the Acquisition Closing Date in light of the then-current
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stage of construction of ON Line (which are identified on Schedule 6 with an asterisk)
and therefore will not necessarily be obtained by the Acquisition Closing Date and (B) is
true and correct only as of the Effective Date, but will be modified via the Disclosure
Schedule Update to set forth the status of each Governmental Approval listed on Schedule
6 as of the Acquisition Closing Date).
(iii) No application submitted by or on behalf of Great Basin or
any of its Affiliates in connection with any Governmental Approval for ON Line contains
any intentional misrepresentation. Great Basin is in compliance with each Governmental
Approval for ON Line in all material respects and each Governmental Approval for ON
Line (A) is in full force and effect, (B) is not subject to any legal proceeding or to any
unsatisfied condition that is not reasonably expected to be satisfied or could reasonably
be expected to allow material modification or revocation thereof and (C) is final and all
applicable appeal periods have expired or terminated.
(iv) Except for modifications to Governmental Approvals for
ON Line that have already been made, no modification to a Governmental Approval is
required for the conveyance or acquisition of the undivided ownership interests in ON
Line to NPC and SPPC equal to their respective Ownership Percentages. No further action
is required for each Governmental Approval for ON Line to be properly in the name of
the Parties.
(v) Great Basin is in compliance with all Applicable Laws in all
material respects with respect to ON Line.
(vi) Great Basin is in compliance with all Environmental Laws
in all material respects with respect to ON Line. To the knowledge of Great Basin,
Hazardous Substances have not been released, spilled, leaked or disposed of on, at, or
under the ON Line ROW, or on, at, or under any property adjacent to the ON Line ROW,
in any amount or concentration that is likely to require investigation or remediation
pursuant to applicable Environmental Laws or in connection with the development,
construction or operation of ON Line.
(vii) Great Basin has obtained the Required Consents.
17.03 MOU. Great Basin represents and warrants as of the Effective Date that it
has not, prior to the Effective Date, to the extent inconsistent with the MOU: (a) sold, assigned,
encumbered, transferred, allowed a Lien to exist upon or otherwise disposed of any interest in or
rights to ON Line,(b)directly or indirectly negotiated,discussed in any material respect,or entered
into any agreement or participated in any inquiries or proposals in any material respect regarding
the purchase of any interest in or rights to ON Line (other than the right to use Great Basin's
Capacity Entitlement with respect to ON Line from and after GB Segment COD), (c) made any
public announcement regarding this Agreement or the transactions contemplated hereby without
prior consultation with the NVE Parties, (d) assigned the MOU without the prior written consent
of the NVE Parties, or (e) done any of the following without the written consent of the NVE
Parties: submitted an application for or accepted any required Governmental Approval in respect
of ON Line, selected a material contractor or vendor for ON Line,made any material modification
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to ON Line's conceptual design, executed, terminated or amended any ON Line Agreement or
waived any of the material terms thereof or exercised any remedies thereunder, initiated or settled
any material litigation, arbitration or other dispute regarding ON Line or any ON Line Agreement,
or adopted any material community outreach or government relations programs for ON Line.
Great Basin further represents and warrants as of the Effective Date that it has, prior to the
Effective Date, promptly (x) provided the NVE Parties with all Governmental Approvals
(including applications therefor), ON Line Agreements (including drafts thereof), and material
communications regarding ON Line, and all material information regarding land rights, expected
development, construction and operation costs, constructability, copies of studies, reports, and
data, and any other information regarding ON Line and Great Basin and its Affiliates providing
services under any ON Line Agreement, in each case to the extent reasonably requested by the
NVE Parties and (y) notified the NVE Parties of all material events in connection with ON Line
of which Great Basin has knowledge, including any dispute under an ON Line Agreement and any
litigation or arbitration in connection with ON Line.
17.04 Non-Severable Improvements. Each NVE Party represents and warrants to
Great Basin,that as of the Effective Date,the NVE Parties do not currently have any plan to make
any material,non-severable(a) improvement, (b)modification or(c) addition to ON Line that will
be paid for by the NVE Parties after the ON Line COD, other than any such non-severable
improvements described in Section 3.04(3) of Internal Revenue Service Revenue Procedure 2001-
28, 2001-1 C.B. 1156; provided, however, that the Parties recognize that the NVE Parties are
public utilities regulated by the PUCN and FERC and may be required at any time to accommodate
transmission service requests and interconnection requests that may require modifications to ON
Line or its interconnected transmission system(s).
17.05 Knowledge. When used in this Article XVII, the term "knowledge", when
used in reference to Great Basin shall mean the actual knowledge of any of Jason Hochberg, Paul
Thessen, Joseph Esteves, Richard Roloff, Mark Milburn and Andrew Dera, and when used in
reference to the NVE Parties shall mean the actual knowledge of any of Roberto Denis, Mario
Villar, Ryan Smith and John Berdrow.
17.06 Exclusivitypresentations. The representations and warranties made
by each Party in this Article XVII are the exclusive representations and warranties made by such
Party with respect to itself and the Transmission Line and the transactions contemplated in this
Agreement. Each Party hereby disclaims any other express or implied representations or
warranties with respect to itself or the Transmission Line. Except as expressly set forth in this
Agreement,the condition of the assets of the Parties shall be"as is"and"where is"and each Party
makes no warranty of merchantability, suitability, fitness for a particular purpose or quality with
respect to any of the tangible assets of such Party(including the Transmission Line or any portion
thereof) or as to the condition or workmanship thereof or the absence of any defects therein,
whether latent or patent.
ARTICLE XVIII
LIENS; FINANCING MATTERS
18.01 Liens.
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(a) Without the prior written consent of the Parties, (i) no Party may
create or permit to exist a Lien(other than an Excluded Lien) on its Ownership Interests(from and
after the Effective Date), (ii) Great Basin may not create or permit to exist a Lien (other than an
Excluded Lien) on the Great Basin Segments (from and after the Effective Date), provided that
this clause (ii) and clause (i) above shall not apply to the excluded assets referred to in the first
proviso set forth in Section 18.04(a), (iii) no Party may take any action that would either cause or
permit a Lien to exist on the Ownership Interests of any other Party and (iv) neither NVE Party
may take any action that would either cause or permit a Lien to exist on Great Basin's ownership
interests in the Great Basin Segments; provided, however, that without the consent of any Party,
in the course of performing ON Line Activities or Operating Activities, the Managing Party or
NPC, as applicable, may, to the extent approved by the Parties (unless NPC is solely responsible,
whether directly or through the payment of the Monthly Payment, for the payment of any amount
referred to in clause (i) or(ii) below), create or permit to exist on the Ownership Interests: (i) any
Lien for Taxes being contested in good faith by appropriate proceedings for which adequate
reserves have been established in accordance with GAAP and (ii) any statutory Lien (including
any Liens of carriers, warehousemen, mechanics and materialmen arising in the ordinary course
of business by operation of law) with respect to a liability which is being contested in good faith,
in each case in (i) and (ii) above, only so long as such Liens shall not involve any reasonable
likelihood of the sale, forfeiture or loss of any material interest in the Transmission Line and shall
not interfere in any material respect with the use or disposition of any material part of the
Transmission Line, the GB Segment Security Interest or the ON Line Security Interest. Great
Basin shall directly acquire and continue to directly own all of the Transmission Line, except with
respect to the NVE Parties' Ownership Interests and the Transfer of ownership interests in the
Transmission Line permitted by this Agreement. Each Party shall promptly notify the other Parties
of the attachment or imposition of any Lien not permitted by this Agreement. Great Basin may
not take any action to either create or permit to exist a Lien on any Applicable Centennial Phase 3
Facilities without NPC's prior written consent; provided, however, that nothing contained herein
shall prevent Great Basin from creating or permitting to exist an Excluded Lien on the Applicable
Centennial Phase 3 Rights during the effectiveness of the SNIP Agreement. Notwithstanding
anything in this Section 18.01(a) to the contrary, any Party may obtain a judgment Lien against
any other Party based on any such other Party's breach under this Agreement, any Security
Document,the SNIP Agreement or any other agreement,and the NVE Parties may create or permit
to exist the ON Line Security Interest and GB Segment Security Interest.
(b) If (i) any Lien (other than an Excluded Lien) is filed against the
Transmission Line by reason of any services or materials supplied or claimed to have been supplied
on or to all or part of the Transmission Line and(ii) such Lien has not been satisfied or discharged
of record, or its enforcement precluded, to the reasonable satisfaction of the Management
Committee, by injunction, payment, deposit, bond, order of court or otherwise as soon as is
reasonably practicable and, in any event, no later than the earlier of(i) ninety (90) days after the
creation of such Lien and (ii) ninety(90) days prior to the first date on which foreclosure of such
Lien is permitted under Applicable Laws, then a Party shall have the right, but not the obligation,
to satisfy, bond or discharge such Lien and the amount incurred by such Party shall be promptly
reimbursed by the other Parties in proportion to their respective Ownership Percentages;provided,
however, that (A) in the event such Lien has been imposed as a consequence of an unauthorized
act or omission, negligence, gross negligence or willful misconduct of a Party, such Party shall
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pay all costs in connection with satisfying, bonding and discharging such Lien and (B) except as
provided in clause (A) above, in the event such Lien has been imposed on the Great Basin
Segments, Great Basin shall pay all costs in connection with satisfying, bonding and discharging
such Lien.
(c) If(i) at any time there exists a Lien to which the NVE Parties are not
senior (except as permitted by Section 18.04(e)) and (ii) such Lien has not been satisfied or
discharged of record, or its enforcement precluded, to the reasonable satisfaction of the NVE
Parties,by injunction,payment, deposit,bond, order of court or otherwise as soon as is reasonably
practicable and, in any event, no later than fifteen (15) days after the NVE Parties first failed to
have seniority with respect to such Lien (except as permitted by Section 18.04(e)), then the NVE
Parties shall have the right,but not the obligation, to satisfy, bond or discharge such Lien and any
costs incurred by any such NVE Party in connection therewith shall be promptly paid to such Party
or Parties by Great Basin.
18.02 Financing.
(a) Great Basin acknowledges that the NVE Parties intend to enter into
discussions with certain U.S. governmental entities regarding providing financing for their share
of the ON Line Costs, and each of the NVE Parties acknowledges that Great Basin intends to enter
into discussions with certain U.S. governmental entities regarding such Persons providing
financing for its share of the ON Line Costs. At the requesting Party's cost, each Party agrees to
cooperate with the other Parties in their efforts to obtain financing from the NVE Lenders, ON
Line Lenders and GB Segment Lenders, as applicable, and provide such other support as may be
reasonably required in connection therewith.
(b) At the requesting Party's cost, each other Party agrees to execute and
deliver to and in favor of the ON Line Lenders, GB Segment Lenders or NVE Lenders, as
applicable, a consent to assignment and such other documents customary for finance transactions
of the types contemplated hereby(including customary legal opinions of the NVE Parties' outside
counsel) and reasonably requested by the ON Line Lenders, GB Segment Lenders or NVE
Lenders, respectively, and reasonably acceptable to the NVE Parties or Great Basin, respectively.
18.03 Non-Disturbance Agreement.
(a) As a condition to (i) granting any Lien over any part of the
Transmission Line to an ON Line Lender or a GB Segment Lender or (ii) granting any Lien over
any part of the Transmission Line as contemplated under Section (g)(i)(B), ii B or(D of the
definition of Excluded Lien (in the case of this clause (ii), only to the extent a Non-Disturbance
Agreement is required under Section (g)(i)(B), ii B or(11,)of the definition of Excluded Lien
to constitute an Excluded Lien), Great Basin shall cause such ON Line Lender (or its agent), GB
Segment Lender (or its agent) or other Person (any such ON Line Lender, GB Segment Lender,
agent or other Person, a "Designated Secured Party") to enter into and maintain in full force and
effect a non-disturbance agreement containing the principles set forth below(except as the parties
thereto otherwise agree in such non-disturbance agreement in their respective sole discretion) and
otherwise in form and substance reasonably satisfactory to the NVE Parties (a"Non-Disturbance
Agreement"):
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(i) except in connection with the exercise of remedies for(A)the
NVE Parties' default under this Agreement to the extent such remedy is exercised in
accordance with this Agreement or(B)default by the NVE Parties' or other counterparty's
default under any other ON Line Agreement assigned to such Designated Secured Party
(collectively with this Agreement,the"Assignedgreements")to the extent such remedy
is exercised in accordance with such other ON Line Agreement,none of either of the NVE
Parties or any other counterparty's rights under such Assigned Agreement shall be
disturbed in connection with the exercise of any right of such Designated Secured Party
under any loan or security agreement or otherwise, and such Designated Secured Party
shall agree not to take any action or request any relief or remedy that would terminate
such Assigned Agreement or otherwise impair the NVE Parties or such counterparty's
rights under such Assigned Agreement or in connection with the Transmission Line;
(ii) without prejudice to any remedies against the NVE Parties for
their default under this Agreement or any other Assigned Agreement, if such Designated
Secured Party(or its designee)forecloses on,takes title to,sells or otherwise assigns(such
purchaser or assignee, a "Transferee") any interest in the Transmission Line (whether by
judicial or non judicial foreclosure sale, any conveyance in lieu of foreclosure or
otherwise), then (A) such Designated Secured Party (or such designee) shall
simultaneously foreclose on or take title to or sell or otherwise assign to such Transferee
all of the interests of Great Basin in the Transmission Line, (B) the Transmission Line
shall remain subject to the terms of each Assigned Agreement and (C) such Designated
Secured Party (or its designee) or Transferee (as the case may be) shall assume and be
bound by all obligations of Great Basin under each Assigned Agreement arising after such
foreclosure, taking title to, sale or other assignment (as the case may be) and each
Assigned Agreement shall continue in full force and effect against such Designated
Secured Party(or its designee) or Transferee; and
(iii) without prejudice to any remedies against the NVE Parties for
their default under this Agreement or any other Assigned Agreement, if (A) such
Designated Secured Party(or its designee) forecloses on, takes title to, sells or otherwise
assigns any interest in the Transmission Line (whether by judicial or non judicial
foreclosure sale,any conveyance in lieu of foreclosure or otherwise)and(B)any Assigned
Agreement is rejected or terminated as a result of any bankruptcy or similar proceeding
affecting Great Basin, then, at the NVE Parties request received within sixty (60) days
after the occurrence of such an event, such Designated Secured Party (or its designee) or
Transferee,as the case may be,shall execute and deliver a new agreement having identical
terms as such Assigned Agreement (subject to any conforming changes necessitated by
the substitution of parties); provided, that the term under the new agreement shall be no
longer than the remaining balance of the term specified in such Assigned Agreement.
(b) Section 18.03(a) shall not apply to any Lien permitted under clause
(1) of the definition of Excluded Lien to the extent such Lien secures vendor financing provided
by an equipment vendor and such Lien is solely on the equipment provided by such vendor.
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(c) No Party is responsible for the payment of principal and interest on
indebtedness solely encumbering the ownership interests of any other Party.
18.04 Security Interest.
(a) Pre-GB Segment COD Security Interests. To secure Great Basin's
obligations under this Agreement, the SNIP Agreement and all other agreements executed and
delivered herewith (but only if and to the extent any such other agreements provide that they are
to be so secured), unless the Parties agree in writing otherwise in their respective sole discretion,
(i) at the Acquisition Closing, Great Basin shall grant to the NVE Parties a security interest in(A)
all of Great Basin's right,title and interest in,to and under ON Line(which shall initially constitute
a seventy-five percent(75%)interest)and(B) all of its rights under this Agreement to the Monthly
Payment and any rights related to ON Line (collectively, the"ON Line Security Interest") and(ii)
at GB Segment Financial Closing, Great Basin shall grant to the NVE Parties either(A) a security
interest in all right, title and interest in, to and under the Great Basin Segments, provided that the
amount that may be realized with respect to such security interest shall not exceed thirty-eight
percent (38%) of the Anticipated Investments in the Great Basin Segments (the "GB Segment
Security Interest Cap") or (B) if Great Basin has made the Transfer contemplated by Section
15.03 i , or such security interest can be granted under Applicable Law without such transfer
and the NVE Parties consent in writing, a security interest in thirty-eight (38%) of all right, title
and interest, in,to and under the Great Basin Segments and(C) a security interest in Great Basin's
rights under this Agreement related to the Great Basin Segments that corresponds to the security
interest granted in clauses (A) and (B) above (collectively, the "GB Segment Security Interest"),
in each case pursuant to the Security Documents; provided, however, that, for the avoidance of
doubt, neither the ON Line Security Interest nor the GB Segment Security Interest shall include a
Lien on any of Great Basin's cash, accounts, securities, books and records (other than in respect
of ON Line Agreements, corresponding agreements required for the construction and operation of
the Great Basin Segments and Governmental Approvals), as more specifically described and
agreed in such Security Documents; provided, further that prior to GB Segment COD, the GB
Segment Security Interest shall only secure the obligations of Great Basin under this Agreement,
the SNIP Agreement and all agreements executed and delivered herewith, in each case that relate
to the Great Basin Segments (but only if and to the extent any such other agreements provide that
they are to be so secured), all as more specifically described and agreed in such Security
Documents.
(b) Post-GB Segment COD GB Segment Security Interest. Upon GB
Segment COD and if the Final NVE Capacity Entitlement (expressed as a percentage) is greater
than thirty-eight percent (38%), unless the Parties agree in writing otherwise in their respective
sole discretion, Great Basin shall either(i)increase the GB Segment Security Interest Cap to equal
the product of(A) the Final NVE Capacity Entitlement (expressed as a percentage) and (B) the
Anticipated Investments for the Great Basin Segments or(ii) if Great Basin has made the Transfer
contemplated by Section 15.03 f) i) or such security interest can be granted under Applicable Law
without such transfer and the NVE Parties consent in writing, grant the NVE Parties an increase
in the GB Segment Security Interest so that the GB Segment Security Interest shall provide the
NVE Parties with a security interest in a percentage of all right, title and interest in, to and under
the Great Basin Segments equal to the Final NVE Capacity Entitlement (expressed as a
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percentage); provided, that if Great Basin has granted the NVE Parties the security interest
contemplated by Section 18.04(a)(ii)(A) and subsequently Great Basin has made (or is making as
of GB Segment COD) the Transfer contemplated by Section 15.03(f)(i) or the security interest
referred to below can be granted under Applicable Law without such transfer and the NVE Parties
consent in writing, then Great Basin may(or, in the case of the Transfer contemplated by Section
15.03 i , shall) grant the NVE Parties the security interest contemplated by this Section
18.04(b)(ii) and, in such event, the NVE Parties shall release the residual security interest granted
by Great Basin under Section 18.04(a)(ii)(A) pursuant to release documentation reasonably
satisfactory to the NVE Parties, Great Basin and the GB Segment Lenders. The NVE Parties'
security interest in Great Basin's rights in this Agreement related to the Great Basin Segments
shall be adjusted to the extent necessary to be consistent with the adjustments contemplated by this
Section 18.04(b).
(c) Post-GB Segment COD ON Line Security Interest. Upon GB
Segment COD and if the GB Segment Security Interest is then valid, legal, perfected, in full force
and effect and has the priority contemplated by Section 18.04, and upon the written request of
Great Basin, unless the Parties agree in writing otherwise in their respective sole discretion, the
NVE Parties shall release a portion of the ON Line Security Interest pursuant to release
documentation reasonably satisfactory to the NVE Parties, Great Basin and the ON Line Lenders
so that the ON Line Security Interest shall provide the NVE Parties with (i) either (A) a security
interest in all of Great Basin's right, title and interest in, to and under ON Line, provided that the
amount that may be realized with respect to such security interest shall not exceed an amount equal
to the product of(1)the positive difference of(x)the Final NVE Capacity Entitlement(expressed
as a percentage) minus (y) the NVE Parties' aggregate Ownership Percentages and (2) the
Anticipated Investments in ON Line or(B) if Great Basin has made the Transfer contemplated by
Section 15.03(f)(i) or such security interest can be granted under Applicable Law without such
transfer and the NVE Parties consent in writing, a security interest in a percentage of all right,title
and interest in, to and under ON Line equal to (1) the positive difference of(x) the Final NVE
Capacity Entitlement(expressed as a percentage)minus(y)the NVE Parties' aggregate Ownership
Percentages and (ii) all right, title and interest of Great Basin in, to and under the Fiber Optic
Capacity and Microwave Capacity for ON Line. The NVE Parties' security interest in Great
Basin's rights in this Agreement related to ON Line shall be adjusted to the extent necessary to be
consistent with the adjustments contemplated by this Section 18.04(c).
(d) Ownership Adjustment. In the event that the NVE Parties'
Ownership Percentages increase or decrease in accordance with this Agreement, then, after GB
Segment COD and upon the written request of a Party,unless the Parties agree in writing otherwise
in their respective sole discretion,the NVE Parties shall release a portion of the ON Line Security
Interest pursuant to documentation reasonably satisfactory to Great Basin and the ON Line
Lenders, or Great Basin shall grant the NVE Parties an increase in the ON Line Security Interest,
in either case, so that the ON Line Security Interest shall provide the NVE Parties with (i) either
(A) a security interest in all of Great Basin's right, title and interest in, to and under ON Line,
provided that the amount that may be realized with respect to such security interest shall not exceed
an amount equal to the product of(1) the positive difference between(x) the Final NVE Capacity
Entitlement (expressed as a percentage) minus (y) the NVE Parties' aggregate Ownership
Percentages and (2) the Anticipated Investment in ON Line or (B) if Great Basin has made the
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Transfer contemplated by Section 15.03(f)(i) or such security interest can be granted under
Applicable Law without such transfer and the NVE Parties consent in writing, a security interest
in a percentage of all right, title and interest in, to and under ON Line equal to (1) the positive
difference between(x)the Final NVE Capacity Entitlement(expressed as a percentage)minus (y)
the NVE Parties' aggregate Ownership Percentages and (ii) all right, title and interest of Great
Basin in,to and under the Fiber Optic Capacity and Microwave Capacity for ON Line(which shall
initially constitute a seventy-five percent (75%) interest).
(e) Priority of Security Interests. The ON Line Security Interest and the
GB Segment Security Interest shall at all times be senior to all Liens; provided, however, that the
ON Line Security Interest and the GB Segment Security Interest shall be subordinated only to the
following:
(i) Liens described in clause (a) of the definition of Permitted
Liens;
(ii) Excluded Liens arising by operation of law that are required
by Applicable Law to be senior to the ON Line Security Interest or the GB Segment
Security Interest, as applicable;
(iii) Liens described in clause 0) of the definition of Excluded
Liens;
(iv) Pre-GB Segment COD, GB Segment Security Interest over
Great Basin Segments Capped at 38%and ON Line Security Interest over ON Line. Prior
to GB Segment COD,unless the Parties agree in writing otherwise in their respective sole
discretion, Liens described in clauses (b) and (c) of the definition of Excluded Liens in
favor of the ON Line Lenders and the GB Segment Lenders, respectively, for (A) with
respect to the ON Line Security Interest, the sum of(1) three hundred thirty-four million
Dollars ($334,000,000) plus eighty percent (80%) of the portion of any Initial Cost
Differential and Incremental Cost Differential paid by Great Basin plus all fees, interest
and other amounts (other than principal repayments) payable to the ON Line Lenders
under the ON Line Financing Agreements,plus (2) eighty percent(80%) of the portion of
the Net Capital Repair Costs paid by Great Basin in respect of ON Line plus (3) in each
case,without duplication,indebtedness associated with interest rate protection agreements
permitted by the ON Line Lenders related to such indebtedness,entered into in accordance
with Prudent Utility Practices and not for speculative purposes and(B)with respect to the
GB Segment Security Interest if the NVE Parties have been granted the security interest
contemplated by Section 18.04(a)(ii)(A), the sum of(1) eighty percent (80%) of the cost
of developing, constructing, completing and starting-up the Great Basin Segments, plus
all fees, interest and other amounts (other than principal repayments) payable to the GB
Segment Lenders under the GB Segment Financing Agreements, plus (2) eighty percent
(80%) of the portion of the capital repair costs paid by Great Basin in respect of the Great
Basin Segments, plus (3) in each case, without duplication, indebtedness associated with
interest rate protection agreements permitted by the GB Segment Lenders related to such
indebtedness, entered into in accordance with Prudent Utility Practices and not for
speculative purposes;
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(v) Pre-GB Segment COD, GB Segment Security Interest over
38% of Great Basin Segments and ON Line Security Interest over ON Line. Prior to GB
Segment COD, unless the Parties agree in writing otherwise in their respective sole
discretion, Liens described in clauses (b) and (c) of the definition of Excluded Liens in
favor of the ON Line Lenders and the GB Segment Lenders, respectively, for (A) with
respect to the ON Line Security Interest, the sum of(1) three hundred thirty-four million
Dollars ($334,000,000) plus eighty percent (80%) of the portion of any Initial Cost
Differential and Incremental Cost Differential paid by Great Basin plus all fees, interest
and other amounts (other than principal repayments) payable to the ON Line Lenders
under the ON Line Financing Agreements,Plus (2) eighty percent(80%) of the portion of
the Net Capital Repair Costs paid by Great Basin in respect of ON Line plus (3) in each
case,without duplication,indebtedness associated with interest rate protection agreements
permitted by the ON Line Lenders related to such indebtedness,entered into in accordance
with Prudent Utility Practices and not for speculative purposes and(B)with respect to the
GB Segment Security Interest if the NVE Parties have been granted the security interest
contemplated by Section 18.04(a)(ii)(B), thirty-eight percent (38%) of the sum of (1)
eighty percent (80%) of the cost of developing, constructing, completing and starting-up
the Great Basin Segments, plus all fees, interest and other amounts (other than principal
repayments) payable to the GB Segment Lenders under the GB Segment Financing
Agreements, plus (2) eighty percent (80%) of the portion of the capital repair costs paid
by Great Basin in respect of the Great Basin Segments, Plus (3) in each case, without
duplication,indebtedness associated with interest rate protection agreements permitted by
the GB Segment Lenders related to such indebtedness, entered into in accordance with
Prudent Utility Practices and not for speculative purposes;
(vi) Post-GB Segment COD, GB Segment Security Interest over
Great Basin Segments Capped at Final NVE Capacity Entitlement and ON Line Security
Interest over ON Line Capped at Final NVE Capacity Entitlement less NVE Ownership
Percentage. On and after GB Segment COD,unless the Parties agree in writing otherwise
in their respective sole discretion, if the NVE Parties have been granted the security
interests contemplated by Sections 18.04(a)(ii)(A) and 18.04(c)(i)(A), Liens described in
clauses (b) and (c) of the definition of Excluded Liens in favor of the ON Line Lenders
and the GB Segment Lenders, respectively, for the sum of(A) three hundred thirty-four
million Dollars($334,000,000)plus eighty percent(80%)of the portion of any Initial Cost
Differential and Incremental Cost Differential paid by Great Basin plus(B) eighty percent
(80%) of the cost of developing, constructing, completing and starting-up the Great Basin
Segments, plus (C) all fees, interest and other amounts (other than principal repayments)
payable to the GB Segment Lenders under the GB Segment Financing plus (D) all fees,
interest and other amounts (other than principal repayments) payable to the ON Line
Lenders under the ON Line Financing Agreements, plus (E) eighty percent (80%) of the
portion of the Net Capital Repair Costs paid by Great Basin in respect of ON Line, plus
(F) eighty percent (80%) of the portion of the capital repair costs paid by Great Basin in
respect of the Great Basin Segments plus (G) in each case, without duplication,
indebtedness associated with interest rate protection agreements permitted by the ON Line
Lenders or the GB Segment Lenders related to such indebtedness, entered into in
accordance with Prudent Utility Practices and not for speculative purposes;
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(vii) Post-GB Segment COD, GB Segment Security Interest over
Final NVE Capacity Entitlement of Great Basin Sements and ON Line Security Interest
over Final NVE Capacity Entitlement less NVE Ownership Percentage. On and after GB
Segment COD, unless the Parties agree in writing otherwise in their respective sole
discretion, if the NVE Parties have been granted the security interests contemplated by
Section 18.04(a)(ii)(B)or Section 18.04(b)(ii)and Section 18.04(c)(i)(B),Liens described
in clauses (b) and(c) of the definition of Excluded Liens in favor of the ON Line Lenders
and the GB Segment Lenders, respectively, for the sum of(A) three hundred thirty-four
million Dollars($334,000,000)Plus eighty percent(80%)of the portion of any Initial Cost
Differential and Incremental Cost Differential paid by Great Basin, Plus (B) all fees,
interest and other amounts (other than principal repayments) payable to the ON Line
Lenders under the ON Line Financing Agreements, Plus (C) eighty percent (80%) of
portion of the Net Capital Repair Costs paid by Great Basin in respect of ON Line Plus
(D)in each case,without duplication,indebtedness associated with interest rate protection
agreements permitted by the ON Line Lenders related to such indebtedness, entered into
in accordance with Prudent Utility Practices and not for speculative purposes; and
(viii) as otherwise may be provided in the Intercreditor
Agreements.
(f) Security Documents. Great Basin shall authorize,execute and deliver
separate security agreements, mortgages and other agreements, documents, fixture filings,
financing statements and instruments, as reasonably requested by the NVE Parties, to grant to the
NVE Parties and maintain the ON Line Security Interest and the GB Segment Security Interest
(the "Security Documents") and, simultaneously with the execution of the applicable Security
Documents, the NVE Parties shall execute and deliver the applicable Intercreditor Agreements.
The NVE Parties may file and record such Security Documents as may be appropriate or required
under Applicable Law to perfect the ON Line Security Interest and the GB Segment Security
Interest, as applicable, and(i) Great Basin shall take such further actions and execute such further
documents and instruments,all as reasonably required by the NVE Parties,to confirm and continue
the validity, priority, and perfection of any such security interest in accordance with this
Agreement and (ii) the NVE Parties shall take such further actions and execute such further
documents and instruments, all as reasonably required by Great Basin, to confirm the
subordination provisions set forth in this Agreement. The granting of the ON Line Security Interest
and the GB Segment Security Interest shall not limit any further Claims or other rights accruing to
the NVE Parties under this Agreement or otherwise. The NVE Parties may exercise any right
provided in this Agreement or in any Security Document to recover any amount owing to the NVE
Parties. The NVE Parties may exercise their rights to all or any part of the ON Line Security
Interest and the GB Segment Security Interest or in any Security Document in such amount, form
and sequence as the NVE Parties may elect in their sole discretion. Any failure to exercise any
right provided to the NVE Parties under this Section 18.04 or in any Security Document shall not
prejudice the NVE Parties' rights to recover damages or amounts in any manner.
(g) Transfer. If Great Basin makes a Transfer contemplated by Section
15.03 e or ff,references to Great Basin shall be deemed to be references to either Great Basin or
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the Affiliated Assignee, or to both Great Basin and the Affiliated Assignee, as the context may
require.
ARTICLE XIX
GOVERNING LAW; DISPUTE RESOLUTION
19.01 Governing Law. THIS AGREEMENT SHALL BE GOVERNED BY,
AND CONSTRUED,INTERPRETED AND ENFORCED IN ACCORDANCE WITH,THE
SUBSTANTIVE LAW OF THE STATE OF NEVADA WITHOUT REFERENCE TO ANY
PRINCIPLES OF CONFLICTS OF LAWS THEREOF THAT REQUIRE THE
APPLICATION OF THE LAWS OF ANOTHER JURISDICTION.
19.02 Dispute Resolution; Binding Arbitration.
(a) Negotiation. Any dispute or claim arising under or relating to this
Agreement, or the breach, termination or validity hereof(a "Dispute"), which cannot be resolved
by the Parties through negotiation by the Parties' Authorized Representatives within ten(10) days
after receipt by a Party of written referral thereto by any other Party(a"Notice") shall be referred
to a panel consisting of a senior executive (President or a Vice President) of each Party, with
authority to decide or resolve the Dispute, for review and resolution. Such senior executives shall
meet and attempt in good faith to resolve the Dispute within twenty-five (25) days after receipt of
a Notice. If, for any reason, a Dispute has not been resolved within forty-five (45) days after
receipt of the Notice, then any Party may refer such Dispute to arbitration for final resolution in
accordance with Section 19.02(b).
(b) Arbitration.
(i) At the request of any Party following the expiration of the
period for senior executives to seek to resolve a Dispute set forth in Section 19.02(a),upon
written notice to that effect to the other Parties (a"Demand"), the Dispute shall be finally
settled by binding arbitration before a panel of three(3) arbitrators in accordance with the
Commercial Arbitration Rules of the American Arbitration Association ("AAA") then in
effect (the "Rules"), except as modified herein and unless the Parties agree otherwise in
writing; provided, however, that any Dispute regarding Contributions or other payments
required hereunder shall be resolved on an expedited basis (regardless of the amount in
Dispute)by a single arbitrator(but such single arbitrator is still referred to in this Section
19.02 b as the"arbitral panel")in accordance with the expedited procedures provided for
by the Rules. The Demand must include statements of the facts and circumstances
surrounding the Dispute,the legal obligation breached,the amount in controversy and the
requested relief accompanied by documents supporting the Demand.
(ii) The arbitration shall be held and the award shall be issued in
Las Vegas, Nevada. The arbitration shall be governed by the United States Arbitration
Act, 9 U.S.C. §§ 1 et sue.
(iii) If there is a single arbitrator,the Parties shall have fifteen(15)
days from receipt by a Party of a Demand to agree on the single arbitrator. If there are
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three (3) arbitrators, the NVE Parties collectively shall select one (1) arbitrator and Great
Basin shall select one (1) arbitrator, in each case within fifteen (15) days after the receipt
of the Demand. Within fifteen (15) days after the selection of the second arbitrator, the
two (2) arbitrators thus appointed shall select the third arbitrator, who shall act as the
chairman of the panel. If any arbitrator is not timely appointed,the AAA shall make such
appointment in accordance with the listing, ranking and striking procedures in the Rules,
with each of the NVE Parties and Great Basin having a limited number of strikes (to be
agreed by the Parties or, failing such agreement, determined by the AAA) except for
cause.
(iv) The award shall be in writing (stating the award and the
reasons, findings of fact and conclusions of law on which it is based), shall be final and
binding upon the Parties and shall be the sole and exclusive remedy among the Parties
regarding any Disputes,counterclaims,or accountings presented to the arbitral panel. The
arbitral panel shall be authorized in its discretion to grant pre-award and post-award
interest at commercial rates,except to the extent that applicable interest rates are otherwise
provided herein. Judgment upon any award may be entered in any court having
jurisdiction.
(v) For purposes of a pre-arbitral injunction, pre-arbitral
attachment or other order in aid of arbitration proceedings, the Parties hereby agree to
submit to the exclusive jurisdiction of the federal courts of the United States located in
Las Vegas, Nevada, and the courts of the State of Nevada located in Las Vegas, Nevada
(collectively, the "Las Vegas Courts") and to the non-exclusive jurisdiction of the Las
Vegas Courts for the enforcement of any arbitral award rendered hereunder. Each of the
Parties irrevocably waives, to the fullest extent permitted by Applicable Law, any
objection it may now or hereafter have to the jurisdiction of such courts or the laying of
the venue of any such proceeding brought in such a court and any claim that any such
proceeding brought in such a court has been brought in an inconvenient forum. Each of
the Parties hereby consents to service of process by registered mail or receipted courier at
its address set forth in Section 20.01 and agrees that its submission to jurisdiction and its
consent to service of process by mail are made for the express benefit of the other Parties.
(vi) This Agreement and the rights and obligations of the Parties
hereunder shall remain in full force and effect pending the award in any arbitration
proceeding hereunder.
(vii) Each Party shall bear its own costs and fees, including
attorneys' fees and expenses. The Parties expressly agree that the arbitrators shall have
no power to consider or award any form of damages barred by Section 12.03.
(viii) The Parties, to the fullest extent permitted by Applicable
Law,hereby irrevocably waive and exclude any recourse to the court system other than to
enforce the agreement to arbitrate pursuant to this Section 19.02, for pre-arbitral
injunction or pre-arbitral attachment or other order in aid of arbitration proceedings or to
prevent irreparable harm prior to the appointment of the arbitral tribunal or enforce the
award of the arbitral panel.
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(ix) If two or more Disputes arise in connection with this
Agreement, then any or all such Disputes may be brought in a single arbitration. If one
or more arbitrations are already pending in connection with this Agreement,then any Party
to a new Dispute in connection with this Agreement or any subsequently filed arbitration
brought in connection with this Agreement may request that such new Dispute or any
subsequently filed arbitration be consolidated into any prior pending arbitration. The new
Dispute or subsequently filed arbitration shall be so consolidated,provided that the arbitral
panel for the arbitration so selected determines that: (A) the new Dispute or subsequently
filed arbitration presents significant issues of law or fact common with those in the prior
pending arbitration, (B)no Party to the new Dispute or prior pending arbitration would be
unduly prejudiced and (C) consolidation under these circumstances would not result in
undue delay for the prior pending arbitration. Any such order of consolidation issued by
the arbitral tribunal shall be final and binding upon the Parties to the new Dispute, and the
prior pending and subsequently filed arbitrations. The Parties waive any right they have
to appeal or to seek interpretation, revision or annulment of such order of consolidation
under the Rules or in any court. The arbitral tribunal for the prior pending arbitration into
which a new Dispute or subsequently filed arbitration is consolidated shall serve as the
arbitral tribunal for the consolidated arbitration. The Parties agree that,upon such an order
of consolidation, they will promptly discontinue any arbitration brought in connection
with this Agreement, the subject of which has been consolidated into another arbitral
proceeding in connection with this Agreement.
(x) This Section 19.02(b) shall not apply to the resolution of any
Deadlock, audit or allocation Disputes to be resolved by the Independent Auditor or other
external auditor or appraiser under Sections 2.02(e) or 2.08, any appraisal to be made
under Section 13.05(b), or any Loss Threshold Deadlock to be resolved under Section
13.07 or Section 14.07;provided,however,that Sections 19.02(b)(v)and viii shall apply
to audit and allocation Disputes to be resolved by the Independent Auditor or other
external auditor or appraiser under Sections 2.02(e) and 2.08, any appraisal to be made
under Section 13.05(b), and any Loss Threshold Deadlock to be resolved under Section
13.07 or Section 14.07. For the avoidance of doubt,the limitation set forth in this Section
19.02 b x shall not preclude the use of the provisions set forth in Section 19.02(b) for
determining a breach of, or interpreting, this Agreement.
ARTICLE XX
MISCELLANEOUS
20.01 Notices. Unless this Agreement specifically requires otherwise, any notice,
demand or request provided for in this Agreement, or served, given or made in connection with it,
shall be in writing and shall be deemed properly served, given or made if delivered by (a) hand
delivery or (b) nationally recognized overnight courier to the applicable Party at the address set
forth below with a copy of such correspondence delivered by e-mail, in each case, which shall be
effective upon the physical receipt thereof:
To Great Basin or LS Power Development, LLC
Great Basin South: 16150 Main Circle Dr., Suite 310
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Chesterfield, MO 63017
Attention: Mark Milburn
E-Mail: [e-mail]
With copy to:
LS Power Development, LLC
16150 Main Circle Dr., Suite 310
Chesterfield, MO 63017
Attention: Paul Thessen
E-Mail: [e-mail]
LS Power Development, LLC
1700 Broadway, 35th Floor
New York,NY 10019
Attention: Ron Fischer
E-Mail: [e-mail]
To NPC: NV Energy
6226 W. Sahara Avenue
Las Vegas,Nevada 89146
Attention: Shahzad Lateef, Vice President, Transmission
E-Mail: [e-mail]
With copy to:
NV Energy
6226 W. Sahara Avenue
Las Vegas,Nevada 89146
Attention: Brandon Barkhuff, Senior Vice President, General
Counsel & Corporate Secretary, Chief Compliance Officer
E-Mail: [e-mail]
To SPPC: NV Energy
6226 W. Sahara Avenue
Las Vegas,Nevada 89146
Attention: Shahzad Lateef, Vice President, Transmission
E-Mail: [e-mail]
With copy to:
NV Energy
6226 W. Sahara Avenue
Las Vegas,Nevada 89146
Attention: Brandon Barkhuff, Senior Vice President, General
Counsel & Corporate Secretary, Chief Compliance Officer
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E-Mail: [e-mail]
20.02 Waivers. No provision of this Agreement may be waived except in writing.
No failure by a Party to exercise, and no delay in exercising, short of the statutory period, any
right,power or remedy under this Agreement shall operate as a waiver thereof. Any waiver at any
time by a Party of any right with respect to an Event of Default under this Agreement, or with
respect to any other matter arising in connection therewith, shall not be deemed a waiver with
respect to any subsequent Event of Default or any other matter.
20.03 No Third-Person Beneficiaries. Except as expressly provided otherwise
herein, none of the promises, rights or obligations contained in this Agreement shall inure to the
benefit of any Person that is not a Party, and no action may be commenced or prosecuted against
any Party by any third Person claiming to be a third-Person beneficiary of this Agreement or the
transactions contemplated hereby.
20.04 Severability. If any provision of this Agreement is held to be illegal,invalid
or unenforceable under any present or future Applicable Law, and if the rights or obligations of
any Party under this Agreement will not be materially and adversely affected thereby, (a) such
provision will be fully severable, (b) this Agreement shall be construed and enforced as if such
illegal, invalid or unenforceable provision had never comprised a part hereof, (c) the remaining
provisions of this Agreement shall remain in full force and effect and will not be affected by the
illegal, invalid or unenforceable provision or by its severance herefrom and (d) in lieu of such
illegal, invalid or unenforceable provision there shall be added automatically as a part of this
Agreement a legal, valid and enforceable provision as similar in terms to such illegal, invalid or
unenforceable provision as may be possible.
20.05 Independent Counsel. The Parties acknowledge that they have been
represented by independent counsel in connection with this Agreement, they fully understand the
terms of this Agreement and they voluntarily agree to such terms for the purposes of making a full
compromise and settlement of the subject matter of this Agreement.
20.06 Further Assurances. Each Party shall promptly and with all due diligence
take all necessary action in aid of obtaining all Governmental Approvals and third party consents
necessary to carry out its obligations under this Agreement. Each Party hereby agrees that it will,
at any time and from time to time, and without further consideration, take all such further actions,
and execute and deliver all such further instruments or documents, as may be reasonably requested
by any other Party to effectuate the purposes of this Agreement.
20.07 No Fiduciary Relationship. IN THEIR RELATIONS WITH EACH
OTHER UNDER THIS AGREEMENT, NO PARTY (WHETHER AS AN OWNER OR IN
ANY OTHER CAPACITY IN CONNECTION WITH THIS AGREEMENT) SHALL
HAVE ANY FIDUCIARY DUTY TO ANY OTHER PARTY, BUT RATHER SHALL BE
FREE TO ACT ON AN ARM'S-LENGTH BASIS IN ACCORDANCE WITH THEIR OWN
RESPECTIVE SELF-INTERESTS,SUBJECT,HOWEVER,TO THE OBLIGATIONS OF
THE PARTIES TO ACT IN GOOD FAITH IN THEIR DEALINGS WITH EACH OTHER
WITH RESPECT TO ACTIVITIES HEREUNDER.
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20.08 Confidential Information.
(a) Confidential Information. "Confidential Information" means
information provided by one Party (the "Disclosing Party") to any other Party (the "Receiving
Party") regarding the Disclosing Party that is clearly labeled or designated as "confidential" or
"proprietary"or with words of like meaning or,if disclosed orally,clearly identified as confidential
with the status confirmed promptly thereafter in writing, excluding the information described in
Section 20.08(c). Notwithstanding the foregoing sentence, the Books and Records of any Party,
any information provided pursuant to Section 9.06 and the terms of this Agreement shall be
Confidential Information.
(b) Treatment of Confidential Information. The Receiving Party shall
treat any Confidential Information with at least the same degree of care regarding its secrecy and
confidentiality as the Receiving Party's similar information is treated within the Receiving Party's
organization. The Receiving Party shall keep confidential and not disclose the Confidential
Information of the Disclosing Party to third Persons,nor use it for any purpose,without the express
prior written consent of the Disclosing Party, except the Receiving Party is permitted to disclose
Confidential Information without consent as follows:
(i) Disclosure shall be restricted solely to (A) its agents,
consultants and representatives as may be necessary to perform its obligations under this
Agreement, (B) its Affiliates, shareholders, directors, officers, employees, advisors,NVE
Lenders,ON Line Lenders and GB Segment Lenders(as the case may be),rating agencies,
and representatives as necessary, (C) any Governmental Authority in connection with
seeking any PUCN Approval, FERC Approval or any other required Governmental
Approval, (D) as required by Applicable Law or any stock exchange rules or,with respect
to any information provided under Section 9.06, financial statements of the NVE Parties
if any such information is aggregated with information of other Persons and(E)potential
transferees of this Agreement, any Ownership Interests or any ownership interests in the
Great Basin Segments (together with their agents, advisors and representatives), as may
be necessary in connection with any Transfer(which Transfer shall be in compliance with
Article XV) or in furtherance of the resolution of any Dispute pursuant to Article XIX, in
each case after advising those Persons of their obligations under this Section 20.08.
(ii) In the event that the Receiving Party is requested or required
by Applicable Law to disclose any Confidential Information, the Receiving Party shall
provide the Disclosing Party with prompt notice of such request or requirement in order
to enable the Disclosing Party to seek an appropriate protective order or other remedy and
to consult with the Disclosing Party with respect to the Disclosing Party taking steps to
resist or narrow the scope of such request or legal process. This Section 20.08(b)(ii) shall
not apply to the disclosure of this Agreement in connection with any disclosure pursuant
to Section 20.08(b)(i)(C) or to comply with any stock exchange rules.
(c) Excluded Information. Confidential Information shall not include the
following:
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(i) Information which is or becomes generally available to the
public other than as a result of a disclosure by the Receiving Party in breach of this Section
20.08;
(ii) Information which was available to the Receiving Party on a
non-confidential basis prior to its disclosure by the Disclosing Party;
(iii) Information which becomes available to the Receiving Party
on a non-confidential basis from a Person other than the Disclosing Party or its
representative who is not otherwise bound by a confidentiality agreement with the
Disclosing Party or its representative or is otherwise not under any obligation to the
Disclosing Party or its representative not to disclose the information to the Receiving
Party; and
(iv) Information that is independently developed by the
Receiving Party.
(d) Public Statements. The Parties shall consult with each other prior to
issuing any public announcement, statement or other disclosure with respect to this Agreement,
ON Line or the transactions contemplated hereby and no Party shall issue any such public
announcement, statement or other disclosure without having first received Management
Committee approval, except as may be required by Applicable Law. Notwithstanding the
foregoing, each Party acknowledges and agrees that the other Parties may, without consent,
advertise, issue brochures and make other announcements, statements and disclosures regarding
the Transmission Line for educational, promotional or informational purposes. It shall not be
deemed a violation of this Section 20.08(d) to file, without consent, this Agreement with the
PUCN, FERC or any other Governmental Authority for approval as required by Applicable Law.
(e) Specific Performance. Each Party acknowledges and agrees that the
failure to perform any of its respective obligations under this Section 20.08 would cause irreparable
harm to the other Parties and that the remedy at law for any violation or threatened violation thereof
would be inadequate, and further agrees that the other Parties shall be entitled to a temporary or
permanent injunction, specific performance or other equitable relief specifically to enforce such
obligations without the necessity of proving the inadequacy of its legal remedies. No Party shall
be required to post any guaranty,letter of credit,bond or other security to obtain an order or decree
of specific performance.
20.09 Other Transmission Lines and Exclusivity.
(a) In the event the HAE Project achieves commercial operation on or
prior to the HAE COD Outside Date,none of the NVE Parties shall,during the period commencing
on HAE COD and expiring on April 30, 2025, place in service a transmission line along a route
that is the same or substantially similar to the SWIP-N route. Except as set forth in the preceding
sentence, none of the Parties shall have any obligation to refrain from (i) owning, operating,
maintaining, modifying, expanding, using or developing transmission lines that compete, directly
or indirectly, with the Transmission Line, including the NVE Project or any similar project, (ii)
investing or owning any interest publicly or privately in, or developing a business relationship
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with, any Person engaged in owning, operating, maintaining, modifying, expanding, using or
developing transmission lines that compete, directly or indirectly, with the Transmission Line,
including the NVE Project or any similar project or(iii)doing business with any client or customer
of the Transmission Line, and no Party shall have any right by virtue of this Agreement in or to
any income or profits derived therefrom.
(b) During the period commencing on the Effective Date and expiring at
the Acquisition Closing, except to the extent that this Agreement is otherwise terminated earlier in
accordance with the terms herein,Great Basin may not,and shall cause its Affiliates not to,directly
or indirectly, including through any agent, employee or other representative, negotiate, discuss in
any material respect, or enter into any agreement or participate in any inquiries or proposals in any
material respect regarding the purchase of any interest in or rights to the Ownership Interests
contemplated by this Agreement to be Transferred to NPC and SPPC at the Acquisition Closing.
Great Basin acknowledges that the NVE Parties and their respective Affiliates are incurring
substantial costs in reliance on their rights under this Agreement and that this exclusivity is
essential for the integrity and viability of the Transmission Line.
20.10 Survival of Obligations. The following shall survive the termination or
expiration of this Agreement:
(a) All obligations under this Agreement owed to a Party arising prior to
or resulting from the termination or expiration of, or on account of the breach of, this Agreement;
(b) Sections 12.01 and 12.02, which shall survive to the full extent of the
statute of limitations period applicable to any third-Person claim;
(c) For a period of one(1)year after the termination or expiration date of
this Agreement, the right to submit a payment Dispute;
(d) The resolution of any Dispute submitted pursuant to this Agreement
prior to, or resulting from, the termination or expiration of this Agreement;
(e) Sections 9.05, 12.03, 13.03, 14.03 and 16.02 and Article XIX; and
(f) This Article XX, except that (i) the provisions of Section 20.08 shall
only survive for one (1) year after the expiration or termination of this Agreement and (ii) the
provisions of Sections 20.17, 20.18 and 20.19 shall not survive the expiration or termination of
this Agreement.
20.11 Construction. The Parties acknowledge that this Agreement has been
jointly prepared by each Party and shall not be strictly construed against any Party. No
presumption will apply in favor of any Party in the interpretation of this Agreement or in the
resolution of any ambiguity of any provision hereof based on the preparation, substitution,
submission or other event of negotiation, drafting or execution hereof.
20.12 Amendment, Effectiveness of Agreement; Effect of commercial operation
of HAE Project.
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(a) This Agreement may be amended,supplemented,or modified only by
a written instrument duly executed by or on behalf of each Party.
(b) The effectiveness of this Agreement is conditioned upon (i) the
receipt of a final order(A) issued by FERC under Section 205 of the Federal Power Act accepting
this Agreement for filing on terms acceptable to the NVE Parties and Great Basin in their
reasonable discretion, and(B) issued by the PUCN approving this Agreement and all transactions
contemplated herein on terms acceptable to the NVE Parties, in their sole discretion, and Great
Basin, in its reasonable discretion, and (ii) with respect to Great Basin, receipt of the consent of
the United States Department of Energy and two indirect equity investors in Great Basin
previously identified to the NVE Parties to the execution,delivery and performance by Great Basin
of this Agreement, on terms acceptable to Great Basin in its sole discretion. In the event that the
final order issued by FERC or the PUCN accepts or approves this Agreement in part or on a
conditional basis, and as a result such order is not acceptable to one or more Parties, the Parties
will discuss and consider in good faith whether revisions to this Agreement (or the terms of the
related transactions) can be made to address the Parties' concerns,but neither Party shall have any
obligation to accept or agree to any such changes.
(c) In the event the HAE Project achieves commercial operation on or
prior to the HAE COD Outside Date, the Parties agree that all references in this Agreement to
"SNIP"or"Centennial Phase 3"(including,without limitation,references within the defined terms
Anticipated Investment, SNIP, Applicable Centennial Phase 3 Facilities, Applicable Centennial
Phase 3 Rights, BLM SNIP License Consent, FERC Approval, GB Segment COD, Great Basin
Segments, Loss Threshold, SNIP, SNIP Agreement, SNIP Option, SNIP Option Closing, SNIP
Option Closing Date, and SNIP Option Right Transfer) shall be deemed to be of no further force
or effect.
20.13 Entire Agreement. This Agreement, including all schedules, attachments
and exhibits hereto, constitutes the complete and entire expression of agreement among the Parties
and supersedes all prior and contemporaneous offers, promises, representations, negotiations,
discussions and communications, whether written or oral, which may have been made in
connection with the subject matter of this Agreement, including the MOU. Any such
representations or claims are hereby disclaimed. Great Basin shall, and the NVE Parties shall
cause NVE Parent to, execute documentation terminating the CA as of the Effective Date.
20.14 Successors and Assigns. This Agreement shall be binding upon and shall
inure to the benefit of the Parties and their respective successors and permitted assigns.
20.15 Headings. Headings are solely for the Parties' convenience, are not a part
of this Agreement and shall not be used to interpret this Agreement.
20.16 Counterparts. This Agreement may be executed in counterparts, each of
which shall be deemed an original and all of which taken together shall constitute one and the same
instrument.
20.17 Running with the Land; Memorandums of this Agreement. To the extent
permitted under Applicable Law, the obligations of each Party under this Agreement shall
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constitute covenants running with the Ownership Interest of such Party(insofar as such Ownership
Interest constitutes an interest in real property) it being understood, for the avoidance of doubt,
that such covenants shall be subject to all of the terms and conditions of this Agreement. Upon
request of any Party from time to time, the Parties shall execute and deliver one or more
memorandums of this Agreement sufficient to set forth this Agreement as a matter of record;
provided, however, that such memorandum(s) shall be acceptable to the Parties and in the event
of any conflict between such memorandum(s) and this Agreement(or any other document filed in
connection herewith), the terms of this Agreement (or other document filed in connection
herewith)shall control. Any Party may,at its sole cost and expense,record any such memorandum
in any county in which the Transmission Line is located.
20.18 Dedication. No Party dedicates, and nothing in this Agreement shall be
construed as constituting a dedication by any Party,of any of its properties or facilities to any other
Party, to any customer of any Party or to the public.
20.19 Integrity Clause; Gratuity.
(a) Great Basin shall comply with the Counterparty Code of Conduct
(but, for the avoidance of doubt, the Parties' Affiliates shall not have any obligations under the
Counterparty Code of Conduct unless and until any such Affiliate becomes bound by the terms
hereof). Great Basin represents and warrants that it is, and Great Basin shall remain throughout
the Term, familiar with its own business practices and the business practices of any third Person
subcontractor and its agents and will ensure Great Basin and its third Person subcontractors and
its agents operate within the guidelines of the Counterparty Code of Conduct.
(b) If Great Basin does not already have a copy, Great Basin may obtain
a free copy of the Counterparty Code of Conduct by contacting the Ethics and Compliance Office
of the NVE Parties at [e-mail] or accessing the information at
www.nvenergy.com. The Counterparty Code of Conduct is hereby incorporated into this
Agreement by this reference; provided, however, that where such Counterparty Code of Conduct
and the requirements of this Agreement conflict the terms of this Agreement shall govern.
(c) Great Basin must notify the NVE Parties' Representative
immediately of any illegal or unethical activities or violations of the Counterparty Code of
Conduct. Great Basin should direct any questions or concerns about compliance or ethics issues
while working for and/or on behalf of the NVE Parties to the NVE Parties' Representative. Great
Basin may also call the NVE Parties'toll-free Integrity Line at 1-888-256-5819 with any questions
or concerns or to report illegal or unethical activities or any violation of the Counterparty Code of
Conduct. The Integrity Line is available 24 hours a day, 7 days a week.
(d) Great Basin shall not give or accept a Gratuity in connection with this
Agreement or the subject matter hereof.
127
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 133 of 198

20.20 Expiration of Options. The options in Sections 3.07(a), 3.08, 3.09 and 6.05
shall expire immediately prior to three hundred sixty-five (365) years after the Effective Date,
subject to the requirements of those Sections.
20.21 Mobile Sierra. The Parties agree that all rates, terms and conditions as
specified in this Agreement shall remain in effect in accordance with their terms and shall not be
subject to change through application to FERC pursuant to the provisions of Section 205 or Section
206 of the Federal Power Act of 1935, as amended, 16 U.S.C. §§ 792 et seq. Absent agreement
of the Parties to a proposed change, the standard of review for changes to any section of this
Agreement by a Party, a non-Party or FERC acting sue sponte, shall be the "public interest"
standard of review set forth in United Gas Pipe Line Co. v. Mobile Gas Service Corp., 350 U.S.
332 (1956) and Federal Power Commission v. Sierra Pacific Power Co., 350 U.S. 348 (1956), or
will be the most stringent standard permissible under then-Applicable Law.
[SIGNATURES APPEAR ON FOLLOWING PAGE]
128
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 134 of 198

IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by
their duly authorized representative as of the 2020 Effective Date.
NEVADA POWER COMPANY
(d/b/a NV Energy)
By:
Name: Shahzad Lateef
Title:Vice President, Electric Delivery
SIERRA PACIFIC POWER COMPANY
(d/b/a NV Energy)
By:
Name:
Title:
GREAT BASIN TRANSMISSION, LLC
By:
Name:
Title:
GREAT BASIN TRANSMISSION SOUTH,
LLC
By:
Name:
Title:
Signature Page—Second Amended and Restated Transmission Use and Capacity Exchange Acement
xhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 135 of 198

IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by
their duly authorized representative as of the 2020 Effective Date.
NEVADA POWER COMPANY
(d/b/a NV Energy)
By:
Name:
Title:
SIERRA PACIFIC POWER COMPANY
(d/b/a NV Energy)
laol
By:
Name: Shahzad Lateef
Title: Vice President, Electric Delivery
GREAT BASIN TRANSMISSION, LLC
By:
Name:
Title:
GREAT BASIN TRANSMISSION SOUTH,
LLC
By:
Name:
Title:
Signature Page—Second Amended and Restated Transmission Use and Capacity Exchange Acement
xhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 136 of 198

IN WITNESS WHEREOF, the Parties have caused this Agreement to be executed by
their duly authorized representative as of the 2020 Effective Date.
NEVADA POWER COMPANY
(d/b/a NV Energy)
By:
Name:
Title:
SIERRA PACIFIC POWER COMPANY
(d/b/a NV Energy)
By:
Name:
Title:
GREAT BASIN TRANSMISSION,LLC
By: �2�� ��
Name: Mark D. Milburn
Title: Vice President
GREAT BASIN TRANSMISSION SOUTH,
LLC
By: . I?Z
Name: Mark D. Milburn
Title: Vice President
Signature Page—Second Amended and Restated Transmission Use and Capacity Exchange Agreement
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 137 of 198

EXHIBIT A
ON Line Budget
January 31, 2013
(Approved by Management Committee Consent dated 2/4/13)
Viescr►ption Amount
500 kV i ransmission Line $ 350.385,334
Robinson Summit 345/500kV Substation $ 81.213,773
Harry Allen 500 kV Switchyard $ 11.637,579
Falcon 345 kV Switchyard and 345kV Loop-In to Robinson Summit $ 24.690,753
Gonder. Falcon, Valmy. Coyote & t racy Relay Upgrades $ 2.451,011
Microwave & Mobile Radio Communications $ 29.564,256
Development & Pre-Closing Costs $ 37.234,234
Contingency S 14.930.060
BUDGET TOTAL $ 552,107,000
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
Confidential
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 138 of 198

EXHIBIT B
DELEGATED RESPONSIBILITIES
Secure permits required for the microwave communications system for ON Line
Secure permits required for the Falcon substation upgrades for ON Line
Secure permits required for the construction of the Robinson Summit Substation at the Robinson Summit
Location
Exhibit B-1
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 139 of 198

Exhibit C -ON Line Schedule
(Approved by Management Committee Consent dated Z4.13)
ON-,ne ip Svie:Lle 1 1-26-,3—I
-.-W F"W&h 70aw Lwral "-z
rea.
1111 11 IN 111U11111i'MU,
SUMMARY ONLINE SUMMARY SCHEDULE . . . . . . .
SUMMARY.OP HARRY ALLEN-ROBINSON 500kv TL
protect Management
. . I . .. . . . . .
r 12-IS-Ir 1 01 0% 1 . . . . . . . . ..
. . . . . . . . . . I
. . . . . . . . . .
OPLR21130 FEDERAL iffrATEILOMPEPOOM48 740.10 A5.27-1 A .1ft . . . . . .
OftArIfIl LAW MONTS ACOWOMM 11-147A 740.10A 120 Im
a-L-'r-w La"Ko"P&A"WfiW #-1-10A 12-41-10A 1 .0ft kw*jai
. . .
0:4-R21'70 LEGAL ...CA '.'.'OA 155 Im
. . . . . . . . . .
n9urrT140 i-*S.Zg A 547-11 A r 9 -oft ?4%mnr4a:
: 11. . . . . . . . . .
0—ESIVISM EV.q4041J-m4TAL M-ACT STA---M-:14T,-=-*, S449A 12,1109A 449 Im 014DW11 81W,AIL W' 'AICF VZATNJ
0-54VISOD COM=LA4 14-11 A S-19-11 A 120 Im
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
0=W11" CIOMMILLA4C.E i UNIMMATKA 3-1-11 A 12-27-ir r7 VL'91. V
0-=W1410 OOM-LIA4W 111011WEATICA(WS ODs) 2-4-Ir 12�V_lr 228 0% V . . .
0--" RE;TORATON I RSCLM"TM 1230'Ir W&UP 40 WA a . . . . . . . . . . . . . . . . . . . .
A G-SMA . . . . . . . . . .
OZSYAKW TubdWTi.op"­PM0o: gy.CJ00" 541-11 A 141-12A 253 '00% Do."
. . . . . . . . . . . . . . . . . . . . . . . . . . . . . .
OZ&V65211r.Te.,-141"al 8VA10&r4A&ftPdM IS-17-12A 6-14Ir 130 SA0% 70
0-8Y165292 CiiriduoW 00%wy 4.14-11 A 240.12A 228
-811,W285 kdoaw/A&NMWI 406AIM 00AVy 7.12 A 2-2&12 A -tal .00% lift
0a51,W264 Lwka To�ws Pedurausail3lb" 5-29-'-A -0-28-"A rA *00% :4,iqy:
0yB?i SW DETALEO LIVE 0113 11 i447A 24-11 A 1107 oft 4 i . . . . . . . . . . . . .
0z8ym,00 0101911114EAD C0NffrRUCn0N f1ba"m) 64II&IT A 1"2019* 2041 817s% a A
0-9.M140 "&WC..W"APA1 . . . . . . .
. . . . . . . . . . . . . . .
A 7-18-12A 4s4 1001. III I lop? qqT"cfnp?qq
nry Allen 500 KV
'EAY._I=-=MJPW- I lwh'Wo
'10,17-11 A 1'14&lr
OZS*A74M TrELE00140,1116114111"Um 6447A 7-2&111 A
OaVdA2540 Tme Faw k-rarzaA S7119% 2
,OZ. 119%
-rTEL 0-9��ASWO E-WIXt, -�-M0-0(X)WrtlJCn0M 3-8,2A 12-15-ir 4&M a
SUMM.ARY.QO ROBINSON SUMMIT 3-4Si5OOkV SWITCHING
L-14 -r a CAb a . . . . . .
-SETACIE •2-14�!r -2-14i
1111
381 Robinson 1�1 kV swfthing ma H I H I I I I I I I H i i i i 1 i 1i 1 i ii 1 1 i 1 1 i 1 11
--."A 5-2 .00%
00L42- SO A . . . . . . .
Robowsm summ hlng Station Phase 1
AcbW Vftt 11 OfttCansrann uhmeam
� Remaining Wort 4 Fmbb Constra r1
NVEr i t
413175980 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 140 of 198

Exhibit C - ON Line Schedule
(Approved by Management Committee Consent dated 2:413)
ONlra;'ca UP Scnenue 1.25.13 17
Comdata Flom =:nr 1 J J J J J 1
O0111I111EM0 CNL I STRUCTURAL COMgr%JGnON CKS" 641-11 A 1221-12 A 504 DD%
oosvlES-00 cNLlsrTEDESM34L$b-=WrrrmoopPORT 12417A 34o.11A ,-0e DDS. �' y3
O I I I I I I I I I I I
0811IE5200 agysr-JL?Ea3v Jm 1.1A 12&12A 725 -00% 1;
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O0111111V1E54s7 S45fJ aarea caoo•i m E0qoP+es..Palo"!VANL_ 11-1-1•A 941.,r 422 7S 67% 20 _
O08NWES4a5 SMW.l awes C1aos•s•ra coay.06•a S&VAM(GAMOL- 9.1.1tr ,O 51.,9• -75 CS 50 �`•"- �fj
OOSVYES 00 &ZECT41GL 0Ea10N 041.10A 419D•1r Tao SS W% -50 i icCZ?I RL17
OOGW54500 8J68TATON CONSTRUCTION •.19.-2 A 8-20.15- 409 eo. s OS IIIIIIIIIIII _I$*_
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3ATIONa ODNSTRUCTION A_24.12 A 12-11-19• SOS Ii 29% 0 I I_I t I I I I I I� I I I -
. . . . . . . . . . . . . . .
SUMMARY.Q2 FALCON GONDER INTO ROBINSON SUMMIT
tr
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130 bW
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Expansion
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1�- _%,.•nF•tawa: 2-22.2A 2.22.12A 'OSli . . i
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9..•47A 9.1-0'A o 100% IIIIIIIIIIIIIIIIIIIIIII IIIIIIIIIII I
C a00 2FOAS ELS -CTRICe,-____ ' SOr ss 81
1 A M Ir e .71% 20 1 1 1 1 1 1 1 1 1 ELIE
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Changes
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Q2E•4n-0G =___ir•ARY 3 _. 10.1-10 A ,20.11 A 70 •oft i PR£LIgIIWtfidlibi E
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OMPM900 IJOITCNAL CNL sIPRC:'_us fra 4.20.19• S-17.-1r •5 0% 20o
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Acbel Wart film Contra,rrt ♦ ♦Mis fine Fade 2 of 6
=3111111=1 Remaining wort d Finist+Cars"r.
NVEnergy.
413175980
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 141 of 198

Exhibit C-ON Line 3Ghedule
(Approved by Manallement Committee Consent dated 214:13)
ONLine Rm up Schefte t t 3 ?
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02ENTS" S-ul vtoa ad,Fac. :sd and Ma.-Ad 64&131 718-,r 20 0%
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- - - - - - - - - - - - -
$ BTATDN CONJCT1 Y7-,r D2 0� 2 SM
WNT4500 REuvco�eRucnoN,00mlmowmm a-a13• 193-1r 0%
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PRELEIANAWDMIGN E1.147A 9-147A ] •00l.
WVALs000 E3ECTR ALDEWN 12.1-10A 7.27-12A 458 IN% I Q I I I I I I
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41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 142 of 198

Exhibit C - ON Line Schedule
(Approved by Management Committee Consent dated Z413)
ONune kra Jp Schedule 1_5-, '
Comae Flo¢ J J 11111 J1111 1 J1,1111,11
OR.1AB2100 1 PRSS!•ARV 0E810V 12.17-07A 1-$148A 40 DDS
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Remaining VI a FinishConstaalt NVEnergy.
413175980
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 143 of 198

Exhibit C - ON Line Schedule
(Approved by Management Committee Consent dated 2'4.13)
ONLine RMS Up Scne2Ue 1-25-13 17
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RbnrnogWat FimsaConsaaka NVE�nergy.
413175980
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 144 of 198

Exhibit C - ON Line Schedule
(Approved by Management Committee Consent dated ZA."113)
�'Zffi JP,S:t1e=Lk- lf-,I 7 23
T" GW.W 21r jr
RESTORATION RRECLAMATIONckima & F1601 Most
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413175980 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 145 of 198

EXHIBIT D
INSURANCE PLAN
L Coverage specific to ON Line and the Great Basin Segments
A. Property Insurance covering ON Line: From ON Line Financial Closing to the
earlier of(a) ON Line COD and(b)the date that operational insurance becomes
effective, the Managing Party shall require each contractor and subcontractor
performing work on the ON Line ROW, as part of its price, to procure and
maintain the following coverages from the date of the notice to proceed under the
applicable contract to the final completion thereof:
l. All coverages described in Part II below(as modified by Part II(E))
2. Delay in Start-up insurance with coverage of$110,000 per day of delay
3. Builders All Risk insurance with limits no less than the full replacement
cost, or an acceptable loss limit, of ON Line
4. Marine and Air Cargo insurance, to the extent that any major equipment
requires overseas transport, with limits sufficient to cover the property at
risk, and Marine and Air Cargo Delay in Start-up insurance with limit and
indemnity period equal to the amounts for the Delay in Start-up insurance
B. Property Insurance covering Robinson Summit Substation: From ON Line COD,
and thereafter throughout the Term, the NVE Parties shall provide the following
Property Insurance coverage on the Robinson Summit Substation:
I. All risk physical loss or damage coverage equivalent to the replacement
value of the substation, subject to coverage limits and exclusions
C. Property Insurance covering the Great Basin Segments:
1. In the period between GB Segment Financial Closing and commercial
operation of each Great Basin Segment, Great Basin shall procure, or
require each contractor and subcontractor performing work on the right-of-
way for the Great Basin Segments to procure, and maintain the following
coverages from the date of the notice to proceed under the applicable
contract to the final completion thereof:
(a) All coverages described in Part II below(as modified by Part
II(E))
(b) Builders All Risk insurance
Exhibit D-1
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 146 of 198

2. From the commercial operation of each Great Basin Segment, and
thereafter throughout the Term, Great Basin shall provide the following
Property Insurance coverages on the Great Basin Segments:
(a) To the extent that the GB Segments include the ownership of any
substation, all risk physical loss or damage coverage equivalent to
the replacement value of the substation, subject to coverage limits
and exclusions
II. Coverage specific to the Parties
Commencing on the Effective Date the Parties shall obtain and maintain the following
insurance policies:
A. Automobile Liability:
Coverage: Bodily injury and property damage for all owned,hired and non-
owned automobiles,trucks and trailers,including coverage for
contractual liability. Coverage shall be provided not less than that of
an ISO Business Auto Policy CA 00 01 or similar:
$1,000,000 Combined Single Limit Each Occurrence for Bodily Injury&Property
Damage.
B. Workers' Compensation and Employers' Liability:
Coverage: Statutory limits required by the Workers'Compensation laws of the
applicable jurisdiction,including United States Longshoreman's and
Harbor Workers'Act(USL&HW and Maritime Employers Liability),
if applicable,with Employer's Liability.
Part One: Workers'Compensation: Statutory Limits
Part Two: Employer's Liability: Required Annual Limits:
USL&HW&MEL $1,000,000 policy limit
Bodily Injury by Accident: $1,000,000 each accident
Bodily Injury by Disease: $1,000,000 each employee
Bodily Injury by Disease: $1,000,000 policy limit
C. General Liability Insurance:
Exhibit D-2
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 147 of 198

Coverage: Third party personal injury,bodily injury and property damage
liability written on an occurrence form(including products liability for
any product manufactured, assembled or otherwise worked upon away
from the project site)including coverage for contractual liability,
actions over and wildfire.
Minimum Requirements: Annual Limits of Liability:
General Aggregate $2,000,000
Products/Completed Operations Aggregate $ 1,000,000
Personal/Advertising Injury Aggregate $ 1,000,000
Each Occurrence Limit $2,000,000
Fire Damage Legal Liability(any one fire) $ 100,000
Medical Expense $ 5,000
D. Excess/Umbrella Liability Insurance:
Coverage: Occurrence form written on a following form basis over the primary
policies/coverages required above.
Minimum Limits of Liability: All Insureds Combined:
Combined Single Limit $25,000,000 each occurrence
General Aggregate $25,000,000
E. Aircraft/Aviation Liability(If required by Contract or if applicable):
Should aircraft of any kind be used by anyone on behalf of the Parties, such parry
using the aircraft shall maintain or cause the operator of the aircraft to maintain
aviation liability insurance with the following requirements:
Combined Single Limit:
(Bodily Injury and Property Damage) $10,000,000 each
occurrence (as required)
Notes:
(a) Waiver of hull damage shall be provided in favor of the Parties
(b) If any lifts are preformed, a slung cargo endorsement shall be
Exhibit D-3
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 148 of 198

attached to the policy to cover the full replacement value of any
equipment or material being lifted
F. Railroad Protective Liability: (if required by contract)
Should the work involve any activities in the vicinity of a railroad, Railroad
Protective Insurance as may be required by the affected railroad, written for not
less than the limits required by such railroad.
III. Requirements Applicable to all Insurance Policies
A. All policies, binders or interim insurance contracts with respect to insurance
maintained by the Parties, contractors, subcontractors or sub-subcontractors
pursuant to this Exhibit D shall:
1. be placed with responsible and reputable insurance companies which are
licensed or authorized to do business in the State of Nevada and are rated
by A.M. Best's Key Rating Guide as "A-", Financial Size"VIII", or better;
2. state that Great Basin, the NVE Parties, ON Line Lenders and GB Segment
Lenders(as applicable)are named as additional insureds,with the exception
of Workers Compensation/Employers Liability;
3. state that it is primary, or in excess only with respect to the specific primary
policy provided by the same party for such coverage, and not excess or
contributing as with respect to any other insurance (or self-insurance)
available to the Parties, ON Line Lenders, GB Segment Lenders (as
applicable) or the additional insureds and that all provisions thereof, except
the limits of liability, shall operate in the same manner as if there were a
separate policy covering each insured under each such policy;
4. provide that there will be no recourse against any additional insured for the
payment of premiums or commissions (if such policies provide for the
payment thereof), additional premiums or assessments, it being understood
that such are obligations of the named insured providing such insurance
pursuant to this Agreement;
5. with respect to the insurance described in Section I1 waive any right of
subrogation of the insurers thereunder against the Parties,ON Line Lenders,
GB Segment Lenders (as applicable) and the officers, directors and
employees of each of them, and any right of the insurers to any set-off or
counterclaim or any other deduction, whether by attachment or otherwise,
with respect to any liability of any such person insured under such policy;
6. with respect to the interests of the additional insured, provide that such
Exhibit D-4
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 149 of 198

insurance shall not be invalidated by any action or inaction of the additional
named insured and shall insure the additional named insured regardless of any
breach or violation of any warranty, declaration or condition contained in such
insurance by the primary named insured;
7. provide that it may not be canceled or materially changed without giving
the Parties sixty (60) days prior written notification thereof, except for ten
(10) days for non-payment of premium.
8. Such policies shall include a separation of insured clause.
9. Operator and any subcontractor shall be responsible for any loss of or
damage to their own property, including tools, equipment and vehicles or
other property which does not form part of the project.
B. Within thirty(30) days after the Acquisition Closing Date, and from time to time
thereafter as reasonably requested by a Party, each Party shall provide the other
Parties with certificates of insurance evidencing the placement of the coverages
required(i)under this Exhibit D and(ii)by the GB Segment Lenders, together
with information regarding any reserves required to be established by the GB
Segment Lenders in respect of such coverages. Each Party shall deliver
replacement certificates evidencing replaced or renewed coverage to the other
Parties on or before the expiration date of the expiring policies.
C. Great Basin, the NVE Parties, the ON Line Lenders and the GB Segment Lenders
shall be named as insured parties and loss payees, as their interests appear, for all
insurance policies contemplated herein. Notwithstanding the above, all insurance
proceeds received by the Parties shall be shared as set forth in this Agreement.
Exhibit D-5
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 150 of 198

EXHIBIT E
FORM OF BILL OF SALE
AND
ASSIGNMENT AND ASSUMPTION AGREEMENT
THIS BILL OF SALE AND ASSIGNMENT AND ASSUMPTION AGREEMENT
(this "Assi_ng ment") is entered into as of , 2010 by and among Great Basin
Transmission, LLC, a Delaware limited liability company ("Great Basin"), Nevada Power
Company, a Nevada corporation, d/b/a NV Energy ("NPC") and Sierra Pacific Power Company,
a Nevada corporation, d/b/a NV Energy ("SPPC"). Great Basin,NPC and SPPC may sometimes
be referred to herein individually as a"Party" and collectively as the "Parties".
RECITALS
WHEREAS, reference is made to the Transmission Use and Capacity Exchange
Agreement (the "Transmission Use Agreement"), dated as of August 20, 2010, by and among the
Parties. All capitalized terms used but not otherwise defined herein shall have the same meaning
as set forth in the Transmission Use Agreement.
WHEREAS, each Party desires to carry out, in part, the intent and purpose of the
Transmission Use Agreement by such Party's execution and delivery of this Assignment
evidencing the vesting in NPC of an undivided twenty-three and seventy-five hundredths percent
(23.75%) ownership interest in all right, title and interest in ON Line and SPPC of an undivided
one and twenty-five hundredths percent (1.25%) ownership interest in all right, title and interest
in ON Line.
WHEREAS, "ON Line" means any and all assets, interests and property rights (real and
personal and tangible and intangible) comprising SWIP-S (to be renamed the "One Nevada
Transmission Line"pursuant to Section 4.08 of the Transmission Use Agreement), including any
fiber optic line comprising SWIP-S, any microwave communication system comprising SWIP-S
and any and all leasehold or other possessory interest in the ON Line ROW, ON Line Agreements,
Governmental Approvals for ON Line, Books and Records, Work Product and depreciation and
other tax benefits, as further described in Schedule 1. For the avoidance of doubt, ON Line does
not include the NVE Project, Excluded Agreements or any information licensed to Great Basin
under the License Agreement.
WHEREAS, NPC will receive certain rights, and assume certain obligations, from Great
Basin under the ON Line Agreements of which it will provide the benefit of those rights, and the
burdens of the obligations, to SPPC pursuant to Section 3.01(c) of the Transmission Use
Agreement.
Exhibit E-1
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 151 of 198

AGREEMENT
NOW, THEREFORE, for good and valuable consideration, the receipt and
adequacy of which are hereby acknowledged, the Parties agree as follows:
Section 1. Bill of Sale.
(a) Great Basin hereby assigns, transfers, conveys and delivers to NPC an undivided
twenty-three and seventy-five hundredths percent (23.75%) ownership interest in all right, title
and interest in ON Line and to SPPC an undivided one and twenty-five hundredths percent(1.25%)
ownership interest in all right, title and interest in ON Line.
(b) Great Basin hereby recognizes the receipt of the NPC Purchase Price, in part, for
the assignment and transfer of an undivided twenty-three and seventy-five hundredths percent
(23.75%) ownership interest in ON Line to NPC and the SPPC Purchase Price, in part, for the
assignment and transfer of an undivided one and twenty-five hundredths percent (1.25%)
ownership interest in ON Line to SPPC.
Section 2. Assignment and Assumption of ON Line Agreements. Great Basin hereby
assigns to NPC an undivided twenty-five percent (25%) ownership interest in all right, title and
interest in and to each ON Line Agreement. NPC hereby assumes and agrees to perform twenty-
five percent (25%) of Great Basin's obligations arising after the Acquisition Closing Date under
each ON Line Agreement. For the avoidance of doubt,with respect to indemnity obligations under
any ON Line Agreement, NPC shall assume no liability for events that occurred through the
Acquisition Closing Date and shall only assume twenty-five percent (25%) of liability for events
that occur after the Acquisition Closing Date with respect to each ON Line Agreement. SPPC
assumes no obligations under this Agreement with respect to any ON Line Agreement.
Section 3. Successors and Assigns. This Assignment shall be binding upon and shall
inure to the benefit of the Parties and their respective successors and permitted assigns.
Section 4. Governing Law. THIS ASSIGNMENT AND THE RIGHTS AND
OBLIGATIONS OF THE PARTIES HEREUNDER SHALL BE GOVERNED BY AND
CONSTRUED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEVADA
(WITHOUT GIVING EFFECT TO THE CONFLICTS OF LAWS PRINCIPLES
THEREOF THAT REQUIRE THE APPLICATION OF ANOTHER JURISDICTION'S
Exhibit E-2
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 152 of 198

Section 5. Severability. If any provision of this Assignment shall be held invalid or
unenforceable, the validity or enforceability of the remaining provisions shall not in any way be
impaired thereby.
Section 6. Construction. Headings are solely for the Parties' convenience, are not a
part of this Assignment and shall not be used to interpret this Assignment. The Parties
acknowledge that this Assignment has been jointly prepared by each Party and shall not be strictly
construed against any Party. No presumption will apply in favor of any Party in the interpretation
of this Assignment or in the resolution of any ambiguity of any provision hereof based on the
preparation, substitution, submission or other event of negotiation, drafting or execution hereof.
In the event of a conflict between the terms of this Assignment and the terms of the Transmission
Use Agreement, the terms of the Transmission Use Agreement shall prevail. The Parties hereby
acknowledge and agree that the only remedies of the Parties and their respective Affiliates,
successors and assigns with respect to the consummation of the transactions contemplated by this
Assignment shall be those remedies specifically provided for in the Transmission Use Agreement.
Section 7. Counterparts. This Assignment may be executed in one or more
counterparts, each of which shall be deemed an original and all of which taken together shall
constitute one and the same instrument.
Section 8. Amendment. This Assignment may be amended, supplemented, or modified
only by a written instrument duly executed by or on behalf of each Party.
Section 9. Further Assurances. Each Party hereby agrees that it will, at any time and
from time to time, and without further consideration, take all such further actions and execute and
deliver all such further instruments or documents, as may be reasonably requested by any other
Party to effectuate the purposes of this Assignment.
Exhibit E-3
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 153 of 198

Section 10. Exclusivity of Representations. THE REPRESENTATIONS AND
WARRANTIES MADE IN ARTICLE XVII OF THE TRANSMISSION USE
AGREEMENT ARE THE EXCLUSIVE REPRESENTATIONS AND WARRANTIES
MADE BY SELLER WITH RESPECT TO ITSELF AND ON LINE AND THE
TRANSACTIONS CONTEMPLATED IN THIS ASSIGNMENT. SELLER HEREBY
DISCLAIMS ANY OTHER EXPRESS OR IMPLIED REPRESENTATIONS OR
WARRANTIES WITH RESPECT TO ITSELF OR ON LINE. EXCEPT AS EXPRESSLY
SET FORTH IN ARTICLE XII OF THE TRANSMISSION USE AGREEMENT, THE
CONDITION OF ON LINE AND ANY PORTION THEREOF SHALL BE "AS IS" AND
"WHERE IS" AND SELLER MAKES NO WARRANTY OF MERCHANTABILITY,
SUITABILITY, FITNESS FOR A PARTICULAR PURPOSE OR QUALITY WITH
RESPECT TO ANY OF THE TANGIBLE ASSETS OF SELLER(INCLUDING ON LINE
OR ANY PORTION THEREOF) OR AS TO THE CONDITION OR WORKMANSHIP
THEREOF OR THE ABSENCE OF ANY DEFECTS THEREIN, WHETHER LATENT
OR PATENT.
Section 11. Several Liability. The covenants, obligations and liabilities of the Parties in
connection with this Assignment are several and not joint.
Section 12. Security Interest. Great Basin shall cause the GB Segment Security Interest
and ON Line Security Interest to secure the performance of Great Basin's obligations under this
Assignment and shall execute and deliver to NPC and SPPC the appropriate Security Documents.
NPC and SPPC may file and record such Security Documents as may be appropriate or required
under Applicable Law to perfect the ON Line Security Interest and the GB Segment Security
Interest, as applicable, and Great Basin shall take such further actions and execute such further
documents and instruments, all as reasonably required by NPC or SPPC, to confirm and continue
the validity, priority, and perfection of any such security interest in accordance with the
Transmission Use Agreement. The granting of the ON Line Security Interest and the GB Segment
Security Interest shall not limit any further Claims or other rights accruing to NPC or SPPC under
this Assignment or otherwise. NPC and SPPC may exercise any right provided in this Assignment
or in any Security Document to recover any amount owing to NPC or SPPC, as applicable. NPC
and SPPC may exercise its rights to all or any part of the ON Line Security Interest and the GB
Segment Security Interest or in any Security Document in such amount, form and sequence as
NPC or SPPC, as applicable, may elect in its sole discretion. Any failure to exercise any right
provided to NPC or SPPC under this Section 11 or in any Security Document shall not prejudice
NPC's or SPPC's rights to recover damages or amounts in any manner.
[SIGNATURE PAGE FOLLOWS]
Exhibit E-4
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 154 of 198

IN WITNESS WHEREOF, the Parties have caused this Assignment to be
executed by their duly authorized representative as of the date first written above.
NEVADA POWER COMPANY
(d/b/a NV Energy)
By:
Name:
Title:
SIERRA PACIFIC POWER COMPANY
(d/b/a NV Energy)
By:
Name:
Title:
GREAT BASIN TRANSMISSION, LLC
By:
Name:
Title:
Exhibit E-5
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, [PC
Page 155 of 198

State of }
} ss:
County of }
This instrument was acknowledged before me on
by as
of
NOTARY PUBLIC
My Commission Expires:
Exhibit E-6
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 156 of 198

State of }
} ss:
County of }
This instrument was acknowledged before me on
by as
of
NOTARY PUBLIC
My Commission Expires:
Exhibit E-7
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 157 of 198

State of }
} ss:
County of }
This instrument was acknowledged before me on
by as
of
NOTARY PUBLIC
My Commission Expires:
Exhibit E-8
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 158 of 198

SCHEDULEI
ON LINE
Exhibit E-9
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 159 of 198

EXHIBIT F
FORM OF ASSIGNMENT AND CONSENT AGREEMENT
This ASSIGNMENT AND CONSENT AGREEMENT (this "Agreement") is
entered into as of [ ], 2010, by and among Nevada Power Company, a Nevada
corporation,d/b/a/NV Energy("Purchaser"), Great Basin Transmission, LLC, a Delaware limited
liability company ("Seller"), and [ ], a I ("Company"). Purchaser, Seller and
Company may be referred to individually herein as a"Party" and collectively as the "Parties."
RECITALS
WHEREAS, Seller and Company have entered into that certain [ ], dated
as of[ ] (the "Assignedgreement");
WHEREAS, Purchaser, Sierra Pacific Power Company, d/b/a NV Energy, and
Seller have entered into that certain Transmission Use and Capacity Exchange Agreement, dated
as of August 20, 2010 (the "Transmission Use Agreement"), pursuant to which Seller has agreed
to assign an undivided twenty-five percent(25%) ownership interest in its rights, title and interest
under the Assigned Agreement to Purchaser, and Purchaser has agreed to assume twenty-five
percent(25%) of Seller's obligations arising under the Assigned Agreement after the closing date
of the acquisition under the Transmission Use Agreement(the "Transaction Closing Date"); and
WHEREAS, Seller requests consent from Company to transfer an undivided
twenty-five percent(25%)ownership interest in Seller's rights,title,interest and obligations under
the Assigned Agreement to Purchaser in accordance herewith.
NOW, THEREFORE, in consideration of the foregoing, and for other good and
valuable consideration,the receipt and adequacy of which are hereby acknowledged,and intending
to be legally bound, the Parties hereby agree as follows:
1. Consent and Agreement. Company hereby consents to (a) the assignment of an
undivided twenty-five percent (25%) ownership interest in Seller's rights, title and interest in the
Assigned Agreement to Purchaser and (b) the assumption by Purchaser of twenty-five percent
(25%) of Seller's obligations arising under the Assigned Agreement, in each case, effective
immediately after the Acquisition Closing Date,except with respect to indemnity obligations under
the Assigned Agreement for which Purchaser shall assume no liability for events that occurred
through the Transaction Closing Date and shall only assume twenty-five percent (25%) of the
Exhibit F-1
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 160 of 198

liability for events that occur after the Transaction Closing Date, in each case, effective
immediately after the Transaction Closing Date. Company further hereby consents to (a) the
assignment of additional undivided ownership interests in the Assigned Agreement between Seller
and Purchaser from time to time effective as of the date set forth in a notice from Seller and
Purchaser to the Company and (b) the corresponding assumption by Purchaser or Seller, as the
case may be, of such assigned interest.
2. Novation of Assi_ng ed Agreement and Acknowledgment. Effective immediately
after the Transaction Closing Date, Company hereby fully and unconditionally releases Seller and
its affiliates of all obligations under the Assigned Agreement assumed by Purchaser under
Paragraph 1. Company acknowledges and agrees that the obligations of Purchaser and Seller under
the Assigned Agreement are several and not joint.
3. Representations.
Company represents and warrants to NPC that: (a) the Assigned Agreement is in
full force and effect and constitutes the legal, valid and binding obligation of Company, except as
enforceability may be limited by bankruptcy, insolvency, reorganization or other similar laws
affecting creditors' rights or by equitable principles, (b) neither Company nor, to Company's
knowledge, Seller is in default of any obligation under the Assigned Agreement and neither has
any existing counterclaims, offsets or defenses against the other, (c)to Company's knowledge, no
event or condition exists which would either immediately or with the passage of any applicable
grace period or the giving of notice, or both, enable Company or Seller to terminate or suspend its
obligations under the Assigned Agreement, (d) to Company's knowledge, no event or condition
exists or has occurred which would give rise to any obligation of Seller to indemnify Company
pursuant to the Assigned Agreement, (e) Seller has no payment amount under the Assigned
Agreement outstanding or overdue and there are no pending claims for any payment amount
related to the Assigned Agreement,(f)the Assigned Agreement has not been amended or otherwise
modified, (g) Company is a [ ] duly formed and validly existing under the laws of the State of
[ ], (h) Company has power and authority to execute and deliver this Agreement and the
execution and delivery of which by Company has been duly and validly authorized and (i) this
Agreement constitutes the legal,valid and binding obligation of Company,except as enforceability
may be limited by bankruptcy,insolvency,reorganization or other similar laws affecting creditors'
rights or by equitable principles. NPC represents and warrants to Company that: (a) NPC is a
corporation duly formed and validly existing under the laws of the State of Nevada, (b) NPC has
power and authority to execute and deliver this Agreement and the execution and delivery of which
by NPC has been duly and validly authorized and (c) this Agreement constitutes the legal, valid
and binding obligation of NPC,except as enforceability may be limited by bankruptcy,insolvency,
reorganization or other similar laws affecting creditors' rights or by equitable principles.
4. Miscellaneous.
(i) This Agreement shall be binding upon the Parties and their respective
successors and assigns, and may be executed in one or more counterparts, each of which shall be
an original, but all of which shall together constitute one and the same instrument.
Exhibit F-2
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 161 of 198

(ii) If any provision of this Agreement shall be invalid or unenforceable, the
validity or enforceability of the remaining provisions shall not in any way be impaired thereby. In
the event of a conflict between this Agreement and the Assigned Agreement, the terms of this
Agreement shall control.
(iii) THIS ASSIGNMENT AND THE RIGHTS AND OBLIGATIONS OF THE
PARTIES HEREUNDER SHALL BE GOVERNED BY AND CONSTRUED IN
ACCORDANCE WITH THE LAWS OF [INSERT "THE STATE OF NEVADA" UNLESS
OTHERWISE AGREED BY PURCHASER AND SELLER] (WITHOUT GIVING EFFECT TO
THE CONFLICTS OF LAWS PRINCIPLES THEREOF THAT REQUIRE THE APPLICATION
OF ANOTHER JURISDICTION'S LAWS).
(iv) This Agreement embodies the complete agreement among the Parties with
respect to the subject matter hereof and supersedes all other oral or written understandings or
agreements.
(v) Company agrees to execute and deliver such instruments and take such
further actions as may be reasonably necessary to effectuate the purposes of this Agreement.
(vi) This Agreement may be amended, supplemented, or modified only by a
written instrument duly executed by or on behalf of each Party.
[Signature Page Follows]
Exhibit F-3
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 162 of 198

IN WITNESS WHEREOF, the Parties have caused their duly authorized officers
to execute and deliver this Agreement as of the date first above written.
[COMPANY]
By:
Name:
Title:
GREAT BASIN TRANSMISSION, LLC
By:
Name:
Title:
NEVADA POWER COMPANY
(d/b/a NV Energy)
By:
Name:
Title:
Exhibit F-4
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, [PC
Page 163 of 198

EXHIBIT G
FORM OF GRANT, BARGAIN AND SALE DEED
A.P.N.:
RECORDING REQUESTED BY,
WHEN RECORDED MAIL TO, AND
MAIL TAX STATEMENTS TO:
NV Energy
P.O. Box 98910
Las Vegas, NV 8915 1-0001
Attn: [ 1
The undersigned hereby affirm(s)that this document,
including any exhibits,submitted for recording does
not contain the social security number of any person or
persons. (Per NRS 23913.030)
GRANT,BARGAIN,AND SALE DEED
THIS DEED ("Deed") WITNESSETH, that Great Basin Transmission, LLC,
a Delaware limited liability company ("Grantor"), for a valuable consideration, the receipt and
sufficiency of which are hereby acknowledged, does hereby grant, bargain, and sell to [Nevada
Power Company]/[Sierra Pacific Power Company], a Nevada corporation, d/b/a NV Energy
("Grantee") (whose address is ), its
successors and assigns forever, an undivided [twenty-three and seventy-five hundredths percent
(23.75%)]/[one and twenty-five hundredths percent (1.25%)] ownership interest in all right, title
and interest in that real property and real property rights situated in the County of[ ], State
of Nevada, bounded and described as follows (the "PropertX"):
SEE LEGAL DESCRIPTION ATTACHED HERETO
AND MADE A PART HEREOF AS ANNEX"A".
TOGETHER WITH an undivided [twenty-three and seventy-five hundredths percent(23.75%)]/[one and
twenty-five hundredths percent(1.25%)] ownership interest in all right,title and interest in all the following
additional land rights:
SEE ADDITIONAL LAND RIGHTS ATTACHED HERETO
AND MADE A PART HEREOF AS ANNEX"B".
Exhibit G-1
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 164 of 198

AND TOGETHER WITH an undivided[twenty-three and seventy-five hundredths percent(23.75%)]/[one
and twenty-five hundredths percent(1.25%)] ownership interest in all right,title and interest in all
improvements situated thereon and all and singular the tenements, hereditaments and appurtenances
thereunto belonging or in anywise appertaining to the Property,and the reversion and reversions,remainder
and remainders,rents, issues and profits of the Property.
SUBJECT TO:
(1) Those matters more particularly described in Annex"C"attached to this Deed;
(2) All restrictions, conditions, reservations, prior reservations (if any), rights, rights of way and
easements now of record or otherwise apparent from a visual inspection of the Property; and
(3) Any applicable zoning or land use regulations or restrictions.
Grantor warrants that it shall execute, acknowledge, deliver, or cause to be executed,
acknowledged, or delivered, all documents or instruments granting security interests to the
Grantee in order to secure the performance of Grantor's obligations under this Deed. Grantee
may file and record all documents or instruments as may be appropriate or required to perfect
such security interests, and Grantor shall take such further actions and execute such further
documents and instruments, all as reasonably required by Grantee, to confirm and continue the
validity, priority, and perfection of any such security interests. Grantee may exercise any and all
rights provided in this Deed or in any security agreement related to the foregoing security
interest to recover any amount owning to Grantee, in such amount, form and sequence as
Grantee may elect in its sole discretion. Any failure to exercise any right provided to Grantee
under this paragraph shall not prejudice Grantee's rights to recover damages or amounts in any
manner.
[Signature Page Follows]
Exhibit G-2
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 165 of 198

IN WITNESS WHEREOF, this instrument has been executed this day of , 2010,to
be effective as of the day of ,2010.
GREAT BASIN TRANSMISSION, LLC, a Delaware limited liability company
By:
Print Name:
Title:
State of }
} ss:
County of }
This instrument was acknowledged before me on
by as
of
NOTARY PUBLIC
My Commission Expires:
Exhibit G-3
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 166 of 198

ANNEX"A"
LEGAL DESCRIPTION
[Legal Description to come when finalized]
Exhibit G-4
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 167 of 198

ANNEX"B"
ADDITIONAL LAND RIGHTS
[Additional Land Rights to come when finalized]
Exhibit G-5
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 168 of 198

ANNEX"C"
PERMITTED EXCEPTIONS
[Permitted Exceptions to come when finalized]
Exhibit G-6
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, [PC
Page 169 of 198

EXHIBIT H
APPLICABLE TRANSFER REPRESENTATIONS
AND WARRANTIES
Bracketed capitalized terms below shall have customary meanings set forth in the agreement for
the applicable Transfer, including that references in this Exhibit H to "[this Agreement]" shall
mean the agreement regarding the applicable Transfer.
1. With respect to a Transfer under Section 3.07(a), 3.08, 3.09 a , 5.03 d , 5.04 c , 13.04,
13.05 a , 14.04, 14.05, 15.02 b , 16.02 d or 16.02 , the Transferring Party shall make
the following representations and warranties to [Great Basin]/[the NVE Parties] as of the
date of the Transfer substantially in the form set forth below:
(a) Due Organization. The Transferring Party is a duly organized, validly existing
entity of the type described in the preface to [this Agreement] and is in good
standing under the laws of the jurisdiction of its formation and is duly qualified to
do business and in good standing as a foreign entity in the jurisdiction of its
principal place of business (if not formed in that jurisdiction).
(b) Power and Authority. The Transferring Party has the full [corporate]/[limited
liability company] legal right, power and authority to enter into [this Agreement]
and perform its obligations under [this Agreement].
(c) Due Authorization. The Transferring Party has taken all appropriate and necessary
[corporate]/[limited liability company] action to authorize its execution, delivery
and performance of[this Agreement] and the transactions contemplated hereunder.
(d) Consents. The Transferring Party has obtained all consents, approvals,permits and
other authorizations in connection with the execution, delivery and performance of
[this Agreement] required to be obtained by it; provided, however, that the
Transferring Party makes no representation or warranty under this Section d with
respect to any consents, approvals,permits or other authorizations necessary for the
development, construction, operation or maintenance of the Transmission Line.
(e) Binding Obligation. [This Agreement] constitutes a legal, valid and binding
obligation of the Transferring Party, enforceable against the Transferring Party in
accordance with its terms (subject to the effects of bankruptcy, insolvency,
reorganization, moratorium, fraudulent conveyance or other Applicable Laws now
Exhibit H-1
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 170 of 198

or hereafter in effect relating to creditors' rights generally and general principles of
equity).
(f) No Violation. The execution, delivery and performance by the Transferring Party
of [this Agreement], the compliance with the terms and provisions of [this
Agreement] and the carrying out of the transactions contemplated by [this
Agreement], (i) do not conflict with and will not result in a breach or violation of
any of the terms or provisions of the organizational documents of the Transferring
Party, (ii) do not conflict with and will not result in a material breach or violation
of any of the terms or provisions of any existing Applicable Law to which the
Transferring Party is subject or by which it or any of its material property is bound,
or any material agreement or instrument to which the Transferring Party is a party
or by which it or any of its material property is bound, or constitutes or will
constitute a default thereunder or (iii) will not result in the imposition of any Lien
upon any of the Ownership Interests being Transferred to [Great Basin]/[the NVE
Parties].
(g) Brokers. All negotiations relative to [this Agreement] and the transactions
contemplated by [this Agreement] have been carried out by the Transferring Party
directly with [Great Basin]/[the NVE Parties] without the intervention of any
Person on behalf of the Transferring Party in such manner as to give rise to any
valid claim by any Person against [Great Basin]/[the NVE Parties] for a finder's
fee, brokerage commission or similar payment.
(h) No Litigation and Compliance with Law. There is no litigation pending or, to the
Transferring Party's knowledge, threatened to which the Transferring Parry or any
of its Affiliates is a party that could reasonably be expected to have a [Material
Adverse Effect] on the resulting transfer. The Transferring Party is not in violation
of any Applicable Law where the effect of which to the Transferring Party,
individually or in the aggregate, could be reasonably expected to have a [Material
Adverse Effect].
(i) Title to ON Line. The Transferring Party possesses good,valid and marketable title
to a [_]% Ownership Interest free and clear of all Liens except Excluded Liens,
and, effective upon the Transfer and the payment of the Applicable Purchase Price
by the non-Transferring Party(ies), (i) [Great Basin] shall Transfer to [NPC and
SPPC] a [_]% Ownership Interest and a [_]% Ownership Interest, respectively,
in each case, free and clear of all Liens except Permitted Liens.
Exhibit H-2
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 171 of 198

(j) Agreements and Governmental Approvals. The Transferring Party has delivered
true, correct and complete copies of each agreement (other than an ON Line
Agreement to which [Great Basin]/[the NVE Parties] is a party) (including any
amendment thereto) to [Great Basin]/[the NVE Parties] as of the date of the
Transfer to which the Ownership Interests being Transferred may be subject.
[NPC]/[Great Basin] is not in material breach of its obligations under any ON Line
Agreement, to [NPC]/[Great Basin]'s knowledge, no counterparty (other than
[Great Basin]/[the NVE Parties])to any such agreement is in material default of its
obligations under any such agreement and each such agreement is an enforceable
and binding obligation of it, and to its knowledge, the other parties (other than
[Great Basin/[the NVE Parties]) thereto (subject to the effects of bankruptcy,
insolvency,reorganization,moratorium,fraudulent conveyance or other Applicable
Laws now or hereafter in effect relating to creditors' rights generally and general
principles of equity). The Transferring Party is in compliance with each
Governmental Approval for ON Line in all material respects.
When used in Sections(a)-(i)above,the term"knowledge"shall be limited to the actual knowledge
of specified persons as reasonably agreed by the Parties. The representations and warranties of
the Transferring Party described in Sections (a)-(i) above shall survive the date of the Transfer as
follows: (a)the representations and warranties in Sections(a)-(gland Q shall survive forever, and
(b) all other representations and warranties shall survive for three (3) years after the date of the
Transfer. The Transferring Party's maximum aggregate liability for Claims which may be
recovered for breaches of representations or warranties contained in Section shall be an amount
equal to the purchase price for the applicable Transfer (or other amount being paid in respect of
the applicable transfer, as applicable) in accordance with this Agreement (the "Applicable
Purchase Price"); provided, however, that (a) there shall be no maximum aggregate liability in
connection with Claims for gross negligence, willful misconduct or fraud and (b) the Applicable
Purchase Price (but only for purposes of determining the maximum aggregate liability in this
sentence) for a Transfer under (i) Sections 5.03(d), 5.04 c , 13.04 and 14.04 shall equal the costs
not funded by Great Basin that give rise to such Transfer and (ii) Section 16.02(f) shall equal the
amount of the applicable Event(s) of Default.
2. With respect to the Transfer contemplated by Section 6.01, [NPC]/[SPPC] shall make the
following representations and warranties to Great Basin as of the date of the Transfer
substantially in the form set forth below:
(a) Due Organization. [NPC]/[SPPC] is a duly organized,validly existing entity of the
type described in the preface to [this Agreement] and is in good standing under the
laws of the jurisdiction of its formation and is duly qualified to do business and in
good standing as a foreign entity in the jurisdiction of its principal place of business
(if not formed in that jurisdiction).
Exhibit H-3
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 172 of 198

(b) Power and Authority. [NPC]/[SPPC] has the full corporate legal right, power and
authority to enter into [this Agreement] and perform its obligations under [this
Agreement].
(c) Due Authorization. [NPC]/[SPPC] has taken all appropriate and necessary
corporate action to authorize its execution, delivery and performance of [this
Agreement] and the transactions contemplated hereunder.
(d) Consents. [NPC]/[SPPC] has obtained all consents, approvals, permits and other
authorizations in connection with the execution, delivery and performance of[this
Agreement] required to be obtained by it; provided, however, that [NPC]/[SPPC]
makes no representation or warranty under this Section (d) with respect to any
consents,approvals,permits or other authorizations necessary for the development,
construction, operation or maintenance of the Transmission Line.
(e) Binding Obligation._ [This Agreement] constitutes a legal, valid and binding
obligation of[NPC]/[SPPC],enforceable against[NPC]/[SPPC] in accordance with
its terms (subject to the effects of bankruptcy, insolvency, reorganization,
moratorium, fraudulent conveyance or other Applicable Laws now or hereafter in
effect relating to creditors' rights generally and general principles of equity).
(f) No Violation. The execution, delivery and performance by [NPC]/[SPPC] of[this
Agreement],the compliance with the terms and provisions of[this Agreement] and
the carrying out of the transactions contemplated by [this Agreement], (i) do not
conflict with and will not result in a material breach or violation of any of the terms
or provisions of the organizational documents of[NPC]/[SPPC], (ii)do not conflict
with and will not result in a breach or violation of any of the terms or provisions of
any existing Applicable Law to which [NPC]/[SPPC] is subject or by which it or
any of its material property is bound, or any material agreement or instrument to
which [NPC]/[SPPC] is a party or by which it or any of its material property is
bound, or constitutes or will constitute a default thereunder and(iii) will not result
in the imposition of any Lien (other under any GB Segment Financing Agreement
or a [Permitted Lien]) upon the Transmission Improvements being Transferred to
Great Basin.
(g) Brokers. All negotiations relative to [this Agreement] and the transactions
contemplated by [this Agreement] have been carried out by [NPC]/[SPPC] directly
with Great Basin without the intervention of any Person on behalf of[NPC]/[SPPC]
in such manner as to give rise to any valid claim by any Person against Great Basin
for a finder's fee,brokerage commission or similar payment.
Exhibit H-4
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 173 of 198

(h) No Litigation and Compliance with Law. There is no litigation pending or, to
[NPC]/[SPPC]'s knowledge, threatened to which [NPC]/[SPPC] or any of its
Affiliates is a party that could reasonably be expected to have a [Material Adverse
Effect] on the resulting transfer. [NPC]/[SPPC] is not in violation of any
Applicable Law where the effect of which to [NPC]/[SPPC], individually or in the
aggregate, could be reasonably expected to have a [Material Adverse Effect].
(i) Title. [NPC]/[SPPC] possesses good, valid and marketable title to all of the
personal property comprising the Transmission Improvements and good, valid,
marketable and indefeasible fee title to all of the real property comprising the
Transmission Improvements or good, valid and marketable leasehold interests in
the real property comprising the Transmission Improvements, and, effective upon
the Transfer and the payment of the Transmission Improvement Purchase Price by
Great Basin, (i) Great Basin shall own and hold good, valid and marketable title to
the Transmission Improvements constituting personal property (tangible and
intangible assets) and (ii) Great Basin shall own and hold good, valid, marketable
and indefeasible title to the real property comprising the Transmission
Improvements or a good, valid and marketable leasehold interest in the real
property comprising the Transmission Improvements, in each case, free and clear
of all Liens except [Permitted Liens].
(j) Governmental Approvals, Compliance with Laws; Hazardous Substances.
(i) [NPC]/[SPPC] has provided true, correct and complete copies of each
Governmental Approval for the Transmission Improvements, and all
applications for any pending Governmental Approval for the Transmission
Improvements, to Great Basin and the status of each Governmental
Approval for Transmission Improvements is set forth in Schedule 1 1.
(ii) No application submitted by or on behalf of [NPC]/[SPPC] or any of its
Affiliates in connection with any Governmental Approval for the
Transmission Improvements contains any intentional misrepresentation.
[NPC]/[SPPC] is in compliance with each Governmental Approval for the
Transmission Improvements in all material respects and each Governmental
Approval for the Transmission Improvements(A)is in full force and effect,
(B) is not subject to any legal proceeding or to any unsatisfied condition
that is not reasonably expected to be satisfied or could reasonably be
expected to allow material modification or revocation thereof and (C) is
final and all applicable appeal periods have expired or terminated.
Exhibit H-5
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 174 of 198

(111) Except for modifications to Governmental Approvals for the Transmission
Improvements that have already been made, no modification to a
Governmental Approval is required for the conveyance or acquisition of the
Transmission Improvements. No further action is required for each
Governmental Approval for the Transmission Improvements to be properly
in the name of Great Basin.
(iv) [NPC]/[SPPC] is in compliance with all Applicable Laws in all material
respects with respect to the Transmission Improvements.
(v) [NPC]/[SPPC] is in compliance with all Environmental Laws in all material
respects with respect to the Transmission Improvements. To the knowledge
of [NPC]/[SPPC], Hazardous Substances have not been released, spilled,
leaked or disposed of on, at, or under the real property comprising the
Transmission Improvements, or on, at,or under any property adjacent to the
real property comprising the Transmission Improvements, resulting from
the construction, operation or maintenance of the Transmission
Improvements in any amount or concentration that is likely to require
investigation or remediation pursuant to applicable Environmental Laws or
in connection with the operation or maintenance of the Transmission
Improvements.
When used in Sections(a)-J)above,the term"knowledge"shall be limited to the actual knowledge
of specified persons as reasonably agreed by [NPC]/[SPPC] and Great Basin. The representations
and warranties of[NPC]/[SPPC] in Sections (a)-(D above shall survive the date of the Transfer as
follows: (a) the representations and warranties in Sections (a)-(g) and�shall survive forever, (b)
all representations and warranties in Section (i)(v) shall survive for five (5) years after the date of
the Transfer and (c) all other representations and warranties shall survive for three (3) years after
the date of the Transfer. [NPC]/[SPPC]'s maximum aggregate liability for Claims which may be
recovered for breaches of representations or warranties contained in Section shall be the amount
paid by Great Basin for the Transmission Improvements in accordance with Section 6.01 (the
"Transmission Improvement Purchase Price");provided,however,that there shall be no maximum
aggregate liability in connection with Claims for gross negligence, willful misconduct or fraud.
3. With respect to the Transfer contemplated by Section 6.05(d), Great Basin shall make the
following representations and warranties to NPC as of the date of the Transfer substantially
in the form set forth below:
(a) Due Organization. Great Basin is a duly organized, validly existing entity of the
type described in the preface to [this Agreement] and is in good standing under the
laws of the jurisdiction of its formation and is duly qualified to do business and in
Exhibit H-6
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 175 of 198

good standing as a foreign entity in the jurisdiction of its principal place of business
(if not formed in that jurisdiction).
(b) Power and Authority. Great Basin has the full limited liability company legal right,
power and authority to enter into [this Agreement] and perform its obligations
under [this Agreement].
(c) Due Authorization. Great Basin has taken all appropriate and necessary limited
liability company action to authorize its execution, delivery and performance of
[this Agreement] and the transactions contemplated hereunder.
(d) Consents. Great Basin has obtained all consents, approvals, permits and other
authorizations in connection with the execution, delivery and performance of[this
Agreement] required to be obtained by it; provided, however, that Great Basin
makes no representation or warranty under this Section (d) with respect to any
consents,approvals,permits or other authorizations necessary for the development,
construction, operation or maintenance of the Transmission Line.
(e) Binding Obligation._ [This Agreement] constitutes a legal, valid and binding
obligation of Great Basin, enforceable against Great Basin in accordance with its
terms(subject to the effects of bankruptcy,insolvency,reorganization,moratorium,
fraudulent conveyance or other Applicable Laws now or hereafter in effect relating
to creditors' rights generally and general principles of equity).
(f) No Violation. The execution, delivery and performance by Great Basin of [this
Agreement],the compliance with the terms and provisions of[this Agreement] and
the carrying out of the transactions contemplated by [this Agreement], (i) do not
conflict with and will not result in a breach or violation of any of the terms or
provisions of the organizational documents of Great Basin, (ii)do not conflict with
and will not result in a material breach or violation of any of the terms or provisions
of any existing Applicable Law to which Great Basin is subject or by which it or
any of its material property is bound, or any material agreement or instrument to
which Great Basin is a party or by which it or any of its material property is bound,
or constitutes or will constitute a default thereunder and (iii) will not result in the
imposition of any Lien(other than under any financing or security agreements with
the NVE Lenders or a [Permitted Lien]).upon any of[the Transferred Assets] being
Transferred to NPC.
(g) Brokers. All negotiations relative to [this Agreement] and the transactions
contemplated by [this Agreement] have been carried out by Great Basin directly
Exhibit H-7
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 176 of 198

with NPC without the intervention of any Person on behalf of Great Basin in such
manner as to give rise to any valid claim by any Person against NPC for a finder's
fee, brokerage commission or similar payment.
(h) No Litigation and Compliance with Law. There is no litigation pending or,to Great
Basin's knowledge, threatened to which Great Basin or any of its Affiliates is a
party that could reasonably be expected to have a [Material Adverse Effect] on the
resulting transfer. Great Basin is not in violation of any Applicable Law where the
effect of which to Great Basin,individually or in the aggregate,could be reasonably
expected to have a [Material Adverse Effect].
(i) Title and no Liens. [ ] At the Transfer, Great Basin has not
created or permitted to exist any Liens on any of the Applicable Centennial Phase
3 Facilities or any other NPC asset.
(j) Governmental Approvals; Compliance with Laws; Hazardous Substances.
(i) Great Basin has provided true, correct and complete copies of each
Governmental Approval obtained by Great Basin for the Applicable
Centennial Phase 3 Facilities (to which NPC is not a Party) and [the
Transferred Assets], and all applications for any pending Governmental
Approval for the Applicable Centennial Phase 3 Facilities(to which NPC is
not a Party) and [the Transferred Assets], to NPC and the status of each
Governmental Approval for the Applicable Centennial Phase 3 Facilities(to
which NPC is not a Party) and [the Transferred Assets] is set forth in
Schedule [ 1.
(ii) No application submitted by or on behalf of Great Basin or any of its
Affiliates in connection with any Governmental Approval for the
Applicable Centennial Phase 3 Facilities and [Transferred Assets] contains
any intentional misrepresentation. Great Basin is in compliance with each
Governmental Approval for the Applicable Centennial Phase 3 Facilities
and [Transferred Assets] in all material respects and each Governmental
Approval for Applicable Centennial Phase 3 Facilities(to which NPC is not
a party) and [Transferred Assets] (A) is in full force and effect, (B) is not
subject to any legal proceeding or to any unsatisfied condition that is not
reasonably expected to be satisfied or could reasonably be expected to allow
material modification or revocation thereof and (C) is final and all
applicable appeal periods have expired or terminated.
Exhibit H-8
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 177 of 198

(iii) Except for modifications to Governmental Approvals for [the Transferred
Assets] that have already been made, no modification to a Governmental
Approval is required for the conveyance or acquisition of[the Transferred
Assets]. No further action is required for each Governmental Approval for
the Applicable Centennial Phase 3 Facilities (to which NPC is not a Party)
or [the Transferred Asset] to be properly in the name of NPC.
(iv) Great Basin is in compliance with all Applicable Laws in all material
respects with respect to the Applicable Centennial Phase 3 Facilities and
[the Transferred Assets].
(v) Great Basin is in compliance with all Environmental Laws in all material
respects with respect to the Applicable Centennial Phase 3 Facilities and
[the Transferred Assets]. To the knowledge of Great Basin, Hazardous
Substances have not been released, spilled, leaked or disposed of on, at, or
under the Applicable Centennial Phase 3 Facilities or [the Transferred
Assets], or on, at, or under any property adjacent to the Applicable
Centennial Phase 3 Facilities or [the Transferred Assets],resulting from the
installation, construction, operation or maintenance of the Applicable
Centennial Phase 3 Facilities or the [the Transferred Assets] in any amount
or concentration that is likely to require investigation or remediation
pursuant to applicable Environmental Laws or in connection with the
installation, construction or maintenance of the Applicable Centennial
Phase 3 Facilities or [the Transferred Assets].
When used in Sections(a)-(i)above,the term"knowledge"shall be limited to the actual knowledge
of specified persons as reasonably agreed by NPC and Great Basin. The representations and
warranties of Great Basin in Sections(a)-(i)above shall survive the date of the Transfer as follows:
(a) the representations and warranties in Sections (a)-(g) and (i) shall survive forever, (b) all
representations and warranties in Section(i)(v) shall survive for five(5) years after the date of the
Transfer and (c) all other representations and warranties shall survive for three (3) years after the
date of the Transfer. Great Basin's maximum aggregate liability for Claims which may be
recovered for breaches of representations or warranties contained in Section shall be an amount
equal to the sum of (A) the Option Exercise Price and (B) the fair market value of any
improvements to the Applicable Centennial Phase 3 Facilities made by Great Basin,minus(ii)the
amount set forth in Section 6.05(b)(iv)(2)(B); provided, however,that there shall be no maximum
aggregate liability in connection with Claims for gross negligence, willful misconduct or fraud.
Exhibit H-9
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, [PC
Page 178 of 198

EXHIBIT I
FORM OF LEGAL OPINION
The legal opinions required by this Agreement shall contain the following opinions subject to
customary assumptions and qualifications. For purposes of this Exhibit I, the following terms
have the meanings set forth below. To the extent not defined below,bracketed terms below shall
have customary meanings set forth in the applicable legal opinions.
"Applicable Laws" shall mean those laws, rules and regulations which in the
experience of the counsel rendering such opinion are normally applicable to transactions of the
type contemplated by the Security Documents, without having made any special investigation as
to the applicability of any specific law,rule or regulation,and which are not the subject of a specific
opinion referring expressly to a particular law or laws.
"Applicable Orders"means those orders or decrees of governmental authorities
identified on Schedule[_] to the Certificate.
"Certificate"means the certificate of Great Basin, dated the date of the applicable
legal opinion, a copy of which is attached to such legal option.
"Delaware Filing Office"means the Secretary of State of the State of Delaware.
"Delaware UCC"means the Uniform Commercial Code as in effect on the date of
the applicable legal opinion in the State of Delaware(without regard to laws referenced in Section
9-201 thereof and without regard to any case law or any administrative rulings thereunder).
"Financing Statement"means an unfiled copy of a financing statement bearing file
date [_] and file number [_] identifying "Great Basin Transmission, LLC" as debtor and
"Nevada Power Company" and "Sierra Pacific Power Company" as secured parties, which was
filed in the Delaware Filing Office, [Nevada Filing Office] or [Idaho Filing Office], as applicable.
"Governmental Approval"means any consent, approval, license, authorization or
validation of, or filing, recording or registration with, any governmental authority pursuant to the
Applicable Laws of the State of Delaware, Idaho, Nevada or New York or United States of
America.
"Idaho UCC"means the Uniform Commercial Code as in effect on the date of the
applicable legal opinion in the State of Idaho (without regard to laws referenced in Section 9-201
thereof).
Exhibit I-1
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 179 of 198

"Letter of Credit Rights"has the meaning set forth in the [[identify state of issuer's
jurisdiction within the meaning of the New York UCC/UCC] with respect to the [identify letter(s)
of credit provided pursuant to any Material Construction Contract].
"Nevada UCC" means the Uniform Commercial Code as in effect on the date of
the applicable legal opinion in the State of Nevada (without regard to laws referenced in Section
9-201 thereof).
"New York UCC"means the Uniform Commercial Code as in effect on the date of
the applicable legal opinion in the State of New York(without regard to laws referenced in Section
9-201 thereof).
"Obligations"has the meaning set forth in the [Security Agreement].
"UCC" means the New York UCC, the Delaware UCC, the Nevada UCC and the
Idaho UCC, as applicable.
1. Great Basin is validly existing and in good standing under the Applicable Laws of
the State of Delaware.
2. Great Basin is qualified to do business and in good standing as a foreign limited
liability company under the Applicable Laws of the States of Nevada and Idaho.
3. Great Basin has the limited liability company power and authority to execute,
deliver and perform all of its obligations under each Security Document to which it is a
party under the Applicable Laws of the State of Delaware. The execution and delivery of
each of the Security Documents and the consummation by Great Basin of the transactions
contemplated thereby have been duly authorized by all requisite limited liability company
action on the part of Great Basin under the Applicable Laws of the State of Delaware. Each
of the Security Documents has been duly executed and delivered by Great Basin under the
Applicable Laws of the State of Delaware.
4. Each of the Security Documents constitutes the valid and binding obligation of
Great Basin enforceable against Great Basin in accordance with its terms under the
Applicable Laws of the States of New York,Nevada and Idaho.
5. The execution and delivery by Great Basin of each of the Security Documents and
the performance by Great Basin of its obligations under each of the Security Documents,
each in accordance with its terms, do not(i) conflict with the [Certificate of Formation] or
[Limited Liability Company Operating Agreement] of Great Basin, (ii) constitute a
violation of, or a default under, any agreement to which Great Basin is a party or its assets
are subject or(iii)cause the creation of any security interest or lien upon any of the property
of Great Basin pursuant to any agreement to which Great Basin is a party or its assets are
Exhibit I-2
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 180 of 198

subject(other than the security interests and liens created in favor of the NVE Parties under
the Security Documents or a Permitted Lien).
6. Neither the execution, delivery or performance by Great Basin of the Security
Documents nor the compliance by Great Basin with the terms and provisions thereof will
contravene any provision of any Applicable Law of the States of New York, Nevada or
Idaho or any Applicable Law of the United States of America which in the experience of
the counsel rendering such opinion is normally applicable to transactions of the type
contemplated by such Security Documents.
7. No Governmental Approval,which has not been obtained or taken and is not in full
force and effect, is required to authorize, or is required in connection with, the execution
or delivery of any of the Security Documents by Great Basin or the enforceability of any
of the Security Documents against Great Basin.
8. Neither the execution, delivery or performance by Great Basin of its obligations
under the Security Documents nor compliance by Great Basin with the terms thereof will
contravene any Applicable Order.
9. The provisions of[the Security Agreement] are effective to create a valid security
interest in favor of the NVE Parties in Great Basin's rights in the Collateral (as defined in
[the Security Agreement]) in which a security interest may be created under Article 9 of
the New York UCC (the "Article 9 Collateral")to secure the Obligations.
10. Under the Delaware UCC, pursuant to the provisions of the [Security Agreement],
Great Basin has authorized the filing of the Financing Statement for purposes of Section
9-509 of the Delaware UCC. Under the Nevada UCC, pursuant to the provisions of the
[Security Agreement], Great Basin has authorized the filing of the Financing Statement for
purposes of Section 9-509 of the Nevada UCC. Under the Idaho UCC, pursuant to the
provisions of the [Security Agreement], Great Basin has authorized the filing of the
Financing Statement for purposes of Section 9-509 of the Idaho UCC.
11. Under the New York UCC, the location of Great Basin, for purposes of Section 9-
307(e) of the New York UCC, is Delaware. Each Delaware Financing Statement is in
appropriate form for filing in the Delaware Filing Office. Upon the proper filing of the
Delaware Financing Statements in the Delaware Filing Office, the security interest of the
NVE Parties in the Article 9 Collateral will be perfected to the extent that a security interest
in such Article 9 Collateral can be perfected by the filing of a financing statement under
the Delaware UCC.
12. The [Mortgage/Deed of Trust] is in appropriate form for filing in the [Official
Public Records of Real Property] of[ ] County, [Nevada]/[Idaho] and creates a
valid lien upon, and security interest in, Great Basin's rights in the [Mortgaged Property]
as defined in the [Mortgage/Deed of Trust] ("Mortgaged Property") that constitutes real
property, or fixtures attached thereto, located in [Nevada]/[Idaho].
Exhibit I-3
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 181 of 198

13. Except for the filing of the [Mortgage/Deed of Trust] in the [Official Public Records
of Real Property] of[ ] County, [Nevada]/[Idaho], and with respect to fixtures,
subject to the terms of paragraph 14 below,no documents or instruments need be recorded,
registered or filed in any public office in the State of[Nevada]/[Idaho] to perfect the liens
and security interests in the real property and fixtures of Great Basin located in [ ]
County, [Nevada]/[Idaho] which constitute part of the Mortgaged Property.
14. The [Fixture Financing Statement] is in appropriate form for filing in the UCC
records of the [Nevada]/[Idaho] Secretary of State. If Great Basin is deemed not to be a
[Transmitting Utility], then the proper recordation of the [Mortgage/Deed of Trust] in the
[Official Public Records of Real Property] of [ ] County, [Nevada]/[Idaho] will
perfect the security interest created under the [Mortgage/Deed of Trust] in the fixtures of
Great Basin located in [ ] County, [Nevada]/[Idaho] constituting part of the
Mortgaged Property. If, however, Great Basin is deemed to be a [Transmitting Utility],
the proper filing of the [Fixture Financing Statement] in the UCC records of the
[Nevada]/[Idaho] Secretary of State will perfect such security interest in the fixtures of
Great Basin located in [ ] County, [Nevada]/[Idaho] constituting part of the
Mortgaged Property described in the [Fixture Financing Statement], and so long as the
[Fixture Financing Statement] continues to identify Great Basin as a [Transmitting Utility],
it will remain effective until a termination statement is filed pursuant to Section [9.515(f)]
of the [Nevada UCC]/[Idaho UCC].
15. Upon the proper recordation of the [Mortgage/Deed of Trust] in the [Official Public
Records of Real Property] of[ ] County, [Nevada]/[Idaho],the liens and security
interests created by the [Mortgage/Deed of Trust] in Great Basin's rights in the real
property and, subject to paragraph 14 above, fixtures described therein located in
[ ] County, [Nevada]/[Idaho] will be perfected.
16. Under the [[identify state of issuer's jurisdiction within the meaning of the New
York UCCJ UCC],the provisions of the [Letter of Credit Consent(s)] are effective to perfect
the security interest of the NVE Parties in Great Basin's rights in the Letter of Credit
Rights.
Exhibit I-4
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 182 of 198

Schedule 1
DESCRIPTION OF TRANSMISSION LINE
The Transmission Line is an above-ground 500 kV AC transmission project in Nevada and
Southern Idaho consisting of three segments. The northernmost and central segments of the
Transmission Line are collectively known as the Southwest Intertie Project. The northernmost
segment, SWIP-N, extends approximately 280 miles from the Midpoint Substation near Jerome,
Idaho to the Robinson Summit Substation and includes BLM right-of-way grants N-85211, N-
49781, 1-26446, and approximately four miles of N-85210 and N-85211 t. The central segment,
SWIP-S or ON Line, extends approximately 231 miles from the Robinson Summit Substation to
the Harry Allen Substation just north of Las Vegas in Clark County, Nevada, and includes BLM
right-of-way grant N-85210. The southernmost segment of the Transmission Line,which is known
as the Southern Nevada Intertie Project or SNIP, extends approximately 59 miles from the Harry
Allen Substation to the Eldorado Substation located southwest of Boulder City,Nevada.
The Transmission Line project will be executed in two phases. Phase 1 will extend from Robinson
Summit to Harry Allen and will consist of the SWIP-S project assets, and the following assets
provided by NVE: microwave communications system, Falcon substation expansion, permits to
locate the Robinson Summit Substation at the Robinson Summit Location, and NVE relay
replacements. The Phase 1 assets shall be renamed the "One Nevada Transmission Line"
(abbreviated as "ON Line")pursuant to Section 4.08 of this Agreement.
Phase 2 is comprised of two segments: (i) SWIP-N,extending from Midpoint to Robinson Summit
and (ii) SNIP, extending from Harry Allen to Eldorado. Phase 2 will include a number of
equipment additions to the Phase 1 assets including the following (each of which if undertaken
prior to GB Segment Financial Closing shall be considered a "Transmission Improvement" for
purposes of Section 6.01 of this Agreement):
• 2—345 kV phase shifting transformers at the Robinson Summit Substation
• Static Var compensator(s) at the Robinson Summit Substation on the 500 kV and/or 345
kV side of the substation
• 500 kV terminal equipment at Midpoint and Robinson Summit Substations with line
reactors for the SWIP-N facilities
• 500 kV series compensation for Phase 1
• 500 kV series compensation for SWIP-N
• 500 kV series compensation for SNIP
• 500 kV terminal equipment at Harry Allen and Eldorado Substations for the SNIP facilities
' The ON Line Owners shall cooperate to pursue an amendment of N-85210 and N-85211,as required,for Great
Basin to obtain BLM authorization for approximately four miles of right-of-way extending the southern terminus of
SWIP-N to the Robinson Summit Location.
Schedule 1-1
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 183 of 198

• 500 kV and 230 kV breaker upgrades at various Eldorado Valley substations as required
to accommodate fault duty as a result of the addition of the Phase 2 facilities
Fiber communications equipment for the SWIP-N
• Fiber communications equipment for the SNIP facilities
For purposes of this Agreement,the term"ON Line"shall be deemed to include(a)a single circuit,
above-ground 500 kV AC transmission line that extends approximately 231 miles from the
Robinson Summit Substation located northwest of Ely, Nevada in White Pine County,Nevada to
the existing Harry Allen Substation located northeast of Las Vegas in Clark County, Nevada, (b)
the Robinson Summit Substation,(c)interconnection facilities required at the existing Harry Allen
Substation, (d) expansion of the existing Falcon Substation, (e) communication facilities, (f)
system relay upgrades, and(g) sub-synchronous resonance mitigation. Each of these components
is further described below.
• ON Line (SWIP-S) 500 kV Transmission Line—The transmission line will be constructed
within BLM right-of-way grant N-85210 in a 200 foot wide right-of-way extending from
Robinson Summit Substation to the Harry Allen Substation. The transmission line is
configured with three bundles of three ACSR"Lapwing"conductors and is protected from
lightning with two overhead shield wires, one of which will be an optical ground wire
containing twenty four fiber optic wires. The primary structure will be a horizontal
configuration, tubular guyed-v with a weathering steel finish.
• Robinson Summit Substation—Robinson Summit Substation for Phase 1 will initially be
configured as a four(4)terminal 345 kV ring bus and a three(3)terminal 500 kV ring bus.
The 500/345 kV substation will serve as the northern terminus of the ON Line and the
southern terminus of the SWIP-N. The substation will also interconnect to the existing
NVE 345 kV Falcon-to-Gonder transmission line. The Robinson Summit Substation will
be located at the Robinson Summit Location (as described in BLM right-of-way grant N-
89507). The Robinson Summit Substation will initially contain two (2) 500/345 kV auto
transformers, two (2) 500 kV shunt reactors, ten (10) 500 kV circuit breakers (five (5) to
be operated at 345 kV), three (3) 500 kV metering voltage transformers, three (3) 500 kV
metering current transformers, one (1) 345 kV shunt reactor, one (1) 345 kV fixed series
capacitor, and all necessary disconnect switches, Capacitive Coupled Voltage
Transformers ("CCVT"), arresters and other appurtenant facilities (e.g., meter house,
trenches, control cables, and other equipment).
• Harry Allen substation interconnection— Harry Allen is an existing NVE-owned breaker
and a half configured 500 kV switchyard located approximately 21 miles northeast of Las
Vegas, Nevada. The new interconnection facilities for ON Line will be contained within
the existing Harry Allen fenceline and will include the addition of a new breaker and a half
bay, two (2) 500 kV shunt reactors, four (4) 500 kV circuit breakers, and all necessary
disconnect switches, CCVT's, arresters, and other appurtenant facilities (e.g.,meter house,
trenches, control cables, and other equipment).
Schedule 1-2
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 184 of 198

• Falcon substation expansion — Falcon Substation is an existing NVE-owned 345 kV
switchyard located in Boulder Valley approximately 40 miles northeast of Battle Mountain,
Nevada. The expansion would require approximately seven (7) acres of additional land
outside the existing fenced boundary(four acres on NV Energy property and three acres to
be obtained from the adjacent private landowner). The new equipment would consist of
345 kV fixed series capacitor bank, along with associated disconnect switches, CCVTs,
arrestors, and any other appurtenant facilities required for control and protection of the
newly installed equipment.
• Communication facilities — Communication facilities include a twenty-four (24) fiber
optical ground wire (OPGW) installed on the 500kV transmission line, two regeneration
sites for the OPGW, and a microwave and mobile radio communications system including
fourteen(14) new microwave sites, the expansion of and additions to six (6) existing sites
located in eastern Nevada, and some fiber connectivity additions within NVE's existing
network.
• System relay upgrades — Various relays and associated communications equipment will
need to be upgraded at five(5)NVE-owned switchyards including Gonder,Falcon,Valmy,
Coyote, and Tracy.
• Sub-synchronous Resonance upgrades — Facilities required near affected generators to
prevent SSR impacts due to Phase 1, 345 kV series compensation, except to the extent the
cost of such upgrades is determined to be the responsibility of a generator.
For purposes of this Agreement, the term "Great Basin Segments"rents" shall be deemed to include (a)
SWIP-N, a single circuit, above-ground 500 kV AC transmission line that extends from the
Robinson Summit Substation to the existing Idaho Power Midpoint Substation near Jerome,Idaho,
(b) expansion of the Robinson Summit Substation, (c) Midpoint Substation interconnection, (d)
SNIP, a single or double circuit above-ground 500 kV AC transmission line that extends from the
Harry Allen Substation to the Eldorado Substation,and(e) sub-synchronous resonance mitigation.
Each of these components is further described below.
• SWIP-N 500 kV Transmission Line — SWIP-N is an approximately 280 mile 500 kV
transmission line expected to be constructed within a 200-foot right-of-way grant defined
by BLM serial numbers N-85211, N-49781, I-26446, and approximately four miles of N-
85210 and N-852112. The transmission line will extend north from the Robinson Summit
Substation into a substation in Idaho, which the Parties currently contemplate shall be
Idaho Power's existing Midpoint Substation near Jerome, Idaho. Numerous private and
2 The ON Line Owners shall cooperate to pursue an amendment of N-85210 and N-85211,as required,for Great
Basin to obtain BLM authorization for approximately four miles of right-of-way extending the southern terminus of
SWIP-N to the Robinson Summit Location.
Schedule 1-3
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 185 of 198

state owned lands will also be crossed. The transmission line is configured with three
bundles of three ACSR "Lapwing" conductors and is protected from lightning with two
overhead shield wires one of which will be an optical ground wire. The primary structure
may be a horizontal configuration, tubular guyed-v with a weathering steel finish.
Microwave communication facilities may also be required.
• Robinson Summit Substation Expansion — The Robinson Summit substation constructed
for the ON Line project, as described above, will ultimately be expanded to include
additional facilities to accommodate SWIP-N. Final configuration details will be defined
in an interconnection agreement between Great Basin and NV Energy. Currently, it is
expected that the following equipment may be necessary: the addition of two (2) 500 kV
breaker and a half bays, two (2) 500 kV fixed and/or TCSC (Thyristor Controlled) series
capacitor banks or other facilities as required for SSR mitigation, two (2) 500 kV shunt
reactors, two (2) 500 kV shunt capacitor banks, 500 and/or 345 kV static var
compensator(s), twenty-four (24) 500 kV circuit breakers, two (2) 345 kV phase shifting
transformers, two (2) 345 kV shunt capacitor banks, and all necessary metering voltage
transformers, metering current transformers, disconnect switches, CCVTs, arresters, and
other appurtenant facilities (e.g., meter house, trenches, control cables, and other
equipment). The expansion will be within BLM right-of-way grant N-82076.
• Idaho Substation interconnection — The Parties currently contemplate that SWIP-N will
interconnect with the Midpoint Substation. Midpoint is an existing Idaho Power substation
that will be expanded to accommodate the SWIP-N transmission line. Details of the
expansion have not been finalized but will likely include the addition of a breaker and a
half bay, two (2) 500 kV shunt reactors, four (4) 500 kV circuit breakers, all necessary
disconnect switches, CCVT's and arresters. Final configuration details will be defined in
an interconnection agreement between Great Basin and the owner of the applicable
substation in Idaho.
• SNIP 500 kV Transmission Line-the Southern Nevada Intertie Project(SNIP), a single or
double circuit 500kV transmission project that extends approximately 58 miles from the
Harry Allen Substation to the Eldorado Substation located southwest of Boulder City,
Nevada. The project will be constructed within right-of-way grants and easements to be
secured from BLM, Bureau of Reclamation, local governmental entities, and private
landowners. A portion of the line may be constructed on existing NVE Centennial Phase
3 facilities. The SNIP will include communications facilities. In addition, both the Harry
Allen and Eldorado substations will be modified to accommodate interconnection of the
SNIP transmission line and might be utilized for the SNIP associated series compensation.
• Sub-synchronous Resonance upgrades — Facilities required near affected generators to
prevent SSR impacts due to Phase 2, 500 kV series compensation, except to the extent the
cost of such upgrades is determined to be the responsibility of a generator.
Schedule 1-4
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 186 of 198

Schedule 2
MONTHLY PAYMENT FACTORS
Period Factor
From the ON Line COD to the fifteenth(15th) anniversary of the 0.00838275
ON Line COD
From the fifteenth(15th) anniversary of the ON Line COD to the 0.00503158
thirtieth (30th) anniversary of the ON Line COD
From the thirtieth (30th) anniversary of the ON Line COD to the 0.00118325
forty-first(41 st) anniversary of the ON Line COD
Schedule 2-1
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 187 of 198

Schedule 3
OPERATING ACTIVITIES
The following shall constitute Operating Activities hereunder:
1. Monitoring the performance of, and making operating adjustments to, the
Transmission Line, as necessary, in accordance with Prudent Utility Practices and all applicable
reliability standards, as amended from time to time, set forth by NERC and/or WECC or their
successors;
2. Reviewing routine, preventative, outage and maintenance programs, and
coordinating maintenance activities, with Great Basin in respect of the Great Basin Segments;
3. Performing, managing and coordinating technical support as is commercially
reasonable and necessary for the operation of the Transmission Line in the ordinary course;
4. Coordinating schedules of any transmission use of the Transmission Line and all
outages in accordance with Prudent Utility Practice, including NERC e-Tag standards, WECC
scheduling protocols and the business practices of the NVE Parties, and all other applicable
reliability standards;
5. Maintaining ON Line, including work (including all labor, supplies, materials and
equipment) that is reasonably necessary or advisable for the day-to-day inspection, cleaning, or
upkeep of any structure, component, surface, machinery, equipment, fixture or other component
of ON Line (or any portion thereof); and
6. To the extent not already addressed by the existing practices or procedures of the
NVE Parties, creating operating practices and procedures for the following: (i) operating
emergencies; (ii) metering; (iii) scheduling; (iv) losses; (v) inadvertent flows; (vi) curtailment
operations; (vii) delivery and accounting of energy; and (viii) coordinating scheduled uses of
capacity over the Transmission Line.
Schedule 3-1
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 188 of 198

Schedule 4
PRIMARY ON LINE AGREEMENTS
A. Material Construction Contracts
1. Transmission Line Construction Services Agreement dated as of , 2010 by
and between Great Basin Transmission, LLC and [ ]
2. Substation Construction Services Agreement dated as of , 2010 by and
between Great Basin Transmission, LLC and [ ]
3. Agreement for the Purchase and Sale of Equipment dated as of , 2010 by and
between Great Basin Transmission, LLC and Thomas & Betts Corporation for tubular
guyed V transmission towers
4. Agreement for the Purchase and Sale of Equipment dated as of , 2010 by and
between Great Basin Transmission, LLC and Thomas & Betts Corporation for tubular
self supporting transmission towers
5. Agreement for the Purchase and Sale of Equipment dated as of , 2010 by and
between Great Basin Transmission, LLC and SAE Towers for lattice transmission towers
6. Agreement for the Purchase and Sale of Equipment dated as of , 2010 by and
between Great Basin Transmission, LLC and [ ] for transmission line conductor
7. Agreement for the Purchase and Sale of Equipment dated as of , 2010 by and
between Great Basin Transmission, LLC and [ ] for fiber optic ground wire
8. Agreement for the Purchase and Sale of Equipment dated as of , 2010 by and
between Great Basin Transmission, LLC and [ ] for 500/345 kV autotransformers
9. Agreement for the Purchase and Sale of Equipment dated as of , 2010 by and
between Great Basin Transmission, LLC and [ ] for 500 kV power circuit breakers
10. Agreement for the Purchase and Sale of Equipment dated as of , 2010 by and
between Great Basin Transmission, LLC and [ ] for 500 kV shunt reactors
11. Agreement for the Purchase and Sale of Equipment dated as of , 2010 by and
between Great Basin Transmission, LLC and [ ] for 500 kV and 345 kV disconnect
switches
12. Agreement for the Purchase and Sale of Equipment dated as of , 2010 by and
between Great Basin Transmission, LLC and [ ] for 500 kV and 345 kV substation
structural steel
Schedule 4-1
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 189 of 198

13. Agreement for services of Compliance Inspection Contractor(CIC) dated as of
, 2010 by and between Great Basin Transmission, LLC and Tetra Tech EC,
Inc.
14. Agreement for services for Cultural Treatment Services dated as of , 2010 by
and between Great Basin Transmission, LLC and SWCA Environmental Consultants
15. Agreement for services for Environmental and Biological Monitors dated as of
2010 by and between Great Basin Transmission, LLC and HDR, Inc.
16. Agreement for services for Quality Assurance Services dated as of , 2010 by
and between Great Basin Transmission, LLC and [ ]
B. Interconnection Agreements
1. Robinson Summit Transmission Interconnection Agreement dated as of ,
2010 by and among SPPC (in its capacity as the transmission provider), Great Basin
Transmission, LLC, SPPC (in its capacity as an owner of ON Line) and NPC (in its
capacity as owner of ON Line)
2. Harry Allen Transmission Interconnection Agreement dated as of , 2010 by
and among NPC (in its capacity as the transmission provider), Great Basin Transmission,
LLC, SPPC (in its capacity as an owner of ON Line) and NPC (in its capacity as owner
of ON Line)
C. Land Contracts
1. Option to Purchase Easement dated as of April 10, 2006, as amended February 17, 2009,
between Bruce A. and Pamela G. Jensen, on the one hand, and Great Basin Transmission,
LLC, on the other hand
2. Grant of Easement dated as of August 2, 2010,between Bruce A. and Pamela G. Jensen,
on the one hand, and Great Basin Transmission, LLC, on the other hand
3. United States Department of the Interior, Bureau of Land Management, Right-of-Way
Grant Serial No. NVN-85210
D. Other Agreements
Schedule 4-2
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 190 of 198

1. Cost Recovery Agreement for Construction of BLM Right-of-Way Grant NVN-85210
dated as of , 20_, by and between Bureau of Land Management and Great
Basin Transmission, LLC [Note: The existing Cost Recovery Agreement is in the
process of being separated into two agreements, one relating to ON Line and the other
relating to the Great Basin Segments.]
Schedule 4-2
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1
Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 191 of 198

Schedule 5
BUYOUT PRICES
Section 3.07 (Great Basin Abandonment or Delay Buyoutght):
The purchase price for the NVE Parties purchase of Great Basin's Ownership Interests pursuant
to Section 3.07 shall be determined in accordance with the following formula:
(0.706 * (Capitalized Costs funded by Great Basin+ $5,500,000)) + Breakage Costs +
Undepreciated Balance
Section 3.08 (30th Anniversary Buyout Right)
The purchase price for the NVE Parties purchase of Great Basin's Ownership Interests pursuant
to Section 3.08 shall be determined in accordance with the following formula:
(0.766 * (Capitalized Costs funded by Great Basin+ $5,500,000)) +Undepreciated Balance
Section 3.09(a)(41 st Anniversary Buyout Right)
The purchase price for the NVE Parties purchase of Great Basin's Ownership Interests pursuant
to Section 3.09(a) shall be determined in accordance with the following formula:
(0.476 * (Capitalized Costs funded by Great Basin+ $5,500,000)) +Undepreciated Balance
Schedule 5-1
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 192 of 198

Section 3.09(b)(Renewal Right)
In the event the NVE Parties exercise their right to renew all (but not less than all) of each
Party's Capacity Entitlements pursuant to Section 3.09(b), then the following changes shall be
deemed to have been made to this Agreement as of the forty-first(41 st) anniversary of the ON
Line COD (but this Agreement, and all terms and conditions hereof, shall otherwise remain in
full force and effect):
(a) The formula for Capitalized Component set out in Section 3.06 shall be amended and
restated to read in its entirety as follows: "Capitalized Component=(0.476 * (Capitalized
Costs funded by Great Basin+ $5,500,000)) * a factor of 0.00729125".
(b) The portion of Section 3.06(a) that is before the proviso shall be amended and restated as
follows: "Subject to Sections 3.06(b)and Uc),commencing in the month in which the forty-
first (41 st) anniversary of the ON Line COD occurs but terminating in the month during
which the last day of the renewal period established pursuant to Section 3.09(b)occurs(the
"Monthly Payment Period"), a monthly amount in Dollars equal to the following (the
"Monthly Payment") shall be due and payable to Great Basin".
Where (in each applicable case):
Breakage Costs=the aggregate amount of any premiums,penalties, fees and other breakage
costs (in each case, based on the difference between U.S. Treasury interest rates in effect at the
time of any such buyout and Great Basin's interest rate or rates under the ON Line Financing
Agreements) paid or payable by Great Basin to the ON Line Lenders in connection with the early
repayment of the debt portion of any financing provided to Great Basin(or guaranteed)by
Western Area Power Administration or the U.S. Department of Energy;
Undepreciated Balance =the sum of the undepreciated balances for(a) any Incremental Cost
Differential, (b)Net Capital Repair Costs, (c)Net Event of Loss Costs and(d)Net
Condemnation Action Costs, in each case, as funded by Great Basin and determined based on a
straight line depreciation schedule over the applicable amortization periods outlined in this
Agreement.
Schedule 5-2
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 193 of 198

Schedule 6
GOVERNMENTAL APPROVAL STATUS
Note: Governmental Approvals listed here are those provided by GBT, not by NVE or any
contractor, and does not include FERC approval of IA or this TUA.
Permit/Review Authority Description Completion
Date
FEDERAL
NEPA review completed and final July 1993
EIS issued
Record of Decision issued Nov. 1994
ROW grant issued Dec. 1994
EA completed&ROW amendment July 2008
NEPA Review and USDI granted
Right-of-Way Grant Bureau of Land COM Plan approved Mar.2009
Management(BLM)
COM Plan update approved Dec.2009,
Aug.2010
Notice to Proceed with construction Aug.2010
Partial assignment of ROW grant to Upon
NV Energy Acquisition
Closing
May 1993,
Mar. 1994,
Dec.2007,
Endangered Species Act Section 7 US Fish&Wildlife Service Biological Opinions issued
Compliance Amended Jun.
2010,
Jul.2010
Programmatic Agreement signed Feb. 1990
National Historic Preservation Act Historic Properties Inventory Plan Sept.2006
BLM&Nevada SHPO approved
Section 106 Compliance
Class III surveys complete Nov.2006
Cultural inventory report filed May 2007
Schedule 6-1
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 194 of 198

Permit/Review Authority Description Completion
Date
Historic Properties Treatment Plan Dec.2009
(HPTP)Vol. la approval
HPTP Vol. lb approval Mar.2010
HPTP Vol. lc approval Jul.2010
Submitted notifications for all
Determination of No Hazard to Air Federal Aviation project features exceeding 200 feet Jun.2010above ground level
Navigation Administration(FAA)
Determinations issued Jul.2010
Impacts to waters(if any)
Clean Water Act Section 404, U.S.Army Corps of insufficient to trigger Corps Aug.2007
Nationwide Permit No. 12 Engineers notification requirement;permit
coverage is automatic
STATE OF NEVADA
UEPA Permit approved Dec.2008
Utility Environmental Protection Public Utilities Commission
Act(UEPA)—Permit to Construct of Nevada Final permit to construct Expected
Aug.2010
Clean Water Act-Construction Nevada Division of SWPPP complete,NOI and fee
Stormwater Permit (NPDES), Environmental Protection, accepted by NDEP,coverage Apr.2009
including Stormwater Pollution effective under General Permit
Prevention Plan Bureau of Water Pollution NVR100000
Control
Nevada Division of
Environmental Protection, Final Class II Air Quality Operating
Surface Area Disturbance Permit for Surface Area May 2009
Permit/Dust Control Plan Disturbance Permit No.
Bureau of Air Pollution AP 1629-2551 issued
Control
Final permits issued for aerial May.2009,
crossings of US-6 and SR-318 renewed May
2010
Permit for Occupancy of Nevada Nevada Department of
Department of Transportation Transportation Final permits issued for aerial Oct.2009
Right-of-Way crossings of US-93
Permit for Highway 50 access Expected
Aug.2010
LOCAL
White Pine County
Special Use Permit Regional Special Use Permit approved Dec.2008
Planning Commission
Schedule 6-2
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598vl Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 195 of 198

Permit/Review Authority Description Completion
Date
Lincoln County
Special Use Permit Special Use Permit approved Feb.2009
Planning Commission
Clark County Special Use Permit approved Dec.2008
Special Use Permit
Planning Commission Amendment for alignment shifts at Jul.2010
Pardee Homes and Harry Allen
Clark County Department
Dust Control Permit of Air Quality and Dust Control Permit issued Sept.2009
Environmental
Management
* Denotes items that,pursuant to Section 17.02(d)(ii)(A),would not be customarily obtained as of the Acquisition
Closing Date in light of the then-current stage of construction of ON Line and therefore will not necessarily be
obtained by the Acquisition Closing date.
Schedule 6-3
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598vl Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 196 of 198

Schedule 7
GREAT BASIN SEGMENTS
SPECIFICATION DEVIATIONS
It is hereby confirmed that the SWIP-N (Southwest Intertie Project -North) and SNIP (Southern Nevada
Intertie Project) 500kV transmission lines shall be designed to comply with the same parameters and
specification used for the joint transmission line project between NVE and Great Basin Transmission,(i.e.
ON Line/SWIP-S), except as indicated below:
Mechanical Design Criteria
SWIP-N
The SWIP-North line will not have loads for NESC Rule 250B Light condition.
SNIP
The SNIP line will not have loads neither for NESC Rule 250B Medium condition, nor for NESC Rule
250D wind and ice condition.
Electrical Design Criteria
The SNIP and SWIP North lines will be designed to the same electrical performance criteria as the ON
Line/SWIP-S. These are:
• Predicted lightning outage rate of no more than 0.8 insulation failures per 100 mile-years
• Predicted switching surge flashover rate (SSFOR) of no more than one insulation failure per
100 breaker operations
• Minimum clearances as defined in the 2007 edition of the National Electrical Safety Code
(NESC)
• Working clearances that include minimum approach distances calculated in accordance with
IEEE Std 516-2003, IEEE Guide for Maintenance Methods of Energized Power Lines plus
space for line workers in accordance with the requirements of the entity maintaining and
operating the line.
Schedule 7-1
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 197 of 198

ANNEX A
OWNERSHIP PERCENTAGES OF THE PARTIES
Party Ownership Percentage
Great Basin 75%
NPC 18.75%
SPPC 6.25%
100%
Annex A
Second Amended and Restated Transmission Use and Capacity Exchange Agreement
41317598v1 Exhibit No.2
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 198 of 198

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-08
IDAHO POWER COMPANY
ELLSWORTH, DI
TESTIMONY
EXHBIT NO. 3

Capacity Allocations across SWIP-North, SWIP-South, and Total SWIP
North—to—South Capacity South—to—North Capacity Total Capacity Cost
Allocation
Midpoint
7E N
• •
1MWI O , •
z
3 3
o o. MW
rIj
rn
Q NVE Ch MNVE
N :0t
Robinson
Summit
CAISO
••, MW
� N
N
IPL
Min 00 0. MW
a ,� V LA
M
cn ry N
.0 MW
Harry Allen
(CAISO&NVE)
Exhibit No.3
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 1 of 1

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-08
IDAHO POWER COMPANY
ELLSWORTH, DI
TESTIMONY
EXHIBIT NO. 4

Great Basin Transmission, LLC
Southwest Intertie Project (SWIP)
WECC Phase 2 Path Rating Report
Version 0-3, FINAL
June 2023
Prepared by
FFMI,- Utifity System Efficiencies,Inc.
Exhibit No.4
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 1 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Table of Contents
1 EXECUTIVE SUMMARY/ INTRODUCTION .............................................................................................1
2 SWIP PROJECT DESCRIPTION ................................................................................................................4
2.1 Plan of Service...............................................................................................................................4
2.2 Planned In-Service Date................................................................................................................5
2.3 Project Status and Schedule .........................................................................................................5
2.4 SWIP Transmission Network Configuration (Diagrams) ...............................................................5
2.5 Project Contact Information .........................................................................................................7
3 STUDY CONCLUSIONS...........................................................................................................................7
4 GENERAL STUDY DESCRIPTION...........................................................................................................10
4.1 Study Scope and Objective .........................................................................................................10
4.2 Power Flow Analysis....................................................................................................................10
4.3 Voltage Stability/Reactive Margin Analysis ................................................................................11
4.4 Transient Stability Analysis .........................................................................................................12
5 STUDY ASSUMPTIONS.........................................................................................................................13
5.1 Base Case Development..............................................................................................................13
5.2 Transmission System Representation.........................................................................................14
5.2.1 Phase 3 Post-Gateway Base Case Representation..............................................................14
5.3 Generation Assumptions ............................................................................................................16
5.4 New Project System Model.........................................................................................................16
5.5 System Stressing.........................................................................................................................17
6 NON-SIMULTANEOUS STUDY RESULTS...............................................................................................18
6.1 Power Flow Results.....................................................................................................................18
6.1.1 SWIP N2S (25HS) Power Flow Results.................................................................................18
6.1.2 SWIP S2N (25HW) Power Flow Results...............................................................................19
6.2 Voltage Stability/Reactive Margin Results..................................................................................20
6.2.1 SWIP N2S Reactive Margin Summary.................................................................................21
6.2.2 SWIP S2N Reactive Margin Summary.................................................................................21
6.3 Transient Stability Results...........................................................................................................22
6.3.1 SWIP N2S (25HS) Transient Stability Results ......................................................................22
6.3.2 SWIP S2N (25HW)Transient Stability Results.....................................................................23
7 SIMULTANEOUS ANALYSIS RESULTS...................................................................................................24
7.1 SWIPN vs. Path 16 Simultaneous Analysis..................................................................................25
7.1.1 Studied Scenarios................................................................................................................26
Exhibit No.4 Page i
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 2 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
7.1.2 Post-Transient Governor Power Flow Analysis...................................................................27
7.1.3 Voltage Stability/Reactive Margin Analysis ........................................................................29
7.1.4 Transient Stability Analysis .................................................................................................30
7.2 SWIPN vs. Path 18 Simultaneous Analysis..................................................................................30
7.2.1 Studied Scenarios................................................................................................................30
7.2.2 Post-Transient Governor Power Flow Analysis...................................................................30
7.2.3 Voltage Stability/Reactive Margin Analysis ........................................................................31
7.2.4 Transient Stability Analysis .................................................................................................31
7.3 SWIPN vs. Path 19 Simultaneous Analysis..................................................................................31
7.3.1 Studied Scenarios................................................................................................................32
7.3.2 Post-Transient Governor Power Flow Analysis...................................................................32
7.3.3 Voltage Stability/Reactive Margin Analysis ........................................................................33
7.3.4 Transient Stability Analysis .................................................................................................33
7.4 SWIPN vs. Path 32 Simultaneous Analysis..................................................................................34
7.4.1 Studied Scenarios................................................................................................................34
7.4.2 Post-Transient Governor Power Flow Analysis...................................................................35
7.4.3 Voltage Stability/Reactive Margin Analysis ........................................................................37
7.4.4 Transient Stability Analysis .................................................................................................38
7.5 SWIPN vs. Path 66 (and Path 65) Simultaneous Analysis ...........................................................38
7.5.1 Studied Scenarios................................................................................................................39
7.5.2 Post-Transient Governor Power Flow Analysis...................................................................39
7.5.3 Voltage Stability/Reactive Margin Analysis ........................................................................41
7.5.4 Transient Stability Analysis .................................................................................................41
7.6 SWIPN vs. Path 76 Simultaneous Analysis..................................................................................41
7.6.1 Studied Scenarios................................................................................................................42
7.6.2 Post-Transient Governor Power Flow Analysis...................................................................42
7.6.3 Voltage Stability/Reactive Margin Analysis ........................................................................42
7.6.4 Transient Stability Analysis .................................................................................................43
7.7 SWIPN vs. Aeolus South (Post-Gateway) Simultaneous Analysis...............................................43
7.7.1 Studied Scenarios................................................................................................................43
7.7.2 Post-Transient Governor Power Flow Analysis...................................................................44
7.7.3 Voltage Stability/Reactive Margin Analysis ........................................................................45
7.7.4 Transient Stability Analysis .................................................................................................45
7.8 SWIPN vs. Midpoint West (Post-Gateway) Simultaneous Analysis............................................45
7.8.1 Studied Scenarios................................................................................................................46
Exhibit No.4 Page ii
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 3 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
7.8.2 Post-Transient Governor Power Flow Analysis...................................................................47
7.8.3 Voltage Stability/Reactive Margin Analysis ........................................................................47
7.8.4 Transient Stability Analysis .................................................................................................48
7.8.5 Mitigation Analysis and Midpoint Changes ........................................................................48
7.9 SWIPN vs. Path 14+ (Post-Gateway) Simultaneous Analysis......................................................50
7.9.1 Studied Scenarios................................................................................................................50
7.9.2 Post-Transient Governor Power Flow Analysis...................................................................51
7.9.3 Voltage Stability/Reactive Margin Analysis ........................................................................52
7.9.4 Transient Stability Analysis .................................................................................................53
7.9.5 Mitigation Analysis and Midpoint Changes ........................................................................53
7.10 SWIPN vs. Path 17+ (Post-Gateway) Simultaneous Analysis......................................................55
7.10.1 Studied Scenarios................................................................................................................55
7.10.2 Post-Transient Governor Power Flow Analysis...................................................................56
7.10.3 Voltage Stability/Reactive Margin Analysis ........................................................................58
7.10.4 Transient Stability Analysis .................................................................................................58
7.10.5 Mitigation Analysis and Midpoint Changes ........................................................................58
7.11 SWIPN vs. Path 19+ (Post-Gateway) Simultaneous Analysis......................................................60
7.11.1 Studied Scenarios................................................................................................................61
7.11.2 Post-Transient Governor Power Flow Analysis...................................................................62
7.11.3 Voltage Stability/Reactive Margin Analysis ........................................................................63
7.11.4 Transient Stability Analysis .................................................................................................63
7.11.5 Mitigation Analysis and Midpoint Changes ........................................................................63
7.12 SWIPN vs. Path 20+ (Post-Gateway) Simultaneous Analysis......................................................65
7.12.1 Studied Scenarios................................................................................................................66
7.12.2 Post-Transient Governor Power Flow Analysis...................................................................67
7.12.3 Voltage Stability/Reactive Margin Analysis ........................................................................68
7.12.4 Transient Stability Analysis .................................................................................................68
7.12.5 Mitigation Analysis and Midpoint Changes ........................................................................68
7.13 SWIPN vs. TWE HVDC Project Simultaneous Analysis ................................................................70
7.13.1 Studied Scenarios................................................................................................................71
7.13.2 Post-Transient Governor Power Flow Analysis...................................................................71
7.14 SWIPN vs. TWE AC-DC Project Simultaneous Analysis ...............................................................72
7.14.1 Studied Scenarios................................................................................................................72
7.14.2 Post-Transient Governor Power Flow Analysis...................................................................73
7.14.3 Voltage Stability/Reactive Margin Analysis ........................................................................73
Exhibit No.4 Page iii
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 4 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
7.14.4 Transient Stability Analysis .................................................................................................74
7.15 SWIPS vs. Path 24 Simultaneous Analysis...................................................................................74
7.15.1 Studied Scenarios................................................................................................................75
7.15.2 Post-Transient Governor Power Flow Analysis...................................................................76
7.15.3 Voltage Stability/Reactive Margin Analysis ........................................................................76
7.15.4 Transient Stability Analysis .................................................................................................77
7.16 SWIPS vs. Path 32 Simultaneous Analysis...................................................................................77
7.16.1 Studied Scenarios................................................................................................................78
7.16.2 Post-Transient Governor Power Flow Analysis...................................................................79
7.16.3 Voltage Stability/Reactive Margin Analysis ........................................................................82
7.16.4 Transient Stability Analysis .................................................................................................83
7.17 SWIPS vs. Path 35 Simultaneous Analysis...................................................................................83
7.17.1 Studied Scenarios................................................................................................................84
7.17.2 Post-Transient Governor Power Flow Analysis...................................................................85
7.17.3 Voltage Stability/Reactive Margin Analysis ........................................................................87
7.17.4 Transient Stability Analysis .................................................................................................87
7.18 SWIPS vs. Path 78 Simultaneous Analysis...................................................................................88
7.18.1 Studied Scenarios................................................................................................................88
7.18.2 Post-Transient Governor Power Flow Analysis...................................................................89
7.18.3 Voltage Stability/Reactive Margin Analysis ........................................................................91
7.18.4 Transient Stability Analysis .................................................................................................92
7.19 SWIPS vs. Path 79 Simultaneous Analysis...................................................................................92
7.19.1 Studied Scenarios................................................................................................................93
7.19.2 Post-Transient Governor Power Flow Analysis...................................................................94
7.19.3 Voltage Stability/Reactive Margin Analysis ........................................................................96
7.19.4 Transient Stability Analysis .................................................................................................97
7.20 SWIPS vs. TWE HVDC Project Simultaneous Analysis.................................................................97
7.20.1 Studied Scenarios................................................................................................................97
7.20.2 Post-Transient Governor Power Flow Analysis...................................................................98
7.21 SWIPS vs.TWE AC-DC Project Simultaneous Analysis................................................................98
7.21.1 Studied Scenarios................................................................................................................99
7.21.2 Post-Transient Governor Power Flow Analysis.................................................................100
7.21.3 Voltage Stability/Reactive Margin Analysis ......................................................................101
7.21.4 Transient Stability Analysis ...............................................................................................101
8 SENSITIVITY ANALYSIS RESULTS........................................................................................................102
Exhibit No.4 Page iv
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 5 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
8.1 Cross-Tie Transmission Project Sensitivity Analysis..................................................................102
8.2 Lava Ridge Generation Sensitivity Analysis...............................................................................104
APPENDIX A: Power Flow Model Data
APPENDIX B: Contingency List
APPENDIX C: N2S Non-Simultaneous Results
APPENDIX D: S2N Non-Simultaneous Results
APPENDIX N16: SWIPN-Path 16 Simultaneous Results
APPENDIX N18: SWIPN-Path 18 Simultaneous Results
APPENDIX N19: SWIPN-Path 19 Simultaneous Results
APPENDIX N32: SWIPN-Path 32 Simultaneous Results
APPENDIX N66: SWIPN-Paths 66-65 Simultaneous Results
APPENDIX N76: SWIPN-Path 76 Simultaneous Results
APPENDIX NGW AS: SWIPN-Aeolus South Simultaneous Results
APPENDIX NGW MPW: SWIPN-MPW Simultaneous Results
APPENDIX NGW14+: SWIPN-Path 14+Simultaneous Results
APPENDIX NGW17+: SWIPN-Path 17+Simultaneous Results
APPENDIX NGW19+: SWIPN-Path 19+Simultaneous Results
APPENDIX NGW20+: SWIPN-Path 20+Simultaneous Results
APPENDIX NTWE1: SWIPN-TWE1 Simultaneous Results (Placeholder)
APPENDIX NTWE2: SWIPN-TWE2 Simultaneous Results (Placeholder)
APPENDIX S24: SWIPS-Path 24 Simultaneous Results
APPENDIX S32: SWIPS-Path 32 Simultaneous Results
APPENDIX S35: SWIPS-Path 35 Simultaneous Results
APPENDIX S78: SWIPS-Path 78 Simultaneous Results
APPENDIX S79: SWIPS-Path 79 Simultaneous Results
APPENDIX STWE1: SWIPS-TWE1 Simultaneous Results (Placeholder)
APPENDIX STWE2: SWIPS-TWE2 Simultaneous Results (Placeholder)
APPENDIX zNCT: SWIPN-CTTP Sensitivity Results
APPENDIX zNLR: SWIPN-LR Sensitivity Results
APPENDIX ZZ: Approved Study Plan, SWIP Phase 2 Rating
Exhibit No.4 Page v
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 6 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Southwest Intertie Project (SWIP)
WECC Phase 2 Path Rating Report
1 EXECUTIVE SUMMARY/ INTRODUCTION
Great Basin Transmission, LLC1 (GBT) is constructing the Southwest Intertie Project (SWIP). Western
Electricity Coordinating Council (WECC) path ratings are being established for two SWIP components:
SWIP-North (SWIPN) consists of a 500 kV AC transmission circuit,traversing approximately 285
miles from Idaho Power Company's Midpoint 500 kV substation (near Twin Falls, Idaho)to
Robinson Summit 500 kV substation (near Ely, Nevada) operated by NV Energy.
SWIP-South (SWIPS) is an upgraded (70%series compensated)version of the existing 231-mile
Robinson Summit-Harry Allen 500 kV line.The existing uncompensated version of this circuit
(also known as "ON Line") connects Robinson Summit substation to NV Energy's Harry Allen
substation, and was placed into service in January 2014.
SWIPN and SWIPS are expected to be in-service on or before December 31, 2026.
In accordance with the procedures of the WECC Three-Phase Project Rating Review Process,this Phase 2
Path Rating Report has been developed to establish Accepted Rating(s)for the northern and southern
components of the Southwest Intertie Project (SWIPN and SWIPS), in both the north-to-south (N2S) and
south-to-north (S2N) directions.
Table 1 below summarizes the Accepted Ratings determined in this Phase 2 Rating Study.The SWIP
addition and associated Ratings were evaluated using power flow contingency analysis,voltage stability
analysis, and transient stability analysis. Study results demonstrate that the identified Accepted Ratings
meet the NERC and WECC Planning Standards as well as applicable local area reliability criteria. In
addition, the studies did not show any adverse impacts to neighboring transmission systems.
Table 1: SWIPN and SWIPS Proposed Accepted Ratings(Phase 26 Results)
Non- Non-
Simultaneous Simultaneous
North-to-South South-to-North
Rating, MW Rating, MW
SWIP-North (Midpoint*-Robinson Summit 500 kV Line) 2,070 1,920
SWIP-South (Robinson Summit*-Harry Allen 500 kV Line) 2,335 2,245
* Denotes metered end of line.
Great Basin Transmission, LLC is a wholly-owned affiliate of LS Power.
Exhibit No.4 11 Page
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 7 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
The proposed SWIPN and SWIPS non-simultaneous ratings are based upon the following limitations:
SWIPN North-to-South (N2S) maximum flow of 2,070 MW N2S is primarily limited by voltage
performance from the following critical contingencies:
• Category P7-2/ N-2 bipole outage of the Pacific DC Intertie (PDCI)with —2,700 MW Northwest
generation tripping causes the Midpoint-Robinson Summit 500 kV series capacitor line-side bus
("MPRSSC2") to reach 600 kV(design limitation).
• Category P1-1/G-1 outage of a Palo Verde generating unit (-1,380 MW) causes the Midpoint-
Robinson Summit 500 kV series capacitor line-side bus ("MPRSSC2")to reach 600 kV(design
limitation).
• Category P1-2/ N-1 outage of the Robinson Summit-Harry Allen 500 kV line requires automatic
post-contingency adjustment of the Robinson Summit 500 kV shunt capacitor bank and
coordinated tripping of the Robinson Summit 345 kV shunt capacitor to maintain Robinson
Summit 500 kV and 345 kV post-contingency bus voltages within high limits.
SWIPN South-to-North (S2N) maximum flow of 1,920 MW S2N is primarily limited by voltage
performance from the following critical contingencies:
• Category P7-2/ N-2 PDCI bipole outage causes the Midpoint-Robinson Summit 500 kV series
capacitor line-side bus ("MPRSSCI")to reach 600 kV(design limitation).
• Category P1-2/ N-1 outage of the Robinson Summit-Harry Allen 500 kV line requires automatic
post-contingency adjustment of the Robinson Summit 500 kV shunt capacitor bank and
coordinated tripping of the Robinson Summit 345 kV shunt capacitor to maintain Robinson
Summit 500 kV and 345 kV post-contingency bus voltages within high limits.
SWIPS North-to-South (N2S) maximum flow of 2,335 MW N2S is primarily limited by voltage
performance from the following critical contingencies:
• Category P1-2/ N-1 outage of the Midpoint-Robinson Summit 500 kV line results in -7.3%
voltage deviations at select 120 kV busses near NVE/Sierra Pacific's Humboldt bus.
• Category P1-2/ N-1 outage of the Robinson Summit-Harry Allen 500 kV line requires automatic
post-contingency adjustment of the Robinson Summit 500 kV shunt capacitor bank and
coordinated tripping of the Robinson Summit 345 kV shunt capacitor to maintain Robinson
Summit 500 kV and 345 kV post-contingency bus voltages within high limits.
SWIPS South-to-North (S2N) maximum flow of 2,245 MW S2N is primarily limited by voltage
performance from the following critical contingencies:
• Category P1-2/ N-1 outage of the Robinson Summit-Harry Allen 500 kV line requires automatic
post-contingency adjustment of the Robinson Summit 500 kV shunt capacitor bank and
coordinated tripping of the Robinson Summit 345 kV shunt capacitor to maintain Robinson
Summit 500 kV and 345 kV post-contingency bus voltages within high limits.
This SWIP Phase 2 Rating Study performed simultaneous analyses of SWIPN's and SWIPS's bidirectional
ratings with over twenty other existing and future WECC Paths; results of these simultaneous analyses
are discussed later in this report. Paths selected for simultaneous analysis were chosen based upon prior
Path Rating studies/experience, results from the Affected Path Test, and/or per the request of PRG
Exhibit No.4 21 Page
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 8 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
members. Simultaneous interactions (expressed through nomograms)were observed for the following
other transfer paths:
• SWIPN (N2S) versus Path 16 Idaho-Sierra (N2S)
• SWIPN (N2S)versus Path 32 Pavant/Intermountain-Gonder(E2W)
• SWIPN (S2N) versus Path 16 Idaho-Sierra (S2N)
• SWIPN (S2N)versus Path 32 Pavant/Intermountain-Gonder (E2W)
• SWIPN (S2N)versus Post-Gateway Midpoint West Upgrade (E2W)
• SWIPN (S2N)versus Post-Gateway Path 14+ (E2W)
• SWIPN (S2N)versus Post-Gateway Path 17+ Borah West Upgrade (E2W)
• SWIPN (S2N)versus Post-Gateway Path 19+ Bridger/Anticline West (E2W)
• SWIPN (S2N)versus Post-Gateway Path 20+ New Path C (S2N)
• SWIPS (N2S)versus Path 32 Pavant/Intermountain-Gonder(E2W)
• SWIPS (N2S)versus Path 32 Pavant/Intermountain-Gonder(W2E)
• SWIPS (N2S)versus Path 35 TOT 2C Red Butte-Harry Allen (N2S)
• SWIPS (N2S)versus Path 78 TOT 2131 Pinto-Four Corners (N2S)
• SWIPS (N2S)versus Path 79 TOT 2132 Sigurd-Glen Canyon (N2S)
• SWIPS (N2S)versus TransWest Express AC-DC IPP-Crystal Line (N2S)
• SWIPS (S2N)versus Path 32 Pavant/Intermountain-Gonder(E2W)
• SWIPS (S2N)versus Path 35 TOT 2C Red Butte-Harry Allen (S2N)
• SWIPS (S2N)versus Path 78 TOT 2131 Pinto-Four Corners (S2N)
• SWIPS (S2N)versus Path 79 TOT 2132 Sigurd-Glen Canyon (S2N)
These simultaneous nomograms limits are approximate and subject to change.The results are
dependent upon the assumed case topology and modeled generation, which are expected to evolve.
This path rating study has applied a conservative approach where the SWIP study cases generally model
a sparse (2025) condition, absent a number of potential new major transmission and generation projects
expected soon after the construction of SWIP. As such,these nomograms may be a better indicator of
which Paths are expected to exhibit simultaneous interactions with SWIPN or SWIPS, rather than the
actual limits themselves. If operating procedures are to be developed for any of these paths,those
simultaneous relationships should be revisited/verified in the operating horizon, nearer to the time of
energization. Lastly,when viewing an identified simultaneous interaction, readers are encouraged to
also consider the (future)frequency and duration of the portrayed directional scenario (e.g., what is the
likelihood or seasonal condition for the coincident operation of both paths at the flow magnitudes and
directions shown?).
In addition to the various Simultaneous analyses conducted,two Sensitivity analyses were performed:
one testing the impact to SWIPN of adding the Cross-Tie Transmission Project("CTTP",the Clover-
Robinson Summit 500 kV line), and another testing SWIPN S2N flow against Lava Ridge output (wind
generation connecting at Idaho Power's Midpoint 500 kV bus). These Sensitivity analyses are for
informational purposes only: mitigation measures are not required for any identified performance
concerns, and these analyses are not required to complete Phase 2 of the WECC Path Rating Process.
Exhibit No.4 3 1 Page
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 9 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
2 SWIP PROJECT DESCRIPTION
2.1 Plan of Service
The Southwest Intertie Project (SWIP) is comprised of two SWIP components: SWIP-North (SWIPN) and
SWIP-South (SWIPS). SWIPN and SWIPS include the following facilities:
SWIP-North (SWIPN)
• A 500 kV AC transmission circuit approximately 285 miles long, spanning from/near Idaho Power
Company's Midpoint 500 kV substation (near Twin Falls, Idaho) to the Robinson Summit 500 kV
substation (near Ely, Nevada) operated by NV Energy. Each line phase will consist of 3-1590
ACSR Lapwing conductor.
• The Midpoint-Robinson Summit 500 kV line will feature 70%series compensation. Half of this
compensation will be placed at Midpoint Substation, while the other half will be placed at
Robinson Summit Substation.
• The overall Midpoint-Robinson Summit 500 kV circuit (series capacitors+ conductor)will feature
ratings of summer normal/emergency=2593.0/3562.0 MVA(expressed on a 500 kV base
voltage).
• Each end of the line will include two shunt line reactors (one fixed, one switchable for voltage
control): 2 x-122.45 WAR reactors at the Midpoint terminal, and 2 x-122.45 WAR reactors at
the Robinson Summit terminal (MVAR sizes expressed on a 500 kV base voltage).
SWIP-South (SWIPS)
• Add 70%series compensation to the existing Robinson Summit-Harry Allen 500 kV AC
transmission line (also known as "ON Line"z).This series compensation will be evenly distributed
in three (3)segments, with series capacitors placed at Robinson Summit, Harry Allen, and within
the middle third of the circuit.
• The overall Robinson Summit-Harry Allen 500 kV circuit (series capacitors+conductor) will
feature ratings of summer normal/emergency= 2873.0/3464.0 MVA(expressed on a 500 kV
base voltage).
• Addition of three (3) +136 WAR switchable shunt capacitors (500 kV base) located at the
Robinson Summit 500 kV bus.
• Addition of a +150 WAR shunt capacitor added to the Robinson Summit 345 kV bus.
• Addition of two (2) 345/345 kV phase-shifting transformers (+/-48°, each rated 600/672 MVA) at
Robinson Summit: one connected towards Falcon, and the other towards Gonder.
Detailed power flow modeling data (".epc"file format, GE PSLF version 21.0.10.1)for SWIP is provided in
Appendix A.
2 The Robinson Summit-Harry Allen 500 kV line(One Nevada Line,or"ON Line")was placed into service in January 2014.This
231-mile line is constructed of 3-1590 ACSR Lapwing conductor per phase. Each end of this line includes two(2)-90.7 MVAR
shunt line reactors(as measured on a 500 kV base voltage).
Exhibit No.4 41 Page
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 10 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
2.2 Planned In-Service Date
At the writing of this report,the SWIPN and SWIPS components are expected to be in-service on or
before December 31, 2026.
2.3 Project Status and Schedule
Interconnection/System Impact Studies (Complete)
Perform WECC Phase 2 Rating Studies, issue Rating Report 8/2020-4/2023
Rights-of-Way acquisition and permitting (Substantially Complete)
Construction & Commissioning Q1 2025-Q4 2026
Commercial Operation Date 12/31/2026
2.4 SWIP Transmission Network Configuration (Diagrams)
This section provides a geographic map and one-line diagram for SWIPN and SWIPS, showing points of
interconnection, metering points, and facility ownership/control.
Figure 1: Geographic Map,Southwest Intertie Project
Midpomt
Two Faro
•
SWIP-North
Rotmnson U T
Summit Ely
PJ V •
SWIP-South
(ONLine)
Harry Allen
C A lssvegaa• DesertLink
Eld do AZ
Exhibit No.4 5 Page
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 11 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Figure 2: Diagram,SWIPN and SWIPS
BURNS
SUMMER MIDPOINT
E 500/345/230/138kV
Substation (IPC)
M ,�N
MP-RS Shunt Line Reactors * KINPORT
-122.45MVAR each (@ 500kV) A5kV)
SWIP-North: 1
(New)Midpoint-Robinson Summit 500kV Line HUMBOLL
Non-Simultaneous Ratings:
2,070 MW N2S/1,920 MW S2N
(-285 miles) 70%series comp.
Upgrades with SWIP-North:
• 70%Series Comp. on RS-HA Line
ROBINSON Phase-Shifting Xfmrs.at RS
SUMMIT • Shunt Capacitors at Robinson
500/345kV Summit
Substation (NVE)
FALCON 345kV SVD:3 x+136 MVAR
^^• (@ 500kV)
120 kV) (345kV) T T T
SWIP-South: +150 WAR Shunt Cap
y� N N (@ 345kV)
Robinson Summit-Harry Allen 500kV Line
Non-Simultaneous Ratings: R
2,335 MW N2S/2,245 MW S2N 345kV PSTs 3a5k
(-231 miles) 70%series comp.
+/-48°each
RS-HA Shunt Line Reactors
HARRY ALLEN (2301,
-90.7 WAR each(@ 500kV) 500/345/230kV
Substation (NVE)
Harry Allen-Eldorado 500kV Line (HAE) 500kV
Non-Simi.Rating=3,496MW N2S/1,390MW S2N
345kV
(-59 miles)
ELDORADO 500kV
Substation (SCE/CAISO)
Exhibit No.4 6 Page
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 12 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
2.5 Project Contact Information
For more information on the Southwest Intertie Project and/or this Phase 2 Rating Study, contact:
DIWAKAR TEWARI, P.E.
Vice President,Transmission Planning
Great Basin Transmission, LLC
c/o LS Power Development, LLC
[phone]
DTewari@LS Power.com
3 STUDY CONCLUSIONS
The results of this Phase 2 Rating Study support the following conclusions:
• Phase 2 study results show the following new non-simultaneous ratings are achievable with the
facilities identified in the SWIPN and SWIPS Plan of Service:
SWIP-North (Midpoint-Robinson Summit 500 kV Line): 2,070 MW N2S 1,920 MW S2N
SWIP-South (Robinson Summit-Harry Allen 500 kV Line): 2,335 MW N2S 2,245 MW S2N
• At the proposed non-simultaneous ratings/flows, the interconnected system meets the
performance requirements of NERC Standard TPL-001-5 and WECC planning criterion TPL-001-
WECC-CRT-3.2,for applicable outages including (but not necessarily limited to) NERC Planning Event
Categories P0, P1, and P7. Study results show that all facilities remain within their thermal and
voltage limits,the system demonstrates adequate reactive margin, cascading outages do not occur,
and the system remains stable.
• The proposed Accepted Ratings are limited by the following voltage performance concerns:
■ For all four directional ratings, a Category P1-2/N-1 outage of the Robinson Summit-Harry Allen
500 kV line requires automatic post-contingency adjustment of the Robinson Summit 500 kV
shunt capacitor bank and coordinated tripping of the Robinson Summit 345 kV shunt capacitor
to maintain Robinson Summit 500 kV and 345 kV bus voltages within high limits.
■ The SWIPN N2S rating is additionally limited by either a Category P7-2/ N-2 PDCI bipole outage
or a Category P1-1/G-1 outage of a Palo Verde generating unit, which causes the post-
contingency voltage at the Midpoint-Robinson Summit 500 kV series capacitor line-side bus
("MPRSSC2", SWIPN's southern series capacitor)to reach 600 kV(insulation design limitation).
■ The SWIPN S2N rating is additionally limited by a Category P7-2/ N-2 PDCI bipole outage, which
causes the Midpoint-Robinson Summit 500 kV series capacitor line-side bus ("MPRSSCI",
SWIPN's northern series capacitor)to reach 600 kV(insulation design limitation).
■ The SWIPS N2S rating is additionally limited by a Category P1-2/ N-1 outage of the Midpoint-
Robinson Summit 500 kV line,which can result in -7.3%voltage deviations at select 120 kV
busses near NVE/Sierra Pacific's Humboldt 120 kV bus.
Exhibit No.4 71 Page
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
■ The SWIPS S2N is rating is only limited by the previously-described Category P1-2/ N-1 outage
of the Robinson Summit-Harry Allen 500 kV line and resulting voltage at the Robinson Summit
500 kV and 345 kV buses.
• For the studied conditions, no adverse impacts were observed for neighboring transmission systems
or for the WECC interconnected system.
• This SWIP Phase 2 Rating Study performed simultaneous analyses of SWIPN's and SWIPS's
bidirectional ratings with over 20 other existing and future WECC Paths. Paths selected for
simultaneous analysis were chosen based upon prior Path Rating studies/experience,Affected Path
Test results, and/or at the request of PRG members. Detailed discussion for each of these
simultaneous analyses is provided later in this report.The following tables summarize the various
SWIP simultaneous analyses:
Table 2A: SWIPN Simultaneous Analyses
Simultaneous
SWIPN Interaction/
(Existing)WECC Path Name&Direction: Direction Nomogram?
Path 16 Idaho-Sierra (500 N2S) N2S Yes
Path 16 Idaho-Sierra (360 S2N) S2N Yes
Path 18 Montana-Idaho(383 N2S) N2S No
Path 19 Bridger West(2,400 E2W) N2S No
Path 19 Bridger West(2,400 E2W) S2N No
Path 32 Pavant/Intermt.-Gonder(500 E2W) N2S Yes
Path 32 Pavant/Intermt.-Gonder(500 E2W) S2N Yes
Path 65 Pacific DC Intertie(3,220 N2S) N2S No
Path 66 CA-OR Intertie(5,100 N2S) N2S No
Path 66 CA-OR Intertie(3,675 S2N) S2N No
Path 76 Reno-Alturas (300 N2S) N2S No
(Future)WECC Path Name&Direction:
Aeolus South Project(Gateway South) 1,700 N2S N2S No
Midpoint West Upgrade(Post-GWW)4,400 E2W S2N Yes
Path 14+ Idaho-Northwest w/B2H Project 3,400 E2W S2N Yes/No*
Path 14+ Idaho-Northwest w/B2H Project 2,250 W2E N2S No
Path 17+Borah West Upgrade(Post-GWW)4,450 E2W N2S No
Path 17+Borah West Upgrade(Post-GWW)4,450 E2W S2N Yes
Path 19+Bridger/Anticline West(Post-GWW)4,100 E2W N2S No
Path 19+Bridger/Anticline West(Post-GWW)4,100 E2W S2N Yes
Path 20+"New Path C" (Post-GWW)2,250 N2S N2S No
Path 20+"New Path C" (Post-GWW)2,250 S2N S2N Yes
TransWest Express(TWE) Phase 1 HVDC 1,500 N2S N2S No
TransWest Express (TWE)AC-DC,3 segments,all N2S:
TWE WY-IPP HVDC(3,000 N2S) N2S No
-------TWE IPP-Crystal AC(1,500 N2S) ------ ---- N2S----- ---------No---------
------------E IPP-Crys--l AC(1,50--------------------------------------- ---------------- -----------------------
TWE Crystal-NV AC 1,680 N2S N2S No
* For Path 14+, mitigation analysis results show elimination of initially-developed nomogram with the
alternate"Midpoint Changes"topology.
Exhibit No.4 81 Page
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Table 213:SWIPS Simultaneous Analyses
Simultaneous
SWIPS Interaction/
(Existing)WECC Path Name&Direction Direction Nomogram?
Path 24 PG&E-Sierra (150 E2W) N2S No
Path 24 PG&E-Sierra (160 ME) S2N No
Path 32 Pavant/Intermt.-Gonder(500 E2W) N2S Yes
Path 32 Pavant/Intermt.-Gonder(500 E2W) S2N Yes
Path 32 Pavant/Intermt.-Gonder(235 ME) N2S Yes
Path 35 TOT 2C/Red Butte-H.Allen (600 N2S) N2S Yes
Path 35 TOT 2C/Red Butte-H.Allen (580 S2N) S2N Yes
Path 78 TOT 2131/Pinto-Four Corners(647 N2S) N2S Yes
Path 78 TOT 2131/Pinto-Four Corners(700 S2N) S2N Yes
Path 79 TOT 2132/Sigurd-Glen Cyn. (265 N2S) N2S Yes
Path 79 TOT 2132/Sigurd-Glen Cyn. (300 S2N) S2N Yes
(Future)WECC Path Name&Direction
TransWest Express(TWE) Phase 1 HVDC 1,500 N2S N2S No
TransWest Express (TWE)AC-DC,3 segments,all N2S:
------------E---------
TW WY-IPP HVDC----------(3,000 N2S)- Y �-------------- ------------------------------ -----N2S----------- ----------No-------------
TWE IPP-Cr stal AC 1,500 N2S)
N2S Yes
TWE Crystal-NV AC---------------�1,680 N2S)
---------------- -----------------------
N2S No
• The Simultaneous Analyses of SWIPN S2N versus various Post-Gateway West paths (Midpoint West,
14+, 17+, 19+, and 20+) included additional study work exploring the potential flow impacts in the
vicinity of the Midpoint 500 kV bus, resulting from the recently-proposed advancement of the
Midpoint-Cedar Hill and Midpoint-Hemingway#2 500 kV lines (and potential delay of the Cedar Hill-
Hemingway 500 kV line). Results from these mitigation analyses indicate that these "Midpoint
Changes" generally improve the thermal loading performance of the system, including reducing the
normal and contingency loadings of the Midpoint 345/230 kV transformers (a common limiting
element for the SWIPN (S2N) analyses with several Post-Gateway Paths (Midpoint West, 14+, 17+,
19+(E2W); and Path 20+ (S2N)).
• This SWIP Phase 2 Rating Study a Sensitivity analysis of TransCanyon's Cross-Tie Transmission
Project (CTTP), to explore this project's possible effect on SWIPN N2S and S2N flows. CTTP
Sensitivity results imply that coexistence of SWIPN and CTTP could potentially affect these paths'
flowability. However, due to uncertainty in future generation dispatch and timing of transmission
projects under development in this region, these results are subject to change. It is recommended
that any simultaneous relationship between these two paths should be revisited by the relevant
Transmission Operators under the normal operational planning processes closer to the projects' in-
service dates.
Exhibit No.4 91 Page
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 15 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
4 GENERAL STUDY DESCRIPTION
4.1 Study Scope and Objective
The main objective of this Phase 2 Rating Study is to obtain WECC Accepted Ratings for SWIPN (the
Midpoint-Robinson Summit 500 kV Line) and SWIPS (the Robinson Summit-Harry Allen 500 kV Line). On
November 15, 2020 Great Basin Transmission circulated a draft Phase 2 Rating study plan'to the Project
Review Group (PRG) and hosted a conference call to collect input and address comments. After several
rounds of comments and revision,the study plan, non-simultaneous base cases, and first simultaneous
base case were finalized on January 7, 2022, reaffirming these projects' Phase 2B status in the WECC
Path Rating Process.
Power system studies were performed using WECC full-loop power flow cases. Prior to performing
simulations,the power flow cases used in this Phase 2 Rating Study were reviewed and approved by the
PRG participants. All work was performed using General Electric's Positive Sequence Load Flow (GE PSLF)
program,version 21.0.10.1 (or newer).
The Phase 2 Accepted Ratings proposed in this report were evaluated using power flow contingency
analysis,voltage stability analysis, and transient stability analysis.The system's performance was
measured against the NERC Planning Standards, WECC System Performance Criteria and applicable local
reliability criteria.
4.2 Power Flow Analysis
Power flow contingency analysis was applied to the study cases, using post-transient governor power
flow solution techniques.'Where applicable, study results are reported in a "Pre-versus Post-Project"
comparison format,where the Pre-Project cases benchmark the expected performance for the existing
system, prior to the SWIP addition.
The list of contingencies is provided in Appendix B. SWIPN and SWIPS Path Ratings were evaluated for
normal conditions (NERC Planning Event PO), over 400 single-contingency (131) outages, and over 30
multiple element contingency outages.'Table 3 below summarizes the power flow solution options
applied in the analysis.
Table 3. Power Flow Contingency Solution Options
Solution Option Normal Conditions Contingency Analysis
Area Interchange: Enabled Disabled
DC Converter Control Adjustment: Enabled Enabled
Phase Shifting Transformer Adjustment: Enabled Disabled
3 A copy of the SWIP Phase 2 Rating Study Plan is provided in Appendix ZZ of this report.
' For a governor power flow solution,the resulting post-contingency mismatch in generation and load is distributed among the
remaining non-baseload units throughout the Western Interconnection(as opposed to steady-state power flow analysis,
where this mismatch is balanced by a single"swing"generator).
5 The Phase 2 Rating contingency list included-for informational purposes only-16"Extreme Event"multiple element
contingencies.
Exhibit No.4 10 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Solution Option Normal Conditions Contingency Analysis
Switched Shunt Control: Enabled In general,SVD Types 1-4 disabled,and SVD
Types 5, 6, 7 enabled.Selected Types 1-4,
enabled for Areas 18, 64, 65, 22,and 24.6
Transformer Load Tap Adjustment: Enabled Disabled.Transformer regulation enabled as
needed in Areas 18,64.
Generator Governor Blocking: N/A Baseload flag used per WECC practice.
Generator Voltage Remote Control: Base case default Enabled for selected PacifiCorp(Area 65)
generators(Emery Hunter 1-3, Huntington
1-2),and PG&E(Area 30)TransBay Cable DC
terminal units (TBC_POT2 and TBC_PTB2);
otherwise disabled.
The following Areas were monitored for contingency performance: Nevada (18), Sierra Pacific(64),
Northwest(40), Idaho Power(60), Montana (62), PacifiCorp-East (65), Arizona Public Service (14), Salt
River Project (15), Western Area Power Administration Lower Colorado (19), Southern California (24),
Los Angeles Department of Water& Power(26), Pacific Gas& Electric (30), and WAPA Rocky Mountain
(73).
System performance was measured against the NERC Transmission System Planning Performance
Requirements (TPL-001-5),the WECC Criterion for Transmission System Planning Performance (TPL-001-
WECC-CRT-3.2),the CAISO Planning Standards, NV Energy's Reliability Criteria for Transmission System
Planning, and other local reliability criteria (as applicable).
For acceptable thermal loading performance, all transmission line and transformer loadings should be
within normal continuous ratings for normal/all-lines-in-service conditions (NERC Planning Event
Category PO), and likewise within their respective emergency ratings under contingency conditions
(Categories 131-137). Where known, specific voltage performance requirements were applied for buses in
the various monitored areas. Otherwise,this study applied Bulk Electric System (BES) bus voltage limits
of 0.95-1.05 per unit under normal conditions and 0.90-1.10 per unit under contingency conditions.
While the WECC Criterion for Transmission System Planning Performance allows deviations up to 8%for
P1 events,this Phase 2 Rating Study's results tables have reported post-contingency voltage deviations
in excess of 5%.
4.3 Voltage Stability/Reactive Margin Analysis
This Phase 2 Rating Study verified the system's voltage stability/reactive margin performance by
applying the voltage stability criteria outlined in WECC Regional Criterion TPL-001-WECC-CRT-3.2,
Requirement WR 5:
• (WECC WR 5.1) For transfer paths, all P0-P1 events shall demonstrate a positive reactive power
margin at a minimum of 105 percent of transfer path flow.
• (WECC WR 5.2) For transfer paths, all P2-P7 events shall demonstrate a positive reactive power
margin at a minimum of 102.5 percent of transfer path flow.
6 Per NV Energy direction,Static VAR Devices(SVDs)in Nevada(Area 18)and Sierra Pacific(Area 64)were allowed to adjust.
Similar switching of selected PACE(Area 65)shunt reactive devices(St.George,Three Peaks,Red Butte,Pavant,etc.)under
low voltage conditions.Selected Type 4 SVDs in SDG&E and SCE(Areas 22 and 24)were left as switchable shunts/regulating
devices,in order to mimic SCE's proprietary"Centralized Grid Capacitor Control"algorithm(CGCC.p).
Exhibit No.4 111 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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For Post-SWIPN and Post-SWIPS cases with both north-to-south (N2S) and south-to-north (S2N)flow,
voltage stability/reactive margin test cases were developed representing 105%flow levels (achieved by
scaling either load or generation in both the sending and receiving areas). For simplicity and
conservativism, P2-P7 outages in this study were tested against the 105%flow case, even though the
WECC criterion only requires positive reactive margin at 102.5%flow.The field of contingencies was
then re-applied to these test cases: adequate positive reactive margin was demonstrated by converged
power flow contingency solutions.
4.4 Transient Stability Analysis
The transient stability analysis of the non-simultaneous cases studied over 450 outage simulations. Most
of these simulations consisted of transmission line outages, with an initiating fault placed either at one
of the terminal buses. For simplicity and conservativism, nearly all the initiating faults were simulated as
3-phase faults.'All simulations were run for a period of 30 seconds.The dynamic datasets used in this
analysis included "phase 2" composite load model records, which consider air conditioner motor
stalling.
The system's transient stability performance was measured against the transient voltage dip measures
and instability criteria specified in NERC Reliability Standard TPL-001-5 and WECC Regional Criterion TPL-
001-WECC-CRT-3.2, summarized as follows:
• (WECC WR1, 1.3) Following fault clearing,the voltage shall recover to 80%of the pre-
contingency voltage within 20 seconds of the initiating event for all P1 through P7 events,for
each applicable bus serving load.
• (WECC WR1, 1.4) Following fault clearing and voltage recovery above 80%, voltage at each
applicable bus serving load shall neither dip below 70%of pre-contingency voltage for more
than 30 cycles nor remain below 80%of pre-contingency voltage for more than two seconds,for
all P1 through P7 events.
• (WECC WR1, 1.5) For Contingencies without a fault (P2.1 category event),voltage dips at each
applicable bus serving load shall neither dip below 70%of pre-contingency voltage for more
than 30 cycles nor remain below 80%of pre-contingency voltage for more than two seconds.
• (NERC TPL-001-5, R4.1.1) For P1 Planning Events ("N-1", loss of a single element): No generating
unit shall pull out of synchronism.
• (NERC TPL-001-5, R4.1.2) For Planning Events P2-P7: When a generator pulls out of synchronism
in the simulations,the resulting apparent impedance swings shall not result in the tripping of
any Transmission system elements other than the generating unit and its directly-connected
Facilities.
• (NERC TPL-001-5, R4.1.3) For Planning Events P1-P7: Power oscillations shall exhibit acceptable
damping as established by the Planning Coordinator and Transmission Planner.
• (WECC WR1, 1.6)All oscillations that do not show positive damping within 30-seconds after the
start of the studied event shall be deemed unstable. [System damping is assessed visually with
the aid of stability plots. Plotted parameters included Relative Rotor Angle, Bus Voltage, and Bus
Frequency for specific major buses/generators in the immediate study area and neighboring
systems. Positive damping is demonstrated by showing that the amplitude of power angle or
7 NERC TPL-001-5 only requires 3-phase faults for Category P1,P3,and select P6 Planning Events.
Exhibit No.4 12 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
voltage magnitude oscillations (after 30 seconds) is less than the initial post-contingency
amplitude.]
• (WECC WR4) Identify the potential for Cascading or uncontrolled islanding when post-
contingency analysis results in steady-state facility loading that is either in excess of a known
BES facility trip setting, or exceeds 125%of the highest seasonal facility rating for the BES facility
studied.
• (WECC WR4) Identify the potential for Cascading or uncontrolled islanding when transient
stability voltage response occurs at any applicable (BES) bus outside of the criteria stated in
Requirement WR1.3 (applies to Planning Events P1-P7: "Following fault clearing, the voltage
shall recover to 80%of the pre-contingency voltage within 20 seconds...").
• (WECC WR4) Identify the potential for Cascading or uncontrolled islanding when either
unrestrained successive load loss occurs or unrestrained successive generation loss occurs. Such
events are considered as unrestrained and successive when the loss of load/generation is
observed beyond the immediate study area. Generators are considered to trip/lose synchronism
when the generator's relative rotor angle exceeds 180 degrees. Generators being disconnected
from the System by fault clearing action or by a Remedial Action Scheme (RAS) are not
considered to be pulling out of synchronism.
5 STUDY ASSUMPTIONS
5.1 Base Case Development
WECC full-loop power flow cases were selected for modeling maximized SWIPN and SWIPS flows, and
were further developed to model the current expected system topology for the Year 2025 (the earliest
possible in-service date for the Project at the time Phase 2 studies commenced).This Phase 2 Rating
Study used available WECC power flow cases as a starting point;these cases were further updated,
reviewed, and approved by the SWIP PRG prior to performing simulations.
2025 Heavy Summer North-to-South (25HS N2S) Base Case. For determining the maximum SWIPN
and SWIPS north-to-south (N2S) ratings, a 2025 Heavy Summer case (25HS)was developed from the
WECC power flow case, "26HS2a.sav", approved and posted on the WECC website on July 30, 2020.
This case was regressed to represent 2025 system topology conditions.Three study cases were
developed: a Pre-Project case, a Post-SWIPN case (with maximized N2S flow on Midpoint-Robinson
Summit), and a Post-SWIPS case (with maximized N2S flow on Robinson Summit-Harry Allen).
2025 Heavy Winter South-to-North (25HW S2N) Base Case. For determining the maximum SWIPN
and SWIPS south-to-north (S2N) ratings, a 2025 Heavy Winter case (25HW)was developed from the
WECC 2025-26 Heavy Winter power flow case, "25HW2a1.sav", approved and posted on the WECC
website on July 8, 2020.This case was adjusted as needed to represent 2025 system topology
conditions.Three study cases were developed: a Pre-Project case, a Post-SWIPN case (with
maximized S2N flow on Midpoint-Robinson Summit), and a Post-SWIPS case (with maximized S2N
flow on Robinson Summit-Harry Allen).
Exhibit No.4 13 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
5.2 Transmission System Representation
Various updates were applied to the source base cases to create the SWIP Phase 2 Rating study cases.
These changes included applying WECC-identified base case modifications and adding or removing
planned future transmission projects as needed to align with the current expected 2025 system
topology. Notable major updates included (but were not necessarily limited to)the following changes:
• Restored Phase-Shifting Transformers (PSTs) along the Arizona-Utah border in the power flow
case as "Type 14"transformers (originally set as Type 11/fixed).This included PSTs at San
Juan/Waterflow, Gladstone, Shiprock, Pinto, Sigurd, and Glen Canyon.
• Restored/reactivated (as "Type 4"transformers) Sierra Pacific's Bordertown 345 kV PST, and
Northwestern Energy's Mill Creek 230 kV PST.
• Updated/corrected the modeling for LS Power's Dynamic Reactive Support STATCOM
installations at the new Fern Road 500 kV substation (connected to PG&E's Round Mountain-
Table Mountain 500 kV lines) and at Orchard 500 kV substation (connecting to PG&E's Gates
500 kV bus).
• Updated normal and emergency ratings for the Intermountain 345/230 kV transformer and the
Intermountain-Gonder 230 kV line (summer normal/emergency= 300.0/351.0 MVA).
• Revised modeling for LADWP's McCullough-Victorville 500 kV#1 and#2 500 kV lines to reflect
LADWP's planned upgrade of these series capacitors (changing to two segments of 25%+45%, or
70%total compensation, each line);this upgrade is currently expected by December 2024.
• Updated the modeling and ratings for the Harry Allen-Eldorado 500 kV line.
• Removed modeling of SCE's Alberhill 500/115 kV substation, restoring the Valley-Serrano 500 kV
line; the in-service date for this project is expected to be >2025.
• Verified and updated the ratings for the Populus-Borah and Populus-Kinport 345 kV lines and
series capacitors.
• Per guidance from PacifiCorp-East (PACE), revised/updated the modeling of various Gateway
South and Gateway West facilities to align with current topology expected for 2025.These
updates included (but were not limited to) modeling of shunt capacitors and reactors at Aeolus,
Anticline, and Clover substations; removal of series compensation in the Aeolus-Anticline 500 kV
line; removal of the Anticline-Populus 500 kV line; removal of the Populus-Cedar Hill-
Hemingway, Midpoint-Cedar Hill, Borah-Populus, and Populus-Midpoint 500kV lines; updating
the modeling of the Anticline 345 kV phase-shifting transformers.
• For the 25HW case (only), reversed the directional flow for the Pacific DC Intertie (PDCI)to
model south-to-north flows.
5.2.1 Phase 3 Post-Gateway Base Case Representation
A number of the planned simultaneous studies involved future Paths resulting from PacifiCorp's
development of the Energy Gateway Projects. Additional modeling of a "Post-Gateway"topology was
required for SWIPN simultaneous studies with the following (WECC Phase 3) Paths:
• Aeolus South Project (Gateway South) 1,700 N2S
• Midpoint West Upgrade (Post-Gateway West/GWW)4,400 E2W
• Path 14+ Idaho-Northwest w/B2H Project 3,400 E2W/2,250 W2E
• Path 17+ Borah West Upgrade (Post-GWW)4,450 E2W/4,100 E2W
Exhibit No.4 14 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
• Path 19+ Bridger/Anticline West (Post-GWW) 4,100 E2W
• Path 20+ "New Path C" (Post-GWW) 2,250 N2S/ 2,250 S2N
For these simultaneous analyses, Great Basin Transmission coordinated with PacifiCorp and Idaho Power
Company to model the latest planned future facilities for PacifiCorp's Gateway West and Gateway South
"Stage 1" Projects', as well as Idaho Power Company's Boardman-to-Hemingway(132H) Project. These
facilities were added to SWIPN non-simultaneous base cases (2025 Heavy Summer and 2025 Heavy
Winter), as a starting point for performing the identified SWIPN simultaneous analyses.
The following table summarizes the various facilities either added or modified in creating the SWIPN
"Phase 3 Post-Gateway" simultaneous cases:
Table 4.Additional Facilities Modeled for Phase 3 Post-Gateway Simultaneous Cases
* ` Facility Addition/Modification
Gateway West
1 Update Windstar-Shirley Basin 230 kV Line
2 Update Aeolus-Freezeout 230 kV Line
3 Update Dave Johnson-Amasa-Heyward-Shirley Basin 230 kV Line
4 Update Static VAR Device (SVD) reactors at Aeolus 230 kV
5 Update SVD capacitors at Aeolus 500 kV
6 Add 50%series compensation to Aeolus-Anticline 500 kV Line
7 Update SVD capacitors at Anticline 500 kV
8 Update Anticline 500/345 kV Transformer
9 Update Bridger 345/230 kV Transformers
10 Add fourth phase-shifting transformer(PST) at Anticline 345 kV
11 Update Anticline-Bridger 345 kV Line
12 Add Anticline-Populus 500 kV Line (50%series compensation)
13 Add one 2000 MVA 500/345 kV Transformer at Populus
14 Add Populus-Borah 500 kV Line
15 Add Borah-Midpoint 500 kV Line [Loop-in Kinport-Midpoint 345 kV Line to Borah.
Convert Borah-Midpoint Line from 345 kV to 500 kV.]
16 Add one 1500 MVA 500/345 kV Transformer at Borah
17 Add Populus-Cedar Hill 500 kV Line (45%series compensation)
18 Add Cedar Hill-Hemingway 500 kV Line (45%series compensation)
Gateway South
19 Update Aeolus-Clover 500 kV Line
20 Update SVD capacitors at Clover 500 kV
21 Update SVD reactors at Clover 345 kV
Gateway Central
22 Update Oquirrh-Terminal 345 kV Lines
The facilities considered/included in Gateway"Stage 1"has changed over time.At the time of coordination for this SWIP
path rating study,elements such as the Midpoint-Hemingway#2 500 kV Line and Midpoint-Cedar Hill 500 kV Line were
considered to be"Stage 2"facilities.
Exhibit No.4 15 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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# Facility Addition/Modification
Boardman-to-Hemingway(1132H)
23 Add Hemingway-Longhorn 500 kV Line (-50%series comp, split equally at each end)
24 Add Hemingway-Bowmont 230 kV Line#2
25 Add Bowmont-Hubbard 230 kV Line
26 Update Midpoint 500/345 kV Transformer
27 Add second Midpoint 500/345 kV Transformer
28 Update Midpoint-Hemingway 500 kV Series Capacitor
29 Update Burns 500 kV Series Capacitor
Other Additions/Modifications
30 Add 1000 MW generator to Aeolus 230 kV
31 Add 800 MW generator to Windstar 230 kV
32 Update Latham SVC
33 Decommission Klamath River generation
5.3 Generation Assumptions
In the 25HS and 25HW study cases, the following generation additions and retirements were applied:
• San Juan units 1 and 4 were retired (approximate net output of 330 MW and 500 MW
respectively,Area 10).
• Diablo Canyon unit 1 (approximate net output of 1140 MW, Area 30)was retired.
• Naughton unit 3 modeling parameters changed from coal to gas (new net output"200 MW,
Area 65)
• Added new renewable resources in Area 73 (WAPA Rocky Mountain):Axial (145 MW), Dolores
(110 MW), Niyol (200 MW), Coyote (120 MW).
• For the Post-SWIP cases, added Magic Valley Energy's' Lava Ridge wind generation project
(-1,100 MW total, Area 60), connecting to Idaho Power's Midpoint 500 kV bus.
5.4 New Project System Model
Modeling for the Southwest Intertie Project was added to the Post-Project cases. Detailed power flow
modeling data (".epc" file format, GE PSLF version 21.0.10.1)for SWIP is provided in Appendix A. SWIP
modeling included the following elements:
• A new Midpoint-Robinson Summit 500 kV AC transmission circuit approximately 285 miles long,
with 70%total series compensation (half placed at Midpoint, half placed at Robinson Summit).
Each end of the line will include two shunt line reactors (one fixed, one switchable for voltage
control): 2 x-122.45 MVAR reactors at the Midpoint terminal, and 2 x-122.45 MVAR reactors at
the Robinson Summit terminal (MVAR sizes expressed on a 500 kV base voltage).
9 Magic Valley Energy,LLC is an affiliate of LS Power.
Exhibit No.4 16 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
• 70%total series compensation added to the existing Robinson Summit-Harry Allen 500 kV AC
transmission line (also known as "ON Line").This series compensation is distributed in three (3)
segments, with series capacitors placed at Robinson Summit, Harry Allen, and within the middle
third of the circuit.
• Addition of three (3) +136 MVAR switchable shunt capacitors (500 kV base) located at the
Robinson Summit 500 kV bus, and addition of a+150 MVAR shunt capacitor at the Robinson
Summit 345 kV bus.
• Addition of two (2) 345/345 kV phase-shifting transformers (+/-48°, each rated 600/672 MVA) at
Robinson Summit: one connected towards Falcon, and the other towards Gonder.
5.5 System Stressing
The following section summarizes the stressing applied to the SWIPN and SWIPS N2S and S2N cases.
Appendices C and D provide representative power flow diagrams for both the Pre-Project and resulting
Post-SWIP cases, as well as summary tables of these cases'Area and Interface tables.
2025 Heavy Summer North-to-South (25HS N2S) Base Cases. Maximized non-simultaneous north-to-
south flows for SWIPN and SWIPS were achieved by increasing generation output and exports from
PacifiCorp-East(Area 65) and dispatching—1100 MW of generation output from the newly-added Lava
Ridge wind resource in Idaho (Area 60).This power was then exported/scheduled to southern and
neighboring receiving Areas with decreased generation such as SRP (15), WAPA L.C. (19), Nevada (18),
San Diego (22),Southern California (24), PG&E (30), Northwest(40) and Sierra Pacific (64).
The Robinson Summit 345 kV Phase-Shifting Transformers (PSTs) at were also used to support
maximized N2S flows on SWIPN and SWIPS. The following table summarizes these PSTs' assumed
settings for each of the Post-SWIP N2S (25HS) cases:
Table SA. Robinson Summit PST Settings,SWIPN and SWIPS N2S Cases
Post-SWIPN N2S Case Post-SWIPS N2S Case
SWIPN Flow (N2S): 2,070 MW 1,760 MW
SWIPS Flow (N2S): 1,870 MW 2,335 MW
Robinson-Falcon PST: +205.9 MW (30.00) -309.1 MW (-9.00)
Robinson-Gonder PST: -100.9 MW (35.0°) -334.4 MW(-2.0°)
2025 Heavy Winter South-to-North (25HW S2N) Base Cases. Maximized non-simultaneous south-to-
north flows for SWIPN and SWIPS were achieved by increasing generation output and exports in Areas
such as APS(14), SRP (15), WAPA L.C. (19), Nevada (18), Southern California (24), and LADWP (26).This
power was then exported/scheduled to northern/receiving Areas with decreased generation such as
Northwest (40), Idaho (60), Montana (62), and PacifiCorp-East (65). Lava Ridge wind generation is
assumed off-line for these S2N non-simultaneous cases.
The Robinson Summit 345 kV Phase-Shifting Transformers (PSTs) at were also used to support
maximized S2N flows on SWIPN and SWIPS.The following table summarizes these PSTs' assumed
settings for each of the Post-SWIP S2N (25HW) cases:
Exhibit No.4 17 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Table 513. Robinson Summit PST Settings,SWIPN and SWIPS S2N Cases
Post-SWIPN S2N Case Post-SWIPS S2N Case
SWIPN Flow (S2N): -1,920 MW -1,620 MW
SWIPS Flow (S2N): -1,984 MW -2,245 MW
Robinson-Falcon PST: -11.2 MW (-41.0°) +312.9 MW (-1.00)
Robinson-Gonder PST: -15.2 MW (-21.0°) +248.4 MW (+17.00)
6 NON-SIMULTANEOUS STUDY RESULTS
6.1 Power Flow Results
Power flow contingency analysis was applied to the 2025 Heavy Summer/north-to-south (25HS N2S)
case and the 2025 Heavy Winter/south-to-north (25HW S2N) case,for both the Pre-Project and Post-
SWIP conditions.The list of applied contingencies is provided in Appendix B.Tables of power flow
results are provided in Appendices C and D.
6.1.1 SWIP N2S(25HS) Power Flow Results
Appendix C,Tables C-3 and C-4 provide the thermal loading and voltage results observed for the Pre-
Project and Post-SWIP N2S 25HS non-simultaneous rating cases.The N2S results show the following:
• No applicable BES transmission element was loaded above 100%of its continuous rating under
normal (all-lines-in-service) conditions, for both the Pre-Project, Post-SWIPN, and Post-SWIPS
N2S cases. Likewise for normal conditions, all WECC Path flows were within their non-
simultaneous ratings.
• The Pre-Project N2S case exhibits several contingency thermal limitations. For Category P1-2
("N-1") outages of either of PG&E's Round Mountain-RM_DRS ("Fern Road")#1 or#2 500 kV
lines, a Remedial Action Scheme (RAS) is assumed to bypass the series capacitor in the surviving
parallel circuit to reduce loadings within 100%of its 3280.5 Amp summer emergency rating.
Additionally, a Category P1-2 outage of NV Energy's Arden-Tolson 230 kV line loads the Tolson
230/138 kV transformer to 99.5%of its 382 MVA emergency rating. All these contingency
loading concerns are reduced in the Post-SWIPN and Post-SWIPS N2S cases.
• High post-contingency loadings were observed for PACE'S Frannie-Pryor Mountain 230 kV line.
The worst observed contingency loading occurred in the Pre-Project case for a Category P1-2
outage of either of the Broadview-Townsend-Garrison 500 kV lines#1 or#2, resulting in 100.6%
loading of the Frannie-Pryor Mountain's 800.8 Amp (4-hour) summer emergency rating.
However,this loading is still within this line's short-term 30-minute emergency rating (77.5%of
1039.1 Amps).These contingency loading concerns are reduced in the Post-SWIPN and Post-
SWIPS N2S cases, and are regarded as a localized concern not associated with the SWIP Project.
• In both the Post-SWIPN and Post-SWIPS N2S cases, a Category P1-2 outage of either of PACE'S
Bridger-Populus#1 or#2 345 kV lines resulted in high post-contingency loading for Bridger-
Three Mile Knoll 345 kV line and surviving Bridger-Populus 345 kV line (100.4-104.7%of these
lines' 4-hour summer emergency ratings of 1600 and 1650 Amps, respectively). However,these
loadings are still within these lines' short-term 30-minute summer emergency ratings (1900 and
1991 Amps).
Exhibit No.4 18 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
• For either SWIPN or SWIPS N2S rated flow,the SWIP Project did not introduce any new Category
PO/normal voltage concerns, nor did it significantly worsen any pre-existing normal voltage
issues.
• Results indicate that the Post-SWIPN and Post-SWIPS N2S non-simultaneous rating cases are
limited by the following post-contingency voltage concerns:
❑ For both the Post-SWIPN and Post-SWIPS N2S cases, a Category P1-2/ N-1 outage of the
Robinson Summit-Harry Allen 500 kV line requires automatic post-contingency adjustment
of the Robinson Summit 500 kV shunt capacitor bank and coordinated tripping of the
Robinson Summit 345 kV shunt capacitor to maintain Robinson Summit 500 kV and 345 kV
bus voltages within high limits.
❑ The SWIPN N2S rating is additionally limited by either a Category P7-2/ N-2 PDCI bipole
outage or a Category P1-1/G-1 outage of a Palo Verde generating unit, which causes the
post-contingency voltage at one of the Midpoint-Robinson Summit 500 kV series capacitor
line-side buses("MPRSSC2", SWIPN's southern series capacitor)to reach 600 kV(insulation
design limitation).
❑ The SWIPS N2S rating is additionally limited by a Category 131-2/ N-1 outage of the
Midpoint-Robinson Summit 500 kV line, which can result in -7.3%voltage deviations at
select 120 kV busses near NVE/Sierra Pacific's Humboldt bus.
• For the Post-SWIPN and Post-SWIPS cases, a P1-2 outage of Idaho Power's Midpoint-Hemingway
500 kV line (including automatic bypassing of the Burns 500 kV series capacitor) leaves the
Hemingway 500 kV bus radialized with a high post-contingency voltage approaching this bus'
high voltage limit of 1.124 per unit. This high post-contingency voltage is largely due to the
Hemingway 500 kV shunt capacitor(+200 MVAR @ 500 kV base), and can be corrected by post-
contingency actions to switch off this device.This performance is regarded as a localized
concern not associated with the SWIP Project.
• For the sake of completeness,the N2S voltage results table identifies other post-contingency
conditions where bus voltage performance met or exceeded the applicable criteria.These
additional voltage results are regarded as localized pre-existing high/low voltage conditions,
which occur in the Pre-Project case (and/or the originating WECC 26HS2a source case). Because
this performance is improved/unchanged in the Post-Project cases, these issues are not
regarded as a SWIP impact.
6.1.2 SWIP S2N (25HW) Power Flow Results
Appendix D,Tables D-3 and D-4 provide the thermal loading and voltage results observed for the Pre-
Project and Post-SWIP S2N non-simultaneous rating cases.The S2N results show the following:
• No applicable BES transmission element was loaded above 100%of its continuous rating under
normal (all-lines-in-service) conditions, for both the Pre-Project, Post-SWIPN, and Post-SWIPS
S2N non-simultaneous cases. Likewise for normal conditions, all WECC Path flows were within
their non-simultaneous ratings.
• In the S2N Pre-Project case only, a Category 131-2 outage of either the Valmy-Coyote Creek or
Valmy-Falcon 345 kV line (Sierra Pacific, Area 64) resulted in 108-117%emergency loading of the
Falcon-Water Tap-Bell 120 kV circuit. (This loading is not observed in the Post-SWIP S2N cases.)
These thermal loading concerns are mitigated by the Falcon 345/120 kV transformer RAS;
Exhibit No.4 19 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
however, Pre-Project results also indicate possible high post-contingency voltages in the
underlying(non-BES) 63 kV system following the RAS operation.
• In both the Pre-Project and Post-SWIP S2N cases, a Category 131-2 outage of SCE's Mohave-
Eldorado 500 kV line resulted in 101-104% loading of NV Energy's Kidwell-Searchlight-Gas
Pipeline 69 kV circuit.These thermal loading concerns are mitigated by the Laughlin RAS.
• In both the Pre-Project and Post-SWIP S2N cases, Category 131-2 outage of the Klamath Falls-
Meridian 500 kV line resulted in 110-138%emergency loadings for several PACW 230 kV
facilities in the Klamath Falls vicinity, and low voltages/negative voltage deviations on the
underlying 69-115 kV system. Similar but lesser loading concerns are observed for 131-2 outages
of either the Captain Jack-Snow Goose or Snow Goose-Klamath Falls 500 kV lines.To mitigate
these concerns, PACW has implemented an operational plan to open the Snow Goose
500/230 kV transformer when these contingency loading concerns are detected and is currently
developing additional high voltage reinforcements for their southern Oregon system.These
issues are regarded as an existing local area concern associated with high S2N flow on Path 66
COI, and unrelated to the SWIP Project.
• For either SWIPN or SWIPS S2N rated flow,the SWIP Project did not introduce any new Category
PO/normal voltage concerns, nor did it significantly worsen any pre-existing normal voltage
issues.
• Results indicate that the Post-SWIPN and Post-SWIPS S2N non-simultaneous rating cases are
limited by the following post-contingency voltage concerns:
❑ For both the Post-SWIPN and Post-SWIPS S2N cases, a Category 131-2/ N-1 outage of the
Robinson Summit-Harry Allen 500 kV line requires automatic post-contingency adjustment
of the Robinson Summit 500 kV shunt capacitor bank and coordinated tripping of the
Robinson Summit 345 kV shunt capacitor to maintain Robinson Summit 500 kV and 345 kV
bus voltages within high limits.
❑ In the Post-SWIPN S2N case, a Category P2-3 breaker failure outage of Midpoint CB 544A
(opening the Midoint-Hemingway 500 kV line and Midpoint 500/345 kV transformer) causes
the Robinson Summit 500 kV and 345 kV bus voltages to approach their high limits.
❑ The SWIPN S2N rating is additionally limited by a Category P7-2/ N-2 PDCI bipole outage,
which causes the post-contingency voltage at one of the Midpoint-Robinson Summit 500 kV
series capacitor line-side buses ("MPRSSCI", SWIPN's northern series capacitor)to approach
600 kV(insulation design limitation).
• For the sake of completeness, the S2N voltage results table identifies other post-contingency
conditions where bus voltage performance met or exceeded the applicable criteria.These
additional voltage results are regarded as localized pre-existing high/low voltage conditions,
which occur in the Pre-Project case (and/or the originating WECC 25-26HW2a source case).
Because this performance is improved/unchanged in the Post-Project cases, these issues are not
regarded as a SWIP impact.
6.2 Voltage Stability/Reactive Margin Results
Voltage stability/reactive margin performance was tested for the SWIP non-simultaneous ratings by
applying the WECC voltage stability criteria (previously discussed in Section 4.3). Post-SWIP reactive
Exhibit No.4 20 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
margin test cases were developed modeling flows at 105% of the proposed N2S and S2N ratings. (For
simplicity and conservativism, P2-P7 outages in this study were tested against the 105%flow case, even
though the WECC criterion only requires positive reactive margin at 102.5%flow.)All applied
contingencies demonstrated converged power flow solutions/adequate positive reactive margin.
6.2.1 SWIP N2S Reactive Margin Summary
For the Post-SWIPN N2S condition, a voltage stability test case was developed by scaling load in both the
sending and receiving areas to achieve 105%SWIPN N2S path flow. For the SWIPN N2S 25HS 105%case,
load was reduced in Northwest (Area 40), Idaho (Area 60), and Sierra Pacific (Area 64) by a combined
total of 326 MW;the resulting 326 MW surplus of generation was then scheduled/exported to the
following receiving Areas with a corresponding total of increased load:APS (14), SRP (15),TEPC(16),
AEPCO (17), WAPA L.C. (19), IID (21), and SDG&E (22).The Robinson Summit 345 kV PSTs were not
adjusted for this scaling.The resulting SWIPN N2S flow increased from 2,070 MW to 2,176 MW (+5.1%).
For the Post-SWIPS N2S condition, a similar approach was applied to construct a 105% N2S case by
decreasing loads in Northwest(40), Idaho (60), and Sierra Pacific (64) by a combined 405 MW and
scheduling/exporting the surplus generation to the previously-identified receiving Areas with increased
loads.The Robinson Summit 345 kV PSTs were not adjusted for this scaling. SWIPS N2S flow increased
from 2,335 MW to 2,454 MW (+5.1%).
The battery of over 400 applicable P1-P7 outages were applied to the new 105%cases. All simulated
contingencies achieved a converged power flow solution (Appendix C,Table C-5), demonstrating
adequate reactive margin performance.
6.2.2 SWIP S2N Reactive Margin Summary
For the Post-SWIPN S2N condition, a voltage stability test case was developed by scaling load in both the
sending and receiving areas to achieve 105%SWIPN S2N path flow. For the SWIPN S2N 25HW 105%
case, load was decreased by a combined total of 500 MW in the following sending Areas: APS (14), SRP
(15),TEPC(16),AEPCO (17), WAPA L.C. (19), IID (21), and SDG&E (22).The resulting 500 MW surplus of
generation was then scheduled/exported to the following receiving Areas with a corresponding total of
increased load: Northwest(40), Idaho (60), and Sierra Pacific (64).The Robinson Summit 345 kV PSTs
were not adjusted for this scaling. The resulting SWIPN S2N flow increased from -1,920 MW to
2,016 MW (+5.0%).
For the Post-SWIPS S2N condition, a similar approach was applied to construct a 105%S2N case by
decreasing loads by a combined 477 MW in the same sending Areas (APS (14), SRP (15),TEPC(16),
AEPCO (17), WAPA L.C. (19), IID (21), and SDG&E (22)).The resulting surplus of generation was then
scheduled/exported to serve increased load in Northwest (40), Idaho (60), and Sierra Pacific (64). The
Robinson Summit 345 kV PSTs were not adjusted for this scaling. SWIPS S2N flow increased
from -2,245 MW to-2,357 MW(+5.0%).
The battery of over 400 applicable P1-P7 outages were applied to the new 105%cases. All simulated
contingencies achieved a converged power flow solution (Appendix D,Table D-5), demonstrating
adequate reactive margin performance.
Exhibit No.4 211 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
6.3 Transient Stability Results
As described in Section 5.4 and identified in the contingency list provided in Appendix B,this Phase 2
Rating Study verified the system's Post-SWIP transient stability performance for rated flows in both the
N2S and S2N directions.The transient stability analysis studied over 430 outage simulations, run for 30
seconds. For simplicity and conservativism, nearly all initiating faults were simulated as 3-phase bus
faults.All work was performed using General Electric's Positive Sequence Load Flow(GE PSLF) program,
version 21.0.10.1.The performance of simulated contingencies was measured against the NERC and
WECC transient stability performance criteria.
6.3.1 SWIP N2S(25HS)Transient Stability Results
For the Pre-Project, Post-SWIPN, and Post-SWIPS 25HS N2S cases, no transient stability limitations were
observed: all applicable simulated contingencies met or exceeded the transient stability performance
criteria outlined in Section 4.4. (All monitored bus voltages met the voltage dip and recovery
performance criteria, no generating units pulled out of synchronism for P1 Planning Events, all power
oscillations exhibited positive damping, etc.)Appendix C,Table C-6 ("Worst Condition Analysis Results")
summarizes the Pre-and Post-SWIP N2S cases'transient stability performance. In addition, Appendix C,
Figures C4-C11 provide selected transient stability plots for the 131-2 outage of the Robinson Summit-
Harry Allen 500 kV line, as applied to Post-SWIPN and Post-SWIPS N2S cases. (Additional transient
stability simulation plots are available upon request.)
In the Pre-Project and Post-SWIP N2S cases, several notable transient stability actions were observed
which are not associated with the SWIP Project. For the sake of completeness,these added observations
are briefly discussed below.
• "Duration 80%" FIDVR Observations. In Appendix C,Table C-6, one of the performance attributes
shown for each stability simulation is "Duration 80%": these columns identify the number of buses
>_100 kV which potentially met the following measure: "Following fault clearing and voltage recovery
above 80 percent,voltage at each applicable BES bus serving load shall... not remain below 80
percent of pre-contingency voltage for more than two seconds,for all P1 through P7 events." (WECC
Standard TPL-001-WECC-CRT-3.2, Requirement R1.4). Further review showed these busses to be
barely and/or briefly reaching 80%of the pre-contingency voltage for 1-2 time steps after fault
clearing,followed by Fault-Induced Delayed Voltage Recovery(FIDVR) lasting 2 or more seconds.
This behavior is not regarded as a WECC criteria violation, but rather as a modeling/data issue
associated with the combination of 3-phase bus faults, heavy summer peak load levels, and the
inclusion of Phase 2 composite load models (featuring air conditioner stalling). Observations of this
FIDVR behavior are summarized as follows:
- Nevada "Duration 80%" Bus Voltages. For several Category P1 stability outages in Nevada (Area
18), post-contingency voltages at various Nevada buses reached 80%of the pre-contingency
voltage for 1-2 time steps,then sagged slightly below 80%while undergoing slow voltage
recovery(>2 seconds).This FIDVR behavior originates at underlying 12.5 kV distribution load
buses and 10 kV composite load buses, but ultimately propagates up to various NV Energy
138 kV buses including but not limited to: #18365 PROCYON,#18693 RILEY, #18052 LEAVITT,
#18672 SPARTA,#18609 LONEMTN,#18110 TENAYA,#18114 VEGAS,#18651 REDROCK, and
#18117 WESTSIDE. In the Post-SWIP N2S cases, improved or similar recovery behavior was
observed at these and/or adjacent buses(including#18671 RAILRD,#18720 MYS,#18684
VILAGEI9,#18069 HUALPAI,#18075 LORENZI, and #18625 BELTWAY).
Exhibit No.4 22 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
- Sierra Pacific"Duration 80%" Bus Voltages. For up to twelve (12) Category P1 stability outages
in Sierra Pacific (Area 64), post-contingency voltages at several 115 kV load-serving buses
exhibited a FIDVR response, primarily at Sierra Pacific's#64049 KINGS RV and#64051
MCDERMIT_SS 115 kV buses. For Post-SWIP N2S conditions, performance at these buses is
either unchanged, improved, or alternately observed at other adjacent 115 kV buses such as
#64210 OROVDA+,#64212 QUINN RV, and/or#64211 BOTTLE_CRK+.
- Idaho"Duration 80%" Bus Voltages. For fifteen (15) Category P1 and three P7 stability outages
in Idaho (Area 60), several Idaho 138kV load-serving buses exhibited a FIDVR response including
(but not limited to): #61239 GOWEN,#61842 CART,#61261 MORA,#61270 SIMPLOT, #61721
MIDROSE,#61712 KUNA,#61212 BUTLER,#61718 ECKERT,#60040 BOISEBCH,#60257
HAPPYVLY. In the Post-SWIP N2S cases,this FIDVR behavior is either improved or similarly
observed at these and/or other nearby buses such as#61708 JOPLIN or#61716 BNLT. Similar
observations were noted in the Post-SWIP cases at#60817 GROUSE_CR#, #61714 VLVU, and
#60140 EMMETT 138 kV buses.
- PacifiCorp-East"Duration 80%" Bus Voltages. For twenty-three (23) Category P1 stability
outages in PACE (Area 65), post-contingency FIDVR response was observed at various PACE
138 kV load-serving buses such as#67463 COZYDALE,#66310 RIVERDAL,#66461 SWEBER,
#65772 HILLFLD,#67052 BURTONL,#65499 E BENCH,#65505 EL MONTE, #67302 PIONEER. For
the Post-SWIP condition,this performance is either improved and/or alternately observed at
adjacent buses.
• "Generator Angle>360°"Observations. N2S stability results shown in Appendix C,Table C-6 also
provide metrics for"Angle 360":these columns identify the number of synchronous generators
whose relative rotor angle exceeded 360' for the simulated outage. Review of these incidents found
the vast majority to be units which were removed from service either as part of the contingency
definition or an associated generator-tripping Remedial Action Scheme (RAS). Additionally,for a
handful of selected P1 outages, four(4) synchronous generators in the Nevada (Area 18) and Sierra
Pacific(Area 64) systems were observed to trip off-line due to low/high voltage ride-through (Ihvrt)
relay models. Sierra Pacific units exhibiting this behavior were: #64931 TUNGSTEN P1,#64105
CAITHNES, and#18276 NCA2A units "B" and "C".These instances are viewed as a localized concerns
with these units' Ihvrt modeling, and are not regarded as a relative rotor angle/loss of synchronism
issue, nor as a SWIP-associated impact.
6.3.2 SWIP S2N (25HW)Transient Stability Results
For the Pre-Project, Post-SWIPN, and Post-SWIPS 25HW S2N cases, no transient stability limitations
were observed: all applicable simulated contingencies met or exceeded the transient stability
performance criteria outlined in Section 4.4. (All monitored bus voltages met the voltage dip and
recovery performance criteria, no generating units pulled out of synchronism for P1 Planning Events, all
power oscillations exhibited positive damping, etc.)Appendix D,Table D-6 ("Worst Condition Analysis
Results") summarizes the Pre-and Post-SWIP S2N cases'transient stability performance. In addition,
Appendix D, Figures D4-D11 provide selected transient stability plots for the P1-2 outage of the
Robinson Summit-Harry Allen 500 kV line, as applied to Post-SWIPN and Post-SWIPS S2N cases.
(Additional transient stability simulation plots are available upon request.)
Exhibit No.4 23 ( P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
7 SIMULTANEOUS ANALYSIS RESULTS
This SWIP Phase 2 Rating Study analyzed a number of other existing and future-planned WECC Paths for
potential simultaneous interactions. (Please see Section 3,Tables 2A and 2B for a summary of the paths
studied for simultaneous interaction.) Paths selected for simultaneous analysis were chosen based upon
results from the Affected Path Test, prior Path Rating studies/experience, and/or per the request of PRG
members.This section provides a detailed discussion for each of these simultaneous analyses,while
tabular results are provided in the associated Appendices.
It should be noted that these simultaneous power flow cases and results were proactively shared and
developed with the pertinent path owners/participants over the course of this path rating study.
Through those discussions, some changes in simultaneous studies were realized from what had
originally been outlined in the SWIP Phase 2 Rating Study Plan. In some cases, planned simultaneous
studies or specific directional scenarios were either modified or not performed/completed. For
completeness,these changes are summarized here:
• Path 24(PG&E-Sierra)simultaneous studies were originally planned for SWIPN. However,
during development of the power flow cases SWIPS flows appeared to show a stronger
interaction/sensitivity with Path 24;therefore this simultaneous study was recast as a SWIPS-
Path 24 simultaneous study.
• Planned simultaneous studies between Path 17 Borah West (E2W) and SWIPN (N2S and S2N)
were suspended. In May/June 2022, Idaho Power announced plans to invest in additional near-
term network upgrades for Path 17 that would require rerating this path. (These network
upgrades included addition of the Midpoint-Kinport 345 kV series capacitor, addition of a
second Midpoint 500/230 kV transformer by Summer 2026, plus upgrades/adjustments to the
Midpoint-Hemingway 500 kV series compensation). Due to the impact of these planned changes
and their near-coincidental timing with SWIP's planned in-service date, Idaho Power and GBT
agreed to withdraw the SWIPN simultaneous analysis with the existing Path 17, and instead
include these new network upgrades when performing the SWIPN simultaneous analysis with
the (Post-Gateway) Borah West Upgrade path ("17+"),
• Simultaneous studies for Path 14 Idaho-Northwest (E2W, W2E) and SWIPN (N2S, S2N)were
initiated, but quickly encountered difficulties. Due to case stressing limitations for select
directional scenarios and the rapidly changing planned system configuration/topology in the
immediate area, GBT and Idaho Power agreed to suspend this study effort and instead focus on
the simultaneous analysis of future planned Path 14 configuration with the Boardman-
Hemingway 500 kV(132H) Project ("14+").
• During the development of a number of the study cases, it was realized that certain
simultaneous directional scenarios (originally identified in the SWIP path rating study plan) were
either unachievable, and/or represented unlikely coexistent flow conditions.These improbable
scenarios were identified and discussed with the pertinent path owners/participants, and
subsequently withdrawn from the study.The following directional scenarios were not analyzed:
SWIPN (N2S) vs. Midpoint West (E2W); SWIPN (N2S)vs. Path 14+ (E2W); SWIPN (S2N)vs. Path
14+(W2E).
Exhibit No.4 24 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
For instances where this study identified simultaneous interactions between SWIPN or SWIPS and
another path, these limitations have been quantified/expressed through a hypothetical planning
nomogram.These simultaneous nomograms limits are approximate and subject to change.The results
are dependent upon the assumed case topology10 and modeled generation, which are expected to
evolve.This path rating study has applied a conservative approach where the SWIP study cases generally
model a sparse (2025) condition, absent a number of potential new major transmission and generation
projects expected soon after the construction of SWIP.As such,these nomograms may be a better
indicator of which Paths are expected to exhibit simultaneous interactions with SWIPN or SWIPS, rather
than the actual limits themselves. If operating procedures are to be developed for any of these paths,
those simultaneous relationships should be revisited/verified nearer to the time of energization. Lastly,
when viewing an identified simultaneous interaction, readers are encouraged to also consider the
(future)frequency and duration of the portrayed directional scenario (e.g., what is the likelihood or
seasonal condition for the coincident operation of both paths at the flow magnitudes and directions
shown?).
7.1 SWIPN vs. Path 16 Simultaneous Analysis
This study included a simultaneous analysis between SWIPN and Path 16, "Idaho-Sierra". Path 16 has an
Accepted Rating of 500 MW North-to-South (N2S), and 360 MW South-to-North (S2N). Path 16 consists
of the following branch:
0 Midpoint-(RGSS-IDAHO-NV-)Humboldt 345 kV circuit (metered at the Idaho-Nevada border)
Power flow cases were developed with SWIPN and Path 16 stressed to their maximum ratings to identify
any impact/simultaneous interaction between these two paths. Post-transient governor power flow
(thermal and voltage),transient stability, and reactive margin analyses were performed to complete this
assessment. Details of the analyses performed are provided in the following sections.
10 An exception would be the"Post-Gateway'cases used for analysis of the Energy Gateway and B2H projects'paths. Even so,
these base cases so not represent several other significant potential future projects(unless stated otherwise),such as
TransWest Express,Cross-Tie Transmission Project,and/or NV Energy's Greenlink West or Greenlink North.
Exhibit No.4 25 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
This simultaneous analysis attempted to evaluate the following conditions for Path 16:
• Path 16=500 MW (N2S),with SWIPN = 2,070 MW (N2S)flow
• Path 16=360 MW (S2N),with SWIPN = 1,920 MW (S2N) flow
For Path 16 and SWIPN at maximized flows (both N2S and S2N), simultaneous interactions/limitations
were observed: the analysis shows that Path 16 and SWIPN cannot simultaneously achieve their
maximum/rated capabilities.These path limitations have been expressed through hypothetical planning
nomograms;further discussion is provided below in the "Post-Transient Governor Power Flow Analysis"
subsections.
For the N2S condition simultaneous power flow cases were developed with SWIPN and Path 16
separately held at their N2S rating while the alternate path's flow was maximized. Likewise for the S2N
condition, simultaneous cases were developed with SWIPN and Path 16 each separately held at their
S2N rating, while attempting to maximize the alternate path's flow. Pre-Project versions of these cases
were also developed to help establish the system's benchmark performance prior to the SWIP addition.
Over 25 relevant/critical contingencies for these paths were applied and evaluated through post-
transient governor power flow(thermal and voltage) analysis, transient stability analysis, and reactive
margin analysis.Appendix N16 provides the list of applied contingencies, as well as detailed tabular
results from these analyses.
7.1.1 Studied Scenarios
The following scenarios were studied to identify any impact/simultaneous interaction between SWIPN
and Path 16.
• SWIPN N2S and Path 16 N2S
Using the non-simultaneous 2025 Heavy Summer N2S Pre-Project base case, a Pre-SWIP case was
developed modeling Path 16 flow of 500 MW N2S.Two Post-SWIP simultaneous cases were also
developed: one modeling SWIPN flow at 2,070 MW N2S (with restricted/limited Path 16 N2S flow),
and another modeling Path 16 flow of 500 MW N2S (with restricted/limited SWIPN N2S flow). N2S
stressing for SWIPN and Path 16 was achieved in part through schedule changes for the Robinson
Summit-Falcon 345 kV phase-shifting transformer (PST), and to a lesser extent, adjustment of the
Robinson Summit-Gonder 345 kV PST. Flows were further stressed and tuned by redispatching
generation and adjusting imports/exports between Nevada (Area 18), Sierra Pacific (Area 64), Idaho
(Area 60), and Northwest (Area 40).
• SWIPN S2N and Path 16 S2N
Using the non-simultaneous 2025 Heavy Winter S2N base cases, Pre-and Post-SWIP cases were
developed modeling Path 16 at 360 MW S2N.Two Post-SWIP simultaneous cases were developed:
one modeling SWIPN flow at 1,920 MW S2N (with restricted/limited Path 16 S2N flow), and another
modeling Path 16 flow of 360 MW S2N (with restricted/limited SWIPN S2N flow). S2N stressing for
SWIPN and Path 16 was partially achieved through schedule changes for the Robinson Summit-
Falcon 345 kV phase-shifting transformer(PST), and to a lesser extent, adjustment of the Robinson
Summit-Gonder 345 kV PST. Flows were further stressed and tuned by redispatching generation and
adjusting imports/exports from several Arizona Areas (14, 15, 16, 19) and Sierra Pacific (Area 64),
Exhibit No.4 26 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 32 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
offset by similar adjustments in Idaho (Area 60), PacifiCorp-East(Area 65), Montana (62). Additional
interchange adjustments were applied between Northwest(Area 40) and Southern California (Area
24), plus a small reduction in the Bordertown 345 kV PST schedule.
7.1.2 Post-Transient Governor Power Flow Analysis
Please see Appendix N16 for this simultaneous analysis' list of applied contingencies and tabular results.
All of the identified contingencies were applied for post-transient governor power flow analysis of both
the Pre-and Post-SWIP simultaneous cases. Pre-Project cases were analyzed to establish a baseline
performance and/or confirm Path 16's limiting factor(s). Results for the Post-SWIPN cases indicate a
simultaneous relationship between Path 16 and SWIPN: these two paths cannot simultaneously achieve
their maximum/rated N2S or S2N capabilities.
7.1.2.1 SWIPN N2S and Path 16 N2S
For SWIPN N2S versus Path 16 N2S, a simultaneous interaction is expected between these two
paths.This limitation can be expressed through a hypothetical planning nomogram with two corner
points:
• Path 16=—410 MW N2S, and SWIPN = 2070 MW N2S (rated flow)
• Path 16= 500 MW N2S (rated flow), SWIPN =—1,450 MW N2S
SWIP-North N2S vs.Path 16 N2S
2200
2000
410,2070
1800 [Max SWIPN N2S]
1600
3 1400
500/1451
3 1200 [Max Path 16 N2S]
0
LL
N 1000
Z
Z
a 800
3
600
400
200
0
0 50 100 150 200 250 300 350 400 450 500 550
Path 16 N25 Flow(MW)
Power flow contingency analysis shows both these points to be limited by a Category 131-2 ("N-1")
outage of the Midpoint-Robinson 500 kV line, resulting low voltage and negative deviations
Exhibit No.4 27 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
(approaching-8%) at NV Energy/Sierra Pacific's Queenstake, Big Spring,Jerritt, and Humboltl
120 kV buses.
7.1.2.2 SWIPN S2N and Path 16 S2N
For SWIPN S2N versus Path 16 S2N, a simultaneous interaction/limit is expected.This limitation can
be expressed through a hypothetical planning nomogram with three corner points:
• Path 16= 178 MW S2N, SWIPN = 1,920 MW S2N (rated flow). With SWIPN at rated S2N flow
and Path 16 flows up to—178 MW S2N, power flow contingency results show the case to be
limited by a Category P1-2 outage of the Midpoint-RGSS/Jackpot Solar 345 kV line, causing
the post-contingency voltage at one of the Midpoint-Robinson Summit 500 kV series
capacitor line-side buses ("MPRSSCI", SWIPN's northern series capacitor)to approach 600 kV
(insulation design limitation). Also at this case stress level, an N-1 of NV Energy/Sierra
Pacific's Valmy-Coyote Creek 345 kV line causes the Falcon-Water Tap 120 kV line section to
reach 100%of its summer emergency rating, without any further assumed RAS actions.
• Path 16= "178+" MW S2N,SWIPN = 1,890 MW S2N. For Path 16 S2N flows increased
>178 MW,the N-1 Valmy-Coyote Creek 345 kV line outage is expected to overload the
Falcon-Water Tap 120 kV line; this overload is mitigated by the Falcon 345/120 kV
Transformer Remedial Action Scheme (RAS), which trips both Falcon banks and causes flows
to redistribute on the surviving system.The resulting post-RAS increase in S2N flow on the
Midpoint-Robinson Summit 500 kV line requires SWIPN pre-contingency flow to be limited to
<_1,890 MW S2N to keep the series capacitor line-side bus ("MPRSSCI") within its 600 kV
limit.
• Path 16=360 MW S2N (rated flow), and SWIPN = 1,790 MW S2N. For Path 16 increased to
its rated flow of 360 MW S2N, SWIPN is limited to 1,790 MW S2N to keep the series capacitor
line-side bus ("MPRSSCI")within its 600 kV limit for the N-1 Valmy-Coyote Creek outage
(including the associated Falcon Transformer RAS).
Exhibit No.4 28 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
SWIP-North S2N vs. Path 16 S2N
2000
1800 2a:178,1920
[Max SW IPN S2N]
1:360,1790 7
1600 [Max Path 16 S2N]
2b:178+,1890
[w/Falcon RAS]
1400
1200
3
° 1000
LL
Z
N
LA
z 800
a_
600
400
200
0
0 50 100 150 200 250 300 350 400
Path 16 S2N Flow(MW)
7.1.3 Voltage Stability/Reactive Margin Analysis
For the voltage stability/reactive margin analysis,the nomogram corner point cases were further
modified by increasing both SWIPN's and Path 16's path flows by+5%for the "P1 Test" (testing Category
P1 outages for a converged solution). As a conservative approach, additional Category P2-P7 outages
(normally tested against a 2.5%increase in Path flow)were also applied to these 5% increase cases.The
table below summarizes the modeled flows on SWIPN and Path 16 for each of these scenarios.
Summary of SWIPN vs. Path 16 Reactive Margin Cases
Rating Nomo. +5% Increase Nomo. +5% Increase
Path (MW) Case 1 (P1-P7 outages applied) Case 2 (P1-P7 outages applied)
SWIPN N2S (HS case) 2,070 2,070 2,179 (+5.3%) 1,450 1,526 (+5.2%)
Path 16 N2S 500 410 432 (+5.3%) 500 531 (+6.3%)
SWIPN S2.N (HW case) -1,920 -1,920 -2,021 (+5.3%) -1,790 -11883 (+5.2%)
--------------- ---- ............ .......................... ....................................
Path 16 S2N -360 -178 -196 (+10.4%) 1 -360 1 -386 (+7.4%)
All of the listed contingencies were applied to these increased flow cases and achieved post-contingency
convergence, indicating adequate reactive margin for the system.
Exhibit No.4 29 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
7.1.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPN-Path 16 N2S and
SWIPN-Path 16 S2N simultaneous cases. Stability performance of these cases was essentially unchanged
as compared to the SWIP non-simultaneous cases: no new or worsened transient stability performance
concerns were observed.
7.2 SWIPN vs. Path 18 Simultaneous Analysis
This study included a simultaneous analysis between SWIPN and Path 18, "Montana-Idaho". Path 18 has
an Accepted Rating of 383 MW North-to-South (N2S) and 256 MW South-to-North (S2N), established in
2012 via a WECC Phase 2 Path Rating process. Path 18 consists of the following branches (asterisk
denotes metered end):
• Dillon Salmon-Big Grassy* 161 kV Line
• Peterson Flats-AMPS* 230 kV
This simultaneous analysis evaluated the following conditions for Path 18 Montana-Idaho:
• Path 18=383 MW(N2S),with SWIPN = 2,070 MW(N2S)flow
For Path 18 (N2S) and SWIPN (N2S) at maximized flows, no simultaneous limitations were observed:the
analysis shows that Path 18 and SWIPN can simultaneously achieve their maximum/rated capabilities.
Power flow cases were developed with SWIPN and Path 18 stressed to their maximum ratings to identify
any impact/simultaneous interaction between SWIPN and Path 18. Over 35 relevant/critical
contingencies for these paths were applied and evaluated through post-transient governor power flow
(thermal and voltage) analysis, transient stability analysis, and reactive margin analysis.Appendix N18
provides the list of applied contingencies, as well as detailed tabular results from these analyses.
7.2.1 Studied Scenarios
The following scenarios were studied to identify any impact/simultaneous interaction between SWIPN
and Path 18.
• SWIPN N2S Transfers and Path 18(Montana-Idaho) N2S Transfers
Using the non-simultaneous 2025 Heavy Summer North-to-South (N2S) base cases, Pre-and Post-
SWIP cases were developed with Path 18 at 383 MW N2S. SWIPN was modeled at 2,070 MW N2S in
the Post-Project case. Flows on Path 18 were achieved mainly by adjusting the Mill Creek-Peterson
Flats 230 kV Phase Shifting Transformer(PST) and Big Grassy-Jefferson 161 kV PST settings to push
additional flow in the N2S direction. N2S flow on SWIPN was maintained by adjusting the schedule
between Nevada (Area 18) and Idaho (Area 60).
7.2.2 Post-Transient Governor Power Flow Analysis
Please see Appendix N18 for this simultaneous analysis' list of applied contingencies and tabular results.
All of the identified contingencies were applied for post-transient governor power flow analysis of both
the Pre-and Post-SWIP simultaneous cases.
Exhibit No.4 30 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
No simultaneous limitation was observed: results indicate that both SWIPN and Path 18 can
simultaneously achieve their rated flows.The Pre-Project case (2025 Heavy Summer)was evaluated for
its contingency performance. For outages of either a Palo Verde generating unit (Category P1-1),the
Dillion Salmon-Big Grassy 161 kV line (Category P1-2), or the Big Grassy-Jefferson 161 kV Phase-Shifting
Transformer(Category P1-3), post-contingency loading of the Mill Creek-Peterson Flats 230 kV PST
reaches 100-102%of its emergency rating. For a single line outage of the Peterson-Amps-Antelope
230 kV circuit, post contingency voltages of 1.12-1.14 pu are observed at the PETERSON 230 kV buses.
In the Post-SWIP cases, no new applicable thermal overload or voltage performance concerns were
observed:the Post-SWIP cases' performance was either unchanged or improved with the SWIP addition.
7.2.3 Voltage Stability/Reactive Margin Analysis
For the SWIPN-Path 18 simultaneous cases, all simulated contingencies achieved a converged post-
transient governor power flow solution (at their applicable increased flow levels), demonstrating
adequate reactive margin performance.
For simplicity/conservativism, P1 and P2-P7 outages were tested against a reactive margin case with
SWIPN and Montana-Idaho simultaneously increased by 5%.The table below summarizes the SWIPN
and Montana-Idaho flows for the developed reactive margin case.
Summary of SWIPN vs. Path 18 Reactive Margin Cases
+5%Increase
Path Rating(MW) (P1-P7 outages applied)
SWIPN N2S (HS case) 2,070 2,175 (+5.1%)
Path 18 (Montana-Idaho) N2S 383 408 (+6.5%)
7.2.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPN-Path 18
simultaneous cases. Stability performance of these cases was essentially unchanged as compared to the
SWIP non-simultaneous cases: no new or worsened transient stability performance concerns were
observed.
7.3 SWIPN vs. Path 19 Simultaneous Analysis
This study included a simultaneous analysis between SWIPN and Path 19, "Bridger West". Path 19 has an
Accepted Rating of 2,400 MW East-to-West (E2W)11, established in 2011 via a joint study completed by
Idaho Power Company and PacifiCorp.
Path 19 Bridger West consists of the following branches (asterisk denotes metered end):
• Jim Bridger*-Threemile Knoll 345 kV Line
• Jim Bridger*-Populus 345 kV Line#1
Path 19 also has an"Other Rating"of 1,250 MW West-to-East established following NERC MOD-029-1a R2.2 requirements.
This rating was not considered as part of this simultaneous analysis.
Exhibit No.4 311 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
• Jim Bridger*-Populus 345 kV Line#2
This simultaneous analysis evaluated the following conditions for Path 19 Bridger West:
• Path 19= 2,400 MW(E2W), with SWIPN = 2,070 MW(N2S)flow
• Path 19 =2,400 MW (E2W), with SWIPN = 1,920 MW(S2N)flow
For Path 19 (E2W) and SWIPN (N2S or S2N) at maximized flows, no simultaneous limitations were
observed: the analysis shows that Path 19 and SWIPN can simultaneously achieve their maximum/rated
capabilities.
Power flow cases were developed with SWIPN and Path 19 stressed to their maximum ratings to identify
any impact/simultaneous interaction between SWIPN and Bridger West. Over 30 relevant/critical
contingencies for these paths were applied and evaluated through post-transient governor power flow
(thermal and voltage) analysis, transient stability analysis, and reactive margin analysis.Appendix N19
provides the list of applied contingencies, as well as detailed tabular results from these analyses.
7.3.1 Studied Scenarios
The following scenarios were studied to identify any impact/simultaneous interaction between SWIPN
and Bridger West.
• SWIPN N2S and Path 19(Bridger West) E2W
Using the non-simultaneous 2025 Heavy Summer North-to-South (N2S) base cases, Pre-and Post-
SWIP cases were developed with Path 19 Bridger West at 2,400 MW E2W. SWIPN was modeled at
2,070 MW N2S in the Post-Project case. Flows on Bridger West were achieved mainly by increasing
generation at Jim Bridger and adjusting the schedule between PACE (Area 65) and the Northwest
(Area 40). N2S flows on SWIPN were maintained by adjusting the schedule between Nevada (Area
18) and Idaho (Area 60).
• SWIPN S2N and Path 19 E2W
Using the non-simultaneous 2025 Heavy Winter S2N base cases, Pre-and Post-SWIP cases were
developed with Bridger West at 2,400 MW E2W. SWIPN was modeled at 1,920 MW S2N in the Post-
Project case. Flows on Bridger West were achieved mainly by increasing generation at Jim Bridger
and other generation facilities in Wyoming, adjusting the phase shifting transformers at Anticline
345 kV, and adjusting the schedule between PACE (Area 65),WAPA R.M. (Area 73), and Northwest
(Area 40). S2N flows on SWIPN were maintained by adjusting the Robinson Summit and Bordertown
345 kV phase shifting transformers.
7.3.2 Post-Transient Governor Power Flow Analysis
Please see Appendix N19 for this simultaneous analysis' list of applied contingencies and tabular results.
All of the identified contingencies were applied for post-transient governor power flow analysis of both
the Pre-and Post-SWIP simultaneous cases.
The Pre-SWIP cases (both Heavy Summer and Heavy Winter)were evaluated for their contingency
performance and found to be within acceptable criteria/limits. For single line outages (Category P1-2) of
Exhibit No.4 32 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
either the Bridger-Three Mile Knoll, Bridger-Populus#1, or Bridger Populus#2 345 kV lines, post-
contingency loading of the surviving lines is within these circuits' 30-minute emergency ratings. For the
common corridor double-line outage of the Bridger-Populus#1 and#2 345 kV lines, application of the
Bridger Remedial Action Scheme (RAS)12 is needed to manage the post-contingency loading of the
Bridger-Three Mile Knoll 345 kV line.
In the Post-SWIP cases, no new applicable thermal overload or voltage performance concerns were
observed:the Post-SWIP cases' performance was either unchanged or improved with the SWIP addition.
7.3.3 Voltage Stability/Reactive Margin Analysis
For the SWIPN-Path 19 simultaneous cases, all simulated contingencies achieved a converged post-
transient governor power flow solution (at their applicable increased flow levels), demonstrating
adequate reactive margin performance.
For simplicity/conservativism, P1 and P2-P7 outages were initially tested against reactive margin cases
with SWIPN and Bridger West flows simultaneously increased by 5%. If/where applicable, an added
"2.5%" reactive margin case was developed to re-test any P2-P7 outages which did not converge for the
+5%case.The table below summarizes the SWIPN and Bridger West flows for the developed reactive
margin cases.
Summary of SWIPN vs. Path 19 Reactive Margin Cases
P1 Test P2-P7 Test
Path Rating(MW) (5%increase) (2.5%increase)
SWIPN N2S (HS case) 2,070 2,175 (+5.1%) --
Path 19 (Bridger West) 2,400 2,533 (+5.5%) --
SWIPN S2N (HW case) 1,920 -2,027.1 (+5.6%) -1,986.4 (+3.5%)
---------------------------- --------------------------------- -------------- -o ......
Path 19 (Bridger West) 2,400 2,534.4 (+5.6/) 2,472.3 (+3.0/)
In the S2N case only,the P2-3 breaker failure outage of Midpoint CB 544A diverged for the+5%case;
however this outage was re-applied to and converged for the (applicable) +2.5%case.
7.3.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPN-Path 19
simultaneous cases. Stability performance of these cases was essentially unchanged as compared to the
SWIP non-simultaneous cases: no new or worsened transient stability performance concerns were
observed.
12 When simulating this double line outage,the Bridger RAS was initially simulated by tripping Bridger Unit 4,TB Flats 1 and 2,
and High Plains wind generation(1,113 MW generation tripping in the Heavy Summer case,and 756.5 MW in the Heavy
Winter case). Per the Bridger RAS logic,additional tripping of Bridger Unit 3(545-560 MW)was required in all cases to
provide an effective amount of Bridger generation tripping.
Exhibit No.4 33 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
7.4 SWIPN vs. Path 32 Simultaneous Analysis
This study included a simultaneous analysis between SWIPN and Path 32, "Pavant-Gonder 230 kV;
Intermountain-Gonder 230 W'. (Likewise, a simultaneous analysis was conducted between SWIPS and
Path 32; this is discussed in a later section.) Path 32 has an Accepted Rating of 500 MW East-to-West
(E2W) and 235 MW West-to-East(W2E). Path 32 consists of the following branches:
• Osceola-(UTAH-NEV*-)Black Rock 230 kV (metered at the Nevada-Utah border)
• Gonder*-Intermountain 230 kV Line
Power flow cases were developed attempting to stress both SWIPN and Path 32 to their maximum
ratings to identify any impact/simultaneous interaction between these two paths. Post-transient
governor power flow(thermal and voltage),transient stability, and reactive margin analyses were
performed to complete this assessment. Details of the analyses performed are provided in the following
sections.
This simultaneous analysis attempted to evaluate the following directional scenarios with Path 32:
• Path 32 =500 MW (E2W), with SWIPN = 2,070 MW (N2S) flow
• Path 32 =500 MW(E2W), with SWIPN = 1,920 MW (S2N)flow
For Path 32 (E2W) and SWIPN (both N2S and S2N) at maximized flows, simultaneous
interactions/limitations were observed:the analysis shows that Path 32 and SWIPN cannot
simultaneously achieve their maximum/rated capabilities.These path limitations have been expressed
through hypothetical planning nomograms; further discussion is provided below in the "Post-Transient
Governor Power Flow Analysis" subsections.
Simultaneous power flow cases were developed with SWIPN and Path 32 separately held at their N2S
and E2W ratings while the alternate path's flow was maximized. Likewise for the S2N condition,
simultaneous cases were developed modeling SWIPN and Path 32 individually stressed to their
maximum rating, while attempting to maximize the alternate path's flow. Pre-Project versions of these
cases were also developed to help establish the system's benchmark performance prior to the SWIP
addition.
Approximately 35 relevant/critical contingencies for these paths were applied and evaluated through
post-transient governor power flow (thermal and voltage) analysis,transient stability analysis, and
reactive margin analysis.Appendix N32 provides the list of applied contingencies, as well as detailed
tabular results from these analyses.
7.4.1 Studied Scenarios
The following scenarios were studied to identify any impact/simultaneous interaction between SWIPN
and Path 32.
• SWIPN N2S and Path 32 E2W
Using the non-simultaneous 2025 Heavy Summer N2S Pre-Project base case, a Pre-SWIP case was
developed modeling Path 32 flow of 500 MW E2W. Two Post-SWIP simultaneous cases were also
developed: one modeling SWIPN flow at 2,070 MW N2S (with restricted/limited Path 32 N2S flow),
Exhibit No.4 34 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
and another modeling Path 32 flow of 500 MW E2W (with restricted/limited SWIPN N2S flow).
Stressing for SWIPN and Path 32 was achieved through schedule changes for the Robinson Summit-
Gonder and Robinson Summit-Falcon 345 kV phase-shifting transformers (PSTs).Adjustment of the
Fort Churchill 120 kV PST was also used to help balance and maximize Path 32 flows, and the local
Spring Valley Wind Generator(Bus#64538)was dispatched at a minimum output of 15 MW. Flows
were further stressed and tuned by redispatching generation and adjusting exports/imports
between Northwest (Area 40), Idaho (Area 60), WAPA R.M. (Area 73), Nevada (Area 18), Sierra (Area
64), LADWP (Area 26), and PacifiCorp-East(Area 65).
• SWIPN S2N and Path 32 E2W
Using the non-simultaneous 2025 Heavy Winter S2N base cases, Pre-and Post-SWIP cases were
developed modeling Path 32 at 500 MW E2W. For the Pre-SWIP case, Path 32 E2W flows were
limited to—435 MW E2W before contingency thermal and voltage concerns were observed.Two
Post-SWIP simultaneous cases were then developed: one modeling SWIPN flow at 1,920 MW S2N
(with restricted/limited Path 32 E2W flow), and another modeling Path 32 flow of 500 MW E2W
(with restricted/limited SWIPN S2N flow). Stressing for SWIPN and Path 32 was achieved through
schedule changes for the Robinson Summit-Gonder and Robinson Summit-Falcon 345 kV phase-
shifting transformers (PSTs).The Spring Valley Wind Generator was dispatched at a minimum output
of 15 MW. Flows were further stressed and tuned by redispatching generation and adjusting
exports/imports between Northwest (Area 40), Idaho (Area 60), Nevada (Area 18), Sierra (Area 64),
LADWP (Area 26), and PacifiCorp-East (Area 65).
7.4.2 Post-Transient Governor Power Flow Analysis
Please see Appendix N32 for this simultaneous analysis' list of applied contingencies and tabular results.
All of the identified contingencies were applied for post-transient governor power flow analysis of both
the Pre-and Post-SWIP simultaneous cases. Pre-Project cases were analyzed to establish a baseline
performance and/or confirm Path 32's limiting factor(s). Results for the Post-SWIPN cases indicate a
simultaneous relationship between Path 32 (E2W) and SWIPN (N2S and S2N): these two paths cannot
simultaneously achieve their maximum/rated capabilities.
7.4.2.1 SWIPN N2S and Path 32 E2W
For SWIPN N2S versus Path 32 E2W, a simultaneous interaction/limit is expected between these two
paths.This limitation can be expressed through a hypothetical planning nomogram with two corner
points:
• Path 32 ="385 MW E2W, and SWIPN = 2,070 MW N2S (rated flow)
• Path 32= 500 MW E2W (rated flow),SWIPN =—1,070 MW N2S
Power flow contingency analysis shows both these points to be limited by a Category P1-2 ("N-1")
outage of the Midpoint-Robinson 500 kV line, resulting in 100%emergency loading of the
Intermountain-Gonder 230 kV line. For the first nomogram point with SWIPN at 2,070 MW N2S, an
added concern is a Category P1-2 Robinson PST-Gonder 345 kV line outage, causing the Midpoint-
Robinson Summit 500 kV southern series capacitor line-side bus ("MPRSSC2")to reach 600 kV
(design limitation). For the second nomogram point with Path 32 at 500 MW E2W, Category 131-2
outages of either the Pavant-Black Rock or Osceola-Gonder 230 kV lines cause loading of the
Intermountain-Gonder 230 kV line to approach 100%of its emergency rating.
Exhibit No.4 35 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
SWIP-North N2S vs. Path 32 E2W
385,2070
2000
3 1500
O
iy 500,1070
N
z
= 1000
0
z
d
3
Soo
0
0 100 200 300 400 5
Path 32 E2W Flow(MW)
7.4.2.2 SWIPN S2N and Path 32 E2W
For SWIPN S2N versus Path 32 E2W, a simultaneous interaction/limit is expected.This limitation can
be expressed through a hypothetical planning nomogram with two corner points:
• Path 32 = 370 MW E2W, SWIPN = 1,920 MW S2N (rated flow). With SWIPN at rated S2N flow
and Path 32 flows of 370 MW E2W, power flow contingency results show the case to be
limited by a Category P1-2 outage of the Robinson Summit-Harry Allen 500 kV line, causing
voltage deviations at PacifiCorp-East's Black Rock 230 kV bus to approach -8%.
• Path 32=500 MW E2W(rated flow), and SWIPN = 1,000 MW S2N. For Path 32 increased to
its rated flow of 500 MW E2W, SWIPN is limited to 1,000 MW S2N. Under this condition, a
Category P1-2 outage of the Robinson Summit-Harry Allen 500 kV line (or the Intermountain-
Gonder 230 kV line) results in causes loading of the Black Rock-UTAH-NEV 230 kV line section
to reach 99%of emergency.
Exhibit No.4 36 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
SWIP-North S2N vs.Path 32 E2W
2000 0,1920 370,1920
3 1500
3
0
LL
500,1000
Z
N
H
1000
O
Z
d
3
500
0 500,0
0 100 200 300 400 500
Path 32 E2W Flow(MW)
7.4.3 Voltage Stability/Reactive Margin Analysis
For the voltage stability/reactive margin analysis,the nomogram corner point cases were further
modified by increasing both SWIPN's and Path 32's path flows by+5%for the "P1 Test" (testing Category
P1 outages for a converged solution). As a conservative approach, additional Category P2-P7 outages
(normally tested against a 2.5%increase in Path flow)were also applied to these 5% increase cases.The
table below summarizes the modeled flows on SWIPN and Path 32 for each of these scenarios.
Summary of SWIPN vs. Path 32 Reactive Margin Cases
Rating Nomo. +5% Increase Nomo. +5% Increase
Path (MW) Case 1 (131-137 outages applied) Case 2 (131-137 outages applied)
SWIPN N2S(HS case) 2,070 2,070 2,186 (+5.6%) 1,070 1,124 (+5.0%)
Path 32 E2W 500 386 407 (+5.6%) 500 528 (+5.7%)
SWIPN S2.N (HW case) -1,920 -1,921 -2,018 (+5.0%) -998 -11059 (+6.1%)
--------------- ---- ............ .......................
Path 32 E2W 500 370 390 (+5.4%) 500 525 (+5.0%)
All of the listed contingencies were simulated on these cases and achieved post-contingency
convergence, indicating adequate reactive margin for the system.
Exhibit No.4 37 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
7.4.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPN N2S-Path 32
E2W and SWIPN S2N-Path 32 E2W simultaneous cases. Stability performance of these cases was
essentially unchanged as compared to the SWIP non-simultaneous cases: no new or worsened transient
stability performance concerns were observed.
7.5 SWIPN vs. Path 66(and Path 65)Simultaneous Analysis
This study included a simultaneous analysis between SWIPN and Path 66, "California-Oregon Intertie"
(COI). Also, for the North-to-South (N2S) scenario described below, development of the Path 66 N2S
case additionally captured a maximized simultaneous condition for Path 65, "Pacific DC Intertie" (PDCI).
Path 66 COI consists of the following branches (asterisk denotes metered end):
• Malin*-Round Mountain 500 kV Line#1
• Malin*-Round Mountain 500 kV Line#2
• Captain Jack*-Olinda 500 kV Line
Path 65 PDCI consists of a ±500 kV DC multi-terminal system between Celilo and Sylmar, with the
Nevada-Oregon border as the point of demarcation. For study purposes, Path 65 flow is calculated as
the sum of the following branches (asterisk denotes metered end):
• Big Eddy-Celilo* 500 kV circuit#1
• Big Eddy-Celilo* 500 kV circuit#2
At the time of this SWIP Phase 2 Path Rating Study, Path 66's N2S rating was undergoing a rerate per the
WECC Path rating Process due to "changes in reliability criteria requirements" (elimination of the
common corridor outage requirement).13 As such,the Project Sponsors of the Path 66 rerate"
requested that the SWIPN simultaneous analysis assume an increased Path 66 flow of 5,100 MW N2S.
No changes were proposed for Path 66's Existing South-to-North (S2N) rating of 3,675 MW (rating
established in November 1992).
Additionally, for the Path 66 COI N2S scenario the Path 66 Rerate Project Sponsors requested that this
case also model Path 65 PDCI at its Existing Rating of 3,220 MW N2S (rating established in July 1992).
This simultaneous analysis evaluated the following conditions for Path 66 COI:
• Path 66=5,100 MW (N2S), with SWIPN = 2,070 MW (N2S) flow, including
Path 65 =3,220 MW (N2S).
• Path 66=3,675 MW (S2N), with SWIPN = 1,920 MW (S2N) flow
13 WECC Path Rating Process(dated July 12,2022)Section 5.5.7.Prior to this rerate, Path 66 featured an existing rating of
4,800 MW N2S,originally implemented in 1992.
14 Path 66 Rerate Project Sponsors included WAPA(Sierra Nevada Region), BPA, PacifiCorp-West, PG&E,TANC,
and SMUD.
Exhibit No.4 38 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
For Path 66 and SWIPN at maximized flows (N2S or S2N), no simultaneous limitations were observed:
the analysis shows that Paths 65, 66 and SWIPN can simultaneously achieve their maximum/rated N2S
capabilities, and that Path 66 and SWIPN can simultaneously achieve their maximum/rated S2N
capabilities.
A simultaneous power flow case was developed with SWIPN, Path 66, and Path 65 stressed to their
maximum N2S ratings to identify any impact/interaction between these paths. Likewise, a south-to-
north simultaneous case was developed modeling SWIPN and Path 66 stressed to their maximum S2N
ratings. Pre-Project versions of these cases were also developed to help establish the system's
benchmark performance prior to the SWIP addition. Over 30 relevant/critical contingencies for these
paths were applied and evaluated through post-transient governor power flow(thermal and voltage)
analysis,transient stability analysis, and reactive margin analysis. Appendix N66 provides the list of
applied contingencies, as well as detailed tabular results from these analyses.
7.5.1 Studied Scenarios
The following scenarios were studied to identify any impact/simultaneous interaction between SWIPN
and Path 66 COI.
• SWIPN N2S, Path 66 (COI) N2S, and Path 65 (PDCI) N2S
Using the non-simultaneous 2025 Heavy Summer North-to-South (N2S) base cases, Pre-and Post-
SWIP cases were developed with Path 66 COI 5,100 MW. Per direction from several COI participants,
these N2S cases also modeled Path 65 PDCI at its rated flow of 3,220 MW N2S. For the Post-SWIP
case, SWIPN flow was modeled at 2,070 MW N2S. N2S flows on COI were achieved by increasing
generation in the Northwest (Area 40) and scheduling this power to SCE (Area 24), LADWP (Area 26,
and PG&E (Area 30). Flow on Path 76 (Alturas Project)was reduced to near 0 MW by adjusting the
Bordertown 345 kV Phase-Shifting Transformer(PST). N2S flows were also monitored on Path 15
(Midway-Los Banos), Path 26 (Northern-Southern California/"Midway-Vincent"),to ensure they
were within applicable limits. N2S flows on SWIPN were maintained by adjusting the schedule
between Idaho (Area 60), Sierra (Area 64), and Nevada (Area 18).
• SWIPN S2N and Path 66 S2N
Using the non-simultaneous 2025 Heavy Winter S2N base cases, Pre-and Post-SWIP cases were
developed modeling Path 66 at 3,675 MW S2N.15 For the Post-SWIP case, SWIPN was modeled at
1,920 MW S2N flow. S2N flows on COI were achieved by increasing generation in SCE (Area 24),
LADWP (Area 26, and PG&E (Area 30) and scheduling this power to the Northwest (Area 40). Flow
on Path 76 (Alturas Project) was reduced to near 0 MW by adjusting the Bordertown 345 kV PST.To
maintain SWIPN S2N flow, additional interchange adjustments were applied between Idaho (Area
60), Sierra (Area 64), Nevada (Area 18), and APS (Area 14).
7.5.2 Post-Transient Governor Power Flow Analysis
Please see Appendix N66 for this simultaneous analysis' list of applied contingencies and tabular results.
All of the identified contingencies were applied for post-transient governor power flow analysis of both
the Pre-and Post-SWIP simultaneous cases. Study results indicate that Paths 65, 66 and SWIPN can
15 For the S2N cases,Path 65 PDCI was modeled at-975 MW(S2N flow,from Sylmar to Celilo).
Exhibit No.4 39 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
simultaneously achieve their maximum/rated N2S capabilities, and that Path 66 and SWIPN can
simultaneously achieve their maximum/rated S2N capabilities, without introducing any new or
significantly worsened reliability issues.
7.5.2.1 SWIPN N2S and Path 66(COI) and Path 65 (PDCI) N2S
For the Heavy Summer Pre-Project case with Path 66 COI flow at 5,100 MW north-to-south (N2S),
single line (Category P1-2) outages of either of the Round Mountain-RM_DRS SOO kV#1 or#2 lines
loads the parallel surviving line to—105-114%16 of its 3280.5 Amp emergency rating.This
performance is essentially unchanged in the Post-Project cases, and therefore is not associated with
the SWIP addition.
For the Pre-and Post-SWIPN N2S cases, a double-line outage of the Grizzly-Malin and Summer Lake-
Malin 500 kV lines (simulated with a post-contingency RAS to trip Northwest generation) results in
emergency thermal loading of 100-112%for the surviving Grizzly-Ponderosa-Captain Jack 500 kV
circuit. Because these loading concerns are unchanged/improved in the Post-SWIP case,this
performance is not regarded as a SWIP-related concern.
In terms of voltage performance,the SWIP Project did not introduce any new Category PO/normal
voltage concerns, nor did it introduce or worsen any P1-P7 contingency voltage issues.
7.5.2.2 SWIPN S2N and Path 66 (COI)S2N
With Path 66 COI flow at 3,675 MW south-to-north (S2N), the Heavy Winter Pre-Project and Post-
SWIPN simultaneous cases were updated to model opening of the Snow Goose 500/230 kV
transformer(see Section 6.1.2, SWIP S2N Power Flow Results for the non-simultaneous case).
However, even with this added mitigation a single line/P1-2 outage of the Klamath Falls-Meridian
500 kV line yields 100-109%emergency loadings for several PACW 230 kV facilities in the Klamath
Falls vicinity, and low voltages/negative voltage deviations (of-8 to -15%) on the underlying 69-
230 kV system. (Similar but lesser voltage performance concerns are observed for 131-2 outages of
either the Captain Jack-Snow Goose or Snow Goose-Klamath Falls 500 kV lines.)As previously
mentioned, PACW is currently developing additional transmission reinforcements for their southern
Oregon system.These issues are regarded as an existing local area concern associated with high
Path 66 S2N flows, and unrelated to the SWIP Project.
In the Post-SWIPN S2N study case, elevated normal voltages (1.05-1.07 per unit)were observed for
various 69-138 kV buses in Area 18 Nevada. A follow-up review of these high normal voltages
showed that these concerns can be resolved by statusing off various 69-138kV shunt capacitors in
Area 18, without impacting the studied path flows or overall case performance. As such,these high
voltage results are regarded as a localized case tuning issue and not a SWIP impact.
Otherwise, no new or notably increased thermal or voltage concerns were observed for the post-
SWIPN versus Path 66 S2N simultaneous case.
16 This outage was simulated both without(114%loading)and with(105%loading)an additional proposed Remedial Action
Scheme(RAS)to bypass the series capacitor in the surviving parallel circuit.
Exhibit No.4 40 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
7.5.3 Voltage Stability/Reactive Margin Analysis
For the voltage stability/reactive margin analysis, base cases were developed with the flows on SWIPN
and Path 66 COI (and for N2S, Path 65 PDCI) each individually increased by 5%for the "P1 Test" (testing
Category P1 outages for a converged solution). As a conservative approach, additional Category P2-P7
outages (normally tested against a 2.5% increase in Path flow) were also applied to the 5% increase
case.The table below summarizes the modeled flows on SWIPN, Path 66, and Path 65 for each of these
scenarios.
Summary of SWIPN vs. Path 66/65 Reactive Margin Cases
+5%Increase Cases
Path Rating(MW) (P1-P7 outages applied)
SWIPN N2S(HS case) 2,070 2,174 (+5.0%) 2,070 (0.0%) 2,070 (0.0%)
----------------------------- ---- ................................................................................. ............................ ...............................................................
Path 66 (COI) N2S 5,100 5,100 (0.0%) 5,355 (+5.0%) 5,100 (0.0%)
Path 65 (PDCI) N2S 3,220 3,220 (0.0%) 3,220 (0.0%) 3,382 (+5.0%)
SWIPN S2N (HW case) -1,920 (+5.0%) -1,930 (0.5%) --
Path 66 (COI) S2N -3,675 -3,675 (0.0%) ---------3,860 (+5.0%) --
All of the listed contingencies were simulated on these cases and achieved post-contingency
convergence, indicating adequate reactive margin for the system.
7.5.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPN-Path 66/65 N2S
and SWIPN-Path 66 S2N simultaneous cases. Stability performance of these cases was essentially
unchanged as compared to the SWIP non-simultaneous cases: no new or worsened transient stability
performance concerns were observed.
7.6 SWIPN vs. Path 76 Simultaneous Analysis
This study included a simultaneous analysis between SWIPN and Path 76, "Alturas Project". Path 76 has
an Accepted Rating of 300 MW North-to-South (1\12S), and 300 MW South-to-North (S2N). Path 76
Alturas is comprised of the following branch:
• Hilltop 230/345 W transformer(metered at Hilltop 230 W terminal)
This simultaneous analysis evaluated the following condition for Path 76 Alturas:
• Path 76=300 MW (1\12S),with SWIPN = 2,070 MW (N2S)flow
For Path 76 (N2S) and SWIPN (N2S) at maximized flows, no simultaneous limitations were observed:the
analysis shows that Path 76 and SWIPN can simultaneously achieve their maximum/rated capabilities.
Power flow cases were developed with SWIPN and Path 76 stressed to their maximum ratings to identify
any impact/simultaneous interaction between SWIPN and Alturas. Over 25 relevant/critical
contingencies for these paths were applied and evaluated through post-transient governor power flow
Exhibit No.4 411 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 47 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
(thermal and voltage) analysis, transient stability analysis, and reactive margin analysis.Appendix N76
provides the list of applied contingencies, as well as detailed tabular results from these analyses.
7.6.1 Studied Scenarios
The following scenario was studied to identify any impact/simultaneous interaction between SWIPN and
Path 76 Alturas:
• SWIPN N2S and Path 76(Alturas) N2S
Using the non-simultaneous 2025 Heavy Summer North-to-South (N2S) base cases, Pre-and Post-
SWIP cases were developed with Path 76 Alturas at 300 MW N2S. SWIPN was modeled at 2,070 MW
N2S in the Post-Project case. N2S stressing on Path 76 Alturas was achieved in part through schedule
changes for the Bordertown 345 W phase-shifting transformer(PST), increasing generation and
exports from Northwest (Area 40), and receiving this power in Sierra Pacific (Area 64). SWIPN N2S
flows were maintained by adjusting the interchange schedules between Idaho (Area 60), Nevada
(Area 18), and Sierra Pacific (Area 64).
7.6.2 Post-Transient Governor Power Flow Analysis
Please see Appendix N76 for this simultaneous analysis' list of applied contingencies and tabular results.
All of the identified contingencies were applied for post-transient governor power flow analysis of both
the Pre-and Post-SWIP simultaneous cases.
The Pre-SWIP (Heavy Summer) case was evaluated for contingency performance and found to be within
acceptable criteria/limits. In the Post-SWIP case, no new applicable thermal overload or voltage
performance concerns were observed:the Post-SWIP case's performance was either unchanged or
improved when compared to the Pre-Project condition.
7.6.3 Voltage Stability/Reactive Margin Analysis
For the voltage stability/reactive margin analysis, both SWIPN's and Path 76's path flows were increased
by+S%for the "P1 Test" (testing Category P1 outages for a converged solution).As a conservative
approach, additional Category P2-P7 outages(normally tested against a 2.5 increase in Path flow)were
also applied to this 5% increase case.The table below summarizes the modeled flows on SWIPN and
Path 76:
Summary of SWIPN vs. Path 76 Reactive Margin Case
+5% Increase
Path Rating(MW) (P1-P7 outages applied)
SWIPN N2S(HS case) 2,070 2,184 (+5.5%)
-------------------------------- -- ..................... o
Path 76 (Alturas) N2S 300 317 (+5.8/)
All of the listed contingencies were simulated on these cases and achieved post-contingency
convergence, indicating adequate reactive margin for the system.
Exhibit No.4 42 ( P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
7.6.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPN-Path 76
simultaneous case. Stability performance of this case was essentially unchanged as compared to the
SWIP non-simultaneous cases: no new or worsened transient stability performance concerns were
observed.
7.7 SWIPN vs. Aeolus South (Post-Gateway)Simultaneous Analysis
This study included a simultaneous analysis between SWIPN and the Aeolus South Project(also known
as "Gateway South"). Aeolus South has an Accepted Rating of 1,700 MW North-to-South (N2S),
established in 2010 by PacifiCorp.
Aeolus South is defined as the sum of the flow on the following facilities (* denotes metered facility):
• Aeolus*-Clover 500 kV Line
This simultaneous analysis evaluated the following conditions for Aeolus South (Post-Gateway):
• SWIPN N2S vs. Aeolus South N2S
Power flow cases were developed with Aeolus South and SWIPN stressed to their maximum achievable
values to identify any impact/simultaneous interaction between Aeolus South and SWIPN. Over 70
relevant/critical contingencies for these paths were applied and evaluated through post-transient
governor power flow (thermal and voltage) analysis,transient stability analysis, and reactive margin
analysis.Appendix NGW_AS provides the list of applied contingencies, as well as detailed tabular results
from these analyses.
No simultaneous relationship was observed for the SWIPN N2S vs.Aeolus South N2S scenario.
7.7.1 Studied Scenarios
For this simultaneous analysis,the "Phase 3 Post-Gateway" versions of the SWIPN non-simultaneous
cases were used as a starting point (see Section 5.2.1 for more detail).The following scenarios were
studied to identify any impact/simultaneous interaction between SWIPN and Aeolus South.
• SWIPN N2S and Aeolus South N2S
No simultaneous interaction was identified for this scenario. Using the modified 2025 Heavy
Summer North-to-South (N2S) bases cases, Pre-and Post-SWIP cases were developed with Aeolus
South at 1,700 MW N2S. SWIPN was modeled at 2,070 MW N2S in the Post-Project case. Flows on
Aeolus South were achieved mainly by increasing generation at Aeolus,Windstar, and Jim Bridger,
reducing generation at Huntington, Emery Hunter, Currant Creek, and other PACE generation near
Clover, and adjusting the Area interchange schedule between PACE (Area 65) and the Northwest
(Area 40).To help control 138 kV flows near Bonanza, phase-shifting capability was restored for the
Upalco 138/138 kV PST(previously locked). N2S flows on SWIPN were maintained by adjusting the
schedule between Nevada (Area 18) and Northwest (Area 40).
Exhibit No.4 43 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
7.7.2 Post-Transient Governor Power Flow Analysis
Please see Appendix NGW—AS for this simultaneous analysis' list of applied contingencies and tabular
results.All the identified contingencies were applied for post-transient governor power flow analysis to
each of the Pre-and Post-SWIP simultaneous cases described in the previous section.
7.7.2.1 SWIPN N2S and Aeolus South N2S
For SWIPN N2S (2,070 MW)versus Aeolus South N2S(1,700 MW), no simultaneous relationship
was observed.The Pre-and Post-SWIP Heavy Summer cases were evaluated for their contingency
performance: for the studied cases and simulated contingency definitions,the Pre-Project case (with
Aeolus South at rated N2S flow) exhibited several unresolved performance concerns. Similar but
improved performance for these outages was observed in the Post-SWIPN case—as such,these are
not regarded as SWIP-related issues.
For single element outages of either the Aeolus-Anticline 500 kV Line, Aeolus-Clover 500 kV Line
(Aeolus South), or Clover 500/345 kV Transformer, simulation of the Aeolus RAS(tripping up to
600 MW of total generation at TB Flats and High Plains) is required to achieve a converged post-
contingency power flow solution in both the Pre-and Post-SWIPN cases. For the outages of either
the Aeolus-Clover 500 kV Line or Clover 500/345 kV Transformer, resulting post-contingency
loadings on the Bonanza-Mona 345 kV line reach 98-99%of the summer emergency rating, for both
the Pre-and Post-SWIPN cases. Negative voltage deviations are also observed for these outages—
for the Aeolus-Clover 500 kV line outage, this performance is limited to several 69 kV buses in PACE
(Area 65) near Amps/Big Grassy (located in Idaho). For loss of the Clover 500/345 kV Transformer,
this outage has an added impact of isolating local area support from the Clover 500 kV SVD: in the
Pre-Project case, negative voltage deviations exceeding-8%are observed at over 35 138-345 kV
buses in the vicinity of PACE's Bonanza and Ben Lomond substations. For both these outages, similar
but improved system performance is observed in the Post-SWIPN case;therefore these are not
regarded as SWIP-related impacts.
In the Pre-Project case, loss of the Craig-Bonanza 345 kV Line resulted in post-contingency overloads
of the MEEKER-W.RV.CTY-CALAMRDG-RANGELY 138 kV circuits. Likewise, for loss of either AEOLUS-
SHIRLYBASIN 230 kV Line#1 or#2, post-contingency overloads are expected for the surviving
parallel circuit(even with the application of higher 30-minute emergency ratings). Post-contingency
performance for the outages in the Post-SWIPN case is relatively unchanged or improved; as such,
these loading concerns are not regarded as SWIP-related issues.
For a variety of outages, thermal overloads are observed for the Dave Johnson-Laramie River 230 kV
Line, for both the Pre-and Post-SWIPN Heavy Summer N2S cases.These loading concerns are
observed in other Pre-and Post-SWIPN N2S Post-Gateway cases (Paths 14+, 17+, 19+, etc.).
(Extensive efforts were applied to redispatch generation in the cases to mitigate these observed
overloads; however, some post-contingency overloads remain unresolved.) Because these overloads
occur in the Pre-Project case and improved/unchanged by the Post-SWIP condition, this concern is
regarded as a pre-existing issue not associated with SWIP.
For the Post-SWIPN case, loss of the Robinson Summit-Harry Allen 500 kV line requires tripping of
the Robinson Summit 345 kV shunt capacitor to keep the Robinson Summit 500 kV and 345 kV bus
voltages within limits. For this outage, negative voltage deviations (approaching-8%) are observed
Exhibit No.4 44 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
at the Abajo and Moab 138 kV buses. An alternate version of this outage was simulated with the
additional insertion of PacifiCorp-East's Pinto 138 kV shunt capacitor(one step of+32 MVAR),which
mitigates these concerns.
7.7.3 Voltage Stability/Reactive Margin Analysis
For the voltage stability/reactive margin analysis, base cases were developed with the flows on SWIPN
and Aeolus South each individually increased by 5%for the "P1 Test" (testing Category P1 outages for a
converged solution).As a conservative approach, additional Category P2-P7 outages (normally tested
against a 2.5% increase in Path flow) were also applied to these 5% increase cases.The table below
summarizes the modeled flows on SWIPN and Aeolus South for each of these scenarios.
Summary of SWIPN vs.Aeolus South Reactive Margin Cases
Rating SWIPN+5%Increase Case Aeolus South+5% Increase Case
Path (MW) (P1-P7 outages applied) (P1-P7 outages applied)
SWIPN N2S(HS case) 2,070 2,178 (+5.1%) 2,073 (+0.1%)
............................................................................. .......................
Aeolus South N2S 1 1,700 1,704 (+0.2%) 1,790 (+5.2%)
7.7.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPN-Aeolus South
simultaneous cases. Stability performance of these cases was essentially unchanged as compared to the
SWIP non-simultaneous cases, with generally no new or worsened transient stability performance
concerns.
For the studied cases and simulated contingency definitions,the Pre-Project case (with Aeolus South at
rated N2S flow) exhibited transient stability performance concerns for the Aeolus-Anticline 500 kV Line
outage (including simulation of the Aeolus RAS,tripping up to 600 MW of total generation at TB Flats
and High Plains). For this transient stability simulation, over twenty 115-230 kV buses in PACE Area 65
(including FT CREEK, PLATTE, AEOLUS, DUNLAP, etc.) exhibited voltage less than 70%of their pre-
contingency value for more than 30 cycles 17. For the Post-SWIPN case,this outage showed similar but
improved performance (fifteen affected 115-230 kV buses)—as such,these are not regarded as SWIP-
related issues.
7.8 SWIPN vs. Midpoint West(Post-Gateway)Simultaneous Analysis
This study included a simultaneous analysis between SWIPN and the Midpoint West Upgrade ("Midpoint
West"), part of the Gateway West Project. Midpoint West has an Accepted Rating of 4,400 MW East-to-
West(E2W), established in 2011 by Idaho Power Company.
Midpoint West is defined as the sum of the flow on the following facilities (* denotes metered facility):
• Midpoint*-Hemingway 500 kV Line
• Cedar Hill*-Hemingway 500 kV Line
17 WECC Standard TPL-001-WECC-CRT-3.2, Requirement R1.4
Exhibit No.4 45 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
• Midpoint*-Boise Bench 230 kV Line#2
• Midpoint*-Boise Bench 230 kV Line#3
• Lower Malad*-Cassia WP 138 kV Line
• Upper Salmon*-Glenns Ferry Tap 138 kV Line
This simultaneous analysis evaluated the following conditions for Midpoint West:
• SWIPN S2N vs. Midpoint West E2W
The SWIP Phase 2 Rating Study Plan also proposed a simultaneous analysis of SWIPN N25 vs. Midpoint
West E2W. However, after discussion with Idaho Power Company this scenario was excluded from this
simultaneous analysis as it does not represent a realistic or achievable coincident path flow condition,
due to lack of resources and/or other system constraints.
Power flow cases were developed with Midpoint West and SWIPN stressed to their maximum
achievable values to identify any impact/simultaneous interaction between Midpoint West and SWIPN.
Over 50 relevant/critical contingencies for these paths were applied and evaluated through post-
transient governor power flow(thermal and voltage) analysis, transient stability analysis, and reactive
margin analysis.Appendix NGW_MPW provides the list of applied contingencies, as well as detailed
tabular results from these analyses.
A simultaneous relationship was observed for the SWIPN S2N vs. Midpoint West E2W scenario.
7.8.1 Studied Scenarios
For this simultaneous analysis,the "Phase 3 Post-Gateway"versions of the SWIPN non-simultaneous
cases were used as a starting point (see Section 5.2.1 for more detail).The following scenarios were
studied to identify any impact/simultaneous interaction between SWIPN and Midpoint West.
• SWIPN S2N and Midpoint West E2W
To achieve increased E2W flows of the Gateway West paths in the Pre-Project and Post-SWIPN S2N
cases, a Light Winter condition was required. For this simultaneous analysis, Light Winter system
conditions were modeled by reducing the 2025 Heavy Winter case's load (and generation) in Area
60(Idaho) and Area 65 (PACE)to better align with the original Gateway Paths' rating study
assumptions.Area 60 load was scaled to 1,736 MW (1,000 MW reduction from 2025 Heavy Winter
case) and Area 65 load was scaled to 6,115 MW(2,000 MW reduction from 2025 Heavy Winter
case).The smaller series capacitor segment(X=-0.0265 per unit) on each of the Midpoint-Boise
Bench 230 kV#2 and#3 lines was normally bypassed to help mitigate loading of the Midpoint
345/230 kV Transformers. For the Pre-Project case,the Midpoint West path reached 4,217 MW E2W
(rated 4,400 MW):further stressing of Midpoint West was limited by Paths 19+ Bridger/Anticline
West and 17+ Borah West being fully loaded.
For the Post-SWIP S2N condition, a simultaneous interaction is expected. Using the modified 2025
Light Winter South-to-North (S2N) base case,two Post-SWIP cases were developed representing
corner points of a nomogram. With SWIPN at 1,920 MW S2N, Midpoint West flow was limited to
3,640 MW E2W; With Midpoint West maximized at—4,400 MW E2W, SWIPN flow was limited to
505 MW S2N (note, Midpoint West's rated flow was realized for the Post-SWIP condition, an
increase/improvement over the limitations observed in the Pre-Project case). Flows on for Midpoint
Exhibit No.4 46 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
West were achieved mainly by increasing generation at Aeolus, Windstar, and Jim Bridger and
adjusting the Area interchange schedule between PACE (Area 65) and the Northwest (Area 40). S2N
flows on SWIPN were maintained by adjusting the schedule between Nevada (Area 18) and Idaho
(Area 60). As done with the Pre-SWIP case,the smaller series capacitor in the Midpoint-Boise Bench
230 kV#2 and #3 lines was normally bypassed to help mitigate loading of the Midpoint 345/230 kV
Transformers. Similarly, for the second Post-SWIP case with SWIPN flow of 505 MW S2N, series
compensation in the Midpoint-Robinson 500 kV Line (SWIPN)was normally bypassed, to help
achieve this flow level and to improve voltage.
7.8.2 Post-Transient Governor Power Flow Analysis
Please see Appendix NGW_MPW for this simultaneous analysis' list of applied contingencies and tabular
results. All the identified contingencies were applied for post-transient governor power flow analysis to
each of the Pre-and Post-SWIP simultaneous cases described in the previous section.
7.8.2.1 SWIPN S2N and Midpoint West E2W
For SWIPN S2N versus Midpoint West E2W, a simultaneous interaction/limit is expected.This
limitation can be expressed through a hypothetical planning nomogram (see graphical depiction in
following "Mitigation Analysis" subsection).The limitations for this nomogram's two corner points
are described as follows:
• Midpoint West= 3,640 MW E2W, SWIPN = 1,920 MW S2N (rated flow). In the case with
Midpoint West E2W transfers limited to 3,640 MW, increased E2W transfers were limited by
thermal overloads on the Midpoint 345/230 kV Transformer#1 following an outage of Midpoint
345/230 kV Transformer#2 (and vice versa).Additionally, high voltages on the Midpoint-
Robinson 500 kV Line (line-side series capacitor bus "MPRSSCI") are observed following the
Aeolus-Anticline 500 kV Line outage. For this outage, no RAS/generation tripping was assumed
due to the reduced E2W transfers on the Bridger/Anticline West path. If the existing Bridger RAS
logic dictates generation tripping is still required at this reduced level of transfer,further
limitations of Bridger/Anticline West E2W transfers would be required.
• Midpoint West=4,400 MW E2W(rated flow), and SWIPN =505 MW S2N. In the Post-SWIP case
with SWIPN limited to 505 MW S2N, increased S2N transfers were limited by thermal overloads
on the Midpoint 345/230 kV Transformer#1 following an outage of Midpoint 345/230 kV
Transformer#2 (and vice versa). Also, for the Category 131-2 loss of the Populus-Cedar Hill
500 kV line, RAS actions are needed to keep Midpoint-Hemingway 500 kV line loading within
emergency limits: these RAS actions included generation tripping at PACE/Area 65's Jim Bridger,
TB Flats, and High Plains, as well as bypassing the Northwest/Area 40 Burns 500 kV series
capacitor.
7.8.3 Voltage Stability/Reactive Margin Analysis
For the SWIPN vs. Midpoint West simultaneous cases, all simulated contingencies achieved a converged
post-transient governor power flow solution with transfers on both paths increased by at least 5%,
demonstrating adequate reactive margin performance.
Exhibit No.4 47 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Summary of SWIPN vs. Midpoint West Reactive Margin Cases
Rating Nomo. +5%Increase Nomo. +5% Increase
Path (MW) Case 1 (PI-P7 outages applied) Case 2 (131-137 outages applied)
SWIPN S2N (LW case) -1,920 -1,920 -2,017 (+5.0%) -505 -530 (+5.0%)
.........................................................................................................
Midpoint West E2W 4,400 3,640 3,945 (+8.4%) 4,400 4,713 (+7.1%)
7.8.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPN-Midpoint West
simultaneous cases. Stability performance of these cases was essentially unchanged as compared to the
SWIP non-simultaneous cases; no new or worsened transient stability performance concerns were
observed.
7.8.5 Mitigation Analysis and Midpoint Changes
For the SWIPN S2N versus Midpoint West E2W simultaneous condition, additional work was performed
to explore potential mitigation of the limiting factor(s). GBT/USE coordinated with PacifiCorp and Idaho
Power in conducting this additional analysis.
Mitigation analysis results show that the SWIPN S2N-Midpoint West E2W simultaneous capability is
significantly improved by the "Midpoint Changes" (alternate Gateway West topology).
For SWIPN S2N/Gateway West E2W conditions, a primary limiting concern was the contingency loading
of the Midpoint 345/230 kV transformers (rated 700 MVA summer normal, 770 MVA summer
emergency): under heavy simultaneous stressing, loss of one Midpoint 345/230 kV transformer bank
would fully load the other surviving transformer.
As the simultaneous analyses of SWIPN versus the Post-Gateway Paths were being completed, Idaho
Power and PacifiCorp announced changes in the timing and development for several Gateway Project
elements, including advancing the construction of the Midpoint-Cedar Hill and Midpoint-Hemingway#2
500 kV lines, and delaying (opening) of the Cedar Hill-Hemingway 500 kV line. It was speculated that
these "Midpoint Changes" may help mitigate/reduce the loading of the Midpoint 345/230 kV
transformers.The Midpoint-Cedar Hill and Midpoint-Hemingway#2 500 kV lines were previously
designated as Gateway West "Stage 2" elements, and were not previously considered in the SWIPN-
Gateway Paths' simultaneous analyses 18, nor were they considered as part of the original Post-Gateway
Paths' Phase 3 ratings or definitions19.
In this Mitigation Analysis,the Midpoint Changes were added to the two previously-identified
simultaneous nomogram corner point cases, and the paths were re-stressed until a new limit was
realized. (Because the ratings of the revised Gateway West Paths are not yet known, existing GWW
18 See Section 5.2.1 for the baseline modeling assumptions applied for the Gateway West and Gateway South"Stage 1"
Projects,as well as the Boardman-to-Hemingway(132H)Project.
19 It should also be noted that with the addition of the Midpoint-Hemingway#2 500 kV line,the definition(and rating)of the
Midpoint West Path would change with this new member branch.
Exhibit No.4 48 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Phase 3 accepted path ratings were adhered to as one potential stopping point.) Using power flow
contingency analysis, the following two (2025 Light Winter) simultaneous cases/conditions were
evaluated:
• Midpoint West=4,295 MW E2W, SWIPN = 1,920 MW S2N (rated flow) with the Midpoint Changes.
For the condition with SWIPN fully stressed at 1,920 MW S2N, addition of the Midpoint Changes was
found to reduce the Midpoint 345/230 kV transformers' loading and allow Midpoint West flows to
reach 4,295 MW E2W.This case is primarily limited by the flow on Path 14+, which reaches its Phase
3 Accepted Rating of 3,400 MW E2W—further increases in Midpoint West's E2W flow would likely
exceed Path 14+'s Accepted Rating.
• Midpoint West=4,400 MW E2W (existing Phase 3 rating), and SWIPN = 512 MW S2N with the
Midpoint Changes. With Midpoint West flow of 4,400 MW E2W, SWIPN was limited to 512 MW S2N
due to the Midpoint West and Path 14+flows reaching their existing Phase 3 path ratings;
otherwise, no thermal or voltage concerns were observed.
The figure below provides a hypothetical planning nomogram of the simultaneous interaction between
SWIPN S2N and Midpoint West E2W,with and without the "Midpoint Changes". Please see Appendix
NGW—MPW for tabular results from this mitigation analysis.
SWIP-North S2N vs. Midpoint West[GWW] E2W
2000
---------C, 4295,1920
1 `lllllllllll1
1800 '
1
3640,1920 i
1600 mited by Path 14+
flow=3,400 MW E2W
1
1400
1
1200 1
I
3 '
0 1000 i
LL I
Z '
1
N ---0--Baseline Si nil Analysis
z 800
I
a --0--Midpoint Changes/Mitigation
� 600
512
400 4400,505
200
0
0 S00 1000 1500 2000 2500 3000 3500 4000 4500 5000
Midpoint West[GWW]E2W Flow(MW)
Exhibit No.4 49 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
7.9 SWIPN vs. Path 14+ (Post-Gateway)Simultaneous Analysis
This study included a simultaneous analysis between SWIPN and Path "14+" - Idaho to Northwest with
Boardman-Hemingway 500 kV(132H) Project. Path 14+ has a WECC Phase 3 Accepted Rating of
3,400 MW East-to-West (EM) and 2,250 MW West-to-East (W2E), established in 2012 by Idaho Power
Company.
Path 14+ is defined as the sum of the flow on the following facilities (* denotes metered facility):
• Hemingway-Longhorn* 500 kV Line
• Hemingway*-Summer Lake 500 kV Line
• Imnaha*-Lolo 230 kV Line
• Hells Canyon-Hurricane* 230 kV Line
• North Powder-Lagrande* 230 kV Line
• Hines-Harney* 115 kV Line
This simultaneous analysis evaluated the following conditions for Path 14+ Idaho to Northwest with
Boardman-Hemingway 500 kV (132H) Project:
• SWIPN N2S vs. Path 14+W2E
• SWIPN S2N vs. Path 14+ E2W
The SWIP Phase 2 Rating Study Plan also proposed simultaneous analyses for SWIPN N2S versus Path
14+ E2W, and for SWIPN S2N versus Path 14+W2E. However, after discussion with Idaho Power
Company these scenarios were excluded from this simultaneous analysis as they do not represent
realistic or achievable coincident path flow conditions, due to lack of resources and/or other system
constraints.
Power flow cases were developed with Path 14+ and SWIPN stressed to their maximum achievable
values to identify any impact/simultaneous interaction between Path 14+and SWIPN. Over 50
relevant/critical contingencies for these paths were applied and evaluated through post-transient
governor power flow (thermal and voltage) analysis,transient stability analysis, and reactive margin
analysis.Appendix NGW14+ provides the list of applied contingencies, as well as detailed tabular results
from these analyses.
No simultaneous relationship was observed for the SWIPN N2S vs. Path 14+W2E scenario.
A simultaneous relationship was observed for the SWIPN S2N vs. Path 14+ E2W scenario.
7.9.1 Studied Scenarios
For this simultaneous analysis,the "Phase 3 Post-Gateway"versions of the SWIPN non-simultaneous
cases were used as a starting point (see Section 5.2.1 for more detail).The following scenarios were
studied to identify any impact/simultaneous interaction between SWIPN and Path 14+ Idaho to
Northwest with Boardman-Hemingway 500 kV(132H) Project.
• SWIPN N2S and Path 14+W2E
No simultaneous interaction was identified for this scenario. Using the modified 2025 Heavy
Summer N2S bases cases, Pre-and Post-SWIP cases were developed with Path 14+at 2,250 MW
W2E. SWIPN was modeled at 2,070 MW N2S in the Post-Project case. Flows on Idaho to Northwest
Exhibit No.4 50 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
with B2H were achieved mainly by increasing generation in the Northwest (Area 40) and adjusting
the interchange schedule between Area 40 and PACE (Area 65). N2S flows on SWIPN were
maintained by adjusting the Area interchange schedule between Nevada (Area 18) and Idaho (Area
60).
• SWIPN S2N and Path 14+ E2W
To achieve increased E2W flows of the Gateway West paths in the Pre-Project and Post-SWIPN S2N
cases, a Light Winter condition was required. For this simultaneous analysis, Light Winter system
conditions were modeled by reducing the 2025 Heavy Winter case's load (and generation) in Area
60 (Idaho Power Company) and Area 65 (PACE)to better align with the original Gateway Paths'
rating study assumptions.Area 60 load was scaled to 1,736 MW (1,000 MW reduction from 2025
Heavy Winter case) and Area 65 load was scaled to 6,115 MW (2,000 MW reduction from 2025
Heavy Winter case).The smaller series capacitor segment(X=-0.0265 per unit) on each of the
Midpoint-Boise Bench 230 kV#2 and#3 lines was normally bypassed to help mitigate loading of the
Midpoint 345/230 kV Transformers. For the Pre-Project case, Path 14+ reached 3,340 MW E2W
(rated 3,400 MW), but further stressing was limited by Paths 19+ Bridge r/Anticline West and 17+
Borah West being fully loaded.
For the Post-SWIP S2N condition, a simultaneous interaction is expected. Using the modified 2025
Light Winter South-to-North (S2N) bases case,two Post-SWIP cases were developed representing
corner points of a nomogram: with SWIPN at 1,920 MW S2N, E2W transfers on Path 14+were
limited to 2,771 MW; with Path 14+at 3,400 MW E2W, S2N transfers on SWIPN were limited to
505 MW (note, Path 14+ rated flow was realized for the Post-SWIP condition, an
increase/improvement over the limitations observed in the Pre-Project case). Flows on Path 14+
were achieved mainly by increasing generation at Aeolus, Windstar, and Jim Bridger and adjusting
the Area interchange schedule between PACE (Area 65) and the Northwest (Area 40). S2N flows on
SWIPN were maintained by adjusting the Area interchange schedule between Nevada (Area 18) and
Idaho (Area 60). As applied in the Pre-SWIP case,the smaller series capacitor in the Midpoint-Boise
Bench 230 kV#2 and#3 lines was normally bypassed to help mitigate loading of the Midpoint
345/230 kV Transformers. For the second Post-SWIP case with SWIPN flow of 505 MW S2N, series
compensation in the Midpoint-Robinson 500 kV Line (SWIPN)was normally bypassed,to help
achieve this flow level and to improve voltage.
7.9.2 Post-Transient Governor Power Flow Analysis
Please see Appendix NGW14+for this simultaneous analysis' list of applied contingencies and tabular
results.All the identified contingencies were applied for post-transient governor power flow analysis to
each of the Pre-and Post-SWIP simultaneous cases described in the previous section.
7.9.2.1 SWIPN N2S and Path 14+W2E
For SWIPN N2S (2,070 MW)versus Path 14+W2E(2,250 MW), no simultaneous relationship was
observed: results indicate that both paths can simultaneously achieve their rated flow. For this
scenario,the Pre-and Post-SWIP Heavy Summer cases were evaluated for their contingency
performance and found to be within acceptable criteria/limits.20 For the single line outage (Category
20 One exception is the Dave Johnson-Laramie River 230 kV line,which exhibited contingency loading concerns in other Post-
Gateway cases(Paths 17+,19+,Aeolus South,etc.),for both the both Pre-Project and Post-SWIPN conditions. Because
Exhibit No.4 511 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 57 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
131-2) of the Hemingway-Longhorn 500 kV Line,the Lolo-Imnaha 230 kV Line reaches 100%of its
summer emergency rating. For either a Category 131-1 outage of a Palo Verde generating unit or a
Category 137-2 PDCI Bipole outage,the Midpoint-Robinson Summit 500 kV southern series capacitor
line-side bus ("MPRSSC2")voltage reaches its design limit voltage of 1.200 per unit.
7.9.2.2 SWIPN S2N and Path 14+E2W
For SWIPN S2N versus Path 14+ E2W, a simultaneous interaction/limit is expected.This limitation
can be expressed through a hypothetical planning nomogram (see graphical depiction in following
"Mitigation Analysis" subsection).The limitations for this nomogram's two corner points are
described as follows:
• Path 14+=2,771 MW E2W,SWIPN = 1,920 MW S2N (rated flow). In the case with Path 14+
transfers limited to 2,771 MW E2W, increased E2W transfers were by thermal overloads on the
Midpoint 345/230 kV Transformer#1 following an outage of Midpoint 345/230 kV Transformer
#2 (and vice versa). Additionally, high voltages on the Midpoint-Robinson 500 kV Line (line-side
series capacitor bus "MPRSSCI") are observed following the Aeolus-Anticline 500 kV Line
outage. For this outage, no RAS/generation tripping was assumed due to the reduced loading on
the Bridger/Anticline West path. If the existing Bridger RAS logic dictates generation tripping is
still required at this reduced level of transfer, further limitations of Bridger/Anticline West E2W
transfers would be required.
• Path 14+=3,400 MW E2W(rated flow), and SWIPN =505 MW S2N. In the Post-SWIP case with
SWIPN limited to 505 MW S2N, increased S2N transfers were limited by 100% loading of the
Midpoint 345/230 kV Transformer#1's summer emergency rating following an outage of
Midpoint 345/230 kV Transformer#2 (and vice versa).Also, for the Category P1-2 loss of the
Populus-Cedar Hill 500 kV line, RAS actions are needed to keep Midpoint-Hemingway 500 kV
line loading within emergency limits:these RAS actions included generation tripping at
PACE/Area 65's Jim Bridger,TB Flats, and High Plains, as well as bypassing the Northwest/Area
40 Burns 500 kV series capacitor.
Note that these SWIPN/Path 14+flows are limited due to critical contingencies and limitations
observed on either"upstream" or"downstream" paths (Path 19+ Bridger/Anticline West and
Midpoint West), rather than being limited by the studied paths' own critical contingency and path
components. It is recognized that different case assumptions (e.g. addition of future queue
generation) could result in a different nomogram relationship between SWIPN and Path 14+;
however,such explorations were outside the scope of this simultaneous analysis.
7.9.3 Voltage Stability/Reactive Margin Analysis
For the SWIPN vs. Path 14+simultaneous cases, nearly all simulated contingencies achieved a converged
post-transient governor power flow solution with transfers on both paths increased by at least+5%,
demonstrating adequate reactive margin performance. A diverged power flow solution was observed in
the +5% increase of the SWIPN N2S and Path 14+W2E scenario,for the "G-2" loss of two Palo Verde
generator units (Extreme Event); however this outage achieved a converged solution with a +2.5%
increase in transfers on both paths.
these overloads are observed in the Pre-Project cases and improved/unchanged by the Post-SWIP condition,this concern is
regarded as a pre-existing issue not associated with SWIP.
Exhibit No.4 52 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 58 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Summary of SWIPN vs. Path 14+ Reactive Margin Cases
Rating +5%Increase +2.5%Increase
Path (MW) (P1-P7 outages applied) (P2-P7 outages applied)
SWIPN N2S (HS case) 2,070 2,175 (+5.1%) 2,123 (+2.6%)
Path 14+W2E -2,250 -2,364 (+5.1%) -2,307 (+2.5%)
Rating Nomo. +5% Increase Nomo. +5% Increase
Path (MW) Case 1 (PI-P7 outages applied) Case 2 (PI-P7 outages applied)
SWIPN S2N (LW case) -1,920 -1,920 -2,017 (+5.0%) -505 -530 (+5.0%)
Path 14+ E2W 1 3,400 2,771 3,078 (+11.1%) 3,400 3,614 (+6.3%)
7.9.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPN-Path 14+
simultaneous cases. Stability performance of these cases was essentially unchanged as compared to the
SWIP non-simultaneous cases; no new or worsened transient stability performance concerns were
observed.
7.9.5 Mitigation Analysis and Midpoint Changes
For the SWIPN S2N versus Path 14+ E2W simultaneous condition, additional work was performed to
explore potential mitigation of the limiting factor(s). GBT/USE coordinated with PacifiCorp and Idaho
Power in conducting this additional analysis.
Results from the mitigation analysis show that the previously-identified SWIPN S2N-Path 14+ E2W
simultaneous limitations are resolved by the "Midpoint Changes" (alternate Gateway West topology).
For SWIPN S2N/Gateway West E2W conditions, a primary limiting concern was the contingency loading
of the Midpoint 345/230 kV transformers (rated 700 MVA summer normal, 770 MVA summer
emergency): under heavy simultaneous stressing, loss of one Midpoint 345/230 kV transformer bank
would fully load the other surviving transformer. Additionally-for high SWIPN S2N flow—possible high
voltage on the Midpoint-Robinson 500 kV Line (line-side series capacitor bus "MPRSSCI") was observed
for an outage of the Aeolus-Anticline 500 kV Line.
As the simultaneous analyses of SWIPN versus the Post-Gateway Paths were being completed, Idaho
Power and PacifiCorp announced changes in the timing and development for several Gateway Project
elements, including advancing the construction of the Midpoint-Cedar Hill and Midpoint-Hemingway#2
500 kV lines, and delaying (opening) of the Cedar Hill-Hemingway 500 kV line. It was speculated that
these "Midpoint Changes" may help mitigate/reduce the loading of the Midpoint 345/230 kV
transformers.The Midpoint-Cedar Hill and Midpoint-Hemingway#2 500 kV lines were previously
designated as Gateway West "Stage 2" elements, and were not previously considered in the SWIPN-
Exhibit No.4 53 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 59 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Gateway Paths' simultaneous analyses21, nor were they considered as part of the original Post-Gateway
Paths' Phase 3 ratings or definitions22.
In this Mitigation Analysis,the Midpoint Changes were added to the previous simultaneous case(s), and
the paths were re-stressed until a new limit was realized. (Because the ratings of the revised Gateway
West Paths are not yet known, existing GWW Phase 3 accepted path ratings were adhered to as one
potential stopping point.) Using power flow contingency analysis,the following two (2025 Light Winter)
simultaneous case/condition was developed and evaluated:
• Path 14+=3,400 MW E2W(existing Phase 3 rating), SWIPN = 1,920 MW S2N (rated flow)with the
Midpoint Changes. For the condition with SWIPN fully stressed at 1,920 MW S2N, addition of the
Midpoint Changes was found to reduce the Midpoint 345/230 kV transformers' loading and allow
Path 14+flow to simultaneously reach its Phase 3 Accepted Rating of 3,400 MW E2W. As such, no
simultaneous nomogram would be required at these flow levels.
The figure below provides a hypothetical planning nomogram of the simultaneous interaction between
SWIPN S2N and Path 14+ E2W, with and without the "Midpoint Changes". Please see Appendix
NGW14+for tabular results from this mitigation analysis.
SWIP-North S2N vs.Path 14+[GWW] E2W
2000
------------Q 3400,1920
1800 2771,1920 i
i
1600
i
1400 �
i
i
i
c lzoo '
Z 1000
V) ---0—Baseline Simi Analysis i
Z 800
--0--Midpoint Changes/Mitigation �
i
v� 600
i
400 P I
3400,505
200
0 — —
0 500 1000 1500 2000 2500 3000 3500 4000
Path 14+[GWW]E2W Flow(MW)
21 See Section 5.2.1 for the baseline modeling assumptions applied for the Gateway West and Gateway South"Stage 1"
Projects,as well as the Boardman-to-Hemingway(132H)Project.
22 It should also be noted that with the addition of the Midpoint-Hemingway#2 500 kV line,the definition(and rating)of the
Midpoint West Path would change with this new member branch.
Exhibit No.4 54 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 60 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
7.10 SWIPN vs. Path 17+ (Post-Gateway)Simultaneous Analysis
This study included a simultaneous analysis between SWIPN and Path "17+" - Borah West Upgrade
(Gateway West). Path 17+ has an Accepted Rating of 4,450 MW East-to-West (E2W), established in 2011
by PacifiCorp and Idaho Power Company.
Path 17+ is defined as the sum of the flow on the following facilities (* denotes metered facility):
• Borah*-Midpoint 500 kV Line
• Populus*-Cedar Hill 500 kV Line
• Borah*-Adelaide 345 kV Line#1
• Borah*-Adelaide 345 kV Line#2
• Borah*-Hunt 230 kV Line
• American Falls*-Raft River-Minidoka 138 kV Line
This simultaneous analysis evaluated the following conditions for Path 17+ Borah West Upgrade
(Gateway West):
• SWIPN N2S vs. Path 17+ E2W
• SWIPN S2N vs. Path 17+ E2W
Power flow cases were developed with Path 17+ and SWIPN stressed to their maximum achievable
values to identify any impact/simultaneous interaction between Path 17+and SWIPN. Over 40
relevant/critical contingencies for these paths were applied and evaluated through post-transient
governor power flow (thermal and voltage) analysis,transient stability analysis, and reactive margin
analysis.Appendix NGW17+ provides the list of applied contingencies, as well as detailed tabular results
from these analyses.
No simultaneous relationship was observed for the SWIPN N2S vs. Path 17+ E2W scenario; however,
Path 17+was not able to achieve its maximum rating. A simultaneous relationship was observed for the
SWIPN S2N vs. Path 17+ E2W scenario.
7.10.1 Studied Scenarios
For this simultaneous analysis,the "Phase 3 Post-Gateway" versions of the SWIPN non-simultaneous
cases were used as a starting point (see Section 5.2.1 for more detail).The following scenarios were
studied to identify any impact/simultaneous interaction between SWIPN and Path 17+ Borah West
Upgrade (Gateway West).
• SWIPN N2S and Path 17+ E2W
No simultaneous interaction was identified for this scenario; however, Path 17+was not able to
achieve its maximum rating. Using the modified 2025 Heavy Summer North-to-South (N2S) bases
cases, Pre-and Post-SWIP cases were developed with maximized Path 17+ E2W flow. Flows on Path
17+were maximized mainly by increasing generation at Aeolus, Windstar, and Jim Bridger and
adjusting the Area interchange schedule between PACE (Area 65) and the Northwest (Area 40).
PACE (Area 65) and Idaho (Area 60) loads were also reduced to help induce increased E2W flows.
N2S flows on SWIPN were maintained by adjusting the schedule between Nevada (Area 18) and
Idaho (Area 60).
Exhibit No.4 55 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 61 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
In the Pre-Project case, Path 17+ achieved a flow of 3,517 MW E2W (rated 4,450 MW). Further
increases were limited by the ratings on Path 19+ Bridger/Anticline West (Post-Gateway) and Path
29 (Intermountain-Gonder 230 kV).
In the Post-Project case with SWIPN flow at 2,070 MW N2S, only 3,912 MW E2W flow was realized
on Path 17+. For these conditions, Path 19+ Bridger/Anticline West flow is nearly at its rated limit of
4,100 MW E2W. Further increased Path 17+flows were not achievable in a North-to-South oriented
case: in order to achieve maximized/increased E2W flows on Path 17+,S2N flows on Path 20+ (New
Path C) are required. However, S2N Path 20+flow was not achievable (or probable) in a case where
SWIPN, COI, PDCI, and IPP are flowing in a N2S direction.After discussion with Idaho Power
Company, it was decided to leave the developed case "as is" (SWIPN 2,070 MW N2S, Path 17+
3,912 MW E2W)for this simultaneous analysis scenario.
• SWIPN S2N and Path 17+ E2W
To achieve increased E2W flows of the Gateway West paths in the Pre-Project and Post-SWIPN S2N
cases, a Light Winter condition was required. For this simultaneous analysis, Light Winter system
conditions were modeled by reducing the 2025 Heavy Winter case's load (and generation) in Area
60 (Idaho Power Company) and Area 65 (PACE)to better align with the original Gateway Paths'
rating study assumptions.Area 60 load was scaled to 1,736 MW (1,000 MW reduction from 2025
Heavy Winter case) and Area 65 load was scaled to 6,115 MW (2,000 MW reduction from 2025
Heavy Winter case).The smaller series capacitor segment(X=-0.0265 per unit) on each of the
Midpoint-Boise Bench 230 kV#2 and#3 lines was normally bypassed to help mitigate loading of the
Midpoint 345/230 kV Transformers. For the Pre-Project case, Path 17+ reached its rated flow of
4,450 MW E2W.
For the Post-SWIP S2N condition, a simultaneous interaction is expected. Using the modified 2025
Light Winter South-to-North (S2N) base case,two Post-SWIPN cases were developed representing
corner points of a nomogram: with SWIPN at 1,920 MW S2N, E2W transfers on Path 17+were
limited to 2,183 MW; for Path 17+ at 4,450 MW E2W, S2N transfers on SWIPN were limited to
505 MW. Path 17+were achieved mainly by increasing generation at Aeolus, Windstar, and Jim
Bridger and adjusting the schedule between PACE (Area 65) and the Northwest (Area 40). S2N flows
on SWIPN were maintained by adjusting the schedule between Nevada (Area 18) and Idaho (Area
60).As applied in the Pre-SWIP case,the smaller series capacitor in the Midpoint-Boise Bench
230 kV#2 and #3 lines was normally bypassed to help mitigate loading of the Midpoint 345/230 kV
Transformers. For the second Post-SWIP case with SWIPN flow of 505 MW S2N, series compensation
in the Midpoint-Robinson 500 kV Line (SWIPN) was normally bypassed, to help achieve this flow
level and to improve voltage.
7.10.2 Post-Transient Governor Power Flow Analysis
Please see Appendix NGW17+for this simultaneous analysis' list of applied contingencies and tabular
results.All the identified contingencies were applied for post-transient governor power flow analysis to
each of the Pre-and Post-SWIP simultaneous cases described in the previous section.
7.10.2.1 SWIPN N2S and Path 17+ E2W
For SWIPN N2S(2,070 MW)versus Path 17+ E2W(3,912 MW), no simultaneous relationship was
observed: however, Path 17+was not able to achieve its maximum rating (4,450 MW E2W).The Pre-
Exhibit No.4 56 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 62 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
and Post-SWIPN Heavy Summer cases were evaluated for their contingency performance and found
to be within acceptable criteria/limits.23 For the single line outage (Category 131-2) of the Robinson
Summit-Harry Allen 500 kV line,the Red Butte-Harry Allen 345 kV line reaches 100%of its summer
emergency rating (1200 Amps/717 MVA). For the single line outage of the Aeolus-Anticline 500 kV
Line (including generation tripping at TB Flats and High Plains, and tripping of the Anticline 500 kV
shunt capacitor/SVD), post-contingency loading of the Standpipe-Miners Tap-Platte 230 kV Line
reaches 99%of this circuit's continuous summer emergency ratings. For single line outages of either
the Bridger-Three Mile Knoll, Bridger-Populus#1, or Bridger Populus#2 345 kV lines, post-
contingency loading of the surviving lines is within these circuits' 30-minute emergency ratings. For
the common corridor double-line outage of the Bridger-Populus#1 and#2 345 kV lines, generation
tripping at Jim Bridger,TB Flats, and High Plains is needed to manage the post-contingency loading
of the Bridger-Three Mile Knoll 345 kV line. For the double line outage of the Borah-Midpoint 500 kV
Line and Borah-Adelaide Tap-Midpoint 345 kV Line,the Bridger RAS is applied to trip generation at
Jim Bridger,TB Flats, and High Plains to manage the post-contingency loading of the remaining
Borah-Adelaide 345 kV Line; in addition,the Burns 500 kV series capacitor was also bypassed.
7.10.2.2 SWIPN S2N and Path 17+ E2W
For SWIPN S2N versus Path 17+ E2W, a simultaneous interaction/limit is expected.This limitation
can be expressed through a hypothetical planning nomogram (see graphical depiction in following
"Mitigation Analysis" subsection).The limitations for this nomogram's two corner points are
described as follows:
• Path 17+ = 2,183 MW E2W, SWIPN = 1,920 MW S2N (rated flow). In the case with Path 17+
transfers limited to 2,183 MW, increased E2W transfers were limited by 100% loading of the
Midpoint 345/230 kV Transformer#1's summer emergency rating following an outage of
Midpoint 345/230 kV Transformer#2 (and vice versa).Additionally, high voltages on the
Midpoint-Robinson 500 kV Line (line-side series capacitor bus "MPRSSCI") are observed
following the Aeolus-Anticline 500 kV Line outage. For this outage, no RAS/generation tripping
was assumed due to the reduced loading on the Bridger/Anticline West path. If the existing RAS
logic dictates generation tripping is still required at this reduced level of transfer,further
limitations of E2W transfers on Path 17+ Borah West Upgrade (Gateway West)would be
required.
• Path 17+=4,450 MW E2W(rated flow), and SWIPN =505 MW S2N. In the Post-SWIP case with
SWIPN limited to 505 MW S2N, increased S2N transfers were limited by 100% loading of the
Midpoint 345/230 kV Transformer#1's summer emergency rating following an outage of
Midpoint 345/230 kV Transformer#2 (and vice versa).Also,for the Category 131-2 loss of the
Populus-Cedar Hill 500 kV line, RAS actions are needed to keep Midpoint-Hemingway 500 kV
line loading within emergency limits:these RAS actions included generation tripping at
PACE/Area 65's Jim Bridger,TB Flats, and High Plains, as well as bypassing the Northwest/Area
40 Burns 500 kV series capacitor.
23 One exception is the Dave Johnson-Laramie River 230 kV line,which exhibited contingency loading concerns in other Post-
Gateway cases(Paths 14+, 19+,Aeolus South,etc.),for both the both Pre-Project and Post-SWIPN conditions. Because
these overloads are observed in the Pre-Project cases and improved/unchanged by the Post-SWIP condition,this concern is
regarded as a pre-existing issue not associated with SWIP.
Exhibit No.4 57 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 63 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Note that these SWIPN/Path 17+flows are limited due to critical contingencies and limitations
observed on either"upstream" or"downstream" paths (Path 19+ Bridger/Anticline West and
Midpoint West), rather than being limited by the studied paths' own critical contingency and path
components. It is recognized that different case assumptions (e.g. addition of future queue
generation) could result in a different nomogram relationship between SWIPN and Path 17+;
however, such explorations were outside the scope of this simultaneous analysis.
7.10.3 Voltage Stability/Reactive Margin Analysis
For the SWIPN vs. Path 17+simultaneous cases, all simulated contingencies achieved a converged post-
transient governor power flow solution with transfers on both paths increased by at least 5%,
demonstrating adequate reactive margin performance.
Summary of SWIPN vs. Path 17+ Reactive Margin Cases
Rating +5%Increase
Path (MW) (P1-P7 outages applied)
SWIPN N2S (HS case) 2,070 2,179 (+5.3%)
Path 17+ E2W 4,450 (31912) 4,124 (+5.4%)
Rating Nomo. +5% Increase Nomo. +5% Increase
Path (MW) Case 1 (P1-P7 outages applied) Case 2 (P1-P7 outages applied)
SWIPN S2N (LW case) -1,920 -1,920 -2,017 (+5.0%) -505 -530 (+5.0%)
............................
Path 17+ E2W 4,450 2,183 2,397 (+9.8%) 4,450 4,762 (+7.0%)
7.10.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPN-Path 17+
simultaneous cases. Stability performance of these cases was essentially unchanged as compared to the
SWIP non-simultaneous cases; no new or worsened transient stability performance concerns were
observed.
7.10.5 Mitigation Analysis and Midpoint Changes
For the SWIPN S2N versus Path 17+ E2W simultaneous condition, additional work was performed to
explore potential mitigation of the limiting factor(s). GBT/USE coordinated with PacifiCorp and Idaho
Power in conducting this additional analysis.
Mitigation analysis results show that the SWIPN S2N- Path 17+ E2W simultaneous capability is notably
improved by the "Midpoint Changes" (alternate Gateway West topology).
For SWIPN S2N/Gateway West E2W conditions, a primary limiting concern was the contingency loading
of the Midpoint 345/230 kV transformers (rated 700 MVA summer normal, 770 MVA summer
emergency): under heavy simultaneous stressing, loss of one Midpoint 345/230 kV transformer bank
would fully load the other surviving transformer. Additionally-for high SWIPN S2N flow—possible high
Exhibit No.4 58 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 64 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
voltage on the Midpoint-Robinson 500 kV Line (line-side series capacitor bus "MPRSSCI") was observed
for an outage of the Aeolus-Anticline 500 kV Line.
As the simultaneous analyses of SWIPN versus the Post-Gateway Paths were being completed, Idaho
Power and PacifiCorp announced changes in the timing and development for several Gateway Project
elements, including advancing the construction of the Midpoint-Cedar Hill and Midpoint-Hemingway#2
500 kV lines, and delaying (opening) of the Cedar Hill-Hemingway 500 kV line. It was speculated that
these "Midpoint Changes" may help mitigate/reduce the loading of the Midpoint 345/230 kV
transformers.The Midpoint-Cedar Hill and Midpoint-Hemingway#2 500 kV lines were previously
designated as Gateway West "Stage 2" elements, and were not previously considered in the SWIPN-
Gateway Paths' simultaneous analyses24, nor were they considered as part of the original Post-Gateway
Paths' Phase 3 ratings or definitions".
In this Mitigation Analysis,the Midpoint Changes were added to the two previously-identified
simultaneous nomogram corner point cases, and the paths were re-stressed until a new limit was
realized. (Because the ratings of the revised Gateway West Paths are not yet known, existing GWW
Phase 3 accepted path ratings were adhered to as one potential stopping point.) Using power flow
contingency analysis, the following two (2025 Light Winter) simultaneous cases/conditions were
developed and evaluated:
• Path 17+= 2,915 MW E2W,SWIPN = 1,920 MW S2N (rated flow) with the Midpoint Changes. For
the condition with SWIPN fully stressed at 1,920 MW S2N, addition of the Midpoint Changes was
found to reduce the Midpoint 345/230 kV transformers' loading and allow Path 17+flows to
simultaneously reach 2,915 MW E2W.This case is primarily limited by the flow on Path 14+, which
reaches its Phase 3 Accepted Rating of 3,400 MW E2W—further increases in Path 17+'s E2W flow
could potentially exceed Path 14+'s Accepted Rating.
• Path 17+=4,450 MW E2W(existing Phase 3 rating), and SWIPN =512 MW S2N with the Midpoint
Changes. With Path 17+flow of 4,450 MW E2W, SWIPN was limited to 512 MW S2N due to the
Midpoint West and Path 14+flows reaching their existing Phase 3 path ratings; otherwise, no
thermal or voltage concerns were observed.
The figure below provides a hypothetical planning nomogram of the simultaneous interaction between
SWIPN S2N and Path 17+ E2W, with and without the "Midpoint Changes". Please see Appendix
NGW17+ for tabular results from this mitigation analysis.
24 See Section 5.2.1 for the baseline modeling assumptions applied for the Gateway West and Gateway South"Stage 1"
Projects,as well as the Boardman-to-Hemingway(132H)Project.
25 It should also be noted that with the addition of the Midpoint-Hemingway#2 500 kV line,the definition(and rating)of the
Midpoint West Path would change with this new member branch.
Exhibit No.4 59 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 65 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
SWIP-North S2N vs.Path 17+[GWW] E2W
2000
-------------
% 2915,1920
1800 %
2183,1920 %` Limited by Path 14+
flow=3,400MWE2W
1600 `%
■ `
1400 Ld
s`
-2 lzoo -��
3
o `
z laoo �����
L Baseline Simi Analysis
Z 800 `
%a --0--Midpoint Changes/Mitigation `�
3 `
Ln 600 � -so,,1�
400 � 4450sos
200
0
0 500 1000 1500 2000 2500 3000 3500 4000 4500 5000
Path 17+[GWW]E2W Flow(MW)
7.11 SWIPN vs. Path 19+ (Post-Gateway)Simultaneous Analysis
This study included a simultaneous analysis between SWIPN and Path "19+" - Bridge r/Anticline West
(Post-Gateway). Path 19+ has an Accepted Rating of 4,100 MW East-to-West (E2W), established in 2010
by PacifiCorp.
Path 19+ is defined as the sum of the flow on the following facilities (* denotes metered facility):
• Anticline*-Populus 500 kV Line
• Jim Bridger*-Threemile Knoll 345 kV Line
• Jim Bridger*-Populus 345 kV Line#1
• Jim Bridger*-Populus 345 kV Line#2
This simultaneous analysis evaluated the following conditions for Path 19+ Bridger/Anticline West (Post-
Gateway):
• SWIPN N2S vs. Path 19+ E2W
• SWIPN S2N vs. Path 19+ E2W
Power flow cases were developed with Path 19+and SWIPN stressed to their maximum achievable
values to identify any impact/simultaneous interaction between Path 19+ and SWIPN. Over 40
relevant/critical contingencies for these paths were applied and evaluated through post-transient
governor power flow(thermal and voltage) analysis,transient stability analysis, and reactive margin
Exhibit No.4 60 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 66 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
analysis.Appendix NGW19+ provides the list of applied contingencies, as well as detailed tabular results
from these analyses.
No simultaneous relationship was observed for the SWIPN N2S vs. Path 19+ E2W scenario.A
simultaneous relationship was observed for the SWIPN S2N vs. Path 19+ E2W scenario.
7.11.1 Studied Scenarios
For this simultaneous analysis,the "Phase 3 Post-Gateway" versions of the SWIPN non-simultaneous
cases were used as a starting point (see Section 5.2.1 for more detail).The following scenarios were
studied to identify any impact/simultaneous interaction between SWIPN and Path 19+ Bridger/Anticline
West.
• SWIPN N2S and Path 19+ E2W
No simultaneous interaction was identified for this scenario. Using the modified 2025 Heavy
Summer North-to-South (N2S) bases cases, Pre-and Post-SWIP cases were developed with Path 19+
flow at 4,100 MW E2W. SWIPN was modeled at 2,070 MW N2S in the Post-Project case. Flows on
Path 19+were achieved mainly by increasing generation at Aeolus, Windstar, and Jim Bridger and
adjusting the Area interchange schedule between PACE (Area 65) and the Northwest (Area 40). N2S
flows on SWIPN were maintained by adjusting the interchange schedule between Nevada (Area 18)
and Idaho (Area 60).
• SWIPN S2N and Path 19+ E2W
To achieve increased E2W flows for the Gateway West paths in the Pre-Project and Post-SWIPN S2N
cases, a Light Winter condition was required. For this simultaneous analysis, Light Winter system
conditions were modeled by reducing the 2025 Heavy Winter case's load (and generation) in Area
60 (Idaho Power Company) and Area 65 (PACE) to better align with the original Gateway Paths'
rating study assumptions.Area 60 load was scaled to 1,736 MW (1,000 MW reduction from 2025
Heavy Winter case) and Area 65 load was scaled to 6,115 MW (2,000 MW reduction from 2025
Heavy Winter case).The smaller series capacitor segment(X=-0.0265 per unit) on each of the
Midpoint-Boise Bench 230 kV#2 and#3 lines was normally bypassed to help mitigate loading of the
Midpoint 345/230 kV Transformers. For the Pre-Project case, Path 19+ reached its rated flow of
4,100 MW E2W.
For the Post-SWIP S2N condition, a simultaneous interaction is expected. Using the modified 2025
Light Winter S2N base case,two Post-SWIPN cases were developed representing corner points of a
nomogram: with SWIPN at 1,920 MW S2N, E2W transfers on Path 19+were limited to 2,315 MW;
for Path 19+ at 4,100 MW E2W, S2N transfers on SWIPN were limited to 505 MW. Flows on
Bridger/Anticline West (Post-Gateway) were achieved mainly by increasing generation at Aeolus,
Windstar, and Jim Bridger and adjusting the Area interchange schedule between PACE (Area 65) and
the Northwest (Area 40). S2N flows on SWIPN were maintained by adjusting the schedule between
Nevada (Area 18) and Idaho (Area 60). As applied in the Pre-SWIP case, the smaller series capacitor
in the Midpoint-Boise Bench 230 kV#2 and #3 lines was normally bypassed to help mitigate loading
of the Midpoint 345/230 kV Transformers. For the second Post-SWIP case with SWIPN flow of
505 MW S2N, series compensation in the Midpoint-Robinson 500 kV Line (SWIPN) was normally
bypassed,to help achieve this flow level and to improve voltage.
Exhibit No.4 611 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 67 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
7.11.2 Post-Transient Governor Power Flow Analysis
Please see Appendix NGW19+for this simultaneous analysis' list of applied contingencies and tabular
results.All the identified contingencies were applied for post-transient governor power flow analysis to
each of the Pre-and Post-SWIP simultaneous cases described in the previous section.
7.11.2.1 SWIPN N2S and Path 19+ E2W
For SWIPN N2S(2,070 MW)versus Path 19+ E2W(4,100 MW), no simultaneous relationship was
observed.The Pre-and Post-SWIPN Heavy Summer cases were evaluated for their contingency
performance and found to be within acceptable criteria/limits.26 For this case, a PDCI Bipole outage
(Category P7-2) causes the Midpoint-Robinson Summit 500 kV line-side series capacitor bus
("MPRSSCI") to reach 600 kV. For the single line outage (Category P1-2) of the Aeolus-Anticline
500 kV Line (including generation tripping at TB Flats and High Plains, and tripping of the Anticline
500 kV shunt capacitor/SVD), post-contingency loading of the Standpipe-Miners Tap-Platte 230 kV
Line reaches 101-102%of this circuit's continuous summer emergency ratings, but still falls within
the 30-minute emergency values. For single line outages of either the Bridger-Three Mile Knoll,
Bridger-Populus#1, or Bridger Populus#2 345 kV lines, post-contingency loading of the surviving
lines is within these circuits' 30-minute emergency ratings. For the common corridor double-line
outage of the Bridger-Populus#1 and#2 345 kV lines,generation tripping at Jim Bridger,TB Flats,
and High Plains is needed to manage the post-contingency loading of the Bridger-Three Mile Knoll
345 kV line.
7.11.2.2 SWIPN S2N and Path 19+ E2W
For SWIPN S2N versus Path 19+ E2W, a simultaneous interaction/limit is expected.This limitation
can be expressed through a hypothetical planning nomogram (see graphical depiction in following
"Mitigation Analysis" subsection).The limitations for this nomogram's two corner points are
described as follows:
• Path 19+= 2,315 MW E2W,SWIPN = 1,920 MW S2N (rated flow). In the case with Path 19+
transfers limited to 2,315 MW, increased E2W transfers were limited by 100% loading of the
Midpoint 345/230 kV Transformer#1's summer emergency rating following an outage of
Midpoint 345/230 kV Transformer#2 (and vice versa). kV Additionally, high voltages on the
Midpoint-Robinson 500 kV Line (line-side series capacitor bus "MPRSSCI") are observed
following the Aeolus-Anticline 500 kV Line outage. No RAS-associated generation tripping was
assumed for this outage due to the reduced level of E2W transfer on Bridger/Anticline West
(Post-Gateway). If the existing RAS logic dictates generation tripping is still required at this
reduced level of transfer,further limitations of E2W transfers on Path 19+ Bridger/Anticline
West would be required.
• Path 19+=4,100 MW E2W(rated flow), and SWIPN = 505 MW S2N. In the Post-SWIPN case with
SWIPN limited to 505 MW S2N, increased S2N transfers were limited by 100% loading of the
Midpoint 345/230 kV Transformer#1's summer emergency rating following an outage of
Midpoint 345/230 kV Transformer#2 (and vice versa).Also,for the Category P1-2 loss of the
26 One exception is the Dave Johnson-Laramie River 230 kV line,which exhibited contingency loading concerns in other Post-
Gateway cases(Paths 14+, 17+,Aeolus South,etc.),for both the both Pre-Project and Post-SWIPN conditions. Because
these overloads are observed in the Pre-Project cases and improved/unchanged by the Post-SWIP condition,this concern is
regarded as a pre-existing issue not associated with SWIP.
Exhibit No.4 62 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 68 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Populus-Cedar Hill 500 kV line, RAS actions are needed to keep Midpoint-Hemingway 500 kV
line loading within emergency limits: these RAS actions included generation tripping at
PACE/Area 65's Jim Bridger,TB Flats, and High Plains, as well as bypassing the Northwest/Area
40 Burns 500 kV series capacitor.
7.11.3 Voltage Stability/Reactive Margin Analysis
For the SWIPN vs. Path 19+simultaneous cases, all simulated contingencies achieved a converged post-
transient governor power flow solution with transfers on both paths increased by at least 5%,
demonstrating adequate reactive margin performance.
Summary of SWIPN vs. Path 19+ Reactive Margin Cases
Rating +5%Increase
Path (MW) (131-137 outages applied)
SWIPN N2S (HS case) 2,070 2,181 (+5.4%)
Path 19+ E2W 4,100 4,305 (+5.0%)
Rating Nomo. +5% Increase Nomo. +5% Increase
Path (MW) Case 1 (131-137 outages applied) Case 2 (131-137 outages applied)
SWIPN S2N (LW case) -1,920 -1,920 -2,017 (+5.0%) -505 -530 (+5.0%)
Path 19+ E2W 1 4,100 2,315 2,476 (+6.9%) 4,100 4,306 (+5.0%)
7.11.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPN-Path 19+
simultaneous cases. Stability performance of these cases was essentially unchanged as compared to the
SWIP non-simultaneous cases; no new or worsened transient stability performance concerns were
observed.
7.11.5 Mitigation Analysis and Midpoint Changes
For the SWIPN S2N versus Path 19+ E2W simultaneous condition, additional work was performed to
explore potential mitigation of the limiting factor(s). GBT/USE coordinated with PacifiCorp and Idaho
Power in conducting this additional analysis.
Mitigation analysis results show that the SWIPN S2N- Path 19+ E2W simultaneous capability is notably
improved by the "Midpoint Changes" (alternate Gateway West topology).
For SWIPN S2N/Gateway West E2W conditions, a primary limiting concern was the contingency loading
of the Midpoint 345/230 kV transformers (rated 700 MVA summer normal, 770 MVA summer
emergency): under heavy simultaneous stressing, loss of one Midpoint 345/230 kV transformer bank
would fully load the other surviving transformer. Additionally-for high SWIPN S2N flow—possible high
voltage on the Midpoint-Robinson 500 kV Line (line-side series capacitor bus "MPRSSCI") was observed
for an outage of the Aeolus-Anticline 500 kV Line.
Exhibit No.4 63 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 69 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
As the simultaneous analyses of SWIPN versus the Post-Gateway Paths were being completed, Idaho
Power and PacifiCorp announced changes in the timing and development for several Gateway Project
elements, including advancing the construction of the Midpoint-Cedar Hill and Midpoint-Hemingway#2
500 kV lines, and delaying (opening) of the Cedar Hill-Hemingway 500 kV line. It was speculated that
these "Midpoint Changes" may help mitigate/reduce the loading of the Midpoint 345/230 kV
transformers.The Midpoint-Cedar Hill and Midpoint-Hemingway#2 500 kV lines were previously
designated as Gateway West "Stage 2" elements, and were not previously considered in the SWIPN-
Gateway Paths' simultaneous analyses27, nor were they considered as part of the original Post-Gateway
Paths' Phase 3 ratings or definitions28.
In this Mitigation Analysis,the Midpoint Changes were added to the two previously-identified
simultaneous nomogram corner point cases, and the paths were re-stressed until a new limit was
realized. (Because the ratings of the revised Gateway West Paths are not yet known, existing GWW
Phase 3 path ratings were adhered to as one potential stopping point.) Using power flow contingency
analysis,the following two (2025 Light Winter) simultaneous cases/conditions were developed and
evaluated:
• Path 19+= 2,912 MW E2W, SWIPN = 1,920 MW S2N (rated flow) with the Midpoint Changes. For
the condition with SWIPN fully stressed at 1,920 MW S2N, addition of the Midpoint Changes was
found to reduce the Midpoint 345/230 kV transformers' loading and allow Midpoint West flows to
simultaneously reach 4,295 MW E2W.This case is primarily limited by the flow on Path 14+, which
reaches its Phase 3 Accepted Rating of 3,400 MW E2W—further increases in Path 19+'s E2W flow
could potentially exceed Path 14+'s Accepted Rating.
• Path 19+ =4,100 MW E2W(existing Phase 3 rating), and SWIPN = 512 MW S2N with the Midpoint
Changes. With Path 19+flow of 4,100 MW E2W, SWIPN was limited to 512 MW S2N due to the
Midpoint West and Path 14+flows reaching their existing Phase 3 path ratings; otherwise, no
thermal or voltage concerns were observed.
The figure below provides a hypothetical planning nomogram of the simultaneous interaction between
SWIPN S2N and Path 19+ E2W, with and without the "Midpoint Changes". Please see Appendix
NGW19+for tabular results from this mitigation analysis.
27 See Section 5.2.1 for the baseline modeling assumptions applied for the Gateway West and Gateway South"Stage 1"
Projects,as well as the Boardman-to-Hemingway(B2H)Project.
28 It should also be noted that with the addition of the Midpoint-Hemingway#2 500 kV line,the definition(and rating)of the
Midpoint West Path would change with this new member branch.
Exhibit No.4 64 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 70 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
SWIP-North S2N vs.Path 19+[GWW] E2W
2000
---------- 2912,1920
1800
2315,1920 .%
Limited by Path 14+
flow=3,400 MW E2W
1600 `
1400 i
3
� lzoo `.
2 1000 J• `%.`
Baseline Simi Analysis %s,
Z 800 s`
a_ --0--Midpoint Changes/Mitigation s`
� 600 � s� 4100,512
400 4100,505
200 i I W
■
0
0 500 1000 1500 2000 2500 3000 3500 4000 4500
Path 19+[GWWJ E2W Flow(MW)
7.12 SWIPN vs. Path 20+ (Post-Gateway)Simultaneous Analysis
This study included a simultaneous analysis between SWIPN and Path "20+" - New Path C (Post-
Gateway). Path 20+ has an Accepted Rating of 2,250 MW North-to-South (N2S) and 2,250 MW South-to-
North (S2N), established in 2011 by PacifiCorp.
New Path C is defined as the sum of the flow on the following facilities (* denotes metered facility):
• Malad-American Falls* 138 kV Line
• Ben Lomond-Populus* 345 kV Line#1
• Ben Lomond-Populus* 345 kV Line#2
• Treasureton-Sunbeam-Brady* 230 kV Line
• Fish Creek-Goshen* 161 kV Line
• Terminal-Populus* 345 kV Line
• Threemile Knoll 345*/138 kV Transformer
• Hooper Springs 138*/115 kV Transformer
This simultaneous analysis evaluated the following conditions for Path 20+/ New Path C:
• SWIPN N2S vs. Path 20+ N2S
• SWIPN S2N vs. Path 20+S2N
Power flow cases were developed with Path 20+and SWIPN stressed to their maximum achievable
values to identify any impact/simultaneous interaction between Path 20+and SWIPN. Over 50
Exhibit No.4 65 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 71 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
relevant/critical contingencies for these paths were applied and evaluated through post-transient
governor power flow (thermal and voltage) analysis,transient stability analysis, and reactive margin
analysis.Appendix NGW20+ provides the list of applied contingencies, as well as detailed tabular results
from these analyses.
No simultaneous relationship was observed for the SWIPN N2S vs. Path 20+ N2S scenario.A
simultaneous relationship was observed for the SWIPN S2N vs. Path 20+S2N scenario.
7.12.1 Studied Scenarios
For this simultaneous analysis,the "Phase 3 Post-Gateway" versions of the SWIPN non-simultaneous
cases were used as a starting point (see Section 5.2.1 for more detail).The following scenarios were
studied to identify any impact/simultaneous interaction between SWIPN and Path 20+ New Path C
(Post-Gateway).
• SWIPN N2S and Path 20+N2S
No simultaneous interaction was identified for this scenario. Using the modified 2025 Heavy
Summer North-to-South (N2S) bases cases, Pre-and Post-SWIP cases were developed with Path 20+
flow at 2,250 MW N2S. SWIPN was modeled at 2,070 MW N2S in the Post-Project case. N2S flows on
Path 20+were achieved mainly by increasing generation at Aeolus and Windstar, decreasing
generation at Emery Hunter, Huntington, and Currant Creek, and adjusting the Area interchange
schedule between PACE (Area 65), Idaho (Area 60), and the Northwest (Area 40).
• SWIPN S2N and Path 20+S2N
In order to achieve increased S2N flows on Path 20+for both the Pre-and Post-SWIPN S2N cases, a
Light Winter condition was required. For this simultaneous analysis, light winter system conditions
were modeled by reducing load (and generation) in Area 65 (PACE) in the 2025 Heavy Winter case to
better align with these previous study assumptions. Area 65 load was scaled to 5,909 MW
(2,100 MW reduction from the original SWIP 2025 Heavy Winter non-simultaneous case). For the
Pre-Project case, Path 20+/New Path C achieved its rated flow of 2,250 MW S2N.
For the Post-SWIP S2N condition, a simultaneous interaction is expected. Using the modified 2025
Light Winter South-to-North (S2N) base case, two Post-SWIPN cases were developed representing
corner points of a nomogram: with SWIPN at 1,920 MW S2N, Path 20+S2N flows were limited to
1,843 MW; for Path 20+at 2,250 MW S2N, S2N transfers on SWIPN were limited to 1,433 MW. Path
20+S2N flows were achieved with extensive changes in generation dispatch and scheduling. PACE
(Area 65) generation was reduced at Jim Bridger and increased elsewhere throughout PACE
(especially near Clover); excess Area 65 generation was scheduled to Idaho (Area 60) and the
Northwest (Area 40). Additionally,generation in Nevada (Area 18) and Arizona (Area 14)was
increased and scheduled to Idaho and the Northwest. N2S flow on the Intermountain Power Project
(IPP) DC Line was reduced to 170-600 MW to minimize outbound flows from Utah to southern
California. Phase-shifting transformers across southern Utah (Harry Allen, Sigurd, Pinto, San Juan,
etc.)were adjusted to support higher S2N flows through Utah and Path 20+. SWIPN S2N flows were
maintained by adjusting the Area interchange schedule between Nevada (Area 18), Arizona (Area
14), Idaho (Area 60), and the Northwest (Area 40).To help mitigate loading of the Midpoint
345/230 kV Transformers,the smaller series capacitor segment (X=-0.0265 per unit) was bypassed
in each of the Midpoint-Boise Bench 230 kV Lines.
Exhibit No.4 66 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 72 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
7.12.2 Post-Transient Governor Power Flow Analysis
Please see Appendix NGW20+for this simultaneous analysis' list of applied contingencies and tabular
results.All the identified contingencies were applied for post-transient governor power flow analysis to
each of the Pre-and Post-SWIP simultaneous cases described in the previous section.
7.12.2.1 SWIPN N2S and Path 20+N2S
For SWIPN N2S (2,070 MW)versus Path 20+N2S(2,250 MW), no simultaneous relationship was
observed.The Pre-and Post-SWIP Heavy Summer cases were evaluated for their contingency
performance. In the Post-SWIPN case,the Aeolus-Clover 500 kV Line outage (Category P1-2) results
is 99.5%emergency loading of the Upalco PST-Emma Park 138 kV Line. For the single line outage
(Category P1-2) of the Aeolus-Anticline 500 kV Line, a diverged post-contingency solution was
observed in both the Pre-and Post-SWIP cases,for both the "No RAS"version of this contingency, as
well as with the "Aeolus RAS" (tripping—600 MW of generation at TB Flats and High Plains). If
additional tripping of Cedar Springs generation (total generation drop of—800 MW) is modeled, a
converged post-contingency solution is achieved,with negative voltage deviations of-8 to-9%at the
CLOVER 500 kV and WYOPO 230 kV buses. Because this performance is observed in both the Pre-
Project and Post-SWIP cases,this is not considered to be a SWIP-related issue. For the single line
outage of Aeolus-Clover(Gateway South) 500 kV Line, generation tripping at TB Flats and High Plains
is required to manage the post-contingency loading of the Bonanza-Mona 345 kV Line and several
138 kV Lines near Bonanza, and to avoid low post-contingency voltages and negative voltage
deviations (exceeding 9%) at the Bonanza 345 kV bus and local 138 kV system. For the common
corridor double-line outage of the Populus-Ben Lomond #2 and Bridgerland-Ben Lomond 345 kV
Lines, the Bridgerland RAS (opening the Bridgerland 345/138 kV Transformer), is required to manage
post-contingency loadings on the 138 kV system between Bridgerland and Ben Lomond.
7.12.2.2 SWIPN S2N and Path 20+S2N
For SWIPN S2N versus Path 20+S2N, a simultaneous interaction/limit is expected.This limitation can
be expressed through a hypothetical planning nomogram (see graphical depiction in following
"Mitigation Analysis" subsection).The limitations for this nomogram's two corner points are
described as follows:
• Path 20+ = 1,843 MW S2N, and SWIPN = 1,920 MW S2N (rated flow)
• Path 20+=2,250 MW S2N (rated flow), SWIPN = 1,433 MW S2N
Increased S2N transfers on both paths were limited for two reasons. First,with the loss of either the
Cedar Hill-Hemingway or Populus-Cedar Hill 500 kV Line, the Midpoint-Hemingway 500 kV Line
reaches its emergency rating. Second,with the loss of one of the Midpoint 345/230 kV
Transformers, the remaining transformer reaches its summer emergency rating.To mitigate the
post-contingency flow on the Midpoint 345/230 kV Transformers,generation in Idaho (Area 60) can
be dispatched. However, such generation changes can cause Path 14+ E2W flow to increase outside
its determined SWIPN-Path 14+ nomogram relationship. For each case, SWIPN or Path 20+S2N
transfers were increased until these limits were reached.
Furthermore,for the case with SWIPN flow limited to 1,433 MW S2N, contingency overloads were
observed on several 138 kV lines between Bridgerland and Ben Lomond for outages of either the
Exhibit No.4 67 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 73 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Bridgerland-Ben Lomond 345 kV Line or common corridor double-line outages involving Populus,
Ben Lomond, and Bridgerland 345 kV Lines. Because this performance occurs in both the Pre-and
Post-SWIP cases and is slightly improved in the Post-SWIP condition,this performance was regarded
as a pre-existing issue not attributable to SWIP.
7.12.3 Voltage Stability/Reactive Margin Analysis
For the SWIPN vs. Path 20+simultaneous cases, all simulated contingencies achieved a converged post-
transient governor power flow solution with transfers on both paths increased by at least 5%,
demonstrating adequate reactive margin performance.
Summary of SWIPN vs. Path 20+ Reactive Margin Cases
Rating +5%Increase
Path (MW) (131-137 outages applied)
SWIPN N2S (HS case) 2,070 2,176 (+5.1%)
Path 20+ N2S 2,250 2,367 (+5.2%)
Rating Nomo. +5% Increase Nomo. +5% Increase
Path (MW) Case 1 (131-137 outages applied) Case 2 (131-137 outages applied)
SWIPN S2N (LW case) -1,920 -1,920 -2,021 (+5.3%) -1,433 -1,507 (+5.2%)
Path 20+S2N 1 -2,250 -1,843 -1,937 (+5.1%) -2,250 -2,367 (+5.2%)
7.12.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPN-Path 20+
simultaneous cases. Stability performance of these cases was essentially unchanged as compared to the
SWIP non-simultaneous cases; no new or worsened transient stability performance concerns were
observed.
7.12.5 Mitigation Analysis and Midpoint Changes
For the SWIPN S2N versus Path 20+S2N simultaneous condition, additional work was performed to
explore potential mitigation of the limiting factor(s). GBT/USE coordinated with PacifiCorp and Idaho
Power in conducting this additional analysis.
Mitigation analysis results show that the SWIPN S2N- Path 20+S2N simultaneous capability is
significantly improved by the "Midpoint Changes" (alternate Gateway West topology).
For SWIPN S2N/Path 20+S2N simultaneous conditions, a primary limiting concern was the contingency
loading of the Midpoint 345/230 kV transformers (rated 700 MVA summer normal, 770 MVA summer
emergency): under heavy simultaneous stressing, loss of one Midpoint 345/230 kV transformer bank
would fully load the other surviving transformer. Additionally, with the original Gateway West topology
loss of either the Cedar Hill-Hemingway or Populus-Cedar Hill 500 kV Line would cause loading of the
Midpoint-Hemingway 500 kV Line to reach its emergency rating.
Exhibit No.4 68 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 74 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
As the simultaneous analyses of SWIPN versus the Post-Gateway Paths were being completed, Idaho
Power and PacifiCorp announced changes in the timing and development for several Gateway Project
elements, including advancing the construction of the Midpoint-Cedar Hill and Midpoint-Hemingway#2
500 kV lines, and delaying (opening) of the Cedar Hill-Hemingway 500 kV line. It was speculated that
these "Midpoint Changes" may help mitigate/reduce the loading of the Midpoint 345/230 kV
transformers (as well as contingency loading of the Midpoint-Hemingway 500 kV line).The Midpoint-
Cedar Hill and Midpoint-Hemingway#2 500 kV lines were previously designated as Gateway West
"Stage 2" elements, and were not previously considered in the SWIPN-Gateway Paths' simultaneous
analyses29, nor were they considered as part of the original Post-Gateway Paths' Phase 3 ratings or
definitions3o
In this Mitigation Analysis,the Midpoint Changes were added to the two previously-identified
simultaneous nomogram corner point cases, and the paths were re-stressed until a new limit was
realized. (Because the ratings of the revised Gateway West Paths are not yet known, existing GWW
Phase 3 path ratings were adhered to as one potential stopping point.) Using power flow contingency
analysis,the following two (2025 Light Winter) simultaneous cases/conditions were developed and
evaluated:
• Path 20+= 2,211 MW S2N,SWIPN = 1,920 MW S2N (rated flow)with the Midpoint Changes.
• Path 20+= 2,250 MW S2N (existing Phase 3 rating), and SWIPN = 1,895 MW S2N with the
Midpoint Changes.
For both of these stressed conditions, addition of the Midpoint Changes was found to reduce the
Midpoint 345/230 kV transformers' loading and nearly allows allow both paths to simultaneously reach
their S2N ratings. For these cases, loss of Midpoint 345/230 kV Transformer#1 or#2 causes the
surviving transformer to reach 99-100%of its 770 MVA summer emergency rating, or 84-85%of the
910 MVA winter emergency rating (a non-issue when winter seasonal ratings are applied).Additionally,
for loss of either of the Midpoint-Hemingway#1 or#2 500 kV Lines, modified RAS actions (bypassing of
series capacitors) are anticipated to avoid overloads of the surviving parallel circuit."
The figure below provides a hypothetical planning nomogram of the simultaneous interaction between
SWIPN S2N and Path 20+S2N, with and without the "Midpoint Changes". Please see Appendix NGW20+
for tabular results from this mitigation analysis.
29 See Section 5.2.1 for the baseline modeling assumptions applied for the Gateway West and Gateway South"Stage 1"
Projects,as well as the Boardman-to-Hemingway(132H)Project.
30 It should also be noted that with the addition of the Midpoint-Hemingway#2 500 kV line,the definition(and rating)of the
Midpoint West Path would change with this new member branch.
31 Such modified RAS actions may include—but are not limited to—bypassing both series capacitor segments of the
Hemingway-Burns 500 kV line,or alternately,bypassing series capacitors in the surviving Midpoint-Hemingway 500 kV line.
Exhibit No.4 69 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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SWIP-North S2N vs.Path 20+[GWW] S2N
2000 2211,19201
-----------a
c
1800 ; 2250,1895
1843,1920 �
1600 i
i
i
i
1400 i
3 � � 2250,1d33
.2 1200
O
u 1000
Z
N
LA Baseline Simi Analysis
Z 800
a
3 --0--Midpoint Changes/Mitigation
600
400
200 '!
0
0 500 1000 1500 2000 2500
Path 20+[GWW]S2N Flow(MW)
7.13 SWIPN vs. TWE HVDC Project Simultaneous Analysis
This study included a simultaneous analysis between SWIPN and the TransWest Express (TWE) HVDC
Project(Path III-15, referred to as "TWE1" in this report). TransWest Express, LLC achieved a Phase
3/Accepted Rating of 1,500 MW N2S for this path in November 2017.
The TWE HVDC Project represents one of two possible alternatives for the development of the overall
TransWest Express Project: at the time of this SWIP Path Rating Study,the alternative "TWE AC and DC
Project" configuration (also evaluated herein) was the preferred alternative most likely to be pursued.
As such, the TWE Project Sponsor asked that GBT/USE only perform power flow contingency analysis
when conducting the simultaneous analysis for the TWE HVDC Project(TWE1).
The TWE HVDC path is defined as the sum of the flow on the following facilities:
• HVDC bi-pole system from TWE-Wyoming to TWE-Nevada, metered at the Nevada terminal.
This simultaneous analysis evaluated the following conditions for the TWE HVDC Project(TWE1):
• SWIPN N2S vs.TWE HVDC N2S
Power flow cases were developed with TWE1 and SWIPN stressed to their maximum achievable values
to identify any impact/simultaneous interaction between the TWE HVDC Project and SWIPN.
Approximately 50 relevant/critical contingencies for these paths were applied and evaluated through
Exhibit No.4 70 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
post-transient governor power flow (thermal and voltage) analysis.Appendix NTWE1 provides the list of
applied contingencies, as well as detailed tabular results from these analyses.
No simultaneous relationship was observed for the SWIPN (N2S)vs.TWE1 HVDC (N2S) scenario.
7.13.1 Studied Scenarios
The following scenario was developed and studied to identify any impact/simultaneous interaction
between SWIPN and the TWE HVDC Project (TWE1).
• SWIPN N2S and TWE1 HVDC N2S
The latest modeling for the TWE HVDC Project32 and accompanying planned Chokecherry/Sierra
Madre (CCSM) wind generation was provided by the TWE Project Sponsor and added to the 2025
Heavy Summer North-to-South (N2S) Pre-Project and Post-SWIP bases cases. These cases were then
developed to show the TWE1 HVDC Project with 1,500 MW N2S flow. SWIPN was modeled at
2,070 MW N2S in the Post-Project case. Flows on TWE1 were achieved by dispatching new wind
generation at the TWE Wyoming Terminal (total of—1,500 MW from NEVINS, SMITH, MCARTHY, and
PINEGRV(PACE Area 65)), and reducing generation and adjusting the Area interchange schedules for
SCE (Area 24, -1,000 MW), LADWP (Area 26, -250 MW), and APS(Area 14, -250 MW). N2S flow on
SWIPN was maintained via a small change in the Robinson Summit-Falcon 345 kV PST's scheduled
flow and refinement of the Area interchange schedules between Nevada (Area 18) and Idaho (Area
60).
7.13.2 Post-Transient Governor Power Flow Analysis
Please see Appendix NTWE1 for this simultaneous analysis' list of applied contingencies and tabular
results.All the identified contingencies were applied for post-transient governor power flow analysis to
the Pre-and Post-SWIP simultaneous cases described in the previous section.
No simultaneous limitation was observed: results indicate that both SWIPN and TWE1 can
simultaneously achieve their rated flows.The Pre-and Post-SWIP cases (2025 Heavy Summer) were
evaluated for their contingency performance and found to be within acceptable criteria/limits. In the
Post-SWIP case, single line outages(Category P1-2) of either the Bridger-Three Mile Knoll, Bridger-
Populus#1, or Bridger-Populus#2 345 kV lines shows the post-contingency loading of the surviving
circuits to be within these circuits' 30-minute emergency ratings.Additionally,for either a (Category P1-
1) Palo Verde generating unit outage or a (Category P7-2) PDCI Bipole outage,the Midpoint-Robinson
Summit 500 kV southern series capacitor line-side bus ("MPRSSC2")voltage reaches 1.197 per
unit/598.5 kV(less than the 600 kV design limitation).
[Per direction of the TWE Project Sponsor,voltage stability and transient stability analyses were not
performed when studying this variation of the TWE Project.]
32 Modeling for the TWE(1)HVDC Project was derived from the file,"OB-FullBuildout_TWE_AC-DC_Stage_1-1500.epc"
provided by the TransWest Express Project Sponsor in February 2023.This modeling includes a 500 kV HVDC system with
the TWE Wyoming Terminal's AC connection modeled as a 500/345 kV substation(FERRIS)looped into the Aeolus-Anticline
500 kV line(represented without series compensation in the SWIP 25HS cases).Topology at the TWE-NV 500 kV bus
included connections to Mead(WAPA),Marketplace(LADWP),McCullough(LADWP),and Eldorado(SCE/CAISO).
Exhibit No.4 711 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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7.14 SWIPN vs. TWE AC-DC Project Simultaneous Analysis
This study included a simultaneous analysis between SWIPN and the TransWest Express (TWE) AC and
DC Project33. In February 2020,TransWest Express, LLC achieved Phase 3/Accepted Ratings for three
paths associated with this project.
The TWE AC and DC Project represents the second of two possible alternatives for the development of
the overall TransWest Express Project: at the time of this SWIP Path Rating Study,the TWE AC and DC
Project alternative was the preferred/most likely configuration. In this report,the TWE AC and DC
Project is sometimes referred to as "TWE2"to help distinguish this AC-DC configuration from the TWE
HVDC Project alternative ("TWE1").
The TWE AC-DC Project consists of three WECC Paths, each defined as the flow on the following
facilities:
• TWE2 HVDC: bi-pole system from TWE-Wyoming to TWE-Intermountain, metered at TWE-
Intermountain and rated 3,000 MW N2S.
• TWE2 IPP-CRYS AC: 500 kV AC line from TWE-Intermountain to TWE-Crystal, metered at TWE-
Crystal and rated 1,500 MW N2S.
• TWE2 CRYS-TWE_NV AC: 500 kV AC line from TWE-Crystal to "TWE-NV" (a new substation
located in the Eldorado Valley, Nevada), metered at TWE-Crystal and rated at 1,680 MW N2S.
This simultaneous analysis evaluated the following conditions for the TWE AC-DC Project (TWE2):
• SWIPN N2S vs.TWE2 HVDC N2S
• SWIPN N2S vs.TWE2 IPP-CRYS AC N2S
• SWIPN N2S vs.TWE2 CRYS-TWE NV AC N2S
Power flow cases were developed with TWE2 and SWIPN stressed to their maximum achievable values
to identify any impact/simultaneous interaction between the TWE AC-DC Project and SWIPN. Over 50
relevant/critical contingencies for these paths were applied and evaluated through post-transient
governor power flow (thermal and voltage) analysis,transient stability analysis, and reactive margin
analysis.Appendix NTWE2 provides the list of applied contingencies, as well as detailed tabular results
from these analyses.
No simultaneous relationship was observed between SWIPN (N2S) and the three TWE2 AC-DC Project
segments/paths (N2S).
7.14.1 Studied Scenarios
The following scenario was developed and studied to identify any impact/simultaneous interaction
between SWIPN and the TWE AC-DC Project (TWE2).
33 The TWE AC and DC Project consists of three"Phase 3"rated paths numbered as Paths III-18,II-20,and III-21 in the WECC
2022 Path Rating Catalog(numbering subject to change).
Exhibit No.4 72 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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• SWIPN N2S and TWE2 AC-DC N2S
The latest modeling for the TWE AC-DC Project (provided by the TWE Project Sponsor34) was
added to the 2025 Heavy Summer North-to-South (N2S) Pre-Project and Post-SWIP bases cases.
These cases were then developed to show the TWE AC-DC Project with the following flows (all
three stresses coincident):TWE2 HVDC at 3,000 MW N2S,TWE2 IPP-CRYS AC at 1,500 MW N2S,
and TWE2 CRYS-TWE_NV AC at 1,680 MW N2S. For the Post-Project case, SWIPN was modeled
at 2,070 MW N2S. Flows on TWE2 were achieved by dispatching new wind generation at the
TWE Wyoming Terminal (total of—3,000 MW from NEVINS, SMITH, MCARTHY, PINEGRV, and
SEVERSN; PACE Area 65), and reducing generation and adjusting the Area interchange schedules
for SCE (Area 24, -1,000 MW), LADWP (Area 26, -1,000 MW), and SRP (Area 15, -1,000 MW).
Scheduled flow on the IPP DC line was increased from 700 MW to 1500 MW, while output of the
Intermountain generating units 1 and 2 was reduced to near minimum (375 MW each).
Additionally,the Crystal 500 kV and 230 kV PSTs were adjusted to support stressing of the TWE2
Crystal-TWE_NV path. N2S flow on SWIPN was achieved/rebalanced through changes in
generation dispatch and scheduled Area interchange from Nevada (Area 18, +700 MW)to Idaho
(Area 60, 430 MW), Sierra Pacific(Area 64, -210 MW) and PACE (Area 65, -60 MW).
Additionally, adjustments were applied to the Robinson Summit-Falcon and Robinson Summit-
Gonder 345 kV PSTs.
7.14.2 Post-Transient Governor Power Flow Analysis
Please see Appendix NTWE2 for this simultaneous analysis' list of applied contingencies and tabular
results.All the identified contingencies were applied for post-transient governor power flow analysis to
the Pre-and Post-SWIP simultaneous cases described in the previous section.
No simultaneous limitation was observed: results indicate that both SWIPN and all three TWE2 paths
can simultaneously achieve their rated flows.The Pre-and Post-SWIP cases (2025 Heavy Summer) were
evaluated for their contingency performance and found to be within acceptable criteria/limits.
In the Pre-Project and Post-SWIP cases, a Category P1-2 outage of the TWE_Crystal-TWE_NV 500 kV
branch loads the McCullough-Crystal 500 kV line to—99-100%of its emergency rating. In the Post-SWIPN
case, a Category P1-2 outage of the Robinson Summit-Harry Allen 500 kV Line causes one of the mid-line
series capacitor buses ("TWE-SC1A") in the TWE2 IPP-Crystal 500 kV line to reach 1.200 per unit/600 kV
(design limitation). Conversely,for outages of either the TWE2 HVDC (bipole, Category P7-2),TWE2 IPP
345/500 kV Transformer(P1-3), or TWE2 IPP-Crystal 500 kV Line (131-2),the Midpoint-Robinson Summit
500 kV southern series capacitor line-side bus ("MPRSSC2")voltage reaches 1.198-1.199 per unit
(approaching the 600 kV design limitation).
7.14.3 Voltage Stability/Reactive Margin Analysis
For simplicity/conservativism, P1 and P2-P7 outages were tested against a reactive margin case with
SWIPN and the three TWE2 paths' N2S flows simultaneously increased by 5%.All simulated
34 Modeling for the TWE(2)AC-DC Project was derived from the file,"02-14-2023_GE_TWE_AC-DC_3000-LCC-D3.epc"
provided by the TransWest Express Project Sponsor in February 2023.This modeling includes a 500 kV HVDC system with
the TWE Wyoming Terminal's AC connection modeled as a 500/345 kV substation(FERRIS)looped into the Aeolus-Anticline
500 kV line(represented without series compensation in the SWIP 25HS cases).Topology at the TWE-Crystal 500 kV bus
included a connection to the Crystal(South)500 kV bus;topology at the TWE-NV 500 kV bus included connections to Mead
(WAPA), Marketplace(LADWP),McCullough(LADWP),and Eldorado(SCE/CAISO).
Exhibit No.4 73 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
contingencies achieved a converged post-transient governor power flow solution (at their applicable
increased flow levels), demonstrating adequate reactive margin performance.The table below
summarizes the modeled flows on SWIPN and TWE2 for the developed reactive margin case.
Summary of SWIPN vs.TWE2 Reactive Margin Case
Rating +5% Increase Case
Path (MW) (P1-P7 outages applied)
SWIPN N2S (HS case) 2,070 2,173 (+5.0%)
TWE2 HVDC N2S 3,000 3,150 (+5.0%)
...................................................................................----- ............................... ------------
TWE2 IPP-CRYS AC N2S 1,500 1,580 (+5.3%)
TWE2 CRYS-TWE NV AC N2S 1,680 1,768 (+5.2%)
7.14.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPN-TWE2
simultaneous cases. Stability performance of these cases was essentially unchanged as compared to the
SWIP non-simultaneous cases, with generally no new or worsened transient stability performance
concerns.
It is noted here that for simulation of a 3-phase,4-cycle bus fault at Intermountain 345 kV bus followed
by an outage of the TWE-IPP-Intermountain 345 kV Line 1, results showed solution difficulties and
excessive noise/hash in the monitored output parameters (for both the Pre-and Post-SWIP cases, using
GE PSLF version 21.0.10.1). Additional simulations of this outage in GE PSLF version 22.0.4 showed
similar performance (especially for the Pre-Project case):this is considered as either a potential software
processing and/or modeling issue. Because this behavior is observed in the Pre-Project case and is
improved/unchanged in the Post-SWIP condition, this is not regarded as a SWIP-related issue.
7.15 SWIPS vs. Path 24 Simultaneous Analysis
This study included a simultaneous analysis between SWIPS35 and Path 24, "PG&E-Sierra". Path 24 has
an Accepted Rating of 160 MW West-to-East (W2E), and 150 MW East-to-West (E2W).
Path 24 consists of the following branches (asterisk denotes metered end):
• Drum-Summit* 115 kV Line#1
• Drum-Summit* 115 kV Line#2
• Spaulding-Summit* 60 kV Line
Power flow cases were developed with SWIPS and Path 24 stressed to their maximum ratings to identify
any impact/simultaneous interaction between these two paths. Post-transient governor power flow
(thermal and voltage),transient stability, and reactive margin analyses were performed to complete this
assessment. Details of the analyses performed are provided in the following sections.
35 The original SWIP Phase 2 rating study plan envisioned a SWIP-North versus Path 24 simultaneous analysis.This was
changed to a"SWIP-South"simultaneous analysis when development of the simultaneous cases showed SWIP-South's
loading to have a stronger impact/relationship with Path 24.
Exhibit No.4 74 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
This simultaneous analysis attempted to evaluate the following conditions for Path 24:
• Path 24= 150 MW (E2W), with SWIPS = 2,335 MW(N2S) flow
• Path 24= 160 MW(W2E), with SWIPS= 2,245 MW(S2N) flow
For Path 24 E2W and SWIPS N2S, no simultaneous interactions were observed. For this directional
scenario,the Pre-and Post-SWIPS cases could not achieve rated flow for Path 24(flow limited to
71 MW). For Path 24 W2E and SWIPS S2N, no simultaneous interactions/limitations were observed: the
analysis shows that both Path 24 and SWIPS can simultaneously achieve their maximum/rated
capabilities.
Pre-and Post-Project power flow cases were developed with Path 24 and SWIPS stressed to rated (or
maximum achievable)flows,to identify any impact/simultaneous interaction between these paths.
Roughly 30 relevant/critical contingencies were applied and evaluated through post-transient governor
power flow (thermal and voltage) analysis,transient stability analysis, and reactive margin analysis.
Appendix S24 provides the list of applied contingencies, as well as detailed tabular results from these
analyses.
7.15.1 Studied Scenarios
The following scenarios were studied to identify any impact/simultaneous interaction between SWIPS
and Path 24.
• SWIPS N2S and Path 24 E2W
Path 24 E2W cases could not achieve rated flow. Path 24's transfer limit is known to vary between 0-
150 MW depending on local system conditions, especially with respect to the North Tahoe area
load.A Pre-SWIP Path 24 E2W case was developed using the non-simultaneous 2025 Heavy Summer
N2S Pre-Project base case as a starting point. In this case, Path 24 flow of 71 MW E2W was achieved
before realizing a reliability limit; this result was confirmed with PG&E and NV Energy and deemed
acceptable for purposes of the SWIP path rating study. For the Post-Project condition, a
simultaneous power flow case was developed modeling SWIPS flow at 2,335 MW N2S, and with
Path 24 flow at 71 MW E2W.
Path 24 E2W stressing was mainly achieved through schedule changes for the CAL SUB 120 kV PST.
SWIPS N2S rated flow was maintained by adjusting the Robinson Summit-Falcon 345 kV PST, with
smaller adjustments of the Robinson Summit-Gonder 345 kV PST. Flows were further stressed and
tuned by redispatching generation and adjusting exports from Sierra Pacific(Area 64), Idaho (Area
60), and Montana (Area 62) and receiving this power in APS (Area 14), SRP (Area 15), and Nevada
(Area 18).
• SWIPS S2N and Path 24 W2E
For the Path 24 W2E condition, Pre-and Post-SWIP cases were developed from the 2025 Heavy
Winter non-simultaneous cases with Path 24 flow at 160 MW W2E (rated flow).The Post-SWIP
simultaneous case modeled SWIPS flow at 2,245 MW S2N. Path 24 E2W stressing was mainly
achieved through schedule changes for the CAL SUB 120 kV PST. Flows were further stressed and
tuned by redispatching generation and adjusting exports from SRP (Area 15) and APS (Area 14), and
Exhibit No.4 75 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
receiving this power in Idaho (Area 60), Montana (Area 62) and Sierra Pacific (Area 64), and Nevada
(Area 18).
7.15.2 Post-Transient Governor Power Flow Analysis
Please see Appendix S24 for this simultaneous analysis' list of applied contingencies and tabular results.
All of the identified contingencies were applied for post-transient governor power flow analysis of both
the Pre-and Post-SWIP simultaneous cases. Pre-Project cases were analyzed to establish a baseline
performance and/or confirm Path 24's limiting factor(s). In the Post-SWIP cases, no new or worsened
applicable thermal overload or voltage performance concerns were observed: results indicate that Path
24 and SWIPS do not exhibit a simultaneous interaction/limit.
7.15.2.1 SWIPS N2S and Path 24 E2W
For SWIPS N2S versus Path 24 E2W, no simultaneous interaction/limit was observed for the
developed cases. For both the Pre-and Post-SWIPS cases, a Category P1-2 outage of the California-
Summit-Drum 120-115 kV Line#2 causes loading of the California Phase Shifter-North Truckee
120 kV Line#1 to approach 100%of its emergency rating.
7.15.2.2 SWIPS S2N and Path 24 W2E
For SWIPS S2N versus Path 24 W2E, no simultaneous interaction/limit was observed for the
developed cases. In the Post-SWIPS simultaneous case (with SWIPS= 2,245 MW S2N and Path 24=
160 MW E2W), a Category P1-2 outage of the Robinson Summit-Harry Allen 500 kV Line (including
tripping of the Robinson Summit 345 kV shunt capacitor and activation of the Drum-Summit RAS)
results in high emergency loading for the Silver Peak 57.5 kV PST(99.3%of emergency rating) and
for the Marble-Cemetery 63 kV line (98.1%of emergency rating).
7.15.3 Voltage Stability/Reactive Margin Analysis
For the voltage stability/reactive margin analysis, the developed simultaneous cases were further
modified by increasing both SWIPS's and Path 24's path flows by+5%for the "P1 Test" (testing Category
P1 outages for a converged solution).As a conservative approach, additional Category P2-P7 outages
(normally tested against a 2.5% increase in Path flow) were also applied to these 5% increase cases.The
table below summarizes the modeled flows on SWIPS and Path 24 for each of these scenarios.
Summary of SWIPS vs. Path 24 Reactive Margin Cases
PI-P7 Test
Path Rating(MW) (5%increase)
SWIPS N2S(HS case) 2,335 2,456 (+5.2%)
Path 24 E2W (PG&E-Sierra) 7136 75 (+5.6%)
SWIPS S2N (HW case) 2,245 2,358 (+5.0%)
Path 24 W2E (PG&E-Sierra) 160 169 (+5.6%)
36 Path 24 E2W rated flow of 150 MW could not be achieved in the study cases;reactive margin test based upon achievable
flow of 71 MW E2W.
Exhibit No.4 76 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
All of the listed contingencies were simulated on these cases and achieved post-contingency
convergence, indicating adequate reactive margin for the system.
7.15.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPS-Path 24
simultaneous cases. Stability performance of these cases was essentially unchanged as compared to the
SWIP non-simultaneous cases: no new or worsened transient stability performance concerns were
observed.
7.16 SWIPS vs. Path 32 Simultaneous Analysis
This study included a simultaneous analysis between SWIPS and Path 32, "Pavant-Gonder 230 kV;
Intermountain-Gonder 230 W'. (Likewise, a simultaneous analysis was conducted between SWIPN and
Path 32; this is discussed in a previous section.) Path 32 has an Accepted Rating of 500 MW East-to-West
(E2W) and 235 MW West-to-East(W2E). Path 32 consists of the following branches (asterisk denotes
metered end):
• Osceola-(UTAH-NEV*-)Black Rock 230 kV (metered at the Nevada-Utah border)
• Gonder*-Intermountain 230 kV Line
Power flow cases were developed attempting to stress both SWIPS and Path 32 to their maximum
ratings to identify any impact/simultaneous interaction between these two paths. Post-transient
governor power flow(thermal and voltage),transient stability, and reactive margin analyses were
performed to complete this assessment; details of these analyses are provided in the following sections.
This simultaneous analysis attempted to evaluate the following directional scenarios with Path 32:
• Path 32 =500 MW(E2W), with SWIPS = 2,335 MW(N2S) flow
• Path 32 =500 MW(E2W), with SWIPS= 2,245 MW(S2N)flow
• Path 32 = 235 MW(WH),with SWIPS= 2,335 MW(N2S)flow
For Path 32 E2W and SWIPS (both N2S and S2N) at maximized flows, simultaneous
interactions/limitations were observed:the analysis shows that Path 32 E2W and SWIPS cannot
simultaneously achieve their maximum/rated capabilities.These path limitations have been expressed
through hypothetical planning nomograms; further discussion is provided below in the "Post-Transient
Governor Power Flow Analysis" subsections.
Likewise for Path 32 W2E and SWIPS N2S,the analysis shows a simultaneous interaction/limit between
the two paths,which has been quantified through a hypothetical planning nomogram.
Simultaneous power flow cases were developed with SWIPS and Path 32 separately held at their N2S
and E2W ratings while attempting to maximize the alternate path's flow.37 Likewise for the SWIPS S2N
37 Case names,SWIPS N2S vs Path 32 E2W:0-25HS_PRE-SWIP_P32-E2W_v3.sav, 1-25HS_SWIPS-N2S_P32-E2W-cp1_v2.sav,
1-25HS_SW I PS-N2S_P32-E2W-cp2_v2.sav
Exhibit No.4 77 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
condition, simultaneous cases were developed modeling SWIPS and Path 32 each stressed to their
maximum rating,while maximizing the alternate path's flow. Pre-Project versions of these cases were
also developed to help establish the system's benchmark performance prior to the SWIP addition.
For SWIPS N2S and Path 32 W2E, a Post-SWIP power flow case was developed with Path 32 and SWIPS
stressed to their rated flow levels; a Pre-Project version of the Path 32 W2E condition was also
developed to help verify the system's benchmark performance.
Approximately 35 relevant/critical contingencies for these paths were applied and evaluated through
post-transient governor power flow (thermal and voltage) analysis,transient stability analysis, and
reactive margin analysis.Appendix S32 provides the list of applied contingencies, as well as detailed
tabular results from these analyses.
7.16.1 Studied Scenarios
The following scenarios were studied to identify any impact/simultaneous interaction between SWIPS
and Path 32.
• SWIPS N2S and Path 32 E2W
Using the non-simultaneous 2025 Heavy Summer N2S Pre-Project base case, a Pre-SWIP case was
developed modeling Path 32 flow of 500 MW E2W.Two Post-SWIP simultaneous cases were also
developed: one modeling SWIPS flow at 2,335 MW N2S (with restricted/limited Path 32 E2W flow),
and another modeling Path 32 flow of 500 MW E2W(with restricted/limited SWIPS N2S flow).
Stressing for SWIPS and Path 32 was achieved through schedule changes for the Robinson Summit-
Gonder and Robinson Summit-Falcon 345 kV phase-shifting transformers (PSTs). In maximizing and
balancing Path 32 flows,flows through the Robinson Summit-Gonder PST are restricted by loading
of the Gonder 345/230 kV transformers. Generation within Sierra Pacific's Zone 642 ("SPP-EastTie")
was reduced, and the local Spring Valley Wind Generator (Bus#64538) was dispatched at a
minimum output of 15 MW. Flows were further stressed and tuned by redispatching generation and
adjusting exports/imports between Sierra (Area 64), WAPA R.M. (Area 73), Idaho (Area 60), Nevada
(Area 18), LADWP (Area 26), and PacifiCorp-East (Area 65).
• SWIPS S21M and Path 32 E2W
Using the non-simultaneous 2025 Heavy Winter S2N base cases, Pre-and Post-SWIP cases were
developed modeling Path 32 at 500 MW E2W. For the Pre-SWIP case, Path 32 E2W flows were
limited to—435 MW E2W before contingency thermal and voltage concerns were observed.The
Post-SWIPS S2N simultaneous relationship with Path 32 E2W is expressed through three different
cases/nomogram points: one modeling SWIPS flow at 2,245 MW S2N (with restricted/limited Path
32 E2W flow); a second (intermediate) nomogram case with slightly reduced SWIPS flow and slightly
increased Path 32 flow; and a third case modeling Path 32 flow of 500 MW E2W(with
restricted/limited SWIPS S2N flow).Simultaneous stressing for SWIPS and Path 32 was achieved
through schedule changes for the Robinson Summit-Gonder and Robinson Summit-Falcon 345 kV
phase-shifting transformers (PSTs). Schedule adjustments were also applied to the Harry Allen
345 kV PSTs and the Fort Churchill 120 kV PST.The Spring Valley Wind Generator was dispatched at
a minimum output of 15 MW. Flows were further stressed and tuned by redispatching generation
and adjusting exports/imports between San Diego (Area 22), Southern California (Area 24), LADWP
(Area 26), Nevada (Area 18), and PacifiCorp-East (Area 65) Idaho (Area 60), Sierra (Area 64),
Northwest (Area 40), and PG&E (Area 30).
Exhibit No.4 78 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 84 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
• SWIPS N2S and Path 32 W2E
Using the non-simultaneous 2025 Heavy Summer N2S Pre-Project base case, a Pre-SWIP case was
developed modeling Path 32 flow of 235 MW W2E.Two Post-SWIPS simultaneous cases were also
developed: one modeling SWIPS flow at 2,335 MW N2S (with restricted/limited Path 32 W2E flow),
and another modeling Path 32 flow of 500 MW E2W (with restricted/limited SWIPS N2S flow). For
the Pre-Project case, Path 32 W2E flow was primarily achieved by dispatching generation and
adjusting exports from Northwest (Area 40), Idaho (Area 60), Sierra (Area 64)to PacifiCorp-East
(Area 65). Also for Path 32 W2E flow, output from the local Spring Valley Wind Generator(Bus
#64538)was maximized at 150 MW. For the Post-SWIPS cases, simultaneous stressing for SWIPS and
Path 32 was achieved through schedule changes for the Robinson Summit-Gonder 345 kV PST,
Robinson Summit-Falcon 345 kV PST, and the Fort Churchill 120 kV PST. Flows in the post-SWIPS
case were further tuned by redispatching generation and adjusting exports from Sierra (Area 64),
Southern California (Area 24), Idaho (Area 60), and Northwest(Area 40), and receiving this power in
Nevada (Area 18) and PacifiCorp-East(Area 65).
7.16.2 Post-Transient Governor Power Flow Analysis
Please see Appendix S32 for this simultaneous analysis' list of applied contingencies and tabular results.
All of the identified contingencies were applied for post-transient governor power flow analysis of both
the Pre-and Post-SWIP simultaneous cases. Pre-Project cases were analyzed to establish a baseline
performance and/or confirm Path 32's limiting factor(s). Results for the Post-SWIPS cases indicate a
simultaneous relationship between Path 32 (E2W) and SWIPS (N2S and S2N): these two paths cannot
simultaneously achieve their maximum/rated capabilities. However, for the directional scenario of Path
32 W2E versus SWIPS N2S, no simultaneous interaction/limitation was observed.
7.16.2.1 SWIPS N2S and Path 32 E2W
For SWIPS N2S versus Path 32 E2W, a simultaneous interaction/limit is expected between these two
paths.This limitation can be expressed through a hypothetical planning nomogram with two corner
points:
• Path 32 =—425 MW E2W, and SWIPS=2,335 MW N2S (rated flow)
• Path 32= 500 MW E2W (rated flow),SWIPS=—1,620 MW N2S
Power flow contingency analysis shows both nomogram corner points to be limited by a Category
P1-2 ("N-1") outage of the Midpoint-Robinson 500 kV line, resulting in 100%emergency loading of
the Intermountain-Gonder 230 kV line.
Exhibit No.4 79 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 85 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
SWIP-South N2S vs. Path 32 E2
2500
i
425,2335
2000
3
500,1620
p 1500
LL
N
Z
L
a_
1000
500
500,0
0
0 100 200 300 400 50
Path 32 E2W Flow(MW)
7.16.2.2 SWIPS S2N and Path 32 E2W
For SWIPS S2N versus Path 32 E2W, a simultaneous interaction/limit is expected.This limitation can
be expressed through a hypothetical planning nomogram with three corner points:
• Point"1a": Path 32 = 240 MW E2W,SWIPS= 2,245 MW S2N (rated flow). With SWIPS at rated
S2N flow and Path 32 flows of 240 MW E2W,the Fort Churchill 120 kV PST reaches 100% normal
loading.Also, for Category P1-2 ("N-1") outage of the Midpoint-Robinson 500 kV line,
emergency loading of the Robinson Summit-Falcon 345 kV PST reaches 98%.
• Point "1b": Path 32 = 300 MW E2W, SWIPS= 2,170 MW S2N. From Point 1a, further increases in
Path 32 E2W flow can only be accomplished by reducing SWIPS flow. At the intermediate Point
"1b" a P1-2 outage of the Robinson Summit-Harry Allen 500 kV line results in -8.0%voltage
deviations at PacifiCorp-East's Black Rock 230 kV bus. Also,the same concerns observed for
Point "1a" remain in effect:the Fort Churchill 120 kV PST is at 97% normal loading, and a P1-2
outage of the Midpoint-Robinson 500 kV line loads the Robinson Summit-Falcon 345 kV PST to
97%of its emergency rating.
• Point 2: Path 32=500 MW E2W (rated flow), and SWIPS =910 MW S2N. For Path 32 increased
to its rated flow of 500 MW E2W, SWIPS is limited to 910 MW S2N. Under this condition, a
Category P1-2 outage of the Intermountain-Gonder 230 kV line loads the Pavant-Black Rock
230 kV line section to 99%of its emergency rating.
Exhibit No.4 80 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 86 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
SWIP-South S2N vs. Path 32 E2W
2000
3
1500
3
0
LL
Z
N
L
j 1000
O
d
3
Soo
0
0 100 200 300 400
Path 32 E2W Flow(MW)
7.16.2.3 SWIPS N2S and Path 32 W2E
For SWIPS N2S versus Path 32 WLH, a simultaneous interaction/limit is expected between the two
paths.This limitation can be expressed through a hypothetical planning nomogram (shown below)
with two corner points:
• Path 32 =—172 MW W2E, and SWIPS=2,335 MW N2S (rated flow)
• Path 32=235 MW W2E (rated flow),SWIPS=^2,268 MW N2S
Power flow contingency analysis shows both nomogram corner point cases to be limited by a
Category P1-2 ("N-1") outage of the Midpoint-Robinson 500 kV line, resulting in emergency loading
>99%for the Robinson Summit-Falcon 345 kV PST. Additionally for these cases,the Fort Churchill
RAS (tripping local Sierra Pacific generation such as McGuiness) is expected to operate for Category
P1-2 outages of either the Frontier-Machacek or Gonder-Machacek 230 kV lines.
Exhibit No.4 811 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 87 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
SWIP-South N2S vs. Path 32 W2E
2500
z000
3
0 1500
LL
N
z
L
3
O
_a
1000
500
0
0 50 100 150 200 250
Path 32 W2E Flow(MW)
7.16.3 Voltage Stability/Reactive Margin Analysis
For the voltage stability/reactive margin analysis,the nomogram corner point cases were further
modified by increasing both SWIPS's and Path 32's path flows by+5%for the "P1 Test" (testing Category
P1 outages for a converged solution). As a conservative approach, additional Category P2-P7 outages
(normally tested against a 2.5% increase in Path flow)were also applied to these 5% increase cases.The
table below summarizes the modeled flows on SWIPS and Path 32 for each of these scenarios.
Exhibit No.4 82 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 88 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Summary of SWIPS vs. Path 32 Reactive Margin Cases
Rating Nomo. +5% Increase Nomo. +5% Increase
Path (MW) Case 1 (P1-P7 outages applied) Case 2 (131-137 outages applied)
SWIPS N2S (HS case) 2,335 2,335 2,453 (+5.1%) 1,620 1,710 (+5.6%)
---- ---- ---- -...... ..................................................... ......... - ---------
Path 32 E2W 500 425 454 (+6.3%) 500 527 (+5.5%)
SWIPS S2N (HW case) -2,245 -2,24538 -2,358 (+5.0%) -910 -957 (+5.1%)
Path 32 E2W 500 240 254 (+6.1%) 500 528 (+5.6%)
SWIPS N2S(HS case) 2,335 2,335 2,454 (+5.1%) 2,268 2,393 (+5.5%)
Path 32 W2E 1 -235 1 -172 1 -181 (+5.0%) 1 -235 1 -248 (+5.5%)
All of the listed contingencies were simulated on these cases and achieved post-contingency
convergence, indicating adequate reactive margin for the system.
7.16.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPS N2S-Path 32
E2W, SWIPS S2N-Path 32 E2W, and the SWIPS N2S-Path 32 W2E simultaneous cases. Stability
performance of these cases was essentially unchanged as compared to the SWIP non-simultaneous
cases: no new or worsened transient stability performance concerns were observed.
7.17 SWIPS vs. Path 35 Simultaneous Analysis
This study included a simultaneous analysis between SWIPS and Path 35, "TOT 2C, also known as the
Red Butte-Harry Allen 345 W line. Path 35 has an Accepted Rating of 600 MW North-to-South (N2S), and
580 MW South-to-North (S2N). Path 35 consists of the following branch:
• Red Butte-Harry Allen 345 W circuit (metered at the Utah-Nevada border)
Power flow cases were developed with SWIPS and Path 35 stressed to their maximum ratings to identify
any impact/simultaneous interaction between these two paths. Post-transient governor power flow
(thermal and voltage),transient stability, and reactive margin analyses were performed to complete this
assessment. Details of the analyses performed are provided in the following sections.
This simultaneous analysis attempted to evaluate the following conditions for Path 35:
• Path 35 =600 MW(N2S),with SWIPS= 2,335 MW (N2S)flow
• Path 35 = 580 MW(S2N),with SWIPS = 2,245 MW (S2N) flow
For Path 35 and SWIPS at maximized flows (both N2S and S2N), simultaneous interactions/limitations
were observed: the analysis shows that Path 35 and SWIPS cannot simultaneously achieve their
maximum/rated capabilities.These path limitations have been expressed through hypothetical planning
38 Values listed for SWIPS S2114 vs.Path 32 E2W Nomogram Point"1a";see Appendix 5-32 for additional"1b"Reactive Margin
case.
Exhibit No.4 83 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 89 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
nomograms;further discussion is provided below in the "Post-Transient Governor Power Flow Analysis"
subsections.
For the N2S condition simultaneous power flow cases were developed with SWIPS and Path 35
separately held at their N2S rating while the alternate path's flow was maximized. Likewise for the S2N
condition, simultaneous cases were developed modeling SWIPS and Path 35 individually stressed to
their maximum S2N rating,while attempting to maximize the alternate path's flow. Pre-Project versions
of these cases were also developed to help establish the system's benchmark performance prior to the
SWIP addition.
Over 30 relevant/critical contingencies for these paths were applied and evaluated through post-
transient governor power flow(thermal and voltage) analysis, transient stability analysis, and reactive
margin analysis.Appendix S35 provides the list of applied contingencies, as well as detailed tabular
results from these analyses.
7.17.1 Studied Scenarios
The following scenarios were studied to identify any impact/simultaneous interaction between SWIPS
and Path 35.
• SWIPS N2S and Path 35 N2S
The SWIP non-simultaneous 2025 Heavy Summer N2S Pre-Project base case was used as a starting
point. A Pre-Project benchmark case was developed with Path 35 TOT 2C(Red Butte-Harry Allen
345 kV line) at its rated path flow of 600 MW N2S.39 With Path 35 at rated N2S flow, the Harry Allen
345 kV PSTs reach 99.4% of their normal rating,while the Harry Allen 345/230 kV transformers
exhibit a slight overload at 101.8% normal loading.
Two Post-SWIP simultaneous cases were also developed: a "Corner Point 1" case modeling SWIPS
flow at 2,335 MW N2S(with restricted/limited Path 35 N2S flow), and a second "Corner Point 2"
case modeling Path 35 flow of 600 MW N2S (with restricted/limited SWIPS N2S flow). N2S stressing
for SWIPS and Path 35 was achieved in part through schedule changes for the following phase-
shifting transformers (PSTs): Robinson Summit-Falcon 345 kV, Robinson Summit-Gonder 345 kV,
Harry Allen 345 kV, Pinto 345 kV, and Sigurd 230 kV. For the Corner Point 1 case,these changes
were accompanied by increasing generation/exports from Idaho (Area 60), Northwest(Area 40), and
WAPA R.M. (Area 73), and sending this power to both Nevada (Area 18) and PACE (Area 65). For the
Corner Point 2 case, reduced SWIPS flow and maximized Path 35 flow was achieved through
increased generation/exports from Nevada (Area 18), LADWP (Area 26), SRP (15), PACE (Area 65),
and Northwest (Area 40);this power was received/imported into Idaho (Area 60), Sierra Pacific
(Area 64), Montana (Area 62), and PG&E (Area 30).
• SWIPS S2N and Path 35 S2N
Using the non-simultaneous 2025 Heavy Winter S2N base cases, Pre-and Post-SWIP cases were
developed modeling Path 35 at 580 MW S2N. With Path 35 at rated S2N flow, both the Harry Allen
345 kV PSTs and Harry Allen 345/230 kV transformers are fully loaded at 99.2-100.3%of their
normal ratings.
39 Also for this Pre-SWIP case,flows on Path 78 TOT261(Pinto-Four Corners 345 kV line)=507 MW N2S(rated 647 MW),and
Path 79 TOT262(Sigurd-Glen Canyon 230 kV line)=250 MW N2S(rated 265 MW).
Exhibit No.4 84 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 90 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Two Post-SWIP simultaneous cases were developed: a "Corner Point 1" case modeling SWIPS flow at
2,245 MW S2N (with restricted/limited Path 35 S2N flow), and a "Corner Point 2" case modeling
Path 35 flow of 580 MW S2N (with restricted/limited SWIPS S2N flow). S2N stressing for SWIPS and
Path 35 was achieved in part through schedule changes for the following phase-shifting
transformers (PSTs): Robinson Summit-Falcon 345 kV, Robinson Summit-Gonder 345 kV, Harry Allen
345 kV, Pinto 345 kV, and Sigurd 230 kV. For the Corner Point 1 case, these changes were
accompanied by increasing generation/exports from Nevada (Area 18) and Southern California (Area
24), and sending this power northward to PACE (Area 65). For the Corner Point 2 case, reduced
SWIPS flow and maximized Path 35 flow was achieved through added changes to schedule power
from Idaho (Area 60) and Northwest(Area 40), receiving this power in Nevada (Area 18).
7.17.2 Post-Transient Governor Power Flow Analysis
Please see Appendix S35 for this simultaneous analysis' list of applied contingencies and tabular results.
All of the identified contingencies were applied for post-transient governor power flow analysis of both
the Pre-and Post-SWIP simultaneous cases. Pre-Project cases were analyzed to establish a baseline
performance and/or confirm Path 35's limiting factor(s). Results for the Post-SWIPS cases indicate a
simultaneous relationship between Path 35 and SWIPS: these two paths cannot simultaneously achieve
their maximum/rated N2S or S2N capabilities.
7.17.2.1 SWIPS N2S and Path 35 N2S
For SWIPS N2S versus Path 35 N2S, a simultaneous interaction/limit is expected between these two
paths.This limitation can be expressed through a hypothetical planning nomogram with two corner
points:
• Path 35 =315 MW N2S, and SWIPS=2,335 MW N2S (rated flow)
• Path 35=600 MW N2S (rated flow), SWIPS=635 MW N2S
Power flow contingency analysis shows both these points to be limited by a Category P1-2 ("N-111)
outage of the Robinson Summit-Harry Allen 500 kV line, resulting in 100%emergency loading of the
Red Butte-Harry Allen 345 kV line. For the case with Path 35 at 315 MW N2S (Corner Point 1), loss of
the Robinson Summit-Harry Allen 500 kV line requires tripping of the Robinson Summit 345 kV shunt
capacitor to keep the Robinson Summit 500 kV and 345 kV bus voltages within limits; this outage
additionally assumes/requires insertion of PacifiCorp-East's Pinto 138 kV shunt capacitor(one step
of+32 MVAR) to avoid negative voltage deviations (exceeding-8%) at the Pinto 345 kV bus and
various local 138 kV buses including Pinto,Abajo, and Moab.
Exhibit No.4 85 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 91 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
SWIP-South N2S vs. Path 35 N2S
2500
0,2335 315,2335
2000
3 lsoo
0
LL
N
Z
I L
7
N 1000
a_
500 600,635_
0
0 100 200 300 400 500 60
Path 35 N2S Flow(MW)
7.17.2.2 SWIPS S2N and Path 35 S2N
For SWIPS S2N versus Path 35 S2N, a simultaneous interaction/limit is expected.This limitation can
be expressed through a hypothetical planning nomogram with two corner points:
• Path 35 =340 MW S2N,SWIPS=2,245 MW S2N (rated flow). With SWIPS at rated S2N flow and
Path 35 flows up to 340 MW S2N, power flow contingency results show the case to be limited by
a Category P1-2 outage of the Robinson Summit-Harry Allen 500 kV line, resulting in 100%
emergency loading of the Red Butte-Harry Allen 345 kV line; this outage requires tripping of the
Robinson Summit 345 kV shunt capacitor to keep the Robinson Summit 500 kV and 345 kV bus
voltages within limits
• Path 35=580 MW S2N (rated flow), and SWIPS= 500 MW S2N. For Path 35 increased to its
rated flow of 580 MW S2N, SWIPS is reduced/limited to 500 MW S2N. The limiting outage for
this condition is a Category P1-2 outage of the Midpoint-Robinson Summit 500 kV line, resulting
in 99.6%emergency loading of the Red Butte-Harry Allen 345 kV line. (A similar result is
observed for the Robinson Summit-Harry Allen 500 kV line outage, loading the Red Butte-Harry
Allen 345 kV line to 97.6%emergency.)
Exhibit No.4 86 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 92 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
SWIP-South S2N vs.Path 35 S2N
2500
0,2245 340,2245
2000
3
3 1500
o
z
N
N
s
Y
O 1000
d
3
500
580,500
0 100 200 300 400 500 600
Path 3S S2N Flow(MW)
7.17.3 Voltage Stability/Reactive Margin Analysis
For the voltage stability/reactive margin analysis,the nomogram corner point cases were further
modified by increasing both SWIPS's and Path 35's path flows by+5%for the "P1 Test" (testing Category
P1 outages for a converged solution). As a conservative approach, additional Category P2-P7 outages
(normally tested against a 2.5%increase in Path flow)were also applied to these 5% increase cases.The
table below summarizes the modeled flows on SWIPS and Path 35 for each of these scenarios.
Summary of SWIPS vs. Path 35 Reactive Margin Cases
Rating Nomo. +5% Increase Nomo. +5% Increase
Path (MW) Case 1 (P1-P7 outages applied) Case 2 (P1-137 outages applied)
SWIPS N2S (HS case) 2,335 2,335 2,452 (+5.0%) 637 688 (+8.1%)
Path 35 N2S 600 313 332 (+6.0%) 600 631 (+5.2%)
SWIPS S2N (HW case) -2,245 -2,245 -2,358 (+5.1%) -500 -527 (+5.3%)
Path 35 S2N -580 -340 -361 (+6.3%) -579 -614 (+6.0%)
All of the listed contingencies were simulated on these cases and achieved post-contingency
convergence, indicating adequate reactive margin for the system.
7.17.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPS-Path 35 N2S and
SWIPS-Path 35 S2N simultaneous cases. Stability performance of these cases was essentially unchanged
Exhibit No.4 87 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 93 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
as compared to the SWIP non-simultaneous cases: no new or worsened transient stability performance
concerns were observed.
7.18 SWIPS vs. Path 78 Simultaneous Analysis
This study included a simultaneous analysis between SWIPS and Path 78, "TOT 2131", also known as the
Pinto-Four Corners 345 kV line. Path 78 has an Accepted Rating of 647 MW North-to-South (1\12S), and
700 MW South-to-North (S2N). Path 78 consists of the following branch:
• Pinto-Four Corners* 345 kV line (metered at Four Corners)
Power flow cases were developed with SWIPS and Path 78 stressed to their maximum ratings to identify
any impact/simultaneous interaction between these two paths. Post-transient governor power flow
(thermal and voltage),transient stability, and reactive margin analyses were performed to complete this
assessment. Details of the analyses performed are provided in the following sections.
This simultaneous analysis attempted to evaluate the following conditions for Path 78:
• Path 78 = 647 MW(1\12S), with SWIPS = 2,335 MW (N2S)flow
• Path 78 = 700 MW (S2N), with SWIPS = 2,245 MW(S2N) flow
For Path 78 and SWIPS at maximized flows (both N2S and S2N), simultaneous interactions/limitations
were observed: the analysis shows that Path 78 and SWIPS cannot simultaneously achieve their
maximum/rated capabilities.These path limitations have been expressed through hypothetical planning
nomograms;further discussion is provided below in the "Post-Transient Governor Power Flow Analysis"
subsections.
For the N2S condition simultaneous power flow cases were developed with SWIPS and Path 78
separately held at their N2S rating while the alternate path's flow was maximized. Likewise for the S2N
condition, simultaneous cases were developed modeling SWIPS and Path 78 individually stressed to
their maximum S2N rating,while attempting to maximize the alternate path's flow. Pre-Project versions
of these cases were also developed to help establish the system's benchmark performance prior to the
SWIP addition.
Over 30 relevant/critical contingencies for these paths were applied and evaluated through post-
transient governor power flow(thermal and voltage) analysis, transient stability analysis, and reactive
margin analysis.Appendix S78 provides the list of applied contingencies, as well as detailed tabular
results from these analyses.
7.18.1 Studied Scenarios
The following scenarios were studied to identify any impact/simultaneous interaction between SWIPS
and Path 78.
• SWIPS N2S and Path 78 N2S
The SWIP non-simultaneous 2025 Heavy Summer N2S Pre-Project base case was used as a starting
Exhibit No.4 gg 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 94 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
point. A Pre-Project benchmark case was developed with Path 78 TOT 2131 (Pinto-Four Corners
345 kV line) at its rated path flow of 647 MW N2S.40 With Path 78 at rated N2S flow, loading of the
Pinto-Four Corners 345 kV line reaches 99%of its normal rating.
Two Post-SWIP simultaneous cases were also developed: a "Corner Point 1" case modeling SWIPS
flow at 2,335 MW N2S(with restricted/limited Path 78 N2S flow), and a second "Corner Point 2"
case modeling Path 78 flow of 647 MW N2S (with restricted/limited SWIPS N2S flow). N2S stressing
for SWIPS and Path 78 was achieved in part through schedule changes for the following phase-
shifting transformers (PSTs): Robinson Summit-Falcon 345 kV, Robinson Summit-Gonder 345 kV,
Harry Allen 345 kV, Pinto 345 kV, and Sigurd 230 kV. For the Corner Point 1 case,these changes
were accompanied by increasing generation/exports from Idaho (Area 60), Northwest(Area 40), and
WAPA R.M. (Area 73), and sending this power to both Nevada (Area 18) and PACE (Area 65). For the
Corner Point 2 case, reduced SWIPS N2S flow and maximized Path 78 flow was achieved through
increased generation/exports from Nevada (Area 18),SRP (15), Northwest (Area 40), and WAPA
R.M. (Area 73);this power was received/imported into Idaho (Area 60), Sierra Pacific (Area 64), and
PACE (Area 65).
• SWIPS S2N and Path 78 S2N
Using the non-simultaneous 2025 Heavy Winter S2N base cases, a Pre-Project benchmark case was
developed with Path 78 TOT 2131 flow of 700 MW S2N.41 With Path 78 at rated S2N flow, loading of
the Pinto-Four Corners 345 kV line reaches 99+%of its normal rating.
Two Post-SWIP simultaneous cases were developed: a "Corner Point 1" case modeling SWIPS flow at
2,245 MW S2N (with restricted/limited Path 78 S2N flow), and a "Corner Point 2" case modeling
Path 78 flow of 700 MW S2N (with restricted/limited SWIPS S2N flow). S2N stressing for SWIPS and
Path 78 was achieved in part through schedule changes for the following phase-shifting
transformers (PSTs): Robinson Summit-Falcon 345 kV, Robinson Summit-Gonder 345 kV, Harry Allen
345 kV, Pinto 345 kV, and Sigurd 230 kV. For the Corner Point 1 case, these changes were
accompanied by increasing generation/exports from Nevada (Area 18) and Southern California (Area
24), and sending this power northward to PACE (Area 65). For the Corner Point 2 case, reduced
SWIPS flow and maximized Path 78 flow was achieved through added changes to schedule power
from Idaho (Area 60) and Northwest (Area 40), receiving this power in Nevada (Area 18).
7.18.2 Post-Transient Governor Power Flow Analysis
Please see Appendix S78 for this simultaneous analysis' list of applied contingencies and tabular results.
All of the identified contingencies were applied for post-transient governor power flow analysis of both
the Pre-and Post-SWIP simultaneous cases. Pre-Project cases were analyzed to establish a baseline
performance and/or confirm Path 78's limiting factor(s). Results for the Post-SWIPS cases indicate a
simultaneous relationship between Path 78 and SWIPS: these two paths cannot simultaneously achieve
their maximum/rated N2S or S2N capabilities.
40 Also for this Pre-SWIP Path 78 N2S case,flows on Path 35 TOT 2C(Red Butte-Harry Allen 345 kV line)=198 MW N2S(rated
600 MW),and Path 79 TOT262(Sigurd-Glen Canyon 230 kV line)=265 MW N2S(rated 265 MW).
41 For the Pre-SWIP Path 78 S2N case,flows on Path 35 TOT 2C(Red Butte-Harry Allen 345 kV line)=550 MW S2N(rated
580 MW),and Path 79 TOT2B2(Sigurd-Glen Canyon 230 kV line)=300 MW S2N(rated 300 MW).
Exhibit No.4 89 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 95 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
7.18.2.1 SWIPS N2S and Path 78 N2S
For SWIPS N2S versus Path 78 N2S1 a simultaneous interaction/limit is expected between these two
paths.This limitation can be expressed through a hypothetical planning nomogram (shown below)
with two corner points:
• Path 78=—480 MW N2S, and SWIPS= 2,335 MW N2S (rated flow)
• Path 78=647 MW N2S (rated flow),SWIPS= 1,100 MW N2S
Power flow contingency analysis shows both these points to be limited by a Category P1-2 ("N-1")
outage of the Robinson Summit-Harry Allen 500 kV line, resulting in 99-100%emergency loading of
the Pinto-Four Corners 345 kV line. For both Corner Point cases, loss of the Robinson Summit-Harry
Allen 500 kV line requires tripping of the Robinson Summit 345 kV shunt capacitor to keep the
Robinson Summit 500 kV and 345 kV bus voltages within limits. For the Corner Point 1 case (with
maximized SWIPS N2S flow), the Robinson Summit-Harry Allen outage additionally
assumes/requires insertion of PacifiCorp-East's Pinto 138 kV shunt capacitor(one step of+32 MVAR)
to avoid negative voltage deviations (exceeding-8%) at the Pinto 345 kV bus and various local
138 kV buses including Pinto, Abajo, and Moab.
SWIP-South N2S vs. Path 78 N2S
2500 —
480,233;
2000
3
3 1500
0
LL
H
N
Z
L
N
1000
G E1-
Ln
500
0
0 100 200 300 400 500 600
Path 78 N2S Flow(MW)
Exhibit No.4 g0 ( P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 96 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
7.18.2.2 SWIPS S2N and Path 78 S2N
For SWIPS S2N versus Path 78 S2N, a simultaneous interaction/limit is expected.This limitation can
be expressed through a hypothetical planning nomogram (shown below) with two corner points:
• Path 78= 570 MW S2N, SWIPS=2,245 MW S2N (rated flow)
• Path 78=700 MW S2N (rated flow), and SWIPS= 1,345 MW S2N
Power flow contingency results show both these corner point cases to be limited by a Category P1-2
outage of the Robinson Summit-Harry Allen 500 kV line, resulting in 99.5%emergency loading of the
Pinto-Four Corners 345 kV line; this outage also requires tripping of the Robinson Summit 345 kV
shunt capacitor to keep the Robinson Summit 500 kV and 345 kV bus voltages within limits.
SWIP-South S21N vs. Path 78 S2N
2500
570,2245
2000
3
1500
0
LL
z 700,1345
N
s
3 1000
0
d
3
500
700,0
0
0 100 200 300 400 500 600 700
Path 78 S2N Flow(MW)
7.18.3 Voltage Stability/Reactive Margin Analysis
For the voltage stability/reactive margin analysis,the nomogram corner point cases were further
modified by increasing both SWIPS's and Path 78's path flows by+5%for the "P1 Test" (testing Category
P1 outages for a converged solution). As a conservative approach, additional Category P2-P7 outages
(normally tested against a 2.5% increase in Path flow) were also applied to these 5% increase cases.The
table below summarizes the modeled flows on SWIPS and Path 78 for each of these scenarios.
Exhibit No.4 911 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 97 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Summary of SWIPS vs. Path 78 Reactive Margin Cases
Rating Nomo. +5% Increase Nomo. +5% Increase
Path (MW) Case 1 (P1-P7 outages applied) Case 2 (P1-P7 outages applied)
SWIPS N2S (HS case) 2,335 2,335 2,452 (+5.0%) 1,100 1,156 (+5.0%)
---- ---- ---- -....... .................................................................... ---- ----
Path 78 N2S 647 479 505 (+5.4%) 647 682 (+5.5%)
SWIPS S2N (HW case) -2,245 -2,244 -2,358 (+5.1%) -1,345 -1,419 (+5.5%)
Path 78 S2N -700 -571 -600 (+5.2%) -700 -738 (+5.5%)
All of the listed contingencies were simulated on these cases and achieved post-contingency
convergence, indicating adequate reactive margin for the system.
7.18.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPS-Path 78 N2S and
SWIPS-Path 78 S2N simultaneous cases. Stability performance of these cases was essentially unchanged
as compared to the SWIP non-simultaneous cases: no new or worsened transient stability performance
concerns were observed.
7.19 SWIPS vs. Path 79 Simultaneous Analysis
This study included a simultaneous analysis between SWIPS and Path 79, "TOT 2132", also known as the
Sigurd-Glen Canyon 230 kV line. Path 79 has an Accepted Rating of 265 MW North-to-South (1\12S), and
300 MW South-to-North (S2N). Path 79 consists of the following branch:
• Sigurd-Glen Canyon* 230 kV line (metered at Glen Canyon)
Power flow cases were developed with SWIPS and Path 79 stressed to their maximum ratings to identify
any impact/simultaneous interaction between these two paths. Post-transient governor power flow
(thermal and voltage),transient stability, and reactive margin analyses were performed to complete this
assessment. Details of the analyses performed are provided in the following sections.
This simultaneous analysis attempted to evaluate the following conditions for Path 79:
• Path 79 =265 MW(N2S), with SWIPS= 2,335 MW (N2S)flow
• Path 79 = 300 MW(S2N), with SWIPS= 2,245 MW (S2N)flow
For Path 79 and SWIPS at maximized flows (both N2S and S2N), simultaneous interactions/limitations
were observed: the analysis shows that Path 79 and SWIPS cannot simultaneously achieve their
maximum/rated capabilities.These path limitations have been expressed through hypothetical planning
nomograms;further discussion is provided below in the "Post-Transient Governor Power Flow Analysis"
subsections.
For the N2S condition simultaneous power flow cases were developed with SWIPS and Path 79
separately held at their N2S rating while the alternate path's flow was maximized. Likewise for the S2N
condition, simultaneous cases were developed modeling SWIPS and Path 79 individually stressed to
Exhibit No.4 92 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 98 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
their maximum S2N rating,while attempting to maximize the alternate path's flow. Pre-Project versions
of these cases were also developed to help establish the system's benchmark performance prior to the
SWIP addition.
Over 30 relevant/critical contingencies for these paths were applied and evaluated through post-
transient governor power flow(thermal and voltage) analysis, transient stability analysis, and reactive
margin analysis.Appendix S79 provides the list of applied contingencies, as well as detailed tabular
results from these analyses.
7.19.1 Studied Scenarios
The following scenarios were studied to identify any impact/simultaneous interaction between SWIPS
and Path 79.
• SWIPS N2S and Path 79 N2S
The SWIP non-simultaneous 2025 Heavy Summer N2S Pre-Project base case was used as a starting
point. A Pre-Project benchmark case was developed with Path 79 TOT 2132 (Sigurd-Glen Canyon
230 kV line) at its rated path flow of 265 MW N2S42: with Path 79 at its rated N2S flow, loading of
the Sigurd 230 kV phase-shifting transformer(PST) is slightly overloaded at 102%of its normal
rating.
Two Post-SWIP simultaneous cases were also developed: a "Corner Point 1" case modeling SWIPS
flow at 2,335 MW N2S(with restricted/limited Path 79 N2S flow), and a second "Corner Point 2"
case modeling Path 79 flow of 265 MW N2S (with restricted/limited SWIPS N2S flow). N2S stressing
for SWIPS and Path 79 was achieved in part through schedule changes for the following phase-
shifting transformers (PSTs): Robinson Summit-Falcon 345 kV, Robinson Summit-Gonder 345 kV,
Harry Allen 345 kV, Pinto 345 kV, and Sigurd 230 kV. For the Corner Point 1 case,these changes
were accompanied by increasing generation/exports from Idaho (Area 60), Northwest(Area 40), and
WAPA R.M. (Area 73), and sending this power to both Nevada (Area 18) and PACE (Area 65). For the
Corner Point 2 case, reduced SWIPS N2S flow and maximized Path 79 flow was achieved through
increased generation/exports from Nevada (Area 18), Northwest (Area 40), and WAPA R.M. (Area
73);this power was received/imported into Idaho (Area 60) and PACE (Area 65).
• SWIPS S21N and Path 79 S21N
Using the non-simultaneous 2025 Heavy Winter S2N base cases, a Pre-Project benchmark case was
developed with Path 79 TOT 2132 flow of 300 MW S2N.43 With Path 79 at rated S2N flow, loading of
the Sigurd 230 kV phase-shifting transformer(PST) reaches 100%of its normal rating.
Two Post-SWIP simultaneous cases were developed: a "Corner Point 1" case modeling SWIPS flow at
2,245 MW S2N (with restricted/limited Path 79 S2N flow), and a "Corner Point 2" case modeling
Path 79 flow of 700 MW S2N (with restricted/limited SWIPS S2N flow). S2N stressing for SWIPS and
Path 79 was achieved in part through schedule changes for the following phase-shifting
transformers (PSTs): Robinson Summit-Falcon 345 kV, Robinson Summit-Gonder 345 kV, Harry Allen
42 Also for this Pre-SWIP Path 79 N2S case,flows on Path 35 TOT 2C(Red Butte-Harry Allen 345 kV line)=198 MW N2S(rated
600 MW),and Path 78 TOT261(Pinto-Four Corners 345 kV line)=647 MW N2S(rated 647 MW).
43 For the Pre-SWIP Path 79 S2N case,flows on Path 35 TOT 2C(Red Butte-Harry Allen 345 kV line)=550 MW S2N(rated
580 MW),and Path 78 TOT2B1(Pinto-Four Corners 345 kV line)=700 MW S2N(rated 700 MW).
Exhibit No.4 93 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 99 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
345 kV, Pinto 345 kV, and Sigurd 230 kV. For the Corner Point 1 case, these changes were
accompanied by increasing generation/exports from Nevada (Area 18) and Southern California (Area
24), and sending this power northward to PACE (Area 65). For the Corner Point 2 case, reduced
SWIPS S2N flow and maximized Path 79 flow was achieved through added changes to schedule
power from Idaho (Area 60)to Nevada (Area 18).
7.19.2 Post-Transient Governor Power Flow Analysis
Please see Appendix S79 for this simultaneous analysis' list of applied contingencies and tabular results.
All of the identified contingencies were applied for post-transient governor power flow analysis of both
the Pre-and Post-SWIP simultaneous cases. Pre-Project cases were analyzed to establish a baseline
performance and/or confirm Path 79's limiting factor(s). Results for the Post-SWIPS cases indicate a
simultaneous relationship between Path 79 and SWIPS: these two paths cannot simultaneously achieve
their maximum/rated N2S or S2N capabilities.
7.19.2.1 SWIPS N2S and Path 79 N2S
For SWIPS N2S versus Path 79 N2S, a simultaneous interaction/limit is expected between these two
paths.This limitation can be expressed through a hypothetical planning nomogram (shown below)
with two corner points:
• Path 79= 230 MW N2S, and SWIPS=2,335 MW N2S (rated flow)
• Path 79=265 MW N2S (rated flow), SWIPS= 1,465 MW N2S
Power flow contingency analysis shows both these points to be limited by a Category P1-2 ("N-1")
outage of the Robinson Summit-Harry Allen 500 kV line, resulting in 99-100%emergency loading of
the Sigurd 230 kV PST line. For both Corner Point cases, loss of the Robinson Summit-Harry Allen
500 kV line requires tripping of the Robinson Summit 345 kV shunt capacitor to keep the Robinson
Summit 500 kV and 345 kV bus voltages within limits. For the Corner Point 1 case with (maximized
SWIPS flow),the Robinson Summit-Harry Allen outage additionally assumes/requires insertion of
PacifiCorp-East's Pinto 138 kV shunt capacitor(one step of+32 MVAR)to avoid negative voltage
deviations (exceeding-8%) at the Pinto 345 kV bus and various local 138 kV buses including Pinto,
Abajo, and Moab.
Exhibit No.4 94 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 100 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
SWIP-South N2S vs.Path 79 N2S
2500
230,2335
2000
3
Io 1500 -265,1475
.2
N
z
s
n 1000
a_
3
500
0
0 50 100 150 200 300
Path 79 N2S Flow(MW)
7.19.2.2 SWIPS S2N and Path 79 S2N
For SWIPS S2N versus Path 79 S2N, a simultaneous interaction/limit is expected.This limitation can
be expressed through a hypothetical planning nomogram (shown below)with two corner points:
• Path 79 = 285 MW S2N, SWIPS=2,245 MW S2N (rated flow)
• Path 79=300 MW S2N (rated flow), and SWIPS= 1,930 MW S2N
Power flow contingency results show both these corner point cases to be limited by a Category P1-2
outage of the Robinson Summit-Harry Allen 500 kV line, resulting in 99-100%emergency loading of
the Sigurd 230 kV PST; this outage also requires tripping of the Robinson Summit 345 kV shunt
capacitor to keep the Robinson Summit 500 kV and 345 kV bus voltages within limits.
Exhibit No.4 95 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 101 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
SWIP-South S2N vs. Path 79 S2N
2500
2S5,2245
2000
3
3 1500
0
LL
Z
N
H
L
7
1000
a_
500
0
U 50 100 150 200 250 300
Path 79 S2N Flow(MW)
7.19.3 Voltage Stability/Reactive Margin Analysis
For the voltage stability/reactive margin analysis,the nomogram corner point cases were further
modified by increasing both SWIPS's and Path 79's path flows by+5%for the "P1 Test" (testing Category
P1 outages for a converged solution). As a conservative approach, additional Category P2-P7 outages
(normally tested against a 2.5%increase in Path flow)were also applied to these 5% increase cases.The
table below summarizes the modeled flows on SWIPS and Path 79 for each of these scenarios.
Summary of SWIPS vs. Path 79 Reactive Margin Cases
Rating Nomo. +5% Increase Nomo. +5% Increase
Path (MW) Case 1 (P1-P7 outages applied) Case 2 (P1-P7 outages applied)
SWIPS N2S (HS case) 2,335 2,335 2,452 (+5.0%) 1,475 1,549 (+5.0%)
Path 79 N2S 2657 229 241 (+5.0%) 265 280 (+5.6%)
SWIPS S2N (HW case) -2,245 -2,244 -2,358 (+5.1%) -1,931 -2,037 (+5.5%)
Path 79 S2N -300 -284 -303 (+6.9%) -300 -318 (+5.6%)
All of the listed contingencies were simulated on these cases and achieved post-contingency
convergence, indicating adequate reactive margin for the system.
Exhibit No.4 96 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 102 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
7.19.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPS-Path 79 N2S and
SWIPS-Path 79 S2N simultaneous cases. Stability performance of these cases was essentially unchanged
as compared to the SWIP non-simultaneous cases: no new or worsened transient stability performance
concerns were observed.
7.20 SWIPS vs. TWE HVDC Project Simultaneous Analysis
This study included a simultaneous analysis between SWIPS and the TransWest Express (TWE) HVDC
Project(Path III-15, referred to as "TWE1" in this report).TransWest Express, LLC achieved a Phase
3/Accepted Rating of 1,500 MW N2S for this path in November 2017.
The TWE HVDC Project represents one of two possible alternatives for the development of the overall
TransWest Express Project: at the time of this SWIP Path Rating Study,the alternative "TWE AC and DC
Project" configuration (also evaluated herein) was the preferred alternative most likely to be pursued.
As such, the TWE Project Sponsor requested that GBT/USE only perform power flow contingency
analysis when conducting the simultaneous analysis for the TWE HVDC Project (TWE1).
The TWE HVDC path is defined as the sum of the flow on the following facilities:
• HVDC bi-pole system from TWE-Wyoming to TWE-Nevada, metered at the Nevada terminal.
This simultaneous analysis evaluated the following conditions for the TWE HVDC Project (TWE1):
• SWIPS N2S vs.TWE HVDC N2S
Power flow cases were developed with TWE1 and SWIPS stressed to their maximum achievable values
to identify any impact/simultaneous interaction between the TWE HVDC Project and SWIPS.
Approximately 50 relevant/critical contingencies for these paths were applied and evaluated through
post-transient governor power flow (thermal and voltage) analysis.Appendix STWE1 provides the list of
applied contingencies, as well as detailed tabular results from these analyses.
No simultaneous relationship was observed for the SWIPS (N2S)vs.TWE1 HVDC(N2S) scenario.
7.20.1 Studied Scenarios
The following scenario was developed and studied to identify any impact/simultaneous interaction
between SWIPS and the TWE HVDC Project (TWE1).
• SWIPS N2S and TWE1 HVDC N2S
The latest modeling for the TWE HVDC Project44 and accompanying planned Chokecherry/Sierra
Madre (CCSM) wind generation was provided by the TWE Project Sponsor and added to the 2025
44 Modeling for the TWE(1)HVDC Project was derived from the file,"OB-FullBuildout_TWE_AC-DC_Stage_1-1500.epc"
provided by the TransWest Express Project Sponsor in February 2023.This modeling includes a 500 kV HVDC system with
the TWE Wyoming Terminal's AC connection modeled as a 500/345 kV substation(FERRIS)looped into the Aeolus-Anticline
500 kV line(represented without series compensation in the SWIP 25HS cases).Topology at the TWE-NV 500 kV bus
included connections to Mead(WAPA),Marketplace(LADWP), McCullough(LADWP),and Eldorado(SCE/CAISO).
Exhibit No.4 97 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 103 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Heavy Summer North-to-South (N2S) Pre-Project and Post-SWIP bases cases.These cases were then
developed to show the TWE1 HVDC Project with 1,500 MW N2S flow. SWIPS was modeled at
2,335 MW N2S in the Post-Project case. Flows on TWE1 were achieved by dispatching new wind
generation at the TWE Wyoming Terminal (total of—1,500 MW from NEVINS, SMITH, MCARTHY, and
PINEGRV(PACE Area 65)), and reducing generation and adjusting the Area interchange schedules for
SCE (Area 24, -1,000 MW), LADWP (Area 26, -250 MW), and APS(Area 14, -250 MW). N2S flow on
SWIPS was maintained through generation redispatch and adjustment of Area interchange
schedules from Northwest (Area 40)to Nevada (Area 18).
7.20.2 Post-Transient Governor Power Flow Analysis
Please see Appendix STWE1 for this simultaneous analysis' list of applied contingencies and tabular
results.All the identified contingencies were applied for post-transient governor power flow analysis to
the Pre-and Post-SWIP simultaneous cases described in the previous section.
No simultaneous limitation was observed: results indicate that both SWIPS and TWE1 can
simultaneously achieve their rated flows.The Pre-and Post-SWIP cases (2025 Heavy Summer) were
evaluated for their contingency performance and found to be within acceptable criteria/limits. In the
Post-SWIP case, single line outages(Category P1-2) of either the Bridger-Populus#1 or#2 345 kV lines
shows the post-contingency loading of the surviving circuits to be within these circuits' 30-minute
emergency ratings.Additionally, the (Category P1-2) outage of the Robinson Summit-Harry Allen 500 kV
Line requires automatic post-contingency adjustment of the Robinson Summit 500 kV shunt capacitor
bank and coordinated tripping of the Robinson Summit 345 kV shunt capacitor to maintain Robinson
Summit 500 kV and 345 kV post-contingency bus voltages within high limits.
[Per direction of the TWE Project Sponsor,voltage stability and transient stability analyses were not
performed when studying this variation of the TWE Project.]
7.21 SWIPS vs. TWE AC-DC Project Simultaneous Analysis
This study included a simultaneous analysis between SWIPS and the TransWest Express (TWE) AC and
DC Project45. In February 2020,TransWest Express, LLC achieved Phase 3/Accepted Ratings for three
paths associated with this project.
The TWE AC and DC Project represents the second of two possible alternatives for the development of
the overall TransWest Express Project: at the time of this SWIP Path Rating Study,this TWE AC and DC
Project alternative was the preferred/most likely configuration.The TWE AC and DC Project is
sometimes referred to as "TWE2" in this report to help distinguish this AC-DC configuration from the
TWE HVDC Project alternative ("TWE1").
The TWE AC-DC Project consists of three WECC Paths, each defined as the flow on the following
facilities:
45 The TWE AC and DC Project consists of three"Phase 3"rated paths numbered as Paths III-18,II-20,and III-21 in the WECC
2022 Path Rating Catalog(numbering subject to change).
Exhibit No.4 98 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 104 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
• TWE2 HVDC: bi-pole system from TWE-Wyoming to TWE-Intermountain, metered at TWE-
Intermountain and rated 3,000 MW N2S.
• TWE2 IPP-CRYS AC: 500 kV AC line from TWE-Intermountain to TWE-Crystal, metered at TWE-
Crystal and rated 1,500 MW N2S.
• TWE2 CRYS-TWE_NV AC: 500 kV AC line from TWE-Crystal to "TWE-NV" (a new substation
located in the Eldorado Valley, Nevada), metered at TWE-Crystal and rated at 1,680 MW N2S.
This simultaneous analysis evaluated the following conditions for the TWE AC-DC Project (TWE2):
• SWIPS N2S vs.TWE2 HVDC N2S
• SWIPS N2S vs.TWE2 IPP-CRYS AC N2S
• SWIPS N2S vs.TWE2 CRYS-TWE NV AC N2S
Power flow cases were developed with TWE2 and SWIPS stressed to their maximum achievable values
to identify any impact/simultaneous interaction between the TWE AC-DC Project and SWIPS. Over 50
relevant/critical contingencies for these paths were applied and evaluated through post-transient
governor power flow (thermal and voltage) analysis,transient stability analysis, and reactive margin
analysis.Appendix STWE2 provides the list of applied contingencies, as well as detailed tabular results
from these analyses.
No simultaneous relationship was observed between SWIPS (N2S) and the TWE2 HVDC or TWE2 CRYS-
TWE_NV AC segments/paths (N2S).
A simultaneous interaction was observed between SWIPS (N2S) and the TWE2 IPP-CRYS AC path (N2S).
7.21.1 Studied Scenarios
The following scenario was developed and studied to identify any impact/simultaneous interaction
between SWIPS and the TWE AC-DC Project (TWE2).
• SWIPS N2S and TWE2 AC-DC N2S
The latest modeling for the TWE AC-DC Project (provided by the TWE Project Sponsor46) was added
to the 2025 Heavy Summer North-to-South (N2S) Pre-Project and Post-SWIP bases cases.These
cases were then developed to show the TWE AC-DC Project with the following flows (all three
stresses coincident): TWE2 HVDC at 3,000 MW N2S,TWE2 IPP-CRYS AC at 1,500 MW N2S, and TWE2
CRYS-TWE_NV AC at 1,680 MW N2S. Flows on TWE2 were achieved by dispatching new wind
generation at the TWE Wyoming Terminal (total of—3,000 MW from NEVINS, SMITH, MCARTHY,
PINEGRV, and SEVERSN (PACE Area 65)), and reducing generation and adjusting the Area
interchange schedules for SCE (Area 24, -1,000 MW), LADWP (Area 26, -1,000 MW), and SRP (Area
15, -1,000 MW). Scheduled flow on the IPP DC line was increased from 700 MW to 1500 MW, while
output of the Intermountain generating units 1 and 2 was reduced to minimum (350 MW each).
46 Modeling for the TWE(2)AC-DC Project was derived from the file,"02-14-2023_GE_TWE_AC-DC_3000-LCC-D3.epc"
provided by the TransWest Express Project Sponsor in February 2023.This modeling includes a 500 kV HVDC system with
the TWE Wyoming Terminal's AC connection modeled as a 500/345 kV substation(FERRIS)looped into the Aeolus-Anticline
500 kV line(represented without series compensation in the SWIP 25HS cases).Topology at the TWE-Crystal 500 kV bus
included a connection to the Crystal(South)500 kV bus;topology at the TWE-NV 500 kV bus included connections to Mead
(WAPA), Marketplace(LADWP),McCullough(LADWP),and Eldorado(SCE/CAISO).
Exhibit No.4 gg 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 105 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Additionally,the Crystal 500 kV and 230 kV PSTs were adjusted to support stressing of the TWE2
Crystal-TWE_NV path.
Two Post-SWIP simultaneous cases were developed: a "Corner Point 1" case modeling SWIPS flow at
2,335 MW N2S (with restricted/limited N2S flow on the TWE2 IPP-CRYS branch), and a second
"Corner Point 2" case modeling TWE2 IPP-CRYS flow maximized at 1,500 MW N2S (with
restricted/limited SWIPS N2S flow).TWE2 stressing was achieved as described above. N2S flows on
SWIPS for both cases were achieved/rebalanced through changes in generation dispatch and
scheduled Area interchange from Nevada (Area 18, +500-1300 MW) to Idaho (Area 60, -310 to -660
MW), Sierra Pacific (Area 64, 0 to-580 MW) and PACE (Area 65, 0 to-190 MW).Additionally,
adjustments were applied to the Robinson Summit-Falcon and Robinson Summit-Gonder 345 kV
PSTs.
7.21.2 Post-Transient Governor Power Flow Analysis
Please see Appendix STWE2 for this simultaneous analysis' list of applied contingencies and tabular
results.All the identified contingencies were applied for post-transient governor power flow analysis to
the Pre-and Post-SWIP (2025 Heavy Summer) simultaneous cases described in the previous section.
For two of the TWE2 segments (TWE2 HVDC and TWE2 CRYS-TWE_NV AC), no simultaneous relationship
with SWIPS was observed. However, a simultaneous limitation was observed between SWIPS and the
TWE2 IPP-CRYS 500 kV AC segment: these two paths cannot simultaneously achieve their
maximum/rated N2S capabilities.
7.21.2.1 SWIPS N2S and TWE2 IPP-CRYS N2S
For SWIPS N2S versus TWE2 IPP-CRYS N2S, a simultaneous interaction/limit is expected between
these two paths.This limitation can be expressed through a hypothetical planning nomogram with
two corner points:
• TWE2 IPP-CRYS=—1,330 MW N2S, and SWIPS=2,335 MW N2S (rated flow)
• TWE2 IPP-CRYS=—1,500 MW N2S (rated flow), SWIPS=—1,475 MW N2S
Power flow contingency analysis shows both these points to be limited by a Category P1-2 ("N-111)
outage of the Robinson Summit-Harry Allen 500 kV line, causing the mid-line series capacitor bus
("TWE-SC1A") in the TWE2 IPP-Crystal 500 kV line to reach 1.200 per unit/600 kV(design limitation).
Also for the Post-SWIPS cases, the Category 137-2 outage of the Harry Allen-Mead and Harry Allen-
Eldorado 500 kV lines results in the Crystal 500 kV PSTs reaching 100%of their emergency ratings.
For both the Pre-and Post-SWIP cases, a Category 131-2 outage of the TWE_Crystal-TWE_NV 500 kV
branch loads the McCullough-Crystal 500 kV line to—99-100%of its emergency rating.
Exhibit No.4100 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 106 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
SWIP-South N2S vs. TWE2 IPP-Crystal AC N2S
2500
1330,2335
2000
3
p 1500
LL 1500,1475
N
Z
t
Y
3
0
1000
d
3
LA
500
1150.,
0
0 250 500 750 1000 1250 1500
TWE2 IPP-Crystal AC N2S Flow(MW)
7.21.3 Voltage Stability/Reactive Margin Analysis
For the voltage stability/reactive margin analysis,the nomogram corner point cases were further
modified by increasing both SWIPS's and TWE2's path flows by+5%for the "P1 Test" (testing Category
P1 outages for a converged solution). As a conservative approach, additional Category P2-P7 outages
(normally tested against a 2.5% increase in Path flow)were also applied to these 5% increase cases.All
simulated contingencies achieved a converged post-transient governor power flow solution (at their
applicable increased flow levels), demonstrating adequate reactive margin performance.The table
below summarizes the modeled flows on SWIPS and TWE2 for the developed reactive margin cases.
Summary of SWIPS vs.TWE2 Reactive Margin Case
Rating Nomo. +5% Increase Nomo. +5%Increase
Path (MW) Case 1 (131-137 outages) Case 2 (PI-P7 outages)
SWIPN N2S (HS case) 2,335 2335 2,454 (5.1%) 1745 1,833 (5.0%)
TWE2 HVDC N2S 3,000 3001 3,150 (+5.0%) 3001 3,150 (+5.0%)
................................................................................................ ............................... .............................. ................................................................... .............................. ....................................................................
TWE2 IPP-CRYS AC N2S 1,500 1330 1,396 (+5.0%) 1500 1,576 (+5.1%)
.................................................................................................. .................................... .............................
TWE2 CRYS-TWE_NV AC N2S 1,680 1680 1 1,769 (+5.3%) 1680 1,772 (+5.5%)
7.21.4 Transient Stability Analysis
Transient stability simulations of all the listed contingencies were applied to the SWIPS-TWE2
simultaneous cases. Stability performance of these cases was essentially unchanged as compared to the
Exhibit No.41011 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
SWIP non-simultaneous cases, with generally no new or worsened transient stability performance
concerns.
It is noted here that for simulation of a 3-phase,4-cycle bus fault at Intermountain 345 kV bus followed
by an outage of the TWE-IPP-Intermountain 345 kV Line 1, results showed solution difficulties and
excessive noise/hash in the monitored output parameters (for both the Pre-and Post-SWIP cases, using
GE PSLF version 21.0.10.1). Additional simulations of this outage in GE PSLF version 22.0.4 showed
similar performance (especially for the Pre-Project case), and is considered as either a potential
software processing and/or modeling issue. Because this behavior is observed in the Pre-Project case
and is improved/unchanged in the Post-SWIP condition,this is not regarded as a SWIP-related issue.
8 SENSITIVITY ANALYSIS RESULTS
This SWIP Phase 2 Rating Study included two Sensitivity analyses: one testing the impact to SWIPN of
adding the Cross-Tie Transmission Project ("CTTP",the Clover-Robinson Summit 500 kV line); and
another testing SWIPN S2N flow against Lava Ridge output (wind generation connecting at Idaho
Power's Midpoint 500 kV bus).
8.1 Cross-Tie Transmission Project Sensitivity Analysis
For informational purposes,this SWIP path rating study included a Sensitivity analysis of SWIPN with the
addition of the Cross-Tie Transmission Project (CTTP).This Sensitivity analysis is only intended to provide
information to the requesting party; mitigation measures are not required for any identified
performance concerns, and this analysis is not required to complete Phase 2 of the WECC Path Rating
Process.
The Cross-Tie Transmission Project primarily consists of a new 213-mile Clover-Robinson Summit 500 kV
line (70%series compensated, with 35% at each line end). Both CTTP and SWIP were engaged in Phase 2
of the WECC Path Rating Process at the same time, with CTTP seeking an approved bi-directional Path
Rating of 1,500 MW (east-to-west (E2W) and west-to-east (W2E)).The expected in-service date for CTTP
is Q4 2026.
This Sensitivity analysis evaluated the following conditions for SWIPN and CTTP:
• SWIPN =2070 MW(N2S) flow with the addition of CTTP
• SWIPN = 1920 MW(S2N) flow with the addition of CTTP
Per the PRG-approved SWIP Phase 2 Rating study plan, CTTP was not normally modeled in the SWIP
path rating study cases. For this Sensitivity study, CTTP was added to both the SWIPN 2025 Heavy
Summer North-to-South (N2S) and 2025 Heavy Winter South-to-North (S2N) non-simultaneous cases.
(Conversely,TransCanyon's CTTP path rating study did not normally model SWIPN, but included two
Sensitivity variations modeling SWIPN in their 2027 Heavy Summer and 2027 Heavy Winter study cases.)
It should also be noted that the SWIP 2025 cases are fairly sparse in modeling potential new/other
generation and transmission projects: it is expected that if/when both SWIP and Cross-Tie were to co-
exist,the region's topology would likely include other new proposed generation resources and
accompanying/complementary transmission reinforcements not modeled in this Sensitivity Analysis.
Exhibit No.4102 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
Such changes may mitigate potential reliability concerns identified herein, and/or affect the observed
interaction between these two Paths.
The Sensitivity analysis results imply that coexistence of SWIPN and CTTP could potentially affect these
paths' flowability.After adding CTTP to the SWIPN case, SWIPN flow was reduced and required
additional effort to re-stress SWIPN back to its non-simultaneous limits. However, due to uncertainty in
future generation dispatch and timing of transmission projects under development in this region,these
results are subject to change. It is recommended that any simultaneous relationship between these two
paths should be revisited by the relevant Transmission Operators under the normal operational planning
processes closer to the projects' in-service dates.
For the SWIPN N2S 2025 Heavy Summer case, addition of the Cross-Tie project(without further
adjustment) reduces the flow on SWIPN from 2,070 MW to 1,259 MW N2S, while Cross-Tie initially loads
to 1,101 MW E2W.To help re-establish SWIPN N2S flow, a large proxy generator was added at the
Midpoint 500 kV bus and dispatched at 1,025 MW.This proxy generator represents potential new
injections at the Midpoint bus, provided either through future transmission projects like Gateway West,
and/or other new generation resources.47
Generation and Area interchanges were then rescheduled to restore SWIPN's rated N2S flow of
2,070 MW. Generation was increased by—+1,000-1,100 MW each in Idaho (Area 60), Northwest (Area
40), and PG&E (Area 30), with corresponding generation decreases/offsets of approximately-300 MW in
Nevada (Area 18), -1,500 MW in PACE (Area 65), and -1,300 MW in APS (Area 14).The resulting case
shows SWIPN flow of 2,070 MW N2S and Cross-Tie flow of 1,049 MW E2W,with SWIPS flows of
2,308 MW N2S (99%of rating). Additionally, several other WECC Paths are at or near their limits for this
case: Path 20 N2S flow at 100% (existing definition, rated 1,600 MW N2S); Path 32 W2E flow at 100%
(rated 235 MW W2E), and Path 66 COI N2S flow at 99.5% (5,100 MW N2S rating).The following table
summarizes the resulting achieved Path flows:
Cross-Tie Sensitivity SWIPN N2S Case, Change in Path Flows(MW)
SWIPN N2S SWIPN N2S
SWIPN N2S w/Cross- w/Cross-
Non-Simi. Tie Tie
change (re-stressed)
SWIPN (N2S): 2,070 -811 1,259 2,070
------------------------------------------------------------------------------------------------------------- ------------------------------------------ ..... ...........................................
SWIPS (N2S): 1,869 +327 2,196 2,308
...................................................................................................................................... .
Cross-Tie (E2W): - +1,101 1,101 1,049
For the SWIPN S2N 2025 Heavy Winter case,the initial addition of the Cross-Tie project reduces the
SWIPN S2N flow from -1,920 MW to-1,698 MW, while Cross-Tie initially loads to 429 MW W2E.
Generation and Area interchanges were then rescheduled to restore SWIPN's rated S2N flow
of-1,920 MW. Generation was increased by—225 MW in Nevada (Area 18) and 400 MW in PacifiCorp
East (Area 65), with corresponding generation decreases/offsets of approximately-100 MW in
Northwest (Area 40) and -525 MW in Idaho (Area 60). For the re-stressed case with SWIPN at rated S2N
47 As of February 2023,Idaho Power's generation interconnection queue listed>2,000 MW additional generation(besides
Lava Ridge)connecting at Midpoint by 12/31/2025.
Exhibit No.4103 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
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Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
flow, Path 66 COI (rated -3,675 MW S2N) reaches a S2N flow of-3,637 MW (99%).The following table
summarizes the resulting achieved Path flows:
Cross-Tie Sensitivity SWIPN S21\1 Case, Change in Path Flows(MW)
SWIPN S21\1 SWIPN S21\1
SWIPN S2N w/Cross- w/Cross-
Non-Simi. Tie Tie
change (re-stressed)
SWIPN (S2N): -1,920 -222 -1,698 -1,920
......................................................................................................................................................... -
SWIPS (S2N): -1,984 -191 -2,175 -2,122
Cross-Tie (W2E): - -429 -429 -366
Power flow analysis of over 430 outages (see Appendix B contingency list, plus the outage of the Cross-
Tie Project itself) was applied to all the developed Cross-Tie Sensitivity cases; tabular thermal and
voltage results can be found in Appendix zNCT.
8.2 Lava Ridge Generation Sensitivity Analysis
For informational purposes,this SWIP path rating study included a Sensitivity analysis of SWIPN
(operating south-to-north)versus Lava Ridge generation output.This Sensitivity analysis is only intended
to provide information to the requesting party; mitigation measures are not required for any identified
performance concerns, and this analysis is not required to complete Phase 2 of the WECC Path Rating
Process.
Lava Ridge is a 1,050 MW wind farm interconnecting at the Midpoint 500 kV bus. Lava Ridge was
modeled in the SWIP path rating study cases; this generation is usually modeled as off-line in the SWIPN
2025 Heavy Winter south-to-north (S2N) non-simultaneous cases.
As outlined in the study plan,this Sensitivity analysis utilized the 2025 Heavy Winter case to evaluate the
following conditions for SWIPN and Lava Ridge:
• SWIPN = 1,920 MW (S2N)flow, with Lava Ridge dispatched until a limit is reached
• Lava Ridge = 1,050 MW output, with SWIPN S2N flow maximized until a limit is reached
For the first condition, SWIPN flow was held at 1,920 MW S2N while Lava Ridge was dispatched until a
limit was reached. Lava Ridge was offset by reducing generation in Northwest(Area 40)to keep SWIPN
S2N flow maximized at 1,920 MW S2N. With Lava Ridge output of—55 MW,the N-1 loss of the
Midpoint-Hemingway 500 kV line was observed to fully load the Midpoint 500/345 kV transformer.
For the second condition, Lava Ridge was dispatched at its maximum output of 1,050 MW while
simultaneously adjusting SWIPN S2N flow until a reliability limit was reached. For this scenario,
increased Lava Ridge dispatch (in Idaho Area 60) was offset by reducing generation in Nevada (Area 18).
With Lava Ridge output of 1,050 MW and reduced SWIPN flow of 1,104 MW S2N,the N-1 loss of the
Midpoint-Hemingway 500 kV Line fully loads the Midpoint 500/345 kV transformer.
Exhibit No.4104 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 110 of 111

Southwest Intertie Project Phase 2 Rating Report-FINAL June 2023
The following table summarizes SWIPN S2N flow and Lava Ridge output for the two cases studied:
Lava Ridge Sensitivity: SWIPN S2N Flow and Lava Ridge Output(MW)
SWIPN S2N Lava Ridge
Maximized Output
Maximized
SWIPN (S2N): 1920 1104
Lava Ridge Output: 55 1050
Power flow analysis of the full contingency list (Appendix B) was applied to all the developed Lava Ridge
Sensitivity cases; tabular thermal and voltage results can be found in Appendix zNLR.
For the studied case topology and conditions, SWIPN and Lava Ridge represent injections into the
Midpoint 500 kV bus, with only two other outlet facilities:the Midpoint-Hemingway 500 kV line and the
Midpoint 500/345 kV transformer.The Sensitivity results show that as the combined SWIP+ Lava Ridge
injections reach 2,000-2,100 MW, loss of the Midpoint-Hemingway 500 kV line is expected to impact the
Midpoint 500/345 kV transformer, and vice-versa. Idaho Power has proposed a near-term plan for
adding a second Midpoint 500/345 kV transformer; however, it is expected that this reinforcement
alone would not significantly change these results, as the Midpoint 3451230 kV transformers would
likely become the next limiting facility for the N-1 loss of the Midpoint-Hemingway 500 kV line. Other
proposed future projects in the Midpoint vicinity (namely the Midpoint-Cedar Hill and Midpoint-
Hemingway 500 kV lines) are anticipated to further mitigate these contingency concerns and help
reduce the Midpoint 345/230 kV transformers' loading.
Exhibit No.4105 1 P a g e
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 111 of 111

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-08
IDAHO POWER COMPANY
ELLSWORTH, DI
TESTIMONY
CONFIDENTIAL
EXHIBIT NO. 5

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-08
IDAHO POWER COMPANY
ELLSWORTH, DI
TESTIMONY
EXHIBIT NO. 6

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Exhibit No.6
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 1 of 1

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-08
IDAHO POWER COMPANY
ELLSWORTH, DI
TESTIMONY
EXHIBIT NO. 7

Desert Southwest Market Depth
Historical Desert Southwest Summer and Winter
Seasonal Peaks
35,000
30,000
25,000 ^' 14,1000 M W
20,000
15,000
10,000
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019 2020 2021 2022 2023
Desert Southwest Summer Peak Desert Southwest Winter Peak
* 2023 FERC Form 714 BAA Data: Desert Southwest =Arizona Public Service+Salt River Project+Tucson Electric Power+ Nevada Energy(Southern Area)+
WAPA Lower Colorado+ Public Service New Mexico + El Paso Electric
Exhibit No.7
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 1 of 1

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-08
IDAHO POWER COMPANY
ELLSWORTH, DI
TESTIMONY
EXHIBIT NO. 8

SEE ATTACHED POWERPOINT
PRESENTATION

BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. IPC-E-25-08
IDAHO POWER COMPANY
ELLSWORTH, DI
TESTIMONY
EXHIBIT NO. 9

January 2024 Winter Weather Event:
Regional Net Imports & Exports, 4 PM — 8 PM
BCHA • AESO
PSEI I I GWA
SCL GCPO I I
TPWR A I �� WAUW
I �
P
IPCO
PA
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i
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I
65 1 +239
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11 SRP I
1
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TEPC 1
HGMA I
GRMA
-312 DEAAI
Source: Analysis of the January 2024 Winter Weather Event.
Exhibit No.9
Case No. IPC-E-25-08
J. Ellsworth, IPC
Page 1 of 1