20240531Direct R. Vail.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. PAC-E-24-04
OF ROCKY MOUNTAIN POWER FOR )
AUTHORITY TO INCREASE ITS RATES ) DIRECT TESTIMONY OF
AND CHARGES IN IDAHO AND ) RICHARD A. VAIL
APPROVAL OF PROPOSED )
ELECTRIC SERVICE SCHEDULES AND
REGULATIONS
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-24-04
May 2024

1 I . INTRODUCTION AND QUALIFICATIONS
2 Q. Please state your name, business address, and current
3 position with PacifiCorp d/b/a Rocky Mountain Power
4 ("PacifiCorp" or the "Company") .
5 A. My name is Richard A. Vail . My business address is 825
6 NE Multnomah Street, Suite 1600, Portland, Oregon 97232 .
7 I am the Vice President of Transmission at PacifiCorp.
8 I am responsible for transmission system planning,
9 customer generator interconnection requests and
10 transmission service requests, regional transmission
11 initiatives, capital budgeting for transmission,
12 transmission and distribution project delivery, and
13 administration of the Company' s Open Access Transmission
14 Tariff ("OATT") .
15 Q. Please describe your education and professional
16 experience.
17 A. I have a Bachelor of Science degree with Honors in
18 Electrical Engineering with a focus in electric power
19 systems from Portland State University. I have been Vice
20 President of Transmission for PacifiCorp since December
21 2012 . I was Director of Asset Management from 2007 to
22 2012 . Before that position, I had management
23 responsibility for a number of organizations in
24 PacifiCorp' s asset management group including capital
Vail, Di 1
Rocky Mountain Power

1 planning, maintenance policy, maintenance planning, and
2 investment planning since joining PacifiCorp in 2001 .
3 II . PURPOSE OF TESTIMONY
4 Q. What is the purpose of your direct testimony in this
5 case?
6 A. The purpose of my testimony is to describe PacifiCorp' s
7 transmission system and the benefits it provides to
8 Idaho customers, and specifically describe PacifiCorp' s
9 major capital investments for new transmission systems
10 included in this rate case . These investments include
11 transmission projects associated with Energy Vision
12 2024, including Gateway South, Gateway West Segment D. 1,
13 Gateway South Supporting projects, and related
14 generation interconnection network upgrades, and a new
15 14-mile, 345 kilovolt ("kV") transmission line.
16 My testimony demonstrates that the Company' s
17 decisions result in an immediate benefit to PacifiCorp' s
18 Idaho customers, and I recommend that the Idaho Public
19 Utilities Commission ("Commission") find these
20 investments are prudent .
21 III . OVERVIEW OF PACIFICORP' S TRANSMISSION SYSTEM
22 Q. What is the purpose of this section of your testimony?
23 A. I provide an overview of PacifiCorp' s transmission
24 system, transmission reliability requirements, and
25 standards and compliance mechanisms .
Vail, Di 2
Rocky Mountain Power

1 Q. Please provide a brief overview of the purpose of
2 PacifiCorp' s transmission system.
3 A. PacifiCorp' s transmission system is designed to reliably
4 transfer affordable electric energy from a broad array
5 of generation resources to loads both within the
6 Company' s balancing authority areas ("BAAs") and beyond,
7 including other BAAs that PacifiCorp interconnects with,
8 and participants in the California Independent System
9 Operator' s ("CAISO") Western Energy Imbalance Market
10 ("WEIM") .
11 Q. Please briefly describe PacifiCorp' s transmission
12 system.
13 A. As seen in the image below, PacifiCorp owns and operates
14 approximately 17, 770 miles of transmission lines ranging
15 from 46 kV to 500 kV across multiple western states .
16 PacifiCorp serves nearly two million customers with over
17 91, 000 customers located in Idaho .
Vail, Di 3
Rocky Mountain Power

Figure 1
PACIFICORP TRANSMISSION ROUTES
WASHING,-TON
T M<Nary M O N TA N A
/.-•Bo■ardman �� \Tula
H
O
0
�� ■ PacifiCorp service area
O R E G O N G A T E W AY O Coal facilities
Hemingway ,D A H O WEST .
■ Natural gas facilities
■ Midpoim, W YO M I N G W;ndstar
E eoran D.i Geothermal plant
■ Bridger/ Shirley Basin
Cedar Hill �o ufus D 3 Anti line D.2 Aeolus l ■ Hydro systems
<a B O 0 A Wind facilities
Terming 10
ti Z Limber Oquirrh go ■ Solar facilities
CALIFORNIA uu c F �Pr 00 O Customer-supported
N E VA DA Ple renewable resources
G
Mona 0 — PacifiCorp-owned primary
!Sigurd 00 C O L O R A D O transmission lines
U TA H ••• Transmission access
Red Butte New transmission lines:
—500 kV minimum voltage
—345 kV minimum voltage
—230 kV minimum voltage
A R I Z O N A • Existing substation
NEW M E X I C O O New substation
Resources depicted represent PacifiCorp's anticipated 2023 owned and customer-enabled purchase portfolio as identified in Its 20191megrated
Resource Plan.By the end of 2029,costs from coal-fired resources will not be included in rates for OR,WA and CA customers.
1 Q. What are Balancing Authorities and BAAs?
2 A. A Balancing Authority is the entity responsible for
3 maintaining balance of load, generation, and interchange
4 in a specific BAA, and supports interconnection
5 frequency in real time. BAAs include all the generation,
6 transmission, and loads within a specific metered
7 region.
Vail, Di 4
Rocky Mountain Power

1 PacifiCorp is a Balancing Authority and manages two
2 BAAs : PacifiCorp East ("PACE") BAA and PacifiCorp West
3 ("PACW") BAA. The PACE BAA interconnects with utilities
4 in the intermountain west and southwest, and also
5 provides access to the southern portion of the CAISO.
6 The PACE BAA interconnects with utilities in Montana,
7 Idaho, Nevada, Arizona, Colorado, and Wyoming. The PACW
8 BAA includes interconnections with the Bonneville Power
9 Administration ("BPA") , northern points of CAISO, and
10 other utilities in California, Oregon, and Washington.
11 As a Balancing Authority, PacifiCorp manages the
12 production and consumption of electricity in these
13 areas, by ensuring that there are adequate and available
14 generation resources or electricity transfers from other
15 BAAs to meet load. As seen in the figure below, there
16 are 38 BAAs in the Western Interconnection. '
' Available at https://www.wecc.org/Administrative/06-
Balancing%20Authority%200verview.pdf.
Vail, Di 5
Rocky Mountain Power

Figure 2
Boundaries are approximate and for Western Interconnection Balancing Authorities(38)
illustrative purposes only. AESO Alberta Electric System Operator
AVA-Avista Corporation
AZPS-Arizona Public Service Company
BANC-Balancing Authority of Northern California
BCHA-British Columbia Hydro Authority
BPAT-Bonneville Power Administration-Transmission
CFE-Comision Federal de Electricidad
CHPD-PUD No.1 of Chelan County
CISO-California Independent System Operator
DEAR-Arlington Valley,LLC
DOPD-PUD No.1 of Douglas County
EPE-El Paso Electric Company
GCPD-PUD No.2 of Grant County
sa GRID-Gridforce
TPWR GRIF Griffith Energy,LLC
Doto GRMA-Sun Devil Power Holdings,LLC
QGWA-NaturEner Power Watch,LLC
HGMA-New Harquahala Generating Company,LLC
III)-Imperial Irrigation District
IPCO-Idaho Power Company
LDWP-Los Angeles Department of Water and Power
NEVP-Nevada Power Company
NWMT-North Western Energy
PACE-PacifiCorp East
PACW-PacifiCorp West
PGE-Portland General Electric Company
PNM-Public Service Company of New Mexico
R - PSCO-Public Service Company of Colorado
PSEI-Puget Sound Energy
SCL-Seattle City Light
SRP-Salt River Project
TEPC-Tucson Electric Power Company
TIDC-Turlock Irrigation District
TPWR-City of Tacoma,Department of Public Utilities
WACM-Western Area Power Administration,Colorado-Missouri Region
WECC
WALL-Western Area Power Administration,Lower Colorado Region
WAUW-Western Area Power Administration,Upper Great Plains Wes[
WWA-NaturEner Wind Watch,LLC
1 Q. How does PacifiCorp operate the two BAAs?
2 A. PacifiCorp separately balances each BAA for energy and
3 load. To optimize dispatch for the benefit of customers,
4 PacifiCorp dispatches generation across both BAAs to
5 serve load across the entire system. Deliveries of
6 energy over PacifiCorp' s transmission system are managed
7 and scheduled in accordance with the Federal Energy
8 Regulatory Commission' s ("FERC") requirements . The
9 flexibility of PacifiCorp' s integrated transmission
10 system provides options for optimizing dispatch to serve
Vail, Di 6
Rocky Mountain Power

1 load and designating units for holding reserves, and
2 provides for additional reliability during planned or
3 unplanned generation outages . PacifiCorp also provides
4 transmission service across both BAAs, meaning that a
5 transmission customer can purchase transmission service
6 from any point in one BAA to the other BAA, for a single
7 tariff rate .
8 Q. Please describe PacifiCorp' s responsibility for
9 maintaining open access to its transmission system and
10 creating stakeholder transmission planning processes .
11 A. In 1996, the FERC required transmission system owners
12 like PacifiCorp to provide non-discriminatory access to
13 their transmission systems for all transmission
14 customers .2 FERC expanded this open-access policy in 2011
15 by requiring transmission system owners to create
16 regional, inter-regional, and local transmission
17 planning processes .3
18 Under these authorities, the Company is required to
19 provide non-discriminatory and reliable transmission and
20 interconnection service according to the rates, terms,
21 and conditions of PacifiCorp' s OATT, and must engage in
22 participant-driven planning processes covering its six-
2 In re Open Access Transmission Services, Order No. 888, 75 FERC q 61, 080
(May 10, 1996) .
3 In re Transmission Planning and Cost Allocation, Order No. 1000, 136
FERC 1 61, 051 (Jul. 21, 2011) .
Vail, Di 7
Rocky Mountain Power

1 state transmission footprint . 4 These planning processes
2 incorporate economics, reliability, and public policy
3 inputs and requirements to develop comprehensive
4 transmission development strategies . 5
5 Where a request for transmission service cannot be
6 reliably provided on the existing system, the Company' s
7 OATT and FERC policies require the Company to construct
8 and expand its system to provide FERC-jurisdictional
9 transmission and interconnection service . 6 This
10 obligation to construct transmission facilities in
11 response to transmission or interconnection service
12 requests applies to both newly identified facilities and
n PacifiCorp's Open Access Transmission Tariff Volume No. 11, (updated
Apr. 15, 2024) (available
https://www.oasis.oati.com/woa/docs/PPW/PPWdocs/20240415 OATTMaster.pdf
5 Id. at Attachment K. ; see, e.g. , PacifiCorp's Local Transmission System
Plan (2022-2023 Biennial Cycle) (Dec. 31, 2023) (available
https://www.oasis.oati.com/woa/docs/PPW/PPWdocs/PacifiCorp Local Trans
mission System Plan 2022-2023 Report Dec 31.pdf) .
6 PacifiCorp's GATT, §§ 28.2 and 15.4 (reflecting FERC' s pro forma tariff
and requiring PacifiCorp to construct facilities as necessary to reliably
provide requested transmission service) ; In re Standardized Generator
Interconnection Agreements and Procedures, Order No. 2003, 104 FERC 91
61, 103 at 767 (2003) (explaining that FERC's pro forma interconnection
services "provide for the construction of Network Upgrades that would
allow the Interconnection Customer to flow the output of its Generating
Facility onto the Transmission Provider's Transmission System in a safe
and reliable manner.") ; In re Preventing Undue Discrimination and
Preference in Transmission Service, Order No. 890, 118 FERC 9[ 61,119 at
814 (2007) (explaining that despite certain policy reforms, transmission
providers "will continue to be obligated to construct new facilities to
satisfy a request for service if that request cannot be satisfied using
existing capacity") .
Vail, Di 8
Rocky Mountain Power

1 planned system expansions or upgrades . '
2 Q. Please describe PacifiCorp' s responsibility for
3 maintaining reliability on its transmission system.
4 A. In 2005, Congress directed the FERC to establish
5 reliability standards to ensure the safe and reliable
6 operation of the Nation' s Bulk Electric System ("BES") .8
7 The following year, the FERC adopted rules to implement
8 the statute, 9 and delegated these responsibilities to
9 the North American Electric Reliability Corporation
10 ("NERC") .10
11 NERC proceeded to establish various reliability
12 standards, including transmission system planning
13 performance requirements ("TPL Standards") . NERC' s TPL
14 Standards establish, among other things, "Transmission
15 system planning performance requirements within the
16 planning horizon to develop a Bulk Electric System (BES)
17 that will operate reliably over a broad spectrum of
18 System conditions and following a wide range of probable
7In re CAISO Tariff Revision, 133 FERC 1 61,224 (2010) (OATT construction
obligations attach to planned facilities identified as necessary to grant
interconnection requests, stating that " [t]he fact that CAISO has
voluntarily chosen to evaluate a network upgrade in its transmission
planning process should not affect the obligation to build these
facilities.") .
8 16 USC § 824o.
9 In re Electric Reliability Standards Rulemaking, 71 FR 8662-01, Docket
No. RM05-30-000; Order No. 672 (Feb. 17, 2006) .
io In re NERC Certification, 116 FERC 91 61,062 (Jul. 20, 2006) , aff'd
Alcoa Inc. v. FERC, 564 F.3d 1342 (D.C. Cir. 2009) .
Vail, Di 9
Rocky Mountain Power

1 Contingencies . " 11 These TPL Standards, along with
2 regional standards (i . e. , established by the Western
3 Electricity Coordinating Council ("WECC") ) and utility-
4 specific planning criteria, define the minimum
5 transmission system requirements to safely and reliably
6 serve customers .
7 Q. How does PacifiCorp ensure compliance with NERC TPL
8 Standards?
9 A. The Company plans, designs, and operates its
10 transmission system to meet or exceed NERC Standards for
11 the BES, and WECC regional standards and criteria. To
12 ensure compliance with applicable TPL Standards,
13 PacifiCorp conducts an annual system assessment to
14 evaluate the performance of the Company' s transmission
15 system and to identify system deficiencies . This annual
16 system assessment is comprised of steady-state,
17 stability, and short circuit analyses to evaluate peak
18 and off-peak load scenarios in the near term (one-, two-,
19 and five- year) and long-term (10-year) planning
11 Standard TPL-001-5.1 — Transmission System Planning Performance
Requirements, at A(3) (available
https://www.nerc.com/pa/Stand/Reliability%20Standards%2OComplete%2OSet/
RSCompleteSet.pdf )
Vail, Di 10
Rocky Mountain Power

1 horizons . 12 The assessment is performed using power flow
2 base cases maintained by WECC, and is developed in
3 coordination among all transmission planning entities in
4 the Western Interconnection. These base cases include
5 load and resource forecasts, along with planned
6 transmission system changes for each of the future year
7 cases, and are intended to identify future system
8 deficiencies to be mitigated.
9 As part of these annual system assessments,
10 corrective action plans are developed to mitigate
11 identified deficiencies, and may prescribe construction
12 of transmission system reinforcement projects or
13 adoption of new operating procedures . In certain
14 instances, operating procedures that change the
15 configuration of the transmission system can prevent
16 deficiencies from occurring when there are two back-to-
17 back or concurrent (N-1-1) transmission system events
18 with allowed system adjustments performed between the
19 two events . However, the use of operating procedure
20 actions has limitations . In particular, actions taken in
21 connection with operating procedures to protect the
12 Analyses consist of taking a normal system (N-0) and applying events
(N-1, N-1-1, N-2, etc. ) within each category (P0, Pl, P2, P3, etc.) listed
within the TPL Standards to identify system deficiencies. For example: An
N-1-1 event describes two transmission system elements out of service at
the same time, but due to independent causes. An example of an N-1-1 event
would be a planned outage of one 230 kilovolt transmission line followed
by an unplanned outage of any additional element in the system being used
to continue service with the initial element out.
Vail, Di 11
Rocky Mountain Power

1 integrity of the larger integrated transmission system
2 in the Western Interconnection can lead to large outages
3 on the occurrence of the second of two back-to-back (N-
4 1-1) events . An effective corrective action plan, one
5 that does not over-rely on operating procedure actions,
6 is critical to ensuring system reliability so that large
7 numbers of customers are not subject to avoidable outage
8 risk.
9 Q. Is compliance with the reliability standards optional?
10 A. No . The reliability standards are a federal requirement,
11 subject to oversight and enforcement by WECC, NERC, and
12 FERC. PacifiCorp is subject to compliance audits every
13 three years and may be required to prove compliance
14 during NERC or WECC reliability initiatives or
15 investigations . Failure to comply with the reliability
16 standards could expose the Company to penalties of up to
17 $1 .29 million per day, per violation.
18 Accordingly, reliability standards are a major
19 driver for the new capital investments in PacifiCorp' s
20 system transmission assets that are identified in and
21 supported by my testimony below.
Vail, Di 12
Rocky Mountain Power

1 Q. Are there additional concerns that influence
2 PacifiCorp' s distribution and transmission system
3 investment decisions?
4 A. Yes . Depending on the project, there are several factors
5 that inform whether PacifiCorp will build new
6 distribution and transmission facilities, including
7 increased demand for transmission capacity, requests for
8 transmission service, requests for generation
9 interconnection service, increased demand for
10 distribution capacity, and the age and condition of
11 existing distribution and transmission facilities . The
12 specific concerns for the projects addressed in my
13 testimony are described in more detail below.
14 IV. CUSTOMER BENEFITS OF PACIFICORP' S TRANSMISSION SYSTEM
15 Q. Please describe how PacifiCorp' s transmission system
16 benefits Idaho customers .
17 A. PacifiCorp' s transmission system is designed to reliably
18 transport electricity from a broad array of generation
19 resources to load across both BAAs, and the Company
20 operates a geographically diverse and expansive
21 transmission system serving retail customers in six
22 western states . This unique geographic footprint,
23 including over 17, 770 miles of transmission lines,
24 allows the Company to take advantage of efficiencies and
25 economies from both a planning and operational
Vail, Di 13
Rocky Mountain Power

1 perspective due to, among other things, retail load
2 characteristics and variable resource diversity.
3 PacifiCorp' s transmission system provides over 200
4 interconnections with adjacent transmission provider
5 BAAs, as well as access to regional energy market hubs
6 in Washington, the California-Oregon Border, Utah, the
7 Four Corners area, and Arizona.
8 This geographic diversity, access to adjacent
9 transmission providers and BAAs, and access to regional
10 energy market hubs allows PacifiCorp to economically
11 dispatch units across its system and transfer energy
12 from other systems as facilitated by the Company' s
13 participation in the WEIM. This expansive footprint
14 ensures that PacifiCorp is uniquely situated to access
15 some of the nation' s best wind and most cost-effective
16 solar resources to serve customer load.
17 PacifiCorp also takes advantage of its transmission
18 system to minimize operation costs related to generation
19 reserve requirements and blackstart capability. The
20 Company is required to carry reserves to ensure system
21 reliability in the event of changes in load or system
22 events . Instead carrying reserves and blackstart
23 capability for each BAA, PacifiCorp can operate its
24 transmission as a collective system and use resources
25 that are geographically remote to meet the system
Vail, Di 14
Rocky Mountain Power

1 requirements in all areas that PacifiCorp serves . This
2 allows the Company to engage in the most economic
3 dispatch of these resources to lower costs for its
4 customers .
5 Q. Does PacifiCorp currently carry reserves in each BAA
6 sufficient to meet that BAA' s requirements?
7 A. Not always . While meeting reliability standard reserve
8 requirements is not a transmission function,
9 PacifiCorp' s transmission system provides flexibility
10 for PacifiCorp to meet its reserve requirements .
11 Q. Are investments across the system necessary to maintain
12 PacifiCorp' s transmission system?
13 A. Yes . The ability to flexibly use a diverse set of energy
14 resources depends significantly on the strength and
15 reliability of PacifiCorp' s transmission system to
16 connect those resources to PacifiCorp' s retail customers
17 in all six states . Transmission system outages and other
18 real-time operation constraints can unnecessarily burden
19 the transmission system when corrective action plans are
20 required to comply with NERC and WECC reliability
21 authorities . Increasing PacifiCorp' s transmission
22 system capacity enhances reliability, allows more
23 generation to interconnect to serve customer load, and
24 provides flexibility in designating generation resources
Vail, Di 15
Rocky Mountain Power

1 for reserve capacity to comply with mandatory
2 reliability standards .
3 Q. Can the benefits of a reliable system be easily
4 quantified?
5 A. No . Reliability is, essentially, the absence of system
6 disruptions . It is difficult to quantify the benefit of
7 reliability investments . That said, the access to
8 different regions and redundancy in operations provides
9 reliable service under a variety of conditions that
10 benefits all PacifiCorp' s customers .
11 V. OVERVIEW OF INVESTMENTS
12 Q. What specific transmission system investments are you
13 addressing in your testimony?
14 A. My testimony addresses PacifiCorp' s major planned
15 transmission system projects that will go in-service
16 during the test period for this rate case. Each of these
17 investments will increase PacifiCorp' s load serving
18 capability, enhance reliability, conform with NERC
19 Reliability Standards, improve transfer capability
20 within the existing system, accommodate point-to-point
21 transmission service requests, relieve existing
22 congestion, and interconnect and integrate new wind
23 resources into PacifiCorp' s transmission system. These
24 projects include:
Vail, Di 16
Rocky Mountain Power

1 • The Gateway South Segment F Aeolus to Mona/Clover 500
2 kV and Gateway West Segment D. 1 Windstar to Aeolus
3 230 kV Transmission Lines;
4 • The EV2024 Generation Interconnection Network
5 upgrades;
6 • The Anticline 345 kV Phase Shifter;
7 • Gateway South Supporting Projects;
8 • The Oquirrh Terminal 345 kV Line Project; and
9 • Path C Transmission Improvements Project.
10 Q. What are the projected investment costs of these
11 projects and their anticipated in-service dates?
12 A. Please see the table below for the total-Company costs
13 and in-service dates for each project. These amounts
14 include costs for engineering, project management,
15 materials and equipment, construction, right-of-way, and
16 an allowance for funds used during construction. These
17 costs are detailed in the testimony and exhibits of
18 Company witness Shelley E. McCoy. The in-service dates
19 are based on our current best available information at
20 the time of preparing this case.
Vail, Di 17
Rocky Mountain Power

TABLE 1
Total- Idaho-
Project Company Allocated Final In-
Cost Cost Service Date
(million) (million)
Gateway South $2, 069 . 8 $112 . 1 December
2024
Gateway West Segment D. 1 $278 . 2 $15 . 1 Various -
2024
EV2024 Network upgrades $40 . 1 $2 . 2 Various -
2024
Anticline 345 kV Phase $133 . 5 $7 . 2 November
Shifter 2024
Gateway South Supporting $20 . 2 $1 . 1 December
Projects 2024
Oquirrh Terminal 345 kV $75 . 8 $4 . 1 November
Line 2024
Path C Transmission $31 . 3 $1 . 7 May 2024
Improvements
1 Q. Will PacifiCorp' s OATT transmission customers pay their
2 proportional share of these assets?
3 A. Yes . Transmission customers pay for transmission and
4 ancillary services through the Company' s transmission
5 formula OATT rate . 13 Formula rates are updated by the
6 Company' s annual transmission revenue requirement
7 ("ATRR") filing that includes the total cost of
8 providing firm transmission service over the test year. 14
9 This includes all transmission system investments made
13 In re PacifiCorp's Application for Formula Rates, 143 FERC 91 61, 162
(May 23, 2013) (letter order approving settlement agreement establishing
formula rate) .
11 See, e.g. , PacifiCorp's OATT Volume No. 11, Attachment H: ATRR for
Network Integration Transmission Service (available
https://www.oasis.oati.com/woa/docs/PPW/PPWdocs/20240415 OATTMaster.pdf
Vail, Di 18
Rocky Mountain Power

1 by the Company, a return on rate base, income taxes,
2 expenses, and certain revenue credits, among other
3 specific elements and adjustments . 15 Transmission
4 assets, including the capital expenditures described in
5 this rate case, will be included in the Company' s annual
6 ATRR filing when each asset is placed in service,
7 weighted by months in service as necessary. This annual
8 filing results in a wholesale customer rate by dividing
9 the total ATRR by firm transmission demand. This rate is
10 then assessed against PacifiCorp' s transmission
11 customers . 16
12 Q. Do PacifiCorp' s Idaho retail customers receive an
13 offsetting revenue credit for a portion of the
14 transmission revenue received under PacifiCorp' s GATT?
15 A. Yes . A portion of PacifiCorp' s transmission revenues are
16 credited to the Company' s state retail customers . Under
17 this approach, the Company allocates 100 percent of its
18 transmission costs to both state retail and FERC-
19 jurisdictional customers . The FERC, through the
is Id. at Attachment H-2: Formula Rate Implementation Protocols, at 376-
398 (available
https://www.oasis.oati.com/woa/docs/PPW/PPWdocs/20230208 OATTMaster.pdf
) ; see also, e.g. , In re PacifiCorp's 2024 Transmission Formula Annual
Update, Docket No. ER11-3643 (May 13, 2022) (available
https://www.oasis.oati.com/woa/docs/PPW/PPWdocs/2024 Depreciation Rate
Update ER24-1612.pdf ) .
11 PacifiCorp's Transmission and Ancillary Services Rates (effective Jun.
1, 2023) (available
https://www.oasis.oati.com/woa/docs/PPW/PPWdocs/Rate Table 20230601.pdf
Vail, Di 19
Rocky Mountain Power

1 Company' s ATRR filings, determines the appropriate
2 amount to be recovered from PacifiCorp' s wholesale
3 customers . This same amount is then credited to
4 PacifiCorp' s retail customers . This ensures that
5 PacifiCorp recovers its transmission expenditures, and
6 both wholesale and retail customers only pay their
7 proportional share of the Company' s transmission system.
8 The testimony below provides additional discussion
9 and details for each of transmission investments that
10 the Company seeks rate recovery for in this proceeding.
11 A. Gateway South and Gateway West Transmission Lines
12 Q. Please describe the Energy Gateway Transmission
13 Expansion.
14 A. In 2007, PacifiCorp launched the Energy Gateway
15 Transmission Expansion, a multi-year strategy to add
16 approximately 2, 000 miles of new transmission lines
17 across the west . 17 To date, three major segments of
18 Energy Gateway are complete and in service . After over
19 a decade of planning, the Company now proposes to move
20 forward with constructing the Gateway South (Segment F)
21 and a portion of Gateway West lines (Segment D. 1) . 18 The
17 See generally https://www.pacificorp.com/transmission/transmission-
projects/energy-gateway.html.
11 See, e.g. , PacifiCorp 2021 Integrated Resource Plan, Vol. 1, Ch. 4 -
Transmission, at 83-102 (available 2021
https://www.pacificorp.com/content/dam/pcorp/documents/en/pacificorp/en
ergy/integrated-resource-plan/2021-irp/Volume%201%20-
%209.15.2021%20Final.pdf) .
Vail, Di 20
Rocky Mountain Power

1 following graphic provides an overview of the Energy
2 Gateway Transmission Expansion generally, and the
3 Gateway South and Gateway West lines specifically.
Figure 3
W A S H I N G T O N
M O N T A N A
McNary Boardman •
O•Wallula
j H
O#e G0N IDAHO
Hemingway GATE WAY W E 5 7 W Y O M I N G
Midpoint Win&a,
E Borah ��•Shirley Basin
Br
Cedar Hill Populid 1
us Anticline D.2 Aeolus
D3
<J B
3 F Terminal t
t
CALIFORNIA aW Limber Oquirrh So°
u u Py
t�
NEVADA Mona
COLORADO
PacifiCorp retail service area Siguurdd
New transmission lines: jGJ U T A H
—500 kV minimum voltage Red Butte •r/`"
—345 kV minimum voltage
—230 kV minimum voltage
• Existing substation
O New substation
A R I Z O N A NEW MEXICO
This map is for general reference only and reflects current plans.
It may not reflect the final routes,construction sequence or exact line configuration.
4 Q. Please describe the Gateway South Transmission Project.
5 A. The Gateway South Project includes the following
6 elements :
7 • A 416-mile, high voltage 500 kV transmission line
8 from the Aeolus substation, near Medicine Bow,
9 Wyoming to the Clover substation near Mona, Utah.
Vail, Di 21
Rocky Mountain Power

1 • Rebuilding certain 345 kV transmission facilities
2 in and around the Mona and Clover substations in
3 Utah.
4 • Two new series compensation stations .
5 • Expansion of the Aeolus, Anticline, and Clover
6 substations along with modifications to the Mona
7 substation.
8 • Additional shunt capacitors at Aeolus, Clover,
9 Bonanza (Utah) , Riverton and Mustang (Wyoming)
10 substations .
11 • Additions and modifications to various remedial
12 actions schemes, voltage controllers and control
13 schemes necessary to ensure protection and control
14 of the grid after integration of Gateway South.
15 Q. Please describe the Gateway West Segment D. 1
16 Transmission Project.
17 A. Gateway West Segment D. 1 includes the following
18 elements :
19 • A new 59-mile high-voltage, 230 kV transmission
20 line from the Shirley Basin substation in
21 southeastern Wyoming to the Windstar substation
22 near Glenrock Wyoming.
23 • Rebuild of the existing Dave Johnston - Amasa -
24 Difficulty - Shirley Basin 230 kV transmission
25 line, which runs approximately 57 miles from the
26 Shirley Basin substation in southeastern Wyoming to
27 the Dave Johnston substation near Glenrock,
28 Wyoming.
29 • A new 230 kV Heward substation adjacent to the
30 Difficulty substation.
31 • Additions to the Shirley Basin, Dave Johnston, and
32 Windstar substations .
Vail, Di 22
Rocky Mountain Power

1 Q. Please explain why the Gateway South and Gateway West
2 Transmission Projects (collectively, the "Transmission
3 Projects") are needed.
4 A. The Transmission Projects are an important component of
5 the Company' s Energy Gateway Transmission Expansion, and
6 Gateway South has long been recognized as a key
7 transmission segment in the region' s long-term
8 transmission planning. These lines will provide
9 substantial customer benefits .
10 For example, the Company needs additional resources
11 to serve load, and the Transmission Projects enable new,
12 cost-effective Wyoming generation resources to fill this
13 need: these Transmission Projects allow the Company to
14 interconnect up to approximately 2, 030 megawatts ("MW")
15 of new resources . These projects will also improve
16 reliability of the transmission system by providing
17 capacity between Gateway West and Gateway Central and
18 relieve transmission congestion on the existing Wyoming
19 230 kV transmission system.
20 The addition of Gateway South relieves the stress
21 on the existing 345 kV transmission system that
22 traverses from Wyoming to Southeast Idaho (Populus and
23 Threemile Knoll substations) and through Idaho to the
24 west . The addition of the Gateway South line unloads
25 these 345 kV lines which would otherwise be stressed to
Vail, Di 23
Rocky Mountain Power

1 serve Wasatch Front load during peak load conditions .
2 The addition of Gateway South and unloading of the
3 existing 345 kV and the underlying 138 kV transmission
4 system enhances the reliability of customers in
5 southeast Idaho and Goshen area and other customers in
6 Idaho . The unloading of these 345 kV lines into Idaho
7 also improves the load serving capability using cost
8 effective resources for customers in Idaho .
9 Q. Is the increased capacity provided by the Transmission
10 Projects consistent with the Company' s obligation to
11 provide transmission service under its GATT?
12 A. Yes . PacifiCorp adhered to OATT processes when
13 identifying the need for these transmission projects . In
14 response to nearly 2, 500 MW of transmission and
15 interconnection service requests, the Company determined
16 that the Transmission Projects were necessary to
17 facilitate the various requests because PacifiCorp
18 lacked adequate transmission capacity. As a result the
19 Transmission Projects have been included in multiple
20 FERC-jurisdictional executed contracts . For example,
21 PacifiCorp has executed 13 contracts with third-party
22 customers that require constructing one or both of the
23 Transmission Projects, including a transmission service
24 agreement that requires construction of Gateway South to
25 reliably provide 500 MW firm point-to-point transmission
Vail, Di 24
Rocky Mountain Power

1 service beginning by the contract start date of January
2 1, 2025 . The Transmission Projects are lynchpins in
3 PacifiCorp' s ability to meet its obligation to grant
4 generator interconnection service and transmission
5 service under the OATT.
6 The Transmission Projects will also enhance the
7 Company' s ability to comply with mandated NERC and WECC
8 reliability and performance standards . Congestion on the
9 current transmission system in eastern Wyoming limits
10 the ability to deliver energy from eastern Wyoming to
11 PacifiCorp load centers in Wyoming, Idaho, Utah, and the
12 Pacific Northwest.
13 Q. Do the Transmission Projects increase the amount of
14 generation that can be interconnected and delivered
15 across the Company' s transmission system?
16 A. Yes . The Transmission Projects will allow the Company to
17 interconnect an additional 2, 030 MW of generation
18 resources in eastern Wyoming, and increase the system
19 transfer capability by approximately 875 MW from the
20 Windstar/Dave Johnston area south to Shirley
21 Basin/Aeolus . This will create approximately 1, 700 MW of
22 incremental transfer capability from eastern Wyoming
23 (Aeolus) to the central Utah energy hub (Mona/Clover) .
Vail, Di 25
Rocky Mountain Power

1 Q. Did the Company consider alternatives to Transmission
2 Projects?
3 A. Yes . PacifiCorp and Northern Grid (then the Northern
4 Tier Transmission Group, an unincorporated association
5 of entities that promotes coordinated and transparent
6 transmission planning and facilitates compliance with
7 FERC transmission planning and reliability standards for
8 the Pacific Northwest and Intermountain West) evaluated
9 one alternative. This alternative analyzed one 345 kV
10 line with bundled conductors from Aeolus to Anticline
11 (138 miles) , and two 345 kV lines with bundled conductors
12 from Anticline to Populus (approximately 198 miles
13 each) , along with other supporting mitigation such as
14 transformers and shunt capacitors at different
15 substations .
16 These analyses indicated that the alternatives were
17 less beneficial compared to the Gateway West and South
18 projects for two reasons . First, these alternative lines
19 would reduce the number of renewable resources that
20 could be interconnected to eastern Wyoming by
21 approximately 1, 100 MW compared to Gateway West and
22 South.
23 Second, this alternative showed additional
24 reliability issues on the transmission system between
25 Rock Springs and Monument, and also between Populus and
Vail, Di 26
Rocky Mountain Power

1 Terminal, that would have to be mitigated to comply with
2 relevant reliability standards . This would result in
3 additional cost burdens . Like the Aeolus to Clover line,
4 this alternative does not provide an adequately diverse
5 path for PacifiCorp' s network loads .
6 These two considerations led the Company to
7 conclude that Gateway West and South were more
8 beneficial .
9 Q. If it did not construct the Transmission Projects , would
10 the Company be able to serve the roughly 2 ,500 MW
11 of interconnection and transmission service without
12 constructing additional facilities?
13 A. No, it would not be possible to serve these requests for
14 interconnection and transmission services with
15 PacifiCorp' s existing BES . For example, to grant only
16 the 500 MW transmission service request, the Company
17 would be required to construct a 230 kV line at a cost
18 of approximately $1 billion. To grant the transmission
19 and interconnection service requests, consistent with
20 the Company' s GATT, would require construction of the
21 functional equivalent of the infrastructure contemplated
22 by the current Transmission Projects .
23 Q. Has the Company obtained all necessary permits and
24 rights-of-way ("ROW") for the Transmission Projects?
25 A. Yes . All permits, certificates of public convenience and
Vail, Di 27
Rocky Mountain Power

1 necessity, and ROW for both Gateway South and Gateway
2 West Segment D. 1 have been secured.
3 Q. Has PacifiCorp begun construction of the Transmission
4 Projects?
5 A. Yes . Once the Company received necessary permits and
6 ROW, the Company began construction of the Gateway South
7 Project in June 2022, and late September 2022 for Gateway
8 West Segment D. 1 .
9 Q. Is the Company confident that the Transmission Projects
10 will be in service by 2024?
11 A. Yes . To manage construction schedule risk, the Company
12 has structured and managed the projects on firm, date-
13 certain, fixed-price, turnkey contracts . Construction
14 contractors and equipment suppliers will be held to key
15 construction and delivery milestones, guarantees, and
16 development of compressed schedule mitigation plans, if
17 required. The construction remains on-track and on
18 schedule .
19 Q. Are the Transmission Projects currently on budget?
20 A. Yes . The project budgets based on contractual provisions
21 require fixed cash flows that are assessed monthly
22 against confirmed construction progress, in addition to
23 identification and mitigation of project risks that
24 could stall or delay completion. To date, almost 2 years
Vail, Di 28
Rocky Mountain Power

1 from starting construction, both projects remain on
2 budget .
3 Q. What are the remaining major milestones for the
4 Transmission Projects?
5 A. Key milestones remaining before the in-service date for
6 these two projects include:
7 • Complete all wound core device deliveries by August
8 2024 .
9 • Complete construction of the 500 kV transmission
10 line by October 2024 .
11 • Complete all communications network additions and
12 upgrades by October 2024 .
13 • Complete construction of the 230 kV Windstar to
14 Shirley Basin line by December 2024 .
15 • Complete reconstruction of the 230 kV transmission
16 line by November 2024 .
17 • Complete commissioning and placed in-service in
18 fourth quarter of 2024 .
19 The Transmission Projects are on track to achieve each
20 milestone .
21 B. EV2024 Generation Interconnection Network Upgrades
22 Q. What are network upgrades?
23 A. Network upgrades are the modifications or additions to
24 transmission-related facilities that are integrated with
Vail, Di 29
Rocky Mountain Power

1 and support PacifiCorp' s overall Transmission System for
2 the general benefit of system users . 19
3 Q. Please explain how network upgrade costs are allocated
4 under the Company' s OATT.
5 A. When PacifiCorp receives a request for generation
6 interconnection or transmission service, the Company
7 completes various studies to determine what new
8 facilities or upgrades to existing facilities are
9 required to accommodate the request.20 The studies
10 classify any required additions to support the requested
11 service into two categories : direct assigned or network
12 upgrade . Direct-assigned assets only benefit, or are
13 used solely by, the customer requesting generator
14 interconnection or transmission service. Those costs are
15 directly assigned and paid for by that customer and will
16 not be included in either the Company' s ATRR or retail
17 rates . Network upgrades, on the other hand, benefit all
18 customers that use the transmission system. Network
19 upgrade costs can be included in PacifiCorp' s ATRR, and
20 ATRR revenues are then credited to PacifiCorp' s retail
21 customers in each state .21
19 PacifiCorp's OATT Volume No. 11, § 1.27 (available
https://www.oasis.oati.com/woa/docs/PPW/PPWdocs/20240415 OATTMaster.pdf
20 Id. §§ 38-43.
21 Id. 47.
Vail, Di 30
Rocky Mountain Power

1 Q. Is the Company requesting recovery of any Generation
2 Interconnection Network Upgrades?
3 A. Yes . There are five generation interconnection projects
4 that were selected from a recent request for proposal to
5 interconnect 1, 640 MW of new wind generation to the
6 Company' s transmission system in eastern Wyoming that
7 are relevant to the test period in this rate case. The
8 request for proposal process and the resulting resources
9 that were selected are described in the testimony of
10 Company witness Rick T. Link. A separate generation
11 interconnection agreement was negotiated and signed for
12 all five projects, and each will require generation
13 interconnection network upgrades to interconnect and
14 integrate with PacifiCorp' s system. These projects
15 include :
16 • Q0409 Boswell Springs Wind. This project is a 320
17 MW wind facility that will interconnect to the
18 existing Freezeout 230 kV substation near Aeolus
19 and is planned to be in service by December 31,
20 2024 . This project includes a new breaker at the
21 Freezeout substation, and a new remedial action
22 scheme and communications equipment at Aeolus
23 substation.
24 • Q0713 Cedar Springs IV Wind. This project is a 350
25 MW wind facility that will interconnect to the
26 existing Yellowcake 230 kV substation near
27 Windstar, and is planned to be in service on January
28 15, 2025 . This project includes construction of a
29 new line position at the Yellowcake substation,
30 including the installation of three new 230 kV
31 circuit breakers, and requires a new microwave
Vail, Di 31
Rocky Mountain Power

1 system and approximately 18 miles of fiber optic
2 cable between Yellowcake and Windstar substations .
3 • Q0785 Anticline Wind. This project is a 100 MW wind
4 facility that will interconnect to a new substation
5 on PacifiCorp' s Casper - Claim Jumper 230 kV line
6 and is planned to be in service on December 31,
7 2024 . This project includes a new three breaker
8 ring bus substation on the Casper - Claim Jumper
9 230 kV line, substation loop in on transmission
10 line, communications upgrade at Casper substation,
11 and Main Grid operations center updates .
12 • Q0835 Rock Creek Wind 1 . This project is a 190 MW
13 wind facility that will interconnect to
14 PacifiCorp' s existing Foote Creek 230 kV substation
15 and is planned to be placed in service on December
16 15, 2024 . This project includes expansion of
17 substation, bus, and line position at Foote Creek
18 substation, expansion for new breaker and line
19 positions at Freezeout and Aeolus substations,
20 construction of new approximately 4 miles long 230
21 kV transmission line between Aeolus and Freezeout
22 substations .
23 • Q0836 Rock Creek Wind 2 . This project is a 400 MW
24 wind facility that will interconnect to
25 PacifiCorp' s existing Aeolus 230 kV substation and
26 is planned to be placed in service on December 15,
27 2024 . This project includes a new bay for a 230 kV
28 line terminal at Aeolus substation.
29 Q. Why are these projects classified as network upgrades ,
30 and not directly assigned assets?
31 A. The interconnection study for each project indicated
32 that these upgrades would provide system-wide benefits .
33 Under PacifiCorp' s GATT, this requires the Company to
34 include these costs in the Company' s ATRR, as opposed to
35 directly assigning these costs to each project.
36 Accordingly, the network upgrade costs for each of these
Vail, Di 32
Rocky Mountain Power

1 projects are reflected in their respective Large
2 Generator Interconnection Agreements .
3 Q. Is the Company confident that it can manage any
4 construction schedule risk and deliver the network
5 upgrades for the new wind facilities by the planned in-
6 service dates?
7 A. Yes . To manage construction scheduling risk, the Company
8 structured each network upgrade contract on a firm,
9 date-certain, turnkey contract basis . Construction
10 contractors and equipment suppliers are held to key
11 construction and delivery milestones and development of
12 compressed schedule mitigation plans, if required. The
13 Company also established construction contract
14 completion dates and backstopped each with guarantees .
15 To date, the remaining network upgrades remain on track
16 for planned in-service dates .
17 C. Anticline 345 kV Phase Shifter
18 Q. Please describe the proposed Anticline 345 kV Phase
19 Shifter Project.
20 A. The Anticline 345 kV Phase Shifter project will install
21 four 345 kV phase shifting transformers (533 . 3/597 . 3
22 megavolt amperes ("MVA") each (summer normal/4-hour
23 emergency) , +40/-40 degrees) at Anticline substation,
24 near Point of Rocks, Wyoming.
Vail, Di 33
Rocky Mountain Power

1 Q. Please explain why these projects are needed and
2 beneficial .
3 A. With the addition of the Gateway South Project, the phase
4 shifters at Anticline are needed to enhance Wyoming
5 transmission utilization and maximize the production of
6 eastern Wyoming wind generation. By utilizing the phase
7 shifters at Anticline, flows on the Aeolus -
8 Bridger/Anticline line can be actively controlled to
9 unload the underlying 230 kV system west of Aeolus, and
10 manage flows on the Aeolus - Clover 500 kV (Gateway
11 South) and the Aeolus-Anticline 500 kV transmission line
12 to within limits depending on system conditions . If the
13 Gateway South transmission path rating limit is
14 exceeded, eastern Wyoming wind generation must be
15 curtailed, and the phase shifters prevent unnecessary
16 curtailment .
17 Q. Did PacifiCorp consider alternatives to the Anticline
18 345 kV Phase Shifter project?
19 A. Yes . Other transmission path power flow control methods,
20 such as multi-segment series capacitors, were previously
21 investigated; however, the installation of phase
22 shifting transformers at Anticline to provide active
23 control flows on the Anticline - Bridger 345 kV line was
24 the most efficient and cost effective as it provides
25 variable flow control using multiple taps on the phase
Vail, Di 34
Rocky Mountain Power

1 shifter. In addition, adding more than 70 percent series
2 compensation on the transmission line is not preferred,
3 and it would limit the applicability of this proposed
4 alternative .
5 D. Gateway South Supporting Projects
6 Q. Please describe the Gateway South Supporting Projects.
7 A. The Gateway South line requires additional supporting
8 projects to enhance Wyoming transmission utilization and
9 maximize the production of eastern Wyoming wind
10 generation. These additional supporting projects
11 include :
12 • Install one 41 . 6 megavolt amperes reactive MVAr
13 shunt capacitor bank at Riverton 230 kV substation,
14 two 30 MVAr shunt capacitor banks at Mustang 230 kV
15 substation, and one 60 MVAr shunt capacitor bank at
16 Bonanza (Deseret Power owned) 138 kV substation.
17 These facilities help maintain flows and voltage
18 reliability at each substation.
19 • Modification to the Aeolus remedial action scheme
20 ("RAS") to add Gateway South line logic and
21 additional wind projects as part of the wind
22 selection logic.
23 • Modifications to the Bridger RAS to support
24 additional wind generation and include it in the
25 wind selection logic .
26 • Implementation of a new fast voltage controller
27 ("FVC") at Aeolus substation to prevent high
28 voltages for the loss of 500kV lines under heavy
29 load scenarios and protect the transmission system
30 under transient conditions (0-15 cycles) .
31 • Modification of the existing Master Grid Controller
32 at Aeolus, to accommodate the addition of the new
33 windfarms and have an appropriate voltage
Vail, Di 35
Rocky Mountain Power

1 coordination with the added wind farms . The Master
2 Grid Controller is used to maintain the voltage at
3 Aeolus .
4 • Development of operating procedures to mitigate N-
5 1-1 loss of the two 230 kV paths from Dave
6 Johnston/Windstar area to Aeolus .
7 • Modifications to the Energy Management System
8 ("EMS") to support monitoring flows on the
9 transmission paths .
10 Q. Please explain why these projects are needed and
11 beneficial .
12 A. The shunt capacitor banks will support additional power
13 flows through the Riverton - Wyopo 230 kV and Mustang -
14 Bridger 230 kV lines under outage conditions and will
15 also alleviate low voltage issues . This is because the
16 loss of transmission lines from Dave Johnston/Windstar
17 to the Aeolus area would divert all generation resources
18 in the Dave Johnston/Windstar area towards the Riverton
19 - Wyopo 230 kV and Mustang - Bridger 230 kV lines, and
20 would cause low voltages on the Riverton and Mustang 230
21 kV buses . Without the shunt capacitor banks, the outage
22 would require significant reductions in wind generation
23 to maintain power flows and voltage reliability at the
24 Mustang and Riverton 230 kV buses . The Bonanza shunt
25 capacitor bank will be owned by Deseret Power, and an
26 agreement has been signed for them to install with
27 PacifiCorp reimbursing their costs .
Vail, Di 36
Rocky Mountain Power

1 Modifying the Aeolus RAS is required to add the
2 Gateway South line and the additional wind projects to
3 the Company' s transmission logic, to trip 627 MW of wind
4 generation for the loss of any of the Gateway South
5 elements from Aeolus to Clover. For the Bridger RAS,
6 until the Bridger units are available for tripping,
7 minor system changes might be required, but if the
8 Bridger units are unavailable while keeping the
9 2400/2200 MW path limit, additional wind generation will
10 have to be included in the Bridger RAS for tripping due
11 to the wind being utilized to load the Bridger West path.
12 The Aeolus FVC is designed to prevent high voltage
13 at Aeolus 500 kV and Aeolus 230 kV bus for the loss of
14 either 500 kV line under transient conditions
15 immediately after the line has tripped. Because Gateway
16 South requires three new 200 MVAr shunt capacitors on
17 the Aeolus 500 kV and 230 kV substations, planning
18 studies have demonstrated that the loss of either 500 kV
19 line could result in high voltages if the shunt
20 capacitors banks are not tripped quickly. Manually
21 tripping shunt capacitors is a complex task, because it
22 depends on evaluating real-time and anticipated power
23 flow levels, and which 500 kV lines are in-service . It
24 is difficult to implement this logic as part of a
25 comprehensive protection scheme. Instead, the Aeolus FVC
Vail, Di 37
Rocky Mountain Power

1 is designed to automatically and quickly trip the shunt
2 capacitor banks and prevent high voltages from the loss
3 of 500 kV lines .
4 Developing an operating procedure for the Windstar
5 area for the N-1-1 loss of the two 230 kV transmission
6 paths from Dave Johnston/Windstar area to Aeolus would
7 require generation curtailment to prevent thermal
8 overloads and low voltage issues in the Casper,
9 Riverton, Thermopolis, and Mustang areas . The operating
10 procedure will identify the list of generators that can
11 be curtailed along with the list of contingencies for
12 which the curtailment may be necessary depending on
13 dispatch scenarios .
14 Q. Did PacifiCorp consider alternatives to these supporting
15 projects?
16 A. Yes . Two alternatives were considered instead of
17 installing the shunt capacitors at Mustang and Riverton.
18 The first was additional transmission from the Dave
19 Johnston/Windstar area to Aeolus, similar to Gateway
20 West segment D. 1 (Windstar - Shirley Basin) , and the
21 second was installing a +/- 100 MVAR Static Var
22 Compensator at Casper. The installation of the shunt
23 capacitors was deemed to be the most efficient and cost-
24 effective option.
Vail, Di 38
Rocky Mountain Power

1 The Company also considered alternatives to the
2 Aeolus RAS modification requirements, which would result
3 in additional transmission from Aeolus - Clover. This
4 would be a significant cost compared to modification of
5 the RAS . In addition, without the RAS modification, the
6 amount of renewable resources that could be integrated
7 into the eastern Wyoming system would be reduced by a
8 minimum of 400 MW.
9 The Company also considered alternatives for the
10 Jim Bridger RAS modification, which would result in
11 additional new transmission between Jim Bridger and
12 Populus (approximately 200 miles of new 345 kV line) .
13 Similar to the Aeolus RAS modification, this would
14 require a significant cost as compared to the
15 modification of the RAS . In addition, without the RAS
16 modification PacifiCorp would be unable to achieve the
17 full path rating on Bridger West under different
18 operating conditions such as high wind and low Bridger
19 generation.
20 E. Oquirrh Terminal 345 kV Line Project
21 Q. Please describe the Oquirrh Terminal 345 kV Line
22 Projects .
23 A. This project involves the construction of a new 14-mile
24 double circuit, 345 kV transmission line between the
25 Company' s Oquirrh substation in West Jordan, Utah, and
Vail, Di 39
Rocky Mountain Power

1 Terminal substation in Salt Lake City, Utah. This
2 transmission line will link together the previously
3 completed Mona to Oquirrh and Populus to Terminal
4 transmission lines, which were both part of the Gateway
5 Central portion of the Energy Gateway Transmission
6 Expansion.
7 Q. Please explain why this project is needed and
8 beneficial .
9 A. This project mitigates transmission constraints that
10 currently exist between the Mona area and Wasatch front,
11 and will improve system reliability and operational
12 redundancy allowing for better load serving capability
13 under various system conditions .
14 For example, the northbound transmission capacity
15 on the Wasatch Front South ("WFS") internal transmission
16 cut plane (a 4, 945 MW rating) is currently fully
17 utilized, 22 and transmission planning studies show that
18 new transmission facilities are necessary to meet
19 anticipated network load service, reliability,
20 contractual point-to-point commitments and enhance WEIM
21 benefits . There are also ongoing requests to
22 interconnect additional renewable generation resources
22 Previous technical studies have determined the current WFS transfer
capability to be 4, 945 MW, prior to addition of the Oquirrh - Terminal
345 kV line addition and associated companion projects. At 4, 945 MW, the
WFS path is 100 percent committed (2016) , prior to the addition of the
Gateway South transmission project.
Vail, Di 40
Rocky Mountain Power

1 in southern Utah and transmit the energy north that
2 further exceed the transmission capacity on the WFS path
3 north of Mona/Clover. Additionally, the Company
4 anticipates that future Gateway South transfers into the
5 Mona/Clover area will require additional transmission
6 going north, and will require the Oquirrh-Terminal
7 double circuit line to increase northbound transfers
8 across the WFS transmission path. Finally, NERC TPL-001-
9 4, requirements Pl and P7 mandate increased transmission
10 system reliability and operational redundancy in the
11 area under all expected operating conditions .
12 The Oquirrh - Terminal double circuit transmission
13 line, in conjunction with the companion projects,
14 addresses each of these issues . It enhances transmission
15 system reliability and operational redundancy within the
16 Wasatch Front by adding additional capacity. This
17 additional transmission capacity also avoids 1, 800 MW of
18 curtailment to the WFS cut plane, and also a similar
19 reduction of the equivalent amount of renewable or
20 conventional generators in southern/central Utah, that
21 would otherwise be required to reduce congestion. This
22 increased capacity also avoids the increase stress on
23 the transmission system from Wyoming to the west and
24 northern Utah that otherwise would be used to serve load
25 in the northwest. Additionally, without this new
Vail, Di 41
Rocky Mountain Power

1 transmission, under system-outage conditions, load shed
2 of up to 1, 350 MW may be required to reduce thermal
3 overload below its 30-minute emergency rating.
4 Q. Did PacifiCorp consider alternatives to the Oquirrh
5 Terminal 345 kV Line?
6 A. Yes . PacifiCorp took an iterative approach for resolving
7 system limitations to increase transmission capacity on
8 the WFS cut plane. This transmission cut plane helps
9 resources from southern Utah move north to serve load,
10 as well as export power further north and to the
11 northwest . Based on the Wasatch Front South Study Table
12 6 posted on PacifiCorp' s OASIS, 23 PacifiCorp first
13 identified an alternative mitigation to resolve the same
14 system limitation (simultaneous outage of two Oquirrh -
15 Terminal #1 & 2 345 kV lines) . This alternative only
16 allowed for a certain amount of capacity increases
17 before the same limitation was observed again, and no
18 other alternative mitigations were available to increase
19 transmission capacity between Oquirrh and Terminal other
20 than adding new transmission. The Company' s Oquirrh
21 Terminal 345 kV project adds new transmission, though
22 provides a higher increase in transmission capacity that
23 Available at
https://www.oasis.oati.com/woa/docs/PPW/PPWdocs/Wasatch Front South Bou
ndary Capacity 7 29 2021.pdf.
Vail, Di 42
Rocky Mountain Power

1 allows additional resources to move south-to-north
2 compared to the alternative case .
3 F. Path C Transmission Improvement Project
4 Q. Please describe the Path C Transmission Improvement
5 Project.
6 A. The Path C Transmission Improvement project adds a new
7 345/138 kV source in northern Utah and southeast Idaho
8 by looping the existing Populus - Terminal 345 kV line
9 in and out of the Bridgerland and Ben Lomond substations .
10 The project also includes upgrades at Bridgerland
11 substation, including a 345/138 kV 700 MVA
12 autotransformer; a new 345 kV bus; three 345 kV breakers;
13 and four 138 kV breakers . This new 345/138 kV source
14 will improve the reliability of the 138 kV system, which
15 runs parallel to Path C and will eliminate system
16 limitations on the parallel 138 kV lines . It will also
17 help maintain Path C (southeast Idaho - northern Utah)
18 ratings as well as add operational flexibility under
19 outage conditions at Ben Lomond substation.
20 Q. Please explain why these projects are needed and
21 beneficial .
22 A. The Path C Transmission Improvement project resolves N-
23 2 issues that were identified as part of an NERC FAC-
24 013 Assessment of Transfer Capability for the Near-Term
25 Transmission Planning Horizon. This assessment was
Vail, Di 43
Rocky Mountain Power

1 conducted to maintain WECC Path C ratings to 1, 600 MW
2 southbound, and 1, 250 MW northbound. The project also
3 adds a new 345/138 kV source in northern Utah and
4 southeast Idaho which improves the reliability of the
5 138 kV system, which runs parallel to Path C and adds
6 operational flexibility under outage conditions at Ben
7 Lomond substation.
8 Q. Did PacifiCorp consider alternatives to the Path C
9 Transmission Improvement project?
10 A. Yes . The first alternative considered was to rebuild 6 . 3
11 miles of Oneida - Treasureton line, 29 . 5 miles of the
12 Treasureton - Wheelon 138 kV line, expand the
13 Bridgerland 138 kV substation, and loop in the
14 Honeyville - Wheelon 138 kV line in and out of the
15 substation. However, this alternative only resolves
16 issues related to Path C southbound flows . To resolve
17 northbound issues on Path C, an additional rebuild of
18 22 . 6 miles of double circuit line from Ben Lomond -
19 Honeyville and 9 miles of Ben Lomond - White Rock 138 kV
20 line would still be required. These alternatives were
21 higher costs than the Company' s primary choice .
22 VI . CONCLUSION
23 Q. Please summarize your testimony.
24 A. I recommend that the Commission conclude that the
25 projects described above are prudent.
Vail, Di 44
Rocky Mountain Power

1 Q. Does this conclude your direct testimony?
2 A. Yes .
Vail, Di 45
Rocky Mountain Power