20210527Vail Direct.pdf

BET'ORE THE IDAEO PUBLIC UTILITIES COMIIISSION
INTHE MATTEROTTHE
APPLICATION OT ROCKY
MOT]NTAIN POWERFOR
AUTIIORITY TO INCREASE ITS
RATES AI\ID CHARGES IN IDAHO
AND APPROVAL Of,' PROPOSEI)
ELECTRIC SERVICE SCIIEDT]LES
AND REGI]LATIONS
)) cAsE NO. PAC-E 21-07
)) Direct Testimony of Richard.d Vail
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ROCI(Y MOI]NTAIN POWER
CASE NO. PAC-EAI07
May2021
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TABLE OF CONTENTS
TNTRODUCTION AND QUALIFICATIONS ........................I
II.
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V.
PURPOSE OF TESTIMONY......... ......... 1
OVERVIEW OF PACIFICORP'S TRANSMISSION SYSTEM AND INVESTMENT
DRTVERS ............3
OVERVIEW OF INVESTMENTS DESCRIBED IN TESTIMONY.............................7
AEOLUS TO BRIDGER/ANTICLINE TRANSMISSION LINE AND NETWORK
UPGRADES ............... ......... t2
THE MONA-TO-OQUTRRH 345 kV TRANSMISSION LINE PROJECT ................. 17
WALLULA.MCNARY 230 KV NEW TRANSMISSION LINE ...............29
sNow GoosE s001230 KV NEw SUBSTATIoN ...............31
VANTAGE TO POMONA HEIGHTS 230 KV NEW TRANSMISSION LINE .......... 33
GOST{EN-SUGARMILL.RIGBY 1 6 I KV TRANSMISSION LINE PROJECT. ........ 3 6
GOSHEN #3 345116I KV 7OO MVA TRANSFORMER INSTALLATION PROJECT 42
CONCLUSION........... _.___....44
ATTACHED EXHIBITS
Exhibit No. 24-Aeolus to BridgerAnticline
Exhibit No. 25-Mona to Oquirrh 345 kV Transmission Project
Exhibit No. 2G-Sigurd to Red Butte 345 kV Transmission Project
Exhibit No. 27-Wallula-McNary 230 kV Transmission Project
Exhibit No. 28-Snow Goose Subsation Project
Exhibit No. 2}-Vantage-Pomona Project
Exhibit No. 3 0-Coshen- Sugarmi ll-Rigby Proj ect
Exhibit No. 3l-Goshen #3 Project
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Rocky Mountain Power
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I. INTRODUCTION AI\D QUALIFICATIONS
Please state your name, business address, and present position with PacifiCorp
d/b/a Rocky Mountain Power (66Company").
My name is Richard A. Vail. My business address is 825 NE Multnomah Street, Suite
1600, Portland, Oregon 97232. My present position is Vice President of Transmission.
I am responsible for transmission system planning, customer generator interconnection
requests and transmission service requests, regional transmission initiatives,
ffansmission capital budgeting, fiansmission and distribution project delivery and
administration of the Open Access Transmission Tariff ("OAIT"). I am testifuing on
behalf of the Company.
Please describe your education and professional experience.
I have a Bachelor of Science degree with Honors in Electrical Engineering with a focus
in elechic power systems from Portland State University. I have been Vice President of
Transmission for PacifiCorp since December 2012. I was Director of Asset
Management from 2007 to 2012. Before that position, I had management responsibility
for a number of organizations in PacifiCorp's asset management group including
capital planning, maintenance policy, maintenance planning, and investment planning
since joining PacifiCorp in 2001.
II. PURPOSE OF TESTIMONY
What is the purpose of your testimony in this case?
The purpose of my testimony is to describe PacifiCorp's transmission system and the
benefits it provides to Idaho customers. PacifiCorp's transmission system is designed
to reliably ffansfer electric energy from a broad array of generation resources to load.
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Rocky Mountain Power
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PacifiCorp's interconnection to other balancing authority areas and participation in the
Energy Imbalance Market provide access to markets and promote affordable and
reliable service to PacifiCorp's customers. Fuflher, all transmission system capacity
increases provide benefits to customers by increasing reliability and allowing more
generation to interconnect to serve customer load, as well as allowing PacifiCorp
flexibility in designating generation resources for reserve capacity to comply with
mandatory reliability standards.
I describe the status of PacifiCorp's construction of the Aeolus-to-
Bridger/Anticline 500 kilovolts ("kV") Transmission Line and the additional 230 kV
network upgrades required to interconnect the Energy Vision 2020 Wind projects
(*230 kV Net'work Upgrades"). I specifically address the current timeline and estimate
of costs.
I also describe PacifiCorp's major capital investment projects for new
transmission systems included in this rate case, specifically:
. Mona-Oquinh 345 kV Transmission Line
. Sigurd-Red Butte-Crystal 345 kV Transmission Line
. Wallula to McNary 230 kV Transmission Line
. Snow Goose 5OO|23O kV Substation
. Vantage to Pomona Heights 230 kV Transmission Line
. Goshen-Sugarmill-Rigby 16l kV Transmission Line
. Goshen#3 345116lkV700Megavolt-Ampere("MVA")Transformer
Installation
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Rocky Mountain Power
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My testimony demonsffates that the Company has made prudent decisions related to
these projects and that these investrnents result in an immediate benefit to PacifiCorp's
customers in Idaho. I recommend that the Idaho Public Utilities Commission
("Commission") find these investrnents prudent and in the public interest.
III. OVERVIEW OF PACIFICORP'S TRANSMISSION SYSTEM AND
II\WESTMENT DRIVERS
Please briefly describe PacifiCorp's transmission system.
PacifiCorp owns and operates approximately 16,500 miles of transmission lines
ranging from 46 kV to 500 kV across multiple western states. PacifiCorp serves over
1.9 million customers with approximately 85,000 customers located in Idaho.
Please describe PacifiCorp's responsibility for maintaining reliability on its
transmission system.
In 1996, the Federal Energy Regulatory Commission ("FERC") issued Order No. 888,1
which required that transmission system owners provide non-discriminatory access to
their transmission systems. PacifiCorp is obligated under its OATT to plan its
transmission system for open access to all transmission customers. Through the OATT
Attachment K local planning process and the FERC Order 1000 regional and inter-
regional planning processes, PacifiCorp participates in open stakeholder planning
processes covering its entire transmission footprint. These planning processes result in
system plans that incorporate economics, reliabiliry and public policy inputs and
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I Promoting Wholesale Competilion Through Open Access Non4iscriminalory Transmission Services by Pub.
Util.; Recovery of Stranded Costs by Pub. Util. and Transmitting Utilities, OrderNo. 888,6l FR 21540 (May
10, 1996), FERC Stats. & Regs. fl 31,036 (1996), order on reh'g, Order No. 888-4, 62FR 12274 (Mar. 14,
1997), FERC Stats. & Regs. !f 3l,048 (1997), order on reh'g, Order No. 888-8, 8l FERC n 61,248 (1997), order
on reh'g, Order No. 888-C, 82 FERC fl 61,046 (1998).
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requirements. PacifiCorp must also coordinate with ottrer entities in the region for
ffansmission planning purposes as required under FERC Order No. 1000.2 tn addition
to these more general requirements, PacifiCorp also must comply with the specific
requirements of the mandatory reliability standards approved by FERC.
a. Who establishes transmission reliability standards?
A. FERC directs the North American Electric Reliability Corporation ("NERC") to
develop Reliability Standards to ensure the safe and reliable operation of the Bulk
Electric System ("BES") in the United States in a variety of operating conditions. On
April 1, 2005, NERC established a set of transmission operations reliability standards.
A subset of the transmission reliability standards are the transmission planning
standards ("TPL Standards"). The purpose of the TPL Standards is to "establish
Transmission system planning performance requirements within the planning horizon
to develop a BES that will operate reliably over a broad spectrum of System conditions
and following a wide range of probable Contingencies."3 The TPL Standards, along
with regional planning criteria (i.e., regional planning criteria established by the
Western Electricity Coordinating Council ("WECC") and utility-specific planning
criteria, define the minimum transmission system requirements to safely and reliably
serve customers.
z Transmission Planning and Cost Allocation by Transmission Owning and Operating Pub. Utll., Order No.
1000, 76 FR 49842 (Aug. I l, 201l), FERC Stats. & Regs. fl 31,323 (201I ), order on reh'g, Order No. 1000-A,
139 FERC fl 61,132 (2012), order on reh'g, Order No. 1000-8 l4l FERC f 6l,0ut4 (2012).
3 See http ://www. nerc.com/files/tp l-00 I -4.pd t.
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How does PacifiCorp ensure compliance with the TPL Standards?
The Company plans, designs, and operates its transmission system to meet or exceed
NERC Standards for BES and WECC Regional standards and criteria. To ensure
compliance with applicable TPL Standards, PacifiCorp conducts an annual system
assessment to evaluate the performance of the Company's ffansmission system and to
identifu system deficiencies. The annual system assessment is comprised of steady-
state, stability, and short circuit analysesa to evaluate peak and off-peak load seasons
in the near-term (one-, two-, and five-year) and long-term (l0-year) planning horizons.
The assessment is performed using power flow base cases maintained by WECC and
developed in coordination among all Eansmission planning entities in the Western
Interconnection. These base cases include load and resource forecasts along with
planned transmission system changes for each of the future year cases and are intended
to identifu future system deficiencies to be mitigated.
As part of the annual system assessment, corrective action plans are developed
to mitigate identified deficiencies, and may prescribe construction of ffansmission
system reinforcement projects oq as applicable, adoption of new operating procedures.
In certain instances, operating procedures prescribing action to change the
configuration of the transmission system can prevent deficiencies from occurring when
there are two back-to-back ('N-1-1") (or concurrent) transmission system events.
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aAnalyses consist of taking a normal system (N-0) and applying events (N-1, N-l-1, N-2, etc.) within each
category (P0, Pl, P2,P3, etc.) listed within the TPL Standards in order to identiff system deficiencies.
Example: An N-l-l event describes two transmission system elements being out of service at the same time, but
due to independent causes. An example of an N- I - I event would be a planned outage of one 230 kV
transmission line followed by an unplanned outage of any element in the system being used to continue service
with the initial element out.
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Howeveq the use of operating procedure actions does have limitations. In particular,
actions taken in connection with operating procedures that are designed to protect the
integrity of the larger integrated transmission system in the Western Interconnection of
the United States can lead to large numbers of customers being at risk of an outage
upon the occurrence of the second of two N-l-1 events. An effective corrective action
plan is critical to ensuring system reliability so that large numbers of customers are not
subjected to avoidable outage risk.
Is compliance with the reliability standards optional?
No. The reliability standards are a federal requirement, subject to oversight and
enforcement by WECC, NERC, and FERC. PacifiCorp is subject to compliance audits
every three years and may be required to prove compliance during other NERC or
WECC reliability initiatives or investigations. Failure to comply with the reliability
standards could expose the Company to penalties of up to $1 million per day, per
violation. Accordingly, and as described more fully later in my testimony, compliance
with reliability standards is a major driver for the new capital investments in
PacifiCorp's ffansmission assets identified in and supported by my testimony.
Please identify other drivers that are relevant to the capital investments in
PacifiCorp's transmission system described in your testimony.
There are several other drivers that inform whether PacifiCorp will build new
transmission facilities, including increased demand for transmission capaciry requests
for transmission service, and the age and condition of existing transmission facilities.
The specific drivers for the projects addressed in my testimony are described in more
detail later in my testimony.
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Rocky Mountain Power
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TV. OYERVIEW OF INMESTMENTS DESCRIBED IN TESTIMONY
What specific transmission system investments are you addressing in your
testimony?
My testimony addresses PacifiCorp's major new transmission system projects included
in this general rate case. Specifically, my testimony addresses the following projects.
l. Aeolus to Bridger/Anticline Line and network upgrades associated with new
wind generation interconnections :
The new fransmission lines consist of 140 miles of 500 kV transmission line;
the new Aeolus (500/230 kV) and Anticline (500-345 kV) substations; a five-mile,
345 kV transmission line from the Anticline substation to the Jim Bridger substation;
and a voltage control device at the existing Latham substation, as shown in the map
attached in Exhibit No. 24. The 230 kV Network Upgrades are required to
accommodate the transmission project and the interconnection of the Energy Vision
2020 New Wind Projects.
2. Mona to Oquirrh 345 kV Transmission Line Project:
The Mona to Oquirrh 345 kV transmission line project involved the
construction of a single-circuit 500 kV transmission line, energued at 345 kV
originating from the Clover substation near Mona in Juab County, Utah, extending
northward approximately 70 miles to the proposed future Limber substation located in
Tooele County, Utah, referred to as the Limber Tap, and continuing from the Limber
Tap as a double-circuit 345 kV line for approximately 30 miles to the Oquirrh
Substation in South Jordan, Utah, as shown in the map attached in Exhibit No. 25.
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Rocky Mountain Power
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3. Sigurd to Red Butte 345 kV Transmission Line Project:
The Sigurd to Red Butte 345 kV transmission line project constructed a new
single circuit 345 kV transmission line between Sigurd substation in Sevier County,
Utah and Red Buffe substation in Washington County, Utah, as shown in the map
affached in Exhibit No. 26. The project also included substation and control system
upgrades and modifications at both Sigurd and Red Butte substations
4. Wallula to McNary 230 kV Transmission Line:
The Wallula to McNary 230 kV new transmission line extending from Wallula
substation located in Wallula, Washington, to McNary substation located nearUmatilla,
Oregon, as shown in the map attached in Exhibit No. 27.
5. Snow Goose 500/230 kV Substation:
The Snow Goose 5O0l23O kV substation which is located near Klamath Falls,
Oregon, as shown in the map attached in Exhibit No. 28.
6. Vantage to Pomona Heights 230 kVTransmission Line:
The Vantage to Pomona Heights 230 kV new transmission line extending from
Vantage substation located northeast of Yakima, Washington, to Pomona Heights
substation located in Selah, Washington, as shown in the map attached in
Exhibit No. 29.
7. Goshen-Sugarmill-Rigby 161 kV Transmission Line:
The Goshen-Sugarmill-Rigby 161 kV transmission line rebuild of an existing
69 kV line from Goshen substation to Sugarmill substation and then construction of a
new l6l kV line from Sugarmill substation to Rigby substation located in the southeast
Idaho area, as shown in the map attached in Exhibit No. 30.
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Rocky Mountain Power
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8. Goshen #3 345116l kV 700 MVA Transformer Installation:
The Goshen#3 345l16l kV 700 MVA transformer installation project located
in southeast Idaho, as shown in the map attached in Exhibit No. 31.
What are the projected costs associated with these transmission investments and
their associated in-service dates?
Table 15 identifies the specific projects and associated costs and in-service dates.
Table I
Project
Total
Company
In-Service
Date
Aeolus to Bridger/Anticline 500 kV line
Sequence One (In Service)$2.1 2017
Seouence Two (In Service)$4.1 Julv 2018
Sequence Three (ln Service)$r2.7 January 2020
Sequence Four (includes202l closeout costs)$634.0 November 2020
TOTAL 500 kV line $652.9
230 kV Network Upsrades
0707 TB Flats I (includes 2021 closeout costs)$36.8 September 2020
Q7l2 Cedar Springs Wind lts) (includes 2021
closeout costs)
$s9. l November 2020
TOTAL 230 kV Network Upgrades $95.9
Other Transmission Proi ects
Mona to Oquinh 345 kV Transmission Line (In
Service)
$363.9 May 2013
Sigurd-Red Butte 345kV Line
Sequence One (In Service)$2.2m Mav 2013
Sequence Two (In Servtce $349.0m May 2015
Sequence Four (In Service)S3.4m June 2017
Wallula to McNary 230 kV New Transmission Line
Sequence One (In Service)$6.4 December 2017
Sequence Two 0n Service)s36.2 Januarv 2019
5 As discussed later in my testimony, Sequence One of the Aeolus to Bridger/Anticline 500 kV line was placed
into service in 201l.
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Snow Goose 500-230 kV New Substation Proiect
Sequence One (In Service)s10.3 May 2Ol7
Sequence Two fln Service)s32.s November 2017
Vantage to Pomona Heights 230 kV New $63.8 May 2O2O
Goshen-Sugarmill-Rigby I 6 I kV Transmission Line Project
Sequence One (tn Service)$26.0 November
2020
Sequence Two (In Service)$3. I February 2021
Sequence Three $9.2 May 2021
Sequence Four $1.2 July 2O2l
Sequence Five $7.0 Dec202l
Sequence Six
(not included in this case)N/A February 2022
Goshen #3 345lL6l kV 700 MVATransforrner Install TPL
Sequence One (In Service)$21.0 December
2020
Sequence Two $9.7 June 2021
Sequence Three
(not included in this case)N/A March2O23
These amounts include costs associated with engineering, project management,
materials and equipment, construction, right-of-way, and an allowance for funds used
during consffuction. These costs are also shown in the testimony and exhibits of
Mr. Steven R. McDougal. The in-service dates are based on the best available
information at the time of preparing this case.
a. Please briefly describe the benelits associated with these investments.
A. The benefits associated with these invesffnents include increased load serving
capability, enhanced reliability, conformance with NERC Reliability Standards,
improved transfer capability within the existing system, and relief of existing
congestion. These benefits will be described more fully below.
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Rocky Mountain Power
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Will PacifiCorp's OATT transmission customers pay for some of these assets?
Yes, through OAIT transmission charges. The Company's current transmission
formula rate (included in PacifiCorp's OATT) was approved by FERC in Docket No.
ERll-3643.6 The Company's transmission formula rate is updated annually with the
annual transmission revenue requirement ("ATRR") that represents the annual total
cost of providing frrm transmission service over the test year. The AIRR calculation
incorporates all fi'ansmission system investrnents by the Company, a return on rate
base, income taxes, expenses, and certain revenue credits, among other specific
elements and adjustments. Transmission assets, including new transmission capital,
are included in the AIRR, weighted by months in service. The AIRR is converted
into a rate by dividing the ATRR by frm transmission demand. All third-party
revenues for transmission service (along with third-party revenues for ancillary
services) are included as revenue credits in the calculation of rates in each of the
Company's retail jurisdictions.
Please explain how network upgrade cost allocation works under the OATT.
In accordance with its OATT, when PacifiCorp receives a request for generation
interconnection or ffansmission service, the Company completes sfudies to determine
what new facilities or upgrades to existing facilities are required to accommodate the
request. The studies identifu the facilities and upgrades required and classifu the asset
additions required to support the service into two categories: direct assigned or network
upgrade. Direct assigned assets are those assets that only benefit or are used solely by
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6 In re PacifiCorp, 143 FERC fl 61,162 (May 23,2013) (letter order approving settlement agreement
establishing formula rate).
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the customer requesting generator interconnection or transmission service. Those costs
are directly assigned and paid for by that customer and will not be included in either
the Company's AIRR or retail rate base. Network upgrades, on the other hand, are
those assets that benefit all customers using the ffansmission system. Costs associated
with network upgrades are investments by the ffansmission provider and are included
in PacifiCorp's ATRRT and retail rate base.
V. AEOLUS TO BRIDGER/ANTICLINE TRANSMISSION LINE AND
NETWORK UPGRADES
Please describe the investment for the Aeolus to Bridger/Anticline transmission
line that is included in the Energy Vision 2020.
The Aeolus to Bridger/Anticline ffansmission line was planned to be placed in-service
in four sequences. The first sequence was the purchase of property used for the new
Aeolus andAnticline substations, which was completed in March 2011. The second
sequence was to construct a replacement access bridge over the Medicine Bow River
and complete associated upgrades to an existing unpaved county road in July 2018. The
third sequence of work, completed in January 2020, was the expansion of the Latham
Substation with a new line termination bay to accommodate the installation of a static
synchronous compensator voltage control device. Finally, the last sequence of plant in-
service, completed in November 2020, included the two 500 kV substations (i.e. Aeolus
7 For generation interconnection customers, those customers may be required to pay the initial cost of network
upgrades, subject to refund through credits to invoiced charges lbr transmission service and full refund of any
remaining amounts after 20 years. ,See Section I1.4 of PacifiCorp's Standard Large Generator Interconnection
Agreement (OATTAttachment N, Appendix 6 and available at
http://www.oasis.oati.com/woa/docVPPW/PPWdocs/20200501_OAfTMASTER.pdf); see also Standardization
of Generator Interconnection Agreements and Procedures, Order No. 2003-8, 109 FERC n il,287 (Dec. 20,
2004).
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I and Anticline), the static synchronous compensator voltage control device and the
500 kV transmission line.
Please describe the 230 kV Network Upgrades associated with the Energy Vision
2020 Projects.
The generation interconnection projects selected as part of a request for proposal to
interconnect 1,150 megawatts ("MW') of new wind generation to the transmission
system in eastern Wyoming were fully described in Case No. PAC-E-17-078 and are
summarized below. Separate generation interconnection agreements were negotiated
and signed for each ofthe projects.
The Ekola Flats network upgrades were placed in-service inAugust 2020. This
work included one 230 kV circuit breaker and one line position with associated
switches, which were included in the Aeolus substation scope of work. As such there
are no stand-alone network upgrade costs associated with the Ekola Flats project.
The TB Flats I and II network upgrades were placed in-service in November
2020. This project included a new l6-mile 230kV ffansmission line parallel to an
existing 230 kV line from Shirley Basin substation to Aeolus substation and included
modifications at the Shirley Basin substation.
The Cedar Springs network upgrades were placed in-service in December 2020.
This project included the reconstruction of four miles of an existing 230 kV
transmission line between Aeolus substation and the Freezeout substation, including
the modifications required at the Freezeout substation; the reconstruction of 14 miles
8 In the matter of the Application of Rocky Mountain Power for a Certificate of Public Convenience and
Necessity and Binding Ratemaking Treatmentfor New Wnd and Transmission Facilities, Case No. Pac-E-17-
07, Ordet No. 34 104 (July 20, 20 I 8).
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of an existing 230 kV transmission line between the Freezeout substation and the
Standpipe substation, including modifications as required at the Freezeout and
Standpipe substations; and the reconstruction of 16 miles of an existing 230 kV
transmission line from the Aeolus substation to Shirley Basin substation.
Did the Company implement any contingency options on the project?
Yes. PacifiCorp instituted a contingency plan for two components of the 230 kV
Network Upgrades. Construction work was hampered during the winter/spring seasons
of 2020 on account of severe winter weather. The Bureau of Land Management
imposed stringent winter game restrictions that adversely affected construction. The
dates affected by the additional Bureau of Land Management restrictions were the
May 2020 estimated completion dates for two ffansmission line segments ofthe 230 kV
Network Upgrades: Aeolus to Shirley Basin andAeolus to Freezeout.
The only impact from the additional restrictions was an anticipated delay to
supplying back-feed power to the Ekola Flats wind project, which was needed by
June 15, 202O.The Company, however, implemented a contingency plan that supplied
the back-feed power needed, on a temporary basis, by the June 15, 2020 date, until
substantial completion the Aeolus to Shirley Basin and Aeolus to Freezeout
transmission lines was achieved on November 4,2020. No other contingency solutions
were required.
What were the major milestones to achieve in-service of the Aeolus to
Bridger/Anticline transmission line and 230 kV Network Upgrades?
Major milestones are identified below:
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1 500 kV Transmission
! Mechanical Completion; September 22,2020
! Substantial Completion; November 4,2020
500 kV Substations
! Mechanical CompletionAeolus 230 kV yard; May 27,2020
E Substantial CompletionAeolus 230 kV yard; June 15,2020
! Mechanical Completion (all remaining work); October 30,2020
E Substantial Completion (all remaining work); October 31,2020
230 kV Network Upgrades
I Aeolus to Shirley Basin Substantial Completion: October 3l,2O2Oe
E Aeolus to Freezeout Substantial Completion: October 23,202010
I Freezeout to Standpipe Substantial Completion: October 13,2020
E Aeolus to Shirley Basin (rebuild) Substantial Completion: November
5,2020
Please describe the total cost of the Aeolus to Bridger/Anticline transmission line
compared to the amount approved in Case No. PAC-E-17-07.
The actual and forecasted costs of the Aeolus to Bridger/Anticline transmission line are
$652.9 million, approximately $26 million lower than the $679.2 million approved in
Case No. PAC-E-17-07. The entire cost oftheAeolus to Bridger/Anticline transmission
line will be incurred by the Company without contribution from any transmission
customer projects.
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e Changed from May 15,2020, due to additional restrictions imposed by the Bureau of Land Management.
r0 Changed from May 30,2020, due to additional restrictions imposed by the Bureau of Land Management.
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Please describe the total cost of the 230 kV Network Upgrades compared to the
amount approved in Case No. PAC-E-17-07.
The 230 kV Network Upgrades actual and forecast cost are $95.9 million,
approximately $17.9 million more than the $78.0 million estimate approved by the
Commission.ll
What are the drivers for the cost increase?
The increase in cost was due to the competitive bid price received for the transmission
line elements of the 230 kV Network Upgrades, which exceeded the initial forecast
value. The increase in ffansmission line costs are attributable to market conditions that
changed after the initial cost estimate was prepared in early 2Ol7 and approved by the
Commission in Case No PAC-E-17-07. The estimate was prepared using historical
metrics to develop a cost plan, which could not have accounted for the rapid expansion
of projects in the industry that occurred just prior to the time of the bid, including
Pacific Gas & Electric Company's transmission improvement program, initiated in
response to extensive wildfires in California. Further increases were caused by extreme
weather conditions, birds and nesting environmental concerns, and delays in getting
required outages from the Western Area Power Administration.
Did the Company issue a request for proposals for the 230 kV Network Upgrades?
Yes. The competitively bid price reflected excess demand on lineman resources as a
result of the increased project demand described above. In addition, the increase in
projects also created cost impacts on steel and other materials. Several potential bidders
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tt In the Matter of the Application of Rocky Mountain Powerfor a Certificate of Public Convenience and
Necessity and Binding Rate Making Trealment for New Wind and Transmission Facilities, Case No. PAC-E- I 7-
07, Order No. 34104 (Jul. 20, 2018).
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who had previously done work for PacifiCorp declined to bid, citing lack of resources
as their reason. Nevertheless, a subsequent final competitive auction among finalist
bidders resulted in an approximate 4.5 percent reduction from the original bid value.
Why was there an increase for the 230 kV Network Upgrades but not for the
Aeolus to Bridger/Anticline transmission line?
The Company sought bids for theAeolus to Bridger/Anticline transmission line earlier
in the process. The construction requirements in California following the wildfires,
however, changed the market conditions when the Company went to bid the 230 kV
Network Upgrade proj ects.
How does the current cost projection for the Aeolus to Bridger/Anticline
transmission line and 230 kV Network Upgrades compare to what was filed in
Case No. PAC-E-17-07?
The current cost projection for the remaining work to complete the Aeolus to
Bridger/Anticline transmission line and230 kV netvrork upgrades is approximately $8
million lower than the amount approved in Case No. PAC-E-17-07 .
yr. THE MONA-TO-OQUrRRrI345 KV TRANSMISSION LrNE PROJECT
Please describe the Mona-to-Oquirrh Project.
This Project was one component of the Company's long range transmission plan and
consists of a single-circuit 500 kV transmission line, energized at 345 kV, originating
from the Clover substation near Mona in Juab County, Utah, extending northward about
70 miles to the proposed future Limber substation to be located in Tooele County, Utah,
referred to as the Limber Tap, and continuing from the Limber Tap as a double-circuit
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345 kV line for approximately 30 miles to the Oquirrh Substation in South Jordan,
Utah.r2
To accommodate the Mona-to-Oquirrh transmission lines, the Oquirrh
substation was upgraded and modified. In addition, the Company constructed the
500kV/345kV/l38kV Clover substation located approximately three miles south of the
Mona substation. The Clover substation, that went into service in December 2012, is
the southern termination point of the Mona-to-Oquirrh Project and was necessary to
provide local 138 kV transmission service to reliably support customers in the local
area. The Clover substation will also be the southem termination point for the future
Gateway South project, although the upgrades necessary to accommodate Gateway
South are not being done at this time, and the costs associated with those upgrades are
not included in this proceeding.
What is the status of the Mona-to-Oquirrh Project?
Construction on the Mona-to-Oquinh Project began in March 2011. The 500/345 kV
transmission line between the Clover and Oquirrh substations was placed into service
in May 2013. Construction of the Clover Substation started inAugust 20ll and was
placed into service in December 2012.
How did the Company ensure that the costs expended to engineer, design, site, and
build the Mona-to-Oquirrh Project were the most cost effective for its customers?
From a planning perspective, the Company applied prudent industry standards to
identifu the best transmission route and substation locations in order to balance
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12 See map in Exhibit No. 25
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engineering requirements, environmental impacts, project costs, and impacts to
communities during the siting process, while ensuring that the siting criteria
requirements were met. This included the completion of project siting and routing
feasibility studies by the Company between 2005 and 2O07, and the completion of the
National Environmental Policy Act Environmental Impact Statement process between
January 2007 and February 2011, resulting in an agency "Record of Decision." This
process determined the final "preferred" transmission line route and substation
locations, which were then incorporated into the Company's competitive bidding
process for construction.
Please describe the Company's competitive bidding process for the Mona to
Oquirrh 345 kV transmission line project.
The Company initiated a competitive bidding process to receive blind sealed bids for
the project to be delivered on a turnkey, fixed price, guaranteed completion date basis
using an engineer, procure, and construct ("EPC") contract. The competitive bidding
process began in July 2009 and provided trvo separate blind-sealed bidding
opportunities. All bid responses were due in October 2009 and again in June 2010 after
additional information was provided to bidders allowing a refinement of previously
submitted design solutions and terms and conditions, including price. Seven qualified
bids were received in October 2009. After extensive evaluations of bidder proposals
and review of exceptions to work scope and base terms and conditions from each bid
proposal, the final two most qualified bidders were identified. The Company received
best and final offers from the final two competing proposals in June 2010. The
Company awarded the contract and issued a notice of intent in December 2010, with a
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notice to proceed issued in February 2011. This process resulted in the Company
obtaining the lowest risk evaluated cost for delivery of the Mona-to-Oquirrh Project.
With respect to the construction of the Mona-to-Oquirrh Project, how did the
Company ensure that the costs to build the project were controlled?
EPC contracts are regarded in the industry as a prudent approach to control costs and
manage design, procurement, and construction risks. EPC conffacts provide schedule
and cost certainty to the benefit of customers and, where possible, cap potential cost
escalations upon the occurrence of defined risks. EPC contracts also ensure more timely
delivery of needed testing, commissioning, and in-service dates to support system
needs and help ensure ongoing ffansmission system reliability.
The fixed-price EPC contract for the Mona-to-Oquirrh Project has sffong
provisions to control cost and schedule variances. Where cost and schedule variances
were not included in the fixed price for certain contingent aspects of the work scope,
these items were identified as risk items and a contingent capped price and schedule
allowance were agreed to before contract execution. Contingent risk items were limited
to defined occurrences such as weather delays and environmental impacts.
How will the Mona-to-Oquirrh Project benefit the Company's customers?
The Mona-to-Oquirrh Project is a key component required for executing the
Company's current and future integrated resource plans, which require reliable
transport of designated network resources to network loads. Executing those plans is
necessary to ensure an adequate, reliable, and low-cost supply of energy is available
and benefits our customers. Having adequate long-term transmission system capacity
is fundamental in developing and executing those integrated plans.
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What analysis has the Company performed to quantify the benefits that the
Mona-to-Oquirrh Project provides to the Company's customers?
The Mona-to-Oquirrh Project, including its associated costs and benefits, was
evaluated on multiple occasions to address changes in the Company's business
environment and to ensure the Company continued to meet customer needs and
provided desired benefits.
Evaluation of the Mona-to-Oquirrh Project began in early 2007 as part of the
overall Energy Gateway analysis, where net power cost calculations were compared
against Energy Gateway construction costs and the prefened resource portfolio in the
Company's Integrated Resource Plan ("IRP") at the time.
Has additional analysis been performed since 2009 regarding the cost and benefrts
of the Mona-to-Oquirrh Project?
Yes. In August 2010, variable power production cost savings were calculated through
the IRP Production and Resource model with and without the entire Energy Gateway
project for a 5O-year period, discounted back to net present values. The variable
production cost inputs used four different combinations of COz taxes per ton and
variable future natural gas prices. These results showed a range of expected variable
production cost savings benefits between $331 million dollars to $549 million dollars
for the Mona-to-Oquirrh Project.
Was the lowest cost alternative selected and constructed to meet the Mona-to-
Oquirrh Project requirements and to the benefit of customers?
Yes. All customers benefited from the project alternative that was selected and then
ultimately constructedby the Company. This alternative selection resulted in an overall
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reduced capital investment amounting to an estimated $181 million savings over the
next best project alternative. This resulted in a lower overall revenue requirement for
the Project and ultimately for customers.
Are there other benefits to customers associated with the completion of the Mona-
to-Oquirrh Project?
Yes. Not only does the project provide new ffansmission capacity necessary to serve
our customers, but it also provides significant system and operational reliability
benefits to the existing system that mitigate the risk of customer outages and load
curtailments. The Mona-to-Oquirrh Project provides transmission reliability
improvements to the existing system between the Mona and Camp Williams
substations and between Camp Williams and the Oquirrh substation. The Mona-to-
Oquirrh Project provides a parallel and alternative transmission path providing backup
capability to the existing system in the event of a system outage.
Specifically, the project provides new transmission capacity between Camp
Williams and Oquinh eliminating the need for capital expenditures estimated at
$70 million for construction of a new 345 kV transmission line between the Camp
Williams and Oquirrh substations that would otherwise be needed for reliability in the
area
In addition, the Mona-to-Oquirrh Project provides customers with reliability
risk reduction benefits on the existing system between Mona and Camp Williams
because it reduces the exposure to customer load loss and associated energy
curtailments during transmission system outages, both planned and unplanned. The
customer load at risk reduction due to the addition of the Mona-to-Oquirrh Project has
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benefits valued over a range of potential energy replacement costs. Two scenanos
analyzed in 2013 estimated benefits between $29 million to $210 million, and the risk
reduction benefits continue to grow in 2020 to a range of $214 million to $1,765
million. The Mona-to-Oquirrh Project, by its selection and design, provides the above-
stated operational reliability benefits and reduces risk for our customers. These system
reliability benefits are not captured in Company net power cost or IRP modeling
activities.
Does the Mona-to-Oquirrh Project provide other benefrts to the Company's
transmission system?
Yes. The transmission grld can be affected in its entirety by what happens on an
individual transmission line. For example, the ffansmission path between southern and
northern Utah is comprised of several individual transmission lines or line segments. A
single outage on any of the individual lines due to storm, fire, or external human
interference can and does cause significant reductions in transmission capacity and can
negatively affect our ability to serve customers. The Mona-to-Oquirrh Project allows
the Company to continue to meet load service obligations in all its states and
contractual obligations to third parties under its OATT. The project connects to other
existing and future segments of Energy Gateway that interconnect the Company's
western and eastern balancing areas, increasing the ability to transport low-cost energy
to the benefit of all our customers. The Mona-to-Oquirrh Project also improved the
Company's access to energy markets, including the Energy knbalance Market.
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Are there other benefits you see from this Mona-to-Oquirrh Project?
Yes. The Mona-to-Oquirrh Project is necessary to maintain the Company's compliance
with mandatory reliability standards, while providing the next necessary increment of
transmission capacity for our customers. It also supports and can be reliably integrated
with other future planned transmission investments that are currently proposed by the
Company and other utilities in the WECC region. This project positions the Company
to be more strongly interconnected to other regional projects currently being planned
and provides options for access to additional future energy resources.
Was the Mona-to-Oquirrh Project included in a Company IRP?
Yes. The Company's 201I IRP included the Mona-to-Oquinh Project as part of the
modeled transmission topology for the purpose of selecting the Company's preferred
portfolio of future supply-side and demand-side resources. The 20ll IRPAction Plan,
Chapter 9, included a number of actions needed to deliver the plan, one of which was
to "Permit and construct a 500 kV line between Mona and Oquirrh." In Chapter 10,
Transmission System Action Plan, the Company provided detailed information for the
Mona-to-Oquirrh Project. The project was necessary to integrate network generation
resources identified in the IRP into the Company's extensive transmission system to
meet our customers' energy demands. The Commission accepted the Company's 2011
IRP.13
t3 In the Matter of the Filing by PacifiCorp dba Roclry Mountain Power of its 20ll Integrated Resource Plan,
Case No. PAC-E-ll-10, Order No. 32351 (Sept. 16, 20ll).
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Was the Mona-to-Oquirrh Project included in previous IRPs?
Yes. The Mona-to-Oquirrh Project was evaluated for cost-effectiveness from an
integrated system benefis perspective as part of the 2007 IRP filed with the
Commission in May 2007. This analysis helped support the decision to include the
Mona-to-Oquirrh Project as part of the Company's preferred resource portfolio.
Were alternatives to the Mona-to-Oquirrh Project considered?
Yes. Long-term altematives to constructing a new transmission line are limited;
however, alternatives were assessed by the Company during the IRP process.
Alternatives considered included: (1) electric load and demand-side management and
energy conservation as part of the Company's IRP; (2) the installation of new
generation facilities within the Salt Lake City area; and (3) additional capacity to
existing transmission lines and alternative transmission technologies. As a result of the
resource portfolio modeling conducted for the 2011 IRP, the Company concluded that
none of these alternatives met the Company's needs and long-term requirements, and
additional transmission transfer capability in Utah presented the lowest overall cost and
was the best alternative to meet our customers' demand for electricity.
YII. SIGURD TO RED BUTTE 345 KV TRANSMISSION LINE PROJECT
Please describe the investment for the Sigurd to Red Butte 345 kV Transmission
Line Project.
This project is a 170-mile single circuit 345 kV line from Sigurd substation in Sevier
County, Utah to Red Butte substation in Washington County, Utah, as shown in the map
attached in Exhibit No. 26. This project was placed in-service in three sequences. The
first sequence, placed in-service in May 2013, was the Three Peaks series capacitor
upgrade. The second sequence included all segments of the new 345 kV transmission
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line, as well as the required upgrades and modifications at Red Butte and Sigurd
substations. Sequence three was the completion of the final cultural report required as
part of the National Environmental Policy Act permitting process.
a. Please explain the benefits of this investment in the Sigurd to Red Butte 345 kV
line and why it is needed.
A. The Sigurd to Red Butte 345 kV line provides a reliable and adequate supply of
electricity to meet existing and future electrical loads. Without the increased
transmission capacity provided by the Sigurd to Red Butte 345 kV line, the Company
would have faced an increased and unacceptable risk of not being able to meet its load
service obligations during peak periods. The Sigurd to Red Butte 345 kV transmission
line enhances the Company's ability to provide safe, reliable, and effrcient service to
all customers. Further, to provide low-cost energy, the Company must have the ability
to acquire power from numerous generation sources to negotiate the most competitive
pricing.
The addition of the Sigurd to Red Butte 345 kV line is an important piece in
strengthening the Western Interconnection transmission infrastructure. The Sigurd to
Red Butte 345 kV line has resulted in a stronger interconnection with other parts of the
Western lnterconnection, providing better ffansmission system access to the other
sources of generation. The Sigurd to Red Butte 345 kV line, especially when
complemented with other projects, such as the Populus to Terminal transmission project
and the Mona to Oquirrh transmission project, greatly strengthens the Company's
transmission capacity and flexibility. This is necessary based upon the near-term and
long-term load growth projections of the Company and its transmission customers, as
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well as the contingencies and restrictions occurring on the system during outage
conditions.
IIas the investment in the Sigurd to Red Butte 345 kV line enhanced PacifiCorp's
access to wholesale markets?
Yes. By adding transmission capacity, the Company has increased its ability and
options to obtain power from additional generation sources at competitive pricing. In
December 2015, Nevada Energy joined the EIM and established an Energy Transfer
System Resource ("ETSR") at Red Butte. The Red Bufte ETSR provides PacifiCorp
the ability to facilitate intra-hour ffansfers between NV Energy and the rest of the EIM
footprint. Were it not for the investment in the transmission segment, PacifiCorp's EIM
transfer capability would likely be 200 MW lower at this ETSR, providing less
customer benefits.
Please explain the benelits of the investment in the Three Peaks series capacitor
upgrade and why it was needed.
To support the additional load flows brought about by the completion ofthe new Sigurd
to Red Butte 345 kV line, the Three Peaks series capacitor needed to be modified to
increase the current (ampere) rating. The Three Peaks series capacitor upgrade had to
be placed in-service before placing the new transmission line between Sigurd and Red
Butte substations in-service. With the completion of the Three Peaks series capacitor
project ahead of the Sigurd to Red Butte 345 kV line, the southem Utah transfer
capability was increased.
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1Q.Did PacifiCorp consider alternatives to investing in Sigurd to Red Butte 345 kV
Transmission Line Project?
The Company took significant steps to identify and implement alternatives that delayed
the need for the Sigurd to Red Butte 345 kV Transmission Line Project. These included:
(l) completion of interimprojects in 2009 which added major equipment to the existing
Three Peaks substation, thus improving the 345 kV system operation and increasing
reliability for serving the general area; (2) addition of major equipment and devices in
201I to the existing Red Butte substation, which increased system capacity, improved
volage support, and maintained the reliability of the system in the general area; and
(3) the addition of a3451230 kV 375 MVA transformer, also in 2011, to the Harry Allen
substation. These projects, along with special operating procedures, allowed the
Company to delay the Sigurd to Red Butte line until the summer of 2015.
PacifiCorp also considered advancing construction of a 345 kV transmission
line from Sigurd to St. George, Utah. The 20ll Southwest Utah Joint Study Report,
conducted in association with Utah Associated Municipal Power Systems, Deseret
Power, and PacifiCorp determined that a future transmission line beyond the proposed
Sigurd to Red Butte 345 kV Transmission Line Project will be needed between Sigurd
and St. George, Utah, when load and reliability requirements reach a critical point, at
the time estimated to be beyond 2025.r4 The planned Sigurd to St. George, Utah 345
kV line would be 185 miles in length, compared to 170 miles for the Sigurd to Red
Butte 345 kV line, and would have been more costly and provided fewer system
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ra Updated studies now indicate load and reliability requirements in the area do not require additional action
until 2028.
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benefits than the enhanced interconnection with a neighboring balancing authority area.
Additionally, the future line will connect to four substations instead of the two which
the Sigurd to Red Butte 345 kV line connects to.
VII. WALLULA.MCNARY 230 KV NEW TRANSMISSION LINE
Please describe the investment for the Wallula to McNary 230 kV New
Transmission Line.
The Wallula to McNary 230 kV New Transmission Line project consisted of trvo
sequences of work, the combined costs of which are included in this general rate case.
The first work sequence was placed in-service in December 2Ol7 for $6.4 million and
included expansion at PacifiCorp's Wallula substation, as well as relay and
communications work at the Nine Mile substation. The second sequence of work was
the construction of the new 230 kV transmission line that went into service in January
2019, for $36.2 million. A one-line diagram of the Wallula to McNary 230 kV New
Transmission Line project is included in Exhibit No. 27.
Please explain why this investment in the Wallula to McNary 230 kV New
Transmission Line project was necessary.
The Wallula to McNary 230 kV New Transmission Line project was needed to enable
PacifiCorp to comply with PacifiCorp's OAIT, its transmission service agreements,
and FERC's requirements to provide the requested transmission service. Before this
line went into service, there were only two MW of available transfer capacity on the
existing line between Wallula and McNary, which was insufficient to satisff the
requests for service from providers of generation capacity from renewable resources.
The completion of the project now enables PacifiCorp to fulfill such requests in
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compliance with its OATT requirements and will also increase the Company's access
to generation capacity from new resources.
In addition, the project enhances transmission reliability by providing a second
connection between the Bonneville Power Administration's ("BPA") McNary
substation and PacifiCorp's Wallula substation. With only a single line between Wallula
and McNary, line outages (either planned or unplanned), historically caused disruption
of service to customers. This disruption resulted in loss of service under existing
contracts or reduced reliability for customers served from the Wallula substation. The
new second line will provide service reliability in a single line outage condition, and,
because it was consffucted with lightning protection, the new line reduces lightning-
caused voltage sag events in the area.
O. Did PacifiCorp consider alternatives to investing in the Wallula to McNary 230 kV
New Transmission Line project?
A. Yes. In lieu of the selected project, PacifiCorp considered re-building the existing
Wallula to McNary 230 kV transmission line to a double circuit line, but this project
had an estimated cost of $73.6 million. As a second alternative, PacifiCorp considered
re-conductoring the existing Wallula to McNary 230 kV transmission line with high
temperature conductor This alternative would have required the addition of phase
shifting fransformers to produce increased flow on the line and a new substation to
place the equipment at an estimated cost of $53.6 million. Both alternatives were
rejected due to cost savings associated with investing in the Wallula to McNary 230 kV
New Transmission Line project.
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YIII. SNOW GOOSE 5OO/230 KV NEW SUBSTATION
Please describe the investment for the Snow Goose 500/230 kV New Substation
project.
This project consisted of constructing a new 500/230 kV substation located near
Klamath Falls, Oregon, as shown on the map provided in Exhibit No. 28. The new
Snow Goose substation has a 500/230 kV 650 MVA transformer bank and associated
switchgear. In addition, PacifiCorp constructed 0.5 miles of 230 kV transmission line
and 1.2 miles of 500 kV transmission line to integrate the substation into the area's 230
kV and 500 kV systems. The 230 kV yard was placed in-service in May 2017, and the
500 kV yard was placed in-service in November 2017, for a total of $42.8 million. A
oneJine diagram of the Snow Goose 5OO123O kV New Substation project is also
included in Exhibit No. 28.
Please explain the benefits of this investment in the Snow Goose 500/230 kV New
Substation and why it was necessary.
The need for the Snow Goose 5001230 kV New Substation project was based on
achieving continued compliance with reliability standards mandated by NERC under
the TPL Standards. In 2012, PacifiCorp performed TPL Standards screening studies
that identified system performance deficiencies following the single contingency loss
of PacifiCorp's existing 5OO|23O kV, 650 MVA transformer bank at Malin substation.
Specifically, PacifiCorp determined that during the 2017 projected sunrmer peak load
conditions, the loss of the transforrner bank would result in the system failing to meet
the low voltage limits on the PacifiCorp-owned 230 kY ll5 kV and 69 kV systems
and an increase in the load on the Copco-Lone Pine 230 kV line. By 2027, the Copco-
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Lone Pine 230 kV line would exceed its rated thermal continuous and emergency
capacity during this outage. This outage would also cause a reduction of the power flow
on the Alturas-Reno WECC Path 76. As a result, firm scheduled transfers on this line
could not continue to be supported without a second 230 kV source.
Construction of the Snow Goose substation provided a second 500 kV to
230 kV transmission tie in the area ensuring that PacifiCorp is able to maintain
adequate system voltage and power delivery during a single contingency outage
condition, thus maintaining service for customers in southern Oregon and northern
Califomia.
Did PaciliCorp consider alternatives to investing in the Snow Goose 500/230 kV
New Substation project?
Yes. In lieu of the Snow Goose 5OOl230 kV New Substation project, PacifiCorp
considered resolving the deficiencies under the TPL Standards by installing a second
transformer at Malin substation and building a second line from Malin to Klamath
Falls. This altemative was rejected as the Malin substation could not be readily
expanded to accommodate a new 500/230 kV transformer position due to physical site
constraints. This alternative was estimated to be $85.0 million.
A second alternative would have involved installing a 5OO/230 kY 650 MVA
transformer at the BPA-owned Captain Jack substation and building 27 miles of 230 kV
line from Captain Jack to Klamath Falls. Adding another transformer at Captain Jack
substation would require increasing the size of the substation property and reaching an
agreement with BPA. This alternative was estimated to be $90.0 million and was
rejected because of insufficient space at the BPA-owned Captain Jack substation,
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inadequacy of the site in serving as a new source of 69 kV to the Klamath Falls
metropolitan area, and additional reinforcement requirements of the 230 kV path
between Captain Jack and Klamath Falls substations.
The last alternative considered would have involved installing a 500/230 kV,
650 MVA transformer at the Klamath Co-Gen substation and building a new 230 kV
line to tap the Klamath Falls-Boyle 230 kV line. As with the first alternative, this option
was rejected due to space and cost limitations. Estimated costs for this alternative were
$85.0 million.
IX. VANTAGE TO POMONA IIEIGHTS 230 KV NEW TRANSMISSION LINE
Please describe the investment for the Vantage to Pomona Heights 230 kV New
Transmission Line.
The Vantage to Pomona Heights 230 kV new transmission line consists of a new 4l
mile, 230 kV ffansmission line that extends from BPA s Vantage substation near
Vantage, Washington, and ends at PacifiCorp's Pomona Heights substation in Yakima,
Washington, as shown on the map attached in Exhibit No. 29.The project consists of
two sequences of work. The first work sequence to expand the Pomona Heights
substation 230 kV ring bus to provide adequate breaker separation between lines and
transformers for breaker failure and bus fault events was placed in-service in November
2015 for $9.4 million. The second sequence of work placed in-service in May 2020 for
$63.8 million included the installation of a new 230 kV transmission line connected at
BPA s Vantage substation and ending at the Pomona Heights substation. The Company
has received full federal permissions to construct this transmission line. The final
segment permission was received from the Bureau of Land Management on September
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27,2019. This portion of the project included the installation of breakers, protection
and control equipment, and communications equipment at each substation as required
to monitor and safely operate the new line. The infrastructure additions at Vantage
substation were designed, purchased, installed, and maintained by BPA. A one-line
diagram of the Vantage to Pomona 230 kV new ffansmission line is also included in
Exhibit No. 29.
Please explain why this investment in the Vantage to Pomona Heights 230 kV New
Transmission Line was necessary.
The need for the Vantage to Pomona Heights 230 kV project was identified through
intemal planning studies and a coordinated Northwest Transmission Assessment
Committee study in 2007. NERC screening studies conducted in 2009 and subsequent
NERC screening studies additionally identified TPL Standards performance
deficiencies following breaker failure and bus fault events on the Pomona Heights 230
kV bus and various N-l-l outages associated with the Wanapum to Pomona Heights
230 kV line. Breaker failure and bus fault and N-l-l events on other portions of the
Yakima 230 kV and l15 kV systems result in additional TPL Standards performance
deficiencies. In total, there are eight contingency combinations that were identified that
could give rise to the need to shed Yakima arca load. The Yakima area is currently
served primarily by two 230 kV transmission sources. The loss of both primary 230 kV
sources or loss of one primary 230 kV source and another major element in the
underlying system leaves the remaining system unable to provide adequate electric
service to all customers in the area.
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The addition of a new 230 kV line between Vantage and Pomona Heights
substations and providing a third 230 kV source to the area mitigates the identified
deficiencies. Specifically, the project eliminates the need to shed Yakima area load for
those eight contingency combinations and eliminates overloads in the PacifiCorp and
BPAtransmission systems with loss of the existing line.
By enabling PacifiCorp to comply with the TPL Standards and increasing the
reliability of PacifiCorp's transmission system by eliminating the need to shed Yakima
area load under certain outage conditions, this project provides benefits to customers.
Did PaciliCorp consider alternatives to investing in the Vantage to Pomona
230 kV New Substation Project?
Yes. ln lieu of the selected project, the new 230 kV line from Vantage to Pomona
Heights, PacifiCorp considered constructing a new 5001230 kV transformer and bus
position at Wautoma substation and a new 230 kV transmission line from Wautoma
substation to Pomona Heights substation resulting in an estimated cost of $89.6 million.
This alternative was rejected because the costs were higher than the selected project.
Another altemative would have involved consffucting a second 230 kV transmission
line from Midway substation to Union Gap substation. This alternative was rejected
because it would have only corrected the identified deficiencies for approximately l0
years before additional transmission reinforcement would be required.
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X. GOSHEN.SUGARMILL.RIGBY 161 KV TRANSMISSION LIITE PROJECT
a. Please describe the investment for the Goshen to Sugarmill to Rigby 161 kV
Transmission Line project.
A. The Goshen-Sugarmill-Rigby 16l kV Transmission Line project consists of
consffucting approximately 44 miles of new transmission lines from the Goshen to
Sugarmill and Sugarmill to Rigby substations located in southeast Idaho. This includes
approximately 22.2 miles of 69 kV line rebuilt to 161 kV and 1.6 miles of new double
circuit construction from Sandcreek substation to Sugarmill substation. Substation
expansions are required at Goshen, Ammon, Sugarmill, and Rigby substations to
accommodate the new 161 kV positions and associated sffuctures and equipment, as
shown on the map provided in Exhibit No. 30. In addition to constructing the new
ffansmission line, Ammon substation will be converted from 69 kV to 161 kV which
resulted in $6.5m of distribution plant in service in Idaho.
Idaho Falls City had a project to expand their Paine substation and build a 161
kV line to interconnect at PacifiCorp Sugarmill substation. To benefitboth sakeholders
it was agreed upon to enter into a joint agreement on the construction and ownership
of the 12 miles of 161 kV line between Sugarmill substation and Idaho Falls City's
Paine substation. The line is being constructed by ldaho Falls City, the Company is
funding 49 percent of the consfuction costs and will be a joint owner of that seguent
of the line. The Company is continuing construction of the 13-mile 161 kV line from
Paine tap to Rigby.
The overall project consists of six sequences of work. The first work sequence,
that went into service in November and December 2020 for $26.0 million, included
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rebuilding 16 miles of 69 kV to 16l kV transmission line between the Goshen and
Ammon substations and the required substation consffuction at both Goshen and
Ammon substations to terminate the new transmission line. The second sequence of
work that was placed in service in February 2021 for $3.1 million was the required
substation work at the Sugarmill substation. The third sequence of worh planned in
May 2021 for $9.8 million, is the completion of 9.2 miles of line from Ammon
substation to Sugarmill substation. The fourth sequence of work, planned to be placed
in service in July 2022 for $1.2 million, is the expansion of the Rigby substation to
accommodate the new 161 kV Transmission [ine. The fifth sequence of work, planned
to be placed in service by December 2022 for $7.0 million, is Idaho Falls City
construction of the 12-mile transmission line between Sugarmill and Paine substations.
The sixth and final sequence of the project, to be placed in service in February 2O23,is
the 13 miles of transmission line from Paine Tap to Rigby substation as well as the 3.5
miles of reconductor of the existing Sugarmill to Goshen 16l kV transmission line.
Work sequences four through six will be completed outside the test period of this case,
and none of these costs are included in the filing.
Please explain why the investment in the Goshen to Sugarmill to Rigby 161 kV
Transmission Line project is necessary.
The need for the Goshen to Sugarmill to Rigby 161 kV line was identified in the 2016
GoshenArea Planning Study to address projected overloads on the Goshen to Sugarmill
l6l kV line and Goshen to Rigby 161 kV line, in addition to low voltage at Rigby and
Sugarmill substations that manifest under heavy loading conditions. Projected peak
sunrmer load conditions in 2O2l inthe Rigby-Sugarmill area indicate that under normal
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operating conditions (N-0) the Goshen to Sugarmill 16l kV line is expected to load to
100 percent of its continuous rating of 201 MVA and the Rigby and Sugarmill
substations 161 kV bus voltage is expected to reach its minimum limit of 0.95 per unit.
Additionally, the projected load growth exacerbates several existing N-l conditions in
the area. Based on202l load, loss of the Goshen to Sugarmill 161 kV line causes the
Goshen to Rigby 161 kV line to overload to 179 percent of its four-hour emergency
rating and can result in excessively low voltage down to 0.68 per unit in the Rigby-
Sugarmill area. The loss of the Goshen to Rigby 161 kV line can cause the Goshen to
Sugarmill 161 kV line to overload to I l1 percent of its four-hour emergency rating of
255 MVA, overload to 102 percent of its 30-minute emergency rating of 279 MVA and
can cause low voltage down to 0.88 per unit at Rigby substation. The Goshen to
Sugarmill 16l kV line and Goshen to Rigby 161 kV line are operated radially during
summer heavy loading periods to mitigate the risk of violating NERC Standard TPL-
001-4 category P0 (N-0), Pl (N-1) and P6 (N-l-l) performance requirements due to
transmission capacity deficiencies in the area. Operating radially puts approximately
150 MW of load at risk for N-l loss of either the Goshen to Sugarmill 16l kV line or
the Goshen to Rigby 161 kV line and 300 MW at risk for N-l-l loss of any two
transmission lines.
The new Goshen-Sugarmill-Rigby 16l kV line will increase load serving
capacity in the Rigby-Sugarmill area by 250 MVA that will allow the ffansmission lines
between Goshen, Sugarmill, and Rigby substations to operate in a normal loop
configuration and N-l thermal overload and low voltage issues on the remaining
transmission line and substation. Benefits also include elimination of the N-0 overload
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risk, improved load service reliability under N-l conditions, and resolution of most N-
l-1 issues present in the area.
Did PacifiCorp consider alternatives to investing in the Goshen to Sugarmill to
Rigby f 6f kV Transmission Line project?
Yes. The first altemative in lieu of the Goshen-Sugarmill-Rigby 161 kV line that
PacifiCorp considered was a project to construct a new approximately 35-mile-long
Goshen to Rigby 345 kV line with 1272 alaminum conductor steel-reinforced
("ACSR") cable and add a new 450 MVA capacity or larger 345116l kV transformer at
the Rigby substation. This would involve expanding both the Goshen and Rigby
substation yards to accommodate the new facilities consisting of at least two 345 kV
breakers at Goshen, one 345 kV breaker at Rigby and at least two 161 kV breakers at
the Rigby 161 kV substation. This altemative was rejected since the estimated cost of
the project was about S17.0 million higher than the chosen project to construct the new
Goshen-Sugarmill-Rigby 161 kV transmission line. The alternative was estimated to
cost $57.7 million.
A second alternative considered was to construct approximately 61 miles of
1 61 kV transmission line from Antelope to Rigby with 1272 ACSR cable or larger. This
involved expanding both theAntelope and Rigby substation yards to accommodate the
new facilities consisting of at least two 161 kV breakers at Antelope and at least two
161 kV breakers at Rigby. A new 161 kV line from Antelope would provide a new
source into the Rigby-Sugarmill area apart from Goshen substation; however, planning
studies indicated that by adding the Antelope to Rigby 161 kV line, the N-l loss of the
Goshen to Sugarmill 161 kV line would still cause thermal overload and low voltage
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issues in the area and that load shedding and radialization of the Rigby-Sugarmill area
would still be required. This alternative was rejected since the estimated cost of the
project was about $8.0 million higher than the new Goshen-Sugarmill-Rigby l6l kV
transmission line and that a new Antelope to Rigby 161 kV transmission line does not
resolve the loading and voltage issues in the Rigby-Sugarmill area. The alternative was
estimated to be $48.0 million.
A third alternative considered was to construct approximately 22.8 miles of
161 kV transmission line from the Meadow Creek wind farm substation to Sugarmill
and Rigby substations to create a looped transmission source back to Goshen
substation. Work involved constructing approximately 5.9 miles of new single circuit
161 kV transmission line from Meadow Creek to a new tap location, using the existing
righrof-way to construct 4.5 miles of double-circuit line from the new tap location to
Sugarmill substation, and construct 12.4 miles of new single-circuit 16l kV line from
the new tap location to Rigby substation. Work also included converting Meadow
Creek's l6l kV substation yard into a new three breaker ring bus, installation of at least
two 161 kV breakers at Sugarmill and Rigby substations, rebuilding the Goshen-
Wolverine Creek-Jolly Hills-Meadow Creek 16l kV line with 1557 ACSR cable
(approximately 32.4 miles), rebuilding the remaining three miles of 795 all-aluminum
conductor ("AAC") cable on the Goshen-Sugarmill 16l kV line, and adding a 161 kV
bus tie breaker at Rigby to facilitate sectionalizing post N-1. Cunently, the Goshen
wind farms are radial from the Goshen 161 kV substation. Once looped through the
Rigby and Sugarmill substations, a detailed voltage control study would be required to
coordinate the wind farms and shunt devices in the area. Since the existing radial wind
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farm line is owned and operated by third parties, an agreement to use or buy the
facilities would need to be negotiated. This alternative was rejected since the estimated
cost of the project was about $8.2 million higher than the new Goshen-Sugarmill-Rigby
161 kV hansmission line and required siguificant coordination with third parties to
deliver the project. The alternative was estimated to be $48.5 million.
The last alternative considered was to loop the existing Goshen to Jefferson
16l kV ffansmission line in and out of the Bonneville substation. Work involved
converting the Bonneville substation into a 161 kV breaker and one-half configuration,
constructing an approximately 27-mile-long 161 kV line from Bonneville to Rigby
substation with at least 1557 ACSR cable. Work also involved expanding both the
Rigby substation yards to accommodate a new 161 kV line position consisting of at
least two 161 kV breakers at the Rigby substation. Adding this new Bonneville to Rigby
16l kV line does not improve N-l and N-l-l issues in the area and therefore is not
considered as a viable alternative. The estimate for this project was S33.2 million.
Additional projects would be required to address the N-l and N-l-l issues. These
projects include reconductoing 32 miles of Goshen to Rigby 16l kV line,
reconductoring 16 miles of Sugarmill to Rigby 161 kV line, and reconductoring 3.5
miles of 795 AAC cable on existing Goshen to Sugarmill 161 kV line. Additionally, a
new Goshen-Sugarmill 161 kV line would be required to mitigate the low voltage and
voltage swings caused by the loss of the existing Goshen to Sugarmill 161 kV line. The
estimate to reconductor these lines was $6.6 million and the estimate to construct a new
Goshen to Sugarmill l6l kV line was $13.3 million. This alternative was rejected since
the estimate for the new Bonneville to Rigby 161 kV line and supporting projects was
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about $12.7 million higher than the recommended new Goshen-Sugarmill-Rigby
l6l kV transmission line project. The alternative was estimated to be $53.1 million.
XI. GOSHEN #3 345116I KV 7OO MVA TRANSFORMER INSTALLATION
PROJECT
Please describe the Goshen #3 3451161kV 700 ltvl transformer project.
The Goshen #3 transformer project will install a third 345116l kV transformer at the
Goshen substation, located in southeast Idaho, and expand the 16l kV yard to
accommodate a new feed from the 345 kV yard. In addition, various 161 kV lines will
be relocated, and the existing Goshen 161 kV dual operate bus will be converted into a
breaker and one-half 16l kV scheme. Redundant 16l kV relays will also be installed.
The project will use a spare 345l16l kV transformer that was delivered in March 2018
and a spare 345/16lkv transformer will be purchased to be located at the Gadsby Plant
as required per PacifiCorp's grid resiliency plan. This project is being placed in service
in two sequences. The expansion of the l6l kV yard, the conversion of the bus scheme,
and the relocation of the 16l kV lines was completed in November 2020 for $20.9
million. The second sequence of work, that is planned to be placed in service in May
2021, is the installation of the 345/16l kV transformer for $9.7 million. The spare
replacement ffansformer is expected to be received in March 2022, which is outside
this rate case.
Please explain why the Goshen #3 345116l kV 700 MVA transformer project is
necessary.
The Goshen #3 transformer installation project will resolve NERC TPL-001-4
Category Pl-3 (N-l) thermal overloading issues on the existing Goshen transformers
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beginning in}O?l. The Goshen substation has two 345116l kV 450 MVA fransformers
which serve the load in the area. As loads in the Goshen area increase, the risk of
overloading one of the existing Goshen transformers due to the loss of the other
increases as well. The 2016 Goshen area studies indicated that by 202l,loss of either
one of the Goshen 345116l kV transforners can overload the remaining Goshen
345116l kV transformer above its emergency rating. Historical Goshen area load and
generation data for the 2013 to 2017 period indicated that the average risk of
overloading one of the Goshen 345l16l transforrners under an N- 1 condition was 10.5
percent each year (915 hours/38 days-the average number hours each year where area
generation was below 200 IvtW and load was in excess of 450 MW). Since a
transformer outage is a potential long-term outage (up to l8 months to order and install
a new fiansformer), the risk of overloading one of the Goshen transformers could be
present for an extended period, or until the spare can be installed which would take 2
to 3 months.
Did PacifiCorp consider alternatives to investing in the Goshen #3 345116l kV 700
MVA transformer installation project?
Yes. The first altemative considered was to add a new 345116l kV transformer at the
Rigby substation. However, since the Rigby substation does not have a 345 kV source,
a new 35-mile-long 345 kV line from the Goshen to Rigby substation would have been
required. This alternative would have also required at least two 345 kV breakers at the
Goshen substation and one 345 kV breaker and one 161 kV breaker at the Rigby
substation. In addition, an expansion of the Rigby substation yard would have been
necessary to accommodate the new 345 kV bus, transformer, breakers etc. An estimate
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of this project is $71 million. This altemative was not selected due to significantly
higher cost than the preferred solution.
The second alternative considered was to construct an approximately 61-mile-
long 16l kV line from Antelope substation to Rigby substation with at least 1272 ACSR
conductor. The un-scoped estimate for this alternative was $48.7 million. planning
studies showed that this alternative line would cause thermal overload and low voltage
issues in the area and load shedding and radialization of the Rigby-Sugarmill area
would still be required. Due to this and the increased cost for construction this
alternative was determined to not be a feasible project to improve service to the Rigby-
Sugarmill area.
XII. CONCLUSION
Please summarize your testimony.
I recommend that the Commission determine that the tansmission projects outlined in
my testimony: were necessary to ensure the Company maintains compliance with
required reliability standards; will serve increased load; will provide benefits to
customers; and are therefore prudent and in the public interest.
Does this conclude your direct testimony?
Yes.
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