20100528Cupparo Direct.pdf

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zaw HAY 28 PH 12: 05
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE )
APPLICATION OF ROCKY )
MOUNTAIN POWER FOR )
APPROVAL OF CHANGES TO ITS )
ELECTRIC SERVICE SCHEDULES )
AND A PRICE INCREASE OF $27.7 )
MILLION, OR APPROXIMATELY )13.7 PERCENT )
CASE NO. PAC-E-10-07
Direct Testimony of John A. Cupparo
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-10-07
May 2010
1 Q.Please state your name, business address and present position with Rocky
2 Mountain Power ("Company").
3 A.My name is John A. Cupparo. My business address is 825 NE Multnomah, Suite
4 1600, Portland, Oregon 97232. My position is Vice President of Trånsmission.
5 Qualifications
6 Q.Please describe your educational and professional background.
7 A.I hold a Bachelor of Science degree in Computer Information Systems from
8 Colorado State University. My experience spans 24 years in the energy industry,
9 including oil, gas and electrc utilties. The majority of my experience has been in
10 information technology supporting natural gas pipelines, energy commodity
11 trading and end-to-end electrc utilty operations. I have also provided support for
12 outage management, customer service, transmission scheduling and regulatory
13 issues. I joined PacifiCorp as Chief Information Officer in September 2000 and
14 assumed my curent position in August 2006. I am responsible for all aspects of
15 PacifiCorp's main grid transmission investment strategy, customer service, main
16 grid planning, contract admnistration and tarf management. I am the co-chair
17 of the Nortern Tier Transmission Group ("NTTG"), which coordinates
1 8 transmission planning, transmission expansion, and project reviews with sub-
19 regional and regional planning organizations within the Western Electricity
20 Coordinating Council ("WECC"). I am also an elected class one voting member
21 (transmission owner class) of the WECC Board of Directors. As a member of the
22 WECC Board of Directors, I paricipate with other WECC members in overseeing
23 WECC's activities, including defining standads and policies to ensure reliabilty
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1 of the western electrc grid. I also hold a position on WECC' s Transmission
2 Expansion Planning Policy Commttee and the Reliability Coordination
3 Commttee.
4 Purpose and Overview of Testimony
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What is the purpose of your testimony?
The purose of my testimony is to provide information on the Populus to
Termnal transmission line, which is the first segment of the Energy Gateway
transmission expansion plan to be constrcted, and for which the Company is
seeking cost recovery in this case. The Populus to.Termnal transmission line,
and subsequent investments within the Company's.long-term, comprehensive
transmission expansion plan known as "Energy Gateway," satisfy multiple
objectives for efficiently operating a six-state transmission system. The
immediate benefit toPacifiCorp's customers in Idaho and elsewhere is a
significant investment to enhance reliabilty and improve transfer capabilty
. within the existing system, followed over time by incremental capacity, which is
key to unlocking rich resource hubs. Specifically, my testimony:
. Provides an overview of the Company's transmission system;
. Outlnes the Company's transmission expansion plan and provides details on
the Populus to Termnal line segment of this plan;
. Demonstrates that the Populus to Termnal transmission investment is
beneficial to customers; and
. Describes how the Populus to Termnal transmission investment helps satisfy
a commtment the Company made as par of the MidAmerican Energy
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Holdings Company ("MEHC") transaction.
Company witness Mr. Darell T. Gerrard provides testimony with additional
details and technical information on the Populus to Termnal transmission
investment.
What investment related to the Populus to Terminal transmision line is
included in the revenue requirement of this rate case?
The estimated cost of the Populus to Termnal trnsmission line to be placed in-
service in the test period of this rate case is approximately $802 millon. . This line
is one of the first components of the Company's comprehensive plan related to
investment in the transmission system. The Populus to Termnal transmission line
is a new double~circuit 345 kilovolt ("kV") transmission line from the Populus
substation near Downey, Idaho to the Termal substation in Salt Lake City, Uta,
which wil be placed in service in two phases. The first phase from the Ben
Lomond substation (near Ogden, Uta) to the Termnal substation was placed in
service in March 2010, and the second phase from the Populus substation to the
Ben Lomond substation wil be in service by November 30,2010. The testimony
of Company witness Mr. Steven R. McDougal describes the revenue requirement
calculations associated with this transmission investment.
19 Overview of PacifCorp's Transmision System
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Pleas briefly describe PacifiCorp's transmission system.
PacifiCorp owns and operates approximately 15,800 miles of transmission lines
ranging from 46 kV to 500 kV across multiple western states. As of December
31,2009, PacifiCorp's total-company net transmission plant in service was
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approximately $2.2 bilion. PacifiCorp is interconnected with more than 80
generation plants and 15 adjacent control areas at approximately 124 points of
interconnection. To provide electrc service to its retail and wholesale customers,
PacifiCorp owns or has interest in generation resources directly interconnected to
its transmission system with a system peak capacity of approximtely 12,131
MW. This generation capacity includes a diverse mix of resources including coal,
hydro, wind power, natural gas simple cycle and combined cycle combustion
turbines, and geothermaL.
Please describe the availabilty of existing transmission capacity on the
system.
The Company's 2008 Integrated Resource Plan ("IRP"), which was filed with the
Idaho Public Utilties Commssion ("Commssion") in May 2009 and
acknowledged in September 2009, identifies the need for investment in major new
transmission facilities.to provide ongoing reliabilty and.to meet the forecast loads
ofPacifiCorp's customers. The IRP analysis is performed by evaluating loads
and resource requirements overa twenty-year period.
PacifiCorp's existing transmission system, as well as the transmission grid
across the western region, is severely constrained, and numerous regional study
groups have identified the pressing need for investment in new transmission
infrastrcture. These studies are described in more detail later in my testimony.
Additionally, new federal standards that mandate increased transmission
system reliabilty along with PacifiCorp's recent operational experience require
additional investments in PacifiCorp's transmission system to ensure the
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Company has the capabilty to provide reliable transmission service under
expected operating conditions, and to maintain the transmission system capacity
necessar to deliver network load service and contractual point-to-point
commtments.
Increasing PacifiCorp' s transmission capacity wil also provide the
opportnity for the Company to make off-system energy purchases or sales,
which are used to reduce overall power supply costs. Lastly, additional
transmission capacity provides the Company added flexibilty in the location and
use of generating reserves and flexibilty to perform routine maintenance on
transmission lines with minimal risk, all of which reduce operating costs to
customers.
Please generally describe . how Pacifi Corp's transmission expansion. plan
became a component of IRP.
As par of MEHC' s acquisition of PacifiCorp, the Company performed a review
of the IRP process. From that review, the Company determned there was a need
for a long-term transmission investment strategy to support the long-term resource
needs of customers. Historically, IRPs were relatively silent on transmission
investments, assuming transmission would follow generation investments. Given
the long-term needs of customers and load growth, existing transmission system
constraints, the time required, and the challenges associated with designing,
permtting and constrcting transmission lines, transmission is now a key element
of the Company's IRP. This shift in focus is evidenced by the inclusion of
Energy Gateway in PacifiCorp's 2008 IRP.
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1 Overview of Energy Gateway Transmission Expansion
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Please generally describe Energy Gateway.
Energy Gateway is a comprehensive transmission plan based on takig immediate
actions while keeping long-term needs in focus. Energy Gateway wil enhance
reliabilty, reduce transmission system constraints and improve the flow of
electrcity to PacifiCorp's customers. The Energy Gateway plan is comprised of
eight interrelated and interdependent transmission segments as outlined in Exhibit
No. 33. The eight line segments within Energy Gateway are grouped and labeled
as par of Gateway Central, Gateway West, Gateway South and the Westside.
The Populus to Termnal line segment is within Gateway Central. When fully
implemented, Energy Gateway wil traverse six states, numerous communities,
. counties and significant areas of federally-admnistered lands and wil add
approximately 2,000 miles of new transmission lines to PacifiCorp's transmission
system. Due to the interconnected natue of PacifiCorp's transmission network,
investments may be required at other facilities in order to maximize the
effectiveness and efficiency of the network. For Energy Gateway, the eight
identified transmission segments provide specific capabilties, but they also
support other transmission segments to enhance the benefits of Energy Gateway.
Please describe Gateway Central relative to the overall Energy Gateway
plan.
Gateway Central includes the Populus to Termnal, Mona to Oquirh and Oquirh
to Termnal transmission lines that wil improve reliabilty and transfer capabilty
to the existing system and also establish the necessar electrcal interconnection
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1 between Gateway West and Gateway South. The Gateway West and Gateway
2 South segments, when complete, wil be the first 500 kV lines to be installed in
3 Wyoming, southeast Idaho and Uta. Gateway Central wil provide an essential
4 reliabilty backbone allowing Gateway West and Gateway South to operate at a
5 higher reliability and at an overall higher capacity than would otherwise be
6 possible without the Gateway Central interconnection. This investment wil not
7 only add incremental trsmission capacity, but wil also strengthen PacifiCorp's
8 overall system while supporting future generation resource development to
9 benefit all PacifiCorp customers.
10 As described earlier in my testimony, the Populus to Termnal
11 transmission segment is comprised of two smaller sections, which in total extend
12 135 miles from the new Populus substation near Downey, Idaho, south to the
13 existing Termnal substation near the Salt Lae International Airort west of Salt
14 Lake City, Uta. The Populus to Termnal transmission segment is a key element
15 of the Energy Gateway's Gateway Central. Populus to Termnal is designated as
16 "Segment B" within Gateway Central in Exhibit No. 33.
17 Populus to Terminal Transmission Investment
18 Q.Please describe the Populus to Terminal transmission investment in more
19 detaiL.
20 A.Exhibit No. 34 is a map of the Populus to Termnal transmission line segment.
21 Ben Lomond to Termnal is the southern section and is highlighted in red on the
22 map. Populus to Ben Lomond is highlighted in yellow, green and blue on the
23 map. Phase I from Ben Lomond to Termnal was the first setion of the Populus
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to Termnal line to be completed and became operational in March 2010. Phase II
from Populus to Ben Lomond is scheduled to be complete and in service by
November 30, 2010.
Please describe the findings of the regional transmission studies related to
Energy Gateway and specifically the Populus to Terminal segment.
Over the past decade, numerous studies were completed documenting the need for
new transmission in the western United States. As early as 2002, the Deparment
of Energy National Transmission Grid Study identified the Wyoming-Idaho
interface as a major constrained interface. The study also found that under
optimal conditions, the Wyoming-Nortern Utah interface is congested during 50
percent or more of the hours during the year. 1
In 2004, the Rocky Mountain Area Transmission Study reached simlar
conclusions and recommended expansion of the 345 kV transmission lines
connecting the Company's Bridger substation to points south and west as
critically needed improvements.2 In addition, the U.S. Deparment of Energy's
2006 National Electric Transmission Congestion Study ("DOE Congestion
Study") identified several constrained transmission paths in the west as shown in
Exhbit No. 35, including lines used to deliver electricity from generation plants
in Wyoming to loads in the west.3 Specifically, the DOE Congestion Study
1 National Transmission Grd Study at pp. 15, 18. A full copy of this report is available at
http://www.pi.energy.gov/documentsrrransmissionGrd.pdf.
2 Rocky Mountain Area Transmission Study at Chapter 3-2, which shows the Bridger expansion as a
critical expansion area from Wyoming to Nortern Utah and Wyomig to Idaho. The full report is available
at htt://psc.state.wy.us/htdocs/subregionaleport.htm.
3 See DOE Congestion Study at pp. 31-35. The transmission constrints identifed in this study were
identifed by reviewing recent transmission studies such as those conducted by WECC and Seams Steerig
Group-Western Interconnection. The full report is available at
http://nietc.anl.gov/documentsldocs/Congestion_Study _2006-9MB. pdf.
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1 ilustrated that expansion of the Bridger West transmission facility is critical for
2 relieving congestion from Wyoming to northern Utah, and Wyoming to Idaho.4
3 Similarly, the Western Interconnection 2006 Congestion Assessment
4 Study, which was issued by the DOE Western Congestion Analysis Task Force,
5 identified areas of congestion in the Rocky Mountain States and projected that
6 based on 2005 load and resource forecasts and a production model, many of the
7 paths associated with the varous segments of the Energy Gateway Project would
8 be heavily congested.5
9 Reports initiated by the Western Governors' Association ("WGA") also
10 show certain paths in PacifiCorp's service terrtory (includig the Populus to
11 Termnal segment) as constrained.6
12 In addition, the DOE sponsored a study through Idaho National
13 Laboratories to assess the economic impact of not building transmission. While
14 the report focused on assessing the economic impact on the Pacific Northwest, it
15 also provides discussion and support for the "hub and spoke" design which is
16 similar to the Energy Gateway model for connecting resource areas to load. The
17 report also describes the interconnected natue of transmission as being
18 geographically dispersed, yet interdependent.7
4 Such expansion is addressed by the Segment E porton of the Project.
5 A full copy of this study is available at http://www.oe.energy.govlDocumentsandMedia/
DOE_Congestion_Study _2006_ Western_Analysis.pdf.
6 The full report is available at http://www.westgov.org/wga/initiatives/cdeacrrransmissionReport-
final.pdf.
7 See The Cost of Not Building Trasmission: Economic Impact of Propose Tranmision Line Projects
for the Pacifc Nortwest Economic Region. Full report is available at
http://www.pnwer.org/Portal/O/Pesentations/2008%20summitlCost%200f%20not%20building%20tansm
ission.pdf.
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1 Existing NTTG sub-regional trnsmission planning studies, conducted in
2 accordance with the Federal Regulatory Energy Commssion's ("PERC") Order
3 890- A, show overall benefits to the region as a result of PacifiCorp' s proposed
4 Energy Gateway.
5 PacifiCorp filed for incentive rates with FERC on July 3, 2008, which is
6 analogous to a need determnation. FERC granted the Company incentive rate
7 treatment, and of equal importance, PERC issued a 4-0 decision stating:
8 (w)e find that PacifiCorp has adequately demonstrated that the
9 Project (with the exception of segment A) wil ensure reliabilty
10 and reduce transmission congestion... We find that segments B
11 through H of the Project would establish for the first time a
12 backbone of 500kV transmission lines in PacifiCorp's Wyoming,
13 Idaho and Utah regions. This would provide a platform for
14 integrating and coordinating futue regional and sub-regional
15 electrc transmission projects being considered in the Pacific
16 Nortwest and the Intermountain West, connecting existing and
17 potential generation to loads in an efficient manner, thus reducing
18 the cost of delivered power. Also, the Petition cites the 2006 DOE
19 National Electric Transmission Congestion Study and the 2004
20 Rocky Mountain Area Transmission Study in stating that that
21 proposed Project wil reduce congestion or maintain reliabilty in
22 the Western Interconnection. Additionally, the project would
23 establish a direct link between PacifiCorp's east and west control
24 areas, providing numerous benefits including increasing trnsfer
25 capabilty, reducing the need for curtailments, and reducing26 transmission congestion.8
27 Commssioner Suedeen Kelly echoed PacifiCorp's Petition in her concurence
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29 ". . . while Segments Band C provide a varety ofbenefits when considered in
30 isolation, they also enable PacifiCorp to achieve the planned transfer capabilty
8 PacifCorp, 125 FERC ei 61,076 (2008) at p. 10, (Exhibit No. 36).
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rating of subsequent segments." 9 A complete copy of the report is provided as
Exhibit No. 36.
As noted in Exhibit 33, Segment B is Populus to Termnal and Segment C
is Mona to Oquirh.
What factors does the Company consider before building new transmission?
The Company considers several factors before buildinK new transmission
facilties including:
. Curent and future forecasts for demand and energy required from existing
and new resources to new and existing loads. These considerations are
addressed in the Company's 2008IRP including demand-side management
and energy conservation programs.
. Alternatives, including building local generation near load, and/or energy
market purchases.
. The Company's abilty to use existing land rights, existing rights-of-way, and
corrdors.
. The use of upgrades to increase operabilty and reliabilty of existing
transmission lines and substations.
. The Company's ability to maximize the capacity and capabilties of existing
facilties.
Because prudent transmission investments are typically large scale to maximize
efficiencies and gain economies of scale, the benefits are realized over the long
term.
9 Exhibit No. 36, p. 25.
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Once the decision is made to invest in new transmission, what is the process
for getting it built?
Once the decision is made to invest in new transmission, capacity sizing of the
transmission line is taken into consideration to balance curent and futue nees.
Constrcting long, linear facilties such as transmission lines requires a long lead
time and is an extensive process. Siting, permtting and constrcting new
transmission can tae up to seven years and potentially involves acquirng new
rights-of-way and permts from local, state and federal agencies. Maximizing the
transmission capacity placed in approved corrdors is a critical consideration to
minimize disruption to communities and landowners. The Company also
considers design and routing to minimize the environmental, visual and human
impacts.
What land rights and permits were acquired for Populus to Terminal?
The Company holds all of the necessar land rights, either in easements or fee
ownership, between the Populus substation and the Termal substation.
However, the Company was required to secure numerous permts and approvals
from federal and state entities, such as:
. The U.S. Ary Corps of Engineers required permts for construction within
jurisdictional wetlands.
. The Federal Aviation Admnistration required aviation permts for
construction of Populus to Termnal near Salt Lake International Airort.
. The Utah and Idaho Departents of Transporttion required permts from
railroad companies for roadway crossings, overhangs and easements.
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. The U.S. Bureau of Reclamation required a crossing permt for the Ogden-
Brigham canaL.
. The Utah Deparent of Wildlife Resources required a permt for crossing
Wildlife and Waterfowl Management Areas, with a separate agreement
required for constrction within the Legacy Natue Preserve.
. The U.S. Fish & Wildlife Service, U.S. Forest Service and Utah State
Historical Preservation Office also required various wildlife & environmental
habitat permts.
What permits were required by local governmental authorities for the
construction of Populus to Terminal?
The Company holds a franchise agreement with each municipality and county
within the route that grants the necessar rights for the construction of the
Populus to Termnal transmission line. In addition, the Company secured
conditional use and/or special use permts from all Idaho and Utah cities and
counties, based on each community's requirements. The Utah Public Service
Commission ("Utah Commssion ") and the Idao Public Utilities Commssion
("Idaho Commission") issued Certificates of Public Convenience and Necessity in
2008. The Idaho Commssion Order states:
Thus, Staff believes that the necessity of the Project should be
viewed in conjunction with energy resources that are constructed,
under way or planned. PacifiCorp elected to undergo a
transmission upgrade as par of its preferred resource portfolio of
an additional 2,000 MWs of renewable resQurces by 2013 in the
Company's 2007 IRP. A significant portion of these renewable
resources wil be located in Wyoming. Staff then listed more than
500 MW s of renewable resources that are either under construction
or in the final stage of development. In response to a Staff data
request, PacifCorp provided four alternatives that it rejected
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because the Company did not believe that these would provide
sufficient capacity for the new resources. Staff agreed that the
Project was necessar in order for the Company to continue to
provide reliable service from these new resources to growing load
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In its Order, the Utah Commssion noted several paries concurred with the nee,
including the Division of Public Utilties:
The Division states it has examined underlying informtion upon
which a need for these additional transmission facilities may be
found and concludes it supports RMP's decision to build the
Transmission Line and confirs RMP's planned integration and
operation of the line with future utilty operations and activities.
The Division agrees with RMP's conclusions that there is a need
for the Transmission Line and the Company's futue utility service
wil be more reliable and efficient with the Transmission Line's
addition. 1 1
Please describe the bidding process the Company used to award contracts for
the construction of the new transmission.
The Company initiated a competitive tendering process to receive blind, sealed
bids for the project work Scope to be delivered on a turney, fixed-price,
guaranteed completion-date basis using an engineer, procure and constrct form
of contracting. The competitive tendering process began in October 2007 and
provided two separate blind, sealed bidding opportnities. All bid responses were
due for submittal in May 2008 and again in July 2008 after the Company provided
additional information to bidders allowing a refinement of previously submitted
design solutions, and terms and conditions, including price. The Company
lOIn the Matter of the Application of Rocky Mountain Power for a Certficate of Public Convenience and
Necessity Authoriing Constrction of the Populus-to-Terminal 345 KV Trasmision Line Project, Case
No. PAC-E-08-03, Order No. 30657 (October 10,2008) at pp. 3-4.
11 In the Matter of the Application of Rocky Mountain Power for a Certficate of Public Convenience and
Necessity Authoriing Constrction of the Populus to Termnal 345 KV Trasmision Line Project, Doket
No. 08-035-42, Report and Orer Granting Certficate and Certficate of Public Need and Necessity,
(September 4, 2008) at p. 3.
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received and evaluated thee qualified bids resulting from the May 2008 proposal
submissions. Durig the evaluation period one of the bidders withdrew its
paricipation. The Company received two competing proposals in July 2008 with
qualified prices of $609 millon and $528 millon, respectively. After extensive
evaluations of bidder proposals and review of exceptions to work scope and base
terms and conditions from each bid proposal, the Company ultimately awarded
the contract in October 2008, detas of which are provided in Mr. Gerrard's direct
testimony. The scope of the bidding process included the Populus to Termnal
segment, which includes the sections outlined in Exhibit 34. The bid process is
described in more detail in Mr. Gerrard's testimony.
Why did the Company use the engineer, procure and construct approach?
The engineer, procure and construct ("EPC") solicitation is a common form of
contracting for large construction projects like the Populus to Termnal
transmission segment and is regarded as a prudent approach for cost control and
managing design, procurement and construction risks. This approach: (1)
. provides certainty relative to schedule and cost outcomes for the benefit of
customers; (2) caps potential cost escalations where possible based upon the
occurrence of defined risks; and (3) ensures more timely delivery to support
system needs and transmission reliabilty.
Please explain what you mean concerning capping costs based upon the
occurrence of identifed risks.
The fixed-price EPC approach has minimal provisions for cost and schedule
varances. Where cost and schedule variances were not included in the fixed price
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for certain contingent aspects of the work scope, these items were identified as
risk items and a contingent capped price and schedule allowance was agreed upon
prior to contract execution should any of these risk items materialize. Contingent
risk items were limited to defined occurrences such as weather delays,
environmental impacts and sub-surace ground conditions.
How wil the Populus to Terminal transmision line benefit PacifiCorp
customers?
The Populus to Termnal transmission line and subsequent investments within
Energy Gateway satisfy multiple objectives for effciently operating a six-state
transmission system in the long term. The initial benefit to PacifiCorp customers
is a significant investment to enhance reliabilty and improve transfer capabilty
within the existing system. In the futue, this investment wil also provide
benefits of incremental capacity to deliver generation resources within the
Company's 2008 IRP.
Reliability is fundamental to effectively and efficiently managing the
Company's six-state transmission system. As a federally-regulated transiIssion
provider, the Company must comply with reliabilty standards mandated by
FERC though the North American Electrc Reliabilty Corporation ("NERC")
and WECC. By meeting these standards the Company continues to maintain a
stable and reliable system durg a varety of operating conditions, which
minimizes potential outages to all customers and financial impacts of having to
deliver higher-cost resources if required. Populus to Termnal increases overall
reliabilty, benefiting all PacifiCorp customers.
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1 Populus to Termnal also increases transfer capabilty from nort to south
2 and south to nort across the Company's transmission system. By doing so, the
3 Company addresses a key constraint (Path C), meets an MEHC transaction
4 commtment and improves the Company's abilty to import and export lower-cost
5 resources depending on seasonal needs and operating conditions. The benefit to
6 all PacifiCorp customers is the abilty of the Company to use the least-cost
7 dispatch of resources to serve loads and manage power costs by sellng excess
8 energy off-system or importing lower-cost market energy to serve load. Also, by
9 providing incremental transmission capacity though this transmission segment,
10 the Company has more flexibilty in locating reserves on PacifCorp-owned
11 generation, and making full use of the Nortwest Power Pool reserve-sharng
12 program. This program allows the Company to cover reserve requirements
13 without having to build additional generation. Increasing the import capabilty
14 allows better access to those reserves, thereby reducing costs for all customers.
15 Reliability and transfer capabilty provide benefits based on the existing system.
16 Populus to Termnal also establishes incremental capacity to provide long-
17 term benefits to customers. Populus to Termnal is the first step within the
18 Energy Gateway strategy to access resources at their source of production.
19 Benefits wil accrue to energy consumers and energy producers by alowing
20 economic resources, new and existing, to be developed and delivered across the
21 Company's service terrtory.
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Did MEHC and PacifiCorp make specific commitments related to investment
in PacifiCorp's transmission system as part of the acquisition approval
process?
Yes. The regulatory commssions in all six states in the Company's service
terrtory approved the Company's capital commtments specifically in
transmission and distribution as par of the acquisition of the Company by
MEHC. MEHC made specific commtments and developed plans for a significant
capital expansion program across the system to support future demands and
growth of its customers. As par of the acquisition approval process, MEHC
commtted to increase transfer capacity on a constrained path known as Path C by
300 MW.12 Populus to Termnal improves the capacity on Path C and has a
planned increase in transfer capacity of 1,400 MW when combined with other
segments of Energy Gateway. As such, the Populus to Termnal transmission
segment wil significantly improve a point of constrant on the system that
currently affects numerous transmission customers, wil strngthen reliability and
wil enable the Company to achieve the planned transfer capabilty rating of
18 subsequent Energy Gateway segments.
19 Conclusion
20 Q.Please summarize your conclusions.
21 A.New transmission is essential to enhance transmission system reliabilty, provide
22 capacity to integrate resources for the long-term benefit of customers and meet
23 load growth. Populus to Termnal is the first step to increase transmission
12 See Order No. 29998 at Page 6 (Commtment No. 34).
Cupparo, Di - 18
Rocky Mountain Power
1
2
3
4 Q.
5
6 A.
7
8
9
10
11
12
13 Q.
14 A.
capacity within PacifiCorp's six-state transmission system. This investment and
subsequent investments in Energy Gateway are prudent, cost effective and
beneficial to customers.
Is the inclusion of Populus to Terminal in Idaho rates in the public interest
and if so, why?
Yes. The Populus to Termnal and subsequent investments within Energy
Gateway satisfy multiple objectives for efficiently operating a six-state
transmission system. The initial benefit to PacifiCorp's customers is enhanced
reliabilty and improved transfer capabilty within the existing system. In the
future, it wil also provide incrementa capacity for delivery of resources within
the Company's 2008 IRP, which is a key to unlocking rich resource hubs for the
benefit of all PacifiCorp customers and ultimately the western interconnect.
Does this conclude your direct testimony?
Yes.
Cupparo, Di - 19
Rocky Mountan Power
Case No. PAC-E-I0-07
Exhbit No. 33
Witness: John A. Cupparo
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of John A. Cupparo
Gateway Map
May 2010
Rocky Mountain Power
Exhibit No. 33 Page 1 of 1
Case No. PAC-E-10-07
Witness: John A. Cupparo
PacifiCorp service area
Planned transmission lines:
~ 500 kV minimum voltage
""w 345 kV minimum voltage
.,.""., 230 kV minimum voltage
o Transmission hub
. Existing substation
This map is for general reference only and reflects the expansion necessary to construct Energy Gateway
to its full capacity of 6000 MW. It may not reflect the final routes or construction sequence.
Case No. PAC-E-1O~07
Exhibit No. 34
Witness: John A. Cupparo
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of John A. Cupparo
Populus to Termnal Map
May 2010
Case No. PAC-E-I0-07
Exhibit No. 35
Witness: John A. Cupparo
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of John A. Cupparo
DOE Congestion on Western Paths Map
May 2010
Rocky Mountain Power
Exhibit No. 35 Page tof 1
Case No. PAC-E-10-07
Witness: John A. Cupparo
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Case No. PAC-E-I0-07
Exhibit No. 36
Witness: John A. Cupparo
BEFORE THE IDAHO PUBLIC UTILITffS COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of John A. Cupparo
Incentive Rate Order
May 2010
Rocky Mountain Power
Exhibit No. 36 Page 1 of 29
Case No. PAC-E-10-07
Witness: John A. Cupparo
125 FERC 161,076
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULA TORY COMMISSION
Before Commissioners: Joseph T. Kelliher, Chaian;
Suedeen G. Kelly, Marc Spitzer,
and Jon Wellnghoff.
PacifiCorp Docket No. EL08-75-000
ORDER ON PETITION FOR DECLARATORY ORDER
(Issued October 21,2008)
1. On July 3, 2008, PacifiCorp filed a petition for declaratory order (Petition)
pursuant to section 219 of the Federal Power Act (FPAi and Order No. 6792 seeking
incentive rate treatment for its Energy Gateway Transmission Expansion Project
(Project). The Project, described by PacifiCorp as eight interdependent line segments,
wil expand PacifiCorp's transmission network by 2,00 miles of extra-high voltage
(EHV) transmission lines. PacifiCorp seeks a 250 basis point adder to its base retu on
equity (ROE) and recovery of prudently-incured abandonment costs if the Project is
cancelled due to factors beyond its control. For the reasons discussed below, we wil
grant in par, and deny in par, PacifiCorp's Petition and grant in par, anddeny in par,
the requested incentive rate treatment for its Project.
I. Background
2. According to PacifiCorp, the Project is one of the most ambitious electrc
infrastructue projects planned in the western United States in the past two decades. The
Project wil enlarge and expand PacifiCorp's system-wide transmission network by
adding approximately 2,000 miles of new EHV transmission lines in the six-state region
including California, Idaho, Oregon, Uta, Washington, and Wyoming, and deliver up to
3,000 MW of capacity from location-constrained renewable resources in Wyomíng to
distant load centers; its estimated cost exceeds $6 bilion. PacifiCorp claims that the
Project wil provide its customers with substantial economic, reliabilty and
1 16 U.S.C. § 824s (2006).
2 Promoting Transmission Investment through Pricing Reform, Order No. 679,
FERC Stats. & Regs. 131,222, order on reh'g, Order No. 679-A, FERC Stats. &Regs.
131,236 (2006), order on reh'g, 119 FERC 161,062 (2007).
Docket No. EL08~75-000
Rocky Mountain Power
Exhibit No. 36 Page 2 of 29
Case No. PAC-E-10-07
Witness: John A. Cupparo
environmental benefits, including reducing transmission congestion and the futue cost of
delivered power thoughout the six-state service terrtory.
3. According to PacifiCorp, the Project is a backbone transmission project providing
a platform for integrating and coordinating futue regional and sub-regional electrc
transmission projects being considered in the Pacific Nortwest and the Intermountain
West. Its configuration is described as a "hub and spoke" design which is characterized
by PacifiCorp as major EHV transmission lines that connect areas with a strong potential
for generation resource development (hubs) to an enhanced transmission system (spokes)
for delivery to customers thoughout the western United States. Under the Project, hubs
are planned for western Wyoming, south central Wyoming, southwestern Idaho, south
central Utah, and southern Oregon. From the hubs, power wil be collected and moved in
different directions to permt PacifiCorp to efficiently deliver power from a varety of
generation sources to load. According to PacifiCorp, the additional transmission
infrastrctue and the "hub and spoke" design wil provide flexibilty, improve efficiency
and enable development of clean and renewable energy resources. and wil ensure that
PacifiCorp's system wil be capable of meeting futue regional needs: 3
4. PacifiCorp states that each of the eight interrelated line segments has been
assigned one of four priority classifications for constrction.4 PacifiCorp explains that
most of the segments are dependent on the development of other segments and the
priority levels have been established to ensure the most prudent approach to deliver
completion of the Project. Four segments comprise Priority One of the Project (segments
A, B, C and G). According to PacifiCorp, these segments are being built to enhance the
base load service and reliabilty of PacifiCorp' s transmission system. PacifiCorp
anticipates that these segments wil be among the earliest portions of the Project to be
placed into.service, and it has begun the preliminar permtting and contracting work to
get these segments on-line between 2010 and 2014.5
3 PacifiCorp Petition at8 and 9.
4 According to PacifiCorp, the priority classification assigned to each segment is
drven by efficiency and cost-effective development and constrction of the Project;
therefore, PacifiCorp clustered segments offering similar general benefits and asset in-
service dates.
5 Segment A is a 230 kV segment which wil extend approximately 56 miles
between Walla Walla, Washington and Umatila, Oregon and cost roughly $108 milion.
Segment B is a double circuit 345 kV line that wil be constrcted in two segments. The
line wil run from a new substation near Downey, Idaho 135 miles south to an existing
substation near Salt Lake City, Utah; the estimated cost is $800 milion. Segment C
extends north from central Uta running 86 miles nort to two futue substations. It is a
(continued. . .)
Docket No. EL08-75-000
Rocky Mountain Power
Exhibit No. 36 Page 3 of 29
Case No. PAC-E-10-07
Witness: John A. Cupparo
5. Two segments comprise Priority Two (segments D and E). PacifiCorp states that
the two segments are designed to enhance the resource adequacy of the region by
connecting transmission-constrained wind resources in Wyoming to westward load
centers.6 Two segments comprise Priority Three of the Project (segments E and H).
PacifiCorp states that these segments are intended to integrate its two control areas within
the Project footprint, and to provide a means for transmitting renewable energy supplies.7
Prority Four consists of segment F which is intended to provide back-up system
reliabilty, as well as rating support for PacifiCorp's newly enhanced system.s
6. The application states that three of the segments may be upsized from a single-
circuit to a double-circuit system.9 PacifiCorp states that it is actively working with
. potential equity parners to determne the interest and commtment to pursue a double-
circuit configuration for these segments.
double circuit line which wil have one segment constrcted at 500 k V and the other at
345 kV and is expected to cost $425 milion. The segment Gtransmission line is
approximately 280 miles and wil connect an existing substation in central Utah to
another substation nort of Las Vegas, Nevada. The lines are planned as a single circuit
345 kV line, and could be upsized to include a 500 kV line configuration. The estimated
cost is $754 milion.
6 The two portions of segment D wil consist of roughly 300 miles of new
transmission line running from eastern Wyoming to western Wyoming and is estimated
to cost approximately $880 millon. PacifiCorp states that the segment wil consist of
two single circuit 230 kVlines, and a double circuit 500 kV1230 kV line. The 230 kV
segment of the line could be upsized to 500 kV. Segment E, also comprised of two
sections both single-circuit 500 k V lines, wil run from a planned generation resource hub
near Rock Springs, Wyoming, across Idaho to a point southwest of Boise, Idaho and cost
an estimated $1.02 bilion.
7 Segment E continues the single circuit, 500 kV, Priority Two line running to
western Idao. Segment H, single circuit 500 kV line, wil run 375 miles from an
existing substation in western Idaho to a Bonnevile Power Administration substation in
nortern California. The cost is estimated at $786 millon.
S Segment F which is also a single circuit, 500 kV line extends approximately 395
miles from a new substation in southeastern Wyoming to central Utah. Segment F is
expected to cost $764 millon.
9 PacifiCorp Petition at n.9 and Cupparo Affidavit at 10-12.
Docket No. EL08-75-000
Rocky Mountain Power
Exhibit No. 36 Page 4 of 29
Case No. PAC-E-10-7
Witness: John A. Cupparo
A. Requested Incentives
7. PacifiCorp requests a 250 basis point adder to its base ROE for the revenue
requirement associated with the capital costs of its Project, not to exceed the upper end of
the zone of reasonableness as determined in a futue proceeding under FP A section 205.
PacifiCorp asserts that the ROE adder is necessar to compensate it for the unusual and
significant project risks.
8. PacifiCorpalso requests authorization to recover all prudently-incured
development and constrction costs if the Project is cancelled or abandoned, in whole or
in par, as a result of its inabilty to obtain necessar approvals, or as a result of any
action or inaction by a governmental authority, or regulatory agency, for any reason
outside PacifiCorp's control.
9. PacifiCorp states that it qualifies for the rate incentives because of the scope and
magnitude of the Project, because it is intended to respond to regional needs in Idaho,
Oregon, Uta, Washington, and Wyoming, and because it wil improve reliabilty, reduce
congestion, provide transmission access for renewable resources, provide transmission
for forecasted load growth and wil deploy advanced transmission technologies. As the
Project will diectly link PacifiCorp'seast and.west control areas, it wil minimize
congestion and relieve loading along paths between Wyoming and areas west and south,
and, by adding interconnections and increasing transfer capacity, the Project wil reduce
the need for curailments and improve access to generation resources needed to meet
system demand and reserve obligations.1o
10. PacifiCorp asserts that it is entitled to a rebuttable presumption of eligibilty for
the requested incentives under Order No. 679 because nearly all segments of the Project
(except segments A and C) were planned and approved under a Fast Track Process
developed in 2007 by the planning commttee of the Nortern Tier Transmission Group
(NTTG), prior to finalizing requirements for the NITG's planning process required by
Order No. 890.11 Additionally, PacifiCorp states that NTTG's 2007 Annual Report
10 See PacifiCorp Petition, Cupparo Affidavit at 19.
11 Preventing Undue Discrimination and Preference in Transmission Service,
Order No. 890, 72 Fed. Reg. 12,266 (March 15,2007), PERC Stats. & Regs. 1 31,241
(2007), order on reh'g and clarifcation, Order No. 890-A, 73 Fed. Reg. 2984 (Jan. 16,
2008), FERC Stats. & Regs. 1 31,261 (2007), order on reh' g and clarifcation, Order
No. 890-B, 123 PERC 161,299 (2008). According to PacifiCorp, the Fast Track
provided a forum for stakeholder input and paricipation in the identification of Fast
Track projects critical to relieving areas of congestion and improving reliabilty. See
PacifiCorp Petition, Cupparo Affidavit at 15-16.
Docket No. EL08-75-000
Rocky Mountain Power
Exhibit No. 36 Page 5 of 29
Case No. PAC-E-10-07
Witness: John A. Cupparo
identified the need for all ofPacifiCorp's proposed segments (except segment A) to
increase transmission capacity in order to reduce congestion and improve reliabilty.12
PacifiCorp states that following the NTTG planning committee approval of the 2007
Annual Report and Fast Track recommendations, the Project (with the exception of
segments A and C) was submitted for Western Electrcity Coordinating Council (WECC)
regional planning review.
13
11. In the event that the Commssion determnes PacifiCorp is not entitled to that
rebuttable presumption, PacifiCorp argues in the alternative that the benefits from
constrcting the Project neverteless satisfy the eligibilty criteria of Order No. 679.
PacifiCorp contends that the Project, once completed, wil result in increased reliabiltl4
and a reduction in congestion. Specifically, PacifiCorp points out that the Project wil:
(1) establish a 500 kV backbone; (2) reduce curailments resulting from over scheduled
use; (3) provide additional access to resources and reserves; (4) increase the diversity of
the available resource mix; (5) connect its two control areas (Pacific Power and Rocky
Mountain Power) to better serve network load; and (6) help satisfy state renewable
portolio requirements. The Petition references numerous transmission studies
identifying constrained paths and intedaces and other areas critical for relieving
congestion in the region; PacifiCorp states that the Project is its response to these
findings, as well as responding to the projected demands on its available capacity due to
growth of its network load obligation. PacifiCorp also highlights that the Project wil
enable it to link remote renewable resources to load centers thoughout the West.
12. At this time, PacifiCorp is not seeking to change its rates under FPA section 205,
but states that it wil make a subsequent section 205 rate filing in the futue to implement
the incentive rate treatment. PacifiCorp also explains that it wil ask state regulators to
include the Project's investment in retail electrc rates; to the extent that the recovery of
all of the transmission investment is permtted in its retail rate base, "PacifiCorp wil
compensate its retail customers by crediting the transmission-related revenues, inclusive
of any incentives granted by the Commssion, against its retail revenue requirement."is
12 According to the Petition, the Fast Track process relied on studies previously
done within the region to identify congested transmission that impedes efficient and
reliable operation of the grid.
13 See PacifiCorp Petition, Cupparo Affdavit at 17.
14 PacifiCorp states that, by adding critical EHV infrastrcture to the bulk power
transmission system, the Project wil provide contingency capacity thoughout the
system, thereby enhancing reliabilty within the NTTG footprint and the broader region.
15 PacifiCorp Petition at 4.
Docket No. EL08-75-0oo
Rocky Mountain Power
Exhibit No. 36 Page 6 of 29
case No. PAC-E-10-07
Witness: John A. Cupparo
PacifiCorp expects that the requested incentives wil be an important consideration in
obtaining state regulator support for including the reliabilty and futue growth elements
of the Project in retail rates.
B. Risks and Challenges
13. PacifiCorp states that its approach to this Project is a significant depare from
past approach~s to the development of major transirssion projects. It notes that
historically such projects were built when associated generation resources were sited;
however, PacifiCorp notes that with the current uncertnty of conventional generating
technology, the time required to permt and construct major transmission and the inabilty
of many renewable resource developers to finance major transmission investments,
. transmission must be sited "ahead" of specific generation resources to best position
utilties to meet futue forecasted load growt. PacifiCorp asserts that with this approach,
PacifiCorp faces greater risks for transmission investment.
14. PacifiCorp explains that it faces signifcant financial and regulatory risks in
pursuing this Project. PacifiCorp cites the estimated $6 bilion cost, camparng that to the
average $111 millon that it spent on capital expenditues annually between 2002 and
2007, and noting that the total cost is more than three times its curent transmission rate
base of $1.8 bilion. In addition, PacifiCorp states that, since the Project would constitute
the backbone for a futue 500 kV infrastrctue in the Project footprint, it would be
"responsible for ensuring. that the underlying system . . . can withstand technical and
regulatory scrutiny, including the protection of neighboring electrcal systems.,,16
According to PacifiCorp, this factor has made it difficult to enlist additional parners in
the Project. Its financial risk is also affected by the fact that it wil be siting transmission
lines ahead of new generation resources, as noted above, and the fact that development
costs are likely to increase over time.
15. PacifiCorp asserts that its Project faces significant regulatory risks because it must
garer approval of varous state and federal authorities, including six states, the Bureau of
Land Management and the United States Forest Service. PacifiCorp also notes that trbal
issues and federal land management are implicated in the construction and development
of the Project. PacifiCorp also states that large portions of the Project are expected to
traverse federally-admnistered lands, as well as through routes that are not situated on
existing rights-of-way. PacifiCorp anticipates that proceedings wil be contested and
prolonged, and recognizes the risk of siting delays and potential re-routing that may
increase the overall cost. This, according to PacifiCorp, equates to added authorization
complexities on a scale unlike previous transmission projects for which the Commission
has granted requested rate incentives.
16 PacifiCorp Petition at 31.
Docket No. EL08-75-000
Rocky Mountain Power
Exhibit No. 36 Page 7 of 29
Case No. PAC-E-10-07
Witness: John A. Cupparo
16. Finally, PacifiCorp states that there wil be uncommon technology-related risks
because it contemplates investing in several advanced transmission technologies that
have not been widely deployed.17 PacifiCorp believes that there is added risk because
there is uncertainty as to how these technologies wil perform within this Project, and it
notes that these novel technologies "must be designed, constrcted and tested to ensure
they meet the requirements of the Project. ,,18
c. Technology Statement
17. PacifiCorp included an advanced technologies statement in its Petition as required
by Order No. .679.19 Subject to fuer study and final engineering, PacifiCorp states that
it intends to utilze several types of advanced technologies in connection with varous
segments. PacifiCorp has not, in most cases, designated the specifc segments on which
the advanced technologies wil be used. According to PacifiCorp, the technologies meet
the standard set fort in Order No. 679, and in section 1223 of the Energy Policy Act of
2005 (EPAct 2005),20 as they mitigate congestion and enhance grd reliabilty by
increasing the capacity, efficiency and reliabilty of an existing or new transmission
facilty. PacifiCorp's advanced technologies fall into the categories of advanced
conductor technology, enhanced power device monitoring, fiber optic technologies,
power electronics and other technologies.21
18. PacifiCorp intends to utilze Trapezoidal Conductor technology which involves
the use of Aluminum Conductor Steel Supportedrapezoidal Wire. According to
PacifiCorp, this advanced conductor design wil increase transmission capacity, and
reduce the sag of the transmission lines as well as avoid energy losses. PacifiCorp
intends to use this technology on 500 kV lines, anticipated to be used on segments C, D,
E, and G.22
17 As fuer discussed below, PacifiCorp plans on utilzing trapezoidal
conductors, and fiber optic shield wires in addition to other innovative technologies.
PacifiCorp Petition at 35.
18 ¡d.
19 Order No. 679, FERC Stats. & Regs.131,222 at P 302.
20 Pub. L. No. 109-58, § 1223, 119 Stat. 594,953 (2005).
21 PacifiCorp Petition at 42.
22 ¡d. at 23, Cupparo Affdavit at 24. PacifiCorp also asserts that an estimated
6,000 to 120,000 metrc tons of carbon dioxide could be avoided annually, as a result of
applying this technology.
Docket No. EL08-75~000
Rocky Mountain Power
Exhibit No. 36 Page 8 of 29
Case No. PAC-E-10-07
Witness: John A. Cupparo
19. PacifiCorp states that it is planning to use Static VAR Compensators (SVCs)
which are electrcal devices used to automatically match impedance to regular voltage
and improve both dynamc and transient network stabilty. PacifiCorp is evaluating the
installation of SVCs on several segments of the Project in order to support the required
dynamic voltage regulation and "firng up" of the system, and also improve reliabilty,
power quality, contingency recovery, create operational benefits and help maximize the
overall total transfer capabilty. 23
20. PacifiCorp plans to use fiber optic technology in order to shield phase conductors
from diect lightning stres, provide high-capacity, high-speed communication channels
and reliably detect short circuits. PacifiCorp states that the installation of the fiber optic
technology can also create additional latent capacity bandwidth, which could also provide
an alternate secure communication path that could be used for national securty and
regional development purposes. PacifiCorp states that this technology has the potential
to be used thoughout the Project.24
21. PacifiCorp also intends to use phase shifters to improve and/or increase stabilty
limits of transmission lines when the maximum power transfer is reached. PacifiCorp
states that phase shifters help provide operational and seasonal flexibilty, and that it is
pursuing targeted applications of this technology to reduce. overall system losses by
eliminating circulating curents, and helping to protect neighboring transmission
systems.2S
22. In addition, PacifiCorp intends to employ Special Protection Schemes (SPS) to
respond to system events and distubance data that could potentially cause undue stress
on its system as necessar to maximize grid tota transfer capabilty, to improve long-
term reliabilty and reduce negative impacts to the interconnected systems, as well as to
benefit the interim ratings of the lines.26
23. Finally, PacifiCorp states that it is evaluating the use of advanced monitors in
transformers at the new substations that wil provide notification when the affected
equipment is near failure. This technology, while not required by reliability standards,
helps protect high-cost investments and improve reliabilty by providing for early
detection of potential issues.
23 PacifiCorp Petition at 45.
24 ¡d.
2S ¡d. at 46.
26 ¡d. at 47.
Docket No. EL08-75-000
Rocky Mountain Power
Exhibit No. 36 Page 9 of 29
Gase No. PAC-E-10-07
Witness: John A Cupparo
II. Notice of Filng and Responsive Pleadings
24. Notice of PacifiCorp's filing was published in the Federal Register, 73 Fed. Reg.
41,064 (2008), with interventions and protests due on or before July 24,2008. Timely
motions to intervene raising no substantive issues were filed by Horizon Wind Energy
LLC, Arizona Public Service Company; the Transmission Agency of Nortern
California, and the Utah Division of Public Utilties. Timely motions to intervene and
protests were filed by the Bonnevile Power Administration (Bonnevile), Industral
Customers of Nortwest Utiities (Industral Customers), and the Utah Municipal Power
Agency (UMPA). Utah Associated Municipal Power Systems (Utah Systems) filed a
timely motion to intervene and comments. On August 6, 2008, PacifiCorp filed a motion
for leave to answer and an answer. On September 5, 2008, UMPA responded to
PacifiCorp's answer.
25. Bonnevile claims that PacifiCorp cannot establish a rebuttable presumption, as
provided under Order No. 679, by satisfying the threshold criteria for eligibilty for
transmission incentive treatment under FPA setion 219 with a showing, in pertinent par,
that a transmissi~n project results from a fai and open regional planning process that
. considers and evaluates projects for reliabilty and/or congestion. Bonnevile notes that
PacifiCorp claims to meet this condition by vire of its paricipation in the NTTG
. planning process. However, Bonnevile contends that the Project was announced in May
of 2007, while NTTG did not sta its planning process until later that year. Thus,
according to Bonnevile, the Project could not have originated from the NTG planning
process.
26. Protesters argue that the requested 250 basis point ROE adder is too high.
Bonnevile asserts that, although some ROE adder would be appropriate, PacifiCorp's
requested incentive is i 00 basis points higher than any previously approved by the
Commssion. UMP A similarly argues that PacifiCorp has failed to justify such a large
adder, calling the 250 basis point incentive rate adder "unprecedented.,,27 UMPA also
alleges that the risks attrbutable to the Project are reduced as a result of PacifiCorp's
recovery of abandoned plant costs; thus, the proposed level of ROE adder is not
waranted.28 Utah Systems note that, although the Project may be larger than any for
which incentives were previously granted, "an incentive retur on equity generates
dollars based on a percentage of the total equity investment.,,29 According to Utah
27 UMPA July 24, 2008 Protest at 9.
28 ¡d. at.iO ("the abandoned plant rate incentive eliminates PacifiCorp's exposure
to the very risks PacifiCorp relies on to justify its extraordinar 250 basis point adder").
29 Utah Systems July 24, 2008 Comments at 4.
Docket No. EL08-75-000
Rocky Mountain Power
Exhibit No. 36 Page 10 of 29
Case No. PAC-E-10-D7
Witness: John A. Cupparo
Systems, since a ROE on a large investment yields a greater number of dollars than the
same ROE on a smaller investment, it is unclea why a greater percentage retu is
appropriate for a larger project. Bonnevile and Industral Customers contend that the
large scope of the Project, which PacifiCorp relies on to justify such a large adder, was
arificially created by vire of PacifiCorp bundling a number of individual, smaller,
projects together into one package.
27. As such, I,onnevile and Industral Customers argue that PacifiCorp has failed to
demonstrate a nexus between the incentives sought and the investment being made.
Industral Customers contends that since PacifiCorp already planned certain transmission
investments included in the Project, the ROE adder is not tailored to its actual risks and
challenges. Further, it asserts that the scope and effects of the Project are not as large as
PacifiCorp claims because it "is not one large transmission investment, but a series of
eight separate and often unrelated transmission projects.,,30 Bonnevile urges the
Commission to analyze each of the segments individually to determne if each is related
to the other segments and whether there is a nexus for each to the requested incentive
rate. In paricular, Industral Customers and Bonnevile claim that segment A is a local
transmission project, separately planned and operationally unrelated to the other
segments.31 They also question whether transmission that has been planned for some
time for PacifiCorp to meet its load service obligations though routine investments
warants incentive rate treatment. 32
28. UMPA similarly argues that PacifiCorp should not receive incentive rate treatment
for transmission investments needed to serve the needs of existing customers.33 UMPA
suggests that the system upgrades proposed by PacifiCorp are "the kinds of routine
investments made in the ordinar course of expanding the system to account for load
growth.,,34 Stating that PacifiCorp is required to maintain its system in order to serve
load and respond to anticipated load growth, UMP A asserts that "curent customers
should not be forced to pay additional incentive rates in order to cause the transmission
30 Industral Customers July 24,2008 Protest at 5.
31 ¡d. at 6; Bonnevile July 24, 2008 Protest at 5.
32 Bonnevile July 24, 2008 Protest at 4; Industral Customers July 24, 2008
Protest at 7.
33 UMP A July 24, 2008 Protest at 5-7.
34 ¡d. at 6.
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provider to provide for the basic transmission service that the provider is ob1isated to
provide. . .,,35 Bonnevile and Industral Customers make similar arguments. 6
29. All four protesters assert that segments A, B, and C were requirements stemmng
from Mid-American Energy Holding Company's (MidAmerican) acquisition of
PacifiCorp. According to Utah Systems, MidAmerican and PacifiCorp aleady received
a constrction incentive (merger approval), and fuer incentives now may be
unnecessar. Bonnevile and UMP A cite Commission precedent for rejecting a request
for incentive rate treatment where a project had been ordered by the Commssion in
another proceeding.37 As the Commssion in Westar denied incentives when the
applicant failed to offer evidence that conditions had changed since its prior
commitments, UMP A asserts that PacifiCorp has also failed to provide any evidence that
circumstaces have changed since it committed to build segments A, B, and C as par of
its merger with MidAmerican.
30. More generally, protesters claim that granting incentive rate treatment to
PacifiCorp wil not serve to promote new investment. Industral Customers contend that
PacifiCorp has not identified any regulatory and technology risks that otherutilties
would not have to face when makng routine transmission investments, and that incentive
. rate treatment in this case would simply give PacifiCorp higher retus on investments it
was aleady planning to make. Utah Systems state that investors may not stand to gain
much from the requested incentives, because PacifiCorp plans that the additional
revenues generated by the ROE wil be used to reduce the transmission rates that
otherwise would be paid by its retail customers. Uta Systems suggest that "the
increased revenue credits to PacifiCorp's retal jursdictions is the price of securng state
approvals,,,38 and is concerned that the Commssion in Order No. 679 did not envision
retail rate relief as a valid reason for granting incentives at the federal leveL.
31. UMPA also raises concerns about the proposed credit to retail customers. UMP A
believes that, as a result of the crediting mechanism, only PacifiCorp's wholesale
35id.
36 See Bonnevile July 24, 2008 Protest at 5 (routine investment necessar to meet
wind generation interconnection requests); Industral Customers July 24, 2008 Protest at
7 (normal and routine transmission investments related to system reliabilty and load
growth).
37 Bonnevile July 24, 2008 Protest at 5-6 and UMPA July 24, 2008 Protest at7-8
(citing Westar Energy Inc. (Westar), 122 PERC t 61,268, at P 49-52 (2008)).
38 Uta Systems July 24, 2008 Comments at 4-5.
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customers would pay the proposed incentive rate. UMPA suggests that PacifiCorp has
requested a higher incentive rate than necessar, given that it wil only be recovered on
ten percent of its transmission revenue requirement,39 and concludes that the retail credit
is preferential and unduly discriminatory.
32. Bonnevile and UMP A request that the Commssion set this .case for hearng to
determine a just and reasonable incentive rate treatment for the varous segments of the
Project40 and to properly tailor any approved incentives to encourage investment without
discriminating against wholesale customers.41
33. Finally, Bonnevile does not object to PacifiCorp's requested incentive for
recovery of prudently incured development and constrction costs if the Project is
cancelled or abandoned "as a result òf any action or inaction by a governmental
authority.,,42 But, Bonnevile requests clarfication that the clause "action or inaction by
a governmental authority" does not include actions or inactions by Bonnevile.
Bonnevile asserts that that provision should protect PacifiCorp from things such as
denial of easements and regulatory approvals, but that action or inaction by Bonnevile
should not trgger cost recovery under that incentive.
III. Discussion
A. Procedural Matters
34. Pusuant to Rule 214 of the Commssion's Rules of Practice and Procedure,
18 C.F.R. § 385.214 (2008), the timely, unopposed motions to intervene serve to make
the entities that filed them paries to this proceeding.
35. Rule 213(a) of the Commssion's Rules of Practice and Procedure, 18 C.F.R.
§ 385.213(a) (2008), prohibits an answer to a protest, unless otherwise permtted by the
decisional authority. We are not persuaded to accept PacifiCorp's answer and UMPA's
response and wil, therefore, reject them.
39 See UMP A July 24, 2008 Protest at 11 (noting that PacifiCorp states it receives
over ninety percent of its recovery on transmission investment though native load and
retail ratemakng processes.)
40 Bonnevile July 24, 2008 Protest at 7.
41 UMP A July 24, 2008 Protest at 2.
42 Bonnevile July, 24, 2008 Protest at 6 (citing PacifiCorp July 3, 2008 Petition at
4).
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B. Section 219 Requirement
36. In EPAct 2005, Congress addressed incentive-based rate treatments for new
transmission constrction.43 Specifically, section 1241 of EPAct 2005 added a new
section 219 to the FPA directing the Commission to establish, by rule, incentive-based
(including pedormance-based) rate treatments for electric transmission. The
Commission issued Order No. 679, which set fort processes by which a public utilty
could seek transmission rate incentives pursuant to section 219, including the incentives
requested here by Petitioners.
43 See Pub L. No. 109-58, 119 Stat 594,961 (2005).
44 See 18 C.P.R. § 35.35(d) (2008).
45 See id.; Order No. 679-A, FERC Stats. & Regs. t 31,236 at P 47.
46 Order No. 679-A, FERC Stats. & Regs. t 31,236 at P 49.
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not subject to any regional planning process review at alL. 47 Under those circumstaces,
we find that the Project is not eligible for the rebuttable presumption of relying on a
regional planning process.
39. Neverteless,. we find that PacifiCorp has adequately demonstrated that the Project
(with the exception of segment A) wil ensure reliabilty and reduce transmission
congestion, and therefore meets the requirements of FPA section 219 for incentive rate
treatment. We find that segments B through H of the Project would establish for the fist
time a backbone of 500kV transmission lines in PacifiCorp's Wyoming, Idaho and Uta
regions.48 This would provide PacifiCorp a platform for integrating and coordinating
futue regional and sub-regional electric transmission projects being considered in the
Pacific Nortwest and the Intermountain West, connecting existing and potential
generation to loads in an efficient manner, thus reducing the cost of delivered power. 49
Also, the Petition cites the 2006 DOE National Electrc Transmission Congestion Study
and the 200 Rocky Mountain Area Transmission Study in stating that the proposed
Project wil reduce congestion or maintain reliabilty in the Western Interconnection.50
Additionally, the Project would establish a direct link between PacifiCorp's east and west
control areas, providing numerous benefits including increasing transfer capabilty,
reducing the need for curailments, and reducing transmission congestion. 51
40. With regard to segment A, which is a 230 kV segment connecting existing power
substations at Walla Walla, Wallula and McNar, Washington and extending to Umatila,
Oregon, we conclude that PacifiCorp has not provided sufficient ~evidenceto meet the
requirements of FP A section 219 for incentive rate treatment and therefore, we decline to
grant any incentive for this segment. In support of segment A, the Petition merely states
that it "could be used to link existing and future sources of renewable resources to bettr
benefit system power transfers.,,52 There are no congestion studies or reliabilty
assessments in the record to support a finding that segment A wil either ensure reliabilty
or reduce the cost of delivered power by reducing congestion, as required by our
regulations to qualify for incentive rates. Accordingly, PacifiCorp has met the
47 See PacifiCorp Petition, Cupparo Affidavit at 15-16.
48 ¡d. at 20 & n.41.
49 ¡d. at 3, Cupparo Affidavit at 4, 7, and 19.
. 50 ¡d. at 21-23, Cupparo Affdavit at 22.
51 See id., Cupparo Affidavit at 39.
52 PacifiCorp Petition at 10. See also Cupparo Affidavit at 8-9.
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requirements of FP A section 219 for segments B though H of the Project; however, we
wil deny incentive rate treatment for segment A of the Project, without prejudice to
PacifiCorp re-filing with the required support for that portion of the Project.
C. Incentives and the Commission's Nexus Requirement
41. In addition to satisfying the section 219 requirement of ensuring reliabilty or
reducing the cost of delivered power by reducing congestion, an applicant must
demonstrate that.there is a nexus between the incentive sought and the investment being
made. In Order No. 679-A, the Commssion clarfied that the nexus test is met when an
applicant demonstrates that the total package of incentives requested is "tailored to
address the demonstrable risks or challenges faced by the applicant. ,,53 As par of our
evaluation of whether the incentives requested are tailored to address the demonstrable
risks or challenges faced by the applicant, the Commission has found the question of
whether a project is "routine" to be paricularly probative. In BG&E,54 the Commssion
clarfied how it wil evaluate projects to determine whether they are routine and the effect
this evaluation has on an applicant's request for incentives. Specifically, to determne
whether a project is not routine, the Commission stated that it wil consider all relevant
factors presented by the applicant. For example, an applicant may present evidence on:
(1) the scope of the project (e.g., dollar investment, increase in transfer capabilty,
involvement of multiple entities or jursdictions, size, effect on region); (2) the effect of
the project (e.g., ensurng reliabilty or reducing congestion costs); and (3) the challenges
or risks faced by the project (e.g., siting, internal competition for financing with other
projects, long lead times, regulatory and political risks, specific financing challenges,
other impediments).55
42. The Project is an enormous undertakng by PacifiCorp to constrct approximately
2,000 miles of new EHV transmission lines thoughout six states (including 230 kV, 345
kV and 500 kV transmission lines). The Project wil provide the first backbone 500 kV
"superhighway" in this part of the Western Interconnection and may facilitate the
addition of futue 500 kV transmission lines in the area. The Project wil improve
transfer capacity; for example, segment B, when combined with the other segments of the
Project, wil increase transfer capacity by 1,400MW, and significantly mitigate a
53 Order No. 679-A, FERC Stats. & Regs. tJ 31,236 at P 40.
54 Baltimore Gas and Electric Company, 120 FERC tJ 61,084, at P 52-55 (2007)
(BG&E).
55 This list provides some examples of evidence that may help inform the
Commssion whether a project is routine in nature, but is not intended to be exhaustive.
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transmission constraint on the system.56 The Bridger Expansion project (par of segment
E) wil increase transfer capacity by a significant amount.57 In addition, the Project wil
relieve several other points of congestion within the PacifiCorp control areas. 58 Also, the
Project wil directly link PacifiCorp's east and west control areas, enabling PacifiCorp to
make effcient use of resources to meet its load and reserve obligations, as well as
minimize congestion and relieve loadig along paths between Wyoming and areas west
and south.59 The Project wil provide substantial benefits in terms of ensurng reliabilty
in the region and wil also reduce congestion costs.
43. Moreover, PacifiCorp faces significant risks and challenges in pursuing this
Project. The Petition enumerates considerable siting, constrction, regulatory, financing,
and technology risks. Namely, the configuration of the Project60 and the siting of its
transmission facilities ahead of the siting for specific generation resources may lead to
additional costs, delays, or modifications down the road. PacifiCorp notes that curently
no 500 kV infrastrctue exists within the Project footprint in Idaho, Utah and Wyoming;
therefore, as the first entity to constrct a new 500 kV system, it wil be responsible for
mitigating any impacts caused on the existing transmission system. PacifiCorp explains
that the new 500 kV transmission system should not cause any overloads on the
underlying lower voltage transmission system. It cites the need to mitigate possible
overloads as the reason to constrct a redundant transmission system, which effectively
raises the costs and risks of incorporating a new higher voltage class of transmission in
the area.61
56 See PacifiCorp Petition, Cupparo Affidavit at 9.
57 ¡d. at Exhibit 4, p. IV.
58 See id. at 22.
59 See id. at Exhibit 5, p. 35.
60 As noted above, PacifiCorp wil employ a "hub and spoke" configuration that is
characterized by major EHV.transmission lines that connect areas with strpng potential
for generation resource development (hubs) to an enhanced transmission system (spokes)
for delivery of capacity and energy to customers thoughout the region.'
61 See PacifiCorpPetition at n.41.
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44. We also find that the Project faces. significant risks related to the magnitude of the
financial investment required (estimated at $6 bilion),62 which represents more than a
330 percent increase in PacifiCorp's existing transmission rate base,63 and the regulatory
risks involved. There are significant siting issues because the individual segments must
be approved by numerous states and several federal authorities, including the Bureau of
Land Management and the United States Forest Service. Furer, trbalissues and federal
land management issues are implicated in the constrction and development of the
Project.
45. Furer, PacifiCorp states that the Project wil also faciltate the delivery of remote
renewable resources, accommodating up to 3,000 MW of capacity from location-
constrained renewable resources in Wyoming to distant load centers. We find that, in
addition to the other bases discussed above, constrction or enhancemeiIt of transmission
facilties designed to provide access to these types of remote resources is not routine.
46. We do not agree with protesters' assertions that the large scope of the Project is an
arificial creation of combining several individual, smaller projects, nor that the
Commssion should analyze each of the segments individually to determne whether there
is a nexus for each. We conclude that each segment of this Project (with the exception of
segment A, as discussed above) wil improve PacifiCorp's transmission operations and,
among other things, increase transfer capabilty. Moreover, even if we were to find that
each segment is a separate project, which we do not, the Commssion has held that an
applicant "may present evidence that a group of projects, when considered in the
aggregate, are not routine. ,,64 Hence, consistent with Commssion precedent, we
consider, and conclude that the Project as a whole satisfies the nexus requirement.
47. Similarly, Bonnevile and Industral Customers' objections that transmission
aleady planned to meet PacifiCorp's load service obligations should not receive
incentive rate treatment are not persuasive. We explained in Order No. 679 that
"(i)nclusion of a facility in a plan does not mean that a project can or wil get built," and
that even in such instances the granting of incentives may help to secure financing.65
62 This cost estimate reflects a single circuit configuration. However; we note that
PacifiCorp seeks equity parners to upsize segments D, E and F from a single circuit to
double circuit configuration, and that could significantly increase the Project costs. ¡d. at
n.9.
63 ¡d. at 7, Cupparo Affdavit at 7,29-30.
64 BG&E, 120 FERC 161,084 at P 53.
65 Order No. 679, FERC Stats. & Regs. 1 31,222 at P 35.
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Additionally, PacifiCorp has provided ample evidence that by adding the additional
transmission capabilty, the Project wil ensure reliabilty and provide other benefits, as
well as serve to meet load service obligations.
48. Regarding protesters' claims that PacifiCorp is aleady obligated to build certain
segments as a result of its merger with MidAmerican,. and that it should not receive
incentive rate treatment consistent with Westar, we find that this case is distinguishable.
In Westar, the Commission found that the petitioner had not explaied why it required
incentives to encourage investment in its project when the Commssion had aleady
directed it to increase transfer capabilty on the transmission line as par of mitigation
requirements in another proceeding. The Commssion explained that projects an entity is
required to build may not necessarly qualify for incentives because there is that
obligation and a high assurance of recovery of the related costS.66 With respect to
PacifiCorp, the record does not indicate that this Commssion required the paries to
constrct any transmission as a condition for approval of the MidAmericanacifiCorp
merger.67 The parties apparently made commtments to build segments A, B, and C in
proceedngs before varous state commssions, but PacifiCorp asserts that "Segments B
and C represent significant expansions, of the original transaction commitments.,,68 As
such, the circumstances have changed since PacifiCorp entered into those transaction
commitments. These distinctions, in conjunction with the manner in which segments B .
and C are integrated with the Project as a whole, lead us to conclude that incentives are
waranted to encourage investment for these segments.
49. Finally, we address concerns raised by Utah Systems that investors may not stand
to gain much from undertakng the risks associated with this investment. Because the
additional revenues generated by the ROE adder wil be used to reduce the transmission
rates of PacifiCorp' s retail customers, Uta Systems suggest that the increased revenue
credits are the price of securng state approvals, which was not identified as a reason for
granting incentives in Order No. 679. There is no evidence in the record regarding the
impact of the requested incentives on state commssion approval, nor is there any reason
to believe the incentives wil not attract investors to the Project. We therefore dismiss
these claims by Utah Systems as speculative.
66 Westar, 122 FERC 161,268 at 49-50, citing Order No. 679, FERC Stats. &
Regs. 131,222 at P 94.
67 See MidAmerican Energy Holdings Co., 113 FERC 1 61,298 (2005), reh' g
denied, 118 FERC 1 61,003 (2007).
68 PacifiCorp Petition at n.32.
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50. Accordingly, forthe reasons discussed above, we find that PacifCorp's Project is
not routine in natue, and, therefore, meets the nexus requirement to be eligible for
incentives under Order No. 679.
D. Requested Incentives
1. ROE Adder
51. PacifiCorp's Project is unparalleled in terms of its size, cost, siting risk, regulatory
and financial risk, technology-related risks, and other factors. In addition to the
numerous risks and challenges associated with this Project, PacifiCorp wil require an
enormous investment (well in excess of $5 bilion, even without the estimated $108
millon needed to constrct segment A), thereby presenting financing challenges not
faced by the ordinar transmission investment. It is also important to recognize that
PacifiCorp has voluntarly proposed to invest a large amount of capital to build backbone
500 kV transmission facilities though large portions of its system, which will ensure
reliabilty and/or reduce congestion costs and facilitate the constrction of additional high
voltage facilities throughout the region. This, together with the vast size of the Project
(roughly 2,000 miles of transmission lines, even excluding segment A) and the extended
period of time for completion (though 2014) is the type of infrastrctue development
envisioned by EP Act 2005 and Order No. 679. All of these factors support the request
for an incentive ROE adder, which PacifiCorp believes wil attact capital for the Project,
when added to the base ROE to be determned in a futue rate case.
52. We also do not agree with Uta Systems' objection that, since a ROE on a large
investment yields a greater number of dollars than the same ROE on a smaller
investment, a greater percentage retu is not appropriate for a larger project. In Order
No. 679, the Commssion permtted, when justified, an incentive-based ROE to all public
utilties for new investments in transmission facilities that benefit consumers by ensurng
reliabilty or reducing congestion costS.69 The Commssion concluded that ROE
incentives encourage investment, and the granting of ROE incentives could make
transmission projects more attractive and, therefore, more likely.70 In evaluating these
incentives, the Commssion considered "the appropriateness of a higher ROE as a
69 Order No. 679, PERC Stats. & Regs.131,222 at P 91.
70 ¡d. See also Commonwealth Edison Co., 124 FERC 161,231, at P 29(2008)
("A higher ROE encourages new transmission investment because it provides a longer
term higher retu on equity after the project comes on line, only for that new investment,
and makes that transmission project more attractive as an investment.").
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mechanism for increasing investment in new capacity.',7 In this instance, we find that
PacifiCorp's incentive rate adder is justified based on the requirements of Order No. 679.
53. Accordingly, as discussed fuer below, we grant a 200 basis point incentive for
the Project, to be added to the base ROE determned in a futue PacifiCorp section 205
filing. Our grant of the incentive ROE adder wil be bound by the upper end of the zone
of reasonableness.
2. Recovery of Abandoned Plant Costs
54. PacifiCorp requests recovery of all prudently-incurred development and
constrction costs in the event the Project is cancelled or abandoned as a result of its
inability to obtain necessar approvals, or as a result of any action or inaction by a
governmental authority or regulatory agency, for reasons beyond PacifiCorp's control. In
Order No. 679, we found that this incentive is an effective means to encourage
transmission development by reducing the risk of non-recovery of costs.72 Consistent
with Order No. 679, PacifiCorp has shown a nexus between the recovery of prudently-
incured costs associated with abandoned transmission projects and its planned
investment. thus, we wil grant the request for the recovery of prudently-incured
development and construction costs if the Project is cancelled or abandoned, in whole or
in par, as a result of PacifiCorp's inabilty to obtain necessar approvals, or as a result of
any action or inaction by a governmental authority or regulatory agency, for any reason
determned to be outside PacifiCorp's control in subsequent section 205 filings.'3
55. We find that this incentive wil be an effective means to encourage the completion
of the Project. For example, besides its scope and size, this Project requires timely
approvals from multiple jursdictions, along with varous federal approvals. Dependence
upon approval by multiple jursdictions introduces a significant element of risk to this
Project that is not faced by utilties building transmission facilties within a single
jursdiction. Granting the request for an abandonment incentive wil help to ameliorate
these risks and help ensure completion of the Project.
56. Regarding Bonnevile's request for clarfication regarding whether its actions
could be constred as those of a "governmental authority" and thus potentially trgger
PacifiCorp's abilty to recover abandoned plant costs, we dismiss this request as
premature. We wil address any request for recovery of abandonment costs in the context
71 See id. P 85.
72 Order No. 679, PERC Stats. & Regs. 131,222 at P 163.
73 ¡d. P 165-66.
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of the required filing under FPA section 205. In that proceeding, PacifiCorp wil bear the
burden of demonstrating that the Project was cancelled or abandoned as a result of its
inabilty to obtain necessar approvals, or as a result of any action or inaction by a
governmental authority, or regulatory agency, for reasons outside PacifCorp's control.
3. Total Package of Incentives
57. As noted earlier, in Order No. 679-A, the Commssion clarfied that its nexus test
is met when an applicant demonstrates that the total package of incentives requested is
tailored to address the demonstrable risks or challenges faced by the applicant. The
Commssion noted that this nexus test is fact-specific and requires the Commssion to
review each application on a case-by-case basis. Consistent with Order No. 679,'4 the
Commssion has, in prior cases, approved multiple rate incentives for paricular
projects.7S This is consistent with our interpretation ofFPA section 219 as authorizing
the Commssion to approve more than one incentive rate treatment for an applicant
proposing a new transmission project, as long as each incentive is justified by a showing
that it satisfies the requirements of the FPA section 219 and that there is a nexus between
the incentives being proposed and the investment being made.
58. PacifiCorp states that the total package of incentives that it has requested is
necessar to compensate it for the substantial risks posed by the Project. It also asserts
that the overall risks associated with building the Project are not fully mitigated by an
abandonment incentive, and argues that reducing its requested ROE adder because it has
been granted an abandonment incentive "would misalign the scope of PacifiCorp's risks
with its narowly tailored incentive package.,,76
59. We find that PacifiCorp has shown, consistent with Order No. 679-A, that
multiple incentives are justified to address the demonstrable risks or challenges faced by
the Project.77 An ROE adder and abandoned plant costs incentive rate treatment are not
mutually exclusive, and PacifiCorp has explained why it is seeking each incentive and
74 Order No. 679, FERC Stats. & Regs. t 31, 222 at P 55.
7S See, e.g., Allegheny Energy, Inc., 116 FERC t 61,058, at P 60, 122 (2006)
(approving ROE at the upper end of the zone of reasonableness and 100 percent
abandoned plant recovery); Duquesne Light Co., 118 FERC t 61,087, at P 55 (2007)
(granting an enhanced ROE, 100 percent CWIP, and 100 percent abandoned plant
recovery).
76 PacifiCorp Petition at 39.
77 Order
No. 679-A, FERC Stats. & Regs. t 31,236 at P 21, 27.
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how each is relevant to the proposed Project. As discussed above, PacifiCorp faces
significant risks and challenges in pursuing this Project. We find here that granting the
ROE incentive, together with abandoned plant recovery, wil encourage greater
paricipation from potential equity parners. Due to the number of approvals needed, the
cost of the Project constrction, the fact that transmission constrction wil precede siting
of new generation, and other factors cited, PacifCorp is exposed to greater risks of
project failure which results in increased risks to debt. The two incentives sought by
PacifiCorp serve different puroses; thus, we reject protestors' arguments that the total
.package ofincentives is unwaranted, and find that PacifiCorp has shown a nexus for the
total package of incentives. However, we wil approve a 200 basis point adder rather
than the 250 basis point adder requested by PacifiCorp. A 200 basis point adder is a
significant increase in the retu on equity that wil be eared on this ambitious
infrastructue investment; we find that such adder is just and reasonable under the
circumstances presented by PacifiCorp's application.
4. Other Issues
60. In Order No. 890, the Commssion required transmission providers to open their
transmission planning process to customers, coordinate with customers regarding futue
system plans, and share necessary planning information with customers.78 The
Commission identified important benefits stemmng from that requiement, finding that
an open, transparent, and coordinated transmission planning process would increase the
abilty of customers to access new generating resources, including renewable resources,
and would promote efficient utilzation of transmission?9 Such potential benefits are
paricularly important with respect to the development of new backbone transmission
facilities like the Project. PacifiCorp indicates in the Petition that it is continuing to
explore the proper size and exact location of some segments of the Project. 80 To the
extent that such aspects of the Project remain under consideration, the Commssion
expects that PacifiCorp wil address them as appropriate though the transmission
planning process required by Order No. 890.81
78 Order No. 890, FERC Stats. & Regs. 131,241 at P 3.
79 ¡d. P 3, 5.
80 See, e.g., PacifiCorp Petition at 13, n.23 (regarding the section of segment E that
is intended to connect the Populus substation to the Hemingway substation) and Cupparo
Affidavit at 12 (regarding possible upsizing of segment G).
81 In July 2008, the Commssion accepted PacifCorp's Order No. 890
transmission planning compliance filing, as well as comparable filings submitted by other
(continued. . .)
Docket No. EL08-75-000
Rocky Mountain Power
Exhibit No. 36 Page 23 of 29
Case No. PAC-E-10-07
Witness: John A. Cupparo
61. UMP A raises concerns about the proposed credit to retal customers. UMP A
believes that, as a result of the crediting mechanism, only PacifiCorp's wholesale
customers would pay the proposed incentive rate. UMP A suggests that PacifCorp has
requested a higher incentive rate than necessar, given that it wil only be recovered on
ten percent of its transmission revenue requirement, and concludes that the retail credit is
preferential and unduly discriminatory.
62. We find that UMP A's assertion is beyond the scope of this proceeding. Any
futue proposal by PacifiCorp to provide a credit to its retail customers is a matter for
state commssion approval. We also disagree that the requested incentive is higher than
necessar, as discussed above. To the extent that UMPA is concerned about the equities
of rate allocation between wholesale and retail customers, this issue is properly raised
when PacifiCorp files under FP A section 205 to recover costs associated with the Project.
63. Finally, we deny protestors' requests that we set this matter for hearng. In
general, the Commssion sets matters for a tral-type evidentiar hearng only to resolve
material issues of law and fact. In this case, however, since PacifiCorp has satisfied the
requirements of Order No. 679, except for segment A, we conclude that setting this
matter for hearng is not appropriate.
The Commssion orders:
The petition for declaratory order is hereby granted in par, and denied in par, as
discussed in the body of this order.
By the Commssion. Commssioners Kelly and Wellnghoff concurng with separate
statements attached.
Commssioner Moeller not paricipating.
(SEAL)
Kimberly D. Bose,
Secreta.
transmission providers in the region and the related NTTG Agreements, subject to
modifications and fuer compliance filings. Idaho Power Co., 124 FERC 161,053
(2008).
Rocky Mountain Power
Exhibit No. 36 Page 24 of 29
Case No. PAC-E-10-07
Witness: John A. Cupparo
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
PacifiCorp Docket No. EL08-75-000
(Issued October 21,2008)
KELLY, Commssioner, concurring:
This order addresses a petition for declaratory order seeking incentive rate
treatment filed by PacifiCorp. PacifiCorp requests two transmission rate
incentives for its extra-high voltage (EHV) transmission project: a 250 basis point
adder to its base retu on equity (ROE) and recovery of prudently-incured
abandonment costs ìf the Project is cancelled due to factors beyond its control.
It is appropriate to consider Segments B though H ofPacifiCorp's EHV
petition as a single, integrated transmission project. In applying the project-based
criteria that I have relied upon in previous transmission incentives proceedigs to
determne whether PacifiCorp's EHV transmission project warants incentive rate
treatment,! I conclude that it does. Thus I concur with the decision to grant the
requested incentives, as modified in the order.2 I take ths opportnity to present
my reasons for doing so.
PacifiCorp's objective in undertakng this EHV transmission project,
among other things, is to establish a 500 kV backbone thoughout 6 western states,
effciently integrate wind resources into the grid, and connect PacifiCorp's Rocky
Mountain Power and Pacific Power control areas. The overall project is
comprised of eight segments, which PacifiCorp has organized into four priority
groups. Intervening paries argued that the varous segments are not necessarly
interrelated and should be analyzed on.an individual basis. In a recent
transmission incentives case, I wared against evaluating disparate transmission
projects as a single, integrated transmission project.3 However, for the reasons
1 American Electric Power Service Corporation, 118 FERC' 61,041
(2007).
2 The order denies incentive rate treatment to Segment A. I concur with
this decision. PacifiCorp has neither demonstrated it is an integrated segment of
the overall project nor shown it to merit incentives on an individual basis.
3 Pepco Holdings, Inc., 124 FERC' 61,176 (2008). See separate statement
(continued. . .)
Docket No. EL08-75-000
Rocky Mountain Power
Exhibit No. 36 Page 25 of 29
Case No. PAC-E-10-07
Witness: John A. Cupparo
listed below, I am satisfied that Segments B through H comprise a single
integrated project. In this case, I assessed the merits of each project individually
and determned that, with the exception of Segment A, all segments would be
eligible for some form of incentive rate treatment. However, I also considered
whether these segments are an integrated whole. I find that Segments B though H
are interrelated because they satisfy the overarching goals of building an EHV
transmission backbone across six states and bringing renewable resources to load
centers. When considered in the aggregate, PacifiCorp's EHV transmission
project represents an exceptional undertaking, larger than any other project the
Commssion has yet seen (within the context of incentives applications) as
measured across any number of metrcs, including tota estimated costs, total line
miles and geographic footprint. For example, while Segments B and C provide a
varety of benefits when considered in isolation, they also enable PacifiCorp to
achieve the planned transfer capabilty rating of subsequent segments.4 Though
Segment G is geographically separate from other pars of this transmission
proposal, it is a piece of Gateway South, which is designed to provide access to
resources from Wyoming to pars of Utah and Nevada. Because the 500 kV
infrastrcture proposed by PacifiCorp is so much larger in voltage terms than the
exiting transmission infrastrcture in pars of Idaho, Uta, and Wyoming,
PacifiCorp must constrct Segments, D, E, and F to provide a fully redundant
transmission system. Finally, PacifiCorp is building Segment H to provide for the
integration of PacifiCorp' s east and west control areas, and to furer support
delivery of renewable energy.
It is appropriate to grantPacifiCorp's request for incentive rate treatment,
as modified by the order. In absolute terms, as well as relative to PacifiCorp's
curent transmission plant in service, the financial undertakng here is significant.
The total estimated cost of Segments B though H is $5.5 bilion, representing
over 3 times PacifiCorp's aleady large $1.8 bilion transmission plant in service.
The Project adds roughly approximately 2,00 miles of new EHV transmission
infrastrctue across 6 states-Nevad, Idaho, Oregon, Utah, Washington, and
Wyoming-and the estimated time to completion for the final segments is 2014.
While PacifiCorp's home terrtory is in most of these states, coordinating
regulatory approvals across a large number of authorities wil require significant
effort and resource commtment. Finally, I believe that the EHV transmission
project wil produce an aray of public interest benefits. It wil create an EHV
backbone transmission system that connects existing and futue resources,
of Commssioner Kelly issued August 27, 2008.
4 PacifiCorp July 3, 2008 Petition for Declaratory Order, Docket No. EL08-
75-00, Appendix A at 10.
Docket No. EL08-75-000
Rocky Mountain Power
Exhibit No. 36 Page 26 of 29
Case No. PAC-E-10-07
Witness: John A Cupparo
including renewables, with consuming areas. PacifiCorp's project wil facilitate
delivery of as many as 3,00 MW from location-constrained renewable resources
in Wyoming. Moreover, once this backbone has been installed, it should facilitate
the addition of futue 500 kV infrastrctue at a lower cost.
I concur with the specific incentives approved in this order-recovery of
prudently-incured abandonment costs and a 200 basis point ROE adder. I have
previously approved the.abandoned plant incentive for projects that I believe to be
eligible for incentives. In this case such treatment is supported by the long
constrction. period, large cost, both in absolute terms and as a percentage of
curent rate plant in service, and risks associated with the regulatory processes.
With respect to an incentive ROE adder, PacifiCorp asserts that the overall
risks associated with building the project are not fully mitigated by an
abandonment incentive.. While I have previously stated that basis point adders to
ROE may be used to overcome either financial or non-financial impediments to
transmission expansion,s I have approved ROE adders in a limited number of
proceedings and those adders were well below 200 basis points. In this case, I
agree with the order and support an ROE adder of 200 basis points for Segments B
though H. Order No. 679-A states "the most compellng case for incentive ROEs
are new projects that present ~ecial risks or challenges, not routine investments
made in the ordinary course." PacifiCorp's EHV transmission project meets this
standard.
There are several featues of PacifiCorp' s project that subject PacifiCorp to
risks and challenges not seen in the ordinary course of business. PacifiCorp wil
be installing Segments B though H over the course of the next five and half years
at an estimated cost of $5.5 bilion. While I generally prefer approving recovery
of 100 percent of prudently incurred Constrction Work.In Progress (CWIP)
incentive to mitigate some of the risks of constrcting a project over a long
development schedule, PacifiCorp asserts that CWIP does not provide significant
protection in this case. As noted above, the abandoned plant incentive is not
sufficient to address such risk alone and therefore an ROE adder is appropriate.
PacifiCorp wil also be deploying an assortment of advanced technologies.
5 Bangor Hydro-Electric Company, 117 PERC t 61,129 (2006) (Opinion
No. 489).
6 Promoting Transmission Investment through Pricing Reform, Order No.
679-A, PERC Stats. & Regs. t 31,236, at P 60 (2006), order on reh'g, 119 PERC
t 61,062 (2007).
Docket No. EL08-75-000
Rocky MOuntain Power
Exhibit No. 36 Page 27 of 29
Case No. PAC-E-10-07
Witness: John A. Cupparo
I believe that PacifiCorp's EHV transmission project provides public
interest benefits that, on balance, contrbute to the appropriateness of the ROE
adder. The geographic and financial scope of the overall project when combined
with PacifiCorp's decision to undertake transmission development ahead of
generation creates significant financial risk that merits an incentive ROE adder.
Rather than embark upon an incremental, small-scale expansion of its transmission
system, PacifiCorp elected to constrct this wide-ranging EHV transmission
project. As PacifiCorp notes, this represents a deparre from convention and
presents novel investment risks. An incentive ROE adder is appropriate here as I
do not believe that other incentives discussed in Order 679 address this
circumstance. It is significant that establishing a "first-of-its-kind energy
superhighway" connecting Wyoming, Idaho, Utah and Oregon wil offer benefits
to future developers of EHV transmission lines as they wil likely face fewer
engineering and system reliabilty obstacles.
There are also opportnities for third pary equity partnership at varous
points in the overall project. Segments D and E appear to be on course to be
jointly-owned with Idaho Power, and there are fuer opportnities for third pary
equity parnership on other segments. Segments F, G, and H are sufficiently
flexible to allow for "upsizing" (i.e. from a single circuit to a double-circuit
system or from 230 kV to 500 kV) orreconfiguration, depending on paricipation
of potential equity parners; PacifiCorp states that it is "actively working with
potential equity parners to determne the interest and commtment to such an
upsize.,,7 Approval of incentives here offers PacifiCorp an appropriate incentive
to progress with development of all project segments and provides eertainty with
respect to approved incentives that should promote equity parnerships. In
instances where the Commssion can support joint ownership and "upsizing" of
infrastrctue, I believe that incentive rate treatment is appropriate. In future
proceedings, I would support approval of a minimum level of incentives (e.g. a
minimum ROE adder) and condition furter incentives, such as supplemental ROE
basis points, on completing equity parnership arangements and commtments to
upsizing transmission infrastrctue.
Accordingly, I respectfully concur with this order.
Suedeen G. Kelly
7 PacifiCorp July 3, 2008 Petition for Declaratory Order, Docket No. EL08-
75-000, at 5 n.9.
Rocky Mountain Power
Exhibit No.36 Page 28 of 29
Case No. PAC-E.1O-Q7
Wìtness: John A Cupparo
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
PacifiCorp Docket No. EL08-75-000
(Issued October 21,2008)
WELLINGHOFF, Commssioner, concurng:
In today's order, the Commssion approves a 200 basis point incentive ROE adder
for PacifiCorp in connection with its Energy GatewayTransmission Expansion Project. I
agree with that decision. I write separately to highlight important characteristics of ths
project that I believe warant this significant incentive ROE adder.
I have dissented from numerous orders in which I felt that the majority
undermned the nexus requirement that is an essential component of Order No. 679 and
inappropriately granted incentive ROE adders.1 By contrast, I agree that this project
satisfies the nexus requirement. It is noteworty that this project is, as described in
today's order, "the fist backbone 500 kV 'superhighway' in this par of the Western
Interconnection and may facilitate the addition of futue 500 kV transmission lines in the
, area.,,2 At least as important, I believe that this project is a non-routine investment
worty of the significant incentive ROE adder granted here because it wil use advanced
technologies that wil benefit all users of the grid and ultimate consumers, and because it
wil significantly increase the availabilty of renewable energy resources.
With respect to the use of advanced technologies, PacifiCorp provides substantial
detail in its required technology statement and accompanying testimony. For example,
PacifiCorp describes its plans concerning advanced conductor technology, Static VAR
Compensators, and phase shifters, among other technologies.3 PacifiCorp Witness John
Cupparo states that "(r)eliance on novel technologies inherently posts increased risks in
the form of added uncertainty as to how they wil pedorm within the context of this large
1 See, e.g., Commonwealth Edison Co., 122 FERC t 61,037 (2008) (dissent in par
of Commssioner Wellnghoff; Virginia Elec. and Power Co., 124 FERC t 61,207
(2008) (dissent of Commssioner Wellnghoff); Duquesne Light Co., 125 FERC t 61,028
(2008) (dissent in par of Commissioner Wellnghoff).
2 PacifCorp, 125 FERC t 61,076 at P 42 (2008).
3 PacifiCorp Petition at 41-48 and Cupparo Affdavit at 24-29.
1
Rocky Mountain Power
Exhibit No. 36 Page 29 of 29
Case No. PAC-E-10-07
Witness: John A. Cupparo
project.,,4 While recognizing such risks and challenges, PacifiCorp also states that it "is
committed to optimizing the technology that wil be utilzed by the Project."s
Docket No.EL08-75-000
As I have discussed previously, I believe that consideration of advanced
technologies and their associated risks and challenges is an appropriate component of the
nexus analysis that the Commission conducts in evaluatig applications for incentives
under Order No. 679.6 Consistent with such consideration, today's order accountsför
technology-related risks in evaluating PacifiCorp's incentives request.'
With respect to increasing the availabilty of renewable energy resources,
PacifiCorp states that this project wil facilitate the delivery of up to 3,000 MW of
capacity from location-constrained renewable resources in Wyoming to distant load
centers.s I agree with the statement in today's order that constrction or enhancement of
transmission facilities designed to provide access to these types of remote resources is not
routine.9 I have stated previously that amd heightened concerns about climate change
and dependence on foreign oil, it is essential that our countr take steps to accelerate the
integration of clean, reliable, domestic renewable energy resources into our energy
portolio.t° In light of the broad and substantial benefits associated with increasing the
availabilty of renewable energy resources, I continue to believe that it is appropriate for
the Commssion to provide investment incentives in this area. I also note that in granting
such incentives, it remains importt for the Commission to promote the use of intellgent
and effcient technologies that optimize operation of the facilties at issue.
For these reasons, I concur with today's order.
Jon Wellnghoff
Commissioner
4 Cupparo Affidavit at 32.
5 PacifiCorp Petition at 42.
6 See, e.g., Potomac-Appalachian Transmission Highline, L.L. c., 122 PERC tJ
61,188 (2008) (dissent in par of Commssioner Wellnghoff at 1-4); Northeast Utilities
Service Co., 124 FERC tJ 61,044 (2008) (dissent of Commssioner Wellnghoff at 2-3).
, PacifCorp, 125 PERC tJ 61,076 at P 43,51 (2008)
SId. P 45.
91d.
10 See Southern California Edison Co., 121 PERC tJ 61,168 (2007) (concurence of
Commissioner Wellnghoff at 2).