20110527Gerrard Di.pdf

RECErVED
20,rHAY 27 AM II: 05
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE )
APPLICATION OF ROCKY )
MOUNTAIN POWER FOR )
APPROVAL OF CHAGES TO ITS )
ELECTRIC SERVICE SCHEDULES )
AND A PRICE INCREASE OF $32.7 )
MILLION, OR APPROXIMATELY )15.0 PERCENT )
CASE NO. PAC-E-l1-12
Direct Testimony of Darrell T. Gerrard
ROCKY MOUNTAI POWER
CASE NO. PAC-E-l1-12
May 2011
1 Q.Please state your name, business address and present position with
2 PacifCorp dba Rocky Mountain Power (the "Company").
3 A.My name is Darell T. Gerrard. My business address is 825 NE Multnomah, Suite
4 1600, Portland, Oregon 97232. I am Vice President of Transmission System
5 Planning for the Company.
6 Qualifications
7 Q.Please describe your education and business experience.
8 A.I have a Bachelor of Science degree in Electrical Engineering (Electrc Power
9. Systems Major) from the University of Utah and Certficate of Completion with
10 Honors in Electrcal Technology from Utah Technical College at Salt Lake. My
11 experience spans more than 30 years in the electrc utility business and electric
12 power industr in general. I have working experience and have had management
13 responsibility for a number of fuctional organizations at PacifiCorp including:
14 Area Engineerig, Area Planning, Region Engineerig, T&D Facilties
15 Management, Transmission, Substation and Distrbution Engineering, System
16 Protection and Control, T&D Project Management and Delivery, Asset
17 Management, Electronic Communications, Hydro System Engineerig,
18 Transmission Grid Operations, and most recently Transmission System Planing.
19 Q.What are your responsibilties as Vice President of Transmission System
20 Planning?
21 A.I am responsible for transmission planing activities required. to support
22 PacifiCorp's existing and futue bulk transmission system and to ensure a safe and
23 reliable transmission system provides adequate service to our customers
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economically. I am also responsible for the conceptual and detailed system
planing and architectue associated with the Company's long-term Energy
Gateway Transmission Expansion Plan ("Energy Gateway").
What is the purpose of your testimony in this proceeding?
The purose of my testimony is to:
. provide support for the Company's request for rate recovery of the porton
of the Populus to Terminal project ("Project") not curently in rate base;
. discuss the "used and useful" stadard in the context of industr planning
practices and precedents, and system path rating requirements;
. describe the timing and key drvers requirg investment in new electrc
transmission infrastrctue such as the Project; and
. request recovery of the additional transmission capital investments
included in this Application.
Please describe the major transmission investments that the Company is
adding to rate base in this rilng.
The Company is requesting that the remaining investment associated with the
Populus to Terminal project, previously found by the Commission not to be
"curently used and useful,"1 be included in rate base. My testimony also discusses
the addition of more than $150 milion in other transmission capital investment for
the test period Januar 1,2011, to December 31,2011, as provided in Exhibit No.
30, Transmission Major Plant Additions.
i IPUC Case No. PAC-E-10-07, Order No. 32196, Febru 28, 2011.
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1 Populus to Terminal
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This Commission found that only 73 percent of the Project is currently used
and useful. Is the Company providing new and additional information to the
Commission in support of inclusion of 100 percent of the project in rate base?
Yes. In its reconsideration order in Case No. PAC-E-IO-07 (the "2010 General
Rate Case"), the Commission stated that the Company "wil receive a full and fair
retu on the remainder of its investment if and when it presents evidentiary
support for moving the balance of the investment (27 percent) into rate base.,,2 I
wil provide additional evidence, in my testimony, about the Project and the
integrated system to support the fact that 100 percent of the Project is presently
used and usefuL.
In your reading of the Commission's Order No. 32224, do you believe the
issue for the Commission is one of timing and not of prudence of the
Company's decision to build the line?
Yes. The Commission acknowledged this in its Order in regards to the Company's
ability to ultimately recover the full investment in the Project.
(the) Company does not lose out on the 27 percent of the investment in the
Transmission Line that is curently slated for the PHFU account.
If..,Rocky Mountain is able to present suffcient evidence which confirms
that 100 percent of the Transmission Line is "used and useful" this
Commission wil include that additional amount in Idaho rate base.3
Did the Commission address the Project in any other proceedings prior to the
Company's 2010 general rate case?
Yes, In Case No. PAC-E-08-03, the Commission approved the Company's
2 Case No. PAC-E-1O-07, IPUC Order No. 32224, page 12, April 18, 2011.3Id.
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Application for a Certificate of Public Convenience and Necessity to constrct the
Populus to Terminal project. Significantly, with regard to the certficate's need
determination, the Commission noted in its Final Order:
The Commission agrees with Staff s assertion that the proposed
transmission project is an "integral par" of the Company's preferred
resource portfolio of an additional 2,000 MWs of renewable resources by
the end of 2013. The Commission also believes that the Project has the
potential to upgrade the Company's overall transmission capacity and
thereby improve the flexibility and reliability of electrcal service for
Idaho customers durng peak demand times.4
In addition, in its September 15, 2009, Acceptance of Filing, the Commission
formally acknowledged the Company's 2008 Integrated Resource Plan (IRP),
which detailed the Project's initial and planed capacity ratings and included in its
Action Plan (Chapter 9)5 the constrction of the Project in 2010 as confgued.
Commission Staff concluded:
Staff believes that PacifiCorp has performed extensive analyses, given
equivalent consideration of supply- and demand-side resourcesj provided
acceptable opportities for public input, and that the end result is
representative of the Commission's directives toward integrated resource
planning.6
Furermore, in its findings, the Commission stated:
We recognize and commend the Company for the Plan that it has
presented and for the public process that it used to produce the Plan.?
Did the Company rely upon the Commission's final order approving a
Certificate of Public Convenience and Necessity when it decided to proceed
with the Project?
Yes. The Company did rely heavily on the Commission's determination and final
4 Case No. PAC-E-08-03, IPUC Order No. 30657, pp. 5-6.
5 PacifiCorp Integrated Resource Plans available at htt://w\\.W.pacificorp.com/es/irp.html.
6 Case No. PAC-E-09-06, Acceptace of Filng, p. 10.7Id.
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order that the Project was necessary and. in the public interest. Had the
Commission's final order made the determination that the Project was not
necessar or not in the public interest, the Company would not have proceeded
with the Project in its curent configuation. In this event, the Company would
have been forced to consider alternatives previously rejected based on cost to
customers and/or their inability to meet the Project's requirements and need.
Do you agree with the finding of the Commission that 27 percent of the
Project investment was not presently used and useful?
No. I do not agree with the Commission's conclusion that 27 percent of the project
investment is not presently used and useful and is contingent on the constrction of
the remainder of Energy Gateway.8 This conclusion is not based on any accepted
utility industr practice, standard, rule or regulation of which I am aware.
Have any other utility commissions disallowed or deferred recovery of a
portion of the Project investment?
No. The Company has been granted full recovery in rates for the Project
investment in each of the states in which recovery has been sought, including
Utah, Oregon, California and Wyoming.9
If a new transmission or generation system addition is not operating at full
capacity at the time it is placed into service, does that mean it is not fully
"used and useful"?
No. When a transmission project or generation plant is energized and placed into
8 Case No. PAC-E-10-07, IPUC Order No. 32196, page 38, Februar 28,2011.
9The Ben Lomond to Terminal segment of the Project was included in the Company's last Wyoming
general rate case (Docket No. 20000-352-ER-09), in which recovery for this investment was grted. The
remaining Project segment investment is included in the Company's curent Wyoming rate proceedig
(Docket No. 20000-384-ER-1O), which, as of the time of this fiing, is curently underway.
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service, all elements of the project are par of the interconnected system. These
elements are fully used and useful in providing transmission or generation service
on the system. Transmission and generation infrstrctue additions inherently
have some ability to provide futue capacity after being placed in service. This
results from using industr standard voltages and design criteria, and reliabilty
requirements necessary for system operation and maintenance.
You indicate that when a new transmission line is added~ it becomes a part of
the integrated system as a whole. Please explain.
Electrcal transmission systems are made up of numerous electrcal elements,
including lines, substations, generation plants and control systems that operate as
a fully integrated network. All elements of the network are electrically dependent
upon each other for the purose of producing and transmitting energy
instantaneously to customers on demand. New transmission capacity, when added
to an existing system, is installed in increments based on standard system
voltages, line conductors, equipment and apparatus that are available in the utilty
industr. Electrcal power flows across the entire system, and on any individual
line or station, is a fuction of the physics of the entire interconnected network
and the level of generation and load present and any given instant in time. As a
result, when a new line or substation is added, it immediately cares its full share
of the total energy being transmitted by the system. Whenever a new line or
substation is added to the transmission system, electrcal capacity on the network
is increased. The incremental capacity increase added to the network is based on
both the capacity of the new facility and on the new facility's electrical interaction
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with all other facilities to which it is interconnected.
Therefore a new project, when added to an existing transmission system,
may not operate at its full planed capacity (l,400MW for this Project) due to
those interactions with other facilities and limits existing at the time it is placed
in-service. Any futue capacity increase on an existing system made possible by
futue constrction of system facilities is attbutable to those futue system
additions. These basic priciples are discussed in fuer detail in a paper titled A
Transmission Tutorial for Non-Technical Readers, available on the Western
Electrcity Coordinating Council's (WECC) Regional Transmission Expansion
Planning (RTEP) document portal on its website.1o
Is the Commission's determination that 27 percent of the Project is not
presently used and useful a reasonable basis for deferring cost recovery of 27
percent of the investment?
Respectfully, no. The Commission notes in its Order that the 73 percent used and
useful portion of the Project "represents 1,022 MW of the total 1,400 MW that
Populus to Terminal can ultimately provide."l1 There is no one-for-one
correlation between megawatt capacity and constrction costs. It is not possible to
size transmission in discrete increments to meet any specific capacity at the time
it is needed. There was no alternative available that met all the Project
requirements at 73 percent of its capacity and at 73 percent of the cost.
What percent of the Project is currently energized?
100 percent. Since the Project went into service in November 2010, 100 percent
10 htt://www.wecc.bizIlalinilig/TransmissionExpansionlR TEP ITransmission
percent20P lanning/Transmission percent20Tutorial.pdf.
11 Case No. PAC-E-10-07, IPUC Order No. 32196, page 38, Februar 28,2011.
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of its elements were energized and being used to provide transmission service.
What percent of the Project's right of way, its 900 poles and foundations, its
permits and 135-mile length is currently being used?
100 percent. It simply would not be viable to constrct the Project with anyting
less than 100 percent of each of these major project components and all of these
components are fully used and usefuL.
Did the Company analyze a phased capacity approach for the Project to
coincide with future segments of Energy Gateway?
Yes. The Company performed a theoretical analysis using a configuation where
the Project would be constructed as designed but the second set of conductors
would not be installed until a later date to coincide with the addition of futue
Energy Gateway segments. This design provided a project rated at 50 percent
capacity and reduced reliability; however, if built at the 50 percent level, the
project costs would be reduced by only nine percent of the total investment. I
have attached Exhibit No. 31, Savings Estimate if Second Circuit Deferred, which
presents this analysis.
Is the Project the most economic to meet system requirements?
Yes. The Company evaluated multiple configuations for the Project where new
transmission line corrdors are scarce due to geographic constraints and heavily
developed urban areas, and determined the Project as constrcted is the most cost
effective. Alternatives considered are discussed in Confidential Exhibit No. 32,
September 2008 Analysis of Populus-TerminaL. Had the Company built a lower
capacity, single circuit 345 kV line in the new project corrdor, the only viable
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option under this alternative for gaining the required futue transmission capacity
would be to remove the line and replace it with a higher capacity line. The
Company estimates that, if it had pursued this option and replaced a single circuit
345 kV line with a double circuit 345 kV line in the futue, the cost to customers
would be approximately $1.24 billon (see Exhibit No. 33, Single Circuit
Constrction Replaced with Double Circuit). This incremental approach would
have resulted in a nearly 50 percent higher total cost for the Project than the
option elected by the Company.
Are there other problems with this theoretical incremental capacity option?
Yes. This option would also require extensive and costly transmission line
outages durg constrction, assuming these outages could be scheduled at all,
and would reduce Path C capacity back to pre-Project levels or lower durg the
lengthy reconstrction period.
If the Company decided not to build the remaining Energy Gateway
segments, would the Project at its current rated capacity still be needed?
Yes. The Project-as designed and constrcted-is needed to relieve existing
system capacity constraints, address known reliability concerns, and provide an
immediate increase in capacity necessar to meet existing and ongoing customer
load service and reserve obligations as demonstrated below. Please refer to
Confidential Exhibit No. 32, September 2008 Analysis of Populus-TerminaL.
Specifically, page 8 of the analysis notes:
Path C needs to be upgraded to support reliability and peak loads, even
without other planned transmission - Energy Gateway West and Energy
Gateway South. The investment is justified independent of the remaining
Energy Gateway segments.
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1 Used and Useful Considerations
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If a new transmission system addition is not operating at full capacity at the
time it is placed into service, does that mean it is not fully "used and useful"?
No. When a transmission project is energized and placed into service, all elements
of the project are used and useful in providing transmission service on the system.
Transmission infrastrctue additions installed and operated as part of an
interconnected electric system inerently have some ability to provide futue
capacity after being placed in service. This fact is a result of using industr
standard voltages, stadardized manufactung of components, design criteria and
reliability requirements necessar for system operation and maintenance.
Is Path C fully subscribed for firm transmission service at this time?
Yes. Path C, which includes multiple lines including the Populus to Terminal
lines, is fully subscribed for firm (non-recallable) transmission services, both for
network and point-to-point service in the southbound direction. A single-circuit
configuation would not be capable of providing the level of incremental capacity
additions, or reliability benefits to Path C being provided by the Project as
constrcted, and therefore would not be fully capabl~ of meeting even today's
customer demand.
Do you have requests for additional firm capacity on Path C that cannot
currently be met because the capacity is fully subscribed?
Yes. A list of pending requests for additional capacity is set fort in Exhibit No.
34, Path C Firm Transmission Reservation.
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Is 27 percent of the Project currently unused, as previously determined by
the Commission?
No. Both circuits of the Project are energized and are providing the system
reliability benefits and increased transfer capacity the Project was designed to
provide. The Project was fully used and useful from the time it was placed into
servce in November 2010.
Furhermore, the Project is operating at 100 percent of its intended
nominal design voltage of 345 kV, not 73 percent or some other number. The
Company's curent customers' electrcal demand is served by power flow across
100 percent of the entire Project elements, not 73 percent or some other portion of
the Project elements. Our future customer demand, as it increases, wil be met
using 100 percent of all the Project elements.
Additionally, each circuit of the Projecti its associated conductors and
substation terminal apparatus has the capabilty to operate at 100 percent of its
planned design. As the Project is configued, one of its lines can be taen out of
service, whether planed or unplanned, without impacting Path C's total transfer
capability since the second line is there to provide 100 percent backup capability.
Lastly, the transmission corrdor, access roads, steel transmission towers,
footings and foundations, conductors, and propert rights obtained for the lines
and stations and all the labor and expense that made the Project possible are
curently fully utilized, not 73 percent or some other percentage. Path C is
operational at 100 percent of its rated capacity approved by WECC in order to
reliably operate as an interconnected transmission system within the western grid,
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1 and 100 percent of this project is in use today and is usefuL.
2 Key Drivers for Transmission Investment and Timing
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Customer load growth information is an important factor in determining the
need and the timing of transmission projects. What load information was
used to determine project need and the investments necessary to meet that
need?
The need and timing for the Project was largely based on PacifiCorp's 2007
Integrated Resource Plan (IRP). The 2007 IRP showed system-wide coincidental
peak load growt forecasted at an average of 2.6 percent per year though 2016
and an annual peak demand growth forecast of 1.2 percent for the state of Idaho
for the same period.12 In addition, the Project is required to support the
Company's recently released 2011 IRP which shows system-wide coincidental
peak load growth forecasted at an average of 2.1 percent per year through 2020,
with Idaho's growth increasing by 2.7 percent on average per year. 13
Does the Company's Open Access Transmission Tariff ("OATT") also
require planning for and construction of transmission resources necessary
for future needs?
Yes. PacifiCorp's OATT,i4 approved by the Federal Energy Regulatory
Commission ("FERC"), details the Company's requirements and responsibilities,
which include the requirement to "plan, constrct, operate and maintain its
transmission system in accordance with good utility practice..." (Section 28.2),
12 PacifiCorp 2007 IR, Table 4.3, available at http://www.pacificorp.comles/irp.html.
13 The Idaho average anual peak load growth rate excludes growt forecasted for the Bonnevile Power
Admnistration's southeast Idaho loads that PacifiCorp serves under its BPA power exchange contrct.
Source: PacifiCorp 2011 IR, Volume 2 Table A. 10, available at htt://www.pacificorp.comles/irp.htinl.14 htt://www.oasis.pacificOl:p.com/oasis/ppwiOATTVoll lBaseline 20100908.pdf.
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and to provide network customers "firm transmission service.. . for the delivery of
capacity and energy from its designated Network Resources to serve its Network
Loads..." (Section 28.3). Section 31.6 defies the network customers'
requirement to supply annual load and resource updates, which enable the
Company to determine futue load and resource requirements for all transmission
network customers. The project investments included in this proceedig are
necessary to meet these requirements and customer demand.
Do you believe that these customer load demand forecasts reflect the
economic conditions in Idaho and impacts on customer demand?
Yes. While I'm not an expert on the economy, I can attest to the fact that
reductions in customer energy demand forecasts have coincided with the
economic downtu. As stated above, the company requests and reviews all of its
forecasted energy demand and resource submittals anually. While the
Company's last four IRPs (fied in 2005, 2007, 2009 and 2011)15 have shown
declining 1O-year system-wide coincidental peak load growt forecasts (3.0
percent, 2.6 percent, 2.4 percent and 2.1 percent, respectively), even the weakest
growth forecast shows a need for an additional 2,158 MW in 10 years16 to serve
customer load growth, 79 percent of which is growth in the east side of
PacifiCorp's system, including Idaho.
Can you provide examples of instances where the Company revised its
investment timing as a result of reductions in forecasted demand?
Yes. The Company uses its customer demand forecasts and best available
15 PacifiCorp IRPs available at htt://www.pacificorp.cOlnies/irp.html.
16 PacifiCorp 2011 IRP, Table A.1 1.
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information to determine project need and investment timing. Examples of
projects in this fiing which have been rescheduled and influenced by actual and
forecast reductions in customer demand include:
· The Red Butte Static V AR Compensator project was delayed early in its
project life cycle from 2009 to 2011 based on reduced risk due to lower
customer demand. The Company delayed the full investment, to the
benefit of customers, by installng only an initial $4 milion portion of the
device in 2010, delaying more than $40 millon of remaining investment
by two years; and
· A portion of the Mona to Oquirh project, the second segment of Gateway
Central, was delayed two years from 2011 to 2013 due to changing
business requirements along with some reduced risk resulting from slower
customer growt and reduced demand.
Beyond growing customer energy demand, are there other transmission
performance requirements driving the need for these system investments?
Yes. In meeting the curent and future customer energy needs described above,
the Company must maintain a minimum level of system reliability to provide
adequate transmission service. The Nort American Electrc Reliability
Corporation ("NERC") and WECC have recently enacted a significant number of
standards and guidelines that specify in detail the levels of system performance
that utilities must maintain durng the planing, operation and ongoing
maintenance of their bulk electrc systems. NERC's reliability standards were
approved by FERC and are mandatory for all FERC-jurisdictional entities. These
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reliability standards are targeted at improving the securty and reliabilty of the
nation's bulk electrc system, including the system in Idaho. The projects and
related investments discussed in my testimony are required for the Company to
comply with these mandatory reliability standards and to provide safe, reliable
and efficient transmission service to customers.
What specifc reliabilty performance standards and criteria require the
project investments in this case?
PacifiCorp plans, designs and operates its trasmission system to meet or exceed
NERC Standards for Bul Electrc Systems and WECC Regional standards and
criteria. The NERC standards are found in 18 CFR Par 40 (Mandatory Reliability
Stadards for Bulk-Power Systems). The WECC standards and criteria are
deemed necessary for the WECC Region to meet or exceed NERC standads.
There are curently more than 100 approved NERC stadards with which the
Company must comply. The project investments and their respective in-service
dates are required to comply with the following standards:
. NERC TPL-OO 1 System Perfonnance Under Normal Conditions17
. NERC TPL-002 Svstem Performance Follo\\ing Loss of a Single
BES Element18
. NERC TPL-003 System Perforniance Following Loss of Two or
More BES Elements19
. NERC TPL-004 System Performance Following Extreme BES
Events20
17 NERC TPL-001 can be found at: htt://ww.nerc.comlfies/TPL-001-0.pdf.
18 NERC TPL-002 can be found at: htt://ww.nerc.comlfiesITPL-002-0.pdf.
19 NERCTPL-003 can be found at: htt://ww.nerc.comlfilesITL-003-0.pdf.
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. TPL OOl-WECC-l-CR System Performance Criteria Normal Conditions21
· TPL 002-WECC-l-CR System Performance Criteria Following Loss of a
Single BES Element
· TPL 003-WECC-l-CR System Performance Criteria Following Loss of
Two or More BES
. TPL 003-WECC-l-CR System Performance Criteria Following Extreme
BES Events
. NERC TOP-002 Normal Operations Planning22
. NERC TOP-004 Transmission Operations23
. NERC TOP-007 Reporting SOL and IROL Violations24
The above-referenced standards dictate the miimum levels of transmission
system reliabilty, redundancy and performance required for transmission
facilities in this case.
Please discuss further how these standards and criteria influence the timing
of the transmission project investments in this case.
The above mandatory standads require the Company to have a forward-looking
transmission plan to reliably serve curent and anticipated customer demands
under all expected operating conditions. These conditions include normal system
operations (all system elements in service) and system contingencies (where
elements of the transmission system are out of service), both planned or
20 NERC TPL-004 can be found at: htt://ww.nerc.comlfiesITPL-004-0.pdf.21 TPL 001- WECC-1-CR - TPL 004- WECC -l-CR can be found at:
htt://ww.wecc.biziStandadsIWCC percent20CriterialTPL-OO 1 percent20thr percent20004- WECC-1-
CR percent20- percent20System percent20Pedormance percent20Criteria.pdf.
22 NERC TOP-002 can be found at: htt://ww.nerc.comlfies/TOP-002-2.pdf.
23 NERC TOP-004 can be found at: htt://ww.nerc.comlfiesITOP-004-2.pdf.
24 NERC TOP-007 can be found at: htt://ww.nerc.comlfiesITOP-007-0.pdf.
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1 otherwise. NERC Transmission Planning Standard TPL 002 states:
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A. Introduction
Purpose: System simulations and associated assessments are
needed periodically to ensure that reliable systems are developed
that meet specified performance requirements with suffcient lead
time, and continue to be modified or upgraded as necessary to meet
present and future svstem needs.
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B. Requirements
RL.The Planning Authority and Transmission Planner shall each
demonstrate through valid assessment that its porton of the
interconnected transmission system is planned such that the
Network can be operated to suiiply projected customer demands
and projected Firm (nonrecallable reserved) Transmission
Services. at all demand levels over the range of forecast system
demands. under the contingency conditons as defIned in Category
B of Table I. To be valid, the Planing Authority and Transmission
Planner assessments shall:
18
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RL.l. Be made anually.
RL.2. Be conducted for near-term (years one through five)
and longer-term (years six though 10) planning horizons.
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R2. When System simulations indicate an inabilty of the systems
to respond as prescribed in Reliabilty Standard TPL-002-0 Rl,
the Planning Authority and Transmission Planner shall each:
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30
R2.1. Provide a wrtten sumar of its plans to achieve the
required system performance as described above
throughout the planning horizon:
R2.L.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-
service dates offacilties.
R2.1.3. Consider lead times necessary to implement plans.
31 (Emphasis added)
32 In sumary, the Company is required to have both short-term and long-
33 term trnsmission plans to reliably meet all expected curent and forecasted
34 customer electrcal demands. The requirement to have such a plan is not optional
35 for the Company. The Company conducts annual load and resource forecasting
Gerrard, Di - 17
Rocky Mountain Power
1 analyses and revises its investment timing as a result of identified reductions in
2 forecasted demand where appropriate. Most of the projects in this filing require
3 multi-year planning, permitting and constrction processes, and the Company
4 must consider the lead times and schedules necessary in advance of customer
5 demand.
6 Standard Industry Practice and Precedents
7 Q.
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Is it common and accepted industry practice for utilities to plan for both the
current needs and to anticipate future system needs when planning,
designing and constructing new transmission infrastructure projects?
Yes. It is a common and accepted industr practice to plan, design and constrct
transmission systems while anticipating futue needs. This has been a common
and accepted practice for decades. Some of the oldest and most trsted utility
system planning and design guides used in the industr address the need to
consider, plan and design for the futue. The Westinghouse Transmission and
Distrbution Reference Book,25 which provides the electrc power industr basic
and essential information when planning and designing electric power systems,
states:
Choice of Voltage; The voltage is sufciently high for use as a sub
transmission voltage if and when the territory develops and
additional load is created. The likelihood of early growth of a load
district is an important factor in selection of the higher voltage and
larger conductor.
26
Furher, the reference book states in Section 9:
Choice of Conductors: As an insurance against breakdown (line
outages) important lines frequently are built with circuits in
25 Westighouse Electrc Corporation, 4th addition, Copyrght 1964.
26 Chapter 1, General Considerations of Transmission Lines, Section 8 page 8.
Gerrard, Di - 18
Rocky Mountain Power
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duplicate. In such cases the cost of conductors for two circuits
should not be overlooked.27
Finally, the reference book states in Section 11:
Choice of Supply Circuits; The choice of the electrical layout of
the proposed power station is based on the conditions prevailng
locally. It should take into consideration the character of the load
and the necessity for maintaining continuity of service. It should be
as simple in arrangement as practicable to secure the desired
flexibilty in operation and to provide the proper facilities for
inspection of the apparatus.
The Company has balanced these industr design criteria in its planning,
designing and constrction of the Project. I believe it is prudent for the Company
to follow these standards.
What process did the Company follow in determining the Project's capacity
contribution to Path C capacity ratings and why?
The Company was required to adhere to industr accepted rating policies and
procedures in place today and administered by the WECc.28 These policy and
review procedures were followed and new ratings were approved by WECC for
Path C capacity with the inclusion of the Project as a new path element. The
Company requested, and WECC has approved, ratings for Path C operation both
today and in the futue when other segments of Energy Gateway are constrcted
and/or when additional generation is added north of Path C. Path C in-servce
operational ratings are reviewed and approved by WECC for each operating
season and can change based on additional transmission and/or generation
facilties installed or removed from the system. It is important to understand that
27 Id., Section 9.
28 WECC Policies and Procedures for Regional Planning, Project Review, Project Ratig Review and
Progress Reporting Revised-April 2005.
Gerrard, Di - 19
Rocky Mountain Power
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the operational capacity ratings of WECC Paths, including Path C, can and do
change. Though this WECC process and procedure, ratings are not established
and approved for an individual transmission line or substation; they are
established and approved based on the capability of the wider interconnected
system. The Company canot simply assign a capacity rating to a project and then
go out and build and operate it as part of the wider interconnected electrc system
in the west. Rather, the Company must meet the governing standads and ratings.
Why did the Company obtain approved ratings for Path C operation at some
future date?
The Company obtained futue Path C ratings to "lock in" for our existing and
futue customers the incremental Path C capacity attbutable to planed
transmission system additions, as that capacity could otherwise be claimed by
another interconnected project, which may not benefit the Company's customers.
The WECC policies and procedures recognize and are specifically crafted based
on the reality that transmission projects are rarely built all at one time; their
capacities come in large increments, and they are often staged and placed into
service over a period of time. These policies reflect very practical economic,
constrctability and load growth considerations as well as the timing of new
generation resources. The Company made a prudent decision not to build all
Gateway segments simultaneously, as it would not have been feasible, practical,
economic or in the best interest of our customers to do so.
Gerrard, Di - 20
Rocky Mountain Power
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Given that the Commission deemed 73 percent of the Project used and useful
based on its current incremental capacity addition to Path C, wouldn't it
have been better for the Company only to seek ratings for the current system
configuration?
No. Our customers would have been disadvantaged by a narow and limited
approach. Had the Company sought WECC ratings of Path C only under the
curent system configuation, with all else equal, the Commission presumably
would have found the Project to be 100 percent used and useful since Path C is
fully subscribed today. However, the Project was necessarily designed and built
with the capability of serving both curent and forecasted customer needs, and the
Path C capacity additions attbutable to futue Energy Gateway segments are
needed to serve growing customer needs. Had the Company opted only to secure
ratings for today's system configuation, any capacity improvements to Path C
attributable to another regional entity's project would potentially belong to that
entity and not to the Company's customers. Therefore, under such a scenario,
customers would not get the full benefit of the Project and fuer investment
would be required to meet futue customer needs. The futue rating secures the
incremental Path C capacity for maximum benefit to customers.
Can you provide examples of transmission projects in the industry that have
been placed into service at one capacity and, at a future date, operated at
higher capacity?
Yes. There are many. The following are examples of transmission projects that
were placed in service with an initial electrcal capacity and, at futue dates, have
Gerrard, Di - 21
Rocky Mountain Power
1 achieved or wil achieve increased capacity due to the addition of: 1) more
2 transmissioJl elements; 2) more generation facilties; and/or 3) increased electrcal
3 load on the system.
4 . Pacific DC Intertie (WCC Path 65) was commissioned in 1970 with an
5 initial capacity of +/- 1,440 MW. As load grew over time and transmission
6 parallel and supporting elements were added to the system, the capacity of
7 the original line has been incrementally increased to its present capacity of8 +/-3,100 MW.
9 . The Intermountain DC line (WECC Path 27) had a capacity of 1,920 MW
10 when commissioned in 1986; however that capacity has recently been
11 increased to 2,400 MW due to modifications to the converter,
12 consideration of the addition of new generation resources, increased loads,
13 and changes in the interconnected system associated with Path 27.
14 . PacifiCorp's 345 kV interconnection with Nevada Energy at Har Allen
15 (WECC Path TOT2C) wil more than double from the existing rating of
16 300 MW in 2014 with the addition of the proposed Sigud-Red Butte #2
l7 345 kV line.
18 . The East of the Colorado River system (WECC Path 49) capacity was
19 increased from 8,055 MW to 9,300 MW due to the addition of new
20 generation resources, load growth and changes in the interconnected
2 1 system connected to Path 49.
22 . The Bridger West system (WECC Path 19) has a present westbound
23 capacity of 2,200 MW. Its joint owners, PacifiCorp and Idaho Power
24 Company, plan to increase this capacity to 2,400 MW as a result of
25 additional new generation resources, load growth and changes in the
26 interconnected system connected to Path 19. This capacity increase is due,
27 in par, to the new transmission capacity resulting from the Project.
28 . The Company's existing Craven Creek-Chapel Creek-Jonah 230 kV line
29 has a capacity rating of 388 MW and presently serves approximately 175
30 MW of growing Upper Green River load. As the customer load increases
31 the Company's plan is to constrct a new 230 kV line from a point south
32 of Atlantic City to Jonah Field. This wil increase the reliabilty in the area33 by elimination of a single radial feed 230 kv line and it wil
34 simultaneously add southbound capability to the existing line and increase
35 the overall transmission capabilty from central Wyoming to southwestern
36 Wyoming. Clearly the line today is used and useful as a radial line serving
37 customer load and its capacity wil increase in the futue as other facilities38 are interconnected.
Gerrard, Di - 22
Rocky Mountain Power
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. Midpoint-Valmy 345 kV line used to deliver Idaho's 50 percent share, 260
MW, of the Valmy generation to Idaho. A single circuit 345 kV line was
constrcted to deliver the power northbound to Idaho. 345 kV voltage was
selected minimize transformation stations, to minimize energy losses and
provide a reliable interconnection to NY Energy's northern system. It has
a northbound WECC rating of 500 MW, but its only firm use is to deliver
Idaho's 260 MW Valmy share. While it is capable of delivering more
capacity on a firm basis, it is clearly used and useful and its capacity could
increase as additional transmission facilties are added to the
interconnected system.
. Fire hole-Little Mountain-Flaming Gorge 230 kV line with a planned
rating of 405 MW went into service in 1964. However the line is presently
limited to 250 MW by the transformer limits at Flaming Gorge. The line
has been in-servce and in rate base for decades. While it is capable of
more than 250 MW it is fully used and useful at its present rating and
could increase over time as additional facilities are interconnected or
equipment is upgraded.
The above examples clearly show that transmission projects, when initially placed
in service may not operate át their full individual rated capabilties and are limited
to some lower capacity due to other limited elements in the wider interconnected
system. This Project is no different and reflects the prudent and accepted utility
industr practice when planing, designing, constrcting and operating
transmission infrastrctue. I urge the Commission to consider the accepted
industr practices as it considers the Project's curent usefulness.
Are there examples of regulatory support for cost recovery of prudent
investment in transmission facilties even though their full utiliation
depended on the future construction of additional facilties?
Yes. The Jim Bridger system located in Wyoming transports all of its energy to
Southeast Idaho via three 345 kV transmission lines built in 1973, 1975 and 1976.
The four Jim Bridger generating units were constrcted in 1974, 1975, 1976 and
Gerrard, Di - 23
Rocky Mountain Power
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1979. The transmission facilities had to be built with sufficient capacity to
transfer all of the planned generation at Bridger (approximately 2,200 MW).
Despite the fact that the transmission was built with excess or unused capacity,
those projects went into rate base for PacifiCorp and Idaho Power at the time of in
servce.
When the Huntington and Hunter plants were planed, Utah Power built
five 345 kV lines, one for each 400 MW planed generation unit, but each line
had an incremental planned capacity of about 500 MW, because you can't build
4/5ths of a line. This extra 1/5 capacity installed at the time has always been
acknowledged as used and useful and part of rate base. Customers have benefited
from this infrastructue for years.
CaD you provide examples of future planned projects that are similar to the
Project and are expected to be placed in servce with some excess capacity for
future use by customers?
Yes. There are a number of similar projects that are curently following the same
industr accepted practices I have stated above, the WECC regional planning and
review. process, the WECC path rating policy and procedures, and the National
Energy Policy Act (NEPA) process. The Company is following the above policies
and requirements in the development, design and configuation of all Energy
Gateway segments. Project examples include:
. McNary-John Day 500 kV
. Big Eddy-Knight 500 kV
. 1-5 Corrdor Reinforcement 500kV
Gerrard, Di - 24
Rocky Mountain Power
1 . Central Ferr-Lower Monumental 500 kV
2 . Boardman-Hemingway 500 kV
3 All the major projects listed above are in various planing or constrction stages
4 and are expected to be placed in service in the next one to five years. All of these
5 projects when placed in service will be interconnected to the wider transmission
6 system and wil initially be operated at capacities estimated to be from 10 to 40
7 percent less than each individual projects planned capacity. All of these projects
8 wil be 100 percent used and useful when placed into service in the western
9 interconnection.
10 Transmission Capital Investment Projects
11 Q.Please describe the other transmission investments in addition to the Populus
12 to Terminal Project that the Company is requesting to add to rate base in this
13 case.
14 A.Between Januar 1, 2011, and December 31, 2011, the Company wil place into
15 service approximately $151 millon of transmission investment, Exhibit No. 30,
16 Transmission Major Plant Additions, lists each of these projects as follows:
17 1. Red Butte Static V AR Compensator and 345 kV Capacitor: $46.4
18 milion. Installation of a 300 MVAR Static VAR Compensator and 345 kV
19 capacitor is required along with facility expansion at the Red Butte
20 substation in southwest Utah. Studies of the southwestern Utah area have
21 shown the need for additional reactive power support durng normal
22 steady-state operations and durng system outage conditions. This project is
23 required to ensure continued reliable service to existing and growig loads
Gerrard, Di - 25
Rocky Mountain Power
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il this area. This includes the customers of Rocky Mountain Power,
UAMPS and Deseret. It is also needed to maintain the Company's existig
firm point-to-point firm transmission service contract obligations on the
WECC rated transmission Path TOT 2C, which connects the Company's
transmission system to Nevada at Nevada Energy's Harr Allen substation.
The project is also required to maintain compliance with mandatory
NERC/WCC Transmission Planing Standards TPL-Ol through 04 and
Transmission Operating Procedures TOP 02, 04, and 07.29
Dave Johnston - Casper 230 kV Rebuild - #1 Line: $6.1 millon. This
project involves relocation of portions and rebuilding of all of the existing
Dave Johnston - Casper 230 kV #1 line. Additionally the project requires
installation of a new conductor on the existing Dave Johnston - Casper 230
kV #2 line. Without this project the WECC rated Path TOT4A operating
capacity must be reduced by approximately 100 megawatts resulting in
reductions of fi energy transfers from the Dave Johnston and Wyodak
plants and wind generation in the area. This project is required to maintain
existing transmission capacity to serve existing customer demand in Idaho
and other states and to meet forecast futue load growth and to maintain
existing WECC Path TOT4A ratings. The project and resulting investment
are also necessar to maintain compliance with NERC/WCC
Transmission Planing Standards TPL-O 1 through 04 and Transmission
Operating Standards TOP-02, 04, and 07.
29 htt://ww.nerc.comlfileslReliability _ Stadads_Complete_Set. pdf.
Gerrard, Di - 26
Rocky Mountain Power
1 3. Malin Substation 500 kV Series Capacitor Replacement: $18.7
2 milion. This project required the replacement of the Company's existing
3 500 kV series capacitor located in Bonnevile Power Admiistration's
4 Malin substation near Klamath Falls, Oregon. There are curently thee
5 separate series capacitors installed on the California-Oregon AC Intertie
6 500 kV system, one of which is owned by the Company. The Company's
7 series capacitor located at Malin is the smallest of the existing thee
8 capacitors and thereby is the limiting electrical elements in obtaining a
9 higher operating transfer capacity on the Pacific AC Intertie, of which the
10 Company is also par owner. Replacement of the series capacitor was
11 agreed to as a necessary transmission system upgrade under FERC Docket
12 Number ER07 -822-000 Article VIT.
13 4. Harry Allen Sub Install Transformer: $15.1 milion. This project
14 requires installation of a second 300 MV A 230/345 kV transformer at
15 Nevada Energy's Harr Allen substation. This is a 230/345 kV transformer
16 which electrically connects the Company's single Red Butte 345 kV line to
17 Nevada. The existing transformer at Harr Allen is not capable of serving
18 the existing or futue forecasted network customer loads. Under certain
19 expected operating conditions the Red Butte substation, which is served
20 from the Harr Allen transformer, wil become overloaded above its
21 operating limits. The project and resulting investment are necessary to
22 maintain compliance with NERCIWCC Trllnsmission Planning Standards
23 TPL-Ol through 04 and Transmission Operating Standards TOP-02, 04, 07.
Gerrard, Di - 27
Rocky Mountain Power
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Mona - Limber - Oquirrh 500/345 kV line Phases I and II: $8.4 milon.
The Mona to Oquirh project is the second segment of Energy Gateway
Central planned for completion in 2013. This initial investment related to
this project is required for development and constrction of the initial
portion of the Mona to Oquirh segment. The project requires "looping in"
the Company's existing Camp Wiliams to Terminal 345 kV line into and
out of the Company's existing Oquirh 345 kV substation located in South
Jordan, Utah. This project is requied for increased reliabilty necessary to
maintain reliable service to existing and futue customers in the Wasatch
Front of Utah and Southeast Idao and to maintain system reliability durng
transmission line outages north of Camp Wiliams. The project and
resulting investment are necessar to maintain compliance with
NERCIWECC Transmission Planing Standards TPL-O 1 through 04 and
Transmission Operating Standards TOP-02, 04, 07.
The Mona to Oquirh project is necessar to remove existing
transmission system limitations, reliably serve existing customers and serve
forecasted long term load growth in the state of Idaho. It is also required to
meet the Company's integrated resource plans and is necessar to deliver
identified energy resources to load centers. The Mona to Oquirh project
has been issued a Certificate of Public Convenience and Necessity by the
Utah Public Service Commission under Docket No. 09-035-54, dated June
16, 2010, and has been approved by the Utah Utilty Facility Review Board
under Docket No. 10-035-39, dated June 10,2010.
Gerrard, Di - 28
Rocky Mountain Power
1 6. Populus-Terminal 345 kV line - Borah Reconductor: $13.4 milion. The
2 Populus to Terminal Project scope of work included a replacement of line
3 conductors on some portions of the Borah to Ben Lomond 345 kV line.
4 This work was defined as an incremental piece of the Populus to Terminal
5 Project, however the Borah to Ben Lomond 345 kV line could not be
6 removed from service for system integrity and reliabilty reasons until the
7 new Populus to Terminal double circuit line was completed and energized,
8 as this new line provided capacity and reliability durig extended outages
9 of the Borah 345 kV line.
10 7. Populus-Terminal: Double Circuit 345 kV Transmission Line -
11 Transmission: $13.4 milion. This investment is related to residual Project
12 closeout costs incured after the Project was placed in servce in November
13 2010. These investments include but are but not limited to land reclamation
14 costs (seeding areas that were previously covered with snow); finalizing as-
15 built drawings; owner's engineer charges; legal fees for condemnation
16 activity; and installation of traveling wave line fault locators.
17 8. Oquirrh - New 345-138 kV Substation Transformer: $6.8 million. This
18 project is required to meet existing and futue customer energy demand. It
19 is located in Salt Lake City, Utah. The addition of a new substation
20 transformer is required in order provide reliable electrc servce to
21 customers and to comply with mandatory NERC/WCC reliability and
22 performance standards. This transformer will provide new capacity
23 required to prevent overloads on six existing interconnected 345-138 kV
Gerrard, Di - 29
Rocky Mountain Power
1 transformers connected to the transmission system in the area. Failure of
2 existing transformers would cause service disruption of up to 87,500
3 customers under certin operating conditions. The project is necessary to
4 comply with NERC performance standard TPL-OO 1 and TPL-002 and TPL-
5 003. The 345 kv lines connected to the Oquirh substation are part of the
6 bulk electrc system serving Southeast Idaho.
7 9. Idaho and Wyoming Clearance Issue Corrections: $6.6 million and $5
8 million, respectively. The Idaho and Wyoming clearance issue correction
9 projects were. implemented to comply with both 1) The National Electric
10 Safety Code (NESC) clearance requirements, and 2) a NERC Alert released
11 in late 2010. Per the NESC requirement, recent sureys of select lines
12 identified several spans which, if loaded to published capacity, would
13 violate the allowable NESC clearance. Phase 1 of these projects is to
14 correct these potential clearance issues. Per the NERC alert, in late 2010
15 NERC issued a reliability alert requirig utilities to verify that published
16 line ratings met field conditions.
17 10. California-Oregon Intertie Upgrade 4800MW Rating: $6.2 million.
18 This project requires installation of a series capacitor at the Bakeoven
19 substation and shunt capacitors at the Captain Jack and Slatt substations, as
20 well as reconductoring of one mile of line on each of the John Day Grzzly
21 #1 and #2 500 kV lines. These additions and upgrades are the result of
22 Bonnevile Power Administration reliability studies on the 500 kilovolt AC
23 California-Oregon Intertie to determine what infrastrctue additions are
Gerrard, Di - 30
Rocky Mountain Power
1 required to operate closer to the operational line rating of 4800 MW. The
2 studies show that the facility modifications wil allow an average 80
3 megawatt increase of operating transfer capability durg summer months
4 on the 500 kV AC California-Oregon Intertie. The Company is par owner
5 in the 500 kV AC intertie and by contract is obligated to participate in
6 Intertie upgrades to maintain reliability.
7 11. Skypark: Build New 138-12.5 kV Substation: $5.1 million. The Skyark
8 substation project is necessary to prevent thermal overloading of 5
9 substations in the Woods Cross/North Salt Lake, Utah area. The new
10 substation wil allow for load transfers from the existing substations and
11 defers additional substation projects in the area until 2020. The project wil
12 also reduce loading at the Woods Cross substation and on the 46 kV
13 transmission systems in the area. This portion of the overall project is
14 related only to the investment in transmission facilities and is required to
15 serve existing and futue customers energy demands and the project is
16 necessary in order for the company to comply with NERC TPL-OOI and
17 TPL-002.
18 Conclusion
19 Q.Please summarize your testimony.
20 A.The Populus to Terminal Project is in-service and is 100 percent used and usefuL.
21 It is capable of operating at 100 percent of its curent WECC rated capacity as an
22 integral par of the wider interconnected transmission system. The Company
23 complied with mandatory standards and followed industr accepted practices and
Gerrard, Di - 31
Rocky Mountain Power
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precedents in planing, designing, constrction and subsequent operation of the
Project. The Company could have sought a reduced rating for Path C based only
on its curent capacity and not taking into consideration the futue impact of the
Project, other Energy Gateway Segments or other generation. This option would
have supported a finding from the Commission in the last case that the Project
was fully used and useful, but it would have put at risk the Company's ability to
reserve the futue benefits of the Project for its customers.
I respectfully request that the porton of the Project investment not
curently in rate base be included in this case. Additionally, the major
transmission capital expenditues included in my testimony are all essential and
are required to meet customers' needs, including those customers in Idaho, both
curent and futue, while providing safe, adequate, reliable and effcient electrc
transmission service. These investments are required in order for the Company to
comply with its statutory obligations to serve customers under its FERC approved
OATT and to comply with FERCINERC/WCC mandatory reliabilty standads
for bulk electrc systems.
Lastly, the transmission capital investments included in this case are in the
public interest for the reasons I discuss throughout my testimony, including
serving Idaho with an ongoing supply of safe, adequate and reliable electric
energy, capacity and service. For these reasons, I urge the Commission to approve
these investments and thereby include them in the Company's rate base.
Does this complete your direct testimony?
Yes.
Gerrard, Di - 32
Rocky Mountain Power
201H1AY 27 AM 11= 05 Case No. PAC-E-11-12
Exhibit No. 30
Witness: Darell T. Gerrard
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Darell T. Gerrard
Transmission Major Plant Additions
May 2011
Rocky Mountain Power
Results of Operations - December 2010
Major Plant Addition Detail - January to December 2011
Project Description In-Service Date
Transmission
Red Butte Static Var Compensator and 345 kV Shunt Capacitor
Malin 500 kV series cap replacement
Harry Allen Sub Install Transformer
Populus-Terminal: Obi Ckt 345 kV TransLn - Transmission
Populus - Terminal 345 kV line - Borah Reconductor
Mona - Limber - Oquirrh 500/345 kV line Phases I and II
Oquirrh New 345-138kV Substation
Idaho Clearance Issue Corrections
Dave Johnston - Casper 230kV Rebuild - #1 Line
California-Oregon Intertie Upgrade 4800MW Rating
Skypark: Build New 138-12.5 kV Substation
Wyoming Clearance Issue Corrections
Transmission Total
May-11
Feb-11
Jun-11
Nov-10
Feb-11
Apr.11/May11
Jan-11
Jun-11
Jan-11
Jul-11
Oct-11
Dec-11
Rocky Mountain Power
Exhibit No. 30 Page 1 of 1
Case No. PAC-E-11-12
Witness: Darrell T. Gerrard
Jan11 to Dec11 Plant
Additions
46,434,990
18,700,000
15,100,000
13,409,213
13,400,000
8,362,700
6,804,918
6,616,683
6,127,474
6,157,000
5,070,679
5,017,130
151,200,786
2011 MAY 27 AH II: 05 Case No. PAC-E-ll-12
Exhibit No. 31
Witness: Darrell T. Gerrard
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAI POWER
Exhibit Accompanying Direct Testimony of Darrell T. Gerrard
Savings Estimate if Second Circuit Deferred
May 2011
Rocky Mountain Power
Exhibit No. 31 Page 1 of 1
Case No. PAC-E-11-12
Witness: Darrell T. Gerrard
Populus - Terminal 2010 Construction Costs
One 345 kV Circuit and Two Substation Bays
2010
Unit QTY $/Unit Cost
1272 Aluminum Conductor LF 4,322,578 $4 $16,641,925
345kV Bundled V String EA 780 $10,504 $8,193,385
345kV Bundled Angle EA 75 $13,268 $995,126
345kV Bundled D.E EA 55 $52,250 $2,873,763
Dampers EA 5,450 $63 $342,424
Single 345kV Bay: Terminal LS 1 $5,475,000 $5,475,000
Single 345kV Bay: Ben Lomond LS 1 $4,725,000 $4,725,000
Access Road/Restoration LS 1 $2,000,000 $2,000,000
Mobil ization/Demobiliation LS 1 $500,000 $500,000
Sales Tax %6.70%$2,797,024
Construction Labor $17,674,750
Construction Management $6,212,003
Bonds/Insurance $580,337
Owners Engineer Support $1,888,184
Rocky Mountain Power Staff $287,235
Permits $365,000
Total- Direct Capital Costs1 $71,551,156
1) Costs do not include capital surcharge or allowance for funds used during construction
20,niAY 27 AM fI: 06 CONFIDENTIAL
Case No. PAC-E-l1-12
Exhibit No. 32
Witness: Darrell T. Gerrrd
BEFORE THE IDAHO PUBLIC UTILITIES COMMSSION
ROCKY MOUNTAI POWER
CONFIDENTIAL
Exhibit Accompanying Direct Testimony of Darrell T. Gerrard
September 2008 Analysis of Populus-Terminal
May 2011
THIS EXHIBIT IS CONFIDENTIAL
AND IS PROVIDED UNDER
SEPARATE COVER
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2011 HAY 27 AM II: 06 Case No. PAC-E-11-12
Exhibit No. 33
Witness: Darrell T. Gerrard
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Darrell T. Gerrard
Single Circuit Constrction Replaced with Double Cirit
May 2011
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ZOUHAY 27 AM II: 06
Case No. PAC-E-ll-12
Exhibit No. 34
Witness: Darrell T. Gerrard
t)
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Darrell T. Gerrard
Path C Firm Transmission Reservation
May 2011
Rocky Mountain Power
Exhibit No. 34 Page 1 of 1
Case No. PAC-E-11-12
Witness: Darrell T. Gerrard
Network Load Service PAC 1146
Network Other Other 100 Future
Sub-total Network Service 1246
Point to Point Service PAC 523
Point to Point Service Other Other 99 Future
Sub-total 622
Total 1868