20100528Gerrard Direct.pdf

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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 Darrell T. Gerrard
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-10-07
May2010
1 Q. Please state your name, business address and present position with
2 PacifiCorp ("Company").
3 A. My name is Darrell T. Gerrard. My business address is 825 NE Multnomah,
4 Suite 1600, Portland, Oregon 97232. I am Vice President of Transmission
5 System Planning.
6 Qualifications
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Briefly describe your education and business experience.
I hold a Bachelor of Science in Electrical Engineering (Power Systems Major)
from the University of Utah and Certificate of Completion with Honors in
Electrical Technology from Utah Technical College at Salt Lake. My experience
spans more than 30 years in the electric utility industry. I've had working
experience and management responsibility for a number of functional
organizations at PacifiCorp including: Area Engineering; Area Planning; Region
Engineering; transmission and distribution ("T&D") Facilities Management;
Transmission, Substation and Distribution Engineering; System Protection and
Control; T&D Project Management and Delivery; Asset Management; Electronic
Communications; Hydro System Engineering; Transmission Grid Operations;
and most recently, Transmission System Planning.
In my current position, I am responsible for transmission planning
activities required to support PacifiCorp's existing and future planned bulk
transmission system. I am also responsible for the conceptual and detailed system
planning and architecture associated with the Company's comprehensive long-
term transmission expansion plan known as Energy Gateway.
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1 Purpose and Overview of Testimony
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What is the purpose of your testimony?
The purpose of my testimony is to provide additional details and technical
information, in support of the testimony of Company witness Mr. John A.
Cupparo, on the Company's decision to build the double-circuit 345 kilovolt
("kV") Populus to Terminal transmission line (Phase I and II), which is part of
Segment B of Energy Gateway (See Exhibit No. 33). Specifically, my testimony:
• Provides an overview of the Populus to Terminal transmission line;
• Explains that the benefits of adding this transmission line are to meet
future load and resource requirements for customers and to maintain
system reliability, consistent with the standards set by the North
American Electric Reliability Corporation ("NERC") and the Western
Electricity Coordinating Council ("WECC");
• Explains the analyses the Company performed that support the
decision to invest in this line;
• Describes the competitive procurement process used to make the
investment and how cost savings opportunities were identified; and
• Provides an overview of the construction process.
19 Overview of Transmission Project
20 Q. Please describe the scale and size of the Populus to Terminal transmission
21 segment.
22 A. Populus to Terminal will add 135 miles of new transmission line, over 8,600,000 ·
23 linear feet of conductor and approximately 900 poles will be installed on new
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foundations. At the time of this filing, the overall Populus to Terminal project is
on schedule for completion in November 2010. The first phase of the project
extending 46 miles, from Ben Lomond Substation near Ogden, Utah to Terminal
Substation in Salt Lake City, has been placed in service and is operational.
Please describe the transmission investment included in this rate case.
In this case, the Company is seeking cost recovery for the Populus to Terminal
transmission segment of Energy Gateway, described in more detail in the direct
testimony of Mr. Cupparo. A map showing the entire route of the Populus to
Terminal segment is shown in Exhibit No. 34. The Company estimates the costs
for the Populus to Terminal segment to be placed in-service in the test period of
this case are approximately $801.5 million as shown in Exhibit No. 37, and
expects the line to be in service by November 30, 2010.
What is the purpose of the Populus to Terminal transmission segment?
In addition to the project benefits described in the testimony of Mr. Cupparo, the
purpose of the Populus to Terminal transmission line is to:
• Increase the overall transmission capacity in the existing transmission
corridor between southeast Idaho and northern Utah, where the existing
system has limited capacity and has demonstrated operational limitations.
• Meet the immediate need to: (1) improve system reliability in the area and
maintain compliance with national electrical system reliability standards
by installing new transmission capacity to ensure the system can sustain
transmission outages north of Terminal Substation without curtailing·
. loads, generation or impacting PacifiCorp's East Control Area and
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neighboring transmission balancing authority areas; and (2) improve the
Company's ability to perform maintenance on transmission facilities
between Populus and Terminal by having alternative transmission paths
that allow facilities to be taken off-line and maintained.
• Meet the transmission capacity and reliability requirements necessary to
deliver resources to loads as specified in the annual Loads and Resource
plans submitted to PacifiCorp under requirements of its Open Access
Transmission Tariff ("OA TI").
• Provide PacifiCorp with options and greater flexibility when considering
future planned resources to meet customers' growing demands for energy
while meeting current and future energy requirements that may be
mandated by state and federal regulation.
• Facilitate the integration of potential new energy resources in Wyoming,
Utah, Idaho and Oregon, and help support economic development in those
states.
• Integrate with future Energy Gateway segments to increase transfer
capability between PacifiCorp's east and west control areas in order to
balance generating resources and loads, and enable commercial energy
purchases or sales while allowing integration of new renewable generation
. resources.
• In the long term, provide an incremental increase in transmission capacity
and reliability benefits for future Energy Gateway transmission segments
planned between Wyoming, Idaho, Utah, Oregon and Washington, and
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1 interconnect the region in general.
2 Need for and Benefit of Additional Transmission
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What information was used in determining the need and justification for this
investment?
PacifiCorp's OATI describes PacifiCorp's requirements and obligations to
provide transmission service.1 Section 28.2 defines PacifiCorp's responsibilities,
which include the requirement to "plan, construct, operate and maintain the
system in accordance with good utility practice." Section 31.6 defines the
requirement for network customers to supply annual load and resource updates for
inclusion in planning studies. The Company solicits this data annually to
determine future load and resource requirements for all transmission network
customers including PacifiCorp's network and third-party customers. The
Company's retail loads comprise the bulk of the transmission network customer
needs including those in Idaho. Section 28.3 includes the requirement for
PacifiCorp to provide "firm service over the system so that designated resources
can be delivered to designated loads." These future requirements and needs will
be met via Energy Gateway and its segments, including the Populus to Terminal
segment.
Are other transmission performance requirements, besides growing
customer energy demand, driving the need for this system investment?
Yes. In meeting the current and future customer energy needs described above,
the Company must maintain a level of system reliability in order to provide
1 Paci.fiCorp's OAIT may viewed at
http://www.oasis.paci.ficorp.com/oasis/ppw/PACREST ATEOOA 1TASOF1- l 0-1 O.PDF
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adequate transmission service. The NERC and the WECC have recently adopted
and enacted a significant number of standards and guidelines that specify in detail
the levels of system performance that entities like PacifiCorp must maintain
during the planning, operation and ongoing maintenance of their bulk electric
systems. NERC' s reliability standards were approved by the Federal Energy
Regulatory Commission ("FERC'') and are mandatory for all FERC-jurisdictional
entities. These reliability standards are targeted at improving the security and
reliability of the nation's electric infrastructure and, specifically in Pacifi.Corp's
case, the WECC region. Investments made in Populus to Terminal will help
PacifiCorp comply with these mandatory reliability requirements. Further, the
investment will provide reliability benefits to future planned high-voltage
transmission additions interconnecting Wyoming, Utah, Idaho, Oregon and the
region.
Are there examples where these new reliability standards and guidelines
resulted in changes to the system and its operation, which drives investments
required in transmission?
Yes. In early 2008, PacifiCorp performed an operational analysis of the
transmission system north of the Ben Lomond substation. As a result of this
analysis, and reflective of NERC and WECC standards and guidelines, the system
firm transmission capacity was reduced from approximately 775 MW to 430 MW
during heavy-load hours and reduced from approximately 900 MW to 620 MW
during light-load hours. This reduction in firm capacity was a result of NERC
and WECC standards and guidelines that require transmission capacity to be
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reduced due to potential outage risks associated with multiple transmission lines
being located adjacent to each other in common corridors. The investment in the
Populus to Terminal segment is required to increase the firm capacity in this part
of the transmission system.
How did the Company determine that additional transmission capacity was
needed?
The Company utilizes the Integrated Resource Plan ("IRP") to review whether
additional transmission capacity is needed. The IRP uses a public process to
develop a framework for the prudent future actions required to ensure the
Company continues to provide reliable and least-cost electric service to its
customers. It must do this while also striking an expectedbalance between cost
and risk over the planning horizon and taking into consideration environmental
issues and the energy policies of Pacifi.Corp's states. As stated in the 2008 IRP,
"PacifiCorp's IRP mandate is to assure, on a long-term basis, adequate and
reliable electricity supply at a reasonable cost and in a manner consistent with the
long-run public interest."2
Did the Company make any commitments to add transmission capacity?
Yes. During the MidAmerican Energy Holdings Company ("MEHC") acquisition
of PacifiCorp in 2006, the Company committed to increase the transmission
capacity by 300 MW from southeast Idaho to northern Utah. The objectives of
the transaction commitment were to:
• Enhance the reliability of the only high use commercial path between
23 Idaho and Utah;
2 2008 IRP at p. 19.
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• Provide for increased transfer capability between PacifiCorp's east and
west control areas; and
• Facilitate the delivery of future power from wind projects in Wyoming
and Idaho, and provide PacifiCorp with greater flexibility and the
opportunity to consider additional options regarding future planned
generation capacity additions.
Describe how the Populus to Terminal transmission segment complies with
the IRP and MEHC commitment.
The Populus to Terminal transmission line segment is designed to meet load
growth, future customer energy service requirements and improve overall system
reliability. Based on the Company's 2008 IRP, PacifiCorp's network load
obligation is expected to grow during the next 10 to 20 years. In addition,
operational reserve obligations required to balance and maintain system reliability
will increase over time as they are a function of load served. The existing
transmission capacity from southeastern Idaho into Utah is fully subscribed and
no additional capacity can be made available without the addition of new
transmission lines. The Populus to Terminal line will add significant new
incremental transmission capacity (1,400 MW planned) to this area of the system
and will help integrate other future planned resources, market purchases and sales
as necessary to help control energy costs. The investment also improves the
system reliability as needed, which I discuss later in my testimony. All of the
above support PacifiCorp' s IRP and the commitments made by MEHC.
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Has the Company performed other studies and analyses that demonstrate the
need to improve the reliabiUty of the transmission system in this area?
Yes. In addition to the long-term energy resource needs discussed in the
testimony of Mr. Cupparo, the Company performed specific analysis in late 2007
and 2008 addressing several system disturbance events that severely impacted
generation, customers, and the operation of the transmission system. These
events also impacted other utilities interconnected to PacifiCorp's transmission
system. Additional details about these disturbances are given later in my
testimony.
Will Populus to Terminal aid in preventing the recurrence of these types of
disturbances?
Yes. It is evident from these disturbances and the resulting analysis that the
transmission system in this area does not have the necessary capacity and
reliability to meet all of the system operating conditions. NERC electric system
reliability standards require that the system demonstrate adequate performance for
all expected operating conditions including multiple contingencies. There were
five system disturbances since September 2007 for which the Populus to Terminal
line directly mitigates the risk of reoccurrence.
Please provide further explanation of how Populus to Terminal will aid in
the prevention of these types of system disturbances.
Three of these disturbances occurred on the system north of Ben Lomond
substation and two occurred south in the Ben Lomond to Terminal section. These
disturbances resulted in system overloads, curtailments of schedules, repeated
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1 curtailments of interruptible loads, and generation reductions in Wyoming, Utah
2 and other surrounding states. The three disturbances occurred on September 27,
3 October 15, and October 21, 2007, during periods of heavy flow northbound from
4 the Terminal Substation towards Ben Lomond and into Idaho and on into the
5 northwest. As a result, over 1,450 customers were affected by the first outage,
6 and some customer loads were either interrupted and/or reduced during all three
7 outages. Generation curtailments and adjustments of more than 1,000 MW had to
8 be requested for all three incidents including reduced generation from Dave
9 Johnston and Naughton plants in Wyoming. Large industrial customers like
10 Nucor Steel and Monsanto Corporations were impacted multiple times during
11 these events and were required to reduce their electrical demands to help bring the
12 transmission system back into reliability limits. Details and analysis of the
13 system performance during the events and transmission limitations are detailed in
14 PacifiCorp System Disturbance Report dated November 11, 2007, and
15 PacifiCorp's Abbreviated System Disturbance Report to WECC dated January 28,
16 2008.
17 On November 27 and November 30, 2007, two disturbances occurred on
18 the Ben Lomond to Terminal section of the system causing overloads on three
19 WECC designated and monitored transmission paths. The disturbances impacted
20 more than 400 MW of PacifiCorp generation along with generation
21 interconnected to three other utilities in surrounding states. These other
22 interconnected transmission providers, external to the states of Utah and Idaho,
23 also experienced overload conditions on their respective systems.
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· Based on the system performance, studies and analysis, it is clear that the
existing system requires new capacity to meet expected operating conditions and
reliability requirements on both a short and long-term basis. The investment in
the Populus to Terminal line is the first step in providing the needed capacity.
What is the transmission capacity and limitations on this system today?
The existing transmission capacity in the area between Salt Lake City and
southeast Idaho is fully subscribed for firm service and has limited transfer
capability between several key transmission substations (Terminal, Ben Lomond,
and proposed Populus) connecting generation facilities in Idaho, Wyoming and
Utah. No new capacity will be available until new transmission facilities are
constructed. The limitations and system performance deficiencies are discussed
later in my testimony. These limitations restrict the ability to transfer firm energy
between PacifiCorp's Eastern Control Area to Western Control Area.
Does the investment in the Populus to Terminal line provide reliability and
capacity benefits to future planned transmission additions in the area?
Yes. The existing transmission in the corridor from Terminal to southeastern
Idaho has limitations. Without investment in the Populus to Terminal line, the
full transfer capability on both of the Gateway West and Gateway South
segments, which are described in Mr. Cupparo's testimony, would not be
possible. To obtain the full capacity of the Gateway West and Gateway South
segments, both segments must be electrically interconnected. This
interconnection is partially achieved by building the Populus to Terminal
transmission line as part of Gateway Central.
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What alternatives to the Populus to Terminal project did PacifiCorp
consider?
The Company considered but rejected four alternatives. The first alternative was
to not build the line or to upgrade other existing paths or seek additional
transmission corridors into Utah. The Company rejected this alternative because
it did not improve existing system reliability or provide any new incremental
transmission capacity. New incremental transmission capacity is needed for both
load service and for contingencies.
The second alternative considered was to rebuild the majority of the
existing 138 kV lines interconnecting Utah and southeast Idaho and continue
operation of these lines at 138 kV. This alternative would have provided a small
incremental increase of 300 MW or less in transmission capacity across the
currently constrained path between southeast Idaho and Utah. It also would not
have provided adequate interconnection capacity between future Gateway West
and Gateway South segments or offer any additional capacity for the future. In
addition to the marginal increase in transmission capacity, this alternative had
serious constructability issues because it required large segments of the path to be
completely removed from service for extended periods (a year or more), while
these existing 138 kV facilities were rebuilt. This would have placed significant
reliability exposure on the transmission system serving the area to customers
during construction. Additionally, this alternative did not allow the Company to
meet its current firm transmission obligations nor did it meet the long-range
resource plans and network load service requirements.
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The third option considered was to construct a new single circuit 345 kV
transmission line from the future Populus substation near Downey, Idaho to the
Ben Lomond substation in Utah, which would have provided some capacity
increase from Idaho to Ben Lomond. This alternative included an upgrade of the
existing 138 kV line between Ben Lomond and Terminal to realize a minimum
increase in capacity of 300 MW from Ben Lomond to Terminal substation.
However, this alternative would not have provided the necessary future system
capacity between Gateway West and Gateway South and would have failed to
take advantage of maximizing transmission capacity installed in the new corridor
and the existing Ben Lomond to Terminal transmission corridor.
The fourth option considered was to build a new 500 kV line along the
route. The Company rejected this option because of its high cost, its potential for
significant siting and community impacts, its requirement for a completely new
corridor between Populus and Terminal substations, and its failure to use existing
vacant corridors and property rights that the Company previously obtained.
Please explain any further considerations that inform the Company's
decision to select the Populus to Terminal line.
The Company selected this transmission line project based on several factors:
• It meets short-term and immediate reliability needs while prudently
planning for the future.
• It adds significant long-term incremental transmission capacity (planned
rating 1,400 MW) across the currently constrained transmission system ..
There have been several transmission outages since 2007 along this
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1 corridor that could have been mitigated with additional transmission
2 facilities. The risk of further unplanned disturbances is considerable if the
3 current facilities are not improved.
4 • It allows increased transfers of up to 1,400 MW of capacity between
5 southeast Idaho and northern Utah that will be required based on long-
6 term planning results.
7 • Construction benefits occur on a significant portion of the transmission
8 project due to existing corridors that were acquired by the Company many
9 years ago just for this purpose. The project optimizes use of limited
10 transmission corridor lands by maximizing installed transmission capacity
11 in new corridors.
12 • Construction could occur with minimum planned outages on existing
13 facilities remaining in service without increasing reliability exposure to
14 the current system.
15 • The Company's ability to perform required maintenance will be improved
16 without significant operational risk associated with taking existing lines
17 out of service.
18 Bid Process
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Please describe the Company's typical procurement process used for major
transmission projects.
The Company uses a competitive blind-sealed bid process to contract for the
development of each project unless certain defined conditions apply, such as a
restriction in the supply of technology or design solutions that prevent an open
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competitive process. The form of contract tendered is a turnkey, fixed-price, date
certain basis for delivery, referred to as an engineer, procure and construct
approach. The Company identifies potential bidders that provide the capabilities
required to deliver the work scope within a boundary of project specific technical
specifications and commercial terms. The tender process includes a question and
answer period to clarify any outstanding issues and provides anonymity to the
requesting bidder, with responses of a non-confidential nature provided to all
bidders. Upon receipt of tender documents, the technical proposals are separated
from commercial proposals and a separate technical and, commercial evaluation is
performed on all qualified bids using pre-established evaluation criteria (see
Exhibit No 38, summary of bidder evaluation). The technical evaluation is
assisted by external consulting firms who have been pre-contracted for such work
based on their industry experience. Upon completion of technical and
commercial evaluations a recommendation is made to enter post-tender
negotiations to reach final terms, conditions and pricing to support contract
execution.
Was this typical procurement process applied to Populus to Terminal?
Yes. Specifically for the project, the Company adopted an open competitive
process where 75 vendors were identified and received an invitation to bid. The
competitive process began in October 2007 and provided two separate blind-
sealed bidding opportunities. During the October 2007 to May 2008 bidding
period, four communications were provided to bidders containing additional
project-specific information. This information was intended to assist bidders to
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1 refine their submissions and specifically, to remove any bid qualifications
2 associated with contingent and non-firm pricing. All bid responses were initially
3 due in May 2008. After additional information was provided to bidders during
4 May 2008 to July 2008, new or revised bids were due in July 2008 to allow a
5 further refinement of previously submitted design solutions, terms and conditions,
6 including price. Three qualified bids were received and evaluated resulting from
7 the May 2008 proposal. Two competing bids were received in July 2008. During
8 the separate technical and commercial evaluations, the Company and its
9 consultants identified non-fixed price aspects of the bidders' proposals affecting
10 cost and schedule. The Company consultant computed a cost associated with
11 non-fixed price work scope submitted by each bidder, which ranged from
12 approximately $103 million to $429 million. The Company negotiated to remove
13 or cap the cost of non-fixed priced work to mitigate post-contract award price
14 escalation and schedule change. The Company awarded the contract in October
15 2008 after negotiations that reduced the contractor's price. The original contract
16 costs associated with the Populus to Terminal investment to be placed in service
17 in 2010 are $567.6 million.3 As shown on Exhibit No. 37, additional project costs
18 are associated with changes in the contractor work orders, materials purchased by
19 the Company, right of way acquisition costs, legal fees, internal labor and
20 purchased services.
3 Toe original contract also includes costs associated with removing and replacing conductor on a
connecting transmission line that will be completed in 2011. These costs are not included in the request for
cost recovery in this case.
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What process, if any, did the Company use to identify and implement cost
savings opportunities during the procurement process?
During the tender evaluation process, bidders were requested to submit cost
4 savings opportunities for consideration. Each item was reviewed to assess
5 savings with respect to potential impact to operability, reliability and
6 maintainability that were included in the final contract price. In addition, post-
7 tender negotiations included a reduction of $25 million due to commodity price
8 reductions that occurred in the global market during the tender evaluation period.
9 Construction Process
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Please describe the construction process.
The construction process involves several major activities and numerous
subordinate tasks in order to engineer, procure and construct transmission
facilities. The high-level tasks are:
• Preconstruction, which includes: planning and engineering; construction
permitting; establishment of lay down yards; development of safety and
construction plans; staging of construction crews and materials; negotiation of
construction stipulation forms with landowners; and public notification of
construction.
• Transmission line construction, which includes: initial access road
construction; foundation installation; tower installation; and installation of
conductor and optical ground wire.
• Substation construction, which includes: access construction; substation
grading; civil construction; steel erection and control building installation; and
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1 equipment installation.
2 • Testing and commissioning. which include individual line and equipment tests
3 and critical punch list resolution.
4 Exhibit No. 39 contains photographs of the construction of the line and Populus
5 substation at various stages completion.
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What is the current status of construction of the Populus to Terminal line?
The first phase of the project between Ben Lomond and Terminal substation is
8 complete. The second phase of the project between Ben Lomond and Populus
9 substation will be energized by November 30, 2010.
10 Q. Please state why you believe the second phase of the project will be complete
11 and in-service by November 30, 2010.
12 A. Weekly project management status reports and field verification confirm
13 construction is on schedule and will be completed by November 30, 2010, barring
14 unforeseen events.
15 Conclusion
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Please summarize .your testimony.
The existing transmission system capacity from southeastern Idaho into Utah is
18 fully utilized, significant operational limitations exist on the system in this area,
19 and no additional capacity can be made available without the addition of new
20 transmission lines. The Populus to Terminal transmission line investment is
21 prudent because it meets immediate short-term reliability requirements and longer
·22 term customer needs by adding significant incremental transmission capacity
23 between southeast Idaho and northern Utah.
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1 Further, the investment facilitates a stronger interconnection to systems in
2 Idaho, Utah, and Wyoming and to the Northwest in general. The Populus to
3 Terminal transmission line, especially when integrated with the other proposed
4 segments of Energy Gateway, is fundamental to the development of new
5 renewable and other generation sources in Utah, Idaho and Wyoming. The
6 . completion of the project will be an important step in strengthening the western
7 grid's transmission infrastructure, which is necessary based upon the projected
8 future energy service requirements of our customers including those in Idaho.
9 The project was bid out through a competitive bid process followed by
10 negotiations with the best bidders. The project is on schedule for completion and
11 to be placed into service by November 30, 2010.
12 Q.
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Does this conclude your direct testimony?
Yes.
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Case No. PAC-E-10-07
Exhibit No. 37
Witness: Darrell T. Gerrard
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Darrell T. Gerrard
Populus to Terminal Cost Summary
May 2010
Populus to Terminal Estimated Costs
Estimated Plant in Service Values at 12/31/2010
Rocky Mountain Power
Exhibit No. 37 Page 1 of 1
case No. PAC-E-10-07
'Nitness:DarrellT.Gerrard
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7 Other Related Materials
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26 Permitti
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AFUDC & Surcha
31 AFUDC
32 PacifiCo Overheads
33
37
Subtotal
Subtotal
Subtotal
Subtotal
Subtotal
Subtotal
Subtotal
Subtotal
Grand Total
$556,699,622
$26130,574
-$20,000,000
$56 830196
$27 434,638
$1,530 072
$2,488,159
$31 45 869
$3 845857
$1 560 108
$7 064245
$439 728
$1,900 000
$14 809938
$58 451 861
$11 399 772
$69 851 633
$1,470,000
$1 470000
$5,063,556
$4 247 792
$3127,448
$221 383
$1 660179
$9,171,583
$2,394,900
$512 075
$3,067,869
$7,067,511
$22,21 937
$61,475 400
$19,852 203
$81,327603
$4,914,609
$4914609
$801 530,965
Case No. PAC-E-10-07
Exhibit No. 38
Witness: Darrell T. Gerrard
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Darrell T. Gerrard
Summary of Bidder Evaluations
· May 2010
Rocky Mountain Power
Exhibit No. 38 Page 1 of 7
Case No. PAC-E-10-07
Witness: Darrell T. Gerrard
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Witness: Darrell T. Gerrard
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Exhibit No. 38 Page 3 of 7
Case No. PAC-E-10-07
Witness: Darrell T. Gerrard
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Case No. PAC-E-10-07
Witness: Darrell T. Gerrard
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Exhibit No. 38 Page 5 of 7
Case No. PAC-E-10-07
Witness: Darrell T. Gerrard
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Exhibit No. 38 Page 6 of 7
Case No. PAC-E-10-07
Witness: Darrell T. Gerrard
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Exhibit No. 38 Page 7 of 7
Case No. PAC-E-10-07
Witness: Darrell T. Gerrard
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Exhibit No. 39
Witness: Darrell T. Gerrard
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Darrell T. Gerrard
Project Photos
May 2010
-
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Exhibit No. 39 Page 3 of 9
Case No. PAC-E-10-07
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