20101014Lobb Di.pdf

BEFORE THE
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IDAHO PUBLIC UTILITIES COMMISSIOMt
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IN THE MATTER OF THE APPLICATION OF )
PACIFICORP DBA ROCKY MOUNTAIN ) CASE NO. PAC-E-10-07
POWER FOR APPROVAL OF CHANGES )
TO ITS ELECTRIC SERVICE SCHEDULES )
)
)
)
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DIRECT TESTIMONY OF RANDY LOBB
IDAHO PUBLIC UTILITIES COMMISSION
OCTOBER 14, 2010
ALLEGEDLY PROPRIETARY DATA HAS BEEN
DELETED FROM THIS DOCUMENT
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Randy Lobb and my business address is
4 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed?
6 A.I am employed by the Idaho Public Utilities
7 Commission as Utili ties Division Administrator.
8 Q.What is your educational and professional
9 background?
10 A.I received a Bachelor of Science Degree in
11 Agricul tural Engineering from the Uni versi ty of Idaho in
12 1980 and worked for the Idaho Department of Water Resources
13 from June of 1980 to November of 1987. I received my Idaho
14 license as a registered professional Civil Engineer in 1985
15 and began work at the Idaho Public Utilities Commission in
16 December of 1987. My duties at the Commission currently
17 include case management and oversight of all technical
18 Staff assigned to Commission filings. I have conducted
19 analysis of utility rate applications, rate design,
20 proposed tariffs and customer petitions. I have testified
21 in numerous proceedings before the Commission including
22 cases dealing with rate structure, cost of service, power
23 supply, line extensions, regulatory policy and facility
24 acquisitions.
25 Q.What is the purpose of your testimony in this
CASE NO. PAC-E-10-0710/14/10 LOBB, R. (Di) 1
STAFF
1 case?
2 A.The purpose of my testimony is to summarize the
3 Staff revenue requirement recommendation, introduce Staff
4 witnesses and describe the issues that each will address.
5 I will also discuss treatment of costs associated with the
6 Irrigation Load Control program, rate base treatment of
7 investment associated with the Populus to Terminal
8 transmission line and recovery of costs associated with
9 wind resource acquisition.
10 Q.Could you please summarize your testimony?
11 A.Yes. Staff will sponsor ten witnesses in this
12 case to support its recommendation for an overall revenue
13 increase of $14.8 million or 7.3% based on an Idaho
14 jurisdictional rate base of $682.3 million. Staff proposes
15 an overall rate of return of 8.025% and a return on equity
16 of 10%.
17 I will show that the costs of the Irrigation Load
18 Control program assigned to Idaho customers is inequitable
19 when compared to the program benefits received. I will
20 show that 50% or approximately $401 million of the $802
21 million cost incurred for the Populus to Terminal
22 transmission line is not currently used and useful and
23 should be placed in plant held for future use rather than
24 included in rate base as proposed by the Company. Finally,
25 I will discuss Staff's review of the Company's wind
CASE NO. PAC-E-10-0710/14/10 LOBB, R. (Di)
STAFF
2
1 acquisition process and my recommendation to include the
2 cost in rate base as proposed by the Company.
3 Q.How is your testimony organized?
4 A.My testimony is organized as follows:
5 I. Recommendation Summary
6 II. Introduction of Staff witnesses
7 III. Case Evaluation
8 IV. The Irrigation Load Control Program
9 V. The Populus to Terminal Transmission Line
10 VI. Wind Resource Acquisition
11 Recommenda tion Sumary
12 Q.Could you please summarize Staff's
13 recommendations in this case?
14 A.Yes, Staff recommends an Idaho jurisdictional
15 revenue requirement increase of $14.8 million or 7.3% with
16 an overall rate of return of 8.025% and a return on equity
17 of 10% (Company proposed 10.6%). Staff accepts the
18 Company's proposed historic test year of January 1, 2009
19 through December 31, 2009 with reasonable proforma
20 adjustments through December 31,2010.
21 Staff rate base adjustments include placing a
22 portion of the Populus to Terminal transmission line and
23 the Dunlap I wind proj ect cost in plant held for future use
24 on the basis that the facilities are not fully used and
25 useful. Recommended expense adjustments include
CASE NO. PAC-E-10-07
10/14/10 LOBB, R. (Di)
STAFF
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1 elimination of all salary increases and bonuses for 2009
2 and 2010, reductions in pension cost, reductions in annual
3 power supply costs, removal of costs associated with wind
4 integration and a variety of other smaller adjustments.
5 Staff's recommended revenue requirement adjustments reduce
6 the Company's annual request by $12.89 million.
7 Staff accepts the Company proposed jurisdictional
8 allocation methodology with the exception of the proposed
9 treatment of Idaho Irrigation Load Control program costs.
10 Staff also accepts the Company proposed class cost of
11 service methodology. Based on the Staff revenue
12 requirement proposal, Staff recommends a class revenue
13 spread that largely follows cost of service with revenue
14 increases of 3.06% for irrigation customers, 4.78% increase
15 for residential customers and a 12.94% increase for
16 Monsanto. Staff does not separate Schedule 1 from Schedule
17 36 Residential customers for the purposes of class revenue
18 spread.
19 Staff supports the Company's proposed two tiered
20 commodity rate for Residential Schedule 1 customers but
21 proposes seasonal block sizes and a limited increase in the
22 customer charge. Staff recommends an increase in the rate
23 components of other customer classes by the percentage
24 increase in the overall class revenue requirement.
25 Staff recommends that Company DSM expenditures
CASE NO. PAC-E-10-0710/14/10 LOBB, R . (D i) 4
STAFF
1 for 2008 and 2009 be found prudent and that the Commission
2 consider a modification to the base rate/tariff rider
3 method of DSM cost recovery. Staff recommends that costs
4 associated with the Idaho Irrigation Load Control program
5 be treated as system power supply expenses instead of being
6 directly assigned to the Idaho Jurisdiction.
7 Finally, Staff recommends that the Company read
8 electrical meters and disconnect when service at a customer
9 location is discontinued to avoid the loss of revenue for
10 unbilled electrical consumption.
11 Introduction of Staff Witnesses
12 Q.Could you please describe Staff's filing in this
13 case?
14 A.Yes. Senior Staff Auditor Cecily Vaughn provides
15 the summary exhibits reflecting Staff's case. She begins
16 with actual audited PacifiCorp system data for the
17 historical 12-month test period of January 1, 2009 through
18 December 31, 2009 with known and measurable changes in and
19 adjustments to investment and expense levels through
20 December 31, 2010 (the Company case). Ms. Vaughn then
21 shows Staff adjustments and allocates the system adjusted
22 costs tò the Idaho Jurisdiction. The resulting Idaho
23 revenue requirement increase is $14.8 million or
24 approximately 7.3%.
25 The revenue requirement proposal provided in
CASE NO. PAC-E-10-0710/14/10 LOBB , R . (D i ) 5
STAFF
1 Ms. Vaughn's testimony is based on rate base adjustments,
2 expense adjustments and jurisdictional allocation
3 modifications that she recommends and that are provided to
4 her by other Staff witnesses.
5 Senior Staff Auditor Joe Leckie reviewed a broad
6 cross section of Company investments included in the test
7 year and the Company's proposed plant additions through
8 December 31, 2010. Mr. Leckie makes adjustments to
9 proforma rate base additions, removes a portion of the
10 Dunlop I wind proj ect costs that are not used and useful,
11 reduces the value of the Company's coal stockpile inventory
12 and recommends an adjustment for the Bridger #2 overhaul.
13 Mr. Leckie also makes an expense adj ustment for wind
14 proj ect O&M expenses and supports tax adj ustments proposed
15 by the Company.
16 Senior Staff Auditor Donn English addresses
17 revenue requirement adjustments for salaries, pensions,
18 property taxes and office lease expense. He recommends
19 that salaries be adjusted to January 1, 2009 levels to
20 reflect appropriate cost control measures in a weak
21 economy. He further recommends that all bonuses included
22 in revenue requirement be removed. Mr. English recommends
23 an adjustment in pension costs to reflect the appropriate
24 amortization of contributions. Finally, he recommends
25 adjustments to reflect a more appropriate accounting of
CASE NO. PAC-E-10-0710/14/10 LOBB, R. (Di)
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1 property taxes and office lease revenues.
2 Deputy Administrator and Audit Section Supervisor
3 Terri Carlock addresses cost of capital and return on
4 equity. Ms. Carlock recommends a return on equity of 10%,
5 updates the cost of debt and preferred equity, and
6 recommends an overall rate of return of 8.025%. Ms.
7 Carlock also addresses the Staff's recommended allocation
8 of the Idaho Irrigation Load Control program costs with
9 respect to the Revised Protocol jurisdictional allocation
10 methodology.
11 Senior Staff Engineer Keith Hessing addresses
12 class cost of service and revenue spread among the classes.
13 Mr. Hessing accepts the Company's class cost of service
14 methodology and recommends that all classes, except the
15 lighting classes, be moved to full cost of service as
16 proposed by the Company. Based on the Staff's recommended
17 revenue requirement, Mr. Hessing recommends class revenue
18 changes ranging from a 3.06% increase for irrigation
19 customers, to a 12.94% increase for Monsanto. Residential
20 customers will see an increase of 4.78%.
21 Staff Economist Bryan Lanspery addresses power
22 supply expense including the Company's proposed wind
23 integration adjustment and rate design. Mr. Lanspery
24 recommends that system power supply costs be reduced to
25 reflect removal of uneconomical contracts, modified
CASE NO. PAC-E-10-0710/14/10 LOBB, R . (D i)
STAFF
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1 treatment of non-firm transmission revenue and
2 recalculation of Bear River hydro generation. He also
3 recommends the Company's proposed expense addition to
4 reflect wind integration cost be removed. The basis for
5 this adjustment is his position that even if these costs
6 were known and measurable, they already flow through and
7 are recovered as part of underlying test year expenses or
S energy cost adjustment mechanisms. The total revenue
9 requirement impact of these adjustments is $2.65 million on
10 an Idaho jurisdictional basis.
11 With respect to rate design, Mr. Lanspery
12 supports the Company's proposal to implement a two tiered
13 commodity rate design for Schedule 1, residential
14 customers. Rather than the Company proposed year round
15 first block, Mr. Lanspery proposes seasonal first blocks of
16 900 kWh and 700 kWh for summer and winter , respectively.
17 Mr. Lanspery also proposes a $5 Schedule 1 customer charge
lS rather than the $12 customer charge proposed by the
19 Company. Mr. Lanspery proposes a uniform increase in the
20 rate components for all other customer classes.
21 Staff Utility Analyst Gary Grayson addresses the
22 prudency of 200S and 2009 DSM expenditures and recommends
23 that they be found to have been prudently incurred.
24 Mr. Grayson also addresses the Company's level of annual
25 DSM expenditures and discusses whether the method of cost
CASE NO. PAC-E-10-0710/14/10 LOBB, R. (Di)
STAFF
S
1 recovery through base rates or tariff rider is appropriate.
2 Finally Utilities Compliance Investigators
3 Marilyn Parker and Curtis Thaden address a variety of
4 consumer issues. Ms. Parker recommends that the Company
5 implement a policy of meter reading and disconnect when
6 customer accounts close to eliminate unbilled electrical
7 consumption. Mr. Thaden addresses the impact of the
8 economy on the customers of the Company and how customers
9 might better cope with increased utility bills.
10 Case Eval ua tion
11 Q.What has been your role in this case?
12 A.My role as Utili ties Division Administrator is to
13 oversee the preparation of the Staff case with respect to
14 identification of issues, coordination of Staff position on
15 those issues and development of Staff policy.
16 Q.What are the important policy issues in this
17 case?
18 A.In my opinion the most important policy issues
19 deal with identifying revenue requirement adjustments,
20 assuring that customer benefits properly match assigned
21 costs and customer rates are properly established.
22 Q.How did Staff take the weakened economy, the
23 impact of rate increases on the Company's customers and
24 customer comments into account in preparing for this case?
25 A.The impact of rate increases on customers is
CASE NO. PAC-E-10-0710/14/10 LOBB, R . (D i)
STAFF
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1 always a consideration of Staff in the preparation of its
2 case. The Staff obj ecti ve is to always obtain the best
3 deal possible for customers. With the weakened economy,
4 the expectation of customers and the approach of Staff is
5 to more aggressively evaluate the Company's request.
6 Staff's recommendations on equity return, elimination of
7 salary increases and bonuses and reasonably limiting cost
8 recovery of investment demonstrates this approach.
9 Q.How did Staff identify its adjustments?
10 A.Staff focused its review on cost of capital,
11 large capital additions and the level of increased
12 operation and maintenance including employee compensation
13 over the last two years. Based on an audit of actual costs
14 booked during the test year, an evaluation of expense
15 increases as compared to economic conditions and a thorough
16 review of large capital additions, Staff identified costs
17 that it believed were inappropriate.
18 Q.What policy issues fall into the category of
19 customer benefits matching assigned customer costs?
20 A.The issues that I believe fall into this category
21 are the treatment of Idaho Irrigation Load Control program
22 costs and benefits, and the determination of what is "used
23 and useful" with respect to large plant additions. Staff
24 witness Carlock and I will address the treatment of
25 Irrigation Load Control program costs and Staff witness
CASE NO. PAC-E-10-0710/14/10 LOBB, R. (Di) 10
STAFF
1 Leckie and I will address the issue of cost recovery
2 associated with the Dunlop I wind project and the Populus
3 to Terminal transmission line , respectively.
4 Q.What are the most important policy issues in this
5 case with respect to rate design?
6 A.I believe there are two important rate design
7 issues in this case. The first is revenue spread to the
8 various customer classes and the second is the tiered rate
9 design for Residential Schedule 1 customers. It is
10 important that class revenue requirement reflects class
11 cost of service and rate design reflects cost of service
12 within customer classes. With cost of service in mind and
13 in response to customer concerns, Staff maintained the
14 differential between Residential Schedule 1 and Residential
15 Schedule 36. Staff witness Hessing discusses revenue
16 spread and Staff witness Lanspery discusses rate design.
17 Idaho Irrigation Load Control Program
18 Q.Please explain the Idaho Irrigation Load Control
19 program.
20 A.The Idaho Irrigation Load Control program is
21 offered to Idaho irrigation customers receiving retail
22 electric service under Schedule 10. Participants agree to
23 allow the Company to curtail their electricity usage, and
24 in exchange participants receive credits valued on a per kW
25 basis. The Idaho Irrigation Load Control Program is
CASE NO. PAC-E-10-0710/14/10 LOBB, R. (Di) 11
STAFF
1 provided under Schedules 72 and 72A. Schedule 72 is a pre-
2 scheduled service interruption, whereas Schedule 72A is a
3 dispatchable s.ervice interruption.
4 Q.How many Schedule 10 irrigation customers
5 participate in the program?
6 A.In 2009 there were 938 customers participating in
7 the program, or nearly 46% of those eligible.
8 Q.How many Schedule 10 irrigation customers
9 participate in the dispatchable Schedule 72A option?
10 A.
11 the dispatchable option, or approximately 88% of eligible
In 2009 there were 826 customers participating in
12 participants. Most of the customers participate under
13 Schedule 72A.
14 Q.Has the Idaho Irrigation Load Control program
15 (Schedules 72 & 72A) grown?
16 A.
17 reports, the program participation has grown as follows:
Yes. According to the Company's annual DSM
18
19
20
21
Year
2006
2007
2008
2009
Participation
478
405
609
938
Annual MW
51
78
215
276
Q.How have program costs grown since the Company
22 started reporting results?
23 According to the Company's annual DSM reports,A.
24 program costs have increased as follows:
25
CASE NO. PAC-E-10-0710/14/10 LOBB, R. (Di) 12
STAFF
1
3
Year
2006
2007
2008
2009
Program Cos t
$ 1,299,129
$ 2,584,508
$ 8,908,216$11,114,948
Annual % Increase
2
99%
245%
25%
4
5 Q.Has the Company calculated the system benefit of
6 the Idaho Irrigation Load Control program?
7 A.Yes. In its 2009 DSM Report, the Company
8 calculates a system benefit value of over $20 million for
9 the Idaho Irrigation Load Control program over ten years.
10 Q.Is the Idaho Irrigation Load Control program
11 deemed to be cost effective?
12 A.Yes. According to the Company's 2009 DSM report
13 the Idaho Irrigation Load Control program meets all cost
14 effectiveness tests including the Total Resource Cost Test
15 (TRC), the Ratepayer Impact Test (RIM) and the Utility Cost
16 Test (UCT).
17 Q.How does the Company propose to treat costs and
18 benefits associated with the Idaho Irrigation Load Control
19 program?
20 A.The Company proposes to directly assign all $11.4
21 million in program cost to customers in the Idaho
22 jurisdiction. The Company then credits or decrements the
23 Idaho jurisdictional demand allocator used in the
24 allocation of system costs to Idaho. The reduced
25 jurisdictional allocat~on factor, reflecting the demand
CASE NO. PAC-E-10-0710/14/10 LOBB, R. (Di) 13
STAFF
1 reducing affect of the Idaho Irrigation Load Control
2 program, benefits Idaho customers by reducing the Idaho
3 jurisdictional revenue requirement.
4 Q.What is the revenue requirement impact of this
5 allocation methodology on Idaho?
6 A.The total proforma cost of the Irrigation Load
7 Control program directly assigned to Idaho is $11.4
8 million. These costs include $7.6 million in program
9 incentive credits paid to customers participating in the
10 Irrigation Load Control program, and $3.82 million in
11 administrative costs. The cost of the incentive payments
12 are recovered through Idaho base rates and the
13 administrative costs are recovered from Idaho customers
14 through the Customer Efficiency Service Rate Adjustment
15 (Schedule 191, tariff rider) .
16 The revenue requirement benefit to Idaho is
17 captured by reducing Idaho's jurisdictional allocation of
18 PacifiCorp system costs. This is accomplished by reducing
19 Idaho's share of system demand to reflect the impact on
20 system demand of the Idaho Irrigation Load Control program.
21 When this demand decrement is applied, Idaho's
22 jurisdictionally allocated revenue requirement is reduced
23 by approximately $7.48 million. The net effect is that
24 directly assigned Idaho program costs of $11.4 million
25 exceed allocated Idaho revenue reqUirement benefits of
CASE NO. PAC-E-10-0710/14/10 LOBB, R. (Di) 14
STAFF
1 $7.48 million by approximately $3.9 million a year.
2 Q.Is this reasonable?
3 A.No. Idaho receives a reduction of system costs
4 that equate to a program benefit of approximately 66% ($7.5
5 million/$ll. 4 million) of the costs. This is unfair when
6 100% of the program costs are directly assigned to Idaho.
7 Q.Does the Company assign any program costs to the
8 system to reflect benefits derived to the system from the
9 Irrigation Load Control program?
10 A.No program costs are directly allocated to the
11 system or other jurisdictions under the Company method.
12 Through the decrement in the demand allocator used to
13 jurisdictionally allocate system costs, other PacifiCorp
14 jurisdictions do receive $7.48 million more in other system
15 costs due to the shift in load responsibility. This amount
16 represents about 66% of total Idaho Irrigation Load Control
17 program costs.
18 However, all other PacifiCorp system production
19 costs and thereby production costs avoided by implementing
20 the Idaho Irrigation Load Control Program are normally
21 allocated to jurisdictions other than Idaho at the rate of
22 approximately 94%. Consequently, non Idaho jurisdictions
23 are receiving 94% of the program benefits but only pick up
24 additional system costs equal to 66% of the program costs.
25 Q.How do you propose to treat the Idaho Irrigation
CASE NO. PAC-E-10-0710/14/10
LOBB, R. (Di) 15
STAFF
1 Load Control program costs?
2 A.I propose that the Company treat the program
3 costs as system purchase power cost and allocate them just
4 as it would any other system power supply expense. This
5 will assure that the costs allocated to each jurisdiction
6 follow the benefits received by each jurisdiction.
7 Q.How does the Company view the capacity provided
S from the Idaho Irrigation Load Control program in
9 comparison to existing supply side resources?
10 A.The Company identifies the Idaho Irrigation Load
11 Control program as a Class 1 DSM resource defined as
12 follows:
13 Class 1 DSM: Resources from fully dispatchable orscheduled firm capacity product offerings/programs -14 Class 1 programs are those for which capacity savings
occur as a result of active Company control or
15 advanced scheduling. Once customers agree to
participate in a Class 1 DSM program, the timing and16 persistence of the load reduction is involuntary on
their part within the agreed limits and parameters of17 the program. In most cases, loads are shifted rather
than avoided.
lS
19 The Company goes on to identify Class 1 DSM as a
20 resource type with its other supply side resources in
21 Table 5.6 - Capacity Ratings of Existing Resources, as part
22 of its 200S IRP.
23 Q.What is the revenue requirement effect of
24 treating Idaho Irrigation Load Control program costs as a
25
CASE NO. PAC-E-10-0710/14/10 LOBB, R. (Di) 16
STAFF
1 system power supply expense in jurisdictional cost
2 allocation?
3 A.Idaho's net revenue requirement would be reduced
4 by approximately $3.25 million when Idaho Irrigation Load
5 Control program costs previously collected through the
6 tariff rider are included. The reduction in revenue
7 requirement collected from Idaho would be collected from
8 PacifiCorp's other jurisdictions through the dynamic system
9 cost allocation of additional system power supply expenses
10 under the Staff's proposal. This proposed distribution of
11 Class 1 Irrigation Load Control program costs more
12 accurately and fairly matches system benefits with system
13 costs.
14 Q.Does your recommended treatment of the Irrigation
15 Load Control program costs violate the Revised Protocol
16 jurisdictional allocation methodology?
17 A.I do not believe treating these Idaho Irrigation
18 Load Control Class 1 DSM expenditures as system production
19 costs violates the intent of the jurisdictional allocation
20 methodology. The Company views this program as comparable
21 to production resources in its IRP and the size of this
22 program has grown by 300% since Revised Protocol was
23 approved. Moreover, I believe that the magnitude of the
24 program costs relative to the size of the Idaho
25 jurisdiction makes situs cost recovery difficult when
CASE NO. PAC-E-10-07
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LOBB , R . (D i ) 1 7
STAFF
1 benefits are based on reduced allocation of unrelated
2 system costs. Staff witness Carlock provides additional
3 testimony regarding treatment of Idaho Irrigation Load
4 Control program costs in conjunction with the Revised
5 Protocol Allocation methodology.
6 Populus to Ter.inal Transmission
7 Q.What is the Populus to Terminal Transmission
S line?
9 A.The Populus to Terminal transmission line is the
10 first of eight proposed new high voltage transmission
11 segments that will make up PacifiCorp's Energy Gateway
12 Transmission Expansion proj ect. Energy Gateway consists of
13 Gateway West, Gateway South and Gateway Central. Populus
14 to Terminal is one of three segments that make up Gateway
15 Central. It is a dual circuit 345 kV, 135 mile long high
16 voltage transmission line stretching from Downey, Idaho to
17 Salt Lake City, Utah.
lS Q.What is the cost of the Populus to Terminal
19 project and how does it compare to the overall estimated
20 cost of Energy Gateway and the transmission plant in
21 service of PacifiCorp?
22 A.The total cost of the 135 mile Populus to
23 Terminal project is $S02 million. In 200S, the 1700 mile
24 Energy Gateway project was estimated at over $4 billion.
25 In 2010, Energy Gateway is described as a 2000 mile long
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STAFF
1 proj ect at an estimated cost of approximately $6.6 billion.
2 PacifiCorp currently has only $2.2 billion in transmission
3 plant in service.
4 Q.What does the Company request in terms of cost
5 recovery for Populus to Terminal in this case?
6 A.The Company requests that the entire cost of the
7 Populus to Terminal project, or approximately $S02 million,
S be placed in rate base as part of this case.
9 Q.How does the Company justify construction of the
10 Populus to Terminal transmission line and including all of
11 the project cost in rate base in this case?
12 A.The Company describes the Populus to Terminal
13 transmission segment as a "key element in Gateway Central",
14 which is described as an "essential reliability backbone
15 allowing Gateway West and Gateway South to operate at a
16 higher reliability and an overall higher capacity". The
17 Company maintains that the Energy Gateway investment will
lS support future generation resource development. Cupparo
19 Di., p. 7, line S
20 Q. What is the Company's estimated time frame for
21 completion of the Energy Gateway Transmission expansion
22 project?
23 A.The original estimate in February of 200S was for
24 completion of Gateway South in 2013 and Gateway West in
25 2014. 2010 estimates now show completion of Gateway South
CASE NO. PAC-E-10-0710/14/10 LOBB, R. (Di) 19
STAFF
1 in the 2018 to 2020 time frame and Gateway West in the 2014
2 to 2018 time frame.
3 Q.Does the Company provide other justification for
4 its proposed treatment of the Populus to Terminal
5 transmission costs?
6 A.Yes. The Company maintains that the proj ect
7 satisfies a Mid American Energy Holdings Company (MEHC)
8 merger commitment to improve the transfer capability over
9 Path C. The Company also maintains that overall
10 reliability is improved and the Company can cover reserve
11 requirements without building new generation.
12 Q.What was the commitment by pacifiCorp to improve
13 transfer capability over Path C as part of the MEHC merger?
14 The Path C upgrade commitment as stated inA.
15 Commission Order No. 29998 (Case No. PAC-E-05-08) issued in
16 March of 2006 was as follows:
17 Path C Upgrade (-$78 million) - Increase Path CCapacity by 300 MW (from S.E. Idaho to Northern Utah) .
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The target completion date is 2010.· Enhances reliability because it increases
transfer capability between the east and westcontrol areas,
· facilitates the delivery of power from windproj ects in Idaho, and
. provides PacifiCorp with greater flexibility and
the opportunity to consider additional optionsregarding planned generation capacity additions.
Q. As constructed, does the Populus to Terminal
Transmission line simply fulfill the Path C Commitment?
A.No. The Populus to Terminal proj ect was
CASE NO. PAC-E-10-0710/14/10 LOBB, R . (D i) 20
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1 oversized to satisfy the future requirements of the Energy
2 Gateway Transmission Expansion proj ect. Rather than the
3 300 MW specified in the MEHC merger commitment, the Populus
4 to Terminal project provides 700 MW of immediate additional
5 capacity and 1400 MW of additional future capacity. Rather
6 than $78 million, the project actually cost $802 million or
7 over ten times the estimated cost identified in the MEHC
8 merger commitment.
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6 Q.What is your recommendation in this case for
7 treating the costs of the Populus to Terminal transmission
S line?
9 A.As Staff stated in its comments filed in
10 Certificate Case No. PAC-E- OS - 03, "the actual costs subj ect
11 to recovery from Idaho ratepayers (related to the Populus
12 to Terminal 345 kV transmission line proj ectJ will not be
13 determined until the proj ect is completed, costs are fully
14 known and project usefulness is fully quantified." I
15 recommend that 50% or approximately $401 million of the
16 investment in the Populus to Terminal transmission line be
17 allowed in rate base as part of this case and 50% or the
lS remaining $401 million be classified as capacity not yet
19 "used and useful" and placed in plant held for future use.
20 This recommendation is justified based on the undisputed
21 fact that the proj ect is oversized and will not be fully
22 utilized unless or until Energy Gateway is completed.
23 Given the changing economic conditions and the planned
24 delays in completion dates of future Energy Gateway
25 segments, it is unclear and speculative when or if the full
CASE NO. PAC-E-10-0710/14/10 LOBB, R. (Di) 27
STAFF
1 benefits of the Populus to Terminal investment will accrue
2 to Idaho customers.
3 The 50% distribution between rate base and plant
4 held for future use was determined based on a usable
5 capacity of 700 MW out of a total design capacity of 1400
6 MW. Additional justification for the distribution includes
7 a cost per mile that is twice that of the remaining Energy
8 Gateway segments and a standalone economic analysis that I
9 believe over estimates the cost of transmission
10 alternatives. The rate base and revenue requirement impact
11 of this adjustment is presented in the testimony of Staff
12 wi tness Vaughn.
13 Q.Could you please summarize your testimony on
14 Populus to Terminal cost recovery?
15 A.Yes. The Company has made it clear through the
16 testimony of Mr. Cupparo and Mr. Gerrard and responses to
17 numerous production requests that Populus to Terminal was
18 constructed in large part to provide the potential future
19 benefits that only completion of Energy Gateway can
20 ultimately ensure. The capacity oversizing of Populus to
21 Terminal is designed for future use and that oversized
22 portion of the Company's investment is not presently "used
23 and useful". Under Idaho Code § 61-502A, rate basing of
24 investment that is not presently "used and useful" in
25 providing utility service is prohibited. While some of the
CASE NO. PAC-E- 10 - 0710/14/10 LOBB, R. (Di) 28
STAFF
1 project costs are justified by benefits customers receive
2 today, 50% of the costs incurred do not generate current
3 benefits. It is unfair and inappropriate for current Idaho
4 customers to pay today for benefits that may only become
5 available when Energy Gateway is completed and Populus to
6 Terminal is fully utilized. Therefore, approximately $401
7 million of the Populus to Terminal project costs should be
8 placed in an account containing plant held for future use,
9 Account No. ios.
10 Wind Resource Acquisition
11 Q.Has Staff reviewed PacifiCorp i s acquisition of
12 new wind resources for which it requests cost recovery in
13 this general rate case?
14 A.Yes, under my direction, Staff reviewed four
15 separate wind acquisition processes. First, Staff reviewed
16 acquisition of the Seven Mile Hill, Glenrock, Rolling
17 Hills, Seven Mile Hill II, Glenrock III, High Plains and
18 McFadden Ridge I proj ects. Together, these resources
19 provide a nameplate capacity of approximately 483 MW, and
20 represent an investment by PacifiCorp of $1.04 billion.
21 Acquisition of these resources is consistent with the
22 Company's 2004, 2007, and 2008 Integrated Resource Plans
23 (IRPs). Staff reviewed the economic analysis conducted by
24 the Company for each of these resources and concluded that
25 each is cost effective and was prudently acquired.
CASE NO. PAC-E-10-0710/14/10 LOBB, R. (Di) 29
STAFF
1 Next, Staff reviewed the Company 1 s resource
2 acquisitions in the 2008R, 2008R-1, and 2009R Request for
3 Proposal (RFP) process. In the 2008R RFP, PacifiCorp
4 signed a 20-year power purchase agreement (PPA) for the
5 energy and renewable energy credits (RECs) from the 99 MW
6 Three Buttes project. In the 2008R-1 RFP, a 20-year PPA
7 was negotiated for energy and RECs from the 200 MW Top of
8 the World project, and in the 2009R RFP the 111 MW Dunlap I
9 proj ect, a $261 million Company-owned benchmark proj ect,
10 was selected. Staff carefully reviewed all price and non-
11 price analysis conducted by the Company in each RFP
12 process, including a detailed review of the modeling used
13 to evaluate and score all of the short-listed bids
14 submitted under each RFP. In addition to the Company 1 sown
15 analysis, Staff also reviewed all reports prepared by
16 independent evaluators hired to monitor and evaluate the
17 2008R-1 and 2009 RFP processes. In each of those RFP
18 processes, the independent evaluators concluded that the
19 selected proposals represented the resources with the
20 greatest net benefits to customers; that the processes were
21 fair and competi ti ve; that the selected proposals
22 represented the lowest cost al ternati ves for customers,
23 wi th an accounting for risk.
24 Q.What do you conclude based on Staff i s review of
25 the wind projects?
CASE NO. PAC-E-10-0710/14/10 LOBB, R. (Di) 30
STAFF
1 A.Based on Staff 1 s review, I conclude that all of
2 the new wind resources acquired by PacifiCorp, both those
3 that are Company-owned and those for which the output is
4 purchased under PPAs, were competitively acquired, are
5 consistent with Company IRPs, and are prudent. Costs for
6 acquisi tion of each Company-owned proj ect should be allowed
7 to be included in rate base, and costs associated with each
8 of the PPAs should be included in the Company's revenue
9 requirement.
10 Q.Does this conclude your direct testimony in this
11 proceeding?
12
13
14
15
16
17
18
19
20
21
22
23
24
25
A.Yes, it does.
CASE NO. PAC-E-10-0710/14/10 LOBB , R . (D i ) 3 1
STAFF
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 14TH DAY OF OCTOBER 2010,
SERVED THE FOREGOING NON-CONFIDENTIAL DIRECT TESTIMONY OF
RANDY LODD, IN CASE NO. PAC-E-1O-07, BY MAILING A COPY THEREOF,
POSTAGE PREPAID, TO THE FOLLOWING:
TED WESTON
ID REGULATORY AFFAIRS MANAGER
ROCKY MOUNTAIN POWER
201 S MAIN ST STE 2300
SALT LAKE CITY UT 84111
(FED EX)
E-MAIL: ted.westonCipacificorp.com
E-MAIL: ONLY
MARK C MOENCH
DANIEL E SOLANDER
ROCKY MOUNTAIN POWER
E-MAIL: mark.moenchCipacificorp.com
danieLsolanderCipacificorp .com
RANDALL C BUDGE
RACINE OLSON NYE ET AL
PO BOX 1391
POCATELLO ID 83204-1391
(FED EX)
E-MAIL: rcbCiracinelaw.net
E-MAIL: ONLY
JAMES R SMITH
MONSANTO COMPANY
E-MAIL: jim.r.smithCimonsanto.com
ANTHONY Y ANKEL
29814 LAKE ROAD
BAY VILLAGE OH 44140
(FED EX)
E-MAIL: tonyCiyanel.net
PAUL J HICKEY
HICKEY & EVANS LLP
1800 CAREY AVE., SUITE 700
PO BOX 467
CHEYENNE WY 82003
(FED EX)
E-MAIL: phickeyCihickeyevans.com
E-MAIL: ONLY
KATIE IVERSON
BRUBAKER & ASSOCIATES
E-MAIL: kiversonCiconsultbai.com
ERIC L OLSEN
RACINE OLSON NYE ET AL
PO BOX 1391
POCATELLO ID 83204-1391
(FED EX)
E-MAIL: eloCiracinelaw.net
CERTIFICATE OF SERVICE
TIM BULLER
JASON HARRS
AGRIUMINC
3010 CONDA RD
SODA SPRINGS ID 83276
(FED EX)
E-MAIL: tbullerCiagrium.com
jaharisCiagrium.com
BENJAMIN J OTTO
IDAHO CONSERVATION LEAGUE
710 N 6TH STREET
POBOX 844
BOISE ID 83702
(HAND CARRED)
E-MAIL: bottoCiidahoconservation.org
E-MAIL: ONLY
DR. DON READING
E-MAIL: dreadingCimindspring.com
MELINDA J DAVISON
DAVISON VAN CLEVE, P.C.
333 SW TAYLOR, SUITE 400
PORTLAND, OR 97204
(FED EX)
E-MAIL: mjdCidvclaw.com
RONALD L WILLIAMS
WILLIAMS BRADBURY, P.C.
1015 W HAYS STREET
BOISE ID 83702
(HAND CARRIED)
E-MAIL: ron($wiliamsbradbury.com
BRAD M PURDY
ATTORNEY AT LAW
2019 N 17TH STREET
BOISE ID 83702
(HAND CARRIED)
E-MAIL: bmpurdy($hotmaiLcom
\~:b.\(~-
SECRETARY
CERTIFICATE OF SERVICE