20101014Lanspery Di.pdf

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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 BRYAN LANSPERY
IDAHO PUBLIC UTILITIES COMMISSION
OCTOBER 14, 2010
1 Q.Please state your name and address for the
2 record.
3 A.My name is Bryan Lanspery and my business address
4 is 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utilities
7 Commission as a utilities rate analyst.
8 Q.Please give a brief description of your
9 educational background and experience.
10 A.I received a Bachelor of Arts degree in Economics
11 with a social science emphasis from Boise State University
12 in 2003. I also earned a minor in Geographic Information
13 Systems from Boise State University in the same timeframe.
14 I received a Master of Arts in Economics from Washington
15 State University in 2005. My Masters work emphasized Labor
16 Economics and Quantitative Econometric Analysis.
17 Concurrent to pursuing my Masters degree, I functioned as
18 an instructor of Introductory and Intermediate Economics as
19 well as Labor Economics.
20 Q.Would you describe your duties with the
21 Commission?
22 A.I was hired by the Commission in late 2005 as a
23 utilities analyst. As such, my duties revolve around
24 statistical and technical analysis of Company filings,
25 including cost/benefit analysis, resource evaluation, price
CASE NO. PAC-E-10-0710/14/10 LASPERY, B. (Di) 1
STAFF
1 forecasting, and weather normalization methods. I have
2 participated in several general rate cases, focusing on
3 power supply, cost of service, and rate design. I have
4 also been actively engaged in integrated resource planning,
5 DSM/energy efficiency program evaluation, and revenue
6 allocation issues. I completed the Practical Skills for
7 the Electric Industry held by New Mexico State University
8 in 2006, among numerous other conferences.
9 Q.What is the purpose of your testimony?
My testimony will discuss the Company's filed net10A.
11 power supply expenses, describe why Staff believes it is
12 too high, and offer a recommendation that Staff believes
13 reasonably reflects the Company's net power costs for the
14 pro forma test year. I will also address rate design, and
15 provide recommendations that Staff believes reflect a
16 balanced approach to revenue recovery and sending
17 appropriate price signals to customers.
18 Q.Could you please summarize Staff's position
19 regarding net power supply expenses?
20 A.Yes. The Company filing indicates an increase in
21 net power costs of $87.7 million to $1.07 billion on a
22 system-wide basis since the 2008 general rate case. This
23 results in an additional $3.1 million above what is
24 currently reflected in Idaho rates. I believe a more
25 representative net power cost figure for the Company's test
CASE NO. PAC-E-10-0710/14/10 LASPERY, B. (Di) 2
STAFF
1 year is $1.03 billion, which represents an increase over
2 current base power supply expenses for Idaho customers of
4
3 $454,000 dollars.
Q.Could you please summarize Staff's position
6
5 regarding rate design?
A.Yes. Staff maintains that rate design should be
7 based on sending cost-based price signals that promote
8 efficient consumption of energy. While the Company does
9 propose a tiered rate design for residential customers as
10 directed by the Commission, I do not believe it
11 sufficiently promotes conservation and energy efficient
12 consumption. Staff proposes implementing a two-tiered
13 residential rate design with different rate blocks for both
14 summer and winter rather than year round rate blocks as
15 proposed by the Company.
16 Net Power Supply
17 Q.Have you reviewed the Company's net power supply
19
18 filing?
A.Yes, I have reviewed the Company's
20 recommendations on power supply outlined in Company witness
21 Shu's testimony, as well as the supporting exhibits and
22 documentation. I have also examined the Company's GRID
23 model, which provides the Company's calculation of net
24 power supply.
25 Q.What is Rocky Mountain Power recommending as the
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1 net power supply cost to be included in its revenue
3
2 requirement?
A.Rocky Mountain Power is recommending a net power
4 supply cost of $1.07 billion on a system basis, up from
5 $982 million included in the last general rate case. On an
6 Idaho basis, this equates to an increase from $66.1 million
8
7 to $69.2 million, or a $3.1 million increase.
Q.Do you accept the power supply costs proposed
10
9 made by the Company?
A.No, I do not. I believe the Company's
11 recommendation is too high for a number of reasons, the
12 most important being the inclusion of wind integration
14
13 costs totaling over $34 million on a system basis.
Q.Why does the Company believe wind integration
16
15 costs should be included in net power supply expenses?
A.According to Company witness Shu's testimony,
17 aside from two wind projects located in BPA's control area,
18 the wind integration charge serves as a proxy for the
19 variable costs incurred to integrate intermittent wind
20 resources into the Company's resource portfolio.
21 Q.What value does the Company use for a wind
23
22 integration cost?
A.The Company uses a value of $6.50 per MWh of wind
24 generation. This is based on the level approved by the
25 Commission in Case No. PAC-E-09-07 for setting published
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1 avoided cost rateS.
2 Q.You do not think it is reasonable for the Company
3 to include this rate in its net power cost filing?
4 A.No, I do not. The wind integration charge
5 approved by the Commission is used as an adj ustment to
6 published avoided cost for mandatory purchases from
7 qualifying wind generation facilities under PURPA.
8 approved 2 contracts for Windland.)
(Just
9 Q.Do you believe Rocky Mountain Power should
10 include the wind integration charge as a variable cost to
11 its own wind facilities and power purchase contracts?
12 A.No, i do not, for several reasons. First of all,
13 these are internal costs that are neither paid under
14 contract or to any other utility. The assumption is that
15 wind causes the power system to operate in a less than
16 optimal fashion due to its variability. That may be the
17 case, but I believe that the Company's filing already
18 reflects integration costs.
19 Q.How so?
20 A.For wind resources in service during the 2009
21 test year, wind integration costs are captured in actual
22 test year expenses. This is reflected in a number of
23 accounts, such as purchases and sales, along with fuel
24 burning expenses. These costs simply are not part of the
25 GRID modeling for the pro forma test year.
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1 Q.Do you believe that wind integration costs should
2 be included for the pro forma test year?
3 A.No. There is no basis to explicitly add these
4 costs into the rate case since estimates are neither
5 accurate nor predictable.
6 Furthermore, Rocky Mountain Power has an energy
7 cost adjustment mechanism (ECA). According to the
8 Company, the ECAM was designed to capture the volatility in
9 net power costs due to, among other things, wind
10 variabili ty (see Duval's testimony in Case No.
11 PAC-E-08-08). The actual costs of wind variability, both
12 on the Company's system and to the extent it provides sales
13 opportunities outside the system, will be captured in the
14 ECAM.
15 Q.Has the Commission granted wind integration costs
16 to any other utilities in its jurisdiction?
17 A.No. The Commission has never expressly approved
18 wind integration costs as part of base power supply expense
19 for the purposes of setting base rates in any utility's
20 general rate case.
21 Q.What is the impact to net power supply expense of
22 removing wind integration costs?
23 A.Removing all but the wind integration costs paid
24 to BPA reduces the net power supply expense by
25 approximately $34 million on a system basis.
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STAFF
1 Q.Do you have any further adjustments to the
3
2 Company's power supply filing?
A.Yes. During the course of reviewing recent rate
4 case proceedings in other jurisdictions, it became apparent
5 that there are a number of inconsistencies in the Company's
6 power supply modeling.
7
8
Q.Do you have specific examples?
A.Yes, there are three that I have incorporated
10
9 into Staff's net power cost calculation.
11
Q.What is the first?
A.The first is a pair of supplemental purchase
12 contracts that Rocky Mountain Power has in its GRID model,
13 labeled' APS Supplemental Purchase Coal' and 'APS
14 Supplemental Purchase Other'. The GRID model selects these
15 resources even though it is uneconomic to do so. It is my
16 understanding that these contracts are not considered 'must
17 take', and excluding both from the model results in a lower
19
18 net power supply.
Q.What is the reduction in net power supply
20 calculated by the GRID model if these contracts are not
21 included?
22 A.Exclusion of the contracts results in a reduction
23 of $1.9 million on a system basis. I include this
24 adjustment in Staff's net power cost recommendation.
25 Q.What is the second modeling inconsistency you
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2
1 have incorporated?
A.The second inconsistency involves the modeling of
3 non-firm transmission in GRID. As noted in recent
4 PacifiCorp rate case proceedings in other jurisdictions,
5 and confirmed in the Company's response to Monsanto Data
6 Requests 2.50 and 2.52, a level of non-firm transmission
7 contracts and Company-owned assets used by the Company to
8 optimize its system have been included as expenses in base
9 rates, yet the offsetting benefits through reduced power
10 supply costs have not been accounted for. I have adjusted
11 the GRID model to account for the average cost and capacity
12 for the transmission links included in the Company's
13 response to Monsanto Data Request 2.50. This only includes
14 non-firm transmission transactions greater than one average
16
15 MW.
Q.What is the reduction in net power supply expense
17 calculated by the GRID model if non-firm transmission
19
18 benefits are included?
A.I have calculated this to be a reduction in net
20 power supply expense of $2.5 million on a system basis. I
21 include this adjustment in Staff's net power cost
22 recommendation.
23 Q.What is the third inconsistency you have
25
24 incorporated?
A.The third inconsistency surrounds the median
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1 output of the Company's Bear River hydro generation. As
2 noted on page 10, lines 19 through 21 of Company witness
3 Shu's testimony, Rocky Mountain Power excludes high water,
4 or flood control years, in its calculation of median stream
6
5 flow for the Bear River system.
7
Q.Do you agree with this calculation?
A.No, I believe this inappropriately biases the
8 potential hydro output downward by skewing the median.
9 While the Company may think it is unlikely this will occur
10 in the future, there are no indications that severely dry
11 years, while of equally low probability, have been removed
12 as well.
13 Q.What is the impact of adjusting the Bear River
15
14 median hydro normalization?
A.The result of adjusting the Bear River median
16 hydro normalization results in a reduction of approximately
17 $2.2 million on a system basis. I include this adjustment
19
18 in Staff's net power cost recommendation.
Q.Do you have any other adjustments to the
20 Company's net power cost filing?
21
22
A.No, I do not.
Q.What is the overall impact on net power cost
24
23 based on your recommendations?
A.The sum of my four adjustments total a reduction
25 in net power cost from the Company's filing of $40.9
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1 million on a system basis. I recommend that the net power
2 cost included in base rates for Rocky Mountain Power be
3 $1.03 billion on a system basis. As reflected in Staff
4 witness Vaughn's Exhibit 108, this results in an Idaho
5 allocated net power cost of $66.6 million, or $2.6 million
6 below the Company's filing. I should note this does not
7 include the treatment of costs associated with the
8 Irrigation Load Control Program as a power purchase
9 expense, as explained in Staff witness Carlock's testimony.
10 Q.The Company has indicated that it will file a
11 revised net power cost upon rebuttal. Do you believe this
12 is appropriate?
13 A.While an argument can be made for having the most
14 recent available data included in this case, I do not agree
15 that updating the net power cost on rebuttal is
16 appropriate. The complexity and the modeling along with
17 the voluminous accompanying data make it impossible for any
18 other parties to thoroughly vet the updated power cost.
19 Rate Design
20 Q.Have you reviewed the Company's rate design
21 proposals?
22 A.Yes, I have.
23 Q.Could you please summarize the Company's
24 position?
25 A.According to Company witness Griffith's
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1 testimony, Rocky Mountain Power's proposed revenue increase
2 by class is based on the results of its class cost of
3 service model, essentially moving all rate classes to full
4 cost of service. Staff witness Hessing further discusses
5 class revenue spread required in order to achieve cost of
6 service. For large industrial customers, including special
7 contract customers, the Company proposes equal increases to
8 all billing determinants. For the remaining commercial
9 customers and irrigation class, the Company proposes a
10 slightly larger increase to demand charges than energy
11 charges based on the results of the cost of service study.
12 The same can be said for time-of -use residential customers
13 (Schedule 36), with the Company maintaining the current
14 relationships between on- and off -peak energy rates.
15 The biggest change proposed by the Company is a
16 two- tiered inverted block rate design for residential
17 Schedule 1 customers. The proposed tier break would be at
18 800 kWh both in the summer and non-summer seasons, with
19 higher comparative rates in the summer. Rocky Mountain
20 also proposes. eliminating the monthly minimum charge of
21 $10.41 and adding a monthly customer charge of $12.00.
22 Q.Do you believe it is reasonable to increase all
23 billing components on an equal percentage basis for large
24 industrial customers?
25 A.Yes, I do.
CASE NO. PAC-E-10-07
10/14/10 LASPERY, B. (Di) 11
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1
3
2 these classes?
Q.Why do you believe that is appropriate for all of
A.It has been said in countless general rate case
4 proceedings in the past, but it is true that cost of
5 service is an inexact science. While it can provide
6 guiding principles for revenue distribution between rate
7 schedules and within rate schedules, the results cannot be
8 looked upon as absolutes.
9 Also, equally spreading the revenue increases to
10 all billing determinants still provides a significant level
11 of fixed cost recovery while sending customers a strong
13
12 price signal through relatively higher energy rates.
Q.Do you support the Company's proposal to keep the
14 on- and off-peak differentials for Schedule 36 customers?
15 A.Yes, I do. Rocky Mountain Power has consistently
16 demonstrated its time-of-use rates are both aggressive and
18
17 fair.
Q.Turning to general residential rate design, what
19 do you believe constitutes effective rate design for
20 residential customers?
21 A.Effective rate design entails promoting efficient
22 consumption of energy through proper pricing. Rocky
23 Mountain Power, like most utilities in the Northwest, has
24 relatively low cost generating resources to meet its
25 average loads but relies on more expensive gas-fired
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1 resources and market purchases through much of the summer
2 and deep winter months to meet peak loads. Flat rate
3 design, in which kilowatt hour (kWh) rates are based on
4 average costs and do not vary based on timing or level of
5 consumption, do not reflect the disparity in costs to serve
6 load during peak periods and off-peak periods.
7 Effective rate design also provides customers
8 with a cost-based price signal that when consumption
9 reaches a certain threshold, or occurs in a particular time
10 period, the cost to provide that energy can be
11 significantly higher than the embedded rate, and the rate
12 charged to customers should reflect that fact. There are
13 many ways that rates can reflect the variable cost to
14 serve, but the two most prevalent ways are through tiered
15 rate design and time-of-use (TOU) rates. Rocky Mountain
16 Power has offered residential TOU rates for a number of
17 years. This filing represents its first proposal for a
18 tiered rate structure for residential customers.
19 Q.You mention that sending proper price signals is
20 an important part of effective rate design. What other
21 factors did you consider when approaching residential rate
22 design?
23 A.I alluded to the fact that prices should reflect
24 the cost to provide the energy. If this were carried to
25 the extreme, an inverted rate design, which both the
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1 Company and the Staff support, would have stark
2 differentials between the first block or tier, and the tail
3 block, in order to reflect the substantial difference
4 between the embedded cost of resources and the cost of
5 marginal resources. But the ability for customers to
6 respond must not be ignored. When promoting tiered rates,
7 one must not lose sight of general rate design principles:
8 rate equity, rate stability, and opportunity for the
10
9 utility to recover its approved costs.
Q.Do you believe the Company's proposal meets these
11 design principles?
12 A.In many respects I do, but overall I believe
13 there are some deficiencies in the filing. Rocky Mountain
14 Power has proposed that its rate differential between
15 blocks be set at 35%. I believe that this differential is
16 substantial enough for customers to receive a strong price
17 signal while still allowing them to control their bills.
18 Average customers would not see a significant change in
19 their bills under the Company's proposal, and only those
20 smallest of users and largest of users would see
22
21 significant percentage increases in their bills.
Q.Why would the smallest users receive larger
24
23 increases under the Company's proposal?
A.The large percentage increase is due to removing
25 the minimum charge currently set at $10.64, and replacing
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1 it with a $12.00 monthly customer charge. Under the
2 current structure, those using up to a little more than 100
3 kWh per month paid just the minimum. Under the Company
4 proposal, the customers would pay both the customer charge
5 and the per-kWh rate for all energy consumed.
6 Q.Do you support the removal of the minimum charge
8
7 in lieu of the monthly customer charge?
A.I do, though I believe the Company proposed
10
9 customer charge is too high.
11
Q.Please elaborate.
A.While the high customer charge does reflect the
12 third principle of cost recovery for the utility, it
13 violates the first two principles. Moving to a high fixed
14 monthly charge diminishes the price signal in the energy
15 charge to conserve electricity. It also results in a
16 nearly doubling of the monthly bill for a subset of small
17 energy consumers, violating the rate stability concept.
18 Q. What do you propose as a monthly customer charge?
19 A. I propose a $5.00 monthly charge for Schedule 1
20 customers. Based on Rocky Mountain Power's Exhibit 53,
21 this amount sufficiently covers the meter reading and
22 billing costs for the class, which has been Staff's
23 traditional basis for setting customer charges.
24
25 other electric utilities in Idaho?
Q.How does your proposed customer charge compare to
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1 A.If the Commission approved a $5.00 customer
2 charge for Rocky Mountain Power, it would rank as the
3 highest among the three investor-owned electric utilities
4 under its jurisdiction, excluding Atlanta Power.
5 Q.Returning to tiered rates, is it generally
6 regarded that this particular rate structure is an
7 effective means to promote energy efficiency?
8 A.Yes. In 2005 the National Action Plan for Energy
9 Efficiency, a public-private initiative consisting of
10 organizations such as the Department of Energy (DOE),
11 Environmental Protection Agency (EPA), and National
12 Association of Regulatory Utility Commissioners (NARUC),
13 stated that "Retail rate designs with clear and meaningful
14 price signals, coupled with good customer education, can be
15 powerful tools for encouraging energy efficiency." The DOE
16 stated more recently in a 2007 report to Congress that rate
17 design is one of 10 mechanisms for enhancing energy
18 efficiency. The 2007 Idaho Energy Plan listed adoption of
19 rate designs that encourage energy efficiency in its action
20 plan to promote conservation. In each case cited, it is
21 noted that rate design must consider the unique
23
22 characteristics of the customer class.
24
Q.Are tiered rates common in Idaho?
A.Yes. Idaho Power currently has a three-tiered
25 rate structure for residential and small commercial
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STAFF
1 customers during the summer and non- summer periods. Avista
2 also has a two-tiered rate structure for residential
3 customers in Idaho. While Rocky Mountain Power currently
4 has a flat rate structure in Idaho, it does have tiered
5 residential rate structures in several other jurisdictions.
6 Q.You mentioned that characteristics unique to the
7 customer class should be considered when designing rate
8 structures. What "unique characteristics" of the
9 residential class did you consider in your rate design?
10 A.Residential customers as a class tend to be quite
11 homogeneous when compared to small commercial and
12 irrigation customers, but more volatile when compared to
13 industrial customer classes. This can be attributed to end
14 use of electricity. Residential basic electric usage can
15 cover lighting and home appliances, such as refrigerators
16 and electric ovens. These tend to vary mainly with the
17 size and occupancy of the residence. I would suggest that
18 heating and, to a lesser degree, cooling should also be
19 considered basic end uses, as well as a point at which
20 residential customers begin to differ from one another.
21 Based on the response to Staff Production Request 192,
22 appro~imately 21% of Rocky Mountain Power's residential
23 customers use electricity for space heating purposes, while
24 others use natural gas, propane, or biofuels, such as wood-
25 fired stoves, for heating. Similarly, many homes have
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1 central cooling systems or some means of air conditioning
2 while many do not.
3 Beyond basic consumption, there is great
4 diversity in discretionary usage such as home computers and
5 home entertainment systems. Between discretionary usage
6 and weather sensitive usage, the residential customers as a
7 whole have relatively low load factors (average load
8 divided by peak load). This impacts the cost to serve
9 residential customers, along with the utility's ability to
10 recover its approved costs.
11 Q.How does this affect residential rate design?
12 A.The low load factor reflects the "peakiness" of
13 residential load profiles. Usage tends to be relatively
14 low in spring and autumn months and higher in winter and
15 summer months. In fact, for Rocky Mountain Power the
16 residential class peaks in winter with a smaller peak in
17 the summer. When designing tiered rates, it is appropriate
18 to provide price signals that reflect the dual-season
19 peaking nature of the class and reduce the class average
20 use per customer.
21 Q.Does the Company's proposal reflect the dual-
22 peaking nature of the residential class?
23 A.No, I do not believe it does. The Company
24 proposes setting the tier block break at 800 kWh year-
25 round, which is slightly below average annual residential
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1 consumption according to Company witness Griffith. When
2 looking at monthly consumption, it is evident that the
3 average is considerably higher in the winter months (949
4 kWh) and lower in the summer months (729 kWh), presumably
5 due to the prevalence of electric space heating in an area
6 of Idaho that can experience quite cold winters.
7 Q.What do you propose as an alternative?
8 A.I propose a two-tiered inverted rate structure
9 with the summer (May through October) blocks of 0-700 kWh
10 and 701 kWh and above. For the winter (November through
11 April) season, I propose setting the block break at 900
12 kWh. I agree with the Company's proposed rate differential
13 between the two blocks.
14 Q.Why do you believe this is a better design than
15 the Company's proposal?
16 A.I believe that my proposal better adheres to the
17 principles I outlined above. Reducing the monthly customer
18 charge to a more reasonable $5.00 maintains a level of rate
19 stability while covering the monthly billing and meter
20 reading costs. Setting the blocks at different seasonal
21 levels preserves the concept of cost-based price signals
22 and rate equity. While the class may be winter peaking, it
23 is small relative to the Company's system, which faces
24 higher costs to serve in the summer months. The higher
25 summer costs and lower average consumption led me to reduce
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1 the first tier block, which better reflects Company costs
2 and sends a stronger price signal to customers. Setting
3 the winter block higher than the Company's proposal may
4 lessen the price signal to a degree, but maintains the
5 block-to-average consumption relationship demonstrated in
6 the summer design and still sends a strong price signal to
7 customers, but acknowledges that the harsh winter
8 condi tions these customers face are not being ignored in
9 the process.
10 Q.In the most recent Idaho Power general rate case,
11 you strongly advocated for a three-tier residential rate
12 design. Why are you not doing so in this instance?
13 A.There are many reasons. First, for rate design
14 to have a significant impact on usage, customers must learn
15 to adapt to the price signals. Idaho Power had a two-
16 tiered residential rate in place at the time of its filing,
17 and while it may not have been the most aggressive design,
18 it was nevertheless the standard for residential customers
19 during the summer months since June of 2004. It seemed a
20 natural progression to go from a two-tiered structure to a
21 three-tiered structure in that case.
22 Rocky Mountain Power customers in Idaho have not
23 faced anything other than seasonal flat rates since the
24 1970' s, at least. The movement to a tiered rate structure
25 will have immediate positive bill impacts on some customers
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1 and negative impacts on others. I do not want to
2 overestimate the rate at which customers will be able to
3 adjust their consumption patterns to the new rate design,
4 thus jumping to a three-tiered rate seems premature at this,
5 point for Rocky Mountain Power.
6 Q.What other reasons lead you to advocate a two-
7 tiered rate over a three-tiered rate?
8 A.I do not believe that the rate design can have as
9 material an effect on Rocky Mountain's long-term resource
10 acquisition path as it could for Idaho Power. Residential
11 customers account for a significant portion of Idaho
12 Power's system demand and peak. The same cannot be said
13 for residential customers in Rocky Mountain Power's Idaho
14 service territory. The fact that this rate class
15 contributes such a small percentage to system peak and load
16 reduces the long-term benefits that may manifest through
17 tiered rates. That said, it does not diminish the argument
18 that in the short run, rates should reasonably reflect cost
19 to serve and provide price signals to customers to promote
20 conservation and efficient energy consumption.
21 As a final point, Rocky Mountain Power is much
22 less reliant on expensive peaking resources to meet its
23 demand and energy needs when compared to Idaho Power. In
24 other words, its resource mix leans more heavily on
25 baseload and intermediate resources (as well as market
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1 purchases) than Idaho Power, thus muting the immediate need
3
2 to institute a tier for the highest energy consumers.
Q.Have you incorporated the results of Staff
4 witness Hessing's cost of service and revenue spread into
6
5 your rate design?
A.Yes, I have. As described by Mr. Hessing, all
7 residential customers would receive an equal percentage
8 increase in revenue requirement. I propose increasing the
9 Schedule 36 monthly customer charge to $14.00, and
10 spreading the remaining revenue deficiency equally to the
11 energy rates. Under Staff's proposal, Schedule 1 customers
12 would have a $5.00 monthly charge and the remaining revenue
13 shortfall spread would be distributed as proposed by the
14 Company, which means some customers would see a bill
15 increase while others would see a decrease. Of the
16 remaining classes, I have spread the revenue deficiency
18
17 equally to all billing components.
20
19 increase to Schedule 1 and Schedule 36 customers?
Q.Why does Staff propose an equal percentage
A.Staff does not believe the Company has provided
21 adequate justification through cost of service to support
22 its proposed increase in residential Schedule 36
23 residential customers.
24
25
Q.Please elaborate.
A.The Company's filing demonstrates a belief that
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1 Schedule 36 will shrink compared to Schedule 1. Rocky
2 Mountain supported this notion due to recent trends in the
3 customer groups. But based on the Company response to
4 Staff Production Request 288, I do not believe the trends
5 are necessarily accurate. The Company continued the
6 downward trend in Schedule 36 customer numbers from 2009,
7 but failed to incorporate the fact that the previous three
8 year did not exhibit such a trend. Company response to
9 Staff Production Request 291 confirmed that estimates used
10 to forecast Schedule 36 energy were significantly
11 understated in relation to Schedule 1 consumption. Until
12 the Company's load research data becomes more reliable, I
13 propose that residential customers remained aggregated, as
14 it is for calculating jurisdictional load factors. The end
15 result is a uniform percentage increase for Schedule 1 and
16 Schedule 36.
17 Q.Have you prepared an exhibit demonstrating the
18 results of Staff's rate spread proposal?
19 A.Yes, I have included Staff Exhibit No. 109, which
20 shows the rate components currently in place, as proposed
21 by the Company, and Staff's proposal for each class. It
22 should be noted that Staff's energy rate for Schedule 1 is
23 higher than that proposed by the Company even with Staff's
24 lower revenue requirement. That is due to the
25 significantly lower proposed customer charge. The revenue
CASE NO. PAC-E-10-0710/14/10 LASPERY, B. (Di) 23
STAFF
1 generated by the class is equal to that submitted by Mr.
2 Hessing.
3 Q.Have you prepared an exhibit demonstrating the
5
4 impact of Staff's proposal on Schedule 1 customer bills?
A.Yes. I have updated a version of Company Exhibit
6 54, Schedule 1 with Staff's revenue requirement and rate
8
7 design proposals. It is included as Staff Exhibit No. 110.
Q.Have you prepared an exhibit demonstrating the
10
9 impact of Staff's proposal on Schedule 36 customer bills?
A.Yes. I have updated a version of Company Exhibit
11 54, Schedule 36 with Staff's revenue requirement and rate
13
12 design proposals. It is included as Staff Exhibit No. 111.
Q.Does this conclude your direct testimony in this
15
14 proceeding?
16
17
18
19
20
21
22
23
24
25
A.Yes, it does.
CASE NO. PAC-E-10-0710/14/10 LASPERY, B. (Di) 24
STAFF
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Exhibit No. 111
Case No. PAC-E-I0-07
B. Lanspery, Staff
10/14/10
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 14TH DAY OF OCTOBER 2010,
SERVED THE FOREGOING DIRECT TESTIMONY OF BRYAN LANSPERY, 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 841 1 1
(FED EX)
E-MAIL: ted.westoncmpacificorp.com
E-MAIL: ONLY
MARK C MOENCH
DANIEL E SOLANDER
ROCKY MOUNTAIN POWER
E-MAIL: mark.moenchcmpacificorp.com
daniel.solandercmpacificorp.com
RANDALL C BUDGE
RACINE OLSON NYE ET AL
PO BOX 1391
POCATELLO ID 83204-1391
(FED EX)
E-MAIL: rcbliracinelaw.net
E-MAIL: ONLY
JAMES R SMITH
MONSANTO COMPANY
E-MAIL: jim.r.smithlimonsanto.com
ANTHONY Y ANKEL
29814 LAKE ROAD
BAY VILLAGE OH 44140
(FED EX)
E-MAIL: tonyliyaneL.net
PAUL J HICKEY
HICKEY & EV ANS LLP
1800 CAREY AVE., SUITE 700
PO BOX 467
CHEYENNE WY 82003
(FED EX)
E-MAIL: phickeylihickeyevans.com
E-MAIL: ONLY
KATIE IVERSON
BRUBAKER & ASSOCIATES
E-MAIL: kiversoncmconsultbai.com
ERIC LOLSEN
RACINE OLSON NYE ET AL
PO BOX 1391
POCATELLO ID 83204-1391
(FED EX)
E-MAIL: eloliracinelaw.net
CERTIFICATE OF SERVICE
TIM BULLER
JASON HARRS
AGRIUMINC
3010 CONDA RD
SODA SPRINGS ID 83276
(FED EX)
E-MAIL: tbuller(ßagrium.com
jaharis(ßagrium.com
BENJAMIN J OTTO
IDAHO CONSERVATION LEAGUE
710 N 6TH STREET
POBOX 844
BOISE ID 83702
(HAND CARRIED)
E-MAIL: botto(ßidahoconservation.org
E-MAIL: ONLY
DR. DON READING
E-MAIL: dreading(ßmindspring.com
MELINDA J DAVISON
DAVISON VAN CLEVE, P.C.
333 SW TAYLOR, SUITE 400
PORTLAND, OR 97204
(FED EX)
E-MAIL: mjd(ßdvclaw.com
RONALD L WILLIAMS
WILLIAMS BRADBURY, P.C.
1015 W HAYS STREET
BOISE ID 83702
(HAND CARRED)
E-MAIL: ron(ßwiliamsbradbury.com
BRAD M PURDY
ATTORNEY AT LAW
2019 N 17TH STREET
BOISE ID 83702
(HAND CARRIED)
E-MAIL: bmpurdy(ßhotmail.com
JOF
SECRETÃRY~~
CERTIFICATE OF SERVICE