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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
)
)
) CASE NO. IPC-E-08-10
)
)
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES
AN CHAGES FOR ELECTRIC SERVICE.
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
DARLENE NEMNICH
1 Q.Please state your name and business address.
2 A.My name is Darlene Nemnich. My business
3 address is 1221 West Idaho Street, Boise, Idaho.
4 Q.By whom are you employed and in what
5 capacity?
6 A.I am employed by Idaho Power Company as a
7 Senior Pricing Analyst.
8 Q.Please describe your educational background.
9 A.In May of 1979, I received a Bachelor of
10 Arts degree in Business Administration with emphases in
11 Finance and Economics from the College of Idaho in
12 Caldwell, Idaho.
13 Q.Please describe your business experience
14 wi th Idaho Power Company.
15 A.In 1982, I was hired as an analyst in the
16 Resource Planning Department. My primary duties were the
17 calculation of avoided costs for cogeneration and small
18 power production contracts and the calculation of costs of
19 future generation resource options. In 1989, I moved to
20 the Energy Services Department where I performed economic,
21 financial and statistical analyses to determine the cost
22 effectiveness of. demand-side management programs. I stayed
23 in that general area, designing, implementing and
24 evaluating programs until 2000, when I was promoted to
NEMNICH, DI 1
Idaho Power Company
1 Energy Efficiency Coordinator. In that capacity, I
2 coordinated the Company's effort to grow customer programs
3 and education in energy efficiency promotion. I was
4 responsible for complying with regulatory and financial
5 requirements in the area of energy efficiency. In 2003, I
6 was promoted to Energy Efficiency Leader where I managed
7 the Company's demand-side management effort, including
8 strategic planning, design and development of programs,
9 regulatory compliance, and overall management of the
10 department. In 2006, I left the Company to pursue personal
11 opportunities. In April 2008, I returned to the Company as
12 a Senior Pricing Analyst in the Pricing and Regulatory
13 Services Department. My duties as Senior Pricing Analyst
14 include the development of alternative pricing structures,
15 analysis of the impact on customers of rate design changes,
16 and the administration of the Company's tariffs.
17 Q.What is the scope of your testimony in this
18 proceeding?
19 A.My testimony will address the Company's rate
20 design proposal for commercial and industrial customers
21 taking service under Schedules 7, Small General Service;
22 Schedule 9, Large General Service; and Schedule 19, Large
23 Power Service, as well as the Special Contract customers.
24 i will also address the rate structure for Schedule 45,
NEMNICH, DI 2
Idaho Power Company
1 Standby Service, and Schedule 46, Alternate Distribution
2 Service.
3 Q.How did you arrive at the proposed rate
4 design presented in this case?
5 A.The design of this rate proposal was
6 accomplished through analysis and input from the Pricing
7 and Regulatory Services Department and consultation with
8 Ms. Brilz, the Company's former Director of Pricing, Mr.
9 Gale, the Company's Vice President of Regulatory Affairs,
10 and the Company's legal staff. For changes to specific
11 schedules, I also consulted with teams from many different
12 departments within the Company, including Load Research,
13 Customer Billing Support, Data Warehouse Management,
14 Customer Relations and Energy Efficiency, and Customer
15 Service. In addition, I gathered customer input on
16 proposed rate design changes during a meeting held on May
17 8, 2008, that included several of the Company's Large
18 General Service customers. A summary of this meeting is
19 included later in my testimony.
20 Q.What are your overall objectives in arriving
21 at the proposed rate designs for the Company's various
22 service schedules?
23 A.As indicated in Mr. Gale's testimony, the
24 Company's primary objective is to establish prices which
NEMNICH, DI 3
Idaho Power Company
1 primarily reflect the costs of services provided. As part
2 of the Company's last several general rate cases, the
3 Company has continually moved to meet this primary
4 objective by emphasizing increases in the demand and
5 customer components and the inclusion of fewer non-energy-
6 related costs in the energy charges.
7 The second obj ecti ve is to provide customers with
8 cost-based price signals which encourage the wise and
9 efficient use of energy. This gives customers the
10 opportunity to manage their bills by conserving energy or
11 shifting usage to less expensive time periods. In
12 addition, consistency and stability in the structure of the
13 rate design is maintained in order to ameliorate problems
14 for customers who move from one rate schedule to another.
15 Q.Are you emphasizing increases in the demand
16 and customer components in this case?
17 A.Yes I am. However, with the movement made
18 in the past several rate cases in setting rates closer to
19 costs, the magnitude of the proposed increases to the
20 demand components in most cases is less than in previous
21 proceedings.
22 Q.What are the major changes to the current
23 rate design you are proposing?
NEMNICH, DI 4
Idaho Power Company
1 A.In addition to modifying the rate levels to
2 reflect the new revenue requirement, I am proposing three
3 rate design changes. First, for Schedule 7, Small General
4 Service, I am proposing to add a block rate on the energy
5 charge during the non-summer time period. This block rate
6 will mirror the existing summer block rate and provide a
7 conservation incentive for customers using more than 300
8 kWh during non-summer months. Second, in order to provide
9 clear price signals and provide opportunities for customers
10 to manage their electricity bills, I am proposing time-of-
11 use rates for customers taking service under Schedule 9,
12 Large General Service, at the Primary and Transmission
13 levels. And third, for Schedule 19, Large Power Service, I
14 am proposing to increase the differentials between the On-
15 Peak, Mid-Peak and Off-Peak Energy Charges during the
16 summer and non-summer seasons. This will provide an
17 increased incentive for customers to reduce or shift load
18 during the summer months, the Company's most expensive time
19 to provide power.
20 Q.Have you prepared any exhibits relating to
21 your rate design testimony?
NEMNICH, DI 5
Idaho Power Company
1 A.Yes. I am sponsoring the following exhibits
2 relating to rate design:
3 Exhibit Description
4 Exhibit No.74 Calculation of Proposed Rates
5 Exhibit No.75 Typical Monthly Billing Comparisons and
6 Billing Impacts of Proposed Rates
7 Q.Please describe Exhibit No.74.
8 A.Exhibit No.74 indicates the rate
9 calculations made, by billing component, for Service
10 Schedules 7, 9, 19, and Special Contracts.
11 Q.Please describe Exhibit No. 75.
12 A.Exhibi t No. 75 shows the impact on
13 customers' bills of the proposed rate designs for Schedules
14 7, 9, and 19.
15 Q.How have you organized the discussion of
16 your rate design proposals?
17 A.My testimony will address rate design
18 proposals for Schedules 7, 9, 19, the Special Contracts,
19 and for Standby and Alternate Distribution Services, in
20 that order.
21 SMAL GENERA SERVICE, SCHEDULE 7
22 Q.What is the present rate structure for Small
23 General Service under Schedule 7?
NEMNICH, DI 6
Idaho Power Company
1 A.As Mr. Gale stated in his testimony, the
2 rates I will describe as the present rate structure are the
3 rates filed in Case No. IPC-E-08-01 related to the Danskin
4 Combustion Turbine. The actual rates approved by the
5 Commissíon in Case No. IPC-E-08-01 (Order No. 30559) vary
6 slightly from those originally filed. In order No. 30559,
7 the Commission excluded a relatively small part of the
8 investment from inclusion in rates ($422,000). The Company
9 has not included this small impact in the General Rate Case
10 filing because of the time impact associated with
11 reprocessing all the analyses and studies. Since the
12 impact of not making the change is to slightly overstate
13 revenues, any disadvantage accrues to the Company's case.
14 Schedule 7 is available to Customers whose metered
15 energy usage is 2,000 kWh or less, per billing period for
16 ten or more billing periods during the most recent 12
17 billing periods. Customers taking service under Schedule 7
18 pay a Service Charge of $4.00 per month. During the summer
19 months they pay an Energy Charge of 7.02809 per kWh for the
20 first 300 kWh used and 7.91589 per kWh for all usage over
21 300 kWh. During the non-summer months of September through
22 May, they pay 7.02809 per kWh for all kWh used. Demand is
23 not billed for Schedule 7 customers.
NEMNICH, DI 7
Idaho Power Company
1 Q.Please describe the rate design proposal for
2 Schedule 7.
3 A.I am proposing to add an inverted block rate
4 during the non-summer months for Schedule 7. This block
5 rate is set at 300 kWh, which is the same level as the
6 existing summer block rate on this Schedule.
7 Q Why did you determine that 300 kWh is the
8 appropriate level for the non-summer first block?
9 A.The existing first block in the summer
10 season is currently set at 300 kWh. For Schedule 7
11 customers, approximately 40 percent of energy consumed
12 during summer months is in the first block, and, similarly,
13 39.0 percent of the energy consumed during the non-summer
14 months is in the first block. A first block higher than
15 300 kWh is not recommended because the average monthly kWh
16 for customers in this schedule is just over 500 kWh.
17 Q.Why is the Company proposing to add a block
18 rate in the non-summer months?
19 A.By setting a block rate in non-summer
20 months, the Company gives a price signal to encourage
21 customers to use electricity efficiently and wisely.
22 Customers who work towards reducing their monthly kWh usage
23 can expect a larger reduction on their bill when they
24 conserve with this block rate than if they had a flat rate.
NEMNICH, DI 8
Idaho Power Company
1 Q.What are the proposed Energy Charges and
2 Service Charge?
3 A.The Energy Charge for both summer and non-
4 summer first block rates is 7.40059 per kWh. The Energy
5 Charge for the summer second block is 8.80969 per kWh and
6 the Energy Charge for the non-summer second block is
7 7.82179 per kWh. In addition, the Company is proposing to
8 increase the Service Charge from $4.00 to $5.00 per month.
9 The rate design proposal for Schedule 7 is included on page
10 one of Exhibit No. 74.
11 Q.Please describe the proposed changes to the
12 Energy Charges for the first and second blocks.
13 A. To provide rate stability for lower use
14 customers, the Energy Charges for both first blocks in the
15 summer and non-summer seasons are equal. I maintained the
16 current differential between the summer and non-summer
17 Energy Charge for the second blocks. The Energy Rates for
18 the first blocks were increased by 5.3 percent over current
19 rates. The Energy Rates for the second blocks for both the
20 summer and non-summer months were both increased by 11.29
21 percent over current rates. In light of the overall
22 revenue requirement increase of 10.63 percent for Schedule
23 7, this rate design gives a stronger price signal in the
24 summer than non-summer months and a stronger price signal
NEMNICH, DI 9
Idaho Power Company
1 for usage over 300 kWh per month.
2 Q.What is the revenue requirement to be
3 recovered from Small General Service customers taking
4 service under Schedule 7?
5 A.The annual revenue requirement for Schedule
6 7 customers as shown on page 4 of Mr. Tatum's Exhibit No.
7 70 is $16,772,713.
8 Q.What is the impact of this proposed rate
9 design on Small General Service customers?
10 A.Page 1 of Exhibit No. 75 shows the billing
11 comparison between the Schedule 7 existing rates and
12 proposed rates for typical billing levels. This exhibit
13 shows the impact of the added non-summer block rate.
14 LAGE GENERA SERVICE, SCHEDUL 9
15 Q.What is the present overall rate structure
16 for Schedule 9?
17 A.Service under Schedule 9 may be taken at
18 Secondary, Primary, or Transmission Service level. This
19 Schedule is applicable to customers whose metered energy
20 usage exceeds 2,000 kWh per billing period for a minimum of
21 three billing periods during the most recent 12 consecutive
22 billing periods and whose metered demand per billing period
23 has not equaled or exceeded 1,000 kW more than twice during
24 the most recent 12 consecutive billing periods. Idaho
NEMNICH, DI 10
Idaho Power Company
1 Power has 144 customers who take service at Primary Service
2 level, two customers who take service at Transmission
3 Service level, and 26,702 customers who take service at
4 Secondary Service level. All customers taking service
5 under Schedule 9 pay a Service Charge, a Basic Charge, and
6 both summer and non-summer Energy and Demand Charges.
7 Customers taking Primary or Transmission service may also
8 pay a Facilities Charge.
9 LAGE GENERA SERVICE, SCHEDUL 9 - SECONDARY
10 Q.What is the present rate structure for
11 Schedule 9 Secondary Service?
12 A.The current rate structure for Schedule 9
13 Secondary Service includes a two-tier declining block
14 Energy Charge along with a block Demand Charge and a block
15 Basic Charge. Under this rate structure, the first block
16 Energy Charge applies to the first 2,000 kWh of usage and
17 the second block Energy Charge applies to all usage greater
18 than 2,000 kWh. In addition, there is no charge for the
19 first 20 kW of Billing Demand or the first 20 kW of Basic
20 Load Capacity.
21 Q.What is the reason that Schedule 9 Secondary
22 Service has this block design in place?
23 A.The current block rate design structure for
24 Schedule 9 Secondary Service was put in place to remedy a
NEMNICH, DI 11
Idaho Power Company
1 pricing disparity that occurred when customers transitioned
2 between Schedule 7 and Schedule 9 at the Secondary level.
3 Before this block structure was put in place, many of the
4 customers moving from Schedule 9 to Schedule 7 would see an
5 increase in their monthly bill of more than 100 percent.
6 This disparity provided an incentive to artificially
7 increase their usage to remain on Schedule 9, even when
8 they qualified for Schedule 7. The block rate structure in
9 place for Schedule 9 Secondary Service provides a similar
10 rate level and a smooth transition to customers moving from
11 Schedule 7 to Schedule 9 Secondary Service level.
12 Q.Please describe the rate design proposal for
13 Schedule 9 Secondary Service level.
14 A.The rate design proposal for Schedule 9
15 Secondary Service level is included on page two of Exhibit
16 No. 74. I am proposing the Service Charge be increased
17 from $12.50 to $15.00 per month. I am also proposing the
18 Basic Charge be increased from $0.67 to $0.80 per kW, the
19 summer Demand Charge be increased from $3.85 to $4.80 per
20 kW, and the non-summer Demand Charge be increased from
21 $3.19 to $3.85 per kW. The current summer Energy Charge of
22 7.30189 for the first 2,000 kWh and the current summer
23 Energy Charge of 3.12859 per kWh for all other usage are
24 increased to 7.99769 and 3.42669 per kWh, respectively.
NEMNICH, DI 12
Idaho Power Company
1 The non-summer Energy Charge of 6.51439 for the first 2,000
2 kWh and of 2.79059 per kWh for all other usage are
3 increased to 7.13519 and 3.05659 per kWh, respectively.
4 Q.How did you arrive at these proposed
5 charges?
6 A.For all rate components, I am proposing
7 rates that represent a uniform seven percent movement
8 towards the costs to serve that rate component. The costs
9 to serve each rate component are indicated on page three of
10 Mr. Tatum's Exhibit No. 67. To calculate each rate
11 component amount, I first considered the percentage of
12 overall revenue requirement identified by demand, energy,
13 basic, and customer components for Schedule 9 Secondary
14 Service level resulting from the Company's preferred class
15 cost-of-service study. These percentages established the
16 target revenue requirement for each component. Second, I
17 determined the percentage of overall revenue recovered by
18 component which is currently provided by the existing base
19 rates. The difference, or gap, between the target and the
20 actual percentage was then determined for each component.
21 I then adjusted the current percentage of overall revenue
22 by component by approximately seven percent of the gap to
23 establish my targets for this proceeding. Customer,
24 demand, basic, and energy related charges were then
NEMNICH, DI 13
Idaho Power Company
1 established to achieve these new targets.
2 Q.What is the revenue requirement to be
3 recovered from Large General Service customers taking
4 service under Schedule 9 Secondary Service level?
5 A.The annual revenue requirement for all
6 Schedule 9 customers, as shown on page 4 of Mr. Tatum's
7 Exhibit No. 70, is $175,488,062. Of this amount, the
8 target revenue requirement for Schedule 9 Secondary Service
9 is $158,806,499.
10 Q.What is the impact of this rate design on
11 Schedule 9 Secondary Service level customers?
12 A.Pages two and three of Exhibit No. 75 show
13 the billing comparison between the Schedule 9 Secondary
14 Service level existing rates and proposed rates for typical
15 billing levels. As can be seen from this exhibit, for each
16 Demand level, the higher load factor customers will see a
17 lower overall increase as compared to low load factor
18 customers.
19 OVERVIEW OF SCHEDULE 9 AN 19 RELATIONSHIPS
20 Q.How are Schedule 9 and Schedule 19
21 interrelated?
22 A.Currently, both Schedule 9 and Schedule 19
23 provide service at Secondary, Primary, and Transmission
24 Service levels. As customers' loads change, they can
NEMNICH, DI 14
Idaho Power Company
1 transfer between Schedule 9 and Schedule 19 while
2 continuing to take service at the same service level.
3 Both Schedule 9 and Schedule 19 have a summer and non-
4 summer Demand Charge and a Basic Charge. In addition,
5 Schedule 19 has an On-Peak Demand Charge in the summer.
6 The Billing Demand is the average kW supplied during the
7 15-consecutive-minute period of maximum use during the
8 billing period, adjusted for Power Factor. The On-Peak
9 Billing Demand for Schedule 19 customers is the average kW
10 supplied during the 15-consecutive-minute period of maximum
11 use during the June, July, and August billing periods for
12 the on-peak time period. The Basic Load Capacity is the
13 average of the two greatest monthly Billing Demands
14 established during the 12 -month period which includes and
15 ends with the current billing period.
16 Q.What is the current relationship between
17 prices on Schedule 9 and Schedule 19?
18 A.The Service Charge and the Basic Charge are
19 the same within service levels for both Schedule 9 and
20 Schedule 19. For example, the Basic Charge for Primary
21 Service level is $0.95 per kW per month for both Schedule 9
22 and Schedule 19; for Secondary Service level, the Basic
23 Charge is $0.67 per kW per month for both Schedule 9 and
24 Schedule 19. Likewise, the summer Demand Charge of $3.80
NEMNICH, DI 15
Idaho Power Company
1 per kW for Schedule 9 Primary Service level is the same as
2 the sum of the summer Demand Charge of $3.36 per kW and the
3 summer On-Peak Demand Charge of $.044 per kW for Schedule
4 19 Primary Service level. Generally, Secondary and
5 Transmission Service level Demand Charge structures mirror
6 the Primary Service level Demand Charge structures.
7 Q.Why has this relationship been established?
8 A.This relationship was established to be
9 reflective of cost and to facilitate customer transitions
10 from Schedule 9 to Schedule 19 and vice versa.
11 Q.Do your rate design proposals for Schedule 9
12 and Schedule 19 customers maintain this pricing
13 relationship between schedules?
14 A.For the most part, yes. The rate design
15 proposals for Schedule 9 and Schedule 19 for both Primary
16 Service level and Transmission Service level maintain the
17 relationship between the Service Charge, the Basic Charge,
18 and the Demand Charges on each of the schedules. The
19 relationship between Schedule 9 and Schedule 19 for these
20 two service levels is most important since almost all
21 customer transitions between these two schedules occur
22 within the Primary and Transmission Service levels.
23 The relationship between Schedule 9 Secondary
24 Service level and Schedule 19 Secondary Service level is
NEMNICH, DI 16
Idaho Power Company
1 much less important. Rarely does a customer transition
2 from Schedule 9 Secondary to Schedule 19 Secondary. In
3 fact, there has been only one customer taking service under
4 Schedule 19 Secondary Service level since the service
5 levels were established in 1995. It is much more common
6 for a Schedule 9 Secondary Service level customer to
7 transition to Schedule 9 Primary Service level prior to
8 transferring to Schedule 19.
9 Q.Does a similar relationship as that between
10 the Service, Demand, and Basic Charges for Schedule 9 and
11 Schedule 19 exist for the Energy Charges on these two
12 schedules?
13 A.No. The implementation of time-of-use rates
14 for Schedule 19 has made any direct relationship between
15 the Energy Charges more challenging. In general, however,
16 the Energy Charges for Schedule 9 Primary and Transmission
17 Service level have been slightly higher than the
18 corresponding Energy Charges for Schedule 19.
19 The Energy Charges have been established to achieve
20 the required revenue for the respective customer classes
21 given the values established for the Service, Basic, and
22 Demand Charges.
NEMNICH, DI 17
Idaho Power Company
1 LAGE GENERA SERVICE, SCHEDULE 9 PRIMAY & TRASMISSION
2 Q.What is the present rate structure for
3 Schedule 9, Primary and Transmission Service?
4 A.All customers taking service under Schedule
5 9, Primary and Transmission Service Levels, pay seasonal
6 Energy Charges, seasonal Demand Charges, a Basic Charge,
7 and a Service Charge. Customers may also pay a Facilities
8 Charge.
9 Q.Please describe the rate design proposal for
10 Schedule 9 customers receiving service at the Primary and
11 Transmission Service levels.
12 A.I am proposing seasonal time-of -use rates to
13 be implemented on a mandatory basis for all customers
14 taking service under Schedule 9 at Primary and Transmission
15 Service levels. Under this proposal, the basic time-of -use
16 rate structure for Schedule 9 Primary and Transmission
17 Service levels will be the same as the time-of -use
18 structure currently in place for customers taking service
19 at similar service levels under Schedule 19. This includes
20 On-Peak, Mid-Peak, and Off-Peak energy prices that would be
21 in effect during the three summer months from June 1
22 through August 31. During all other months, Mid-Peak and
23 Off-Peak energy prices would be in effect.
NEMNICH, DI 18
Idaho Power Company
1 In addition to energy rates, I am also proposing to
2 add a summer On-Peak Demand Charge. This On-Peak Demand
3 charge mirrors the existing On-Peak Demand charge that is
4 currently in place for Schedule 19 customers. The rate
5 design proposals for Schedule 9 Primary and Transmission
6 Service level are included on pages three and four of
7 Exhibit No. 74.
8 Q.Why are you proposing time-of -use rates for
9 Schedule 9, Primary and Transmission service?
10 A.Energy is more costly during the summer
11 months and it is more costly during certain hours of the
12 day. Schedule 9 customers currently have the metering in
13 place to accommodate hourly pricing. The implementation of
14 time-of-use rates will provide the economic signal that
15 energy is more costly during both the peak hours of the day
16 and the peak months of the year. It is anticipated that
17 time-of -use rates will encourage reduced consumption or
18 energy shifting during both the summer months as well as
19 during the daily peak hours.
20 Q.Did you gather any direct customer
21 information to help design this rate structure?
22 A.Yes. Idaho Power held a meeting on May 8,
23 2008, for customers taking service on Schedule 9 Primary or
24 Transmission Service levels. Five customers attended as
NEMNICH, DI 19
Idaho Power Company
1 well as a consultant for Kroeger, Inc., along with staff
2 from the Idaho Public Utili ties Commission and Idaho Power
3 Company. Several of the customers attending also had
4 facilities taking service under Schedule 19. The purpose
5 of the meeting was to discuss changing the rate structure
6 for Schedule 9 Primary and Transmission Service levels from
7 flat seasonal Energy Charges to time-of-use seasonal Energy
8 Charges. The addition of a summer On-Peak Demand Charge
9 was also discussed. Customer feedback on all issues was
10 solicited.
11 Q.What is your proposal for the Service Charge
12 and Basic Charge for Schedule 9 Primary and Transmission
13 Service level customers?
14 A.I am proposing that the Service Charge be
15 increased from $210.00 per month to $250.00 per month. I
16 am proposing that the Basic Charge be increased from $.95
17 per kW per month of Basic Load Capacity to $1.00 per kW per
18 month.
19 Q.How did you arrive at these rates?
20 A.As was discussed earlier, the Service Charge
21 and Basic Charge for both Schedule 9 Primary and
22 Transmission Service levels and Schedule 19 Primary and
23 Transmission Service levels are set to be equal in order to
24 facilitate ease of transition between rate schedules for
NEMNICH, DI 20
Idaho Power Company
1 customers. The cost-of-service results show customer unit
2 costs to be $245.87 and $313.33 for Schedule 9 Primary
3 Service and Schedule 19 Primary Service, respectively.
4 These are shown on pages four and five of Mr. Tatum's
5 Exhibit No. 67. The proposed value of $250.00 for Service
6 Charge represents a reasonable movement towards these unit
7 costs.
8 Q.Please describe the Company's proposal for
9 Demand Charges for Schedule 9 Primary and Transmission
10 level customers.
11 A.For Schedule 9, Primary and Transmission
12 customers the Company is proposing to mirror the rate
13 design currently in place for Schedule 19 customers.
14 During the three summer months, the Company is proposing to
15 implement a two-tiered Demand Charge for monthly peak
16 demand. The proposed Demand Charge for Billing Demand,
17 which is the average kW supplied during the 15 -minute
18 period of maximum demand during the billing period, is
19 $3.95 per kW for Primary Service and $3.84 for Transmission
20 Service. An additional charge of $0.75 is proposed for
21 each kW of On-Peak Billing Demand, which is the average kW
22 supplied during the 15-minute period of maximum demand
23 during the billing period for the On-Peak hours. For
24 customers whose peak demand during the billing period
NEMNICH, DI 21
Idaho Power Company
1 occurs during the On-Peak period, the Billing Demand and
2 the On-Peak Billing Demand will be the same. However, for
3 customers whose peak demand occurs during the Mid-Peak or
4 Off-Peak period, the Billing Demand will be greater than
5 the On-Peak Billing Demand. During the non-summer months,
6 only Billing Demand will apply. There is no On-Peak
7 Billing Demand during the non-summer months. The proposed
8 Demand Charges for the non-summer months are $3.65 per kW
9 for Primary Service and $3.55 per kW for Transmission
10 Service.
11 Q.How did you determine the Demand Charges?
12 A.My overall goal was to move summer and non-
13 summer Demand Charges closer to cost of service while at
14 the same time maintaining relationships among schedules and
15 service levels.
16 To calculate the Demand Charges, I first examined
17 the existing differential between summer and non-summer
18 Demand Charges which is slightly less than 20 percent.
19 From pages four and five of Exhibit No. 67, the cost-of-
20 service results show differentials between summer and non-
21 summer demand to be 62 percent for Schedule 9 Primary and
22 74 percent for Schedule 19 Primary. In order to move
23 towards alignment with cost-of service, my proposal is to
24 move 25 percent closer to the cost-of-service results.
NEMNICH, DI 22
Idaho Power Company
1 This results in an overall proposed differential of
2 approximately 29 percent between summer and non-summer
3 Demand Charges.
4 The summer demand unit costs for Schedule 9 Primary
5 and Schedule 19 Primary are $6.51 and $7.75, respectively,
6 as indicated on pages four and five of Mr. Tatum's Exhibit
7 No. 67. I set the total summer demand amount at $4.70 per
8 kW per month, which represents 72 percent of. Schedule 9
9 Primary unit cost to serve and 61 percent of the Schedule
10 19 Primary unit cost to serve. This total summer demand
11 amount is separated to two amounts; the On-Peak Demand
12 Charge and the summer Demand Charge.
13 I set the summer On-Peak Demand Charge at $0.75 per
14 kW per month, which is 16 percent of the total summer
15 demand amount at the Primary Service level. This is
16 slightly higher than the current 12 percent. I increased
17 the percent in order to send a stronger price signal during
18 the Company's peak time periods. The summer On-Peak Demand
19 Charge is set to the same amount for Schedule 9 Primary and
20 Transmission levels as well as Schedule 19 customers at all
21 Service levels.
22 The summer Demand Charge for Schedule 9 Primary
23 Service level is $3.95 per kW per month, which is the total
24 summer demand amount of $4.70 less the summer On-Peak
NEMNICH, DI 23
Idaho Power Company
1 Demand Charge of $0.75.
2 The non-summer demand unit costs for Schedule 9
3 Primary and Schedule 19 Primary are $4.13 and $4.77,
4 respectively, as indicated on pages four and five of Mr.
5 Tatum's Exhibit No. 67. I set the non-summer Schedule 9
6 Primary Service level Demand Charge at $3.65 per kW per
7 month, which represents 91 percent of Schedule 9 Primary
8 unit cost to serve and 79 percent of the Schedule 19
9 Primary unit cost to serve.
10 From Primary Service level, the summer and non-
11 summer Demand Charges, as well as the summer On-Peak Demand
12 Charge, were spread to the Transmission Service level
13 maintaining traditional relationships.
14 Q.Is the Company proposing to apply the
15 current Schedule 19 time-of-use block definitions to the
16 new rate design proposal for Schedule 9?
17 A.Yes.
18 Q.What are the time-of-use block definitions
19 that the Company is proposing for the Energy Charges?
20 A.During the three summer months, the Company
21 is proposing three time-of-use blocks. The On-Peak block
22 is defined as 1 p.m. to 9 p.m. Monday through Friday except
23 holidays. The Mid-Peak block is defined as 7:00 a.m. to
24 1:00 p.m. and 9:00 p.m. to 11 p.m. Monday through Friday
NEMNICH, DI 24
Idaho Power Company
1 and 7:00 a.m. to 11:00 p.m. Saturday and Sunday except
2 holidays. The Off-Peak block is defined as 11:00 p.m. to
3 7: 00 a.m. every day Monday through Saturday and all hours
4 on holidays. During the non-summer months, the Company is
5 proposing just two time-of use blocks. The Mid-Peak block
6 during the non-summer months is defined as 7:00 a.m. to
7 11: 00 p. m. Monday through Saturday except holidays. The
8 Off-Peak block is defined as 11:00 p.m. to 7:00 a.m. Monday
9 through Saturday and all hours on Sunday and holidays. All
10 times are in Mountain Time.
11 Q.What are the specific proposed Energy
12 Charges for Schedule 9 by service level?
13 A.
14 and Transmission
15 are:
16 Time
17 Period
18 Summer
19 On-Peak
20 Mid-Peak
21 Off-Peak
22 Non-Summer
23 Mid-Peak
24 Off-Peak
The Energy Charges for Schedule 9 Primary
customers by time period for each season
Service Level
Primary Transmission
3.35099 3.25609
3.04639 2.97049
2.84689 2.77959
2.65919 2.59879
2.54969 2.50249
NEMNICH, DI 25
Idaho Power Company
1 Q.What were your goals in developing these
2 Energy Charges?
3 A.The first goal was to utilize the same
4 seasonal energy rate differentials used in existing rates
5 and apply it to the proposed Off-Peak time blocks. This
6 differential is approximately 12 percent. My second goal
7 was to apply the time block differentials used in the
8 existing Schedule 19 time-of-use rates to the proposed
9 Schedule 9 Primary and Transmission time-of-use rates. My
10 third goal was to recover the residual revenue requirement
11 given the proposed Service, Basic, and Demand Charges.
12 Q.Why did you use the current Schedule 19
13 time-of-use rate differentials for Schedule 9?
14 A.Many of our Schedule 9 customers also have
15 Schedule 19 accounts so they may have some familiarity
16 operating with this rate structure. Furthermore, these
17 differentials, set at approximately 7 percent between the
18 summer Off-Peak and summer Mid-Peak Energy Charges,
19 approximately 10 percent between the summer Mid-Peak and
20 summer On-Peak Energy Charges, and approximately 4 percent
21 between the non-summer Off-Peak and non-summer Mid-Peak
22 Energy Charges, are not very large but do provide an
23 introductory level of time differentiated rates. Customers
24 have the opportunity to become familiar with time variant
NEMNICH, DI 26
Idaho Power Company
1 pricing gradually, see how their usage patterns impact
2 their bills, and plan accordingly.
3 Q.How did you calculate the specific time-of-
4 use Energy Charges?
5 A.For Schedule 9 customers taking service at
6 the Primary Service level, the summer Off-Peak Energy
7 Charge was set at 2.84689, which is close to the current
8 summer Energy Charge. The non-summer Off-Peak Energy
9 Charge was set at 2.54969, which is close to the current
10 non-summer Energy Charge. Therefore, electricity used
11 during Off-Peak hours will see virtually no rate increase
12 for this rate component. This gives a strong price signal
13 to those customers who can primarily use electricity during
14 Off-Peak time blocks.
15 The summer and non-summer Mid-Peak Energy charges
16 were calculated by applying the differentials of
17 approximately 7 percent and approximately 4 percent,
18 respectively, to the Off-Peak Energy Charge. The summer
19 On-Peak Energy Charge was calculated by applying the
20 approximately 10 percent differential to the summer Mid-
21 Peak Energy Charge.
22 The Energy Charges for the Schedule 9 customers
23 taking service at the Transmission level were calculated in
24 the same process. I have provided a comparison of current
NEMNICH, DI 27
Idaho Power Company
1 and proposed rates together with seasonal and time-of-use
2 differentials in my work papers.
3 Q.Why are you proposing that these time-of-use
4 rates for Schedule 9 Primary and Transmission levels be
5 mandatory?
6 A.These time-of -use rates more accurately
7 reflect the costs to serve our customers and therefore
8 provide a better overall pricing signal. By providing
9 time-of-use rates to all customers, not just those who
10 might benefit from being on time-of-use rates, we are
11 providing incentives to customers to conserve and/or shift
12 load. If customers respond to this signal by conserving or
13 shifting load, the resulting energy use pattern lowers
14 overall costs for all customers.
15 Q.Are you proposing a "phase-in" period for
16 time-of-use rates similar to what was adopted when time-of-
17 use was implemented for Schedule 19?
18 A.No. I propose implementing a customer
19 communication and education plan that provides customers
20 with information on the possible impact of time-of-use
21 rates on their bills. Examples of energy conservation or
22 load shifting ideas may be also provided at that time.
23 By working with customers before the rates go into
24 effect they can plan and make purchasing decisions and
NEMNICH, DI 28
Idaho Power Company
1 determine how best to react to the new structure. In turn,
2 by providing customer support up front, Idaho Power can
3 avoid the costs of manual bill processing associated with
4 shadow bills that occurred during the Schedule 19 time-of-
5 use rate implementation.
6 Q.What is the revenue requirement to be
7 recovered from Schedule 9 Large General Service customers
8 taking service at the Primary and Transmission levels?
9 A.The annual revenue requirement for Schedule
10 9 customers as shown on page four of Mr. Tatum's Exhibit
11 No. 70 is $175,488,062. Of this amount the revenue
12 requirement target for Schedule 9 Primary and Transmission
13 is $16,681,613.
14 Q.What is the billing impact of this rate
15 design proposal on the customers receiving service under
16 Schedule 9 Primary and Transmission Service levels?
17 A.Page four of Exhibit No. 75 shows the
18 billing comparison between the existing rates and proposed
19 rates for Schedule 9 Primary Service level and Schedule 9
20 Transmission Service level. These comparisons are based on
21 actual billing data for 2007. Approximately 53 percent of
22 the customers receive an increase in their annual bills
23 less than or equal to 7 percent. Approximately 40 percent
24 of the customers receive an increase of between 7 percent
NEMNICH, DI 29
Idaho Power Company
1 and 9 percent and approximately 6 percent of the customers
2 recei ve an increase greater than 9 percent. No customers
3 received an increase greater than 16 percent.
4 LAGE POWER SERVICE, SCHEDULE 19
5 Q.What is the present rate structure for
6 Schedule 19?
7 A.Service under Schedule 19, just like service
8 under Schedule 9, is provided under Secondary, Primary, and
9 Transmission Service levels. All customers taking service
10 under Schedule 19 pay seasonal time-of-use Energy Charges,
11 seasonal Demand Charges, a summer On-Peak Demand Charge, a
12 Basic Charge, and a Service Charge. Customers taking
13 Primary or Transmission Service may also pay a Facilities
14 Charge. In addition, Schedule 19 includes a 1,000 kW
15 minimum Billing Demand and Basic Load Capacity.
16 Q.What is the rate design proposal for
17 Schedule 19?
18 A.The rate design proposal for Schedule 19 is
19 shown on pages five through seven of Exhibit No. 74.
20 Increases are proposed for all rate components on Schedule
21 19. There are two primary changes to the rate design
22 proposed for Schedule 19 customers. First, the
23 differentials between Off-Peak, Mid-Peak, and On-Peak
24 Energy Charges during the summer season and the
NEMNICH, DI 30
Idaho Power Company
1 differential between Off-Peak and Mid-Peak Energy Charges
2 during non-summer season have been increased. And, second,
3 more emphasis has been placed on the Demand, Basic, and
4 Service Charge components.
5 Q.What are the proposed changes for the
6 Service Charge?
7 A.The proposed Service Charge for both
8 Schedule 19 Primary and Transmission Service levels is
9 $250.00 per month. The cost-of-service result of the
10 Service Charge for Schedule 19 is $313.33 and is shown on
11 page five of Mr. Tatum's Exhibit No. 67. The proposed
12 Service Charge of $250 represents approximately 80 percent
13 of the cost-of-service results.
14 The proposed Service Charge for Schedule 19
15 Secondary Service level is $15.00 per month, which
16 maintains the alignment between Secondary Service levels
17 between Schedule 19 and Schedule 9.
18 Q.What are the proposed changes for the
19 proposed Basic Charge for Schedule 19?
20 A.For the Primary Service level, the Basic
21 Charge is $1.00 per kW per month. This amount is
22 approximately 90 percent of the cost-of-service result of
23 $1.12 as shown on page five of Mr. Tatum's Exhibit No. 67.
24 To calculate Basic Charges for the Secondary and
NEMNICH, DI 31
Idaho Power Company
1 Transmission levels, historic relationships between the
2 three levels were calculated and maintained. The Basic
3 Charge for Secondary Service level was also modified to
4 align with Schedule 9 Secondary Service. The proposed
5 Basic Charges for Schedule 19 Secondary Service is $0.80
6 per kW per month and for Transmission Service is $0.53 per
7 kW per month.
8 Q.Please describe your proposal for Demand
9 Charges.
10 A.The proposed summer On-Peak Demand Charge is
11 $0.75 kW for all service levels. The proposed summer
12 Demand Charges are $4.08, $3.95, and $3.84 per kW and the
13 proposed non-summer Demand Charges are $3.75, $3.65, and
14 $3.55 per kW for the Secondary, Primary, and Transmission
15 Service levels , respectively. These Charges were
16 calculated to maintain the relationships between Schedules
17 and Service levels described earlier. For Schedule 19
18 Secondary Service level, the summer and non-summer Demand
19 Charges were modified slightly from traditional alignment
20 with Schedule 9 Secondary Service level. These charges
21 were modified in order to maintain the proposed Energy
22 Charge differentials while at the same time recover the
23 residual revenue requirement.
NEMNICH, DI 32
Idaho Power Company
1 Q.What are the specific proposed Energy
2 Charges by service level for Schedule 19 customers?
3 A.The Proposed Schedule 19 Energy Charges by
4 service level and time period for each season are:
Time
Period
Service Level
Secondary Primary Transmission
5
6
7 Summer
8 On-Peak 4.78469 3.97359 3.91489
9 Mid-Peak 3.66509 3.02669 2.99709
10 Off-Peak 3.18709 2.63139 2.60499
11 Non-Summer
12 Mid-Peak 3.37909 2.80259 2.76879
13 Off-Peak 2.93799 2.43689 2.40859
14 Q.How were these Energy Charges derived?
15 A.The overall approach for calculating the
16 Energy Charges was to keep the Off-Peak Energy Charge as
17 low as possible while increasing the differentials for Mid-
18 Peak and On-Peak Energy Charges and at the same time
19 meeting the revenue requirements for this schedule as
20 specified by Mr. Tatum's cost-of-service study in Exhibit
21 No. 70. In order to calculate new Off-Peak Energy Charges
22 for the summer and non-summer seasons, the current rates
23 were increased by approximately 7.5 percent. This is
24 approximately half of the total overall increase of 15
NEMNICH, DI 33
Idaho Power Company
1 percent for Schedule 19 customers. This gives a strong
2 price signal to those customers who can primarily use
3 electricity during Off-Peak hours.
4 Then I calculated the new Mid-Peak and Off-Peak
5 Energy Charges in an i terati ve process resulting in new
6 differentials. The resulting differential between Off-Peak
7 and Mid-Peak Energy Charges for both summer and non-summer
8 is approximately 15 percent. The resulting differential
9 between Mid-Peak and On-Peak is approximately 31 percent.
10 The overall summer total rate differential between On-Peak
11 Energy Charge and Off-Peak Energy charge is approximately
12 46 percent.
13 I have included details on the comparison of rate
14 component and differentials for Schedule 19 and Schedule 9
15 Secondary Primary and Transmission Service levels in my
16 work papers.
17 Q.Do you think these levels are reasonable?
18 A.Yes. I reviewed time-of-use rate structures
19 of the other utilities and found that a total overall
20 differential of 46 percent is within a typical range. The
21 proposed Schedule 9 Primary Service level summer On-Peak
22 Energy Charge of 3.97359 cents is just over half of the
23 average summer marginal cost.
NEMNICH, DI 34
Idaho Power Company
1 Q.Why are you proposing to increase the rate
2 differentials?
3 A.When time-of-use rates were implemented for
4 Schedule 19 customers four years ago, the differentials
5 between On-Peak, Mid-Peak, and Off-Peak Energy Charges were
6 set at an "introductory" level. By increasing the rate
7 differentials, a stronger price signal is sent that will
8 provide a stronger incentive to conserve or to shift the
9 time of energy usage to a less costly time period. This
10 stronger price signal provides higher benefits to those
11 customers who modify operations or purchase equipment that
12 uses less energy. Overall, this rate structure reflects a
13 better cost recovery mechanism.
14 Q.What is the revenue requirement to be
15 recovered from Large Power Service customers taking service
16 under Schedule 19?
17 A.The annual revenue requirement for Schedule
18 19 customers as shown on page four of Mr. Tatum's Exhibit
19 No. 70 is $80,811,772.
20 Q.What is the impact of the rate design on
21 Large Power Service customers?
22 A.Page five of Exhibit No. 75 shows the
23 billing comparison between the existing rates and the
24 proposed rates for Schedule 19 including all service
NEMNICH, DI 35
Idaho Power Company
1 levels. These comparisons are based on actual billing data
2 for 2007. Approximately 40 percent of the customers
3 recei ve an increase in their annual bills less than 15
4 percent, which is the overall increase for the Schedule 19
5 customers. Approximately 31 percent of the customers
6 receive an increase of between 15 percent and 15.5 percent
7 and approximately 29 percent of the customers receive an
8 increase greater than 15.5 percent.
. 9 SPECIA CONTRACT CUSTOMERS
10 Q.What are your rate design proposals for the
11 Special Contract customers?
12 A.I am proposing to maintain the current rate
13 structures for the Special Contract customers of Micron,
14 the J. R. Simplot Company, and the Department of Energy.
15 Accordingly, the existing rates for the Special Contract
16 customers are simply increased uniformly by 15 percent to
17 recover the revenue requirement as shown on page 4 of Mr.
18 Tatum's Exhibit No. 70. The rates for Micron, the J. R.
19 Simplot Company, and the Department of Energy are shown on
20 pages 8, 9, and 10 of Exhibit No. 74, respectively.
21 STANBY AN ALTERNATE DISTRIBUTION SERVICE
22 Q.Are any customers currently taking service
23 under Schedule 45, Standby Service?
NEMNICH, DI 36
Idaho Power Company
1 A.Yes. One customer is currently taking
2 Schedule 45 service.
3 Q.Are any revisions to Schedule 45 being
4 proposed?
5 A.Yes. The Schedule 45 charges are being
6 revised to reflect the updated cost information resulting
7 from the 3CP/12CP cost-of-service study. The updated
8 charges have been derived using the same methodology used
9 to derive the charges approved by the Commission in the
10 Company's last four general rate cases, Case No. IPC-E-94-
11 5, Case No. IPC-E-03-13, Case No. IPC-E-05-28, and Case No.
12 IPC-E-07-08. No other changes are being made to Schedule
13 45.
14 Q.What are the proposed charges for Schedule
15 45?
16 A.The proposed Standby Reservation Charge for
17 each kW of Available Standby Capacity during the summer
18 months is increased from $1.67 per kW to $1.83 per kW for
19 Primary Service level and from $0.39 per kW to $0.51 per kW
20 for Transmission Service level. During the non-summer
21 months, the proposed Standby Reservation Charge is
22 increased from $1.54 per kW to $1.66 per kW for Primary
23 Service level and from $0.26 per kW to $0.34 per kW for
24 Transmission Service level. The proposed Standby Demand
NEMNICH, DI 37
Idaho Power Company
1 Charge of Standby Billing Demand consumed in the summer is
2 increased from $4.60 per kW to $5.62 per kW for Primary
3 Service level and from $4.34 per kW to $5.31 per kW for
4 Transmission Service level. During the non-summer months,
5 the proposed Standby Billing Demand Charge per kW is
6 increased from $4.29 per kW to $4.66 per kW for Primary
7 Service level and from $4.06 per kW to $4.40 per kW for
8 Transmission Service level. No changes are proposed for
9 the Excess Demand Charge.
10 Q.Are any customers currently taking service
11 under Schedule 46,Alternate Distribution Service?
12 A.Yes.There are four customers currently
13 taking service under Schedule 46.
14 Q.Are you proposing any changes to Schedule
15 46,Alternate Distribution Service?
16 A.The Schedule 46 Capacity Charge is proposed
17 to increase from $1.28 per kW to $1.47 per kW to reflect
18 the current cost of providing Alternate Distribution
19 Service. The $1.47 amount is derived by summing the
20 Distribution demand revenue requirement for Substations,
21 Primary Lines, and Primary Transformers for Schedule 19
22 shown on page five of Mr. Tatum's Exhibit No. 67
23 ($1,898,021; $3,461,958; and $229,799, respectively) and
24 dividing this sum by the total billed kW of 4,238,815.
NEMNICH, DI 38
Idaho Power Company
1 This methodology is the same as that used to derive the
2 charges approved by the Commission in the Company's last
3 four general rate cases.
4 MISCELLAOUS SPECIAL CONTRACT, SCHEDULE 31
5 Q.What is the miscellaneous special contract
6 under which the Company is providing service?
7 A.The Company has entered into a contract with
8 the Amalgamated Sugar Company to provide customized standby
9 service. The Company's initial contract with the
10 Amalgamated Sugar Company to provide standby service was
11 entered into on April 6, 1998. Standby Service is
12 currently being provided to the Amalgamated Sugar Company
13 under the provisions of a revised Standby Electric Service
14 Agreement dated December 7, 2005. This agreement has been,
15 as was the initial agreement, approved by the Commission.
16 Q.Are you proposing any changes to the standby
17 charges under the Standby Electric Service Agreement with
18 the Amalgamated Sugar Company?
19 A.Yes. I am revising the charges to reflect
20 the updated cost information resulting from the 3CP/12CP
21 cost-of-service study. The methodology used to update the
22 charges is the same methodology used to establish the
23 currently approved charges.
NEMNICH, DI 39
Idaho Power Company
1 I have included details on the derivation of the
2 updated charges in my work papers.
3 Q.Does this conclude your testimony?
4 A.Yes, it does.
NEMNICH, DI 40
Idaho Power Company