20110602Sparks Di, Exhibits.pdf

RECEIVED
2011 JUN -I PM 2: 43
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC SERVICE
TO ITS CUSTOMERS IN THE STATE OF
IDAHO.
CASE NO. IPC-E-II-08
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
SCOTT D. SPARKS
1 Q.Please state your name and business address.
2 A.My name is Scott D. Sparks and my business
3 address is 1221 West Idaho Street, Boise, Idaho.
4 Q.By whom are you employed and in what capacity?
5 A.I am employed by Idaho Power Company (" Idaho
6 Power" or "Company") as a Senior Regulatory Analyst in the
7 Regulatory Affairs Department.
8 Q .Please describe your educational background.
9 A.In May of 1989, I received a Bachelor of
10 Business Administration degree in Business Management from
11 Boise State University. I have also completed post-
12 graduate econometrics courses and attended the electric
13 utility ratemaking course offered through New Mexico State
14 Uni versi ty' s Center for Public Utili ties as well as various
15 advanced ratemaking courses presented by the Edison
16 Electric Institute.
17 Q.Please describe your work experience with
18 Idaho Power.
19 A.I became employed by the Company in 1985 as a
20 part-time mail clerk and have held positions as Meter
21 Reader, Customer Service Representative, Economic Analyst,
22 Human Resource/Compensation Analyst, Regulatory Analyst,
23 and Resource Planning Analyst.
24 In January of 1991, after two years in the Customer
25 Service Department, I was offered and I accepted a position
SPARKS, DI 1
Idaho Power Company
1 in the Company's Energy Services Department. My
2 responsibilities over six years in the department varied
3 from conservation program evaluation, special studies, load
4 forecasting, and load research. In 1995, I was asked to
5 temporarily transfer to the Human Resources Department to
6 assist with implementation of the Company's reorganization,
7 benefit, and compensation plans.
8 In 1998, I applied for and accepted a position in
9 the Regulatory Affairs Department where I was responsible
10 for reviving the Company's resource planning and integrated
11 resource planning processes. As part of reorganization, I
12 was reassigned to the Power Supply Planning Department in
13 2001 where I acted as the lead analyst for the Integrated
14 Resource Plan. In July 2003, I left the Company to pursue
15 self-employment in the real estate and construction
16 sectors. I returned to the Company as a Senior Regulatory
17 Analyst in the Regulatory Affairs Department in June 2008.
18 Q.What is the scope of your testimony in this
19 proceeding?
20 A.Based upon direction from Mr. Michael J.
21 Youngblood, Manager of Rate Design, my testimony addresses
22 proposed changes to the Company's commercial, industrial,
23 irrigation, lighting, and non-metered retail tariff
24 schedules. I will also address proposed changes to Rule H,
25 New Service Attachments and Distribution Line Installations
SPARKS, DI 2
Idaho Power Company
1 or Alterations, and updates to the rates charged under the
2 Company' s facilities charge provisions.
3 Q.What are your overall obj ecti ves in arriving
4 at the proposed rate designs for the various service
5 schedules identified in your testimony?
6 A.As discussed in Mr. Youngblood's testimony,
7 the first obj ecti ve is to establish prices which primarily
8 reflect the costs of the services provided. As part of the
9 Company's last several general rate cases, this obj ecti ve
10 has been pursued in demand-metered schedules by emphasizing
11 increases in the demand and customer components and the
12 inclusion of fewer non-energy-related costs in the energy
13 charges. Mr. Youngblood's testimony also discusses a
14 second objective of designing the cost-based rate proposals
15 to encourage increased energy efficiency.
16 I . COMMRCIAL AN INDUSTRIAL
17 Q.How is the discussion of your rate design
18 proposals organized within your testimony for the
19 commercial and industrial customer classes?
20 A.My testimony for the commercial and industrial
21 customer classes will address rate design proposals for
22 Schedules 7, 9, 19, 31, 45, and 46, respectively.
23 Q.Please describe the methodology used to
24 determine the rate component adjustments for Schedules 7,
25 9, and 19.
SPARKS, DI 3
Idaho Power Company
1 A.The methodology used to calculate the proposed
2 rate component adjustments for Schedules 7, 9, and 19
3 represent a uniform percentage movement of 5 percent toward
4 the unit cost of service intended for recovery by that rate
5 component. In doing this, the Company first considered the
6 ~ercentage of overall revenue requirement identified by the
7 customer billing components for Schedules 7, 9, and 19
8 resulting from the Company's proposed class cost-of-service
9 study. These percentages established the target revenue
10 requirement for each billing component. Second, the
11 Company determined the percentage of overall revenue
12 currently recovered by each billing component of existing
13 base rates. The difference, or gap, between the target and
14 the actual percentage was then determined for each billing
15 component. The current percentage of overall revenue by
16 billing component was then adjusted by approximately 5
17 percent of the gap to establish targets. The customer
18 related charges were then established to achieve these new
19 targets.
20 A.Small General Service, Schedule 7.
21 Q.What is the present rate structure for Small
22 General Service under Schedule 7?
23 A.Customers taking service under Schedule 7 pay
24 a monthly Service Charge, a monthly seasonal Energy Charge
25 for the first 300 killowatt-hours ("kWh") used, and a
SPARKS, DI 4
Idaho Power Company
1 separate seasonal Energy Charge for all usage over 300 kWh
2 in a month. Summer Energy Charges begin on June 1 of each
3 year and end on August 31 of each year while the non-summer
4 Energy Charges begin on September 1 of each year and end on
5 May 31 of each year. Schedule 7 customers do not have a
6 Demand Charge.
7 Q.What is the revenue requirement to be
8 recovered from Small General Service customers taking
9 service under Schedule 7?
10 A.The annual revenue requirement for Schedule 7
11 customers is $16,493,381. This is shown on page 9 of Mr.
12 Matthew T. Larkin's Exhibit No. 38.
13 Q.Please describe the proposed rate design
14 adjustments for Schedule 7.
15 A.The Service Charge for Schedule 7 was set to
16 coincide with the Service Charge proposed by Ms. Darlene
17 Nemnich for Schedule 1. These charges have traditionally
18 been set at the same rate and the Company desires to
19 continue this rate design relationship. For all energy
20 components, the Company is proposing rates that represent a
21 uniform 5 percent movement towards the costs to serve that
22 rate component. All rate design adjustments for Schedule 7
23 are included on page 1 of Exhibit No. 47 and target the
24 proposed class revenue increase of 14.85 percent shown on
25 page 9 of Mr. Larkin's Exhibit No. 38.
SPARKS,DI 5
Idaho Power Company
1 Q.Have you prepared an exhibit that illustrates
2 the impact of the proposed rate adjustments on Small
3 General Service customers?
4 A.Yes, page 1 of Exhibit No. 48 shows the
5 billing comparison between Schedule 7 existing rates and
6 proposed rates for typical billing levels.
7 B.Large General Service, Schedule 9.
8 Q.In general terms, what is the current rate
9 structure for Schedule 9?
10 A.Service under Schedule 9 may be taken at
11 Secondary, Primary, or Transmission Service level. All
12 customers taking service under Schedule 9 pay a Service
13 Charge, a Basic Charge, and both summer and non-summer
14 Energy and Demand Charges. Customers taking Primary or
15 Transmission service may also pay a Facilities Charge for
16 Company-owned facilities installed beyond Idaho Power's
17 Point of Delivery.
18 c.Large General Service, Schedule 9 - Secondary.
19 Q.What is the current rate structure for
20 Schedule 9, Secondary Service?
21 A.The current rate structure for Schedule 9
22 Secondary Service includes a two-tier declining block
23 Energy Charge along with a block Demand Charge and a block
24 Basic Charge. Under this rate structure, the first block
25 Energy Charge applies to the first 2,000 kWh per month of
SPARKS, DI 6
Idaho Power Company
1 usage and the second block Energy Charge applies to all
2 usage greater than 2,000 .kWh per month.
3 Under the Demand Charge, the first rate block
4 applies to the first 20 kilowatts ("kW") of Billing Demand
5 and the second block applies to all additional kW.For
6 the Basic Charge, the first rate block applies to the first
7 20 kW of Basic Load Capacity and the second block applies
8 to all additional kW.
9 Q.What is the reason that Schedule 9 Secondary
10 Service has this block design in place?
11 A.The current block rate design structure for
12 Schedule 9 Secondary Service was put in place to remedy a
13 pricing disparity that occurred when customers transitioned
14 between Schedule 7 ànd Schedule 9 at the Secondary level.
15 Before this block structure was put in place, many of the
16 customers moving from Schedule 9 to Schedule 7 would see an
17 increase in their monthly bill of more than 100 percent.
18 This disparity provided an incentive to artificially
19 increase their usage to remain on Schedule 9, even when
20 they qualified for Schedule 7. The block rate structure in
21 place for Schedule 9 Secondary Service provides a similar
22 rate level and a smooth transition to customers moving from
23 Schedule 7 to Schedule 9 Secondary Service.
24 Q.What is the revenue requirement for customers
25 taking Secondary Service under Schedule 9?
SPARKS, DI 7
Idaho Power Company
1 A.The annual revenue requirement for customers
2 taking Secondary Service under Schedule 9, as shown on page
3 9 of Mr. Larkin's Exhibit No. 38, is $181,624,927.
4 Q.Have you prepared an exhibit that illustrates
5 the rate design proposal for revenue recovery under
6 Schedule 9 Secondary Service?
7 A.Yes, the rate design proposal for Schedule 9
8 Secondary Service is included on page 2 of Exhibit No. 47
9 and targets the proposed class revenue increase of 14.85
10 percent shown on page 9 of Mr. Larkin's Exhibit No. 38. As
11 previously described, for all rate components, the Company
12 is proposing rates that represent a uniform 5 percent
13 movement towards the costs to serve that rate component.
14 The costs to serve each rate component are indicated on
L5 page 3 of Mr. Larkin's Exhibit No. 36.
16 Q.Have you prepared an exhibit that shows the
17 impact of the rate design on Schedule 9 Secondary Service
18 level customers?
19 A.Pages 2-4 of Exhibit No. 48 show the billing
20 comparison between the Schedule 9 Secondary Service level
21 existing rates and proposed rates for typical billing
22 levels. As can be seen from this exhibit, for each Demand
23 level, the higher load factor customers will see a lower
24 overall increase as compared to low load factor customers.
25
SPARKS, Dr 8
Idaho Power Company
1 Q.Are you proposing any other changes to
2 Schedule 9?
3 A.Yes. The Company is proposing to change the
4 section heading of "Power Factor" to "Power Factor
5 Adjustment". This clarification is a more accurate
6 description of the section and it aligns with the "Power
7 Factor Adjustment" headings listed under Schedules 19 and
8 24.
9
10
11
12
D .Large General Service, Schedule 9 - Primary &
Transmission.
Q.What is the current rate structure for
13 Schedule 9, Primary and Transmission Service?
14 A.All customers taking service under Schedule 9
15 Primary or Transmission Service pay seasonal time-of-use
16 Energy Charges, seasonal Demand Charges, a summer On-Peak
17 Demand Charge, a Basic Charge, and a Service Charge.
18 Customers may also pay a Facilities Charge for Company-
19 owned facilities installed beyond Idaho Power's Point of
20 Delivery.
21 Q.What is the revenue requirement to be
22 recovered from Schedule 9 customers taking service at the
23 Primary and Transmission levels?
24 A.The annual revenue requirement for Schedule 9
25 Primary and Transmission level customers as shown on page 9
26 of Mr. Larkin's Exhibit No. 38 is $21,239,152.
SPARKS, Dr 9
Idaho Power Company
1 Q.Have you prepared an exhibit that illustrates
2 the rate design proposal for revenue recovery of Primary
3 and Transmission Service under Schedule 9?
4 A.Yes, the rate design proposals for Schedule 9
5 Primary Service and Transmission Service are included on
6 pages 3 and 4 of Exhibit No. 47 and target the proposed
7 class revenue increase of 14.85 percent shown on page 9 of
8 Mr. Larkin's Exhibit No. 38. For all rate components, the
9 Company is proposing rates that represent a uniform 5
10 percent movement towards the costs to serve that rate
11 component. The costs to serve each rate component are
12 indicated on page 4 of Mr. Larkin's Exhibit No. 36.
13 Q.Have you prepared an exhibit that shows the
14 billing impact of this rate design proposal on customers
15 receiving Primary Service under Schedule 9?
16 A.Yes, pages 5-7 of Exhibit No. 48 show the
17 billing comparisons between the existing rates and proposed
18 rates for Schedule 9 Primary Service.
19 E.Large Power Service, Schedule 1.9.
20 Q.What is the current rate structure for
21 Schedule 19?
22 A.Service under Schedule 19, just like service
23 under Schedule 9, is provided at Secondary, Primary, and
24 Transmission Service levels. All customers taking service
25 under Schedule 19 pay seasonal time-of-use Energy Charges,
SPARKS, DI 10
Idaho Power Company
1 seasonal Demand Charges, a summer On-Peak Demand Charge, a
2 Basic Charge, and a Service Charge. Customers taking
3 Primary or Transmission Service may also pay a Facilities
4 Charge for Company-owned facilities installed beyond rdaho
5 Power's Point of Delivery. In addition, Schedule 19
6 includes a 1,000 kW per month minimum Billing Demand and
7 Basic Load Capacity.
8 Q.What is the revenue requirement to be
9 recovered from Large Power Service customers taking service
10 under Schedule 19?
11 A.The annual revenue requirement for Schedule 19
12 customers as shown on page 9 of Mr. Larkin's Exhibit No. 38
13 is $95,170,378.
14 Q.Have you prepared an exhibit that illustrates
15 the proposed rate design to recover the annual revenue
16 requirement for Schedule 19?
17 A.Yes, the rate design proposal for Schedule 19
18 is shown on pages 6-8 of Exhibit No. 47 and targets the
19 proposed class revenue increase, of 14.84 percent shown on
20 page 9 of Mr. Larkin's Exhibit No. 38. For all rate
21 components, the Company is proposing rates that represent a
22 uniform 5 percent movement towards the costs to serve that
23 rate component. The costs to serve each rate component are
24 indicated on page 3 of Mr. Larkin's Exhibit No. 36.
25
SPARKS, DI 11
Idaho Power Company
1 Q.Have you prepared an exhibit that shows the
2 billing comparisons between the existing rates and the
3 proposed rates for Schedule 19 Primary Service customers?
4 A.Pages 8-10 of Exhibit No. 48 show the billing
5 comparisons between the existing rates and the proposed
6 rates for Schedule 19 Primary Service customers. As with
7 Schedule 9 Primary Service, for each Demand level, the
8 higher load factor customers will see a lower overall
9 increase as compared to low load factor customers.
10 F.Schedule 31.
11 Q.Is the Company proposing any rate adjustments
12 to the standby charges for Amalgamated Sugar Company under
13 Schedule 31?
14 A.Yes. The Company has revised the charges to
15 reflect the updated unit cost information resulting from
16 the cost-of-service study for Schedule 19 Primary Service.
17 The methodology used to update the charges is the same
18 methodology used to establish the currently approved
19 charges. The derivations of the updated charges are
20 included in my workpapers.
21 G.Standby Service, Schedule 45.
22 Q.Is the Company proposing any rate adj ustments
23 to Schedule 45, Standby Service?
24 A.Yes. The proposed rate design for Schedule 45
25 reflects the updated cost information resulting from the
SPARKS, DI 12
Idaho Power Company
1 cost-of-service study. The updated charges were derived
2 using the same methodology used to derive the charges
3 approved by the Commission in past general rate cases. The
4 derivations of the updated charges are included in my
5 workpapers.
6 H.Al ternate Distribution Service, Schedule 46.
7 Q.Is the Company proposing any rate design
8 changes to Schedule 46, Alternate Distribution Service?
9 A.Yes. The Company is proposing to increase the
10 Capacity Charge under Schedule 46. The updated Capacity
11 Charge is derived by summing the Distribution demand
12 revenue requirement for Substations, Primary Lines, and
13 Primary Transformers for Schedule 19 Primary Service shown
14 on page 5 of Mr. Larkin's Exhibit No. 36 ($3,648,086;
15 $4,633,134; and $516,902, respectively) and dividing this
16 sum by the total billed kW of 4,848,941. This methodology
17 is the same as that used to derive the charges approved by
18 the Commission in the Company's previous general rate
19 cases. The derivation of the updated charge is included in
20 my workpapers.
21 II. IRRIGATION
22 A.Schedule 24 Aqricul tural Irrigation Service.
23 Q.What is the current rate structure for
24 Schedule 24?
25
SPARKS, DI 13
rdaho Power Company
1 A.Service under Schedule 24 is classified as
2 being either "in-season" or "out-of-season." The in-season
3 for each customer begins with the customer's meter reading
4 for the May billing period and ends with the customer's
5 meter reading for the September billing period. The out-
6 of-season encompasses all other billing periods.
7 For the in-season, customers pay a higher monthly
8 Service Charge than during the out-of-season to encourage
9 customers to continue service throughout the out-of-season
10 period.
11 Customers pay both an Energy Charge and a Demand
12 Charge for the metered usage during the in-season. The
13 Energy Charge utilizes a load-factor pricing mechanism by
14 separating charges into two energy blocks. The first block
15 charges irrigation customers a monthly rate per kWh for the
16 first 164 kWh per kW of demand. The second block charges
17 customers a lower monthly energy rate per kWh for all other
18 energy use to encourage installation of energy efficient
19 irrigation systems with reduced demand and longer hours of
20 operation. Customers pay an in-season Demand Charge only.
21 During the out-of-season, customers pay a flat Energy
22 Charge per kWh for all energy use.
23 Both Secondary Service and Transmission Service are
24 available under Schedule 24, although no customers are
25 currently taking Transmission Service.
SPARKS, DI 14
Idaho Power Company
1 Q.What is the revenue requirement to be
2 recovered from Schedule 24?
3 A.The total annual revenue to be recovered from
4 customers taking service under Schedule 24, as shown on
5 page 9 of Mr. Larkin's Exhibit No. 38, is $118,371r905.
6 Q.Please describe the rate design proposal for
7 Schedule 24.
8 A.Consistent with the overall rate design
9 obj ecti ves, the Company is proposing to move the individual
10 rate components 5 percent closer to the costs indicated by
11 Mr. Larkin's class cost-of-service study as shown on page 6
12 of Exhibit No. 36. The rate design proposal on page 9 of
13 Exhibit No. 47 targets the capped 14.85 percent average
14 revenue increase indicated on page 9 of Mr. Larkin's
15 Exhibit No. 38.
16 In addition to moving each rate component closer to
17 the cost-of-service, the Company is also proposing to
18 increase the pricing differential between energy blocks for
19 the in-season load factor pricing mechanism. Out-of-season
20 energy sales will not be impacted by the proposed change to
21 the load-factor energy rates.
22 Q.Why are you proposing to increase the
23 differential between the current load factor energy pricing
24 blocks?
25
SPARKS, DI 15
Idaho Power Company
1 A.By increasing the differential between the in-
2 season load factor energy pricing blocks, a stronger
3 pricing signal will be sent to irrigators encouraging them
4 to install and operate their irrigation systems more
5 efficiently.
6 Q.What is the current price differential between
7 the first and second load factor energy blocks?
8 A.The current price differential between the
9 first and second load factor energy blocks is 3 percent.
10 Q.What price differential is the Company
11 proposing between the first and second energy blocks?
12 A.The Company is proposing to increase the load
13 factor pricing differential from 3 percent to 6 percent in
14 order to send a stronger pricing signal to irrigators
15 encouraging them to install and operate their irrigation
16 systems more efficiently. As stated in Case No. IPC-E-08-
17 10, the 3 percent differential was established as an
18 introductory rate design to help familiarize customers with
19 the load factor pricing structure.
20 Q.How were the rates for Transmission Service
21 determined?
22 A.Once the percentage revenue change for each
23 rate component was determined for Secondary Service, the
24 same percentage changes were applied to each component for
25
SPARKS, DI 16
Idaho Power Company
1 Transmission Service to maintain the same relationship
2 between service levels as currently exists.
3 Q.Have you prepared an exhibit that shows the
4 billing impact of the rate design on Schedule 24 irrigation
5 service customers?
6 A.Yes, pages 11-13 of Exhibit No. 48 show the
7 impact on customers' bills of the proposed rate adjustments
8 for Schedule 24 Secondary Service. As can be seen from
9 Exhibit No. 48, with load factor pricing, customers with
10 the highest percentage increase in annual bills have the
11 lowest average load factors. Similarly, the higher a
12 customer's load factor, the more beneficial the rate
13 structure tends to be in terms of the overall impact to the
14 annual billing.
15 III. LIGHTING
16 Q.How have you organized the discussion of the
17 rate design proposals for area lighting, unmetered service,
18 street lighting and traffic control signal lighting?
19 A.The discussion of rate design proposals for
20 lighting will address Schedules 15 (Dusk to Dawn Customer
21 Lighting), 40 (Unmetered General Service), 41 (Street
22 Lighting Service), and 42 (Traffic Control Signal Lighting
23 Service) , respectively.
24
25
SPARKS, Dr 17
Idaho Power Company
1 A.Dusk To Dawn Customer Lighting, Schedule 15.
2 Q.What is the current rate structure for Dusk to
3 Dawn Customer Lighting under Schedule 15?
4 A.Customers taking service under Schedule 15 are
5 charged on a per lamp basis. Lamps currently served under
6 Schedule 15 include 100, 200, and 400 watt high pressure
7 sodium vapor area lighting, 200 and 400 watt high pressure
8 sodium vapor flood lighting, and 400 and 1,000 watt metal
9 halide flood lighting.
10 Q.What is the revenue requirement to be
11 recovered from customers taking service under Schedule 15?
12 A.The annual revenue requirement for Schedule 15
13 customers as shown on page 9 of Mr. Larkin's Exhibit No. 38
14 is $1,128,744.
15 Q.Have you prepared an exhibit that illustrates
16 the rate design proposal for Schedule 15?
17 A.Yes. The rate design proposal for Schedule 15
18 is included on page 5 of Exhibit No. 47 and does not
19 include any rate increases to recover the proposed revenue
20 requirement. Although no rate adjustment is required, the
21 Company is proposing to update rate components based upon
22 the actual cost-of-service for each lamp size offered under
23 Schedule 15. My workpapers detail the updated actual cost-
24 of-service for each lamp size.
25
SPARKS, Dr 18
Idaho Power Company
1 Q.rs the Company proposing any other changes to
2 Schedule 15?
3 A.Yes, the Company is proposing to update the
4 Facilities Charge from 1.75 percent to 1.51 percent to more
5 accurately reflect current costs. The derivation of the
6 updated facilities charge is addressed later in my
7 testimony.
8 Unmetered General Service, Schedule 40.B.
9 Q.What is the present rate structure for
10 Unmetered General Service under Schedule 40?
11 A.Customers taking service under Schedule 40 are
12 non-metered but have energy loads and periods of operation
13 which are fixed. A customer's estimated usage is charged a
14 flat Energy Charge. Demand- and customer-related costs are
15 also recovered through the Energy Charge. The minimum bill
16 for service under Schedule 40 is $1.50 per month. With
17 Company approval, an Intermittent Usage Charge, per unit,
18 per month, may be charged to municipalities or agencies of
19 federal, state, or county governments having the potential
20 of intermittent variations in energy usage.
21 Q.What is the revenue requirement to be
22 recovered from customers taking service under Schedule 40?
23 A.The annual revenue requirement for Schedule 40
24 customers as shown on page 9 of Mr. Larkin's Exhibit No. 38
25 is $1,174,275.
SPARKS, DI 19
Idaho Power Company
1 Q.Please describe the rate design proposal for
2 Schedule 40.
3 A.The rate design proposal for Schedule 40 is
4 included on page 11 of Exhibit No. 47. It targets the
5 proposed class revenue increase of 10.56 percent as shown
6 on page 9 of Mr. Larkin's Exhibit No. 38.
7 Q.Are any other changes being proposed to
8 Schedule 40?
9 A.Yes. The Company is proposing to remove
10 language in the Applicability section of Schedule 40
11 indicating that service under this schedule may include
12 "street and highway lighting". The Company is proposing
13 that all street lighting systems are served under Schedule
14 41, Street Lighting Service, to more accurately reflect the'
15 Company's cost to serve these types of facilities. The
16 Company is also proposing to rename Schedule 40 from
17 "Unmetered" General Service to "Non-Metered" General
18 Service in an effort to maintain consistent use of terms
19 throughout all schedules.
20 c.Street Lighting Service, Schedule 41.
21 Q.What is the present rate structure for Street
22 Lighting Service under Schedule 41?
23 A.The current rate structure for Schedule 41
24 provides two service options for street lighting customers.
25 Option "A" provides for Idaho Power-owned and Idaho Power-
SPARKS, Dr 20
Idaho Power Company
1 maintained street lighting systems. Street lighting
2 systems under this option are not metered and customers pay
3 monthly lamp charges based on their choice of standard
4 wattage high pressure sodium vapor lamps. Standard
5 wattages include 70, 100, 200, 250, and 400 watts. The
6 monthly lamp charges under Option "A" reflect the Company's
7 cost to provide energy, install the street lighting system,
8 and provide ongoing maintenance.
9 Option "B" provides for customers choosing to own
10 and install their own street lighting systems. Under this
11 option, street lighting systems may be metered or non-
12 metered. For metered systems, maintenance may be provided
13 by the customer or by Idaho Power. For non-metered
14 systems, Idaho Power provides maintenance.
15 As in Option "A", standard wattages include 70, 100,
16 200, 250, and 400 watts. The monthly lamp charges for non-
17 metered service reflect the Company's cost to provide
18 energy, install lamps, and provide ongoing maintenance of
19 the lamps only. For metered systems, customers may choose
20 to provide their own maintenance and incur a kWh charge for
21 their energy usage only or request maintenance from Idaho
22 Power. In the latter case, customers pay an additional
23 monthly maintenance ~harge based on their choice of
24 installed standard wattage high pressure sodium vapor lamps
25 (70, 100, 200, 250, and 400 watts).
SPARKS, DI 21
Idaho Power Company
1 Both Options "A" and "B" offer a monthly Non-Metered
2 Service - Variable Energy Charge for non-metered street
3 lighting systems installed prior to June 1, 2004, that
4 allow for potential or actual variation in energy use.
5 This charge is applied to the estimated usage of the
6 variable energy use to determine a separate monthly charge.
7 All systems installed on or after June 1, 2004, which allow
8 for potential or actual variation in energy usage are
9 required to be metered.
10 Q.What is the revenue requirement to be
11 recovered from customers taking service under Schedule 41?
12 A.The annual revenue requirement for Schedule 41
13 is $2,786,748 as shown on page 9 of Mr. Larkin's Exhibit
14 No. 38. The Company is not proposing a rate adj ustment to
15 recover this revenue requirement.
16 Q.Please describe the rate design proposal for
1 7 Schedule 41.
18 A.The rate design proposal for Schedule 41 is
19 included on pages 12-15 of Exhibit No. 47. These pages
20 outline the proposed new service options and monthly
21 charges for street lighting service under Schedule 41.
22 Q.Please explain why the Company is proposing to
23 modify Schedule 41 provisions and offer new service
24 options?
25
SPARKS, DI 22
rdaho Power Company
1 A.The Company is proposing to modify Schedule 41
2 in an effort to meet customer needs resulting from the
3 introduction of new and enhanced street lighting
4 technologies. In recent years, the Company has received a
5 growing number of inquiries from street lighting customers,
6 namely cities and municipalities, concerning the inability
7 of the existing street lighting rate schedule to properly
8 address energy charges and maintenance provisions related
9 to new lighting technologies.
10 Q.What specific changes is Idaho Power proposing
11 for Schedule 41?
12 A.Based on the Company's internal evaluation and
13 interaction with current street lighting customers, the
14 Company is proposing changes for street lighting service
15 that will: 1) update all existing charges to reflect the
16 current cost-of-service, 2) add language requiring that all
17 new customer-owned street lighting systems installed
18 outside of subdivisions be metered and maintained by the
19 customer, 3) modify the existing Option "B" to apply to
20 customer-owned and Idaho Power-maintained street lighting
21 systems only, and 4) add a new Option "C" for customer-
22 owned and customer-maintained street lighting systems.
23 Q.Please describe the charges that are being
24 updated in Schedule 41.
25
SPARKS, DI 23
Idaho Power Company
1 A.The Company is proposing to update the
2 accelerated replacement charge, lamp charges, meter
3 charges, energy charges, and facilities charges in an
4 effort to more accurately represent actual costs.
5 Q.How did the Company update these charges to
6 reflect the actual cost-of-service?
7 A.The Company conducted a new cost-of-service
8 analysis for the accelerated replacement charge, lamp
9 charges, meter charges, and energy charges under Schedule
10 41. The update to the facilities charge under Schedule 41
11 is described later in my testimony.
12 Q.Please describe the methodology used in cost-
13 of-service analysis to update charges.
14 A.The cost-of-service methodology used to update
15 the accelerated replacement charge, lamp charges, meter
16 charges, and energy charges determined the actual cost to
17 provide these services. The analysis examined the
18 Company's labor costs, lamp and fixture costs, maintenance
19 costs, sales taxes, overheads, vehicle costs, metering
20 costs and energy costs to determine the updated charges. A
21 complete breakout of these costs and the methodology used
22 to update charges is contained in my workpapers.
23 Q.Please describe the proposed service options
24 under the proposed Schedule 41.
25
SPARKS, DI 24
Idaho Power Company
1 A.The Company is proposing to offer three
2 service options under Schedule 41:
3 . "A" - Idaho Power-Owned, Idaho Power-4 Maintained System
5
6 . "B"- Customer-Owned, Idaho Power-Maintained7 System
8
9 . "c" - Customer-Owned, Customer-Maintained10 System
1112 Options A and B are currently offered under Schedule
13 41 while Option "c" is a newly proposed section.
14 Q.Please describe Option A.
15 A.Option A provides for non-metered, high
16 pressure sodium vapor lighting systems that are installed,
17 owned, operated, and maintained by Idaho Power. Customers
18 choosing this option are required to pay a monthly per lamp
19 charge to cover the cost of energy, materials, and
20 maintenance provided by the Company.
21 Q.Please describe the proposed updates to Option
22 A.
23 A.In an effort to clarify the requirements for
24 receiving service under Option A, the Company is proposing
25 to change the heading from "Overhead Lighting - Company-
26 Owned System" to "Idaho Power-Owned, Idaho Power-Maintained
27 System". As mentioned above, all existing lamp, pole, and
28 facilities charges have been updated to more accurately
SPARKS, DI 25
Idaho Power Company
1 reflect the current cost of providing street lighting
2 service.
3 Q.Is the Company proposing to offer any new
4 lighting technologies, such as light emitting diodes
5 (LEDs), under Option A?
6 A.No. Idaho Power is not proposing to offer new
7 lighting technologies on Idaho Power-owned street lighting
8 systems due to high product costs and unproven energy and
9 maintenance savings. Although LEDs are an attractive
10 option for customers receiving federal grants or other
11 forms of additional funding, the Company has determined
12 that the monthly charges needed to offer these products on
13 its own lighting systems would be too high to attract
14 customer participation. This was confirmed in an informal
15 assessment of existing street lighting customers.
16 Nevertheless, the Company will continue to evaluate the
17 cost, energy savings, and maintenance savings of LEDs and
18 other new lighting technologies on an ongoing basis.
19 Q.What changes are being proposed for Option B
20 in Schedule 41?
21 A.Option B has been modified to include
22 customer-owned and Idaho Power-maintained street lighting
23 systems only. This service option will only be offered to
24 existing customers that desire to have Idaho Power maintain
25 their high pressure sodium vapor street light systems. As
SPARKS, DI 26
Idaho Power Company
1 proposed, no new service will be allowed under this option
2 as the Company implements its new policy requiring that all
3 new customer-owned systems are metered and maintained by
4 the customer. Existing lighting systems under Option B may
5 be metered or non-metered.
6 Q.Why are you proposing to add Option C to
7 Schedule 41?
8 A.The proposed provisions and charges under
9 Option C are designed for customers that own their own
10 lighting systems and desire to install new and unique
11 lighting technologies and designs that are not offered by
12 the Company. This option will also allow customers with
13 non-metered systems to provide their own maintenance
14 without being charged for Idaho Power-provided maintenance,
15 as is the case under the current rate design.
16 Ultimately, over time, the Company anticipates that
17 Option C will become the primary service option for
18 customer-owned street lighting systems as it transitions to
19 requiring meters and customer-provided maintenance on all
20 new customer-owned lighting systems. This new provision
21 will provide customers greater flexibility as they seek to
22 install new and unique lighting technologies that are not
23 standard to Idaho Power.
24 Q.Is the Company proposing to require metering
25 on street lighting systems installed inside subdivisions?
SPARKS, DI 27
Idaho Power Company
1 A.No. The Company is not proposing to require
2 metering on street lighting systems installed inside
3 subdivisions for two reasons: 1) this requirement would
4 create additional maintenance costs for customers and 2)
5 this requirement would require installation of duplicate
6 infrastructure.
7 Typically, developers of subdivisions are required
8 to install street lighting systems inside subdivisions at
9 the request of municipalities or agencies of federal,
10 state, or county governments. Once installed, the
11 municipality assumes ownership of the street lighting
12 system and provides ongoing maintenance. As pointed out in
13 conversations with various cities, a requirement to install
14 meters for street lighting inside of subdivisions would
15 necessitate installation of duplicate infrastructure and
16 would not be supported by some municipalities. In many
17 cases, developers would need to install meter cabinets, a
18 second conduit/circuit system for the lighting, and in some
19 cases a third conduit/circuit for the irrigation system
20 power. In the long-term, cities would have to maintain the
21 second circuit system including dig-line markings,
22 additional junction boxes and connections, asweii as
23 . multiple meter cabinets.
24 Q.Is the Company proposing to update any other
25 charges under Schedule 41?
SPARKS, DI 28
Idaho Power Company
1 A.Yes, the Company is proposing to update all
2 charges ~n the "No New Service" section of Schedule 41 to
3 more accurately reflect the Company's cost to serve
4 customer-owned mercury vapor lamps. The derivations of
5 these updates are shown in my workpapers.
6
7
8
9
D.Traffic Control Signal Lighting Service,
Schedule 42.
Q.What is the present rate structure for Traffic
10 Control Signal Lighting Service, Schedule 42?
11 A.Customers taking service under Schedule 42 pay
12 an Energy Charge for each kWh of estimated energy use for
13 non-metered systems and for each kWh of actual usage for
14 metered systems. For non-metered systems, usage is
15 estimated based on the number and size of lamps burning
16 simultaneously in each signal and the average number of
17 hours per day the signal is operated. There is no minimum
18 charge under Schedule 42.
19 Q.What is the revenue requirement to be
20 recovered from customers taking service under Schedule 42?
21 A.The annual revenue requirement for Schedule 42
22 customers as shown on page 9 of Mr. Larkin's Exhibit No. 38
23 is $183,979.
24 Q.Please describe the rate design proposal for
25 Schedule 42.
SPARKS, DI 29
Idaho Power Company
1 A.The rate design proposal for Schedule 42 is
2 included on page 16 of Exhibit No. 47. It targets the
3 proposed capped class revenue increase of 14.85 percent
4 shown on page 9 of Mr. Larkin's Exhibit No. 38.
5 iv. RULE H
6 Q.What changes to Rule H, New Service
7 Attachments and Distribution Line Installations or
8 Alterations, is the Company proposing?
9 A.The Company is proposing to remove the 1.5
10 percent limitation for recovery of general overhead costs
11 in the Work Order Cost definition of Rule H. The Company
12 instead proposes to recover all actual general overhead
13 costs related to construction under Rule H.
14 This proposal was most recently requested in Case
15 No. IPC-E-08-22 in an effort to recover general overhead
16 costs related to new service attachments and line
17 installations. In Order No. 30853, the Commission agreed
18 that "customers requesting Rule H line extensions should
19 bear the overhead costs of those line extensions"; however,
20 the "appropriate calculations and adjustments are best made
21 during the Company's next general rate case to ensure that
22 rates are set based on costs that do not include the
23 portion of construction overhead belonging to Rule H work
24 orders". Order No. 30853, p. 11.
25
SPARKS, DI 30
Idaho Power Company
1 Q.What is the current general overhead rate for
2 new service attachments and line installations under Rule
3 H?
4 A.The Company's current general overhead rate
5 for construction related to new service attachments and
6 line installations is 22.00 percent.
7 Q.Is this the overhead rate the Company is
8 proposing to include on all Rule H work orders?
9 A.Yes it is.
10 Q.Why is the current and effective cap of 1.5
11 percent on general overhead costs so low when compared to
12 the actual general overhead rate?
13 A.The current cap on general overheads is
14 misaligned for a couple of reasons. First, the cap was
15 originally established in Case No. IPC-E-95-18 and expenses
16 have changed greatly since 1995. Also, as explained to me
17 by Mr. Gregory W. Said, the Commission capped the general
18 overhead rate in Case No. IPC-E-95-18 at 1.5 percent to
19 avoid double collection of engineering charges.
20 Q.Are engineering fees included in the proposed
21 collection rate for general overheads?
22 A.No. Engineering fees are currently charged
23 directly to work orders and are not included in the
24 Company's determination of general overheads. This was
25
SPARKS, DI 31
Idaho Power Company
1 audited and confirmed by the Commission's Staff in Case No.
2 IPC-E-08-22.
3 Q.Please provide a detailed explanation of how
4 general overhead costs are determined.
5 A.Overhead costs are pooled costs that are
6 incurred in support of the Company's construction process,
7 but would be very difficult to directly associate to a
8 particular construction job. These costs are accumulated
9 and allocated back to construction jobs based on a cost
10 allocation methodology. It is Idaho Power's policy, per
11 Code of Federal Regulations, Title 18, Part 101, Electric
12 Plant Instructions, to apply overheads to construction work
13 orders.
14 "18 CFR Part 101 Electric Plant Instructions
15 (4) (2007) allows the pay and expenses of the general
16 officers , administrative workers, engineering supervisors
17 and other engineering services applicable to construction
18 work to be charged to construction." As a result, some of
19 the construction related-employees that support Rule H type
20 proj ects charge a portion of their wages and other expenses
21 to overhead (FERC account 107). Each cost center that is
22 invol ved in the construction process has a separate
23 overhead work order that employees charge to for general
24 support tasks that benefit both operations and the
25 construction process. These work orders are allocated
SPARKS, DI 32
Idaho Power Company
1 based on yearly studies of the actual split between direct
2 operations and maintenance ("O&M") and direct capital work
3 performed by the cost center. The amount of overhead are
4 bucketed and monitored monthly by leaders to assure that
5 only reasonable and prudent costs are charged to the
6 accounts. Through the use of these overhead work orders,
7 the Company determines the amount each cost center has
8 contributed to overheads.
9 The Company accumulates the budgeted overheads,
10 groups them by contributing functional area, and divides
11 them by the budgeted construction projects during the same
12 period, by work order type, to create the overhead rate.
13 The Company has a separate overhead rate for Co-Generation,
14 Stations, Transmission Lines, and Distribution Lines. The
15 Distribution Line rate applies to the Rule H work orders.
16 Q.Please explain how general overheads are
1 7 recovered.
18 A.The Company's general overheads are recovered
19 per 18 CFR Part 101 Electric Plant Instructions (4) (2007),
20 to apply overheads to construction work orders. Overhead
21 costs are applied back to actual construction jobs based on
22 the methodology described previously.
23 When capital work orders are completed, the overhead
24 charges that have been allocated to those work orders are
25 closed to the individual plant accounts based on the
SPARKS, 01 33
Idaho Power Company
1 property units on the work order.At this point the
2 overheads become part of Idaho Power's rate base.
3 Q.How often does the Company update its general
4 overhead rate for Rule H construction?
5 A.General overhead rates are updated
6 periodically depending on significant changes in costs.
7 Q.If Idaho Power was allowed to charge its
8 actual general overhead rate for Rule H construction, would
9 the periodic updates to general overheads be reflected in
10 Rule H work orders?
11 A.Yes. If approved, any accounting adjustments
12 (increases or decreases) to general overhead rates would be
13 automatically reflected in the Company's work order
14 processing and accounting systems.
15 V. FACILITIES CHAGES
16 Q.What change is the Company proposing to
17 facili ties charges?
18 A.The Company is proposing to update the rates
19 that customers pay under Idaho Power's facilities charge'
20 provisions to more accurately reflect the Company's current
21 costs to offer this service.
22 Q.When was the last time the facilities charge
23 rates were reviewed by the Commission?
24 A.The facilities charge rates were last reviewed
25 by the Commission in 1987 in Case No. U-1006-298.
SPARKS, DI 34
Idaho Power Company
1 Subsequent Order No. 21836 reaffirmed that the monthly
2 facili ties charge rates of 1. 75 percent for Schedule 15 and
3 41 and 1. 7 percent for Schedule 19 were reasonable and
4 should continue.
5 Q.Please explain Idaho Power's existing
6 facilities charge provisions.
7 A.At the option of the Company, facilities
8 charges may be offered to Primary and Transmission Service
9 level customers under Schedule 9 (Large General Service)
10 and Schedule 19 (Large Power Service). Facilities charges
11 may be offered to Transmission Service level customers only
12 under Schedule 24 (Agricultural Irrigation Service). If
13 offered, and in consideration of a Customer paying a
14 monthly facilities charge, the Company will own, operate,
15 and maintain facilities installed beyond Idaho Power's
16 Point of Delivery.
17 As of June 1, 2004, customers taking service under
18 Schedule 15 (Dusk to Dawn Customer Lighting) and Schedule
19 41 (Street Lighting Service) were no longer eligible for
20 facili ties charges although some customers continue to pay
21 monthly facilities charges for facilities installed prior
22 to June 1, 2004.
23 Q.What rates do eligible customers pay under the
24 current facilities charge provisions?
25
SPARKS, DI 35
Idaho Power Company
1 A.Customers taking Primary or Transmission
2 Service under Schedules 9 and 19 and Transmission Service
3 under Schedule 24, pay a facilities charge rate of 1. 7
4 percent per month of the Company's total investment in
5 facilities installed beyond Idaho Power's Point of
6 Delivery.
7 Customers taking service under Schedules 15 and 41
8 pay a facilities charge rate of 1. 75 percent per month of
9 the Company's investment in facilities installed prior to
10 June 1, 2004. Eligible facilities installed under
11 Schedules 15 and 41 included overhead secondary, poles,
12 anchors, and underground circuits. Costs for these
13 facili ties are charged through work orders.
14 Q.What monthly rates is the Company proposing
15 for facilities charges?
16 A.The Company is proposing to update the monthly
17 facilities charge rate to 1.41 percent for customers taking
18 Primary or Transmission Service under Schedules 9 and 19.
19 The Company is also proposing a rate of 1.41 percent for
20 customers taking Transmission Service under Schedule 24.
21 For customers taking service under Schedule 15, the
22 Company is proposing a rate of 1.51 percent per month and
23 for Schedule 41, the Company is proposing a rate of 1.21
24 percent per month.
25
SPARKS, DI 36
Idaho Power Company
1 Q.What cost components were used to update the
2 current facilities charge rates?
3 A.The cost components used to update the
4 facili ties charge rates include:
5 . Rate of Return
6 . Depreciation
7 . Income Taxes
8 . Property Taxes
9 . Other Taxes (Regulatory Fees)
10 . Operation and Maintenance Expenses
11 . Administration and General Expenses
12 . Working Capital
13 . Insurance
14 Q.Are these the same cost components that were
15 reviewed and considered reasonable by the Commission in its
16 most recent review of Idaho Power' s facilities charge
17 rates?
18 A.Yes. These are the same cost components that
19 the Company presented in Case No. U-1006-298 to validate
20 the Company's current facilities charge rates.
21 Q.Please describe the individual cost components
22 that are used to derive the Company's facilities charges.
23 A.The cost components used to derive the
24 Company's facilities charges are the same components
SPARKS, DI 37
Idaho Power Company
1 included in the Company's revenue requirement for like
2 facili ties. Descriptions of each cost component are as
3 follows:
4 Rate of Return - Idaho Power's cost of financing its
5 original investment in facilities. This uses a weighted
6 average of the Company's cost of debt and cost of equity.
7 The facilities charge methodology uses a level payment
8 stream to simplify the rate calculation and the
9 administration of the facilities charge. The Rate of
10 Return used to determine the facilities charge will be the
11 Rate of Return ordered by the Commission in this filing.
12 Booked Depreciation - The straight-line annual
13 depreciation of assets based on a levelized 31 year basis.
14 Income Taxes - The tax that Idaho Power pays on the
15 amount of revenue received from the equity portion of the
16 Rate of Return.
17 Property Taxes - The tax that Idaho Power pays for
18 its distribution facilities. Each dollar the Company
19 invests beyond the Point of Delivery is assessed property
20 taxes.
21 Other Taxes (Regulatory Fees) - The taxes and fees
22 that Idaho Power pays to the Idaho and Oregon public
23 utili ties commissions. A portion of these fees is tied to
24 the Company's distribution investment which includes
25
SPARKS, DI 38
Idaho Power Company
1 facili ties installed beyond the Company's Point of
2 Delivery.
3 Operation and Maintenance Expenses - Includes all of
4 Idaho Power's costs to operate and maintain its
5 distribution facilities. This cost component represents an
6 average maintenance rate for all distribution equipment.
7 Administration and General Expenses - Represents an
8 expense based on total Administration and General as a
9 percentage of total plant investment.
10 Working Capital - Working Capital is the carrying
11 cost of inventory. Working Capital is based on the cost of
12 capital to finance the distribution facilities inventory
13 and the property taxes that the Company pays on its
14 inventory.
15 Insurance - The insurance rate reflects the
16 additional cost Idaho Power incurs for insurance premiums
17 resul ting from facilities installed beyond the Company's
18 Point of Delivery. This insurance rate covers property,
19 casualty, and worker's compensation. It does not cover
20 facili ty replacement costs for failed facilities.
21 Q.What are the proposed percentage amounts for
22 each cost component by rate class?
23 A.The proposed percentage amounts used to derive
24 the proposed facilities charge rates are as follows:
25
SPARKS, DI 39
Idaho Power Company
Cost Components Rate 15 Rate 19 Rate 41
1 Rate of Return 4.81%4.81%
2 Book Depreciation 3.23%
3 Income Taxes 1. 90%
4 Property Taxes 0.56%
5 Other Taxes (Regulatory Fees)0.14%
6 Operation & Maintenance 4.73%
7 Administration & General 2.28%
8 Working Capital 0.14%
9 Insurance 0.32%
10 Annual Total 18.10%
11 Monthly Rate 1.51%1.21%
1
2 Q.Please explain why Schedules 9 and 24 are not
3 identified in the table.
4 A.Under Idaho Power's approved rate schedules,
4.81%
3.23%
1.90%
0.56%
0.14%
3.58%
2.28%
0.14%
0.32%
17.00%
1.41%
3.23%
1.90%
0.56%
0.14%
1. 18%
2.28%
0.14%
0.32%
14.60%
5 the facilities charge rates for Schedules 9 and 24 are
6 aligned with the derived rate for Schedule 19. The Company
7 and the Commission, through previous orders, have
8 determined that the facilities charge rate for Schedule 19
9 accurately reflects facilities charge costs under Schedules
10 9 and 24.
11 Q.What cost component has driven the proposed
12 reduction in the facilities charge rates?
SPARKS, DI 40
Idaho Power Company
1 A.The primary cost component that has driven the
2 reduction in the facilities charge rates is the Rate of
3 Return, which has decreased since the last update.
4 Q.What is the estimated reduction in the
5 Company's revenue from the proposed facilities charge
6 rates?
7 A.The estimated reduction in revenue received
8 through facilities charges under the Company's proposal is
9 approximately $1.1 million per year.
10 Q.How will the reduction in revenue for
11 facilities charges affect the energy rates of customer
12 classes?
13 A.The reduction in revenue will result in
14 increases in the revenue requirements for each customer
15 class that collects facilities charge revenue, namely
16 Schedules 9, 15, 19, 24, and 41. In turn, the energy rates
17 for these customer classes will increase slightly to
18 recover the decline in facilities charge revenue.
19 Q.Does this conclude your testimony?
20 A.Yes it does.
21
22
23
24
25
SPARKS, DI 41
Idaho Power Company
RECEIVED
BEFORE THE lOll JUN -1 PM 2=48
, t-ri.i \,Qi~;J~~C);y;tJ3
IDAHO PUBLIC UTiliTIES COM'MlSSIUN
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
-
SPARKS, 01
TESTIMONY
EXHIBIT NO. 47
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Z3tt JUri -I PM 2= 48
! !ï!i i!L1;'~r.tq¿2~iri!';,( s
IDAHO PUBLIC UTILITIES COMMISSI-ON
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
SPARKS, 01
TESTIMONY
EXHIBIT NO. 48
Idaho Power Company
Typical Monthly Biling Comparison
State of Idaho
General Rate Case
Filed June 1, 2011
Schedule 7, Small General Service
(1 )(2)(3)(4)(5)(6)(7)(8)(9)
Summer Non-Summer Avg Mth Cost -12 Mths
Line Energy Current Proposed Percent Current Proposed Percent Current Proposed Percent
No kWh Revenue Revenue Difference Revenue Revenue Difference Revenue Revenue Difference
1 100 12,31 14.46 17.47%12.31 14.46 17.47%12,31 14.46 17.47%
2 200 20.62 23.92 16.01%20.62 23.92 16,01%20.62 23.92 16.00%
3 300 28,92 33.37 15.39%28.92 33.37 15.39%28.92 33.37 15.39%
4 400 38.81 44.74 15.28%37.70 43.32 14.90%37.98 43.68 15.01%
5 500 48.70 56,11 15.21%46.48 53,27 14.60%47.04 53.98 14.75%
6 600 58.60 67.48 15,17%55.27 63.22 14.39%56.10 64.28 14.58%
7 700 68.49 78.85 15.14%64,05 73,17 14.24%65.16 74.59 14:47%
8 800 78.38 90.22 15.11%72.83 83.11 14.12%74.22 84.89 14.38%
9 900 88.27 101.59 15.10%81.61 93.06 14.03%83.27 95.20 14.33%
10 1,000 98.16 112,96 15.08%90.39 103.01 13.96%92.33 105.50 14.26%
11 1,100 108.05 124.33 15.07%99.17 112.96 13.90%101.39 115.80 14.21%
12 1,200 117.94 135.70 15.06%107.95 122.91 13.85%110.45 126.11 14.18%
13 1,300 127,83 147,08 15.05%116,73 132,86 13,81%119,51 136.41 14.14%
14 1,400 137.72 158.45 15,05%125.51 142.80 13.78%128,57 146.71 14.11%
15 1,500 147.62 169,82 15.04%134,30 152.75 13.74%137,63 157.02 14.09%
16 2,000 197.07 226,67 15,02%178.20 202.49 13.63%182.92 208.54 14.01%
17 2,500 246.53 283.52 15.00%222.11 252.24 13.57%228.21 260.06 13,96%
18 3,000 295.98 340.37 15,00%266.01 301.98 13.52%273.50 311.58 13.92%
19 4,000 394.89 454.07 14.99%353.82 401.46 13.46%364.09 414.61 13,88%
20 5,00 493.80 567.77 14.98%441.63 500.94 13.43%454.68 517,65 13,85%
Exhibit No. 48
Case No. IPC-E-11-08
S. Sparks, IPC
Page 1 of 13
Idaho Power Company
Typical Monthly Biling Comparison
State of Idaho
General Rate Case
Filed June 1, 2011
Schedule 9, Large General Service - Secondary
Summer
(1 )(2)(3)(4)
Line Demand BLC Load Energy Current Proposed Difference Percent
No kW kW Factor kWh Rate Rate m.Difference
1 10 11 20%1,440 144.21 150.51 6.30 4.37%
2 35%2,520 214.77 223.65 8.88 4.13%
3 50%3,600 256.50 266.91 10.41 4.06%
4 65%4,680 298.23 310.17 11,94 4.00%
5 80%5,760 339.96 353.43 13.47 3.96%
6 50 57 20%7,200 562.76 619.20 56.44 10.03%
7 35%12,600 771.41 835.50 64.09 8.31%
8 50%18,000 980.06 1,051.80 71,74 7.32%
9 65%23,400 1,188.71 1,268.10 79.40 6.68%
10 80%28,800 1,397.36 1,484.41 87.05 6.23%
11 100 114 20%14,400 1,115.92 1,249.89 133.97 12.01%
12 35%25,200 1,533.22 1,682.50 149.28 9.74%
13 50%36,000 1,950.52 2,115.10 164.58 8.44%
14 65%46,800 2,367.82 2,547.70 179.88 7.60%
15 80%57,600 2,785.12 2,980.31 195.19 7.01%
16 300 342 20%43,200 3,328.56 3,772.66 444.10 13.34%
17 35%75,600 4,580.46 5,070.48 490.01 10.70%
18 50%108,000 5,832.37 6,368.29 535.92 9.19%
19 65%140,400 7,084.27 7,666.11 581.83 8.21%
20 80%172,800 8,336.18 8,963.92 627.75 7.53%
21 500 570 20%72,000 5,541.20 6,295.44 754.23 13.61%
22 35%126,000 7,627.71 8,458.46 830.75 10.89%
23 50% 180,000 9,714.22 10,621.48 907.27 9.34%
24 65% 234,000 11,800.72 12,784.51 983.79 8.34%
25 80% 288,000 13,887.23 14,947.53 1,060.30 7.64%
26 750 855 20% 108,000 8,307.01 9,448.90 1,141.89 13.75%
27 35% 189,000 11,436.77 12,693.44 1,256.67 10.99%
28 50% 270,000 14,566.53 15,937.97 1,371.45 9.42%
29 65% 351,000 17,696.29 19,182.51 1,486,23 8.40%
30 80% 432,000 20,826.04 22,427,05 1,601,00 7.69%
Exhibit No. 48
Case No, IPC-E-11-08
S. Sparks, fPC
Page 2 of 13
Idaho Power Company
Typical Monthly Biling Comparison
State of Idaho
General Rate Case
Filed June 1, 2011
Schedule 9, Large General Service - Secondary
Non-Summer
(1 )(2)(3)(4)
Line Demand BLC Load Energy Current Proposed Difference Percent
No kW kW Factor kWh Rate Rate 2-1 Difference
1 10 11 20%1,440 130.22 136.21 5.99 4.60%
2 35%2,520 193,17 201.56 8.40 4.35%
3 50%3,600 230.39 240.22 9.83 4.27%
4 65%4,680 267.61 278.87 11.27 4.21%
5 80%5,760 304.83 317.53 12.70 4.17%
6 50 57 20%7,200 493.72 530.96 37.24 7.54%
7 35%12,600 679.82 724.24 44.41 6.53%
8 50%18,000 865.93 917,51 51.59 5,96%
9 65%23,400 1,052.03 1,110.79 58.76 5.59%
10 80%28,800 1,238.14 1,304,07 65.93 5,32%
11 100 114 20%14,400 970.32 1,053,95 83.64 8.62%
12 35%25,200 1,342.53 1,440.51 97.98 7.30%
13 50%36,000 1,714.74 1,827.06 112.32 6.55%
14 65%46,800 2,086,95 2,213.61 126,66 6.07%
15 80%57,600 2,459,16 2,600.17 141.00 5.73%
16 300 342 20%43,200 2,876,72 3,145,92 269.20 9.36%
17 35%75,600 3,993.35 4,305.58 312.23 7.82%
18 50%108,000 5,109.99 5,465.24 355.26 6.95%
19 65%140,400 6,226.62 6,624.90 398.28 6.40%
20 80%172,800 7,343.26 7,784.57 441.31 6.01%
21 500 570 20%72,000 4,783.12 5,237.89 454.77 9.51%
22 35%126,000 6,644.18 7,170,66 526.48 7.92%
23 50% 180,000 8,505.24 9,103.43 598.19 7.03%
24 65% 234,000 10,366.29 11,036.20 669.90 6.46%
25 80% 288,000 12,227.35 12,968.96 741,62 6.07%
26 750 855 20% 108,000 7,166,13 7,852.85 686.73 9.58%
27 35% 189,000 9,957.71 10,752.01 794.29 7,98%
28 50% 270,000 12,749,30 13,651.16 901.86 7.07%
29 65% 351,000 15,540.88 16,550,31 1,009.43 6,50%
30 80% 432,000 18,332.46 19,449.46 1,117.00 6.09%
Exhibit No. 48
Case No. IPC-E-11-08
S. Sparks, IPC
Page 3 of 13
Idaho Power Company
Typical Monthly Biling Comparison
State of Idaho
General Rate Case
Filed June 1, 2011
Schedule 9, large General Service - Secondary
Weighted Monthly Average
(1 )(2)(3)(4)
Line Demand BlC load Energy Current Proposed Difference Percent
No kW kW Factor kWh Rate Rate m.Difference
1 10 11 20%1,440 133.71 139.78 6.07 4.54%
2 35%2,520 198.57 207.08 8.52 4.29%
3 50%3,600 236.91 246,89 9.98 4.21%
4 65%4,680 275.26 286.70 11.44 4.15%
5 80%'5,760 313.61 326,50 12.89 4.11%
6 50 57 20%7,200 510.98 553,02 42.04 8.23%
7 35%12,600 702,72 752.05 49,33 7.02%
8 50%18,000 894.46 951.09 56.63 6.33%
9 65%23,400 1,086.20 1,150.12 63.92 5.88%
10 80%28,800 1,27794 1,349.15 71.21 5.57%
11 100 114 20%14,400 1,006.72 1,102,94 96.22 9.56%
12 35%25,200 1,390.20 1,501,00 110.80 7.97%
13 50%36,000 1,773.69 1,899,07 125.39 7.07%
14 65%46,800 2,157.17 2,297.14 139,97 6.49%
15 80%57,600 2,540.65 2,695.20 154,55 6.08%
16 300 342 20%43,200 2,989.68 3,302.61 312.93 10.47%
17 35%75,600 4,140.13 4,496,81 356.67 8.62%
18 50%108,000 5,290.58 5,691.01 400,42 7.57%
19 65%140,400 6,441.03 6,885.21 444.17 6.90%
20 80%172,800 7,591.49 8,079.40 487.92 6.43%
21 500 570 20%72,000 4,972.64 5,502,28 529,63 10.65%
22 35%126,000 6,890.06 7,492.61 602.55 8.75%
23 50% 180,000 8,807.48 9,482.94 675,46 7.67%
24 65% 234,000 10,724.90 11,473.27 748.37 6.98%
25 80% 288,000 12,642.32 13,463.61 821.29 6.50%
26 750 855 20% 108,000 7,451.35 8,251.87 800.52 10.74%
27 35% 189,000 10,327.48 11,237.36 909,89 8.81%
28 50% 270,000 13,203.60 14,222.86 1,019.26 7.72%
29 65% 351,000 16,079.73 17,208.36 1,128.63 7,02%
30 80% 432,000 18,955.86 20,193.86 1,238.00 6.53%
Exhibit No. 48
Case No. IPC-E-11-08
S. Sparks, IPC
Page 4 of 13
Idaho Power Company
Typical Monthly Biling Comparison
State of Idaho
General Rate Case
Filed June 1, 2011
Schedule 9, large General Service - Primary
Summer
On-Peak (1 )(2)(3)(4)
Line Demand Demand BlC load Energy Current Proposed Difference Percent
No kW kW kW Factor kWh Rate Rate m.Difference
1 400 358 460 40%115,200 6,754.94 7,870,76 1,115.83 16,52%
2 50%144,000 7,758.27 8,998.90 1,240.63 15.99%
3 60%172,800 8,761.61 10,127.04 1,365.43 15.58%
4 70%201,600 9,764.94 11,255.18 1,490.23 15.26%
5 80%230,400 10,768,28 12,383,31 1,615.03 15.00%
6 500 448 575 40%144,000 8,381,85 9,J61.20 1,379,35 16.46%
7 50%180,000 9,636.02 11,171.38 1,535.35 15.93%
8 60%216,000 10,890,19 12,581.55 1,691,36 15.53%
9 70%252,000 12,144.36 13,991.72 1,847.36 15.21%
10 80%288,000 13,398.53 15,401.89 2,003.36 14,95%
11 600 538 690 40%172,800 10,008.77 11,651.64 1,642.88 16.41%
12 50%216,000 11,513.77 13,343.85 1,830.08 15.89%
13 60%259,200 13,018.78 15,036.06 2,017.28 15,50%
14 70%302,400 14,523,78 16,728,26 2,204.48 15.18%
15 80%345,600 16,028,79 18,420,47 2,391.68 14.92%
16 700 627 805 40%201,600 11,635.68 13,542.09 1,906.40 16.38%
17 50%252,000 13,391,52 15,516.33 2,124,80 15.87%
18 60%302,400 15,147,36 17,490.57 2,343.21 15.47%
19 70%352,800 16,903.20 19,464,81 2,561.61 15.15%
20 80%403,200 18,659.04 21,439.05 2,780.01 14.90%
21 800 717 920 40%230,400 13,262.60 15,432,53 2,169.93 16,36%
22 50%288,000 15,269,27 17,688,80 2,419.53 15,85%
23 60%345,600 17,275.95 19,945.08 2,669.13 15.45%
24 70%403,200 19,282,62 22,201.35 2,918.73 15.14%
25 80%460,800 21,289.29 24,457.63 3,168.34 14.88%
26 900 806 1,035 40%259,200 14,889.52 17,322.97 2,433.45 16.34%
27 50%324,000 17,147.02 19,861.28 2,714.25 15.83%
28 60%388,800 19,404.53 22,399.59 2,995.06 15.43%
29 70%453,600 21,662.04 24,937.90 3,275.86 15,12%
30 80%518,400 23,919.54 27,476.21 3,556.66 14.87%
Exhibit No. 48
Case No. IPC-E-11-08
S. Sparks, IPC
Page 5 of 13
Idaho Power Company
Typical Monthly Billng Comparison
State of Idaho
General Rate Case
Filed June 1,2011
Schedule 9, large General Service - Primary
Non-Summer
(1 )(2)(3)(4)
Line Demand BlC load Energy Current Proposed Difference Percent
No kW kW Factor kWh Rate Rate 2-1 Difference
1 400 503 40%115,200 5,791.42 6,656.92 865.50 14.94%
2 50%144,000 6,645.69 7,621.52 975.83 14.68%
3 60%172,800 7,499.97 8,586.11 1,086.15 14.48%
4 70%201,600 8,354.24 9,550.71 1,196.47 14.32%
5 80%230,400 9,208.52 10,515.31 1,306.79 14.19%
6 500 628 40%144,000 7,177.45 8,243.90 1,066.45 14.86%
7 50%180,000 8,245,30 9,449,65 1,204.35 14.61%
8 60%216,000 9,313.14 10,655,39 1,342.25 14.41%
9 70%252,000 10,380.99 11,861.14 1,480.15 14.26%
10 80%288,000 11,448.83 13,066.88 1,618.05 14.13%
11 600 754 40%172,800 8,563,49 9,830.88 1,267.39 14.80%
12 50%216,000 9,844,90 11,277.78 1,432.87 14.55%
13 60%259,200 11,126,32 12,724.67 1,598.36 14.37%
14 70%302,400 12,407.73 14,171,57 1,763,84 14.22%
15 80%345,600 13,689,14 15,618.46 1,929.32 14.09%
16 700 880 40%201,600 9,949.53 11,417.86 1,468.34 14.76%
17 50%252,000 11,444,51 13,105.91 1,661.40 14.52%
18 60%302,400 12,939.49 14,793.95 1,854.46 14.33%
19 70%352,800 14,434.47 16,481.99 2,047.52 14,18%
20 80%403,200 15,929.45 18,170,04 2,240.58 14.07%
21 800 1,005 40%230,400 11,335,56 13,004.84 1,669.28 14.73%
22 50%288,000 13,044.12 14,934.04 1,889.92 14,49%
23 60%345,600 14,752,67 16,863.23 2,110.56 14.31%
24 70%403,200 16,461.22 18,792.42 2,331.21 14.16%
25 80%460,800 18,169.77 20,721.62 2,551.85 14.04%
26 900 1,131 40%259,200 12,721.60 14,591.82 1,870.22 14.70%
27 50%324,000 14,643.72 16,762.17 2,118.45 14.47%
28 60%388,800 16,565.84 18,932.51 2,366,67 14.29%
29 70%453,600 18,487.96 21,102.85 2,614.89 14.14%
30 80%518,400 20,410.08 23,273.19 2,863.11 14.03%
Exhibit No. 48
Case No. IPC-E-11-08
S. Sparks, IPC
Page 6 of 13
Idaho Power Company
Typical Monthly Biling Comparison
State of Idaho
General Rate Case
Filed June 1,2011
Schedule 9, Large General Service - Primary
Weighted Monthly Average
(1 )(2)(3)(4)
Line Demand Load Energy Curr Proposed Difference Percent
No kW Factor kWh Rate Rate m.Difference
1 400 50%144,000 6,032,30 6,960.38 928.09 15,39%
2 60%172,800 6,923.84 7,965.86 1,042.03 15,05%
3 70%201,600 7,815.38 8,971.35 1,155.97 14,79%
4 80%230,400 8,706.92 9,976.83 1,269.91 14.59%
5 90%259,200 9,598.46 10,982.31 1,383.85 14.42%
6 500 50%180,000 7,478,55 8,623.23 1,144.67 15.31%
7 60%216,000 8,592.98 9,880.08 1,287.10 14.98%
8 70%252,000 9,707.40 11,136.93 1,429,53 14.73%
9 80%288,000 10,821.83 12,393.78 1,571.95 14.53%
10 90%324,000 11,936.26 13,650.64 1,714.38 14.36%
11 600 50%216,000 8,924.81 10,286.07 1,361.26 15.25%
12 60%259,200 10,262.12 11,794.30 1,532.17 14.93%
13 70%302,400 11,599.43 13,302.52 1,703.09 14,68%
14 80%345,600 12,936.74 14,810.74 1,874.00 14.49%
15 90%388,800 14,274.05 16,318.96 2,044.91 14.33%
16 700 50%252,000 10,371.07 11,948.92 1,57785 15.21%
17 60%302,400 11,931.26 13,708.51 1,777.25 14.90%
18 70%352,800 13,491,46 15,468.11 1,976.65 14.65%
19 80%403,200 15,051.65 17,227,70 2,176.04 14.46%
20 90%453,600 16,611,85 18,987,29 2,375.44 14.30%
21 800 50%288,000 11,817,32 13,611,76 1,794.44 15.18%
22 60%345,600 13,600.40 15,622.73 2,022.32 14.87%
23 70%403,200 15,383.49 17,633.69 2,250.21 14.63%
24 80%460,800 17,166.57 19,644.65 2,478.09 14.44%
25 90%518,400 18,949.65 21,655.62 2,705.97 14.28%
26 900 50%324,000 13,263.58 15,274.61 2,011.03 15.16%
27 60%388,800 15,269.55 17,536.94 2,267.40 14.85%
28 70%453,600 17,275.51 19,799.28 2,523,77 14.61%
29 80%518,400 19,281.48 22,061.61 2,780.13 14.42%
30 90%583,200 21,287,44 24,323,95 3,036.50 14,26%
Exhibit No. 48
Case No. IPC-E-11-08
S. Sparks, IPC
Page 7 of 13
Idaho Power Company
Typical Monthly Billng Comparison
State of Idaho
General Rate Case
Filed June 1,2011
Schedule 19, Large Power Service - Primary
Summer
On-Peak (1 )(2)(3)(4)
Line Demand Demand BLC Load Energy Current Proposed Difference Percent
No kW kW kW Factor kWh Rate Rate m.Difference
1 1,000 917 1,100 50%360,000 18,361.78 22,149.62 3,787.84 20.63%
2 60%432,000 20,745.36 24,798.73 4,053.37 19.54%
3 70%504,000 23,128.94 27,447.85 4,318.90 18.67%
4 80%576,000 25,512.53 30,096.96 4,584.43 17.97%
5 90%648,000 27,896.11 32,746.08 4,849.97 17.39%
6 2,500 2,293 2,750 50%900,000 45,533.54 54,885.04 9,351.51 20.54%
7 60%1,080,000 51,492.50 61,507.83 10,015.34 19.45%
8 70%1,260,000 57,451.46 68,130.62 10,679.16 18.59%
9 80%1,440,000 63,410.42 74,753.41 11,342,99 17.89%
10 90%1,620,000 69,369.38 81,376.20 12,006,82 17.31%
11 4,000 3,670 4,399 50%1,440,000 72,705.29 87,620.47 14,915.17 20.51%
12 60%1,728,000 82,239.63 98,216.93 15,977,30 19.43%
13 70%2,016,000 91,773.97 108,813.39 17,039.42 18.57%
14 80%2,304,000 101,308.30 119,409.85 18,101.55 17.87%
15 90%2,592,000 110,842.64 130,006.32 19,163.68 17.29%
16 5,500 5,046 6,049 50%1,980,000 99,877.05 120,355.89 20,478,84 20.50%
17 60%2,376,000 112,986.77 134,926.03 21,939,26 19.42%
18 70%2,772,000 126,096.48 149,496.16 23,399.68 18,56%
19 80%3,168,000 139,206.19 164,066.30 24,860,11 17.86%
20 90%3,564,000 152,315.90 178,636.43 26,320,53 17.28%
21 7,000 6,422 7,699 50%2,520,000 127,048.81 153,091.32 26,042.50 20.50%
22 60%3,024,000 143,733.90 171,635.13 27,901,22 19.41%
23 70%3,528,000 160,418.99 190,178.93 29,759.94 18.55%
24 80%4,032,000 177,104.08 208,722.74 31,618,66 17.85%
25 90%4,536,000 193,789.17 227,266.55 33,477.38 17.28%
26 8,500 7,798 9,349 50%3,060,000 154,220.57 185,826.74 31,606.17 20.49%
27 60%3,672,000 174,481.04 208,344.22 33,863.19 19.41%
28 70%4,284,000 194,741.50 230,861.71 36,120.20 18.55%
29 80%4,896,000 215,001.97 253,379.19 38,377.22 17.85%
30 90%5,508,000 235,262.43 275,896.67 40,634,24 17.27%
Exhibit No. 48
Case No. IPC-E-11-08
S. Sparks, IPC
Page 8 of 13
Idaho Power Company
Typical Monthly Billng Comparison
State of Idaho
General Rate Case
Filed June 1, 2011
Schedule 19, large Power Service - Primary
Non-Summer
(1 )(2)(3)(4)
Line Demand BlC Load Energy Current Proposed Difference Percent
No kW kW Factor kWh Rate Rate 2-1 Difference
1 1,000 1,171 50%360,000 15,515,05 17,661.81 2,146,77 13.84%
2 60%432,000 17,524.41 19,900.64 2,376.24 13.56%
3 70%504,000 19,533.77 22,139.47 2,605.70 13.34%
4 80%576,000 21,543.13 24,378.30 2,835.17 13,16%
5 90%648,000 23,552.49 26,617.13 3,064.64 13.01%
6 2,500 2,926 50%900,000 38,416,71 43,665.53 5,248.82 13.66%
7 60%1,080,000 43,440.12 49,262.61 5,822.49 13.40%
8 70%1,260,000 48,463,52 54,859.68 6,396,17 13.20%
9 80%1,440,000 53,486,92 60,456.76 6,969.84 13.03%
10 90%1,620,000 58,510.33 66,053.83 7,543.51 12.89%
11 4,000 4,682 50%1,440,000 61,318.38 69,669.25 8,350.88 13.62%
12 60%1,728,000 69,355,82 78,624.57 9,268.75 13.36%
13 70%2,016,000 77,393.27 87,579.89 10,186.63 13.16%
14 80%2,304,000 85,430,71 96,535.22 11,104.50 13.00%
15 90%2,592,000 93,468.16 105,490,54 12,022,38 12.86%
16 5,500 6,438 50%1,980,000 84,220.04 95,672.97 11,452.93 13,60%
17 60%2,376,000 95,271.53 107,986.54 12,715.01 13.35%
18 70%2,772,000 106,323.02 120,300.11 13,977.09 13.15%
19 80%3,168,000 117,374.50 132,613.67 15,239.17 12.98%
20 90%3,564,000 128,425.99 144,927.24 16,501.25 12.85%
21 7,000 8,194 50%2,520,000 107,121,71 121,676,69 14,554.98 13.59%
22 60%3,024,000 121,187.24 137,348.51 16,161.27 13.34%
23 70%3,528,000 135,252.77 153,020.32 17,767.55 13,14%
24 80%4,032,000 149,318.30 168,692.13 19,373.83 12.97%
25 90%4,536,000 163,383.82 184,363.94 20,980.11 12.84%
26 8,500 9,949 50%3,060,000 130,023.38 147,680.41 17,657.04 13.58%
27 60%3,672,000 147,102.95 166,710.47 19,607.52 13.33%
28 70%4,284,000 164,182.52 185,740.53 21,558.01 13.13%
29 80%4,896,000 181,262.09 204,770.58 23,508.50 12,97%
30 90%5,508,000 198,341.66 223,800.64 25,458.98 12.84%
Exhibit No. 48
Case No. IPC-E-11-08
S. Sparks, IPC
Page 9 of 13
Idaho Power Company
Typical Monthly Billng Comparison
State of Idaho
General Rate Case
Filed June 1, 2011
Schedule 19, Large Power Servce - Primary
Weighted Average Monthly
(1 )(2)(3)(4)
Line Demand Load Energy Current Proposed Difference Percent
No kW Factor kWh Rate Rate 0.Difference
1 1,000 50%360,000 16,226.73 18,783,76 2,557.03 15.76%
2 60%432,000 18,329.65 21,125.17 2,795,52 15,25%
3 70%504,000 20,432.56 23,466.57 3,034.00 14.85%
4 80%576,000 22,535.48 25,807,97 3,272.49 14.52%
5 90%648,000 24,638.40 28,149.37 3,510.97 14.25%
6 2,500 50%900,000 40,195.92 46,470.41 6,274.49 15.61%
7 60%1,080,000 45,453,21 52,323.91 6,870.70 15.12%
8 70%1,260,000 50,710.50 58,177.42 7,466.91 14.72%
9 80%1,440,000 55,967,80 64,030.92 8,063.13 14.41%
10 90%1,620,000 61,225,09 69,884.43 8,659.34 14.14%
11 4,000 50%1,440,000 64,165.11 74,157.06 9,991.95 15.57%
12 60%1,728,000 72,576.78 83,522.66 10,945.89 15.08%
13 70%2,016,000 80,988.44 92,888.27 11,899.83 14.69%
14 80%2,304,000 89,400.11 102,253,87 12,853.76 14.38%
15 90%2,592,000 97,811.78 111,619.48 13,807.70 14.12%
16 5,500 50%1,980,000 88,134.30 101,843.70 13,709.41 15.56%
17 60%2,376,000 99,700.34 114,721.41 15,021.07 15.07%
18 70%2,772,000 111,266.38 127,599.12 16,332.74 14.68%
19 80%3,168,000 122,832.43 140,476.83 17,644.40 14.36%
20 90%3,564,000 134,398.47 153,354.54 18,956,07 14.10%
21 7,000 50%2,520,000 112,103.49 129,530.35 17,426.86 15,55%
22 60%3,024,000 126,823.90 145,920.16 19,096.26 15.06%
23 70%3,528,000 141,544.32 162,309.97 20,765,65 14.67%
24 80%4,032,000 156,264.74 178,699.78 22,435.04 14.36%
25 90%4,536,000 170,985,16 195,089.59 24,104.43 14.10%
26 8,500 50%3,060,000 136,072.68 157,217.00 21,144.32 15.54%
27 60%3,672,000 153,947.47 177,118.91 23,171.44 15.05%
28 70%4,284,000 171,822.26 197,020.82 25,198.56 14,67%
29 80%4,896,000 189,697.06 216,922,73 27,225.68 14,35%
30 90%5,508,000 207,571.85 236,824.65 29,252.80 14,09%
Exhibit No. 48
Case No. IPC-E-11-08
S. Sparks, IPC
Page 10 of 13
Idaho Power Company
Typical Monthly Billng Comparison
State of Idaho
General Rate Case
Filed June 1, 2011
Schedule 24, Agricultural Irrigation Service - Secondary
In-Season
(1 )(2)(3)(4)
Line Demand Load Energy Curr Proposed Difference Percent
No kW Factor kWh Rate Rate m.Difference
1 10 20%1,440 $142.15 $173.50 $31.36 22.06%
2 35%2,520 $191.55 $228.27 $36.73 19.17%
3 50%3,600 $240.67 $282.44 $41.78 17.36%
4 65%4,680 $289.79 $336.61 $46.83 16,16%
5 80%5,760 $338,92 $390.77 $51.85 15.30%
6 50 20%7,200 $639.37 $770.56 $131.19 20.52%
7 35%12,600 $884.99 $1,041.38 $156,39 17.67%
8 50%18,000 $1,130.61 $1,312,21 $181.60 16.06%
9 65%23,400 $1,376,23 $1,583.04 $206.81 15.03%
10 80%28,800 $1,621.85 $1,853.86 $232.01 14,31%
11 100 20%14,400 $1,260.57 $1,516.10 $255.53 20,27%
12 35%25,200 $1,751.81 $2,057.76 $305,95 17.46%
13 50%36,000 $2,243.05 $2,599.41 $356.36 15.89%
14 65%46,800 $2,734.28 $3,141.06 $406.78 14.88%
15 80%57,600 $3,225.52 $3,682.71 $457.19 14.17%
16 300 20%43,200 $3,745.34 $4,498.32 $752.98 20.10%
17 35%75,600 $5,219.05 $6,123.28 $904.23 17,33%
18 50% 108,000 $6,692.77 $7,748.24 $1,055.47 15.77%
19 65% 140,400 $8,166.48 $9,373.19 $1,206.71 14.78%
20 80% 172,800 $9,640,20 $10,998,15 $1,357.95 14.09%
21 500 20%72,000 $6,230.11 $7,480.54 $1,250.43 20.07%
22 35% 126,000 $8,686.30 $10,188.80 $1,502.50 17,30%
23 50% 180,000 $11,142.49 $12,897.06 $1,754.57 15.75%
24 65% 234,000 $13,598.68 $15,605.33 $2,006,65 14.76%
25 80% 288,000 $16,054.87 $18,313.59 $2,258.72 14.07%
26 750 20% 108,000 $9,336,07 $11,208.31 1,872.24 20.05%
27 35% 189,000 $13,020.36 $15,270.71 2,250.35 17.28%
28 50% 270,000 $16,704.65 $19,333.10 2,628.45 15.73%
29 65% 351,000 $20,388.93 $23,395.49 3,006.56 14.75%
30 80% 432,000 $24,073.22 $27,457,89 3,384.67 14.06%
In-season months include June. July, August, September
Exhibit No. 48
Case No. IPC-E-11-08
S. Sparks, IPC
Page 11 of 13
Idaho Power Company
Typical Monthly Billng Comparison
State of Idaho
General Rate Case
Filed June 1,2011
Schedule 24, Agricultural Irrigation Service - Seeóndary
Out-of-Season
(1 )(2)(3)(4)
Line Demand Load Energy Current Proposed Difference Percent
No kW Factor kWh Rate Rate 2-1 Difference
1 10 20%1,440 $84.61 $92.86 8,25 9.75%
2 35%2,520 $145,47 $159.88 14.41 9.91%
3 50%3,600 $206.33 $226.90 20.57 9.97%
4 65%4,680 $267.19 $293.92 26.73 10,00%
5 80%5,760 $328.05 $360.94 32.89 10,03%
6 50 20%7,200 $409.19 $450,30 41.11 10.05%
7 35%12,600 $713.50 $785,39 71,89 10.08%
8 50%18,000 $1,017.80 $1,120.49 102.69 10.09%
9 65%23,400 $1,322.10 $1,455.59 133.49 10.10%
10 80%28,800 $1,626.40 $1,790.68 164.28 10.10%
11 100 20%14,400 $814,93 $897.09 82.16 10.08%
12 35%25,200 $1,423,53 $1,567.29 143.76 10.10%
13 50%36,000 $2,032.13 $2,237.48 205.35 10.11%
14 65%46,800 $2,640,73 $2,907.67 266.94 10.11%
15 80%57,600 $3,249.34 $3,57787 328.53 10.11%
16 300 20%43,200 $2,437.87 $2,684.28 246.41 10.11%
17 35%75,600 $4,263.67 $4,694.86 431.19 10.11%
18 50% 108,000 $6,089.48 $6,705.44 615.96 10.12%
19 65% 140,400 $7,915.28 $8,716.02 800.74 10.12%
20 80% 172,800 $9,741.09 $10,726.60 985,51 10.12%
21 500 20%72,000 $4,060.80 $4,471.46 410.66 10.11%
22 35% 126,000 $7,103.81 $7,822.43 718.62 10.12%
23 50% 180,000 $10,146.82 $11,173.40 1,026.58 10.12%
24 65% 234,000 $13,189.83 $14,524.37 1,334.54 10.12%
25 80% 288,000 $16,232,84 $17,875.34 1,642.50 10.12%
26 750 20% 108,000 $6,089.48 $6,705.44 615,96 10.12%
27 35% 189,000 $10,653,99 $11,731.90 1,077.91 10.12%
28 50% 270,000 $15,218.50 $16,758.35 1,539.85 10,12%
29 65% 351,000 $19,783.01 $21,784.81 2,001.80 10,12%
30 80% 432,000 $24,347.52 $26,811.26 2,463,74 10.12%
Exhibit No. 48
Case No. IPC-E-11-08
S. Sparks, IPC
Page 12 of 13
Idaho Power Company
Typical Monthly Biling Comparison
State of Idaho
General Rate Case
Filed June 1, 2011
Schedule 24, Agricultural Irrigation Service - Secondary
Weighted Average Monthly
(1 )(2)(3)(4)
Line Demand Load Energy Curr Proposed Difference Percent
No kW Factor kWh Rate Rate m.Difference
1 10 20%1,440 103.79 119.74 15,95 15,37%
2 35%2,520 160,83 182.68 21.85 13,59%
3 50%3,600 217.78 245.41 27.64 12.69%
4 65%4,680 274.72 308.15 33.43 12,17%
5 80%5,760 331.67 370.88 39.21 11,82%
6 50 20%7,200 485.92 557.05 71.14 14.64%
7 35%12,600 770.66 870.72 100,06 12.98%
8 50%18,000 1,055.40 1,184.40 128.99 12.22%
9 65%23,400 1,340.14 1,498.07 157.93 11.78%
10 80%28,800 1,624.88 1,811.74 186.86 11.50%
11 100 20%14,400 963,48 1,103.43 139.95 14.53%
12 35%25,200 1,532.96 1,730.78 197.82 12,90%
13 50%36,000 2,102.44 2,358.12 255.69 12.16%
14 65%46,800 2,671.91 2,985.47 313.55 11,74%
15 80%57,600 3,241.40 3,612.82 371.42 11.46%
16 300 20%43,200 2,873.69 3,288.96 415.27 14.45%
17 35%75,600 4,582,13 5,171.00 588.87 12.85%
18 50% 108,000 6,290.58 7,053.04 762.46 12.12%
19 65% 140,400 7,999.01 8,935.08 936.06 11.70%
20 80% 172,800 9,707.46 10,817,12 1,109,66 11.43%
21 500 20%72,000 4,783.90 5,474.49 690.58 14.44%
22 35% 126,000 7,631.31 8,611.22 979.91 12.84%
23 50% 180,000 10,478.71 11,747.95 1,269.24 12,11%
24 65% 234,000 13,326,11 14,884.69 1,558.58 11,70%
25 80% 288,000 16,173.52 18,021.42 1,847.91 11.43%
26 750 20% 108,000 7,171,68 8,206.40 1,034,72 14.43%
27 35% 189,000 11,442.78 12,911.50 1,468.72 12.84%
28 50% 270,000 15,713,88 17,616,60 1,902,72 12.11%
29 65% 351,000 19,984,98 22,321,70 2,336,72 11.69%
30 80% 432,000 24,256.09 27,026.80 2,770.72 11.42%
Exhibit No. 48
Case No. IPC-E-11-08
S. Sparks, IPC
Page 13 of 13