20210527Meredith Direct.pdf

BEFORE THE IDAIIOPT]BLIC UTILITIES COMNtrSSION
INTEE MATTEROFTHI
APPTICATION OT ROCICT
MOIINTAIN POWERr1OR
AUTHORIIY TO INCREASE ITS
RATES AND CIIARGES IN II}AEO
AND APPROVAL OF PROPOSEI)
ELECTRIC SERVICE SCHEDTILDS
AND REGITL^ATIONS
c.asE No. PAC-E-21-07
Direct Testimony of Robert 1l[. Meredith
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ROCKY MOT]NTAIN POWER
CASE NO. PAC.E.21.O7
Itday 2021
TABLE OF CONTENTS
I. QUALIFICATIONS
II. PRESENT REVENUE ANID BILLING DETERMINANTS.......
M. CLASS COST OF SERVICE STUDY
A. Cost of Service Shrdy Changes....
B. Description of Cost of Service Procedures
IV. PROPOSED RATE SPREAD...
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A. Federal Tax Act Adjustment
V. RATE CHANGES FOR THE MAJOR CUSTOMER RATE SCHEDULES
A. Residential Rate Design.......
B. General Service and Irrigation Rate Desigu
C. Special Confiact Requirements and Schedule 401
D. Schedule 400.........
E. Schedule 19 - Commercial and Industrial Space Heating.....
VL LIGHTING PRICE RE.DESIGN.........
A. Area Lights........
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AITACHED E)(HIBITS
Ex&ibit No. 45--8i1ling Determinants
Exhibit No. 46{ost of Service - Summary by Rate Schedtrle
ExhibitNo. 47-Cost of Service - Summary by Function
ExhibitNo. 48-{ost of Servioe Study
ExhibitNo. 49-Proposed Price Change by Rare Schedule
Exhibit No. 5O-Proposed Revised Tariffs
ExhibitNo. 5l-Proposed Revised Taritrs in kgislative Format
Exhibit No. 52-Basis for Residential Custome,r Service Charge
Exhibit No. 53-Average Weighted EIM Prices
Ex&ibit No. S4-Average 24 Hourly EIM Prices for Winter & Summer Seasons
ExhibitNo. ss-Sfioet Light - EstimatedAnnual Energy Consumption
Exhibit No. 56-Monthly Bill Comparisons
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Please state your name, business address and present position with PaciliCorp
d/b/a Rocky Mountain Power ("the Company").
My name is Robert M. Meredith. My business address is 825 NE Multnomah Sreet,
Suite 2000, Portland, Oregon 97232. My present position is Director, Pricing and Cost
of Service.
I. QUALIFICATIONS
Please describe your education and professional background.
I have a Bachelor of Science degree in Business Administration and a minor in
Economics from Oregon State University. In addition to my formal education, I have
attended various industry-related seminars. I have worked for the Company for 16 years
in various roles of increasing responsibility in the Customer Service, Regulation, and
Integrated Resource Planning departments. I have over 11 years of experience
preparing cost of service and pricing related analyses for all six states that PacifiCorp
serves. In March 2016,1became Manager, Pricing and Cost of Service. In June 2019,
I was promoted to my current position.
What are your responsibilities?
I am responsible for regulated retail rates and cost of service analysis in the Company's
six state service territory.
Have you appeared as a witness in previous regulatory proceedings?
Yes. I have testified for the Company in regulatory proceedings in ldaho, Utah, Oregon,
Wyoming, Washington, and California.
What is the purpose of your testimony?
I present the Company's embedded class cost of service ("COS") study based on the
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l2-month period ending December 31,2020.I also present the Company's proposed
rate spread and rate design changes for the affected rate schedules.
How is your testimony organized?
My testimony is organized as follows:
. First, I describe the present revenue used in this case which is based upon
calendar year 2019 billing determinants and scaled to the level of energy sales
and customer count that occurred during calendar year 2020.
. Secon4 I present the results of the COS study, including a description of
changes in the COS since the last general rate case in Docket No. PAC-E-|L-I?
(*2011Rate Case"), and procedures used in the preparation of the study.
. Third, I present the Company's proposed rate spread, which is the allocation of
the rate increase to the major customer rate schedules.
. Fourth, I describe and present the Company's proposed rate changes for the
major customer rate schedules.
. Lastly, I present the Company's street and area lighting cost study as well as its
proposal to re-design pricing for Company-owned light service.
IL PRESENT REVENUE AND BILLING DETERMINANTS
What is the historic test period used for this rate case?
The historic test period used in this rate case is the l2-month period ending
December 31,2020.
Was 2020 a unique year for the composition of customer loads and usage
characteristics?
Yes. As a result of the COVID-I9 global pandemic, the mix of customer class loads
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and customer usage characteristics were altered during 2A20. Stay-at-home orders
resulted in a relative increase in residential customer load and a slump in load for
commercial and indusfrial customers. Table I below shows the year-on-year change in
load and average price for each major class for calendar year 2020:
Table 1. Change to Load and Average Price in202O
Table I shows that while overall load was nearly flat, there were significant changes
in energy usage for individual classes of customers. Table I also shows that despite
having a stable level of total usage, the average price paid by all customers was about
1.3 percent higher.
Why was the average price customers paid higher in 2020?
Overall price was higher in 2020 for two reasons. First, the mix of customer load by
class in 2020 had more energy sales for the higher priced residential and irrigation
classes and less energy sales for the lower priced industrial class. Second, the customer
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Residential Energy Sales (MWh)
Comrnercial Energy Sales (MWh)
Industrial Energy Sales (MWh)
Special Contract Energy Sales (MWh)
Irrigation Energy Sales (MWh)
Total Enersy Sales (MWh)
2019
729,881
513,409
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1,474,154
616,729
3.527.9t9
2020
742,806
492,420
153,877
1,488,237
646,312
3.526.366
Yeanoven
Year Change
r.8%
-4.r%
-19.4%
1.0%
4.8%
0.0%
Residential Average Price ($/MWh)
Comrnercial Average Price ($/1VtWh)
Industrial Average Price ($/IIWh)
Special Contract Average Price ($/hAilh)
Irrigation Average Price ($iNIWh)
Total Averase Price ($/MWh)
2019
$104.63
$82.97
$68.06
$s7.44
$87.98
$76.93
2020
$ 105.53
$83.4s
$69.47
$s8.22
$88.99
s77.94
Yeanover-
Year Change
0.9%
0.6%
2.r%
r.3%
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usage characteristics in 2020 resulted in a higher average price for each major class.
On residential Schedule 1, customers pay more per kilowatt-hour ("kWh")
when their monthly usage exceeds a threshold and falls into the second block.l On
residential time-of-day Schedule 36, customers pay more for kWh consumption during
the 16 hour on-peak period.2 During 2020, there was a greater proportion of second
block and on-peak energy sales which increased the average price paid by residential
customers.
Most non-residential commercial and industrial load is subject to demand
charges, which are based upon the highest kilowatt ("kW") reading during any 15-
minute interval during the month. Declining loads for commercial and industrial
customers consequently resulted in a higher average price per kWh as load factor, or
the effective utilization of maximum capacity, dropped with the more fixed component
of kW charges being spread across fewer kWh. In summary, increased loads for
residential customers raised the average price forresidential customers while decreased
loads for commercial and industrial customers also raised the average price for non-
residential customers.
Did the Company use the actual 2020 billing determinants to prepare present
revenue and proposed prices in this rate case?
No. For the reasons given, the Company believes that2020 was an abnormal year for
both the mix of class load as well as the underlying billing determinants within each
class. The Company does not believe that customer usage characteristics in 2020 will
I 700 kwh per month in summer and 1,000 kWh per month in winter.
2 8 A.M. to I I P.M., Monday through Friday, except holidays in summer and 7 A.M. to l0 P.M., Monday
through Friday, except holidays in winter.
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reflect conditions going forward.
What set of billing determinants did the Company use to prepare present revenue
and proposed prices in this rate case?
The Company used calendar year 2Ol9 billing determinants, which were adjusted to
the same overall level of energy sales and customer count as occurred in 2020. From
2019 to 202A, the Company's normalized energy sales decreased by 0-04 percent and
its customer count increased by 2.17 percent. To put the 2019 billing determinants on
a comparable basis with the 2020 historical test period, the Company therefore
decreased all usage-related billing determinants by 0.04 percent and increased all
customer-related billing determinantsby 2.17 percent. The Company believes that this
is appropriate since 2019 is a more typical year for customer usage patterns that will be
more likely to represent the rate effective period. Exhibit No. 45 shows the billing
determinants used in preparing the pricing proposals in this case. It shows billing
quantities and prices at present rates and proposed rates.
How was this treatment of adjusted normalized 2Al9 actuals applied to
assumptions in the cost of service study?
ln the class cost of service study, class energy usage and demand measurements derived
from load research from 2019 information were adjusted down by the same
0.04 percent applied to billing determinants. Similarly, customer counts by class used
in the cost of service study were increased by 2.17 percent. The inputs for cost of
service were therefore put on a comparable basis with present revenues and billing
determinants for each class.
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III. CLASS COST OF SERVICE STIJDY
Please identify Exhibit No. 46, Cost of Service - Summary by Rate Schedule, and
explain what it shows.
Exhibit No. 46, Cost of Service - Summary by Rate Schedule, shows the summary of
the results from the cost of service ("COS") study for Idaho. It is based on the
Company's actual December 2020 results of operations for the state of Idaho presented
in the testimony of Company wihress Mr. Steven R. McDougal. Page 1 presents a
summary of the Company's actual earned rate of return by rate schedule based on
current rate levels. Page2 shows the results using the target rate of return based on the
requested $19.0 million revenue increase.
Please describe Exhibit No. 47, Cost of Service - Summary by Function.
Exhibit No. 47, Cost of Service - Summary by Function, shows the cost of service
results by rate schedule and by function. Page I contains the total cost of service
summary by rate schedule and pages 2 through 6 contain a sunmary by rate schedule
for each function.
A. Cost of Service Study Changes
Are the methodologies used in this COS study the same as those used in the cost
study filed with the Commission in the 2011 Rate Case?
Yes. The class COS study is generally consistent with the methodologies used in the
2011 Rate Case, with the exception of two changes that the Company is proposing to
the way it allocates distribution costs.
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What two changes does the Company propose for the allocation of distribution
cost?
First, the Company proposes that the weighting of monthly distribution coincident
peaks be based upon the capacity instead of the count of substations that peak in each
month. This more accurately reflects cost causation, because the cost of a substation
will be largely driven by its capacity and a simple count does not take into consideration
the size of different substations as they peak throughout the year.
Second the Company proposes allocating distribution line transformer costs on
each class' share of the current installation costs of the transformers that serye them,
with the exception of the lighting classes. For lighting classes, the Company proposes
allocating distribution line transformers on the basis of their share of non-coincident
peak ("NCP").
In the 2011 Rate Case, how were distribution line transformers allocated?
Distribution line transformers were allocated on the maximum secondary voltage NCP
for the class weighted by a coincidence factor for classes that typically share
transformers. The coincidence factor recognized that transformers could be designed at
capacities less than the sum of the estimated non-coincident peaks for all customers
sharing that transformer, because of the diversity in the timing of their loads.
How does the Company propose allocating distribution line transformers?
lnstead of allocating on weighted maximum NCP for the class, the Company proposes
allocating disfibution line transformer cost on the current installed cost of the actual
ffansformers serving each class.
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How did the Company determine the current installed cost of the actual
transformers serving each class?
First, the Company determined which ffansformers serve each customer based upon
information in its geographical information system. For transforners that are shared by
more than one customer, a fraction of the transformer was allocated to that customer
by taking the class average NCP for the customer and dividing by the sum of the class
average NCPs for all customers sharing the transformer. For example, suppose a
residential customer shares a ffansformer with a Schedule 23 customer. The average
maximum NCP for a residential Schedule I customer is 5.9 kW and 7.8 kW for a
Schedule 23 customer. Under this example, 43 percent3 of the transformer would be
assigned to the residential customer and the remaining 57 percent would be assigned to
the Schedule 23 customer.
Next, the Company determined the current installed cost for each type of
transformer based upon phase, capacity in kilovolt amperes, and whether the
transformer is pole mount (overhead service) or pad mount (underground service). The
Company then calculated an average transformer cost for each class by multiplying
the cost of each type of transformer by the number of transformers serving each class
and dividing by the number of customers in the class for the data examined.
Finally, the average installed cost for each class was input into the cost of
service study and multiplied by secondary voltage customer count to produce the
proposed distribution line transformer allocator.
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3 5.9 kW / (5.9 kW + 7.8 kW).
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Please describe why this method of allocating distribution line transformers is
more accurate.
This method is more accurate because it utilizes the actual currant installed cost of the
transformers that are serving customers and thus is a more realistic representation of
the costs customers impose on the system for this aspect of their service. This method
is also very similar to the way the Company allocates the costs of meters and services,
which are allocated on the average current installed cost of meters and service drops
multiplied by the count of customers for each class.
Does the Company propose using this method to allocate transformer costs to all
classes?
No. The Company does not have good data regarding the transformers that serve
customers on the lighting classes. For the lighting classes (Schedules 7 , 7 A, 1t and
12), the Company proposes to allocate transformer costs on maximum NCP.
Are there any new adjustments to revenue requirement that require special
handling in the class cost of service study?
Yes. As described in Mr. McDougal's testimony, a situs reduction in renewable energy
credit (*REC") sales was made to the state of Idaho to reflect an agreement the
Company entered into with its largest Idaho customer. Under the terms of this
agreement, Special Contract Customer I will forego its allocated share of REC sales
and the Company will retire those RECs on behalf of the customer to help it meet its
corporate sustainability goals. This situs adjustment in revenue requirement to the state
of Idaho is therefore reflected in the class cost of service study as a direct assignment
to Special Contract Customer l. The reduction in REC sales revenue increases Special
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Confact Customer 1's revenue requirement, which reflects this customer's choice and
holds other customers harmless.
B. Description of Cost of Service Procedures
Please explain how the cost of service study was developed.
The cost of service study utilizes the Idaho results of operations produced by Mr.
McDougal. The study employs a three-step process generally referred to as
frrnctionalization, classification, and allocation. These three steps recognize the way a
utility provides elecrical service and assigns cost responsibility to the groups of
customers for whom those costs were incurred.
Please describe functionalization and how it is employed in the cost of service
study.
Functionalization is the process of separating expenses and rate base items according
to utility function. The production function consists of the costs associated with power
generation, including coal mining and wholesale sales and purchases. The transmission
function includes the costs associated with the high voltage system utilized for the bulk
ffansmission of power from the generation source and interconnected utilities to the
load centers. The distribution function includes the costs associated with all the
facilities that are necessary to connect individual customers to the transmission system.
This includes distribution substations, poles and wires, line transforners, service drops,
and meters. The retail sewice function includes the costs of meter reading, billing,
collections, and customer service. The miscellaneous function includes costs associated
with demand side management, franchise taxes, regulatory expenses, and other
miscellaneous expenses.
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Describe classification and explain how the Company uses it in the cost of service
study.
Classification identifies the component of utility service beingprovided. The Company
provides, and customers purchase, service that includes at least three different
components: demand-related, energy-related, and customer-related components.
Demand-related costs are incurred by the Company to meet the maximum demand
imposed on generating units, transmission lines, and distribution facilities. Energy-
related costs vary with the output of a kWh of electricity. Customer-related costs are
driven by the number of customers served.
How does the Company determine cost responsibility between customer groups?
After the costs have been functionalized and classified, the next step is to allocate them
among the customer classes. This is achieved by the use of allocation factors that
specify each class' share ofa particular cost driver such as systempeak demand, energy
consumed, or number of customers. The appropriate allocation factor is then applied to
the respective cost element to determine each class' share of cost. A detailed
description of the Company's functionalization, classification and allocation
procedures and the supporting calculations for the allocation factors are contained in
Exhibit No. 48, Cost of Service - Study. Also, included in the Exhibit No. 48 is the
functionalized results of operations and class cost of service detail.
How are generation and transmission costs apportioned among customer classes?
Production and transmission plant and non-fuel related expenses are classified as
75 percent demand-related and 25 percent energy-related. The demand-related portion
is allocated using the class' 12 monthly peaks coincident with the Company's system
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firm peak. The energy portion is allocated using class megawatt hours adjusted for
losses to generation level.
Please describe how distribution costs are determined.
Distribution substations and primary lines are allocated using the weighted monthly
coincident distribution peaks. Secondary lines are allocated on NCP-only to classes
whose a\rerage number of customers per transformer is greater than one. Distribution
line transfonners and services costs are allocated to secondary voltage delivery
customers only using the installed cost of new ffansformers and services for different
types of customers. Meter costs are allocated to all customers. The meter allocation
factor is developed using the installed costs of new metering equipment for different
types of customers.
Please explain how customer accounting and customer service expenses are
allocated.
Customer accounting expenses are allocated to classes using weighted customer
factors. The weightings reflect the resources required to perform such activities as
meter reading, billing, and collections for different types of customers. Customer
service expenses are allocated on the number of customers in each class.
How are administrative & general expenses, general plant and intangible plant
allocated by the Company?
Most general plant, intangible plant, and administrative and general expenses are
functionalized and allocated to classes based on generation, transmission, and
distribution plant. Costs identified as supporting customer systems are considered part
ofthe retail services function and are allocated using customer factors. Coal mine plants
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are allocated on the energy factor.
Ifow are costs and revenues associated with wholesale contracts and other electric
revenues treated in the cost ofservice study?
The revenues from wholesale transactions are treated as revenue credits and are
allocated to customer classes using appropriate allocation factors. Other electric
revenues are also treated as revenue credits. Revenue credits reduce the revenue
requirement that is to be collected from retail customers. The cost of purchased power
contracts are allocated to customer classes using the appropriate allocation factors
increasing the Company' s revenue requirement.
IV. PROPOSED RATE SPREAI)
Please describe Roclry Mountain Power's proposed rate spread in this case.
The Company proposes to allocate the price change to customers in line with the class
cost of service results filed in this case. In developing the rate spread, the Company
proposes to follow the results of the cost of service study with one exception. The
Company proposes that the rate increase be limited so that all major rate schedule
classes receive proposed increases at or below l0 percent. This will assure that
movement toward full cost of service responsibility is maintained for all rate schedule
classes.
Please describe the Company's proposal for the allocation of the revenue
requirement.
The overall proposed revenue requirement increase is 7.0 percent. The Company
proposes the following allocation of the base price increase for the major rate
schedules:
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Customer Class
Residential - Schedule I
Residential - Schedule 36
General Service
Schedule 23123A
Schedule 6/6,4.
Schedule 9
Irrigation - Schedule 10
Special Contracts
Schedule 400
Lighting Schedules
Proposed Rate Chanee
9.2%
10.0%
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-38.6%0
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Please describe Exhibit No.49.
Exhibit No. 49 shows the estimated effect of the proposed price change by rate
schedule for the adjusted normalized test period. The table displays the present
schedule number, the average number of customers during the adjusted test year, and
the megawatt hours of energy use in Columns (2) through (4). Revenues by tariff
schedule are divided into two columns - one for present revenues and one for
proposed revenues. Column (5) shows annualized revenues under present base rates.
Column (6) shows annualized revenues under proposed base rates. Column (7) shows
Schedule 197 - Federal Tax Act Adjustment ("FTA.A") at zero as a placeholder.
Columns (9) and (10) show the dollar and percentage changes in rates.
Please describe Exhibit Nos. 50 and 51.
Exhibit No. 50 contains the Company's proposed revised tariffs in this case. Exhibit
No. 51 contains the revised tariffsheets in legislative format.
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I A. Federal Tax ActAdjustment
What does the Company propose regarding the disposition of the remaining
benefits associated with the Tax Cut and Jobs Act?
As discussed in the testimony of Company witness Ms. Joelle R. Steward, the
Company proposes holding offon refunding the remaining deferred tax benefits and
setting the price on Schedule 197 - Federal TaxActAdjustnent to zero at this time,
since near-term federal tax policy is uncertain.
V. RATE CHANGES FORTHE MAJOR CUSTOMER RATE SCHEDTILES
How are the major rate schedules presented in the remainder of your testimony?
In the next two sections, I present the major customer rate schedule changes. First, I
describe the changes to the residential schedules, followed by the changes to general
service and irrigation rate schedules. Second, I explain changes to special contracts and
the Company's proposal to move the Schedule 401 customer to Schedule 9. Third, I
explain changes to Schedule 400 and Schedule 19. Fourth, I describe the Company's
proposed lighting price re-design and supporting lighting cost study. Finally, I introduce
Exhibit No. 56 and the monthly billing comparisons.
A. Residential Rate Design
How does the Company propose to implement the price change for Schedule I
residential customers?
The Company proposes to increase the customer service charge from $5 to $8 for
Schedule l. The Company also proposes flattening the differential in the tiered block
energy charges by 50 percent and moving the difference between sunmer and winter
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energy prices towards levels that reflect seasonal differences in cost with an update to
the seasons so that May is included in the lower cost winter season.
What costs should be reflected in the residential customer service charge?
The residential basic charge should include the fixed costs associated with customer
seryice, billing, and the local infrastructure that is located geographically close to the
customer and is dedicated to serving one or a small number of customers. Specifically,
it is appropriate for the residential basic charge to recover the full costs as shown in the
cost of service study of the Retail and Miscellaneous functions and the portions of the
Distribution function that are related to meters, services or service drops and line
tansformers. Exhibit No. 52 shows a breakout per customer for each of the cost
categories that I identify for the residential Schedule 1 class. Including these cost
categories, a $17.29 customer service charge can be justified. For this case, the
Company proposes that the customer service charge be increased to $8 per month to
make movement towards cost while minimizing bill impacts.
Why is the Company proposing an increase in its customer service charge for
Schedule I customers?
At $5, the Company's present customer service charge falls short of cost. Setting the
customer service charge at a level that better recovers the fixed costs of customer
service, billing, and local infrastructure is important because this helps the Company
keep energy more affordable for its customers. Given a fixed level of revenue to be
collected from all residential customers, an increase in the basic charge will lower
energy charges.
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How does the Company's current and proposed customer service charge compare
to other electric utilities in ldaho?
The Company's current and proposed customer service charge compare favorably to
the basic charges of other major Idaho utilities. The Company examined the residential
rates of 6 other elecffic utilities in Idaho. Table 2 below shows those basic charges as
well as an average for all 6 utilities.
Table 2. Comparison of PacifiCorp's Current and Proposed Basic Charge to Other
Idaho Electric Utilities
The average basic charge of the six utilities examined is $20.88, which is higher than
the Company's proposed customer service charge of $8.
Please explain how the Company's current tiered energy charges work.
Residential Schedule I customers are subject to seasonal inclining block tiered rates
where the price of energy is more expensive when a customer uses more than a given
threshold during a monthly billing period. Additionally, energy charges vary in their
price depending upon the season with higher energ:y pricing in the summer season of
Meredith, Di - 17
Rocky Mountain Power
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ss.00
s8.00
$20.88
Note - Prices were those available from each trility's website
Average
Residential Basic Charse
as of March 23 2021
Clearwater Power Conpany
Lights, lnc
Current Rocky Mormtain Power
Proposed Rocly Mourtain Power
$5.00
$6.00
$ I8.00
$32.50
$30.00
s33.7s
Idaho Power
Avista
City of Idaho Falls
Kootenai Electric Coop Inc
l5
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May through October and lower pricing in the winter season of November through
April. During each monthly billing cycle in the winter season, a residential customer's
first 1,000 kWh of energy consumption is 8.5806 cents per kWh, and all additional
kWh are priced at 11.4943 cents. In the sunlmer season, the first 700 kWh of
consumption is I l.l3l6 cents and all additional kWh is priced at 14.9382 cents. Table
3 below shows the Company's current residential Schedule 1 energy charge prices:
Table 3. Current Residential Energy Charge Pricing
Price
May thrnugh October
lst 700 kWh
AII additional kwh
November through April
lst 1,000 kWh
AII additionalkWh
Historically, why have tiered energy charges been implemented?
The inclining block rate sfructure has been used as a tool for encouraging customers to
use less energy. The theory is that the first block covers some basic level of usage at a
lower rate to help keep the overall bill affordable for customers and a second or third
block with a higher rate makes incremental energy usage more expensive to encourage
energy efficiency. For a customer with usage in the higher tieq making an energy
efficient choice like installing light emitting diode ("LED") light bulbs would yield
greater savings than under a flat energy charge rate design.
Why is the Company proposing to cut the difference between first and second tier
energy charges by half?
While well intentioned, tiered rates produce more problems than they solve because
they are not economically justified and unduly penalize customers. In this case, the
Meredith, Di - l8
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Company proposes a flattening of the tiered energy charge rate structure. While the
Company believes that eliminating tiers is in the best interest of customers in the longer
term, it is only requesting a 50 percent reduction in the differential at this time to
mitigate bill impacts for smaller users.
Please explain why tiered rates are not economically justified.
There is no reason why after using 700 kwh or 1,000 kWh in a given month that the
next kWh consumed by a customer should cost more. The timing of energy
consumption, both seasonally and during different hours, can affect the utility's cost of
providing service to the customer. The load factor or the effective utilization of kWh
consumption relative to peak kilowatt demand can also change the average cost of
providing energy. However, there is nothing special about additional overall usage in a
monthly billing period that makes it more expensive for the utility to produce that next
kWh of electricity.
Please explain why tiered rates unduly penalize customers.
Charging higher prices for greater usage in a givan month causes larger users to
subsidize smaller users. Under a tiered rate structure, customers who heat their home
with natural gas benefit and those who use electric heat are punished. A large household
with a lot of people living under one roofwill be more likely to have usage in the higher
second block rate and the person living alone will likely not. Someone who has a
demanding career and seldom comes home may also have less energy consumption,
while a retiree who is home all day may find it more challenging to reduce electric
usage. Effectively, inclining block rates unfairly reward some customers and punish
others, often for reasons outside the customer's control.
Meredith, Di - 19
Rocky Mountain Power
1Q.
2A.
Is the tiered rate structure universally understood by customers?
No. In 2019, the Company conducted an email survey of its customers and collected
end use and demographic information from participants. According to the Company's
2019 survey, only 37 percent of customers were aware of the tiered rate strucfure. Of
those 37 percent who were aware of the structure, 38 percent said that it did not impact
their electricity usage decisions.
What prices does the Company propose for Schedule 1 residential energy
charges?
The Company's proposal for residential energy charges in this case balances the need
to effect change gradually while also making movement towards a more equitable and
economically principled rate sfucture. While the inclining block rate sffucture is
problematic, the Company proposes flattening tiered rates by half as a reasonable and
gradual first step.
The Company also proposes that the difference in energy charges for both tiers
would more closely reflect seasonal cost differences and that the sunmer season would
be limited to June through October and May would move to the lower cost winter
season. The Company therefore proposes a price of 9.7463 cents for the first 1,000 kwh
and 11.3324 cents for all additional kWh during the winter season of November through
May, and 11.6955 cents for the first 700 kwh and 13.5988 cents for all additional kWh
during the summer season of June through October.
Upon what basis did the Company determine a cost difference between the
summer and winter seasons?
To determine a cost basis for charging different prices based upon the two seasons, the
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Company took lS-minute PacifiCorp east balancing authority area ("PACE") Energy
Imbalance Market ("EIM") load aggregation point ("LAP") prices for the 36 month
period ending December 2020 and weighted it by PacifiCorp's houdy loads for each
month. Exhibit No. 53 shows the average weighted EIM prices for each of the
12 months of the year. For the summer season, which includes June through October,
the weighted average price is $29.73 per megawatt-hour ("MWh"), which is about
1.ll times the weighted average price of $26.86 per MWh calculated for the winter
season, which includes November through May. Cunently, the Schedule I summer
energy prices are about 30 percent higher than winter energy prices. To better reflect
the seasonal difference in cost while moderating potantial impacts to individual
customers, the Company set average srunmer energy prices for the first and second tier
at levels that are 1.2 times the corresponding average for winter energy prices. For other
rate schedules, the Company proposes relying upon the same 1.l l relative difference
in the seasonal value of energy as a guide for rate design.
Why is the Company moving May from the summer season to the winter season?
Exhibit No. 53 shows that the weighted average EIM price is the lowest in the month
of May. As a result, the Company proposes moving May to the lower cost winter season
for residential as well as all other rate schedules. Making this change better aligns with
cost and will help customers focus their energy efficiency efforts to the higher cost
sufilmer months.
How does the Company propose to implement the price change for Schedule 36 -
Optional Time of Day Residential Service?
The Company proposes to increase the current customer service charge of $14 per
Meredith, Di - 2l
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month to $15, which is still below the $20.18 that can be justified by cost on Exhibit
No. 52 and increase energy charges proportionately. The Company is not requesting
any changes to the seasonal definitions for Schedule 36, because doing so would
require re-prograrnming meters. After the Company has data from advanced metering
infrastructure in Idaho, the Company anticipates requesting improvements to the
seasons and time of use periods for Schedule 36 in a future rate case.
B. General Service and Irrigation Rate Design
O. Please summarize the Company's proposed rate design changes for general
service customers.
A. For general service customers, the Company proposes moving May from the summer
season prices to the winter season prices and setting seasonally differentiated rates at
levels where summer prices are 1.ll times winter prices. The Company proposes to
implement time of use pricing for Schedule 9 and eliminate the 15,000 kW load size
cap from Schedule 9 and 31. The Company also proposes eliminating Schedule 19 and
401.
a. What changes does the Company priopose for customers on Schedule 6 and 6A?
A. The Company proposes to apply the proposed revenue requirement change by applying
the average percentage price change to the customer service charge, power charges,
and energy charges. Power charges were designed so that summer prices were set at a
level 1.11 times winter prices.
a. What changes does the Company propose for customers on Schedule 10?
A. The Company proposes to apply the revenue requirement change by applying the
average percentage price change to the customer service charge, power charge, and
Meredith, Di - 22
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energy charges.
What changes does the Company propose for customers on Schedule 23 and 23A?
The Company proposes to apply the proposed revenue requirement change by
increasing the customer service charge from $16 to $18 to make movement towards the
level of $22.21 that can be justified from cost of service as shown on Exhibit No. 52.
The remaining increase was applied to energy charges and the summer energy price
was set at a level I .11 times the winter energy price.
What changes does the Company propose for customers on Schedule 35 and 35A?
The Company proposes to apply the proposed revenue requirement change uniformly
to all prices.
What does the Company propose for Schedule 9?
The Company proposes that energy charges for Schedule 9 customers be broken out
into time differentiated prices for on- and off-peak consumption. Power charges were
designed so that sunmer prices were set at a level l.l1 times winter prices.
Why does the Company propose differentiating enerry charges by time period?
The cost to produce and procure energy varies depanding on the time at which
customers consume it. Charging large customers difflerent prices for energy based on
time period promotes economic efiiciency by giving them the opportunity to shift when
they use energy from on-peak to off-peak. Customers with larger loads represent the
greatest opportunity per meter for loads to be shifted into lower cost periods.
What definition for on-peak does the Company propose for Schedule 9?
The Company proposes to use the on-peak periods of 6 a.m. to 9 a.m. and 6 p.m. to
11 p.m. in the winter months of November through May, and 3 p.m. to l1 p.m. in the
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summer months of June through October
Why did the Company select these periods for on-peak?
Similarly to how it developed a seasonal price differential, the Company developed its
proposal for time of use periods for Schedule 9 based upon prices for the l5-minute
PACE EIM LAP for the 36-month period ending December 2020. Exhibit No. 54 shows
the average 24 hourly EIM prices for the winter and summer seasons. The Company
proposes to use the top eight hours in both seasons as the on-peak period for Schedule
9. Exhibit No. 54 also shows the average prices for the on- and off-peak periods. The
difference in value between tle on- and oflpeak periods is 1.272 cents per kWh. To
moderate rate impacts to customers, the Company proposes that half of this difference
or 0.636 cents per kWh would be used as the difference in energy charge prices between
the on- and oflpeak periods.
C. Special Contract Requirements and Schedule 401
Is there a limitation on the size of customer that may take service under Schedule
9?
Yes. Presently, the Company's tariff Schedule 9 is restricted to customers with load
sizes less than or equal to 15,000 kW. Customers with load sizes that are greater than
15,000 kW must negotiate with the Company for conditions of service under special
contract arrangements.
Why does Schedule t have this prohibition?
It is not entirely clear to the Company why Schedule 9 is limited to customers with load
sizes of 15,000 kW or less. This limitation has been apafi of the Company's Schedule
9 tariffsince the 1970's.
Meredith, Di - 24
Rocky Mountain Power
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What does the Company propose with respect to this limitation?
The Company proposes eliminating the 15,000 kW load size limit for Schedule 9 and
31. The Company does not presently have a reason for this restriction and lifting it will
make the Company's pricing more transparent for prospective customers who may
consider siting new loads greater than 15,000 kW in the Company's service area. This
change will also make the Company's ldaho Schedule 9 tariff better align with the
Company's tariffs for transmission voltage service in its other Rocky Mountain Power
jurisdictions of Utah and Wyoming where such a limitation does not exist.
What does the Company propose for Schedule 401?
The Company proposes to discontinue Schedule 401 and move the one customer on it
to Schedule 9.
What is the bill impact for the Schedule 401 customer on proposed Schedule 9
rates?
The bill impact for Schedule 401 under Schedule 9 rates is a 5.7 percent increase.
Has the Company communicated to this customer that it would be proposing to
move it onto Schedule 9 as part of its rate case?
Yes.
Why does the Company propose making this change?
There are no special circumstances for why the customer on Schedule 401 is different
from other customers on Schedule 9, except that it has a load size greater than 15,000
kW. Schedule 401 was required for this customer because of the requirement on
Schedule 9 that customers with loads greater than 15,000 kW be subject to special
Meredith, Di - 25
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contract arrangements. As explained earlier in my testimony, the Company proposes
eliminating this provision from Schedule 9.
D. Schedule 400
Please describe the Company's proposed rate design changes for Schedule 400.
For Schedule 400, the Company proposes a uniform percentage increase to all billing
elements.
E. Schedule 19 - Commercial and Industrial Space Heating
What does the Company propose for Schedule 19?
The Company proposes to discontinue Schedule 19 and move the current customers
served under Schedule 19 to Schedule 23.
Why does the Company propose making this change?
Schedule 19's rates are structured in a very similar way to those on Schedule 23 with a
customer service charge plus seasonally differentiated energy charges. Schedule 19
offers a much lower energy price in the winter season. Since the Company is proposing
to set the difference between srunmer and winter energy charges at the same level as
their difference in value for Schedule 23,the Company does not believe that there is a
compelling reason to retain the closed Schedule 19 legacy option.
What would be the bill impact to Schedule 19 customers of moving them onto
proposed Schedule 23 rates?
The Company estimates that bills would rise on average by 13 percent for Schedule 19
customers when they are moved onto Schedule 23.
Meredith, Di - 26
Rocky Mountain Power
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YI. LIGHTING PRICE RE.DESIGN
a. What does the Company propose for lighting customers?
A. For Company-owned street and area lights, prices have been re-designed to be based
on the level of lighting service that the Company is providing, rather than on technology
(i.e., bulb) type.
a. Please provide a brief overview of the Company's current pricing structure for
Company-owned lighting?
A. The Company currently offers service to Company-owned lights under the following
schedules:
. Schedule 7 - Security Area Lighting
. Schedule ll - Street Lighting Service Company-Owned System
Street lights are provided for govemmental entities to illuminate public streets,
highways, and thoroughfares. Area lights, which are currently closed to new service,
are provided to residential and non-residential customers to light spaces outside such
as driveways or alleys. Prices for Company-owned steet and area lights are based on
the particular technology and type of lamp that the Company is providing. For example,
a 7,000 lumen mercury vapor area light is $27.22per month and a 4,000 lumen LED
street light is $15.34. Additional charges are also imposed if a security area light has a
steel pole, which varies based upon the length, vintage, and gauge. For example, an I I
gauge steel pole installed before June 1, 1973 increases the cost by $ I .00 per pole per
month. A three gauge, 35 foot direct, direct buried pole installed after June 1, 1973
increases the cost by $4.65 per pole per month. In summary, pricing for Company-
owned lights is complicated.
Meredith, Di - 27
Rocky Mountain Power
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What does it mean to base prices for Company-owned street and area lighting on
Ievel of service?
Presently, prices for Company-owned street and area lights are based on the particular
technology and type of lamp that the Company is providing. The Company believes
that at this time it should move away from this model for pricing lights that the
Company owns and maintains. Ultimately, what the Company provides street and area
lighting customers is a level of light to a specific area. The Company therefore proposes
that Company-owned street and area light prices be based on the level of lighting
service that the Company provides irrespective of technology or lamp type. The level
of lighting service would be based on ranges of LED equivalent lumens. Under this
new paradigm, an LED, a mercury vapor, and a high pressure sodium vapor lamp that
provide the same level of light would have the same price. For area lights, the Company
proposes the following levels:
. Level I (0-5,500 LED Equivalent Lumens)
. Level 2 (5,501-12,000 LED Equivalent Lumens)
. Level 3 (12,001 and Greater LED Equivalent Lumens)
For street lights, the Company proposes the following levels:
. Level I (0-3,500 LED Equivalent Lumens)
. Level2 (3,501-5,500 LED Equivalent Lumens)
. Level3 (5,501-8,000 LED Equivalent Lumens)
. Level4 (8,001-12,000 LED Equivalent Lumens)
. Level5 (12,001-15,500 LED Equivalent Lumens)
. Level6 (15,501 and Greater LED Equivalent Lumens)
Meredith, Di - 28
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Why is the Company proposing this change to the way it prices Company-owned
street and area lights?
First, basing prices on service level better aligns the Company's incentives towards
providing the provision of lighting at the lowest possible cost. LED has emerged as the
dominant lighting technology and is the most effrcient way to light a space, but the
present structure of its rates dis-incentivizes the Company from converting lights to
LED. If the Company replaces an older light with LED, its revenue decreases to reflect
the lower-priced LED lamp. Basing the price for Company-owned lights on level of
service will provide the Company with an incentive to transition its fleet of lights to
the most effrcient technology available.
Second, the Company's present prices for Company-owned lighting service are
hard to understand. Simplifying them to specific ranges of light levels makes it easier
for customers to understand.
What is the Company's lighting class cost study?
The lighting cost study is a more detailed analysis of the different prices included in
the rate schedules that form the sffeet and area lighting class. This study specifically
examines three cost categories: (l) Production/Transmission/Distribution Costs; (2)
Customer-Related Costs; and (3) Company-Owned Light Cost. Informed by the cost
analysis and based on the Company's proposed rate spread for the lighting classes, the
study produces proposed prices including those for Company-owned lights that are
based on level of service.
How were prices calculated on the lighting class cost study?
Exhibit No. 55 shows the calculations in the lighting class study, which were used to
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develop proposed prices. Page 1 of Exhibit No. 55 shows the estimated annual and
monthly maintenance of Company-owned sffeet and area lights. Maintenance activities
include replacing poles, mast arms, photocells, and luminaires. Estimated materials and
labor are shown for each maintenance activity. Page I also shows the estimated cost to
install street and area lights on existing distribution poles and calculates an estimated
monthly revenue requirement based on an 8.81 percent annualization factor. The lowest
cost installation on an existing distribution pole was assumed, because it is likely that
an installation on another more costly pole would be paid for by the customer as part
of the line extension policy. The Company's most recent cost estimates for LED lamps
were used to reflect that this is the lowest cost technology that the Company plans to
use going forward. Page 2 of Exhibit No. 55 shows the estimated annual energy
consumption for the different proposed street and area lighting levels of service based
on the most current LED lamps which the Company plans to use for new lamps going
forward. Page2 also shows how these estimated annual energy consumption amounts,
along with counts of lamps and customers, are applied to functionalized unit costs to
determine the pricing for each of the proposed service levels. For the
Production/TransmissionlDistribution functions, the Company performed an
embedded cost of service study that stripped out the cost of owning and maintaining
lights. This study produces the average cost of delivering energy to the lighting classes
apart from the cost of the lamp installations themselves. For the Customer and
Miscellaneous functions, costs were allocated to each rate schedule based on customer
count. The Company-Owned Lighting function was calculated by applying the monthly
installation and maintenance costs for each lighting service level.
Meredith, Di - 30
Rocky Mountain Power
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Page 3 of Exhibit No. 55 show the present and suggested proposed prices for
each level of lighting service. The bottom ofpage 4 shows that an adjustment factor of
44.18 percent applied to Company-Owned Lighting prices is required to achieve the
overall target revenue requirement for both of the Street and Area Lighting classes
specified in the Cost of Service Study. This approach to setting prices ensures that the
relative differences across prices for different levels of service reflect the cost of
owning and maintaining current LED technology, but collect the embedded revenue
requiranent related to cost in the test period.
Page 4 of Exhibit No. 55 shows the list of consolidated prices for the lighting
classes for reference. With this new pricing, the count of unique Company-owned street
and area lighting charges goes from 40 prices to 12 prices.
A. Area Lights
In addition to re-designing the Company-owned lamp prices, what other change
does the Company propose for Schedule 7 - Security Area Lighting?
The Company proposes that Schedule 7 be open to new service again on existing
distribution poles only.
Why did the Company close its area light schedule to new service?
My understanding is that area lights were closed for new service for two reasons. First,
the Company was concerned about the costs associated with maintaining lights at
homes and businesses throughout its service area. Second, the Company reasoned that
a customer could always install an area light on its own side of the meter.
Meredith, Di - 31
Rocky Mountain Power
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Why is the Company requesting that Schedule 7 be opened up for new service
again?
With LED technology, maintenance of area lights is far less than for other legacy
lighting technologies. While a high pressure sodium vapor lamp needs to have its bulb
changed out every six years on average, an LED area light head is designed to last for
25 years. With the falling cost of LED lights, the Company can provide an effrcient,
low-cost solution for its customers'outdoor lighting needs.
While customers can install area lights on their side of the meter, this is not
always a good option for them. Sometimes the area that a customer wants to illuminate
is much closer to distribution lines than to the customer's meter. In these circumstances,
particularly in the Company's more rural service areas, running wke underground to a
light a long distance away is not always cost effective orpractical. Offering to own and
maintain area lights can be a valuable service for customers.
Why is the Company restricting new lamps to being on existing distribution poles
only?
Installing new poles on customers' premises to provide area lighting service can
increase maintenance costs for the Company and can also create access issues for
service personnel who need to visit a lamp. Restricting new service to existing
distribution poles mitigates these concems.
Does the Company propose any other changes to its lighting schedule tariffs?
Yes. Presently, Schedule 7 contains a price for customer-owned and customer-
maintained 150 watt sodium vapor flood lights. To keep all customer-owned lights
together, the Company proposes moving this price to Schedule 12 and renaming
Meredith, Di - 32
Rocky Mountain Power
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t Schedule 12 ta "Street and Security Area Lighting Service - Customer-Owned
2 Systern".
3 Monthly Billiag Comparisons
4 Q. Please explaln ExhibltNs.56.
5 A. Exhibit No. 56 details the customer impacts of the Company's proposed pncing
6 chauges, For each rate schedule, it shows the dollar and percentage cbange in msnthly
7 bills for various load aod usage levels.
8 Q. Does t[is concludeyour direct testimony?
9 A. Yes.
Meredith, Di - 33
Rocky Mormain Power