20190610Knox Direct.pdf

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DAVID J. MEYER
VICE PRESIDENT AND CHIEF COI.]NSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O.BOX3727
I4I I EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220 -3727
TELEPHONE: [phone]
FACSIMILE: (s09)495-88s1
[e-mail]
;0r9 JUlt t0
ID
TILiT
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC SERVICE
TO ELECTRIC CUSTOMERS IN
THE STATE OF IDAHO
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CASE NO. AVU-E-19-04
DIRECT TESTIMONY
OF
TARA L. KNOX
FOR AVISTA CORPORATION
(ELECTRIC)
RECEIVED
Al{ I0: l0
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ISSION
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o I I. INTRODUCTION
2 Q. Please state your name, business address and present position with
3 Avista Corporation.
4 A. My name is Tara L. Knox and my business address is 1411 East Mission
5 Avenue, Spokane, WashinSon. I am employed as Manager of Regulatory Accounting
6 Initiatives in the Regulatory Affairs Department.
7 Q. Would you briefly describe your duties?
8 A. Yes. I am responsible for preparing the electric cost of service studies for
9 the Company, as well as providing support for the preparation of results of operations
10 reports, among other things.
I I a. What is your educational background and professional experience?
12 A. I am a graduate of Washington State University with a Bachelor of Arts
13 degree in General Humanities in 1982, and a Master of Accounting degree in 1990. As
14 an employee in the Regulatory Affairs Department at Avista since I 991, I have attended
15 several ratemaking classes, including the EEI Electric Rates Advanced Course that
16 specializes in cost allocation and cost of service issues. I am also a member of the Cost
17 of Service Working Group and the Northwest Pricing and Regulatory Forum, which are
l8 discussion groups made up of technical professionals from regional utilities and utilities
19 throughout the United States and Canada concerned with cost of service issues.
20 a. What is the scope of your testimony in this proceeding?
2l A. My testimony and exhibits will cover the Company's electric revenue
22 normalization adjustment to the test year results of operations, the proposed Load Change
23 Adjustment Rate to be used in the Power Cost Adjustment and Fixed Cost Adjustment
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o mechanisms, and the electric cost of service studies performed for this proceeding. A
table of contents for my testimony is as follows:
Descrintion Pase
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I.
II.
III
IV
Introduction
Electric Revenue Normal ization
Proposed Load Change Adjustment Rate
Electric Cost of Service
Base Case Cost of Service Study
Alternative Cost of Service Studies
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a. Are you sponsoring any exhibits in this case?
A. Yes. I am sponsoring Exhibit No. I I composed of five schedules.
Schedule 1 details the calculation of the proposed Load Change Adjustment Rate,
Schedule 2 includes a narrative of the electric cost of service study process, Schedule 3
presents the base case electric cost of service study summary results, Schedule 4 is the
electric cost of service workshop presentation, and Schedule 5 presents key results from
the alternative cost of service studies.
a. Were these exhibit schedules prepared by you or under your
direction?
A. Yes, they were.
II. ELECTRIC REVENUE NORMALIZATION
a. Would you please describe the electric revenue normalization
adjustment included in Company witness Ms. Andrews' pro forma results of
operations?
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A. Yes. The electric revenue normalization adjustment represents the
difference between the Company's actualrecorded retailrevenues during the 12-months
ended December 2018 test period, and base rate retail revenues on a normalized (pro
forma) basis. The total revenue normalization adjustment increases Idaho net operating
income by $1,512,000, as shown in adjustment column 2.07 on page 6 of Ms. Andrews'
Exhibit No. 4, Schedule l.
The revenue normalization adjustment consists of four primary components: l)
re-pricing customer usage (adjusted for any known and measurable changes) to base tariff
rates presently in effect, 2) adjusting customer load and revenue to a 12-month calendar
basis (unbilled revenue adjustment), 3) weather normalizing customer usage and revenue,
and 4) eliminating both the deferred revenue associated with the 2018 Fixed Cost
Adjustment (FCA) mechanism and the 2017 Tax Reform Provision for Rate Refund
included in 2018 results.
a. Since these elements are combined into a single adjustment, would
you please identify the impact of each component?
A. Yes. A breakdown of the four components of the revenue normalization
is as follows:
The re-pricing of billed usage including the effects of the January 1,2019
base rate increase including Permanent Tax Reform rate adjustment
Schedule 72 (AVU-E-17-01, Compliance Filing 2), as well as the
elimination of adder schedule revenue and related amortization expense
(Schedule 59 Residential Exchange Credit, Schedule 75 Fixed Cost
Adjustment, Schedule 9l Public Purpose Tariff Rider, Schedule 95
Optional Renewable Power and Schedule 97 Rebate of Electric Earnings
Test Deferral)l results in a decrease to net income of $1,714,000.2
I Municipal Franchise Fee and Power Cost Adjustment revenues and related expenses are eliminated in
separate adjustments.
2 This analysis reclassifies Schedule 25 and25P unbilled transition from no lag(0o/o unbilled) to one-
month lag ( I 00% unbilled) to represent the unbilled amounts reflected in pro forma billed usage.
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2. The re-pricing of unbilled calendar usage and elimination of unbilled
adder schedule revenue and expense results in an increase to net income
of $77,000.3
3. The weather adjustment increases net income $1,245,000.4. The elimination of the 2018 FCA deferred revenue and tax reform
provision for rate refund increases net income by $1,904,000.
The combined impact of these four elements is an increase to net income of
s 1,512,000.
a. Earlier you stated that customer usage is "adjusted for any known
and measurable changes". What material usage adjustments were made to the 2018
test year?
A. One large customer moved from Schedule 25 to Schedule 2l after the test
year. The schedule shifting impact was reflected in the re-pricing of billed usage.
a. Please briefly summarize the electric weather normalization process.
A. The Company's electric weather normalization adjustment calculates the
change in kWh usage required to adjust actual loads during the 2018 test period to the
amount expected if weather had been normal. This adjustment incorporates the effect of
both heating and cooling on weather-sensitive customer groups. The weather adjustment
is developed from a regression analysis of ten years of billed usage per customer and
billing period heating and cooling degree-day data. The resulting seasonal weather
sensitivity factors (use-per-customer-per-heating-degree day and use-per-customer-per-
cooling-degree day) are applied to monthly test period customers and the difference
between normal heating/cooling degree-days and monthly test period observed
heating/cooling degree-days.
3 The unbilled adjustment consists of removing December 2017 usage billed in January 2018 from the
2018 test year, adding December 2018 usage billed in January 2019 to the 2018 test year, and re-pricing
the net usage at present base rates.
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a. Have the seasonal weather sensitivity factors been updated since the
last rate case?
A. Yes. The factors used in the weather adjustment are based on regression
analysis of monthly billed use-per-customer from January 2007 through December 2016,
which is the most recent completed analysis.
a. What data did you use to determine "normal" heating and cooling
degree days?
A. Normal heating and cooling degree days are based on a rolling 3O-year
average of heating and cooling degree-days reported for each month by the National
Weather Service for the Spokane Airport weather station. Each year the normal values
are adjusted to capture the most recent year with the oldest year dropping off, thereby
reflecting the most recent information available at the end of each calendar year. The
calculation includes the 30-year period from 1989 through 2018.
a. Is this proposed weather adjustment methodology consistent with the
methodology utilized in the Company's last general rate case in Idaho?
A. Yes. The process for determining the weather sensitivity factors and the
monthly adjustment calculation is consistent with the methodology presented in Case No.
AVU-E-17-01.
a. What was the change in kWhs resulting from weather normalization
for the l2-months ended December 2018 test year?
A. Weather was warmer than normal most of the 2018 test year. Since
electric usage is impacted by both heating and cooling, weather normalization required
an addition to usage for warm weather during the winter months that was offset by a
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Avista Corporation
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o reduction to usage for some colder than normal spring months and hot summer months.
Overall, the adjustment to normal required the addition of 447 heating degree-days during
the heating season,4 and the deduction of 78 cooling degree-days during the summer
season.s The annual total adjustment to Idaho electric sales volumes was an addition of
17,386,949 kWhs, which is approximately 0.60/o of billed usage. The electric system
monthly weather adjustment volumes were provided to Company witness Mr. Kalich as
an input to the Pro Forma Power Supply adjustment.
III. PROPOSED LOAD CHANGE ADJUSTMENT RATE
a. What is the Load Change Adjustment Rate?
A. The Load Change Adjustment Rate (LCAR) is part of the Power Cost
Adjustment (PCA) mechanism that prices the change in power supply-related costs
associated with the change in actual retail loads from the retail loads that were used to set
the PCA base costs. The LCAR determination process for all Idaho investor-owned
utilities was established in IPUC Case No. GNR-E-10-03, Order No. 32206, which was
approved on March, 15,2011. The LCAR is also a key component in the Company's
electric Fixed Cost Adjustment (FCA) mechanism.6
a. How was the LCAR determined?
A. The proposed LCAR was determined by first computing the proposed
revenue requirement on the total production and transmission costs contained within Ms.
4 The heating season includes the months ofJanuary through June and October through December.5 The summer season includes the months of June through September. June is included in both seasons
because both heating load and cooling load fluctuations occur during the month. May was also adjusted
for cooling in 2018 as the month was extraordinarily warm.
6 As required in the Company's FCA, the LCAR from the PCA (grossed up for revenue-related expenses)
multiplied by kWh sales is deducted from base rate revenues in the FCA to ensure that no overlap occurs
between the PCA and the FCA.
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o 1 Andrews' Idaho electric pro forma total results of operations. The
2 production/transmission revenue requirement amount is then divided by the Idaho
3 normalized retail load used to set rates in order to arrive at the average production and
4 transmission cost-per-kWh embedded in proposed rates. This amount is then multiplied
5 by the proportion of production and transmission costs classified as energy-related in the
6 cost of service study. The LCAR, therefore, represents the energy-related portion of
7 Avista's production and transmission costs, on a per-kWh basis.
8 Q. Do you have an exhibit schedule that shows the calculation of the
9 proposed LCAR for the rate year?
l0 A. Yes. Exhibit No. 11, Schedule I begins with the identification of the
I I production and transmission revenue, expense and rate base amounts included in each of
12 Ms. Andrews' actual, restating, and pro forma adjustments to results of operations. The
I 3 "2020 Pro Forma Total" on Line 32 atthe bottom of page 1 shows the resulting production
l4 and transmission cost components.
15 Page 2 shows the revenue requirement calculation on the production and
16 transmission cost components. The rate of return and debt cost percentages on Line 2 are
l7 inputs from the proposed cost of capital. The normalized retail load on Line l0 comes
l8 from the workpapers supporting the revenue normalization adjustment. Line I 1
19 represents the average total production and transmission cost-per-kWh proposed to be
20 embedded in Idaho customer retail rates. Lines 12 and 13 are values taken from the cost
21 of service study report titled "Functional Cost Summary by Classification at Uniform
22 Requested Return" which represents total costs at unity. Line 12 shows the amount of
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o production and transmission costs classified as energy-related, while Line l3 shows the
total production and transmission costs in the study.
The resultin92020 LCAR on Page 2,Line l4 is $0.02341 per kWh or $23.41 per
MWh. The calculation of the LCAR for the rate year will be revised based on the final
production and transmission costs, and rate of return, that are approved by the
Commission in this case.
IV. ELECTRIC COST OF SERVICE
a. Please briefly summarize your testimony related to the electric cost of
service study.
A. I believe the Base Case electric cost of service study presented in this case
is a fairrepresentation of the costs to serve each customergroup. The Base Case study
shows General Service Schedules lll12, Large General Service Schedules 21/22 and
Street and Area Lighting Schedules 41-49 provide more than the overall rate of return
under present rates. All of the other service schedules provide less than the overall rate
ofreturn under present rates to varying degrees.
a. What is an electric cost of service study and what is its purpose?
A. An electric cost of service study is an engineering-economic study, which
separates the revenue, expenses, and rate base associated with providing electric service
to designated groups of customers. The groups are made up of customers with similar
load characteristics and facilities requirements. Costs are assigned or allocated to each
group based on, among other things, test period load and facilities requirements, resulting
in an evaluation of the cost of the service provided to each group. The rate of return by
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o customer group indicates whether the revenue provided by the customers in each group
recovers the cost to serve those customers.
The study results are used as a guide in determining the appropriate rate spread
among the groups of customers. Schedule 2 of Exhibit No. 1 I explains the basic concepts
involved in performing an electric cost of service study. It also details the specific
methodology and assumptions utilized in the Company's Base Case cost of service study.
BASB CASE ELECTRIC COST OF SERVICE STUDY
a. What is the basis for the Base Case electric cost of service study
provided in this case?
A. The electric cost of service study provided by the Company as Exhibit No.
ll, Schedule 3 is based on the 2018 Pro Forma Study presented by Ms. Andrews in
Exhibit No. 4, Schedule 1.
O. Would you please explain the cost of service study presented in
Exhibit No. 11, Schedule 3?
A. Yes. Exhibit No. I l, Schedule 3 is composed of a series of summaries of
the cost of service study results. The summary on page 1 shows the results of the study
by FERC account category. The rate of return by rate schedule and the ratio of each
schedule's return to the overall return are shown on Lines 39 and 40. This summary was
provided to Company witness Mr. Miller for his consideration regarding rate spread and
rate design. The results will be discussed in more detail later in my testimony.
Pages 2 and 3 are both summaries that show the revenue-to-cost relationship at
current and proposed revenue. Costs by category are shown first at the existing schedule
returns (revenue); next the costs are shown as if all schedules were providing equal
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o recovery (cost). These comparisons show how far current and proposed rates are from
rates that would be in alignment with the cost study. Page 2 shows the costs segregated
into production, transmission, distribution, and common functional categories. Line 44
on page 2 shows the target change in revenue which would produce unity in this cost
study. Page 3 segregates the costs into demand, energy, and customer classifications.
Page 4 is a summary identifying specific customer-related costs embedded in the study.
The Excel model used to calculate the cost of service and supporting schedules
has been included in its entirety both electronically and in hard copy in the workpapers
accompanying this case.
a. Given that the specific details of this methodology are described in the
narrative in Exhibit No. 11, Schedule 2, would you please give a brief overview of
the key elements and the history associated with those elements?
A. Yes. Production costs are classified to energy and demand in this case
based on the system load factor. The Company has proposed this approach in prior
general rate cases (Case Nos. AVU-E-11-01, AVU-E-15-05, AVU-E-16-03 and AVU-E-
17-01).
Transmission costs are classified as 100% demand and allocated by the average
of the l2 monthly coincident peaks. This methodology is the same treatment as the last
four Idaho cases (Case Nos. AVU-E-12-08, AVU-E-15-05, AVU-E-16-03 and AVU-E-
17-01) and reflects the methodology accepted in the Settlement in Case No. AVU-E-10-
01.
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Distribution costs are classified and allocated by the basic customer theory
accepted by the Idaho Commission in Case No. WWP-E-98-11.7 Additional direct
assignment of demand-related distribution plant has been incorporated to reflect
improvements accepted by the Commission in Case No. AVU-E-04-01.
Administrative and general costs are first directly assigned to production,
transmission, distribution, or customer relations functions. The remaining administrative
and general costs are categorized as common costs and have been assigned to customer
classes by the four-factor allocator accepted by the Idaho Commission in Case No. AVU-
E-04-0r.
a. Does the Company's electric Base Case cost of service study follow the
methodology filed in the Company's last electric general rate case in Idaho?
A. Yes.
a. What are the results of the Company's electric Base Case cost of
service study presented in this case?
A. Table No. I below summarizes the Base Case cost of service study results:
7 Basic customer cost theory classifies only meters, services, and street lights as customer-related plant; all
other distribution facilities are considered demand-related.
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Customer Class
Residential Service Schedule 1
General Service Schedules 11/L2
Large General Service Schedules 21/22
Extra Large General Service Schedule 25
Extra Large General Service Clearwater
Paper Schedule 25P
Pumping Service Schedules 31/32
Lighting Service Schedules 4I - 49
Total ldaho Electric System
Rate of
Return
5.81%
70.77%
7.70%
6.22%
6.68%
6.82%
10.88%
7.08%
Return
Ratio
Revenue to
Cost Ratio
Cost Less
Revenue
S000s
s8,376
($4,180)
(Srzs1
5s22
s713
s201
(Sssa1
S5,255
0.82
1.'52
1.09
0.88
0.94
0.95
1.54
1.00
0.93
t.L2
1.00
0.95
0.97
0.97
1,.20
0.98
The first two columns show the rate of retum and the relationship of the customer
class return to the overall return (relative return ratio) at present rates for each rate
schedule. The next column presents the ratio of revenue provided by present rates divided
by the total cost of service at the requested overall return (revenue to cost ratio), followed
by the dollar value of the difference between total cost and present revenue for each
customer class.8
As can be observed from the above table, Residential Service Schedule 1, both
Extra Large General Service Schedules 25 and 25P, and Pumping Service Schedules
(31132) show under-recovery of the costs to serve them. The General, Large General,
and Lighting Service Schedules (1lll2, 21122, and 4l-49) show over-recovery of the
costs to serve them. The summary results of this study were provided to Mr. Miller for
consideration in the development of proposed rates.
8 In my cost of service exhibit the Cost less Revenue value is called "Target Revenue Increase" and may
be found on Exhibit I l, Schedule 3, page 2,atline 44.
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o ALTERNATIVE COST OF SERVICE STUDIES
2 Q. In the Company's last general rate case, the Stipulation and
3 Settlement approved by the Commission included agreement to hold a workshop to
4 "meet and confer regarding the Company's electric cost of service study". Has this
5 workshop taken place?
6 A. Yes, the workshop was held on March 27,2019 at the Commission hearing
7 room in Boise. In addition to Avista, representatives of Commission Staff, Idaho Forest
8 Group (lFG), Clearwater Paper, and ldaho Conservation League (lCL) attended the
9 workshop (Jointly "the Parties").
l0 a. What was discussed in this workshop?
1l A. Prior to the workshop the Company reached out to the Parties for input
12 regarding what they would like to discuss at the workshop. Based on their input, the
13 Company created the presentation attached as Exhibit I l, Schedule 4. Workshop
14 discussion topics included methods to measure movement toward unity with cost of
15 service and each of the classification and allocation scenarios presented in this exhibit.
16 a. How does the Company usually measure movement toward unity with
17 cost ofservice?
18 A. Avista uses the relationship of each customer group's earned return to the
l9 overall Idaho electric earned return, called the retum ratio, as the measure of relative cost
20 recovery provided by present and proposed rates. At the workshop Commission Staff
21 expressed interest in considering a revenue-to-cost measurement of alignment with the
22 cost study in addition to the return ratio.
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o I Q. What is revenue-to-cost and what does it add to interpretation of cost
2 study results?
3 A. Revenue-to-cost is a stand-alone measure of how each group's revenue
4 compares to total cost of service for the group (as indicated by the cost study). It can be
5 shown as a ratio of revenue divided by cost or the difference of cost less revenue. A
6 revenue-to-cost ratio less than 1.00 indicates that the customer group is not covering the
7 costs to serve them, whereas a ratio greater than 1.00 indicates that the customer group is
8 paying more than the cost to serve them (providing a subsidy to other groups). When
9 shown as the difference of cost less revenue, the value represents the revenue change
10 necessary to equal the cost ofservice indicated by the cost study.
I I Table No. l, above (page l2) included both "revenue-to-cost" ratios and "cost less
12 revenue" values in addition to the rate of return and return ratios produced by the
13 Company's Base Case cost of service study presented as Exhibit ll, Schedule 3. The
l4 implications of both measures are essentially the same, but generally the return ratio is
15 more sensitive to moderate revenue change proposals.
16 a. Moving on to cost of service methodology, in the Settlement
17 Stipulation in the 2017 Case the Company agreed to provide, at a minimum, three
18 cost of service studies in this rate case.e Did the workshop discussion arrive at
19 methodologies the parties wanted to see?
20 A. There were many different thoughts shared at the workshop. The
21 workshop concluded with agreement that the parties would confer among themselves and
22 provide any other methodology suggestions to Avista. On April 15,2019, IFG submitted
e AVU-E-17-01 Settlement Stipulation Provision l7 approved by IPUC Order No. 33953.
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o 1 written comments identifying recommendations for the electric cost of service studies in
2 this case. Based on the conversations held at the workshop and IFG's written comments,
3 Avista developed three methodological alternatives.
4 Q. Would you please describe your first alternative methodology?
5 A. For all of the scenarios, I started with the Company Base Case (which
6 represents the methodology presented in all recent prior cases) and made specific
7 changes. The first scenario (Scenario I ) incorporated the classification of Distribution
8 Land and Land Rights (FERC Plant Account 360) as related to other distribution plant in
9 FERC Plant Accounts 361 through 367. The rationale behind this modification is that the
l0 land or land rights are not directly related to customer demand, but rather are necessary
I I support for the substations and distribution lines that provide service to customers.
12 a. What were the results of this scenario?
13 A. Please see Page I of Exhibit I l, Schedule 5 which shows the key results
14 of alternative Scenario l, as well as a comparison to the Base Case results. Lines 17 and
15 18 show the impact of this change in methodology on the return ratio and total costs
l6 produced by the study. Scenario I is not a material change from the Company Base Case.
17 a. Would you please describe your second alternative methodology?
18 A. The second scenario (Scenario 2) modified the coincident peak allocation
19 factor which is used on all demand-related production and transmission costs to reflect
20 the average of the seven highest monthly peaks during the test period. For the 2018 test
2l period, the seven highest peak months were August, July, February, January, December,
22 March and November (ordered from highest to lowest peak values). The purpose of this
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o I scenario is to emphasize the winter and summer peaks in the assignment of demand-
2 related costs.
3 Q. What was the impact of this methodology change?
4 A. Please see Page 2 of Exhibit ll, Schedule 5 which shows key results of
5 alternative Scenario 2, as well as a comparison to the Base Case results. This change
6 increased costs considerably for the Residential customer group, slightly for Street and
7 Area Light group and reduced costs for all other rate groups especially Large General
8 Service as shown on line 18. On a relative basis, the greatest impact was to Pumping
9 Service where the return ratio improved from 0.96 to 1.22 as a result of removing spring
l0 and fall contributions to the coincident peak cost assignment.
11 a. Would you please describe your third alternative methodology?
12 A. The third scenario (Scenario 3) also involved modification of the
l3 coincident peak allocation factor which is used on all demand-related production and
14 transmission costs. This methodology uses all l2 monthly peaks, but the demand values
15 are weighted by the marginal cost of power in each month. Mr. Kalich identified the
16 Aurora On-Peak Prices included in his pro forma power supply workpapers as the
17 appropriate monthly marginal values to use for weighting peak demand. This
18 methodology emphasizes the higher cost months (which may or may not be the highest
l9 peak months) without allowing the potential for free ridership that occurs when not all
20 months are represented in the demand allocation factor.
2l a. What were the results of Scenario 3?
22 A. Please see Page 3 of Exhibit 11, Schedule 5 which shows key results of
23 alternative Scenario 3, as well as a comparison to the Base Case results. This
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o 1 methodology increased cost responsibility moderately for Residential, slightly for:
2 General, Extra Large General 25P, and Street and Area Lights while it reduced cost
3 responsibility moderately for Large General, Extra Large General 25, and Pumping.
4 Q. Are there any common implications from the results of all the cost of
5 service studies?
6 A. Please see Table 2 which shows the Return Ratio from each of the studies:
7 Table No.2:
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Customer Class
Return Ratio
Residential Service Schedule 1
General Service Schedules 1.1/12
Large General Service Schedules 21/22
Extra Large General Service Schedule 25
Extra Large General Service Clearwater
Paper Schedule 25P
Pumping Service Schedules 3U32
Lighting Service Schedules 4l - 49
Total ldaho Electric System
Base Case Scenario 1 Scenario 2 Scenario 3
0.82
r.52
1.09
0.88
0,82
1.52
1.09
0.88
0.75
1.53
1.16
0.98
0.81
t.52
L,7L
0,91
0.94 0.95 1.06 0.94
0.96
1.54
1.00
0.96
1.53
1,00
L.22
1..49
1.00
1.08
r.52
1.00
All ofthe studies indicate Residential Service Schedule I under-recovers assigned
costs more than any other group and both General Service Schedules llll2 andlighting
Service Schedules 41 - 49 over-recover their assigned costs by a considerable amount.
Results vary for the other rate groups, but they are all relatively close to providing the
overall return for the Idaho electric system.
a. Does this conclude your pre-filed direct testimony?
A. Yes.
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a Knox, Di
Avista Corporation
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