20210129Knox Direct.pdf

DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
[e-mail]

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-21-01
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC SERVICE ) DIRECT TESTIMONY
TO ELECTRIC CUSTOMERS IN ) OF
THE STATE OF IDAHO ) TARA L. KNOX
)

FOR AVISTA CORPORATION

(ELECTRIC)

Knox, Di 1
Avista Corporation
I. INTRODUCTION 1
Q. Please state your name, business address and present position with 2
Avista Corporation. 3
A. My name is Tara L. Knox and my business address is 1411 East Mission 4
Avenue, Spokane, Washington. I am employed as Manager of Regulatory Accounting 5
Initiatives in the Regulatory Affairs Department. 6
Q. Would you briefly describe your duties? 7
A. Yes. I am responsible for preparing the electric cost of service studies for 8
the Company, as well as providing support for the preparation of results of operations 9
reports, among other things. 10
Q. What is your educational background and professional experience? 11
A. I am a graduate of Washington State University with a Bachelor of Arts 12
degree in General Humanities in 1982, and a Master of Accounting degree in 1990. As 13
an employee in the Regulatory Affairs Department at Avista since 1991, I have attended 14
several ratemaking classes, including the EEI Electric Rates Advanced Course that 15
specializes in cost allocation and cost of service issues. I am also a member of the Cost 16
of Service Working Group and the Northwest Pricing and Regulatory Forum, which are 17
discussion groups made up of technical professionals from regional utilities and utilities 18
throughout the United States and Canada concerned with cost of service issues. 19
Q. What is the scope of your testimony in this proceeding? 20
A. My testimony and exhibits will cover the Company’s electric revenue 21
normalization adjustment to the test year results of operations, the proposed Load Change 22
Adjustment Rate to be used in the Power Cost Adjustment and Fixed Cost Adjustment 23
Knox, Di 2
Avista Corporation
mechanisms, and the electric cost of service study performed for this proceeding. A table 1
of contents for my testimony is as follows: 2
Description Page 3
I. Introduction 1 4
II. Electric Revenue Normalization 2 5
III. Proposed Load Change Adjustment Rate 6 6
IV. Electric Cost of Service 8 7
8
Q. Are you sponsoring any exhibits in this case? 9
A. Yes. I am sponsoring Exhibit No. 16 composed of three schedules. 10
Schedule 1 details the calculation of the proposed Load Change Adjustment Rate, 11
Schedule 2 includes a narrative of the electric cost of service study process, Schedule 3 12
presents the base case electric cost of service study summary results. 13
Q. Were these exhibit schedules prepared by you or under your 14
direction? 15
A. Yes, they were. 16
17
II. ELECTRIC REVENUE NORMALIZATION 18
Q. Would you please describe the electric revenue normalization 19
adjustment included in Company witness Ms. Andrews’ pro forma results of 20
operations? 21
A. Yes. The electric revenue normalization adjustment represents the 22
difference between the Company’s actual recorded retail revenues during the 12-months 23
ended December 2019 test period, and base rate retail revenues on a normalized (pro 24
forma) basis. The total revenue normalization adjustment decreases Idaho net operating 25
Knox, Di 3
Avista Corporation
income by $7,046,000, as shown in adjustment column 2.07 on page 7 of Ms. Andrews’ 1
Exhibit No. 5, Schedule 1. 2
The revenue normalization adjustment consists of four primary components: 1) 3
re-pricing customer usage (adjusted for any known and measurable changes) to base tariff 4
rates presently in effect, 2) adjusting customer load and revenue to a 12 -month calendar 5
basis (unbilled revenue adjustment), 3) weather normalizing customer usage and revenue, 6
and 4) eliminating both the deferred revenue associated with the 2019 Fixed Cost 7
Adjustment (FCA) mechanism and the 2017 Tax Reform Provision for Rate Refund 8
recorded in 2019 results. 9
Q. Since these elements are combined into a single adjustment, would 10
you please identify the impact of each component? 11
A. Yes. A breakdown of the four components of the revenue normalization 12
is as follows: 13
1. The re-pricing of billed usage including the effects of the December 1, 14
2019 base rate decrease, elimination of the revenue and expense associated 15
with the Clearwater Purchase and Sale agreement, as well as the 16
elimination of adder schedule revenue and related amortization expense 17
(Schedule 59 Residential Exchange Credit, Schedule 74 Temporary Tax 18
Refund, Schedule 75 Fixed Cost Adjustment, Schedule 91 Public Purpose 19
Tariff Rider, Schedule 95 Optional Renewable Power and Sched ule 97 20
Rebate of Electric Earnings Test Deferral)1 results in a decrease to net 21
income of $4,848,000. 22
2. The re-pricing of unbilled calendar usage and elimination of unbilled 23
adder schedule revenue and expense results in a decrease to net income of 24
$494,000.2 25
3. The weather adjustment decreases net income $1,431,000. 26
4. The elimination of the 2019 FCA deferred revenue and tax reform 27
provision for rate refund decreases net income by $273,000. 28

1 Municipal Franchise Fee and Power Cost Adjustment revenues and related expenses are eliminated in
separate adjustments.
2 The unbilled adjustment consists of removing December 2018 usage billed in January 2019 from the
2019 test year, adding December 2019 usage billed in January 2020 to the 2019 test year, and re-pricing
the net usage at present base rates.
Knox, Di 4
Avista Corporation
The combined impact of these four elements is a decrease to net income of 1
$7,046,000. 2
Q. Earlier you stated that customer usage is “adjusted for any known 3
and measurable changes”. What material usage adjustments were made to the 2019 4
test year? 5
A. One large Schedule 25 customer was temporarily moved from Schedule 6
25 to Schedule 21 for a portion of the 2019 test year until they were able to return to full 7
production. The customer usage had returned to normal late in 2019 and was 8
subsequently returned to Schedule 25. The repricing adjustment included eliminating the 9
volumes recorded as Schedule 21 and replacing them with the customer’s Schedule 25 10
billing determinants recorded in 2020.3 The net adjustment to 2019 historical retail load 11
(approximately 7 million kWhs) was provided to Company witness Mr. Kalich for 12
inclusion in normalized power supply costs. 13
Q. Please briefly summarize the electric weather normalization process. 14
A. The Company’s electric weather normalization adjustment calculates the 15
change in kWh usage required to adjust actual loads during the 2019 test period to the 16
amount expected if weather had been normal. This adjustment incorporates the effect of 17
both heating and cooling on weather-sensitive customer groups. The weather adjustment 18
is developed from a regression analysis of ten years of billed usage per customer and 19
billing period heating and cooling degree-day data. The resulting seasonal weather 20
3 An error occurred with the manual adjustment for the 2019 number of bills shifted from Schedule 21 to
Schedule 25. Schedule 21 number of bills were correctly reduced, but Schedule 25 number of bills were
not correspondingly increased leading to an understatement of Schedule 25 fixed demand charge revenue.
The discrepancy was discovered after revenue requirement had been finalized. The Company will provide
updated revenue normalization, cost of service, and rate design workpapers. Correction of this error would
have reduced revenue requirement by $112,000.
Knox, Di 5
Avista Corporation
sensitivity factors (use-per-customer-per-heating-degree day and use-per-customer-per-1
cooling-degree day) are applied to monthly test period customers and the difference 2
between normal heating/cooling degree-days and monthly test period observed 3
heating/cooling degree-days. 4
Q. Have the seasonal weather sensitivity factors been updated since the 5
last rate case? 6
A. Yes. The factors used in the weather adjustment are based on regression 7
analysis of monthly billed use-per-customer from January 2009 through December 2018, 8
which is the most recent completed analysis. 9
Q. What data did you use to determine “normal” heating and cooling 10
degree days? 11
A. Normal heating and cooling degree days are based on a rolling 30-year 12
average of heating and cooling degree-days reported for each month by the National 13
Weather Service for the Spokane Airport weather station. Each year the normal values 14
are adjusted to capture the most recent year with the oldest year dropping off, thereby 15
reflecting the most recent information available at the end of each calendar year. The 16
calculation includes the 30-year period from 1990 through 2019. 17
Q. Is this proposed weather adjustment methodology consistent with the 18
methodology utilized in the Company’s last general rate case in Idaho? 19
A. Yes. The process for determining the weather sensitivity factors and the 20
monthly adjustment calculation is consistent with the methodology presented in Case No. 21
AVU-E-19-04. 22
Knox, Di 6
Avista Corporation
Q. What was the change in kWhs resulting from weather normalization 1
for the 12-months ended December 2019 test year? 2
A. During the 2019 test year, weather was colder than normal during the 3
winter and warmer than normal during the summer. Since electric usage is impacted by 4
both heating and cooling, weather normalization required a reduction to usage for colder 5
than normal weather during the winter months and a reduction to usage for warmer than 6
normal summer months. Overall, the adjustment to normal required the deduction of 229 7
heating degree-days during the heating season,4 and the deduction of 20 cooling degree-8
days during the summer season.5 The annual total adjustment to Idaho electric sales 9
volumes was a reduction of 21,750,200 kWhs, which is approximately 0.7% of billed 10
usage. The electric system monthly weather adjustment volumes were provided to 11
Company witness Mr. Kalich as an input to the Pro Forma Power Supply adjustment. 12
13
III. PROPOSED LOAD CHANGE ADJUSTMENT RATE 14
Q. What is the Load Change Adjustment Rate? 15
A. The Load Change Adjustment Rate (LCAR) is part of the Power Cost 16
Adjustment (PCA) mechanism that prices the change in power supply-related costs 17
associated with the change in actual retail loads from the retail loads that were used to set 18
the PCA base costs. The LCAR determination process for all Idaho investor-owned 19
utilities was established in IPUC Case No. GNR-E-10-03, Order No. 32206, which was 20

4 The heating season includes the months of January through June and October through December.
5 The summer season includes the months of April through October as cooling degree days may occur
during that time. The shoulder months of April through June and October are included in both seasons
because both heating load and cooling load fluctuations may occur.
Knox, Di 7
Avista Corporation
approved on March 15, 2011. The LCAR is also a key component in the Company’s 1
electric Fixed Cost Adjustment (FCA) mechanism.6 2
Q. How was the LCAR determined? 3
A. The proposed LCAR was determined by first computing the proposed 4
revenue requirement on the total production and transmission costs contained within Ms. 5
Andrews’ Idaho electric pro forma total results of operations. The 6
production/transmission revenue requirement amount is then divided by the Idaho 7
normalized retail load used to set rates in order to arrive at the average production and 8
transmission cost-per-kWh embedded in proposed rates. This amount is then multiplied 9
by the proportion of production and transmission costs classified as energy-related in the 10
cost of service study. The LCAR, therefore, represents the energy-related portion of 11
Avista’s production and transmission costs, on a per-kWh basis. 12
Q. Do you have an exhibit schedule that shows the calculation of the 13
proposed LCAR for the rate years beginning September of 2021 and 2022? 14
A. Yes. Exhibit No. 16, Schedule 1 begins with the identification of the 15
production and transmission revenue, expense and rate base amounts included in each of 16
Ms. Andrews’ actual, restating, and pro forma adjustments to results of operations. The 17
resulting production and transmission cost components are summarized on page 1. Rate 18
Year 1 (September 1, 2021 – August 31, 2022) values are shown on Line 35 and Rate 19
Year 2 (September 1, 2022 – August 31, 2023) values are shown on Line 42. 20

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.
Knox, Di 8
Avista Corporation
Page 2 shows the revenue requirement calculations for each rate year based on the 1
production and transmission cost components from page 1. The rate of return and debt 2
cost percentages on Line 2 are inputs from the proposed cost of capital (Exhibit No. 5, 3
Schedule 1, Page 4). The normalized retail load on Line 10 comes from the workpapers 4
supporting the revenue normalization adjustment. Line 11 represents the average total 5
production and transmission cost-per-kWh proposed to be embedded in Idaho customer 6
retail rates. Lines 12 and 13 are values taken from the cost of service study report titled 7
“Functional Cost Summary by Classification at Uniform Requested Return” which 8
represents total costs at unity. Line 12 shows the amount of production and transmission 9
costs classified as energy-related, while Line 13 shows the total production and 10
transmission costs in the study. 11
The resulting LCARs on Page 2, Line 14 are $0.02572 per kWh or $25.72 per 12
MWh for Rate Year 1 and $0.02652 per kWh or $26.52 per MWh for Rate Year 2. The 13
calculation of the LCAR for each rate year will be revised based on the final production 14
and transmission costs, and rate of return, that are approved by the Commission in this 15
case. 16
17
IV. ELECTRIC COST OF SERVICE 18
Q. Please briefly summarize your testimony related to the electric cost of 19
service study. 20
A. I believe the Base Case electric cost of service study presented in this case 21
is a fair representation of the costs to serve each customer group. The Base Case study 22
shows Residential Service Schedule 01 and Extra-Large General Service Schedule 25 23
Knox, Di 9
Avista Corporation
provide less than the overall rate of return under present rates. All of the other service 1
schedules provide more than the overall rate of return under present rates to varying 2
degrees. 3
Q. What is an electric cost of service study and what is its purpose? 4
A. An electric cost of service study is an engineering-economic study, which 5
separates the revenue, expenses, and rate base associated with providing electric service 6
to designated groups of customers. The groups are made up of customers with similar 7
load characteristics and facilities requirements. Costs are assigned or allocated to each 8
group based on, among other things, test period load and facilities requirements, resulting 9
in an evaluation of the cost of the service provided to each group. The rate of return by 10
customer group indicates whether the revenue provided by the customers in each group 11
recovers the cost to serve those customers. 12
The study results are used as a guide in determining the appropriate rate spread 13
among the groups of customers. Schedule 2 of Exhibit No. 16 explains the basic concepts 14
involved in performing an electric cost of service study. It also details the specific 15
methodology and assumptions utilized in the Company’s Base Case cost of service study. 16
Q. What is the basis for the electric cost of service study provided in this 17
case? 18
A. The electric cost of service study provided by the Company as Exhibit No. 19
16, Schedule 3 is based on the 2019 Pro Forma Study presented by Ms. Andrews in 20
Exhibit No. 5, Schedule 1. 21
Q. Would you please explain the cost of service study presented in 22
Exhibit No. 16, Schedule 3? 23
Knox, Di 10
Avista Corporation
A. Yes. Exhibit No. 16, Schedule 3 is composed of a series of summaries of 1
the cost of service study results. The summary on page 1 shows the results of the study 2
by FERC account category. The rate of return by rate schedule and the ratio of each 3
schedule’s return to the overall return are shown on Lines 39 and 40. This summary was 4
provided to Company witness Mr. Miller for his consideration regarding rate spread and 5
rate design. The results will be discussed in more detail later in my testimony. 6
Pages 2 and 3 are both summaries that show the revenue-to-cost relationship at 7
current and proposed revenue. Costs by category are shown first at the existing schedule 8
returns (revenue); next the costs are shown as if all schedules were providing equal 9
recovery (cost). These comparisons show how far current and proposed rates are from 10
rates that would be in alignment with the cost study. Page 2 shows the costs segregated 11
into production, transmission, distribution, and common functional categories. Line 44 12
on page 2 shows the target change in revenue which would produce unity in this cost 13
study. Page 3 segregates the costs into demand, energy, and customer classifications. 14
Page 4 is a summary identifying specific customer-related costs embedded in the study. 15
The Excel model used to calculate the cost of service and supporting schedules 16
has been included in its entirety both electronically and in hard copy in the workpapers 17
accompanying this case. 18
Q. Given that the specific details of this methodology are described in the 19
narrative in Exhibit No. 16, Schedule 2, would you please give a brief overview of 20
the key elements and the history associated with those elements? 21
A. Yes. Production costs are classified to energy and demand in this case 22
based on the system load factor. The Company has presented this approach in prior 23
Knox, Di 11
Avista Corporation
general rate cases (Case Nos. AVU-E-11-01, AVU-E-15-05, AVU-E-16-03, AVU-E-17-1
01 and AVU-E-19-04). 2
Transmission costs are classified as 100% demand and allocated by the average 3
of the 12 monthly coincident peaks. This methodology is the same treatment as the last 4
five Idaho cases (Case Nos. AVU-E-12-08, AVU-E-15-05, AVU-E-16-03, AVU-E-17-5
01 and AVU-E-19-04) and reflects the methodology accepted in the Settlement in Case 6
No. AVU-E-10-01. 7
Distribution costs are classified and allocated by the basic customer theory 8
accepted by the Idaho Commission in Case No. WWP-E-98-11.7 Additional direct 9
assignment of demand-related distribution plant has been incorporated to reflect 10
improvements accepted by the Commission in Case No. AVU-E-04-01. 11
Administrative and general costs are first directly assigned to production, 12
transmission, distribution, or customer relations functions. The remaining administrative 13
and general costs are categorized as common costs and have been assigned to customer 14
classes by the four-factor allocator accepted by the Idaho Commission in Case No. AVU-15
E-04-01. 16
Q. Does the Company’s electric Base Case cost of service study follow the 17
methodology filed in the Company’s last electric general rate case in Idaho? 18
A. Yes. 19
Q. What are the results of the Company’s electric Base Case cost of 20
service study presented in this case? 21
7 Basic customer cost theory classifies only meters, services, and street lights as customer-related plant; all
other distribution facilities are considered demand-related.
Knox, Di 12
Avista Corporation
A. Table No. 1 below summarizes the Base Case cost of service study results. 1
The first two columns show the rate of return and the relationship of the customer class 2
return to the overall return (relative return ratio) at present rates for each rate schedule.8 3
The next column presents the ratio of revenue provided by present rates divided by the 4
total cost of service at the requested overall return (revenue-to-cost ratio)9, followed by 5
the dollar value of the difference between total cost and present revenue for each customer 6
class.10 7
Table No. 1: 8
9
10
11
12
13
14
15
16

8 Avista typically has used the relationship of each customer group’s earned return to the overall Idaho
electric earned return, called the return ratio, as the measure of relative cost recovery provided by present
and proposed rates.
9 Revenue-to-cost is a stand-alone measure of how each group’s revenue compares to total cost of service
for the group (as indicated by the cost study). It can be shown as a ratio of revenue divided by cost or the
difference of cost less revenue. A revenue-to-cost ratio less than 1.00 indicates that the customer group is
not covering the costs to serve them, whereas a ratio greater than 1.00 indicates that the customer group is
paying more than the cost to serve them (providing a subsidy to other groups). When shown as the
difference of cost less revenue, the value represents the revenue change necessary to equal the cost of
service indicated by the cost study. 10 In my cost of service exhibit the Cost less Revenue value is called “Target Revenue Increase” and may
be found on Exhibit 16, Schedule 3, page 2, at line 44.
Customer Class
Rate of
Return
Return
Ratio
Revenue
to Cost
Ratio
Cost Less
Revenue
$000s
Residential Service Schedule 01 4.15%0.81 0.87 $16,574
General Service Schedules 11/12 7.08%1.38 0.98 $866
Large General Service Schedules 21/22 5.19%1.01 0.91 $4,966
Extra Large General Service Schedule 25 4.23%0.82 0.88 $2,325
Extra Large General Service Clearwater
Paper Schedule 25P 7.86%1.53 1.00 ($77)
Pumping Service Schedules 31/32 5.46%1.06 0.91 $533
Lighting Service Schedules 41 - 49 9.89%1.92 1.12 ($404)
Total Idaho Electric System 5.15%1.00 0.91 $24,783
Base Case Cost of Service Study Result Summary Statistics
Knox, Di 13
Avista Corporation
As can be observed from the above table, the return ratio measure of relative cost 1
recovery shows that Residential Service Schedule 01 and Extra-Large General Service 2
Schedule 25 provide less than the overall rate of return under present rates (under unity). 3
All other service schedules provide more than the overall rate of return under present 4
rates to varying degrees (over unity). The revenue-to-cost ratio measure indicates that 5
present revenues from Extra-Large General Service Clearwater Paper Schedule 25P and 6
the Lighting Service Schedules 41 – 49 meet or exceed the total cost of service produced 7
by the study. Present revenues from all other customer groups provide less than the total 8
cost to serve them. The summary results of this study were provided to Mr. Miller for 9
consideration in the development of proposed rates. 10
Q. Does this conclude your pre-filed direct testimony? 11
A. Yes. 12