20170612Knox 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-17-01
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND ) DIRECT TESTIMONY
NATURAL GAS SERVICE TO ELECTRIC ) OF
AND NATURAL GAS CUSTOMERS IN THE ) TARA L. KNOX
STATE OF IDAHO )

FOR AVISTA CORPORATION

(ELECTRIC ONLY)

Knox, Di 1
Avista Corporation
I. INTRODUCTION 1
Q. Please state your name, business address and 2
present position with Avista Corporation. 3
A. My name is Tara L. Knox and my business address is
1411 East Mission Avenue, Spokane, Washington. I am employed
as a Senior Regulatory Analyst in the State and Federal
Regulation Department.
Q. Would you briefly describe your duties? 8
A. Yes. I am responsible for preparing the electric
cost of service studies for the Company, as well as providing
support for the preparation of results of operations
reports, among other things.
Q. What is your educational background and 13
professional experience? 14
A. I am a graduate of Washington State University
with a Bachelor of Arts degree in General Humanities in 1982,
and a Master of Accounting degree in 1990. As an employee
in the State and Federal Regulation Department at Avista
since 1991, I have attended several ratemaking classes,
including the EEI Electric Rates Advanced Course that
specializes in cost allocation and cost of service issues.
I am also a member of the Cost of Service Working Group and
the Northwest Pricing and Regulatory Forum, which are
discussion groups made up of technical professionals from
Knox, Di 2
Avista Corporation
regional utilities and utilities throughout the United
States and Canada concerned with cost of service issues.
Q. What is the scope of your testimony in this 3
proceeding? 4
A. My testimony and exhibits will cover the Company’s 5
electric revenue normalization adjustment to the test year
results of operations, the proposed Load Change Adjustment
Rate to be used in the Power Cost Adjustment and Fixed Cost
Adjustment mechanisms, and the electric cost of service
study performed for this proceeding. A table of contents
for my testimony is as follows:
Description Page 12
I. Introduction 1
II. Electric Revenue Normalization 3
III. Proposed Load Change Adjustment Rate 9
IV. Electric Cost of Service 11
17
Q. Are you sponsoring any exhibits in this case? 18
A. Yes. I am sponsoring Exhibit No. 14 composed of
three 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, and
Schedule 3 presents the electric cost of service study
summary results.
Knox, Di 3
Avista Corporation
Q. Were these exhibit schedules prepared by you or 1
under your direction? 2
A. Yes, they were.

II. ELECTRIC REVENUE NORMALIZATION 5
Q. Would you please describe the electric revenue 6
normalization adjustment included in Company witness Ms. 7
Andrews’ pro forma results of operations? 8
A. Yes. The electric revenue normalization adjustment
represents the difference between the Company’s actual 10
recorded retail revenues during the 12-months ended December
2016 test period, and base rate retail revenues on a
normalized (pro forma) basis. The total revenue
normalization adjustment increases Idaho net operating
income by $1,208,000, as shown in adjustment column 2.07 on
page 6 of Ms. Andrews’ Exhibit No. 12, Schedule 1.
The revenue normalization adjustment consists of four
primary components: 1) 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
Knox, Di 4
Avista Corporation
2016 Fixed Cost Adjustment (FCA) mechanism as well as a true-
up to the 2015 earnings test provision.
Q. Since these elements are combined into a single 3
adjustment, would you please identify the impact of each 4
component? 5
A. Yes. A breakdown of the four components of the
revenue normalization is as follows:
1. The re-pricing of billed usage including the
effects of the January 1, 2017 base rate increase
(AVU-E-16-03), as well as the elimination of adder
schedule revenue and related amortization expense
(Schedule 59 Residential Exchange Credit, Schedule
91 Public Purpose Tariff Rider, Schedule 95
Optional Renewable Power and Schedule 97 Rebate of
Electric Earnings Test Deferral)1 results in an
increase to net income of $3,115,000.
2. The re-pricing of unbilled calendar usage and
elimination of unbilled adder schedule revenue and
expense results in a decrease to net income of
$96,000.2
3. The weather adjustment increases net income
$2,343,000.
4. The elimination of the 2016 FCA deferred revenue
and 2015 earnings test provision true-up decreases
net income by $4,154,000.
The combined impact of these four elements is an
increase to net income of $1,208,000.

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 2015 usage billed
in January 2016 from the 2016 test year, adding December 2016 usage
billed in January 2017 to the 2016 test year, and re-pricing the net
usage at present base rates.
Knox, Di 5
Avista Corporation
Q. Earlier you stated that customer usage is 1
“adjusted for any known and measurable changes”. What 2
material usage adjustments were made to the 2016 test year? 3
A. Two large customers shifted from Schedule 21 to
Schedule 25 during the test year. In addition, the usage on
Schedule 25P is expected to be reduced later in 2017, prior
to new rates going into effect. Both of these changes were
reflected in the re-pricing of billed usage. These estimated
load reductions from the test year were provided to Mr.
Kalich in order to capture the associated cost reduction in
the power supply adjustment.
Q. Have you quantified the impact of the load 12
reductions since the last general rate case on the revenue 13
requirement in this case? 14
A. Yes. Pumping Service Schedules 31/32 had
reductions in usage compared to the 2015 test year billing
determinants used to set present rates. For Schedule 25P,
in addition to the expected reduction in load later in 2017
indicated above, the 2016 test period Schedule 25P load is
already lower than the load in 2015. The following table
compares the usage and revenues expected from the rates
approved in Case No. AVU-E-16-03 with the usage and revenues
at present rates in this case for Schedule 25P and Schedules
31/32:
Knox, Di 6
Avista Corporation
Schedule Case No.Case No.
Number AVU-E-16-03 AVU-E-17-01 Difference
Revenue $000s
Ex. Lg. Gen. Service 25P 21,634$ 19,145$ (2,489)$
Pumping Service 31,32 5,919$ 5,494$ (425)$
Total Revenue Difference 27,553$ 24,639$ (2,915)$
kWh's
Ex. Lg. Gen. Service 25P 419,473,590 362,572,860 (56,900,730)
Pumping Service 31,32 65,364,271 60,392,324 (4,971,947)
Total kWh difference 484,837,861 422,965,184 (61,872,677)
Table No. 13

Q. Please briefly summarize the electric weather 8
normalization process. 9
A. The Company’s electric weather normalization
adjustment calculates the change in kWh usage required to
adjust actual loads during the 2016 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

3 Lower power costs associated with these reduced loads, estimated using
the proposed PCA Load Change Adjustment Rate, would be approximately
$1.5 million resulting in a net revenue requirement impact of
approximately $1.4 million.
Knox, Di 7
Avista Corporation
normal heating/cooling degree-days and monthly test period
observed heating/cooling degree-days.
Q. Have the seasonal weather sensitivity factors been 3
updated since the last rate case? 4
A. Yes. The factors used in the weather adjustment
are based on regression analysis of monthly billed use-per-
customer from January 2006 through December 2015, which is
the most recent completed analysis.
Q. What data did you use to determine “normal” 9
heating and cooling degree days? 10
A. Normal heating and cooling degree days are based
on a rolling 30-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 1987
through 2016.
Q. Is this proposed weather adjustment methodology 20
consistent with the methodology utilized in the Company’s 21
last general rate case in Idaho? 22
A. Yes. The process for determining the weather
sensitivity factors and the monthly adjustment calculation
Knox, Di 8
Avista Corporation
is consistent with the methodology presented in Case No.
AVU-E-16-03.
Q. What was the change in kWhs resulting from weather 3
normalization for the 12-months ended December 2016 test 4
year? 5
A. Weather was warmer than normal throughout 2016.
Since electric usage is impacted by both heating and cooling,
weather normalization required an addition to usage for warm
weather during the winter and spring that was partially
offset by a reduction to usage for the hot summer months.
Overall, the adjustment to normal required the addition
of 766 heating degree-days during the heating season,4 and
the deduction of 19 cooling degree-days during the summer
season.5 The annual total adjustment to Idaho electric sales
volumes was an addition of 42,628,368 kWhs, which is
approximately 1.5% of billed usage.
The electric system monthly weather adjustment volumes
were provided to Company witnesses Mr. Kalich and Mr. Johnson
as an input to the Pro Forma Power Supply adjustment.

4 The heating season includes the months of January 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.
Knox, Di 9
Avista Corporation
III. PROPOSED LOAD CHANGE ADJUSTMENT RATE 1
Q. What is the Load Change Adjustment Rate? 2
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 11
Adjustment (FCA) mechanism.6
Q. How is the rate determined? 13
A. The proposed LCAR was determined by first
computing the proposed revenue requirement on the total
production and transmission costs contained within Ms.
Andrews’ Idaho electric pro forma total results of 17
operations. The production/transmission revenue requirement
amount is then divided by the Idaho normalized retail load
used to set rates in order to arrive at the average
production and transmission cost-per-kWh embedded in

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 10
Avista Corporation
proposed rates. This amount is then multiplied by the
proportion of production and transmission costs classified
as energy-related in the cost of service study. The LCAR,
therefore, represents the energy-related portion of Avista’s 4
production and transmission costs, on a per-kWh basis.
Q. Do you have an exhibit schedule that shows the 6
calculation of the proposed LCAR for the 2018 and 2019 rate 7
years? 8
A. Yes. Exhibit No. 14, Schedule 1 begins with the
identification of the production and transmission revenue,
expense and rate base amounts included in each of Ms.
Andrews’ actual, restating, and pro forma adjustments to
results of operations. The “2018 Pro Forma Total” on Line
30 at the bottom of page 1 shows the resulting production
and transmission cost components.
Page 2 shows the revenue requirement calculation on the
production and transmission cost components. The rate of
return and debt cost percentages on Line 2 are inputs from
the proposed cost of capital. The normalized retail load on
Line 10 comes from the workpapers supporting the revenue
normalization adjustment. Line 11 represents the average
total production and transmission cost-per-kWh proposed to
be embedded in Idaho customer retail rates. Lines 12 and 13
are values taken from the cost of service study report titled
Knox, Di 11
Avista Corporation
“Functional Cost Summary by Classification at Uniform
Requested Return” which represents total costs at unity.
Line 12 shows the amount of production and transmission costs
classified as energy-related, while Line 13 shows the total
production and transmission costs in the study.
The same process is repeated for the 2019 rate year pro
forma period on pages 3 and 4 of Exhibit 14, Schedule 1.
(“2019 Pro Forma Total” production and transmission cost 8
components are shown on Line 35 of Page 3).
The resulting 2018 LCAR on Page 2, Line 14 is $0.02489
per kWh or $24.89 per MWh. The resulting 2019 LCAR on Page
4, Line 14 is $0.02534 per kWh or $25.34 per MWh. The
calculation of the LCAR for each 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 18
Q. Please briefly summarize your testimony related to 19
the electric cost of service study. 20
A. I believe the Base Case cost of service study
presented in this case is a fair representation of the costs
to serve each customer group. The Base Case study shows
Residential Service Schedule 1, Extra Large General Service
Knox, Di 12
Avista Corporation
Schedule 25, and Pumping Service Schedules 31/32 provide
less than the overall rate of return under present rates.
All of the other service schedules provide more than the
overall rate of return under present rates to varying
degrees.
Q. What is an electric cost of service study and what 6
is its purpose? 7
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 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. 14 explains the basic concepts
involved in performing an electric cost of service study.
Knox, Di 13
Avista Corporation
It also details the specific methodology and assumptions
utilized in the Company’s Base Case cost of service study.
Q. What is the basis for the electric cost of service 3
study provided in this case? 4
A. The electric cost of service study provided by the
Company as Exhibit No. 14, Schedule 3 is based on the 2018
Pro Forma Study presented by Ms. Andrews in Exhibit No. 12,
Schedule 1.
Q. Would you please explain the cost of service study 9
presented in Exhibit No. 14, Schedule 3? 10
A. Yes. Exhibit No. 14, 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. Ehrbar 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 recovery (cost). These comparisons show how
Knox, Di 14
Avista Corporation
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.
Q. Given that the specific details of this 14
methodology are described in the narrative in Exhibit No. 15
14, Schedule 2, would you please give a brief overview of 16
the key elements and the history associated with those 17
elements? 18
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 and AVU-E-16-03).
Transmission costs are classified as 100% demand and
allocated by the average of the 12 monthly coincident peaks.
Knox, Di 15
Avista Corporation
This methodology is the same treatment as the last three
Idaho cases (Case Nos. AVU-E-12-08, AVU-E-15-05 and AVU-E-
16-03) and reflects the methodology accepted in the
Settlement in Case No. AVU-E-10-01.
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-04-01.
Q. Does the Company’s electric Base Case cost of 18
service study follow the methodology filed in the Company’s 19
last electric general rate case in Idaho? 20
A. Yes.

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 16
Avista Corporation
Q. What is the Company proposing in this case with 1
regard to the peak credit methodology? 2
A. In this case the Company is proposing to use the
system load factor to determine the proportion of the
production function that is demand-related.8 This peak
credit ratio is then applied uniformly to all production
costs. This is the same method the Company proposed in Case
Nos. AVU-E-11-01, AVU-E-15-05, and AVU-E-16-03 that was
derived through cost of service workshops held at the Idaho
Commission in February 2011 and September 2012.
Q. What do you believe are the benefits of using the 11
system load factor to determine the peak credit ratio? 12
A. There are several benefits to the system load
factor approach for identifying the demand-related
proportion of production costs: 1) it is simple and
straightforward to calculate; 2) it is directly related to
the system and test year under evaluation; and 3) the
relationship should remain relatively stable from year to
year.
Q. What are the results of the Company’s electric 20
cost of service study presented in this case? 21

8 One minus the load factor equals the demand percentage or peak credit
ratio.
Knox, Di 17
Avista Corporation
Customer Class Rate of Return Return Ratio
Residential Service Schedule 1 5.14%0.81
General Service Schedule 11/12 9.37%1.47
Large General Service Schedule 21/22 7.25%1.14
Extra Large General Service Schedule 25 6.13%0.96
Extra Large General Service Clearwater
Paper Schedule 25P 6.78%1.06
Pumping Service Schedule 31/32 5.88%0.92
Lighting Service Schedules 41-49 6.84%1.07
Total Idaho Electric System 6.38%1.00
A. Table No. 2 below shows the rate of return and the
relationship of the customer class return to the overall
return (relative return ratio) at present rates for each
rate schedule:
Table No. 2: 5
6
7
8
9
10
11
12

As can be observed from the above table, Residential
Service Schedule 1, Extra Large General Service Schedule 25,
and Pumping Service Schedules (31/32) show under-recovery of
the costs to serve them. The General, Large General, Extra
Large General-Clearwater Paper, and Lighting Service
Schedules (11/12, 21/22, 25P, and 41-49) show over-recovery
of the costs to serve them. The summary results of this
study were provided to Mr. Ehrbar for consideration in the
development of proposed rates.
Knox, Di 18
Avista Corporation
Q. Does this conclude your pre-filed direct 1
testimony? 2
A. Yes.