20160526Knox 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-16-03
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC SERVICE ) DIRECT TESTIMONY
TO ELECTRIC CUSTOMERS IN THE ) OF
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 2
present position with Avista Corporation. 3
A. My name is Tara L. Knox and my business address is 4
1411 East Mission Avenue, Spokane, Washington. I am employed 5
as a Senior Regulatory Analyst in the State and Federal 6
Regulation Department. 7
Q. Would you briefly describe your duties? 8
A. Yes. I am responsible for preparing the electric 9
regulatory cost of service studies for the Company, as well 10
as providing support for the preparation of results of 11
operations reports, among other things. 12
Q. What is your educational background and 13
professional experience? 14
A. I am a graduate of Washington State University 15
with a Bachelor of Arts degree in General Humanities in 1982, 16
and a Master of Accounting degree in 1990. As an employee 17
in the State and Federal Regulation Department at Avista 18
since 1991, I have attended several ratemaking classes, 19
including the EEI Electric Rates Advanced Course that 20
specializes in cost allocation and cost of service issues. 21
I am also a member of the Cost of Service Working Group and 22
the Northwest Pricing and Regulatory Forum, which are 23
discussion groups made up of technical professionals from 24
Knox, Di 2
Avista Corporation
regional utilities and utilities throughout the United 1
States and Canada concerned with cost of service issues. 2
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 6
results of operations, the proposed Load Change Adjustment 7
Rate to be used in the Power Cost Adjustment mechanism, and 8
the electric cost of service study performed for this 9
proceeding. A table of contents for my testimony is as 10
follows: 11
Description Page 12
I. Introduction 1 13
II. Electric Revenue Normalization 3 14
III. Proposed Load Change Adjustment Rate 7 15
IV. Electric Cost of Service 9 16
17
Q. Are you sponsoring any exhibits in this case? 18
A. Yes. I am sponsoring Exhibit No. 12 composed of 19
three schedules. Schedule 1 details the calculation of the 20
proposed Load Change Adjustment Rate, Schedule 2 includes a 21
narrative of the electric cost of service study process, and 22
Schedule 3 presents the electric cost of service study 23
summary results. 24
Knox, Di 3
Avista Corporation
Q. Were these exhibit schedules prepared by you or 1
under your direction? 2
A. Yes, they were. 3
4
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 9
represents the difference between the Company’s actual 10
recorded retail revenues during the twelve months ended 11
December 2015 test period, and base rate retail revenues on 12
a normalized (pro forma) basis. The total revenue 13
normalization adjustment increases Idaho net operating 14
income by $3,635,000, as shown in adjustment column 2.07 on 15
page 6 of Ms. Andrews Exhibit No. 11, Schedule 1. 16
The revenue normalization adjustment consists of four 17
primary components: 1) re-pricing customer usage (adjusted 18
for any known and measurable changes) to base tariff rates 19
presently in effect, 2) adjusting customer load and revenue 20
to a 12-month calendar basis (unbilled revenue adjustment), 21
3) weather normalizing customer usage and revenue, and 4) 22
eliminating the provision for earnings sharing associated 23
with the 2015 earnings test. 24
Knox, Di 4
Avista Corporation
Q. Since these elements are combined into a single 1
adjustment, would you please identify the impact of each 2
component? 3
A. Yes. A breakdown of the four components of the 4
revenue normalization is as follows: 5
1. The re-pricing of billed usage including the 6
elimination of adder schedule revenue and related 7
amortization expense (Schedule 59 Residential 8
Exchange Credit, Schedule 91 Public Purpose Tariff 9
Rider, Schedule 95 Optional Renewable Power and 10
Schedule 97 Rebate of Electric Earnings Test 11
Deferral)1 results in an increase to net income of 12
$45,000. 13
2. The re-pricing of unbilled calendar usage and 14
elimination of unbilled adder schedule revenue and 15
expense results in an increase to net income of 16
$1,120,000.2 17
3. The weather adjustment increases net income 18
$1,113,000. 19
4. The elimination of the 2015 provision for rate 20
refund results in an increase to net income of 21
$1,357,000. 22
The combined impact of these four elements is an 23
increase to net income $3,635,000. 24
Q. Please briefly summarize the electric weather 25
normalization process. 26
A. The Company’s electric weather normalization 27
adjustment calculates the change in kWh usage required to 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 2014 usage billed
in January 2015 from the 2015 test year, adding December 2015 usage
billed in January 2016 to the 2015 test year, and re-pricing the net
usage at present base rates.
Knox, Di 5
Avista Corporation
adjust actual loads during the 2015 test period to the amount 1
expected if weather had been normal. This adjustment 2
incorporates the effect of both heating and cooling on 3
weather-sensitive customer groups. The weather adjustment 4
is developed from a regression analysis of ten years of 5
billed usage per customer and billing period heating and 6
cooling degree-day data. The resulting seasonal weather 7
sensitivity factors (use-per-customer-per-heating-degree 8
day and use-per-customer-per-cooling-degree day) are applied 9
to monthly test period customers and the difference between 10
normal heating/cooling degree-days and monthly test period 11
observed heating/cooling degree-days. 12
Q. Have the seasonal weather sensitivity factors been 13
updated since the last rate case? 14
A. Yes. The factors used in the weather adjustment 15
are based on regression analysis of monthly billed usage-16
per-customer from January 2005 through December 2014, which 17
is the most recent completed analysis. 18
Q. What data did you use to determine “normal” 19
heating and cooling degree days? 20
A. Normal heating and cooling degree days are based 21
on a rolling 30-year average of heating and cooling degree-22
days reported for each month by the National Weather Service 23
for the Spokane Airport weather station. Each year the 24
Knox, Di 6
Avista Corporation
normal values are adjusted to capture the most recent year 1
with the oldest year dropping off, thereby reflecting the 2
most recent information available at the end of each calendar 3
year. The calculation includes the 30-year period from 1986 4
through 2015. 5
Q. Is this proposed weather adjustment methodology 6
consistent with the methodology utilized in the Company’s 7
last general rate case in Idaho? 8
A. Yes. The process for determining the weather 9
sensitivity factors and the monthly adjustment calculation 10
is consistent with the methodology presented in Case No. 11
AVU-E-15-05. 12
Q. What was the change in kWhs resulting from weather 13
normalization for the twelve months ended December 2015 test 14
year? 15
A. Weather was warmer than normal throughout 2015, 16
except for November, which was slightly colder than normal. 17
The summer months of June, July and August were particularly 18
hot. Since electric usage is impacted by both heating and 19
cooling, weather normalization required an addition to usage 20
for warm weather during the winter and a reduction to usage 21
for the hot summer. These offsetting impacts resulted in a 22
moderate annual weather adjustment even though the monthly 23
variations were volatile. 24
Knox, Di 7
Avista Corporation
Overall, the adjustment to normal required the addition 1
of 1,022 heating degree-days during the heating season,3 and 2
the deduction of 335 cooling degree-days during the summer 3
season.4 The annual total adjustment to Idaho electric sales 4
volumes was an addition of 17,685,588 kWhs, which is 5
approximately 0.6% of billed usage. 6
The electric system monthly weather adjustment volumes 7
were provided to Company witnesses Mr. Kalich and Mr. Johnson 8
as an input to the Pro Forma Power Supply analysis. 9
10
III. PROPOSED LOAD CHANGE ADJUSTMENT RATE 11
Q. What is the Load Change Adjustment Rate? 12
A. The Load Change Adjustment Rate (LCAR) is part of 13
the Power Cost Adjustment (PCA) mechanism that prices the 14
change in power supply-related costs associated with the 15
change in actual retail loads from the retail loads that 16
were used to set the PCA base costs. The LCAR determination 17
process for all Idaho investor-owned utilities was 18
established in IPUC Case No. GNR-E-10-03, Order No. 32206, 19
which was approved on March, 15, 2011. 20
21

3 The heating season includes the months of January through June and
October through December.
4 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 8
Avista Corporation
Q. How is the rate determined? 1
A. The proposed LCAR was determined by computing the 2
proposed revenue requirement on the production and 3
transmission costs contained within Ms. Andrews’ Idaho 4
electric pro forma total results of operations. The 5
production/transmission revenue requirement amount is then 6
divided by the Idaho normalized retail load used to set rates 7
in order to arrive at the average production and transmission 8
cost-per-kWh embedded in proposed rates. This amount is 9
then multiplied by the proportion of production and 10
transmission costs classified as energy-related in the cost 11
of service study. 12
Q. Do you have an exhibit schedule that shows the 13
calculation of the proposed LCAR? 14
A. Yes. Exhibit No. 12, Schedule 1 begins with the 15
identification of the production and transmission revenue, 16
expense and rate base amounts included in each of Ms. 17
Andrews’ actual, restating, and pro forma adjustments to 18
results of operations. The “2017 Pro Forma Total” on Line 19
27 at the bottom of page 1 shows the resulting production 20
and transmission cost components. 21
Page 2 shows the revenue requirement calculation on the 22
production and transmission cost components. The rate of 23
return and debt cost percentages on Line 2 are inputs from 24
Knox, Di 9
Avista Corporation
the proposed cost of capital. The normalized retail load on 1
Line 10 comes from the workpapers supporting the revenue 2
normalization adjustment. Line 11 represents the average 3
total production and transmission cost-per-kWh proposed to 4
be embedded in Idaho customer retail rates. Lines 12 and 13 5
are values taken from the cost of service study report titled 6
“Functional Cost Summary by Classification at Uniform 7
Requested Return” which represents total costs at unity. 8
Line 12 shows the amount of production and transmission costs 9
classified as energy related, while Line 13 shows the total 10
production and transmission costs in the study. 11
The resulting 2017 LCAR on Line 14 is $0.02496 per kWh 12
or $24.96 per MWh. The calculation of the LCAR will be 13
revised based on the final production and transmission 14
costs, and rate of return, that are approved by the 15
Commission in this case. 16
17
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 21
presented in this case is a fair representation of the costs 22
to serve each customer group. The Base Case study shows 23
Residential Service Schedule 1 and Pumping Service Schedule 24
Knox, Di 10
Avista Corporation
31/32 provides less than the overall rate of return under 1
present rates. All of the other service schedules provide 2
more than the overall rate of return under present rates to 3
varying degrees. 4
Q. What is an electric cost of service study and what 5
is its purpose? 6
A. An electric cost of service study is an 7
engineering-economic study, which separates the revenue, 8
expenses, and rate base associated with providing electric 9
service to designated groups of customers. The groups are 10
made up of customers with similar load characteristics and 11
facilities requirements. Costs are assigned or allocated to 12
each group based on, among other things, test period load 13
and facilities requirements, resulting in an evaluation of 14
the cost of the service provided to each group. The rate of 15
return by customer group indicates whether the revenue 16
provided by the customers in each group recovers the cost to 17
serve those customers. 18
The study results are used as a guide in determining 19
the appropriate rate spread among the groups of customers. 20
Schedule 2 of Exhibit No. 12 explains the basic concepts 21
involved in performing an electric cost of service study. 22
It also details the specific methodology and assumptions 23
utilized in the Company’s Base Case cost of service study. 24
Knox, Di 11
Avista Corporation
Q. What is the basis for the electric cost of service 1
study provided in this case? 2
A. The electric cost of service study provided by the 3
Company as Exhibit No. 12, Schedule 3 is based on the twelve 4
months ended December 31, 2015 test year pro forma results 5
of operations presented by Ms. Andrews in Exhibit No. 11, 6
Schedule 1. 7
Q. Would you please explain the cost of service study 8
presented in Exhibit No. 12, Schedule 3? 9
A. Yes. Exhibit No. 12, Schedule 3 is composed of a 10
series of summaries of the cost of service study results. 11
The summary on page 1 shows the results of the study by FERC 12
account category. The rate of return by rate schedule and 13
the ratio of each schedule’s return to the overall return 14
are shown on Lines 39 and 40. This summary was provided to 15
Company witness Mr. Ehrbar for his consideration regarding 16
rate spread and rate design. The results will be discussed 17
in more detail later in my testimony. 18
Pages 2 and 3 are both summaries that show the revenue-19
to-cost relationship at current and proposed revenue. Costs 20
by category are shown first at the existing schedule returns 21
(revenue); next the costs are shown as if all schedules were 22
providing equal recovery (cost). These comparisons show how 23
far current and proposed rates are from rates that would be 24
Knox, Di 12
Avista Corporation
in alignment with the cost study. Page 2 shows the costs 1
segregated into production, transmission, distribution, and 2
common functional categories. Line 44 on page 2 shows the 3
target change in revenue which would produce unity in this 4
cost study. Page 3 segregates the costs into demand, energy, 5
and customer classifications. Page 4 is a summary 6
identifying specific customer-related costs embedded in the 7
study. 8
The Excel model used to calculate the cost of service 9
and supporting schedules has been included in its entirety 10
both electronically and in hard copy in the workpapers 11
accompanying this case. 12
Q. Given that the specific details of this 13
methodology are described in the narrative in Exhibit No. 14
12, Schedule 2, would you please give a brief overview of 15
the key elements and the history associated with those 16
elements? 17
A. Yes. Production costs are classified to energy 18
and demand in this case based on the system load factor. 19
The Company has proposed this approach in prior general rate 20
cases (Case Nos. AVU-E-11-01 and AVU-E-15-05). 21
Transmission costs are classified as 100% demand and 22
allocated by the average of the 12 monthly coincident peaks. 23
This methodology is the same treatment as the last two Idaho 24
Knox, Di 13
Avista Corporation
cases (Case Nos. AVU-E-12-08 and AVU-E-15-05) and reflects 1
the methodology accepted in the Settlement in Case No. AVU-2
E-10-01. 3
Distribution costs are classified and allocated by the 4
basic customer theory accepted by the Idaho Commission in 5
Case No. WWP-E-98-115. Additional direct assignment of 6
demand-related distribution plant has been incorporated to 7
reflect improvements accepted by the Commission in Case No. 8
AVU-E-04-01. 9
Administrative and general costs are first directly 10
assigned to production, transmission, distribution, or 11
customer relations functions. The remaining administrative 12
and general costs are categorized as common costs and have 13
been assigned to customer classes by the four-factor 14
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 17
service study follow the methodology filed in the Company’s 18
last electric general rate case in Idaho? 19
A. Yes. 20

5 Basic customer cost theory classifies only meters, service lines from
the distribution system to the customer’s premise, and street lights as
customer-related plant; all other distribution facilities are considered
demand-related.
Knox, Di 14
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 3
system load factor to determine the proportion of the 4
production function that is demand-related.6 This peak 5
credit ratio is then applied uniformly to all production 6
costs. This is the same method the Company proposed in Case 7
Nos. AVU-E-11-01 and AVU-E-15-05 that was derived from ideas 8
developed through cost of service workshops held at the Idaho 9
Commission in February 2011 and September 2012. 10
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 13
factor approach for identifying the demand-related 14
proportion of production costs: 1) It is simple and 15
straightforward to calculate; 2) it is directly related to 16
the system and test year under evaluation; and 3) the 17
relationship should remain relatively stable from year to 18
year. 19
20
21

6 One minus the load factor equals the demand percentage or peak credit
ratio.
Knox, Di 15
Avista Corporation
Customer Class Rate of Return Return Ratio
Residential Service Schedule 1 4.86% 0.74
General Service Schedule 11/12 9.08% 1.39
Large General Service Schedule 21/22 7.75% 1.19
Extra Large General Service Schedule 25 8.03% 1.23
Extra Large General Service Clearwater
Paper Schedule 25P 8.01% 1.23
Pumping Service Schedule 31/32 5.95% 0.91
Lighting Service Schedules 41-49 6.59% 1.01
Total Idaho Electric System 6.53% 1.00
Q. What are the results of the Company’s electric 1
cost of service study presented in this case? 2
A. Illustration No. 1 below shows the rate of return 3
and the relationship of the customer class return to the 4
overall return (relative return ratio) at present rates for 5
each rate schedule: 6
Illustration No. 1: 7
8
9
10
11
12
13
14
15
16
As can be observed from the above table, Residential 17
service Schedule 1 and Pumping service schedules (31/32) 18
show under-recovery of the costs to serve them. The Lighting 19
service schedules (41-49) are slightly over, but very near 20
unity. The General, Large General, Extra Large General and 21
Extra Large General-Clearwater Paper service schedules 22
(11/12, 21/22, 25, and 25P) show over-recovery of the costs 23
to serve them. The summary results of this study were 24
Knox, Di 16
Avista Corporation
provided to Mr. Ehrbar for consideration in the development 1
of proposed rates. 2
Q. Does this conclude your pre-filed direct 3
testimony? 4
A. Yes. 5