20190610Andrews Direct.pdf

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ON
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DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-37 27
TELEPHONE: (509) 49s-43t6
FACSIMILE: (s09) 495-88s 1
[e-mail]
:019 JUil l0 At{ l0:
ITAIJC PUBLICTtLll'lls c0f,,{Mlss
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
ELZABETH M. ANDREWS
FOR AVISTA CORPORATION
(ELECTRIC)
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I.INTRODUCTION
a. Please state your name, business address, and present position with
Avista Corporation.
A. My name is Elizabeth M. Andrews. I am employed by Avista Corporation
as Senior Manager of Revenue Requirements in the State and Federal Regulation
Department. My business address is 1411 East Mission, Spokane, Washington.
a. Would you please describe your education and business experience?
A. I am a 1990 graduate of Eastern Washington University with a Bachelor of
Arts Degree in Business Administration, majoring in Accounting. That same year, I
passed the November Certified Public Accountant exam, earning my CPA License in
August 19911. I worked for Lemaster & Daniels, CPAs from 1990 to 1993, before
joining the Company in August 1993. I served in various positions within the sections of
the Finance Department, including General Ledger Accountant and Systems Support
Analyst until 2000. In 2000, I was hired into the State and Federal Regulation
Department as a Regulatory Analyst until my promotion to Manager of Revenue
Requirements in early 2007, and later promoted to Senior Manager of Revenue
Requirements. I have also attended several utility accounting, ratemaking and leadership
courses.
a. Would you briefly describe your responsibilities?
A. Yes. As Senior Manager of Revenue Requirements, I am responsible for
the preparation of normalized revenue requirement and pro forma studies for the various
jurisdictions in which the Company provides utility services. Since 2000, I have led or
1 Currently I keep a CPA-Inactive status with regards to my CPA license.
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assisted in the Company's electric and/or natural gas general rate filings in Idaho,
Washington and Oregon.
a. What is the scope of your testimony in this proceeding?
A. My testimony and exhibits in this proceeding will cover accounting and
financial data in support of the Company's electric rate request and the need for the
proposed increase in rates for 2020. I will explain pro formed operating results, including
expense and rate base adjustments made to actual operating results and rate base. In
addition, I incorporate the Idaho share of the proposed adjustments of other witnesses in
this case. The Company is not otherwise proposing an increase in nafural gas base rates.
A table of contents for my testimony is as follows:
o I. Introduction
[. Revenue Requirement Summary -2020 Rate Year
IIII. Derivation of 2020 Revenue Requirement
IV. Standard Commission Basis and Restating Adjustments
V. 2020Pro Forma Adjustments
VI. FASB and FERC Changes in Accounting
VII. Allocation Procedures
Vlll. 2017 GRC Case No. AVU-E-17-01 & Avu-G-17-01Sefflement
Stipulation Commitments
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0. Are you sponsoring any exhibits to be introduced in this proceeding?
A. Yes. I am sponsoring Exhibit No. 4, Schedule 1, which was prepared by
me. This exhibit consists of worksheets, which show actual l2-months ended December
31,2018 operating results, and pro forma and proposed electric operating results and rate
base for the State of Idaho for the 2020 rute year. The exhibits also show the calculation
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of the general revenue requirement, the derivation of the Company's overall proposed
rate of return, the derivation of the net-operating-income-to-gross-revenue-conversion
factor, and the specific pro forma adjustments proposed in this filing for 2020.
II. REVENUE REOUIREMENT SUMMARY _ 2O2O RATE YEAR
a. Please summarize the results of the Company's Idaho electric pro
forma study.
A. After taking into account all standard Commission Basis adjustments2, as
well as additional pro forma and normalizing adjustments, the pro forma elechic rate of
retum ("ROR") for the Company's Idaho jurisdictional operations is 7.08% for rate year
2020. This return level is below the Company's requested rate of return of 7 55% for the
2020 rateyear.
The incremental revenue requirement necessary to provide the Company an
opportunity to earn its requested ROR in rate year 2020 is $5,255,000 for its electric
operations. The overall 2020 base electric increase associated with this request is 2.08%.
a. What is the Company's rate of return that was last authorized by this
Commission for its electric operations in Idaho?
A. The Company's last authorized rate of return for its ldaho electric
operations was 7 .610/o, effective January 1, 2018 for our electric system.
a. What are the primary factors driving the Company's need for an
electric increase?
2 "Commission Basis" adjustments are defined as individual normalizing and restating adjustments that are
standard components of general rate case filings previously approved by the Idaho Public Utilities
Commission (IPUC).
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I A. The increase in overall costs to serve customers is driven primarily by the
2 continuing need to replace and upgrade the facilities and technology we use every day to
3 serve our customers3. As discussed further below, in2020, proposed net power supply
4 expense is reduced from that currently authorized, offsetting the Company's overall
5 increase. The remaining increase impacting the Company's revenue requirement request
6 relates to net increases in operation and maintenance (O&M) and administrative and
7 general (A&G) expenses for Avista's electric operations compared to current authorized
8 levels, mainly due to increased labor and benefits, as well as increases in information
9 services and technology (IS/IT) non-labor expenses.
10 To recognize these cost changes, the Company has included a number of pro
I I forma adjustments to capture the net increases the Company will experience from the
12 2018 test year.
13 O. What are the major components of the increased net plant investment
14 included in the Company's request?
15 A. Looking at the changes to "gross" plant in service proposed in this filing,
16 Idaho'ogross" plant increases by approximately $93.3 million through December 31,
17 2079, or 6.loh for electric operations, as compared to what is currently embedded in base
18 retail rates. A breakdown of the incremental electric sross plant additions by major
19 component for each year is as shown in Table No. I below:
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3 As discussed by Mr. Thies, from 2019 through 2023,the capital expenditure level is expected to remain
constant at approximately $405 million annually, for utility generation, transmission, electric and natural
gas and distribution facilities, and other requirements.
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Table No. 1: Gross Plant Additions
Gnoss Plant Additions (000s)
Investment 2019
Generation/Transmission $ 50,321
Disribtrion $ 30,229
General&Intangible $ 12,830
TotalElectric Gross Additions $ 93,380
As noted in Table No. 1, in order to meet the energy and reliability needs of our
customers, $50.3 million of the elechic "gross" plant increase is due to the Company's
investment in thermal and hydro generating facilities, as well as additional transmission
investment. Electric distribution "gross" plant increases $30.2 million above that
approved in the last general rate case. The electric portion of general and intangible
"gross" plant increases $12.8 million.
Ms. Schuh sponsors the restating and pro forma capital adjustments which
incorporate the effects of these capital investments in the determination of the Company's
proposed revenue requirements. Other Company witnesses, (i.e. Mr. Thackston regarding
production assets, Ms. Rosentrater regarding transmission, distribution and general assets,
and Mr. Kensok regarding the costs associated with Avista's IS/IT projects) provide more
information regarding the 2019 pro forma capital projects included in this case,
describing the need for and timing of these capital projects.
a. Please provide an overview of the changes in net power supply
expenses.
A. As discussed in Company witness Mr. Kalich's direct testimony, the level
of Idaho's share of power supply expense for rate year 2020 pro formed into this case has
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1 decreased by approximately $3.8 million ($11 million on a system basis), from the level
2 currently included in base rates.
3 Q. In addition to the changes in capital investment and net power supply
4 expense, would you please identify the main components of increased O&M and
5 A&G expense impacting the Company's filed request?
6 A. Yes. A number of expense items have also increased since the 2016 test
7 year pro forma used in the last rate case. Ll this case, we are utilizing a 2018 historical
8 test year. However, new base electric rates resulting from this filing are not expected to
9 go into effect until January 1,2020. Accordingly, the Company has included a number of
10 pro forma adjustments to capture some of the cost changes that the Company will
11 experience from the 2018 test year. For example, as explained later in my testimony,
12 employee benefits such as wages, pension and medical insurance expenses have been pro
13 formed versus 2018 actuals, thereby increasing O&M and A&G expense approximately
14 $2.5 million for electric operations.a lncreases in IS/IT non-labor expenses have also
15 been pro formed beyond 2018 actual expenses, increasing expense approximately $0.9
16 million for electric operations.s As discussed by Mr. Kensok, IS/IT expense increases are
17 primarily caused by increased contractual costs associated with products and services,
18 licensing and maintenance fees, and other costs, necessary to support Company cyber and
19 general security, emergency operations readiness, electric and natural gas facilities and
20 operations support, and customer services.6
a See Andrews Exhibit No. 4, Schedule l, page 8, Pro Forma adjustments 3.03 through 3.05
s See Andrews Exhibit No. 4, Schedule 1, page 8, Pro Forma adjustment 3.06.
6 See Mr. Kensok's direct testimony.
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1 Q. Given the growth in Company investments, O&M and A&G costs, as
2 noted above, did the Company review the need for a natural gas general rate case?
3 A. Yes, it did. Using a similar methodology as that used in preparing the
4 Company's electric pro forma study, the Company also prepared a preliminary natural gas
5 pro forma study. The results of the natural gas study showed for the rate year 2020 avery
6 slight revenue sufficiency of $6,000 or -0.01%. The results of the Company's natural gas
7 study included the impact of the reduction in depreciation rates approved by the IPUC
8 (per Case No. AW-G-18-02) effective April l, 2019. Prior to consideration of the
9 depreciation rate adjustment, the preliminary natural gas study results showed a revenue
10 deficiency of approximately S645,000 or 7.50oA, resulting from increased plant
11 investment, O&M and A&G expenses, and changes in cost of capital. These results for
12 the natural gas study were de minimis, unlike the electric pro forma study, which showed
13 a substantial revenue deficiency, albeit reduced due to the offsetting reduction of net
14 power supply costs.
15 Therefore, due to the de minimis result of the preliminary natural gas study, the
16 Company determined that a natural gas case was not necessary at this time, choosing to
17 delay any such filing until a future period beyond rate year 2020. In addition, as agreed to
18 in Case No. AVU-G-18-02, without a natural gas GRC filing prior to the effective date of
19 the Company's Purchased Gas Adjustment in November 2019, the Company is required
20 to begin defening the benefit of the natural gas depreciation expense reduction, effective
2l November l, 2019, and do so until such time as the revised depreciation rates are
22 reflected in base rates. Customers, therefore, will receive the benefit of the reduced
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o depreciation rates anyways, and these benefits will not otherwise offset increased
expenses during the2020 rate period.
III. DXRIYATISN OF2O2O REVENUE REQIIIREMENT
a. On what test period is the Company basing its need for additional
electric revenue?
A. The test period being used by the Company is the l2-month period ending
December 31, 2018, presented ona2020 pro forma average-of-monthly-averages (AMA)
basis. Currently authorized rates, effective January l, 2019, were based upon the 12-
months ending December 31,2016 test year utilized in case AVU-E-17-01, adjusted on a
pro forma basis.
Revenue Requirement - 2020
a. Would you please explain what is shown in Exhibit No. 4, Schedule 1?
A. Yes. Exhibit No. 4, Schedule l, shows actual and pro forma 2018 electric
operating results and rate base for the State of Idaho. Column (b) of page 1 of Exhibit
No. 4, Schedule l, shows December 31, 2018 actual operating results and components of
the AMA rate base as recorded; column (c) is the total of all adjustments to net operating
income and rate base to reflect 2018 results; and column (d) is the 2018 pro forma results
of operations, all under existing rates. Column (e) shows the revenue increase required
which would allow the Company to earn a 7.55o/o rate of return for 2020. Column (f)
reflects 2020 pro forma operating results with the requested increase of $5,255,000 for
electric operations.
a. Would you please explain page 2 of Exhibit No. 4, Schedule 1?
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o 1 A. Yes. Page 2 of Exhibit No. 4, Schedule 1, shows the 2020 revenue
requirement calculations for electric operations of $5,255,000 at the requested 7 .55o/o rate
of return.
a. What does page 3 of Exhibit No. 4, Schedule 1 show?
A. Page 3 shows the proposed Cost of Capital and Capital Structure utilized
by the Company in this case, and the weighted average cost of capital of 7.55%.
Company witness Mr. Thies discusses the Company's proposed rate of return and the pro
forma capital structure utilized in this case, while Company witness Mr. McKenzie
provides additional testimony related to the appropriate return on equity for Avista.
a. Would you now please explain page 4 of Exhibit No. 4, Schedule 1?
A. Yes. Page 4 shows the derivation of the net-operating-income-to-gross-
revenue-conversion factor. The conversion factor takes into account uncollectible
accounts receivable, Commission fees and Idaho State income taxes. Federal income
taxes are reflected at2lo/o.
a. Now turning to pages 5 through 9 of Exhibit No. 4, Schedule 1, please
explain what those pages show?
A. Page 5 begins with actual operating results and rate base for the test period
in column (1.00). Individual Commission Basis normalizing and restating adjustments
that are standard components of general rate case filings begin on page 5, in column
(1.01) and continue through column (2.13) on page 7.
Individual pro forma adjustments for the 2020 rate year begin in column (3.01) on
page 8 and go through column (3.13) on page 9, with the"2020 FINAL TOTAL" column
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o I on page 9 representing the total pro forma operating results and net rate base for the 2020
pro forma period.
IV. STAI\DARD COMMISSION BASIS AND RESTATING ADJUSTMENTS
a. Please explain each of the standard Commission basis and restating
adjustments?
A. Below I explain each standard Commission basis and restating
adjustments. These adjustments were prepared consistent with current regulatory
principles and the manner in which they have been addressed in recent cases (i.e., AW-
E-17-01), unless otherwise noted. The columns following the Results of Operations
column (1.00), reflect restating adjustments necessary to: restate the actual results based
on prior Commission orders; reflect appropriate annualized expenses and rate base;
correct for errors; or remove prior period amounts reflected in the actual results of
operations.
In addition to the explanation of adjustments provided herein, the Company has
also provided workpapers, both in hard copy and electronic formats, outlining additional
details related to each of the adjustments. A summary of each adjustment follows:
Adjustment (1.01) - Deferred FIT Rate Base, adjusts the electric and natural gas
accumulated deferred federal income tax (ADFIT) rate base balance included in the
Results of Operations column (1.00) to the adjusted ADFIT balance reflected on an
average-monthly-average (AMA) basis, as shown within my workpapers provided with
the Company's filing. ADFIT reflects the defened tax balances arising from accelerated
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o I tax depreciation (Accelerated Cost Recovery System, or ACRS, and Modified
2 Accelerated Cost Recovery, or MACRS) and bond refinancing premiums.
3 The effect of this adjustment on Idaho rate base is a reduction of $2,467,000. The
4 effect on Idaho net operating income (NOD due to the Federal lncome Tax (FIT) expense
5 on the restated level of interest on the change in rate baseT is a reduction of $13,000.
6 Adjustment (1.02) - Deferred Debits, Credits and Regulatory Amortizations,
7 is a consolidation of previous Commission Basis or other restating rate base adjustments
8 and their NOI impact. The net impact on a consolidated basis of this adjustment
9 increases Idaho electric rate base by $853,000 and increases NOI by $558,000.
l0 Adjustments included in the Deferred Debits and Credits consolidated adjustment
11 are those necessary to reflect restatements from 2015 acfial results (included in column
12 1.00 "Per Results of Operations"), based on prior Commission orders as explained below.
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o Colstrip 3 AFUDC Elimination is a reallocation of rate base and
depreciation expense between jurisdictions. In Cause Nos. U-81-15 and U-82-10,
the Washington Utilities and Transportation Commission (WUTC) allowed the
Company a return on a portion of Colstrip Unit 3 construction work in progress
(CWIP). A much smaller amount of Colstrip Unit 3 CWIP was allowed in rate
base in Case No. U-1008-144 by the IPUC. The Company eliminated the
AFUDC associated with the portion of CWIP allowed in rate base in eachjurisdiction. Since production facilities are allocated on the
Production/Transmission formula, the allocation of AFUDC is reversed and a
direct assignment is made. The rate base adjustment reflects the average-of-
monthly-averages amount for the test period. No adjustment from that recorded
within results of operations is necessary.
o Colstrip Common AFUDC is also associated with the Colstrip plants in
Montana, and increases rate base. Differing amounts of Colstrip common
facilities were excluded from rate base by this Commission and the WUTC until
Colstrip Unit 4 was placed in service. The Company was allowed to accrue
AFUDC on the Colstrip common facilities during the time that they were
excluded from rate base. It is necessary to directly assign the AFUDC because of
7 The net effect of FIT expense on the restated level of interest expense due to a change in rate base is
shown within each individual adjustment.
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the differing amounts of common facilities excluded from rate base by this
Commission and the WUTC. In September 1988, an entry was made to comply
with a Federal Energy Regulatory Commission (FERC) Audit Exception, which
transferred Colstrip common AFUDC from the plant accounts to Account 186.
These amounts reflect a direct assignment of rate base for the appropriate average-
of-monthly-averages amounts of Colstrip common AFUDC to the Washington
and Idaho jurisdictions. Amortization expense associated with the Colstrip
common AFLIDC is charged directly to the Washington and Idaho jurisdictions
through Account 406 and is a component of the actual results of operations.
a Kettle Falls & Boulder Park Disallowances reflect the Kettle Falls
generating plant disallowance ordered by this Commission in Case No. U-l008-
185 and the Boulder Park plant disallowance ordered by the IPUC in Case No.
AW-E-04-1. The IPUC disallowed a rate of return on $3,009,445 of investment
in Kettle Falls, and $2,600,000 million of investment in Boulder Park. The
disallowed investment, and related accumulated depreciation and accumulated
deferred taxes are removed. These amounts are a component of actual results of
operations.
o Restatine CDA Settlement Deferral adjusts the net assets and DFIT
balances associated with the 200812009 past storage and $10(e) charges deferred
for future recovery as recorded to a 2019 AMA basis, and records the annual
amortization expense based on a ten-year amortization, as approved in Case No.
AVU-E-10-01. The effect on rate base is a decrease of $24,000 to reflect the level
of rate base at December 31,2019 (AMA).
o Restating Spokane River Deferral adjusts the net asset and DFIT
balances related to the Spokane River defened relicensing costs as recorded to a
2019 AMA basis, and records the armual amortization expense based on a ten-
year amortization as approved in Case No. AVU-E-10-01. The effect on rate base
is a decrease of $5,000 to reflect the level of rate base at December 31, 2019
(AMA).
o Restating Spokane River PM&E Deferral adjusts the net asset and
DFIT balances related to the Spokane River deferred PM&E costs as recorded to a
2019 AMA basis, and records the annual amortization expense based on a ten-
year amortization as approved in Case No. AVU-E-I0-01. The effect on rate base
is a decrease of $21,000 to reflect the correct level of rate base at December 31,
201e (AMA).
o Restating Montana Riverbed Lease reflects the costs associated with the
Montana Riverbed lease settlement. In the Montana Riverbed lease settlement,
the Company agreed to pay the State of Montana $4.0 million arurually beginning
in2007, with annual inflation adjustments, for a lO-year period for leasing the
riverbed under the Noxon Rapids Project and the Montana portion of the Cabinet
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Gorge Project. The first two annual payments were deferred by Avista as
approved in Case No. AVU-E-07-10. In Case No. AVU-E-08-01 (see Order No.
30647), the Commission approved the Company's accounting treatment of the
deferred payments, including accrued interest, to be amortized over the remaining
eight years of the agreement starting October 1, 2008. The l0-year amortization of
the first two annual payment deferral expired on September 31,2016, therefore
there is no rate base balance. The lease continues on a year-to-year basis, with
payments being paid into escrow until resolution of pending litigation. The
Company has included lease expense, increased for annual inflation through 2019
as previously required, increasing expense by $51,000.
a Weatherization and DSM Investment includes in rate base the
Sandpoint weatherization grant balance (FERC account 124.350). Beginning in
July 1994 accumulation of AFUCE8 ceased on Electric DSM and full
amortization began on the balance based on the measure lives of the investment.
Beginning in 1995 the amortization rates were accelerated to achieve a 14 year
weighted ayerage amortization period, which was completed in 2010. Remaining
as an Idaho rate base item is the weatherization loan balance of approximately
$59,000.
o Customer Advances decreases rate base for funds advanced by customers
for line extensions, as they will be recorded as contributions in aid of construction
at some fufure time.
o Lake Spokane Deferral Amortization reflects the amortization expense
included in 2018 as a result of the three-year amortization of the deferred costs
related to improving dissolved oxygen levels in Lake Spokane. ln Case No.
AW-E-13-05 (see Order No. 32917), the Company received approval of an
Accounting Order to defer the costs related to the improvement of dissolved
oxygen levels in Lake Spokane. Order No. 32917 authorized the Company to
defer and transfer Idaho's share of these costs (approximately $473,000) to FERC
account 182.3 (Other Regulatory Assets) for later recovery, with no carrying
charge. A three-year amortization of the deferral balance beginning January 1,
2016 through December 31,2018 was approved in Case No. AVU-E-15-05. This
portion of the adjustment removes the expiring amortization, reducing expense by
$117,000.
o Tax Reform Non-Plant Excess ADIT Regulatory Liability reflects the
regulatory liability associated with the tax reform non-plant excess accumulated
deferred income tax (ADIT) liability. Because of the Tax Cuts and Jobs Act
passed in2017, all defened tax assets and liabilities were revalued to represent the
federal tax rate of2lo/o instead ofthe 35Yo federal tax rate that had been recorded.
In the Company's Depreciation Case No. AVU-E-18-03, the Commission
approved setting aside this tax benefit for use against the acceleration of the
8 Allowance for funds used to conserve energy
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o depreciation of Colstrip Unit 3 and 4 to 2027. This adjustment removes the
regulatory liability recorded in 2018, used to offset the Colstrip Regulatory Asset
established in Case No. AVU-E-18-03. The impact of this adjustment increases
Idaho electric rate base by $908,000.o Amortization of Proiect Compass Deferral includes the 2018
amortization expense associated with the three-year amortization of 80% of the
deferred electric revenue requirement amounts associated with the Company's
Project Compass Customer lnformation System (Project Compass) for calendar
year 2015. ln Case No. AVU-E-14-05, the Commission approved an all-party
settlement, in which the Parties agreed that eighty-percent (80%) of the revenue
requirement associated with Project Compass during 2015, beginning the month
the Project goes into service, would be deferred, without a carrying charge, for
recovery in a future proceeding. This project was moved into service on February
2, 2075. A three-year amortization of the deferral balance beginning January 1,
2016 through December 31, 2018 was approved in Case No. AVU-E-15-05. This
portion of the adjustment removes the expiring amortization expense included in
the 2018 test year, reducing expense by $669,000.
The net effect of each of these adjustments decreases Idaho electric expense by
$735,000, increasing NOI by $558,000 and increasing total rate base by $853,000.
Adjustment (1.03) - Working Capital, is used to restate the working capital
balance reflected in the Company's Results of Operations column (1.00), to the adjusted
working capital balance. For 2018, the working capital balance reflected in the
Company's Results of Operations was properly stated and therefore, no adjustment is
required.
The Company uses the Investor Supplied Working Capital (ISWC) methodology
to calculate the amount of working capital reflected in its actual results of operations.
This method is generally consistent with that incorporated in the Company's last
approved Idaho electric general rate case, Case No. AVU-E-17-01, except for two
changes. As a result of the Company's Washington general rate case (Docket Nos. UE-
170485 and UG-170486), the Company agreed to two changes that better reflect the level
of working capital for Avista as follows: 1) reclassified certain interest-bearing accounts
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1 to investments and 2) changed the methodology for allocating certain working capital to
2 non-utility operations. In the past, the investment in non-utility property was used to
3 determine the allocation. The updated method uses all non-rate base investments to
4 determine the allocation. Reflecting these same changes consistently between
5 Washington and Idaho allows for administrative efficiencies when recording working
6 capital within the Company's jurisdictional results of operations. The net effect on Idaho
7 results of reflecting these changes within Idaho's working capital methodology resulted in
8 a decrease in electric net rate base of $530,000. As noted above, the 2018 test period
9 working capital balance reflects this revised working capital methodology, therefore the
10 Company's Results of Operations were properly stated and no adjustment was necessary.
ll Adjustment (1.04) - Restate Capital 2018 EOP, restates the capital investment
12 and expenses associated with adjusting the 2018 AMA plant related balances to
13 December 31, 2018 end-of-period (EOP) balances. Company witness Ms. Schuh
14 sponsors this adjustment. The effect on Idaho results increases rate base by $16,374,000,
l5 and increases NOI by $89,000 related to the federal income tax effect of debt interest.
16 Adjustment (2.01) - Eliminate B & O Taxes, eliminates the revenues and
17 expenses associated with local business and occupation (B & O) taxes, which the
18 Company passes through to its Idaho customers. The effect of this adjustment decreases
19 electric NOI by $9,000.
20 a. Please turn to page 6 of Exhibit No. 4, Schedule I and continue with
2l your discussion of the restating adjustments.
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1 A. Starting on page 6 of Exhibit No. 4, Schedule 1, Adjustment (2.02) -
2 Uncollectible Expense, restates the accrued expense to the actual level of net write-offs
3 for the test period. The effect of this adjustment decreases electric NOI by $45,000.
4 Adjustment (2.03) - Regulatory Expense, restates recorded test period regulatory
5 expense to reflect the 2019IPUC assessment rates applied to test period revenues, and the
6 actual levels of FERC fees paid during the test period. The effect of this adjustment
7 decreases electric NOI by $64,000.
8 Adjustment (2.04) - Injuries and Damages, is a restating adjustment that replaces
9 the accrual with the six-year rolling average of actual injuries and damages payments not
l0 covered by insurance. This methodology was accepted by the Commission in Case No.
I I WWP-E-98-11, and has been used since that time. The effect of this adjustment increases
12 electric NOI by $22,000.
13 Adjustment (2.05) FIT/DFIT/ITC/PTC Expense, adjusts the FIT and DFIT
14 expenses calculated at 2lYo within Results of Operations, as needed, by reflecting the
15 appropriate Schedule M items and jurisdictional allocation of these Schedule M items as
16 compared to Results of Operations. ln addition, this adjustment records the appropriate
17 level of production tax credits and income tax credits on qualified electric generation.
18 These tax levels were appropriately reflected, therefore no adjustment from that recorded
19 within results of operations was necessary.
20 Adjustment (2.06) - SIT/SITC Expense, adjusts Idaho State Income Tax (SIT)
21 expense and Idaho State lnvestment Tax Credits (SITC) applicable to Idaho electric
22 operations as recorded. This approach is consistent with that included and reviewed by
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o I the parties in Case No. AW-E-I5-05. The effect on Idaho elechic NOI is an decrease of
2 $281,000.
3 Adjustment (2.07) - Revenue Normalization, is an adjustment taking into
4 account known and measurable changes that include l) revenue normalization which
5 reprices customer usage using the current authorized base rates (approved in Case No.
6 AVU-E-17-01 effective January 1,2019),2) weather normalization, and 3) an unbilled
7 revenue calculation. Schedule 91 Tariff Rider, Schedule 97 BPA Settlement Rebate and
8 Schedule 59 Residential Exchange are excluded from pro forma revenues, and the related
9 amortization expense is eliminated as well. Company witness Ms. Knox sponsors this
10 adjustment. The effect of this adjustment increases electric NOI $1,512,000.
11 Adjustment (2.08) - Miscellaneous Restating removes a number of non-operating
12 or non-utility expenses associated with advertising, dues and donations, etc., included in
13 error, and removes or restates other expenses incorrectly charged between service and or
14 jurisdiction. The net effect of this adjustment increases electric NOI by $20,000.
15 a. To the best of your knowledge, were all expenses associated with the
16 failed merger with Hydro One removed from the Company's electric results of
17 operations?
18 A. Yes. Any costs associated with the proposed merger were charged to nqn-
19 utility accounts. As a second check, and as part of the review for this Miscellaneous
20 Adjustment, Avista's Regulatory Affairs personnel did a thorough review of its general
2l ledger to verify that no costs were included in this case that were associated with the
22 proposed transaction.
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1 Q. Please turn to page 7 of Exhibit No. 4, Schedule 1 and continue with
2 your discussion of the restating adjustments.
3 A. Adjustment (2.09), starting on page 7 of Exhibit No. 4, Schedule 1 -
4 Restate Incentives, restates actual O&M incentive compensation included in the
5 Company's 2018 test period to reflect a six-year average (2013-2018) of actual payout
6 amounts.
7 For non-executive officers. the six-year average of incentive compensation
8 expense payout is $6.5 million (system) for O&M metrics designed to drive cost-control,
9 and delivery of safe, reliable service with a high level of customer satisfaction. For
10 executive officers, the six-year average expense payout of O&M metrics related to
I I efficiencies in cost management (O&M cost-per-customer), customer service and
12 reliability have averaged approximately $1.29 million (system) in operating expenses.
13 Incentive compensation related to financial metrics are excluded from the Company's
14 filing with expenses borne by shareholders. The net effect of this adjustment, including
15 both non-executive and executive changes, increases electric NOI by approximately
t6 $86,000.
17 O. Please provide an overview of the Company's non-executive employee
18 short-term incentive plan ("Non-Executive Employee STIP").
19 A. [n accordance with the Company's overall compensation design to align
20 elements of incentive plans among all Company employees including executives, the
2l Non-Executive Employee STIP plan has essentially the same stated goals as the Short-
22 Term Incentive Plan for executives (Executive STIP). Both plans provide incentives and
23 focus employees on stated goals while recognizing and rewarding employees for their
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contributions toward achieving those goals. The components of the Non-Executive
Employee STIP are all operational in nature, including cost containment on a per
customer basis. The weighting of each component is as follows: 50% O & M Cost-Per-
Customer, 20% Customer Satisfaction,2|Yo Reliability Index and l0o/o Response Time.
This pay-at-risk component of compensation is part of the overall compensation
for employees that is designed to be comparable with that of other similar utilities. If this
pay-at-risk compensation were to be reduced or eliminated then base pay would need to
be increased in order for overall compensation to remain competitive.
a. Please briefly describe the Executive STIP.
A. The Executive STIP is designed to align the interests of executives with
both customer and shareholder interests in order to achieve overall positive operating and
financial performance for the Company. The Executive STIP has four operational
components, plus an earnings per share (EPS) components. The total amount associated
with utility operational components is 40% and is broken down as follows: 20% O&M
Cost-Per-Customer, 8% Customer Satisfaction, 8o/o Reliability, and 4o/o Response Time.
The Consolidated Diluted EPS components accounts for 60% of the total opportunity.
Only the operational components (a0%) are proposed to be included in retail rates.
Customers benefit from these metrics that are designed to drive cost-control, and delivery
of safe, reliable service with a high level of customer satisfaction. The remaining 60%o of
the Executive STIP related to EPS targets is borne by shareholders.
a. What portion of the Short Term Incentive Plans have been included
in this case?
The Company has included 100% of the Non-Executive Employee STIP
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o 1 and 40% of the Executive STIP (excluding those metrics related to EPS targets) in this
2 case. All incentive compensation included in this case directly benefits customers either
3 in cost containment and efficiencies, operationally via the reliability index and response
4 time metrics, or customer satisfaction as measured via the Voice of the Customer Survey.
5 By focusing employees on effective management of O&M costs, we are able to maintain
6 or reduce charges to customers in future rate cases. The Company has excluded all
7 incentive pay related to the EPS portion of Executive STIP. In addition, a proportionate
8 share of incentive pay for employees (in the same percentage as employee labor) related
9 to non-utility operations has also been excluded from this case. Therefore, the
l0 appropriate portion of incentives related to Idaho utility operations has been included in
I I this case.
12 a. Please describe the Long Term Incentive Plan (LTIP).
13 A. The Long Term Incentive Plan (LTIP) is comprised of two components,
14 which serve two different purposes.e Performance Shares account for 75o/o of the plan
15 with metrics related to Cumulative Earnings-Per-Share (CEPS) and Total Shareholder
16 Return (TSR). The purpose for this portion of the plan is to provide a direct link to the
17 long-term interests of shareholders by assuring that performance shares will be paid only
18 if the Company attains specified financial performance levels. This portion of the plan
19 was modified in 2014 to include both Cumulative Earnings-Per-Share (CEPS) and Total
20 Shareholder Return (TSR). In previous years, vesting of performance-based equity
2l awards were 100% contingent on the Company's Total Shareholder Return (TSR) relative
e As with all other components of the executive compensation, the Compensation Committee determines all
material aspects of the long-term incentive - who receives the award, the amount of the award, the timing of
the award, as well as any other aspects of the award that may be deemed material.
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o I to our peer group over a three-year period. Under the new design, two-thirds of the
2 awards are contingent on TSR relative to our peers, and one-third is measured by our
3 CEPS over a three-year period. The Company has excluded the costs associated with the
4 Performance Share portion of the LTIP from the revenue requirement in this case.
5 Restricted Stock Unit (RSU) awards account for 25oh of the LTIP and vesting is
6 based on a continuation of service by the employee. The purpose for this portion of the
7 plan is to provide an incentive for employees to remain with the Company. The long-
8 term nature of large-scale utility projects spanning multiple years are completed more
9 efficiently with experienced, consistent leadership. In addition, it is the Company's
l0 policy to promote from within when possible, preserving the values inherent in our
I I culture that drive customer satisfaction, reliability of service, etc. Employees with a long
12 tenure of employment with the Company are well versed in the Company's culture and
13 tend to continue to cultivate the values embedded within Avista. The Company has
14 included approximately $245,000 electric expense.
15 a. Please continue with explaining the remaining restating adjustments
16 on page 7 of Exhibit No. 4, Schedule 1.
17 A. The next adjustment, included on page 7 of Exhibit No. 4, Schedule 1, is
18 Adjustment (2.10) - Idaho PCA, which removes the effects of the accounting for the
19 Power Cost Adjustment (PCA). Under the PCA certain differences in actual power
20 supply costs, compared to those included in base retail rates are deferred and then
2l surcharged or rebated to customers in a future period. Revenue adjustments due to the
22 PCA and the power cost deferrals affect actual results of operations and need to be
23 eliminated to produce normalized results. Actual revenues and power supply costs are
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o I normalized in adjustments (2.07) Revenue Normalization and (3.01) Power Supply,
2 respectively. The effect of this adjustment increases Idaho NOI by $7,058,000.
3 Adjustment (2.11) - Nez Perce Settlement Adjustment, reflects a decrease in
4 production operating expenses. An agreement was entered into between the Company
5 and the Nez Perce Tribe to settle certain issues regarding earlier owned and operated
6 hydroelectric generating facilities of the Company. This adjustment directly assigns the
7 Nez Perce Settlement expenses to the Washington and Idaho jurisdictions. This is
8 necessary due to differing regulatory treatment in Idaho Case No. WWP-E-98-11 and
9 Washington Docket No. UE-991606. The effect of this adjustment increases Idaho NOI
10 by 525,000.
1l Adjustment (2.12) - Colstrip/CS2 Maintenance. As approved in Order 32371
12 on September 30, 2011, (in Case Nos. AVU-E-l l-01 and AW-G-11-01), the Company
13 deferred the non-fuel O&M costs associated with the Company's Colstrip and CS2
14 thermal generating plants. The deferral amount is the difference between actual costs and
15 the authorized "Base O&M" costs for each respective year, included in base rates for the
16 years 20 1 3 - 2019 and estimat ed for 2020 .
17 For calendar years 2013 through2015, the authorized "Base O&M" expense level
18 (established in2013 in AVU-E-12-08) was $14.4 million (system). Each year deferred
19 costs were amortized over a three-year period.ro For 2016, in Case No. AVU-E-15-05,
20 the system "Base O&M" cost was adjusted upward from $14.4 million to $20.4 million,
2l to better reflect O&M expenses in the future based on a five-year average for the period
'0 The 2013 deferred amount was delayed for recovery until January 1,2016 as a part ofthe 2014 rate plan
extension, therefore a portion ofthis three-year amortization was included in the 2018 historical test period.
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o 2012-2016, and will remain this amount going forward unless adjusted. Each prior year
deferred costs are amortized over a three-year period.
One-third of each amount deferred for calendar years 2017 through2019, net of
the expiration of prior year deferred amortizations, decreases Idaho electric expense by
approximately $1.16 million, and increases NOI by $872,000.
Electric Adjustment (2.13) - Restate Debt Interest, restates debt interest using
the Company's pro forma weighted average cost of debt on the Results of Operations
level of rate base shown in column (1.00) only. The weighted average cost of debt is as
provided in the testimony and exhibits of Mr. Thies. This adjustment results in a revised
level of tax deductible interest expense on actual test period rate base. The Federal
income tax effect of the restated level of interest for the test period decreases electric NOI
by $492,000.
As noted above, the Federal income tax effect of the restated level of interest on
all other rate base adjustments included in the Company's filing are included and shown
as an income impact of each individual rate base adjustment described elsewhere in this
testimony.
V. 2O2O PRO FORMA ADJUSTMENTS
a. Please explain the significance of the adjustments beginning at page 8
of Exhibit No. 4, Schedule 1.
A. The adjustments on pages 8 and 9 of Exhibit No. 4, Schedule 1, are pro
forma adjustments that recognize the jurisdictional impacts of items that will impact the
2020 pro forma operating period.
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I These pro forma adjustments for the 2020 rate year encompass revenue and
2 expense items as well as additional capital projects, bringing the operating results and rate
3 base to the final pro forma level for the 2020 rate year. The methodology behind each of
4 these adjustments are consistent with that used in Case No. AVU-E-17-01.
5 In the discussion that follows, an explanation of each 2020 rate year pro forma
6 adjustment is provided. The Company has also provided workpapers, both in hard copy
7 and electronic formats, outlining additional details related to each of the adjustments.
8 Q. Please explain each of the Pro Forma adjustments shown on pages 8
9 and 9 of Exhibit No. 4, Schedule 1?
l0 A. The first column on page 8 of Exhibit No. 4, Schedule l, is Adjustment
I I (3.01) - Pro Forma Power Supply. This adjustment was made under the direction of
12 Company witness Mr. Kalich and is explained in detail in his testimony. This adjustment
13 includes pro forma power supply related revenue and expenses to reflect the l2-month
14 period January l, 2020 through December 31, 2020, using weather normalized historical
15 loads. Mr. Kalich's testimony outlines the system level of pro forma power supply
16 revenues and expenses that are included in this adjustment. The adjustment in column
17 (3.01) calculates the Idaho jurisdictional share of those figures. The net effect of this
18 adjustment decreases electric NOI by 54,279,000.
19 Adjustment (3.02) - Pro Forma Transmission Revenue, was made under the
20 direction of Mr. Kalich. As discussed by Mr. Kalich, this adjustment adjusts actual2018
2l transmission-related revenues to reflect the current authorized level of transmission
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o 1 revenues reflected in the Company's PCA.ll The net effect of this adjustment decreases
electric NOI by $724,000.
a. The next three adjustments (3.03) through (3.05) relate to pro forma
labor and benefit adjustments. Prior to addressing each of the adjustments, please
provide an overview of the Company's total compensation philosophy.
A. Avista is committed to providing total compensation to employees that
will attract and retain qualified people required to meet the needs and expectations of all
utility stakeholders, including but not limited to, customers, shareholders and regulators.
To that end, the Company provides employees with cash compensation (base pay and
variable pay in the form of pay-at-risk incentive compensation) and a comprehensive
benefit package including medical and retirement. The overall package is designed to
meet the following goals:
o Clearly identifr the specific measures of Company performance that are likely to
create long-term value for the Company's customers and shareholders;
. Keep employees focused on cost control, customer satisfaction, reliability and
operational efficiencies by awarding variable pay for meeting pre-determined
metrics;
o Promote a culture of safety;
. Pay competitively compared to others within our market;. Reward outstanding performance; and
o Align elements of the incentive plans among all Company employees, including
executive officers.
Each component is carefully considered within the overall package in order to
provide total compensation which will be cost-effective for the Company, as well as,
ll The Company is proposing no adjustment to transmission revenues from those levels authorized in Case
No. AVU-E-17-01. Actual revenues for 2018 were elevated due to the Enbridge natural pipeline rupture,
resulting in increased short-term demand for Avista transmission during 2018. The level of revenues during
2018 received by the Company therefore is not reflective of expected levels during the 2020 rate year.
Whereas, current authorized transmission revenues are expected to be representative ofthe 2020 rateyear.
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1 attract and retain employees. Compensation components within the overall package may
2 be adjusted over time to achieve the goal of recruiting and retaining qualified employees.
3 The Company generally targets overall compensation levels within the range that is 15%
4 above or below the median of Avista's peer group.
5 Q. Please now explain the pro forma labor and benefit adjustments
6 starting with adjustment (3.03) Pro-Forma Labor Non-Exec on page 8 of Exhibit
7 No.4, Schedule 1.
8 A. Adjustment (3.03) - Pro Forma Labor Non-Exec, reflects changes in
9 base pay, which together with pay-at-risk (Short Term Incentive Compensation) is
10 designed to provide competitive compensation in the market place. The level of base pay
11 is determined based on position qualifications such as level of education, professional
12 designations or certifications, experience, roles and responsibilities, and within the
13 market where we compete for talent. Avista participates in numerous confidential salary
14 surveys provided by third-party consulting firms which compare Avista's pay programs
15 and structure to other organizatrons in the utility industry, as well as other industries,
16 regionally and nationally. Salary surveys are part of the input in the determination of
17 salary increases and salary range updates (minimum, mid-point and maximum), as well as
18 benchmarking jobs to market data. Avista benchmarks many jobs within the Company
19 and reviews market data to determine if the salary range midpoints still accommodate the
20 new estimated values established by the benchmarking process. Based on the information
2l provided in these surveys, salary recommendations are presented to the independent
22 Compensation Committee of the Board of Directors for their consideration and approval.
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1 The Compensation Committee can choose to grant higher or lower salary adjustments,
2 based on the available market data.
3 The specific electric adjustments, reflect changes to test period union and non-
4 union wages and salaries, excluding executive salaries, which are handled separately in
5 adjustment (3.04). For non-union employees, the adjustment annualizes the impact of
6 increases effective March 2018, and includes a3Yo adjtstment for increases which were
7 effective March 2019 andplanned for March 202012. Union employee increases are made
8 in accordance with contract terms to annualize the impact of the 30lo increase in 2018, and
9 3% for 2019 and 2020 in accordance with contract terms. The current contract with the
10 IBEW Union 77 (Washinglon/Idaho) expires on March 25, 2021. The methodology
11 behind this adjustment is consistent with Case No. AVU-E-I7-01. In total, this portion of
12 the adjustment represents an increase in electric expense of approximately $1.34 million.
13 The Company has also included an adjustment to reclassifu the amount of 2018
14 labor expense previously charged during 2018 to non-utility for the Hydro One Merger
15 (Merger) case to utility operations. The time and associated labor costs charged to
16 Merger are not recurring in nature. Those employees who worked on the Merger will
17 resume their previous responsibilities related to utility operations. This portion of the
18 adjustment represents an increase of approximately $121,000 in electric expense.
19 Accounting for both annual increases, as well as the reclassification related to the
20 Merger, the total net effect on expense of this non-executive labor adjustment is
12 A minimum increase of 3.0%o for 2020 was approved by the Compensation Committee of the Board of
Directors at the May 2019 Quarterly Board meeting. The actual increase will be updated at or above this
minimum based on market data provided in November 2019, with an effective date in March2020.
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1 $1,463,528 for electric operations. The overall impact on NOI of this adjustment is a
2 reduction of $1,102,000 for electric.
3 Adjustment (3.04) - Pro Forma Labor-Executive, reflects actual salary levels
4 approved by the Board of Directors and that are in effect as of March 2019. This salary
5 level is allocated between Utility and Non-Utility based on20l6levels actual percentages
6 (90% utility I l0% non-utility). These percentages are an accurate representation of
7 allocation between Utility and Non-Utility, absent work previously spent on the Hydro
8 One Merger Case.
9 The Compensation Committee of the Board of Directors (Board) determined and
10 approved the level of executive officer level of base salary effective March 2019, as with
11 all components of executive officer compensation. The Board considers several intemal
12 factors such as individual and Company performance goals, succession planning, job
13 complexity, experience and breadth of knowledge in the determination of base pay.
14 Similar to non-executive compensation, the Board also utilized external peer group data
15 to benchmark its executives against a group of companies with similar business profiles,
16 similar revenue size and market capitalization. These companies were reasonably
17 assumed to be the companies with which we compete for talent.
18 The net impact of this adjustment, increases electric expense by $151,000 and
19 reduces electric NOI by $114,000.
20 Adjustment (3.05) - Pro Forma Employee Benefits, adjusts the 12-months ended
2l December 31,2018 Retirement Plans (401(k) and Pension), and Medical insurance for
22 active employees and for those retired (post-retirement medical) to the exgected amount
23 for 2020. Annually, the Company works with independent consultants in order to
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o I determine the appropriate level of expense for both the Retirement Plans (Willis Towers
Watson) and the Medical Plans (Mercer). The impact of these changes are summarized in
Table No. 2 below: 13
Table No. 2: Benefit Adiustment
Benefit Adjustment System O&M ID Electric
Retirement
Medical
Total
$ 3,444,935 $
$ 2,932,006 $
1,939,843 $
1,651,013 $
449,462
382,540
s 6,376,941 $ 3,590,856 $ 832,001
The Company offers a comprehensive benefit plan for employees. Employees
have several choices to elect benefits, such as medical and life insurance, so they can
determine the best fit for their circumstances. The plans are designed to be competitive
with the overall market practices and are in place to attract and retain qualified
employees. Periodically, to aid in benchmarking, Avista participates in a comprehensive
benefit evaluation study (BENEVAL) performed by an independent actuarial company,
Willis Towers Watson. Similar to cash compensation, the Company generally targets the
level of benefits it offers to be within +l- 15% of the market median.
a. Please describe the Retirement portion of the Benefit Adjustment
included in Adjustment 3.05 and ldaho's share of this expense.
A. The Company's Retirement portion of the calculation adjusts the 401(k)
expense and Pension Plan from the l2-months ending December 31, 2018 to reflect what
will be in effect during 2020, resulting in an increase in electric expense of approximately
13 Benefits associated with capital labor are embedded within the Company's Capital Additions Adjustment
(3.0e).
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1 $450,000. Estimates for Pension Plan expense is determined annually by Willis Towers
2 Watson based on the expected return on assets, discount rates and asset value. The
3 primary contributor to this increase in expense is related to a decrease in asset value due
4 to the actual return on assets for 2018 partially offset by a slight increase in the discount
5 rate and the expected long-term return on assets for 2020. Assumptions utilized in the
6 calculation are presented to and approved by the Board of Directors annually. ln addition,
7 these calculations and assumptions are reviewed by the Company's outside accounting
8 firm annually for reasonableness and comparability to other Companies. The Company
t has included in this case the most recent estimates provided by our actuary for 2020.
l0 In addition, the Company has made changes to the overall retirement plan,
11 discussed below, resulting in an increase in 401(k) expense due primarily to participation.
12 However, decreases in pension expense will reduce overall retirement net expense over
13 the long-term.
14 a. Please describe changes to the Company's retirement plan, which
15 began in2014.
16 A. In October 2013, the Company revised the defined benefit pension plan
17 such that, as of January 1,2014, the plan is closed to all non-union employees hired or
18 rehired on or after January l,2\l4.t4 All actively employed non-union employees that
19 were hired prior to January 1,2014, and were covered under the defined benefit pension
20 plan at that time, will continue accruing benefits as originally specified in the plan. A
2l defined contribution 401(k) plan replaced the defined beneflt pension plan for all non-
22 union employees hired or rehired on or after January 1, 2014. Under the defined
ra Changes were applicable to Local Union 659 (Southeast Oregon) effective April l, 2014.
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I contribution plan the Company will provide a non-elective contribution as a percentage of
2 each employee's pay based on the age of the employee. This defined contribution is in
3 addition to the existing 401(k) contribution where Avista matches a portion of the pay
4 deferred by each participant. ln addition to the above changes, the Company also revised
5 our lump sum calculation for non-union retirees under the defined benefit pension plan to
6 provide non-union participants who retire on or after January 1,2014 with a lump sum
7 amount equivalent to the present value of the annuity based upon applicable discount
8 rates.
9 Q. Please now describe the Medical portion of the Benefit Adjustment
l0 included in the Benefits adjustment.
11 A. The Company's medical portion of the calculation adjusts Medical
12 expense (for both active and post-retirement) for the l2-months ending December 31,
13 2018 to reflect what will be in effect for 2020, resulting in an increase in electric expense
14 of approximately $383,000.r5
15 a Please provide an overview of how medical expenses are determined
16 by the Company.
17 A. Avista sponsors a self-funded medical plan that provides various levels of
18 coverage for medical, dental and vision as a portion of employee benefits. Annually,
19 medical premiumsl6 for the Company are estimated by an independent consultant,
20 Mercer,lT based on medical trend, which is a combination of utilization (the pattern of use
15 Post Retirement is also based on the2020 estimate from Willis Towers Watson.
16 In this context, "premium" is defined as total medical costs including both the Company and employee
contribution.
17 Mercer is currently the world's largest human resources consulting firm, with more than 20,500
employees, based in more than 40 countries.
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o 1 or intensity of services used for a particular timeframe), and the estimated increase in the
2 costs (such as medical services, office visits, medical equipment, etc.) to treat patients
3 from one year to the next. The following factors are taken into consideration in the
4 development of premiums:
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Population Profile - the number and composition of participating employees (such
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Estimated Medical and Prescription Costs - the increase in unit cost for a given
medical service or treatments, the mix and intensity of differing types of service,
and new treatments/therapy/technology.
Laws and Regulation - changes and associated costs, such as those required as
part of the Affordable Care Act.
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Actual medical expense will vary from premium cost estimates based on
variations in plan utilization and actual components in the medical trend. For the past
several years, acfual expense has been lower than our premium cost estimates, resulting in
lower costs for the Company and our customers. Some reasons could include the effects
of the Company's wellness programs, the severity of flu season in a given year, the level
of acute or chronic illness, or for a variety of other reasons. We do not anticipate this
trend to continue, due primarily to increased utilization rates, price increases and our
population profile, resulting in an overall increase in2019 and2020 expense.
As with the Pension Plan, estimates for the Post-Retirement Medical piece of the
Medical adjustment are based on the expected return on assets, discount rates and asset
value. In this case, the primary contributor to the increase in expense is related to a
decrease in asset value. The overall impact of the Pro Forma Employee Benefits
adjustment reduces electric NOI by $626,000.
Andrews, Di
Avista Corporation
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I Q. Please continue with your discussion of the 2020 pro forma
2 adjustments.
3 A. The next adjustment (3.06) - Pro Forma IS/IT Expense, adjusts the
4 actual level of information services and technology (IS/IT) expense included in the 2018
5 test year to include incremental expenses incurred during the 2020 rate period. This
6 adjustment includes the incremental costs primarily associated with signed contracts for
7 products and services, licensing and maintenance fees, and other costs. These
8 incremental expenditures are necessary to support Company cyber and general security,
9 emergency operations readiness, electric and nafural gas facilities and operations support,
10 and customer services. Mr. Kensok sponsors this adjustment and provides more
11 information within his testimony. The effect of this adjustment decreases electric NOI by
t2 $651,000.
13 Adjustment (3.07) - Pro Forma Property Tax, restates the 2018 test period
14 accrued levels of property taxes to the 2020 rate period level using the most current
15 information. As can be seen from my workpapers provided with the Company's filing,
1 6 the properfy on which the tax is calculated is the property value as of December 31, 2019,
17 reflecting the 2020 level of expense the Company will experience during the 2020 rate
18 period. The net effect of this adjustment decreases electric NOI by $992,000.
19 Adjustment (3.08) - Pro Forma Update Depreciation Expense, reflects the
20 revised depreciation rates approved by the Commission in Order No. 34276 of Case No.
2l AW-E-18-03 on March 19, 2019, effective April 1, 2019. Ms. Schuh sponsors this
22 adjustment and provides more information within her testimony. The effect of this
23 adjustment increases electric NOI by $154,000.
Andrews, Di
Avista Corporation
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o 1 Q. Turning to page 9 of Exhibit No. 4, Schedule 1, please explain the
2 remaining 2020 pro forma adjustments.
3 A. Starting on page 9 of Exhibit No. 4, Schedule l, Adjustment (3.09) - Pro
4 Forma Capital Additions 2019 EOP, reflects the addition of 2019 capital additions,r8
5 together with the associated AD and ADFIT on a December 31,2019 EOP basis. This
6 adjustment also includes associated depreciation expense for these 2019 additions, as
7 well as, incremental annualized depreciation expense on plant-in service at December 31,
8 2018. In addition, the plant-in-service at December 31, 2018 end-of-period was adjusted
9 to a December 31,2019 EOP basis. Ms. Schuh describes this adjustment in detail within
10 her testimony. The net effect of this adjustment increases Idaho electric rate base
l1 $24,019,000 and decreases NOI $3,552,000.
12 Adjustment (3.10) Pro Forma O&M Offsets, as explained by Ms. Schuh, the
l3 Company reviewed large capital additions in2019 to determine any offsets (e.g., reduced
14 O&M costs, etc.) resulting in rate period reductions effective January l, 2020.
15 Maintenance records were reviewed to determine whether any specific maintenance costs
16 were incurred in the test period that would be reduced or eliminated by the investment for
17 2019 capital projects. Those reductions in costs were quantified and included as a
18 reduction to O&M. The effect of this adjustment increases electric NOI by $59,000.
19 Adjustment (3.11) Pro Forma Fee-Free Amortization. reflects the annual
20 electric expense associated with the "fee-free" payment expense incurred during the rate
r8 Capital additions in 2019 associated with distribution-related capital expenditures for connecting new
customers to the Company's system are excluded. An increase in revenues from growth in the number of
customers from the historical test year to the 2020 rate year is excluded, therefore, the growth in plant
investment associated with customer growth was also excluded.
Andrews, Di 34
Avista Corporation
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1 year of $268,000, as well as the amortization expense, as a result of amortizing the "fee-
2 free" payments deferred from February 2017 through December 31, 2019, over the one-
3 year rate period (January 1,2020 through December 31,2020).
4 On January 13, 2016, Avista filed with the IPUC an application requesting an
5 order authorizing accounting and ratemaking treatment of fees for credit and debit card
6 pay-ents made by residential customers. Avista asked to defer, for up to 36 months from
7 the time the program went into effect, all fees paid by Avista related to offering a fee-free
8 program for payment of bills by Idaho residential customers that use credit and debit
9 cards. Avista also proposed that the deferred balance would be included in the
10 Company's next general rate case and amortized over 24 months.
1l On April 1,2016 the Commission issued Order No. 33494 in Case No. AVU-E-
12 l6-01 and AW-G-16-01 approving Avista's petition for an order authorizing accounting
13 and ratemaking treatment of its residential fee-free payment program, including deferred
14 accounting treatment of up to 36 months. However, the Commission ordered the
15 amortization period was to be determined in the Company's next general rate case. The
16 fee-free payment program was then successfully launched February 19,2077.
17 The Company has paid invoices through January 2019. As of December 2018,
18 $631,642 of Idaho customer transactions through the fee-free payment progrcm has been
19 deferred. Of the $631,642 deferred, $385,109 was deferred for electric customers and
20 $246,533 was deferred for natural gas customers. The Company estimates the amount to
2l be deferred through December 31,2019 (prior to the start of new rates in this proceeding)
Andrews, Di
Avista Corporation
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2 proposing to amortize the elechic deferred balance of $653,000 over the 2020 rate period
3 from January 1,2020 through December 31,2020-
4 Avista is also including an adjustment to expense for the fee-free program related
5 to the expected rate year expense of approximately $268,000 for electric customers.
6 Therefore, for electric, the Company has included a total adjustment to expense of
7 $921,000 (including $653,000 for the amortization of the deferred balance and
8 approximately $268,000 for the rate year expense (based on $22,301 per month x l2).te
9 The net effect of this adjustment decreases electric NOI by $693,000.
l0 Adjustment (3.12) Pro Forma Colstrip Amortization, reflects the approved
I I treatment by the IPUC to recover Avista's investment in Colstrip Units 3 and 4 after
12 reflecting an accelerated depreciation rate of 2027.20 This adjustment also reflects the
13 Company's proposal to include the 2018 and 2019 Colstrip capital additions in the
14 Colstrip Regulatory Asset for recovery over its authorized amortization period.
15 The effect of this adjustment increases regulatory amortization expense by
16 $863,000, decreases depreciation expense by $3,000 and reduces Colstrip net plant by
17 S5,1111,000 (after including 2019 Colstrip capital additions, offset by the use of 2017
18 Tax Reform "temporary" tax credits associated with non-plant excess DFIT of $6.5
19 million). The net impact of this adjustment decreases electric NOI by $675,000.
te See Andrews' workpapers at electric Adjustment 3.11 for further adjustments between accounts, which
have no impact on overall expense.
20 Avista owns a l5% share of two coal-fired generation facilities located in Colstrip, Montana, known as
Colstrip Units 3 and 4, which have a combined capacity of about 1,480 MW. These two facilities were
placed in service in 1984 and 1986.
Andrews, Di 36
Avista Corporation
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a. Please provide a brief summary of the accounting treatment approved
by the IPUC for Colstrip Units 3 and 4 in Order 34276 of Case No. AVU-E-18-03.
A. On March 19, 2019, per Order 34276 in Case No. AW-E-18-03, the
IPUC approved the Settlement Stipulation proposed by the Settling Parties,2l regarding
Avista's recovery of Colstrip Units 3 and 4's undepreciated balance of $55.18 million
(Idaho's share22), including its investment in Colship Units 3 and 4 of $34.84 million,23
and its asset retirement obligations (ARO) for Colstrip of $20.34 million2a, assuming a
remaining "useful life" of those units through December 31,2027.2s The IPUC approved
the recovery of the undepreciated balance of $55.18 million as follows:
Maintain the current level of Idaho depreciation expense of $2.47 5 million
annually currently being recovered from customers, totaling $21.66
million April 1, 2019 through December 31,2027.26
Use of $6.41 million (ID share) of "temporary" tax credits associated with
Non-plant Excess ADFIT2T to offset the total balance associated with the
acceleration of depreciation/ARO costs on the current Colstrip Unit 3 and
4 assets. (The balance of $5.77 million of other "temporary" tax credits is
being returned to customers by separate tariff, starting on April 1, 2019
through March 31, 2020.)
21 Settling Parties include Avista, IPUC Staff, Clearwater Paper, Idaho Conservation League, Idaho Forest
Group, and the Sierra Club.
22 All amounts included in this testimony represents Idaho's share, unless otherwise noted.
23 Net book value of Colstrip Units 3 and 4, including transmission assets, at December 31,2017, offset by
the accumulated depreciation balance through March 3 I , 201 9.
24 The asset retirement obligations costs, as referred here, include decommissioning, remediation costs and
interim cost of removal.
25 Prior to the "useful life" of 2027 for depreciation purposes approved in Case No. AVU-E-18-03, these
units had been on a depreciation schedule of 2034 and2036, respectively. No closure date was established
for Colstrip Units 3 and 4 as a part of the Settlement agreement.
26 Annual depreciation expense is approximately $7.0 million on a system-basis.
27 The primary provision of the Tax Cuts and Jobs Act (TCJA) was a reduction in the federal corporate tax
rate from 35%oto2l%o,reducing the current and deferred tax expense, currently included in Idaho customer
rates through separate tariff. The TCJA also required accumulated DFIT balances as of December 2017 to
be revalued at the lower corporate rate (2lYo). The difference between the original balance recorded at
35o/o and the new balance recorded at 2l%o, resulted in excess DFIT (EDIT). EDIT was categorized as
"protected" and "unprotected." "Protected" EDIT is generally defined as capital assets (plant) depreciated
under Internal Revenue Code (IRC) section 167, and these timing differences are required to be recorded
and then reversed (i.e. normalized) over the depreciable lives of the capital assets that created the EDIT.
"Unprotected" EDIT mainly represents non-plant related deferred assets/liabilities. The non-plant EDIT
balances have no IRC requirement as to when they must be reversed.
Andrews, Di 37
Avista Corporation
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o The remaining balance of $27.11 million will be recovered through the
amortization of a Regulatory Asset (FERC Account No. 183.3 - Colstrip
Regulatory Asset), and amortized over approximately 34.75 years (starting
April 1, 2019) through 2053, resulting in annual amortization expense of
approximately $780,000. The Regulatory Asset, net of accumulated
deferred federal income taxes, will be included in rate base and will earn
Avista's rate of refurn.28
Prudency of any capital additions not yet in current rates (beyond
December 31,2017) are subject to review in future rate proceedings.
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a. Please discuss the detail accounting approved by the IPUC included in
Adjustment Q.lz), and the impact of this adjustment on expense and rate base as
proposed in this case.
A. Adjustment (3.12) Pro Forma Colstrip Amortization reflects the approved
recovery of Avista's investment on Colstrip as described above, with updated amounts. In
addition, the Company has included capital investment for 2018 and 2019, for prudency
review in this proceeding. As noted above, the IPUC approved for recovery the
undepreciated balance of Colstrip Units 3 and 4 of approximately $55.18 million (net
plant investment of $34.84 million, plus unrecovered Colstrip ARO of $20.34 million).
As shown in Table No. 3 below, updating the unrecovered balance at March 31,
2019 of $55.18 million to reflect the collection of $1.86 million of current depreciation
expense between April 1, 2019 and December 1,2019, revises the unrecovered balance,
as of the proposed effective date of this case January 1,2020, to $53.32 million.
Further, reflecting 1) the offset of the "temporary" tax credit of $6.45 million
28 The Colstrip related accounts included as rate base include the following: FERC Account No. 101.0 -
Plant Cost, FERC Account No. 108.0 - Accumulated Depreciation, FERC Account No. 182.3 - Regulatory
Asset ARO, FERC Account No. I 82.3 - Regulatory Asset Colstrip, FERC Account No. 230.0 - Colstrip
ARO, and FERC Account No. 242.0 - Colstrip Accounts Payable.
Andrews, Di 38
Avista Corporation
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o (including interest), as well as 2) the Colstrip Regulatory Asset amortization of $585,000
for the period April 1, 2019 - December 31, 2019 ($780,000 * 9ll2), and 3) the
unrecovered balances of 2018 and 2019 Colstrip capital additions of $1.52 million and
$1.34 million2e, respectively, proposed for recovery in this proceeding, produces a
undepreciated balance of $49.15 million as of January 1,2020.
Table No. 6 below summarizes the updated undepreciated balance of Colstrip
Unit 3 and 4 of $49.15 million as of January 1,2020:
Table No.3
2e Please see the direct testimony of Mr. Thackston for the discussion on Colship Unit 3 and 4 2018 and
20 19 capital additions.
Andrews, Di 39
Avista Corporation
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Summary of Idaho Colstrip Undepreciated Balance at January 1,2020 ($000s)
Net Book Vafue of Colstrip Units 3 & 4, including transmission assets,
in service at December 31,2017, at March 31,2019
Estimated Asset Retirement Obligations
Undepreciated Balance at March 3lr2019
Depreciation Expense for April 1,2019 through December 31,2019
(current amount recovered in rates)
Undepreciated Balance at December 31,2019
Temporary Tax Credits (including accrued interest)
Colstrip Regulatory Amortization (April 1,2019 - December 31,2019)
Net Book Value of Colstrip Additions in 2018
Estimated Net Book Value of Colstrip Additions r:,2019
Undepreciated Balance at January 1,2020
$ 34,841
20,334
55,175
( 1,856)
53,319
(6,450)
(s8s)
1,520
1,344
$ 49,148
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a. How does this updated undepreciated balance at January l,2020 of
$49.15 million impact the amortization expense for the Colstrip Regulatory Asset?
A. As shown in Table No. 4, using the updated undepreciated balance at
January l, 2020 of $49.15 million, results in a revised annual regulatory amortization
expense for the remaining 34 years of $863,000.
Table No.4
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13 a. How does Adjustment(3,12) impact rate base?
A. As shown in Table No. 5, the impact of adjusting the 2018 historical test
period rate base balance for 2019 Colstrip capital additions (net of accumulated
depreciation and ADFIT), offset by the "Temporary" Excess DFIT Tax Credit reduces
rate base by $5.111 million.
Table No. 5
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Summary ofAdjustment to Idaho Colstrip Rate Base ($000s)
Colstrip 2019 Capital Additions, net of accumulated depreciation and ADFIT
'Temporary Excess ADFIT Tax Credit
Proposed Adjustment to Rate Base in Adjustment (3.12)
1,338
(644e)
$ (5,111)2t
Andrews, Di
Avista Corporation
Idaho Cols trip Re gulatory Amortization ($00 0s )
Undepreciated Balance at January 1,2020
Future Depreciation Expense Recovered Janrary 1,2020 - December 31,2027
Net Colstrip Costs Deferred as Regulatory Asset
Amortization Period (Years)
Annual Regulatory Amortization expense proposed in Adjustment (3.12)
$ 49,148
(19,802)
$ 29,346
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a. Continuing on page 9 of Exhibit No. 4, Schedule 1, please explain the
final2020 pro forma adjustment.
A. The final adjustment, Adjustment (3.13) Pro Forma Insurance Expense,
adjusts the 2018 level of insurance expense for general liability, directors and officers
("D&O") liability, and property insurance to the level of insurance expense the Company
will experience during the rate year. The effect of this adjustment decreases electric NOI
by $27,000.
Final Summary
a. Please explain the final column u2020 Final Total" on page 9 of
Exhibit No.4, Schedule 1.
A. The final column on page 9 of Exhibit No. 4, Schedule l, shows the total
pro forma operating results (NOI of $59,246,000) and rate base ($836,820,000) for the
pro forma test period, and the total revenue requirement need for the 2020 rate year
proposed in this case of $5,255,000. This final revenue requirement is the amount
required for the State of Idaho electric operations to allow the Company an opportunity to
earn its proposed 7.55% rate of return on a pro forma basis.
VI. FASB AND FERC CHANGES IN ACCOUNTING
a. Have there been any changes to accounting methods used by Avista
since the last general rate case filing in Idaho that may impact the rate year results?
A. Yes. There have been three areas that have experienced changed
accounting methods. Two of the areas, including pension accounting and lease
accounting, were changed due to updated accounting standards required by FASB
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Avista Corporation
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I (Financial Accounting Standards Board). The third area, accounting for AFUDC
2 (Allowance for Funds Used During Construction) was changed due to FERC (Federal
3 Energy Regulatory Commission) requirements that were identified during a recent audit
4 byFERC.
5 Q. Please describe the changes required by FASB and the impact to rate
6 year results in this filing.
7 A. Neither of these updated accounting standards have resulted in a material
8 change to rate year results.
9 ASU No. 2016-02 - Leases (Topic 842) was effective January l, 2019. This
10 standard requires most leases to be capitalized and shown on the balance sheet with
11 corresponding lease assets and liabilities. For expense recognition, there will be a
12 straight-line recognition of the minimum lease expense over the entire expected life of the
13 lease, with a portion affecting the amortization of the asset and a portion to the liability,
14 similar to interest. The Company has identified the Montana Riverbed Lease, the ground
15 lease for Coyote Springs 2, and various telecomm site leases under the requirements of
16 the new accounting standard. The Company will not include the recorded asset or
17 liability in rate base and the Company does not expect the level of expense or
18 classification of the expense to be materially different from the amount included in the
19 test year. For leases entered into in the future, the Company will apply the new standard
20 and will provide details of the new leases to the Commissions when those leases impact
2l the next filed general rate case.
22 ASU No. 2017-07 - Compensation-Retirement Benefits (Topic 715) was effective
23 January l, 2018. This standard amends the income statement presentation of the
Andrews, Di
Avista Corporation
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o 1 components of the net periodic benefit cost for Avista's defined benefit pension and other
2 post retirement plans. Under previous accounting, the net periodic benefit cost, which is
3 comprised of current service-costs and other cost components, were all shown as pension
4 expense or were capitalized to plant-in-service. Under the new standard, for financial
5 statements prepared using generally accepted accounting principles, only the service-cost
6 component is eligible for capitalization in plant-in-service and presented in the income
7 statement as costs related to employees. The other costs components are required to be
8 shown as a regulatory asset and outside of income from operations in the income
9 statement. FERC did not require this accounting change, and therefore, Avista maintains
10 its records using the FERC-approved method. Only Avista's consolidated financial
1l statements are updated for the revised accounting with consolidating journal entries.
12 Because Avista has used the FERC method in each of its state jurisdictions, this
13 accounting was not adopted in the States, and therefore, the rate period results are
14 consistent with prior cases.
15 O. Please describe the change in accounting related to AFUDC that was
16 required by FERC.
17 A. FERC notified Avista in December 2017 that they would be auditing the
18 Company's compliance with Form I and 3-Q, and accounting requirements of the
19 Uniform System of Accounts under CFR part 101. During the course of the audit (which
20 is ongoing), FERC staff made recommendations regarding the recording of AFUDC and
2l the tax treatment of the equity component of AFUDC. Neither of the recommended
22 changes will result in changes to Avista's overall rate base. The new method of recording
23 AI'UDC and associated income taxes was recorded in 2018, which resulted in a decrease
Andrews, Di
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1 of deferred federal income taxes. This decrease is only a timing difference as deferred
2 federal income taxes will be higher in future years. Avista deferred this tax benefit
3 beginning in 2018, resulting in an Idaho deferred balance of approximately $389,000 for
4 electric and $l13,000 for natural gas, and will continue to defer it until such time that the
5 new method of calculating DFIT on equity AFUDC is built into rates.3O
6 The Company filed an accounting application on February l, 2019 (Case Nos.
7 AVU-E-19-02 and AVU-G-19-01) requesting approval to record a regulatory asset in
8 place of amounts recorded as plant-in-service.3l In addition, the Company requested
9 authorization to defer the excess deferred taxes collected (as noted above) and indicated it
10 would work with Staff to return those funds to customers in a separate regulatory filing.
11 On May 2, 2019, the Commission issued Order No. 34326 approving the Company's
12 application and treatment of AFUDC.
13 a. Has the Company proposed any accounting treatment with regards to
14 returning the excess deferred taxes collected and owed customers in this case?
15 A. No, not at this time. The Company will work with Commission Staff
16 regarding the appropriate treatment to return the excess deferred taxes collected and owed
17 customers. The Company is not opposed to returning the electric deferred balance for the
18 period 2018 through December 31,2019, as a one-year amortization included in this GRC
19 as an adjustment to the Company's base rates requested in this case, offsetting other
30 The Company estimates the total deferral for 2018 through December 31,2019 to total approximately
$814,000 for Idaho electric and $190,000 for Idaho natural gas.
3r The Company also filed accounting applications in its Washington (Docket Nos. UE-190074 and UG-
190075) and Oregon (UM-l993) jurisdictions with similar requests. Both the Washington Utilities and
Transportation Commission and the Public Utility Commission of Oregon have yet to take action as of this
time.
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proposed regulatory amortizations, or through a separate tariff returning these amounts
over a period determined at a later time.
VII. ALLOCATION PROCEDURES
a. Have there been any changes to the Company's system and
jurisdictional procedures since the Company's last electric general rate case, Case
No. AVU-E-17-01?
A. No. For ratemaking purposes, the Company allocates revenues, expenses
and rate base between electric and natural gas services and between Idaho, Washington
and Oregon jurisdictions where electric and/or natural gas service is provided. The
updated allocation factors used in this case have been provided with my workpapers.
VIII.2017 GRC CASE NO. AVU-E-17-01 & AVU-G-17-01
SETTLEMENT STIPULATION COMMITMENTS
a. In the Companyos prior general rate case (Case Nos. AVU-E-17-01 &
AVU-G-17-01), the Company and settling parties agreed to a number of
commitments prior to the filing of Avistaos next GRC. Has the Company completed
each of the required commitments?
A. Yes it has. Table No. 6 below lists each of the commitments agreed to by
the parties, as well as the status of those commitments, which have all been completed.
Andrews, Di
Avista Corporation
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Does that conclude your pre-filed direct testimony?
Yes, it does.
Andrews, Di
Avista Corporation
Prior to the Company's next general rate case liling the Company and the Settling Parties agrced toi Conpleted
I Meet and confer reprding the Conrpany's electric cost of service sndy. The purpose of the workshop will
be to discuss tlrc merits of diflering cost of service methodologies. Based on the inpu fom the workshop,
the Company agrees to provide, at a minimw4 three cost of service shrdies refective ofthe these diflering
nrethodologies in its ne* general rate case. Ms. Knox discusses the Cost of Service Workshops and the
cost of service shdies produced for this fling.
Yes
2 Meet and conftr to consider whetlrer Iow lncorne Weatheriation Program and Enerry Conservatbn
klucation Progam finrding should be irrcreased from the cr.nrent Connnission-approved levels of $700,000
and $50,000 respectively. Ifagree flurding increase is necessary, Conpany agrees to make necessary
filing(s) wittr the Cornmission on or before December 3 I , 201 7.
Yes
3 Meet and confer to review the Connnission's Service Rules for Gas Utilities (IDAPA 31.31.01) to
determine which provbions should be retained and/or nrodifed, and, ilthe partic[ants agree, irrcorporate
those changes into tlre Conrpany's tariff Any changes requiring Conrnissbn approva[ e.g, tarifrevisiors,
will be subffied by the Company on or before July I, 2018.
Yes
4 Meet and confer to review its meter phcement and protection policies and practices and determine, based
on the agreement ofthe parties, what additional steps should be taken to revise the Conpany's current
policies ard practbes. Any necessary changes requiring Commission approval e.g, tariffrevisions, will be
submined by the Conpany on or before July 1, 201 8.
Yes
5 Develop simihr performance standards, custorner guarantees and a reporting mechanism for is Idaho
custorners. Following those discussions, the Conpany will file is proposal with the Commission requesting
implementation on or before July I , 2018. Ms. Rosentater discusses Avista s Idaho Service Quality
Prognm (ISQ) approved by the Commission within her testinnny
Yes
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