20150601Andrews 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-15-05 OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-G-15-01 AUTHORITY TO INCREASE ITS RATES ) AND CHARGES FOR ELECTRIC AND ) NATURAL GAS SERVICE TO ELECTRIC ) DIRECT TESTIMONY AND NATURAL GAS CUSTOMERS IN THE ) OF STATE OF IDAHO ) ELIZABETH M. ANDREWS ) FOR AVISTA CORPORATION (ELECTRIC AND NATURAL GAS)

CONTENTS 1
Section Page 2
I. Introduction 1 3
II. Combined Revenue Requirement Summary – 4
Two-Year Rate Plan: 2016 & 2017 3 5
III. Derivation of Two-Year Rate Plan Revenue Requirement 11 6
Test Period for Ratemaking Purposes 11 7
Revenue Requirement – 2016 & 2017 11 8
IV. Standard Commission Basis and Restating Adjustments 15 9
V. 2016 and 2017 Pro Forma Adjustments 42 10
2016 Rate Year – Summary of Adjustments 43 11
2017 Rate Year – Summary of Adjustments 55 12
Final Summary 60 13
VI. Allocation Procedures 61 14
15
Exhibit No. 12: 16
Schedule 1 – 2016 & 2017 Electric Revenue 17
Requirement and Results of Operations (pgs 1-11) 18
Schedule 2 – 2016 & 2017 Natural Gas Revenue 19
Requirement and Results of Operations (pgs 1-10) 20
21

I. INTRODUCTION 1
Q. Please state your name, business address, and 2
present position with Avista Corporation. 3
A. My name is Elizabeth M. Andrews. I am employed by 4
Avista Corporation as Manager of Revenue Requirements in the 5
State and Federal Regulation Department. My business 6
address is 1411 East Mission, Spokane, Washington. 7
Q. Would you please describe your education and 8
business experience? 9
A. I am a 1990 graduate of Eastern Washington 10
University with a Bachelor of Arts Degree in Business 11
Administration, majoring in Accounting. That same year, I 12
passed the November Certified Public Accountant exam, 13
earning my CPA License in August 19911. I worked for 14
Lemaster & Daniels, CPAs from 1990 to 1993, before joining 15
the Company in August 1993. I served in various positions 16
within the sections of the Finance Department, including 17
General Ledger Accountant and Systems Support Analyst until 18
2000. In 2000, I was hired into the State and Federal 19
Regulation Department as a Regulatory Analyst until my 20
promotion to Manager of Revenue Requirements in early 2007. 21
I have also attended several utility accounting, ratemaking 22
and leadership courses. 23
1 Currently I keep a CPA-Inactive status with regards to my CPA license.
Andrews, Di 1
Avista Corporation

Q. Would you briefly describe your responsibilities? 1
A. Yes. As Manager of Revenue Requirements, I am 2
responsible for the preparation of normalized revenue 3
requirement and pro forma studies for the various 4
jurisdictions in which the Company provides utility 5
services. During the last fifteen years, I have led or 6
assisted in the Company’s electric and/or natural gas 7
general rate filings in Idaho, Washington and Oregon. 8
Q. What is the scope of your testimony in this 9
proceeding? 10
A. My testimony and exhibits in this proceeding will 11
cover accounting and financial data in support of the 12
Company's two-year rate plan and the need for the proposed 13
increase in rates for both 2016 and 2017. I will explain 14
pro formed operating results, including expense and rate 15
base adjustments made to actual operating results and rate 16
base. In addition, I incorporate the Idaho share of the 17
proposed adjustments of other witnesses in this case. 18
Q. Are you sponsoring any exhibits to be introduced 19
in this proceeding? 20
A. Yes. I am sponsoring Exhibit No. 12, Schedule 1 21
(Electric) and Schedule 2 (Natural Gas), which were prepared 22
under my direction. These exhibits consist of worksheets, 23
which show actual twelve months ended December 31, 2014 24
operating results, pro forma, and proposed electric and 25
Andrews, Di 2
Avista Corporation

natural gas operating results and rate base for the State of 1
Idaho for rate years 2016 and 2017. The exhibits also show 2
the calculation of the general revenue requirement, the 3
derivation of the Company’s overall proposed rate of return, 4
the derivation of the net-operating-income-to-gross-revenue-5
conversion factor, and the specific pro forma adjustments 6
proposed in this filing for 2016 and 2017. 7
8
II. COMBINED REVENUE REQUIREMENT SUMMARY – TWO-YEAR RATE 9 PLAN: 2016 and 2017 10
11 Q. Please describe the Company’s two-year rate plan 12
proposed for the 2016 and 2017 rate years. 13
A. The Company is proposing a two-year rate plan for 14
calendar years 2016 and 2017, with proposed increases 15
effective January 1 of each year. The company is proposing 16
a two-year rate plan, to once again, avoid annual rate cases 17
in its Idaho jurisdiction2, providing benefits to all 18
stakeholders. A two-year rate plan, with increases in 2016 19
and 2017, would provide benefits to its customers by 20
providing rate certainty over this two-year period; to 21
Avista by providing a two-year window to manage its business 22
in order to achieve a fair rate of return within known price 23
changes; and relief to all stakeholders – customers, the 24
2 Avista’s last general rate case filing was in 2012 (Case Nos. AVU-E-12-08 and AVU-G-12-07) in which a two-year rate plan was approved for 2013-2014. The Commission later approved a proposal by the parties to extend the rate plan, with no base rate increase, until January 1, 2016 in Case Nos. AVU-E-14-05 and AVU-G-14-01.
Andrews, Di 3
Avista Corporation

Service
2016
Pro Forma
2017
Pro Forma Proposed
ID Electric 6.53%5.46%7.62%
ID Natural Gas 6.07%5.33%7.62%
Two-Year Rate plan
Rates of Return
Commission and its Staff, intervenors, and the Company, from 1
the administrative burdens and costs of litigation of annual 2
general rate cases. 3
Q. Please provide a summary of the 2016 and 2017 two-4
year rate plan results included in the Company’s Idaho 5
electric and natural gas operating pro forma studies. 6
A. After taking into account all standard Commission 7
Basis adjustments, as well as additional pro forma and 8
normalizing adjustments, the pro forma electric and natural 9
gas rates of return (“ROR”) for the Company’s Idaho 10
jurisdictional operations are 6.53% and 6.07%, respectively 11
for rate year 2016. After taking into account additional 12
incremental pro forma adjustments for the 2017 rate year, 13
the pro forma electric and natural gas ROR are 5.46% and 14
5.33%, respectively, for rate year 2017. These return levels 15
are well below the Company’s requested rate of return of 16
7.62% for both the 2016 and 2017 rate years. 17
Table No. 1 below provides a summary of the 2016 and 18
2017 Rates of Return per the pro forma studies versus that 19
proposed by the Company. 20
Table No. 1 21
22
23
24
25
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Avista Corporation

Service
Revenue Base %Revenue Base %
ID Electric 13,230$ 5.40%13,713$ 5.31%
ID Natural Gas 3,205$ 8.84%1,665$ 4.22%
Natural gas % increase on a billed basis:4.48%2.19%
Two-Year Rate Plan
2016 2017
Revenue Requirement and Percentage Increases
The incremental revenue requirement necessary to 1
provide the Company an opportunity to earn its requested ROR 2
in rate year 2016 is $13,230,000 for its electric 3
operations, and $3,205,000 for its natural gas operations. 4
The overall 2016 base electric increase associated with this 5
request is 5.40%. The 2016 base natural gas increase is 6
8.84% (or 4.48% on a billed basis). 7
The incremental revenue requirement necessary to give 8
the Company an opportunity to earn its requested ROR in rate 9
year 2017 is $13,713,000 for its electric operations and 10
$1,665,000 for its natural gas operations. The overall 2017 11
incremental base electric increase associated with this 12
request is 5.31%. The incremental 2017 base natural gas 13
increase is 4.22% (or 2.19% on a billed basis). 14
Table No. 2 below provides a summary of the 2016 and 15
2017 requested revenue requirement and percentage increases. 16
Table No. 2 17
18
19
20
21
22
23
Andrews, Di 5
Avista Corporation

Q. What are the Company’s rates of return that were 1
last authorized by this Commission for its electric and 2
natural gas operations in Idaho? 3
A. The Company’s last authorized rate of return for 4
its Idaho operations was 7.91%, effective October 1, 2013 5
for both our electric and natural gas systems. 6
Q. What are the primary factors driving the Company’s 7
need for electric and natural gas increases? 8
A. The primary factor driving the Company’s electric 9
and natural gas revenue requirements in 2016 and 2017 is an 10
increase in net plant investment (including return on 11
investment, depreciation and taxes, and offset by the tax 12
benefit of interest) from that currently authorized (based 13
on 2013 levels). As discussed further below, in 2016 these 14
increased costs for electric operations are significantly 15
offset by a reduction in net power supply and transmission 16
expenditures. For 2017 net power supply expenses contribute 17
significantly to the incremental revenue requirement 18
requested above that proposed for 2016. 19
Other changes impacting the Company’s revenue 20
requirement requests relate to slight net increases in 21
distribution, operation and maintenance (O&M), and 22
administrative and general (A&G) expenses for both electric 23
and natural gas operations compared to current authorized 24
levels. 25
Andrews, Di 6
Avista Corporation

Q. What are the major components of the increased net 1
plant investment included in the Company’s 2016 and 2017 2
electric and natural gas results? 3
A. Looking at the changes to “gross” plant in service 4
for 2016, Idaho “gross” plant increases by approximately 5
$162.3 million for electric, and approximately $35.6 million 6
for natural gas, as compared to what was approved in the 7
last general rate case (based on 2013 levels). For 2017, 8
“gross” plant increases by approximately $55.4 million for 9
electric, and approximately $9.4 million for natural gas, as 10
compared to 2016. 11
In order to meet the energy and reliability needs of 12
our customers, $74.5 million for 2016 and $29.9 million for 13
2017, of the electric “gross” plant increase is due to the 14
Company’s investment in thermal and hydro generating 15
facilities, as well as additional transmission investment. 16
In 2016, electric distribution “gross” plant increases $56.2 17
million above that approved in the last general rate case, 18
with an additional increase for 2017 of $21.4 million. The 19
electric portion of general and intangible “gross” plant for 20
2016 and 2017 increases $31.6 million and $4.1 million, 21
respectively. 22
Related to natural gas, in 2016 and 2017, $27.9 million 23
and $8.3 million, respectively, of the “gross” plant 24
increase is due to the Company’s investment in natural gas 25
Andrews, Di 7
Avista Corporation

distribution plant, while general “gross” plant for 2016 and 1
2017 increases $7.7 million and $1.1 million, respectively. 2
The specific 2015 through 2017 pro forma capital 3
expenditures undertaken by the Company to expand and replace 4
its generation, transmission and distribution facilities are 5
discussed further by Company witnesses Mr. Kinney regarding 6
production assets, Mr. Cox regarding transmission and 7
distribution assets and Mr. Kensok regarding the costs 8
associated with Avista’s Information Service/Information 9
Technology (IS/IT) projects. In addition to discussing the 10
actual restating and pro forma adjustments regarding net 11
plant investment, Company witness Ms. Schuh also describes 12
all remaining 2015 through 2017 plant additions not 13
described by Mr. Kinney, Mr. Cox or Mr. Kensok. 14
Q. Ms. Schuh explains the restating pro forma capital 15
adjustments included in this case. Could you please briefly 16
describe the conclusions drawn by Ms. Schuh regarding the 17
increased capital investment? 18
A. Yes. As described in Ms. Schuh’s testimony, the 19
Company is making substantial new investment in its electric 20
and natural gas system infrastructure to address the 21
replacement and maintenance of Avista’s aging system, and to 22
sustain reliability and safety. As soon as this new plant 23
is placed in service, the Company must start depreciating 24
the new plant and incur other costs related to the 25
Andrews, Di 8
Avista Corporation

investment. Unless this new investment is reflected in 1
retail rates in a timely manner, it has a negative impact on 2
Avista’s earnings, particularly because the new plant is 3
typically far more costly to install than the cost of the 4
plant that was embedded in rates decades earlier. As plant 5
is completed and is providing service to customers, it is 6
appropriate for the Company to receive timely recovery of 7
the costs associated with that plant. 8
Q. Could you please provide additional details 9
related to the changes in electric production and 10
transmission expense? 11
A. Yes. As discussed in Company witness Mr. Johnson’s 12
testimony, the level of Idaho’s share of power supply 13
expense for 2016 has decreased by approximately $5.5 million 14
($15.7 million on a system basis) from the level currently 15
included in base rates. However, for 2017, the proposed 16
level of power supply expense is $8.7 million (ID share) 17
higher than that proposed for 2016. Over half of this 18
increase in 2017 is related to the expiration of a capacity 19
sales agreement with Portland General Electric on December 20
31, 2016, resulting in reduced Idaho electric revenues of 21
approximately $5.1 million ($14.5 million system). 22
Transmission net expense in 2016 is not materially 23
different to that in current base rates, however, offsetting 24
the increased power supply expense in 2017, transmission 25
Andrews, Di 9
Avista Corporation

revenues are expected to increase by $776,000 ID share 1
($2,200,000 system) related to a Palouse Wind service 2
contract, as explained by Mr. Cox. 3
Q. Could you please identify the main components of 4
the distribution, O&M and A&G expense changes included in 5
the Company’s filing? 6
A. Yes. Certain expense items have increased since 7
the 2013 rate year used in the last rate case. Employee 8
benefits such as wages, pension and post-retirement medical 9
expenses have increased. Also, as discussed by Mr. Kensok, 10
additional costs associated with IS/IT expenses required to 11
support a range of new and updated applications and systems 12
for cyber security, the operation of the new Customer 13
Information and Work and Asset Management Systems (Project 14
Compass), the Asset Facilities Management application, etc., 15
have increased from that in current base rates. 16
To recognize these cost changes, the Company has 17
included a number of 2016 and 2017 pro forma adjustments to 18
capture the net increases the Company will experience from 19
the 2014 test year. 20
21
Andrews, Di 10
Avista Corporation

III. DERIVATION OF TWO-YEAR RATE PLAN 1 REVENUE REQUIREMENT 2 3
Test Period for Ratemaking Purposes 4
Q. On what test period is the Company basing its need 5
for additional electric and natural gas revenue? 6
A. The test period being used by the Company is the 7
twelve-month period ending December 31, 2014, presented on a 8
2016 and 2017 pro forma basis. Currently authorized rates, 9
effective October 1, 2013, were based upon the twelve-months 10
ending December 31, 2012 test year utilized in cases AVU-E-11
12-08 and AVU-G-12-07, adjusted on a pro forma basis. 12
13
Revenue Requirement – 2016 and 2017 14
Q. Would you please explain what is shown in Exhibit 15
No. 12, Schedules 1 and 2? 16
A. Yes. Exhibit No. 12, Schedules 1 and 2, show 17
actual and pro forma (2016 and 2017) electric and natural 18
gas operating results and rate base for the test period for 19
the State of Idaho. 20
Column (b) of page 1 of Exhibit No. 12, Schedules 1 and 21
2, show December 31, 2014 actual operating results and 22
components of the average-of-monthly-average (AMA) rate base23
Andrews, Di 11
Avista Corporation

as recorded3; column (c) is the total of all adjustments to 1
net operating income and rate base to reflect 2016 results; 2
and column (d) is the 2016 pro forma results of operations, 3
all under existing rates. Column (e) shows the revenue 4
increase required which would allow the Company to earn a 5
7.62% rate of return for 2016. Column (f) reflects 2016 pro 6
forma operating results with the requested increase of 7
$13,230,000 for electric and $3,205,000 for natural gas. 8
Page 2 of Exhibit No. 12, Schedules 1 and 2, show 9
similar columns starting with 2016 pro forma results (equal 10
to column (d) on page 1 of Exhibit No. 12, Schedules 1 and 11
2), reflecting operating results and components of the 12
average-of-monthly-average rate base at December 31, 2016, 13
in column (b). Column (c), of page 2, is the total of all 14
adjustments to net operating income and rate base to reflect 15
2017 results; and column (d) is the 2017 pro forma results 16
of operations, all under existing rates. Column (e) and (f) 17
shows the revenue increases required in 2016 and 2017 to 18
allow the Company to earn a 7.62% rate of return for 2017. 19
Column (g) reflects 2017 pro forma operating results with 20
the requested increases of $13,713,000 for electric and 21
$1,665,000 for natural gas, above that requested in 2016. 22
23
3 Actual plant rate base (cost, accumulated depreciation and associated DFIT) uses the 2014 AMA balances. Plant rate base is adjusted to a 2016 and 2017 AMA basis with restating and pro forma adjustments.
Andrews, Di 12
Avista Corporation

Q. Would you please explain page 3 of Exhibit No. 12, 1
Schedules 1 and 2? 2
A. Yes. Page 3 of Exhibit No. 12, Schedule 1, shows 3
the 2016 and 2017 revenue requirement calculations for 4
electric of $13,230,000 and $13,713,000, respectively. Page 5
3 of Exhibit No. 12, Schedule 2, shows the 2016 and 2017 6
revenue requirement calculations for natural gas of 7
$3,205,000,000 and $1,665,000, respectively. Each 8
calculation is at the requested 7.62% rate of return. 9
Q. What does page 4 of Exhibit No. 12, Schedules 1 10
and 2 show? 11
A. Page 4 shows the proposed Cost of Capital and 12
Capital Structure utilized by the Company in this case, and 13
the weighted average cost of capital of 7.62%. Company 14
witness Mr. Thies discusses the Company’s proposed rate of 15
return and the pro forma capital structure utilized in this 16
case, while Company witness Mr. McKenzie provides additional 17
testimony related to the appropriate return on equity for 18
Avista. 19
Q. Would you now please explain page 5 of Exhibit No. 20
12, Schedules 1 and 2? 21
A. Yes. Page 5 shows the derivation of the net-22
operating-income-to-gross-revenue-conversion factor. The 23
conversion factor takes into account uncollectible accounts 24
Andrews, Di 13
Avista Corporation

receivable, Commission fees and Idaho State income taxes. 1
Federal income taxes are reflected at 35%. 2
Q. Now turning to pages 6 through 11 for electric 3
(Schedule 1), and pages 6 through 10 for natural gas 4
(Schedule 2), of your Exhibit No. 12, please explain what 5
those pages show? 6
A. Yes. Page 6 begins with actual operating results 7
and rate base for the test period in column (1.00). 8
Individual normalizing and restating adjustments that are 9
standard components of Commission Basis reporting or general 10
rate case filings begin in column (1.01). 11
For electric, Exhibit No. 12, Schedule 1, individual 12
pro forma adjustments for 2016 begin in column (3.01) on 13
page 9 and go through column (3.14) page 10, with the “2016 14
FINAL TOTAL” column on page 10 representing the total pro 15
forma operating results and net rate base for the 2016 pro 16
forma period. Page 11 of Exhibit No. 12, Schedule 1, 17
includes all 2017 pro forma adjustment columns (17.01) 18
through (17.05), with the “2017 FINAL TOTAL” and 19
“INCREMENTAL 2017I FINAL TOTAL” columns, representing the 20
total pro forma operating results and net rate base for the 21
2017 pro forma period, and the incremental balances above 22
the 2016 pro forma rate year. 23
For natural gas, at Exhibit No. 12, Schedule 2, 24
individual pro forma adjustments for 2016 begin in column 25
Andrews, Di 14
Avista Corporation

(3.01) on page 8 and go through column (3.11) page 9, with 1
to the “2016 FINAL TOTAL” column on page 9 representing the 2
total pro forma operating results and net rate base for the 3
2016 pro forma period. Page 10 of Exhibit No. 12, Schedule 4
2, includes all 2017 pro forma adjustment columns (17.01) 5
through (17.04), with the “2017 FINAL TOTAL” and 6
“INCREMENTAL 2017I FINAL TOTAL” columns, representing the 7
total pro forma operating results and net rate base for the 8
2017 pro forma period, and the incremental balances above 9
the 2016 pro forma rate year. 10
11
IV. STANDARD COMMISSION BASIS AND RESTATING ADJUSTMENTS 12
Q. Please explain each of the standard Commission 13
basis and restating adjustments? 14
A. Yes, but before I begin, I will note that the 15
following adjustments are consistent with current regulatory 16
principles and the manner in which they have been addressed 17
in recent cases (i.e., AVU-E-12-08 and AVU-G-12-07), unless 18
otherwise noted.4 Columns following the Results of 19
Operations column (1.00) reflect restating adjustments 20
necessary to: restate the actual results based on prior 21
Commission orders; reflect appropriate annualized expenses 22
4 In Restating adjustments (1.03) Working Capital, (2.06) SIT/SITC expense and (2.09) Restate Incentives, the Company has proposed a different methodology to adjust the actual Idaho electric and natural gas results of operations amounts as recorded for 2014, as described below.
Andrews, Di 15
Avista Corporation

and rate base; correct for errors; or remove prior period 1
amounts reflected in the actual results of operations. 2
In addition to the explanation of adjustments provided 3
herein, the Company has also provided workpapers, both in 4
hard copy and electronic formats, outlining additional 5
details related to each of the adjustments. 6
A summary of each adjustment follows: 7
Electric Adjustment (1.01) and Natural Gas Adjustment 8
(1.01) - Deferred FIT Rate Base, adjusts the electric and 9
natural gas Accumulated Deferred Federal Income Tax (ADFIT) 10
balances. ADFIT reflects the deferred tax balances arising 11
from timing differences between book recognition and tax 12
recognition of certain income and deductions. The primary 13
deductions that have timing differences, and therefore 14
associated ADFIT, are Accelerated tax depreciation 15
(Accelerated Cost Recovery System, or ACRS, and Modified 16
Accelerated Cost Recovery, or MACRS) and bond refinancing 17
premiums. 18
The effect of these adjustments on Idaho rate base is a 19
reduction of $5,200,000 electric, and an increase of 20
Andrews, Di 16
Avista Corporation

$2,477,000 natural gas5. The effect on Idaho net operating 1
income (NOI) due to the Federal Income Tax (FIT) expense on 2
the restated level of interest on the change in rate base6 3
is a reduction of $49,000 electric and an increase of 4
$23,000 natural gas. 5
Electric Adjustment (1.02) and Natural Gas Adjustment 6
(1.02) - Deferred Debits and Credits, is a consolidation of 7
previous Commission Basis or other restating rate base 8
adjustments and their NOI impact. The net impact on a 9
consolidated basis of this adjustment decreases Idaho 10
electric rate base by $545,000 and increases NOI by 213,000. 11
No adjustment is necessary for natural gas rate base or net 12
income. 13
Adjustments included in the Deferred Debits and Credits 14
consolidated adjustment are those necessary to reflect 15
restatements from 2014 actual results (included in column 16
1.00 “Per Results of Operations”), based on prior Commission 17
orders as explained below. 18
5 The changes in electric and natural gas rate base are primarily due to two items. First, an increase in ADFIT as a result of Avista recording in the test period the estimated tax deduction the Company intends to file with its 2014 federal tax return. Avista plans to make a “Change of Accounting” filing to implement certain IRS Tangible Property Regulations associated with revised rules on property capitalization versus repair requirements. The study to implement this tax accounting change, commonly referred to as a “Repairs Study”, will be finalized during 2015. The 2014 recorded estimate was based on the best available information and currently is not expected to change materially. Second, an increase in electric ADFIT, and a reduction to natural gas ADFIT, was recorded to reflect corrections of ADFIT balances within the general ledger. 6 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.
Andrews, Di 17
Avista Corporation

• Colstrip 3 AFUDC Elimination (electric) is a 1 reallocation of rate base and depreciation expense 2 between jurisdictions. In Cause Nos. U-81-15 and U-82-3 10, the Washington Utilities and Transportation 4 Commission (WUTC) allowed the Company a return on a 5 portion of Colstrip Unit 3 construction work in 6 progress (CWIP). A much smaller amount of Colstrip 7 Unit 3 CWIP was allowed in rate base in Case No. U-8 1008-144 by the Idaho Public Utility Commission (IPUC). 9 The Company eliminated the AFUDC associated with the 10 portion of CWIP allowed in rate base in each 11 jurisdiction. Since production facilities are 12 allocated on the Production/Transmission formula, the 13 allocation of AFUDC is reversed and a direct assignment 14 is made. These amounts are a component of actual 15 results of operations. 16 17
• Colstrip Common AFUDC (electric) is also 18 associated with the Colstrip plants in Montana, and 19 increases rate base. Differing amounts of Colstrip 20 common facilities were excluded from rate base by this 21 Commission and the WUTC until Colstrip Unit 4 was 22 placed in service. The Company was allowed to accrue 23 AFUDC on the Colstrip common facilities during the time 24 that they were excluded from rate base. It is 25 necessary to directly assign the AFUDC because of the 26 differing amounts of common facilities excluded from 27 rate base by this Commission and the WUTC. In 28 September 1988, an entry was made to comply with a 29 Federal Energy Regulatory Commission (FERC) Audit 30 Exception, which transferred Colstrip common AFUDC from 31 the plant accounts to Account 186. These amounts 32 reflect a direct assignment of rate base for the 33 appropriate average-of-monthly-averages amounts of 34 Colstrip common AFUDC to the Washington and Idaho 35 jurisdictions. Amortization expense associated with 36 the Colstrip common AFUDC is charged directly to the 37 Washington and Idaho jurisdictions through Account 406 38 and is a component of the actual results of operations. 39 40
• Kettle Falls & Boulder Park Disallowances 41 (electric) reflects the Kettle Falls generating plant 42 disallowance ordered by this Commission in Case No. U-43 1008-185 and the Boulder Park plant disallowance 44 ordered by the IPUC in Case No. AVU-E-04-1. The IPUC 45 disallowed a rate of return on $3,009,445 of investment 46 in Kettle Falls, and $2,600,000 million of investment 47 in Boulder Park. The disallowed investment, and 48 related accumulated depreciation and accumulated 49
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Avista Corporation

deferred taxes are removed. These amounts are a 1 component of actual results of operations. 2 3
• Restating CDA Settlement Deferral (electric) 4 adjusts the net assets and DFIT balances associated 5 with the 2008/2009 past storage and §10(e) charges 6 deferred for future recovery as recorded to a 2016 AMA 7 basis, and records the annual amortization expense 8 based on a ten-year amortization, as approved in Case 9 No. AVU-E-10-01. 10 11
• Restating Spokane River Deferral (electric) 12 adjusts the net asset and DFIT balances related to the 13 Spokane River deferred relicensing costs as recorded to 14 a 2016 AMA basis, and records the annual amortization 15 expense based on a ten-year amortization as approved in 16 Case No. AVU-E-10-01. 17 18
• Restating Spokane River PM&E Deferral (electric) 19 adjusts the net asset and DFIT balances related to the 20 Spokane River deferred PM&E costs as recorded to a 2016 21 AMA basis, and records the annual amortization expense 22 based on a ten-year amortization as approved in Case 23 No. AVU-E-10-01. 24 25
• Restating Montana Riverbed Lease (electric) 26 reflects the costs associated with the Montana Riverbed 27 lease settlement. In this settlement, the Company 28 agreed to pay the State of Montana $4.0 million 29 annually beginning in 2007, with annual inflation 30 adjustments, for a 10-year period for leasing the 31 riverbed under the Noxon Rapids Project and the Montana 32 portion of the Cabinet Gorge Project. The first two 33 annual payments were deferred by Avista as approved in 34 Case No. AVU-E-07-10. In Case No. AVU-E-08-01 (see 35 Order No. 30647), the Commission approved the Company’s 36 accounting treatment of the deferred payments, 37 including accrued interest, to be amortized over the 38 remaining eight years of the agreement starting October 39 1, 2008. The eight-year amortization of the deferral 40 expires September 2016, and has been properly reflected 41 in this filing. This adjustment also includes the 42 adjustment to annual lease payment expense for the 43 required annual inflation adjustment. 44 45
• Weatherization and DSM Investment (electric) 46 includes in rate base the Sandpoint weatherization 47 grant balance (FERC account 124.350). Beginning in July 48
Andrews, Di 19
Avista Corporation

1994 accumulation of AFUCE7 ceased on Electric DSM and 1 full amortization began on the balance based on the 2 measure lives of the investment. Beginning in 1995 the 3 amortization rates were accelerated to achieve a 14 4 year weighted average amortization period, which was 5 completed in 2010. 6 7
• Customer Advances (electric and natural gas) 8 decreases rate base for moneys advanced by customers 9 for line extensions, as they will be recorded as 10 contributions in aid of construction at some future 11 time. 12 13
• Amortization of Reardan (electric) removes the 14 amortization expense included in the 2014 test period. 15 In May 2008, Avista purchased the Reardan Wind Project 16 Site from Energy Northwest, the then-current developer, 17 after it was demonstrated as the Company’s least-cost 18 option for securing a renewable resource for its 19 customers, consistent with its 2007 Integrated Resource 20 Plan. Avista later chose to delay the construction of 21 the Reardan project and take advantage of much-lower 22 costs for wind projects that emerged in 2011 (Palouse 23 Wind). Avista recorded approximately $4.0 million of 24 site acquisition and preparation costs, of which $1.747 25 million was Idaho’s share. In Case No. AVU-E-12-08, the 26 Commission approved a two-year amortization of the 27 deferral balance beginning April 1, 2013 through March 28 31 2015. 29 30
Electric Adjustment (1.03) and Natural Gas Adjustment 31
(1.03) - Restate Capital 2014 EOP, restates the capital 32
investment and expenses associated with adjusting the 2014 33
average-of-monthly-average (AMA) plant related balances to 34
December 31, 2014 end-of-period (EOP) balances. The effect 35
on Idaho rate base is an increase of $226,000 to electric, 36
and a reduction of $2,674,000 to natural gas rate base. The 37
effect on Idaho net operating income (NOI) is an increase of 38
7 Allowance for funds used to conserve energy.
Andrews, Di 20
Avista Corporation

$2,000 electric, and a reduction of $25,000 natural gas 1
related to the federal income tax effect of debt interest. 2
Electric Adjustment (1.04) and Natural Gas Adjustment 3
(1.04) - Working Capital, adjusts the working capital rate 4
base amount from the amount included in the Results of 5
Operations column (1.00) to the 2014 AMA test period amount 6
calculated using the Investor Supplied Working Capital 7
(ISWC) method. Working capital included in the Results of 8
Operations is only Idaho’s portion of the 2014 average-9
monthly-average balances of FERC accounts 151 (Fuel Stock 10
Inventory) and 154 (Plant Materials & Supplies). 11
Working capital represents the funds necessary to cover 12
the lag in time between the collection of revenues for 13
services rendered, and the necessary outlay of cash by the 14
Company to pay the expenses of providing those services. 15
Working capital represents investor supplied funds that are 16
properly included in the Company’s rate base for ratemaking 17
purposes. 18
While there are various methods used to determine a 19
Company’s working capital, the Company has calculated its 20
working capital in this proceeding using the Investor 21
Supplied Working Capital method. By including only Fuel 22
Stock Inventory and Plant Materials & Supplies, working 23
capital is understated. The Company believes the ISWC is a 24
reasonable approach to computing working capital, 25
Andrews, Di 21
Avista Corporation

representing expended funds to provide reliable service to 1
its customers. 2
Q. Does the need for working capital also include 3
long-term timing differences? 4
A. Yes, specifically, FERC account 228.3 (Pension and 5
other post-retirement liabilities), and FERC account 182.3 6
(associated pension related regulatory assets). In order to 7
recover the financing costs associated with the Company’s 8
net prepaid pension asset, offset by its accrued post-9
retirement liability and associated ADFIT, the Company 10
believes it is appropriate to include these balances in its 11
ISWC. 12
The Company’s net prepaid pension asset/accrued post-13
retirement liability represents the difference between the 14
amounts contributed to its pension and post-retirement 15
benefit plans, and amounts recorded to expense for those 16
same plans. These differences between cumulative expense 17
and contributions have arisen as a result of funding 18
requirements and funding policies. For example, the federal 19
Pension Protection Act of 2006, as amended, has required the 20
Company to contribute significant amounts to its pension 21
plan since enacted. 22
For ratemaking purposes, the Company recovers pension 23
and post-retirement costs based on the amount recorded to 24
expense. Investor capital is impacted by any difference 25
Andrews, Di 22
Avista Corporation

between the amounts contributed to the plans and the amounts 1
included in rates as expense, therefore investors have borne 2
the cost of financing the incremental contributions. 3
As of December 31, 2014, these cumulative contributions 4
in excess of cumulative expenses, have resulted in a net 5
prepaid pension asset/accrued post-retirement liability 6
(offset by associated AFDIT) of $49.2 million on an AMA 7
basis. Idaho’s allocated share totals $10.7 million for 8
electric, and $2.7 million for natural gas. 9
Q. Have the net prepaid pension contributions been 10
included in working capital in other jurisdictions? 11
A. Yes. In the Company’s Washington jurisdiction, the 12
Washington Utilities and Transportation Commission (WUTC) 13
approved this approach for PacifiCorp, in WUTC v. 14
PacifiCorp, Docket UE-130043. WUTC Staff witness Mr. 15
Zawislak, in Exhibit No. ___(TWZ-1), at page 3, lines 20-22, 16
supported the inclusion of post-retirement benefits in 17
PacifiCorp’s working capital balance, stating: 18
Mr. Stuver’s treatment of [pension and] 19 post-retirement benefits achieves a proper 20 balance of ratepayer interests and allows 21 investors to earn a return on the net unamortized 22 funds they have contributed to Company employees’ 23 post-retirement benefits. 24 25 The WUTC Commissioners approved this treatment at Order 26
05, page 93, paragraph 240, stating: 27
28
Andrews, Di 23
Avista Corporation

As Mr. Zawislak testifies, PacifiCorp’s ISWC 1 adjustment is a refinement to the methodology 2 that corrects the calculation of ISWC with 3 respect to pensions and other post-retirement 4 benefit liabilities including the associated 5 regulatory assets and derivative assets and 6 liabilities. We determine that PacifiCorp’s 7 adjustment to working capital relying on the ISWC 8 approach is supported by the record and should be 9 allowed. 10 11 In 2014, Docket Nos. UE-140188 and UE-140189, UTC Staff 12
witness Ms. Erdahl, in Exhibit No. ____(BAE-1T), page 4, 13
lines 3-10, recommended approval of Avista’s requested 14
treatment of pensions and other post-retirement benefits and 15
liabilities, including the associated regulatory assets and 16
related tax impacts in its ISWC. Specifically at page 8, 17
lines 17-22 she states: 18
Staff evaluated Avista’s ISWC calculation 19 for both electric and natural gas service. Staff 20 reviewed the underlying balance sheet accounts 21 and allocation methodology and determined the 22 Company’s calculation is correct as of the update 23 Avista provided on June 26, 2014, in response to 24 Staff Data Request 115. Accordingly, there are 25 no substantive differences between Staff and 26 Company on this issue.8 27 28
In Avista’s Oregon service territory, the Public 29
Utility Commission of Oregon has an on-going investigation 30
(Docket UM 1633) into the treatment of pension costs in31
8 Avista’s revenue requirement approved in its most recent Washington general rate case (GRC) proceedings were approved through an all party settlement with an agreed upon amount. No specific approval from the Commission was noted in the order relating to working capital; however, no party to the proceeding opposed the Company’s ISWC calculated amounts. This same approach has been included in the Company’s current GRC filed with the WUTC in Docket Nos. UE-150204 and UG-150205.
Andrews, Di 24
Avista Corporation

utility rates, including the opportunity to rate base net 1
prepaid pension asset balances (offset by ADFIT). A 2
decision in this Docket is expected in July 2015. 3
Q. What is the impact of the electric and natural gas 4
working capital adjustments on Idaho’s pro forma rate base 5
and net income? 6
A. The effect of the Working Capital adjustments 7
(1.04) on Idaho rate base from that recorded in the 2014 8
test period is an overall increase of $14,732,000 electric 9
and $2,218,000 natural gas. The effect on Idaho net 10
operating income (NOI) is an increase of $138,000 electric 11
and $21,000 natural gas, related to the federal income tax 12
effect of debt interest. 13
Q. Please continue with your discussion of the 14
restating adjustments included in Exhibit No. 12, Schedules 15
1 and 2. 16
A. Electric Adjustment (2.01) and Natural Gas 17
Adjustment (2.01) - Eliminate B & O Taxes, eliminates the 18
revenues and expenses associated with local business and 19
occupation (B & O) taxes, which the Company passes through 20
to its Idaho customers. The effect of this adjustment 21
decreases electric NOI by $6,000 and natural gas NOI by 22
$1,000. 23
Electric Adjustment (2.02) and Natural Gas Adjustment 24
(2.02) - Uncollectible Expense, restates the accrued expense 25
Andrews, Di 25
Avista Corporation

to the actual level of net write-offs for the test period. 1
The effect of this adjustment increases electric NOI by 2
$61,000 and natural gas NOI by $206,000. 3
Electric Adjustment (2.03) and Natural Gas Adjustment 4
(2.03) - Regulatory Expense, restates recorded test period 5
regulatory expense to reflect the IPUC assessment rates 6
applied to expected revenues for the test period and the 7
actual levels of FERC fees paid during the test period. The 8
effect of this adjustment increases electric NOI by $35,000, 9
while natural gas NOI decreases by $5,000. 10
Electric Adjustment (2.04) and Natural Gas Adjustment 11
(2.04) - Injuries and Damages, is a restating adjustment 12
that replaces the accrual with the six-year rolling average 13
of actual injuries and damages payments not covered by 14
insurance. This methodology was accepted by the Idaho 15
Commission in Case No. WWP-E-98-11, and has been used since 16
that time. The effect of this adjustment increases electric 17
NOI by $35,000 and decreases natural gas NOI by $77,000. 18
Electric Adjustment (2.05) FIT/DFIT/ITC/PTC Expense and 19
Natural Gas Adjustment (2.05) - FIT/DFIT Expense, adjusts 20
the FIT and DFIT expenses calculated at 35% within Results 21
of Operations, as needed, by reflecting the appropriate 22
Schedule M items and jurisdictional allocation of these 23
Schedule M items as compared to Results of Operations. In 24
addition, for electric this adjustment records the 25
Andrews, Di 26
Avista Corporation

appropriate level of production tax credits and income tax 1
credits on qualified electric generation. 2
For the electric adjustment, the net tax credit 3
adjustment decreases Idaho electric NOI by $6,000. For the 4
natural gas adjustment, no adjustment is required. 5
Electric Adjustment (2.06) and Natural Gas Adjustment 6
(2.06) - SIT/SITC Expense, adjusts Idaho State Income Tax 7
(SIT) expense and Idaho State Investment Tax Credits (SITC) 8
applicable to Idaho electric and natural gas operations as 9
recorded. The effect on Idaho net operating income (NOI) is 10
a decrease of $1,246,000 for electric and a decrease of 11
$442,000 for natural gas. In this filing, the Company made 12
two changes to its method to determine the rate year level 13
of SIT expense from previous general rate cases in Idaho, 14
which are described below. The Company used the same 15
revised method to determine the SIT rate that is used in the 16
derivation of the net operating income to gross revenue 17
conversion factor as shown on page 4 of Exhibit No. 12, 18
Schedules 1 and 2. 19
Q. Please describe the two changes made to determine 20
the rate year level of SIT expense. 21
A. The Company has historically used the 22
apportionment method to determine SIT expense and continues 23
to use the apportionment method in this filing. This method 24
determines Idaho’s taxable income using an apportionment 25
Andrews, Di 27
Avista Corporation

factor for Idaho that is applied to the total Company 1
taxable income. Idaho’s state tax rate is then applied to 2
the computed Idaho’s taxable income to derive the state 3
income tax expense. In past general rate cases, the Company 4
has used the system apportionment tax rate and has applied 5
it to Idaho stand-alone taxable net income, which 6
incorrectly computes SIT expense. In this filing, the 7
system apportionment tax rate was converted to an Idaho tax 8
rate, so when it is applied to Idaho stand-alone taxable net 9
income, the SIT expense is properly computed. 10
The second change made by the Company relates to the 11
use of Idaho investment tax credits. The Company has 12
historically used the flow-through method to pass through 13
earned tax credits to rate payers. Using the flow-through 14
method, all Idaho investment tax credits available in a year 15
were used to offset 50% of the SIT owed to Idaho, so 16
customers immediately had the benefit of lower state income 17
taxes. 18
Through discussions with Avista’s external auditor’s 19
(Deloitte Touche) it was determined that this method should 20
no longer be used by Avista. Avista is required to 21
normalize its federal investment tax credits pursuant to 22
Internal Revenue Code section 46(f)(2). In addition, the 23
Idaho tax code refers to the Federal standards for ITC 24
normalization. Therefore, it was determined that the 25
Andrews, Di 28
Avista Corporation

Company must also normalize its Idaho investment tax 1
credits. Beginning with the effective date of new customer 2
rates from this case, the Company will defer its SITCs and 3
will amortize (i.e. return to customers) the credits over 4
the life of the assets. 5
Q. What SIT rate was used in the net operating income 6
to gross revenue conversion factor? 7
A. The Company used 4.9% for the SIT rate in this 8
case, before adjusting for other revenue-sensitive expenses. 9
The calculation of this rate is described below. 10
Idaho’s taxable income is determined by applying the 11
apportionment factor of 19.73% to system taxable income. 12
The tax is then computed by applying the Idaho tax rate, 13
currently 7.40%, to the calculated Idaho taxable income. 14
This amount is the tax that is paid to the State of Idaho. 15
Avista records approximately 82% of total Idaho tax to the 16
Idaho electric operations and 18% to the Idaho natural gas 17
operations. 18
The “apportionment tax rate” for computing Idaho state 19
income taxes is shown below in Table No. 3. 20
21
Andrews, Di 29
Avista Corporation

Table No. 3: 1
2
3
4
5
6
7
By using the three components of the actual tax 8
calculation for the Idaho operations, an Idaho apportionment 9
tax rate is 1.46%, which is then applied to system taxable 10
income. This rate can only be used if it is applied to 11
Avista Utilities’ total system revenues, system expenses and 12
system taxable income. When Avista prepares a general rate 13
case revenue requirement, the starting point is the actual 14
Results of Operations for its Idaho electric and natural gas 15
operations. Use of this rate in a general rate case, which 16
is calculated based on Avista’s total utility system in 17
Idaho, Washington and Oregon, would understate SIT. In this 18
filing, the Company used an Idaho apportionment tax rate of 19
4.9%, which produces the appropriate level of expense when 20
applying it to Idaho’s taxable income. 21
The 4.9% tax rate was determined by “grossing up” the 22
1.46% apportionment rate for system taxable net income by 23
Idaho’s (electric and natural gas) share of system revenues, 24
Idaho's
Apportionment
Rate X
Idaho's Tax
Rate =
Idaho's Apportionment Tax Rate
(Applied to System Taxable Income)
19.73%X 7.40%=1.460%
Calculation of Avista's Apportionment Tax Rate
Andrews, Di 30
Avista Corporation

totaling approximately 29.8%. (Idaho apportionment tax rate 1
= 1.46% / 29.8% = 4.9%) 2
Electric Adjustment (2.07) and Natural Gas Adjustment 3
(2.07) - Revenue Normalization, is an adjustment taking into 4
account known and measurable changes that include 1) revenue 5
normalization which reprices customer usage using the 6
current authorized base rates (approved in Case Nos. AVU-E-7
12-08 and AVU-G-12-07 effective October 1, 2013), 2) weather 8
normalization, and 3) an unbilled revenue calculation. For 9
the electric adjustment, Schedule 91 Tariff Rider, Schedule 10
97 BPA Settlement Rebate and Schedule 59 Residential 11
Exchange are excluded from pro forma revenues, and the 12
related amortization expense is eliminated as well. For the 13
natural gas adjustment, all revenues and expenses associated 14
with the Purchased Gas Cost Adjustment Schedule 150 have 15
been removed from the Company’s filing. In addition, 16
revenues associated with the temporary Gas Rate Adjustment 17
Schedule 155, Schedule 191 Tariff Rider, and Schedule 197 18
Refund of Deferred Gas Costs are excluded from pro forma 19
revenues, and the related amortization expenses are 20
eliminated as well. Company witnesses Ms. Knox (electric) 21
and Mr. Miller (natural gas) sponsors these two adjustments. 22
The effect of this adjustment increases electric NOI 23
$4,056,000 and increases natural gas NOI $838,000. 24
Andrews, Di 31
Avista Corporation

Electric Adjustment (2.08) and Natural Gas Adjustment 1
(2.08) - Miscellaneous Restating removes a number of non-2
operating or non-utility expenses associated with 3
advertising, dues and donations, etc., included in error, 4
and removes or restates other expenses incorrectly charged 5
between service and or jurisdiction. In addition, this 6
adjustment reflects 2014 retroactive union salary increases 7
paid in 2015 above that accrued in September and December of 8
20149. The net effect of this adjustment decreases electric 9
NOI by $47,000 and decreases natural gas NOI by $13,000. 10
Electric Adjustment (2.09) and Natural Gas Adjustment 11
(2.09) - Restate Incentives, restates the actual employee 12
payroll incentives included in the Company’s test period 13
using a six-year average payout percentage. 14
For officers, the incentive amount included in the 15
Company’s filing is based on the 2015 incentives to be 16
accrued for officers (paid Q-1 of 2016), based on O&M 17
targets.10 This amount was then multiplied by the six-year 18
average of actual percentage payouts for the years 2009-2014 19
9 The Union Contract for IBEW Local 77 expired as of March 31, 2014. No salary increases were granted effective April 1, 2014 with the understanding that once the new contract was finalized, increases would be retro-active to this date. In September and December 2014 estimated amounts were recorded to the General Ledger for the retro-active payout. A new contract was signed in January 2015 and actual retro-active pay was calculated resulting in an additional accrual of approximately $700,000. In order to reflect the appropriate labor for 2014, this adjustment recognizes this increase in expense. 10 Officer STIP based on earnings per share targets are excluded from this calculation. Long-term incentives based on financial metrics (performance shares) and those short-term incentives based on earnings per share are currently borne by shareholders.
Andrews, Di 32
Avista Corporation

(or 40.23%). For non-officer incentives, this is calculated 1
by using the 2016 level of labor expense (determined in 2
adjustment (3.03) electric and (3.02) natural gas - Pro 3
Forma Labor Non-Exec) multiplied by the payout incentive 4
opportunity per the Company’s current incentive plan (or 12% 5
overall) to determine the incentive payout opportunity, 6
multiplied by the six-year average of actual percentage 7
payouts for the years 2009-2014 (or 102.16%). The net 8
effect of this adjustment increases Idaho NOI by $315,000 9
electric and $80,000 natural gas. 10
Q. Please briefly describe the Executive Short Term 11
Incentive Plan. 12
A. The Short Term Incentive Plan (STIP) is designed 13
to align the interests of executives with both customer and 14
shareholder interests in order to achieve overall positive 15
operating and financial performance for the Company. The 16
STIP is a pay-at-risk plan whereby employees are eligible to 17
receive cash incentive pay if the stated targets are 18
achieved. 19
The STIP has four operational components, plus two 20
earnings per share (EPS) components. The total amount 21
associated with utility operational components is 40% and is 22
broken down as follows: 20% O&M Cost-Per-Customer, 8% 23
Customer Satisfaction, 8% Reliability, and 4% Response Time. 24
The EPS components account for 60% of the total opportunity 25
Andrews, Di 33
Avista Corporation

and are broken out into 50% utility EPS and 10% non-utility 1
EPS. Only the operational components (40%) are proposed to 2
be included in retail rates. Customers benefit from these 3
metrics that are designed to drive cost-control, and 4
delivery of safe, reliable service with a high level of 5
customer satisfaction. The remaining 60% related to EPS 6
targets are currently borne by shareholders. 7
Q. Please provide an overview of the Company’s non-8
executive employee incentive plan. 9
A. Employee compensation is a combination of base pay 10
and pay-at-risk/variable performance based via the Short 11
Term Incentive Plan (STIP). The STIP provides for a portion 12
of compensation to be at risk contingent upon the 13
achievement of specific goals for performance, which are 14
likely to produce long term customer benefits. This tension 15
in plan design helps incent and focus all employees on the 16
stated goals of the Company. In order to achieve this pay-17
at-risk compensation, employees have to keep focused on cost 18
control, customer satisfaction and reliability within the 19
system. These metrics are designed to be reasonably 20
achievable with strong management performance. Maximum 21
performance levels are designed to be difficult to achieve 22
given historical performance and forecasted results at the 23
time the metrics are approved. The pay-at-risk component of 24
compensation is not designed to pay out the full incentive 25
Andrews, Di 34
Avista Corporation

opportunity every year, nor is it designed to have no payout 1
for an extended period of time. Pay-at-risk plans are 2
designed to help focus employees on stated goals that 3
benefit the Company and its customers, while at the same 4
time functioning as an integrated component of total 5
compensation. 6
In accordance with the Company’s overall compensation 7
design to align elements of incentive plans among all 8
Company employees and executives, the non-executive employee 9
incentive plan has essentially the same stated goals as the 10
STIP discussed above. Both plans provide incentives and 11
focus employees on stated goals while recognizing and 12
rewarding employees for their contributions toward achieving 13
those goals. The components of the non-executive employee 14
incentive plan are as follows: 60% O & M Cost-Per-Customer, 15
15% Customer Satisfaction, 15% Reliability Index and 10% 16
Response Time. 17
Q. What portion of the Short Term Incentive Plans 18
have been included in this case? 19
A. The Company has included 100% of the non-executive 20
STIP and 40% of the executive officer STIP (excluding those 21
metrics related to EPS targets) in this case. Because all 22
metrics in the non-officer STIP and 40% of the Officer STIP 23
are customer-focused and benefit ratepayers, it is 24
appropriate to include the customer focused STIP incentives 25
Andrews, Di 35
Avista Corporation

in general rates. The 2014 base year already excludes the 1
portion of officer STIP related to EPS targets. In 2
addition, because incentive loaders follow where base salary 3
labor dollars are charged, a portion of non-officer 4
incentives are also already charged to non-utility accounts 5
for those employees performing work not related to the 6
utility. Therefore, the appropriate portion of incentives 7
related to non-utility is reflected on the Company’s general 8
ledger for both executive and non-executive STIPs. 9
Q. Please describe the Executive Long Term Incentive 10
Plan (LTIP). 11
A. The Executive Officer Long Term Incentive Plan 12
(LTIP) is comprised of two components, which serve two 13
different purposes11. Performance Shares account for 75% of 14
the plan with metrics related to Cumulative Earnings-Per-15
Share (CEPS) and Total Shareholder Return (TSR). The 16
purpose for this portion of the plan is to provide a direct 17
link to the long-term interests of shareholders by assuring 18
that performance shares will be paid only if the Company 19
attains specified financial performance levels. This 20
portion of the plan was modified in 2014 to include both 21
Cumulative Earnings-Per-Share and Total Shareholder Return.22
11 As with all components of the executive officer compensation, the Compensation Committee determines all material aspects of the long-term incentive reward – 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.
Andrews, Di 36
Avista Corporation

In previous years, vesting of performance-based equity 1
awards were 100% contingent on the Company’s Total 2
Shareholder Return (TSR) relative to our peer group over a 3
three-year period. Under the new design, two-thirds of the 4
awards are contingent on TSR relative to our peers and one-5
third is measured by our CEPS over a three-year period. The 6
Company has excluded the Performance Share portion of the 7
LTIP from the retail ratemaking because it is tied to 8
shareholder performance. 9
Restricted Stock Unit (RSU) awards account for 25% of 10
the LTIP and vest based on continued service. The purpose 11
for this portion of the plan is to provide an incentive for 12
employees to remain employed by the Company. The long-term 13
nature of large-scale utility projects spanning multiple 14
years are completed more efficiently with experienced, 15
consistent leadership. In addition, it is the Company’s 16
policy to promote from within when possible, preserving the 17
values inherent in our culture that drive customer 18
satisfaction, reliability of service, etc. Employees with a 19
long tenure of employment with the Company are well versed 20
in the Company’s culture and will continue to cultivate the 21
values embedded within Avista. The Restricted Stock Unit 22
portion of the plan is included in retail ratemaking because 23
customers benefit from long-term leadership with a vested 24
Andrews, Di 37
Avista Corporation

interest in the efficient operation of the Company and high 1
customer satisfaction12. 2
Q. What amount of the LTIP costs is included in 3
retail rates in this filing? 4
A. The LTIP expense included in retail rates in this 5
filing are related to Restricted Stock Units totaling $1.0 6
million on a system basis in 2014. Idaho’s share of this 7
expense amount is approximately $229,000 electric and 8
$58,000 natural gas. 9
Q. Please continue with explaining the remaining 10
restating adjustments in Exhibit 12, Schedules 1 and 2. 11
A. The next adjustment is Electric Adjustment (2.10) 12
- Idaho PCA, which removes the effects of the financial 13
accounting for the Power Cost Adjustment (PCA). Under the 14
PCA certain differences in actual power supply costs, 15
compared to those included in base retail rates are deferred 16
and then surcharged or rebated to customers in a future 17
period. Revenue adjustments due to the PCA and the power 18
cost deferrals affect actual results of operations and need 19
to be eliminated to produce normalized results. Actual 20
revenues and power supply costs are normalized in 21
adjustments (2.07) Revenue Normalization and (3.01) Power 22
12 The total CEO Long Term Incentive Plan expenses have been excluded because both the restricted stock and performance shares have financial performance-related triggers.
Andrews, Di 38
Avista Corporation

Supply, respectively. The effect of this adjustment 1
decreases Idaho NOI by $1,033,000. 2
Electric Adjustment (2.11) - Nez Perce Settlement 3
Adjustment, reflects a decrease in production operating 4
expenses. An agreement was entered into between the Company 5
and the Nez Perce Tribe to settle certain issues regarding 6
earlier owned and operated hydroelectric generating 7
facilities of the Company. This adjustment directly assigns 8
the Nez Perce Settlement expenses to the Washington and 9
Idaho jurisdictions. This is necessary due to differing 10
regulatory treatment in Idaho Case No. WWP-E-98-11 and 11
Washington Docket No. UE-991606. The effect of this 12
adjustment increases Idaho NOI by $8,000. 13
Electric Adjustment (2.12) - Restating CS2 Levelized 14
Adjustment, removes the final amortization expense recorded 15
in 2014 related to the deferred return associated with 16
Coyote Springs 2 (CS2). In the Company's electric general 17
rate case, Case No. AVU-E-04-1, Order No. 29602, dated 18
October 8, 2004, the Commission approved the deferral of 19
return on CS2 investment in early years for recovery in 20
later years in order to levelize the revenue requirement on 21
CS2 plant investment for the first ten years of operation of 22
the plant. The ten-year period ran from September 1, 2004 23
through August 31, 2014. This adjustment removes the test 24
period amount. This adjustment increases NOI by $253,000. 25
Andrews, Di 39
Avista Corporation

(2.13) – Colstrip/CS2 Maintenance. As approved in 1
Order 32371 on September 30, 2011, (in Case Nos. AVU-E-11-01 2
and AVU-G-11-01), the Company deferred the non-fuel O&M 3
costs associated with the Company's Colstrip and CS2 thermal 4
generating plants. The deferral amount is the difference 5
between actual costs in excess of authorized “Base O&M” 6
costs for each respective year, included in base rates for 7
the years 2011 – 2014 and estimated for 2015. 8
For calendar years 2013 through 2015, the last 9
authorized “Base O&M” expense level (established in 2013 in 10
AVU-E-12-08) was $14.4 million, and will remain this amount 11
going forward unless adjusted. Each prior year deferred 12
costs are amortized over a three-year period. 13
In addition to the three-year amortization, the Company 14
is proposing to adjust the “Base O&M” cost upward from $14.4 15
million to $20.4 million to better reflect O&M expenses in 16
the future based on a five-year average for the period 2012-17
2016. The effect of this adjustment to the “Base O&M” cost 18
reduces the amount of the deferral that will be required in 19
2016 and forward, where actual O&M expense is expected to be 20
$24.3 million in 201613, and range from $18.8 million to 21
$22.0 million in years 2017-2019. The effect of this 22
proposed change increases Idaho electric expense by $2.0723
13 In 2016 CS2 will require its 72,000 run-hour hot gas path maintenance, which occurs on an approximate four-year cycle, the last occurring in 2012.
Andrews, Di 40
Avista Corporation

million. 1
One-third of each amount deferred for calendar years 2
2013 through 2015, plus the additional proposed expense for 3
the 2016 rate year, increases Idaho electric expense by 4
approximately $2.6 million, and decreases NOI by $1,705,000. 5
Electric Adjustment (2.14) and Natural Gas Adjustment 6
(2.10) - Restate Debt Interest, restates debt interest using 7
the Company’s pro forma weighted average cost of debt On 8
the Results of Operations level of rate base shown in column 9
(1.00) only. The weighted average cost of debt is as 10
provided in the testimony and exhibits of Mr. Thies. This 11
adjustment results in a revised level of tax deductible 12
interest expense on actual test period rate base. The 13
Federal income tax effect of the restated level of interest 14
for the test period decreases electric NOI by $437,000 and 15
natural gas NOI by $75,000. 16
As noted above, the Federal income tax effect of the 17
restated level of interest on all other rate base 18
adjustments included in the Company’s filing are included 19
and shown as an income impact of each individual rate base 20
adjustment described elsewhere in this testimony. 21
22
Andrews, Di 41
Avista Corporation

V. 2016 AND 2017 PRO FORMA ADJUSTMENTS 1
Q. Please explain the significance of the adjustments 2
beginning at page 9 for Schedule 1 (electric) and page 8 for 3
Schedule 2 (natural gas) of Exhibit No. 12. 4
A. The adjustments on pages 9 and 10 of Exhibit No. 5
12, Schedule 1, and pages 8 and 9 of Exhibit No. 12, 6
Schedule 2 are pro forma adjustments that recognize the 7
jurisdictional impacts of items that will impact the 2016 8
pro forma operating period. 9
Included on page 11, Schedule 1 and page 10, Schedule 2 10
of Exhibit No. 12, are additional pro forma adjustments that 11
recognize the jurisdictional impacts of items that will 12
impact the 2017 pro forma operating period. 13
These pro forma adjustments in 2016 and 2017 encompass 14
revenue and expense items as well as additional capital 15
projects, bringing the operating results and rate base to 16
the final pro forma levels for the 2016 and 2017 rate years. 17
In the discussion that follows, an explanation of each 18
2016 and 2017 pro forma adjustment is provided. The Company 19
has also provided workpapers, both in hard copy and 20
electronic formats, outlining additional details related to 21
each of the adjustments. As described below and provided in 22
accompanying workpapers, these adjustments are consistent 23
with current regulatory principles and the treatment 24
Andrews, Di 42
Avista Corporation

reflected in the last rate case, with a few proposed changes 1
by the Company discussed below. 2
2016 Rate Year – Summary of Adjustments 3
Q. Please explain each of the 2016 Pro Forma 4
adjustments included in Exhibit No. 12, starting on page 9 5
of Schedule 1 and page 8 of Schedule 2. 6
A. The first adjustment, starting on Exhibit No. 12, 7
page 9, of Schedule 1 is Electric Adjustment (3.01) - Pro 8
Forma Power Supply. This adjustment was made under the 9
direction of Mr. Johnson and is explained in detail in his 10
testimony. This adjustment includes pro forma power supply 11
related revenue and expenses to reflect the twelve-month 12
period January 1, 2016 through December 31, 2016, using 13
weather normalized historical loads. Mr. Johnson’s 14
testimony outlines the system level of pro forma power 15
supply revenues and expenses that are included in this 16
adjustment. The adjustment in column (3.01) calculates the 17
Idaho jurisdictional share of those figures. The net effect 18
of this adjustment increases electric NOI by $3,302,000. 19
Electric Adjustment (3.02) - Pro Forma Transmission 20
Revenue/Expense, was made under the direction of Mr. Cox and 21
is explained in detail in his testimony. This adjustment 22
includes pro forma transmission-related revenues and 23
expenses to reflect the twelve-month period January 1, 2016 24
Andrews, Di 43
Avista Corporation

through December 31, 2016. The net effect of this 1
adjustment decreases electric NOI by $19,000. 2
Electric Adjustment (3.03) and Natural Gas Adjustment 3
(3.01) - Pro Forma Labor Non-Exec, reflects changes to 2014 4
test period union and non-union wages and salaries, 5
excluding executive salaries. 6
For non-union employees, base year wages and salaries 7
are restated to annualize the March 2014 overall actual 8
increase of 3.0%, the March 2015 overall increase of 3.0%, 9
and 10 months of the planned March 2016 increase of 3.0%14. 10
For union employees, adjustments were made to the 2014 11
base year wages and salaries in accordance with contract 12
terms. The current contract between the Company and Local 13
Union No. 77 is in effect from March 26, 2014 through March 14
26, 2016. The terms of the contract call for 3% wage and 15
salary increases effective March 27th for 2014 and 2015. 16
Accordingly, base year wages and salaries are restated to 17
annualize the March 2014 increase, the March 2015 increase 18
and approximately nine months of an expected 2016 increase. 19
The net effect of this adjustment on Idaho’s NOI is a 20
decrease of $1,132,000 electric and $293,000 natural gas. 21
Electric Adjustment (3.04) and Natural Gas Adjustment22
14 A minimum increase of 2.9% for 2016 was approved by the Compensation Committee of the Board of Directors at the May 2015 Quarterly Board meeting. The actual increase will be updated at or above this minimum based on market data provided in November 2015, with an effective date in March 2016.
Andrews, Di 44
Avista Corporation

(3.02) - Pro Forma Labor Exec, reflects the current 2015 1
executive officer salaries. However, the Company has 2
included updated utility and non-utility allocation 3
percentages planned for 2016. The net result of these 4
changes increases the executive compensation expense 5
approximately $151,000 electric and an increase of $30,000 6
for natural gas from that included in the Company’s 7
historical base year. No additional increases in executive 8
labor for 2016 have been included in this filing. 9
The allocation of individual executive officer base 10
salaries between utility and non-utility is based on an 11
annual survey, which asks each officer to estimate the 12
percent of their time they will spend on utility, AEL&P and 13
non-utility operations. Allocation percentages are based on 14
the informed judgment of each executive officer taking into 15
consideration a number of factors including, but not limited 16
to, current and past job responsibilities, anticipated 17
changes due to projects specific to the upcoming year, 18
anticipated responsibility and/or overall upcoming strategic 19
initiatives and associated roles. The non-utility/utility 20
labor is updated in the bi-weekly timekeeping system as we 21
progress through the year based on actual time and changes 22
to strategic initiatives or job responsibilities. 23
As discussed by Mr. Thies, during 2014 the Company sold 24
its largest subsidiary (ECOVA), and acquired Alaska Energy 25
Andrews, Di 45
Avista Corporation

and Resources Company (AERC) and its subsidiary Alaska 1
Electric Light & Power (AEL&P). These activities took time 2
during 2014 that will not be required during 2015 and 2016. 3
Accordingly, executive officers have adjusted their non-4
utility allocation percentage to reflect these changes for 5
2015/2016 resulting in an overall decrease to approximately 6
11% from the 15% level in the last survey. Therefore, while 7
the level of base salaries has remained at the 2015 level, 8
changes due to updated utility/non-utility allocation 9
factors to approximately 89% utility and 11% non-utility 10
resulted in a decrease in Idaho electric NOI of $98,000 and 11
an NOI decrease of $20,000 for natural gas. 12
Electric Adjustment (3.05) and Natural Gas Adjustment 13
(3.03) - Pro Forma Employee Benefits, adjusts for changes in 14
both the Company’s pension and medical insurance expense and 15
decreases electric NOI by $1,050,000 and decreases natural 16
gas NOI by $282,000. 17
Q. Please describe the pension expense portion of the 18
Employee Benefits adjustment and Idaho’s share of this 19
expense. 20
A. The Company’s pension expense portion of the 21
calculation above is determined in accordance with 22
Accounting Standard Codification 715 (ASC-715), and has 23
increased on a system basis from approximately $19.5 million 24
for the actual base year costs for the twelve months ended 25
Andrews, Di 46
Avista Corporation

December 31, 2014, to $28.7 million for 201615. The 1
increase in pension expense included in this case (Idaho 2
share of $1.2 million electric and $330,000 natural gas) is 3
primarily due to updated mortality tables, the discount rate 4
on pension liability and expected return on assets. 5
The pension cost included in this case is based on 6
expected costs as of September 22, 2014 as determined in 7
accordance with ASC-715 by an independent actuarial firm, 8
Towers Watson. These calculations and assumptions are 9
reviewed by the Company’s outside accounting firm annually 10
for reasonableness and comparability to other companies. 11
Q. Please describe the changes to the Company’s 12
retirement plan. 13
A. In October 2013, the Company revised the defined 14
benefit pension plan such that, as of January 1, 2014, the 15
plan is no longer offered to its non-union employees hired 16
or rehired by Avista on or after January 1, 2014. A defined 17
contribution 401(k) plan will replace the defined benefit 18
pension plan for all non-union employees hired or rehired on 19
or after January 1, 2014. Under the defined contribution 20
plan, the Company will provide a non-elective contribution 21
as a percentage of each employee’s pay based on his or her22
15 In May 2015 the Company received and presented to the Compensation Committee of the Board revised 2016 Pension cost amounts totaling $31.4 million. These amounts were received after the revenue requirement calculations had been finalized. The Company will provide all updates associated with pension expense during the process of this proceeding.
Andrews, Di 47
Avista Corporation

age. The defined contribution is in addition to the 1
existing 401(k) contribution in which the Company matches a 2
portion of the pay deferred by each participant. 3
Q. Please describe the medical insurance and post-4
retirement expense portion of Electric Adjustment (3.05) and 5
Natural Gas Adjustment (3.03), and Idaho’s share of this 6
expense. 7
A. The Company’s medical insurance and post-8
retirement expense portion of these adjustments (Idaho’s 9
share of $472,000 electric and $127,000 natural gas) adjusts 10
for the expected medical-related costs for 2016 above the 11
2014 base year. This adjustment includes costs associated 12
with the employee and retiree medical plans and the FAS 106 13
expense, which records the costs associated with post 14
retirement medical. Net medical insurance and post-15
retirement expense has increased on a system basis from 16
$27.5 million for the 2014 base year to $31.0 million for 17
201616. The increase in 2016 represents medical trend and 18
utilization expectations, as well as accounting for Health 19
Care Reform mandates. 20
21
16 In May 2015 the Company received and presented to the Compensation Committee of the Board revised 2016 post-retirement and medical cost amounts totaling $31.7 million. These amounts were received after the revenue requirement calculations had been finalized. The Company will provide all updates associated with post-retirement and medical expense during the process of this proceeding.
Andrews, Di 48
Avista Corporation

Q. Please describe the changes to the Company’s 1
medical plans. 2
A. In October 2013 the Company revised its health 3
care benefit plan for non-union employees hired or rehired 4
on or after January 1, 2014. Upon retirement the Company 5
will no longer provide a contribution towards his or her 6
medical premiums. The Company will provide access to the 7
retiree medical plan, but the non-union employees hired or 8
rehired on or after January 1, 2014, will pay the full cost 9
of premiums upon retirement. In addition, beginning January 10
1, 2020, the method for calculating health insurance 11
premiums for non-union retirees under age 65 and active 12
Company employees will be revised. The revision will result 13
in separate health insurance premiums for each group. 14
Q. Please continue with your discussion of the 2016 15
pro forma adjustments. 16
A. The next adjustment is Electric Adjustment (3.06) 17
and Natural Gas Adjustment (3.04) - Pro Forma Insurance, 18
which adjusts the 2014 test period insurance expense for 19
general liability, directors and officers (“D&O”) liability, 20
and property insurance to 2016 expected levels. 21
Costs of system-wide insurance policies for 2016 have 22
increased $410,000 or approximately 8% from the policies in 23
2014. Over half of this increase relates to the increase in 24
general liability insurance, which is mainly due to primary 25
Andrews, Di 49
Avista Corporation

insurance policy providers seeking increases due to adverse 1
impacts over the last several years from increased claim 2
history and due to suspension by insurance providers of the 3
continuity credit provided in previous years. The net 4
effect of this adjustment decreases NOI by $58,000 electric 5
and $15,000 natural gas. 6
Electric Adjustment (3.07) and Natural Gas Adjustment 7
(3.05) – Pro Forma Property Tax, restates the 2014 test 8
period accrued levels of property taxes to the 2016 rate 9
period level using the most current information. As can be 10
seen from my workpapers provided with the Company’s filing, 11
the property on which the tax is calculated is the property 12
value as of December 31, 2015, reflecting the 2016 level of 13
expense the Company will experience during the 2016 rate 14
period. The net effect of this adjustment decreases NOI by 15
$795,000 electric and $322,000 natural gas. 16
Electric Adjustment (3.08) and Natural Gas Adjustment 17
(3.06) – Pro Forma Information Technology/Information 18
Services Costs, which includes the incremental costs 19
associated with software development, application licenses, 20
maintenance fees, and technical support for a range of 21
information services programs. As discussed further by Mr. 22
Kensok, these incremental expenditures are necessary to 23
support Company cyber and general security, emergency 24
operations readiness, electric and natural gas facilities 25
Andrews, Di 50
Avista Corporation

and operations support, and customer services. The effect 1
of this adjustment decreases Idaho NOI by $380,000 electric 2
and $96,000 natural gas. 3
Electric Adjustment (3.09) and Natural Gas Adjustment 4
(3.07) – Pro Forma Capital Additions 2015 EOP, reflects 5
additional 2015 capital additions17 together with the 6
associated AD and ADFIT at a December 31, 2015 EOP basis. 7
This adjustment also includes associated depreciation 8
expense for these 2015 additions. In addition, the plant-9
in-service at December 31, 2014 end-of-period was adjusted 10
to a December 31, 2015 EOP basis. Ms. Schuh describes this 11
adjustment in detail within her testimony. The effect of 12
this adjustment increases Idaho rate base $77,712,000 13
electric and $11,716,000 natural gas. The effect of this 14
adjustment on Idaho NOI is a decrease of $3,618,000 electric 15
and $661,000 natural gas. 16
Electric Adjustment (3.10) and Natural Gas Adjustment 17
(3.08) - Pro Forma Capital Additions 2016 AMA, reflects all 18
2016 capital additions together with the associated AD and 19
ADFIT at a 2016 AMA basis. This adjustment includes 20
associated depreciation expense for the 2016 additions. In 21
addition, the plant-in-service at December 31, 2015 was 22
17 For each of the periods December 2015, 2016 and 2017, distribution-related capital expenditures associated with connecting new customers to the Company’s system was excluded. An increase in revenues from growth in the number of customers from the historical test year to the 2016 and 2017 rate years are excluded, therefore, the growth in plant investment associated with customer growth was also excluded.
Andrews, Di 51
Avista Corporation

adjusted to a 2016 AMA basis. Ms. Schuh also describes this 1
adjustment in detail within her testimony. The net impact 2
of this adjustment is a reduction in total rate base of 3
$1,789,000 electric and $669,000 natural gas. The net 4
effect of this adjustment on Idaho NOI is a decrease of 5
$469,000 electric and $97,000 natural gas. 6
Electric Adjustment (3.11) and Natural Gas Adjustment 7
(3.09) – Pro Forma Operation & Maintenance (O&M) Offsets, 8
includes O&M offsets related to specific plant additions. 9
As explained by Ms. Schuh, all of the 2015 and 2016 capital 10
additions were reviewed for any net O&M offsets, both 11
increases in expenses and savings that are expected in the 12
2016 rate period. Specific expenses and savings identified 13
were included as an increase or reduction to O&M costs in 14
the Pro Forma Studies, and discussed in Mr. Kinney, Mr. Cox, 15
and Ms. Schuh’s direct testimonies with the capital asset 16
with which the net offset relates. The net effect of this 17
adjustment decreases Idaho NOI by $12,000 electric and 18
$2,000 natural gas. 19
Natural Gas Adjustment (3.10) - Pro Forma Atmospheric 20
Testing, adjusts the test period expense for Atmospheric 21
Corrosion Testing expense to include one-third of the 22
expenses recorded in the 2014 test period. Over the last 23
several years Atmospheric Testing has been completed on a 24
three-year rotation between the Company’s jurisdictions 25
Andrews, Di 52
Avista Corporation

(Idaho, Washington and Oregon) and was therefore, coded 1
directly to each jurisdiction operations in the year in 2
which the inspection occurred. In 2014, this inspection 3
program was completed in Idaho and expensed in total to 4
Idaho operations at a cost of $593,000. Therefore, the 5
Company has included only one-third of these costs in order 6
to recover this amount over a three-year period (2014-2016), 7
reducing Idaho natural gas expense by $395,000.18 The net 8
effect of this adjustment increases natural gas NOI by 9
$244,000. 10
Electric Adjustment (3.10) - Pro Forma Lake Spokane 11
Two-Year Amortization, reflects the proposed two-year 12
amortization of the deferred costs related to improving 13
dissolved oxygen levels in Lake Spokane. In Case No. AVU-E-14
13-05 (see Order No. 32917), the Company sought, and 15
received approval of an Accounting Order to defer the costs 16
related to the improvement of dissolved oxygen levels in 17
Lake Spokane. Order No. 32917 authorized the Company to 18
defer and transfer Idaho’s share of these costs 19
(approximately $473,000) to FERC account 182.3 (Other 20
Regulatory Assets) for later recovery, with no carrying 21
charge, and a prudency review of these costs to occur in the22
18 Starting in 2016 in Washington, and 2017 in Idaho and Oregon, Atmospheric Testing will be transitioned from completing this testing every three years by state to an inspection cycle that is completed 1/3 by state, per year. See 2017 pro forma adjustments discussion below for further explanation.
Andrews, Di 53
Avista Corporation

next general rate case or future proceeding. Mr. Kinney 1
discusses these costs in his direct testimony. The net 2
effect of this adjustment decreases electric NOI by 3
$147,000. 4
Electric Adjustment (3.13) - Pro Forma Colstrip 5
Settlement, reflects the proposed two-year amortization of 6
the deferred revenues received from insurance proceeds 7
related to the Colstrip lawsuit settlement funds received in 8
2014. Consistent with expenses associated with the Colstrip 9
lawsuit settlement payments made in 2008 previously 10
deferred19 and amortized over two-years20 in Idaho’s 11
jurisdiction, the Company is proposing a two-year 12
amortization of these refund amounts. The net effect of 13
this adjustment increases electric NOI by $124,000. 14
Electric Adjustment (3.14) and Natural Gas Adjustment 15
(3.11) - Pro Forma Project Compass Deferral Amortization, 16
includes the amortization expense associated with a proposed 17
two-year amortization of 80% of the deferred electric and 18
natural gas revenue requirement amounts associated with the 19
Company’s Project Compass Customer Information System 20
(Project Compass) for calendar year 2015. 21
In Case Nos. AVU-E-14-05 and AVU-G-14-01, the22
19 Deferral of lawsuit expenses were approved in Order No. 30638, Case No. AVU-E-08-03. 20 A two-year amortization of the Colstrip Lawsuit expenses were approved in Case No. AVU-E-09-01.
Andrews, Di 54
Avista Corporation

Commission approved an all-party settlement, in which the 1
Parties agreed that eighty-percent (80%) of the revenue 2
requirement associated with Project Compass during 2015, 3
beginning the month the Project goes into service, would be 4
deferred, without a carrying charge, for recovery in a 5
future proceeding. The 80% figure was arrived at through 6
negotiation for calendar year 2015 only, and was unrelated 7
to any assessment or determination of the prudence of the 8
Project. The deferral was due, in part, to the uncertainty 9
of the timing of the in-service date for the project. 10
Avista was to address the prudence of Project Compass in its 11
next general rate case. 12
This project was moved into service on February 2, 13
2015. Mr. Kensok discusses Project Compass in detail within 14
his testimony, and Ms. Schuh incorporates the capital 15
additions related to this project within her adjustments. 16
The effect of this adjustment decreases Idaho NOI by 17
$822,000 electric and $207,000 natural gas. 18
2017 Rate Year – Summary of Adjustments 19
Q. Please now explain each of the 2017 Pro Forma 20
adjustments included in Exhibit No. 12, starting on page 10 21
of Schedule 1 and page 9 of Schedule 2. 22
A. Yes. But before I begin, it is important to note 23
that the Company has only included the incremental expenses24
Andrews, Di 55
Avista Corporation

above 2016 level revenue and expenses for major cost 1
categories, such as new plant investment, including 2
depreciation and property taxes, expected increases in net 3
power supply and transmission costs, labor costs, and 4
atmospheric testing related to natural gas operations. The 5
Company believes there will be additional increased expenses 6
during the 2017 rate year not included here, and therefore 7
the results of the 2017 pro forma incremental 2017 revenue 8
requirement included in this filing is conservative. 9
Please also note, in addition to the explanation of 10
adjustments provided herein, the Company has also provided 11
workpapers, both in hard copy and electronic formats, 12
outlining additional details related to each of the 2017 pro 13
forma adjustments. A summary of each adjustment follows: 14
The first adjustment, starting on Exhibit No. 12, page 15
11, of Schedule 1 is Electric Adjustment (17.01) - Pro Forma 16
Power Supply. This adjustment was made under the direction 17
of Mr. Johnson and his testimony discusses the 2017 system 18
level pro forma power supply revenues and expenses that are 19
included in his adjustment. This adjustment includes 20
Idaho’s share of the net pro forma power supply revenue and 21
expenses to reflect the twelve-month period January 1, 2017 22
through December 31, 2017, using historical loads. The Pro 23
Forma 2017 power supply revenues and expenses is compared to 24
the Pro Forma 2016 power supply revenues and expenses to 25
Andrews, Di 56
Avista Corporation

adjust for the incremental power supply expense in the 2017 1
rate year.21 The net effect of this adjustment decreases 2
electric NOI by $5,427,000. 3
Electric Adjustment (17.02) - Pro Forma Transmission 4
Revenue/Expense, was made under the direction of Mr. Cox and 5
is explained in detail in his testimony. This adjustment 6
includes pro forma transmission-related revenues and 7
expenses to reflect the incremental revenues and expenses 8
for the twelve-month period January 1, 2017 through December 9
31, 2017. The net effect of this adjustment increases 10
electric NOI by $437,000. 11
Electric Adjustment (17.03) and Natural Gas Adjustment 12
(17.01) - Pro Forma Labor Non-Exec, reflects incremental 13
union and non-union wages and salaries from 2016 to 2017, 14
excluding executive salaries. 15
For non-union employees, wages and salaries were 16
adjusted to annualize the March 2016 estimated increase of 17
3.0%22, and 10 months of the estimated March 2017 increase 18
of 3.0%. For union employees, wages and salaries were 19
adjusted to annualize the March 2016 estimated increase and20
21 As discussed by Mr. Johnson, the largest driver increasing net power supply expense from 2016 to 2017 is the expiration of the Portland General Electric capacity sale December 31, 2016, increasing Idaho’s net power supply expense approximately $5.1 million ($14.5 million system).
22 A minimum increase of 2.9% for 2016 was approved by the Compensation Committee of the Board of Directors at the May 2015 quarterly Board meeting. The actual increase will be updated at or above this minimum based on market data provided in November 2015, for an effective date in March 2016.
Andrews, Di 57
Avista Corporation

10 months of the estimated increase for March 2017. The 1
incremental increase above the 2016 Pro Forma labor Non-Exec 2
adjustment was included in 2017 to reflect 2017 rate year 3
levels. The net effect of this adjustment on Idaho’s NOI is 4
a decrease of $378,000 electric and $101,000 natural gas. 5
Electric Adjustment (17.04) and Natural Gas Adjustment 6
(17.02) – Pro Forma Property Tax, reflects incremental 7
property tax expense from 2016 to 2017 using the most 8
current information. As can be seen from my workpapers 9
provided with the Company’s filing, the property on which 10
the tax is calculated is the property value as of December 11
31, 2016, reflecting the 2017 level of expense the Company 12
will experience during the 2017 rate period. The net effect 13
of this adjustment decreases NOI by $571,000 electric and 14
$161,000 natural gas. 15
Electric Adjustment (17.05) and Natural Gas Adjustment 16
(17.03) - Pro Forma Capital Additions 2017 AMA, reflects all 17
2017 capital additions together with the associated AD and 18
ADFIT at a 2017 AMA basis. This adjustment includes 19
associated depreciation expense for the 2017 additions. In 20
addition, the plant-in-service on a 2016 AMA basis is 21
adjusted to a 2017 AMA basis. Ms. Schuh also describes this 22
adjustment in detail within her testimony. The net impact 23
of this adjustment is an increase in total rate base of 24
$17,746,000 electric and $3,339,000 natural gas. The net 25
Andrews, Di 58
Avista Corporation

effect of this adjustment on Idaho NOI is a decrease of 1
$1,136,000 electric and $223,000 natural gas. 2
Natural Gas Adjustment (17.04) - Pro Forma Atmospheric 3
Testing, adjusts the 2016 rate year expense for Atmospheric 4
Testing to the expense level expected in the 2017 rate year. 5
As noted above in Pro Forma Atmospheric Testing 6
adjustment (3.10), the 2016 Atmospheric Corrosion expense 7
was included at one-third of the expenses recorded in the 8
2014 test period to recover costs over three years to match 9
the every-three-year cycle in which this testing program was 10
being completed in each state. Starting in 2016 in 11
Washington, and 2017 in Idaho and Oregon, however, the 12
Atmospheric Testing will be transitioned from completing 13
this testing every three years by state to an inspection 14
cycle that is completed one-third by state, per year. 15
Over the last several years, administering this program 16
on an every-three-year cycle has resulted in two primary 17
program challenges: 1) inadequate availability of state 18
resources to respond to inspection follow-up actions due to 19
the volume spike of work once every three years and 2) 20
varying O&M expenditure requirements related to the 21
inspection results in each state during this three year 22
period. Moving the inspection cycle to one-third by state 23
by year will levelize program spending and resources 24
required to mitigate the inspection anomalies noted above. 25
Andrews, Di 59
Avista Corporation

(For more information regarding the Atmospheric Testing 1
program see my filed workpapers.) 2
The net effect of this adjustment decreases natural gas 3
NOI by $284,000. 4
Final Summary 5
Q. How much additional net operating income would be 6
required for the State of Idaho electric operations to allow 7
the Company an opportunity to earn its proposed 7.62% rate 8
of return on a pro forma basis? 9
A. The net operating income deficiency amounts to 10
$8,131,000 for 2016 and $8,428,000 for 2017, as shown on 11
line 5, page 3 of Exhibit No. 12, Schedule 1. The resulting 12
revenue requirement is shown on line 7 and amounts to 13
$13,230,000 for 2016, or an increase of 4.58%, and 14
$13,713,000 for 2017, or an increase of 5.31%. 15
Q. How much additional net operating income would be 16
required for the State of Idaho natural gas operations to 17
allow the Company an opportunity to earn its proposed 7.62% 18
rate of return on a pro forma basis? 19
A. The net operating income deficiency amounts to 20
$1,970,000 for 2016 and $1,023,000 for 2017, as shown on 21
line 5, page 3 of Exhibit No. 12, Schedule 2. The resulting 22
revenue requirement is shown on line 7 and amounts to 23
$3,205,000 for 2016, or an increase of 8.84% (4.48% on a 24
Andrews, Di 60
Avista Corporation

billed basis), and $1,665,000 for 2017, or an increase of 1
4.22% (or 2.19% on a billed basis). 2
3
VI. ALLOCATION PROCEDURES 4
Q. Have there been any changes to the Company’s 5
system and jurisdictional procedures since the Company’s 6
last general electric and natural gas cases, Case Nos. AVU-7
E-12-08 and AVU-G-12-07? 8
A. No. For ratemaking purposes, the Company 9
allocates revenues, expenses and rate base between electric 10
and natural gas services and between Idaho, Washington and 11
Oregon jurisdictions where electric and/or natural gas 12
service is provided. The annually updated allocation 13
factors used in this case have been provided with my 14
workpapers. 15
Q. Does that conclude your pre-filed direct 16
testimony? 17
A. Yes, it does. 18
Andrews, Di 61
Avista Corporation