20121011Andrews DI.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-12-08
OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-G-12-07
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)

Andrews, Di 1
Avista Corporation
CONTENTS 1
Section Page 2
I. Introduction 2 3
II. Combined Revenue Requirement Summary 4 4
III. Derivation of Revenue Requirement 10 5
Test Period for Ratemaking Purposes 10 6
Revenue Requirement 11 7
Standard Commission Basis and Restating Adjustments 14 8
Pro Forma Adjustments 32 9
Summary 42 10
IV. Allocation Procedures 43 11
12
Exhibit No. 10: 13
Schedule 1 - Electric Revenue Requirement and 14
Results of Operations (pgs 1-9) 15
Schedule 2 - Natural Gas Revenue Requirement and 16
Results of Operations (pgs 1-9) 17

Andrews, Di 2
Avista Corporation
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 3
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 twelve years, I have assisted or 6
led the Company‟s electric and/or natural gas general rate 7
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 need for the proposed increase in rates. I will 13
explain pro formed operating results, including expense and 14
rate base adjustments made to actual operating results and 15
rate base. In addition, I incorporate the Idaho share of 16
the proposed adjustments of other witnesses in this case. 17
Q. Are you sponsoring any exhibits to be introduced 18
in this proceeding? 19
A. Yes. I am sponsoring Exhibit No. 10, Schedule 1 20
(Electric) and Schedule 2 (Natural Gas), which were prepared 21
under my direction. These exhibits consist of worksheets, 22
which show actual twelve months ended June 30, 2012 23
operating results, pro forma, and proposed electric and 24
natural gas operating results and rate base for the State of 25

Andrews, Di 4
Avista Corporation
Idaho. The exhibits also show the calculation of the 1
general revenue requirement, the derivation of the Company‟s 2
overall proposed rate of return, the derivation of the net-3
operating-income-to-gross-revenue-conversion factor, and the 4
specific pro forma adjustments proposed in this filing. 5
6
II. COMBINED REVENUE REQUIREMENT SUMMARY 7
Q. Would you please summarize the results of the 8
Company’s pro forma study for both the electric and natural 9
gas operating systems for the Idaho jurisdiction? 10
A. Yes. After taking into account all standard 11
Commission Basis adjustments, as well as additional pro 12
forma and normalizing adjustments, the pro forma electric 13
and natural gas rates of return (“ROR”) for the Company‟s 14
Idaho jurisdictional operations are 7.32% and 5.84%, 15
respectively. Both return levels are below the Company‟s 16
requested rate of return of 8.46%. The incremental revenue 17
requirement necessary to give the Company an opportunity to 18
earn its requested ROR is $11,393,000 for the electric 19
operations and $4,561,000 for the natural gas operations. 20
The overall base electric increase associated with this 21
request is 4.58%. The base natural gas increase is 7.20%. 22
Q. What are the Company’s rates of return that were 23
last authorized by this Commission for its electric and gas 24
operations in Idaho? 25

Andrews, Di 5
Avista Corporation
A. The Company‟s last authorized rate of return for 1
its Idaho operations was 8.55%, effective October 1, 2010 2
for both our electric and natural gas systems.2 3
Q. What are the primary factors driving the Company’s 4
need for an electric and natural gas increases? 5
A. Approximately 70% of the Company‟s electric 6
revenue requirement, and 48% for natural gas, is due to an 7
increase in Net Plant Investment (including return on 8
investment, depreciation and taxes, and offset by the tax 9
benefit of interest).3 10
The remaining revenue requirement request is due to 11
increases in distribution, operation and maintenance (O&M), 12
and administrative and general (A&G) expenses for both 13
electric and natural gas operations. However, the increased 14
costs for electric operations are partially offset by a 15
reduction in net power supply and transmission expenditures. 16
Also impacting the Company‟s electric request, the 17
Company has included an Energy Efficiency Load Adjustment 18
(EELA) increasing the Company‟s revenue requirement by 19
approximately $1.6 million. As explained by Company Witness 20
2 For the 2011 cases (AVU-E-10-01 & AVU-G-10-01), which had rates
effective October 1, 2011, the Parties to the cases agreed to black box
settlements, therefore, the ROR was not specified. 3 These figures represent an approximate breakdown of amounts between
the Company‟s request in this case compared to that approved in the
Company‟s prior general rate case proceeding (Case Nos. AVU-E-11-01 and
AVU-G-11-01). Due to the black-box nature of the Company‟s prior
settlement approved by the IPUC in Case Nos. AVU-E-11-01 and AVU-G-11-
01, the Company made certain assumptions as to the amounts approved for
various rate base and expense items in order to create the estimate of
the breakdown of the rate increase request.

Andrews, Di 6
Avista Corporation
Mr. Ehrbar, the reduced load from the EELA causes an 1
increase in revenue requirement in each of the major cost 2
categories, because the foregone retail revenue from the 3
load reduction is designed to recover costs in each of the 4
categories. 5
Q. What were the major components of the increased 6
net plant investment included in the Company’s electric and 7
natural gas filings? 8
A. Looking at the changes to “gross” plant in 9
service, Idaho “gross” plant increased by approximately 10
$37.2 million electric and $12.3 million natural gas, as 11
compared to what was included in the last rate case. In 12
order to meet the energy and reliability needs of our 13
customers, $15.4 million of the electric “gross” plant 14
increase is due to the Company‟s investment in thermal and 15
hydro generating facilities, as well as additional 16
transmission investment. Electric distribution “gross” 17
plant increased $10.0 million above that included in the 18
last rate case, while the electric portion of general and 19
intangible “gross” plant increased $11.8 million. 20
Related to gas, $8.2 million of the natural gas “gross” 21
plant increase is due to the Company‟s investment in natural 22
gas distribution plant above that included in the last rate 23
case, while the natural gas portion of general “gross” plant 24
increased $4.1 million. 25

Andrews, Di 7
Avista Corporation
The specific 2012 and 2013 pro forma capital 1
expenditures undertaken by the Company to expand and replace 2
its generation, transmission and distribution facilities are 3
discussed further by Company witnesses Mr. Lafferty 4
regarding production assets, and Mr. Kinney regarding 5
transmission and distribution assets. In addition to 6
discussing the actual restating and pro forma adjustments 7
regarding net plant investment, Company witness Mr. DeFelice 8
also describes all remaining 2012 and 2013 plant additions 9
not described by Mr. Lafferty and Mr. Kinney. 10
Q. Mr. DeFelice explains the restating pro forma 11
capital adjustments included in this case. Could you please 12
briefly describe the conclusions drawn by Mr. DeFelice 13
regarding the increased capital investment? 14
A. Yes. As described in Mr. DeFelice‟s testimony, 15
the Company is making substantial new investment in its 16
electric and natural gas system infrastructure to address 17
the replacement and maintenance of Avista‟s aging system, 18
and to sustain reliability and safety. As soon as this new 19
plant is placed in service, the Company must start 20
depreciating the new plant and incur other costs related to 21
the investment. Unless this new investment is reflected in 22
retail rates in a timely manner, it has a negative impact on 23
Avista‟s earnings, particularly because the new plant is 24
typically far more costly to install than the cost of the 25

Andrews, Di 8
Avista Corporation
plant that was embedded in rates decades earlier. As plant 1
is completed and is providing service to customers, it is 2
appropriate for the Company to receive timely recovery of 3
the costs associated with that plant. 4
Q. Could you please provide additional details 5
related to the changes in electric production and 6
transmission expense? 7
A. Yes. As discussed in Company witness Mr. Johnson‟s 8
testimony, the level of Idaho‟s share of power supply 9
expense has decreased by approximately $4.7 million ($13.56 10
million on a system basis) from the level included in the 11
last rate case. 12
This decrease in pro forma power supply expense over 13
the expense included in the last rate case is primarily a 14
result of lower natural gas and power prices. For example, 15
the natural gas price included in the Company‟s AURORA model 16
has decreased from an annual average of $4.62/dth to 17
$3.44/dth. The average modeled power purchase price has 18
decreased from $40.45/MWh to $28.33/MWh. In addition, pro 19
forma system loads are lower by 3.2 average megawatts (aMW) 20
than the load included in the last rate case. Mr. Johnson 21
discusses in further detail the changes in power supply 22
expenses. 23
The reduction in power supply expense is partially 24
offset by increased generation expense of approximately $2.2 25

Andrews, Di 9
Avista Corporation
million, including one-third of the three-year amortization 1
of deferred Colstrip & Coyote Springs 2 (CS2) operation and 2
maintenance (O&M) expense4 of $1.3 million, (Idaho share) 3
and increased hydro generation major maintenance expense of 4
$907,000 (Idaho share) planned in 2013. 5
Lastly, pro forma net transmission expenditures 6
decreased, mainly due to approximately $3.8 million (System) 7
of increased electric revenues from various contracts, 8
including the BPA Parallel Capacity support contract and a 9
reduction in expenses from that included in the last rate 10
case of $1.9 million (System) associated with the 11
Transmission Line Ratings Confirmation Plan to be completed 12
in 2013, as discussed by Mr. Kinney. 13
Q. Could you please identify the main components of 14
the distribution, O&M and A&G expense changes included in 15
the Company’s filing? 16
A. Yes. A number of expense items have increased 17
since the 2010 test year pro forma used in the last rate 18
case. For example, employee benefits such as wages, pension 19
and post-retirement medical expenses have increased. 20
We are utilizing a June 30, 2012 twelve-months-ended 21
test year. The Company has included a number of pro forma 22
4 As approved in Case No. AVU-E-11-01, the Company is amortizing prior
year‟s deferred operation and maintenance (O&M) expense (the amount of
actual costs in excess of costs included in base rates for 2011 and
2012) related to the Company‟s Coyote Springs 2 (CS2) natural gas-fired
generating plant and Avista‟s 15 percent ownership share of the Colstrip
3 & 4 coal-fired generating plants, over a three-year period.

Andrews, Di 10
Avista Corporation
adjustments to capture some of the cost changes that the 1
Company will experience from the test year. In particular, 2
the Company has pro formed in the increased costs associated 3
with compensation, including labor, pension and medical 4
expense increases of approximately $2.4 million electric and 5
$700,000 natural gas, and increases in Information Systems 6
and Technology expenses of approximately $345,000 electric 7
and $74,000 natural gas, which equates to approximately 45% 8
of the electric and 30% of the natural gas additional 9
increases in distribution, O&M and A&G expense included in 10
the Company‟s filing. The majority of the remaining 11
increases reflect net increases in costs over the 18-month 12
period since the Company‟s last general rate case filing. 13
14
III. DERIVATION OF REVENUE REQUIREMENT 15
Test Period for Ratemaking Purposes 16
Q. On what test period is the Company basing its need 17
for additional electric and natural gas revenue? 18
A. The test period being used by the Company is the 19
twelve-month period ending June 30, 2012, presented on a pro 20
forma basis. Currently authorized rates, effective October 21
1, 2011, were based upon the twelve-months ending December 22
31, 2010 test year utilized in cases AVU-E-11-01 and AVU-G-23
11-01, adjusted on a pro forma basis. 24
25

Andrews, Di 11
Avista Corporation
Revenue Requirement 1
Q. Would you please explain what is shown in Exhibit 2
No. 10, Schedules 1 and 2? 3
A. Yes. Exhibit No. 10, Schedules 1 and 2, show 4
actual and pro forma electric and natural gas operating 5
results and rate base for the test period for the State of 6
Idaho. Column (b) of page 1 of Exhibit No. 10, Schedules 1 7
and 2, show June 30, 2012 actual operating results and 8
components of the average-of-monthly-average rate base as 9
recorded5; column (c) is the total of all adjustments to net 10
operating income and rate base; and column (d) is pro forma 11
results of operations, all under existing rates. Column (e) 12
shows the revenue increase required which would allow the 13
Company to earn an 8.46% rate of return. Column (f) 14
reflects pro forma operating results with the requested 15
increase of $11,393,000 for electric and $4,561,000 for 16
natural gas. The restating adjustments shown in columns 17
(1.01) through (2.13), of pages 6 through 10 of Exhibit No. 18
10, Schedule 1 (electric), and columns (1.01) through 19
(2.09), of pages 6 through 10 of Exhibit No. 10, Schedule 2 20
(natural gas) are consistent with current regulatory 21
principles and the manner in which they have been addressed 22
in recent cases. 23

5 Actual plant rate base (cost, accumulated depreciation and associated
DFIT) uses the AMA December 31, 2011 balances. Plant rate base is
adjusted to a 2013 AMA basis with restating and pro forma adjustments.

Andrews, Di 12
Avista Corporation
Q. Would you please explain page 2 of Exhibit No. 10, 1
Schedules 1 and 2? 2
A. Yes. Page 2 of Schedule 1 shows the calculation 3
of the $11,393,000 revenue requirement for electric and Page 4
2 of Schedule 2 shows the calculation of the $4,561,000 5
revenue requirement for natural gas at the requested 8.46% 6
rate of return. 7
Q. What does page 3 of Exhibit No. 10, Schedules 1 8
and 2 show? 9
A. Page 3 shows the proposed Cost of Capital and 10
Capital Structure utilized by the Company in this case, and 11
the weighted average cost of capital of 8.46%. Company 12
witness Mr. Thies discusses the Company‟s proposed rate of 13
return and the pro forma capital structure utilized in this 14
case, while Company witness Dr. Avera provides additional 15
testimony related to the appropriate return on equity for 16
Avista. 17
Q. Would you now please explain page 4 of Exhibit No. 18
10, Schedules 1 and 2? 19
A. Yes. Page 4 shows the derivation of the net-20
operating-income-to-gross-revenue-conversion factor. The 21
conversion factor takes into account uncollectible accounts 22
receivable, Commission fees and Idaho State income taxes. 23
Federal income taxes are reflected at 35%. 24

Andrews, Di 13
Avista Corporation
Q. Now turning to pages 5 through 9 of your Exhibit 1
No. 10, Schedules 1 and 2, would you please explain what 2
those pages show? 3
A. Yes. Page 5 begins with actual operating results 4
and rate base for the test period in column (b). Individual 5
normalizing and restating adjustments that are standard 6
components of Commission Basis reporting or general rate 7
case filings begin in column (1.01). Individual pro forma 8
adjustments begin in column (3.01) on page 8 and continue 9
through page 9. The final column on page 9 is the total pro 10
forma operating results and net rate base for the test 11
period. 12
13
Standard Commission Basis and Restating Adjustments 14
Q. Would you please explain each of these 15
adjustments? 16
A. Yes, but before I begin, I will note that the 17
following adjustments are consistent with the adjustments 18
made in the Company‟s previous filed cases (AVU-E-11-01 and 19
AVU-G-11-01), utilizing the same methodology to determine 20
the adjustments. Rate base adjustments primarily adjust the 21
June 30, 2012 test period amounts to a 2013 AMA amount. 22
I will note a few changes made to the Results of 23
Operations column (1.00), reflecting the Company‟s actual 24
electric operating results and rate base. 25

Andrews, Di 14
Avista Corporation
In past general rate case filings based on past 1
Commission orders, this column represented actual net 2
operating income and net utility plant, which included 3
balances after accumulated depreciation and amortization, 4
but before accumulated deferred income taxes (DFIT) and 5
other rate base adjustments impacting the Company‟s actual 6
net rate base results. Accumulated DFIT and other rate base 7
adjustments were included as “Standard Commission Basis and 8
Restating Adjustments” to be consistent with prior 9
Commission orders, resulting in a “Restated Total” provided 10
within the Company‟s filing. 11
In this filing however, column (1.00) Results of 12
Operations reflects the actual operating results and total 13
net rate base experienced by the Company on an average-of-14
monthly-average (AMA) basis, including Accumulated DFIT and 15
other rate base adjustments previously shown as restating 16
adjustments.6 Columns following the Results of Operations 17
column (1.00) reflect restating adjustments necessary to: 18
restate the actual results based on prior Commission orders; 19
reflect appropriate annualized expenses; correct for errors; 20
or remove prior period amounts reflected in the actual 21
results of operations. 22

6 As noted above, actual plant rate base (cost, accumulated depreciation
and associated DFIT) uses the AMA December 31, 2011 balances. Plant
rate base is adjusted to a 2013 AMA basis with restating and pro forma
adjustments. All other rate base amounts are included in column 1.00 on
a June 30, 2012 AMA basis.

Andrews, Di 15
Avista Corporation
In addition to the explanation of adjustments provided 1
herein, the Company has also provided workpapers, both in 2
hard copy and electronic formats, outlining additional 3
details related to each of the adjustments. 4
A summary of the adjustments follows: 5
Electric Adjustment (1.01) and Natural Gas Adjustment 6
(1.01) - Deferred FIT Rate Base, adjusts the electric and 7
natural gas DFIT rate base balances to the corrected DFIT 8
balances, as shown within my workpapers provided with the 9
Company‟s filing. Accumulated DFIT reflects the deferred 10
tax balances arising from accelerated tax depreciation 11
(Accelerated Cost Recovery System, or ACRS, and Modified 12
Accelerated Cost Recovery, or MACRS) and bond refinancing 13
premiums. The effect on Idaho rate base is a reduction of 14
$285,000 electric and an increase of $297,000 natural gas. 15
The effect on Idaho net operating income (NOI) is a 16
reduction of $3,000 electric and an increase of $3,000 17
natural gas. 18
Electric Adjustment (1.02) and Natural Gas Adjustment 19
(1.02) - Deferred Debits and Credits, is a consolidation of 20
previous Commission Basis or other restating rate base 21
adjustments and their NOI impact. The net impact on a 22
consolidated basis of this adjustment decreases Idaho 23
electric rate base by $409,000 and increases natural gas 24

Andrews, Di 16
Avista Corporation
rate base by $2,000. Idaho electric NOI increases by a 1
total of $16,000, while natural gas NOI decreases by $8,000. 2
As noted above, the June 2012 AMA actual rate base 3
amounts of other rate base adjustments are included in the 4
Results of Operations column (1.00). Adjustments included 5
in the Deferred Debits and Credits consolidated adjustment 6
are those necessary to reflect restatements from actual 7
results based on prior Commission orders, and are explained 8
below. For consistency with prior rate case filings, a 9
description of each previously separated adjustment is 10
included below. 11
The following items are included in the consolidation: 12
Gain on Office Building reflects the removal of 13
the amortization expense and AMA rate base balance 14
included in the Company‟s test period related to 15
Idaho‟s portion of the amortized gain on the sale of 16
the Company‟s general office facility. The facility 17
was sold in December 1986 and leased back by the 18
Company. Although the Company repurchased the building 19
in November 2005, the Company opted to continue to 20
amortize the deferred gain over the remaining 21
amortization period ending in 2011. 22
Colstrip 3 AFUDC Elimination is a reallocation of 23
rate base and depreciation expense between 24
jurisdictions. In Cause Nos. U-81-15 and U-82-10, the 25
Washington Utilities and Transportation Commission 26
(WUTC) allowed the Company a return on a portion of 27
Colstrip Unit 3 construction work in progress (CWIP). 28
A much smaller amount of Colstrip Unit 3 CWIP was 29
allowed in rate base in Case No. U-1008-144 by the 30
Idaho Public Utility Commission (IPUC). The Company 31
eliminated the AFUDC associated with the portion of 32
CWIP allowed in rate base in each jurisdiction. Since 33
production facilities are allocated on the 34
Production/Transmission formula, the allocation of 35
AFUDC is reversed and a direct assignment is made. 36
Colstrip Common AFUDC is also associated with the 37
Colstrip plants in Montana, and increases rate base. 38

Andrews, Di 17
Avista Corporation
Differing amounts of Colstrip common facilities were 1
excluded from rate base by this Commission and the WUTC 2
until Colstrip Unit 4 was placed in service. The 3
Company was allowed to accrue AFUDC on the Colstrip 4
common facilities during the time that they were 5
excluded from rate base. It is necessary to directly 6
assign the AFUDC because of the differing amounts of 7
common facilities excluded from rate base by this 8
Commission and the WUTC. In September 1988, an entry 9
was made to comply with a Federal Energy Regulatory 10
Commission (FERC) Audit Exception, which transferred 11
Colstrip common AFUDC from the plant accounts to 12
Account 186. These amounts reflect a direct assignment 13
of rate base for the appropriate average-of-monthly-14
averages amounts of Colstrip common AFUDC to the 15
Washington and Idaho jurisdictions. Amortization 16
expense associated with the Colstrip common AFUDC is 17
charged directly to the Washington and Idaho 18
jurisdictions through Account 406 and is a component of 19
the actual results of operations. 20
Kettle Falls & Boulder Park Disallowances reflects 21
the Kettle Falls generating plant disallowance ordered 22
by this Commission in Case No. U-1008-185 and the 23
Boulder Park plant disallowance ordered by the IPUC in 24
Case No. AVU-E-04-1. The IPUC disallowed a rate of 25
return on $3,009,445 of investment in Kettle Falls, and 26
$2,600,000 million of investment in Boulder Park. The 27
disallowed investment, and related accumulated 28
depreciation and accumulated deferred taxes are 29
removed. These amounts are a component of actual 30
results of operations. 31
Restating CDA Settlement Deferral adjusts the net 32
assets and DFIT balances associated with the 2008/2009 33
past storage and §10(e) charges deferred for future 34
recovery to a 2013 AMA basis, and records the annual 35
amortization expense based on a ten-year amortization, 36
as approved in Docket No. AVU-E-10-01. 37
Restating Spokane River Deferral adjusts the net 38
asset and DFIT balances related to the Spokane River 39
deferred relicensing costs to a 2013 AMA basis, and 40
records the annual amortization expense based on a ten-41
year amortization as approved in Case No. AVU-E-10-01. 42
Restating Spokane River PM&E Deferral adjusts the 43
net asset and DFIT balances related to the Spokane 44
River deferred PM&E costs to a 2013 AMA basis, and 45
records the annual amortization expense based on a ten-46
year amortization as approved in Case No. AVU-E-10-01. 47
Restating Montana Riverbed Lease reflects the 48
costs associated with the Montana Riverbed lease 49

Andrews, Di 18
Avista Corporation
settlement. In this settlement, the Company agreed to 1
pay the State of Montana $4.0 million annually 2
beginning in 2007, with annual inflation adjustments, 3
for a 10-year period for leasing the riverbed under the 4
Noxon Rapids Project and the Montana portion of the 5
Cabinet Gorge Project. The first two annual payments 6
were deferred by Avista as approved in Case No. AVU-E-7
07-10. In Case No. AVU-E-08-01 (see Order No. 30647), 8
the Commission approved the Company‟s accounting 9
treatment of the deferred payments, including accrued 10
interest, to be amortized over the remaining eight 11
years of the agreement starting October 1, 2008. This 12
adjustment includes amortization of one-eighth of the 13
deferred balance and the adjustment to lease payment 14
expense for the additional annual inflation. 15
Weatherization and DSM Investment includes in rate 16
base the Sandpoint weatherization grant balance (FERC 17
account 124.350), and removes the 1994 DSM Program 18
amortization expense included in the test period. 19
Beginning in July 1994 accumulation of AFUCE7 ceased on 20
Electric DSM and full amortization began on the balance 21
based on the measure lives of the investment. 22
Beginning in 1995 the amortization rates were 23
accelerated to achieve a 14 year weighted average 24
amortization period, which was completed in 2010. As 25
no expense will be incurred during the 2013 rate year 26
the portion of the 2010 amortization included in the 27
test period is being eliminated. 28
Customer Advances decreases rate base for moneys 29
advanced by customers for line extensions, as they will 30
be recorded as contributions in aid of construction at 31
some future time. 32
33
Electric Adjustment (1.03) and Natural Gas Adjustment 34
(1.03) - Working Capital, maintains the working capital rate 35
base amount at the June 30, 2012 AMA test period amount 36
included in the Results of Operations column (1.00), and 37
therefore there is no additional adjustment to rate base 38
needed. The Company has calculated its working capital in 39
this proceeding by including Idaho‟s portion of the June 30, 40

7 Allowance for funds used to conserve energy.

Andrews, Di 19
Avista Corporation
2012 average-monthly-average balances of FERC accounts 151 1
(Fuel Stock Inventory) and 154 (Plant Materials and 2
Supplies). 3
Electric Adjustment (1.04) and Natural Gas Adjustment 4
(1.04) - Restate 2011 Capital, restates the capital cost and 5
expenses associated with adjusting the 2011 average-of-6
monthly-average (AMA) plant related balances to end-of-7
period (EOP) balances for plant in service at December 31, 8
2011.8 The effect on Idaho rate base is an increase of 9
$9,464,000 to electric and a reduction of $242,000 to 10
natural gas rate base. The effect on Idaho net operating 11
income (NOI) is a reduction of $327,000 electric and $73,000 12
natural gas. 13
Electric Adjustment (2.01) and Natural Gas Adjustment 14
(2.02) - Eliminate B & O Taxes, eliminates the revenues and 15
expenses associated with local business and occupation (B & 16
O) taxes, which the Company passes through to its Idaho 17
customers. The effect of this adjustment decreases electric 18
NOI by $5,000, while natural gas nets to a $0 NOI change. 19
Electric Adjustment (2.02) and Natural Gas Adjustment 20
(2.03) - Uncollectible Expense, restates the accrued expense 21
to the actual level of net write-offs for the test period. 22

8 Separate Pro Forma adjustments revise the total plant in service at
December 31, 2011 to end-of-period December 31, 2012 and then to AMA
2013 in adjustments “Planned Capital Additions 2012” and “Planned
Capital Additions 2013 AMA.” See Electric Adjustments (3.09) and (3.10)
and Natural Gas Adjustments (3.08) and (3.09) described below.

Andrews, Di 20
Avista Corporation
The effect of this adjustment increases electric NOI by 1
$106,000 and natural gas NOI by $211,000. 2
Electric Adjustment (2.03) and Natural Gas Adjustment 3
(2.04) - Regulatory Expense, restates recorded test period 4
regulatory expense to reflect the IPUC assessment rates 5
applied to expected revenues for the test period and the 6
actual levels of FERC fees paid during the test period. The 7
effect of this adjustment increases electric NOI by $23,000, 8
while natural gas NOI decreases by $1,000. 9
Electric Adjustment (2.04) and Natural Gas Adjustment 10
(2.05) - Injuries and Damages, is a restating adjustment 11
that replaces the accrual with the six-year rolling average 12
of actual injuries and damages payments not covered by 13
insurance. This methodology was accepted by the Idaho 14
Commission in Case No. WWP-E-98-11, and has been used since 15
that time. The effect of this adjustment decreases electric 16
NOI by $234,000 and natural gas NOI by $13,000. 17
Electric Adjustment (2.05) and Natural Gas Adjustment 18
(2.06) - FIT/DFIT/ITC/PTC Expenses, adjusts the FIT and DFIT 19
expenses calculated at 35% within Results of Operations by 20
removing the effect of certain Schedule M items, matching 21
the jurisdictional allocation of other Schedule M items to 22
related Results of Operations allocations and adjusts the 23
appropriate level of production tax credits and income tax 24
credits on qualified electric generation. 25

Andrews, Di 21
Avista Corporation
For the electric adjustment, the net FIT and production 1
tax credit adjustments increase Idaho electric NOI by 2
$188,000, while adjusting for the proper level of deferred 3
federal income tax (DFIT) expense for the test period, 4
decreases Idaho NOI by $180,000, resulting in a net NOI 5
reduction of $8,000. For the natural gas adjustment, the 6
net effect of the FIT and DFIT adjustments results in a $0 7
impact to NOI. 8
Electric Adjustment (2.06) - Idaho PCA, removes the 9
effects of the financial accounting for the Power Cost 10
Adjustment (PCA). The PCA normalizes and defers certain 11
power supply costs on an ongoing basis between general rate 12
filings. Certain differences in actual power supply costs, 13
compared to those included in base retail rates are deferred 14
and then surcharged or rebated to customers in a future 15
period. Revenue adjustments due to the PCA and the power 16
cost deferrals affect actual results of operations and need 17
to be eliminated to produce a normal period. Actual 18
revenues and power supply costs are normalized in 19
adjustments (2.09) Revenue Normalization and (3.01) Power 20
Supply, respectively. The effect of this adjustment 21
increases Idaho NOI by $2,060,000. 22
Electric Adjustment (2.07) - Nez Perce Settlement 23
Adjustment, reflects a decrease in production operating 24
expenses. An agreement was entered into between the Company 25

Andrews, Di 22
Avista Corporation
and the Nez Perce Tribe to settle certain issues regarding 1
earlier owned and operated hydroelectric generating 2
facilities of the Company. This adjustment directly assigns 3
the Nez Perce Settlement expenses to the Washington and 4
Idaho jurisdictions. This is necessary due to differing 5
regulatory treatment in Idaho Case No. WWP-E-98-11 and 6
Washington Docket No. UE-991606. The effect of this 7
adjustment increases Idaho NOI by $12,000. 8
Electric Adjustment (2.08) - Restating CS2 Levelized 9
Adjustment, adjusts the deferred return amounts related to 10
Coyote Springs 2 (CS2) to the amounts that will be recorded 11
during the rate year. In the Company's electric general 12
rate case, Case No. AVU-E-04-1, Order No. 29602, dated 13
October 8, 2004, the Commission approved the deferral of 14
return on CS2 investment in early years for recovery in 15
later years in order to levelize the revenue requirement on 16
CS2 plant investment for the first ten years of operation of 17
the plant. The ten-year period runs from September 1, 2004 18
through August 31, 2014. This adjustment restates the test 19
period amount of amortization expense, inclusive of the 20
carrying charge on the deferred return, to the amount that 21
will be recorded in the rate year. The change in deferred 22
income tax expense from the test period to the rate period 23
is also reflected. This adjustment reduces NOI by $150,000. 24

Andrews, Di 23
Avista Corporation
Electric Adjustment (2.09) and Natural Gas Adjustment 1
(2.01) - Revenue Normalization, is an adjustment taking into 2
account known and measurable changes that include 1) revenue 3
normalization (which reprices customer usage using the 4
current authorized rates, which were approved in the current 5
cases, Case Nos. AVU-E-11-01 and AVU-G-11-01, that were 6
effective October 1, 2011), 2) weather normalization, and 3) 7
an unbilled revenue calculation. For the electric 8
adjustment, Schedule 91 Tariff Rider and Schedule 59 9
Residential Exchange are excluded from pro forma revenues, 10
and the related amortization expense is eliminated as well. 11
For the natural gas adjustment, associated natural gas costs 12
are replaced with natural gas costs computed using 13
normalized volumes at the currently effective weighted-14
average-cost-of-gas, or WACOG rates in Schedule 150. 15
Revenues associated with the temporary Gas Rate Adjustment 16
Schedule 155, Schedule 191 Tariff Rider, and Schedule 199 17
Deferred SIT Adjustment are excluded from pro forma 18
revenues, and the related amortization expenses are 19
eliminated as well. Company witness Ms. Knox sponsors these 20
adjustments. The effect of this adjustment increases 21
electric NOI by $1,724,000 and natural gas NOI by $275,000. 22
Electric Adjustment (2.10) and Natural Gas Adjustment 23
(2.07) - Miscellaneous Restating Adjustment removes a number 24
of non-operating or non-utility expenses associated with 25

Andrews, Di 24
Avista Corporation
advertising, dues and donations, etc., included in error, 1
and removes or restates other expenses incorrectly charged 2
between service and or jurisdiction. The effect of this 3
adjustment increases electric NOI by $16,000 and natural gas 4
NOI by $5,000. 5
Electric Adjustment (2.11) and Natural Gas Adjustment 6
(2.08) - Restating Incentives, restates the actual employee 7
payroll incentives included in the Company‟s test period 8
using a six-year average adjusted by the Consumer Price 9
Index. 10
Q. Please briefly explain the Company’s incentive 11
plan. 12
A. Avista's current incentive plan was first 13
implemented in 2002, with a goal of focusing employees on 14
controlling O & M costs per customer by improving our 15
processes and driving efficiencies to better manage our 16
business (O & M cost per customer and capital spending) 17
while paying close attention to our customers‟ voices 18
regarding the products and services we provide. Since that 19
time, we have maintained the basic framework of the plan 20
incorporating additional measures to create a more balanced 21
approach to electric and natural gas reliability, as well as 22
continuous improvement through our Performance Excellence 23
measure. 24

Andrews, Di 25
Avista Corporation
The Employee Incentive Plan is a pay-at-risk plan 1
whereby employees are eligible to receive cash incentive pay 2
if the stated targets are achieved. The plan encourages 3
employees at all levels to focus on common objectives that 4
are designed to align the interests of all employees with 5
the interests of our customers. Establishing specific 6
targets for each element, measuring progress toward meeting 7
the targets, and paying an incentive for achieving them 8
motivates employees to focus on the key elements each year. 9
Q. How is the pay-at-risk component incorporated into 10
Avista’s total compensation package for employees? 11
A. Avista is committed to providing a total 12
compensation program that provides base salaries, 13
performance-based award programs and benefits that are 14
competitive in the marketplace. Market data shows that pay-15
at-risk or variable pay plans are prevalent in over 80% of 16
organizations, and most utilities, including Avista, have 17
some kind of pay-at-risk plan. 18
The Company views the Plan as a competitive necessity, 19
and a driver of desired behavior among employees, as well as 20
a means to achieve cost-control. For example, if the 21
existing incentive plan were to be eliminated, base salaries 22
would need to be adjusted upward in order for Avista‟s total 23
compensation to remain competitive with other utilities. 24

Andrews, Di 26
Avista Corporation
A pay-at-risk component of compensation is not designed 1
to pay out the full incentive opportunity every year, nor is 2
it designed to have no payout for an extended period of 3
time. Pay-at-risk plans are designed to help focus 4
employees on making decisions that benefit the Company and 5
its customers, while at the same time functioning as an 6
integrated component of total compensation. 7
Q. Please describe the specific targets included in 8
the Company’s 2011 incentive plan? 9
A. The targets included in the Company‟s 2011 plan 10
included: 1) an O&M Cost-Per-Customer target metric to focus 11
the business on controlling costs and driving efficiencies 12
in order to keep our costs reasonable for our customers; 2) 13
use of a Customer Satisfaction rating to track satisfaction 14
levels of customers that have had recent contact with us; 15
and 3) a reliability index measure, which combines three 16
common industry indices in order to balance our focus on 17
electric reliability. These reliability measures include: 18
the Customer Average Interruption Duration Index (CAIDI), 19
measuring the average restoration time for sustained 20
outages; the System Average Interruption Frequency Index 21
(SAIFI), which measures the average number of customers who 22
had sustained outages (>5 minutes), divided by the customers 23
served; and the Customer Experiencing Multiple Sustained 24
Interruptions (more than 3) (CEMI3), measuring the 25

Andrews, Di 27
Avista Corporation
percentage of customers that experienced more than three 1
sustained outages in the year, 4) a response time metric 2
that measures the percentage of time the Company responds 3
within targeted time goals for dispatched natural gas 4
emergency calls, and 5) a performance excellence metric 5
demonstrating the Company‟s commitment to continuously look 6
for opportunities for efficiencies in order to keep costs 7
reasonable for our customers. 8
Each of these targets are independent components to the 9
incentive plan with individual targets or measures that must 10
be achieved for a portion of the payout. The customer 11
satisfaction, reliability index, response time and 12
performance excellence measures are core objectives to our 13
business therefore; these non-financial measures are 14
designed as a “meets” or “not meets” metric, paying out only 15
if the target of “meets” is achieved. 16
The O&M cost per customer target is based on the actual 17
year end number of customers, targeted O&M expense and a 18
formula for the payout to employees, based on the level of 19
O&M savings below the target. This measure provides an 20
incentive for employees to keep actual O&M costs as low as 21
possible. Payments under this portion of the plan can range 22
from 0% to 150% depending on the level of performance 23
achieved. The formula for the payout, which was adopted in 24
2010, is structured such that as the level of savings below 25

Andrews, Di 28
Avista Corporation
the O&M target increases, the payout to employees, as a 1
percentage of the savings, is reduced. 2
Q. Please explain the use of a six-year average to 3
restate incentive expense. 4
A. Since annual Company incentive plan payouts will 5
vary year-to-year, the Company believes an average of annual 6
payouts is most appropriate in order to “normalize” these 7
costs. Often where there are revenues or expenses that can 8
vary significantly from year-to-year, the Commission has 9
approved averages to properly reflect a fair and reasonable 10
level of revenue or expense to be included in customers‟ 11
rates. Utilizing a six-year average of the Company‟s 12
incentive plan payouts is consistent with other averaging 13
methods utilized by this Commission in past proceedings. 14
For example, as shown in Illustration No. 1 below using the 15
years 2006 through 2011, one can see the large variability 16
that can occur in each year in payout, and therefore the 17
variability in customer rates if an average was not 18
utilized, and the impact of the six-year average as proposed 19
in this case: 20

Andrews, Di 29
Avista Corporation
Illustration No. 1 1
2
3
4
5
6
7
Illustration No. 1 above9, reflects the restating 8
(reduction) / increase to test period expense of ($.986) 9
million and $0.276 million (Idaho electric) for the years 10
2010 and 2011 respectively (Line No. 5). Therefore, 11
customers benefited from the $.986 million reduction to the 12
Company‟s revenue requirement in the previous GRC. To 13
exclude this six-year average in the current case, would 14
understate the expense that the Company has incurred over 15
time, preventing the Company from recovering its costs over 16
time, although customers have benefited from the O&M savings 17
that have occurred, and triggered the incentive payout. 18
Q. What are some other examples where the use of an 19
average has been used by the Company, and approved by the 20
9 The incentive amounts shown on Line No. 6 (Recovered in
Rates/Proposed) in Illustration No. 1 for columns 2009 and 2010
represent an approximate amount approved in the Company‟s prior general
rate case proceedings (Case Nos. AVU-E-10-01 and AVU-E-11-01). Due to
the black-box nature of the Company‟s prior settlements approved by the
IPUC in Case Nos. AVU-E-10-01 and AVU-E-11-01, the Company made certain
assumptions as to the incentive amounts approved in order to create the
comparison used in Illustration No. 1, and the discussion that follows.
Line
No.
1 Test Period 2006 2007 2008 2009 2010 2011
2 Rate Case AVU-E-08-01 AVU-E-09-01 AVU-E-10-01 AVU-E-11-01 Current Filing
3 System Expense 4.406$ 3.255$ 2.856$ 5.059$ 9.371$ 3.428$
4 ID - Electric Share 1.128$ 0.833$ 0.717$ 1.270$ 2.277$ 0.819$
5 Normalization Adjustment (0.986) 0.311
6 Recovered in Rates/Proposed 1.128$ 0.833$ 0.717$ 1.270$ 1.291$ 1.130$
Note:
CPI Index was removed from analysis.
Historical Incentive Plan Payout

Andrews, Di 30
Avista Corporation
Commission, to determine the appropriate level of revenue or 1
expense to include in its general rate case filings? 2
A. There are several examples of revenue or expense 3
amounts which have been averaged or normalized and approved 4
by this Commission. One example is the calculation of 5
injuries and damages expense, which includes the restating 6
adjustment described earlier in my testimony that replaces 7
the amount accrued in the test period with a six-year 8
rolling average of actual payments for injuries and damages 9
not covered by insurance. Another example is the use of a 10
five-year average for power plant availability. 11
Q. Briefly explain the reasoning behind the use of 12
the CPI to adjust the average incentive level. 13
A. Incentive compensation is based on employees 14
salary levels at the time of payout. These salary levels 15
increase over time. If one does not adjust the historical 16
years‟ expenses so that they are based on a comparable level 17
of salaries, when the calculation is computed to determine 18
the average, one is not using comparable levels of expenses 19
in order to get to an “apples to apples” comparison. 20
Q. What is the impact of the Company’s adjustment for 21
a six-year average in this case? 22
A. The Company adjusted the six-year average by the 23
CPI explained above, but also excluded all incentive target 24
payouts that are not specifically related to reliability, 25

Andrews, Di 31
Avista Corporation
customer service and operational efficiency targets, i.e., 1
the earnings per share portion of the officer incentive plan 2
are excluded from utility expenditures. The effect of this 3
adjustment decreases electric NOI by $174,000 and natural 4
gas NOI by $47,000. 5
Q. Please continue with explaining the adjustments on 6
Page 7 of Exhibit 10, Schedules 1 and 2. 7
A. The next adjustment, is Electric Adjustment (2.12) 8
– Colstrip/CS2 Maintenance. As approved in Order 32371 on 9
September 30, 2011, (in Case Nos. AVU-E-11-01 and AVU-G-11-10
01), the Company deferred the non-fuel O&M costs (the amount 11
of actual costs in excess of costs included in base rates) 12
associated with the Company's thermal generating plant and 13
is amortizing the prior year's deferred costs over a 3-year 14
period. The amortization expense (one-third of the amount 15
deferred for calendar years 2011 and 2012), increases 16
expense by approximately $1.3 million, and decreases NOI by 17
$857,000. 18
Electric Adjustment (2.13) and Natural Gas Adjustment 19
(2.09) - Restate Debt Interest, restates debt interest using 20
the Company‟s pro forma weighted average cost of debt, as 21
outlined in the testimony and exhibits of Mr. Thies, on the 22
Results of Operations level of rate base shown in column 23
(1.00) only, resulting in a revised level of tax deductible 24
interest expense on actual test period rate base. The 25

Andrews, Di 32
Avista Corporation
Federal income tax effect of the restated level of interest 1
for the test period decreases electric NOI by $191,000 and 2
natural gas NOI by $33,000. 3
The Federal income tax effect of the restated level of 4
interest on all other rate base adjustments included in the 5
Company‟s filing are included and shown as an income impact 6
of each individual rate base adjustment described elsewhere 7
in this testimony. 8
Pro Forma Adjustments 9
Q. Please explain the significance of the adjustments 10
beginning at page 8 on your Exhibit No. 10, Schedules 1 and 11
2. 12
A. The adjustments starting on page 8 are pro forma 13
adjustments that recognize the jurisdictional impacts of 14
items that will impact the pro forma operating period for 15
known and measurable changes. They encompass revenue and 16
expense items as well as additional capital projects. These 17
adjustments bring the operating results and rate base to the 18
final pro forma level for the test year. The pro forma 19
adjustments shown in columns (3.01) through (3.13), of pages 20
8 through 9 of Exhibit No. 15, Schedule 1 (electric), and 21
columns (3.01) through (3.11), of pages 8 through 9 of 22
Exhibit No. 10, Schedule 2 (natural gas) are consistent with 23
current regulatory principles and the treatment reflected in 24

Andrews, Di 33
Avista Corporation
the last rate case, with a few proposed changes by the 1
Company as described in my testimony below. 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 the adjustments follow: 7
Electric Adjustment (3.01) - Pro Forma Power Supply, 8
was made under the direction of Mr. Johnson and is explained 9
in detail in his testimony. This adjustment includes pro 10
forma power supply related revenue and expenses to reflect 11
the twelve-month period January 1, 2013 through December 31, 12
2013, using historical loads. Mr. Johnson‟s testimony 13
outlines the system level of pro forma power supply revenues 14
and expenses that are included in this adjustment. The 15
adjustment in column 3.01 calculates the Idaho 16
jurisdictional share of those figures. The net effect of 17
this adjustment increases electric NOI by $1,529,000. 18
Electric Adjustment (3.02) - Pro Forma Transmission 19
Rev/Exp, was made under the direction of Mr. Kinney and is 20
explained in detail in his testimony. This adjustment 21
includes pro forma transmission-related revenues and 22
expenses to reflect the twelve-month period January 1, 2013 23
through December 31, 2013. The net effect of this 24
adjustment increases electric NOI by $236,000. 25

Andrews, Di 34
Avista Corporation
Electric Adjustment (3.03) and Natural Gas Adjustment 1
(3.01) - Pro Forma Labor - Non-Exec, reflects known and 2
measurable changes to test period union and non-union wages 3
and salaries, excluding executive salaries. For non-union 4
employees, test period wages and salaries are restated to 5
include the March 2012 overall actual increase of 2.6%, and 6
10 months of the planned March 2013 minimum increase of 7
2.6%. This 2012 minimum increase was presented to the 8
Compensation Committee of the Board of Directors and was 9
approved at the Board‟s May 2012 meeting. 10
Also included in this adjustment are the 2012 and 2013 11
union contract increases agreed to in 2010 of 3% for both 12
years. 13
The net effect of this adjustment decreases electric 14
NOI by $499,000 and natural gas NOI by $137,000. 15
Electric Adjustment (3.04) – Pro Forma Generation Major 16
O&M, adjusts for incremental non-labor generation plant O&M 17
costs planned for 2013 above the test period. These 18
additional expenditures are mainly due to major O&M 19
expenditures planned for the Company‟s thermal generation 20
plant at Kettle Falls, and its hydro generation plants.10 21
10 Major O&M expenditures of approximately $560,000 (system) planned at
Avista‟s Kettle Falls thermal generation plant include upgrades to its
boiler feed pump and main reclaimer bull gear, as well as replacement of
its hog motor and expansion joint-turbine/condenser work. Major O&M
expenditures of approximately $3.4 million (system) are planned at
Avista‟s hydro facilities. This work includes approximately $2.1 million
at Cabinet Unit for re-wedge stator winding maintenance, discharge ring
repair, hub and oil head repair, replacement of wicket gate bushings,

Andrews, Di 35
Avista Corporation
The net effect of this adjustment decreases electric NOI by 1
$590,000. 2
Electric Adjustment (3.05) and Natural Gas Adjustment 3
(3.03)11 - Pro Forma Employee Benefits, adjusts for changes 4
in both the Company‟s pension and medical insurance expense 5
and decreases electric NOI by $883,000 and natural gas NOI 6
by $243,000. 7
Q. Please describe the pension expense portion of the 8
Employee Benefits adjustment and Idaho’s share of this 9
expense. 10
A. The Company‟s pension expense portion of this 11
adjustment is determined in accordance with Accounting 12
Standard Codification 715 (ASC-715), and has increased on a 13
system basis from approximately $23.5 million for the actual 14
test year costs for the twelve months ended June 30, 2012, 15
to $29.7 million for 2013. The increase in Idaho pension 16
expense ($885,000 electric and $242,000 natural gas) is 17
primarily due to a decrease in the discount rate used in 18
calculating the pension expense and liability as well as a 19
decrease in the expected return on assets and changes in 20
other actuarial assumptions that are not predictable. At 21

re-insulation of field windings, and rock scaling for access road
safety. Additional major maintenance include projects at Long Lake dam
of approximately $1 million for a FERC committed project to refurbish
the interior coating of the four long lake penstocks and at the Post
Falls north channel dam of approximately $300,000 for the rehabilitation
of the piers and spillway aprons. For detail descriptions of activities,
see Andrews workpapers filed with the Company‟s case. 11 Natural Gas Adjustment (3.02) intentionally left blank.

Andrews, Di 36
Avista Corporation
this time the amounts included in this case are based on the 1
most current available data. Preliminary pension expense is 2
determined by an outside actuarial firm, in accordance with 3
ASC-715, and provided to the Company late in the first 4
quarter of each year. These calculations and assumptions 5
are reviewed by the Company‟s outside accounting firm 6
annually for reasonableness and comparability to other 7
companies. 8
Q. Please now describe the medical insurance expense 9
portion of the Employee Benefits adjustment and Idaho’s 10
share of this expense. 11
A. Medical insurance expense has increased on a 12
system basis from $27.7 million for the actual test year 13
costs for the twelve months ended June 30, 2012, to $31.3 14
million for 2013. The Company‟s Idaho medical insurance and 15
post-retirement expense portion of this adjustment ($506,000 16
electric and $138,000 natural gas) adjusts for the medical-17
related costs planned for 2013 above the test period. In 18
recent years, the Company has experienced increasing ASC 715 19
expense. ASC 715 requires employers to recognize the cost of 20
providing post-retirement benefits on an accrual basis. The 21
cost must be recognized during the working years of the 22
employees to full eligibility date. Most of the increase in 23
ASC 715 expense can be explained by declining interest 24
rates, lower than expected investment returns, and greater 25

Andrews, Di 37
Avista Corporation
amortization expense due to changes in the valuation of the 1
actuarial liability. 2
The net impact of the increases in pension and medical 3
costs is an increase in Idaho electric expense of 4
approximately $1.4 million and natural gas expense of 5
$380,000. 6
Electric Adjustment (3.06) and Natural Gas Adjustment 7
(3.04) - Pro Forma Insurance, adjusts the test period 8
insurance expense for general liability, directors and 9
officers (“D&O”) liability, and property to the actual cost 10
of insurance policies that are in effect for 2012. Costs of 11
system-wide insurance policies for 2012 varied only slightly 12
from those policies in 2011. Insurance costs that are 13
properly charged to non-utility operations have been 14
excluded from this adjustment. The net effect of this 15
adjustment increases electric NOI by $8,000 and natural gas 16
NOI by $2,000. 17
Electric Adjustment (3.07) and Natural Gas Adjustment 18
(3.05) - Property Tax, restates the test period accrued 19
levels of property taxes to the 2013 rate period level using 20
the most current information. As can be seen from my 21
workpapers provided with the Company‟s filing, the property 22
on which the tax is calculated is the property value as of 23
December 31, 2012, reflecting the 2013 level of expense the 24
Company will experience during the rate period. The net 25

Andrews, Di 38
Avista Corporation
effect of this adjustment decreases electric NOI by $291,000 1
and natural gas NOI by $66,000. 2
Natural Gas Adjustment (3.06) - Pro Forma Atmospheric 3
Testing, adjusts the test period expense for Atmospheric 4
Corrosion expense to a three-year average. This expense is 5
on a three-year rotation between the Company‟s jurisdictions 6
(Idaho, Washington and Oregon) and was therefore, coded 7
directly to Idaho operations for the year in which the 8
inspection occurs (2011 for Idaho was at a total cost of 9
$390,000). The Company has included one-third of these costs 10
in order to recover over a three-year period (2011-2013), 11
and, therefore, has pro formed $130,000 for atmospheric O&M 12
expense. The Company has received approval of this 13
accounting treatment in its Oregon jurisdiction and has 14
requested this treatment in the Company‟s recent filed 15
Washington general rate case as well, so the Company remains 16
whole on an annual basis. This adjustment was made under 17
the direction of Mr. Kopczynski and is described further in 18
his testimony. The net effect of this adjustment increases 19
natural gas NOI by $77,000. 20
Electric Adjustment (3.08) and Natural Gas Adjustment 21
(3.07) – Pro Forma IS/IT Costs, adjusts for incremental 22
IS/IT costs planned for 2013 above the test period. These 23
additional expenditures are mainly due to the Company's 24
replacement of the Customer Service Information System 25

Andrews, Di 39
Avista Corporation
(CIS), incremental labor to support various business 1
processes, application support and additional security 2
requirements, as well as increases in annual contractual 3
agreements and maintenance and license fees.12 The net 4
effect of this adjustment decreases electric NOI by $224,000 5
and natural gas NOI by $47,000. 6
Electric Adjustment (3.09) and Natural Gas Adjustment 7
(3.08) - Pro Forma Capital Additions 2012, pro forms in the 8
capital cost and expenses associated with capital 9
expenditures for 2012. This adjustment includes projects 10
expected to be completed and transferred to plant-in-service 11
by December 31, 2012, and thus were normalized to reflect 12
annual amounts. The capital costs have been included for 13
the appropriate pro forma period with the associated 14
depreciation expense, as well as the appropriate accumulated 15
depreciation and deferred income tax rate base offsets. In 16
addition, the total plant in service at December 31, 2011 17
(including accumulated depreciation and deferred FIT) was 18
adjusted to an EOP December 31, 2012 adjusted balance. The 19
12 Net increases in Information System / Information Technology O&M
expenses total approximately $1.4 million system ($354,000 Idaho
electric and $74,000 Idaho natural gas). These increases include
increased expenses associated with the Company‟s Customer Service System
(CIS) project (as described further in Company witness Mr. Kopczynski‟s
testimony), due to incremental labor to support the new business
processes and application support, and increased hosting, license and
software maintenance fees. Additional increases are due to incremental
labor to support other new and existing applications and security
requirements, cost of living adjustments on existing contract
obligations, and new software purchases, licenses and maintenance fees.
For detail descriptions of incremental costs, see Andrews workpapers
filed with the Company‟s case.

Andrews, Di 40
Avista Corporation
net effect of this adjustment decreases electric NOI by 1
$1,859,000 and natural gas NOI by $442,000. The impact to 2
total rate base is an increase in electric rate base of 3
$20,705,000 and natural gas rate base of $4,449,000. 4
Electric Adjustment (3.10) and Natural Gas Adjustment 5
(3.09) - Pro Forma Capital Additions 2013, pro forms in the 6
capital cost and expenses associated with capital 7
expenditures for 2013. This adjustment includes projects 8
expected to be completed and transferred to plant-in-service 9
during 2013, and thus were included on an AMA plant basis 10
for the 2013 rate period. The capital costs have been 11
included for the appropriate pro forma period with the 12
associated depreciation expense, as well as the appropriate 13
accumulated depreciation and deferred income tax rate base 14
offsets. In addition, the total plant in service at 15
December 31, 2012 (including accumulated depreciation and 16
deferred FIT) was adjusted to a 2013 AMA plant basis. The 17
net effect of this adjustment decreases electric NOI by 18
$589,000 and natural gas NOI by $124,000. The impact to 19
total rate base is an increase in electric rate base of 20
$1,582,000 and a reduction to natural gas rate base of 21
$1,309,000. 22
Electric Adjustment (3.11) - Pro Forma Energy 23
Efficiency Load Adjustment (EELA), reflects the reduction in 24
retail revenues due to energy efficiency programs, the 25

Andrews, Di 41
Avista Corporation
resulting savings in power supply expense, and includes the 1
change in all other revenue related expenses and taxes 2
associated with this adjustment, as described in detail by 3
Mr. Ehrbar. The net effect of this adjustment decreases 4
electric NOI by $1,034,000. 5
Electric Adjustment (3.12) and Natural Gas Adjustment 6
(3.10) - Operation & Maintenance (O&M) Offsets, includes a 7
reduction to expense for anticipated operation and 8
maintenance savings expected during the pro forma period, as 9
compared to the test period. These O&M savings include 10
reductions related to certain additional generation, 11
transmission, distribution and general plant investment 12
included in the 2011, 2012 and 2013 capital addition 13
adjustments. The savings related to capital projects have 14
been discussed further within Mr. Lafferty‟s (generation 15
projects), Mr. Kinney‟s (distribution and transmission 16
projects), and Mr. DeFelice„s (general plant) direct 17
testimony. Additional detail can be found within my 18
workpapers included with the Company‟s filing. The net 19
effect of this adjustment increases electric NOI by $72,000 20
and natural gas NOI by $4,000. 21
Electric Adjustment (3.13) and Natural Gas Adjustment 22
(3.11) – Depreciation Study, as described in detail by Mr. 23
DeFelice, reflects an increase in depreciation expense due 24
to the utilization of new depreciation rates that were the 25

Andrews, Di 42
Avista Corporation
result of a detailed depreciation study performed by a 1
consultant from Gannett Fleming, Inc. The Company last 2
changed its depreciation rates on January 1, 2008. The net 3
effect of this adjustment decreases electric NOI by $300,000 4
and natural gas NOI by $306,000. 5
6
Summary 7
Q. How much additional net operating income would be 8
required for the State of Idaho electric operations to allow 9
the Company an opportunity to earn its proposed 8.46% rate 10
of return on a pro forma basis? 11
A. The net operating income deficiency amounts to 12
$7,259,000, as shown on line 5, page 2 of Exhibit No. 10, 13
Schedule 1. The resulting revenue requirement is shown on 14
line 7 and amounts to $11,393,000, or an increase of 4.58% 15
over pro forma general business revenues. 16
Q. How much additional net operating income would be 17
required for the State of Idaho natural gas operations to 18
allow the Company an opportunity to earn its proposed 8.46% 19
rate of return on a pro forma basis? 20
A. The net operating income deficiency amounts to 21
$2,906,000, as shown on line 5, page 2 of Exhibit No. 10, 22
Schedule 2. The resulting revenue requirement is shown on 23
line 7 and amounts to $4,561,000, or an increase of 7.20% 24
over pro forma general business and transportation revenues. 25

Andrews, Di 43
Avista Corporation
IV. ALLOCATION PROCEDURES 1
Q. Have there been any changes to the Company’s 2
system and jurisdictional procedures since the Company’s 3
last general electric and natural gas cases, Case Nos. AVU-4
E-11-01 and AVU-G-11-01? 5
A. No. For ratemaking purposes, the Company 6
allocates revenues, expenses and rate base between electric 7
and natural gas services and between Idaho, Washington and 8
Oregon jurisdictions where electric and/or natural gas 9
service is provided. The annually updated allocation 10
factors used in this case have been provided with my 11
workpapers. 12
Q. Does that conclude your pre-filed direct 13
testimony? 14
A. Yes, it does. 15