20130318Volume III.pdf

ORIGINAL
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION DBA AVISTA ) CASE NO. AVU-E-12-08
UTILITIES FOR AUTHORITY TO ) CASE NO. AVU-G-12-07
INCREASE ITS RATES AND CHARGES FOR ) :•
ELECTRIC AND NATURAL GAS SERVICE )
IN IDAHO )
ID 00
co m
- ;
-
BEFORE
COMMISSIONER PAUL KJELLANDER (Presiding)
COMMISSIONER MARSHA SMITH
COMMISSIONER MACK REDFORD
PLACE: Commission Hearing Room
472 West Washington Street
Boise, Idaho
DATE: March 7, 2013
VOLUME III - Pages 22 - 114
CSB REPORTING
Constance S. Bucy, CSR No. 187
23876 Applewood Way * Wilder, Idaho 83676
[phone]
Email csbheritagewifi.com
7-
0
For Clearwater Paper: RICHARDSON & O'LEARY
by Peter J. Richardson, Esq.
515 North 27th Street
Boise, Idaho 83702
For Idaho Forest Group: McDEVITT & MILLER
by Dean J. Miller, Esq.
420 West Bannock Street
Boise, Idaho 83702
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1 APPEARANCES
2

3 For the Staff: Karl Klein, Esq.
Deputy Attorney General
4 472 West Washington Street
Boise, Idaho 83720-0074
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6 For Avista Corporation: David J. Meyer, Esq.
Vice President & Chief Counsel

7 Avista Corporation
Post Office Box 3727

8 Spokane Washington 99220
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For CAPAI: Brady M. Purdy, Esq.

16 Attorney at Law
2019 North 17th Street

17 Boise, Idaho 83702
Benjamin J. Otto, Esq.
Idaho Conservation League
Post Office Box 844
Boise, Idaho 83701
Mr. Ken Miller
Snake River Alliance
Post Office Box 1731
Boise, Idaho 83701
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For Idaho Conservation
League:
For Snake River
Alliance:
CSB REPORTING APPEARANCES
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WITNESS EXAMINATION BY PAGE
Kelly 0. Norwood Mr. Meyer (Direct) 24
(Avista Corp.) Prefiled Direct Testimony 27
Commissioner Smith 70
Commissioner Kjellander 72
Randy Lobb Mr. Klein (Direct) 75
(Staff) Prefiled Direct Testimony 77
Commissioner Smith 110
CSB REPORTING INDEX
[phone]
EXH I B ITS
NUMBER DESCRIPTION
FOR AVISTA CORPORATION:
1. Stipulation and Settlement Premarked
Admitted
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FOR THE STAFF:
101. Stipulation and Settlement Premarked
Admitted
CSB REPORTING INDEX
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1 BOISE, IDAHO, THURSDAY, MARCH 7, 2013, 9:30 A. M.
2
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4 COMMISSIONER KJELLANDER: Well, good
5 morning. This is the time and place set for a technical

6 hearing in Case Nos. AVU-E-12-08 and AVU-G-12-07. It's

7 in direct reference to a settlement and stipulation

8 that's been filed that attempts to fully resolve the

9 cases that are before us today. My name is Paul

10 Kjellander. I'm the Chairman of today's proceedings. To
11 my right is Commissioner Mack Redford. To my left is

12 Commissioner Marsha Smith. We comprise the Commission

13 and we will ultimately render a final decision based on

14 our deliberations in relationship to these cases and

15 these proceedings today.

16 Let's begin with the appearances of the

17 parties and let's start with Avista.

18 MR. MEYER: Thank you. David Meyer

19 appearing on behalf of Avista.

20 COMMISSIONER KJELLANDER: Good morning and

21 welcome. Commission Staff.

22 MR. KLEIN: Thank you. Karl Klein on

23 behalf of the Commission Staff.

24 COMMISSIONER KJELLANDER: Idaho Forest

.

25 Group, LLC.
CSB REPORTING 22 COLLOQUY
(208)' 890-5198
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1 MR. MILLER: Thank you, Mr. Chairman.
2 Dean J. Miller of the firm McDevitt & Miller on behalf of

3 Idaho Forest Group, and also with me is Mr. Larry
4 Crowley.

5 COMMISSIONER KJELLANDER: Good morning and

6 welcome. Clearwater Paper Corporation.

7 MR. RICHARDSON: Good morning,

8 Mr. President. Peter Richardson on behalf of Clearwater

9 Paper Corporation, and just with the indulgence of the

10 Commission, I will have to leave early today if that's

11 all right with the Commission.

12 COMMISSIONER KJELLANDER: We appreciate

.

13 that and hopefully, we will be able to move through this

14 quickly so you can attend the entire session.

15 MR. RICHARDSON: Thank you. Clearwater
16 did execute the stipulation and has no questions for

17 either witness.

18 COMMISSIONER KJELLANDER: We appreciate

19 that and thank you. Idaho Conservation League.

20 MR. OTTO: Good morning. Ben Otto with

21 the Idaho Conservation League.

22 COMMISSIONER KJELLANDER: Good morning,
23 and Community Action Partnership.

24 MR. PURDY: Yes, Brad Purdy on behalf of

25 the Community Action Partnership Association of Idaho.
CSB REPORTING 23 COLLOQUY
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COMMISSIONER KJELLANDER: Good morning,
Brad, and the Snake River Alliance.
MR. MILLER: Good morning, Mr. President.
Ken Miller with the Snake River Alliance.
COMMISSIONER KJELLANDER: Good to see you
and welcome. Are there any other parties that we've
missed for purposes of identification in the record? If
not, let's see if there any initial items that need to
come before the Commission.
Hearing none, then I think we're ready to
start with the first witness and let's begin with Avista.
KELLY 0. NORWOOD,
produced as a witness at the instance of the Avista
Corporation, having been first duly sworn, was examined
and testified as follows:
DIRECT EXAMINATION
BY MR. MEYER:
Q Mr. Norwood, for the record, please state
your name and your employer.
A Yes, Kelly Norwood. I work for Avista
Corporation.
Q And what is your title?
CSB REPORTING 24 NORWOOD (Di)
[phone] Avista Corporation
S 1 A Vice president of state and federal
2 regulation.

3
Q And have you prepared direct testimony in
4 support of the stipulation and settlement?

5 A Yes, I have.

6
Q Do you have any changes or corrections to

7 make to that?

8 A We just had one corrected page that was
9 previously filed with the Commission. It was Attachment

10 B to the stipulation which is Exhibit 1 to my

11 testimony.

12 MR. MEYER: May I inquire, did that get
.

13 distributed to members of the Bench, Mr. Chairman? That

14 revised attachment, did that make its way into your

15 files?

16 COMMISSIONER KJELLANDER: It certainly

17 did. Thanks for asking.

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Q BY MR. MEYER: With that, if I were to ask

19 you the questions in your testimony, would your answers

20 be the same?

21 A They would.

22 MR. MEYER: I would ask that Mr. Norwood's

23 testimony be entered into the record as if read.

24 COMMISSIONER KJELLANDER: And without
.

25 objection, we will spread that across the record as if
CSB REPORTING 25 NORWOOD (Di)
[phone] Avista Corporation
.

1 read.
2 MR. MEYER: Thank you, and he has Exhibit

3 No. 1 and I can offer that now if you'd like or wait,

4 whatever your preference.

5 COMMISSIONER KJELLANDER: It's your

6 pleasure.

7 MR. MEYER: I offer that now, please.

8 COMMISSIONER KJELLANDER: Then without any

9 kind of objection to the exhibit being entered into the

10 record, it is.

11 MR. MEYER: Thank you.

12 (Avista Corporation Exhibit No. 1 was
S
13 admitted into evidence.)

14 (The following prefiled testimony of

15 Mr. Kelly Norwood is spread upon the record.)
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CSB REPORTING 26 NORWOOD (Di)
[phone] Avista Corporation
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I. INTRODUCTION
Q. Please state your name, employer and
business address.
A. My name is Kelly 0. Norwood and I am
employed as the Vice-President of State and Federal
Regulation for Avista Utilities ("Company" or "Avista"),
at 1411 East Mission Avenue, Spokane, Washington.
Q. Would you briefly describe your
educational background and professional experience?
A. Yes. I am a graduate of Eastern
Washington University with a Bachelor of Arts Degree in
Business Administration, majoring in Accounting. I
joined the Company in June of 1981. Over the past 31
years, I have spent approximately 20 years in the Rates
Department with involvement in cost of service, rate
design, revenue requirements and other aspects of
ratemaking. I spent approximately 11 years in the Energy
Resources Department (power supply and natural gas
supply) in a variety of roles, with involvement in
resource planning, system operations, resource analysis,
negotiation of power contracts, and risk management. I
was appointed Vice-President of State & Federal
Regulation in March 2002.
27 Norwood, Di 1
Avista Corporation
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Q. What is the scope of your pre-filed
testimony in this proceeding?
A. The purpose of my testimony is to
describe and support the Stipulation and Settlement
("Stipulation"), filed on February 6, 2013 between the
Staff of the Idaho Public Utilities Commission ("Staff'),
Clearwater Paper Corporation ("Clearwater"), Idaho Forest
Group, LLC ("Idaho Forest"), the Idaho Conservation
League ("Conservation League"), and the Company, which,
if approved by the Commission, would resolve all of the
issues in the Company's filing. These entities are
collectively referred to as the "Parties," and represent
several parties in the above-referenced cases.'
The Stipulation is the product of
January 17 and 24, 2013. The Stipulation between the
Parties resolved all issues associated with the
calculation of the Company's requested cost of capital,
including capital structure and
-- The Community Action Partnership Association of Idaho ("CAPAI")
participated in settlement discussions and is continuing to review
its position with regard to the Stipulation, as proposed, and will be
filing separate comments and/or testimony in that regard. The Snake
River Alliance, as an intervenor, was provided notice of the
settlement discussions, but did not participate. However, on
February 20, 2013, The Snake River Alliance, through separate
communication filed notice with the Commission indicating that,
although not a signatory to the Settlement agreement, they do support
the Stipulation agreed to by the Parties.
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cost components, and resolved all revenue requirement,
rate spread and rate design issues.
The Stipulation represents a compromise
among differing points of view. Concessions were made by
all Parties to reach a balancing of interests. As will
be explained in the following testimony, the Stipulation
represents a fair, just and reasonable compromise of the
issues and is in the public interest.
Q. Are you sponsoring any exhibits?
A. Yes. I am sponsoring Exhibit No. 1,
which is a copy of the Stipulation and Settlement filed
on February 6, 2013, with the Commission.
Q. Please explain how the Parties
arrived at the Stipulation in this proceeding.
A. The Stipulation is the end result of
extensive audit work conducted through the discovery
process 2 , including a week-long on-site audit by
Commission Staff, and hard bargaining by all Parties in
this proceeding. I would like to express my appreciation
to all Parties involved in this proceeding for their
efforts in arriving at this Stipulation and to this
Commission for your
2 For its part, Avista responded to over 270 production requests
(including sub-parts) from IFUC Staff and other intervening parties.
29 Norwood, Di 3
Avista Corporation
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1 willingness to hear this matter promptly, in light of the
proposed April 1 effective date.
Q. Why is the Stipulation in the public
A. The Stipulation is in the "public
interest" for several reasons, which include:
It was the product of the
give-and-take of negotiation that produced an "end
result" th is just and reasonable.
It is supported by the evidence,
demonstrating the need for rate adjustments to
provide recovery of necessary expenditures and
investment, the costs of which are not offset by a
growth in Les margins.
The Settlement enjoys broad-based
support from a variety of constituencies, including
Clearwater, Idaho Forest, the Conservation League,
and the Snake River Alliance, serving to address
their specific needs, and the Staff of the
Commission presenting all customers.
The Settlement provides base rate
certainty over the next two years (2013/2014), which
would benefit all customers, as they plan and budget
for theirds.
It would prohibit Avista from making
further changes in base rates prior to January 1,
2015, thereby breaking the yearly cycle of rate
filings.
The impact of the base rate increases
in Step 2, effective October 1, 2013, would be
mitigated, in part, by the amortization of the BPA
settlement payment for electric and the PGA deferral
credit bal e for natural gas.
The "stay-out" provision preventing a
further change in base rates until 2015 would
challenge Avista to manage its costs in order to
have the opportunity to earn the agreed-upon return
on equity; indeed, the Company has already put in
place cost saving measures, such as the voluntary
severance program reducing Avista's work force by 55
individual • executed at year-end 2012.
Finally, as I will discuss later in
my testimony, in order to allay any concerns that
Avista might somehow "over-earn" during the
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30 Norwood, Di 4
Avista Corporation
2013/2014 rate-effective period, Avista would agree
to refund back to customers 50% of any earnings that
exceed the 9.8% agreed-upon ROE during the 2013 and
2014 rate-effective periods, based on actual,
consolidated results for its Idaho electric and
natural gas operations.
Q. Would you briefly summarize the
Stipulation?
A. Yes. Under the terms of the
Stipulation, Avista would implement revised tariff
schedules designed to recover additional annual electric
and natural gas revenue in two steps, effective April 1
and October 1, 2013. This represents a two-year rate
plan for the period 2013 and 2014, designed to provide
retail revenues necessary to allow the Company the
opportunity to earn the return agreed to in the
Stipulation.
For electric operations, there is no
electric base rate increase in the first step (April 1,
2013), however, effective October 1, 2013 (Step 2), the
Parties agree to an overall base rate increase of 3.1%
(3.2% on a billed basis) or $7.825 million in electric
annual base tariff revenues. Partially offsetting the
October 1, 2013 electric increase is $3.865 million of
revenues resulting from a payment to be made to Avista by
the Bonneville Power Administration (BPA)3 . This payment
to Avista is for the Parallel Operation
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3 The agreement between Avista and BPA was approved by FERC on
February 5, 2013.
32 Norwood, Di 5a
Avista Corporation
Settlement agreement, pertaining to BPA's prior use of
Avista's transmission system (discussed later in my
testimony), and amortized over 15 months, from October 1,
2013 to December 31, 2014, resulting in a decrease to
billed customer rates of 1.3%. As a result of the two
October 1, 2013 adjustments, the overall net increase on
a billed basis is 1.9%. A residential customer using an
average of 930 kilowatt hours per month would see a
$2.04, or 2.6%, increase per month for a revised monthly
bill of $80.73. (See Exhibit No. 1, Paragraph 21, for the
October 1, 2013 percentage change in rates by rate
schedule.)
The table below summarizes the April 1 and
October 1, 2013 electric rate changes:
Swninaiy of Electric Rate Changes (ions)
Revenue Base Rate Billing Rate Net Bilg
Reqiñreiient Change Change Ofet Rate Change
April 1, 2013 $0.00 0.0% 0.0% 0.00/0. 0.0%
October 1, 2013 $7.825 3.1% 3.2% -1.3% 1.9%
For natural gas, under Step 1, effective
April 1, 2013, Avista would implement revised tariff
schedules designed to recover $3.115 million in
additional annual natural. gas revenue, representing an
overall 4.9% (5.0% on a billed basis) increase. As a
result of the April 1, 2013 rate adjustment, a
residential customer using an average of 60
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33 Norwood, Di 6
Avista Corporation
C 1 therms per month would see a $2.82, or 5.4%, increase per
2 month for a revised monthly bill of $55.37.

3 Under Step 2, effective October 1, 2013,
4 Avista would implement revised tariff schedules designed

5 to recover an additional $1.330 million in annual natural

6 gas revenue, representing an overall 2.0% increase (on

7 both a base and billed basis) . Partially offsetting the

8 natural gas rate increase would be a $1.550 million

9 Purchase Gas Adjustment (PGA) deferral credit balance

10 from the 2012 PGA. This credit would be amortized over

11 15 months, October 1, 2013 to December 31, 2014,

12 resulting in a decrease to billed customer rates of 1.7%.

.

13 The result of the two October 1, 2013 adjustments is an

14 overall net increase on a billed basis of 0.3%. A

15 residential customer using an average of 60 therms per

16 month would see a $0.31, or 0.6%, increase per month for

17 a revised monthly bill of $55.68. Other customer classes,

18 except transportation customers, would see an overall net

19 rate decrease October 1, 2013. (See Exhibit No. 1,

20 Paragraph 22, for the April 1 and October 1, 2013 change

21 in rates by rate schedule.)
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34 Norwood, Di 7
Avista Corporation
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The table below summarizes the April 1 and October 1,
2013 proposed natural gas rate changes:
Swnniaiy of Natural Gas Rate Changes (millions)
Revenue Base Rate Billing Rate Net Billing
Reqi.ñrexuent Change Change Offset Rate Change
Apr11 1, 2013 $3.115 4.9% 5.0% 0.00/0 5.0%
October 1, 2013 $1.330 2.0% 2.00/a -1.7% 0.3%
Avista would not file another electric or
natural gas general rate case before May 31, 2014, and
while it may request an effective date earlier than
January 1, 2015, final approved new rates would not go
into effect prior to January 1, 2015. This does not
apply to tariff filings authorized by or contemplated by
the terms of the Power Cost Adjustment (PCA), or the
Purchased Gas Adjustment tariff (PGA), or other
miscellaneous filings.
In determining these revenue increases,
the Parties have agreed to various adjustments to the
Company's original filing, which are summarized in the
Stipulation, and described further below.
The Stipulation calls for an overall rate
of return of 7.91%, determined using a capital structure
consisting of 50% common stock equity and 50% long-term
debt, an authorized return on equity of 9.8% and cost of
debt of 6.01%.
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35 Norwood, Di 8
Avista Corporation

in II. HISTORY OF FILING

2 Q. Please describe the Company's general

3 rate case request, as filed.

4 A. On October 11, 2012, Avista filed an
5 Application with the Commission for authority to increase

6 revenue from electric and natural gas service in Idaho by
11 4.6% and 7.2%, respectively. If approved, the Company's

8 revenues for electric base retail rates would have

9 increased by $11.4 million annually; Company revenues for

10 natural gas service would have increased by $4.6 million

11 annually. The Company requested an effective date of

12 April 1, 2013 for its proposed electric and natural gas
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13 rate increases. By Order No. 32689, dated December 4,

14 2012, the Commission suspended the proposed schedules of

15 rates and charges for electric and natural gas service.

16 The Company proposed utilizing the results

17 of its electric and natural gas service studies,

18 sponsored by Company witness Knox, as a guide to spread

19 the overall requested electric and natural gas revenue

20 increases by rate schedule on a basis which: 1) moved the

21 rates for nearly all the schedules closer to the cost of

22 providing service, and 2) resulted in a reasonable range

23 in the (net) proposed percentage increase across the

24 schedules. The spread of the proposed electric increase

25 generally resulted in the rates
36 Norwood, Di 9
Avista Corporation

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1 of return for the various electric service schedules
2 moving approximately 15% closer to the overall rate of

3 return (unity); whereas the proposed increases for the
4 various natural gas service schedules would move the

5 return approximately 25% closer to the overall rate of

6 return (unity). The Company did not request a change in

7 its electric or natural gas residential basic charges.

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Q. What are the primary factors driving

9 the Company's need for electric and natural gas

10 increases?

11 A. Approximately 70% of the Company's

12 electric revenue requirement, and 48% for natural gas, is

13 due to an increase in net plant investment (including
II return on investment, depreciation and taxes, and offset

15 by the tax benefit of interest)

16 The remaining revenue requirement request

17 is due to increases in distribution, operation and

18 maintenance (O&M), and administrative and general (A&G)

19 expenses for both electric and natural gas operations.

20 However, the increased costs for electric operations are
21 partially offset by a reduction in net power supply and

22 transmission expenditures.
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37 Norwood, Di 10
Avista Corporation

1 III. REVENUE REQUIREMENT ELEMENTS OF THE STIPULATION
2
Q. Please explain the derivation of the
3 Electric and Natural Gas Revenue Requirements outlined in
4 the Stipulation.

5 A. The Parties agreed that Avista would

6 implement revised tariff schedules designed to recover

7 additional annual electric and natural gas revenue in two

8 steps, effective April 1 and October 1, 2013. This

9 represents a two-year rate plan designed to provide

10 sufficient retail revenues for the period 2013 and 2014,
11 which together with management of costs, would provide
12 the Company with the opportunity to earn the return

.

13 agreed to in the Stipulation.

14 While Avista's filing requested an

15 electric revenue requirement increase of $11.393 million

16 effective April 1, 2013, agreed-upon adjustments,

17 including the agreed-upon rate of return, result in a

18 recommended electric revenue requirement increase of $0.0

19 as of April 1, 2013 and $7.825 million as of October 1,

20 2013.

21 Similarly, while the Company requested a

22 natural gas revenue requirement increase of $4.561

23 million effective April 1, 2013, agreed-upon adjustments

24 result in a recommended natural gas revenue requirement
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25 increase of $3.115 million as of April 1, 2013 and $1.330
million as of October 1, 2013.
38 Norwood, Di 11
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1 Q. Please explain the Parties' agreement
2 with regard to an Authorized Rate of Return, including

3 the Return on Equity.
4 A. The Parties have agreed to a revenue

5 requirement which produces an overall rate of return of

6 7.91%, based on a return on equity of 9.8%, an equity

7 component at 50% and cost of debt of 6.01%. By

8 comparison, the Company's original filing requested an

9 overall rate of return of 8.46%, a return on equity of

10 10.9%, an equity component of 50% and cost of debt of

11 6.02%.

12 Q. What is the proposed effective date

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13 of new rates from the Stipulation?

14 A. The Parties have requested

15 implementation of new retail rates from the Stipulation

16 on April 1, 2013, with further tariff changes on October

17 1, 2013. These proposed effective dates are an integral

18 part of the Stipulation that includes a negotiated

19 resolution of all of the issues.

20 Q. Please provide an overview of the

21 revenue requirement adjustments agreed to by the Parties

22 resulting in the April 1 and October 1, 2013 revenue

23 requirements.

24 A. A number of the adjustments, agreed

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25 to by the Parties, resulted in delaying recovery of 2013
39 Norwood, Di 12
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expenditures to the agreed-upon levels by the Parties.
The Parties agreed to revenue requirements that reflect
the adjustments shown below in the excerpted tables from
the Stipulation:
Table 1: April 1, 2013 Electric Revenue Requirement
SUMMARY TABLE OF ADJUSTMENTS TO ELECTRIC REVENUE REQUIREMENT
EFFECTIVE APRIL 1, 2013
000s of Dollars
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Revenue
Requirement Rate Base
Amount as Filed: $ 11,393 $ 639,030
Adjustments:
Cost of Capital S (5,517)
Remove 2013 Capital Additions (Delay to October 1, 2013) $ (1,117) $ (1,582
Remove 2013 Expenses: Delay Recovery to October 1, 2013 Rate Change
Major Generation O&M $ (926)
ii.Information Services & Technology $ (318)
iii.CS2 Levelized Return $ (38)
iv.Non-Exec Labor $ (426)
Remove 2013 Property Tax Expense $ (428)
Remove Officer Incentive and CPI escalation $ (187)
Two-Year Amortization of Reardan $ 878
Include Palouse Wind in PCA until in base rates in 2015 (900/o/100/o sharing) $ (3,139)
Miscellaneouse Adjustments: Two-Year Amortization of Booz Consulting
costs, Oasis Training Abandoned Projects & Depreciation Study expense $ (175)
Adjusted Amounts Effective April 1, 2013 $ - $ 637,448
41 Norwood, Di 13
Avista Corporation
Table 2: October 1, 2013 Electric Revenue Requirement
Amount as Filed:
Adjustments:
a.)Cost of Capital
b.)Remove 2013 Capital Addkiois (Delay to October 1, 2013)
c.)Remove 2013 Expenses: Dely Recovery to October 1, 2013 Rate Chang
1. Information Services & Tchnology
0. Non-Exec Labor
d.)Remove 2013 Property Tax Expense
e.)Remove Officer Incentive an 11 CPI escalation
L) MisceiJaneouse Adustments4Two-Year Amortization of Booz Consulting
costs, Injuries & Damages, Abandoned Projects & Depreciation Study
expense
Adjusted Amounts Ecti'e April 1, 2013
Amounts Effective April 1, 2013
Adjustments to October 1, 2013 Rate Change:
2013 Capital Additions
2014 Capital Additions
Add 2013 Expenses
L Major Generation O&M
iL Information Services & Technology
HL CS2 Levelized Return
iv. Non-Exec Labor
Adjusted Amounts Effective October 1, 2013
SUMMARY TABLE OF ELECTRIC REVENUE REQUIREMENT
EFFECTIVE OCTOBER 1, 2013
000s of Dollars
Revenue
Requirement Rate Base
$ - $ 637,448
$ 5,488 $ 20,705
$ 629 $ 888
$ 926
$ 318
$ 38
$ 426
$ 7,825 $ 659,041
Revenue
Requirement Rate Base
$ 4,561 $ 110,930
$ (957)
$ (22) $ 1,309
$ (42)
$ (215)
$ (84)
$ (50)
$ (76)
$ 3,115
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
2C
21
22
2
2
2
Table3:April1,2013NaturalGasRevenueRequirement
SUMMARY TABLE OF ADJUSTMENTS TO NATURAL GAS REVENUE REQUIREMENT
EFFECTIVE APRIL 1, 2013
000s of Dollars
42 Norwood, Di 14
Avista Corporation
2
3
4
5
6
7
8
9
10
11
12 •
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16
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23
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• 25
Table 4: October 1, 2013. Natural Gas Revenue Requirement
SUMMARY TABLE OF ADJUSTMENTS TO NATURAL GAS REVENUE REQUIREMENT
EFFECTIVE OCTOBER 1, 2013
000s of Dollars
Revenue
Requirement Rate Base
Amounts Effective April 1, 2013 $ - $ 112,239
Adjustments to October 1, 2013 Rate Change:
2013 Capital Additions $ 1,073 $ 3,831
Add 2013 Expenses
L Information Services & Technology $ 42
L Non-Exec Labor $ 215
Adjusted Amounts Effective October 1, 2013 $1,330 $116,070 -
As can be seen by a quick review of the
individual line descriptions provided within the summary
tables excerpted from the Stipulation, the adjustments
accepted for settlement purposes cover a broad range of
revenue and cost categories, including the authorized
rate of return. The individual adjustments should not be
viewed in isolation; rather, they should be viewed in
total as part of the entire Stipulation, and are the
result of hard bargaining and compromise.
Q. Would you please elaborate on the
individual line items contained within the excerpted
tables?
A. Yes. A description of these
adjustments resulting in the Step 1 revenue requirement,
effective April 1, 2013 and the Step 2 revenue
requirement, effective October 1, 2013, follows.
43 Norwood, Di 15
Avista Corporation
.
1
2
Step 1: April 1, 2013 Rate
Gas $3.115 million:
Electric $0.0; Natural
3 Remove 2013 Capital additions - (Table 1, Line b.
4 and Table 3, Line b.) The 2013 electric and natural gas
5 capital additions adjustments, as proposed by the Company
6 in its original filings, were removed, delaying recovery
7 of the associated revenue requirement until the October
8 1, 2013 rate increase. April 1, 2013, therefore,
reflected total depreciation expenses and rate base, net
10 of accumulated depreciation and accumulated deferred
11 income tax, as of year-end December 31, 2012.
12 Remove 2013 Expenses - (Table 1, Line c. and Table
fl
13 3, Line c.) The following adjustments remove 2013
14 expenses pro formed in the Company's original filing,
15 delaying recovery of those expenditures until the October
16 1, 2013 rate change:
17 Major Generation O&M - (Table 1, Line c.i.)
18 2013 incremental non-labor generation plant
19 operation and maintenance (O&M) expenses related to
20 the Company's thermal generation plant at Kettle
21 Falls, and its hydro generation plants (electric
22 only).
23 Information Services & Technology - (Table 1,
24 Line c.ii. and Table 3, Line c.i.) 2013 incremental
.

25 information service and technology expenses, related
44 Norwood, Di 16
Avista Corporation
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to the Company's replacement of the Company's
Customer
45 Norwood, Di 16a
Avista Corporation
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1 Service Information System, and increased costs to
2 support various business processes, application

3 support, additional security requirements, annual

4 contractual agreements and maintenance and license

5 fees.

6 CS2 Levelized Return - (Table 1, Line c.iii.)

7 2013 incremental amortization of the deferred

8 levelized return related to the 10-year deferral of

9 return on the Coyote Springs 2 (CS2)

10 investment (electric only)

11 Non-Exec Labor - (Table 1, Line c.iv. and Table

12 3, Line c.ii.) 2013 incremental non-executive labor
.

13 increases, includes increases approved by the Board

14 of Directors for 2013 for its non-union,

15 non-executive employees, as well as the 2013 union

16 contract increases for union employees.

17 Remove 2013 Property Tax Expense - (Table 1,

18 Line d. and Table 3, Line d.) This adjustment removes

19 the 2013 incremental pro forma property tax expense. In

20 its original filing, the Company adjusted test period

21 accrued property tax expense to the expected 2013 rate
22 period expense level based on property values as of

23 December 31, 2012. This adjustment reduces recovery of

24 property tax to 2012 expense levels.
.

25
46 Norwood, Di 17
Avista Corporation
Q
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Remove Officer Incentive and CPI Escalation - (Table
1, Line e. and Table 3, Line e.) This adjustment removes
the officer portion of the employee incentive expense
included in the Company's original filing. Included in
the Company's original filing was a six-year average
(2006-2011) of actual incentive expense adjusted by the
Consumer Price Index (CPI) . This adjustment in the
Settlement also removes the CPI escalation.
Miscellaneous Adjustments - (Table 1, Line h. and
Table 3, Line f.) The Company adopted, for settlement
purposes, Staff's proposal to adjust or remove various
administrative and general (A&G) and O&M-related costs,,
including a two-year amortization of Booz & Co.
consulting fees, thereby reducing test period expenses,
as well as removal of certain other amounts related to
OASIS 4 training, abandoned projects, injuries and damages
(natural gas only) and depreciation study expenses.
Reardan Wind Site - (Table 1, Line f.) In May 2008,
Avista purchased the Reardan Wind Project Site from
Energy Northwest after it was demonstrated as the
Company's least-cost option for securing a renewable
resource for its customers, consistent with its 2007
Integrated Resource
Open Access Same-Time Information Systems (OASIS)
47 Norwood, Di 18
Avista Corporation

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1 Plan. Avista later chose to delay the construction of
2 the Reardan project and take advantage of much-lower

3 costs for wind projects that emerged in 2011 (Palouse
4 Wind). Avista recorded $4.0 million of site acquisition

5 and preparation costs, of which approximately $1.7
6 million is Idaho's share. This includes approximately

7 $0.4 million in AFUDC in accordance with Order No. 30611

8 (Case No. AVU-E-08--04). As a part of the agreed-upon

9 Settlement, Avista would amortize Idaho's portion of the

10 Reardan Wind Project deferred balance of approximately

11 $1.7 million over a two-year period beginning April 1,

12 2013.
.

13 Palouse Wind - (Table 1, Line g.) The Parties agree

14 that recovery of costs related to the Palouse Wind Power

15 Purchase Agreement ("PPA") would be included in the PCA,

16 subject to the current sharing (90% customer, 10%

17 Company) until it is included in base rates as part of

18 the implementation of new rates from the Company's next

19 general rate case, anticipated in 2015. This adjustment
20 removes the Palouse Wind PPA expenses from the pro forma
21 power supply adjustment included in the Company's

22 original filing.

23 Q. Please summarize the impact of these

24 adjustments on Step 1, effective April 1, 2013.
C
25 A. Consolidation of the adjustments
discussed above
48 Norwood, Di 19
Avista Corporation
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1 for the Step 1 base rate change, effective April 1, 2013,
2 reduces Avista's electric revenue requirement request of

3 $11.393 million to $0.0, and its natural gas revenue

4 requirement request of $4.561 million to $3.115 million,

5 resulting in a 0.0% electric and 3.1% natural gas base

6 rate increase. Net rate base for electric and natural

7 gas is $637.45 million and $112.24 million, respectively,

8 effective April 1, 2013.

9
Q. Please continue your explanation of
10 the revenue requirement adjustments agreed to by the

11 Parties resulting in the electric and natural gas Step 2,

12 October 1, 2013, rate changes.

13 A. As discussed above, a number of

14 capital and expense related adjustments proposed in the

15 Company's original filing were removed from the electric
16 and natural gas revenue requirements for purposes of the

17 Step 1, rate changes effective April 1, 2013, delaying

18 the recovery of those incremental 2013 increased costs to

19 the Step 2, October 1, 2013 rate changes. A description

20 of these adjustments resulting in the Step 2 increases,

21 effective October 1, 2013, follows.
22
23
24
25
49 Norwood, Di 20
Avista Corporation
E
1 Step 2: October 1, 2013 Rate Changes: Electric $7.825
2 million; Natural Gas $1330 million:

CI 2013 Capital additions - (Table 2, Line a. and Table
4 4, Line a.) This adjustment includes 2013 capital

5 additions, reflecting total depreciation expense and rate
6 base, net of accumulated depreciation and accumulated

7 deferred income tax, as of year-end December 31, 2013 for

8 electric operations, and an agreed-upon level of rate

9 base for natural gas operations.

10 2013 Expenses - (Table 2, Line c. and Table 4, Line

11 b.) The following adjustments include the 2013 expenses

12 removed from the Step 1 increases, effective April 1,
.

13 2013, described above, for recovery in Step 2, effective

14 October 1, 2013:

15 Major Generation O&M - (Table 2, Line c.i.)

16 2013 incremental non-labor generation plant

17 operation and maintenance (O&M) expenses (electric

18 only).

19 Information Services & Technology - (Table 2,

20 Line c.ii. and Table 4, Line b.i.) 2013 incremental

21 information service and technology expenses.

22 CS2 Levelized Return - (Table 2, Line c.iii.)

23 2013 incremental amortization of the CS2 deferred

24 levelized return (electric only)
S
25
50 Norwood, Di 21
Avista Corporation
n
1 Non-Exec Labor - (Table 2, Line c.iv. and Table
2 4, Line b.ii.) 2013 incremental non-executive labor

3 increases.
4 2014 Capital additions - (Table 2, Line b.) This

5 adjustment includes certain 2014 capital additions,

6 including depreciation expense and rate base, net of
7 accumulated depreciation and accumulated deferred income

8 tax, to represent an agreed-upon level of rate base

9 (electric only).

10 Amortization of 2013 Coyote Springs 2/Colstrip

11 Maintenance Deferral - Per Order No. 32371 in Case No.

12 AVU-E-11-01, in order to address the large variability in n
13 year-to--year O&M costs, beginning in 2011, the Company

14 was allowed to defer changes in O&M costs related to its

15 Coyote Springs 2 (CS2) natural gas-fired generating plant

16 located near Boardman, Oregon, and its fifteen (15)

17 percent ownership share of the Colstrip 3 & 4 coal-fired

18 generating plants located in southeastern Montana. The

19 Company compares actual, non-fuel, O&M expenses for the

20 Coyote Springs 2 and Colstrip 3 & 4 plants in the

21 applicable deferral year with the amount of expenses

22 authorized for recovery in base rates, and defers the

23 difference from that currently authorized. The deferral

24 occurs annually, with no carrying charge, with deferred

.

25 costs being amortized over a
51 Norwood, Di 22
Avista Corporation

S 1 three-year period, beginning in January of the year
2 following the period costs are deferred.

3 As a part of this Settlement agreement,
4 the Parties agree that the amount deferred in 2013

5 related to the Company's O&M costs of its C52 and
6 Coistrip 3 & 4 generating plants would be amortized over

7 three years, beginning with the implementation of new

8 base rates resulting from the Company's next general rate

9 case filing, anticipated in 2015.

10 Q. Please summarize the impact of these

11 adjustments on the Step 2 rate adjustments, effective

12 October 1, 2013.
.

13 A. Consolidation of the adjustments

14 discussed above for the Step 2 base rate changes,

15 effective October 1, 2013, results in an electric revenue

16 requirement of $7.825 million, or a 3.1% increase, and a

17 natural gas revenue requirement of $1.330 million, or a

18 2.0% rate increase. Net rate base for electric and

19 natural gas is $659.04 million and $116.07 million,

20 respectively, effective October 1, 2013.

21
Q. Please explain the offset agreed to

22 by the Parties to mitigate the overall impact of the

23 electric October 1, 2013 base rate increase.

24 A. Effective October 1, 2013, coincident

C
25 with the electric base rate change described above, for
52 Norwood, Di 23
Avista Corporation

S
1 rate mitigation purposes, the Company would amortize a
2 $3.865 million credit resulting from a payment to be made

3 to Avista by the Bonneville Power Administration (BPA)
4 relating to the prior use of Avista's transmission

5 system.

6 In December 2012, Avista and Bonneville

7 reached a settlement pertaining to the prior and future

8 use of Avista's transmission system by Bonneville. BPA

9 Settlement Revenue of $3.865 million represents Idaho

10 cus tomers ! share of the $12.224 million (system) to be

11 paid by BPA for its prior use of A vi sta !s transmission

12 system5 . The settlement was intended to resolve the

.

13 issue of compensation to Avista for the prior use of its
'U transmission system by BPA, as well as provide Bonneville
15 with continuing access to transmission in lieu of it

16 constructing additional transmission facilities at this

17 point in time.

18 On February 5, 2013, Avista received
19 approval from the Federal Energy Regulatory Commission

20 (FERC) (Docket No. ER13-689-000) for the settlement filed

21 on December 31, 2012.

22 Avista would amortize the BPA settlement

23 revenue over 15-months from October 1, 2013 to December

24 31, 2014, which reduces the overall bill increase to
.

25 customers on October 1, 2013 from 3.2% to 1.9%.
53 Norwood, Di 24
Avista Corporation
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5 For prior periods up through February 28, 2013.
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54 Norwood, Di 24a
Avista Corporation
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Q. Please explain the offset agreed to
by the Parties to mitigate the overall impact of the
natural gas October 1, 2013 base rate increase.
A. Effective October 1, 2013, coincident
with the natural gas base rate change described above, to
partially offset the base rate increase, the Company
would amortize the $1.55 million PGA deferral credit
balance resulting from the 2012 PGA, over 15-months,
October 1, 2013 to December 31, 2014. This PGA deferral
credit balance results from Docket AVU-G-12-05, in which
the Commission approved Staff's proposal that
approximately $1.55 million in un-refunded credit
balances be held back due to the Company's filing of a
"Notice of Intent to File a General Rate Case." The
Commission stated in Order 32651, on page 6, that "the
resulting $1.55 million un-refunded credit balance will
help mitigate potential rate increases and provide rate
stability for customers." This credit would reduce the
overall bill increase to customers effective October 1,
2013 from 2.0% to 0.3%.
IV. OTHER ELEMENTS OF THE STIPULATION
Q. Please explain the settlement terms
relating to the PCA authorized level of expenses.
55 Norwood, Di 25
Avista Corporation
.

1 A. The new level of power supply
2 expense, retail load and Clearwater Paper generation, for
3 purposes of monthly PCA calculations, are detailed in
4 Attachment B of the Stipulation and Settlement provided

5 as Exhibit No. 1. The Parties agree for settlement
6 purposes to accept the Company's normalized load forecast

7 without specifically accepting the weather normalization
8 methodology or the proposed Energy Efficiency Load

9 Adjustment.

10 Q. Please explain the settlement terms

11 relating to Depreciation Rates.

12 A. The Parties have agreed to the

.

13 updated electric and natural gas depreciation rates as

14 filed by the Company, with all common/allocated plant

15 depreciation rates, including the new depreciation rates

16 for transportation equipment, effective January 1, 2013

17 to coincide with the Company's Washington and Oregon

18 jurisdictions; the remaining direct Idaho plant

19 depreciation rate changes would be effective April 1,

20 2013.

21 Q. Please explain the settlement terms

22 relating to the after-the-fact earnings test for 2013 and

23 2014.

24 A. The Company agrees to an

.

25 after-the-fact earnings test, where it would refund to
56 Norwood, Di 26
Avista Corporation
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1 customers one-half of any earnings in excess of the
2 agreed-upon 9.8% ROE for each of the years 2013 and 2014,
3 to allay any concerns that the base
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57 Norwood, Di 26a
Avista Corporation
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1 rate relief in April 1, 2013 and October 1, 2013 may
2 allow the Company to exceed its authorized return. The

3 earnings test would be based on actual, consolidated
4 results for Idaho electric and natural gas operations.

5
Q. Please explain the settlement terms

6 relating to the rate freeze / stay-out agreed to by the
7 Parties.
8 A. The Parties agree that, in

9 recognition of the two-year rate plan covered by this

10 Stipulation, Avista would not file another electric or

11 natural gas general rate case before May 31, 2014, and

12 while it may request an effective date earlier than

.

13 January 1, 2015, final approved new rates would not go

14 into effect prior to January 1, 2015. This does not

15 apply to tariff filings authorized by or contemplated by

16 the terms of the Power Cost Adjustment (PCA), or the

17 Purchased Gas Adjustment tariff (PGA), or other

18 miscellaneous filings.

19
Q. How does the Stipulation's two-year

20 rate plan, including the rate freeze / stay-out element,

21 agreed to by the Parties challenge Avista to manage its

22 costs?

23 A. The two-year rate plan for the period

24 2013 and 2014 would only provide retail revenues

.

25 sufficient to provide Avista the opportunity to earn the
58 Norwood, Di 27
Avista Corporation
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1 return agreed to by the Parties, if the Company
2 undertakes aggressive cost management measures now and
3 going forward.
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59 Norwood, Di 27a
Avista Corporation
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1 As explained in Avista's direct testimony,
2 the Company is experiencing significant increases in
3 plant investment and non-fuel O&M expenses required to
4 serve its customers, both of which are growing at a much

5 faster pace than its retail sales. Although we continue

6 to take extensive measures to ensure that the costs that

7 we are incurring represent the most cost-effective and

8 reliable way to continue to serve our customers, while
9 preserving a high level of customer satisfaction, we

10 continue to experience significant increases in annual

11 operating expenses.

12 Avista has put into place additional

S
13 cost-management measures, which combined with the rate

14 adjustments in the Settlement, will provide the Company a

15 reasonable opportunity to earn the return agreed to in

16 the Stipulation. As an example, in October 2012, Avista's

17 Board of Directors approved the Company's Voluntary

18 Severance Incentive Plan (VSIP), which was implemented in

19 December 2012. Through this program, effective January 1,

20 2013 Avista reduced its number of employees by 55.
21

22 V. RATE SPREAD & RATE DESIGN

23 Q. Please explain the settlement terms

24 relating to cost of service.
.

25
60 Norwood, Di 28
Avista Corporation
S in A. For electric operations, the Company

2 prepared a cost of service analysis using a peak credit
3 method of classifying production costs, allocating 100%

4 of transmission costs to demand, and allocating

5 transmission costs on a twelve-month basis. For

6 settlement purposes, the Parties agreed to use a pro-rata

7 allocation based on the Company's proposed 15% move

8 towards unity for purposes of spreading the revised

9 electric revenue requirement, while not agreeing on any

10 particular cost of service methodology.

11 For natural gas operations, the Company
12 proposed that all rate schedules be moved approximately
fl
13 25% towards unity. For settlement purposes, the Parties

14 agreed to use a pro-rata allocation of the Company's
15 natural gas rate spread percentages from its original

16 filing for purposes of spreading the revised revenue

17 requirement, without agreement on any particular cost of

18 service methodology.

19 Q. How did the Stipulation address rate

20 design?

21 A. For settlement purposes, the Parties have agreed

22 that the revenue requirement for each electric and
23 natural gas service schedule would be applied as a

24 uniform percentage increase to each volumetric energy

.

25 rate, as shown in Attachment C of the Stipulation and
61 Norwood, Di 29
Avista Corporation
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Settlement provided as Exhibit No. 1, and there would be
no change to
/
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/
62 Norwood, Di 29a
Avista Corporation

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on the residential electric Schedule 1 and natural gas

2 Schedule 101 basic charges.

3 Attachment C of the Stipulation provides a

4 summary of the current and proposed rates and charges for

5 electric and natural gas service.

6 Q. Please explain how the Stipulation

7 addresses rate spread/rate design related to the electric

8 and natural gas base rate offsets effective October 1,

9 2013.

10 A. The Parties have agreed that the

11 electric base rate offset related to the BPA Settlement

12 Revenues would be spread to electric rate schedules on a

.

13 uniform cents per kWh basis, and the natural gas base

14 rate offset related to the 2012 PGA deferral credit

15 balance of $1.55 million would be spread to natural gas

16 rate schedules on a uniform cents per therm basis.

17 Attachment D of the Stipulation contains

18 the form of tariff related to the electric and natural

19 gas offsets agreed to by the Parties. A new electric

20 rate schedule, Schedule 97, would be used for purposes of
21 passing through to customers the electric offset. A new

22 natural gas rate schedule, Schedule 197, would be used

23 for purposes of passing through to customers the natural

24 gas offset. Both tariffs would expire on December 31,
fl
25 2014.
63 Norwood, Di 30
Avista Corporation
Any under- or over-refunded amounts
relating to the electric or natural gas offsets would be
trued up in the following year's Power Cost Adjustment
(electric) or Purchased Gas Cost Adjustment (natural gas)
filings.
VI. CUSTOMER SERVICE PROGRAMS
Q. Does the Company have programs in
place to mitigate the impacts on customers of the
proposed rate increases?
A. Yes. We have a history of making it a
priority within our Company to maintain meaningful
programs to assist our customers that are least able to
pay their energy bills. We also have programs to assist
our entire customer base, i.e., not just our low-income
customers. Some of the key programs that we offer or
support are as follows:
DSM Energy Efficiency Programs and Funding.
The Company offers a broad array of energy
efficiency program measures that provide
customers with increased opportunity to manage
their energy bills. In 2012, Avista hosted two
Energy Fairs, one in Lewiston, and the other in
Coeur d'Alene. Over 280 customers were in
attendance and received energy efficiency tips
and kits that included low cost/no cost ways to
reduce energy consumption.
Project Share. Project Share is a
voluntary program allowing customers to donate
funds that are distributed through community
action agencies to customers in need. In
addition to the Idaho customer contributions
•:
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64 Norwood, Di 31
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during the 2011/2012 program year of $66,490,
the Company also contributed $69,421 (Idaho's
share) to the program.
65 Norwood, Di 31a
Avista Corporation
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Comfort Level Billing. The Company offers the
option for all customers to pay the same bill
amount each month of the year by averaging
their annual usage. Under this program,
customers can avoid unpredictable winter
heating bills.
Payment Arrangements. The Company's Contact
Center Representatives work with customers to
set up payment arrangements to pay energy
bills.
CARES Program. Customer Assistance Referral
and Evaluation Services provides assistance to
special-needs customers through access to
specially trained (CARES) representatives who
provide referrals to area agencies and churches
for help with housing, utilities, medical
assistance, etc.
Senior Energy Outreach: Avista has developed
specific strategic outreach efforts to reach
our more vulnerable customers (seniors and
disabled customers) with bill paying assistance
and energy efficiency information that
emphasizes comfort and safety. Some examples of
this effort are as follows:
Senior Publications: Avista has created a
one-page advertisement that has been
placed in senior resource directories and
targeted senior publications to reach
seniors with information about energy
efficiency, Comfort Level Billing, Avista
CARES and energy assistance. A brochure
with the same information has also been
created for distribution through senior
meal delivery programs and other senior
home-care programs.
Senior Energy Workshops: With the help of
additional workshop presenters, 9 Senior
Energy Workshops were held during 2012 in
Idaho. Over 393 seniors were reached and
were given Senior Energy Efficiency kits
along with learning about low-cost/no-cost
ways to reduce energy use.
66 Norwood, Di 32
Avista Corporation
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VI. CONCLUSION
Q. In conclusion, why is this
Stipulation in the public interest?
A. This Stipulation strikes a reasonable
balance between the interests of the Company and its
customers, including its low-income customers. As such,
it represents a reasonable compromise among differing
interests and points of view.
The terms of the Settlement agreement
represent a two-year rate plan designed to provide
necessary retail revenues. For its part, the Company will
continue to closely manage its costs during this two-year
period. The Parties have agreed that the Company has
demonstrated the need for revenue requirement increases
for both its electric and natural gas operations, thus
providing recovery of its costs over the two-year rate
period.
Therefore, the Stipulation is designed to
address the multiple purposes of addressing the Company's
revenue requirement needs; minimizing the impact to
customers from changes in retail rates; providing rate
certainty over the two year period 2013-2014; and
reducing the administrative burden to all parties and the
Commission associated with this general rate case, as
well as avoiding another rate filing in 2013 for new
rates in 2014. It also provides a
67 Norwood, Di 33
Avista Corporation
form of price cap regulation under which the Company is
expected to manage its costs under the given rates to
earn a fair return.
In the final analysis, however, any
settlement reflects a compromise in the give-and-take of
negotiations. The Commission, therefore, has before it a
Stipulation that is supported by sound analysis and
supporting evidence, the approval of which is in the
public interest.
Q. Does this conclude your pre-filed
direct testimony?
A. Yes, it does.
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68 Norwood, Di 34
Avista Corporation
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I (The following proceedings were had in
2 open hearing.)
3 MR. MEYER: With that, Mr. Norwood is
4 available.

5 COMMISSIONER KJELLANDER: Let's see if

6 there is any cross-examination. Let's begin with the
7 Commission Staff.
8 MR. KLEIN: None.

9 COMMISSIONER KJELLANDER: Idaho Forest

10 Group.

11 MR. MILLER: No, thank you.

12 COMMISSIONER KJELLANDER: Clearwater
n
13 Paper?

14 MR. RICHARDSON: No questions,

15 Mr. Chairman.

16 COMMISSIONER KJELLANDER: Idaho

17 Conservation League?

18 MR. OTTO: No questions, Mr. Chairman.

19 COMMISSIONER KJELLANDER: Community Action

20 Partnership.

21 MR. PURDY: I have none. Thank you.

22 COMMISSIONER KJELLANDER: Thank you.

23 don't believe we have legal counsel here for the Snake

24 River Alliance, so in accordance with our Rules, we won't
.

25 probably have any questions coming from the Snake River
CSB REPORTING 69 NORWOOD
[phone] Avista Corporation
.
1 Alliance today. Are there any questions from members of
2 the Commission?

3 COMMISSIONER REDFORD: No.
4 COMMISSIONER SMITH: Just one.
5

6 EXAMINATION
7

8 BY COMMISSIONER SMITH:

9
Q Mr. Norwood, I guess I'd appreciate your

10 insights on what you see as the issues going forward.

11 Sometimes we congratulate ourselves and the parties when

12 a stipulation is able to be reached that accommodates, it

.

13 seems, the needs of the parties who participated, but I'm
14 wondering if you see issues going forward that you think
15 will need to be addressed here at the Commission or that
16 the Company will need to address on its own in order that

17 customers in Idaho will have the services they're

18 supposed to have.

19 A I can think of a number of responses that

20 are appropriate to answer your question. We looked at a
21 number of things as we negotiated with the parties on

22 this settlement. One is our interest is no surprises for

23 anyone as we go forward. One example is the power cost

24 adjustment mechanism. Typically, we have the rate

25 adjustment in October of each year related to that, so we
CSB REPORTING 70 NORWOOD (Corn)
[phone] Avista Corporation

.
'U looked at the current balance, as well as the

2 expectations going forward, and what that tells us is the

3 expectation is there will be minimal rate adjustment in
4 October based on what we know today.

5 What we also looked at was as we look

6 forward to 2015, we entered into this settlement. It's a

7 two-year plan that adjusts base rates and carries us

8 through the end of '14, so, again, as I look at our

9 financial forecast for 2015 and 1 16, it's important to me

10 that we not have a big bow wave of dollars out there, so

11 our numbers today tell us that we need roughly $25-30

12 million of rate relief in 2015, and that is on a system

I
13 basis, so that would be from Washington, Idaho, and

14 Oregon. Our revenues are over a billion dollars, so that
15 would tell you that we would need based on what we know
16 today roughly a two-and-a-half percent rate adjustment in

17 2015.

18 Now, things can change between now and

19 then. We also look at what's changing in our world, the

20 utility industry. You know that we've gone through for

21 the past several years relicensing the Clark Fork River,

22 the Spokane River. We had some litigation with the Coeur

23 d'Alene Tribe which has been resolved, and so as we go

24 forward, we don't see, at least based on today, major

25 changes or investments, issues that should have a huge
CSB REPORTING 71 NORWOOD (Corn)
[phone] Avista Corporation

.
1 impact on the Company.
2 Now, I'm going to caveat that based on we

3 don't know what's going to happen to the future, but
4 based on what we know today, we don't see anything

5 terribly unusual out there. We're obviously watching
6 what the EPA is doing at the federal level, and so we are
7 paying more attention to things like the Colstrip project

8 and what the right thing to do is long term with that, so

9 we'll pay attention to that; otherwise, as we've

10 indicated in our case, we're spending roughly $250-260
11 million per year in capital investment. A 1t of that is

12 upgrading our hydro plants, our substations. We have a

13 lot of feeders that are very old and we're upgrading

14 those, so a lot of this is pretty straightforward,

15 upgrades to old equipment, a little bit of load growth to

16 serve new customers, but not a lot of load growth going

17 on right now.

18 COMMISSIONER SMITH: Thank you,

19 Mr. Chairman.
20

21 EXAMINATION
22
23 BY COMMISSIONER KJELLANDER:

24 Q Just one question, Mr. Norwood, and it's

25 not directly tied to your testimony, but more to the
CSB REPORTING 72 NORWOOD (Corn)
[phone] Avista Corporation
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process that we've seen with this specific case, and
since there aren't a whole lot of cross-examination
questions, I thought maybe this is a good time to at
least pose it. As we looked at the public hearings and
the process we went through, there's a lot of travel
associated to take testimony from two public witnesses.
I'm not saying that we should eliminate travel to visit
face to face with customers in that context, but given
the fact we had a settlement and given the fact that
technology may in fact play a significant role in the
reduction of participation, what are your thoughts about
the use of technology and telephonic hearings in the
future to perhaps get more participation from members of
the public in that public hearing process?
A First of all, I think I want to make sure
it's clear that I believe it's important that our
customers have the opportunity to weigh in and some of
them have done so through emails to the Commission which
I've looked at. We have, this Commission has, used the
telephonic method before. Personally, I thought that it
was a good method to use and I think it's worthwhile to
try it again to see if there's more participation. In my
view, I think there might be more participation if
customers had the opportunity to call in as opposed to
take time out of their evening to go and attend a
CSB REPORTING 73 NORWOOD (Com)
[phone] Avista Corporation
meeting, so in my view, I think it would provide a better
opportunity and easier opportunity for customers to
participate and would more likely result in more
participating and I would be supportive of that.
COMMISSIONER KJELLANDER: Thank you,
Mr. Norwood. Any other questions?
COMMISSIONER REDFORD: No.
COMMISSIONER KJELLANDER: I would doubt
that there's any redirect.
MR. MEYER: That's correct, yes.
COMMISSIONER KJELLANDER: Thank you.
Thank you very much, Mr. Norwood.
(The witness left the stand.)
COMMISSIONER KJELLANDER: I believe the
only other witness that we have today is from Commission
Staff.
MR. KLEIN: Staff calls Randy Lobb.
CSB REPORTING 74 NORWOOD (Corn)
[phone] Avista Corporation
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RANDY LOBB,
produced as a witness at the instance of the Staff,
3 having been first duly sworn, was examined and testified
4 as follows:
5
6 DIRECT EXAMINATION
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BY MR. KLEIN:
Q Mr. Lobb, will you please state your full
name and spell your last name for the record?
A My name is Randy Lobb, L-o-b-b.
Q And by whom are you employed and in what
capacity?
A I'm employed by the Idaho Public Utilities
Commission. I'm the administrator of the utilities
division.
Q And you're the same Randy Lobb that filed
direct testimony in this case, including Staff Exhibit
101?
A Yes.
Q Earlier Mr. Norwood referenced a
substitution of an exhibit to the stipulation. Other
than that change, do you have any changes to your
testimony?
A Idonot.
CSB REPORTING 75 LOBB (Di)
[phone] Staff
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Q Okay; so if I were to ask you the same

2 questions that are in the testimony, you would give the

3 same answers today?

4 A Yes.

5 MR. KLEIN: I move to spread the testimony

6 on the record.

7 COMMISSIONER KJELLANDER: Is there any

8 objection? Hearing none, then we would spread the
9 testimony across the record as if read and admit Exhibit

10 101.

11 (Staff Exhibit No. 101 was admitted into

12 evidence.)
.

13 (The following prefiled testimony of Mr.

14 Randy Lobb is spread upon the record.)
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CSB REPORTING 76 LOBB (Di)
[phone] Staff
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Q. Please state your name and business
2 address for the record.

3 A. My name is Randy Lobb and my business

4 address is 472 West Washington Street, Boise, Idaho.

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Q. By whom are you employed?

6 A. I am employed by the Idaho Public

7 Utilities Commission as Utilities Division Administrator.

8
Q. What is your educational and
9 professional background?

10 A. I received a Bachelor of Science

11 Degree in Agricultural Engineering from the University of

12 Idaho in 1980 and worked for the Idaho Department of

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13 Water Resources from June of 1980 to November of 1987. I
NXII received my Idaho license as a registered professional

15 Civil Engineer in 1985 and began work at the Idaho Public

16 Utilities Commission in December of 1987. I have

17 analyzed utility rate applications, rate design, tariff

18 analysis and customer petitions. I have testified in
19 numerous proceedings before the Commission including

20 cases dealing with rate structure, cost of service, power

21 supply, line extensions, regulatory policy and facility

22 acquisitions. My duties at the Commission include case
23 management and oversight of all technical Staff assigned

24 to Commission filings.
.

25
Q. What is the purpose of your testimony
AVU-E-12-08/AVU-G-12-07 77 LOBB, R (Stip) 1
02/25/13 STAFF

•
1 in this case?
2 A. The purpose of my testimony is to

3 describe the

wIll
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AVU-E-12-08/AVU-G-12--07 78 LOBB, R (Stip) la
02/25/13 STAFF
•: parties' comprehensive settlement in the case and explain
Staff's support.
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Q. Please summarize your testimony.
A. After thorough review of the
Company's application, detailed identification of
adjustments, two settlement workshops and thoughtful
assessment of settlement alternatives, Staff believes
that the proposed multi-phase, two-year Settlement is in
the public interest, is fair, just and reasonable and
should be approved by the Commission.
Q. How is your testimony organized?
A. My testimony is subdivided under the
following headings:
Stipulation Overview Page 2
Staff Investigation Page 4
The Settlement Process Page 8
Settlement Evaluation Page 9
Cost of Service/Rate Design Page 14
Stipulation Overview
Q. Please summarize the Stipulation and
Settlement.
A. The Stipulation filed with the
Commission provides for a two-phase rate plan for both
electric and natural gas service, with a further base
rate increase stay-out provision through January 1, 2015.
AVU-E-12-08/AVU-G-12-07 79 LOEB, R (Stip) 2
02/25/13 STAFF
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I. The first phase of the plan would take effect on April 1,
2 2013 and provide for no increase in electric base revenue
3 and an annual increase in natural gas revenue of $3.12
4 million or 4.92%. The second phase of the
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AVU-E-12-08/AVU-G-12-07 80 LOBB, R (Stip) 2a
02/25/13 STAFF

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1 plan, proposed to take effect on October 1, 2013,

2 specifies an annual electric base revenue increase of

3 $7.825 million or 3.2%. Annual natural gas revenues
4 would increase by $1.33 million or 2.0%. There would be

5 no base rate increase in 2014.

6 When these proposed base rate increases
7 are combined with Bonneville Power Administration

8 transmission revenue credits and Purchased Gas Adjustment

9 credits, the net increase over two years is about $4.77

10 million (1.9%) for electric and $3.31 million (5.2%) for

11 natural gas service, respectively.

12 The Stipulation specifies a 9.8% return on

13 equity and a 7.91% overall rate of return, annual power

14 supply cost levels, non executive salary levels, end of
15 period rate base levels and treatment of Palouse Wind

16 expenses and benefits. The Stipulation also specifies a

17 cost of service based revenue spread to the various

18 customer classes with a uniform increase in the energy
19 portion of the rate. The Stipulation was signed by all
20 parties to the case expect the Consumer Action

21 Partnership of Idaho (CAPAI). The Settlement document is

22 attached as Staff Exhibit No. 101.

23
Q. How does the stipulated annual

24 revenue requirement increase for electric and natural gas

.

25 service compare to the increases originally requested by
AVU-E-12-08/AVU--G-12-07 81 LOBB, R (Stip) 3
02/25/13 STAFF
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Avi st a?
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A. Avista originally proposed to
increase annual
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AVU-E-12-08/AVU-G-12-07 82 LOBB, R (Stip) 3a
02/25/13 STAFF
.

1 electric revenue by $11.393 million (or 4.6%) and annual
02 natural gas revenue by $4.561 million (or 7.2%) effective

3 April 1, 2013. The Company requested a 10.9% return on
4 equity with an 8.46% overall rate of return.

5 The Stipulation provides for no increase

6 in electrical rates on April 1, 2013 and a $7.825
7 million, 3.2% annual revenue increase October 1, 2013.

8 Annual natural gas revenues would increase by $3.12

9 million or 4.92% on April 1, 2013 and $1.33 million or

10 2.0% on October 1, 2013. A key difference between the

11 Company's original proposal in this case and the

12 Stipulation is the prohibition on any additional base •

S
13 rate increases through January 1, 2015.

14 The stipulated electric increase is about

15 68% of the Company's original proposal and delays

16 implementation of the rate increase for six months. The

17 proposed increase in natural gas revenue on April 1, 2013

18 is also about 68% of the Company's original proposal.
19 However, combined with the second phase of the natural

20 gas increase on October 1, 2013, the Settlement

21 represents about 98% of the Company's original

22 application for natural gas. Under the Company's

23 original proposal, the rate increases would have all

24 taken effect on April 1, 2013 and the Company could have

25 realistically filed three more general rate cases before
AVU-E-12-08/AVU-G-12-07 83 LOBB, R (Stip) 4
02/25/13 STAFF
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1 the January 1, 2015 stay-out date stipulated in the
2 Settlement.
3 Staff Investigation
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AVU-E-12-08/AVU-G-12-07 84 LOBB, R (Stip) 4a
02/25/13 STAFF
.

1 Q. What type of investigation did Staff
2 conduct to evaluate the Company's rate increase request?

3 A. Staff began analyzing the Company's

4 filing on August 29, 2012, with 21 Commission Staff
5 members assigned to the case. Staff submitted 199 formal
6 production requests to the Company and numerous formal

7 and informal audit requests. Staff also reviewed the

8 latest Avista electric and natural gas rate case filings

9 in the State of Washington, including over 300 data

10 requests and responses. Three Staff accountants each

11 conducted a week long on-site audit of Company books and

12 reviewed external auditor workpapers.
.

13 Q. What areas and issues were

14 specifically identified and assigned for review?

15 A. Capital expenditures and plant

16 investment in generation, transmission, distribution and

17 information technology were specifically identified for

18 both gas and electric service and were separately

19 evaluated. Return on equity, capital structure and cost

20 of debt were evaluated and determined. Staff examined
21 and verified operation and maintenance expenses including

22 electric power supply costs, natural gas purchase costs,

23 taxes, depreciation, salaries, level of workforce,

24 consultant costs, incentive pay and vegetation management

.

25 costs.
AVU-E-12-08/AVU-G-12--07 85 LOBB, R (Stip) 5
02/25/13 STAFF
• 1 Staff also evaluated the Company's proposed Energy
2 Efficiency Load Growth Adjustment, Jurisdictional
3 allocation
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AVU-E-12-08/AVU-G-12-07 86 LOBB, R (Stip) 5a
02/25/13 STAFF

S 1 methodology, class cost of service methodology and rate
2 design options.

3
Q. What type of adjustments to the
4 Company's proposed electric revenue requirement did Staff

5 identify?

6 A. Staff particularly focused on

7 possible adjustments in five primary areas: 1) rate of

8 return, 2) power supply expenses, 3) 2012/2013 capital

9 investment and O&M expenses, 4) salaries, and 5)
10 miscellaneous test year expenses. Staff developed
11 positions on individual adjustments in each of these five

12 categories then refined and quantified the revenue

.

13 requirement impact of each in preparation for pre-filed

14 direct testimony.

15 With respect to rate of return, Staff

16 believed that 9.8% return on equity was reasonable,

17 calculated a debt cost of 5.98% and identified a capital

18 structure of 53% debt and 47% equity. The resulting

19 overall return of 7.84% reduced the Company's proposed

20 annual revenue requirement by an estimated $6 million.

21 Power supply adjustments included removing

22 expenses and benefits associated with the Company's

23 Palouse Wind power purchase agreement, reducing forced

24 outage rates for the Company's coal fired power plants
25 and modifying load forecasts by improving weather
AVU-E-12-08/AVU-G-12-07 87 LOBB, P. (Stip) 6
02/25/13 STAFF
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1 normalization methodology and removing the proposed
2 Energy Efficiency Load Adjustment. Eliminating the
3 effect of Palouse Wind from power supply
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AVU-E-12-08/AVU-G-12-07 88 LOBB, R (Stip) 6a
02/25/13 STAFF

1 reduced annual expenses by an estimated $2.9 million on a

2 normalized basis.

3 Staff proposed to remove 2013 Capital

4 additions, O&M expenses and Information Technology (IT)

5 investments to limit test year proforma through December

6 31, 2012. In addition to adjustment for 2013 salary

7 increases, Staff identified adjustments for prior year

8 salary increases for nonexecutive labor starting in 2011.

9 Staff also identified adjustments for executive officer

10 incentives and the effects of the Company's announced

11 workforce reduction.

12 Finally, Staff identified 10 other

13 individual miscellaneous annual adjustments ranging from

14 $400,000 for unspent vegetation management to $1,000 for

15 transmission training and travel. The combined impact of

16 this category of adjustments was estimated at

17 approximately $1 million.

18 Q. What type of adjustments did Staff
19 identify for natural gas revenue requirement and what was

20 the impact?

21 A. Most of the adjustments identified by

22 Staff on the electric side were applied to the natural

23 gas revenue requirement as well. These adjustments

24 included rate of return, 2013 capital additions and O&M,

.

25 salary/workforce expenses and many of the miscellaneous
AVU-E-12-08/AVU-G-12-07 89 LOBB, R (Stip) 7
02/25/13 STAFF
•

items. These adjustments totaled approximately $1.6
2 million on an annual basis.
3 Staff's investigation of the Company's
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application
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AVU-E-12-08/AVU-G-12-07 90 LOBB, R (Stip) 7a
02/25/13 STAFF

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1 was essentially complete and all of the adjustments were

2 identified prior to settlement discussions. Staff was in

3 the process of refining its position on the various
4 issues in preparation for presentation at hearing.
5 The Settlement Process

6 Q. Would you please describe the process

7 leading to the Stipulated Settlement?

8 A. Yes. The Company filed its rate

9 application with the Commission on August 29, 2012 and

10 Staff immediately began its investigation. The first

11 settlement conference was held on January 17, 2012 in the

12 Commission hearing room with all parties of record in the

.

13 case invited to participate. Workshop participants

14 included Commission Staff, Avista, Clearwater Paper
15 Company, Idaho Forest Group, the Community Action

1 6 Partnership of Idaho (CAPAI) and the Idaho Conservation

17 League. The Snake River Alliance (SRA) was a party to

18 the case but did not participate in the Conference.

19 Settlement discussions focused on revenue requirement

20 issues such as capital budget requirements, appropriate

21 return on equity, Capital Structure, Company salaries,

22 O&M expenses, load adjustments, acceptable test period

23 and the acquisition costs associated with the Palouse
24 Wind project. Given the wide disparity in the revenue

.

25 requirement position of the various parties, the
AVU-E-12-08/AVU-G-12-07 91 LOBB, R (Stip) 8
02/25/13 STAFF
El
1 possibility of a multi-year rate agreement was also
2 discussed as an
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AVU-E-12--08/AVU-G-12-07 92 LOBB, R (Stip) 8a
02/25/13 STAFF

1 avenue to settlement.
2 Q. Was settlement reached at that time?

3 A. No. The parties could not reach
4 agreement and convened a second settlement conference on

5 January 24, 2013. Again, all parties participated except
6 the SRA. The second conference focused primarily on

7 needed capital additions over the next two years, the

8 costs and benefits of the Palouse Wind project and how a
9 two-year rate plan might be structured. After numerous
10 proposals and counter proposals, with give and take by

11 all parties, a two-year rate agreement was ultimately

12 reached. The Stipulation and Settlement was filed with

.

13 the Commission on February 6, 2013.
14 Settlement Evaluation

15
Q. How did Commission Staff evaluate the

16 Stipulated Settlement to determine that it was

17 reasonable?

18 A. Staff evaluated the merits of the

19 Settlement in this case for both electric and gas service
20 by looking closely at each of the Staff identified

21 revenue requirement adjustments to assess how they might

22 hold up at hearing.

23 Staff also evaluated the potential for and the likely

24 impact of additional Avista general rate case filings

.

25 during the proposed Settlement stay-out period. The
AVU-E-12-08/AVU-G-12-07 93 LOBB, R (Stip) 9
02/25/13 STAFF
1 overall objective of Staff's assessment was to achieve
2 the best outcome for customers with respect to base rates
3 in this case and with respect to base rate increases that
4 might otherwise
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AVU-E-12-08/AVU-G-12-07 94 LOBB, R (Stip) 9a
02/25/13 STAFF

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1 occur due to additional general rate filings during the
2 Settlement stay-out period.

3
Q. Why did Staff conclude that the
4 Settlement was better than the alternative?

5 A. Although Staff identified significant

6 adjustments to propose at hearing it is unlikely Staff
7 would have prevailed on all or most of them. Many

8 proposed adjustments were to costs and expenses the

9 Company already incurred or will incur in 2013. For

10 example, Staff proposed to eliminate recovery of worker

11 salary increases starting in 2011, but Avista certainly

12 could make a case at hearing that these wage increases

.

13 were fair and prudent, and they were actually paid by the

14 Company. Some of Staff's proposed adjustments were to

15 capital costs in 2012 and 2013. Staff did not conclude

16 from its investigation that these costs were imprudent,

17 so even if Staff had prevailed on these adjustments in

18 this case, it would only delay Avista's recovery until

19 the next rate case. This would likely make certain that
20 Avista would immediately file another case and perhaps

21 another after that.

22 Q. Could you please describe Staff's
23 position regarding other issues specified in the

24 Settlement?

S
25 A. Yes. The Settlement specifies a 9.8% return on
AVU-E-12-08/AVU-G-12-07 95 LOBB, R (Stip) 10
02/25/13 STAFF
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1 equity, a 6.1% cost of debt and a capital structure of
2 50% equity and 50% debt for an overall 7.91% rate of
3 return. Staff believes the resulting overall rate of
4 return is
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AVU-E-12-08/AVU-G-12--07 96 LOBB, R (Stip) lOa
02/25/13 STAFF

S 1 justified and a reasonable compromise in this case. It
2 reflects the same return on equity recently approved for
3 Avista by the Washington Commission. It also reflects a
4 current actual cost of debt that is slightly higher than
5 previously calculated by Staff and an imputed rather than

6 actual capital structure. The imputed Capital Structure

7 is consistent with past cases and representative of the

8 estimated December 2013 Capital Structure.

9 The Settlement also specifies annual power

10 supply expenses for use in the Power Cost Adjustment
11 mechanism. Staff adjustments reflecting forced outage

12 rates, weather normalization and the energy efficiency

13 load adjustment are not captured in stipulated power

14 supply expenses. Staff recognizes that actual expenses

15 associated with these adjustments will effectively flow
16 through the Power Cost Adjustment mechanism whether they

17 are included in base rates or not.

18 Staff will further evaluate the Company's
19 weather normalization methodology and the affects of

20 energy efficiency programs on load forecasts in

21 subsequent rate cases.

22 Q. How did Staff incorporate reduction

23 in expenses associated with the Company's announced

24 voluntary reduction in workforce?

25 A. Staff originally identified the test
year costs and
AVU-E-12-08/AVU-G-12-07 97 LOBB, R (Stip) 11
02/25/13 STAFF
benefits of the workforce reduction program to determine
the net effect on annual revenue requirement. The
workforce reduction benefits or costs were not included
in the Company's Application. Staff analysis showed that
actual test year expenses to implement the program
exceeded test year benefits (due to expensing in a single
year) . However, in subsequent years, benefits of the
program will continue while program expense will not.
Staff therefore, amortized the expense over several years
to assure a test year benefit.
Staff ultimately determined that if
reasonable settlement on revenue requirement is achieved
in this case, the full benefit of workforce reduction can
still be captured in future test years without any
expense offset. Staff therefore, conceded the issue as
part of the Settlement.
Q. Could you please address Staff's
position regarding the Settlement's treatment of Palouse
Wind project costs?
A. Yes. For purpose of settlement in
this case, the costs and benefits associated with the
Palouse Wind power purchase agreement are not included as
normal power supply expenses in base rates. Rather, the
net costs/benefits are tracked and recovered through the
Power Cost Adjustment mechanism at 90%. This represents
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AVU-E-12-08/AVU-G-12-07 98 LOBB, R (Stip) 12
02/25/13 STAFF
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1 a compromise from Staff's original position that would
2 have excluded Palouse project costs from any rate
3 recovery until it was shown to be needed to serve Idaho
1 load.
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AVU-E-12-08/AVU-G-12-07 99 LOBB, R (Stip) 12a
02/25/13 STAFF
1 Staff objected to the project because the
2 Company acquired it to satisfy a Washington State
3 Renewable Portfolio Standard without any immediate need

4 to serve load. Moreover, Staff determined that the
5 project power supply expenses would exceed project
6 benefits under near term normalized load and power supply

7 conditions.

8 However, Staff recognized that the project
9 will likely be economical for Idaho customers over the

10 20-year contract life and could be economical over the

11 next two years under a variety of load and resource

12 conditions. Staff also recognized that the project could
13 provide additional value through the sale of renewable

14 energy credits and could likely be justified to meet load

15 by 2015. Consequently, Staff deemed that treatment
16 through the Power Cost Adjustment mechanism, with partial

17 contribution of net project expense by the Company,

18 reasonably resolved this issue.

19 Q. What types of capital costs are

20 included in this case and how are they treated in the

21 two-year Settlement?

22 A. Capital investment included in this case makes up

23 about 70% of the Company's electric revenue increase

24 request and 48% of the natural gas increase request.

25 Staff's, investigation shows that 94% of the 2012
AvU-E-12-08/AVU-G-12-07 100 LOBB, R (Stip) 13
02/25/13 STAFF
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1 investments were to replace aging infrastructure or
2 upgrade existing plant. In 2013, over 96% of the capital
3 investment was to replace or upgrade existing plant.
4 Staff identified reasonable
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AVU-E-12-08/AVU-G-12-07 101 LOBB, R (Stip) 13a
02/25/13 STAFF
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expenditures for distribution plant replacement on the
gas and electric side as well as radio and customer
service software used to serve all utility customers.
While Staff supports maintaining service
quality and assuring safety by replacing aging
infrastructure such as distribution poles and conductors
and Adyl--A natural gas pipeline, Staff questions the
timing for inclusion in rates. Staff limited proforma
test year plant additions to December 31, 2012.
Consequently, 2012 investment was included for base rate
recovery on April 1, 2013. But 2013 investment was not
allowed in base rates until October 1, 2013. The
attached Settlement shows how 2013 capital additions were
removed from the April increase and added back for the
October increase.
With respect to vegetative management
expenses, Staff originally proposed an adjustment to
reduce the amount requested in the Application to reflect
expenses actually incurred. As part of the Settlement,
Staff agreed that customers would be better served if the
requested vegetative management expenses were maintained
and actually put toward the intended purpose.
Cost of Service/Rate Design
Q. Please describe the Stipulated
Settlement with respect to customer class cost of service
AVU-E-12-08/AVU-G-12-07 102 LOBB, R (Stip) 14
02/25/13 STAFF
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1 and rate design.
2 A. The Settlement spreads the Idaho
3 jurisdictionally
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AVU-E--12-08/AVU-G-12-07 103 LOBB, R (Stip) 14a
02/25/13 STAFF

S 1 allocated revenue requirement to customer classes based
2 on the Company's proposed gas and electric cost of

3 service studies. The studies showed that residential
4 customers were paying a smaller than necessary part of
5 the cost while larger customers were paying more than

6 necessary.

7 Staff evaluated the results of the cost of

8 service studies by first ensuring that the underlying

9 jurisdictional allocation methodology assigned a

10 reasonable portion of electric and natural gas system

11 costs to Idaho. Staff then evaluated various cost of

12 service methodologies on the electric side to determine

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13 how customer classes were affected by the differences.

14 While not adopting a specific methodology, Staff agrees

15 that the cost of service move for the various gas and
16 electric customer classes as proposed by the Company is

17 reasonable in this case (25% move toward cost of service

18 for gas customer classes and 15% move for electric

19 customer classes). Consequently, Staff supports the
20 prorated application of the Company's cost of service

21 studies based on the stipulated gas and electric revenue

22 requirement increases.

23
Q. Does the Settlement provide for

24 changes in rate design?

25 A. No. Existing rate design will not
AVU-E-12-08/AVU-G-12-07 104 LOBB, R (Stip) 15
02/25/13 1 STAFF
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change for either electric or gas customers, and the
monthly residential customer charges will not increase.
All of the proposed
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AVU-E-12-08/AVU-G--12-07 105 LORB, R (Stip) 15a
02/25/13 STAFF
1 revenue increase will be applied uniformly to the energy
2 component of rates. Staff maintains that these rate

3 changes are reasonable given the limited change in

4 overall revenue requirement.

5
Q. What rate offsets are available to
6 mitigate the base rate increases?

7 A. The parties have agreed to use $3.865
8 million in Bonneville Power Administration Settlement

9 Revenue beginning October 1, 2013 to partially offset the

10 electric base rate increase. The revenue represents

11 Idaho's share of money that the Bonneville Power
12 Administration must pay Avista for having used Avista's

13 transmission system. It will be used to reduce the

14 billed energy rate over the period of October 1, 2013

15 through December 31, 2014.

16 The natural gas base rate increase will be

17 partially offset by a $1.55 million un-refunded credit
18 balance held back by the Commission in the most recent

19 purchased gas adjustment case, Case No. AVU-G-12-05. The
20 Commission held the credit refund plus interest in

21 anticipation of Avista filing a natural gas general rate

22 case. The Parties agreed to refund the credit balance

23 over the period October 1, 2013 through December 31,

24 2014. Staff believes returning the credit during the

25 15-month period beginning in October provides the
AVU-E-12-08/AVU-G-12-07 106 LOBB, R (Stip) 16
02/25/13 STAFF
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greatest benefit to residential gas and electric
customers.
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AVU-E-12-08/AVU-G-12-07 107 LOBB, R (Stip) 16a
02/25/13 STAFF
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Q. How does the proposed base rate

2 Settlement impact residential customer bills?

3 A. The net effect of the electric base

4 rate increase and partially offsetting credit is about a

5 $2.21 per month increase for a residential customer using

6 1000 kWh. This increase will not take effect until

7 October 1, 2013 with the credit lasting through December

8 of 2014.

9 The net effect of the gas base rate

10 increase beginning April 1, 2013 will be $4.69 per month

11 for a residential customer using 100 therms. The net

12 effect of the gas base rate change and partially
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13 offsetting credit on October 1, 2013 will be $0.51 per
14 month increase for a residential customer using 100

15 therms.

16 Q. Does this conclude your testimony in

17 this case?

18 A. Yes, it does.
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AVU-E-12-08/AVU-G-12-07 108 LOBB, R (Stip) 17
02/25/13 STAFF

1 (The following proceedings were had in
2 open hearing.)

3 COMMISSIONER KJELLANDER: And I believe,

4 then, you are ready to tender Mr. Lobb for

5 cross-examination?

6 MR. KLEIN: Yes, no further questions.

7 COMMISSIONER KJELLANDER: Let's begin with

8 Avista.

9 MR. MEYER: No questions.

10 COMMISSIONER KJELLANDER: Idaho Forest

11 Group.

12 MR. MILLER: No, thank you.

13 COMMISSIONER KJELLANDER: Clearwater

14 Paper.

15 MR. RICHARDSON: No questions,

16 Mr. Chairman.

17 COMMISSIONER KJELLANDER: Idaho

18 Conservation League.

19 MR. OTTO: No questions, Mr. Chairman.

20 COMMISSIONER KJELLANDER: Community Action

21 Partnership.

22 MR. PURDY: I have none. Thank you.

23 COMMISSIONER KJELLANDER: Thank you. Are
24 there any questions from members of the Commission?

25 COMMISSIONER REDFORD: No.
CSB REPORTING 109 LOBB
[phone] Staff
S 1 COMMISSIONER KJELLANDER: Commissioner
2 Smith.
3
4 EXAMINATION
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6 BY COMMISSIONER SMITH:
7 Q So kind of the same line of question I
8 asked Mr. Norwood, sometimes when the Commission is
9 presented with a settlement, some in the public believe
10 that we didn't do our job correctly or fully, and I just
11 want to know your belief as to whether the Staff fully
12 and aggressively pursued what it believed was the correct
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13 outcome.
14 A Yes, I believe we have fully pursued the
15 investigation. We did everything that we would have done
16 had we filed testimony before the Commission, and one of
17 the things that we tried to do in this case is develop a
18 stipulation that was more transparent than it has been in
19 the past, outlining and specifying all of the
20 investigation, my testimony covers that aspect fairly
21 fully, the types of adjustments, the types of
22 investigation that we did, exactly what is included and
23 what is not included in rates in terms of the rate base
24 and capital additions, and exactly what we allowed in
.

25 this rate case and what we did not, so we've had the
CSB REPORTING 110 LOBB (Corn)
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term -- used the term black box in the past. We got rid
of that. We believe this stipulation is much more
transparent than that.
Q In addition, sometimes when a settlement
is reached, some issues aren't addressed or are left for
the future, and most often those seem to be in the areas
of cost of service and rate design, so in your mind, are
there outstanding issues with regard to those or anything
else that will need the Commission's attention in the
near future or might suffer in the interim because they
weren't fully developed in a rate case hearing?
A I agree, there are some issues that
probably are kicked down the road a bit with settlements.
In this particular case with respect to cost of service,
we looked at several different methodologies in cost of
service and they all seemed to indicate a similar
direction in terms of rate spread and we applied that
rate spread. The parties agreed to apply that rate
spread in the stipulation. We made moves towards cost of
service and so I think we're fairly well in agreement on
at least the direction that cost of service should take,
so I'm pretty comfortable with that one.
There was other issues with regard to rate
design, whether there should be more tiers in the
residential rate, whether customer charges should be
CSB REPORTING 111 LOBB (Corn)
[phone] Staff

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1 higher, how the blocks should change, and I think we plan

2 to look at that more fully. I don't think we saw any

3 compelling information that would result in significant

4 changes in this case, and particularly when you have a

5 fairly small rate increase, you don't want to cause large
6 percentage changes by changing rate design, and that was

7 a factor for us, but we don't see anything compelling in

8 terms of rate design.

9 The issues down the road, I think, are

10 capital budgets. We looked pretty closely at that, what

11 the Company needs, what's reasonable for customers to pay

12 for, and we're fairly comfortable with that. It's a very

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13 lean amount of capital additions, so salaries are always

14 an issue and we want to keep our eye on those.

15 Certainly, environmental costs associated with coal

16 plants is an issue that we're going to want to look at

17 down the road, but it wasn't really a factor in this

18 case.

19 COMMISSIONER SMITH: Thank you, Mr. Lobb.

20 We're all well aware that ratemaking is an art, not a

21 science, so I appreciate your thoughts. Thank you.

22 COMMISSIONER KJELLANDER: Any other

23 questions? Any redirect?

24 MR. KLEIN: No.
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25 COMMISSIONER KJELLANDER: Thank you.
CSB REPORTING 112 LOBB (Corn)
(2 08) 8 90-5 198 Staff
I Thank you, Mr. Lobb.
2 (The witness left the stand.)
3 COMMISSIONER KJELLANDER: I believe that
4 exhausts the witness list and so I guess we're at the
5 point, is there any further issue or items that need to
6 come before the Commission today?
7 COMMISSIONER SMITH: No posthearing
8 briefs?
9 COMMISSIONER KJELLANDER: Mr. Purdy.
10 MR. PURDY: Mr. Chairman, I'm sure the
11 Commission is quite aware that my client filed a joinder
12 in the settlement late in this case. The reasons for
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13 that are stated in the notice itself and I just want to
14 make very clear on the record that Community Action does
15 join in the settlement. We needed additional time to
16 discuss rate design and other issues, but thank you.
17 COMMISSIONER KJELLANDER: Thank you,
18 appreciate that. Anything else that needs to come before
19 the Commission today? Then I certainly do appreciate
20 everybody's appearances here today. We wish you the
21 best. The Commission then will consider this record
22 fully developed and we will deliberate on that and try to
23 render a decision within the timeline before us, so with
24 that, then, today we are adjourned.
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25 (The Hearing adjourned at 9:50 a.m.)
CSB REPORTING 113 COLLOQUY
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AUTHENTICATION
This is to certify that the foregoing
proceedings held in the matter of the application of
Avista Corporation dba Avista Utilities for authority to
increase its rates and charges for electric and natural
gas service in Idaho, commencing at 9:30 a.m., on
Thursday, March 7, 2013, at the Commission Hearing Room,
472 West Washington Street, Boise, Idaho, is a true and
correct transcript of said proceedings and the original
thereof for the file of the Commission.
Accuracy of all prefiled testimony as
originally submitted to the Reporter and incorporated
herein at the direction of the Commission is the sole
responsibility of the submitting parties.
-j.
CONSTANCE S. BUCY
Certified SJ1Øt4n1?eporter #18
VS
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CSB REPORTING 114 COLLOQUY
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