20130225Norwood DI in Support.pdf

Avista Corp.
1411 East Mission P.O. Box 3727 AINVISTAff Spokane. Washington 99220-0500
Telephone [phone] Corp.
Toll Free 800-727-9170
FILED ELECTRONICALLY AND VIA OVERNIGHT MAIL
—4
February 22, 2013
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Jean D Jewell -
Commission Secretary =
Idaho Public Utilities Commission
472 W. Washington Street
Boise, ID 83702
Re: Case Nos. AVU-E-12-08 and AVU-G-12-07
Direct Testimony of Kelly 0. Norwood in Support of the Stipulation and Settlement
Enclosed for filing with the Commission in the above-referenced dockets are the original
and nine copies of the Direct Testimony of Kelly 0. Norwood in Support of the
Stipulation and Settlement, dated February 22, 2013.
Sincerely,
~77/_____
David J. Meyer
Vice President, Chief Counsel for Regulatory
& Governmental Affairs
Enclosures
c: Service List
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that I have this 22nd day of February, 2013, served the Direct
Testimony of Kelly 0. Norwood in support of the Stipulation and Settlement in Docket
No. AVU-E-12-08 and AVU-G-12-07, upon the following parties, by mailing a copy
thereof, properly addressed with postage prepaid to:
Jean D Jewell, Secretary
Idaho Public Utilities Commission
Statehouse
Boise, ID 83720-5983
Jean. iewelkpuc.idaho.qov
Karl Klein
Weldon Stutzman
Deputy Attorneys General
Idaho Public Utilities Commission
472 W. Washington
Boise, ID 83702-0659
karI.kleinpuc. idaho.qov
Weldon.stutzmancpuc. idaho.qov
Mary Lewallen
Clearwater Paper
601 W. Riverside Avenue
Suite 1100
Spokane, WA 99201
mary. lewallen(clearwaterpa per. com
Scott Atkison
Idaho Forest Products
171 Highway 95 N.
Grangeville, ID 83530
scottatidahoforestgrouD. com
Larry A. Crowley
The Energy Strategies Institute, Inc.
5549 South Cliffsedge Avenue
Boise, Idaho 83716
crowleya(äaoI.com
Ken Miller
Clean Energy Program Director
Snake River Alliance
Boise, ID
kmillercsnakeriveralliance.org
Brad M. Purdy
Attorney at Law
2019 N 17 1h Street
Boise, ID 83720
bmpurdychotmail.com
Peter J. Richardson
Greg M. Adams
Richardson & O'Leary PLLC
515 N. 27th Street
P0 Box 7218
Boise, ID 83702
oeterrichardsonandoIearv. com
qreqcrichardsondolearv. com
Dean J. Miller
McDevitt & Miller, LLP
420 W. Bannock St.
P0 Box 2564-83701
Boise, ID 83701-2564
ioemcdevitt-miller. corn
Benjamin J. Otto
Idaho Conservation League
710 N. 6th St.
Boise, ID 83702
bottoidahoconservation.org
Dr. Don Reading
6070 Hill Road
Boise, Idaho
dreading crnindspring.com
Paul Kimball
Sr. Regulatory Analyst
DAVID J. MEYER
VICE PRESIDENT, CHIEF COUNSEL FOR REGULATORY &
GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC
AND NATURAL GAS CUSTOMERS IN THE
STATE OF IDAHO
CASE NO. AVU-E-12-08
CASE NO. AVtJ-G-12-07
DIRECT TESTIMONY
OF KELLY 0. NORWOOD
IN SUPPORT OF THE
STIPULATION AND
SETTLEMENT
FOR AVISTA CORPORATION
(ELECTRIC AND NATURAL GAS)

I I. INTRODUCTION

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Q. Please state your name, employer and business

3 address.

4 A. My name is Kelly 0. Norwood and I am employed as

5 the Vice-President of State and Federal Regulation for

6 Avista Utilities ("Company" or "Avista"), at 1411 East

7 Mission Avenue, Spokane, Washington.

8 Q. Would you briefly describe your educational
background and professional experience?

10 A. Yes. I am a graduate of Eastern Washington

11 University with a Bachelor of Arts Degree in Business

12 Administration, majoring in Accounting. I joined the

13 Company in June of 1981. Over the past 31 years, I have

14 spent approximately 20 years in the Rates Department with

15 involvement in cost of service, rate design, revenue

16 requirements and other aspects of ratemaking. I spent

17 approximately 11 years in the Energy Resources Department

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(power supply and natural gas supply) in a variety of roles,

19 with involvement in resource planning, system operations,

20 resource analysis, negotiation of power contracts, and risk

21 management. I was appointed Vice-President of State &

22 Federal Regulation in March 2002.
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Avista Corporation
I Q. What is the scope of your pre-filed testimony in
2 this proceeding?
3 A. The purpose of my testimony is to describe and
4 support the Stipulation and Settlement ("Stipulation"),
5 filed on February 6, 2013 between the Staff of the Idaho
6 Public Utilities Commission ("Staff'), Clearwater Paper
7 Corporation ("Clearwater"), Idaho Forest Group, LLC ("Idaho
8 Forest"), the Idaho Conservation League ("Conservation
9 League"), and the Company, which, if approved by the
10 Commission, would resolve all of the issues in the Company's
11 filing. These entities are collectively referred to as the
12 "Parties," and represent several parties in the above-
13 referenced cases.'
14 The Stipulation is the product of settlement
15 discussions held in the Commission offices on January 17 and
16 24, 2013. The Stipulation between the Parties resolved all
17 issues associated with the calculation of the Company's
18 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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Avista Corporation
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
For its part, Avista responded to over 270 production requests
(including sub-parts) from iptic Staff and other intervening parties.
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Avista Corporation

1 willingness to hear this matter promptly, in light of the

2 proposed April 1 effective date.

3 Q. Why is the Stipulation in the public interest?

4 A. The Stipulation is in the "public interest" for

5 several reasons, which include:

6 • It was the product of the give-and-take of

7 negotiation that produced an "end result" that is

8 just and reasonable.

9 • It is supported by the evidence, demonstrating the

10 need for rate adjustments to provide recovery of

11 necessary expenditures and investment, the costs of

12 which are not offset by a growth in sales margins.

13 • The Settlement enjoys broad-based support from a

14 variety of constituencies, including Clearwater,

15 Idaho Forest, the Conservation League, and the Snake

16 River Alliance, serving to address their specific

17 needs, and the Staff of the Commission representing

18 all customers.

19 • The Settlement provides base rate certainty over

20 the next two years (2013/2014), which would benefit

21 all customers, as they plan and budget for their

22 needs.

23 • It would prohibit Avista from making further

24 changes in base rates prior to January 1, 2015,

25 thereby breaking the yearly cycle of rate filings.

26 • The impact of the base rate increases in Step 2,

27 effective October 1, 2013, would be mitigated, in

28 part, by the amortization of the BPA settlement

29 payment for electric and the PGA deferral credit

30 balance for natural gas.

31 • The "stay-out" provision preventing a further

32 change in base rates until 2015 would challenge

33 Avista to manage its costs in order to have the

34 opportunity to earn the agreed-upon return on equity;

35 indeed, the Company has already put in place cost

36 saving measures, such as the voluntary severance

37 program reducing Avista's work force by 55

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individuals, executed at year-end 2012.

39 • Finally, as I will discuss later in my testimony,

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in order to allay any concerns that Avista might

41 somehow "over-earn" during the 2013/2014 rate-
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Avista Corporation

I effective period, Avista would agree to refund back

2 to customers 50% of any earnings that exceed the 9.8%

3 agreed-upon ROE during the 2013 and 2014 rate-

4 effective periods, based on actual, consolidated

5 results for its Idaho electric and natural gas

6 operations.
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8 Q. Would you briefly summarize the Stipulation?

9 A. Yes. Under the terms of the Stipulation, Avista

10 would implement revised tariff schedules designed to recover

11 additional annual electric and natural gas revenue in two

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

13 represents a two-year rate plan for the period 2013 and

14 2014, designed to provide retail revenues necessary to allow

15 the Company the opportunity to earn the return agreed to in

16 the Stipulation.

17 For electric operations, there is no electric base rate

18 increase in the first step (April 1, 2013), however,

19 effective October 1, 2013 (Step 2), the Parties agree to an

20 overall base rate increase of 3.1% (3.2% on a billed basis)

21 or $7.825 million in electric annual base tariff revenues.

22 Partially offsetting the October 1, 2013 electric increase

23 is $3.865 million of revenues resulting from a payment to be

24 made to Avista by the Bonneville Power Administration

25 (EPA)3 . This payment to Avista is for the Parallel Operation
The agreement between Avista and BPA was approved by FERC on February
5, 2013.
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Avista Corporation
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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 l.9'. A residential customer using an average of 930
kilowatt hours per month would see a $2.04, or 2.6s,
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:
Summary of Electric Rate Changes (millions)
Revenue Base Rate Billing Rate Net Billing
Requirement Change Change Ofiet Rate Change
April 1, 2013 $0.00 0.0% 0.0% 0.0% 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
Norwood, Di 6
Avista Corporation

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, Avista would

4 implement revised tariff schedules designed to recover an

5 additional $1.330 million in annual natural gas revenue,

6 representing an overall 2.0% increase (on both a base and

7 billed basis). Partially offsetting the natural gas rate

8 increase would be a $1.550 million Purchase Gas Adjustment

9 (PGA) deferral credit balance from the 2012 PGA. This

10 credit would be amortized over 15 months, October 1, 2013 to

11 December 31, 2014, resulting in a decrease to billed

12 customer rates of 1.7%. The result of the two October 1,

13 2013 adjustments is an overall net increase on a billed

14 basis of 0.3%. A residential customer using an average of

15 60 therms per month would see a $0.31, or 0.6%, increase per

16 month for a revised monthly bill of $55.68. Other customer

17 classes, except transportation customers, would see an

18 overall net rate decrease October 1, 2013. (See Exhibit No.

19 1, Paragraph 22, for the April 1 and October 1, 2013 change

20 in rates by rate schedule.)
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Avista Corporation
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The table below summarizes the April 1 and October 1,
2013 proposed natural gas rate changes:
Summary of Natural Gas Rate Changes (millions)
Revenue Base Rate Billing Rate Net Billing
Requirement Change Change Oflet Rate Change
April 1, 2013 $3.115 4.9% 5.0% 0.0% 5.0%
October 1, 2013 $1.330 2.0% 2.0% -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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Avista Corporation
1 II. HISTORY OF FILING
2 Q. Please describe the Company's general rate case
3 request, as filed.
4 A. On October 11, 2012, Avista filed an Application
5 with the Commission for authority to increase revenue from
6 electric and natural gas service in Idaho by 4.6 and 7.2'6,
7 respectively. If approved, the Company's revenues for
8 electric base retail rates would have increased by $11.4
9 million annually; Company revenues for natural gas service
10 would have increased by $4.6 million annually. The Company
11 requested an effective date of April 1, 2013 for its
12 proposed electric and natural gas rate increases. By Order
13 No. 32689, dated December 4, 2012, the Commission suspended
14 the proposed schedules of rates and charges for electric and
15 natural gas service.
16 The Company proposed utilizing the results of its
17 electric and natural gas service studies, sponsored by
18 Company witness Knox, as a guide to spread the overall
19 requested electric and natural gas revenue increases by rate
20 schedule on a basis which: 1) moved the rates for nearly all
21 the schedules closer to the cost of providing service, and
22 2) resulted in a reasonable range in the (net) proposed
23 percentage increase across the schedules. The spread of the
24 proposed electric increase generally resulted in the rates
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Avista Corporation
I of return for the various electric service schedules moving
2 approximately 15% closer to the overall rate of return
3 (unity); whereas the proposed increases for the various
4 natural gas service schedules would move the return
5 approximately 25% closer to the overall rate of return
6 (unity). The Company did not request a change in its
7 electric or natural gas residential basic charges.
8 Q. What are the primary factors driving the Company's
9 need for electric and natural gas increases?
10 A. Approximately 70% of the Company's electric
11 revenue requirement, and 48% for natural gas, is due to an
12 increase in net plant investment (including return on
13 investment, depreciation and taxes, and offset by the tax
14 benefit of interest).
15 The remaining revenue requirement request is due to
16 increases in distribution, operation and maintenance (O&M),
17 and administrative and general (A&G) expenses for both
18 electric and natural gas operations. However, the increased
19 costs for electric operations are partially offset by a
20 reduction in net power supply and transmission expenditures.
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Avista Corporation

1 III. REVENUE REQUIREMENT ELEMENTS OF THE STIPULATION

2 Q. Please explain the derivation of the Electric and

3 Natural Gas Revenue Requirements outlined in the

4 Stipulation.

5 A. The Parties agreed that Avista would implement

6 revised tariff schedules designed to recover additional

7 annual electric and natural gas revenue in two steps,

8 effective April 1 and October 1, 2013. This represents a

9 two-year rate plan designed to provide sufficient retail

10 revenues for the period 2013 and 2014, which together with

11 management of costs, would provide the Company with the

12 opportunity to earn the return agreed to in the Stipulation.

13 While Avista's filing requested an electric revenue

14 requirement increase of $11.393 million effective April 1,

15 2013, agreed-upon adjustments, including the agreed-upon

16 rate of return, result in a recommended electric revenue

17 requirement increase of $0.0 as of April 1, 2013 and $7.825

18 million as of October 1, 2013.

19 Similarly, while the Company requested a natural gas

20 revenue requirement increase of $4.561 million effective

21 April 1, 2013, agreed-upon adjustments result in a

22 recommended natural gas revenue requirement increase of

23 $3.115 million as of April 1, 2013 and $1.330 million as of

24 October 1, 2013.
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Avista Corporation
I Q. Please explain the Parties' agreement with regard
2 to an Authorized Rate of Return, including the Return on

3 Equity.

4 A. The Parties have agreed to a revenue requirement

5 which produces an overall rate of return of 7.91%, based on

6 a return on equity of 9.8%, an equity component at 50% and

7 cost of debt of 6.01%. By comparison, the Company's

8 original filing requested an overall rate of return of

9 8.46%, a return on equity of 10.9%, an equity component of

10 50% and cost of debt of 6.02%.

11 Q. What is the proposed effective date of new rates

12 from the Stipulation?

13 A. The Parties have requested implementation of new

14 retail rates from the Stipulation on April 1, 2013, with

15 further tariff changes on October 1, 2013. These proposed

16 effective dates are an integral part of the Stipulation that

17 includes a negotiated resolution of all of the issues.

18 Q. Please provide an overview of the revenue
19 requirement adjustments agreed to by the Parties resulting
20 in the April 1 and October 1, 2013 revenue requirements.
21 A. A number of the adjustments, agreed to by the
22 Parties, resulted in delaying recovery of 2013 increased
23 costs until October 1, 2013, as well as reducing certain
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Avista Corporation
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
Revenue
Requirement Rate Base
Amount as Filed: $ 11,393 $ 639,030
Adjustments:
a.) Cost of Capital $ (5,517)
b.) Remove 2013 Capital Additions (Delay to October 1, 2013) $ (1,117) $ (1,582)
c.) Remove 2013 Expenses: Delay Recovery to October 1, 2013 Rate Change
i.Major Generation O&M $ (926)
ii.Information Services & Technology $ (318)
HL CS2 Levelized Return $ (38)
iv. Non-Exec Labor $ (426)
d.) Remove 2013 Property Tax Expense $ (428)
e.) Remove Officer Incentive and CPI escalation $ (187)
£) Two-Year Amortization of Reardan $ 878
g.) Include Palouse Wind in PCA until in base rates in 2015 (90%/10 1/o sharing) $ (3,139)
h.) 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
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Avista Corporation
1 Table 2: October 1, 2013 Electric Revenue Requirement
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SUMMARY TABLE OF ELECTRIC REVENUE REQUIREMENT
EFFECTIVE OCTOBER 1, 2013
000s of Dollars
Amounts Effective April 1, 2013
Adjustments to October!, 2013 Rate Change:
a.)2013 Capital Additions
b.)2014 Capital Additions
c.)Add 2013 Expenses
L Major Generation O&M
ii.Information Services & Technology
iii.CS2 Levelized Return
iv.Non-Exec Labor
Adjusted Amounts Effective October 1, 2013
Revenue
Requirement Rate Base
$ - $ 637,448
$ 5,488 $ 20,705
$ 629 $ 888
$ 926
$ 318
$ 38
$ 426
$7,825 $659,041
Table3:April1,2013Natural Gas RevenueRequirement
SUMMARY TABLE OF ADJUSTMENTS TO NATURAL GAS REVENUE REQUIREMENT
EFFECTIVE APRIL 1, 2013
000s of Dollars
Revenue
Requirement RateBase
Amount as Filed: $ 4,561 $ 110,930
Adjustments:
a.) Cost of Capital $ (957)
b.) Remove 2013 Capital Additions (Delay to October 1, 2013) $ (22) $ 1,309
c.) Remove 2013 Expenses: Delay Recovery to October 1, 2013 Rate Change
L Information Services & Technology $ (42)
ii. Non-Exec Labor $ (215)
d.) Remove 2013 Property Tax Expense $ (84)
e.) Remove Officer Incentive and CPI escalation $ (50)
C) Miscellaneouse Adjustments: Two-Year Amortization of Booz Consulting $ (76)
costs, Injuries & Damages, Abandoned Projects & Depreciation Study
expense
Adjusted Amounts Effective April 1, 2013 $3,115 $
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Avista Corporation
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!, 2013 Rate Change:
a.)2013 Capital Additions $ 1,073 $ 3,831
b.)Add 2013 Expenses
1. Information Services & Technology $ 42
ii. 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.
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Avista Corporation
I Step 1: April 1, 2013 Rate. Change: Electric $0.0; Natural
2 Gas $3.115 million:
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4 Remove 2013 Capital additions - (Table 1, Line b. and
5 Table 3, Line b.) The 2013 electric and natural gas capital
6 additions adjustments, as proposed by the Company in its
7 original filings, were removed, delaying recovery of the
8 associated revenue requirement until the October 1, 2013
9 rate increase. April 1, 2013, therefore, reflected total
10 depreciation expenses and rate base, net of accumulated
11 depreciation and accumulated deferred income tax, as of
12 year-end December 31, 2012.
13 Remove 2013 Expenses - (Table 1, Line c. and Table 3,
14 Line c.) The following adjustments remove 2013 expenses pro
15 formed in the Company's original filing, delaying recovery
16 of those expenditures until the October 1, 2013 rate change:
17 Major Generation O&M - (Table 1, Line c.i.) 2013
18 incremental non-labor generation plant operation and
19 maintenance (O&M) expenses related to the Company's
20 thermal generation plant at Kettle Falls, and its
21 hydro generation plants (electric only).
22 Information Services & Technology - (Table 1,
23 Line c.ii. and Table 3, Line c.i.) 2013 incremental
24 information service and technology expenses, related
25 to the Company's replacement of the Company's Customer
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Avista Corporation

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 of

14 Directors for 2013 for its non-union, non-executive

15 employees, as well as the 2013 union contract

16 increases for union employees.

17 Remove 2013 Property Tax Expense - (Table 1, Line d.

18 and Table 3, Line d.) This adjustment removes the 2013

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incremental pro forma property tax expense. In its original

20 filing, the Company adjusted test period accrued property

21 tax expense to the expected 2013 rate period expense level

22 based on property values as of December 31, 2012. This

23 adjustment reduces recovery of property tax to 2012 expense

24 levels.
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Avista Corporation
I Remove Officer Incentive and CPI Escalation - (Table 1,
2 Line e. and Table 3, Line e.) This adjustment removes the
3 officer portion of the employee incentive expense included
4 in the Company's original filing. Included in the Company's
5 original filing was a six-year average (2006-2011) of actual
6 incentive expense adjusted by the Consumer Price Index
7 (CPI). This adjustment in the Settlement also removes the
8 CPI escalation.
9 Miscellaneous Adjustments - (Table 1, Line h. and Table
10 3, Line f.) The Company adopted, for settlement purposes,
11 Staff's proposal to adjust or remove various administrative
12 and general (A&G) and O&M-related costs, including a two-
13 year amortization of Booz & Co. consulting fees, thereby
14 reducing test period expenses, as well as removal of certain
15 other amounts related to OASIS training, abandoned
16 projects, injuries and damages (natural gas only) and
17 depreciation study expenses.
18 Reardan Wind Site - (Table 1, Line f.) In May 2008,
19 Avista purchased the Reardan Wind Project Site from Energy
20 Northwest after it was demonstrated as the Company's least-
21 cost option for securing a renewable resource for its
22 customers, consistent with its 2007 Integrated Resource
" Open Access Same-Time Information System (OASIS).
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Avista Corporation

1 Plan. Avista later chose to delay the construction of the

2 Reardan project and take advantage of much-lower costs for

3 wind projects that emerged in 2011 (Palouse Wind). Avista

4 recorded $4.0 million of site acquisition and preparation

5 costs, of which approximately $1.7 million is Idaho's share.

6 This includes approximately $0.4 million in AFUDC in

7 accordance with Order No. 30611 (Case No. AVtJ-E-08-04). As

8 a part of the agreed-upon Settlement, Avista would amortize

9 Idaho's portion of the Reardan Wind Project deferred balance

10 of approximately $1.7 million over a two-year period

11 beginning April 1, 2013.

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

13 that recovery of costs related to the Palouse Wind Power
14 Purchase Agreement ("PPA") would be included in the PCA,
15 subject to the current sharing (90% customer, 10% Company)
16 until it is included in base rates as part of the
17 implementation of new rates from the Company's next general
18 rate case, anticipated in 2015. This adjustment removes the
19 Palouse Wind PPA expenses from the pro forma power supply
20 adjustment included in the Company's original filing.
21 Q. Please summarize the impact of these adjustments
22 on Step 1, effective April 1, 2013.
23 A. Consolidation of the adjustments discussed above
Norwood, Di 19
Avista Corporation

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 rate

6 increase. Net rate base for electric and natural gas is

7 $637.45 million and $112.24 million, respectively, effective

8 April 1, 2013.

9 Q. Please continue your explanation of the revenue

[[I] requirement adjustments agreed to by the Parties resulting

11
in the electric and natural gas Step 2, October 1, 2013,

12 rate changes.

13 A. As discussed above, a number of capital and

14 expense related adjustments proposed in the Company's

15 original filing were removed from the electric and natural

16 gas revenue requirements for purposes of the Step 1, rate

17 changes effective April 1, 2013, delaying the recovery of

18 those incremental 2013 increased costs to the Step 2,

19 October 1, 2013 rate changes. A description of these

20 adjustments resulting in the Step 2 increases, effective

21 October 1, 2013, follows.
22
Norwood, Di 20
Avista Corporation
I Step 2: October 1, 2013 Rate Changes: Electric $7.825
2 million; Natural Gas $1.330 million:
3 2013 Capital additions - (Table 2, Line a. and Table 4,
4 Line a.) This adjustment includes 2013 capital additions,
5 reflecting total depreciation expense and rate base, net of
6 accumulated depreciation and accumulated deferred income
7 tax, as of year-end December 31, 2013 for electric
8 operations, and an agreed-upon level of rate base for
9 natural gas operations.
10 2013 Expenses - (Table 2, Line c. and Table 4, Line b.)
11 The following adjustments include the 2013 expenses removed
12 from the Step 1 increases, effective April 1, 2013,
13 described above, for recovery in Step 2, effective October
14 1, 2013:
15 Major Generation O&M - (Table 2, Line c.i.) 2013
16 incremental non-labor generation plant operation and
17 maintenance (O&M) expenses (electric only).
18 Information Services & Technology - (Table 2, Line
19 c.ii. and Table 4, Line b.i.) 2013 incremental
20 information service and technology expenses.
21 C52 Levelized Return - (Table 2, Line c.iii.)
22 2013 incremental amortization of the CS2 deferred
23 levelized return (electric only).
Norwood, Di 21
Avista Corporation

1 Non-Exec Labor - (Table 2, Line c.iv. and Table 4,

2 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. AVtJ-

12 E-ll-Ol, in order to address the large variability in year-

13 to-year O&M costs, beginning in 2011, the Company was

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

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

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

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

18 plants located in southeastern Montana. The Company

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

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

21 deferral year with the amount of expenses authorized for

22 recovery in base rates, and defers the difference from that

23 currently authorized. The deferral occurs annually, with no

24 carrying charge, with deferred costs being amortized over a
Norwood, Di 22
Avista Corporation

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, the Parties

4 agree that the amount deferred in 2013 related to the

5 Company's O&M costs of its CS2 and Colstrip 3 & 4 generating

6 plants would be amortized over three years, beginning with

7 the implementation of new base rates resulting from the

8 Company's next general rate case filing, anticipated in

9 2015.

10
Q. Please summarize the impact of these adjustments

11 on the Step 2 rate adjustments, effective October 1, 2013.

12 A. Consolidation of the adjustments discussed above

13 for the Step 2 base rate changes, effective October 1, 2013,

14 results in an electric revenue requirement of $7.825

15 million, or a 3.1% increase, and a natural gas revenue

16 requirement of $1.330 million, or a 2.0% rate increase. Net

17 rate base for electric and natural gas is $659.04 million

18 and $116.07 million, respectively, effective October 1,

19 2013.

20 Q. Please explain the offset agreed to by the Parties

21 to mitigate the overall impact of the electric October 1,
2013 base rate increase.

23 A. Effective October 1, 2013, coincident with the

24 electric base rate change described above, for rate
Norwood, Di 23
Avista Corporation
1 mitigation purposes, the Company would amortize a $3.865
2 million credit resulting from a payment to be made to Avista
3 by the Bonneville Power Administration (BPA) relating to the
4 prior use of Avista's transmission system.
5 In December 2012, Avista and Bonneville reached a
6 settlement pertaining to the prior and future use of
7 Avista's transmission system by Bonneville. BPA Settlement
8 Revenue of $3.865 million represents Idaho customers' share
9 of the $12.224 million (system) to be paid by BPA for its
10 prior use of Avista's transmission system5 . The settlement
11 was intended to resolve the issue of compensation to Avista
12 for the prior use of its transmission system by BPA, as well
13 as provide Bonneville with continuing access to transmission
14 in lieu of it constructing additional transmission
15 facilities at this point in time.
16 On February 5, 2013, Avista received approval from the
17 Federal Energy Regulatory Commission (FERC) (Docket No. ER13-
18 689-000) for the settlement filed on December 31, 2012.
19 Avista would amortize the BPA settlement revenue over
20 15-months from October 1, 2013 to December 31, 2014, which
21 reduces the overall bill increase to customers on October 1,
22 2013 from 3.2 to 1.91.
For prior periods up through February 28, 2013.
Norwood, Di 24
Avista Corporation
I Q. Please explain the offset agreed to by the Parties
2 to mitigate the overall impact of the natural gas October 1,

3 2013 base rate increase.

4 A. Effective October 1, 2013, coincident with the

5 natural gas base rate change described above, to partially

6 offset the base rate increase, the Company would amortize

7 the $1.55 million PGA deferral credit balance resulting from

8 the 2012 PGA, over 15-months, October 1, 2013 to December

9 31, 2014. This PGA deferral credit balance results from

10 Docket AVU-.G-12-05, in which the Commission approved Staff's

11 proposal that approximately $1.55 million in un-refunded

12 credit balances be held back due to the Company's filing of

13 a "Notice of Intent to File a General Rate Case." The

14 Commission stated in Order 32651, on page 6, that "the

15 resulting $1.55 million un-refunded credit balance will help

16 mitigate potential rate increases and provide rate stability

17 for customers." This credit would reduce the overall bill

18 increase to customers effective October 1, 2013 from 2.0% to

19 0.3%.
20

21 IV. OTHER ELEMENTS OF THE STIPULATION
22 Q. Please explain the settlement terms relating to
23 the PCA authorized level of expenses.
Norwood, Di 25
Avista Corporation

1 A. The new level of power supply expense, retail load

2 and Clearwater Paper generation, for purposes of monthly PCA

3 calculations, are detailed in Attachment B of the

4 Stipulation and Settlement provided as Exhibit No. 1. The

5 Parties agree for settlement purposes to accept the

6 Company's normalized load forecast without specifically

7 accepting the weather normalization methodology or the

8 proposed Energy Efficiency Load Adjustment.

9
Q. Please explain the settlement terms relating to

10 Depreciation Rates.

11 A. The Parties have agreed to the updated electric

12 and natural gas depreciation rates as filed by the Company,

13 with all common/allocated plant depreciation rates,

14 including the new depreciation rates for transportation

15 equipment, effective January 1, 2013 to coincide with the

16 Company's Washington and Oregon jurisdictions; the remaining

17
direct Idaho plant depreciation rate changes would be

18 effective April 1, 2013.

19 Q. Please explain the settlement terms relating to

20
the after-the-fact earnings test for 2013 and 2014.

21 A. The Company agrees to an after-the-fact earnings

22 test, where it would refund to customers one-half of any

23 earnings in excess of the agreed-upon 9.8W ROE for each of

24 the years 2013 and 2014, to allay any concerns that the base
Norwood, Di 26
Avista Corporation
1 rate relief in April 1, 2013 and October 1, 2013 may allow
2 the Company to exceed its authorized return. The earnings
3 test would be based on actual, consolidated results for
4 Idaho electric and natural gas operations.
5 Q. Please explain the settlement terms relating to
6 the rate freeze / stay-out agreed to by the Parties.
7 A. The Parties agree that, in recognition of the two-
8 year rate plan covered by this Stipulation, Avista would not
9 file another electric or natural gas general rate case
10 before May 31, 2014, and while it may request an effective
11 date earlier than January 1, 2015, final approved new rates
12 would not go into effect prior to January 1, 2015. This
13 does not apply to tariff filings authorized by or
14 contemplated by the terms of the Power Cost Adjustment
15 (PCA), or the Purchased Gas Adjustment tariff (PGA), or
16 other miscellaneous filings.
17 Q. How does the Stipulation's two-year rate plan,
18 including the rate freeze / stay-out element, agreed to by
19 the Parties challenge Avista to manage its costs?
20 A. The two-year rate plan for the period 2013 and
21 2014 would only provide retail revenues sufficient to
22 provide Avista the opportunity to earn the return agreed to
23 by the Parties, if the Company undertakes aggressive cost
24 management measures now and going forward.
Norwood, Di 27
Avista Corporation

1 As explained in Avista's direct testimony, the Company

2
is experiencing significant increases in plant investment

3 and non-fuel O&M expenses required to serve its customers,

4 both of which are growing at a much faster pace than its

5 retail sales. Although we continue to take extensive

6 measures to ensure that the costs that we are incurring

7 represent the most cost-effective and reliable way to

8 continue to serve our customers, while preserving a high

9 level of customer satisfaction, we continue to experience

10 significant increases in annual operating expenses.

11 Avista has put into place additional cost-management

12 measures, which combined with the rate adjustments in the

13
Settlement, will provide the Company a reasonable

14 opportunity to earn the return agreed to in the Stipulation.

15 As an example, in October 2012, Avista's Board of Directors

16 approved the Company's Voluntary Severance Incentive Plan

17
(VSIP), which was implemented in December 2012. Through this

18 program, effective January 1, 2013 Avista reduced its number

19 of employees by 55.
20

21
V. RATE SPREAD & RATE DESIGN

22 Q. Please explain the settlement terms relating to

23 cost of service.
Norwood, Di 28
Avista Corporation
I A. For electric operations, the Company prepared a
2 cost of service analysis using a peak credit method of
3 classifying production costs, allocating 100% of
4 transmission costs to demand, and allocating transmission
5 costs on a twelve-month basis. For settlement purposes, the
6 Parties agreed to use a pro-rata allocation based on the

7 Company's proposed 15% move towards unity for purposes of

8 spreading the revised electric revenue requirement, while

9 not agreeing on any particular cost of service methodology.

10 For natural gas operations, the Company proposed that
11 all rate schedules be moved approximately 25% towards unity.

12 For settlement purposes, the Parties agreed to use a pro-
13 rata allocation of the Company's natural gas rate spread

14 percentages from its original filing for purposes of

15 spreading the revised revenue requirement, without agreement

16 on any particular cost of service methodology.

17 Q. How did the Stipulation address rate design?

18 A. For settlement purposes, the Parties have agreed

19 that the revenue requirement for each electric and natural

20 gas service schedule would be applied as a uniform
21 percentage increase to each volumetric energy rate, as

22 shown in Attachment C of the Stipulation and Settlement

23 provided as Exhibit No. 1, and there would be no change to
Norwood, Di 29
Avista Corporation

I the residential electric Schedule 1 and natural gas

2 Schedule 101 basic charges.

3 Attachment C of the Stipulation provides a summary of

4 the current and proposed rates and charges for electric and

5 natural gas service.

6 Q. Please explain how the Stipulation addresses rate

7 spread/rate design related to the electric and natural gas

8 base rate offsets effective October 1, 2013.

9 A. The Parties have agreed that the electric base

10 rate offset related to the BPA Settlement Revenues would be

11 spread to electric rate schedules on a uniform cents per

12 kWh basis, and the natural gas base rate offset related to

13 the 2012 PGA deferral credit balance of $1.55 million would

14 be spread to natural gas rate schedules on a uniform cents

15 per therm basis.

16 Attachment D of the Stipulation contains the form of

17 tariff related to the electric and natural gas offsets

18 agreed to by the Parties. A new electric rate schedule,

19 Schedule 97, would be used for purposes of passing through

20 to customers the electric offset. A new natural gas rate

21 schedule, Schedule 197, would be used for purposes of

22 passing through to customers the natural gas offset. Both

23 tariffs would expire on December 31, 2014.
Norwood, Di 30
Avista Corporation
I Any under- or over-refunded amounts relating to the
2 electric or natural gas offsets would be trued up in the
3 following year's Power Cost Adjustment (electric) or
4 Purchased Gas Cost Adjustment (natural gas) filings.
5
6 VI. CUSTOMER SERVICE PROGRAMS
7 Q. Does the Company have programs in place to
8 mitigate the impacts on customers of the proposed rate
9 increases?
10 A. Yes. We have a history of making it a priority
11 within our Company to maintain meaningful programs to assist
12 our customers that are least able to pay their energy bills.
13 We also have programs to assist our entire customer base,
14 i.e., not just our low-income customers. Some of the key
15 programs that we offer or support are as follows:
16 • DSM Energy Efficiency Programs and Funding. The
17 Company offers a broad array of energy efficiency
18 program measures that provide customers with increased
19 opportunity to manage their energy bills. In 2012,
20 Avista hosted two Energy Fairs, one in Lewiston, and
21 the other in Coeur d'Alene. Over 280 customers were in
22 attendance and received energy efficiency tips and kits
23 that included low cost/no cost ways to reduce energy
24 consumption.
25
26 • Project Share. Project Share is a voluntary program
27 allowing customers to donate funds that are distributed
28 through community action agencies to customers in need.
29 In addition to the Idaho customer contributions during
30 the 2011/2012 program year of $66,490, the Company also
31 contributed $69,421 (Idaho's share) to the program.
Norwood, Di 31
Avista Corporation
1

2 • Comfort Level Billing. The Company offers the option

3 for all customers to pay the same bill amount each

4 month of the year by averaging their annual usage.

5 Under this program, customers can avoid unpredictable

6 winter heating bills.
7

8 • Payment Arrangements. The Company's Contact Center

9 Representatives work with customers to set up payment

10 arrangements to pay energy bills.

11 • CARES Program. Customer Assistance Referral and

12 Evaluation Services provides assistance to special-

13 needs customers through access to specially trained

14
(CARES) representatives who provide referrals to area

15 agencies and churches for help with housing, utilities,

16 medical assistance, etc.
17

18 • Senior Energy Outreach: Avista has developed specific

19 strategic outreach efforts to reach our more vulnerable

20 customers (seniors and disabled customers) with bill

21 paying assistance and energy efficiency information

22 that emphasizes comfort and safety. Some examples of

23 this effort are as follows:
24

25 • Senior Publications: Avista has created a one-

26 page advertisement that has been placed in senior

27 resource directories and targeted senior

28 publications to reach seniors with information

29 about energy efficiency, Comfort Level Billing,

30 Avista CARES and energy assistance. A brochure

31 with the same information has also been created

32
for distribution through senior meal delivery

33 programs and other senior home-care programs.
34

35 • Senior Energy Workshops: With the help of

36 additional workshop presenters, 9 Senior Energy

37 Workshops were held during 2012 in Idaho. Over

38 393 seniors were reached and were given Senior

39 Energy Efficiency kits along with learning about

40 low-cost/no-cost ways to reduce energy use.
41
Norwood, Di 32
Avista Corporation
1 VI. CONCLUSION
2
Q. In conclusion, why is this Stipulation in the
3 public interest?
4 A. This Stipulation strikes a reasonable balance
5 between the interests of the Company and its customers,
6 including its low-income customers. As such, it represents
7 a reasonable compromise among differing interests and
8 points of view.
9 The terms of the Settlement agreement represent a two-
10 year rate plan designed to provide necessary retail
11 revenues. For its part, the Company will continue to
12 closely manage its costs during this two-year period. The
13 Parties have agreed that the Company has demonstrated the
14 need for revenue requirement increases for both its
15 electric and natural gas operations, thus providing
16 recovery of its costs over the two-year rate period.
17 Therefore, the Stipulation is designed to address the
18 multiple purposes of addressing the Company's revenue
19 requirement needs; minimizing the impact to customers from
20 changes in retail rates; providing rate certainty over the
21 two year period 2013-2014; and reducing the administrative
22 burden to all parties and the Commission associated with
23 this general rate case, as well as avoiding another rate
24 filing in 2013 for new rates in 2014. It also provides a
Norwood, Di 33
Avista Corporation

I form of price cap regulation under which the Company is

2 expected to manage its costs under the given rates to earn

3 a fair return.

4 In the final analysis, however, any settlement

5 reflects a compromise in the give-and-take of negotiations.

6 The Commission, therefore, has before it a Stipulation that

7 is supported by sound analysis and supporting evidence, the

8 approval of which is in the public interest.

9 Q. Does this conclude your pre-filed direct

10 testimony?

11 A. Yes, it does.
Norwood, Di 34
Avista Corporation
. .
DIRECT TESTIMONY OF
KELLY 0. NORWOOD
IN SUPPORT OF THE
STIPULATION AND SETTLEMENT
Case Nos. AVU-E-12-08 & AVU-G-12-07
EXHIBIT 1
REVISED - March 1, 2013
David J. Meyer, Esq.
Vice President and Chief Counsel of
Regulatory and Governmental Affairs
Avista Corporation
1411 E. Mission Avenue
P.O. Box 3727
Spokane, Washington 99220
Phone: [phone], Fax: [phone]
Karl Klein
Weldon Stutzman
Deputy Attorneys General
Idaho Public Utilities Commission Staff
P.O. Box 83720
Boise, ID 83720-0074
Phone: [phone], Fax: [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
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 )
CASE NOS. AVU-E-12-08
AVU-G- 12-07
STIPULATION AND SETTLEMENT
This Stipulation is entered into by and among Avista Corporation, doing business as
Avista Utilities ("Avista" or "Company"), the Staff of the Idaho Public Utilities Commission
("Staff), Clearwater Paper Corporation ("Clearwater"), Idaho Forest Group, LLC ("Idaho
Forest") and the Idaho Conservation League ("Conservation League")'. These entities are
collectively referred to as the "Parties," and represent several parties in the above-referenced
cases that participated in settlement discussions. The Parties understand this Stipulation is
subject to approval by the Idaho Public Utilities Commission ("IPUC" or the "Commission").
'The Community Action Partnership Association of Idaho ("CAPAI") participated in settlement discussions and is
continuing to review its position with regard to the Settlement, 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.
STIPULATION AND SETTLEMENT - AVU-E-12-08 & AVU-G-12-07 Page 1
I. INTRODUCTION
1. The terms and conditions of this Stipulation are set forth herein. The Parties agree
that this Stipulation represents a fair, just and reasonable compromise of all the issues raised in
the proceeding and that this Stipulation and its acceptance by the Commission represents a
reasonable resolution of the multiple issues identified in these cases. The Parties, therefore,
recommend that the Commission, in accordance with RP 274, approve the Stipulation and all of
its terms and conditions without material change or condition.
II. BACKGROUND
2.On October 11, 2012, Avista filed an Application with the Commission for
authority to increase revenue from electric and natural gas service in Idaho by 4.6% and 7.2%,
respectively. If approved, the Company's revenues for electric base retail rates would have
increased by $11.4 million annually; Company revenues for natural gas service would have
increased by $4.6 million annually. The Company requested an effective date of April 1, 2013
for its proposed electric and natural gas rate increases. By Order No. 32689, dated December 4,
2012, the Commission suspended the proposed schedules of rates and charges for electric and
natural gas service.
3.Petitions to intervene in this proceeding were filed by Clearwater, Idaho Forest,
CAPAI, the Idaho Conservation League, and the Snake River Alliance. By various orders, the
Commission granted these interventions. See, IPUC Order Nos. 32678, 32680 and 32687.
4.Settlement conferences were noticed and held in the Commission offices on
January 17 and 24, 2013, and were attended by signatories to this Stipulation; further discussions
ensued. Based upon the settlement discussions among the Parties, as a compromise of positions
STIPULATION AND SETTLEMENT - AVU-E-12-08 & AVU-G-12-07 Page 2
in this case, and for other consideration as set forth below, the Parties agree to the following
terms:
III. TERMS OF THE STIPULATION AND SETTLEMENT
5. Overview of Settlement and Revenue Requirement. The Parties agree that Avista
should be allowed to implement revised tariff schedules designed to recover the following
revenue requirement in two steps, as summarized in Attachment A, and below:
Electric
Step 1: April 1. 2013
a. No electric base rate change effective April 1, 2013, instead of the proposed
4.6%, or $11.393 million.
Step 2: October 1. 2013
a.Overall electric base rate increase of 3.1% (3.2% in billed rates) or $7.825 million
effective October 1, 2013.
b.Offsets - Apply $3.865 million for rate mitigation purposes (the BPA Parallel
Operation Settlement 2), and amortize that offset over 15 months, from October 1,
2013 to December 31, 2014.
C. Net overall bill increase to customers of 1.9% effective October 1, 2013.
Summary of Electric Rate Changes
Billing Rate Net Billing
Change Oflet Rate Change
April 1, 2013 0.0% 0.0% 0.0%
October 1, 2013 3.2% -1.3% 1.9%
2 The BPA Settlement Revenue of $3.865 million represents the Idaho customers' share of $12.224 million (system)
for the past use of Avista's transmission system for the period January 2005 through February 2013. In December
2012, Avista and Bonneville reached a settlement that pertains to the use of Avista's transmission system by
Bonneville. Avista and Bonneville each own and operate transmission systems that are interconnected at various
points. Between June 1998 and December 2009, Bonneville integrated four generation projects onto its 115 kV
transmission system in the Walla Walla, Washington area. Bonneville sold transmission capacity to wind projects
totaling 336 MW. The transmission path for these four projects follows a single Bonneville line that has a rated
capacity of only 203 MW. Upon Avista's discovery of this situation, Avista asserted that Bonneville requires the
use of up to 133 MW of parallel capacity support through the Avista system in order to fulfill Bonneville's
transmission service obligations for these wind projects. The Settlement Agreement was intended to resolve the
issue of compensation to Avista for the prior use of its transmission system, as well as provide Bonneville with
continuing cost-effective parallel capacity support in lieu of constructing additional transmission facilities at this
point in time. Avista anticipates FERC approval of the Settlement in February 2013, after which Avista will bill
Bonneville.
STIPULATION AND SETTLEMENT —AVU-E-12-08 & AVU-G-12-07 Page 3
Natural Gas
Step 1: April 1, 2013
a. Overall natural gas base rate increase of 4.9% (5.0% in billed rates) or $3.115
million, instead of the proposed 7.2%, or $4.561 million, effective April 1, 2013.
Step 2: October 1, 2013
a.Overall natural gas base rate increase of 2.0% (2.0% in billed rates) or $1.330
million effective October 1, 2013.
b.Offsets - Apply $1.550 million PGA deferral credit balance from 2012 PGA' to
partially offset the base rate increase, amortized over 15 months, October 1, 2013
to December 31, 2014.
C. Net overall bill impact to customers of 0.3% effective October 1, 2013.
Summary of Natural Gas Rate Changes
Billing Rate Net Billing
Change Oflet Rate Change
April 1, 2013 5.0% 0.0% 5.0%
October 1, 2013 2.0% -1.7% 0.3%
6. Cost of Capital. The Settling Parties agree to a 9.8 percent return on equity, with
a 50.0 percent common equity ratio, and adopt the capital structure and resulting rate of return as
set forth below:
Capital ProForma ProForma
Component Structure Cost Weighted Cost
Total Debt 50.00% 6.01% 3.01%
Common Equity 50.00% 9.80% 4.90%
Total 100.00% 7.91%
In Docket AVU-G-12-05, 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."
STIPULATION AND SETTLEMENT - AVU-E-12-08 & AVU-G-12-07 Page 4
A. ELECTRIC
7. Overview of Electric Revenue Requirement (April 1. 2013). Below is a summary
table and descriptions of the electric revenue requirement components agreed to by the Parties
for April 1, 2013:
SUMMARY TABLE OF ADJUSTMENTS TO ELECTRIC REVENUE REQUIREMENT
EFFECTIVE APRIL 1, 2013
000s of Dollars
Amount as Filed:
Adjustments:
a.) Cost of Capital
b.) Remove 2013 Capital Additions (Delay to October 1, 2013)
c.) Remove 2013 Expenses: Delay Recovery to October 1, 2013 Rate Change
i.Major Generation O&M
ii.Information Services & Technology
iii.CS2 Levelized Return
iv.Non-Exec Labor
d.) Remove 2013 Property Tax Expense
e.) Remove Officer Incentive and CPI escalation
C) Two-Year Amortization of Reardan
g.)Include Palouse Wind in PCA until in base rates in 2015 (900/o/10% sharing)
h.)Miscellaneouse Adjustments: Two-Year Amortization of Booz Consulting
costs, Oasis Training, Abandoned Projects & Depreciation Study expense
Adjusted Amounts Effective April 1, 2013
Revenue
Requirement Rate Base
$ 11,393 $ 639,030
$ (5,517)
$ (1,117) $ (1,582)
$ (926)
$ (318)
$ (38)
$ (426)
$ (428)
$ (187)
$ 878
$ (3,139)
$ (175)
$ - $ 637
a.Cost of Capital. As previously described (see Paragraph 6 above).
b.Remove 2013 Capital Additions. Reflects total depreciation expense and rate
base, net of accumulated depreciation and accumulated deferred income tax,
as of year-end December 31, 2012. Moves 2013 capital additions to October
1, 2013 rate change.
c.Remove 2013 Expenses: Delay Recovery to October 1, 2013 Rate Change.
i. Major Generation O&M. Removes the 2013 incremental non-
labor generation plant operation and maintenance (O&M) expense
related to the Company's thermal generation plant at Kettle Falls,
STIPULATION AND SETTLEMENT - AVU-E- 12-08 & AVU-G- 12-07 Page 5
and its hydro generation plants, to be included in the October 1,
2013 rate change.
ii.Information Services & Technology. Removes the 2013
incremental information service and technology expenses, related
mainly to the Company's replacement of the Company's Customer
Service Information System, and increased costs to support various
business processes, application support, additional security
requirements, annual contractual agreements and maintenance and
license fees, to be included in the October 1, 2013 rate change.
iii.CS2 Levelized Return. Removes the 2013 incremental
amortization of the deferred levelized return related to the 10-year
deferral of return on the Coyote Springs 2 (C52) investment, to be
included in the October 1, 2013 rate change.
iv.Non-Exec Labor. Removes the 2013 incremental non-executive
labor increases, to be included in the October 1, 2013 rate change.
d.2013 Property Tax. Removes the 2013 incremental property tax expense,
adjusting property tax expense to December 31, 2012 levels.
e.Remove Officer Incentive and CPI Escalation. Removes officer portion of
incentives and removes the Consumer Price Index adjustment on incentives
included in the Company's original filing.
f.Two-Year Amortization of Reardan. See Paragraph 10 below for further
information.
g.Include Palouse Wind in PCA until Reflected in Base Rates in 2015. See
Paragraph 9 below for further information.
STIPULATION AND SETTLEMENT —AVU-E-12-08 & AVU-G-12-07 Page 6
h. Miscellaneous Adjustments. Includes a two-year amortization of Booz & Co.
consulting fees, thereby reducing test period expenses, and removes certain
other amounts related to OASIS training, abandoned projects and depreciation
study expenses.
8. Overview of Electric Revenue Requirement (October 1. 2013). Below is a
summary table and descriptions of the Electric revenue requirement components agreed to by the
Parties for October 1, 2013:
SUMMARY TABLE OF ELECTRIC REVENUE REQUIREMENT
EFFECTIVE OCTOBER 1, 2013
000s of Dollars
Amounts Effective April 1, 2013
Adjustments to October!, 2013 Rate Change:
2013 Capital Additions
2014 Capital Additions
Add 2013 Expenses
I. Major Generation O&M
ii.Information Services & Technology
iii.CS2 Levelized Return
iv.Non-Exec Labor
Adjusted Amounts Effective October 1, 2013
Revenue
Requirement Rate Base
$ - $ 637,448
$ 5,488 $ 20,705
$ 629 $ 888
$ 926
$ 318
$ 38
$ 426 -
$ 7,825
a.2013 Capital Additions. Includes 2013 capital additions, reflecting total
depreciation expense and rate base, net of accumulated depreciation and
accumulated deferred income tax, as of year-end December 31, 2013.
b.2014 Capital Additions. Includes certain 2014 capital additions, including
depreciation expense and rate base, net of accumulated depreciation and
accumulated deferred income tax, to represent an agreed-upon level of rate
base.
c.2013 Expenses:
STIPULATION AND SETTLEMENT - AVU-E-12-08 & AVU-G-12-07 Page 7
i.Major Generation O&M. Includes the 2013 incremental non-labor
generation plant O&M expense discussed above in Paragraph
7(c)(i).
ii.Information Services & Technology. Includes the 2013
incremental information service and technology expenses
discussed above in Paragraph 7(c)(ii).
iii.CS2 Levelized Return. Includes the 2013 incremental
amortization of the deferred CS2 levelized return discussed above
in Paragraph 7(c)(iii).
iv.Non-Exec Labor. Includes the 2013 incremental non-executive
labor increases discussed above in Paragraph 7(c)(iv).
9.Palouse Wind. The Parties agree that recovery of costs related to the Palouse
Wind Power Purchase Agreement ("PPA") will be included in the PCA, subject to the current
sharing (90% customer, 10% Company) until it is included in base rates as part of the
implementation of new rates from the Company's next general rate case anticipated in 2015.
10.Reardan Wind Site Deferral. The Parties agree to amortize the Reardan Wind
Project deferred balance of $1.747 million over a two-year period beginning April 1, 2013.
11.Amortization of 2013 Coyote Springs 2/Colstri12 Maintenance Deferral. The
Parties agree that the amount deferred in 2013 related to the Company's O&M costs of its
Coyote Springs 2 (C S2) natural gas-fired generating plant and its fifteen (15) percent ownership
In May 2008, Avista purchased the Reardan Wind Project Site from Energy Northwest, the then-current developer,
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 Plan. Avista later chose to delay the construction of the Reardan
project and take advantage of much-lower costs for wind projects that emerged in 2011 (Palouse Wind). Avista
recorded $4.0 million of site acquisition and preparation costs, of which approximately $1.7 million is Idaho's share.
This includes approx. $0.37 million in AFUDC in accordance with Order No. 30611 (Case No. AVU-E-08-04)
STIPULATION AND SETTLEMENT - AVU-E-12-08 & AVU-G-12-07 Page 8
share of the Colstrip 3 & 4 coal-fired generating plants will be amortized over three years,
beginning with the implementation of new base rates resulting from the Company's next general
rate case filing.5
B. NATURAL GAS
12. Overview of Natural Gas Revenue Requirement (April 1. 2013). Below is a
summary table and descriptions of the Natural Gas revenue requirement components agreed to
by the Parties:
SUMMARY TABLE OF ADJUSTMENTS TO NATURAL GAS REVENUE REQUIREMENT
EFFECTIVE APRIL 1, 2013
000s of Dollars
Revenue
Requirement Rate Base
Amount as Filed: $ 4,561 $ 110,930
Adjustments:
a.) Cost of Capital $ (957)
b.) Remove 2013 Capital Additions (Delay to October 1, 2013) $ (22) $ 1,309
c.) Remove 2013 Expenses: Delay Recovery to October 1, 2013 Rate Change
I. Information Services & Technology $ (42)
ii. Non-Exec Labor $ (215)
d.) Remove 2013 Property Tax Expense $ (84)
e.) Remove Officer Incentive and CPI escalation $ (50)
L) Miscellaneouse Adjustments: Two-Year Amortization of Booz Consulting $ (76)
costs, Injuries & Damages, Abandoned Projects & Depreciation Study
expense
Adjusted Amounts Effective April 1, 2013 $ 3,115 $ 112,239
a.Cost of Capital. As previously described (see Paragraph 6 above).
b.Remove 2013 Capital Additions. Reflects total depreciation expense and rate
base, net of accumulated depreciation and accumulated deferred income tax,
Per Order No. 32371 in Case No. AVU-E-1 1-01, in order to address the large variability in year-to-year O&M
costs, beginning in 2011, the Company was allowed to defer changes in O&M costs related to its Coyote Springs 2
(C52) natural gas-fired generating plant located near Boardman, Oregon, and its fifteen (15) percent ownership
share of the Colstrip 3 & 4 coal-fired generating plants located in southeastern Montana. The Company compares
actual, non-fuel, O&M expenses for the Coyote Springs 2 and Colstrip 3 & 4 plants with the amount of expenses
authorized for recovery in base rates in the applicable deferral year, and defers the difference from that currently
authorized. The deferral occurs annually, with no carrying charge, with deferred costs being amortized over a three-
year period, beginning in January of the year following the period costs are deferred.
STIPULATION AND SETTLEMENT - AVU-E-12-08 & AVU-G-12-07 Page 9
as of year-end December 31, 2012. Moves certain 2013 capital additions to
the October 1, 2013 rate change.6
c. Remove 2013 Expenses: Delay Recovery to October 1, 2013 Rate Change.
i.Information Services & Technology. Removes the 2013
incremental information service and technology expenses as
discussed above, to be included in the October 1, 2013 rate change.
ii.Non-Exec Labor. Removes the 2013 incremental non-executive
labor increases as discussed above, to be included in the October 1,
2013 rate change.
d. 2013 Property Tax. Removes the 2013 incremental property tax expense,
adjusting property tax expense to December 31, 2012 levels.
e. Remove Officer Incentive and CPI Escalation. Removes officer portion of
incentives and removes the Consumer Price Index adjustment on incentives
included in the Company's original filing.
f. Miscellaneous Adjustments. Includes a two-year amortization of Booz & Co.
consulting fees, thereby reducing test period expenses, and removes certain
other amounts related to injuries and damages, abandoned projects and
depreciation study expenses.
6 In the Company's filed case, inclusion of total net plant, including accumulated depreciation and accumulated
deferred income tax on an average-of-monthly-average basis for 2013, had the effect of reducing rate base by $ 1.309
million and increasing revenue requirement associated with a net increase in depreciation expense by $22,000. This
is due to the original filed adjustment that depreciated all plant, including the plant in service balance at December
31, 2012, to the AMA balance at December 31, 2013. The additional accumulated depreciation on plant in service
at December 31, 2012 was greater than the net plant additions in 2013 on an AMA basis, which had an overall
impact of reducing net rate base.
STIPULATION AND SETTLEMENT - AVU-E-12-08 & AVU-G-12-07 Page 10
13. Overview of Natural Gas Revenue Requirement (October 1. 2013). Below is a
summary table and descriptions of the Natural Gas revenue requirement components agreed to
by the Parties:
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
Adjustments to October!, 2013 Rate Change:
a.)2013 Capital Additions
b.)Add 2013 Expenses
i.Information Services & Technology
ii.Non-Exec Labor
Adjusted Amounts Effective October 1, 2013
$ 1,073 $ 3,8311
$ 42
$ 215
$ 1,330 $ 11
a.2013 Capital Additions. Includes certain 2013 capital additions, including
depreciation expense and rate base, net of accumulated depreciation and
accumulated deferred income tax, to represent an agreed-upon level of rate
base.
b.2013 Expenses:
i.Information Services & Technology. Includes the 2013
incremental information service and technology expenses
discussed above in Paragraph 12(c)(i).
ii.Non-Exec Labor. Includes the 2013 incremental non-executive
labor increases discussed above in Paragraph 12(c)(ii).
STIPULATION AND SETTLEMENT - AVU-E-12-08 & AVU-G-12-07 Page 11
C. OTHER SETTLEMENT COMPONENTS
14.PCA Authorized Level of Expense. The new level of power supply expense, retail
load and Clearwater Paper generation, and the April 1, 2013 and October 1, 2013 Load Change
Adjustment Rates resulting from the April 1, 2013 and October 1, 2013 settlement revenue
requirements for purposes of the monthly PCA mechanism calculations, are detailed in
Attachment B. The parties agree for the purpose of Settlement in this case to accept the
Company's normalized load forecast without specifically accepting the weather normalization
methodology or the proposed Energy Efficiency Load Adjustment.
15.Depreciation Rates. The Parties have agreed to the updated electric and natural
gas depreciation rates as filed by the Company, with all common/allocated plant depreciation
rates, including the new depreciation rates for transportation equipment, effective January 1,
2013 to coincide with the Company's Washington and Oregon jurisdictions, with the remaining
direct Idaho plant depreciation rate changes effective April 1, 2013.
16.Earnings Test. The Company agrees to an after-the-fact earnings test, where it
would refund to customers one-half of any earnings in excess of the 9.8% ROE for each of the
years 2013 and 2014, to allay any concerns that the base rate relief in April 1, 2013 and October
1, 2013 may allow the Company to exceed its authorized return. The earnings test would be
based on actual, consolidated results for Idaho electric and natural gas operations.
17.Rate Freeze/Stay Out. The Parties agree that, in recognition of the two-year rate
plan covered by this Stipulation, Avista will 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 will 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.
STIPULATION AND SETTLEMENT —AVU-E-12-08 & AVU-G-12-07 Page 12
D. COST OF SERVICE/RATE SPREAD/RATE DESIGN
18. Cost of Service. For electric operations, the Company prepared an analysis using
a peak credit method of classifying production costs, allocating 100% of transmission costs to
demand, and allocating transmission costs on a twelve-month basis. For settlement purposes, the
Parties agreed to use a pro-rata allocation based on the Company's proposed 15% move towards
unity for purposes of spreading the revised electric revenue requirement, while not agreeing on
any particular cost of service methodology.
For natural gas operations, the Company proposed that all rate schedules be moved
approximately 25% towards unity. For settlement purposes, the Parties agreed to use a pro-rata
allocation of the Company's natural gas rate spread percentages from its original filing for
purposes of spreading the revised revenue requirement.

19. Rate Spread/Rate Design (Base Rate Changes).
(a)As indicated above, the Parties agreed that the increase in base revenues
would be spread to all electric and natural gas rate schedules on a pro-rata allocation of
the Company's rate spread percentages from its original filing.
(b)The Parties agree that the revenue requirement for each electric and natural
gas service schedule will be applied as a uniform percentage increase to each volumetric
energy rate as shown in Attachment C. The Parties agree that there will be no change to
Schedule 1 and Schedule 101 basic charges.
(c)Attachment C provides a summary of the current and revised rates and
charges (as per the Settlement) for electric and natural gas service.

20. Rate Spread/Rate Design (Offsets).
STIPULATION AND SETTLEMENT - AVU-E-12-08 & AVU-G-12-07 Page 13
(a)The Parties have agreed that the electric base rate offset related to the BPA
Settlement Revenues will be spread to electric rate schedules on a uniform cents per kWh
basis.
(b)The Parties have agreed that the natural gas base rate offset related to the
2012 PGA deferral credit balance of $1.55 million will be spread to natural gas rate
schedules on a uniform cents per therm basis.
(c)Attachment D contains the form of tariff related to the electric and natural gas
offsets agreed to by the Parties. A new electric rate schedule, Schedule 97, will be used
for purposes of passing through to customers the electric offset. A new natural gas rate
schedule, Schedule 197, will be used for purposes of passing through to customers the
natural gas offset. Both tariffs would expire on December 31, 2014.
(d)Any under- or over-refunded amounts relating to the Electric or Natural Gas
offsets will be trued up in the following year's Power Cost Adjustment (electric) or
Purchased Gas Cost Adjustment (natural gas).
21. Resulting Percentage Increase by Electric Service Schedule. The following tables
reflect the agreed-upon percentage increase by schedule for electric service 7:
Electric Increase Percentage by Schedule - April 1, 2013
Rate Schedule
Increase in Base
Rates
Net Increase in
Billing Rates
Residential Schedule 1 0.0% 0.0%
General Service Schedule 11/12 0.0% 0.0%
Large General Service Schedule 21/22 0.0% 0.0%
Extra Large General Service Schedule 25 0.0% 0.0%
Clearwater Paper Schedule 25P 0.0% 0.0%
Pumping Service Schedule 31/32 0.0% 0.0%
Street & Area Lights Schedules 0.0% 0.0%
Overall 0.0% 0.0%
Avista will file both electric and natural gas conforming tariffs related to the October 1, 2013 rate changes with the
Commission on or before August 30, 2013 for the Commission's review and approval.
STIPULATION AND SETTLEMENT - AVU-E-12-08 & AVU-G-12-07 Page 14
Electric Increase Percentage by Schedule - October 1, 2013
Rate Schedule
Increase in Base
Rates
Net Increase in
Billing Rates*
Residential Schedule 1 3.5% 2.6%
General Service Schedule 11/12 2.8% 1.9%
Large General Service Schedule 21/22 3.3% 2.1%
Extra Large General Service Schedule 25 2.7% 1.0%
Clearwater Paper Schedule 25P 2.3% 0.4%
Punqing Service Schedule 31/32 3.9% 2.9%
Street& Area Lights Schedules 3.1% 2.7%
Overall 3.1% 1.9%
* Net Increase includes the effects of the proposed changes in Schedule 97 (BPA
Adjustment) and the General Rate Increase, all effective on October 1, 2013.
22. Resulting Percentage Increase by Natural Gas Service Schedule. The following
tables reflect the agreed-upon percentage increase by schedule for natural gas service:
Natural Gas Increase Percentage by Schedule - April 1, 2013
Rate Schedule
Increase in Base
Rates
Net Increase in
Billing Rates
General Service Schedule 101 5.3% 5.4%
Large General Service Schedule 111/112 3.8% 3.9%
Interruptible Sales Service Schedule 131/132 4.0% 4.0%
Transportation Service Schedule 146 8.7% 8.7%
Overall 4.9% 5.0%
Natural Gas Increase Percentage by Schedule - October 1, 2013
Rate Schedule
Increase in Base
Rates
Net Increase in
Billing Rates**
General Service Schedule 101 2.1% 0.6%
Large General Service Schedule 111/1 12 1.6% -0.5%
Interruptible Sales Service Schedule 131/132 1.4% -1.4%
Transportation Service Schedule 146 3.5% 3.5%
Overall 2.0% 0.3%
** Net Increase includes the effects of the proposed changes in Schedule 197 (PGA) and
the General Rate Increase, all effective on October 1, 2013.
STIPULATION AND SETTLEMENT -AVU-E-l2-08 & AVU-G-12-07 Page 15
IV. OTHER GENERAL PROVISIONS
23.The Parties agree that this Stipulation represents a compromise of the positions of
the Parties in this case. As provided in RP 272, other than any testimony filed in support of the
approval of this Stipulation, and except to the extent necessary for a Party to explain before the
Commission its own statements and positions with respect to the Stipulation, all statements made
and positions taken in negotiations relating to this Stipulation shall be confidential and will not
be admissible in evidence in this or any other proceeding.
24.The Parties submit this Stipulation to the Commission and recommend approval
in its entirety pursuant to RP 274. Parties shall support this Stipulation before the Commission,
and no Party shall appeal a Commission Order approving the Stipulation or an issue resolved by
the Stipulation. If this Stipulation is challenged by any person not a party to the Stipulation, the
Parties to this Stipulation reserve the right to file testimony, cross-examine witnesses and put on
such case as they deem appropriate to respond fully to the issues presented, including the right to
raise issues that are incorporated in the settlement terms embodied in this Stipulation.
Notwithstanding this reservation of rights, the Parties to this Stipulation agree that they will
continue to support the Commission's adoption of the terms of this Stipulation.
25.If the Commission rejects any part or all of this Stipulation or imposes any
additional material conditions on approval of this Stipulation, each Party reserves the right, upon
written notice to the Commission and the other Parties to this proceeding, within 14 days of the
date of such action by the Commission, to withdraw from this Stipulation. In such case, no Party
shall be bound or prejudiced by the terms of this Stipulation, and each Party shall be entitled to
seek reconsideration of the Commission's order, file testimony as it chooses, cross-examine
witnesses, and do all other things necessary to put on such case as it deems appropriate. In such
case, the Parties immediately will request the prompt reconvening of a prehearing conference for
STIPULATION AND SETTLEMENT —AVU-E-12-08 & AVU-G-12-07 Page 16
purposes of establishing a procedural schedule for the completion of the case. The Parties agree
to cooperate in development of a schedule that concludes the proceeding on the earliest possible
date, taking into account the needs of the Parties in participating in hearings and preparing
testimony and briefs.
26.The Parties agree that this Stipulation is in the public interest and that all of its
terms and conditions are fair, just and reasonable.
27.No Party shall be bound, benefited or prejudiced by any position asserted in the
negotiation of this Stipulation, except to the extent expressly stated herein, nor shall this
Stipulation be construed as a waiver of the rights of any Party unless such rights are expressly
waived herein. Execution of this Stipulation shall not be deemed to constitute an
acknowledgment by any Party of the validity or invalidity of any particular method, theory or
principle of regulation or cost recovery. No Party shall be deemed to have agreed that any
method, theory or principle of regulation or cost recovery employed in arriving at this Stipulation
is appropriate for resolving any issues in any other proceeding in the future. No findings of fact
or conclusions of law other than those stated herein shall be deemed to be implicit in this
Stipulation.
28.The obligations of the Parties under this Stipulation are subject to the
Commission's approval of this Stipulation in accordance with its terms and conditions and upon
such approval being upheld on appeal, if any, by a court of competent jurisdiction.
29.This Stipulation may be executed in counterparts and each signed counterpart
shall constitute an original document.
STIPULATION AND SETTLEMENT - AVU-E-12-08 & AVU-G-12-07 Page 17
DATED this C day of February, 2013.
Avista Corporation
By: "
'LT1ivid J. Mevcr
Attorney for Avista corporation
Idaho Public Utilities Conunission Stall
By:
Karl Klein
Weldon Stutzman
Deputy Attorneys General
Clearwater Paper Corporation
13v:_________
Peter Richardson
Attorney for Clearwater Paper
Idaho Conservation League
By:
Benjamin J. Otto
Attorney for ICL
Idaho Forest Group
By:
Dean J. Miller
Attorney for Idaho Forest Group LLC
STIPULATION AND SETTLEMENT * AVU-E-12-O8 & AVU-0-12-07 Page 18
Attorney for Avista Corporation Weidon Stutzmn
DCputy Attorneys General
Clearwater Paper Corporation Idaho Forest Group
By: iM
Peter Richardson Dean J Miller
Attorney for Clearwater Paper Attorney for Idaho Forest Group LLC
Idaho Conservation League
By
Benjamin J Otto
Attorney for ICL
STIPULATION AND SETTLEMENT —AVU-E-12-08 & AVU-G-12-07 Page 18
DATE!) this day of February, 2013.
Avista Corporation
By:
David J. Meyer
Attorney for Avista Corporation
Idaho Public Utilities Commission Staff
By:
Karl Klein
Weldon Stutzman
Deputy Attorneys General
Paper
Peter Ri hardson
Attorney for Clearwater Paper
Idaho Conservation League
Benjamin J. Otto
Attorney for ICL
Idaho Forest Group
By:
Dean J. Miller
Attorney for Idaho Forest Group LLC
STIPULATION AND SETTLEMENT - AVU-E-12-08 & AVU-G-12-07 Page 18
DATED this j day of February, 2013.
Avista Corporation Idaho Public Utilities Commission Staff
By:
David J. Meyer Karl Klein
Attorney for Avista Corporation Weldon Stutzman
Deputy Attorneys General
Clearwater Paper Corporation Idko o •st
By: By
Peter Richardson Dean J. Miller
Attorney for Clearwater Paper Attorney for Idaho Forest Group LLC
Idaho Conservation League
By:
Benjamin J Otto
Attorney for ICL
STIPULATION AND SETTLEMENT - AVU-E-12-08 & AVU-G-12-07 Page 18
DATED this ,2 1 of February, 2013.
Avista Corporation Idaho Public Utilities Commission Staff
By:_, By:__________
David J. Meyer Karl Klein
Attorney for Avista Corporation Weldon Stutzrnan
Deputy Attorneys General
Clearwater Paper Corporation
By:________
Peter Richardson
Attorney for Clearwater Paper
Idaho Conservation League
By:% .
Benjamin I Otto
Attorney for ICL
Idaho Forest Group
By: -
Dean I Miller
Attorney for Idaho Forest Group LLC
STIPULATION AND SETTLEMENT - AVU-E-1 2-08 & AVU-G- 12-07 Page 18
STIPULATION AND SETTLEMENT
Case Nos. AVU-E-12-08 & AVU-G-12-07
ATTACHMENT A
Avista Utilities
Idaho Rate Adjustments Electric
RESIDENTIAL GENERAL SVC. LG. GEN. SVC. EX LG GEN SVC CLEARWATER PUMPING ST & AREA LTG
Effective April 1, 2013 TOTAL SCHEDULE 1 SCH. 11,12 SCH. 21,22 SCHEDULE 25 SCHEDULE 25P SCH. 31,32 SCH. 41-49
1 Total Billed Revenue $ 245,924,000 $ 96,390,000 $ 32,597,000 $ 51,597,000 $ 16,024,000 $ 41,005,000 $ 4,867,000 $ 3,444,000
2 Revenue Changes
3 GRC Increase 1$ - I $ - $ - $ - $ - $ - $ - $ -
4 Total Revenue Change $ - $ - $ - $ - $ $ - $ - $ -
5
6 Percentaee Chanses
7 GRC increase 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
8 Total Billed Percentage Change 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
9
10
11
12
13
14
15
16 Effective October 1. 2013

0.0% 0.0%

0.0% 0.0%
17 Total Billed Revenue $ 245,924,000 $ 96,390,000 $ 32,597,000 $ 51,597,000 $ 16,024,000 $ 41,005,000 $ 4,867,000 $ 3,444,000
18 Revenue Chanees
19 GRC Increase * $ 7,825,000 $ 3,532,000 $ 920,000 $ 1,714,000 $ 434,000 $ 928,000 $
20 BPA Reduction (15 Month Amortization) ** $ (3,058,000) $ (1,024,000) $ (301,000) $ (614,000) $ (273,000) $ (782,000) $
21 Total Revenue Change $ 4,767,000 $ 2,5081000 $ 619,000 $ 1,100,000 $ 161,000 $ 146,000 $
22
23 Percentage Changes
190,000 $ 107,000
(51,000) $ (13,000)
24 GRC Increase 3.2% 3.7% 2.8% 3.3% 2.7% 2.3% 3.9% 3.1%
25 BPA Reduction -1.3% -1.1% -0.9% -1.2% -1.7% -1.9% -1.0% -0.4%
26 Total Billed Percentage Change 1.9% 2.6% 1.9% 2.1% 1.0% 0.4% 2.9% 2.7%
27
28
29 * Utilizes a pro-rata allocation of the Company's electric rate spread percentage from its original filing for purposes of spreading the revised revenue requirement.
30 ** The BPA settlement benefit of $3.865 million amortized over 15 months is equal to $3.058 million annually. It will expire @ 12/31/14.
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
Attachment A Page 1 of 2
L
Avista Utilities Natural Gas
Idaho Rate Adjustments
GEN SERVICE LRG GEN SVC INTERRUPTIBLE TRANSPORT SPECIAL
Effective April 1. 2013 TOTAL SCHEDULE 101 SCH. 111&112 SCH. 131&132 SCHEDULE 146 CONTRACTS
1 Total Billed Revenue $ 62,090,000 $46,896,000 $14,607,000 $201,000 $289,000 $97,000
2 Revenue Changes
3 GRC Increase * $ 3,114,740 $ 2,512,740 $ 569,000 $ 8,000 $ 25,000 $ -
4 Total Revenue Change $ 3,114,740 $ 2,512,740 $ 569,000 $ 81000 $ 25,000 $ -
5
6 Percentage Chances
7 GRC Increase 5.0% 5.4% 3.9% 4.0% 8.7% 0.0%
8 Total Billed Percentage Change 5.0% 5.4% 3.9% 4.0% 8.7% 0.0%
9
10
11
12
13
14 Effective October 1, 2013
15 Total Billed Revenue $ 65,204,740 $ 49,408,740 $ 15,176,000 $ 209,000 $ 314,000 $ 97,000
16 Revenue Changes
17 GRC Increase * $ 1,330,000 $ 1,073,000 $ 243,000 $ 3,000 $ 11,000 $ -
18 PGA Reduction (15 Month Amortization) ** $ (1,131,000) $ (799,000) $ (326,000) $ (6,000) $ - $ -
19 Total Revenue Change $ 199,000 $ 274,000 $ (83,000) $ (3,000) $ 11,000 $ -
20
21 Percentage Changes
22 GRC Increase 2.0% 2.2% 1.6% 1.4% 3.5% 0.0%
23 PGA Reduction -1.7% -1.6% -2.1% -2.9% 0.0% 0.0%
24 Total Billed Percentage Change 0.3% 0.6% -0.5% -1.4% 3.5% 0.0%
25
26 * Utilizes a pro-rata allocation of the Company's natural gas rate spread percentages from its original filing for purposes of spreading the revised
27 revenue requirement.
28 ** The PGA deferral of $1.55 million amortized over 15 months is equal to $1.31 million annually. It will expire @ 12/31/14.
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
AttachmentA Page 2 of 2
. .
STIPULATION AND SETTLEMENT
Case Nos. AVU-E-12-08 & AVU-G-12-07
ATTACHMENT B
REVISED - March 1, 2013
Avista Corp
Pro forma January - December
PCA Authorized Expense and Retail Sales
PCA Authorized Power Supply Expense - System Numbers (1)
Ipisi January February March April may g) September Octobe November December
Account 555-Purchased Power (2) $88,182,972 $10,717,432 $9,359,487 $8,546,885 $6,841,564 $5,337,699 $5,287,042 $5,648,618 $7,939,502 $5,551,282 $5,789,904 $8,437,276 $8,726,282
Account 501 - Thermal Fuel $30,916,732 $2,789,917 $2,632,215 $2,785,057 $2,031,330 $1,718,372 $1,405,767 $2,715,972 $2,948,383 $2,925,528 $3,051,784 $2,909,636 $3,002,771
Account 547-Natural Gas Fuel $86,631,151 $8,264,229 $7,537,533 $7,376,233 $4,927,841 $2,851,219 $2,201,285 $6,893,937 $8,303,984 $8,561,441 $9,099,171 $9,713,701 $10,900,577
Account 447-Sale for Resale $57,620,639 $4,641,568 $4,386,361 $4,792,538 $5,372,207 $5,022,215 $3,271,701 $6,033,100 $3,115,032 $4,649,875 $4,672,288 $5,573,841 $6,089,913
Power Supply Expense $148,110,215 $17,130,010 $15,142,875 $13,915,637 $8,428,528 $4,885,076 $5,622,392 $9,225,427 $16,076,838 $12,388,375 $13,268,571 $15,486,772 $16,539,716
Transmission Expense $17,970,479 $1,495,284 $1,530,877 $1,480,538 $1,427,248 $1,371,518 $1,420,882 $1,432,251 $1,480,124 $1,483,239 $1,547,809 $1,665,262 $1,635,447
Transmission Revenue $15,910,828 $1,324,260 $1,118,308 $1,231,356 $1,159,555 $1,231,179 $1,409,821 $1,563,830 $1,439,516 $1,361,638 $1,498,286 $1,294,553 $1,278,524
PCA Authorized Idaho Retail Sales (31
Total January February )siti Agril Mav June g( September Q(QDyI November December
Total Retail Sales, MWh 2,920,315 288,554 259,942 251,709 220,890 215,126 211,354 242,247 239,641 218,705 210,034 262,809 299,304
Clearwater Paper Retail Load Generation, MWh 444,563 39,257 35,848 26,604 38,658 38,512 33,557 38,814 38,992 35,735 38,447 38,899 41,240
April 1, 2013 Approved Rates
Load Change Adjustment Rate $26.63 IM\Mi
October 1, 2013 Approved Rates
Load Change Adjustment Rate $26.97 /MVVtr
PCA Authorized Clearwater Paper Directly Assigned Values
Total January February March A01 May July Auqut September Octob November December di
Purchased Power $19,080,644 $1,684,910 $1,538,596 $1,141,844 $1,659,201 $1,652,935 $1,440,266 $1,665,897 $1,673,537 $1,533,746 $1,650,145 $1,669,545 $1,770,021
April 1, 2013 Approved Rates
Retail Revenue from Load Generation (4) $21,043,428 $1,854,485 $1,707,734 $1,256,968 $1,833,636 $1,819,288 $1,591,683 $1,833,555 $1,841,967 $1,694,991 $1,816,219 $1,844,742 $1,948,159
October 1, 2013 Approved Rates
Retail Revenue from Load = Generation (4) $21,523,556 $1,896,882 $1,746,450 $1,285,700 $1,875,387 $1,860,881 $1,627,925 $1,875,474 $1,884,078 $1,733,555 $1,557,742 $1,686,753 $1,992,699
1)Multiply system numbers by 34.76% to determine Idaho share.
2)Purchased Power Expense includes reduction for Pro Forma Billing Determinants at system cost.
3)12 months ended June 2012 weather normalized Idaho retail sales (utilizes Company's Pro Forms Billing Determinants).
4) Calculated at approved marginal Schedule 25P rates assuming 100% load factor for demand charge.
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
Revised Attachment B- March l,2013 Page lofi
STIPULATION AND SETTLEMENT
Case Nos. AVU-E-12-08 & AVU-G-12-07
ATTACHMENT C
AVISTA UTILITIES
IDAHO ELECTRIC, CASE NO. AVU-E-12-08
PROPOSED INCREASE BY SERVICE SCHEDULE
12 MONTHS ENDED JUNE 30, 2012
(000s of Dollars)
lEffective October 1st, 2013 I
Base Tariff Base Tariff Base Total Billed Total Billed Gen. Incr.
Revenue Proposed Revenue Tariff Revenue Total Total Revenue as a %
Line Type of Schedule Under Present General Under Proposed Percent at Present General Sch. 97- BPA at Proposed of Billed
No. Service Number Rates(1) Increase Rates (1) Increase Rates(2) Increase Decrease Rates(2) Revenue
(a) (b) (c) (d) (e) (f) (9) (h) (i) (j) (k)
I Residential I $99,497 $3,532 $103,029 3.5% $96,390 $3,532 ($1,024) $98,898 2.6%
2 General Service 11,12 $32,432 $920 $33,352 2.8% $32,597 $920 ($301) $33,216 1.9%
3 Large General Service 21,22 $51,400 $1,714 $53,114 3.3% $51,597 $1,714 ($614) $52,698 2.1%
4 Extra Large General Service 25 $16,036 $434 $16,470 2.7% $16,024 $434 ($273) $16,185 1.0%
5 Clearwater 25P $41,091 $928 $42,019 2.3% $41,005 $928 ($782) $41,151 0.4%
6 Pumping Service 31,32 $4,859 $190 $5,049 3.9% $4,867 $190 ($51) $5,006 2.9%
7 Street & Area Lights 41-49 $3,405 107 $3,512 3.1% $3,444 107 $3,539 2.7%
8 Total $248,720 $7,825 $256,545 3.1% $245,924 $7,825 ($3,058) $250,691 1.9%
(1)Excludes all present rate adjustments (see below).
(2)Includes all present rate adjustments: Schedule 59- Residential & Farm Energy Rate Adjustment, Schedule 66- Temporary
Power Cost Adjustment, Schedule 91 - Energy Efficiency Rider Adjustment, and Schedule 97- BPA Rate Adjustment
Attachment C
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
Page 1 of
AVISTA UTILITIES
IDAHO ELECTRIC, CASE NO. AVU-E-1 2-08
PRESENT AND PROPOSED RATE COMPONENTS BY SCHEDULE
lEffective October 1st, 2013 I
General Proposed Proposed
Base Tariff Present Present Rate Sch. 97-BPA Billing Base Tariff
Sch. Rate Other Adj.(1) Billing Rate Inc/(Decr) Decrease Rate Rate
(a) (b) (C) (d) (e) (f) (9) (h)
Residential Service - Schedule I
Basic Charge $5.25 $5.25 $0.00 $5.25 $5.25
Energy Charge:
First 600 kWhs $007848 ($000276) $007572 $0.00298 ($0.00091) $0.07779 $0.08146
All over 600 kWhs $0.08764 ($000276) $0.08488 $0.00332 ($0.00091) $0.08729 $0.09096
General Services - Schedule 11
Basic Charge $10.00 $10.00 $0.00 $10.00 $10.00
Energy Charge:
First 3,650 kWhs $009338 $000072 $009410 $0.00296 ($0.00091) $0.09615 $0.09634
All over 3,650 kwhs $006958 $000072 $007030 $000220 ($0.00091) $0.07159 $0.07178
Demand Charge:
20 kW or less no charge no charge no charge no charge
Over 20 kW $5.25/kW $5.25/kW $5.25/kW $5.25/kW
Large General Service - Schedule 21
Energy Charge:
First 250,000 kWhs $006039 $000035 $006074 $0.00258 ($0.00091) $0.06241 $0.06297
All over 2(2) Includes all preser $005154 $000035 $0.05189 $0.00219 ($0.00091) $0.05317 $0.05373
Demand Charge:
50 kW or less $350.00 $350.00 $0.00 $350.00 $350.00
Over 50 kW $4.75/kW $4.75/kW $4.75/kW $4.75/kW
Primary Voltage Discount $0.20/kW $0.20/kW $0.20/kW $0.20/kW
Extra Large General Service - Schedule 25
Energy Charge:
First 500,000 kWhs $0.05047 ($000004) $005043 $0.00165 ($0.00091) $0.05117 $0.05212
All over 500,000 kWhs $0.04275 ($000004) $004271 $0.00139 ($0.00091) $0.04319 $0.04414
Demand Charge:
3,000 kva or less $12,500 $12,500 $12,500 $12,500
Over 3,000 kva $4.50/kva $4.50/kva $4.50/kva $4.50/kva
Primary Volt. Discount $0.20/kW $0.20/kW $0.20/kW $0.20/kW
Annual Minimum Present: $666,570 Proposed: $683,420
Clearwater -Schedule 25P
Energy Charge:
all kWhs $004146 ($0.00010) $0.04136 $0.00108 ($0.00091) $0.04153 $0.04254
Demand Charge:
3,000 kva or less $12,500 $12,500 $12,500 $12,500
Over 3,000 kva $4.50/kva $4.50ikva $4.50/kva $4.50/kva
Primary Volt. Discount $0.20/kW $0.20/kW $0.20/kW $0.20/kW
Annual Minimum Present: $606,060 Proposed: $617,940
Pumping Service - Schedule 31
Basic Charge $8.00 $8.00 $0.00 $8.00 $8.00
Energy Charge:
First 165 kW/kWh $008939 $000052 $008991 $0.00360 ($0.00091) $0.09260 $0.09299
All additional kWhs $007620 $000052 $0.07672 $0.00307 ($0.00091) $007888 $0.07927
(1) Includes all present rate adjustments: Schedule 59 - Residential & Farm Energy Rate Adjustment, Schedule 66- Temporary
Power Cost Adjustment, and Schedule 91 - Energy Efficiency Rider Adjustment.
Stipulation and Settlement
Case No. AVU-E-1 2-08 and AVU-G-1 2-07
Avista
Attachment C Page 2 of 6
AVISTA UTILITIES
IDAHO GAS, CASE NO. AVU-G-12-07
PROPOSED INCREASE BY SERVICE SCHEDULE
12 MONTHS ENDED JUNE 30, 2012
(000s of Dollars)
lEffective April 1st, 2013 I
Base Tariff Base Tariff Base Total Billed Total Billed Percent
Revenue Proposed Revenue Tariff Revenue Total Revenue Increase
Line Type of Schedule Under Present General Under Proposed Percent at Present General at Proposed on Billed
No. Service Number Rates (1) Increase Rates (1) Increase Rates (2) Increase Rates (2) Revenue
(a) (b) (C) (d) (e) (f) (g) (h) (i) (j)
1 General Service 101 $47,852 $2,513 $50,365 5.3% $46,896 $2,513 $49,409 5.4%
2 Large General Service 111/112 $14,997 $569 $15,566 3.8% $14,607 $569 $15,175 3.9%
3 Interruptible Service 1311132 $201 $8 $209 4.0% $201 $8 $209 4.0%
4 Transportation Service 146 $289 $25 $314 8.70/6 $289 $25 $315 8.7%
5 Special Contracts 148 0.0% 0.0%
6 Total $63,436 $3,115 $66,551 4.9% $62,090 $3,115 $65,205 5.0%
(1)Includes Schedule 150- Purchased Gas Cost Adjustment
(2)Includes Schedule 155- Gas Rate Adjustment
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
Attachment C Page 3 of 6
AVISTA UTILITIES
IDAHO GAS, CASE NO. AVU-G-12-07
PRESENT AND PROPOSED RATE COMPONENTS BY SCHEDULE
I lEffective April 1st, 2013
General Proposed Proposed
Base Present Present Rate Billing Base
Rate (1) Rate Adj.(2) Billing Rate Increase Rate Rate (1)
(a) (b) (c) (d) (e) (f) (9)
General Service - Schedule 101
Basic Charge $4.25 $4.25 $0.00 $4.25 $4.25
Usage Charge:
All therms $0.82291 ($0.01785) $0.80506 $0.04690 $0.85196 $0.86981
Large General Service - Schedule 111
Usage Charge:
First 200 therms $0.84418 ($001785) $0.82633 $0.04689 $0.87322 $0.89107
200- 1,000 therms $0.71203 ($0.01785) $069418 $0.02413 $0.71831 $0.73616
1,000- 10,000 therms $0.63624 ($0.01785) $0.61839 $0.02156 $0.63995 $0.65780
All over 10,000 therms $058630 ($0.01785) $0.56845 $0.01987 $058832 $0.60617
Minimum Charge:
per month $81.61 $81.61 $9.38 $90.99 $90.99
per therm $0.43612 ($0.01785) $0.41827 $0.41827 $0.43612
Interruptible Service - Schedule 132
Usage Charge:
All Therms $0.50911 $0.50911 $0.02074 $0.52985 $0.52985
Transportation Service - Schedule 146
Basic Charge $225.00 $225.00 $0.00 $225.00 $225.00
Usage Charge:
All Therms $0.10671 $010671 $0.00978 $0.11649 $0.11649
(1)Includes Schedule 150 - Purchased Gas Cost Adjustment
(2)Includes Schedule 155 - Gas Rate Adjustment
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
Attachment C Page 4 of 6
AVISTA UTILITIES
IDAHO GAS, CASE NO. AVU-G-12-07
PROPOSED INCREASE BY SERVICE SCHEDULE
12 MONTHS ENDED JUNE 30, 2012
(000s of Dollars)
lEffective October 1st, 2013 I
Base Tariff Base Tariff Base Total Billed Total Billed Percent
Revenue Proposed Revenue Tariff Revenue Total Total Revenue Increase
Line Type of Schedule Under Present General Under Proposed Percent at Present General Sch 197 - PGA at Proposed on Billed
No. Service Number Rates (1) Increase Rates (1) Increase Rates (2) Increase Increase Rates (3) Revenue
(a) (b) (c) (d) (e) (f) (g) (h) (i) (j) (k)
1 General Service 101 $50,365 $1,073 $51,438 2.1% $49,408 $1,073 -$799 $49,682 0.6%
2 Large General Service 111/112 $15,566 $243 $15,809 1.6% $15,175 $243 -$326 $15,092 -0.5%
3 Interruptible Service 131/132 $209 $3 $212 1.4% $209 $3 -$6 $206 -1.4%
4 Transportation Service 146 $314 $11 $325 3.5% $315 $11 $0 $326 3.5%
5 Special Contracts 148 0.0% 0.0%
6 Total $66,551 $1,330 $67,881 2.0% $65,204 $1,330 -$1,131 $65,403 0.3%
(1)Includes Schedule 150- Purchased Gas Cost Adjustment
(2)Includes Schedule 155 - Gas Rate Adjustment
(3)Includes Schedule 155- Gas Rate Adjustment and Schedule 197- PGA Rate Adjustment
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
Attachment C Page 5 of 6
AVISTA UTILITIES
IDAHO GAS, CASE NO. AVU-G-12-07
PRESENT AND PROPOSED RATE COMPONENTS BY SCHEDULE
lEffective October 1st,2013 I
Base Present Present
Rate (1) Rate Adi.(2) Billing Rate
(a) (b) (c) (d)
General Service -Schedule 101
Basic Charge $4.25 $4.25
Usage Charge:
All therms 80.86981 ($0.01785) $0.85196
Large General Service - Schedule 111
Usage Charge:
First 200 therms 80.89107 ($0.01785) 80.87322
200- 1,000 therms 80.73616 (80.01785) 80.71831
1,000-10,000 therms 80.65780 (80.01785) 80.63995
All over 10,000 therms 80.60617 ($001785) 80.58832
Minimum Charge:
per month $90.99 $90.99
per therm $043612 ($0.01785) $0.41827
Interruptible Service -Schedule 132
Usage Charge:
All Therms 80.52985 80.52985
Transportation Service - Schedule 146
Basic Charge $225.00 $225.00
Usage Charge:
All Therms 80.11649 $0.11649
General Proposed Proposed Proposed
Rate Sch. 197 PGA Billing Base
Increase Adi. Rate Rate Rate (1)
(e) (f) (g) (h)
$0.00 $4.25 $4.25
$0.02003 ($0.01489) 80.85710 $0.88984
$0.02005 ($0.01489) 80.87838 $0.91112
$0.01026 ($0.01489) $0.71368 $0.74642
$0.00927 ($0.01489) $0.63433 $0.66707
$000845 ($0.01489) $0.58188 $0.61462
$4.01 $95.00 $95.00
($0.01489) 80.40338 80.43612
$0.00759 ($0.01489) $0.52255 80.53744
$0.00 $225.00 $225.00
$0.00426 80.12075 80.12075
(1)Includes Schedule 150- Purchased Gas Cost Adjustment
(2)Includes Schedule 155- Gas Rate Adjustment
Stipulation and Settlement
Case No. AVU-E-1 2-08 and AVU-G-1 2-07
Avista
Attachment C Page 6 of 6
STIPULATION AND SETTLEMENT
Case Nos. AVU-E-12-08 & AVU-G-12-07
ATTACHMENT D
Avista Corporation
State of Idaho
BPA Rate Adjustment Offset
ID portion of BPA Settlement -$3,846,000
Conversion Factor 0.995010
Revenue Requirement 7$3,865,288
15 Month Amortization Rate Pro Forma BPA
Sch kWh Reduction
1 1,454,376,696 ($1,320,981)
11&12 418,029,209 ($379,688)
21&22 847,204,858 ($769,499)
25 373,474,024 ($339,219)
25P 1,079,930,838 ($980,879)
31&32 65,224,871 ($59,242)
4149 17,372,742 ($15,779)
Total 4,255,613,238 ($3,865,288)
Uniform cents reduction ($0.00091)
* Effective October 1st, 2013 through December 31st, 2014
** Any residual balance will be trued up in a future PCA filed by the Company.
Stipulation and Settlement
Case No, AVU-E-12-08 and AVU-G-12-07
Avista
Page 1 of 4
Attachment D
I.P.U.C. No.28 Original Sheet 97 97
AVISTA CORPORATION
d/bla Avista Utilities
SCHEDULE 97
BONNEVILLE POWER ADMINISTRATION SETTLEMENT - IDAHO
AVAILABLE:
To Customers in the State of Idaho where Company has electric service
available.
PURPOSE:
To adjust electric rates for revenues related to the Bonneville Power
Administration settlement.
MONTHLY RATE:
The energy charges of electric Schedules 1, 11, 12, 21, 22, 25, 25P, 31
32 and 41-49 are to be decreased by 0.0910 per kilowatt-hour in all blocks of
these rate schedules.
TERM:
The energy charges will be reduced for a fifteen month period, from
October 1, 2013 through December 31, 2014. Any residual balance will be trued
up in a future PCA filed by the Company.
SPECIAL TERMS AND CONDITIONS:
Service under this schedule is subject to the Rules and Regulations
contained in this tariff. The above Rate is subject to increases as set forth in Tax
Adjustment Schedule 58.
ssuea eptemoer AA, zui s trective umooer 1,
By Kelly Norwood, Vice President, State & Federal Regulation
Attachment D Stipulation and Settlement
Case No. AVI.J-E-12-08 and AVU-G-12-07
Avista
Page 2 of 4
Avista Corporation
State of Idaho
PGA Rate Adjustment Offset
Refund of Deferred Gas Costs -$1,542,264
Conversion Factor 0.995009
Revenue Requirement -$1,550,000
15 Month Amortization Rate Pro Forma PGA
ac h Therms Reduction
101 74,508,535 ($1,109,559)
111&112 29,081,957 ($433,080)
131&132 494,346 ($7,362)
Total 104,084,838 ($1,550,000)
Uniform cents reduction ($0.01489)
* Effective October 1st, 2013 through December 31st, 2014
** Any residual balance will be trued up in a future PGA filed by the Company.
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
Attachment D Page 3 of 4
LP.U.C. No.27
Sheet 197 1 197
AVISTA CORPORATION
d/b/a Avista Utilities
SCHEDULE 197
REFUND OF DEFERRED GAS COSTS - IDAHO
AVAILABLE:
To Customers in the State of Idaho where Company has natural gas
service available.
PURPOSE:
To adjust natural gas rates for the refund of prior deferred gas costs.
MONTHLY RATE:
The energy charges of natural gas Schedules 101, lii, 112, 131, and 132
are to be decreased by 1.4890 per therm in all blocks of these rate schedules,
TERM:
The energy charges will be reduced for a fifteen month period, from
October 1, 2013 through December 31, 2014. Any residual balance will be trued
up in a future PGA filed by the Company.
SPECIAL TERMS AND CONDITIONS:
Service under this schedule is subject to the Rules and Regulations
contained in this tariff. The above Rate is subject to increases as set forth in Tax
Adjustment Schedule 158.
1 ,
by Avista Utilities
By Kelly Norwood, Vice President, State & Federal Regulation
Attachment 0 Stipulation and Settlement
Case No. AVU-E-12-08 and AVUG12-07
Avista
Pae4 of 4