20130318Exhibits.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION DBA AVISTA ) CASE NO. AVU-E-12-08
UTILITIES FOR AUTHORITY TO ) CASE NO. AVU-G-12-07
INCREASE ITS RATES AND CHARGES FOR
ELECTRIC AND NATURAL GAS SERVICE
IN IDAHO )
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EXHIBITS
BEFORE
COMMISSIONER PAUL KJELLANDER (Presiding)
COMMISSIONER MARSHA SMITH
COMMISSIONER MACK REDFORD
PLACE: Commission Hearing Room
472 West Washington
Boise, Idaho
DATES: March 4, 5 & 7, 2013
VOLUMES I - III - Pages 1 - 114
CSB REPORTING
Constance S. Bucy, CSR No. 187
23876 Applewood Way * Wilder, Idaho 83676
[phone]
Email csbheritagewifi.com
1 0
DIRECT TESTIMONY OF
KELYY 0. NORWOOD
IN SUPPORT OF THE
STIPULATION AND SETTLEMENT
Case Nos. AVU-E-12-08 & AVU-G-12-07
1 0
EXHIBIT 1
0
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 )
S 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
S 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.
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
0 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.
Stei, 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), 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 Offset 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
I.
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 3 to
partially offset the base rate increase, amortized over 15 months, October 1, 2013
to December 31, 2014.
C. Net overall jffl impact to customers of 0.3% effective October 1, 2013.
Summary of Natural Gas Rate Changes
Billing Rate Net Billing
Change Ofiet 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 Staffs proposal that approximately $1.55 million in un-
S 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
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)
iii.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 (900/o/10% 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 $ -
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 Exoenses: 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
fl

deferral of return on the Coyote Springs 2 (CS2) 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
Revenue
Requirement Rate Base
$ - $ 637,448
$ 5,488 $ 20,705
$ 629 $ 888
$ 926
$ 318
$ 38
$ 426
$ 7,825 $659,041
Amounts Effective April 1, 2013
Adjustments to October 1, 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
a. 2013CapitalAdditions. 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 2014CapitalAdditions. 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. 2013Expenses:
STIPULATION AND SETTLEMENT —AVU-E-12-08 & AVU-G-12-07 Page 7
0 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. 4
II. 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 (CSZ) 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) Misceilaneouse Adjustments: Two-Year Amortization of Booz Consulting $ (76)
costs, Injuries & Damages, Abandoned Projects & Depreciation Study
expense
Adjusted Amounts Effective April 1, 2013 S 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
(CS2) 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 $ - $ 112,239
Adjustments to October 1, 2013 Rate Change:
a.)2013 Capital Additions $ 1,073 $ 3,831
b.)Add 2013 Expenses
i.Information Services & Technology $ 42
ii.Non-Exec Labor $ 215
Adjusted Amounts Effective October!, 2013 $ 1,330 $ 116,070
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
0 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
0 (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.
(1,) 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 I 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:
Fleefri Inert-.wqp Prtnhue liv Schedule - Ann! 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%
Punqing 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!, 2013
Rate Schedule
Increase in Base
Rates
Net Increase in
Billing R ates*
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%
Pumping Service Schedule 3l/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 111/112 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.
S
STIPULATION AND SETTLEMENT -AVU-E-12-08 & 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
44
DATED this day of February, 2013.
Avi:sta Corporation Idaho Public Utilities Commission Staff
By:,iT77 / i By:
Dvid. J. Meyer Karl Klein
Attorney for Avista Corporation Weldon Stutzman
Deputy Attorneys General
Clearwater Paper Corporation Idaho Forest Group
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 SETFLEMFNT— AVU-E--12-08 & AVU-G-12-07 Page 18
Avista Corporation Idaho Public Utilities Compuission Staff
By_________ By:. "W J
David J Meyer Karl Klein
Attorney for Avista Corporation Weldon Stutzman
Deputy Attorneys General
Clearwater Paper Corporation
By;
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- 12-08 & AVU-G- 12-07 Page 18
DATED this 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 Idaho Forest Group
I) _
By: -e By:
Peter Ri hardson 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 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 Ido o st 9rcjiiJ
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 a4day of February, 2013
Avista Corporation Idaho Public Utilities Commission Staff
By:_ By:____________
David J. Meyer Karl Klein
Attorney for Avista Corporation Weldon Stutzman
Deputy Attorneys General
Clearwater Paper Corporation Idaho Forest Group
By:
Peter Richardson Dean J. Miller
Attorney for Clearwater Paper Attorney for Idaho Forest Group LLC
Idaho Conservation League
By:__4_
Benjamin J. Otto
Attorney for ICL
~ 0
STIPULATION AND SETTLEMENT - AVtJ-E-12-08 & 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 GRClncrease - 1$ - $ - $ - $ - $ - $ - $ -
4 Total Revenue Change $ - $ - $ - $ - $ - $ - $ - $ -
S
6 Percentage Changes
7 GRC Increase 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0% 0.0%
X Total Billed Percentage Change 0.0% 0.0% 0.01/0 0.0% 0.0% 0.0% 0.0% 0.0%
9
10
11
12
13
14
15
16 Effective October 1. 2013
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 Changes
19 GRC Increase * 1 $ 7,825,000 $ 3,532,000 $ 920,000 $ 1,714,000 $ 434,000 $ 928,000 $ 190,000 $ 107,000
20 BPA Reduction (15 Month Amortization) 1 $ (3,058,000) $ (1,024,000) $ (301,000) $ (614,000) $ (273,000) $ (782,000) $ (51,000) $ (13,000)
21 Total Revenue Change $ 4,767,000 $ 2,508,000 $ 619,000 $ 1,100,000 $ 161,000 $ 146,000 $ 139,000 $ 94,000
22
23 Percentage Changes
24 GRC Increase 3.2% 3.7% 2.8% 3.3% 2.7% 2.3% 3.9% 3.1
WA P,,d,,,*b,n -1.3% -1.1% -0.9% -1.2% -1.7% -1.9% -1.0%
26 Total Billed Percentage Change 1.9% 2.6% 1.9% 2.1% 1.0% 0.4%
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 $3058 million annually. It will expire @ 12/31/14.
2.9% 2.7%
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
Attachment A Page 1 of 2
. . .
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 $ 8,000 $ 25,000 $ -
5
6 Percentage Changes
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
Attachment :A Page 2 of 2
.
STIPULATION AND SETTLEMENT
Case Nos. AVU-E-12-08 & AVU-G-12-07
ATTACHMENT B
REVISED - March 1, 2013
.
0
. . .
Avista Corp
Pro forma January - December
PCA Authorized Expense and Retail Sales
PCA Authorized Power Supply Expense System Numbers (1)
Total January February March April May June July Auoust September Qç(2.y.L 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 $5551282 $5,789,904 $6,437,276 $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 $8,284,229 $7,537,533 $7,378,233 $4,927,841 $2,851,219 $2,201,285 $8,893,937 $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 $4,388,361 $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 $16,078,838 $12,388,375 $13,268,571 $15,488,772 $16,539,716
Transmission Expense $17,970,479 $1,495,284 $1,530,877 $1,460,538 $1,427,248 $1,371,518 $1,420,882 $1,432,251 $1,480,124 $1,483,239 $1,547,809 $1,685,262 $1,635,447
Transmission Revenue $15,910,828 $1,324,260 $1,118,308 $1,231,356 $1,159,556 $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 Februa March Aorll may g( Seotember October 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 $26.83 /MWh
October 1, 2013 Approved Rates
Load Change Adjustment Rate $28.97 /MWh
CA Authorized Clearwater Paper Directly Asslaned Values
Total January February March April May June JUIV Auqu September October November December
Purchased Power $19,080,644 $1,684,910 $1,538,596 $1,141,844 $1,659,201 $1,652,935 $1,440,288 $1,665,897 $1,673,537 $1,533,746 $1,850,145 $1,669,545 $1,770,021
April 1, 2013 Approved Rates
Retail Revenue from Load - Generation (4) 821,043,428 $1,854,485 $1,707,734 $1,256,968 $1,838,636 $1,819,288 $1,91,653 $1,833,555 $1,841,987 $1,894,991 $1,816,219 $1,844,742 $1,946,159
October 1, 2013 Approved Rates
Retail Revenue from Load = Generation (4) $21,523,558 $1,896,882 $1,746,450 $1,285,70Q $1,87,387 $1,880,881 $1,627,925 $1,87,474 $1,884,078 $1,733,585 $1,87,742 $1,888,753 $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 Forma 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 1, 2013 Page 1 of I
STIPULATION AND SETTLEMENT
Case Nos. AVU-E-12-08 & AVU-G-12-07
I
ATTACHMENT C
0
. . .
AVISTA UTILITIES
IDAHO ELECTRIC, CASE NO. AVU-E-1 2-08
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(l) Increase Rates (1) Increase Rates(2) Increase Decrease Rates(2) Revepue
(a) (b) (c) (d) (e) (f) (g) (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.%
7 Street & Area Lights 41-49 $3,405 I107 $3,512 3.1% $3,444 107 $3539 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.
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
Attachment C Page 1 of 6
$0.04163 $0.04254
$12,500 $12,500
$4.50Ikva $4.50/kva
$0.20/kW $0.20/kW
$617,940
$8.00 $8.00
$0.09260 $0.09299
$0.07888 $0.07927
AVISTA UTILITIES
IDAHO ELECTRIC, CASE NO. AVU-E-12-08
. PRESENT AND PROPOSED RATE COMPONENTS BY SCHEDULE
lEffective October 1st, 2013 I
General Proposed
Base Tariff Present Present Rate Sch. 97-BPA Billing
Sch. Rate Other Adi.(1) Billing Rate lnc/(Decr) Decrease Rate
(a) (b) (c) (d) (e) (f) (g)
Residential Service - Schedule I
Basic Charge $5.25 $5.25 $0.00 $5.25
Energy Charge:
First 600 kWhs $007848 ($0.00276) $0.07572 $0.00298 ($0.00091) $0.07779
All over 600 kWhs $0.08764 ($0.00276) $008488 $0.00332 ($0.00091) $0.08729
Proposed
Base Tariff
Rate
(h)
$5.25
$0.08146
$0.09096
.
General Services - Schedule 11
Basic Charge $10.00 $10.00 $0.00
Energy Charge:
First 3,650 kWhs $009338 $0.00072 $009410 $0.00296 ($0.00091)
All over 3,650 kWhs $006958 $000072 $0.07030 $0.00220 ($0.00091)
Demand Charge:
20 kW or less no charge no charge no charge
Over 20 kW $5.25/kW $5.25/kW
Lange General Service - Schedule 21
Energy Charge:
First 250,000 kWhs $006039 $0.00035 $006074 $0.00258 ($0.00091)
All over 2(2) Includes all preser $0.05154 $000035 $005189 $0.00219 ($0.00091)
Demand Charge:
50 kW or less $350.00 $350.00 $0.00
Over 50 kW $4.75/kW $4.75/kW
Primary Voltage Discount $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)
All over 500,000 kWhs $0.04275 ($000004) $0.04271 $0.00139 ($0.00091)
Demand Charge:
3,000 kva or less $12,500 $12,500
Over 3,000 kva $4.50/kva $4.50/kva
Primary Volt. Discount $0.20/kW $0.20IkW
Annual Minimum Present: $666,570 Proposed:
Clearwater - Schedule 25P
Energy Charge:
all kWhs $004146 ($0.00010) $0.04136 $0.00108 ($0.00091)
Demand Charge:
3,000 kva or less $12,500 $12,500
Over 3,000 kva $4.50/kva $4.50/kva
Primary Volt. Discount $0.20/kW $0.20/kW
Annual Minimum Present: $606,060 Proposed:
Pumping Service - Schedule 31
Basic Charge $8.00 $8.00 $0.00
Energy Charge:
First 165 kW/kWh $008939 $000052 $008991 $0.00360 ($0.00091)
All additional kWhs $007620 $0.00052 $0.07672 $0.00307 ($0.00091)
$10.00
$0.09615
$0.07159
$5 .25/kW
$0.06241
$0.05317
$350.00
$4.75/kW
$0.20/kW
$10.00
$0.09634
$0.07178
no charge
$5.25/kW
$0.06297
$0.05373
$350.00
$4.75/kW
$0.20/kW
$0.05117 $0.05212
$0.04319 $0.04414
$12,500 $12,500
$4.50Ikva $4.50/kva
$0.20/kW $0.20IkW
$683,420
(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.
~ 0
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
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) (9) (h) (i) U)
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 8.7% $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-1 2-08 and AVU-G-1 2-07
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 Adi.(2) Billing Rate Increase Rate Rate (1)
(a) (b) (c) (d) (e) (f) (g)
General Service - Schedule 101
Basic Charge $4.25 $4.25. $0.00 $4.25 $4.25
Usage Charge:
All therms $0.82291 ($0.01785) $080506 $0.04690 $0.85196 $0.86981
Large General Service - Schedule 111
Usage Charge:
First 200 therms $0.84418 ($0.01785) $0.82633 $0.04689 $0.87322 $0.89107
200 - 1,000 therms $0.71203 ($0.01785) $0.69418 $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 $0.58630 ($001785) $0.56845 $0.01987 $0.58832 $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 $0.10671 $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
. S
L
AVISTA UTILITIES
IDAHO GAS, CASE NO. AVU-G-12-07
PROPOSED INCREASE BY SERVICE SCHEDULE
12 MONTHS ENDED JUNE 30, 2012
(0005 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 1111112 $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-1 2-08 and AVU-G-1 2-07
Avista
Attachment C Page 5 of 6
(Effective October 1st, 2013
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 $0.86981 ($0.01785) $0.85196
Large General Service - Schedule 111
Usage Charge:
First 200 therms $0.89107 ($0.01785) $0.87322
200- 1,000 therms $073616 ($0.01785) $071831
1,000 - 10,000 therms $0.65780 ($0.01785) $0.63995
All over 10,000 therms $060617 ($0.01785) $058832
Minimum Charge:
per month $90.99 $90.99
per therm $043612 ($0.01785) $0.41827
Interruptible Service - Schedule 132
Usage Charge:
All Therms $052985 $052985
Transportation Service - Schedule 146
Basic Charge $225.00 $225.00
Usage Charge:
All Therms
•
$0.11649 $011649
General Proposed Proposed Proposed
Rate Sch. 197 PGA Billing Base
Increase Adi. Ra Rate Rate (1)
(e) (f) (g) (h)
$0.00 $4.25 $4.25
$0.02003 ($0.01489) $0.85710 $0.88984
$0.02005 ($0.01489) $0.87838 $0.91112
$0.01026 ($0.01489) $0.71368 $0.74642
$0.00927 ($0.01489) $0.63433 $0.66707
$0.00845 ($0.01489) $0.58188 $0.61462
$4.01 $95.00 $95.00
($0.01489) $0.40338 $0.43612

$0.00759 ($0.01489) $0.52255 $0.53744

$0.00 $225.00 $225.00

$000426 $0.12075 $0.12075
AVISTA UTILITIES
IDAHO GAS, CASE NO. AVU-G-12-07
Ask PRESENT AND PROPOSED RATE COMPONENTS BY SCHEDULE
(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
1 0
STIPULATION AND SETTLEMENT
Case Nos. AVU-E-12-08 & AVU-G--12-07
ATTACHMENT D
~ 0
Ll
• Avista Corporation
State of Idaho
BPA Rate Adjustment Offset
ID portion of BPA Settlement -$3,846,000
Conversion Factor 0.995010
Revenue Requirement -$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 ($379688)
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)
41-49 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-1248 and AVU-G-12-07
Avista
Page 1 of 4
Attachment D
0
I.P.U.C. No.28 Sheet 97 97
AVISTA CORPORATION
dlb/a 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.
2013
W] y Avista Utilities
By Kelly Norwood, Vice President, State & Federal Regulation
Attachment 0 Stipulation and Settlement
Case No. AVU-E-12-08 and AVUG-12-07
Avista
Page 2 of 4
• Avista Corporation
State of Idaho
PGA Rate Adiustment 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
Sch Therms Reduction
101 74,508,535 ($1,109,559)
111&112 29,081,957 ($433,080)
131&132 494,346 ($7,362)
Total 104,064,838 ($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.
S..
.. .. . .. .. ... Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
Attachment D Page 3 of 4
~ I
S IP.U.C. No.27 Sheet 197 197
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, 111, 112, 131, and 132
are to be decreased by 1.4890 per therm in all blocks of these rate schedules.
TERM: 5 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.
Iss ued September XX, 2013 Effective October 1, 2013
. Issued by Avista Utilities

By Kelly Norwood, Vice President, State & Federal Regulation
Attachment 0 Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
Page 4 of 4
• 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]
RECEIVE:.D
2013 FEB 7 Pil 2: 17
UJ4Ho P!JB tic UTILI I S Cu.MiS ION
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
.S discussions, but did not participate.
STIPULATION AND SETTLEMENT - AVU-E- 12-08 & AVU-G- 12-07 Page 1
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 1 of 39
.
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.
IL 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-1 2-07 Pae2 Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 2 of 39
•
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.
Step2: October l2013
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 Settlóment 2), and amortize that offset over 15 months, from October 1,
• 20l3to December 3l,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 Offset Rate Change
April 1, 2013 0.0% 0.00/0 0.00/0
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 Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 3of39
.
fl
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 3 to
partially offset the base rate increase, amortized over 15 months, October 1, 2013
to December 31, 2014.
C. Net overall kifi impact to customers of 0.3% effective October 1, 2013.
Sunlma1y of Natural Gas Rate Changes
Billing Rate Net Billing
CbgnE Offset Rate Chan
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 ProFonna
Component i Structure Cost Weighted Cost
Total Debt 50.00% 6.01% 3.01%
Common Equity 50.00% 9.800/o 4.900/0
Total 100.00% 7.91%
In Docket AVIJ-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 326511 on page 6, that "the resulting $1.55 million un-refunded credit is balance will help mitigate potential rate increases and provide rate stability for customers."
STIPULATION AND SETTLEMENT— AVU-E-12-08 & AVU-0-12-07 Pnore ' Exhibit No. 101
Case Nos. AVU-E- 12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 4of39
0 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
HL CS2 Levelized Return
iv. Non-Exec Labor
d.)Remove 2013 Property Tax Expense
e.)Remove Officer Incentive and CPI escalation
L) Two-Year Amortization of Reardan
g.)Include Palouse Wind in PCA until in base rates in 2015 (900/o/100/o sharing)
h.)Misceffaneouse 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)
$
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 ExDenses: 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,
S STIPULATION AND SETTLEMENT —AVU-E-12-08 & AVU-G-12-07 Page 5 Exhibit No. 101
Case Nos. AVU-E- 12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 5of39
S 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 Level ized Return. Removes the 2013 incremental
amortization of the deferred levelized return related to the 10-year
deferral of return on the Coyote Springs 2 (CS2) investment, to be n
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 Pate 6 Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 6of39
S
$ 5,488 $ 20,705
$ 629 $ 888
$ 926
$ 318
$ 38
$ 426 -
$ 7,825 ...!
S
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
Revenue
Requirement Rate Base
S
Amounts Effective April 1, 2013
Adjustments to October 1, 2013 Rate Change:
2013 Capital Additions
2014 Capital Additions
Add 2013 Expenses
I. Major Generation O&M
Ii. Information Services & Technolop
Ill. CS2 Levelized Return
iv. Non-Exec Labor
Adjusted Amounts Effective October 1, 2013
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
C. 2W 3 Lxnenses:
S STIPULATION AND SETFLEMENT— AVU-E-12-08 & AVU-G-12-07 Page 7 Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-1 2-07
R. Lobb, Staff
02/25/13 Page 7 of 39
S
9.
5 Wind Power I
sharing (90%
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).
The Parties agree that recovery of costs related to the Palouse
Agreement ("PPA") will be included in the PCA, subject to the current
, 10% Company) until, it is included in base rates as part of the
implementation of no rates from the Company's next general rate case anticipated in 2015.
10. The Parties agree to amortize the Reardan Wind
Project deferred of $1.747 million over a two-year period beginning April 1, 2013.
The
Parties agree that the amount deferred in 2013 related to the Company's O&M costs of its
Coyote Springs 2 (C2) natural gas-fired generating plant and its fifteen (15) percent ownership
In May 2008, Avista Pu thased 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 advanta e of much-lower costs for wind projects that emerged in 2011 (Palouse Wind). Avista
recorded $4.0 million of s te acquisition and preparation costs, of which approximately $1.7 million is Idaho's share.
This includes approx. $0. 7 million in AFUDC in accordance with Order No. 30611 (Case No. AVU-E-08-04)
STIPULATION AN - ----- SETTLEMENT AVU E 12 08&AVU 0 12 -07 Page 8 Exhibit No. 101
S
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page Sof39
•
share of the 3 & 4 coal-fired generating plants will be amortized over three years,
beginning with the of new base rates resulting from the Company's next general
rate case filing.5
B. NATURAL GAS
12. Below is a
summary table and of the Natural Gas revenue requirement components agreed to
by the Parties:
SUMMAR 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
Adjustmen :
a.)Cost of Cap al $ (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
S i.Information Services & Technology $ (42)
ii. Non-Exec Labor $ (215)
d.)Remove 2013 Property Tax Expense $ (84)
e.)Remove Of 1cer Incentive and CPI escalation $ (50)
L) Miscellaneo ise Adjustments: Two-Year Amortization of Booz Consulting $ (76)
costs, Injun s & Damages, Abandoned Projects & Depreciation Study
expense
Adjusted) mounts Effective April 1, 2013 $ 3,115 $ 112,239
of Capital. As previously described (see Paragraph 6 above). a.Cost
b.Remove 2011 Capital Additions. Reflects total depreciation expense and rate
net of accumulated depreciation and accumulated deferred income tax,
Per Order No. 32371 irk 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
(CS2) natural gas-fired 3generating 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 xpenses 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 PaRe 9 Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 9of39
• 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 Propern' 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 tiled 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 $1309
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 —Av1j-E.l2-o & AVU-G-12-07 Pane 10 Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 10 of 39
•
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
Amounts Effective April 1, 2013
Adjustments to October 1, 2013 Rate Change:
a.)2013 Capital Additions
b.)Add 2013 Expenses
L Information Services & TechnoIo'
ii. Non-Exec Labor
Adjusted Amounts Effective October 1, 2013
Revenue
Requirement Rate Base
$ - $ 112,239
$ 1,073 $ 3,831 I.
$ 42
$ 215
S 11330 $ 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 I 2(c)(i).
ii.Non-Exec Labor. Includes the 2013 incremental non-executive
labor increases discussed above in Paragraph 1 2(c)(ii).
0 STIPULATION AND SETTLEMENT - AVU-E-12-08 & AVU-G-12-07 Page 11 Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 11 of 39
. 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 Paae 12 Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 12 of 39
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).
S (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).
0 STIPULATION AND SETFLEMENT— AVU-E-12-08 & AVU-O-12-07 Page 13 Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 13 of 39
• (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
0 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 -A wil 1., 2013
Rate Schedule
Increase in Base
Rates
Net Increase in
Billing Rates
Residential Schedule 1 0.00/0 0.0%
General Service Schedule 11/12 0.0% 0.0%
Large General Service Schedule 21/22 0.00/0 0.0%
Extra Large General Service Schedule 25 0.0% 0.0%
Clearwater Paper Schedule 25P 0.0% 0.0%
Punpiig 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
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 14 of 39
.
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%
Pun,kig 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 111/112 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- 12-08 & AVU-G-1 2-07 Pae15
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 15 of 39
0 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 Stipulation1 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 filly 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 SETFLEMENT— AVU-E-12-08 & AVU-G-12-07 Page 16 Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 16of39
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 Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 17 of 39
.
DATED this. day Of February, 2013..
Avista Corporation
By: 1c7/ '
"Dvid J. .Weyer
Attorney for Avista Corporation
Idaho Public Utilities Commission .Staff
By:
Karl Klein
WeidonS.tutzrnan
Deputy Attorneys General
C
.
Clearwater Paper Carpo ion Idaho Forest,-Group
By:..
Peter Richardson Dean J Miller
Attorney for Clearwater Paper Attorney for Idaho Forest, &oup:LLC..
Idaho Conservation League.
Benjamin I Otto
Attorney.: for ICL
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 18 of 39
STIPULATION. AND SETTLEMENT - AVU-E-12-08 & AVU-0-12-07 Page. 18
DATED this day of February, 2013.
Avista Corporation Idaho Public Uduities Commission- Staff.
By-,.
David L Meyer
Attorney for Avista corporation
Clearwater Pap Corporation
Peter Ri hardson
Attorney for Clearwater Paper
By:
Karl Klein
Weldon. Stutzrnan
Deputy Attorneys General
Idaho Forest Group
By
Dean J. Miller
Attorney for Idaho Foresj.:Group LLC
Idaho COnservatiOn League
By:
Benjamin J Otto
Attorney for !CL
S STIPULATION AND SETTLEMENT - AVU-E-12-08 &.AVU-G-i2-07 Page 18
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 20 of 39
E
L DATED this J~j day of February, 2013.
Avista Corporation Idaho Public Utilities, Commission Staff
By: By:
David J. Meyer Karl Klein
Attorney for Avista Corporation Weldon Stutzman
Deputy Attorneys General
Qeatwter Paper Corporation Id o o
By: By:
Peter Richardson ean Miller
Attorney for Clearwater Paper Attorney for Idaho Forest Group.LLC
Idaho Conservation League
Benjamin:J. Otto
Attorney for ICL
Exhibit No. 101 -
Case Nos. AVU-E-12-08/
AVU-G-1 2-07
R. Lobb, Staff
02/25/13 Page 21 of 39
STIPULATION AND SETTLEMENT - AVU-E-1 2-08 & AVU-G-12-07 Page 18
.
DATED this, 7dqy of February, 2013.
Avista. Corporation
By:_
Dayid L Meyer
Attorney for Avsta Corporation
Idaho Pubiie.UtiiitiesCoñuflission Staff.
By:
Karl Klein
Weldon Stutzrnan
Deputy Attorneys General
Clearwater Paper Corporation- Idaho Forest Group
By: - - By:
Peter Richardson Dean J. Miller
Attorney for Clearwater Paper Attorney for Idaho Forest (Jmup LLçI
Idaho Conservation League
By: 4.
Benjamin J. Otto
Attorney for ICL
.
0 STIPULATION AND SETTLEMENT - AVU-E-1 2-08 & AVTJ.Gl 2-07 Pace 18.
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 22 of 39
STIPULATION AND SETTLEMENT
Case Nos. AVU-E-12-08 & AVU-G-12-07
ATTACHMENT A
S
C
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-1 2-07
R. Lobb, Staff
02/25/13 Page 23 of 39
. .
Avista Utilities
Idaho Rate Adjustments Electric
RESIDEN11AL GENERAL SVC. 1G. GEN. SVC. EXLG GEN SVC CLEAR WATER PUMPING ST & AREA LTG
Effective Apr iI 1. 2013 TOTAL SCHEDULE 1 SCH. 11.12 SCH. 21,22 SCHEDULE 25 SCHEDULE 25P SCH. 31,32 SCH. 4149
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 Chanees
3GRCIncrease ($ -Is - $ - $ - $ $ $ $ -
4 Total Revenue change $ - $ - $ $ - $ - $ - $ $ -
5
6 Percentaee Chances
7 GRC Increase 0.0% 0.0% 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% 0.0% 0.0%
9
10
11
12
13
14
15
16 Effective October 1. 2013
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 Chanaee
19 GRC increase * $ 7,82S,0001 $ 3,532,000 $ 920,000 $ 1,714,000 $ 434,000 $ 928,000 $ 190,000 $ 107,000
20 SPA Reduction (15 Month Amortization) $ (3.058,000) $ (1,024,000) $ (301,000) $ (614,000) $ (273,000) $ (782,000) $ (51,000) $ (13,000)
21 Total Revenue change $ 4,767,000 $ 2,508,000 $ 619,000 $ 1,100,000 $ 161,000 $ 146,000 $ 139,000 $ 94,000
22
23 Percentase Changes
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% 4.0%
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.
vo
CD
4 00
Attachment A
Stipulation and Settlement
Case No. AVU-E4208 and AVU-G'12-07
Avista
Page 1 of 2
. . .
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 $97,000
2 Revenue Chances
3 GRC Increase * J$ 3,114,7401 $ 2,512,740 $ 569,000 $ 81000 $ 25,000 $ -
4 Total Revenue Change $ 3,114,740 $ 2,512,740 $ 569,000 $ 81000 $ 25,000 $ -
5
6 Percentage chanees
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 $ 31000 $ 11,000 $ -
18 PGA Reduction (15 Month Amortization) ** $ (1,131,000) $ (799,000) $ (326,000) $ (61000) $ - $
19 Total Revenue Change $ 199,000 $ 274,000 $ (83,000) $ (31000) $ 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% 4.4% 34% 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.
c11
3r' ' uo
p. o
- Stipulation and Settlement
Case No. AVU-E-12-08 and AVU.G-12-07
Avista
Attachrnent..-:. Page 2of2 6 .'o

STIPULATION AND SETTLEMENT
Case Nos. AVU-E-12-08 & AVU-G-12-07
ATTACHMENT B
REVISED - March 1, 2013
S
Exhibit No. 101
Case Nos. AVU-E- 12-08/AVU-G- 12-07
R. Lobb, Staff
03/01/13 Page 26 of 39
. . .
Avista Corp
Pro forma January - December
PCA Authorized Expense and Retail Sales
PCA Authorized Power Suolv Expense -System Numbers 11)
Total ani,iaiy February March April jy June JUN Augus) 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 $2,948383 $2,925,528 $3,051,784 $2,909,636 $3,002,771
Account 547-Natural Gas Fuel $06,631,151 $8,264,229 $7,537,533 $7,376,233 $4,97,841 $2,851,219 $2,201,285 $8,893,937 $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 $1,495,264 $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 $1,159,556 $1,231,179 $1,409,821 $1,563,830 $1,439,516 $1,361,638 $1,498,286 $1,294,553 $1,278,524
RCA Authorized Idaho Retail Sales (3)
Total jy Februa March Agril Mav June July Auau j September Octobe 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 /MWh
October 1, 2013 Approved Rates
Load Change Adjustment Rate $26.97 /MWh
PCA Authorized Clearwater Paper Directly AssIgned Values
I1s1 Janus n February M=h &jl Mav June JUIV Auau Seotember Q1.)gjJ November December
C' ru 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
Z Retail Revenue from Load = Generation (4) $21,043,428 $1,854,466 $1,707,734 $1,256,968 $1,83,636 $1,819,288 $1,591,683 $1,833,555 $1,641,967 $1,694,991 $1,816,219 $1,844,742 $1,948,159
z October 1, 2013 Approved Rates
P Retail Revenue from Load = Generation (4) $21,523,556 $1,896,882 $1,746,45b $1,285,700 $1,875,387 $1,860,881 $1,627,925 $1,87,474 $1,884,078 $1,733,585 $1,857,742 $1,886,753 $1,992,699
tu1 1)Multiply system numbers by 34.76% to determine Idaho share.
2)Purchased Power Expense includes reduction for Pro Forms Billing Determinants at system cost.
'0 , 3)12 months ended June 2012 weather normalized Idaho retail sales (utilizes Company's Pro Forma Billing Determinants).
4) Calculated at approved marginal Schedule 25P rates assuming 100% load factor for demand charge.
Stipulation and Settlement
Case No. AVtJ-E-12-08 and AVU-G-12-07
Avista
Revised Attachment B - March 1, 2013 Page 1 of I
STIPULATION AND SETTLEMENT
Case Nos. AVU-E-12-08 & AVU-G-12-07
ATTACHMENT C
I
I
.
Exhibit No. 101
Case Nos. AVU-E- 12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 28 of 39
.
S
...
AVISTA UTILITIES
IDAHO ELECTRIC, CASE NO. AVU-E42-08
PROPOSED INCREASE BY SERVICE SCHEDULE
12 MONTHS ENDED JUNE 30, 2012
(000$ 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) (g) (h) (i) 09 (k
1 Residential 1 $99,497 $3,532 $103.029 3.59A $95,390 $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 $1714 $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 0.46/6
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 $3405 $3.512 3.1% $3444 tIQZ I= $3539 2.7%
8 Total $248720 $7,825 $256,545 3.1% $245,924 $7,825 ($3,058) $250,691 1.90/0
(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.
crri
(MO
.-
0
Attachment C li
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..12-08
PRESENT AND PROPOSED RATE COMPONENTS BY SCHEDULE
1 Effective October 1st, 2013 1
General Proposed Proposed
Base Tariff Present Present Rate Sch. 97-SPA Billing Base Tariff
Sch. Rate Other Adi(1 I Billing Rate Incl(Decrl Decrease 392 Eft (a) (b) (C) (d) (e) (f) (g) (h)
Residential Service. Schedule I
Basic Charge $5.25 $5.25 $0.00 $5.25 $5.25 Energy Charge:
First 600 kWhs $0.07848 ($0.00276) $0.07572 $0.00298 ($0.00091) $0.07779 $0.08148
All over 600 kWhs $0.08764 ($0.00276) $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 kWbs $0.09338 $0.00072 $.09410 $0.00296 ($0.00091) $0.09615 $0.09634
All over 3,650 kWhs $0.06958 $0.00072 $0.07030 $0.00220 ($0.00091) $027159 $0.07178
Demand Charge:
20 kW or less no charge no charge no charge no charge
Over 20 kW S5.25/kW $5. 25/kw $5.251kW $5. 25/kW
Larne General Service - Schedule 21
Energy Charge:
First 250.000 kWs $0.06039 $0.00035 $.06074 $0.00258 ($0.00091) $006241 $0.06297
All over 2(2) Includes all preser $0.05154 $0.00035 $0.05169 $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 $4.751kW $4.751kW $4.75/kW
Primary Voltage Discount $0.20/kW $0.20/kW 50.201kW $0,20/kW
Extra Lame General Service - Schedule 25
Energy Charge:
First 500,000 kwhs $0.05047 ($0.00004) $0.05043 $0.00165 ($0.00091) $0.05117 $0.05212
All over 500,000 kWhs $0.04275 ($0.00004) $0.04271 $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 $4.50Ikva $4.50Ikva $4.50Ikva
Primary Volt. Discount $0.20/kW $0.20/kW $0.20lkW $0.20/kW
Annual Minimum Present: $666,570 Proposed: $683,420
Clearwater- Schedule 25P
• Energy Charge:
all kWbs $0.04146 ($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. 50/kva $4.50/kva $4.50Ikva
Primary Volt Discount 50.20/kW $0.20/kW $0.20/KW 50.20/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 $0.08939 $0.00052 $0.08991 $0.00360 ($000091) $.09260 $0.09299
All additional kWhs $0.07620 $0.00052 $0.07672 $0.00307 ($0.00091) $0.07888 $0.07927
(1) Includes all present rate adjustments: Schedule 59- Residential & Farm Energy Rate Adjustment, Schedule 66-Temporary
Power Cost Adjustment, and Schedule 91 Energy Efficiency Rider Adjustment.
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
02/25/13 Page 3Oof39
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista.
Attachment C Page 2 of 6
. . .
AVISTA UTILITIES
IDAHO GAS, CASE NO. AVU-G-12-07
PROPOSED INCREASE BY SERVICE SCHEDULE
12 MONTHS ENDED JUNE 30, 2012
(000$ of Dollars)
lEffective April 1st, 2013
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
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 5.40A
2 Large General Service 111/112 $14,997 $569 $15,566 3.8% $14,607 $569 $15,175 3.9%
3 Interruptible Service 131/132 $201 $8 $209 4.04A $201 $8 $209 4.0%
4 Transportation Service 146 $289 $25 $314 8.7% $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
Z: o
Cl) o
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
ww Attachment C Page 3 of 6
'0
General Proposed Proposed
Rate Billing Base
Increase Rate Rate (1
(e) (f) (g)
$0.00 $4.25 $4.25
$0.04690 $0.85196 $0.86981
$0.04689 $0.87322 $0.89107
$0.02413 $0.71831 $0.73616
$0.02156 $0.63995 $0.65780
$0.01987 $0.58832 $0.60617
$9.38 $90.99 $90.99
$0.41827 $0.43612

$0.02074 $0.52985 $0.52985

$0.00 $225.00 $225.00

$0.00978 $0.11649 $0.11649
.
AVISTA UTILITIES
IDAHO GAS, CASE NO. AVU-G-12-07
PRESENT AND PROPOSED RATE COMPONENTS BY SCHEDULE
.
lEffective April 1st, 2013 1
Base Present Present
Rate (1) Rate Adi(2) BiIhno Rate
(a) (b) (c) (d)
General Service - Schedule 101
Basic Charge $4.25 $4.25
Usage Charge:
All therms $0.82291 ($0.01785) $0.80506
Lame General Service - Schedule 111
Usage Charge:
First 200 therms $0.84418 ($0.01785) $082633
200- 1,000 therms $0.71203 ($0.01785) $0.69418
1,000- 10,000 therms $0.63624 ($001785) $061839
All over 10,000 therms $0.58630 ($001785) $0.56845
Minimum Charge:
per month $81.81 $81.61
per therm $0.43612 ($0.01785) $0.41827
Interruptible Service - Schedule 132
Usage Charge:

All Therms $0.50911 $0.50911
TransportatIon Service - Schedule 146

Basic Charge $225.00 $225.00
Usage Charge:

All Therms $0.10671 $0.10671
(1)Includes Schedule 150 - Purchased Gas Cost Adjustment
(2)Includes Schedule 155- Gas Rate Adjustment
Exhibit No. 101
Case Nos. AVU-E- 12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 32 of 39
.

Stipulation and Settlement
Case No. AVU-E-12-08 and AW-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
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
Service Number Rates (1) Increase Rates (1) Increase Rates (2) Increase Increase Rates (3) Revenue
(a) (b) (c) (d) (e) (f) (g) (h) (I) 0) (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% $16,175 $243 -$326 $15,092 0.5%
3 Interruptible Service 1311132 $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
2 Case No. AVU-E-12-08 and AVU-G-12-07
Cri Avista
,!, Attachment C Page 5 of 6 - tJt')
lEffective October 1st, 2013 I
Base Present Present
Rate (11 Rate AdL(2) Billino Rate
(a) (b) (c) (d)
General Service - Schedule 101
Basic Charge $4.25 $425
Usage Charge:
All therms $0.86981 (60.01785) 60.85196
Lame General Service - Schedule 111
Usage Charge:
First 200 therms 60.89107 ($001785) 60.87322
200-1,000 therms. 60.73616 ($0.01765) $0.71831
1,000- 10,000 therms 60.65780 (60.01785) $0.63995
All over 10,000 therms 60.60617 ($0.01785) 60.58832
Minimum Charge:
per month $90.99 $90.99
per therm 60.43612 ($0.01785) $0.41827
Interruptible Service - Schedule 132
Usage Charge:
All Therms 60.52985 $0,52985
Transportation Service - Schedule 146
•. Basic Charge
Usage Charge:
$225.00 $225.00
All Therms $0.11649 $0.1160
General Proposed Proposed Proposed
Rate Sch. 197 PGA Billing. Base
Increase Adi, Rate Rate Rate (1
(a) (fl (g) (h)
$0.00 $4.25 $4.25
$0.02003 ($0.01489). 60.85710 $0.88984
60.02005 ($0.01489) 60.87838 $0.91112
$0.01026 ($0.01489) $0.71368 $0.74642
$0.00927 (60.01489) 60.63433 60.66707
60.00845 (60.01489) $058188 $0.61462
$4.01 $95.00 $95.00
($0.01 489) $0.40338. 60.43612

$000759 (60.01489) $0.52255 $0.53744

$0.00
$225.00 $225.00

$0.00426 60.12075 $0.12076
AVISTA UTILITIES
. IDAHO GAS, CASE NO. AVU-G-1 207
PRESENT AND PROPOSED RATE COMPONENTS BY SCHEDULE
(1)Includes Schedule 150- Purchased Gas Cost Adjustment
(2)Includes Schedule 155 - Gas Rate Adjustment
Exhibit No. 101
Case Nos. AVU-E-12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 34 of 39 n
Stipulation and Settlement
Case No. AVU-E-1208 and AW-G-12-07
Avlsta
Attachment Page 6ot6
I 40
STIPULATION AND SETTLEMENT
Case Nos. AVU-E-12-08 & AVU-G-12-0•7
ATTACHMENT D
I.
S
Exhibit No. 101
Case Nos. AVU-E- 12-08/
AVU-G- 12-07
R. Lobb, Staff
02/25/13 Page 35 of 39
S Avista Corporation
State of Idaho
BPA Rate Adiustment Offset
ID portion of BPA Settlement $3,846,000
Conversion Factor 0.995010
Revenue Requirement -$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 1242)
41-49 17,372,742 ($15,779)
Total 4,255613,238 ($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.
S
I.P.U.C. No.28 Sheet 97 I 97
AVISTA CORPORATION
d/b/a Avista Utilities
SCHEDULE 97
BONNEVILLE POWER ADMINISTRATION SETTLEMENT - IDAHO
AVAILABLE:
To Customers in the State of Idaho where Company has electric service
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, 2.1, 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, 20.13 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.
Issued September XX, 2013 Effective October 1, 2013
Issued by Avista Utilities
By Kelly Norwood, Vice President, State & Federal Regulation
Aflathment D Stipulation and Settlement
Case No. AVU-E-4-03 and AW-G-1247
Avista Exhibit No. 101
Page 2of4 Case Nos. AVU-E-12-08/
AVU-G-12-07
R. Lobb, Staff
- 02/25/13 Page 37of39
.
'Refund of Deferred Gas Costs
Conversion Factor
Revenue Requirement
Avista Corporation
State of Idaho
PGA Rate Adlustment Offset
-$1,542,264
0.996009
-$1,550,000
.15 Month Amortization Rate Pro Forma PGA
Sch 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.
Exhibit No. 101
Case Nos. AVU-E- 12-08/
AVU-G- 12-07
R. Lobb, Staff
.
02/25/13 Page 38 of 39
Stipulation and Settlement
Case No. AVU-E-12-08 and AVU-G-12-07
Avista
Attachment 0 Page 3 of 4:
I.P.U.C. No.27 Sheet 197 197
AVISTA CORPORATION
dlb/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, 111, 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.
Issued September XX, 2013 EffectIve. October 1, 2013
Issued by Avista Utilities
S By Kelly Norwood, Vice President, State & Federal Regulation
Attachment 0 stipulation and Setuement
Case. No. AVU..E.12-08 and AW.G-12.07
Avista Exhibit No. 101
Page 4 of 4 • • Case Nos. AVU-E-12-08/
AVU-G-12-07
R. j.obb, Staff
02/25/13 Page 39 of 39