20151113Andrews Exhibit 1.pdf

DAVID J. MEYER
vrcE ,RESTDENT AND cHrEF couNSEL FoR ?fiI5N$V 13 AS gr
REGULATORY & GOVERNMENTAL AEFAIRS rh,, r/\ r,!i *ri r/a
AVISTA CORPORATION IU,.;1T/ I"!.JOL;I''
uTlLtTiE$ c0l,ii,ilsP.O. BOX 3727
1.4T1. EAST MISSION AVENUE
SPoKANE, WASHTNGTON 99220-372'l
TELEPHoNE: [phone]L6
FACSIMILE: [phone]
DAVID. MEYERGAVISTACORP . COM
BEEORE TTIE IDAIIO PT'BLIC I'EII.IUES CODO{ISSION
IN THE MATTER OF THE APPL]CATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ]TS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC
AND NATURAL GAS CUSTOMERS IN THE
STATE OF IDAHO
CASE NO. AVU_E-15-05
CASE NO. AVU-G-15-01
EXHIBIT NO. 1
ELlZABETH M. ANDREWS
FOR AVISTA CORPORATION
(ELECTR]C AND NATURAL GAS)
\Jr{
David J. Meyer, Esq.
Vice President and Chief Counsel of
Regulatory and Governmental Affairs
Avista Corporation
l41l E. Mission Avenue
P.O.Box3727
Spokane, Washington 99220
Phone: [phone], Fax: [phone]
Karl Klein
Brandon Karpen
Deputy Attorneys General
Idaho Public Utilities Commission Staff
P.O. Box 83720
Boise,lD 83720-0074
Phone: [phone]l2,Fax; [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF AVISTA CORPORATTON DBA AVISTA ) CASE NOS.
UTILITIES FOR AUTHORITY TO )
INCREASE ITS RATES AND CHARGES )
FOR ELECTRIC AND NATURAL GAS )
SERVICE IN IDAHO ) STIPULATION AIID 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"), the Community Action Partnership Association of Idaho ("CAPAI"), the Idaho
Conservation League ("ICL"), and the Snake River Alliance ("Snake River"). These entities are
collectively referred to as the "Parties," and represent all ofthe parties in the above-referenced
cases. The Parties understand this Stipulation is subject to approval by the ldaho Public Utilities
Commission ("IPUC" or the "Commission").
AW-E-15-05
AVU-G-15-01
STIPULATION AND SETTLEMENT _ AVU-E-I5-05 & AVU-G-Is-OI Page I
I. INTRODUCTION
l. 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, is in the public interest 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 June 1,2015, Avista filed an Application with the Commission for authority
to increase revenue effective January 1,2016 for electric and natural gas service in ldaho by
5.2%o and 4.5yo, respectively. If approved, the Company's 2016 revenues for electric base retail
rates would have increased by $13.2 million annually, and Company revenues for natural gas
service would have increased by $3.2 million annually. The Company also requested an increase
to electric base retail revenue of $13.7 million (s.loh), and an increase in natural gas base retail
revenue of $1.7 (2.2%), effective January 1,2017. By OrderNo.33324, dated June 15,2015,
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, ldaho Forest,
CAPAI, ICL, and Snake River. The Commission granted these interventions through IPUC
Order Nos. 33331 and 33338.
STIPULATION AND SETTLEMENT _ AVU-E.I5-05 & AVU.G.Is-OI Page2
4. A settlement conference was noticed and held in the Commission offices on
September 18,2015, and was attended by signatories to this Stipulation.l Based upon the
discussions among the Parties, as a compromise of positions in this case, and for other
consideration as set forth below, the Parties agree to the following terms:
III. TERMS OF THE STIPULATION AI\[D SETTLEMENT
5. Overview of Settlement and Revenue Requirement. The Parties agree that Avista
should be allowed to implement revised tariff schedules designed to recover $1.7 million in
additional annual electric revenue, and $2.5 million in additional annual natural gas revenue,
which represent a 0.690/o and 3.49o/o increase in electric and natural gas annual base tariff
revenues, respectively. New electric and natural gas rates would become effective January 1,
2016.
6. Cost of Capital. The Settling Parties agree to a 9.5 percent return on equity, with
a 50.0 percent common equity ratio. The capital structure and resulting rate of return is as set
forth below:
Coryonent
Capital
Strucfuie Cost Weishted Cost
Debt 50% 5.34% 2.67%
CornrnonEqufy 50o/o 9.50o/o 4.75Yo
Total 100% 7.42o/o
' ICL was unable to attend the Settlement Conference; however, they did provide a "Position Statement" on
September 17,2015 providing their views on issues related to the proposed Fixed Cost Adjustment mechanisms and
rate design.
STIPULATION AND SETTLEMENT - AVU.E-I5-05 & AW-G-15-OI Page 3
A. ELECTRIC
7. Overview of Electric Revenue Requirement. Below
descriptions of the electric revenue requirement components agreed to
1,2016:
is a summary table and
by the Parties for January
.)
i.
ii.
llt.
iv.
)
$
$
$
$
$
$
$
$
$
$
$
$
$
$
)
r)
c.)
h.)
i.)
j.)
k.)
r.)
SUMMARYTABLE OF ADJUSTMENTS TO ELECTRIC REVENUE REQUIREMENT
EFFECTIVE JANUARY I, 2016
(000s ofDollars)
Revenue
Requirement Rate Base
Amount as Filed:
Adjustments:
Cost of Capital
Revise 2015 Capital Additions
Remove 2016 Capital Additions
Revise Deferred Debits and Credits to Reflect 2015 Balances
Remove 2016 Expenses
Insurance Expense
Information Services & Technolory
Non-Executive Labor
O&M Offsets
Update 2015 Employee Benefit Costs
Adjust InjLries and Damages Expense
Remove Officer Incentives and Restate Non-Officer Incentives
Include Four-Year Amortizatbn of 2015 Project Compass Deferral
Include Four-Year Amortization of Lake Spokane Deferral
Inchrde Palorse Wind in PCA
Miscellaneous A&G Adjustrnents: Director & Offlrcer Insurance, Board of
Director Expenses, Reallocation of Legal Expenses, Removal of Environmental
Cleanup Costs, and Removal of Miscellaneous Agreed-To Experses
Adjusted Amounts Efrective January 1,2016
$ 13,230 S 749,225
$ (580)
$ 1,700 $ 735,020
(2,438)
(3,345) $ (16,r
(548) $ r,78e
52 $ l3l
(62)
(s2l)
(385)
212
481
(8)
(r00)
(66e)
(1le)
(3,500)
a. Cost of Capital. As previously described (see Paragraph 6 above). This adjustment
reduces the overall revenue requirement by $2.438 million.
b. Revise 2015 Capital Additions. Reflects adjustments to updated information related
to 2015 capital additions, including the delay in completion of the Nine Mile
Hydroelectric Capital Project from 2015 to 2016 and the impact on depreciation
expense, as well as accumulated depreciation (A/D) and accumulated deferred federal
STTPULATION AND SETTLEMENT _ AVU-E.I5.05 & AVU-G-Is.OI Page 4
income taxes (ADFIT). This adjustment reduces the overall revenue requirement by
$3.345 million and reduces rate base by $16.125 million.
Remove 2016 Capital Additions. Reflects the removal of proposed 2016 capital
additions) and related depreciation expense, as well as the impact on A/D and
ADFIT. This adjustment reduces the overall revenue requirement by $548,000 and
increases rate base by $1.7S9 million2.
Revise Deferred Debits and Credits. Revises the deferred debits and credits
regulatory balances to reflect balances as of December 2015, rather than the 2016
balances as proposed by the Company. This adjustment increases the overall revenue
requirement by $52,000 and increases rate base by $ I 3 I ,000.
Remove 2016 Expenses. These adjustments remove 2016 incremental expenses or
offsets as proposed by the Company, including:
i. Insurance Expense - This adjustment reduces the overall revenue
requirement by $62,000, by removing2016 incremental expenses.
ii. Information Services & Technoloey - This adjustment reduces the overall
revenue requirement by $521,000, by removing 2016 incremental
expenses.
Non-Executive Labor - This adjustment reduces the overall revenue
requirement by $385,000, by removing 2016 incremental expenses.
O&M Offsets - This adjustment increases the overall revenue requirement
by $212,000, by removing 2016 offsets related to 2016 capital additions
removed in sub-paragraph c. above.
2 Removing the impact of 2016 capital additions, as well as removing the impact on accumulated depreciation and
accumulated deferred federal income taxes on total net plant during 2016, has the result ofincreasing overall net rate
base.
STTPULATION AND SETTLEMENT _ AW.E-I5-05 & AVU-G-l5-OI
d.
I ll.
lv.
Page 5
Update 2015 Emplovee Benefit Costs. Reflects updated information related to2015
incremental pension and medical costs. This adjustment increases the overall revenue
requirement by $48 1,000.
Adjust Injuries and Damaees Expense. Revises the six-year average of injuries and
damages. This adjustment decreases the overall revenue requirement by $8,000.
Remove Officer Incentives and Restate Non-Officer Incentives. Reflects the removal
of officer incentives and adjusts the non-officer incentive six-year average from a
102%to a l00o/o payout. This adjustment decreases the overall revenue requirement
by $100,000.
lnclude Four-Year Amortization of 2015 Project Compass Deferral. Revises the two-
year amortization of the 2015 Project Compass Deferral, as proposed by the
Company, to a four-year amortization. This adjustment decreases the overall revenue
requirement by $669,000.
lnclude Four-Year Amortization of Lake Spokane Deferral. Revises the two-year
amortization of the Lake Spokane Deferral, as proposed by the Company, to a four-
year amortization. This adjustment decreases the overall revenue requirement by
$l19,000.
lnclude Palouse Wind in PCA. Reflects the removal of the Palouse Wind Power
Purchase Agreement net expenses from base power supply expense. This adjustment
decreases the overall revenue requirement by $3.5 million. See Paragraph 8 below
for further information related to Palouse Wind.
Miscellaneous A&G Adjustments. Reflects the removal of net administrative and
general (A&G) expenses related to: l) removing an additional 40o/o of Idaho electric
Director and Officer insurance expense ($114,000); 2) removing legal expenses
h.
J.
k.
t.
STIPULATION AND SETTLEMENT _ AVU-E-15-05 & AVU-G-I5-01 Page 6
allocated to Idaho electric in error ($5,000); 3) removing 213 of environmental
cleanup expenses incurred in 2014 ($322,000); 4) removing miscellaneous expenses
as agreed to ($65,000); and removing additional Board of Director expenses included
in 2014 ($74,000). This adjustment decreases the overall revenue requirement by
$580,000.
8. Palouse Wind. The Parties agree that, for purposes of this case, the recovery
costs related to the Palouse Wind Power Purchase Agreement ("PPA") will continue to
included in the PCA, subject to the current sharing (90% customer,llYo Company).
B. NATURAL GAS
9. Overview of Natural Gas Revenue Requirement. Below is a summary table and
descriptions of the Natural Gas revenue requirement components agreed to by the Parties:
SUMMARYTABLE OF ADJUSTMENTS TO NATURAL GAS REVENUE REQUIREMENT
EFFECTIVE JANUARY I, 2016
(000s ofDollan)
Revenue
Requirement Rate Base
Amount as Filed: $ 3,205 S 127,498
Adjustments:
a.) Cost of Capital $ (415)
b.) Revise 2015 CapitalAdditions $ 440 $ 3,758
.) Remove 2016 Capital Additions $ (76) $ ffi9
Revise Defened Debits and Credits to Reflect 2015 Balances $ (3)
Remove 2016 Expenses
i. Inswance Expense $ (16)
ii. Information Services & Technolory $ (132)
iii. Non-Executive Labor $ (185)
f) Update 2015 Empbyee BeneftCosts $ 129
Adjustlnjurbs andDamages Expense $ (126)
h.) Remove Offrcer lncentives and Restate Non-Offrcer Incentives $ (25)
i.) Include Four-Year Amortization of 2015 Project Compass Deferral $ (168)
) Miscellaneous A&G Adjustrnents: Director & Officer Insurance, Board of
Director Expenses, Reallocation ofl,egal Expenses, and Removal of
Miscellaneous Agreed-To Expenses $ (128)
Adjusted Amounts Eftctive January 1,2016 $ 2,500 $ 131,925
of
be
STIPULATION AND SETTLEMENT _ AVU-E-15-05 & AVU-G-Is-OI Page 7
a.
b.
Cost of Capital. As previously described (see Paragraph 6 above). This adjustment
reduces the overall revenue requirement by $415,000.
Revise 2015 Capital Additions. Reflects adjustments to updated information related
to 2015 capital additions and the impact on depreciation expense, as well as A/D and
ADFIT. This adjustment increases the overall revenue requirement by $440,000 and
increases rate base by $3.758 million.
Remove 2016 Capital Additions. Reflects the removal of proposed 2016 capital
additions and related depreciation expense, as well as the impact on A/D and ADFIT.
This adjustment reduces the overall revenue requirement by $76,000 and increases
rate base by $669,0003.
Revise Deferred Debits and Credits. Revises the deferred debits and credits
regulatory amortization expense to reflect 2015 expenses, rather than 2016 expense
levels as proposed by the Company. This adjustment decreases the overall revenue
requirement by $3,000.
Remove 2016 Expenses. These adjustments remove 2016 incremental expenses as
proposed by the Company, including:
i. lnsurance Expense - This adjustment reduces the overall revenue
requirement by $16,000, by removing2016 incremental expenses.
ii. [nformation Services & Technoloqy - This adjustment reduces the overall
revenue requirement by $132,000, by removing 2016 incremental
expenses.
Non-Executive Labor - This adjustment reduces the overall revenue
requirement by $185,000, by removing 2016 incremental expenses.
d.
e.
tid
STIPULATION AND SETTLEMENT _ AW-E-I5-05 & AW.G.l5.OI Page 8
Update 2015 Emoloyee Benefit Costs. Reflects updated information related to 2015
incremental pension and medical costs. This adjustment increases the overall revenue
requirement by $ I 29,000.
Adjust Injuries and Damages Expense. Revises the six-year average of injuries and
damages. This adjustment decreases the overall revenue requirement by $126,000.
Remove Officer Incentives and Restate Non-Officer Incentives. Reflects the removal
of officer incentives and adjusts the non-officer incentive six-year average from a
102%to a 100%o payout. This adjustment decreases the overall revenue requirement
by $25,000.
Include Four-Year Amortization of 2015 Project Compass Deferral. Revises the two-
year amortization of the 2015 Project Compass Deferral, as proposed by the
Company, to a four-year amortization. This adjustment decreases the overall revenue
requirement by $ 168,000.
Miscellaneous A&G Adjustments. Reflects the removal of net administrative and
general (A&G) expenses related to: 1) removing an additional 40%o of Idaho Director
and Oflicer insurance expense ($29,000); 2) removing legal expenses allocated to
Idaho natural gas in error ($1,000); 3) removing miscellaneous expenses as agreed to
($79,000); and removing additional Board of Director expenses included in 2014
($19,000). This adjustment decreases the overall revenue requirement by $128,000.
C. OTHERSETTLEMENTCOMPONENTS
12. PCA Authorized Level of Expense. The new level of power supply revenues,
expenses, retail load and Load Change Adjustment Rate resulting from the January 1,2016
ob'
h.
j.
STIPULATION AND SETTLEMENT _ AVU-E-15-05 & AVU-G-Is-OI Page 9
settlement revenue requirement for purposes of the monthly PCA mechanism calculations are
detailed in Appendix A.
13. Fixed Cost Adjustment Mechanism. The Parties agree that Avista will implement
electric and natural gas Fixed Cost Adjustment mechanisms ("FCA"). The electric and natural
gas FCAs are illustrated in Appendices B and C and will commence concurrently with the
natural gas and electric rate changes January 1,2016. Below are the key components of the
mechanisms:
A. FCA Mechanisms Term. The Parties agree to an initial FCA term of 3 years, with a
review of how the mechanisms have functioned conducted by Avista, Staff, and other
interested parties following the end of the second full-year. Avista may seek to extend
the term of the mechanism prior to its expiration.
B. Rate Groups. There will be two rate groups established for both the electric FCA and
natural gas FCA:
Electric Customer Rate Groups:
l. Residential - Schedule I
2. Commercial - Schedules I l, 12,21,22, 31,32
Natural Gas Rate Groups:
l. Residential - Schedule l0l
2. Commercial - Schedules lll and ll2
C. Existing Customers and New Customers. The Parties have agreed that revenue
related to certain items discussed below would not be included in the FCA for new
customers. The result is that the Fixed Cost Adjustment Revenue-Per-Customer for new
customers will be less than the Fixed Cost Adjustment Revenue-Per-Customer for
existing customers. For new electric customers added after the test period, recovery of
STIPULATION AND SETTLEMENT _ AVU-E.I5.05 & AW.G-Is-OI Page l0
incremental revenue related to fixed production and transmission costs would be
excluded from the electric FCA. For new natural gas customers added after the test
period, recovery of incremental revenue related to fixed production and underground
storage facility costs would be excluded. These modifications are included in Appendices
B and C to the Stipulation.
D. Ouarterly Reporting. Avista will file, within 45 days of the end of each quarter, a
report detailing the FCA activity by month. The reporting will also include information
related to the deferrals by rate group, what the deferrals would have been if tracked by
rate schedule, use and revenue-per-customer for existing and new customers, and other
summary financial information. Avista will provide such other information as may be
reasonably requested, from time to time, in the future quarterly reports.
E. Annual Filings. On or before July 1, the Company will file a proposed rate
adjustment surcharge or rebate based on the amount of deferred revenue recorded for the
prior January through December time period. The rate adjustment would be calculated
separately for each Rate Group, with the applicable surcharge or rebate recovered from
each group on a uniform cents per kWh or per therm basis. The proposed tariff
(Schedule 75 for electric, Schedule 175 for natural gas) included with that filing would
include a rate adjustment that recovers/rebates the appropriate deferred revenue amount
over a twelve-month period effective on October I for electric (to match with Power Cost
Adjustment and Residential Exchange annual rate adjustments time period) and
November I't for natural gas (to match with the annual Purchased Gas Cost Adjustment
rate adjustment time period). The deferred revenue amount approved for recovery or
rebate would be transferred to a balancing account and the revenue surcharged or rebated
during the period would reduce the deferred revenue in the balancing account. After
STTPULATION AND SETTLEMENT _ AVU-E-I5-05 & AVU-G.I5.01 Page 1l
determining the amount of deferred revenue that can be recovered through a surcharge
(or refunded through a rebate) by Rate Group, the proposed rates under Schedules 75 and
175 would be determined by dividing the deferred revenue to be recovered by Rate
Group by the estimated kWh sales (Electric FCA) or therm sales (Natural Gas FCA) for
each Rate Group during the twelve-month recovery period. Any deferred revenue
remaining in the balancing account at the end of the amortization period would be added
to the new revenue deferrals to determine the amount of the proposed surcharge/rebate
for the following year.
F. Interest. lnterest will be accrued on the unamortized balance in the FCA balancing
accounts at the Customer Deposit Rate.a
G. Accounting. Avista will record the deferral in account 186 - Miscellaneous Deferred
Debits. The amount approved for recovery or rebate would then be transferred into a
Regulatory Asset or Regulatory Liability account for amortization. On the income
statement, the Company would record both the deferred revenue and the amortization of
the deferred revenue through Account 456 (Other Electric Revenue), or Account 495
(Other Gas Revenue), in separate sub-accounts. The Company would file quarterly
reports with the Commission showing pertinent information regarding the status of the
current deferral. This report would include a spreadsheet showing the monthly revenue
deferral calculation for each month of the deferral period (January - December), as well
as the current and historical monthly balance in the deferral account.
a Based on Order No. 33187 in Case No. GNR-U-14-L2,the deposit rate for 2015 is 1.0%.
annually.
STIPULATION AND SETTLEMENT _ AW-E-I5.05 & AW-G-I5-OI
The rate is updated
Page 12
H. 3%o Rate Increase Cap. An FCA surcharge, by rate group, cannot exceed a3Yo annual
rate adjustment, and any unrecovered balances will be carried forward to future years for
recovery. There is no limit to the level of the FCA rebate.
D. COST OF SERYICE/RATE SPREAD/RATE DESIGN
14. Cost of Service. For electric operations, the Company prepared an analysis using
a system load factor 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 25Yo 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 33o/o 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.
15. Rate Spread/Rate Design (-Base Rate Changes).
(a) As indicated above, the Parties agreed that the increase in base revenues
would be spread to all electric and natural gas rate schedules on a pro-rata allocation of
the Company's rate spread percentages from its original filing.
(b) Electric Rate Design. The Parties agree that the revenue requirement for each
electric service schedule will be applied as a uniform percentage increase to each
volumetric energy rate as shown in Appendix D. Fixed monthly charges and fixed and
variable demand charges will remain unchanged. The electric Residential Basic Charge
STIPULATION AND SETTLEMENT _ AVU-E-I5-05 & AVU-G-15-OI Page 13
(Schedule l) will remain at $5.25 per month. Finally, the street and area light codes and
calculation methodology described in Mr. Ehrbar's direct testimony will be adopted.
(c) Natural Gas Rate Design. The Parties agree that the Basic Charge for
Schedule l0l will increase by $1.00 per month, from $4.25 to $5.25. The revenue
requirement for all other natural gas service schedules will be applied as a uniform
percentage increase to each volumetric energy rate as shown in Appendix D.
(d) Appendix D provides a summary of the current and revised rates and charges
(as per the Settlement) for electric and natural gas service.
16. Electric Rebate Extension. Through rate Schedule 97, customers are receiving a
rebate of $0.00091 per kWh for 2015 (approximately $2.8 million). This rebate rate was first
approved in the Company's 2012 general rate case, Case No. AVU-E-12-08. As a part of the
settlement stipulation approved by the Commission in Case No. AVU-E-14-05, the rebate rate
was extended through December 31,2015 using the 2013 electric earnings sharing deferral. For
2014, Avista deferred approximately $5.6 million under the electric earnings sharing. The
Parties agree to use the $5.6 million deferral balance from 2014 and extend the Schedule 97
rebate rate for 2016 and2}ns. This information is shown on Appendix E.
17. Natural Gas Rebate Extension. Through rate Schedule 197, customers are receiving
a rebate of $0.01489 per therm through December 31,2015 (approximately $1.2 million). This
rebate rate was first approved in the Company's 2012 general rate case, Case No. AW-G-12-07.
As a part of the settlement stipulation approved by the Commission in Case No. AVU-G-14-01,
the rebate rate was extended for 2015 using the 2013 natural gas earnings sharing deferral, as
well as the Schedule 191 Natural Gas Energy Efficiency funding balance. For 2014, Avista
deferred approximately $0.2 million under the natural gas earnings sharing. The Company is
5 The electric and natural gas earnings sharing is in place for the 20 I 3-20 I 5 rate plan.
STIPULATTON AND SETTLEMENT _ AVU-8.I5.05 & AVU-G-l5-OI Page 14
proposing to use the $0.2 million natural gas deferral balance from 2014 to partially offset the
expiration of the $1.2 million rebate that will occur on January 1,2016. This information is
shown on Appendix E.
18. Resulting Percentage Increase by Electric Service Schedule. The following tables
reflect the agreed-upon percentage increase by schedule for electric service:
Rate Schedule
Residential Sctredule I
General Service Scheduhs I l/12
l,arge General Service Schedules 2lD2
Extra t arge General Service Schedule 25
Charwater Paper Schedule 25P
Pmping Service Sctredules 3ll32
Steet & Arealrdts Schedules 4l-48
Overall
Increase in Base Increase in
Rates BiUine Rates
19. Resulting Percentaee Increase by Natural Gas Service Schedule. The following
tables reflect the agreed-upon percentage increase by schedule for natural gas service:
0.9%
0.s%
0.6%
0.6%
0.4%
0.7%
0$%W
0.9%
0.5%
0.6%
0.6%
0.4%
0.7%
0.8%
0J%
Incrcase in
Base Rates
Increase in
Billing Increase
Net of New&
Rate Schedule
General Service Sctredule l0l
large General Service Sctredules llllll2
Intempt. Sales Service Schedules l3lll32
Billins Rates Expirine Rebate
7.7%
3.7%
7s%
4.1%
1.5%
2.7%
5.2%
3,5ile
5.3%
3.1%
4.8%
3.1%
L'EYu
Transportatbn Service Schedule 146* 5.2%
Ovelall 6.9%
* excludes commodity and interstate pipeline tronsportation costs
20. CustomerService-Relatedlssues.
(a) Low-lncome Usage Data. The Company and interested parties will meet and
confer prior to the Company's next general rate case in an effort to identifu low income
STIPULATION AND SETTLEMENT _ AVU.E.I5-05 & AVU-G-I5-OI Page 15
customers served by the Company, quantify the number of customers so identified, and
determine those customers' usage patterns. An initial meeting shall occur no later than
June 30, 2016, with follow-up meetings to occur as the attendees may deem appropriate.
(b) Collaboration on Low-Income Weatherization. The Company and interested
parties will meet and confer prior to the Company's next general rate filing in order to
assess the Low Income Weatherization and Low Income Energy Conservation Education
Programs and discuss appropriate levels of cost-effective, low-income weatherization
funding in the future. An initial meeting shall occur no later than June 30, 2016, with
follow-up meetings to occur as the attendees may deem appropriate.
IV. OTHER GENERAL PROVISIONS
21. 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.
22. 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 sefflement terms embodied in this Stipulation.
STIPULATION AND SETTLEMENT - AVU-E-15-05 & AVU-G-Is-OI Page 16
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.
23. 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
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.
24. The Parties agree that this Stipulation is in the public interest and that all of its
terms and conditions are fair, just and reasonable.
25. 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 aniving at this Stipulation
is appropriate for resolving any issues in any other proceeding in the future. No findings of fact
STTPULATION AND SETTLEMENT - AVU.E.I5-05 & AVU-G-l5-OI Page 17
or conclusions of law other than those stated herein shall be deemed to be implicit in this
Stipulation.
26. The obligations of the Parties under this Stipulation are subject to the
Commission's approval of ttris Stipulation in accordance with its terms and conditions and upon
such approval being upheld on appeal, if any, by a court of competent jurisdiction.
27, This Stipulation may be executed in counteqparts and each signed counterpart
shall constitute an original document.
'uL4
DATED tni" iG'.' 6yof october, 2ol 5.
Avista Corporation Idaho Public Utilities Commission Staff
By:By:
for Avista Corporation
Clearwater Paper Corporation
By:
Karl Klein
Brandon Karpen
Deputy Afiomeys General
Forest Group
Dean J. Miller
Attorney for ldaho Forest Group LLC
River Alliance
KelseyNunez
Attorney for Snalce Nver Allianoe
Page l8
Idatro
By:
Peter Richardson
Attorney for Clearwater Paper
Idaho Conservation League
By:
Benjamin J. Otto
Attorney for ICL
Snake
By:
STIPULATION AND SETTLEMENT - AW.E.15-05 & AW.G.15.01
or conclusions of law other than those stated herein shall be deemed to be implicit in this
Stipulation.
26, The obligations of the Parties under this Stipulation are subject to the
Commission's approval of this Stipulation in ascordance with its terms and conditions and upon
such approval being upheld on appeal, if any, by a court of competent jurisdiction.
27. This Stipulation may be executed in counterparts and each signed counterpart
shall constitute an original document.
DATED tfris I0faay of October, 2015.
ista Corporation
David J. Meyer
Attorney for Avista Corporation
Avi
By;
Cleanpater Paper Corporation
Peter Richardson
Attorney for Clearwater Paper
Idaho Consewation League
By:
Benjarnin J. Otto
Attorney for ICL
Brandon Karpen
Deputy Attorneys General
Forest Group
Dean J. Miller
Attorney for Idaho Forest Group LLC
River Alliance
KelseyNunez
Attorney for Snake River Alliance
Idaho
By:By:
Snake
By:
Idaho Public Utilities Commission Staff
STTPULATION AND SETTLEMENT _ AVU.E.Is.Os & AVU.G.I5.Ol Page 18
or conclusions of law other than those stated h€rein $hall be deeroed to be implicit in this
Stipulation.
26. The obligations of the Parties under this Stipulation are subject to the
Commission's approval of this Stipulation in aocordance with its terms and conditions and upon
such approval being upheld on appeal, if any, by a oourt of competent juisdiction.
27. This Stipulation may be executed in counterparts and each signed counterpart
shall constitute an original document.
DATED this_day of October,2015.
Avista Corporation Idaho Public Utilities Commission Staff
By:By:
David J. Meyer
Attomey for Avista Corporation
IGrl Klein
Brandon Ikrpsn
Deputy Attorneys General
Forcst Group
DeanJ. Miller
Attorney for Idalp Forest Group LLC
RiverAlliance
KelseyNunez
Attorney for Snake River Alliance
Idaho
By:
Idaho Snake
By:By:
Benjamin J. Otto
Auorney forICL
PetciRichardson 14b/o
Attorney for Clearwater Papet
STIPULATTON A}.ID SETTLEI\dENT _ AW.E.I5.O5 & AW-G.IS.OI Page l8
or conclusions of law other than those stated herein shall be deemed to be implicit in this
Stipulation.
26. 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.
27. This Stipulation may be executed in counterparts and each signed counterpart
shall constitute an original document.
DATED thir _ day of October, 2015.
Avista Corporation
By:
David J. Meyer
Attorney for Avista Corporation
Clearwater Paper Corporation
By:
Peter Richardson
Attorney for Clearwater Paper
Idaho Conservation League
By:
Ber{amin J. Otto
Attomey for ICL
Idaho Public Utilities Commission Staff
By:
Karl Klein
Brandon Karpen
Deputy Attorneys General
Dean J. Miller
Attorney for Idaho Forest Group LLC
Snake RiverAlliance
By:
KelseyNunez
Attorney for Snake River Alliance
STIPULATION AI.ID SETTLEMENT- AW.E-I5-05 & AW-G.IS-OI Page 18
or conclwions of law other than those stated herein shall be deerned to be implicit in this
Stipulation.
26. 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.
27. This Stipulation may be executed in counterparts and each signed counterpart
shall constirute an original document
DATED this _ day of October,Z0li.
Avista Corporation
By:
David J. Meyer
Attomey for Avista Corporation
Clearwater Paper Corporation
By:
Peter Richardson
Attorney for Clearwater Paper
Idaho Public Utilities Commission Staff
By:
Karl Klein
Brandon Karpen
Deputy Attorneys General
Forest Group
By:
Idaho
Dean J. Miller
Attorney for Idatro Forest Crroup LLC
Snake RiverAlliance
By:
Kelsey Nunez
Attomey for Snake River Alliance
League
Attomey for ICL
STIPI.JLATION A}ID SETTLEMENT - AW.E.I5.Os & AW.G-Is.OI Page l8
or conclusions of law other than those stated herein shall be deemed to be implicit in this
Stipulation.
26. 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.
27. This Stipulation may be executed in counterparts and each signed counterpart
shall constitute an original document.
DATED,lri, [5 day of october,2015.
Avista Corporation
By:
David J. Meyer
.Attorney for Avista Corporation
Clearwater Paper Corporation
By:
Peter Richardson
Attorney for Clearwater Paper
Idaho Public Utilities Commission Staff
By:
Karl Klein
Brandon Karpen
Deputy Attorneys General
Idaho Forest Group
By:
Idaho Conservation League
By:
Be4lamin J. Otto
Attorney for ICL
Dean J. Miller
Attorney for Idatro Forest Group LLC
Kelsey
STIPULATION AND SETTLEMENT - AVU.E.I5-05 & AVU.G-Is.OI Page 18
or conclusions of law other than those stated herein shall be deemed to be implicit in
Stipulation.
26. 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 upop
such approval being upheld on appeal, if any, by a court of competent jurisdiction.
27. This Stipulation may be executed in counterparts and each signed counterpart
shall constitute an original document.
DATED this _ day of October,2015.
Idaho Public Utilities Commission Staff
By:
I
this
Avi
By:
ista Corporation
By,
David J. Meyer
Attorney for Avista Corporation
Clearwater Paper Corporation
Karl Klein
Brandon Karpen
Deputy Attorneys General
Idaho Forest Group
Dean J. Miller
Attorney for Idaho Forest Group LLC
Snake Rivq Alliance
By:
Kelsey Nunez
Attomey for Snake River Alliance
By:
Peter Richardson
Attorney for Clearwater Paper
Idaho Conservation League
By:
Benjamin J. Otto
Attorney for ICL
Community Action Partnership Association of Idaho
Attorney for CAPAI
STIPULATION AND SETTLEMENT _ AVU-E-I5-05 & AVU-G-15.0I Page 18
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Sumcosl
Scenrio: AVU-E-1$05 Settlement Case
Load Factor Peak Credit
Transmission By Demand 12 CP(b) (c) (d) (e)
Description
Fundional Cost Compononts I Cunfit Retum by Schodule
Prcduction
Transmission
Distribution
Common
AVISTA UTILITIES ldaho Jurisdiction
Revenue to Cost by Functional Component Summay El€cfic Utility
For fie Tt etue ilonths Ended Decernber 3'1, 20'14
0 6) (h) 0 0 (k) (l) (m)
Residential Gen€ral Legecen ExfaLarge ExfaLrge Pumping Sbeet&
Sysbm &rvbe Service Selice Gen Servioe Seryhe CP Seilbe Atea Lighb
Tobl Sch'l Sch 1'l-12 *h21-n Sch 25 Sch 25P Sch 31-32 Sch 4149
116,381,261 43,834,300 15,151,702 26,940,838 11,113,743 16,942,287 2,009,519 388,872
25,875,928 9,718,351 3,934,119 6,214,281 2,249,812 3,351,999 364,384 42,983
6'1,351,755 29,831,665 10,79,769 14,076,269 1,699,164 428,16S 2,077,164 2,4s9,555
4'1,363,055 21,554,684 6,430,4'10 7,127,612 2,089,282 2,735,545 826,933 598,589
244,972,0& 104,939,000 36,46,000 54,3s9,000 17,'152,000 23,458,000 5,278,000 3,490,000
01/01/16
b
7
I
o
10
Total Curent Rab Revenue
Expressed as $/kwh
Production
Transmission
Distribution
Common
Total Cuneflt Melded Rahs
$0.03787 $0.03820 $0.04174
$0.00842 $0.00847 $0.01084
$0.01996 $0.02600 $0.0a70
s0.01346 $0.01879 S0.0'1771
$0.03855 $0.0351s $0.03566 $0.03407 $0.02862
$0.00889 $0.00712 $0.00706 $0.00618 $0.00316
$0.02014 $0.00537 $0.00090 $0.03521 $0.18101
s0.0'1020 $0.00661 $0.00s76 $0.01402 $0.04405
11 Pmduction
12 Transmission13 Disfibution14 Common15 Total Unilorm CunentCost
Exg€ssod as $ftWh16 Pmduction
17 Tran$nEsion'18 Distribution19 Common20 Total CunentUnifo.m Melded Rates
21 Rwcnucb Co.t Rato .t Cumnt R.i!.
Fundiond Cost Components 8t Unilorm Cunent Rdum
$0.07972 $0.00146 $0.09999 $0.07779 $0.05425 $0.04938 $0.08948 $0.25684
115,229,071 46,239,371 14,149,565 26,099,426 10,965,434 15,396,018 1,9U,232 395,025
25,s31,066 11,31s,196 3,299,985 s,714,435 2,170,174 2,634,191 352,205 ,14,880
62,s27,157 33,660,930 9,307,333 13,023,320 1,642,9'16 331,779 2,015,160 2,545,7n
41,684.69s 23.112.21s 5.880.13'l 6.816.316 2.050.s18 2.400.469 812.634 612.411
244,972,000 114,327,712 32,637,014 sl,653,498 16,84,043 n]62,4s7 5.164.232 3,598,045
$0.03750
$0.00831
$0.02035
$0.01356
$0.04030 $0.03898 $0.0373s
$0.00986 $0.00909 $0.00818
$0.029s4 $0.02564 $0.01864
$0.02014 $0.01620 $0.00975
$0.03468 $0.03241 $0.03364 $0.0A07
$0.00686 $0.00s55 $0.00597 $0.00330
$0.00520 $0.00070 $0,03416 $0.18735
$0,00649 $0.0050s $0,01378 $0.04507
s0.07972 $0.09964 50.08901 $0.07392 $0,0s323 $0.04371 $0.087s5 $0.26480
0.971.021.02 '1.13'1.050.921.00
22
23
24
25
26
Fundionel Cost Compon$ts at Propoo€d Rdum by Schedule
Production
Transmission
0isfibution
Common
Total Proposed Rate Revonue
116,879,049 44,076,123 '15,'198,8't1 27,043,470 11,161,961 16,990,473 2,017,744 390,467
b,179,972 9,878,907 3,963,927 6,275,24 2,275,703 3,374,367 368,344 43,475
61,998,205 30,216,681 10,848,984 14,2U,700 1,717,451 431,172 2,0973n 2,481,887
41,614,24 21,711,289 6,456,278 7,'165,582 2,'101,885 2,745,987 831,583 602,171
246,672,000 10s,883,m0 36,468,000 54,689,000 17,257,M 23,542,000 5,315,000 3,518,000
s0.0135t m.01892 $0.0129 $0.01025 $0.00665 $0.00578 $0.04432
$0.08027 $0.09228 $0.10046 $0.078m $0.054s8 $0.04956 $0.09011 $0,25890
115,740,980 46,444,790 14,212,425 26,215,374 11,014,149 15,48t,415 1,993,047 396,780
25,838,799 1'1,451,581 3,339,761 5,783,313 2,196,331 2,665,941 3s6,451 45,421
63,150,604 33,987,985 9,399,691 13,168,414 1,661,391 336,043 2,036,774 2,570,307
41,931,6'17 23,245,2,14 5,914,647 6,859,212 2,063,251 2,415,291 817,619 616,354
246,672,000 115,129,600 32,866,523 52,026,313 16,935,122 20,881,690 5,203,891 3,628,861
30
3'r
Common
Total Proposed lvlelded Rat€s
Production
Transmission
Disfibution
Common
ToblUnihrm Cost
Bpross€d as SkWh
Production
Transmission
Distibuton
Common
Total Uniform t\&lded RaGs
Rdanu! to Colt R.fo at Prcpotld futaa
Cumt Rffiuo io Pmpotrd Cort tuilo
Trrgat Rrvffu! lnq€la
$0.03766 $0.04048 $0.03915
$0.00841 $0.m998 $0.00920
$0.020s5 $0.02962 $0.02589
$0.01365 $0.02026 S0.01629
$0.037s1 $0.03484 $0.0325s $0.03379 $0.0A20
t0.00828 $0.0069s $0.00561 $0.00604 $0.00334
$0.01884 $0.0r52s $0.00071 $0.03453 $0.18916
$0.00982 $0,00653 $0.00508 $0.01386 $0.04536
$0.01410
Fundlon.l Cost Compments { Unilofln R€qu6tod Rdum
32
33
34
35
36
37
38
39
40
41
0.97
0.96
1.02
t.01
1.13
1.12r.0t
0.92
0.9t0.99
$0.08027 $0.10034 $0.09054 $0.07445 $0.0s3s6 $0.04396 $0.08822 $0.26706
1.m 1.1',1
1.10
1.05 't.02
t.u
r,700,000 10,190,000 (3,429,000) (2,333,000) (217,000) (2,576,000)
s0.0irE70 10.03530 s0.035l? $0.0:!t2t t0.0287t
$0.00E61 $0.01092 t0.00898 t0.00720 30.00710 30.00621 s0.00320
43
Appendix B
(74,000)t3!,,000
Page 4 ol 4
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Line Description
AVISTA UTILITIES
Company Se{llement Summary by Function with Margin Analysis
Case FortheYearEndedDecember3l, 2014
Nalural Gas Utility
ldaho Jurisdiction
(s) (h) (i) (k)
Residential Large Firm lnterrupt TransportService Service SeMce SeMce
Sch 101 Sch 111 Sch 131 Sch 146
(e)(d)(c)(0
System
Total
Funclional Cori ComponenE at CuEsnt Ratss
1 Produclion
2 Underground Storag€
3 Distribution
4 Common
5 Total Current Rato Rovenua
6 Excluds Cost of Gas w / Revenue Exp.
7 Tot l Margin Rsvonus at Curront Rabs
Margin per Therm at Cunant Rats
8 Produclion
9 Underground Storage
10 Distribulion
1 '1 Common
12 Total Current Margin Melded Rate p€r Them
Underground Storage
Distribution
Common
Total Unifom Curent Cost
Exclude Cost of Gas w / Revenua Exp.
Total Unifom Curent Margin
Margin p6r Therm at Uniform Current R6tum
Prcduclion
Und€rground Storage
Distribution
Common
Total Cunent Uniform Margin Melded Rate per Them
Maigln to Cost Ratlo at Curent Ratss
36,173,000 25 t39,84 4,425,127
337,03'l
1,746,'t 19
24,249,66
9,840,181
235,918
1 ,135,497 561,698
19,367,003 4,614,048
8,401,406 ',t.352,211
1,399 2,5425,600 43,32446,393 222,22614,2U 72,360
67,596 t40,452
0
'13
14
15
16
't7
18
19
20
2',1
22
23
24
25
26
27
2E
29
30
31
32
Functional Coct Components at Unitorm Cungnt Rstum
Prcduclion
36,173,000 29,139,8U 6,625,127 67,596 W,452
$0.00413 $0.00423 $0.00423 $0_00423 $0.00094s0.02137 $0.02036 $0.02448 S0.01695 S0.01600$0.29681 S0.34761 $0.20107 $0.14042 $0.08207$0.12044 $0.15080 $0.05893 $0.04299 90.02672$0.44275 30.52303 t0.28870 30.20,159 10.12674
337,031
I,689,279
235,9't8 97,171
1,231,4','9 416,370 5,255 36,235
4,'t49 197,52624,225,976 20,2%,739 3,685,5619,922,715 8,625,255 't,215,502 13,913 68,045
36,173,000 30,389,331 5,414,605 64716 304,311800000
36,173,000 30,389,331 5,4,t4,505 64716 304,34E
$0.00413 $0.00423 $0.00423 $0.00423 $0.00094$0.02068 $0.02210 $0.01814 $0.01590 $0.01338$0.29650 $0.3A€0 S0.16061 $0.13363 $0.07295$0.12145 $0.15481 $0.05297 $0.04211 90.0251340.4275 t0.545r15 t0.23595 30.19587 30.1140
1.04 1.12
Functionrl Cost ComponenE at Propolsd Ratos
Prcduclion
Underground Storage
Distribution
Common
Total Prcposod Rats RsYonue
Exclude Cost of Gas w / Revenue Exp.
Total Margln Royenue at Proposod Rato3
Therm al
36 Common
37 Total Prcposed Margin Meldad Rate perTherm
Functional Co3t Gomponents at Unifom Prcpo3ed Retum
Production
Underground StoEga
Distribution
Common
Total Unifom Propossd Cost
Exclude Cost of Gas w / Revenu€ Exp.
Toial Uniform Proposed Margin
Margin p6r Therm at Uniform Prcpced R6tum
Production
Underground Storags
50 Uargin to Coct Rdio.t Proposed Rater
Cumnt Mrrgin to Propored Co3t Ratio
337,031 235,918 97,17',1 1,399 2,5421,951,059 1,306,768 591,232 6,200 rt6,859
26,114,616 21,027,055 4,@2,732 50,288 2U,*1
10,270,295 E,801,083 1,379,992 14,709 74,511
38,673,ilt0 31,t7O,8A A,E71,127 72,596 35E,452
00000
$o.3774',t $0.20929 $0.15221 $0$0.12s71 $0.1s797 $0.06014 $0.04452 $0.027s210.4733s 30.56307 t0.29S42 30.21973 30.13238
38
39
40
41
42
43
44
45
46
47
48
49
337,031
't,903,251
26,093,052
10,339,666
235,9'18
1,387,397
21,808,556
97,171
469,1 10
4,022,507
1,399 2,5425,920 40,825
8,472 2',t3,5',t7
Distribulion $0.3193E $0.39144 $0.17529 $0.14671 $0.07886Common $0.12656 $0.16135 $0.055i3 $0.04381 $0.02616
Total Proposed Unifom Margin Meldgd Rate per Ttrem
989.242 't't25,E53,900 7O,2A5 327,72t
s0.00413 $0.00423 $0.00423 $0.00423 $0.00094$0.02330 $0.02490 s0.02044 $0.01792 S0.01508
1.',t7 1.03 1.09
,.13 0.96 1.040.94
Appendix c
33
34 30.023t8 30.023{5 $0.02576 30.0,t876 30.01
00000
3E,673,@0 32,421,113 5,853,900 70,265 327,7A2
51
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AVISTA UTILITIES
IDAHO ELECTRIC, CASE NO, AVU.E.15-05
PRESENTAND PROPOSED RATE COMPONENTS BY SCHEDULE
Effective January 1, 2016
General
Rate
lnc/(Decrl
(e)
$0.00
s0.00078
s0.00087
$0.00
$0.00052
$0.00038
no charge
(a)
Base Tariff Present Present
Sch. Rate Other Adi.(1) Billinq Rate(b) (c) (d)
Proposed
Billing
Rate
(0
$s.25
$0.08325
$0.09284
$r0.00
$0.09834
$0.07364
$5.25lkW
$0.06430
$0.05500
$350.00
$4.7s/kw
$0.20/kw
10.0s270
$0.04465
$'12,500
$4.50/kva
$0.20/kw
$687,360
$0.04280
$r2,500
$4.50/kva
$2.00/kva
$0.2olkw
$619,920
$8.00
$0.09482
$0.08'100
Proposed
Base Tariff
Rate
(s)
$s.25
$0.08224
$0.09183
$10.00
$0.09686
$0.07216
no charge
$5.25lkW
$0.06344
$0.05414
s350.00
$4.75/kW
$0.2olkw
$0.0s251
$0.04446
$r2,500
$4.50/kva
$0.2olkw
$0.04272
$12,500
$4.50/kva
$2.00/kva
$0.2o/kw
$8.00
$0.09365
$0.07983
Residential Service - Schedule 'l
Basic Charge
Energy Charge:
First 600 kWhs
All over 600 k\Mts
General Services - Schedule 11
Basic Charge
Energy Charge:
First 3,650 k\Ms
All over 3,650 k\Ms
Demand Charge:
20 kW or less
Over 20 kW
Laroe General Service - Schedule 2'l
Energy Charge:
First 250,000 k\Ms
All over 250,000 kWhs
Demand Charge:
50 kW or less
Over 50 kW
Primary Voltage Discount
$5.25
$0.08146 $0.00101
$0.09096 $0.00101
$10.00
$0.09634 $0.00148
$0.07178 $0.00148
no charge
$5.2s/kw
$0.06297 $0.00086
$0.05373 $0.00086
$350.00
$4.75lkw
$0.2o/kw
$0.05212 $0.00019
$0.04414 $0.00019
$12,500
$4.50/kva
$0.2o/kwPresent: $683,420
$0.04254 $0.00008
$12,500
$4.50/kva
$2.0O/kva
$0.2olkw
Present: $617,940
$8.00
$0.09299 $0.00'117
$0.07927 $0.00117
Extra Laroe General Service - Schedule 25
Energy Charge:
First 500,000 k\Ms
All over 500,000 k\Ms
Demand Charge:
3,000 kva or less
Over 3,000 kva
Primary Volt. Discount
Annual Minimum
Clearwater - Schedule 25P
Energy Charge:
all kWhs
Demand Charge:
3,000 kva or less
3,000 - 55,000 kva
Over 55,000 kva
Primary Volt. Discount
Annual Minimum
Pumoino Service - Schedule 31
Basic Charge
Energy Charge:
First 165
All additional k\A/hs
$5.25
$0.08247
$0.09197
$10.00
$0.09782
$0.07326
no charge
$5.2slkw
$0.06383
$0.05459
$350.00
$4.7slkw
$0.2o/kw
$0.05231
$0.04433
$'12,500
$4.50/kva
$0.2olkw
$0.04262
$12,500
$4.50/kva
$2.00/kva
$0.2o/kw
$8.00
$0.09416
$0.08044
$0.00047
$0.00041
$0.00
$0.00039
30.00032
$0.000r8
$0.00
00.00066
$0.00056
(1) lncludes 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 - Eamings
Test Rebate.
Stipulation and Settlement
Case No. AVU-E-15-05 and AVU-G-I5-01
Avista
Page 2 ot 4Appendix D
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AVISTA UTILITIES
IDAHO GAS, CASE NO. AVU.G.1s.OI
PRESENT AND PROPOSED RATE COMPONENTS BY SCHEDULE
Sch 197 -2013 Sch 197 -2014 Proposed
Present Base Present General Earnings Te3t Earnings Test Proposed Base
Distribution Billing Present Rate & PGA Rebate Rebate Billing DistributionRate Rate Adi.(1) Billino Rate lncreaae Expiration Credit (2) Rate Rate(b) (c) (d) (e) (0 (s) (h) (D
Effective January 1, 2016
Tvo€ of SeNice
(a)
General Service - Schedule l0l
Basic Charge
Usage Charge:
All therms
Larqe General Service - Schedule lll
Usage Charge:
First 200 therms
200 - 1,000 therms
1,000 - 10,000 therms
All over 10,000 therms
Minimum Charge:
per month
per therm
Usage Charge:
All Therms
Traneoortation Service - Schedule 14'6
Basic Charge
Usage Charge:
All Therms
$4.25
$0.45372 $0.44741
$0.47500 $0.44741
$0.31030 $0.44741
$0.23095 $0.44741
$0.17850 $0.44741
$95.00
$0.00000 $o.4/741
$4.2s $r.00
$0.90113 $0.02374
$0.92241 $0.02875
$0.75771 $0.00924
$0.67836 $0.00688
$0.62s91 $0.00531
$95.00
$o.44741
$5.75
$0.20459 $0.37021 $0.57480
$22s.OO $22s.00
s0.1 2075 s0.1 2075
$0.01,l89
$0.01,l89
$0.01,{89
$0.0r489
$0.0rlag
$0.01489
$0.01,|89
($0.00268)
($0.00268)
($0.00268)
($0.00268)
($0.00268)
($0.00268)
(10.00268)
$5.2s
$0.93708
$0.96337
$0.77916
$0.69745
$0.643,(l
$100.75
10.45962
30.60214
$5.25
$0.47746
$0.s0375
$0.31954
$0.23783
$0.18381
$100.75
$0.00000
$0.21972$0.01513
30.00
$0.00665 ($0.00268)
(1 ) Includes Schedule 'l 50 - Purchased Gas Cost Adjustment, Schedule I 55 - Gas Rate Adjustment, and Schedule 1 97 - PGA/DSM Rebate
(2) The 2014 Eamings Test Rebate Credit will be effective January 1, 2016 through December 3'1, 2016
s225.00 322s.00
$0.12472 $0.12740
Stipulation and Settlement
Case No. AVU-E-15-05 and AVU-G-15-01
Avista
Page 4 of 4Appendix D
Pro Forma
Therms
55,714,011
22,947,786
330,396
78,992,193
2013 Earnings
Rebate & DSM
Reduction
$ 829,582
$ 341,693
$ 4,920
Schedule 197
Present Rebate Expirinq 12131/201 5
Rebate of 2013 Earnings Test & DSM Defenals
Uniform Cents Reduction
Proposed Rebate Effective 1/l/16 - 12131/16
Rebate of 2014 Earnings Test
GeneralService
Large General Service
lnterruptible Service
Rate
Schedule
101
1111112
't31t132
Total
0.01489
2014 EarningsRate Pro Forma RebateSchedule Therms Reduction101 55,714,011 $ (149,314)
111t112 22,947,786 $ (61,500)131t132 330,396 $ (885)146 2,707,661 $ (7,257)Total 81,699,8il $ (218,9@
GeneralService
Large GeneralService
lnterruptible Service
Transportation Service
2014 Earnings Test Balance
Uniform Cents Reduction
$
$
(219,212)
(0.00268)
Stipulation and Seftlement
Case No. AVU-E-15-05 and AVU-G-15-01
Avista
Page 1 of 1Appendix E