20151019Stipulation and Settlement.pdf

Avista Corp.
141 I East Mission P.O. Box 3727
Spokane. Washington 99220{500
Telephone 509489{1500
Toll Free 800-727-9170
FILED ELECTRONICALLY AND VIA OVERNIGHT MAIL
frwsrt
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October 16,2015
Jean D. Jewell
Commission Secretary
Idaho Public Utilities Commission
472 W . Washington Street
Boise,lD 83702
Re: CaseNos. AVU-E-15-05 andAVU-G-15-01
Stipulation and Settlement and Joint Motion
Enclosed for filing with the Commission in the above-referenced docket are the original
and seven copies of the Joint Motion for Approval of Stipulation and Settlement, and the
Stipulation and Settlement, dated October 16,2015.
Sincerely,
q//
David J. Meyer
Vice President, Chief Counsel for Regulatory
& Governmental Affairs
Enclosures
c: Service List
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I HEREBY CERTIFY that I have this
Stipulation, and Joint Motion, upon the
addressed with postage prepaid to:
Jean D Jewell, Secretary
Idaho Public Utilities Commission
Statehouse
Boise,ID 83720-5983
Jean [e-mail]
Karl Klein
Brandon Karpen
Deputy Attorneys General
Idaho Public Utilities Commission
472W. Washington
Boise, D 83702-0659
karl.klein@puc. idaho. gov
[e-mail]. gov
Kelsey Nunez
Snake River Alliance
223 N 6th Street, Suite 317
Boise, D 83702
kmiller@snakeriveral liance.org
[e-mail]
Larry A. Crowley
The Energy Strategies lnstitute, Inc.
5549 S. Cliffsedge Ave
Boise, D 83716
[e-mail]
Ken Miller
Clean Energy Program Director
Snake River Alliance
223 N 6th Street, Suite 317
Boise,ID 83702
[e-mail]
CERTIFICATE OF SERVICE
16ft day of October,
following parties, by
2015, served the Settlement and
mailing a copy thereof, properly
Brad M. Purdy
Attorney at Law
2019 N l7m Street
Boise,ID 83720
[e-mail]
Peter J. Richardson
Greg M. Adams
Richardson & O'Leary PLLC
515 N.27ft Street
PO Box 7218
Boise, ID 83702
[e-mail]
ere g@richardsondoleary. com
Dean J. Miller
McDevitt & Miller, LLP
420W. Bannock St.
PO Box 2564-83701
Boise, D 83701-2564
i oe@mcdevitt-mi I ler.com
Benjamin J. Otto
Idaho Conservation League
710 N. 6th st.
Boise, D 83702
botto@idahoconservation. org
Dr. Don Reading
6070 Hill Road
Boise,ID 83703
dreadin [e-mail]
Manager, Rates & Tariffs
David J. Meyer, Esq.
Vice President and Chief Counsel of
Regulatory and Governmental Affairs
Avista Corporation
1411 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, ID 83720-0074
Phone: [phone],Fax: [phone]
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
RECEIVII"I
?015 OCT l9 ltt ll: 20
uT r J i'ttliti5* iii s r m',
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASENOS. AVU-E-I5-05
AVU-G-15-01
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"), 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 of the parties in the above-referenced
cases. The Parties understand this Stipulation is subject to approval by the Idaho Public Utilities
Commission ("IPUC" or the "Commission").
STIPULATION AND SETTLEMENT _ AVU-E- I 5-05 & AVU-G- I 5-O I 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 Idaho by
5.2%o and 4.5oA, 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.lyo), and an increase in natural gas base retail
revenue of $1.7 (2.2o ), 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-15.05 & AVU-G-I5-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 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 $1.7 million in
additional annual electric revenue, and $2.5 million in additional annual natural gas revenue,
which represent a 0.69Yo and 3.49Yo increase in electric and natural gas annual base tariff
revenues, respectively. New electric and natural gas rates would become effective January l,
20t6.
6. Cost of Caoital. 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:
Cornponent
Capital
Structure Cost Weishted Cost
Debt 50% 5.34% 2.67%
Cornnon Equtry 50% 9.50% 4.75%
Total 100% 7.42Yo
' 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.
STTPULATION AND SETTLEMENT _ AVU-E-I5-05 & AVU-G-Is-OI Page 3
A. ELECTRIC
7. Overview of Electric Revenue Requirement. Below is a summary table and
descriptions of the electric revenue requirement components agreed to by the Parties for January
1,2016:
SUMMARY TABLE 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 Capial Additions
Remove 2016 Capital Additions
Revise Deferred Debits and Credis to Reflect 2015 Bahnces
Remove 2016 Expenses
i. Instuance Expense
ii. Information Services & Technolory
iii. Non-ExecutiveLabor
iv. O&M Offsets
Update 2015 Emphyee Beneflt Costs
Adjust Injwies and Damages Expense
Remove Offher Incentives and Restate Non-Offrcer Incentives
Include Fow-Year Amortization of 2015 Project Compass Deferral
Include Four-Year Amortizatbn of Lake Spokane Deferral
Inchrde Palouse Wind in PCA
Miscellaneous A&G Adjustments: Director & Offrcer Insurance, Board of
Director Expenses, Reallocatbn of Legal Expenses, Removal of Environmental
Cbanup Costs, and Removal of Miscellaneous Ageed-To Expenses
Adjusted Amounts Efrective January 1,2016
$ 13,230 $ 749,225
$ (2,438)
$ (3,345) $ (16,
$ (548) $ 1,789
$52Sl3r
.)
c.)
h.)
i.)
j.)
k.)
r.)
$
$
$
$
$
$
$
$
$
$
(62)
(521)
(385)
212
481
(8)
(100)
(66e)
(l le)
(3,500)
$ (s8o)
$ 1,700 $ 73
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 Caoital 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
STIPULATION AND SETTLEMENT _ AVU-E-I5.05 & AVU-G-I5-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 $1.789 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 & Technology - 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 Offses - 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.
d.
lll.
lv.
STIPULATION AND SETTLEMENT - AVU-E-15-05 & AVU.G-15-01 Page 5
Update 2015 Employee Benefit Costs. Reflects updated information related to 2015
incremental pension and medical costs. This adjustment increases the overall revenue
requirement by $48 1,000.
Adjust Injuries and Damages 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 100% payout. This adjustment decreases the overall revenue requirement
by $100,000.
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 $669,000.
Include 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.
Include 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
o
h.
J.
k.
l.
STIPULATION AND SETTLEMENT - AVU-E-I5.05 & AVU.G.Is-OI 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 of
costs related to the Palouse Wind Power Purchase Agreement ("PPA") will continue to be
included in the PCA, subject to the current sharing (90% customer,l0o/o 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:
SUMMARY TABLE OF ADJUSTMENTS TO NATURAL GAS REI'ENUE REQUIREMENT
EFFECTIVE JANUARY I, 2016
(000s ofDollan)
Revenue
Requirrment Rate Base
Amount as Filed: $ 3,205 S 127,498
Adjustments:
cost of capital $ (415)
Revise 2015 Capital Additions $ 440 $ 3,758
Remove 2016 Capital Additions $ (76) $ 69
Revise Deferred Debis and Credits to Reflect 2015 Balances $ (3)
Remove 2016 Expenses
i. Insurance Expense $ (16)
ii. Information Services & Technolory $ (132)
iii. Non-Executive Labor $ (185)
Update 2015 Employee Beneft Costs $ 129
Adjust Injurbs and Damages Expense $ (126)
Remove Officer Incentives and Restate Non-Offrcer Incentives $ (25)
Inchde Four-Year Amortization of 2015 Project Compass Deferral $ (168)
Miscellaneous A&G Adjusknents: Director & Officer Insurance, Board of
Director Expenses, Reallocation of lrgal Expenses, and Removal of
Miscellaneous Agreed-To Expenses $ (128)
Adjusted Amounts Eftctive JanuarT 1,2016 $ 2,500 $ 131,925
.)
STIPULATION AND SETTLEMENT - AVU-E-I5-05 & AVU.G.Is-OI Page 7
d.
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 Caoital 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. Insurance Expense - This adjustment reduces the overall revenue
requirement by $16,000, by removing2016 incremental expenses.
ii. Information Services & Technolog), - 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 removing2016 incremental expenses.
e.
3.,ta
STIPULATION AND SETTLEMENT - AVU-E-15-05 & AVU-G-l5-OI Page 8
Update 2015 Emnloyee Benefit Costs. Reflects updated information related to 2015
incremental pension and medical costs. This adjustment increases the overall revenue
requirement by $ 1 29,000.
Adjust Injuries and Damaees 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 lncentives. Reflects the removal
of officer incentives and adjusts the non-officer incentive six-year averuge from a
102%to a l00o/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 $ I 68,000.
Miscellaneous A&G Adjustments. Reflects the removal of net administrative and
general (A&G) expenses related to: l) removing an additional 40Yo of Idaho Director
and Officer 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
o
h.
J.
STIPULATION AND SETTLEMENT _ AVU-E-I5-05 & AW-G-I5-OI Page9
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
elecffic 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 l, 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 1 l, 12,21,22, 31, 32
Natural Gas Rate Grouos:
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 & AVU-G-I5-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 l, 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
STIPULATION AND SETTLEMENT - AW-E.I5-05 & AVU-G-Is-OI Page I I
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. Interest 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-14-12,the deposit rate for 2015 is 1.0%.
annually.
STIPULATION AND SETTLEMENT - AVU-E-15-05 & AVU-G-I5-01
The rate is updated
Page 12
H. 3olo Rate Increase Cap. An FCA surcharge, by rate group, cannot exceed a3%o 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 25o/o 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 SpreadlRate 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-l5-OI Page 13
(Schedule 1) 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. AVU-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 2013-2015 rate plan.
STIPULATION AND SETTLEMENT - AVU-E-15-05 & AW-G-I5-OI Page 14
proposing to use the $0.2 million natural gas deferral balance from 2014 to partially offset the
expiration of the $1.2 million rebate that will occur on January 1,2016. This information is
shown on Appendix E.
18. Resultine Percentage Increase by Electric Service Schedule. The following tables
reflect the agreed-upon percentage increase by schedule for electric service:
Rate Schedule
Resitlential Schedule I
General Service Schedules I l/12
l^arge General Servbe Schedules 21122
E><ta Large General Service Schedule 25
Clearwater Paper Schedule 25P
Pwping Service Schedules 3ll32
Sreet & Area Liglts Schedules 4l-48
Ovemll
Increase in Base Increase in
Rates Billine Rates
19. Resultine Percentage [ncrease by Natural Gas Service Schedule. The following
tables reflect the agreed-upon percentage increase by schedule for natural gas service:
0.9%
0.5%
0.6%
0.6%
0.4%
0.7%
0.8%
0J%
09%
0.s%
0.6%
0.6%
0.4%
0.7%
0.8%
0J%
Increase in
Base Rates
Incrcase in
Billing Increase
Net of New&
Rate Schedule
General Service Sclrcduh l0l
Large General Service Schedules lll/ll2
Intemryt. Sales Service Schedules l3lll32
Bi[ine Rates Expiring Rebate
7.7%
3.7%
7.5%
4.t%
15%
2.70
5.2%
3s%
5.3%
3.1%
4.8%
3.1%
4.$Yo
TransportationService Schedule 146* 5.2yo
Overall 69%
* excludes commodity and interstate pipeline transportdtion costs
20. CustomerService-Relatedlssues.
(a) Low-Income Usage Data. The Company and interested parties will meet and
confer prior to the Company's next general rate case in an effort to identify low income
STIPULATION AND SETTLEMENT _ AVU-E-15-05 & 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 lncome 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 conf,rdential 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 settlement terms embodied in this Stipulation.
STIPULATION AND SETTLEMENT _ AVU-E-I5-05 & AVU.G-I5-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. tf 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 consffued 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
STIPULATION AND SETTLEMENT - AVU-E-15-05 & AVU-G-15-01 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 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.
Idaho Public Utilities Commission Staff
By:
Karl Klein
Brandon Karpen
Deputy Attorneys General
Idaho Forest Group
By:
Dean J. Miller
Afforney for Idaho Forest Group LLC
Snake River Alliance
By:
Kelsey Nunez
Attorney for Snake River Alliance
, rf4
DATED this i tg d-ay of October,20l5.
Avista Corporation
By:
J.
ttorney for Avista Corporation
Clearwater Paper Corporation
By:
Peter Richardson
Afforney for Clearwater Paper
Idaho Conservation League
By:
Benjamin J. Otto
Attorney for ICL
STIPULATION AND SETTLEMENT - AVU-E-I5-05 & AVU.G-Is-OI Page 18
or conclusions of law other than those stated hersin 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 beingupheld ott appeal, if any' by a court of competent jurisdiction.
27. This Stipulation may be executed in counterparts and eaoh signed countorpart
shall constitute an original document.
DATED ttris @aay of October, 2015.
Avista Corporation
By:
Idaho
David J. Meyer
Attorney for Avista Corporation
Clearwater Paper Corporation
By:
Peter Richardson
Attorney for Clearwater Paper
Conseryation League
By:
Benjarnin J. Otto
Attorney forICL
Brandon Karpen
Deputy Attorneys General
ldaho Forest Group
By:
Dean J. Miller
Attorney for Idaho Forest Group LLC
Snake River Alliance
By:
KelseyNunez
Attorney for Snake River Alliance
Idaho Public Utilities Commission Staff
STTPULATION AND SETTLEMENT _ AVU.E. I 5.05 & AVU.G.I 5.O I Page 18
or conclusiontl 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 juisdiction.
27. This Stipulation may be executcd in counterputs and each signed counterpart
shall constitute an original document.
DATED this _ day of October, 2015.
Avista Corporation
David J. Meyer
Attorney for Avista Corporation
Idaho Conservatiou League
By:
BenjaminJ. Otto
Attorney for ICL
Idaho Public Utilities Commission Staff
By:
Karl Klein
Brandon Karpen
Deputy Attorneys General
Forest Group
By:
Idaho
DeanJ. Miller
Attorney for Idalro Forest Group LLC
RiverAlliance
KelseyNunez
Attorney for Snake River Alliance
Snake
By:
STIPULATION AI{D SETTLEMENT - AW.E.I5-05 & AVI',-G-I5.OI Page 18
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 ane 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 this _ day of October,2015.
Avista Corporation Idaho Public Utilities Commission Staff
By:By:
David J. Meyer
Attorney for Avista Corporation
Clearwater Paper Corporation
By:
Peter Richardson
Attorney for Clearwater Paper
Idaho Conservation League
By:
Benjamin J. Otto
Attorney for ICL
Karl Klein
Brandon Karpen
DeanJ. Miller
Attomey for Idaho Forest Group LLC
RiverAlliance
Kelsey Nunez
Attorney for Snake River Alliance
Snake
By:
Deputy Attorneys General
Forest Group
STIPULATION AND SETTLEMENT - AW-E- 1 5 -05 &, AW-G- I 5-O I Page l8
or concluriions 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 this _ day of October, 2015.
Avista Corporation Idaho Public Utilities Commission Staff
By:By:
David J. Meyer
Attorney for Avista Corporation
Clearwater Paper Corporation
By:
Peter Richardson
Attorney for Clearwater Paper
Idaho League
By:
ialrrin J. Otto
Karl Klein
Brandon Karpen
Deputy Attorneys General
Idaho Forest Group
Dean J. Miller
Attorney for Idatro Forest Group LLC
Snake River Alliance
By:
Kelsey Nurez
Anorney for Snake River Alliance
By:
Attorney for ICL
SIPIILATION Al.lD SETTLEMENT - AW-E-15-05 & AW-c-15-01 Page 18
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
Forest Group
By:
Dean J. Miller
Attomey for Idaho Forest Group LLC
Idaho
Idatro Conservation League Alliance
By:
Benjamin J. Otto
Attorney for ICL
Kelsey
Attorney for
STIPULATION AND SETTLEMENT _ AVU-E.I5.05 & AVU.G.Is-OI Page 18
I
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 iurisdiction.
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
By:
David J. Meyer
Attorney for Avista Corporation
Clearwater Paper Corporation
By'
Peter Richardson
Attorney for Clearwater Paper
Idaho Conservation League
By:
Idaho Public Utilities Commission Staff
By:
Karl Klein
Brandon Karpen
Deputy Attorneys General
Idaho Forest Group
By:
Benjamin J. Otto
Attorney for ICL
Community Action Partnership Association of Idaho
Dean J. Miller
Attorney for Idaho Forest Group LLC
Snake Rivcr Alliance
By:
Kelsey Nunez
Attomey for Snake River Alliance
Brad Purdy
Attorney for CAPAI
STIPULATION AND SETTLEMENT _ AVU.E- 15-05 & AVU-G-Is.OI Page l8
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Sumcost
Scenario: AVU-E-1 s05 Settlement Case
Load Factor Peak Credit
Transmission By Demand 12 CP(b) (c) (d)
Descnptiofl
Functional Cost Compon$ts 8t Cunont Rdum by Schodulo
AVISTA UTILITIES ldaho Jurisdiction
Revenue to Cost by Functional Component Summay Elecuic Utility
For the T,r'lelve lllonths Ended December 31, 2014
(e) (0 G) 0) (D 0 (k)
Residential Gefleral Lrge Gen Exta Large Extra Large
SysEm Service Service Seilbe Gen Service SeMce CPTotal Sch 1 Sch 11-12 Sch2l-22 Sch 25 Sch 25P
01/01/16
(l) (m)
Pumping Sueet&
SeNice Arca Lighb
Sch 31-32 Sch 4'149
2,009,s19 388,872
364,384 42,983
2,077j64 2,459,555
826.933 s98.589
1
2
?
4
5
b
7
II
10
Production
Transmission
Disfibution
Commofl
Total Curent Rab Revenue
Expressed as $/kwh
Production
Transmission
Disfibution
Common
Total Cunenl irelded Rabs
1'16,381,261 43,834,300 15,151,702 m,9/t0,838 11,113,743 16,942,287
25,875,928 9,718,351 3,934,119 6,214,281 2,249,812 3,351,999
61,351,755 A,$1,66s 10,779,769 14,076,269 1,699,164 428,169
41.363.05s 21.554,684 6.430.410 7.127.612 2.089.282 2.735.545
24r'.,97a0n 104,939,000 35,46,000 54,359,000 17,152,000 23,458,000 5.278,000 3.490.000
$0,03787 $0.03820 $0.04174
$0,00842 $0.00847 $0.01084
$0,01996 $0.02600 $0.02970
$0,01346 $0.01879 $0.01771
$0.03855 $0.03s1s $0.03566 $0,03407 $0.02862
$0.00889 $0.00712 $0.00706 $0.00618 $0,00316
$0.02014 $0.00s37 $0.00090 $0.03s21 $0.18101
$0.01020 $0.00561 $0.00576 $0.01402 $0.04405
11 Poduction
12 Transmission
13 Distribution14 Common15 Total Uniform CunentCost
Functional Cost Compon$t3 at Unilorm Currcnl Rstum
$0.07972 $0.09146 $0.09999 $0.0r/79 $0.05425 $0.04938 $0.08948 $0.25684
115,n9,071 46,239,371 14,149,565 26,009,426 10,965,434 1s,396,018 1,9U,232 395,025
25,s31,066 11,31s,196 3,299,985 5,714,43s 2,170,174 2,6U,191 352,205 '14,88062,527,167 33,660,930 9,307,333 13,023,320 1,642,916 331,779 2,015,160 2,545,729
41,684,695 23,112,215 5,880,131 6,816,3'16 2,050,518 2,400,469 812,634 612,411
244,9720N 114,327,712 32,637,014 51,653,498 16,8A,043 n,762,457 5,164,232 3,598,045
$0,03750 $0.04030 $0.03898 $0.03735 $0.03468 $0.03241 $0.03364 $0.0A07
$0,00831 $0.00s6 $0.00909 $0.00818 $0.00686 $0.0055s $0.00597 $0.00330
$0.02035 $0.02934 $0.02s64 $0.01864 $0.00520 $0.00070 $0.03416 $0.18735
$0.01356 $0.02014 $0.01620 $0.00975 $0.00649 $0.00s05 $0.01378 $0.04507
$0.07972 $0.09964 $0.08991 $0.07392 $0.05323 $0.04371 $0.087s5 $0.26480
16
17
18
19
20
Exfessed a SkWh
Prcduclion
Transmission
Disfibution
Common
Total Curent Uniform Melded Rabs
Rdanu! to Colt Rdo at Cumnt RrtE 0.971.021.131.020.921.00 1'.t1 1.0s
Func{lonal Cost Componsfits at Propoood Retum by Sch€dulo
22
23
24
25
26
Production
Transmission
Disfibution
Common
Total Proposed Rate Revenue
as SkWh
Disfibution
Common
Total Proposed lvlelded Rates
Fundlonal Cost Componsr6 I Unitom R6qu6tcd Rdum
Production
Transmission
Distibution
Cormon
Total Unibrm Cost
Expressed as &kwh
Production
Transmission
Distibutlon
Common
Total Uniform [relded Rabs
Rwmuc to Colt Rstio .t Prcpot.d tutrr
Cumnt Rd$uG to Prepolld Coai Rrilo
Targrt Rry$ue lncreale
116,879,049 44,076,123 15,1W!11 27,U3,470 11,161,961 16,990,473 2,017,744 390,467
26,179,972 9,878,907 3,963,927 6,275,248 2,275,703 3,374,367 368,344 43,475
61,998,205 30,216,581 10,848,984 14,2U,700 1,717,451 431,172 2,097,3N 2,481,897
41,il4,n4 21,711,289 6,456,278 7,165,s82 2,101,885 2,745,987 831,583 &2,171
246,672,000 10s,883,000 36,468,000 s4,689,000 17,257,M 23,542,000 5,315,000 3,518,000
$0.02018 $0.02634 $0.02989 $0.02033 $0.00543 $0.00091 $0.03556 $0.18265
$0.01354 $0.01892 $0.0129 $0.01025 $0.00665 $0.00s78 $0.01410 $0.04432
$0,08027 $0.09228 $0.10046 $0.07826 $0.05458 $0.04956 $0.09011 $0.2s890
115,740,980 46,M,7n U,212,425 26,215,374 11,014,149 15,464,415 1,993,047 396,780
25,838,799 11,4s1,581 3,339,761 5,783,313 2,196,331 2,665,941 356,451 45,421
63,160,604 33,987,985 9,399,691 13,168,4't4 1,661,391 336,043 2,036,774 2,570,307
41,931,617 23,245,244 5,914,U7 6,8s9,212 2,63,251 2,415,291 817,619 616,354
246,672pN 115,129,600 32,866,523 52,026,313 16,935,122 20,881,690 5,203,891 3,628,861
$0.03766 $0.04048 $0.0391s $0.03751 $0.03484 $0.032s5 $0.03379 $0.02920
$0.00841 $0.00998 $0.00920 $0.00828 $0.00695 $0.00551 $0.00604 $0.00334
$0.02055 $0.02962 $0.02s89 $0.01884 $0.00s25 $0.00071 $0.034s3 $0.18916
$0.01365 $0.02026 $0,01629 $0.00982 $0.00653 $0.00508 $0.01386 $0.04s36
$0.08027 $0.10034 $0.09054 $0.07,145 $0.0s3s0 $0.04396 $0.08822 $0.26706
,l,700,000 10,190,000 (3,429,000) (2,333,000) (217,000) (2,576,000)
30
3'l
32
JJ
J4
35
36
37
38
39
40
41
0.971.02
t.0t
1.13
1.12
1.021.11
t.0t1.(N1.10
1.050.92
0.910.99
1.0042
S0.03841 l0.0,tlE7 t0.0:1870 $0.03530 30.03t728 Transmlssion 10.00852 t0.00861 S0.01092 t0.00898 $0.00720 $0.00710 $0.00621 $0.00320
43
Appendix B
(74,000)139,000
Page 4 ol 4
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AVISTA UTILITIES
Company Settlement Summary by Fundion with Margin Analysis
Case For the Year Ended December 31, 2014
(f)
Syslem
Line DescriDtion Total Sch 101
Natural Gas Utility
ldaho Jurisdidion
(s) (h) (i) (k)
Residential Large Firm lntenupt TransportService SeMce SeMce Service
Sch 111 Sch 131 Sch 146
(e)(d)(c)(b)
1
2
3
4
b
7
8
9
10
11
't2
Functional CoBt Compon3nts at Curront Ratss
Produclion
Underground Storag6
Distribution
Common
Total Currcnt Rats Rovenue
Excludo Cost of Gas w / Revenue Exp.
Totrl targin Royenuo at Curr3nt Rataa
Margin p€r Them at Cunent Rates
Production
Underground StoragB
Distribution
Common
337,031 235,918 97 ,171 1,399 2,542
't,7$j19 1,135,497 561,698 5,600 45,32424249,W 19,367,003 4,6',t4,U6 46,393 222,226
9.840.181 8.40'1.406 ',1.352.211 14.2U 72.360
36,173,000 25,1r9,8U 8,625,127 67,596 3/10,45200000
30J
s0.00413
$0.02137
$0.29681
$o.12044
$0.00423 $0.00423 $0.00423 $0.00094$0.0203E s0.0244E $0.01695 $0.01600
$0.34761 $0.20107 $0.14042 $0.08207s0.15080 s0.05893 $0.04299 50.02672
Total Current Margin Melded Rate p€r Them Jo.44275 t0.52303 10.28870
Func{ional CGt Compments at Unlfom Curront Rstum
337,03't 235,918 97,171'1,689,279 1,231,419 416,370
24,223,976 20,2%,739 3,685,561
S0.20'159 J0.12574
1,399 2,5425,255 36,23544,149 197,526
13 Produciion
'14 UndergroundStorage
15 Distribdion
16 Common
17 Total Unifom Curent Cost
1 E Excludo Cost of Gas w / Revenue Exp.
19 Total Unifom Curent Margin
9,922,715 8,625,255 1,2',t5,502 13,913 68,045
30,173,(no 30,3E9,33't 5,414,605 U,716 304348
30,'173,000 30,3E9,331 5,4't4,605 64716 304,3/A
Margin per Them at Uniform Cunent Rstum
Prod$tion
Underground Storags
Oistribution
Common
Total Cunent Uniform Margin M6ld€d Rate per Them
margln to Cost Rdio rt Current R.t s
s0.0@113
$0.02068
$0.29650
$0.12145
$0.00423
s0.022't0
$0.36430
$0.1 5481
$0.00423 $0.00423 $o.000e1
$0.01814 $0.01590 $O.0133E
$0.16061 $0.13363 $0.07295
$0.05297 $0.M211 $0.02513
to.4275
1.00
10.54545
0.96 1.O1 1.12
10.23595 10.195E7 10.11240
1.22
20
2',1
22
23
24
25
26
27
28
29
30
3'r
32
337,03'l
'1,951,059
26,1 14,616
't0,270,295
235,918
1,306,768
21,O27,055
8,801,083
97,17'l
591,232
4.802,732
'1,399 2,542
6,200 46,859
50,2E8 2U.il1
Functlonrl CGt Compononts at Propo3od Ratsa
Produclion
Undsrground Storagg
Oistribution
Common
Tot l Proposed Rate Rsvenue
Exclude Cost of Gas w / Revenue Exp.
Totll ilargin Roysnus at Propcsd Ratss
Common
Total Uniform Propossd Cost
Exclude Cost of Gas w / Revenus Exp.
Total Unifom Prcposed Margin
Margin per Them at Uniform Proposed Retum
Produclion
Underground Storage
Distribution
Common
Total Proposed Uniform Margin M6ld6d Rate por Therm
Mtrgln to Cost Ratio at Proposed R.to3
Cuttlnt tlargin to Propoled Cost Rato
1,379.W2 14,709 74.511
38,873,000
0
31,370,44 E,571,127 7\5*
0
358,452
0
36
37 Total Proposad Margin Melded Rats p€r Them
Funcffonal CGt CompononE .t Unifoam Prcposd Rotum
Produciion
Undorgrend Storage
Distribution
Common
38,073,000 31,370,84 e,57',t,127 72,596 35E,452
$0.15797 $0.06014 $0.04452 $o.o2752
t0.47335
337,031
'1,903,251
26,093,052
10,339,666
so.56307 t0.29942 $0.21973 $.13238
8,9A9242 1,265,',t12 14,474 70,838
38
39
40
41
42
43
44
45
46
47
,a
49
235,918 97,',t71'1,387,397 469,110
2't,808,556 4.O22.sO7
'1,399 2,542
5,920 40,A25
8.472 2'.t3.517
38,073,000
0
32,421,113 5,853,9@
0
70,265 327,71200
3E,673,0q' 32,121,113 5,853,900 70,265 327,72it
$0.00423 $0.00423 $0.00091
$0.02044 $0.01792 $0.01508
$0.17529 $0.14671 $0.07886
00.05513 $0.04381 $0.02616
$0.00413
$0.02330
$0.31 938
$0.12656
$0.00423
$0.02490
$0.39144
$0.16135
30.47335 l{r.58192 30.25510 30.12104
1.09
't.o1
1.17
t.t3
1.00
0.94
Appendix C
33
34 30.0a86 30.02345 30.02576
$0.12571
51
io.212s7
Page 4 of4
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AVISTA UTILITIES
IDAHO ELECTRIC, CASE NO. AVU-E-15-05
PRESENT AND PROPOSED RATE COMPONENTS BY SCHEDULE
Effective January 1, 2016
General
Rate
Inc/(Decrl
(e)
$0.00
$0.00078
$0.00087
$0.00
$0.00052
$0.00038
no charge
Base Tariff Present Present
Sch. Rate Other Adi.(1) Billinq Rate(b) (c) (d)(a)
Residential Service - Schedule 1
Basic Charge
Energy Charge:
First 600 k\Ms
All over 600 klMts
General Services - Schedule 11
Basic Charge
Energy Charge:
First 3,650 k\Ms
All over 3,650 kWhs
Demand Charge:
20 kW or less
Over 20 kW
Laroe General Service - Schedule 21
Energy Charge:
First 250,000 k\Ms
All over 250,000 kWhs
Demand Charge:
50 kW or less
Over 50 kW
Primary Voltage Discount
$5.2s
$0.0010't $0.08247
$0.00101 $0.09197
$10.00
$0.00148 $0.09782
$0.00148 $0.07326
no charge
$5.2s/kw
$0.00086 $0.06383
$0.00086 $0.05459
$350.00
$4.7slkw
$0.2olkw
$0.00019 $0.05231
$0.00019 $0.04433
$12,500
$4.50/kva
$0.2o/kw
$683,420
$0.00008 $0.04262
912,500
$4.50/kva
$2.00/kva
$0.2olkw
$617,940
$8.00
$0.00117 $0.09416
$0.00117 $0.08044
$5.25
$0.08146
$0.09096
$10.00
$0.09634
$0.07178
no charge
$s.2slkw
$0.06297
$0.05373
$350.00
$4.75lkw
$0.2olkw
$0.05212
$0.04414
$12,500
$4.50/kva
$0.20lkw
Present:
$0.04254
$12,500
$4.50/kva
$2.00/kva
$0.2olkw
Present:
$8.00
$0.09299
$0.07927
$0.00047
$0.00041
$0.00
$0.00039
$0.00032
$0.00018
$0.00
$0.00066
00.00056
Proposed
Billing
Rate
(0
$s.25
$0.08325
$0.09284
$r0.00
$0.09834
$0.07354
$5.2slkw
$0.06430
$0.0s500
$350.00
$4.75&W
$0.20lkw
$0.0s270
$0.0,1465
sr2,500
$4.50/kva
$0.2olkw
$687,360
$0.04280
$12,500
$4.50/kva
$2.00/kva
$0.20lkw
$619,920
$8.00
s0.09482
$0.08100
Proposed
Base Tariff
Rate
(s)
$s.25
$0.08224
$0.09183
010.00
00.09686
$0.07216
no charge
$5.2slkw
$0.063'04
$0.05414
$350.00
$4.75/kW
$0.2o/kw
$0.05251
$0.04446
012,500
fi.50/kva
$0.2olkw
$0.04272
$12,500
$4.50/kva
$2.00/kva
$0.2olkw
$8.00
$0.0936s
$0.07983
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 kwk\ /h
All additional kWhs
(1) lncludes all present rate adjustments: Schedule 59 - Residenlial & Farm Energy Rate Adjustment, Schedule 66 -
Temporary Power Cost Adjustment, Schedule 91 - Energy Efficiency Rider Adjustment, and Schedule g7 - Eamings
Test Rebate.
Stipulation and Settlement
Case No. AVU-E-15-05 and AVU-G-15-01
Avista
Page 2 of 4Appendix D
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AVISTA UNLMES
IDAHO GAS, CASE NO. AVU-G-{5{1
PRESENT ANO PROPOSED RATE COMPONENTS BY SCHEDULE
Effective January 1, 2016
Present Base Present
Distribution Billing Present
Tyoe of Service Rate Rate Adi.(l) Billinq Rate(a) (b) (c) (d)
$4.2s $4.2s
Usage Charge:
All therms $0.45372 $0.44741 $0.90113
Laroe 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
lnterruotible Service - Schedule 132
Usage Charge:
All Therms
Transooftation Service - Schedule 146
$225.00
s0.1 2075
$225.00
s0.1 2075
Proposed
Billing
Rate
(h)
$5.2s
$0.93708
$0.96337
$0.77916
$0.69745
$0.6,13,l(l
$100.75
$0.45962
$0.60214
1225.00
$0.12472
Proposed
BaBe
Distribution
Rate
(i)
$5.25
$0.47746
$0.s0375
$0.319s4
$0.23783
$0.1838r
$100.75
$0.00000
$0.2t972
1225.00
$0.12740
$0.47500 $0.114741 $0.92241
$0.31030 $0.44741 $0.75771
$0.23095 $O.44741 $0.67836
$0.17850 $O.44741 $0.62591
$95.00 $9s.00
$0.00000 $0.44741 $0.4/.741
$0.20459 $0.37021 $0.57480
Sch 197 - 2013
General Earnings TestRate & PGA Rebatelncrease Erpiration(e) (0
$r.00
$0.02374 $0.01,189
t0.02875 $0.0{1189
$0.00924 $0.01,l89
$0.00688 $0.01489i0.00531 s0.01lag
$5.75
$0.01,l89
$0.01513 $0.01'189
$0.(x)
10.00665
Sch 197 - 2014
Earnings Test
Rebate
Credit (2)
(s)
($0.00268)
($0.00268)
($0.00268)
($0.00268)
($0.00268)
($0.00268)
($0.00268)
Basic Charge
Usage Charge:
All Therms
(1) lncludes Schedule 150 - Purchased Gas CostAdjustment, Schedule 155 - Gas RateAdjustment, and Schedule 197 - PGA/DSM Rebate
(2)The 2014 Eamings Test Rebate Credit will be effective January 1, 2016 through December 31, 20'16
($0.00268)
Stipulation and Settlement
Case No. AVU-E-15-05 and AVU-G-15-01
Avista
Page 4 of 4Appendix D
Schedule 197
Present Rebate Expirinq ,l 2/3{/201 5
Rebate of 2013 Earnings Test & DSM Deferrals
GeneralService
Large GeneralService
lnterruptible Service
Rate
Schedule
101
111t112
131t132
Total
Pro Forma
Therms
55,714,011
22,947,786
330,396
2013 Earnings
Rebate & DSM
Reduction
$ 829,582
$ 341,693$ 4.920
Uniform Cents Reduction
Prooosed Rebate Effective 1/l/16 - 12131/16
Rebate of 2014 Earnings Test
78,992,193 $ 1,176,194
0.01489
2014 EarningsRate Pro Forma Rebate
Schedule Therms Reduction
101 55,714,011 $ (149,314)111t112 22,947,786 $ (61,500)131t132 330,396 $ (885)146 2,707,661 $ (7,2s7)Total 81,699,854 $ (218,956)
GeneralService
Large General Service
lnterruptible Service
Transportation Service
2014 Earnings Test Balance
Uniform Cents Reduction
$
$
(219,212)
(0.00268)
Stipulation and Settlement
Case No. AVU-E-15-05 and AVU-G-15-01
Avista
Page 1 of 1Appendix E