20161212Exhibit.pdf

or:c .:1\tED i ·~ h.-/ -..~ • -
DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR ,-i~ •ru I'--~~ q; 50 tw J .J 1.•..J 'f Lt h 1 ! .,
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
• I ••
C •' ; ·,, ,, .... l: .: .... ,.:iOiJ
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: [phone]
FACSIMILE: [phone]
[e-mail]
BEFORE THE :IDAHO PUBLIC UTJ:LJ:TJ:ES COMMISSION
IN THE MATTER OF THE APPLICATION
OF AVISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC
SERVICE TO ELECTRIC CUSTOMERS
IN THE STATE OF IDAHO
) CASE NO. AVU-E-16-03
)
)
)
) EXHIBIT NO. 14
)
)ELIZABETH M. ANDREWS _________________ )
FOR AVISTA CORPORATION
(ELECTRIC)
David J. Meyer, Esq.
Vice President and Chief Counsel of
Regulatory and Governmental Affairs
A vista Corporation
1411 E. Mission A venue
P.O. Box 3727
Spokane, Washington 99220
Phone:[phone],Fax: [phone]
Brandon Karpen
Deputy Attorney General
Idaho Public Utilities Commission Staff
P.O. Box 83720
Boise, ID 83720-0074
Phone: [phone], Fax: [phone]
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF A VISTA CORPORATION OBA AVISTA ) CASE NO. A VU-E-16-03
UTILITIES FOR AUTHORITY TO )
INCREASE ITS RA TES AND CHARGES )
FOR ELECTRIC SERVICE IN IDAHO )
) STIPULATION AND SETTLEMENT
This Stipulation is entered into by and among A vista 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"), 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").
STIPULA TlON AND SETTLEMENT -A VU-E-16-03 Page 1
I. INTRODUCTION
1. The terms and conditions of this Stipulation are set forth herein. The Parties agree
that this Stipulation represents a fair, just and reasonable compromise of all the issues raised in
the proceeding, is in the public interest and its acceptance by the Commission represents a
reasonable resolution of the multiple issues identified in this case. 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 May 26, 2016, Avista filed an Application with the Commission for authority
to increase revenue effective January 1, 2017 for electric service in Idaho by 6.3%. If approved,
the Company's 2017 revenues for electric base retail rates would have increased by $15.4 million
annually. By Order No. 33536, dated June 7, 2016, the Commission suspended the proposed
schedules of rates and charges for electric service.
3. Petitions to intervene in this proceeding were filed by Clearwater, Idaho Forest,
CAPAI, and Snake River. The Commission granted these interventions through IPUC Order
Nos. 33539, 33542, 33549 and 33550.
4. A settlement conference was noticed and held in the Commission offices on
October 3, 20 J 6, and was attended by parties to this case.1 As a compromise of positions in this
case, and for other consideration as set forth below, the Parties agree to the following terms:
1 Clearwater and Snake River were unable to attend the settlement conference, but are supportive of the Stipulation
and Settlement.
STlPULA TION AND SETTLEMENT -A VU-E-16-03 Page2
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 $6.25 million in
additional annual electric revenue, which represents a 2.6% increase in electric annual base tariff
revenues. New electric rates would become effective January 1, 2017.
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:
Capital
Component Structure Cost Weighted Cost
Debt 50% 5.67% 2.83%
Con:nmn_ Equity 50% ' 9.50% 4.75%
Total 100% 7.58%
A. ELECTRIC REVENUE REQUIREMENT
7. Overview of Electric Revenue Requirement. Below is a summary table and
descriptions of the electric revenue requirement components agreed to by the Parties:
SUMMARY TABLE OF ADJUSTMENTS TO ELECTRIC REVENUE REQUIREMENT
EFFECTIVE JANUARY I, 2017
(OOOs of Dollars)
Amount as Filed:
Adjustments:
a.) Cost of Capital
b.) Revise Net Rate Base
c.) Revise Deferred Debits and Credits to Reflect Corrected 2016 Balances
d.) Remove 2017 Non-Union Labor Expenses
e.) Update 2016 Employee Benefit Costs
£) Add Nine Mile Investment Tax Credit
g.) Remove Officer Incentives
h.) Remove 2015 Storm Costs
i.) Include Palouse Wind in PCA
j.) Miscellaneous A&G Adjustments: Board of Director Expenses, Reallocation of
Legal Expenses, Expired Leases and Inclusion of O&M Savings
Adjusted Amounts Effective January 1, 2017
STIPULATION AND SETTLEMENT -A VU-E-16-03
Revenue
Requirement Rate Base
$ 15,433 $ 754,636
$ (2,471)
$ (1,329) $ (740)
$ (62) $ 107
$ (310)
$ 1,221
$ (162)
$ (171)
$ (1 ,057)
$ (4,509)
$ (333)
$ 6,250 $ 754,003
Page 3
a. Cost of Capital. As previously described (see Paragraph 6 above). This adjustment
reduces the overall revenue requirement by $2.4 71 million.
b. Revise Net Rate Base. Reflects adjustments to net rate base to: 1) update information
related to 2016 capital additions; 2) remove adjustments proposed by the Company
for Plant Held For Future Use and 2017 capital additions, including related
depreciation expense, as well as the impact on Accumulated Depreciation and
Accumulated Deferred Federal Income Taxes; and 3) remove agreed-upon amount
related to Asset Management Transmission project. This adjustment reduces the
overall revenue requirement by $1.329 million and reduces net rate base by $740,000.
c. Revise Deferred Debits and Credits. Revises the deferred debits and credits
regulatory balances to reflect corrected balances as of December 2016, rather than the
2017 balances as proposed by the Company. This adjustment decreases the overall
revenue requirement by $62,000 and increases rate base by $107,000.
d. Remove 2017 Non-Union Labor Expenses -This adjustment reduces the overall
revenue requirement by $310,000, by removing 2017 incremental non-union labor
expenses.
e. Update 2016 Employee Benefit Costs. Reflects updated information related to 2016
incremental pension and medical costs. This adjustment increases the overall revenue
\
requirement by $1.221 million.
f. Add Nine Mile Investment Tax Credit. Reflects the amortization of the investment
tax credit benefit associated with the Nine Mile Redevelopment upgrade project on
Units I and 2.
g. Remove Officer Incentives. Reflects the removal of all officer incentives. This
adjustment decreases the overall revenue requirement by $171 ,000.
STIPULATION AND SETTLEMENT -A VU-E-16-03 Page 4
h. Remove 2015 Storm Costs. Removes 2015 storm-related expenses included in the
Company's historical test period beyond the 6-year average (2009-2014) of storm
expenses. Includes $210,000 of amortization expense representing the customer
portion ($630,000) to recover for regulatory purposes over the period 2017-2019.
This adjustment reduces the overall revenue requirement by $1.057 million.
1. Include Palouse Wind in PCA. Reflects the removal of the Palouse Wind Power
Purchase Agreement net expenses from base power supply expense. 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, I 0% Company). This adjustment decreases the
overall revenue requirement by $4.509 million.
j. Miscellaneous A&G Adjustments. Reflects the net change in administrative and
general (A&G) expenses related to: I) removing additional Board of Director
expenses included in 2015 ($159,000); 2) removing legal expenses allocated to Idaho
electric in error ($33,000); 3) removing expenses associated with certain expired
leases in 2015 ($62,000); and 4) inclusion of the O&M savings associated with the
Company's Street & Area Light project ($79,000). This adjustment decreases the
overall revenue requirement by $333,000.
B. OTHER SETTLEMENT COMPONENTS
8. 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, 2017
settlement revenue requirement for purposes of the monthly PCA mechanism calculations are
detailed in Appendix A.
STIPULATION AND SETTLEMENT-A VU-E-16-03 Page 5
9. Electric Fixed Cost Adjustment Mechanism Authorized Base. The new level of
baseline values for the electric fixed cost adjustment mechanism resulting from the January I,
20 l 7 settlement revenue requirement are detailed in Appendix B.
C. COST OF SERVICE/RATE SPREAD/RATE DESIGN/LOW INCOME
I 0. 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 coincident
peak allocation factor. For settlement purposes, the Parties agreed to use a pro-rata allocation
based on the Company's proposed 25% move towards unity for purposes of spreading the
revised electric revenue requirement, while not agreeing to any particular cost of service
methodology.
l l . Rate Spread/Rate Design (Base Rate Changes). As indicated above, the Parties
agreed that the increase in base revenues would be spread to all electric rate schedules on a pro­
rata allocation of the Company's rate spread percentages from its original filing.
12. Electric Rate Design. With the exception of the Residential Basic Charge, the
Parties agree to the rate design changes proposed by the Company in Mr. Ehrbar's direct
testimony. For the electric Residential Basic Charge (Schedule 1 ), the Parties agreed that it will
increase from $5.25 per month to $5.75 per month, an increase of $0.50 per month. Appendix C
provides a summary of the current and revised rates and charges (as per the Settlement) for
electric service.
13. Resulting Percentage Increase by Electric Service Schedule. The following tables
reflect the agreed-upon percentage increase by schedule for electric service:
STIPULATION AND SETTLEMENT -AVU-E-16-03 Page 6
Increase in Increase in
Rate Schedule Base Rates Billing Rates
Residential Schedule 1 3.2% 3.1%
General Service Schedules I I /12 1.9% 1.8%
Large General Service Schedules 2 I /22 2.3% 2.3%
Extra Large General Service Schedule 25 1.9% 1.9%
Clearwater Paper Schedule 25P 1.8% 1.8%
Pumping Service Schedules 3 I /32 3.1% 3.0%
Street & Area Lights Schedules 41-48 3.4% 3.3%
Overall 2.6% 2.5%
14. Electric Cost of Service Workshop. The Parties agreed, prior to the Company's
next general rate case filing , to meet and confer regarding the Company's electric cost of service
study. Included in the workshop(s) would be discussion related to the methodologies used by
A vista to classify and allocate its costs, as well as a review of the changes that occurred between
the cost of service study results from the Company's 2015 general rate case filing and its 2016
general rate case filing.
The Company will provide available information, studies and data requested by a Party
so as to enable meaningful workshop participation and discussion of issues.
Unless it decides to do so, a Party shall not be bound by workshop discussions and may
contest cost of service and rate spread issues in subsequent proceedings.
15. Collaboration on Low lncome Issues. 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 to explore
policy goals and program structures that may enhance or improve Avista's low-income program.
STIPULATION AND SETTLEMENT - A VU-E-16-03 Page 7
·-·-·-·· ···-····-··-··---------· ------------~
IV. OTHER GENERAL PROVISIONS
16. 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.
17. The Parties submit this Stipulation to the Commission and recommend approval
in its entirety pursuant to RP 274. Parties shall support this Stipulation before the Commission,
and no Party shall appeal a Commission Order approving the Stipulation or an issue resolved by
the Stipulation. If this Stipulation is challenged by any person not a party to the Stipulation, the
Parties to this Stipulation reserve the right to file testimony, cross-examine witnesses and put on
such case as they deem appropriate to respond fully to the issues presented, including the right to
raise issues that are incorporated in the settlement terms embodied in this Stipulation.
Notwithstanding this reservation of rights, the Parties to this Stipulation agree that they will
continue to support the Commission's adoption of the terms of this Stipulation.
18. If the Commission rejects any part or all of this Stipulation or imposes any
additional material conditions on approval of this Stipulation, each Party reserves the right, upon
written notice to the Commission and the other Parties to this proceeding, within 14 days of the
date of such action by the Commission, to withdraw from this Stipulation. In such case, no Party
shall be bound or prejudiced by the terms of this Stipulation, and each Party shall be entitled to
seek reconsideration of the Commission's order, file testimony as it chooses, cross-examine
witnesses, and do all other things necessary to put on such case as it deems appropriate. In such
case, the Parties immediately will request the prompt reconvening of a prehearing conference for
STIPULATION AND SETTLEMENT -A VU-E-16-03 Page 8
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.
19. The Parties agree that this Stipulation is in the public interest and that all of its
terms and conditions are fair, just and reasonable.
20. No Party shall be bound, benefited or prejudiced by any position asserted in the
negotiation of this Stipulation, except to the extent expressly stated herein, nor shall this
Stipulation be construed as a waiver of the rights of any Party unless such rights are expressly
waived herein. Execution of this Stipulation shall not be deemed to constitute an
acknowledgment by any Party of the validity or invalidity of any particular method, theory or
principle of regulation or cost recovery. No Party shall be deemed to have agreed that any
method, theory or principle of regulation or cost recovery employed in arriving at this Stipulation
is appropriate for resolving any issues in any other proceeding in the future. No findings of fact
or conclusions of law other than those stated herein shall be deemed to be implicit in this
Stipulation.
21 . 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.
22. This Stipulation may be executed in counterparts and each signed counterpart
shall constitute an original document.
STIPULATION AND SETTLEMENT-AVU-E-16-03 Page 9
I ----
a. ~.s-DA TED this _I_ day of October, 2016.
A vista Corporation
By:~/
DtilMeyer
Attorney for A vista Corporation
Clearwater Paper Corporation
By: ____________ _
Peter Richardson
Attorney for Clearwater Paper
Community Action Partnership Association
ofldaho
By: ____________ _
Brad Purdy
Attorney for CAP AI
Idaho Public Utilities Commission Staff
By: ____________ _
Brandon Karpen
Deputy Attorney General
Idaho Forest Group
By: ____________ _
Dean J. Miller
Attorney for Idaho Forest Group LLC
Snake River Alliance
By: ____________ _
Ken Miller
Snake River Alliance
STIPULATION AND SETILEMENT-A VU-E-16-03 Page 10
I I
DATED this f f~ day of Octobert 2016.
A vista Corporation
By: ___________ _
David J. Meyer
Attorney for A vista Corporation
Clemwater Paper Corporation
Peter Richardson
Attorney for Clearwater Paper
Community Action Partnership Association
ofldaho
By:.~------------Brad Purdy
Attorney for CAP AI
Idaho Forest Group
By: __________ _
Dean J. Miller
Attorney for Idaho Forest Group LLC
Snake River Alliance
By: ___________ _
Ken Miller
Snake River Alliance
STIPULATION AND SETTI..EMENT -A VU-E-16-03 Page 10
A vista Corporation
David J. Meyer
Attorney for A vista Corporation
CIZJ:a Corpor~tion
By. ·r~
Peter Richardson
Attorney for Clearwater Paper
Community Action Partnership Association
of Idaho
By: __ ____, __________ ...:;
Brad Purdy
Attorney for CAP AI
Idaho Forest Group
Dean J. Miller
Attorney for Idaho"_Forest Groll}
Snake River Alliance
-------------------------------······-·················
DATED this __ day of October, 2016.
A vista Corporation
By: ___________ _
David J. Meyer
Attorney for A vista Corporation
Clearwater Paper Corporation
By: ____________ _
Peter Richardson
Attorney for Clearwater Paper
Community Action Partnership Association
of Idaho
By: ___________ _
Brad Purdy
Attorney for CAP AI
Idaho Public Utilities Commission Staff
By: ___________ _
Brandon Karpen
Deputy Attorney General
=~~ Dean J. Miller
Attorney for Idaho Forest Group LLC
Snake River Alliance
By: ___________ _
Ken Miller
Snake River Alliance
STIPULATION AND SETTLEMENT - A VU-E-16-03 Page 10
DATED this __ day of October, 2016.
A vista Corporation Idaho Public Utilities Commission Staff
David J. Meyer Brandon Karpen
Attorney for A vista Corporation Deputy Attorney General
Clearwater Paper Corporation Idaho Forest Group
By: _____________ _
Peter Richardson Dean J. Miller
Attorney for Clearwater Paper Attorney for Idaho Forest Group LLC
Community Action Partnership Association ::dab/?~
b
Brad Purdy
Attorn~
Snake River Alliance
By: ___________ _
Ken Miller
Snake River Alliance
STIPULATION AND SETTLEMENT -AVU-E-16-03 Page 10
-·---·-··-------------------------------------------,
DATED this __ day of October, 2016.
A vista Corporation
By: ___________ _
David J. Meyer
Attorney for A vista Corporation
Clearwater Paper Corporation
By: ___________ _
Peter Richardson
Attorney for Clearwater Paper
Community Action Partnership Association
ofldaho
By: ___________ _
Brad Purdy
Attorney for CAP AI
Idaho Public Utilities Commission Staff
By: ____________ _
Brandon Karpen
Deputy Attorney General
Idaho Forest Group
By: ___________ _
Dean J. Miller
Attorney for Idaho Forest Group LLC
Snake ~er Alliance
By:~~
Ken Miller
Snake River Alliance
STIPULATION AND SETILEMENT-AVU-E-16-03 Page 10
Avista Corp
Proforma January 2017 -December 2017
PCA Authorized Expense and Retail Sales
2015 Normallzed Loads
PCA Authori1ed Power l!Ul!l!lll! Exl!!nse • l!ll!!tem Numbers !1)
Total January February March ~ .M!Y
Account 555 -Purchased Power $90,526,809 $9,519,018 $8,941,137 $8,090,123 $7,193,081 $5,574,392
Account 501 -Thermal Fuel $28,582.064 $2,623,577 $2.414,726 $2,489,588 $2,219,535 $1,919,943
Account 547 -Natural Gas Fuel $83,615.977 $7,496.448 $6,383,459 $6,191.000 $4,127,172 $2,227.503
Account 447 -Sale for Resale $42,666,054 $3,853,546 $3,409,878 $3,652,294 $4,889,733 $3,785,610
Power Supply Expense $140,058,796 $15,785.497 $14,329.444 $13,118.418 $8,650,056 $5,936,228
Transmission Expense $17,696,508 $1 ,494,602 $1.475,745 $1,463,502 $1 ,469,692 $1 ,454,063
Transmission Revenue $17,163,284 $1,258.554 $1,342,410 $1,380.906 $1,325,245 $1,456.540
Net REC Revenue $3,423.000 $290,850 $262,050 $290,850 $281,250 $290,850
$137,169,021
PCA !dal!o Retell ljales
Total January February March ~ .M!Y
Tatel Retail Sales, MWh 3,011,312 287,473 258,568 271,002 228,286 228,974
Load Change Adjustment Rate $24.00 /M'Nn
1) Multiply system numbers by 34.37% to determine Idaho share.
2) 12 months ended December 2015 weather normalized Idaho retail sales.
Appendix A
June
$5,284,240
$1 ,572,469
$1,803.506
$2,350,863
$6,309,353
$1.425.853
$1,614,866
$281,250
June
224,777
,1l!!Y. August September October November December
$6,394,106 $7,883,449 $6,345,982 $6,367,918 $9,249,398 $9,683,965
$2,337,541 $2,599,424 $2,567,872 $2,552,450 $2,593,186 $2,691.753
$3,770.606 $5,642.678 $5,571 .559 $5,667,221 $6,527.519 $8,207.306
$3,011,999 $2,803,724 $2,951 ,547 $2,433,459 $4,254,971 $5,268.431
$9.490,254 $13,321.827 $11,533,866 $12,154,129 $14,115,132 $15,314,593
$1,474.893 $1,469,493 $1,450,695
$1,670.553 $1,520,946 $1,466,611
$290,850 $290,850 $281 ,250
,1l!!Y. August September
245.462 255,918 214,673
$1,483.230 $1.490.253 $1,544,488
$1,406,355 $1 ,406,387 $1,313,910
$290,850 $281,250 $290,850
October November ~
238,519 248,276 309,383
Stipulation and Settlement
Case No. AVU-E-16-03
Avista
Page 1 of 1
Avista Utilities
Electric Fixed Cost Adjustment Mechanism (Idaho)
Development of Fixed Cost Adjustment Revenue by Rate Schedule -Electric
AVU-E-16-03 Rates Effective 1/1/2017
RESIDENTIAL GENERAL SVC. LG. GEN. SVC.
TOTAL SCHEDULE I SCH. 11,12 SCH. 21,22
I Total Normalized Test Year Revenue $ 243,599,000 $ 105,522,000 $ 36,021,000 $ 52,133,000
2 Proposed Revenue Increase $ 6,250,000 $ 3,330,000 $ 667,000 $ 1,196,000
3 Total Rate Revenue (January I, 2017) $ 249,849,000 $ I 08,852,000 $ 36,688,000 $ 53,329,000
4 Normalized kWhs (Test Year) 3,011,311,824 1,143,267,490 357,684,869 657,453,609
5 Load Change Adjustment Rate (Ln 14) $ 0.02416 $ 0.02416 $ 0.02416 $ 0.02416
6 Variable Power Supply Revenue (Ln 4 • Ln 5) $ 72,753,294 $ 27,621,343 $ 8,641,666 $ 15,884,079
6A Fixed Production and Transmission Rate per kWh (New Customers Only) $ 0.02459 $ 0.02838 $ 0.02407
68 Fixed Production and Transmission Revenue (New Customers Only) $ 70,578,572 $ 28,117,257 $ 10,149,399 $ 15,825,220
7 Subtotal (Ln 3 -Ln 6) ('rest Year Customers) $ 151 ,061,711 $ 81,230,657 $ 28,046,334 $ 37,444,921
7A Subtotal (Ln 3 -Ln 6-Ln 68) (New Customers) $ 95,866,503 $ 53,113,401 $ 17,896,935 $ 21 ,619,701
8 Customer Bills (Test Year) 1,525,780 1,246,051 249,128 13,816
9 Proposed Fixed Charges $ 5.75 $ 12.00 $ 400.00
10 Fixed Charge Revenue (Ln 8 • Ln 9) $ 15,848,579 $ 7,164,793 $ 2,989,536 $ 5,526,400
II Fixed Cost Adjustment Revenue (Ln 7 -Ln I 0) (Test Year Customers) $ 135,213,132 s 74,065,864 s 25,056,798 $ 31,918,521
l lA Fixed Cost Adjustment Revenue (Ln 7A -Ln 10) (New Customers) $ 80,017,924 $ 45,948,607 $ 14,907,399 $ 16,093,301
12 Load Change Adjustment Rate $0.02400
13 Gross Up Factor for Revenue Related Exp 100.68%
14 Grossed Up Load Change Adjustment Rate $0.02416
Residential Non-Residential Group
IS Average Number of Customers (Line 8 I 12) 103,838 23,311
16 Annual kWh 1,143,267,490 1,080,502,749
17 Basic Charge Revenues 7,164,793 8,683,786
18 Customer Bills 1,246,051 279,729
19 Average Basic Charge $5.75 $31.04
Appendix B
$
$
$
$
$
$
$
$
$
$
$
$
$
OTHER
PUMPING SERVICE
SCH. 31, 32 SCHEDULES
5,742,000 $ 44,181,000
177,000 $ 880,000
5,919,000 $ 45,061,000
65,364,271 787,541,585
0.02416
1,579,201 $ 19,027,005
0.01688
1,103,332 $ 15,383,365
4,339,799 Excluded From 3,236,467 Fixed Cost
16,785 Adjustment
10.00
167,850
4,171,949
3,068,617
Stipulation and Settlement
Case No. AVU-E-16-03
Avista
Page 1 of 4
Line
No.
2
3
2
3
Avista Utilities
Electric Fixed Cost Adjustment Mechanism (Idaho)
Development of Annual Fixed Cost Adjustment Revenue Per Customer -Electric
A VU-E-16-03 Rates Effective 1/1/2017
Source
(a) (b)
Existing Customer FCA
Fixed Cost Adjustment Revenue Page 1 $
Test Year Number of Customers Revenue Data
Fixed Cost Adjustment Revenue Per Customer (1)/(2) $
New Customer FCA
Fixed Cost Adjustment Revenue Page I $
Test Year Number of Customers Revenue Data
Fixed Cost Adjustment Revenue Per Customer (1)/(2) $
* Schedules 11 , 12, 21 , 22, 31 , and 32.
Appendix B
Residential
(c)
74,065,864
103,838
713.29
45,948,607
103,838
442.50
Non-Residential
$
$
$
$
Schedules*
(d)
61 ,147,268
23,311
2,623 .14
34,069,317
23,311
1,461 .53
Stipulation and Settlement
Case No. AVU-E-16-03
Avista
Page 2 of 4
Avista Utilitiu
Electric Fiud Cost Adjustment Mechanism (Idaho)
Devtlopment of Monthly Fiud Cost Adjustment Revtnue Per Customer -Electric
A VU-E-16-03 Rates Effective 1/1/2017
Liu Source No. Ju F•b M" Ap, !\11y Jun Jul Aug
(a) (b) (c) (d) (c) (t) (g) (h) (i) fj)
~
8uid,miJ1/
-Weather-NonnaJiz.ed kWh Sales Monthly Test Year 134,935.067 106,332,869 111,428,605 K3,66K.292 77,786,324 69,134,768 86,644,4<14 79,655,406
-'Y. of Annual Total 'Y•ofTotal 11.80% 9.30-/e 9.75% 7.32% 680% 6.05% 7.SIWo 6.97%
6 Non-Rerldentiat•
-Wcathcr-Normahzed kWh Sales Monthly Test Year k6,125,182 89,927,640 90,755,331 &3,493,150 87,18),940 SK,747,983 91,963,568 97,627,588
- % of Annual Total %ofTotal 7.97% IU2% 8.40% 7.73% 8.07"/o 8.2lo/o 8.51% 904%
1
10
II M211•1x Ei1al ,m1 6di121mu1 Bn,11, en t:111amn f 'BtC"l
12 t:.e:. rm r,•r:: '91!1.•r. k!f.ct!?!!!a:1
13 R~skien11al
14 -2016 Fixed Cost AdJ. Rc\lenue per Customer Page 2
15 -2016 Monthly Fixed Cost Adj. Rcvcnui: per Custom (4), (14) s 84.19 S 66.34 s 69 52 5 52.20 5 4&.53 5 43.13 5 54.06 S 49.70 S
16
17 Non-Re1idrm1af•
18 -2016 Fixed Cost Adj. Revenue per Customer Page 2
19 -2016 Monthly Fixed Cost Adj. Revenue per Custom (8), (18) $ 209.09 s 218.32 s 220.33 s 202.70 s 211 66 S 21S.4S s 223.26 s 237.01 s
20
21
22 For New CustOM~n
23 Bni!knJkJJ
24 -2016 Fixed Cost Adj. Revenue per Customer Page 2
25 -2016 Monthly Fixed Cost Adj. Revenue per Custom (4), (24) s 52.23 s 41.16 s 43.13 s 32.38 s 30 I I s 26.76 S 33.54 s JO.Kl s
26
27 Non-Re.mlemiof•
28 -2016 Fixed Cost Adj. RcvcnlN: per Cus&omcr Page 2
29 -2016 Monthly Fixed Cost Adj. Revenue per Custom (8), (28) $ 116.50 S 121.64 S 122.76 S 112.94 $ 117 93 s 120.04 s 124.39 s 132.05 $
• ScheduJu 11, 12,21.22,31.and 32.
Appendix B
S.p Oct
(k) (I)
67,301,724 82,07),309
5.89"k 7.18%
86,161,233 91,867,649
7.97% 8.50%
41.99 s 51.21 $
209.17 s 223.03 s
26.05 s 31.77 s
116.55 s 124.26 S
Nov Ott TOTAL
(m) (n) (o)
101,867,616 142,439,066 1.14),267,490
8.91% 12.46o/. 100.00-/o
X.4,390,531 102,258,945 1.mm.502,749
7.81% 9.46% 100.00"/,
s 713.29
63.56 s 88,87 s 713.29
s 2,623.14
204.88 s 248.25 $ 2,623.14
s 442.50
39.43 s 55.13 s 442.50
s 1,461.53
I 14.15 s 138.32 s 1,461.53
Stipulation and Settlement
Case No. AVU-E-16-03
Avista
Page 3 of 4
Sumcost AVISTA UTILITIES Idaho Jurisdiction
Scenario: AVU-E-1~3 Settlemenl Case Revenue to C.ost by Functional Component Summary Electric Utility 10/03116
Load Factor Peak Credit For the Twelve Months Ended December 31, 2015
Transmission By Demand 12 CP
(b) (c) (d) (e) (f) (g) (h) (i) G) (k) (I) (m)
Residenlial General Large Gen Extra Large Extra Large Pumping Street &
System Service Service Service Gen Service Service CP Service Area Lights
Description Total Sch 1 Sch 11-12 Sch 21-22 Sch 25 Sch 25P Sch 31-32 Sch 41-49
Functional Coat Components at Current Return by Schedule
Production 115,040,037 44,320.419 14,809,845 25,422,314 12,569,224 15,262,249 2,227,995 427,991
Transmission 25,264,199 9,933,659 3,684,724 5,699,676 2,409,625 3,092,119 394,325 50,070
3 Distribution 61,360,578 29,280,337 10,965,292 14,030,362 2,047,999 383,093 2,205,173 2,448,321
4 Comrron 41,934,186 21,987,585 6,561,139 6,980,648 2,392,152 2,509,538 914,507 588,617
5 Total Current Rate Revenue 243,599,000 105,522,000 36,021,000 52,133,000 19,419,000 21,247.000 5.742,000 3,515,000
Expressed as $/kWh
Production $0.03820 $0 03877 $0.04140 $0.03867 $0.03552 $0.03638 $0.03409 $0.03016
Transmission $0.00839 $0.00869 $0.01030 $0.00867 $0.00681 $0.00737 $0.00603 $0.00353
Distribution $0.02038 $0.02561 $0.03066 $0.02134 $0.00579 $0.00091 $0.03374 $0.17255
9 Common $0.01393 $0.01923 $0.01834 $0.01062 $0.00676 $0.00598 $0.01399 $0.04148
10 Total Current Melded Rates $0.08089 $0.09230 $0.10071 SO 07930 $0.05487 $0.05065 $0.08785 $0.24772
Functional Coat Components at Uniform Current Return
11 Production 114,116,865 46,899,317 13,687,291 24,468,703 11,915,390 14,434,008 2,280,276 431,879
12 Transmission 25,076,464 11,609,150 3,032,045 5,170,758 2,106,273 2,687,382 419,574 51,282
13 Distribution 62,120,226 32,911,083 9,379,279 12,854,443 1,815,929 334,848 2,325,977 2,498,666
14 Common 42,285,445 23,644,757 5,929,464 6,620,623 2,224,127 2,326,060 944,028 596,386
15 Total Uniform Current Cost 243,599,000 115,064,307 32,028,080 49,114,527 18,061,720 19.782,298 5,969,855 3,578,213
Expressed as $/kWh
16 Production $0.03790 $0.04102 $0.03827 $0.03722 $0.03367 $003441 $0.03489 $003044
17 Transmission $0.00833 $0.01015 $0.00848 $0 00786 $0.00595 $000641 $0.00642 $0.00361
18 Distnbution $0.02063 $0.02879 $0.02622 $0.01955 $0.00513 $0.00080 $0.03558 $0.17610
19 Common S0.01404 $0.02068 $0.01658 $0.01007 $0.00628 $0.00555 $0.01444 $0.04203
20 Total Current Uniform Melded Rates $0.08089 $0.10065 $0.08954 $0.07470 $0.05104 $0.04716 $0.09133 $0.25218
21 Revenue to COit Ratio II Current RIies 1.00 0.92 1.12 1.06 1.08 1.07 0.96 0.98
Functional Coat Components at Proposed Return by Schedule
22 Production 116,951,569 45,220,072 14,997,271 25.799,984 12,749,325 15,481,021 2,268,589 435,306
23 Trans mission 26,380,297 10,518,528 3,793,794 5,909,315 2,493,252 3,199,113 413,944 52,352
24 Distribution 63,624,243 30,547,580 11,230,294 14,496.417 2,111,971 395,846 2,299,031 2,543,103
25 Common 42,892,891 22,565,820 6,666,641 7,123,284 2,438,451 2,558,020 937,436 603,239
26 Total Proposed Rate Revenue 249,849,000 108,852,000 36,688,000 53,329,000 19,793,000 21,634,000 5,919,000 3,634,000
Expressed as $1kWh
27 Production $0.03884 $0.03955 $0.04193 $0.03924 $0.03603 $0.03691 $0.03471 $0.03068
28 Tran1mi11ion $0.00876 $0.00920 $0.01061 $0.00899 $0.00705 $0.00763 $0.00633 $0.00369
29 Distribution $0.02113 $0.02672 $0.03140 $0.02205 $0.00597 $0.00094 $0.03517 $0.17923
30 Common $0.01424 $0.01974 $0.01864 $0.01083 $0.00689 $0.00610 $0.01434 $0.04251
31 Total Proposed Melded Rates $0.08297 $0.09521 $0.10257 $008111 $0.05593 $0.05157 $0.09055 $0.25611
Functional Coat Components at Uniform Requested Return
32 Production 116,060,094 47,697,938 13,920,364 24,885,366 12,118,290 14,679,797 2,319,105 439,233
33 Transmission 26,198,029 12,128,378 3,167,656 5,402,024 2,200,478 2,807,578 438,340 53,575
34 Distribution 64,360,317 34,036,086 9,708,775 13,368,580 1,887,993 349,175 2,415,756 2,593,951
35 Common 43,230,560 24,158,070 6,060,652 6,777,981 2,276,286 2,380,526 965,960 611,085
36 Total Unfform Cost 249,849,000 118,020,473 32,857,446 50,433,952 18,483,047 20,217,075 6,139,162 3,697,845
Expressed as $/kWh
37 Production $0.03854 $0.04172 $0.03892 $003785 $0.03424 $0.03500 $0.03548 $0.03096
38 Transmission S0.00870 $0.01061 $0.00886 $000822 $0.00622 $0.00669 $0.00671 $0.00378
39 Distribution $0.02137 $0.02977 $0.02714 $0 02033 $0.00534 $0.00083 $0.03696 $0.18281
40 Common $0.01436 $0.02113 $0.01694 $0.01031 $0.00643 $0.00568 $0.01478 $0.04307
41 Total Uniform Melded Rates $0.08297 $0.10323 $0.09186 $0.07671 $0.05223 $0.04820 $009392 $0.26061
42 Revenue to COit Ratio II Proposed Rites 1.00 0.92 1.12 1.06 1.07 1.07 0.96 0.98
43 Curnnt Revenue to Proposed Colt Ratio 0.97 0.89 1.10 1.03 1.05 1.05 0.94 0.95
44 Target Revenue Iner••• 6,250,000 12,499,000 (3,164,000) (1,699,000) (936,000) (1,030,000) 397,000 183,000
Stipulation and Settlement
Case No. AVU·E-16-03
Avista
Appendix B Page 4 of 4
AVISTA UTILITIES
IDAHO ELECTRIC, CASE NO. AVU-E-16-03
PROPOSED INCREASE BY SERVICE SCHEDULE
12 MONTHS ENDED DECEMBER 31, 2015
(OOOs of Dollar.!1)
Base Tariff Base Tariff Base Total Billed Total Billed Percent
Revenue Proposed Revenue Tariff Revenue Total Revenue Increase
Line Type of Schedule Under Present General Under Proposed Percent at Present General at Proposed on BIiled
No. Service Number Rates(1} Increase Rates (1) Increase Rates(2l Increase
(a) (b) (c) (d) (e) (f) (g) (h)
Residential 1 $105,522 $3,330 $108,852 3.2% $106,402 $3,330
2 General Service 11,12 $36.021 $667 $36,688 1.9% $36,604 $667
3 Large General Service 21,22 $52,133 $1,196 $53,329 2.3% $52,797 $1,196
4 Extra Large General Service 25 $19,419 $374 $19,793 1.9% $19,540 $374
5 Clearwater 25P $21,247 $387 $21,634 1.8% $21,343 $387
6 Pumping Service 31,32 $5,742 $177 $5,919 3.1°1,, $5,828 $177
7 Street & Area Lights 41-49 $3,515 llli $3,634 3.4°/,, $3.594 llli
8 Total $243,599 $6,250 $249,849 2.6% $246,107 $6,250
(1) Excludes all present rate adjustments (see below).
(2) Includes all present rate adjustments: Schedule 59-Residential & Farm Energy Rate Adjustment, Schedule 66 -Temporary Power
Cost Adjustment, Schedule 91 -Energy Efficiency Rider Adjustment, and Schedule 97 -Earnings Test Deferral.
Pro-rata Allocation of Avista Proposed
Original
Proposed Settlement
Type of Schedule General Percentage Spread
Service Number Increase ofTotal $6.25 Million
Residential 1 $8,223 53.28% $3,330
General Service 11, 12 $1,648 10.68% $667
Large General Service 21,22 $2,954 19.14% $1,196
Extra Large General Service 25 $924 5.98% $374
Clearwater 25P $955 6.19% $387
Pumping Service 31,32 $436 2.83% $177
Street & Area Lig his 41-49 $293 1.90% llli
$15,433 100.00% $6,250
Appendix C
Rates(2l
(i)
$109,732
$37,270
$53,993
$19,913
$21,730
$6,005
$3.713
$252,357
Revenue
U)
3.1%
1.8%
2.3%
1.9%
1.8%
3.0%
3.3%
2.5%
Stipulation and Settlement
Case No. AVU-E-16-03
Avista
Page 1 of 2
AVISTA UTILITIES
IDAHO ELECTRIC, CASE NO. AVU-E-16-03
PRESENT AND PROPOSED RATE COMPONENTS BY SCHEDULE
Effective January 1, 2017
General Proposed Proposed
Base Tariff Present Present Rate Billing Base Tariff
Sch. Rate Other Adj.(1) Billing Rate lnc/(Oecr) Rate Rate
(a) (b) (c) (d) (e) (f) (g)
Residential Service -Schedyle 1
Basic Charge $5.25 $5.25 $0.50 $5.75 $5.75
Energy Charge:
First 600 kWhs $0.08224 $0.00077 $0.08301 $0.00225 $0.08526 $0.08449
All over 600 kWhs $0.09183 $0.00077 $0.09260 $0.00251 $0.09511 $0.09434
General Services -Schedule 11
Basic Charge $10.00 $10.00 $2.00 $12.00 $12.00
Energy Charge:
First 3,650 kWhs $0.09686 $0.00163 $0.09849 $0.00018 $0.09867 $0.09704
All over 3,650 kWhs $0.07216 $0.00163 $0.07379 $0.00000 $0.07379 $0.07216
Demand Charge:
20 kW or less no charge no charge no charge no charge
Over20 kW $5.25/kW $5.25/kW $0.50/kW $5.75/kW $5.75/kW
Large Gen!!ral Service -Schedule 21
Energy Charge:
First 250,000 kWhs $0.06344 $0.00101 $0.06445 ($0.00022) $0.06423 $0.06322
All over 2 (2) Includes all presen $0.05414 $0.00101 $0.05515 ($0.00018) $0.05497 $0.05396
Demand Charge:
50 kW or less $350.00 $350.00 $50.00 $400.00 $400.00
Over50 kW $4.75/kW $4.75/kW $0.50/kW $5.25/kW $5.25/kW
Primary Voltage Discount $0.20/kW $0.20/kW $0.20/kW $0.20/kW
Extra Large G!!neral Service -Schedule 25
Energy Charge:
First 500,000 kWhs $0.05251 $0.00034 $0.05285 $0.00048 $0.05333 $0.05299
All over 500,000 kWhs $0.04446 $0.00034 $0.04480 $0.00041 $0.04521 $0.04487
Demand Charge:
3,000 kva or less $12,500 $12,500 $1,000 $13,500 $13,500
Over 3,000 kva $4.50/kva $4.50/kva $0.25/kva $4.75/kva $4.75/kva
Primary Volt. Discount $0.20/kW $0.20/kW $0.20/kW $0.20/kW
Annual Minimum Present: $687,360 $704,290
Cl!!arwat!!r -§chedule 25P
Energy Charge:
all kWhs $0.04272 $0.00023 $0.04295 $0.00036 $0.04331 $0.04308
Demand Charge:
3,000 kva or less $12,500 $12,500 $1,000 $13,500 $13,500
3,000 -55,000 kva $4.50/kva $4.50/kva $0.25/kva $4.75/kva $4.75/kva
Over 55,000 kva $2.00/kva $2.00/kva $0.25/kva $2.25/kva $2.25/kva
Primary Volt. Discount $0.20/kW $0.20/kW $0.20/kW $0.20/kW
Annual Minimum Present: $619,920 $635,880
Pumeing Service -Schedule 31
Basic Charge $8.00 $8.00 $2.00 $10.00 $10.00
Energy Charge:
First 165 kW/kWhs $0.09365 $0.00132 $0.09497 $0.00240 $0.09737 $0.09605
All additional kWhs $0.07983 $0.00132 $0.08115 $0.00204 $0.08319 $0.08187
(1) ~ 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 -Earnings
Test Deferral
Appendix C
Stipulation and Settlement
Case No. AVU-E-16-03
Avista
Page 2 of 2