20081110Staff to IPC 1-21.pdf

WELDON B. STUTZMAN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
472 WEST WASHINGTON STREET
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BARNO. 3283
NEIL PRICE
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
ISB NO. 6864
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5983
Attorney for the Commssion Staff
RE-CE'\/Cfj,,_ ' . ¡ t... ..$
2008 NOV 10 PH 3= 24
IDAHO PUBL G
UTILITIES COMM SSiON
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
IDAHO POWER COMPANY FOR AUTHORITY )
TO INCREASE ITS RATES AN CHAGES )
FOR ELECTRIC SERVICE TO ITS )
CUSTOMERS IN THE STATE OF IDAHO. )
)
)
)
CASE NO. IPC-E-08-10
STAFF RESPONSE TO THE
FIRST PRODUCTION
REQUEST OF IDAHO POWER
COMPAN
The Staff of the Idaho Public Utilities Commission, by and though its attorney of record,
Weldon B. Stutzan, Deputy Attorney General, provides the following documents and
information in response to Idaho Power Company's First Production Request to Commission
Staff.
STAFF RESPONSE TO THE FIRST
PRODUCTION REQUEST OF
IDAHO POWER COMPANY 1 NOVEMBER 10, 2008
REQUEST NO.1: Please provide copies of all electronic files, with formulas intact that
were used or relied on to develop the analyses and/or schedules supportng Staffs testimony.
RESPONSE NO.1: Copies of all electronic files, with formulas intact that were used or
relied on to develop the analyses and/or schedules supporting Staffs testimony, were provided to
the Company on Thursday, October 30, 2008. An additional copy (updated to include Staff
witness Leckie's workpapers and Excel files of Staff witness Elam) is provided in CD format
attched to this response.
REQUEST NO.2: Please provide copies of all workpapers and supporting documents
Staff relied on to support their testimony, exhbits, ançl any analysis contained therein.
RESPONSE NO.2: Information requested is included in Response NO.1.
REQUEST NO.3 TO STAFF WITNESS LECKIE: Referg to Exhibit 118, please
provide workpapers or other documentation identifyg the source of the data included in Exhbit
118.
STAFF WITNESS LECKIE RESPONSE NO.3: The information was taken from the
Company's response to Commission Staffs Audit Request No. 74. The information from FERC
Account 923, Outside Services for the Dewey LeBoeuf Law Firm was extracted, and then the data
for Exhibit 118 was taken from that extraction. The Excel file titled Dewey LeBoeuf in Leckie
workpapers provided on CD, Response No.1, shows all ofthe Dewey LeBoeuf payments
extracted from the Company's provided information.
REQUEST NO.4 TO STAFF WITNESS LECKIE: On page nine of Mr. Leckie's
testimony, he recommends a reduction of O. 5% to be applied to the combined 2.5% associated
with the Customer Satisfaction and Network Reliability incentive payments proposed by the
Company. Please provide copies of any workpapers, studies, or analysis that support the selection
of the 0.5% reduction.
STAFF RESPONSE TO THE FIRST
PRODUCTION REQUEST OF
IDAHO POWER COMPANY 2 NOVEMBER 10, 2008
STAFF WITNESS LECKIE RESPONSE NO.4: There are no workpapers, studies or
additional analyses beyond the direct testimony of Staff witness Leckie that were relied upon to
justify the reduction.
REQUEST NO.5 TO STAFF WITNESS LECKIE: In Staff witness J. Leckie's
testimony, page 14, lines 5 and 7, he states that the directors ofIdaho Power eared $337,676 in
interest on deferred fees. Please provide a detailed calculation, including any workpapers and/or
supporting documentation, showing how the $337,676 amount was computed.
STAFF WITNESS LECKIE RESPONSE NO.5: The data for the director's interest
eared was taken from the Company's response to the Commission Staffs Audit Request No:
100. The total of$337,676 stated in Leckie testimony page 14, line 6 in ths Idaho Power
Company case is not correct. The correct total should be $336,676, or $1,000 less.
REQUEST NO.6 TO STAFF WITNESS LECKIE: In Staff witness J. Leckie's
Exhbit 113, he lists Miscellaneous Serce Revenues for 2005 in the amount of $6,012,639.
Please provide a detailed calculation, including any workpapers and/or supporting documentation,
showig how the $6,012,639 amount was calculated.
STAFF WITNESS LECKIE RESPONSE NO.6: The amount of$6,012,639 for 2005
Miscellaneous Servce Revenues was taken from the Trial Balance for 2005 received from the
Company in its response to Commission Staffs Audit Request NO.1. The Excel file titled
Miscellaneous Serice Revenues in Leckie workpapers provided on CD, Response NO.1 shows
the results of extracting the amounts from the tral balances for the years 2000 through 2007.
REQUEST NO.7 TO STAFF WITNESS ANDERSON: On page 2, line 19, of Staffs
testimony, Mr. Anderson states: "Since 1999 I have served the Commission as a policy strategist
for electrcity. .. Is Mr. Anderson currently serving as a policy strategist for the Idaho Public
Utilities Commission?
STAFF RESPONSE TO THE FIRST
PRODUCTION REQUEST OF
IDAHO POWER COMPANY 3 NOVEMBER 10,2008
STAFF WITNESS ANERSON RESPONSE NO.7: Yes, on an as needed basis.
REQUEST NO.8 TO STAFF WITNESS ANDERSON: Is Mr. Anderson acting in his
capacity as a policy strategist in this proceeding (Case No. IPC-E-08-10)?
STAFF WITNESS ANDERSON RESPONSE NO.8: No.
REQUEST NO.9 TO STAFF WITNESS ANDERSON: On page 2, line 10-18,
Mr. Anderson refers to being a Staff representative on Idaho Power's Energy Effciency Advisory
Group ("EEAG"). Is Mr. Anderson curently a member of Idaho Powér EEAG? If so, for how
long has he been a member?
STAFF WITNESS ANDERSON RESPONSE NO.9: Yes, Mr. Anderson is curently
listed by Idaho Power as being an EEAG member. He believes he has been so listed since April
of2002.
REQUEST NO. 10 TO STAFF WITNESS ANDERSON: On page 8, lines 5-7,
Mr. Anderson states ". . . it is increasingly important that the utilities, other paries, and the
Commission have clear concepts of what constitutes DSM prudency." When has Mr. Anderson
or any other member of Commission Staff conducted a DSM prudency review on a utility?
Please provide the name of the company, date, order number, and a copy of any
order/reportdocumentation produced by Staff describing the DSM prudency review and its
outcome for each review conducted in the last 5 years.
STAFF WITNESS ANERSON RESPONSE NO. 10: Withn the past five years, the
following DSM prudency reviews have been conducted or requested: A prudency review was
requested by Avista Utilities in Case No. A VU-E-04-l/A VU-G-04-1 and Lyn Anderson
conducted ths review and filed testimony stating his opinion that Avista Utilities' DSM efforts
were conscientious and cost-effective. (See attached Order No. 29602, Errata to Order No.
29602, Final Order on Reconsideration No. 29638 and Direct Testimony ofLyn Anderson.)
STAFF RESPONSE TO THE FIRST
PRODUCTION REQUEST OF
IDAHO POWER COMPANY 4 NOVEMBER 10, 2008
A prudency review was requested by Avista Utilities in Case. No. A VU-E-08-l/A VU-G-08-1, in
which the paries and Staff signed a settlement agreement that included a stipulation that A vista's
DSM efforts were prudent. (See attached Motion for Approval of Stipulation, Direct Testimony
of Randy Lobb in Support of Stipulation and Final Order No. 30647). Rocky Mountain Power, in
Case No. P AC-E-08-7, has requested a DSM prudency finding, but Staff has not filed any DSM
documents in ths open case.
REQUEST NO. 11 TO STAFF WITNESS ANERSON: Thoughout Mr. Anderson's
testimony he states that he has not received from the Company adequate information to deterine
prudency ofthe Company's DSM programs. Please specifically identify which Idaho Power
DSM programs for which Mr. Anderson clais he does not have enough information to form a
recommendation regarding prudency.
STAFF WITNESS ANERSON RESPONSE NO. 11: To facilitate Staff evaluation of
Idaho Power's DSM prudency from 2003 though 2007, additional information about general
organization, adinistration and decision-makng is needed. Staff also needs additional
information for all specific DSM programs except Irrgation Peak Rewards, Weatherization
Assistance for Qualified Customers, and the Nortwest Energy Effciency Allance. Also, Staff
may not need more information for Custom Effciency if evaluations for all 114 completed
projects are currently available.
REQUEST NO. 12 TO STAFF WITNESS ANDERSON: On page 9, line 17-18,
Mr. Anderson states: "Although the Company provided some, but not all, minutes ofEEAG
meetings. . ." Please specifically identify which EEAG minutes were not provided.
STAFF WITNESS ANDERSON RESPONSE NO. 12: Minutes of the October 2,2008,
EEAG meeting were not provided. (Originally, due to the combination of unconventional sorting
of meeting minutes on the CD provided by Idaho Power and the reduction of meeting frequency
from four per year to thee per year, Staff eroneously thought additional meeting minutes were
not provided.)
STAFF RESPONSE TO THE FIRST
PRODUCTION REQUEST OF
IDAHO POWER COMPANY 5 NOVEMBER 10, 2008
REQUEST NO. 13 TO STAFF WITNESS VAUGHN: Please provide the detailed
calculation and any workpapers and/or supporting documentation for the A&G accounting entres
included in Staff witness C. Vaugh's Exhbit No. 122, colums 3 though 7, line 5.
STAFF WITNESS VAUGHN RESPONSE NO. 13: All data for Staff calculations were
provided by the Company in response to Audit Request No. 53. Staff calculations are shown in
Excel workbook CAGR Escalation Analysis Workpaper.xlsm. Copies of all electronic files, with
formulas intact, used or relied on to develop the analyses and/or schedules supporting Staff
testimony, are provided on the attached CD, Response NO.1.
REQUEST NO. 14 TO STAFF WINESS VAUGHN: Please provide the detailed
calculation and any workpapers and/or supporting documentation for the P-Card adjustments
included in Staff witness C. Vaughn's Exhbit No. 125, pages 1 and 2.
STAFF WITNESS VAUGHN RESPONSE NO. 14: Detailed P-Card transactions for
2007 were provided to Staff in response to Audit Request Nos. 1-4, dated Februar 8, 2008. Data
provided was analyzed by Staff; analysis workpapers are included as Excel workbooks
PCard2007 _ AllTx _ ExpClassified.x1sm and PCard2007 _ AllTx _ExpClassified (2).xlsm.
Calculation of the P-Card adjustments are shown in Excel workbook IPC Pcard Exclusions
Workpaper.xlsm. Copies of all electronic files, with formulas intact, used or relied on to develop
the analyses and/or schedules supporting Staff testimony, are provided on the attached CD,
Response No. 1.
REQUEST NO. 15 TO STAFF WITNESS VAUGHN: In Staff witness C. Vaugh's
testimony on page 3, lines 18 though 20 , she states the Company requested an increase to O&M
of$15,985,407. Please provide a detailed calculation, including any workpapers and/or
supporting documentation, showing how the $15,985,407 amount was calculated.
STAFF RESPONSE TO THE FIRST
PRODUCTION REQUEST OF
IDAHO POWER COMPANY 6 NOVEMBER 10, 2008
STAFF WITNESS VAUGHN RESPONSE NO. 15: The Company requested O&M
was calculated by multiplyig the O&M 2007 base year figues by the Company CAGRs; these
data were provided by the Company in Exhbit Nos. 36-45 and the associated electronic
workpapers. Staff Calculations are shown in Excel Folder JSS COS Modell 0 24 2008, Excel- - -
workbook USE THIS ONE_JSS Working Copy.xlsm, tab JSS DATA IPUC Adjusted, Colum T,
Row 493. Copies of all electronic files, with formulas intact, used or relied on to develop the
analyses and/or schedules supporting Staff testimony, are provided on the attached CD, Response
NO.1.
REQUEST NO. 16 TO STAFF WITNESS STERLING: Please provide the Excel
spreadsheet that created the basis differential of$0.13 from Hen Hub to Sumas.
STAFF WITNESS STERLING RESPONSE NO. 16: To clarfy, Staffused a basis
differential of $0.13 between Hen Hub and Danski, not between Hen Hub and Sumas. The
basis differential of$O.13 between Hen Hub and Danskin is derived on the "HH-Danskin basis"
tab of the confidential spreadsheet tited "IPUC 1 Q6 ConfidentiaL." Note that the Henr Hub-
Sumas basis differential was derived on the "Sumas Natual Gas" tab of the confidential
spreadsheet titled "IPCo 2009 Electrc & gas forwards."
TheHenr Hub-Danskin basis differential is equal to the Henr Hub-Sumas basis
differential plus gas transportation charges from Sumas to Danskin. (See attached Confidential
CD).
REQUEST NO. 17 TO STAFF WITNESS STERLING: Please provide the Excel
spreadsheet for the "monthly shape factors" that were used in your analysis for gas prices.
STAFF WITNESS STERLING RESPONSE NO. 17: The monthly shape factors were
derived on the "Sumas Natual Gas" tab of the confidential spreadsheet titled "IPCo 2009 Electrc
& gas forwards." (See cells B443 - M443). (See attached Confidential CD).
STAFF RESPONSE TO THE FIRST
PRODUCTION REQUEST OF
IDAHO POWER COMPANY 7 NOVEMBER 10, 2008
REQUEST NO. 18 TO STAFF WITNESS LANSPERY: On page 10 of Staff witness
Lanspery's testimony, he states that an increase in the customer charge for residential customers
is not justified because Staff witness Hessing's Cost of Servce results did not warant a rate
increase to the residential customers. Assuming hypothetically that Staffwitness Hessing's Cost
of Service results waranted a rate increase for the residential customers, would an increase to the
service charge be justified? If so, how much?
STAFF WITNESS LANSPERY RESPONSE NO. 18: The traditional stance taken by
the Commission Staff is that the customer charge is designed to collect the portion of costs
associated with meter reading and biling. Based on the Company's fiing, these costs are
between $4.11 (not including uncollectables) and $4.51 (including uncollectables) (Tatu Exhibit
No. 67, lines 41-44), rather than the $14.89 citied on page 6, line 14 of Company witness Waite's
testimony. Based on the Staff Cost of Service, the customer charge ranges from $3.74 (not
including uncollectables) to $4.13 (including uncollectables). Even under the Company's filing,
Staff would not be able to justify a $1.00 increase in the customer charge.
REQUEST NO. 19 TO STAFF WITNESS LANSPERY: On page nine of Staff witness
Lansper's testimony, he states that ". . . heating and cooling should also be considered basic end
uses, as well as a point at which residential customers begin to differ from one another." Please
explain why heating and cooling should be considered basic household electrc end use, and why
- if it is a point at which usage begins to differ greatly - does it follow that it should then be
considered a basic end use?
STAFF WITNESS LANSPERY RESPONSE NO. 19: Staff notes that there is a
difference between "base" usage and "basic" usage. Base usage may be considered energy
consumption levels that do not var due to weather. Basic usage, as Staff proposes, refers to end
use that seres basic needs. Along with lighting, refrgeration, and water heating, Staff believes
that heating one's home is a basic use for energy (as is, to a lesser extent in Idaho, space cooling).
In sending cost based price signals, it seems proper to look at the months where the Company is
STAFF RESPONSE TO THE FIRST
PRODUCTION REQUEST OF
IDAHO POWER COMPANY 8 NOVEMBER 10, 2008
capacity constrained, i.e. the summer months and deep winter months, where heating and cooling
occurs.
Whle one of the goals of tiered rate design is to encourage customers to use energy
effciently throughout the year, it is imperative to send price signals durig the periods where it is
most waranted. Without a current end use study, there is no reason to believe that all customers
with low bils are using energy efficiently, nor that customers with high bils consume
inefficiently.
REQUEST NO. 20 TO STAFF WITNESS LANSPERY: On pages 11 though 13
of Staff witness Lansper's testimony, he uses the "60 percent method" of the August and January
usages to determne that "the first block level should be set closer to 800 kWh. Furher he
"deduced" that the proper cut-off point for a first block should be between 600 kWh and 1000
kWh. Why was the high end of 1000 kWh chosen for the first block?
STAFF WITNESS LANSPERY RESPONSE NO. 20: Please refer to Staff witness
Lanspery's testimony, page 12, line 5 through page 13, line 11.
REQUEST NO. 21 TO STAFF WITNESS ELAM: On page 7 of Mr. Elam's testimony
he states: "I utilized the Schedule 19 historical time-of-use data implemented in Order No. 29547
to determine how the demand for energy shifted to different times given the price strctue
movement from a traditional rate design to a TOU rate design. Please provide the workpapers
used in ths analysis.
STAFF WITNESS ELAM RESPONSE NO. 21: Information requested is included in
Response No. 1.
STAFF RESPONSE TO THE FIRST
PRODUCTION REQUEST OF
IDAHO POWER COMPANY 9 NOVEMBER 10, 2008
DATED at Boise, Idaho, this idtay of November 2008.
tJ. ~WeldonB. Stutzm~
Deputy Attorney General
Technical Staff: Joe Leckie
Lyn Anderon
Cecily Vaugh
Rick Sterling
Bryan Lanspery
Matt Elam
i:umsc:prodreqipce08.10wsnp prd re stff responsel.doc
STAFF RESPONSE TO THE FIRST
PRODUCTION REQUEST OF
IDAHO POWER COMPANY
2008
10 NOVEMBER 10,
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 10TH DAY OF NOVEMBER 2008,
SERVED THE FOREGOING STAFF RESPONSE TO IDAHO POWER COMPANY'S
FIRST PRODUCTION REQUEST TO THE COMMISSION STAFF, IN CASE
NO. IPC-E-08-10, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO THE
FOLLOWING:
BARTON L KLINE
LISA D NORDSTROM
DONOV AN E WALKER
IDAHO POWER COMPANY
POBOX 70
BOISE ID 83707-0070
E-MAIL: bklineCfidahopower.com
InordstromCfidahopower .com
dwalker(fidahopower.com
PETER J RICHARDSON
RICHARDSON & O'LEARY
PO BOX 7218
BOISE ID 83702
E-MAIL: peter(frichardsonandolear.com
RANDALL C BUDGE
ERIC L OLSEN
RACINE OLSON NYE ET AL
PO BOX 1391
POCATELLO ID 83204-1391
E-MAIL: rcbCfracinelaw.net
eloCfracinelaw.net
MICHAEL L KURTZ ESQ
KURT J BOEHM ESQ
BOEHM KURTZ & LOWRY
36 E SEVENTH ST STE 1510
CINCINATI OH 45202
E-MAIL: mkurz(fBKLlawfrm.com
kboehm(fBKLlawfirm.com
BRAD MPURDY
ATTORNEY AT LAW
2019N 17THST
BOISE ID 83702
E-MAIL: bmpurdy(fhotmaiLcom
JOHN R GALE
VP - REGULATORY AFFAIRS
IDAHO POWER COMPANY
PO BOX 70
BOISE ID 83707-0070
E-MAIL: rgale(fidahopower.com
DR DON READING
6070 HILL ROAD
BOISE ID 83703
E-MAIL: dreadingCfmindspring.com
ANTHONY Y ANKEL
29814 LAK ROAD
BAY VILLAGE OH 44140
E-MAIL: yanel(fattbi.com
KEVIN HIGGINS
ENERGY STRATEGIES LLC
PARKS IDE TOWERS
215 S STATE ST STE 200
SALT LAKE CITY UT 84111
E-MAIL: khigginsCfenergystrat.com
LOTH COOKE
ARTHUR PERRY BRUDER
UNITED STATE DEPT OF ENERGY
1000 INDEPENDENCE AVE SW
WASHINGTON DC 20585
E-MAIL: 10t.cooke(fhq.doe.gov
CERTIFICATE OF SERVICE
DWIGHT ETHERIDGE
EXETER ASSOCIATES INC
5565 STERRTT PLACE, SUITE 310
COLUMBIA MD 21044
E-MAIL: detheridge(fexeterassociates.com
DENNIS E PESEAU, Ph.D.
UTILITY RESOURCES INC
1500 LIBERTY STREET SE, SUITE 250
SALEM OR 97302
E-MAIL: dpeseau(fexcite.com
arhur. bruder(fhg .doe. gov
CONLEY E WARD
MICHAEL C CREAMER
GIVENS PURSLEY LLP
601 WBANNOCKST
PO BOX 2720
BOISE ID 83701-2720
E-MAIL: cewCfgivenspursley.com
KEN MILLER
CLEAN ENERGY PROGRAM DIRECTOR
SNAKE RIVER ALLIANCE
PO BOX 1731
BOISE ID 83701
E-MAIL: kmilerCfsnakeriverallance.org
~l(~
SECRETARY
CERTIFICATE OF SERVICE
-
STAFF'S RESPONSE TO IDAHO POWER REQUEST NO. I
SEE ATTACHED CD
STAFF WITNSS ANDERSON'S
RESPONSE TO IDAHO POWER REQUEST NO.1 0
Office of the Secret
Service Date
October 19,2004
BEFORE THE IDAHO PUBLIC UTITIES COMMSSION
IN THE MATTER OF THE APPLICATION OF )
AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES AND )
CHGES FOR ELECTRIC AN NATURAL )
GAS SERVICE TO ELECTRIC AN NATUR )
GAS CUSTOMERS IN THE STATE OF IDAHO. )
)
CASE NO. AVU-E-04-l
AVU-G-04-1
ERRTA TO
ORDER NO. 29602
On October 8, 2004, Order No. 29602 was issued by this Commssion. The
following chages should be made to that Order:
Page 5, Paragraph 2, Lines 5-7
READS:
"The Commssion finds use of a 12-month test year ending December 31,
2002 for net operating income and an average of 2004 monthy averages for
rate base to be reasonable and appropriate."
SHOULD READ:
"The Commssion finds use of a 12-month test year endig December 31,
2002 for net operating income and a 2002 average of monthly averages for
rate base to be reasonable and appropriate."
Page 25, Paragraph 1, Lines 4-6
READS:
"Ths adjustment increases net operatig income by $366,000 and reduces
Avista's revenue requirement by $73,000. Tr. at 1168-1170; Tr. at 1090."
SHOULD READ:
"This adjustment increases net operating income by $366,000 and reduces
Avista's revenue requiement by $573,000. Tr. at 1168-1170; Tr. at 1090."
ERRTA TO
ORDER NO. 29602 1
Page 25, Paragraph 5, Lines 1-2
READS:
"A vista proposed a pro forma electric rate base of $440,270,000 for the Idaho
jursdiction. Exh. 14, p. 2."
SHOULD READ:
"A vista proposed a pro forma electric rate base of $440,207,000 for the Idaho
jursdiction. Exh. 14, p. 2."
DATED at Boise, Idaho this I e¡tk day of October 2004.
~!).~
J D. JewellC ~ion sect:
bls/O:A VUE0401_A VUG0401_sw7 _FinatErrta
ERRTA TO
ORDER NO. 29602 2
Offce of the Secrear
Service Date
October 8, 2004
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
AVISTA CORPORATION FOR THE ) CASE NO. A VU-E-04-1
AUTHORITY TO INCREASE ITS RATES AND ) A VU-G-04-1
CHARGES FOR ELECTRIC AND NATURA )
GAS SERVICE TO ELECTRIC AND NATUR )
GAS CUSTOMERS IN THE STATE OF IDAHO.) ORDER, NO. 29602
)
ISSUED OCTOBER 8, 2004
BOISE, IDAHO
TABLE OF CONTENTS
Summary ......................................................................................................................................1
Application...... ........ ..................... ...... ..................... ................... ........ ...........................................2
Appearances........................ ...... ......... ............. .......... .... ................. ............... ....................... ..... ... 3
Public Workshops, Hearngs and Comments... ................................... ................................... ...... 3
Avista Utilities - Electric and Gas ............................................................................................4
Test Year .........................................................................................................................4
Capital Strcture and Rate of Retu ...............................................................................5
1. Capital Strcture.... ...... ....................... ........... ......... ................... ....... ................. 5
2. Cost of Debt ...................................................................................................... 6
3. Cost of Trust Preferred Securties .....................................................................6
4. Cost of Preferred Stock ...................................................................................... 6
5. Cost of Common Equity Capita....................................................................... 7
Avista's Electric. Case ..............................................................................................................1.0
Adjustments to Electrc Test Year. Revenues, Expenses and Rate Base.................................... 10
A. Agreed Upon Adjustients ................................ ..................................... ................. 11
1. Accounts Receivable Progr'am Fees................................................................ 11
2. Debt Interest Restatement Adjustient.......................................................... 12
3. Low Income Weatherization Assistance (LIW A) Funding ............................ 12
4. Demand Side Management (DSM) Funding Levels...................... ................. 14
5. Coyote Springs 2 (CS2) Deferred Retur ....................................................... 15
B. Disputed Adjustients..............................................................................................15
1. Transmission Projects ..... .............................................. .................................. 15
2. Boulder Park Small Generation Project .......................................................... 17
3. Prudency of Coyote Sprigs 2 (CS2)..............................................................19
4. Vegetation Management (Tree Trimming) ..................................................... 22
5. Pension Expense.............................................................................................. 23
6. Legal Expenses....................................................................................... .........25
Rate Base.......................................... ............................................................................. 25
Revenue Requirement..................... .............................................................................. 26
Sumar of Adjustients to Electrc Test Year Revenues, Expenses and Rate Base............... 26
Calculation of Revenue Deficiency ...........................................................................................26
Jursdictional Separations, Cost of Service and Rate Design 27 ............................................... 27
1. Jursdictional Separations..... ..................................................................................... 27
2. Class Cost of Service Methodology ......................................................................... 27
A. Weather Normalization ............... ................ ........... .................. ....... ............... 31
B. Power Supply Adjustments ................. .............. ..................... ........................ 31
11
,
3. Class Revenue Allocations..............................................................,..,..................... 32
4. Rate Design and Tarff Issues......................................................................... .......... 32
A.' Residential Service (Schedule 1).................................................................... 33
B. General Service (Schedules 11 and 12).......................................................... 34
C. Large General Service (Schedules 21 and 22) ...............................................35
D. Extra Large General Servce (Schedule 25) ................................................... 35
E. Potlatch's Lewiston Plant ............................................................................... 37
F. Pumping Service (Schedules 31 and 32) ......................:.................................39
G. Street and Area Lighting (Schedules 41 and 49)............................................39
Electrc Rates ................. .................................................... ...................... .................................. 39
Power Cost Adjustment (PCA) Issues ................................... ......................... ...........................40
1. Deal "A" and Deal "B" (PCA Issues) ......................................................................40
2. Updated PCA Components.............................................:......................................... 46
3. PCA Rate Recovery..................................................................................................47
4. PCA Rate Design......................................................................................................47
Other Issues................................................................................................................................ 48
1. After Hours Connection Fees ................................................................................... 48
2. Winter Payient Plan ............................................... ..... .......... ................ ..................49
3. Telephone Call Center ..............................................................................................49
4. Prudency ofDSM Expenditues.........................................~..................................... 50
5. Advanced Meter Reading (AM) ............................................................................ 51
6. Intervenor Funding ..................... .................... ......... .................. ..................... .......... 52
Avista's Natural Gas Case....................................................................................................... 52
Adjustments to Gas Test Year Revenues, Expenses and Rate Base .......................................... 53
A. Agreed Upon Adjustments.............. .............................................................. .......... 54
1. Gas Inventory........................................... ....................................................... 54
2. Accounts Receivable Progran Fees................................................................ 55
3. Restate Debt Interest....................................................................................... 55
B. Disputed Issues ........................................................................................................55
1. Pension Expense..............................................................................................55
. 2. Legal Expense .................................................................................................55
Summar of Adjustments to Gas Test Year, Revenues, Expenses and Rate Base.................... 55
Rate Base ...........................................................................................~.......................................56.
Revenue Requirement................................................................................................................56
Calculation of Revenue.Deficiency ...........................................................................................56
Gas Jursdictional Separations, Weather Normalization and Cost of Service ........................... 57
1. Gas Jurisdictional Separations..................................................................................57
2. Weather Normalization .....................................................................................;......57
3. Gas Cost of Service ........................... ........................... ..................... .................. .....57
4. Cost of Gas in Base Rates ........................................................................................ 58
iii
"
Natural Gas Rate Design and TarffIssues................................................................................. 58
1. Residential (Schedule 101)....................................................................................... 59
2. Large General Service (Schedule 111) ............................................ ......................... 59
3. Extra Large General Servce (Schedule 121) ........................................................... 60
4. Interrptible Service (Schedule 131)........................................................................ 61
5. Tranportation Service (Schedule 146) .................................................................... 61
6. Special Contracts...................................................................................................... 61
Other Issues............. .... ....... .......... ........................ .... ...................................... ............. ............... 62
1. Prudency of DSM Expenditures............................................................................... 62
2. Tarff Sumar Sheet ..........................................................~................................... 62
Conclusions of Law ............................................................... .......... ...... .................................... 62
ORDER......................................................................................................................................63
Appendices
iv
Offce of the Secretary
Service Date
October 8, 2004
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
A VISTA CORPORA nON FOR THE )
AUTHORITY TO INCREASE ITS RATES AND )
CHARGES FOR ELECTRIC AND NATURA )
GAS SERVICE TO ELECTRIC AND NATURAL )
GAS CUSTOMERS IN THE STATE OF IDAHO. )
)
CASE NO. AVU-E-04-1
AVU-G-04-1
ORDER NO. 29602
SUMMARY
On Febru 6, 2004, Avista Corporation dba Avista Utilities (Avista; Company)
filed an Application with the Idaho Public Utilities Commission (Commission) for authority to
increase its rates and charges for electric and natural gas servce in the State of Idaho. The
Company serves approximately 109,315 electrc customers and 61,799 natural gas customers in
northern Idaho. A change in the Company's current Power Cost Adjustment (PCA) surcharge
was also requested. On September 9, 2004, the Commission issued Amended Interlocutory
Order No. 29588 that contained our initial findings in these cases and authorized changes in the
Company's electrc and natual gas rates. In this final Order we reaffrm the rate changes set out
in Order No. 29588 and provide our detaled findings.
By this final Order the Commission affrms the change in electrc rates authorized in
Amended Interlocutory Order No. 29588 and authorizes the Company to increase its Idao
electrc base revenue requirement by $24,716,195' or approximately 16.90%. This increase is
offset by disallowances in the Power Cost Adjustment (PCA) coupled with an adjustment in the
PCA recovery period and a reduction in the Energy Effciency Rider. These offsettg
adjustments reduce the authorized net revenue increase to $3,182,000 or 1.9% of curent anual
revenue. The electrc rates we approve as just and reasonable are set out in attached Appendix
A. Idaho Code § 61-502. The net amount of actu increase vares by class of customer and
usage. .The resultant increase for an electrc residential customer using an average of 941 kWh
per month is $4.01, or a 7.1% increase in the customer's electrc bilL.
The Commission also affirms the change in natual gas rates authorized in Amended
Interlocutory Order No. 29588 and authorizes the Company to increase its Idao natual gas
revenues by $3,311,000 or approximately 6.38%. The natual gas rates we approve as just and
reasonable are those set fort in attached Appendix B. Idaho Code § 61-502. The base rates we
ORDER NO. 29602 1
approve are the embedded fixed base rates used in the updated weighted average cost of gas
(WACOG) calculation of $0.44989 per thenn and incorporated in the Company's PGA
adjustment authorized in Order No. 29590, Case No. A VU-G-04-2. The net amount of actual
increase vares by class of customer and usage. The resultant increase for a natural gas
residential customer using an average of 73 thenns of gas per month is $12.84 per month, or
21.39%.
In ths Order the Commission approves a pro fonna electric rate base of
$424,114,000; a 'pro fonnanatual gas rate base of $59,653,000; a retur on equity of 10.4%;
and an overall rate of retur of9.25%.
APPLICATION
A vista is a public utility engaged in the generation, transmission and distribution of. .' .
electric power and the distrbution of natural gas. The Company in its Application requested a
Commission Order approving revised electric and natural gas rates and charges effective March
10, 2004. The proposed effective date was suspended pending hearng on the Application and
fuer Order of the Commission. Order No. 29432; Idaho Code § 61-622.
Avista's last electric general rate èase in Idaho was completed in 1999. (Case No.
WWP-E-98-11, Order No. 28097.) Since that time, Avista's overall electric rates in Idaho have
been modified under the Company's Power Cost Adjustment (PCA) mechanism to reflect
changes in power costs related to streamflow and wholesale market conditions. A vista contends
that an electrc rate increase is necessitated by new generating projects, reduced wholesale
revenue and increased fuel costs. The Company's original Application request of$35.2 millon
or a 24.1 % increase in electrc revenue was revised at hearng to $31.1 milion or 21.2%.
Avista's last natual gas general rate case in Idaho was completed in 1989. (Case
No. WWP-G-88-5, Order No. 22749.) Since that time, Avista's overall natural gas rates in
Idaho have been modified under the Company's Purchased Gas Cost Adjustment (PGA)
mechansm to reflect changes in varable gas-related costs. Avista contends that a natural gas
rate increase is necessitated by decreased thenn usage and increased general business expenses.
The Company's original request of $4.754 milion or a 9.16% increase in natua1 gas revenue
costs was revised at hearng to $4.06 milion or 7.8%.
The Company's requested revenue increase in its Application is predicated on a
proposed 9.82% rate of retu, including an 11.5% retu on equity. Tr. at 98; 104. Avista
ORDER NO. 29602 2
alleges that the rates in its present tarffs are no longer reasonable or adequate and do not allow
it to ear a fair and reasonable retur on investment.
Appearances
A technical hearng in Case Nos. A VU-E-04-1 and A VU-G-04-1 was held in Boise,
Idaho the week of July 19, 2004. The following paries appeared by and through their respective
counsel of record:
Brad M. Purdy, Esq.
Scott D. Woodbur, Esq.
Lisa Nordstrom, Esq.
A continued technical hearng was held in Boise on August 16, 2004.
Public Workshops, Hearings and Comments
Prior to the technical hearngs in this case, the Commission Staff. in May 2004
conducted public workshops in Coeur d Alene and Moscow to discuss the Company's
Application and to answer customer questions. Public testimony hearngs conducted by the
Commission were held in Kellogg and Sandpoint on July 26,2004 and in Lewiston on July 27,
2004. Six customers attended the workshops and about 100 people attended the thee public
hearngs. Of those who attended, 25 people testified at the hearngs. Among those testifying
were Idaho State Senator Shawn Keough and Representative Bonnie Douglas. The Commission
also solicited public wrtten comments regarding the Company's Application. By August 6,
2004, the Commission had received written comments from 81 residential customers and 15
non-residential customers. The Commission also received wrtten comments from area taxing
authorities - four school distrcts, Shoshone and Clearater County Commissioners, and a
sewer distrct, all concerned about the impact of a rate increase. Additionally, more than 1,500
signatues were attached to four separate petitions from the Company's customers. All those
who commented and signed petitions opposed any rate increase.
The Commission greatly appreciates the efforts customers made to express their
opinions regarding their electrc and natural gas rates. Approximately one-half of the comments
were from low and fixed income customers concemed about being able to afford any increases
A vista Corporation
Potlatch Corporation
Coeur Silver Valley, Inc.
Community Action Parership
Association of Idaho (CAP AI)
Commission Staff
David S. Meyer, Esq.
Conley E. Ward, Esq.
Charles L. A. Cox, Esq.
ORDER NO. 29602 3
~
in their utility bils. More than one-half of the residential customer comments also asked that
the Commission consider the poor economy in nortern Idaho before granting any rate
increases.
We have reviewed and considered the record in Case Nos. A VU-E-04-1 and A VU-
G-04-1 including: the Prehearing Memorandum filed by Potlatch; the transcript of technical
proceedings; th~ transcript of public testimony and filed public comments; and the Petition for
Intervenor Funding filed by CAP AI. Although this Order grants an increase, our decisions on
Low Income Weatherization Assistance, DSM programs and the Winter Payment Program can
help customers manage their bils. With this background in mind we now discuss the test year,
capital strcture and rate of return issues presented in this case and common to both the
Company's electrc and natu gas operations.
Avista Utilties - Electric and Gas
As set out in greater detail below, the Commission approves a normalized l2-month
test year ending December 31, 2002 for net operating income and an average of monthly
averages 2002 test year for rate base for Avista Utilties. We approve an embedded capital
strctue for Avista at December 31, 2003 consisting of 50.08% debt, 5.57% trst preferred
securties, 1.76% preferred stock and 42.59% common equity. We accept an embedded cost of
debt of 8.68%, embedded cost for trst preferred securities of 6.15% and embedded preferred
stock cost of 7.35%. We approve a return on common equity of 10.4% and an overall weighted
cost of capital and rate ofretum of9.25%.
Test Year
A vista proposed a 2002 test year presented on a pro forma basis for net operating
income and an average of monthly average 2002 test year for rate base items. Tr. at 147. Staff
accepted the 2Q02 test year proposed by the Company. Tr. at 111 7. Potlatch witness Peseau
argues that use of a 2002 test year, adjusted for allegedly known and measurable changes,
produces, a mismatch of revenues from 2002 and year-end expenses and rate base from 2004.
This mismatch, Potlatch contends, should be corrected by: (1) reversing the pro forma entres
and properly matching test year averages for both sides of the ledger, (2) updating revenues to
the 2004 level in the same maner as rate base and expenses (preferred method), or (3)
employing the rate base adjustments adopted in the Idaho Power rate case. Tr. at 922-926.
ORDER NO. 29602 4
~
Addressing Potlatch's contention that there is a mismatch between revenues and
expenses, Avista witness Falkner contends that each of the Company's test year adjustments fall
into an accepted category of adjustment. Revenues, the Company maintains, canot be
anualized to 2004 year-end levels to correct a Potlatch-perceived mismatch because: (1) the
2004 year-end levels of revenues would not be "known and measurable" for another six months,
(2) expenses would also need to be adjusted to year-end, and (3) additional revenue from load. -
growt caused by new customers would be offset by additional costs. Tr. at 214-217.
The Commission finds that the timing of the Company's rate case fiing was dictated
by Company commitment and Commission direction in the Company's 2003 PCA filing, Case
No. AVU-E-03-6, Order No. 29377. Avista had a deadline of March 31, 2004 to file its electrc
general rate case. The timing of the rate case influenced the Company's selection of the test
year. The Commission finds use of a 12-month test year endtng December 31, 2002 for net
operating income and an average of 2004 monthly averages for rate base to be reasonable and
appropriate. The matching of test year adjustments wil be discussed later with other revenue,
expense and rate base adjustments.
CAPITAL STRUCTURE AND RATE OF RETURN
1. Capital Structure
In its initial filing, A vista witness Malquist recommended a pro forma capital
strcture consisting of 48.19% long-term debt, 5.79% trst preferred securities, 1:72% preferred
stock, and 44.30% common equity, that included adjustments to reflect known and projected
changes in long-term debt issuances/redemptions and associated costs though September 30,
2004. Tr. at 97-100; 105; 421-426.
Potlatch witness Thornton recommended no changes to Avista's pro forma capital
strcture. Tr. at 975. Staff witness Carlock, however, contended that the pro forma changes
proposed by Avista were not adequately known and measurable. Staff recommended instead
using the embedded capital strcture at December 31, 2003 consisting of 50.08% debt, 5.57%
trst preferred securities, 1:76% preferred stock and 42.59% common equity. Tr. at 1474.
A vista in rebuttal agreed with Staff to use the capital strcture at the embedded December 31,
2003 actual levels. Tr. at 193.
ORDER NO. 29602 5
The Commission finds Avista's actual embedded capital structue at December 31,
2003 as proposed by Staff and agreed to by the Company, to be appropriate for calculating the
Company's overall rate of retu.
2. Cost of Debt
Avista testified that its embedded cost of long-term debt on December 31, 2003 was
8.68%. Exh. 2, p. 2. The Company proposed making certain pro forma adjustments to update
the debt cost through September 30,2004 to 8.70%. Tr. at 101; Exh. 2, p. 2. Staff accepted and
recommended use of the Company's average actual cost of long-term debt outstanding on
December 31,2003, i.e., 8.68%. Tr. at 1475.
The Commission fids it reasonable based on the evidence of the record to reject the
pro forma adjustments to be consistent with the capital strcture adopted and to use the
Company's year-end 2003 embedded cost of debt calculation, 8.68%.
3. Cost of Trust Preferred Securities
Avista testified that its embedded cost of trst preferred securities on December 31,
2003 was 6.15%. Exh. 2, p. 2. The Company proposed making certai pro forma adjustments
to update the debt cost though September 30, 2004 to 7.01%. Tr. at 102-103; Exh. 2, p. 2.
Staff accepted and recommended use of the Company's embedded cost of trt preferred
securities on December 31, 2003, 6.15%. Tr. at 1475.
The Commission finds it reasonable based on the evidence of the record to reject the
pro forma adjustments to be consistent with the capital structure adopted and to adopt the
Company's 6.15% year-end 2003 embedded cost fortrst preferred securties as the appropriate
cost rate.
4. Cost of Preferred Stock
A vista witness Malquist testified that the Company's embedded cost of prefered
stock on December 31,2003 was 7.35%. Exh. 2, p. 2. The Company proposed makng cerain
pro forma adjustments to update the preferred stock cost though September 30, 2004 to 7.34%.
Tr. at 102-103; Exh. 2, p. 2. Staff witness Carlock accepted and recommended use of the
Company's embedded cost of preferred stock on December 31,2003,7.35%: Tr. at 1475.
The Commission finds it reasonable based on the evidence of the record to reject the
pro forma adjustments to be consistent with the capital strcture adopted and to adopt the
Company's 7.35% year-end 2003 embedded cost for preferred stock as the appropriate cost rate.
ORDER NO. 29602 6
5. Cost of Common Equity Capital
A vista, Staff and Potlatch disagree as to the appropriate cost of common equity
capitaL. The cost of common equity capital, stated as a rate of return on common equity, is a
function of several varables. It is priarly an attempt to quantify a rate of retu required by
investors for that paricular investment that is equal to retums eared at the same time by entities
of similar risk and uncertainty. The return should also be reasonably suffcient to allow the
utilty to support its credit and attract new capital needed for utilty operations. Avista's electrc
operation was previously authorized to ear an 8.979% overall retur and a 10.75% retur on
common equity. Case No. WW-E-98-11, Order No. 28097. For its gas operation the
Company was authorized to ear an 11.02% overall return and a 12.75% retur on equity. Case
No. WWP-G-88-5, Order No. 22749.
A vista in this case requests a rate of return of 1 1. 5% on the common equity portion
of its capital strcture. Tr. at 98; 104. The Company's cost of capital witness, Dr. Avera,
proposes a range for equity return of 10.4-1 1.9% (eight Westem Electrc Utilties Benchmark
Group) and advocates a higher return withn that range. Tr. at 372. Avista witness Malquist
believes that the requested 11.5% retum wil support a bond upgrade and wil minize
customer impacts. Tr. at 103-105. Dr. Avera contends that Avista's unque investment risks are
significantly greater than the benchmark group. The 11.5% retu requested by Avista, Avera
contends, is too low given'expectations for higher utility bonds going forward, unsettled power
markets, below investment-grade credit rating, and hydro uncertainties. Tr. at 372-373.
Staff witness Carlock proposes a range for equity return of 9.5-10.9% and
recommends a retu on equity of 10.4%. Tr. at 1475. Staff uses the results of discounted cash
flow (8.8-11.3%) analysis and the comparable earnings method for industrals and utilties (lO-
II %) in its computation. Tr. at 1471, 1473.
Potlatch witness Thornton proposes a much lower range for equity retu based on a
capital asset pricing model (7.70%- 9.90%) and discounted cash flow model analysis (7.5%-
9.20%) and recommends a return on equity of 8.5%. Tr. at 1001. Thornton contends that
Company witness Ma1quist bases his return on equity recommendation on personal belief and
provides no financial analysis or cost of equity calculations. Tr. at 1003. Thornton believes
Company witness Avera's results are upwardly biased and that the eight-company benchmark
sampling is too small to impart sufficient confidence. Tr. at 1004-1005. Potlatch witness
ORDER NO. 29602 7
Peseau offers simple updates to Avera's data (i.e., growth rate, dividend yields, interest rates)
that lowers Avera's ROE estimate by 140 basis points (1.4%). Tr. at 941-952.
Commission Findings
In this case, as in Avista's most recent electrc rate case (WWP-E-98-11), the paries
have advanced different methodologies to analyze and ascertain a fair rate of return on common
equity capital, including discounted cash flow (DCF) method, risk premium analysis, and
comparable earings method. Each method attempts to establish a rate of return on common
equity at a point sufficiently attrctive that free market investors wil consider purchasing
common equity shares in the company. As with other analytcal tools used in the ratemakng
process, the methods to evaluate a common equity rate of return are imperfect predictors of
futue performance. Additionally, the rate of return on equity specified by aregulatory agency
is but one factor considered by prudent investors when evaluating a utilty's stock. A utility's
stock performance in the marketplace is deterined by many varables, including management
decisions, weather, streamflow conditions, and a host of separate economic factors. Also
considered in the instance of Avista Utilties is the corporate strctue of Avista Corporation and
the Company's unregulated activities.
This Commssion has found it reasonable in the past to primarly rely on DCF and
comparable earings methods to determine an appropriate rate of retur on common equity~We
have confidence in those approaches and primarly rely on them again in ths case. The DCF
analysis utilzes the dividend rate, stock price and expected growth rate of a company to
quantify the return required by the investor. Flotation costs have also been reflected with the
DCF method. The comparable earings method evaluates retus eared by other companies,
including utilties, to quantify an investors expected retu, taking into account the risks
associated with a particular investment. A third methodology to determine a required rate of
return on common equity is the risk premium analysis. The risk premium method stars with the
rate of return for a low-risk investment, such as governent or utility bonds, and adds a
premium based on the relative risk associated with a utility's stock: A four method, the capital
asset pricing model (CAPM) measures risks using the Beta coeffcient. The retu on equity is
measured in relation to the market as a whole. As markets change, new concerns develop in
varous financial circles related to the calculations used to determine the cost of equity. One
such concern continues to be the measurement and proper use of Beta. This Commission has
ORDER NO. 29602 8
not focused on Beta or CAPM for determining the cost of equity; therefore any new concerns or
methods are not at issue in this case and wil not be specifically addressed.
The Commission has considered all methodologies and rationale i~ the cost of
capital testimony of the witnesses and finds the middle ground position advanced by Staff
witness Carlock to be reasonable. The evidence in this case supports a rate of retur on corron
equity for Avista ranging from 9.5-10.9%. This range encompasses the lower end of Avista's
recommended range from 10.4-10.9%, and the upper range of 9.5-9.9% from Potlatch's
recommendations. We find A vista's reasonable required rate of retur .on corron equity to be
10.4%. Ths retu on equity with the December 31, 2003 capital strctue and cost results in an
overall rate of retu of 9.25%. In authorizing a 10.4% retu on common equity, this
Commission acknowledges its desire to maintain Avista as a financially viable utility with credit
ratings at or above the curent leveL. The Staff proposal, adopted by this Order, results in a pre-
tax interest coverage ratio of 2.71 times. Tr. at 453. This is at the bottom of S&P's BBB-
rating. ¡d. A rating ofBBB would be an increase for Avista. As Avista continues to strengthen
its capital strcture, refinance high cost debt and address other rating agency concerns, the pre-
tax interest coverage ratio wil also improve. This is a move in the right direction to improve
Avista's utilty bond rating. We anticipate that non-utility operations/affliates will also be
makng similar efforts to reduce risk and improve earngs contributions to improve ratings. We
encourage Avista to investigate with the Staff reasonable ring fencing efforts to fuer reduce
utility risk and improve ratings. The use of this cost of corron equity, together with the cost of
debt, cost of trt preferred securties, cost of preferred stock and capital strcture previously
found, yields the following overall retu for rate base:
Component Percentage of Cost Weighted Cost
Capital Structure
Debt 50.08%8.68%4.35%
Trust Preferred Securties 5.57 6.15 .34
Preferred Stock 1.76 7.35 .13
Corron Equity 42.59 10.40 4.43
TOTAL 100.00%9.25%
ORDER NO. 29602 9
A VISTA'S ELECTRIC CASE
ADJUSTMENTS TO ELECTRIC TEST YEAR REVENUES,
EXPENSES AN RATE BASE
Once a test year is selected, adjustments are made to test year accounts and rate base
to reflect known and measurable changes so that test year totals accurately reflect anticipated
amounts for the future period when rates wil be in effect. The Idaho Supreme Cour has
described "rate base" as "the utilty's capital investment amount." Industrial Customers of
Idaho Power v. Idaho PUC, 134 Idaho 285, 291, 1 P.3d 786, 792 (2000). Adjustments to test
year accounts generally fall i~to three categories: 1) nonnalizing adjustments made for unusual
occurences, like one-time events or extreme weather conditions, so they do not unduly affect
the test year; 2) anualizing adjustments made for events that occured at some point in the test
year to average their effect as if they had been in existence durng the entire year; and 3) known
and measurable adjustments made to include events that occur outside the test year but wil
continue in the futue to affect Company income and expenses.
Staff witnesses Stockton and Hars accepted Avista's proposed Standad
Commission Basis Adjustments (Falkner Exh. 14, pp. 4-7, colums c though x), Pro Fonna
Insurance Adjustment that decreases net operating income by $649,000 (Falkner Exh. 14, p. 8,
colum ad) and Pro Forma Power Supply Adjustment (Falkner Exh. 14, p. 8, column ab) that
decreases net operating income by $7,832,000. Tr. at 1118-1119, 1075.
The Company on rebuttal agreed to and incorporated into its Rebuttal Exhibit 26,
pages 10-12 the following Staffproposed adjustments to net operating income and/or rate base:
Net Operating
Income after
Adjustment Reason Taxes Rate Base
Cabinet Gorge Update estimates to actuals $1,000 ($110,000)
Boulder Park Synchronize depreciation between
Depreciation states 57,000 13,000
Skookumchuck Sale of plant approved by the
Commission, plant and related
operating items no longer to be
n04,000)recovered through rates 8,000
Deferred Federal Appropriate deferred tax accounting -
Income Tax treatment (9,966,000)
Coyote Springs 2 Update estimates to actuas 172,000 (1,621,000)
ORDER NO. 29602 10
Small Gen. Options Remove capital costs, treatment similar (539,000)
to other unfinished plant
Labor (Non-Exec.)Update estimates to actuals 26,000
Labor (Exec.)Update estimates to actuals 9,000
Depreciation Synchronize depreciation between 432,000
states
Corp. Fees Similar treatment for Idaho utilties -
split 50%/50%74,000
Miscellaneous Similar to prior Commission treatment,
Expense exclude contributions, dues, and
expenses benefitinJl affiliates 250~000
Western Electrcity Remove expense to reflect Company's
CoordinatinJl Council non-member status 10,000
Advertising Expense Similar to prior Commission treatment,
exclude chartable contrbutions, image
advertising and non-electric ads 36,000
Avista Foundation Correctly assigns expenses to affliate 5,000
By accepting these uncontested adjustments the Company revises its requested electrc revenue
increase to $31,070,000 or 21.24%. Avista Reb. Exh. 26, at 2; Tr. at 195-196,217.
A. Agreed Upon Adjustments
1. Accounts Receivable Program Fees
Avista's Accounts Receivable Sale Program was initiated in 1988 when the
Company entered into a five-year agreement to sell $30 millon of its accounts receivable. At
that time, the effect of the program was to reduce the Company's need for financing and provide
the Company with a source of funds at a much lower effective cost. Since 1988, the Company
ha expanded the limit to sell up to $125 milion of the Company's accounts receivable. Staff
witness Stockton recommends removing the fees associated with the Company's Accounts
Receivable Sale Program because it is analogous to (or a substitute for) a working capital
addition to rate base. Avista, Stockton states, has a negative working capital requirement,
indicating that shareholders were not the source of working capital and thus no retur to
shareholders should be allowed on working capitaL. Stafs adjustment increases net income by
$357,000 and decreases total revenue requirement by $558,000. Tr. at 1116; 1127-1131; Tr. at
1087-1088.
On rebuttal A vista witness Falkner states that the Commission has previously
allowed the fees as recoverable expense. The Account Receivable Program, he states, is a cost
effective method of caring customer receivables on the Company's balance sheet. The
ORDER NO. 29602 11
alternative to sellng the accounts receivable, he contends, would be a working capital addition
to rate base at the Company's authorized rate of retur. The Company has not included a
working capital adjustment in the past due to the complexity of doing such a study. Falkner
contends Staff misinterpreted the results of its working capital study, that actually, he states,
shows that working capital is, in fact positive, not negative. Falkner contends that Stafs study
supports including the fees associated with the accounts receivable sale as an operating expense.
Tr. at 201-202.
As reflected in Stockton's rejoinder testimony, Staff and Avista agreed to reduce
Stas proposed adjustment by 50%. This amended adjustment increases Idaho net operating
income afer taxes by $179,000 and decreases total revenue requirement by $280,000. Tr. at
1141-1142. The Commission has considered the merits of both Staff and Company positions.
The Commission finds the compromise adjustment reached by the Company and Staff to be a
reasonable resolution of this issue.
2. Debt Interest Restatement Adjustment
Avista restates debt interest using the Company's pro forma weighted average cost
of debt and pro forma nite base to produce a pro forma level of tax-deductible interest expense.
Tr. at 163. Staffs adjustment rest¡:tes debt interest using the Staff-proposed embedded weighted
average cost of debt to Staffs pro forma rate base. Tr. at 1093-1094. Avista witness Falkner in
his rebuttal testimony listed Staffs Debt Interest Adjustment amongst the Company's contested
adjustments. Tr. at 196. At hearng, however, Mr. Falker explained that he agreed with Staff s
calculation methodology to restate debt interest and the only .difference between his calculation
and Stafs calculation was the level of rate base that is utilzed in the calculation. Tr. at 224-
225.
As noted below, Avista contests two adjustments (transmission projects and Boulder
Park project costs disallowance) that affect the rate base used in Stafs debt interest restatement
calculation. The Commission finds that the calculation methodology is not contested and should
be applied to the rate base amount we ultimately approve.
3. Low Income Weatherization Assistance (LIWA) Funding
The Community Action Parership Association of Idaho (CAP AI) in the direct
testimony of its witness Staper recommended: 1) elimination of the "R" number requirement
that is the total kilowatt usage per year so that all households with electrcity as the primary heat
ORDER NO. 29602 12
~
source can automatically qualify for weatherization; 2) a change in the current contract between
Avista and Communty Action Parership (CAP) to add windows, doors, and base load
measures as allowable weatherization measures fuded by Avista toward meeting the 1.0
savings to investment ratio; and 3) an increase in low-income weatherization funding from the
curent 2004 level of $108,208 (Idaho only) to $490,000 to fud the weatherization of 123
Avista units in Nort Idaho. Tr. at 1061-1064. CAPAI estimates that there are approximately
21,000 households curently eligible for Avista's weatherization program. At curent funding
levels and program design, it would take nearly 50 years to meet all the needs in nort Idaho.
Tr. at 1038, 1039.
To be equivalent to Idaho Power on a per customer basis, Staff witness Anderson
noted that A vista would have to increase electrcity Demand Side Management (DSM) fuding
for LIW A to $320,000 per year. Staff did not take a position on this issue. Tr. at 849-850.
A vista in rebuttal notes that the Company reached separate agreement with CAP AI.
Avista agreed to increase anual limited income electrc and gas DSM and BPA Conservation
and Renewable Discount (C&RD) funding to $350,000 commencing in 2006. This is slightly
higher than the $320,000 calculation appearing in Staffs testimony, but less than the $490,000
originally proposed by CAPAI. The funding wil come from the Company's gas and electric
DSM tarff riders. The Company also agrees to extend funding eligibility to include doors,
windows, and customers who use permanently installed electrc or natural gas heating
appliances regardless of historic electric usage, and agrees that customers that qualify under U.S.
Departent of Energy financial standards would be eligible for any measure meeting a savings
to investment ratio of 1.0 or above. Tr. at 747-749.
The Commission believes that fuds devoted to LIW A are a wise investment that
wil benefit all Avista ratepayers not just those who experience reduced power bils. Increased
LIW A funding can provide significant benefits in terms of lowering uncollectibles and creating
permanent load reduction. The Commission commends CAP AI and A vista for the compromise
agreement that they presented. As par of the agreement, the Company agreed to increase
anual low income weatherization funding from curent levels to $350,000 for qualifyng
electric and gas customers for 2006 and beyond. We find the terms and Company commitments
to be both reasonable and acceptable. We note further that the Company's agreement wil
provide considerable flexibility to the community action agencies in leveraging the fuds
ORDER NO. 29602 13
available so they can do their best job in weatherzing homes. CAP AI estimates that Avista has
approximately 17,500 customers below 150% of the federal poverty guidelines in its Idaho
service area. Exh. 403; Tr. at 1038; 1048. CAPAI's participation in ths case we find was a
great benefit to the many small communities and low-income customers served by Avista in
nortern Idaho.
4. Demand Side Management (DSM) Funding Levels
Avista at its May 19, 2004 meeting of its External Energy Effciency (EEE)
Advisory Board proposed reducing the Company's electricity DSM surcharge from the current
1.95% to about 1.25% of base revenues or approximately a $ 1 milion anual reduction. Exh.
132, p. 10. The Company also proposed that the DSM surcharge be set as a cents-per-kWh rate
rather than a percentage of base revenues. Tr. at 845, 846. Staff witness Anderson testifies that
in light of anticipated DSM expenditures and the need for relief from a likely base rate increase
in this case, he agrees to a reduction to the DSM tarff rider with the following conditions: (1)
assurance that a reduction in DSM revenues will not negatively impact Avista's pursuit of cost-
effective energy measures, regardless of whether such measures result in Avista's DSM fund
balance being negative, and (2) an increase in Avista's LIWA contribution to a level determined
reasonable by the Commission. Even with the reduction, Anderson notes that Avista's DSM
revenue wil stil be higher than Idaho Power's. Sta supports a surcharge change from a
percentage ofbasè revenues to a cents-per-kWh base charge. Tr. at 845-849; 851.
On rebuttal, Avista witness Powell states that a tariff rider equal to 1.25% of curent
base revenues should be suffcient to meet the Company's forecasted fuding needs for year
2005. The Còmpany commts to incur a negative tarff rider balance 'if cost-effective DSM
resource acquisitions require more fuds than are available from DSM tarff rider resources.
The Company proposes to correct any negative or positive balances in the electric or gas DSM
tarff rider through anual revisions. The Company also proposes to revise its DSM surcharge
from a percent of revenues to an amount equal to a percent of the current retail rate. Tr. at 745-
749. The Company's proposal is not a flat cents per kilowatt hour across all rates, Powell
explains, it is a reduction from an amount equal to 1.95% of current base revenues to an amount
equal to 1.25% of current base rates. Tr. at 750-751; also at 753.
The Commission finds Avista's proposal to reduce the DSM surcharge from 1.95%
to 1.25% of base revenues to be both justified and acceptable. We also find it reasonable to
ORDER NO. 29602 14
apply the surcharge on a cents/kWh basis. In doing so we commend the Company for its
continued commitment to cost-effective DSM resource acquisitions and we expect the Company
to continue to pursue cost effective DSM regardless ofDSM funding balances.
5. Coyote Springs 2 (CS2) Deferred Return
Coyote Sprigs 2 (CS2) is a 280 MW natural gas combined cycle combustion
turbine (CCCT) located near Boardman, Oregon. It was selected by Avista as a supply side
resource in the Company's 2000 Request for Proposal (RFP) process. Avista owns 50% of the
plant and is requesting a ratebasing of its investment as par of this rate case. Staff witness
Hars proposed reducing the Company's revenue requirement by deferring the Company's
retur on the Coyote Springs 2 project. A return on the project would not be denied, but full
recovery of this retur deferral would take 10 years to be completed, The Company's annual
revenue requirement is reduced by $13,054 per millon dollars of Coyote Springs 2 gross plant.
Tr. at 1094. While Avista witness Falkner in his rebuttal testimony and schedules did not
reduce the revenue requested by the Company for this deferral, during the hearng he stated that
the Company agreed with this proposal. Tr. at 225. The Commission accepts Stafs CS2
deferred retu proposal as reasonable. Deferrg the retu serves to mitigate the associated
rate increase. The Company will receive the same net present value over 10 years because the
~eferred balance accrues a carrng charge at the return authorized in this case.
B. Disputed Adjustments
1. Transmission Projects
To reflect project estimated costs, depreciation, property taxes and income taxes of
thee transmission projects, i.e., Pine Creek 2003 kV substation, the Beacon-Rathdru 230 kV
line and the Beacon-Bell #4 230 kV line, Avista proposed a pro forma adjustmentincreasing
rate base by $8,849,000 and decreasing net operating income by $249,000. Tr. at 172-173; Tr.
at 247.
Staff witness Hars recommends removal of the Beacon to Bell line ($438,000), a
project that was suspended until 2005; recommends that the estimated costs for Beacon to
Rathdru line and Pine Creek Substation Rebuild be updated from estimates to lower actual
amounts resulting in a rate base reduction of $615,000; and contends that Avista did not reflect
proper matching of revenues and expenses as if projects had been in service the full year. To
include the plant investment as if the plant had been in operation the full year without
ORDER NO. 29602 15
corresponding revenue and expense adjustments, Staff contends, is uneasonable and creates a
mismatch between test year revenues and expenses. The Commission could disallow the entire
adjustment because of this mismatch. One alternative to denying the plant adjustment, Staff
suggests, is to remove anualization and show reduced costs for only one month of the test year.
Hars stated that the effect of ths adjustment reduces rate base by $8,518,000, operating
expenses by $358,000, and revenue requirement by $1,592,000. A second alternative is to
anualize the projects' costs using a proxy for imputed revenues and expense reductions,
producing approximately $270,000 of imputed Idaho revenue and $30,000 of reduced Idaho
electric expense. The corrected anualized costs increase rate base by $7,801,000. Tr. at 1076-
1080; Exh. 103.
Potlatch witness Peseau contends that Avista pro formed into rate base $26.3 milion
in transmission projects but made no similar revenue adjustment. This mismatch, Peseau
contends, should be corrected by: (1) reversing the pro forma entres and properly matching test
year averages on both sides of the ledger, or (2) updating revenues to the 2004 level in the same
manner as rate base and expenses, his preferred method, or (3) employing the rate base
adjustments adopted in the Idaho Power rate case (5% of the rate base additions). Tr. at 925-
926.
Avista witness Falkner on rebuttal contends that the multi-year transmission
upgrades included in the Company's filing are complete, known and measurable. Thefinancial
benefits of importexport energy revenue, he states, are captured in the power supply modeL.
Should the Commission determine, however, than an adjustment to revenues and/or expenses in
conjunction with the full rate base treatment of the new transmission adjustment was necessar,
Falkner contends that Staffs proposed proxy alternative of including approximately $270,000 in
additional revenues and a $30,000 expense reduction would be reasonable. Tr. at 197-199.
Commission Findings
The Commission has reviewed the testimony and recommendations of the paries. It
is reasonable as Potlatch surmises that there is an offset or savings related to transmission
investment. When significant plant improvements are completed late in the test year or after the
test year, the challenge is to reasonably include the investments in the test year in a way that
fairly compensates the Company for its investment, but also fairly treats ratepayers by matching
investment revenues with investment expenses. We encourage the Company to develop means
ORDER NO. 29602 16
of computing the expense savings and revenue enhancements associated with transmission
investment. We accept as reasonable Stafs proposed Beacon-Bell adjustment and the proposal
to update the Beacon-Rathdru and Pine Creek constrction estimates to actuals. Rather than
deny the Company's anualizing plant rate base adjustment outright or require the Company to
wait for its next rate case to include the plant in rates, we accept Staffs proxy proposal for
calculating imputed revenues and expense reductions. We do so reluctantly, however, because
the Company has not adequately attempted to calculate expense savings and revenue producing
effects. We put the Company on notice that ths is not a method we want to use in the futue.
Henceforth, if the Company seeks full recovery of plant investment as if the plant had been in
operation a full year, it must present a corresponding adjustment to revenues and expenses.
2. Boulder Park Small Generation Project
Avista witness Lafferty contends that the 25 MW Boulder Park natural gas-fired
reciprocating engine generation project was a reasonable addition to Avista's energy resource
portfolio and was economic compared to market alternatives at the time the decision to build
was made durng the "energy crisis." The project was fast-tracked, Laffery states, in order to
mitigate the high prices and volatility in the electrc power market in the 2000-2001 energy
crisis. Lafferty contends that the Company reasonably managed Boulder Park project costs
under the circumstances even though costs were higher than projected due to the fast-track
design and constrction approach. The May 2001 constrction cost estimate was $21 milion;
the total actual cost was approximately $31.9 milion. Contractor costs were approximately $4.7
millon over budget due to such factors as the additional design scope, change orders, overall
project complexity and project management costs due to the extra time requied to complete the
project. A vista constrction costs were over budget by approximately $2.2. millon due to
changes in project scope and complexity. Tr. at 541; 592-598.
Staff witness Sterling believes the Company's decision to pursue the Boulder Park
project durng the 2000-2001 energy crisis was a reasonable response to extremely low water
conditions and high market prices. Completion of "fast-track" constrction, however, was
delayed by eight months, from September 2001 until May 2002. There were also considerable
cost overrns. The final cost of Boulder Park was $32.1 milion, $11 milion over the $21
milion construction cost estimate, a greater than 50% cost overr. Although not new
technology for the power industry, the natural gas fuel reciprocating engine generators were the
ORDER NO. 29602 17
first project of its kind for A vista, a factor which A vista states contrbuted in par to actual
constrction costs being higher than original estimates. Tr. at 1220; Avista summary of cost
varations, Exh. 129. It is common, Sterling contends, to include a contingency amount in the
cost estimate for large construction projects to insure that fuds are available in the event of
unplaned problems, circumstances or conditions. Contingency amounts for projects similar to
this one, Sterling estimates, are typically in the range of 5-15%. Sterling believes ratepayers
should be able to expect a utility to have the ability to construct projects at least cost. Staff
recommends 10% of the final project cost be disallowed, that equates to a $205,000 reduction in
anual Idaho revenue requirement and a $1,085,000 reduction in rate base. Tr. at 1082-1083;
Tr. at 1218-1224; Exh. 129.
On rebuttal Avista contends that Stas recommended 10% Boulder Park
disallowance is not appropriate given the challenges presented by the market conditions and the
project's unique characteristics. Avista also contends that the slow down of the project was
justified by a change in circumstances, lower market energy prices in the sumer of2001 and a
financial need to preserve cash. Tr. at 632-633.
Commission Findings
The Commission has considered the testimony regarding Boulder Park and finds that
a 53% construction cost overr is uneasonable. We expect a utility such as Avista to have the
experise and experience to plan, constrct and manage any project it undertakes at a reasonable
cost. This project was planed as a "fast track" response to poor water and a volatile energy
market. It was not completed on time and was 53% over budget. The Company must assume
some responsibility for the excessive cost. Staff recommends a 10% disallowance and identifies
specific cost category overrs. We believe that the Company should be held to a higher
standard. Ratepayers will not be asked to pay for what we find to be a Company learing
experience. Staff notes that the CS2 and Kettle Falls overrs totaled 16% and 8%,
respectively. We find it reasonable to limit the authorized rate base amount for Boulder Park to
the project construction estimate plus a 15% contingency. The original constrction estimate for
Boulder Park was $21,000,000 (Exh. 8, Sch. 35; Exh. 129). An additional 15% increases the
total rate base allowed to $24,150,000. The final cost of Boulder Park was approximately $32
milion. The total disallowed amount is $7.62 millon on a system basis. The Idao
jursdictional share of the disallowance is $2.6 milion.
ORDER NO. 29602 18
3. Prudency of Coyote Springs 2 (CS2)
Company witness Lafferty testifies that A vista in a sprig 2000 update to its 1997
Integrated Resource Plan (IR) identified a need for new resources. The Company issued an all-
resource 2000 Request for Proposal (RFP) for 300 MW of capacity and energy. The Company
received 32 proposals from 23 bidders for a total of 2700 MW of supply-side and demand-side
resources. The RFP process included third-par review and critique. Resource alternatives
were raned in an evaluation matrx. The Company selected the 280 MW CS2 combined cycle
combustion turbine as the preferred supply-side option. CS2 is a project acquired by Avista
Power from Enron and was included in the RFP process at an "at cost" price. In addition to
overall cost effectiveness, a key factor cited by the Company in selecting the CS2 project was
that it included a fully licensed site. The major equipment had already been ordered and an
Engieerig, Procurement and Constrction Contractor (NEPCO) an Enron affiliate, had already
been selected.
Due to finanèial challenges facing the Company because of low water conditions
and high market prices in the first half of 2001 and diffculty encountered in finding project
financing, Avista sold 50% of the CS2 project to Mirant on December 12,2001. As par of the
transaction, Mirant pays one-half of all capital costs and one-half of all operation and
maintenance costs for the project. Mirant is responsible for securing its own natural gas supply
and transportation and for making its own arangements fOr transmission to move power from
the plant. Avista maintans it took reasonable steps to bring, the CS2 project to commercial
completion as quickly as practicable, and to manage the failure of and damage to CS2's
transformers. The project star-up delays, the Company contends, were unforeseeable 'and
uncontrollable. Avista's management of the cost overrs caused by the banptcies of Enron
and NEPCO, the Company contends, was reasonable. Avista's share of CS2's constrction
costs as of 9/30/03 was approximately $109 milion rather than the $94 millon originally
projected. Tr. at 540; 542-563.
Staff witness Sterling contends that the CS2 resource was needed by Avista to
address projected generation deficits identified in the Company's IRP. One of the primar
reasons for the deficit identified in the Company's IR was the sale of the Company's 201 MW
share of the 1340 MW Centralia coal-fired generatig plant. Sterling believes that the
ORDER NO. 29602 19
Company's RFP process was fair and Staff confirms that CS2 was transferred by Avista Power
to Avista Utilties "at cost." It is Stafs position that Avista should not be denied recovery of
$15 milion in cost overrs, overrs which, Sterling contends, were neither foreseeable nor
within the Company's control. Tr. at 1210-1217.
Potlatch witness Peseau notes that in the Company's corporate strctue (Exh. 1, p.
5), Avista Utilities is not a separate business entity, only an operating division of Avista Corp.
This organzational relationship, he contends, blurs the distinction between regulated and
unregulated activities. Tr. at 899. In Avista's last rate case, Peseau reminds the Commission
tht Potlatch expressed concern that Avista's corprate structue, and its practice of not
contemporaneously making trades to its regulated or non-regulated ar, left it with the latitude
to subsequently allocate trades based on their profitability. Tr. at 899-900. The transactional
facts surounding CS2, Peseau contends, presents a case that is far worse. Tr. at 900.
As Potlatch recounts events, CS2 was originally a Portland General Electric (PGE)
project to be built as a companion to PGE's Coyote Springs 1 generating station located near
Boardman, Oregon. At that time PGE was a regulated Enron subsidiar. In mid-1999, Enron
and PGE decided to sell CS2. On October 4, 1999, Avista Power, an unegulated Avista Corp.
subsidiary, entered into an "evaluation agreement" with PGE that allowed it to begin a due
diligence investigation of the plant. On March, 4, 2000, Avista Power signed a Letter of Intent
with Enron to buy both CS2 and a turbine purchased by Enron for CS2. The total purchase price
when the deal was finally concluded was approximately $59.5 millon. Tr. at 900-903.
In December 2000 Avista Corp. anounced it would acquire CS2 from Avista
Power. Tr. at 553; 606-607. But Potlatch contends that Avista did not in fact immediately
follow though on ths anouncement. Tr. at 905. Avista responds that the Company chose to
keep ownership of the plant with the CS2, LLC until construction was completed citing the
benefit of forming LLCs to separate costs and liabilities durng constrction and the Company's
initial intent to obtain separate construction financing. Tr. at 607. Potlatch contends that Avista
Power was never under a legal obligation to sell to Avista Corp. Avista discovery responses to
Potlatch revealed no contract, memorandum of understanding, or any other document that would
evidence an intention to proceed with the sale. Tr. at 907. Once Avista began experiencing cash
flow problems, Company memos indicate that Avista Power was trng to &ell the entire plant to
thid paries in the summer and fall of2001, months after the anouncement that Avista Utilties
ORDER NO. 29602 20
would acquire CS2 from Avista Power. Tr. at 905. Ultimately Avista Power sold a 50 percent
share of CS2 to Mirant on December 12, 2001. Tr. at 552. The remaining 50 percent of CS2
was not transferred to Avista Corp. until Januar 1, 2003, afer constrction was substantially
complete. The project began commercial operation for the utility in July 2003. Tr. at 607.
In April 2002, CS2's prime contractor, NEPCO, an Enron affiliate, fied for
banptcy and CS2 lost the benefit of its fixed price constrction contract, while at the same
time incurng the cost of replacing the prime contractor and settlng with subcontractors. Tr. at
553. The history of CS2, as characterized by Potlatch, has been and continues to be an
economic and operational nightmare. The constrction problems caused the estimated cost of
Avista's half of the plant to increase from approximately $94 milion to $109 milion. Tr. at
903-904.
Potlatch contends that CS2 should not be recovered in rates until it js proven "used
and usefuL." Peseau contends that is not currently used and useful, and there is no indication it
wil ever be after the three failures experienced thus far. If CS2 is included in rate base, Peseau
recommends that costs be limited to the plant's fair market value as of the Janua 1, 2003
transfer date, $84,560,000 by his calculations, to prevent an unegulated affliate from profiting
at ratepayer expense. Tr. at 906-908. The basis for Potlatch's fair market value number was a
$604/kW constrction cost estimate advanced by Avista in rebuttal testiony in a 2002 generic
PURA Surogate Avoided Resource (SAR) case (GNR-E-02-1). On cross, Potlatch conceded
that the Commission did not accept Avista's avoided capital cost in that case, but instead in
Order No. 29124 adopted a Northwest Power Planng Council (NWPPC) generating resource
advisory committee number ($679/kW), a year 2000 number that when escalated forward two
years to provide a comparable comparson to CS2 results in a $99,094,000 value. Tr. at 968.
On rebuttal Avista notes that between July 1, 2003 and Januar 15, 2004, CS2
performed with a 92% availabilty factor, generating approximately 85 aMW. The Company at
hearng expected CS2 to retu to servce in mid- to late-August 2004. Tr. at 602; 604-608.
Commission Findings
Despite a rather involved history of resource acquisition and constnction and the
Company's unfortunate entanglement in the Enron banptcy, the Commission fids that CS2
was a needed resoUrce and that the acquisition of CS2 by A vista Utilities was reasonable and
prudent. We find the purchase cost was reasonable in the context of other resource alternatives
ORDER NO. 29602 21
offered in the Company's 2000 RFP. The question of whether there was a legal obligation to
transfer CS2 following a simple Company anouncement of resource selection and the timing of
the transfer from Avista Power to Avista Corporation (Avista Utiities) raise questions of
opportunstic gamesmanship between regulated and unegulated entities in the A vista Corp.
family. The transactional history of the CS2 acquisition suggests that a ring fencing mechanism
needs to be put in place to insulate the regulated utility from risks undertaken by non-regulated
affiliates. Techniques to be explored include pro-active regulatory oversight, financial
restrictions, strctual separations, and operational controls.
The "used and useful" issue raised by Potlatch as an arguent against ratebasing is
perceived by this Commission on the facts of ths case to be one of operational and regulatory
timing. If the project rate base question had been considered prior to the Januar 15, 2004
transformer failure, the Company would have been able to demonstrate that CS2 was used and
usefu and no pary would have challenged the Company's assertion. CS2 was indeed
operational from July 2003 to Januar 2004. It performed with a 92% availability factor,
generating approximately 85 aMW. It was economically dispatched for two weeks and was
ostensibly available for the remainder of that period. We also canot ignore the fact as stated
above that the CS2 project was the low cost resource selected in the Company's 2000 RFP, and
that there was a need for the resource.
Applying the reasoning advanced in our discussion above of Boulder Park, we find
that Company self-build projects should be subject to a cost overr cap. We find it reasonable
to limit the authorized rate base amount for CS2 to the project constrction estimate plus a 15%
contingency. The original constrction estimate ofCS2 was $93,933,400. Rev. Exh. 6, Sch. is,
p. 3. An additional 15%, $14,090,010, increases the total rate bRse authorized to $108,023,410
(system). The resultant Idaho Commission authorized gross plant is $37,172,000. This
compares to the Company and Staff agreed CS2 gross plant (Idaho) number of $37,291,000.
Exh. 109. The calculated amount of rate base disallowance is $119,000.
4. Vegetation Management (Tree Trimming)
To reflect planed increases in vegetation management, Avista witness Kopczynski
proposes a $1.2 milion Idaho jursdictional adjustment using a 2004-2007 four-year average of
scheduled Company vegetation management projects. Company witness Falker contends that
the proposed expenditure level is necessar for the proper management of vegetation around
ORDER NO. 29602 22
both transmission and distrbution lines to most effectively ensure reliabilty levels, improve
safety and reduce customer outages. The effect of this adjustment reduces Idaho electric net
operating income by $785,000. Tr. at 256; Tr. at 172.
Staff witness Stockton proposes to replace the Company's requested vegetation
management expense adjustment with an average of the actual amounts expended during the
six-year period of 1998-2003 to reflect varabilty of expenses and an abnormally low 2002 test
year expense. Stafs proposed adjustment increases net income by $288,000 and decreases
total revenue requirement by $451,000. Tr. at 1116; 1125-1127; Tr. at 1086-1087.
In response to 'Staf concerns, A vista witness Faler recommends use of a "one-
way" balancing account. If the Commission were to authorize the Company-requested level of
expenses ($ 1.8 milion Idaho), the Company would commit that level of resources annually to
vegetation management going forward. If less is spent, the difference would be recorded as a
liability and. either spent in a futue period or retumed to customers though an appropriate
tracking mechanism. Ifthe Commission were to adopt a six-year historical average as suggested
by Staff, Falkner recommends that the Commission exclude the 2002 level of $550,255 as
abnormally low. Tf. at 199-200; Tr. at 264-265.
The Commission appreciates the importance of the Company's tree tring
program for system reliability. A good vegetation management program reduces customer
outages and maintains system integrty. We also note the level of vegetation management
expense approved by the Commission in the Company's last general rate case and recognize the
need to enhance expenditues as time passes. This is paricularly tre in light of the Company's
limited expenditures on vegetation management in 2002. Consequently, we fid it reasonable to
fund the $1.8 milion level of expense recommended by A vista for Idaho tree trmming.
5. Pension Expense
Avista included in its test year expenses $14,000,000 on a total system-wide basis
for employee pension expenses, including an expense adjustment of$900,153 to reduce pension
expense from the 2003 Net Periodic Pension Cost of $14,900,153 to the 2004 estimated Net
Periodic Pension Cost. Tr. at 168. This pension expense equates to an Idaho electric
jurisdictional expense of $2.1 milion. Staff witness English disagreed with using 2004 pension
expense on the premise that the expense proposed by the Company is simply an estimate and not
known and measurable. Tr. at 1155. Staff witness English also disagreed with the use of Net
ORDER NO. 29602 23
Penodic Pension Cost and proposed the use of the Required Minimum Contnbution under the
Employee Retirement Income Securties Act of 1974 (ERISA). Tr. at 1162.
Staff proposed reducing system-wide test year pension expense of $14,000,000 by
$5,305,315, bnnging the test year pension expense to $8,694,685, thus, increasing Idaho
operating income by $554,000 and reducing the Company's revenue requirement by $867,000.
Tr. at 1088; Tr. at 1158. Staff witness English explained that the adjustment is a reconciliation
between cash and accrual accounting. In other words, although the Company accrues a pension
contrbution on its books for financial reporting puroses, A vista is only required to contnbute
to the plan the amount calculated under the ERISA calculations. The recovery of pension
expense, English contends, should be based on the actual amount of cash a company is required
to contnbute to the plan to meet its minimum funding liabilty. Any fuding over the Required
Minimum Contnbution under ERISA, English contends, penalizes ratepayers. Tr. at 1158-1163.
Company witness Falkner responded in rebuttal that F AS 87 has been the standard
for pension expense since its adoption in 1987 and has been previously accepted in Idaho. The
reduction of the retum on asset assumption, he contends, is supported by actual fud retu
history, as well as consistency with return reductions by other nortwest utilties. Actual
contrbutions to the pension fud have exceeded the level included in Idaho general rates by $29
milion since 1999. Absent a larger than minimum contnbution in 2002, the minimum 2003
contnbution level would have been approximately $14 milion, that is the FAS 87 accrual level
proposed in this case. Had the Company not contnbuted additional money to the plan in 2002,
Falker contends, the Required Minimum Contrbution for 2003 would be greater than Stafs
proposal and by accepting Staff s proposal, the Commission would penalize the Company for
attempting to achieve a fully fuded pension plan. Tr. at 202-210.
On the evidence presented in this case, the Commission finds the adjustment
proposed by the Staff for the pension plan expenses to reconcile cash and accrual accounting to
be fair and reasonable. However, the Commission does not wish to unduly impose a penalty
upon the Company for its additional contrbutions in 2002. Therefore, the Commission accepts
the amortization of the additional $4.5 milion contrbution in 2002 over a two year penod.
Avista wil be allowed to recover in rates a total pension expense of $10,347,343 on a system
basis or $1,549,386 from the Idaho electnc jursdiction. Ths results in an adjustment increasing
Idaho net operating income by $381,000.
ORDER NO. 29602 24
6. Legal Expenses
Staff witness English proposes removing expenses from the test year for legal costs
that should have been directly assigned to unegulated affliates (Avista Labs; Avista
Communications) or that were for extraordinary events that wil not recur (Le., Enron
banptcy; or the now closed 2002 FERC investigation into electrcity trading practices). This
adjustment increases net operating income by $366,000 and reduces Avista's revenue
requiement by $73,000. Tr. at 1168-1170; Tr. at 1090.
In response, A vista witness Falkner agrees that legal expenses related to A vista Labs
and Avista Communications should be removed. Tr. at 211. Falkner argues, however, that legal
fees related to the Enron banptcy and FERC investigation are representative of ongoing legal
expense, that has remaied constant at $3.8 milion over the last six years. Such a level, the
Company contends, should be reflected in rates absent a showing of imprudence. Alternatively
the Company proposes use of a six-year average of legal expense charged to operational
accounts to "smooth out" extraordinar items. Such an average would reduce Idaho legal
expense allocations to the electrc system by $32,500. Tr. at 210-214.
The Commission finds Staffs adjustments removing non-recurrng extraordinar
legal expense to be reasonable and appropriate. A vistá contends that some extraordinar
expense always comes up and should not be a reason for excluding the level of expense
requested. Our view is that the level of legal expense incurred by the Company is somewhat
withn its control. Furer, we note that the regulatory accounting system does not pennit
inclusion of unusual expenses in a test year for ratemaking purposes. The Commission has
confidence that A vista Corp. wil continue to act in good faith to protect the interests of its
utility customers and its shareholders.
Incorporating the foregoing adjustments, the Commission approves the following for
rate base and revenue requirement.
Rate Base
Avista proposed a pro forma electric rate base of $440,270,000 for the Idaho
jursdiction. Exh. 14, p.2. As we indicated in our prior Amended Interlocutory Order No.
29588 the Commission approves as just and reasonable an electrc pro forma rate base of
$424,114,000. See attached Appendix C.
ORDER NO. 29602 25
Revenue Requirement
Curent revenue recovered in Idaho's electric base rates is $146,248,000. The
Commssion in this case approves a base revenue requirement of $170,964,195, an increase in
electrc base rates of $24,716,195 or 16.90%. The resultant average cents per kilowatt hour for
base rates is 5.47 cents.
Summary of Adjustments to Electric Test Year Revenues, Expenses and Rate Base
Considering all the evidence presented, and including all adjustments, the
Commission finds just and reasonable Idaho jursdictional expenses for the 2002 test year in the
amount of $140,696,000, and Idaho jursdictional operating revenues in the amount of
$168,191,000 for an operating income before federal income tax of $27,495,000. The after tax
Idaho operating income is $23,121,000. Afer all adjustments, we find a 2002 total Idaho
jursdictional rate base amount of $424,114,000 to be just and reasonable. Appendix C to this
Order sumarzes the Commission's findings on rate base and operating results for the test year.
Calculation of Revenue Deficiency
Based on ultimate' decisions determining the Idaho rate base, net operating income
requirement, and retur on common equity, we proceed to determe the Idaho revenue
deficiency with the following calculation:
Rate Base
Rate of Retu
Net Operating Income Requirement
Operating Income
Income Deficiency
Conversion Factor
Revenue Requirement Deficiency
Levelized Deferred Retur on Coyote Springs 2
Revised Revenue Requirement Deficiency
$424,114,000
9.250%
$39,231,000
$23,121,000
$16,110,000
.63926135
$25,201,000
(485,000)
$24,716,000
ORDER NO. 29602 26
JURISDICTIONAL SEPARTIONS, COST OF SERVICE
AND RATE DESIGN
The Commission, for the puroses of electric rate design maintais existing
customer/service charges, approves a separte rate schedule for Potlatch, approves a two-block
energy rate and declining tail-block for electrc general service Schedules 11, 21 and 25, and
moves all customer classes to within i 0% of full Cost of Service.
The Commission also accepts the Company Cost of Service study methodology and
allocation factors including the four factor allocation adjustment proposed by Potlatch witness
Peseau and accepted by A vista in rebuttal testimony and the A vista rebuttal compromise to the
Schedule 25 primary plant distrbution adjustment proposed by Coeur Silver witness Yanel.
The accepted Cost of Service results were used as the starting point for revenue allocation to
customer classes.
1. Jiirisdictional Separations
The jurisdictional separations methodology is used by A vista to allocate total electrc
system costs to its Idaho, Washington or Federal Energy Regulatory Commission (FERC)
jurisdictions. The FERC jurisdiction is comprised of Avista's wholesale sales of energy to other
utilities. A vista witness Falkner uses the same jursdictional separation methodology approved
by the Commission in the Company's last general rate case, WWP-E-98-4. The methodology
directly assigns revenues, costs and investments to jursdictions where appropriate and allocates
the remainig amounts. The methodology uses 2002 test year booked amounts without
adjustment. All adjustments are included on an Idaho system basis at the beginnng of the cost
of service process.
Staff witness Hessing, noting the value of consistency from case to case, accepts the
Company's jurisdictional separation methodology. Tr. at 1259-1260.
The record in this case s~pports a Commission finding that the methodology the
Company used to separate costs between the Idaho, Washington and FERC jurisdictions is
reasonable and appropriate. The jurisdictional separations study results in an Idaho system
revenue requirement allocation of$169.3 million.
2. Class Cost of Service Methodology
Once Idaho jurisdictional test year costs are deterined with the jursdictional
separations study, the next step is to állocate the adjusted costs or the revenue requirement to a
ORDER NO. 29602 27
series of fuctional costs and then to the different customer classes served by Avista in
accordance with recognized principles and generally accepted procedures in order to obtain an
indication of relative cost responsibilities of each class of customer. Ths allocation is done in
two pars. First, a class cost of service (COS) study is conducted that identifies what the
revenue allocation for each class would be at full COS. Finally, if some increases are
considered to be too large, a maximum increase cap is established and unrecovered revenue is
spread to other classes.
Avista witness Knox uses the "Peak Credit" Cost of Service methodology approved
by the Commission in the Company's last two general rate cases. The Peak Credit method for
COS separates the Company's generation costs into demand and energy components. It then
allocates demand on a 12 coincident peak basis and energy on a class consumption basis. Avista
in ths case, however, depars from its standard 60 percent (customer)/40 percent (energy)
allocation and proposes to allocate "common costs" on the basis of four factors: direct O&M
expenses, direct labor, net direct plant and number of customers. Common costs are typically
defined as those costs necessar for the utilty to fuction, but which are left over after most
directly assignable costs have been identified and "functionalized;' to production, transmission,
distrbution or customer accounts. Knox provides an altemative scenaro to ilustrate the impact
of different allocations. Under either scenario, residential and extra large general service
customers stil provide less revenue than the cost to serve them. Tr. at 320-328. Staring with
the COS result, A vista witness Hirschkom proposed a rate spread moving the relative rate of
retu' for each schedule approximately one-half way toward cost of service, with the exception
of the lighting schedules. Tr. at 777.
As in the case of Jursdictional Separations, Staff witness Hessing states that there is
value in applying a consistent class cost of service methodology from case to case. Use of a
consistent methodology, he states, allows usage, and customer characteristics and the accounting
data to drve the results. Hessing accepts the Company's proposed cost of service methodology
which he states is the same methodology with minor modifications that the Commission
accepted as the staring point for revenue allocation in the Company's last general rate case. Tr.
at 1259-1260.
Changes to cost-of-service methodology shift costs among classes and affect
revenue requirement responsibilty. Staff witness Schunke also proposes an incremental move
ORDER NO. 29602 28
(20%) toward full cost of service in recognition that cost of service results are not precise and
unacceptably large increases to some classes would occur. If a second step adjustment in cost of
service is needed, Schunkerecommends reviewing cost of servce after the Power Cost
Adjustment (PCA) balance drops to zero. Tr. at 1321-1325; Tr. at 1318; Exh. 143.
Coeur Silver Valley witness Yankel contends that if data is utilzed that is more
reflective of cost causation, the rate of retur for the Schedule 25 class comes out to be above
the jurisdictional average. Mr. Yanel recommends that Schedule 25 customers be given the
average jursdictional increase. Yanel notes that Avista did not directly assign identifiable
primar plant (i.e., lines, towers, and overhead conductors in Accounts 364-367) to
corresponding Schedule 25 customers, as it did for Potlatch. Yanke i proposes that certain
Schedule 25 Primar Distribution costs be directly assigned. Yanel contends that rates should
be established that better reflect load factor differences and cost causation. Tr. at 515-523.
Potlatch witness Peseau contends that the change proposed by Avista witness Knox
to move to a four-factor allocator for common costs is a significant change that improperly shifts
costs to higher load factor customers. Tr. at 957-959. Peseau contends that Knox in her cost of
service analysis has improperly defined direct O&M expenses as one of the four-factors to
allocate common costs. Peseau contends that this can be corrected by removing the fuel and
purchased power expenses.
Avista, Peseau notes, has historically allocated common costs to customer groups
with a 60% customer/40% energy allocation factor. Peseau recommends that the Commission
continue to use its previously adopted 60%/40% method for common cost allocation or adopt
the four-factor method with his corrections. Tr. at 926-933; 958-959.
If the overall approved increase is less than 10%, Peseau recommends that all
customer classes be moved to full cost of service. If the increase is greater than 10%, residential
and large general service rate customers, he states, should be moved at least halfway toward rate
of retur parity, with two anual automatic adjustments thereafter to close the remaining gap.
Tr. at 938. Peseau contends that Stafs proposal to move various rate schedules only 20%
toward cost of service wil perpetuate the longstanding subsidies among customer classes. The
PCA reduction proposed by the Company in this case, he states, provides an opportunity to
make a bold move toward cost of service; Tr. at 959-962. Peseau proposes to allocate
transmission costs strctly on a demand basis as, he states, was done in the recent Idaho Power
ORDER NO. 29602 29
rate case, Case No. IPC-E-03-13. Peseau contends that Avista's cost of service study overstates
the anual cost of serving Potlatch by approximately $1.4 milion per year. Tr. at 926-938.
A vista witness Knox on rebuttal agreed with Potlatch that resource costs should be
excluded from the O&M portion of the four-factor allocator used for common costs in cost of
service. She revised her COS study accordingly. Tr. at 338. Knox contends that the 100%
demand allocation advocated by Peseau for all transmission costs represents a material change
from the peak credit methodology the Company has historically applied and opposes its use. Tr.
at 339-341. Regarding Couer Silver's proposal, Knox contends that the cost of primary
distrbution plant Yanel proposes to assign to Schedule 2? customers is understated and canot
be reasonably estimated without fuer investigation. Knox proposes an intermediate cost
assignment between the Company's allocation and Yanel's estimated assignment, a change
which materially increases the rate of return for Schedule 25 customers (including Potlatch's
Lewiston Facility) and shifts cost responsibility to other customer classes. Tr. at 341-344.
Hirschkorn recommends that the Commission use the ratio of the revenue increase it
proposes for each schedule as a guideline to move halfway toward COS regardless of the overall
approved increase. Tr. at 815-817.
Recommended Spread of Revenue Increase
Residential Schedule 1 .401
General Service Schedule 11 .101
Large General Service Schedule 21 .236
Extra Large General Servce Schedule 25 .076Potlatch (Schedule 25) .155
Pumping Service Schedule 31 .017
Street and Area Lighting Schedules 41-49 .014TOTAL 1.00
Hirschkorn disagrees with Peseau' s recommendation that all schedules be moved to full COS
over the next 2 years based on the curent COS study if the rate increase is greater than 10%.
Hirschkom' contends that the cost of service study should only be used as a guide in establishing
rates. The testimony has shown, he states, that one or two adjustments in cost allocation can
significantly change the results of a study. Tr. at 822.
The Commission has reviewed and considered the Company's cost-of-service
allocation study, Potlatch and Coeur Silver's critique of same and Stafs support of the study.
ORDER NO. 29602 30
The Commission finds Avista's Peak Credit Cost of Service methodology with the Company
proposed revisions to allocation of common costs suggested by Potlatch and allocations of
primary distrbution costs as suggested by Coeur Silver to be an appropriate staring point to
allocate costs to customer classes. Recognzing cost-of-service studies are a balance of ar and
economic principles, we find that the COS study methodology proposed by the Company reflect
a reasonable approximation of class revenue responsibility.
A. Weather Normalization
An adjustment is used to calculate the change in kWh usage required to adjust loads
experienced to the amount expected given "normal" weather. Avista witness Knox proposes a
change in the prior weather normalization methodology to include the effect of weather sensitive
cooling and reflect exactly five heating seasons rather than five and a half. The change is
reflective of increased satuation of the air conditioning market in the region. It also reflects that
although normally a winter peaking utility, in recent years the Company has experienced
summer peaks near the same level as the winter peaks. Without incorporating cooling
sensitivity, the prior method would add usage during an abnormally hot sumer due to fewer
than normal heating degree days. Tr. at 319-320. Staff witness Sterling accepts Avista's
electric weather normalization performed as accurate and reasonable. Tr. at 1190; 1192-1194.
The Commission has reviewed the record and approves the change in the weather
normalization method as reasonable and comporting with changes in the Company's heating
degree days and customer usage.
B. Power Supply Adjustments
Avista witness Johnson states that the Company's power supply expense has
increased by approximately $11 millon (Idaho) from the prior general rate case. The increase is
priarly drven by reduced wholesale net revenues and an increase in fuel expense. The
Company proposed 67 pro forma adjustments to 2002 test year power supply revenue and
expenses, the majority of which are associated with contracts, the expiration of an existing
contract or the initiation of an existing contract, or due to specific, projected or estimated
changes in contract rates or charges. The remaining charges result from the AURORA dispatch
simulation model, and projected fuel expenses. Expenses have been reduced by $85.9 milion
and revenues have been reduced by $55.4 milion for a net $30.5 million decrease in the system
ORDER NO. 29602 31
revenue requirement from the 2002 test year (a $7.832 milion decrease in Idaho). Tr. at 270-
277; Tr. at 167-168.
Staff witness Sterling agrees that it is appropriate to pro form the normalized 2002
test year power supply expènses to the period of September 1, 2004 through August 1, 2005.
Fifty-two of the adjustments are to test year expenses; 15 adjustments are to test year revenues.
Exh. 128. Staff reviewed information related to the underlying contracts including some
contracts and Company workpapers and excerpts. Sterling concludes that the power supply
adjustments proposed by Avista are reasonably known and measurable. Sterling also concludes
that the adjustments are based strctly on test year loads and are independent of futue retail load
conditions. Staf recommends approval of the Company's power supply adjustments. Tr. at
1194-1204.
The Commission has reviewed the record and is satisfied that the pro forma
adjustments to power supply are proper.
3. Class Revenue Allocations
Accepting the Cost of Servce results as a starng point, the Commission must
determine the appropriate revenue requirement to be recovered in the rates of the different
customer classes. In doing so we strive to achieve an equitable apportionment of the revenue
requirement among the customer classes. The closer customer classes are moved to full cost of
service the fairer the rates that are set. In this case A vista's COS study indicates that Schedule 1
residential customers and Schedule 25 Extra Large General Serce customers are receiving
substantial subsidies from all remaining customer classes. Tr. at 321.
Although cost of service studies are not precise, we find it is important that cross
subsidies among customer classes be miniized. We find it reasonable in this case that all
customer classes be moved to within 10% of full cost of servce; no class less than 90%, no class
greater than 110%. See Appendix E.
4. Rate Design and Tarif Issues
A vista proposes a number of changes to rate design for the customer classes,
including increasing the fixed customer charge for residential customers. The Company
proposes a declining tail block for Schedule 11 customers to preserve class identity and revenue
responsibility and to discourge customer migration between classes. The Company also
proposes to increase energy charges for every customer class in order to generate thè authorized
ORDER NO. 29602 32
revenue requirement. This section of the Order addresses each customer class and the changes
proposed.
A. Residential Service (Schedule 1)
A vista proposes to increase the basic customer or minimum monthly charge for
residential customers from $4.00 to $5.00. The customer charge is a fixed component in rates
that recovers a portion of the cost required to serve a customer. The Company recommends that
the remaining revenue requirement be recovered though an equal increase to both energy
blocks. Tr. at 782.
Staff recommends no increase in the $4.00 basic and minimum charges. Tr. at 1325.
Citing a Commission ruling in a recent Idaho Power rate case, Order No. 29502 at 53, Staff
witness Schune testified that the basic charge should be based on the direct cost of meter
reading and biling and should not include any fixed plant cost. The monthly cost associated
with meter reading and biling for Avista is $2.62 for residential customers. The 25% increase
in the basic charge recommended by the Company, Staff contends, would have a
disproportionate affect on customers with low usage. Tr. at 1326-1327. Staff recommends that
the two-block energy rate continue to be priced with a higher second block rate for usage in
excess of 600 kWh (month). Staff recommends an average overall increase in base rates of
18.8% for Schedule 1. Tr. at 1325-1326.
On rebuttal A vista proposes a revised rate spread that would provide an identical
increase in rates for each of the two energy blocks. If the proposed increase in the monthly
basic charge is not approved, Avista proposes that a higher percentage increase be applied to the
first block rate. The Company argues that an increase to the basic charge is appropriate to
recover the costs associated with the plant that is on the customer's propert and dedicated to
serve that customer. Tr. at 818-819.
The Commission is unwiling to dampen the incentive for customers to conserve
energy. For the residential customer that incentive is generally a price signal and the ability to
control the total bil amount. We find that the present customer charge for residential customers
is suffcient to provide the Company with recovery, of those costs that are directly attributed to
the customer taking service. We find that those charges are related to meter reading and
customer biling costs, in this case approximately $2.62/residential customer. While we are not
inclined to increase the charge; neither do we find a compellng reason to decrease it. We also
ORDER NO. 29602 33
approve an increase in the inverted block energy rates that recover the class revenue requirement
and use the ratio between blocks proposed by Staff.
B. General Service (Schedules 11 and 12)
Avista proposes adding an additional energy usage block that would provide a lower
energy rate for usage in excess of 3650 kWh per month than for usage below that amount
because, under present rates, customers whose monthly peak demand exceeds 20 kW are biled
at a higher average amount per kWh even though these high load factor customers cost less to
serve on a per kWh basis. No increase to the customer or demand charge for monthly peak
demand in excess of20 kW is proposed. Tr. at 783-785.
Having both demand-metered and non-demand metered customers on a demand
schedule, Staff contends, is the real problem that the Company is attempting to address with a
declining tail-block. This is because higher use customers effectively pay more per kWh
because Avista does not bil the first 20 kW. Although opposed to Avista's proposed declining
block rates, Staff recommends acceptance in this case with the requirement that Avista be
directed to gather additional information só that the Company can provide a proposal in its next
rate case to: (1) divide Schedule 11 into two separate schedules, one demand metered and one
not; (2) eliminate declining block rates in Schedules 11, 21 and 25; and (3) implement time of
use (TOU) rates wherever practicaL. Staff recommends an average overall increase in base rates
of 11.4% for General Service Schedules 11 and 12. Staf recommends no change in the basic
charge, the minimum charge, or the demand charge. Tr. at 1319; 1327-1329.
On rebuttal the Company committed to conduct a study to split the schedule prior to
its next general filing and to assess whether Staffs proposal should be implemented. Tr. at 819-
820.
The Commission agrees with Staff that demand metered and non-demand metered
customers should be separated to allow for a more appropriate biling of demand and energy.
However, we recognize that the information necessar to make such a separation is currently
unavailable. We.therefore direct the Company to gather the required information and submit its
findings to the Commission as par of its next general rate case. We accept the Company and
Staff proposal to move to two block declining energy rates. Our rates recover the class revenue
requirement and incorporate the ratio between blocks proposed by the Staff.
ORDER NO. 29602 34
C. Large General Service (Schedules 21 and 22)
A vista proposes adding an energy usage rate block to Schedules 21 and 22 so that
the larger customers would pay a lower incremental energy rate for usage beyond 250,000
kWhmonth than for usage below that amount. The Company is proposing that the base tarff
rates be the same for usage over 250,000 kWh under Schedule 21 and for usage under 500,000
kWh under Schedule 25. Approximately 1,800 customers take service under Schedule 21.
Customers served under the schedule can have a monthly demand anywhere from 50 kW up to
2500 kW, the minimum level required for service under Schedule 25. Generally, larger use
customers under the schedule are less costly to serve than smaller use customers on a per kWh
basis. Several Schedule 21 customers have a higher load factor than many customers served
under Schedule 25 - yet they pay an average energy rate under Schedule 21 that is presently up
to 50% higher. Because of the present rate differential between Schedules 21 and 25, a
customer switching from Schedule 21 to 25 can see a lower anual energy bil well in excess of
$100,000, that represents a revenue/margin loss to the Company until corrected in a general rate
case. The Company reports that two of the 15 customers presently served under Schedule 25
switched from Schedule 21 in 2003. The Company proposes to increase the minimum demand
charge from $225 to $250, and increase the demand charge for kW over 50/month from $2.75 to
$3.00. Tr. at 785-789.
Staf recommends that Avista's proposal for the second block energy rate and for
increases to the demand charges be accepted. Staff recommends' that A vista be directed to
develop additional information before the next rate case assessing the economic impact of the
second block and justifying the continued use of a declining block energy charge. Tr. at 13 1 9;
1329-1330. Staff proposes an overall increase in base rates of 12.9% for Schedules 21 and 22.
The Commission accepts the demand charge as supported by both the Company and
Staff. We also accept a second block energy rate with the caveat that the Company further
justify a declining block rate before the next rate case. Finally, we establish the energy rates to
achieve the allocated revenue requirements with the Staff proposed ratio between first and
second block energy rates.
D. Extra Large General Service (Schedule 25)
The Company proposes a declining block energy charge whereby the Schedule's
larger customers would pay a lower incremental energy rate for usage beyond 500,000
ORDER NO. 29602 35
kWh/month, than for usage below that amount. The Company proposes to increase the
minimum demand charge from $7,500 to $9,000, and to increase the demand charge for kva
over 3,000/month from $2.25 to $2.75 per kva. Tr. at 788-789.
Avista includes Potlatch's Lewiston facilty in this Schedule but proposes changes to
the rate strcture so that Potlatch will pay an average rate per kWh that is lower than the average
rate(s) paid by other Schedule 25 customers. Tr. at 769; 780; 785-794.
Staff recommends that A vista's proposal for the declining second block energy rate
and for increases to the demand charges be accepted. Staff recommends that Avista be directed
to demonstrate in its next rate case that the Schedule 25 tail-block rate exceed the Company's
varable costs and provides a contrbution to the Company's fixed costs. Staff recommends an
overall increase inbase rates of20% for Schedule 25, with Potlatch receiving a 14.9% increase.
Tr. at 1319; 1330-1331.
Coeur Silver recommends that Schedule 25 customers be given the average
jursdictional increase. By way of critique, Coeur Silver recommends that Avista should be
directly assigning as opposed to allocating distrbution plant to Schedule 25 customers with
identifiable primar plant. Coeur Silver also recommends that rates be established that better
reflect load factor differences and thus cost causation. After Potlatch-Lewiston, Coeur Silver
contends that it is the next largest customer in Schedule 25 and has a significantly higher load
factor than the others. Those customers with a high load factor, it contends, should be rewarded
with lower rates. Coeur Silver recommends that the Commission (1) increase the demand
charge and lower the energy charge(s), or (2) develop a declining block energy rate that is load.
factor dependent (i.e., the first so many kWh per kW are priced at one rate while usage above
that level is priced at a lower rate). Although Coeur Silver has no preference as to which
method should be adopted, it suggests that the Commission target a ratio of demand to energy
charges of at least 120. Tr. at 500-501; 508-513.
Based on the significant increase in the present rate of retu for Schedule 25 that
results from the revised allocation of common and distrbution costs, A vista on rebuttal proposes
to reduce the original proposed rate increase. The first block energy rate would be decreased
and the second block increased. The reduction in the proposed increase for Schedule 25 is offset
by an additional increase to Residential Schedule 1. Tr. at 814-815; 818.
ORDER NO. 29602 36
Coeur Silver is troubled by Staff comments regarding the declining block and
though it welcomes the development of additional data, it does not believe that its intended
purose should be the elimination of the declining block rates. Tr. at 520. Coeur Silver dislikes
Stafs rate design because in spite of the inclusion of a declining block energy rate, it reduces
rates too little for higher load factor usage. Yankel proposes a rate design that better rewards
high load factor customers. Instead of $9,000 for the first 3,000 kW and $2.75 per kW for each
additional kW, Yankel proposes the initial 3000 kW be priced at $10,500 and that each
additional kW be priced at $3.25 per kW - similar to Idaho Power's rate. Tr. at 520-523.
Potlatch on rebuttal expresses support in principle for Coeur Silver's proposal to
directly assign primary facilties costs to Schedule 25 customers. Peseau is convinced that all
cost of service models - including his own - significantly overstate Schedule 25's cost of
service. Tr. at 962-963.
The Commission hereby adopts the increase in demand charges as proposed by the
Company and accepted by Staf. We also approve the creation of a second block energy rate
and establish energy rates that achieve the revenue requirement for the class while maintaining
the Staff proposed first and second block rate differential ratios, However, we find the
testimony of Potlatch and Coeur Silver persuasive regarding the make up of Schedule 25. We
believe it is not appropriate to continue to include Potlatch as a customer in Schedule 25 and we
therefore establish a separate stand alone schedule for Potlatch as discussed more fully in the
following section.
E. Potlatch's Lewiston Plant
On Januar 15,2004, in Order No. 29418, this Commission approved a new Power
Purchase and Sale Agreement (Agreement) between Avista and Potlatch. The Agreement is for
a 10-year term, beginning July 1, 2003 and ending June 30, 2013. As the sole purchaser of
Potlatch's generation at the plant, Avista pays Potlatch $42.92 per megawatt-hour for up to
543,120 megawatt-hours (62 average megawatts) generated by Potlatch durng each "Operating
Year" (July 1 through June 30) of the Agreement. This amount is equivalent to 62 average
megawatts and is referred to in the Agreement as the "Base Generation Amount." There are
special provisions in the Agreement for the purchase of additional amounts generated by
Potlatch in excess of the Base Generation Amount. A vista wil serve Potlatch's entire load
requirements at the Lewiston Plant, approximately 100 average megawatts, under its Extra
ORDER NO. 29602 37
Large General Service Schedule 25 rates, including the present Power Cost Adjustment (PCA)
surcharge and all other applicable rate adjustments, unless the Commission issues an Order in
the future authorizing different biling rates. Nothing in the Agreement prejudices either
Avista's or Potlatch's right to propose, or the Commission to order in future rate proceedings,
that Avista's service to Potlatch should be priced at rates other than Schedule 25. Tr. at 790-
791.
Avista is proposing that Potlatch continue to be sered under Schedule 25, however,
the Company is proposing changes to the present Schedule 25 rate strcture that wil result in
Potlatch paying a lower average rate per kWh than the average rate(s) paid by other Schedule 25
customers. Tr. at 769; 785-794. The Company is proposing a two-tier declining block energy
rate strctue for Schedule 25, as compared to the present single energy rate for all usage under
the Schedule. Tr. at 791. Because of the magnitude of Potlatch's load requirement, over 99% of
their 2002 energy usage would be priced at the lower second block rate. For all other Schedule
25 customers in total, only 72% of their usage is priced at the lower second block rate.
Additionally, Potlatch's load factor is substantially higher than other Schedule 25 customers.
Tr. at 792.
Potlatch contends that the Avista and Potlatch power supply agreement is a unique
contract that governs Avista's service to only one customer - the Potlatch Lewiston facility. In
that agreement, the paries agreed to the temporar use of Schedule 25 rates for service to the
facility, pending the next rate case. But Potlatch did not agree to become a Schedule 25
customer. It has always been a "special contract customer." Potlatch recommends rejection of
Avista's proposal to include Potlatch's Lewiston facility in Schedule 25 because Potlatch is
three times the size of the entire Schedule 25 class and should have its own tarff as a special
contract customer. Tr. at 938-939.
Peseau's recommendation to create a separate rate schedule for Potlatch's Lewiston
facilty, the Company concedes on rebuttal, has merit, especially as rates are moved closer to the
cost of providing service in the futue. If the Commission creates a separate rate schedule for
Potlatch, Avista proposes that the original proposed energy rates for Schedule 25 be reduced by
a uniform percentage to yield the revised overall increase for the Schedule. Tr. at 821-822.
ORDER NO. 29602 38
Coeur Silver on rebuttal contends that Potlatch-Lewiston should not be included in
Schedule 25 rates because no other Schedule 25 customers have load characteristics that are
remotely similar. Tr. at 520.
As indicated in our Schedule 25 discussion, the Commission finds it reasonable to
establish a separate stand alone service schedule for Potlatch's Lewiston facilty. As stated by
witness Peseau, Potlatch is thee times larger than all other Schedule 25 customers combined.
We believe establishing a separate schedule for Potlatch wil result in rates for Potlatch and
Schedule 25 that more accurately reflect cost of service. The Commission hereby approves
demand rates for Potlatch equal to those established in Schedule 25 but establishes a single
block energy rate that generates the Potlatch revenue requirement.
F. Pumping Service (Schedules 31 and 32)
A vista proposed that an increase be applied to the present energy blocks of pumping servce
schedules on an equal cents per kWh basis. Tr. at 789-790. Staff agrees with the Company that
all of the proposed increases to the pumping class should be applied to the energy rate. The
basic charge under both Company and Staff proposals would remain at $6.00. Staff
recommends that Schedule 31 and 32 base rates be increased by 13.5% Tr. at 1331.
The Commission agrees that the basic charge for service Schedules 31 and 32 should
not be changed. We increase the declining block energy rates in the ratio proposed by Staff.
G. Street and Area Lighting (Schedules 41-49)
A vista proposes to increase all present street and area light rates on an equal percentage basis.
Tr. at 790. Staff recommended a unform increase to lighting customers and recommends that
Schedule 41-49 base rates be increase by 17.2%. Tr. at 1332.
The Commission approves a uniform increase to Street and Area Lighting schedules
and increases rates in the ratio proposed by Staff.
Electric Rates
The electrc rates we approve as just and reasonable are set out in attached Appendix
A. Idaho Code § 61-502. Base electric rates increase by $24,716,000 while PCA rates decrease
by $20,337,000 and DSM rates decrease by $1,197,000. This results in a net increase of
$3,182,459 or 1.9%. The authorized electrc revenue to be recovered in rates including
residential exchange credit, Centralia credit, PCA surcharge and DSM rider is $175,029,459 for
a total average rate of 5.60 cents or 1.9% increase. The increase for an electrc residential
ORDER NO. 29602 39,
customer using an average of 941 kWhs per month is $4.01, or a 7.1% increase in their electrc
bil.
POWER COST ADJUSTMENT (PCA) ISSUES
1. Deal'~" and Deal "B" (peA issue)
In Avista PCA Order No. 29377, Case No. A VU-E-03-6, the Commission deferred
to this rate case a PCA recovery decision regarding the Company's acquisition and later sale at a
loss of natural gas to fuel the Coyote Springs 2 (CS2) combined cycle combustion turbine or
other less effcient Company generation resources. During the first half of 2001 Avista
experienced a combination oflow water conditions and high market prices. Tr. at 551. Avista
entered into a series of contracts, purchases and financial swaps, beginning in March 2001 to
secure gas and gas transportation, i.e., Deal A and Deal B. CS2 was initially scheduled for
testing in early 2002 and was expected to be commercially available in July 2002.
The first gas supply contract (Deal A) was to be delivered November 1, 2001
through November 1, 2004. Deal A consists of two transactions of 10,000 dthday each, for a
36-month delivery term, that were entered into for the purose of hedging or fixing, the natural
gas price for the period November 1, 2001 though October 31, 2004. Tr. at 564. One
transaction was entered into on April 11,2001 at a price of $6.75/dth and the second transaction
was entered into on May 2, 2001 at a price of$6.50/dth. Tr. at 564. The price for October 2004
gas was locked-in for thee and one-half years into the future. Exh. 139, p. 7. The system net
loss attrbuted to Deal A gas is $47,936,000 though May 31,2004.
The second gas supply contract (Deal B) was for delivery to begin June 1,2002 and
continue through October 31, 2003. Deal B consists of two hedge transactions of 10,000
dth/day each, for the 17 -month delivery term June 2002 through October 2003. One transaction
was entered into on April 10, 2001 and another transaction on May 10, 2001 at prices of
$6.50/dth and $5.35/dth, respectively. Tr. at 565. The October 2003 price was locked-in two
and one-half years into the future. Exh. 139, p. 7. The system net loss attrbuted to Deal B gas
is $21,755,640 through May 31,2004.
In March 2001, Avista Energy secured a physical supply of natural gas for CS2. Tr.
at 572, 573; 609, 610. The purchase price, however, was not fixed but was index based. Avista
maintains that the purchase of firm indexed based natural gas satisfied the fuel requirement for
CS2 project financing. Tr. at 571.
ORDER NO. 29602 40
The Deal A and Deal B transactions fixed the price for 84% of the gas purchased at
index based prcies. Tr. at 574. The Deal A and B transactions were financial hedge transactions
as opposed to physical transactions. A financial gas transaction as explained at hearng involves
no actual exchange of physical gas. Instead, a financial deal is agreed upon by a buyer and
seller who take "price positions." The buyer bets that futue gas prices will rise, while the seller
bets that future gas prices wil falL. Depending upon the future monthly movement of gas prices;
the loser, or the counter-pary on the wrong side of the bet writes a monthly check or "settles"
with the other pary. BP aid Mirant were the counter-paries on Deal A. Tr. at 909-910. Avista
Energy was the counter-pary on Deal B.
A vista argues that the purchases were necessar because A vista had an electrc
resource deficit, hedge prices compared favorably to forward prices, and that the purchases were
reasonable given energy crisis market conditions. Tf. at 540-541; 564-591. It is also worth
noting, the Company states, that prior to the acquisition of CS2, the Company's gas-fired units
were all peaking units. The ownership of CS2, a base-load gas-fired project, brings with it a
greater need to enter into hedge transactions. Tr. at 615. The Company maintains that at the
time the natural gas was purchased, it was anticipated that when the gas was to be delivered CS2
would be operational and more economical to operate than making market energy purchases.
However, as the Company states, as with all forward transactions the market conditions at the
time of delivery wil undoubtedly be different from what they were at the time the transactions
were executed. Tr. at 585. As it tu out at the time the gas was scheduled for delivery CS2
was not operational nor was it economical to use the gas purchased for CS2 at the Company's
other facilities. Instead Avista simply purchased its power needs on the electrc market and sold
the gas back into the gas market at a loss because gas prices had declined. Tr. at 1261.
Taking simultaneous and opposite positions on the same Deal B financial hedge
transaction, Potlatch contends, canot be deemed prudent. Tr. at 917. Potlatch contends the
energy trader at Avista who was buyig the fixed-price hedge on behalf of Avista Utilties was
the same energy trader who was sellng it on behalf of Avista Energy. The length of the Deal A
and B hedges based on Potlatch's investigation appear to be unprecedented, outside the
Company's normal business practice, and seemingly unmatched in the industry. Tr. at 918-919.
Avista disputes Potlatch's contention that the Deal A and B transactions were of unprecedented
length. Tr. at 615-616.
ORDER NO. 29602 41
Potlatch contends that the only thing that made simultaneously taking opposite sides
of the bet on the Deal B swap an attractive transaction for Avista Corp. was that the PCA
mechansm insulated the shareholders of the parent company by passing though to ratepayers
the excess of the locked in hedged natural gas prices over and above the actual market prices
that existed at the time. Tr. at 910-91 i. Avista Energy's role as a broker for the utility division,
Potlatch contends, placed it in a fiduciar position to disclose that it considered Deal B to be a
bad deal for Avista Utilities. Tr. at 912. Speaking to the roles and responsibilities of Avista
Utilities and Avista Energy in Deal A, Avista Utilties states that it requested that Avista Energy
enter into the Deal B hedge transactions due to the non-standard 17-month term. Also there
were limited counterparies wiling to transact with Avista Utilities. Tr. at 618.
The high costs associated with Deals A and B, Potlatch contends, are the result of
imprudent decisions and self-dealing between Avista Corp. and Avista Energy that resulted in
more than $62 milion in excess gas costs on a system-wide basis. These unprecedented long-
term financial swaps were never "in the money" nor did they allow for physical delivery. Both
deals ($62.4 milion) should be disallowed for imprudence, Potlatch contends, but at a
minimum, Deal B ($18.3 milion) must be disallowed due to self-dealing. Tr. at 908-922.
Potlatch contends that the Company's normal practice (for its retail natural gas
business) was to hedge for periods approximately six months prior to a season (November-
March or April-October). For example, May 1,2001 prices were used for the November 2001-
March 2002 season. Exh. 203. If Avista had hedged for Deal A in the same maner it was
hedging other natural gas purchases in the same time frame, Deal A gas costs would have been
$30,365,240 lower. Tr. at 921; Exh. 203. Potlatch contends that should the Commission not
disallow the entirety of the Deal A costs, it should disallow the $30.4 millon of Deal A costs the
Company would not have lost had it engaged in normal hedging practices, adjusted for both the
Idaho jurisdiction allocation as well as PCA sharng. Tr. at 921-922. Avista responds that it is
important that the purchasing practice and hedging strategies for the Company's natual gas
distribution business not be confused with the purchasing practices and strategies of the
vertically integrated electric utilty. Tr. at 613. The Company's natural gas purchasing practices
and hedging strategies, it states, were developed in consultation with the Commission Staffs in
Idaho, Washington and Oregon, both through informal communications, though the natual gas
IR process and through the current Benchmark Mechansm. Tr. at 614.
ORDER NO. 29602 42
Staff recommends that $6,496,669 of Idaho net losses from Deal "B" gas purchases
to ru Coyote Springs 2 should be denied because Avista violated risk policy provisions (in
excess of the 150MW long limit) in the Company's Energy Resources Risk Policy and
transacted with an unregulated affiliate without appropriate safeguards (a proper code of conduct
or a requirement of lower- of-cost or market pricing). Tr. at 1262; Exh. 141; Tr. at 1274. Staff
contends that its Deal B proposal amounts to giving the customer the better deal, cost or market.
Tr. at 1270. Staf proposes to leave the $8,677,766 in Idaho Deal "A" losses in the PCA. Staf
contends that Deal A hedges were not done with an A vista affliate and that Deal A did not put
Avista over the long limit contained in its Risk Management Policy. Tr. at 1270. Potlatch notes
however that Deal A and B were both financial only - and not the physical index-priced gas
purchases. Potlatch contends that its irrelevant that the physical purchases were, or were not,
over some designated volumetrc or long limit. Tr. at 955.
Both Deal A and B purchases, Staff states, were ongoing at the 18-month short-term
risk policy transition point in October 2002. Tr. at 1264. In contrast to Staffs near term risk
policy point of view, Avista analyzes this issue with a long-term (greater than 18 months)
resource planing point of view. Staff argues the short-term risk policy should be used because
the long-term IR does not include gas acquisition criteria and the load balance was not
consistent with the long-term acquisition process. Staff contends that the Company took
unusual risks for both Avista Energy and its customers when hedging the price for the length of
the Deal B contracts. Avista Energy's risk was that gas prices would go up and that when it
needed gas for delivery it would be more costly. The utilty was exposed to several types of
risk. It had the risk that gas prices would both go down and gas would cost less when it was
needed. The utility also had the risk that electrc and gas prices would go down such that the
gas could not be economically used to produce electricity. Because the deal with Avista Energy
was not provided to Avista Utilties at cost, Avista Energy had the opportunity to profit by
keeping the difference between the actual cost and fixed price of gas sold to the utilty. In the
end A vista Energy profited and the regulated utilty is proposing that its customers pay 90% of
the costs. Because Avista did not enter into similar long-term gas purchases for its gas
customers, Staff contends that it was inconsistent and highly speculative to do so for electric
customers. Tr. at 1260-1274; Exh. 140.
ORDER NO. 29602 43
A vista maintains that the costs associated with the Deal A and Deal B contracts were
prudent given the information and circumstances at the time and should ultimately be
recoverable through the Idaho PCA mechanism. Tr. at 586. The Company maitais that the
transactions were reasonable and consistent with the Company's long-term planing criteria and
risk policy. The duration of these purchases was not of an unusual length to cover open power
positions. It cannot be assumed Avista Energy profited by $18 milion from the Deal B
transactions as suggested by Peseau. If the Commission determnes par of the 'Deal B
transactions should be disallowed, the Company proposes two alternative methodologies to
calculate disallowance ($2.7 milion or $4 milion v. Stafs $6.5 milion). Tr. at 193-194; 602;
609-631.
Potlatch on rebuttal maintains that Staff should not have accepted the Deal A excess
gas costs because Hessing's compellng argument to disallow Deal B gas costs applies to Deal A
as well. Both transactions lack cost-benefit analyses, were irregular, and were speculative. Tr.
at 953-957.
Commission Findings
Before the Commission can address the Deal A and B losses we must first consider a
threshold issue, the propriety of the Avista Energy transactions themselves. Relevant to our
consideration is the affliate relationship that exists between A vista Energy and A vista Utilities.
The Commission has authorized Avista Energy to act as an agent for Avista Utilities gas. As a
condition of such approval a benchmark mechanism and agency agreement were put in place.
We established some sideboards, a code of conduct and rules that established transparency and
governed the transactions performed' by A vista Energy on behalf of A vista Utilties. Ths
operational infrastrcture was put in place to provide an auditable paper trail and to insulate
Avista Utilities and its customers from the risk associated with the Company's non-regulated
subsidiary operations.
A vista Energy had authorization by this Commission to act on behalf of A vista
Utilties-gas, not on behalf of Avista Utilities-electrc. The record reflects that there was an
understanding between the Company and Commission Staff that there would be no transactions
between Avista Utilities-electrc and Avista Energy. Tr. at 54, 55. A protocol had not been
established for such transactions. When asked whether a similar protocol was followed for
Avista Utilities-electric, the Company's policy witness Morrs stated that Avista follows FERC
ORDER NO. 29602 44
guidelines with respect to its electric operations. Tr. at 54. He contends that the Company also
follows its Risk Management P~licy. Tr. at 58. Durng the time of these transactions the
Company was in a severe liquidity crisis. Because of its financial troubles it was also having
difficulty doing business with other counterparties. The Company made a choice at that time
that it was in the best interest of its customers to be able to lock-in a $38 to $48 product. The
Company preceded to hedge and lock-in a price at market. Tr. at 58.
A vista may have had the best intentions. The best intentions however canot
overcome the perception that it also had a divided loyalty, an obligation to shareholders to
maximize profits and an obligation to treat its utility customers fairly. There was no protocol in
place for electrc side gas procurement. In choosing to act without regulatory approval the
Company assumed the risk of loss. We have reviewed the documentation provided by the
Company. Tr. at 590; Exh. 7. The paper trail that the Commission and our auditing Staff rely
on for gas benchmark transactions was not present for Deal A and B. The appearance at hearng
was that the justification for the transactions was cobbled together after the fact. Other than a
notational entr that the financial hedges were required by lenders to obtain constrction
financing (financing that was ultimately not secured), there was no lender documentation to
support such a requirement.
Regarding Deal B hedge losses, we find absolutely no justification for authorizing
PCA recovery. Avista Energy assumed a financial position directly at odds with Avista
Utilities. At a minimum it was highly iregular. Certainly it was speculative. The Company
was operating outside its own risk management policy. When it chose to act without regulatory
approval of an affiliate methodology, it was risking its own money, not its ratepayers'.
Regarding Deal A hedge losses, we find that many' of the reasons justifying our
disallowance of Deal B are also present for Deal A. However, there are differences that create a
basis for different treatment. Among those differences are the counterparies themselves, neither
of whom were affiliates of Avista Utilities, and Staffs analysis that demonstrates that these
transactions, had an operating protocol been in place, would have been viewed by Staff to be
withi the Company's established risk management limits.
This Commission acts knowing that it's decisions may have financial repercussions
in the lending community and on Wall Street. At the same time we send a signal to the
regulated utility and its parent that affliate transactions between regulated and unegulated
ORDER NO. 29602 45
entities must be guided by protocol. In failing to put such a protocol in place, the Company
acted at its periL. We find that as to Deal A losses there should be a sharng of risk between
ratepayers and shareholders. We find a reasonable disallowance to be one-thrd of the total
losses.
As developed at hearng in Exhibit 141, Idao PCA deferral balance at the end of
May 2004 was $26,261,334. Deal A losses through May amounted to $47,936,010 on a system
basis; $15,905,167 on an Idaho jursdictional basis. With 90/10 PCA sharng the Idaho PCA
amount related to Deal A losses is $14,314,651. Of that amount $5,636,885 was previously
authorized for PCA recovery (July 1 - June 2002). Based on our consideration ofthe record and
Deal A findings, the Commission finds it reasonable to exclude or disallow one-third of the
Idaho system Deal A losses, or $4,771,550. Our mathematical calculation of the Idaho
jurisdictional disallowance is based on the total Deal A losses through May 2004. This decision
wil also apply to Deal A losses after May 31, 2004 that otherwse may be in next year's PCA.
We also direct A vista to work with Staff to make the appropriate interest adjustments to the
PCA deferral account. The Commission disallows the losses associated with Deal B, in the
amount of $6,496,669.
2. Updated PCA Components
Avista's electrc Schedule 66 Power Cost Adjustment (PCA) is a rate adjustment
mechanism that anually adjusts a portion of customer rates to allow A vista to recover or refud
90% of the amount above or below the base power supply costs established in a general rate
case and included in the revenue requirement and base rates for the customer classes.
The new authorized level of annual power supply expense proposed by the Company
is $71,456,998. This is the sum of Accounts 555 (Purchased Power), 501 (Thermal Fuel), and
547 (Fuel) less Account 447 (Sale for Resale). Base power supply costs are updated in general
rate cases for use in the PCA. The Company also proposes to update the load change revenue
adjustment multiplier (average anual variable power supply cost of meeting new load as
determined from the Company power supply model) from 21.23 $/MWh to 36.38 $/MWh. Ir. at
279-280.
Staff witness Hessing agrees with the Company's calculations and supports Avista's
base power supply amounts and update to the load change revenue adjustment multiplier. Tf. at
1274-1276. The Commission approves these proposed updates.
ORDER NO. 29602 46
3. PCA Rate Recovery
Avista's witness, Mr. Hirschkorn, proposes to reduce PCA rates in this case to
recover one-half of the estimated Idaho PCA deferred balance each year for two years. Tr. at
767; 779; 820. Staff witness Hessing supports the Company's proposal to calculate rates to
recover the remaining PCA balance over two years but recommends use of an actual known end
of month balance instead of an estimated balance. Tr. at 1276-1277.
With respect to PCA issues deferred to this rate case in Order No. 29377 regarding
Coyote Springs 2 (CS2), the Commission notes an audited PCA deferral account balance May
31, 2004 of $26,261,334 (reference Case No. A VU-E-04-3); disallows CS2 Deal B losses of
$6,496,669; and disallows $4,771,550 of Deal A losses for a net PCA account balance total of
$14,993,115. The Commission approves the Company proposal to recover the remaining PCA
deferral balance over a two-year period. The resultant annual PCA recovery is $7,496,558,
subject to anual PCA review and adjustment. The Commission authorizes changing in the
future from the current uniform percentage recovery method to a recovery method based on
energy consumption.
The Commission in this Order also approves the assignent and recovery from the
residential class through the PCA of authorized CAP AI intervenor fuding in the amount of
$12,622.75.
4. PCA Rate Design
A vista witness Hirschkorn recommends recovery of the PCA surcharge by a unifonn
percentage allocation to each customer class and a single rate for all energy usage within the
class (except for residential block rates). Tr. at 780.
Staff witness Hessing agreed with the Company proposal while there is a remaining
deferral balance. However, he proposes that once the current PCA deferral balance is
eliminated, PCA costs be recovered from ratepayers on a uniform cents per kWh basis rather
than a uniform percentage of revenue by class. The PCA rate would then be the same for all
schedules except lighting. Staff advocates this as a more appropriate way to collect varable
energy costs. Tr. at 1277-1279.
A vista on rebuttal agrees that from a cost causation viewpoint, an equal cents per
kWh application to all schedules is more appropriate than the present PCA methodology. The
ORDER NO. 29602 47
Company also agrees that the change in methodology should not occur until the present deferral
balance is fully recovered. Tr. at 821.
Potlatch witness Peseau opposes Staffs proposal on both theoretical and practical
grounds and recommends that it be rejected or modified. Potlatch contends that power supply
costs are not lOO% energy or kWh-based and should not therefore be spread on an energy-only
basis. There is both a fixed or capacity component and a seasonal differential cost component to
power supply costs, he contends, that makes spreading balances on a flat, equal kWh basis
inaccurate. A cents per kWh recovery method, Peseau contends, would expose high load factor
customers to greater volatility because the surcharge and rebates wil be greater than under the
curent system thus making business planing and management decisions more diffcult. Rate
increases can cause disruption and losses, he contends, that canot be recovered by
corresponding decreases in subsequent years. If Staff s proposal is adopted, Potlatch
recommends that the Commission "seasonalize" the cents/kWh recovery on a monthly or
quarerly basis in a maner similar to avoided costs rates. Tr. at 963-965.
The Commission finds that a cents per kWh recovery method for the PCA is
superior to the percentage basis curently used. While we recognze the difficulties pointed out
by Potlatch, we find the cents per kWh rate more equitable to all customers than the percentage
allocation. We recognize that the varable cost of energy fluctuates from year to year based on
the amount of energy consumed and should therefore be surcharged or credited on an equal
cents per kWh basis. We authorize the change to an equal cents per kWh when the present
deferral balance is eliminated. We reject Potlatch's proposal to seasonalize PCA recovery
amounts on a monthly or quarerly basis as being administratively burdensome and unecessary
to achieve fairness and equity.
OTHER ISSUES
1. After Hours Connection Fees
A vista witness Hirschkom proposes reconciling changes to non-recurg charges
for reconnection rates so there is only one set of charges that applies to any reconnect or service
tu-on situation. The proposed rate is $24 for reconnections occurrng durng normal business
ho~s and $48 for after-hours, plus $4.00 for each additional service connected at the same time.
Tr. at 811.
ORDER NO. 29602 48
Staff witness Parker recommends approval of Avista's proposed changes for: (1)
reconnection of seasonal gas customers, and (2) after-hours connection charges for both gas and
electric customers. Staff recommends, however, that the tariff provision allowing an additional
$4.00 charge to connect a second meter at the same location be eliminated. Tr. at 865.
Rebuttal witness Kopczynski was generally supportive of Staff positions while
noting that several issues are concurrently being reviewed in the Staff-hosted Best Practices
Task Force. Tr. at 258-264. The Company supports Stas proposal to eliminate the $4.00
reconnection of additional meters at the same premises. Tr. at 826.
The Commission based on its review supports the changes in reconnection and after-
hours connection fees agreed to by the Company and Staff. The Commission understands that
there wil not be a signficant net change in revenue.
2. Winter Payment Plan
Staff witness Parker recommends that Avista take steps to resolve its computer
programing issues so that a customer who has declared Moratorium eligibility can also
paricipate in the Winter Payment Plan. Staff also recommends that the Company improve its
communication with customers about the Winter Payment Plan and Moratorium. Tr. at 865.
On rebuttal Avista witness Kopczynski states that the Company's computer system
does in fact allow customers to be set up on both the Winter Payment Plan and the Idaho
Moratorium. The Company commits that all of its customer service representatives wil be
provided additional training by November 1,2004. Tr. at 258-260.
3. Telephone Call Center
In a 2002 Edison Electric Institute/American Gas Association (EElI AGA) study
cited by Staff witness Parker, the average service level (the percentage of calls answered within
a defined number of seconds) among the 62 reportng utilty companes was 73.8% of calls
answered in 32.3 seconds. Avista has recently set its intemal service level goal at answering
70!ó of incoming calls within 60 seconds. Staff recommends that Avista be encouraged to
answer 80% of calls within 30 seconds by Januar 2005 and significantly reduce the number of
abandoned calls per month. Tr. at 865.
A vista witness Kopczynski on rebuttal notes that in the past 18 months, A vista has
added 6.5 full time equivalent (FTE) positions to the Company's contact center and is improving
its response time. To meet Stafs recommendations, however, Kopczynski states, an additional
ORDER NO. 29602 49
nine full-time positions would be required. The need for flexible staffing means that 9 FTE
translates to approximately 13 new employees. Avista intends to add this additional contact
center staff in the next year and establish 80% of incoming calls answered in 30 seconds as a
target. This additional PTE complement would increase expense over that requested by the
Company's Application by $162,735 for Idaho and Avista believes it is appropriate to reflect
these additional costs in the Company's revenue requirement. Tr. at 260-263. As the Company
moves to an 80% answered-calls-in-30-seconds standard, it believes the number of customers
who hang up before they reach a contact representative (or abandoned calls) should be reduced.
Addressing Kopczynski's rebuttal testimony, Staff at hearing noted that the
Company failed to indicate that they have five PTE positions in customer service that are
currently vacant, and additionally, they have four FTE positions where the employees have been
reassigned. Also in the last year or so the Company has filled 6.5 FTEs. And so, to the extent
the Company has had all these positions vacant, Staff concludes that its not surprising that with
the call volumes increasing, servce levels and employee morale have declined. Even if the
Company fills the vacant PTEs immediately, Staff contends that it will take some time for them
to be trained. Staff recommends that the Company be given tie to improve service and to
explore some technology-based solutions designed to help improve service levels. Staff
recommends that the Company be directed to fie a report with the Commssion in July 2005
reporting on the prior 12 months and indicating what progress it has made in improving the
average service leveL. Tr. at 887, 888.
The Commission encourages the Company to improve its response time to customer
calls and to reduce the number of abandoned calls. We find that this issue should be addressed
by the Company and direct the Company to fie a status and progress report with the
Commission in July 2005 detailing the steps the Company has taken and implemented to
improve the average servce leveL. Until ths issue is more fully explored, we find no basis for
providing an increase in authorized revenue for additional Company FTEs.
4. Prudency of DSM Expenditures
When the Commission approved the Company's energy effciency programs in
1995, A vista committed to demonstrate the prudence of program expenØitues in futue general
rate cases. Avista witness Hirschkom requests that the Company's electric DSM expenditues
from Januar 1, 1999 though December 31,2003 be found to have been prudently incurred and
ORDER NO. 29602 50
gas DSM prudent from March 13, 1995 through December 31, 2003. Tr. at 808-810. Since
1995, the Company calculates that over 286 milion kWh (and 5.8 milion thenns) have been
saved through its energy effciency programs. Tr. at 809. A 15-year levelized utility cost per
saved kWh of 1.4 cents per kWh has been achieved. The levelized avoided cost during ths
same period has been 4.7 cents per kWh. Hirschkom also said the 15 year levelized cost per
saved thenn has averaged 14 cents per thenn. Tr. at 809. Staff witness Anderson offered two
corrections to Hirschkorn' s testimony. Anderson said that the prudency review of both gas and
electrcity DSM for this case should have ended October 31, 2003. Tr. at 844. Anderson also
said the average levelized cost of gas DSM savings was 25 cents per thenn, not 14 cents per
thenn. Tr. at 845. Avista did not rebut these corrections.
Avistacollects revenues for its DSM programs from surcharges. Currently tarff
Schedule 91 electrc surcharges amount to 1.95% of base revenues. The Company collected
about $2.7 milion in 2002. Staff witness Anderson finds Avista's DSM approach
conscientious, cost-effective, and reasonable. Tr. at 844-845.
The Commission finds that the DSM programs of A vista have been demonstrated to
be suc,cessfu1. Paricipating customers have benefited through lower bils and cost-effective
energy efficiency measures. Non-paricipants benefit from the Company's acquisition of low
cost resources. We find that the Company's DSM expenditues from January 1, 1999 though
October 31, 2003 to have been prudently incurred.
5. Advanced Meter Reading (AMR)
A vista apprises the Commission in ths case of its proposal to install AM devices
on all Idaho electrc and natual gas meters over a four-year perod commencing Januar 2005.
The Company estimates that its anual electrc net cost would increase $188,700. The
Company estimates a $63,000 decrease in anual gas costs over a IS-year period. Avista
requests that the estimated $16.3 millon AM project cost be capitalized as Constrction Work
in Progress (CWIP) until the entire project is completed and depreciation begins. Avista is not
proposing a change in rates in this fiing to pay for AMR. Tr. at 733-739; Tr. at 190.
Staff witness Anderson supports in principle the Company's proposal to install AMR
facilties without specific time of use (TOU) pricing facilties at this time. He noted that the
estimated $188,700 anual net cost increase equates to approximately a 7-cent increase on a $50
customer bil. He also noted that the estimated $63,000 anual net cost decrease to gas service
ORDER NO. 29602 51
equates to about a 7 cent decrease on a $57 customer bilL. Although Avista wil benefit from
AMR before completion of the entire four-year installation, Staff wants to promote
implementation and is not opposed to the requested deferred accounting treatment. Anderson
anticipates critical peak TOU pricing wil become cost-effective by about the time Avista
completes its AM project and that additional components necessary for such a pricing system
should begin to be installed at that time. Tr. at 851-854.
The Commission supports the Company's plans to install AMR and authorizes the
Company-requested deferral accounting treatment for its related investment. In doing so we
acknowledge and support Stafs TOU comments.
6. Intervenor Funding
The Commission approves CAP AI's Petition for Intervenor Funding in the requested
amount of$12,622.75. Reference Idaho Code § 61-617A. Our award is based on a fiding that
CAP AI's participation materially contributed to the Commission's decision, that the costs of
intervention are reasonable and would be a significant financial hardship for CAPAI ifno award
is given, that the recommendations made by CAP AI differed materially from Staffs case, and
that CAP AI's paricipation addressed issues of concern to residential and low income customers.
The award is to be recovered from residential customers through the Company's electrc PCA
mechanism.
AVISTA'S NATURAL GAS CASE
The Company in this general rate filing requested an overall Idaho natural gas base-
rate increase of $4,754,000 or 9.16%. Avista contends that a rate increase is needed because of
decreased therm usage and increased general business expenses. Tr. at 15-18; Tr. at 147; 180,
Exh. 15, p. 2 of 8. From 1999 to 2002, Idaho residential and small commercial customers
decreased their gas usage from an average of 82 therms per month to 73 therms per month, or
about 11 %. During this same time period the number of residential and small commercial
customers served in Idaho increased by 11 %, or about 5,800 customers. Tr. at 799.
Because A vista is a combined natural gas and electrc utilty many of the
Commission's findings regarding the Company's utility operations are generic in scope and to
the extent they have been discussed above wil not be repeated in this section of the Order. To
the extent they bear repeating for purposes of identifyg the revenue requirement effect it wil
only be referenced below in brief fashion.
ORDER NO. 29602 52
Specifically addressed above and not discussed below are the Commission's
decisions regarding Test Year, Capital Strcture, Cost of Debt, Return on Equity, and Rate of
Return. Also not discussed are the Commission's decisions regarding Reconnections and After-
Hour Connection Fees; Winter Payment Plan, LIWA Funding and Advanced Meter Reading.
Adjustments to Gas Test Year Revenues, Expenses and Rate Base
Once a test year is selected, adjustments are made to test year accounts and rate base
to reflect known and measurable changes so that test year totals accurately reflect anticipated
amounts for the futue period when rates wil be in effect. As indicated in our discussion of
electrc service, adjustments to test year accounts generally fall into three categories. 1)
nonnalizing adjustments made for unusual occurences, like one-time events or extreme weather
conditions, so they do not unduly affect the test year; 2) anualizing adjustments made for
events that occurred at some point in the test year to average their effect as if they had been in
existence during the entire year; and 3) known and measurable adjustments made to include
events that occur outside the test year but wil continue in the future to affect Company income
and expenses. Order No. 29505. This section of the Order addresses the proposed adjustment to
test year revenues, expenses and rate base associated with natural gas service.
Staff witness Stockton and Hars accepted Avista's proposed Standard Commission
Basis Adjustments except for the Company's gas inventory adjustment (Falkner Exh. 15, pp. 4-
6, columns c through 0) and also accepted the Company's Pro Forma Insurance Adjustment that
decreases net operating income by $131,000 (Falker Exh. 14, p. 7, column r). Tr. at 1097-
1098, 1135-1136.
The Company on rebuttal agreed to and incorporated into its Rebuttal Exh. 27, pages 8-9
the following Staff proposed adjustments to net operating income and/or rate base:
Net
Operating
Income
Adjustment Reason after Taxes Rate Base
Deferred Federal Appropriate deferred tax accounting
Income Tax treatment (2,639,000)
Labor (Exec.)Update estimates to actuals 2,000
Labor (Non-Exec.)Update estimates to actuals 6,000
Depreciation Synchronize depreciation between 28,000
states
ORDER NO. 29602 53
Corp. Fees Similar treatment for Idaho utilities-
split 50%/50%17,000
Misc. Exp.Similar to prior Commission treatment,
exclude contributions, dues, and
expenses benefiti,g affliates 71,000
Ad. Exp. Similar to prior Commission treatment,
exclude chartable contrbutions and
image advertising 6,000
Avista Foundation Correctly assigns expenses to affiliate 1,000
Actual Therm Usage Updated to actual 15,000
Schedule M Allocator Conforms to electrc system treatment 2,000
By accepting these uncontested adjustments the Company revises its requested gas revenue
increase to $4,061,000 or 7.82%. Avista Reb. Exh. 27, p. 2, Tr. at 218.
A. Agreed Upon Adjustments
After Avista fied its rebuttal testimony, Staff and Avista agreed to reduce Stafs
originally proposed Gas Inventory and Accounts Receivable Sale Program Fees Adjustments by
50%. Tr. at 1142-1143. These revised adjustments increase net operating income after taxes by
$29,000 and decrease rate base by $786,000. Tr. at 1142-1143.
1. Gas Inventory
Avista witness Falker adjusts rate base for the average of monthly average value of
gas stored at Jackson Prairie underground storage facilty and the Plymouth LNG Plant. The
Company adjustment increases Idaho rate base by $ 1,572,000. Tr. at 182.
Staff witness Stockton removed the Company's Pro Forma Gas Inventory
adjustment from rate base because Avista has a negative cash working capital and thus Staff
contends that it is not an appropriate rate base addition. Stafs adjustment decreases rate base
by $1,572,000 and decreases total revenue requirement by $227,000. Tr. at 1116; 1137; Tr. at
1099.
Avista on rebuttal contends that Staffs interpretation of its working capital analysis
is incorrect. The Company's working capital, it states, is actually positive, not negative. Also,
Star s classification of gas inventory in the working capital analysis excludes it from working
capitaL. The Company notes that the Commission has historically allowed gas inventory to be
included in rate base and recommends that it continue to do so in this case. Tr. at 219.
ORDER NO. 29602 54
Staff on rejoinder represents that Staff and Avista have agreed to reduce Stafs
adjustment by 50%. This amended adjustment decreases Idaho gas rate base by $786,000 and
the total revenue requirement by $114,000. Tr. at 1142.1143.
2. Accounts Receivable Program Fees
As per Staff witness Stockton Rejoinder, the Company and Staff agreed to an
amended adjustment increasing Idaho gas net operating income by $29,000 and decreasing the
total revenue requirement by $45,000 for the same reasons as described in the electrc section of
this Order. Tr. at 1141.1142.
3. Restate Debt Interest
Adoption of Staff adjustment increases the Idaho gas federal tax accrual by $36,000
and increases revenue requirement by $56,000. Tr. at 1107; Rev. Exh. 107. For furher detail
regarding the nature of the adjustment, please refer to the electrc section of this Order.
The following issues were discussed earlier in the electrc rate section and are treated
consistently with our findings there.
B. Disputed Issues (Resolved in Electric)
1. Pension Expense
Staff s proposed adjustment to gas pension expense to reflect the 2003 ERISA
required minimum contrbution increases Idaho gas net operating income by $137,000 and
decreases the Company's Idaho gas revenue requirement by $214,000. Tr. at 1101-1102; 1171.
1172. However, for the reasons discussed in the electrc section of this Order, the Commission
allows Avista recovery of $381,311 pension expense in its Idaho gas jurisdiction on the
evidence presented in this case. This results in an adjustment increasing Idaho net operating
income by $93,000.
2. Legal Expense
Adoption of Staff adjustment increases net operating income by $13,000 and reduces
Avista's revenue requirement by $20,000. Tr. at 1102-1103; 1173.
Summary of Adjustments to Gas Test Year Revenues, Expenses and Rate Base
Considering all the evidence presented, and including all adjustments, the
Commission finds just and reasonable Idaho jursdictional expenses for the 2002 test year in the
amount of $48,368,000, and Idaho jurisdictional operating revenues in the amount of
$52,575,000 for an operating incòme before federal income tax of $4,207,000. The afer tax
ORDER NO. 29602 55
¿
Idaho operating income is $3,402,000. Afer all adjustments, we find a 2002 total Idaho
junsdictional rate base amount of $59,653,000 to be just and reasonable. Appendix D to this
Order summarzes the Commission's findings on rate base and operating results for the test year.
Rate Base
Avista in Exhibit 15, p. 2 proposed a pro forma rate base of $63,078,000 for the
Idaho junsdiction. As we indicated in our prior Amended Interlocutory Order No. 29588 the
Commission approves as just and reasonable a gas pro forma rate base of $59,653,000. See
Appendix D.
Revenue Requirement
Curent revenue recovered in Idaho's gas base rates is $51,919,000. The
, Commission in this case appro~es a base revenue requirement of$55,230,000, an increase in gas
base rates of $3,311 ,000 or 6.38%. The resultant average base rates for sales therms is 81 cents
pertherm.
Calculation of Revenue Deficiency
Having determined the Idaho gas rate base, net operating income requirement, and
retur on common equity, we proceed to determine the Idaho revenue deficiency with the
following calculation:
Rate Base
Rate ofRetu
$59,653,000
9.250%
Net Operating Income Requirement
Operating Income
Income Deficiency
Conversion Factor
Revenue Requirement Deficiency
$5,518,000
$3,402,000
$2,116,000
.639
$3,311,000
The Commission approves a pro forma rate base of $59,653,000. See attached
Appendix D. The Commission approves additional natural gas revenues of $3,311,000 for a
total revenue requirement of $55,230,000, a 6.38% revenue increase.
ORDER NO. 29602 56
.
Gas Jurisdictional Separations, Weather Normalization and Cost of Service
1. Gas Jurisdictional Separations
Avista used the same jursdictional separation methodology approved by the
Commission in the Company's last natural gas rate case. This general methodology has been
approved for the Company in all of its other operating jursdictions. Staff witness Fuss accepts
Avista's Gas Jursdictional Separation Study using the four-factor methodology with one minor
adjustment. He used the four-factor allocator for Schedule "M" accounts instead of "allocator 5-
Actual Thenns Purchased." Stafr s adjustment reduces Idaho's share of taxes and increases the
Idaho gas net operating income by $1,888. Tr. at 1238-1242; Revised Exh. 107, p. 2. The
Commission accepts Avista's Gas Jursdictional Separation Study using the four-factor
methodology with Staff-proposed adjustments.
2. Weather Normalization
No change was made to the historical methodology used to calculate natural gas
weather sensitivity. Tr. at 328-329. Staff witness Sterling accepts Avista's gas weather
nonnalization perfonned as accurate and reasonable. Tr. at 1190; 1192-1194. The Commission
accepts Avista's weather nonnalization as accurate and reasonable.
3. Gas Cost of Service
Avista used the same Base Case (aka "Peak Credit") Cost of Service methodology
(with minor modifications) approved in the Company's last natural gas rate case. The proposed
rate spread of the increase results in approximately a one-half movement to the cost of service
for each schedule. Tr. at 329-334; Tr. at 801.
Staff witness Fuss accepts Avista's Gas Cost of Service Study (aka Washington
Accepted Methodology) with two adjustments: (1) adjust usage within the pro fonna revenue
calculation resulting in a $23,000 revenue increase, and (2) allocate storage expenses and credits
based on winter thenn usage not anual usage as proposed by A vista to better allocate value
received by each class. Stafrs adjustments result in a net Idaho revenue requirement decrease
of $23,414. Tr. at 1238; 1242-1249. The Commission accepts the Company's Gas Cost of
Service Study (aka Washington accepted methodology) with Staff-proposed adjustments.
A vista on rebuttal accepts Stafr s recommendation for allocation of underground
storage costs and related capacity release revenues. Tr. at 335-337; Tr. at 826. The Commission
ORDER NO. 29602 57
finds Stafs proposed allocation of underground storage costs and related capacity release
revenues to be reasonable.
4. Cost of Gas in Base Rates
Avista proposes adding the current PGA WACOG adjustment of$0.27186/therm to
base rates to produce a total base rate gas cost of$0.44989/therm. Tr. at 1249.
Staff agrees with Avista's request and believes increasing the cost of gas in base
rates to reflect the best estimate of futue gas costs wil reduce the overall magnitude of future
PGA adjustments. Tr. at 1238-1239; 1249-1250.
The Commission adopts Avista's proposal to add the curent PGA weighted average
cost of gas (W ACOG) adjustment of $0.27186/therm to base rates to produce a total base rate
gas cost of $0.44989/therm.
Natural Gas Rate Design and Tarif Issues
Avista witness Hirschkom contends that the rates for natual gas Schedules 101, 111
and 121 provide a clear distinction for customer placement as well as a reasonable classification
of customers for analyzing the costs of providing service: customers who use less than 200
therms/month should be placed on Schedule 101; customers who use between 200 and 10,000
therms/month should be placed on Schedule 111; and only those customers who generally use
over 10,000 therms/month should be placed on Schedule 121. Tr. at 805.
In calculating the revenue allocation between the natural gas customer classes, Staff
witness Schune balanced the objective to move each class customer closer to cost of service
with the objective of achieving an equal contrbution to the non-gas related costs (which is
referred to the margin) from Schedules 121, 131 and 146. Staffs proposed revenue allocation
between classes was achieved by staring with the cost of service results. Then Schedules 121,
131 and 146 were moved closer to an equal contrbution to the margin in order to discourage
switchig between schedules and to protect against a revenue shortfall. Tr. at 1332, 1333.
The natural gas base rates the Commission approves as just and reasonable are those
set fort in attached Appendix B. Idaho Code § 61-502. The base rates we approve in this case
are the fixed base rates incorporated in the Company's PUA adjustment authorized in Order No.
29590, Case No. A VU-G-04-2. The resultant proposed increase for a natual gas residential
customer using an average of 73 therms of gas per month wil be $12.84 per month, or 21.39%.
ORDER NO. 29602 58
.
With this Order the Commission approves an increase in all gas commodity rates
maintaining the relationships between the classes as proposed by Staff to achieve the revenue
requirement for each class. The increase for each class are those reflected in Appendix F. We
reject an increase in customer charges for Schedule 101. We accept a customer charge of$200
for Transportation Schedule 146 and approve increases in first block minimum charges for
Schedules 111 and 121. For Schedule 131 we approve an increase in the annual minimum
deficiency charge to be reflective of the Company's margin rate.
1. Residential (Schedule 101)
A vista witness Hirschkom proposes to increase the residential basic and minimum
charges from $3.28 to $5.00 to recover one-half of the basic fixed costs of providing servce.
Tr. at 802-804. Staff witnesses Schunke and Parker recommend that the basic and minimum
charges remain at $3.28. Staff contends that the customer charge should be based on the direct
cost of meter reading and biling and should not include any fixed plant cost. The cost of meter
reading and biling for Schedule 101 is $2.46. Staff also cites customer opposition to this type
of charge. See discussion in electrc. Tr. at 1319; 1333-1334; Tr. at 866. Staff recommends an
average overall increase in base rates of 6.97% to Schedule 101.
Avista on rebuttal states that the cost of providing service to residential customers
has increased over the 15 years since the $3.28 basic charge was last set. The basic charge,
Avista contends, should recover not only meter reading and biling, but also the cost associated
with providing a meter and service line. Avista contends that the average cost associated with
these expenses is well over $9.00 per customer per month. Avista believes that Staffs
minimum charge proposal incorporates current PGA gas costs under Schedule 150, regardless of
the customer's usage. A vista believes it is more reasonable to increase the fixed minimum
charge under this schedule by the increase in margin and bil the present Schedule 150 rate only
for those therms used by the customer. Tr. at 824-825.
The Commission rejects an increase in the customer charge for Schedule 101 and
approves an increase in the commodity rate as reflected in Appendix F.
2. Large General Service (Schedule 111)
Schedule 111 is a thee tier declining block rate structure. Avista proposes a $12.75
increase to the monthly minimum charge for Schedule 111 customers. Tr. at 802; 805. Staff
recommends an increase in the basic or minimum charges to reflect the overall base rate
ORDER NO. 29602 59
.
increase for the first block. Tr. at 1334-1335. Staff recommends an average overall increase in
base rates of2.78% to Schedule 111. Tr. at 1319.
On rebuttal A vista recommends increasing the fixed minimum charge under this
Schedule by the increase in margin and biling the present Schedule 150 rate only for those
therms used by the customer. The Company's proposed rates, it states, incorporate the present
Schedule 150 rate in the block usage rates under this Schedule and as an additional variable
charge to the monthly minium charge. The monthly minimum charge would increase from
$97.30/month to $108.26/month, plus a 27.186jt/therm charge under the present Schedule 150
(W ACOG adjustment). Tr. at 825.
The Commission approves an increase in the commodity rates for Schedule 111 as
reflected in Appendix F and approves an increase in the minimum charge to reflect the resultant
increase in first block rates.
3. Extra Large General Service (Schedule 121)
Schedule 121 has a four-tier declinig block rate structure. The $267.63 monthly
minimum charge is in addition to a 27.186jt/therm charge under the present Schedule 150
(WACOG adjustment). Avista proposes a $29.30 increase to the monthly minimum charge.
There is also a minimum anual load factor requirement of approximately 58%. The Company
proposes adding an anual minimum usage requirement of 60,000 therms for service under this
schedule. Tr. at 802-803; 805-806. Staff recommends an increase in basic or minimum charges
to reflect the overall base rate increase for the first block. Staff recommends an average overall
increase in base rates of 1.86% to Schedule 121. Tr. at 1319; 1335.
A vista on rebuttal recommends increasing the fixed minimum charge under this
schedule by the increase in margin and biling the present Schedule 150 rate only for those
therms used by the customer. The Company's proposed rates incorporate the present Schedule
150 rate in the block usage rates under this schedule and as an additional varable charge to the
monthly minimum charge. The monthly minimum charge would be $265.74/month plus a
27 .186jt/therm charge under the present Schedule 150 (W ACOG adjustment). Tr. at 825.
The Commission approves an increase in the commodity rates for Schedule 121 as
reflected in Appendix F and approves an increase in the minimum charge to reflect the resultant
increase in first block rates.
ORDER NO. 29602 60
..
4. Interruptible Service (Schedule 131)
Schedule 131 is a single rate tariff. The present anual minimum charge is based on
a usage requirement of 250,000 therms per year. Avista recommends revising the anual
minimum charge to an anual minimum deficiency charge based on margin as it appears
unreasonable to charge the customer for gas costs when the gas was not used. The anual
deficiency charge will be determined by subtracting the customer's anual usage from 250,000
therms. Any resulting usage deficiencies wil be multiplied by the present margin (revenue less
gas costs) per therm under the Schedule, with the proposed margin level being 10.739
cents/thermo Tr. at 803; 806.
Staff to be reflective of the Company's margin rate recommends an increase in the
anual minimum deficiency charges. Tr. at 1319; 1335-1336.
The Commission accepts an increase in the anual minimum deficiency charge to
reflect the margin rate for Schedule 131 and approves an increase in the commodity rates as
reflected in Appendix F. The Company is directed to calculate and fie tarffs reflective of their
margin rate as of September 9,2004.
5. Transportation Service (Schedule 146)
Schedule 146 is a single rate tariff for all volumes transported on the Company's
distrbution system and includes an anual minimum charge based on 250,000 therms per year.
The Company is proposing to add a $200 monthly customerlbasic charge reflective of the
administrative costs associated with gas scheduling, balancing and billng transportation
customers. Tr. at 769; 801; 803; 807.
Staff recommends an average overall increase in base rates of 6.94% to Schedule
146. The proposed increase for transportation Schedule 146 excludes gas costs. If gas costs
were included the resulting increase would be approximately 1.5%. Staff recommends that the
Company-proposed basic charge of$200/month be approved. Tr. at 1317-1318; 1336; 1320.
The Commission approves the $200/month basic charge for Schedule 146 agreed to
by the Company and Staff and approves an increase in the energy rate as reflected in Appendix
F.
6. Special Contracts
Avista included all expenses associated with providing service to Idaho's Gas
Special Contract customers in the general rate filing. The Company has three transportation
ORDER NO. 29602 61
,
service customers under special contract (potlatch-Lewiston, Lignetics and IMCO fonnerly
IMSAMET). All three of the contracts were negotiated, executed and approved based on the
customers' close proximity to an interstate pipeline and their reasonable ability to by-pass the
Company's distribution system. Tr. at 798-799.
Staff recommends acceptance of Avista's treatment of Idaho gas special contracts
within the Gas COS study without changes. Tr. at 1239; 1250-1252.
The Commission acknowledges the Company's special contracts with Potlatch-
Lewiston, Lignetics and IMCO. The tenns and conditions of those contracts have been
previously approved by this Commission.
Other Issues
1. Prudency of DSM Expenditures
The Commission finds Avista gas DSM expenditues from March 13, 1995 through
October 31, 2003 to be prudently incured.
2. Tarif Summary Sheet
Staff recommends that Avista be required to add a tarff sumary sheet (sheet D) to
its gas tarff schedules because it wil provide clarty for customers without being
adinistratively burdensome. Tr. at 1239; 1252; Tr. at 884.
Avista on rebuttal agrees to file the tarff summar sheet each time rates change. Tr.
at 826.
The Commission directs the Company to prepare and fie a tarff sumary sheet for
natural gas rates.
CONCLUSIONS OF LAW
The Idaho Public Utilities Commission has jursdiction over this Application and
Avista Corporation dba A vista Utilties, an electrc and natural gas utilty, pursuant to the
authority and power granted under Title 61 of the Idaho Code and the Commission's Rules of
Procedure, IDAPA 31.01.01.000 et seq.
The Commission has jursdiction and authority pursuant to the above identified
statute and rules to authorize and requie Avista to re-allocate its revenues among the customer
classes to change its rate components withi the customer classes, to award intervenor fuding
and to address the other issues in the maner set forth in the text of this Order.
ORDER NO. 29602 62
'"
,
ORDER
In consideration of the foregoing and as more paricularly described above and
reflected in Amended Interlocutory Order No. 29588 issued September 9,2004, IT is HEREBY
ORDERED and the Commission hereby authorizes A vista Corporation dba A vista Utilities to
increase its net electrc revenues by $3,182,000 or approximately 1.9%. Ths increase
incorporates the base revenue increase approved by the Commission, a two year recovery of the
adjusted PCA deferral balance, and a decrease in DSM rates. We approve for rates and charges
in compliance with the terms of this Order the amended tarff sheets filed, by A vista in
compliance with Order No. 29588 and for service rendered on and afer September 9, 2004.
IT is FURTHER ORDERED and the Commission hereby authorizes Avista
Corporation dba Avista Utilities to increase its net gas revenues by $3,311,000 or approximately
6.38%. We approve for rates and charges in compliance with the terms of this Order the
amended tarff sheets filed by Avista in compliance with Order No. 29588 and for service
rendered on and afer September 9, 2004.
IT is FURTHER ORDERED that Avista Corporation dba Avista Utilities comply
with all other directives of the text of this Order.
IT is FUTHER ORDERED that Community Action Parership Association of
Idaho is awarded intervenor fuding in the amount of $12,622.75. Avista Utilties is directed to
pay this amount within 28 days of the date of ths Order.
THIS is A FINAL ORDER. Any person interested in ths Order (or in issues
finally decided by this Order) or in interlocutory Orders previously issued in ths Case Nos.
A VU-E-04-1 and A VU-G-04-1 may petition for reconsideration within twenty-one (21) days of
the service date of this Order with regard to any matter decided in this Order or in interlocutory
Orders previously issued in this Case Nos. A VU- E-04-1 and A VU-G-04- 1. Within seven (7)
days after any person has petitioned for reconsideration, any other person may cross-petition for
reconsideration. See Idaho Code § 61-626.
ORDER NO. 29602 63
f
DONE by Order ofthe Idaho Public Utilties Commission at Boise, Idaho ths gf'
day of October 2004.
PAfiJJ:f
~LíU_
MASHA H. SMITH, COMMISSIONER
D~J~R
ATTEST:
it.~J D.Jew~
mmission Secretar
blslO:AVUE0401_AVUG0401_sw7
ORDER NO. 29602 64
.
Basic Charge
Present Rates
First 600 kWhs
All over 600 kWhs
PCA Rate 0 - 600 kWh
All over 600 kWh
Energy Efficiency Rider
Basic Charge
Present Rates
Energy Charge
Demand Charge:
20 kW or less
Over 20 kW
PCA Rate
Energy Effciency Rider
Energy Charge
Present Rates
Demand Charge:
50 kWor less
Over 50 kW
Primary Voltage Discount
PCARate
Energy Effciency Rider
Energy Charge
Demand Charge:
3,000 kva or less
Over 3,000 kva
Primary Voltage Discount
Annual Minimum
PCARate
Energy Effciency Rider
Rales exhibit 9100 KDH
AVISTA UTILITIES
AVU.E-04.1
Present and Commission Ordered Electric Rates
Residential Service. Schedule 1
Commission Ordered Rates$4.00 Basic Charge $4.00
4.555 rf/kWh
5.303 rf/kWh
First 600 kWhs
Allover 600 kWhs
5.717 rf/kWh
6.487 rf/kWh
0.939 rf/kWh PCA Rate 0.286 rf/kWh
1.092 rf/kWh
0.104 rf/kWh Energy Effciency Rider 0.081 rf/kWh
General Service. Schedule 11 -
Commission Ordered Rates$6.00 Basic Charge $6.00
7.148 rf/kWh
6.076 rf/kWh
no charge
$3.50/kW
1.391 rf/kWh PCA Rate
0.140 rf/kWh Energy Effciency Rider
Large General Service. Schedule 21
Commission Ordered RatesFirst 250,000 kWh 4.688 Ø/kWh
All Over 250,000 kWh 3.985 Ø/kWh
0.335 Ø/kWh
0.095 Ø/kWh
$250.00
$3.00/kW
20Ø/kW
0.256 Ø/kWh
0.073a,kWh
$9,000.00
$2.75/kva
20Ø/kva
$502,670
0.181 rf/kWh
0.052 Ø/kWh
. APPENDIX A
Page 1 of 2
Order No. 29602
Case Nos. AVU-E-04-1
1\\111 ~ nil 1
6.564 Ø/kWh First 3650 kWh
All Over 3650 kWh
1.011 Ø/kWh PCA Rate
0.100 Ø/kWh Energy Effciency Rider
Extra Large General Service. Schedule 25
Present Rates Commission Ordered Rates
2.874 rf/kWh First 500,000 kWh 3.862 rf/kWh
All Over 500,000 kWh 3.259 rf/kWh
no charge
$3.50/kW
Demand Charge:
20 kWor less
Over 20 kW
3.996 Ø/kWh
$225.00
$2.75/kW
Demand Charge:
50 kWor less
Over 50 kW
20rf/kW Primary Voltage Discount
$7,500.00
$2.25/kva
Demand Charge:
3.000 kva or less
Over 3,000 kva
20Ø/kva
$406,140
0.607 rf/kWh
0.068 Ø/kWh
Primary Voltage Discount
Annual Minimum
PCA Rate
Energy Effciency Rider
.
.
AVISTA UTILITIES
AVU.E-04.1
Present and Commission Ordered Electric Rates
Present Rates
Potlatch. Schedule 25P
Energy Charge'
First 3650 kWh
2.874 rl/kWh'Energy Charge 3.333 rl/kWh
Demand Charge:
$7,500.00 3,000 kva or less $9,000.00
$2.25/kva Over 3,000 kva $2.75/kva
20rl/kva Primary Voltage Discount 20Ø/kva
$406,140 Annual Minimum $474,630
Demand Charge:
3,000 kva or less
Over 3,000 kva
Primary Voltage Discount
Annual Minimum
PCARate
Energy Effciency Rider
Basic Charge
Present Rates
0.607 rl/kWh PCA Rate
0.068 i/kWh Energy Effciency Rider
Pumping Service. Schedule 31
Commission Ordered Rates
Basic Charge
0.163 i/kWh
0.046 rl/kWh
$6.00 $6.00
First 85 kWh/kW
Next 80 kWh/kW
All additional kWhs
5.716 t/kWh
5.716 rf/kWh
4.548 t/kWh
First 85 kWh/kW
Next 80 kWh/kW
All additional kWhs
6.440 rf/kWh
6.440 rf/kWh
5.474 t/kWh
PCARate
Energy Effciency Rider
0.888 t/kWh PCA Rate
0.102 rf/kWh Energy Effciency Rider
Street and Area Lights. Schedules 41-49Present Rates Commission Ordered Rates
0.265 rf/kWh
0.076 rf/kWh
Base Rates Various Base Rate Increase 20.19%
PCA Surcharge 19.37%PCA Surcharge 4.385%
Energy Effciency Rider 1.95%Energy Effciency Rider 1.25%
Rate Exibl 912004 KOH
APPENDIX A
Page 2 of 2
Order No. 29602
Case Nos. AVU-E-04-1
A \/1 1..r,-n4-1
.
.
AVISTA UTILITIES
AVU-G.04-1
Present and Commission Ordered Natural Gas Rates
Present Rates 1
General Service - Schedule 101
Commission Ordered Rates2
$3.28 Basic Charge $3.28Basic Charge
All Therms 74.197 Ørrherm All Therms 80.050 ørrherm
Present Rates 1
Large General Service - Schedule 111
Commission Ordered Rates2
1 st 200 Therms
Next 800 Therms
Over 1,000 Therms
75.836ç;rrherm*
74.197Ørrherm
64.97Sç;rrherm
1 st 200 Therms
Next 800 Therms
Over 1,000 Therms
78.301 trrherm*
76.481 Ørrherm
66.239Ørrherm
*Minimum - $97.301M0nth
piiis 27.186ørrherm
*Minimum - $156.60IMonth
Present Rates 1
Large General Service - Schedule 121
Commission Ordered Rates2
1 st 500 Therms
Next 500 Therms
Next 9,000 Therms
Over 10,000 Therms
74.852trrherm*
74.197ç;rrherm
64.97Sç;rrherm
63.284ørrherm
1 st 500 Therms
Next 500 Therms
Next 9,000 Therms
Over 10,000 Therrns
77 .209ç;rrherm*
76.481 Ørrherm
66.239Ørrherm
64.361 ç;rrherrn
*Minirnum - $238.33/Month
plus 27.186ørrherm *Minimum - $386.051M0nth
Present Rates 1
Interruptible Service - Schedule 131
Commission Ordered Rates2
All Therms 55.724Ørrherm*All Therms 56.586Ørrherm*
*Annual Minimurn $78,385 *Annual Minimum 3
Transportation Service - Schedule 146
Present Rates 1 Commission Ordered Rates2
Basic Charge $0.00 Basic Charge $200 ¡Month
All Therms 10.S74Ørrherm All Therms 10.960Ørrherm
1 Includes Purchase Gas Adjustment Schedule 150/Excludes all other rate adjustments
2 Does not include Schedule 150 or any other rate adjustment.
3 Annual Minimum: Each Customer shall be subject to an Annual Minimum Deficiency Charge if their gas
usage during the prior year did not equal or exceed 250,000 therms. Such annual Minimum Deficiency
Charge shall be determined by subtracting the Customer's actual usage for the twelve-month period
ending each August from 250,000 therms multiplied by 11.597rl per thermo
Rates Exibit tabRate Ex
MJF
APPENiJI)(S
Order No. 29602
Case Nos. AVU-E-04-1
AVU-G-04-1
.
.
AVISTA UTILITIES
CALCULATION OF GENERAL REVENUE REQUIREMENT
IDAHO ELECTRIC SYSTEM
TEST YEAR 2002
(OOO'S OF DOLLARS)
~I Description
1
2
3
Pro Forma Rate Base
Proposed Rate of Return
Net Operating Income Requirement (Line 1 x Line 2)
4 Pro Forma Net Operating Income
5 Net Operating Income Deficiency (Line 3 - Line 4)
6 Conversion Factor
7 Revenue Requirement Deficiency (Line 5ILine 6)
8 Levelized Deferred Return on Coyote Springs 2
9 Revised Revenue Requirement Deficiency (Line 7 + Line 8)
10 'Total General Business Revenues
1 1 Percentage Revenue Increase (Line 9ILine 10)
Commission
Decision
$424,114
9.250%
$39,231
$23,121
$16,110
0.63926135
$25,201
(485)
$24,7161
$146,248
16.90%
APPENDIXC
Order No. 29602
Case Nos. AVU-E-04-1
AVU-G-04-1
".
.
AVISTA UTILITIES
CALCULATION OF GENERAL REVENUE REQUIRÈMENT
IDAHO GAS
TEST YEAR 2002
(OOO'S OF DOLLARS)
5a1 Commission
Description DecisionNo.
1 Pro Forma Rate Base $59,653
2 Proposed Rate of Retur 9.250%
3 Net Operating Income Requirement (Line 1 x Line 2)$5,518
4 Pro Forma Net Operating Income $3,402
5 Net Operating Income Deficiency (Line 3 - Line 4)$2,116
6 Conversion Factor 0.639
7 Revenue Requirement Deficiency (Line 5/Line 6)$3,311 I
8 Total General Business Revenues $51,919
9 Percentage Revenue Increase (Line 7/Line 8)6.38%
APPENDIX D
Order No. 29602
Case Nos. AVU-E-04-1
AVU-G-04-1
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Offce of the Secret
Servce Dat
November 24, 2004
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF mE APPLICATION OF )
A VISTA CORPORATION FOR TH )
AUmORITY TO INCREASE ITS RATES AN )
CHAGES FOR ELECTRC AN NATURAL )
GAS SERVICE TO ELECTRIC AND NATURL )
GAS CUSTOMERS IN THE STATE OF IDAHO. )
)
CASE NOS. AVU-E-04-1
AVU-G-04-1
ORDER NO. 29638
On Februar 6, 2004, Avista Corporation dba Avist Utilties (Avista; Company)
fied an Application with the Idaho Public Utilties Commssion (Commssion) for authority to
increase its rates and chages for electrc and natual gas service in the State of Idaho.
On October 8, 2004, the Commission issued fi Order No. 29602 authorizg
Avista to increase its Idaho electrc base revenue requirement by $24,716,195 or approximately
16.90%. This increase was offset by disallowances in the Power Cost Adjustment (PCA)
coupled with an adjustment in the PCA recovery perod and the reduction in the energy
effciency rider. These offsetting adjustments reduced the authorized electrc net revenue
increase to $3,182,000 or 1.9% of curent anua revenue. The Commssion also authorized
Avista to increase its natual gas revenues by $3,311,000 or approximately 6.38%.
On October 29,2004, Avista filed a Petition for Reconsideration of Order No. 29602.
Idaho Code § 61-626. On November 5, 2004, Potlatch Corporation filed an Anwer and Cross
Petition for Reconsideration. Also filed on November 5, was Commssion Staffs Reply to
Avista's Petition for Reconsideration. The Commission in this Order approves the technical
computation errors identified by the Company and agreed to by Staff and denies the remaing
relief sought in the Company's Petition for Reconsideration and Potlatch's Cross Petition for
Reconsideration.
The respective Petition, Anwer and Cross Petition, and Reply can be sumarized as
follows:
Avista Petitin for Reconsideration
Avista contends tht certn portons of the Commission's Order No. 29602 are
uneasonable, unlawf, erroneous and not otherwse in conformity with the facts of record
and/or the applicable law, resulting in a revenue requirement and rates tht are confiscatory.
ORDER NO. 29638 i
L Deal A Disallowance
Avista contends that the Commission's disallowance of one-thd of the Idao
jursdictional share of Power Cost Adjustment (PCA) Coyote Springs 2 (CS2) Deal A losses fails
to recognize evidence of record and was otherwse uneasonable.
In Avista PCA Order No. 29377, Case No. A VU-E-03-6, the Commission deferred a
PCA recovery decision regarding the Company's acquisition and later sale at a loss of natural
gas to fuel the Coyote Springs 2 (CS2) combined cycle combustion turbine. CS2 was initially
scheduled for testing in early 2002 and was expected to be commercially available in July 2002.
As it turs out, at the time the gas was scheduled for delivery CS2 was not operational nor was it
economical to use the gas purchased at the Company's other facilties. Instead A vista simply
purchased its power needs on the electrc market and sold the Deal A gas back into the gas
market at a loss because gas prices had declined.
As reflected in the Commission's Order, Deal A consisted of two transactions of
10,000 dth/day each, for a 36 month delivery tenn (November 1, 2001 though October 30,
2004), that were entered into for the purose of hedging or fixing, the natual gas price of index-
based physical purchases for the period of November 1,2001, though October 31, 2004. One
transaction was entered into on April 11, 2001 at a price of $6.7525/dth and the second
transaction was entered into on May 2, 2001 at a price of $6.50/dth. The price for October 2004
gas was locked-in for thee and one-half years into the futue. The system loss attrbutable to
Deal A gas though May 31,2004 was $47,936,000. The Idaho jursdictional amount disallowed
by the Commission was $4,771,550.
On reconsideration A vista contends, as previously indicated at hearng by its witness
Robert Lafferty, that the combination of net system varabilty and highvolatile energy prices,
posed a "signficant economic risk" to the Company. The Company in response elected to hedge
a portion of the monthly deficit associated with the combined varabilty of loads and
hydroelectrc generation conditions.
Avista points out that the Commission's own Sta was quite clear and unambiguous
in its recommendation to disallow only Deal B hedge losses. As Staff witness Hessing indicated,
"Deal A hedges were not done with an A vista afliate, but Deal B hedges were. Also, the Deal
A gas purchase did not put the Company over the long limit contained in its Risk Policy. . . ."
Tr. at 1270. Citing Commission Staff, Avista contends that Deal A was well within the
ORDER NO. 29638 2
Company's risk parameters or "protocols"; provided the necessar gas supply, at a fixed cost, to
fuel the needed Coyote Springs 2 generation plant; and was not "speculative" because it aligned
the Company's loads and resources for the futue and within the limits that were set in the
Company's Risk Policy. Tr. at 1270, 1271-72, 1308-09.
A vista includes as an Appendix to its Petition a load resource position sumar
based on 90% confidence interval planing that it contends demonstrates that Deal A if looked at
alone, was well within and consistent with the Company's resource planng criteria. Tr. Exh. 7,
Sch. 26, p. 2. (A 90% confidence interval represents a 5% chance that the Company would have
to purchase some amount of energy above a specific megawatt amount for a given month.)
Avista disputes the Commission's finding that the Company's supporting analysis
appeared to be "cobbled together" after the fact, citing Lafferty testimony describing the
Company's analysis. Avista contends that the record reflects that the Company conducted
extensive modeling of its load/resource balance prior to enterig into the hedge transactions and
also undertook a comparative analysis of the cost to generate power at the hedged price of gas
compared to electrc power prices available at the time.
Avista contends that fixing the price of index-based physical purchases through the
Deal A hedged transactions was also consistent with its electrc Integrated Resource Planing
(IR) objectives.
The Company concludes that when one looks to the "prudence" of decision making
at the time the decisions were made, the evidence demonstrates that (a) an analysis of the
load/resource balance with Deal A had been conducted, demonstrating that even with Deal A, the
Company was in a resource deficit position, and (b) that an examnation of forward prices, at the
time, demonstrated that the hedged natual gas fuel would result in generation costs of between
$38/MWh to $48/MWh - well below the higher-priced power available in the market, and (c)
that Deal A hedged transactions were consistent with resource planing objectives and Risk
Policy guidelines or protocols. The record, the Company contends, demonstrates that both the
need for the hedge transactions and the cost of such transactions were, in fact, analyzed before
entering into the transactions. Analysis and documentation pertaining to both the loadresource
deficits and the forward market prices did exist, the Company states, before it entered into the
transactions.
ORDER NO. 29638 3
Potlatch Cross Petition
Potlatch in its Cross Petition contends as both a matter of law and equity, that the
entirety of the Deal A costs should be disallowed, citing the "just and reasonable" stadard of
Idaho Code § 61-301. The ''just and reasonable" rate standard, Potlatch contends, necessarly
assumes reasonable managerial competence and prudence. If a utilty spends money
unecessarily or imprudently, Potlatch contends it should not be allowed to recover such
expenditures. The underlyig physical purchases for Deal A had already been made, Potlatch
states. What Deal A, Potlatch contends, did was to lock-in an imediate gamble on the price
direction of the natual gas futues market. The 36-month length of the Deal A hedges and the
financial exposure created, Potlatch contends, was, as reflected in its testimony of Potlatch
witness Dr. Denns Peseau, unprecedented for Avista, and for the electrc industry as a whole.
Potlatch contends that the risk assumed in Deal A was a derivative risk and that the risk was
assumed without any formal cost benefit analysis. The failure of the Company to evaluate it as
an exposure separate and distinct from the physical purchase of gas, Potlatch contends, was not
only imprudent, it was specifically prohibited by Avist's Risk Mangement Policy. Citing Risk
Management Policy:
Any incremental market exposure created from the use of derivatives is
inconsistent with the risk management objectives of ths Policy and is not
permitted. The use of dervatives exposes Avista Corp. to risks similar to
risks of physical products, and may have additional liquidity, settlement,
legal, and systematic risk attrbutes. Even the proposed use of derivatives
that would hedge risks should be assessed against these additional risks, and
such use is permitted only to the extent that the expected benefit is
considered to outweigh these risks. Tr. at 956 (Confidential).
Potlatch contends tht the Commission's disallowance of one-third of Deal A's cost
is a wholly inadequate remedy. Deal A, it states, was imprudent and "not permitted" under the
Company's Risk Policy and it should be similarly "not permitted" for ratemaking puroses. The
Commission, Potlatch states, can have no basis for finding that any portion of the costs
associated with Deal A can be passed onto ratepayers as a necessar and prudent expenditue.
The Commission, Potlatch contends, simply does not have authority to attempt a middle
approach that attempts to give something to both the utilty shareholders and its ratepayers. Deal
A losses, it concludes, must be left with the utilty whose incompetence and recklessness caused
their incurence.
ORDER NO. 29638 4
Commission Findings
The Commission has reviewed the filings of record in Case Nos. A VU-E-04-1/ AVU-
G-04-1 including Avista's Petition for Reconsideration, Potlatch's Answer and Cross Petition for
Reconsideration, Commission Staffs Reply, the underlying transcript of proceedings and our
Order No. 29602. We have also reviewed recent customer comments filed with the Commission
opposing fuer rate increases.
Contrar to Avista's contention, the Commission did recognize evidence of record.
The Commission weighed all the evidence including conflcting evidence and reached its
conclusions.
Despite Avista's contention to the contrar, as reflected in the record, the
Commission finds that Deal A did not conform to established protocols. There were no
Commission-approved protocols in place for electric side gas procurement. The transaction both
in length (36 months) and financial exposure was unprecedented for Avista and was
accompanied by little supportng analysis and paper trail, of the sort relied upon by the
Commission's auditing Staff for utility gas Benchmark trnsactions. The Deal A hedge
transaction was a financial derivative contract. The Company took a price view using
derivatives that despite the Company's contention to the contrar was clearly not permitted
under its internal Risk Management Policy. Nor was the financial transaction, we find, the sort
of physical transaction clearly authorized in the Company's electric Integrated Resource Plan.
The Commission in its Order prefaces its discussion of Deal A losses with a
consideration of what it determined to be a threshold issue, the propriety of Avista's transactions
with Avista Energy. Contrar to Avista's contention, the Commission's findings regarding no
"operating protocol" being established for transactions between Avista Energy and Avista's
electrc operations was not a finding of deficiency as to Deal B alone - it was also a finding
regarding Deal A. The need for operating protocols governing conduct between the utilty and
its unegulated affliate exists whether or not A vista Energy was acting as a counter-par.
Although not a counter-par to the Deal A transaction, A vista Energy brokered the deaL. Thus,
contrar to Avista's contention, Deal A hedge losses canot be viewed separate and apar from
any A vista Energy involvement.
The Company's Risk Management Policy, we find, was an internal Company policy
intended to provide transactional guidance. It was not an operatig protocol fied with or
ORDER NO. 29638 5
approved by the Commission. The Benchmark Mechanism, on the other hand, is an operating
protocol approved by the Commission; but it exists only on the gas side, not the electrc.
The Company's statements regarding the consistency of Deal A hedge transactions
with its risk policy guidelines and resource planing objectives are not sufficient to justify
transactions that were otherwise engaged in without an underlying Commission approved
operating protocol and agency agreement. The Company's actions exposed utility customers to
the risk associated with the Company's non-regulated subsidiar operations. Deal A was highly
iregular and apar from any other transactions made by A vista. The fact that the Company
failed to purchase gas with the same kid of long-term deals for its gas customers that it did for
its electrc customers, we find, also demonstrates the Company's inconsistency.
Potlatch contends that the Commission has no choice but to deny recovery of Deal A
amounts. The Commission disagrees. While Avista was certainly engaging in objectionable
transactions in Deal A and B, the transactions themselves were not expressly prohibited by
Commission Order or established protocol. There was no Order; there was no protocol on the
electrc side to provide guidance in affiiate transactions. It is a grey area, not black and white.
The Commission has a joint obligation to the utility and its customers. The Commission has
authority under Idaho Code §§ 61-50i and 61-301 to assess the reasonableness of the
Company's actions and to determine a reasonable level of cost recovery.
Consequently, we reaffrm our decision to disallow a portion of the losses associated
with Deal A.
Deal A - Miscalculations
A vista in its Petition also contends that there are four miscalculations related to the
determination of Deal A losses that need to be corrected. The cumulative reduction for the four
Company-identified miscalculations is $2,648,937. Incorporating these four adjustments to the
calculation of gas losses results in a Deal A disallowance of $2,122,937. This compares to the
Deal A disallowance of$4,771,550 in Order No. 29602.
A. Company Contention: Staff Exhibit 141 relied upon by the Commission, has the
wrong number of days for the months of July 2003 though May 2004. This error overstates the
loss calculation for Deal A. ... The Company-proposed adjustment is $91,035.
ORDER NO. 29638 6
Staff Reply
Staff in its Reply concurs with the Company-proposed corrections to the wrong
number of days in the months that were included in Deal A calculations.
Commission Findings
We accept on reconsideration the corrections for number of days in the month
included in Deal A calculations.
B. Company Contention: The Staff Exhibit No. 141 calculation of Deal A gas losses
includes an incorrect calculation of the Deal A gas profitably burned for the months of
November 2003 though May 2004. It included only one-half of the Deal A gas profitably
bured and should have included all of it, since Deal B had ended October 31, 2003. The
Company-proposed adjustment is $35,819.
Staff Reply
Staff in its Reply concurs with the Company-proposed corrections to the calculation
for gas profitably bured for the perod November 2003 - May 2004.
Commission Findings
We accept on reconsideration the corrections for Deal A gas profitably bured for the
perod November 2003 - May 2004.
C. Company Contention: The Commssion-ordered disallowance of $4,771,550 is
based on "one-third" of the Deal A losses. The Company has aleady absorbed 10% of the tota
Deal A losses through the 90%/10% sharng featue of the PCA. The effective disallowance is
therefore 40% of the total losses-not the "one-third" disallowance ordered by the Commission.
The Company proposed adjustment is $1,060,344.
D. Company Contention: The Deal A disallowance is based on tota Deal A losses
for the period November 2001 though May 2004. The losses in the period November 2001
though June 2002, however, had previously been authorized by the Commission for PCA
recovery. To order a disallowance based on losses that were previously approved for recovery
would, the Company contends, constitute retroactive ratemaking. The Company proposed
adjustment is $1,461,415.
Staff Reply - C & D
The methodology used to calculate Deal A disallowance, Staff contends, is clearly
specified in Order No. 29602 on page 46:
ORDER NO. 29638 7
Deal A losses though May amounted to $47,936,010 on a system basis;
$15,905,167 on .an Idaho jursdictional basis. With 90/10 sharng the Idaho
PCA amount related to Deal A losses is $14,314,651. Of that amount
$5,636,885 was previously authorized for PCA recovery (July 1 - June 2002).
Based on our consideration of the record and Deal A findings, the
Commission finds it reasonable to exclude or disallow one-thrd of the Idaho
system Deal A losses, or $4,771,550.
The table below, Staff states, duplicates the Commssion specified methodology. The
total amount of Deal A losses, at the system level, is multiplied by the allocation factor for the
Idaho Jurisdiction, to come up with the Idaho Jursdictional amount of the total Deal A losses.
This amount is then adjusted to reflect the i 0% sharng mechanism in the PCA calculation and
the ratepayer portion of the losses. The ratepayer porton is then divided by thee to arve at the
disallowance ordered by the Commission. Using the same methodology with corrections
incorporating the proper number of days and the proper amount of gas profitably bured results
in a Deal A disallowance of $4,608,452.
1. Losses already recovered on Deal A:
2. Losses deferred for recovery on Deal A:
3. Total System losses on Deal A:
4. Jursdictional Factor:
5. Idaho Jursdictional Portion of Deal A Losses:
6. 10% Shareholder PCA Portion of Deal A Losses:
7. Ratepayer Portion of Deal A Losses:
8. One Third of Ratepayer Portion of Deal A Losses:
9. Disallowance Amount of Deal A Losses:
Commission
Order
$18,876,448
$29,059.562
$47,936,010
33.18%
$15,905,168
$ 1,590,517
$14,314,651
$ 4,771,550
$ 4,771,550
Commission Order
With Corrections
$18,876,448
$27.421.045
$46,297,493
33.18%
$15,361,508
$ 1,536,151
$13,825,357
$ 4,608,452
$ 4,608,452
With respect to miscalculation items C and D described above, Staff contends that the
Company's calculation of the Deal A disallowance is not consistent with the Commission's
Order. Rather than using total Deal A losses of $46,297,493 (as corrected) to calculate the
disallowance as specified by the Commission, the Company, Staff notes, uses only Deal A losses
of $27,421,045 (as corrected) curently deferred for recovery. The Company then improperly
takes one thd of the unecovered Idaho jursdictional Deal A losses before applying the 10
percent PCA sharng. This is in contrast, Staff contends, to the Commission Order that applies
the 10% sharng first to the Idaho Jursdictional losses and then takes one third of the remaing
total to establish the disallowed amount.
ORDER NO. 29638 8
manner:
The Company, Staff states, has calculated the Deal A disallowance in the following
Deal A losses deferred for recovery:
Jursdictional Factor:
Idaho Jurisdictional Portion of Unrecovered Deal A Losses:
One Third of Idaho Jursdictional porton of Unrecovered Deal A Losses:
Less 10% of Idaho Jursdictional portion of Unrecovered Deal A Losses:
Company Disallowance Amount of Deal A Losses
$27,421,045
33.18%
$ 9,098,303
$ 3,032,768
$ 909,830
$ 2,122,937
The Company, Staff contends, perceives inclusion of the $18,876,448 in the Deal A
disallowances calculation to be retroactive ratemakng and therefore, removes the amount to
correct what it characterizes as a calculation error. However, the Commission Order, Staff notes,
clearly states ". . . $5,636,885 was previously authorized for PCA recovery (July I-June 2002)."
The $5,636,885 is the Idaho jursdictional ratepayer share of $18,876,448. Total Deal A losses
were simply used in the Order to establish what amount of the additional losses was subject to
recovery though the PCA and what amount was not. Prior amounts recovered in rates are not
being reversed.
Commission Findings
We reject Avista's characterization of the disallowance methodology and stad by
the clear language of the Order that sets out the process used to establish the disallowed amount.
Contrar to Avista's contention, we have not required a refuding of Deal A losses previously
approved for recovery. While our, mathematical calculation is based on the total Deal A losses
though May 2004, we find the Deal A disallowance dollar amount to be otherwise reasonable as
a reduction to the unrecovered Deal A loss amount.
In sumary, the net effect of the proposed corrections A and B is an increase in Deal
A loss recovery through the PCA of $163,098 after applying the Commission ordered
disallowance methodology.
IL Boulder Park
The Commission's disallowance of costs associated with Boulder Park, Avista
contends, was excessive and unduly harsh.
The Commission in Order No. 29602 regarding Boulder Park found a 53%
constrction cost overr to be unreasonable. The original cost estimate in May 2001 was $21
millon. The total actual cost upon completion was $31.9 milion. The Commission found it
ORDER NO. 29638 9
reasonable to limit the authorized rate base amount for Boulder Park to the project constrction
estimate plus a 15% contigency, or $24,150,000. The Idaho jursdictional share of the
disallowance is $2.6 millon. The Company contends that the disallowance should not exceed
the 10% of final project costs recommended by Staf, $1.1 millon (Idaho jurisdictional share).
Potlatch Answer
Regarding Boulder Park, Potlatch supports in its Answer the Commission's
disallowance. The simple fact, Potlatch states, is that Boulder Park costs were wildly excessive
when compared to any reasonable cost overr possibilties. Clearly if Boulder Park had been
purchased from an independent third pary contract, Potlatch posits, it would have been
uneasonable for A vista not to cap any potential cost overrs by contract. Similarly, Potlatch
contends, it is not uneasonable for the Commission to impose an overr limitation on plants
built by A vista.
Commission Findings
The Commssion in Order No. 29602 found that Avista should be held to a higher
standard than recommended by Staff. Ratepayers, we found, should not be asked to pay for what
we continue to find to be a Company learing experence. The reasonableness of our
disallowance is not the percentage of total disallowed, but the percentage of cost overr
allowed.
IlL Pension Expense Adjustment (Electric/Gas)
Avista in its Petition identified a techncal correction to the adjustment of the
Company's pension cost. The identified changes are needed to correctly allocate the "system"
corporate level of pension expense to utilty operations prior to applying the Idao jursdictional
allocation factors. The correction results in a $46,411 increase in the electrc revenue
requirement and an $11,422 increase in the natual gas revenue requirement. Avista Petition,
Attachment D.
Staff Reply
Staff agrees with the techncal correction proposed by the Company.
Commission Findings
The Commission accepts the Company-proposed pension expense adjustments.
ORDER NO. 29638 10
CONCLUSIONS OF LAW
The Idaho Public Utilties Commission has jursdiction over ths Petition and Avista
Corporation dba Avista Utilities, an electrc and natual gas utility, pursuant to the authority and
power granted under Title 61 of the Idaho Code and the Commssion's Rules of Procedure,
IDAPA 31.01.01.000 et seq.
ORDER
In consideration of the foregoing and as more paricularly described above, IT IS
HEREBY ORDERED and the Commission by this Order on Reconsideration of final Order No.
29602 in Case Nos. A VU-E-04-1 and AVU-G-04-1 approves the Deal A techncal corrections
for proper number of days and the proper amount of gas profitably bured.
IT IS FURTHER ORDERED and the Commission by this Order approves the
techncal corrections to the natural gas and electrc pension expense adjustments.
IT IS FUTHER ORDERED and the Commission by ths Order denies
reconsideration of the underlying disallowance for PCA Deal A losses and Boulder Park cost
overrs and reaffrms its related fidings in Order No. 29638.
THIS is A FINAL ORDER ON RECONSIDERATION. Any par aggreved by
ths Order or other final or interlocutory Orders previously issued in this Case Nos. A VU-E-04-1
and A VU-G-04-1 may appeal to the Supreme Court of Idaho pursuant to the Public Utilities Law
and the Idaho Appellate Rules. See Idaho Code § 61-627.
ORDER NO. 29638 11
, I
DONE by Order of the Idaho Public Utilities Commission at Boise, Idaho this c2 'l;l
day of November 2004.
Comm. Smith was Out of the Offce ths Date
MARSHA H. SMIT, COMMISSIONER
ATIEST:
Êt0~J. D. Jeweii~
ommission Secretar
blslO:A VUE0401_A VUG0401_sw8
ORDER NO. 29638 12
..
"
RECEIVED infilED 0
iflOI¡ JUN 21 PM I: 57
IUi\HG FUBLIC
UTILITIES COf1MlSSION
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF AVISTA CORPORATION FOR ) CASE NO. AVU.E.04.11
AUTHORITY TO INCREASE ITS RATES) AVU.G.04.1
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ~
AND NATURAL GAS CUSTOMERS IN )
THE STATE OF IDAHO. )
)
DIRECT TESTIMONY OF LYNN ANDERSON
IDAHO PUBLIC UTILITIES COMMISSION
JUNE 21, 2004
~
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Lynn Anderson and my business
4 address is 472 West Washington Street, Boise, Idaho.
5 Q.By whom are you employed and in what capacity?
I am employed by the Idaho Public Utilities6A.
7 Commission as a Staff economist.
8 Q.What are your duties with the Commission?
9 A.My duties include evaluating electricity,
10 natural gas, water and telephone utility applications and
11 customer petitions, as well as conducting generic
12 investigations, the results of which are used to make
13 recommendations to the Commission.
14 Q.Would you please outline your academic and
15 professional background?
16 A.I have a Bachelor of Science degree in
17 government and a Bachelor of Arts degree in sociology,
18 both from Idaho State University where I also studied
19 economics and architecture. I studied engineering at
20 Northwestern University and Brigham Young University and
21 public administration and quantitative analysis at Boise
22 State University. I have attended many training seminars
23 and conferences regarding utility regulation, operations,
24 forecasting, and marketing.
25 I began my employment with the Commission in
CASE NOS. AVU-E-04-1/AVU-G-04-106/21/04 ANERSON (Di) 1
STAFF
1 1980 as a utility rate analyst. In 1983 I was appointed
2 to the position of telecommunications section supervisor
3 and in 1992 I was appointed to my present position as an
4 economist. In that capacity I have been a Staff
5 representative to the Northwest Energy Efficiency
6 Alliance, Avista's External Energy Efficiency Board and
7 Idaho Power's Energy Efficiency Advisory Group. Since
8 1999 I have served the Commission as a policy strategist
9 for electricity and telecommunications issues on an as-
10 needed basis.
11 From 1975 to 1980 I was employed by the Idaho
12 Transportation Department where I performed benefit/cost
13 analyses of highway safety improvements and other
14 statistical analyses.
15 Q.What is the purpose of your testimony?
The purpose of my testimony is to make16A.
17 recommendations regarding Avista' s request that its
18 electricity and gas demand side management (DSM or energy
19 efficiency) expenditures be deemed reasonable and
20 prudent. I will also present changes to Avista' s
21 electricity DSM funding level that the Company proposed
22 at the May 19, 2004 meeting of its External Energy
23 Efficiency (EEE) Advisory Board and that it reiterated to
24 the Staff on June 2 f 2004. Finally f I will comment on
25 Avista's proposed advanced meter reading (AMR) proposal.
CASE NOS. AVU-E-04-1/AVU-G-04-106/21/04
ANERSON (Di) 2
STAFF
1 Demd Side Management/Energy Efficiency
2 Q.Please describe the energy efficiency
3 expenditures that the Company has requested be deemed
4 reasonable and prudent by the Commission.
5 A.The Company is asking that its electricity DSM
6 expenditures from January 1, 1999 through October 31,
7 2003, and its gas DSM expenditures from March 13, 1995
8 through October 31, 2003 be found to have been prudently
9 incurred.(Company witness Hirschkorn's pre-filed direct
10 testimony has a slight error, showing December 31, 2003
11 as the end date.) As noted by Avista witness Brian
12 Hirschkorn on page 44 of his pre-filed testimony, the
13 Commission previously found that the Company's
14 electricity DSM expenditures were prudently incurred
15 through December 31, 1998.
16 Q.How does Avista collect revenues that finance
17 its energy efficiency programs?
18 A.Avista collects revenues for its DSM programs
19 from surcharges described in its tariff Schedule 91 for
20 electricity DSM and Schedule 191 for its gas DSM.
21 Currently, the electricity surcharges amount to 1.95% of
22 base revenue and the gas surcharges amount to 0.5% of
23 base revenues. For 2002 these surcharges collected about
24 $2.7 million and $279,000 per year for electricity and
25 natural gas DSM, respectively.
CASE NOS. AVU-E-04-1/AVU-G-04-106/21/04 ANERSON (Di) 3
STAFF
1 Q.Do you believe Avista has been reasonable and
2 prudent in managing its DSM revenues?
3 A.Yes. Through my participation in Avista' s EEE
4 Advisory Board and the Northwest Energy Efficiency
5 Alliance (NEEA) Board and various committees, I have
6 observed Avista's conscientious approach to obtaining
7 energy efficiency for its customers. I have also
8 reviewed Avista's detailed DSM cost-effectiveness
9 reports. As stated by Mr. Hirschkorn on page 45 of his
10 pre-filed, direct testimony, Avista estimates that its
11 average, historical, 1S-year levelized utility cost of
12 electricity savings is 1.4ç per kilowatt hour (kWh).
13 Avista's similarly calculated utility cost of gas savings
14 is 25Ç per thermo (Hirschkorn erroneously states that
15 Avista's utility cost of gas savings is 14ç per therm.)
16 Both the electricity and gas costs of energy saved are
17 well below Avista's avoided costs. Although there may be
18 room for some minor disagreements among reasonable
19 evaluators about Avista's DSM cost-effectiveness
20 calculations, Avista's assumptions and calculations are
21 easily within a range of reasonableness.
22 Q.What changes did Avista propose to its
23 electricity DSM funding level at its May 19 EEE Board
24 meeting and again when it met with Staff on June 2, 2004?
25 A.Avista proposed reducing its electricity DSM
CASE NOS. AVU-E-04-1/AVU-G-04-106/21/04
ANDERSON (Di) 4
STAFF
1 surcharge from the current 1.95% to about 1.25% of base
2 revenues.(See page 10 of Exhibit No. 132.) This
3 equates to nearly a $1 million dollar reduction. Avista
4 also proposed that the surcharge be set on a cents-per-
5 kWh basis rather than on a percent of revenue basis as is
6 currently done.
7 Q.Does Staff agree with Avista's proposed
8 reduction in its DSM tariff rider?
9 A.Yes, Staff is willing to accept the reduction
10 in total DSM revenue collections contingent upon the
11 following two conditions:
12 1) Assurance by Avista that the reduction in DSM
13 revenues will not affect the Company's pursuit of cost-
14 effective energy efficiency measures, regardless of
15 whether such measures result in Avista DSM fund balance
16 being negative; and,
17 2) An increase in Avista's contribution to the Low
18 Income Weatherization (LIWA) program to a level
19 determined to be reasonable by the Commission in this
20 rate case.
21 Q.Has Avista indicated agreement to those two
22 conditions?
23 A.Yes. Jon Powell, Avista's DSM manager, assured
24 its EEE Advisory Board on May 19 that the proposed
25 reduction in DSM tariff rider revenue will not reduce the
CASE NOS. AVU-E-04-1/AVU-G-04-106/21/04
ANERSON (Di) 5
STAFF
1 availability of cost-effective energy efficiency
2 incentives and assistance for its customers.(See
3 pages 2 and 4 of Exhibit No. 132.) Furthermore, it is my
4 understanding that Avista will request that its DSM
5 surcharges be increased if its surcharge balance becomes
6 too negative for too long. Mr. Powell restated these
7 assurances to me after other Company representatives
8 reiterated the proposal at its meeting with the Staff on
9 June 2. Mr. Powell also suggested that Avista is not
10 opposed to a reasonable increase to its funding of LIWA.
11 Q.What have been the historical levels of
12 Avista's electricity DSM surcharges?
13 A.The DSM surcharge was initiated at 1.55% in
14 1995, decreased slightly to 1.503% in 1996, decreased
15 significantly to 1.0% in 1999 due to a large balance
16 being carried, and was increased to the current 1.95% in
17 June of 2001 shortly after Avista had begun rapidly
18 accelerating its DSM efforts in response to the western
19 states energy crisis.
20 Q.What is the history of Avista' s electricity DSM
21 revenue collections and expenses?
22 A.The table in Exhibit No. 133 shows Avista's
23 reported annual DSM revenues, expenses and fund balance.
24 Q.What general programs does Avista's electricity
25 DSM surcharge fund?
CASE NOS. AVU-E-04-1/AVU-G-04-1
06/21/04 ANDERSON (Di) 6
STAFF
1 A.Avista's electricity DSM surcharge funds all of
2 the Company's own electricity DSM programs, about
3 $250,000 for the Company's Idaho share of the Northwest
4 Energy Efficiency Alliance's (NEEA) market transformation
5 efforts, and a small portion of the company's maximum
6 allocation of $210,000 annually for the Lewiston
7 Community Action Partnership's (CAP) various low-income
8 programs, including weatherization.
9 Avista says that the $210,000 allocated to the
10 CAP is funded from a combination of Bonneville Power
11 Administration's Conservation and Renewable Discount (BPA
12 C&RD) funds and its own electricity and gas DSM funds.
13 Avista has also indicated that the CAP does not always
14 spend all of the $210,000 maximum allocation.
15 Q.Given Avista's claim that its electricity DSM
16 programs have bought energy efficiency at an average
17 levelized utility cost of i. 4ç per kWh, why is Staff
18 willing to accept Avista's proposed reduction in its DSM
19 surcharge?
20 A.As previously described, Avista has assured
21 Staff that the level of its DSM funding will not limit
22 its pursuit of cost-effective energy efficiency measures.
23 Avista's DSM surcharge historically has been increased
24 and decreased in response to changing needs. Avista has
25 been willing to ramp up its DSM efforts when it is cost-
CASE NOS. AVU-E-04-1/AVU-G-04-106/21/04 ANERSON (Di) 7
STAFF
1 effective to do so regardless of its DSM balance. Staff
2 believes that it is important for Avista to maintain
3 control of its DSM programs and funding levels especially
4 given its historically good stewardship of these programs
5 and funds. The reduction at this time better reflects
6 anticipated DSM expenditures and also provides some rate
7 relief as base rates will likely increase as a result of
8 this rate case. And, in comparison to the just completed
9 Idaho Power rate case, Avista's proposed DSM funding
10 level does not seem unreasonable.
11 Q.How do Idaho Power's DSM funding levels compare
12 to Avista' s proposal?
13 A.Idaho Power's DSM surcharge equates to about
14 0.5% of base revenues and collects about $2.7 million
15 annually, but that Company funds NEEA ($1.2 million for
16 Idaho) and LIWA ($1.2 million going forward) and some of
17 its DSM general administrative costs ($0.3 million) from
18 other sources. In total, Idaho Power will likely spend
19 about $5.4 million annually for DSM or about 1.1% of
20 total base revenues. Even with Avista's proposed
21 reduction to 1.25%, its DSM revenue as a percent of base
22 revenues would stiii be higher than Idaho Power's.
23 Q.Do you have a specific recommendation for
24 Avista's level of LIWA funding?
25 A.No. I am aware that Idaho Power's recently
CASE NOS. AVU-E-04-1/AVU-G-04-106/21/04 ANDERSON (Di) 8
STAFF
1 ordered increase to $1.2 million for LIWA for each of the
2 next three years (exclusive of any BPA C&RD funding)
3 equates to about $3 per Idaho Power customer ($1.2
4 million/400,000 total Idaho customers) .
5 Q.Are you suggesting that Avista increase its
6 electricity DSM funding for LIWA to $320,000 per year?
7 A.No. I am simply stating that amount is about
8 equivalent, on a per customer basis, to the $1.2 million
9 recently approved by the Commission for Idaho Power.
10 In comparing northern and southern Idaho LIWA
11 funding levels, it should be noted that Avista also
12 contributes to LIWA from its gas DSM, whereas
13 Intermountain Gas does not contribute to LIWA. And, as
14 previously mentioned, the CAP apparently does not always
15 spend all of the maximum $210, 000 that Avista authorizes
16 it to spend for weatherization and other programs.
17 I anticipate that the Community Action
18 Partnership Association of Idaho (CAPAI) will recommend
19 and support an appropriate funding level based upon a
20 needs assessment specific to Avista's service area and
21 the ability of the CAP office based in Lewiston and its
22 satellite offices in Grangeville, Moscow, Coeur d' Alene
23 and Sandpoint to efficiently and prudently increase their
24 weatherization efforts for low-income households.
25 Q.You mentioned that Avista also proposed that
CASE NOS. AVU-E-04-1/AVU-G-04-106/21/04
ANERSON (Di) 9
STAFF
1 its DSM surcharge be set as a cents-per-kilowatt-hour
2 (kWh) rate rather than being set as a percent of base
3 revenues. Does the Staff support this change?
4 A.Yes. The current DSM surcharge rates, although
5 set as a uniform percent of base revenue, are also shown
6 in the tariff as various cents per kWh by class of
7 service. I believe it would be simpler for the tariff to
8 list just the cents per kWh. Doing so would also
9 eliminate the need to change the tariff language
10 coincident with general rate changes. Exhibit No. 134
11 shows the current DSM surcharges and the proportional DSM
12 surcharges that result from a $1 million reduction.
13 Q.Are you recommending or suggesting any changes
14 to Avista's natural gas DSM surcharges, programs or
15 contribution to CAP for LIWA?
16 A.No.
17 Advanced Meter Reading (AM)
18 Q.Briefly describe Avista' s advanced meter
19 reading (AMR) proposal.
20 A.As described in more detail in Company witness
21 David Holmes' pre-filed, direct testimony, Avista is
22 proposing to install advancèd meter reading (AMR)
23 capability over a four-year period for all of its
24 electrici ty and gas customers in Idaho. Mr. Holmes says
25 AMR will result in reduced meter reading operating
CASE NOS. AVU-E-04-1/AVU-G-04-106/21/04
ANERSON (Di) 10
STAFF
1 expenses, will provide other immediate system benefits
2 and will provide much of the infrastructure necessary for
3 critical peak and/or time-of-use (TOU) pricing in the
4 future.
5 Q.Does Avista believe that the immediate savings
6 in operating expenses after completion of the AMR proj ect
7 will completely offset the capital costs?
8 A.Not quite. Mr. Holmes estimates the net gas
9 savings to be $63,000 per year or 0.12% of $51 million in
10 revenue (about a 7ç decrease to a $57 customer bill), but
11 that the electricity net cost would be an increase of
12 $189,000 or 0.13% of $146 million in revenue (about a 7ç
13 increase to a $50 customer bill). Mr. Holmes concludes
14 the estimated very small net revenue requirement increase
15 is more than offset by additional system benefits that
16 have not been monetarily quantified.
17 Q.Does Staff support Avista' s AMR proposal in
18 principle?
19 A.Yes. We believe one of the most important
20 future system benefits of AMR will be the capability to
21 implement critical peak TOU pricing. Staff anticipates
22 that critical peak TOU pricing will become cost-effective
23 for Avista by about the time the AMR system is completed
24 and that the additional components necessary for such a
25 pricing system should begin to be installed at that time.
CASE NOS. AVU-E-04-1/AVU-G-04-106/21/04
ANDERSON (Di) 11
STAFF
1 In other words, Staff believes it reasonable for Avista
2 to consider installing just the AMR facilities without
3 specific TOU pricing facilities at this time.
4 Q.Is it Staff's position that Avista's proposal
5 should be deemed a reasonable and prudent capital
6 investment?
7 A.No, Staff does not have sufficient information
8 to make a final judgment and Avista is not requesting
9 such judgment from the Commission in this case.
10 Q.What is Avista requesting of the Commission
11 regarding its four-year AMR proposal?
12 A.As explained by Avista witness Don Falkner op
13 page 46 of his pre- filed direct testimony, Avista wants
14 to be able to ~... treat AMR investment costs as a unique
15 construction project." As such, Avista proposes that its
16 AMR investment would be capitalized as construction work
17 in progress until after the entire metering project is
18 completed. At that time depreciation would begin and the
19 investment could be included in rate base should the
20 Company file an Application to do so.
21 Q.Does the Staff agree with Avista's proposed
22 deferred accounting treatment for its four-year AMR
23 implementation?
24 A.Staff believes that Avista will begin to
25 benefit from automated meter reading before completion of
CASE NOS. AVU-E-04-1/AVU-G-04-106/21/04 ANERSON (Di) 12
STAFF
1 the entire four-year AM installation. However, to
2 promote Avista's implementation of AMR at this time,
3 Staff is not opposed to the deferred accounting treatment
5
4 proposed by Mr. Faulkner.
Q.Does this complete your direct testimony?
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CASE NOS. AVU-E-04-1/AVU-G-04-106/21/04 ANDERSON (Di) 13
STAFF
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Case No. AVU-E-04-1/
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6/21/04 Page 1 of 13
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Case No. AVU-E-04-1I
A VU-G..4-1
L. Anderson, Staff
6121104 Page 7 of 13
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Case No. A VU-E-04-1/
AVU-G-04-1
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6/21/04 Page 9 of 13
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Case No. AVU-E-04-1/
AVU-G-04-1
L. Anderson, Staff
6/21/04 Page 11 of 13
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Exhibit No. 132
Case No. AVU-E-04-1/
AVU-G-04-1
L. Anderson, Staff
6/21/04 Page 12 of 13
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Avista's Electrcity DSM Revenues, Expenses and End-of-Year Balances for Idaho
Year Revenuesw.Expenses inc!.End of Year
Interest LIWA&NEEA Balance
1999 $ 1,640,637 $ 1,588,759 $775,920
2000 $ 1,237,548 $ 2,006,370 $7,098
2001 $ 1,672,173 $ 5,214,921 ($ 3,535,650)
2002 $ 2,660,353 $882,959 ($ 1,758,256)
2003 (10 mo.)$ 2,236,728 $738,956 ($ 318,869)
Exhibit No. 133
Case No. A VU-E-04-1/
AVU-G-04-1
L. Anderson, Staff
6/21/04
..
-
Avista's Curent and Proposed DSM Surcharges in Idaho
Schedule Curent Rate Reduced Rate
1 residential O.i04~ /kWh O.067~ / kWh
11 & 12 O.i40~ /kWh O.090~ /kWh
21 &22 O.iOO~ /kWh O.064~/kWh
25 O.0684~ / kWh O.044~ /kWh
31 &32 O.i02~ /kWh O.065~ /kWh
41- 49 1.95% of bil 1.25% of bil
Revenue $2.7 millon $ 1. 7 millon
Exhibit No. 134
Case No. AVU-E-04-1/
AVU-G-04-1
L. Anderson, Staff
6/21/04
.4
-
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 21ST DAY OF JU 2004,
SERVED THE FOREGOING DIRECT TESTIMONY OF LYNN ANDERSON, IN
CASE NO. AVU-E-04-l/AVU-G-04-1, BY MAILING A COpy THEREOF, POSTAGE
PREPAID, TO THE FOLLOWING:
DAVID 1. MEYER
SR VP AN GENERA COUNSEL
AVISTA CORPORATION
PO BOX 3727
SPOKA WA 99220-3727
KELLY NORWOOD
VICE PRESIDENT - STATE & FED. REG.
A VISTA UTILITIES
POBOX 3727
SPOKA WA 99220-3727
CONLEY E WAR
GIVENS PURSLEY LLP
PO BOX 2720
BOISE ID 83701-2720
DENNIS E PESEAU, PH. D.
UTILIT RESOURCES INC
1500 LffERTY ST SE, SUITE 250
SALEM OR 97302
CHAES L A COX
EVANS KEAN
111 MA STREET
POBOX 659
KELLOGG ID 83837
BRA MPURY
ATTORNY AT LAW
2019 N 17TH ST
BOISE ID 83702
~::.kQâ.
SECRETARY
CERTIFICATE OF SERVICE
f:;~ i::. (~ E,~"lV'STA.
Corp.Iii!';,'," it i", ',"", 8 (' 10 3"
iJJvtl HUb -. ('Y'1,:b
IDAHG ¡.u, ,.,.," ','
UTILITIES ('i'" l':"t"""'"" " , vVf'l1¡Vilo;.lu i\
D. Jewell
ommission Secretar
Idaho Public Utilities Commssion
472 W. Washington Street
Boise, ID 83702
Re: Case Nos. A VU-E-08-01 and A VU-G-08-01
Avista's Motion for Approval of Stipulation
Enclosed for filing with the Commssion in the above-referenced docket are the original and seven
copies of Avista's Motion for Approval of Stipulation dated August 7, 2008.
The pares to'the Stipulation intend to file testimony in support of the Stipulatiòn.,
Sincerely,
?' ,J#' i.
Kelly O. Norwood
Vice President
Enclosures
c: Service List
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that I have this 7th day of August, 2008, served the Avista's
Motion For Approval of Stipulation in Docket No. AVU-E-08..01 and AVU-G-08..01
upon the following' parties, by mailng a copy thereof, propert addressed with
postage prepaid to:
Jean 0 Jewell, Secretary
Idaho Public Utilties Commission
Statehouse
Boise, 1083720-5983
Scott Woodbury
Deputy Attorney
Idaho Public Utilties Commission
472 W. Washington
Boise, 10 83702..0659
Brad M. Purdy
Attorney at Law
2019 N 17th Street
Boise, 10 83720
Conley E. Ward
Givens Pursley LLP
602 W. Bannock Street
Boise, 10 83702-2720
~, atty Olsness
Rates' Coordinator
David J. Meyer, Esq.
Vice President and Chief Counsel of
Reguatory and Govemmenta'Affairs
A vista Corporation
, 1411 E. Mission Avenue
P. O. Box 3727
Spokane, VVashigton 99220
Phone: ' [phone], Fax: [phone]
t".:i r.C""r: ,: \j F rr\t- ".. 'I '_',
2IJOB AUG -8 'PM to: 36
IDAHO ¡:v,;o\,;,
UTIUTIES COMMISSlOi \
BEFORE THE IDAHO PUBLIC UTIITIS COMMSSION
IN TH MATTER OF THE APPLICATION
OF A VISTA CORPORATION FOR THE
AUTHORITY TO INCREASE ITS RATES
AND CHAGES FOR ELECTRIC AND
NATURA GAS SERVICE TO ELECTRC
AND NATU GAS CUSTOMERS IN THE
STATE OF IDAHO
)
) CASE NOS. A VU-E-08-01
) A VU-G'-08..0 1
)
) MOTION FOR APPROVAL OF
) STIPULATION
)
COMES NOW, Avista Corpration ("Avista" or "Company"), the
Commssion Sta and the other Pares to the setlement Stipulation, and hereby move
the Commssion for an Order accepting the settlement Stipulation fied'herewith. RP 56;
272; 274. Ths Motion is based on the followig:
1. On April 3, 2008, Avista fied an Application with the Commssion for
authority to increase revenue for electrc and natual gas service in Idao by 16.7% and
5.8%, respectively. If approved, the Company's revenues for electrc base retail rates
would have increased by $32.3 milion anualy; Company revenues for natual gas
service would have increased by $4.7 millon anualy. The Company requested an
effective date of May 5, 2008 for its proposed electrc/gas rate increase. By Order No.
30528, dated April 16, 2008, the Commission supended the proposed schedules of rates
Motion for Approval of Stipulation Page 1 of3
and charges for electrc and natu gas servce for a period of thrt (30) days plus five
(5) months from May 5, 2008, or until such tie as the Commission entered an Order
accepting, rejecting or modifyng the Application in this matter.
2. Petitions to intervene in ths proceding were filed by Potlatch Corporation
("Potlatch") and Communty Action Parership Association of Idao ("CAP AI"). By
varous orders, the Commission grte these inteentions. See, IPUCOrder Nos.
30550 and 30551.
3. Public workshops for Avista customers were held on July 23,2008 in
Moscow, Idao, and on July 24, 2008 in Coeur d Alene, Idao, for the purose of
explaining the Company's Application and in order to provide an opportty for
customers to ask questions of Sta.
4. Based on settlement discussions, the Pares whose signatues appear on
the Stipulation have agreed to resolve and settle all of the issues in the case. A copy of
the signed Stipulation evidencing that settlement is enclosed as Atthment 1.
5. The Pares recommend that the Commission grant ths Motion and
approve the Stipulation in its entirety, without material change or condition, puruat to
RP274.
6. The Paries respectfly request an evidentiar hearg for the purose of
presenting the Stipulation and intend to pre-fie supportg testimony in advance thereof.
In addition, it is understood tht the Commission may schedule hearngs for the receipt of
public testiony at a tie and place of its own choosing.
7. As noted in the Stipulation, all of the Pares agree that the Stipulation is in
the public interest and tht all of its terms and conditions ar fair, jus and reasnable.
Motion for Approval of Stipulation Page 2 of3
NOW, THEREFORE, the Pares respectfly request that the Commssion issue
a fial order in Case Nos. A VU-E-08-0 i and A VU-G-08-0 i :
i . Grting this Motion and accepting the Stipulation (Attchment i), in its
entiety, without material change or condition; and
2. Authonzing the Company to implement revised taff schedules designed'
to recover $23, i 63,000 in additional anua electrc revenue and $3,878,000 in
additiona anua natual gas revenue from Idaho customer consistent with the terms of
the Stipulation; and
3. Authorizing that revised taff schedules be made effective October i,
2008.
¡-LJ
Respectfuly submitted ths -Zay of August, 2008.
~l/-
Vidier ·
Attorney for Avista Corporation
Motion for Approval of Stipulation Page 3 of3
ATTACHMENT 1
David J. Meyer, Esq.
Vice President and Chief Counsel of
Reguatory and Governenta Affairs
A vista Corporation
1411 E. Mission Avenue
P. O. Box 3727
Spokane, Washington ,99220
Phone: [phone], Fax: [phone]
BEFORE TH IDAHO PUBLIC UTILITIES COMMSSION
INTHE MATTR OF TH APPLICATION
OF AVISTA CORPORATION FOR TH
AUTHORITY TO INCREASE ITS RATES
AN CHAGES FOR ELECTRIC AN
NATURA GAS SERVICE TO ELECTRC
AN NATU GAS CUSTOMERS IN THE
STATE OF IDAHO
)
) CASE NOS. A VU-E-08..01) AVU-G-08-01
)
) STIPULATION
)
)
Ths Stipulation is entered into by and among Avista Corporation, doing
business as A vista Utilties ("A vista" or "Company"), the Sta of the Idao Public
Utilties Commission ("Sta'), Potlatch Corporation ("Potlatch"), and the Communty ,
Action Parership Association of Idaho ("CAP AI"). These entities are collectively
referred to as the "Paries," and represent all paries in the above-referenced cases. The
Paries understd this Stipulation is subject to approval by the Idao Public Utilties
Commission ("IPUC" or the "Commssion").
I. INTODUCTIQN
1. The terms and conditions of ths Stipulation ar set fort herein. The Pares
agree that ths Stipulation represents a fai, just and reonable compromise of the issues
raised in the proceeding and that ths Stipulation and its acceptace by the Commssion
represent a reasonable resolution of multiple issues identified in this matter. The Pares,
Stipulation Page 1 of12
therefore, recommend tht the Commission, in accordace with RP 274, approve the
Stipulation and all of its terms and conditions without matenal change or condition.
II. BACKGRQUND
2. On April 3; 2008, Avista filed an Application with the Commssion for
authonty to increae revenue from electrc and natu'gas serce in Idao by 16.7% and
5.8%, respectively. If approved, the Company's revenues for electrc base retal rates
would have increased by $32.3 milion anualy; Company revenues for natu gas
service would have increased by $4.7 milion anually. The Company requested an
effective date of May 5, 2008 for its proposed electrc/gas rate increae. By Order No.
30528, dated April 16, 2008, the Commssion suspended the proposed schedules of rates
and charges for electrc and natual gas servce for a penod of th (30) days plus five
(5) month, from May 5, 2008, or until such time as the Commission entered an Order
accepting, rejecting or modifyng the Application in ths matter.
3. Petitions to intervene in ths proceedig were filed by Potlatch and
CAP AI. By varous orders, the Commission grted these interventions. See, IPUC
Order Nos. 30550 and 30551.
4. Public workshops for Avista customers were held on July 23, 2008 in
Moscow, Idaho, and on July 24, 2008 in Coeur d' Alene, Idaho, for the purose of
explaining the Company's Application, , and in order to provide an opportty for
customers to ask questions of Sta.
5. On July 28,2008, Commssion Sta filed with the Commssion a Notice
of Intent to Engage in Settement Discussions. RP 272. A settlement conference was
Stipulation Page 2 of 12
..subsequently held in the Conuission offces on July 31, 2008, and was attended by
representatives of all Pares.
6. Based upon the settement discussions among the Pares, as a compromise
of positions in this case, and for other consideration as set fort below, the Pares agree
to the followig terms:
DI. TERMS OF THE STIPULATION
7. Revenue Requiement. The Paries agee that Avist shal be allowed to
implement revised taff schedules designed to recover $23,163,000 in additional anua
electrc revenue and $3,878,000 in additiona anua natu gas revenue, which represent
an 11.98% and 4. 7% increae in electrc and natual gas anual base taff revenues,
respectively. In determining these revenue increases, the Paries have agreed to varous
adjustments to the Company's filing, which are sumard in the Tables below and are
reflected in Appendix I and will be fuer explained in prefied testimony to be filed by
the Pares in support of the Stipulation. In addition, certn elements of the revenue
increases are fuer discussed immediately below:
(a.) Cost of Capita. The Pares agree that Avista's cost of capital shall be
determined using a capital strcture consisting of 47.94% common stck equity, and
52.06% long-term debt. Avista's authorized retu on equity shal be 10.20%; the cost of
debt shal be 6.84%. These components produce an authorized rate of retu of 8.45%.
(b.) Other Adjustments. The Sumar Table of Adjusents, as set fort
immediately below, describes the remaiing revisions to the Company's originally-filed
electrc and natual gas revenue requirements:
Stipulation Page 3 of 12
Revenue
Requirment Rate Base
I' Amount As Filed $32328 $ 54.266
SUMMARY TABLE OF ADJUSTMENTS TO ELECTRIC REVENUE REQUIREMENT
OOOs of Dollars
Adiustments:
Return on Equity Adjust return on equity to 10.20%(2,485)0
Power Supply -Pnest Rapidslanapum Contrct $(614)(735)
(use average of '08 & '09 figures)0
-Elimination of PPM Wind integration costs $(109)
-Reflec Kootenai Transmission contrct $( 12)
Labor-Non-Exec Remove 50% of 2009 non-executive labor expense (296)0
Labor-Executive Remove 2009 executive labor expense (39)0
Transmission Rev/Exp Remove 2009 revenues and expenses 81 0
Capital Additions 2008 Includes capital investment and depreciation
through December 2008 152 1,327
Asset Management Remove 50% of 2009 expenses (489)0
Spokane River Relicensing Remove adjustment (establish deferral)(2,631)(12,039)
Confidential Litigation *Remove adjustment (establish deferral)(1,514)(6,264)
Colstnp Mercury Emission O&M Remove adjustment (533)0
Executive Incentives Remove executives' incentives (103)0
CS2 Levelized Adjustment Remove 2009 deferrd return (114)0
Carbón Financíallnstruments Add net revenues frm sale of CFls
(CFls)(427)0
Miscellaneous A&G Expenses Remove vanous A&Gexpenses, including dues,(502)0
sponsorships, A&G study, 50% of Directors &
Offcers' insurance, and 50% of Board of Director
expenses
Production Propert Flow through impact of Production & Transmission 320 997
,adjustments
Restate Debt Interest Flow through impact of Rate Base adjustments 350 0
Total Adjustments $19.165)$ 117,979)
I Adjusted Amounts 1$ 23,163 $530,287 I
* Please see Andrews' Direct unredacted testimony at Pages 32-33.
Stipulation Page 4 of12
SUMMARY TABLE OF ADJUSTMENTS TO NATURAL GAS REVENUE REQUIREMENT
OOOs of Dollars
Revenue
Reaull'Ment Rate Base
I Amount As Flied $4.725 $85.690-
Adiustment:,
Return on Equity Adjust return on equit to 10.20%(389)0Labor-Non-Exec Remove 50% of 2009 non-executive
labor expense (73)0
Labor-Executive Remove 2009 executive labor
exoense (9)0Capital Additions 2008 Includes capital investment and
depreciation through, December
(103)(531)2008
Incentives Remove executives' incentives (23)0Miscellaneous A&G Expenses Remove various A&G expenses,(260)0
including dues, sponsorships, A&G
study, 50% of Directors & Offcers'
insurance, and 50% of Board of
Director expenses
Rèstate Debt Interest Flow through impact of Rate Base
adjustments 10 0
Total Adjustments $(847)$15311
I Adjusted Amounts I $3,878 1$ 85,159 I
8. Rate Effective Date. The Pares request that the Commssion issue its
order approving the retal rates contaed in ths Stipulation to become effective October
1,2008.
9. Accounting Treatment for Cert Costs.
(a.) Spokane , River Relicensing - The Company included the processing costs
associated with its Spokae River relicensing efforts, which expenditus included actual
life-to-date costs from Apól 2001 though December 31, 2007, and 2008 pro forma
expenditues though December 31,2008. (See Andrews' Direct Testimony at page 32)
Although the Company anticipates receivig a final license from the Federal Energy
Regulatory Commission ("FERC") in the near futu, tht has yet to occur. The
Stipulation Page 5 of12
relicensing costs will remai in CWIP (Constrction Work in Progress) and the
Company will' continue to accrue AFDC until issuace of the licene~ at which time the
relicensing costs will be trsferred to plant in service and depreciation will begi to be
recrded. The Pares have agee to defer as a reguatory expense item (in Account 186
- Miscellaneous Deferred Debits) on the Company's balance sheet depreciation
associated with Idaho's shae of the aforementioned relicensing costs and related
protection, mitigation, or enhancement expenditues, until the ealier of twelve (12)
months from the date of the issuace of the license or the conclusion of Avista's next
general rate case ("GRC"), together with a carng charge on the deferral; as well as a
carg charge on the amount of relicensing costs not yet included in rate base. The
caring charge for deferrals and rate base not yet included in establishig rates would be
the customer deposit rate at tht time (presently 5%).
(b.) Confdential Litigation - Company Witness Andrews describes
confidential litigation at pages 32 and 33 of her prefied diect testimony (unedacted).
Inasmuch as tht matter is still pending and has yet to be finally resolved, but is expected
to reach resolution in the near futue, the Pares have agreed to defer as a regulatory
expense item (in Account 186 - Miscellaneous Deferred Debits) on the Company's
balance sheet depreciation associated with Idaho sha of the aforementioned costs with
a carg charge on the deferr as well as a carg charge on the amount of costs not
yet included in rate base for subsequent recovery in rates. The carng charge will be
the customer deposit rate (presently 5%). Ths deferr, together with a carg chage,
will continue until the earlier of twelve (12) month from the date of resolution of the
litigation or until the conclusion of Avist's next genera rate case (ORC).
Stipulation Page 60f12
(c.) Montaa Riverbed Litigation- On November 1,2007, Avist filed an
Application with the Commission (Case NO.A VU-E-07-10) requesting an accounting
order authorizig deferr of settement lease payments and interest acs relatirtgto
the recent settlement of a lawsut in the State of Monta over the use ófthe riverbe
related to the Company's ownership of the Noxon Rapids and Cabinet Gorge
hydroelectrc projects located on the Clark Fork River. The Commission, in its Order
No. 30492, authorized the deferrl of settlement lease payments and delayed a decision
on inteest, until the matter was addressed in this genera rate filing. The Pares have
agreed to the Company's requested amortiztion of costs, together with recovery of
accrued interest on the Idao shae of deferrals at the cusomer deposit rate (presently
5%).
(d.) Revenues Associated with Sale of Carbon Finacial Intrents (CFIs)-
On May 22, 2008 A vista filed a request with the Commission (Case No. A VU-E-08-2) to
defer the revenues associated with the sale of Carbon Financial Instrents (CFIs) on the
Chicago Climate Exchange. The Company's Application was approved on Augut 5,
2008 in Order No. 30610. Idaho's share of the revenues, net of expenses, from the CFI
sales is $850,571. These dollar will be amorted over a two-year period beginnng in
the calenda month of the effective date of new retal rates resulting from ths Stipulation,
with a carg charge on the unortd balance at the custmer deposit rate. The
revenue requiement included in this Stipulation has been reduced for the CFI revenues,
in order to flow these benefits though to customers.
10. PCA Authorized Level of Expense. Appendix 3 sets fort the agreed-upon
level of power supply expeiie, retal load and revenue credit resulting from ths
Stipulation Page 70f12
Stipulation, tht will be used in the monthy Power Cost Adjustment ("PCA") mechanism
calculations.
1 1. Prudency of Energy Effciency Expeditus. The Pares agree tht
A vista's expenditues for electrc and natual gas energy effciency programs from
November 1, 2003 though December 31, 2007 have ben prudently incurd.
12. Rate Spread. Appendix 2 shows the impact on each service schedule of
the agreed-upon electric and natur gas increases. The proposed electrc revenue
increase of$23,163,000 represents an overall increase of 1 1.98% in base rates, and with
one exception, is spread on a unform percentage basis to all schedules. Schedule 25P
(for Potlatch's Lewiston plant),however, will receive an increase of 10.36%, in orderto
reflect a Schedule 25P rate that is no higher th the talblock rate of Schedule 25. With
this chage, the relative rate of retu for Schedule 25P would move approximately one-
half way toward unty, more consistent with the movement of other servce schedules.
All other'schedules will receive a 12.33% increas.
The spread of the increased natual gas revenue requirement of $3,878,000 is set
fort in Appendix 2, and represents an overall increae of 4.7% in base rates. It reflects a
reduction to what the Company had proposed by way of an increase for each of the gas
service schedules proportional to the reduction in the overall increase.
13. Rate Design. The Paries agee to changes in the electrc customer and
demand charges as set fort in the Company's filing, and sumarzed in Appendix 2.
Ths includes an increase in the residential monthy basic charge from $4.00 to $4.60.
The energy rates with each electc serce schedule are increaed by a unform
percentage.
Stipulation Page 8of12
With respect to natu gas rate design, the Paries agree to apply the increase in
rates withn each servce schedule in the same maner as proposed by the Company. ' The
monthy basic chage for the residential schedule will increase from $3.28 to $4.00, as
proposed by the Company.
14. Customer-Related Issues.
(a.) Low-Income DSM Fundig - At present, $350,000 per year is
provided to Idaho service (CAP) agencies for proposed fuding oflow-income Deman..
Side Mangement (DSM). The Pares agree to increase the anua level of fuding to
$465,000 for such progrs (which includes adinistrative overhead). The continuation
and level of such fuding will be revisited in the Company's next general rate filing.
(b.) Funding for Outrach for Low-Income Conseration -The Paries
agree tht anua fuding in the amount of $25,000 will be provided to Idaho (CAP)
agencies for the purose of underwting the dedication of agency personnel tö assist in
low-income outreach and education concernng conservation. The dollars will be fuded
though the DSM Tarff Rider (Schedules 91 and 191), and will be in addition'to the
$465,000 of Low-Income DSM Funding. The continuation and level of such funding will
be revisited in the Company's next general rate filing.
Stipulation Page 90f12
..
(c.) Establishment of Generic Workshops- Avista agres to support and
actively parcipate in any Coinssion-estblished workshops for the purse of
examinig issues surounding energy afordabilty and cusomers' ,abilty to pay energy
bils with respect to all jursdictional utilities. As par of ths process, A vista agrees to
explore the feasibilty of establishing a Low-Income Rate Assistace Program (LIRA),
or similar program, to assist low-income residential customers in Idao.
15. The Paries agree that ths Stipulation repreents a compromise of the
positions of the Paries in this case. As provided in RP 272, other than any testimony
filed in support of the approval of ths Stipulation, and except to the extent necessa for
a Par to explain before the Commssion its own sttements and positions with respect to
the Stipulation, all statements made and positions taen in negotiations relating to ths
Stipulation shal be confdential and will not be adssible in evidence in ths or any
other proceeding.
i 6. The Paries submit ths Stipulation to the Commission and recommend
approval in its entirety pursuat to RP 274. Pares shall support this Stipulation before
the Commission, and no Par shall appeal a Commission Order approving the
Stipulation or an issue resolved by the Stipulation. If ths Stipulation is challenged by any
person not a par to the Stipulation, the Pares to ths Stipulation reserve the right to, fie
testimony, cross-examne witnesses and put on such case as they deem appropriate to
respond fuly to the issues presented, including the right to raise issues that are
incorporated in the settlement terms embodied in ths Stipulation. Notwthstading this
reservation of rights, the Paries to this Stipulation agre that they will continue to support
the Commission's adoption of the terms of ths Stipulation.
Stipulation Page 10 of12
.17. If the Conission rejects any par or all of ths Stipulation or imposes any
additional material coiiditions on approval of ths Stipulation, eah Par reserves the
right, upon wrtten notice to the Conission and the other Pares to ths proceedig,
withn 14 days of the date of such action by the Commission, to withdraw from ths
Stipulation. In such case, no Par shal be bound or prejudiced by the terms of ths
Stipulation, and each Par shal be entitled to seek reconsideration of the Commssion's
order, fie testimony as it chooses, cross-examine witnesses, and do all other things
necessar to put on such case as it deems appropriate. In such case, the Paries
immediately will request the prompt reconvenig of a preheag conference for puroses
of establishig a procedural schedule for the completion of the case. The Paries agree to
cooperate in development of a schedule that concludes the proceeding on the earliest
possible date, takng into account the needs of the Paries in parcipating in heangs and
preparg testímony and briefs.
18. 'The Paries agree that ths Stipulation is in the public interest and that all
of its terms and conditions are fair, just and reasonable.
19. No Par shall be bound, benefited or prejudiced by any position aserted
in the negotiation of ths Stipulation, except to the extent expressly stted herein, nor
shal ths Stipulation be constred as a waiver of the rights of any Par uness such rights
are expressly waved herein. Execution of ths Stipulation shal not'be deemed to
constitute an acknowledgment by any Par of the validity or invalidity of any parcular
method, theory or principle of regulation or cost recovery. No Par shall be deemed to
have agred that any method, theory or priciple of reguation or cost recovery employed
in arving at ths Stipulation is appropriate for resolving any issues in any other
Stipulation Page i i of12
..
proceeding in the futue. No fidings of fact or conclusions of law other th those stated
herein shall be deemed to be implicit in ths Stipulation.
20. The obligations of the Paries under ths Stipulation are subject to the
Commission's approval of ths Stipulation in accordance with its terms and conditions
and upon such approval being upheld on appeal, if any, by a cour of competent
jursdiction.
21. Ths Stipulation may be executed in counterpars and each signed
counterpar shall constitute an original document.
,1'1DATED this 2:day of August, 2008.
A vista Corporation Idao Public Utilities Commssion Sta
BY--2Z
Attorney for A vista Corpration
By
Scott Woodbur
Attorney for !PUC Sta
Potlatch Corporation Communty Action Parership Association
By By
Bra M. Purdy
Stipulation Page 12 ofii
..
ar exp1'sly waived herein. Execion of this Stipulation shall not be deemed to
constitute an acknowledgrntby any Pary of the validity or invalidity of any parcular
method. theor or principle of regulation or cost reovery. No Par shall be deemed to
have agr that any metod. theory or prnciple of reguation or cost (every employed
in mrving at this' Stipulation is appronat for resolving any issues in any other
proeding in the futue. No fmdis of fact or conc1usioni: of 1awother than those stated
herein sha be deemed to be implicit in tls Stipulation.
20. The obligations of the Pares unde this Stipulation ar subject to the
Commssion's approval ofthii: Stipulaton in acrdance with its term and conditions
and upon such approval being upheld on ap, if any, by a cour of competent
jurdiction.
2 i. This Stipulation may be executed in counterpar and eah signed
countear shall constitute an original document.
DATED ths :Jday of August, 2008.
A vista Corpration Idaho Public Utilities Commission Sta
By By
David J.Meyer
Attorney for A vista Coiporation
Scott Woodbur
Attrney for IPUC Sta
Potlatch Corporaton Community A~tion Parterhip Association
By
?~~BY/~.~_~--
Stipulation Page 11 of 12
08/0712008 THU 14: 52 (TX/RX NO 5448) Il 002
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APPENIX 2
.-
AViSTA UTIUES
lDAMO ELRIC
PREST ANDPROPOD,RATE COPONEHTSBYSCHEOUL
Pre
Ba Tar , tRM&, "P.,nt
$p. Bate. 'Ot AdÚttBlJlni Ra(b) (a). (ô)(a)
Reidential S~ce.SChedule 1
Basic Charge
Ene Chlge:
Fir 60 kWb
All over $0 kWßs'
Gen!Se .'Schedulè11BasiCbl
Ene Cham~¡
Firs3,65QkWtls
AU over3~65 kWhsDertGli'l!:;
20kW òrlè
OVr20kW
$4,00 $4.00
$(t0582 ($O;OO06)$O:05
$0;001'2 ($.0.00206)'$0.06
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nó:ii.
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bm Glml;§(¡..,SCulé 21,Energy Cï.:' 'FIrs i5Ø.ØQkWhs $0.04
Ai,I ov 250.000 kWti $ò.041
Dèand Ch:
50 kW ,or IE!
QvrSOkW
Primary VòltDlsnt
$OOO ,$O,Q514Ø
JQ(0ô$Õ.Q43i
$250.00
$3.00lW
$O.201W
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EXlLargfGend 8e-.saédiilê 25Ene~ê:' """',',
Ftr'SO,OOkWhs $O;O~, $Q()~1j lQ.01~~1,Allover5Ø.W(1Nh$ $O,~ $tt0ó319 $O.QStl
Qe,Ghlrg:3.00kvaorles
pil~a~ ~1oÜrit
Annual Mium,
$$00:-:.:-1- .".
$2.7'5fvå$O.2Ô
Pf~ $5~h410
$9tQ'
$2.151
~$Oo2W
Pof -Sçhedule 25
Etiig Charge; ,
all kWh'SOemand'~
3,OO'kvs or'les
Over 3./Jk!is
Primary Volt Plsont
Annual'Mimum '
$Q.Ó3404 $O.Ô031å$O.0'tti
$SiaOO
~~W
Pres: $42,44
'S.OO~:t5ìe$ó
pumpbI1Sèè8. :Sèe:3
Bå$iCC~e '
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Rtt165 kWIkWh
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$Ö.OO$5 $'()~003'O;06$$$
$Ö.~$O,ò0343 '$0;1)5932
Geal Pt PropRaBlUinBa Tar
Increa ß!Rate
(e)(f)(g)
$0.60 $4.60 $460
$O~OO71l $0.0$$0,0652
$0.00_$o.øn1é $0.07416
$0.5
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$275.00
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$275.00
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$10.000
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$1tOOó $10.000 $10,000
$O.5óå $3.251va $325/kva
$O.2OW $O;20!k
$$2.42
$0.50 k5Ø $6;5
$0.0015 $0.01113 $0.07310
$0.0065 $0.06627 $0.08284
(1) lnøesall' re"te ";¿~~ SCledul ".Tem~Pê,AdI,~Îê:91..~di:ffc.Øt RtdeArJj.., ' , , ' p ra 8uJ...'-.... " , ø, , ". ""..,7 ,', ,~"" ' " ,', ., ',,' "
an6Sóle59detl& FåtmE~ Rä Adj;($d¡,1 ~. '
" ' Appebt2
Case No. Avuë~B.1 &,.AVOO~1.. 'PSge2of4
..
AYlTAUTILmeS:t
1000$A$:
PR.,PnseøINClEÄè:llYSf$\lCESCHl:OOLE
12f,0lfSeNP$ l)àG'$siR31, 201
(OOO øf DoUai')
Line
No:
Týpof
SåNtee
(a)
~seTari
Revnle
ScheiJle Undêr Preent
Numbe R$f1 i
, (I))' (e)
Bas Tari
Pro~' Revnu~
General Under Propoed
lnçà$ RatM(d) , , (e)
Baa
TariPèrcIncre
(1)
1 Gënet Ser 101 $63,201 $3,375 $6,582 5.3%
2 Lart¡e$enf$e 111 $1l.~~$4$-$18,$5 2.t~
a 'ntemptlb..~,131 $.67 $15 $$82 4.ø%
4 Ttaortlse 146 $417 $3 $420 0,,8%
5 Speìål Connót 148 '211 '¡Q $211 0;0%
6 Totl $82,071 $3,818 $85,950 4.7%
(1)' IncudesPurçh~seAØlu~ Scul'1,sa., ~c:udea ot ràtè adjOstrnèits.
ApPdiX2
Casef.();AV1E.;$;,1 &,.AVU~~1",',' Pag8of4
.
..
AVlSA,o:S
,~,"CW,
PRAN PROO$im RAte COEN BYSCHEbûL,
Gè.,rá Proll Pro
Base Prel Pres Ræ SOh.1i1 BiIins Ba~RatcAdi.2)BlRate 1il ~ß!ß!
(8)(b)(e)(d)(e)(f)(9)(ll)
S$OraSsrAA - Sched!e,'101Basic Char ,$328 $3.2 $0.7.2 $4.0 $400 22.0%Usae-Che:Al ths $1.108 ($O.oo32e)$1'0560,$O.OS087 '$1;1sØ7 $1.5$4.1J
Ll Gøerlsery '. SCiA 111
Usage Chrg:Firs 20 thS'
20Q - 1,00 thll
tOO. 1Ô,oO fts,Al~10ioo:~Mlnlmudi,~mônl.perth
$1,0l1~7
$1.0731~
$ti.97Ôt1
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($Q.Q9)$l,()ss $0.01087 ($0;0010)$1.0783 $1.08 1.0%
($0;1)064)$09613 $O.Ð423 ($f.0ö0)$1.00 $1.01100 4.1%
($.OO~)~~96t3 $O.ø ($0,0010),$O,.'$0.97100 (U)ØAi
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(loA~tø):$O~~'$O.ætn O.O~
$1$'~$(~
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FirSt 200:ts
200 -5(tteis'
500 -1,00 tbs
1.00-10,OQthers
Anov,1Ô~OOÖther
Mll'mum Charge:
pemonlhP8ith $386.13 $å.13
$O:3 ($Q;002.) $0,30170 ($z:iU1)
$Ø.O~$1.140OJ S1.1~e.o%.
$0.000 S:Ml183i $1.08 0.3%
$Ì.OQ08 $1.~$1:0e4 1.0%
$0.00018 $1.00 $1.1100 4.1%
$0.0008 $0.96526 $lt911lK 2.0%
$"IØ7.S $1$1,62 -5ß%
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$0.9169 $0.90
$2;00 $2,00
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All Ther '$0.87157 ($.ø.oQ $0,-8$9
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(1) IrcludSéedülè'la6. ~ed Ga CØ,Mj.
(2) 1iiSted 15$ ,.$a'RatiAdI.; ~e 19"" ~E1~Rir AC.
Appex2
CâNo. AW;;!ËoÖ8-1 & AVU~Q1Pag4af4
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BEFORE THE
r"" ..... .... '.C',,
¡''';.:.... '.,,; ;
,..'. '"')10: 21,'~,-
IDAHO PUBLIC UTILITIES COMMIS~tt/F'"
.i ~ "",'J ,. t r~-" ': r. ", r. ,~'_, f
~J t ~i.¡ i d":~' .~.. ,..;;¡
IN THE MATTER OF THE APPLICATION )
OF AVISTA CORPORATION FOR THE ) CASE NO. AVU-E-oS-1
AUTHORITY TO INCREASE ITS RATES) AVU-G-OS-1
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC )
AND NATURAL GAS CUSTOMERS IN THE )STATE OF IDAHO )
)
)
DIRECT TESTIMONY OF RANDY LOBB
IN SUPPORT OF STIPULATION
IDAHO PUBLIC UTILITIES COMMISSION
AUGUST 22, 200S
..
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2 the record.
Q.Please state your name and business address for
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A.My name is Randy Lobb and my business address is
472 West Washington Street, Boise, Idaho.
Q.By whom are you employed?
I am employed by the Idaho Pulic Utilities
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7 Commission as Utilities Division Administrator.
A.
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Q.What is your educational and professional
background?
A.I received a Bachelor of Science Degree in
Agricultural Engineering from the University of Idaho in
1980 and worked for the Idaho Department of Water Resources
13 from June of 1980 to November of 1987. I received my Idaho
14 license as a registered professional Civil Engineer in 1985
15 and began work at the Idaho Public Utilities Commission in
16 December of 1987. My duties at the Commission currently
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25 Q.What is the purpose of your testimony in this
CAE NO. AVU-E-08-1/AVU-G-08-108/22/08 LOBB, R. (Di) 1
STAFF
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1 case?
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A.The purpose of my testimony is to describe the
principal components of the filed Stipulation (the Proposed
Settlement) and to explain the rationale for Staff' B
support.
Q.Please summarize your testimony.
Staff believes that the comprehensive ProposedA.
Settlement agreed to by all parties is in the public
interest, is just and reasonable and should be approved by
the Commission.
Staff's support is based on its review of the
Avista gas and electric rate case filing, a comprehensive
audit of Company test year results of operations and
consideration of the rate case issues it intended to
present if this case were fully litigated.
The Company originally proposed a revenue
increase of $32.33 million for electric service and $4.7
million for natural gas service for an overall base rate
increase of 16.7% and 5.8% respectively. The Company
proposed a 10.80% return on equity. The Proposed
Settlement specifies an annual revenue requirement increase
of $23.16 million on the electric side and $3.88 million on
the gas side for an overall increase of 11.98% and 4.7%,
respectively. The parties agreed to a return on equity of
25 10.20%
CASE NO. AVU-E-08-1/AVU-G-08-108/22/08 LOBB, R. (Di) 2
STAFF
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The primary focus of Staff in its review of the
Company's filing was to evaluate the 2007 historic results
of operations for gas and electric service, assess the
adjustments made by the Company to those test year costs
and develop a reasonable revenue requirement. Other areas
investigated included class cost of service, rate design,
prudency of DSM expenditures and affordability.
While Staff's comprehensive audit and review of
the Company's filing identified a variety of adjustments to
the requested increase, the overwhelming cost drivers were
found to be critical facility investment and the rising
market price of purchased electricity and natural gas.
Staff's revenue requirement investigation
included a review of the Company's capital investment in
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16 operation and maintenance, fuel and salaries. Staff also
transmission, generation and metering, expense increases in
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evaluated test year expenditures to determine what costs
were known and measureable and used and useful in providing
service.
The cost of service study used by the Company in
this case was the same study used in the 2004 rate case.
While useful in assigning general revenue responsibility
for the customer classes, the study utilized stale load
data and was not accurate enough to make meaningful changes
in class revenue contribution or justify significant
CASE NO. AVU-E-08-1/AVU-G-08-108/22/08 LOBB, R. (Di) 3
STAFF
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changes in rate design. Based on its revenue requirement
analysis and cost of service and rate design evaluation,
Staff concluded that relatively few facts in this case were
in dispute. Staff believed that rather than face the
uncertainty of processing the case through a contested
technical hearing, customers could be best served by
bringing the parties together, candidly discussing its case
and negotiating a favorable settlement of issues.
Recognizing also the very real impact that higher
gas and electric costs will have on the low income
customers of Avista, the Proposed Settlement includes a
commitment to investigate alternatives to help mitigate
those impacts.
The Settlemnt
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16 Settlement?
Q.What are the key components of the Proposed
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A.The Proposed Settlement is attached as Staff
Exhibit No. 101. The key components of the Proposed
Settlement include an increase in the annual electric
revenue requirement of $23.16 million or 11.98% and an
increase in the annual natural gas revenue requirement of
$3.88 million or 4.74%. The revenue requirement was
established using a return on equity of 10.20%, a debt cost
of 6.84% and a capital structure of 48%/52% to produce an
overall return of 8.45%.
CAE NO. AVU-E-08-1/AVU-G-08-108/22/08 LOBB, R. (Di) 4
STAFF
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The negotiated adjustments to the Company's
original request removed over $9 million from the proposed
electric increase through deferral of pending capital and
expense additions, removal of pro formed test year costs as
not known and measurable or not used and useful, and
elimination or reduction of inappropriate or unjustified
costs. Nearly all of the adjustments made in the natural
gas revenue requirement resulted from allocated adjustments
made in electric revenue requirement.
The Proposed Settlement is based upon a 2007
historic test year adj usted for known and measurable
expense changes and major capital additions through 2008.
It also specifies the use of 2009 power supply costs in the
Power Cost Adjustment (PCA) mechanism and treatment of
power supply costs associated with growing load (retail
load and revenue credit).
Other issues addressed in the Proposed Settlement
include verification of prudent DSM expenditures, a uniform
increase in all customer class revenue except Potlatch
Schedule 25P, and an increase in the residential customer
charge for both electric and natural gas service. No other
rate design changes were included.
Finally, the parties agreed to a series of
commitments for customers including increased low income
DSM funding, educational outreach for low income customers
CASE NO. AVU-E-08-1/AVU-G-08-108/22/08 LOBB, R. (Di) 5
STAFF
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and the need to address energy affordability through
generic workshops.
Revenue Requiremnt
Q.How did Staff identify adjustments to the
Company's case and what were the primary considerations in
reaching agreement on the stipulated revenue requirement?
A.Staff identified issues in this case by reviewing
the Company's rate case filing and conducting a
comprehensive audit of Company test year results of
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10 operations. Staff then identified adjustments to the
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Company proposed revenue requirement. The procedure used
by Staff in this case was the same process it uses in
preparing for a contested proceeding.
Staff then evaluated the justification for each
of the proposed revenue requirement adjustments to
determine at what level they could be successfully
supported at hearing. Staff established an overall revenue
requirement target that it believed could be achieved with
reasonable and reliable certainty and then negotiated
identified adjustments that had debatable and less
compelling justification to arrive at an overall revenue
requirement compromise.
Staff's ultimate goal was to balance the needs of
the Company for adequate revenue while securing the lowest
reasonable rates for customers.
CAE NO. AVU-E-08-1/AVU-G-OB-108/22/08 LOBB, R. (Di) 6
STAFF
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Q.What type of adjustments did Staff identify and
how were they evaluated for settlement?
A.The single largest adjustments identified by
4 Staff in this case were those determined to be not "known
5 and measurable" or not "used and useful." For example,
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Spokane River Relicensing costs, confidentially negotiated
agreements and expense increases/capital additions beyond
2008 were all adjustments associated with timing. Either
the proj ects were incomplete or future cost increases were
estimated or projected.
Staff believed it possible that some of the
larger timing adjustments could potentially be eliminated
or cured by the Company as proj ects and contract terms were
finalized by the time the case was processed through
hearing.
Q.Why was the Staff unable to identify more
definitive adjustments in the Company's proposed revenue
requirement?
A.The primary reason is that the Company simply
filed a relatively clean case and mitigated the effect of
many big ticket increases on which Staff has traditionally
focused its investigation. For example, the Company
proposed to include capital additions through the end of
2008 and utilize a year-end 2008 rate base rather than a
2008 average. The Company then offset most of the
CASE NO. AVU-E-08-1/AVU-G-08-108/22/08 LOBB, R. (Di) 7
STAFF
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resulting $29 million increase by subtracting from rate
base an entire year of depreciation expense and adjusting
for deferred taxes. The net effect of the proposal was an
increase in rate base of only $716,000 and a revenue
requirement increase of less than 1%.
The Company also proposed to calculate power
supply costs based on projected 2009 loads. It then
reduced the base rate revenue requirement by implementing a
Production Property Adj ustment to reflect the fact that
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10 2007 loads were used to recover costs. In addition, the
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Company applied a hydro mitigation adj ustment to purposely
reduce estimated power supply costs recovered through base
rates. Actual costs will be tracked through the PCA but
only at 90% of what would have been collected through base
rates.
For natural gas service $3 million of the $3.8
million increase agreed to in the Proposed Settlement is
associated with acquisition of Jackson Prairie natural gas
storage and installation of Automated Meters (AM).
Additional storage will provide benefits to gas customers
through the annual Purchase Gas Adj ustment (PGA) and AM
provides significant savings in meter reading/customer
service expenses.
Finally, much has been made of executive
compensation. Newspaper reports cite total compensation
CASE NO. AVU-E-08-1/AVU-G-08-108/22/08 LOBB, R. (Di) 8
STAFF
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for the top five Avista executives of approximately $3.6
million per year. The Proposed Settlement is based on
compensation of $1.45 million per year or only 40% of total
compensation. While still seemingly high, if all the
compensation included in rates for the top 12 Avista
..
executives were eliminated, the effect would be a rate
reduction of less than 0.5%.
Return On Equity
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10 Proposed Settlement and how was it determined?
Q.What is the return on equity specified in the
A.The Proposed Settlement specifies a return on
12 equity of 10.2%. This return is certainly within the range
13 that Staff would have recommended had the issue gone to
14 hearing. A 10.2% return was approved in Avista' s recent
15 Washington settlement and is reasonable given the improved
16 financial performance of the Company and improved credit
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rating upgrades by S&P and Moody's. It also recognizes the
ongoing capital requirements of the Company and the need
for investment grade ratings (UBBB- "or higher by Standard &
Poor's or "Baa-" or higher by Moody's) .
Net Power Supply Cost
Q.Please explain how net power supply costs were
established at stipulated levels.
A.Staff reviewed all of the inputs and assumptions
used by the Company in the AURORA model to determine net
CAE NO. AVU-E-08-1/AVU-G-08-1
08/22/08 LOBB, R. (Di) 9
STAFF
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normalized power supply costs. Because the results
obtained using AURORA are particularly sensitive to
assumptions abut natural gas prices, and because gas
prices have been extremely volatile since the time the
Company performed its analysis and filed its case, Staff
carefully examined the effect of different gas prices by
performing numerous simulations using gas price forecasts
from many sources and forward prices for 2009. In
addition, because pro forma power supply costs were based
on forecasted 2009 loads, Staff performed numerous
simulations to examine the effect of different load
assumptions. Staff concluded that the inputs and
assumptions used by Avista, including those related to fuel
prices and loads, were reasonable.
Q.Could gas prices and net power supply costs have
been higher than those agreed to in the Proposed Settlement
if argued at hearing?
A.Possibly. While natural gas prices have
moderated recently, they are still higher than those used
by the Company in calculating net power supply costs.
incorporating higher gas costs in the power supply analysis
at a later date could have increased net power supply costs
recovered in base rates.
Q.Why has Staf f agreed to the use of 2009 loads in
the calculation of base power supply costs?
CAE NO. AVU-E-08-1/AVU-G-08-108/22/08 LOBB, R. (Di) 10
STAFF
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A.Staff has agreed to the use of 2009 loads in
recognition that normalized power supply costs included in
base rates are always based on an estimate or a forecast.
Use of 2009 forecasted load in the calculation does not
make the cost any less known and measurable.
In addition, the Company has also included in its
calculation, a hydro mitigation adjustment that reduces
base rate power supply costs and a production property
adjustment that reduces base rate revenue requirement for
generation to serve 2009 loads. The effect of these
adj ustments is to shift costs from base rate recovery to
PCA recovery with reduced impact on customers due to PCA
cost sharing. The Company benefits from using 2009 loads
by reducing its exposure to the retail revenue adjustment
embedded in the PCA.
Q.Did Staff identify any adjustments to the
Company's proposed power supply costs?
A.Yes. In addition to a thorough review of the
Company's AURORA analysis, Staff reviewed each of the
adjustments made to reflect contract changes between the
2007 test period and the 2009 pro forma period. Staff
determined that several adjustments to purchase contracts
beyond 2008 were not known and measurable. Those
adjustments were discussed during settlement negotiations,
and incorporated in an annual $735,000 reduction in the
CAE NO. AVU-E-08-1/AVU-G-08-108/22/08 LOBB, R. (Di) 11
STAFF
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Priest Rapids contract price recoverable in rates.
Cost of Service
Q.What did Staff review with respect to cost of
service (COS) and what have the parties agreed to in the
Proposed Settlement with respect to class specific revenue
requirement?
A.Staff has reviewed both cost of service models
for electric and gas service and found that the methodology
did not change from the Company's last general rate case
filing in 2004. However, Staff noted and Avista
acknowledged that electric load data used in the COS was
generated in the 1980s and statistically updated in 1993.
Therefore, given the age of the load data, Staff believes
the cost of service results in this case should be used
only as a general guideline for assigning revenue
responsibility.
While the Company has agreed to engage in new
load studies, the information necessary to update the cost
of service analysis will not be available until 2009.
Consequently, the parties agreed to use the current results
to move all classes halfway to cost of service as specified
by the study.
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24 classes?
Q.Will the increase be uniformly spread among all
A.Yes, with one exception each customer class will
CAE NO. AVU-E-08-1/AVU-G-08-1
08/22/08 LOBB, R. (Di) 12
STAFF
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1 receive a uniform increase of 12.33%. Schedule 25P,
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3 increase of 10.36%. The 10.36% increase moves Potlatch
service to Potlatch's Lewiston plant, will receive an
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approximately halfway to cost of service similarly to other
classes yet maintains an energy rate that is lower than the
rate charged to Schedule 25 customers. The parties agreed
to the revenue spread in recognition that Potlatch is much
larger than customers served under industrial Schedule 25,
it has a higher load factor and should pay a lower overall
energy rate.
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12 customers?
Q.What revenue spread is proposed for natural gas
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A.The parties propose to increase all gas rate
schedules based on the natural gas cost of service study as
originally proposed by the Company. The resulting revenue
increase was reduced proportionally to reflect the overall
4.74% increase specified in the Proposed Settlement.
Rate Design
Q.How did the Staff evaluate electric and natural
gas rate design and how is rate design addressed in the
Proposed Settlement?
A.Staff evaluated existing electric and natural gas
rate design by reviewing the cost of service study and
comparing current rate components to those of other
utilities. Neither Avista nor Staff believed major changes
CAE NO. AVU-E-08-1/AVU-G-08-108/22/08 LOBB, R. (Di) 13
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in rate design were warranted given the imprecise and
inaccurate nature or the Company's COS study. In addition,
Avista remains the only electric utility under Commission
jurisdiction with true residential tiered rates, with a
differential of 13% for usage over 600 kWh/month.
The parties agreed to an increase in the monthly
customer charge from $4.00 to $4. 60/month for electric
customers and from $3.28 to $4.00/ month for gas customers.
All other rate components were increased uniformly to
generate the required revenue. This rate design represents
the original Company proposal and recognizes the increasing
monthly costs of metering and billing.
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14 future?
Q.Are there any plans to address rate design in the
A.Yes. Staff and Avista have discussed adjusting
16 block size and rate differentials in the future once
17 accurate cost of service data is available. Staff and
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Avista will also investigate whether there are economies of
scale (bundling of electric/gas service) that could allow
reduced monthly customer charges when a customer takes both
gas and electric service. At the very least, a similar
customer charge for gas and electric service will be
considered.
Q.What is the effect on an average monthly customer
bill as a result of the Proposed Settlement?
CAE NO. AVU-E-08-1/AVU-G-08-108/22/08 LOBB, R. (Di) 14
STAFF
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A.If the Commission were to adopt the Proposed
Settlement, the monthly bill of a residential customer
using 977 kilowatt-hours per month (the average for Avista
customers) would increase by $7.89. An average gas
customer who uses 65 therms per month would see an increase
of about $4.03 per month. Proposed increases by customer
class and a comparison of present and proposed rate
components are attached in Exhibit 101 as Appendix 2 to the
Stipulation.
Energy Affordaili ty
Q.What does the Proposed Settlement provide with
respect to low income issues?
A.In recognition that the proposed increase in both
electric and natural gas rates will unduly impact the
lowest income Avista customers, the parties have agreed to
two specific low income provisions. The first is an
increase in the anual low income weatherization funding
from $350,000 to $465,000. The second provision calls for
funding of $25,000 for state Community Action agencies to
provide educational assistance on energy issues in
conjunction with its other low income programs. The
increased funding required for these programs will come
from the existing DSM tariff rider and will not require a
ra te increase.
Q.Are there any other low income provisions
CASE NO. AVU-E-08-1/AVU-G-08-108/22/08 LOBB, R. (Di) 15
STAFF
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included in the Proposed Settlement?
A.. Yes. Under the Stipulated Settlement, Avista has
agreed to support and actively participate in any
Commission-established workshops for the purpose of
examining issues surrounding energy affordability and
customers' ability to pay energy bills. Staff supports the
idea of workshops involving all energy utilities serving
Idaho and is prepared to immediately proceed upon
Commission approval.
All parties to the Proposed Settlement recognize
that electric and gas rates will increase as a result of
this case, with the prospect of additional rate increases
on the horizon due to the Company's PCA and PGA cases.
Staff foresees an unrelenting and significant upward
pressure on rates, which unfortunately is occurring during
an economic downturn in the state as a whole and northern
Idaho in particular. The decline of the mining and timber
industries continues to have a negative impact on small
communities that have limited employment opportunities
beyond mines, mills, and logging operations.
Energy affordability has become a central issue
for many Idaho households, and utilities are facing the
prospect of more customers being unable to pay their energy
bills in full and/or on time. Through workshops, the
Commission can help identify issues and explore possible
CASE NO. AVU-E-OS-1/AVU-G-OS-1
OS/22/0S LOBB, R. (Di) 16
STAFF
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solutions to anticipated problems. Staff supports this
undertaking and suggests that universal service, Low Income
Rate Assistance Plans (LIRA) and alternative rate designs
all be included as discussion topics in the workshops.
Q.Does this conclude your testimony in this
proceeding?
A.Yes, it does.
CAE NO. AVU-E-08-1/AVU-G-08-1
08/22/08 LOBB, R. (Di) 17
STAFF
""'' ~00 00 i.
raised in the proceeding and tht ths Stipulation and its acptace by the Commsson ~ 6 ~.. I I ~
represent a reasonable resoluton of multiple isses identified in ths inater. ThPares~ ~ ~ ~ ~ Zz. ~oo
.~ ~ ~ se
~ 9l 0 N~ø ~c:~u ~~
David J. Meyer, Esq. ,
Vice President and Chief Counel of
Reguatory and Govermenta Affairs
A vist Corporation
1411 E. Mission Avenue
'Po O. Box 3727
Spokae, VV ashington 99220
Phone: (5Q9) 425-4316, Fax: [phone]
" BEFORE TH IDAHO PUBLIC UTITIS COMMSSION
IN TH MATTR OF TH APPLICATION
OFAVISTA CORPORATION FOR TH
AUTORITY TO INCREASE ITS RATES
AND CHAGES FOR ELECTRC AN
NATU GAS SERVICE TO ELECTRC
AND NATU GAS CUSTOMERS IN TH
STATE OF IDAHO
)
) CASE NOS. A VU-E-08-01
)A VU-G-08-0 1
)
) 'STIULATION
)
)
Ths Stipulation is enterd into by and among A vist Corpration, doing
business as AvistaUtiities ("Avist" or "Company"), the Sta of the Idao Public
Utilities Commssion ("Staf'), Potlatch Corpration ("Potlatch"), and the Communty
Action Parership Association of Idao ("CAP AI"). Thes entities are collectively
referred to as the "Pares," and represent all pares in the abve.;refence cas. The
Pares undersd ths Stipulation is subject to approval by the Idao Public Utilities
Commission ("IPUC"or the "Commssion'').
I. INODUCTON
1. The ters and conditions of th Stipulation ar se fort herin. The Pares
agee tht ths Stipulation Íepresents a fai, jus and reasnable compromise of the issues
Page 1 of12
therefore, recommend tht the Commssion, in accordace with RP 274, approve the
Stipulation and all of its terms and conditions without matenal chage or condition.
II. BACKGROUND
2. On Apnl3, 2008, A vist filed an Application with the Commssion for
autority to increase revenue frm elecc and natl gas servce in Idao by 16.7% and
5.8%, respectivety. If approved; the Company's revenues for electrc ba retal rates
would have incread by S32.3millon anualy;Company revenues for natual gas
servce would have increased by $4'.7 millon anualy.Th~ Comp~y requested an '
effective date of May 5,2008 for its proposed electrc/gas rate increase. By Order No.
30528~ dated Apnl 16, 2008, the Commssion suspended the proposed schedules of rates
and chages for electrc and natual gas servce for a penod of thrt (30) days plus five
(5) month, from May 5, 2008, or until such time 'as the Commsson enter ai Order
accepting, rejectig or modifyg the Application in ths mattr.
/
3. Petitions to interene in ths proceedig were filed by Potlatch and
CAP AI. By varous order, the Commssion granted these inteentions. See, IPUC
Order Nos. 30550 and3055L.
4. Public workhops for Avist customer were held on July 23,2008 in
Moscow, Idao, and on July 24,2008 in Coeur d'Alene, Idao, for the purse of
explaig the Company's Application, an in order to provide an opportty for
customers tòask questoll of Sta.
5. On July 28, 2008, Commssion Sta filed with the Conission a Notice --.= ":; ~, 00 00 t¡00 0f 'ii r~' ri! C'o Intent to Eng, age in Setement Discusions. "RP 272. A settement co ' erence was - \w, õ66~ f
ci~~~~z. noo
:Ë~ :g~~ ~ ~SStipulation Page.2 of 12 ~ 0 i: 0
subsequently held in the Commission offces on July 31, 2008, and was attended by
representatives of all Pares.
6. Basd upon the settementdiscusionsamong the Pares, as a compromise
of positions in ths case, and for other consideration as set fort below, the Pares agre
to the followigteri: '
m~ TERMS OF THE STIULATION
7. Revenue Requiment. The Pares ~ tht A vist shal be allowed to
implement revised ta schedules designed to recover $23,163,000 in additiona anual
electrc revenue and $3,878,000 in additional anua natural gas revenue, which represent
an 11.98% and 4.7% increas in electrc and natu gas anua base taffrev~ues,
respctively. In determg these revenue increass, the Pares have agred to varous .
adjusents to the Company's filing, which ar suared in the Tables below and are
reflected in Appendix I and wil be, fuer explaed in prefiled testiony to be fied by
the Pares in support of the Stipulation. In addition; cert elements of the revenue
increases ar fuer discussed imediately below:
(a.) Cost of Capita. The Pares agree tht Avista's cost of capita shà1 be
determed using a capita strtue consistig of 47.94% common stock equity, and
52.06% long-term debt. Avista's authorized retumon equity shal be 10.20%; the cost of
debt shall be 6..84%. These components produce anautlorid rateofret of 8.45%.
(b.) 'Other Adjustments. TheSumBr Table of Adjustments, as set fort
immedately below, describes the remaig revisions to the Compay's origily-fied
electrc and natu gas reenue requiments:
" Page Jofl7
.... ~I I N
~ oQC (,i I 0r.O ~
~~~~l
z' ~QC..0 ,.o.- Z ,. --~ t) j ~
1C g¡ _J QCr.U ~o
,SUMMARY TABLE OF ADJUSTMENTS TO ELECTRIC REVENUE REQUIREMENT
OOOs of Dollars
Revenue
Re ulrement
$ 32328
Rate Base
$ 548266
Adlustments~
,Return on Equity Adjust return on equity to 10.20%(2485) ,0
Power Supply .Priest RapidsJanapum Contract $(614)(735)
(use average of '08 & '09 fiures)0
-Eliminatin of PPM Wind Integration costs $(109)
-Reflect Kootenai Transmission contrc;t $( 12)
Labor-Non-Exec Remove 50% of 2009 non-executive labor expense (296)0
.',
Labor-Executie "Remove 2009 executie labor expnse (39)0
Transmission Rev/Exp Remove 2009 revenues and expenses 81 0
Capital Additions 2008 Includes capital investment and depreciation
through December 2008 152 1,327
Asset Management Remove 50% of 2009 expenses (489 0
Spokane River ,Relicensing Remove adjustment (establish deferrl)'(2831 (12039)
Confidential Litigation *Remove adjustment (establish deferrl)(1 514 (8264)
Colstrip Mercury Emission O&M Remove adjustment (533 0
Executive Incentives Remove executives' incentives (103)0
CS2 Levelizec Adjustment Remove 2009 deferred retum (114)0
,
Carbon Financial Instrments Add net revenues from sale of CFls
fCFls)(427) ,0
Miscellaneous A&G Expenses Remove various A&G ~xpenses, including dues,(502)0
sponsorships, A&G study, 50% of Direcors &
Offcers' insurance, and 50% of Board of Direor
"expenses ,
Producton Propert Flow through impat of Prouction & Transmission 320 997
adjustments
Restate Det Interest Flow through impact of Rate Base adjustments 350 0
1 Total Adjustments $19.165)$(17,979)
I Adjusted Amounts ,I $ 23,163 $ 530,287
* Please see Andrews' Direc unredacted testimony at Pages 32-33.
Exhbit No. 101
Case No. A VU-E-08-1
AVU-G-08-1
R. Lobb, Sta
08/22/08 Page 4 of 23
Page 4 of12
SUMMARY TABLE OF ADJUSTMENTS TO NATURAL GAS REVENUE REQUIREMENT
ODDs of Dollars
Adiustmnts:, "','
Return on Equit Adjust retum on equity to 10.20%(389)0
Labor-Non-Exec Remove 50% of 2009 non-executive
labor expense (73)0
Labor-Executie Remove 2009 executie labor
exoense ,'.' (9)0
Capital Addltions 2008 Includes capitl investment and
depreciation through December
(103)(531)2008
Incentives Remove executives' incentives (23)0
Miscellaneous A&G Expenses Remove vanous A&G expenses,(260)0
including dues, sponsorships, A&G
study, 50% of Direors & Offcers'
insurance, and 50% of Board of
Direcor expenses ,,','
,
Restate Debt Interest Flow through impact of Rate Base
','
adjustments 10 0
Total Adjustments $(847)$(531)
I Adjusted Amounts I $3,878 1'$, 85,159 I
8. Rate Effective Date. The Pares request tht the Commssion issue its
order approving the reta rates contaed in ths Stipulation to become effective October
1,2008.
9. Accountig Treatment for Cer CoSt.
(a.) Spokae River Relicensing The Company included the processing costs
associated with its Spokae River relicensing effort, which expeditus included actu
life-to.;date costs from April 200 i though December' 31, 2007" and: 2008- pro forma
expenditues though December 31, 2008. "~ Andrews' Direct Testmony at page 32)
Page 5 of 12
__ ('I I N00 00 '+9 c¡ 0~ ~ Ii
§~~~ ~
Zo ~ ~ l: Q.o n 00;:Z ~~:.Q) ~~~ ~ . 00~u ~o
Although the Company anticipates receiving a fi license frm the Federal Energy
Reguatory Commssion ("FERC") in 'the nea futue, tht ha yet to occur. ,The
relicensing cost will reman in CWI (Consction Work in Progress) and the
Company will contiue to accrue AFUDC until issuace of the license, at which time the
relicensingcosts wi be transferred to plant in serce and depreciation wil ~gin to be
recorded. The Pares have aged to defer as a reguatory expense item (in Account 186 '
- Miscellanus Deferr Debits) on the Company's balance sheet depreciation
assoiated with Idao's shar of the aforementioned relicening cost and relaté
protection, mitigation, orenhcementexpenditues, until the earlier of twelve (12)
month from the date of the issuace of the licens or the conclusion of Avista's next
genera rate case ("GRC"),togetherwith a carg chage on the deferral; as well as a
cag chae on the amount ofrelicensing cost not yet included in rate'bas. The ,
caing chage for deferrals and rate base not yet included in estblishig rates would be
the customer deposit råte at that tie (presently 5%).
(b.) Confdential Litigation - Company Witness Andrews describes
confdential litigation at pages 32 ~d 33 of her prefied dirct testiony (unedted).
Inmuch as that matter is still pendig aÎd ha yet to be finly resolved, but is expected
to reach resolution in the nea futue, the Pares have agreed to defer as a reguatory
expensitem (in Account 186 ..Miscellaneous Deferred Debits) on the Company's
balance sheet depreciaton asociated with Idao shae of the aforementiónedcosts with
a cag chage on the deferr as well as a carg chage on the amount of cost not
yet included in rate base for subsequent rever in rates. The carg chae will be
the customer deposit rate (presently 5%). This deferr, together with a carg chare,
will contiue until the earlieroftwelve (12) month frm the date of resolution of the
litigaton or unti the conclusion of Avista's next general rate cas (GRC).
-- ~l l N~ 000 tii I 0¡; 0 IQ- I I Cl
~~~~Z
z. ~oo.~~ ~~
','~ ~ ~8¡;u ~~Page 6of12
Application witlithe Commssion (Cas No. A VU-E-07-10) requestig an acounting
hydrelectc projects located on the CI~k Fork River. The Commssion, in îts Order
, order authoazig deferral of settement lea payments and interest accrus relatig to
the recent settement ora lawst in the Sta of Montaa over the use of the riverboo
related to the Company's oWnership of the Noxon Rapids and Cabinet Gorge
No. 30492, authorized the deferr of settement lease payments and delayoo adecision
on interest,uitil the matter was addressd in ths genera rate filing. The Pares have
agred to the Company's requested amorttion of costs, together with recvery of
accroo ìnterest on the Idao shae of defers at the customer deposit rate (presently
5%).
(d.) Revenues Associated with Sale of Carbon Financial Inents (CFIs)-
c
Chicago Climte'Exchange. ,The Company's Applicatiòn wa approvoo on August 5,
, On May22, 2oo8Avista fied a reues with the Commssion (Case No. A VU-E-08-2)to
'defer the revenues associated with the sae of Carbon Fincial Instruments (CFls) On the
2008 in Order No. 30610. Idao's sha of the revenues, net of expenses, frm the CFI
sales is $850,571. These dollas wil be amortd. over a two-year period begiDIngin
the 'calenda month ofthe'efIective datëofnew retl rates resultig frm ths Stipulation,
with a carg charge on the unort balance at the cutomer deposit rate. The'.
revenue requirment included in ths Stipulaton ha been reduced for the CFIrevenues,
in order to flow these benefits though to cusmers.
level of power supply expense, reta load and revenue crdit resulting frm ths
"'"' ~00 00 ~
PCAAuthorizooLevelofExpene.Appendix 3 sets fort the ageed-upon ~ 6 ::. " " - " Q,o~~i: OJ
:~~i3ifz. ~oo..ZO ~o:s 0 N:. g i- ~
.&3 d ~ ~
10.
Stipulation, thtmll be used in the monthy Power Cost Adjustent ("PCA") mechansm
1 1. Prericy of Energy Effciency Expenditues. The Pares agee tht
caculationS.
Avi~ta' s expenditues for electrcand natu gas energy effciency progrs from
Novembe 1, 2003 through December 31,2007 have ben pruently incured.
12. Rate Spread. Appedix 2 shows the impact on eah service schedule of
the agred-upon electrc and natual' gas increases. The proposed electrc revenue
increase of$23,163,000represents an overl increa of 1 1.98% in base rates, and with '
one exception, is spread on a uniform percentage basis to all schedules. Schedule 25P
(for Potlatch's Lewiston plaIt), however, will receive an increae of10.36%, in order to
reflect a Schedul 25P.rate tht is no higher th the'tablock rae of Schedule 25. With
ths chae,' the relative rate of retu for Schedule 25Pwould move, approximately one-
haf way towad unty, more consistent with the movemenfof other serce schedules.
All other schedules will receive a 12.33% incree.
The spread of the increased natual gas revenue requiement of $3,878,000 is set
fort in Appendix 2, and represents an overall increase of 4.7% in base rates. It reflects a
servce schedules proportona to the reuction in the overall increae.
reducon to what the Company ha proposed by way ofan increase for each of the gas
13. Rate Design. 'The Pares 'agre to chages in the electrc cusomer and
demad charges as set fort in the Company's'filingt and sumze in Appendix 2.
Page 8 of12
_.. Mi I N00 00 e.c: c: 0u: 0 00§~~~ f
ò -( -( r¡ ø.z. ~oo.t: ~ :: ~
~ Q) ~ ~x ~ -.u:u ~~
Ths includes an incree in the residential monthy basic chage frm $4.00 to $4.60.
The energy rates withn each electrc servce schedule ar incread by a unform
With respect to natura gas rate design, the Pares agree to apply the increase in
rates withn each service schedule, in the same maer as proposed by the Company. The
proposed by the CODJpany.
14. Cusomer-Related Issues.
(a.) Low-Income DSM Fundig - At present, $350,000 per yea is
prvided to ldahoserce (CAP) agencies for proposed fudig oflow-income Demad-
Side Mangement (DSM). The Pares agre to incras the anualevel of fuding to
$465,000 for such progr (which includes adstative overhead). The contiuation
and level of such fudig will be revisited in the Company's next gener rate 'fiing:
(b.) Funding for Outrach for Low-Income Consrvation -The Pares
agre tht anua fudig in the amount of $25,000 will be provided to Idao (CAP)
agencies for the purose of undertig the dèdication of agencyperonnelto assist in
low-income outreach ándeducation concerng conservation. The dollar will be fuded
. thoug the DSM Tar Rider (Schedules 91 and 191), and will be in addition to the
$465,000 of Low-Income DSM Funding. The continuation and level of such fuding will
be revisited in the Company's nex genera rate filing.
Stipulation
, ExhbifNo. 101
Case No. A VU-E-08-1
AVU-G-08-1
R. Lobb, Sta
08/22/08 Page 9 of 23 ,
Page90f12
Establishment of Generic Workshops -A vista agres to 'support and,
actively parcipate in any Commssion-estblished workshops for the pUrse of
examg issues suroundig energyafordabilty and customers' abiUty to pay energy
bils with respect to,alljursdictona utilities. As par of ths process, Avi agreesto
explore the feasibilty of èstblishig a Low-Income Rate Assistce Progr (LIR),
or simlar progr, to asist low-income residential cusmers in Idaho.
15. The'Pares agee tht ths Stipulation reesents a compromise 'of the
positions of the Paries in ths case. 'As provided in RP 272, other than any testimony
, filed in support of the approval of ths Stipulation, and except to the extent necessar for
a Par to explai before the Commssion its own sttements and positions.with respet to, '
the Stiplltion, al statements made and positions taen in negotiations relatig to ths
Stipulation shal, be. confdential and will not be, adssible in evidence in ths' or any
16. The Pares submt ths Stipulation to the Commssion and reommend
other proceedig.
approval in its entirety purt toRP 274. Pares shall support ths Stipulation before
- the Commssion, and no Par shal appeal a Commssion Order approving the
Stipulation or an issu resolved by the Stipulaton. If ths Stipulation is chaenged by àny
person not a par to the Stipulation, the Pares to ths Stipulation resere therightto fùe
testimony, cross,,exame witnesses and put on such cae as they deem appropriate to
respond fuly to the issues presented, includg the right to raise isses th ar
incorprated in the settlement terms emboded in ths Stipulation~ Notwthdigths ('.. .. C'I I I+00 00 0
reservation of rights, the Pares to ths Stipulation agre that they will continue to support ~ 6 :;
ô66ti ~
the Commission's adoption of the term of ths Stipulation. Ó ~ ~ ~ ~
z. ~oo.~~ ~~~ 0 .s ~
Page 10 of 12 r. 8 ~ ~Stipulation
, ,'IftheCommissionr~Jects any par or all of ths Stipulation or imposes any
additional material condtions 'on approval of ths Stipulation, each Par reserves the
right, upon wrtten notice to the Commssion ' and the other Pares to ths proceeding,
with i 4 days of the date of such action by the Commssion, to withdraw from ths
Stipulation. In such case, no Par shall be bound or prejudiced by the terms of ths
Stipulation, and each Par shall be entitled to seek reconsideration of the Commission's
order, fie testiony as it chooses, cross-exame witnesses, and do all other things
necessar to put on such case as it deems appropriate. In such case, the Paries
imediately will request the prompt reconvenig of a prehearg conference for purses
of establishig a procedural schedule for the completon of the' cae. The Pares agr to
coo~tein development of a schedule tht concludes the proceeding on the earliest
possible date, tang into acount the needs of the Pares in parcipating in heangs and
prearg testimony and briefs. .
18. The Pares ag tht ths Stipulation is in the public interest and tht all
of its terms and conditions are fai, jus and reonable.
19. No Par shal be bound, benefited or prejudiced by any position asserted
in the negotiation of ths Stipulaton, except to the extent expressly stted herein, nor
sha ths Stipulation be constred asa waver of the rightS of any Par uness such rits
are expressly waived herein. Execution of ths Stipulation shall not be deemed to
constitute an acknowledgment by any Par of the validity. or invalidity ,of any parcular,
method, theory ,or priciple of reguation or cost ~covery. ,No Par shall bedeeiIed to
have agr tht any method, theory or priciple of reguation or cost recover employ~d
in arving at ths Stipulation is appropriate for resolvig any issuesinany other
Page ilof12
C"_ _ r'ol ol c.00I I ..~ö -- I I Q)
~~~it ~ó~~b3i:z. ~oo.. 0 .. 0.... Z ..-.~Q) ~gi~ ~ -.~u ~~
proceedig in the futue. No findings of fact or conclusions oflaw other th those stated
The obligations of the Pares under ths Stipulation are subject to the
herin shall be deemed to be implicit in ths Stipulation.
Commssion's approval of ths Stipulation in accordance with its term andc~nditions
21. Ths Stiptiation may be executed in counterpar and eah signed
and 'upon such approval' being upheld òn appeal, if any, by ~ cour of competent
jursdiction.
counterpar shall consttute an original document.
r"l , .DATEDthsi:dayofAugut,2oo8.
A vist Corpration Idao PUblic Utities Commssion Sta
B~~
Attorney for Avista Corporation
Scott Woodbur
Attorney for IPUC Sta
Potlatch Corporation. ,COInunty Action Parerhip Assciation
Bra M. Pudy
! -
", EXhbifNo:-10f
Case No. A VU-E-08-1
AVU-G-08-1
R. Lobb, Staff
08/22/08 Page 12 of23
Stipulation Page 12 of 12
68/67/2668 16: 45 268--336-2537 FEDEKINKO'S 5122 PAG6:Z
constitute an acknowledgment by any Pary of the validity or invalidity of any parcular
method, th or principle of regulation or cost reovery. 'No par shal be deeed to
have, agr that any method, theory or prnciple of reguation or cost recovery employed
in arving at ths Stipulation is appropnate for resoIving any issues in any oter
proceeding in the fuiu. No findis of fact or conelusions of law other than thos' state
herein sha be deemed to be Unplicit in th Stipulation. '
20. The obligations of the pares under this Stipulation ar subjetto the
Commssion's approval ofthi~ Stipulaton in acordance withits term and conditions
'and upon such approval being upheld on app, if any, by a cour of competent
jur'Kictiori.
'21. Thi Stipulation may be C7\eCted in counterpars and each signed '
counterpar shall constitute an original document.
, 1tl, DATED tls _day of August,200R.
Avista Corpraon
By:By
Scott Woobwy
Attrney for IPUC Sta
David J. Meyer
Attorney for Avista Coipraon
f"__ Ni I ~,00 00 0qq M~O -.- I I Cl~ ~ :: lJ ~. '" ~ .s i:o " -0 00
Community Actionparership Assoiation .~ ~ ~ ~
".., . ,','" " , ".', ,,', ',',"'. -. ,',', .,~~'" ',',,',', '.'.~ ~ ~ ~ , '
By,/sC£2;; ~o
PotlathCorporåon
Page 11 of 12
08/01/?OORTHII 14' i'? rTXlRX NO 54481 1d002
APPENlX 1
"
Exhbit No:-1Öi-'
Case No. A VU-E-08-1
AVU-G-08-1
R. Lobb, Sta
, 08/22/08 Page 14 of 23
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APPENIX,2
Eillbit No. -icfi - -~_.,-
Case No. A VU-E-08-1
AVU-G-08-1
R. Lobb, Sta
08/22/08 Page 17 of 23
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AVlSlA UTlUlES
IDAHO ELECTIC
PREseT AND PROPOSED, RATE eoPONENTSBYSCKEOULE
Pr.,Ba iarËRM& , ,PreiJt
$P. Bate .Ot AdÜ1 lEllli' Rat
(b) (Q), Cd)(8)
Residental Serce ~ ,Scledule 1Bas Chrge '
Enef Charg
Fir GO kWhs.
All ever 60 kWhs
$4.00 $4.00
$OJ)5842 ($o.Q006)$O.05
$..oè1'2 ($..00206) ,$0.06
Genèt Ser. SchedUle 11
BaslcC~rge .
Ene,rgyChcøe~ ,,' "
First 3,85lr kWhs
Al' ove, 3. klbs
DêiminGlirge:
2ekWorlè
OV20,kW
$G,OO
$Q.o12'$O.o~
ii'wi''
$3.5ØJlVV
Lam G!erat§:ecè'''$cle 21"
Enêrgy Ch8ï': 'Firs 25.9Q,kWbs $O~~Allov:25,QOO kWIn $0;047Oeand O~: ' '50 'iW or lea ' $2S(j;lOOvrsOkW se.OOWPrimar VOlGlSri $o:iÒJk
§xLargGel'et Seël,.Sdédûle25.En Chê. .,-AI' SO.tlkWJ $O;OseAU b\ef 500;QO.~h'$ $O.~~9
DemChli:e¡ ,
3,OO:kvaor lea
Qvlla;QØ kv ,
PñmìlJy Vt)1t DIscnt',
AnUal Mlmmw.,
'$6.00'
lO,Ø02 ' $( , '51$Q:~:i'$Ó;r.,
noGhi'
'$BJ5W
$O:OO .,$Q,Q&4,()$t;0Ø$ò.0431
$250.00
'$3.OIW
$O.201W
$li:XI~1g SQ.94~1
$Q~0ó~19 $O.~~58
.¡oo$2.7$i'$i2
..oø
$2.15ikVå
$O;íÔI
~t' $5,'.4.70
Pgt-Sehedul 25Enig.Ci' .ali kWha ., , Denctll
3.öOkV1 oi:,leS
Ov$l 3.!J kva
Priary VølL Disoot
Annua Mlr.mi
$Q.ò34b4 to.Ø03 ;$i3ifi
, ~~QO"U.7~a
$O;2wPre $4.44
'$$.;00
,$t.,15i$O.2
PurrplgSerce ~Sdede:3
, B:ås¡c:C~e' ,
~rg Chá:.
Fl~65/(WlkWhAll~ltikvis
$&ll $é.QO
$o "$OQb43 $ " .
$Órs:' ~b034~~g:=
GeAefal
RaeIncrea'
(e)
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, $O~o011(J$0.00
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so:fiW
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$0.00469
,$O~O,Ö39t
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~e."
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(f)
$4.60
$0.06
fO.et7210
$6.50
Q~OGsn.
$0;813
$460
$0;0652
$0.07416
~50
$0.08
$00700 '
nóêh8lgØ
$4~OOW' S4.OÒ/kW
$6,0574.$0'
, $275.00
$&soW
$Oi21k
$o.j1.,.s
$0.0455
$10;000
$B.2lJl ',~i~W
'$$71.4l
$0.05384
$0.044
$25.00
$3.5OW
$O.201W
$0.0411
$0.03736
$1Q.OOOS3,2à
Slf)lilk
$0.00$1.',ó.1)J5
S1..0l)Ô $10,.000 $10~ODO
$O:5olks '$3.25Jva $3.2a
'$IUO/kW $O.201k
$52.420
$O~~K50'$G.6ô
$O,0Ð5 $0;01713 "$0.01370
$0.005 $0.06627 ' $0.0684
-- ~00 ~ '-.
i: i: 0'ti 0 .-- I I Go
o §; ~ a: bO
-::c~Si:~ .~~-o .0--;1: Z .0 ~~ ~ 3~
tid ~gg(1) lnoude$,a11 preiBte~: ,Stl~:.Tei~Pc~... ~:è'.~EttQMe' Ri.~..antfSdi& 5~entf:a FàtmEn Rä Adj; ,(~ 1or
, , ,',' Aplx2
Ca No. Âvu~8-1 ~AVu.'(8-1" "Page2of4
..
AVlTA,UTlUTlES,~
IDAHO GAS
PROP,OSED,INOREAE'$YsßRte SCHEDULE'
1zM.OHTHSENPÊPØet-eMl3ER 31, 2007
(0005 øfDOllërs) ,
Llie
No.~T)iof 'SèrV
(a)
ß3seTanf '
Rever:i¡
SCheiJeUrtder PrentNumbe Ra(1)
(b) , (c)
Ba Tar
Propas Revenu
GeraiUndér flròpQed
Inceasè ',~
Cd) , , (e)
~TariPercIncre
(1)
~ Total
101 $R3,27 $3315 $6,582'5.3%
111 $Ü,ee9 ~$'8,$5 2.'7' ,
131 $Š61 $16 ~,l.~
146 $41'$3 '$42 n.S%
148 m.m,$211 0;0%
$82,071,,$3.818 $$5,950 4.1%
1 Gênø SeM
2 Lare~I'Se
3 lht~ptb!e~
4 Tr'OItl,;se.
Søeial'Co~
(1llnct:'f'\;ÇhasA4i~sten~;lørf ~ucS at rEteadustments.
EXhbit No:-lof --
Case No. A VU-E-08-1
AVU-G-08-1
R. Lobb, Staf
08122/08 Page 20 of 23
Ap2~:Np.AVlE~~ &.AVti~1, '" Page30f 4
,..
AVl$1AUti,lQ.. .~ANOPROOSa;RÄTEcOèNrs8Y$CHEtJ
Gera Propo ProedBasPresenpresentRaSc:h.1'91 Billing Base8lBa Ad,(2) BlßnORàte Itia!Ctarae ~ßm
(a)(bl (el (d)(e)(1)(g)(h) .
Gera SerUte - §Cheeul!'191BasícCh~$3.2 $3.2 '$o.2 $4~OO $400 ,/%2.0%
Usae.Chge:
Al tteiii '$1.108 ($0.0328)$",0560 $O.OS081 . $1.S87 $1.159 4.11.
La Ge,rlseryC!. Sçbeut 111Usa Chrg, Flrs20ths
200 -1.00 lha
tOO- 10.00 ti
AI',ovtl"lO"o.OØ;~
Minimum tii::
pemOM'pelh
$1;$137
'$1.7319
.'$tUl7ÔtT
'$~''Rn
($(M1O~)$1~6$~3:$G.Ð~5 ($,.0Q0)$1.40 $1.145 5.0%($q.~$1Ji1S $8.01087 (SMOO10:)$1.7832 $1.08 1.0%
($0.00)$O.961!$0..23 ,($.*'0)$1.0l $1.01100 4.1%
~~.OOS6 '$O;~'t $O.G ($.GOO)$O.~$O.WlOO O.l)~~.
$1$liea f1.o~lS $.l7~S161~r.o'~l$~)'~~ai,($0."9):$f.$o'.:SÔ~. o.~~=
, Hih OOniLq;fâLb Genet:Sèr ~§èb!d m",MO TQ;SC!l 111
U$age Chrg: "FIrSt 20tls
2QG - 50 1nem&
50 .1.00 tler$
1.oo.'0;'O Ihems
Al ov.1'I'.OOÖ tner
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permølb,pe th
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$O07 $Ô~9_$CUl71OÐ 2.0%
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$O,QnQl $ó,~$0'-82 0;0f
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(1) lr~ïlt~ - ~ed Ga ~l4
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BxhbitNo.1Òl
Case No. A VU..E-08-1
AVU-G-08-1
R. Lobb, Sta
08/22/08 Page 21 of 23
APPENIX 3
Exhbit No.Tõì
Case No. A VU-E-08-1
AVU-G-08-1
R. Lobb, Sta
08/22/08 Page 22 of 23
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CERTIICATE OF SERVICE
I HEREBY CERTIFY THT I HAVE THS 22ND DAY OF AUGUST 2008,
SERVED TH FOREGOING DIRCT TESTIMONY OF RAY LOBB IN
SUPPORT OF STIPULATION, IN CASE NOS. AVU-E-08-01 & A VU-G-08-01, BY
MALING A COPY THREOF, POSTAGE PREPAID, TO TH FOLLOWIG:
DAVIDJ. MEYER
VICE PRESIDENT AND CHIEF COUNSEL
AVISTA CORPORATION
POBOX 3727
SPOKAE WA 99220
E-MAIL: david.meyer(ßavistaorp.com
CONLEY E WAR
GIVENS PURSLEY LLP
601 W BANOCK ST (83702)
PO BOX 2720
BOISE ID 83701-2720
E-MAL: cew(ßgivenspursley.com
BRA M. PURY
ATIORNYATLAW
2019N 17TH STRET
BOISE, ID 83702
E-MAL: bmpurdy~hotmaii.com
SCOTT ATKISON
CHIEF OPERATIG OFFICER
BENNETI FOREST INDUSTRIS INC.
171 HIGHWAY 95 N.
GRAGEVILLE, IDAHO 83530
E-MAL: scottcæbennettorest.com
KELLY NORWOOD
VICE PRESIDENT - STATE & FED. REG.
A VISTA UTILITIES
PO BOX 3727
SPOKAE WA 99220
E-MAL: keiiy.norwood~vistacorp.com
DENNIS E. PESEAU PhD
UTILITY RESOURCES INC
1500 LIBERTY STRET SE
SUITE 250
SALEM OR 97302
E-MAIL: dpeseau~excite.com
DEAN J. MILER
McDEVITI & MILLER LLP
PO BOX 2564-83701
BOISE, IDAHO 83702
E-MA: ioe~cdevitt-miler.com
i,di~SEC~ -
CERTIFICATE OF SERVICE
..
..Offce of the Secretar
Service Date
September 30, 2008
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF A VISTA CORPORATION FOR THE
AUTHORIY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC AND
NATURAL GAS SERVICE TO ELECTRIC
AND NATURAL GAS CUSTOMERS IN THE
STATE OF IDAHO
)
) CASE NOS. A VU-E-08-01
) A VU-G-08-0l
)
)
) ORDER NO. 30647
)
On April 3, 2008, Avista Corporation dba Avista Utilities (Avista; Company) filed an
Application with the Idao Public Utilities Commission (Commission) for authority to increase
its rates and chages for electrc and natual gas service in Idao. The Commission in ths Order
approves the Stipulation offered as a proposed settlement of the rate issues in Case Nos. AVU-E-
08-01 and AVU-G-08-0L. The Parties to the Stipulation ar: Avista; Potlatch Corporation
(Potlatch); the Community Action Parership Association of Idaho (CAP AI); and Commission
Sta. The Commission finds the proposed settlement to be fair, just and reasonable and in the
public interest.
Rate chages approved with an effective date of October 1, 2008, increase authorized
anual base taff revenues for electrc service by $23.2 milion, or 11.98%, and for natual gas
service by $3.9 milion, or 4.7%. The net amount of actual increase wil var by class of
customer and usage. An average electric residential customer (Schedule 1) using 977 kilowatt
hours of electrcity per month will see a $7.89 per month increase. This includes an increase in
the basic monthy customer service charge from $4.00 to $4.60. An average residential natual
gas customer (Schedule 101) using 65 therms per month wil see an increase of $4.03 per month.
This includes an increase in the monthly basic customer service charge from $3.28 to $4.00.
The Commission in ths Order also anounces the contemporaneous establishment of
a generic docket to examine energy afordabilty issues (GNR-U-08-01, Order No. 30644),
approves increased fuding for low-income weatherization, and authorizes fuding for low-
income outreach and conservation education. An intervenor fuding grat of $3,400 is approved
for the Communty Action Parership Association of Idaho (CAP AI).
ORDER NO. 30647 1
..
Initial Application
On April 3, 2008, Avista fied an Application with the Commission for authority to
recover $32.3 milion (16.7%) in additional anual electric revenue and $4.7 milion (5.8%) in
additional anua natul gas revenue. Tr. p. 81.
Electric
The proposed revenue increase for electric servce requested in this case, the
Company states, is driven primarly by increased power supply costs (including higher retal
loads, reduced hydro generation, increased fuel costs, increased Mid-Columbia purhases, and
increaed transmission expenses), capital investments in generation, trsmission and
distrbution plant to increase capacity and reliabilty, various hydro relicensing costs, and the
Company's investment in advanced meter reading (AMR). Tr. pp. 83-85.
Natural Gas
Driving the natural gas rate request in ths case is Avista's investment in expanding
the natual gas stòrage and delivery capacity at its Jackson Prairie Storage Facilty and the
Company's investment in advanced meter reading (AMR). Tr. p. 85. The proposed rate change
for natu gas customers does not reflect changes in the cost of natur gas purchased by A vista
to serve customers. Changes in the cost of natural gas are reflected in the Company's anual
Purchased Gas Adjustment.
Evidence in support of the Company's need for a rate increase for electrc and natu
gas is based on a 2007 test year. Tr. p. 83. The Company in its initial Application proposed an
average rate of retur on rate base of 8.74%, with a 47.94% common equity ratio and a 10.8%
retu on equity. Also identified was a cost of debt of 6.84% and a long-term debt component of
52.06%. Tr. p. 88. Avistaalleges that unless it is authorized to increase its rates, the Company's
rates will not be fair, just and reasonable and it will not have the opportity to realize a fair
retu on its investment.
The Company's base rates and charges for electrc and natual gas serce were last
adjusted in 2004 (Case Nos. A VU-E-04-01/AVU-G-04-01, Order No. 29602). An additiona
electrc rate adjustment related to the Coyote Springs II generating project was implemented
April 12, 2005 (Case No. AVU-E-05-01).
ORDER NO. 30647 2
Stipulation and Proposed Settlement (bereafter "Stipulation")
On July 28, 2008, the Commission Staff fied with the Commission a Notice of Intent
to Engage in Settlement Discussions. RP 272. A settlement conference was subsequently held
on July 31, 2008, wherein all pares to the case as of that date (the Settlement Paries) were
present and paricipated. Puruant to settlement discussions, the Settlement Paries entered into a
Stipulation that purrts to resolve all issues raised in this proceeding. RP 272-276. The
Stipulation was filed with the Commission on August 8, 2008. Tr. Exh. 101. Under the terms of
the Stipulation, Avista is authorized to recover $23.2 milion (11.98%) in additional anual
electric revenue and $3.9 millon (4.7%) in additional anual natural gas revenues. Stipulation'
2. The Stipulation represents a compromise of the positions of the Settlement Paries in this
proceeding. Stipulation' 15. The Settlement Paries represent that the Stipulation is in the
public interest and that all of its terms and conditions are fair, jus and reasonable. Stipulation'
18.
Parties of Record
A Notice of Application and Notice of Intervention Deadline was issued by the
Commission on April 16, 2008, setting a May 9, 2008 deadline for intervention. Two paries
timely fied for, and were granted, intervention - Potlatch Corporation (potlatch) and
Community Action Parership of Idaho (CAPAI). On August 18, 2008, Bennett Forest
Industres, Inc. (Bennett Forest) fied an untimely Petition for Intervention and was grated
intervention with qualified paricipatory rights. Order No. 30632, August 27, 2008. Bennett
Forest did not paricipate in settlement negotiations or sign the Stipulation, but in post-hearing
written comments filed September 5, 2008, states it "does not oppose approval of the Settlement
Stipulation." Bennett Comments p. 4.
Public WorksbopslHearings
Public workshops for A vista customers were held in Moscow and Coeur d Alene on
July 23 and 24, 2008, respetively for the purose of explaining the Company's initial
Application and to provide an opportty for customers to ask questons of Commission Sta.
On August 28, 2008, a technical and evidentiar hearing on the Settlement Stipulation
was held in Boise. Public hearings in northern Idaho were held in Lewiston and Sandpoint on
August 27 and 28, 2008. At the technical hearing the following paries appeared by and though
their respective counsel:
ORDER NO. 30647 3
Avista Corpration David J. Meyer
Potlatch Conley E. Ward
CAP AI Brad M. Purdy
Commission Sta Scott D. Woodbury
Bennett Forest Industries. Inc. Dean 1. Miler
Pursuat to Rule 274 of the Commission's Rules of Procedure. "when a settlement,
be it active or passive, is presented to the Commssion. the Commission will prescribe
procedures appropriate to the natue of the settement to consider the settlement." As reflected in
the Commission's Rules. the Commssion is not bound by settements. RP 276. Proponents ofa
proposed settlement car the burden of showing that the settlement is reasonable. in the public
interest. or otherwise in accordance with law or regulatory policy. RP 275. On Augus 12,2008.
the Proposed Settement was noticed. an August 22 deadline for supporting testimony was set.
public and technical hearings on the settlement were scheduled. and a September 5 deadline for
public comments was established.
Settlement Terms
The terms of the Stipulation are described and discussed below. Testimony
supporting the Stipulation was presented on August 28,2008 by Avista witness Kelly Norwood.
Vice President of State and Federal Regulation for the Company; Commssion Staff witness
Randy Lobb, Administrator of the Utilties Division; and Terr Ottens. Policy Director of
CAPAI.
Cost of Capital- Stipulatin' 7a
The Settlement Paries agree that Avista's cost of capita will be determined using a
capita structure consisting of 47.94% common stock equity and 52.06% long-term debt. the
same as proposed in the original Application. Avista's authorized retu on equity (ROE) will be
10.2% (Application 10.8%); its cost of debt 6.84%. These components produce an authorized
rate of retu (ROR) of 8,45% (Application 8.74%). Tr. pp. 86-88.
A 10.2% retur on equity, Staf states. is within the range Staff would have
recommended if the case were fully litigated. It is a retu that was approved in Avista's recent
Washington settement and is reasonable. Staff contends, given the improved financial
performance of the Company and improved credt rating upgrades for A vista by Stadard & Poor
ORDER NO. 30647 4
and Moody's. It also recognizes the ongoing capital requirements of the Company and the need
for investment grade ratings. Tr. p. 45.
Revenue Requirement - Stipulation ~ 7
In supporting testimony, Sta states it established an overall revenue requirement
target that it believed could be achieved with reasonable and reliable certainty and then
negotiated adjustments that had debatable and less compellng justification to arve at an overall
revenue requirement compromise. Tr. p. 42. Pusuant to Paragrph 7 of the Stipulation, Avista
will be authorized to recover $23,163,000 in additional anual electric revenue and $3,878,000
in additional anual natual gas revenue, representing an 11.98% and 4.7% increase in electric
and natul gas anua base taff revenues, respectively.
In determining these revenue increases the paries have agreed to varous adjustments
to the Company's filing. Exh. 101, Appendix 1. Individual adjusents, the Company states,
should not be viewed in isolation; rather they should be viewed in total as par of the entire
Stipulation, and are the result of hard bargaining and compromise. Tr. p. 86. The Stipulation
sumarzes the adjustments made by the Settlement Paries to the Company's electrc general
rate cae filing and discusses specific accounting treatment for (a) Spokane River relicensing, (b)
confidential litigation, (c) Montana riverbed litigation, and (d) revenues associated with sale of
carbon financial instrents (CFIs). Stipulation' 9a.d; Tr. pp. 88.93. Oter adjustments are
detaled in Stipulation' 7(b) in a summar table. The natue of the adjustments consist of (a)
deferral of pending capital and expense additions; (b) removal of pro formed test year costs as not
"known and measurable" or not "used and useful"; and (c) elimination or reduction of
inappropriate or unjustified costs. Tr. p. 40. The Proposed Settlement is based upon a 2007
historical test year adjusted for known and measurable expense changes and major capita
additions though 2008. Tr. p. 40. As proposed, the revised tariff schedules would become
effective October 1,2008. Stipulation' 8.
Staff states that for natural gas service, $3 milion of the agreed $3.8 milion increase
is associated with acquisition of Jackson Prairie Natural Gas Storage and installation of
automated meters (AMR), both plamed for completion in the four quar of 2008. Additional
storage will provide benefits to gas customers through the amua Purchased Gas Adjustment
(pGA). Automated Meter Readng (AMR) will provide savings in meter reaing and customer
ORDER NO. 30647 5
servce expense. The technology would allow for time of use or critical peak pricing; although
additional changes would be required for data storage and biling. Tr. pp. 44, 85, 114-115.
Cost of Service
In its investigation, Staf reviewed Avista's cost of service (COS) models for electric
and gas service and found that the methodology ha not changed from the Company's 2004
general rate case filing. Tr. p. 37. The electric load data used in the Company's cost of service
model was generated in the 1980s and was statistically updated in 1993 (Le., adjusted based on
changes in customer counts and load per customer that occured between 1980 and 1993). Tr.
pp. 49, 60. Given the age of the load data, Staff believes that cost of service results in this case
can be used only as a general guideline for assigning revenue responsibilty and canot be used
to make meanngful changes in class revenue contribution or jusify significant changes in .ate
design. Tr. pp. 37-39. Avista concedes that the present load study information is dated, but
contends that does not mean it's bad data, or that it's not representative of the cost to sere
customers. Tr. p. 126. While A vista has agreed to engage in new load studies, the Company is
only now selecting the hourly meters. The information necessar to update the cost of service
analysis will not be available until late 2009. Tr. pp. 49, 75. Consequently, the Paries agreed to
use the current results to move all classes halfway to COS as specified by the study. Tr. p. 49.
Rate Spread - Stipulation' 12
Appendix 2 to the Stipulation reflects the impact on each service schedule of the
agred-upon electrc and natual gas increases. As reflected in Stipulation , 12, the proposed
electrc revenue increase of $23.2 milion represents an overall increase of 11.98% in base rates
and, with one exception, is spread on a uniform percentage basis to all schedules. However,
Schedule 25P for the Potlatch Lewiston facilty wil receive an increase of 10.36% in order to
reflect a Schedule 25P rate that is no higher than the tail block rate of Schedule 25. The
Schedule 25P adjustment can be supported by cost of service and load data, the Company states,
because Schedule 25 and 25P customers have hourly meters. Tr. p. 105. The Schedule 25P
Potlatch plant is a high load factor customer and is thee times the combined size of all Schedule
25 customers (Le., 100 aMW). Tr. pp. 112-113. With this change the relative rate of retur for
Schedule 25P wil move approximately halfway toward unity (Le., toward full cost of service l,
and be more consistent with the movement of other service schedules. All other schedules will
receive a 12.3% percent increase. Tr. pp. 49-50, 98, 104. The monthly bil of a residential
ORDER NO. 30647 6
electrc customer using 977 kWhmonth (the average for Avista) will increase by $7.89/month.
Tr. p. 54. The proposed increase by customer class and a comparison of present and proposed
rate components are set fort in Attachment 1 to this Order.
The spread of the increaed natural gas revenue requirement of $3.8 milion is also set
forth in Appendix 2, and represents an overall increase of 4.7% in base rates. It reflects a
reduction to what the Company had proposed by way of an increase for each of the gas service
schedules proportional to the reduction and the overal increase. An average gas customer who
uses 65 therms/month will see an increase of$4.03/month. Tr. pp. 50, 54,98.
Rate Design - Stipulation' 13
Neither A vista nor Staf believes major changes in rate design ar warted given
the imprecise and dated nature of the Company's cost of service studies. Tr. p. 51. Avista, Sta
notes, remains the only electric utilty in Idaho with true residential tiered rates - a second block
differential of 13% for usage over 600 kWhmonth. Tf. p. 52. The paries to the Stipulation in ~
12 agre to an increase in the electrc and demand charges as recommended in the Company's
original filing, and sumarized in Appendix 2. This includes an increase in the residential
monthy basic charge from $4.00 to $4.60. Ths increase, Staf states, represents the increasing
monthly costs of metering and biling. All other rate components are increased by a uniform
percentage to generate the reuired revenue. Tf. pp. 52, 90. In fied written comments, the
Idaho Community Action Network (ICAN) opposes an increase to the base rates, which it states
disproportionately impacts low-income customers and customers on fixed incomes.
Regarding natural gas rate design, the Settlement Paries agree to apply the increae
in rates within each service schedule in the same maner as proposed by the Company in its
original filing. The monthly base charge for the residential schedule wil increase from $3.26 to
$4.00. Tr. pp. 52, 90. As with the electrc base rate, ICAN similarly opposes any increase to the
base rate for gas.
As reflected in Staff testimony, Staff and Avista discussed adjusting block size and
rate differentials in the future once accurate cost of serce data is available. They will also
investigate whether there are economies of scale (bundling of electric/gas service) that could
allow reduced monthly customer charges when a customer taes both gas and electc service.
Tr. p.52.
ORDER NO. 30647 7
peA Authorized Level of Expense - StiPiation ~ 10
Stipulation Exhibit 101, Append x 3 (Attchment 2 to this Order) specifies the use of
2009 power supply costs for use in the ompany's monthly Power Cost Adjustment (PCA)
calculations and in the treatment of power supply costs associated with retail load and revenue
crdit. Stipulation ~ 10; Tr. p. 40.
Sta concludes that the inputs and assumptions used by A vista, including those
related to fuel prices and loads, are reaso able. Tr. p. 47. Staff agreed with the Company's
proposal to use 2009 loads in the calcul tion of base power supply costs recognizing that
normalized power supply costs included i base rates are always based on an estimate or a
forecast. Tr. pp. 47, 48. In addition, Stafinotes that the Company included a hydro mitigation
adjustmt in its caculaton th reduces ~e ba ra power supply costs and a pron
propert adjustent that reduces the base ~te revenue requirement for generation to serve 2009
loads. Appendix 3 of the Stipulation notes that the retail revenue credit will be $41.45/MWh for
October-December 2008 and then $53.63~Wh for 2009. The Company benefits from using
200 load by recing its exposu to the ktal revenue adjustment embedded in the PeA. Tr.
p. 48. Adjustments to the Company's plposed power supply costs were discussed during
settement negotiations and an anual $7t,000 reduction in the Priest Rapids contrct price
recoverable in rates was incorporated. Tr. p .48,49.
Prudency of Energy Effciency ExpenditUTS - Stipulation ~ 11
The Settlement Paries in StiPulition ~ 11 agree that Avista's expenditues for electric
and natual gas energy effciency programs Ifrom November 1, 2003 through December 31, 2007
were prudently incured.
Customer-Related Issues - Stipulation ~ 4
· Low-Income DSM Funding (Stipulation ~ 14a)
Curently only 10% of homes ceiving LIHEAP benefits are weatherized. Tr. p.
140. The Settlement Paries agree to inc ase the anual level of fuding provided to Idaho
servce (CAP) agencies for low-income demand-side management (DSM) weatherization
programs from $350,000 to $465,000, whi h includes administrative overhead. The increased
fuding will come from the Company's exi ting DSM tarff riders. Tr. pp. 54,93,94.
In fied written comments, the I~ahO Communty Action Network (lCAN) states that
weatherization benefits cost an average ~f $3,366 per household. ICAN believes that the
ORDER NO. 30647 8
$115,000 incree to low-income weatherizrtion is too litte. Even if weatherization costs have
not increased at all in thee years, a $1115,000 increase will serve only an additional 34
households. ICAN sttes that low-income teatherization program funding should be increasedto $700,000. I
Staf notes that the ratio of custorers to dollar committed for weatherization is fairly
similar for Avista and Idaho Power. In fae Avista's investment, Sta contends, is greater than
either Idaho Power and PacifCorp. Tr. p. 6 .
· Funding/or Outeach/or Low-Income onservation (Stipulation ,r 14b)
CAP AI is concerned that the co bined, proposed increases in fees and rates will add
to the already unwieldy energy cost burden that low-income familes in Idao face. Tr. p. 138.
The Settement Paries agree that anual ding through the DSM tarff rider in the amount of
$25,000 will be provided to Idaho (CAP agencies for the purose of underwiting agency
personnel assisting in low-income outreach bd conservation education. Tr. p. 94.
· Establishment 0/ Generic Workshops O~t. nergy Affordabilit (Stipulation ,r 14c)
A vista agrees to support and ctively paricipate in any Commission-established
workshops for the purse of examining i ,sues surounding energy affordabilty and abilty of
customers to pay energy bils. As par of~is process, Avista agrees to explore the feasibilty of
esblishing a Low-Income Rate ASSistC1 Prgr (LIRA), or sometng simila. Ir. p. 94.
Reference new Commission Docket No. GNR-U-08-01. Staff suggests tht universal service and
ialternative rate designs be included as diicussion topics in the workshops. Tr. p. 57. The
Commission noted at hearing that sometim1s what is done by working groups on the outside can
format the strctue of the legislative reVie¡ of those issues and how legislation is developed.
Tr. p. 124.
Avista identifies the followin additional programs that are available to assist
customers with the proposed rate increase: Energy Effciency programs, Project Share, Comfort
Level Biling, Payment Arangements, e Customer Assistance Referral and Evaluation
Services (CARES) program, and customer sprvice automation. Tr. pp. 95-98.
Customer Comments and Testimony I
i
The Idao Community Action
I Network (ICAN) appeared at the Commission'sAugust 27 hearng in Lewiston and also s~bmitted written comments. ICAN opposes the rate
hike and the Proposed Settlement and ur es the Commission to continue with the rate case
ORDER NO. 30647 9
process, including investigation and prep tion of testimony by Commission Sta and public
hearngs afer Sta testimony has been ade public. The role of the Commission, ICAN
contends, "is to protect the interests of the customers, rather than the utilty company's
shaeholders." ICAN Comments p. 1. ICAN appear to believe that the settlement was
negotiated by the utilty and the intervenin paries before Commission Staff had time to review
the Company's filing. While the CAP ag~nCieS and other organzations may speak for some
consumers, ICAN contends they canot s eak for all consumers. ICAN is concerned about
settement negotiations being conducted in secret meeting without public input.
The opposition of ICAN to the roposed increase is generaly representative of other
writte,n comments filed by customers, cuso~er on fixed incme who bndge! ever pey. Tr.
p. i O. Many customers cite a newspaper aricle in the Spokesman Review reporting a 72%
quaerly jump in Avista profits as reason 0 deny the Company's proposed rate increase. The
Company explains the inaccuracy of the SEkesman Review headline beginning at Tr. p. 130,
concluding that for calendar year 2007 the ompany stil failed to realize the overall Idaho retur
authorized by the Commission. Profit or e 'ngs, the Company contends, is really the interest
piec for the investr; and if th re is fat attve enough investrs will ta thei money
someplace else. Tr. p. 133. I
Customers also cite what they ~elieve to be excessive executive compensation for
A vista employees. The Spokesman RevieW report a total anual compensation for the top five
Avista executives of approximately $3.6 mllion. In its testimony, Staff notes that the Settlement
in Idaho is based on anual rate base com ensation of $1.45 millon for the top five executives,
or 40% of the total $3.6 milion compensat on. While stil seemingly high, Staf states that if all
compensation included in rates for the top i 2 executives were eliminated, the effect would be a
rate reduction of less than 0.5%.
,
Commission Findings I
The Commission has reviewed and considered the filings of record in Case Nos.
A VU-E-OS-O i and A VU-G-OS-U i inclui Stipulation provisions and the commen of
customers. The supporting context lr the Commission's deliberation regarding the
reasonableness of the Stipulation terms is Ithe Commission's August 28, 2008 transcript of the
technical and evidentiar hearing in thi~ case. The Commission is also informed by the
trscripts of Lewiston and Sandpoint, ldafo proceedings where customers and other paries of
ORDER NO. 30647 10
4
interest were provided the opportunity tr raise their concerns and give testimony on the
Seement Stipulaton, an by fied public c mments, including the wrtten comments of Benett
Forest. The Commission finds that the es blished record forms a sufficient basis for decision
and that no fuer hearng or procedure is rfquired.
Settlements are reviewed under Commission Rules of Procedure 274-276. We
incorprate by reference the submitted St~pulation (and Proposed Settlement) as if set fort
herein in its entirety. See Tr. Exh. 101. I
The Commission finds it necestar to correct the misperception of some at public
hearing and in written comments that the s ttement process is a private and secret process that
excludes paricipation and does not pr vide for representation of all customers. The
Commission's Rules of Procedure establ sh the framework for settlements. RP 271-276.
Settlements may involve one or more pies. If Commission Staff is involved in settlement
negotiations, Sta must provide other pari s with notice. Sta must also give all other paries
an opportty to paricipate in or be appri d of the coure of the settlement negotiations before
a final settlement involving Sta is reac ed. RP 272. The problem in a general rate case
affecting different customer classes is th1t not all customer interests are the same. In fact,
customers often have opposing interests. the only trly common interest of all customers is to
limt the incree allowe the Compay. rmmission Sta. whetrprocesng a case thugh
hearng or through settlement, represents I the interests of all customer classes. This is the
objective of the Staff regardless of the proless followed, and is a result, Staf believes, that can
sometimes be best achieved though settenlent. Tr. p. 39.
Paricipants in settlement negOlittions must be paries of record. Early on in this rate
cas the Commission issue a Notice of I tervention Deadline. One of the sta pur of
intervention, as set fort in our Notic , is "to paricipate in settlement or negotiation
conferences." Without intervenor status, public paricipation in the settlement process in this
case was limited to testifying at the public hearings or filing written comments.
As a general rule, settlement t ks are not initiated unti paries are familar with a
utilty's application, have paricipated in th discovery process, have a familarty with the issues
presented in the case and have developed ary positions and goals. Paricipants are expected to
have a good grasp of the case they themseiyes would present, including the witnesses they would
use and the testimony they would fie. pnly then are they able to sit down and engage in
I 11
ORDER NO. 30647
constrctive and fruitful dialogue. Negotiations do not always result in settlement. Unless all
paricipants agree to the contrar, the positions taken in negotiations are confidentiaL. RP 272.
This condition of confidentially allows for candid discussions by the paries and an opportity
for compromise. The advantage of a negotiated settlement is that the paries themselves are able
to cra mutually acceptable terms. Even then however, under Rule 275 of the Commission's
Rules of Procedure, proponents of a proposed settlement car the burden of proof showing tht
the settlement is reasonable, in the public interest, or otherwse in accordace with the law or
reguatory policy.
As stated in Rule 276
The Commission is not bound by settlements. It wil independently review
any settlement proposed to it to determine whether the settlement is just, fair
and reasonable, in the public interest, or otherwise in accordance with law or
regulatory policy. When a settlement is presented for decision, the
Commission may accept the settlement, reject the settlement, or state
additional conditions under which the settlement wil be accepted. ...
We find that the process used and notice given in this case complies with the letter and spirit of
the Commission's Settlement Rules. IDAPA 31.01.01.271-276.
As reflected in the August 28, 2008 trscript of proceedings, the Company in this
case initially requested authority to recover $32.3 milion (16.7%) in additional anual electrc
revenue and $4.7 millon (5.8%) in additional anual natual gas revenue. Tr. p. 81. In the
Stipulation, the Settlement Paries agree that the Company wil be authorized to recover $23.2
millon (11.98%) in additional anual electrc revenue and $3.9 millon (4.7%) in additional
anual natual gas revenue. Stipulation' 7.
In arving at their recommended rate increase for the Company's Idaho electric and
gas operations, the Settlement Paries agree that the cost of capital for A vist will be determined
using a capita strcture consisting of 47.94% common stock equity and 52.06% long-term debt.
Avist's agreed authorized retur on equity (ROE) will be 10.2%, a reduction from the 10.8%
ROE originally requested; the Company's cost of debt is recognized to be 6.84%. These
components produce an authorized rate of return of 8.45%. Stipulation' 7a.
The Commission at hearng inquird of the Company regarding its intentions to
update its "cost of service" study as par of its next general rate case filing. Under Commission
Rules of Procedure (Rule 121.01.e), a general rate case by Avista must be accompanied by
ORDER NO. 30647 12
.
,
"appropriate cost of service studies." Bennett Forest in post-hearing comments suggests that "in
the absence of a curent cost of service study, it is diffcult for the Commission to make a record-
based evidentiar finding that allocations to customer classes, and resulting rates, are fair, just
and reasonable. Avista is a multi-jursdictional utilty. Once the Company's Idaho jursdictional
costs are determined the next step is to allocate those costs among the different customer classes.
This assigning of cost responsibilty is generally done with a cost of service study. Certnly the
Commission's preference in decision-maing is to have good studies and the most recent and
best information available. We prefer actual data to statistical estimates or forecass. Avista
informs the Commission that it may not have complete load data that it can roll into a cost of
servce study until late 2009. Tr. p. 75. A cost of service study, while useful, is not a perfect
tool for assignng system and service costs to customer classes. Load data is only one element of
a cost of service study. This Commission relies on a cost of service study as a starting point to
allocate costs, but in the end we must, and do, consider other factors such as rate continuity,
equity and proportonality. We expect as always tht the Company in its rate filings wil comply
with the Commission's procedural requirements. A vista states a cost of service study will be
provided in its next rate case. Presently only Schedule 25 and Schedule 25P customers have
hourly meters. Tr. p. 105. The Company contends that the completed load data for other classes
will result only in a fine-tung as opposed to a major shift in dollar, whether it be across
customer classes or withn schedules. Tr. p. 126. In this case the Commission finds the
Company-fied cost of servce study to be suffcient to determine rate design in this case. We
direct the Company in its next general rate case to provide updated load data as par of its COS
study or, in the alternative, show how the lack of such an update affects COS-based revenue
allocations to customer classes.
The Commission finds the Stipulation and negotiated settlement terms submitted in
these cases to be fair, just and reanable and in the public interest. As represented, we find that
the Settlement is a compromise by all Settlement Pares. We find the proposed $23.2 millon
(11.98%) authorized increae in electric revenue and $3.9 milion (4.7%) authorized increase in
natual gas revenue to be fair, just and reasonable, as is spreading the increase to customer
classes in the maner set fort in the Stipulation, including the proposed increase in base charges
for electrc and gas residential customers. Idaho Code § 61-502. We find the proposed uniform
percentage spread of the rate adjustment to be reasonable given the age of the COS data. We
ORDER NO. 30647 13
L
also find the adjustent made for Schedule 25P reasonable and find it to be supported by
Potlatch's relative load chaacteristics compared to Schedule 25. The resultat average chages
in electrc and gas rates for the Company's customer service schedules that we find reasonable to
approve are set fort in Attchment to this Order. The effective date of implementation is
October 1,2008.
The Commission also authorizes an increase in the base charges for residential
electrc and gas customers. We do so in par because it is an integral term of a negotiated
stipulation. Stipulation ~ 13. Testimony reflects also that the increase in the base charge is
justified by the increased monthly cost of metering and biling. Tr. p. 52.
The Stipulation provides for an increase in weatherization program benefits
(Stipulation ~ 14a), and fuding for low-income outreach and conservation education
(Stipulation ~ 1 4b). The fuding is payable from the Company's existing DSM taff riders, and
involves simply a re-allocation of DSM dollar. The increase in weatherization fuding is not as
much as ICAN recommends, but as Sta notes, is greater than either Idaho Power or PacifiCorp
in the ratio of customers to dollars committed. Tr. p. 63. The Commission has initiated a
generic case (GNR-U-08-01, Order No. 30644) to examine energy affordabilty issues.
Stipulation ~ 14c. In that case, we direct Avist and our other major energy providers (Idaho
Power, PacifiCorp and Intermountan Gas) to paricipate. We encourage CAPAI, ICAN and
other staeholders to also paricipate.
In addressing energy affordabilty for low-income customers, we are reminded by
Bennett Forest that large increases in electric rates also have serious consequences for Schedule
25 industrial customers, many of whom, like Bennett Forest, operate in a competitive market and
do not necessarly have the abilty to raise prices to recover increases in operating costs. In
calendar year 2007 Bennett Forest reports it purchased almost 25 milion kilowatt hours of
electric energy from A vista at a cost of almost $ 1.1 milion. There can be no denying that the
cumulative increase to Bennett Forest resulting from increases in this docket and the Company's
PCA docket are significant and will have operational consequences. Bennett Forest requests no
change to the Stipulation. Stil, in its comments, it reminds this Commission that "rate shock" is
a shortand expression for regulatory policy that favors rate stabilty and disfavors abrupt and
significant changes to current rates. This Commission is not oblivious to the consequences of its
rate orders. The volatilty in the energy markets however shows no sign of abating. A vista in
ORDER NO. 30647 14
,~
ths case anounces its intent to file another rate case in early 2009. A phase-in of rates does not
appear to be a viable option.
Opportity for real near-term relief for customers, including Bennett Forest, lies in
their abilty to enact energy effciency and conservation measures and reduce their energy
demand. At hearng, Bennett Forest inquired about progrs to mitigate rate impacts for large
customers. Tr. p. 110. A vista stated that it has a number of energy effciency progras for its
industial customers and Company engineers who wil go to customer sites to work with
customers to identify cost recovery measures. We encourage Bennett Forest to take advantage of
ths opportunity.
Intervenor Funding
Intervenor fuding is available pursuant to Idaho Code § 61-617 A and Commission
Rules of Procedur 161 though 165. Section 61-617A(I) declares that it is the "policy of
(Idaho 1 to encourage paricipation at all stages of all proceedings before this Commission so tht
all afected customers receive full and fai representation in those proceedings." The sttutory
cap for intervenor fuding that can be awarded in anyone case is $40,000. Idaho Code § 61-
617A(2). Accordingly, the Commission may order any regulated utilty with intrastate anua
revenues exceeding $3.5 milion to pay all or a portion of the costs of one or more paries for
legal fees, witness fees and reproduction costs not to exceed a total for all intervening pares
combined of $40,000.
On September 10, 2008, the Community Action Parnership Association of Idaho
(CAPAI) fied a Petition for Intervenor Funding. Idaho Code § 61-617A; RP 161-165. CAPAI
is dedicated to promoting self-suffciency though removing the causes and conditions of poverty
in Idaho's communties. Tr. p. 136. The organization was created by federal law to help
administer federal low-income programs. Tr. p. 145. CAPAI advanced the low-income
consumer issues addressed in Stipulation' 14a, b and c. CAPAI requests $3,400. Petition, Exh.
A.
Rule 162 of the Commission's Rules of Procedure provides the form and content
requirements for a Petition for Intervenor Funding. The petition must contain: (l) an itemized
list of expenses broken down into categories; (2) a statement of the intervenor's proposed finding
or recommendation; (3) a statement showing that the costs the intervenor wishes to recover are
reasonable; (4) a statement explaining why the costs constitute a significant financial hardship
ORDER NO. 30647 15
..
..
for the intervenor; (5) a statement showig how the intervenor's proposed fiding or
reommendation differed materially from the testimony and exhibits of the Commission Staf;
(6) a statement showing how the intervenor's recommendation or position addressed issues of
concern to the general body of utilty users or customers; and (7) a statement showing the class
of customer on whose behalf the intervenor appeared. The Petition for Intervenor Funding filed
by CAPAI comports with the procedural and techncal requirements of the Commission's Rules.
Commsion Findings
Submitted for Commission consideration is the Petition for Intervenor Funding filed
by the Community Action Parership Association of Idao. The Commission has reviewed the
Petition, the Stipulation and the testimony of the Petitioner.
Idaho Code § 61-617 A includes a statement of policy to encourage paricipation by
intervenors in Commission findings. The Commission determines an award for intervenor
fuding based on the following considerations:
(a) A finding that the paricipation of the intervenor has materially
contributed to the decision rendered by the Commission; and
(b) A finding that the costs of intervention are reasonable in amount and
would be a signficant finacial hardship for the intervenor; and
( c) The recommendation made by the intervenor difered materially from
the testimony and exhibits of the Commission Staf; and
(d) The testimony and paricipation of the intervenor addressed issues of
concern to the general body of users or consumers.
Idaho Code § 61-617 A. We find that the Petition of CAP AI satisfies the substative findings
that we are requied to make to justify an award. IDAPA 3 LOLOLI65.0La-e. We find tht the
paricipation and presentation of CAP AI, as reflected in its testimony and the Stipulation,
materially contributed to the Commission's decision. CAPAI's parcipation adds an informed
perspective to the hearng record. We find that the recommendation of CAPAI differed
materially from the testimony of Commission Sta and provided measurable form and substace
to the Settlement Stipulation.
Ths parcular case was resolved by way of settlement and not litigation. CAP AI is a
non-profit corporation overseeing a number of agencies that assist with issues related to the
causes and conditions of povert in Idaho. We find it fair, just and reasonable to award the total
ORDER NO. 30647 16
~
..
request of CAP AI in the amount of $3,400 and find that the public interest is well served by such
award. We find the itemized costs of CAPAI to be reasonable and recognize that the cost to
CAPAI of paricipating in this proceeding constitutes a significant financial hardship. We find
that CAP AI was professional and economical in the marshallng of its time and efforts.
The Commission finds that the intervenor fuding award to CAP AI is fair and
reasonable and will fuer the purose of encouraging "paricipation at all stages of all
proceedings before the Commission so tht all afected customers receive full and fair
representation in those proceedings." Idaho Code § 61-617A(1).
CONCLUSIONS OF LAW
The Idaho Public Utilities Commission has jursdiction over A vista Corporation dba
A vista Utilities, an electric utilty, and the issues presented in this case, puruant to the powers
grated it under Title 61 of the Idaho Code and pursuant to the Commission's Rules of
Procedure, IDAPA 31.01.01.000 et seq., including specifically Rules 272 through 280 as pertains
to settlements.
ORDER
In consideration of the foregoing and as more parcularly described and quaified
above, IT is HEREBY ORDERED and the Commission hereby accepts the Stipulation and
Proposed Settlement tendered in Case Nos. AVU-E-08-01 and AVU-G-08-01 approving a $23.2
millon (1 1.98%) authorized increase in anual base tariff revenues for electric service and a $3.9
milion (4.7%) authorized increase in anual base tariff revenues for natural gas service for an
effective date of October 1,2008. Reference Order No. 30647, Attachment 1. The Company is
directed to file amended tariffs comportng with ths Order.
IT is FURTHR ORDERED that the Community Action Parership Association of
Idaho's Petition for Intervenor Funding is granted in the amount of $3,400. Reference Idaho
Code § 61-617A. Avista is directed to pay said amount to CAPAI within 28 days from the date
of this Order. IDAPA 31.01.01.165.02. Avista shall include the cost of this award of intervenor
fuding to CAPAI as an expense to be recovered in the Company's next general rate case
proceeding from the residential customer class. Idaho Code § 61-617A(3).
THIS is A FINAL ORDER. Any person interested in this Order may petition for
reconsideration withn twenty-one (21) days of the service date of this Order. Within seven (7)
ORDER NO. 30647 17
"I
..
days afer any person has petitioned for reconsideration, any other person may cross-petition for
reconsideration. See Idaho Code § 61-626.
DONE by Order of the Idaho Public Utilties Commission at Boise, Idaho this 30"'
day of September 2008.
~~-L~RD~T7
~J~
RšTH, COMMISSIONER
ATTEST:
fkfj.~Je ~ell~
Commission Secretar
blslO:A VU-E-08-0 I_A VU-Q-08-0 I _sw3
ORDER NO. 30647 18
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A VIstA l1lUlES
IDARO ElirC
PRESENT AND P-R0.PQSEß. ~TE. eOMI?ONEN1S BY .SCHEOULE
PteeiB~ ra:ËIiM.Ir' ,P.F~t.
. $¿. Råte' .Other AdÜ:i) .Bilfiijgåt
, t!i (6). '(Q)(;:)
Residential Seiice . .S,cAedule 1
. Bas Charge
Ener.g,Y Cha~
. Firt 600 kWbs.. '
All ovar 600.itWhs
$4.00 '$4.00
$Q.tl84 ($0.0000) '$..05e3~
$.M,IS6il2: . \:$El.~2Ö)' .$0.061)
Genera! Servtces ..Sc!edule,11
Bask C~!irg!! .
E ne.FQ .Chai:!l '
First 3,sb' kWl:s
.Ai' oirer, å.Q kWhs
Demi:ri,'chr:e: ' .
29 iM orJê&~
Qiet 2llkW '
GeQ~al p.r.lPQs~d . PropÐS,
Rate Billng Bas Tariff
Increas 'Rate ' B!
(l!)',(i (9)
$00.60 $4.60 $4.60
, $Q.-o071P $:0.06346 '$.¡06552. '. "$'o.ònio '$0.7416$0.00804
¡e,oo 'ta,oo '$.liÐ $6~50 '$~50 ..
$i.0729 .' $.r:i~ßi."~,Q15S,$O~OÔ91:j i$.ø;ø~-$0.0&208
$äÖs;z3 S'~~S~~'$é~5$S;'$~-.~11â .'$O~Ð7363 $O:Oi.o'l ; :.,"
riiii.ëfiåié''11 'Gi:i:i!f. '. iib~ëfaiöe'.nt:ø~iJrgø "'.¡'
...'
$3,501W :$ß;5O/W: .'..' $:O;$9lJV\',:$I1;~W,, ,$4.0Ð/kW
Larq! Geri&i.al.:SerJcé:..~SChèdl:le 2.,.
Energy Chai~~: ' , .F!i; izsQ.9Q.kWl)s $O~~O
AlI tN:Z5:O,QOtik~ $D.04el ,Deand Óliaftl:
50 kVV er tes .
oVr-50kW'
, ,Primar Vólt. '9~nt
s:o'C .,$i~4.a
$Q0Øb' .lO~1
$Q,;$,QSS4 $Ó,05724"
.tØöØ94;7 ". ~.b93' '
$0.0538'4'$O,ii4
d ,$2o':eii
$~,QOJ
, $0'.20MV
$25tU)Ø, $2500
:$.3J:iØtkW, . $d.50IkW
,$'',201ltW
. $2f5öQO ,
$8òÓo/W'
$.O¡2QIkW
,$2,5¡QO.
$J.5GJk .
$O,2C1W
. " Exta:'Lr.qii.Gefie.( Sfirv .-.Sêéôülé,25 '.
'EneCl Cl:atte;." , ---
Fir$t'S~0Q.,kW,hS' ' $O;Ol94
, AU Qvet 5P.Q¡WP.~'$ $Ö,O.a3~ ,
, Demad,:Oh~t9e¡, . : .
3 ,£lot ~¡ta 'Or le. ,
" .O~r~;ø.go!t~
Prlàf¥ \1nìt,OiseQl,til'
. Anriiii lÝnir1ui: . '
'. ~.~.'t,a¡,.!.,11.g.$ .J.a;~e1.. ' ,.S1J.,~4£~, :"''' ~!f'" , '$O.oS~$ "d'.sO.QQ397
$Q.:Q'47:$Ð , $'0.04411. "
$0:0455 $0.0313.6". .
, ~ti(J''. . .~~.' .:$.75/a '
~;'2Ð1W ,
, '~S)Ø9,~.15t~
SO.~íkWpt~t:'$.si:~h4.()
'thOOÐ-
~i5è'Ià'"
, S1'D¡OO''
$a.i5lk"~ "
;.$n.:iQ/W .,.
, ,:':SSij.4'-ll ,:.
. .$10..110
$ß~.yá'
$)~2ÔJ!
Potlatcl .SthetJu1e ZiP.
Cn~i'iCharg:
$Q.óä4O*$.O~~G31ä 'ttiO$ifjit 'iO.pQ;l1,$ .ld.'0~'$OöO3722 '~J1 kWhS
Oem~~ 'Gll~
'. 00 S1Ó..Ö.OÒ. 3.öojH,~ .li~:It'S . ~J.a,~;:oOò $1..0G.O $1'O,OØ'0
Over 3.oó k..a $~.7S.l¡.va :$..s1a $:,SOAe.a '$3.25/kva S3.2~a
Ptlimry Vplt öis~rit $Ô;2Ö/W $å.1k $G-.W $O.2ÐJlW
. Annuål Mii:illi'P'resl!nt:$482,44 $5.29,420'
P.unìpitig serfc.e" :SchedùIe~'$6.SôB:åstc Cf¡~e '~..øa '$éø.$0.50 ~:5If
Energ eha.l9e.
$Ö.O,65~i:n"O:O.34-~:$p:96.e$e ' $0;07310
Ri'(~ ßS k,Wl,kWh $0,0:08-15 $0.01713-
All aai;iton.åJ kWts S,d.b:~S$:$~~:OO343 . $.e~bS'9az lO.0'695 $0.06621 S9.06284
, (.i) l'r:oluQe:¡ ,all prèsent'räté.adjuseml SttêtÍiJlê;,6&1i¡iR~i'W.~AM,. S~ed\1(~:9lI.Enig9'Êttc;~l.&Y' Riçlr ~ai.,
anifSsfiédlë 59,RëSdè.tiaf& F.äft'l:æõê'y. Räe Mji ~~eh~,1 ¡¡~' , , .
ATIACHMENT1
Case No. AVU-E..S..1/AVU-G-OS..1
Order No. 30647
Pag~ 2 of4
"
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AVlSl')\o,.\T,ILlTES:
1000SA$,
PRØPOSËO JNb,RtAsàßY"'seRic,e SCHE'DULE' .
1i:::MQNlllSSiPi=p. p,EC:e.M..BER .31, iOn1
,(O.OQs øf ~lIiars)
, LiMe
Nø~
Type-of
, Sè"i:Îce'~
,!3se.1 aii
Rever:i¡
SchedWe UnderPtësent
NIJr:.De RàestH
(b) , ,,(c)
Base Tari
Prop~sed Re~enue
Gener.al . Uiiiiël' Pr.ópòse
InQreasè 'Rates(d),' ¡ W"
Bai;Tari
Percel'
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ATTACHMENT 1
Case No. AVU-E-GS-G1/AVU-G-OS-01
Order No. 30647
Page 3 of4
..
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.w1S-l'À:UtILllis
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"
ATTACHMENT 1
Case No. AVU-E-Oa-01/AVU-G-Ða-Ð1
Order No. 30647
Page 4 of4
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