20090407AVU to Staff 73-80, 82, etc.pdf

Avista Corp.
1411 East Mission P.O. Box 3727
Spokane. Washington 99220-0500
Telephone [phone]
Toll Free 800-727-9170
F~E:CEt
JI~'v.srJl.
Corp.
2009 APR - 7 AM II: I 3
April 6, 2009
Idaho Public Utilities Commission
472 W. Washington
Boise, ID 83702-5918
Attn: Donald Howell & Krstine Sasser
Deputy Attorneys General
Re: Production Request of the Commission Staff in Case Nos. AVU-E-09-01 and
A VU-G-09-01
Dear Mr. Howell and Ms. Sasser,
Enclosed are an original and two copies of Avista's responses to IPUC Stafts production
requests in the above referenced docket. Included in this mailing are Avista's responses to
production requests 073 through 080, 082, 084 through 086, 089 and 098. The electronic
versions of the responses were emailed on 04/6/09 and are also being provided in electronic
format on the CDs included in this mailing.
Also included are Avista's CONFIDENTIAL responses to PR 082C through 086C. These
responses contain TRADE SECRET, PROPRIETARY or CONFIDENTIAL information and
is separately filed under IDAP A 31.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code,
and pursuant to the Protective Agreement between Avista and IPUC Staff dated January 8, 2009.
It is being provided under a sealed separate envelope, marked CONFIDENTIAL.
If there are any questions regarding the enclosed information, please contact me at (509) 495-
4546 or via e-mail at j oe.miler(favistacorp. com
Joe Miler
Regulatory Analyst
Enclosures
CC (Paper):The Energy Project (Roseman)
WUTC Staff (Trautman - 3 copies)
lCND (Schoenbeck, Van Cleve)
Public Counsel (ffitch)
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
IDAHO
A VU-E-09-01 / A VU-G-09-01
IPUC
Production Request
Staff-073
DATE PREPARD:
WITNSS:
RESPONDER:
DEP ARTMENT:
TELEPHONE:
04/02/2009
Tara Knox
Tara Knox
State & Federal Regulation
[phone]
.
REQUEST:
In Knox's Exhibit No. 11, Schedule No.5, page 1, lines 11-16, she says "Traditionally customer
accounting, customer information, and sales expenses are included in the distrbution fuction and
administrative and general expenses and general plant rate base are allocated to all fuctions. In
this study I have created a separate functional category for common costs. Administrative and
general costs that canot be directly assigned to the other fuctions have been placed in this
category." In an effort by Staff to maintain consistency withn each rate case's Cost of Service
study, please provide a detailed explanation and all supporting executable electronically formatted
analysis ilustrating:
a. Why the Company has determined that it is necessar to create a separate functional
category for common costs that canot be directly assigned to the other fuctions.
b. How this methodology change of creating a separate functional category for common
costs in the cost of service study impacts the allocation of costs to each class and the final Revenue
Requirement in comparison to what has been traditionally used and accepted by the Idaho
Commission in Case Nos. A VU-G-04-1 and A VU-G-08-1.
c. Which administrative and general costs that cannot be directly assigned to the other
functions have now been placed in the new common costs category.
.
.
RESPONSE:
a.It is not necessary to show common costs in a separate category. I include it to be able to
identify direct costs of the primary fuctions. If other companies cost of servce summary
reports have a sumary by fuctional category, they usually distrbute common costs back
into the primar functions based on the relational source of the allocation factors used on
the common costs. My presentation provides an additional piece of summar information
by showing the direct costs assigned to the fuctions with the indirect costs shown
separately.
Providing a summar which shows common costs as a separate category does not impact
the allocation of costs to each class or the final revenue requirement in any way. It is
simply a summary presentation difference from the way other companies typically show
costs rolled up by fuction. The report "Summar by Function with Margin Analysis"
presented as page 2 of Exhibit No. 17, Schedule 5 in Case No. A VU-G-04-01 included the
same summar categorization of costs as the present case. Likewise the report "Summary
by Function with Margin Analysis" presented as page 2 of Exhibit No. 14, Schedule 5 in
Case No. A VU-G-08-01 also included the same summar categorization of costs as the
present case.
The common cost category includes general plant and computer software costs including
related depreciation expense and property taxes as well as operating and maintenance
expenses recorded in FERC accounts 920 through 935.
b.
c.
.
.
.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
JUSDICTION:
CASE NO:
REQUESTER:
TYPE:
REQUEST NO.:
IDAHO
A VU-E-09-01 1 A VU-G-09-01
IPUC
Production Request
Staff-074
DATE PREPARD:
WITSS:
RESPONDER:
DEP ARTMENT:
TELEPHONE:
04/0212009
Tara Knox
Tara Knox
State & Federal Regulation
[phone]
REQUEST:
In Knox's Exhibit No. 1 I, Schedule No.5, page 3, lines 17-19, she says "The gas scheduling
process includes transportation customers, so estimated scheduling dispatch labor expenses are
allocated by throughput. The remaining gas supply deparent expenses are allocated by sales
volumes." Please provide a detailed explanation and all supporting executable electronically
formatted analysis ilustrating the process the Company uses to determine the way the gas supply
department expenses are allocated by sales volumes vs. throughput. In this response, please
indicate the date all corresponding data was collected to make this determination.
RESPONSE:
The electronic executable file associated with the classification of Account 813 into sales versus
throughput was included in the electronic workpapers fied with the case. The excel file named
"Assign Misc.xls" contains the calculation in the tab named "Acct 813".
First, the proportion of Account 813 costs that are attributable to gas scheduling is detennined. In
this case, the value used in A VU-G-08-01 was repeated under the assumption that the relationship
remains similar from year to year. Attached in "StafCPR_074 Attachment A" is a labor analysis
from the twelve months ended September 2008 showing how the scheduling assignent of the
total account percentage would have changed if it had been updated.
Next, the value attributed to gas scheduling in the test year is assigned 75% by throughput to
reflect the fact that the schedulers perform servce for the transporters as well as core customers
when they cary out their dispatch duties. The 75% dispatch estimate was determined by interiew
with the schedulers prior to the A VU-G-04-01 case, the date ofthe intervew was not documented.
Telephone confirmation that the relationship remains reasonable was received prior to fiing
WUTC Docket No. UG-070805 in 2007, again the date ofthe call was not documented.
The purpose of segregating a portion of this account to allocate by throughput, is to recognize that
transporters receive benefits from the gas supply deparent and therefore should bear some of the
cost. The individuals in the gas supply department do not attempt to identify the specific hours
required to provide for the needs of transport customers, therefore no quantitative analysis is
available to capture the cost that should be borne by transporters. Interviewing the individuals
providing the service provides a reasonable approach that enables a fair split ofthis account
between scheduling dispatch activities that benefit all versus other procurement activities for the
benefit of sales customers.
.
.
.
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.
.
A VISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
IDAHO
A VU-E-09-0l 1 A VU-G-09-0l
IPUC
Production Request
Staff-075
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
04/0212009
Tara Knox
Tara Knox
State & Federal Regulation
[phone]
REQUEST:
In Knox's Exhibit No. 11, Schedule No.5, page 5, lines 4-5, she says "Meter investment costs are
allocated using the number of customers weighted by the relative current cost of meters in service
at December 31, 2007." Please provide a detailed explanation and all supporting executable
electronically formatted analysis pertaining to Workpapers TLK-G-70 though TLK-G-73.
Specifically, describe hòw the Company can quantitatively assume each class's "Orig Cost" and
"Install Cost" to be homogeneous between rate Schedules when determining the "2007 Total
Cost."
RESPONSE:
The electronic executable files associated with those workpaper pages were included in the
electronic workpapers fied with the case. The excel file named "meter cost.xls" contains the
calculation of weighted current cost of meters for the different rate schedules. This analysis
differentiates between the schedules based on how many of each sub-type of meter is curently in
service for each schedule. The total retirement cost by sub-type per the fixed asset system (the sum
of original cost and installation cost) for the most recent year available is used to price the number
of meters in service by sub-type to arve at the weighted cost by schedule. The fixed asset unit
costs represent an average of all items classified as each sub-type installed durng the year. There
is no question of homogeneousness between rate schedules at the meter sub-type level, because
meter sub-type is blind to schedule. The number of each sub-type of meter in use is the
differentiating factor between rate schedules. Equipment sub-type is the appropriate level of detail
to determine weighted average meter cost by schedule.
This weighted average current cost analysis provides the desired forward looking relationship to
be applied to the embedded cost of metering equipment.
.
.
.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMNT:
TELEPHONE:
04/0212009
Tara Knox
Tara Knox
State & Federal Regulation
[phone]
IDAHO
A VU-E-09-01 1 A VU-G-09-01
IPUC
Production Request
Staff-076
REQUEST:
In Knox's Exhibit No. 11, Schedule 5, page 5, lines 5-7, she says "Services investment costs are
allocated using the number of customers weighted by the relative current cost of typical service
installations." Please provide a detailed explanation and all supportng executable electronically
formatted analysis ilustrating:
a. The quantifiable difference between a Washington and Idaho typical service
installation cost, specifically given that Washington's costs were used in Workpaper TLK-G-74.
b. How the Company quantifiably assumes that the 2006 components shown on
Workpaper TLK -G-7 4 ilustrating the "Curent Typical Services Cost" are adequate to estimate
the Allocation Factors used for the 2008-2009 cost of service study.
RESPONSE:
a.There is no quantifiable difference between a typical service in Washington versus
Idaho. The analysis was derived from the experience of distribution engineers who
design installations for the Company's gas north division. Their experience covers
both states and the analysis was intended to establish a forward looking cost
relationship between residential, small commercial, and large commercial or industrial
installations. The resulting weights are then multiplied by the relevant customers in the
specific cost study to create an allocation factor for the embedded cost of services plant
(account 380) included in the study.
The gas engineering deparent only provides updates to the cost estimation guideline
periodically (included in the workpapers as pages TLK-G-75 and TLK-G-76). At the
time this study was completed 2006 was the most recent data available. The cost of
service study in Case No. A VU-G-04-01 included this same analysis with 2003 costs
and the weighting factors produced were 1, 1, 7, and 12 compared to the curent case
analysis which produces weighting factors of 1, 1, 6, and 10. Furtermore, the test year
in this case goes from October of2007 though September 2008 (not 2008-2009 as
stated in the question), which is not so far removed from 2006.
b.
.
.
.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
IDAHO
A VU-E-09-01 1 A VU-G-09-01
IPUC
Production Request
Staff-077
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
04/0312009
Tara Knox
Tara Knox
State & Federal Regulation
[phone]
REQUEST:
In Knox's Workpaper TLK-G-39, used to determine the proportional weight oflarge and small
main expenses used in the Cost of Service Study, the weighting for more recent main costs are not
weighted heavier than prior year costs. Please explain why the Company has not determined that it
may be necessary to weight the value of more current main costs heavier than those that may have
occurred in 1957. (Knox, Workpapers TLK-G-39 though TLK-G-45).
RESPONSE:
The purpose of this analysis is to estimate the proportion of booked historical amounts in Account
376 related to mains less than four inches in diameter. The desired information is not available in
the financial accounting system. However, the number of feet installed in each year and the
vintage cost per foot retirement value is available. The cost of mains is weighted by the number of
feet installed per year of the varous sizes and types. Per the most recent depreciation study, mains
have a remaining life of 50 years, which makes it perfectly reasonable to include the cost of pipe
laid in 1957 as it remains on the books. A comparson of the total weighted cost estimate
compared to the ending balance per books (included on the workpaper) indicated that the total
estimated balance was quite reasonable as it was within 3% of the actual balance per books.
.
.
.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
IDAHO
A VU-E-09-01 1 A VU-G-09-01
IPUC
Production Request
Staff-078
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMNT:
TELEPHONE:
04/03/2009
Tara Knox
Tara Knox
State & Federal Regulation
[phone]
REQUEST:
In Knox's Exhibit No. 11, Schedule No.5, page 5, lines 14-17, she says "Other administrative and
general expenses are allocated 50% by anual throughput (classified commodity related) and 50%
by the sum of operating and maintenance expenses not including purchased gas cost or
administrative & general expenses." Please provide a detailed explanation and all supporting
executable electronically formatted analysis ilustrating how allocating 50% of operating and
maintenance by annual throughput and 50% by the sum of operating and maintenance expenses
was determined to be the appropriate allocation.
RESPONSE:
Following is an excerpt from my testimony in Case No. A VU-G-04-01 where this methodology
was first accepted by the Idaho Commission.
"Q. When was the last time the Company fied a natual gas cost of servce study with the
Idaho Public Utilities Commission? A. The last natual gas cost of service study was
fied with Case No. WW-G-88-5......Q. Does the Natural Gas Base Case cost of
service study utilize the methodology from Avista's last Idaho natural gas case? A. No.
The Base Case cost of service methodology for distrbution, customer services, and
administrative and general costs is based on the most recent methodology employed by
Avista in the Washington jursdiction. This methodology, accepted in Washington since
1994, resulted from a fully litigated cost of service case specifically intended to
determine appropriate natural gas distribution rates in the era of transportation service
(WUTC Docket No. UG-940814). The result was a compromise methodology accepting
ideas promulgated by Washington Natural Gas Company (now Puget Sound Energy), the
Commission Staff, and Public CounseL."
The 50% throughput, 50% other O&M (excluding gas cost) for administrative and general
expenses that are not either plant or labor related was proposed by Public Counsel in WUTC
Docket No. UG-940814 and subsequently accepted by the Commission. Attached in
"StafCPR _ 078 Attachment A" are three pages from the direct testimony of Jim Lazar on behalf of
Public Counsel in WUC Docket No. UG-940814 that discuss their proposal for the allocation of
administrative and general costs. The gist of the argument is that "corporate officials devote more
time and attention to their largest customers" (StafCPR _078 Attachment A, page 2, at lines 19 and
20), and the use of the throughput allocator acknowledges that by giving more weight to large
usage customer groups.
The following quote from the Fifth Supplemental Order in Docket No. UG-940814, page 15 shows
the Washington Commission's response to Public Counsel's argument.
.
Response to Staff Request No. 349
Page 2
"The Commission accepts Public Counsel's proposaL. The Commission finds persuasive
Public Counsel's observation that A&G functions are not devoted to O&M activities. It
believes that the Public Counsel proposal best matches expense to benefit."
.
.
1
2.
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18.20
21
22
23
24
25
26
27
28
29
30
31
32
33
.
In particular, it is highly inappropriate that the Company would classify and alocate
approximately $1.4 milion in sales expense (the cost of secug new business) based on
the ~stomer count of existing customers. For each of WNG's 400,00 cutomers to be
allocated $3.60¡year in order to support the Company's sales force -- which is what Mr.
Feingold's cost of servce study and Mr. Amen's Exbit 16 effectvely proposes - is simply
irrational and unacceptable.
Q. How do you propose that these costs should be Classified and alocated?
A. Conservation costs (Account 908) should be alocated on the same basis as gas costs, as
they have been in' electric proceedigs for many years. The other costs are mostly
overhead costs associated with the business, and I propose that they be alocated based on
the revenue from each class of cutomers; thi is reflected in my cost of servce results
presented'in Exibit _(JL-).
5. Administrative and General Costs
Q. What costs are included in the category of Administrtive and Genera (A&G) costs?
A. These expenses include A&G salares, Offce Supplies, Outside Servces, Employee
Pensions and Benefits, Inurance, Injunes and Damges, Reguatory Commsion Exenses,
General Plant rate base, Maitenace of General Plant, and some other mior categories.
In all, -they total some $18.3 m.io~ about one-thd of the Company's tota non-gas
expense.
Q. How has the Company proposed to alocate these costs?
A It has separated them into ,thee categories: The bul are denoted "Labor-related" with
lesser amounts identied as "Plant-related", and "Other-related". It then alocates the
Labor-related costs on the basis of diecty alocated labor for each class, Plant-related
costs on the basis of diectly-alocated plant, and the "Other" costs based on the subtotal of
the first two categories.
Direct Testimony of Jim La
Docket No. UG-940814 Page 34
StafCPR_078 Attachment A Page 1 of 3
Q. What is wrong with the Company proposal?
A. The Company's allocated labor expenses and its allocated rate base are overwhelmingly
associated with distribution mains, servces, meters, meter reading, and biling. As a result,
the directly-allocated plant and labor costs are overwhelmingly assigned to the residential
and small commercial customers. On the other hand, the Company's A&G Salares
account covers compensation to corporate offcers who certainly do not spend the majority
of their ti,ne supervising distr~bution main instaers and meter readers. To alocate these
A&G expenses on the basi.s of directly allocated expenses simply assign virtally all of
them to the small use customers.
o. Has the method proposed by the Company been proposed in the past?
A. Yes. In the WWP proceeding, Docket UG-901459, Ms. Kihara, the Company's witness,
proposed allocating the labor-related A&G on the same basis as directly allocated labor
expense. In that cae, the staff vigorously contested this methodology, stati.o:
One would assume that corporate offcials would be more involved in minimiing the
overall costs of the corporation. One would also assume that corporate officials tend
to devote more time and attention to their largest customers. (Testimony of John
Bushnell, Docket UG-901459, Exhibit T-53, P. 14-15)
i agree wlth that testimony, and it is as applicable today as it was in 1990. Mr. Vititoe, Mr.
Davis. and the other WNG offcers simply do not spend the majority of their tie
supervising the line employees whose labor costs are allocated in the distribution ma
meter reading, or customer accounting categories which make up the majority of the
Company's labor expense, and the administrative costs should nöt be alocated as if they
do.
Q. What decision did the Commssion make in the WW proceeding with respect to A&G
expenses?
A. The Commission accepted the staff methodology, which allocated employee pensions and
henefits based on the labor study, propert insurance costs based on plant direct
Direct Testimony of Jim Lar
Docket No. UG-940814
Staff_PR_078 Attachment A
Page 35
Page 2 013
.,.~
4
:1
Ó
7
S
Q
10
i 1
12
D
14
15
ló
17
IX.
20
21
22
23
24
25
26
27
28
29
30
31
32
33.
allocations, and all remaining A&G expenses 50% based on throughput and 50% based on
non-gas expense.
Q. How did that method compare with the method approved in the Cascade case?
A. In the Cascade Cause U-86-100, A&G expenses were allocated based on total O&M
expense directly allocated, including gas costs for all classes. Since gas costs at that time
were about half of total expenses and were allocated on a volumetric basis, the
mathematical effect of the two methods is approximately the same. The WW
methodology. however, evolved after the availability of tranportation servce and is better
suited to the current gas utilty environment.
Q. What met-hod do you recommnd be used in this proceeding?
A. I recommend that the method approved by the Commssion in the WW proceedig be
applied. In my cost of service study, I have allocated insurance costs and pensions &
henefits as the Company has proposed. I have refunctionalzed 50% of the other A&G
accounts as production-related, and allocated them based on the total throughput factor.
The other 50% of the expenses in these A&G is allocated based on the Company labor-
cost method. This is one advantage of the cost of servce model I utilied; it is capable of
performing an allocation of this tye, for example, as shown on Page 14 of Exbit _(JL-
9). The Company's model does not produce a subtotal of O&M before A&G, and
therefore cannot perform this tye of allocation.
Vi. RATE SPREAD BETWEN CLASSES
Q. Please summarize how you. propose rates be spread among the cutomer classes in this
proceeding.
A First of all, I do not necessarily agree that rate spread should be modified in this
proceeding. The Commssion directed this proceeding to examne cost-based transportation
rates, not necessarily to redistribute the cost burden between clases. Having said that, my
Direct Testimony of Jim Laar
Docket No. UG-940814 Page 36
Staff_PR_078 Attchment A Page 3 of 3
.
.
.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
DATE PREPARD:
WITESS:
RESPONDER:
DEPARTMNT:
TELEPHONE:
04/3/2009
Tara Knox
Tara Knox
State & Federal Regulation
[phone]
IDAHO
A VU-E-09-01 1 A VU-G-09-01
IPUC
Production Request
Staff-079
REQUEST:
In Knox's Exhibit No. 11, Schedule No.5, page 5, lines 22-23, page 6, line 1, she says "The
revenue from these special contract customers has been segregated from general rate revenue and
allocated back to all the other rate classes by relative rate base." Please provide a detailed
explanation and all supporting executable electronically formatted analysis ilustrating how the
revenue from these customers is segregated from general rate revenue and allocated back to all the
other rate classes by relative rate base. Also, if any costs were attbutable to special contract
customers, please provide a detailed explanation and all supporting executable electronically
formatted analysis ilustrating how costs were proportionally allocated back to the other rate
classes by relative rate base.
RESPONSE:
Please see hardcopy workpaper pages Andrews h, Knox TLK-G-19, TLK-G-55, and TLK-G-87.
On 13 in the middle of the page, there is a note which indicates that the $431,000 of pro forma base
transportation revenue includes Special Contract revenue moved to "Other Revenue" in the
Revenue Requirement of $11 0,000 resulting in $321,000 of "Total Transp Rev" for the Revenue
Requirement. The execution of this transfer of $11 0,000 into "Other Revenue" can be seen at
column N, row 389 ofthe excel workbook "Proform 1.6.09.xls" (hardcopy print TLK-G-19). The
derivation ofthe $110,000 of special contract revenue can be found on page TLK-G-55 (which is
an excerpt from the Hirschkorn workpapers). It is made up of the sum of$89,000 of present
revenue from Schedule 159 and $21,000 of present revenue from Schedule 147.
The pro forma value in "Account 495.xx Other Gas Rev - Misc & Spec Cont Rev" of $134,000 is
assigned to rate schedules in the cost of servce model at row 417 of the Detail tab of "Idaho Gas
COS Base Case.xls" (hardcopy print TLK-G-87). As notated in the classification basis column,
the Other Revenue value has been assigned to classes "as Rate Base" which is on row 123. Related
disaggregation into function is shown in rows 430 through 433 of the same page.
The following information addresses incremental costs associated with the two contracts. In Order
No. 26559 approving the Schedule 147 special contract, the Commission found "that the 2~ per
therm contract rate for distribution service is competitive, reasonable and necessary to retain the
IMSAMT load. Avista has found that the cost of the incremental facilities installed to serve
IMSAMET were recovered by the Company in the prior contract ter. Based on the information
presented, the Company finds that the proposed contract servce charges exceed the Company's
varable cost of providing service." In Order No. 30307 approving the current Schedule 159
special contract, the Commission found "that the provisions of the Agreement are reasonable.
Considering the surrounding circumstances, the company has negotiated an acceptable net
contrbution to fixed costs."
.
.
.
Response to Staff Request No. 079
Page 2
The net contrbution to fixed costs from these special contract customers is flowing back to all
other customers as a reduction to the required return on rate base because the allocated "Other
Revenue" reduces the amount of revenue otherwise necessar to be recovered through base rates.
.
.
.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
IDAHO
A VU-E-09-01 1 A VU-G-09-01
IPUC
Production Request
Staff-080
DATE PREPARED:
WITSS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
04/0612009
Tara Knox
Tara Knox
State & Federal Regulation
[phone]
REQUEST:
In Knox's Testimony page 6, lines 17-23, page 7, lines 1-8, she talks about the "change from a
25-year to a 30-year average for normal degree days." In an effort by Staffto maintain consistency
within each rate case's Cost of Servce study, please provide a detailed explanation and all
supporting executable electronically formatted analysis (with the exception ofWC _0908_ w _30 yr
rollng. xIs) ilustrating:
a. The "concerns in another jursdiction that twenty-five years may be insuffcient to
determine 'normaL'"
b. A comparison ofthe change from a 25-year to a 30-year average for normal degree
days. In your response include all comparsons ilustrating how the final Revenue Requirement for
gas and electric is different with respect to the change from a 25-year to a 30-year average for
normal degree days.
c. The long term trend in regional temperatures. In your response include an
explanation of how the trend and varability is measured and why more recently occurng
varability is less important than long-term climatological trends when settng rates, which
frequently change on an anual basis given more recent rate case trends.
RESPONSE:
a. Please see attachment "Staff PR 080 Attachment A" which contains an e-mail
correspondence from the WUC Staff member responsible for evaluating the Company's
weather normalization adjustment expressing their concerns.
b. If the Company had used 25-year average degree days for the definition of normal in the
weather correction calculation the electrc revenue requirement would have been lower by
$27,000 and the gas revenue requirement would have been higher by $17,000. Attached is
an excel workbook labeled "StafCPR _080 Attachment B" with the calculations showing
the electric and gas load adjustments for weather with the 25 year average and what the
production property adjustment would have been with the revised loads, as well as a
calculation of the revenue requirement impact compared to the filed case.
c. The analysis relied upon for the testimony was included in the WC_0908_w_30 yr
rolling.xls workbook on the sheets labeled "Avg DDH Char", "Sheet 1 ", "1951 2008
Heating". The char (hardcopy workpaper page TLK - W -66) shows the trendline produced
by the rolling 30 year averages (annual total) using the data available from the NOAA
publication "Anual Climatological Summary" for the Spokane International Airport
National Weather Station. The equation associated with the trendline indicates that on a
rollng average basis the region has experienced more than 5 fewer heating degree days
each year since the 30 year period ended June 1981. The improved varability of30-year
over 25-year rollng averages refers to the char which shows through visual inspection that
.
Response to Staff Request No. 080
Page 2
the 25-year rolling averages bounce around more from year to year than the 30 year
averages do.
.
.
Page i of i
Knox, Tara
. '.. _..____..__~.ø._ _.,.__._,_.._..,_...,.._~~.~. ...-....' "... -y-...-_.-_._..,...- ...-. -......... .
. From: Novak, Vanda (UTe) (vnovak~utc.wa.govl
Sent: Thursday, October 02,20085:11 PM
To: Knox, Tara
Subject: 25 year weather dataset
The general reluctance to accept your 25 year n0111al weather as a future standard stems from views here that it
is a biased look at deriving a n0l11al weather pattem, that there is not significant enough statistical evidence that
the warming trend wil continue and that the trend is possibly par of the noimal climactic cycle and therefore
should not be focused on exclusively. Possibly showing something like serial correlation in the data and
sufficient weather analysis to detennine the accuracy of the continued waimer weather cycle and confidence in
the cycle lengths. Also there was a concern about weather station data quality (the lesser the quality, the more
shaky it would be to obtain an average from a smaller data set) for a year forward, absent these points, it would
be more prudent choice to probably go with the bigger dataset of30 years, unless otherwise shown marc
convincingly.
Yanda Novak
.
.
StafCPR_080 Attachment A Page 1 of 1
1 U-02-200S
.
.
.
AVIST A UTILITIES
IPUC Case No. AVU-E-09-01 and AVU-G-D9-01
Response to Staff Production Request No. 80. Part B
Revenue Requirement Impact of 25-Year Average Weather Correction vs Filed Case
Electric Weather Correction kWhs
With 25-Year Average Normal
As filed
Change in Load Adjustment
Total
(23,962,206)
(24,948,329)
986,123
$OOO's
Schedule 1 Schedule 11
(20,938,728) (3,023,478)
(21,683,164) (3,265.165)
744,436 241,687
Weather Sensitive Rate 0.07416 0.07001
Change in Revenue $72 $55,207 $16.921
Uncollectibles 0.2528%0
Commission Fees 0.2507%0
Idaho State Income Tax 1.2216%1
Operating Income Before FIT $71
Federal Income Tax 35%25
Net Operating Income Change $46
Change in Production Property Adjustment
With 25-Year Average Normal
As filed
Change in Production Propert AdjState Income Tax 1.2216%
Operating Income Before FIT
Federal Income Tax 35%
Net Operating Income Change
Electric Revenue Requirement Impact
Gas Weather Correction Therms
With 25-Year Average Normal
As filed
Change in Load Adjustment
Net Expense Rate Base Debt Cost
(5.162)(10,119)
(5,196)(10,202)
$34 $83 3.30%
0
$(34)0
(12)(1 )
$(22) $1
$(37) $10 $(27)
Total
(2,883,369)
(2,827,731 )
(55,638)
Schedule 101 Schedule 111
(2,459,925) (423,444)
(2,410,754) (416,977)
(49,171) (6,467)
Weather Sensitive Rate
Cost of Gas
Change in Revenue
Change in Gas Cost
Uncollectibles
Commission Fees
Idaho State Income Tax
Operating Income Before FIT
Federal Income Tax
Net Operating Income Change
1.19854 1.04020
0.88013 0.88013
$(66) $(58,933) $(6.727)
$(49) $(43,277) $(5,692)
0.2528%(0)
0.2507%(0)
1.2216%(0)
$(16)
35%(6)
$(11 )
$17Gas Revenue Requirement Impact
Staff_PR_080 Attachment B.xls Page 1 of 4
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4
,
2
9
7
,
6
0
3

-
3
,
6
6
9
,
9
2
3

-
1
2
,
0
2
7
,
3
2
0

-
1
1
,
2
4
2
.
2
7
6

3
,
8
6
6
,
1
7
4

-
4
,
5
7
5
.
0
1
5

5
6
9
,
7
1
6

-
3
,
6
0
8
,
6
0
3
95
4
,
2
2
3
-8
6
3
,
1
3
1

-
3
1
6
,
1
7
3

5
,
0
2
6
,
8
3
4
No

o
f

C
u
s
t
19
8
,
3
4
7
19
8
,
8
5
4
19
9
,
3
8
3
19
9
,
1
4
1
19
8
,
9
2
2
19
8
,
2
4
5
19
7
,
6
5
9

1
9
7
,
5
3
0
19
7
,
5
5
2
19
8
,
5
0
7
19
7
,
1
5
2
19
8
,
6
0
1
19
8
,
6
2
0
Us
a
g
e
/
D
O
H
0.
5
7
5
2
0.
5
7
5
2
0.
5
7
5
2
0.
3
9
8
0
0.
3
9
8
0
0.
3
9
8
0
O.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
0.
3
9
8
0
0.
3
9
8
0
0.
5
7
5
2
Us
a
g
e
/
D
O
C
O.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
0.
9
6
1
4
0.
9
6
1
4
0.
9
6
1
4
0.
9
6
1
4
O.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
WA

R
e
s

S
c
h
e
d

1
1
-6
3
0
,
1
7
4
-2
5
0
,
2
5
5
-6
4
,
3
5
9
-2
1
0
,
9
5
9
-1
6
8
,
6
2
3
58
,
2
1
7
-5
1
,
8
6
4
3,
4
3
0
-2
1
,
8
4
6
5,
7
5
6
-1
2
,
8
0
7
-4
,
6
8
7
87
,
8
2
4
No

o
f

C
u
s
t
7,
6
6
6
7,
6
2
1
7,
6
5
6
7,
6
4
8
7,
6
8
6
7,
6
9
0
7,
7
0
3
7,
7
2
6
7,
7
6
9
7,
7
7
8
7,
5
3
6
7,
5
8
4
7,
5
9
8
Us
a
g
e
/
D
O
H
0.
2
6
2
7
0.
2
6
2
7
0.
2
6
2
7
0.
1
5
4
5
0.
1
5
4
5
0.
1
5
4
5
O.

0
0
0
0
o.

0
0
0
0
O.

0
0
0
0
0.
1
5
4
5
0.
1
5
4
5
0.
2
6
2
7
Us
a
g
e
/
D
O
C
O.
0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
0.
1
4
8
0
0.
1
4
8
0
0.
1
4
8
0
0.
1
4
8
0
O.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
WA

C
o
r
n

S
c
h
e
d

1
1
-2
,
8
0
7
,
7
7
6
-8
4
0
,
0
4
9
-2
1
5
,
7
3
1
-7
0
5
,
4
9
2
-3
9
8
,
7
9
3
-4
1
6
,
9
0
6
-3
0
1
,
5
5
2
61
,
4
2
8
-3
8
9
,
7
0
0
10
2
,
4
1
3
11
,
6
7
1
-1
1
,
1
6
6
29
6
,
1
0
1
No

o
f

C
u
s
t
19
,

0
0
7
19
,

a
l
l
19
,

0
7
1
19
,

0
0
7
19
,

0
4
0
19
,

0
2
3
19
,

0
9
4
18
,
9
9
8
19
,

0
3
0
19
,

0
0
4
18
,
8
4
5
18
,
9
2
5
19
.

0
3
7
Us
a
g
e
/
D
O
H
0.
3
5
3
5
0.
3
5
3
5
0.
3
5
3
5
0.
1
4
7
5
0.
1
4
7
5
0.
1
4
7
5
O.

0
0
0
0
O.
0
0
0
0
O.
0
0
0
0
0.
1
4
7
5
0.
1
4
7
5
0.
3
5
3
5
Us
a
g
e
/
D
O
C
O.
0
0
0
0
O.

0
0
0
0
O.
0
0
0
0
2.
2
4
1
8
2.
2
4
1
8
1.
0
7
7
8
1.
0
7
7
8
1.
0
7
7
8
1.

0
7
7
8
2.
2
4
1
8
2.
2
4
1
8
O.

0
0
0
0
WA

R
e
s

S
c
h
e
d

2
1
-3
6
2
,
3
5
7
-1
3
9
,
9
9
7
-3
5
,
8
3
9
-1
1
5
,
9
4
1
-8
4
,
1
9
3
29
,
4
6
2
-3
7
,
6
8
9
4,
9
1
8
-3
1
,
1
5
0
8,
1
9
7
-6
,
3
3
8
-2
,
3
7
2
48
,
5
8
5
No

o
f

C
u
s
t
72
71
71
70
71
72
75
75
75
75
69
71
70
Us
a
g
e
/
D
O
H
15
.
7
7
4
3
15
.
7
7
4
3
15
.
7
7
4
3
8.
3
5
0
8
8.
3
5
0
8
8.
3
5
0
8
O.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
8.
3
5
0
8
8.
3
5
0
8
15
.
7
7
4
3
Us
a
g
e
/
D
O
C
o.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
O.
0
0
0
0
21
.
8
5
9
7

2
1
.

8
5
9
7
21
.

8
5
9
7
21
.

8
5
9
7
O.

0
0
0
0
O.

0
0
0
0
O.
0
0
0
0
10

R
e
s

S
c
h
e
d

1
-2
0
,
9
3
8
,
7
2
6
-7
,
5
0
8
,
4
0
0

-
1
,
9
0
9
,
6
2
6
-6
,
2
6
4
,
5
0
1
-6
,
0
6
7
,
3
3
2

2
,
0
9
2
,
5
9
4

-
2
,
3
1
5
,
6
0
1

2
6
0
,
8
4
7

-
1
,
6
4
7
,
2
1
4
43
6
,

0
6
1
-4
6
3
,
8
1
7

-
1
7
0
,
2
7
2

2
,
6
1
8
,
5
3
3
No

o
f

C
u
s
t
98
,
5
4
8
99
,
4
4
9
98
.
8
0
1
98
,
7
7
8
98
,
5
1
9
98
,
4
6
9
98
,
3
3
2
98
,
7
7
2
98
,
4
8
4
99
,

0
7
1
97
,
2
2
2
98
,
1
5
1
98
,
5
3
0
Us
a
g
e
/
D
O
H
0.
6
0
4
0
0.
6
0
4
0
0.
6
0
4
0
0.
4
3
3
7
0.
4
3
3
7
0.
4
3
3
7
O.
0
0
0
0
0.
0
0
0
0
O.

0
0
0
0
0.
4
3
3
7
0.
4
3
3
7
0.
6
0
4
0
Us
a
g
e
/
D
O
C
O.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
0.
8
8
0
3
0.
8
8
0
3
0.
8
8
0
3
0.
8
8
0
3
O.

0
0
0
0
0.
0
0
0
0
o.
0
0
0
0
10

R
e
s

S
c
h
e
d

1
1
-3
4
0
,
1
7
8
-1
3
9
,
2
4
9
-3
5
,
2
8
1
-1
1
5
,
9
3
0
-7
7
,
9
9
3
27
,
1
5
4
-2
8
,
4
7
6
2,
9
4
1
-1
8
,
5
3
8
4,
9
1
0
-5
,
9
0
2
-2
,
1
7
7
48
,
3
6
3
No

o
f

C
u
s
t
4,
2
4
9
4,
2
7
8
4,
2
3
4
4.
2
4
0
4,
2
3
8
4,
2
7
6
4,
2
6
0
4,
3
0
3
4,
2
8
3
4,
3
1
1
4,
1
4
0
4,
2
0
0
4,
2
2
1
Us
a
g
e
/
D
O
H
0.
2
6
0
4
0.
2
6
0
4
0.
2
6
0
4
0.
1
2
9
6
0.
1
2
9
6
0.
1
2
9
6
O.

0
0
0
0
O.
0
0
0
0
O.
0
0
0
0
0.
1
2
9
6
0.
1
2
9
6
0.
2
6
0
4
Us
a
g
e
/
D
O
C
o.
0
0
0
0
O.
0
0
0
0
O.
0
0
0
0
0.
0
0
0
0
O.

0
0
0
0
0.
2
2
7
8
0.
2
2
7
8
0.
2
2
7
8
0.
2
2
7
8
O.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
10

C
o
r
n

S
c
h
e
d

1
1
-2
,
6
8
3
,
2
9
8
-8
8
3
,
2
2
8
-2
2
4
,
8
0
8
-7
3
6
,
4
8
4
-6
8
5
,
2
6
6
23
6
,
7
0
9
-3
8
4
,
8
8
3
66
,
5
0
5
-4
1
9
,
5
8
4
11
0
,
4
8
5
-5
2
,

0
4
1
-1
9
,
2
6
3
30
8
,
5
5
8
No

o
f

C
u
s
t
14
,
5
1
1
14
,
6
2
6
14
,
5
4
2
14
,
5
1
9
14
,
5
0
5
14
,
5
2
0
14
,
5
2
4
14
,
5
9
6
14
,
5
4
0
14
,
5
4
9
14
,
2
2
0
14
,
4
7
5
14
,
5
1
6
Us
a
g
e
/
D
O
H
0.
4
8
3
1
0.
4
8
3
1
0.
4
8
3
1
0.
3
3
2
7
0.
3
3
2
7
0.
3
3
2
7
O.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
0.
3
3
2
7
0.
3
3
2
7
0.
4
8
3
1
Us
a
g
e
/
D
O
C
O.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
O.

0
0
0
0
1.
5
1
8
8
1.
5
1
8
8
1.
5
1
8
8
1.
5
1
8
8
O.

0
0
0
0
O.
0
0
0
0
O.

0
0
0
0
To
t
a
l

E
l
e
c
t
r
i
c

A
d
j
u
s
t
m
e
n

-
6
7
,
9
4
5
,
6
0
5

-
2
4
,
0
5
8
,
7
7
9

-
6
,
1
5
5
,
5
6
8

-
2
0
,
1
7
6
,
6
2
6

-
1
8
,
7
2
4
,
4
7
5

5
,
8
9
3
,
4
0
5

-
7
,
6
9
5
,
0
8
0

9
6
9
,
7
8
6

-
6
,
1
3
6
,
6
3
5

1
,
6
2
2
.
0
4
5

-
1
,
3
9
2
,
3
6
6

-
5
2
6
,
1
1
0

8
,
4
3
4
,
7
9
8
WA

s
u
b
t
o
t
a
l
-4
3
,
9
8
3
,
4
0
4

-
1
5
,
5
2
7
,
9
0
3

-
3
,
9
8
5
.
8
5
3

-
1
3
,
0
5
9
,
7
1
2

-
1
1
,
8
9
3
,
8
8
4

3
,
5
3
6
,
9
4
7

-
4
,
9
6
6
,
1
2
0

6
3
9
.
4
9
3

-
4
.
0
5
1
,
3
0
0

1
,
0
7
0
,
5
8
9
-8
7
0
,
6
0
6

-
3
3
4
,
3
9
7

5
,
4
5
9
,
3
4
4
10

s
u
b
t
o
t
a
l
-2
3
,
9
6
2
,
2
0
2
-8
,
5
3
0
,
8
7
6

-
2
,
1
6
9
,
7
1
4
-7
,
1
1
6
,
9
1
4
-6
,
8
3
0
,
5
9
0

2
,
3
5
6
,
4
5
8

-
2
,
7
2
8
,
9
5
9

3
3
0
,
2
9
3

-
2
,
0
8
5
,
3
3
5
55
1
,
4
5
6
-5
2
1
,
7
6
0

-
1
9
1
.
7
1
3

2
,
9
7
5
,
4
5
4
Su
m
r
i
z
e

b
y

S
c
h
e
d
u
l
e
WA

S
c
h

1
-4
0
,
1
8
3
,
0
9
7

-
1
4
.
2
9
7
.
6
0
3

-
3
,
6
6
9
,
9
2
3

-
1
2
,
0
2
7
,
3
2
0

-
1
1
,
2
4
2
,
2
7
6

3
,
8
6
6
,
1
7
4

-
4
,
5
7
5
,
0
1
5

5
6
9
,
7
1
6

-
3
,
6
0
8
,
6
0
3
95
4
,
2
2
3
-8
6
3
,
1
3
1

-
3
1
6
,
1
7
3

5
.
0
2
6
,
8
3
4
WA

S
c
h

1
1
-3
,
4
3
7
,
9
4
9
-1
,
0
9
0
,
3
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AVISTA UTILITIES
Production Factor Adjustment
. Idaho Electric Rate Case
Twelve Months Ended September 30, 2008
$OOO's Production Transmission Pro formed Production Test Year Workpaper
Penod Total Factor Adjustment Total References
Pro forma Rate Base
Plant
Capital Additions 383,217 165,657 548,874 0.031706 17,403 531,471 PF6,7
Spokane River Relicensing 13,596 13,596 0.040487 550 13,046 PF10
CDA Tribe Settlement 11,930 11,930 0.040487 483 11,447 PF11
Montana Lease 2,435 2,435 0.040487 99 2,336 PF12
Total pro formed Plant 411,178 165,657 576,835 18,535 558,300
Accumulated Depreciation
Capital Additions (148,563)(57,612)(206,175)0.031706 (6,537)(199,638)PF6,7
Spokane River Relicensing (145)(145)0.040487 (6)(139)PF10
CDA Tribe Settement (219)(219)0.040487 (9)(210)PF11
Total pro formed AD (148,927)(57,612)(206,539)(6,552)(199,987)
Accumulated Deferred FIT
Capital Additions (35,979)(15,208)(51,187)0.031706 (1,623)(49,564)PF6,7
Spokane River Relicensing (1,267)(1,267)0.040487 (51)(1,216)PF10
CDA Tribe Settlement (3,850)(3,850)0.040487 (156)(3,694)PF11
Montana Lease (852)(852)0.040487 (34)(818)PF12
Total pro formed DFIT (41,948)(15,208)(57,156)(1,864)(55,292)
Net Rate Base 220,303 92,837 313,140 10,119 303,021
Depreciation/Amortization
Capital Additions 9,576 3,340 12,916 0.031706 410 12,506 PF6,7
Spokane River Relicensing 1,037 1,037 0.040487 42 995 PF10
CDA Tribe Settlement 401 401 0.040487 16 385 PF11.Montana Lease 1,917 1,917 0.040487 78 1,839 PF12
Total pro formed Depr/Amort 12,931 3,340 16,271 546 15,725
Propert Taxes
Capital Additions 3,771 1,816 5,587 0.031706 177 5,410 PF 6,7, Land B
Total pro formed Propert Tax 3,771 1,816 5,587 177 5,410
O&M Expense
Spokane River Relicensing 1,063 1,063 0.040487 43 1,020 PF10
Power Supply - Purchased Power 77,830 77,830 0.040487 3,151 74,679 PF1
Power Supply 38,157 5,017 43,174 0.040487 1,748 41,426 PF1
Labor 4,918 1,420 6,338 0.040487 257 6,081 PF 3
Transmission 698 698 0.040487 28 670 PF5
Asset Management 1,047 1,047 0.040487 42 1,005 PF9
Mercury Emission 596 596 0.040487 24 572 PF13
CS2 Levelized (3)(3)0.040487 (3)PF15
Production Plant O&M 9,108 9,108 0.040487 369 8,739 PF17
Benefits 1,494 432 1,926 0.040487 78 1,848 PF18 and PF3
Wartsila Amortzation 185 185 0.040487 7 178 PF21
Colstrip Lawsuit 369 369 0.040487 15 354 PF22
Total pro formed O&M Expense 133,717 8,614 142,331 5,762 136,569
Revenue
Power Supply - Sales for Resale 28,782 28,782 0.040487 1,165 27,617 PF1
Power Supply - Other Revenue 115 115 0.040487 5 110 PF1
Transmission - Other Revenue 3,357 3,357 0.040487 136 3,221 PF5
Chicago Climate Exchange - Other ¡425 425 0.040487 17 408 PF20
Total pro formed Revenues 29,322 3,357 32,679 1,323 31,356
Net Operating Expense Before TaxE 121,097 10,413 131,510 5,162 126,348.Idaho Retail Loads PF2
12 Months Ended June 2010 3,635,626 0.040487 June 2010 Factor
12 Months Ended December 2009 3,602,657 0.031706 December 2009 Factor
Normalized 12 Months Ended September 2008 3,488,432
StafCPR_080 Attchment B.xls Page 3 of4
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6
No

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63
,
5
9
7
63
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7
7
1
63
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7
4
7
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1
0
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8
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8
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3
6
0
No

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t
7,
3
2
4
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3
4
8
7,
3
6
7
7,
3
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4
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1
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4
6
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3
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4
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4
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1
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1
5
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2
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5
7
ID

I
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S
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1
0
1
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2
6
9
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,
7
9
9
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3
3
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1
4
8
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6
7
7
92
4
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5
0
0
0
0
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0
7
-8
0
1,

3
0
1
No

o
f

C
u
s
t
71
74
71
73
69
69
70
72
71
71
69
73
72
Us
a
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D
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4
1
0
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4
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7
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4
1
0
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2
7
3
2
0.
2
7
3
2
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2
7
3
2
0.
0
0
0
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0.
0
0
0
0
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0
0
0
0
0.
2
7
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2
7
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2
0.
4
1
0
7
ID

C
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S
c
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d

1
1
1
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2
3
,
4
4
4
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6
3
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8
7
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3
8
8
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3
7
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7
8
5
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3
7
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2
2
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47
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5
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2
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2
5
0
0
0
0
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,
9
9
5
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,
7
1
2
56
,
9
5
9
No

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f

C
u
s
t
74
7
73
9
74
8
74
1
75
3
75
6
76
2
77
2
76
3
76
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70
8
72
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73
1
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7
7
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7
7
0
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7
7
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9
1.
2
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3
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1.
2
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3
4
1.
2
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0.
0
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2
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3
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9
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0
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6
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6
7
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2

-
2
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1
8
9
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8
5
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9
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2
8
3
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JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
REQUEST:
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
IDAHO
A VU-E-09-01 / A VU-G-09-01
IPUC
Production Request
Staff-082
DATE PREPARD:
WITSS:
RESPONDER:
DEP ARTMNT:
TELEPHONE:
04/0612009
Clint Kalich
Clint Kalich
Energy Resources
[phone]
Please provide electrc and natual gas forward prices for July 2009 through June 2010 contract
months (the pro forma period) as reported daily for all settlement dates durng the perod 11112007
through the present for each of the locations included in the forward price data previously provided
in the workpapers of Clint Kalich. Please provide the data in an electronic Excel format. Please
include any analysis used to prepare, adjust or modify the data for use in AURORA. Please cite
the source for the price data and discuss any adjustments or assumptions made by A vista in
preparng the data.
RESPONSE:
Please see Avista's response 082C, which contains TRADE SECRET, PROPRIETARY or
CONFIDENTIAL information and exempt from public view and is separately filed under
IDAPA 31.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code, and pursuant to the
Protective Agreement between Avista and IPUC Staff dated Januar 8, 2009.
.
.
.
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
REQUEST:
A VISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
IDAHO
A VU-E-09-01 1 A VU-G-09-01
IPUC
Production Request
Staff-084
DATE PREPARD:
WITESS:
RESPONDER:
DEP ARTMENT:
TELEPHONE:
04/0612009
Clint Kalich
C. Kalich 1 L. Andrews
Energy Resources
[phone]
Please provide AURORA summar output showing results if a weather normalized test year
system load (October 1, 2007 through September 30, 2008) is used rather than the July 2009
through June 2010 pro forma system load. Provide the output in a format similar to that used in
Kalich's Exhibit No.5, Schedule 2.
RESPONSE:
Please see Avista's response 084C, which contains TRADE SECRET, PROPRIETARY or
CONFIDENTIAL information and exempt from public view and is separately fied under
IDAP A 31.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code, and pursuant to the
Protective Agreement between Avista and IPUC Staff dated January 8, 2009.
Please also see attachment "StafCPR_083 Attachment C-Summary of PR_083-086.xls" which
contains a summar of the requested changes for Staff Production Requests StafCPR _ 083 -
Staff PR 086.
.
.
.
JUISDICTION:
CASE NO:
REQUESTER:
TYPE:
REQUEST NO.:
REQUEST:
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
IDAHO
A VU-E-09-01 1 A VU-G-09-01
IPUC
Production Request
Staff-085
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
04/0612009
Clint Kalich
C. Kalich 1 L. Andrews
Energy Resources
[phone]
Please provide AURORA sumar output showing results if term power and natural gas
transactions (less than 18 months) are excluded from the analysis. Provide the output in a format
similar to that used in Kalich's Exhibit No.5, Schedule 2.
RESPONSE:
Please see Avista's response 085C, which contains TRAE SECRET, PROPRIETARY or
CONFIDENTIAL information and exempt from public view and is separately filed under
IDAPA 31.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code, and pursuant to the
Protective Agreement between Avista and IPUC Staff dated Januar 8,2009.
Please also see attachment "StafCPR_083 Attachment C-Summar of PR_083-086.xls" which
contains a summar of the requested changes for Staff Production Requests StafCPR_083 -
Staff PR 086.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION.JURISDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
IDAHO
A VU-E-09-01 1 AVU-G-09-01
IPUC
Production Request
Staff-086
DATE PREPARED:
WITNESS:
RESPONDER:
DEP ARTMENT:
TELEPHONE:
04/06/2009
Clint Kalich
C. Kalich/L. Andrews
Energy Resources
[phone]
REQUEST:
Please provide AURORA sumar output showing results if all term power and natural gas
transactions (less than 18 months) are included in the analysis, but updated to include all currently
effective term transactions rather than those that were in effect at the time the Company filed its
rate case Application. Provide the output in a format similar to that used in Kalich's Exhibit No.5,
Schedule 2.
RESPONSE:
Please see Avista's response 086C, which contains TRAE SECRET, PROPRIETARY or
CONFIDENTIAL information and exempt from public view and is separately filed under
IDAP A 31.01.01, Rule 067 and 233, and Section 9-340D, Idaho Code, and pursuant to the
Protective Agreement between Avista and IPUC Staff dated January 8, 2009.
. Please also see attachment "StafCPR _ 083 Attachment C-Summar of PR _ 083-086.xls" which
contains a summary of the requested changes for Staff Production Requests StafCPR_083 -
Staff PR 086.
.
.
.
.
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
REQUEST:
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMTION
IDAHO
A VU-E-09-01 1 A VU-G-09-01
IPUC
Production Request
Staff-089
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMNT:
TELEPHONE:
04/03/2009
. Clint Kalich
Clint Kalich
Energy Resources
[phone]
On what date was the July 2009 through June 2010 pro forma load forecast used in AURORA
modeling runs prepared? When wil the next load forecast coverng the pro forma period be
prepared and available? If a revised load forecast coverng the pro forma period has been prepared
since the Company submitted its rate case Application, please provide a copy.
RESPONSE:
The July 2009 through June 2010 pro forma load forecast used in AURORA modeling rus was
prepared in July 2008. There has not been a revised load forecast coverng the pro forma period
since the Company submitted its rate case Application. The Company is in the process of
preparng an update to the electric load forecast to reflect possible changes in load due to the
curent economic downturn. It is scheduled to be completed in April 2009. At this time, it is not
possible to determine if changes wil be materal because in mid-July 2008 we predicted an
economic downturn would occur in 2009 and 2010. At the time a new load forecast is completed a
copy will be provided.
.
.
.
AVISTA CORPORATION
RESPONSE TO REQUEST FOR INFORMATION
JUSDICTION:
CASE NO:
REQUESTER:
TYE:
REQUEST NO.:
DATE PREPARD:
WITSS:
RESPONDER:
DEPARTMENT:
TELEPHONE:
04/0312009
Dave DeFelice
Jeane Pluth
State & Federal Reg.
[phone]
IDAHO
A VU-E-09-01 1 A VU-G-09-01
IPUC
Production Request
Staff-098
REQUEST:
Please itemize the revenue producing 2009 capital additions stated on page 24, line 14-16 ofMr.
Defelice's testimony as being excluded. Please explain the rationale for the exclusions.
RESPONSE:
The Company separates the growth/revenue producing capital projects in specific ERs. The 2009
revenue producing capital that was not included in the pro forma capital adjustment is detailed on
DeFelice's workpapers at page 54, as follows:
Revenue Supported ER's (Budget Category: New Revenue/Customers)
Electnc Revenue Blanket 1000
Gas Revenue Blanket 1001
Elec Meters Minor Blanket 1002
Distribution Line Transformen 1003
Street Light Minor Blanket 1004
Area Light Minor Blanket 1005
Combustion Turbine 1010
Gas Meters Minor Blanket 1050
Gas Regulators Minor Blanke' 1051
Industrial Gas Cust Minor Blkl 1052
Gas ERT Minor Blanket 1053
Total
All 2009
(OOO's)
14,913
14,980
900
12,096
1,250
521
1,500
650
200
500
47,510
The pro forma capital expenditures for 2009 that the Company included in this filing excludes
distribution related capital expenditures made that are associated with connecting new customers
to the Company's system (shown above). The rationale for excluding the revenue producing
capital, as described in Mr. DeFelice's direct testimony on page 30, is that the Company
recognizes the fact that new customers provide incremental revenue that helps offset the revenue
requirements of the distrbution related capital additions that the Company incurs to provide
service to those customers. These adjustments eliminated the AM 2008 and EOP 2009 capital
activity related to new customer connections in order to avoid an unintended mismatch of revenues
exceeding the cost to serve customers.