HomeMy WebLinkAbout20101014Schoenbeck Di.pdfMelinda J. Davison
Davison VanCleve, PC
333 SW Taylor, #400
Portland, OR 97204
Tel: 503.241.7242
Fax: 503-241-8160
mjd~dvc1aw.com
R:E'CE r1
zuieoer l 4 AM 9: 32
Ronald L. Wiliams, ISB No. 3034
Wiliams Bradbur, P.C.
1015 W. Hays S1.
Boise ID, 83702
Telephone: 208-344-6633
Fax: 208-344-0077
ron~wiliamsbradbur.com
Attorneys for PacifCorp Idaho Industrial Customers
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE )APPLICATION OF ROCKY )
MOUNTAIN POWER FOR APPROVAL )
OF CHANGES TO ITS ELECTRIC )
SERVICE SCHEDULES AND A PRICE )
INCREASE OF $27.7 MILLION OR )
APPROXIMATELY 13.7 PERCENT )
CASE NO. PAC-E-IO-07
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
DIRECT TESTIMONY OF DONALD SCHOENBECK, RANDALL J. FALKENBERG,
AND GREG R. MEYER
Davison Van Cleve PC
TEL (503) 241-7242 . FAX (503) 241-8160 . mail~dvclaw.com
Suite 400333 SW TaylorPortland, OR 97204
RECE F:f)
2010 OCT 14 APi 9: 32
October 14,2010
Via Email and Federal Express
Jean Jewell
Commission Secretary
Idaho Public Utilties Commission
PO Box 83720
Boise, ID 83720-0074
Re: In the matter of the Application ofPacifiCorp d/b/a Rocky Mountain
Power for Approval of Changes to its Electrc Service Schedules
Case No. PAC-E-IO-07
Dear Ms. Jewell:
Enclosed please find an original and nine (9) copies of the Direct Confidential
Testimony of Greg Meyer and Radall Falkenberg, the original and nine (9) copies of the Direct
Redacted Testimony of Greg Meyer and Randall Falkenberg, and the original and nine (9) copies
of the Direct Testimony of Donald Schoenbeck.
Than you for your assistance.
&:.~
Sarah A. Kohler
Enclosures
cc: Service List
CERTIFICATE OF SERVICE
I hereby certify that I have ths day served the Direct Testimony of Greg Meyer,
Randall Falkenberg, and Donald Schoenbeck on behalf ofIndustrial Customers of Northwest
Utilties upon all paries of record in ths proceeding by mailng a copy thereofin a sealed, first-
class postage prepaid envelope to each individual's last-known address, as listed below.
Confidential versions were sent only tn individuals who signed the protective
DATED this 14th day of October, 2010.
Davison Van Cleve, P.C.~6k
Sarah A. Kohler
Ted Weston
PaciflCorp/dba Rocky Mountain Power
201 S, Main Street, Suite 2300
Salt Lake City, UT 84111
E-Mail: ted.weston(gpacificorp.com
Paul J. Hickey
Hickey & Evans, LLP
1800 Carey Ave., Suite 700
PO Box 467
Cheyenne, WY 82003
E-Mail: phickey(ghickeyevans.com
(W Mark C. Moench (C)
Daniel Solander
PaciflCorp/dba Rocky Mountain Power
201 S. Main Street, Suite 2300
Salt Lake City, UT 84111
E-Mail: mark.moench(gpacificorp.com
daniel.so lander(gpacificorp .com
Scott Woodbury (C)
Deputy Attorney General
Idaho Public Utilties Commission
427 W. Washington (83702)
PO Box 83720
Boise,ID 83720-0074
E-Mail: scott.woodbury(gpuc.daho.gov
Randall C. Budge
Monsanto Company
Racine Olson Nye Budge & Bailey
201 E. Center
PO Box 1391
Pocatello,ID 83204-1391
E-Mail: rcb(gracinelaw.net
(W) Katie Iverson
Monsanto Company
Brubaker & Associates
17244 W. Cordova Court
Surprise, AZ 85387
E-Mail: kiverson(gconsultbai.com
PAGE 1- CERTIFICATE OF SERVICE
¡-c=..e:o("-l..,¡
~\...(,N
(W) James R. Smith
Monsanto Company
PO Box 816
Soda Springs, ID 83276
E-Mail: jim.r.smith(gmonsanto.com
Anthony Yankel
Idaho Irrigation Pumpers Association, Inc.
29814 Lake Road
Bay Vilage, OH 44140
E-Mail: tony(gyankeL.net
Benjamin J. Otto
Idaho Conservation League
710 N. 6th Street
POBox 844
Boise, ID 83702
E-Mail: botto(gidahoconservation.org
Brad M. Purdy
Community Action Partnership Association of
Idaho
Attorney at law
2019 N. 17th Street
"Boise,ID 83702
E-mail: bmpurdy(ghotmaiL.com
PAGE 2 - CERTIFICATE OF SERVICE
Eric L. Olson
Idaho Irrigation Pumpers Association, Inc.
Racine Olson Nye Budge & Bailey
201 E. Center
PO Box 1391
Pocatello, ID 83204-1391
E-Mail: elo(gracinelaw.net
Tim Buller
Jason Harris
Agrium, Inc.
3010 Conda Road
Soda Springs, ID 83276
E-Mail: tbuller(gagrium.com
jaharisifagrium.com
Ronald L. Williams
PaciflCorp Idaho Industrial Customers
Wiliams Bradbur, P.C.
1015 W.Hays St.
Boise, ID 83702
E-Mail: ronifwiliamsbradbury.com
Dr. Don Reading
6070 Hil Road
Boise,ID 83703
E-mail: dreading(gmindspring.com
.
\1
~Hl nrT i i q: 1.1b." I'.. Vi., i.l - 'i
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE )
APPLICATION OF ROCKY MOUNTAIN )
POWER FOR APPROVAL OF )
CHANGES TO ITS ELECTRIC )
SERVICE SCHEDULES AND A PRICE )
INCREASE OF $27.7 MILLION OR )
APPROXIMATELY 13.7 PERCENT )
CASE NO. PAC-E-I0-07
Direct Testimony of Donald W.
Schoenbeck
DIRECT TESTIMONY OF DONALD W. SCHOENBECK
ON BEHALF OF
THE PACIFICORP IDAHO INDUSTRIL CUSTOMERS
October 14,2010
1 Q.
2 A.
3
4
5 Q.
6 A.
7
8
9
10
11 Q.
12 A.
13
14
15 Q.
16 A.
17
18
19
20
I. INTRODUCTION AND SUMMARY
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
My name is Donald W. Schoenbeck. I am a member of Regulatory &
Cogeneration Services, Inc. ("RCS"), a utilty rate and economic consulting firm.
My business address is 900 Washington Street, Suite 780, Vancouver, WA 98660.
PLEASE DESCRIBE YOUR BACKGROUND AND .EXPERIENCE.
I've been involved in the electrc and gas utilty industries for over 35 years. For
the majority of this time, I have provided consulting services for large industrial
customers addressing regulatory and contractual matters. A further description of
my educational background and work experience can be is attached as Exhibit
601 in this proceeding.
ON WHOSE BEHALF ARE YOU APPEARG IN TilS PROCEEDING?
I am testifying on behalf of the PacifiCorp Idaho Industral Customers ("PUC").
PUC is a coalition of Idaho industrial companies served by Rocky Mountain
Power ("RMP" or the "Company").
WHAT TOPICS WILL YOUR TESTIMONY ADDRESS?
I wil address the Company's hourly load data, certain aspects of the Company's
cost-of-service study presented in Exhibit No. 49, the Company's proposed rate
spread presented in Exhibit No. 50 and Schedule 6, 6A and 9 rate design. This
testimony wil not address revenue requirement issues. PUC is submitting
separate testimony regarding revenue requirement matters.
1
Schoenbeck, Di
PacifiCorp Idaho. Industrial Customers
1 Q.
2
3 A.
4
5
6
7
8
9
LO
11
12
13
14
15
16
17
18
19
20
21
22
PLEASE BRIEFLY SUMMARIZE YOUR FINDINGS AND
RECOMMNDATIONS ADDRESSED IN THIS TESTIMONY.
The Company's jurisdictional separation study uses hourly load data from 2010 to
assign system costs between the various state jursdictions with certain
adjustments. However, the Company's cost-of-service study uses hourly load
data from 2009 for most classes and an average of five historical years for the
irrigation class (Schedule 10) and one of the contract customers for assignng
generation and transmission demand-related costs. In future proceedings, PIle
recommends the same load research data be used in both studies to more
accurately determine cost responsibilty. The demand allocation factors used in
the Company's cost of service study should be modified to more accurately assign
demand-related costs. I recommend the class demand allocation factor be based
on the comparable jursdictional peak hour with a more up to date irrgation class
demand. The Company's twelve monthly coincident peak factor ("12 CP") for
assigning generation and transmission-related demand costs should be replaced
with a winter/sumer peak factor ("W/S CP") using the peak load months of July
and December. The weighted twelve monthly peak factor used by the Company
for distribution-related demand costs should be replaced with the class maximum
peak demands ("1 NCP") to more accurately assign distribution cost
responsibilty.
The Company's rate spread recommendation is based on the results
indicated by its cost study. PUC supports a cost-based rate spread approach, but it
2
Schoenbeck, Di
PacifiCorp Idaho Industral Customers
1 should be done using the results ofthe PILC cost-of-service study.
2 The Company's Schedule 6, 6A and 9 rate design applies a slightly greater
3 increase to the demand charges as compared to the energy charges. PILC supports
4 this cost-based rate design for these rate schedules.
n. HOURY LOAD DATA
5 Q.
6 A.
7
8
9
10
11
12
13
14
15
16
17
18
19
20
PLEASE EXPLAIN THE RELEVANCE OF LOAD RESEARCH DATA.
Load research data is the necessary foundation of any cost-of-service study. Most
of the meters installed for biling purposes do not have the capabilty to record
customer usage by time period (for example, at five minute intervals). Typical
meters for residential customers and small commercial customers simply record
accumulated energy usage (kilowatt-hours, or "kWhs"). The next most prevalent
meters-installed for customers on a tarff with demand charges-record the
accumulated kWhs and the peak hourly value for the biling period. Usually, only
the largest customers-such as those on Schedule 9-have "time-of-use" meters
installed. These meters record energy usage at very small time intervals-
typically every five minutes. Consequently, it is necessary to undertke a load
research program and install time-of-use meters-generally through a sampling
selection process-to ascertin class demand levels and class contributions to
system or local peaks for almost all classes of customers. Absent this critical
information, "guestimates" must be made to derive the demand allocation factors
used to assign class cost responsibilty within a cost-of-service study.
3
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
1 Q.DOES THE COMPANY HA VE CURRNT LOAD RESEARCH
2 INFORMATION FOR ALL CUSTOMER CLASSES?
3 A.Yes. The Company's response to the Idaho Irrgation Punpers Association, Inc.
4 ("IIPA") Data Request 2D (attched as Exhbit 603) indicates the time period over
5 which the load research data was collected. Except for Schedule 19, the data
6 response indicates very recent time periods. The Company's response to IIPA
7 Data Request 8 (attched as Exhbit 604) includes an EXCEL spreadsheet that
8 contans the 2009 test period hourly loads for each class. The hourly load
9 research data from 2009 was adjusted upward or downward to achieve the
10 monthly energy sales level for each class. The Company provided this data as
11 support for the class cost-of-service study demand allocation factors.
12 Q.DID THE COMPANY USE THIS SAME TYPE OF HOURLY CLASS
13 LOAD DATA IN ITS JURISDICTIONAL SEPARATION STUDY TO
14 DERIVE THE ALLOCATION OF SYSTEM COSTS TO IDAHO?
15 A.No. As noted in the written response to lIP A 8, the Idaho jursdictional loads
16 were not derived from class hourly load data. The response states that "different
17 data sources" are used and that the class load data does not "flow through to the
18 state jursdiction load."
19 Q.HA VE YOU ANALYZED AND COMPARED THE JURISDICTIONAL
20 PEAKS AND THE CLASS LOAD PEAKS?
21 A.Yes. The following table presents the monthly Idaho jursdictional megawatt
22 ("MW") peak values from RMP's Exhbit 2, page 10.13, with the class peak
23 demands set fort in Exhibit 49.
4
Schoenbeck, Di
PacifiCorp Idaho Industral Customers
Jurisdictional Adjusted
Cost Study Difference CostMonthDataJurisdictionalDataStudy - Adj JurisData
January 40 406 466 60
February 416 416 434 18
March 399 399 396 -3
April 415 415 387 -28
May 503 503 442 -61
June 613 429 633 204
July 664 475 496 21
August 538 356 534 178
September 447 447 388 -59
October 406 40 372 -34
November 443 443 414 -29
December 467 467 40 -63
1 The values in the column labeled "Jurisdictional Data" are the projected peaks
2 prior to any adjustments for any load curailment or dispatch program. The
3 colum labeled "Adjusted Jurisdictional Data" are the values that are used to
4 allocate and assign system related costs to Idaho. In this colum, the months of
5 June, July and August conta lower values (about 185 MWs) reflecting the
6 expected curailment attbutable to the irrigation load control programs. The
7 colum labeled "Cost Study Data" shows the aggregate system peak used in the
8 cost study. For this colum, it should be noted that the peak demand for the
9 irrgation class is derived from five years of historical data affecting the demands
10 for the months of June though September. (The Company used a five year
11 average of historical data for one contract customer as well). The last column in
12 the above table shows the difference between the adjusted jursdictional load and
5
Schoenbeck, Di
PacifiCorp Idaho Industral Customers
1 class demand total. A cursory review of this column raises concemsover the
2 level of the irrigation peak dem,and in the cost study during the irrigation season
3 but there are differences in all other months that cannot be explained by simply
4 the one year difference represented by the data (2009 versus 2010).
5 Q.
6
ARE THE PEAK DEMANDS IN THE ABOVE TABLE FOR THE SAME
DAY AND HOUR OF EACH MONTH?
7 A.No. The following table shows the day and hour of the peak demand used in the
8 jurisdictional separation study and the class cost of service study.
Month Jurisdictional Company Cost
Peaks Study
January 25th,19:00 27th, 9:00
Februar 4th,8:00 10th, 20:00
March 30th, 8:00 lIth, 9:00
April 1st, 8:00 1st, 10:00
May 18th,15:00 29th, 17:00
June 24th, 15:00 29th, 18:00
July 19th, 16:00 27th, 18:00
August 26th, 15:00 3rd, 18:00
September 9th, 15:00 2nd, 17:00
October 4th, 19:00 28th, 10:00
November 24th, 18:00 30th, 19:00
December 15th, 18:00 9th, 9:00
9 As shown by the table, there is only one single month-April-where the two
10 studies use the same peak day. There is no month when the same hour is used.
11 Given the readily available load research data the Company has, there should be a
12 direct linkage between the data used in the jurisdictional and class studies. By
13 doing so, the monthly peak hours and loads would be the same in the two studies.
6
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
1 Q.
2
3
HAVE YOU COMPARED THE CLASS LOAD DATA BETWEEN THE
JURISDICTIONAL PEAK HOUR AND THE COMPARABLE CLASS
PEAK HOURS
4 A.Yes. The following table shows the class peaks for the same hour and same day
5 ofthe week as had been used in the jurisdictional study. In other words, as the
6 January system peak was a Monday, the class study value shown in the following
7 table is for Monday, January 26,2009 at 19:00 hours.
Class Company Cost
Difference Cost
Month
Load Data Study Study - Class Lod
Data
January 460 466 6
February 44 434 -6
March 365 3%31
April 428 387 -41
May 453 442 -11
June 601 633 32
July 567 496 -71
August 534 534 0
September 422 388 -34
October 373 372 -1
November 395 414 19
December 387 404 17
8 The above table shows a wide variation between the two sources across all twelve
9 months. While there are some months where the values are quite close (Januar,
10 February, May, August and October), there are also several months where the
11 difference are quite large (March, April, July and September). These differences
12 would not exist if the Company used the same load research data for both the
7
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
1
2
3
4 Q.
5
6 A.
7
8
9
10 Q.
11
12 A.
13
14 Q.
15
16 A.
17
18
19
20
21
22
23
jurisdictional and class studies. PIIC recommends the Commission require this of
the Company in future proceedings.
III. COST OF SERVICE - PEAK DEMAND SELECTION
HAVE YOU ANALYZED THE COST-OF-SERVICE STUDY PRESENTED
BY THE COMPANY IN THIS PROCEEDING?
Yes. I analyzed the Company's cost-of-service study submitted as Exhibit 49,
reviewed the associated workpapers, reviewed the Company's responses to data
requests of other paries addressing cost-of-service matters and sought additional
information through PIIC data requests.
DO YOU AGREE WITH THE MANNER IN WHICH THE STUDY WAS
DONE?
No. I disagree with the method employed by the Company to allocate demand-
related generation, transmission and distribution costs.
HOW HAS THE COMPANY CALCULATED THE PEAK DEMANDS
USED IN ITS COST-OF-SERVICE STUDY?
The Company's study uses two main demand (or peak) allocation factors: class
coincident demands for generation and trasmission costs and a weighted monthly
class coincident demand for major distrbution costs (substations, pole, cable and
conductor). For each of these demands, the Company uses the class values from
all 12 months ofthe year. For the generation and transmission demand allocation
factor, it is simply the sum of all twelve monthly coincident peak values ("12
CP"). For the main distrbution demand allocation factor, the Company starts
with the same twelve monthly coincident class values as used for the generation
8
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
1 and transmission allocation factor. However, the Company applies a monthly
2 weighting factor to the class peaks based upon the number of distrbution
3 substation peaks that have occurred in each month for the last five years. The
4 following table shows the derivation ofthese monthly weighting factors.
Month 2005 2006 2007 2008 200 5YrAvg Weight
January 6 1 9 11 2 5.8 8.01%
February 4 0 3 6 1 2.8 3.87%
March 0 2 0 0 2 0.8 1.0%1
Apnl 2 1 1 1 1 1.2 1.66%
May 0 4 4 2 5 3 4.14%
June 17 13 20 8 5 12.6 17.40%
July 32 28 14 32 19 25 34.53%
August 4 12 13 8 22 11.8 16.30010
September 1 2 1 1 2 1.4 1.93%
October 2 0 1 0 0 0.6 0,83%
November 2 3 2 1 1 1.8 2.49%
December 2 6 5 3 12 5.6 7.73%
Total 72 72 73 73 72 72.4 100.00010
5 As shown by the final weighting factors, the Company's approach tends to
6 emphasize the peak demands that occur during the three summer months (with
7 factors ranging from 16.3% to 34.5%) as compared to all other months.
8 Q.WHY DO YOU DISAGREE WITH THE USE OF ALL TWELVE
9 MONTHLY PEAKS FOR THE GENERATION AND TRANSMISSION
10 DEMAND ALLOCATION FACTOR?
11 A.Using a value based upon all twelve months is inappropriate as it dramatically
12 understates the demand level of certin classes. Giving each and every month
13 equal weighting ignores the fundamental driver of new generation, transmission
9
Schoenbeck, Di
PacifiCorp Idaho Industral Customers
1 or distribution investment. The need for these facilties is determined based on
2 the peak demands placed on such facilties. Including other irrelevant demands in
3 the derivation of the class value simply causes a shift in cost responsibilty to
4 other classes in the cost study. Ths latter point can be appreciated by reviewing
5 the following table containing the adjusted PacifiCorpl! system monthly peak data
6 from RMP's Exhbit 2, page 10.2.
Adjusted Percent of MWs
BelowMonthJurisdictionalPeakPeakDataMonthMonth
January 8,514 93%66
February 8,221 9Q1o 957
March 7,661 83%1,516
April 7,257 79%1,921
May 7,848 86%1,330
June 8,407 92%771
July 9,178 100%0
August 8,975 98%202
September 8,356 91%822
October 7,336 80%1,842
November 8,322 91%856
December 8,722 95%455
7 Most of the months have peak demands substantially below the sumer peak
8 value that occurs in July. However, the December value is relatively close
9 (within 5%) thereby identifying PacifiCorp as having a dual peak with both witer
1/When I reference PacifiCorp in this testimony, I am referring to PacifiCorp's entire six state
system and not just RM.
10
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
1
2
3
4
5
6
7
8
9
10
11 Q.
12
13 A.
14
15
16
17
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19
20
21
22
and sumer months being important. For most of the remaining months~ the peak
load level is significantly below the peak demand leveL. For example, the four
months of March, April, May and October are over 1,000 MWs less than the
system peak value. As generation and transmission demand-related costs
represent a substantial amount of the Company's proposed revenue requirement,
use of the Company's 12 CP system demand allocation factor is wrong. The
Company's generation and transmission demand related costs should be allocated
using the July and December jursdictional peak hours, taing into account an
appropriate adjustment for the irrgation class in July to reflect the load control
programs.
WHY DOES THE IRRGATION CLASS LOAD NEED TO BE
ADJUSTED?
As previously noted, the irrigation class demand is based on the average load
level for the past five years. This is inappropriate as the Company's load control
programs for the irrgation class have grown substantially in recent years. The
following table shows the avoided MWs for just the irrgation dispatch program
compiled from the Company's Schedule 72 & 72A Idaho Irrgation Load Control
Program Reports. This shows a substantial growth in the program from just 2007
to 2009 of over 160 MW. Furer, the Company's response to IIPA Data Request
23 indicates an expected 2010 avoided load of282 MWs in July under the Idaho
load control programs. Basing the 2009 irrgation load level on years prior to
2009 wil overstate the demand contribution for this class due to the substantial
11
Schoenbeck, Di
PacifiCorp Idaho Industral Customers
1 in program.participation.
Highest Mean Highest
Year Event Hour
2007 76 76
2008 203 210
200 237 242
Average:in 176
200-Avg 65
2 Q.
3 A.
4
5
6
7
8
9
10
11
12
13
14
15
16
HOW SHOULD THE IRRGATION CLASS LOAD BE ADJUSTED?
There are at least two ways in which a reasonable adjustment could be done.
Using the Company's historical class load data, the Company could re-construct
the hourly class loads assuming no curtilments had occurred in 2009. Then the
current expected program curtailment amount could be deducted from the summer
irrigation months to arrive at the value to use for cost allocation purposes. As an
example to ilustrate this approach, assume the "un-curtailed" irrgation demand
for the July peak hour is 350 MWs and the expected net avoided MWs given
current customer paricipation levels is 250 MWs. The adjusted July peak for this
class would be 100 MWs (350 MWs - 250 MWs = 100MWs). A second method
is to rely in part on the jurisdictional hourly load data using the assumed level of
net curtailment from the jurisdictional study applied to the class load data. To
ilustrate this approach, the unadjusted Idaho coincident peak for July is 664 MWs
while the adjusted peak is 475 MWs. For the comparable hour, the class load data
has an Idaho peak of 567 MWs, a value 92 MWs above the jurisdictional value.
12
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
This amount can be deducted from the irrgation class load for this hoùr to
2 approximate the adjusted irrigation class demand for July. Given that the second
3 method can be readily implemented, I recommend this adjustment be incorporated
4 into the class cost study.
5 Q.
6
7
8
PLEASE PROVIDE A COMPARSON OF THE COMPANY'S 12 CP
DEMAND ALLOCATION FACTOR WITH YOUR
RECOMMENDATIONS FOR ALLOCATING GENERATION AND
TRASMISSION DEMAND-RELATED COSTS.
9 A.The following table compares theMW values for the Company 12 CP allocation
10 factor with the results of incorporating my recommendations for using the
11 comparable jurisdictional peak hour, using only the class loads from the peak
12 months of July and December and adjusting the July irrigation class load to reflect
13 the çurrent program participation levels.
Company 12 cp pncw/scp Delta
Residential 109 105 -4
Small Power (23)26 26 0
Large Power (6/3 52 49 -3
High Voltage 14 13 -2
Irrgation (10)72 67 -5
Lighting 0 0 0
Space Heating 1 1 0
Contract 1 161 156 -5
Contract 2 11 7 -4
Total 447 425 -22
14 Q.
15
16
WHY DO YOU DISAGREE WITH THE COMPANY'S APPROACH IN
DETERMINING THE DISTRIBUTION DEMAND ALLOCATION
FACTOR FOR SUBSTATIONS, POLES AND WIR?
17 A.The Company's use òfthe 12 CP coincident demands as a starting point in its
13
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
1 derivation ofthe distribution demand allocation factor ignores the localized
2 diversity that exists on the Company's distribution system. The 72 distribution
3 substations have a capacity of over 1,100 MWs in order to provide reliable
4 localized service. For 2009, these substations had an accumulated peak load of
5 628 MW s. Yet, the highest coincident peak for all twelve months used in the
6 Company's allocation factor is just 483 MWs and the average ofthe 12 monthly
7 distribution coincident peaks is less than 300 MW s.
8 Application ofthe Company's monthly weighting factors tends to lessen
9 the impact of using all 12 monthly values but in actuality, this is an unnecessary
10 step. Absent having the most accurate metric (class loads at each substation
1 1 peak), a reasonable-and most often used-alternative is. class non"'coincident
12 demand levels as acknowledged by the NARUC Electric Utilty Cost Allocation
13 Manual ("1 NCP"). PIIC recommends this method be used to ascertin
14 distribution demand-related cost responsibilty. The following tables compare: 1)
15 the Company's weighted l2CP demand approach; 2) the maximum coincident
16 demand for each class; and 3) the class maximum non-coincident peak demand
17 ("1 NCP") I derived from the hourly load research data.
14
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
Class (Schedules)
Residential (1/36)
Small Power (23)
Lage Power (6/35)
Irrgation (10)
Tota:
Company
Weighting
Method
113
25
53
199
390
Maxum
Coincident Peak
194
35
64
314
606
Maxm Qass
Hourly Peak
208
38
68
320
633
Class (Schedules)
Residential (1/36)
Small Power (23)
Large Power (6/35)
Irrgation (10)
Total:
Company
Weighting
Method
28.90%
6.4010
13.60%
51.0%
100.00%
Maxum
Coincident Peak
32,00%
5,70%
10.60%
51.70%
100.00%
Maxum Class
Hourly Peak
32.80%
6.10%
10.70%
50.50%
100.00%
1 It is apparent from the table that the Company's method has understated
2 the costs assigned to Schedules 1 and 36 while overstating the distribution
3 demand costs assigned to all other major rate schedules.
4 Q.
5
6
HAVE YOU PERFORMED A COST -OF-SERVICE SENSITIVITY
INCORPORATING ALL YOUR DEMAND ALLOCATION FACTOR
RECOMMENDATIONS?
7 A.Yes. Exhibit 602 to this testimony is the summary page from the Company cost-
8 of-service model modified to reflect my recommendations. The following table
9 compares the revenue to cost ratio (or "parity ratio") from the Company's study
1 0 and the PILC for the major customer classes. The parity ratio is the most
11 appropriate yardstick for determining whether the rate schedule charges are
15
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
1 equitable to each customer class. It is a statistic that takes into account both the
2 operating expenses and the rate base needed to serve each customer class. The
3 relationship between operating expense and rate base wil vary depending upon
4 the utilzation offacilties (or load factor) for each class. For example, a class
5 with a low load factor wil require a larger rate base investment relative to
6 operating expense. On the other hand, a class with a high load factor wil require
7 more operating expense as compared to rate base investment. As the parity ratio
8 includes both the return on rate base and the operating expenses of each class, it is
9 the most accurate measure to use in rate spread determinations. A parity ratio less
10 than 1.0 or 100% indicates a class is not paying its fair share of costs.
11 Conversely, a ratio greater than 100% indicates the class is paying charges in
12 excess of its cost responsibilty.
Class Company PIIC
Residential 105%104%
Residential - TOD 99/0 97%
General Service - Lage 100%103%
General Service - High Voltage 99%102%
Irrgation 104%105%
Street & Area Lighting 145%130%
Space Heating 102%97%
General Service. Small 103%103%
Contract 1 94%94%
Contract 2 97%108%
State ofIdaho 100%100%
13 The difference in parity ratios for all major customers classes changes only
14 slightly from the Company's study. The largest parity change between the two
16
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
1 studies is for the lighting class, but the PIIC parity ratio is stil quite high at 130%.
2 Q.
3
4 A.
5
6
7
8
9 Q.
10 A.
11
12
13
14
15
IV. RATE SPREAD
HOW is THE COMPANY PROPOSING TO RECOVER ANY REVENUE
INCREASE GRANTED BY THE COMMSSION IN THIS PROCEEDING?
The Company proposal tracks the results ofits cost of service study very closely.
The noted exception is for thè lighting class where the Company is proposing no
rate decrease for this class even though the cost study indicates it would be
justified. For the lighting class, the Company is proposing no rate change at this
time.
DO YOU SUPPORT THE COMPANY'S RATE SPREAD PROPOSAL?
I support the objective of achieving cost-based rates. However, the Company's
cost-of-service study should not be used for determining an equitable rate spread
in this proceeding. Instead, the PIIC cost study should be used as the foundation
to achieve a cost-based rate spread in this proceeding. The following table
compares the cost-base rate spreads from the Company and PIIC study at the full
increase sought by the Company.
17
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
Company Proposed Prce Increase - $000
Company
Study
$3,167
$3,236
$3,00
$741
$3,852
($165)
$65
$1,345
$11,741
$715
$27,698
Clas
Residential
Residential - TOD
General Service - Large
General Service - High Voltage
Irrgation
Street & Area Lighting
Space Heating
General Service - Small
Contract i
Contract 2
State ofIdaho
PILC Study
$3,781
$3,607
$2,357
$572
$3,443
($108)
$97
$1,455
$12,340
$155
$27,698
Diference
$614
$371
($64)
($169)
($410)
$57
$32
$110
$599
($561)
$0
1 Q.WHAT IS YOUR SPECIFIC RATE SPREAD RECOMMENDATION?
2 A.The following table presents my specific recommendation along with the
3 Company proposal for comparative purposes at the Company's full request
4 amount. As shown by the table, the PIIC recommendation gives no inèrease to
5 the lighting rate schedules and a cost-based increase to all other classes.
18
Schoenbeck, Di
PacifiCorp Idaho-Industrial Customers
Class Company
Pr osal
$3,135
$3,219
$2,984
$737
$3,820
$0
$64
1,335
$11,696
$712
$27,702
Residential
Residential- TOD
General Service - Large
General Service - High Voltage
Irrgation
Street & Area Lighting
Space Heating
General Service - Small
Contract 1
Contract 2
State ofIdaho
PILC
Recommendation
$3,766
$3,593
$2,348
$570
$3,430
$0
$97
$1,450
$12,294
$154
$27,702
Difference
$632
$374
($636)
($167)
($390)
$0
$32
$1l5
$598
($558)
$0
Q. HOW WOULD YOU ALLOCATE THE COMPANY'S RATE INCREASE?
2 A.The rate increase should be spread to the various classes using the following
3 percentages.
Class
Residential
Residential- TOD
General Service - Lae
General Service - High Voltage
Irrgation
Street & Area Lighting
Space Heating
General Service - Small
Contract 1
Contract 2
State ofIdaho
Rate Spread
Percentages
13.60%
12.97%
8,47%
2.06%
12.38%
0.0010
0.35%
5.23%
44.38%
0.56%
100.0010
4 The percentages were derived from the PILC rate spread recommendation at the
19
Schoenbeck, Di
PacifiCorp Idaho Industral Customers
2 Q.
3
4
5 A.
6
7
8
9
10 Q.
11
12 A.
13
14
15
16
17
18
19
20
21 Q.
22 A.
Company's full request amount.
v. INDUSTRIAL RATE DESIGN
HOW IS THE COMPANY PROPOSING TO RECOVER THE REVENUE
INCREASE ASSIGNED TO INDUSTRIAL SCHEDULE 6, 6A AND 9
CUSTOMERS?
The Company's rate design increases the demand charges by a larger percentage
than the energy charges. Specifically, under the Company's full request, the
demand charges for Schedules 6 and 6A are being increased by about 17% while
the energy charges are being increased by 12%. For Schedule 9, the demand
charges are increased by 21 % while the energy charge is being increased by 12%.
DOES PUC SUPPORT THIS RATE DESIGN PROPOSAL FOR THE
INDUSTRIAL SCHEUDLES?
Yes. The Company's cost-of-service model aggregates the costs allocated to
these schedule into three categories that are extremely useful for rate design
purposes. These categories are: customer, energy, and demand. A comparison of
the per unit costs for the demand and energy categories from the cost study with
the per unit revenue recovery from the industrial schedules provides valuable
information on how to assign any schedule's rate increase. In the instant case,
this comparison shows that the Company's proposal is justified-the demand
charges should be given a greater percentage increase than the energy charges.
PIIC supports the Company's industrial rate design proposal in this proceeding.
DOES THIS CONCLUDE YOUR DIRCT TESTIMONY?
Yes, it does.
20
Schoenbeck, Di
PacifiCorp Idaho Industrial Customers
Case. No. PAC-E-IO-07
Exhibit No. 601
Witness: Donald W. Schoenbeck
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
PACIFICORP IDAHO INDUSTRIL CUSTOMERS
Exhibit Accompanying Direct Testimony of Donald W. Schoenbeck
Qualifications of Donald W. Schoenbeck
October 14,2010
1 .Q.
2 A.
3
4 Q.
5 A.
6
7 Q.
8
9 A.
10
11
12
13
14
15
16
17
18
19
20
21
22
PacifiCorp Idaho Industral Customers
Exhibit NO.60l Page 1 OF2
Witness: Donald W. Schoenbeck
QUALIFICATIONS AND BACKGROUND OF DONALD W. SCHOENBECK
PLEASE STATE YOUR NAME AND BUSINESS ADDRESS.
Donald W. Schoenbeck, 900 Washington Street, Suite 780, Vancouver,
Washington 98660.
PLEASE STATE YOUR OCCUPATION.
I am a consultant in the field of public utilty regulation and I am a member of
Regulatory & Cogeneration Services, Inc. ("RCS").
PLEASE SUMMARIZE YOUR EDUCATIONAL BACKGROUND AND
EXPERIENCE.
I have a Bachelor of Science Degree in Electrical Engineering from the University
of Kansas and a Master of Science Degree in Engineering Management from the
University of MissourI.
From June of 1972 untilJune of1980, I was employed by Union Electric
Company in the Transmission and Distribution, Rates, and Corporate Planning
functions. In the Transmission and Distribution function, I had various areas of
responsibilty, including load management, budget proposals and special studies.
While in the Rates function, I worked on rate design studies, fiings and exhibits
for several regulatory jurisdictions. In Corporate Planning, I was responsible for
the development and maintenance of computer models used to simulate the
Company's financial and economic operations.
In June of 1980, I joined the consulting firm ofDrazen-Brubaker &
Associates, Inc. Since that time, I have participated in the analysis of various
utilties for power cost forecasts, avoided cost pricing, contract negotiations for
2
3
4
5
6
7
8
9
10 Q.
11
12 A.
13
14
15
16
17
18
PacifiCorp Idaho Industral Customers
Exhibit No.601 Page 2 OF 2
Witness: Donald W. Schoenbeck
gas and electric services, siting and licensing proceedings, and rate case purposes
including revenue requirement determination, class cost-of-service and rate de-
sign.
In April i 988, I formed RCS. RCS provides consulting services in the
field of public utilty regulation to many clients, including large industrial and
institutional customers. We also assist in the negotiation of contracts for utilty
services for large users. In general, we are engaged in regulatory consulting, rate
work, feasibilty, economic and cost-of-service studies, design of rates for utilty
service and contract negotiations.
IN WHICH JURISDICTIONS HAVE YOU TESTIFIED AS AN EXPERT
WITNESS REGARDING UTILITY COST AND RATE MATTERS?
I have testified as an expert witness in rate proceedings before commissions in the
states of Alaska, Arizona, California, Delaware, Idaho, Ilinois, Maryland,
Montana, Nevada, North Carolina, Ohio, Oregon, Washington, Wisconsin and
Wyoming. In addition, I have presented testimony before the Bonnevile Power
Administration, the National Energy Board of Canada, the Federal Energy
Regulatory Commission, publicly-owned utilty boards and in court proceedings
in the states of Washington, Oregon and California.
Case. No. PAC-E-1O-07
Exhibit No. 602
Witness: Donald W. Schoenbeck
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
PACIFICORP IDAHO INDUSTRIL CUSTOMERS
Exhibit Accompanying Direct Testimony of Donald W. Schoenbeck
PUC Cost Of Service Summary
October 14, 2010
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Case. No. PAC-E-10-07
Exhibit No. 603
Witness: Donald W. Schoenbeck
BEFORE THE IDAHO PUBLIC UTILITIES COMMSSION
PACIFICORP IDAHO INDUSTRIAL CUSTOMERS
Exhibit Accompanying Direct Testimony of Donald W. Schoenbeck
Rocky Mountain Power's Response to LIP A's Data Request 2
October 14,2010
PAC-E-10-07/Rocky Mountain Power
June 30, 2010
LIP A Data Request 2
PacifiCorp Idaho Industrial Customers
Exhibit No. 603 Page 1 of 4
Case No. PAC-E-1O-07
Witness: Donald W. Schoenbeck
LIP A Data Request 2
Please answer the following with respect to information contained on Paice's
Exhibit 49, Tab 5 "Cost of Service Allocation Factors":
A. Are the times of the system peaks listed on page 6 the same as the actual
coincident system peaks durng each of those months?
B. Are the times listed on page 6 on Pacific or Mountain time?
C. How do the total jurisdictional values for each month on page 6 relate to the
Idaho values on McDougal's Exhbit 2, Tab 1O?
D. With respect to the data listed on pages 7 and 12, which data came from the
Company's load research data and which data came from census data? Iffrom
load research data, over what timeframe was the data collected? If the data
came from load research data, but was adjusted, please provide an electronic
copy of all workpapers and/or calculations that support the adjustments to
actual values.
E. With respect to the data listed on page 13, which data came from the
Company's load research data and which data came from biling data? If the
data came from biliing data, but was adjusted, please provide an electronic
copy of all workpapers and/or calculations that support the adjustments to
actual values.
F. What was the level of curtailment/interrption for each customer class or
Monsanto during the times of each of the monthly peaks listed on page 7?
(Please specify at input leveL.)
G. Is there any weather normalization ofthe Distribution Peak data on page 12 or
the Non-Coincident Peak data on page 13? If this data is weather normalized,
please provide an electr6nic as well as hard copy of all workpapers used to
support this normalization.
Response to lIP A Data Request 2
A. Yes.
B. Mountain time.
C. Please refer to the Company's response to IIPA Data Request 8.
D. Schedule 001
Schedule 036
Load Research Data
Load Research Data
Jan09-Dec09
Jan09-Dec09
P AC-E-1 0-07/Rocky Mountain Power
June 30, 2010
LIP A Data Request 2
PacifiCorp Idaho IndustrialCustomers
Exhibit No. 603 Page 2 of 4
Case No. PAC-E-10-07
Witness: Donald W. Schoenbeck
Schedule 006 Load Research Data Jan09-Dec09
Schedule 023 Load Research Data Jan09-Dec09
Schedule 019 Load Research Data 1996, 1998, 1999
Schedule 010 Load Research Data '05-'09 Irrig. Seasons
Schedule 009 Census Data Jan09-Dec09
Contract 1 Census Data Jan06-Dec08
Contract 2 Census Data Jan09-Dec09
Please refer to Attachment lIP A 2d for a listing of adjustments to actual values.
Jan06-Dec08
Jan06-Dec08
Jan06-Dec08
Jan06-Dec08
Jan06-Dec08
Jan06-Dec08
Jan06-Dec08
Jan06-Dec08
Jan06-Dec08
E. Schedule 001 Est. From Load Research Data
Schedule 036 Est. From Load Research Data
Schedule 006 Est. From Load Research Data
Schedule 023 Est. From Load Research Data
Schedule 019 Est. From Load Research Data
Schedule 010 Est. From Load Research Data
Schedule 009 Est. From Load Research Data
Contract 1 Est. From Load Research Data
Contract 2 Est. From Load Research DataSchedule 007 Billng DataSchedule 011 Biling DataSchedule 012 Billng Data
Please refer to Attachment LIP A 2d for a listing of adjustments to actual values.
F. Please refer to the Company's responses to IIPA Data Requests 15 and l6(b).
G. There is no weather normalization ofthe distribution peak data or non-
coincident data.
Recordholder:
Sponsor:
C. CraigPaice / Scott D. Thornton
C. Craig Paice
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Case. No. P AC-E-1O-07
Exhibit No. 604
Witness: Donald W. Schoenbeck
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
PACIFICORP IDAHO INDUSTRIAL CUSTOMERS
Exhibit Accompanying Direct Testimony of Donald W. Schoenbeck
Rocky Mountain Power's Response to I1PA's Data Request 8
October 14, 2010
PAC-E-1O-07/Rocky Mountain Power
June 30, 2010
LIP A Data Request 8
PacifiCorp Idaho Industrial Customers
Exhibit No. 604 Page 1 of 1
Case No. PAC-E-10-07
Witness: Donald W. Schoenbeck
LIP A Data Request 8
On Exhibit 2, page 10.13 there is a different coincident peak value for Idaho (406)
for Januar 2010 than the value used on Exhibit 49 pages 6 and 7. Please provide
all data, equations, and assumptions used to develop the figure on both Exhibit 2
and Exhibit 49. Please supply ths data in Excel format. Explain how, if at all,
the jurisdictional data from Exhibit 49 (pages 6 and 7) flows through or is
incorporated in Exhibit 2 Tab 10.
Response to lIP A Data Request 8
Idaho jurisdiction loads on Exhibit 2, page 10.13 were developed from adjusted
state jurisdictional loads as explained in Company witness Peter C. Eelkema's
testimony. Class loads on Exhibit 49, Tab 5, pages 6 and 7 were developed from
both sample and direct census Load Research data. Therefore, because they are
from different data sources and used for different puroses, class loads do not
directly flow through to the Idaho state jurisdiction load.
Please refer to Attachment lIP A 8a for the support for class loads and Attachment
IIPA lffor support for page 10.13 of Exhibit 2.
Recordholder:
Sponsor:
C. Craig Paice
C. Craig Paice