20101014Yankel Direct.pdf

LAW OFFICES OF
W. MARCUS W. NYE
RANDALL C. BUDGE
JOHN A. BAILEY, JR.
JOHN R. GOODELL
JOHN B. INGELSTROM
DANIEL C. GREEN
BRENT O. ROCHE
KIRK B. HADLEY
FRED J. LEWIS
ERIC L. OLSEN
CONRAD J. AIKEN
RICHARD A. HEARN, M.D.
LANE V. ERICKSON
FREDERICK J. HAHN, III
DAVID E. ALEXANDER
PATRICK N. GEORGE
SCOTT J. SMITH
JOSHUA D. JOHNSON
STEPHEN J. MUHONEN
CANDICE M. MCHUGH
CAROL TIPPI YOLYN
BRENT L. WHITING
JONATHON S. BYINGTON
DAVE BAGLEY
THOMAS J. BUDGE
JONATHAN M. VOLYN
MARK A. SHAFFER
JASON E. FLAIG
FERRELL S. RYAN, III
RACINE OLSON NYE BUDGE Be BAILEY
CHARTERED
201 EAST CENTER STREET
POST OFFICE BOX 1391
POCATELLO, IDAHO 83204-1391
TELEPHONE [phone]
FACSIMILE [phone]
ww.racinelaw.net
SENDER'S E-MAIL ADDRESS:elo~racinelaw.net
October 14,2010
HAND DELIVERY
Jean D. Jewell, Secretar
Idaho Public Utilties Commission
472 W. Washington
Boise, Idaho 83702
Re: Case No. PAC-E-IO-07
Dear Ms. Jewell:
BOISE OFFICE
101 SOUTH CAPITOL
BOULEVARD, SUITE 208
BOISE, IDAHO 83702
TELEPHONE: [phone]"
FACSIMILE: (209) 43300.87
IDAHO FALLS OFFICE
477 SHOUP AVENUE
SUITE 107
POST OFFICE BOX 50698
IDAHO FALLS. ID 83405
TELEPHONE: [phone]'0'
FACSIMILE: (208) 528~61 09
ALL OFFICES ..OLL FREE
(877) 232-81 0 I
L.OUIS F. RACINE (1917~20Q5)
WILL.IAM D. OLSON, OF COUNSEL
~~~:...i:
-;r:.,.-cP
Enclosed for filing in the captioned matter, please find nine copies of the Idaho Irgation
Pumpers Association, Inc.'s Direct Testimony and Exhbits of Anthony J. Yanel, with one copy
designated as a reporter's copy. We are also submitting a CD containing the testimony in MS Word
format and testimony and exhibits in PDF format.
Sincerely,
ERIC L. OLSEN
ELO:rg
Enclosures
cc: Service List
~
-ìc:z-"'.-'c._.c:o
iQi~ OCT lt-l PM 12: 19
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF PACIFICORP DBA ROCKY MOUNTAIN )
POWER FOR APPROVAL OF CHANGES TO)
ITS ELECTRIC SERVICE SCHEDULES )
)
CASE NO. PAC-E-1O-07
IDAHO IRRIGATION PUMPERS ASSOCIATION, INC.
DIRECT TESTIMONY
OF
ANTHONY J. YANKEL
OCTOBER 14,2010
1 Q.PLEASE STATE YOUR NAM, ADDRESS, AND EMPLOYMNT.
2
3 A.I am Anthony J. Yane!. I am President of Yane 1 and Associates, Inc. My
4 address is 29814 Lake Road, Bay Vilage, Ohio, 44140.
5
6 Q.WOULD YOU BRIFLY DESCRIBE YOUR EDUCATIONAL
7 BACKGROUND AN PROFESSIONAL EXPERINCE?
8
9 A.I received a Bachelor of Science Degree in Electrcal Engineerig from Carnegie
10 Institute of Technology in 1969 and a Master of Science Degree in Chemical Engineerig from
11 the University ofIdaho in 1972. From 1969 though 1972, I was employed by the Air
12 Correction Division of Universal Oil Products as a product design engineer. My chief
13 responsibilities were in the areas of design, start-up, and repai of new and existing product lines
14 for coal- fired power plants. From 1973 though 1977, I was employed by the Bureau of Air
15 Quality for the Idaho Departent of Health & Welfare, Division of Environment. As Chief
16 Engineer of the Bureau, my responsibilities covered a wide range of investigative functions.
17 From 1978 though June 1979, I was employed as the Director of the Idaho Electrcal Consumers
18 Offce. In that capacity, I was responsible for all organzational and techncal aspects of
19 advocatig a varety of positions before various governental bodies that represented the
20 interests of the consumers in the State ofIdaho. From July 1979 though October 1980, I was a
21 parter in the firm ofYankel, Eddy, and Associates. Since that tie, I have been in business for
22 myself. I am a registered Professional Engineer in the states of Ohio and Idaho. I have
23 presented testimony before the Federal Energy Regulatory Commission (FERC), as well as the
Yanel, DI-l
Irgators
1 State Public Utility Commissions of Idaho, Montana, Ohio, Pennsylvana, Uta, and West
2 Virgina.
3
4 Q.ON WHOSE BEHALF ARE YOU TESTIFYING?
5
6 A.I am testifyng on behalf of the Idaho Irgation Pumpers Association (LIP A).
7
8 Q.WHAT IS THE PUROSE OF YOUR TESTIMONY IN THIS PROCEEDING?
9
10 A.My testimony wil address the Company's jursdictional revenue requirement as it
11 is impacted by the level of test year weather normalized Irgation sales used by the Company,
12 the inappropriate level of losses being assigned to Idaho, and the treatment of the benefits and
13 costs of the Irgation Load Control Program as they impact Idaho. I also address the treatment
14 of the Load Growt Adjustment Rate in PacifiCorp's ECAM proceedings, when the actul usage
15 falls below that projected in the Company's GRID model in general rate cases, and the data used
16 by the Company to calculate the cost of service for the Irgation customers.
17
18 Q.PLEASE SUMMARIE YOUR TESTIMONY.
19
20 A.Aside from ths introduction, my testimony is divided into five sections.
21 * The first section deals with the level of Irgation sales that the Company used to
22 develop its 2010 forecasted test year revenues and revenue requirement. Although
23 PacifiCorp recognizes that the 2009 Irgation sales were quite low because of "an
Yanel, DI-2
Irgators
1 unusually wet spring", its weather normalization process does not address precipitation.
2 Using PacifiCorp's weather normalized Irgation sales for the 11 years prior to 2009, it
3 can be projected that in 2010 that the weather normalized Irgation sales should have
4 been 545,000 MW (17.7%) higher than used in the Company's fiing. The test year
5 Irgation revenue as well as the Idaho Jursdictional revenue would be increased $7
6 million if a realistic weather normalized Irgation sales figue would have been used.
7 * The second section deals with the assignent of cost responsibility to the Idaho
8 jursdiction based upon the energy allocation factor used for Idaho. This energy factor
9 is based upon the same forecast sales data as used to develop the Idaho revenue, but a
10 different (greater) set oflosses is applied to these sales than is calculated in the
11 Company's loss study for Idaho. PacifiCorp uses somethng referred to as "Border
l2 Load" to calculate Idaho's losses for jursdictional allocation puroses. This Border
13 Load method effectively measures all losses that occur in Idaho. However, only 13%
14 of all of the electrcity that enters the Idaho jursdiction is consumed in Idaho, with the
15 rest of it simply passing through to non-Idaho customers. Idaho customers should not
16 be charged for losses associated with energy that is simply passing though Idaho to
17 serve others.
18 * The thd section deals with the benefit that Idaho receives and the costs that it incurs as
19 a result of the Irgation Load Control Program. I generally conclude that although the
20 Program is a major benefit to the system (provides a great savings for all system
21 customers), the Idaho customers are payig significantly more than the benefit that they
22 are receiving. I recommend that in the long term (by the next rate case) that ths
23 program be treated more as a system benefit where the curilments are "sold" to the
Yanel, DI-3
Irgators
1 system at their tre value. For puiposes of this case, a more realistic reduction/credit
2 should be given to Idaho in the Company's jursdictional allocation model that reflects
3 the actual curilment that was available durig the test year as opposed to the limited
4 (lower) amount that was used in the Company's filing. Use of actual 2010 curilment
5 levels as opposed to levels lower that what were even available in 2009 results in a
6 reduction of the revenue requirement by 2.5 milion.
7 * The four section deals with the Load Growth Adjustment Rate ("LGAR") that is a
8 part of the Company's ECAM proceeding, but the rate is set in ths, a general rate case.
9 The LGAR was originally established to keep the Company from double recovery of
10 growt related power supply costs. An unforeseen problem has arsen with respect to
11 the fact that it was never conceived that load would be decreasing as opposed to
12 increasing between rate cases. Under such circumstances, the LGAR acts as a
13 decoupling mechansm and actually increases rates when load is lost. My testimony
l4 recommends that the Commssion specify that the LGAR is not a symetrcal
15 adjustment and that it only is used when there is growth between rate cases.
16 * The fift and last section of my testimony deals with the development of the class cost
17 of service study. I point out that the Company's cost of service study (as was the
18 jursdictional model) does not have an adequate level of test year sales to the Irgators.
19 I also point out that the class cost of service study does not reflect the peak load
20 reduction capability that is available, or even as used in the jursdictional study. I do
21 not present specific adjustments to this study, but simply recommend adoption of the
22 Company's proposed increase to the Irgators that is set at 70% of the jursdictional
23 average increase.
24
Yankel, DI-4
Irgators
1 Irrigation Sales Level
2 Q.is THE LEVEL OF TEST YEAR IRGA nON SALES USED BY THE
3 COMPAN APPROPRITE?
4
5 A.No. Although the weather normalized value of 545,290 MWH for Idaho
6 Irgation sales i is claimed to be based upon test year number of customers, combined with sales
7 per customer, and developed from regression analysis technques using time trend variables;2 a
8 simple review of the historic data reveals that ths level of usage is significantly below what
9 would be considered a normalized test year value for the Irgation customers. The actual sales
10 levels to the Irgation customers over the last 10 years were provided in the Company's
11 Response to LIP A Request 87 and are graphically presented in Figue 1 below. Except for the
12 2005 and 2009 actual sales levels, the other recent anual sales to the Irgation customers have
13 been well in excess of the normalized value proposed in ths case.
800,000
700,000
600,000
X"SOO,OOO;:
!400,000
Figure 1
Actual Irrigation Sales
........................................................................................................................................................................................................
.
-+-- .-. .-,.
v
$...-
¡-....._._.__.__.._.._......_-----
300,000 ..........................................................-.......
200,000
100,000 ..................................................................................................................................._.................................._.................................
¡-..- ........._...__.................._...--r-.--"~._--~--_..""_..-,---~--T..__....."~-_._.:-
1998 2000 2002 2004 2006 2008 2010
14
i At sales level which for the Irrgators is considered to be at secondar distrbution leveL.
Yankel, DI-5
Irgators
1 Q.WHY WERE IRIGATION SALES SO LOW IN 2009?
2
3 A.The Company gave the following explanation in Mr. Eelkema's testimony at page
4 3, line 3:
5 Idaho's 2009 sales were unusual for at least two reasons. First, 2009 industral
6 sales were abnormally low. Second, an unusually wet sprig resulted in a
7 decrease in irgation sales. The usage from these two customer classes decreased
8 approximately 20 to 21 percent from 2007 and 2008 levels, reducing Idaho's 2009
9 total sales approximately 12 to 13 percent from 2007 and 2008 levels. (Emphasis10 added)
11 I fully concur with ths explanation.
12
13 Q.IS IT APPROPRITE TO SIMLY RELY UPON ACTUAL HISTORICAL
14 SALES TO JUGE THE VALIDITY OF THE COMPAN'S WEATHER NORMIZED
15 VALUES?
16
17 A.Lookig at actual data is a good staing point, but weather normalized data
18 should be reviewed as well. The Company provided its historic weather normalized sales per
19 customer data for the previous 12 years in its response to IIP A Request 22e. This historic
20 weather normalized sales per customer data was combined with the number of Irgation
21 customers taken from the Company's Response to lIP A Request 84 and is graphically displayed
22 on Figure 2 below. There are two things to note: first, on a normalized basis there has been a
23 gradual, but steady increase in Irgation sales since 1998; and second, the weather normalized
24 sales for 2009 is signficantly below the trendline of all of the weather normalized data-it does
25 not fit. Remember-ths data is on a "weather normalized" basis that should have removed all
2 See generally Eelkema's direct testimony page 5, line 11 through page 6 line 9.
Yanel, DI-6
Irgators
1 impacts of different weather in different years. The Company's weather normalized 2009
2 Irgation sales are clearly an outlier.
700000
Figure 2
Normalized Irrigation Sales
..
..
Á .."'+.. .600000
.. .,.500000 ..
..
:i 400000
~ 300000
y -: 9,480.46x. 18,436,417
R2 -: 0.35'-_..-
200000
100000
3
4
o
1996 1998 2000 2002 2004 2006 2008 2010
5 Q.WHY DOESN'T THE COMPAN'S WEATHER NORMLIZED DATA FOR
6 2009 FIT THE PATTERN SHOWN IN THE TRENDLINE IN FIGUR 2?
7
8 A.The reason that the weather normalized 2009 Irgation sales data is so . low and
9 not fitting the trendline can be simply traced back to Mr. Eelkema'sstatement that 2009
10 Irrgation sales were so low because of an unusually wet sprig. In spite of this recognition, the
11 Company does not weather normalize Irgation sales data for precipitation3 thus, the unusually
12 low sales data in 2009 that was due to an unusually wet sprig, was in fact not normalized for the
13 weather anomaly that occured. In spite of the Company's testimony that the wet sprig caused
3 See Response to lIP A Request 22-f.
Yankel, DI-7
Irgators
1 low Irgation sales in 2009, its weather normalization procedures did nothng to take ths
2 situation into account.
3
4 Q.DOES IDAHO POWER WEATHER NORMIZE ITS IRGATION SALES
5 DATA FOR PRECIPITATION?
6
7 A.Yes. In support of its weather normalization adjustments used in Case No. IPC-
8 E-03-13, Idaho Power supplied to the Commission Staff (in response to its Request No.3) its
9 supporting documentation for weather normalization. With respect to the regression models that
10 Idaho Power ran for Irgation sales, the following description was provided with respect to the
11 Irgation models for each of the Company's operating centers:
12 The weather variables utilized by the system irgation weather adjustment
13 model are constrcted as weighted averages of degree day varables from four
14 service area weather stations: Boise, Twin Falls, Pocatello, and Ontao. That is,
15 the growing degree day varable (cooling degree days Base 50) is an average of
16 growing degree days from the four weather stations, each weighted by the share
17 of total system irgation pumping horsepower connected in the division
18 associated with that weather station. The precipitation varable was constrcted
19 and weighted in the same maner. A second precipitation varable was used to
20 measure the impact of pre-growing season precipitation on the early months of the
21 growing season (May and June). This variable is zero for all months except May
22 and June of each year where it is the total of the weighted precipitation for the two
23 previous months. . . .
24 Thus, unike PacifiCorp, Idaho Power's Irgation weather normalization model not only
25 recognied the impact of precipitation on Irgation sales, but also recognzes a second
26 precipitation variable that deals with the early growing season-precisely under the conditions
27 where PacifiCorp noted abnormal precipitation and abnormally low sales. For ths reason, even
28 though PacifiCorp' s weather normalized Irgation sales for 2009-no adjustment was made to
29 normalize for the "unusually wet sprig".
Yankel, DI-8
Irgators
1
2 Q.SHOULD PACIFICORP'S 2009 IRGATION SALES BE INCLUDED
3 AND/OR USED IN THE GRAPH AND/OR ANALYSIS ABOVE?
4
5 A.No. As noted above, a review of the graph in Figue 2 reveals 2009 to be an
6 outlier (even on a weather normalized basis) and the fact that PacifiCorp underwent an
7 ''uusually wet sprig" without makig normalization adjustments for precipitation indicates that
8 this "normalized" value is wrong or simply meanigless.
9
10 Q.WHAT WOULD THIS GRAPH LOOK LIK IF THE MEANINGLESS 2009
11 DATA WERE IGNORED?
12
13 A.The graph in Figue 3 below shows that the annual, normalized sales data is much
14 more unform with the 2009 data removed.
Figure 3
Normalized Irr. Sales (no 2009 data)
700,000
600,000
500,000
..
:i 400,000
Y"'~
=i 300,000
200,000
100,000
15 1996 1998 2000 2002 2004 2006 2008 2010
Yanel, DI-9
Irgators
1 By removing one piece of obviously bad "normalized" data, the R-Square for this trendline is
2 almost double that of the previous graph in Figue 2.
3
4 Q.THE NORMLIZED IRGATIONS SALES DATA IN FIGURS 2 AND 3
5 ARE INCREASING. is THIS CONSISTENT WITH EXPECTATIONS?
6
7 A.Yes. First, it must be remembered that ths data is PacifiCoip' s own data and it
8 reflects only Southeastern Idaho. Second, the data is based upon actual sales data that has been
9 normalized to remove some of the obvious weather anomalies-the data is not based upon
10 assumptions regarding anticipated changes in independent variables. Thid, the increased sales
II data generally fits with the increase number of Irgation customers that ths region has
12 experienced.
13
14 Q.HOW MANY NEW IRGATION CUSTOMERS HAS PACIFICORP ADDED
15 IN ITS IDAHO SERVICE TERRORY OVER THE LAST 10 YEARS?
16
17 A.Durg the last 10 years there has been an increase in the number of Irgation
18 customers in PacifiCoip' s Idaho service terrtory of approximately 350 customers or 8%.4
19 Figure 4 below depicts this growth over the last 10 years:
4 Generally see the Response to IIPA "Request 84.
Yankel, DI-lO
Irgators
Figure 4
Irrigation Customers
5000
4500 .... ....... ..
i4000+
y:= 0.0898x + 1159.3
R2:: 0.9698
3500 ;.---.------
3000
1998
J
2001 2004 2006 2009 2012
1
2 In spite of ths well established relationship of the ever increasing average number of Irgation
3 customers over the last 10 years, the Company's test year average number of Irgation
4 customers is 11 customers less than what was realized in 2009.
5
6 Q.WHT DOES TH ABOVE COMPANY WEATHER NORMLIZED
7 IRRGATION SALES DATA PREDICT WITH RESPECT TO THE 2009 AND TEST YEAR
8 2010 IRGATION SALES LOAD?
9
10 A.Based upon the trendline though the Company's weather normalized irgation
11 sales data in Figue 3, the normalized Irgation sales in 2009 would have been 647,440 MWH
12 compared to the actual Irgation sales of 500,255 MWH.5 The test year 2010 weather
13 normalized Irgation sales would be 662, l67 MWH compared to the inappropriate level of
14 545,290 MWH used in the filing. Essentially, the Company used a value for Irgation sales that
5 See response to lIP A Request 18.
Yanel, DI-ll
Irgators
1 was 17.7%6 less th what is predicted-similar to the general conclusion discussed on page 3 of
2 Mr. Eelkema's testimony:
3 ... usage from these two customer classes decreased approximately 20 to 21
4 percent from 2007 and 2008 levels
5
6 Q.ARE THERE OTHER INSTANCES WHERE THE COMPANY'S TEST YEAR
7 FORECAST SALES PRODUCE TOO LOW OF A RESULT?
8
9 A.I have only briefly looked at the Company's forecast test year sales for the
10 Residential class. The response to Staff Request 291 listed the actul (weather normalized) sales
11 for the Residential customers for the first six months of the test year as well as the forecasted
12 (weather normalized) sales as well. As can be seen on Exhibit 301, the forecasted sales for all
13 Residential customers for the fist six months of the test year was 365,652 MWH, while the
14 actual sales (after weather normalization) was 388,066 MW or 6.13% higher. Because both
15 figues are based upon "normal" weather, ths deviation of6.13% (since the case was put
16 together) is huge. The fact that both the Company's Irgation model and its Residential model
17 are under-predicting sales by such large amounts raises concerns regarding the other sales data
18 used by the Company in this case.
19 Furermore, even the number of forecasted Residential customers in the Company's test
20 year start off below the number of Residential customers that were on the system at the end of
21 2009. Exhibit 3027 lists the number of Residential customers for each of the 36 months for 2007
22 through 2009. Out of the 36 months listed on that exhibit, the number of Residential customers
23 increased in 32 of the 36 months. The average decrease that occured durng those other four
6545,290/662,167 = 0.826
Yanel, DI-12
Irgators
1 months was only 48 customers per month. There were 57,156 Residential customers in the
2 jursdiction on December 2009, one month before the test year. By contrast, the number of
3 Residential customers forecast for Janua 20108 was 56,725 or 431 less than the actual number
4 of customers the month before. Once again, the Company's forecast of biling units, and thus
5 revenue, is coming up short.
6
7 Q.WHAT ADJUSTMENTS AR YOU PROPOSING TO BRIG THE
8 COMPAN'S TEST YEAR SALES LEVELS MORE IN LIN WITH "NORMAL" LEVELS?
9
10 A.Although the Residential sales data is clearly understated, I am only
11 recommending an adjustment to the Irgation sales data. I am not makg an adjustment to the
12 Residential sales because I have not reviewed it to the extent I have the Irgation data-not
13 because I do not believe that an adjustment is necessar. I recommend that the Irgation sales
14 data be increased by 116,877 MW-the difference between what the trendline based upon the
15 Company's own weather normalized values over 11 years and the value used by the Company in
16 the development of its test year sales.
17 Although I am proposing to increase Irgation sales by 116,877 MWH, I am not
18 proposing an increase in the biling kW, which is far more stable from year to year (in spite of
19 weather varation) and the Company's forecasted values generally look appropriate. By way of
20 comparson, recent annual biling kW are listed below as well as that used in the Company's test
21 year: 9
7 Based upon the Company's response to IPUC 20.
S See the Company's response to IPUC 292.
9 See Response to lIP A Request 26.
Yankel, DI-13
Irgators
1 Table 1
3
2005
2006
2007
2008
2009
test year
Billng kW
1,299,501
1,365,546
1,354,124
1,325,036
1,324,449
1,346,186
2
4
5
6 Q.WHAT RATE SHOULD BE ASSIGNED TO THESE INCREASED
7 IRRGA nON SALES?
8
9 A.Although Schedule 10 for Irgation contains thee different rate blocks durig the
10 Irgation season and a separate rate block durg the off-season, historical data demonstrates that
11 the average "energy related" revenue collected each month is quite close (plus or minus) to the
12 off-season energy rate. For that reason, I wil simply use the off-season energy rate to establish
13 the additional revenue that would be collected if the test year Irgation sales were more properly
14 established. I recommend that the 116,877 additional MW of Irgation sales be multiplied by
15 6.0315 cents/kWh in order to produce additional revenue of $7,049,436. The Irgation test year
16 revenue should thus be set at $46,895,173.
17
18 Q.HOW DOES YOUR PROPOSED TEST YEAR IRRGATION REVENUE
19 COMPARE WITH THAT COLLECTED HISTORICALLY?
20
21 A.The total Irrgation revenue of $46,895, 173 compares quite favorably with that
22 collected over the last several years--nce the impact of recent rate increases is taen into
23 account in order to put the historical revenues on the same basis as today's rates. The table
Yankel, DI-14
Irgators
1 below lists the historic revenues, the level of increases to the Irgation customers, and the
2 effective revenue for each year at today's rates:
Table 2
2006
2007
2008
2009
Actual
$37,795,154
$45,193,746
$42,740,305
$37,330,030
Rate
Increases
1.70%
4.89%
1.73%
Equivalent
Revenue
$40,329,167
$48,223,804
$43,479,712
$37,330,030
PacifiCorp
$39,845,737
$46,895,173Proposed
3
4 It should be remembered that the above revenue figues are based upon actual usage and not
5 weather normalized usage. The 2009 Irgation season saw the lowest Irrgation sales for the
6 most recent 12 years reviewed and thus, the revenues for that year would be expected to be
7 unusually low. Likewise, normalized 2008 sales were slightly below the trendline and 2007
8 sales were above.
9
10 Q.WHAT WOULD HAVE THE ADJUSTMENT BEEN TO THE IRGATION
11 SALES IF ALL 12 MONTHS OF HISTORICAL DATA WERE USED, INCLUDING THE
12 IMPROPERLY NORMALIZED 2009 DATA?
13
14 A.Although the 2009 data is clearly too low and significantly under estimates
15 Irrgation sales, using the trendline from Figue 2 above results in a predicted 2010 usage of
16 619,308 MWH which is 70,018 MWH above the value used by the Company as test year
17 Irgation sales. Valuing these additional sales at 6.0315 cents per kWh, the additional revenue
18 that should be assigned to the jurisdiction is $4,223,136. Even using ths inappropriate data that
Yanel, DI-15
Irgators
1 does not tae into account the "unusually wet sprig" of 2009, results in the need for a
2 significant adjustment to the Company's filing.
3
4 Q.BECAUSE OF THE PROBLEMS WITH THE COMPANY'S FORECAST,
5 AND BECAUSE WE ARE NEARIG THE END OF THE YEAR, WOULD IT BE MORE
6 APPROPRITE IN THIS CASE TO SIMLY SUBSTITUTE ACTUAL 2010 IRGATION
7 SALES AN REVENUS?
8
9 A.No. The Company cannot pick and choose where it wishes to normalize and
10 where it wishes to use actul data. Furhermore, it is my understading that the 2010 Irgation
11 season may have been similar to 2009-an unusually wet sprig. Even if the Company's entire
12 filing had been on an actual (as opposed to a normalized) basis, stadard ratemakig treatment
13 would dictate that such abnormal weather/sales would need to be normalized. The point is that
14 the data needs to be normalized, but the Company's proposed normalized Irrgation sales are
15 clearly inappropriately too low.
16
17 Q.HOW SHOULD THE PROPER NORMLIZATION OF THE IRGATION
18 LOAD BE TREATED IN THE COMPANY'S OVERALL REVENU REQUIREMENT?
19
20 A.Both the increased Irgation sales and revenue need to be incorporated into the
21 Company's jursdictional allocation models (JAM and RA). The increased test year Irgation
22 revenue wil decrease the revenue requirement in this case, but that wil be somewhat offset by
23 the allocation of increased costs to Idaho because of the increased load. However, before I
Yankel, DI-16
Irgators
1 calculate the impact of these adjustments, I need to address the overall amount of energy that is
2 assigned to Idaho in the jursdictional allocation modeL.
3
Yanel, DI-17
Irgators
1 Jurisdictional Sales vs. Jurisdictional Allocations
2 Q.DO THE COMPANY'S JURSDICTIONAL SALES AND THUS REVENUE
3 PROPERLY REFLECT THE ENERGY RELATED COSTS THAT AR ALLOCATED TO
4 IDAHO ON A JUSDICTIONAL BASIS?
5
6 A.No. There is a significant difference between the amount of sales, and
7 thus revenue, attbuted to the Idaho jursdiction and the amount of energy/kWh used
8 to allocate costs to the Idaho jursdiction. Specifically, there is 2.66% niore
9 energy/kWh responsibility attbuted to Idaho in the jursdictional allocation model
10 than what is attbuted to Idaho for the calculation of jursdictional revenues. 10 The
11 net effect is that more costs are being allocated to Idaho than are required to serve the
12 Idaho load-Idaho is being asked to pay the cost of serving others.
13
14 Q.GENERALLY SPEAKIG, WHT IS THE CAUSE OF THIS DIFFERENCE
15 IN THE AMOUNT OF SALES ASSOCIATED WITH THE REVENU ATTRIUTED TO
16 IDAHO AND THE AMOUN OF ENERGY USAGE ATTRIBUTED TO JUSDICTIONAL
17 EXPENSES?
18
10 Exhibit 2, Tab 1, page 1.3 lists the total Idaho normalized General Business test year revenue at
$202,733,163. Exhibit 50 lists the present Idaho revenue at $202,733,000 associated with 3,325,872
MWH. Exhbit 49, Tab 5, page 14, line 10, lists test year sales ((?sale level) as 3,325,873 MWH which is
associated with 3,557,594 MWH on line 14 (? Input. By comparson, Exhibit 2, Tab 10, page 10.14 uses a
load 00,652,385 MWH to allocate costs to Idaho or 2.66% more usage (3,652,385 /3,557,594) =
1.0266446) than the revenue that Idaho is given credit for.
Yankel, DI-18
Irgators
1 A.The difference results from the use of two different methods of applyig losses to
2 the jursdiction. ii Firt, the Company has periodically conducted loss studies for each
3 jursdiction. The values from these loss studies are used in the Company's cost of service study
4 and for other purposes. Exhibit 303 contains six pages-the sumary page of the loss study for
5 each of the states in which the Company operates. 12 Near the bottom right of each page are
6 listed the "cum(m)ulative sales expanion factors" (loss factors) for each voltage leveL. Under
7 the heading of "Energy" and under the colum labeled "e" there is listed cumulative energy (as
8 opposed to demand) losses at each voltage leveL. For example, page 1 of Exhibit 303 lists the
9 following losses by voltage level for Idao:
Table 3
Expansion
Factors
Trans. 1.03605
Primary 1.06475
Secondary 1.10148
Percent
Losses
3.605%
6.475%
10.148%
10
11 What ths data means is that a Transmission customer in Idaho is assigned a percentage loss of
12 3.605% or the Company has to generate 1.03605 MWH for each MWH that the customer
13 consumes. Likewise, the Company must generate l.10 148 MWH for each MW tht is
14 consumed by a Secondar customer.
15 Table 4 lists the various loss factors that the Company has calculated for each of the
16 states in which it operates:
17
11 Generally see Responses to IIPA Requests 130 and 133.
)2 Loss studies provided in Response to IIPA Request 45.
Yankel, DI-19
Irrgators
1
Table 4
Idaho Utah Oregon Wash.Wyoming Calif.
Trans.3.605%3.605%3.605%3.605%3.605%3.605%
Primary 6.475%5.763%5.771%6.039%5.594%5.946%
Secondary 10.148%8.757%9.180%8.822%8.136%9.848%
2
3 There are two thgs of interest regarding Table 4: 1) all Transmission losses are considered to
4 be equal (transmission, lie generation, is a system fuction and transmission losses should be
5 equally shared by all jursdictions); and 2) Idaho has the distiction of having the highest
6 percentage losses on the distrbution system (priar and seconda) of any of the states.
7
8 Q.WHAT IS THE SECOND METHOD OF ASSIGNING LOSSES TO THE
9 VARIOUS JUSDICTIONS THAT RESULTS IN AN EXCESSIV AMOUNT OF
10 RESPONSIDILITY BEING ASSIGNED TO IDAHO?
11
12 A.The assignment of jurisdictional cost responsibility starts with the same test year
13 sales figues as used to establish the jursdictional test year revenue, but the losses assigned to
14 Idaho are based on a 5-year relationship between what is referenced as the "Border Load" to the
15 jursdictional sales. The Border Load is simply calculated each hour by measuring the amount of
16 energy coming into the state, plus the amount generated in the state, less the amount leaving the
17 state. The losses are then calculated by comparg these Border Loads with the monthly or
18 anual sales that took place in the state.
19 This has the appearnce of being quite stright forward and even highly accurate. A
20 review of the monthy losses calculated for each state demonstrates the fallacy of that perception.
Yankel, DI-20
Irgators
1 Simply lookig at the Idaho monthly losses in Table 5 below, there are four months (March,
2 June, August, and November) when the losses were negative and thee months (July, September,
3 and October) with losses greater than 20%.
2009
January
February
March
April
May
June
July
August
September
October
November
December
Simple Average
4
Table 5
Utah
6.5%
7.7%
3.6%
8.7%
6.7%
9.5%
1.3%
8.7%
1.9%
7.4%
15.2%
2.5%
Idaho
1.3%
13.3%
~0.4%
8.2%
11.2%
-7.8%
43.1%
-10.9%
27.7%
22.1%
-0.3%
5.7%
6.64%9.41%
5 Q.IS THE VARITION IN LOSSES SHOWN IN TABLE 5 BECAUSE THE
6 DATA IS PRESENTED ON A MONTHLY BASIS THAT COULD REFLECT LARGE
7 CHANGES IN SOME LOADS FROM MONTH TO MONTH?
8
9 A.No. Firt, if that were the case, Uta's and Idao's percentages would generally
10 trck each other-they do not. Second, IIP A Request 4 sought information regarding hourly
11 load data by customer class to compare with the Border Load data. By assignng the loss factors
12 derived from the Company's loss studies to each class' hourly loads; it is possible to review how
13 the Border Load fluctuates with the actual hourly sales loads. By way of example, the following
14 hourly data from Friday September 4, 2009 demonstrates how varable the relationship between
15 the hourly Idaho loads and the Idaho Border Loads can be:
Yanel, DI-21
Irgators
1
Table 6
Idaho Border
Hour Monsanto NuWest Distribution Sales Load Delta Percentage
16 22,716 12,241 281,823 316,780 415,713 98,934 31%
17 96,986 12,260 291,616 400,862 356,268 -44,594 -11%
18 104,001 12,171 281,756 397,928 422,909 24,980 6%
19 102,665 12,173 284,224 399,062 428,988 29,926 7%
2
3 Although the varation from month to month or hour to hour in the losses calculated on the basis
4 of Border Load is an obvious concern the main concern at ths point is the inppropriately high
5 level of losses that is being assigned to Idaho in ths case.
6
7 Q.UPON WHT BASIS CAN IT BE DETERMIND THAT USING BORDER
8 LOAD DATA ASSIGNS AN INAPPROPRITE AMOUN OF LOSSES TO IDAHO?
9
10 A.There are a couple of different ways to demonstrte this. As seen from the Table
11 4 above, Idaho has been calculated to have the highest percentage losses of any state with respect
12 to priary and secondary distrbution. (Appropriately, all states have the same transmission loss
13 factor as transmission is a system fuction.) However, ths does not mean that Idaho should have
14 the highest overall percentage of losses. By comparison to the other states, Idaho has a very high
15 percentage (45%) of its sales at the Transmission level where the percentage ofloss is much
16 lower. Based upon the Company's loss study, combined with the test year loads, Idaho's losses
17 should only be 6.98%.13 However, the Company's use of its Border Load data assigns 9.82%
13 Company Exhibit 49, tab 5, page 14 lists total sales (at sales level) at 3,325,873 MWH and at input level
at 3,557,873 MWH for an overall level oflosses of 6.9756%.
Yanel, DI-22
Irgators
1 losses to Idaho. 14 By comp~rison, the Company's loss study indicates that if all ofIdaho's load
2 (including Monsanto) were at the seconda level, the overall losses should only be 10.148%--
3 almost the same as what is calculated by the Border Load.
4
5 Q.HOW ELSE CAN IT BE SHOWN HOW INAPPROPRITE THE LOSSES
6 ASSIGNED TO IDAHO AR?
7
8 A.From Table 5 it can be calculated that (relatively speakg) the losses assigned to
9 Idaho in 2009 under the Border Load method would be approximately 42% more than those
10 assigned to Utah.15 As pointed out above, based upon the Company's loss study and the actual
11 test year usage in Idao, the losses for Idaho would be 6.98%. Doing a similar analysis on the
12 test year usage data fied in the most recent general rate case in Utah, it can be calculated that the
13 overall Utah losses would be 8.08%.16 Even though the Distrbution losses in Utah are
14 calculated to be at a lower percentage than those in Idaho, Utah has only 8% of its sales at the
15 Transmission level where losses are the least, while Idaho sales are 45% at the Transmission
16 leveL. Thus, when combinig the sales in Idaho with recognition of the voltage level at which
17 those sales take place, it becomes apparent that the overall losses attbuted to Idaho should be
18 less than those attbuted to Utah. However, the Border Load data suggests that the percentage
19 of losses in Idaho should be 42% greater than that found in Uta. The Border Loads are clearly
20 measurg somethg inappropriate.
14 Compared to the sales level 00,325,873 MWH, Company Exhbit 2, page 10.14 assigns 3,652,385
MWH at input to Idaho for an overall level oflosses of9.8173%.159.4116% / 6.6399% = 1.417
16 In Utah Docket 09-035-23 on Exhbit (CCP-3), Tab 5, page 16 the total test yea sales level at input is
listed as 23,161,564 MWH and on page 17 the total test year sales at sales level is listed at 21,430,490
MWH.
Yankel, DI-23
Irgators
~~ç:
~
i1 ~:i
2 Q. WHAT is WRONG WITH THE BORDER LOADS T .'. ..IS~U&lNG AN
(JJ..'". " .t!~:r: N3 INAPPROPRIATE AMOUNT OF COSTS TO BE ALLOCATED TO IDA-HaP,,"-.0,,_,'-,."~"'-,,.,.,
4
5 A.Although the Border Load calculation has some degree of accuracy, the fact is
6 that it is an inappropriate measure of the losses that should be assigned to Idaho. The Border
7 Loads determine all losses that occur in Idaho, but all losses that occur should not necessarly be
8 assigned to Idaho. Specifically, any losses that occur on the Transmission system are system
9 losses and not Idaho losses in that they will have little, if anything, to do with Idaho load.
10 For example, in 2009 there were 12,715,000 MWH that entered the Idaho jurisdiction and
11 9,495,000 MWH that left Gust went though) the jursdiction.
i The difference (Border Load) of
12 3,220,000 either went to Idaho sales customers or losses. Idaho sales were only 2,950,000 MWH
13 which is only 23% of what entered Idaho. Based upon the Border Load calculation, ths leaves
14 270,000 MWH for losses that occured in Idaho, but not necessarly for Idaho. Those losses not
15 only related to the 2,950,000 MWH of sales in Idaho, but the 9,495,000 MWH of energy that
16 simply passed though Idaho on its way to non-jurisdictional customers.
17 The Company's loss studies appropriately assign to all states the same level/percentage of
18 Transmission loss-the Border Load method simply assigns to Idaho any losses that happen to
19 occur on the Transmission system in Idaho to Idaho.
20
21 Q.HOW SHOULD LOAD AN LOSSES BE ASSIGNED TO IDAHO IN THE
22 JUSDICTIONAL ALLOCATION MODEL?
i See Response to LIP A Request 132.
Revised Yanel, DI-24
Irgators
1
2 A.Load should be assigned to Idao using the same load/sales as used to set the test
3 year revenue requirement. Losses should be based upon the same losses that were calculated in
4 the Company's loss study and applied to the test year sales in Idaho.
5 Based upon the Company's filing there was 3,325,873 MWH sold in Idaho at the sales
6 level and this equates to 3,557,594 MW at input. Previously, I recommended that 116,877
7 MWH at the sales level be added to reflect a more properly nornalized Irgation usage. Using
8 Company's 10.148% losses that are assigned to Idaho secondar sales, the losses associated with
9 ths correction would add an additional 11,861 MWH. is Thus, the total energy that should be
10 used to assign costs to the Idaho jursdiction should be 3,686,332 MW. 19 Ths energy figure is
11 virally the same as that used in the Company's filing, which did not include an appropriate
12 level of normalized Irgation usage (3,652,385 MW). Thus, I recommend increasing test year
13 energy by 33,947 MWH or 0.929% in order to reflect normalized Irrgation sales, but removing
14 excess losses assigned to Idaho. 20
15 As the Company indicated in its testiony, it developed a test year set of monthly
16 coincident peak and then adjusted those peaks in order to match the changes it made in test year
17 sales. In the same maner as was used by the Company, I recommend an increase in the
18 Company fied jursdictional coincident peaks for Idaho by ths same amount (0.929%).
19
20 Q.WHAT IS THE NET IMPACT OF TH CHANGE IN THE NORMLIZED
21 TEST YEAR SALES TO THE IRGATORS COMBIND WITH THE REDUCTION IN THE
is 116,877 x 0.10148 = 11,861.
193,557,594 + 116,877 + 11,861 = 3,686,332.
20 3,686,332 / 3,652,385 = 1.0092944.
Yankel, DI-25
Irgators
1 EXCESSIVE LOSSES THAT WERE ASSIGNED TO IDAHO BECAUSE OF THE USE OF
2 BORDER LOAD DATA?
3
4 A.As pointed out above, the more appropriate normalization of test year Irgation
5 usage/revenues results in an increase in Irgation and jursdictional revenues of $7 million. The
6 removal of the excess losses associated with the use of Border Load data almost entirely removes
7 the impact (Idaho energy and demand allocators) of the increase in the normalized Irgation
8 data. The net impact is an increase of jursdictional energy and demand allocation values by
9 0.929%. Using the company's JAM and RAM models with these new inputs results in the
10 Company's proposed rate increase of $27,697,872 being reduced by $5,394,641.
11
Yankel, DI-26
Irgators
1 Irrigation Load Control Program
2 Q.HAS THE COMPANY'S IRGATION LOAD CONTROL PROGRAM BEEN
3 SUCCESSFUL?
4
5 A.Yes, it has been very successfuL. As a matter of fact, given the size of the
6 jursdiction, it is probably the largest load control program in the countr. The Company's 2009
7 report on the Irrgation Load Control Programs contains a number of interesting facts:
8 * There was a total of 258 MW (at sales level) of participation during the peak
9 month of July 2009. Of this amount, 4 MW was on the Schedule Forward
10 Program (Schedule 72) and 254 MW was on the Company Dispatch Option
11 Progr (Schedule 72A).21
12 * Only an average of 12.6 MW opted out of the curilments durg July 2009.22
13 * The benefit of the program is established to be $81.56/kW -yr at the sale leveL. 23
14 * The all-in progra costs (adinistration, field and equipment costs, and
15 paricipation credits was established to be $41.34 per kW of participation. 24
16 * The Company Dispatch Option Program (Schedule 72A) customers (that make
17 up 98.5% of the participating load) are paid a credit (which is included in the all-
18 inprogramcosts)of$30perkW.
19
21 Schedule 72 & 72A Idaho Load Control Program (2009 Credit Rider Initiative Final Report), at 11.
22 !d. at 8.
23 !d. at 10. This is based upon only using a loss factor of 10.39%, which is the peak demand factor used
for the Utah secondary system, not the 11.642% that the Company uses for Idaho.
24 ¡d. at 16.
Yanel, DI-27
Irgators
1 Q.WAS THE PARTICIPATION IN THE IDAHO IRRGATION LOAD
2 CONTROL PROGRAM DURG THE TEST YEAR SIMILAR TO THAT LISTED IN THE
3 2009 REPORT?
4
5 A.A report for the 2010 Irgation season has not been produced as of ths wrting.
6 According to preliminary reports,25 the amount of paricipation grew in 2010 (the test year). The
7 paricipation level (at sales) is believed to now be:
Table 7
2010
June
July
Aug.
Avoided
MW
261
282
278
At Input
Avoided
MW
291
315
310
8
9 Weather conditions in 2010 were simlar to those of 2009, so it is expected that the need for
10 curilments was below "normal" durg 2010.
11
12 Q.ARE THE IRGATORS PAID THE FULL BENEFIT THAT IS REALIZED
13 BY THE SYSTEM FROM THIS PROGRAM?
14
15 A.No, far from it. As pointed out above, the system benefit is calculated to be at
16 least $81.56 per kW of Irgation demand that participates in the program. The Dispatch Option
17 customers are paid only $30 per kW as a credit. Another $11.34 per kW of cost is incured in the
25 See Response to lIP A Request 23-A.
Yankel, DI-28
Irgators
1 operation of the program. Ths leaves $40.22 per kW26 of benefit that is left to be shared by all
2 customers on the system.
3
4 Q.is THE BENEFIT OF THE IDAHO IRRGATION LOAD MAAGEMENT
5 PROGRAM PROPERLY CREDITED TO IDAHO AND THUS THE IDAHO IRRIGATORS?
6
7 A.No. It is a well recognized fact that all of the Company's customers, not just the
8 Idaho customers or the Idaho Irgators, equally share in the benefit of the progr. In fact, the
9 customers in Oregon, Utah, and the other states get even more than what would seem to be the
10 "system benefit" of $40.22 per kW that is above the cost of the program. This is because the
11 Irgation Load Management Program is treated as a situs cost and not a system cost.
12 Generally speakig, the Company's jursdictional cost allocation model has Idaho pay for
13 all costs associated with the Progra (admstrative and credit payments), but reduces the test
14 year coincident peak load to Idaho in recogntion of the Irgation Load Management Program as
15 follows:
Table 8
2010
June
July
Aug.
Jurisdictional
Credited MW
184
189
182
16
17 Rung these reductions through the Company's jursdictional allocation models results in a net
18 reduction in revenue requirement of approximately $7.5 millon dollars. This is approximately
19 the same as the $7.3 millon of participation credits for which the Idaho jursdiction is made
26 $81.56 less $30.00 less $11.34 = $40.22
Yanel, DI-29
Irgators
1 responsible for in the Company's situs assignent of these costs to Idao.27 Essentially, Idaho is
2 made "even" with respect to the partcipation credits that are paid to the Irgators.
3 However, Idaho is also situs assigned all of the other costs of the program as well.
4 PacifiCorp Schedule 191 (Customer Effciency Service Rate) has built into it $4,300,000 per
5 year of forecasted Irgation Load Control administrative costs. These are costs that are not
6 being spread in any fashion to the other system customers.
7
8 Q.WHAT IS THE NET RESULT OF THIS SITUS TREATMENT WITH
9 RESPECT TO THE REST OF THE SYSTEM CUSTOMERS?
10
11 A.Based upon the benefit of$8L.56/kW, and the credit that is given to Idaho in the
12 jursdictional allocation model, all of the system customers essentially pay for the parcipation
13 credit of $30/kW, but they pay none of the adminstrative costs of the program. Essentially all of
14 the non-Idaho system customers are receiving a benefit of$5L.56/kW,28 while Idaho ís pickig
15 up all of the admnistrative costs and its share of the partcipation credit costs.
16
17 Q.ASIDE FROM THE INEQUITABLE SITUS TREATMENT OF THE IDAHO
18 IRGATION LOAD CONTROL PROGRA COSTS, ARE THERE PROBLEMS WITH THE
19 MANNR IN WHICH THESE COSTS AND BENEFITS ARE ALLOCATED?
20
21 A.Yes. The benefit to Idaho, as passed though the jursdictional model, is based
22 upon data that does not fully compensate Idaho for the reductions that are being offered. The
27 See Company Exhibit 2, page 4.5
28 $81.56 less $30.00 = $51.56
Yanel, DI-30
Irgators
1 curilment reductions used by the Company (as listed in Table 8 above) are based upon two
2 inappropriate assumptions. Firt, the starting point for the development of these figues is too
3 low. The Company used a starng point of 229 MW of curilment for each of the three summer
4 months in the test year. In 2009, ths value was exceeded durng all thee sumer month. As
5 can be seen from Table 7 above, the anticipated partcipation level for each sumer month of the
6 test yearis 30-50 MW higher than ths starting value. The second problem is tht these levels
7 of "potential" curtilment are at the sales level and not at the input level-they need to be
8 increased by 11.642%--the demand loss factor used for seconda distrbution in Idaho. The
9 appropriate level of potential curilment is listed below on Table 9 as well as the same
10 coincident factor values used by the Company to come up with the ultimate reduction that should
11 be applied to the jursdictional allocation model:
2010
June
July
Aug.
Irrigation
Avoided M\i
261
282
278
Table 9
At Input
Avoided MW
291
315
310
Coincident
Factors
80.20%
82.50%
79.40%
Curtailment
Adjustment
234
260
246
12
13 Q.WHAT IMPACT IS THERE TO THE COMPAN'S REVENU
14 REQUIMENT OF USING ACTUAL 2010 POTENTIAL CURTAILMENT LOADS AND
15 LOSS FACTORS TO REFLECT LOAD AT INPUT?
16
17 A.By only reflectig 2010 potential curilment load and incorporating loss factors,
18 the Company's revenue requirement in Idao was decreased by $2,524,000.
19
Yanel, DI-31
Irgators
1 Q.WH HAD THE COMPAN LIMITED ITS POTENTIAL CURTAILMENT
2 OF IRGATION LOAD TO ONLY 229 MW?
3
4 A.The reasons that the curailment levels used were limited to 229 MW can be
5 gleaned from the 2009 Idaho Irgation Load Curilment Report at page 18 where under
6 "Dispatch considerations" it was stated in part:
7 · Idaho Engineerig Area Plang is concerned that too much load is either
8 removed from or added to the system in too narow of a time-frame (causing
9 voltage imbalances).
10 · Upon intiation of a dispatch event voltage spikes above toleraces of existing
II substation and/or circuit protective equipment and systems.
12 · Upon the conclusion of the dispatch event and loads are once again retued to
13 their 'normal' position voltage drops below toleraces of existig substation
14 and/or circuit protective equipment and systems.
15 . Curently there is simply insufficient tie delay in either substation and/or system
16 circuitr to accommodate the drmatic voltage changes. (Emphasis added)
17 These statements were followed up on page 18 of the 2009 Report with the following
18 "Recommendations":
19 . Plenary discussions with RM Area Plannng (Idaho) has determed that a more
20 intellgent stepping into and out-of dispatch events wil correct the voltage
21 spikes/sages curently occurrg.
22 . Changes to the dispatch protocol may be an effective strategy to delay additional
23 capital investment in infrastrctue assets.
24 . Changing the dispatch protocol wil require analysis of the RM engineering
25 database to determine geospatialload locations as well as coordination with
26 growers.
27 . A changed dispatch protocol wil require the available dispatch windows to be28 lengtened.
29 . The aforementioned changes have been preliminarly discussed with Idaho
30 growers and with members of the Idaho Irgators Pupers' Association (IIPA).
31 . The IIP A is supportve of the requisite chages.
32 . This requirement wil also necessitate a tariff modification.
33 . As soon as anlysis can be concluded and a dispatch strtegy designed the
34 Company wil provide details that will be (1) reviewed with the IIP A and (2) put
35 forward the appropriate taff changes to Schedule 72A for Commission
36 consideration. (Emphasis added)
Yankel, DI-32
Irgators
1 There are three points that can be gathered from the above discussion that was in the Company's
2 2009 Idaho Irrgation Load Curilment Report: 1) Some, if not all of the problems could be
3 addressed with distrbution equipment upgrades; 2) The spacing out of the curilments was
4 believed to be an inexpensive solution to the problem; and 3) The Company planed to make
5 changes in its dispatchig of curilments durng 2010.
6 As pointed out earlier in this testimony, Idaho has the highest Distrbution loss factors of
7 any of the states in which PacifiCorp operates. Additional expenditues to modernze the Idaho
8 Distrbution equipment may be a good idea and is not necessarly somethg to be avoìded.
9 From my review of the Company's 2009 load research data associated with the Irgators
10 it would appear that the curilments of the Irgation customers had already been spread out to
11 some extent. We have not heard the results of the fuher spreading out of these curìlments
12 durng 2010 and do not expect to hear until the 2010 Report is filed.
13 The Company filed ths general rate case with the 229 MW limitation on curailments
14 before the 2010 Irgation season even began and before it had tred its new dispatching protocol.
15 Furhermore, the Company added additional curailable load in 2010, which presumably the
16 Company felt that it could accommodate.
17 Based upon all of the above, there is no reasòn in this general rate case to limit the credit
18 calculated for the Idaho jurisdiction to a potential curilment of just 229 MW.
19
20 Q.IN THE LONG TERM, WHT DO YOU PROPOSE BE DONE IN ORDER TO
21 EQUITABLY ALLOCATE SYSTEM COSTS AND SYSTEM BENEFITS OF THE IDAHO
22 IRGATION LOAD CONTROL PROGRAM?
23
Yankel, DI-33
Irgators
1 A.Not all load management programs are equal. It makes sense to have the same
2 treatment for all programs, but that treatment should not be as archaic as the present method
3 where most of the benefits of a progrm are essentially spread to the system, while all the costs
4 are absorbed by the host jursdiction. If a jursdiction is going to absorb all of the costs of a
5 direct load control program, then that jursdiction should also be assigned all of the benefits of
6 that program. In ths manner, if the program has benefit beyond its cost, then the net benefit
7 would be realized by the host jursdiction. If the program has little or no net benefit, then the
8 host jursdiction wil bear the consequences.
9 This allocation of benefits could simply be done by "selling" reductions to the system at
10 the avoided cost-presently calculated to be $8L.56/kW-year at the sales leveL. In the case of the
11 Idaho Irgation Load Control Program, Idaho would be responsible for the approximate
12 $4L.34/kW of all-in costs, and there would be no "reduction" in coincident demand calculated as
13 a result of the program-the allocations would impute a value for any curilments that took
14 place durng the montWy system coincident peaks. The difference between the $81 "sale price"
15 and the $41 cost would go to reduce Idaho's revenue requirement.
16
17 Q.CAN YOU GIVE A SIMPLIFIED EXALE OF HOW THIS WOULD
18 WORK?
19
20 A.Yes. Assuming that there are 300 MW of Irgation load signed up for Schedule
21 72A's dispatchable load control program, ths could be "sold" to PacifiCorp for $81.56/kW or a
22 total of $24,500,000 (300,000 kW times $81.56). Ths would be treated as a purchase power
23 cost and allocated to all jursdictions on a demand basis. Idaho would be responsible for
Yankel, DI-34
Irgators
1 approximately 5.22% of this cost, based upon the System Capacity allocation factor. Idaho
2 would thus pay approximately $1.3 milion associated with ths "purchase". Idaho would also
3 absorb the $9.0 milion associated with the credit paid to the Irgators (300,000 kW time
4 $30/kW). Idaho would also pay the adminstrative cost of the program which it is now paying of
5 $4.3 milion though Schedule 191. Idaho would pay $14.6 milion (1.3 + 9.0 + 4.3 == 14.6), but
6 would be given a credit of 24.5 milion as a credit against its jursdictional revenue requirement.
7 Thus, instead of the program costing Idao approximately $4.3 milion per year, it would benefit
8 by $9.9 million and all of the other jursdictions would simply be kept neutral.
9
10 Q.WOULD UTAH'S COOL KEEPER AND IRRGATION LOAD CONTROL
11 PROGRAMS BE TREATED IN THE SAME MAER?
12
13 A.Yes. However, care would need to be taken to insure tht the costs of the
14 progras are calculated in a manner similar to that being done for the Idaho Irgation Load
15 Control Program. Such an analysis for Utah's progras has not been done, so the Company's
16 present treatment in Utah (Situs treatment of costs and assignment of demand reduction) should
17 contiue until such time as either the Uta Jursdiction or the Company wish to put forth the
18 information upon which to make such a change. If the Uta Cool Keeper progrm is not cost
19 effective, Utah may desire to keep the present treatment.
20
Yankel, DI-35
Irgators
1
2
The Load Growth Adjustment Rate in the
Energy Cost Adjustment Mechanism
3 Q.PLEASE DESCRIE THE ENERGY COST ADJUSTMENT MECHAISM
4 AND LOAD GROWTH ADJUSTMENT RATE AS THEY RELATE TO THIS CASE.
5
6 A.The Energy Cost Adjustment Mechasm ("ECAM") is designed to recover on an
7 actual basis the sum of all components of net power supply costs as defined in a general rate case
8 such as ths. The mechanism does not address fixed-cost recovery such as the fixed costs of
9 investment in rate base. Basically, the ECAM only considers the variable power supply costs
10 that are modeled in GRID and compares them with the actual costs incured.
11 In addition to comparng actual net power costs to those modeled by GRI in a general
12 rate case, the ECAM includes some additional components such as the Load Growt Adjustment
13 Rate ("LGAR"). The theory behind the LGAR is that the Company should not be allowed to
14 collect growt-related power supply costs though an ECAM surcharge and also collect base
15 revenues from the new load to recover those same power supply costs.
16
17 Q.WHAT PROBLEMS AR BEING ENCOUNERED WITH RESPECT TO THE
18 LGAR?
19
20 A.PacifiCorp has had an ECAM and thus an LGAR for only a short period of time.
21 However, the Commission has had a great deal of experience with an ECAM tye mechansm
22 and an LGAR as they relate to Idaho Power. Unfortately, due to the recent economic
23 recession and possible other causes, the LGAR for both companes has not worked as intended.
Yankel, DI-36
Irgators
1 The LGAR was intended to off-set the double recovery of growth related costs in both base rates
2 and the ECAM. Although the mechanism works well as intended for growth, it produces
3 untended consequences under conditions of load decline-somethng that it was never
4 designed to address. In the case of load decline, the LGAR adjustment does not reflect costs that
5 were incured by Company but, it represents costs that were never incured. If allowed to
6 operate durng ties of load loss, as well as load growth, ths adjustment would give the
7 Company revenue to cover costs that were never incured. Such a result is unquestionably unjust
8 and uneasonable. Essentially, under these conditions, the LGAR operates as a decoupling
9 mechasm that was never approved by the Commission.
10
11 Q.PLEASE EXPLAIN FURTHER.
12
13 A.The entire concept of the ECAM was to recover varations in actual power
14 supply expenses that differ from test year calculations-the emphasis here should be on
15 actual power supply expenses. The ECAM itself was meant to be "symetrcal" in that it
16 was designed to give the Company more money/revenue when its power supply expenses
17 went up (compared to test year) and less money/revenue when its power supply expenses
18 went down (compared to test year). However, ths symetr was only in relationship to
19 the power supply expenses themselves, not to the LGAR.
20 It is appropriate in a pass-though mechansm such as the ECAM, that the
21 consumers pay more when expenses go up, but it makes no sense to raise rates when
22 usage, and thus costs, go down. When rates go up as usage goes down, a decoupling
23 mechanism is in effect-not a pass-though. The Commission has not authorized a
Yanel, DI-37
Irgators
1 decoupling mechansm. It is appropriate that the load growth adjustment offsets to some
2 extent the amount of money that the Company gets in its ECAM to reflect the increased
3 base revenue that PacifiCorp gets associated with additional load. However, it makes no
4 sense to increase the revenue that PacifiCorp gets in the ECAM because of loss of load
5 when expenses are reduced.
6
7 Q.WHT is THE REASON FOR THE LGAR IN PACIFICORP'S ECAM?
8
9 A.Very simply, it is to prevent the double recovery of a single cost. It
10 prevents the Company from collectig growt related power supply expenses though the
11 ECAM that are .also being collected in base revenue from new/increased load to cover the
12 same power supply expenses. The concern here is in the case where the growt has not
13 occured, the cost of growth has not occured, and there have been no additional power
14 supply expenses that were incured. Why should the LGAR increase the ECAM revenue
15 for growt, and costs of growth, that never occured? Clearly the collection of an
16 expense that never occured is againt all priciples of fairess, let alone the
17 Commission's statutory responsibility.
18
19 Q.SHOULD THE LGAR BE SYMTRICAL?
20
21 A.Although the ECAM was designed to be symetrcal, the LGAR should
22 not. It is appropriate that the ECAM increase or decrease as the Company's power
23 supply expenses increase or decrease. However, when the power supply expenses
Yanel, DI-38
Irgators
1 decrease because the load has dropped, the LGAR should never be increased to make up
2 for expenses that were never incured. The LGAR was never meant to be symmetrcal
3 and it does not make sense that it should be symetrcal. Because of the sustained
4 growt that PacifiCorp and Idaho Power have expenenced over the last 20-30 years, the
5 idea of a load decrease was far from everyone's mind when the LGAR was created.
6 Even the name of the LGAR (Load Growth Adjustment Rate) demonstrates that ths is a
7 one-way adjustment related to growth. If it had been conceived of as a symmetrcal
8 adjustment, it would have been more properly called an "Adjustment Rate for Load
9 Changes".
1 0 There are numerous places in Commssion Orders as well as in testimony
11 presented before the Commission that demonstrate that the intent of the LGAR was to
12 address the issue of increased power supply expenses due to growt and the offsettng
13 additional revenue that comes with new load. There has never been mentioned in a
14 Commission Order of the intent of the LGAR (in PacifiCorp's or Idaho Power's cases) to
15 reflect any type of adjustment for a reduction in system load, let alone to be an
16 adjustment to increase the Company's revenues when loads decreased.
17 More specifically, the LGAR was designed to insure that there was no double
18 recovery of the additional power supply expenses that result due to growt. There are no
19 "additional" power supply expenses associated with a reduction in load~simply, less
20 coal is bured, there is less power purchased, or there are more sales for resale that brigs
21 in additional revenue.
Yankel, DI-39
Irgators
1 The design of the LGAR/ARG29 to insure that there was no double recovery of
2 additional power supply expenses as a result of load growt was sumarized by Staff
3 witness Hessing in Idaho Power Case No. IPC-E-06-830:
4 Q. Please discuss Idaho Power Company's intial PCA filing.
5 A. Idaho Power Company fied for a PCA in 1992 and it was
6 approved and implemented in 1993 with some modifications. Idaho
7 Power's 1992 fiing was made to address the problem of fluctuating water
8 conditions that caused widely varing power supply costs. When water
9 conditions were poor, power supply costs were higher than what was
10 authorized for recovery in rates. A general rate case provided no relief
II from high power supply costs associated with below normal water
12 conditions since water conditions and power supply costs are normalized
13 in a general rate case.
14 Staff observed that in the Company's original PCA proposal,
15 varations from the normalized costs of power supply were due to water
16 conditions and power supply cost increases caused by load growth. Staff
17 believed that load growt costs could be significant and that load growth
18 costs were not the kind of costs that the PCA should recover. Staff
19 proposed a load growth adjustment mechanism in the PCA that removed
20 actual power supply costs associated with load growth by multiplyig the
21 amount of load growt by the marginal cost of power supply and
22 subtracting the result from actual power supply costs. Staff approximated
23 the marginal cost of power supply as 16.84 $/M which was the average
24 of the varable costs of Valmy and Boardman, the company's two highest
25 operating costs at that time. In that case Staff also argued that without the
26 adjustment the Company would double recover the normalized cost of
27 power supply because it was included in base rates and in actual booked
28 power supply costs that accumulated in the PCA tre up mechanism.
29 (Emphasis Added)
30 The testimony of Staff in Case No. IPC-E-06-8 that the LGARARG was designed to
31 prevent double recovery of power supply expenses did not stand on its own, but was fully
32 supported by the Company testiony in that same case. Idaho Power witness Said made
33 numerous references to the fact that the LGAR/ARG was designed to prevent the
29 In PacifiCorp ECAM cases this "growth adjustment" is known as an LGAR, while in Idaho Power PCA
cases the "growt adjustment' is known as an Expense Adjustment Rate for Growt ("EARG").30 See Hessing's direct testimony in Case No. IPC-E-06-8 page 4, begiing on line 9.
Yankel, DI-40
Irgators
1 double recovery of growth related power supply expenses in his Rebuttl testimony in
2 that same case: 31
3 Adoption of an adjustment mechanism based on expenses levels created
4 the potential for double collection of power supply expenses from
5 customers. Idaho Power believes that the intent of the load growth
6 adjustment rate was to eliminate the possibility of double collection of
7 power supply expenses.
8 Q. Do the other witnesses in ths case agree that eliminatig the
9 possibility of double collection of power supply expenses from customers
10 has been a historical intent of the load growt adjustment rate?11 A. Yes. ...
12 Later in his testiony in that same case, Idao Power witness Said sumarizes his
l3 testiony and makes an even stronger case for the Company's position/elief that the
14 LGARARG is only for puroses of preventing the Company from double recoverig
15 growt related power supply expenses: 32
16 Q. Please sumarie your rebuttl testimony.
17 A. All pares agree that a principal purose of the PCA load growt
18 adjustment rate is to eliminate the potential for double recovery of power
19 supply expenses. Idaho Power believes ths should be the sole puose of
20 the load growth adjustment. (Emphasis added)
21
22 Mr. Said made it very clear what Idaho Power felt was the "sole purpose" of the
23 LGAR/ARG. However, because of a quirk in the calculation, that became evident as a
24 result of a severe global economic crisis, both PacifiCorp and Idao Power have now
25 used the LGAR and the EARG to collect revenue for expenses that never occured.
26 Given the steady growth that has taen place over the last 20-30 years, there had
27 been virally no consideration of what happens when growt is negative. Like Idaho
28 Power witness Mr. Said testified, the sole purpose of the growth adjustment was to insure
31 See Said's Rebuttal testimony in Case No. IPC-E-06-8 page 3, beging on line 6.
32 See Said's Rebuttal testimony in Case No. IPC-E-06-8 page 27, begining on line 11.
Yanel, DI -41
Irgators
1 that there was no double recovery of power supply expenses when there was positive
2 growt (as occured every year in the past). However, even though there was little or no
3 consideration of the possibility of what the LGAR calculation would produce if there was
4 a decrease in load, the thought that the LGAR could ever produce a negative result was
5 rejected by the Commission Staff. In Case IPC-E-07-8, Staff witness Hessing made such
6 a declaration that was never challenged by any par in that case, including Idaho Power.
7 Staff witness Hessing stated on page 18 line 14 of his direct testiony that: "It is not
8 reasonable to apply a negative EARG in the PCA."
9
10 Q.WHT ARE YOU RECOMMENDING IN THIS CASE REGARDING
11 THELGAR?
12
13 A.I am not addressing the level or dollar amount of the LGAR. I am only
14 addressing the use of the LGAR in situtions where load is declinig-such situations
15 that are just the opposite of the LGAR's intended purose. In both the recent PacifiCorp
16 ECAM case and an Idaho Power PCA case, negative growt has been encountered and
17 for lack of direction or for whatever reason, the LGAR has been allowed to effectively
18 operate as a decoupling mechanism and increase rates in the face of reduced sales. I
19 recommend that in ths case when the Commission sets the LGAR rate, that the
20 Commission state very clearly that the LGAR is only to be applied in cases where there
21 has been growth on the system compared to sales levels used in the general rate case to
22 develop the net power costs that wil be included in rates.
23
Yankel, DI-42
Irgators
1 Class Cost of Service
2 Q.WHT DOES THE COMPAN'S COST OF SERVICE STUDY
3 INDICATE ABOUT THE RATE OF RETUR BEING SUPPLIED BY THE
4 IRGATORS?
5
6 A.The Company's cost of service study calculates that the Irrgators are
7 providing a rate of retu that is 20% greater than the system average.33 Based upon this,
8 the Company is proposing that the Irgators only get 70% of the average rate increase
9 that wil be adopted.
34
10
11 Q.IS THE COMPAN'S COST OF SERVICE STUDY WITH RESPECT TO THE
12 IRRGATORS BASED UPON APPROPRITE INFORMTION?
13
14 A.No, the Company's cost of servce study suffers from two major flaws with
15 respect to the Irgators: 1) as pointed out above, the normalized sales levels used are grossly
16 inadequate and understate the amount of Irgation sales and thus revenues; and 2) the
17 Company's method of developing sales over a 5-year average results in effectively giving
18 Irgators virally no recogntion in the cost of service study for any curilment associated with
19 the load management program.
20
21 Q.PLEASE DESCRIE THE SHORTCOMIG WITH RESPECT TO THE
22 IRGATION SALES LEVELS FURTHER.
33 See generally Company Exhibit 49, Tabs 4 and 4.1
Yanel, DI-43
Irgators
1
2 A.As pointed out above with respect to the jursdictional revenue requirement, the
3 test year "weather normalized" Irgation sales were signficantly below the normalized values
4 that have been seen over the last ten years, as well as fallng short of the slightly increasing trend
5 in normalized Irgation sales over time. Adjustig the test year sales to a more realistic level
6 would increase Irgation revenues by $7 milion, while only increasing energy/variable related
7 costs and not fied demand or customer related costs. As such, an increase in sales would result
8 in a significant increase in Irgation revenue tht would be larger than the associated increase in
9 expenses. Thus, these increased sales would increase the Irgation rate of retu, well in excess
10 of what the Company calculated.
11
12 Q.PLEASE DESCRIE FURTHER THE SHORTCOMING WITH RESPECT TO
13 THE LACK OF RECOGNITION OF THE IMPACT OF THE CURTAILMENT OF
14 IRGATION LOAD THAT IS TAKIG PLACE.
15
l6 A.Earlier I pointed out that the Company's jursdictional model did not give
17 full credit to the Idaho jurisdiction for the level of curailment that took place with respect
18 to the Irgation Load Control Progrm. However, the Company at least reduced the
19 Idaho sumer jursdictional peaks by 184, 189, and 182 MW each. Unlike these
20 reductions (that were inadequate), there was no such recognition of any curilment of the
21 Irgation load in the Company's class cost of service study. This is in spite of the fact
34 See Griffith direct testimony at page 2
Yanel, DI-44
Irgators
1 that the same 5-year average Irgation load was used for both the class cost of service
2 study and the jursdictional modeL.
3
4 Q.ARE YOU PROPOSING AN SPECIFIC CHAGES TO THE
5 COMPAN'S COST OF SERVICE STUDY TO CORRCT THESE
6 SHORTCOMIGS?
7
8 A.Not at ths time. I provide these observations in order to inform the
9 Commission that the rate of retu calculated by the Company for the Irgation class is
10 severely understated and that the actual rate of retu for the Irgators is much higher
11 than calculated by the Company.
12 Because I am not proposing specific adjustments at ths time to the Company's
13 cost-of-service study, I am acceptig (for now) the Company proposal to limit the rate
14 increase to the Irgators to the 70% of system average as proposed by the Company.
15 Assuming no other party advocates for an increase greater thn 70% of the system
16 average for the Irgation customer, I wil not propose any fuher adjustments in this
17 case.
18
19 Q.DOES THIS CONCLUDE YOUR DIRCT TESTIMONY?
20
21 A.Yes.
Yankel, DI-45
Irgators
Forecasted Weather Normalized Residential Sales
vs.
Actual Weather Normalized Residential Sales
Forecast--weather normalized
Year Month Schedule 1 Schedule 36 Schedule 135 Schedule 7 Schedule 7AR2010 1 45,756 35,828 100 1 92010 2 38,666 29,889 95 1 82010 3 38,601 28,320 93 1 92010 4 32,533 22,652 83 1 92010 5 30,004 18,579 85 1 102010 6 28,661 15,561 88 1 10 365,652
Actual--weather normalized
Year Month
2010 1 50,577 39,805 109 1 9
2010 2 42,392 32,608 105 1 9
2010 3 38,138 28,583 85 1 9
2010 4 33,892 24,666 74 1 9
2010 5 29,242 19,428 74 1 9
2010 6 29,818 18,348 65 1 9 388,066
Delta
Year Month
2010 1 4,821 3,977 9 0 1
2010 2 3,726 2,719 11 0 1
2010 3 (463)263 (9)0 (0)
2010 4 1,360 2,014 (9)0 (0)
2010 5 (762)849 (12)(0)(1)
2010 6 1,157 2,787 (23)(0)(1)22,414
6.13%
Source:
Attachment IPUC Production 291
Exibit No. 301
Case No. PAC-E-l0~07
Yankel, Irrigators
Change in Residential Customers
Yearmonth Number of Customers Biled Delta
200701 54,556
200702 54,663 107
200703 54,721 58
200704 54,842 121
200705 54,902 60
200706 54,985 83
200707 55,237 252
200708 55,259 22
200709 55,426 167
200710 55,539 113
200711 55,820 281
200712 55,925 105
200801 55,946 21
200802 56,000 54
200803 56,088 88
200804 56,089 1
200805 56,148 59
200806 56,154 6
200807 56,321 167
200808 56,376 55
200809 56,488 112
200810 56,578 90
200811 56,706 128
200812 56,805 99
200901 56,745 (60)
200902 56,844 99
200903 56,780 (64)
200904 56,733 (47)
200905 56,739 6
200906 56,807 68
200907 56,908 101
200908 56,887 (21)
200909 56,947 60
200910 57,039 92
200911 57,130 91
200912 57,156 26
Source:
Attachment IPUC 20
Exhibit No. 302
Case No. PAC-E-10-07
Yankel, Irrigators
Case No. PAC-E-10-07 Exhibit 303
Yankel, Irrigators Page 1 of 6
PACIFICORP IDAHO 2007 LOSS ANALYSIS
PACIFICORP IDAHO REVISED
EXHIBIT 1
SUMMARY OF COMPANY DATA
ANNUAL PEAK 700 MW
GENERATION & PURCHASES-INPUT 3,735,483 MWH
ANNUAL SALES -OUTPUT 3,485,83 MWH
SYSTEM LOSSES INPUT
OUTPUT
2~9,649 or 6.68%
or 7.16%
61.0%SYSTEM LOAD FACTOR
. SUMMARY OF LOSSES - OUTPUT RESULTS
SERVICE KV MW % TOTAL MWH % TOTAL
TRANS 345,161,115 33.2 59.89%129,98 52.07%
4.74%3.48%
PRIMARY 69,34,12,1 12.7 22.97%55,144 22.09%
1.82%1.48%
SECONDARY 9.5 17.14%64,522 25.85%
1.36%1.73%
TOTAL 55.4 100.00%249,649 100.00%
7.91%6.68%
SUMMARY OF LOSS FACTORS
CUMMULATIVE SALES EXPANSION. FACTORS
SERVICE KV DEMAND ENERGY
d 1/d e 1/e
TRANS 345,161,115 .1.04975 0.95260 1.03605 0.96520
PRIM SUBS 69,46,35 0.00000 0.00000 0.0000 0.00000
PRIMARY 69,34,12;1 1.0864 0.92043 1.06475 0.93919
SECONDARY 1.11642 0.89572 1.10148 0.90787
Case No. PAC-E-10-07
Yankel, Irrigators
Exhbit 303
Page 2 of6
PACIFICORP UTAH 2007 LOSS ANYSIS
PACIFICORP UTAH REVISED
EXHIBIT 1
SUMMARY OF COMPANY DATA
ANNUAL PEAK 4,373 MW
GENERATION & PURCHASES-INPUT 24,246,948 MWH
ANNUAL SALES -OUTPUT 22,631,375 MWH
SYSTEM LOSSES INPUT
OUTPUT
1,615,573 or 6.66%
or 7.14%
63.3%SYSTEM LOAD FACTOR
SUMMARY OF LOOSES - OUTPUT RESULTS
SERVICE KV MW % TOTAL MWH % TOTAL
TRANS .345,161,115 207.3 59.45%843,718 52.22%
4.74%3.48%
PRIMARY 69,34,12,1 75.6 21.69%343,266 21.25%-
1.73%1.42%
SECONDARY.65.8 18.86%428,589 26.53%
1.50%1.77%
TOTAL 348.6 100.00%1,615,573 100.00%
7.97%6.66%
SUMMARY OF LOSS FACTORS
CUMMULATIVE SALES EXPANSION FACTORS
SERVICE KV DEMAND ENERGY
d 1/d e 1/e
TRANS 345,161,115 1.04975 0.95260 1.03605 0.96520
PRIM SUBS 69,46,35 0.00000 0.00000 0.00000 0.00000
PRIMARY 69,34,12.1 1.07706 0.92846 1.05763 0.94551
SECONDARY 1.10349 0.90621 1.08757 0.91948
Case No. PAC-E-10-07 Exhbit 303
Yankel, Irrigators Page 3 of 6
PACIFICORP OREGON 2007 LOSS ANYSIS
PACIFICORP OREGON REVISED
EXHIBIT 1
SUMMARY OF COMPANY DATA
ANNUAL PEAK 2,598 MW
GENERATION & PURCHASES-INPUT 15,300,810 MWH
ANNUAL SALES -OUTPUT 14.120,569 MWH
SYSTEM LOSSES INPUT
OUTPUT
1,180,240 or7.71%
or 8.36%
67.2%SYSTEM LOAD FACTOR
SUMMARY OF LOSSES - OUTPUT RESULTS
SERVICE KV MW % TOTAL MWH % TOTAL
TRANS 345,161,115 123.1 49.92%532,420 45.11%
4.74%3.48%
PRIMARY 69,34,12,1 70.2 28.48%288,840 24.47%
2.70%1.89%
SECONDARY 53.3 21.61%358,980 30.42%
2.05%2.35%
TOTAL 246.7.100.00%1,180,240 100.00% .
9.50%7.71%
SUMMARY OF LOSS FACTORS
CUMMULATIVE SALES EXPANSION FACTORS
SERVICE KV DEMAND ENERGY
d 1/d e 1/e
TRANS 345~161,115 1.04975 0.95260 1.03605 0.96520
PRIM SUBS 69,46,35 0.0000 0.0~0.00000 0.00000
PRIMARY 69,34,12,1 1.08191 0.92430 1.05771 0.9454
SECONDARY 1.1130 0.89842 1.09180 0.91592
Case No. PAC-E-10-07
Yankel, Irrigators.
Exhbit 303
Page4of6
PACIFICORP WASHINGTON 2007 LOSS ANALYSIS
PACIFICORP WASHINGTON REVISED
EXHIBIT'
SUMMARY OF COMPANY DATA
ANNUAL PEAK .753 MW
GENERATION & PURCHASES-INPUT 4,435,907 MWH
ANNUAL SALES -OUTPUT 4,090,955 MWH
SYSTEM LOSSES INPUT
OUTPUT
SYSTEM LOAD FACTOR
34,952 or 7.78%
or 8.430/067.3% .
SUMMARY OF LOSSES - OUTPUT RESULTS
;,
SERVICE KV MW % TOTAL MWH % TOTAL
TRANS 345,161,115 .35.7 48.81%154,356 44.75%
4.74%3.48%
PRIMARY 69,34,12,1 23.4 32.07%98,269 28.49%
3.11%2.22%
SECONDARY 14.0 19.12%92,327 26.77%
1.86%2~08%
TOTAL 73.1 100.00%344,952 100.00%
9.71%7.78%
SUMMARY OF LOSS FACTORS
CUMMULATIVE SALES EXPANSION FACTORS
SERVICE KV DEMAND . ENERGY
d 1/d e 1/e
TRANS 345,161,115 1.04975 0.95260 1.03605 0.96520
PRIM SUBS 69,46,35 0.00000 0.00000 0.0000 0.0000
PRIMARY 69,34,12,1 1.08523 0.92147 1.06039 0.94305
SECONDARY 1.11123 0.89990 1.08822 0.91893
Case No. PAC-E-10-07
Yankel, Irrigators . Exhbit 303
Page 50f6
PACIFICORP WYOMING 2007 LOSS ANALYSIS
. PACIFICORP WYOMING REVISED
EXHIl31T 1
SUMMARY OF COMPANY DATA
ANNUAL PEAK
GENERATION & PURCHASES-INPUT
1,127 MW
9,037,952 MWH
ANNUAL SALES -OUTPUT 8,548,886 MWH
SYSTEM LOSSES INPUT
OUTPUT
489,066 or 5.41 %
or 5.72%
91.5%SYSTEM LOAD FACTOR
SUMMARY OF LOSSES - OUTPUT RESULTS
SERVICE KV MW % TOTAL MWH % TOTAL
TRANS 345,161,115 53.4 63.68%314,492 64.30%
4.74%3.48%
PRIMARY 69,34,12.1 22.9 27.30%110,747 22.64%
2.03%1.23%
SECONDARY 7.6 9.02%63,827 13.05%
0.67%0.71%
TOTAL 83.9 100.00%489,06 100.00%
7.44%5.41%
SUMMARY OF LOSS FACTORS
CUMMULATIVE SALES EXPANSION FACTORS
SERVICE KV DEMAND ENERGY
d 1/d e 1/e
TRANS 345.161.115 1.04975 0.95260 1.03605 0.96520
PRIM SUBS 69,46,35 0.00000 0.00000 0.00000 0.00000
PRIMARY 69.34,12,1 1.08392 0.92258 1.05594 0.94702
SECONDARY 1.10925 0.90151 1.08136 0.92476
Case No. PAC-E-10-07
Yankel; Irrigators
Exhbit 303
Page 6 of6
PACIFICORP CALIFORNIA 2007 ioss ANALYSIS
PACIFICORP CALIFORNIA REVISED
EXHIBIT 1
SUMMARY OF COMPANY DATA
ANNUAL PEAK 160 MW
GENERATION & PURCHASES-INPUT 973,601 MWH
ANNUAL SALES -OUTPUT 887,818 MWH
SYSTEM LOSSES INPUT
OUTPUT
85,783 or 8.81 %
or 9.66%
69.5%SYSTEM LOAD FACTOR
SUMMARY OF LOSSES - OUTPUT RESULTS
SERVICE KV MW % TOTAL MWH % TOTAL
TRANS 345,161,115 7.7 45.55%34,260 39.94%
4.81%3.52%
PRIMARY 69,34,12,1 4.9 29.16%20,759 24.20%
3.08%2.13%
SECONDARY 4.3 25.29%30,765 35.86%
2.67%3.16%
TOTAL 16.9 100.00%85,783 100.00%
10.55%8.81%
SUMMARY OF LOSS FACTORS
CUMMULATIVE SALES EXPANSION FACTORS
SERVICE KV DEMAND ENERGY
d -1/d e 1/e
TRANS 345,161,115 1.04975 0.95260 1.03605 0.96520
PRIM SUBS 69,46,35 0.00000 0.00000 0.00000 0.00000
.
PRIMARY 69,34,12,1 1.08478 0.92184 1.05946 0.94388
SECONDARY 1.11961 0.89317 1.09848 0.91035