20071213Corrected Yankel direct.pdf

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Z001 DEC I 0 PM 5: I 0
ID,AHO PUBLIC
UTILITIES COMMISSiO¡
BEFORE THE IDAHO PUBLIC UTILITIES COMMSSION
IN TH MATTER OF TH APPLICATION )
OF IDAHO POWER COMPAN FOR )
AUTHORITY TO INCREASE ITS )
RATES AN CHARGES FOR ELECTRIC )
SERVICE TO ELECTRIC CUSTOMERS )
IN THE STATE OF IDAHO )
CASE NO. IPC-E-07-08
IDAHO IRGATION PUMERS
DIRCT TESTIMONY
OF
ANHONY 1. Y ANL
DECEMBER 10, 2007
1 Q.PLEASE STATE YOUR NAM, ADDRESS, AN EMPLOYMNT.
2
3 A.I am Anthony 1. Yanel. I am President ofYankel and Associates, Inc. My
4 address is 29814 Lake Road, Bay Vilage, Ohio, 44140.
5
6 Q.WOULD YOU BRIFLY DESCRIE YOUR EDUCATIONAL
7 BACKGROUN AN PROFESSIONAL EXPERINCE?
8
9 A.I received a Bachelor of Science Degree in Electrical Engineering from Carnegie
10 Institute of Technology in 1969 and a Master of Science Degree in Chemical Engineering from
11 the University ofIdaho in 1972. From 1969 through 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 repair of new and existing product lines
14 for coal-fired power plants. From 1973 through 1977, I was employed by the Bureau of Air
15 Quality for the Idaho Department 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 through June 1979, I was employed as the Director of the Idaho Electrical Consumers
18 Offce. In that capacity, I was responsible for all organizational and technical aspects of
19 advocating a variety of positions before various governmental bodies that represented the
20 interests of the consumers in the State ofIdaho. From July 1979 through October 1980, I was a
21 partner in the firm ofYankel, Eddy, and Associates. Since that time, 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
1 Yanel, DI
Irrgators
1 State Public Utility Commissions ofIdaho, Montana, Ohio, Pennsylvania, Utah, and West
2 Virginia.
3
4 Q.
5
6 A.
7 (Irrigators).
8
9 Q.
10
11 A.
12
13
14
15
16
17
18 Q.
19 CASE?
20
21 A.
22
23
ON WHOSE BEHAF AR YOU TESTIFYIG?
I am testifying on behalf of the Idaho Irrigation Pumpers Association, Inc.
WHAT IS THE PUROSE OF YOUR TESTIMONY IN THIS PROCEEDING?
My testimony will address:
. Disproportionate growth on the system
. Irrigation Load Research data and curtailment
. BPAcredit
. Irrigation Peak Rewards Program
. Irrigation Time-of-Day rates
WHAT AR YOUR CONCLUSIONS AN RECOMMNDATIONS IN THS
I make the following conclusions and recommendations:
. There has been very rapid growth on the system for all customer classes
except the Irrigators' load which has been flat for at least the last 25 years.
2 Yankel, DI
Irrigators
1 The cost of this growth shows up in all aspects of the Company's cost
2 structure; Production, Transmission, and Distribution.
3 . In spite of the lack of Irrigation growth, the Company's cost -of-service study
4 allocates disproportionate amounts of these costs to the Irrigators. Without
5 addressing growth and the cost of growth, all cost of service studies wil
6 continue to inappropriately allocate the cost of growth to the Irrigators and
7 away from the customers that are causing these growth related costs. The
8 Irrigators have inappropriately gotten more than the system average increase
9 for at least the last 14 years. Essentially, without recognizing who causes the
10 cost of growth, the cost of service studies to the Commission in this case and
11 previous cases have attempted to spread the cost of growth "equally", thus
12 harming classes that are not growing and benefiting classes that are growing.
13 The Company's cost of service study in this case continues to not allocate the
14 cost of growth to classes that are causing the growth related cost increases on
15 the system.
16 . If the Company's "Base Case" cost-of-service study were modified to match
17 its marginal cost allocation factors with the growth causing the marginal costs
18 (as opposed to historic usage biling determinants), the rate of
return for the
19 Irrigation class would more appropriately reflect the lack of Irrigation
20 contribution to the system growth and growth related costs. If the impact of
21 growth is recognized, the Irrigation rate of return would be over twice the
22 system average. Based upon a proper matching of the Company's marginal
3 Yanel, DI
Irrigators
1 costs allocation factors with growth (as opposed to historic billng
2 determinants), I recommend no increase in this case for the Irrigators.
3 . The load research data used in this case for the Irrigators does not reflect the
4 curtailments under the Irrigation Peak Rewards Program. This is an oversight
5 due to the newness of the program. This needs to be corrected in future cases.
6 . The Irrigation Peak Rewards Program only partially benefits the Irrigators for
7 the significant benefit it provides the rest of the system. There needs to be a
8 significant increase in the level of the curtailment credits paid. An increase of
9 37 times the existing credits is cost justified.
10 . The Company has let its Irrigation time-of-day program slip away. As an
11 alternative to the Irrigation Peak Rewards program, an Irrigation TOD
12 program could bring significant benefit to the Irrigators as well as the
13 Company. As opposed to abandoning the TOD program, corrections need to
14 be made to the rates and the time periods involved in order to make the TOD
15 program workable for the benefit of all.
16
4 Yane!, DI
Irrigators
1 DISPROPORTIONATE GROWTH ON THE SYSTEM
2 Q.HAS GROWTH ON THE IDAHO POWER SYSTEM BEEN UNORM?
3
4 A.No. For more than two decades there has been a major imbalance in the growth
5 on the Idaho Power system between customer classes.
6
7 Q.UPON WHAT DO YOU BASE YOUR STATEMENT THAT THRE HAS
8 BEEN AN IMALANCE OF GROWTH ON THE SYSTEM?
9
10 A.Even the most casual observer should note that for years there has been strong and
11 persistent growth on the Idaho Power system and that this growth has not occurred in the
12 Irrigation load. This is most easily demonstrated by observing the following graph!:
7,000
6,000
5,000
l 4,000
3,000
2,000
Historic Growth.........................................................................................................................................................................................¡
I, t....:...
Comm. & Ind.
.-.&.,......$-:..
/f,......."f? ,_:::,.,. ,i.r'
..;:::
...-..:'$~..A~/& /.~.,t? _......__88/.:k... .--" ~. .x~/ i!.- i........::::.""~:;. __ø__......w- Residential ii;
. ."", ,t" _lI-.-8''-
.ii$;:i'-I::~::.:...-.:...:.:...::.~.. Jt:..ø.'"
-Irrgation
1,000 ,I I
13
1980 1985 1990 1995 2000 2005
5 Yanel, DI
Irrigators
1 Over the last 25 years, the Irrigation load has been basically flat-decreasing 2%; Residential
2 load has increased 54%; and the combined Commercial/Industrial load has over doubled at an
3 increase of 124%. All customer classes, except the Irrigation class, have caused the phenomenal
4 growth on the Idaho Power system.
5
6 Q.HAS THIS GROWT IN LOAD BEEN ACCOMPAND BY GROWTH IN
7 UTILITY PLANT-IN-SERVICE?
8
9 A.In order to keep up with this growth, there have been significant increases in
10 Plant-In-Service at all functions as demonstrated by the following graph2:
11
Historic Plant in Service1,800
1,600
1,400
0 1,2000Oft1,00000ct'l 800)(ll 600
400
200
............................................................................................................................................................................................................1
/..''-- ~_---.-./ I_..-.- ¡
I..' I" ,.........".. .,., Ii,!!
........'-"................... .. ..... .. i
.. _,/--,,~.--'-1....._...fransmission !
!
--_...._._.._.._..._./
Generation //..r//
.~...._.._.._._._._.__._._~'
./---_..-./Distribution
............-".
d'o'......
..............................(.........~........-. .-.'
::=..:::=......_.............._....--_.__...._....._.._...._._.__.,....
o
1980
I I I I I I
1985 1990 1995 2000 2005
12
1 Historic usage data taken from pages 25, 27, 29, 31 of Appendix A ofldaho Power's 2006 IR.
6 Yankel, DI
Irrigators
i In the last 25 years, Generation plant has increased $768 milion or 93%, Transmission plant has
2 increased $360 milion or 145% (more than doubled its 1981 level), and Distribution plant has
3 increased the most by adding an additional $780 milion or 246% (over tripled its 1981
level).
4 Given the huge percentage growth in Distribution Plant-In-Service and the fact that the
5 absolute dollar magnitude even exceeded that of new Generation plant, it is worthwhile to look at
6 these accounts in more detail:
7
Historic Plant Account Values
350
300
250
00oft 20000Oftor150)(tß
100
50
...'.'..................~..~...............-....¥O'..............................................................n............................'..o'...........n.._........................................................'...................60.......................................
/1/'./Line Transformers
~------------------"
/.//--/------
;'/."'..----------"--
Poles ....................,.... I
,..'~ .." ~.......
.....,..........-..., UG conductoF"/
..... ." "."...,',.,.....,"
...........
........:: .:~__-~~~'.:::::-=-ëïHc;;.;:i;;---
"
....."'.....UG conduit ..... ,0' ..~...
----
_.-.-.-"
.............................."'......................................................
......... .......
.... ..... ........... ............
o ..................;... i
1980
.........N.........................................................
I I I 1 ,I I
1985 1990 1995 2000 2005
8
9 As can be seen from the above graph, the increase in plant in service has occurred in all aspects
10 of Distribution Plant. What is not readily apparent from the above graph is the percentage
11 change in various accounts. The Overhead Conductor account has doubled, while the Poles and
2 Data taken from FERC Fonn 1 for years 1981-2006.
7 Yanel, DI
Irrigators
1 Line Transformer accounts have tripled in the last 25 years. However, the Underground
2 accounts have gone up over 700% of their levels from 25 years ago.
3
4 Q.DOES THE COMPAN'S ALLOCATION METHODS AN COST OF
5 SERVICE STUIES PROPERLY REFLECT THE IMACT OF THESE GROWTH RATES
6 ON COSTS TO CUSTOMER CLASSES?
7
8 A.No. Inappropriately, over the last 25 years or so the Company's cost of service
9 studies have allocated a significant portion of this growth to the Irrigation class. Given the
10 obvious fact that growth and the cost of growth is not being fueled by the Irrigators, the
11 allocation of significant portions of the cost of this growth to the Irrigators is on its face counter-
12 intuitive.
13
14 Q.PLEASE FUTHER EXPLAI HOW THE RESULTS OF THE COMPAN'S
15 CLASS COST OF SERVICE STUDY AR COUNTER-INUITIVE.
16
17 A.As pointed out above, the trend that has been in place for more than two decades
18 is that the non-Irrigation load has increased, while the Irrigation load has either stayed even or
19 decreased. Unlike PacifiCorp which has also been undergoing a tremendous amount of growth
20 over the last 20 plus years, Idaho Power has been deemphasizing the 12 CP allocation method
21 and has been focusing on the growth that has taken place during the summer peaks. The
8 Yanel, DI
Irrigators
1 following lists the annual system peak demand that occurs in July data utilized in both this case
2 and Case IPC-E-94-5 which used a 1993 test year3:
3 Annual System Peak 1993 2007 % Change
4 Irrigation 572,219 609,905 6.6%
5 Non-Irrigation 1,212,428 2,273,905 87.5%
6 As can be seem from above, the changes in load at the time of the single annual system peak are
7 striking. Over the last 14 years, the rate of growth for the non-irrigation customers has been at a
8 rate that is approximately 13 times greater than that for the Irrigators.
9 A similar pattern can be seen with respect to the annual energy consumption:
10 Annual Energy Usage 1993 2007 % Change
11 Irrigation 1,799,035 1,707,083 -5.1%
12 Non-Irrigation 8,867,253 13,077,851 47.5%
13 As can be seem from above, the changes in annual energy usage follow a diverging pattern.
14 Over the last 14 years the Irrigation usage has decreased usage by approximately 5% while Non-
15 Irrigation usage has increased approximately 50%.
16
17 Q.WH IS THIS HISTORIC PRESPECTIVE OF BILLING DETERMANTS
18 IMORTANT?
19
20 A.It has been an often repeated theme of this rate case as well as past rate cases that
21 growth on the system is causing cost increases and the corresponding need to seek rate increases
22 for the customers. As stated by Company President Mr. Keen in this case:
3 The non-irgation data listed for Case IPC-E-94-5 does not include data for FMC.
9 Yankel, DI
Irrigators
1 Q. What does the continued record growth mean to the level of the
2 Company's expenditures?
3 A. Both operation and maintenance and capital expenditures have increased
4 in order to enable us to serve our growing customer base and to reinforce our
5 system reliability.
6 Q. Does the Company project that it will be required to continue to make
7 substantial infrastructure investments over the next three years?
8 A. Yes. The Company's latest forecast shows construction budgets of
9 approximately $266 milion in 2008 and $815 milion for 2008 through 2010
10 combined. Expenditures of this magnitude wil enable the Company to develop
11 new resources and sustain those the Company already has, and to build and
12 upgrade transmission and distribution systems required to serve the Company's
13 customers.
14
15 Given the substantial growth on the Idaho Power system and the cost of that growth, one would
16 expect that the cost of that growth would be borne upon the customers that are causing that
17 growth. Contrary to this premise, the Company's cost of service studies over the last 14 years
18 have proposed to allocate disproportionate increases to the Irrigators in order to pay for the cost
19 of growth of other customers. The following is a listing of the percentage increases recently
20 sought by Idaho Power and the percentages increases that the Company's costs of service studies
25
assigned to the Irrigators:
Overall Increase to
Case No. Increase Irrigators
4 17.68%67.10%IPC-E-03-13
IPC-E-05-285 7.82%27.03%
6 10.35%42.64%IPC-E-07-08
21
22
23
24
26
27 Clearly, these Company cost of service studies have been produced counter-intuitive
28 recommendations with respect to the Irrigation customers.
4 Exlubit 41 page 1 line 233
5 Exlbit 44 page 1 line 53
6 Exlbit 45 page 1 line 53
10 Yankel, DI
Irrigators
1 Q.is TH ALLOCATION METHODOLOGY IN TH COMPAN'S COST OF
2 SERVICE STUDY IN THIS CASE THE SAM AS THAT FROM 14 YEARS AGO?
3
4 A.Generally speaking, yes. There have been some minor changes from 14 years
5 ago, but the allocation methodology used in this case under Exhibit 43 (referred to by the
6 Company as its "Base Case") is similar for the major allocators (DI0, DB, and E1O). If
7 anything, the allocation methodology under the Company's Base Case is more tolerant of
the
8 lack of Irrigation growth than was the allocation methodology used 14 years ago. In spite of
the
9 Company's proposed method in this case being "more tolerant of the lack of Irrigation growth",
10 it is still wide-of-the-mark of fairly allocating the cost of growth to those classes that have been
11 growing.
12
13 Q.HOW DO THE COSTS ALLOCATED TO THE IRGATORS AN OTHER
14 CUSTOMERS IN THIS CASE, COMPARD TO TH COST OF SERVICE STUDY
15 PROVIED 14 YEARS AGO, REFLECT THE LACK OF GROWTH OF THE IRGATION
16 CLASS AN THE SIGNIICANT GROWTH IN OTHER CUSTOMER CLASSES?
17
18 A.A comparison of the level of costs allocated to Irrigators in this case with those
19 allocated 14 years ago, demonstrates the counter-intuitive nature of
these studies when growth
20 and the cost of growth is not addressed in the allocation factors. A comparison of the allocated
21 Production rate base between this case (IPCo's "Base Case") and the case 14 years ago reveals
22 the following:
11 Yankel, DI
Irrigators
1 Production7 (x$1000)1993 2007 % Change
2 Irrigation $164,667 $226,680 37.7%
3 Non-Irrigation $847,877 $1,450,689 71.1%
4 Under the Company's allocation method, the percentage of new Production plant attributed to
5 Irrigators (whose load has been virtually stagnant) is approximately half the percentage increase
6 that has been allocated to all of the customer classes that have been experiencing rapid growth.
7 The counter-intuitive nature of the Company's allocation methods with respect to this
8 lopsided growth are even better observed with respect to the rate base associated with
9 Transmission plant. A comparison of the allocated Transmission rate base between this case
10 (IPCo's "base case") and the case 14 years ago reveals the following:
7 1993 data comes from Case No. IPC-E-94-5, Company Exliibit 32, pages 3 and 4. The 2007 data comes
from Case No. IPC-E-07-08, Company Exliibit 46 (base case), page 3.
12 Yanel, DI
Irrigators
1 Transmission8 (x$lOOO)1993 2007 % Change
2 Irrigation $41,271 $ 87,612 112.3%
3 N on-Irrigation $207,152 $537,748 159.6%
4 In spite of the fact that the overall energy usage of the Irrigators has been on the decline and their
5 growth in contribution to the annual system peak has been virtually non-existent in comparison
6 to the other customer groups, the Company's allocation method is giving Irrigators
7 approximately the same percentage increase in new Transmission plant that it is giving all other
8 customer classes.
9 The counter-intuitive nature of the Company's allocation methods with respect to this
10 lopsided growth can also be observed with respect to the rate base associated with Distribution
11 plant. A comparison of the allocated Distribution rate base between this case (IPCo's "base
12 case") and the case 14 years ago reveals the following:
13 Distribution9 (x$lOOO)1993 2007 % Change
14 Irrigation $105,394 $183,596 74.2%
15 Non-Irrigation $425,080 $988,935 132.6%
16 Once again, in spite of the fact that the overall energy usage of the Irrigators has been on the
17 decline and their growth in contribution to the annual system peak has been virtually non-
18 existent in comparison to the other customer groups, the Company's allocation method is giving
19 Irrigators approximate half of the percentage increase in new Distribution plant that it is giving
20 all other customer classes. One would expect only a small amount of
this growth in Distribution
21 plant went to serve Irrigation customers.
8 1993 data comes from Case No. IPC-E-94-5, Company Exhibit 32, pages 3 and 4. The 2007 data comes
from Case No. IPC-E-07-0S, Company Exhibit 46 (base case), page 3.9 1993 data comes from Case No. IPC-E-94-5, Company Exhibit 32, pages 3 and 4. The 2007 data comes
from Case No. IPC-E-07-oS, Company Exlubit 46 (base case), page 3.
13 Yanel, DI
Irrigators
1
2 Q.WAS THE WORKSHOP THAT WAS INTIATED AS A RESULT OF THE
3 2003 CASE ABLE TO COME TO AN CONCLUSIONS REGARING THE TREATMENT
4 OF THE ALLOCATION OF TH COSTS ASSOCIATED WITH THIS GROWTH?
5
6 A.Although there was general consensus among the workshop participants on a
7 number of issues, the only agreement regarding the treatment of growth in the Company's cost of
8 service study is that there is a disconnect between the classes that were growing and causing the
9 costs to be incurred and the allocation of those costs. Regarding whether new growth was
10 properly covering its cost of service, "The Parties' Final Report in IPC-E-04-23" stated:
11 Most of the workshop time was devoted to discussion of this issue. The parties
12 agreed that there was something inherently troubling with the way costs,
13 associated with growth. were allocated. This is evidenced by the relatively large
14 increase in revenue reQuirement allocated to customers whose load and energy
15 reQuirements were unchanged or grew only slightly. While there was agreement
16 that the cost of growth did not necessarily get allocated to the customer classes
17 that grew. we were unable to devise a technical remedy to the allocation
18 procedure that would also satisfy the courts. The parties were unable to devise
19 and agree to a cost-of-service allocation methodology that would properly allocate
20 the cost of growth, without making a distinction between new and old customers.
21 Even a search of what others, around the country, were doing produced little in
22 the way of an acceptable solution. Therefore, it was concluded that the only
23 remedy is a policy solution. The parties were not wiling to agree to the
24 particulars of such a policy and recommend that the Commission formulate such a
25 policy in the next rate proceeding. (Emphasis added)
26
27 Q.WERE THE WORKSHOP PARTICIPANTS ABLE TO DEVELOP A
28 CONSENSUS POSITION THAT DEFIND TH COST IM ACTS OF GROWTH?
29
30 A.No. As pointed out above, the workshop participants were not able to develop a
31 consensus method for allocating the cost of growth in a manner that was acceptable to all parties.
14 Yanel, DI
Irrigators
1 The problem with attempting to develop a consensus was recognized by various participants at
2 the workshop. Although there was general consensus that there was something inherently very
3 wrong with the present allocation scheme as related to its ability to allocate the cost of growth,
4 no one felt that they could go back to their clients and admit that they agreed to a methodology
5 that would cost their client more money-this decision was left to the Commission.
6
7 Q.DOES THE COMPAN'S APPROACH TO RATEMAKG AN COST
8 ALLOCATION ATTEMPT TO REFLECT COSTS?
9
10 A.That is the Company's stated goal, although that may not be the result. The
11 classification and allocation used by the Company, only looks at half ofthe cost causation
12 equation-it assumes a steady state situation or one with even growth across all classes. The
13 NARUC Electric Utility Cost Allocation Manual makes a general statement that is right on target
14 in this situation:
15 The common objective of the methods reviewed in the following two
16 parts is to allocate production plant costs to customer classes
17 consistent with the cost impact that the class loads impose on the
18 utility system. (emphasis added)lO
19
20 As a general statement, I believe all parties would agree with this NARUC policy. As
21 demonstrated above, there has been a tremendous amount of growth on the system over the last
22 25 years with associated costs to support that growth. For all practical purposes, the Irrigators
23 have not participated in that rapid growth. However, as has been demonstrated above, the
24 Company's present cost of service studies do not address the disproportionate cost of growth
25 and. thus. do not accomplish this goal.
15 Yanel, DI
Irrigators
IÕ"
-'~:4':.~;~ .
i
2 Q.is THE COMPANY ADVOCATING THE SAME GENERAL ALLOCATION
3 METHODOLOGY IN THIS CASE AS ITDID OVER THE PAST 14 YEARS?
4
5 A.'No. Although the Company provided as its Base Case an allocation methodology
6 that is similar to what it has proposed in the past, it is favoring a new classification/allocation
7 method in this case. The results of the Company's Base Case are contained in Mr. Tantum's
8 Exhibit 45. The new method favored by MI'. Tanitu and the Company, classifies/allocates
9 Production costs based upon function (base, intermediate, and peak) during the three summer
10 months. The results of the Company's preferred method are contained in MI'. Taiitum's Exhibit
11 53. The Company is not proposing any changes to its Transmission, Energy, or Distribution
12 allocators. Thus, there is very little overall change.
13
14 Q.is THE NEW ALLOCATION METHOD ADVOCATED BY THE COMPANY
15 FOR PRODUCTION RELATED COSTS AN IMPROVEMENT OVER THE PAST :M:ETHOD
16 THAT IT ADVOCATED?
17
18 A.No. This method only addresses Production cost and it stil suffers from the same
19 shortcomings as the Company's past studies-it allocates costs on a stagnant basis, with no
20 recognition of the impact of growth on costs.
21
10 Electric Utility Cost Allocation Manual, published by the National Association of Regulatory Utilty
Commissioners 1992 at page 39.
16 Yankel, DI
Irrigators
1 Q.DOES THE COMPAN BASE CASE ALLOCATION METHODOLOGY
2 RECOGNIE THE NEED TO RECOGNIE GROWTH IN ITS ALLOCATION
3 METHODOLOGY?
4
5 A.Although the Company's Base Case allocation methodology falls short of
6 recognizing the disparity of growth on the system, it has been stated that it is the Company's
7 intention to do so. In Case IPC-E-05-28 Company witness Brilzll offered the following with
8 respect to the Company's thoughts regarding the Base Case methodology:
9 Q. What is the reasoning for using marginal cost weightings in the derivation of
10 the demand-and energy- related allocation factors?
11
12 A. The use of marginal cost weighting is intended to strike a balance between
13 backward-looking costs already incurred and forward-looking costs to be incurred14 in the future.
15
16 The exact same language appears in Mr. Tatum's testimony in this case12. The intent is
17 appropriate-the execution falls short of the goal.
18 The balance between historic and forward looking costs that is struck in the Company's
19 study is 50% based upon an unweighted 12-CP allocation that is designed to reflect today's share
20 of cost causation on the system13. The other 50% of the allocation factor purports to reflect
21 forward-looking costs and this is where the major disconnect occurs. The Company
22 inappropriately defines forward-looking costs using the same test-year 12-CP usage
23 characteristics (present day usage) and combines it with marginal weighting factors that reflect
24 "forward-looking costs to be incurred in the future" in order to meet growth. Thus, the Irrigators
25 (as well as all classes) get assigned costs, based upon weighting factors designed to reflect
ii Case No. IPC-E-05-28, witness Brilz at page 19.
I:! Tatum's testimony in t1us case, page 25, line 10
17 Yanel, DI
Irrigators
1 growth that is going to be incurred by the System in the future, but not based upon the
2 usage/growth that is going to create those costs. Thus, unrealistic results occur where the
3 Irrigation load is stagnant/decreasing, but the cost of the system growth is being assigned to it.
4 not based upon future growth of the Irrigators, but based upon the present usage of the Irrigators.
5
6 Q.HOW COULD THE COMPAN'S BASE CASE ALLOCATION
7 METHODOLOGY BE BETTER ALIGNED TO REFLECT "BACKWAR-LOOKIG COSTS
8 ALREADY INCURD AN FORWAR-LOOKIG COSTS TO BE INCURD IN THE
9 FUTUR"?
10
11 A.The simplest way to correct the Company's Base Case study would be to continue
12 to define "backward-looking costs" based on test year usage levels and "forward-looking costs"
13 at the anticipated increase in usage levels in the Company's IR. The "backward-looking costs"
14 would simply be costs as they exist today and allocated on the basis oftoday's energy or 12-CP
15 as is presently done in the Company's cost of service study. The "forward-looking costs" would
16 be based upon the same weighting factors developed by the Company associated with the cost of
17 growth anticipated, but would be allocated on the basis of only the growth that is anticipated
18 from each rate schedule over the next ten years. The relative share of
historic costs and
19 anticipated costs related to growth would then be averaged using the Company's existing
20 procedure in order to develop a composite allocation factor for use in spreading test year costs
21 for allocation purposes. In this manner, the methodology would be exactly the same as the
13 For puroses oftlus discussion, I accept tlus part oftlie Company's metliod. However, tlus approacli
ignores tle lopsided grm\'1li tlmt lias taen place for over two decades on tlie system.
18 Yankel, DI
Irrigators
1 Company's Base Case, but the marginal costs would be tied to the marginal usage and not to the
2 present level ( status quo) of usage.
3
4 Q.HOW COULD THE CHAGE THAT YOU PROPOSE BE IMLEMENTED
5 TO THE COMPAN'S COST OF SERVICE STUY IN ORDER TO INSUR THAT THESE
6 COUNR-INTUITIVE RESULTS DO NOT OCCUR IN THE FUTUR?
7
8 A.One very simple change could be made. Instead of combining the Company's
9 growth related weighting factors with existing biling determinants, they could be combined with
10 forecasted growth-making an apples-to-apples comparison.
11 The Company's 2006 IR that served as a basis for developing the weighted cost factors
12 can also serve as the source of the data for the forecasted growth as welL. In Exhibit 301, I have
13 simply modified the Company's allocation weighting procedure to apply the marginal cost
14 weightings developed by the Company to only the growth that is expected over the next ten
15 years14. For example, the Company's Exhibit 47 page 1 takes the May normalized demand for
16 the Residential class of751,370 and multiplies it by a weighting of 14.33 in order
to develop a
17 weighted demand of 10,767,13515. The original figure of751,370 is a test year value and not
18 reflective of the growth that will take place on the system. According to the Company's 2006
19 IR16, the average load for the Residential class will increase from 4,865,000 to 5,811,000 biled
20 MWh or 19.45% between 2006 and 2016. The Company's biling unit of751,370 needs to be
14 A ten year grO,"'1h horizon was chosen to give some stabilty to the nnmbers without forecasting out so
far that reliabilty concerns would be raised. Although a five year gro\\1h horizon would have produced
more beneficial allocators for the Irgators, it was felt that a ten year growth horizon would be preferable.15 75U70 X 14.33 = 10,767.135
16 Idal~o Powers 2006 ff--Sales and Load Forecast page 26.
19 Yankel, DI
Irrigators
1 modified in order to reflect the fact that only 19.45% of
this figure wil be associated with the
2 cost of growth over the next ten years.
3
4 Q.DID YOU PROPOSE THIS MECHASM AS A MEANS OF REFLECTING
5 THE COST OF GROWTH TO THE WORSHOP IN CASE IPC-E-04-23?
6
7 A.No. The proposal I made to the Workshop was one that looked backward and
8 tried to capture the amount of growth and the cost of growth that took place over the previous 25
9 years. The Workshop was not able to come to an agreement regarding that proposed
10 methodology as a means of properly allocating the cost of growth. The methodology that I am
11 proposing here is forward looking and it match future marginal costs with future growth.
12
13 Q.WHAT GROWTH PERCENTAGES DID YOU INCORPORATE INTO YOUR
14 REVISION OF THE COMPAN'S BASE CASE COST OF SERVICE STUDY?
15
16 A.
17 calculated:
18
19
20
21
22
Based upon the Company's 2006 IR17, the following growth percentages were
Residential 19.45%
Commercial (Sch. 7, 9, 40, 42)30.04%
Industrial (Sch. 19)27.24%
Irrigation 1.03%
Special Contracts 9.38%
17 Idaho Powers 2006 IR-Sales and Load Forecast pages 26-36
20 Yankel, DI
Irrigators
1 I utilized these percentages as the basis for calculating the amount of growth (beyond test year
2 billng determinants) associated with the Generation and Transmission plant (allocators D10,
3 DB, and EI0). I made no calculation to reflect the growth in Distribution plant that is larger
4 than the growth in either Generation or Transmission plant.
5
6 Q.WHAT is THE IMACT ON THE COMPANY'S BASE CASE COST OF
7 SERVICE STUDY WHN ITS GROWTH RELATED WEIGHTING FACTORS AR
8 APPLIED TO FORECAST GROWTH AS OPPOSED TO HISTORICIPRESENT USAGE AN
9 HOW DO THOSE RESULTS COMPAR WITH THE BASE CASE STUY IN THE
10 COMP AN FILING?
11
12 A In spite of the fact that this change is only directed at 50% of the allocation factor,
13 as can be seen from Exhibit 302, there is a major difference between the indexed rates of return
14 that result from using weighting factors that are properly aligned with expected growth,
15 compared to the Company's Base Case study that does not link marginal cost weighting factors
16 with growth. The indexed rates of return for the major rate schedules are summarized below:
17 Study Res. Sch. 9 (s)Sch. 19 Irr.
18 Growth Corrected 1.346 0.219 0.142 2.564
19 Company's Base Case 1.315 1.039 0.817 0.295
20 Although the difference between these two cost of service runs is quite large for some rate
21 schedules, it should come as little surprise. It has been well recognized by virtually all parties
22 that the Company's present allocation method does not properly address the cost of growth and
21 Yanel, DI
Irrgators
1 the fact that for at least twenty-five years the Irrigators have been getting saddled with costs that
2 they have not placed upon the system.
3 By way of contrast, the Growth Corrected study follows more intuitive logic. The growth
4 on the system over the last two-plus decades has not been even across all classes. Irrigation load
5 has been virtually flat, Residential load has increased rapidly, but not as rapidly as Commercial
6 and Industrial load. Given the growth in average system load18 of20.7% that is predicted over
7 the next ten years in the 2006 IR, any rate group that would be growing less than the average
8 should be getting a smaller share (compared to its size) of
the marginal costs, while those
9 growing faster should get a higher percentage. The Irrigation growth is very low and Special
10 Contract growth is less than the average, so this Growth Correction increases the rate of return
11 for those classes over that produced by the Company's Base Case study. Residential growth is
12 about the system average, so there is little impact of
using the Growth Corrected method
13 compared to the Company's Base Case. The Commercial and Industrial load growth is above
14 average system growth so the Commercial and Industrial customers rate of return is lowered.
15 Given the fact that the Corrected Growth cost of service run recognize~ the link between growth
16 and the growth related weighting factors, the resulting indexed rates of
return are quite logical:
17 . The Residential growth rate is somewhat less than the system average; therefore, the
18 indexed rate of return goes up a little when compared to the Normalized study.
19 . The Commercial growth rate is significantly above system average; therefore, the
20 indexed rate of return for Schedule 9 significantly drops when compared to the
21 Normalized study.
18 Idaho Powers 2006 IR Sales and Forecast at page 36 shows sales in 2016 of 16,817 GWli compared to
13,938 GWh in 2006 for a dierence of20.7%.
22 Yanel, DI
Irrigators
1 . The Industrial growth rate is above system average (but not as much as Commercial);
2 therefore, there is a substantial drop in the indexed rate of return for Schedule 19 when
3 compared to the Normalized study.
4 . The Irrigation growth rate is essentially non-existent; therefore, the indexed rate of return
5 goes up a great deal when few of the growth related costs are allocated to it compared to
6 the Normalized study.
7
8 Q.DO THE RESULTS OF TH COST OF SERVICE STUDY IN EXHIT 302
9 REFLECT THE GROWTH DIFFERENTIAL THAT is ASSOCIATED WITH THE
10 DISTRIUTION SYSTEM?
11
12 A.No. Exhibit 302 only reflects changes to the Company's cost of
service study to
13 reflect growth on the Generation and Transmission system. Over the last 25 years, the growth in
14 Plant-in-Service associated with the Distribution system has been greater than both the
15 Generation and Transmission system. A methodology needs to be adopted for addressing the
16 growth on the Distribution system as well. It should be remembered that not only have the
17 Irrigators had very little impact for the past 25-plus years on the cost of
the Company's
18 distribution plant, the Irrigators have virtally nothing to do with the costs associated with the
19 Company's Underground Distribution costs.
20
21 Q.HOW SHOULD THE RESULTS OF EXHIT 302 BE UTILIZED FOR
22 PUROSES OF THIS CASE?
23
23 Yankel, DI
Irrigators
1 A.The issue of addressing growth in the Company's cost of service study is a new
2 direction for the Commission, and one that generally has not been faced by other commissions
3 across the country. As the Final Report in the IPC-E-04-23 Workshop recognized, there is
4 "something inherently troubling with the way costs, associated with growth, (is) allocated." As
5 recognized at the Workshop, the cost causation of growth is indisputable and the lack of growth
6 on the part of the Irrigators is indisputable as well. Recognizing that the Commission moves
7 cautiously (but deliberately) in these matters, I recommend that Exhibit 302 be used to generally
8 direct the Commission's ordered rate spread in this case.
9
10 Q.BASED UPON THE GENERA RESULTS OF EXHIT 302, WHT
11 PORTION OF THE RATE INCREASE IN THIS CASE DO YOU RECOMMND FOR THE
12 IRGATORS?
13
14 A.Over the last several rate cases, the Irrigators have been given the same or a
15 higher percentage increase than the system average. These increases have been given because
16 the Company's cost-of-service studies have never addressed the disproportionate growth and
17 associated costs between the classes. The following represents a brief picture of the increases
18 that have been given to the Irrigators because this disproportionate growth and cost causation has
19 not been recognized:
20 Case # Order # Ave. Increase Irrigation Increase
21 05-28 30035 3.20%3.20%
22 03-13 29505 5.20%13.95%
23 94-05 25880 4.19%10.23%
24
24 Yankel, DI
Irrigators
1 Over the last 10-plus years, the Irrigators have gotten well over the average rate increase, in spite
2 of the fact that they have not been causing the growth and the need for the rate increases on the
3 system. Based upon the greater than average increases which have been given to the Irrigators in
4 the past and the results of the simple correction/alignment of marginal costs with the growth
5 causing those costs which demonstrates19 that the Irngators should be given a 33.8% decrease in
6 rates; I recommend that the Irrigators be given no increase in this case. I recommend that the
7 Residential class be given the average rate increase, and that Schedules 9 and 19 be given larger
8 than average increases.
19 Exhibit 302 line 43
25 Yankel,DI
Irrigators
. ~.~~.:...-.-
1 IRRGATION LOAD RESEARCH DATA AND CURTAILMENT
2 Q.DOES THE COMPAN'S LOAD RESEARCH DATA IN TilS CASE
3 EFFECTIVELY CAPTURE THE IMPACT OF THE IRGA nON PEAK REWARDS
4 PROGRA?
5
6 A.No. Although the Company has made progress in a number of areas regarding the
7 utilzation of its load research data, its abilty to adequately incorporate the Inigation Peak
8 Rewards Program (curtailments) into this data is severely deficient. Because the Inigation
9 cuitailments are completely under-represented, the load research data that makes its way to the
10 Company's cost of service studies; significantly over~al1ocates peak responsibilty to the
11 Irrigators. There are three basic areas where this data is deficient:
12 . The Company is now utilzing the median ofthe past five years of data to define the
13 monthly coincident load factor for each rate schedule. The Irrigation Peak Rewards
14 Program has not been around that long. Therefore, the use of a 5-year median (although
15 conceptually sound), is not reflective of the results of a rapidly developing program.
16 . The curtailment customers in the load research data do not represent an acceptable cross-
17 section of those participating in the progrm, and ultimately; under-represent the
18 cuitailments tag place.
19 . As it tums out, some of the customers in the load research sample that were iiivolved in
20 the curtailment program in 2006 were (for some reason) not interiupted at various times;
21 thus, under-valuing the impact of the curtailment that should have taken place.
22
26 Yaiikel, DI
Irrigators
1 Q.HOW DOES TH FACT THAT THE CURTAIMENT PROGRA HAS NOT
2 BEEN IN EXISTENCE FOR FIVE YEARS IM ACT THE WAY THAT THE COMPANY
3 DEVELOPS ITS COINCIDENT PEAK DEMAN DATA?
4
5 A.The Company has recently adopted a procedure where it uses the median monthly
6 load factors from the previous five years of load research data in order to derive its
7 normalized monthly peak demands for cost allocation purposes. I fully agree with this
8 approach, except in the case where there are known changes to the overall data being
9 collected. The introduction of, and increasing paricipation in, the Irrigation curtailment
10 program will greatly skew the monthly coincident load factor data being collected. The data
11 from 2006 should represent an entirely different situation than that from 2002 when the Peak
12 Rewards program did not exist.
13
14 Q.PLEASE EXPLAI WHY THE CUSTOMERS IN THE COMPAN'S LOAD
15 RESEARCH DATA DO NOT REPRESENT AN ACCEPTABLE CROSS-SECTION OF
16 THOSE PARTICIPATING IN THE CURTAIMENT PROGRA.
17
18 A.The Company's response to lI A Request 3-3 states:
19 The company does not have a statistical
load research sample specific to Schedule
20 23. However, to monitor and spot-check the performance of
the Irrigation Peak
21 Rewards Program, some interval meters were installed. ... Since these meters are
22 not par of a statistical sample, stratum weighting factors do not apply.
23
24 Out of the 145 Irrigators in the Company's load research study, the Response to lIP A Request 3-
25 1 lists 21 load research customers as being on the curtailment program. Two of these 21
26 customers had no energy listed during any hour of
the curtailment timeframe: June, July, and
27 Yankel, DI
Irrigators
1 August. The following depicts how these 19 sampled customers were curtailed each day of the
2 week and how large their combined load was:
3 Customers MW
4
5
6
7
8
9
10
Monday
Tuesday
Wednesday
Thursday
Friday
2
10
2
6
3
0.2
6.4
0.4
2.4
1.9
According to the Company's 2005 report20 on its Irrigation Peak Rewards program, the
11 scheduled curtailments on Tuesdays, Wednesdays, and Thursdays was approximately 2.5 times
12 greater than that scheduled for Monday's and Fridays. It is obvious from a review of
the above
13 load research data that the 19 sample customers were not representative of
this overall
14 distribution of the curtailments that took place by day of the week.
15 Of even more concern is the fact that during June the system coincident peak occurred on
16 a Tuesday, but it occurred on a Monday for both July and August. For all practical purposes,
17 there was essentially zero representation of participating load curtailment in the load research
18 data for Mondays. It is not that load was not curtailed on these Mondays, it is that the load
19 research data does not reflect what was curtailed.
20
21 Q.YOU INICATED THAT SOME OF THE CUSTOMERS IN THE LOAD
22 RESEARCH SAMLE THAT WERE INOLVED IN THE CURTAIMENT PROGRA IN
23 2006 WERE (FOR SOME REASON) NOT INERRUPTED AT VAROUS TIMS; THUS,
24 UNER VALUIG THE IM ACT OF THE CURTAIMENT THT SHOULD HAVE
2S TAKN PLACE. PLEASE ELABORATE.
20 December i, 2005 Irgation Pea Rewards progrm page i i, Table 6
28 Yanel, DI
Irrigators
1
2 A.There are instances21 in both the load research data and the Schedule 23 load
3 profie data where customers should have been curtailed, but the data does not show a
4 curtailment. For example, load research customer 62400025 was supposed to be curtailed on
5 Tuesdays, but had a load of 366 kW during the hour of the June coincident peak. The data
6 demonstrates that this customer is normally curtailed on Tuesdays, but for some reason or other
7 there is usage data listed during the time of this monthly coincident peak when there should have
8 been a curtailment.
9
10 Q.DO YOU HA VB SPECIFIC RECOMMNDATIONS REGARING THE
11 GATHERIG AN USAGE OF LOAD RESEARCH DATA FOR THE IRGATION CLASS
12 IN THIS CASE?
13
14 A.Generally, I believe the Company has been working hard to collect reliable load
15 research data. However, the Irrigation Load Curtailment program is a new twist that will need
16 better scrutiny in the future in order to extract reliable data. I point out the above problems so
17 that they can be addressed before the Company's next case and to add support to my proposal
18 that the Irrigators be given no increase in this case.
21 See the Company's Response to IIPA 3-3
29 Yanel, DI
Irgators
1 BPA Credit
2
3 Q.WHAT is THE IM ACT OF THE RECENT LOSS OF THE BPA CREDIT ON
4 TH IRGATION CUSTOMERS?
5
6 A.According to the Company, the BPA credit for Irrigators22 in 2006 'fing was
7 $1,917,264. By comparison, the revenue from Schedule 10 was only listed23 as $70,750,659.
8 Thus, the Irrigators effectively paid only $68,833,39524. Absent any increase in this case to the
9 Irrigators, their effective rate will jump $1.9 milion or 3% above what they have been paying.
10 Although such a rate increase may appear to be small, it is an additional cost burden that
11 Irrigators wil be facing. The Residential class has also lost its BP A credit25 of $16,246,281.
12 Out ofa total revenue of$294,087,612 in 2006, the Residential customers effectively paid
13 $277,841,331. Thus, the Residential customers are facing an approximate 6% increase, absent
14 anything that happens in this case.
15 Although these losses cannot be directly off-set in this case, the Commission needs to
16 establish cost-effective ways for customers to help themselves and the Company better control
17 overall costs. For the Irrigators, the best way to accomplish this would be to put in place an
18 effective Peak Rewards program and/or an effective time-of-day rate.
22 Company Response to IIPA Request 4-2
23 Company Exlubit 58, page 1
24 $70,750,659 _ $1,917,264 = $68.833395ry~ .' .' .'-- Company Response to IIPA Request 4-3
30 Yanel, DI
Irgators
1 IRRIGATION PEAK REWARDS PROGRAM
2 Q.AR THE IRGATORS SUPPORTIVE OF THE COMPANY'S IRGATION
3 PEAK REWARS PROGRA?
4
5 A.Yes. The Irrigators have been very supportive of this program as well as the one
6 offered in the PacifiCorp service area that interrupts electricity to irrigation pumps during the
7 summer super-peak hours. The Irrigation Peak Rewards Program is a workable program that
8 produces tangible benefits for the Company as well as all ratepayers.
9
10 Q.DO THE IRGATORS FULLY AGREE WITH HOW THE IRGATION
11 PEAK REWARS PROGRA IS BEING IMLEMENTED?
12
13 A.No. Although the Irrigators are very supportive of the program in general, there
14 are a number of areas where the Irrigators believe that substantial improvements can be made.
15 The Irrigators believe that a general rate case is an appropriate time and place to review matters
16 related to specific rate schedules such as the Company's Schedule 23.
17
18 Q.PLEASE GIVE A BRIF OVERVIW OF THE EXISTING IRGATION
19 LOAD CONTROL PROGRA ON THE IDAHO POWER SYSTEM.
20
21 A.At present Schedule 23 is the main DSM type vehicle for Irrigators which consists
22 offixed/pre-scheduled times and days for interrptions of
Irrigation load. Under Schedule 23,
31 Yanel, DI
Irrigators
1 Irrigators are interrpted for 4-hours on either 1,2, or 3 days per week during the months of
2 June, July, and August. The present monthly credits are as follows:
3
4
5
6
7
1 day per week
2 days per week
3 days per week
$2.01 /kW month
$3.36/kW month
$4.36/kW month
The total annual credit (assuming that an Irrigator operates each of
the three months) is:
8
9
10
11
1 day per week
2 days per week
3 days per week
$ 6.03/kW-year
$10.08/kW-year
$13.08/kW/-year
12 Q.HAS THE IRGATION CURTAIMENT PROGRA UNER SCHEDULE
13 23 ENJOYED A GREAT DEAL OF SUCCESS?
14
15 A.Success is a relative measure. According to the Company's July 23,2007 press
16 release, there was a reduction of 40 MW during the Fourth of July holiday when temperatures
17 reached triple digits. This level of curtailment may seem significant, but when compared to the
18 Irrigator's 2007 projected contribution to the July system peak of
over 600 MW, this 40 MW
19 seems small. Although there may be a number of factors causing this program to only produce a
20 relatively small reduction in peak load, these factors generally boil-down to a simple question of
21 economic incentive.
22 It should be noted that this 40 MW' s is the same figure mentioned in the Company's
23 2006 IR26 regarding the reduction in peak load during 2005-suggesting that there has not been
24 a major change in participation since its first year of operation in 2005. However, there was an
25 increase in some of the participation credits between 2005 and 2007. For example, the credit for
26 the I-day/week option stayed the same at $2.01/ kW, but the 2-day/week option credit increased
32 Yankel, DI
Irrigators
1 from $2. 52/kW up to $3.36/kW (an increase of33%), and the 3-day/week option credit increased
2 from $2.76 up to $4.36/kW (an increase of 58%).
3 Two things should be gleaned from this credit and curtailment information. First, the
4 impact of the program was low in the program's first year of operation (2005) with 40 MW of
5 peak reduction occurring and that impact has changed little with a reported 40 MW (out of 600
6 MW ofIrrigation load) of system reduction in 2007. The Irrigation Peak Rewards program can
7 be a great benefit to the system, its customers, and to the Irrigators. However, it is being
8 underutilized. The level of the credit (economic incentive) is the primary reason for this lack of
9 participation.
10 Second, even assuming that the credit for the I-day/week option is appropriate, the
11 increases of33% and 58% to the 2-day/week and 3-day/week options were completely
12 inadequate to reflect an appropriate credit for these multiple day options. If an Irrigator should
13 be paid $2.01 for curtailing 1 kW of demand I-day per week, he should be paid at least twice
14 that amount if he curtails twice as often. It should be "at least twice that amount" because there
15 are no further hardware, installation, administrative, or other costs getting the Irrigator to be
16 interrupted on 2-days/week as opposed to just I-day/week. This cost savings should be passed
17 on as an additional incentive in order to get more participants. However, instead of
being offered
18 a credit of$4.02/kw for interruptions on 2-days/week, the Company offers only $3.36/kW. The
19 3-day/week option credit is even worse (in spite ofthe 58% increase that it has received since
20 2005). The 3-day/week option offers three times the interruptions as the I-day per week option
21 and so it should have a credit of at least $6.03/kW. However, the Company is only offering a
22 credit of $4.36/kW. One needs to ask why any customer would opt for being curtailed on
26 Appendix B-Demand Side Maagement 2005 Anual Report, page 9.
33 Yanel, DI
Irigators
1 multiple days when the amount of credit per curtailment decreases. The present credit structure
2 represses, as opposed to promotes, additional participation.
3
4 Q.is THE PRESENT CREDITS LISTED UNER SCHEDULE 23 FOR THE 1-
5 DAYIWEK OPTION APPROPRIATE?
6
7 A.No, from two perspectives. First, as demonstrated above, although there have
8 been increases in the level of the credit paid, participation (as measured by overall curtailment) is
9 not strong. Basically, there is an interest in the program on the part of the Irrigators, but they are
10 either finding a cost/benefit ratio that is very low or one where costs exceed the benefit (credit).
11 From a policy standpoint, it makes little sense to offer programs that have only marginal or no
12 benefits to the customers.
13 Second, in a recent report regarding DSM Resources that was prepared for PacifiCorp, it
14 was demonstrated that the benefits of the Irrigation Load Curtailment program (mostly in its
15 Idaho service area) far exceeds the costs associated with that program (even under the Report's
16 assumption of a $20 per year credit being paid). From a policy standpoint, it is inappropriate to
17 have a DSM type resource with such a large advantage to the system being under utilized by the
18 customers because the credit being paid is such a small fraction of the benefit being realized.
19
20 Q.PLEASE ELABORATE ON THIS DSM REPORT FOR PACIFICORP.
21
22 A.On July 11, 2007 Quantec issued its Report to PacifiCorp entitled
23 "Assessment of Long-Term, System-Wide Potential for Demand-Side and Other
34 Yanel, DI
Irrigators
1 Supplemental Resources". This Report was designed to (and virtually did) cover all
2 aspects ofDSM or alternative resources. Relevant pages regarding the Irrigation
3 Curtailment program are contained in Exhibit 303. The Irrigation Load Curtailment
4 program was viewed as one of only three "firm" DSM options that represent a Class 1
5 resource. Of these three Class 1 options, the Irrigation Load Curtailment program had the
6 lowest costs per unit of avoided capacity and in fact these costs were calculated to be less
7 than half of the cost of the next closest option (direct load control of air conditioners).
8 The Irrigation Load Curtailment program was calculated to have a levelized cost of
9 $47/kW-year (based upon a $20/kW-year credit) compared to an avoided cost of capacity
10 in the Rocky Mountain Power region of$98/kW-year.
11
12 Q.HOW APPLICABLE TO IDAHO POWER IS THAT REPORT'S AVOIDED
13 CAPACITY FIGUR OF $98IKW-YEARFORROCKY MOUNTAI POWER?
14
15 A.Although these are different utilities, they operate in the same general market, and
16 in this case, both operate in southern Idaho. Based upon Lamont Keen's testimony in this case
17 (page 4), IPCo is pursuing the addition of the following resources:
18
19
20
21
22
23
24
25
170 MW Simple Cycle CT
100MWWind
50 MW Geothermal
Expansion ofDSM
Residential Existing Const.
Commercial Existing Const.
Industrial Effciency
$/kW-month27
$5.53
$16.40
$33.68
$/kW-year
$69
$197
$404
$5.34
$10.15
$10.26
$64
$122
$123
'27 Levelized cost of generation taken from IPCo's 2006 IRP, Appendix D, page 59. Levelized DSM costs
taken from IPCo's 2006 IR, pages 67 and 68.
35 Yankel, DI
Irrigators
1 Based upon these options that IPCo is pursuing, the $98/kW-year figure is a good representation
2 of the avoided cost of a program like the Irrigation Peak Rewards program.
3
4 Q.WHAT HAS BEEN TH COST OF THE IRGATION PEAK REWARS
5 PROGRA?
6
7 A.There has been very little information published regarding IPCo's program by
8 comparison to the annual reports produced by PacifiCorp regarding its program. IPCo's 2006
9 IR indicates28 that in the first full year of operation (2005) that $1,468,000 was spent and 40.3
10 MW of summer peak demand was saved. Of this amount $479,484 was associated with program
11 costs (equipment, installation, advertising, and administrative), while the remainder was paid out
12 in incentives/credits.
13 In spite of the fact that the first-year costs would have included a number of start-up and
14 non-reoccurring costs, the program costs (not including incentive/credit payments) of
$479,000
15 worked out to only $1 1. 89/kW-year29 of summer peak demand savings. Effectively, this leaves
16 another $86/kW-year ($98 - $12 = $86) of avoided cost savings that could be used as credits to
17 pay Irrigators for the benefit they provide to the system and to induce significantly more
18 participation.
19 The total coseo of the incentive paid in 2005 to obtain this 40.3 MW reduction in summer
20 peak demand was $988,798, which averages out to $24.54/kW-year31 of
peak reduction realized.
21 Note, this incentive cost of $24. 54/kW-year is the overall incentive paid to get 40.3 MW of
18 2006 IR, Appendix B, page 53
19 $479.494 / 40.3 MW /1000 = $1 1. 89/kW
30 Fron~ the 2006 IR, Appendix B, page 53, total utility costs of $1,468,282 less the total resource cost of
$479,484 yields an incentive amount of $988,798.
36 Yankel, DI
Irrigators
1 actual peak reduction, while the actual incentive paid out to individual customers is $6.03/kW-
2 year. In other words, the Company is paying approximately four Irrigators $6.03/kW-year
3 ($24. 18/kW-year in total) in order to get one kW of actual peak reduction.
4
5 Q.HOW MUCH COULD TH IRGATION LOAD CURTAIMENT CREDIT
6 BE INCREASED BEFORE TH COST OF THE PROGRA WOULD EQUAL THE
7 MI CAP ACITY VALUE OF THESE INRRUPTIONS?
8
9 A.Presently the Company is paying out $24. 54/kW-year in order to obtain a
10 reduction of 1 kW of peak. With the minimum headroom of $ 86/kW-year, a credit that is 3.5
11 times larger32 than the present credit could be justified.
12
13 Q.WHAT LEVEL OF CREDIT DO YOU RECOMMND IN THS CASE?
14
15 A.It is clearly a loss to the system (and to the Irrigation customers in paricular) to
16 have less than 10% participation33 in a program that provides a savings of
at least $98/kW-year,
17 but only costs the Company less than $ 12/kW-year plus a credit payment. I recommend that this
18 credit be increased so as to bring the cost of the Irrigation Peak Rewards Program up to at least
19 $98/kW-year. Depending upon acceptance of the program after this case and the gathering of
20 additional data, it may be necessary to adjust this credit upward at a later date.
31 $988.798/40.3 MW / 1000 = $24.54/kW-year
3:! $86 i $24.54 = 3.5 .
33 On page 5 of the Company's report on its 2005 Irrgation Peak Rewards Program, it lists 893
partcipating sen-ice points. Company Exhibit 59 page 13 indicates that there were 62,675 in-season bils
for an average nwnber of bils during 5 months of 12,535. Therefore 7.1% oftlie average nwnber of
service points paricipated in 2005.
37 Yane!, DI
Irrigators
1 With respect to designing the rate, I will start with the assumption that all Irrigators are
2 on the I-day/week option. Because the Company does not expect an equal chance ofthe peak
3 occurring on each day of the week, it has spread the curtailable load in a manner that presumably
4 reflects its anticipation of peak load. Given the manner in which Schedule 23 customers are
5 spread across the days of the week34, it would take 3.84 kW of curtailable load to get 1 kWof
6 summer peak savings. Thus, this $86/kW of summer peak savings/credit would need to be
7 spread over 3.84 kW of paricipating load or $22.40IkW of curtailable load ($86 I 3.84 =
8 $22.40). I recommend that this $22.40/kW credit be applied for the season as opposed to over
9 the individual months.
10
11 Q.WHAT CREDITS DO YOU RECOMMND FOR THE 2-DAYIWEK AN 3-
12 DAY/WEEK CURTAILMENT OPTIONS?
13
14 A.Because the 2-day/week option produces twice the curtailable load as the 1-
15 day/week option, that credit should be twice this amount or $44.80/kW. Likewise, the 3-
16 day/week option should have a credit of $67.20/ kW. The Company has justified paying 2-
17 day/week option customers less than twice the credit paid I-day/week customers on the concern
18 that there could be "free-riders" associated with customers that opt for interruptions more than
19 one day per week. In this case, a "free-rider" is considered to be someone that would not be
20 operating absent the program and thus, the credit would be paid with no true curtailment benefit
21 going to the Company. I do not share the level of concern the Company has with free-riders.
22 Furthermore, I do not believe the way to address a free-rider problem is to price all multiple day
34 According to Table 6 on page 11 of the Company's 2005 report on its Irigation Peak Rewards program,
Tuesdays, Wednesdays, and Thursdays get allocated approximately the same level of curtailable load,
38 Yankel, DI
Irrigators
1 curtailment customers less than the multiple benefit that they provide when the concern
2 regarding free-riders would only represent a fraction of the customers.
3
4 Q.DO YOU HA VB A RECOMMNDATION THAT WOULD BETTER
5 ADDRESS THE COMPAN'S FREE-RIER CONCERNS, WHE NOT PENALIZING ALL
6 THE CUSTOMERS THAT OPT FOR MUTIPLE DAYS OF CURT AILMENT?
7
8 A.Yes. I make this recommendation for all credits that are greater than the I-day
9 credit of $22.40/kW.
10 It can be calculated35 from Company Exhibit 59, page 13 that the average, in-season load
11 factor for the Irrigators is 50.25%. If a customer that is on a multi-day option has a load factor
12 less than this class average, an adjustment could be made to reflect the fact that he has more
13 times when he is not operating and thus a higher potential for being a free-rider. For example, if
14 a customer on a 2-day curtailment option has an average seasonal load factor of only 25.13%
15 (half that of the Irrigators as a whole), then he should get half the credit for the second day of
16 curtailment, i.e., he should get a $22.40/kW credit for the first day plus $11.20/kW for the
17 second day of curtailment. If a customer is on a 3-day curtailment option and only has a
18 seasonal load factor of 25 .13 %, then he should get full credit for the first day and only half of the
19 credit for the second day and half for the third day of curtailment. Effectively, the customer on
20 the 3-day curtailment option gets the same credit as a customer on a 2-day curtailment option,
21 which is fair because he has half of the load factor, but is offering twice the curtailment above
22 the I-day curtailment option.
while Mondays and Fndays get approximately 42% of this amount.
35 1,109,400,571 in-season kW / (3,025,809 kW / 5 months) /152 days / 24 hours = 50.25%.
39 Yankel, DI
Irrigators
1
2 Q.WH AR YOU NOT APPLYIG THS LOAD FACTOR ADJUSTMENT TO
3 THE I-DAY CURTAIMENT OPTION?
4
5 A.The only way it would be fair to apply this load factor adjustment to the I-day
6 curtailment option would be if it was symmetrical, i.e., it would have to be applied as a penalty
7 to those with average seasonal load factors below 50.25% and as a benefit to those with average
8 seasonal load factors above 50.25%. I believe this would be overly complicated and confusing
9 to the customers. I only proposed this load factor correction to address the Company's free-rider
10 concerns regarding customer choosing multi-day curtailment options that may in fact be free-
11 riders.
12
13 Q.DO YOU HAVE AN PROPOSED CHAGES TO IPCO'S PEAK REWARS
14 PROGRA IN ADDITION TO THE INCREASE IN THE LEVEL OF THE CREDIT?
15
16 A.Yes. If the curtailment credit is going to be increased up to a level that reflects
17 the true marginal cost of capacity, then I recommend that the curtailment period be expanded
18 from the present three summer months to include the entire five months of the Irrigation season.
19 The Company's various marginal cost studies and its 2006 IR point to capacity deficiencies in
20 all five months of the Irrigation season-not just June, July, and August. If the credit to
21 Irrigators would not be set at the true levelized value of the benefit provided, then it would not be
22 appropriate to increase the period over which curtailments could take place.
23
40 Yankel, DI
Irrigators
1 Q.AR THERE OTHER CHANGES YOU WISH TO PROPOSE TO THE PEAK
2 REWARS PROGRA?
3
4 A.Yes. At present IPCo limits participation in the Peak Rewards program to
5 Irrigators with at least 75 horsepower. This greatly limits the number of customers that can
6 participate and prevents all but the largest Irrigators from participating. In the past IPCo has
7 justified its 75 horsepower limit on the basis that the installation costs do not justify the
8 installation of such equipment on smaller customers. Contrary to this, PacifiCorp's program has
9 no horsepower restriction. I recommend that participation in IPCo' s Peak Rewards program be
10 put on a par with that ofPacifiCorp's by removing the present horsepower limit and including
11 the same language as found in PacifiCorp's Schedule 72, Sheet 72.4, paragraph 8:
12 Cost of Control Devices. The paricipation Customer shall pay the cost of timers or
13 other load control devices and associated installation. Such costs include, but are
14 not limited to, direct and indirect costs of load control devices, labor, and material
15 and equipment required to achieve scheduled load control events. The participating
16 Customer shall pay such cost only to the extent that they exceed one thousand
17 dollars per meter. Customers required to pay the cost of control devices under
18 terms of this Special Condition will be provided a statement detailing such costs.
19
20 Q.PACIFICORP HAS STARTED A NEW "COMPAN OPTION"
21 CURTAILMENT PROGRA AS OPPOSED TO JUST THE DESIGNATED DAY
22 PROGRA THAT IT AN IDAHO POWER HA VB BEEN OPERATING IN THE PAST. DO
23 YOU HA VB AN RECOMMNDATIONS WITH RESPECT TO SUCH A PROGRA FOR
24 IDAHO POWER?
25
41 Yankel, DI
Irrigators
1 A.From everyhing that I have been able to gather, this "Company Option" program
2 that is being conducted by PacifiCorp is both a hit with the Company as well as the Irrigators that
3 are participating. We should get a report back on this new option late this falL. I recommend
4 that PacifiCorp's report on this option be reviewed closely by Idaho Power, the Commission
5 Staff, and the Irrigators with the intention (if all goes well) of implementing a similar program or
6 at least a pilot program in the Idaho Power service area for the summer of 2008.
7
8 Q.THE IRRGATORS AN P ACIFICORP STIPULATED TO A NUER OF
9 DIFFERENT CONDITIONS AN RATES IN PACIFICORP'S RECENT RATE CASE.
10 SOME OF THE RATES THAT AR IN THAT STIPULATION AR LOWER THA WHAT
11 YOU PROPOSE HERE. WH SHOULD THE COMMSSION ADOPT THE HIGHER
12 RATES THAT YOU AR PROPOSING IN THS CASE?
13
14 A.The rates to which the Irrigators agreed in the PacifiCorp case were a part of a
15 package. That package contained the Company Option curtailment package that I mentioned
16 above. That package does things like give the Irrigators less curtailments than what is offered
17 here as well as the ability to opt -out of five curtailments throughout the year. The credit for the
18 Company Option package is higher than what is recommended here for a I-day curtailment
19 option. Basically, the Irrigators were happy with the entire package they got in the PacifiCorp
20 rate case, and would be happy with the same package in this case. However, it would be
21 completely inappropriate to take only pieces of
the PacifiCorp stipulation and assume they can
22 be applied with any validity in this case.
42 Yanel, DI
Irrigators
1 Irrigation Time-Or-Day Rate
2 Q.DOES IDAHO POWER HA VB EXPERINCE WITH VOLUNTARY TIM-
3 OF-DAY RATES?
4
5 A.Yes. There has been a limited program for both Residential and Irrigation
6 customers. However, in my opinion these Time-of-Day (TOD) rates are not producing desired
7 results and the Irrigation TOD Schedule 25 has been abandoned as of
October 1, 2007.
8 By contrast, PacifiCorp in Idaho seems to have had a great deal of success with its
9 Residential TOD program in Idaho. There has been a Residential Time-Of-Day (TOD) rate
10 schedule (Schedule 36) in Idaho for the last 20 years. It has been more successful than many
11 TOD rate schedules. In PacifiCorp's current rate case there are 16,276 Residential customers on
12 Schedule 36 out ofa total of 54,047 total Residential customers. Approximately half (47%) of
13 the Residential usage takes place on Schedule 36. Schedule 36 contributes less to the system
14 peaks as demonstrated by the fact that its contribution to the 12-coincidents peaks is only 43% of
15 the overall Residential contribution.
16 It is noteworthy that even during the summer months (when there is no alternative to air-
17 conditioning) that the relative usage between super-peak hours (2:00 p.m. to 8:00 p.m.) and
18 average usage for Schedule 36 customers is less than that for larger Schedule 1 customers that
19 have air-conditioning potentiaiJ6. Basically, Schedule 36 customers are shifting a portion of
their
20 usage from the super-peak to other times.
21 It is noteworthy to contrast PacifiCorp's Residential TOD program with that ofIdaho
22 Power's Schedule 5 which is limited to one geographic area with AM metering. There are only
43 Yanel, DI
Irrigators
1 86 TOD customers taking service under this program3? Even for the limited availability area in
2 which Schedule 5 is offered, this is a very low participation rate.
3
4 Q.TO WHAT DO YOU ATTRIUTE THE SUCCESS OF PACIFICORP'S
5 RESIDENTIAL TOD RATE IN IDAHO?
6
7 A.Like any program or rate schedule, there are a variety of things that contribute to
8 the success ofPacifiCorp's Schedule 36 compared to Idaho Power's Schedule 5 or Schedule 25.
9 Historically, standard Residential rates in PacifiCorp's Idaho service area have been higher than
10 comparable rates in the Idaho Power service area-higher rates make alternative rate designs
11 more attractive. According to the 2006 FERC Form 1 's, PacifiCorp's non-TOD Residential
12 Schedule 1 customers paid an average of8.39 cents/kWh, while Idaho Power's non-TOD
13 Residential Schedule 1 customers paid an average of 5.97 cents/kWh.
14 Of more significance is the differential in rates between on-peak and off-peak hours. If
15 this differential is not suffciently large, there is little incentive to shift usage from on-peak hours
16 to off-peak hours. PacifiCorp's Schedule 36's summer TOD rates38 are simply 10.8 cents/kWh
17 on-peak, and 3.7 cents/kWh off-peak, for a differential between on-peak and off-peak of 7.1
18 cents/kWh.
19 Idaho Power's Schedule 5's summer TOD rates are more complex with three tiers (on-
20 peak, mid-peak, and off-peak), but one can readily see the differences between this rate and
21 Schedule 36. Schedule 5's highest priced, on-peak rate (1:00 p.m. to 9:00 p.m.) is 8.3
36 Schedule 1, Strtu 3 customers average usage was 1,276 kWh in June, 1,396 kWh in July, 1,243 kWh
in August, and 1,165 kWh in September.37 Company Exhibit 59, page 1
38 All rates in t1us section of testimony have been round to one decimal point for easy of reading.
44 Yankel, DI
Irrigators
1 cents/kWh. This "highest rate" is 2.5 cents/kWh less than the Schedule 36 on-peak rate and is
2 almost as large as the entire differential of 7 .1 cents/kWh in Schedule 36. Schedule 5' slowest
3 priced, off-peak rate (9:00 p.m. to 7:00 a.m.) is 4.5 cents/kWh. This "lowest rate" is almost a
4 penny more than the off-peak rate in Schedule 36. Schedule 5's mid-peak rate (7:00 a.m. to 1:00
5 p.m.) is 6.1 cents/kWh. This mid-peak rate essentially dampens any differential between the
6 high and low cost hours-it is essentially a neutral time.
7 It is important to remember that PacifiCorp's Schedule 36 and Idaho Power Schedule 5
8 are voluntary/optional rates. Schedule 36 offers customers a significant choice differential and is
9 successfuL. Idaho Power's Schedule 5 offers significantly less difference between on-peak and
10 off-peak rates and the paricipation rate reflects this fact.
11
12 Q.HOW DO PACIFICORP'S SCHEDULE 36 RATES COMPAR WITH TOD
13 RATES BEING DEVELOPED TODAY?
14
15 A.According to the Pacificorp's "Assessment of Long-Term, System-Wide Potential
16 for Demand-Side and Other Supplemental Resources" study, the new TOD rates being
17 developed are more inverted than those being offered in Schedule 36. On page 46 of
that Report,
18 it is stated:
19 The TOU (TOD) rates developed in recent years typically differ from those of the
20 past in several important ways. First, most new TOU rates contain three price
21 tiers as opposed to the two-tier rates common in many long-standing TOU
22 programs, including those offered by PacifiCorp. This allows utilities to set high
23 prices during their highest peak periods and offer exceptionally low off-peak
24 prices overnight when the cost is at its lowest and supply is plentifuL. The
25 majority of hours are assigned a "mid-peak" price that is typically a slightly
26 discounted version of the standard rate. Another change is that the duration of
the
27 peak period is typically shorter than in the past. Finally, the price differentials
28 between peak and off-peak prices tend to be greater than in the past to encourage
45 Yankel, DI
Irrigators
1 load shifting away from the peak period. For long-standing TOU rates, this
2 differential averaged about 7.6 centslkWh, whereas newer programs tend to have
3 a differential of greater than 10 cents/kWh. For comparison, PacifiCorp's
4 existing TOU rates offer a price differential of
roughly 4.5 cents/kWh to 7.5
5 cents/kWh, depending on the operating utility and the season.
6
7 Q.HOW DID IDAHO POWER'S IRGATION TOD RATE (SCHEDULE 25)
8 COMP AR WITH P ACIFICORP' S SUCCESSFUL RESIDENTIAL TOD PROGRAM?
9
10 A.Like its Residential TOD rate, Schedule 25 had three rate periods with very little
11 differential between the on-peak rate of 6.2 cents/kWh and the off-peak rate of 1.8 cents/kWh.
12 Instead of a differential that approached and/or exceeded 1 0 cents/kWh, the rate differential was
13 only 4.4 cents/kWh. A second problem with Schedule 25 was the length of
time for each ofthe
14 time slots. An Irrigator is generally a customer with one piece of equipment that can either be
15 turned on or off. Portions of the load cannot be shifted, either the entire load is shifted or none of
16 it is shifted. As a result, the off-peak period which is an award time is way too short at only 12
17 hours every day (including weekends and holidays), and the super-peak timeframe is way too
18 long at 8 hours every day.
19
20 Q.HOW CAN THIS INORMATION BE USED TO DEVELOP A TOD RATE
21 FOR IRGATION CUSTOMER?
22
23 A.A TOD rate for Irrigators is an opportunity to not simply lower the costs to the
24 Irrigators, but to lower the overall system costs as well. Like Schedule 36, a TOD rate for
25 Irrigators should get its own cost-of-service treatment such that the rates and benefits stand on
26 their own.
46 Yanel, DI
Irrigators
1 TOD rates (as an option and not mandatory) could be a feasible alternative for many
2 Irrigation customers. However, Irrigators can not be realistically expected to follow a similar on-
3 peak pattern as Residential customers. Instead, I recommend that something more like a super-
4 peak price be developed in conjunction with an off-peak price. For the super-peak timeframe, I
5 recommend the same 5-days per week as in the Irrigation Curtailment program and the same 4-
6 hours per day (4:00 p.m. until 8:00 p.m.).
7 I recommend that the super-peak price be set at 15 cents/kWh and that the off-peak price
8 be set at 4.2 cents/kWh. These rates have been chosen in order to develop a spread of over 10
9 cents/kWh between the super-peak and the off-peak and in order to remain revenue neutral if
10 there is no net change in consumption patterns.
11
12 Q.DOES THIS CONCLUDE YOUR DIRCT TESTIMONY?
13
14 A.Yes.
47 Yankel, DI
Irrgators
'l
Exhibit No. 301
. Case No. PAC-E-07-05
AnthonyJ. Yankel
"llPA and Idaho Power Company Development of
Weighted Demand and Energy Allocators, Based on
Growth For The Twelve Months Ended December 31,
2007"
10 pages
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Case No. PAC-E-07-0S
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"Growth Weiglited Class Cost of Servce Study Twelve
Months Ending December 31, 2007"
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Exhibit No. 303
Case No. PAC-E-07-05
Anthony J. Yankel
"Assessment of Long-Term System-Wide Potential for
Demand-Side and Other Supplemental Resources Final
Report-Volume I"
31 pages
..
iI~~~l~~~W~ili~~Jm;'~~iÎ\ .
Final Report-Volume I
Assessment of Long-Term,
System-Wide Potential for
Demand-Side and Other
Supplemental Resources
Prepared for PacifiCorp
July 11 f 2007
I n collaboration with Summit Blue Consulting and Nexant, Inc.
:./~~;~r1j.~~t~ll~~~~~lll
..
quantec Raising the bar Ì11 t1ui/ytics""
-
Investigators:
Hossein Haeri, Ph.D., Lauren Gage, Tina Jayaweera, Ph.D., Colln Ellot,
Eli Morris, Rick Ogle, P.E., Tony Larson, Aquila Velonis. Matei Perussi,
Allen Lee, Ph.D., and Ann Grifn, Quantec, LLC.
Kevin Cooney, Randy Gunn, Stuart Schare,
Adam Knickelbein, and Roger Hil, Summit Blue Consulting
Terry Fr, Mike Boutross, and Pranesh Venugopal, Nexant, Inc.
Rioõ6RtoJëbm\2oš5ar(eãClêôml2~07lG~ãêì~DSMi?ôTElbli~~2O58W1:g1O
Quantec Offces
720 SWWashlnglon, Sulte 400
Portand, OR 97205
(503) 2282992: [phone] fa
WN.quan!ecllccom
1722 14tf St., Suite 210
Bolder, CO 80302
(303) 9980102 ;(303) 9981007 fa
28 E. Main St., SuUe A
Reedsbui, WI 53959
[phone]; (608) 5246361 fax
~N'.iCi\2 ie f"
3445 Grant Sl
Eugene, OR 97405
[phone]; (541) 6853683 fax
20022 Cow Circle
Hunng Beach. CA 92646
(74) 287-6521
-
Table of Contents: Volume I
Acknowledgeineiits.. ... .......... ........... ............. ........... ........ ......................... ........... ..... ....... xiii
Executive Summary ................................ .......... ............... ......................... ..."I.....a...ES-1
Overview..................................................................................................................................E8-1
Sumary of the Results ................................................................................................. ES-2
ResourceAcquisition Costs........................................................................................... E8-9
Resource Potential under Altemative Scenarios ........................................................... E&9
1. Introduction ................................................................................................ I
Background4.4...4....~.t......l.t..'..l".....,...t........,...................................................................... ..................1
Study Scope and Objectives.................................................................................................2
General Approach....................................... ......................................................................... 5
Organization of the Report...................................................................................................8
2. Capacity-Focused Resources (Class 1 and Class 3 DSM)....................9
Scope of Analysis ................................................................................................................ 9
Assessment Methodology .......................................................................................... 1 1
ResourcePotential.............................................................................................................18
Resource Costs and Supply Cues ................................................................................... 20
ResourceAcquisition Schedule .........................................................................................26
Resource Potential under Altemative Scenarios................................................................27
Class 1 DSM Resource Results by Progrin Option........................................................ 28
Class 3 DSM Resource Results by Program Option............... ...........................................40
3. Energy-Efficiency Resources (Class 205M) ..........................'..............57
Scope of Analysis ..............................................................................................................57
Resource Potential......... .......... ........... .... ................... ............. ............ ...... .. ............. ..........58
Resource Potential under Altemative Scenarios................................. .............................. .62
Assessment Methodology..................................................................................................63
Class 2 DSM Detailed Resource PotentiaL. ............ ............................................................85
4. Education and Information (Class 4 DSM).............................................95
Scope of Analysis ..............................................................................................................95
Potential and Costs........................................................................................................... 99
Pacifi -Assessment of Long-Term, Syste-Wde Potential
5. Supplemental Resources ......................................................................101
Scope of Analysis ............................................................................................................101
Assessment Methodology ...............................................................................................1 0 1
Resource Potel1tial . ... ........... ....... .... .... ..... ........... ............. .................... ......... ............... ....1 02
Resource Acquisition Schedule ..... ............................. .....................................................1 04
Resource Potential under Alternative Scenaros.............................................................. 106
Coinbuied Heat and Power Results-...............................................................u........u.........l06
On-Site Solar Results .......................................................................................................115
Dispatchable Stadby Generation Results .......................................................................123
6. Effects of Structural Changes....................Ii.lI.""..........**.......u....l;u...:i.........129
Overvew ..... ".........................,.....,.............................................................i...........................129
Macroeconomic Strctual Changes................................................................................ 130
Technological Changes....................................................................................................131
Public Policy and Regulation...........................................................................................132
PacifiCorp -Assessment of Long-Term, System-Wide Potential
Tables and Figures
Executive Summary ............................................................................................. 1
TableES-1. Energy-Focused Resource Potential (aMW in 2027): Technical,
Economic. and Achievable by Resource and Service Terrtory ..................2
Table ES2. Peak Demand Reduction Potential (M in 2027): Techl1ical,
Economic, and Achievable by Resource and Service Tenitory ..................3
Figue ES.1. Achievable DSM Potential by Resource Type (M and aMW
2027) (Rocky Mountain Power Terrtory).................................................. 4
Figue ES2. AchievableDSM Potential by Resource Type (2027) (Pacific
Power Terrtory. Excluding Oregon for Class 2 DSM) ...............................4
TableES.3. Achievable Class 1 and Class 3 (Capacity-focused)DSMResource
Potential by Cutomer Sector and Service Terrtory (M in 2027) ..........5
Table ES.4 . Achievable Class 2 (Energy-Effciency) DSM ResourcePotential
by Customer Sector and Servce Territory (aMW in 2027).........................6
Figue ES3. Class 2 DSM (Energy-Effciency) Supply Cures for TechncaL.
Economic. and Achievable Potential (aMW in 2027) .................................7
Table ES. Achievable Supplemental Resource Potential by Technology and
Service Terrtory (aMW and MW in 2027) ................................................8
Table ES.6. Base-Case Resource Acquisition Costs (NV and Levelized) by
Resourceatd Service Terrtory .........."..................u..........I..........~....,...............9
Table ES-7. Achievable Potential in 2027 by Resource and Economic Scenal'o .........10
1. Introduction ...llii.....................lrli..............'I......"".lIy............".........................11...............1
Figue 1.Reliabilty and Customer Choice Considerations in Demand-Side
ManagementResources .................................. ..............~.... ................".........,..3
Figue 2. General Methodology for Assessment of Demand-Side Resource
Potential................................................................................................... 6
2. Capacity-Focused Resources (Class 1 and Class 3 DSM)....................9
Table 1. Class 1 and Class 3 DSM Data Sources.....................................................12
Figue 3. PacifiCorp System Load Duration Curve (2006).......................................13
Table 2. Capacity-focused Analysis Customer Sectors and Segments ....................13
Figue 4. PacifiCorp System Monthly Sales (MWh) by Sector ................................1 4
Figue 5. Average Sumer Weekday Load - All End Uses.....................................15
Table 3. C&I Surey Results: Attitude toward Capacity-Focused Progrm
Options.......................................................................................................16
Table 4. C&I Survey Results: Program Preferences................................................! 7
PacifiCorp -Assessment of long-Term. Syste-Wide Potential
Table 6.
Table 7.
Table 8.
Table 9.
Figue 6.
Figue 7.
Table 10.
Figue 8.
Figue 9.
Figue 10.
Figue 11.
Table 11.
Table 12.
Figue 12.
Table 13.
Table 14.
Table 15.
Figue 13.
Table 16.
Table 17.
Figue 14.
Table 18.
Table 19.
Figure 15.
Table 20.
Class 1 DSM: Rocky Mountain Power Terrtory TechncaL.
Economic, and Achievable Potential (M in 2027) .................................19
Class 1 DSM: Pacific Power Terrtory TechnicaL. Economic. and
Achievable Potential (MW in 2027)...............................................u",....u19
Class 3 DSM: Rocky Mountain Power Terrtory TechnicaL.
Economic, and Achievable Potential (M in 2027) .................................20
Class 3 DSM: Pacific Power Terrtory TechncaL. Economic. and
Achievable Potential (M in 2027)..........................................................20
Class 1 DSM: Levelized Costs and Market Potential (M in 2027)........22
Class 1 DSM: Rocky Mountain Power Terrtory Supply Cure
(CumulativeMW in 2027).........................................................................23
Class 1 DSM: Pacific Power Terrtory Supply Cure
(Cumulative MW in 2027).........................................................................23
Class 3 DSM: Levelized Costs and Market Potential (M in 2027)........24
Class 3 DSM: Rocky Mountain Power Territory Supply Cure
(CumulativeMW in 2027)........................................................................25
Class 3 DSM: Pacific Power Terrtory Supply Curve
(Cuulative MW in 2027).........................................................................25
Class 1 DSM: Acquisition Schedule for Achievable Resource
Potential by Year and Territory ...........................,......................................26
Class 3 DSM: Acquisition Schedule for Achievable Resource
Potential by Yea and Territory .................................................................27
Ecnomic and Achievable Scenaros: Achievable Potential (M
in 2027) ...............................................,...........................................................28
DLC Air Conditioning: Technical and Market Potential (M in
2027)..........................................................................................................30
DLC Air Conditionig: Market Potential by State (M in 2027)...........31
DLC Air Conditioning: Levelized Costs and Scenarios............................32
DLC Air Conditioning and Water Heat: Levelized Costs and
Scenarios......................................................................................................33
DLC Large Commercial: Techncal and Market Potential (M in
2027)..........................................................................................................34
D LC Large Commercial: Market Potential by State (MW in 2027) .........35
DLC Large Commercial: Levelized Costs and Scenarios .........................35
Irrgation: Techncal and Market Potential (M in 2027)........................36
Irgation: Market Potential by State (M in 2027) .................................37
Irgation: Levelized Costs and Scenaros .................................................37
Thennal Energy Storage: Techncal and Market Potential (M in
2027) ........,...................,..,.,.,.............................................................................38
Thermal Energy Storage: Market Potential by State (M in 2027) .........39
Thennal Energy Storage: Levelizd Costs and Scenaros.........................39
PaclflCorp -Assessment of long-Term, System-Wide Potential Iv
Table 21.
Figue 16.
Table 22.
Table 23.
Figure 17.
Table 24.
Table 25.
Figue 18.
Table 26.
Table 27.
Figue 19.
Table 28.
Table 29.
Figure 20.
Table 30.
Table 31.
Figue2L.
Table 32.
Curilable TariffPo~: Technical and Market Potential (MW
in 2027) ......t.,.......,..,.".....I-~........~.........................................................................41
Curilable Tarff Progr: Market Potential by State (MW in
2027)................................................................................................................42
Curilable Tarff Program: Levelized Costs and Scenaros......................43
Demand Buyback: Technical and Market Potential (M in 2027) ..........45
Demand Buyback: Market Potential by State (M in 2027)....................45
Demand Buyback: Levelized Costs and Scenaros....................................46
Time of Use Rates: Technical and Market Potential (MW in 2027).........47
Time of Use Rates: Market Potential by State (M in 2027)...................48
Time of Use Rates: Levelized Costs and Scenaros...................................48
CPP Residential/Small Commercial: Technical and Market
Potential (M iii 2027) ............................................................................50
CPP Residential/Small Commercial: Market Potential by State
(1 in 2027) .1............"........................................................................."....51
CPP Residential/SmaIl Commercial: Levelized Costs and
Scenarios.. .................. .................................. ....................... ...... .................51
CPP C&I: Technical and Market Potential (M in 2027)........................53
CPP~C&I: Market Potential by State (M in 2027) .................................53
CPP C&I: Levelized Costs and Scenaros ............................................... 54
Real-Time Pricing: Technical and Market Potential (M in 2027) .........55
Real-Time Pricing: Market Potential by State (M in 2027) ...................55
Real-Time Pricing: Levelized Costs and Scenaros...................................56
3. Energy-Efficiency Resources (Class 2 DSM) ........................................57
Table 33.
Table 34.
Table 35.
Table 36.
Figue 22.
Table 37.
Table 38.
Table 39.
Figure 23.
Energy-Effciency Measure Counts (Base-Case Scenaro) .......................57
TechncaL. Economic and Achievable Energy-Effciency Potential
(aMW in 2027) by Sector ..........................................................................59
Technical, Economic, and Achievable Energy~Bffciency Potential
(aM in 2027) by State.............................................................................59
Techncal, Economic, and Achievable En~rgy-Effciency Potential
(aMW in 2027) by Sector and Resource Type...........................................60
Acquisition Schedule for Achievable Savings by Year and Sector ........... 61
Technical, Economic and AchievableEnergy-Bffciency Potential
(aMW in 2027) by Sector and TechnologyType ......................................61
Ecnomic and Achievable Scenaros: Achievable Potential by
Sector (aMWin 2027) ...............................................................................62
Economic and Achievable Scenaros: Achievable Potential by
State (aMW in 2027)..................................................................................63
Representation of Alternative Forecast Approach to Estimation of
Energy-Effciency Potential.......................................................................65
PaclfiCorp -Assessment of long-Tenn, System-Wide Potential v
Table 40.
Table4L.
Table 42.
Table 43.
Table 44.
Table 45.
Table 46.
Table 47.
Table 48.
Table 49.
Figue 24.
Table 50.
Table 51.
Figue 25.
. Figue26.
Table 52.
Table 53.
Figue 27.
Figure 28.
Table 54.
Table 55.
Figure 29.
Table 56.
Figue 30.
Table 57.
Figue 31.
Table 58.
Figue 32.
Table 59.
Class 2 DSM PacifiCorp Data Sources......................................................66
Class 2 DSM Pacific Nortwest Data Sources ..........................................66
Residential Sector Dwellng Types and End Uses.....................................68
Commercial Sector Customer Segments and End Uses ............................68
Industral Sector and End Uses.............................................................. 69
Residential Energy-Effciency Measures...................... ........... ..................72
ResidentialEmerging Technology Measures ............................................72
Coinniercial Energy-Effciency Measures ................................................. 73
Commercial Emerging Technology Measures...........................................?3
Industral Energy-Effciency Measures .....................................................74
Example of Equipment Potential: Average Eil for Large Office
Chillers in Existing Constrction...............................................................75
Measure Applicability Factors...................................................................78
Economic Assumptions by State ................................................. ..............80
Rocky Mountain Power Terrtory Anual JR Decrement and
MarketPóee Values...............................................................,..............a..........81
Pacific Power Terrtory Anual IR Decrement and Market Price
Values ........................................................................................................81
Assumptions of Achievable Potential as Percent of Economic, by
Sector aid End Use.............................................................................................84
Residential Sector Energy-Effciency Potential by State (aMW in
2027) ................................................................................................................85
Residential Sector Achievable Potential by Segment................................86
Residential Sector Achievable Potential by End Use ................................87
Residential Sector Energy-Effciency Potential by End Use (aM
in 2027) .................. .........4..................................................................................1l..........."..88
Commercial Sector Energy-Effciency Potential by State (aMW in
2027)..........................................................................................................................89
Commercial Sector Achievable Potential by Segment.............................. 89
Coininercial Sector Energy-Effciency Potential by End Use (aM
in 2027)........................................................ ..............................................90
Commercial Sector Achievable Potential by End Use ..............................90
Industral Sector Ener,g- Effciency Potential by State (aMW in
2027) ..........................................................................................................................91
Industral Sector Achievable Potential by Segment..................................92
Industral Sector Energy-Effciency Potential by End Use (aM in
2027) ...................................................................................................................92
Industral Sector Achievable Potential by End Use...................................93
Irgation Sector Energy-Effciency Potential by State (aM in
2027) ..........................................................................................................93
PacifiCorp -Assessment of Long-Tenn. System-Wide Potential vi
4. Education and Information (Class 4 DSM).............................................95
Table 60. Class 4 DSM Activity Types ..................................................................... 95
Table 61. Estiated Residential Impacts of Class 4 DSM Programs (aMW)...........99
Table 62. Estimated Commercial Impacts of Class 4 DSM Programs (aMW) .......1 00
Table 63.
5. Supplemental Resources ......................................................................101
Table 64.
Table 65.
Table 66.
Figure 33.
Table 67.
Table 6S.
Table 69.
Table 70.
Table7!.
Table 72.
Figure 34.
Table 73.
Table 74.
Table 75.
Table 76.
Table 77.
Table 7S.
Table 79.
Figure 35.
Table SO.
TableS!.
TableS2.
Supplemental Resources Installed Capacity by State and Resource
Category (M ........................ ...... ..........................................................1 02
Supplemental Resources Technical Potential by Region and
Resource Category (aMW and MW in 2027) .......................................... 103
Levelized Cost for Supplemental Resources and Economic Screen
by Terrtory..............................................................................................104
Achievable Potential for Supplementa Resources by Terrtory
(aM andMW in 2027).......................................................................... l04
Acquisition Schedule for Supplemental Resources by Resource
Category .................. .................................... .............................................105
Economic and Achievable Scenaros: Achievable Potential (aMW
andMW in 2027)................................................. ......................,,,................106
CH Prototyical Generating Units......................................................... 1 OS
Costs for Assessed Technologies (2007$) ..............................................1 09
CHP Technical Potential by State and Resource Category (aMW in
2027) .......,.,..........................."'.......................................................................111
Market Potential for CHP (aM in 2027) ..............................................112
Market Potential for CHP by State and Technology(aMW in 2027)......113
CH Cuulative Supply Cure. by Technology (Cumulative aMW
in 2027)..................................................................11.................................114
Achievable Potential for CHP by State with Cost Theshold ..................114
CHP Average Leve1izd Costs ($/kWh) for Different Ecnomic
Scenarios..................................................................................................115
CHP AlternativeEconomic Scenarios for Base Achievable
Potential by State(aMW in 2027) ........................................................... 115
On-Site Solar Technology Costs and Measure Lives ..............................117
Solar Anual Capacity Factors. by State .................................................119
On-Site Solar Technical Potential by State (aMW in 2027)....................1 19
On-Site Solar Market Potential and Levelized Costs by State
(aMW in 2027).........................................................................................121
Diffsion Cure for Product Adoption ....................................................122
Potential Market Penetration of Adopters by Payback Period.................l 22
Existing Backup Generation, Commercial Sector ...................................1 24
Existing Backup Generation. Industral Sector ........................................124
PaciliCorp -Assessment of Long-Term. System-Wide Potential vii
Table 83.
Table 84.
Table 85.
Table 86.
Table 87.
State Emission Standards for Diesel Backup Generators........................125
DSG Technical Potential by State (M in 2027) ...................................125
Costs for DSG............................................................................. .............126
Achievable Potential and Cost for DSG (MW in 2027)..........................127
Alternate Econoinic Scenaros for DSG Base Achievable Potential
by Terrtory (M in 2027)......................................................................127
6. Effects of Structural Changes............"".......ii....ui.uu.................................129
Table 88.
Figue 36.
Categories of Strctual Changes and Examples.....................................l29
Ilustrtion of Linages between Súuctural Changes and
Achievable Potential ................................................................................130
PacifCorp -Assessment of Long~Term. System-Wide Potential
Table of Contents: Volume II
Appendix A-1. Surveys Results. Overview....................................................A-1
CI and ClI Surey Sumaries..................................... ................................................. A-I
Appendix A2 . Survey Results. Detailed ....................11............... .......n................A-7
CI Surey Results: Overall............................................................................................. A - 7
CHP Survey Results: Overall........................................................................................ A-4l
Appendix A3 . Survey Instruments...UIi........a..................llt......liu........."..Ii....Iu.A.55
CI Surey Instrent.................................................................................................... A-57
ClI Surey Instrment................................................................................................ A -73
Appendix 8~1. Capacity-Focused Resource Materials: Detailed
Assumptions by Program Option.....u.......iiU1i.....................II...lllill....ll.Ii.....:ilu,,,..11:....8..1
DLC Residential - Air Conditioning Only .......u....................................uu...................uuB- i
DLC Residential- Air Conditioning and Water Heating................................................B-3
DLC Coinmercial .........................................................,......tlt......................................,........,....B-6
Irgation ............. ............................ ....................... ............. ......... .................. .............. ..B-14
Thermal Energy Storage ................................................................................................B-15
Curtailable Load................................................................~...............................................................~..B-17
Demand Bidding .................................................... ........................................................B- 21
Residential Time of Use Rates.......................................................................................B-25
Residential and Small Commercial Critical Peak Pricing .............................................B-26
Commercial and Industrial: Critical Peak Pricing.........................................................B-27
Real Time Pricing ...................................................,.......................,......"...a.......,...............- 1
Appendix B-2. Capacity-Focused Resource Materials: Load Basis and
Calibration... .............. '" .1I~''l...1I ,.,....... ...........:lz.....ati....a.....Ii.Ii.... .it......,................... ..... ...8-35
California .....'a'...............,.................a'a...............,a...a.........,.,..... .....................,........................8-35
Idaho .....'...a.................a...............'a.........aa........a...........'..a..........................,.....,....................B- 38
Oregon.............. ...... ............ .............. .......... ........ ............. .................... .......... .............. ...B-40
Uta.. ...... ....,., .., ..... ..... ... ....... ,... ..... ..a.... ....... ........ .... ...... .... ...... .... .... .......... .a....... ........ ........ ..B-42
W as.hington .........................,.................."............................,............................................. ..........B-44
Wyomig.'.....r....'............l.........".................................................,.........1-............,.......'.a......B-46
All States Total..............................................................................................................B-49.
PacifiCorp -Assessment of LongMTerm, System-Wide Potential
Appendix B-3. Capacity-Focused Resource Materials: Detailed
Program Results _ Year and Market Segment (Summer)...........................6-53
DLC _ RES _ AC and Water Heat .................................................................................B-53
DLC _ RES - AC ........................................................................................................... B-55
DLC _ Coml11ercial ...........11........................................................................................,............B-57
Irrgation ........................................................................................................................ B-59
Thennal Energy Storage................................................................................................ B..61
Curtailable Load......................................................................................................................B-63
Time Of Use Rates.............................................................................................................B-67
Appendix 6-4. Capacity-Focused Resource Materials: Winter Results....6-75
Class 1 DRPrograins.................................................................................................... B-75
Class 3 DR Prograins ....,..................................4...............................................................B-76
Appendix C..1. Technical Supplements: Energy Efficiency Resources.
Measure Descriptions ................... ............. ............... ....................................... C..1
Residential Measure Descriptions..................................................................... ...............C- i
Residential Emerging Technology.................................................................................- 1
Commercial Measure Descriptions................................................................................- 3
Commercial Emerging Technologies .......................................................................... C-28
Industral Measure Descnptions ............. .......................................................................C- 30
Appendix C-2. Technical Supplements Energy Efficiency Resources.
Market Segmentation ..................................................................................... C-33
Baseline Forecasts.......................................................................................................... C-35
End Use Satuations and Electric Shares.......................................................................C-47
End-Use Consumption Estimates ..................................................................................C-62
Appendix C3 . Technical Resources: Energy Efficiency Resources.
Measure I n puts ..........'a'...... "..ii.ii........................ ...."'...11.... ...'..Itt:..................... "II",C-63
Appendix C-4. Technical Resources: Energy Efficiency Resources.
Class 2 DSM Decrement Analysis.. ..... ......................... ............................ ....C-93
Appendix D. Technical Supplements: Class 4 Resources ..........................0-1
Descnptions and References for Reviewed Programs......................................... ........... D- i
PacifiCorp -Assessment of long-Term. System-Wide Potential
Appendix E~1. Technical Supplements: Supplemental Resources
CHP..............................................................................................................E.1.
Appendix E2 . Technical Supplements: Supplemental Resources
On-Site Solar......................................"......................*.....................................&...... E.65
Appendix E3 . Technical Supplements: .Supplemental Resources
DSG......II..................... ..IR................... .....ir ............ ........ .... ....11..... .11..... ........... ......... ........ E-79
Appendix F. Simulations & Home Electronics..............................................F-1
Scope.....................................,................................................................................................ii....E-l
Methodology .....t................................jll.................................................................................F- 38
Results............ .........................................................................................................................F -42
Appendix G. Treatment of Externalities.........................................................G-1
Introduction and Purpose..........................................,...........................".............................. G.I
Objectives and Approach..........................................................................................:..... G-l
Findings........................................................................................................................... G-2
PacifiCorp-Assessment of Long-Term, System-Wde Potental
Acknowledgements
This study required compilation of a large amount of data from various sources, includig
several departents at PacifiCorp. It would be difficult to overstate the importance of the
contributions made by PacifiCorp staff to this effort. We than all of them for their assistace.
We are especially grateful to Chrstopher KanofE our project manager, who worked had to
ensure the necessarinfonnation was delivered to us on time. Bil Marek made himself available
to us when we needed him and helped us develop a better understanding ofthe complexities of
PacifiCorp's Class 1 and Class 3 DSM programs and made it possible to model them properly.
Pete Waren provided much needed support in coordinating the assessment of the potential
with the integrted resource planning process.
We thank Jeff Bumgarer, Director of Demand Side Management, and Don Jones, Jr., Energy
Efficiency Segment Manager at PacifiCorp, for their support. They offered invaluable insight
and direction throughout the course of the study while allowing us to exercise our independent
judgment and to maintain our objectivity.
PacifiCorp-Assessment of Long-Tenn. System-Wide Potential xli
Executive Summary
Overview
For neal'y 25 years, PacifiCorp has ben actively engaged in the design and delivery of demand-
side management (DSM) products and services. Beginning with its management and sponsorship
of the Hood River Conservation Project in the early 19808, PacifiCorp has contiued to be an
innovator in energy effciency and has conceived and implemented programs such as Energy
Finswer, which, in its class, is considered one of the best programs in North America. Over
the fast 15 years, PacifiCorp has invested approximately $345 milion on DSM progrms,
offsetting nearly 2,700 G\Vh of energy -the equivalent of nearly 515 MW of capacity anually,
assuming a 60% load factor on averge.' Curently, PacifiCorp operates successful capacity-
focused programs for irrigation load curtilinent, demand buyback, and air conditioning direct
load contsol, which together helped reduce PacifiCorp's pea loads by 149 MW in 2006.
PacifiCorp also has an additional 260 MW available for control under interrptible agreements
with a select group ofits largest commercial and industral customers.
Begining in the early 1990s, PacifiCorp developed biennal integrated resource plans (lRs) to
identify the optimal, least-cost mix of supply and demand-side options to meet its projected long-
run resource requirements. This report summarizes the results of an independent study to conduct
a comprehensive, multi-sector assessment of the long-ru potential for DSM resources in
PacifiCorp's Pacific Power (Or Washington, and California) and Rocky Mountain Power
(Idao, Wyomig, and Uta) service terrtories to support the PacifiCorp's integrated resource
planing process and help fuher PacifiCorp's active pursuit ofDSM resources.
This study's pricipal goal is to develop reliable estimates of the magntude, timig, and costs of
alternative DSM resources, comprised of capacity-focused program options (defied throughout
this report as Class 1 and Class 3 DSM resources), energy-effciency products and services
(defined as Class 2 DSM resources), and other" supplemental "resources such as solar, combined
heat and power, and dispatchable stadby generation. The analysis of resource potential in this
study are augmented by an examation of the benefits of consumer awareness and education
initiatives (Class 4 DSM resources) and an analysis of how future strctual changes, such as
technological inovation, macroeconomic conditions, and public policy, might affect the
findings and conclusions ofthis study.
The main emphasis of this study has been on resources with suffcient reliability characteristics,
which are expected to be technically feasible (technical potential), cost-effective (economic
potential), and realistically achievable (achievable potential) durng the 20-year planng
horizon. For Class2 DSM (energy-effciency) resources, the methods used to evaluate the
2
Expenditues and savings include PacifiCorp's contrbutions to the Energy Trust of Oregon and the associated
energy savings generated by those funds. All savings and capacity infonnation calculated at generator.
Since the Energy Trust of Oregon is responsible for the planning and delivery of Class 2 DSM resources in
Oregon, potential for these resources are exclusive of Oregon.
PaclflCorp.- Assessmentof Long- Tem?,System- Wide Potential ES-1
Figure 6. Class 1 DSM. Rocky Mountain Power Terrtory Supply Curve
(CumulativeMW in 2027)
æ
g!
ti
~o't
~
§
$160
DLC PC Direc load contrl for aIr condllning
DLC COM: Direc load control for large commrcal customers
1£8: Thermal enery storage
.
lES.
DLCCom
$120
$100 CapacityValu: S98/kW-yea---- ----- - - - - - --- -- --- --- --;-
DLCAC
$80
$60'
$40
.
Irrgation
$20
$0
o
I . I i' T
20 40 80 80 100 120 140 160 180 200 220 240 260 280
Cumulate Savings (MN)
Figure 7. Class 1 DSM: Pacific Power Territory Supply Curve (Cumulative MW in 2027)
$160
-el\(I~
~ti
1i8'tGl.i:
l
$140
DLCAC: Direc bad contrl for air conditinIng
DLC CO: Direc load control for large commcil customers
1£S: Thermal energy storage
lE~
DLCCo
$120
$100 .
DLCAC
$801
$60 Capacity Value: $58W-year- - --- -- - - - -- - - -- -- --- -- -- - - --
$4û
.
Irngaton
$20
$0
o 10 15 20 25 30 35
Currlative Savings (MN
40 45 505
PacifiCorp -Assessmentof Long-Term, System-Wide Potential
Irrigation
A program targeting irgation is an ideal option to reduce summer peak due to the coincidence
of irgation pumping with mid-afternoon sumer peak. PacifiCorp's curent irrgation load
control program in Idaho is a scheduled control program; customers subscribe in advance for
specific days and number of hour when their irgation systems wil be tted off. Load
management is executed automatically based on a pre-determined schedule set though a timer
device. Although a total of 100 MW of irgation loads are contracted for management under this
control proram, less than half are available at any time due to the alternating schedules of
program participants. III the Northwest, the Bonnevile Power Adminstration (EPA) has ru a
pilot irgation program (on a dispatched rather than scheduled basis), and Idao Power has
implemented a program simlar to PacifiCorp's scheduled control program. In 2007, PacifiCorp
began piloting a limited-scope45 MW dispatchableprograin in addition to its scheduled control
option. Presuming it will be successful, this analysis asswnes tht, in the futue, half of the
participants wil sign up for the dispatchable control option and half wil sign up for the
scheduled control option.
Techncally, it is assumed all irgation loads are eligible for this program, excepting half of the
Oregon load (which is horintal pumping and not suitable for this offering). This results in a
technical potential oB08 MW (Rocky Mountain Power) and 108 MW (pacific Power).
In temiS of program paricipation, both PacifiCorp's and Idao Power's scheduled control option
program have had solid paricipation rates: 35% and 25% of eligible load, respectively. This
analysis assumes PacifiCorp ca increase the paricipation rate in Idao to 50% and wil reach
25% in other states, where pumps tend to be smaller and loads are distributed across more
customers. Assuming one-hair of paricipants are on a scheduléd control program, during any
one event, only 75% of the load wil be available. These factors lea to a market potential
estimate of20 MW for Pacific Power (~1 % of2027 territory peak). For Rocky Mountain Power,
104 MW is available, which includes the 81 MW of expected 2007 achievements (78 MW in
Idaho and 3 MW in Uta).
Due to load distrbution the majority of this is expected to wine from Idaho (93 MW. The
PacifiCorp forecasts of irgation loads expect an overall reuction of approximately 10% over
the next 20 year, which is accounted for in the estitnate of potential in 2027.
Table 17. Irrigation: Technical and Market Potential (MW in 2027)
Rockv Mountain Power Pacific Power
Sector Technical Market Market as % Technical Market Market as %
Potential Potential of 2027 Peak Potential Potential of 2027 Peak
Residential
Commercal
Industnal
Iròoatlon
Total
30.3
30.3
104.2
104.2
21.3%
1.3%
107.9
107.9
20.2
3).2
&1%
0.4%
PacifiCorp -Assessment of Long- T erm, System-Wide Potential 36
Figure 14. Irrigation: Market Potential by State (MW in 2027)
Caorna ,;,';;'
Idaho :~.~$l;~t:tt:''l:i,,!\~~~S:~t:~r,:Of~:';'.' ;:~?:.~'~~:"~i ~~~~-'C~,a..~i~ '",('l~t:.:::~J¡'i:ti ~i1l~,:.!~~:,~"Zj~;';;~:tf.'\.i ~":X:~~,:~~f:;
Oregoni~iri";
Uta ~~:Y.r'U:-~~
Washington :.t:.iH
Wyomig
20 40 60
MW (in 2027)
80 100
I (J lriigation I
Costs for the irgation program include $400,000 for upfront program costs, $1,000 for installed
technology with a life of seven year, $500 for marketing to new customers, and $10/kW for
ongoing maintenance and communication systems based on Rocky Mountain Power's
experience. Although PacifiCorp curently pays $l1/kW-year for incentives (2006 progr
year), paricipation level assumptions are based on a higher incentive amount of $20IkW-year in
recognition that greater penetration wil require higher incentives and the emergence of the
dispatchablecontrol option is expected to increase the value of the control to PacifiCorp.
Table 18 displays the resulting levelized costs for the irgation. With an expected cost of
$47/kW-year and $501kW -yea (Rocky Mountain Power and Pacific Power terrtories,
respectively), ths program option passes all economic screens. The high achievable scenario
assumes a 20% increase in paricipation and a 50% increase in incentives. With a high
achievable cost of $67/kW-year and $70/kW-year (Rocky Mountain Power and Pacific Power,
respectively), irgation in the Rocky Mountain Power territory passes all economic scenarios.
Table 18. Irrigation: Levelized Costs and Scenarios
MW Leveiize Economic ScreenPotential d Cost Low Base High
Rocky Mountain Power
Excted Achievable 104 $47 Pass Pass Pass
High Achievable 125 $67 Pass Pass Pass
Pacific Power
Excted Achievable 20 $50 Pass Pass
High Achievable 24 $70 Pass
PacifiCorp -Assessment of Long-Term. System-Wide Potential
Table 24 also shows the high achievable scenario, assumg all respondents indicating a "very
positive" reaction to the program and one-half of those indicating "somewhat positive" can be
convinced to participate, resulting in 29% of customers, or 38 MW for Rocky Mountain Power
and 15 MW for the Pacific Power terrtory. Consistent with all other programs, the high
achievable scenaro is assumed to have a 50% increase in incentives; so costs rise to
$24/k W-year, which again pass all economic screens.
Table 24. Demand Buyback: Levelized Costs and Scenarios
MV Leveli Economic Screen
Potential Cost I.Base Hi
Rocky Moita Power
Exp Achievle 26 $18 Pass Pass Pass
Hi Achile 38 $24 Pass Pass Pass
Pacific Power
Expte Achievable 10 $18 Pass Pass Pass
Hi Acevle 15 $24 Pass Pass Pass
Residential Time of Use Rates
fufom1ation on TOU rates was obtained from tariffs from 60 U.S. utilities, promotional materials
used by utilities offering new TOU (or TOU with CPP) programs durng the past fiv~ year, and
several interviews with utility staff members,35 TOU rates have been offered by U.S. utilities
since at least the 197080 but the historic impacts have been quite low. hi fact, PacifiCorp ran a
TOU pilot in 2002 to 2004, which had extremely low progr sign-up (940 residential
customers at the end of 2004, with an average of 25% anual attition), despite an intensive
marketing effort.
The TOU rates developed in recent year tyically differ from those of the past in several
importnt ways. First, most new TOU rates contain three price tiers as opposed to the two-tier
rates common in many long-stading TOU programs, includig those offered by PacifiCorp.
This allows utilities to set high prices durng their highest peak periods and offer exceptionally
low off-peak prices overnight when the wst is at its lowest and supply is plentifuL. The majority
of hours are assigned a "mid-pea price that is tyically a slightly discounted version of the
stadad rate. Another change is that the duration of the peak period is tyically shorter than in
the past. Finally, the price differentials between peak and off-peak prices tend to be greater than
in the past to encourage load shifting away from the peak period. For long-stading TOU rates,
this differential averaged about 7.6 centslkWh, whereas newer programs tend to have a
differential of greater than 10 centslWh. For comparison, PacifiCorp's existing TOU rates offer
a price differential of roughly 4.5 cents/ Wh to 7.5 cents/Wh, depending on the operating utility
and the season.
35 Includes: Gulf Power, Alabama Power, Ameren, Pacific Gas and Electrc, Southern California Edison, San
Diego Gas and Electrc, and Teco Energy. Interviews with utility staff Arzona Public Servce, Salt River
Project, and Florida Power and Light.
PaclfiCorp - Assessment cf Long- Term, System-Wide Potential 46
TOU rates are assumed to be available only to the residential customer segments, and the
potential is based on the total load rather than individual end uses. The techncally feasible
portion of the load basis expected to be reduced durg peak hours is 5% based on results from
CaHfomia36 and Puget Sound Energy. The paricipation rate of the top ten hîghest.enrolled TOU
program in the eountry17 is on average 16%t yet these programs do not represent the experience
of all national programs, many of which have parcipation rates of -:1 %. If a robust marketing
effort is made in conjunction with a TOU rate design that is more than double PacifiCorpts
current TOU differential the expected participationrate is asumed to be 10%.
Table 25 shows there is 107 MW of technical potential and 11 MW of market potential in the
Rocky Mountain Power terrtory. In the Pacific Power terrtory, there is 78 MW of technical
potential and 8 MW of market, both representing less than 1 % of2027 terrtory peak.
Table 25. Time of Use Rates: Technical and Market Potential (M in 2027)
Roc Moimta Power PacificPower
Sector Techncal Maet Ma as %Technical Ma Maas %
Potential Potential of 2027 Pea Potential Potential of 2027 Pea
Reidenti 106.7 10.7 0.5%776 7.8 0.4%CoIndu
Ingaon
.~~l% ITota106.7 10.7 77.6 7.8 0.2%
Figure 18 shows Utah has the most potential, with 9 MW, followed by Oregon with nearly
6MW.
Table 26 displays the per-unit costs, using the assumptions of $400,000 in progri development
(based on 2002 PGE and PacifiCorp TOU rate program development costs3g)~ $125 in new
paricipant costs ($100 per meter and $25 of marketing), with new paricipant costs reoccurg
with anual attition of 5% (based on electrcal tumoverl9) and a 20-year measure life on
meters. Due to low per-custqmer impacts, the cost per kW"year is $166/kW-year for Rocky
Mountain Power territory and $173/kW-year for Pacific Power terrtory, which pass the
ecnomic screens. This finding is consistent with the 2005 evaluation of PacifiCorp~s TOU
36 Charles River Associates, "Impact Evaluation of the California Statewide Pricing Pilot, Final Report," March
16,2005. See also, Piette, Mar An and David S. Watson "Paricipation through Automation: Fully Automated
Critical Peak Pricing in Commercial Buildings," 2006, Lawrence Berkeley National Laboratory. Linkugel. Eric
Proceedings ofthe 2006 ACEEE Summer Study on Energy Efficiency in Buildings, Pacific Grove, CA, August
37 2006.
FERC, 2006 and R Gun, "Nort American Demand Response Surey Results" (Association of Energy
3& Services Professionals, Phoenix, A'4 February 2006).
Levelize per unit costs are drven primarly by hardware costs. Removal of upfront development reduces the
39 results by $4IW.yea.
Ths is likely a conservative estimate - PacifiCorp 2004 pilot TOU progrm experienced up to 25% annual
atttion.
PacifiCorp - Assessment of Long- Ter System-Wide Potetial 47
~~_ll~zlJ£~~~lt~~~1.~~1::~1¡. ~.~
Final Report - Volume \I
Assessment of Long-Term,
System-Wide Potential for
Demand-Side and Other
Supplemental Resources:
Appendices
Prepared for PacifiCorp
July 11 J 2007
In Collaboration with Summit Blue Consulting and Nexant, Inc.
"f:.-. \:.~~'.::\ ~~~:~Ii~i~~
_.......
quantec Raisi1ll the bill' in a1Ui/yticsnl
~ , '~'. . ~: ~ ..~~11lllfli~~\~~~¡~~ltr~i~~!ü.:~\1:4ü/,.'
Principal Investigators:
Hossein Haeri, Ph.D., Lauren Gage, Tina Jayaweera, Ph.D., Colln Elliot,
Eli Morris, Rick Ogle, P.E., Tony Larson, Aquila Velonis, Matei Perussi,
Allen Lee, Ph.D., and Ann Griffn, Quantec, LLC.
Kevin Cooney, Randy Gunn, Stuart Schare,
Adam Knickelbein, and Roger Hil, Summit Blue Consulting
Terry Fry, Mike Boutross, and Pranesh Venugopal, Nexant, Inc.
~:eŠmJQSIQlÆ~rgQ'JlCRÃ~Reim~~otëílià1Lin~l¥oi658ro90i~dPC:m
Quantec Offces
720 SWWashlnglon, Sulto 400
Poiand, OR 97205
[phone]; [phone] faww.quatecllc.com
1722 14th St., Sulle 210
Boulder, CO 80302
(303) 998-102; [phone] fax
28 E. Main St., Sulle A
Reedsburg, WI 53959
[phone]; (608) 524~3B1 fa
~Pi'"\%,~-
3445 Grant Sl
Eugene, OR 97405
[phone]: [phone] fax
20022 Cove CIrcle
Huntington Beach, CA 92646
[phone]
Table of Contents: Volume I
Acknowledgements...........................................................................................................xiii
Executive Summary tiE........................,.............................................ii............I1..... ES-1
Overvew..................................,..................."'........................................................................'E-1
Sumar of the Results................................................................................................. ES-2
Resource Acquisition Costs...........................................................................................ES-9
Resource Potential Under Alternative Scenaros...................................... .....................ES-9
1. Introduction ..........................11..........................................li..................I1.....".1
Background ..........................................................................................................................1
Study Scope and Objectives ................................................................................................2
General Approach...... ....... ........................ ...... .... ................... ..... .... .......... .................... ....... 5
Organition of the Report ..............................................................,......................................8
2. Capacity-Focused Resources (Class 1 and Class 3 DSM) ...................9
Scope of Anysis ......."...........................................................................................................9
AssessmentMethodology..................................................................................................11
Resource Potential.............................................................................................................18
Resource Costs and Supply Cures ................................. ..................................................20
Resource Acquisition Schedule .........................................................................................26
Resource Potential Under Alternative Scenaros...............................................................27
Class 1 DSM Resource Results by Program Option.........................................................28
Class 3 DSM Resource Results by Program Option.........................................................40
3. Energy-Efficiency Resources (Class 2 DSM) ...................................... 57
Scope of Analysis ......................................................,.............".,...........................................57
Resource Potential....... .................. ...... .................. .... ...... ............ ............. .......... -...... ........58
Resource Potential Under Alternative Scenaros.................................................... ...........62
AssessmentMethodology................................................................................................. 63
Class 2 DSM Detailed Resource Potential........................................................................ 85
4. Education and Information (Class 4 DSM) ......................................... 95
Scope of Analysis ..............................................................................................................95
Potential and Costs ..........."...........,.....................................................................................99
PacifiCorp _ Assessment of long*Term, System-Wide P~tentlal, Appendices
5. Supplemental Resources ...................................................................101
Assessment Methodology ................................................................................................ 101
Scope of Analysis ........................................................................................................... 101
Resource Potential........................................................................................................... i 02
Resource Acquisition Schedule .......................................................................................104
Resource Potential Under Alternative Scenaros............................................................. 106
Combined Heat and Power Results .......................................................................................1 07
On-Site Solar Results.......................................................................................................116
Dispatchable Standby Generation Results....................................................................... 124
6. Effects of Structural Changes....w..........................."..............................129
Overview..........................................."....................................................................'...................129
Macroeconomic Strctual Changes ................................................................................ 130
Technological Changes....................................................................................................131
Public Policy and Regulation..........................................................................................J32
PaclfiCorp -Assessment of Long-Term, System-Wide Potential. Appendices
Table of Contents: Volume II
Appendix A-1. Surveys Results. Overview..................................................A-1
CI and CLI Survey Sunimaries ................................................................................... A-I
Appendix A2. Survey Results. Detailed ......................................................A-7
CI Surey Results: Overall .................................................................................................A-7
CHP Surey Results: Overall........................................................................................A-4l
Appendix A3. Survey Instruments ...................,,".............II..1I11............u;............A-55
CI Surey Instrent..,.iI.................................~........"......................................................A-5.7
ClI Survey Instrnent.................................................................................................A-73
Appendix By1. Capacity-Focused Resource Materials: Detailed
Assumptions by Program Option.................................................................a.1
DLC Residential- Air Conditionig Only...................................................................... 1
DLC Residential- Air Conditioning and Water Heating................................................B-3
DLC CommerciaL............................................................................................................B-6
Irgation ............................................................1.....................................................~...,...,..B-14
Therinal Energy Storage ................................................................................................B-15
Cuilable Load ............................................................................................................B-17
Deinand Bidding............................................................................................................B-21
Residential Tiine of Use Rates ......................................................................................B-25
Residential and Small Commercial Critical Peak Pricing.............................................B-26
Commercial and Industral: Critical Peak Pricing......................................................... B-27
Real Tiine Pricing... ........ ......................... .......................... ....... ....... ............ ...... ... .........- 1
Appendix B2 . Capacity-Focused Resource Materials: Load Basis and
Cali bration... . ........8811..11. .... ....... II..".. a..... Sil..... 8 ........II..C.. ... a a... ... .... ..... ..c...... II.. .....8-35
Califomia.......................................................................................................................B-35
Idao ....,.i'.ii..............~.....................................................................................................".....".B-38
Utah.". ..........................,.,...................."..,...............................................................,.....~.........l....,.B~42
Oregon ..........................................................~......."........................................ ........................".B-40
Washington................................................................................................................................B-4
Wyoming ..........................,.................................................................................................~.B-46
All States Total..............................................................................................................B-49
PacifiCorp -Assessment of Long-Tenn. System-Wide Potential. Appendices iii
Appendix B-3. Capacity-Focused Resource Materials: Detailed
Program Results - Year and Market Segment (Summer)..........................8-53
DLC _ RE _ AC and Water Heat..................................................................................B-53
DLC. RE - AC....................................."..........................................,....................................B-55
DLC - Cominercial ........................................................................................................B-57
Irgation....................................................................................................................... B-59
Therm Energy Storage ......."............,.."'............"..............................................................B-61
Curilable Load ............................................................................................................B-63
Time Of Use Rates.........................................................................-....................................B-67
Appendix B4 . Capacity-Focused Resource Materials: Winter Results....6-75
Class 1 DR Programs......................................................................... ............................B-75
Class 3 DR Programs ........................................................................................................... B-76
Appendix C-1.Technical Supplements: Energy Efficiency Resources.
Measure Descriptions ............................................................................C:1..
Residential Measure Descnptions ...................................................................................C-1
Residential Emerging Technology ................................................................................C-11
Coinmerial Measure Descnptions................................................................................ 1 3
Coinmercial Emerging Technologies ............................................................................ C-28
Industral Measure Descnptions ....................................................................................C-29
Appendix C2 . Technical Supplements Energy Efficiency Resources.
Market Segmentation ..................................................................................C-33
Baseline Forecasts .........................................................................................................C-35
End Use Satuations and Electric Shares .............................. .........................................C-4 7
End-Use Consumption EstI111ates ..................................................................................C-62
Appendix C3 . Technical Resources: Energy Efficiency Resources.
Measure Inputs............................................................................................C-63
Appendix CA . Technical Resources: Energy Efficiency Resources.
Class 2 DSM Decrement Analysis.....Ii............u........................u..Il.....,It.........C-93
Appendix D. Technical Supplements: Class 4 Resources..........................D-1
Descnptions and References Dr Reviewed Program... ............... ...................................D-l
PaclfiCorp -Assessment of Long-Term. System-Wide PotentiaL. Appendices iv
Appendix E-1. Technical Supplements: Supplemental Resources
CHP ...... ......a.... .... ii1...........~..lI.............................................a.".."................................. E-I
Site Solar...... ...I...............Ii.....I:......,.ir........I....~ii.................,.............,................... E.65
Appendix E2 . Technical Supplements: Supplemental Resources On-
Appendix E3 . Technical Supplements: Supplemental Resources
DSG......... '1:1.. ..... ..... ..... ..1. IJlII" ...." ..... ...,. I.. I. ..... "co. IItrl .....11.... ...... 1..."...~i .......tr...... .... ....... E-79
Appendix F. Simulations & Home Electronics............................................. F-1
Scope......................................................................................................................................,.. F-l
Methodology.................................................................................................................. F-38
Results............................................................................................................................ F-42
Appendix G. Treatment of Externalities... ............................ ....................... 0-1
Introduction and Purose................................................................................................. 0-1
Objectives and Approach.................................................................................................G~ 1
Findigs .........................................................................................................Il.............................................Il...,.G-2
PacltCorp -Assessment of long-Tenn. System-Wide PotentiaL. Appendices
Irrigation
Table B.9. Program Basics
Program Name irrigation
Customer Secors Eligible Irrgation only
End Uses Eligible for Program Irrgation Pumping
Customer Size Requirements, if any All irrgation customers
Summer Load Basis Top 40 Summer HoursWinter Load Basis No Winter
Table B.10. Inputs and Sources not Varyng by State or Sector
Inputs Value Sources or Assumptions
Annual Attriton (%) 5% Based on changes in elecrical service
Annual Administrative Costs 15% All resource classes assume admin adder of 15%
(%)
Technology Cot (per new
partcipant)
Marketing Cost (per new
partdpant)
Incentives(annual costs per
partcipating kW)
Incentives (annual costs per
partidpating kW)
Overhead: First Costs (2007$)
Technical Potential as % of
Load Basis
Program Participation (%)
Event Partpation (%)
per Customer Impacts (kW)
$1,000
$500
$20
$10
$400,000
100%
Varies by
Secor
Technology costs assume $1000 per new participant for installation costs
Both Idaho Power and PacifiCrp marketing costs are approximately $500
per new partcipant
Idaho Power currently pays $16/kW/year; although Rocky Mountain Power
pays S111cW, hIgh program par/cipaUoii raies and acptance by
customers can be attined only wIth higher Incentives, particularly In
diverse georaphic regions
Ongoing Maintenance and Communications (per KW
Standard Program OevelopmentAsumption, Including necessary Internal
labor, research and JTlblllIng syslem changes
Assumes all loads can be controlled
25%Idaho Power and Paci!Corp have participation rates of 25% for the
scheduled program. Paclforp has signed up an additional 45 MI for the
OLC optin, w~lc totals 35% of the load basis. Assumes thaI more load
Is available (50%)
Assumes that one-half of partcipants wil be on scheduled proram where
participants choose 2 days of each week to schedule reductons during
peak times (50% event participation for 50% of program Is an average of
75% event participation).
Product of technical potential and average kW of customers greater than
250 kW (PC database of C&I customers)
75%
PacifiCorp -Assessment of Long-Term, System-Wide Potential, Appendices
Residential Time of Use Rates
Table B.20. Program Basics
Program Name Time Of Use Rates
Customer Sectors Eligible All Residential Market Segments
End Uses Eligible for Program Total Load of All End Uses
Customer Size Requirement, if anv Residential
Summer Load Basis Top 40 Summer Hours
Winter Load Basis Top 40 WInter Hours
Table B.21. ¡n¡mts and Sources not Varying by State or Sector
inputs Value Sources or Assumptions
Annual Attrition (%1 5% Consistent with PacißCorp electric turnovers. Rate of 3.5% reported by
Rosemary Morley of FPL.
AD resource classes assume admin adder of 15%Annual AdministrativeCosts
('Y)
T ecnologyCost (per new
parpant)
Ma~eting Co~ (per new
partpant)
Incentives (annual costs per
partlpant)
Overhead: First Costs (2007$)
$100
$25
$400,000
Technical Poientiai as % of
Load Basis
Program Partcipation(%)
Event Participation (%)100%
per Customer impacts (kW)
15%
incremental cost of a TOU meter, APS and FERC 2006
$0
APS reported Incremental costs of $20.$30 per new participant, Including
ma~eiing costs and support.
Bil savings may acca for some custrs, equating to lost revenues for
the utliity. This analysIs assumes revenue neutrality for the utilty.
Standard Program Development Assumption, including necessary internal
labor, research and ITlbiling system changes
California residential pricing programs results from CA SPP, fixed TOU
show SOLO average peak demand reduced (Charles River Associates,
2005). Results from Puget Sound Energy's cacelled TOU program are
similar.
APS has the highest TOU enrollment of er utilit in the countr at nearl
400,000 participants or 45% of residential customers (Chuck Miesner,
APS, 207; FERC report of 2006). The partcipation rate of the top 10
hlghes~enrolled TOU programs In the countr is on average 16%
(excluding the mandatory rates by PS Oklahoma. Yet these programs 00
not represent the experience of all national programs; many TOU
programs around the country have participation rates of ..1 % (but many of
these are legacy prorams that are not being promoted). Even among the
top 10 highest enrollment programs (according to FERC), half have single
digit partcipation rates. if a reasonabie effort is made, the reasonable low
range mlght be 2%, which is the lowest participation rate among the top 10
programs, and an expected participation rate of 10%.
There are no "events. with TOU rates. Partcipation can be viewed as
100%.
Product of technical potential and average kW of customers based on load
basIs. Consistentwith national ~udies.
5%
10%
Pacifiorp-Assessmentof Long-Tern, System-Wide Potential, Appendices 8-24