20070928Yankel direct.pdf

W. MARCUS W. NYE
RANDALL C. BUDGE
JOHN A. BAILEY, JR.
JOHN R. GOODELL
JOHN B. INGELSTROM
DANIEL C. GREEN
BRENT O. ROCHE
KIRK B. HADLEY
FRED J. LEWIS
MITCHELL W. BROWN
ERIC L. OLSEN
CONRAD J. AIKEN
RICHARD A. HEARN, M.
DAVID E. ALEXANDER
LANE V. ERICKSON
PATRICK N. GEORGE
SCOTT J. SMITH
STEPHEN J. MUHONEN
BRENT L. WHITING
JUSTIN R. ELLIS
JOSHUA D. JOHNSON
JONATHON S. BYINGTON
DAVE BAGLEY
CAROL TIPPI VOLYN
THOMAS J. BUDGE
CANDICE M. MCHUGH
LAW OFFICES OF
RACINE OLSON NYE BUDGE Be BAILEY
CHARTERED
201 EAST CENTER STREET
POST OFFIC E BOX 1391
POCATELLO, IDAHO B3204-1391
TELEPHONE [phone]
FACSIMILE [phone]
www.racinelaw.net
SENDER'S E-MAIL ADDRESS: elo(9)racinelaw.net
September 27 2007
Jean Jewell, Secretary
Idaho Public Utilities Commission
472 W. Washington Street
Boise, Idaho 83702
Re:
Dear Mrs. Jewel:
P A C-O 7-
BOISE OFFICE
101 SOUTH CAPITOL
BOULEVARD, SUITE 20B
BOISE, IDAHO 83702TELEPHONE: [phone]
FACSIMILE: [phone]
IDAHO FALLS OFFICE
477 SHOUP AVENUE
SUITE 203A
IDAHO FALLS, ID 83402TELEPHONE: [phone]
FACSIMILE: [phone]
COEUR D'ALENE OFFICE
2S0 NORTHWEST
BOULEVARD, SUITE 106A
COEUR D'ALENE, ID 83814TELEPHONE: [phone]
ALL OFFICES TOLL FREE
[phone]
LOUIS F. RACINE (1917-2005)
WILLIAM D. OLSON, OF COUNSEL
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Enclosed for filing please find nine copies of Direct Testimony of Anthony J. Yankel (with
exhibits), Mark Mickelsen, and Stanley G. Searle.
Thank you for your assistance.
ELO
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ERIC L. OLSEN
Eric L. Olsen ISB# 4811
RACINE, OLSON, NYE, BUDGE &
BAILEY, C~TERED
O. Box 1391; 201 E. Center
Pocatello, Idaho 83204-1391
Telephone: [phone]
Fax: [phone]
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Attorneys for the Idaho Irrigation Pumpers Association, Inc.
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF)
ACIFICORP DBA ROCKY MOUNTAIN
POWER FOR APPROV AL OF CHANGES TO
ITS ELECTRIC SERVICE SCHEDULES
CASE NO. P AC-07-
IDAHO IRRIGATION PUMPERS' ASSOCIATION, INC.S NOTICE OF SERVICE
You will please take notice that IDAHO IRRIGATION PUMPERS' ASSOCIATION , INC.
by and through their attorneys of record, served the Direct Testimony and exhibits of Anthony
Yankel, Mark Mickelsen, and Stanley C. Searle upon the parties to this action by providing said
documents to the following individuals in the manner specified in the attached Certificate of
Service below.
Respectfully submitted this 27th day of September, 2007.
RACINE, OLSON, NYE, BUDGE &
BAILEY, C RED
ERIC L. OLSEN
Attorneys for the Idaho Irrigation Pumpers
Association, Inc.
CERTIFICATE OF SERVICE -
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 2ih day of September, 2007, I served a true
correct and complete copy of the Direct Testimony of Anthony Yankel (with exhibits),
Mark Mickelsen, and Stanley C. Searle to each of the following, via U.S. Mail postage
prepaid, e-mail or hand delivery:
Jean Jewell (9 copies)
Idaho Public Utilities Commission
472 W. Washington Street
O. Box 83720
Boise, Idaho 83720-0074
E-mail: iean.iewell~puc.idaho.gov
S. Mail
James R. Smith
Monsanto Company
O. Box 816
Soda Springs, ID 83276
E-mail: iim.r.smith~monsanto.com
u.S. Mail
Maurice Brubaker
Katie Iverson
Brubaker & Associates
17244 W. Cordova Court
Surprise, AZ 85387
ki verson~sconsul tbai. com
S. Mail
Anthony Yankel
29814 Lake Road
Bay Village, OH 44140
E-mail: tony~yankel.net
S. Mail
Idaho Irrigation Pumpers
Association, Inc.
c/o Lynn Tominaga
O. Box 2624
Boise, ID 83701-2624
E-mail: lvnn tominaga~hotmail.com
u.s. Mail
CERTIFICATE OF SERVICE - 2
Randall C. Budge
Racine, Olson, Nye, Budge
& Bailey, Chtd.
O. Box 1391
Pocatello, Idaho 83204-13 91
Hand Delivery
Brian Dickman
Rocky Mountain Power
201 South Main, Suite 2300
Salt Lake City, Utah 84111
Email: brian.dickman~pacificorp.com
Overnight delivery
Dean Brockbank
Justin Brown
Rocky Mountain Power
201 South Main, Suite 2300
Salt Lake City, Utah 84111
E-mail: dean. brockbank~pacificorp.com
E-mail: justin.brown~pacificorp.com
S. Mail
Tim Buller
Agrium, Inc.
3010 Conda Road
Soda Springs, Idaho 83276
E-mail: tbuller~agrium.com
S. Mail
Conley E. Ward
Michael C. Creamer
Givens Pursley LLP
608 W. Bannock Street
O. Box 2720
Boise ID 83701-2720
E-mail: cew~givenspursley.com
S. Mail
Dennis Peseau, Ph.
Utility Resources, Inc.
1500 Liberty Street S., Ste. 250
Salem, OR 97302
E-mail: dpeseau~excite.com
S. Mail
Scott Woodbury
Deputy Attorney General
Idaho Public Utilities Commission
472 W. Washington (83702)
O. Box 83720
S. Mail
CERTIFICATE OF SERVICE - 3
Boise ID 83720-0074
Brad M. Purdy
Attorney at Law
2019 N. 1 ih Street
Boise ID 83702
Kevin B. Homer, Esq.
1565 South Boulevard
Idaho Falls ID 83404
CERTIFICATE OF SERVICE - 4
S. Mail
S. Mail
1\/C
~....
l\t.
.~"
ZOOl SEP 28 AM 10: 0 I
IDAHO PUBLIC
UTiliTIES COMMISSIQt,
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER FOR
APPROVAL OF CHANGES TO ITS
ELECTRIC SERVICE SCHEDULES
CASE NO. P AC-07-
IDAHO IRRIGATION PUMPERS
DIRECT TESTIMONY
ANTHONY J. YANKEL
SEPTEMBER 28, 2007
PLEASE STATE YOUR NAME, ADDRESS, AND EMPLOYMENT.
I am Anthony 1. Yankel. I am President of Yankel and Associates, Inc. My
address is 29814 Lake Road, Bay Village, Ohio, 44140.
WOULD YOU BRIEFLY DESCRIBE YOUR EDUCATIONAL
BACKGROUND AND PROFESSIONAL EXPERIENCE?
I received a Bachelor of Science Degree in Electrical Engineering from
Carnegie Institute of Technology in 1969 and a Master of Science Degree in Chemical
Engineering from the University of Idaho in 1972. From 1969 through 1972, I was
employed by the Air Correction Division of Universal Oil Products as a product design
engineer. My chief responsibilities were in the areas of design, start-up, and repair of new
and existing product lines for coal-fired power plants. From 1973 through 1977, I was
employed by the Bureau of Air Quality for the Idaho Department of Health & Welfare
Division of Environment. As Chief Engineer of the Bureau, my responsibilities covered a
wide range of investigative functions. From 1978 through June 1979, I was employed as the
Director of the Idaho Electrical Consumers Office. In that capacity, I was responsible for all
organizational and technical aspects of advocating a variety of positions before various
governmental bodies that represented the interests of the consumers in the State ofIdaho.
Since 1979, I have been in business for myself. I am a registered Professional Engineer.
have presented testimony before the Federal Energy Regulatory Commission (FERC), as
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Irrigators
well as the State Public Utility Commissions of Idaho, Montana, Ohio, Pennsylvania, Utah
and West Virginia.
ON WHOSE BEHALF ARE YOU TESTIFYING?
I am testifying on behalf of the Idaho Irrigation Pumpers Association (lIP A).
WHAT ISSUES WILL YOU ADDRESS IN THIS PROCEEDING?
I will address the following issues in this case:
Inequities ofthe present Revised Protocol interjurisdictional allocation
methodology as it punishes all Idaho customers for the system benefit
provided by the Irrigation Load Curtailment Program;
The lack of representation of Irrigation Load Curtailment customers in the
Company s load research program results in excessive costs being
allocated to the Irrigators;
The loss of the BPA credit will have a sobering impact upon both
Irrigators and Residential customers. Programs need to be developed or
better aligned with costs in order for Irrigators to take better control of
their overall costs while paying for the costs they place upon the system.
PLEASE GIVE AN OVERVIEW OF THE RECOMMENDATIONS THAT
YOU WILL BE MAKING IN THIS CASE.
Yankel, DI
Irrigators
I will make the following recommendations:
Because of the situs treatment of the curtailment credit given to Irrigators
under Schedule 72, the revenue requirement for Residential and all other
Idaho customers is increased, the more Irrigators join in the Load
Curtailment Program. I recommend that the Irrigator Load Curtailment
program be regarded as system benefit resources, and not treated as situs.
The Company s load research data does not fully reflect the level of
Irrigation Load Curtailment, and thus, the Company s cost of service study
attributes too much demand to the Irrigators and thus, increases the
allocated costs. I recommend that the Company s coincident peak data for
the Irrigators be adjusted in order to reflect the actual level of Load
Curtailment that is taking place. This adjustment increases the rate of
return for the Irrigators. I recommend that (in keeping with the
Company s proposal) that the Irrigators get no more than 2/3 ofthe
average jurisdictional percentage increase.
The present credit for Irrigation customers on Schedule 72 is considerably
below the benefit provided to the system. I recommend that this credit be
increased by $40/kW-year, in order to bring more Irrigators into the
program, benefit the entire system at a cost less than avoided cost, and to
provide an overall benefit to the system that is greater than what is
presently being realized.
Yankel
Irrigators
I recommend that time-of-day rates be established for Irrigators as an
additional option that could both benefit the system and the customers that
choose that rate.
Yankel
Irrigators
Interjurisdictional Treatment of Irrigation Curtailment Program
HOW MUCH INTERRUPTIBILITY IS THERE GENERALLY IN THE
IDAHO JURISDICTION?
Generally speaking, there is 67 MW of economic curtailment associated with
Monsanto and 95 MW of emergency interruptibility as well. The Irrigation Load
Curtailment program in the test year 2006, generally reduced peak demands by another 50
MW. This totals to 212 MW. Approximately an additional 25 MW or Irrigation Load
Curtailment was expected in 2007.
Elsewhere on the system there is approximately 189 MW of interruptible load, 97
MW of curtailable load. Additionally, the Utah Cool Keeper Air Conditioning Load Control
Program achieved an estimated maximum reduction in 2006 of90 MW . This totals to 376
MW. Although the Idaho Jurisdiction is allocated 6.3% ofthe system generation costs , it
provides approximately 36% of the megawatts available for system
interruptibility/curtailment benefits.
IS THERE A PROBLEM WITH THE DISPARITY IN THE AMOUNT OF
INTERRUPTION CAP ABILITY IN IDAHO VERSUS THE REST OF THE SYSTEM?
There would not be a problem if allocations were performed on a basis that
reflected the system benefits ofthese various interruptibility/curtailment programs. Under
I See Response to lIP A Request 1.13.2 Exhibit 11, page 10.1 lists Idaho s SG allocation factor as 6.3064%
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Irrigators
the Revised Protocol method (which is presently being used to do jurisdictional allocations
on the PacifiCorp system), interruptions and curtailments that occur to special contract
customers are treated as a system benefit. This is appropriate. However, in spite ofthe fact
that the Idaho Irrigation Curtailment program reduced peak demand by approximately 50
MW in 2006 (and was expected to provide 75 MW in 2007)3 , it is labeled as DSM and
simply allocated situs to Idaho. Thus, although the benefits of such interruptions are spread
system wide, the cost ofthe program is kept within the jurisdiction that is supplying the
system benefit. In Idaho s case, it actually increases the Idaho jurisdiction costs , while
providing the system a benefit.
HOW DOES SITUS TREATMENT OF THE IDAHO IRRIGATION LOAD
CURTAILMENT PROGRAM NEGA TIVEL Y IMP ACT IDAHO RA TEP AYERS?
The July 2007 Report prepared for the Company entitled "Assessment of
Long- Term, System-Wide Potential for Demand-Side and Other Supplemental Resources
(DSM Report) has information regarding costs and benefits of curtailment programs. It
states that there is a system benefit of $98/kW-year for a program that can reduce demand by
1 kW. Given the Idaho Jurisdiction s GS (System Generation) allocation factor of 6., this
means that for every kW of demand that is reduced because of the Idaho Irrigation Load
Curtailment program, the Idaho Jurisdiction gets a benefit from such a decrease of $6.18 ($98
x 0.063064 :::; $6.18).
3 According to the Company s Response to IPUC 24-, there will be approximately 50 MW per month
on Schedule 72A and 50 MW on Schedule 72 which is split evenly between the two curtailment
periods.
Yankel, DI
Irrigators
On the other side of the ledger are the expenses that bring about this benefit. There
are certainly some administrative costs, installation costs, and ongoing field expenses. One
ofthe most obvious expenses is the "credit" that is paid to Irrigators for participation in the
program. Currently, that credit is set at $11.19/kW-year . In the Company s filing, this
credit is treated as entirely situs, meaning that the Idaho Jurisdiction pays $11.19 (plus its
share of the other related expenses) in order to receive a benefit of$6.18. There is a net cost
to Idaho of $5.01 for every k W of demand that is saved for the system ($11.19 - $6.18 =
$5.01).
This result is completely unjust for the Irrigators who are "given" a credit and then
have their overall rates increased to cover the credit that they rightfully deserve. Effectively,
the Irrigators are taking money out of their left pocket and putting it in their right pocket in
order to pay themselves for the $98/kW-year benefit that they provide to the system. It'
even more unjust that this jurisdictional cost of $5.01 is allocated 22% to the Residential
customers. The net impact on the Idaho Residential class is that they pay $1.11 for each $98
of system benefit caused by the Irrigator and receive nothing in return
WHA T DO YOU RECOMMEND TO CORRECT THIS PROBLEM?
This is the first full general rate case in the Idaho Jurisdiction of PacifiCorp in
a very long time. Because of this, the Revised Protocol Interjurisdictional Allocation has
been around for a couple of years, but never used to establish rates in Idaho. I recommend
that for purposes of this case that this portion of the Revised Protocol be ignored and a more
4 Based upon Schedule 72, the 6 hour/day and 2 day/week option.5 ($11.19 cost - ($98 x 6.063064) benefit) x 22.2% allocator = $1.11 cost.
Yankel, DI
Irrigators
appropriate "system" treatment of these costs be utilized. Over the long-term, this defect in
the Revised Protocol should be corrected, such that it reflects the treatment of the benefit of
the Irrigation Load Curtailment program in a manner similar to the treatment of the benefit of
the Monsanto interruptible program.
UNDER THE REVISED PROTOCOL METHOD , MONSANTO IS
TREATED AS A FIRM CUSTOMER, ITS INTERRUPTIBLE LOAD ADDED BACK FOR
COST OF SERVICE PURPOSES AND A SEP ARA TE CREDIT IS GIVEN FOR THE
INTERRUPTIBILITY. SHOULD THE INTERRUPTIBLE PORTION OF THE
IRRIGATION LOAD BE ADDED BACK TO THE IRRIGATION LOAD FOR PURPOSES
OF COST OF SERVICE?
That would be in keeping with the Revised Protocol. However, unlike
Monsanto, the source of this data is less clear. There are two different sources (and thus
values) of Irrigation interruptible load. In order to be consistent, with the rest of the data, the
load to be added back to the Irrigators must come from the same load research data that
established their overall usage. I raise this concern because the interruptibility of the
Irrigators is undervalued in the load research data. Although the Company s 2006 "Schedule
72 Idaho Irrigation Load Control Progress Report" (2006 Schedule 72 Report) indicates that
the Company avoided in July on Tuesdays/Thursdays as high as 46.7 MW and on
Mondays/Wednesdays 47.5 MW (See Exhibit 301), the load research data represents far less
interruptions. If the same load research data is used to add back the interruptibility, there will
be a wash and the problem will go away. If a different source of data (i., from the 2006
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Irrigators
Schedule 72 Report) is used to add back the interruptibility portion, it is possible to attribute
load to Irrigators which does not exist.
Yankel
Irrigators
Load Research Data and Irrigator Interruptibility
DOES THE COMPANY'S LOAD RESEARCH DATA FULLY REFLECT
THE IRRIGATION LOAD CURTAILMENT PROGRAM?
No. In fact, the Irrigation load research data was not set up to reflect the
Irrigation Load Curtailment program. The load research meters for Irrigators were put in
place in 1999, long before the Irrigation Load Curtailment program went into place
HOW WELL WAS THE IRRIGATION LOAD CURTAILMENT
PROGRAM REPRESENTED IN THE LOAD RESEARCH DATA?
The Company has indicated that 18 (32%) of the Irrigation customers in its
load research sample were on the Irrigation Load Curtailment program . However, a closer
review indicates that the Irrigation Load Curtailment program was under-represented in the
2006 data, based on demand. Two of those 18 sample customers only had limited data and
this data was not used. Additionally, the load research data indicates that four of these
sample customers did not undergo interruptions in 2006. As indicated on Exhibit 302, of the
12 sample customers that were being interrupted, the following breakdown by strata
occurred:
Stratum 1
Stratum 2
Stratum 3
Stratum 4
2 customers
1 customer
9 customers
zero customers
6 See Response to IPUC Request 25.
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Irrigators
Although three of the smaller customers are represented in this sample, there are no large
(Stratum 4) customers represented.
Of most significance is that most of these sample customers are on the
Monday/Wednesday interruption schedule, and even at that, they only reflect an interruptible
load of 44.7 MW of potential interruption. In contrast to this level, the Company s 2006
Schedule 72 Report (Exhibit 301 , page 2) indicated that at the beginning of the season it had
50.8 MW of firm, scheduled resources each day. Thus, the Monday/Wednesday load
research data reflected only 88% of the potential Irrigation curtailment on the day of the
week which defined the coincident peaks in June and July. Of more concern is the
Tuesday/Thursday interruption group where the load research data only reflects 17.6 MW of
the 50.8 MW of potential of interruption.
HOW SHOULD THIS INFORMATION BE USED TO CORRECT THE
IRRIGA TION PEAK LOAD DATA?
If interrupted Irrigation load is going to be added back to the Irrigator usage in
the cost of service study, then, in order to be consistent, the interruptible data must come
from the load research. If one of the sample customers was operating around the time of a
system peak (but was interrupted), then this interruptible load should be added to the
Irrigation firm peak demand. Exhibit 303 lists the load research predicted interruptions for
the June and July peaks as 44.1 MW and 35.6 MW respectively. Exhibit 304 lists the load
research predicted interruptions for the August and September peaks as 8.8 MW and 2.4 MW
7 Response to IIP A Request 5.1 lists 18 samples being on the load curtailment program, while the other
39 were not.
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Irrigators
respectively. If the Commission decides to add back any interruptions to the Irrigators
demand (in order to be consistent with the Monsanto treatment), the Irrigation coincident
peak loads should be increased by 44.35., 8., and 2.4 MW for the summer months of
2006.
Ifthe Irrigation Load Curtailment data is going to be simply used in a standard cost-
of-service study to reflect actual usage at the hour of peak of each month, then the data
should be adjusted to reflect the fact that the load research sample does not fully represent the
extent of the interruptions on the system-the Irrigation peak loads (at sales level) in the
Company s cost of service study should be adjusted as follow:
June
July
August
September
+ 6.8 MW
- 11.1
- 28.5 MW
- 44.3 MW
In this manner, the Company s load research data and ultimately the cost-of-service study
will reflect the level of curtailment by month that was calculated to occur in the Company
2006 Schedule 72 Report.
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Irrigators
Revenue Spread To The Irrigators
WHAT DOES THE COMPANY'S FILING SUGGEST WITH RESPECT TO
THE RATE OF RETURN AND RATE SPREAD TO THE IRRIGATORS?
The Company s filing lists the rate of return for the Irrigators at 6.03%, which
is 1.05 times greater than the jurisdictional average rate of return of 5.76%. Since the filing
in this case, some errors have been addressed. After correcting these errors, Monsanto s rate
of return went up and the rate of return for other customer groups went down. The
Company s Response to Monsanto Request 9.6 now has the rate of return for Irrigators at
06%-equivalent to the new jurisdictional average of 6.07%.
IS THE COMPANY'S LOAD RESEARCH DATA APPROPRIATE TO USE
IN THE DEVELOPMENT OF THE RATE OF RETURN FOR THE IRRIGATORS?
, for two reasons. First, as pointed out above, from purely the perspective
of adequately covering the Load Curtailment program, the load research sample does not
fully reflect the curtailable load on Monday s and Wednesday , which impacts the June and
July data. For the months of August and September, (when the peaks occurred on Tuesdays)
less than 15% of the curtailable load is reflected in the load research data.
Second, there are major calibrations made to the Irrigation load research data as
follows:
June
July
August
117%
100%
107%
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Irrigators
September 144%
The weighted average calibration during these four months was 111 %, i., the sample load
research data was adjusted upward by 11 % in order to be brought in line with actual energy
usage of the entire population of Irrigators.
WHA T REVENUE SPREAD DO YOU RECOMMEND TO THE
IRRIGATORS?
Based on the above, it is obvious that there are some serious data issues
associated with the Irrigation load. These data issues all tend to lower the Irrigators' rate of
return. In spite of these issues, the Irrigators have been showing a rate of return at or above
the jurisdictional average. Company witness Griffith has proposed that Schedule 10 get 2/3
of the average jurisdictional percentage increase. Given the additional problems I have
pointed out with respect to the Company s demand data for Schedule 10, it would not be
appropriate to give the Irrigators more than 2/3 of the jurisdictional average percentage
increase as initially proposed by the Company.
Yankel, DI
Irrigators
Rate Design
WHAT IS THE IMP ACT OF THE RECENT LOSS OF THE BP A CREDIT
ON THE IRRIGATION CUSTOMERS?
In the filing, the revenue from Schedule 10 was only listed8 as $35 569 932.
There was an additional $3 834 747 collected because ofthe RMA adjustment. The BPA
credit for Irrigators listed9 in the Company s filing was $17 555 537. Thus, the Irrigators
effectively paid only $21 849 14210 . Absent any increase in this case to the Irrigators, the
Irrigators ' effective rate will jump $17.6 million or 80% above what they have been paying
Although such a rate increase is intolerable for any customer group, there are limited options
in this case that would supply a benefit similar to that of the BP A credit. Additionally, the
only other large customer class in this jurisdiction is the Residential class and it lost its BP
credit!O of$13 101 921. Instead of directly replacing the BPA credit, the Commission must
look elsewhere in order to find methods for mitigating the impact of this loss.
IF THE COMMISSION CANNOT DIRECTLY REPLACE THE BP
CREDIT, HOW CAN IT GO ABOUT MITIGATING THE IMPACT OF THE LOSS OF
THE BP A CREDIT FOR THE IRRIGATORS?
8 Company Exhibit 35, page 4
9 Company Response to IIPA Request 1.31
10 $35 569 932 + $3,834 747 - $17 555 537 = $21 849 142II Increasing the amount paid by $17 555 000 over the $21 849 000 paid in the past is an 80.
increase.
Yankel, DI
Irrigators
One of the simplest and most straightforward ways to mitigate the impact of
the loss of the BP A credit would be to provide interruption/curtailment options that are fully
cost justified. By developing appropriated interruption/curtailment programs, the Irrigators
will be given the opportunity to better control their own costs, while providing a benefit to
the system. First, I recommend that the present Irrigation Load Curtailment Credit Rider
(Schedule 72) be priced more appropriately to reflect the benefit that the Company claims to
be accruing to the system. Second, I recommend that a Time-Of-Day (TOD) rate be
established as another option for the Irrigators.
Irrie:ation Load Control Credit Rider (Company Study)
PLEASE GIVE A BRIEF OVERVIEW OF THE EXISTING IRRIGA nON
LOAD CURTAILMENT PROGRAM ON THE PACIFICORP SYSTEM.
At present Schedule 72 is the main vehicle for Irrigators which consists of
fixed/pre-scheduled times and days for interruptions of Irrigation load. There is also a pilot
program (Schedule 72A) that is a "Company Option" program that is just completing its first
season of operation. Because there is little data compiled regarding the Company Option
program, I will focus my comments on the designated day (Schedule 72) program.
Under the designated day program, there are three options/levels of interruptibility for
Irrigators:
* 6 hours/day for 2 days/week
* 3 hours/day for 2 days/week; and
* 3 hours/day for 4 days/week.
Yankel , DI
Irrigators
During 2006, approximately 91 % of the curtailable Irrigation load was under the "6 hour/day
for 2 days/week" option. Because of this, as a general matter, I will focus most of my
comments on this "6 hour/day, 2 day/week" option. The present credit under Schedule 72 for
this option varies monthly as follows:
$3.05 /kW month
$3.64/kW month
$3.49/kW month
$1.01lkW month
June
July
August
September
The total credit (assuming that an Irrigator operates each month of the summer season) is
$11.19 per kW. Although Schedule 72 has an allowance for an energy credit as well as a
demand credit, thus far, the energy credit has always been set at zero.
HAS THE IRRIGATION LOAD CURTAILMENT PROGRAM UNDER
SCHEDULE 72 ENJOYED A GREAT DEAL OF SUCCESS?
Success is a relative measure. According to the Company s 2006 Schedule 72
Report during the Irrigation Season, there was an average of 50.8 MW of firm scheduled
curtailment at the beginning of the season 12 and an average of 47.1 MW at the end of the
season. This level of curtailment is significant when compared to the jurisdictional
coincident demands used to allocate demand costs 13 during the summer months that range
from 492-666 MWs.
12 Exhibit 301 , page 2.
13 Company Exhibit 11 , page 10.
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Irrigators
However, as pointed out in the 2006 Schedule 72 Report , only 20.1 % ofthe total
available irrigation sites participated. Of more concern, the Report made the following
observation:
The reader should note that the Commission approved a ~21 % increase in
participation credits over the 2005 Program year. Despite increased
participation credits there was no corresponding increase in participation sites.
In fact participation marginally waned (9.9% decrease in avoided MW;
12.58% decrease in the number of participatinz sites; 25% decrease in the
number of participatinz customers)... While it is not entirely clear, the fact
of the matter is that the Irrigation Management Team can offer no definitive
explanation for the lower-than-expected-participation. (Emphasis added)
CAN THE CURRENT INTERRUPTIBILITY CREDIT OFFERED IN
SCHEDULE 72 IN ANY WAY OFFSET THE LOSS OF THE BP A CREDIT?
Only to a very minor extent. Both the BP A credit and the interruptibility
credit existed in 2006 for approximately 20% of the Irrigators and approximately 25% of the
Irrigation loadl5. Thus, for those customers that were already receiving the interruptibility
credit, the loss of the BP A credit is simply a loss that cannot be offset by the present
interruptibility credit. However, for the other 75% of load that was not previously on
Schedule 72, the movement to an Irrigation Load Curtailment program could help offset
some of the loss.
HOW MUCH OF THIS LOSS COULD BE OFFSET?
14 Exhibit 301 , page 1.
15 According to the 2006 Schedule 72 Report at page 2 the participating load hit a maximum of
100 132 kW during July 2006; according to Company Exhibit 30, Tab 5 , page 13, the Irrigation non-
coincident peak (fY input was 429 860 kW (374 874 assuming losses of 1.14668); thus, 26.71 %
participated (100 132/374 874 = 0.2671)
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Irrigators
That is not an easy question to answer with any precision. It must be
understood that, unlike the BP A credit, there is an offsetting cost associated with Schedule 72
that did not exist with the BP A credit. The BP A credit was simply a credit, with no
corresponding costs to the Irrigator. However, there are definite costs associated with the
Irrigation Load Curtailment program-some are tangible and some are intangible. On the
tangible side, there are clearly additional labor costs associated with restarting irrigation
equipment after an interruption and also additional labor costs associated with operating the
irrigation system on weekends or other times when the curtailed pumping activity must be
made up. There are also intangible costs such as the fact that occasionally equipment
problems arise that prevent restarting the equipment, crops could be excessively stressed and
yield/profits lowered, etc. No matter what the specific reason causing the participation to
drop in 2006 (in spite of a 21 % increase in the credit), the economics of the costlbenefit ratio
had to come into play and 12.6% ofthe Irrigators from 2005 decided not to participate in
2006.
In order to put some ballpark limits on this answer, I will assume that there is only
benefit associated with Schedule 72 and no costs to the Irrigators (in spite of the fact that
12.6% of the sites in 2006 decided that the costs exceeded the benefits). As stated above, I
will assume that 25% of the 2006 Irrigation load participated in the program. According to
the 2006 Schedule 72 Report, the total credits paid out were $925 577. If it were possible, to
induce the rest of the Irrigators to participate under the same rates as specified in Schedule
, the increase in the credit would be $2.8 million . Even assuming that this $2.8 million
16 $925 577 x (75%! 25%) = $2 776 731
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credit increase comes at no cost to the Irrigators, such an increase in the level of this credit is
a far cry from the loss of the BP A credit that amounts to $17.6 million.
ARE THE PRESENT CREDITS LISTED UNDER SCHEDULE 72
APPROPRIATE?
, from two perspectives. First, as demonstrated in the Company s 2006
Schedule 72 Report, in spite of an increase in the level of the credit, participation declined.
There is an interest in the program on the part of the Irrigators, but they are either finding a
cost/benefit ratio that is very low or one of little value to them. From a policy standpoint, it
makes little sense to offer programs that have only marginal benefits to the customers.
As pointed out above, on July 11 , 2007 Quantec issued its Report to the Company
entitled "Assessment of Long-Term, System-Wide Potential for Demand-Side and Other
Supplemental Resources" (DSM Report). In the Company s DSM Report, it was clearly
demonstrated that the benefits of the Irrigation Load Curtailment program far exceeds the
costs associated with that program (even under the Report's assumption of a doubling of the
credit paid). From a policy standpoint, it is inappropriate to have a DSM type resource with
such a large advantage to the system being under utilized by the customers because the credit
being paid is such a small fraction of the benefit being realized.
PLEASE ELABORATE ON THIS DSM REPORT.
As stated in the Executive Summary:
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Irrigators
This study s principal goal is to develop reliable estimates of the magnitude
timing, and costs of alternative DSM resources , comprised of capacity-focused
program options (defined throughout this report as Class 1 or Class 3 DSM
resources), energy-efficiency products and services (defined as Class 2 DSM
resources, and other "supplemental" resources such as solar, combined heat and
power, and dispatchable standby generation. The analysis of resource potential
in this study are augmented by an examination of the benefits of consumer
awareness and education initiatives (class 4 DSM resources) and an analysis of
how future structural changes, such as technological innovation
macroeconomic conditions, and public policy, might affect the findings and
conclusion of this study.
Thus, the DSM Report was designed to (and virtually did) cover all aspects ofDSM and
alternative resources. The Irrigation Load Curtailment program was viewed as one of only
three "firm" options that represent a Class 1 resource. Of these three Class 1 options, the
Irrigation Load Curtailment program had the lowest costs per unit of avoided capacity and in
fact these costs were calculated to be less than half of the cost of the next closest option. The
Irrigation Load Curtailment program was calculated to have a levelized cost of$47/kW-year
(based upon a $20/kW-year credit) compared to an avoided cost of capacity in the Rocky
Mountain Power region of$98/kW-year.
DOES THE QUANTEC REPORT DEMONSTRATE THE RELATIONSHIP
BETWEEN THE COSTS OF AVOIDED CAPACITY, THE LEVELIZED COST OF THE
IRRIGATION LOAD CURTAILMENT PROGRAM, AND OTHER CLASS
PROGRAMS?
Yes, it does. The Report contains a figure that demonstrates that the Irrigation
Load Curtailment program not only is far more cost effective than any other Class 1 DSM
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program, butthat the other programs have costs that are near, or actually exceed the avoided
capacity cost of $98/k W -year. The following figure from that Report is reproduced below:
Figure 6. Class 1 DSM: Rocky Mountain Power Territory Supply Curve
(Cumulative MW in 2027)
$160
DLC AC: Direct load control for air conditioning
DLC COM; Direct load control for large commercial customers140 TESc Thermal energy storage
TES
I.)DLC Com
$120
$100
fft
'1;;$80
$60
!:::!
$40
(:,
:1rnccliy \l"iuc, S9S!f,'/o' V"'T
DLC AC
...
Irrigation
$20
40 80 100 120 140 160 180 200 220 240 260 280
Cumulative Savings (MN)
WHAT COMPONENTS MAKE UP THE IRRIGATION LOAD
CURTAILMENT LEVELIZED COST OF $47/KW-YEAR FOUND IN THE REPORT?
The Report assumes a number of costs in the development of this levelized
cost figure of$47/kW-year. They include:
Standard Program Development
Installation costs
Marketing costs
On-going maintenance
Incentive Payment
$400 000 one time
000 per new participant
$500 per new participant
$10 per kW in the program
$20 per kW in the program
I do not agree with all of these costs, but at this point I only wish to address the Incentive
Payment value which is obviously contrary to what is presently being paid to Irrigators.
Even the DSM Report recognizes the fact that this Incentive Payment level is above what is
actually being paid when it states on page 37:
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Irrigators
Although PacifiCorp currently pays $ll/kW-year for incentives (2006
program year), participation level assumptions are based on a higher incentive
amount of$20/kW-year in recognition that greater penetration will require
higher incentives and the emergence of the dispatchable control option is
expected to increase the value of the control to PacifiCorp.
Without consideration of an Incentive Payment, the levelized avoided cost would be only
$27/kW-year. Given the capacity value of$98/kW-year in the Rocky Mountain Power
service area, the Incentive Payment could be $71/kW-year, before the avoided capacity cost
of $98/kW-year would be reached. If the levelized avoided cost for the Irrigation Load
Curtailment program were $98/kW-year, it would mean that the cost of this program would
be only slightly higher than the Company s levelized cost ($93/kW-year) of its Direct Load
Control program for air-conditioning, but significantly below the Company s levelized cost
($138/kW-year) of its Direct Load Control program for large commercial customers.
GIVEN THE FACT THAT THE COMPANY'S STUDY INDICATES THAT
THE IRRIGATION LOAD CURTAILMENT CREDIT COULD BE INCREASED BY A
F ACTOR OF ALMOST "7" BEFORE THE COST OF THE PROGRAM WOULD EQUAL
THE CAPACITY VALUE OF THESE INTERRUPTIONS , WHAT LEVEL OF CREDIT
DO YOU RECOMMEND IN THIS CASE?
It is clearly a loss to the system (and to the Irrigation customers in particular)
to have only 20% participation in a program that provides a savings of $98/kW -year, but only
costs the Company $27/kW-year (not counting the credit payment). Given that the present
cost of the program (less credit paid) is $27/kW-year and the avoided capacity cost is
$98/kW-year, the difference available for a credit payment is $71/kW-year. At the moment
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the credit payment is $ll/kW-year, leaving another potential $60/kW-year available for
credit payments. I recommend that in this case that 2/3 of this additional available credit
($40/kW-year) be added to the existing credit being given to the Irrigators. The total credit
would thus be $51.19/kW-year ($11.19 + $40.00 = $51.19). I make this recommendation in
part as an initial movement towards the full benefit of the program and in part as a
replacement of the BP A credit.
HOW DOES AN INTERRUPTIBILITY CREDIT OF $51. 19/KW-YEAR
COMP ARE WITH THE LOSS OF THE BP A CREDIT?
An interruptibility credit of $51.19/k W -year is on a par with, but does not
fully make up for the loss of the BP A credit. During 2006 , the BP A credit amounted to
$17.6 million. The Irrigation Load Curtailment program in 2006 (representing 25% of the
Irrigation load or an average billing demand !? of 89 808 kW) resulted in a $0.9 million
reduction to the Irrigators bill. Once again, the $17.6 million BP A credit came without costs
while the Load Curtailment credit has costs that are not addressed in this analysis. If we
assume full participation in the Load Curtailment program of the average billing demand!8 of
342 412 kW, then at a credit of $51.19/kW -year, the overall credit would be $17 528 000.
17 According to page 2 of the 2006 Schedule 72 Report, the following participation rates were realized:
June 82 653 kW; July 100 132 kW; August 95 322 kW; and September 81 128 kW.
18 According to Exhibit 30, Tab 5 , page 13 , the following non-coincident demands were realized: June
416 761 kW; July 429 860 kW; August 388 153 kW; and September 335 773 kW. The average of
these four months is 392 637 kW at input. Assuming losses at 1.14668, the average amount at sales
level is 342 412, kW.
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Irrigators
HOW DOES THE IMPACT OF A $51.19/KW-YEAR CREDIT COMPARE
WITH THE LOSS OF THE BPA CREDIT AND THE IRRIGATION LOAD
CURTAILMENT CREDIT THAT WAS IN PLACE DURING 2006?
The impact of a $51.19/kW -year credit is not as large as the summation ofthe
BP A credit from 2006 ($17.6 million) plus the existing Load Curtailment credit ($0.
million). The impact of a $51.19/k W -year credit not only falls $1 million short of the credits
received by Irrigators in 2006, but as stated before, it comes with internal costs that are not
included in this analysis-costs that many farmers did not find beneficial when the credit was
$ll/kW-year.
HOW DO THE BENEFITS OF A $51. 19/KW-YEAR CREDIT AND FULL
PARTICIPATION IN THE IRRIGATION CURTAILMENT PROGRAM COMPARE
WITH THE PRESENT CREDIT OF $ll/KW-YEAR AND PARTIAL PARTICIPATION
IN THE PROGRAM?
As a simplified example, assume that we have today 1 kW of savings at an
avoided cost rate of$98 and a cost of$38 . Thus, the present benefit to the system is a total
savings of $60. Now assume that the participation can be increased from 1 kW up to 4 kW.
The benefit is $392 ($98 x4). The cost has been increased to $78 per kW ($38 plus an
additional credit of $40), for a total cost of $312 ($78 x 4). Thus, the net benefit under the
19 $47 Company calculated costs less the additional $9 in credits that was added into this figure, but not
presently being paid.
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new rates would be a total savings of $80 ($392 - $312 = $80). This is a 33% increase over
the present net benefit to the system ($80 - $60 = $20).
HOW WOULD RATES BE DESIGNED UNDER THE ASSUMPTION OF
A $51.19/KW-YEAR CREDIT?
It may not be desirable to simply increase the demand credits each month by a
factor of approximately 4.20 because the demand credit would far exceed the present
demand charge of$4.28/kW-month. Even the increase in the credit proposed in the
Company s report from $11.19/kW-year up to $20/kW-year would run into the same
problem. Thus, a portion of the credit should be spread over the energy charge as is
presently contemplated in Schedule 72, but previously set at zero. Based upon the existing
rates, I propose that the demand portion of the credit be set at $4.28/kW during June, July,
and August with the September credit at $2.14/kW (reflecting 15 days usage)-effectively
removing the demand charge during each month. This demand credit would total
$ 14.98/kW -year (of course it would be increased by whatever percentage increase is given to
Schedule 10's demand charge in this case). The remaining $36.21/kW-year credit would be
collected in the energy portion of the credit.
For the sake of calculating the energy portion of the credit, I will assume that all
customers participate under the "6 hours/day for 2 days/week" option under Schedule 72 and
that the overall credit of $51.19/kW -year would be $17 528 000. The demand credit of
850 20421 would mean that the total energy credit would represent the remainder of
20 $51.19/ $11.19 = 4.57462\ Exhibit 35 page 4-the demand credit would equal the entire seasonal demand charge
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$11 677 ,866. Based upon 481 194 MWh of in-season usage, this translates into a credit of
2.42685 cents per kWh for all usage (of course it would be increased by whatever percentage
increase is given to Schedule 10's energy charge in this case).
For the "3 hours/day for 2 days/week" option under Schedule 72, I simply propose at
this time that the credit be set at half of the level as under the "6 hours/day for 2 days/week"
option. For the "3 hours/day for 4 days/week" option under Schedule 72, I simply propose at
this time that the credit be set at the same level as under the "6 hours/day for 2 days/week"
option.
Because this is a significant increase over the present credit level (that is not
producing as well as hoped), I would expect to get near 100% participation. Because of this
it may be appropriate to adjust the level of the credit upwards as the costs of the program in
the Company s Report were only based upon a projected participation rate of75%.
WHAT IS YOUR RECOMMENDATION WITH RESPECT TO THE
COMPANY'S OPTIONAL SCHEDULE 72A RATE DESIGN?
Schedule 72A is a good option for Irrigators and the Company. Right now the
credit given to Schedule 72A is essentially the same ($11.18/kW-year) as that given under
the "6 hours/day for 2 days/week" option under Schedule 72. I recommend that the new
level of credit for Schedule 72-A continue to mimic that of the "6 hours/day for 2 days/week"
option under Schedule 72. The demand credit should be the same as that for Schedule 72
(i., the demand charge that is in effect in Schedule 10) and the energy credit should be the
same 2.42685 cents per kWh (increased by the average rate increase for Schedule 10).
Yankel, DI
Irrigators
Irril!ation Load Control Credit Rider (Alternative Analysis)
WHY ARE YOU PROPOSING AN AL TERNA TIVE METHOD FOR
CALCULA TING A CREDIT FOR THE IRRIGATION LOAD CURTAILMENT
PROGRAM?
The Company s DSM Report lacks detail with respect to the source of some
of its assumptions and equations for developing the levelized cost of the Irrigation Load
Curtailment program. As I stated above, I am not fully in agreement with all of the cost
assumptions that were made. Therefore, I am providing an alternative analysis.
UPON WHAT ARE YOU BASING THIS AL TERN A TIVE ANALYSIS?
The Company has been operating its Idaho Irrigation Load Curtailment for
over four years. It has published detailed reports each year (Schedule 72 Reports) that
covered the operation of this program in 2003 2004 2005 , and 2006. I will base my
analysis on each of those four annual reports. The following table lists the annual program
costs (without credits) per kW avoided:
Costs Avoided kW $/kW
2003 $273 000 000 $11.
2004 $307 000 000 $9.
2005 $382 000 000 $7.
2006 $374 000 000 $7.
These are not levelized costs that are spread out over a number of years; they are simply total
expenses for the year, divided by the avoided kW in that year. It should be noted that these
figures contain a great deal of startup costs that will not be repeated as the program moves
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forward. For example, once a control devise is installed, that cost will generally not have to
occur again for that customer for a significant amount of time. Additionally, there were
many timer failures in 2005 that caused much higher than expected field expenses. Because
of the timer failure problem in 2005 , during 2006 100% of the sites that participated in the
program during 2005 were visited to inspect the equipment and identify faulty timers-once
again causing a higher than normal expense. In spite of all ofthese startup problems, the cost
of this program has dropped to less than $8/kW of avoided capacity.
HOW DO THESE ANNUAL COSTS OF LESS THAN $8/KW COMPARE
WITH THE COMPANY'S AVOIDED COSTS?
Given the avoided cost in the East end of the PacifiCorp system of$98/kW-
year, this means that there is $90/kW-year that can be spent on "participation credits" and
still be at, or below the Company s avoided cost.
HOW DOES THIS $90/KW - YEAR TRANSLATE INTO A CREDIT FOR
THE IDAHO IRRIGATION LOAD CURTAILMENT PROGRAM?
Under the "6 hour/day for 2 days/week" option, it takes 2 kW ofload (every
other day) to result in 1 kW of avoided capacity. Thus, the participation credit of $90/kW-
year would need to be split between 2 kW in order to get the 1 kW of avoided capacity. This
means that a maximum annual credit of $45/kw-year could be given under Schedule 72 for
each kW signed up to participate.
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Irrigators
However, under the new "Company option" Schedule 72A (which is presently
experiencing an equal popularity compared with Schedule 72), it does not take 2 kW of load
under contract to result in a reduction of 1 k W of actual demand. As indicated in the
Company s DSM Report, it expects to be near 100% accurate with its calling of interruptions
under Schedule 72A; and thus, the entire participation credit ($90/kW-year) could be
returned to each participant. Assuming 50% of the customers would choose the prescheduled
option of Schedule 72 and 50% would choose the Company option under Schedule 72A, this
would mean that for every 2 kW of load in the program that the Company could avoid 1.
kW of capacity (i., the event participation rate would be 75%). With an event participation
rate of75% and a $90/kW-year avoided cost margin available for an incentive, the credit
could be as high as $67.50/kW-year ($90 x 0.75 = $67.50).
BASED UPON THIS AL TERNA TIVE ANALYSIS , DO YOU
RECOMMEND ANYTHING DIFFERENT THAN THE $51.19/KW - YEAR
CURT AILMENT CREDIT THAT YOU SUGGESTED USING THE COMPANY'
REPORT?
No. Given that the "6 hour/day for 2 days/week" option under Schedule 72
would justify a curtailment credit very near the $51.19/kW year level, and given the fact that
about half of the Irrigators are preferring the Company option Schedule 72A where a
significantly higher curtailment credit can be justified, my original recommendation of a
$51.19/kW year credit holds. During the next case, when data is available regarding the
participation in the Schedule 72A option and the Company s ability to avoid demand under
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Irrigators
this option, new (and presumably higher) credits can be justified.
Yankel
Irrigators
Irrie:ation Time-Of-Dav Rate
DOES P ACIFICORP HAVE EXPERIENCE WITH TIME-OF-DA Y RATES
IN IDAHO?
Yes. There has been a Residential Time-Of-Day (TOD) rate schedule
(Schedule 36) in Idaho for the last 20 years. It has been more successful than many TOD
rate schedules. In this case there are 16 276 Residential customers on Schedule 36 out of a
total of 54 047 total Residential customers. Approximately half (47%) of the Residential
usage takes place on Schedule 36. Schedule 36 contributes less to the system peaks as
demonstrated by the fact that its contribution to the 12-coincidents peaks is only 43% of the
overall Residential contribution.
It is noteworthy that even during the summer months (when there is no alternative to
air-conditioning) that the relative usage between super-peak hours (2:00 p.m. to 8:00 p.
and average usage for Schedule 36 customers is less than that for larger Schedule
customers that have air-conditioning potentiaf2. Basically, Schedule 36 customers are
shifting a portion of their usage from the super-peak to other times.
It is noteworthy to contrast PacifiCorp s Residential TOD program with that ofIdaho
Power s Schedule 5 (this is a program limited to one geographic area with AMR metering).
According to Idaho Power s Exhibit .59 , page 1 in Case No. IPC-07-, there are only 86
TOD customers taking service under this program. Even for the limited availability area in
which Schedule 5 is offered, this is a very low participation rate. I bring up Idaho Power
22 Schedule 1, Stratum 3 customers average usage was 1 276 kWh in June, 1 396kWh in July, 1 243
kWh in August, and 1 165 kWh in September.
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Schedule 5, not as an example to follow, but in order to put Schedule 36's success into
perspective.
TO WHAT DO YOU ATTRIBUTE THE SUCCESS OF PACIFICORP'
RESIDENTIAL TOD RATE IN IDAHO?
Like any program or rate schedule, there are a variety of things that contribute
to the success ofPacifiCorp s Schedule 36 compared to Idaho Power s Schedule 5.
Historically, standard Residential rates in PacifiCorp s Idaho service area have been higher
than comparable rates in the Idaho Power service area-higher rates make alternative rate
designs more attractive. According to the 2006 FERC Form 1 ', PacifiCorp s non-TOD
Residential Schedule 1 customers paid an average of 8.39 cents/kWh, while Idaho Power
non- TOD Residential Schedule 1 customers paid an average of 5.97 cents/kWh.
Of more significance is the differential in rates between on-peak and off-peak hours.
If this differential is not sufficiently large, there is little incentive to shift usage from on-peak
hours to off-peak hours. PacifiCorp s Schedule 36's summer TOD rates23 are simply 10.
cents/kWh on-peak, and 3.7 cents/kWh off-peak, for a differential between on-peak and off-
peak of7.1 cents/kWh.
Idaho Power s Schedule 5's summer TOD rates are more complex with three tiers
(on-peak, mid-peak, and off-peak), but one can readily see the differences between this rate
and Schedule 36. Schedule 5's highest priced, on-peak rate (1 :00 p.m. to 9:00 p.) is 8.
cents/kWh. This "highest rate" is 2.5 cents/kWh less than the Schedule 36 on-peak rate and
23 All rates in this section oftestimony have been rounded to one decimal point for easy of reading.
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is almost as large as the entire differential of7.! cents/kWh in Schedule 36. Schedule 5'
lowest priced, off-peak rate (9:00 p.m. to 7:00 a.) is 4.5 cents/kWh. This "lowest rate" is
almost a penny more than the off-peak rate in Schedule 36. Schedule 5's mid-peak rate (7:00
m. to 1 :00 p.) is 6.1 cents/kWh. This mid-peak rate essentially dampens any differential
between the high and low cost hours-it is essentially a neutral time.
It is important to remember that PacifiCorp s Schedule 36 and Idaho Power Schedule
5 are voluntary/optional rates. Schedule 36 offers customers a significant choice differential
and is successful. Idaho Power s Schedule 5 offers significantly less difference between on-
peak and off-peak rates and the participation rate reflects this fact.
HOW DO PACIFICORP'S SCHEDULE 36 RATES COMPARE WITH TOD
RATES BEING DEVELOPED TODAY?
According to the Company s "Assessment of Long-Term, System-Wide
Potential for Demand-Side and Other Supplemental Resources" study, the new TOD rates
being developed are more inverted than those being offered in Schedule 36. On page 46
that DSM Report, it is stated:
The TOU rates developed in recent years typically differ from those of the
past in several important ways. First, most new TOU rates contain three price
tiers as opposed to the two-tier rates common in many long-standing TOU
programs, including those offered by PacifiCorp. This allows utilities to set
high prices during their highest peak periods and offer exceptionally low off-
peak prices overnight when the cost is at its lowest and supply is plentiful.
The majority of hours are assigned a "mid-peak" price that is typically a
slightly discounted version of the standard rate. Another change is that the
duration of the peak period is typically 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-
standing TOU rates, this differential averaged about 7.6 cents/kWh, whereas
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Irrigators
newer programs tend to have a differential of greater than 10 cents/kWh. For
comparison, PacifiCorp s existing TOU rates offer a price differential of
roughly 4.5 cents/kWh to 7.5 cents/kWh, depending on the operating utility
and the season.
HOW CAN THIS INFORMATION BE USED TO DEVELOP A TOD RATE
FOR IRRIGATION CUSTOMERS?
As pointed out above, with the loss of the BP A credit, some serious thought
must be given to mitigating the severe financial impact that could occur if nothing were done.
A TOD rate for Irrigators is a DSM type option and is an opportunity to not simply lower the
costs to the Irrigators, but to lower the overall system costs as well. Like Schedule 36, a
TOD rate for Irrigators should get its own cost-of-service treatment such that the rates and
benefits stand on their own.
TOD rates (as an option and not mandatory) are a feasible alternative for many
Irrigation customers. However, Irrigators can not be realistically expected to follow a similar
on-peak pattern as Residential customers. Instead, I recommend that something more like a
super-peak price be developed in conjunction with an off-peak price. For the super-peak
timeframe, I recommend the same 4-days per week as in the Irrigation Curtailment program
and the same 6-hours per day (2:00 p.m. until 8:00 p.
I recommend that the super-peak price be set at 15 cents/kWh and that the off-peak
price be set at 4.2 cents/kWh. These rates have been chosen in order to develop a spread of
over 10 cents/kWh between the super-peak and the off-peak and in order to remain revenue
neutral if there is no net change in consumption patterns.
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Irrigators
DOES THIS CONCLUDE YOUR TESTIMONY?
Yes.
Yankel
Irrigators
Exhibit No. 301
Case No. PAC-07-
Anthony J. Yankel
Excerpts from "Schedule 72 Idaho Irrigation Load
Control Program 2006 Credit Rider Initiative Final Report
http://www,pacificorp.com/Article/Article75535,html
20 pages
A DIVISION OF PACIFICORP
Schedule 72 Idaho Irrigation Load Control Program
2006 Credit Rider Initiative Final Report
23 October 2006
Table of Contents
Page
Background .....................................................................................................................................................................
2006 results ......................,...........................................................................................................................,..................
Cost effectiveness analyses ....................................................................................................................................,.....
2005 cost effectiveness calculation error................
...........,..................................,...........................,..........................
Load profile data ................,............................................................................................................................................
Technical challenges....................................................................,....,..........................................................................
Measurement & Verification (M&V) processes...............,........,............................................................,................,....
Crop type analysis ...............,...,........................................................................................................................,...........
Program enhancements under consideration............................................................................................................ 16
Background
Idaho Public Utilities Commission Order No. 29209 and Order No. 29416 in Case No. PAC-E-O3-14 requires
PacifiCorp dba Rocky Mountain Power ( the Company) prepare an annual report on the Idaho Irrigation Load
Control Program (Program). Subsequent to 2003, reporting requirements include responses to the following:
1. The number of irrigation customers who were eligible to participate in the Program
2. The number of irrigation customers who entered into a load control Service Agreement
3. The number of irrigation customers who participated in the Program for the full three and one-half months
4. The number of irrigation customers who are not eligible to participate in the following year's Program
5. The total dollar amount of credits provided under the Program identified by month
6. Proposed changes and/or recommendations to improve the Program
2006 results
Table One details eligible 2006 Schedule 10 sites and customers (requirement #1)1. Table One also contains counts
of customers and sites that entered into an actual load control contract (requirement #2). Details for Program years
2003, 2004 and 2005 are provided for comparison. The data presented in Table One reflect the number of irrigation
customers and sites that participated in the Program for the full three and one-half months (requirement #3). In
2006, 20.1 % of total available sites and 23.3% of the total available customers participated in the Program. There
are zero customers NOT eligible to participate in 2007 (requirement #4).
Table One
Schedule 10 Eligible & Full-Year Participating Sites & Customers
Participant Sites Participant Customers
2003 Actual Participants 401 207
2004 Actual Participants 734 340
2005 Actual Participants 1,065 489
2006 Actual Participants 931 478
Eligible 2006 Counts 4 636 2 044
~ustomers NO~_.eligible to
'p~
!!!cipate 2.29
~____-~!~--_._-----------_._~--_.._--_
Note: based on 15 September reports
Unadjusted monthly participation credit amounts issued to 2006 Program participants are presented in Table Two
(requirement #5). The total Program participation credits ($925 577.33) represent an 8.9% increase over 2005
credits. Table Two further presents the total amount of resource under contract at the time of credit issuance. Table
Three presents a comparative analysis of credits issued for the 2003, 2004, 2005 and 2006 Program years. Here
again, 2006 values are unadjusted. The reader should note that the Commission approved a ..,21 % increase in
1 Data are reported as of 15 September 2006. This notation is important as Program participants and subsequently loads change throughout the
irrigation season as Program participation staws may change as a function of agri-business, weather, aop type and/or equipment vagaries.
Wherever possible and based on what the Irrigation Management Team has determined to be the most understandable way to communicate
quantitative Program demographics and impacts, reporting date may change. Accordingly, and throughout this report the date for the specific
quantitative result will be noted.
participation credits over the 2005 Program year. Despite increased participation credits there was no corresponding
increase in participation sites. In fact, participation marginally waned (9.9% decrease in avoided MW; 12,58%
decrease in the number of participating sites; 2.25% decrease in the number of participating customers)2. Program
management has speculated as to the reason for this trend including the following:
1. Commodity prices for agricultural product crop selection
2. Water soil moisture considerations
3. 2005 premature timer failures
While it is not entirely clear, the fact of the matter is that the Irrigation Management Team can offer no definitive
explanation for the lower-than-expected-participation. Meetings with growers were planned and executed to assess
the whys and wherefores of grower participation with regards to the load control initiative. Moreover, and during the
meetings with growers, consideration was given to discussing the potential use of a fully duplexed control
technology that would permit dispatch options at the discretion of the Company (similar to the 2001 Program
design). The result of these discussions and the pilot testing of the new control technology are discussed in the
Program Enhancements Under Consideration section.
Further, it should be noted that the 2006 Program year-end report statistics are based on the Program
transactional database. The database offers a 'snapshot' in time and does not take Into consideration Program
participants who may have elected to discontinue participation prior to 15 September. Hence, the statistical
information may, if anything, understate Program impacts (particularly, avoided kW). For example, at the conclusion
of the sign-up phase and the beginning of the dispatch period (1 June) the database recorded 50.8 MW firmed
scheduled resource. At the conclusion of the irrigation season the database indicated an average peak avoided MW
of 47., a difference of 3.7MW.
Table Two
2006 Participation Credits x Month
Credits
kW Under Contract
June
$240,705.
652.
July
$317 825.
100,131.
August
$288,371.
95,321.
September
$78,674.
81,127.
Table Three
2003-2006 Comparative Participation Credits Issuance
Year
2003
2004
2005
2006
Total Participation Credits Issued
$277 583.
$406 002.
$842 666,
$925 577.
2 Comparisons were based on the peak average difference as of 15 September.
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Table Four introduces unadjusted 2006 Program costs. For years 2003, 2004 and 2005 Program costs are
represented for comparative purposes. During 2006 100% of sites that participated in the Program during 2005 were
visited to inspect equipment and identify faulty timers. As discussed in the Technical Challenges section of this
report, during 2005 the Program experienced a high frequency of timer failure. The source of the problem was
identified as a flawed board design. Working closely with the manufacturer (Grasslin, a German subsidiary of GE)
and the local distributor (Consolidated Electric Company (CED); Logan, UT) timer change-outs were negotiated for
the 2006 season. This change-out practice had a dramatic effect on customer service as there was less than 10
customer service calls (or .c:: 1 % of total timers installed) associated with equipment failures during 2006.
Table Four
Comparative Load Control Program Costs 2003, 2004, 2005 & 2006
2003 Costs 2004 Costs 2005 Costs 2006 Costs
Cost Category (Aprll'O3-Sept '03)Oct 'O3-Sept 'Oct '04--Sept 'Oct 'O5-Sept '
Administrative support 613.665.$851.$194.
--'----
..!.~ram evaluation 135,$8,369.$377.50 $0.
Field Db admin. expenses $250,222.$239,807.$326 061.$330,802.
Pa~icipation credits $277,583.$410,325.49 $842,666.$925 577.33
Program manage!'1ent $10 992.$55 036.$54,826.$ 42 554.
Reporting $351.940.$0.$0.
,---,----"
Total Program cos!~--$550 900.$717 143.$1,224 783.299,128.
----
Note: 2003 costs over 6 month period; subsequent Program-year costs are calculated over a 12 month period
Table Five provides avoided kW statistics and participation site counts based on participation option (again note:
data are current as of 15 September). A couple of observations are noteworthy. First, the three hour option was not
a popular offer. The Irrigation Management Team met with growers and learned that the inconvenience and
associated labor of having to accommodate a three-hour interruption was not offset by the participation credit. This
was particularly noteworthy with larger growers. Nevertheless, the three hour dispatches were again important in
demonstrating 'load shaping' capabilities. If modeling being undertaken by PacifiCorp s Commercial & Trading (C&T)
organization shows that the 'load shaping' capabilities are sufficient to result in additional resource value, further
enhancements in Program design may be warranted. For example, a pricing differential could be offered to growers
to gain additional participation for a three-hour option. Bottom line, the reader should be cautioned to not unduly
dismiss the low participation in the three hour blocks. It may be that these particular options have significant and
measured value to the Company.
Second, the six hour dispatch blocks were, by far, the most popular option I representing 91 % of total Program
participation.
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Table Five
Program Impacts by Participation Option
Participation Site June Avoided July Avoided Aug. Avoided Sept. AvoidedOption Ct. kW kW kW
IMW2-8pm 411 35,708.2 43,557.7 41,605.9 34,931.
I TTH2-8pm 437 35,151.6 43 869.5 41 314.0 36,016.
.__!~~_
:3::6Pl!1m
~,~.."~__"'_"~
m '" 9~~~__""m"..","",,~3~.
".~.~__,_
35.
~~-
II MW4-7pm 9 1 268.4 1,495.4 1,417.0 818.
----~-
TT~E!!I_
~~__
.195.
---~,-
~~Z:
~------,-"
589
-----
54 ~
~----,-
II TTH 4-7 7 631.8 789.
___-
656.
_-
453.
III MWTTH 3-6pm 18 458.9 666,4 632.1 579.
lll~WTrH4-7prn 20 699.9 ,825?
_..__
?!.IU__.. 682.
IV M 2-8pm 7 2 358.4 3,052.0 2 996.7 2 850.
Totals: 931 77 568.2 95,811.7 90 860.8 77 709.
Note: data reported as of 15 September
Table Six transposes the data presented in Table Five into dispatch schedules. Table Six indicates the avoided kW
by month, control day (Tuesday Thursday) and by hour. Here also the reader should take into consideration that
Program participants who discontinued participation prior to the 15 September time horizon are NOT reflected in
these data. Hence these data understate the avoided kW that was actually realized at points earlier in the irrigation
season. Table Seven mirror images data presented in Table Six with the exception that Table Seven reflects the
Monday Wednesday control period.
Table Six
2006 Avoided kW by Month, Tuesday Thursday Gtrt. Day & Hour
Hour
Avoided kW
JUNE TuesdayfThursday Avoided kW by Hour
2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59
35,151.6 36 005.8 37 337.5 37 337.5 36,483.
7:00-7:59
35,151.6
Hour
Avoided kW
JULY TuesdayfThursday Avoided kW by Hour
2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59
43,869.5 45 133.8 46,748.7 46 748,7 45,484.4
7:00-7:59
43,869.
Hour
Avoided kW
AUGUST TuesdayfThursday Avoided kW by Hour
2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59
314.0 42,535.2 43,901.6 43 901.6 42 680.
7:00-7:59
314.
Hour
Avoided kW
SEPTEMBER TuesdayfThursday Avoided kW by Hour
2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59
36,016.9 37 137.0 38,273.1 38,273.1 37 153.
7:00-7:59
016.
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Table Seven
2006 Avoided kW by Month, Monday Wednesday Ctri. Day & Hour
Hour
Avoided kW
JUNE MondaylWednesday Avoided kW by Hour
2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59
35,708.2 37 062.8 39,031.1 39,031.1 36,408.
7:00-7:59
35,708.
Hour
Avoided kW
JULY MondaylWednesday Avoided kW by Hour
2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59
43,557.7 45,182.0 47 503.1 47,503.1 44 383.
7:00-7:59
43,557.
Hour
Avoided kW
AUGUST MondaylWednesday Avoided kW by Hour
2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59
41,605.9 43 177.6 45,304.7 45,304.7 42 316.
7:00-7:59
605.
Hour
Avoided kW
SEPTEMBER MondaylWednesday Avoided kW by Hour
2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59
34,931.9 36,346.1 37 847.1 37 847.1 35 614.
7:00-7:59
34,931.
Cost effectiveness analyses
Based upon the cost and avoided MW values above together with the $/kW-yr avoided as provided by the 2004 IRP
(and used in 2005 year end computations), cost effectiveness calculation were prepared for each of the four
standard utility industry tests:
1. Total Resource Cost (TRC)
2. Utility
3. Ratepayer
4. Participant
The Program cost-effectiveness analysis is based on the ratio of the present value of the Program s benefits to costs
and the net benefits (benefits minus costs), discounted at the appropriate rate for the various benefit/cost tests.3 The
benefits are based on the calculations as defined by the Capacity Expansion Model (CEM) and reported in the 2004
Integrated Resource Plan (IRP)4. The CEM selection of Schedule 72 at $27. 19/kW-yr was based on 2003/2004
costs to deliver the Program. Costs used in these calculations include administrative costs, contractor (field
technician and database design administration), participant credits, and associated equipment costs. The
participation credits are not included in the Total Resource Cost (TRC) test because they are a transfer payment
from the utility to the participants.
The cost effectiveness of the Program was calculated by Quantec using a simplified spreadsheet analysis. This
analysis multiplies average demand reductions for the June, July and August period as a result of customers
participating in the Program, by the estimated value of avoided demand noted above. Again, this value is
$27.19/kW-yr. This value is multiplied by 10% to account for the effect of line losses, resulting in a cost effectiveness
calculation value of $29.91/kW-yr.
3 Note that no discounting of costs or benefits was required in this analysis since all costs and benefIts occurred in 2006.
4 Chapter 8, p. 166, Table 8.
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Based on data from the Program in 2003 and 2004, PacifiCorp and Quantec examined whether energy savings,
hence revenue losses, should be included in the analysis. This analysis showed that energy use is 'shifted' rather
than 'avoided' hence zero energy savings were accrued for the Program and lost revenues are not included as a
cost and energy savings are not applicable as indicated above. Accordingly, the benefits for the cost-effectiveness
analysis are based on capacity savings alone and are presented in Table Eight: 2006 Cost Effectiveness Analyses.
As shown in Table Eight, the Schedule 72 passes the TRC Test. The Program also passes the Participant Test
since the participant incurs no costs. As a result, the benefit/cost ratio would be infinite for the Participant Test and
the value is indicated as 'N/A' in Table Eight.
Table Eight
2006 Cost Effectiveness Analyses
Test Benefits Costs Net Benefits Benefit/Cost Ratio
TRC 246,330.$374 096,$872 234,
Utility 246,330.299,673.($53 342.97)
,...., ......, ..",..,......".., ......
Ratepayer 246,330.299 673,($53 342.97)
....
Participant $925,577 ,$0.$925 577.N/A
------..----..---
2005 cost effectiveness calculation error
In the course of preparing 2006 cost effectiveness analyses it was discovered that the Company had inadvertently
made two errors in the 2005 analysis. First, the $/kW-yr. value for a 'fully dispatch able' resource was mistakenly
selected instead of the value for a 'firm scheduled forward' resource. The 'dispatchable' resource $/kW-year is
$58.35 vs. $27.19 for the 'scheduled firm' resource. Second, in performing the calculations the units were mistakenly
transposed. Instead of calculating cost effectiveness benefit stream on the basis of $/kW-yr they were calculated on
$/MW-yr. In the 2005 Year-End Schedule 72 Report cost effectiveness values were reported as those indicated in
Table Nine (below). These errors were corrected and cost effectiveness calculations recomputed. The results of
these analyses are presented in Table Ten. Noteworthy is the change in TRC values. In 2005 the TRC was reported
as 2,94. The corrected TRC value for 2005 is 3., a difference of 0.87.
Table Nine
Original Values Reported in 2005 Cost Effectiveness Analyses
Test Benefits Costs Net Benefits Benefit/Cost Ratio
RC $1 24,284 $382 117 $742 167 2.
----- --.----....-..-...----------------------.----....,-------'--..-....
Utility $1 124 284 $1 224 784 $ (100,499) 0.
--- -- -_..,- -.. ----'---'--"- --- - ,-----.- ,- -,-,
Ratepayer $124 284 $1 224 784 $ (100,499)
, ..._,.. " , " -'-_."""-'--"'-'-'-~--'-""'---"'--~--=_._--'"
Participant $842 667 $0 $ 842 667 N/A
---, -----------,....-.. -.. -..-- -..-...----.-.. -- ---- --- ...--
MMU
...., '.....'~,,'..
'n...
... ~'
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. ,
Table Ten
Corrected 2005 Cost Effectiveness Analyses
Test
TRC
Utility
Ratepayer
Participant
Benefits
455 484
455,484
$1,455,484
$ 842 667
Costs Net Benefits Benefit/Cost Ratio
$382 117 $1 073,367
-------------,-- ----.
224 784 $230 700 1.
224,784 $230 700 1.
--------------"-----"---'-'"
$0 $842 667 N/A
----------- ---'- - -.,----".."..--,
Load profile data
Throughout the control period, Company SCADA data were collected and used in preparing impact analyses.
Transmission Circuit Breaker #67 (CB-67 (Big Grassy)) aggregates four distribution substations (Hamer, Sandune,
Camas and Dubois) which were known to have a significant number of Program participants. SCADA values were
taken and logged at 120 second intervals. Log files from CB-67 were culled, data manipulated and subsequently
plotted for the July August period. A pivot table was prepared and data averages for day-of-week as well as for
control vs. non-control periods were also calculated.
Illustration One (Schedule 72 Idaho Irrigation Load Control-Average Daily Load CuNe: Control vs. Non-Control
Periods for July August (CB 67-Big Grassy) depicts (1) the average for all control days (Monday through
Thursday, inclusive) and (2) the average for all non-control days (Friday through Sunday, inclusive). In addition to
the load control dispatch, what is noteworthy is the load shifting effect as depicted in the difference between control
and non-control days particularly during the non-dispatch hours. The reader will note that this 'gap' is wider in the
evening and early morning hours. It is hypothesized that this trend in the 'gap' is a function of growers scheduling
irrigation turns to minimize the effects of moisture loss resulting from transvaporation which, of course, is greater in
the heat of the afternoon. Further note that the 'gap' narrows in the afternoon and in early evening hours.
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Illustration One
Schedule 72 Idaho Irrigation Load Control-Average Daily Load Curve:
Control vs. Non-Control Periods for July & August (CB 67-Big Grassy')
40.
35.
30.
25,
~ 20.
15.
10.
I-cuI. Days (Moo- Th) -AD Noll-C1r1 Days (FriI, Sat.S"..) I
Illustration Two (Schedule 72/daho Irrigation Load Control-Daily Load Curve: Control Average Control Dispatch
Schedule (M/Wvs. TTH) Averages (CB 67-Big Grassy)) plots Big Grassy 120-second interval load data by the two
principle control periods (M/W and TffH). The overall average for all control days during the '06 July/August period is
also plotted in Illustration Two. Highlighted is the six-hour dispatch block of the 'Dispatch Event'
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Illustration Two
Schedule 72 Idaho Irrigation Load Control-Daily Load Curve:
Control Average & Control Dispatch Schedule (MJW vs. TTH) Averages (CB 67-Big Grassy)
40.
35.
30.
25.
~ 20.
15.
10.
!-Avg. MonlWed C1!1 Days -Avg. Tuesffhur CM Day. -Avg Aft C1!1. Days I
Illustration Three (Schedule 72 Idaho Irrigation Load Control-Daily Load Curve: Individual Control Day-of-Week &
Overall Average Control Days) plots Big Grassy 120-second interval load data by individual day-of-week (clrl days).
Average daily control plots are also included in Illustration Three. Highlighted is the six-hour dispatch block and the
impacts as a result of the 'Dispatch Events . Tuesday recorded the greatest avoided demand than any other dispatch
day. This finding was rewarding as, on average, the Company experiences the greatest demand on Tuesday. The
reader should note that while the Company works hard to balance dispatch loads across all dispatch days, there is
equal attention to accommodate grower preference for a particular dispatch option.
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Illustration Three
, Schedule 72 Idaho Irrigation Load Control-Daily Load Curve:
Individual Control Day-ot-Week & Overall Average Control Days (CB 67-Big Grassy')
40,
35.
30.
25,
~ 20,
15.
10.
MoooO)/ - . . - - Tuesday - - - - - Wednesday - - - - - Thursday -Avg, MonlWed -Avg. TuelThur -Avg. All C\I1. Days I
Illustration Four (Schedule 72 Idaho Irrigation Load Control-Daily Load Curve: Control Average vs. Non-Control Days
(CB 67-Big Grassy)) plots Big Grassy 120-second interval load data by (1) individual non-control day-ot-week, (2)
average tor all non-control days and (3) the average tor all control days. Highlighted is the six-hour dispatch block and
the resulting impacts ot non-control days,
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Illustration Four
Schedule 72 Idaho Irrigation Load Control-Daily Load Curve:
Control Average vs. Non-Control Days (CB 57-Big Grassy)
~ 20
:;;
Sunday - - , , , Friday' - - - . Saturday -Non-CuI. Day AIIQ, -Cut Day AIIQ, I
Illustration Five (Schedule 72 Idaho Irrigation Load Control-Daily Load CuNe: Total PacifiCorp Hourly Idaho Load
(July) Estimated Impact of Schedule 72) plots the total Company average hourly interval load data for the month of
July5. Also plotted is a 44MW decrement (estimated average avoided MW generated as a function of Schedule 72
across the 5 hr dispatch block). While Schedule 72 accounts for a measured 'dip' in the load profile, the Idaho load
even without Schedule 72 would naturally be reduced in the afternoon hours (areas shaded in striped tan). The reason
for this is that growers prefer to avoid irrigating in the heat of the day to minimize soil moisture loss as a function of
transvaporation.
5 Note: at the time of the preparation of this report data are not yet fully adjudicated for FERC reporting; nevertheless it is not anticipated there will be
measured deviations from what is indicated in Illustration Five
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Illustration Five
Schedule 72 Idaho Irrigation load Control-Daily load Curve:
Total PacifiCorp Hourly Idaho load (July) & Estimated Impact of Schedule 72
650 ,
580
640
630
620
610
~ 600
590
570
560
550 10 11 12 13 14 15 16 17 18 19 20 21 22 23
lime (24 hrsl
I-TOt. ID July Load Profile I
Technical challenges
During the 2005 irrigation season, field technicians experienced an unusually high frequency of timer malfunctions.
Upon making this discovery a conference call was made between the load Control Management Team, field
technicians, Consolidated Electrical Distributors (the distributors through which the timers are purchased) and the
clock manufacturer Grasslin (U.S. headquarters in NJ)6. Grasslin s U.S. Engineering group requested and was
provided with a half of dozen of the failed units. At first, their evaluation was inconclusive other than that the
batteries had clearly failed. At the time of the preparation of the drafting of the 2005 year-end report their European
counterparts were similarly unable to precisely pin-point the cause of battery failure.
Additional analysis was conducted during the early winter. Around the first of the New Year the principal board
designer was contacted and a root-cause analysis prepared. It turned out that the cause of the failure was a
miscalculation on the circuit board used in the timer as to the amount of Amperes drawn on the battery. That is, the
failed board design exceeded the (Amp-hour (Ah) rating) of the battery itself. Changes in the board design were
made to correct the problem and no cost replacement units provided to Rocky Mountain Power for the 2006
Program season.
6 Grasslin is a European timer manufacturer who was acquired by GE in 2002.
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With new equipment, but without knowledge of the status of each of the field installed units, a decision was made to
visit and assess each of the installed timers. Accordingly, Program technicians were instructed to test and replace,
where necessary, each unit. With (1) more than 1 300 individual timers, (2) an uncertain and sporadic delivery date
of the re-designed boards, (3) a dynamic Program participation customer base, (4) field technician scheduling
optimization, (5) weather vagaries and (6) only a limited installation window a re-drafting offield logistics and
database modifications were required to meet the scheduled Program start date. Accordingly, some additional
Program costs were incurred in juggling the logistics. However, it turns out that through the cooperation of end-use
customers, committed field installers, a database administrator and the Company s Irrigation Hotline management
staff, total Program costs ended up being within anticipated 2006 budgets.
Measurement & Verification (M&V) processes
Consistent with the previous three irrigation seasons, field technicians prepared random, unannounced site visits for
the purpose of ensuring the integrity of timer performance and the absence of fraud. Five timer and timer-related
parameters ((1) tape seal, (2) meter lock, (3) battery, (4) clock calendar and (5) pump panel) were considered in the
evaluation. M&V technicians were also asked to confirm the presence of PacifiCorp Site 10 stickers for inventory
purposes. Where it is suspected there were variances in anyone or multiple above-defined components field
technicians were required to indicate said variances in the database and to the Irrigation Load Control Management
Team for adjudication. The results of the 2006 M&V activities are indicated in Table Eleven. In addition, there was
one site reported to the Irrigation Load Control Management Team for adjudication but in this instance, evidence
pointed to a field installation error, not end-use customer fraud.
Table Eleven
Results of the 2006 Measurement & Verification
Ct.
Ct. of Units Percent
QA Parameter Failures Inspected Failure
SitelO Sticker 41 144 28.50%
----------
Tape Seal
___-
20%
_..._-
yu~ Panel
_____.
2__--
~__
50%
Meter Lock 144 0.70%,,__om
- - - ~,,-- "...-- -
_m- ",~,- -
,~,-,,--
Clock Calendar 144 0,70%
- --'--_._--_.-'- '-..------'---'--... ,--- -.- ------.--..-----.--
Batt~'L_____9._..._-_...._-
~~._-_.__.
.9. OOL
Crop type analysis
As part of the 2005 year-end report the Idaho Commission requested that the Company prepare analysis of avoided
loads by crop type for the 2006 season. This analysis is somewhat problematic as a majority of field installations
occur in January, February and March prior to when a grower has made a final decision on crops and prior to
planting. Nevertheless, field technicians either inquired of the grower as to crop type or could identify the emerging
crop himself (in the case of late-in-season installs). Table Twelve: Known Site Estimation of Crop Type x Site &
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Avoided kWpresents the results of these field data gathering efforts7. The avoided kW values were calculated by
taking the full summer (1 June through 15 September) average for each of the identified sites and summing those
avoided kW values by crop type.
Table Twelve
Known Sites Estimation of Crop Type x Site & Avoided kW
Cro
grain
hay
spuds
pasture
grass
com
.9.olfcourses
sod
----
trees
canal
in/potatoes
rechar
otatoes/com
Totals
No. of Sites Tot. Avg. kW
~!!._---_..-
363.5 .
378 38,442.
186 24,400.
______
992.
~ ,
273.
-.-
12 ~24.
4 124.
3 419.
,--------
76.
366.4
------
2 257.1 13.
1 292,
153 123,047,
Despite being estimates, these data indicate that Program participation is largely limited to 'field' crops. 'Row' crops
particularly potatoes have not and do not participate in the Schedule 72 initiative. Moreover, the data clearly
illustrates an opportunity to grow Program participation among potato growers. Additional consideration of this
finding is further discussed in the Program Enhancements Under Consideration section.
Table Thirteen: 2006 Program Participant Estimation of Crop Type Site Avoided kWpresents field installer
estimates of only 2006 Program participant crop types. Again, these are estimates and the same constraints exist
with these data as referenced with Table Twelve. Accordingly, attempts to synch-up avoided MW as reported in
Table Twelve to reported Program totals should be avoided.
7 Note: these estimates represent infonnation about ALL known sites in the PacifiCorp service territory whether the site was participating in the 2006
initiative or not
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Table Thirteen
2006 Program Participant Estimation of Crop Type x Site & Avoided kW
Crop Type No. of Sites Tot. Avg. kW
-_____
grain 60 44,309,
------
315 31,912.
___
uds
____.
13,131
.____
~tur
~- _._-----
~.:2._
_..---------g~~~--~--------
1 ,065,corn 9 2 268.
golf~urses
..-----
122.sod 3 419.
trees 3 76.canal 366.
".. .... , ,_.. .. ,- - -" ,.... ,......
grain/potatoes 2 257.
potatoes/corn 1 292.recharge 1 13.
Totals 894.0 95 847.
Table Fourteen: 2006 Program Participant Estimation of Crop Acreage Crop Type presents field installer estimates
of only 2006 Program participant crop types x acreage. Here again, these values represent estimates and the same
constraints exist with these data as referenced with Table Twelve and Thirteen.
Table Fourteen
2006 Program Participant Estimation of Crop Acreage x Crop Type
Crop Type
grain
hay
spuds
pasture
corn
Total Acres
64,026
50,623
13,970
644
2,460
534
200
560
300
300
121
138,737
grass
grain/potatoes
sod
golf courses
potatoes/corn
trees
Totals
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Program enhancements under consideration
Over the course of the three years that Schedule 72 (Irrigation Load ControQ has been available to Rocky Mountain
Power's Schedule 10 (APS) customers, the Irrigation Management Team has attempted to consider and implement
operational changes to (1) enhance delivery, (2) improve efficiencies, (3) provide for greater data integrity / accuracy
and (4) grow customer participation. The 2006 irrigation season is no different. In 2006 the Irrigation Management
Team piloted new control technology. 25 new control technology units were field tested at 14 customer sites. If, it
was reasoned, the results of the field test proved successful then additional changes could be considered to one or
more of the aforementioned objectives to further improve Program performance. Moreover successful trial could
mean the technology would be considered for implementation in the 2007 irrigation season. The information that
follows is summary of the pilot background, objectives, customer assessments and anticipated benefits.
Background
Previous year failures with the electronic timers has created and/or contributed to (1) increased field
maintenance costs, (2) customer dissatisfaction / frustration, (3) lower than expected Program participation,
and (4) administrative overhead / burden. Beginning in the late fall 2005 and throughout the winter, 2006 the
Irrigation Management Team began to identify and investigate alternative control technologies. Two
technologies were bench tested and one (M2M Communications, Boise, 10) was selected for further
consideration and piloting during the 2006 irrigation season.
Throughout the 2006 irrigation season 25 sites (14 customers) participated in testing the fully duplexed
(cellular / satellite) M2M pump/pivot control technology. M2M provides the underlying remote control
equipment to Valley Irrigation the world's most popular and largest agricultural pivot manufacturer. This
particular product line (remote pivot control) has been available for five years and, according to Valley, is one
of the more popular options to their base equipment. Moreover, the equipment's durability has received
favorable endorsement as function of little / no reports of failure / malfunction during the five years it has
been in the field8. The version of the control equipment tested in 2006 was based upon and nearly identical
to that used by Valley Irrigation.
Underlying objectives
It was anticipated that the M2M technology would lower the recursive field costs and provide platform for
additional agri-business offerings. These new offerings would create operational efficiencies and improve
performance reliability. By so doing, it was hypothesized that a value proposition could be struck that would
address agri-business practices important to growers thereby capturing additional participation. Driving much
of the thinking behind the pilot was bias towards potato growers and the need to capture their participation
if the Program were to increase in volume. Moreover, the offering could move the Load Control Program
beyond simple exchange of participation credit for shifted load. That is, growers could be provided with
additional dispatch-options for growers. This approach would also eliminate the stranded equipment assets
currenUy incurred as a function of crop rotations. Ultimately, and over time, the M2M equipment would
replace the current solid state Grasslin timers.
6 As reported by equipment distributors, customers and Valley's own internal statistics.
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Equipment benefits / costs
An additional benefit of the M2M equipment is the elimination of M&V as the new control technology provides
an authoritative log of pump activity. But perhaps most important is the benefit of being able to remotely
query the unit and test operational effectiveness. The new equipment is solid state design so there are no
moving parts or battery to keep date/time in synch as all intelligence has been migrated to the server to
which the field unit communicates. The grower has improved and increased flexibility in managing equipment
to meet their agri-business requirements as all commands can be managed either through the Internet or via
standard telephony (cellular or traditionallandline). Older RF controllers used in the past often ended up
being disconnected from the system due to breaking of antennas or coffee can shields. It is not anticipated
that the M2M technology will experience this sort of either active or passive sabotage because the grower
now, operating his irrigation equipment through the M2M technology, has a 'vested interesf (both operational
and economic) in the equipment's effective operation.
The down-side of this technology is (1) capital and (2) recursive air time communication (satellite / cellular)
charges. Recursive air time communication costs only occur during the season and their impact is = $7 per
site per month. The cost of the unit itself is more than twice the standard Grasslin timer currently in use.
However, this is somewhat misleading. Evaluation of current and past budgets suggests that recursive field
costs incurred by one-way technologies (or in the case of the Idaho program Grasslin timers) have added
substantial to the overall base costs for these technologies. These un-anticipated costs have had a negative
impact on Program performance. Moreover, timer failure has had a negative effect on customer service.
Based on revised proforma calculations taking into consideration the use of the M2M equipment, life-cycle
and maintenance costs, the M2M equipment would be more cost effective than the current Grasslin timer
technology. For example, current Grasslin timer technology costs = $315 per site9 and due to the lack of
reliability of the timer the Irrigation Management Team has determined that each site configured with a timer
MUST be visited each year. This decision has been made to maintain appropriate and reasonable levels of
customer service and to ensure grower participation in the Program does not further erode. Factoring in that
=30% of the participating sites require two or more timers + an annual site visit + troubleshooting at .05% of
the total population the M2M equipment at =$570 per site break even is less than one control season.
Pilot results
With the exception of a single unit which appeared to fail as a function of installation error the M2M
equipment operated according to design specifications. The Irrigation Management Team received a number
of anecdotal comments from customers indicating their surprise and pleasure in being notified when the
status of the pump changed as a function of a power interruption or lightning.
9 Note that:: 30% of the snes require two or more timers. This snuation occurs when a grower does not have either a pressure swnch or a low
voltage control connection between the pump and the pivolln these instances the cost to control thi!~ sne is roughly doubled or $600 per site.
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Modeling
Currently the Company s Commercial & Trading (C&T) organization is performing cost effectiveness
modeling assuming the installation and use of the proposed technology as a fully dispatchable solution. As of
the preparation of this report, the results of these analyses are not yet available. However, when these data
become available and if it is determined that a significant and measured change to the Credit Rider Initiative
could be implemented, the Company will bring its recommendations to the Commission for consideration.
nMn....
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Exhibit No. 302
Case No. P AC-07-
Anthony J. Yankel
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Exhibit No. 305
Case No. P AC-07-
Anthony J. Yankel
Excerpts from "Assessment of Long-Term System-Wide
Potential for Demand-Side and Other Supplemental
Resources
22 pages
~Yf,~Y1IitC€~LL,
. ,
Final Report - Volume I
'---.....,..--'-..,-.., ,
Assessment of Long-Term
System-Wide Potential for
Demand-Side and Other
Supplemental Resources
--'-"-""'....---,-"" - --
Prepared for PacifiCorp
July 11 , 2007
In collaboration with Summit Blue Consulting and Nexant, Inc.
', ,
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, ...., ,.......
quantec Rilisillg, tht~ bar in aru1.lytics
_:ntjt~'j;8f~;$i:'~f;'b;:; ;':'
':
Investigators:
Hossein Haeri , Ph., Lauren Gage, Tina Jayaweera , Ph., Collin Elliot
Eli Morris, Rick Ogle, P., Tony Larson, Aquila Velonis , Matei Perussi
Allen Lee, Ph., and Ann Griffin, Quantec, LLC.
Kevin Cooney, Randy Gunn , Stuart Schare
Adam Knickelbein , and Roger Hill, Summit Blue Consulting
Terry Fry, Mike Boutross, and Pranesh Venugopal , Nexant, Inc.
Ki~!iQ~ p19~~~1ftllk~" (e ~~ jft cO'iPri.Q.QZ;.c.P~ ~QJtjl? a~ GJi&f ~M~anH1iII81L~Th.--V9i' um'\~i Q() 65 8~ Q9.ThJrl.:1lli ~
Quantec Offices
720 SWWashington, Suite 400
Portland, OR 97205
[phone]; [phone] fax
www.quantecllc.com
1722 14th SI., Suite 210
Boulder, CO 80302
[phone]; [phone] fax
28 E. Main SI., Suite A
Reedsburg, WI 53959
[phone]; (608) 524-$361 fax
Printed on\:3:1 recycled paper
3445 Grant SI.
Eugene, OR 97405
[phone]; [phone] fax
20022 Cove Circle
Huntington Beach, CA 92646
[phone]
Table of Contents: Volume I
Acknowledgements......................................... ................................................................. xiii
Executive Summary
...................
.................................................................... ES-
Overview....................................... ...............................
"."""""""""""""""""""""'." .
ES-
Summary of the Results ......... .................................................................."....... .............ES-
Resource Acquisition Costs
""""""""""""""""""""""""""""""'.'" ..........................
ES-
Resource Potential under Alternative Scenarios...... ........................................
.......... ....
ES-
Introduction........................... ........... ..........................................................
Background.................. ........................................................................................................
Study Scope and Obj ecti ves.................................................................................................
General Approach................................................................................................................
Organization of the Report...................................................................................................
Capacity-Focused Resources (Class 1 and Class 3 DSM)....................
Scope of Analysis.............................................................. ..................................................
Assessment Methodology............................................................................. .............
....... .
Resource Potential............................................................................................................ .
Resource Costs and Supply Curves ...................................................................................
Resource Acquisition Schedule ................................... .......................
........................ .......
Resource Potential under Alternative Scenarios
......... ................. ............................... .......
Class 1 DSM Resource Results by Program Option..........................................................
Class 3 DSM Resource Results by Program Option..........................................................40
Energy-Efficiency Resources (Class 2 DSM) ........................................
Scope of Analysis...... ................ ...........................................................................".......... .
Resource Potential........... ................. .................................................................................5 8
Resource Potential under Alternative Scenarios .................................................
.............. .
Assessment Methodology............................................. ......................
.............................. .
Class 2 DSM Detailed Resource Potential........ ........................ .............................. ........... 85
Education and Information (Class 4 DSM).............................................
Scope of Analysis................................................. ......................
.................................. .... .
Potential and Costs.......
"""""""""'" "'."""""""""""""'."""""""""."""""""""""""'" .
PacifiCorp -Assessment of Long-Term, System-Wide Potential
Supplemental Resources ......................................................................101
Scope of Analysis .................................................... ........................................................101
AsseSSlnent Methodology.............................. ..................................................................101
Resource Potential...........................................................................................................1 02
Resource Acquisition Schedule.................................................. .....................................104
Resource Potential under Alternative Scenarios ..............................................................1 06
Combined Heat and Power Results............. ...................
............. ........................ .............
1 06
On-S ite Solar Results
"""""""""""""""""""",." ........................."........ ............ ........., ..
115
Dispatchable Standby Generation Results .......................... .................................... .........123
Effects of Structural Changes...............................................................129
Overview................................................................................................................. ....... ..129
Macroeconomic Structural Changes ..........................
......... .................., ..........................
130
Technological Changes................................................................................................... .131
Public Policy and Regulation........... .................. .................... ....................................... ...132
PacifiCorp -Assessment of Long-Term, System-Wide Potential
Tables and Figures
Executive Summary
............................................. ................ ................................
Table ES-1. Energy-Focused Resource Potential (aMW in 2027): Technical
Economic, and Achievable by Resource and Service Territory .................
Table ES-2. Peak Demand Reduction Potential (MW in 2027): Teclmical
Economic, and Achievable by Resource and Service Territory .................
Figure ES-1. Achievable DSM Potential by Resource Type (MW and aMW
2027) (Rocky Mountain Power Territory) ............................................... ...
Figure ES-2. Achievable DSM Potential by Resource Type (2027) (Pacific
Power Territory, Excluding Oregon for Class 2 DSM) ..............................
Table ES-3. Achievable Class 1 and Class 3 (Capacity-focused) DSM Resource
Potential by Customer Sector and Service Territory (MW in 2027) ...........
Table ES-4. Achievable Class 2 (Energy-Efficiency) DSM Resource Potential
by Customer Sector and Service Territory (aMW in 2027).........................
Figure ES-3. Class 2 DSM (Energy-Efficiency) Supply Curves for Technical
Economic, and Achievable Potential (aMW in 2027) .................................
Table ES-5. Achievable Supplemental Resource Potential by Technology and
Service Territory (aMW and MW in 2027) .................................................
Table ES-6. Base-Case Resource Acquisition Costs (NPV and Levelized) by
Resource and Service Territory ...................................................................
Table ES- 7. Achievable Potential in 2027 by Resource and Economic Scenario .........
Introduction...................................... ..........................................................
Figure 1. Reliability and Customer Choice Considerations in Demand-Side
Management Resources..............................................
~................................
Figure 2. General Methodology for Assessment of Demand-Side Resource
Potential.......................................................................... .............................
Capacity-Focused Resources (Class 1 and Class 3 DSM)....................
Table 1. Class 1 and Class 3 DSM Data Sources..................................................... 12
Figure 3. PacifiCorp System Load Duration Curve (2006).......................................
Table 2. Capacity-focused Analysis Customer Sectors and Segments ....................13
Figure 4. PacifiCorp System Monthly Sales (MWh) by Sector ................................
Figure 5. Average Summer Weekday Load - All End Uses.....................................15
Table 3. C&I Survey Results: Attitude toward Capacity-Focused Program
Options................................................................................................... ....
C&I Survey Results: Program Preferences................................................17Table 4.
PacifiCorp -Assessment of Long-Term, System-Wide Potential iii
Table 5.
Table 6.
Table 7.
Table 8.
Table 9.
Figure 6.
Figure 7.
Table 10.
Figure 8.
Figure 9.
Figure 10.
Figure 11.
Table 11.
Table 12.
Figure 12.
Table 13.
Table 14.
Table 15.
Figure 13.
Table 16.
Table 17.
Figure 14.
Table 18.
Table 19.
Figure 15.
Table 20.
Class 1 DSM: Rocky Mountain Power Territory Technical
Economic, and Achievable Potential (MW in 2027) .................................
Class 1 DSM: Pacific Power Territory Technical, Economic, and
Achievable Potential (MW in 2027) ..........................................................
Class 3 DSM: Rocky Mountain Power Territory Technical
Economic, and Achievable Potential (MW in 2027) .................................
Class 3 DSM: Pacific Power Territory Technical, Economic, and
Achievable Potential (MW in 2027) ............................................... ...........
Class 1 DSM: Levelized Costs and Market Potential (MW in 2027)........
Class 1 DSM: Rocky Mountain Power Territory Supply Curve
(Cumulative MW in 2027) .............................................................. ...........
Class 1 DSM: Pacific Power Territory Supply Curve
(Cumulative MW in 2027) .........................................................................
Class 3 DSM: Levelized Costs and Market Potential (MW in 2027)........
Class 3 DSM: Rocky Mountain Power Territory Supply Curve
(Cumulative MW in 2027).........................................................................
Class 3 DSM: Pacific Power Territory Supply Curve
(Cumulative MW in 2027) .............................,... ........................................
Class 1 DSM: Acquisition Schedule for Achievable Resource
Potential by Year and Territory .................................................................
Class 3 DSM: Acquisition Schedule for Achievable Resource
Potential by Year and Territory .................................................................
Economic and Achievable Scenarios: Achievable Potential (MW
in 2027)
"""""""""""""""""""""""""""""""""""""""""""""""""'" .
DLC Air Conditioning: Technical and Market Potential (MW in
2027) ............................ ..............................................................................30
DLC Air Conditioning: Market Potential by State (MW in 2027) ............
DLC Air Conditioning: Levelized Costs and Scenarios ............................
DLC Air Conditioning and Water Heat: Levelized Costs and
Scenarios.................................................................. ..................................33
DLC Large Commercial: Technical and Market Potential (MW in
2027) ....... ................................
;................................................................. .
DLC Large Commercial: Market Potential by State (MW in 2027) .........
DLC Large Commercial: Levelized Costs and Scenarios .........................
Irrigation: Technical and Market Potential (MW in 2027)........................
Irrigation: Market Potential by State (MW in 2027) .................................
Irrigation: Levelized Costs and Scenarios .................................................
Thennal Energy Storage: Technical and Market Potential (MW in
2027) ..........................................................................................................38
Thennal Energy Storage: Market Potential by State (MW in 2027) .........
Themlal Energy Storage: Levelized Costs and Scenarios .........................
PacifiCorp -Assessment of Long-Term , System-Wide Potential
Energy-Efficiency Resources (Class 2 DSM)
........................................
Table 33. Energy-Efficiency Measure Counts (Base-Case Scenario) .......................
Table 34. Technical, Economic and Achievable Energy-Efficiency Potential
(aMW in 2027) by Sector ..........................................................................
Technical, Economic, and Achievable Energy-Efficiency Potential
(aMW in 2027) by State.............................................................................
Technical, Economic, and Achievable Energy-Efficiency Potential
(aMW in 2027) by Sector and Resource Type...........................................
Acquisition Schedule for Achievable Savings by Year and Sector ...........
Technical, Economic and Achievable Energy-Efficiency Potential
(aMW in 2027) by Sector and Technology Type ......................................
Economic and Achievable Scenarios: Achievable Potential by
Sector (aMW in 2027) """"""""""""""""""""""""""""""""""""""".
Economic and Achievable Scenarios: Achievable Potential by
State (aMW in 2027).............................. ........................................... ..".... .
Representation of Alternative Forecast Approach to Estimation of
Energy-Efficiency Potential............... .....
..................... ..............................
Table 21.
Figure 16.
Table 22.
Table 23.
Figure 17.
Table 24.
Table 25.
Figure 18.
Table 26.
Table 27.
Figure 19.
Table 28.
Table 29.
Figure 20.
Table 30.
Table 31.
Figure 21.
Table 32.
Table 35.
Table 36.
Figure 22.
Table 37.
Table 38.
Table 39.
Figure 23.
Curtail able Tariff Program: Technical and Market Potential (MW
in 2027) ...........................................................................................,......... .
Curtailable Tariff Program: Market Potential by State (MW in
2027)
"""""""""""""""""""""""""""""""""""""""""""""""""""'" .
Curtailable Tariff Program: Levelized Costs and Scenarios ......................43
Demand Buyback: Technical and Market Potential (MW in 2027) ..........45
Demand Buyback: Market Potential by State (MW in 2027)....................45
Demand Buyback: Levelized Costs and Scenarios....................................46
Time of Use Rates: Technical and Market Potential (MW in 2027) .........47
Time of Use Rates: Market Potential by State (MW in 2027)...................48
Time of Use Rates: Levelized Costs and Scenarios...................................48
CPP Residential/Small Commercial: Technical and Market
Potential (MW in 2027) .....................................................................,......
CPP Residential/Small Commercial: Market Potential by State
(MW in 2027) ......................................... ..
............................................." ..
CPP Residential/Small Commercial: Levelized Costs and
Scenarios................................................................................................... .
CPP C&I: Technical and Market Potential (MW in 2027)........................
CPP-C&I: Market Potential by State (MW in 2027) .................................
CPP C&I: Levelized Costs and Scenarios .................................................
Real-Time Pricing: Technical and Market Potential (MW in 2027) .........
Real-Time Pricing: Market Potential by State (MW in 2027) ...................
Real-Time Pricing: Levelized Costs and Scenarios ...................................
PacifiCorp -Assessment of Long-Term, System-Wide Potential
Table 40.
Table 41.
Table 42.
Table 43.
Table 44.
Table 45.
Table 46.
Table 47.
Table 48.
Table 49.
Figure 24.
Table 50.
Table 51.
Figure 25.
Figure 26.
Table 52.
Table 53.
Figure 27.
Figure 28.
Table 54.
Table 55.
Figure 29.
Table 56.
Figure 30.
Table 57.
Figure 31.
Table 58.
Figure 32.
Table 59.
Class 2 DSM PacifiCorp Data Sources......................................................
Class 2 DSM Pacific Northwest Data Sources ..........................................
Residential Sector Dwelling Types and End Uses.....................................
Commercial Sector Customer Segm,ents and End Uses ............................
Industrial Sector and End Uses ..................................................................
Residential Energy-Efficiency Measures .................... ...............................
Residential Emerging Technology Measures ............................................
Commercial Energy-Efficiency Measures ...................... ...........................
Commercial Emerging Technology Measures...................... .....................
Industrial Energy-Efficiency Measures ............................................... ......
Example of Equipment Potential: Average EUI for Large Office
Chillers in Existing Construction .................. .............................................
Measure Applicability Factors .............................................................. .....
Economic Assumptions by State ......
............................ ...................."...... .
Rocky Mountain Power Territory Annual IRP Decrement and
Market Price Values.................................................................................. .
Pacific Power Territory Annual IRP Decrement and Market Price
Values ........................................................................................................
Assumptions of Achievable Potential as Percent of Economic, by
Sector and End Use................................................................................... .
Residential Sector Energy-Efficiency Potential by State (aMW in
2027) ...................................................................................................".... .
Residential Sector Achievable Potential by Segment................................
Residential Sector Achievable Potential by End Use ................................
Residential Sector Energy-Efficiency Potential by End Use (aMW
in 2027) ..................................................................................................." .
Commercial Sector Energy-Efficiency Potential by State (aMW in
2027) ......................................................................................................... .
Commercial Sector Achievable Potential by Segment ..............................
Commercial Sector Energy-Efficiency Potential by End Use (aMW
in 2027) ................................................................,.................................... .
Commercial Sector Achievable Potential by End Use ..............................
Industrial Sector Energy-Efficiency Potential by State (aMW in
2027) ................................................................................................."...... .
Industrial Sector Achievable Potential by Segment...................................
Industrial Sector Energy-Efficiency Potential by End Use (aMW in
2027) ............................ ..................................
""""""""""""""""""""'" .
Industrial Sector Achievable Potential by End Use ...................................
Irrigation Sector Energy-Efficiency Potential by State (aMW in
2027) """""""""""""""""""""""""""....................................................
PacifiCorp -Assessment of Long-Term, System-Wide Potential
Education and Information (Class 4 DSM).............................................
Table 60. Class 4 DSM Activity Types .....................................................................
Table 61. Estimated Residential Impacts of Class 4 DSM Programs (aMW) ...........
Table 62. Estimated Commercial Impacts of Class 4 DSM Programs (aMW) .......100
Supplemental Resources ........................,.............................................101
Table 63. Supplemental Resources Installed Capacity by State and Resource
Category (MW) ........................................................................................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 Territory..................................... ........................ .................................104
Achievable Potential for Supplemental Resources by Territory
(aMW and MW in 2027)..... ............
.......... .............. .................................
104
Acquisition Schedule for Supplemental Resources by Resource
Category.................................................... ...............................................105
Economic and Achievable Scenarios: Achievable Potential (aMW
and MW in 2027) ................................ ............................................... ......1 06
CHP Prototypical Generating Units................................. ........................1 08
Costs for Assessed Technologies (2007$) ...............................................109
CHP Technical Potential by State and Resource Category (aMW in
2027) ..........."............
"""""""""""""""""""'" .........."....................... ...
111
Market Potential for CRP (aMW in 2027) ..............................................112
Market Potential for CHP by State and Technology (aMW in 2027)......113
CHP Cumulative Supply Curve, by Technology (Cumulative aMW
in 2027) ....................................................................................................114
Achievable Potential for CHP by State with Cost Threshold ..................114
CHP Average Levelized Costs ($/kWh) for Different Economic
Scenarios................................................................ ................................ ..115
CHP Alternative Economic Scenarios for Base Achievable
Potential by State (aMW in 2027) ...........................................................115
On-Site Solar Technology Costs and Measure Lives ..............................117
Solar Annual Capacity Factors, by State .................................................119
On-Site Solar Technical Potential by State (aMW in 2027) ....................119
On-Site Solar Market Potential and Levelized Costs by State
(aMW in 2027) ...................................................................................... ...121
Diffusion Curve for Product Adoption ....................................................122
Potential Market Penetration of Adopters by Payback Period.................122
Existing Backup Generation, Commercial Sector ...................................124
Existing Backup Generation, Industrial Sector ........................................124
Table 64.
Table 65.
Table 66.
Figure 33.
Table 67.
Table 68.
Table 69.
Table 70.
Table 71.
Table 72.
Figure 34.
Table 73.
Table 74.
Table 75.
Table 76.
Table 77.
Table 78.
Table 79.
Figure 35.
Table 80.
Table 81.
Table 82.
PacifiCorp -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 (MW in 2027) ...................................125
Costs for DSG
"""""""""""""""""""""""""""'."""""""""""""""" ..
126
Achievable Potential and Cost for DSG (MW in 2027) ..........................127
Alternate Economic Scenarios for DSG Base Achievable Potential
by Territory (MW in 2027) .................................. ................................... .127
Effects of Structural Changes
....................... ........................................
129
Table 88. Categories of Structural Changes and Examples .....................................129
Figure 36. Illustration of Linkages between Structural Changes and
Achievable Potential............................................................................... .130
PacifiCorp -Assessment of Long-Tenn , System-Wide Potential viii
Table of Contents: Volume
Appendix A-1. Surveys Results, Overview....................................................
CI and CHP Survey Summaries....................................... ............................................... A-
Appendix A-2. Survey Results, Detailed ........................................................
CI Survey Results: Overall ............
"""""""""""
......................"........ ............... ............ A - 7
CHP Survey Results: Overall. ........................................ ............................................... A -
Appendix A-3. Survey Instruments...............................................................
CI Survey Instrulnent.................... ................................................................................ A-
CHP Survey Instrulnent ................ ................................................................................ A - 73
Appendix B-1. Capacity-Focused Resource Materials: Detailed
Assumptions by Program Option ........... ........................................................ B-
DLC Residential- Air Conditioning Only............................ ..........................................
DLC Residential- Air Conditioning and Water Heating ................................................
DLC Commercial................................. ....................................................."................... ..
Irrigation............................................................................. .......................................,. ..
Thennal Energy Storage ......................
........ .................................. """"""""""'." ........
Curtail able Load... ................................................. ....................................................... ..
Demand Bidding........................................................................................................... .B- 21
Residential Time of Use Rates................................................................................. ......
Residential and Small Commercial Critical Peak Pricing .............................................
Commercial and Industrial: Critical Peak Pricing .........................................................
Real Time Pricing ....................................................................................................... ...B- 31
Appendix B-2. Capacity-Focused Resource Materials: Load Basis and
Cal i bration... .. .............................. .......................................... ......................... B-
California.................................................................................................................... ...3 5
Idaho............................................................................................................................ ..B- 38
Oregon............................................................................................................................
Utah.............................................................................................................................. ..
Washington................. .......................................................................................... ....... ..
Wyoming........................................................................................................................
All States Total......................................................................... .................................... .
PacifiCorp -Assessment of Long-Term, System-Wide Potential
Appendix B-3. Capacity-Focused Resource Materials: Detailed
Program Results - Year and Market Segment (Summer)...........................
DLC - RES - AC and Water Heat ..................................................................................
DLC - RES - AC ............................................................................................................
DLC - Comlllercial ................,...................................................................................... .5 7
Irrigation....................................................................................................................... .
Thermal Energy Storage ..... .............................. ............................................
......... ........
Curtailable Load........................................................................................................... ..
TilTIe Of Use Rates........................................................................................................ .
Appendix B-4. Capacity-Focused Resource Materials: Winter Results....
Class 1 DR PrognuTIs
................................................................................................... ..
B- 7 5
Class 3 DR ProgralTIS
........................................................................."......................... .
B- 7 6
Appendix C-1. Technical Supplements: Energy Efficiency Resources
Measure Descriptions
................................ ............................ ..........................
Residential Measure Descriptions..... ...............................................................................
Residential Emerging Technology......... ...........
............. ................................................
Commercial Measure Descriptions ..... ...........................................................................
Commercial Emerging Technologies ...........................................
...... ...................... .....
Industrial Measure Descriptions ......................................."...................................... .....
Appendix C-2. Technical Supplements Energy Efficiency Resources,
Market Segmentation
............... .................................... ..................................
Baseline Forecasts......................................................................................................... .C- 35
End Use Saturations and Electric Shares .......................................................................
End-U se Consumption Estimates ..........................................,.......................................
Appendix 3. Technical Resources: Energy Efficiency Resources,
Measure Inputs............................ ...............................,....... ............................ C
Appendix C-4. Technical Resources: Energy Efficiency Resources,
Class 2 DSM Decrement Analysis
................................ ................................
Appendix D. Technical Supplements: Class 4 Resources
..........................
Descriptions and References for Reviewed Programs.................................................... D-
PacifiCorp -Assessment of Long-Term, System-Wide Potential
Appendix E-1. Technical Supplements: Supplemental Resources
CHP......... ............. .........................
................................................ .............
........ E-
Appendix E-2. Technical Supplements: Supplemental Resources
On-Site Solar.... ...................... ....... ......... ................ .................. ............. .......... E-
Appendix E-3. Technical Supplements: Supplemental Resources
DSG............................................... ... ................ ........................................... ..... E-
Appendix F. Simulations & Home Electronics ................................ .............. F-
Scope..................................................... ........................................................................... F-
Methodology.................................................................................................................. F -
Results......................................................................... ........................................."........ F -
Appendix G. Treatment of Externalities.........................................................
Introduction and Purpose................................................................................................ G-
Objectives and Approach................................................................................................ G-
Findings........................................................................................................................... G-
PacifiCorp -Assessment of Long-Term, System-Wide Potential
Acknowledgements
This study required compilation of a large amount of data from various sources, including
several departments at PacifiCorp. It would be difficult to overstate the importance of the
contributions made by PacifiCorp staff to this effort. We thank all of them for their assistance.
We are especially grateful to Christopher Kanoff, our project manager, who worked hard to
ensure the necessary information was delivered to us on time. Bill Marek made himself available
to us when we needed him and helped us develop a better understanding of the complexities of
PacifiCorp s Class 1 and Class 3 DSM programs and made it possible to model them properly.
Pete Warnken provided much needed support in coordinating the assessment of the potential
with the integrated resource planning process.
We thank Jeff Bumgarner, 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-Term, System-Wide Potential xiii
Executive Summary
Overview
For nearly 25 years, PacifiCorp has been 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 1980s, PacifiCorp has continued to be an
innovator in energy efficiency and has conceived and implemented programs such as Energy
FinAnswer, which, in its class, is considered one of the best programs in North America. Over
the last 15 years, PacifiCorp has invested approximately $345 million on DSM programs
offsetting nearly 2 700 GWh of energy - the equivalent of nearly 515 MW of capacity annually,
assuming a 60% load factor on average.) Currently, PacifiCorp operates successful capacity-
focused programs for irrigation load curtailment, demand buyback, and air conditioning direct
load control, which together helped reduce PacifiCorp s peak loads by 149 MW in 2006.
PacifiCorp also has an additional 260 MW available for control under interruptible agreements
with a select group of its largest commercial and industrial customers.
Beginning in the early 1990s, PacifiCorp developed biennial integrated resource plans (IRPs) 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-run potential for DSM resources in
PacifiCorp s Pacific Power (Oregon 2 Washington, and California) and Rocky Mountain Power
(Idaho, Wyoming, and Utah) service territories to support the PacifiCorp s integrated resource
planning process and help further PacifiCorp s active pursuit ofDSM resources.
This study s principal goal is to develop reliable estimates of the magnitude, timing, and costs of
alternative DSM resources, comprised of capacity-focused program options (defined throughout
this report as Class 1 and Class 3 DSM resources), energy-efficiency products and services
(defined as Class 2 DSM resources), and other "supplemental" resources such as solar, combined
heat and power, and dispatchable standby generation. The analysis of resource potential in this
study are augn1ented by an examination of the benefits of consumer awareness and education
initiatives (Class 4 DSM resources) and an analysis of how future structural changes, such as
technological innovation, macroeconomic conditions, and public policy, might affect the
findings and conclusions of this study.
The main emphasis of this study has been on resources with sufficient reliability characteristics
which are expected to be technically feasible (technical potential), cost-effective (economic
potential), and realistically achievable (achievable potential) during the 20-year planning
horizon. For Class 2 DSM (energy-efficiency) resources, the methods used to evaluate the
Expenditures and savings include PacifiCorp s contributions to the Energy Trust of Oregon and the associated
energy savings generated by those funds. All savings and capacity information 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.
PacifiCorp -Assessment of Long-Term , System-Wide Potential ES-
Figure 6. Class 1 DSM: Rocky Mountain Power Territory Supply Curve
(Cumulative MW in 2027)
$160
TESDLC AC: Direct load control for air conditioning
$140 DLC COM: Direct load control for large commercial customers
TES: Thermal energy storage
ffi
::-.
1ii
::-
$120
Capacity Value: $98/kW-year
OLC Com
- - - - - - - - - - - - - - - - - - - - - - - - - - - - -
OLC AC
$80
$60
$40 Irrigation
Figure 7. Class 1 DSM: Pacific Power Territory Supply Curve (Cumulative MW in 2027)
$160
$100
$20
80 100 120 140 160 180 200 220 240 260 280
Cumulative Savings (M-N)
DLC AC: Direct load control for air conditioning
DLC COM: Direct load control for large commercial customers140 TES: Thermal energy storage
-c:-
::-.
O!:
1ii
::-
..J
$120
$100
$80
$60 Capacity Value: $58/kW-year
TEe.
OLC Com
OLC AC
$40 Irrigation
- - - - - - - - - - - - - - - - - - - - - - - - - - - - -
$20
Cumulative Savings (M-N)
PacifiCorp - Assessment of Long-Term, System-Wide Potential
Irrigation
A program targeting irrigation is an ideal option to reduce summer peak due to the coincidence
of irrigation pumping with mid-afternoon summer peaks. PacifiCorp s current irrigation load
control program in Idaho is a scheduled control program; customers subscribe in advance for
specific days and number of hours when their irrigation systems will be turned off. Load
management is executed automatically based on a pre-detennined schedule set through a timer
device. Although a total of 100 MW of irrigation loads are contracted for management under this
control program , less than half are available at any time due to the alternating schedules of
program participants. In the Northwest, the Bonneville Power Administration (BP A) has run a
pilot irrigation program (on a dispatched rather than scheduled basis), and Idaho Power has
implemented a program similar to PacifiCorp s scheduled control program. In 2007, PacifiCorp
began piloting a limited-scope 45 MW dispatchable program in addition to its scheduled control
option. Presuming it will be successful , this analysis assumes that, in the future, half of the
participants will sign up for the dispatchable control option and half will sign up for the
scheduled control option.
Technically, it is assumed all irrigation loads are eligible for this program, excepting half of the
Oregon load (which is horizontal pumping and not suitable for this offering). This results in a
technical potential 0008 MW (Rocky Mountain Power) and 108 MW (Pacific Power).
In tenus of program participation, both PacifiCorp s and Idaho Power s scheduled control option
programs have had solid participation rates: 35% and 25% of eligible load, respectively. This
analysis assumes PacifiCorp can increase the participation rate in Idaho to 50% and will reach
25% in other states, where pumps tend to be smaller and loads are distributed across more
customers. Assuming one-half of participants are on a scheduled control program, during any
one event, only 75% of the load will be available. These factors lead to a market potential
estimate of 20 MW for Pacific Power (.::1 % of 2027 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 Utah).
Due to load distribution the majority of this is expected to come 1Tom Idaho (93 MW). The
PacifiCorp forecasts of irrigation loads expect an overall reduction of approximately 10% over
the next 20 years, which is accounted for in the estimate of potential in 2027.
Table 17, Irrigation: Technical and Market Potential (MW in 2027)
Rocky Mountain Power Pacific PowerSector Technical Market Market as % Technical MarketPotential Potential of 2027 Peak Potential Potential
Market as %
of 2027 Peak
Residential
Commercial
Industrial
Irrigation
Total
308.3
308.
104.
104.
21.
3% I
107.
107.
20.
20.
PacifiCorp -Assessment of Long-Term, System-Wide Potential
Figure 14. Irrigation: Market Potential by State (MW in 2027)
California
Idaho
Oregon
Utah
Washington
Wyoming 40
MW (in 2027)
100
I 0 Irrigation I
Costs for the irrigation program include $400 000 for up front program costs, $1 000 for installed
technology with a life of seven years, $500 for marketing to new customers, and $10/kW for
ongoing maintenance and communication systems based on Rocky Mountain Power
experience. Although PacifiCorp currently pays $l1/kW-year for incentives (2006 program
year), participation level assumptions are based on a higher incentive amount of $20/kW-year in
recognition that greater penetration will require higher incentives and the emergence of the
dispatchable control option is expected to increase the value of the control to PacifiCorp.
Table 18 displays the resulting levelized costs for the irrigation. With an expected cost of
$47/kW-year and $50/kW -year (Rocky Mountain Power and Pacific Power territories
respectively), this program option passes all economic screens. The high achievable scenario
assumes a 20% increase in participation 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), irrigation in the Rocky Mountain Power territory passes all economic scenarios.
Table 18. Irrigation: Levelized Costs and Scenarios
MW Levelize Economic ScreenPotential d Cost Low Base High
Rocky Mountain Power
Expected Achievable 104 $47 Pass Pass Pass
High Achievable 125 $67 Pass Pass Pass
Pacific Power
Expected Achievable $50 Pass Pass
h Achievable $70 Pass
PacifiCorp -Assessment of Long-Term, System-Wide Potential
Table 24 also shows the high achievable scenario, assuming 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 territory. Consistent with all other progran1s, the high
achievable scenario is assumed to have a 50% increase in incentives; so costs rise to
$24/kW-year, which again pass all economic screens.
Table 24. Demand Buyback: Levelized Costs and Scenarios
Levelized Economic Screen
Potential Cost Low Base
Rocky Mountain Power
Expected Achievable $18 Pass Pass Pass
High Achievable $24 Pass Pass Pass
Pacific Power
Expected Achievable $18 Pass Pass Pass
High Achievable $24 Pass Pass Pass
Residential Time of Use Rates
Information on TOU rates was obtained ITom tariffs ITom 60 U.S. utilities, promotional materials
used by utilities offering new Tau (or Tau with CPP) programs during the past five years, and
several interviews with utility staff members.35 TaU rates have been offered by u.s. utilities
since at least the 1970s, but the historic impacts have been quite low. In fact, PacifiCorp ran a
Tau pilot in 2002 to 2004, which had extremely low program sign-up (940 residential
customers at the end of 2004, with an average of 25% annual attrition), despite an intensive
marketing effort.
The TOU rates developed in recent years typically differ ITom those of the past in several
important ways. First, most new TOU rates contain three price tiers as opposed to the two-tier
rates common in many long-standing Tau programs, including those offered by PacifiCorp.
This allows utilities to set high prices during their highest peak periods and offer exceptionally
low off-peak prices overnight when the cost is at its lowest and supply is plentiful. The majority
of hours are assigned a "mid-peak" price that is typically a slightly discounted version of the
standard rate. Another change is that the duration of the peak period is typically 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 ITom the peak period. For long-standing Tau rates
this differential averaged about 7.6 cents/kWh, whereas newer programs tend to have a
differential of greater than 10 cents/kWh. For comparison, PacifiCorp s existing TaU rates offer
a price differential of roughly 4.5 cents/kWh to 7.5 cents/kWh, depending on the operating utility
and the season.
35 Includes: Gulf Power, Alabama Power, Ameren, Pacific Gas and Electric, Southern California Edison, San
Diego Gas and Electric, and Teco Energy. Interviews with utility staff: Arizona Public Service, Salt River
Project, and Florida Power and Light.
PacifiCorp -Assessment of Long-Term, System-Wide Potential
Tau 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 technically feasible
portion of the load basis expected to be reduced during peak hours is 5% based on results from
Califomia36 and Puget Sound Energy. The participation rate of the top ten highest-enrolled TaU
programs in the country7 is on average 16%, yet these programs do not represent the experience
of all national programs, many of which have participation rates of -::::1 %. If a robust marketing
effort is made in conjunction with a Tau rate design that is more than double PacifiCorp
current TaU differentia~ the expected participation rate is assumed to be 10%.
Table 25 shows there is 107 MW of technical potential and 11 MW of market potential in the
Rocky Mountain Power territory. In the Pacific Power territory, there is 78 MW of technical
potential and 8 MW of market, both representing less than 1 % of 2027 territory peak.
Sector
Table 25. Time of Use Rates: Technical and Market Potential (MW in 2027)
Rocky Mountain Power Pacific PowerTechnical Market Market as % Technical Market Market as %Potential Potential of 2027 Peak Potential Potential of 2027 Peak
106.7 10.7 0.5% 77.6 7.0.4%Residential
Commercial
Industrial
Irriaation
Total 106.10.77.6
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 program development
(based on 2002 PGE and PacifiCorp Tau rate program development costs ), $125 in new
participant costs ($100 per meter and $25 of marketing), with new participant costs reoccurring
with annual attrition of 5% (based on electrical tumovers ) and a 20-year measure life on
meters. Due to low per-customer impacts, the cost per kW-year is $166/kW-year for Rocky
Mountain Power territory and $173/kW-year for Pacific Power territory, which pass the
economic 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
2005. See also, Piette, Mary Ann and David S. Watson "Participation through Automation: Fully Automated
Critical Peak Pricing in Commercial Buildings " 2006, Lawrence Berkeley National Laboratory. Linkugel, Eric
Proceedings of the 2006 ACEEE Summer Study on Energy Efficiency in Buildings, Pacific Grove, CA, August
2006.
37 FERC, 2006 and R. Gunn
, "
North American Demand Response Survey Results" (Association of Energy
Services Professionals, Phoenix, AZ, February 2006).38 Levelized per unit costs are driven primarily by hardware costs. Removal of upfront development reduces the
results by $4/kW-year.39 This is likely a conservative estimate - PacifiCorp 2004 pilot TOU program experienced up to 25% annual
attrition.
PacifiCorp -Assessment of Long-Term, System-Wide Potential
~~~~
~%j".;tt~nL7EE:'
~, ,. ,~. ..-
Final Report Volume II
------,-,---
_.,.,-, _n ,--
Assessment of Long-Term
System-Wide Potential for
Demand-Side and Other
Supplemental Resources:
Appendices
------,-'.n,","'"-".,-
,',,
Prepared for PacifiCorp
July 11 , 2007
In Collaboration with Summit Blue Consulting and Nexant, Inc.
" , ,-,--~:..
L2~,,~~~i;Z!.~jE8~~~~tri1
.....a..
q~~ntec Raising the bar in t.Ulil0,'ffCS
~~~1:8l~i~~~1?f;t;c~"? :,:1J;'" -
. .
Principal Investigators:
Hossein Haeri, Ph., Lauren Gage, Tina Jayaweera, Ph., Collin Elliot
Eli Morris, Rick Ogle, P., Tony Larson , Aquila Velonis, Matei Perussi
Allen Lee, Ph., and Ann Griffin, Quantec, LLC.
Kevin Cooney, Randy Gunn, Stuart Schare
Adam Knickelbein, and Roger Hill, Summit Blue Consulting
Terry Fry, Mike Boutross, and Pranesh Venugopal, Nexant, Inc.
~jJlf 1iW~1:W!r o~gJP~.Cifie~=QP~'lRfPRIDP. a em C(?!p :LQ .RPfenJl ~l\.VO1 umeJ.F 1Q.g9.?~ T 06 f9~ 1 ~.1l~~&~
Quantec Offices
720 SWWashington, Suite 400
Portland, OR 97205
[phone]; [phone] fax
www.quantecilc.com
1722 14th SI., Suite 210
Boulder, CO 80302
[phone]; [phone] fax
28 E. Main SI., Suite A
Reedsburg, WI 53959
[phone]; [phone] fax
PonIed on
\%I recycled peper
3445 Grant SI.
Eugene, OR 97405
[phone]; [phone] fax
20022 Cove Circle
Huntington Beach, CA 92646
[phone]
Table of Contents: Volume I
Acknowledgeillents............... ............................................................................................ xiii
Executive Summary ................................................................................... ES-
Overview................................. ..................................,...... ....................... .........,............. ES-
SUI11111ary of the Results.....
............................................ ................................"............. .
ES- 2
Resource Acquisition Costs....... .................................................................................... ES-
Resource Potential Under Alternative Scenarios...........
....... ..............
...................."..... ES- 9
Introduction ............................................................................................
Background ...........................................................................,..............................................
Study Scope and Objectives................................................................................................ 2
General Approach........................................................................................ .......... ..............
Organization of the Report .................................................................................................. 8
Capacity-Focused Resources (Class 1 and Class 3 DSM) ................... 9
Scope of Analysis.................................................. .........................................,.... ................ 9
Assessment Methodology...................... ........ .............,..................................................... .
Resource Potential................................... ...........". ......................,.............................. ..."..
Resource Costs and Supply Curves ...................................................................................
Resource Acquisition Schedule... .......................... ................................."... ............"....... .
Resource Potential Under Alternative Scenarios...............................................................
Class 1 DSM Resource Results by Program Option .........................................................
Class 3 DSM Resource Results by Program Option .........................................................40
Energy-Efficiency Resources (Class 2 DSM) ...................................... 57
Scope of Analysis....................
"""""""""""""'" .............................................................
Resource Potential............. ................................................................................................ 58
Resource Potential Under Alternative Scenarios......
........... ..".......... .......".. .....................
Assessment Methodology..................................... .................".......................................... 63
Class 2 DSM Detailed Resource Potential........................................................................ 85
Education and Information (Class 4 DSM) ..........oo.............................. 95
Scope of Analysis................ ............".......... ........................ ..............................................
Potential and Costs........... ....
......... .......................,. ........... ................................"..... .........
PacifiCorp - Assessment of Long-Term, System-Wide Potential, Appendices
Supplemental Resou rces
.... ....... ............... .......... ..... ..... ............ .........
101
Scope of Analysis......................................................................................................... ...1 0 1
Assessment Methodology ....................................................................."........ .........." .....1 0 1
Resource Potential............. .......................................................... .................................... 102
Resource Acquisition Schedule........................ .......................
..................................... ...
1 04
Resource Potential Under Alternative Scenarios............................................................. 1 06
Combined Heat and Power Results .................................................................................107
On-Site Solar Results.................
"".""""" """""",."""""""""""
................. .."....... ....... 116
Dispatchable Standby Generation Results .......................................................................124
Effects of Structural Changes....
....... ................. ...... ..........................
129
Overview........................................................................................................................ ..129
Macroeconomic Structural Changes ...
................................................. ............................
130
Technological Changes.................................................................................................... 131
Public Policy and Regulation.................................................. .........................................132
PacifiCorp - Assessment of Long-Tenn, System -Wide Potential , Appendices
Table of Contents: Volume
Appendix A-1. Surveys Results, Overview ..........oo....oo..........oo.....oooo....oo.....
CI and CHP Survey Summaries ......................"..............................................................
Appendix A-2. Survey Results, Detailed ..............oo......................oo..oooo........
CI Survey Results: Overall ....
..........................,............................................................. .
A- 7
CHP Survey Results: Overall .....................................................................".................
Appendix A-3. Survey Instruments.. ..oooo..oo................ oo...... ..oo.....oooo......... ..
CI Survey Instrument...................................................................................... ............. ..A- 5 7
CHP Survey Instrument """"""""""""""""""""""""'.""""""""""""""...................A- 73
Appendix B-1. Capacity-Focused Resource Materials: Detailed
Assumptions by Program Option.............. ..oooo....oo...oo ............................. .....
DLC Residential - Air Conditioning Only.............................................................. ........
DLC Residential - Air Conditioning and Water Heating................................................
DLC CommerciaL........
""""""""""."""""""'.""""""""""""""""""""""""""'"
........ B-
Irrigation............... ............... ......................................................................."................. B-
Thennal Energy Storage......................................................................... .... .............".... B-
Curtailable Load........................................................................... ................................, B-
DelIland Bidding.......................................................................................... .................. B- 21
Residential Tune of Use Rates.............................. .....,........................................... ....... B- 25
Residential and Small Commercial Critical Peak Pricing .............................................
Commercial and Industrial: Critical Peak Pricing .........................................................
Real Tilne Pricing........... ................................................................... ........".................. B-
Appendix B-2. Capacity-Focused Resource Materials: Load Basis and
Calibration... ....
..... ....... .......... ... ....... ... .... ... ..... ............ ..... ............ ...............
California ...............................................................................,.......................................
Idaho .....,.................................................",.""""",."""""""""""""",.,."",..................
Oregon........................................................................................................................ ...
Utah................................................................................................................................
Washington.................................... ........... .................................. ............ ....................... B-
Wyoming ...",.,.,.""",.",.""""""""""""".."..................................................................
All States Total........................ .... ......................................... ...................,..... ................ B-
PacifiCorp - Assessment of Long-Term, System -Wide Potential , Appendices iii
Appendix 8-3. Capacity-Focused Resource Materials: Detailed
Program Results - Year and Market Segment (Summer) ..........................
DLC - RES - AC and Water Heat..................................................................................
DLC - RES - AC........................................................................................................... .B- 5 5
DLC - ComlTIercial ..... .................................... ............................................................... B- 5
Irrigation ...................... ........................................ .......................................................... B-
Thermal Energy Storage
............................"................................................ .................
Curtailable Load...................... ...................................................................................... B-
Time Of Use Rates................................................................ ..............."... ...........,......... B-
Appendix 8-4. Capacity-Focused Resource Materials: Winter Results....
Class I DR ProgrmTIs ....................................."..............................................................B- 75
Class 3 DR Progranls ..................................................................................................... B- 76
Appendix C-1. Technical Supplements: Energy Efficiency Resources,
Measure Descriptions ...................................................................................
Residential Measure Descriptions .......
...................................... ................... ....... ............
Residential Emerging Technology ................
.................... ............. ............"...... .......,.. .
Commercial Measure Descriptions ................................................. ...............................
Commercial Emerging Technologies........................................................................... .C- 28
Industrial Measure Descriptions............................................................ ...................... ..
Appendix C-2. Technical Supplements Energy Efficiency Resources,
Market Segmentation ..................................................................................
Baseline Forecasts .....................................,......... .........."............................................ ..C- 35
End Use Saturations and Electric Shares .......................................................................
End- Use Consumption Estin1ates
"""'."""""""""""""""""""""""" .........".... ...........
Appendix C-3. Technical Resources: Energy Efficiency Resources,
Measure Inputs...... ............... ...........
........... ..... ... ......... ........... ............ ..... ....
Appendix C-4. Technical Resources: Energy Efficiency Resources,
Class 2 DSM Decrement Analysis ..............................................................
Appendix D. Technical Supplements: Class 4 Resources..........................
Descriptions and References 1Dr Reviewed Programs.....................................................
PacifiCorp - Assessment of Long-Term, System -Wide Potential , Appendices
Appendix E-1. Technical Supplements: Supplemental Resources
CHP ............... .. .....
................. ....... ..... .......... ....... .......... ..... ...
............... ...... ..... E-
Appendix E-2. Technical Supplements: Supplemental Resources On-
Site Solar...... ..
..... ............ ..... ....... ............... ..... ......... ...........
........................ E-
Appendix E-3. Technical Supplements: Supplemental Resources
DSG...................... ............ ............ ...
......... .... .... ..... ....... ..... ... ....
........... ......... E- 79
Appendix F. Simulations & Home Electronics............................................. F-
Scope....... .................................................................................................... ............."...... F-
Methodology.......................................................................................... ...... ................., F -
Results............................................................................................................................ F -
Appendix G. Treatment of Externalities...................................................... G-
Introduction and Purpose............................................................................ ....,............... .
Objectives and Approach................................................................................................ .
Findings ...........................................................................................................................
PacifiCorp - Assessment of Long-Tenn, System -Wide Potential, Appendices
Irrigation
Table B.9. Program Basics
Program Name
Customer Sectors Eligible
End Uses Eligible for Program
Customer Size Requirements, if any
Summer Load Basis
Winter Load Basis
Irrigation
Irrigation only
Irrigation Pumping
All irrigation customers
Top 40 Summer Hours
No Winter
Table B,10. Inputs and Sources not Varying by State or SectorInputs Value Sources or AssumptionsAnnual Attrition (%) 5% Based on changes in electrical service
Annual Administrative Costs 15% All resource classes assume admin adder of 15%
(%)
Technology Cost (per new
participant)
Marketing Cost(per new
participant)
Incentives (annual costs per
participating kW)
000
$500
$20
Incentives (annual costs per $10participating kW)
Overhead: First Costs (2007$)$400,000
Technical Potential as % of 100%
Load Basis
Program Participation (%)25%
Event Participation (%)75%
per Customer Impacts (kW)Varies by
Sector
Technology costs assume $1000 per new participant for installation costs
Both Idaho Power and PacifiCorp marketing costs are approximately $500
per new participant
Idaho Power currently pays $16/kW/year; although Rocky Mountain Power
pays $11/kW, high program participation rates and acceptance by
customers can be attained only with higher incentives I particularly in
diverse geographic regions
Ongoing Maintenance and Communications (per KW)
Standard Program Development Assumption , including necessary internal
labor, research and IT/billing system changes
Assumes all loads can be controlled
Idaho Power and PacifiCorp have participation rates of 25% for the
scheduled program. PacifiCorp has signed up an additional 45 MW for the
DLC option, which totals 35% of the load basis. Assumes that more load
is available (50%)
Assumes that one-half of participants will be on scheduled program where
participants choose 2 days of each week to schedule reductions 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)
PacifiCorp - Assessment of Long-Tenn, System-Wide Potential, Appendices
Residential Time of Use Rates
Table B.lO. Program BasicsProgram 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 Requirements, if any ResidentialSummer Load Basis Top 40 Summer HoursWinter Load Basis Top 40 Winter Hours
Table B.ll. Inputs and Sources not Varying by State or SectorInputs Value Sources or AssumptionsAnnual Attrition (%) 5% Consistent with PacifiCorp electric turnovers. Rate of 3.5% reported by
Rosemary Morley of FPL.
All resource classes assume admin adder of 15%Annual Administrative Costs 15%
(%)
Technology Cost (per new $100
participant)
Marketing Cost (per new $25
participant)
Incentives (annual costs per
participant)
Overhead: First Costs (2007$)$400 000
Technical Potential as % of
Load Basis
Program Participation (%)10%
Event Participation (%)100%
per Customer Impacts (kW)
Incremental cost of a TOU meter, APS and FERC 2006
APS reported incremental costs of $20-$30 per new participant, including
marketing costs and support.
Bill savings may accrue for some customers, equating to lost revenues for
the utility. This analysis assumes revenue neutrality for the utility.
Standard Program Development Assumption , including necessary internal
labor, research and IT/billing system changes
California residential pricing programs results from CA SPP , fixed TOU
show 5% average peak demand reduced (Charles River Associates,
2005). Results from Puget Sound Energys cancelled TOU program are
similar.
APS has the highest TOU enrollment of any utility in the country at nearly
400 000 participants or 45% of residential customers (Chuck Miessner
APS, 2007; FERC report of 2006). The parti cipation rate of the top 10
highest-enrolled TOU programs in the country is on average 16%
(excluding the mandatory rates by PS Oklahoma. Yet, these programs do
not represent the experience of all national programs; many TOU
programs around the country have participation rates of 0::1 % (but many of
these are legacy programs that are not being promoted). Even among the
top 10 highest enrollment programs (according to FERC), half have single
digit participation rates. If a reasonable effort is made, the reasonable low
range might 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. Participation can be viewed as
100%.
Product of technical potential and average kW of customers based on load
basis. Consistent with national studies.
PacifiCorp - Assessment of Long-Tenn, System -Wide Potential, Appendices