20070816PAC to Staff 24, 32.pdf

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~OUNT AIN 201 South Main, Suite 2300
Salt lake City, Utah 84111
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August 15 2007
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Scott Woodbury
Deputy Attorney General
Idaho Public Utilities Commission
472 W Washington
Boise, ID 83702-5983
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Neil Price
Deputy Attorney General
Idaho Public Utilities Commission
472 W Washington
Boise, ID 83702-5983
RE:PAC-07-
IPUC Production Data Request 18-
Please find enclosed Rocky Mountain Power s Response to IPUC Production Requests
24 and 32.
If you have any questions, please feel free to call me at [phone].
Sincerely,
/J
*'"
c..(Brian Dickman, Manager
Regulation
Enclosures
P AC- E-07 -05/Rocky Mountain Power
August 15 2007
IPUC Production Data Request 24
IPUC Production Data Request 24
a. Please explain how the Idaho Irrigation Load Control program is modeled in
GRID.
b, Have the net power costs been adjusted to reflect the dispatchable pilot
program approved in Case No. PAC-06-12?
c. Have any adjustments been made to the Idaho jurisdictional loads and the
irrigation Schedule 10 loads to account for the approved pilot program?
d. How does the monthly peak reduction (actual and expected) for 2007 compare
with 2006 peak reduction?
Response to IPUC Production Data Request 24
a. The company includes the Idaho Irrigation Load Control program in its rate
case by reflecting the actual hourly weather normalized loads from 2006. The
loads include the actual Idaho irrigation curtailments and also include any
incremental loads caused by irrigators making up for the curtailment once the
curtailment restrictions are removed. The incentive payment made to
participating customers is included as other power supply cost in FERC
Account 557, and is situs assigned to the company s Idaho jurisdiction (refer
to Page 4.11 of Exhibit 11).
In responding to this request, the company discovered it also included the
Irrigation Load Control program as a system-allocated resource in the GRID
model in addition to the costs included in Account 557. The company will
provide a revised GRID run with its rebuttal testimony that corrects this
double inclusion of the program; the impact on the case will be minimal.
b. No. The Idaho case was prepared before the start ofthe 2007 irrigation
season. The best information available at the time the case was prepared was
the Schedule 72 Idaho Irrigation Load Control 2006 Credit Rider Initiative
Final Report which is provided as Attachment IPUC Production 24.
c. No.
d. During 2007 the company received approval to implement a pilot dispatchable
load control program (Schedule 72A) in addition to the pre-scheduled
curtailment program (Schedule 72). The lack of a full season s experience
with the pilot program, the uncertain duration of the pilot program, and the
differences between the two programs make it difficult to directly compare
peak reduction expected in 2007 to that achieved in 2006. During 2006, the
Schedule 72 pre-scheduled curtailment program had between 77 MW and 95
MW on a monthly basis, spilt between Monday-Wednesday and Tuesday-
Thursday curtailments (refer to Attachment IPUC Production 24).
PAC-07-05/Rocky Mountain Power
August 15, 2007
IPUC Production Data Request 24
Preliminary results for the 2007 irrigation season indicate that the Schedule
72A pilot program has between 45 and 55 MW of dispatchable curtailment
and the Schedule 72 pre-scheduled curtailment program has 50 MW split
between Monday- Wednesday and Tuesday-Thursday curtailments. Please
note: data for the 2007 irrigation is preliminary; verified customer counts, site
counts and associated loads will be provided in the final irrigation load control
program report at the conclusion of the 2007 irrigation season.
(Steven R. McDougal prepared this response and is the recordholder. It has not
been determined who will sponsor this response at hearing. Please contact Brian
Dickman at 801-220-4975 to discuss this response.
IDAHO
P AC-O7-
ROCKY MOUNTAIN POWER
IPUC PRODUCTION DATA REQUESTS 18-
TT ACHMENT IPUC PRODUCTION
ROCKY MOUNTAIN
POWER
A DIVISION OF PAClF1CORP
Idaho Public Utilities Commission
472 West Washington
Boise, ill 83702-5983
RECE\\lEO
'lOnb NO~ - 2 ~"\O: Z \
I I',"iJ ,JOt. v
UT\~Rf~s COMM\SS\O,\
201 South Main, Suite 2300
Salt Lake City, Utah 84111
November 2, 2006
PAC--03 -14
Attention:Jean D. Jewell
Commission Secretary
Re:'Idaho 2006 Irrigation Load Control Credit Rider Program Evaluation Report
PacifiCorp d.a. Rocky Mountain Power (the Company) hereby submits an original and eight
copies of the 2006 Idaho Irrigation Load Control Credit Rider Program Evaluation Report. The
purpose of this filing is to comply with Commission Order Nos. 29209 and 29416 and provide an
annual evaluation of the Irrigation Load Control Credit Rider program.
The Company does not intend to make a separate application in 2006 to change the amount of
the Schedule 72 Load Control Service Credit for the 2007 irrigation season. On May 24, 2006
the Company entered into an agreement with the Idaho Irrigation Pumpers Association that the
tariff amount for 2007 will equal the current amount (subject to Commission approval, Docket
No. PAC-06-4). However, per program specifications, the Company will notify all Schedule
10 customers of the 2007 credit level by January 15 2007.
It is respectfully requested that all formal correspondence and staff requests regarding this matter
be addressed to:
By E-mail (preferred):datareq uest€Yoacifi corp. com
By Fax:[phone]
By regular mail:Data Request Response Center
PacifiCorp
825 NE Multnomah St., Suite 2000
Portland, OR 97232
Informal questions should be directed to Brian Dickman [phone].
sin~d~A~
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:~sl=n (p,
Vice President, Regulation
Enclosures
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 ............,...........................................................,........,....."................................,........,.................................. 1
Cost effectiveness analyses............,......,........,...........................................................,......,.......................................... 5
2005 cost effectiveness calculation error................................,.....................................................................,..............
Load profile data.......................................,............................,...,.........................,..........................................................
Technical challenges..........................,......,.......................,......,.,....,.....................,........................,.......................,.....
Measurement & Verification (M&V) processes
""""""""""""""""""""""""""""""""""""""""""""""'"...........
Crop type analysis..........,...................,.............................."""""""""""""""""""""""""""""""""""""....,.."........
Program enhancements under consideration ..........................................,...,.,.................."""""""""""""""""""" 16
2006 Idaho l11igation Load Control Program-Final Report
Background
Idaho Public Utilities Commission Order No. 29209 and Order No. 29416 in Case No, PAC-E-Q3-14 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 tinder 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
2003 Actual Participants
2004 Actual Participants
2005 Actual Participants
2006 Actual Participants
Eligible 2006 Counts
Customers NOT eligible to participate 2006
Nom: ba~d on 15 Sepmmher re~
Partici ant Sites
401
734
065
931
636
N/A
Participant Customers
207
340
489
478
044
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 subsequenUy loads change throughout the
irrigation season as Program participation status may change as a function of agri-business, weather, crop type and/or equipment vagaries.
Wherever possible and based on what the Irrigation Management Team has detennined to be the most understandable way to communicate
quantitative Program demographics and impacts. reporting date may change. Accordingly, and throughout this report the(jate for the specific
quantitative result will be noted.
2006 Idaho Irrigation Load Control Program-Final Report
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 selection2. 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-paTticipation. 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
of47., a difference of3.7MW.
Table Two
2006 Participation Credits x Month
Credits
kW Under Contract
June
$240 705.
82,652.
July
$317,825.
100,131.8
August
$288,371.66
95,321.
September
$78,674.
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.
2006/daho Irrigation Load Control Program-Final Report
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 the~e 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 (April '03-Sept '03)Oct 'O3-Sept 'Oct 'O4-Sept 'Oct 'O5-Sept '
Administrati~~- support $9,613.$1,665.$851,$194:60
Program evaluation $2,135.43 $8,369.$377.$0.
Field Db admin. expenses $250,222,$239,807,$326,061.$330,802,ijQ
Participation ~re(lits $277,583.$410,325.$842,666.80 ,$925,577.
Program management $10,992.$55,036.$54,826.$ 42 554.
Reporting $351.79 $1,940.$0.$0.
Total Program costs -$550,900.$717,143.$1,224,783.$1,299,128.
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 thatthe 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, representing 91% of total Program
participation.
2006 Idaho Irrigation Load Control Program-Final Repod 3 -
Table Five
Program Impacts by Participation Option
Participation Site June Avoided July Avoided Aug. Avoided Sept. Avoided
tion Ct.
I MW 2-8pm 411 35,708.557.605.34,931,
I TTH2-8pm 437 35,151.6 43,869.41,314.36,016.
II MW3-6pm 895.957.939.835.
II MW4-7pm 268.1,495.1,417.818.
II TTH 3-6pm 395.597.589.541.1
II TTH 4-7pm 631.789.656.453,
III MWTTH 3-6pm 458.666.632.579.
III MWTTH 4-7pm 699.825.710,682.4
IV M 2-8pm 358.052.996,850.
Totals:931 77,568.95,811.7 90,860.709.
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 Ctrl. Day & Hour
Hour
Avoided kW
JUNE TuesdaylThursday Avoided kW by Hour
2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-8:59
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 TuesdaylThursday Avoided kW by Hour
2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:Q0.6:59
43,869.5 45,133,8 46,748.7 46.748,7 45,484.
7:00-7:59
43,869.
Hour
Avoided kW
AUGUST TuesdaylThursday Avoided kW by Hour
2:00-2:59 3:00-3:59 4:()Q..4:59 5:00-5:59 6:0Q.;6:59
41,314.0 42,535.2 43,901.6 43,901.6 42,080.
7:00-7:59
41,314.
Hour
Avoided kW
SEPTEMBER TuesdaylThursday 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
36,016.
2006 Idaho Irrigation Load Control Program-Final Report
Table Seven
2006 Avoided kW by Month, Monday / Wednesday Ctrl. Day & Hour
Hour
Avoided kW
JUNE MondaylWednesday Avoided kW by Hour
2:00-2:59 3:00-3:59 4:004:59 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 4:004:59 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 4:004:59 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
41,605.
Hour
Avoided kW
SEPTEMBER MondaylWednesday Avoided kW by Hour
2:00-2:59 3:00-3:59 4:004:59 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 (TRe)
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.
2006 Idaho Irrigation Load Control Program"Final Report - 5-
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 benefiUcost ratio would be infinite for the Participant Test and
the value is indicated as 'NIA' in Table Eight.
Table Eight
2006 Cost Effectiveness Analyses
Test Benefits Costs Net Benefits Benefit/Cost Ratio
TRC $1,246,330.$374,096.$872,234.
Utility $1,246,330,$1,299,673.($53,342.97)
Ratepayer $1,246,330.$1,299,673.~$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 3,81. a difference of 0.87.
Table Nine
Original Values Reported in 2005 Cost Effectiveness Analyses
Test Benefits Costs Net Benefits Benefit/Cost Ratio
TRC 124,284 $382,117 $742,167
".-
Utility 124 284 $1,224,784 $ (100,499)
.""----.--..---.-.
Ratepayer 124,284 $1,224,784 $ (100,499)
---"
Participant $842,667 $ 842,667 N/A
2006 Idaho Irrigation Load Control Program-Final Reporl 6 -
Table Ten
Corrected 2005 Cost Effectiveness Analyses
Test Benefits Costs Net Benefits Benefit/Cost Ratio
TRC $1,455,484 $382,117 073,367
Utility $1,455,484 $1,224 784 $230,700 1.19
Ratepayer $1,455,484 $1,224,784 $230,700 1.19
Participant $ 842,667 $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 aster
control vs. non-control periods were also calculated.
Illustration One (Schedule 72 Idaho Irrigation Load Control-Average Daily Load CuNe: Control VB. Non-Control
Periods for July August (Ce 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, oh:ourse, is greater in
the heat of the afternoon. Further note that the 'gap' narrows in the afternoon and in early evening hours.
2006 Idaho Irrigation Load Control Program-Final Report - 7-
lIiusiration One
Schedule 72 Idaho Irrigation Load Controi-lweiage Daily Load Curve:
Control vs" Non-Contro: Periods for July & August (CS 57-Big Gr2ssy
25"
,. 2M
~5"
10"
limo 124 h,,"
I-cut Do~ (More Th) -An Non-"'" Day-. (FrlI , SaL,Suo,) I
Illustration Two (Schedule 72 Idaho Irrigation Load Contiol-Daily Load Curve: Control Average Control Dispatch
Schedule (MlWvs. TTH) Averages (CB 67-Big Grassy)) plots Big Grassy 120-second interval load data by the two
principle control periods (!VIfW and TfTH). 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'.
2006 Idaho Irrigation Load Control Program-Final Report - 8-
IIlusu-aiion Two
Schedule 72 idaho Irrigation Load Control-Daily Load Curve:
Control Average & Cantro: Dispatch Schedule (MNV vs, TTH) lwerages (CB 57-Big Grassy)
lime (2.4 h...
i-A,,!:" McnlWe1J CI~ Days -A,,!:, T...,,'ThurCtrI Do,.. -AVO All Clo" DaY" I
Illustration Three (Schedule 72 Idaho irrigation Load Control-Daily Load Curve: Individual Control Day-or-Week
Overalf Average Control Days) plots Big Grassy 120-second intervalloaddata"by individual day-of-week (ctrl 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.
2006 idaho inigaiion Load Control Program-Final Report
Illustration Three
Schedule 72 idaho Irrigation Load Control-Daily Load Curve:
Individua! C~mtrol Day-of-Week & OveraJ: ,Average Control Days(CB 57-8i9 Grassy
10"
/213 1'15/617/819/10/,,1'2/'3114/15/16/17/18
time (24 h".
, -"
Monde!, - - " - , ..esaay - - . " - Wednesdey "- - " - Thursday -A,-,"" MonIWeO -A,'I:" .uelThur -Ave" All Clrt Days
Illustration Four (Schedule 72 Idaho Irrigation Loaa' Control-Daily Load Curve: Control Average vs. Non-Control Days
(Ca 67-Big Grassy)) plots Big Grassy 120-second interval load data by (1) individual non-control day-or-week, (2)
average for all norl-control days and (3) the average for all control days. Highlighted is the six-hour dispatch block and
the resulting impacts of norl-control days"
2006 idaho irrigation !.oad Contro! Program-Final RepoIt 10
lIiustration Four
Schedule 72 Idaho irrigation Load Contro!-Daily Load Curve:
Contro! Average vs" Non-Contro! Days (CS 67-Big Grassy)
t;m. (24 hIS.
" Sun"a, - - " - - rriOay " - - - " Salumay Non-Clrt,Day AVO,Cllt Day AVO"
Illustration Five (Schedule 72 Idaho Irrigation Load Control-Daily Load Curve: Total PacifiCorp Hourly Idaho Load
(July) Estimated Impact of Schedule 72) plots the total Company average hourly interval load data for the month of
Julys. Also plotted is a 44MW decrement (estimated average avoided MW generated as a function of Schedule 72
across the 6 hr dispatch block). While Schedule 72 accounts for a measured 'dip' in the load profile, the Idaho load
even without Schedule 72 would naturafly 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 nof yet iully adjudi::ated ior F"RC reoorting; nevertheless it is not anticipated there will be
measured deviafions iTom what is indicated in Illustration Five
2006 Idaho Irrigation Load Coniro! Program-Final Report 11.
Illustration Five
Schedule 72 Idaho Irrigation Load Control-Daily Load Curve:
Total ?acifiCOrD Hourly idaho Load (July) & ::stimated Impact of Schedule 72
59D
~ SDD
58D
570
560
=50
t;me (24 h'-I
!-TOL JD July Load Profile I
T ec:hnic:al 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, Consoridated 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 preciseiy pin-point the cause of batiery failure.
Additional analysis was conducted during the early winter. Around the first of the New Year the principal board
designer was contacted and a fOok:aUS8 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 t'1e 2006
Program season.
6 Gres:sun is a European timer manufacturer who was acquired by GE in 2002.
2006 Idaho Irrigation Load Control Program-Final Report - i2-
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 of field 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 ID 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
QA Parameter
SitelD Sticker
Seal
Pum Panel
Meter Lock
Clock Calendar
Batte
Ctof
Failures
Ct. of
Units
Inspected
144
144
144
144
144
144
Percent
Failure
28.50%
20%
50%
70%
70%
00%
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 Site
2006 Idaho Irrigation Load Control Program-Final Report 13 -
Avoided kW presents 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
Crop Type No. of Sites
grain ~39hay 378spuds 186
_._._
p"asture
~~-
rass "- corn
----9.olf courses
sodtrees canal
. grain/potatoes
~_.
recha~
potatoes/corn
Totals 1,153
Tot. Av . kW
363.
442.
24,400.
992.
273.
024.
124.
419.
76.
366.
257.
13.
292.
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.
Tab/e 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 2006iniliativeornol ,
2006 Idaho Irrigation Load Control Program-Final Report 14 -
Table Thirteen
2006 Program Participant Estimation of Crop Type x Site & Avoided kW
Crop Type
grain
hay
spuds
pasture
ras
~_-
com
golf courses
sad
trees
canal
.Jjrainlpotatoes
potatoes/com
recharge
Totals
No. of Sites
360
315
894.
Tot. Av . kW
44,309.
31,912.
13,131.
612.
065.
268.
122.
419.
76.
366.
257.
292.
13.
95,847.
Table Fourteen: 2006 Program Participant Estimation of Crop Acreage x 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
com
grass
grain/potatoes
sad
golf courses
potatoes/corn
trees
Totals
Total Acres
64,026
50,623
13,970
644
2,460
534
200
560
300
300
121
138,737
2006 Idaho Irrigation Load Control Program-Final Report 15 -
Program enhancements under consideration
Over the course of the three years that Schedule 72 (Irrigation Load Contro~ 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 I (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 a 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, a successful trial could
mean the technology would be considered for implementation in the 2007 irrigation season. The information that
follows is a 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 altemative 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 beerJ 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 a
favorable endorsement as a function of little / no reports of failure / malfunction during the five years it has
been in the fields. 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 a 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 a 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 a 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
currently incurred as a function of crop rotations. Ultimately, and over time, the M2M equipment would
replace the current solid state Grasslin timers.
8 As reported by equipment distributors, customers and Yalley s own internal statistics.
2006 Idaho Irrigation Load Control Program-Final Report 160
Equipment benefits / costs
AQ 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 interest' (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 E= $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 sites require lwo or more timers. This situation occurs when a grower does not have either a pressure switch or a low
voltage control connection belween the pump and the pivot. In these instances the cost to rontrol that site is roughly doubled or $600 per site.
2006 Idaho Irrigation Load Control Program-Final Report 17 -
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.
2006 Idaho Irrigation Load Control Program-Final Report 18.
PAC-07-05/Rocky Mountain Power
August 15 2007
IPUC Production Data Request 32
IPUC Production Data Request 32
Please provide transmission costs associated with qualifying facilities referenced
on page 5 in Company witness Bennion s testimony, along with any additional
costs included in this rate filing, Please list the transmission costs by QF
specifying the location of each QF.
Response to IPUC Production Data Request 32
Pursuant to PURP A guidelines and state commission policies, QFs are generally
required to pay the utility most or all costs required to interconnect their projects
to the utility s transmission system. Transmission upgrades which principally
improve service quality, reliability, and delivery of power to meet general
customer load requirements may be exceptions. During the test year in this rate
case, the company did not upgrade any qualifying facility interconnection
requirements in the generation interconnection or transmission project queue.
(Douglas N. Bennion prepared this response, is the recordholder, and is expected
to sponsor this response at hearing. Please contact Brian Dickman at 801-220-
4975 to discuss this response.