HomeMy WebLinkAbout20110718PAC to IIPA Attach 34 -2.pdf
Schedule 72 & 72A Idaho Irrigation Load Control
Programs
2010 Credit Rider Initiative Final Report
7 January 2011
ID PAC-E-11-12
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Table of Contents
Page
Report Organization .................................................................................................................................................... 1
Background ................................................................................................................................................................. 1
2010 Schedule 72 (Scheduled Forward) Results ..................................................................................................... 1
Table One Longitudinal and Current Year Scheduled 72 Eligible & Full-Year Participating Sites & Customers .... 1
Table Two 2010 Schedule 72 Participation Credits by Month................................................................................. 2
Table Three Longitudinal and Current Year Scheduled 72 Participation Credits Issued ........................................ 2
Table Four Comparative Scheduled 72 & 72A (Total) Costs 2003, 2004 & 2005 ................................................... 2
Table Five Schedule 72 Program Nominal Loads by Participation Option ............................................................. 3
Table Six Schedule 72 2010 Nominal kW by Month, Monday Control Day & Hour ............................................... 4
Table Seven Schedule 72 2010 Nominal kW by Month, Tuesday Control Day & Hour ......................................... 4
Table Eight Schedule 72 2010 Nominal kW by Month, Wednesday Control Day & Hour ...................................... 5
Table Nine Schedule 72 2010 Nominal kW by Month, Thursday Control Day & Hour .......................................... 5
Cost-effectiveness analyses ..................................................................................................................................... 6
Table Ten 2010 Benefit / Cost Categories & Values−Schedule 72 ........................................................................ 6
Table Eleven 2010 Cost-effectiveness Analyses−Schedule 72 .............................................................................. 7
Measurement & Verification (M&V) processes ........................................................................................................ 7
2010 Schedule 72A (Dispatch) Results ..................................................................................................................... 8
Table Twelve Schedule 10 Eligible & Full-Year Participating Sites & Customers ................................................... 8
Customer Opt-Outs .................................................................................................................................................... 8
Table Thirteen Opt-outs, Liquidated Damages, kW NOT Avoided and $/MWh by Dispatch Event ........................ 8
Table Fourteen 2010 Dispatch Dates & Durations .................................................................................................. 9
Dispatch Events .......................................................................................................................................................... 9
Problem definition .................................................................................................................................................. 9
Analysis and solution .......................................................................................................................................... 10
Results .................................................................................................................................................................. 11
Illustration One Stair−Stepping Big Grassy Distribution Substation.................................................................... 11
Grid-ops tap change dispatches......................................................................................................................... 11
Illustration Seven Impacts of Grid Operations Dispatch Events .......................................................................... 12
Table Fifteen Dispatch Program Only: SCADA Estimated Load (kW) Impacts x Dispatch Event x Designated
Northern Tier Transmission Substations (Amps, Big Grassy, Bonneville, Jefferson & Rigby) .............................. 14
Table Sixteen Dispatch Program Realized Net Load: SCADA Estimated Derived (kW) Impacts x Dispatch Event
x Designated Northern Tier Transmission Substations (Amps, Big Grassy, Bonneville, Jefferson & Rigby ......... 15
Table Seventeen: Dispatch Program Impacts less Nominal Opt-Outs ................................................................. 16
Table Eighteen: Net Load Estimated Impacts to the Grid in Northern Tier Areas ................................................ 16
Table Nineteen: Total Dispatchable Program (grossed-up) Estimated Impacts x Hour x Dispatch Event ........... 17
Cost-effectiveness analyses ................................................................................................................................... 18
Table Twenty 2010 Benefit / Cost Categories & Values−Schedule 72A ............................................................... 18
Table Twenty-One 2010 Cost-effectiveness Analyses.......................................................................................... 18
2010 Schedule 72 & Schedule 72A Results ............................................................................................................ 19
Avoided demand ....................................................................................................................................................... 19
Table Twenty-Two Program Impacts by Participation Option ............................................................................... 19
Illustration Eight Dispatch Windows for Dispatch Event Scheduled Blocks & Asset Management Dispatches .... 20
Table Twenty-Three Hourly Estimated Load Impacts Entire 2010 Program Season ............................................ 21
Load profile data impact analysis ........................................................................................................................... 27
Cost-effectiveness analyses ................................................................................................................................... 27
Table Twenty-Four 2010 Benefit / Cost Categories & Values−Schedules 72 & 72A ............................................ 27
Table Twenty-Five 2010 Cost-effectiveness Analyses.......................................................................................... 28
Conclusions............................................................................................................................................................... 28
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Grid characteristics and associated distribution of program loads ............................................................... 28
Grower perception considerations ..................................................................................................................... 28
Change considerations ....................................................................................................................................... 29
Meteorological considerations ........................................................................................................................... 29
Recommendations .................................................................................................................................................... 29
Attachment One: Rocky Mountain Power Northern Tier Transmission Substations ........................................ 31
Geo-spatial location of transmission substations .................................................................................. 31
Big Grassy Plots ............................................................................................................................................... 32
Amps Plots ......................................................................................................................................................... 34
Bonneville Plots ................................................................................................................................................ 36
Jefferson Plots .................................................................................................................................................. 38
Rigby Plots ......................................................................................................................................................... 40
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Report Organization
Idaho Public Utilities Commission Order No. 29209 and Order No. 29416 in Case No. PAC-E-03-14 requires Rocky
Mountain Power (the Company), a division of PacifiCorp, prepare an annual report on the Idaho Irrigation Load
Control Program (Program). In 2007, and as approved by the Commission in Order No. 30243, Rocky Mountain
Power (RMP) initiated a Dispatch irrigation pilot program (Schedule 72A) evaluating the efficacy of a 2-way control
technology. This report presents quantitative results on Schedule 72 and Schedule 72A as required by the
Commission order. The Schedule 72A assessment will follow the standard report. Summary statistics from both
Schedule 72 and Schedule 72A will be combined and presented. Recommendations and Conclusions will be
presented. All costs are accrued for the 2010 program year (1 October 2009 through 31 September 2010) with the
exception of participation credits.
Unless otherwise noted, data are calculated as of 19 October 2010. It should be further noted that in
previous years report analysis was done on nominal (book) values of participating loads. In 2010 and
primarily for Dispatch results we reflect avoided load data based on estimated SCADA analysis of avoided
loads.
Background
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
2010 Schedule 72 (Scheduled Forward) Results
Table One
Longitudinal and Current Year Scheduled 72 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
2007 Actual Participants 681 405
2008 Actual Participants 87 79
2009 Actual Participants 123 112
2010 Actual Participants 122 105
Eligible 2010 Counts 4,701 1,975
Customers NOT eligible to participate 2010 N/A 0
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Table Two
2010 Schedule 72 Participation Credits by Month
June July August
Standard Credits $11,686.82 $15,491.89 $14,630.13
kW Under Contract 3,950.51 4,466.0 4,332.0
Total Credits $41,808.84
Note: avoided kW is as of the day of credit issuance
Table Three
Longitudinal and Current Year Scheduled 72 Participation Credits Issued
Year Total Participation Credits Issued
2003 $277,583.72
2004 $410,325.49
2005 $842,666.80
2006 $925,577.33
2007 $684,924.98
2008 $30,680.65
2009 $43,912.27
2010 $41,808.84
Table Four
Comparative Scheduled 72 & 72A (Total) Costs 2003, 2004 & 2005
Cost Category
2003 Costs
(April ’03−Sept ’03)
2004 Costs
Oct ‘03−Sept ‘04
2005 Costs
Oct ‘04−Sept ‘05
Administrative support $9,613.43 $1,665.29 $851.56
Program evaluation $2,135.43 $8,369.88 $1,820.00
Field / Equip / Db admin. expenses $250,222.98 $239,807.03 $326,061.01
Participation credits $277,583.72 $410,325.49 $842,666.80
Program management $10,992.99 $55,036.29 $54,826.69
Reporting $351.79 $1,940.00 $0.00
Total Program costs $550,900.34 $717,143.98 $1,226,226.06
Note: 2003 costs over 6 month period; subsequent Program-year costs are calculated over a 12 month period (1 October thru 31
September)
1 Throughout this report and in all cases avoid demand nominal values are reported at the site and are NOT grossed-up by 10.39% for generation
thereby taking into account T&D losses.
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Table Four (cont)
Comparative Load Control Program (Total) Costs 2006, 2007 & 2008
Cost Category
2006 Costs
Oct ‘05−Sept ‘06
2007 Costs
Oct ‘05−Sept ‘06
2008 Costs
Oct ‘07−Sept ‘08
Administrative support $194.60 $1,500.00 $1,640.50
Program evaluation $1,125.00 $2,268.75 $2,268.75
Field / Equip / Db admin. expenses $330,802.05 $747,664.85 $2,816,386.26
Participation credits $925,577.33 $1,752,930.47 $5,993,868.57
Program management $42,554.85 $80,144.00 $94,051.68
Reporting $0.00 $0.00 $0.00
Total Program costs $1,300,253.83 $2,584,508.07 $8,908,215.76
Table Four (cont)
Comparative Load Control Program (Total) Costs 2009 & 2010
Cost Category
2009 Costs
Oct ‘08−Sept ‘09
2010 Costs
Oct ‘09−Sept ‘010
Administrative support $253.27 $0.0
Program evaluation $4,195.00 $11,758
Field / Equip / Db admin. expenses $3,361,818.68 $3,801,022.87
Participation credits $7,246,582.84 $8,101,480.75
Program management $67,760.75 $117,518.03
Reporting $0.0 $0.0
Total Program costs $10,680,610.54 $12,031,779.65
Table Five
Schedule 72 Program Nominal Loads by Participation Option
Participation Option
Site
Cnt.
June
Avoided kW
July Avoided
kW
Aug. Avoided
kW
Option I m w 2-8 52 1,713.5 1,797.5 2,019.0
Option I t th 2-8 39 910.0 1,012.5 992.0
Option II m w 3-6 10 293.5 393.5 298.5
Option II m w 4-7 0 0 0 0
Option II t th 3-6 0 0 0 0
Option II t th 4-7 1 20.0 20.5 19.0
Option III m t w th 3-6 8 344.5 376.0 316.5
Option III m t w th 4-7 1 31.0 31.0 30.0
Option IV m 2-8 8 264.5 384.0 290.5
Option IV w 2-8 3 182.5 273.5 275.0
Schedule Forward Totals 122 3,760 4,289 4,241
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Tables Six through Nine transpose the data presented in Table Five into hourly dispatch schedules by each of the
four Schedule Forward dispatch days (Monday−Thursday). Each of the four subsequent tables indicates the avoided
kW by month, control day (Monday−Thursday) and hour.
Table Six
Schedule 72 2010 Nominal kW by Month, Monday Control Day & Hour
JUNE Monday Avoided kW by Hour
Hour 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 1,978.0 2,616.0 2,647.0 2,647.0 2,009.0 1,978.0
JULY Monday Avoided kW by Hour
Hour 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 2,181.5 2,951.0 2,982.0 2,982.0 2,212.5 2,181.5
AUGUST Monday Avoided kW by Hour
Hour 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 2,309.5 2,924.5 2,954.5 2,954.5 2,339.5 2,309.5
Table Seven
Schedule 72 2010 Nominal kW by Month, Tuesday Control Day & Hour
JUNE Tuesday Avoided kW by Hour
Hour 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 910.0 1254.5 1305.5 1305.5 961.0 910.0
JULY Tuesday Avoided kW by Hour
Hour 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 1,012.5 1,388.5 1,440.0 1,440.0 1,064.0 1,012.5
AUGUST Tuesday Avoided kW by Hour
Hour 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 992.0 1,308.5 1,357.5 1,357.5 1,041.0 992.0
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Table Eight
Schedule 72 2010 Nominal kW by Month, Wednesday Control Day & Hour
JUNE Wednesday Avoided kW by Hour
Hour 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 1,896.0 2,534.0 2,565.0 2,565.0 1,927.0 1,896.0
JULY Wednesday Avoided kW by Hour
Hour 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 2,071.0 2,840.5 2,871.5 2,871.5 2,102.0 2,071.0
AUGUST Wednesday Avoided kW by Hour
Hour 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 2,294.0 2,909.0 2,939.0 2,939.0 2,324.0 2,294.0
Table Nine
Schedule 72 2010 Nominal kW by Month, Thursday Control Day & Hour
JUNE Thursday Avoided kW by Hour
Hour 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 910.0 1,254.5 1,305.5 1,305.5 961.0 910.0
JULY Thursday Avoided kW by Hour
Hour 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 1,012.5 1,388.5 1,440.0 1,440.0 1,064.0 1,012.5
AUGUST Thursday Avoided kW by Hour
Hour 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
Avoided kW 992.0 1,308.5 1,357.5 1,357.5 1,041.0 992.0
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Cost-effectiveness analyses
Cost-effectiveness is calculated for the following program components:
1. Schedule 72 (Scheduled Forward) only
2. Schedule 72A (Dispatch) only
3. Schedule 72 and Schedule 72A (combined)
Results on each of the four standard utility industry tests−(1) Total Resource Cost (TRC); (2) Utility; (3)
Ratepayer and (4) Participant will be provided for each of the three aforementioned program cases. The tests
for Schedule 72 (Scheduled Forward option) will be based upon the cost and nominal MW values as defined
in Table Ten below2. The information below will describe the methodology used in evaluating each of the
subsequent program components.
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 tests3. The benefits (avoided costs) are based on the calculations as defined by the Company’s
Integrated Resource Planning (IRP) organization and presented to the Idaho Public Utilities Commission,
and the Idaho Irrigation Pumpers’ Association in a report titled Proposed Valuation Methodology for the Idaho
Irrigation Load Control Program. It should be noted that the avoided costs used in all cost-effectiveness
analyses calculations presented in this report considered the overall program size (Scheduled Forward +
Dispatch program options) rather than individual program characteristics. From an analytic perspective it is
clear that the Dispatch initiative is valued higher than a Scheduled Forward option. That said the
extraordinarily smaller size of the Schedule Forward initiative compared to the Dispatch option simply did not
warrant a separate avoided cost analysis.
Table Ten
2010 Benefit / Cost Categories & Values−Schedule 72
Cost Categories Cost Values Benefit Category Benefit Value
Administrative support $0.0 $/kW-yr avoided $73.09/kW
Program evaluation $175.46
Field / Equip / Db admin. expenses $56,722.69
Participation credits $41,808.84
Program management $1,753.72
Total $100,460.72
Note: with the exception of participation credits costs have been allocated based on the percent of load the
Schedule Forward option comprises of the total (combined) irrigation load control programs.
Costs used in these calculations include administrative costs, contractor costs (field technician, customer
service, equipment and back office system design / administration) and associated participant credits costs.
2 To the extent possible, certain cost categories have been allocated by (1) the respective Schedule initiative and (2) percent of participating load.
3 Note that no discounting of costs or benefits was required in this analysis since all costs and benefits occurred in program year 2010.
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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 Cadmus using a simplified spreadsheet analysis.
This analysis multiplies nominal demand reductions for the June, July and August period (as is consistent
with previous program year calculations) as a result of customers participating in the Program by the
estimated value of avoided demand noted above. As noted, the avoided demand value of is $73.09/kW-yr is
increased by 10.39% to account for the effect of T&D line losses, resulting in a value of $81.56/kW-yr used in
the cost-effectiveness calculations.
Based on previous research that showed energy use is ‘shifted’ rather than ‘avoided’, lost revenues are not
included as a cost and energy savings are not applicable as indicated above.
As shown in Table Eleven, the Scheduled Forward component of the program passes the TRC Test. The
Scheduled Forward program also passes the Utility and Ratepayer Test. Since the participant incurs no costs
the benefit/cost ratio would be infinite for the Participant Test. Accordingly, for the Participant Test the value
is indicated as ‘N/A’ in Table Eleven.
Table Eleven
2010 Cost-effectiveness Analyses−Schedule 72
Test Benefits Costs Net Benefits Benefit/Cost Ratio
TRC $147,542.97 $58,651.87 $88,891.10 2.52
Utility $147,542.97 $100,460.71 $47,082.26 1.47
Ratepayer $147,542.97 $100,460.71 $47,082.26 1.47
Participant $41,808.84 $0.00 $41,808.84 N/A
Measurement & Verification (M&V) processes
The control equipment provides log files that can authoritatively determine issues of grower fraud and/or
tampering with the control equipment. Throughout the 2010 season there remained a residual amount of
confusion among growers relative to equipment / program operations. Accordingly, the Irrigation
Management Team decided that it would be important to provide additional M&V field technician site visits.
This was done to meet customer services as well as M&V objectives. In the end there were no sites reported
to be out of compliance relative to grower fraud. There was, throughout each of the site visits, significant
attention to training and easing grower fears / concerns regarding the remote control equipment and how
best to operate the equipment relative to agri-operation requirements.
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2010 Schedule 72A (Dispatch) Results
Table Twelve
Schedule 10 Eligible & Full-Year Participating Sites & Customers
Participant Sites Participant Customers
2008 Actual Participants 1,491 530
2009 Actual Participants 1,927 826
2010 Actual Participants 2,194 773
Eligible 2010 Counts 4,701 1,975
Customers NOT eligible to participate 2010 N/A 0
Note: ‘customers’ is a calculated number and is based on a query employing the ‘distinct’ operand
Customer Opt-Outs
Schedule 72A permits growers to ‘opt-out’ of five Dispatch Events throughout the Irrigation Season. Each of
these opt-out events incurred a cost resulting in a reduction to the customer’s Load Control Service Credit.
The cost to opt-out is the day-ahead ($/MWh) RMP would otherwise have to pay for power during that
dispatch period. A summary of opt-outs, liquidated damages and kW not avoided by each of the Dispatch
Events is presented in Table Thirteen. Table Fourteen summarizes 2010 dispatch dates and durations.
Table Thirteen
Opt-outs, Liquidated Damages, kW4 NOT Avoided and $/MWh by Dispatch Event
Count Dispatch Date Weekday Count of Sites Opting-outs Liquidated Damages kW NOT Avoided $/MWh (day ahead)
1 29-Jun Thursday 40 $856.05 4,553.5 $47.00
2 8-Jul Thursday 45 $1,040.61 5,946.0 $43.75
3 15-Jul Thursday 125 $4,124.64 19,830.0 $52.00
4 16-Jul Friday 98 $3,587.08 15,802.0 $56.75
5 19-Jul Monday 90 $3,920.19 17,269.5 $56.75
6 20-Jul Tuesday 142 $4,909.27 23,157.0 $53.00
7 26-Jul Monday 81 $2,177.28 11,458.5 $47.50
8 2-Aug Monday 33 $986.39 4,811.5 $51.25
9 5-Aug Thursday 40 $1,502.75 7,551.5 $49.75
10 24-Aug Thursday 25 $1,258.80 5,245.0 $60.00
11 26-Aug Thursday 21 $697.98 3,116.0 $56.00
totals / average ($/MWh) 740 $25,061.04 118,740.5 $52.16
4 kW represents connected load based on the average monthly demand for June, July and August for 2008 and 2009.
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Table Fourteen
2010 Dispatch Dates & Durations
Dispatch dates
Dispatch
Duration (hours)
Dispatch dates
Dispatch
Duration (hours)
June August
Tuesday, June 29, 2010 4 Monday, August 02, 2010 4
Thursday, August 05, 2010 4
July Tuesday, August 24, 2010 4
Thursday, July 08, 2010 4 Thursday, August 26, 2010 4
Thursday, July 15, 2010 4
Friday, July 16, 2010 4 Grid-ops dispatch
Monday, July 19, 2010 4 Tuesday, June 01, 2010 1
Tuesday, July 20, 2010 4 Wednesday, June 02, 2010 1
Monday, July 26, 2010 4 Monday, June 07, 2010 1
Wednesday, July 14, 2010 4
Grand Total hours 51
Dispatch Events
Problem definition
In 2009 the Customer & Community Management (C&CM) organization along with the Irrigation
Management Team learned that Dispatch Events (DE) could no longer simply be implemented in a single 4-
hour window. The reason for this was as follows:
The distribution system in southeast Idaho that serves rural, primarily agri-irrigtion areas has very
little / no automation. Accordingly, capacitors are manually engaged each season as irrigation load
increases at the beginning of the season. The capacitors are disengaged at the end of the season
in a similar manner.
Pump load (motors) create inductive line reactance (lagging); line capacitors (capacitance
reactance) are placed on the circuits to counter-act this effect so the sinusoid electrical wave is at
unity or as close to unity as possible thereby maintaining operational efficiency.
By the time irrigation load control begins to execute dispatch events all line capacitor banks have
been manually engaged.
To compensate, the Company would have to physically disengage the capacitor banks in
anticipation of a DE and correspondently reengage the capacitor banks following each event in
order to accommodate the return of the inductive load, an activity that from a resource perspective
is not supportable.
Moreover, and with the precipitous and instantaneous drop in load, the voltage regulators (which
are in the distribution substation as well as on the distribution circuits themselves) simply do not
have sufficient time to make a ‘step change’ to maintain appropriate voltages. Note: regulators
require ~90s to ‘adjust’ to a change in the load.
Due to (1) the magnitude of the program’s participating loads, (2) the concentration of loads on
agricultural-dominant substations and (3) circuits not having the capability to scale loads DE events
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were inadvertently creating a situation where there is (1) too much capacitor reactance and (2) too
high of voltage (outside of IEEE + tariff specifications).
To avoid this situation DE’s require intelligent scheduling / implementation. In 2010 and beyond DE’s would
be required to be implemented in such a way that Irrigation Load Control provided a rudimentary ‘Smart
Grid’. Additionally and anticipated, ‘smart implementation’ would augment existing infrastructure assets and
perhaps improve Grid performance. A description of the problem solving process and the benefits associated
with the resultant approach are discussed below.
Analysis and solution
To deliver on this objective a 6-month modeling exercise was undertaken. The effort involved professional
resources from Customer & Community Management (C&CM), Grid-Ops, Area Planning, Distribution
Engineering, Metering, and Demand Side Management. The effort began with an inventory of loads for each
of the five transmission substations that provide service to those geo-spatial areas where there is
extraordinary concentration of program participants. In fact, 77.9% of total program participation (on a load
basis) is served by the five transmission substations.
Working with Distribution Engineering (Rexburg Service Center) distribution substations and their associated
circuits were mapped to participating pump / pivot loads. Mapping was completed using the Company’s
CADOPS Engineering Database. Coincident with the aforementioned mapping effort the Area Planning
organization for Idaho prepared a ‘flicker study’ that would model upper and lower limits of loads that could
be removed / added to the circuit in any single ‘step’ before a power excursion >3% would be generated.
The 3% variation was determined to be the acceptable limit for tariff and IEEE compliance.
Pursuant to the flick study and armed with distribution substation performance parameters, the Irrigation
Management Team constructed a step-function load model for each circuit, distribution substation and
transmission substation. Each DE step-function had a ‘bounded kW’ value for load removal. Specific sites
and the associated grower were identified and ‘tagged’ by circuit, distribution substation and transmission
substation. Field technicians most familiar with the area served by a transmission substation were asked to
allocate farms / loads in the most appropriate manner to (1) meet target load drops as defined above and (2)
accommodate farming operations.
Field technicians were then tasked to visit each grower together with the appropriate C&CM representative.
The field technician, C&CM representative along with the grower reviewed the specific ‘dispatch slot’ to
determine if the specified ‘dispatch slot’ would work given their farms, labor, equipment and irrigation delivery
system configurations. Subsequent feedback necessitated changes to the schedule. Altogether 52 separate
dispatches were designed and grower sites slotted into one of the following three 4-hour DE time periods.
11:00a ................... 3:00p
2:00p ..................... 6:00p
3:00p ..................... 7:00p
Once into the dispatch season the Irrigation Management Team learned from Area Planning that the Hamer
Distribution Substation which was originally planned to be fed out of Jefferson Transmission Substation
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would, for the 2010 season, continue to be fed out of Big Grassy. After the first four DE’s the C&CM
representative along with the Irrigation Management Team was informed that DE’s were continuing to over-
volt the Big Grassy transmission sub. Further dispatching would require that still further load be shifted away
from the 11:00a − 7:00p dispatch window. Accordingly, a fourth dispatch window was established that
operated from 7:00a − 11:00a. Approximately 20 MW of load was shifted to the 7:00a − 11:00a dispatch
window. Here as in other aspects of the Irrigation Load Control initiative, growers stepped-up and
volunteered to change their schedule to accommodate the new requirement.
Results
The result of the stair−stepping of load into and out of DE was a remarkable success. The stair-stepping
worked as expected. Distribution Engineering and Area Planning reported no voltage excursions beyond
standard operating parameters. The impact of stair−stepping on the Big Grassy transmission substation is
depicted in Illustration One which comes directly from Company SCADA data on a sample DE day. Nearly
identical results were replicated on each of the DEs across each of the transmission substations.
Illustration One
Stair−Stepping Big Grassy Distribution Substation
Grid-ops tap change dispatches
Grid Operations together with Idaho Area Planning decided in early July that a 2-step tap change would be
required on the Big Grassy transmission substation in order to maintain voltages within tariff specifications.
Grid Ops approached the Irrigation Management Team requesting a ‘special’ 1-hour dispatch of ~20 MW on
the Big Grassy substation. Coinciding with this DE would be a shift in the load that feeds the associated
distribution subs (Hamer, Camas, Dubois and Sandune). Executing the tap change in this manner would
allow customers to enjoy continuous service without the inconvenience of a planned outage for ALL loads on
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the four distribution substation associated with the Big Grassy transmission substation. Plans to implement
this transition were made for 1 July. The 1 July effort failed due to a problem with the phase shifter on the line
to Anaconda. A second attempt was made the following day (2 July) but this attempt also failed as the loads
were out of synch and the tap change could not be negotiated. A third attempt was initiated on 7 July. The 7
July effort was successful and is so illustrated in Illustration Seven along with the 1 July and 2 July failed
attempts.
Grid Operations again contacted the Company’s Irrigation C&CM and the Irrigation Management Team on 14
July. This time Grid-Ops requested what was at first a 3-hour dispatch and later revised for an additional
single hour in response to a five-mile area of line that had been destroyed in a brush fire. The results of these
special Grid-Ops dispatches are depicted in Illustration Seven.
Illustration Seven
Impacts of Grid Operations Dispatch Events
Table Fifteen provides the estimated loads by dispatch hour for each of the DE’s in 2010. The use of
estimated data is markedly different from previous year reporting where only nominal (book) loads were
used. To the extent possible SCADA estimates provide the basis for avoided kW. The reader should keep in
mind that the values reported on the five transmission substations reflect 77.9% of total program
participation. To assess total program participation one would need to ‘gross-up’ the avoided kW values by
dividing the reported kW by 77.9%. This grossing-up of estimates is performed for the data reported in Table
Nineteen.
The loads reflected in Table Fifteen do NOT take into account credits for AMD dispatch sites and their
associated loads. The AMD loads, of course, are not available for dispatch as they were dedicated for the
big grassy (grid ops dispatches)
0
5
10
15
20
25
30
35
40
45
50
55
0:0
0
0:3
2
1:0
4
1:3
6
2:0
8
2:4
0
3:1
2
3:4
4
4:1
6
4:4
8
5:2
0
5:5
2
6:2
4
6:5
6
7:2
8
8:0
0
8:3
2
9:0
4
9:3
6
10
:
0
8
10
:
4
0
11
:
1
2
11
:
4
4
12
:
1
6
12
:
4
8
13
:
2
0
13
:
5
2
14
:
2
4
14
:
5
6
15
:
2
8
16
:
0
0
16
:
3
2
17
:
0
4
17
:
3
6
18
:
0
8
18
:
4
0
19
:
1
2
19
:
4
4
20
:
1
6
20
:
4
8
21
:
2
0
21
:
5
2
22
:
2
4
22
:
5
6
23
:
2
8
time
mw
1-Jul 2-Jul 7-Jul 14th fire
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AMD trials. Accordingly, the net estimated realized loads for dispatch across each of the five transmission
substations are presented in Table Sixteen.
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Table Fifteen
Dispatch Program Only: SCADA Estimated Load (kW) Impacts x Dispatch Event x Designated Northern
Tier Transmission Substations (Amps, Big Grassy, Bonneville, Jefferson & Rigby)
Date Weekday 7:00-7:59 8:00-8:59 9:00-9:59 10:00-10:59 11:00-11:59 12:00-12:59 1:00-1:59 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59
29-Jun Thursday 0.0 0.0 0.0 0.0 53,225.2 53,225.2 53,225.2 87,725.2 106,918.7 106,918.7 106,918.7 72,418.7
8-Jul Thursday 0.0 0.0 0.0 0.0 53,225.2 53,225.2 53,225.2 87,725.2 106,918.7 106,918.7 106,918.7 72,418.7
15-Jul Thursday 0.0 0.0 0.0 0.0 53,225.2 53,225.2 53,225.2 87,725.2 106,918.7 106,918.7 106,918.7 72,418.7
16-Jul Friday 0.0 0.0 0.0 0.0 53,225.2 53,225.2 53,225.2 87,725.2 106,918.7 106,918.7 106,918.7 72,418.7
19-Jul Monday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 67,782.6 102,976.1 102,976.1 102,976.1 69,418.7
20-Jul Tuesday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 67,782.6 102,976.1 102,976.1 102,976.1 69,418.7
26-Jul Monday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 67,782.6 102,976.1 102,976.1 102,976.1 69,418.7
2-Aug Monday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 67,782.6 102,976.1 102,976.1 102,976.1 69,418.7
5-Aug Thursday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 67,782.6 102,976.1 102,976.1 102,976.1 69,418.7
24-Aug Thursday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 67,782.6 102,976.1 102,976.1 102,976.1 69,418.7
26-Aug Thursday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 67,782.6 102,976.1 102,976.1 102,976.1 69,418.7
Note: to estimate the total program load impacts x hour one should divide each of the values in the table above by 77.9%.
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Table Sixteen
Dispatch Program Realized Net Load: SCADA Estimated Derived (kW) Impacts x Dispatch Event x Designated Northern
Tier Transmission Substations (Amps, Big Grassy, Bonneville, Jefferson & Rigby
Date Weekday 7:00-7:59 8:00-8:59 9:00-9:59 10:00-10:59 11:00-11:59 12:00-12:59 1:00-1:59 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59
29-Jun Thursday 0.0 0.0 0.0 0.0 53,225.2 53,225.2 53,225.2 76,751.0 95,944.5 95,944.5 95,944.5 61,444.5
8-Jul Thursday 0.0 0.0 0.0 0.0 53,225.2 53,225.2 53,225.2 76,751.0 95,944.5 95,944.5 95,944.5 61,444.5
15-Jul Thursday 0.0 0.0 0.0 0.0 53,225.2 53,225.2 53,225.2 76,751.0 95,944.5 95,944.5 95,944.5 61,444.5
16-Jul Friday 0.0 0.0 0.0 0.0 53,225.2 53,225.2 53,225.2 75,031.4 94,224.9 94,224.9 94,224.9 59,724.9
19-Jul Monday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 57,028.7 92,222.2 92,222.2 92,222.2 58,664.8
20-Jul Tuesday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 58,481.5 93,675.0 93,675.0 93,675.0 60,117.6
26-Jul Monday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 57,028.7 92,222.2 92,222.2 92,222.2 58,664.8
2-Aug Monday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 57,028.7 92,222.2 92,222.2 92,222.2 58,664.8
5-Aug Thursday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 56,808.4 92,002.0 92,002.0 92,002.0 58,444.5
24-Aug Thursday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 67,782.6 102,976.1 102,976.1 102,976.1 69,418.7
26-Aug Thursday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 67,782.6 102,976.1 102,976.1 102,976.1 69,418.7
Note: the green highlighted areas are those where the AMD loads have been removed from the values presented in Table Fifteen. In fact the AMD dispatch loads extended to the
8:00p hour.
Table Seventeen presents the AMD impacts in the 7:00p-7:59 hour. Note: values in Table Seventeen are negative as these are loads not available for dispatch on the respective
DE weekday. Table Eighteen presents net load estimated impacts to the Grid less the Opt-Outs. That is, the column to the far right presents load impacts to northern tier areas
served by Amps, Big Grassy, Bonneville, Jefferson or Rigby (what the Grid would actually see in that area). Also presented in the column to the furthest right are the avoided
‘grossed-up’ loads x hour x DE. Values in June and August have been adjusted based on the percent of load they represent of the max July values. Accordingly, June was
factored by 92.7% and August factored by 98.6%.
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Table Seventeen:
Dispatch Program Impacts less Nominal Opt-Outs
Date Weekday 7:00p-7:59p Date Weekday 7:00p-7:59p
29-Jun Thursday (10,974.2) 26-Jul Monday (10,753.9)
8-Jul Thursday (10,974.2) 2-Aug Monday (10,753.9)
15-Jul Thursday (10,974.2) 5-Aug Thursday (10,974.2)
16-Jul Friday (12,693.7) 24-Aug Thursday (10,974.2)
19-Jul Monday (10,753.9) 26-Aug Thursday (10,974.2)
20-Jul Tuesday (9,301.1)
Table Eighteen:
Net Load Estimated Impacts to the Grid in Northern Tier Areas
Date Weekday 7:00-7:59 8:00-8:59 9:00-9:59 10:00-10:59 11:00-11:59 12:00-12:59 1:00-1:59 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 Impacts Less Opt -Outs Impacts Grossed-up
29-Jun Thursday 0.0 0.0 0.0 0.0 53,225.2 53,225.2 53,225.2 76,751.0 95,944.5 95,944.5 95,944.5 61,444.5 155,810.7 200,013.7
8-Jul Thursday 0.0 0.0 0.0 0.0 53,225.2 53,225.2 53,225.2 76,751.0 95,944.5 95,944.5 95,944.5 61,444.5 166,749.5 214,055.8
15-Jul Thursday 0.0 0.0 0.0 0.0 53,225.2 53,225.2 53,225.2 76,751.0 95,944.5 95,944.5 95,944.5 61,444.5 152,865.5 196,233.0
16-Jul Friday 0.0 0.0 0.0 0.0 53,225.2 53,225.2 53,225.2 75,031.4 94,224.9 94,224.9 94,224.9 59,724.9 153,454.4 196,989.0
19-Jul Monday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 57,028.7 92,222.2 92,222.2 92,222.2 58,664.8 149,981.4 192,530.7
20-Jul Tuesday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 58,481.5 93,675.0 93,675.0 93,675.0 60,117.6 146,999.6 188,703.0
26-Jul Monday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 57,028.7 92,222.2 92,222.2 92,222.2 58,664.8 155,792.4 199,990.2
2-Aug Monday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 57,028.7 92,222.2 92,222.2 92,222.2 58,664.8 160,110.8 205,533.8
5-Aug Thursday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 56,808.4 92,002.0 92,002.0 92,002.0 58,444.5 156,975.8 201,509.4
24-Aug Thursday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 67,782.6 102,976.1 102,976.1 102,976.1 69,418.7 180,882.9 232,198.8
26-Aug Thursday 18,000.0 18,000.0 18,000.0 18,000.0 34,225.2 34,225.2 34,225.2 67,782.6 102,976.1 102,976.1 102,976.1 69,418.7 182,981.4 234,892.7
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Table Nineteen presents the Net Load Impacts to the Grid for all Program Areas. In this presentation the value of AMD are added back into the avoided kW values as the
Company received benefit on the respective weekdays. Because AMD’s fell outside of DE’s, calculations were performed to add AMD values as if they executed simultaneous
with the DE. Opt-outs are once again excluded from these values as these loads were appropriately captured in credit calculations issued to growers. The values in Table
Nineteen are those that are representative of system impacts as a function of the dispatch initiative.
Table Nineteen:
Total Dispatchable Program (grossed-up) Estimated Impacts x Hour x Dispatch Event
Date Weekday 7:00-7:59 8:00-8:59 9:00-9:59
10:00-
10:59
11:00-
11:59
12:00-
12:59 1:00-1:59 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
29-Jun Thursday 0.0 0.0 0.0 0.0 68,325.0 68,325.0 68,325.0 102,987.0 127,625.6 127,625.6 127,625.6 83,338.1 4,461.9
8-Jul Thursday 0.0 0.0 0.0 0.0 68,325.0 68,325.0 68,325.0 102,987.0 127,625.6 127,625.6 127,625.6 83,338.1 4,461.9
15-Jul Thursday 0.0 0.0 0.0 0.0 68,325.0 68,325.0 68,325.0 102,987.0 127,625.6 127,625.6 127,625.6 83,338.1 4,461.9
16-Jul Friday 0.0 0.0 0.0 0.0 68,325.0 68,325.0 68,325.0 106,254.9 130,893.6 130,893.6 130,893.6 86,606.0 9,937.4
19-Jul Monday 18,000.0 18,000.0 18,000.0 18,000.0 43,934.8 43,934.8 43,934.8 80,386.5 125,564.3 125,564.3 125,564.3 82,486.8 7,178.9
20-Jul Tuesday 18,000.0 18,000.0 18,000.0 18,000.0 43,934.8 43,934.8 43,934.8 105,483.0 150,660.8 150,660.8 150,660.8 107,583.3 30,410.5
26-Jul Monday 18,000.0 18,000.0 18,000.0 18,000.0 43,934.8 43,934.8 43,934.8 80,386.5 125,564.3 125,564.3 125,564.3 82,486.8 7,178.9
2-Aug Monday 18,000.0 18,000.0 18,000.0 18,000.0 43,934.8 43,934.8 43,934.8 80,386.5 125,564.3 125,564.3 125,564.3 82,486.8 7,178.9
5-Aug Thursday 18,000.0 18,000.0 18,000.0 18,000.0 43,934.8 43,934.8 43,934.8 77,386.7 122,564.6 122,564.6 122,564.6 79,487.0 4,461.9
24-Aug Thursday 18,000.0 18,000.0 18,000.0 18,000.0 43,934.8 43,934.8 43,934.8 87,012.3 132,190.1 132,190.1 132,190.1 89,112.6 0.0
26-Aug Thursday 18,000.0 18,000.0 18,000.0 18,000.0 43,934.8 43,934.8 43,934.8 87,012.3 132,190.1 132,190.1 132,190.1 89,112.6 0.0
hourly average 52,804.0 52,804.0 52,804.0 92,115.4 129,824.4 129,824.4 129,824.4 86,306.9 7,248.4
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Cost-effectiveness analyses
Cost-effectiveness calculations were prepared for each of the four standard utility industry tests in the
manner consistent with that described above for the Schedule 72 portion of this program. Benefits and costs
for Schedule 72A (Dispatch option) upon which calculations are prepared are presented in Table Twenty
below5.
Again, the cost-effectiveness of the Program was calculated by Cadmus using a simplified spreadsheet
analysis. This analysis multiplies nominal demand reductions for the June, July and August period (as is
consistent with previous program year calculations) less opt-out MW’s by the estimated value of avoided
demand. In the case of Schedule 72A, the value of potential avoided demand is based on the volume of
avoided kW times dispatch hours and the benefit calculations provided by PacifiCorp. The avoided cost
benefits were presented to the Idaho Public Utilities Commission and the Idaho Irrigation Pumpers’
Association in a report titled Proposed Valuation Methodology for the Idaho Irrigation Load Control Program.
The 2010 value was determined to be $73.09/kW-yr. Values are increased by 10.39% to account for the
effect of T&D line losses setting the value used in the calculations at $81.56/kW-yr.
Table Twenty
2010 Benefit / Cost Categories & Values−Schedule 72A
Cost Categories Cost Values Benefit Category Benefit Value
Administrative support $0.0 $/kW-yr avoided $73.09/kW
Program evaluation $11,582.54
Field / Equip / Db admin. expenses $3,744,300.18
Participation credits $7,980,582.30
Program management $115,764.31
Total $11,852,229.32
As shown in Table Twenty-One, Schedule 72A passes the TRC, Utility and Ratepayer Tests. The Program also
passes the Participant Test. However, since the participant incurs no costs the benefit/cost ratio would be infinite.
Accordingly for the Participant Test the value is indicated as ‘N/A’ in the Benefit/Cost Ratio column.
Table Twenty-One
2010 Cost-effectiveness Analyses
Test Benefits Costs Net Benefits Benefit/Cost Ratio
TRC $21,094,596.62 $3,871,647.03 $17,222,949.59 5.45
Utility $21,094,596.62 $11,852,229.33 $9,242,367.29 1.78
Ratepayer $21,094,596.62 $11,852,229.33 $9,242,367.29 1.78
Participant $7,980,582.30 $0.00 $7,980,582.30 N/A
5 Again, to the extent possible, costs have been allocated by the respective Schedule initiative
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2010 Schedule 72 & Schedule 72A Results
This section of the report provides quantitative summaries of the two combined initiatives−Schedule 72 (Scheduled
Forward) and Schedule 72A (Dispatch).
Avoided demand
Program nominal impacts by participation option for both Schedule 72 and 72A are presented in Table
Twenty-Two.
Table Twenty-Two
Program Impacts by Participation Option
Option Counts June Avoided kW July Avoided kW Aug Avoided kW
Option I m w 2-8 52 1,713.5 1,797.5 2,019.0
Option I t th 2-8 39 910.0 1,012.5 992.0
Option II m w 3-6 10 293.5 393.5 298.5
Option II m w 4-7 0 0 0 0
Option II t th 3-6 0 0 0 0
Option II t th 4-7 1 20.0 20.5 19.0
Option III m t w th 3-6 8 344.5 316.5
Option III m t w th 4-7 1 31.0 30.0
Option IV m 2-8 8 264.5 384.0 290.5
Option IV w 2-8 3 182.5 273.5 275.0
Scheduled Forward totals 122 3,760 4,289 4,241
Option dispatch dispatchable 2,194 257,882.0 278,291.5 274,302.0
Grand Totals: 2,316 261,641.5 282,580.0 278,542.5
Illustration Eight, and with the exception of the Grid-Ops dispatches, depicts the four foundational dispatch
blocks. Also note the specific reference to the ‘super-on-peak’ and ‘on-peak’ dispatch time horizons.
The potential avoided demand by dispatch hour associated with each of the Dispatch Events is presented in
Table Twenty-Three. The values in this table are additive. That is, they represent the combination of
Scheduled Forward loads plus Dispatch loads and are ‘grossed-up’ for the entire program6. In considering
these data a zero (0) occasionally appears. This is due to the fact that the Scheduled Forward initiative
operates Monday thru Thursday inclusive. For instance, when the Dispatch initiative was exercised on Friday
the only avoided demand is that associated with Dispatch loads and none occurred after 7:00 pm on Friday.
6 The values remain at ‘site’ and are NOT ‘grossed-up’ for T&D losses.
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Illustration Eight
Dispatch Windows for Dispatch Event Scheduled Blocks & Asset Management Dispatches
Season-long hourly estimated load impacts for Schedule 72 and 72A are presented in Table Twenty-Three. The tan color-coding represents the hour and day of DEs. The blue
color-coding represents Schedule Forward dispatches.
7:00-7:59 8:00-8:59 9:00-9:59 10:00-10:59 11:00-11:59 12:00-12:59 1:00-1:59 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
On-Peak period
Super On-Peak period
AMD selected days
7:00a-11:00a BG only starting @ 19 July dispatch
11:00a-3:00p
2:00p-6:00p
3:00p-7:00p
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Table Twenty-Three
Hourly Estimated Load Impacts Entire 2010 Program Season
1-Jun 2-Jun 3-Jun 4-Jun
monday tuesday wednesday thursday friday
2:00-2:59 na 910.0 1,896.0 910.0 0.0
3:00-3:59 na 1,254.5 2,534.0 1,254.5 0.0
4:00-4:59 na 1,305.5 2,565.0 1,305.5 0.0
5:00-5:59 na 1,305.5 2,565.0 1,305.5 0.0
6:00-6:59 na 961.0 1,927.0 961.0 0.0
7:00-7:59 na 910.0 1,896.0 910.0 0.0
7-Jun 8-Jun 9-Jun 10-Jun 11-Jun
monday tuesday wednesday thursday friday
2:00-2:59 1,978.0 910.0 1,896.0 910.0 0.0
3:00-3:59 2,616.0 1,254.5 2,534.0 1,254.5 0.0
4:00-4:59 2,647.0 1,305.5 2,565.0 1,305.5 0.0
5:00-5:59 2,647.0 1,305.5 2,565.0 1,305.5 0.0
6:00-6:59 2,009.0 961.0 1,927.0 961.0 0.0
7:00-7:59 1,978.0 910.0 1,896.0 910.0 0.0
14-Jun 15-Jun 16-Jun 17-Jun 18-Jun
monday tuesday wednesday thursday friday
2:00-2:59 1,978.0 910.0 1,896.0 910.0 0.0
3:00-3:59 2,616.0 1,254.5 2,534.0 1,254.5 0.0
4:00-4:59 2,647.0 1,305.5 2,565.0 1,305.5 0.0
5:00-5:59 2,647.0 1,305.5 2,565.0 1,305.5 0.0
6:00-6:59 2,009.0 961.0 1,927.0 961.0 0.0
7:00-7:59 1,978.0 910.0 1,896.0 910.0 0.0
21-Jun 22-Jun 23-Jun 24-Jun 25-Jun
monday tuesday wednesday thursday friday
2:00-2:59 1,978.0 910.0 1,896.0 910.0 0.0
3:00-3:59 2,616.0 1,254.5 2,534.0 1,254.5 0.0
4:00-4:59 2,647.0 1,305.5 2,565.0 1,305.5 0.0
5:00-5:59 2,647.0 1,305.5 2,565.0 1,305.5 0.0
6:00-6:59 2,009.0 961.0 1,927.0 961.0 0.0
7:00-7:59 1,978.0 910.0 1,896.0 910.0 0.0
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 24 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 22
Table Twenty-Three (cont.)
Hourly Estimated Load Impacts Entire 2010 Program Season
28-Jun 29-Jun 30-Jun 1-Jul 2-Jul
monday tuesday wednesday thursday friday
11:00-11:59 0.0 68,325.0 0.0 0.0 0.0
12:00-12:59 0.0 68,325.0 0.0 0.0 0.0
1:00-1:59 0.0 68,325.0 0.0 0.0 0.0
2:00-2:59 1,978.0 103,897.0 1,896.0 1,012.5 0.0
3:00-3:59 2,616.0 128,880.1 2,534.0 1,388.5 0.0
4:00-4:59 2,647.0 128,931.1 2,565.0 1,440.0 0.0
5:00-5:59 2,647.0 128,931.1 2,565.0 1,440.0 0.0
6:00-6:59 2,009.0 84,299.1 1,927.0 1,064.0 0.0
7:00-7:59 1,978.0 5,371.9 1,896.0 1,012.5 0.0
5-Jul 6-Jul 7-Jul 8-Jul 9-Jul
monday tuesday wednesday thursday friday
11:00-11:59 0.0 0.0 0.0 68,325.0 0.0
12:00-12:59 0.0 0.0 0.0 68,325.0 0.0
1:00-1:59 0.0 0.0 0.0 68,325.0 0.0
2:00-2:59 2,181.5 1,012.5 2,071.0 103,999.5 0.0
3:00-3:59 2,951.0 1,388.5 2,840.5 129,014.1 0.0
4:00-4:59 2,982.0 1,440.0 2,871.5 129,065.6 0.0
5:00-5:59 2,982.0 1,440.0 2,871.5 129,065.6 0.0
6:00-6:59 2,212.5 1,064.0 2,102.0 84,402.1 0.0
7:00-7:59 2,181.5 1,012.5 2,071.0 5,474.4 0.0
12-Jul 13-Jul 14-Jul 15-Jul 16-Jul
monday tuesday wednesday thursday friday
11:00-11:59 0.0 0.0 0.0 68,325.0 68,325.0
12:00-12:59 0.0 0.0 0.0 68,325.0 68,325.0
1:00-1:59 0.0 0.0 0.0 68,325.0 68,325.0
2:00-2:59 2,181.5 1,012.5 2,071.0 103,999.5 106,254.9
3:00-3:59 2,951.0 1,388.5 2,840.5 129,014.1 130,893.6
4:00-4:59 2,982.0 1,440.0 2,871.5 129,065.6 130,893.6
5:00-5:59 2,982.0 1,440.0 2,871.5 129,065.6 130,893.6
6:00-6:59 2,212.5 1,064.0 2,102.0 84,402.1 86,606.0
7:00-7:59 2,181.5 1,012.5 2,071.0 5,474.4 9937.4
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 25 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 23
Table Twenty-Three (cont.)
Hourly Estimated Load Impacts Entire 2010 Program Season
19-Jul 20-Jul 21-Jul 22-Jul 23-Jul
monday tuesday wednesday thursday friday
7:00-7:59 18,000.0 18,000.0 0.0 0.0 0.0
8:00-8:59 18,000.0 18,000.0 0.0 0.0 0.0
9:00-9:59 18,000.0 18,000.0 0.0 0.0 0.0
10:00-10:59 18,000.0 18,000.0 0.0 0.0 0.0
11:00-11:59 43,934.8 43,934.8 0.0 0.0 0.0
12:00-12:59 43,934.8 43,934.8 0.0 0.0 0.0
1:00-1:59 43,934.8 43,934.8 0.0 0.0 0.0
2:00-2:59 82,568.0 106,495.5 2,071.0 1,012.5 0.0
3:00-3:59 128,515.3 152,049.3 2,840.5 1,388.5 0.0
4:00-4:59 128,546.3 152,100.8 2,871.5 1,440.0 0.0
5:00-5:59 128,546.3 152,100.8 2,871.5 1,440.0 0.0
6:00-6:59 84,699.3 108,647.3 2,102.0 1,064.0 0.0
7:00-7:59 9,360.4 31,423.0 2,071.0 1,012.5 0.0
26-Jul 27-Jul 28-Jul 29-Jul 30-Jul
monday tuesday wednesday thursday friday
7:00-7:59 18,000.0 0.0 0.0 0.0 0.0
8:00-8:59 18,000.0 0.0 0.0 0.0 0.0
9:00-9:59 18,000.0 0.0 0.0 0.0 0.0
10:00-10:59 18,000.0 0.0 0.0 0.0 0.0
11:00-11:59 43,934.8 0.0 0.0 0.0 0.0
12:00-12:59 43,934.8 0.0 0.0 0.0 0.0
1:00-1:59 43,934.8 0.0 0.0 0.0 0.0
2:00-2:59 82,568.0 1,012.5 2,071.0 1,012.5 0.0
3:00-3:59 128,515.3 1,388.5 2,840.5 1,388.5 0.0
4:00-4:59 128,546.3 1,440.0 2,871.5 1,440.0 0.0
5:00-5:59 128,546.3 1,440.0 2,871.5 1,440.0 0.0
6:00-6:59 84,699.3 1,064.0 2,102.0 1,064.0 0.0
7:00-7:59 9,360.4 1,012.5 2,071.0 1,012.5 0.0
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 26 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 24
Table Twenty-Three (cont.)
Hourly Estimated Load Impacts Entire 2010 Program Season
2-Aug 3-Aug 4-Aug 5-Aug 6-Aug
monday tuesday wednesday thursday friday
7:00-7:59 18,000.0 0.0 0.0 18,000.0 0.0
8:00-8:59 18,000.0 0.0 0.0 18,000.0 0.0
9:00-9:59 18,000.0 0.0 0.0 18,000.0 0.0
10:00-10:59 18,000.0 0.0 0.0 18,000.0 0.0
11:00-11:59 43,934.8 0.0 0.0 43,934.8 0.0
12:00-12:59 43,934.8 0.0 0.0 43,934.8 0.0
1:00-1:59 43,934.8 0.0 0.0 77,386.7 0.0
2:00-2:59 82,696.0 992.0 2,294.0 78,378.7 0.0
3:00-3:59 128,488.8 1,308.5 2,909.0 123,873.1 0.0
4:00-4:59 128,518.8 1,357.5 2,939.0 123,922.1 0.0
5:00-5:59 128,518.8 1,357.5 2,939.0 123,922.1 0.0
6:00-6:59 84,826.3 1,041.0 2,324.0 80,528.0 0.0
7:00-7:59 9,488.4 992.0 2,294.0 5,453.9 0.0
9-Aug 10-Aug 11-Aug 12-Aug 13-Aug
monday tuesday wednesday thursday friday
7:00-7:59 0.0 0.0 0.0 0.0 0.0
8:00-8:59 0.0 0.0 0.0 0.0 0.0
9:00-9:59 0.0 0.0 0.0 0.0 0.0
10:00-10:59 0.0 0.0 0.0 0.0 0.0
11:00-11:59 0.0 0.0 0.0 0.0 0.0
12:00-12:59 0.0 0.0 0.0 0.0 0.0
1:00-1:59 0.0 0.0 0.0 0.0 0.0
2:00-2:59 2,309.5 992.0 2,294.0 992.0 0.0
3:00-3:59 2,924.5 1,308.5 2,909.0 1,308.5 0.0
4:00-4:59 2,954.5 1,357.5 2,939.0 1,357.5 0.0
5:00-5:59 2,954.5 1,357.5 2,939.0 1,357.5 0.0
6:00-6:59 2,339.5 1,041.0 2,324.0 1,041.0 0.0
7:00-7:59 2,309.5 992.0 2,294.0 992.0 0.0
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 27 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 25
Table Twenty-Three (cont.)
Hourly Estimated Load Impacts Entire 2010 Program Season
16-Aug 17-Aug 18-Aug 19-Aug 20-Aug
monday tuesday wednesday thursday friday
7:00-7:59 0.0 0.0 0.0 0.0 0.0
8:00-8:59 0.0 0.0 0.0 0.0 0.0
9:00-9:59 0.0 0.0 0.0 0.0 0.0
10:00-10:59 0.0 0.0 0.0 0.0 0.0
11:00-11:59 0.0 0.0 0.0 0.0 0.0
12:00-12:59 0.0 0.0 0.0 0.0 0.0
1:00-1:59 0.0 0.0 0.0 0.0 0.0
2:00-2:59 2,309.5 992.0 2,294.0 992.0 0.0
3:00-3:59 2,924.5 1,308.5 2,909.0 1,308.5 0.0
4:00-4:59 2,954.5 1,357.5 2,939.0 1,357.5 0.0
5:00-5:59 2,954.5 1,357.5 2,939.0 1,357.5 0.0
6:00-6:59 2,339.5 1,041.0 2,324.0 1,041.0 0.0
7:00-7:59 2,309.5 992.0 2,294.0 992.0 0.0
23-Aug 24-Aug 25-Aug 26-Aug 27-Aug
monday tuesday wednesday thursday friday
7:00-7:59 0.0 18,000.0 0.0 18,000.0 0.0
8:00-8:59 0.0 18,000.0 0.0 18,000.0 0.0
9:00-9:59 0.0 18,000.0 0.0 18,000.0 0.0
10:00-10:59 0.0 18,000.0 0.0 18,000.0 0.0
11:00-11:59 0.0 43,934.8 0.0 43,934.8 0.0
12:00-12:59 0.0 43,934.8 0.0 43,934.8 0.0
1:00-1:59 0.0 43,934.8 0.0 43,934.8 0.0
2:00-2:59 2,309.5 88,004.3 2,294.0 88,004.3 0.0
3:00-3:59 2,924.5 133,498.6 2,909.0 133,498.6 0.0
4:00-4:59 2,954.5 133,547.6 2,939.0 133,547.6 0.0
5:00-5:59 2,954.5 133,547.6 2,939.0 133,547.6 0.0
6:00-6:59 2,339.5 90,153.6 2,324.0 90,153.6 0.0
7:00-7:59 2,309.5 992.0 2,294.0 992.0 0.0
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 28 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 26
Table Twenty-Three (cont.)
Hourly Estimated Load Impacts Entire 2010 Program Season
30-Aug 31-Aug
monday tuesday
7:00-7:59 0.0 0.0
8:00-8:59 0.0 0.0
9:00-9:59 0.0 0.0
10:00-10:59 0.0 0.0
11:00-11:59 0.0 0.0
12:00-12:59 0.0 0.0
1:00-1:59 0.0 0.0
2:00-2:59 2,309.5 992.0
3:00-3:59 2,924.5 1,308.5
4:00-4:59 2,954.5 1,357.5
5:00-5:59 2,954.5 1,357.5
6:00-6:59 2,339.5 1,041.0
7:00-7:59 2,309.5 992.0
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 29 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 27
Load profile data impact analysis
Throughout the control period, Company SCADA data were collected and used in preparing estimated impact
analyses. Attachment One includes 60s SCADA data for each of the following five transmission substations on each
of the dispatch event days: (1) Amps; (2) Big Grassy; (3) Rigby; (4) Bonneville and (5) Jefferson. The impact of load
dispatches is dramatic and unequivocal. The magnitude of the first half of June loads is significantly less than
previous seasons. Further analysis suggests that the maturing of field crops and the 2nd cutting for alfalfa hay have a
predictable impact on reducing loads post August 1st.
Cost-effectiveness analyses
Cost-effectiveness calculations were prepared for each of the four standard utility industry tests in a manner
consistent with the methodologies described earlier. In this evaluation, however, full program costs for both
Schedule 72 and Schedule 72A together with benefits from both program components are used as the basis for the
evaluations. Benefits and costs for Schedule 72 and 72A upon which calculations are prepared are presented in
Table Twenty-Four below7.
Table Twenty-Four
2010 Benefit / Cost Categories & Values−Schedules 72 & 72A
Cost Categories Cost Values Benefit Category Benefit Value
Administrative support $0.0 $/kW-yr avoided $73.09/kW
Program evaluation $11,758.00
Field / Equip / Db admin. expenses $3,801,022.87
Participation credits $8,101,480.75
Program management $117,518.03
Total $12,031,779.65
All-in $/kW program costs8 $42.58 Total kW 282,580*
*Total max nominal load for July
As shown in Table Twenty-Five, the combined initiatives (Schedule 72 + Schedule 72A) pass the TRC, Utility and
Ratepayer Tests. The Program also passes the Participant Test. However, since the participant incurs no costs the
benefit/cost ratio would be infinite. Accordingly and for the Participant Test the value is indicated as ‘N/A’ in the
Benefit/Cost Ratio column.
7 All program costs (both Scheduled Forward and Dispatch program components) have been included in this table.
8 This is a rudimentary calculation simply performed by dividing all program costs by the monthly max (July) avoided demand.
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 30 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 28
Table Twenty-Five
2010 Cost-effectiveness Analyses
Test Benefits Costs Net Benefits Benefit/Cost Ratio
TRC $21,653,300.86 $3,930,298.90 $17,723,001.96 5.51
Utility $21,653,300.86 $12,031,779.65 $9,621,521.21 1.80
Ratepayer $21,653,300.86 $12,031,779.65 $9,621,521.21 1.80
Participant $8,101,480.75 $0.00 $8,101,480.75 N/A
Conclusions
Grid characteristics and associated distribution of program loads
Altogether, the load on the five transmission substations monitored comprises ~77.9% of the total irrigation
load control participating load.
With the exception of the Rigby Transmission Substation there is virtually no load diversity on the four
transmission substations−(1) Amps; (2) Big Grassy; (3) Jefferson and (4) Bonneville.
Of the five transmission substations monitored−((1) Amps; (2) Big Grassy; (3) Jefferson, (4) Rigby and (5)
Bonneville) there is a total of 336 MW. Of that total, irrigation load represents 295MW or 88%.
Irrigation Load Control Program participation on the five monitored transmission substations totals to
220MW or 75% of the total available irrigation load and 65% of the total load.
66 of the 90 circuits (or 73% of the circuits) fed by one of the five transmission substations have irrigation
loads that represent ≥85% of the total load on that circuit
55 of the 90 circuits (or 61% of the circuits) fed by one of the five transmission substations have irrigation
loads that represent ≥95% of the total load on that circuit
The above data make it more than clear that DE’s must absolutely be executed in an intelligent fashion.
Grower perception considerations
The 2010 Dispatch stair-stepping initiative was positively received by the growers with no indication from
growers that either row or field crops were adversely affected by quality or yield impacts
Key to program success is maintaining a local presence of agri-irrigation / information systems specialists
and irrigation equipment / agri-electrician specialists.
The 2010 season represented the 8th consecutive season where no complaints have been issued to either
the Commission or to the Company. Local C & CM staff and field teams have been required and are
motivated to a customer service approach to solving problems coincident to when the problem presents
itself. This approach is viewed and valued as a risk mitigation strategy and ultimately minimizes program
and Company costs.
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 31 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 29
Throughout the 2010 season additional growers began to actively use the remote control equipment for
regular irrigation turns. That said, there has been and remains a variety of interesting technical issues and
operational considerations that require additional attentions to ensure system robustness.
The principle issues that blunt further program effectiveness center on equipment reliability and program size, which
impacts program realization during any particular hour needed.
Change considerations
Growers perceived the stair-stepping of loads into and out-of dispatch events along with minimizing loads
that could be removed at any one time had a positive effect on pump motors.
The stair-stepping effort was and is the precursor to a ‘smart-grid’. Successful further utilization of Irrigation
Load Control to achieve the benefits of ‘smart-grid’ will require a continued cooperative efforts between
various RMP organizations including but not limited to C & CM, Distribution Engineering, Grid-Ops,
Demand Side Management, Area Planning, Commercial & Trading, Metering and Regulatory. The benefits
of a ‘smart-grid’ approach require quantification, however.
Meteorological considerations
From a meteorological perspective the 2010 season was relatively normal both in terms of rainfall and
temperature.
That said the first two weeks of June were wetter and cooler than normal and it had a particularly adverse
effect on hay production. Moreover, field crops were late in the harvest cycle. Some fields were not
harvested until September.
Recommendations
Find a solution to the equipment reliability issue. The 2-way equipment has allowed the program to migrate
to a ‘dispatch’ initiative. That said, making the transition has come at a price. Time, resources and budget
have been consumed with simply getting and keeping the system operational. RMP is and will continue to
work with the equipment vendor to remedy current equipment shortcomings and to further ‘harden’ the
equipment for the harsh agricultural environment.
Design dispatch protocol to extract additional value from a ‘smart-grid’ approach. For example, in 2010
benefit from Irrigation Load Control was provided to C&T, Grid-Ops and Area Planning. Concomitant
efforts will be required to appropriate value these benefits and to assess their viability to alternative
solutions.
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 32 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 30
Continue to work with individual growers and the IIPA to gain their support for the variety of requisite
dispatch protocols and potential offerings that could add additional value to the Company and to the Idaho
ratepayer.
To date the Company has constructed a solution that has required creativity and innovation. From the
control technology, to program design and operations a solution has been built from the ground up and at
each juncture the Company has had to evolve the program solution to address new challenges. While
much is behind the Irrigation Management Team, continued program evolution is anticipated to resolve
technical problems and maximize the value to the Grid. Accordingly, current tariffs may require
modification to accommodate the flexibility required to allow for the testing of alternative solutions,
operational processes / practices.
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 33 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 31
Attachment One: Rocky Mountain Power Northern Tier Transmission Substations
Geo-spatial location of transmission substations
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 34 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 32
Big Grassy Plots
big grassy (season 2010)
0
5
10
15
20
25
30
35
40
0:000:40 1:202:002:403:204:004:405:206:006:40 7:208:008:409:20
10:00
10:40
11:20
12:00
12:40
13:20
14:00
14:4
0
15:20
16:00
16:4
0
17:20
18:00
18:40
19:20
20:00
20:40
21:20
22:00
22:40
23:2
0
time
mw
ctrl-season non-ctrl-season
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 35 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 33
big grassy july 2010
0
5
10
15
20
25
30
35
40
45
50
55
60
0:
0
0
0:
3
2
1:
0
4
1:
3
6
2:
0
8
2:
4
0
3:
1
2
3:
4
4
4:
1
6
4:
4
8
5:
2
0
5:
5
2
6:
2
4
6:
5
6
7:
2
8
8:
0
0
8:
3
2
9:
0
4
9:
3
6
10
:
0
8
10
:
4
0
11
:
1
2
11
:
4
4
12
:
1
6
12
:
4
8
13
:
2
0
13
:
5
2
14
:
2
4
14
:
5
6
15
:
2
8
16
:
0
0
16
:
3
2
17
:
0
4
17
:
3
6
18
:
0
8
18
:
4
0
19
:
1
2
19
:
4
4
20
:
1
6
20
:
4
8
21
:
2
0
21
:
5
2
22
:
2
4
22
:
5
6
23
:
2
8
time
mw
8-Jul 15-Jul 16-Jul 19-Jul 20-Jul 26-Jul
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 36 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 34
Amps Plots
amps (season 2010)
0
5
10
15
20
25
30
35
0:000:40 1:202:002:403:204:004:405:206:006:40 7:208:008:409:20
10:00
10:40
11:20
12:00
12:40
13:20
14:00
14:4
0
15:20
16:00
16:4
0
17:20
18:00
18:40
19:20
20:00
20:40
21:20
22:00
22:40
23:2
0
time
mw
ctrl-season non-ctrl-season
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 37 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 35
amps july 2010
0
5
10
15
20
25
30
35
40
45
50
0:
0
0
0:
3
2
1:
0
4
1:
3
6
2:
0
8
2:
4
0
3:
1
2
3:
4
4
4:
1
6
4:
4
8
5:
2
0
5:
5
2
6:
2
4
6:
5
6
7:
2
8
8:
0
0
8:
3
2
9:
0
4
9:
3
6
10
:
0
8
10
:
4
0
11
:
1
2
11
:
4
4
12
:
1
6
12
:
4
8
13
:
2
0
13
:
5
2
14
:
2
4
14
:
5
6
15
:
2
8
16
:
0
0
16
:
3
2
17
:
0
4
17
:
3
6
18
:
0
8
18
:
4
0
19
:
1
2
19
:
4
4
20
:
1
6
20
:
4
8
21
:
2
0
21
:
5
2
22
:
2
4
22
:
5
6
23
:
2
8
time
mw
8-Jul 15-Jul 16-Jul 19-Jul 20-Jul 26-Jul
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 38 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 36
Bonneville Plots
bonneville (season 2010)
0
5
10
15
20
25
30
35
40
45
0:000:40 1:20 2:00 2:40 3:20 4:004:405:206:006:40 7:20 8:00 8:40 9:20
10:0
0
10:4
0
11:2
0
12:0
0
12:40
13:20
14:00
14:40
15:20
16:00
16:40
17:20
18:0
0
18:40
19:2
0
20:0
0
20:4
0
21:2
0
22:00
22:4
0
23:20
ctrl-season non-ctrl season
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 39 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 37
bonneville july 2010
0
5
10
15
20
25
30
35
40
45
50
55
60
0:
0
0
0:
3
2
1:
0
4
1:
3
6
2:
0
8
2:
4
0
3:
1
2
3:
4
4
4:
1
6
4:
4
8
5:
2
0
5:
5
2
6:
2
4
6:
5
6
7:
2
8
8:
0
0
8:
3
2
9:
0
4
9:
3
6
10
:
0
8
10
:
4
0
11
:
1
2
11
:
4
4
12
:
1
6
12
:
4
8
13
:
2
0
13
:
5
2
14
:
2
4
14
:
5
6
15
:
2
8
16
:
0
0
16
:
3
2
17
:
0
4
17
:
3
6
18
:
0
8
18
:
4
0
19
:
1
2
19
:
4
4
20
:
1
6
20
:
4
8
21
:
2
0
21
:
5
2
22
:
2
4
22
:
5
6
23
:
2
8
time
mw
8 July 15-Jul 16-Jul 19-Jul 20-Jul 26-Jul 8 mw
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 40 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 38
Jefferson Plots
jefferson (season 2010)
0
5
10
15
20
25
30
35
40
45
50
0:000:40 1:202:002:403:204:004:405:206:006:40 7:208:008:409:20
10:00
10:40
11:20
12:00
12:40
13:20
14:00
14:4
0
15:20
16:00
16:4
0
17:20
18:00
18:40
19:20
20:00
20:40
21:20
22:00
22:40
23:2
0
time
mw
ctrl season non-ctrl season
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 41 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 39
jefferson july 2010
0
5
10
15
20
25
30
35
40
45
50
55
60
65
0:
0
0
0:
3
2
1:
0
4
1:
3
6
2:
0
8
2:
4
0
3:
1
2
3:
4
4
4:
1
6
4:
4
8
5:
2
0
5:
5
2
6:
2
4
6:
5
6
7:
2
8
8:
0
0
8:
3
2
9:
0
4
9:
3
6
10
:
0
8
10
:
4
0
11
:
1
2
11
:
4
4
12
:
1
6
12
:
4
8
13
:
2
0
13
:
5
2
14
:
2
4
14
:
5
6
15
:
2
8
16
:
0
0
16
:
3
2
17
:
0
4
17
:
3
6
18
:
0
8
18
:
4
0
19
:
1
2
19
:
4
4
20
:
1
6
20
:
4
8
21
:
2
0
21
:
5
2
22
:
2
4
22
:
5
6
23
:
2
8
time
mw
8-Jul 15-Jul 16-Jul 19-Jul 20-Jul 26-Jul 2-Aug
tap change @ big grassy
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 42 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 40
Rigby Plots
rigby (season 2010)
0
20
40
60
80
100
120
140
0:000:401:202:002:403:204:004:405:206:006:407:208:008:409:20
10:00
10:40
11:20
12:00
12:40
13:20
14:00
14:40
15:20
16:00
16:4
0
17:2
0
18:00
18:40
19:20
20:0
0
20:40
21:20
22:00
22:40
23:2
0
time
mw
ctrl season non ctrl season
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 43 of 44
2010 Idaho Irrigation Load Control Program-Final Report Page 41
rigby july 2010
50
60
70
80
90
100
110
120
130
140
150
160
170
0:
0
0
0:
3
2
1:
0
4
1:
3
6
2:
0
8
2:
4
0
3:
1
2
3:
4
4
4:
1
6
4:
4
8
5:
2
0
5:
5
2
6:
2
4
6:
5
6
7:
2
8
8:
0
0
8:
3
2
9:
0
4
9:
3
6
10
:
0
8
10
:
4
0
11
:
1
2
11
:
4
4
12
:
1
6
12
:
4
8
13
:
2
0
13
:
5
2
14
:
2
4
14
:
5
6
15
:
2
8
16
:
0
0
16
:
3
2
17
:
0
4
17
:
3
6
18
:
0
8
18
:
4
0
19
:
1
2
19
:
4
4
20
:
1
6
20
:
4
8
21
:
2
0
21
:
5
2
22
:
2
4
22
:
5
6
23
:
2
8
time
mw
8-Jul 15-Jul 16-Jul 19-Jul 20-Jul 26-Jul
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -2
Attach IIPA 34 -2.pdf Page 44 of 44