HomeMy WebLinkAbout20110708PAC to IIPA Attach 12 -1.pdf
Schedule 96 & 96A Utah Irrigation Load Control
Programs
2010 Credit Rider Initiative Final Report
29 December 2010
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Table of Contents
Page
Report Organization ...................................................................................................................................................... 1
Background ................................................................................................................................................................... 1
2010 Schedule 96 (Scheduled Forward) Results.......................................................................................................... 1
Table Two Longitudinal and Current Year Scheduled 96 Participation Credits Issued ............................................... 1
Table Three Comparative Scheduled 96 & 96A Costs 2008, 2009 & 2010 ................................................................ 2
Table Four Schedule 96 Program Nominal Loads by Participation Option ................................................................. 2
Table Five Schedule 96 2010 Nominal kW by Month, Monday Control Day & Hour ................................................... 3
Table Six Schedule 96 2010 Nominal kW by Month, Tuesday Control Day & Hour.................................................... 3
Table Seven Schedule 96 2010 Nominal kW by Month, Wednesday Control Day & Hour ......................................... 4
Table Eight Schedule 96 2010 Nominal kW by Month, Thursday Control Day & Hour ............................................... 4
Cost-effectiveness analyses ......................................................................................................................................... 5
Table Nine 2010 Benefit / Cost Categories & Values−Schedule 96 ........................................................................... 5
Table Ten 2010 Cost-effectiveness Analyses−Schedule 96 ....................................................................................... 6
Measurement & Verification (M&V) processes ............................................................................................................. 6
2010 Schedule 96A (Dispatch) Results ........................................................................................................................ 7
Customer Opt-Outs ...................................................................................................................................................... 7
Table Twelve 2010 Dispatch Dates & Durations ......................................................................................................... 7
Table Thirteen Opt-outs, Liquidated Damages, kW NOT Avoided and $/MWh by Dispatch Event............................. 8
Dispatch Events ............................................................................................................................................................ 8
Table Fourteen Dispatch Program Only Nominal Load (kW) Impacts x Dispatch Event .............................................. 8
Table Fifteen Dispatch Program Estimated Net Load (kW) Impacts x Dispatch Event ............................................... 9
Cost-effectiveness analyses ......................................................................................................................................... 9
Table Sixteen 2010 Benefit / Cost Categories & Values−Schedule 96A .................................................................. 10
Table Seventeen 2010 Cost-effectiveness Analyses ................................................................................................ 10
2010 Schedule 96 & Schedule 96A Results ............................................................................................................... 11
Avoided demand ......................................................................................................................................................... 11
Table Eighteen Program Impacts by Participation Option ......................................................................................... 11
Table Twenty 2010 Dispatch Events & Associated Estimated Net Avoided kW (Schedule 96 & Schedule 96A) ..... 12
Table Twenty-One Net Hourly Estimated Load impacts Entire 2010 Program Season ............................................. 13
Table Twenty-One (cont.) Net Hourly Estimated Load impacts Entire 2010 Program Season ................................. 14
Table Twenty-One (cont.) Net Hourly Estimated Load impacts Entire 2010 Program Season ................................. 15
Table Twenty-One (cont.) Net Hourly Estimated Load impacts Entire 2010 Program Season ................................. 16
Load profile data impact analysis ............................................................................................................................... 17
Cost-effectiveness analyses ....................................................................................................................................... 17
Table Twenty-Three 2010 Cost-effectiveness Analyses ........................................................................................... 18
Conclusions................................................................................................................................................................. 18
Attachment One .......................................................................................................................................................... 19
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Report Organization
This report summarizes the Utah Irrigation Load Control Program (Program) for Schedule 96 and Schedule 96A. In addition
summary statistics from both Schedule 96 and Schedule 96A 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 15 October 2010.
Program impacts within this report are based on participating loads and are not intended to represent realized reductions
during a particular dispatch event.
Background
The reporting will 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 96 (Scheduled Forward) Results
Table One
Longitudinal and Current Year Scheduled 96 Eligible & Full-Year Participating Sites & Customers
Participant Sites Participant Customers
2007 Actual Participants 79 40
2008 Actual Participants 113 49
2009 Actual Participants 17 17
2010 Actual Participants 26 25
Eligible 2010 Counts 2,491 1,652
Customers NOT eligible to participate 2010 N/A 0
Table Two
Longitudinal and Current Year Scheduled 96 Participation Credits Issued
Year Total Participation Credits Issued
2007 $55,980.79
2008 $107,841.33
2009 $4,400.33
2010 $7,630.06
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Table Three
Comparative Scheduled 96 & 96A Costs 2008, 2009 & 2010
Cost Category
2008 Costs
Oct ‘07−Sept ‘08
2009 Costs
Oct ‘08−Sept ‘09
2010 Costs
Oct ‘09−Sept ‘10
Administrative support $0.00 $0.00 $0.00
Program evaluation $0.00 $1,053.25 $1,905.00
Field / Equip / Db admin. expenses $654,090.00 $1,300,911.46 $1,151,758.99
Participation credits $107,841.33 $1,055,637.60 $1,338,679.12
Program management $0.00 $70,688.33 $83,084.15
Reporting $0.00 $0.00 $0.00
Total Program costs $761,931.00 $2,428,290.64 $2,575,427.26
Note: 2008 costs are for the ‘Scheduled Forward’ option only. 2009 and 2010 costs include both ‘Schedule Forward’ and
‘Dispatch’ options
Table Four
Schedule 96 Program Nominal Loads by Participation Option
Option Counts
June
Avoided kW
July
Avoided kW
Aug Avoided
kW
Option I m w 2-8 15 387.5 436.0 431.5
Option I t th 2-8 9 185.5 205.5 199.0
Option II m 2-8 0 0.0 0.0 0.0
Option III m w 3-6 0 0.0 0.0 0.0
Option III m w 4-7 0 0.0 0.0 0.0
Option III t th 3-6 0 0.0 0.0 0.0
Option III t th 4-7 0 0.0 0.0 0.0
Option IV m t w th 3-6 0 0.0 0.0 0.0
Option IV m t w th 4-7 0 0.0 0.0 0.0
Option IV m 2-8 1 24.0 23.0 22.0
Option IV w 2-8 1 103.5 104.0 111.0
Schedule Forward Totals 26 700.5 768.5 763.5
Tables Five through Eight transpose the data presented in Table Four 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.
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Table Five
Schedule 96 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 411.5 411.5 411.5 411.5 411.5 411.5
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 459.0 459.0 459.0 459.0 459.0 459.0
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 453.5 453.5 453.5 453.5 453.5 453.5
Table Six
Schedule 96 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 185.5 185.5 185.5 185.5 185.5 185.5
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 205.5 205.5 205.5 205.5 205.5 205.5
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 199.0 199.0 199.0 199.0 199.0 199.0
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Table Seven
Schedule 96 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 491.0 491.0 491.0 491.0 491.0 491.0
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 540.0 540.0 540.0 540.0 540.0 540.0
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 542.5 542.5 542.5 542.5 542.5 542.5
Table Eight
Schedule 96 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 185.5 185.5 185.5 185.5 185.5 185.5
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 205.5 205.5 205.5 205.5 205.5 205.5
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 199.0 199.0 199.0 199.0 199.0 199.0
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Cost-effectiveness analyses
Cost-effectiveness is calculated for the following program components:
1. Schedule 96 (Scheduled Forward) only
2. Schedule 96A (Dispatch) only
3. Schedule 96 and Schedule 96A (Scheduled Forward + Dispatch options)
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
96 (Scheduled Forward option) will be based upon the cost and nominal MW values as defined in Table Nine
below1. 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
tests2. The benefits (avoided costs) are based on the calculations as defined by the Company’s Integrated
Resource Planning (IRP) organization in a report titled Proposed Valuation Methodology. 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 the extraordinarily smaller size of the Schedule Forward initiative
compared to the Dispatch option simply did not warrant a separate avoided cost analysis.
Table Nine
2010 Benefit / Cost Categories & Values−Schedule 96
Cost Categories Cost Values Benefit Category Benefit Value
Administrative support $0.00 $/kW-yr avoided $73.09/kW
Program evaluation $29.48
Field / Equip / Db admin. expenses $17,826.11
Participation credits $7,630.06
Program management $1,285.92
Total $26,771.58
Note: with the exception of participation credits costs have been allocated based on the percent of load the
Schedule Forward option comprises of the Utah total
Costs used in these calculations include administrative costs, contractor costs (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 Cadmus using a simplified spreadsheet analysis. This
analysis multiplies average demand reductions for the June, July and August period (as is consistent with
1 To the extent possible, certain cost categories have been allocated by (1) the respective Schedule initiative and (2) percent of participating load.
2 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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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 $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 Ten, the Scheduled Forward component of the program passes the TRC Test. The Scheduled
Forward program also passes the Utility and Ratepayer Tests. 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 Ten.
Table Ten
2010 Cost-effectiveness Analyses−Schedule 96
Test Benefits Costs Net Benefits Benefit/Cost Ratio
TRC $27,543.43 $19,141.51 $8,401.92 1.44
Utility $27,543.43 $26,771.57 $771.86 1.03
Ratepayer $27,543.43 $26,771.57 $771.86 1.03
Participant $7,630.06 $0.00 $7,630.06 N/A
Measurement & Verification (M&V) processes
The control equipment provides log files that can authoritatively determine issues of grower fraud and/or
tampering with the control equipment. Throughout 2010 there remained a residual amount of confusion among
growers relative to equipment / program operations. Accordingly, the Irrigation Management Team decided that it
would be important to provide additional M&V field technician site visits. This was done to meet customer services
as well as M&V objectives. In the end there were no sites reported to be out of compliance relative to grower
fraud. There was, throughout each of the site visits, significant attention to training and easing grower concerns
regarding the remote control equipment.
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2010 Schedule 96A (Dispatch) Results
Table Eleven
Eligible & Full-Year Participating Sites & Customers
Participant Sites Participant Customers
2009 Actual Participants 498 148
2010 Actual Participants 602 191
Eligible 2010 Counts 2,491 1,652
Customers NOT eligible to participate 2010 N/A 0
Customer Opt-Outs
Schedule 96A permits growers to ‘opt-out’ of five Dispatch Events throughout the Irrigation Season. Each of these
opt-out events incurred a cost resulting in a reduction to the customer’s Load Control Service Credit. The cost to
opt-out is the day-ahead ($/MWh) RMP would otherwise have to pay for power during that dispatch period. A
summary of opt-outs, liquidated damages and nominal kW not avoided by each of the Dispatch Events is
presented in Table Thirteen. Table Twelve summarizes the dispatch dates and dispatch duration.
Table Twelve
2010 Dispatch Dates & Durations
Dispatch Dates Duration (hours)
June
Tuesday, June 29, 2010 4
July
Thursday, July 08, 2010 4
Thursday, July 15, 2010 4
Friday, July 16, 2010 4
Monday, July 19, 2010 4
Tuesday, July 20, 2010 4
Monday, July 26, 2010 4
August
Monday, August 02, 2010 4
Thursday, August 05, 2010 4
Tuesday, August 24, 2010 4
Thursday, August 26, 2010 4
Total hours 44
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Table Thirteen
Opt-outs, Liquidated Damages, kW3 NOT Avoided and $/MWh by Dispatch Event
Count Date Weekday
Count of
Opt-outs
Liquidated
Damages
kW NOT
avoided
$/MWh
(day ahead)
1 29-Jun Thursday 15 $238.84 1,270.5 $47.00
2 8-Jul Thursday 13 $222.53 1,271.5 $43.75
3 15-Jul Thursday 7 $115.24 554.0 $52.00
4 16-Jul Friday 25 $464.44 2,046.0 $56.75
5 19-Jul Monday 18 $355.39 1,565.5 $56.75
6 20-Jul Tuesday 18 $313.64 1,479.5 $53.00
7 26-Jul Monday 16 $228.80 1,204.0 $47.50
8 2-Aug Monday 11 $201.53 983.0 $51.25
9 5-Aug Thursday 26 $504.76 2,536.5 $49.75
10 24-Aug Thursday 63 $1,701.36 7,089.0 $60.00
11 26-Aug Thursday 44 $869.81 3,883.0 $56.00
totals / average 256 $5,216.34 23,882.5 $52.16
Dispatch Events
Nominal loads avoided by the Dispatch Events are captured in Table Fourteen. Table Fifteen captures estimated
net kW avoided for each Dispatch Event as opt-outs are netted from Table Fourteen calculations.
Table Fourteen
Dispatch Program Only Nominal Load (kW) Impacts x Dispatch Event
Count Date Weekday 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
1 29-Jun Thursday 46,318.0 46,318.0 46,318.0 46,318.0 0.0 0.0
2 8-Jul Thursday 47,303.0 47,303.0 47,303.0 47,303.0 0.0 0.0
3 15-Jul Thursday 47,303.0 47,303.0 47,303.0 47,303.0 0.0 0.0
4 16-Jul Friday 47,303.0 47,303.0 47,303.0 47,303.0 0.0 0.0
5 19-Jul Monday 47,303.0 47,303.0 47,303.0 47,303.0 0.0 0.0
6 20-Jul Tuesday 47,303.0 47,303.0 47,303.0 47,303.0 0.0 0.0
7 26-Jul Monday 47,303.0 47,303.0 47,303.0 47,303.0 0.0 0.0
8 2-Aug Monday 48,346.0 48,346.0 48,346.0 48,346.0 0.0 0.0
9 5-Aug Thursday 48,346.0 48,346.0 48,346.0 48,346.0 0.0 0.0
10 24-Aug Thursday 48,346.0 48,346.0 48,346.0 48,346.0 0.0 0.0
11 26-Aug Thursday 48,346.0 48,346.0 48,346.0 48,346.0 0.0 0.0
Mean 'Dispatch Event' Avoided kW x hr. 47,592.7 47,592.7 47,592.7 47,592.7 0.0 0.0
Median 'Dispatch Event' Avoided kW x hr. 47,303.0 47,303.0 47,303.0 47,303.0 0.0 0.0
3 kW represents connected load based on the average monthly demand for June, July and August for 2008 and 2009.
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Table Fifteen
Dispatch Program Estimated Net Load (kW) Impacts x Dispatch Event
Count Date Weekday 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
1 29-Jun Thursday 45,047.5 45,047.5 45,047.5 45,047.5 0.0 0.0
2 8-Jul Thursday 46,031.5 46,031.5 46,031.5 46,031.5 0.0 0.0
3 15-Jul Thursday 46,749.0 46,749.0 46,749.0 46,749.0 0.0 0.0
4 16-Jul Friday 45,257.0 45,257.0 45,257.0 45,257.0 0.0 0.0
5 19-Jul Monday 45,737.5 45,737.5 45,737.5 45,737.5 0.0 0.0
6 20-Jul Tuesday 45,823.5 45,823.5 45,823.5 45,823.5 0.0 0.0
7 26-Jul Monday 46,099.0 46,099.0 46,099.0 46,099.0 0.0 0.0
8 2-Aug Monday 47,363.0 47,363.0 47,363.0 47,363.0 0.0 0.0
9 5-Aug Thursday 45,809.5 45,809.5 45,809.5 45,809.5 0.0 0.0
10 24-Aug Thursday 41,257.0 41,257.0 41,257.0 41,257.0 0.0 0.0
11 26-Aug Thursday 44,463.0 44,463.0 44,463.0 44,463.0 0.0 0.0
Mean 'Dispatch Event' Avoided kW x hr. 45,421.6 45,421.6 45,421.6 45,421.6 0.0 0.0
Median 'Dispatch Event' Avoided kW x hr. 45,809.5 45,809.5 45,809.5 45,809.5 0.0 0.0
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 96 portion of this program. Benefits and costs for Schedule
96A (Dispatch option) upon which calculations are prepared are presented in Table Sixteen below4.
Again, the cost-effectiveness of the Program was calculated by Cadmus using a simplified spreadsheet analysis.
This analysis multiplies average 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. In the case of Schedule 96A, the value of 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
initially presented to the Idaho Public Utilities Commission and have been used in the Utah jurisdiction as well.
The 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.
4 Again, to the extent possible, costs have been allocated by the respective Schedule initiative
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Table Sixteen
2010 Benefit / Cost Categories & Values−Schedule 96A
Cost Categories Cost Values Benefit Category Benefit Value
Administrative support $0.00 $/kW-yr avoided $73.09/kW
Program evaluation $1,875.52
Field / Equip / Db admin. expenses $1,133,932.88
Participation credits $1,331,049.06
Program management $81,798.23
Total $2,548,655.68
As shown in Table Sixteen, Schedule 96A 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 the
value for the Participant Test is indicated as ‘N/A’ in the Benefit/Cost Ratio column.
Table Seventeen
2010 Cost-effectiveness Analyses
Test Benefits Costs Net Benefits Benefit/Cost Ratio
TRC $3,704,791.96 $1,217,606.63 $2,487,185.33 3.04
Utility $3,704,791.96 $2,548,655.69 $1,156,136.27 1.45
Ratepayer $3,704,791.96 $2,548,655.69 $1,156,136.27 1.45
Participant $1,331,049.06 $0.00 $1,331,049.06 N/A
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2010 Schedule 96 & Schedule 96A Results
This section of the report provides quantitative summaries of the two combined initiatives−Schedule 96 (Scheduled
Forward) and Schedule 96A (Dispatch).
Avoided demand
Program impacts by participation option for both Schedule 96 and 96A are presented in Table Eighteen.
Table Eighteen
Program Impacts by Participation Option
Option Counts June Avoided kW July Avoided kW Aug Avoided kW
Option I m w 2-8 15 387.5 436.0 431.5
Option I t th 2-8 9 185.5 205.5 199.0
Option II m w 3-6 0 0 0 0
Option II t th 3-6 0 0 0 0
Option II m w 4-7 0 0 0 0
Option II t th 4-7 0 0 0 0
Option III m t w th 3-6 0 0 0 0
Option III m t w th 4-7 0 0 0 0
Option IV m 2-8 1 24.0 23.0 22.0
Option IV w 2-8 1 103.5 104.0 111.0
Schedule Forward totals 26 700.5 768.5 763.5
Option dispatch dispatchable 602 46,318.0 47,303.0 48,346.0
Totals: 628 47,018.5 48,071.5 49,109.5
The estimated avoided demand by dispatch hour associated with each of the Dispatch Events is presented in
Table Nineteen. The values in this table are additive. That is, they represent the combination of Scheduled
Forward loads plus Dispatch loads. Table Twenty presents these same data with the exception that the opt-out
loads are taken into the calculations. Two important facts need to be taken into consideration in evaluating these
data. First, zeros (0) appears in several cells. This is due to the fact that the Scheduled Forward initiative operates
Monday thru Thursday inclusive. When the Dispatch initiative was exercised on Friday the only avoided demand
is that associated with Dispatch loads and none occurred after 6 pm on Friday. Second, the table calculates the
average (mean) as well as a median for each of the hourly loads per ‘Dispatch Event’.
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Table Nineteen
2010 Dispatch Events & Associated Estimated Avoided kW (Schedule 96 & Schedule 96A)
Count Date Weekday 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
1 29-Jun Thursday 46,503.5 46,503.5 46,503.5 46,503.5 185.5 185.5
2 8-Jul Thursday 47,508.5 47,508.5 47,508.5 47,508.5 205.5 205.5
3 15-Jul Thursday 47,508.5 47,508.5 47,508.5 47,508.5 205.5 205.5
4 16-Jul Friday 47,303.0 47,303.0 47,303.0 47,303.0 0.0 0.0
5 19-Jul Monday 47,762.0 47,762.0 47,762.0 47,762.0 459.0 459.0
6 20-Jul Tuesday 47,508.5 47,508.5 47,508.5 47,508.5 205.5 205.5
7 26-Jul Monday 47,762.0 47,762.0 47,762.0 47,762.0 459.0 459.0
8 2-Aug Monday 48,799.5 48,799.5 48,799.5 48,799.5 453.5 453.5
9 5-Aug Thursday 48,545.0 48,545.0 48,545.0 48,545.0 199.0 199.0
10 24-Aug Thursday 48,545.0 48,545.0 48,545.0 48,545.0 199.0 199.0
11 26-Aug Thursday 48,545.0 48,545.0 48,545.0 48,545.0 199.0 199.0
Mean 'Dispatch Event' Avoided kW x hr. 47,844.6 47,844.6 47,844.6 47,844.6 251.9 251.9
Median 'Dispatch Event' Avoided kW x hr. 47,762.0 47,762.0 47,762.0 47,762.0 205.5 205.5
Table Twenty
2010 Dispatch Events & Associated Estimated Net Avoided kW (Schedule 96 & Schedule 96A)
Count Date Weekday 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59
1 29-Jun Thursday 45,233.0 45,233.0 45,233.0 45,233.0 185.5 185.5
2 8-Jul Thursday 46,237.0 46,237.0 46,237.0 46,237.0 205.5 205.5
3 15-Jul Thursday 46,954.5 46,954.5 46,954.5 46,954.5 205.5 205.5
4 16-Jul Friday 45,257.0 45,257.0 45,257.0 45,257.0 0.0 0.0
5 19-Jul Monday 46,196.5 46,196.5 46,196.5 46,196.5 459.0 459.0
6 20-Jul Tuesday 46,029.0 46,029.0 46,029.0 46,029.0 205.5 205.5
7 26-Jul Monday 46,558.0 46,558.0 46,558.0 46,558.0 459.0 459.0
8 2-Aug Monday 47,816.5 47,816.5 47,816.5 47,816.5 453.5 453.5
9 5-Aug Thursday 46,008.5 46,008.5 46,008.5 46,008.5 199.0 199.0
10 24-Aug Thursday 41,456.0 41,456.0 41,456.0 41,456.0 199.0 199.0
11 26-Aug Thursday 44,662.0 44,662.0 44,662.0 44,662.0 199.0 199.0
Mean 'Dispatch Event' Avoided kW x hr. 45,673.5 45,673.5 45,673.5 45,673.5 251.9 251.9
Median 'Dispatch Event' Avoided kW x hr. 46,029.0 46,029.0 46,029.0 46,029.0 205.5 205.5
Season-long hourly estimated load impacts are presented in Table Twenty-One. The tan color-coding represents the hour
and day of dispatch events. The blue color-coding represents Schedule Forward dispatches. Tan color-coded areas
represent Schedule Forward + Dispatch options.
2010 Utah Irrigation Load Control Program-Final Report Page 12
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Table Twenty-One
Net 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 185.5 387.5 185.5 0.0
3:00-3:59 na 185.5 387.5 185.5 0.0
4:00-4:59 na 185.5 387.5 185.5 0.0
5:00-5:59 na 185.5 387.5 185.5 0.0
6:00-6:59 na 185.5 387.5 185.5 0.0
7:00-7:59 na 185.5 387.5 185.5 0.0
7-Jun 8-Jun 9-Jun 10-Jun 11-Jun
monday tuesday wednesday thursday friday
2:00-2:59 411.5 185.5 491.0 185.5 0.0
3:00-3:59 411.5 185.5 491.0 185.5 0.0
4:00-4:59 411.5 185.5 491.0 185.5 0.0
5:00-5:59 411.5 185.5 491.0 185.5 0.0
6:00-6:59 411.5 185.5 491.0 185.5 0.0
7:00-7:59 411.5 185.5 491.0 185.5 0.0
14-Jun 15-Jun 16-Jun 17-Jun 18-Jun
monday tuesday wednesday thursday friday
2:00-2:59 411.5 185.5 491.0 185.5 0.0
3:00-3:59 411.5 185.5 491.0 185.5 0.0
4:00-4:59 411.5 185.5 491.0 185.5 0.0
5:00-5:59 411.5 185.5 491.0 185.5 0.0
6:00-6:59 411.5 185.5 491.0 185.5 0.0
7:00-7:59 411.5 185.5 491.0 185.5 0.0
21-Jun 22-Jun 23-Jun 24-Jun 25-Jun
monday tuesday wednesday thursday friday
2:00-2:59 411.5 185.5 491.0 185.5 0.0
3:00-3:59 411.5 185.5 491.0 185.5 0.0
4:00-4:59 411.5 185.5 491.0 185.5 0.0
5:00-5:59 411.5 185.5 491.0 185.5 0.0
6:00-6:59 411.5 185.5 491.0 185.5 0.0
7:00-7:59 411.5 185.5 491.0 185.5 0.0
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Table Twenty-One (cont.)
Net Hourly Estimated Load impacts Entire 2010 Program Season
28-Jun 29-Jun 30-Jun 1-Jul 2-Jul
monday tuesday wednesday thursday friday
2:00-2:59 411.5 46,503.5 491.0 436.0 0.0
3:00-3:59 411.5 46,503.5 491.0 436.0 0.0
4:00-4:59 411.5 46,503.5 491.0 436.0 0.0
5:00-5:59 411.5 46,503.5 491.0 436.0 0.0
6:00-6:59 411.5 185.5 491.0 436.0 0.0
7:00-7:59 411.5 185.5 491.0 436.0 0.0
5-Jul 6-Jul 7-Jul 8-Jul 9-Jul
monday tuesday wednesday thursday friday
2:00-2:59 459.0 205.5 540.0 47,508.5 0.0
3:00-3:59 459.0 205.5 540.0 47,508.5 0.0
4:00-4:59 459.0 205.5 540.0 47,508.5 0.0
5:00-5:59 459.0 205.5 540.0 47,508.5 0.0
6:00-6:59 459.0 205.5 540.0 205.5 0.0
7:00-7:59 459.0 205.5 540.0 205.5 0.0
12-Jul 13-Jul 14-Jul 15-Jul 16-Jul
monday tuesday wednesday thursday friday
2:00-2:59 459.0 205.5 540.0 47,508.5 47,303.0
3:00-3:59 459.0 205.5 540.0 47,508.5 47,303.0
4:00-4:59 459.0 205.5 540.0 47,508.5 47,303.0
5:00-5:59 459.0 205.5 540.0 47,508.5 47,303.0
6:00-6:59 459.0 205.5 540.0 205.5 0.0
7:00-7:59 459.0 205.5 540.0 205.5 0.0
19-Jul 20-Jul 21-Jul 22-Jul 23-Jul
monday tuesday wednesday thursday friday
2:00-2:59 47,762.0 47,508.5 540.0 205.5 0.0
3:00-3:59 47,762.0 47,508.5 540.0 205.5 0.0
4:00-4:59 47,762.0 47,508.5 540.0 205.5 0.0
5:00-5:59 47,762.0 47,508.5 540.0 205.5 0.0
6:00-6:59 459.0 205.5 540.0 205.5 0.0
7:00-7:59 459.0 205.5 540.0 205.5 0.0
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Table Twenty-One (cont.)
Net Hourly Estimated Load impacts Entire 2010 Program Season
26-Jul 27-Jul 28-Jul 29-Jul 30-Jul
monday tuesday wednesday thursday friday
2:00-2:59 47,762.0 205.5 540.0 205.5 0.0
3:00-3:59 47,762.0 205.5 540.0 205.5 0.0
4:00-4:59 47,762.0 205.5 540.0 205.5 0.0
5:00-5:59 47,762.0 205.5 540.0 205.5 0.0
6:00-6:59 459.0 205.5 540.0 205.5 0.0
7:00-7:59 459.0 205.5 540.0 205.5 0.0
2-Aug 3-Aug 4-Aug 5-Aug 6-Aug
monday tuesday wednesday thursday friday
2:00-2:59 48,799.5 199.0 542.5 48,545.0 0.0
3:00-3:59 48,799.5 199.0 542.5 48,545.0 0.0
4:00-4:59 48,799.5 199.0 542.5 48,545.0 0.0
5:00-5:59 48,799.5 199.0 542.5 48,545.0 0.0
6:00-6:59 453.5 199.0 542.5 199.0 0.0
7:00-7:59 453.5 199.0 542.5 199.0 0.0
9-Aug 10-Aug 11-Aug 12-Aug 13-Aug
monday tuesday wednesday thursday friday
2:00-2:59 453.5 199.0 542.5 199.0 0.0
3:00-3:59 453.5 199.0 542.5 199.0 0.0
4:00-4:59 453.5 199.0 542.5 199.0 0.0
5:00-5:59 453.5 199.0 542.5 199.0 0.0
6:00-6:59 453.5 199.0 542.5 199.0 0.0
7:00-7:59 453.5 199.0 542.5 199.0 0.0
16-Aug 17-Aug 18-Aug 19-Aug 20-Aug
monday tuesday wednesday thursday friday
2:00-2:59 453.5 199.0 542.5 199.0 0.0
3:00-3:59 453.5 199.0 542.5 199.0 0.0
4:00-4:59 453.5 199.0 542.5 199.0 0.0
5:00-5:59 453.5 199.0 542.5 199.0 0.0
6:00-6:59 453.5 199.0 542.5 199.0 0.0
7:00-7:59 453.5 199.0 542.5 199.0 0.0
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Table Twenty-One (cont.)
Net Hourly Estimated Load impacts Entire 2010 Program Season
23-Aug 24-Aug 25-Aug 26-Aug 27-Aug
monday tuesday wednesday thursday friday
2:00-2:59 453.5 48,545.0 542.5 48,545.0 0.0
3:00-3:59 453.5 48,545.0 542.5 48,545.0 0.0
4:00-4:59 453.5 48,545.0 542.5 48,545.0 0.0
5:00-5:59 453.5 48,545.0 542.5 48,545.0 0.0
6:00-6:59 453.5 199.0 542.5 199.0 0.0
7:00-7:59 453.5 199.0 542.5 199.0 0.0
30-Aug 31-Aug
monday tuesday
2:00-2:59 453.5 199.0
3:00-3:59 453.5 199.0
4:00-4:59 453.5 199.0
5:00-5:59 453.5 199.0
6:00-6:59 453.5 199.0
7:00-7:59 453.5 199.0
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2010 Utah Irrigation Load Control Program-Final Report Page 17
Load profile data impact analysis
Throughout the control period, Company SCADA data were collected and used in assessing impact analyses.
Attachment One includes 60s SCADA data for each of the following three distribution substations for the season and on
each of the dispatch event days in July: (1) Enterprise Valley; (2) Parowan; and (3) Milford. With the exception of the
Milford distribution substation (which is primarily assigned to city, not agricultural loads) the impact of load dispatches is
dramatic and unequivocal.
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 96 and
Schedule 96A together with benefits from both program components are used as the basis for evaluation. Benefits and
costs for Schedule 96 and 96A upon which calculations are prepared are presented in Table Twenty-Two below5.
Table Twenty-Two
2010 Benefit / Cost Categories & Values−Schedules 96 & 96A
Cost Categories Cost Values Benefit Category Benefit Value
Administrative support $0.00 $/kW-yr avoided $73.09/kW
Program evaluation $1,905.00
Field / Equip / Db admin. expenses $1,151,758.99
Participation credits $1,338,679.12
Program management $83,084.15
Total $2,575,427.26
All-in $/kW program costs6 $53.27 Total max kW 48,346.0*
*Total max load for Aug
As shown in Table Twenty-Three, the combined initiatives (Schedule 96 + Schedule 96A) 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.
5 All program costs (both Scheduled Forward and Dispatch program components) have been included in this table.
6 This is a rudimentary calculation simply performed by dividing all program costs by the monthly max (July) avoided demand as presented in Table
Seventeen.
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2010 Utah Irrigation Load Control Program-Final Report Page 18
Table Twenty-Three
2010 Cost-effectiveness Analyses
Test Benefits Costs Net Benefits Benefit/Cost Ratio
TRC $3,725,335.11 $1,236,748.14 $2,488,586.97 3.01
Utility $3,725,335.11 $2,575,427.26 $1,149,907.85 1.45
Ratepayer $3,725,335.11 $2,575,427.26 $1,149,907.85 1.45
Participant $1,338,679.12 $0.00 $1,338,679.12 N/A
Conclusions
Grower perception considerations
The 2010 Dispatch initiative was positively received by the growers with no indication from growers that crops
were adversely affected in terms of either quality or yield.
Key to program success is maintaining a local presence of agri-irrigation / information systems specialists and
irrigation / ag-electrician equipment specialists. Throughout the 2010 season 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.
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 an adverse effect on hay
production.
July monsoons in southern Utah also had a negative effect on hay production in that region.
Dispatch considerations
As is evident in Attachment One loads are either precipitously removed from (upon dispatch initiation) or added
to (upon dispatch conclusion) the RMP grid.
Altogether, the irrigation load control initiative accounts for a significant portion on primarily ag-related
substations (Enterprise, Parowan, Milford, Elberta and Holden areas7).
Despite these areas of large agricultural pump loads Distribution Engineering is not complaining of voltage
imbalances that would require change to the dispatch protocol.
7 We have SCADA data available for the Enterprise and Parowan areas. However and at the current time we do not have available SCADA for Milford,
Elberta and Holden areas. That said, there has been discussion relative to consideration to collecting data via load loggers for these areas.
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Attachment One
Geo-spatial location of distribution substations
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parowan (season 2010)
0
1
2
3
4
5
6
7
time0:301:101:502:303:103:504:305:105:506:307:107:508:309:109:50
10:30
11:1
0
11:50
12:30
13:10
13:50
14:30
15:10
15:5
0
16:30
17:10
17:50
18:30
19:10
19:50
20:3
0
21:10
21:50
22:30
23:10
23:50
time
mw
ctrl-season non-ctrl season
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parowan july 2010
0
2
4
6
8
10
12
14
16
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
Results of a grid-generated
momentarySevere electric / rain storm in the Beaver / Milford / Parowan
area coincident with 26 July Dispatch…repeated manipulations
to keep loads off during line power interruptions
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enterprise (2010 season)
0
1
2
3
4
5
6
7
0:000:401:202:00 2:40 3:204:004:405:206:006:40 7:208:008:409:20
10:0
0
10:40
11:20
12:0
0
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
21:2
0
22:00
22:40
23:20
time
mw
ctrl-season non-ctrl-season
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enterprise july 2010
0
1
2
3
4
5
6
7
8
9
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
15+16 and 19+20 July lower loads in Enterprise as those
growers were down for haying (2nd cutting)
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milford (total season)
0
1
2
3
4
5
6
7
8
0:000:401:202:00 2:40 3:204:004:405:206:006:40 7:208:008:409:20
10:0
0
10:40
11:20
12:0
0
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
21:2
0
22:00
22:40
23:20
time
mw
ctrl-season non-ctrl-season
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milford july 2010
0
1
2
3
4
5
6
7
8
9
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
the milford sub that feeds the ag-loads is south of town…this milford sub
serves town and only some of the ag-pumping load…it provides some
perspective of avoided loads but is largely incomplete
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