20110718PAC to IIPA 34 -1.pdf

Schedule 72 & 72A Idaho Irrigation Load Control
Programs
2009 Credit Rider Initiative Final Report

14 November 2009

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Table of Contents
Page
Report Organization ...................................................................................................................................................... 1
Background ................................................................................................................................................................... 1
2009 Schedule 72 (Scheduled Forward) Results.......................................................................................................... 1
Table Two Longitudinal and Current Year Scheduled 72 Participation Credits by Month ........................................... 2
Table Three Longitudinal and Current Year Scheduled 72 Participation Credits Issued ............................................ 2
Table Four Comparative Scheduled 72 & 72A Costs 2003, 2004 & 2005 .................................................................. 2
Table Five Schedule 72 Program Impacts by Participation Option ............................................................................. 3
Table Six Schedule 72 2009 Avoided kW by Month, Monday Control Day & Hour ..................................................... 4
Table Seven Schedule 72 2009 Avoided kW by Month, Tuesday Control Day & Hour .............................................. 4
Table Eight Schedule 72 2009 Avoided kW by Month, Wednesday Control Day & Hour ........................................... 5
Table Nine Schedule 72 2009 Avoided kW by Month, Thursday Control Day & Hour ................................................ 5
Cost-effectiveness analyses ......................................................................................................................................... 6
Table Ten 2009 Benefit / Cost Categories & Values−Schedule 72 ............................................................................. 6
Table Eleven 2009 Cost-effectiveness Analyses−Schedule 72 .................................................................................. 7
Measurement & Verification (M&V) processes ............................................................................................................. 7
2009 Schedule 72A (Dispatch) Results ........................................................................................................................ 8
Customer Opt-Outs ...................................................................................................................................................... 8
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 .............................................. 9
Table Fifteen Dispatch Program Only Net Load (kW) Impacts x Dispatch Event ........................................................ 9
Cost-effectiveness analyses ......................................................................................................................................... 9
Table Sixteen 2009 Benefit / Cost Categories & Values−Schedule 72A .................................................................. 10
Table Seventeen 2009 Cost-effectiveness Analyses ................................................................................................ 10
2009 Schedule 72 & Schedule 72A Results ............................................................................................................... 11
Avoided demand ......................................................................................................................................................... 11
Table Eighteen Program Impacts by Participation Option ......................................................................................... 11
Table Twenty 2009 Dispatch Events & Associated Net Avoided kW (Schedule 72 & Schedule 72A) ...................... 12
Table Twenty-One Hourly Load impacts Entire 2009 Program Season .................................................................... 12
\Table Twenty-One Hourly Load impacts Entire 2009 Program Season ................................................................... 13
Table Twenty-One (cont.) Hourly Load impacts Entire 2009 Program Season ......................................................... 14
Table Twenty-One (cont.) Hourly Load impacts Entire 2009 Program Season ......................................................... 15
Load profile data impact analysis ............................................................................................................................... 16
Cost-effectiveness analyses ....................................................................................................................................... 16
Table Twenty-three 2009 Cost-effectiveness Analyses ............................................................................................ 17
Conclusions................................................................................................................................................................. 17
Recommendations ...................................................................................................................................................... 18
Attachment One .......................................................................................................................................................... 19

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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 unique to the irrigation industry. 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 2009 program year (1 October 2008 through 31
September 2009) with the exception of participation credits. Unless otherwise noted, data are calculated as of 19
October 2009.

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

2009 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
Eligible 2009 Counts 4,723 2,032
Customers NOT eligible to participate 2009 N/A 0

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Table Two
Longitudinal and Current Year Scheduled 72 Participation Credits by Month

June July August September
Standard Credits $13,401.88 $14,140.39 $13,349.56 $3,020.44
kW Under Contract 5,887.01 4,204.0 4,151.0 3,344.0
Total Credits $43,912.27
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

Table Four
Comparative Scheduled 72 & 72A 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 Throughout this report and in all cases avoid demand values are reported at the site and are NOT grossed-up for generation thereby taking into
account T&D losses.
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Table Four (cont)
Comparative Load Control Program 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 Costs 2009

Cost Category
2009 Costs
Oct ‘08−Sept ‘09
Administrative support $253.27
Program evaluation $4,195.00
Field / Equip / Db admin. expenses $3,361,818.68
Participation credits $7,246,582.84
Program management $67,760.75
Reporting $0.0
Total Program costs $10,680,610.54

Table Five
Schedule 72 Program Impacts by Participation Option

Participation Option Site Cnt. June Avoided kW July Avoided kW Aug. Avoided kW Sept. Avoided kW
Option I m w 2-8 60 1,902.5 2,164.5 2,083.0 1,550.0
Option I t th 2-8 44 954.5 1,066.5 1,102.0 941.5
Option II m w 3-6 7 656.0 663.0 661.5 575.5
Option II m w 4-7 0 0.0 0.0 0.0 0.0
Option II t th 3-6 1 11.5 12.5 12.5 7.0
Option II t th 4-7 1 20.5 20.5 19.0 20.0
Option III m t w th 3-6 5 95.5 95.0 108.0 94.5
Option III m t w th 4-7 4 108.0 107.5 106.0 96.5
Option IV m 2-8 0 0.0 0.0 0.0 0.0
Option IV w 2-8 1 34.0 33.0 33.0 33.0
Totals 123 3,782.5 4,162.5 4,125.0 3,318.0
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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 2009 Avoided 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 1,902.5 2,654.0 2,762.0 2,762.0 2,010.5 1902.5

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 2,164.5 2,922.5 3,030.0 3,030.0 2,272.0 2,164.5

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 2,083 2,852.5 2,958.5 2,958.5 2,189.0 2,083.0

SEPTEMBER 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 1,550.0 2,220.0 2,316.5 2,316.5 1,646.5 1,550.0

Table Seven
Schedule 72 2009 Avoided 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 954.5 1,061.5 1,190.0 1,190.0 1,083.0 954.5

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 1,066.5 1,174.0 1,302.0 1,302.0 1,194.5 1,066.5

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 1,102.0 1,222.5 1,347.5 1,347.5 1,227.0 1,102.0

SEPTEMBER 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 941.5 1,043.0 1,159.5 1,159.5 1,058.0 941.5

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Table Eight
Schedule 72 2009 Avoided 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 1,936.5 2,688.0 2,796.0 2,796.0 2,044.5 1,936.5

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 2,197.5 2,955.5 3,063.0 3,063.0 2,305.0 2,197.5

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 2,116.0 2,885.5 2,991.5 2,991.5 2,222.0 2,116.0

SEPTEMBER 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 1,583.0 2,253.0 2,349.5 2,349.5 1,679.5 1,583.0

Table Nine
Schedule 72 2009 Avoided 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 954.5 1,061.5 1,190.0 1,190.0 1,083.0 954.5

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 1,066.5 1,174.0 1,302.0 1,302.0 1,194.5 1,066.5

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 1,102.0 1,222.5 1,347.5 1,347.5 1,227.0 1,102.0

SEPTEMBER 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 941.5 1,043.0 1,159.5 1,159.5 1,058.0 941.5

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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 avoided 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
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
2009 Benefit / Cost Categories & Values−Schedule 72

Cost Categories Cost Values Benefit Category Benefit Value
Administrative support $4.05 $/kW-yr avoided $73.09/kW
Program evaluation $67.12
Field / Equip / Db admin. expenses $53,789.10
Participation credits $43,912.27
Program management $1,084.17
Total $98,856.71
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

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

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 2009.
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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 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
2009 Cost-effectiveness Analyses−Schedule 72

Test Benefits Costs Net Benefits Benefit/Cost Ratio
TRC $150,189.21 $54,944.44 $95,244.77 2.73
Utility $150,189.21 $98,856.71 $51,332.50 1.52
Ratepayer $150,189.21 $98,856.71 $51,332.50 1.52
Participant $43,912.27 $0.00 $43,912.27 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 2009 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.
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2009 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
Eligible 2009 Counts 4,723 2,032
Customers NOT eligible to participate 2009 N/A 0

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 Twelve.

Table Thirteen
Opt-outs, Liquidated Damages, kW NOT Avoided and $/MWh by Dispatch Event

Count
Dispatch
Date Weekday
Count of
Opt-outs
Liquidated
Damages
kW NOT
avoided
$/MWh
(day ahead)
1 30-Jun Tuesday 64 $1,410.86 9,533 $37.00
2 17-Jul Friday 117 $2,127.22 12,891 $41.25
3 23-Jul Thursday 85 $2,213.75 11,776 $47.00
4 3-Aug Monday 42 $1,044.16 6,870 $38.00
5 5-Aug Wednesday 40 $1,166.96 7,294 $40.00
6 13-Aug Thursday 36 $648.82 4,159 $39.00
$8,611.77 52,521

Dispatch Events
Nominal loads avoided by the Dispatch Events are captured in Table Fourteen. Table Fifteen captures net
kW avoided for each Dispatch Event as opt-outs are netted from Table Fourteen calculations.

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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 30-Jun Tuesday 231,042.4 231,042.4 231,042.4 231,042.4 0.0 0.0
2 17-Jul Friday 254,192.9 254,192.9 254,192.9 254,192.9 0.0 0.0
3 23-Jul Thursday 254,192.9 254,192.9 254,192.9 254,192.9 0.0 0.0
4 3-Aug Monday 244,587.9 244,587.9 244,587.9 244,587.9 0.0 0.0
5 5-Aug Wednesday 244,587.9 244,587.9 244,587.9 244,587.9 0.0 0.0
6 13-Aug Thursday 244,587.9 244,587.9 244,587.9 244,587.9 0.0 0.0
Mean 'Dispatch Event' Avoided kW x hr. 245,532.0 245,532.0 245,532.0 245,532.0 0.0 0.0
Median 'Dispatch Event' Avoided kW x hr. 244,587.9 244,587.9 244,587.9 244,587.9 0.0 0.0

Table Fifteen
Dispatch Program Only 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 30-Jun Tuesday 221,509.9 221,509.9 221,509.9 221,509.9 0.0 0.0
2 17-Jul Friday 241,301.9 241,301.9 241,301.9 241,301.9 0.0 0.0
3 23-Jul Thursday 242,417.4 242,417.4 242,417.4 242,417.4 0.0 0.0
4 3-Aug Monday 237,718.4 237,718.4 237,718.4 237,718.4 0.0 0.0
5 5-Aug Wednesday 237,294.4 237,294.4 237,294.4 237,294.4 0.0 0.0
6 13-Aug Thursday 240,428.9 240,428.9 240,428.9 240,428.9 0.0 0.0
Mean 'Dispatch Event' Avoided kW x hr. 236,778.5 236,778.5 236,778.5 236,778.5 0.0 0.0
Median 'Dispatch Event' Avoided kW x hr. 239,073.7 239,073.7 239,073.7 239,073.7 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 72 portion of this program. Benefits and costs
for Schedule 72A (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 72A, 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 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

4 Again, to the extent possible, costs have been allocated by the respective Schedule initiative
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Program. The value was determined to be $59.43/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 $66.32/kW-yr.

Table Sixteen
2009 Benefit / Cost Categories & Values−Schedule 72A

Cost Categories Cost Values Benefit Category Benefit Value
Administrative support $249.22 $/kW-yr avoided $73.09/kW
Program evaluation $4,127.88
Field / Equip / Db admin. expenses $3,308,029.58
Participation credits $7,202,670.57
Program management $66,676.58
Total $10,581,753.83

As shown in Table Seventeen, 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 Seventeen
2009 Cost-effectiveness Analyses

Test Benefits Costs Net Benefits Benefit/Cost Ratio
TRC $20,026,707.58 $3,379,083.26 $16,647,624.32 5.93
Utility $20,026,707.58 $10,581,753.83 $9,444,953.75 1.89
Ratepayer $20,026,707.58 $10,581,753.83 $9,444,953.75 1.89
Participant $7,202,670.57 $0.00 $7,202,670.57 N/A

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2009 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 impacts by participation option for both Schedule 72 and 72A are presented in Table Eighteen.

Table Eighteen
Program Impacts by Participation Option

Option Counts June Avoided kW July Avoided kW Aug Avoided kW Sept Avoided kW
Option I m w 2-8 60 1,902.5 2,164.5 2,083 1,550
Option I t th 2-8 44 954.5 1066.5 1102 941.5
Option II m w 3-6 7 656 663 661.5 575.5
Option II m w 4-7 0 0 0 0 0
Option II t th 3-6 1 11.5 12.5 12.5 7
Option II t th 4-7 1 20.5 20.5 19 20
Option III m t w th 3-6 5 95.5 95 108 94.5
Option III m t w th 4-7 4 108 107.5 106 96.5
Option IV m 2-8 0 0 0 0 0
Option IV w 2-8 1 34 33 33 33
Schedule Forward totals 123 3,782.5 4,162.5 4,125.0 3,318.0
Dispatch Option totals 1,927 231,042.4 254,192.9 244,587.9 215,604.4
Totals: 2,050 234,824.9 258,355.4 248,712.9 218,922.4

The 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, a zero (0) appears in two 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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2009 Idaho Irrigation Load Control Program-Final Report Page 12
Table Nineteen
2009 Dispatch Events & Associated Avoided kW (Schedule 72 & Schedule 72A)

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 30-Jun Tuesday 231,996.9 232,103.9 232,232.4 232,232.4 1,083.0 975.0
2 17-Jul Friday 254,192.9 254,192.9 254,192.9 254,192.9 0.0 0.0
3 23-Jul Thursday 255,259.4 255,366.9 255,494.9 255,494.9 1,194.5 1,066.5
4 3-Aug Monday 246,670.9 247,440.4 247,546.4 247,546.4 2,189.0 2,083.0
5 5-Aug Wednesday 246,703.9 247,473.4 247,579.4 247,579.4 2,222.0 2,116.0
6 13-Aug Thursday 245,689.9 245,810.4 245,935.4 245,935.4 1,227.0 1,102.0
Mean 'Dispatch Event' Avoided kW x hr. 246,752.3 247,064.7 247,163.6 247,163.6 1,319.3 1,223.8
Median 'Dispatch Event' Avoided kW x hr. 246,687.4 247,456.9 247,562.9 247,562.9 1,210.8 1,084.3

Table Twenty
2009 Dispatch Events & Associated Net Avoided kW (Schedule 72 & Schedule 72A)

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 30-Jun Tuesday 222,464.4 222,571.4 222,699.9 222,699.9 1,083.0 975.0
2 17-Jul Friday 241,301.9 241,301.9 241,301.9 241,301.9 0.0 0.0
3 23-Jul Thursday 243,483.9 243,591.4 243,719.4 243,719.4 1,194.5 1,066.5
4 3-Aug Monday 239,801.4 240,570.9 240,676.9 240,676.9 2,189.0 2,083.0
5 5-Aug Wednesday 239,410.4 240,179.9 240,285.9 240,285.9 2,222.0 2,116.0
6 13-Aug Thursday 241,530.9 241,651.4 241,776.4 241,776.4 1,227.0 1,102.0
Mean 'Dispatch Event' Avoided kW x hr. 237,998.8 238,311.2 238,410.1 238,410.1 1,319.3 1,223.8
Median 'Dispatch Event' Avoided kW x hr. 240,551.7 240,936.4 240,989.4 240,989.4 1,210.8 1,084.3

Season-long hourly load impacts are presented in Table Nineteen. The tan color-coding represents the hour and day
of dispatch events. The green color-coding represents Schedule Forward dispatches.

Table Twenty-One
Hourly Load impacts Entire 2009 Program Season

1-Jun 2-Jun 3-Jun 4-Jun 5-Jun
hour monday tuesday wednesday thursday friday
2:00-2:59 1,902.5 954.5 1,936.5 954.5 0.0
3:00-3:59 2,654.0 1,061.5 2,688.0 1,061.5 0.0
4:00-4:59 2,762.0 1,190.0 2,796.0 1,190.0 0.0
5:00-5:59 2,762.0 1,190.0 2,796.0 1,190.0 0.0
6:00-6:59 2,010.5 1,083.0 2,044.5 1,083.0 0.0
7:00-7:59 1,902.5 975.0 1,936.5 975.0 0.0

ID PAC-E-11-12
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2009 Idaho Irrigation Load Control Program-Final Report Page 13
Table Twenty-One
Hourly Load impacts Entire 2009 Program Season

8-Jun 9-Jun 10-Jun 11-Jun 12-Jun
hour monday tuesday wednesday thursday friday
2:00-2:59 1,902.5 954.5 1,936.50 954.5 0.0
3:00-3:59 2,654.0 1,061.5 2,688.0 1,061.5 0.0
4:00-4:59 2,762.0 1,190.0 2,796.0 1,190.0 0.0
5:00-5:59 2,762.0 1,190.0 2,796.0 1,190.0 0.0
6:00-6:59 2,010.5 1,083.0 2,044.50 1,083.0 0.0
7:00-7:59 1,902.5 975.0 1,936.50 975.0 0.0

15-Jun 16-Jun 17-Jun 18-Jun 19-Jun
hour monday tuesday wednesday thursday friday
2:00-2:59 1,902.5 954.5 1,936.50 954.5 0.0
3:00-3:59 2,654.0 1,061.5 2,688.0 1,061.5 0.0
4:00-4:59 2,762.0 1,190.0 2,796.0 1,190.0 0.0
5:00-5:59 2,762.0 1,190.0 2,796.0 1,190.0 0.0
6:00-6:59 2,010.5 1,083.0 2,044.50 1,083.0 0.0
7:00-7:59 1,902.5 975.0 1,936.50 975.0 0.0

22-Jun 23-Jun 24-Jun 25-Jun 26-Jun
hour monday tuesday wednesday thursday friday
2:00-2:59 1,902.5 954.5 1,936.5 954.5 0.0
3:00-3:59 2,654.0 1,061.5 2,688.0 1,061.5 0.0
4:00-4:59 2,762.0 1,190.0 2,796.0 1,190.0 0.0
5:00-5:59 2,762.0 1,190.0 2,796.0 1,190.0 0.0
6:00-6:59 2,010.5 1,083.0 2,044.5 1,083.0 0.0
7:00-7:59 1,902.5 975.0 1,936.5 975.0 0.0

29-Jun 30-Jun 1-Jul 2-Jul 3-Jul
hour monday tuesday wednesday thursday friday
2:00-2:59 1,902.5 231,996.9 2,197.5 1,066.5 0.0
3:00-3:59 2,654.0 232,103.9 2,955.5 1,174.0 0.0
4:00-4:59 2,762.0 232,232.4 3,063.0 1,302.0 0.0
5:00-5:59 2,762.0 232,232.4 3,063.0 1,302.0 0.0
6:00-6:59 2,010.5 1,083.0 2,305.0 1,194.5 0.0
7:00-7:59 1,902.5 975.0 2,197.5 1,066.5 0.0

ID PAC-E-11-12
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Table Twenty-One (cont.)
Hourly Load impacts Entire 2009 Program Season

6-Jul 7-Jul 8-Jul 9-Jul 10-Jul
hour monday tuesday wednesday thursday friday
2:00-2:59 2,164.5 1,066.5 2,197.5 1,066.5 0.0
3:00-3:59 2,922.5 1,174.0 2,955.5 1,174.0 0.0
4:00-4:59 3,030.0 1,302.0 3,063.0 1,302.0 0.0
5:00-5:59 3,030.0 1,302.0 3,063.0 1,302.0 0.0
6:00-6:59 2,272.0 1,194.5 2,305.0 1,194.5 0.0
7:00-7:59 2,164.5 1,066.5 2,197.5 1,066.5 0.0

13-Jul 14-Jul 15-Jul 16-Jul 17-Jul
hour monday tuesday wednesday thursday friday
2:00-2:59 2,164.5 1,066.5 2,197.5 1,066.5 254,192.9
3:00-3:59 2,922.5 1,174.0 2,955.5 1,174.0 254,192.9
4:00-4:59 3,030.0 1,302.0 3,063.0 1,302.0 254,192.9
5:00-5:59 3,030.0 1,302.0 3,063.0 1,302.0 254,192.9
6:00-6:59 2,272.0 1,194.5 2,305.0 1,194.5 0.0
7:00-7:59 2,164.5 1,066.5 2,197.5 1,066.5 0.0

20-Jul 21-Jul 22-Jul 23-Jul 24-Jul
hour monday tuesday wednesday thursday friday
2:00-2:59 2,164.5 1,066.5 2,197.5 255,259.4 0.0
3:00-3:59 2,922.5 1,174.0 2,955.5 255,366.9 0.0
4:00-4:59 3,030.0 1,302.0 3,063.0 255,494.9 0.0
5:00-5:59 3,030.0 1,302.0 3,063.0 255,494.9 0.0
6:00-6:59 2,272.0 1,194.5 2,305.0 1,194.5 0.0
7:00-7:59 2,164.5 1,066.5 2,197.5 1,066.5 0.0

27-Jul 28-Jul 29-Jul 30-Jul 31-Jul
hour monday tuesday wednesday thursday friday
2:00-2:59 2,164.5 1,066.5 2,197.5 1,066.5 0.0
3:00-3:59 2,922.5 1,174.0 2,955.5 1,174.0 0.0
4:00-4:59 3,030.0 1,302.0 3,063.0 1,302.0 0.0
5:00-5:59 3,030.0 1,302.0 3,063.0 1,302.0 0.0
6:00-6:59 2,272.0 1,194.5 2,305.0 1,194.5 0.0
7:00-7:59 2,164.5 1,066.5 2,197.5 1,066.5 0.0

ID PAC-E-11-12
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2009 Idaho Irrigation Load Control Program-Final Report Page 15
Table Twenty-One (cont.)
Hourly Load impacts Entire 2009 Program Season

3-Aug 4-Aug 5-Aug 6-Aug 7-Aug
hour monday tuesday wednesday thursday friday
2:00-2:59 246,670.9 1,102.0 246,703.9 1,102.0 0.0
3:00-3:59 247,440.4 1,222.5 247,473.4 1,222.5 0.0
4:00-4:59 247,546.4 1,347.5 247,579.4 1,347.5 0.0
5:00-5:59 247,546.4 1,347.5 247,579.4 1,347.5 0.0
6:00-6:59 2,189.0 1,227.0 2,222.0 1,227.0 0.0
7:00-7:59 2,083.0 1,102.0 2,116.0 1,102.0 0.0

10-Aug 11-Aug 12-Aug 13-Aug 14-Aug
hour monday tuesday wednesday thursday friday
2:00-2:59 2,083.0 1,102.0 2,116.0 245,689.9 0.0
3:00-3:59 2,852.5 1,222.5 2,885.5 245,810.4 0.0
4:00-4:59 2,958.5 1,347.5 2,991.5 245,935.4 0.0
5:00-5:59 2,958.5 1,347.5 2,991.5 245,935.4 0.0
6:00-6:59 2,189.0 1,227.0 2,222.0 1,227.0 0.0
7:00-7:59 2,083.0 1,102.0 2,116.0 1,102.0 0.0

17-Aug 18-Aug 19-Aug 20-Aug 21-Aug
hour monday tuesday wednesday thursday friday
2:00-2:59 2,083.0 1,102.0 2,116.0 1,102.0 0.0
3:00-3:59 2,852.5 1,222.5 2,885.5 1,222.5 0.0
4:00-4:59 2,958.5 1,347.5 2,991.5 1,347.5 0.0
5:00-5:59 2,958.5 1,347.5 2,991.5 1,347.5 0.0
6:00-6:59 2,189.0 1,227.0 2,222.0 1,227.0 0.0
7:00-7:59 2,083.0 1,102.0 2,116.0 1,102.0 0.0

24-Aug 25-Aug 26-Aug 27-Aug 31-Aug
hour monday tuesday wednesday thursday monday
2:00-2:59 2,083.0 1,102.0 2,116.0 1,102.0 2083.0
3:00-3:59 2,852.5 1,222.5 2,885.5 1,222.5 2852.5
4:00-4:59 2,958.5 1,347.5 2,991.5 1,347.5 2958.5
5:00-5:59 2,958.5 1,347.5 2,991.5 1,347.5 2958.5
6:00-6:59 2,189.0 1,227.0 2,222.0 1,227.0 2189.0
7:00-7:59 2,083.0 1,102.0 2,116.0 1,102.0 2083.0

ID PAC-E-11-12
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Load profile data impact analysis
Throughout the control period, Company SCADA data were collected and used in preparing 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 Grassey; (3) Rigby; (4) Bonneville and (5) Jefferson. The impact of load
dispatches is dramatic and unequivocal. When interpreting these plots keep in mind that June was 348% of normal
rainfall and only 55% of normal temperature. Hence, the magnitude of June loads is significantly less than previous
seasons. Further analysis suggest 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-two below5.

Table Twenty-two
2009 Benefit / Cost Categories & Values−Schedules 72 & 72A

Cost Categories Cost Values Benefit Category Benefit Value
Administrative support $253.27 $/kW-yr avoided $73.09/kW
Program evaluation $4,195.00
Field / Equip / Db admin. expenses $3,361,818.68
Participation credits $7,246,582.84
Program management $67,760.75
Total $10,680,610.54

All-in $/kW program costs6 $41.34 Total kW 258,355.4*
*Total max load for July

As shown in Table Twenty-three, 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.

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.
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Table Twenty-three
2009 Cost-effectiveness Analyses

Test Benefits Costs Net Benefits Benefit/Cost Ratio
TRC $20,149,384.07 $3,434,027.70 $16,715,356.37 5.87
Utility $20,149,384.07 $10,680,610.54 $9,468,773.53 1.89
Ratepayer $20,149,384.07 $10,680,610.54 $9,468,773.53 1.89
Participant $7,246,582.84 $0.00 $7,246,582.84 N/A

Conclusions
Grower perception considerations
™ The 2009 Dispatch 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 / ag-electrician specialists.
™ Throughout the 2009 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.

Meteorological considerations7
™ From a meteorological perspective June was an anomaly. Rainfall was 348% of normal and temperatures
only 55% of normal.
™ The two above mentioned factors translated into virtually no (zero) pump load during June.
™ July temperatures were 114% of normal (as measured by the ΣCDD and rainfall was 39% of normal
™ August temperatures were 97% of normal (again, as measured by ΣCDD) and rainfall was 53% of normal
™ Over the three summer months rainfall was 149% of normal and temperature 95% of normal

Peak considerations
™ In the arid intermountain west it is high night-time lows that drive system peak. 2009 was unique in that
there were only four instances where the night-time low stayed ≥ 70oF. Moreover, only two of those days
where the night-time low stayed ≥ 70oF fell on a weekday.
™ In 2007 the all-time system peak was reached. In 2009 the peak was never close to being breeched. This
was likely due to a slower economy and more normal-like temperatures. Nevertheless, dispatch events
were executed coincident with each of the respective three summer months, day and hour peaks.

7 All data is based on Salt Lake City. This is relevant as RMP east-side grid control area is driven by Wasatch Front meteorological considerations. Further note that ‘normal’ was calculated over a 40-year time horizon.
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2009 Idaho Irrigation Load Control Program-Final Report Page 18
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 ~40% of the Goshen Transmission Substation
and nearly 80% of four of the five transmission substations monitored.
™ Idaho Engineering Area Planning is concerned that too much load is either removed from or added to the
system in too narrow of a time-frame (causing voltage imbalances).
™ With the exception of the Rigby Transmission Substation there is virtually no load diversity on the four
transmission substations−(1) Amps; (2) Big Grassey; (3) Jefferson and (4) Bonneville.
™ Upon initiation of a dispatch event voltage spikes above tolerances of existing substation and/or circuit
protective equipment and systems.
™ Upon the conclusion of the dispatch event and loads are once again returned to their ‘normal’ position
voltage drops below tolerances of existing substation and/or circuit protective equipment and systems.
™ Currently there is simply insufficient time delay in either substation and/or system circuitry to accommodate
the dramatic voltage changes.

Recommendations
Changes to dispatch protocols
™ Plenary discussions with RMP Area Planning (Idaho) has determined that a more intelligent stepping into
and out-of dispatch events will correct the voltage spikes / sags currently occurring.
™ Changes to the dispatch protocol may be an effective strategy to delay additional capital investment in
infrastructure assets.
™ Changing the dispatch protocol will require analysis of the RMP engineering database to determine geo-
spatial load locations as well as coordination with growers
™ A changed dispatch protocol will require the available dispatch windows to be lengthened
™ The aforementioned changes have been preliminarily discussed with Idaho growers and with members of
the Idaho Irrigators Pumpers’ Association (IIPA).
™ The IIPA is supportive of the requisite changes.
™ This requirement will also necessitate a tariff modification.
™ As soon as analysis can be concluded and a dispatch strategy designed the Company will provide details
that will be (1) reviewed with the IIPA and (2) put forward the appropriate tariff changes to Schedule 72A
for Commission consideration.

ID PAC-E-11-12
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Attachment One

Schedule & Duration of ’09 Dispatch Events

IDAHO
30 June ................. 4 hrs
17 July ................... 4 hrs
23 July ................... 4 hrs
3 August ................ 4 hrs
5 August ................ 4 hrs
13 August .............. 4 hrs
Total hours ............ 24
Note: all dispatch events were executed between 2:00p−6:00p
Further Note: dispatch events were executed coincident with individual month, day and hour as well as seasonal
peak periods

Load Plot Contents

Rocky Mountain Power Transmission Substations ..................................................................................................... 20
Big Grassey Transmission Substation (30 June) ....................................................................................................... 21
Big Grassey Transmission Substation (17 July) ......................................................................................................... 21
Big Grassey Transmission Substation (23 July) ......................................................................................................... 22
Big Grassey Transmission Substation (3 August) ...................................................................................................... 22
Big Grassey Transmission Substation (5 August) ...................................................................................................... 23
Big Grassey Transmission Substation (13 August) .................................................................................................... 23
Amps-Monteview Area Transmission Substation (30 June) ....................................................................................... 24
Amps-Monteview Area Transmission Substation (17 July) ........................................................................................ 24
Amps-Monteview Area Transmission Substation (23 July) ........................................................................................ 25
Amps-Monteview Area Transmission Substation (3 August) ..................................................................................... 25
Amps-Monteview Area Transmission Substation (13 August) ................................................................................... 26
Rigby Transmission Substation (30 June) .................................................................................................................. 27
Rigby Transmission Substation (17 July) ................................................................................................................... 27
Rigby Transmission Substation (23 July) ................................................................................................................... 28
Rigby Transmission Substation (3 August) ................................................................................................................ 28
Rigby Transmission Substation (5 August) ................................................................................................................ 29
Rigby Transmission Substation (13 August) .............................................................................................................. 29
Bonneville Transmission Substation (30 June) .......................................................................................................... 30
Bonneville Transmission Substation (17 July) ............................................................................................................ 30
Bonneville Transmission Substation (23 July) ............................................................................................................ 31
Bonneville Transmission Substation (3 August) ......................................................................................................... 31
Bonneville Transmission Substation (5 August) ......................................................................................................... 32
Bonneville Transmission Substation (13 August) ....................................................................................................... 32
Jefferson Transmission Substation (17 July) .............................................................................................................. 33
Jefferson Transmission Substation (23 July) .............................................................................................................. 34
Jefferson Transmission Substation (3 August) ........................................................................................................... 34
Jefferson Transmission Substation (5 August) ........................................................................................................... 35
Jefferson Transmission Substation (13 August) ......................................................................................................... 35

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Rocky Mountain Power Northern Tier Transmission Substations

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Big Grassey Transmission Substation (30 June)
big grassey 30 june 09
0
5
10
15
20
25
30
35
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 (24 hrs)
mw
60s load data

Big Grassey Transmission Substation (17 July)
big grassey 17 july 09
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 (24 hrs)
mw
60s load data
units released early as a function of a wide-spread momentary

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Big Grassey Transmission Substation (23 July)
big grassey 23 july 09
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 (24 hrs)
MW
60s load data

Big Grassey Transmission Substation (3 August)
big grassey 3 august09
0
5
10
15
20
25
30
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 (24 hrs)
mw
60s load data
released early upon the request
of GridOps

ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -1
Attach IIPA 34 -1.pdf Page 24 of 37

2009 Idaho Irrigation Load Control Program-Final Report Page 23
Big Grassey Transmission Substation (5 August)
big grassey 5 august 09
0
5
10
15
20
25
30
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 (24 hrs)
mw
60s load data
units released early as a function of a
wide-spread momentary

Big Grassey Transmission Substation (13 August)
big grassey 13 august 09
0
5
10
15
20
25
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 (24 hrs)
mw
60s load data
units released early upon the
request of GridOps

ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -1
Attach IIPA 34 -1.pdf Page 25 of 37

2009 Idaho Irrigation Load Control Program-Final Report Page 24
Amps-Monteview Area Transmission Substation (30 June)
amps 30 june 09
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 (24 hrs)
mw
60s load data

Amps-Monteview Area Transmission Substation (17 July)
amps 17 july 09
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 (24 hrs)
mw
60s load data
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -1
Attach IIPA 34 -1.pdf Page 26 of 37

2009 Idaho Irrigation Load Control Program-Final Report Page 25
Amps-Monteview Area Transmission Substation (23 July)
amps 23 july 09
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 (24 hrs)
mw
60s load data

Amps-Monteview Area Transmission Substation (3 August)
amps 3 august 09
0
2
4
6
8
10
12
14
16
18
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 (24 hrs)
mw
60s load data
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -1
Attach IIPA 34 -1.pdf Page 27 of 37

2009 Idaho Irrigation Load Control Program-Final Report Page 26
Amps-Monteview Area Transmission Substation (5 August)
amps 5 august 09
0
2
4
6
8
10
12
14
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 (24 hrs)
mw
60s load data

Amps-Monteview Area Transmission Substation (13 August)
amps 13 august 09
0
2
4
6
8
10
12
14
16
18
20
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 (24 hrs)
mw
60s load data
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -1
Attach IIPA 34 -1.pdf Page 28 of 37

2009 Idaho Irrigation Load Control Program-Final Report Page 27
Rigby Transmission Substation (30 June)
rigby 30 june 09
0
10
20
30
40
50
60
70
80
90
100
110
120
130
140
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 (24 hrs)
mw
60s load data

Rigby Transmission Substation (17 July)
rigby 17 july 09
0
10
20
30
40
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 (24 hrs)
mw
60s load data
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -1
Attach IIPA 34 -1.pdf Page 29 of 37

2009 Idaho Irrigation Load Control Program-Final Report Page 28
Rigby Transmission Substation (23 July)
rigby 23 july 09
0
10
20
30
40
50
60
70
80
90
100
110
120
130
140
150
160
170
180
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 (24 hrs)
mw
60s load data

Rigby Transmission Substation (3 August)
ribgy 3 august 09
0
10
20
30
40
50
60
70
80
90
100
110
120
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 (24 hrs)
mw
60s load data
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -1
Attach IIPA 34 -1.pdf Page 30 of 37

2009 Idaho Irrigation Load Control Program-Final Report Page 29
Rigby Transmission Substation (5 August)
rigby 5 august 09
0
10
20
30
40
50
60
70
80
90
100
110
120
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 (24 hrs)
mw
60s load data

Rigby Transmission Substation (13 August)
rigby 13 august 09
0
10
20
30
40
50
60
70
80
90
100
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 (24 hrs)
mw
60s load data
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -1
Attach IIPA 34 -1.pdf Page 31 of 37

2009 Idaho Irrigation Load Control Program-Final Report Page 30
Bonneville Transmission Substation (30 June)
bonneville 30 june 09
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 (24 hrs)
mw
60s load data

Bonneville Transmission Substation (17 July)
bonneville 17 july 09
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 (24 hrs)
mw
60s load data
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -1
Attach IIPA 34 -1.pdf Page 32 of 37

2009 Idaho Irrigation Load Control Program-Final Report Page 31
Bonneville Transmission Substation (23 July)
bonneville 23 july 09
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 (24 hrs)
mw
60s load data

Bonneville Transmission Substation (3 August)
bonneville 3 august 09
0
5
10
15
20
25
30
35
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 (24 hrs)
mw
60s load data
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -1
Attach IIPA 34 -1.pdf Page 33 of 37

2009 Idaho Irrigation Load Control Program-Final Report Page 32
Bonneville Transmission Substation (5 August)
bonneville 5 august 09
0
5
10
15
20
25
30
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 (24 hrs)
mw
60s load data

Bonneville Transmission Substation (13 August)
bonneville 13 august 09
0
2
4
6
8
10
12
14
16
18
20
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 (24 hrs)
mw
60s load data
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -1
Attach IIPA 34 -1.pdf Page 34 of 37

2009 Idaho Irrigation Load Control Program-Final Report Page 33
Jefferson Transmission Substation (30 June)
jefferson 30 june 09
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 (24 hrs)
mw
60s load data

Jefferson Transmission Substation (17 July)
jefferson 17 july 09
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 (24 hrs)
mw
60s load data
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -1
Attach IIPA 34 -1.pdf Page 35 of 37

2009 Idaho Irrigation Load Control Program-Final Report Page 34
Jefferson Transmission Substation (23 July)
jefferson 23 july 09
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 (24 hrs)
mw
60s load data

Jefferson Transmission Substation (3 August)
Jefferson 3 august 09
0
5
10
15
20
25
30
35
40
45
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 (24 hrs)
mw
60s load data
Beginning with the 3 August dispatch and continuing through the 13 August dispatch
the Jefferson Transmission Substation load data is calculated using transformer 1 + transformer 2. This was done because transformer 1 was reporting in error. The net
effect is that the max values are somewhat depressed and indicate slightly lower
values. The minimum values, however, are unaffected.

ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -1
Attach IIPA 34 -1.pdf Page 36 of 37

2009 Idaho Irrigation Load Control Program-Final Report Page 35
Jefferson Transmission Substation (5 August)
jefferson 05 august 09
0
5
10
15
20
25
30
35
40
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 (24 hrs)
mw
60s load data

Jefferson Transmission Substation (13 August)
jefferson 13 august 09
0
5
10
15
20
25
30
35
40
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 (24 hrs)
mw
60s load data
ID PAC-E-11-12
IIPA 34 Attachment IIPA 34 -1
Attach IIPA 34 -1.pdf Page 37 of 37