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Home My WebLink About20081202Report for 2008.pdf"~ROCKY MOUNTAIN POWI:R A DIVISN OF PAIACORP RECEIVED 2000 DEC -2 AM 10: l 6 201 South Main, Suite 2300 Salt Lake City, Utah 84111 December 2, 2008 IDAHO PUBLIC .TI.... "'''U'i''i;c':UTILI di "..l.,¡,I.¡"k,;..i: Idaho Public Utilties Commission 4 72 West Washigton Boise, il 83702-5983 Plrc.-iS -0' -l~ Attention:Jean D. Jewell Commission Secreta Re: Irrigation Load Control 2008 Report Rocky Mountain Power, a division ofPacifiCorp, hereby submits for filing its report detaling the results of the Dispatchable Irrgation Load Control Credit Rider Program for 2008. In case PAC-E-06-12 the Commssion issued Order No. 30243 requig the Company to fie a report at the end of the 2007 irgation season. The Company complied with tht order and is fiing this report for informationa puroses. The Company recommends the continuation of the dispatchable irrgation load control program as a demand side management offerig in its Idaho service terrtory. The Company also recommends tht the irrgation load control program results be incorporated into the anua DSM report filed in Apnl of each year. An agreement specifying the incentive level, based on customer paricipation, for the load control service credit through the 2009 irgation season was reached with the Idaho Irgation Pumpers Association as par of the Company's 2007 general rate case and was approved by the Commission in Case No. PAC-E-07-05. It is respectfuly requested that all formal correspondence and Staff requests regarding this matenal be addressed to: Bye-mail (preferred):dataequest~pacificorp.com By reguar mail:Data Request Response Center PacifiCorp 825 NE Multnomah, Suite 2000 Portland, Oregon 97232 By fax:(503) 813-6060 Any informal inquines may also be directed to Ted Weston, Idaho Regulatory Affais Manager, at 801-220-2963. Idaho Public Utilties Commission December 2, 2008 Page 2 Jeffy K L se ~ft Vice President, Reguation . Enclosures A DIVISION OF PACIFICORP s g_ .c:Sa ~ ;0ri5: C' i;(Po ' rng-o N ~ ~,~~ ~ rnS~vJ ::c:, ~~~, S -tfJ __ ç:;-Schedule 72 & 72A Idaho Irrigation Load Control "'~. Programs 2008 Credit Rider Initiative Final Report (1 25 November 2008 Table of Contents Page Report Organization................................................................................................................... ....................................... 1 Background .... ...... ...................... .......................... .... ...... ...... ........................ ... .......................... ...................... .................. 1 2008 Schedule 72 (Scheduled Forward) Results.............................................................................................................. 1 Table Two 2008 Scheduled Forward Participation Credits by Month .......................................................................... 2 Table Three 2003-2008 Comparative Schedule 72 Participation Credits Issued ....................................................... 2 Table Four Comparative Load Control Program Costs 2003, 2004 & 2005................................................................ 3 Table Five Program Impacts by Participation Option...................................................................................................4 Table Six 2008 Avoided kW by Month, Monday Control Day & Hour..........................................................................4 Table Seven 2008 Avoided kW by Month, Tuesday Control Day & Hour.................................................................... 5 Table Eight 2008 Avoided kW by Month, Wednesday Control Day & Hour................................................................. 5 Table Nine 2008 Avoided kW by Month, Thursday Control Day & Hour .....................................................................6 Cost-effectiveness analyses....................................................................................................................... .................. 6 Table Ten 2008 Benefit I Cost Categories & Values-Scedule 72 ............................................................................. 7 Table Eleven 2008 Schedule 72 Cost-effectiveness Analyses.................................................................................... 8 Measurement & Verification (M& V) processes............................................................................................................. 8 2008 Schedule 72A (Dispatch) Results..... .......................... ........................................................... ........ ................ ........... 9 Background.................................................................................................................... ............................................... 9 Customer Credits....................................................................................................................... ...................................9 Customer Opt-Outs....................................................................................................................... ................................ 9 Table Twelve Opt-outs by Dispatch Event................................................................................................................10 Dispatch Events..........................................................................................................................................................10 Table Thirteen Dispatch Program Only Nominal Load (kW) Impacts x Dispatch Event ............................................ 11 Table Fourteen Dispatch Program Only Net Load (kW) Impacts x Dispatch Event................................................. 11 Cost-effectiveness analyses........................................................................................................................ ............... 12 Table Fifteen 2008 Benefit i Cost Categories & Values-Schedule 72A....................................................................12 Table Sixteen 2008 Cost-effectiveness Analyses......................................................................................................12 2008 Schedule 72 & Schedule 72A Results....................... ....................................... .................. .................................... 13 Avoided demand ..... ...... ........................ ............. .... .................. ...... ...... .... ................................................................... 13 Table Seventeen 2008 Dispatch Events & Associated Avoided kW..........................................................................13 Load profile data (CB-67 (Big Grassey)).....................................................................................................................14 Table Eighteen Dispatch Events & Load Impacts (CB-67) ........................................................................................14 Ilustration One Big Grassey Transmission Load Profile June 18, 2008 (CB 67-'Big Grassy') ..................................15 Ilustration Two Big Grassey Transmission Load Profile June 30,2008 (CB 67-'Big Grassy') ..................................16 Illustration Three Big Grassey Transmission Load Profile July 15+18, 2008 (CB 67-'Big Grassy')........................... 17 Ilustration Four Big Grassey Transmission Load Profile July 21, 2008 (CB 67 _'Big Grassy') .................. ................. 18 Ilustration Five Big Grassey Transmission Load Profile July 25,2008 (CB 67-'Big Grassy') ...................................19 Ilustration Six Big Grassey Transmission Load Profile July 28+29,2008 (CB 67-'Big Grassy') ............................... 20 Ilustration Seven Big Grassey Transmission Load Profile August 11,2008 (CB 67-'Big Grassy') ...........................21 Ilustration Eight Big Grassey Transmission Load Profile August 20,2008 (CB 67-'Big Grassy') .............................22 Ilustration Nine Big Grassey Transmission Load Profile August 25,2008 (CB 67-'Big Grassy') ..............................23 Irrigation season load profile........................................:..............................................................................................23 Ilustration Ten Big Grassey Irrigation Season Maximum, Minimum & Average Daily Plots...................................... 25 Load profile data (Total RMP Southeast Idaho unadjusted FERC load data) ............................................................25 Ilustration Eleven Total RMP Hourly Idaho Loads (June): Idaho Irrigation Load Control-Dispatch Days vs. Non-Control Days............................................................................................................. 26 Ilustration Twelve Total RMP Hourly Idaho Loads (July): Idaho Irrigation Load Control-Dispatch Days vs. Non-Control Days............................................................................................................. 27 Ilustration Thirteen Total RMP Hourly Idaho Loads (August): Idaho Irrigation Load Control-Dispatch Days vs. Non-Control Days............................................................................................................. 28 Ilustration Fourteen Total RMP Hourly Idaho Loads June 18 & June 30 Dispatch Days..........................................29 Ilustration Fifteen Total RMP Hourly Idaho Loads July 16,17,21,25,28 & 29 Dispatch Days ...............................30 Ilustration Sixteen Total RMP Hourly Idaho Loads August 11, 20 & 25 Dispatch Days............................................ 31 Ilustration Seventeen Total RMP Hourly Idaho Loads June Estimated Impact to Peak ........................................... 32 Ilustration Eighteen Total RMP Hourly Idaho Loads July Estimated Impact to Peak................................................ 33 Ilustration Nineteen Total RMP Hourly Idaho Loads August Estimated Impact to Peak.. .........................................34 Cost-effectiveness analyses...................................................................................................................... ................. 34 Table Twenty 2008 Cost-effectiveness Analyses ...................................................................................................... 35 Conclusions & Recommendations................................................................................................................ .................. 35 ii Report Organization Idaho Public Utilties 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 Irrgation 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 effcacy of a 2-way control technology unique to the irrigation industry. This report presents results on Schedule 72 and Schedule 72A as required by the Commission order. The Schedule 72A assessment wil follow the standard report. Finally, summary statistics from both Schedule 72 and Schedule 72A wil be combined and presented. 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 SeNice 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 andlor recommendations to improve the Program 2008 Schedule 72 (Scheduled Forward) Results Table One provides the number of irrigation customers and sites eligible to participate in the Program (requirement #1) 1 and the number of customers and sites that entered into the load control Service Agreement (requirement #2). Details for Program years 2003, 2004, 2005, 2006 and 2007 are provided for comparison. The data presented in Table One reflect the number of irrigation customers and sites that participated in the Program for the full three and one-half months (requirement #3). In 2008, 1.9% of total available sites and 3.9% of the total available customers participated in the Program. These figures represent a decrease of 87.3% and 80.4% respectively over 2007 participation counts (14.8% of eligible sites and 20.0% of eligible customers) There are zero customers NOT eligible to partcipate in 2008 (requirement #4). 1 Data are reportd as of 6 November 2008. This notation is importnt as Program partcipants may change tlroughout tle season as a functon of agri-busines, weatler, crop type and/or equipment vagaries. Wherever poible and based on what tle Irratin Management Team has determined to be the most understandable way to communicate quanlitive Program demographics and impact, reportng date may change and apper to be somewhat inconsistent Accrdingly, and tlroughout tlis report tle date for the specific quantittive reult wil be noted. 2008 Idaho Irrigation Load Control Proram-Final Report Page 1 Table One Schedule 10 Eligible & Full-Year Participating Sites & Customers 2003 Actual Participants 2004 Actual Participants 2005 Actual Participants 2006 Actual Participants 2007 Actual Participants 2008 Actual Participants Eligible 2008 Counts Customers NOT eligible to participate 2008 Note: based on 6 November 2008 data sets Partcipant Sites 401 734 1,065 931 681 87 4,637 NIA Partcipant Customers 207 340 489 478 405 79 2,013 o The monthly participation credit amounts issued to 2008 Program participants are presented in Table Two (requirement #5). Total Program participation credits ($30,680.65) represent a 95.5% decrease (or $653,244.33 less) over 2007 credits. The reason for this decrease is because a significant number of growers elected to participate in the Dispatch (Schedule 72A) option. Table Two further presents the total amount of resource under contract at the time of credit issuance. Table Three presents a comparative analysis of credits issued for the 2003, 2004, 2005, 2006, 2007 and 2008 Program years. Table Two 2008 Scheduled Forward Participation Credits by Month Standard Credits kW Under Contract Total Credits June $7,489.47 2,600.02 $3068065 Note: avoided kW is as of the day of crit issuance July $10,305.58 2,987.5 August $10,081.16 3,019.5 September $2,804.44 2,925.5 Table Three 2003-2008 Comparative Schedule 72 Partcipation Credits Issued Year Total Participaton Creits Issued 2003 $277,583.72 2004 $410,325.49 2005 $842,666.80 2006 $925,57733 2007 $684,924.98 20083 $30,680.65 2 Throughout this report and in all cases avoid demand values are reported at the site and are NOT groed-up for generation thereby taking into accuntT&D losses. 2008 Idaho Irrgation Loa Control Program-Final Reporl Page 2 Table Four provides information on 2008 Program costs as well as prior year costs for comparative purposes (Note: Program costs for both Schedule Forward and Dispatch initiatives are included in Table Four). Separate program costs used in determining cost-effectiveness are delineated in each of the 'Cost-effectiveness' sections of the report. During 2008 100% of the sites that participated in the Scheduled Forward Program during 2007 were visited to inspect equipment and to identify and ultimately change-out faulty timers. For 2008 field expenses more than doubled due to (1) the use of new 2-wayequipment; (2) field labor costs to assist growers on training and market transformation issues related to the use of remote control equipment and (3) program participation (as measured by MWavoided) more than doubled. Table Four Comparative Load Control Program Costs 2003, 2004 & 2005 2003 Costs 2004 Costs 2005 Costs Cost Category (April '03-8ept '03) Oct '03-Sept '04 Oct '04-ept '05 .....A~.~inis!'~y.~..~u.pp~!!_......._...._..._.......___J9,613.43_.......... ......................~!~ee?:.?e............................................~~?~.:.~ .....t.r~~r~r!!.~y.~luat.ion $2, 13~~~...............___...J;369.88.......................................J.~ß?9.:QQ._............. Fie.I.~.L.§9.~i.P !.~~..~.~~i.~.:..~~P~~~~.~.............__$~§9.~??:e.a. $239,eQ!~Q~_......._._.......~.~?~~~.......... ....P..~n!~ip~t!~.~..~r.~~.it.~................................................................. ....~.??!.!.!.e.~:!..?__......_.._~.~.Q!~~.49_____.......~~42,666.80 .................. .....p.~~r~'!..~~.~.~~~.~~.~t......................................................~.1.Q!.ee.?:.ee.__...._......._........~??.!Q~~_.__.._..4,8~~.:.e~...__..._.. R~p~nin~.............................................................................~~.S!.:e.._........................ ........~.~..!940.0Q__.__...._--Q:.~Q............... ......................................... ........!~t~t...p.r~wam c.9..t~....................~?.SQ!.eQQ:.~~........ $?~!.! 143:.e~___..............$1 ,226!~?~:Q~............... Note: 2003 costs over 6 month period; subsequent Program-year costs are calculate over a 12 month period Table Four (cont) Comparative Load Control Program Costs 2006, 2007 & 2008 2008 Costs Oct '07-Sept '08 $1,640.50......................__.__.................. ...t.~r~'....~y..~I.~.~t!~.~........................................................._............11..~.??:99.__.._...~~!.?e~..?__.........._.._!2,268.??_... .....i.!.~I.~..L.§9.~.ip....~~..~~.~i.~:.~xpenses..........~~~Q!.~Q.?:.Q?..__...............J?.~7 ,664~~.__........ $2,8!.6!~~e.:.?e...___ ..£.~.ni.~ip~tig~...~r.~~!t~...... ..............~e?s!.s!.?.:.~~...........~.~.Z.s~e.~Q.:~.?.......J?..!.ee~!.ae~.:.s!................_. J'r9.~r~'....~~~.~~~'.e.~t ...............................................~.?!.s~.:.~?.......................................sa9.!.!~:.Q.9...........................................~e~!.Q?.~..:.e~..................... _~e.p.g.n!~~.__.................._._____........... ....................J9.:~.......................... ......................$Q:Q.Q.......................................................~QgQ...................... .......___............!~t~!.f'~9ra'...9.9.~t~_........J.!200,253.83.......................... $2,584!?Q~.:Q.?.............................~~.!.eQ~.~?.~.?.:?.e...................... 2006 Costs 2007 Costs Cost Category Oc 'OS-Sept '06 Oct 'OS-Sept '06 .....A~'.~~.i.~t.r.~t!y.e su.P~rt............................................___._!!e!eQ_._.--~!.?QQ.:QQ...........__ Table Five provides avoided kW statistics and participation site counts for the Scheduled Forward initiative based on participation option. A couple of observations are noteworthy: First, the load control service credit in the Dispatch 3 Includes creits for 2008 Scheduled Forwrd proram partcipants only. 2008 Idaho Irrgation Loa Control Proram-Final Reporl Page 3 option (Schedule 72A) is nearly three times that of the Schedule Forward (Schedule 72) option. Second, the Dispatch Option is approximately % the hours of the Scheduled Forward option. These two factors were key program components that reduced grower participation in the Schedule Forward option. Table Five Program Impacts by Participation Option June July Aug. Sept Site Avoided Avoided Avoided AvoidedPartcipaton Option Cnt kW kW kW kW ...................................9pti9.I.r,~?:S..............A~............___._._...Jt?!!s.~S._--34.L._..._...__._....11466.5........___1376.0 .................9ptiQ.n...i...!Jn...?:S.............. 33 .........._.._..~3.§.:s.....___J!140:S__.___-- ,057.5 ...__..____ 1 ,08~_ ..............................pti.2n...I.i.r,..~..~=L.....?....__...................._............~9..:9...._____.__....._._.....?~:.?.._...______..14:Q.....___JÆ.:S.._ .................QptiQn..Ii.r,..~.A=!........................9......._....9..:9..____.._..___.......9:9..._...________9._~Q...._____._.9:9... ...Qpt.iQn.I.i.tth..~:§........................9................. .......9.~Q_._ . ..........9:9...__________....9.:.9.._.___.__._..........9..:9.... _._........................9pt.iQ.n...i.l..tn...E...~...............................................?.1.9...._...._.................................?9.:.?...___..__._........9..,9.....___..._._..........?.1.9....... _._.__._..pti.2n...I.i.r,J..~J.h...~:§._3.............................................J..4.~.:p.......................................J.4.p.:.?..___.....__._._._J.?.1.:...____.........._.........Ze.:.s..... _.._.Qpti.Qn..I.i.Jri..t~jn..A=L.._............._A.._..............................J..4.?.:.s......................................~4.!.p...___.........._....J..4.M.______._.._.._....J.3._e.~s...... ..._._..9pJiQ_~l.\L.r..?:S........_.._....._.L..__............................??e.:.s...................................?~9.:.Q._._..............??.e.§..._....._......................???.:..... Option IV w 2-8 0 0.0 0.0 0.0 0.0 Totals 87 2,794.5 3,148.0 3,032.0 2,938.0 Note: data reported as of 6 November 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 2008 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 1,515.0 1,688.5 1,868.5 1,868.5 1,695.0 1,515.0 JULY Monday Avoided kW by Hour Hour 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59 Avoided kW 1,664.5 1,839.5 2,018.5 2,018.5 1,843.5 1,664.5 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 1,693.0 1,828.0 2,006.0 2,006.0 1,871.0 1,693.0 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 1,604.0 1,698.0 1,866.0 1,866.0 1,720 1,604.0 2008 Idaho Irrgation Load Control Program-Final Report Page 4 Table Seven 2008 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 936.5 1,080.0 1,281.0 1,281.0 1,137.5 936.5 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 1,140.5 1,286.0 1,485.5 1,485.5 1,340.0 1,140.5 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 1,057.5 1,178.5 1,356.5 1,356.5 1,235.5 1,057.5 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 1,082.5 1,162.0 1,351.0 1,351.0 1,271.5 1,082.5 Table Eight 2008 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-:59 7:00-7:59 AvoidedkW 1,285.5 1,459.0 1,639.0 1,639.0 1,465.5 1,285.5 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 1,434.5 1,609.5 1,788.5 1,788.5 1,613.5 1,434.5 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 1,466.5 1,601.5 1,779.5 1,779.5 1,644.5 1,466.5 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 1,376.0 1,470.0 1,638.0 1,638.0 1,544.0 1,376.0 2008 Idaho Irrgation Load Control Program-Final Report Page 5 Table Nine 2008 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 936.5 1,080.0 1,281.0 1,281.0 1,137.5 936.5 JULY Thursday Avoided kW by Hour Hour 2:00-2:59 3:00-3:59 4:00-:59 5:00-5:59 6:00-6:59 7:00-7:59 Avoided kW 1,140.5 1,286.0 1,485.5 1,485.5 1,340.0 1,140.5 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 1,057.5 1,178.5 1,356.5 1,356.5 1,235.5 1,057.5 SEPTEMBER Thursay 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 1,082.5 1,162.0 1,351.0 1,351.0 1,271.5 1,082.5 Cost.effeciveness analyses Cost-effectiveness wil be 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) Utilty; (3) Ratepayer and (4) Participant wil be provided for each of the three aforementioned program cases. The tests for Schedule 72 (Scheduled Forward option) wil be based upon the cost and avoided MW values as defined in Table Ten below'. The information below will descnbe 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 vanous benefit/cost tests5. The benefits (avoided costs) are based on the calculations as defined by the Company's IRP organization and presented to the Idaho Public Utilties Commission, and the Idaho Irngation Pumpers' Association in a report titled Proposed Valuation Methodology for the Idaho Irrgation 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 charactenstics. From an analytic perspective it is clear that the Dispatch initiative is 4 To the extent possible, certin cost categories have been allocte by th repeve Schedule initiatie. S Note that no discounting of costs or benefit was require in this analysis since all cots and benefits occurrd in 2008. 2008 Idaho Irrgation Loa Control Proram-Final Report Page 6 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 2008 Benefit I Cost Categories & Values-Schedule 72 Cost Categories Administrative support Program evaluation Field I Equip I Db admin. expenses Participation credits Program management Cost Values Benefit Category $24.45 $/kW-yr avoided $33.81 $41,973.45 $30.680.65 $1,401.68 $74.114.04 Benefit Value $59.43 Total Costs used in these calculations include administrative costs, contractor costs (field technician and database design I 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 partcipants. 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 $59.43/kW-yr is increased by 10.39% to account for the effect of T&D line losses, resulting in a value of $66.321kW-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 Utilty 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 'NIA' in Table Eleven. 2008 Idaho Irrgation Loa Control Proram-Final Report Page? Table Eleven 2008 Schedule 72 Cost-effectiveness Analyses Test Benefits Costs Net Benefit BenefiCost Ratio .............................TR~_...... ......lae".QQa,4L__ $43,!3..~:~_._............_!Sl!S.?S.:g......... .............................?,?.1...._...................... .................................y!i.li.~~....................see.'.QQS,.:.4§l_...____._E4!~.14.04 ___. $21 &e4:!S_.....__._...................J&Q...._.____........ ...................~~~:~~~:.r.........................see.,.QQa,.4~L..._.._.__E4,1) 4.04 __..?M.e4.,4.S............__..................J..,~9._.__.... Parti~!~~~.~.. ....s~9.,.eS,Q.:.es............................................$..OO_..___~aQ&SO.65_.._._____.._._..._____~~_......... Measurement & Verification (M&V) processes Although the new M2M equipment provides log files that can authoritatively determine issues of grower fraud andlor tampering with the control equipment the Irrigation Management Team decided that for the 2008 season it would be important to provide additional M&V field technician site visits. This was done as much for customer services purposes as it was for M&V. There was considerable confusion among growers and there was concern among the Irrigation Management Team that growers would become disgruntled I frustrated or worse. The Irrigation Management Team knew from previous years that it would be important to eliminate problems before they became such. 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 I concerns regarding the new, remote control equipment. (Intentionally blank) 2008 Idaho Irrgatin Load Control Proram-Final Report Page 8 2008 Schedule 72A (Dispatch) Results In 2007 RMP implemented a pilot test of a dispatch solution. As a function of the succss of this initiative RMP requested and subsequently received permission for a full scale roll-out of the Dispatch Program for the 2008 program year. The results of the 2008 Dispatch Program are described below. Background A total of 530 distinct customers (1,491 sites) participated in the full-scale Dispatch initiative using the proprietary (cellular I RF) M2M pump I pivot control technology. Based on 2007 program success, accompanying word-of-mouth marketing and the standard annual mailing describing the Dispatch Program operating parameters and potential credits only minor efforts were required to gain grower participation. The principle sellng features behind the Dispatch Program were: (1) at 52 hours per irrigation season the dispatch program is less than % the Schedule Forward operating hours of 168 per season and (2) the participation credit for the dispatch program is close to three times that of the Schedule Forward initiative. Grower acceptance and succss of the 2007 Dispatch initiative created a situation where very little, if any, marketing investment was required. Customer Credits The total Dispatch Program load control service credits paid for 2008 totaled $5,972,757.30. This credit was calculated as specified in Schedule 72A and in keeping with the terms and conditions of the Stipulation Agreement (Case PAC-E-07-05) the Company entered into with the Idaho Irrigation Pumpers' Association and approved by the Idaho Public Utilities Commission. Since Program participation was )175MW the base credit was $28.00 per kW-yr. In addition the valuation model generated a value greater than $35.00 per kW- yr so an additional credit of $2.00 per kW-yr was added providing the Dispatch Program participants a credit of $30.00 per kWavoided. Customer Opt-Outs Schedule 72A permits growers to 'opt-out' of five Dispatch Events throughout the Irrigation Season. Each of these opt-out events incurred a cost resulting in a reduction to the customer's Load Control Service Credit. The cost to opt-out is the price ($/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. A softare system was developed to identify and track grower opt-outs. During the year there were technical issues with the equipment's Operating System (OS) causing the field technician's attention to be diverted from training to addressing OS issues. Therefore growers were not fully trained with the equipment or the consequences of their behavior. 2008 Idaho Irrgation Load Control Proram-Final Reporl Page 9 For example, during Dispatch Events farm help would notice the pump I pivot was not operating. Thinking something was wrong they would often restart the pump and in so doing override the Dispatch Event. This data was recorded in the control equipment log files. The Irrigation Management Team felt it was neither prudent nor appropriate to hold growers accountable for unintentional opting-out of Dispatch Events. Instead field technicians used this data to further instruct growers on the impact of their behavior. For the most part 2008 participation credit opt-out considerations were consistently and liberally interpreted with a bias that favored growers. Situations where it was clear that a grower's intentions were to opt-out were managed consistently with the terms and conditions of the tariff with respect to partcipation credits being adjusted based on per event liquidated damage charges. Dispatch Date 18-Jun 30-Jun 16-Jul 17-Jul 21-Jul 25-Jul 28-Jul 29-Jul 11-Aug 20-Aug 25-Aug Totals Table Twelve Opt-outs by Dispatch Event Count of Opt- Outs 7 20 21 13 19 18 20 24 21 19 6 188 Liquidated Damages $261.11 $1,183.45 $794.28 $488.18 $932.08 $807.71 $1,058.68 $1,651.09 $883.00 $838.09 $112.28 $9,009.95 kW not avoided 456.5 2,258.5 1,817.5 1,196.5 2333 2,092.5 2,908.5 4697 2,671.5 2910 324.5 23,666 Dispatch Events The Company has, based on historical precedence and meteorological considerations determined there would likely be 40 hours or 0.5% of the available annual hours a class 1 resource (such as irrigation load control) would likely operate6. At the beginning of the season the Irrigation Management Team identified 44 hours of the tariff available 52 hours for dispatching by PacifiCorp's Commercial and Trading Organization. The remaining eight hours were reserved for system emergencies (GRID-1 defined). Each of the 11 Dispatch Events called were four hours in duration resulting in a total of 44 dispatch hours (reference Table Thirteen) spread over three months. The load avoided by the Dispatch Events is also captured in Table Thirteen. Table Fourteen captures net kW avoided for each Dispatch Event as opt-outs are netted from Table Thirteen calculations. Table Eighteen captures both Dispatch and Schedule Forward loads. Combined impacts are further discussed in the next section 2008 Schedule 72 & Schedule 72A Results. 6 The 40-hours of dispatch are consistent wit what other electc utilites report I anticipate based on reuireents for pek avoidance. 2008 Idaho Irrgation Load Control Proram-Final Report Page 10 Table Thirteen 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 .......................J........__l 8-J'!~::ß.........Wednes~_.._.__........................_.....QJl___J.e?.!~a.e..............1.el!e.9.a:e......Je.?.,.ee.s:.e.............1.e?.,9.9.a:.9..............................Q.,9.... .........................?......._.......~Q~!!n::a......Monq~......................._.............__..QJ_1..g!!e§.:~.............t~.,e.9.s,e............1.gee.S:.e.............1.e?,.9.ea:.e.........................Q.:9..... .........................~.........._.......1.a-J.~.l:Qa.........YYeQ.'le~.9..?Y...............__~__......_......L1.!.?QaJ.............?J..1..!.?Q.sJ.............?1..1.,lQSJ.......?.1..t.,?.QsJ...... ........................A..............J.?~~I::a..I~.~!.~q?y.............................____.....9"'L.. 211 ,208.1 211.,.?.Q§J..........?.~1.i..QsJ..............?.t.1..i.9.8..t...........................Q.:9.. .........?.....................?..1.:.~.~.I::a..........~gn.9.?Y......_...._.................:Q............211 ,208.1 211.,.?QSJ.............?1.tlQ.s:J...........?..1J.!?08.1 ..................................Q.,9..... ......................ß......................??~.~.I::a..........n.9?y....................?1.J.,.?Q?-:..1.............lJ..8.1._...?.H!.?.9~L..1 ,20a..1.........__ O.O................................Q.:9.... ............................................?.S~.~.Hi.S............M2n9?Y...............................?1...1i.?Q?-:..1..............?J..1.!?.QaJ......?..1..1 ,208:.L.._~J,.?Q§J__.....................................................Q,Q..... _.__8_..............?9.~.~l.:QS...........I~.e~9?Y.............?1.J.,?9SJ...?1J.!.?QSJ.............?.1...1 ,208..1._?11..!?9~__.....Q.,Q................_............Q.:9.... ___............1..1..:~~..:QS._.....M2.n.9?Y......................... ..........9:........?Q?!.5.4.?,.9.............?9.?l?.4.LQ.............?Q.?!.MZJ9.?.!5.4.?.,.Q........__...........:9_. .._........J!L.....?9:A.l!~'NeQ!1.e~9?Y............................?Q.?&~.?:.Q..........?Q?!.5.4.?:9............?9.?!.~?..:9..........?9?,.M?:tl....._.......................Q.:9 0.0 11 25-Aug-D8 Monday 202,547.0 202,547.0 202,547.0 202,547.0 0.0 0.0 Mean 'Dispatch Event' Avoided kW x hr. 94,428.9 186,334.5 205,535.2 205,535.2 111,106.3 19,200.7 Median 'Dispatch Event' Avoided kW x hr. 0.0 202,547.0 211,208.1 211,208.1 192,998.9 0.0 Table Fourteen 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 ....__J.a-J!!n::a...........Wedn~~q?y.................................. 0.0 1..e?!.5.4.?,4............1e.?,5.4.?:4.....J..9.?.!.~?.:.........J.e.?,.5.4.?..:.4...................................Q.:Q...... .........................?....JQ~.\!n::a..M2nq?.Y..............................._...._..&........e..1~.t4._ 190,?4.9A............1..9.QZ49.A.........1eQ,?49:.4....................................9.:Q...... ........................?...................J..a~.~.I::a...........lNeQ!1.e~Q?y.........._..........._..9:.9..............._.._ 0.0 20e.!~aQ.:p............?.9e.!3..e...:e............?.Qe,~eQ.:§..........?99.!.?.9.9.&.... ........A................J..:~.~.I::a.........I~.~.~Q.?Y.................................................9:.9..?1 0, 01..&..........?1..9..&1.1._...? 1 0 ,011.&......... 21Qi011. 6 _.........................Q.:9..... .._.._......_.?....................?.1..~.~.I:9.a..........M2.n.9.?.y..............................................................9:.9.......?QM1?.:.1......_.?.Qs.&?. 208,875.1. 208,875.1 .................................,9... __.ß..................?p.~~.I:Qa...f..n.Q?Y...........................?Q.9.!.1..1?&...........?Q9..!lJp.&...?.Q~,115.6 .....99, 1J.5................._Q:..................._.............Q:9... _...........?§~!J..::ß....._M2.n9.?Y.............................................?9S,.?ea:.a...........?9.a,?9.9.&........?.Q?-,.?e,9.,.e......._?QS!.?~eL........._..............9.,.Q...... 0.0 _.._L.....?9.~.YJ.~Qa__I~.e~Q?Y...........................................?9M1.J.:.1..............?9.MJJ.J..........?QMJJJ............?Q.M~..1................................~.9......__.. 9..........1.J:~\!g::lL....._M2.n.Q?Y..............__....................9:.9.........J..9.e&??:?..........1..e.9.,ß.?.5.:.5........J..eM.?5.,S..........1.ee&??.:.5.......___....9.. _...............?Q:~..~g.:QlL_lNeQ.n.e~9..?l._..._........1.e.9.,e~.?:.9...J9.9.,e.~?:9............1e.9.,p.??:.9.....J.9.9.!.e.~?:..9................................9:..._..._...........9,9..... 11 25-Aug-D8 Monday 202,222.5 202,222.5 202,222.5 202,222.5 0.0 0.0 Mean 'Dispatch Event' Avoided kW x hr. 93,253.3 184,348.3 203,383.8 203,383.8 110,130.5 19,035.5 Median 'Dispatch Event' Avoided kW x hr. 0.0 202,222.5 206,511.1 206,511.1 190,740.4 0.0 2008 Idaho Irrgation Loa Contrl Proram-Final Reporl Page 11 Cost.efectiveness 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 Fifteen below? 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 partcipating 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 Irrgation Load Control 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/W-yr. Table Fifteen 2008 Benefit I Cost Categories & Values-Schedule 72A Cost Categories Administrative support Program evaluation Field I Equip I Db admin. expenses Participation credits Program management Cost Values Benefi Category $1,616.05 $/kW-yr avoided $2,234.94 $2,774,412.81 $5,972,757.30 $92,650.00 $8.843.671.10 Benefit Value $59.43 Total As shown in Table Sixteen, Schedule 72A passes the TRC, Utility and Ratepayer Tests. The Program also passes the Participant Test. However, since the partcipant incurs no costs the benefit/cost ratio would be infinite. Accrdingly for the Participant Test the value is indicated as 'NIA' in the Benefit/Cost Ratio column. Table Sixteen 2008 Cost-effectiveness Analyses Tes Benefits Costs Net Benefits Beneft/Cost Ratio ....._._.____T~~ ........HM~8,558.2e..................$?"a!Q!e.~..?:.e9. ..1~.9,.eJ..?.,.!3.Aa.................. ........................4.9......................_..... ._.._._.........~!ili.i.~_~JMee.!.S,Ss~.?e.._...........~!843,67.J.:..9.... ...............~~&!.~,ee.?:..a......................................1.5.~.......................... ..................~~i.~.P~~~~ ......1~.~.,.~ee..sa:?8 $8,843,67.-1:!.._ ......J~'64.~,.ee.? ..1.e........................................:.s~.......................... Participant ...$S"e??.?s?.J.9......_..__.._...._.._......._..$:9~,97.?.,.l§.JQ._.....____...............,!.6__...__.............. 7 Again, to the extent poible, cots have ben allocted by the repecve Schedule initative 2008 Idaho lrogation Load Control Program-Final Report Page 12 2008 Schedule 72 & Schedule 72A Results This secton of the report provides a brief quantitative summary of the two combined initiatives-Schedule 72 (Scheduled Forward) and Schedule 72A (Dispatch). Only minimum narrative wil be provided as the majority of the rationale behind these data has already been provided. Avoided demand The avoided demand by dispatch hour associated with each of the Dispatch Events is presented in Table Seventeen. The values in this table are additive. That is, they represent the combination of Scheduled Forward loads plus Dispatch initiative loads less the opt-out loads (see Table Twelve). 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 7 pm on Friday. Second, the table calculates the average (mean) as well as a median for each of the hourly loads per 'Dispatch Event'. Table Seventeen 2008 Dispatch Events & Associated Avoided kW Dispatch Hour 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59Q~ ~ ~ ~ ~ ~ ~ Dispatch Avoided Avoided Avoided Avoided Avoided AvoideEvent Date Name kW kW kW kW kW kW __..._.__L........_.1.e.:.~.~.i:.:Qa.............Y.~.ne~a.~y .............1.!.?aS,.s.. .J~4JlQ1-4__.._. ...1.~4,~~._~4, 14-e.,g_ 193,976A....................Ji-?§.s,.s..... 2 _...~9.:l.~.n:Q.e___.__.___..~l?n.a~y..._ ......._......_......_....1...1S,Q....J~?A?S~e ..........J.~?,577 .L_ie_?.S?lAJ 92,~Q~.:~......_.._._.._.....1.l.s1.S&... ...._......~.._...__._.._...._.!e:l!Jl-08_VYl:a.ne~_~.~y.__.._._._.1Alt.S.......................J..!.eQe.:.s ......?.11t1.4L.L..._.J.1..!!..1.47.6 _.._._._?j_QÆ~.:t__..?JQ&25. t.. ..............._4._........_._..._..JI:~_lJl-0.L__.!.~~.r.~a~y_...__..__.....1.!..1A.Q,.S.................?JJ.!.?~?&...............~.tMe_S:§...._._._...?.1.M.65.6._...._..J.1.1.I.~.?9.J___.-.,l4.~.. .................?._......__ ......._..?_1-Jul-08 __._....~l?_'!~_~y....._.__..__....Jß~,.s.................?J.Q!.!!4.&..........?J9-'S§?:.1..__..........?..1.Q.&1ejì._._.._.....?.1M.a?.~L-1 ,664.5_... ..................§........._ ........_ 25-Jul-08_____.._.E.r~l!______..?Q.e,JJ.s.&...............?Qe.!.1J?&...............?Qa,.1..1.?.&...........?.Qe..1..1.§;§....._._..............................9L__~.. ...................?.....................~::ui=-qe.__...._._.._~onday__...?Q.e!.ee4.,..t_..._...._?J.Q!.peJ............_....?1.Q!.?aa.?......_.....?.1.Q..?..s§&.........................t&1.?~9__..__..._._._M~.5 _ .........a._...._............ 29--!l:9.e_..._.__!.~sdaL_.__.?Q.?!e?.1ß_..__.1Q?.!.!~?..:.1......?Q?!.eeS:.1..................?Q?.,e.asJ......................J..,~Qa:s.._..........._.J.I.J_4.9.:?_._ 9.1!:~~tQe_.............._~onday______.........Jße.~,Q...._...._....~Q.1..!.!Q~.:.s.................?QJ..!.aSQ.:9..............?Q1..,aS9._:.9................?QJ.i?..s:............_......J.l.e~.3.0 .._ .....1.9................. 20-Au9.:Qa.__.._...yvedn~~.l!_...___._...?Q.1.!JQ.:t§.--QJ.J.?~s.:.s.................?Q1..!.~aS:.Q................?QJ..,~.as.:Q...................t.,§J~:Q...._.........._..J.1.4ae:-S.._ 11 25-Aug-08 Monday 203,915.5 204,050.5 204,197.0 204,197.0 1,839.5 1,693.0 Mean 'Dispatch Event' Avoided kWx hr. 95,765.1 187,813.2 207,151.6 207,150.5 112,580.1 20,536.9 Median 'Dispatch Event' Avoided kW x hr. 1,693.0 204,375.0 211,208.1 211,208.1 194,432.9 1,515.0 2008 Idaho Irration Load Contrl Proram-Final Report Page 13 Load profile data (CB.67 (Big Grassey)) Throughout the control period, Company SCADA data were collected and used in preparing impact analyses. Transmission Circuit Breaker #67 (CB-67 (Big Grassey)) aggregates four distribution substations (Hamer, Sandune, Camas and Dubois) which were known to have a significant number of Program participants. A significant portion of the partcipants in this area participated in the Dispatch (Schedule 72A) program. SCADA values were taken and logged at 60-second intervals for periods when dispatches were executed (see Table Eighteen Dispatch Events & Load Impacts (CB-67)). Virtually all of the 11 'Dispatch Events' had identical profiles although different Dispatch Events produced different absolute volumes. Each of eleven profiles are described and presented in ilustrations One thru Nine below. Table Eighteen Dispatch Events & Load Impacts (CB-67) Count of Cumulative Min Max DifferenceDispatch Day-of- Duration duration Start End Load Load (Avoided Events Date Week (hrs) (hrs.) time time (MW) (MW) Demand) _...........L.........................1?:Jun-08 .......'Jea.n.~a9.y....... 4.........................................._....._ .......J..s.~QQ.........19:00 -..~..&..........._Æ.L__.............?s~~_....._.... _.._~..__..............~Q.~~n-08..M.9na.?Y.................. 4..........ß......._......_..........1..?..:Q.Q.....19:00_J.§§....._....S.t:t.....................?4L.__ ___._;!......__._...._..Je:~.':.i.::a..._.........'Je~i.n.e~a9.y 4...................................1.?........................J..e~Q.Q...........fo:0lL___ls~.~........_~~~_.._.................?;!L.__ _..___~_....._....E:~.':.i.:.Qa................n.~rs.g.9.y. .....................................................1.§..._......................1..S.~QQ...........~~ 19.6 _..__54.0 _._._...........~.,.L._..... __li___...................?1.:~1l.i:Qa..M.9na.?.Y.................... ................?9......._...__...._..1?.:.QQ.._1~:Q~QJ._....._... 52.3 ._....;!?~~............... __....~.............................?.s:~.':.i.:Qa...........rna?y...............................~.................?4....____1.~.:.QQ... .......18:00 -.&...._.....~_......?J.~.e............ _.......?-............................?G:~':.i:.Qa.........M.9na.?Y..........................................?L..__...__~..:.tQ.Q.....l8:00 ....___.._ 46:L-.....?S~L......... _.......t...__...._........?e:Jul-08 ............I~~a.?y.....................4 ..............J?............................14:00 18:00 15.4 43.4 ....._.......?.a,.Q........_.. _......e_.._..........._..J..1.:A~9.:.Q? ......M.9na?Y..........................4..................... ....?e.._....._..............?..O'..Q.......... 9:~lLe.:~........_ 28.4 _.....1.,t............ _.J.9........................?.Q:A~9.:.Qa.............'Jeane~a9.y........................4.......................9......_...._.........l~.:.QQ.............18:00 13.7 27 .9 _.._......_.....J.4~.?......__.. _J..L....._.......?S:A~9.:.Qa....................M.9na.?.1............4....................................44............................1.~.:.QQ......18:.Q__.J..3.._..._..~6.~§._...._...............J~A_..._...._ Ilustration One (Big Grassey Transmission Load Profile June 18, 2008 (CB 67-'Big Grassey')) depicts grid impacts as a function of both Scheduled Forward (Schedule 72) and Dispatch (Schedule 72A) options. That said the real story here is the Dispatch impacts as Schedule Forward impacts are indiscemible to identify given the load plot scale. Additional noteworthy items of this plot are discussed following the presentation of Ilustration One. 2008 Idaho Irrgation Loa Control Proram-Final Report Page 14 Ilustration One Big Grassey Transmission Load Profile June 18, 2008 (CB 67-'Big Grassy') Big Grassey CB 67 (MVA) 60 15 55 50 45 40 35 :; 30:; 25 20 10 g~~~ ~e~~ ~~~~ ~~~8 ~~ ~8S~~ ~~~~~mreg ~~~8e~:~~~~ ~mreö ö ~ ~ N N M M ~. ~ ~ m ~ ~ ~ ~ ~ m ö ö ~ ~ N N M M.~ ~ m ID ~ ~ m ~ m m öö ~ ~ N N M~~~~~~~~~~~~ ~~~~~~~NN NN NNN Time (24 his.) 17.Jun 18.Jun 19.un i There are three important components ilustrated in the initial Dispatch Event depicted in Ilustration One. First, the magnitude of the impact of the Dispatch Event is approximately 38MW. Out of curiosity and because it was known that nearly all Agricultural Pump Sites (APS) in the region served by CB-67 were partcipating in the Load Control Program the Irrigation Management Team was interested in assessing the magnitude of the load drop reported by SCADA. Accordingly, the Team contacted the RMP Rexburg Engineering Services to determine what additional loads are served by the Big Grassey transmission substation and the associated four distribution substations. It was learned that non-irrigation loads served by Big Grassey amount to -12.5MW (reference embedded notes on the SCADA plot in Ilustration One). From the plot above one can see that all but -1MW can be accunted for. Second, the 'notch' noted during the first 1 Y2 hours of the dispatch event was a function of field technician error. The Irrigation Management team had not completely figured out how to operate the system and thereby ensure the systems would remotely open the circuit to the pumps. Approximately 3-MW of pump load was inadvertently opted- out of the Dispatch Event. However, by coordinating with service technicians strategically positioned in the field at the time of the Dispatch Event the Irrigation Management Team was able to identify and then remotely and electronically correct the problem through the M2M web portal. The impacted units eventually joined the Dispatch Event as noted in the plot itself. 2008 Idaho Irrgation Load Control Program-Final Report Page 15 Third, when compared to load plots from the day prior to and following the Dispatch Event the effcacy of the Event itself is impressive. The reader should also note the precipitous drop upon dispatch and the more gradual recovery when units came back on line. Soon after this load drop and re-start pattern occurred the Irrigation Management Team was contacted by Engineering Services and was told that the abrupt load drop and re-start pattm would present a problem to RMP switch gear as well as other hardware systems. Furter note that the units that returned to normal operations coincident with the conclusion of the Dispatch Event were configured with auto-restart. Those pumps that began pumping at a latter hour did so as a function of the grower manually restarting the pump. Ilustration Two Big Grassey Transmission Load Profile June 30, 2008 (CB 67-'Big Grassy') Big Grassy CB 67 (MVA) 55 50 45 40 35 30 ~:: 25 20 15 10 g ~~ ~ ~ e ~: ~ ~ ~ ~ ~~ ~ g ~ ~ ~ ~ e ~: ~ ~ ~ ~ ~ ~ re 8 ~ ~~ ~ e ~: ~ ~ ~ ~ ~ ~ ~ö ö~ ~ N N M M ~ ~ ~ ~ ~ ø ~ ~ ~ m m ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~~ Time (24 hrs.) 29-un 3G-Jun 1-Jul I Ilustration Two (Big Grassey Transmission Load Profile June 30,2008 (CB 67-'Big Grassy')) plots Big Grassy 60s SCADA data for June 30th. Here again, what is instructive in this partcular data set is the precipitous drop in load upon the initiation of the Dispatch Event. As in the 18 June plot the recovery is more gradual. again, depending on the presence I absence of grower equipment affxed with auto restart. It should be noted however that the dramatic and sudden drop in load was noted by RMP Distribution Engineering organization. Distribution Engineering contacted the Irrigation Management Team and indicated that there was need for an alternative dispatch strategy as the sudden impacts would, over time, damage transformer regulation 200Bldaho Irrgation Loa Contrl Program-Final Repotf Page 16 equipment located in the substation. The Irrigation Management Team was requested to develop alternative dispatch strategies so that both the initiation of Dispatch Events and conclusion of the Dispatch Event could be more gradual in how loads are both shed and restored. Ilustration Three Big Grassey Transmission Load Profile July 15+18,2008 (CB 67-'Big Grassy') Big Gra.ey CB 67 (MVA) 60 15 55 50 45 40 35 ~ 30 25 20 10 g ~g~~ ~ ~~~~~~ ~~reg~g~8~ ~~~~~~~~re g ~ g~8~ ~ :~~~~~~reÖÖ~~N N MM~.~~ ~~~ww ~m~~ ~~~~~~~~~ ~ ~ ~~~~ ~ ~~~~~ ~ ~~ Time (24 hrs.) 15-Jul 16-Jul 17-Jul 18-JUII Ilustration Three: (Big Grassey Transmission Load Profile July 15 + 18, 2008 (CB 67 -'Big Grassy')) plots Big Grassy SCADA data for July 15th and July 18th. As mentioned in the description for Ilustration Two there was concern noted by RMP Distribution Engineering that the precipitous drop and restart of loads could and would eventually have a negative impact on voltage regulation equipment. Accrdingly, the Irrigation Management Team developed softare techniques that would, over the space of a 20-minute time horizon, bring units into the Dispatch Event and again release units from the Dispatch Event. Although this more gradual stepping into and out of the Dispatch Events is diffcult to see these changes can and are distinctly noted when the plots are enlarged and studied in detaiL. 2008 Idaho Irrgatn Load Control Proram-Final Report Page 17 Ilustration Four Big Grassey Transmission Load Profile July 21,2008 (CB 67-'Big Grassy') Big Grasey CB 67 n/VA) 55 50 45 40 35 30 ~:; 25 20 15 10 s~~~~ ~ ~;~~~~ ~~~s ~~~~~~;~~~~~~~ s ~~~~~ ~ ;~~~~ ~~~OO~~N NMM .~~~ ~~~~ ~ ~~OO~~NNMM ~~~ m m ~~~~ m moo~~ N NM~~_~~_ ~~ ~~~~ ~~~~~ ~ ~NNNN N NN Time (24 his.) Selies1 Seiies2 Series31 Ilustration Four (Big Grassey Transmission Load Profile July 21, 2008 (CB 67-'Big Grassy')) again plots Big Grassy 60s SCADA data for July 21. In this particular plot one can more clearly identify the ever-so-slight displacement from the SCADA plot at the time of dispatch initiation and dispatch conclusion from the green horizontal line. Units were transitioned to enter into a Dispatch Event and to 'step-out of the Dispatch Event over a 20-minute window. This small but important modification was the first step in developing a Dispatch Event implementation system to protect valuable and expensive regulation equipment. Again, note the magnitude of overall displacement from the day proceeding and day preceding the Dispatch Event. The Irrigation Management Team wil be working with Distribution Engineering to develop and implement 2009 dispatch strategies that minimize impacts to the system and substation equipment. 2008 Idaho Irrgaton Loa Control Program-Final Report Page 18 Ilustration Five Big Grassey Transmission Load Profile July 25, 2008 (CB 67-'Big Grassy') Big Grassey CB 67 (MVA) 55 50 45 40 35 30 ~:: 25 20 15 10 o N~ W ~ON~WW ONvWW 0 NeWWO N~WWON .ww ON.WW 0 Nv W WON VWWo MO M OV~V~V N~N~NO MOMO. ~ v~vN~ N~NOMOMO v ~v~ vN~ N~NÖ ö~~NN M M.. ~~~ø~ ~ ~ææöö ~ ~NNMM ~.~ ~~~~~ ~ æm öö~~ NNM~~~~~~~~~~~~~ ~ ~~~~~NNNN NNN Time (24 hrs.) 24-ul 2504ul 26-UII Ilustrations Five and Six are very similar to the previous Dispatch Events with the exception that one can begin to clearly see the effcacy of distributing the stepping-into and exiting-from each of the dispatch events. 2008 Idaho Irrgation Load Control Program-Final Report Page 19 Ilustration Six Big Grassey Transmission Load Profile July 28+29,2008 (CB 67-'Big Grassy') Big Glassey CB67 (MVA) 50 45 40 35 30 ~ 25:: 20 15 10 o N~ W ~ONvIDW ONvIDW ONvIDWO N vID W ON VWW ONvIDW 0 NvIDWONvW Wo ~o M OV~ v~v N~N~NO MOMOv ~ v~vN~N~N OMOMOv ~v~vN~N~NÖ Ö~~NN M M~.~~~Ø~~ ~ææöö ~ ~NN~M ~.~ mm~~~ ~ mæöö~~NN~~~ ~ ~~~~~ ~~~ ~~~~~ ~ ~~NNNN NNN Time (24 hrs.) 1-27-JUI-28-JUI .. -._.29-ul -3D-Jull 2008 Idaho Irrgation Load Control Proram-Final Report Page 20 Ilustration Seven Big Grassey Transmission Load Profile August 11,2008 (CB 67-'Big Grassy') Big Grassey CB 67 (MVA) 34 12 32 30 28 26 24 22 20 0( 18". :; 16 14 10 o N.W ~ 0 N ~w ~ ON~ W~ 0 NvWroON vwro ONVWID ONvWro 0 NvWroONvID roo MO MOv ~ v~ vN~ N~N 0 MOMOv~v~vN~N~N OMOMO v ~v~vN~N~NÖ Ö~~NN M M~.~~ ~ ~~ ~ ~mmöö~ ~NNM M~.~ wø~~~ ø mmöö~ ~NNM~~~~~~~~~~~ ~~~~~ ~ ~~NNNNNNN Time (24 hrs) 10-Aug 11-Aug 12.Aug I Beginning on the above Illustration (Dispatch Event (August 11th)) one clearly notes the difference in the magnitude of the avoided load as a function of the Dispatch Event. On the 11 August Dispatch Event only approximately 12MW of load was avoided. What accounts for this paucity in avoided demand in this Dispatch Event and the following two Dispatch Events? To answer this question attention needs to be given to Ilustration Ten-Big Grassey Irngation Season Maximum, Minimum & Average Daily Plots. Ilustration Ten shows a large and precipitous drop in load pnor to 11 August as pumps were turned off to field crops to enable the plants to mature and ready wheat I barley for harvest. The amount of avoided load actually realized is dependent on the loads operating to begin with. Simply put, all Dispatch Events are not equal. If Dispatch Events are called pnor to the penod8 when active irrigation is discontinued on field crops then the startng point for the load drop is far greater than if the Dispatch Event is called after those loads are turned off. More on this finding is presented in the subsequent section (Irrigation season load profile). 8 Depending on the climate zone and weather pattrns loads to field crps are generally discontinued on or about 1 August. 2008 Idaho Irrgation Load Control Proram-Final Report Page 21 Ilustration Eight Big Grassey Transmission Load Profile August 20,2008 (CB 67-'Big Grassy') Big Grassey CB 67 (MVA) 30 28 26 24 22 20 18 16 ;;::14 12 10 g~~ ~~~~~ ~~~~~~ ~g ~ ~~~~~~~~~~ ~~reg ~~~~~ ~ ~~~~~ ~mreÖÖ~~NN~M ~ ~~~~~~~ m mm~~~~ ~~~ti ~~~~~~~ ~~~~~ ~~~ ~ ~~ Time (24 hrs.) 1-19-AU9 -20-Aug 21-Aug I 2008 Idaho Irrgation Load Control Proram-Final Report Page 22 Ilustration Nine Big Grassey Transmission Load Profile August 25,2008 (CB 67-'Big Grassy') Big Grassey CB 57 (MVA) 32 18 30 28 25 24 22 20 ~ 16 14 12 10 ON~ W roONeW ~ ON~W~ ON~ W ~o N~W ro ONvW ~ ONvW~O NvIDroONvID ~OMO ~ Ov~v~ v N~N~N O~OMOv~v~ vN~N~ N OM OMO v ~v~vN~N~ Noo~~ NNM M~~ ~~WID~ ~~mmcio ~~N N MM.~~ IDID~~W W mmöö~~NNM~~ ~~~~~~~~~ ~~~~~ ~ ~~NNNNNNN Time (24 hrs.) 1-24-AU9 -25-Aug 25-Aug I Irrigation season load profile The Irrigation Management Team noted the overall drop in loads throughout the irrigation season. To further understand the impact of avoided loads, 60s SCADA data were collected from 6 June9 thru 15 September 2008. Daily maximum (max), minimum (min) and average (avg) values were culled from the data sets. To avoid the plottng of spurious data10 observations only within 5% of the max and min were used for plotting purposes. The effect of this data manipulation was to ensure the plot of more representative data and to somewhat moderate excessive data anomalies created by momentary voltage fluctuations on the distribution system. In addition SCADA data was overlaid with the dates when growers in the Hamer area harvested alfalfa and field crops (wheat I barley). Each of these data along with the date of each of the eleven Dispatch Events is noted in Ilustration Ten (Big Grassey Irrigation Season Maximum Minimum & Average Daily Plots). There are a couple of very interesting observations which come from this initial data set. First, there is a clear and unequivocal load profile that closely corresponds to agri-irrgation practices. The pumping profile increases rapidly 9 Data collecon began on 6 June and not 1 June (the start of the irrgation season) because there were corrpte SCADA data sets prior to this date. 10 SCADA report all values including ouUier values. Ofen values are skewed as a function of a momentary or inaccurate reding in the data acquisition, trnsmission and retreval pro from the Remote Terminal Unit (RTUs). The aforementioned data manipulation methodology was a technique adopte to normlize for the ouUier values which, if used, would have intruce a measure of bias. 2008 Idaho Irrgation Load Contrl Program-Final Report Page 23 beginning mid-June, maintains a high profile through 23 July and then begins to taper off. Clear drops in load can be seen coincident with the 2nd cutting of alfalfa and again when water to field crops (wheat I barley) are turned off to ripen and ready those crops for harvest. The impacts of the Dispatch Events to the RMP system are significantly different depending on when the Dispatch Event is called. For instance, the average load impact for the two June Dispatch Events11 is 36.8MW. For July that value drops to 31.4MW. In August that value drops significantly to 13.3MW (reference both Ilustration Ten below and Table Nineteen). The take-away here, and as mentioned earlier, is that all Dispatch Events are not equal. Instead, and depending upon when the Dispatch Event is called, RMP can and should expect to receive a different amount of avoided load. The good news, of course, is that the peak irrigation load largely corresponds to the RMP system peak period (5 July thru 13 August) and requirement for load relief. To understand the irrigation pump load profile presented in Ilustration Ten one must also understand the effcts of meteorological considerations. Among other variables the weather pattern is the principle factor driving the decision to activate pumps. The winter and particularly the spring of 2008 were both wetter and cooler than normal. This pattern continued through May 12th. Startng on May 13th the weather pattern changed and became dry and somewhat warmer than normaL. This dry I warmer pattem continued through the 9th of June where only 0.06" of rain was recorded for nearly one full month (from 13 May to 9 June). Accrdingly, on the 10th of June growers made the decision to turn ON their pumps. This event is noted in Ilustration Ten with the rise in MW pump load. Interestingly, coincident with the growers' decsion to activate their pumps, a wet, cool weather front moved into the region from 10 June through 12 June (a 3-day period, inclusive). During this time a total of 0.06" of rain was deposited in the area. Growers again, tumed off the pumps and kept them off until soil water requirements dictated additional moisture. Additional irrigation watering began on 15 June (again, note the load profile in Ilustration Ten) and remained at the typical agricultural load profiles for the remainder of the irrigation season. 11 Again, keep in mind we are only taking into consideration the Big Grassy trnsmission substation in this analysis and corrsponding discussion. 2008 Idaho Irrgation Loa Control Proram-Final Report Page 24 Ilustration Ten Big Grassey Irrigation Season Maximum, Minimum & Average Daily Plots 60 15 55 50 45 40 35 ~ 30 25 20 10 ~ ~~ M ~ ~æ~M ~ ~ m ~ M~~ m~ M ~ ~m ~ M~~ m ~N~ ~~ ON ~ ~ ~ONvW ~ 0 ~ M~~m ~M~ø Ð~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ w w w ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ ~ m m m m ~ ~ ~ Time (day) 1-5% dbmax -5% dbmin - - - - - average I Load profile data (Total RMP Southeast Idaho unadjusted FERC load data) Ilustration Eleven (Total RMP Hourly Idaho Loads (June): Schedule 72A Idaho Irrigation Load Control-Dispatch Days vs. Non-Control Days) plots RMP's Southeast Idaho Service Territory average hourly interval load data for June. Data are segregated by dispatch (June 18th and 30th) and non-dispatch days. Data is only plotted for weekdays. The comparative June plots are somewhat disconneced as there are only two dispatch days and very litte pumping during the first half of the month as the spring season was both wetter and cooler than normaL. The impacts of the two Dispatch Events show roughly a 150MW impact to loads in southeast Idaho. An identical plot is generated for July as well as for August and presented in Ilustrations Twelve and Thirteen respectively. In Ilustration Twelve the comparison between control and non-control days are more in keeping with one another as there were a greater number of Dispatch Events, the weather and consequently pump loads more consistent throughout the month. Conversely lIustr~tion Thirteen is more similar to June. However, unlike June, August was impacted by the significant drop in irrigation loads to field crops were water was turned off to mature the crop and ready it for harvest. 2008 Idaho Irrgation Loa Control Program-Final Report Page 25 Cautionary note: When interpreting the entire southeast Idaho Service Territory average hourly interval load data keep in mind that while aggregate values provide some indication as to impacts these data should not be interpreted as being conclusive evidence for or against operational effcacy. There are a wide variety of activities impacting the electric grid other than irrigation. Moreover, Dispatch Events within a given month do not always have the same start and end times. Where appropriate, attempts wil be made to provide interpretation I rationale of the data that is presented. Ilustration Eleven Total RMP Hourly Idaho Loads (June): Idaho Irrigation Load Control-Dispatch Days vs. Non-Control Days 800 350 750 700 650 ~ 600 oJ:~:E 550 i'5 :g 500 450 400 300 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Time (24 hrs.) June Non-ctrl. Days -June Ctrf Days. . . . . All June Weekdays I 2008 Idaho Irrgation Load Control Proram-Final Report Page 26 Ilustration Twelve Total RMP Hourly Idaho Loads (July): Idaho Irrigation Load Control-Dispatch Days vs. Non-Control Days BOO 350 750 700 650 600 550 500 450 400 300 10 11 12 13 14 15 16 17 1B 19 20 21 22 23 24 Time (24 hrs.) July eirl. Days July Non.Ctrl. Days - - - . - All July Weekdays I 200Bldaho Irrgation Load Control Proram-Final Report Page 27 Ilustration Thirteen Total RMP Hourly Idaho Loads (August): Idaho Irrigation Load Control-Dispatch Days vs. Non-Control Days 600 350 550 500 ~o.c~!! 450 !o., 400 300 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Time (24 hrs.) Aug Clrl Days Aug Non-Clrl Days I Ilustration Fourteen (Total RMP Hourly Idaho Loads June 18 & June 30 Dispatch Days) provides daily plots during the period of the two June Dispatch Events. On average the system records nearly 150MW of avoided demand during the dispatch period. 2008 Idaho Irrgation Load Control Program-Final Report Page 28 Ilustration Fourteen Total RMP Hourly Idaho Loads June 18 & June 30 Dispatch Days 800 750 700 650 ¡: 600 ~o-.'3 550 i'S ~ 500 450 400 350 300 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Time (24 hrs.) !-3O-Jun 18-Jun . - . . - A..rage I Ilustration Fifteen provides similar plots for individual dispatch days for the July time period. To ease some of the confusion and when interpreting these data the reader is cautioned to pay close attention to the three distinct 'Dispatch Windows' (start and end hour of the dispatch event itsein. Page 292008 Idaho Irrgation Load Control Program-Final Report Ilustration Fifteen Total RMP Hourly Idaho Loads July 16,17,21,25,28 & 29 Dispatch Days 800 750 700 650 ~ 600 ~o.c~:5 550 ! ~ 500 450 400 350 300 !-l6-UI 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Time (24 hr..) 17-Jul -21-Jul -25-Jul -28-Jul -29-Jul . . . . . average I Ilustration Sixteen provides similar plots for individual dispatch days for the August time period. Here again, when interpreting these data the reader is cautioned to pay close attention to the two distinct 'Dispatch Windows' (start and end hour of the dispatch event itsel~. Page 302008 Idaho Irrgation Load Control Proram-Final Report Ilustration Sixteen Total RMP Hourly Idaho Loads August 11, 20 & 25 Dispatch Days 600 550 500 450 ~o=..:5 400 æ ~oII 350 300 250 200 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Time (24 hrs.) 11-Aug 25-Aug 20-Aug . . . .. avg ct~ days I Ilustrations Seventeen, Eighteen and Nineteen plot hourly data for all weekdays within the three respective irrigation months-June, July and August. A second regression accmpanies each of these plots estimating what the peak load would likely have been were it not for the Irrigation Load Control Program. Again, keep in mind two facts: (1) data is aggregate hourly FERC values for RMP's southeast Idaho service territory. Accrdingly, there are a variety of other residential, commercial and industrial loads that are operating simultaneously with irrigation. (2) Estimated values are just that, an estimate. The estimate plot was generated by a 5th order polynomial to approximate the anticipated slope of the avoided load. 2008 Idaho lrogation Loa Control Proram-Final Report Page 31 Ilustration Seventeen Total RMP Hourly Idaho Loads June Estimated Impact to Peak 820 800 580 580 ~ 540oi = .! 520;;o., 500 480 480 440 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Time (24 hr..) june Estimate. . - Poly. (Estimata) I Page 322008 Idaho Irrgation Load Control Proram-Final Report Ilustration Eighteen Total RMP Hourly Idaho Loads July Estimated Impact to Peak 740 720 700 680 ! ~~:! 660 IoII 640 620 600 580 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Time (24 hrs.) july Serie52. . - Poly. (Seri52) I Page 332008 Idaho Irrgation Load Control Proram-Final Report Ilustration Nineteen Total RMP Hourly Idaho Loads August Estimated Impact to Peak 540 520 530 510 ;: 500 æ5 ~~:E 490 ! ~ 480 470 460 450 440 10 11 12 13 14 15 16 17 16 19 20 21 22 23 24 TIme (24 hrs.) aug Series2 - - - Poly. (Series2) I Cost.effectiveness analyses Cost-effectiveness calculations were prepared for each of the four standard utilty 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 72A upon which calculations are prepared are presented in Table Nineteen below12. 12 All proram costs (both Scheduled Forward and Dispatch proram components) have ben include in this table. 2008 Idaho IrrgaUon Load Control Program-Final Report Page 34 Table Nineteen 2008 Benefit I Cost Categories & Values-Schedules 72 & 72A Cost Categories Administrative support Program evaluation Field I Equip I Db admin. expenses Participation credits Program management Cost Values $1,640.50 $2,268.75 $2,816,386.26 $6,003,437.95 $94,051.68 $8 917 78514 Benefit Category $/kW-yr avoided Benefi Value $59.43 Total All-in $/kW program costs13 $41.60 Total kW 214,356.1 · . Total max load for July As shown in Table Twenty, the combined initiatives (Schedule 72 + Schedule 72A) pass the TRC, Utilty and Ratepayer Tests. The Program also passes the Partcipant Test. However, since the participant incurs no costs the benefit/cost ratio would be infinite. Accrdingly and for the Participant Test the value is indicated as 'NIA' in the Benefit/Cost Ratio column. Table Twenty 2008 Cost-effectiveness Analyses Tes Benefi Cost Net Benefits BenefiCost Ratio _.__..._......!..~~...._l1M~a!.~J?:.e?...._ $2,914,~~?Je..__..J1 0,67S,se.s,n.. .......4:.ee__....... ~!.ili!¥..._.11~.,.S~e.!.el?:.e?_._s.~,~J?.,.?.~.5.14 $4&?_?!.l.??:.?.s....__........._..__...... .........~~!~p.~¥.~~.....~.1.~,See.!.e1?:e?._.."...S§!.e.1LZa5.14 _._._S'4Æ.?1127.78 ..___._~....__..__........_... ................~.~~.i~ip.~.~!.............le,.QQ~.,.4~?.:.eS..............................................19~.QQ__.........S,e"QM.?I~L._............___.NL~......................._ Conclusions & Recommendations The 2008 Dispatch initiative was positively received by the growers as indicated by participating volumes. The Schedule Forward initiative waned significantly since the Dispatch initiative was made available to the larger grower population. There was no indication from growers that either row or field crops were adversely affected either by quality or yield impacts to those participating in the Dispatch Program. Key to program success is maintaining a local presence of agri-irrigation I information systems specialists and irrigation equipment specialists to ensure the initiative's success. If nothing else, the Dispatch initiative is about market transformation to an emerging agri- business irrigation practice of remote control of irrigation equipment. That said, there has been and remains a variety of interesting technical issues and operational considerations that require additional attentions as the network and network operations are improved over time. 13 This is a rudimentary calculation simply performed by dividing all proram cots by the monthly max (July) avoided demand. 2008 Idaho Irrgation Loa Control Program-Final Report Page 35 First, it wil take time before farm managers and growers alike become fully comfortable with the remote control irrigation management systems to meet the demands of the dispatch schedule. Providing skilled, local and professional resources on a 7 x 24 basis to train, council, instruct and lor troubleshoot problems as they presented themselves was and is vital to program success. Growers appear to be favorably disposed to a long-term partnership with RMP. Nearly all growers point to this partnership and commitment to technology innovation as an important underpinning to program succss. Second, during the 2008 season inroads were made to gain partcipation among surface water irrigation systems. There were four canal companies that participated in the Dispatch initiative. Working with each of the irrigation system board members and the respective water masters, RMP was able to develop modeling techniques that permitted growers served by these systems to partcipate without the threat of canal levies being overrun during times of dispatch. While it is too early to claim victory for the modeling process there was considerable succss that can be built upon for the 2009 irrigation season. Third, the Irrigation Load Control program requires year-round attention and effort. Substantial efforts must be given during the 2009 season to further develop procsses, systems and procedures to ensure system robustness, data accuracy and operational integrity. The dispatch process itself must be more closely integrated with system requirements and business rules for dispatch. A number of growers expressed confusion as to the rationale for the callng of Dispatch Events. Clearly the Irrigation Management Team must find ways to communicate and more closely integrate growers and the RMP Commercial & Trading organization so that mis-understandings and missed expectations are minimized. Fourth, implementing and managing a resource :-200 MW over a diverse geographical area, unique grower requirements and irrigation systems requires an ERP-like system. The embodiment of that requirement is largely captured by the Program's CreditRider system. There are two additional systems, however, that tie into CreditRider-the PacifiCorp CSS system and the M2M Communications web portal. Together all three of these platforms are required. The customer largely interfaces with the M2M web portal while back offce personnel interface principally with CreditRider and to a lesser extent CSS. Field technicians interface with both the M2M web portl and CreditRider. Further back offce developments wil be implemented in 2009. It is important that enhancements to the CreditRider system be done off-season otherwise the Irrigation Management Team jeopardize the in-season use and integrity of the system. Fift, it is both instructive and important to note that field technicians are not your standard ag-electrician. They must, of necessity, have digital capabilities that can handle the interface between standard pivot I pump panel electrical components and firmware located in the M2M control unit itself and on the web port as well as in CreditRider. Moreover, when problems arise, it is not always clear whether it is an (1) irrigation equipment problem, (2) power quality problem, (3) operator error or a (4) load control device problem. Accordingly, customer service cannot be handled by a remote call center operation. The Irrigation Management Team has made a considerable commitment to the development of field electricians. That investment has been reciprocated by way of market development, troubleshooting and commitment to customer service. The Irrigation Management Team has urged field technicians to work closely with the growers' electricians and, where possible, to gain the involvement of those electricians in the installation and troubleshooting of the equipment. Knowledgeable growers and I or their electricians are and wil increasingly become an important extension of the Irrigation Management Team. As 2008 Idaho Irrgatfon Loa Contrl Proram-Final Report Page 36 mentioned previously, this program is more about gaining grower buy-in and commitment to the technology and process than simply a contractual exchange between the grower and RMP. Sixth, operational practices under a Dispatch Program are radically different than under a Scheduled Forward offering. Under the Dispatch Program RMP has an on-going, daily interaction with the grower. For their part the grower must relinquish their exclusive control of their irrgation equipment and share with RMP. That is a tall order given the size of the participation credit in light of the potential revenue in a single circle. Moreover, coordination between different parties can, at times, be confusing. The process can be further complicated because irrigation practices are often implemented by those with only marginal English skils andlor technical backgrounds. There has been and can be missed or poor communications that are often the function of capabilities or training. For instance, many growers wil leave their pump I pivot panel switch in the ON position and elect to control their irrigation turns via their disconnect switch. This practice works in certain irrigation equipment configurations. However, this practice often introduces a significant measure of confusion among growers, farm managers, field technicians and the Irrigation Management Team in the management of Dispatch Events and the issuance of participation credits. The Irrigation Management Team has much to do by way of improving operational practices in this area. Seven, to-date the program has been evolving with significant internal company support. As the program transitions from build to a maturity there may result in slightly higher operational costs. Near-term operation of the Irrigation Load Control Program wil entail more hours for management, and additional outside resources for troubleshooting, training and field-based customer service. Consequently, RMP expects to cautiously increase delivery expenses. Anticipated expense increases will come from year-round staffng to meet work load requirements, grower training along with the management of a significantly larger network. Providing program solutions without risk to the grower and RMP are, at best, diffcult. For example there is always the risk of crop I equipment damage, customer complaints and associated litigation and fraud. Other potential problems include misuse of load control equipment, miscalculation of customer credits, and miscommunication with growers regarding Dispatch Events as well as other customer service related problems. To prevent these problems and mitigate exposures, resources wil have to expended to address them. The Irrigation Management Team wil, continue to deliver a cost effective and sound program, with the continued and full support of RMP. While program maturity wil be increasing over the next several years RMP expects and is fully prepared to judiciously maneuver through the often not-so-clear complex operational changes to meet the challenges. RMP also expects that changes may also be reflected in tariff considerations. As tariff-related issues arise RMP wil bring them forward to the Commission for consideration. 2008 Idaho Irration Load Contrl Proram-Final Report Page 37