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Home My WebLink About20071220Report for 2007.pdf.. ~~~OUNTAIN RECEI 20010EC i 9 AM 4: 29 201 South Main, Suite 2300 Salt Lake City, Utah- 84111 December 19, 2007 IDAriO PUBUC UTILITIES COMMISSIOi, Idao Public Utilities Commission 472 West W i;higtn Boise, ID 83702-5983 Attention:Jean D. Jewell Commssion Secret Re:Irrgation Lo Contol 2007 Reort Includig Dispatch Pilot Progr Case No. PAC-E-06-12 Rocky Moun Power, a division of PacifiCorp, hereby submits for filing its reprt deting the operation of the Irrgation Load Contl Creit Rider Progr including the operationa results of the 2007 dispatchable pilot progr. Ths report is provided in compliance with Order No. 30243 issued in the above reerenced cae. The Company recommends continuing the dispatchable progra as a demad side magement prog offering in its Idao servce terrtory. An ageement with regards to contiued progr operation and the level of incentives was rehed with the Idao Irgation Pupers Association as pa of the Company's 2007 genera rate cae and was submitted to the Commission for approva in Case No. PAC-E-07-05. Revised taff wil be submitted in compliace with the Commission's order in tht cae once it is issued. It is respectlly requested tht all form correspondence and Sta reques regarding ths material be addressed to: Bye-mal (preferred):dataequestpacifcorp.com By regular mal:Data Request Response Center PacifiCorp 825 NE Multnoma Suite 2000 Portand, Oregon 97232 By fa:(503) 813-6060 Any inform inquiries may also be dieced to Brian Dickm Idao Regulatory Af Maner, at 801-220-4975. Sincerely,~t.~/P! Jeffey K. Larsen Vice Presiden, Regulaon Enclosures L. A DIVISION OF PACIFICORP Schedule 72 & 72A Idaho Irrigation Load Control Programs 2007 Credit Rider Initiative Final Report 18 December 2007 l Table of Contents Page Report Organization ........... ..... .................................... ................................ .................... .... ...................... .... .................... 1 Background .............. .......... ........................ ............................... ........ .... .............................. .... ........ ...... ...... ...................... 1 2007 Schedule 72 (Scheduled Forward) Results.............................................................................................................. 1 Cost-effectiveness analyses....................................................................................................................... ..................7 Measurement & Verification (M& V) processes ...................... ........................ .............. .......................... .......................8 2007 Schedule 72A (Dispatchable) Results....................................................................................................................10 Background.................................................................................................................... ............................................. 10 Tanff highlights....................................................................;.......................................................................................11 Installation schedule...................................................................................................................... ............................. 11 Customer Credits....................................................................................................................... ................................. 13 Customer Opt-Outs.....................................................................................................................................................13 2007 Dispatch Events.......................................................................................................................... ....................... 15 Customer Feedback....................................................................................................................................................16 Cost-effectiveness analyses ...............................................ò.......................................................................................19 2007 Schedule 72 & Schedule 72A Results........ ...................................... ............ ............ ............................ ..................20 Avoided demand .........................................................................................................................................................20 Crop type analysis ........ ..... .............................. ...... .............................. .......... .................. .................... .... ... ................21 Load profile data (CB-67 (Big Grassey)).....................................................................................................................22 Ilustration One Big Grassey Transmission Load Profile July 12, 2007 (CB 67 -'Big Grassy') ..................... ...... .........23 Ilustration Two Schedule 72 Idaho Irrigation Load Control-Average Daily Load Curve: Control vs. Non-Control Periods for July & August 2006 (CB 67 -'Big Grassy') ............................................................................24 Ilustration Three Big Grassey Transmission Load Profile August 13, 2007 (CB 67 _'Big Grassy') ............................. 25 Load profile data (Total Rocky Mountain Power Southeast Idaho unadjusted FERC load data) ...............................25 Ilustration Four Total PacifiCorp Hourly Idaho Loads (July): Schedule 72A Idaho Irrigation Load Control-Dispatch Days vs. Non-Control Days.................................................................................................... 26 Ilustration Five Total PacifiCorp Hourly Idaho Loads (June+July): Schedule 72 Idaho Irrigation Load Control-Scheduled Forward Days vs. Non-Control Days................. .............................. .................................... 27 Ilustration Six Total PacifiCorp Hourly Idaho Loads Comparing Schedule 72 + Schedule 72A to Non-Control Days........................................................................................................................... ........................ 28 Ilustration Seven Total PacifiCorp Hourly Idaho Loads Comparing July Total Schedule 72A (Dispatchable) to Non-Control Days ...........................................................................................................................29 Cost-effectiveness analyses ........ .......... ... .............................. ............ ............ ................ ............ ............ ....................29 Conclusions & Recommendations............................................................................................................... ................... 30 Attachment One............................................................................................................................ .................................. 33 2007 Idaho Irrgation Load Control Proram-Final Report Page 1 of41 J, 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 lnigation Load Control Program (Program). As approved by the Commission in Order No. 30243, Rocky Mountain Power initiated a dispatch able irrigation pilot program (Schedule 72A) evaluating the effcacy of a 2-way control technology unique to the irrigation industry. In addition to the standard analysis on Schedule 72, this report wil include a review of 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 will be combined and presented. Background Subsequent to 2003, reporting requirements include responses to the following: 1. The number of irrigation customers who were eligible to participate in the Program 2. The number of irrigation customers who entered into a load control Service Agreement 3. The number of irrigation customers who participated in the Program for the full three and one-half months 4. The number of irrigation customers who are not eligible to participate in the following year's Program 5. The total dollar amount of credits provided under the Program identified by month 6. Proposed changes and/or recommendations to improve the Program 2007 Schedule 72 (Scheduled Forward) Results Table One detail§ eligible 2007 Schedule 10 sites and customers (requirement #1)1. Table One also contains counts of customers and sites that entered into an actual load control contract (requirement #2). Details for Program years 2003, 2004, 2005 and 2006 are provided for companson. 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 2007, 14.8% of total available sites and 20.0% of the total available customers participated in the Program. There are zero customers NOT eligible to participate in 2007 (requirement #4). 1 Data are reportd as of 30 September 2007. This notation is importnt as Program partcipants may change throughout the season as a function of agri-business, weather, crop type andlor equipment vagaries. Wherever poible and based on what the Irrgation Management Team has determined to be the most understandable way to communicate quantitative Program demographics and impact, reportng date may change. Accrdingly, and throughout this report the date for the specifc quantitatie reult wil be noted. 2007 Idaho Irrgation Load Control Proram-Final Report Page 1 of41 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 Eligible 2007 Counts Customers NOT eligible to participate 2007 Note: based on 30 September 2007 data sets Participant Sites 401 734 1,065 931 681 4,596 N/A Participant Customers 207 340 489 478 405 2,014 o The monthly participation credit amounts issued to 2007 Program participants are presented in Table Two (requirement #5). Total Program participation credits ($684,201.09) represent a 26.1 % decrease (or -$240,652.35) over 2006 credits. This decrease in credits occurred despite the addition of $450,000 (denoted 'Supplemental Credit') divided among all 2007 Program participants. The reason for this decrease is because a significant count of growers elected to participate in the Dispatchable (Schedule 72A) pilot program. 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 and 2007 Program years. Further, it should be noted that the 2007 Program year-end report statistics are based on the Program's transactional database. The database offers a snapshot in time and does not take into consideration Program participants who may have elected to discontinue partcipation prior to 15 September. Table Two 2007 Scheduled Forward Participation Credits x Month Standard Credits kW Under Contract Total Season Supplemental Credits Total Credits (Standard + Supplemental) June $110,951.25 37,501.29 $188,287.72 $68492498 July $181,494.39 51,506.00 August $165,409.32 49,664.00 September $38,782.30 40,491.80 2007 Idaho Irrgation Load Control Program-Final Report Page 2 of 41 Table Three 2003-2007 Comparative Schedule 72 Participation Credits Issuance Year Total Partcipation Credits Issued 2003 $277,583.72 2004 $410,325.49 2005 $842,666.80 2006 $925,577.33 2007 $684,924.98 Table Four provides information on 2007 Program costs (Note: Program costs for both Schedule Forward and Dispatchable 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.). For years 2003, 2004, 2005 and 2006 Program costs are represented for comparative purposes. During 2007 100% of sites that participated in the Scheduled Forward Program during 2006 were visited to inspect equipment and identify faulty timers3. This practice of visiting ALL participating sites was initiated in 2006 in response to the lack of control equipment reliabilty. This site inspection practice had a dramatic effect on customer service as there was less than eight customer service calls (or 1.17% of total timer-installed sites)4 associated with equipment failures during 2007. For 2007 the more than doubling of costs for field expenses is due to (1) the $529k for new 2-way equipment and (2) field labor costs to remove timer units in advance of the installation of 2-way equipment and required for inventory balancing. 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 .~~r.i.~i.~.tr..~tiy~...~.~'pP'?.~. ......................~e!.?.1.~,:~~___..____.._..s~ß?~:~e..,...,......,..,...._..........................~??.J.:.~?.............."... Pro9.r~!!..~y~I.~~ti?n_.,.............".,.....,....,.........~?.!.J,~~,:~~_...,.........._,.,........,.....~?!.~.~~.?a.,._......._...._...............~.J..!.??9.:9g_._"........., ".~i~!.~J..~~l~lP..L~b adr..i~.:.~~p.~.n~~~... $250,22.?:e.?...,.,...........,....................~?.~e,80~:9~_._.._._...,.._..S326,0~~ ,~~~~cpation cred~_.......__.._.._._._..... .... ,~,?!.!.!~.?~:?? .................,..................~~.~.9!.~~?:.~e..,............ ......,.._ja~?!.?~?.~a..9"................. .....E''?~~'..~~!.~~~.i:.~~_.._...............~.J.Q!.~e?.:e_e.............,...,..,...............J~?!.9.~?:.?e...,.........,...,......,..,._J~~.!.??~:.?~......_ ......R~p.?.~i.~Q....................................................... ................................__.__ $351. 79...........,.............._...J.~..!.e.~Q.:.9.Q.........."., ..,......,....,........................~.Q:.QQ.... .........................................................TC?t.~!..E''?~~'!..9.?~~.......__.,.J~?.g!.eQ.Q:~4 $7_1..!.J..~~.:.e?................, ..,...,....J.1.!.???!.???:.9?..................,.... Note: 2003 costs over 6 month period; subsequent Program-year cots are calculated over a 12 month period 2 Includes 'standard partcipation' crdits + 'supplemental' credit for 2007 Scheduled Forward program participants only. 3 The only proram offere during 2006 was the Scheduled forward initiative 41f calculations were prepare on the total number of timers installed (not sites) the percnt of failures would be even less (likely 0:1.0%). 2007 Idaho Irrgation Loa Control Proram-Final Report Page 3 of41 Table Four (cont) Comparative Load Control Program Costs 2006 & 2007 2006 Costs 2007 Costs Cost Category Oc '05-Sept '06 Oct '05-Sept '06 ",~~,~!n,!~~~,t~y'~,~~'pp'~~"......_____............_......~.60__.._ ...._....___.J~500.9-Q._._...._ ......~r~~ré.r...~y.~.I~.~ti.~n,....................__.....__..._..................................__~!!-t,??:9.,9-.._.._....,_..__.~~!-?~a,:~_,_. "..i=!~i.~..!..~,g~i.PJ.P~...~~~.i.~: expens~~,...,..............,...E~_Q!.a.Q?:9?........,...__..__..E~..!§~~:~,_.__........_ ....,~~~i~!p~ti?.~..~r.~.~.it~......".....,..........,.....,.............,.,.........,....J???!.?.!!.~3..a.............,..._._,_.....~,~..!.!??.!.eaQ.:~!......_.,.......,._, ......~r~.~ré.r...~.~.n,~~.~~~.~!.._................................................_..........J..~?!?,?~ß.?..................,.,.......................~..a9..!,!.~:.Q9.,...................... ..,.,~~.P~~!~.~.........,....._...._.__.___.__._.............,.....,................_.....__......................~9..:9..9.................................................~9..:.99....,....,..,....., ______......_ Tot~!£ror~'..,~~~.t~___...!.a9.9~??.~.:~.a....._....__....., ......g?a~.!.?9.a:.Q..........,......,....., Table Five provides avoided kW statistics and participation site counts for the Scheduled Forward initiative based on participation option. A couple of observations are noteworty. First, and as reported in the 2006 year-end report, the three hour option was not a particularly popular offer. Growers reported that the inconvenience and associated labor of having to accmmodate a three-hour interruption was not offset by the participation credit. Second, the six hour dispatch blocks were, by far, the most popular option, representing 88.1 % of total Program site participation and 87.1% of total avoided kW. Table Five Program Impacts by Partcipation Option Site June Avoided July Avoided Aug. Avoided Sept. AvoidedParticipation Option Ct. kW kW kW kW ,..,_..........,...,.,.,.QetiOnl!!.,~.,?-~t..___~1.Q__.___...__._.._..._J_M§LL-........._,..._,?:?&~1ß..._.._................_...........?J.,!,~esß........................................J_e,!.?9..9ß,.., ......,.,.........,.,...,gP!9.,r:J.JJb"?:S,,........__....?e.9.._............'...._..'_ 17 ,5201____,_,,__..1!524.5 _............_.._.......?J_!p82.t3...............,.,......____.......S.4:........ ,..,.......,...........,.9pti.Qn...iLr...~..~:§........._.............,.§................................_________~...~-'~__....._..._. 615.0 __....._..__..____..._,....3.L__..._..___--~~A..... .........................9p!i.Qn....i..,r..~...:?.........._._..............§............_...................,_._....,.....J..s.s:.~...................._____.._._??.e,~~.....,____?85.4 ___..___...,?.§Qi, ......._.._._...._..Qeti9..r:...I.1J..!bJ:§............................? ...............................................J.4e:..,........."..,',.....,.?§.4~..1........__............,......._,....,....?S~.:.L................ ........,.,..........?51 :9,_ ____C?e!.i9.!!...I.1J..b_F_..............._._._?______._._...................JJ.?:9................_........................,,1§1.&.......,..,.,...................................1?eß,......................................._......J.?.4~~.. ......._.9pti.QnJ!!.~.!.I!_~~.....__lL......._......_.__..__._._!g1:,.,....._......_...1.!.???:L........_....,.....,.,.J..!.?e,?:.?............,........,.,........,......1.!...91ß..... .....,.9p!i.Qn_...'..~..tY:,.!b.,.E.....,_._..,.,.?~.....,.,...,..,.,.,...,.....,_._--51.8_._____._.._.__.~??:.................._...................J?-?J........................_........._.__..§.1.~.?.., Option IV m 2-8 9 2,425.0 3,122.7 3,086.4 2,959.6 Totals 681 39,181.6 51,710.4 49,568.3 40,507.1 Note: data reportd as of 30 September 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. 2007 Idaho Irrgation Loa Control Program-Final Report Page 4 of41 Table Six 2007 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 19,077.5 20,441.9 21,382.0 21,382.0 20,017.6 19,077.5 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 25,731.0 27,598.5 28,746.9 28,746.9 26,879.4 25,731.0 AUGUST Monday Avoided kW by Hour Hour 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59 Avoided kW 24,458.9 26,340.5 27,548.0 27,548.0 25,666.4 24,458.9 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 19,645.1 21,010.3 22,032.4 22,032.4 20,667.2 19,645.1 Table Seven 2007 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 17,520.3 18,590.4 19,457.2 19,457.2 18,387.1 17,520.3 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 22,524.5 24,041.1 25,064.7 25,064.7 23,548.1 22,524.5 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 21,582.6 23,135.1 24,186.8 24,186.8 22,634.3 21,582.6 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 18,084.1 19,436.9 20,322.9 20,322.9 18,970.1 18,084.1 2007 Idaho Irrgation Load Contrl Program-Final Report Page 5 of41 Table Eight 2007 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 16,652.5 18,016.9 18,957.0 18,957.0 17,592.6 16,652.5 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 22,608.3 24,475.8 25,624.2 25,624.2 23,756.7 22,608.3 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 21,3725 23,254.1 24,461.6 24,461.6 22,580.0 21,372.5 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 16,685.5 18,050.7 19,072.8 19,0728 17,707.6 16,685.5 Table Nine 2007 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 17,520.3 18,590.4 19,457.2 19,457.2 18,387.1 17,520.3 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 22,524.5 24,041.1 25,064.7 25,064.7 23,548.1 22,524.5 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 21,582.6 23,135.1 24,186.8 24,186.8 22,634.3 21,582.6 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 18,084.1 19,436.9 20,322.9 20,322.9 18,970.1 18,084.1 2007 Idaho Irrgation Load Contrl Proram-Final Report Page 6 of 41 Cost.effectiveness analyses Cost-effectiveness will be calculated for the following program components: 1. Schedule 72 (Scheduled Forward) only 2. Schedule 72A (Dispatchable) 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 will be provided for each of the three aforementioned program cases. The tests for Schedule 72 (Scheduled Forward program component) wil be based upon the cost and avoided MW values as defined in Table Ten below5. The information below wil descnbe the methodology and wil be used in evaluating each of the subsequent program components. Table Ten 2007 Benefit / Cost Categories & Values-Schedule 72 Cost Categones Administrative support Program evaluation Field / Equip / Db admin. expenses Participation credits Program management Reporting Cost Values Benefi Category $495.00 $/kW-yr avoided $1,134.38 $186,916.21 $684,924.98 $27,248.96 $0.00 $90071953 Benefit Value $49.56 Total 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 tests6. The benefits are based on the calculations as defined by the Company's Commercial & Trading organization7. Costs used in these calculations include administrative costs, contractor costs (field technician and database design / administration), participant credits, and associated equipment costs. The participation credits are not included in the Total Resource Cost (TRC) test because they are a transfer payment from the utilty to the participants. The cost-effectiveness of the Program was calculated by Quantec using a simplified spreadsheet analysis. This analysis multiplies average demand reductions for the June, July and August period (as 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. Again, this value is $49.56/kW-yr. This value is increased by 10% to account for the effect of line (T&D) losses, resulting in a value of $54.52/kW-yr used in the cost- effectiveness calculations. 5 To the extnt posible, ærtin cost categories have been allocated by the repectve Schedule initiative 6 Note that no discounting of costs or benefit was require in this analysis sinæ all costs and benefit occurrd in 2007. 7 The methodology for determining avoided costs ($/kW-yr) are on file with the Company's Commercial & Trading organization (C&T). 2007 Idaho Irrgation Load Contrl Program-Final Report Page 7 of41 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 2007 Schedule 72 Cost-effectiveness Analyses Test Benefits Cost Net Benefits Benefit/Cost Ratio TRC....~J,'~sJ,.!.QQS_____,_,___l?J.S,?~~__..._.____l1i.t~s!.?.H....................................,.....,...........9..?§................................... ",.,...,..........._.y!.~li.!r.................JJ..,.~sJ..!.QQa_.........,....,.,...,..........~e.QQ! 720 ______~,S91?.ae..._............._..._..._...................._LS9......_...._...._........... ....................~~!.~~r.:.r.................JJ..,.~sJ..!.Q9.s.......................................~e.QQ,z?.Q....._,.........._........HS.CL289 --_.__..__._._._.lSQ--_..., ".. .._._..__~~rtici~~.!........................~§S1.e_?s.................................................JQ.:Q.Q.. .."....,._...........~§.S11e.?.S..._.,....._ .........._.....__ti~._,.,__......__,_..._._._ Measurement & Verification (M&Y) processes Consistent with the previous four irrigation seasons, field technicians prepared random, unannounæd site visits for the purpose of ensuring the integrity of timer performanæ and the absence of grower fraud. Five timer and timer-related parameters-(1) tape seal, (2) meter lock, (3) battery, (4) clock calendar and (5) pump panel-were considered in the evaluation. M&V technicians were also asked to confirm the presenæ of a PacifiCorp Site ID sticker for inventory purposes. Where it is suspected there were vanances in anyone or multiple of the aforementioned evaluation elements field technicians were required to indicate said variances in the database and to the Irrigation Load Control Management Team for adjudication. The results of the 2007 M&V activities are indicated in Table Twelve. There were two sites reported to the Irrigation Load Control Management Team for adjudication. On both of these occasions the Irngation Product Manager contacted the growers involved. With each incident the information clearly indicated no outward attempt to circumvent the control equipment or defraud Rocky Mountain Power. In both instances the ænter pivot was stopped during a control event at a position in the field requiring the grower to manually by-pass the equipment in order to move the pivot for the harvesting machinery too access that position in the field. Subsequently, the control equipment was corrected for proper dispatch sequencing. In both instanæs growers were advised that in future they should contact Rocky Mountain Power prior to manipulating the control equipment. 2007 Idaho Irrgation Load Control Program-Final Report Page 8 of 41 Table Twelve Results of the 2007 Measurement & Verification Ct. of Ct. of Units Percent QA Parameter Failures Inspected Failure SitelD Sticker 29 101 28.7%........................................_.....__............................... ........................... . ..................................................................................................... ............._._....._J~~_Seal...........................J............................,. 1 01..............,................Q:e~!.o............... ................._._e_~.n:Q.~~.nel....................._......?....__.._............. 1 01...........,....,.................J..:e~.......".Meter Lock 1 1 01 0.9%.....................____._u..................................................._.............................................. ...........................................................Clock Calendar 0 111 0.0%............__................__..............................._.._........................._............................. ................................ ____.._.__..._........._..ê.!llte.!Y_.___-._._..__ .......___,_,_l1.l.__.............................Q:9..~...__,. (Intentionally blank) 2007 Idaho Irrgation Load Control Program-Final Report Page 9 of41 2007 Schedule 72A (Dispatch able) Results In the fall of 2006, coincident with the year-end report and based on the results of a 25-unit pilot test of the prototype control technology, Rocky Mountain Power proposed and subsequently received permission to pursue a full-scale pilot test of a fuy dispatchable solution for the 2007 irrigation season. The results of the Dispatchable program are described below. Background A total of 17 customers (448 sites) participated in the full-scale Dispatchable initiative using the propnetary (cellular / RF) M2M pump / pivot control technology. M2M provides the underlying remote control equipment to Valley lnigation the world's largest agricultural pivot manufacturer. This particular product line (remote pivot control) has been available for five years. Rocky Mountain Power worked with M2M in the design, development and manufacturing of a wireless proprietary master / slave configuration such that a 1 to many pump / pivot configuration could provide independent control of irrigation sites8. This was viewed as a major step forward in providing an agn-business solution that would attract grower participation. Prospective large-grower participants were contacted and onginally notified of the pilot in late fall 2006. In the spring of 2007 these growers were again notified that the pilot had been approved by the Idaho Public Utilties Commission and asked if they would like to participate. Growers who indicated a preference for participation dunng the 2007 season were subsequently notified to disregard the standard notification mailng announcing the Idaho Irrigation Load Control program for 2007. Growers were also told that the Irrigation Management Team would work directly with them or their farm managers in preparing program participation application materials, site preparation / installation and training on equipment use. Concurrent with the management of the grower interface, the Irrigation Management Team worked closely with M2M Communication in technology reviews and softare development readying the technology for manufactunng and later field deployments. The Irrigation Management Team also deployed field technicians to begin removal of the solid-state timers during the late winter and early spring period prepanng the Dispatchable sites to receive the new 2-way control units. These parallel efforts (technology development, grower communications and site preparation) continued during the late winter / early spnng period until M2M units began to ship. In communicating with the growers about the Dispatchable program growers were apprised of the foundational components of the Dispatchable pilot including but not limited to the operating parameters described in the 'Tariff highlights' below. B As with the timer technology it should be noted that a single irrgation sit oftn required multple 'slave' units in order to serviæ a single site. That is, it is not uncommon for a single pump to be sized and connected to multiple pivots. The master/slave technology provided by M2M allows the user to independently operate the pump as well as each pivot site. With these configurations, however, separate field installations had to be completed on the pump as well as on each pivot. 2007 Idaho Irrgation Load Control Program-Final Report Page 10 of41 Tariff highlights The operational parameters of the approved tariff are bulleted below: . Applicable: To qualifying customers served on Schedule 10 and who met the following participation criteria: o an aggregate minimum of 1 MW (1,500 Hp) demand under their control (single account or multiple accounts) for either or both of July or August o an integrated pump / pivot irngation system o a minimum pump size of 100 Hp o continuous access to the Intemet from May 1 through September 15 . Grower Notification: grower would be notified on a day-pnor and day-of the Dispatch Event . Grower Opt-out: growers could, upon their discretion, opt-out of 2 'Dispatch Events' with no financial penalty. Growers could also opt~out of 3 additional 'Dispatch Events' but would incur a financial penalty described below in the 'Liquidated Damages' section. . Liquidated Damages: Growers could 'opt-out' of up to a maximum of five Dispatch Events with the provision that any opt-outs beyond the first two the grower would have their credits reduced by the amount the Company would otherwise have to pay for power for the duration of the 'Dispatch Event'. . Dispatch Conditions: The Company shall have the right to implement a Dispatch Event for participating customers accrding to the following criteria: o Available Dispatch Hours: 2:00 PM to 8:00 PM Mountain Daylight Savings Time (MDT) o Maximum Dispatch Hours: 65 hours per Irrigation Season o Dispatch Duration: Not more than three and one-half hours per Dispatch Event o Dispatch Event Frequency: limited to a single (1) Dispatch Event per day o Dispatch Days: Monday through Friday (inclusive) o Dispatch Day Exclusions: July 4 and July 24 and/or their respective designated weekday offcial holiday Installation schedule The design, manufacturing, and installation nuances related to the dispatch able units and the requirement to ensure 100% quality control of all hardware components meant installation was delayed such that not all units were fully installed by the start of the tariffed irngation season (1 June). Nevertheless, a substantial number of units (271 units OR 41.6MW) were installed and readied prior to the initial Dispatch Event on 6 July. Subsequent installations and training of growers on equipment use meant that installations came on- line in series following installation, database and Internet control reading of all user interfaces and user training. To manage this process and because there were a far greater number of installation considerations that needed to be taken into account, the Irrigation Management Team contacted a single grower who expressed interest in the technology and was wiling to act as defacto 'guinea pigs' for technology introduction. This gesture on the part of this grower allowed the Irrigation Management Team to work through the many 2007 Idaho Irrgation Load Contrl Program-Final Report Page 11 of41 technical and operational challenges the new technology presented. This meant that, instead of installng all 448 participating sites in parallel with multiple installation teams, the field effort would focus on getting the installation process, technology settings and database components correct with this single grower before moving on to parallel installations with subsequent growers. In the end, this approach proved effective for two reasons. First, problems and technical challenges could be reasonably solved without unduly impacting all growers. The potential 'damage' (negative spin, grower discontent, and frustrations) was limited to a single grower rather than to the entire population of participating growers. Second, field costs were limited as field re-work was constrained to a specific count of sites and not all of the participating sites. This approach resulted in conserving field expenses. The following example may help to further clarify the field cost issue. When field installations were begun, units were deployed with Operating System (OS) v 3.0. By the time the installation of all units was complete OS v 9.0 was being installed. Having to re-install all 448 sites (and, in many cases, their 'slave' counterparts) with each new release of the OS (seven additional site visits to each site) would have unduly impacted field operating budgets and further delayed installation of units to all growers. As it turned out, the Irngation Management Team was able to eliminate a certain amount of redundant field work and contain grower discontent by adopting a serial approach to installation rather than a parallel approach. The trade-off, of course, was that participating loads came on-line in chunks throughout July (see Table Thirteen) with all participating loads available for the August through September dispatch period. Table Thirteen Cumulative Participating Loads Available for Dispatch x Dispatch Event Count of Dispatch Duration CumulativeEvents Date (hrs) Duration (hrs.)1 6-Jul-Q7 3.5 3.5'~'~"""""'.......'"'-''---'-'''''''''''''''''''''''''''''.._.._..................................................................................... .....................................................................2 12-Jul-Q7 3.0 6.5..._---_......_--_.................__.__._-_.._---_..__._......................_...__._--_.................................................._........................... ......,_.,...,...............~...................,..,........................1.§::J..!J-':9?__~.______JtL9___............_...........,..,.,.............~?!.?eQ.,s..........._................... .....................................4...................................,...1.e.~~.I:9?_.__._.___...~Q....,....,_._..__.... ..................__i5..!.9QQ:.5.,........ ......................................s..............................................?,~~~.I:QZ._.........,........,.,......~:......."....._..,........,..,..,.1a&............___--5.!.900.5 .......e"......_..._..... ",....,?e:~~I:QZ...,..,......~.,Q.,.............,............._..........1e:.9....,___..............__.,_..............e7 ,891:1.._,.........,...,...,......... _.......,.............,_.L_..,.,....._...._.~1:Jul~L....,...,..,............~.,Q...............................................,??,:.9....,................,...................................ee.&Q~,:s,.....,........................... .__,s.._..........,__.J__Al9:.?......................._~.,Q.._................................?5.,:.9............,...................................,....,.?e...~e?J..................................... .................Jl.,..........................,...........S:A!J.9::.7 3~Q_......._._.....,......_..?8.0__...........................,..,.....,............?.e...~eZ.:J.............,..........,........., ,......0 ....................J.Q:A.~.g:.9L__.._.....,.,l:.Q......_..... 31.0 ........................................,....J§...~e?J..._......._..._...,_, ..........................,11..,......,,1~:A.~.g:9L ..............~:.Q......,......_,___..._.......li:.9..,..,_........____._._..e.!~eZcL___.__... ...................................12 .............,..J..s:A~,g:9?.., 3.9, "..,...................,...........~Z.:.Q........__,_,__..........._..?!?l~_,_.,_,._,..... J.~__.__........... .........J..:A.i¿:9Z.....................~.,Q,..,....,.................4.Q.:.9............_._.."..........................?a..?Jl?J..,.. Cumulative Participating Loads (kW.) ..,....,1....~,e?ß................................... .............1..!.~.e?.&..............,..,......,..... Table Fourteen indicates by participating grower numberS the 17 growers that participated in the pilot Dispatchable initiative, their participating loads and the percent each of those loads represent of the total participating in the Dispatchable component of the irngation load control initiative. 9 Grower names have been replace by grower # to maintain the anonymity of the growers and their irrgation loads. 2007 Idaho Irrgation Load Control Proram-Final Report Page 12 of41 Table Fourteen 2007 Participating Loads x Grower and the Percent Each Load Represents of the Total Grower Participating Loads (kW) % of Dispatchable TotalGrower 1 893.7 1.2%........................................................................................ ....................___..__....................n."...................................._ .....~rQ\fe.r...?..............................................J...~s.:~..........................._.._......,.....A&0(.___..___. _..C?'Ae.r..~............_......._...........................~.,.9e?.:s...................................................._,..,.,....~,:9% ..___._ Grower 4 823.6 1.1%_....._.....n............................__.__.__....................................................... .. ..........................................................n... .................................. Grower.___ _ __... .1.A1.M_....._,........., ......,..............................1..:.e.~...............,........,........ ......~r.9.'!e.r§........,..............,......,..,.,._.....?i.s?.a&__.___...............J.:.~.~....................................... .,....~r.C?'Ie,r7....,......,......,...,....,..,....._..__L.84a:.___.._..............._..............,...,..,..._?:.~~. ,.....,........................... .,.~r.C?'Ie,r.8 ...,"'" ,....__Jl126.~.._,_............___.__....._.___..._.._J 6.1.r.o..,...,......................... Grower 9 ..............._..J_~.i.ee~.:.9....,.,...,.,,__JLe~.... .J~rQ\fe,rJ.9....,',..,.,."".,.1J,!,?e?.:e............"...._.._.._,_.._..__,........,...1.:~~_......_ Gro\fe,rJJ............__.__.._....._._...........si.e?s:~...........................................,...........7:4rG._.__ _ ai:'ler.1?..__.. . 1 ,91.?.............................................................. 2.5%.........................,.,...,....... ,....~r.9.werJL,_,.__...._..__.._._.....?.i.e!.eA.._..........__.._.............................. 3.5% .............................. ..,...~r.9.~e.rJA._......,...,.._,.....,_..,........_?.!?1.ec.9...____.............................,..,~:.9~...................................... ......~r.C?'Ie.rJs.......,.........................,...__L209.7 __...._....... ............,.,......,..._..J.ß~....................................... ......~r.C?'Ie.r...1.§.....................................___4..,§.lJl___._._...___._._____ ..._._....___~:.r.o.............Grower 17 6,593.3 8.6% Total 76,397.1 100.0% Customer Credits All dispatch customers were issued both standard tariff credits of $11.19/kW avoided and supplemental credits. Supplemental credits were calculated based upon the porton of load a grower's particular pump site represented of the total (both Scheduled Forward and Dispatchable) under control for the 2007 irrigation season. Credits by type and total credits are reflected in Table Fifteen below. Table Fifteen 2007 Dispatchable Participation Standard & Supplemental Credits Credit Type Standard Supplemental Credit Amount $806,293.21 $261,712.28 Total Dispatchable Credits $1 06800549 Customer Opt-Outs Schedule 72A permits growers to 'opt-out' of two Dispatch Events with no financial penalty. Growers are also permitted to opt out of three additional Dispatch Events but would be charged the price Rocky Mountain Power would otherwise have to pay for power during that dispatch period. For the 2007 pilot season growers were NOT assessed fees (credit discounts) for opt-outs beyond the allowed two. There were two reasons growers were NOT assessed the fees. 2007 Idaho Irrgation Load Control Program-Final Report Page 13 of41 First, as an entirely new technology both softare and hardware needed to be stress-tested. In so doing the Irrigation Management Team coordinated with the grower and their farm managers in executing and requiring opt-outs during each of the 13 Dispatch Events in order to test both hardware and softare system components. Second, was the issue of technology usabilty and grower training. Technology usabilty was and remains the single biggest obstacle to technology adoption. The Irngation Management Team understood that for the Dispatchable initiative to be successful growers and their farm managers would have to change operational habits and practices. Fundamentally, that meant controllng pump / pivot sites either through their cell phone or the Internet. This was not a trivial consideration. Accrdingly, much effort was taken to train growers / farm managers on the new technology. The Irrigation Management Team urged practice use of the equipment, including opting-out of Dispatch Events even though the grower would have otherwise participated in the Dispatch Event. The decision was made and the objective adopted to get growers / farm managers comfortable with the technology and its operation. Bottom line: Schedule 72A was a pilot and the Irngation Management Team treated it as such and encouraged growers / farm managers to do likewise. Nevertheless, statistics were gathered on the count of opt-outs and load NOT avoided by Dispatch Event. These data are presented in Table Sixteen. (Note: of the first three Dispatch Events (July 6, 12, 16) approximately 91 % of the opt-out counts onginated from a single grower. Again, on July 26 and 31 more than 80% of the opt-outs originated from that same grower.) Table Sixteen 2007 Dispatch Event Parameters, Count of Opt-Outs & Loads Not Avoided Count of Cumulative Load NOTDispatch Duration Participating Ct. of Opt- Avoided Net Load Events Date (hrs) Loads (kW.) Outs (kW) Avoided .._...__.._._._J________e:~_l!I:QZ__......~.,.s....................._............_..4.~..!.~~?.&...............................,.s~..,..,...........,a,.Qa.?.:.s........................~~.!.~Q?,:L._..., .....,._..__L_,__.............l~-.l!-O~........__,__.._.J~.Q........_...._...___4J..!.~~?.&...................................s~.....................~,..~.a.?.s........................~?!.?Q?.:.t........ .........._.............~....................................,1.e_~,~.I.::.?...........,.,........_3..L_.._,__g?QQ~S__......__......n.....,..,.,.......M~.?:.?.......................A4.!.~?~.:.9.....,.... 4.......,...,..................J.~:~!:I-:.?......................._.__l:_.____._.S§Æ.9?.....__.___........e... .........................J...aQ.9:....,..,...,.........,.,?~.!.?QQ,:s,......... ......._..._.........?.................................J_H~.I.::.?........................iO"__,_____,____?.5,09...~5._.______._..,.,O ...................._...:9..............................??!..QQ.:.s....... ...........,..,....,......e_....................................?e:~,~.I.::.?..,........,.,.....,..-lJl___.._,_,_,__...._,67,ee.U_..__..... 16......,.aQ.9:..........................ee.!.9_eJ..J........... ........,...........,..,7..,.............,.,................~.~,:~,~.i.::.?.....,........,...,_,__~~.Q_,_...._,__....,.._....~9,803.8__.......?.Q_ ....,...JJ..!.~..:.?..............._.......eMaa:.~.......... ....,.... .."....,,a....,...,......,...............,.~:Al!9.::.?..,......................._.._~.g..........................._..........L6,39.?J____,_,_......__.........a._...___~.9,..9.._......,._.___J5,4gZ.J........... .......,....,.............~.....................................a:Al!9.:.9.?............,.,.,_....,~,g............,....,.?e.!?~.?,:,L,__.._,.._....____L___ 6QQJL__ 75le.?.,J............ ._......._............1..............._..................:Al!9..::.?........_...................~.g,..,...................,....,......?~!.~~.?.:J..............................._JL__.___,_..__.._..9L____._LaL~~.?.'J......._ __...............JJ......................__._J.~:Al!g.::.?. "" ~,.Q """"""",.........._.?~!.~~.?.:J,..............................._.....J.................,......,..,1.9"Q,:9..._...,.,...............?~!.?~7 .1_ _..............J?____!.?.:A_~9._9J.______,J,g".. ......._....._.?e.!.a~.?J....................................._..............."........,..,.,......9&.._....................._...?~!.~~.?!.__,. ,..__.._......_L-_J.z:A!:g..QL_.......~.g..........................__.....Je.!~~.?:,~,.,..................,.,.,..1..~................................J.,J?.s,:........,...,.,..,....?s.!.???.:,t._......, 2007 Idaho Irrgatin Load Contrl Program-Final Report Page 14 of41 2007 Dispatch Events The avoided demand by dispatch hour associated with each of the Dispatch Events is presented in Table Seventeen. The values in this table represent dispatchable loads only. A zero (0) appears in several of the hourly ælls (most notably the 2:00p-4:00p block). This is due to the fact that the dispatchable initiative was only exercised for either a 3.0 or 3.5 hour block (4:00p-7:00p / 7:30p). The reader should also be aware that on July 6 and, again, on July 16 the Dispatchable option was exercised for 3.5 hours. To accommodate the Y2 hour during the 7:00p-7:59p period the Dispatchable load was reduæd by 50%. In reality the full load was realized for the first 30-minutes of this dispatch hour and zero load during the secnd half of the 7:00p-7:59p period. While not perfect, taking 50% of the total load was the most expeditious way to represent these data in Table Seventeen without using Y2 hour increment categories. Table Seventeen averages the loads (weighing each 'Dispatch Event' equally) by hour for each of the 13 'Dispatch Events'. Finally, it should be noted that there were NO (zero) instances reported where, onæ the technology was installed tested and operational on a stable operating system, the technology failed to respond to a Dispatch Event. Table Seventeen 2007 Dispatch Events x Dispatch Hour & Associated Parameters Dispatch Hour 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59 Tot.Tot.Tot.Tot.Tot.Tot. Ct. of Dispatch Day-of-Avoided Avoided Avoided Avoided Avoided Avoided Event Date Week kW kW kW kW kW kW 1 6-Jul-07 Friday 0 0 41,392.6 41,392.6 41,392.6 20,811.8 2 12-Jul-07 Thursday 0 0 41,392.6 41,392.6 41,392.6 0 3 16-Jul-07 Monday 0 0 52,760.5 52,760.5 52,760.5 26,495.8 4 19-Jul-07 Thursday 0 0 55,000.5 55,000.5 55,000.5 0 5 23-Jul-07 Monday 0 0 55,000.5 55,000.5 55,000.5 0 6 26-Jul-07 Thursday 0 0 67,891.1 67,891.1 67,891.1 0 7 31-Jul-07 Tuesday 0 0 69,803.8 69,803.8 69,803.8 0 8 3-Aug-07 Friday 0 0 76,397.1 76,397.1 76,397.1 0 9 8-Aug-07 Wednesday 0 0 76,397.1 76,397.1 76,397.1 0 10 10-Aug-07 Friday 0 0 76,397.1 76,397.1 76,397.1 0 11 13-Aug-07 Monday 0 0 76,397.1 76,397.1 76,397.1 0 12 15-Aug-07 Wednesday 0 0 76,397.1 76,397.1 76,397.1 0 13 17-Aug-07 Friday 0 0 76,397.1 76,397.1 76,397.1 0 Average 'Dispatch Event' Avoided kW x hr.0 0 64,740.3 64,740.3 64,740.3 23,653.810 Note: data presented in this table ignore all Company- and grower-initiated opt-outs (see Table Sixeen) 10 The mean for the 7:00-7:59p hour was calculated ignoring the zeros (0) in the eleven dispatch events. 2007 Idaho Irration Load Control Program-Final Report Page 15 of 41 l Customer Feedback The Company has, based on historical precedence, meteorological considerations and other class 1 initiatives, 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 operate11. The Irrigation Management Team wanted to provide growers with a realistic feel for the number and duration of dispatches so they could provide reasonable post-season feedback and could make a realistic assessment for participation in subsequent irrigation seasons. The Irrigation Management Team was also interested in this feedback so the appropnate adjustments, if any, could be made to improve the program offering. As a pilot, and in addition to the ad hoc feedback received from growers / farm managers throughout the irrigation load control season, it was important to collect grower data relative to the Dispatchable initiative. Moreover, gathering grower feedback was required in the Commission order approving Schedule 72A. It was hoped that information gained from the questionnaire and associated discussion would assist in making specific changes that would (1) improve operations, (2) enhance the value proposition to both the grower and to Rocky Mountain Power, and (3) improve cost-effectiveness. Accordingly, a brief questionnaire (see Attachment One) was developed and used in a post-season interview with growers. In addition to the questionnaire a follow-up information gathering interview was held with each of the growers / farm managers to gain additional insights / observations as to the Dispatchable initiative's strengths and weaknesses. The six broad categones investigated by the questionnaire and reviewed in discussion are listed below. 1. Program introduction / terms and conditions 2. Selecting and scheduling site installations 3. Field installation activities / processes 4. 'Dispatch Event' operations 5. Training 6. M2M control equipment Results from the questionnaire / interview with growers sort themselves into nine categories. A succinct descnption along with representative grower comments related to each of the categones follows. 1. The Company did a relatively good job informally communicating with growers as to the value proposition, tariff parameters and technology operations. Growers partcularly appreciated the local presence of well known field technicians in whom they had confidence and trust to accurately and correctly represent the technology and operational considerations. The Company's local, well- known and trusted Customer and Community Management Representative (Bob Smead) was also cited by growers as having made program components understandable. 2. Growers were not as complementary when it came to keeping them (growers) abreast of development efforts. Until technical issues were largely resolved, the Irrigation Management Team allowed attentions to focus nearly exclusively on problem solving and gave little consideration to growers waiting in the wings for implementation on their farm(s). Communications to the large grower population was lacking. 11 The 40-hours of dispatch is consistent wiUi what oUier electc utilities report I anticipate based on requirements for peak avoidance. 2007 Idaho Irrgation Load Control Program-Final Report Page 16 of41 3. While training effort were ranked positively, nearly all growers offered a number of recommendations to improve training / technology implementation. Grower criticisms were instructive in assisting the Irrigation Management Team in making adjustments to the irrigation initiative. The nature of the criticisms (some of which are indicated below) suggest a partnership approach between growers and the Company. Improve the pump site naming / identification and how the software works.. . also need better / more explanation as to why certain sites are not applicable for participation. Need to do a better job of visiting with growers prior to the install and explaining operations and issues and how they impact the system. The information for managing slave / masters could and should be made more clear. On the website it would be helpful to be able to use the back key...a/so the website times-out too quickly need to lengthen this capability. The website need to be explained better or made to be more intuitive so it can stand alone without so much training / rehearsal. Naming conventions don't work for when you are just managing pumps vs. pumps and pivots...not being able to independently manage these units and name ilem axoromwy ma~s ile ~stem awkwam Training, particularly for when you're training just for surface water folks, need improvement. We wil need training again next year to know what we need to do and how to operate the equipment. Perhaps we ought to do both group training and individual (1: 1) training, that way we can cover general stuff and take advantage of general information and then provide specifics. 4. Growers were somewhat irritated as to the delay in program implementation. These delays were viewed as being organizational and not technology-driven. There was a universally simple and clear message: Make sure the Company does enough in advance so that there is suffcient time to implement the program 5. The 'opt-out' option was enormously important to the Dispatchable value proposition. Without this option growers would have simply elected to not participate in the initiative. The 'opt-out' stuf was important to making the program work.. .single most important piece. Flexibilit (opt-out) is what makes the whole deal work. Without this option this program is dead. Options (opt-outs) are key! More options is good... Opt-outs are the key. Key is to have opt-outs...that is what makes the program work. 6. The accptance of the M2M control unit would take time for farm managers to get their arms around and get comfortable with. This finding was corroborated with data from Valmont Industries (Valley Irrigation) who indicated that it typically takes growers 3 seasons or more to become 2007 Idaho Irrgation Load Control Program-Final Report Page 17 of 41 completely familar with the technology and confident it its reliabilty. Nevertheless growers feel it is a worthwhile transition and investment in time. The farm managers learned how to use equipment but wil have to re-Ieam next year. We stil have a way to go before all farm managers feel comfortable (probably 3-years for some of the farm managers) with the new equipment. But we wil get there and in the end it wil help the power company and help us with credits. 7. Growers valued and appreciated being able to solve problems with local resources. In the end, managing irrigation pumps / chemical pump tanks and pivots via the existing control panels and bolt-on utility equipment requires highly specialized knowledge. Growers do not allow anybody to drive onto their propert and work on equipment which can often impact ::$300,000 in potential revenue on a single pivot. Moreover, there are real threats of biological infestations that can be introduced to the acreage if vehicles and equipment are not properly cared for, attended to or if those doing the work do not have knowledge of agri-business operations. When you just throw program at us and sçiy 'OK there it is' than it don't work.. .the people you have working on it (load control program) makes the whole deal work. If Brad, Andrew or Ty would have ignored the problems then we would have had a different result. Yeah, there were some glitches...but want local resources...don't want somebody in Chicago answering the phone or tellng us what to do without really meaning it.. . this actually worked and your local people made it work.. .didn't hurt yield or quality either. The inigation team got it working...you guys worked to get the farm managers to make it work. 8. Growers made a number of recommendations to improve control technology operations and program viability. It should be important to note that virtually 100% of the changes are softare initiated adjustments and not changes to the fundamental underlying hardware. Among other items growers recommended the following: .:. Use text messaging for communicating status change conditions... the robotic voice is diffcult to understand. Also, provide text messaging in Spanish. .:. Further shorten the call sequence to execute a particular command. Provide a sequence of code numbers without having to listen to the voice prompts... put this on the 'cheat sheets' provided to the growers. .:. Provide the user with the capabilty to view units grouped as well as ungrouped for the offce staff. .:. Provide exception reporting and not simply status change reportng. .:. Want feedback when you opt-out. Growers need a little bit more of a road map such as pop-up screen saying "you are opting out, please confirm". .:. The status summary screen is not entirely clear on what is going on in the field. 9. Operating parameters appear to be an accptable risk. That is, the three hour dispatch event was seen as virtually no different as a potential four hour Dispatch Event. Moreover, it was reported that a total of 50 hours seemed workable to growers so long as it got past the period when the canopy had grown over. 2007 Idaho Irrgation Load Control Program-Final Report Page 18 of41 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 (Dispatchable option) upon which calculations are prepared are presented in Table Eighteen below12. Table Eighteen 2007 Benefit / Cost Categories & Values-Schedule 72A Cost Categories Administrative support Program evaluation Field / Equip / Db admin. expenses Participation credits Program management Reporting Cost Values Benefit Category $1,005.00 $/kW-yr avoided $1,134.38 $560,748.64 $1,068,005.49 $52,895.04 $0.00 $168378855 Benefi Value $49.56 Total As shown in Table Nineteen, the Schedule 72A passes the TRC, Utility and Ratepayer Tests. The Program also passes the Participant Test. However, since the participant incurs no costs the benefiUcost ratio would be infinite. Accordingly for the Participant Test the value is indicated as 'N/A' in the BenefiUCost Ratio column. Table Nineteen 2007 Cost-effectiveness Analyses Test Benefits Costs Net Benefit Benefit/Cost Ratio ..........................,........!.~,~......,. ,....1~ßSe.A?9......___.__J§J_~2.,,~.._ ...__...._..._g?Æl,e,S?..............................................e,:,?e................................. ..,...........................y!i.li.~~.................l~ßSe.!.4.?9......................_......~MS,~!.?S.L__l?lE?&S1._...._......._._.._._____.........?:'?L...__._... _........._.......~~~:~~~_~~._....".,J.MSM?9........,.....~M.S~!.?S.e............................~?,,J.??&sJ.......___._..__...._.._......-.,?~_._..,_...._..___..... .__--art~~~~_~!_._._...._.ll.968,005 _,.., ............._......_19.:.9.9..................,.,...,.11 ,06S!.Q9.S_.........._................,.......,..........,.N!~................................._ 12 Again, to the extent poible, cots have been allocated by the repectve Schedule initiative 2007 Idaho Irrgaton Load Contrl Proram-Final Report Page 19 of41 2007 Schedule 72 & Schedule 72A Results This section of the report provides a brief quantitative summary of the two combined initiatives-Schedule 72 (Scheduled Forward) and Schedule 72A (Dispatchable). 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 Twenty. The values in this table are additive. That is, they represent the combination of Scheduled Forward loads plus Dispatchable loads. Two important facts need to be taken into consideration in evaluating these data. First, a zero (0) appears in several cells. This is due to the fact that the Scheduled Forward initiative operates Monday thru Thursday inclusive. When the Dispatchable initiative was exercised on Fnday the only avoided demand is that associated with Dispatchable loads. Second, on July 6th and, again, on July 16th the Dispatchable option was exercised for 3.5 hours. To accommodate the Y2 hour during the 7:00p-7:59p penod the Dispatchable load was reduced by 50%. In reality the full load was realized for the first 30-minutes of this dispatch hour and zero load during the second half of the 7:00p-7:59p period. While not perfect, taking 50% of the total load was the most expeditious way to represent these data. Finally, the table calculates the average (mean) as well as a median for each of the hourly loads per 'Dispatch Event'. Table Twenty 2007 Dispatch Events & Associated Parameters Dispatch Hour 2:00-2:59 3:00-3:59 4:00-4:59 5:00-5:59 6:00-6:59 7:00-7:59a~ ~ T~ ~ T~ T~ ~ Dispatch Avoided Avoided Avoided Avoided Avoided AvoidedEvent date Name kW kW kW kW kW kW m....mmmmmm,.....mJ....,....~J:Q!.................._J:riday .............................:.Q....._.......,...............:9....................4JI.~~.?&.............m.4.'~....?e,?':§m.'.m'.'.'m,4~..,.?e,?:.a.._ 20,696.3 m, m'........?..,.__...R:!~.I:Q!.........._.._)hu~~Q9y...........?~!.S?4.:.S..._..14,.9AJ.,.1...................ae,.4.s.!~..................ee!,4.s!.:'~'..'mmmm'§4.,.e,4.Q.:.!.,......'.'m?.?-,S?4.5.... .....................................?m........'...,1.S~~,1:Q!.....,.._._..._~gn.Q9.y...............~SJlQ§L-..eÆ.~§.................aQ!.e.e?:. ",.. m'e9..!.???:...................?e, ,9.JA.:.e,...,....,.........sJ.,.4...,S:?.,... ..............A..................J.Hy..I:Q!............_.m'.m'..ln.Y.,~Q9.y.... 22,524.S_m'_'.?4.,,9.4J..:.............s9.,.9Ss:.?.................?Q.PSS.:.?,...,.,....,.?M4.e,&......,....,..?.?.!.S?,4.:,S,.... .........s.........??:l.y.I:Q!.................................M9.n.Q9.y........._,.?sJ.9e,:9.......m'm?~97:i.S_.._ 83, 1..??:..................s~,!,J,??,A.,.............a~..,.?S4.,t..,...........?s!..~..e:9...... ......................a...................?.S:l.y..I:Q!................,.........,..Th.y..r.sQ9.y'.......m?'?..,S?.4"S,.'.......m'?4,041.1 9?Jl.SM..................e,?,e,SS&......,........~J.Aa~.:.?,....m.....'..??!.S?4.:s.... ..._........__.....1.....................~J.~.y..I:Q!...............................y..eSQ9.y..,',..?,?..,S?4,:'Sm....'....?A.&4JJ.,..,._.....e,4.I.eeel........e,4,868:,S...,.,.,...,.,.~...351.~...,........??!.s.?.'!s.... .........__JL................~:Ay..g:Q!........................................E.ri.Q9.y...m...............,..,....,9., ..m ....m.'...'..9.,g..........m'..?ß.!.~~J.:L._?6,39J.:.L_.._76,?97 .1 .................................:.Q..... .m......__'..__~...,.......s:Ay.,g:9L_.............Yea.n.esa9.y................?9.,74.!:.S.................??,.e?e,J..........J.9.9.!.?33. 7 --23?.L.....~352.1 ..............?Q!.!.4.!S..., ...,..,.................J.9._......J9.:A~Jl:Q?_...........................n~.~...........'m...........:..............'..m....m.m..:9...................M~?J............_..!.e...?e,?.:76,3e,.!:.L..._..............._..9:.9.... ,..,.......,......JJ.............~.:Aug-07 __m............_....M.Qn.._,........??,.s~.?:.e,.................?,SiT1.S.:.S............J..Q~!.~?Q.:.............J..9.~,..~,?9..:L.._,.J9.1ÆS.:S..._..~ß3~~... .........m..'....,..'.'..'mJ..?...._.._5-A~9:L..,.......Ye2nes.Q9..........?9.,.!4.!S...............??...S?~:Jm....~..Q!.?~,?:.!..........J..Q9..!.?~E_..............e,a,.~S?.:J.m_ 20,747.513 17-Aug-07 Friday 0.0 0.0 76,397.1 76,397.1 76,397.1 0.0 Mean 'Dispatch Event' Avoided kW x hr. 15,818.4 17,006.5 82,517.2 82,517.2 81,329.0 19,439.7 Median13 'Dispatch Event' Avd. kW x hr. 22,524.5 24,041.1 80,882.4 80,882.4 79,014.9 22,524.5 13 Note: Where there are outlier values median values should be used as opposed to mean (average) values to more corrcty reflect the avoided kW. Mean values skew data as they are unduly impacted by spuriously high (103MW) and low (zero) values. 2007 Idaho Irrgation Load Control Proram-Final Report Page 20 of 41 Crop type analysis Consistent with the 2006 report an analysis was prepared of avoided loads by crop type for the 2007 season. As mentioned in the 2006 year-end report this analysis is somewhat problematic as a majonty offield installations occur in January, February and March prior to when a grower has made a final decision on crops and prior to planting. Nevertheless, field technicians either inquired of the grower as to crop type or could identify the emerging crop himself (in the case of late-in-season installs). Table Twenty-One: 2007 Program Participation by Crop Type / Application x Site Count & Average Avoided kW presents the results of these field data gathenng efforts14. The avoided kW values were calculated by taking the full summer (1 June through 15 September) average for each of the identified sites and summing those avoided kW values by crop type / application. Table Twenty-One 2007 Program Participation by Crop Type / Application x Site Count & Average Avoided kW Crop Type / Application Count of Sites Total Avg. kW15 ......G.r.ei~........._._..........__._..............................................................~.7 4.0 ................_......__14.!~e1.3......._.,...,........ .....~.eL_......_...__.....................................................J.s~:.Q.........................., .....'._......_ 33,8Zf:L................. ......sp.~Q!.,_,...._...._....__....,_..,.,.,....,..,...,.,....,....."...,' 95.9....".,..........,......................__.._.....,81.7.2 __,_......._._.. ,,'pe~t~r.~., ..,..........,....._......_..._....._._e.~:.9....,....,............................,..................J.!.~s?.:.a..,...._..__ ..,G.r'l~~........,.,...............,.._....,...____5.~:.9..,..........................................................?.!.1..9S,:.?....,_.............. ......G9..r.n........................................................_______._..__.........1.e:...........,....,..,.,..............................................!.?se.:.?.................... ......M~Q...~k~.J~~!:.i.~L..............._........................................§...__._._.......................?.!.~se.:.s..,............, .....ßi.Y.er.......... ...........,...."....,',..,............__.._._......., ,.s~s.:.~.......................... _~..eQ..~ir.~le~...................."...., ",. 3.0_..__........._........_...........,...!1eeß............................Orchard 2.0 25.5._.~._~.._......._........_.............._...__......_... ............................................_............................_-_....__.........._.._..._........................Pond 2.0 292.1..........................................................._--_.................River 1.0 104.6....................................................................................................._....._....._..........................................................................................._......................_- .....Ge.rete.'l......................................____...:.9............................................................................J.e.:.9...............,.......... Canol a 1.0 2.78.................. ..................................._.........- ............_............_.....__....._........................................................................................................................Radish 1.0 36.3..................................................................................................._.................................._.._....._._..._._.__............................................................................ ..Flood 1.0 12.1 Total 983.0 100,59.7 Table Twenty-Two: 2007 Program Participant Estimation of Crop Type x Total Acres presents field installer estimates of 2007 Program participant crop types x acres16. Again, these are estimates are constrained by the same parameters indicated in Table Twenty-One. In addition, data accuracy is further constrained by having to estimate the size of the total acres under cultivation at a particular site. Accordingly, attempts to synch-up avoided MW as reported in Table Twenty-One should be avoided. 14 Note: these estimates reprent infonnation about 2007 partcipating sites in the PacifCorp service terrtory. Specifcally these data repreent sites where the crop type has been indicated by field installation teams. Sites where crop type has not been identified by field installation teams are eliminated as part of the query. 15 Data includes results from both Scheduled Forward as well as Dispatchable initiatives 16 The query extcting these data reuire that both 'crop type' and 'acreage' fields be populated with values from field installation teams. Where either or both fields were left blank the values were not included in the resultant table. 2007 Idaho Irrgation Load Control Proram-Final Report Page 21 of 41 Table Twenty-Two 2007 Program Participant Estimation of Crop Type x Total Acres Crop Type I Application Total Acres Grain 79,801.0...................................... ..............................._................-...................................._...._..... .....~.~Y...................,.......,_.__.......,_,e~!~_~?,:,Q....__ .._.?p~.~~.........,."...,.".,.,....".,_.,..,..........~,a,!,~.~.?:.Q____Grass 4,787.0~.._...._..._.._....................................................................................................................._---_.....Pasture 3,671.0--_..._-_...................................... ........................................................_..................Corn 2,465.0.__.__............................................................................................................................................ Mixed circles 1,600.0-----_.................................................................................................................................................Canola 260.0..__._......................................................................................................................_._..............Radish 130.0-_.._.................................................................................................................Flood 100.0........._.._--_.......... ............._................................................................................................................. ,-,~,~~~!~-ry.._._..._._....._.._._-----_...............................,',.,...,~,?,:QOrchards 6.0................................................._.._--_...._......Mud lake (canal co.) N/A Total Acres 173,384.0 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 participants in this area, however, partcipated in the Dispatchable (Schedule 72A) program. Hence the impact of the Scheduled Forward component is diffcult to observe. Nevertheless, SCADA values were taken and logged at 20-second intervals for periods when dispatches were executed. Virtually all of the 13 'Dispatch Events' had identical profiles. Two of those profiles are described and presented in the ilustrations below. Ilustration One (Big Grassey Transmission Load Profile July 12, 2007 (CB 67-'Big Grassey')) depicts gnd impacts as a function of both Scheduled Forward (Schedule 72) and Dispatchable (Schedule 72A) options. What is noteworthy is (1) the magnitude of the load shifting effect as depicted in the difference between control and non-control hours and (2) the impact of 'load shaping' as a function of the combined impacts of the Scheduled Forward and Dispatchable program components. This shaping capabilty is important as it provides Rocky Mountain Power with greater optionality and control over the grid in systematically meeting load requirements during summer peak periods. The 'shaping' is dramatically different than that experienced with the use of the electronic timers alone. The aggregate impact of electronic timers results in a hard edge in the SCADA profile as opposed to a more gradual load shape with the combined used of the electronic timers and the 2-way control equipment. For comparison and ilustrative purposes of this 'edging effect' 2006 load data is provided in Ilustration Two. 2007 Idaho Irrgation Load Control Proram-Final Report Page 22 of41 Ilustration One Big Grassey Transmission Load Profile July 12, 2007 (CB 67-'Big Grassy') 55 50 45 40 f5 = 30 ë" l 25....g 20 15 10 0 0 0 g ~¡;g ~0 g 0 ¡;g a 0 0 0 g 0 0 g 0 ¡;g 0 0 g 0 ¡;g 0 g ~0 0 0 0 g ~¡;0 0 0 g0..':N ..':..N "N "..N ..N N 0 ..N 0 "N g '"~~8 ~~;;~~~~~"'~~~g 0 ~~~~~::i:~~;;g ~~ig re g '"ä ~~~g ..~~ö Ö N N M M ".;.;,¡,¡;.;;;;0;g g ::::~~ti ti ;!;!~~~t:;.~~~gj ~¡;¡;~~g'gi Time (24 hrs.) 1- Transmission Load ProfileI Page 23 of412007 Idaho Irrgation Load Control Proram-Final Report Ilustration Two Schedule 72 Idaho Irrigation Load Control.Average Daily Load Curve: Control vs. Non.Control Periods for July & August 2006 (CB 67.'Big Grassy') 40.0 5.0 Cl. Days (Mn-Th) All Non-Crl Days (Fril, Sat,Sun.) I 35,0 30.0 25.0 ~ 20.0 15.0 10,0 0.0 Ilustration Three (Big Grassey Transmission Load Profile August 13, 2007 (CB 67-'Big Grassy')) plots Big Grassy 20-second interval load data for August 13. Again, what is instructive is that nearly all 13 'Dispatch Events' incur the identical load profile with only minor perturbations. 2007 Idaho Irrgation Loa Control Program-Final Report Page 24 of41 Ilustration Three Big Grassey Transmission Load Profile August 13, 2007 (CB 67.'Big Grassy') 35 15 30 25 20 10 o 88888 g 8gg g g gg gg g g g gg 88 gg 8gg gg gg 88 8 g 8 gg gg g g gg gggg~ ~~ ~~ 8~ 8 ~ g~~ ~~~~t ~~ ~~ ~~ ~~re ~rem~ ~~ ä ~ ~ ~s ~g e ~ ~~ ~~~öö ~~ NN MM. ~ ~ ~~ ~~~ ~ ~ mm öö ~~ NN M M..~ ~~ ~ ~~ ~ m mö ö ~ ~N NM M~~ ~~ ~~~ ~~~~ ~~ ~ ~~~~ ~N N N NN NNN 1- Transmission Load Profile I Load profile data (Total Rocky Mountain Power Southeast Idaho unadjusted FERC load data) Ilustration Four (Total PacifiCorp Hourly Idaho Loads (July): Schedule 72A Idaho Irrigation Load Control-Dispatch Days vs. Non-Control Days) plots the total Company Southeast Idaho Service Territory average hourly interval load data for the first two-thirds of July17. Data is segregated by dispatch days (Dispatchable component only) and non-dispatch days (including scheduled forward dispatches). Additional Southeast Idaho Service Territory average hourly interval load data plots wil be provided below. In evaluating these data a cautionary note is warranted in their interpretation. The aggregate Southeast Idaho load profile data provides some indication as to impacts as a function of the Irngation Load Control program. These data, however, should not be interpreted as being conclusive evidence for or against operational effcacy as there are a wide variety of activities impacting the electric gndother than irrigation alone. Where appropriate, attempts wil be made to provide interpretation / rationale of the data that is presented. Also, and at the time of the preparation of this report, only preliminary June and July FERCdata were available. 17 Note: at the time of the preparation of this report data are not yet fully adjudicated for FERC reportng; nevertheless it is not anticipated there wil be measure deviations from what is indicated in Ilustrtion Five 2007 Idaho Irrgation Load Control Program-Final Report Page 25 of41 Ilustration Four Total PacifiCorp Hourly Idaho Loads (July): Schedule 72A Idaho Irrigation Load Control.Dispatch Days vs. Non.Control Days 760 650 750 740 730 720 710 ~ 700 ?: ~ 690 ~ ~ 680.~ ¡ 670 W 660"' 640 630 620 610 600 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Time (24 hrs.) I-Non-Controi Days Oispatchable Days I Ilustration Five (Total PacifiCorp Hourly Idaho Loads (June+July): Schedule 72 Idaho Irrigation Load Control- Scheduled Forward Days vs. Non-Control Days) plots the total Southeast Idaho Service Territory average hourly interval load data for June and July. Data is segregated by the Scheduled Forward dispatch days (Monday thru Thursday inclusive) and non-dispatch days (Friday thru Sunday inclusive)18. Two important findings are revealed in these data. First, Friday and weekend loads are approximately 75MW less than Monday thru Thursday loads. This is not surprising but it does confirm what is typical for the Rocky Mountain Power system. Second, there is an approximate 25MW 'depression' on weekday afternoons during the control penod. This highly unusual pattern is unique to agricultural loads as residential and commercial loads are 'temperature-following' and would otherwise be expected to rise during the heat in the afternoon. This unique agricultural-pattern is likely the result of two culprits: (a) the six-hour Scheduled Forward dispatch block and (b) grower tendency to minimize water loss to evapotranspiration during the heat of summer afternoons by reducing, where possible, irrigation turns dunng those hours. 18 There were zero days in June where the Dispatchable reouræ was executed. Ergo, only Scheduled Foiward Dispatch Events are reported for this particular plot. 2007 Idaho Irrgation Load Control Program-Final Report Page 26 of41 Ilustration Five Total PacifiCorp Hourly Idaho Loads (June+July): Schedule 72 Idaho Irrigation Load Control-Scheduled Forward Days vs. Non-Control Days 750 525 725 700 675 ~'5650 ~Ë I" 8 625.~ lJo~ :E 600 wlJ 575 550 500 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Time (24 hrs,) Scheduled Forward Days Non-Ctrt Days I Ilustration Six (Total PacifiCorp Hourly Idaho Loads Comparing Schedule 72 + Schedule 72A to Non-Control Days) plots the total Southeast Idaho Service Territory average hourly interval load data for the first two-thirds of July. Data is segregated by the Scheduled Forward dispatch days (Monday thru Thursday inclusive) + Dispatchable dispatch days vs. non-dispatch days (Friday thru Sunday inclusive + 6 July which was a Dispatchable day and which fell on Friday). The results of these plots are somewhat confusing as we would have anticipated an additive drop in load when compared to the non-control days. It is likely that the less-than- remarkable difference is due to the fact that non-control days are only marginally higher than the control periods as a function of the naturally occurring reduction in Friday and weekend loads. Again, it is, at best, diffcult to draw conclusions on these data taking into consideration gnd vagaries, agricultural practices, meteorological considerations and on-going program operations when the entire Southeast Idaho load is considered. 2007 Idaho Irrgation Load Control Program-Final Report Page 27 of41 Ilustration Six Total PacifiCorp Hourly Idaho Loads Comparing Schedule 72 + Schedule 72A to Non-Control Days 760 650 750 740 730 720 710 î 700~ ~ 690 ~ 8 680.~ ~ 670 :2 w 660(/ 640 630 620 610 600 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Time (24 hrs.) Non-Ctrl Days Scheduled Forward + Dispatchable Days I Illustration Seven (Total PacifiCorp Hourly Idaho Loads Comparing July Total Schedule 72A (Dispatch able) to Non-Control Days) plots the total Southeast Idaho Service Territory average hourly interval load data for July. Data is segregated by the Dispatchable dispatch days vs. non-dispatch days (Friday thru Sunday inclusive). The results of these plots are interesting in that they indicate the effcacy of the dispatch able component to shift loads to shoulder and off-peak hours. Final note on SCADA plots: taking the previous six ilustrations into consideration the impact of irrigation load control is diffcult to deny. By the same token, using SCADA data it is diffcult, at best, to precisely determine the magnitude of its impact. At this point what can be provided is nominal data on what occurred. 2007 Idaho Irrgation Load Control Proram-Final Report Page 28 of41 Ilustration Seven Total PacifiCorp Hourly Idaho Loads Comparing July Total Schedule 72A (Dispatchable) to Non-Control Days 670 540 660 650 640 630 620 I 610 '" ~ 600 ~.~ 590 ~ 580 .i W 570(J 560 550 530 520 510 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 Time (24 hrs.) I-Non-Ctrl-Oispatchable I 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 72A upon which calculations are prepared are presented in Table Twenty-Three below19. 19 Again, to the extnt possible, costs have been allocated by the respectve Schedule initative 2007 Idaho Irrgation Load Control Program-Final Report Page 29 of41 Table Twenty-Three 2007 Benefit / Cost Categories & Values-Schedules 72 & 72A Cost Categories Administrative support Program evaluation Field / Equip / Db admin. expenses Participation credits Program management Reporting Cost Values $1,500.00 $2,268.75 $747,664.85 $1,752,930.47 $ 80,144.00 $0.00 $258450807 Benefit Category $/kW-yr avoided Benefit Value $49.56 Total As shown in Table Twenty-Four, the combined initiatives (Schedule 72 + Schedule 72A) pass the TRC, Utilty and Ratepayer Tests. The Program also passes the Participant Test. However, since the participant incurs no costs the benefit/cost ratio would be infinite. AccordinglyJor the Participant Test the value is indicated as 'N/A' in the Benefit/Cost Ratio column. Table Twenty-Four 2007 Cost-effectiveness Analyses Test Benefits Costs Net Benefits Benefit/Cost Ratio TRG......,....S4,.S,es,',?.1?....,.,._.._ ...........,..,..1S,?.1,,578 $4,Qe~!.S.~S......... ................,..._...........S"ee........._................................ ....~.i.i!~t~...................S4,.S,eS.,.?1..?.................................gSê.~!§Q~L_..__.__,J?!.?.1..!,ZQ~...........___..,.......J..:se..,.........._.__.............,...... ......._...._.....~~~~~.r....... $4,aee,.?1..?.. ,......,.."......gS.S,'.hS.QS, .._....,...............~?!.?1. ,704 _._____,.._.........1.&e_._._____........ ...__.. Parti~ipani....... .......J.1......_?.,.~_?.O,. ,.,""" "...,.....~Q,,9.Q,............................~1..52,g?.Q..____.._.._......___~~_____........,...., Conclusions & Recommendations The pilot Dispatchable initiative was positively received by the growers and significantly oversubscribed for the 2007 irrigation season. There were four factors that can be attributed to the favorable reception: 1. The fundamental value proposition / program design that permits growers to opt-out of Dispatch Events. Each and every one of the growers indicted that without the opt-out feature it is highly unlikely the pilot would have been positively received and participation would have continued to hover in the range of 50MW. The abilty to opt-out is central to receiving favorable grower acceptance and making the Dispatchable initiative work. 2007 Idaho Irrgation Load Control Program-Final Report Page 30 of41 2. Growers appear to have preliminarily concluded that high water use row crops (corn and potatoes) are not adversely affected (either quality or yield impacts) by participation in the Dispatchable program. The Irrigation Management Team wil continue to closely monitor grower perceptions relative to yield / quality impacts as it relates to program participation. 3. Fewer dispatch hours. If either quality or yield were affected by the Dispatch Events growers simply would not participate. As one grower indicated they can lose the entire participation credits in just a couple of bushels per acre less yield. The current program design appears to be much better tailored to agri- business needs and requirements and yet still provide grid benefits as measured by SCADA data. 4. Initiating and maintaining a local presence of agri-irngation / information systems specialists and irrigation equipment specialists to ensure the initiative's success. Throughout the pilot, growers continued to reassure Rocky Mountain Power of their commitment to stand behind the irrigation initiative as knotty technical issues and operational considerations required attention. Both the growers and the Irrigation Team understood that it would likely take three or more growing seasons until farm managers and growers alike were fully inculcated with the remote control irngation management systems and equipment. Providing skiled, local and professional resources on a 7 x 24 basis to train, council, instruct and / or troubleshoot problems as they arose was viewed as important as the technology itself. Growers indicated a favorable response to a joint (growers / Rocky Mountain Power) long-term partnership. Nearly all growers point to this partnership and commitment to technològy innovation as an important underpinning to program success. Based on the results and findings from the 2007 Irngation Load Control initiative Rocky Mountain Power advances the following four considerations as they relate to the 2008 effort and beyond. 1. The Dispatchable load control initiative should be a permanent offering in the portolio of grower participation options. As part of the settlement reached with the Idaho Irrigation Pumpers Association in the company's general rate case, Rocky Mountain Power wil modify the current tariff to reflect ongoing Program operation and a revised level of incentive credits. The tariff wil include the appropnate operational modifications gleaned from the 2007 pilot and agreed to as part of the stipulated settlement. 2. Due to (1) the difference in committed participation hours, (2) the inabilty to opt-out and (3) the availabilty of advanced control technology it is likely that very few, if any, growers wil participate in the Scheduled Forward initiative. Nevertheless, the choice to participate in this option should continue to be made available to growers at least through the 2008 irrigation season. The intent would be to evaluate the Scheduled Forward option at the conclusion of the 2008 season to determine its effcacy for subsequent program years. 3. Allow growers to participate year-over-year without having to re-sign-up each year. Allowing growers to participate without having to re-indicate their intent to participate would expedite operational considerations and allow the Irngation Team to prepare for the ensuing irrigation season in a more expeditious fashion. The current practice of having growers re-initiate their intent to participate in the Irrigation Load Control Program is awkward and confusing to growers and adds an administrative burden that could and should be removed to improve effciencies. 2007 Idaho Irrgation Load Contrl Program-Final Report Page 31 of41 4. Year-round operation. The magnitude (both scope and complexity) of the program requires practices and procedures beyond the efforts that have driven program design, development and implementation thus far. For instance, Rocky Mountain Power cannot reasonably expect to send notifications to growers by mid- January; receive response back by mid-February and have units fully installed and operationally ready by June 1. As noted above, Rocky Mountain Power received criticisms relative to timeliness of installs, customer service and program operations. The criticism was largely 'self-inflicted' as the Irrigation Management Team elected to expand the pilot beyond the onginal45 MW in an attempt to meet grower desire for participation. Implementing and managing over 100 MW employing a technology which requires a substantial change in established irrigation practices has and wil, for at least the next three years, remain a year-round effort as growers transition to new irrigation practices and habits. Moreover, using the advanced, remote 2-way technology requires Rocky Mountain Power to maintain an on-going relationship with growers, farm managers and ultimately participating pump / pivot sites throughout the irrigation season. Today, operational practices are radically different than in previous program years under a Scheduled Forward offering. For instance, initial and on-going training of the growers and of their farm managers in equipment use and operation requires significant effort that must continue if program operations are expected to be prudently implemented and robustly operated. Near-term operation of the Irrigation Load Control Program wil entail more hours for management, and additional outside resources for troubleshooting, training and customer service. Consequently, Rocky Mountain Power expects a 3x or more increase in delivery expenses over the next several years. Anticipated expense increases wil come from year-round staffng to meet work load requirements, conversion of the pilot to a permanent program, grower training along with the management of a much larger network. The Irngation Management Team wil, of course, continue to do everyhing possible to retard program delivery costs. While this transition wil be occurring over the next several years Rocky Mountain Power expects and is fully prepared to judiciously maneuver through the often not-so-clear complex operational changes to meet the challenges. Rocky Mountain Power also expects that changes may also be reflected in tariff considerations. As tariff-related issues anse Rocky Mountain Power wil bring them forward to the Commission for consideration. 2007 Idaho Irrgation Load Control Program-Final Report Page 32 of41 Attachment One Dispatchable Load Control Initiative Grower Questionnaire 2007 Idaho Irrgation Load Control Proram-Final Report Page 33 of41 Idaho Irrigation Dispatchable Load Control Initiative (IPUC Tariff 72A) My primary responsibility with this farm is as follows: (circle only one) 1. Farm owner I operator 2. Manager of individual farm managers 3. Farm manager 4. Administrative I office operations 5. Information technology I financial Program introduction I terms 'n conditions Select one option only How did you first learn about the Dispatchable program?Bob Brad I Ty Irrigation (circle only one)Smead (field Hot Line installers) Other For each question below check only a single box Middle Agree,...,Road . ........I._i~~_9!~~'.m' When first contacted, the Dispatchable program was explained so that I understood what was involved?0 0 0 I understood what would be required of me (grower) / farm 0 0 0 managers and/or office personnel? I understood what Rocky Mountain Power's responsibility 0 0 0 would be? Based on the information I was able to make an informed decision about my participation?0 0 0 Additional comments as they relate to Program introduction /terms 'n conditions 2007 Idaho Irrgation Load Control Program-Final Report Page 34 of41 Selecting and scheduling site installations For each question below check only a single box Middle .......~.g.r~,~,--Road Disagree _.._...._...................................... Appropriate information was provided in helping me to select participating sites?0 0 0 While i wasn't entire clear about which sites to include after a bit of further explanation I understanding i was able to 0 0 0 make an informed decision? i was kept abreast of when field installers would be 0 0 0 working on my irrigation equipment? Where required, the Rocky Mountain Power irrigation team worked with me in identifying and selecting participating 0 0 0 sites? The importance of pump site naming I identification and 0 0 0 how the softare would work? Where required, the reason for excluding certain sites was 0 0 0 described to me? When there were delays in getting units installed on my 0 0 0 equipment the reasons were explained? Additional comments as they relate to Selecting and scheduling site installations 2007 Idaho Irrgation Load Control Program-Final Report Page 35 of41 ~ ~ Field installation activities I processes For each question below check only a single box Middle Agree Road Disagree Field installers/electricians understood and respected farm practices as it relates to. . . Communicating which sites would be visited and D D D approximate times of those site installations? Knowledge of irrigation equipment?D D D Proper and safe treatment of equipment?D D D Removal of miscellaneous site debris (wire nuts, wire,D D D tape, etc) the site was left in a clean, orderly fashion? Proper and appropriate entry into and exit from fields D D D to access pivot / pump sites? Leaving the pump in the operational position that it was D D D prior to their working on the equipment? When there were problems troubleshooters were D D D dispatched in a timely manner? When i asked about how the control equipment worked i D D D was provided with a clear description? Troubleshooting problems and related problems with the control technology were quickly defined and explained to D D D me? Additional comments as they relate to Fie/d installation activities 2007 Idaho Irrgation Load Contrl Program-Final Report Page 36 of41 .. .. It 'Dispatch Event' operations For each question below check only a single box Middle Agree Road Disaaree The frequency (how often) 'Dispatches' were called were D D D what I was led to believe would occur? The duration of 'Dispatches' were what I was led to believe D D D would occur? Generally I was able to work within the frequency and D D D duration of 'Dispatch Events'? The time-of-day 'Dispatch Events' occurred (3:00p-7:00p)D D D were easily accommodated into my irrigation schedule? 'Day-ahead' notifications were sufficient to allow me to D D D adjust my water schedule? Notifications the 'morning-of' the 'Dispatch Event' were D D D helpful reminders? Had dispatches been executed in June I would have had to D D D 'opt-out' of a greater number of 'Dispatch Events'. Based on notification information I was able to make an informed decision about my participation in 'Dispatch D D D Events'? Having the ability to opt-out of 'Dispatch Events' gives me confidence that i am in control and wil likely participate in D D D the future if a dispatch option is offered? Additional comments as they relate to Dispatch Event operations 2007 Idaho Irrgation Load Control Proram-Final Report Page 37 of41 ., .. . Training For each question below check only a single box Middle Aaree Road Disagree The training on how to use the softare was helpful in 0 0 0 getting me knowledgeable on how the system works? Using the phone system to control irrigation sites was more 0 0 0 convenient than the Internet? Training materials / information was organized and 0 0 0 appropriate to meet my needs? During training my questions were answered and/or comments taken into consideration by those providing the 0 0 0 training? When i got stuck and called for support it was provided in a 0 0 0 timely fashion? Call center people could log-on and see what i was seeing and could appropriately respond to my questions and/or 0 0 0 direct me in what I needed to do as it relates to the softare... the phone? What changes would you like to see in the softare to made to make the user interface more accessible and easier to navigate? Additional comments as they relate to Training 2007 Idaho Irrgation Load Control Program.Final Report Page 38 of41 it_ .. M2M Control Equipment For each question below check only a single box Middle Agree Road Disagree Information was provided on how the equipment worked~0 0 0 After using the equipment for some time I am confident I 0 0 0 will gain additional confidence in its reliabilty? I believe I will use the equipment for the management of 0 0 0 my regular irrigation turns? The control equipment is a physically acceptable 'bolt-on'0 0 0 to the standard pump / pivot equipment? The 'Irrigation Hot Line' was helpful in answering questions 0 0 0 I had as they related to the equipment? Members of the irrigation management team were helpful 0 0 0 in answering questions I had as they related to the equipment? I found the web-site softare intuitive and easily 0 0 0 understandable? The phone system menu was easily negotiated?0 0 0 Additional comments as it relates to M2M Control Equipment 2007 Idaho Irrgation Load Contrl Program-Final Report Page 39 of41