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HomeMy WebLinkAboutAK Intertie Operating Committee 1991ALASKA INTERTIE OPERATING COMMITTEE WEDNESDAY,NOVEMBER 13,1991 (CHUGACH ELECTRIC ASSOCIATION TRAINING ROOM) MEETING MINUTES Present: James Hall Alaska Electric Generation &Transmission (AEG&T)/Matanuska Electric Assoc.(MEA) Afzal H.Khan Alaska Energy Authority (AEA)Stan Sieczkowski Alaska Energy Authority (AEA)Eric Marchegiani Alaska Energy Authority (AEA)Doug Hall Anchorage Municipal Light &Power (AML&P) Tom Lovas Chugach Electric Association (CEA) John Cooley Chugach Electric Association (CEA) Bob Orr Golden Valley Electric Association (GVEA)Marvin Riddle Golden Valley Electric Association (GVEA) The meeting was called to order by Chairman Tom Lovas at 9:45 a.m.at the ChugachElectricAssociationTrainingRoom,Anchorage,Alaska. Doug Hall moved that the IOC adopt the September 11,1991 meeting minutes withmodifications.Jim Hall seconded the motion.The motion was adopted unanimously.The modifications to the meeting minutes were as follows:first paragraph on page 3shouldread"The IOC briefly discussed the Kenai islanding.The CEA will island theKenaiareaonSeptember16,1991.An outage of the Alaska Intertie is scheduled simultaneously." The November 13,1991 IOC meeting agenda was modified by adding Item V (H),Teeland-Douglas T/L segment.The modified agenda was adopted unanimously. Under Dispatch,Marvin Riddle distributed the following: 1)Summary of Intertie Outages/System Disturbances 2)Alaska Intertie Operating Guides Marvin Riddle briefly discussed the above items. Under Protection Coordination,Afzal Khan stated that the subcommittee did not meet but he kept the subcommittee members informed on the load shedding study status.Afzal Khan also stated that he has received a letter from PTI regarding an estimate for completing Load Shedding Study.The PTI letter was distributed to subcommitteemembersforcomments.The comments were received from MEA and CEA (attached). The Protection Coordination subcommittee will meet after the Thanksgiving Dayholiday. Under the Machine/Rating Subcommittee,the IOC Chairman will write a letter toMachine/Rating Subcommittee Chairman. Under Reliability/Criteria,John Cooley distributed the September 19,1991 andOctober31,1991 meeting minutes and discussed them.There was a brief discussiononCaswellLakesroadcrossingguardstructureand138kVdisconnectswitchclosingdutyintoaload. 91Q4/1T2060(1) Intertie Operating Committee Meeting November 13,1991 Under Correspondence,IOC Chairman Tom Lovas stated that he received the following: 1)MEA letter,dated October 2,1991,regarding operation of switch 2S3 at the Douglas Substation. 2)MEA letter,dated October 25,1991,regarding switching of the AEAIntertieattheTeelandSubstation. Under Intertie Status,Eric Marchegiani provided an update on Intertie structure #749temporaryfixandGoldhillSubstationSVCBuildingroofmodification.Chairman TomLovasstatedthathehastalkedtobankeronwithdrawing$160,000 for SVC Buildingroofmodification. The Operating Committee took a break from 10:45 a.m.to 11:00 a.m. Stan Sieczkowski stated that he received a letter,dated September 24,1991,from IOCChairmanTomLovasregardingCaswellLakeRoadcrossingguardstructure(attached).Stan Sieczkowski also stated that the guard structure installation to guardthelineasrecommendedbytheIOCfortheCaswellLakesroadcrossingisnotacceptable.Stan Sieczkowski suggested the following:initially removing insulatorbellsfromthree(3)structures thereby increasing ground clearance during heavy snowloading;then fix the problem by installing an additional structure and reducing the sag.Chairman Tom Lovas stated that we need to consider 230kV operation.RemovingbellsfromstructuresisnotanacceptablesolutiontoIOC. No visitors were present. The Operating Committee went into work session. Under Dispatch,Chairman Tom Lovas stated that each IOC member needs to work with their Production/Generation group for obtaining the necessary information onmachineoutagesand/or data.In addition,the information associated with disturbances needs to be forwarded to area controllers. Doug Hall provided an update on problems caused by splitter valve on AML&P #8.Doug Hall stated that GE 1s looking into this problem.There was a brief discussion on Summary of Intertie Outages/System Disturbances. Under Protection Coordination,the discussion was focussed on the PTI Contract for the Railbelt Under Frequency Load Shedding Study.The subcommittee is to compilecommentsfromDavidBurlingameandStevenHaagensonregardingmissingitemsfrom the study.The Energy Authority will write to PTI regarding the comments andreaffirmearliercorrespondencedirectingPTItocompletethework. Under Machine/Rating,Chairman Tom Lovas stated that the Machine/Rating subcommittee should get back on proposed agenda of August 28,1991.The IOCChairmanwillwritealettertoSubcommitteeChairman. Under Reliability/Criteria,Jim Hall referred to his October 25,1991 letter to CEAconcerningtheavailabilityofCEApersonneltoperformswitchingoftheAEAequipmentattheTeelandSubstation.Chairman Tom Lovas stated that he will report back to IOC with results. 91Q4/1T2060(2) Intertie Operating Committee Meeting November 13,1991 Jim Hall stated that MEA objects to the operating procedures being applied in theoperationofswitch253byAML&P at the Douglas Substation.The Energy AuthoritywillwritealettertoAML&P advising on disconnect switch closing duty. Bob Orr stated that the MEA should continue investigation of insulator failures near theDouglassubstation.IOC would like to see that the failed strings be tested. Under Intertie FY93 Budget,Afzal Khan distributed the preliminary FY93 Budget forIOCreviewandcomments. Under T/L Structure and Conductor Evaluation,Chairman Tom Lovas stated that theEnergyAuthoritydoesnotwanttotakeactionontheissueofaguardstructureforthe Caswell Lakes road crossing of the Alaska Intertie. Chairman Tom Lovas recommends that the utilities update Intertie OperatingCommitteeanditssubcommitteesmemberlist. Under Formal Operating Committee Action/Recommendation,Bob Orr moved that MEA investigate and evaluate insulator flashover problem on Teeland-Douglas 138 kVline.Propose a staged fix and cost to correct by:1)installing additional insulators (9) when maintenance is done on the line;and 2)cost per tower to replace insulators in the suspected area.IOC expects MEA proposal for partial cost recovery through wheelingrates.Jim Hall seconded the motion.The motion was adopted unanimously. Bob Orr moved that IOC write a letter to Mr.Charlie Bussell,Executive Director, Alaska Energy Authority,about installing a guard structure for the Caswell Lakes roadcrossingoftheIntertieasrecommendedbytheAlaskaIntertieOperatingCommittee.Jim Hall seconded the motion.The motion was adopted unanimously. The IOC recommended that the Dispatch subcommittee provide some kind of referenceonthefrontpageoftheAlaskaIntertieOperatingGuidesasthisguideisrelatedto Alaska system.The IOC will consider for approval (Alaska Intertie Operating Guides) at the next IOC meeting. Under Subcommittee Assignments,Chairman Tom Lovas directed the DISPATCH subcommittee to meet at the discretion of its Chairman to work on:Dispatch TrainingPlan;maintenance response and communications coordination among the area utilities and Technical Guidelines for Operation,Metering and Protective Relaying for Non-Utility Power Producers and Cogenerators and develop operating guides to go withthem.In addition,the Dispatch subcommittee is to investigate switching and tagging procedures for IOC approval.Also Chairman Tom Lovas directed this subcommittee to propose a regular schedule of meetings to IOC. Chairman Tom Lovas directed the MACHINE/RATING subcommittee to meet at the discretion of its Chairman to continue work on the machine rating book.Also Chairman Tom Lovas directed this subcommittee to follow the proposed agenda of the MACHINE/RATING subcommittee memo dated August 15,1991. Chairman Tom Lovas directed the PROTECTION COORDINATION subcommittee to meet at the discretion of its Chairman to continue work on underfrequency loadsheddingstudy. 91Q4/1T2060(3) Intertie Operating Committee Meeting November 13,1991 THE NEXT REGULARLY SCHEDULED MEETING OF THE ALASKA INTERTIE OPERATING COMMITTEE WILL BE ON WEDNESDAY,JANUARY 8,1992,AT 9:30 A.M.AT THE ANCHORAGE MUNICIPAL LIGHT &POWER MAIN CONFERENCE ROOM. The Operating Committee set the agenda for the next meeting of the OperatingCommittee. The Operating Committee unanimously adopted the motion to adjourn at 2:00 p.m. Respectfully submitted,Meet li Afzal H.Khan Manager/Engineering Support Stanley E.Sieczkowski,SecretaryAlaskaIntertieOperatingCommittee Attachments: l. 2.January 8,1992 meeting agenda.IOC November 13,1991 meeting attendance sheet.. The following were distributed at the November 13,1991 meeting: 91Q4/1T2060(4) Summary of Intertie Outages/System Disturbances CEA letter to AEA dated November 9,1991 Subject:Railbelt Loadshedding Study MEA letter to AEA dated November 14,1991 Subject:Railbelt Loadshedding Study Reliability/Criteria Subcommittee September 13,1991 Meeting Minutes.Reliability/Criteria Subcommittee October 31,1991 Meeting Minutes. MEA letter to IOC Chairman Tom Lovas dated October 2,1991. Subject:Operation of Switch 2S3 at Douglas Substation. MEA letter to IOC Chairman Tom Lovas dated October 25,1991. Subject:Switching of the AEA equipment at the Teeland Substation. IOC Chairman Tom Lovas letter dated September 24,1991 Subject:Caswell Lake Road Guard Structure Power Technologies,Inc.letter dated November 6,1991 Subject:Estimate for Completing Load Shedding StudyAlaskaIntertieOperatingGuides ALASKA INTERTIE OPERATING COMMITTEE MEETING AGENDA WEDNESDAY,JANUARY 8,1992 BEGIN AT 9:30 A.M. I.Adoption of prior meeting minutes IL.Approval/modification of agenda III.|Committee correspondence and reports: Dispatch SubcommitteeProtectionCoordination Subcommittee Machine/Rating SubcommitteeReliability/Criteria SubcommitteeCorrespondenceReceivedIntertieStatusUpdateReportingRequirementsOMMUND>IV.'Visitors comments related to items on agenda Vv.Work Session: T/L Structure and Conductor Evaluation Reporting RequirementsTeeland-Douglas T/L ProblemCaswellLakesRoadCrossing A.Recess and work session B.DispatchCc.Protection Coordination D.Machine/Rating E.Reliability/CriteriaF.FY93 BudgetG. H. I. J. VI.'Formal Operating Committee action/recommendation Vil.Subcommittee Assignments VIII.Determine agenda for next meeting IX.Adjournment Next meeting location: Anchorage Municipal Light &PowerMainConferenceRoom 1200 E.First Avenue Anchorage,Alaska 99501(907)279-7671 91Q4\JD2021(1) ALASKA INTERTIE.OPERATING CORAITTEEHEETING In Attendance:Date Nov.13,9 Nane LONpAny Phone No, Wiat /mall JAS (ted MES EY & John Csetec,CE rk hz ¥S77 Poop ad ae Buon #retiy Yu Hall Me fP 26%-sfS3 ER Marcheyrr AE 56/-7 222 Sti Sreckuk|GAZ SOl-7&77 BIB FEA CVE OC?352 -SS Jif zal Le Kha n AEA 366-777 ewes D.Hall AEGET 245-C264 SUMMARY OF INTERTIE OUTAGES/SYSTEM DISTURBANCES April 1991 -October 1991 April 9,1991 At 1600 hours AMLP unit #8 tripped with 77 MW's load.GVEA shedfirststageunderfrequencyofapproximately10MW's plus 4 MW's ofFMUSload.The problem was traced to loss of water regulator,whichcausedatemperaturedifferentialtrip. April 25,1991 At 2218 hours AMLP units 6 and 7 tripped,caused by earthquake.Intertie was isolated for work at Ester Substation.Healy andCantwellsubstationsloadshedonunderfrequency. May 10,1991 At 1512 hours CEA had the Pt.MacKenzie/Beluga 230 KV line relayopen.In addition,one Beluga 230 KV breaker was out of service for maintenance so when the fault occurred (due to losing a tower on theoneline),both 230 KV circuits were out of service. Indication at CEA showed a single phase to ground fault so a test of the line was attempted.This caused the Alaska Intertie breakers at Teeland and Douglas to open. There was no indication of what tripped the intertie breakers, although the power swing was extreme and likely an out of step condition occurred. AMLP had units 7 and 8 in service with a combined load of 98 MW's. GVEA had Healy with 27 MW's of load,Zehnder GT #1 with 15 MW's ofload,Chena 3 and 5 at FMUS were on with 22 MW's of load on them. June 7,1991 At 1500 hours AMLP unit #7 tripped.The trip also resulted in lossofthesteamunit#6.Unit #7 had 66 MW's of load on it,unit #6 had 23 MW's of load on it. GVEA had the Healy unit in service with 26 MW's of load,FMUS hadChena3and5inservicewith3MW's and 20 MW's on them.The problem was caused by failure of an electric solenoid in the hydraulic system which caused the fuel valve to close. AMLP also found a problem in unit #8 governor circuit that caused it not to respond during the disturbance. CEA had Beluga units 3,5,6,and 7 with a total load of 237 MW'sBerniceLakeunit#3 was in service with 8 MW's and both Eklutna units were in service with 16 MW's on each. Summary of Intertie Outages/System DisturbancesApril1991-October 1991 Page 2 The system frequency decayed enough to shed two levels ofunderfrequencyinFairbanksforatotalof12.3 MW and one level atCEA/AMLP in Anchorage for a total of 40 MW. The poor performance of the spinning reserve was probably due mostlytothegovernorproblemonAMLPunit#8 as described above. June 26,1991 At 0318 hours AMLP units 6 and 7 tripped due to control conductorfailure.No load was shed. June 26,1991 At 0829 hours AMLP unit 8 tripped.Not part of relay test.No loadwasshed. July 9,1991 At 1312 hours AMLP units 6 and 7 tripped.No load was shed. July 30,1991 Two Cooper Lake units tripped,and at the same time indication was received by the CEA Dispatcher that the gas supply to Bernice Lakewasbeinglost.The CEA Dispatcher requested manual load shed togivehissystemrelief.GVEA manually shed 18 MW's to accommodateCEAuntiladditionalpowerwasavailablefromAMLPandZehnderGT's. August 28,1991 Beluga #7 tripped,causing loss of half load on Beluga #8 steamunit.Total loss of generation was 85 MW's. Approximately 20 MW's of load was shed on underfrequency.Thefrequencyrecoveredto59.8 HZ and a Zehnder unit was started.The Dispatchers started to restore load when the CEA SCADA (AGC)systemmalfunctionedandstartedunloadingtheCEAunitsonline.This time Bradley unit 1 tripped and the system frequency collapsed. GVEA shed load manually and started two Zehnder GT's and diesels to help restore interconnect frequency. GVEA-FMUS shed 30 MW's of load,started two Zehnder GT's and two diesels.This zeroed the intertie and shipped approximately 18 MW'ssouthtoassistinsystemfrequencyrecovery. August 19,1991 AMLP unit 7 tripped,which also caused unit #6 (steam unit)to trip.GVEA-FMUS shed first level underfrequency approximately 18 MW's.The unit was tripped by operator error,killing control power tounitaccidentally. Summary of Intertie Outages/System DisturbancesApril1991-October 1991 Page 3 September 27,1991 Transmission line fault at tower 94N (according to SEL relays)caused Teeland 538 and Douglas Bl to open.GVEA shed 40 MW's”that were on the intertie.Problem insulator flashover appears to be thecause.1§ground fault bad string found at tower 96. September 30,1991 AMLP unit 8 tripped.One GVEA substation shed on underfrequency.Cause of the trip was splitter valve. October 1,1991 Teeland-Douglas line relayed (see indication 19 ground).Badinsulatorsfoundattower96andreplaced.The disturbance causedAMLPunit8totrip,Teeland 230 KW breakers 4510 and 4610 also tripped.GVEA and FMUS shed 45 MW's of load. October 2,1991 AMLP unit 8 tripped.Load on the unit at time of the trip was 36MW's.Problem was found to be splitter valve problem on unit.GVEA and FMUS shed 8 MW''s on first stage underfrequency. October 11,1991 AMLP unit 7 tripped which caused unit 6 (steam unit)to trip.Totalloadonthetwounitswas100MW's.The trip was caused by acontractordiggingintorelaycircuitsfromunit7step-uptransformer.GVEA shed 3.8 MW's of first stage underfrequency.AMLP shed 11 MW on underfrequency.CEA also requested GVEA to zerotie,which was accomplished by starting Zehnder frame 5's. October 12,1991 AMLP unit 7 tripped which caused unit 6 (steam unit)to trip.Loadontheunitswas72MW's.GVEA shed 12.4 MW's on underfrequency.AMLP shed 8.1 MW's on underfrequency.The trip was caused by AMLPmaintenancemanpushingwrongbutton,tripping the unit. October 13,1991 CEA Beluga unit #8 tripped,at the same time Eklutna #2 tripped.GVEA shed 6 MW's on first stage underfrequency relays. October 14,1991 Teeland-Douglas line relayed.Distance indication was inconclusiveonSELrelays,but showed B and C §to ground fault.GVEA-FMUS shed47MW's of load.Suspect snow covered tree went through line (wetandheavysnowstormonsouthend). Summary of Intertie Outages/System DisturbancesApril1991-October 1991 Page 4 October 22,1991 Teeland-Douglas line relayed.Indication was CQ ground faultapproximately20milesnorthofTeelandand6milessouthofDouglas.Bad insulators were found at towers 94-96.GVEA and FMUS shed 37 MW's. October 26,1991 AMLP unit #8 tripped,caused by high fuel splitter pressure.GVEA shed 8 MW's on underfrequency relays.The CEA dispatcher then askedustomanuallyshedsotheycouldrecoverfrequency.GVEA manually shed an additional 13 MW's. CHUGACH ELECTRIC ASSOCIATION,INC. Anchorage,Alaska November 9,1991 TO:Afzal Khan,Alaska Energy Authority FROM:David W.Burlingame,Manager,Facilities Engineering SUBJECT:Railbelt Loadshedding Study I've attempted to review PTI's original letter several times but could never make it through to the end.Can you provide a brief synopsis of the PTI letter including a comparison of what is required in the contract. Some specific items which come to mind are: When did PTI review relay types,breaker operating times andloadsheddinglevelsdifferentthanwhatisexisting? When did PTI submit alternatives to existing system,and what is their recommended alternative? When did PTI address the question of system separation? When did we get the 10 cases to be specified by the utilities? When did PTI address shedding at different frequency levels asopposedtotheexisting? When did PTI address loadshedding levels in the different areas different than existing? What was the meeting when PTI came up to Anchorage and submitted the results of some of their studies?Who changed their directionafterthatmeeting?Did you accept any of their reports asfulfillingcontractualobligations? Some other Subcommittee members may have more ideas. I think it would be beneficial to have your review completed priortoThanksgivingwithaSubcommitteemeetingshortlythereafter. cc:Steve Haagenson -GVEA Larry Hembree -ML&P Jim Hall -MEA Sam Matthews -HEA ALASKA INTERTIE OPERATING COMMITTEE Reliability/Criteria Subcommittee MEETING MINUTES September 19,1991 Meeting at Chugach Attendees:John Cooley,-CEAJimHall,MEA Larry Hembree,ML&P Afzal Khan,AEA Jim Smith,GVEA The proposed guard structure for the Caswell Lakes road crossing was discussed.The desired guard structure was a grounded guy wire supported over the road connected to multiple ground rods and the nearest structure ground which would fault the line and remove the Intertie from service before it endangered vehicles on the road.A motion torecommendsuchastructurewaspassedunanimously.The chairman is to pass this recommendation on to the IOC chairman for action. The proposed reactor installation at Douglas was discussed.MEA had madea preliminary investigation of installing a reactor on the 24.9 kV bus at Douglas.The preliminary cost estimate was $125,000 for a 7 MVA reactor.Chugach is to run the PSS/E program to estimate the required reactor size needed to keep voltages in line on energization of the Intertie from Healy.AEA is to obtain a price estimate from PTI to conduct a study to determine the voltage transient when using MEA customer load to reduce the voltage to allow starting the Teeland SVS from the North.GE's recommendation was to use load but the subcommittee was not comfortable with GE's recommendation.The study could eliminate the need for a reactor,but if not,would not add significantly to the cost.The price estimate was to be provided for the next meeting. Disturbance reporting and evaluation was discussed.A consensus was reached to required reporting of disturbances which met the following definition: "A Reportable disturbance is (1)the tripping or loss of any generator carrying load;or (2)the tripping of a transmission line which islands generation or causes loss of load.” A control center should be assigned the duty,rotated on an annual basis,to assign sequential disturbance numbers and descriptions such as "91-001 Trip of Beluga-MacKenzie Circuit #2"to the disturbances as they occur.This control center would be required to forward the list of disturbances to the IOC at each meeting.The dispatchers should make an initial review of the disturbance to verify if the system acted as they expected.If not, they would start an investigation into the disturbance.The IOC should review the list, compare with the reports submitted by the Dispatch Subcommittee,and could order investigations for those disturbances which they felt were significant but had not been previously studied. The next meet was scheduled for 1:00 PM on Thursday,October 24,1991 at Chugach in the Production conference room. 3142.JSC/ts File 505.1.6,RF Z ka Electric>MatanusCAAssociation,Inc. oO P.O.Box 2929 Palmer,Alaska 99645 Telephone:(907)745-3231 Fax:(907)745-9328 November 14,1991 Mr.Afzal Khan Alaska Energy AuthorityP.O.Box 190869 Anchorage,AK 99519-0869 Dear Afzal, It appears to me that PTI does not want to bear any of the burden for not producing asatisfactoryloadshedstudy.There clearly is a difference of opinion as to why the studywasflawed.We believe that PTI was at least partly responsible.We appear unable togetthentomoveatallonthismatterandtheyintendtoessentiallystartover. We,therefore,believe that we should consider the use of another consultant especially ifthatconsultantcouldusethemodelthatexists,perhaps through one of the utilities.[fete Cid”James D.Hall Project Engineer edes469jdh ..4PIIIATEYG ALASKA INTERTIE OPERATING COMMITTEE Reliability/Criteria Subcommittee Meeting Minutes October 31,1991 Meeting At Anchorage ML&P *y "y Attendees:while.Jim Smith,GVEA John Cooley,Chugac sLarryHembree,MLP Afzal Khan,AEA - Jim Hall,MEA Doug Hall,MLP The proposed reactor installation at Douglas was discussed.The voltage study showed that Teeland open end voltage should be 150 KV with 138 KV at Healy.During the last test,starting problems were not evident with Teeland voltages below 151 KV.MEA also reported that with the installation of SCADA control of Douglas feeder breakers,they could energize the station transformer,run the tapchangerdownandthenclosefeederbreakerswithoutsubjecting their customers to excessive over voltages.A consensus was reached that no further action is required to allow the Teeland SVS to be started from the North. Switch 2S3 at Douglas was discussed.AEA had previously directed MLP not to use the switch to energize or de-energize the Teeland- Douglas line.The switch is not a load-break switch and does not have any whips.AEA is to determine the ratings of the switch. MEA will investigate the installation of whips on the switch.AEA will investigate the technical feasibility of using the switch to energize the line and if feasible,so direct MLP. Afzal reported that AEA has received the letter from the IOC chairman requesting the installation of a guard structure at the Caswell Lakes crossing.Stan is still evaluating the request. Afzal also reported that AEA is having PTI investigate the feasibility of installing a capacitively coupled battery charging device on the intertie.The battery charger would charge batteries which in turn would be connected to a 150-200 KW Ac invertor to supply McKinley Village.This is being investigated as an alternative to GVEA extending its distribution line about 23 miles. 3215.J3SC/1mb 505.1.6,RF Q)Oo Oo Y en [MU/L S[re Matanuska Electric Association,Inc. P.O.Box 2929 ee ee Palmer,Alaska 99645 . - Telephone:(907)745-3231 CL.ae Costes,Fax:(907)745-9328 'g kele ve ' October 2,1991 Mr.Tom Lovas,Chairman Intertie Operating Committeec/o Chugach Electric AssociationP.O.Box 196300 Anchorage,AK 99519-6300 Dear Mr.Lovas: Matanuska Electric Association,Inc.(MEA)objects to the operating procedures beingfollowedbyAnchorageMunicipalLightandPower(AML&P)in the operation of switch2S3attheDouglasSubstation. Their refusal to allow this switch to be used to energize the 138 KV line from Douglas toTeelandhascausedanunnecessaryoutagetothe1,064 MEA customers who are servedfromtheDouglassubstation. This motor operated disconnect switch must be rated for fault closing duty as are mostsuchswitches.The fault duty at this location is very minimal due to the largeimpedanceoftheonehundredseventyfivemilesoflinebetweenDouglasandHealy.Standard utility practice allows use of group operated switches for line closing.If theexistingswitchcannotbeusedtoenergizetheline,then it must be replaced with a devicecapableoflineclosingduty. We strongly urge the Intertie Operating Committee to take the necessary action toclearlydirectAML&P to modify their operating procedures to allow the use of switch2S3forlineclosing,and to further direct them to use the switch for line closing in thefuturewheneversuchactionisrequestedbyMEAtopreventunnecessaryoutagetoits customers. Sincerely,SapJamesD.Hall Projects Engineerand Alternate Member Intertie Operating CommitteeforAlaskaElectricGeneration and Transmission JDH:BB 451EDES CC:Bob Orr,GVEA;Doug Hall,AML&P;Sam Mathews,HEA;Larry Colp,FMUS;Afzal Kahn,AEA;Ken Ritchey,MEA;Bob Mau,MEA;Bob Hufman,AEG&T ®)Matanuska Electric BOOTHi=nAssociation,Inc.- 2 P.O.Box 2929 wakes RAE Palmer,Alaska 99645 AneaoTagch Telephone:(907)745-3231 Fax:(907)745-9328 October 25,1991 Tom Lovas,Chairman Toc c/o Chugach Electric Assocaition P.O.Box 196300 Anchorage,AK 99519-6300 Dear Ton, We have recently experienced some scheduling problems concerning the availability of CEA personel to perform switching of the AEA intertie at the Teeland Substation.We would encourage consideration of the use of MEA personel to perform these switching procedures when they are required in conjunction with line work being performed by MEA personel.If this is not possible then consideration should be given to the use of disconnect switch TD100,or TD101 near Hollywood Road to establish the visually open required for a line clearance.This type of procedure would result in much greater efficiency and less travel and standby labor.It could also prevent coordination problems,and thereby prevent additional lost time, and aid in more rapid restoration of service on the Intertie. Your consideration of this matter is appreciated Sincerely,ww &Let James D.Hall Projects Engineer 462EDES cc:Bob Orr,GVEA Doug Hall,AML&P Sam Matthews,HEA Bob Hufman,AEG&T Afzal Khan,AEA Larry Colp,FMUS CHUGACH ELECIRIC ASSOCIATION,INC. amci September 24,1991 Alaska Energy Authority ee P.O.Box 190869 oe Anchorage,Alaska 99519-0869" Attention:Mr.Stan Sieczkowski,Director Facilities Operations and Engineering Subject:Caswell Lake Road Guard Structure Dear Stan: At the most recent Alaska Intertie Operating Committee meeting,the issue of a guard structure proposed for the Caswell Lakes road crossing of the Alaska Intertie was referred to the Reliability/Criteria Subcommittee.The Subcommittee met and recommended that AEA have installed a guy wire supported over the road.The preference was for a grounded guy wire connected to multiple ground rods and the nearest structure ground which would fault the line and remove the Intertie from service.An alarm mechanism which would permit the operator to remove the line from service without faulting the line is acceptable; however,the subcommittee had no recommendation on such a mechanism.Faulting the line was considered preferable to having an unknown hazard continue. I have subsequently contacted each of the Intertie Operating Committee representatives and have received each Participants'concurrence for the recommended course of action.The estimated cost of the structure is between $3,000 and $5,000. At the next IOC meeting,scheduled for November 13,1991 at Chugach,we would appreciate a progress report on the installation of the guard structure. Sinc gly, CMe Thomas A.Lovas,Chairman Intertie Operating Committee Sar 3143.TAL/ts "py! ce:Larry Colp,FMUS ous ieJohnCooley,CEA David Gerdes,FMUS Doug Hall,ML&P Sam Matthews,AEG&T Bob Orr,GVEA BANA Minnacntan Deca 2 RR ann POWER TECHNOLOGIES,INC. FACSIMILE TRANSMISSION One Sierragate Plaza Suite 340B Total Pages:2 Roseville,CA 95678 Fax #:(916)783-2086 Tel #:(916)783-3566 TO ;:Afzal Khan FROM:John Doudna DATE;November 6,1991 SUBJECT:Estimate For Completing Load Shedding Study Ss I have not had sufficient time to prepare a detailed study scope and estimate for completion of the Railbelt Load Shedding Study.However,I have briefly summarized below what I feel is a reasonable estimate. This estimate is in large part based on the estimate (man-hours)which we provided for the original study.Depending on the IOC's perspective as to the status of the study and the work yet to be done,I essentially see us expending the same effort outlined for Tasks 2 through 5 for the original study.Further,based on the results observed for the study of this last sammer's disturbance events,I envision some work to "clean up"and resolve of some questions about governor responses.I was not expecting there to be much model updating or development,but I learned from discussions last week with Steve Haagenson that there will be some modifications necessary in the Fairbanks area due to relay changes &equipment additions. -NOoOY-6-91 WED 17:58 PTI Po Thercfore,following is a very rough estimate for completion of the load shedding study: Task 1 -Develop base case models from latest data base and update dynamics data to agree with changes in system.(2 days) Task IA-Obtain detailed information about governor limitations &operating constraints and validate model response against the July 20,August 3 and August 5 Railbelt disturbance events.(3 days) Task 2 -Simulate response of existing system.(5 days) Task 3 -Select load shedding options &simulate system response with these options applied.(7 days) Task 4 -Select best alternatives.(4 days) Task 5 -Prepare report.(7 days) The above work totals 28 days.I expect the majority of this will be done after the first of the year at our new rates for 1992 (see attached Policy FIN-2). Excluding any costs for travel &living expenses or meeting time (I am assuming such things can be scheduled to coincide with Bradley Project meetings),but including expected computer costs,I estimate the cost to complete the study to be $32,500. Please advise if you have any questions.As I noted to you earlier,I will be on vacation until Wednesday,November 13. VAC Matanuska Electric Association,Inc. P.O.Box 2929 RECEIVED Palmer,Alaska 99645 Telephone:(907)74473231Fax:(907)us.9328 |29 1991 wiasxa Energy Authority®October 25,1991 Tom Lovas,Chairman roc c/o Chugach Electric Assocaition P.O.Box 196300 Anchorage,AK 99519-6300 Dear Ton, We have recently experienced some scheduling problems concerningtheavailabilityofCEApersoneltoperformswitchingoftheAEA intertie at the Teeland Substation.We would encourage consideration of the use of MEA personel to perform these switching procedures when they are required in conjunction with line work being performed by MEA personel.If this is not possible then consideration should be given to the use of disconnect switch TD100,or TD101 near Hollywood Road to establish the visually open required for a line clearance.This type of procedure would result in much greater efficiency and less travel and standby labor.It could also prevent coordination problems,and thereby prevent additional lost time, and aid in more rapid restoration of service on the Intertie. Your consideration of this matter is appreciated Sincerely,a)"of /Vows O Let //James D.Hall Projects Engineer 462EDES CC:Bob Orr,GVEA Doug Hall,AML&P Sam Matthews,HEA Bob Hufman,AEG&T Afsat:Ria,REX Larry Colp,FMUS GB Matanuska Electric Association,Inc. P.O.Box 2929 RECEIVED Palmer,Alaska 99645 Telephone:(907)745-3231 ek VAGFax:(907)745-9328 ' . October 23,1991 Mr.Stanley E.Sieczkowski,DirectorFacilitiesOperations&EngineeringAlaskaEnergyAuthorityP.O.Box 190869 701 East Tudor Road Anchorage,Alaska 99519-0869 This is written in reference to your letter of August 16,1991 to Mr.J.F.McIntoshconcerningtakinginventoryoftheTalkeetnastorageyardforIntertiematerial. Although I certainly agree that this material needs to be sorted,inventoried andcategorized,it was impossible for us to complete the project this fall.We had ashortageofmanpowerandanunexpectedlyheavyconstructionseason.Thosefactors,coupled with our own annual physical inventory and a major power outagemadecompletingtheTalkeetnayardanunattainablegoal. I intend to schedule this project for as early as possible in the spring,and I willkeepyouinformedoftheexactdatesassoonasweareabletodeterminewhentheweather_will permit us to start.1 af ogize for the4[edad |Wa OsbornChiefofMaterials Management ce:J.F.McIntosh Tom Hocking 205.C_9U0Z3,4 Movicheere ve [harlie3fe;ws - Cre}:jl <>Matanuska ElectricAssociation,Inc. P.O.Box 2929 Palmer,Alaska 99645 Telephone:(907)745-3231 Fax:(907)745-9328 r "17 {i yi EDOctober2,1991 - '7 V99! a arity Mr.Tom Lovas,Chairman ee Intertie Operating Committeec/o Chugach Electric AssociationP.O.Box 196300 Anchorage,AK 99519-6300 Dear Mr.Lovas: Matanuska Electric Association,Inc.(MEA)objects to the operating procedures beingfollowedbyAnchorageMunicipalLightandPower(AML&P)in the operation of switch2S3attheDouglasSubstation. Their refusal to allow this switch to be used to energize the 138 KV line from Douglas toTeelandhascausedanunnecessaryoutagetothe1,064 MEA customers who are servedfromtheDouglassubstation. This motor operated disconnect switch must be rated for fault closing duty as are mostsuchswitches.The fault duty at this location is very minimal due to the largeimpedanceoftheonehundredseventyfivemilesoflinebetweenDouglasandHealy.Standard utility practice allows use of group operated switches for line closing.If theexistingswitchcannotbeusedtoenergizetheline,then it must be replaced with a devicecapableoflineclosingduty. We strongly urge the Intertie Operating Committee to take the necessary action toclearlydirectAML&P to modify their operating procedures to allow the use of switch2S3forlineclosing,and to further direct them to use the switch for line closing in thefuturewheneversuchactionisrequestedbyMEAtopreventunnecessaryoutagetoits customers. Sincerely, Y/James D.HallProjectsEngineer and Alternate Member Intertie Operating Committee _for Alaska Electric Generation and Transmission JDH:BB 451EDES CC:Bob Orr,GVEA;Doug Hall,AML&P;Sam Mathews,HEA;Larry Colp,FMUS;Afzal Kahn,AEA;Ken Ritchey,MEA;Bob Mau,MEA;Bob Hufman,AEG&T State of AlaskaNWaltersmickel.Governor Alaska Energy Authority A Public Corporation October 1,1991 Mr.Robert aad OManagerofSystems ration P.O.Box 71249 PeFairbanks,Alaska 99707-1249 Subject:Anchorage-Fairbanks Intertie Goldhill Substation SVC Control BuildingShell Addition Dear Bob: Please reference recent conversations with you and your staff concerning the aboveproject.We have reviewed the information provided by your staff and concur withtheirrecommendationtomoveforwardandawardtheBuildingShellAdditionContracttoNorconatabidpriceof$159,012.We have coordinated this with Mr.Lovas (Intertie Operating Committee Chairman).The SVS reserve fund will beusedtofundthisproject.Please continue to coordinate with us while the Contractoriscompletingthisproject. If you have any questions,please call me at 561-7877. Sincerely,Hee.Wh.LoonAfzalH.Khan Manager/Engineering Support AHK:skb cc:Sta E.Sieczkowski,Alaska Energy AuthorityErichegiani,Alaska Energy AuthorityWilliamSobolesky,Alaska Energy AuthorityTomLovas,Intertie Operating mmittee ChairmanGregWyman,Golden Valley Electric Association [PO.Box AM Juneau,Alaska 99811 (907)465-3575BYPO.Box 190869 704 East Tudor Road =Anchorage,Alaska 99519-0869 (907)561-7877 91a4&kh 162/11 CHUGACH ELECTRIC ASSOCIATION,INC.ach ¥Cikinc xED :ae p;September 24,1991 Alaska Energy Authority me P.O.Box 190869 So Sac Anchorage,Alaska 99519-0869" Attention:Mr.Stan Sieczkowski,Director Facilities Operations and Engineering Subject:Caswell Lake Road Guard Structure Dear Stan: At the most recent Alaska Intertie Operating Committee meeting,the issue of a guard structure proposed for the Caswell Lakes road crossing of the Alaska Intertie was referred to the Reliability/Criteria Subcommittee.The Subcommittee met and recommended that AEA have installed a guy wire supported over the road.The preference was for a grounded guy wire connected to multiple ground rods and the nearest structure ground which would fault the line and remove the Intertie from service.An alarm mechanism which would permit the operator to remove the line from service without faulting the line is acceptable; however,the subcommittee had no recommendation on such a mechanism.Faulting the line was considered preferable to having an unknown hazard continue. I have subsequently contacted each of the Intertie Operating Committee representatives and have received each Participants'concurrence for the recommended course of action.The estimated cost of the structure is between $3,000 and $5,000. At the next IOC meeting,scheduled for November 13,1991 at Chugach,we would appreciate a progress report on the installation of the guard structure. Sine rgly, MMM Thomas A.Lévas,Chairman Intertie Operating Committee "Sar 3143.TAL/ts "py! ce:Larry Colp,FMUS OMS jieJohnCooley,CEA David Gerdes,FMUS Doug Hall,ML&P Sam Matthews,AEG&T Bob Orr,GVEA 5401 Minnesata Mriva a DM DAL ansran + iN Alaska Energy Authority 4 2Uolic Corocrarer September 13,1991. Hyundai Heavy Industries Co.,Ltd.1 Cheonha Dong Ulsan,Korea Subject:Anchorage Fairbanks Intertie,Structure Modifications Dear Sir: The Intertie has been operational for almost seven years and recently we haveexperiencedextremelyheavysnowandiceloadingontheline.This has caused a numberofphasetogroundfaults.Recent investigations indicate that one possible solution to thisproblemwouldbetoremovethestaticwirefromthestructuresinthesouthernportionoftheline(for approximately 12 miles)where this problem appears to be the worst. Therefore,our question is:if the static wire is removed,will there be any structuralproblemswiththetowers,and should the static wire support arm (goatheads)be left inplaceorremoved. One other solution which has been considered is the possibility of reducing the number ofbellinsulators,such that the line would only be insulated for 230 kV rather than the 345kVitwasoriginallydesignedfor.Would this modification adversely affect the structuresintegrity.If not,are there any precautions that should be taken in the process of makingthismodification. We request you provide an answer or contact Afzal Khan or myself within 30 days ofreceiptofthisletter.If I do not hear from you within this timeframe,we will assume thattherewouldnotbeanyproblemwithmakingtheabovesuggestedmodifications.We canbereachedat(907)561-78777 in Anchorage,Alaska.Thank you for your attention to this matter. Sincerely, Stanley E.ES s aeFacilitiesOperations&Engineering EAM:SES:it cc:Tom Lovas,Chugach Electric AssociationJohnCooley,Chugach Electric AssociationTimMcConnell,Anchorage Municipal Light &PowerDougHall,Anchorage Municipal Light &PowerJimHall,Matanuska Electric Association Afzal Khan,Alaska Energy AuthorityEricMarchegiani,Alaska Energy Authority =PO.Box AM Juneau,Alaska 99811 (907)465-3575MPO.Box 190869 §=704 East Tudor Road Anchorage,Alaska 99519-0869 (907)561-7877 91Q3\IT1576(1) --_"\ POWER TECHNOLOGIES,INC.ONE SIERRAGATE PLAZA SUITE 3408 ROSEVILLE.CA 95678 916 783-3566 TELEFAX 916 783-2086 TELEX 145498 October 3,1991 Mooi Mr.Afzal Khan PN Alaska Energy Authority ee,P.O.Box 190869 ve Anchorage,AK 99519-0869 passe ee Dear Afzal: RE:August 15,1991 letter from the IOC,signed by Stanley E.Sieczkowski concerning the Railbelt Load Shedding Study We have reviewed the subject letter.It is apparent that the status of the study from the view of the IOC is considerably different from the status as viewed by PTI.There appears to be a considerable difference of opinion as to work performed under the original contract and the work which remains to be done.We have attempted to address these issues in this letter,although it is a rather lengthy dissertationin an effort to make this response complete.In addressing theseissues,we have referenceditemsinthesubjectletter. The second and fourth paragraphs in the subject letter indicate that the IOC believes that only Task 1 of the original proposal has been completed.The work done by PTI and documented in the November 8,1989 draft report has advanced well into Task 3.Furthermore,the second paragraph of the subject letter implies that the kind of study we performed for the August 29,1990 disturbance event was part of Task 1 under the original proposal.Task 1 did not include or contemplate such a detailed study.Task 1 was limited to a kick-off meeting,data collection and data base assembly,and data "sanity"checks using automated data checking routines in PSS/E. These items were completed according to the proposal. The third paragraph we find to be confusing and somewhat contradictory.It acknowledges that PTI submitted base cases which were derived from loading and unit dispatch scenarios provided by the utilities.But,it then states that the base cases developed as part of Task 1 were not submitted for approval prior to proceeding with the study.However,it then indicates that the IOC acknowledges that work using the base cases was authorized.The last item references data changes made after the completion of the Railbelt machine tests.Response to the issues raised in the third paragraph may be best addressed by reviewing the chronological events of the study process and related activities. Concerning the data base preparation and review process,the sequence of events is a fairly well documented in our files.At the August 7,1989 kick-off meeting,the CORPORATE OFFICES©1482 ERIE BOULEVARD ©PO.BOX 1058 ¢SCHENECTADY,NY 12301-1058 ©518 374-1220 --_"\p> Page 2 Mr.Afzal Khan October 3,1991 data to be supplied by the utilities was discussed (see Harrison's meeting notes faxed to you on August 8,1989).The required data changes discussed included power flow data necessary to update PTI's Railbelt model,the load and generation dispatch data to be supplied,governor data for the Railbelt machines,existing underfrequency relay data,and voltage control equipment data. On August 8,1989,Harrison Clark forwarded to CEA and GVEA a then current data listing for the Railbelt system.Following the meeting and the transmittal of the existing data base,new/revised data for the Railbelt system was supplied by each of the utilities through a series of faxes,letters and telephone discussions.By September 1,1989,the majority of the data necessary to prepare the study base cases had been received. In reviewing the data supplied,it was noted that the load and generation dispatch data did not agree exactly with the proposed cases listed in the original RFP.The differences were mainly in the interchange between Anchorage and the other areas (particularly the Kenai),and the inclusion of a summer valley load condition case which was not explicitly identified as such in the RFP.Moreover,in GVEA's data response,they indicated that one of the summer interchange cases identified in the RFP was not feasible.Thus,the utilities provided load and generation dispatch data for five cases versus the six listed in the RFP. The differences between the load and generation scenario data submitted and the cases identified in the RFP appear to have occurred at the time of the kick-off meeting.The meeting notes summarize the data which the utilities agreed to supply, and the data as supplied agrees with what was discussed at the meeting.PTI accepted this data as being the system conditions desired by the Railbelt utilities for the study and developed cases on this basis. A few discussions were had with some of the utilities in early September to clarify some of the data that had been provided.However,following clarification of the data, we prepared a base case model for the winter peak,normal dispatch condition.This model was sent to each of the Railbelt utilities and AEA on September 8,1989 for review.The utilities were advised that unless PTI received comments to the contrary,we would proceed with the development of the remaining models needed for the study. We received comments on the winter peak case from GVEA via fax on September 12. We also received some additional data from some of the other utilities by mid-September via fax,phone and letter.Thus,we made the necessary modifications to the winter peak case,and we proceeded with the development of the remaining study base cases (i.e.,summer peak and summer valley).These cases were provided to the utilities by mid-September. "p> Page 3 Mr.Afzal Khan October 3,1991 Also by mid-September,data for the existing underfrequency load shedding relays had been provided by the utilities.The generator and excitation model data for the Railbelt machines were taken from the Railbelt Data Book since it was the best available source.No specific manufactures'data or data from tests was available for the machine governors,so we utilized the best available typical governor data.This was the option identified in the proposal if actual governor data was not available. Moreover,in the August 7 meeting notes it was specifically stated that the study would not be delayed to take advantage of turbine-governor data which might be developed from contemplated tests. Through our verbal discussions with the utilities,it was indicated that the system models as developed were acceptable,and all of the system data appeared to be complete.Moreover,the dynamics data had been checked using the automated checking routines within PSS/E.Thus,by September 17,1989 we felt that we had completed all of the activities associated with Task 1.Although we had not received any formal,written authorization from the IOC to proceed,we did proceeded with Task 2 (review of existing system performance)based on the verbal discussions. Moreover,completion of the work in a timely matter was of extreme importance to AKA and the utilities.Thus,it was necessary to proceed without delay in order to meet the work schedule and budget. A significant amount of work was performed on Task 2 prior to a meeting in Anchorage in early October 1989.Some preliminary results from the Task 2 dynamic simulations were presented and delivered at that meeting.Some updated power flow models were also distributed at that meeting based on some minor changes which had been received in late September. Following the meeting,we continued to receive updates to the power flow base case models.These changes were minor in nature and did not appear to have a significant impact on the work already completed on the review of the existing underfrequency load shedding relay performance.These changes were,however,incorporated in the models as they were received so that any further simulations would be based on the most current and accurate data available. We have record of having received only one utility response to the preliminary information we presented at the October meeting.This response indicated that the performance of the existing system as portrayed in the preliminary studies was indicative of actual load shedding experiences which had occurred on the system. This utility's response posed some additional questions which needed to be addressed by the study,but it did not indicate any problems with the study work done to dateorindicateinanywaythatthestudywas"off base".Thus,we proceeded with the study.By October 15,1989 we had completed Task 2,and having received no information to the contrary,proceeded with Task 3. -_\r> Page 4 Mr.Afzal Khan October 3,1991 For Task 3 in the proposal,numerous options were listed as possible methods for improving underfrequency load shedding.However,the proposal recognized that it was not feasible to test all options,and that the most likely option would be selected through engineering judgement.Moreover,the remaining project budget and schedule at this point did not allow for the review of multiple options. The results from the Task 2 studies had provided us with considerable insight to the response of the Railbelt system under various resource deficiency situations.It had also revealed the deficiencies of the existing,conventional underfrequency relays employed on the Railbelt system.Therefore,with this information and considering the noted budget and time constraints,PTI selected what it expected to be the most feasible option for providing the desired load shedding performance on the Railbelt system.This option was pursued in the Task 3 studies. By early November 1989,we had completed the analysis of the one option for improving load shedding.However,we still recognized that there was further work to do under Task 3.But at this point,we thought it appropriate to prepare a draft report of the work done so far and to solicit comments and suggestions from the utilities before proceeding.We sent this draft report to the utilities and AEA on November 8,1989. Subsequent to this,we received comments from all of the utilities which took exception to the findings and objected to the study process.These comments came as quite a surprise since this was the first indication from any of the utilities that the study process was not occurring as expected or that various aspects of the study had not been completed and that specific information had not been supplied to the utilities.The comments received also noted that the utilities themselves were not in agreement as to the treatment of intertie flows and the interruptibility of sales between utilities.It was felt that until this issue was resolved,no further work on the study should be made.PTI was instructed by AEA in December 1989 to halt work on the study until the outstanding issues were resolved. As we mentioned at the top of this letter,there is considerable disagreement as to what has and has not done on this study,what should and should not have been done,whether the study followed the RFP and proposal,and whether on not authorization existed to proceed with various stages of the study.Without trying to fix blame or to shift responsibility,it may be helpful to discuss some of the reasons the present state of disagreement exists.Moreover,discussion of such issues as it regards the study work which has been performed may be useful in helping avoid further disagreement as we proceed with the study. The study was requested by AEA on behalf of the IOC.However,PTI's was directed to communicate directly with individuals at the various utilities and to keep AEA informed as to these communications.We did this as requested and we relied on the --_"\pr Page 5 Mr.Afzal Khan October 3,1991 individuals at the utilities to supply the necessary data,review the information we provided and to actively comment on the progress of our work to assure that the study was going in the proper direction.Although we did throughout the study process get data and technical comments related to the study models,we did not receive any comments from the individuals at the utilities concerning the direction of the study.We assumed that these individuals were keeping their respective IOC members informed,and that we would be given such direction from the IOC if the study was not proceeding along its desired course.In the absence of any direct communications from the IOC,we had to assume the study was on-course.Thus,the communications process associated with the study may have contributed to some of the problems. A second concern was the time allocated for the study.The study,based on the amount of work to be performed,required very fast-paced work given the ambitious study schedule.This fast-pace necessitated the use of streamlined communications such as noted above,and it required prompt responses from the utilities.It would appear that the fast pace of this study did not provide sufficient opportunity for the review of the work.It would appear (hind-sight being 20/20)that the study process should have had more "hold points"to allow the IOC to review the study process and information,and to provide any changes in direction needed in the study. The overall scope of the study as first outlined in the RFP and later presented in the proposal may also have contributed to some the problems which exist.The beginning thrust of the study was to collect data and develop models for numerous proposed - conditions and to do "what if"type analysis.Perhaps the initial thrust of the study should have more explicitly been directed to the collection of data to develop a model for some well defined,pre-exiting system condition (such as has now been done for the August 29,1990 study case and subsequent disturbance events during the 1991 summer),and to do a post-mortem analysis of an actual disturbance event which involved load shedding.The scope of work listed in the RFP did not specifically request or require a post-mortem type of analysis.The scope of work listed in Task 2 of the proposal had one sentence covering the "comparison”of cases to past load shedding studies and system events,but the proposal did not predicate doing a detailed post-mortem study. Another factor which probably also contributed to some of the problems is that not all of the "ground rules”were fully established and agreed to prior to beginning the study.For example,as was indicated in the comments to the draft report,there was not a consensus among the utilities as to how to handle or account for intertie transfers in addressing the spinning reserve issue.Further,in reviewing our records, the IOC never provided any study criteria to be used in conducting the study.This issue was raised at the kick-off meeting and requested from the utilities,but none was ever provided.It may have been premature to proceed with the study without having study criteria and the intertie transfer issues resolved. --_"\pr> Page 6 Mr.Afzal Khan October 3,1991 Recognizing that we cannot change the events of the past or fix mistakes which may have occurred,the prime question which needs to be answered now is:where are we in this study process and where do we go from here?It has been a year and a half since we issued the draft report for comment during the Task 3 work.In the meantime,many events have transpired. _The first of these was the test and derivation of detailed models for the Kenai units. This activity was being completed about the same time the draft report was produced. The original load shedding study used simplified governor models which were based only on typical data.Analysis done after the Kenai machine tests revealed that the simplified governor models based on typical data did not accurately predict the response of the Kenai combustion turbines. This finding subsequently lead to the test of all the major units in the Railbelt system.Detailed models with test-verified data were developed by the summer of 1990.Thus,the machine models and data used in the original load shedding study for all major Railbelt units have been updated or replaced as a result of the tests. During the summer of 1991,the detailed models with test-verified data were used in several post-mortem studies of actual disturbance events.The results from the first such study provided good correlation to actual system performance using the new machine model data.However,in several additional post-mortem studies which have been conducted,we have found that even the new models do not provide a completely accurate representation of the governors on all units.We have identified areas where governor response appears to still be in question and is not representative of the response captured by the test or represented by the models.We have yet to fully resolve and answer the question as to which machines may not respond (or at least are slow to respond)to underfrequency situations due to governor limits or operating constraints which are utilized. Yet another event which has transpired has been the changes in the underfrequency relay settings utilized in the Fairbanks area.This has altered the response of the existing load shedding relays in this area compared to what was simulated in the original study. Thus,due to the number of events which have transpired,the usefulness of the original load shedding study results are in question.This would be the case even had there been no perceived problems with the original study process.This conclusion is based on the considerable amount of information which has now been developed and on the what we have learned about the system in the intervening time.The better information and the better understanding of the system have been garnered from efforts which went well beyond the work included in the original load shedding study. "pr Page 7 Mr.Afzal Khan October 3,1991 We are certainly willing to resume the underfrequency load shedding study from what ever point AEA and the IOC wishes to select.However,we do not feel that the perceived deficiencies with the original study are solely the responsibility of PTI.We feel that we acted properly and in good faith in trying to fulfill the study requirement of AEA and the IOC.Moreover,the events which have transpired during the intervening time have,through no ones fault,nullified the applicability of the original study work.Thus,further work on the underfrequency load shedding study by PTI will have to be on a compensated basis. Please advise if you have any questions concerning this response to the IOC's August 15,1991 letter. Sincerely,AI Se hode."John H.Doudna,P.E. Senior Engineer JHD: ce:H.K.Clark ALASKA INTERTIE OPERATING GUIDES OPERATING GUIDES "Adopted by the Alaska Intertie Operating Committee"' TABLE OF CONTENTS PageINTRODUCTION TERMS USED IN THE GUIDES GUIDE IL SYSTEMS CONTROL A.GENERATIONCONTROL..........2.0-0.0080eeeae llB.VOLTAGECONTROL...........000000ceeeveees L3C.TIMEANDFREQUENCYCONTROL............020008-14D.INTERCHANGESCHEDULING .............0.080080%16E.CONTROL PERFORMANCE CRITERIA...........0.00200.8.17 F.INADVERTENT INTERCHANGE MANAGEMENT............L9 G.CONTROLSURVEYS ....2...2c eee were en eee eens 1.10H.CONTROL EQUIPMENT REQUIREMENTS..........2..00.2.Ill APPENDIX LC.TIME ERROR CORRECTION PROCEDURES APPENDIX LF.INADVERTENT INTERCHANGE ENERGY ACCOUNTING PRACTICES GUIDE I.SYSTEM SECURITY A.MWGENERATION RESERVE ........20000ceeeevee IL1B.REACTIVE POWERSUPPLY........2020cccccvvevseves 0.2C.TRANSMISSION OPERATION..........00c0ceceveces 0.3D.RELAYCOORDINATION..........200000ceceesecees 1.3E.MONITORING INTERCONNECTION PARAMETERS ..........0.6 F.INFORMATION EXCHANGE..........2020020c0c0ceees 11.8SystemConditions...2...2...ee eee ww eee 0.8DisturbanceReporting...2...0.2 ee eee wees 11.9G.MAINTENANCE COORDINATION............0-.2c8080-8 0.10 GUIDE OL EMERGENCY OPERATIONS A.INSUFFICIENT GENERATION CAPACITY .............6..1.1 B.TRANSMISSION OVERLOAD,VOLTAGE CONTROL..........1.2C.LOADSHEDDING......2...e eee e nce reevesvens 01.3D.SYSTEM RESTORATION..ee ae ee ee ee 1.3 E.EMERGENCY INFORMATION EXCHANGE...........6.020-1.4 F.SPECIAL SYSTEM OR CONTROL AREAACTION.........2...1.5 G.CONTROLCENTERBACKUP .........2000ceeeenevae 11.6 GUIDE IV.OPERATING PERSONNEL A.RESPONSIBILITY ANDAUTHORITY.........2202000cee IV.1B.SELECTION.e °[on e e e oe 8 e ®@ e@ ©@ @ ©®@®@ @ ©©@##@##®@ @ @ @ IV.1C.TRAINING ..1...0 ee ee ewe te ee te were ee ewe we IV.2D.RESPONSIBILITY TO OTHER OPERATING GROUPS..........IV.3 ALASKA INTERTIE OPERATING GUIDES APPENDIX IV.C.SUGGESTED ITEMS FOR INCLUSION IN A TRAINING COURSE ALASKA INTERTIE Approved NERC le "Revised TABLE OF CONTENTS PageGUIDEV.OPERATIONS PLANNING A.NORMALOPERATIONS..........2.000 ee eee ee ene VilB.PLANNING FOR EMERGENCY CONDITIONS ...........-..V.2 C.LONG-TERM DEFICIENCIES ............0.020208202886.V.2D.LOADSHEDDING.............0.0-000008ceeeevee V.4E.SYSTEMRESTORATION............2020200c00eceeeee V.5 GUIDE VL COMMUNICATIONS A.FACILITIES..............0202028208082008eeeevee VI1B.SYSTEM OPERATOR COMMUNICATION PROCEDURES ........VI.2 C.LOSS OF COMMUNICATIONS.........-26cccccvcveeveve V1.2 APPENDIX VLA INSTRUCTIONS FOR INTERREGIONAL EMERGENCY TELEPHONE NETWORKS APPENDIX VLB NOTIFICATION OF SOLAR MAGNETIC DISTURBANCE WARNINGS REVISION PROCEDURE REVISION SUMMARIES ALASKA INTERTIE Approved NERC 2.-Revised NORTH AMERICAN ELECTRIC RELIABILITY COUNCIL OPERATING GUIDES INTRODUCTION The NERC-OC Operating Guides (Guides)are designed to promote coordinatedoperationamonginterconnectedsystemsandtoachievehighlevelsofinterconnectedsystemsreliabilityandcontrol.The Guides specify how the basic operating policy of theNERCOperatingCommittee,containedin the Reliability Criteria for Interconnected SystemsOperation(Criteria),is to be implemented.The Criteria and Guides are based onestablishedtechnicalrationaleandmatureoperatingexperienceandjudgment.Systemoperatorinputisvitaltotheestablishmentandmaintenanceofgoodoperatingpolicy.TheCriteriaandGuidesarereviewedandupdatedbytheOperatingCommitteeasnecessarywithpresentandfutureInterconnectionandsystemrequirementsinmind. In practice,certain Guide statements are more essential to reliableInterconnectionoperationthanothers.Therefore,the Guide statements have beenclassifiedaseitherOperatingRequirementsorOperatingRecommendations. A NERC OperatingRequirementis a written statement,duly adopted under theNERCOperatingConnuittee'smybick procedures,that describes the obligations of a controlareaandsystemsfunctioningasapartofacontrolarea.An Operating Requirement mayalsospecifywhethertherewillbemonitoringforcompliance. A NERC Operating Recommendationis a written informational statement,dulyadoptedundertheNERCOperatingCommitteevotingprocedures,describing good operatingpractices.The application of recommendations may vary among control areas to cover localconditionsandindividualsystemcharacteristics. The Guides are organized the same as the Criteria.A Criteria referencestatement,extracted from the Reliability Criteria for Interconnected Systems Operation,isfoundatthebeginningofeachGuidesubsection.Requirements,Recommendations,andBackgroundcategoriesarealsoincludedineachGuidesubsection.A glossary of termsprecedestheGuides;an appendix and revision procedure follow the Guides. Refer to the Reliability Criteria for Interconnected Systems Operation for thecompletesetofCriteriastatements. ALASKA INTERTIE Approved Revised ooae .TERMS USED IN THE GUIDES Adequate Regulating Margin The minimum on-line capacity that can be increased ordecreasedtoallowthesystemtorespondtoallreasonabledemandchangesinordertobeincompliancewiththeControlPerformanceCriteria. Adjacent System or Adjacent Control Area Any system or control area either directlyinterconnectedwith,or affected by schedules or metering of,another system orcontrolarea. Area Control Error (ACE)The instantaneous difference between actual and scheduled interchange,taking into account the effects of frequency bias (and time error orunilateralinadvertentifautomaticcorrectionforeitherispartofthesystem's AGC). Automatic Generation Control (AGC)Equipment which automatically adjusts a controlarea's generation from a central location to maintain its interchange schedule plusfrequencybias. Bulk Electric System The aggregate of electric generating plants,transmission lines,andrelatedequipment.The term may refer to those facilities within one electric utility,or within a group of utilities in which the transmission lines are interconnected. Capacity Emergency A capacity emergency exists when a system's or pool's operatingcapacity,plus firm purchases from the Interconnection,to the extent available orlimitedbytransfercapability,are inadequate to meet its demand plus its regulatingrequirements. Control Area A system capable of regulating its generation in order to maintain itsinterchangeschedulewithothersystemsandcontributeitsfrequencybiasobligationtotheInterconnection. Demand The rate at which energy is being used by the customer. Disturbance 1.Any perturbation to the electric system.2.The unexpected change inACEthatexceeds3timesL,which is caused by the sudden loss of generation orinterruptionofload. Dynamic Schedule A schedule that is continuously adjusted in real time to match anactualinterchange.Commonly used for "scheduling”generation from another control area. Energy Em cy An energy emergency exists when a system or pool does not have anadequatesupply(including water for hydro units)to provide its customers'expected energy requirement over a given period. Frequency Bias A value,in MW/0.1 Hz,set into a control area's AGC equipment torepresentacontrolarea's nse to frequency deviation from scheduled frequency,and to separate internal load/generation unbalance from external unbalance so that acontrolareamayregulateitsownloadwhilecontributingtoInterconnectionfrequencyregulation. ALASKA INTERTIE Approved NERC -1-Revised TERMS USED IN THE GUIDES Hourly Value Data measured on a clock-hour basis. Inadvertent Interchange The difference between the control area's net actual interchangeandnetscheduledinterchange. Interconnection When capitalized,any one of the four bulk electric system networks inNorthAmerica:Eastern,Western,Texas,and Quebec.When not capitalized,thefacilitiesthatconnecttwosystemsorcontrolareas. Interruptible Load Demand that can be interrupted by the supplying system in accordancewithcontractualprovisions. Load The amount of electric power delivered or required at any specified point or points on a system.; Leap Second A second of time added occasionally by the National Bureau of Standards tocorrectfortheoffsetbetweentheclock-hour day and the solar day. Metered Value An electrical quantity measured that may be collected by telemetering,SCADA,or other means. Neighboring System An adjacent system,or system "electrically”close to a utility. Net Energy for Load Net system generation plus interchange received minus interchangeelive Non-spinning Reserve That operating reserve not connected to the system but capable ofservingdemandwithinaspecifiedtime,or interruptible load that can be removedfromthesysteminaspecifiedtime. Operating Reserve That capability above firm system demand required to provide forregulation,load forecasting error,equipment forced and scheduled outages and localareaprotection.It consists of spinning and non-spinning reserve. Region One of the NERC Regional Reliability Councils. Subregion A portion of a Region. Supervisory Control and Data Acquisition (SCADA)A system of remote control andtelemetryusedtomonitorandcontrolthetransmissionsystem. Special Protection System A protection system designed to perform functions other thantheisolationofelectricalfaults.Also called "remedial action scheme.” Spinning Reserve Unloaded generation which is synchronized and ready to serveadditionaldemand. Station Service The electric supply for the ancillary equipment used to operate ageneratingstationorsubstation. ALASKA INTERTIE Approved Revised !TERMS USED IN THE GUIDES 'Station Service Generator A generator (usually found in hydro plants)used to supply i electric energy for station service equipment. System A combination of generation,transmission,and distribution components comprisinganelectricutility,or group of utilities. System Operator A person who operates the electric system. ALASKA INTERTIE 'Approved NERC -3-Revised ALASKA INTERTIE GUIDE |.SYSTEMS CONTROL A.GENERATION CONTROL Criterla Reference Requirements 1.Automatic Generation Control (AGC)shall compare total net actual interchange to total net scheduled interchange plus frequency bias contribution to determine the control area's Area Control Error (ACE),and respond to return the ACE to zero. 2.Each control area shall maintain generating regulating capability,synchronized to the Interconnection,that can be increased or decreased by AGC to provide for adequate system regulation and Control Performance. 3.Each control area shall operate its AGC on tie-line frequency bias,unless such operation is adverse to system or Interconnection reliability.The requirements for tie-line bias control follow: 3.1.The control area shall set its frequency bias (expressed in MW/0.1 Hz)as close as practical to the control area's frequency response characteristic.Frequency bias may be calculated several ways: 3.1.1,A fixed frequency bias value may be used which is based on a fixed, straight-line function of tie-line deviation versus frequency deviation. The fixed value shal!be determined by observing and averaging the frequency response characteristic for several disturbances during on-peak hours. 3.1.2.A variable (linear or non-linear)bias value may be used which is based on a variable function of tie-line deviation to frequency deviation.The variable frequency bias value shall be determined by analyzing frequency response as it varies with factors such as load,generation,governor characteristics,and frequency. 3.2.The Performance Subcommittee shal!set demonstration and performance standards for whichever frequency bias method is used. 3.2.1.In no case shall the monthly average frequency bias be less than 1%of the control area's estimated yearly peak demand per 0.1 Hz change as described in the Control Performance Criteria Training Document. 3.3.Each control area must be able to demonstrate and verify to the Performance ALASKA INTERTIE Approved NERC -L1-Revised GUIDE |.SYSTEMS CONTROL ALASKA INTERTIE A.GENERATION CONTROL Subcommittee that its frequency bias setting closely matches its system response. 3.4.Each control area shall review its frequency bias settings by January 1 of each year and recalculate its setting to reflect any change in area frequency response characteristic. 3.4.1.The bias setting,and the method used to determine the setting,may be changed whenever any of the factors used to determine the current bias value change. 3.4.2.Each control area shall report its frequency bias setting,and method for determining that setting,to the Performance Subcommittee. Recommendations 1.AGC should remain in operation as much of the time as possible. 2.AGC may be suspended at frequencies above 60.2 Hz or below 59.8 Hz if continued control would result in generation changes that could endanger system reliability. 3.Turbine governors and control systems,including AGC,and HVDC control systems should be checked periodically to verify their correct operation. 4.|Turbine governors and HVDC controls,where applicable,should be allowed to respond to system frequency deviation,unless there is a temporary operating problem. 5.The utility should establish normal and emergency rates of response for each generator and HVDC terminal. 6.Load-limiting devices should be applied only to restrict the extent of load change which might have an adverse effect on the generator or jeopardize transmission security. 7.Regulating margin should be distributed over as many units as possible. 8.Each control area should plan for future adequate control performance to meet expected changes in load characteristics and daily load patterns. 9.All generating units of consequential size should be equipped with AGC to ensure that the control area can continuously balance its generation with its demand plus net scheduled interchange. Background Accurate and adequate generator control helps reduce time error,frequency deviations,and inadvertent interchange within the Interconnection. ALASKA INTERTIE Approved NERC -12-Revised GUIDE 1.SYSTEMS CONTROL ALASKA INTERTIE A.GENERATION CONTROL Each control area will respond to frequency deviations according to its system response characteristic.Most of this response will be reflected in the control area's net tie flow to the Interconnection.By monitoring the interchange deviation from schedule,the frequency deviation from schedule,and by using the control area's frequency response characteristic,the control area, through its AGC,can determine whether the imbalance in load and generation is internal or external to its control area.If internal,the AGC will adjust the generation to correct the imbalance.If external,no AGC action should occur;however,the system frequency response to the deviation should be allowed to continue until the external system with the generation surplus or deficiency corrects its imbalance and returns the frequency to schedule.Until actual system response can be continuously measured,it must be estimated.This estimate is the tie-line frequency bias setting.The closer the tie-line frequency bias matches the actual system frequency response,the better the AGC will be able to distinguish internal and external imbalances and reduce the number of unnecessary control actions.Therefore,the basic requirement of tie-line frequency bias is that it match the actual system response as closely as practicable. B.VOLTAGE CONTROL Criteria Reference aA ai . A apa »and inducti .Pq i :PSOUrCE vel maintain m_and interconnection vol withi lished high and low limi R iv neration scheduling,transmission switching,and|hedding,if n ary,shall b implement maintain these levels,Each man ntrol area shall maintain Mvar reserve resources to support its voltage under credible contingency conditions. Requirements 1.Devices used to regulate transmission voltage and reactive flow shall be available for use by the system operator. 2.System operators shall monitor transmission system voltage for deviation from prearranged voltage levels and take corrective action to keep voltages within allowable limits. 2.1.Prearranged voltage levels,reactive control equipment settings,and changes in transmission configuration shall be coordinated with neighboring systems. 2.2.Transfer or interchange limits shall reflect voltage or reactive restrictions. 2.3.|System operators shall monitor and keep reactive power flow within established limits on tie-lines. Recommendations 1.Important transmission lines should be kept in service during light-load periods as much as possible.They should be removed from service for voltage control measure only after all reactive control measures are fully implemented and appropriate studies indicate that system reliability will not be degraded below acceptable levels. ALASKA INTERTIE Approved NERC -13-Revised GUIDE |.SYSTEMS CONTROL ALASKA INTERTIE B.VOLTAGE CONTROL 2.Automatic voltage regulators and power system stabilizers on generators and synchronous condensers should be kept in service as much of the time as possible. 3.Devices used to regulate transmission voltage and reactive flow should be switchable without deenergizing other facilities. 4.When a generator's automatic voltage regulator is out of service,field excitation should be maintained at a level adequate for stable operation. 5.Systems with dc transmission facilities should utilize reactive capabilities of converter terminal equipment for voltage control. C.TIME AND FREQUENCY CONTROL Criteria Reference terconnection fr ncy shall heduled Hz.an ntroll hat val x for h ti in which frequen viations ar h led rr ime error rating limits for fr n iationand time error shal lish ith nnection reliabili irst priori Each control area shall participate in interconnection time error correction, Control areas which are operating in parallel shall select one contro!area to monitor time error x the interconnection an issue time error correction order Requirements 1,Each Interconnection shall designate an Interconnection Monitor who shall monitor time error and shall initiate or terminate corrective action orders when time error reaches predetermined limits as shown in Appendix ILC. 2.'Time error corrections shall start and end on the hour or half-hour,and notice shall be given at least twenty minutes before the time error correction is to start or stop. 3.Time error correction notifications shall be serialized alphabetically on a monthly basis. 4.The time error correction offset shall be applied by either of the following two methods: 4.1.The frequency schedule may be offset by 0.02 Hz,leaving the bias setting normal,or 4.2.If the control frequency base setting cannot be offset,the Net Interchange schedule (MW)may be offset by an amount equal to the computed bias contribution during a 0.02 Hz frequency deviation (i.e.,20%of the frequency bias setting). ALASKA INTERTIE Approved NERC -L4-Revised GUIDE I.SYSTEMS CONTROL ALASKA INTERTIE C.TIME AND FREQUENCY CONTROL 5.A Regional Monitor shall be designated through which time error correction notifications originating with the Interconnection Monitor will be routed to each system in the Region by way of established Time Notification Channels. 6.The Interconnection Monitor shall periodically issue a notification of time error,accurate to within 0.1 second,to the Regional Monitors to assure uniform calibration of time standards. 7.Using the Time Notification Channels,the Regional Monitors shall,each hour,on the hour,notify all systems within their respective Regions of the accumulated time error within 0.1 second.Time error notification shall be accompanied by the alphabetic designator if a time error correction is in progress. 8.Each control area shall at least annually check and calibrate its time error and frequency devices against a common reference. 9.|When one or more control areas has been separated from the Interconnection,uponreconnection,they shall adjust their time error devices to coincide with the Interconnection by one of the following methods: 9.1.Before connection,the separated area may institute a Time Error Correction Procedure to correct its accumulated time error to coincide with the indicated time error of theInterconnectionMonitor,or 9.2.After interconnection,the time error devices of the previously separated area may be recalibrated to coincide with the indicated time error of the Interconnection Monitor. A notification of adjusted time error shall be passed through Time Notification Channels as soon as possible after interconnection. 10.Standards of allowable time error are found in Appendix I.C. Recommendations 1,The control areas of an Interconnection may implement automatic time error control as a part of their AGC scheme. 1.1.If automatic time error correction is used,all control areas of the Interconnection should participate. 1.2.Automatic time error control should be suspended whenever an announced time correction is in progress. 2.Systems using time error devices that are not capable of automatically adjusting for leap- seconds should arrange to receive advance notice of the leap-second and make the necessary manual adjustment in a manner that will not introduce a disturbance into their control system. ALASKA INTERTIE Approved NERC -15-Revised GUIDE 1.SYSTEMS CONTROL ALASKA INTERTIE C.TIME AND FREQUENCY CONTROL Background The difference between load and generation resultsin frequency deviations from 60 Hz,andtheintegrateddeviationappearsasadeparturefromcorrecttime. The satisfactory operation of the Interconnected systems is dependent,in part,upon accurate frequency transducers and recorders and time error devices associated with AGC equipment. D.INTERCHANGE SCHEDULING Criterla Reference hedulin wer between control ar hall one through transmission h lish ntr rownershi henet amoun interchan hedul ween control ar hallnot exceed them ll ablish ransfer limits of the common interconnections and alternat hs which hav rranged for between th tties.When establishing normal and emergen ransfer limits,th i ntract intermediary,an celvin rol ar hall consi he eff f power flow hrough their own an her parallel systems or control areas ba n mutually acceptable reliabili Inn hallthe schedul wer between ontrol x h al install f own rt arranged-for transmission iliti ween the tw ntrol ar ALASKA INTERTIE Approved NERC -1.6-Revised =weweowevGUIDE |.SYSTEMS CONTROL ALASKA INTERTIE D.INTERCHANGE SCHEDULING Requirements 1. NERC Interchange shall be scheduled only between control areas having directly connecting facilities in service unless there is a contract or mutual agreement with other control areas to provide connecting facilities. Interchange schedules or schedule changes shall not cause any other system to violate established reliability criteria. 2.1.When control areas are connected so that parallel flows present reliability issues,the combinations of control areas shall develop multi-control area interchange monitoring techniques and pre-determined corrective actions to mitigate or alleviate potential or actual transmission system overloads. 2.2.Transfer limits shall be reevaluated and interchange schedules adjusted as soon as practicable if transmission facilities become overloaded or are out of service,or when changes are made to the bulk system which can affect these limits. The maximum net scheduled interchange between two control areas shall not exceed the lesser of two values: 3.1.The total capacity of the transmission facilities in service between the two control areas owned by them or available to them under specific arrangements,contracts,or mutual agreements,or 3.2.The mutually established First Contingency Total Transfer Capability of the two control areas considering other transmission facilities available to them under specific arrangements,First Contingency Total Transfer Capability is defined in Appendix L.D., Transfer Capability,A Reference Document,NERC October 1980 The sending,contract intermediary,and receiving control areas that are parties to a interchange transaction shall agree on the following: 4.1.The schedule's magnitude,starting and ending times. 4.2.The schedule's magnitude and rate of change shall be equal and opposite and not exceed the ability of the systems to effect the change. 4.3.The scheduled generation in one control area that is delivered to another control area must be scheduled with all intermediate control areas unless there is a contract or mutual agreement among the sending,contract intermediary,and receiving control areas to do otherwise. Control areas shall develop procedures to disseminate information on interchange schedules and facilities out of service which may have an adverse effect on other control areas not involved in the scheduled interchange and the involved parties shall predetermine schedule priorities, which will be used if a schedule reduction becomes necessary. ALASKA INTERTIE Approved -L7-Revised GUIDE |.SYSTEMS CONTROL ALASKA INTERTIE D.INTERCHANGE SCHEDULING Background Scheduled interchange must be coordinated between control areas to prevent frequency deviations and accumulations of inadvertent interchange,and prevent exceeding mutually established transfer limits. E.CONTROL PERFORMANCE CRITERIA Critterla Reference The Control Performance Criteria define a standard of minimum control performance.Each control area is to have the best operation above this minimum that can be achieved within the bounds ]nomi hysical ion Requirements 1.Two criteria shall be used to continually monitor control performance during normal conditions (See the "Control Performance Criteria Training Document,"Section 2.1): 1.1.Ail Criteria -The ACE must return to zero within ten minutes of previously reaching zero.Violations of this criteria count for each subsequent ten-minute period that the ACE fails to return to zero. 1.2,<A2 Criteria -The average ACE for each of the 6 ten-minute periods during the hour (i.c.,for the ten-minute periods ending at 10,20,30,40,50,and 60 minutes past the hour)must be within specific limits,referred to as L,,that are determined from thecontrolarea's rate of change of demand characteristics.See the "Control Performance Criteria Training Document,"Section 2.1.2.1 for the methods for calculating Ly. 2.Two criteria shall be used to continually monitor control performance during disturbance conditions (See the "Control Performance Criteria Training Document,"Section 2.2): 2.1.B1 Criteria -The ACE must return to zero within ten minutes following the start of the disturbance. 2.2.B2 Criteria -The ACE must start to return to zero within one minute following the start of the disturbance. 3.The ACE used to determine compliance to the Control Performance Criteria shall reflect its actual value,and exclude short excursions due to transient telemetering problems or other influences such as control algorithm action. 4._All control areas shall respond to control performance surveys that are requested by thePerformanceSubcommittee. ALASKA INTERTIE Approved NERC -1.8-Revised GUIDE |.SYSTEMS CONTROL ALASKA INTERTIE E.CONTROL PERFORMANCE CRITERIA Recommendations 1.Each control area should be in compliance with the Al and A2 Criteria at least 90%of the time. Background Control performance is the degree to which a control area matches its generation to its demand plus scheduled interchange taking into account the effects of frequency bias.The NERC Operating Committee has established the Control Performance Criteria (CPC)which include standards of acceptable control performance.The CPC establish minimum standards for control performance and provide a means for measuring the relative control performance of each control area.While these standards define the minimum acceptable performance,each control area shall meet and strive to exceed these standards. F.INADVERTENT INTERCHANGE MANAGEMENT Criterla Reference h control ar hall,through dail h le verification and th liable meterin 'a rately a 'f i erte inte hange Re ogni ing penéra ign and load m h control area shal!be active in preventing unintentional inadvertent interchan accumulation,Each control area shall also be diligent in reducing accumulated inadvertent balances in accordance with Operating Committee procedures. Each contrgl area interconnecti int shall i ith mm meter,with dings provided hour!h ntrol center of h ar Requirements 1.Inadvertent interchange shall be calculated and recorded hourly and may accumulate as a credit or debit to the control area.(See the Inadvertent Interchange Accounting Training Document.) 2.All interconnections shall be included in the inadvertent interchange account.Interchange served through jointly owned facilities and interchange with borderline customers must be properly taken into account. 3.Inadvertent interchange accumulations shall be paid back by one or both of the following methods: 3.1.Method 1 -Inadvertent interchange accumulations may be paid back by scheduling interchange with another control area. 3.1.1.The other control area must have an inadvertent accumulation in the opposite direction. ALASKA INTERTIE Approved NERC -1.9-Revised GUIDE I.SYSTEMS CONTROL ALASKA INTERTIE F.INADVERTENT 3.1.2, INTERCHANGE MANAGEMENT The amount of inadvertent payback scheduled shall be agreed upon by all involved systems. 3.2.Method 2 -Inadvertent interchange accumulations may be paid back unilaterally by offsetting tie-line schedule when such action will aid in correcting the existing time error. 3.2.1. 3.2.2, 3.2.3. 3.2.4. 3.2.5. If time is slow and there is a negative accumulation (undergeneration),the AGC may be offset to overgenerate and pay back inadvertent interchange accumulation and reduce time error. If time is fast and there is a positive accumulation (overgeneration),the AGC may be offset to undergenerate and pay back inadvertent interchange accumulation and reduce time error. AGC offset may be made by either offsetting the frequency schedule up to 0.02 Hz,leaving the bias setting normal or offsetting the net tie-line schedule by up to 20%of the control area's bias or 5 MW,whichever is greater. Inadvertent payback shall end when either the time error is zero or has 'changed signs,the accumulation of inadvertent interchange has been corrected to zero,or a scheduled time error correction begins,which takes precedence over offsetting frequency schedule to pay back inadvertent. Control areas within Interconnections using automatic time error control techniques shall not use Method 2 to reduce their accumulations of inadvertent.Method 1 is the only acceptable way for these control areas to manually reduce their accumulations of inadvertent. 4.Inadvertent interchange accumulated during "on-peak"hours shall be paid back during "on-peak"hours.Inadvertent interchange accumulated during "off-peak"hours shall be paid back during "off-peak"hours. 5.Each control area shall submit a monthly summary of inadvertent interchange as detailed in Appendix LF.,"Inadvertent Interchange Energy Accounting Practices." 5.1.Inadvertent interchange summaries shall include at least the previous accumulation,net accumulation for the month,and final net accumulation,for both the "on-peak"and "off-peak"periods. 5.2.Each control area shall submit its monthly summary report to its Performance Subcommittee representative who will prepare a composite tabulation for distribution to all other Performance Subcommittee representatives. 5.3.Each Performance Subcommittee representative shall distribute summaries to their respective control areas as agreed upon. NERC ALASKA INTERTIE Approved -1.10-Revised GUIDE |.SYSTEMS CONTROL ALASKA INTERTIE F,INADVERTENT INTERCHANGE MANAGEMENT Background Inadvertent interchange is the difference between the control area's net actual interchange and net scheduled interchange.The major cause of intentional inadvertent interchange is the bias response to frequency deviations occurring on the Interconnection.Causes of unintentional inadvertent interchange are instrument and control errors,improper control settings,generator response time,fluctuations in demand,etc. G.CONTROL SURVEYS Criterla Reference riodi¢c surv f th otro!perform f th ntrol ar hall n surveys serve the purpose of revealing contro!equipment malfunctions,telemetering errors,improper r n i in heduling errors,in neration under mati neration control general control performance deficiencies,or other factors contributing to inadequate control performance, Requirements 1,Each Interconnection shall perform each of the following surveys,as described in the Control Performance Criteria Training Document,when called for by the Performance Subcommittee: 1.1.Area Control Error survey to determine the control areas'interchange error(s)due to equipment failures or improper scheduling operations,or improper AGC performance. 1.2.Area Frequency Response Characteristic survey to determine the control areas'response to changes in system frequency. 1.3.Control Performance Criteria survey to monitor the control areas'control performance during normal and disturbance situations. 2.The survey results will be reviewed by the Performance Subcommittee at each regular meeting, and by the Operating Committee as necessary,and distributed to all control areas and other appropriate parties in NERC.” H.CONTROL EQUIPMENT REQUIREMENTS Criterla Reference The control equipment of each control area shall be designed and operated so that the control r n contin ly an rately meet i man reonnecti ntr ligations an rei rman h ntrol ipm ign gn ion shall follow in techniques, It controlarea interconnection ti ints shall i lemeterMW pow w bar ntrol centers simultaneous!he telem ing shall be from an apreed-n terminal utilizing common metering equipment, ALASKA INTERTIE Approved NERC o[.11-Revised GUIDE 1.SYSTEMS CONTROL ALASKA INTERTIE Requirements 1.Each control area shall perform hourly control error checks using tie line MWh meters to determine the accuracy of its control equipment. 2.The system operator shall adjust control settings to compensate for any equipment error until repairs can be made. 3.All tie-line flows between control areas shall be included in each control area's ACE calculation. 4.System operators shall be provided with a recording of those variables necessary to facilitate monitoring of control performance,generation response,and after-the-fact analysis of area performance.As a minimum,area control error (ACE),system frequency,and net tie-line interchange data shall be continuously recorded. Recommendations 1.Adequate and reliable backup power supplies should be provided and periodically tested at the system control center and other critical locations to ensure continuous operation of AGC and vital data recording equipment during loss of the normal power supply. 2.All tie-line MW and MWH/Hr telemetry should be telemetered to both control centers,and should emanate from a common,agreed upon terminal using common primary metering equipment. ALASKA INTERTIE Approved NERC -f.12-Revised ---TIME CORRECTION SLOW FAST OPERATING GUIDE NO.1APPENDIXC TIME ERROR CORRECTION PROCEDURES INITIATION TERMINATION TIME ERROR-SECONDS TIME ERROR=SECONDS TIME OF ALASKA ALASKA INITIATION INTERTIE INTERTIE --ON DAYS HAVING PEAK PERIOD -- ANY -2.-+.1 ANY +2 +.1 NOTE:The Interconnection Monitor may postpone or cancel a time correction if requested to do so by regions or systems comprising 30 percent or more of the total frequency bias in the interconnected area,or if warranted by the overall capacity situation. ALASKA INTERTIE Approved Revised ALASKA INTERTIE APPENDIX LF.INADVERTENT INTERCHANGE ENERGY ACCOUNTING PRACTICES A.INTRODUCTION These uniform accounting practices will provide a method for isolating and eliminating the source of accounting errors and aid in identifying the poor control performance that contributes to inadvertent interchange accumulations. B.RELATIONSHIP TO NERC REQUIREMENTS These practices outline the methods and procedures required to reconcile energy accounting and inadvertent interchange balances. In order for a control area to properly monitor and account for inadvertent interchange,the Reliability Criteria for Interconnected Systems Operation and the Operating Guides must be adhered to. These practices do not supercede any provisions in the NERC Operating Manual.The intent is to bring the several items together into one document. C.SCHEDULES All hourly schedules and schedule changes shall be agreed upon between control areas involved prior to implementation in regard to magnitude,rate of change and common starting time. 1.Dynamic schedules integrated on an hourly basis shall be agreed upon by the control areas involved subsequent to the hour,but in such a manner as not to impact inadvertent accounts. D.ACCOUNTING PROCEDURES 1.Daily accounting -Each control area shall agree with adjacent control areas upon the following quantities at least once each day: 1.1.Scheduled interchange (MWh). 1.2.Actual interchange (MWh). 1.3.Totals during each day for on-peak and off-peak periods. 2.Monthly accounting -Having agreed on the on-peak and off-peak period scheduled and actual interchange each day,adjacent control areas shall verify that the accumulated values for the month balance. E.ADJUSTMENTS FOR ERROR 1.Periodic adjustments shall be made to correct for differences between hourly MWh meter totals and the totals derived from register readings of the tie-line meters. ALASKA INTERTIE Approved NERC 1-Revised APPENDIX I.F.INADVERTENT INTERCHANGE ENERGY ALASKA INTERTIE ACCOUNTING PRACTICES 2.Adjacent control areas shall agree upon the difference determined above and assign this correction to the proper on-peak and off-peak period at the same times and in equal quantities in the opposite directions. 3.Any adjustments necessary due to known metering errors,franchised territories,transmission losses or other special circumstances shall be made in the same manner. ALASKA INTERTIE Approved NERC =2-Revised APPENDIX I.F.INADVERTENT INTERCHANGE ENERGY ALASKA INTERTIE ACCOUNTING PRACTICES F.ON-PEAK AND OFF-PEAK PERIODS 1.Eastern and Texas Interconnections 1.1.On-peak period:HE (Hour Ending)0700 -HE 2200 CST'(HE 0800 -HE 2300EST"),Monday -Saturday. 1.2.Off-peak period:HE 0100 -HE 0600 and HE 2300 -HE 2400 CST"(HE 0100 -HE 0700 EST'and HE 2400 EST"),Monday -Saturday,HE 0100 through HE 2400CST'and EST'on Sundays and the days listed in Section 1.2.1. 1.2.1.Additional off-peak days -1991 New Year's Day January 1 Memorial Day May 27 Independence Day July 4 Labor Day September 2 Thanksgiving November 28 Christmas December 25 2.Western Interconnection 2.1.On-peak period:HE (Hour Ending)0700 -HE 2200 PST?(HE 0800 -HE 2300MST?),Monday -Saturday. 2.2.Off-peak period:HE 0100 -HE 0600 and HE 2300 -HE 2400 PST'(HE 0100 -HE 0700 MST?and HE 2400 MST*),Monday -Saturday,HE 0100 through HE2400PST?and MST®on Sundays and the days listed in Section 1.2.1. 3.Daylight Saving Time -1991 Daylight Saving Time begins on Sunday,April 7 and ends on Sunday,October 27. lor Daylight Saving Time,whichever is prevailing in Columbus,Ohio. ?or Daylight Saving Time,whichever is prevailing in Los Angeles,California. ALASKA INTERTIE Approved NERC -3-Revised ALASKA INTERTIE GUIDE Il.SYSTEMS SECURITY A.REAL POWER (MW)SUPPLY Criterla Reference equipment unavailability,number and size of generating units,system equipment forced outage Iates,maintenance schedules,regulating requirements,and regional and system load diversity. i ppropri C pext contingency, _Each Region or Subregion shall specify its operating reserve policies,including its allocation among members,the permissible mix of spinning and nonspinning reserve,and procedure for applying operating reserve in practice,and the limitations,if any,upon the amount of ible 1 which m incl Requirements 1 The system operator shal]be kept informed of all generation and transmission resources available for use. 2.The system operator shall have information,including weather forecasts and past load patterns,available to predict the system's near-term load pattern. 3.Each Region or Subregion shall provide,as a minimum,operating reserve as follows: 3.1 An amount of spinning reserve,responsive to AGC,which is sufficient to provide normal regulating margin,plus 3.2 An additional amount of operating reserve sufficient to reduce Area Control Error to zero within 10 minutes following loss of generating capacity which would result from the most severe single contingency. 3.2.1 At least 50%of this operating reserve shall be spinning reserve which will automatically respond to frequency deviations. 3.2.2 The spinning reserve component may be reduced below 50%of the operating reserve providing the Region or Subregion can demonstrate that with this reduction and upon its most severe single contingency,it will still be able to meet or exceed established Control Performance Criteria,and not jeopardize the reliable operation of the Interconnection. 3.2.3 Interruptible load may be included in the non-spinning reserve provided that it can be interrupted within 10 minutes. ALASKA INTERTIE Approved NERC eoll.1-Revised GUIDE Il.SYSTEM SECURITY ALASKA INTERTIE A.REAL POWER (MW)SUPPLY 3.3.An additional amount of reserve shall be made available as soon as practicable to aid in reestablishing this minimum operating reserve after such reserve has been used. 4.Operating reserve shall be dispersed throughout the system and shall consider the effective use of capacity in an emergency,time required to be effective,transmission limitations,and local area requirements. 5.All Regions,Subregions,and control areas shall frequently review probable contingencies to determine the adequacy of operating reserve. Recommendations 1,The effect of station service generators on area security should be considered before they are shut down for economy. B.REACTIVE POWER (MVAR)SUPPLY Criterla Reference . h control ar hall provide for th ly of itsr iv wer requirements,includin ropriate reserv rotect the volt levels for contingen nditions.This includes th control area's share of the reactive requirements of interconnecting transmission circuits,The rve shall ]1 ically wherei n li ffectively,withinth ropri time interval,when contingencies occur, Control areas shall coordinate the use of voltage control equipment to maintain transmission 1 ndr ive flow level nsistentwithinterconnection securi Requirements 1.The system operator shall be provided information on all available generation and transmission reactive power resources. 2.Reactive sources shall be operated so that scheduled voltages are maintained for all normal and first contingency conditions. 3.Reactive reserve shall be dispersed and located electrically so that it can be applied effectively and quickly when contingencies occur. 4.Prompt Action shall be taken to restore reactive resources if they drop below acceptable levels. 5.System operators shall take corrective action,including load reduction,necessary to prevent voltage collapse when reactive resources are insufficient. Recommendations 1.Reactive reserves should be automatically applied in the event of an emergency. ALASKA INTERTIE Approved NERC -ll2-Revised GUIDE Il.SYSTEM SECURITY ALASKA INTERTIE B.REACTIVE POWER (MVAR)SUPPLY 2.Surveys to determine compliance with voltage and reactive guidelines should be made ona regular basis. 3.Reactive reserve should be carried by rotating machinery and static var compensators which can be applied automatically when contingencies occur. C.TRANSMISSION OPERATION Criteria Reference When line loadings,equipment loadings,or voltage levels deviate from normal operating mergency limi Howin ntingen B liabili f h lk power ly is thr ned,control areas experiencing or sing th ndition shall tak mediat lieve th ndition,Th t incl notifyin her m justin neration,changin hedul ween control ar initiatin lief m res,an kin such other action as may be required, Transmission system operation shall be coordinated among systems,control areas,pools,and Regions,This includes coordination of equipment outages,voltage levels,MW and MVAR flow nitoring,and switching that affe wo or mor m Requirements 1.The system operator shall monitor all critical transmission system parameters including compliance with normal and emergency ratings and voltage limits. 2.Scheduled transmission outages shall be coordinated with known systems that may be affected. 3.Forced transmission outages shall be communicated to any systems that may be affected. 3.1.Forced outages of key transmission facilities shall be communicated to all adjacent systems as expeditiously as possible,thereby increasing the ability to detect acts of multi-site sabotage.If multi-site sabotage activity is suspected,interregional telecommunications shall be initiated for further detection. 4.Each control area shall use appropriate,up-to-date studies as a reference for establishing transmission operation procedures. Recommendations 1.Important transmission lines should be kept in service during light-load periods as much aspossible.They should be removed from service for voltage control measure only after allotherreactivecontro!measures are fully implemented and appropriate studies indicate that system reliability will not be degraded below acceptable levels. ALASKA INTERTIE Approved NERC -ll.3-Revised GUIDE I.SYSTEM SECURITY ALASKA INTERTIE D.RELAY COORDINATION Criterla Reference System operators shall be familiar with the intended operation of protective relays and shall Requirements 1.Appropriate technical information concerning protective relays shall be available in each system control center. 2.System operators shall be familiar with the purpose and limitations of protection system schemes. 3.If a protective relay or equipment failure reduces system reliability,the proper personnel shall be notified,and corrective action shall be undertaken as soon as possible. 4.All new protective systems and all protective system changes shall be coordinated among neighboring systems if the new and changed protective systems affect neighboring systems. 5.Protection systems on major transmission lines and interconnections should be coordinated with the interconnected systems. 6.Neighboring systems shall be notified in advance of changes in generating sources, transmission,load,or operating conditions which could require changes in their protection system. 7.The system operator shall monitor the status of each Special Protection System (SPS)and notify all affected systems of each change in status. Recommendations 1,Protection system design and operations should consider the following: 1.1 'Protection systems should be of minimum complexity consistent with achieving their purpose. 1.2 _-_'Protection systems should have redundancy to allow for their normal maintenance and calibration. 1.3.Protection systems should not normally operate for minor system disturbances,brief overloads,or recoverable system power swings. ALASKA INTERTIE Approved NERC -11.4-Revised GUIDE Il.SYSTEM SECURITY ALASKA INTERTIE D.RELAY COORDINATION 3. NERC 1.4 1.5 1.6 1.7 1.8 High-speed relays,high-speed circuit breakers,and automatic reclosing should be used where studies indicate the application will enhance stability margins.Single- pole tripping or reclosing may be appropriate on some lines. Automatic reclosing during out-of-step conditions should be prevented. Underfrequency load shedding relays should be coordinated with the generating plant off-frequency relays to assure preservation of system stability and integrity. Protection system applications,settings,and coordination should be reviewed periodically and whenever major changes in generating resources,transmission,load or operating conditions are anticipated. Adequacy of protection system communications channels should be reviewed periodically.Automated channel monitoring and failure alarms should be provided for protective system communications channels which could cause loss of generation, loss of load,or cascading outages in the event of misoperation or failure. Each system should implement protection system application,operation,and preventive maintenance procedures which will enhance their system reliability with the least adverse effect on the Interconnection.These protection system procedures should be provided to all appropriate system personnel and should provide for instruction and training where applicable.Each system should coordinate these procedures with any other systems that could be affected.These procedures should govern: 2.1 2.2 2.3 2.4 2.5 Planning and application of protection systems. Review of protection systems and settings. Intended functioning of protection systems under normal,abnormal,and emergency conditions. Regularly scheduled testing and preventive maintenance of relays,vital system protection equipment,and associated components. 2.4.1 The operation of the complete protection system should be tested under conditions as close to actual operating conditions as possible,including actual circuit breaker operation where feasible. 2.4.2 Testing protection system communication channels between systems should be coordinated with test results recorded. Analysis of actual protection system operations. A prompt investigation should be made to determine the cause of abnormal protection system performance and correct any deficiencies in the protection scheme. ALASKA INTERTIE Approved oll.5-Revised GUIDE Il.SYSTEM SECURITY ALASKA INTERTIE D.RELAY COORDINATION 4.The system operator shall monitor the status of each Special Protection System (SPS)and notify all affected systems of any changes in status. 5.SPS should be designed for periodic testing without affecting the integrity of the protected power system.They should normally achieve at least the same high level of reliability as that provided by normal protection systems. 6.SPS should be designed with inherent security to minimize the probability of an improper operation,even with the failure of a primary component. 7.Each SPS should be reviewed frequently to determine if it is still required and will still perform the intended functions.Seasonal changes in power transfers may require changes in the SPS or its relay settings. 8.Each SPS operation should be reviewed and analyzed for correctness. 9.Prompt action should be taken to correct the causes of an improper operation. Background Protection systems greatly influence the operation of interconnected systems,especially under abnormal!conditions.Protection systems used on tie points between interconnected systems for generator tripping and other remedial measures are of primary concern to the respective systems.However,internal system protection often directly,or indirectly,affects adjacent systems. Special Protection Systems,also known as Remedial Action Schemes,are relay configurations designed to perform functions other than isolation of electrical faults.These systems are usually installed to maximize transfer capability.However,they may be used to maintain system or unit stability or to control power and reactive flows on critical facilities immediately following a disturbance on a system,or to separate a system or interconnection at preplanned locations to prevent cascading.The general design objective for any SPS shall be to perform its intended function in a dependable manner while refraining from unnecessary operation.An SPS can expose a system to greater reliability risk.The integrity of the power system may depend on its correct operation. -.MONITORING INTERCONNECTION PARAMETERS Criterla Reference Each system and control area shall continuously monitor those electric system parameters (such as MW flow,Mvar flow,frequency,voltage,phase angle,etc.),internal and external to its m or control ar hat indicate the electrical system strength h m rator shall rovi with ipmen mplish thi ive,Metering of suitable ran n iability for h mal and em n ion hall maintain rom str 1 tem poin . ALASKA INTERTIE Approved NERC -I1.6-Revised GUIDE il.SYSTEM SECURITY ALASKA INTERTIE E.MONITORING INTERCONNECTION PARAMETERS Requirements 1,Monitoring equipment shall be used to bring to the system operator's attention important deviations in operating conditions and to indicate,if appropriate,the need for corrective action. 2.Each control area shall use sufficient metering of suitable range,accuracy and sampling rate (if applicable)to ensure accurate and timely monitoring of operating conditions under both normal and emergency situations. 3.System operators shall monitor transmission line status,MW and Mvar flows,voltage,LTC settings and status of rotating and static reactive resources. 4,System operators shall monitor system frequency. Recommendations 1.Reliable instrumentation,including voltage and frequency meters with sufficient range to cover probable contingencies,should be available in each generating plant control room. 2.Automatic oscillographs and other recording devices should be installed at key locations and set to standard time to aid in post-disturbance analysis. 3.Because of possible system separation,frequency information from selected locations should be monitored at the control center. 4,Monitoring should be sufficient,so that in the event of system separation,both the existence of the separation and the boundaries of the separated areas can be determined. 5.Transmission line monitoring should include a means of evaluating the effects of the loss of any significant transmission or generation facilities,both within and outside the control area. 6.|Where practical,critical unmanned facilities should be monitored for physical security. 7.Scheduled outages of generation or transmission facilities should be considered in themonitoringscheme. 8.Voltage schedules should be coordinated from a central location within each control area and coordinated with adjacent control areas. 'Background The system operator must have information available to them at all times so that they can accurately picture the system under normal operating conditions,make effective decisions following the occurrence of a contingency,and properly restore system integrity following a disturbance. ALASKA INTERTIE Approved NERC oIL.7-Revised GUIDE tl.SYSTEM SECURITY ALASKA INTERTIE &MONITORING INTERCONNECTION PARAMETERS F.INFORMATION EXCHANGE -SYSTEM CONDITIONS Criterla Reference nditions -Inform in iti ] adjacent control areas and non-adjacent control areas as needed to assure adequate protection oftheInterconnection, Requirements Each control area shall disseminate information on actual and scheduled interchange, voltages,and facilities out of service which may have an adverse effect on other control areas. 1,System operators shall notify other systems of current or foreseen operating conditions which may affect interconnection reliability.Examples of operating conditions that may affect reliability are:critically loaded facilities,scheduled and forced equipment outages, new facilities,abnormal voltage conditions,new or degraded protective systems,acts of God (severe weather,fire,earthquake),and new or degraded communications. Recommendations 1.To assure that communication networks are functioning properly and that timely exchange of pertinent operating information is taking place,specific communication monitoring and testing procedures should be developed,documented and exercised between interconnected systems. G.INFORMATION EXCHANGE -DISTURBANCE REPORTING Criterla Reference isturbance r ing-Disturban run 1 rren which j rdize th ration of the interconnected systems,that result,or could result,in system equipment damage,or customer interruption S,shall be studied in sufficient depth to increase industry knowledge of]ical inter ion m hani h similar ven n reven f nagers,reliabili ncils,and regulator nci ntitl information, Requirements 1.Major operating problems that could affect other systems shall be reported as soon as possible to adjacent systems.These operating problems include loss of generation or load or facilities failures. 2.Bulk system disturbances affecting two or more systems shall be promptly analyzed by the affected systems. ALASKA INTERTIE Approved NERC -I1.8-Revised GUIDE Il.SYSTEM SECURITY ALASKA INTERTIE G.INFORMATION EXCHANGE -DISTURBANCE REPORTING 3.Based on the magnitude and duration of the disturbance or unusual occurrence,those systems responsible for investigating the incident shall provide oral,and if appropriate, written reports. 3.1 An oral report shall be made to the systems'Regional Council staff within twenty--four hours after the disturbance.This oral report is in addition to the reporting requirements of any regulatory agency having jurisdiction over the systems. 4.The U.S.Department of Energy's most recent Power System Emergency Reporting Procedures,shown in Appendix II.G.are the minimum requirements for reporting disturbances to NERC. Recommendations 1.If an operating problem cannot be corrected quickly,the probable duration and possible effects should be reported. 2.The system should provide written reports following a disturbance. 2.1 «If appropriate,a preliminary written report should be available within several days of the disturbance. 2.2 'If appropriate,a final written report should be available for review according to system policies. 3.If,in the judgment of the system(s)involved,such an "unusual occurrence”would be of interest to the electric utility industry,the incident should be reported to NERC whether or not it is reported under DOE Reporting Procedures. 4.When there has been a disturbance affecting the bulk system,the Region's OC representatives should make themselves available to the system or systems immediately affected in order to provide any needed assistance in the investigation. 5.Information concerning bulk system disturbances in other parts of the world can be of value in furthering the objectives of NERC.To the extent that relevant information can be obtained,it should be appropriately utilized. Background Other affected systems must be kept informed of potential or actual operating problems. Disturbances which result in substantial customer interruptions will attract news media.The event and its causes will also be of considerable interest to the electric utility industry.The NERC staff is the focal point for numerous inquiries from industry leaders,regulatory agencies, and the media when there has been a bulk electric system disturbance.It is expected that all systems will keep their Regional Council staffs advised of potential system problems or actual disturbances.Disturbances will be discussed by the Operating Committee.Each disturbanceshouldbeviewedbysystemoperatorsasapotentiallearningexperience. ALASKA INTERTIE Approved NERC oll.9-Revised oeoeoeowweOeOeOeweBeweOeOeReOeOeOeOwOeBeOwEeOeSeCeowoeGUIDE II.SYSTEM SECURITY ALASKA INTERTIE G INFORMATION EXCHANGE --DISTURBANCE REPORTING H.INFORMATION EXCHANGE --SABOTAGE REPORTING Criterla Reference TOpri ms vernmental nei n 1 i Requirements 1.System operators shall be provided with guidelines including lists of utility contact personnel, for reporting disturbances due to sabotage events. 2.Systems shall establish communications contacts with local Federal Bureau of Investigation (FBI)or Royal Canadian Mounted Police (RCMP)officials and develop reporting procedures as appropriate to their circumstances. Recommendations 1.Systems should establish procedures for supplying sabotage-related information to the media. Release of this information must be coordinated with the appropriate FBI or RCMP personnel. Background Prompt notification to other systems,law enforcement agencies,and regulatory bodies following disturbances caused by sabotage is essential in minimizing the adverse effects on the security of the Interconnection. i.MAINTENANCE COORDINATION Criterla Reference h m shall lish schedules for in ion and preventive maintenan fi i rapsmission ion m ntrol,communication an her electri iliti These maintenan nd in ion schedules shall inated with other m D ntrol ar ssure_an equipmen rn that willn iolate interconnection Requirements 1.Scheduled generator and transmission outages that may affect the reliability of interconnected operations shall be planned and coordinated among affected systems and control areas. Special attention shall be given to results of pertinent studies. 2.Scheduled outages of system voltage regulating equipment,such as automatic voltage regulators on generators,supplementary excitation control,synchronous condensers,shunt and series capacitors,reactors,etc.,shall be coordinated as required. ALASKA INTERTIE Approved NERC 11.10-Revised GUIDE tl.SYSTEM SECURITY ALASKA INTERTIE y MAINTENANCE COORDINATION 3.Scheduled outages of telemetering and control equipment and associated communication channels shall be coordinated between the affected areas. ALASKA INTERTIE Approved NERC -fL11-Revised ALASKA INTERTIE APPENDIX 11.G. REPORTING REQUIREMENTS FOR MAJOR ELECTRIC UTILITY SYSTEM EMERGENCIES Every electric utility or other entity subject to the provisions of Section 311 of the Federal Power Act,engaged in the generation,transmission,or distribution of electric energy for delivery and/or sale to the public shall expeditiously report to the U.S.Department of Energy's (DOE) Emergency Operation Center (EOC)any of the events described in the following.(A report ora part of a report required by DOE may be made jointly by two or more entities or by a Regional Council or power pool.) A.LOSS OF FIRM SYSTEM LOADS 1,Any load shedding actions resulting in the reduction of over 100 megawatts (MW)of firm customer load for reasons of maintaining the continuity of the bulk electric power supply system. 2.Equipment failures/system operational actions which result in the loss of firm system loads for a period in excess of 15 minutes,as described below: 2.1.Reports from entities with a previous year recorded peak load of over 3,000 MW are required for all such losses of firm loads which total over 300 MW. 2.2.Reports from all other entities are required for all such losses of firm loads which total over 200 MW or 50%of the total customers being supplied immediately prior to the incident,whichever is less. 3.Other events or occurrences which result in a continuous interruption for three hours or longer to over 50,000 customers,or more than 50%of the system load being served immediately prior to the interruption,whichever is less. NOTE:The DOE EOC shall be notified as soon as practicable without unduly interfering with service restoration and,in any event,within three hours after the beginning of the interruption. B.VOLTAGE REDUCTIONS OR PUBLIC APPEALS 1.Reports are required for any anticipated or actual system voltage reductions of three percent or greater for purposes of maintaining the continuity of the bulk electric power supply system. 2.Reports are required for any issuance of a public appeal to reduce the use of electricity for purposes of maintaining the continuity of the bulk electric power system. NOTE:The DOE EOC shall be notified as soon as practicable,but no later than 24 hours after initiation of the actions described in paragraph 2,above. C.VULNERABILITIES THAT COULD IMPACT BULK ELECTRIC POWER SYSTEM ADEQUACY OR RELIABILITY 1.Reports are required for any actual or suspected act(s)of physical sabotage (not vandalism) ALASKA INTERTIE Appoved NERC -1-Revised APPENDIX II.G.-REPORTING REQUIREMENTS FOR MAJOR ELECTRIC UTILITY SYSTEM EMERGENCIES or terrorism directed at the bulk electric power supply system in an attempt to either: 1.1,Disrupt or degrade the adequacy or service reliability of the bulk electric power system such that load reduction action(s)or a special operating procedure is or may be needed. 1.2.Disrupt,degrade,or deny bulk electric power service on an extended basis to a specific:(1)facility (industrial,military,governmental,private),(2)service (transportation,communications,national security),or (3)locality (town,city, country).This requirement is intended to include only major events involving the supply of bulk power. D.REPORTS FOR OTHER EMERGENCY CONDITIONS OR ABNORMAL EVENTS 1,Reports are required for any other abnormal emergency system operating conditions or other events which,in the opinion of the reporting entity,could constitute a hazard to maintaining the continuity of the bulk electric power supply system.DOE has a special interest in actual or projected deterioration in bulk power supply adequacy and reliability due to any causes. Events which may result in such deterioration include,but are not necessarily limited to: natural disasters;failure of a large generator or transformer;extended outage of a major transmission line or cable;Federal or state actions with impacts on the bulk electric power system. NOTE:The DOE EOC shall be promptly notified as soon as practicable after the detection of any actual or suspected acts(s)or event(s)directed at increasing the vulnerability of the bulk electric power system.A 24-hour maximum reporting period is specified in the regulations;however, expeditious reporting,especially of sabotage or suspected sabotage activities,is requested. 1. FUEL SUPPLY EMERGENCIES Reports are required for any anticipated or existing fuel supply emergency situation which would threaten the continuity of the bulk electric power supply system,such as: 1.1,Fuel stocks or hydroelectric project water storage levels are at 50%or less of normal for that time of the year,and a continued downward trend is projected. 1.2.Unscheduled emergency generation is dispatched causing an abnormal use of a particular fuel type,such that the future supply or stocks of that fuel could reach a level which threatens the reliability or adequacy of electric service. NOTE:The DOE EOC shall be notified as soon as practicable,or no later than three days after the determination is made. ALASKA INTERTIE Appoved NERC -2-Revised ALASKA INTERTIE GUIDE Ill,EMERGENCY OPERATIONS A.INSUFFICIENT GENERATION CAPACITY Criterla Reference ng prepar ] Requirements 1.Operating agreements between neighboring systems or pools shall contain appropriate provisions for emergency assistance,including provisions to obtain emergency assistance from remote systems or pools. 2.In the event of a capacity deficiency,generation and transmission facilities shall be used to the fullest extent practicable to promptly restore normal system frequency and voltage and return ACE to acceptable performance criteria as defined in Guide LE. 2.1.If automatic generation control (AGC)has become inoperative,manual contro!shall be used to adjust generation to maintain scheduled interchange. 2.2.The deficient system shall schedule all available assistance that is required with as much advance notice as possible. 2.3.The deficient system shall use the assistance provided by the Interconnection's frequency bias only for the time needed to accomplish the following: 2.3.1.Utilize its readily available operating reserve. 2.3.2.Analyze its ability to recover using only its own resources. 2.3.3.If necessary,determine the availability of assistance from other systems and schedule that assistance. 3.If all other steps prove inadequate to relieve the capacity emergency,the system shall take immediate action which includes,but is not limited to,the following: 3.1.Schedule all available emergency assistance from other systems. ALASKA INTERTIE Approved NERC olll.t-Revised GUIDE Ill.EMERGENCY OPERATIONS ALASKA INTERTIE A.INSUFFICIENT GENERATION CAPACITY 3.2.Implement manual load shedding. 4.Unilateral adjustment of generation to return frequency to normal by systems not experiencing capacity deficiencies,beyond that supplied through frequency bias action and interchange schedule changes,shall not be attempted.Such adjustment may jeopardize overloaded transmission facilities. Recommendations 1.Generators and their auxiliaries should be able to operate reliably at abnormal voltages and frequencies. 2.Where station service generators are used in parallel with the system,station auxiliary busses should be separated automatically from the system before the frequency has decayed sufficiently to adversely affect the station service units. 3.Plant operators should be supplied with instructions specifying the frequency and voltage below which it is undesirable to continue to operate generators connected to the system. 3.1.Protection systems should be considered for automatically separating the generators from the system at predetermined high and low frequencies. 3.2.If feasible,generators should be separated with some local,isolated load still connected.Otherwise,generators should be separated carrying their own auxiliaries. 4.Emergency sources of power should be available to facilitate safe shutdown,enable turning gear operation,minimize the likelihood of damage to either generating units or their auxiliaries,maintain communications,and expedite restarting. B.TRANSMISSION ---OVERLOAD,VOLTAGE CONTROL Criteria Reference ALASKA INTERTIE Approved NERC -fl1.2-Revised GUIDE Ill.EMERGENCY OPERATIONS ALASKA INTERTIE B.TRANSMISSION -OVERLOAD,VOLTAGE CONTROL Requirements 1,If an overload on a transmission facility or abnormal voltage/reactive condition persists due to operations of another system,the affected system shall notify the neighboring or remote system(s)of the severity of the overload or abnormal voltage/reactive conditions and request appropriate relief. 2.If the overload on a transmission facility or abnormal voltage/reactive condition persists and equipment is endangered,the affected system or pool may disconnect the affected facility. Neighboring systems impacted by the disconnection shall be notified prior to switching,if practicable,otherwise,promptly thereafter. 3.Action to correct a transmission overload shall not impose unacceptable stress on internal generation or transmission equipment,reduce system reliability beyond acceptable limits,or unduly impose voltage or reactive burdens on neighboring systems.If all other means fails, corrective action may require load reduction. 4.Systems shall take all appropriate action up to and including shedding of firm load in order to keep the transmission facilities within acceptable operating limits. C.LOAD SHEDDING Criteria Reference fter taking all other remedials m_or controlarea wh integrity is inj rd u insufficien neration or transmission ci hall sh ustomer load ratherthanriskan uncontrolled failure of components of the Interconnection, Requirements 1.Automatic load shedding shall be coordinated throughout the Region or Subregion with other underfrequency isolation,such as generator tripping or isolation,shunt capacitor tripping, and other automatic actions which occur during abnormal frequency or voltage conditions. 2.Automatic load shedding shall be in steps related to one or more of the following:frequency, rate of frequency decay,voltage level,rate of voltage decay,or power flow. 3.After a system or control area separates from the Interconnection,if there is insufficient generating capacity to restore system frequency following automatic underfrequency load shedding,additional load shall be shed manually. Recommendations 1.Voltage reduction for load relief should be made on the distribution system.Voltage reduction on the subtransmission or transmission system may be effective in reducing load; ALASKA INTERTIE Approved NERC -l11.3-Revised GUIDE tll.EMERGENCY OPERATIONS ALASKA INTERTIE C.LOAD SHEDDING however,voltage reduction should not be made on the transmission system unless the system has been isolated from the Interconnection. 2.In those situations where it will be beneficial,manual load shedding should be used to prevent imminent separation from the Interconnection due to transmission overloads or to prevent voltage collapse. D.SYSTEM RESTORATION Criteria Reference 4 a - a a 4".ad ud Jerl nn ms an ntrol ar hall rdin heirr ration actions,R ration ll iven h ion ly of power plants and the transmission m,Even though th ion j x iti tem rators shall avoid prematur ion reven : ored @ nizing that load an neration m remain in balance at norma!frequen h mi restored, Requirements 1.Each system shall have a restoration plan. 1.1.Operating personnel shall be trained in the implementation of the plan.Such training should include simulated exercises,if practicable. 1.2.The restoration plan shall be updated,as necessary,to reflect changes in the power system network and to correct deficiencies found during the simulated restoration exercises. 1.3.Telecommunication facilities needed to implement the plan shall be periodically tested. 2.Following a disturbance in which one or more system areas become isolated,steps shall begin immediately to return the system to normal: 2.1.The system operator shall determine the extent and condition of the isolated area(s). 2.2.The system operator shall then take the necessary action to restore system frequency to normal,including adjusting generation,placing additional generators on line,or load shedding. 2.3.When voltage,frequency and phase angle permit,the system operator may resynchronize the isolated area(s)with the surrounding area(s),properly notifying ALASKA INTERTIE Approved NERC oIll.4-Revised GUIDE Ill.EMERGENCY OPERATIONS ALASKA INTERTIE D.SYSTEM RESTORATION adjacent systems,and considering the size of the area being reconnected and the capacity of the transmission lines effecting the reconnection. 2.4.Restoration of off-site power to nuclear stations shall be given high priority. E.EMERGENCY INFORMATION EXCHANGE Criterla Reference Asystem,control area,or pool which is experiencing or anticipating an operating emergency ]muni i rrent and futur ighborin m ntrol ar r poolsan r h he Interconnection m ]rovi mergen istan hall make known heir iliti Requirements 1.A system shall inform other systems in their Region or Subregion,through predetermined communication paths,whenever the following situations are anticipated or arise: 1.1.The system's condition is burdening other systems or reducing the reliability of the Interconnection. 1.2.The system is unable to purchase capacity to meet its load and reserve requirements on a day-ahead basis or at the start of any hour. 1.3.The system's line loadings and voltage/reactive levels are such that a single contingency could threaten the reliability of the Interconnection. 1.4.The system anticipates 3%or greater voltage reduction or public appeals because of an inability to purchase emergency capacity. 1.5.The system has instituted 3%or greater voltage reduction,public appeals for load reduction,or load shedding for other than local problems. 1.6.The system suspects or has identified a multi-site sabotage occurrence,or single-sitesabotageofacriticalfacility. 2.Refer to Appendix VLA.for information regarding the communication network for each Interconnection. F.SPECIAL SYSTEM OR CONTROL AREA ACTION Criterla Reference ALASKA INTERTIE Approved NERC olll.5-Revised GUIDE Ill.EMERGENCY OPERATIONS ALASKA INTERTIE Requirements 1,When an operating emergency occurs,a prime consideration shall be to maintain parallel operation throughout the Interconnection.This will permit rendering maximum assistance to the system(s)in trouble. If an area becomes separated during a disturbance,interchange schedules between control areas or fragments of control areas within the separated area shall be immediately reviewed and appropriate adjustments made in order to gain maximum assistance in restoration. Attempts shall be made to maintain the adjusted schedules whether generation control is manual or automatic. Recommendations 1,If abnormal levels of frequency or voltage resulting from an area disturbance make it unsafe to operate the generators or their support equipment in parallel with the system,their separation or shutdown should be accomplished in a manner to minimize the time required to re-parallel and restore the system to normal. AGC should remain operative if practicable. CONTROL CENTER BACKUP Criterla Reference h contro!area shall hav lan nti rationin the eventi ntrol cen mes inoperabl Recommendations 1.The standards of Guide I should be considered when developing the plan to continue operation so that the control area will not be a burden to the Interconnection if its own control center becomes inoperable. 1.1.If the control area has a backup control center,it should be remote from the primary control center site. ALASKA INTERTIE Approved NERC IN.6-Revised ALASKA INTERTIE GUIDE IV.OPERATING PERSONNEL A.RESPONSIBILITY AND AUTHORITY Criteria Reference h m rator shall 1 fficien Ti ke an ion n r Requirements 1.Each control area shall provide its operators with a clear definition of their responsibilities and authority. 2.Each control area shall make other system personnel aware of the authority of the system operator. B.SELECTION Criterla Reference h system and control area shall sel i erator nf rs that are designed rom reliabl ration Recommendations 1.Personnel selected as system operators should be capable of directing other operating personnel in their own system,and at the same time,working compatibly with their counterparts in adjacent systems. 1,1.A system operator should have a high level of intellectual ability,above-average reasoning,reasonable mechanical,electrical,and mathematical aptitude,plus skills in communications,supervision,and decision-making. 1.2.Successful performance in lower-level assignments is desirable in the selection of system operators. 2.To maintain an adequate level of capability and expertise in system operations,each system should implement a screening and selection procedure for its system operators which may include: ALASKA INTERTIE Approved NERC -IV.1-Revised GUIDE IV.OPERATING PERSONNEL ALASKA INTERTIE B.SELECTION 2.1.Evaluation of candidates against a detailed job description. 2.2.Analysis of the candidate's past record including experience. 2.3.In-depth interview with each candidate. 2.4.Evaluation of intelligence,logic,aptitude,mathematical and communications skills along with psychological fitness. 2.5.Educational background check. 2.6.Physical examination,including tests for hearing and vision. C.TRAINING Criterla Reference ch system ntrol ar nd/or Region shall provide i rsonnel with training that i i rom liabl ion Requlrements 1.Each control area shall provide its system operators with guidelines for solving problems that can be caused by realistic contingencies and known facility limitations. 2.Each system operator shall be thoroughly indoctrinated in the basic principles and procedures of interconnected systems operation as outlined in the NERC-OC Criteria and Guides as well as in Regional,pool,and control area operating policies. 3.Each control area shall have procedures for the recognition of and for making its system operators aware of sabotage events on its facilities and multi-site sabotage affecting larger portions of the Interconnection.Procedures shall also be established for the communication of information concerning sabotage events to appropriate parties in the Interconnection. Recommendations 1.Each system should implement a training program for its system operating personnel. 1.1.Training should include both classroom and on-the-job training. 1.2,Each system should periodically practice simulated emergency situations. 2.Each system should consider a power system simulation training program. ALASKA INTERTIE Approved NERC -1V.2-Revised GUIDE IV.OPERATING PERSONNEL ALASKA INTERTIE C.TRAINING 3.Each system should consider the list of suggested items in Appendix IV.C.for inclusion in their training program. 4.Each system should consider sabotage awareness as part of their training program. Background The increasing sophistication of power system control centers,which include control equipment,instrumentation and data presentation techniques,plus the closer integration of power systems through stronger interconnections,requires careful selection and training of system operating personnel.Proper action during a system emergency,as well as in the minute-to-minute operation of a complex system,depends upon human performance.Each system operator should be well qualified,adequately educated,mentally suited,and thoroughly indoctrinated in the principles and procedures of interconnected system operation.To achieve and maintain the necessary expertise,a well-defined training program for system operating personnel is essential. To operate a power system effectively,a system operator must have a thorough understanding of the basic principles of electricity.A power system consists of a variety of components,equipment,and apparatus.As with basic principles of electricity,a thorough understanding of this apparatus,its functions and characteristics,is essential,along with how these devices integrate into an operating system.The system operator should also have skills in supervision,communications and decision-making. The threat of sabotage to the facilities of the Interconnection requires special training of system operators to increase their awareness and ability to quickly communicate information concerning suspected or confirmed sabotage events. ALASKA INTERTIE Approved NERC -IV.3-Revised GUIDE IV.OPERATING PERSONNEL ALASKA INTERTIE C.TRAINING ; D.RESPONSIBILITY TO OTHER OPERATING GROUPS Criteria Reference h man ntrol ,rsonnel shall r nsive to the information requiremen f other m ntrol ar ols,th ions,and the NER ratin mmitte Requirements 1.System and control area personnel shall be aware of the operating information needs of other systems,control areas,pools,Regions,and the NERC staff. 2.Procedures shall be in place for the effective transfer of operating information between these other groups. Background A key ingredient of good system and Interconnection operation is the efficient transfer of information between the other various operating personnel during normal as well as emergency operating conditions. ALASKA INTERTIE Approved NERC -IV.4-Revised ALASKA INTERTIE APPENDIX IV.C.SUGGESTED ITEMS FOR INCLUSION IN A TRAINING COURSE The following outline includes suggested items for inclusion in a training course.This outline is intended to be a comprehensive listing to be utilized by interconnected systems in designing training courses to meet the specific needs of system operating personnel. A.NORMAL OPERATIONS 1.Power flow concepts,determination and control. 1.1 1.2. Alternating Current (ac) 1.1.1.Generation 1.1.2.Transmission 1.1.3.Transformation 1.1.4,Loads and effects on system 1.1.5.Phase angle 1.1.6.Phase shifting transformers 1.1.7.Reactors 1.1.8.Capacitors 1.1.9.Parallel flows Direct Current (dc) 1.2.1.Transmission 1.2.2.Interconnections 2.Voltage control concepts 2.1. 2.2. 2.3. 2.4. 2.5. 2.6. 2.7. 2.8. NERC Load characteristics Standards Schedules Causes for voltage deviations Generation excitation Transformer taps Reactive sources The need for and importance of: 2.7.1.Generators 2.7.2.Synchronous condensers 2.7.3.Capacitors 2.7.4.Reactors 2.7.5.Static var compensators Line and cable switching -1- ALASKA INTERTIE Approved Revised APPENDIX IV.C.SUGGESTED ITEMS FOR INCLUSION NERC IN A TRAINING COURSE Control concepts 3.1. 3.2. 3.3. 3.4. 3.5. 3.6. Dispatching techniques AGC and unit governor relationships Area control error Interchange control Inadvertent interchange Special operating program(s) Economic operations concepts 4.1. 4.2. 4.3. 4.4, 4.5. 4.6. 4.7. 4.8. 4.9. 4.10. 4.11. 4.12. 4.13. Dispatching techniques Heat rates Fuel costs Start-up and shutdown costs Pumped storage costs Unit commitment Economic loading Transmission loss effect Reactive flow Utilization of limited energy capacity Pumped storage capacity Incremental and decremental costs Accounting procedures Operating guides and constraints 5.1. 5.2. 5.3 5.4. 5.5. 5.6. 5.7. 5.8. 5.9. 5.10. Operating Manual Operating Guides Control Performance Criteria Reliability Criteria for Interconnected Systems Operation Contingency assessments 5.5.1.Generator outage 5.5.2.Transmission outage 5.5.3.Transformer outage 5.5.4,Combination of above Equipment capabilities and limits 5.6.1.Thermal 5.6.2.Voltage/reactive 5.6.3.Relay 5.6.4.Stability Reserve requirements (special) Time error and frequency Voltage 'Switching -voltage and redistribution of flow Operating considerations 6.1. 6.2. 6.3. 6.4. 6.5. Safety of personnel and equipment Synchronizing Line switching and clearance Ferroresonance Metering failures ALASKA INTERTIE ALASKA INTERTIE Approved Revised APPENDIX IV.C.SUGGESTED ITEMS FOR INCLUSION NERC 6.6. IN A TRAINING COURSE Maintenance scheduling criteria 6.6.1.Generation 6.6.2.Transmission 6.6.3.Substation 6.6.4.Protection ABNORMAL OPERATIONS Dynamic performance of system 1.1. 1.2. 1.3. 1.4. 1.5. 1.6. Transient stability Oscillations Relay action Control-initiated swings Causes of disturbances Special protection systems Dynamic performance of equipment 2.1. 2.2. 2.3. 2.4. 2.5. 2.6. Governor response Exciter response Relays and breakers Underfrequency relays 2.4.1.Special protection systems Metering Automatic controls 2.6.1.Plant 2.6.2,AGC 2.6.3.Voltage 2.6.4.Generator and load tripping 2.6.5.System separation Recognition of abnormal conditions 3.1. 3.2. 3.3. 3.4. 3.5. 3.6. 3.7. 3.8. 3.9. 3.10. 3.11, Loss of load Breaker operations Line faults Generator trips Frequency deviations Interchange amounts Voltage levels System separations Communications with other plants and utilities Parallel flows Multi-site sabotage Remedial action 4.1. 4.2. 4.3. 4.4. 4.5. Islanding Load shedding Generator dropping Shifting generation Switching operations,including interconnection -3- ALASKA INTERTIE ALASKA INTERTIE Approved Revised APPENDIX IV.C.SUGGESTED ITEMS FOR INCLUSION ALASKA INTERTIE IN A TRAINING COURSE 4.6.Isolating system operation 4.7.High-and low-frequency operation 4.8.High-and low-voltage operation 5.Recovery 5.1.Generation start-up capabilities and pickup rates '5.2.°Sectionalizing 5.3.Load pickup priorities and problems 5.4.Low voltage networks 5.5.Synchronizing within system and at interconnections 6.Multi-site sabotage awareness 6.1.Physical security of critical facilities 6.2.Multi-site sabotage techniques and strategies 6.3.Criteria for differentiating sabotage or vandalism from routine equipment outages 6.4.Operating considerations unique to multi-site sabotage attacks C.COMMUNICATIONS 1,Facilities available 1.1.Common carrier systems 1.2.Private systems (microwave) 1.3.Radio 1.4.Power line carrier 1.5.Emergency power supplies 2.Information exchange 2.1.Standard terminology 2.2.Neighboring systems 2.3.Coordinating council offices 2.4.Power plants 2.5.Substations 2.6.Management 2.7.News Media 2.8.Governmental agencies D.INTERCONNECTED SYSTEM OPERATION 1,NERC and regional Operating Criteria and Guides 2.Philosophy of operation 2.1.Benefits 2.2.Obligations 2.3.Responsibilities 2.4.Authority 3.Effects on system performance 3.1.Frequency 3.2.Interchange ALASKA INTERTIE Approved NERC -4-Revised APPENDIX IV.C.SUGGESTED ITEMS FOR INCLUSION ALASKA INTERTIE IN A TRAINING COURSE 3.3.Reserves 3.4.Mutual assistance 3.5.Pooling arrangements 3.6.Communications 3.7.Solar Magnetic Disturbance 4.Off-normal operations 4.1.Responsibilities 4.2.Actions required E.MODERN POWER SYSTEM CONTROL AIDS 1.Equipment 1.1.Man-machine interface 1.2.Supervisory control 1.3.Data acquisition 1.4.Failover and restart 2.Theory and use of application programs in normal and emergency operation. 2.1.Interaction of program results on systems and other programs 2.2.Effects of data errors 3.Alternative contro!methods during equipment and program unavailability ALASKA INTERTIE Approved NERC -§-Revised APPENDIX !V.C.SUGGESTED ITEMS FOR INCLUSION ALASKA INTERTIE IN A TRAINING COURSE 4,Typical application programs used 4.1.Economic dispatch 4.2,AGC 4.3.Unit commitment 4.4.Operator load flow 4.5.Contingency analysis 4.6.Corrective strategies 4.7.State estimation 4.8.Interchange accounting 4.9.Transaction evaluation 4.10.Automated billing F.SUPERVISORY SKILLS 1.'Personnel supervision 2.On-the-job training preparation 3.Verbal communication 4.Decision-making 5.Stress influence ALASKA INTERTIE Approved NERC -6-Revised --owALASKA INTERTIE GUIDE V.OPERATIONS PLANNING A.NORMAL OPERATIONS Criterla Reference Requirements 1. 2. Each control area shall plan to be able to meet daily load patterns and changes in system load characteristics. The results of system studies pertinent to operations shall be available to the system operators. Recommendations 1.Reviews should be made with planning engineers periodically to ensure that the long-range plans will allow for compliance with the NERC Operating Committee Criteria and Guides. Each control area should participate in studies with other systems,when required,to consider: 2.1.The facilities on each system which may affect the operation of the coordinated area. 2.2.The operating limitations of generating facilities. 2.3.The operating limitations of the system when all transmission facilities are in service. 2.4.The operating limitations of the system when transmission facilities are scheduled or forced out of service. 2.5.Voltage and reactive schedules. Studies should be made annually (or at such times as bulk system changes warrant)to determine the transfer capability between interconnected control areas. Generating capability determination should include,among other variables,weather,ambient air and water conditions,and fuel quality and quantity. Each control area should determine the power transfer capabilities of its transmission system and identify potential problems by conducting operating studies as required. 5.1.Thermal,stability,short-and long-term loading,and voltage limits,plus seasonal (temperature)characteristics,should be considered when determining the ratings on transmission facilities. 5.2.Transfer capability studies should consider voltage,reactive,thermal,and stability limits of internal and external system equipment.(Ref:"Transfer Capability,A ALASKA INTERTIE Approved NERC -V.1-Revised GUIDE V.OPERATIONS PLANNING ALASKA INTERTIE A.NORMAL OPERATIONS Reference Document,"NERC October 1980)Generating unit and transmission facility outage patterns should be considered.Studies should determine additional reactive requirements resulting from reasonable generation and transmission contingencies. 6.Computer models utilized for analyzing and planning system operations should be renewed and updated as necessary to ensure that they accurately and adequately represent the system. 7.Neighboring systems should use uniform line identifiers and ratings when referring to transmission facilities of an interconnected network. B.PLANNING FOR SHORT-TERM EMERGENCY CONDITIONS Criteria Reference f plan nsistent with NER ing Criteria an i rticular]ide IIT il vel d,main ine 'and implement sr ir h tem ntrol r i Requirements 1.Plans developed and maintained to cope with operating emergencies shall include procedures that can be executed by system operators. Recommendations 1.Appropriate governmental agencies should be apprised of the plans. C.PLANNING FOR LONG-TERM EMERGENCY CONDITIONS Criterla Reference h m ntrol ar l,and Regional neil shall intai mprehensiv rdinat r r Lwith long-term 1 r ener ficienci Recommendations 1.Each system or poo!should develop capacity and energy emergency plans that will enable it to mitigate,to the fullest extent possible,the effect of a capacity or energy emergency on itscustomers. 2.Appropriate governmental agencies should be apprised of the plans. 3.If existing interchange agreements cannot be used,new agreements should be arranged to provide for emergency capacity or energy transfers. 4.The energy emergency plan should include or consider the following items: ALASKA INTERTIE Approved NERC -V.2-Revised oeoeGUIDE V.OPERATIONS PLANNING ALASKA INTERTIE C.LONG-TERM DEFICIENCIES 4.1. 4.2. 4,3. 4.4. 4.5. 4.6. 4.7. 4.8. 4.9. 4.10. 4.11. 4.12. 4.13 The functions to be coordinated with and among neighboring systems. An adequate fuel inventory plan which recognizes reasonable delays or problems in the delivery or production of fuel. Fuel switching plans and plans to seek removal of environmental constraints for generating units and plants. The reduction of the system's own energy use to a minimum. Appeals to the public through all media for voluntary load reductions and energy conservation including educational messages on how to accomplish such load reduction and conservation. Implementation of load management and voltage reductions,if appropriate. The operation of all generating sources to optimize the availability of the fuel in short supply. Appeals to large industrial and commercial customers to reduce non-essential energy use and maximize the use of customer-owned generation that rely on fuels other than the one in short supply. Use of interruptible and curtailable load to conserve the fuel in short supply. Requests to appropriate government agencies to implement programs to achieve necessary energy reductions. A mandatory load curtailment plan to use as a last resort.This plan should address the needs of critical loads essential to the health,safety,and welfare of the community. Notification of appropriate government agencies as the various steps of the emergency plan are implemented. Notification of cogeneration and independent power producers to maximize output and availability. 5.The capacity emergency plan should address the following items: 5.1 5.2 5.3. NERC The functions to be coordinated with and among neighboring systems. An adequate fuel supply plan which recognizes reasonable delays or problems in the delivery or production of fuel. Fuel switching plans for units for which fuel supply shortages may occur,e.g.gas and light oil. ALASKA INTERTIE Approved -V3-Revised GUIDE V.OPERATIONS PLANNING ALASKA INTERTIE C.PLANNING FOR LONG-TERM EMERGENCY CONDITIONS 5.4 5.5 5.6 5.7 5.8 5.9 5.10 5.11 5.12 5.13 '5.14 Plans to seek removal of environmental constraints for generating units and plants. The reduction of the system's own energy use to a minimum. Appeals to the public through all media for voluntary load reductions and energy -conservation including educational messages on how to accomplish such load reduction and conservation. Implementation of load management and voltage reductions,as appropriate. The operation of all generating sources to maximize output and availability.This should include plans to winterize units and plants during extreme cold weather. Appeals to large industrial and commercial customers to reduce non-essential energy use and start any customer-owned back-up generation. Use of interruptible and curtailable customer load to reduce capacity requirements. Requests to appropriate government agencies to implement programs to achieve necessary energy reductions. A mandatory load curtailment plan to use as a last resort.This plan should address the needs of critical loads essential to the health,safety,and welfare of the community. Notification of appropriate government agencies as the various steps of the emergency plan are implemented. Notification of cogeneration and independent power producers to maximize output and availability. 6.Each Region,system,and/or pool should participate in the coordination of capacity and energy emergency plans and actions to maximize mutual aid during such emergencies.The following steps should be taken: 6.1. 6.2. 6.3. 6.4. 6.5. NERC Establish and maintain reliable communications between interconnected systems. If a capacity or energy emergency is foreseen,contact neighboring systems as far in advance as possible to assess regional conditions and arrange for whatever relief is available or required. Coordinate transmission and generator maintenance schedules to maximize capacity or conserve the fuel in short supply.(This includes water for hydro generators). Arrange deliveries of electrical energy or fuel from remote systems through normal operating channels. Continue to apprise the interconnected systems of the level of generating capacity or energy supply and future needs. ALASKA INTERTIE Approved -V.4-Revised GUIDE V.OPERATIONS PLANNING ALASKA INTERTIE D.LOAD SHEDDING D.LOAD SHEDDING Criterla Reference m,control ar od Region shal lish a program of manualan matic load i i +31 :2 ..ae age >or extreme Wwe It in an uncontroll lur nen he In necti h m_shall h h rconn n vent yn n ]h in hi Requirements 1.Each system shall establish plans for automatic load shedding and shall give system operators the authority to implement manual load shedding when necessary. 1.1.Load shedding plans shall be coordinated among the interconnected systems. 1.2.Automatic load shedding shall be initiated at the time the system frequency or voltage has declined to an agreed-to level. 1.2.1.Automatic load shedding shall be in steps related to one or more of the following: frequency,rate of frequency decay,voltage level,rate of voltage decay or power flow levels. 1.2.2.The load shed in each step shall be established to minimize the risk of further uncontrolled separation,loss of generation,or system shutdown. 1.3.Automatic load shedding shall be coordinated throughout the Region with underfrequency isolation of generating units,tripping of shunt capacitors,and other automatic actions which will occur under abnormal frequency,voltage,or power flow conditions. Recommendations 1.Automatic load shedding plans should be based on studies of system dynamic performance, simulating the greatest probable imbalance between load and generation. 1.1. NERC Plans to shed load automatically should be examined to determine if unacceptable overfrequency,overvoltage,or transmission overloads might result. 1.1.1.If overfrequency is likely,the amount of load shed should be reduced or automatic overfrequency load restoration should be provided. 1.1.2.If overvoltages are likely,the load shedding program should be modified to minimize that probability.; ALASKA INTERTIE Approved-V.5-Revised GUIDE V.OPERATIONS PLANNING ALASKA INTERTIE D.LOAD SHEDDING 2.When scheduling load to be shed automatically,the system should consider its local area requirements and transmission capabilities between areas. 3.<A generation-deficient control area may establish an automatic isolation plan in lieu of automatic load shedding,if by doing so it removes the burden it has imposed on the Interconnection.This isolation plan may be used only with the consent of neighboring systems,and if it leaves the remaining bulk electric system intact. 4.Acontrol area should consider isolating its generators to protect them from extended abnormal voltage and frequency operation.If feasible,generators should be separated with some local,isolated load still connected.Otherwise,generators should be separated carrying their own auxiliaries. E.SYSTEM RESTORATION Criterla Reference Each system,control area,and Region shall develop and periodically update a logical plan toestablishitselectricsminastableandorderlymannerintheeventofttialortotal shutdown of the system,This plan shall be coordinated with other control areas in the nection r nsi r i ion r r r m from th nerating uni nstructions shall i x vailabilit eneration restoration steps shall be verified b l testing whenever possible ALASKA INTERTIE Approved NERC -V.6-Revised GUIDE V.OPERATIONS PLANNING ALASKA INTERTIE E.SYSTEM RESTORATION Requirements 1.Each system shall establish a restoration plan with necessary operating instructions and procedures to cover emergency conditions,including the loss of vital telecommunications channels. 1.1.Restoration plans must be developed with the intent of restoring the integrity of the Interconnection. 1.2.Restoration plans shall be coordinated with neighboring systems. 2.System restoration procedures shall be verified by actual testing or by simulation. Recommendations 1,Where an outside source of power is necessary for generating unit start-up,switching procedures should be prearranged and periodically reviewed with system operators and other operating personnel. 2.Periodic tests should be made to verify black-start capability. 3.In order to systematically restore loads without overloading the remaining system,opening circuit breakers should be considered to isolate loads in blacked-out areas. 4.Load shed during a disturbance should be restored only when doing so will not have an adverse effect on the system or Interconnection. 4.1.Load may be restored manually or by supervisory control only by direct action or order of the system operator as generating and transmission capacity become available. 4.2.Automatic load restoration may be used where feasible to minimize restoration time. 4.2.2.Automatic restoration should be coordinated with neighboring systems, coordinated areas,and Regions. 4.2.3.Automatic restoration should not aggravate system frequency excursions, overload tie lines,or burden any system in the Interconnection. 5.All synchroscopes should be calibrated in degrees,and phase angle differences at interconnection points should be communicated in degrees. 6.Reenergizing oil-filled pipe-type cables should be given special consideration,especially if loss of oil pumps could cause gas pockets to form in pipes or potheads. 7.The following should be considered when trying to maintain normal transmission voltage during restoration: ALASKA INTERTIE Approved NERC oV.7-Revised GUIDE V.OPERATIONS PLANNING ALASKA INTERTIE 10. 11. 12. 13. SYSTEM RESTORATION 7.1,Removal of shunt capacitors or addition of reactors or addition of small blocks of isolated load to prevent excessive voltage when energizing long transmission lines. 7.2.Effects of energizing high-voltage cables at the end of a long,lightly-loaded system. 7.3.The capability of the generators to provide or absorb reactive power flows. System operators should know the preplanned synchronizing locations and procedures. Procedures should provide for alternative action to be taken in case of lack of information or loss of communication channels that would affect resynchronizing. Each control area should have written plans for orderly start-up and shutdown of the generating units. 9.1.These plans should be updated when required. 9.2.Drills should be held periodically to assure that plant operators are familiar with the plans. Each generating plant should have a source of emergency power to expedite restarting. Hydroelectric plants should have internal provisions for restarting. Backup voice telecommunications facilities,including emergency power supplies and alternate telecommunications channels,should be provided to assure coordinated control or operations during the restoration process. Control centers using SCADA systems should consider providing master trip points for each station to expedite the restoration process. Proper protection systems should be considered in the restoration sequence.Relay polarization sources should be maintained during the process. ALASKA INTERTIE Approved NERC -V8-Revised awnoewe--owALASKA INTERTIE GUIDE Vi.TELECOMMUNICATIONS A.FACILITIES Criterla Reference assure the exchange of Interconnection information necessary to maintain reliability,When possible,these facilities shall be redundant and diversely routed, Requirements 1.Reliable and secure telecommunications networks shall be provided within and among systems,control areas,pools,and Regions. 2.Exclusive telecommunications channels shall be provided between the system control center and the control center of each adjacent connecting system. 3.All telecommunications channels shall be tested regularly or monitored on-line.Special attention should be given to emergency telecommunications channels and channels not used for routine communications. Recommendations 1.Telecommunications networks should be provided for voice,AGC,SCADA,special protection systems,and protective relaying where appropriate. 2.Computer data exchange should be considered where appropriate. 3.Critical telecommunications channels should not require intermediate switching to complete the channel. 4.Alternate and physically independent telecommunications channels should be provided for emergency use to back up the circuits used for critical data and voice communications. 5.Restoration services on critical telecommunications channels should be available 24 hours per day. 6.Each control center should be able to take control of any telecommunications channel for system operator use when necessary. ALASKA INTERTIE Approved NERC -VI.1-Revised --GUIDE VI.TELECOMMUNICATIONS ALASKA INTERTIE A.FACILITIES , Background Ia addition to system,control area,pool and Regional telecommunications channels,networks have been implemented within each of the NERC Interconnections.These networks provide telecommunications capabilities during emergency situations,or when adverse operating conditions appear likely. 1.The Eastern Interconnection uses a telephone network which connects the seven Eastern Regions for voice communications. 2.The Western Interconnection (WSCC)uses a combination voice and computerized message system to connect the four Subregions and the WSCC office. 3.The ERCOT Interconnection uses computer terminal and telephone networks that tie each control area to its respective security center ---one in north Texas,and one in south Texas. Either security center can be tied into either network. Descriptions of the three telecommunication networks and the procedures for operating them are found in Appendix VIA. B.SYSTEM OPERATOR TELECOMMUNICATION PROCEDURES Criteria Reference Requirements 1.Each coordinated area shall provide a means to coordinate telecommunications among the systems in the area.This shall include the ability to investigate and recommend solutions to telecommunications problems within the area and with other areas. Background The Eastern Interconnection has established procedures for notifying all Eastern systems of solar magnetic disturbances.These procedures are found in Appendix VI.B. ALASKA INTERTIE Approved NERC -Vi2-Revised GUIDE Vi.TELECOMMUNICATIONS C.LOSS OF TELECOMMUNICATIONS Criteria Reference Requirements ALASKA INTERTIE 1.Each control area shall have written operating instructions and procedures to enable continued operation of the system during loss of telecommunications facilities. NERC ALASKA INTERTIE Approved Revised_ ALASKA INTER HST Commu ATIwS :(ever\ '\ i . \ U3 .<)|;<. .3 Dizcet RAMs Aiwe To y A C)MEA Cen,Ame?A PX (Fee),y $a meA EXisr> l <.\t<'|$|aE :Ci \ a .|AE _Amcp ())areccrsnse/tent hie aéA Dam eine 7 DiCect Radio Awe To C)iteAHeA-CEA O”™ ALASKA INTERTIE APPENDIX VI.B.NOTIFICATION OF SOLAR MAGNETIC DISTURBANCE WARNINGS Solar Magnetic Disturbances (SMDs)are capable of causing serious disruptions to electric power systems especially in the northern United States and Canada. The National Oceanic and Atmospheric Administration's Space EnvironmentalServicesCenter,located in Boulder,Colorado,provides a solar disturbance forecasting service.Although they are unable to predict precisely when solar flares will occur,they are able to determine when the disturbance is just beginning. The information from this forecasting service is made available to the AmericanElectricPowerServiceCorporation(AEP)of Columbus,Ohio,which has been designated toreceiveanddisseminatenotificationsofpossibleSMDstothesevenEasternRegions. Whenever AEP receives an SMD warning of K-5 or higher,the information will be routed to each system via the Time Notification Channels. ALASKA INTERTIE Approved NERC -1-Revised ALASKA INTERTIE OPERATING COMMITTEE WEDNESDAY,SEPTEMBER 11,1991 (GOLDEN VALLEY ELECTRIC ASSOCIATION BOARD ROOM) MEETING MINUTES Present: James Hall Alaska Electric Generation &Transmission (AEG&T)/Matanuska Electric Assoc.(MEA) Afzal H.Khan Alaska Energy Authority (AEA) Doug Hall Anchorage Municipal Light &Power (ML&P) Tim McConnell Anchorage Municipal Light &Power (ML&P) John Cooley Chugach Electric Association (CEA) Bob Orr Golden Valley Electric Association (GVEA) Larry Colp Fairbanks Municipal Utilities System (FMUS) The meeting was called to order by Vice Chairman Bob Orr at 9:40 a.m.at the Golden Valley Electric Association Board Room,Fairbanks,Alaska. John Cooley moved that the I0C adopt the July 10,1991 meeting minutes.Doug Hall seconded the motion.The motion was adopted unanimously. The September 11,1991 I0C meeting agenda was modified byaddingItemsI,J and K.The modified agenda was adoptedunanimously. Under Dispatch,Bob Orr stated that this subcommittee did not meet. Under Protection Coordination,Afzal Khan stated that on August 15,1991 this subcommittee met with John Doudna and briefly discussed the Underfrequency Load Shedding Study Contract.Mr.Doudna stated that he will respond to AEA letters dated August 14,1991 and August 15,1991. Under the Machine/Rating Subcommittee,the IOC has not received the Machine/Rating subcommittee August 28,1991 meeting minutes. Under Reliability/cCriteria,John Cooley Stated that this subcommittee did not meet because there was not any work assigned by I0c. Under Correspondence,Afzal Khan stated that he received the following: 1)GVEA letter,dated July 17,1991,regarding Intertie 1 Operating Committee Members. 2)CEA letter,dated May 20,1991,regarding CEA's representative on the Intertie Operating Committee and its subcommittees. Under Intertie Status,there was a brief discussion on the Goldhill substation SVC Building roof addition and Intertie structure 749 temporary fix. No visitors were present. The Operating Committee took a break from 10:30 a.m.to 10:45 a.m. The Operating Committee went into work session. Under Dispatch,Vice Chairman Bob Orr stated that each I0c member needs to work with their Production/Generation group for obtaining the necessary information on machine outages and/or data.In addition,the information associated with disturbances needs to be forwarded to area controllers.Bob Orr stated that the Dispatch subcommittee needs to update the Alaska Intertie Operating Guides with the latest NERC guides before the next IOC meeting.IOC will have to adopt the revised Operating Guides at the next IOC meeting. Under Protection Coordination,the discussion was focussed on the PTI Contract for the Railbelt Under Frequency Load Shedding Study. Under Machine/Rating,Vice Chairman Bob Orr stated that the Machine/Rating subcommittee's proposed agenda of August 28, 1991 meeting looks good. Under Reliability/Criteria,Vice Chairman Bob Orr stated that this subcommittee should undertake further discussion on the reactor installation at the Douglas'substation. There was a brief discussion on the analytical review of outages/disturbances and disturbance reporting and evaluation. The Operating Committee took a lunch break from 12:10 p.n. to 12:50 p.m. Under SVS,there was no discussion. Under Intertie FY93 Budget,Afzal Khan distributed the preliminary FY93 Budget for IOC review and comments. Under T/L Structure and Conductor Evaluation,there was a brief discussion on the proposed guard structure for the 2 Pp)FE Caswell Lakes road crossing and weather station.Vice Chairman Bob Orr stated that the Reliability/criteria subcommittee should make a decision on the guard structure installation at the Caswell Lakes road crossing.John Cooley stated that the AEA should find out from the manufacturer about the structure integrity when something is done to the structure.There was also a brief discussion on snow and iceing problem on the southern portion of the Alaska Intertie. The I0C briefly discussed the Kenai islanding.The CEA will island the Kenai area on September 16,1991 and this will cause an outage of the Intertie. Jim Hall briefly discussed the MEA tap of the Alaska Intertie close to the Talkeetna-Spurr road.This tap will include 138 kV motor operated line switches,138 kV circuit switcher,power transformer,25 kV equipment and transformer protection (includes differential,overcurrent and pressure).The estimated peak load is 2 MW.Jim Hall stated that the substation design will be completed by mid summer 1992.There was a brief discussion on the MEA tap. The IOC members briefly discussed the spinning reserve issue.The discussion was focussed on the different methods of reserve calculations,level of spinning reserve and how it is allocated among the participants and what reserves available and response. Vice .Chairman Bob Orr recommends that the utilities update Intertie Operating Committee and its subcommittees member list. Under Formal Operating Committee Action/Recommendation,Vice Chairman Bob Orr moved that the IOC adopt the ten year climbing cycle for line maintenance.John Cooley seconded the motion.The motion was adopted unanimously. Under Subcommittee Assignments,Vice Chairman Bob Orr directed the DISPATCH subcommittee to meet at the discretion of its Chairman to work on:Dispatch Training Plan; maintenance response and communications coordination among the area utilities and Technical Guidelines for Operation, Metering and Protective Relaying for Non-Utility Power Producers and Cogenerators and develop operating guides to go with them.In addition,the Dispatch subcommittee is to investigate switching and tagging procedures and submit revised NERC Operating Guides for IOC approval.Also Vice Chairman Bob Orr directed this subcommittee to propose a regular schedule of meetings to I0c. Vice Chairman Bob Orr directed the MACHINE/RATING 3 subcommittee to meet at the discretion of its Chairman to continue work on the machine rating book.Also Vice Chairman Bob Orr directed this subcommittee to follow the proposed agenda of the MACHINE/RATING subcommittee memo dated August 15,1991. Vice Chairman Bob Orr directed the PROTECTION COORDINATION subcommittee to meet at the discretion of its Chairman to continue work on underfrequency load shedding study. Vice Chairman Bob Orr directed the RELIABILITY/CRITERIA subcommittee to meet at the discretion of its Chairman to evaluate the technical merits and cost consideration for Reactor installation at Douglas substation. THE NEXT REGULARLY SCHEDULED MEETING OF THE ALASKA INTERTIE OPERATING COMMITTEE WILL BE ON WEDNESDAY,NOVEMBER 13,1991, AT 9:30 A.M.AT THE CHUGACH ELECTRIC ASSOCIATION TRAINING ROOM. The Operating Committee set the agenda for the next meeting of the Operating Committee. Larry Colp moved for the meetingto adjourn,seconded by BobOrr.The Operating Committee unanimously adopted the motion to adjourn at 2:40 p.m. Respectfully submitted,Ofjee.Ht hlawAfzalH.Khan Manager/Engineering Support Stanley E.Sieczkowski,Secretary Alaska Intertie Operating Committee Attachments: 1.November 13,1991 meeting agenda The following were distributed at the Sept.11,91 meeting: 2.Alaska Intertie Preliminary FY93 Budget. 3.MEA letter to AEA dated August 15,1991. Subject:Anchorage-Fairbanks Intertie Budget 4.GVEA letter to AEA dated July 26,1991. Subject:GVEA Revised FY93 Alaska Intertie Operating Budget Submittal 5.Anchorage-Fairbanks Intertie Project Insurance Premiums 4 11. 12. 13. 14. and Fees FY92 with attachments. AEA letter to MEA dated August 16,1991. Subject:Anchorage-Fairbanks Intertie,Talkeetna Yard Inventory GVEA letter to AEA dated July 11,1991. Subject:AEA Tie Line Patrol AEA letter to GVEA dated August 16,1991. Subject:Goldhill Substation SVC Building Roof Addition Dryden &LaRue letter to AEA dated September 6,1991. Subject:Anchorage-Fairbanks Intertie Structure 749 Temporary Fix Guy Anchors GVEA letter to AEA dated July 17,1991. Subject:IOC Committee Members CEA letter to AEA dated May 20,1991. Subject:Alaska Intertie Operating Committee Members AEA letter to Power Technologies dated August 15,1991. Subject:Railbelt Load Shedding Study,Scope of Work AEA letter to Power Technologies dated August 14,1991. Subject:Railbelt Load Shedding Study for Alaska Intertie Operating Committee Proposed Agenda,Alaska Intertie Machine Rating Subcommittee August 28,1991 Meeting ALASKA INTERTIE OPERATING COMMITTEE MEETING AGENDA WEDNESDAY,NOVEMBER 13,1991 BEGIN AT 9:30 A.M. I.Adoption of prior meeting minutes II.Approval/modification of agenda III.Committee correspondence and reports A.Dispatch Subcommittee B.Protection Coordination Subcommittee c.Machine/Rating Subcommittee D.Reliability/Criteria Subcommittee E.Correspondence Received F.Intertie Status Update IV.Visitors comments related to items on agenda Vv.Work Session A.Recess and work session B.Dispatch c.Protection Coordination D.Machine/Rating E.Reliability/Criteria F.FY93 Budget G.T/L Structure and Conductor Evaluation VI.Formal Operating Committee action/recommendation VII.Subcommittee Assignments VIII.Determine agenda for next meeting IX.Adjournment Meeting location: Chugach Electric Association Training Room 5601 Minnesota Drive Anchorage,Alaska 99519 (907)563-7494 ALASKA INTERTIE:UPERATING CORAITTEE WiActes MEETING In Attendance:late Sept 11,91 lane Congy Phone Ho Cas FAT VAN [-(E07 TEEIIEY Pf 221 khan AEA :S677 Larry Calp EMUS YS9-O28SSimHeUfACCET745-9 26g Deve Hat!MLih 263-SY4S% Tain MSConpey |ML 263-5494 John §Cooley Chag acte 76Z YS77 DATE: TO: FROM: SUBJECT: Alaska Energy Authority MEMORANDUM September 11,1991 Stanley E.Sieczkowski,DirectorFacilitiesOperations&Engineering Afzal H.Khan,Manager 4EngineeringSupportvVitra...- Alaska Intertie Preliminary FY93 Budget Min ates The table below summarizes the budgeted expenditures by type for theAlaskaIntertieduringFY93: ALASKA INTERTIE FY93 BUDGET Operations: Maintenance: Miscellaneous: TOTAL lEstimate AHK:SES:jd Northern Area Controller (GVEA)Operation Labor SCADA Debt.Service SCADA Maintenance Southern Area Controller (ML&P)Operation Labor SCADA Debt.Service SCADA Maintenance Intertie Operating CommitteeAnalysisandReviewAlaskaEnergyAuthority(AEA) Northern Area Contractor (GVEA)Transmission Line Maintenance Substation Maintenance Southern Area Contractor (MEA)Transmission Line Maintenance Substation Maintenance Talkeetna Material StorageTeelandSub.Contractor (CEA) Transmission Service (MEA)!Info.Services,TelecommunicationsRepair&ReplacementInsurance $209,615 $65,723 $21,284 $216,906 $39,314 $24,534 $50,000 $50,999 $40,364 $108,267 $5,746 $10,800 cc:Gloria Manni,Director/Accounting &AdministrationBillSobolesky,AccountantEricMarchegiani,Civil Engineer/Cost Estimator $296,622 $280,754 $50,000 $184,763 $91,363 $124,813 $17,607 $100,225 $ $ $1,444,947 G Matanuska Electric Association,Inc. P.O.Box 2929 Palmer.Alaska 99645 Telephone:(907)745-3231 Fax:(907)745-9328 mo August 15,1991 Mr.Stanley E.Sieczkowski,DirectorFacilitiesOperationsandEngineeringAlaskaEnergyAuthority P.O.Box 190869 Anchorage,Alaska 99519-0869 Dear Stan: SUBJECT:RAGE-FAIRB,i TIE B Enclosed is MEA's revised "Fiscal Year 1993 WUNAT eS . Intertie Transmission Line Maintenance Budget.”This submittal reflects a reduction in the "TransmissionLineMaintenance”portion of the Budget based on calculations using the newten-year climbing cycle.This revision represents a reduction of $26,039.65 for"Total Transmission Line Maintenance Expense.” Please call should you have any questions. Sincerely, Jac &-HansonAdministrativeAssistant (for) James F.McIntosh Manager of Operations jh201A.0413.45(OPR) Enclosures ce:AEA File Afzal H.Khan,AEA Operations/Engineering Janell McPherson,MEA Accounting Frank O'Brien,MEA Operations Debbi Drake,MEA Accounting Jim Hall,MEA Engineering FISCAL YEAR 1993 ANCHORAGE-FAIRBANKS INTERTIE TRANSMISSION LINE MAINTENANCE BUDGET AND WORK PLAN S U MMAR Y ACTIVITY DESCRIPTION 3 ea.Aerial 1 ea.Ground Patrols 1/10 Climbing Inspection Insurance Right-of-Way Clearing TOTAL TRANSMISSION LINE MAINTENANCE EXPENSE TOTAL SUBSTATION MAINTENANCE EXPENSE TALKEETNA MATERIAL STORAGE REPAIR AND REPLACEMENT Tower Ladders/Material MONTHLY CHARGE Talkeetna Material Storage COST $12,486.36 62,672.60 26,115.78 1,791.07 5,201.60 $108,267.41 $5,745.80 $10,800.00 $22,510.17 $900.00 Note:Emergency and Maintenance charges will be billed as actual expenses each month. 1993 CLIMBING INSPECTIONS Perform climbing inspections on 90 miles of transmission towers,approximately424towers.42 towers per year for the next 10 years. ACTIVITY DESCRIPTION DURATION HR.RATE TOTAL Supervision .75 hrs.ST $61.43 $46.07 Foreman 2.00 hrs.ST 59.63 119.26 Lineman 2.00 hrs.ST 53.27 106.54 Lineman 2.00 hrs.ST 53.27 106.54 SUB TOTAL PER TOWER 378.41 ° EQUIPMENT ACTIVITY DESCRIPTION DURATION HR.RATE TOTAL Truck to Haul Bearcat 2.00 hrs.ST 89.52 $6179.04 Manhaul (pickup)2.00 hrs.ST 14,32 28.64 SUB TOTAL PER TOWER 207 .68 SUB TOTAL PER TOWER 586.09 SUB TOTAL $586.09 X 42 =24,615.78 Per Diem 10 Days @ $300.00 3,000.00 COST FOR YEARLY CLIMB INSPECTION........TOTAL $26,115.78 INSURANCE Special Insurance (required by Contract)$1,791.07 (5) UNATES e =) A GOLDEN VALLEY ELECTRIC ASSOCIATION INC.Box 71249,Fairbanks,Alaska 99707-1249,Phone 907-452-1151 July 26,1991 RECEIVED AUG 7?1991 aska Energy AuthorjAfzalKhanAlly Director,Engineering Support Alaska Energy Authority791EastTudorRoad P.O.Box 190869 Anchorage,Alaska 99519-0869 Subject:GVEA Revised FY93 Alaska Intertie Operating BudgetSubmittal Attached is GVEA's revised FY93 budget submittal for: NORTHERN HALF TRANSMISSION LINE MAINTENANCE The reduction from $72,231 to $50,999 for transmission line maintenance is due to the climbing cycle being extended from fiveyearstotenyears,and more closely reflects actual costs expendedinthepast. Other comments on the proposed budget: 1.It is hoped that MEA can adjust their budget closer to actual and reflect the new ten year climbing cycle. 2.AEA $184,763 budget appears excessive.I don't understand whyittakessomuchtomanagetheintertieandprocessthebills.I would expect a number of $50,000 to $75,000 per year.Notethateachparticipant,including AEA,agreed not to charge fortheOperatingCommittee/Subcommittees time.A more detailedexplanationofcostsshouldbeprovided. 3.Regarding the communications maintenance budget,I understcod that the State was no longer going to charge for thecommunicationcircuits.Please explain the three circuits (15,16,17)from CEA to Eklutna.It seems CEA should be paying forthese. GOLDEN VALLEY ELECTRIC ASSOCIATION INC. Revised FY93 Budget July 26,1991 "Page 2 Thank you for the opportunity to comment on the proposed FY93 intertie budget. MebodJ.aRobertOrr Manager of System Operations cc:Virgil Gillespie FMUS Dave Highers CEA Tim McIntosh MEA Kenneth Ritchey MEA Stan Sieczkowski AEA Tom Stahr AMLP Norm Story HEA Mike Kelly GVEA Robert Hansen GVEA Marvin Riddle GVEA Rev.7-91 FY 1993 ANCHORAGE-FAIRBANKS INTERTIE TRANSMISSION LINE MAINTENANCE (Northern 1/2) AND WORK PLAN summa Yearly Cost 3 ea.Routine Patrols $12,201 1 ea.Ground Patrol 10,000 1/10 Climbing Inspection 27,048 Insurance 1,750 TOTAL TRANSMISSION LINE MAINTENANCE (Northern 1/2)$50,999 Page 1 FY 1993 ANCHORAGE=-FAIRBANKS INTERTIE PREVENTIVE MAINTENANCE AND WORK PLAN of Approximately 85 Mile of Intertie Line (Northern 1/2) Intertie Transmission Line Maintenance Program Section 3.0 AEA Preliminary Draft Routine Patrols,Aerial Special Patrols,Aerial | Emergency Patrols,Aerial Ground Patrols Climbing Inspections There are many conditions that occur which cause operating problemsonatransmissionlineorlimititsusefullife.The above maintenance tasks will help discover these conditions and corrective action may prevent serious damage or line failure. Page 2 FY 1993 ANCHORAGE-FAIRBANKS INTERTIE PREVENTIVE MAINTENANCE BUDGET INTERTIE TRANSMISSION LINE NORTHERN PORTION Routine Patrols Routine visual aerial inspection patrol.Pilot and helicopter (fuelfurnished)by contract or by owner furnished each occurrence. Recommend every 120 days.Three per year. Time Per Hour Total Yearly Helicopter and pilot wet 6 hrs flying $520.00 $3120 Standby time for helicopter 2 hrs standby 0 0 One Line Foreman Inspector 8 hrs ST 64.33 515 One Manhaul Vehicle 8 hrs ST 14.00 112 Infrared Camera 8 hrs 20.00 160 w/helicopter mount High Intensity Light on 8 hrs 20.00 160 helicopter Total $4067 3 ea.Routine Patrols/Year $3917 x 3 =$12,201/yr Special Patrols Special aerial patrol is a non-scheduled or a short notice scheduled visual inspection of the line performed after there has been a momentary interruption due to severe weather or indication ofproblemsinvicinityoftheline. Time Per Hour Total Helicopter and pilot wet Standby time for helicopter One Line Foreman Inspector hrs flying $520.00 $3120 hrs standby 0 0 hrs ST 64.33 515 foe)OOaOnnOne Manhaul Vehicle hrs ST 14.00 112 Infrared Camera hrs 20.00 160 w/helicopter mountHighIntensityLight on hrs 20.00 160 helicopter Total $4067 (NOT INCLUDED IN BUDGET ESTIMATE) Page 3 Rev.7-91 Emergency Patrols Non-scheduled aerial visual inspection when there is an apparentpermanentfaultonthelineandtheprotectivecircuitbreakersarelockedout. Time Per Hour Total Helicopter and pilot wet 6 hrs flying $520.00 $3120Standbytimeforheliccoter2hrsstandby00 One Line Foreman Inspector 8 hrs ST 64.33 515 One Manhaul Vehicle 8 hrs 14.00 112 High Intensity Light with 8 hrs 20.00 160 helicopter mount Total $3907 (NOT INCLUDED IN BUDGET ESTIMATE) Ground Patrols Summer or winter ground patrol.Estimated one patrol per year. Total Equipment Required $5,500 (est.)Total Labor Required 4,500 (est.) Total 10,000 One Ground Patrol/Year $10,000 Page 4 Rev.7-91 Climbing Inspections Climbing inspection,per tower,every ten years unless needed in severe weather areas or remote locations.Estimated 424 towers. Labor Time Per Hour Total Foreman l hr st S$64.33 $64.33 Lineman 1 hr st 64.33 64.33 Apprentice 1 hr st 64.33 64.33 Equipment Equipment Manhaul 1 hr 14.00 14 Possible helicopter 2 hrs 520.00 104 (est.1/5 of towers) Tracked Manhaul 2 hrs 150.00 300 Lodging &meals (3 man @ 110/day and 10 towers/day)33 Total $644/tower Climbing Inspection (1/10 above)for yearly =$27,048 Special Insurance Special Insurance Required by Contract $1,750 TOTAL TRANSMISSION LINE MAINTENANCE $50,999 NOTE:1)Supervision and recordkeeping costs are included in the overhead for the manhour rate. 2)More helicopter time,in addition to that shown,may benecessaryforaccessonroutinegroundpatrolandclimbinginspections. Page 5 FY 1993 GVEA EQUIPMENT Equipment Snow Machine Pick-up (4x4) Service Truck (4x4) Bucket Truck (wheel) Digger Truck (6x6) Dozer 350-550 Trailers (small) Lowboy Trailer Tractor Terra Flex Digger Manhaul Track Vehicle Kershaw Brushcutter Portable Building Terra Flex Bucket ATV (small) Hagglund Bearcat 206 Page 6 Rev.7-91 Cost per Hour $15.00 12.00 14.00 60.00 100.00 60.00 7.00 20.00 70.00 100.00 65.00 100.00 25.00 105.00 15.00 150.00 GVEA LABOR COSTS FY 1993 Position STRAIGHT TIME Dispatcher Electrician/Lineman Accounting Superintendent OVERTIME Dispatcher Electrician/Lineman Accounting Current GVEA Base Rate Overhead $28.38 $36.88 $27.97 $36.36 $25.50 $33.15 $29.13 $37.87 $42.57 $36.88 $55.94 $36.36 $38.25 $33.15 Page 7 Rev.7-91 Total Cost/Manhour $65.26 $64.33 $58.65 $67.00 $79.45 $92.30 $71.40 Revised 7-91 ACCOUNT.NUMBERS AEA INTERTIE MAINTENANCE BASIC ACCOUNT NUMBERS Transmission Operation 560 Operation Supervision and Engineering 562 Station Expense 563 Overhead Line Expense Transmission Maintenance 568 Maintenance Supervision and Engineering 570 Maintenance of Station Equipment 571 Maintenance of Overhead Lines Detailed Accounting Codes Tieline HLS cwS Substation Operation/Man/hr.562.10 562.11 Inventory Substation Maintenance Man/Hr.570.10 570.11 Working Patrol Ground Mile 563.11 Aerial Patrol Mile 563.10 Climbing Inspection Structure 563.12 Insulator (replace)String 571.10 Right-of-Way Reclear Acre 571.11 and Treatment Culvert &Gate Each 571.12 (repair &installation) Tower Repair Structure 571.13 Conductor &Hardware Position 571.16 Inventory/Repair or Replace Emergency Patrol Mile 571.14 'Emergency Repair (major)Incident 571.15 Operations Supervision Man/Hr.560.10 560.10 560.10 and Engineering Maintenance Supervision Man/Hr.568.10 568.10 568.10 and Engineering Page 8 GHS 562.12 570.12 560.10 568.10 WTO oe ANCHORAGE-FAIRBANKS INTERTIE PROJECT INSURANCE PREMIUMS AND FEES FY92 OWNER'S RISK $1 M Line of Credit Fee (4)$1,800 Boiler and Machinery (>)18,473 General Liability (©)2,100 Watercraft and Aviation (4)__500 $22,873 INTERTIE OPERATING COMMITTEE'S RISK General Liability 15,000 Aviation 8,500 $23,500 Total Premium &Fees $46,373 August 7,1991 WQ3UID9 164(4) SELF-INSURED RETENTIONS AND LOSS LIMITS (a)Property*: Covered by Insurance Reserve Business Plan $1,000,000 (b)Boiler and Machinery*: -SIR,Transformers 100,000 kva or more $100,000 -SIR,Turbine Generators,Power Distribution Transformers and all objects at Substation andSwitchyards $50,000 -SIR,All Other Objects $25,000 Loss limit per Accident:$15,000,000 Sub-limits: Expediting Expense $250,000 Ammonia Contamination $75,000 Water Damage $75,000 PBC Clean-up $75,000 Additional Expenses $5,000 (c)General Liability ** SIR $5,000,000 Loss Limit $100,000,000 (d)Watercraft and Aviation **$1,000,000 Loss Limit $200,000,000 Notes: *Property and Boiler Machine self-insured retention are a Intertie OperatingCommittee(IOC)responsibility. **General Liability,Watercraft and Aviation self-insured retention are a Stateresponsibilityforthedurationofthecatastrophiclossfund. BROKER: Corroon &Black,Inc. CARRIERS:°Property -(Exhibit 5) MASTER48(3) °Boiler &Machinery -Chubb/Pacific Indemnity (Exhibit 2 &3) °'Best Rating:A+XIII General Liability°Watercraft &Aviation -Part of overall state policy for the durationofthestatecatastrophiclossfund BOILER &MACHINERY EXCLUSIONS THIS POLICY DOES NOT APPLY: 1)To loss from an accident caused directly or indirectly by: a)A hostile or warlike action,including action in hindering,combating or defending against an actual,impending or expected attack,by (i)any government or sovereign power (de jure or de facto)or any authority maintaining or using military,maval or air forces, (ii)military,naval or air forces,or (iii)an agent of any such government,power,authority or forces. b)Insurrection,rebellion,revolution,civil war or usurped power, including any action in hindering,combating or defending againstsuchanoccurrence,or by confiscation by order of any government or public authority. 2)To loss,whether it be direct or indirect,proximate or remote. a)From an accident caused directly or indirectly by nuclear reaction, nuclear radiation or radioactive contamination,all whether controlled or uncontrolled;or b)From nuclear reaction,nuclear radiation or radioactive contamination,all whether controlled or uncontroiled,caused directly or indirectly by,contributed to or aggravated by an accident; Nor shall the Company be liable for any loss covered in whole or in part by any contract of insurance,carried by the Insured,which also covers any hazard or peril of nuclear reaction or nuclear radiation; 3)To any increase in the loss necessitated by any ordinance,law orregulation,rule or ruling regulating or restricting repair,alteration, use,operation,construction or installation; CORROON &BLACK.INC. 4)Under Sections I,I!,and III to loss: a) b) c) d) e) f) from fire concomitant with or following an accident or from the useofwaterorothermeanstoextinguishfire, from an accident caused directly or indirectly by fire or from the use of water or other means to extinguish fire, from a combustion explosion outside the Object concomitant with or following an accident. from an accident caused directly or indirectly by a combustion explosion outside the Object, from flood unless an accident ensues and the Company shall then be liable only for loss from such ensuing accident, from an accident caused directly or indirectly by earth movement, including but not limited to earthquake,landslide,mud_slide, subsidence or volcanic eruption, from delay or interruption of business or manufacturing or process, from lack of power,light,heat,steam or refrigerations,and from any other indirect result of an accident. CORROON &BLACK.INC. eee 4 ALASKA ENERGY AUTHORITY ANCHORAGE -FAIRBANKS INTERTIE Original Constructional Estimated Value Description/F.E.R.C.Acct.Procurement Cost July,1986 Cantwell Substation (353)$2,250,000 $2,259,000 Gold Hill Substation (353)3,350,000 3,363,400 Healy Substation (353)4,050,000 4,066,200 Tee Land Substation (353)4,150,000 4,166,600 General Property -Misc.1,650,000 1,656,600 $15,450,000 $15,511,800 NOTE:Intertie Completed -1984 To increase the July 1986 values of $15,512,000 to 1991 replacement,a 1.172 factor was used resulting in an estimated 1990 value of $18,178,892 EXHIBIT 1 |CORROON &BLACK,INC.| + ALASKA ENERGY AUTHORITY SYNOPSIS OF BOILER &MACHINERY INSURANCE COVERAGE COVERAGE:Utility Comprehensive (Broad Form) Repair or Replacement Coverage Included Breakdown Coverage on all Turbine Generators LIMITS:Limit per Accident of $15,000,000 Expediting Expense sublimit of $250,000 Ammonia Contamination sublimit of $75,000 Water Damage sublimit of $75,000 PCB Clean-up sublimit of $75,000 Additional Expenses sublimit of $5,000 SPECIAL FEATURES: Coverage for Computer Process Control Equipment Explosion Elimination Endorsement to avoid duplication with the Fire and Extended Coverage perils Contractual Acceptance Provision Annual Property Damage aggregate deductible of $300,000.Anypropertydamagelossinexcessof$10,000 and up to the applicabledeductibleperlossshallbeaccrueduntiltheannualaggregateis reached.Thereafter,each future loss shall be subject to a $10,000 deductible.This is applicable to the following locations: Solomon Guleh Hydro Electric Plant Swan Lake Hydro Electric Plant Tyee Lake Hydro Electric Plant Terror Lake Hydro Electric Plant Anchorage-Fairbanks Intertie Coverage for Computer Process Control Equipment located at the following locations: Copper Valley Electric Diesel Plant,Vaidez,AK Bailey Diesel Plant,Ketchikan,AK Wrangell Diesel Plant,Wrangell,AK Kodiak Diesel Plant,Kodiak Island,AK EXHIBIT2 +$$$$$______| ALASKA ENERGY AUTHORITY DEDUCTIBLES Property Damage deductible of $25,000 per occurrence for all objects except: Property Damage deductible of $50,000,000 per occurrence for all Turbine Generators. Property Damage deductible of $100,000 per occurrence for any Transformer having a capacity of 100,000 KVA or more. EXHIBIT 3 CRABAMA!@ Beart thi PUIMAT ES State of AlaskaNWalterJ.Hickel.Governor a, Alaska Energy Authority A Public Corporation August 16,1991 Mr.J.F.McIntosh Matanuska Electric Association,Inc. P.O.Box 2929 Palmer,Alaska 99645 Subject:Anchorage Fairbanks Intertie,Talkeetna Yard,Inventory Dear Mr.McIntosh: Recently our consultant (Mr.Peabody),a representative from Golden ValleyElectricAssociation(GVEA),and a member of your staff met at the TalkeetnaYardtohuntforvariouspartsthatmightbeusedintherepairofStructureNo.749.This latest experience and the requirement of needing to know what is available incaseofanemergencyrepair,has made us all aware of the need to complete anindepthinventoryoftheTalkeetnaYard. Discussions with personnel at that time indicated that,they thought that it wouldtaketwomenwithaforkliftapproximatelyoneweektoorganizeandinventorytheentireTalkeetnaYard.Based upon this rough estimate,I would like you to allocatethenecessaryresourcestoaccomplishthereorganizationoftheyardandacompleteinventoryofallitemsintheyard.This work should be billed to the AEAasapartofyouron-going maintenance. I expect that your staff will draw up a map of the entire yard indicating the locationofallthedifferentmaterialsintheyard.All loose materials such as bolts,nuts,andotherhardwareshouldbeplacedinwoodenboxesofsimilarhardware.If necessaryconstructtheadditionalboxesthatmaybeneededtoputthesematerialsin,then allthematerialsneedtobeplacedandorganizedsotheywillbeeasilyaccessed. A complete list of the materials will need to be made up with a coding of where intheyardthosematerialsmaybefound.A possible system would be to break theyardupintovarioussectionsandlabelthesectionsbynumber(1,2,3,etc.)or aletter(A,B,C,etc.).The snow depth in Talkeetna gets to be very deep in thewinteranditmaystillbeverydifficulttolocatevariousmaterials,so I wouldrecommendthatyouplaceanantennaateachlocationwithaflagatthetopoftheantennaindicatingthelocation(i.e."A").This would facilitate any need to findmaterialsinthemiddleofthewinter. Generally speaking,the exact details of how the inventory and organization arecompleteddonotconcernme.However,I do wish to stress the need for a complete inventory with the ability to locate any of those materials at anytime of the O PO.BoxAM Juneau.Alaska 99814 (907)465-3575 M PO.Box 190869 704 EastTudor Road Anchorage,Alaska 99519-0869 (907)561-7877 91Q3D1378(1) Mr.J.F.McIntosh August 16,1991Page2 year on short notice.This work should be completed prior to any major snow fall inTalkeetnathisyear.We need to be prepared for an emergency and presently wereallydon't know what we have.I expect to receive an inventory list and a map oftheTalkeetnaYardnolaterthanNovember1,1991.Thanks for your attention to this matter. If you have any questions please feel free to contact me. Sincerely, Stanley E.Sieczkowski,DirectorFacilitiesOperations&Engineering EAM:SES;jd cc:hee rityaskaEnergyAuthorityan,Intertie Operating Committee 91Q3D1378(2) W744/E> - _/ GOLDEN VALLEY ELECTRIC ASSOCIATION INC.Box 71249,Fairbanks,Alaska 99707-1249,Phone 907-452-1151OWED July 11,1991 Afzal Khan Alaska Energy Authority P.O.Box 190869 Anchorage,AK 99£19-0869 Subject:AEA Tieline Patrols This summer we will be completing our first cycle of the ground and climbing patrols on the northern section of the tieline.Except for towers 749 and 571,our crews have found very few problems with the structures. Given this history,I would like to suggest that the IOC entertain the idea of extending the cycle from five years to ten years for the ground and climbing patrols.We would still continue our normal schedule on the aerial patrols (three per year). A.Fe Robert Orr Manager of System Operations ccs:Marvin Riddle Steve Swift Monte Ervin W111 VU TT State of AiaskaDNWalterJHickel,Governor Alaska Energy Authority A Public Corporation August 16,1991 Mr.Robert Orr Manager of System OperationsGoldenValleyElectricAssociation Inc.P.O.Box 71249 Fairbanks,Alaska 99707-1249 Subject:Gold Hill Substation Building Roof Addition Dear Mr.Orr: Please reference Mr.Wyman's recent fax to us concerning the above subject.Wehavereviewedthegeneralschemeandconcurwithit.Please proceed withcompletionofthePlansandSpecificationsandadvertisetocompletetheworkpriortofreeze-up.We expect that you will send us a complete copy of the Plans andSpecificationswhenyoumakethemavailabletocontractors. The preliminary cost estimate as outlined by Loftus &Dailey looks better,but maystillbesomewhatlow.The GVEA shutdown costs ($30,000),as identified will needtobediscussedbytheIOCpriortoinclusion.Please keep us posted as the projectcontinuestoprogress.If you have any questions,please feel free to contact me. Stanley E.Sieczkowski,Director FeFacilitiesOperations&Engineering EAM:SES;jd Sincerely, cc:|Greg Wyman,Golden Valley Electric Association,Inc.Tom Lovas,Chairman,Intertie Operating Committee wre eewReeEricMarchegiani,Alaska Energy Authority Cl PO.BoxAM Juneau,Alaska 99841 (907)465-3575OPO.Box 190869 704 East Tudor Road Anchorage,Alaska 99519-0869 (907)561-7877 91Q3D1377(1) Wii wn kzIDRYDENiILalIRUvE,IINc.CONSULTING /ENGINEERS 6436 Homer Drive.Anchorage.AK 99518 Mailing Adaress:P.O.BOX 111008.ANCHORAGE.AK 99511-1008 1907)REC F WED September 6,1991 SEF 10 199) splaska Energy Authority Stanley E.Sieczkowski,Director Facilities Operations &Engineering ALASKA ENERGY AUTHORITY P.O.Box 190869 Anchorage,Alaska 99519-0869 Reference:Anchorage-Fairbanks Intertie Str.749 Temporary Fix Guy Anchors Eric Marchegiani asked me to give some background on the choice of the guy anchors for the temporary fix and to address why a smaller diameter grouted anchor could not be used.Rohn Abbot of Shannon and Wilson in Fairbanks helped us with the design,particularly with the embedment of the grouted anchors.We also consulted with him about whether the diameter of the anchors could be reduced. In our original instructions we were told that the temporary design should "take into account any final design considerations", therefore the anchors were designed as if they were part of a permanent stabilization scheme. We considered plate anchors,mechanically anchored rock anchors and grouted anchors.The soils at the site are a silty,gravelly sand overlying a weathered schist at roughly 20 ft.depth.The soils and rock are warm permafrost with a temperature below the active zone of around 32°F.The active layer is estimated to be 6 to 8 ft deep in the vicinity of the structure.The soil has ice and ice coated particles. Plate anchors were rejected for several reasons.Plate anchors would require a large excavation,fill would probably have to be flown in to get suitable compaction and design would have to be based on the anchors being in the active zone.Plate anchors would be subject to movement due to the annual freeze thaw cycle and could creep under long term load. Mechanical anchorages for rock anchors require competent rock for installation.The underlying weathered schist is not of sufficient quality to use mechanical anchorages. We decided to use grouted rock anchors.Our design assumption was that the anchor would be in highly weathered schist with a Electric Power:Transmission,Distribution.Substations,Control Systems.Generation.System Studies Stanley E.Sieczkowski September 6,1991 Alaska Energy Authority ;Page 2 temperature of around 32°F.Recommendations for grouting anchors in this environment include having a minimum annular space between the rod and the edge of the hole to have enough mass of grout to generate sufficient heat of hydration to prevent freezing of the grout before curing can take place.CRREL Special Report 80-34, "Design and Construction of Foundations in areas of Deep Seasonal Frost and Permafrost"states ""Grouted anchors may be set in ice-free rock in conventional drill holes.The drill holes will require preheating before grouting if the rock is frozen. Grouted anchors may be installed in ice free rock without preheating if the rock is warmer than 30°F,if high-early or other fast setting cements are used,provided the temperature of the grout is greater than 60°F at the time of placement and the annular thickness of the grout around the anchor rod is at least 2-1/2 in.(i.e., diameter of hole 6 in.or greater for l-in.rod)." The anchor rod being used has a nominal diameter of 1.41 inches giving an annular space of 2.3 inches.The grout specified,Sika Arctic Grout 100 is specially formulated for use in cold ground with temperatures from 14°F to 39°F.We are comfortable that with proper installation we will get an acceptable anchor;however reducing the hole size would increase the risk of the grout freezing before it has a chance to cure. DRYDEN &LARUE,INC. Lo bbe Alan B.Peabod lDihb-Uf Bf ee) ABP:db\stans.ltr\tyee3 (Korcc.A.Kahn ' E.Marchegiani S.Swift RECEIVED nities JUL 22 1991 C J GOLDEN VALLEY ELECTRIC ASSOCIATION INC.Box 71249,Fairbanks,Alaska 99707-1249,Phone 907-452-1151 July 17,1991 Stan Sieczkowski Alaska Energy Authority P.O.Box 190869 Anchorage,AK 99519-0869 Subject:IOC Committee Members SAW Dear Mr.SiecZkowski: Golden Valley Electric Association has designated the following individuals to serve on the Alaska Intertie Operating Committee and it's subcommittees. Intertie Operating Committee Bob Orr Representative Marvin Riddle Alternate Ioc Subcommittees Protection Coordination Steve Haagenson Machines /Rating Frank Abegg Reserves Evaluation Marvin Riddle SCADA/Metering/Communication Bob Orr &Marvin Riddle Dispatch Marvin Riddle Reliability/Criteria Jim Smith Insurance Robert Hansen ASCC Coordination |Bob Orr MA. Mike Kelly General Manager cc:Bob Orr YOO ALCS CHUGACH ELECTRIC ASSOCIATION,INC. DAVID L.HIGHERS General Manager May 20,1991 RECEIVED Alaska Energy Authority MAY 2.4 1991P.O.Box 190869 Anchorage,Alaska 99519-0869 aiaska Energy Authority Attention:Mr.Stan Sieczkowski,Secretary Intertie Operating Committee Subject:Alaska Intertie Operating Committee Dear Mr.Sieczkowski: Chugach Electric Association has designated the following individuals to serve on the Alaska Intertie Operating Committee and its subcommittees: PROTECTION COORDINATION Dave Burlingame MACHINES /RATING Ray Olson RESERVES EVALUATION Brad Evans SCADA METERING Brad Evans |Vance Cordell LAXSPATCH Brad Evans RELIABILITY /CRITERIA John Cooley INSURANCE Mike Cunningham ASCC QCoORDINATION __Tom Lovas a qai Vi David L.Highers General Manager 2029.TAL/ts 5601 Minnesota Drive «P.O.Box 196300 ¢Anchorage,Alaska 99519-6300 Phone 907-563-7494 ¢FAX 907-564-8406 or 907-562-0027 MV OATES |State of AlaskaDNWalterJ.Hickel.Governor ok Alaska Energy Authority A Public Corporation August 15,1991 Mr.John Doudna Power Technologies,Inc. One Sierragate Plaza,Suite 340B Roseville,California 95678 Subject:Railbelt Load Shedding Study Scope of Work Dear Mr.Doudna: To clarity the scope of work yet to be completed under the above reference contract, we had intended to issue a letter enumerating the intent of the committee recommendations made at the May 22,1991 meeting.Your letter of July 19,1991 preempted the initial direction,but will serve as part of the basis for completion of work under this contract. The Committee believes the study accepted at the May 22,1991 meeting completes PTI's obligation under their original proposal to establish a base case to verify pertormance of the system model.PTI is now authorized to proceed with the studyasOutlinedintheoriginalPTIproposaldatedMay3,1991. In the original proposal,PTI set forth a scope of services intended to comply with therequestforproposals.We do not believe those services as outlined have been provided.PTI has submitted a previous base case and several cases drawn on theresultsofthebasecase.The development of this base case was under the loadingandunitdispatchsubmittedbytheutilities.However,the base case was notsubmittedforapprovalpriortoproceeding,and consequently several cases weredevelopedbyPTIandnotacceptedbytheRailbeltutilities.We do however,acknowledge that PTI's work on the original base case was authorized and this base case was changed to a more recent event after the machine testing was completed. We expected PTI to provide a study in compliance with the original proposal.According to the original proposal,it would appear PTI is now ready to begin task 2onpage7todeveloptheexistingloadsheddingbehavioroftherailbeltsystem. We would like to specifically note that PTI was originally charged with evaluating thecurrentloadsheddingrelaysthemselves,relay time settings relative to system set points and different breaker operate times,load levels at each shed point,frequencyshedpointsofeachsystemwhichcouldbeislanded,load shed in lieu of spinning reserve and other systems conditions which could be changed to improve load shedding.Your letter of July 19,1991 appears to indicate you believe this work has been accomplished.If accomplished by PTI,the work has not been submitted to. and accepted by AEA. J PO.BoxAM Juneau,Alaska 99811 (907)465-3575 GI PO.Box 190869 701 East Tudor Road Anchorage,Alaska 99519-0869 (907)561-7877 WQ3ID1362(1) Mr.John Doudna August 15,1991 Page 2 Bradley Lake is intended to be studied as part of the 10 cases for utility use aftercompletionofthebasestudy,together with the implementations recommended byPTIandacceptedbytherailbeltutilities. Your conversation with David Burlingame was correct in that the committee believes only one winter and one summer load case need to be studied.However,these loadlevelswillrequiredifferentunitdispatchesandtielineflowsasindicatedinthe original scope. The under frequency set points cited in your July 19,1991 letter are correct for theexistingsystem,however PTI is to recommend new set points and settings aspreviouslystated.We believe recommending under frequency set points at variousfrequencyandtimedelaysisrequiredtoevaluatetheconceptofloadsheddinginlieuofspinningreserveasPTIwasoriginallycharged. The study as outlined in your letter appears to adequately assess the existing underfrequencyloadsheddingsystem.However,the intent of the study was to review the existing load shedding scheme used by the Railbelt utilities and make recommendations for changes which may ultimately lead to a better under frequencyprotectionsystem.To this end it would appear PTI needs to have a directcomparisonbetweentherailbeltperformanceusingtheexistingloadsheddingsystemandwiththechangesrecommendedbyPTIasexpressedinPTI's original proposal. To more expressly clarify the status of the contract deliverables as related to theoriginalPTIproposalwebelieveonlyTask1andthatportionofTask2pertainingtotheestablishmentofabenchmarktestcasehavebeencompleted.PTI 1s authorizedtoproceedwithTasks2&3 as outlined in the proposal.After completion,theutilitieswillreviewtheresultsofthestudiesandevaluatePTI's recommendations for changes and authorize PTI to proceed with completion of the study.At that time theutilitieswilloutline10additionalcasestobestudied. If there are any questions or comments,please feel free to contact Afzal Khan at your convenience. Sincerely, Stanley ENSieczkowski,DirectorFacilitiesOperations&Engineering AK:SES:tlj ce:Afzal Khan,Alaska Energy AuthorityTomLovas,Chairman,Intertie Operating Committee 91Q3\JD1362(2) Mian FES |State of AlaskaDNWalterJHickel.Governor Alaska Energy Authority A Public Corporation August 14,1991 Mr.John Doudna Power Technologies,Inc.One Sierragate Plaza,Suite 340B Roseville,California 95678 Subject:Railbelt Load Shedding StudyforAlaskaIntertieOperatingCommittee Dear John: The status of this contract was discussed at the July 10,1991,meeting of the AlaskaIntertieOperatingCommittee(IOC).The IOC is aware of the potential foradditionalchargesthatPTImayrequesttocompletetheoriginalscopeofworkinthiscontract.e IOC,however,expects PTI to perform in accordance with thecontractasspecifiedandrequestsnotificationoftheanticipatedcompletiondate. Thank you for your attention to this matter of finalizing the original contract.OnbehalfoftheIOC,we look forward to hearing from you at your earliest convenience. Sincerely, Stanley E.CE Director Facilities Operations &Engineering AK:SES:tlj cc:Afzal Khan,Alaska Energy AuthorityTomLovas,Chairman,Intertie Operating Committee O PO.BoxAM Juneau,Alaska 99844 (907)465-3575 JK PO.Box 190869 704 East Tudor Road =Anchorage Alaska 99519-0869 (907)561-7877 TJ1354(1) munntles PROPOSED AGENDA ALASKA ENTERTIE MACHINE RATING SUBCOMMITTEE OATE:AUGUST 15,19ST TO:FRANK ASE6G,RAY OLSCN,SAM MATTHEWS,&AFZAL H.KHAN SUBJECT:PROPOSED AGENDA LY THE MACHINE RATING SUSCOMMITTEE MEETING WILL 8E HELO WEDNESDAY AUSUST 28,1991 10103 AM MUNICIPAL LIGHT &POWER MAIN CONFERENCE ROOM 1280 E.FIRST AVE.ANCHORASE ALASKA THE SU66E 1S AS FOLLOWES: 1.REVIEW UPDATED DATA SHEETS. 2.REVIEW THE MISSION OF THE MACHINE RATING SUBCOMMITTEE AND THE PERIMETERS THAT IT SHOULD COVER.THE FOLLOWING ITEMS ARE SUGGESTED FOR OISCUSSION. 'i REVIEW *CURRENT MACHINE RATING METHODOLOGY |*ESTABLISHMENT OF A NEW DERATING POLICY,SHORT TERM,| |LONG TERM \ 1 ®METHODOLO6Y OF MOOIFYING THE HAND BOOK zOd .THILNGYTat AVIAek wey tos aN TR cRTt 'an Municipal Lig.'&Power 1200 EAST FIRST AVENUE-ANCHOA 'KA 98601-1688 TELEPHONE (607)27 Tom Fink,TELECOPIER (807)27t <u01 Mayor PROM FAX:(907)263-5349 FAX COVER SHEET vo.Aliza|Khe AtA vax wo.56/-PS8Y prom:_\'.G Drege ANml¢P Ah $587 - TOTAL PAGES of (including cover sheet) FAX NUMBER:.(907)263 5349 pescarprion:§=_Agate” Mgdnd A MESSAGE:|VAN y SS caewr te 'PROVIDE FOR TOMORROW,SAVE ENERGY TODAY. Sn =ee es ee eee -Smeeatere ALASKA INTERTIE OPERATING COMMITTEE WEDNESDAY,JULY 10,1991 (HOMER ELECTRIC ASSOCIATION BOARD ROOM) MEETING MINUTES PRESENT: Sam Matthews,Alaska Electric Generation &Transmission (AEG&T)/Homer Electric Association.(HEA) James Hall,Matanuska Electric Association (MEA) Afzal H.Khan,Alaska Energy Authority (AEA)Eric Marchegiani,Alaska Energy Authority (AEA) Doug Hall,Anchorage Municipal Light &Power (ML&P)Tim McConnell,Anchorage Municipal Light &Power (ML&P)Hank Nikkels,Anchorage Municipal Light &Power (ML&P) Tom Lovas,Chugach Electric Association (CEA)John Cooley,Chugach Electric Association (CEA) Bob Orr,Golden Valley Electric Association (GVEA) The meeting was called to order by Chairman Tom Lovas at 11:10 a.m.at theHomerElectricAssociationBoardRoom. Doug Hal!moved that the Intertie Operating Committee (IOC)adopt theMay8,1991 meeting minutes with modifications.Bob Orr seconded the motion.The motion was adopted unanimously.The modifications to the meeting minuteswereasfollows:Doug Hall was present at the meeting;delete the last sentence of thefirstparagraphonpage3;and insert word "reserve"before word "fund"inparagraph4onpage3. Under Dispatch,this subcommittee met jointly with Protection Coordination toreviewthebasecaseverificationfortheAugust29,1990 event. Under Protection Coordination,Afzal Khan distributed the May 22,1991 draft meeting minutes of the joint meeting with the Dispatch subcommittee.There was abriefdiscussiononthePTIContract.Chairman Tom Lovas decided that this issue should be discussed in the work session. Under the Machine/Rating Subcommittee,Hank Nikkels distributed theMachines/Rating Subcommittee Report and discussed its contents.Hank NikkelsstatedthattheDraftofMachineRatingBookwillbereadybyAugust15,1991.Hank Nikkels briefly discussed the future issue items 1 &2,listed in thesubcommitteereport.He said these two items are the most important items. Under correspondence,Tom Lovas stated that he received a letter,datedMay10,1991,from ML&P regarding ML&P's representative on the IntertieOperatingCommittee.Afzal Khan stated that AEA received a letter,dated 91Q3\JD1254(1) May 20,1991,from CEA regarding CEA's representative on the Intertie OperatingCommitteeanditssubcommittees. Under Intertie Status,Afzal Khan and Eric Marchegiani distributed the following: 1.Amendment No.1 to the Alaska Intertie Agreement,Article 17 - Insurance and Liability. 2.MEA letter,dated May 23,1991,to AEA.Reference:DouglasSubstationTransformerOvercurrentRelaySettings. 3.GVEA letter,dated July 9,1991,to AEA.Reference:Engineer'sFindingsonStructure#749. 4.AEA letter,dated June 17,1991,to Dryden &LaRue. Reference:Structure #749 Letter Request For Proposal. 5.Dryden &LaRue letter,dated July 3,1991,to AEA.Reference:Structure #749,"Temporary Fix"with attachments. 6.Dryden &LaRue letter,dated July 9,1991,to AEA.Reference:Structure #749,"Temporary Fix"Construction CostEstimate. 7.Loftus &Dailey letter,dated June 11,1991,to GVEA.Reference:Goldhill SVS Building Roof Modifications. Eric Marchegiani briefly discussed the engineer's design for Structure #749,"Temporary Fix."IOC members were satisfied with the approach taken by theEnergyAuthority.There was also a brief discussion on the Goldhill SVS Buildingroofmodifications.The Energy Authority questioned Loftus &Dailey,Inc.,consultant hired by GVEA for IOC,cost estimate of $60,000 for the roofmodifications.Eric Marchegiani requested that GVEA provide the EnergyAuthoritywithadetailedcostbreakdownforEnergyAuthority's review. Jim Hall distributed the July 3,1991 MEA letter,addressed to IOC Chairman. Jim Hall stated that MEA has investigated installation of a guard structure at the Caswell Lakes road crossing.Jim Hall also stated,that the guard structure wouldcost$3,000,material and labor,and with deadend insulators this would cost $3,800.There was a brief discussion on precipitation measuring devices. No visitors were present. The Operating Committee took a break from 12:30 p.m.to 12:45 p.m. The Operating Committee went into work session. Under Dispatch,Chairman Tom Lovas stated that each [OC member needs to workwiththeirProduction/Generation group for obtaining the necessary information onmachineoutagesand/or data.In addition,the information associated withdisturbancesneedstobeforwardedtoareacontrollers.Bob Orr stated that the dispatch subcommittee needs to update,the Alaska Intertie Operating Guides with 91Q3D1254(2) 710-9 the latest NERC guides before the next IOC meeting.IOC will have to adopt therevisedOperatingGuidesatthenextIOCmeeting. Under Protection Coordination,the discussion was focussed on the PTI Contract for the Railbelt Under Frequency Load Shedding Study.Chairman Tom Lovas directedtheEnergyAuthoritytodraftalettertoPTIindicatingIOC's awareness of PTI'sdesireforadditionalchargestocompletetheoriginalscopeofworkofthePTIContractwiththeEnergyAuthority.The Intertie Operating Committee expects PTItoperforminaccordancewiththeoriginalcontractasspecifiedandrequestnotificationofanticipatedcompletiondate. Under Machine/Rating,Hank Nikkels stated that the Machine/Rating subcommitteewillmeetassoonashereceivesthereviseddatasheets.Tom Lovas stated that the Machine Rating Book and items:(1)Current machine rating methodology;and(2)the establishment of a new policy for short and long term derating will beaddressedatthenextIOCmeeting.Chairman Tom Lovas suggested that thissubcommitteeundertakeconsiderationofadditionaltopics,and would like to seethatSamMatthews,AEG&T representative,be included as a subcommittee member.In addition,Tom Wilde,Alaska Power Administration,is to be included as a non voting member. The Operating Committee took a break from 2:30 p.m.to 2:45 p.m. Under SVS (Teeland Starting-Douglas Reactor),Chairman Tom Lovas stated thattheReliability/Criteria subcommittee is to address this issue.The remaining SVSreservefundscouldbeusedtocompletethisprojectifitisdeterminedtobetechnicallyfeasible.The estimated cost to complete the Goldhill SVS building roofmodificationsis$60,000 and this amount will be funded from SVS reserve funds. Under Intertie FY93 Budget,Afzal Khan distributed the preliminary FY93 BudgettorIOCreviewandcomments. Under T/L Structure and Conductor Evaluation,Eric Marchegiani stated that thereisnotmuchtodiscussotherthanwhatwasalreadydiscussed. Chairman Tom Lovas recommends that the utilities update Intertie OperatingCommitteeanditssubcommitteesmemberlist. Under Formal Operating Committee Action/Recommendation,Tom Lovas directedthattheEnergyAuthoritydraftalettertoPTIrequestingthatPTIcompletetheoriginalscopeofworkfortheunderfrequencyloadsheddingstudyandcirculatethedrafttoIOCmembersforcomments.Chairman Tom Lovas will consolidate members comments. Chairman Tom Lovas moved that IOC affirms the subcommittees recommendations and directs the Protection Coordination Subcommittee Chairman to prepare a lettertoPTIandsubmittoEnergyAuthorityforresubmittaltoPTI.Bob Orr seconded the motion.The motion was adopted unanimously. Under Subcommittee Assignments,Chairman Tom Lovas directed the dispatchsubcommitteetomeetatthediscretionofitsChairmantoworkon:DispatchTrainingPlan;maintenance response and communications coordination among the 91Q3\JD1254(3) area utilities and Technical Guidelines for Operation,Metering and ProtectiveRelayingforNon-Utility Power Producers and Cogenerators and develop operatingguidestogowiththem.In addition,the Dispatch subcommittee is to investigateswitchingandtaggingproceduresandsubmitrevisedOperatingGuidesfor[OC approval. Chairman Tom Lovas directed the MACHINE/RATING subcommittee to meet at the discretion of its Chairman to continue work on machine rating book. Chairman Tom Lovas directed the PROTECTION COORDINATION subcommittee to meet at the discretion of its Chairman to continue work on under frequency load shedding study. Chairman Tom Lovas directed the RELIABILITY/CRITERIA subcommittee to meet at the discretion of its Chairman to evaluate the technical merits and cost consideration for Reactor installation at Douglas substation. THE NEXT REGULARLY SCHEDULED MEETING OF THE ALASKA INTERTIE OPERATING COMMITTEE WILL BE ON WEDNESDAY, SEPTEMBER 11,1991,AT 9:30 AMM.AT THE GOLDEN VALLEY ELECTRIC ASSOCIATION BOARD ROOM. The Operating Committee set the agenda for the next meeting of the OperatingCommittee. Doug Hall moved for the meeting to adjourn,seconded by Tom Lovas.TheOperatingCommitteeunanimouslyadoptedthemotiontoadjournat3:35 p.m. Respectfully submitted, Ufppe.1 Wir -fogStanleyE.Sieczkowski,SecretaryAlaskaIntertieOperatingCommittee Attachments 1.September 11,1991 meeting agenda. The following were distributed at the July 10,1991 meeting: 2.ML&P letter,dated May 10,1991,to [OC Chairman regarding IntertieOperatingCommitteerepresentative. 3.Draft Protection Coordination Subcommittee May 22,1991 meeting minutes. 4,Reliability/Criteria Subcommittee July 2,1991 meeting minutes. 5.MEA letter,dated July 3,1991,to Reliability/Criteria SubcommitteeChairmanJohnCooleyregardingtheguardstructureestimatedcostattheCaswellLakesroadcrossing. 91Q3\D1254(4) 13. 14. ML&P letter,dated July 1,1991,to IOC Chairman Tom Lovas. Reference:Report of Machine/Rating Subcommittee. Amendment No.1 To The Alaska Intertie Agreement,Article 17 -Insurance and Liability. CEA letter,dated May 20,1991,to IOC Secretary Stanley Sieczkowski.Reference:IOC members and its subcommittees members. MEA letter,dated May 23,1991,to AEA.Reference:TransformerOvercurrentRelaySettings. GVEA letter,dated July 9,1991,to AEA.Reference:Engineer's Findings onStructure#749. AFA ietter,dated June 17,1991,to Dryden &LaRueReference:Structure #749 Letter Request For Proposal. Dryden &LaRue _letter,dated July 3,1991,to AEA.Reference:Structure #749 "Temporary Fix"with attachments. Dryden &LaRue letter,dated July 9,1991,to AEA.Reference:Structure #749 "Temporary Fix"Construction Cost Estimate. Loftus &Dailey letter,dated June 11,1991,to GVEA.Reference:Goldhill SVS Building Roof Modifications. 91Q3\JD1254(5) IIL. _ALASKA INTERTIE OPERATING COMMITTEE MEETING AGENDA WEDNESDAY,SEPTEMBER 11,1991 9:30 A.M. Adoption of prior meeting minutes Approval/modification of agenda Committee correspondence and reports A.Dispatch SubcommitteeB.Protection Coordination Subcommittee C.Machine/Rating SubcommitteeD.Reliability/Criteria SubcommitteeE.Correspondence ReceivedF.Intertie Status Update IV.Visitors comments related to items on agenda V.Work Session A.Recess and work session B.DispatchC.Protection Coordination D.Machine/RatingE.Reliability/Criteria er F.SVS G.FY93 BudgetH.T/L Structure and Conductor Evaluation VI.Formal Operating Committee action/recommendation VI.Subcommittee Assignments VIII.Determine agenda for next meeting IX.Adjournment MEETING LOCATION: Golden Valley Electric Association,Inc. Board Room 758 Illinois Street Fairbanks,Alaska 99707 (907)452-1151 91Q3\JD1255(1) Waynes NY Municipal Light &Power 1200 East First Avenue Anchorage,Alaska 99501-1685 (907)279-7671,Telecopiers:(907)276-2961,"REC E |V E D May 10,1991 MAY 4 4 1991 PLANNING &RATES DEPARTME! Cf:WS efureTomLovas,Chairman : Alaska Intertie Operating Committee c/o Chugach Electrie Association,Inc. Pouch 6300 Anchorage,AK 99502-0300 Dear Chairman Lovas: Doug Hall will be ML&P's representative and Moe Aslam will be our alternative representative on the Alaska Intertie Operating Committee. Very tyaly yours, "7 >Om Thomas R.Stahr General Manager ee:Stan Sieezkowski,AEA Larry Colp,FMUS Bob Orr,GVEA Marvin Riddle,GVEA James Hall,ABG&T bec:Hank Nikkels Moe Aslam Doug Hall Putting Energy Into Anchorage OOP ff fe 6 a /A wen FO Pana whe 0 A ieotet ee) ---- ----DRAFT----- ---DRAFT=DRAFT -----------DRAFT- --- HUGACH ELECTRIC ASSOCIATION,INC.R E C E \V E Anchorage,Alaska May 22,1991 IoC Dispatch-Scheduling SubCommittee FROM:David Burlingame,Manager,Facilities engineering//7/C°SUBJECT:Meeting Minutes -May 22,1991 Below are the draft meeting minutes of the joint subcommittee meeting of May 22,1991. A.Khan passed out meeting minutes for the August 7,1990,October25,1989 and October 6,1989 meetings for record. The committee discussed the results of the base case verification performed by PTI for the August 29,1990 event and the relatedstudycases.The joint committee approved by formal motion theacceptanceofthosecases.The motion read as follows: MOTION -Move to approve all cases related to the August 29,1990 event as last revised in the PTI letter of May 3,1991. The motion was unaminously approved. The committees discussed the Scope of Work included in the original contract and agreed the scope as originally defined in the contract was still pertinent and should not be changed.The study should bebasedontheunitcommitmentsanddispatchingschedulespreviously supplied for winter/summer cases.The committees unaminouslypassedthefollowingmotions MOTION -Instruct PTI to develop a loadshedding schedule for the Railbelt system based on the system model verified in the 1990casesasspecifiedintheoriginalscopeofwork.PTI should usetheloadsheddinginleuofspinsuchthatloadsheddingclosely simulates system conditions encountered if real spinning reservewaspresent.Loadshedding in leu of spin shall be that capable ofbeingperformedbytheGVEASCADAsystem.Loadshedding shouldstartat59.7 Hz or a similar level proposed by PTI. The hardest thing the committee did was to agree on a motion toacceptthedatabaseandreleasethedatabaseforuseonotherstudies.The motion passed unaminously and reads as follows: MOTION --Recommend to the IOC that the data base as verified in the 1990 case specified in PTI's May,1991 letter be released for anysystemstudies,including those related to Bradley Lake under thedirectionoftheTCS. A.Khan advised the committee that additional funds may be requiredtocompletetheproject,but he will solve all financial concerns. The committees unaminously passed the following motion: MOTION -AEA was instructed to have PTI complete the scope of workofthecasesspecifiedintheoriginalscopeofworkbyJune21,1991. Distributions David Burlingame -ChugachMarvinRiddle-GVEA Afzal Khan -AEA Jim Hall -MEA Larry Hembree -ML&P Steve Haagenson -GVEA Sam Matthews -HEA Brad Evans =Chugach Doug Hall -ML&P MEMORANDUM DATE:May 15,1991 TO:David Burlingame,CEA Brad Evans,CEA Steve Haagenson,GVEA Marvin Riddle,GVEA Larry Colp,FMUS James Hall,MEA Doug Hall,ML&P Larry Hembree,ML&P Sam Matthews,HEA Afzal Khan,AEA FROM:Afzal H.Khan ALASKA INTERTIE PROTECTION COORDINATION AND DISPATCH SUBCOMMITTEES MEETING AGENDA WEDNESDAY,MAY 22,1991 BEGIN AT 1:30 P.M. I.Review RFP Scope of Work,Railbelt Load Shedding Study (attached) II.Review PTI Contract Railbelt Load Shedding Study (attached) III.PTI Railbelt Load Shedding Study for August 29,90 Event IV.PTI 88/89 Base Case (completed on September 8,1989) Vv.Formal Subcommittee action/recommendation Meeting Location:Chugach Electric Association Engineering Conference Room 5601 Minnesota Drive Anchorage,Alaska 99519 (907)563-7494 Mirat el ALASKA INTERTIE OPERATING COMMITTEE Reliability/Criteria Subcommittee Meeting Minutes July 2,1991 Meeting At Chugach Attending:."le lene”a .;"Jim Smith,GVEA =”0°"John Cooley,ChugachGregWyman,GVEA Mike Massin,Chugach Jim Hall,MEA The subcommittee selected John Cooley to be the new Chairman of the Subcommittee. The subcommittee discussed the proposed solutions and cost estimates tqcorrect the icing problems experienced on the linesectionimmediatelynorthoftheDouglasSubstation.Jim Hall reported that there are deadends in the line at 4,12,and 84 spansnorthfromDouglas.Since the spans rotated back into place and the rotation has only occurred once in the past six years,no corrective action is required on the spacers and vertical alignment unless the problem reoccurs more «frequently.The subcommitteereachedaconsensusthatoptions1and4ofGVEA's cost estimateletterweretheappropriatecorrectiveactionstobetaken.The following course of action is recommended by the subcommittee:1.-Investigate and install if possible a remote recording a weather station at the Douglas substation to provide a _...better history of weather problems."-.2.-:Patrol«the=line:north:from--Douglas whenever MEA is 'experiencing heavy snow loading/outages on their distribution lines out of Douglas.Take the intertie out of service if the clearances are-low..<aasyp.3 +c;-Investigate®«<installation=of..a-quard-structure.-on..theea-Caswell'Lake*road crossing:* MEX will 'provide'a designandestimate. whe Have AEA obtain concurrence from the tower..manufacturer :for.the following modifications along with anyprecautionstobefollowedduringthemodifications:a.Remove the static wire b.Shorten insulator string to 230 KV design c.Disposition of static wire support arm (goathead), should it be left in place or removed? 5.Remove the static wire and shorten the insulator strings (Options 1 &4)on the first 12 spans north from Douglas during the summer of 1992.This section is to serve as a test case to see if the corrective actions are effective. 6.Evaluate removal of the static wire and shortening the insulator strings on spans 13 through 84 north of Douglas based upon the results of the 12 span test case. mp nantes Matanuska Electric R E C E|V ED Association,Inc.ig 1991WPLANNING&RATESP.O.Box 2929 DEPARTMENTPalmer,Alaska 99645 Telephone:(907)745-3231 Fax:(907)745-9328 July 3,1991 Mr.John CooleyChairman Reliability SubcommitteeIntertieOperatingCommitteeP.O.Box 196300 Anchorage,AK 99519-6300 Dear John: Matanuska Electric Association,Inc.(MEA)has investigated installation of a guardstructureattheCaswellLakesroadcrossing.Assuming a sag increase in the crossingspansuchthattheminimummidspanclearancetoground1sthreefeet,then theminimumclearanceovertheroadwouldbeabouttwelvefeet.This agrees fairly wellwithfieldobservations. A guard structure consisting of two thirty-five foot poles with an overhead guy betweenthemtosupportthesaggingline,and appropriate down guys to support the structureswillcostabout$3,000.This could include 115 KV deadend insulators in the overheadguytoallowthelinetoremaininservicewithonelowphase;however,this wouldIncreasethecosttoabout$3,800. A device to measure precipitation in the form of either rain or snow,which wouldproduceapulseforeachonehundredthofaninch,would cost about $3,500 notincludingconnectionfromapulsesplittingrelayinthebuildingtothevariousSCADARTUs.It is anticipated that each utility would desire to connect this output to theirownRTU. Both of the costs listed above include materials and installation labor.Should theCommitteewishtoproceedwitheitheroftheseitems,please let me know. Aincerely,wa i J ames D.Hall Projects Engineer JDH404EDES ;cc:|Tom Lovas,Chairman,Intertie Operating Committee,c/o CEA LDV eles \i/NZ Sake |Municipality of Anchorage Municipal Light &PowerTomFink,Mayor 1200 East First Avenue Anchorage,Alaska 99501-1685 (907)279-7671,Telecopiers:(907)276-2961,277-9272 rd Date:July i,1991 Tos Tom Lovus Chairman,Intertie Operating Committee From:Hank Nikkels Chairman,Machine/Rating Subcommittee SUBJECT;REPORT OF SUBCOMMITTEE cc:F.Abegg,A.Kahn,R.Olsen The following report is submitted by the Machine/Rating Subcommittee:F.Abegg,Golden Valley Electric Association; R.Olsen,Chugach Electric Association;A.Kahn of Alaska Power Authority;and,H.Nikkels (chairman). P.T.I.REPORT The subcommittee elected to only comment on the governor/machine response issues of the report.The report provided new information about the intertied system,but the governor/response data was not adequate to make detailed plans for the system at this time.The key issue,loss of load testing,cannot be equated with a unit's ability to pick up load. The variety of control systems in the area cannot be made to operate to a single standard of performance.It is even possible to damage machinery by attempting new controls settings that the controls or the turbines have not been designed to accept. It is the recommendation of the subcommittee that individual utilities continue to maintain their own standards and methods of review for control settings.It is suggested that forensic review of system disturbances offers the most objective review of governor setting and for the identification of machines that have gross control problems. Putting Energy into Anchorage Machine/Rating Subcommittee Report Page 2 July 1,1991 MACHINE RATING HANDBOOK The sub-committee is pursuing an updated handbook. ML&P will compile the initial draft.At this writing,not all utilities have submitted revised data sheets.A new goal of 8/15/91 has been established for the draft. FUTURE ISSUES It is suggested the subcommittee address the following issues at future meetings as part of compling the revised handbook: "1)Current machine rating methodology 2)Establish a new policy for short and long term derating 3)Establish guidelines for performance testing 4)Establish guidelines for control system testing ADDITIONAL TOPICS If desired by the IOC,the subcommittee is willing to address or comment on the following issues: 1)Review and comment on the spinning reserves formula 2)Review and comment on the use of "Peak"rating for spinning reserves.This topic was briefly discussed.Opinions of the committee members varied,but it was generally agreed that the use of the higher temperature limit will create additional operating costs.The lower limit of the costs would be to establish and maintain a testing program to assure the operability of the rating since it is not generally used by the utilities at this time, Chairman,Machine/Rating Subcommittee C:HN1-30 AMENDMENT NO.1 TO THE ALASKA INTERTIE AGREEMENT ARTICLE 17 --INSURANCE AND LIABILITY This Amendment No.1 is made this 294 day of March1991,by the Participants,ALASKA POWER AUTHORITY,now the Riaska Energy Authority,a public corporation of the State of Alaska ("AEA");the MUNICIPALITY OF ANCHORAGE,ALASKA d/b/a MUNICIPAL LIGHT &POWER (""AML&P");CHUGACH ELECTRIC ASSOCIATION,INC. ("Chugach");THE CITY OF FAIRBANKS,ALASKA,MUNICIPAL UTILITIES SYSTEM ("FMUS");GOLDEN VALLEY ELECTRIC ASSOCIATION,INC. ("GVEA");and ALASKA ELECTRIC GENERATION AND TRANSMISSION COOPERATIVE,INC.("AEG&T"),signatories to the Alaska Intertie Agreement,dated December 23,1985,hereinafter referred to as "Agreement."The signatory parties are hereinafter referred to as "Participants." WITNESSETH WHEREAS THE MUNICIPALITY OF ANCHORAGE,ALASKA,d/b/a MUNICIPAL LIGHT &POWER;CHUGACH ELECTRIC ASSOCIATION,INC.;THE CITY OF FAIRBANKS,ALASKA,MUNICIPAL UTILITIES SYSTEM;GOLDEN VALLEY ELECTRIC ASSOCIATION,INC.;and ALASKA ELECTRIC GENERATION AND TRANSMISSION COOPERATIVE,INC.,are all Utility Participants and signatories to the Alaska Intertie Agreement;and WHEREAS the AEA is a Participant and signatory to the AlaskaIntertieAgreement;and WHEREAS the signatories to the Alaska Intertie Agreement desire to have Article 17 amended; NOW THEREFORE,the Participants agree as follows: ARTICLE 17 Insurance and Liability Section 17.1 Insurance During the term of this Agreement,each Participant shall purchase and maintain insurance with a carrier or carriers satisfactory to the Operating Committee and the AEA covering injury to persons or property suffered by any Participant or a third party,as a result of errors,omissions,or operations which arise both out of and during the course of this contract by the Participant or by any of its subcontractors.The coverage shall also provide protection against injuries to all employees of the Utility Participant and the employees of any of its subcontractors engaged in work under this Agreement. If approved by the Operating Committee and the AEA, AML&P,FMUS and the AEA may qualify for certain levels of self-insurance.Any such undertaking to self-insure will be furnished to the Operating Committee and theAEAbeforebeginningoperationsunderthisAgreement.* As an additional alternative,group policies shall be acceptable under Section 17.2 of this Agreement if such policies meet the expressed coverage requirements individually and collectively for the signatories of this Agreement.Any other alternative allowed under Sections 17.2 must provide identical or better limits of coverages required for each of the exposures,as specified in that Section 17.2. Section 17.2 Types of Insurance 17.2.1 The following insurance must be provided by each Participant to cover those operations of the Participants performed under this Agreement: Worker's Compensation Insurance:Each Participant shall provide and maintain,for all employees of the Participant engaged in work under this Agreement, Worker's Compensation Insurance as required by AS 23.30.045.Statutory worker's compensation coverage may be provided through purchase of insurance,self- insurance (in the case of AML&P,FMUS and the AEA only) or a combination of both.A self-insurance program must provide a high level of statutory excess over the self-insured level. Each Participant shall require Worker's Compensation Insurance for any of its subcontractors who directly or indirectly provide services under this Agreement.Each insurance policy must include: (a).Statutory coverage for states in which employees are engaging in work; (b)Employer's Liability Protection of not less than $500,000 per occurrence; ?Where in this Article 17 the AEA is entitled to self- insurance and there are requirements for approval by the Operating Committee and AEA for such self-insurance,the AEA shall not participate in such approval. -2- (Cc)Broad Form All States Endorsement; (d)Coverage as required by all State and Federal Acts where applicable; The Worker's Compensation Insurance policy shall contain a waiver of subrogation in favor of the other Participants.Any Participant who is self-insured hereby waives subrogation in favor of the other Participants. AML&P,FMUS and the AEA may self-insure for Worker's Compensation Insurance up to the maximum filed and approved with the State Department of Labor. A copy of the insurance policies and/or descriptions of self-insurance program will be furnished to the Operating Committee and the AEA on February 1 of each year. 17.2.2 Comprehensive General Liability Insurances:Each Participant shall purchase and maintain comprehensive general liability insurance subject to the following limits of liability: (a)Bodily Injury and Property Damage Liability of a minimum of $5,000,000 Combined Single Limits each occurrence and affording insurance for Premises- Operations,Owners'and Contractors'Protective, Independent Contractors,Products/Completed Operations,Blanket Contractual Liability,Broad Form Property Damage,and Personal Injury Liability. (b)Automobile Liability Insurance covering all vehicles.Such insurance shall provide coverage of not less than $5,000,000 Combined Single Limit each occurrence for Bodily Injury and Property Damage Liability. (c)Owned Aircraft (if applicable)and Non-Owned Aircraft with seating capacity of five seats or less,except commercial,scheduled flights,with limits of liability not less than:$5,000,000 - Bodily Injury per occurrence;$1,000,000 for Passenger Liability per seat;and $5,000,000 for Property Damage Liability per occurrence. Coverage must include Slung Cargo exposures.If an aircraft with more than five-seat capacity is used,special coverage and limits must be obtained and approved by the Operating Committee. (d)Owned Watercraft (if applicable)and Non-Owned Watercraft (if applicable)with limits of liability not less than $5,000,000 per single occurrence as provided in the "In Rem Endorsement" under "Maritime Coverage B." If approved by Operating Committee and the AEA,AMLE&P, FMUS and the AEA may self-insure any or all of the required coverages in (a),(Db),(Cc),and (d)above. Participants intending to pursue this alternative coverage must provide proof of solvency to be approved annually by the Operating Committee and the AEA.The Operating Committee and the AEA shall establish the guidelines to insure such solvency.Members who have in place approved alternative coverage shall notify the Operating Committee and the AEA on semi-annual basis of any fluctuation(s)that may reduce or limit their solvency as originally approved by the Operating Committee and the AEA. The other Participants shall be included as additional insured as respects insurance required in this Section 17.2.2 of Article 17 and shall not by their inclusion be responsible to the Insurance carrier for payment of premium therefor.These insurance policies must also contain a cross liability or severability of interest endorsement. Section 17.3 Other Insurance Coverage Requirements 17.3.1 Each Participant will bear the cost of the required insurance.Insurance required to be maintained under this Article 17 may be maintained as part of any other policy or policies of the Participant so long as the coverage of such policy or policies is substantially the same as if such coverage were maintained under a separate policy. 17.3.2 These policies must provide that any cancellation, non-renewal or material change be upon 30 days'notice to all named insured.Each Participant must provide the Operating Committee and the AEA with evidence of insurance.Insurance companies,or self-insurers,shown on the certificate of insurance must have financial ratings acceptable to the AEA. Failure to furnish satisfactory evidence of insurance or lapse of the policy is a material breach of this Agreement. IN WITNESS WHEREOF,the Participants have executed this Amendment No.1 to the Alaska Intertie Agreement in several counterparts by their authorized officers or representatives as of the day andyearfirstabovewritten. Approved as to form:GY AUTHORITY Veoh)&f x2 425 -7/:"A thoCOALpmWN=By:--p,Office'of the Attorney General --y .Cpocibe.hireTitle° SUBSCRIBED AND SWORN TO before me this au day of Februaty '199¢. Notary Publi My Commissi ,State of Alaska Expires:Oct 12,1923 MUNICIPALITY OF ANCHORAGE,ALASKAd/b/a MUNICIPAL LIGHT POWER he[-By:Ltr /Seer MAN atopTitle_ 199g.AND SWORN TO before me this AS day of Geta -1999.we C WNithen >Notary Public,State of Alaska My Commission Expires:2-53-¢2. CHUGACH INC. ECTRIC ASSOCIATION, By; SUBSCRIBED AND SWORN TO before me this /Z-day of 74ewJ4Y_,1996.. Notary Public,State of Alaska My Commission Expires:3°7/35-Z- CHUGACH ELECTRIC ASSOCIATION, INC. By:es 2 ta 02s»Président of the Board SUBSCRIBED AND SWORN TO before me this 2x day of Aeugey_,1999.L ; Notary Public,State of Alaska My Commission Expires:4 -/3-32 CHUGACH ELECTRIC ASSOCIATION, INC. Lo esident of the BoSUBSCRIBEDANDSWORNTObeforeme'this "@<day of -%SrA1999.,Alene Ahetheman- 'Notary Public,State ofCAlaska My Commission Expires<s y7-g2z s CITY OF FAIRBANKS,ALASKA MUNICIPAL UTILITIES SYSTEM By '=---=LigneBMtorngsceHdPe ty ae AND SWORN TO before me this 77%day of 77).«%199 e a LA V7 a 4 eT Notary Public,State of Alaska My C ission Expires:Reb Poel GOLDEN VALLEY ELECTRIC ASSOCIATION,INC. By:"Wuih..s GliMichbelP.KellyGeneralMangaar Title SUBSCRIBED AND SWORN TO before me this 17 xs,of Om has '1990. Notary Public,State @f Alaska My Commission Expires: 4-77-72 ALASKA ELECTRIC GENERATION and TRANSMISSION COOPERATIVE,INC. Waa G2Title7 SUBSCRIBED AND SWORN TO before me this Bb day of ere 4 F1530379|.heebeck 0 Stat@ of AlaskaMyCommissionExpires:/27-27_95.2 -7-LGH\gma450.doe POM ATCR? CHUGACH ELECTRIC ASSOCIATION,INC. DAVID L.HIGHERS General Manager May 20,1991 RECEIVED Alaska Energy Authority MAY 2.4 1991P.O.Box 190869 huthorAnchorage,Alaska 99519-0869 pjaska Energy rity Attention:Mr.Stan Sieczkowski,Secretary Intertie Operating Committee Subject:Alaska Intertie Operating Committee Dear Mr.Sieczkowski: Chugach Electric Association has designated the following individuals to serve on the Alaska Intertie Operating Committee and its subcommittees: 10c REPRESENTATIVE |Tom Lovas SUBCOMMITTEES PROTECTION COORDINATION Dave Burlingame MACHINES /RATING Ray Olson RESERVES EVALUATION Brad Evans SCADA METERING Brad Evans Vance Cordell DIsPATCH Brad Evans RELIABILITY /CRITERIA John Cooley INSURANCE Mike Cunningham |ASCC COORDINATION Tom LovasSin\y,ry ay DS David L.Highers General Manager 2029.TAL/ts 5601 Minnesota Drive «P.O.Box 196300 *«Anchorage,Alaska 99519-6300 Phone 907-563-7494 «FAX 907-564-8406 or 907-562-0027 S wn ina KES: Matanuska Electric Association,Inc. P.O.Box 2929 Palmer,Alaska 99645 - Telephone:(907)745-3231 Fax:(907)745-9328 May 23,1991 RECEIVED Mr.Afzal Khan MAY 28 1991AlaskaBoorgyAuthoritypackaEnerayAnoAnchorage,AK 99519-0869 Dear Afzal: In accordance with our recent phone conversation,we have reset the neutral overcurrent relay on the 138 KV to 24.9 KV transformer at the Douglas Substation. This is a time overcurrent relay.The new settings are tap 7,time lever 3.This relay uses a 600:5 current transformer in the neutral of the power transformer. Should you have any questions concerning this matter,please contact me. BD flakeJamesD.Hall Projects Engineer jdh303C.351ACg Sincerely, Orvaowv gL Iniop GVER ee2punalee . GOLDEN VALLEY ELECTRIC ASSOCIATION INC.Box 71249,Fairbanks,Alaska 99707-1249,Phone 807-462-1161 July 9,1991 Eric MarchegianiAlaskaEnergyAuthorityP.O.Box 190869 Anchorage,AK 99519-0869 Subject:Engineer's Findings on Tower 749 This letter is in response to your request that we review the Dryden&LaRue letter of July 3,1991 which you sent to us by faxyesterday.This ia also confirmation of our teleconference today. Dryden &LaRue should be given instructions to proceed immediatelywiththetechnicalspecificationssowecanexpeditetheprocess.If possible,GVEA needs the technical specs by July 15,1991.Following ara our comments. 1.GVEA will check out the Healy storage facility to see if anymaterialsthatcouldbeusedontheprojectarestoredthere.Steve Swift will be in contact with you to help round up therestofthematerials.These need to be expedited.TheEngineer(Peabody)needs to inspect all materials to confirmtheyarethecorrectones.You and Steve Swift will becoordinatingthiseffort.Hopefully,all the materials can beassembledbyJuly12,1991. 2.We assume the engineer confirmed (fxom the Shannon &Wilsonreport)that suitable rock for rock anchors is at the desiredanchorlocations, 3.Did the engineer consider using a guy from the uphill anchors tothebaseofthestructureinordertostabilizethetowerbase? 4.It dis our recommendation that the engineer proceed immediatelywiththetechnicalspecsandengineer's estimate.We hope thesewillavailablebyJuly15,1991 so GVEA can put the job outforbid. 87/89/91 19:96 GVEA 823 GOLDEN VALLEY ELECTRIC ASSOCIATION INC. Enginaear's Findings on Tower 749July9,1991Page2 5.Contacts for the project ares GVEA -Stave Swift 452-1151 ext.603 AEA -Eric Marchegiani 261-7242 D&L -Alan Peabody 349-6653 These people will be the primary contacts for all futureactivitiesonthisproject.This was agreed upon during ourJuly9,1991 teleconference. Thank you for the opportunit to comment.As you know,we areextremelyconcernedaboutthestabilityofthisstructure.Therefore,we would like to complete the temporary fix as soon aspossible. LLbertOrr Manager of System Operations ce:Stan Siecskowski AEA Marvin Riddle GVEA Steve Swift GVEA Greg Wyman GVEA Saves S43NAqcer.-2Ke So. Alaska Energy Authority 4 Sloe Corporarticr June 17.1991 Mr.Delbert LaRue Dryden &LaRue Inc. 6436 Homer Drive P.O.Box 111008 Anchorage,Alaska 99511-1008 Subject:Contract No.2800266,Work Order No.AEA-DRL-005 Anchorage-Fairbanks Intertie,Structure No.749 Letter Request For Proposal Dear Mr.LaRue: Please reference our most recent conversations with Mr.Peabody of your ofticeconcerningtheabovesubject.Reference is made to Article C-10,Scope of Work ofsubjectcontract,we request a proposal in accordance with the Scope ot Work listedbelow.It shall include budget and schedule to provide the necessary engineeringdesignservicestorthedesignofarepairforStructureNo.749 on theAnchorage/Fairbanks Intertie. SCOPE OF WORK Structure Number 749 has experienced some foundation problems on the AnchorageFairbanksIntertie.The Alaska Energy Authority (AEA)working in conjunction withGoldenValleyElectricAssociation(GVEA)had contracted with Shannon & Wilson,Inc.to complete some geotechnical testing this past winter.We havepreviouslyprovidedacopyoftheirreportforyourinformation. Task | Task |will encompass the temporary design fix for Structure No.749.This shallincludethedesignofasystemofguysandanchorstoincreasethestabilityotthestructure.This may include:designing welds or existing slip joints,adding through vangs or adding a reinforcing girdle and vangs to the shaft of the pole,analyzing the tower for increased column loading,and developing footing reactions for themodifiedstructure.A more permanent construction fix may also be designed at alaterdateoncethetemporarydesignisolatesthestructuresuchthatitdoesnotfail.Theretore,the temporary design should take into account any final design considerations. A short letter report to the AEA will be developed which will include:(1)Basicfindings;(2)general design assumptions;(3)the basic temporary solution;(4)aengineersestimateforthetemporarysolution;(5)a list of materials necessary to complete the fix,and recommended steps to determine the final solution. =PO.Box AM Juneau,Alaska 99811 (907)465-3575 0869 (907)561-787791Srsty190809701EastTudorRoad =Anchorage,Alaska 99519-0869 (907) Mr.Delbert LaRue June 17,1991 Page 2 Task 2 Task 2 shall incorporate the information from Task 1 to develop plans and technicalspecificationsfortheinstallationoftheguysandanchorsdesignedinTask1.ThePlansandSpecificationsshallbeusedtobidthework.The particular format tor theplansandspecificationsshallbeprovidedbytheAlaskaEnergyAuthoritypriortoinitiationofthistask.Assistance may be required in obtaining and evaluating thebidsforconstruction.Completion of a one day trip to the site with an AEARepresentativewhenconstructionisnearingcompletiontoinspectwork(travelarrangementswillbemadebyAEA.) This task will proceed only after the AEA provides direction concerning the formatoftheplansandspecifications. Your proposal is expected no later than June 21,1991.Mr.Marchegiani is yourpointofcontactforthiswork.If you have any questions please feel free to contactMr.Marchegiani. Sincerely, Khuect UsominicOstariZoContractsOfficer EAM:DC:jd i VA cc:Stanley E.Sieczkowski,Alaska Energy AuthorityAfzalH.Khan,Alaska Energy AuthorityWilliamSobolesky,Alaska Energy AuthorityEricMarchegiani,Alaska Energy Authority 9102\JD0942/2) fninwnt>-DRYDEN é (LalRuc INC.CONSULTING /ENGINEERS 6436 Homer Drive.Anchorage.AK 99518 Mailing Adaress:P.O.BOX 111008.ANCHORAGE.AK 99511-1008 (907!349-6653 e FAX 522-2534 July 3,1991 Stanley E.Sieczkowski,Director Facilities Operations &Engineering ALASKA ENERGY AUTHORITY 701 East Tudor Road P.O.Box 190869 Anchorage,Alaska 99519-0869 Reference:Anchorage-Fairbanks Intertie Structure 749 "Temporary Fix" On the afternoon of June 21,1991 Afzahl Kahn directed us to proceed with design of a temporary system of guys for Structure 749.Based on that conversation and Dominic Costanzo's letter of June 17,1991,this letter will discuss: +Basic findings +Recommended steps to determine a final solution +Temporary Solution &General design assumptions +List of materials Basic Findings At this time,it appears that the rotation of.the foundation is due to thaw consolidation of the fill under the downhill side of the foundation possibly aggravated by creep of the anchors on theuphillside.This mechanismwas suggested by Shannon and Wilson intheirApril1991report.AT this time it is the best explanation. The foundation was constructed in several stages.See the attached summary of inspection reports. The first stage was installing anchors.Holes were drilled and #11 Dwyidag bars were grouted in the holes with a cement based grout.The grout was apparently Tremgrout 747 or a similar formulation. The anchors were tested to 75,000 lbs.Six of the anchors were noted as moving one to two inches.This indicates that they were probably not grouted securely into competent rock.If the anchors had been all securely grouted,movement should have been limited totheelasticstretchoftherodsorroughly0.6 in.. Electric Power:Transmission,Distribution.Substations,Control Systems,Generation,System Studies The predrilling performed in 1983 showed rock at 21 ft.Shannon and Wilson's logs show moderately to highly weathered schist at 20 to 22 ft..The logs for the anchor installation show easy drilling in permafrost.The movement of the anchors could be explained if some of the grout had frozen rather than curing and reaching its design strength.The testing would then reflect soil anchors in permafrost rather than rock anchors.Tremgrout 747 is "not recommended for placing below 35°F"(see attached product information).The temperature profiles in Shannon and Wilson's report show an equilibrium temperature of 32°F in the rock on March 20,1991 (also,refer to 8/2/84 log noting ground ice in excavation). After the anchors were tested,the pad and pier were poured.PVC pipe was used around the anchor rods to isolate the anchor rods from the concrete. After the concreted had cured (about 27 days)the anchors were tensioned to 47,000 lbs against the pad.The anchor rods and nuts and washers were painted with mastic to protect them.The foundation was then backfilled. From the review of the inspection reports,it appears that the anchor rods are not rigidly attached to the foundation.It is possible that the pad has settled around the anchor rods leaving the nuts some distance above the pad. Recommended steps to determine a final solution We recommend that the AEA proceed with installing temporary guys and anchors on the uphill side of structure 749.This will keep the structure from leaning further downhill and possibly tipping over.After the guys are installed,the foundation should be excavated only enough to expose the pad and anchors to try and determine the foundation condition.If the nuts on the anchor rods are loose,an independent bench mark should be set and the elevations of the nuts and the pad recorded.The nut should then be run down tight while some final solution is being considered. If we are correct in thinking that the anchor rod nuts are loose, mud jacking could be considered to level the foundation.Freeze piles and insulation could then be installed to stabilize the soil underneath the foundation.It is possible that other modifications will need to be made to regain the original design strength of the foundation systen. Temporary Solution and General Design Assumptions Our temporary solution to the tower leaning is shown in the attached sketches SK1-7-2-91 Location of Temporary Guys Str.749 and SK2-7-2-91 Temporary Guying Str.749.Two rock anchors spaced 10 to 20 ft apart will be installed uphill of the structure to maintain a 1:1 guy lead.A guy vang will be added to the tower just under the lowest crossarm. We are assuming that upslope winds sufficient to fail the foundation in the opposite direction of its present lean will not occur between now and when a final solution is completed. Additional guying would be difficult due to the unfavorable slope and may not be required in the final solution. The temporary guys are designed for the 126 mph wind loads given in Case II on the original "Pictorial Loading,Type "SA"-Single Pole Structure,Tangent (0-3°)(Drawing 2005 Sht 14,AEA #T01-d-D-55- 4264-R49)applied blowing from the uphill side downhill.The tower base is assumed to be pinned in the transverse direction. List of Materials Attached are: SK1-7-2-91 Location of Temporary Guys Str.749 SK2-7-2-91 Temporary Guying Str.749 Material List Spares List "APA spare parts moved from Talkeetna to Healy" Spares List "APA Material Move,Eklutna Yard" NEW-S-BEC-054 Bradley Lake Submittal for Guy Hardware,Fargo TD-1118 &TD-1100 NEW-DCR-BEC-023 Bradley Lake Submittal for Newbery Alaska 1" Anchor Eye. NEW-S-BEC-073 Bradley Lake Submittal for Anchor Shackle TM-2 Item 6 Excerpt from Dwyidag Catalog "DWYIDAG System Detail" Sika Grout Arctic 100 Technical Data Sheet Chances are good that all of the materials except the guy vang for the pole (item 1)and grout are available from spares for the Anchorage-Fairbanks Intertie or from spares for Bradley Lake. Item 1 is the vang for attaching the guys to the structure.It is shown as a through vang with a stiffening ring.This will require slotting the pole on each side,sliding the vang through,welding it in place and then welding the stiffening ring in place.An alternate guy vang design will also be provided in the plans and specifications which will not require piercing the pole.It will consist of a reinforcing plate 3/4 inch thick and perhaps 1'-4" wide wrapped around the pole with the vang welded to it. Items 2 and 3 and 5,the chain shackle,yoke plate,and guy strand are from the standard G4 guy assembly (Joslyn Dwg D7806,AEA #TO1- D-55-V4013-R49)used in the original construction.Eight G4 guying assemblies and 6,000 ft of 19#8 guy strand are shown as available at Healy. Items 4 and 6,the upper and lower guy fittings are also part of the G4 assemblies.The original assemblies use a zinc poured socket furnished by Joslyn.The filler metal is an aluminum-zincalloy.These fittings require a jig to properly hold the guystrandandthefitting.A torch is used to preheat the socket and a controlled temperature melting pot to melt the alloy which is poured into the socket.An alternative is to use some similar fittings furnished by Fargo to Newbery Alaska for the Bradley Lake project (See NEW-BEC-054).These fittings have a compressionsleevefortheguystrandinstalledwithahydraulicpress.There should be some spares stored at Bradley Lake. Item 7 is a 40,000 lb shackle,it can be either an anchor or chain shackle.Its likely there will be a suitable shackle in theIntertiespares;however,if not,Bradley Lake item NEW-S-BEC-073 could be used. Item 8 is an anchor eye for the #11 Dwyidag Rod.It is likely that there are some in the spares,if not,it can be fabricated froma coupler and plate steel.For a similar eye,see NEW-S-BEC-023 (Bradley Lake).I am not sure that the Bradley eye could be used, if available,because I do not know what size rod it is for. Items 9 and 10,the #11 Dwyidag rod and couplers were used extensively on the foundations for the intertie.The "APA Material Move,Eklutna Yard"lists several lengths of Dwyidag rods,but no diameters are given.It is likely there are some #11 rods in the spares.The dimensions are included in an attachment. Item 11,Sika Grout Arctic 100 is a tentative choice for the grout and may change.It is available through Polar Supply in Anchorage. It appears that all of the material with the exception of the vang and the grout may be available in the AEA's stock of spares.The availability needs to be verified before proceeding.The design can be changed to try to use the material available. Please call if you have any questions or comments. DRYDEN &LARUE UW bealbrbeyAlanB.Peabody,P.E. ABP:db/aea/int/stanmat.ltr \ cc:E.Marchegiani,P.E.w/enclosures A.Kahn w/enclosures Item Description Material List Oty 1 10 11 Guy Vang w/Stiffening Ring 1 1-1/8"Chain Shackle 2 Yoke Plate 1 Upper Guy Fitting 2 Guy Strand 19#8 AW As Rqd Lower Guy Fitting 2 Anchor Shackle-40,000 1b 2 Anchor Eye for Rock Anchor 2 Anchor Rod 4 Coupler w/2 Hex nuts 2 Grout As Rqd@ Mfr/Cataloq No. Special fabrication ASTM A-588 Steel Joslyn 6763 Joslyn 7810 Fargo TDA 1100 Fargo TDA 1118 30'#11 Dwyidag Rod #11 Dwyidag Coupler Sika Arctic Grout 100 from 5/18/83 5/26/83 6/2/83 6/28/84 6/29/84 7/7/84 7/8/84 7/9/84 7/10/84 Summary of Inspection Reports Structure 749 Tower is confirmed staked Clearing is inspected,crew to return to midspan 749 to 750 Cold Regions Consulting Engineers bores at 749.Notes refusal at 21 ft,"Possible weathered bedrock below 21'" Crew building helicopter pad and started excavation for foundation. Excavation in progress "Crew cleaning out site".Also Commonwealth checking foundation be material. "First day on site for drill crew",Survey crew stakingoutreferencepoints.Some anchors drilled and grouted Drilling and grouting anchors continues Drilling and grouting anchors continues Drilling and grouting anchors completed Drilling and grouting logs indicate easy drilling in permafrost.A September 10,1984 letter from L.G.Miller to C.R.Parish indicates that 749 was grouted instead of usingCeltiteresinasdothedrilllogs.All anchor rods were 30' with 3'exposed. 7/17/84 7/19/84 7/26/84 7/31/84 8/1/84 Drainage Trench dug CAI on site,crew "mucking out mud/unstable material"an additional 3',anchors are tested,all pass "6,7,9,11, 12,14 moved about 1 to 2"all held 5700 psi"test load was apparently 75 kips.Testing may not have been completed until 7/21/84.Anchors were left with 5 to 6' exposed. "Site partially caved in" "No activity" "16 each Dywidags covered with PVC Pipe around them in ground.Rebar matt and pier in hole for foundation. Approx 6 yds poured ????.Form around base mat.""Crew poured 13+yds concrete.Concrete pour release form reports 8.2cy.Concrete batch record reports 10cy for 749. The foundation calculates out at 8.1 cy in pad and 12.5 cy in the pier.(Pad 2'x10'-6"x10'-6",pier 8'x6'-6"x6'-6") 8/2/84 8/2/84 8/3/84 8/13/84 8/30/84 9/1/84 9/14/84 10/16/84 10/26/84 10/29/84 "Visited site w/Hoop.Pad poured.Granular backfill placed.Solid under ???around base.Foreman said 18" had been placed and muck removed from hole.No water - but can see some ground ice in sides (uphill)of excavation.Hoop not concerned about frozen ground here. Muck gravel and fractured rock at this site.Good bearing once muck is removed." "Crew set up rebar (pier)cage for form to set around." Pier poured.(12.5cy reported) Forms reported as stripped,probably stripped between 8/3 and 8/13. Anchors pretensioned to 47 kips. Foundation tolerances reported 4.7 ft to natural ground, noted on 9/15 4.9 ft to top of backfill Ground resistance checked Conductor sagged Structure torqued Structure approved for payment on final inspection. SECTIO) A-A bb ats ONAn9 NavaodwaL 16-t-L -TASIEheleaey 95°82 3%lesic &we:le din TREMgrou Heavy DutyindustrialGrout Exceeds Corps.of Engineers CRD-C621 If these =Wl eee fee eee oe FON ee ees es ee”(ees oe TECHNICAL DATA Plastic Flowable FluidMpressiStroncth(ASTM Age:Psi :Psi -PsiC1091ODay8,000 7,860 4,625 3 Days 9,050 6,235 6,950 7 Days 11,650 10,880 8,280 14 Oays 12,250 11,510 8,755 28 Days 12,950 12,640 9,230 Water By Weight (%)11.4 12.3 15.8 Flow and Fiow Table AnalysisSetData{ASTM G-230) 5 Drops in 3 Seconds 123%140%N/A Flow Cone Analysis(CRD-C-611-80)N/A NiA 23-28 Seconds Setting Time (ASTM C-191)Iniual Set (minutes)18-22 22-26 N/AFinalSet(minutes)70-80 98-105 NIA eb |a8 ft |ae |af ac |as |at]ae fw]fe |ee]oe |e 1 DESCRIPTION 3 FEATURES Leveling Shims: ahrout 747 ie soecany igri satly strength ihe grout has hardened1e-s '9 specially Non-shrink they should beforrnulatedfornon-shrink industrial applications where melaliic,gas form- ing,and sand-cement grouts are unsuitable.This non-shrink,non-metallic grout does not contain chloride and can be used in a range of consistencies from plastic to fluid. 2 GENERAL USES TREMgrout 747 Non- Metallic is ideally suited for u wide range of applica- tions requiring strength and durability including: ¢Heavy equipment and machincry bases ¢Structural Columns ¢Pump &Equipment Bases ¢Pra-Cast Tee joints ¢Re-pointing mortar joints e Structural Cracks ¢Bearing Plates ¢Rail Posts,Seating Balts¢Pust Tensioned Cables ¢Patching *Non-gas forming *Non-rusting *Meets CRO-C627 ©interior/exteriar applications °Easy to use *Good chemical resistance ¢Excellent freeze/thaw resistance ¢10 years proven performance 4 INSTRUCTIONS FOR USE A Surface Preparation: Surfaces must be free from oil,grease or any loose material.If the concrete surface is Cefective or has laitance, it must be cut back to a sound base.Bolt holes or mortar pockets must be blown cicar of any dirt or debris. Base Plate Preparation: It is essential that area is clean and free from oil,grease or scale.Air pressure relief holes should be provided to allow venting of any isolated high spots. treated with a thin layer of grease, Pre-Soaking;Several hours prior to grouting, the clean area should be flooded with fresh water.Immediataly prior to grouting,any free standing water should be removed with par- ficular care being taken to blow out all bolt holes and pockets. B Mixing:The amount of water added to obtain the desirable consistency must be precise,and aft accurate measuring method must be employed.Consistencies described conform to CRO-C621-83.According to the desired grout con- sistency,the amount of water required for each 55 Ib.unit of TREMgrout 747 Non-Metallic is: Fluid Consistency 4-4%Quarts Flowable Consistency 3-3%Quarts Plastic Consistency 2%-3 Quarts TREMCRETE --_--- in cold conditions warn waler (95-110°F)may be uscd !0 accelerate the strength development. C Application:For best results,a mechanically powered groul mixer should be used.For small quantities of 1-2 bags,a slow speed electric drill with a Suitable paddle ts recommended. it is essential that machine mixing capacity and labor availability is adequate to enabie the grouting operation to be carried out continuously.This may require the use of holding tank with provision for gentle agitation to maintain fluidity.The selected water content should first be accurately measured into the mixer. Slowly add the total con- tents of the TREMgrout 747 bag.Mix continuously for 5 minutes,making sure that a smooth, even consistency is obtained.Place the grout within §minutes of mixing.Where large volumes have to be placed.TREMgrout 74/ may be pumped.A heavy duty diaphragm pump is recommended for this purpose. Coverage and Placing: A 55 Ib.unit of TREMgrout 747 will yield approxi- matcly Ye cubic foot. When placing TREMgrout 747 or any other grout, a continuous grout flow is essential.Sufficient grout must be available prior to starting and the line taken 10 pout a batch must be regulated to the time taken (to prepare the next. Pouring and placing grout should be from ane side only to alimnate voids wn the cured grout by entrap- ment of air of Surplus pre-soaking water.A grout head rriust be Maintained at all times So (hat a corttinuous grout front is achieved. Curing:Upon completion of the grouting operation, exposed areas which are not to be cut back should be thoroughly cured using normal con- crete curing melhods and practice.Tremcrete Systems Incorporated manufactures a variety of chernical Curing corri- pounds which may be used with TREMgrout 747.Please contact your Tremcrete representativa for additional information, Bonding Agents:In an effort to meet the grow- ing demands to utilize TREMogrout 747 in a wide variety of patching conditions,Tremercic Systems,Inc,has Ceveloped both two part epoxy bonding agents and one part water solu- ble bonding agents. Plaase contact your local Tremcrete Systems, Inc.ficid representative or our Technical Services Department for a specific Tremcrete bonding agent recommendation. DC ung.Prior to curing TREMgrout 747 may be Ccleaned-up using water E Limitations:Not recom: mended for placing below 35°F Do not re-temper. 5 PACKAGING 95 Ib.polylined bags 6 STORAGE AND HANDLING A Shell life:TREMyrout should be stored indoors and when left in its original unopened pack- age will maintain its designed performance Characteristics for 12 months. 8 Storage:Keep out of inclement weather 7 PRECAUTIONS Read warnings noted on product package and refer to product Material Safety Data Sheet (MSDS)prior to uS®. 8 WARRANTY We warrant our products to be free of defacts and manufactured to meet pub- lished physical properties when cured and tested according to ASTM and TSi standards.Under this war- ranty,we will provide,at no charge,product in containers to replace any product proved to be dcicctive when applied in accordance with our written instructions and in applications recorn- mended by us as suitable for this product. TREMCRETE SYSTEMS INCORPORATED A PRE Ac Gg Cameras 665 North County Ad.101Woodland,CA 95695 916-666-3633 4492 Commerce Circle SW Atlanta,GA 30336 404-691-1875 Wn ante .Ie VALLEY ELE ITS oc S51 Otte agaceeaec F.o.200SHEETS22-14530SHEETSoa'22-142100SHEETSsamp22.144pers Jo :(eons NM wnsfon:§,Saft,GuBA ph Ap SAE PER WWED /Ranh PreeTOHey 22D 1365 rat2)0 GOLDEN VALLEY ELECTRIC 45:25€ eocaccar fi S260 '-"6,STEEL Guy STRHIVO Cf-"eeee)CI-REEL ©2500 LES ;TS500'°146 wes6000-19/8 Guy CRE §I-REEL&Soap Les.)2000' 37/5"C1-266l @ 6285ces)32000!-37/é it (1PEEL@ Y722 £45) le SUNDLE QWE-STEY 276444 ONL]RS l-BUNOLE TWO-STEP STEEL LANLERS 72+10"SUSPENSION INSULATORLeeey)6-10"Susreusio msilarve CBeaw)Ue -10"SusPEension sa/Sulavoe C BLUE) 1S -STATIC WILE ZVSUCATORS 20°170K DAMPERS 11}-170G°10 DAMPERS / C4-ZEM LB SHOES W/YokKESFE HOWe DA.163-1843-COUNTER LUE IGHTS 2S 5173.34)ALCOA 74 suneER ConVeECrak L0O-FN2,277 ALCOA Stee.eve DE. Cae BY GLUING ASS.4e-G7 7 C7BIl GuyinG YOCE PLATESCTBIOGQUVINGYOFEFLa7es 2- /- JKIVOSOR AGE TOF AIEEE'FIG C7 ME TEUER pian7S SO-12"LecknuTs SO-Le"HEX NUTSO-l2Xile HEL POULT SO-Vex ivf u u 20-2 KZ/2 0 * S -#2xXBl2 *n 50 -2 LoceNUTS50-SY HEX NUT}o-VY RK 22 HEX BOLTj2-A4Kd/Z»» 24.-VEx Ze Hex Bar"G-Texsy Lo-Wer4 oo»» 20-|"HEK NYT S-)XS hex Cccr24-1G ow 12-1XISB*uwfeo-)XA 4 4 SB-}X2Sl «a7G-1 X24 HEX BOLT il-12°Hex NUTJ-12X42 HEX COLTa-WVeKILa/n 24 -172XBO 4h2Z4-i/2xK 3)hoa.'1 lexazler « -IK 2%HEK KOLT S-2X6 NEX cOLT \2-2/4 LoceNUT lo-2Yd¢WEX NUTo-al XT eX BAT 12-2"Lecenur o-212 XB HEX HQT 21 22/1985 iiize GILITEN VALLE'SWE ITRIS S52 GE lo-Y'CLEW/S EVE B-GUY Wie THUARLE CLEVIS50-8 Guy GRIPS PREFDENM 2Z4-Gile"EYE EXTENSIOW IZ-SS"EVE EXTEVSOY 2O-LARGE COTTER KEYS TOTAL F.aa =¢8MATANUSKA ELECTRIC ASSOCIATION,INC. P.O.Box 2929 Palmer,Alaska 99645 TELECOPIER COVER LETTER SENT BY: DATE: TIME: ansuet TO:C\\Peabody FAX #: PHONE #3 SENDER:-acie.Hanson FAX #:907-745-9328 PHONE a J4S-Ga RO \TERIAL TO BE TRANSMITTED: NUMBER OF PAGES:(EXCLUDING COVER SHEET) EMARKS3 er SteMATANUSKA ELECTRIC ASSOCIATION,INC.P.O.Box 2929 Palmer,Alaska 99645 TELECOPIER COVER LETTER SENT BY: DATE? TIME: 'ANSMIT TO:O\\Peabody FAX #3: PHONE #3 SENDER: acie.Ronson FAX #:907-745-9328 rxone #1 ]D-FARO ATERIAL TO BE TRANSMITTED:_ NUMBER OF PAGES:(EXCLUDING COVER SHEET) .EMARKS3 TOCSACms 6 SACL SOMO Jee eT Te oe hime bd we8&&NYRYRHHeeHewnNw>aWwuy24"x36' 24"x%34' 24"x34' 24"x65' 24"x60' 24"x66' 30"x54' 30"x34' S 7VEwevrFsy- GUEA 8s APA MATERIAL MOVE vaEKLUTNAYARDSg 6'Tower Washer 2"thick 24"x68' 30"x35' 24"x59! 30"x67' 30"x37' 30"x34' 30"x49" 30"x63' 30"x44' 30"x33' 30"x58' 30"x48' 36"x48' 36"x62' 36"x38! 36"x51' ,tapered ,tapered ,tapered TACe-Ors ff /AK)"HOWL 2ePest TR.Se MOL 12 Hn&@each each each each each each each each each each 4 each nwts-ewsNYNYFPFYBYWeenneach each each each each each each each each each each each each each each each each 36"x55' 36"x30' 48"x57',tapered 36"x67' 36"x50' Waists 12"x15' 18"x16' B"x14' 10"x16' 8"x1l' 10"x9' 8"x7' 20"x15' 16"x17' 14"x16' 36"x30' 36"x24' 48"x34' 48"x40' 60"x27' 72"x16' 72"x15' 60"x23' 60"x27' 48"x27' 48"x31' 60"x17' ,tapered ,tapered TACL "we!¢31fAG)Sm 341!Ome ST TE Do RATT 1 each -60"x22' l each -60"x25' 1 each -48"x30' 1 each 30"x55' DAMAGED TOWERS l each -24"%x64' 1 each -16"x16' 2 each =24"x35' l each -24"x43' l each -24"x64' 1 each -36°x63' 1 each -24"x34' MISCELLANEOUS 13 reels -954 "Rail" 4 each -40'Tubular Ladders 7 each 28'Square Ladders 1 each -10'Square Ladders 2 each -20'Tubular Ladders -DAMAGED 12 reels -Guy Wire,misc. S each -Guy Wire,Lagged 41 bundles -Ladders 2 bundles -Ladders -DAMAGED 7 pallets -Rock Anchors 1 each -Funnel 1 bundle -Copper,3 str. 3 bundles -Galvanized Tower Washers 88 bundles -Dwyidag,25' feFPWwWWwWDSOoFFbundle -12'x6"Dwyidag pallets -3'Bwyidag bundles -15'Dwyidag bundles -11'Dwyidag pallets -8"Square Washers pallet -Steel Couplings crate -Miscellaneous Steel barrels -Hardware bundle -1ll"xll'x%"plate bundle -30'Dwyidag bundle -20'Dwyidag each -55 Gallon Drums,empty pallets -Insulators (1 crate has exposed and concealed damage) pallets and crates mixed poleline hardware reels -Trench Wire. bundles rebar,various lengths pallets -celltite epoxy resin crates -celltite epoxy resin crates and pallets of steel components |Lo.ce 44gnBRADLEYLAKEHYDROELECTRICPROJECTwomog161983ALASKAENERGYAUTHORITYRECciveuvv! CS CONTRACT/NO._2890107 SUBMITTAL DATA SHEET LaeSUBMITTAL NO._NEW-S-BEC-054TO:BECHTEL CORPORATION CONSTRUCTION MANAGER P.O.BOX 1869,HOMER,AK 99603 SPEC.OR DRAWING REFERENCE:3.4.3.2.1 DATE SUBMITTED:10-9 89 /3.-2.l.c :DWG 15800-"S-320c-2 DESCRIPTION OF SUBMITTAL:Guy narawabe cat.info./Guy install &insvectprocedure:Item #10&11:Fargo TDA-1118 ThA-(100 SUBMITTED:X_ORIGINAL __.RESUBMITTAL -_..SUBSTITUTION __SHOP DRAWINGS ___PRINTS ___PLANS -SAMPLES ___.CATALOG DATANo.of Copies Transmitted 8 No.of Sheets per Copy 4 The attached submittal has been checked for accuracy,compliance,and complete- ness with the Specifications and is hereby transmitted for your review. Contractor:Newbery Alaska,Inc.By James R.Seym ¥ Date Rec'd from Contr.[o/2AE By 7F-_pate Sent to SWEC fofte/t4 By 264 COMMENTS :File 6.3.3.¢f ROUTE. _cA AMwee$.04-003 CoO >Guy HARDWARE CAT.INFO _._PFE C6.3,04-004-00;Guy INSTALL +INSPELT PRicedye =- GNTAonttrrderstamchthesevieteS?-_ME/EEtemothsacumcadishpertteTok1eeey°aahiest 2 -7 0 Tea-1/____AEA-A 1)2a.Ange ger ass'4 tor VE-Z Ass!+19 N0.P Abs,_.._--__AEA-B Date Sent from SWEC By Date Rec'd from SWEC.By APPROVAL STATUS 1.Approved -Work may proceed. 2.Approved as noted -Revise and resubmit.Work may proceed subject to the incorporation of the changes indicated. 3.Not approved -Correct and resubmit.Work may not proceed. 4.Review not required.Work may proceed. BECHTEL Review By Date SWEC Review By Date 19736ProjectPrintNo._17707-TS-3,04-003-00 004-06 Returned to Contractor by Date BECHTEL CORPORATION Receipt Acknowledged by Date CONTRACTOR:White.Sotdenrod RFCUTEL:Green,Pink SWEC:Canary Catalog Section 8 Page 47 TOWER GUY DEAD-END FOR LARGE DIAMETER STRANDGALVANIZEDSTEEL-ALUMOWELD"BRIDGE STRAND The Fargo Tower Guy Dead-End has been developed and !ested lor terminating high strength gtv strand commonly used on transmis- sion and communication towers. PATENT PENDING FEATURES FAST INSTALLATION -can be installed by one man in minutes. SAFE -mechanical integrity less dependent on installer or individual techniques. PERMANENT-requires no retensioning after installation. VERSATILE -can be pre-assembled at remote locations or at the job site. HIGH STRENGTH-develops full mechanical strength of strand rating. LONG LIFE -components provide excellent corrosion resistance. COMPACT ASSEMBLY-no additional helical support rods are required. LIGHTWEIGHT-provides convenience ol {ransport and installation. ADJUSTABLE-up to 18"of guy strand take-up available. ASSEMBLY COMPONENTS .;Fix OAS ptyee g OPERSNeeGELS U-BOLT -galvanized steel : ; COMPRESSION SLEEVE -aluminum alloy RETAINING YOKE -aluminum alloy SPACER BAR-aluminum alloy THRUST WASHERS-galvanized steel HEX NUTS -galvanized steel hex and heavy hex type FARGO MFG.COMPANY,INC. Section 8 Page 48 TOWER GUY DEAD-END TESTED PERFORMANCE The Fargo Tower Guy Dead-End has been extensively tested on steel and alumoweld strand using a 200.000poundhorizontaltestmachine.In order to meet Fargo's high standards of performance,testing in excess of in- dustry requirements was conducted.These tests incluce: MECHANICAL HOLDING STRENGTH:Tension applied to ultimate assembly strength at the rate of 10.000 Ibs./min. SUBSTAINED LOAD -A)77%of assembly strength for 168 hours B)85%of assembly strength for 168 hours C)95%of assembly strength for 168 hours CYCLIC LOADING -1000 cycles at 60%of!assembly strength tor 6 minutes followed by 10%for 1 minute ADJUSTABILITY -Determine field adjustability following loads up to 75%of assembly strength. TORQUE VS.TENSION-Determine torque required for lensions from 0-25 %of rating. TYPICAL TEST RESULTS STRAND.]")STRAND |);SUSTAINED...|"CYCLIC =|225°ULTIMATE.,SIZE.”-|RATING (Ibs.),|"2°!LOAD 2:[fss-LOAD 3s |-:38.:TENSION (lbs.) %”EHS 79,700 NO SLIP NO SLIP 87,280 (109.5%) 37 #5 AW 142,800 NO SLIP NO SLIP 157,610 (110.4%) INSTALLATION TOOLING The Fargo Model T-220D High Speed Hydraulic Press ]Qa ae develons 220 tons of force using a standard 10.000 P.S1.arr Br att Phe double acting hydraulic pump.Furnished compiete withiBgquickcouplersandgroundstand(not shown).A convenient lease/rental plan is available. NOTE:Due to its increased capacity,the Fargo 72200 isPer---|-*ne diene Ria recommended for other compression fittings such asTy<i splices and dead-ends.The longer "bile length”of the diessignificantlyreducesthenumberofcompressionsrequiredresullingindecreasedinstallationtime,less connector"bowing”and a more secure assembly. MONE!7-2200 ° Approx.Wt.=200 Lbs. Section 8 Page 49 TOWER GUY DEAD-END I 3; gq ------_ontre STEEL STRAND (ALL TYPES) STRAND ADJUST-|CATALOG ||LENGTH]DIA:|RADIUS |DIE |APPROX.|ASSEMBLYSIZEMENTNUMBER"LE”."p""R”SIZE |WEIGHT RATING ye .NONE TDS-0900 12.4 a .3.0 Ibs. |. %°OR %¥0.97 B509 : ;18"TDS-0918 31.6 '6.5 Ibs.38.000 Ibs. ye NONE TDS-1100 14.6 ye -5.0 Ibs. :/1.03 B511 42,400 Ibs., 18°TDS-1118 34.2 i 10.0 Ibs. os "NONE TDS-1300 17.0 ..8.0 Ibs.¥,y 1.22 B513 58,300 Ibs.18"TDS-1318 37.0°°15.0 Ibs. ¥NONE TOS-1500 19.3 1”1.41"B515 11.0 lbs.79,700 ibs. 18 TDS-1518 39.5°21.0 Ibs. "NONE TDS-1700 21.7 1"rer |asi7 L_tZO tbs.104.500 Ibs. 18 TDS-1718 42.4 29.0 Ibs. .NONE TDS-1900 .24.2 7 .23.0 Ibs.%1Y,1.80 B519 130.800 Ibs.18"TDS-1918 45.1 fe 38.0 Ibs. 18 TDS-2118.47.8 49.0 Ibs. ALUMOWELD®STRAND 74S NONE TDA-0900 11.3"2.5 Ibs. 746 x"0.97"|8509 27.190 Ibs. 19#10 18"TDA-0918 29.7"6.0 Ibs. 1948 NONE TDA-1100 12.0°4.0 Ibs...11 43,240 Ibs.19#9 18"TDA1118 ||31.6 %1.03"|85 9.0 Ibs.3.240 Ibs 19#7 NONE TDA-1300 14.0 ..6.5 Ibs. ye 1 .950 Ibs.37#10 18”TDA-1318 33.9 '1.22 B513 13.5 Ibs.52.9 19#6 NONE TDA-1500 15.9°10.0 ibs. 37#9 1"1.41”|8515 84.200 Ibs. 3748 18"TDA-1518 ||36.1 19.0 Ibs. 1945 NONE TDA-1700 18.0"1%"rei |BS17 14.0 Ibs.100.700 Ibs. 37#7 18"TDA-1718 38.5 26.0 Ibs. NONE TDA-1900 19.9 .. 19.0 Ibs. v,1.B519 120.200 Ibs.3746 18”TDA-1918 40.8 ,80 35.5 Ibs. NONE TDA-2100 21.8 . 25.5 Ibs. 14!.B52!142.800 Ibs.3745 18"TDA-2118 43.0°m 2.00 44.0 Ibs. NOTES:HF Minimum press size -220 tons @ Spacer bar assembly furnished on adjustable units only FOR OTHER TYPES &SIZES -CONTACT FACTORY m For tamperproof nut guards add sullix "G" Section 4 Page 50 TOWER GUYODEAD-END INSTALLATION PROCEDURE 1.For ease of installation.strand should be 4.Select the proper compression die as indicated straight,in-lay and free o!burrs.Deburr end of on sieeve.Start first compression between the strand as required.end of the sieeve nearest the retaining yoke and the first knurl.Continue compressions be-2.Slide retaining yoke onto strand and out of the {ween knuris to opposite end of sleeve.(Figureway.(Figure 1)2) Figure 3Figure| Insert U-bolt through anchor eye or attachment fitting.On adjustable units.close spacer bar and securely tighten nuts.(Figure 3) 3.Slide compression sleeve onto strand (do not 5. rotate)so that a length equal to two (2)strand diameters extends beyond end olf sleeve. (Figure 1) Figure 4 Insert U-bolt into the yoke/sleeve assembly.In- stall thrust washers,heavy hex (thicker)nutsandhexnutsinthatorder.Tighten nuts evenlyOosoyokeissquareonU-boll.(Figure 4)Figure 2 A 'BRADLEY LAKE HYDROELECTRIC PROJECT ra ALASKA ENERGY AUTHORITY /CONTRACT/NO._2.:-:V1LU7DESIGNCLARIFICATIONREQUEST TO:BECHTEL CORPORATION DCR NO.jtw-Ovnesen2. CONSTRUCTION MANAGER P.O.BOX 1869,Homer,AK 99603 DATE SUBMITTED:ince if.-oLY SPEC.OR DRAWING REFERENCE:<.4,-.2,13,.240 [12 500-F5+2204-4 SUBJECT:Soei./3oil aachor Guy jcssennen: DESCRIPTION/REQUEST:2e@cuest aovroval for nsterial anu tiwensioa ¢3227773 SA Wie SuUDItCo uy atwacnszeAt subulctsu and e00roveu on wSb-127 12 pry ae:reaviges parental as (G-sanatana me eye ADIYOVEL 15 Seuuestec adAF dus 19 Lons 132¢dne to fsbpricars Contractor:.iewoerv Alas<a._lne.By ovr a pales Ay Seynou:o.1,AAVANGE bag]FATED TS.vayaen FEAT?TA GFF"Date Rec'd from contr AS}'By 77 _Date Sent to SWEC 4/6 76 By =-77=.7 ra éRESPONSE/RESOLUTION:/rire Lie.3.B.4/.tt nouTS" .:(LLL ae LEP A Fyre PFE AE CE ME/EE PROC FCM AEA-A AEA-B 93479ResolvedByDateApprovedByDate Requires:E&DCR DCN MEC No Further Action Date Sent from SWEC By Date Rec'd from SWEC By Returned to Contractor By Date BECHTEL CORPORATION Receipt Acknowledged By Date CONTRACTOR:White,Goldenrod BECHTEL:Green,Pink SWEC:Canary RCV BY'Xerox felecepier 7020 5 3-29-00 |12:29 5032038059<9072354083i8 1 ¢ "2 ,b '0 A | |a AYwy!ye :=Re hse 'yl |AS72 GRSO - |a a Ny) vif}:om) ap |Toyoy gue |haorm|TT, tm iTS)a.\\L -\2renxnt oD 3479\ 347 i NEWBRBERY ALASKA (Y AnmigcHaRm EWE \.BRADLEY LAKE HYDROELECTRIC PROJECT ALASKA ENERGY AUTHORITY 'CONTRACT/NO.2890107ew' SUBMITTAL DATA SHEET TO:BECHTEL CORPORATION SUBMITTAL NO.NEW-S-BEC-073 CONSTRUCTION MANAGER P.O.BOX 1869,HOMER,AK 99603 DATE SUBMITTED:10-11-89SPEC.OR DRAWING REFERENCE:3.5.3.2.-D |DWG 15800-FS- 320D--1 DESCRIPTION OF SUBMITTAL:CAT.INFO.INSULATOR HARDWARE .ANCHOR SHACKLE TM-2 ITEM 6 SUBMITTED:XX_ORIGINAL ___RESUBMITTAL ___SUBSTITUTION ___SHOP DRAWINGS __PRINTS ___PLANS SAMPLES ___CATALOG DATANo.of Copies Transmitted fe}No.of Sheets per Copy ] The attached submittal has been checked for accuracy,compliance,and complete- ness with the Specifications and is hereby transmitted for your review. Contractor:_NEWBERY ALASKA,INC,By rsa Ce Doig remJAMESReNSEYMOUR Date Rec'd from Contr.A falfp By v4)Date Sent to SWEC LOLLY ES By "4H COMMENTS :File C¢.3.3 tours.* __CA AEHShacklehas6pening"WwW "dimens.of [+e ”---_PFE AE40kae.-- CE /____ME/EEWidthotVAMshodbecheckeelhelesize?__aoeandthroatdepthfvaneintcheckle”"OO _shackle belt __._FCMshackkeNemY_._AEA-Aac-1 TPN ___AEA-B-_ ake - Date Sent from SWEC By Date Rec'd from SWEC By APPROVAL STATUS _.1.Approved -Work may proceed. __2.Approved as noted -Revise and resubmit.Work may proceedsubjecttotheincorporationofthechangesindicated. _.3.Not approved -Correct and resubmit.Work may not proceed. __4.Review not required.Work may proceed. BECHTEL Review By Date SWEC Review By Date 19784ProjectPrintNo._17707-TS-3.09 Q0Y-00 Returned to Contractor by Date BECHTEL CORPORATION Receipt Acknowledged by Date oOLINE AND TOWER END HARDWARE ANCHOR SHACKLE TYPE AS Anchor shackles are used to attach associated hardware to the tower pad.Back to back anchor shack- les are commonly used at the tower attachment point to orientate the plane of the tower plate and the balance of the insulator hardware. Material:Body-galvanized steel Hardware-galvanized steel Cotter Pin-stainless steel (3FORGED STEEL AS ULTIMATE OIMENSIONS-INCHES (MM)APPROX.|CATALOG STRENGTH WT.EACH NUMGER LBS.(KG)L 8 w c T R PO LBS.(KG) IAS-25 30.000 20 %%1%”he %74(13.608)(55.56)|(15.88)|(22.23)|(34.92)|(12.70)|(17.48)|(15.88)(34)30.000 2s %Z *D "he cry 86AS-25-BNK (13.608)(85.65)|(15.88)|(22.23)|(3492)|(12.70)|(17.46)|(15.88)(39)|AS-254 30.000 Pa %A 1%”Ts cry 1.00(13.608)(70.64)|(15.88)|(22.23)|(34.92)|(12.70)|(16.67)|(15.88)(45)|30.00 a %”1%D rey rvs 1.12AS-25-L-BNK (13,608)(70.64)|(15.88)|(22.23)|(34.92)|(12.70)|116.67)|(15.88)(siAS-25-W 25,000 3 %1¥%i'Ke v7 1 ry 1.50 (11.340)(76.20)|(15.88)|(4445)|(42.86)|(15.88)|(25.40)|(15.88)(68)30.000 3 *™%Te %1 %1.65AS-25-W-BNK (13.608)(76.20)|(15.88)|(4.45)|(42.86)|(15.88)|(25.40)|(15.88)(75)|AS-35 35.000 Pn 'he 1%1s %Ye Ya 1.47 |(15.876)(70.64)|(17.48)|(26.99)|(42.86)|(15.88)|(19.06)|(19.05)(.67)40.000 a "he 1s Te %%%1.66AS-3S-BNK (18.144)(70.64)|(17.48)|(42.86)|(26.99)|(15.88)|(19.05)|(19.05)(75)AS-50 50.000 ry Z h 3 ¥e Ve rm 225(22.680)(aa.90)|(22.23)|(22.23)|(47.62)|(19.05)|(19.05)|(19.05)(1.02)60,000 3”7s z 1%”Ve %%e 244AS-50-BNK (27.216)(88.90)|(22.23)|(22.23)|(47.62)|(19.05)|(19.05)|(19.05)(1.14)AS-50-W 50.000 EV ”1%1%¥%1 z 225(22.680)(88.90)|(22.23)|¢31.75)|149.21)|(19.05)|(25.40)|(22.23)(102)60,000 vA”a 1%Te %1 ”275AS-50-W-BNK (27.216)198.90.|(22.23)|(31.75)|(49.21)|(19.08)|(28.40)|(22.23)(1.25)0.000 ™”he 2 A 1"1 a31AS-60-BNK (36.288)(95.25)|(22.23)|13651)|(5398)|(22.23)|(2858 |(25.40)(196)AS-135 135.000 ¢1”2%7%1%THe 1"15.75(61.236)(154.40)|(38.10)|(57.15)|(85.73)|(34.93)|(48.04)|(38 10)(7.14)150,000 '1%:2%7%1%Te 1”15.75AS-135-BNK (68.040)(152.40)|(38.10)|(57.15)|(85.73){(3493)|(46.04)|(38.10)(7.14) ANOERGON ELECTINGCAL CONNECTORSDSQUAREJ)COMPANY 19784 25 DYWIDAG System Details -.a...°?éi)weeSgkwJumelilwe Right hand thread. . +..1|Threadbar eireate secon Strength Weight |Maximum :Coupler Aen ut io Width |Diameter (fov-ki)Area (fpwAgs)(Ibs./ft.)|Diameter Diameter Length a (in.)a (in.)e (in.) (inches)(A,.-inches2)}(Kips);(inches)d (in.)¢(in.): Ys 157 0.28 43.5 0.98 .750 1.250 |4.50 1.625 2.00 |1.25 1 150°0.85 127.5 3.01 1.125 2.000 |5.50 1.875 2.375;1.75, 1Y%.150°1.25 187.5 4.39 1.437 2.375 |6.75°°2.50 350 |2125 | 1%150°1.58 237.0 5.56 1.562 2.625 |8.625 275 |350 |2375 | "b's the minimum threadbar protrusion (in inches)to accommodate prestressing,proof loading or coupling."b'=v2 ¢+2”. *Grade 160 Dywidag Threadbars available on special order when lead time permits.**7V¥2"tong coupler available on special!order ANCHOR NUT ={-ttTe Resin anchors using Dywidag prestressing steel may be proof stressed to 80%of the guaranteed ultimate strength of the prestressing steel.Final working force should not exceed 60%of the guaranteed ultimate strength of the prestressing steel. COUPLER Ex --= sa:nrarcing steel!-SSTM A SiS (Sreae 32) Left hand thread for size #6 thru #11 and right hand thread for #14 and #18. Threadbar |threaabar|Section |W'S,|weight |Threadbar |>__Hex NutDesignationDiameterArea(f,Ac-kips)(Ibs./ft.)Diameter Diameter Length Width Length(inches)(A.-inches?)(inches)d (in.)¢(in.)e (in.)a (in.) 6 0.750 0.44 26.4 1.502 0.862 1.125 3.500 1.125 1.000 #7 0.875 0.60 36.0 2.044 0.996 1.312 3.750 1.250 1.250 #8 1.000 0.79 47.4 2.670 1.122 1.500 4.000 1.437 1.375 #9 1.128 1.00 60.0 3.400 1.268 1.687 4.250 1.625 1.625 #10 1.270 1.27 76.2 4.303 1.433 1.875 §.000 1.750 1.875 #11 1.410 1.56 93.6 §.313 1.614 2.125 6.000 2.000 2.000 14°1.693 2.25 135.0 7.65 1.862 2.687 7.500 2.500 3.500 18°2.257 4.00 240.0 13.60 2.504 3.500 10.000 3.250 4.000 "b''1s the minimum threadbar protrusion (in inches)to accommodate prestressing proof loading or coupling,"b'=Yac +v2”. "e”is measured across nut flats. "Coupler and hex nuts #14 and #18 develop 100%or the guaranteed ultymate strength. HEX COUPLER NUN a i)al Jawad $C 5 Ee --clefjp Resin anchors using Dywidag reinforcing steel may be proof stressed to 90%of the quaranteed yield strength of the reinforcing steel.The final working force varies with the Typical Data(Material at 23°Cc,50%RH) Properties:Tested at water/solids ratios 0.24 by weight Colour dark grey when mixed with water: Flow cone Initial set (+20°C,Vicat Needle) Placement Time 15-20 secods 85-110 minutes 30 minutes minimum Compressive Strengths (As determined in a simulated pile grout test cell on150 mm x 300 mm cylinders) Wet Grout Temp.°C Substrate Temp.°C Compressive Strength at 24 hours 20 3its 40 (7°=28 MPa 20 -5 725 32 MPa 20 +1 32495 26 MPa Packaging:25 kg Multi-wall bag of lo, ro)Yield:2 we le e *(hails wei ?14.2 litres Shelf Life:6 months (if longer shelf life required consult Sika for package options). 'Chart #1 Wet Grout Temperatures for Various Water/Dry Grout Temperatures Wet Grout Dry GroutTemperatureTemperature-c_-_-C_ 20 -10 20 0 20 10 20 20 25 -10 25 0 25 10 25 20 Water Temperature °-ci 50 40 30 20 60 50 40 30 Surface/Pile conditions: HOW TO USE All free standing water (ice)and other foreign materials to be removed from interior of pile jacket or drill hole. Steel pile should be held securely in position so that it does not move during grouting and until grout has attained minimum 24 hour cure. The "down-hole”placement temperature range to be -10°C to +4°C.If down hole temperature exceed +4°C,recommended use of Sikagrout 212.If down hole temperatures are below -10°C call Sika Technical Services. implement protection of grouting operation under adverse weather conditions. Mixing/Application:For mixing of grout a mechanical mixer,paddle,mortar or concrete type.is strongly recommended.The size of the mixer should be appropriate to the volume of grout required.Refer to "Pump Application”for recommendations on pumping grout. Insure potable water is available. Pre-measure temperature of the DRY bagged grout . Pre-heat mixing water so that mixed WET grout temperature is +20°C to +25°C (refer to Wet Grout Temp.Chart).Compensate for any pre-cooling of water while in mixing container prior to addition of ORY grout. Measure 6.1 litres of water per 25 kg bag and mix for 3 minutes.Check WET grout temperature to insure it is between +20°C to +25°C. Once mixed the grout will remain fluid for placing up to 15 minutes.If longerplacingtimesarerequired,keep grout agitated and place within 30 minutes. DO NOT pre-batch excessive units of grout if placement cannot comply to the above time limitations. With pile and/or anchor preset into bore hole,pump or pour mixed grout into bore hole using a grout tube placed at the bottom of the hole. Pump Application:Equipment recommendation;Chem Grout CE-550P Mini Grout and mixer,with 1 inch ID x 50 feet of Grout Hose. With mixer blades running at approximately 60-75 RPM mix grout for 3 minutes (after all dry material has been added to required mixer water).Grout will be a creamy smooth,lump free consistency. Do not allow grout to sit for more than 5 minutes without resuming pumping and/or re-circulation operation. Sika Grout Arctic 100 Technical Data Sheet Description:Sika Grout Arctic 100 is a preblended,cementitious,ready to use,pile and rockboltgrout.When pre-conditioned,Sika Grout Arctic 100 can be placed intosubstratewithtemperaturesrangingfrom-10°C to 4°C.It was formulated to meet the exacting specifications for pile grouting at the Short Range Radar Stations intheCanadianArctic. Where to use:®Standard piling operations in permafrost conditions. *Anchoring rebar in piling jacket under permatrost conditions. *When substrate temperatures prohibit the use of normal portland cement pile grouts. Advantages:*High heat of hydration to off-set low substrate temperature. ®Early strength gain. *Designed for work in permafrost conditions. *Easy to mix,ready to use,pre-packaged system. *Easily pumped. *Flowable consistency. *Proven applications in Arctic Environment. Sika Grout Arctic 100 Technical Data Sheet Description:Sika Grout Arctic 100 is a preblended,cementitious,ready to use,pile and rock bolt grout.When pre-conditioned,Sika Grout Arctic 100 can be placed intosubstratewithtemperaturesrangingfrom-10°C to 4°C.It was formulated to meettheexactingspecificationsforpilegroutingattheShortRangeRadarStationsin the Canadian Arctic. Where to use:®Standard piling operations in permafrost conditions. ®Anchoring rebar in piling jacket under permafrost conditions. ®When substrate temperatures prohibit the use of normal portland cement pile grouts. Advantages:*High heat of hydration to off-set low substrate temperature. ®Early strength gain. ®Designed for work in permafrost conditions. ®Easy to mix,ready to use,pre-packaged system. ®Easily pumped. *Flowable consistency. *Proven applications in Arctic Environment. Minn f25[DRYDEN i _AlRUE INC.CONSULTING /ENGINEERS 6436 Homer Drive.Anchorage.AK 99518 Mailing Address:P.O.BOX 111008.ANCHORAGE,AK 99511-1008 (907)349-6653 @ FAX 522-2534 July 9,1991 RECEIVED iJL04 1951 Stanley E.Sieczkowski,Director ALASKA ENERGY pUTunartyFacilitiesOperations&Engineering ALASKA ENERGY AUTHORITY P.O.Box 190869 Anchorage,Alaska 99519-0869 Reference:Anchorage-Fairbanks Intertie Structure 749 "Temporary Fix" Construction Cost Estimate We estimate the cost of adding the guys to Structure 749 described in my letter to you of July 3,1991 as: Labor &Equipment 54,600 Contractor Furnished Materials 3,800 Helicopter Charter 22,500 Subtotal 80,900 Contingency 8,100 Total 89,000 The "on-site"construction looks like it will take just over two weeks.Allowing two weeks after notice to proceed for purchase and delivery of materials (which may be pushing it)would give four to five weeks from notice to proceed to completion. If you have any questions,please give me a call. DRYDEN &LaRUE,INC. GleeAlanB.veapoay (1 "a E. ABP:db/stanest.ltr Electric Power:Transmission,Distribution,Substations,Control Systems,Generation,System Studies PUNT IDRYDEN ¢(LalRue Inc.CONSULTING /ENGINEERS 6436 Homer Orive.Anchorage.AK 99518 Mathing Address P.O.BOX 111008.ANCHORAGE,AK 99511-1008 19071 349-6653 @ FAX 522-2534 RECEIVED June 20,1991 ible 2 39] ALASKA ENERGY 2 TnRiTy Mr.Dominic Costanzo Contracts Officer ALASKA ENERGY AUTHORITY 701 East Tudor Road P.O.Box 190869 Anchorage,Alaska 99519-0869 Reference:Contract No.2800266,Work Order No.AEA-DRL-005 Anchorage-Fairbanks Intertie,Structure No.749 Proposal This proposal is to design a temporary fix for structure 749 on the Anchorage-Fairbanks Intertie.We propose to perform the services in the Scope of Work described in your letter of June 17,1991 with the schedule and estimated costs of: Task 1 (Design): Labor:$8,300 Expenses:300 Subcontracts:2,500 Total:11,100 Schedule:Complete within 4 weeks of notice to proceed. Task 2 (Plans &Specifications): Labor:$5,200 Expenses:200 Subcontracts:700 Total:6,100 Schedule:Plans and Specs complete within 3 weeks of notice to proceed,site visit as appropriate. As part of Task 1 we have included some time for consultation with the Fairbanks office of Shannon and Wilson.Shannon and Wilson performed the subsurface investigation at the site.In task 2 we have include time for consultation with the Testing Institute of Alaska on welding procedures and specifications. Electric Power:Transmission,Distribution,Substations,Control Systems,Generation.System Studies We suggest a fee of $800 for Task 1 and $400 for task 2. If you need any more information or wish to discuss the cost, please give me a call. Delbert S.LaRue P.E. OSL:db/aea\constanzo.!tr LeKemy-torters 1 Eric Marchegian 612-31 @9:43 GVEA ENGINEERING 907 451-5638 adeWorst14)se LUIS &DALLEY LNC 355 Pade -yrp1ast tes Loftus &Dailey,Inc. structural engineering @ angineering management June 11,1991! Golden Vailey Electric Asscciation P.O.Box 1249 Fairbanks,AK 99707 Attention:Greg Wyman Subject:Gold Hill Substation -Roof Modifications Dear Mr.Wyman, A meeting took place in our office on May 15th during which time we discussed the roof modifications to the Gold Hill Substation.A synopsis of our Investigative efforts and design alternatives was presented to you at that time.This letter serves to document our discussions with you during that meeting. The main concern with the substation Is ica and snow sliding off the roof and demaging equipment on the wast sida of tha building.Loftus &Dalley.inc.was asked to investigate tha problam and coma up with @ solution.Tha dasign criteria included several stipulations thet complcata the problem.The high voltage equipmant within the substation creates a hazardous environment for construction.it {a not possible to work within the fenced area sdjecent to the west side of the building without shutting down tha substation and shutdown costs are considerable.Also,sensitive equipment housed within the building must be protected from exposure to weather and dust during construction.itis clear that any designschemeshouldstriveforsimpleandexpoditiousconstructiontaminimizedowntime. Two conceptual design possibilities wore investigated.'The first involved a retrofit of the existing roof system.The second adds an independent frame and reat assembly to shedenowawayfromhighvoltageequipment.A retrofit of the existing roof system would add insulation and allow air ciroulation to reduce melting.This necessitates strengthening the structural members to carry the Incressed snow loeding.icv cleats can be addad to retard sliding anow.There is @ considerable emount of labor invoived with thia ratrofit scheme requiring a prolonged shutdown period.There is some concer that holding snow an the roof will pause icing to occur along the eave areas giving rise to probleme with the roofing weatherseal,interior leaks over high voltage equipment would present yet another problem. {028 Aurora Drive 341 West Tudar Raad,Suite 207 Fairbanks,Alaska 99709-5526 Anchorage,Alaska 99503-6638 (907)436-7660 (907)562-2066 @6/12/91 Q@9:44 GUEA ENGINEER 6338Mo-3i-gl 14:93 LOFTUS &DAILEY INC ING 90?ee Pes one From @ practical standpoint,the existing metal building is weather tight and shows no signsoffaturefromoverioadingorfreeze-thaw cycles.A eclution that lesvas the exiating structure unchanged and simply adds a root over tha west half of the building eppears extravagant. However,upon closer examination,the benefits of working outside the high voltage area with minimal downtime to the substation become apparent,There ure two design alternatives proposed for this concept.Alternate No.1 Involves a rigid frame thet spens the 86 ft. direction and sheds snow to the north and south.Another version of thie alternate usee column at midspan.Alternate No.2 has a frame that continues the pitch of the exieting roofwiththeideaofsneddingsnowtothesastsideofthebuilding. Of the proposed indepandent frame aiternatives,Alternates No.1 appears ty be the moat economical,All work Is performed outside the nigh voltage areas.The foundation work can be accomplished while the substation tz enargizad.In adation,the steel erection ls very fast with all shop welded,field bolted connections.Siding can be agded to close In east and west gable ends.North and south ends can be sided Gown to the elevation of the existing bulldingeavefines.The construction will nave tittle Impact on the existing structure and Its simplicity will afford 8 minimum of down time to the operation of the substation. We consider the BO ft.free span version of Alternate No.1 to be the best solution to the substation roof problem.A preliminary cost estimate for the construction of this eltternate is approxdmately $60,000, The Gold Mili Substation hes proven to be an interesting problem.We look forward tocontinueworkingwithyouonthisproject.If you have any questions regarding tneinformationinthisfetter.please cell us. Sincerely, Loftus &Dalley,inc.febikUdKeinbath Patrick W,Reinhard PWRiceh ALASKA INTERTIE OPERATING COMMITTEE WEDNESDAY,MAY 8,1991 (ALASKA ENERGY AUTHORITY CONFERENCE ROOM) MEETING MINUTES Present: James Hall Matanuska Electric Association (MEA Sterling Larson Matanuska Electric Association (MEASamMatthewsAlaskaElectricGeneration&Transmission (AEG&T)/HomerElectricAssoc.(HEA)Stan Sieczkowski Alaska Energy Authority (AEAAfzalH.Khan Alaska Energy Authority (AEATomLovasChugachElectricAssociation (CEAJohnCooleyChugachElectricAssociation(CEABobOrrGoldenValleyElectricAssociation(GVEA) The meeting was called to order by Vice Chairman Tom Lovas at 10:10 a.m.at theAlaskaEnergyAuthorityConferenceRoom. Bob Orr moved that the IOC adopt the March 12,1991 meeting minutes as written.Doug Hall seconded the motion.The motion was adopted unanimously. The March 12,1991 meeting agenda was modified by adding Election of OfficersunderitemII.The modified agenda was adopted unanimously. Under Election of Officers,Vice Chairman Tom Lovas requested nominations forChairmanbecauseofthevacancycreatedbyJohnCooleywhoresignedfromAML&P.Doug Hall moved that the vacated position of Chairman be filled by ViceChairman.Sam Matthews seconded the motion.The motion was passed unanimously.Tom Lovas was elected Chairman.Doug Hall nominated Bob Orr forViceChairman.Tom Lovas seconded the nomination.Sam Matthews moved that the nomination for Vice Chairman be closed.Stan Sieczkowski seconded the motion.The motion was adopted unanimously.Bob Orr was elected ViceChairman. Under Dispatch,Afzal Khan on behalf of Marvin Riddle distributed the March 26,1991 subcommittee meeting minutes with attachments.Doug Hall discussed thecontentsofthemeetingminutes. Under Protection Coordination,Afzal Khan stated that the subcommittee did not meet but discussed the PTI base case for 8/29/90 event with members of both Protection coordination and Dispatch subcommittees and received no comments.He distributed the following: 1)PTI letter,dated April 8,1991,to AEA -Railbelt Load SheddingStudyfor8/29/90 Event 2)PTI letter,dated May 3,1991,to AEA -Railbelt Load Shedding Studyfor8/29/90 Event There was a brief discussion on PTI Contract.Afzal Khan stated that there be willa joint meeting of Protection Coordination and Dispatch subcommittees for thepurposeofreviewingthePTIContractincludingRFPScopeofWork. Under Machine/Rating Subcommittee,Chairman Tom Lovas requested Doug HallgetsubcommitteemeetingminutesfromitsChairman. Under Correspondence,Stan Sieczkowski stated that he received a letter,datedApril10,1991,from MUS.designating their new _representativeCharlaneBigelowSteadonInsuranceSubcommittee. Under Intertie Status,Afzal Khan distributed the following: 1)GVEA letter,dated March 15,1991,to AEA.Reference:Icing Conditions at Goldhill Substation SVS Building 2)AEA letter,dated March 27,1991,to GVEA.Reference:Goldhill Substation SVS Building Engineering/Design 3)GVEA letter,dated April 2,1991,to AEA.Reference:Geotechnical Report for Structure #749 4)MEA letter,dated May 7,1991,to IOC.Reference:Intertie Maintenance 5)GVEA letter,dated May 7,1991,to AEA.Reference:Cost Evaluation of Corrective Measures to the Southern Portion of the Alaska Intertie 6)Commonwealth Associates,Inc.letter,dated April 4,1991,to AEA.Reference:Anchorage-Fairbanks Intertie Extreme Loading Problem 7)Commonwealth Associates,Inc.letter,dated April 29,1991,to AEA.Reference:Anchorage-Fairbanks Intertie Extreme Loading Problem Jim Hall discussed the contents of his memorandum to IOC,dated May 7,1991.HeinformedIOCmembersthatthetenspanswithtwistedbundleconductorswerestraightenedandnowintheiroriginalconfiguration. There was a brief discussion on GVEA Cost Evaluation of Corrective Measures totheSouthernPortionoftheAlaskaIntertie.IOC members agree that this taskshouldbeassignedtoReliability/Criteria subcommittee to evaluate the technicalmeritsandfeasibilityofthevariousalternatives,feasibility of the test segment andidentificationofadditionalunreviewedoptions.urthermore,engineering consideration with regard to spacer and vertical alignment. Teeland substation SVS PT problem was discussed. No visitors were present. The Operating Committee took a break from 11:35 a.m.to 11:45 a.m. The Operating Committee went into work session. Meg B91 Under Dispatch,Chairman Tom Lovas stated that each IOC member needs to work with their Production/Generation group for obtaining the necessary information onmachineoutagesand/or data.In addition,the information associated withdisturbancesneedstobeforwardedtoareacontrollers.There was a briefdiscussiononswitchingandtaggingprocedures.Doug Hall stated that the Cantwellsubstationhasnomotoroperatedgroundingswitches.Teeland,Douglas,Healy and Goldhill substations have no problems. Under Protection Coordination,Chairman Tom Lovas stated that this subcommittee is to meet jointly with Dispatch subcommittee to review PTI Contract for loadsheddingstudy.Also this subcommittee to provide recommendation to ChairmanTomLovasforreleasingdatabaseforuseonotherstudies. Under Machine/Rating,Chairman Tom Lovas stated that this subcommitteeChairmantobriefIOCatthenextmeeting. Under SVS,IOC members agree on using SVS funds to correct icing problem at theGoldhillSubstationSVSBuilding. Under Intertie FY92/93 Budget,Afzal Khan distributed the final Alaska IntertieFY92Budget.Afzal Khan stated that the preliminary Alaska Intertie FY93 BudgetwillbeavailablebythenextIOCmeeting. IOC members agree on $50,000 budget for Alaska Intertie Performance Analysis andReviewforFY93. Under T/L Structure and Conductor Evaluation,Bob Orr distributed a GVEA letter, dated May 7,1991,to AEA on cost estimate for different options to resolve theconductorgroundclearanceproblemsonthesouthernintertie.Bob Orr also statedthatIOCmemberstakethecostestimatewiththemforreviewandcomments. Under Formal Operating Committee action/recommendation,Bob Orr moved thatIOCapprove$50,000 for Intertie Operating Committee Budget for FY93.Stan Sieczkowski seconded the motion.The motion was adopted unanimously. Bob Orr moved that the SVS reserve funds be allowed for the repair of the GoldhillsubstationSVSbuilding.Tom Lovas seconded the motion.The motion was adopted unanimously. Chairman Tom Lovas recommends that the utilities update Intertie Operating Committee and its subcommittees member list. IOC recommends Protection Coordination subcommittee to release the data base developed under the Load Shedding Study for use on other studies. Under Subcommittee Assignments,Chairman Tom Lovas directed the DISPATCHsubcommitteetomeetatthediscretionofitsChairmantoworkon:DispatchTrainingPlan;and review the base case for 8/29/90 event in a joint meeting withProtectionCoordinationsubcommittee.In addition,the Dispatch subcommittee is toreviewthemaintenanceresponseandcommunicationscoordinationamongtheareautilitiesandTechnicalGuidelinesforOperation,Metering and Protective RelayingforNon-Utility Power Producers and Cogenerators and develop operating guides togowiththem. Chairman Tom Lovas directed the MACHINE/RATING subcommittee to meet at the discretion of its Chairman to continue work on machine rating book.ChairmanTomLovasalsodirectedtheSubcommitteeChairmantoattendthenextIOC meeting to brief IOC members. Chairman Tom Lovas directed the PROTECTION COORDINATION subcommittee to meet at the discretion of its Chairman to continue work on underfrequency load shedding study. Chairman Tom Lovas directed the RELIABILITY/CRITERIA subcommittee to meet at the discretion of its Chairman to evaluate the technical merits,cost calculations,feasibility of the various alternatives,feasibility of the test segment andidentificationofadditionalunreviewedoptionsforSouthernPortionoftheAlaskaIntertie.Furthermore,engineering consideration with regard to spacer and vertical alignment. THE NEXT REGULARLY SCHEDULED MEETING OF THE ALASKA INTERTIE OPERATING COMMITTEE WILL BE ON WEDNESDAY, JULY 10,1991,AT 11:00 AM.AT THE HOMER ELECTRIC ASSOCIATION BOARD ROOM,HOMER,ALASKA. The Operating Committee set the agenda for the next meeting of the OperatingCommittee. Stan Sieczkowski moved for the meeting to adjourn,seconded by Doug Hall.TheOperatingCommitteeunanimouslyadoptedthemotiontoadjournat1:45 p.m. Respectfully submitted, Stanley E.a5 Owski,SecretaryAlaskaIntertieOperatingCommittee Attachments: 1.July 10,1991 meeting agenda2.IOC May 8,1991 meeting attendance sheet The following were distributed at the May 8,1991 meeting: 3.Dispatch Subcommittee March 26,1991 meeting minutes withattachments. 4,PTI letter,dated April 8,1991,to AEA -Railbelt Load SheddingStudyfor8/29/90 Event 5.PTI letter,dated May 3,1991,to AEA -Railbelt Load Shedding Study for 8/29/90 Event 6.GVEA letter,dated March 15,1991,to AEA. Reference:Icing Conditions at Goldhill Substation SVS Building 10. 11. 12. 13. AEA letter,dated March 27,1991,to GVEA. Reference:Goldhill Substation SVS Building Engineering/Design GVEA letter,dated April 2,1991,to AEA.Reference:Geotechnical Report for Structure #749 MEA letter,dated May 7,1991,to IOC. Reference:Intertie Maintenance GVEA letter,dated May 7,1991,to AEA.Reference:Cost Evaluation of Corrective Measures to the Southern Portion of the Alaska Intertie FMUS letter,dated April 10,1991,to AEA.Reference:Intertie Operating Committee,Insurance Subcommittee Commonwealth Associates,Inc.letter,dated April 4,1991,to AEA.Reference:Anchorage-Fairbanks Intertie Extreme Loading Problem Commonwealth Associates,Inc.letter,dated April 29,1991,to AEA.Reference:Anchorage-Fairbanks Intertie Extreme Loading Problem ALASKA INTERTIE OPERATING COMMITTEE MEETING AGENDA WEDNESDAY,JULY 10,1991 BEGIN AT 11:00 A.M. I.Adoption of Prior Meeting Minutes IT.Approval/Modification of Agenda Hl.Committee Correspondence and Reports A.Dispatch SubcommitteeB.Protection Coordination Subcommittee C.Machine/Rating SubcommitteeD.Reliability/Criteria SubcommitteeE.Correspondence ReceivedF.Intertie Status Update IV.Visitors Comments Related to Items on Agenda V.Work Session A.Recess and work session ° B.DispatchC.Protection Coordination D.Machine/RatingE.Reliability/CriteriaF,SVS G. FY93 BudgetH.T/L Structure and Conductor Evaluation VI.Formal Operating Committee Action/Recommendation VIL.Subcommittee Assignments VIN.Determine Agenda for Next Meeting IX.Adjournment Meeting location: Alaska Electric Generation &Transmission,Inc. Homer Electric Association Board Room Homer,Alaska (907)235-8167 Ws rer ke s ALASKA INTERTIE.OPERATING COreTTEEMEETING In Attendance:Inte May 8,01 Nane Lonpany Phone Ho, ohn Coster,CEA 262-YS77 "1 ee Na |MLtP 263-5452 iSh rling,Larsan AEG AT TAS 9 2b4. Jie HALL AéGEd 145-4269 Soy Morrie 4AcedT 235-3307|)Syece Kush LIE Sb/-7877 Affect H khan AEA SEI-7877 Tt LOVAS (0 EA-Me2-V7V2 Bee Cee.GVEA 452-5\ Myint DISPATCH SCHEDULING SUBCOMMITTEE March 26,1991 CEA at 9:45 a.m. Attendance:Brad Evans Doug HallMarvinRiddle )}. - 1.Subcommittee recommended that the IOC declare that all pertinent backup information needs to be submitted to the Dispatch/Scheduling Subcommittee members for each utility so theexecutivesummaryandoutagereportscanbeproperlyprepared for presentation to the IOC from the subcommittee. 2.Subcommittee agreed that the chairman would prepare an executive summary of all outages that should be reported to the IOC.Thesubcommitteememberswouldthenreviewthesummaryandsubmitit to the I0C,specifically noted that if any utility took exception to the summary a utility could append the summary. Teeland coordination problems were discussed. 1.CEA stated their crews would be a contractor while working on AEA equipment. 2.Doug Hall,AMLP,presented the first draft of intertie switchingproceduresforreview.This needs to be done for allAEA/jointly operated and maintained facilities. Switching and tagging procedures were discussed in detail todeterminehowwewouldinsureclearanceonAEAequipment. Start reviewing and compiling guides for NUG (Non-Utility Owned Generators). To perform work on the intertie there is no acceptable way to clearthelineformaintenanceotherthandrivingtobothterminals.Thereneedstobemoreresearchonhowwemightdothisremotely. Subcommittee is looking at other alternatives and will developrecommendations.The recent problem with snow unloading pointed out this problem again. Oo SUMMARY OF SYSTEM DISTURBANCE April 9,1991 At 1600 hours on April 9,1991 AMLP lost Unit #8.The water regulator failed which stopped water injection and the unit trippedduetohighdifferentialtemperatures. Unit #8 had 77 MW on it at the time of the trip.GVEA had the Healy unit in service with 27 MW and FMUS had Chena 5 in service with 20 MW load. CEA had the following units in service with available unloaded spin of approximately 94 MW. Beluga 3 Bernice Lake 3 Beluga 5 International 1,3 Beluga 6,7,8 Eklutna 1 The system frequency decayed to 59.3 HZ and the following feeders were shed: CEA Total MW GVEA Total MW Jewel Lake Gold Hill Tudor 15 Chena Pump Spenard Cantwell Johnson Road 10.6 FMUS Highway Park Healy Eagan Avenue 2.5 Brockman Available on-line generation was loaded.All load was restored in the north in two minutes and in the south in 5 minutes. SUMMARY OF SYSTEM DISTURBANCE April 25,1991 At 2218 hours on April 25,1991 AMLP Unit #7 tripped.Unit #6trippedaftersteampressuredecayed.The units tripped due to anearthquakeintheAnchoragearea. The Alaska intertie was in service,but the GVEA Gold Hill to Nenana 138 KV line was out of service for scheduled maintenance. Unit #7 had 48 MW on it at the time of the trip and Unit #6 had 18 MW on it. FMUS had Chena 5 in service with 18 MW on it,GVEA had North Pole Unit #1 and Zehnder Unit #1 in service and the Fairbanks load was islanded from Anchorage at Gold Hill. The GVEA Healy unit was in service on the Anchorage system and we were supplying Anchorage 20 MW.CEA had the following units in service: Beluga 5,6,8 Bernice Lake 3,4 Eklutna 1 The Anchorage system frequency decayed to 59.2 and the following feeders were shed: AMLP Total MW CEA Total MW Sub 15 Campbell Lake Sub 12 10 Sand Lake Raspberry 25 GVEA O'Mallay Woodland Park Healy R2 Cantwell R1,R3 1 Available on-line generation was loaded.All load was restored in 5 minutes. The approximate amount of unloaded spin on the Anchorage system was 70 MW. SUMMARY OF SYSTEM DISTURBANCE March 20,1991 At 0810 hours on March 20,1991 AMLP lost Unit #7 due to unknown causes (control wire ground was suspected but not confirmed).TwominuteslaterUnit#6 tripped due to loss of steam pressure. Unit #7 had 70 MW on it,and at the time of the trip Unit #6 had 23 MW on it. GVEA had the Healy unit in service with 27 MW,FMUS had Chena 5 in service with 20 MW load. CEA had the following units in service with available unloaded spinofapproximately29MW: Beluga 1 Beluga 6,7,8 Beluga 3 Bernice Lake 2 Beluga 5 Cooper Lake Unit 1 The system frequency decayed to 59.1 HZ and the following feederswereshed: AMLP Total MW CEA Total MW Plant 1,Bkr 1130 13 Jewell Lake Sub Sub 12,Bkr 120 Spenard Sub 28 Sub 15,Fdrs 1,2,5,7,8 Boniface Sub Tudor Sub FMUS Total MW GVEA Total MW Eagan Ave 6 Gold Hill 23 Garden Island Highway Park Chena Pump Johnson Road Cantwell Dawson Steese Brockman Ester Healy International Airport Available on-line generation was.loaded and additional generation started.All load was restored in the north in 18 minutes and in the south in 36 minutes. prada s"pr POWER TECHNOLOGIES,INC.ONE SIERRAGATE PLAZA SUITE 3408 ROSEVILLE.CA 95678 916 783-3566 TELEFAX 916 783-2086 TELEX 145498 April 8,1991 RECEIVED ors Y59]& Mr.Afzal Khan Alaska Energy Authority P.O.Box 190869 Anchorage,AK 99519 Al AQWA FNERRY ANITUORITY Dear Afzal: Re:Railbelt Load Shedding Study for 8/29/90 Event We have completed the subject study which was requested by the Relay/Protection Subcommittee through AEA.The scope for this study was first outlined in the Subcommittee's letter dated November 21,1990,and was discussed and clarified at the February 27,1991 meeting. This study was based on system information originally provided in the November 21 letter, and on additional information provided at or subsequent to the February 27 meeting.The power flow base case for this study was developed and sent to the Subcommittee members on March 22 for review and comment.Comments and suggested changes were received from each of the members and were incorporated into the base case power flow model. Governor response and machine output limits were critical to this study.Thus,the dynamics data for the governor on each of the on-line Railbelt machines was reviewed and adjusted so that machine output capability in the model agreed with the output limits specified for the 8/29/90 condition.Through the course of this work,and work being done by Lou Hannett on the re-write of the Kenai machine test report,we observed that the governor data for the AMLP #5 unit produced unstable (oscillatory)results in the on-line mode.Governor data for this unit was modified.Lou shculd be sending you data revisions for the AMLP #5 governor. Also,it should be noted that this cese utilized the AMLP #3 unit.This unit was not tested as part of the Railbelt machi::e testing program.Thus,it is represented by only the simplified GAST governor model.However,based on model comparisons I did for the Kenai units (and which I reported to you in a letter dated December 13,1989),I modified the simplified GAST model data for the AMLP #3 governor to match the simplified model data previously derived for Bernice Lake unit #4.Thus,I feel that the simplified GAST model for AMLP #3,as implemented in this study,provides a reasonable representation of this unit. N\oo Page 2 Mr.Afzal Khan April 8,1991 With the base case power flow and dynamics data for the system developed,we ran the dynamic simulations proposed by the Relay/Protection Subcommittee.All simulations assumed the sudden loss of Beluga #7 (CT unit of combined cycle plant)with the gradual output reduction of Beluga #8 (steam unit of combined cycle plant).However,we did not represent any AGC action on governor set points during these simulations.After some initial consideration of how to implement such action in the model,we determined that this would be quite complicated to implement,and would have consumed more time and budget than was available for this study. All dynamic simulations were run for 60 seconds,and the Beluga #7 loss was modeled as occurring at t =0 seconds.Ix a!l cases,separation of Eielson AFB was allowed to occur @ 59.8 Hz with 18 cycle delay.This was deemed appropriate even in cases where underfrequency load shedding was disabled.Eielson is set to separate at a frequency well above other load shed frequencies used on the system.Thus,this separation is essentially independent of whether or not other load shedding actions occur. The dynamic simulation cases are discussed below.Frequency and turbine mechanical power output plots for each case are attached. CASE 1A The intent of this case was to duplicate the sequence of events which actually occurred on 8/29/90.This simulation came close,but it did not completely duplicate all load shedding events.Only the GVEA/FMUS and CEA load was shed in this simulation.In this simulation,the system frequency dropped to about 59.5 Hz within 2-seconds,recovered slightly due to governor action,and then declined to a minimum of about 59.29 Hz,13 seconds after the generation 'oss.The minimum system frequency observed in this simulation is only 0.09 Hz above the point at which the AMLP load shed relays are set to pick up.Thus in this simulation,the AMLP load did not shed.However,after the GVEA/FMUS and CEA loads shed at about 13 seconds,the frequency recovered to about 59.75 Hz. CASE 1AX This was a supplemental case set up to duplicate all load shedding which occurred during the actual event.Per discussions with the Railbelt utilities,it was indicated that the potential exists for the AMLP load shed relays to pick up at frequencies slightly above their intended pick up point.Thus,this case was run with the frequency pick up on the AMLP relays set at 59.28 Hz instead of 59.20 Hz.The GVEA/FMUS load shed relays were also set to pick up at 59.28 Hz instead of 59.30 Hz.With these slight changes,this case duplicated all load N\po Page 3 Mr.Afzal Khan April 8,1991 shedding actions which actuaily cccurred.In this case,the frequency profile is nearly the same as for Case 1A,but it reccvered to about 59.9 Hz after all load was shed. CASE 1B This case is a "what if"scenario intended to identify how low the system frequency would have dropped if load shedding had not occurred during the actual event.It can be observed from this case that 60-seconds after the loss of Beluga #7,the frequency is around 58.65 Hz and still slowly declining. CASE 1C In this "what if"scenario,the only load shedding allowed to occur was GVEA/FMUS load which would need to be shed in lieu of having actual spinning reserve.This amounted to dropping 14 MW of GVEA/FMUS load 2-seconds after the frequency reached 59.7 Hz.This load shedding coupled with the 5.2 MW of actual spin on the GVEA/FMUS systems kept the frequency from dropping below £9.5 Hz.After the load was shed,the frequency recovered to around 59.75 Hz. CASE 2A This is a variation of the 8/29/90 condition which assumes the GVEA/FMUS area is carrying its entire load by utilizing both North Pole units,and has sufficient on-line capacity to meet its spinning reserve obligation.No underfrequency load shedding is assumed in this case. Following loss of Beluga #7,the system frequency in this case drops to about 59.42 Hz and then recovers to around 59.7 Hz.However,the frequency response for this case,particularly within the first 2-seconds,is suspect.It may not be representative of what would actually happen.During this time,the mechanical power output of North Pole #1 drops significantly, thus compounding the frequency decay problem.Such response is uncharacteristic of a combustion turbine.We will need to review this situation further to determine whether the governor data is incorrect or whether there could be a tuning problem in the actual governor controls. CASE 2B This case,as with Case 2A,represents the GVEA/FMUS area carrying its entire load by utilizing North Pole #1,Zender #1 and Chena #5 all operating at their maximum output levels attainable under the 8/29/90 condition.This leaves the north-end without any actual spinning reserve.Following loss of Beluga #7,the system frequency in this case drops to about 59.33 Hz and then recovers to around 59.8 Hz after 29.1 MW of load is shed in lieu of spinning reserve in the GVEA/FMUS system.However,as with Case 2A,the frequency response for this case is suspect due to the response of the North Pole #1 unit. L\ Page 4 Mr.Afzal Khan April 8,1991 CASE 3A This case is a second variation of the 8/29/90 condition which has only Zender #1 and Chena #5 on-line (similar to the actual condition),but both units are at their full rated output level leaving the north-end system without actual spinning reserve.The GVEA/FMUS load is scaled in this case such that the north-end loads are fully covered by internal generation. Following the loss of Beluga #7,the system frequency dips to around 59.45 Hz.Following 19.2 MW of load shedding in lieu of spinning reserve on the GVEA/FMUS system,the frequency recovers to around 59.7 Hz. CASE 3B This case is a "what if”variation of Case 3A,but no load shedding is assumed to occur on the Railbelt system.This case was intended to identify how low the system frequency would drop assuming the GVEA/FMUS system carried no spinning reserves and performed no load shedding in lieu of spin.Following the loss of Beluga #7,the frequency drops to about 59.45 Hz,recovers to about 59.6 Hz due to governor action,and then declines to a nearly steady-state value near 58.9 Ez,60-seconds after loss of the Beluga unit.One thing interesting to note in this case is that the Zender unit (even though it is initially at its base rating)provides momentary governor action until the exhaust gas temperature limiting controls return the unit to its base rating level. Observations . We have compared the frequency results (magnitude)from Cases 1A and 1AX against a frequency strip chart recording provided by AMLP.Both the simulations and the strip chart recorder show a minimum system frequency of near 59.3 Hz.After the occurrence of underfrequency load shedding,both our simulations and the strip chart recorder show the frequency recovering to the 59.7 to 59.8 Hz range.Thus,the simulation results compare quite favorably with what was recorded during the actual event.This is one measure which indicates that our model is representative of the Railbelt system's actual response. However,due to the time scale vsed on the strip chart,we are not able to completely confirm whether or not our model represents the actual frequency response on a time/event basis within the first several seconds after the trip of Beluga #7.However,we can observe from the frequency strip chart that the system frequency stayed at or below 59.5 Hz for about 4.5 seconds.This compares to 5.5 seconds as observed in Case 1A and 5.1 seconds as observed in Case 1AX.This tends to indicate that our model is likewise representative of the Railbelt system's actual response from a time/event basis.However,to completely confirm our model against the actual system response,we would need DSM recordings of the disturbance which could precisely show the system response and capture all of the events which occurred. --\v 0 Page 5Mr.Afzal Khan April 8,1991 Assuming that our model does faithfully represent the response of the Railbelt system for the date and time under study,we can draw the following conclusions: 1) 2) 3) 5) From Case 1B,it is apparent that load shedding is important in arresting system frequency decay.Without load shedding,however,it does not appear that the system would have been in immediate jeopardy of losing generators due to underfrequency tripping. Also from Case 1B,it ap;ears that the first stage of load shedding could have been set to occur somewhere belo's %9.3 Hz without detrimental effect on the system. From Case 1C,2-second load shedding in lieu of spinning reserve in the GVEA/FMUS area would have been very effective in arresting system frequency decay and minimizing load shedding elsewhere in the system. Comparing Case 1's,it is apparent that governor response is the most important factor in arresting the initial frequency drop.It also appears that there is sufficient window of time in which to shed load in lieu of carrying spinning reserve.However, if there were no or very little spinning reserve anywhere on the system,this same observation might not be true. Comparing Case 1C (27%actual GVEA/FMUS spin &balance of spin requirement met by load shed),Case 2A (00%of GVEA/FMUS requirement in actual spin)and Case 3A (all of GVEA/FMUS sp:requirement met by load shed),load shedding in lieu of actual spinning reserve "nthe GVEA/FMUS compares favorably with having actual spinning reserve.All of these cases show a frequency performance advantage over what occurred during the actual event. --__"\pr 0)Page 6Mr.Afzal Khan April 8,1991 After you and the Relay/Protection Subcommittee members have had a chance to review these study results,please advise if you have any questions.Also,please advise if you would like me to run any additional cases for this study. Sincerely, John H.Doudna,P.E. Senior Engineer JHD: 0 Enclosure cc:Dave Burlingame -CEA Larry Hembree -AMLP Steve Haagenson -GVEA RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS. TRIP BELUGA #7 @ T=0.0 &COAST DOWN OF BELUGA #8. UNDERFREQUENCY LOAD SHED ON GVEA &CEA SYSTEM. FILE:CASE-1A.CHN |ZENDER 69KV_FREQUENCY (HZ)160.0000 0 mn 59.000 | BELUGA _138KV FREQUENCY (HZ) [60.000 _-=59.000| |AMLP_230KV FREQUENCY (HZ)[60.000 --59.000 | ||if 1 |||3 r<) iSa [-J 3 ="le : c-J Qo =oale ” c=] = 3 7s OI) 3 o _se a o |||io 30.00042.000TIME16.0006.0000357APR02199119SYSTEMFREQUENCIESTUE,RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS. TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA #8. UNDERFREQUENCY LOAD SHED ON GVEA &CEA SYSTEM. FILE:CASE-1A.CHN |AMLP #8 MECH POWER (PU)j [1.0000 ieee 0 | AMLP ¢5 MECH POWER (PU)| [1.0000 _-_1 AMLP $3 MECH POWER (PU)J [1.0000 ----_-*| ||||} =4 -= |1 ||l 48.00036.00024.00012.00030.00042.00054.000TIME16.0006.000019:57AMLPTURBINEPOWERSAPR021991TUE, RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS. TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA 48.2 UNDERFREQUENCY LOAD SHED ON GVEA &CEA SYSTEM.bo FILE:CASE-1A.CHN a an an ton N Qo BELUGA $8 MECH POWER (PU)|[1.0000 --+0.0 |8|BELUGA §5 MECH POWER (PU)][1.0000 eon e 0.0 |aBELUGA$3 MECH POWER (PU)J}ze[1.3000 -----*0.30000| BELUGA ¢1 MECH POWER (PU)J{1.0000 »-----_*#0.0 | 1 L igrtjrTTTT_T 3't 3|;gL_:-_]2° t |]a t '! |'8 _-i2i]e|t : 4 't j '3 l 1 t[] :|: ='t 45|'” 'd'|i 3L4!--]2 '|a '! 't io '|1 3|!4:'|{we t '! o |'\t _3L)* '\- $1 ,]1 3__4 oO o -eecor7”/|s %4 | \-3=Ly i]-_be1- .7 J ae{|--=-b -!J !|1 i BELUGATURBINEPOWERSTIMERAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS. wo TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA #8.2 UNDERFREQUENCY LOAD SHED ON GVEA &CEA SYSTEM.a FILE:CASE-1A.CHN - in an So| N oOo ZENDER $1 MECH POWER (PU)]os41.0000 -"---0.0 |oyCHENA$5 MECH POWER (PU)! f1.0000 _-_<2<---ry 0.0 |. BERNICE $4 MECH POWER (PU)!B].1.0000 ---¢«0.0| BERNICE $3 MECH POWER (PU)J 11.0000 o-_4 0.0 | |t|{{||||3 1!g it g ty 713 ry a ,_B ':' 1sfy 3 Z i 4:?v t'{ly 2'°oe {'4stt ' 't '$seo _t 4 $ 'I °!\_|2 -* \ }F|/ezy{!4 "|8 ';,L_at an'fu " ny 8aso Haan 42 Pa ' ”' =' 4- -}:=-.°|!|!g KENAI&FAIRTURBINEPOWETIME RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS. TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA #8. UNDERFREQUENCY LOAD SHED ON GVEA,CEA &AMLP SYSTEM. FILE:CASE-1AX.CHN ZENDER 69KV_FREQUENCY (HZ)¥60.000 0 SR SS Se 59.000 | BELUGA _138KV_FREQUENCY (HZ)|60.000 _-59.000| I AMLP_230XV_FREQUENCY {HZ)J |60.000 4 59.000 | ||||||{1 3 Qo is 2 °eo°o -43 ioE =3 o 8 =ls : 3 So _-le * -Joer ) ="loa EI Qo -"i o 8 |-« wt io o 1 ae B} c-Jcs o eo =- l w i e 24313FRI,APR051991SYSTEMFREQUENCIESTIMERAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS. TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA #8. UNDERFREQUENCY LOAD SHED ON GVEA,CEA &AMLP SYSTEM. FILE:CASE-1AX.CHN AMLP $8 MECH POWER (PU)| [i 0000 ertslee AMLP $5 MECH POWER (PU) {1.0000 =-_= AMLP $3 MECH POWER (PU)J }1.0000 ----a | er\!acae”A60.00012.00024,00036.00048.00018.00030,00042,00054.000TIME6.000034313FRI,APR051991AMLPTURBINEPOWERS RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS. TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA #8. UNDERFREQUENCY LOAD SHED ON GVEA,CEA &AMLP SYSTEM. FILE:CASE-1AX.CHN |BELUGA $8 MECH POWER (PU)| 11.0000 .SS SF 0.0| .BELUGA $5 MECH POWER (PU)J [1.0000 ene -=---e 0.0 | |BELUGA $3 MECH POWER (PU)| 11.3000 ---€0.30000| |BELUGA {1 MECH POWER (PU)| }1.0000 -_---o 0.0 | v r ioror|j |||l |'|3 '{3 I |;_-1 ' - \|i]t1|!g =42 l f : ; '-_ 1 i | t 3 ='"T13' '| ' '|L_$4 |t g?ro|'|+:' '{ U z=') _ \i :]8ee/-s %a" \- a \_ 1 \4 Pe{oes l |¢30.00042.00054.000TIME18.0006.000013:43APR051991BELUGATURBINEPOWERSFRI,RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS. = TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA #8.acs UNDERFREQUENCY LOAD SHED ON GVEA,CEA &AMLP SYSTEM.re) FILE:CASE-1AX.CHN Ay |N.POLE ¢2 MECH POWER (PU)Joa [1.0000 roe ->7o|=|N.POLE g}MECH POWER (PU)!"FA[1.0000 Morr ts x .0 |a 9|ZENDER #1 MECH POWER (PU)l [1.0000 ----0 |oy|CHENA $5 MECH POWER (PU)ad [1.0000 iat 'Ol or {BERNICE $4 MECH POWER (PU)|GH ]1.0000 ----<70 |ro |BERNICE $3 MECH POWER (PU)|sal 11.0000 --_---_*#0 |wseeOego i 3 & !aE+?&\5M | oO|3 {"Ts t '3 I a id t '3 t oo !mm t e !3 !18 =& \3'ai (o ¢8 4 1s 3 °ooonfeCoal Qoo o o con RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS. aw TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA §8..f] NO UNDERFREQUENCY LOAD SHED IN RAILBELT SYSTEM.2H FILE:CASE-1B.CHN 3omfl"8 wvooaifxs|ZENDER 69KV FREQUENCY (HZ)b>}[60.0000 °°=----SS e 59.000|5 py BELUGA _138KV FREQUENCY {H2)|;ae[0.000 -=-<59.000 |2|AMLP_230RV_FREQUENCY (HZ)]n[60.000 o----__4 59.000 | I |||||||3 3 3 =-S 3 3 io ooeo =ts c-J 3 =le nm Lo gy8Hu 8 +e bo} 3o e we enh |} RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS. o (dp)TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA #8.are NO UNDERFREQUENCY LOAD SHED IN RAILBELT SYSTEM.©f:) FILE:CASE 1B.CHN = «aOomAuin te)2xH82|AMLP $6 MECH POWER (PU)J i=)[1.0000 -----ST 71 B EaAMLP$5 MECH POWER (PU)J «waJ1.0000 _-=o|psAMLP_$3 MECH POWER (PU)| 1.0000 _----*#0 |4 rp td T ]|T g 'gt14 3 =i 4:)of ° e ''oo 8{@ _H -. !3 ry}oa g°ot)-_A- '¢/' t oY 3 =i <61!” 1 Io:g =s 42 eii: 1 iJ I '3L.ssota”'s _'oS of '4:' '3 ='meHys ' o,8 °o |-. !!![J S RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS. sw TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA #86.°m % NO UNDERFREQUENCY LOAD SHED IN RAILBELT SYSTEM.2 (2) FILE:CASE-1B.CHN = aO4Gu ot2B BELUGA $8 MECH POWER (PU)]4 H(1.0000 SSS 0.0 |a9BELUGA_§5 MECH POWER (PU)511.0000 meen een °0.0 |°)&BELUGA $3 MECH POWER (PU)J {1.3000 TT 0.30000}sBELUGA$1 MECH POWER (PU)511.0000 ----*0.0 |re'TT +g!|||\q J |3 t io ' a '3 '4 ¢ t mn t ' '8 '°o '"le ': 4 1 2 !8 ': ' i] L]9 '3 'le 1 om ' [] z412?'ae) 'e 4 1 lo 'EY 'is t oe t ' t 3 t i? s t $ °o Ts t-J3 °o 4s. !|3 RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS. oa icaTRIPBELUGA#7 @ T=0.0 €COAST-DOWN OF BELUGA #8.ae NO UNDERFREQUENCY LOAD SHED IN RAILBELT SYSTEM.ae) FILE:CASE-1B.CHN ay t N.POLE ¢2 MECH POWER (PU))a [1.0000 ----->oo}&3|N.POLE #1 MECH POWER {PU}17°G[1.0000 Meee x 0.0]z=oy|ZENDER ¢1 MECH POWER (PU)tie[1.0000 ---S 0.0}a|CHENA $5 MECH POWER (PU)} }1.0000 @---+H °00]Sa|BERNICE $4 MECH POWER (PU)|&H[1.0000 as 0.64 «f I BERNICE ¢3 MECH POWER (PU)5 ha [1.0000 4 0.0 |a I re ee ee |BL,Ss «3 2 _4° 3 MG leL.-e Aa c-J3 As °o 3"1 gw43é& t-J8 x F 36 rt Fy -{: a So8 c=) -1< J I i |& 0 RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS. 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' i] 13 _B=':4 L}1s 3 _ry 4é1; 1}:1 ° |'2 NN|' |!3i] '-j 2=': a Lt 2 -'5 71s 4 4 3 3 | »s ueSe[- -$--,J !I |:222APR03199116WED,AMLPTURBINEPOWERSTIME RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS,BUT WITH CEA-GVEA TIE FLOW ZEROED.2-NORTH POLE UNITS ON.NwTRIPBELUGA#7 @ T=0.0 &COAST-DOWN OF BELUGA #8.- NO UNDERFREQUENCY LOAD SHED IN RAILBELT SYSTEM.% FILE:CASE-2A.CHN = aain Coe)oF BELUGA §8 MECH POWER (PU)Jetfi.0000 TSF 0.0 |a 2}BELUGA ¢5 MECH POWER (PU)i 5}1.0000 eee °00]gk BELUGA _¢3 MECH POWER (PU)|&J1-3000 ===T79.30000|gBELUGA#1 MECH POWER (PU)!511.0000 --s4 0.0 |Mia0Agfa \ '3i][-94|!3Lo !4% 1 | ,i] '|!s 4 eo t |t ° '\'|3__-f]_x1' - '| :t '|!3-'i - s H 2Ii é ”{ar-+ss i]t Qu '}t ad t '' |'C '_2 1 |t x i 'i] pt |: t "ls t ||a ry '§3 ='|ii]|ie i }1 ° é !3a|° Le t"es:| --k .|l LN |l eS RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS,BUT WITH CEA GVEA TIE FLOW ZEROED.2-NORTH POLE UNITS ON.X 1TRIPBELUGA#7 @ T=0.0 &COAST-DOWN OF BELUGA #8.iS NO UNDERFREQUENCY LOAD SHED IN RAILBELT SYSTEM.ba oOFILE:CASE-2A.CHN Oy N.POLE $2 MECH POWER (PU){= [1.0000 wes ee >oof &aNM.POLE #1 MECH POWER (PU){"&11.0000 Mrs x 0.0 |2 9ZENDER$1 MECH POWER (PU){.[1.0000 St 0.0 |aCHENA_§S MECH POWER (PU)| |1.0000 ener aeen °ool a|BERNICE $4 MECH POWER (PU)J BH[1.0000 ----0.0 |aBERNICE$3 MECH POWER (PU)J |1.0000 ---«4 0.0 |aw p 3||}"|Pov ||||3 M4t].1 2 4 e .,"g A =';'+" '.'a MG '.''2 3 '._{eL_'':i].' 4 :: t .N ':.3 -':'783 ':' ..°'.4 E} -'':13: '. . '.'8 =ry :'é2 g'.'a B'.. t .' >'.: ';'8-'::mt i .a 4 .. 'by t 3'''_j @L_'::i], . ¢:' '.ry 3 _'.'_r t ..q sg t .e t .. I ''3i].° |1 :42 '' i : '. il [+----b !:0 -- RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS,BUT WITH CEA-GVEA TIE FLOW ZEROED.NORTH POLE #1 &ZENDER #1 ON. TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA #8. GVEA LOAD SHED IN LIEU OF SPIN @ 59.7HZ +2 SECONDS. FILE:CASE-2B.CHN |ZENDER 69KV FREQUENCY (H2)| 160.0000 EE ESR °59.000 | |BELUGA 138KV FREQUENCY (HZ) [60.000 -_--59.000 | |AMLP_230KV FREQUENCY (HZ)|60.000 ------_*59.000 | {|if |||i 1 3 3 o8 4 3 io o r-) ="le 7 3 ="a vr oo Qo =-. "” 3 oL_-s n” io 8L_cenFdtI °ooee ="i <« ot 3 io|_io[Ia Sscr]°o o =om !|3 Lun"Bl ans aga o "1D«2a[rya>}pidaaa > nw Sy H is] RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS,BUT WITH CEA-GVEA TIE FLOW ZEROED.NORTH POLE #1 &ZENDER #1 ON. TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA #8. GVEA LOAD SHED IN LIEU OF SPIN @ 59.7HZ +2 SECONDS. 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'|!3=1 i]7s 't !|I ='- L] 1 4 t c-J 'l 3{>--'"1s i)to !1 '|! |t Fi -' ');3 4s'Pp | '{;t \_.,S J -_ tx a|>-F -_|!i 3 08:07APR041991BELUGATURBINEPOWERSTHU,18.00030.00042.000TIME6.0000RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS,BUT WITH CEA-GVEA TIE FLOW ZEROED.NORTH POLE #1 &ZENDER #1 ON.5TRIPBELUGA#7 @ T=0.0 &COAST-DOWN OF BELUGA #8.m GVEA LOAD SHED IN LIEU OF SPIN @ 59.7HZ +2 SECONDS.2 FILE:CASE-2B.CHN |N.POLE ¢2 MECH POWER (PU) :s72-0000,mn - 3 I N.POLE #1 MECH POWER (PU)|ba[1.0000 Wor ee x =|ZENDER $1 MECH POWER (PU){2.[1.0000 ------+1 ay|CHENA $5 MECH POWER (PU)| [1.0000 +-------r)1s |BERNICE $4 MECH POWER (PU){2 [1.0000 aS T 1 |BERNICE $3 MECH POWER (PU) [1.0000 -_----s |il |+I |||3 1!'3i].gti'_&-mt :5 Vy : t H x g r-}':7s'e 4 ' z ba :4 3aH:g (.'i]fyIo.3'.3° =1}:=)\x ':t '.3 =)4 .4s 8'.aHlo'H ry :° 1!'_|8T ti ;' ry : i *3=1 ;4 3 1 : ry e ]'.c=] iy :iS =':7 8 '' f 1 id o )!:3 t .-_]2-yt 'ry st . --{' Ln t-- -}t-.|I I 2 KENAI&FAIRTURBINEPOWE CONDITIONS FOR 08/29/90 @ 1300 HRS;WITH GVEA &FMUS LOAD SCALED &TIE ZEROED.CHENA #5 &ZENDER #1 ON FULL. 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Pad 'i-J'|'3H's \|i 1 !4 = '/j s'"Ts1|!' \|I 3 t }i "183 H ! 3 +'3H"TNsi ' a Y g t - |l « '|t " +\1 '{3H|J x '1' 1 |{3 -''4:_a \asae|Fp-kf J l Ne I |g BELUGATURBINEPOWERSTIMECONDITIONS FOR 08/29/90 @ 1300 HRS;WITH GVEA &FMUS LOAD SCALED &TIE ZEROED.CHENA #5 &ZENDER #1 ON FULL.=TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA #8.- GVEA LOAD SHED IN LIEU OF SPIN @ 59.7HZ +2 SECONDS.ba FILE:CASE 3A.CHN NK.POLE ¢2 MECH POWER (PU)Joa 72.0000 0 es ->oof & H.POLE ¢1 MECH POWER (PU){o- 92.0000 rw x 0.0 |=|ZENDER $1 MECH POWER (PU)f 211.0000 =F 0.01 eyCHENA$5 MECH POWER (PU)| 11.0000 [ieee e 0.0 |8|BERNICE $4 MECH POWER (PU)J]6 |1.0000 --<0.0 | |BERNICE $3 MECH POWER (PU)J [1.0000 4 0.0 | |mi ||||{||3 is -' = !r]4 <¢|'vy '}q tt 3 -}'"TI' 144t'37ryby a']'s ry _£8|.'3I'4 {!'3 =14 4¢Iu i1,3tt8 7 1 a Vy vt 3 ='4 °$i s Mybu 2i!tiL_1 - Vi a thi ° 5!3 '8-fou "- a”i] ”i) i rl eo---}/..,1 |J |J ||KENAI&FAIRTURBINEPOWETIME - CONDITIONS FOR 08/29/90 @ 1300 HRS;WITH GVEA &FMUS LOAD SCALED &TIE ZEROED.CHENA #5 &ZENDER #1 ON FULL. 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FILE:CASE-3B.CHN {ZENDER 69KV FREQUENCY (HZ)08:28[60.000 BELUGA 136KV_FREQUENCY (HZ) 59.000 |THU,160.000 AMLP 230KV_FREQUENCY (HZ) 59.000 |APR041991SYSTEMFREQUENCIES[60.000 59.000 | ||||||]|]12.00024.00836.00048.00060.0018.00630.00042.00054.000TIME6.0000CONDITIONS FOR 06/29/90 @ 1300 HRS;WITH GVEA &FMUS LOAD SCALED &TIE ZEROED.CHENA #5 &ZENDER #1 ON FULL.2TRIPBELUGA#7 @ T=0.0 &COAST-DOWN OF BELUGA #8.v NO UNDERFREQUENCY LOAD SHED IN RAILBELT SYSTEM.2 FILE:CASE-3B.CHN om in a et wv oO aAMLP$8 MECH POWER (PU)J [1.0000 SS STSry 71 $ |AMLP 95 MECH POWER {PU)) [1.0000 ---4 0] I AMLP $3 MECH POWER (PU)j [1.0000 _----4 .o] a 6'9 'wa 1 4 3L_'4 é 1}° ' '|3 3 ='2 lo ° ry '}3 g ='_s14 4 oO|3 3 :a|' i] 4fo 8_-¢-_s{i' '3|H i |!ss 'nn /t '--i)3 4N\}.\'8 1 °o ='42 oo”" \i :\8 -'1. ?\ 43 °l Low b--,l J !¢AMLPTURBINEPOWERSTIME CONDITIONS FOR 08/29/90 @ 1300 HRS;WITH GVEA &FMUS LOAD SCALED &TIE ZEROED.CHENA #5 &ZENDER #1 ON FULL. TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA #8. NO UNDERFREQUENCY LOAD SHED IN RAILBELT SYSTEM. FILE:CASE-3B.CHN BELUGA §¢8 MECH POWER (PU)][1.0000 ---_--+0.0] |BELUGA $5 MECH POWER (PU)J 11.0000 mmmeo 0.0 | BELUGA #3 MECH POWER (PU)_| [1.3000 ---4 0.30000|} BELUGA §]MECH POWER (PU)| }1.0000 oo 0.0 | 1 M 3aa '\3 L-'j \ \_ 1 | i]|]i]z '|'3 '_|°i]oe 1 }t . '| ! =;_ ft 'h t LJ '|I 3='\2'w '||” ' t l t L ;= t]j |4 t io |'!I _}8 i < '|\ 't1 t ! ='}-_ S '| "77 d |3_\7 \"Ts'7 ']I ' 1 | =.i](.7 \|',7 J Fey ek.|L |J |¢2808BELUGATURBINEPOWERSTHU,30.00042.000TIME18.0006.0000APR041991CONDITIONS FOR 08/29/90 @ 1300 HRS;WITH GVEA &FMUS LOAD SCALED &TIE ZEROED.CHENA #5 &ZENDER #1 ON FULL.2 es]TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA #8. S NO UNDERFREQUENCY LOAD SHED IN RAILBELT SYSTEM.20 FILE:CASE-3B.CHN Ay |N,POLE $2 MECH POWER (PU)_|oa [1.00000 es =>0.0}&8|NW,POLE 1 MECH POWER (PU)}"412.0000 00 Be x 0.0 |bt 9|ZENDER @]MECH POWER (PU)] [1.0000 ==a =F rare |§2|CHENA ¢5 MECH POWER (PU)[2.0000 00 mm mmm e 0.0 |p 0|BERNICE¢4 MECH POWER (PU)Jae [1.0000 =<0.0 |G|BERNICE $3 MECH POWER (PU)i] 1.0000 4 0.0 |a 0 '3 « '3 aufx]L_'+éh5 MG tLH °"_B_i : i i °if 3 -'"lai]»7 1 I"3 =iH Te !_ 1 (] tJ =Ps 2g 'gw le H 4i 3L_i 7si] i!t "i 3 =1 4s!i]4 fe g"'Ss |ai|'tr 2 a im 8 '"=,!' o tiian1 So --}-.||!t |||; CONDITIONS FOR 08/29/90 @ 1300 HRS;WITH GVEA &FMUS LOAD SCALED &TIE ZEROED.CHENA #5 &ZENDER #1 ON FULL. TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA #8. NO UNDERFREQUENCY LOAD SHED IN RAILBELT SYSTEM. FILE:CASE-3B.CHN ZENDER 69KV_FREQUENCY (HZ) 60.000 Omennmmnnan ©58.000 BELUGA 138KV FREQUENCY (HZ) 60.000 -----58.000 AMLP 230KV FREQUENCY (HZ) 60.000 ee 58.000 L 4 ? 4 60.00048.00036.00024.00012.000008:4530.00042.00054.000TIME18.0006.0000THU,APR041991SYSTEMFREQUENCIES - Sn al 26. ---\r POWER TECHNOLOGES,INC.ONE SIERRAGATE PLAZA SUITE 3408 ROSEVILLE.CA 95678 0 916 783-3566 TELEFAX 916 783-2086 TELEX 145498 May 3,1991 cone c |VV F D 3 i991 Ajass4 mie.oy muindoritydeererMr.Afzal Khan Alaska Energy Authority P.O.Box 190869 Anchorage,AK 99519 Dear Afzal: Re:Railbelt Load Shedding Study for 8/29/90 Event The subject study was summarized and reported to you and the Relay/Protection Subcommittee members in my April 8,1991 letter report.In that letter report,I noted that 0 the Railbelt frequency response for Case 2A and Case 2B was suspect due to the unexpectedanduncharacteristicresponseoftheNorthPole#1 unit.I have performed some further investigation of the North Pole unit response for these two cases.This letter summarizes the findings of that investigation. The CT model used to represent the Railbelt CTs (as presently written)has to be initialized for each dynamic simulation with the proper constants.These constants include a temperature constant which corresponds to the exhaust gas temperature of each CT when operating at its base rating under the ISO conditions for which each unit is designed.This is necessary to establish the proper state conditions for the exhaust gas temperature in each simulation. For dynamic simulations representing the CTs under ISO conditions,the simulation can proceed after the initialization process with no modifications.However,in setting up the dynamic simulations for the 8/29/90 system condition,it was necessary to alter the reference temperature variable in the model used to represent the North Pole and other Railbelt CTs. This is necessary to establish the proper reference temperature (and thus base rating output) which should apply for each CT for the assumed ambient temperature conditions being represented. Under most situations where a CT's exhaust temperature is sufficiently below its desired temperature limit,resetting the reference temperature variable after initialization is transparent in the model.However,if the CT's exhaust temperature is near the desired RRRAAR ATE RAPER 2 400 OIE AAI EAM 2 ON BAY ance 2 COUCKNECTAMW AIV 199N1-1NEA @ 61%T4199 ---"\p-- O Page 2Mr.Afzal Khan May 3,1991 reference temperature,setting the new reference temperature causes the exhaust gas temperature limiting logic in the model to respond momentarily and affect the CT output. This was the case for the North Pole #1 unit when it was represented in the simulations. The reference temperature variable was changed after initialization,but a few cycles before the disturbance.Thus the dip in North Pole #1 output which occurred after application of the disturbance was the result of the model alteration,not suspect machine data.However, it appears that no other CTs were affected by the anomaly. To circumvent this problem,I reran Case 2A and Case 2B using a modified approach.The results are shown in the attached dynamic simulation plots labeled as Case 2AX and Case 2BX.In the modified approach,the cases were initialized and the reference temperature variables modified as before,but the simulations were allowed to run for 10 seconds before the system disturbance was applied.This allowed time for the perturbation caused by resetting the reference temperature on the North Pole unit to settle out before the system ro)was subjected to the disturbance.Thus,the attached plots should replace the plots for Case 2A and Case 2B.They are otherwise identical except for the fact that the time scale for the new plots runs from 10 to 70 seconds (i.e.,60 seconds following the disturbance applied at t =10 seconds).The new cases are summarized below. CASE 2AX This is a variation of the 8/29/90 condition which assumes the GVEA/FMUS area is carrying its entire load by utilizing both North Pole units,and has sufficient on-line capacity to meet its spinning reserve obligation.No underfrequency load shedding is assumed in this case. Following loss of Beluga #7,the system frequency in this case drops to about 59.57 Hz and then recovers to around 59.7 Hz. CASE 2BX This case,as with Case 2AX,represents the GVEA/FMUS area carrying its entire load by utilizing North Pole #1,Zender #1 and Chena #5 all operating at their maximum output levels attainable under the 8/29/90 condition.This leaves the north-end without any actual spinning reserve.Following loss of Beluga #7,the system frequency in this case drops to about 59.49 Hz and then recovers to around 59.8 Hz after 29.1 MW of load is shed in lieu of oO spinning reserve in the GVEA/FMUS system. --"\pr O Page 3Mr.Afzal Khan May 3,1991 Observations The revised cases do not substantially change the observations drawn in the previous letter report.Case 1C (27%actual GVEA/FMUS spin &balance of spin requirement met by load shed),Case 2AX (100%of GVEA/FMUS requirement in actual spin)and Case 3A (all of GVEA/FMUS spin requirement met by load shed),still compare favorably.The case where the GVEA/FMUS system has 100%actual spinning reserve now shows a slightly improved (0.3-0.8 Hz)first-swing minimum frequency compared to when load shedding (either partially or completely)is substituted. In all cases,however,load shedding in other portions of the Railbelt system is avoided.Thus, for the conditions studied,the presence or absence of actual spinning reserve in the GVEA/FMUS system appears to has no significant impact.However,this may not be the case if the amount of actual spinning reserve elsewhere in the Railbelt system is at the bare minimum level required. ©)After you and the Relay/Protection Subcommittee members have had a chance to review these new study results,please advise if you have any questions. Sincerely, Bud. John H.Doudna,P.E. Senior Engineer JHD: Enclosure ce:Dave Burlingame -CEA Larry Hembree -AMLP Steve Haagenson -GVEA RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS,BUT WITH CEA-GVEA TIE FLOW ZEROED.2-NORTH POLE UNITS ON. TRIP BELUGA #7 @ T-0.0 &COAST- DOWN OF BELUGA #8. NO UNDERFREQUENCY LOAD SHED IN RAILBELT SYSTEM. FILE:CASE-2AX.CHN ZENDER 69KV_FREQUENCY (HZ)(60.0000 0°;==QE SSS 59.000 | BELUGA_138KV_FREQUENCY (HZ){60.000 -59.000| AMLP _230KV FREQUENCY {Hz)]160.000 ----2 59.000 | ]]|J |3 o 2 o Qo =-_]2° 3 o i=] -2 2 w 3 o--"le wn io oO -=le : i-J o o =_|2o $ Qo 3=>. Dal °o o -see os] 3 +Scomm[1ro) 3 co} -"|e * 3 oOwends}|||] s 14:05MAY031991FRI,SYSTEMFREQUENCIESTIME(SEC)RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS,BUT WITH CEA-GVEA TIE FLOW ZEROED.2-NORTH POLE UNITS ON. TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA &8. NO UNDERFREQUENCY LOAD SHED IN RAILBELT SYSTEM. FILE:CASE-2AX.CHN AMLP_$8 MECH POWER(PU)|Ji-0000,©.SSS SSSS >| AMLP_#5 MECH POWER (PU)| 11.0000 -----.€o{ AMLP_¢3 MECH POWER (PU){1.0000 _-_----o .0 |c "||||||1 3 2 o|'8 =:"s\' 'co] _ \_2 \oo ad}|3 °o =43loa \\2 _'4?'rr) 1 . ' 'los 8So T j 'Te t ' |14 _4 Ca \bs4 t1}3 |H 3L_.!a bedla" é ' a ,'13we 4 be} on Ss a 3{|""n-£--,J |||3 14:06MAY031991AMLPTURBINEPOWERSFRI,TIME(SEC) RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS,BUT WITH CEA-GVEA TIE FLOW ZEROED.2-NORTH POLE UNITS ON. TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA #8. NO UNDERFREQUENCY LOAD SHED IN RAILBELT SYSTEM. FILE:CASE-2AX.CHN BELUGA #8 MECH POWER (PU)_|11.0000 ers 0.0| BELUGA #5 MECH POWER (PU)][1.0000 ees7)0.0 | BELUGA #3 MECH POWER (PU)]}1.3000 _--*0.30000| BELUGA #1 MECH POWER (PU)}[1.0000 -----4 0.0 | rf 3rsetjtTYTTT: '21|' 1 1 '|4 ;| i] t |(3 ='42t|{ + '! '- 1 t '|i ' 't 3 °-a I coun r || ;tPg/ t y 7] f ! :|'3|'j +: t |a” ' 1 ! i] =\|4 '\+' io |j : 1 ]iy' ')I i] '¢t _-t t -4 \4 I nee !3!Ys b I |Les!|3 06BELUGATURBINEPOWERSMAY03.199114FRI,-0006440.00052.000TIME(SEC)28.00016.000RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS,BUT WITH CEA-GVEA TIE FLOW ZEROED.2-NORTH POLE UNITS ON.©TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA 48.acs NO UNDERFREQUENCY LOAD SHED IN RAILBELT SYSTEM.a @) FILE:CASE 2AX.CHN Au |N.POLE #2 MECH POWER (PU){a }1.0000 maa ">of 2 a|N._POLE {1 MECH POWER (PU){SsPY.0000 0 EROS enw x 0]2m|ZENDER ¢1 MECH POWER (PU){.&%[1.0000 ==+0 |gq?|CHENA ¢5 MECH POWER (PU){a }1.0000 ileeneieneiel °Ol oa |BERNICE ¢4 MECH POWER (PU){BHJ1.0000 ---*:0 |rH |BERNICE $3 MECH POWER (PU)f fxs 11.0000 ----4 10 |a .'3eeaesBy '°1 e rsh ':°3 a |1 ; '+=:8 '° °3M q 0 ;;*'3-'° '"|e '0 ' 4 °° '°t ° '°.S ':'Py ':' 0 °co] = :FS |e'.5 bi] '*' '°\eu'; ;2y 4 °i]g ':.31'°'H '°.gs eH'°'° ='°2 t 3 °x i]° i]*t 2't '_|&= ''': '°t 4 et ' 1 °:3 -'°'"Ws t °° t .' 1 :'° '°a 8 -::(3 q °- 1 °e y 3ceeSeCOl: 258MAY03.199113AMLPTURBINEPOWERSFRI,TIME(SEC)RAILBFLT CONDITIONS FOR 08/29/90 @ 1300 HRS,BUT WITH RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS,BUT WITH CEA-GVFA TIE FLOW ZEROED.NORTH POLE #1 &ZENDER #1 ON.=Ww CEA-GVEA TIE FLOW ZEROED.NORTH POLE #1 &ZENDER #1 ON. TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA 48.o»fx]TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA #8. GVEA LOAD SHED IN LIEU OF SPIN @ 59.7HZ +2 SECONDS.OH GVEA LOAD SHED IN LIEU OF SPIN @ 59.7HZ +2 SECONDS. FILE:CASE-2BX.CHN 1S)FILE:CASE-2BX.CHNaeae28Oo[a44Ixy ZENDER 69KV FREQUENCY (HZ)>>}|AMLP ¢8 MECH POWER (PU}]|60.000 eeraase .59.000 |3 fay}12-0000 ES -0 ||BELUGA _138XKV FREQUENCY (HZ)Bet |AMLP_¢5 MECH POWER (PU)}[60.000 -SST 39-000|Y [7.0000 a ry |AMLP_230KV_FREQUENCY (H2)w AMLP_§¢3 MECH POWER (PU)|[60.000 o-----59.000 |[1.0000 o-___-_#0 4 I |]T |I J if 3 |J '|||]3 3 '3erros 3 1 3 °t 4 o=os -'s -{3 4 i] 3 I}gPoF1mi 4 i]3 Jot 3 -4a -'48 i]8 '3 °1 °o=Ts - |'Te*' o ' '3 fl fo 3 =a ry S"|3 az '"1s#i 3 ©|4 3' -+-oF |4:1 4 i-J ' oes1|g t ;3 {'E =io ry ° os -yt os Uy{4 3 4 3=_j 2 =acd _j 2°4 .s_s. 8 "ot 3 -i |!3 |"\-=f--,|!|!g RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS,BUT WITH CEA-GVEA TIE FLOW ZEROED.NORTH POLE #1 &ZENDER #1 ON. TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA 48. GVEA LOAD SHED IN LIEU OF SPIN @ 59.7H2 +2 SECONDS. FILE:CASE-2BX.CHN |BELUGA _#8 MECH POWER (PU)| 11.0000 -or ot 0.0| BELUGA @5 MECH POWER (PU)] }1.0000 #-------r)0.0 | BELUGA @3 MECH POWER (PU)| [1.3000 --=<0.30000| |BELUGA @1 MECH POWER (PU)| 11.0000 6--_-__-4 0.0 | a ee ||im |TY rT, '|{ 1 _'|4 t \/ Z '|H | 1 \|i '|! =\| 4 \|{ i] j { bo --'| T !' '|i 'j ' 1 i]j' L !|'a |\' po 'Z ' i] 4 |y ;{( =1 i - ' 'p I '(\ ' /' -?t )+ -”-_c '_ SL |te bk I |Ls!|46.00058.00034.00022.00010.000-0006440.00052.000TIME(SEC)28.00016.00013:58BELUGATURBINEPOWERSMAY031991FRI,RAILBELT CONDITIONS FOR 08/29/90 @ 1300 HRS,BUT WITH CEA-GVEA TIE FLOW ZEROED.NORTH POLE #1 &ZENDER #1 ON. TRIP BELUGA #7 @ T=0.0 &COAST-DOWN OF BELUGA #8. GVEA LOAD SHED IN LIEU OF SPIN @ 59.7HZ +2 SECONDS. FILE:CASE-2BX.CHN N.POLE #2 MECH POWER (PU) .0000 - N.POLE ¢1 MECH POWER (PU)o_.0000 x ZENDER #1 MECH POWER (PU)°-----0000 CHENA €5 MECH POWER (PU)°poeeaee1.0000 ------- -r)0 BERNICE ¢4 MECH POWER (PU) 1.0000 -_---*é 0 BERNICE $3 MECH POWER (PU) 1.0000 ----4 .0 +|i ||||||3 fo}1}'2 t 4 ts A =t : 4 fr 0 '6Vy' a x 3 '.e=|\'4s t ° t4 ; ''tr ° '7 |7 (J!° '4I;°3 |1!°4sI\x +, '0 =4 °4!'0i)° 1 a|'0 fo] tt °3 -'°l1<eta°” '4I,' I |™ '=11 4 -: 4 9 to 6 ° \'0 3 ae '0 , I3\':: to ° '0 = My ° 4at0 s !° t 8bE-m -t °3 - -}+-.,|||1 |l 3 FRI,-00040.00052.000TIME(SEC)26.00016.00013:58KENAI&FAIRTURBINEPOWEMAY031991 Mia.Ach GOLDEN VALLEY ELECTRIC ASSOCIATION INC.Box 71249,Fairbanks,Alaska 99707-1249,Phone 907-452-115 March 15,1991 RECEIVED MAR 18 1991 Alaska Energy AuthorityEricA.Marchegiani,P.E. Alaska Energy Authority PO Box 190869 Anchorage AK 99519-0869 Re:Anchorage-Fairbanks IntertieIcingConditionsatGoldhill Substation SVS Building Dear Mr.Marchegiani: During the winter,we have been discussing our options to theabovereferencedproblem.As discussed with you on site lastyear,we originally thought about adding a cold roof over there)existing roof structure. We have been in contact with a local roofing contractor,and have come to the conclusion that,based on the plans you sent us,the original roof was not built to sustain any additionalloadthatanewroofwouldimpose. It was discovered that the original design only accounted for a30poundliveload,which is less than the local codes require.In discussions with the roofing contractor anda structuralengineer,it was agreed that our best course of action would betomodifytheexistingstructuretoincorporatemoreinsulationandnewroofmembersadequatetoprovideacoldroofanda40 pound live load. This method should solve the icing problem and the substandardstrengthoftheexistingroofwithminimalstructuralchanges. I would like your approval to proceed with the analysis anddesignphaseofthisprojectbasedonthefeeproposalfromLoftus&Dailey Structural Engineers;a copy of which is enclosed. Upon completion of the design,we will come up withaconstructioncostestimateforyourapproval.Tentatively,design could be completed in mid-April,with construction scheduled for mid-summer. GOLDEN VALLEY ELECTRIC ASSOCIATION INC. 'Eric A.Marchegiani March 15,1991 Page 2 Anchorage-Fairbanks Intertie If you have any questions regarding this project,please don'thesitatetocallmeat452-1151,extension 329. Sincerely, ek.a CeGregoryE.Wyman,P.E. Senior Engineer GEWsmmf Enclosure ccs Steven Haagenson Robert Orr LOFTUS &DAILEY,INC. 0 Consulting Structural Engineers March 13,1991 Golden Valley Electric Association P.O.Box 1249 Fairbanks,Alaska 99707 Attention:Greg Wyman Subject:Gold Hill Substation -Roof Modifications Fee Proposal Dear Mr.Wyman, Thank you for considering us for the above referenced project.This letter presents our fee proposal for the work we discussed previously.It also outlines our understanding of the scope of services appropriate O for the modifications.In general our project consists of design work necessary to describe construction of a new roof on an existing 40'x80"pre-engineered steel building.The new roof,and supporting structure,will be designed for a 40 psf snow load and incorporate insulation appropriate for the Fairbanks climate.This work is similar to that which we have done on other projects,and we look forward to the chance to assist you. The scope of work and accompanying cost is as follows: 1.Site visit to check as-built drawings,get critical dimensions,and develop base drawings. Cost:.$590.00 2.Structural analysis and design as required to strengthen existing primary lateral and gravity load systems;specifically the rigid bents and purlins. Cost:$1,500.00 3.Roofing system design and details for the new insulation,flashing,and connections. Cost:$1,030.00 4.Administrative costs for coordination,meetings,report,and drawing plots. Cost:$280.00 The total cost for these services comes to $3,400.00.As discussed,we have not included any time for construction administration,cost estimating,or a separate specification package. © 1028 AURORA DRIVE FAIRBANKS,RLASKA 99709-5526 (907)456-768 3340 ARCTIC BLVD,SUITE 101 ANCHORAGE,ALASKA 99503-4550 (907)563-306 LOFTUS &DAILEY,INC. 0 We look forward to your response.Please feel free to call if you have any questions. Sincerely, Loftus &Dailey,Inc. Chee J.f JJL/cah ANCHORAGE FRIRBANF ey 24 State of 4iasxaNWalter,mickel.Goverror Alaska Energy Authority A Public Corporation March 27,1991 Mr.Steven Haagenson Golden Valley Electric Association,Inc. P.O.Box 71249 Fairbanks,Alaska 99707-1249 Subject:Goldhill Substation Engineering/Design Dear Mr.Haagenson: Please reference Mr.Wyman's recent letters to Mr.Eric Marchegiani ofMarch15and21,1991 which summarize Loftus &Dailey,Inc.'sengineeringanddesignproposaltocompletethenecessaryroofmodificationstotheGoldhillSubstationbuilding.It is our understanding that the costs are as follows: DESCRIPTION COSTS 1.Site Visit,Check As Builts,Develop Base Drawings $590 2.Structural Analysis &Design For Existing Members $1,500 3.New Roofing System Design and Details $1,030 4.Construction Costs Estimate of Project $320 5.Full Plans and Specifications $500 6.Administrative Costs,Coordination,Meetings,Report $280 SUBTOTAL $4,220 7.Construction Administration $1,200 TOTAL $5,420 The Alaska Energy Authority concurs with this proposal and recommendsthatyoumoveaheadbyissuingthenecessarycontractdocumentstobringLoftus&Dailey,Inc.on board to initiate the required design work fortheGoldhillSubstation.Please keep us advised as to your progress.We would like to receive a copy of the resulting report along with areviewcopyoftheplansandspecificationsforEnergyAuthorityreview.At that time we will decide whether to move forward with construction. Our present expectation is that a construction contract will be issuedpriortosnowfalltoinsurethatthepresenticingproblemdoesnotoccuragain. C PO.BoxAM Juneau,Alaska 99814 (907)465-3575Bl,PO,BOx,190869 704 East Tudor Road Anchorage,Alaska 99519-0869 (907)561-7877 Mr.Steven Haagenson March 26,1991 Page 2 If you have any questions please feel free to contact me. Sincerely, Stanley -ieczkowski,Director Facilities Operations &Engineering EAM:SES:jd cc:Bob Orr,Golden Valley Electric Association Tom Lovas,Chugach Electric AssociationJohnCooley,Anchorage Municipal Light &PowerJimHall,Matanuska Electric Association Afzal Khan,Alaska Energy Authority Eric Marchegiani,Alaska Energy Authority 0 GV GOLDEN VALLEY ELECTRIC ASSOCIATION INC.Box 71249,Fairbanks,Alaska 99707-1249,Phone 907-452-1151 April 2,1991 RECEIVED £323 199] Mr.Eric Marchegiani Alaska Energy Authority P.O.Box 190869 Anchorage,Alaska 99519-0869 ALASKA Eticru:»JTUORITY Subject:Tower 749 Dear Eric: Enclosed you will find a copy of the preliminary geotechnical reportfortower#749.I expect the final report will be available soon and I will forward that document as soon as_possible.I don't ro)expect to see any significant changes in the final report.I talked with Mr.Sieczkowski concerning the report and our futureplansonfindinga_solution to the foundation problem.Mr.Sieczkowski indicated that you would be the project engineer and I should work with you in selecting and contracting a consultant to guide us towards remedying the problem. Please review the report and contact me as soon as possible.I still hope to start on this before breakup this spring. ev ift ine pt. cc:Stan Sieczkowski,AEA Robert Orr,GVEA Greg Wyman,GVEA #749 file patna tec Matanuska Electric Association,Inc. P.O.Box 2929 Palmer,Alaska 99645 Telephone:(907)745-3231 Fax:(907)745-9328 MEMORANDUM DATE:May 7,1991 TO:Chairman ;Intertie Operating Committee FROM:James D.Hall Projects EngineerMatanuskaElectric Association,Inc, (Alternate AEG&T Representative) SUBJECT:INTERTIE MAINTENANCE Matanuska Electric Association,Inc.'s crews have completed the normal 1991 climbingmaintenanceoftheAlaskaIntertie. Two items of interest were corrected.The ten spans with twisted bundle conductorswerestraightened.They are in their original configuration.It has not beendeterminedwhetherornottherewasanydamagecausedbythetwisting,but none isapparent.One structure was found with only four of the original twelve boltsremainingintheboltedflangetypeconnectioninthemiddleofthelowerleg.One ofthesefourboltsfailedasthestructurewasbeingclimbedtoreplacethemissingbolts.The failed bolts were lost in the snow;however,two of the remaining bolts were senttotheAlaskaEnergyAuthoritysotheycouldbeexaminedinanattempttodeterminethecauseoffailure.After the snow is gone,it may be possible to locate some of thefailedboltsifthatisdeemeddesirable. If you have any questions,please feel free to call me at (907)745-9269. O James D.Hall jdh302A.335 NMinnirKee Gy GOLDEN VALLEY ELECTRIC ASSOCIATION INC.Box 71249,Fairbanks,Alaska 99707-1249,Phone 907-452-1151 May 7,1991 Mr.Stanley E.SieczkowskiDirector/Facilities Operations &EngineeringAlaskaEnergyAuthority P.O.Box 190869 Anchorage,Alaska 99519-0869 Re:Cost Evaluation of Corrective Measures to the Southern Portion of the Alaska Intertie Dear Mr.Sieczkowski: We have reviewed the material presented by Mr.Brian White regardingtheconductorproblemsencounteredthispastwinteronthesouthern©)portion of the Intertie.This data,along with the directions of theIntertieOperatingCommittee,was used to form the guidelines by which this cost estimate was developed. Estimates are provided for each of the several different options available to resolve the static to phase clearance problem and the conductor ground clearance problems.While some of these options may mitigate different symptoms they may not resolve all of the existingconditionsthathavebeenpreviouslyaddressed. The following list shows the different options that have been investigated: 1.Removal of Overhead Static Conductors. 2.Removal of Overhead Static Conductors and Re-sagging of Phase Conductors. 3.Re-sagging of both the Overhead Static and Phase conductors. 4.Removal of Bells from Insulator String to make 230 KV String. 5.Install the Inverted V Insulators to limit the Conductor's Longitudinal Travel. eo)6.Install Intermediate 230 KV "H"Structures,using Wood Poles. 0 GOLDEN VALLEY ELECTRIC ASSOCIATION INC. Mr.Stanley E.Sieczkowski May 7,1991 Page 2 7.%Install Intermediate 230 KV Steel Structures,using eitherH-pile or Concrete Foundations.: 8.Rotate conductor Bundles to Vertical. 9.Make no line modifications,increase line patrol duringlikelytroubletimes.(Do nothing option) As in Mr.White's report,we have used an average span of 1200'and the costs shown in this document are for a 12 mile section of the line.Since the tower spacing is fairly regular through thissection,it is reasonable to assign the costs proportionally for any segment. Further study may indicate something other than the twelve mile re- construction area,however,for the purpose of this report the relative costs per mile will remain consistent for this study. For the above options 1 through 3 the costs consist of transportation and labor with minimal amounts of material necessary.The labor could be provided by utility force account crews,or a subcontractor could be hired to complete the project.The costs shown herein include per diem costs to maintain crews in a central staging area such as Talkeetna or Willow.Such costs are included in the mobilization and demobilization amounts. To make the most efficient use of helicopter time,we have used a combination of two 4-man crews to work alternate towers.This method should keep helicopter stand-by time to a minimum.It appears that there are two methods used to climb the towers,using the ladder system provided with the towers or by use of a modified ladder that hangs over the tower arm and extends to ground level.The laddersprovidedaretimeconsumingtoinstallandmayfitpoorlyinthetowersockets.The modified ladders take a bit more finesse to install,but are much quicker and easier to use.Investigation indicates as much as one crew hour may be saved at each tower location by using a modified ladder system. GOLDEN VALLEY ELECTRIC ASSOCIATION INC. Mr.Stanley E.Sieczkowski0May7,1991Page3 The summary of costs for the various options are as follows: 1)Removal of Overload Static Conductors Mobilization/Demobilization S 8,500.00 On-site Labor &Transportation 53,460.00IntertieOut-of-Service Costs (9 days)124,200.00 Option 1 Cost $186,160.00 2)Removal of Overhead Static Conductors &Re-sagging of PhaseConductors Mobilization/Demobilization $13,200.00 On-site Labor &Transportation 100,980.00 Intertie Out-of-Service Costs (17 days)234,600.00 Option 2 Cost $348.780.00 ©)3)Re-sag both Overhead Static &Phase Conductors Mobilization/Demobilization $15,400.00 On-site Labor &Transportation 114,600.00 Intertie Out-of-Service Costs (20 days)276.000.00 Option 3 Cost $406.000.00 4)Removal of Bells from 345 KV Insulator String to make230KVString This option requires more than simple adjustments and/orre-sagging.While the out-side phases could easily be modified,the center phase would have to be changed to averticalstringortheexistingVstringmightbemodified by removing bells and reconnecting the strings at the arm. A more thorough engineering analysis should be done toverifyclearancesandloadingspriortoanymodifications.If conditions allow such a modification the estimated costs are as follows: Mobilization/Demobilization $11,950.00 Material 4,050.00 On-site Labor &Transportation 81,060.00 Intertie Out-of-Service Costs (14 days)193,200.00©.Option 4 Cost $290,260.00 0 GOLDEN VALLEY ELECTRIC ASSOCIATION INC. Mr.Stanley E.Sieczkowski May 7, Page 4 5) 6) 7) 1991 Install Inverted V Insulators As mentioned in previous reports,this option is contingent upon the ability of the towers to withstand the additional strains.The following costs are based on the assumptions that with only minor modifications to the tower,Inverted V Insulator can be installed. Engineering Analysis $9,600.00Mobilization/Demobilization 15,400.00 Material 67,300.00 On-site Labor &Transportation 131,800.00 Intertie Out-of-Service Costs (22 days)296,000.00 Option 5 Cost $520,100.00 Install intermediate 230 KV "H"Structures,using WoodPoles It is not believed that every span for the 12 mile area. would require an intermediate structure,therefor for,the costareshownonaperstructurebasis.It is realized that access along the route will vary in difficulty,and we have attempted to develop a cost that can be used as an average. Cost per structure: Mobilization/Demobilization $2,670.00 Material 4,500.00 On-site Labor &Transportation 10,600.00 Intertie Out-of-Service Costs (per struct.)31,400.00 Option 6 Cost (per struct.)$49,170.00 To compare with other options,we have used a total of 53 structures within the 12 miles.Cost of engineering and construction management are included in the above per structure cost. Install intermediate 230 KV "Steel X"tower using either steel pile or concrete foundations. As described above,the following costs are on a per structure basis using H-pile foundations. Mobilization/Demobilization $6,400.00 Material 21,000.00 On-site Labor &Transportation 17,800.00 Intertie Out-of-Service Costs 41,400.00 Option 7 Cost (per struct.)$86,600.00 To compare with other options,we have used a total of 53structureswithinthe12miles.Using concrete pad withrockanchortypefoundationwillincreaseabovecostsby approximately $4,000.00 per structure. 0 GOLDEN VALLEY ELECTRIC ASSOCIATION INC. Mr.Stanley E.Sieczkowski May 7,1991 Page 5 8)Rotate conductor bundles to vertical. If the spacer system is indeed inadequate as Mr.White suspects,it may be premature to develop costs for rotating the existing bundles to a vertical configuration.The greatest advantage to the clearance problems in a vertical bundle would be the elimination of the available area for snow bridging between conductors.We believe that by de- creasing the load possibilities may help _in maintainingphaseclearanceswiththeground.No costs for this option have been developed at this time. 9)Do nothing -make no modifications and increase line patrolactivitiesduringlikelytroubletimes. The direct costs of this option is in the Intertie Out-of- Service Cost and Labor necessary to clear the lines after- the-fact.Based on past performance the costs can be estimated as follows: Out-of-Service Cost during winter storm(est.7-10 days/year)$138,000.00 Labor to Respond to outage 27,600.00 Extra Patrols 15,600.00 Expected Do-Nothing Costs per Yr.$181,200.00 The large unknown is the liability of having below minimumclearancesatcertaintimesoftheyear.This is difficult to put a cost value on,but this exposure needs to beaddressedcarefullyifthedo-nothing.option is chosen. The following matrix shows the problems which will be mitigated be the other different mitigation options.Yes to cure slapping,indicates that the option will resolve the overhead ground to phaseconductorslapping.Yes to Phase clearance,indicates that theoptionwillresolvethereducedgroundclearancefromlongitudinalinsulatorswing.Yes to Lightning Shield indicates that the optionwillprovideforcontinuedlightningshieldingfromtheoverheadstatic.A yes on the Bundle twist indicates that the option willresolvethephasebundletwistingactionwhichhasbeenexperienced. 0 GOLDEN VALLEY ELECTRIC ASSOCIATION INC. Mr.Stanley E.Sieczkowski May 17,1991Page6 Option Cure Phase Lightning Bundle Slapping Clearance Shield Twist A)Yes No No No B)Yes Yes No No C)No worse Yes Yes No D)No Yes Yes No E)No Yes Yes No F)No No Yes Yes G)Yes Yes Yes Yes H)Yes Yes Yes Yes T)Yes Yes Yes Yes J)No No .Yes No The estimated costs in this report include direct labor manhours, room and board costs for crew,helicopter and fuel,administrationandsomeconstructionmanagement.There is also some contingency duetofutureengineeringanalysisfindingsandtowercapabilitieswhich have yet to be checked out. A large portion of the costs involved in all the options is that oflossofservice.This cost will vary depending on the time of year,but we have tried to find an average cost to having the Intertie out- of-service.This cost involves the increased generation expense to GVEA and a loss of revenue for the southern utilities. These costs should give you some comparisons in an evaluation ofwhichdirectiontoproceedandifwecanbeofanyfurtherassistance please feel free to contact us. Sincerely, LEOSebohan Senior Engineer GW:bj ce CITY OF FAIRBANKS .Office of the City Attorney 410 CUSHMAN STREET FAIRBANKS,ALASKA 99701-4683 907-459-6750 April 10,1991 R Er Efuer DStanSieczkowski Alaska Energy Authority Aw Py 1yyl 701 East Tudor RoadAnchorage,Alaska 99503 *!4SK4 ENERGY putunpity RE:Intertie Operating Committee,Insurance Subcommittee Dear Mr.Sieczkowski: Ron Smith was replaced by James T.Mulhall,Deputy City Attorney,on the Intertie Operating Committee,Insurance Subcommittee.James T.Mulhall is no longer associated with the City of Fairbanks,Municipal Utilities System (FMUS),and I have taken his place.It is my understanding that Mr.Smith and then Mr.Mulhall,occupied a place on the referenced insurance committee.Since Mr.Mulhall's departure,|have been selected by FMUS to represent it on the Insurance Subcommittee.Please change your records to reflect this change and advise me of any scheduled meetings.|look forward to meeting with you. Sincerely, OFFICE OF THE CITY ATTORNEY CEZ2QKOMOCharlaneBigelowStead Deputy City Attorney CBS:lbe paimtet ' C OMMONWEALTH ASSOCIATES INC.AT comnt 1184-Jackeon,Michigan 49204-1124 (517)783-45900.engineers «consultants e construction management April 4,1991 Mr.David R.Eberle Project ManagerBradleyLakeHydroelectric ProjectAlaskaEnergyAuthority P.0.Box 190869 Anchorage,AK 99519-0869 SUBJECT:ANCHORAGE-FAIRBANKS INTERTIE EXTREME LOADING PROBLEMS Dear David: I really appreciate the time you took to talk to me on my last trip to Anchorage.I also want tothankDominicCostanzoforthetimehetooktodiscusstheprospectsforfuturework.Inaddition,Fee ear ctot Ye 6 oRportnity to be introduced to Stanley Sleczkowski,Afzal-Khan and Eric Marchegiani. The two documents you copied for me,written by Brian White,were very interesting.WeundersfandthattheproblemwiththerecentextremeJonding.of_thecondvctarandshicld wireOfthesubjectproject,is being reviswed in a "Urainstorming"fashion for ideas as to possible solutions.As I discussed with you by telephone,we would be very concerned about certainideastomodifytheoriginaldesign.The tensions of the shield wire and conductor,along with the flexibility of the suspension assemblies and the towers were considered on a composite basis for design,and any changes could affect the structural integrity and reliability of the line. In reviewing the documents,there was no indication of the actual status of the lineon a span-by-span and phase-by-phasebasis.It would seem appropriate to determine the actual condition ofboththeshieldwireandconductor.This would include the determination of sags and the swingoftheinsulatorstringsateachtowerandforeachphaseintheareaswhereproblemsexist.Thetwistingdeformationofthebundledconductorsshouldalsobereviewedinmoredetail.In doingthis,a pattern or somethinginparticular may be discovered that would assistin formulatingasolution.In any case,a detailed survey would determine the actual problem as it exists. The extreme loading was noted and reviewed.The probability that this type of loading will everhappenagaindefinitelyneedstobeconsideredfurther. Mr.David R.Eberte April 4,1991 Page 2 One other item of concern is the spacers.The application and design were as specified by Alcoa.They have the experience and expertise to consider problems such as have occurred. I have discussed this briefly with Alcoa representatives,and they requested information concerning the shield wire,conductor and spacer problems.I then sent them the data provided in the two documents and they are reviewing it. In summary,we are concerned about what might be done to the line.We also see it as necessary to determine the actual condition of the conductor,shield wire and structures.If anyofthesehavebeenoversircssed,knowledge about their present condition will help in arrivingatasolutionforfixupthatwillbeeconomicalandprovideforcontinuingreliabilityandoperationinthefutureat345kV, Please let us know if there is any way we can be of assistance to the Alaska Energy Authorityinprovidingforrepairoftheline.We wouldbevery pleased to work with you. Yours very truly, ARE R.R.Hoop,P.E. Project Manager RRH/ljr =-mee 6 m e set FQMeeemw Lt MSM LILIEA @tZ er inl &t'Ga-v -ads bnsannw Tes CA COMMONWEALTH ASSOCIATES INC.P.O.Box 1124 -Jackson,Michigan 49204-1124 (517)783-4590 0 engineers e consultants e construction management April 29,1991 Mr.Stanley E.Sieczkowski Director/Facilities Operations &Engineering Alaska Energy Authority P.O.Box 190869 Anchorage,AK 99519-0869 Subject:Anchorage-Fairbanks Intertie Extreme Loading Study Dear Stan: I knowI said it several times,but I want to say it once more --I was pleased that you took thetimetoseemeonTuesday,April 23,1991.I was also very pleased to discuss the intertie and your concerns for proper repair of the different items which have been damaged. re]I have,as you know,reviewed the two letter reports as prepared by Brian White,and want to state my opinion concerning certain statements or ideas that he proposed for consideration.Most of these we talked about in our meeting. One item was the debate as to whether this type of loading would ever occur again.As you stated,whether it happens or not,you cannot tolerate the possibility of the ground clearance being reduced to where it is dangerous and life threatening to snowmobilers who may happen to come along and contact the phase conductors.Thus,something has to be done. One other item was the overlapping or twisting of the conductor in a bundle.My theory (and this is without actually seeing them)is that I do not believe it had anything to do with the adequacy of the spacers to do the job for which they were designed.I believe that one of the conductors in a bundle was overstressed or stretched in some way,such that now there is just a dead load of that conductor hanging on the other which is adequate to keep the spacers in thepositionthattheyare.If there was any tension in the conductor that is twisted around the other, it should pull itself back into position.Thus,it is probably not the spacer,but the conductor that has been lengthened in some way to reduce the tension and make it nothing more than a limp dead toad. Many repair considerations were stated and several of these are items we would agree with and others present concern. Mr.Stanley E.Sieczkowski April 29,1991 Page 2 One of the possibilities being considered is the elimination of the shield wire in a specific area. This we would agree with since it should not greatly affect the operating reliability of the line and would eliminate the possibility of it sagging to a point where it would be at the same elevation as the conductor at mid-span.The extent of the shield wire,which would be removed, is of concern regarding the terminal capability of the structures at the removal end points. The removal of links or insulators in either the shield wire or conductor suspension assemblies is of concern.As we discussed,the flexibility of the line components was considered on a composite basis for the structure design.Without this flexibility,a loading,such as that recently experienced,will result in the failure of structural members. Another item of concern is the possibility of increasing the conductor tensions.Again,this will affect the flexibility of the line to resist possible future extreme loadings.In addition,the condition of the conductor is not known at this time and there is a possibility of some spans being damaged. We understand that cost estimates are being prepared for different aspects of repair and for specific solutions to the problems.In view of our concerns and the work you are doing or having done,we would like to propose,for your consideration,a plan to do a detailed survey of spans in particular where the following may be noted: Structures may be leaning. Structures may be twisted. Shield wire suspension assemblies are not hanging vertically. Conductor suspension assemblies are not hanging vertically. Conductor suspension assembly yokes are twisted,indicating unbalanced tensions in the conductors. Conductor phase bundles are twisted or wrapped.UPYWNraWe suggest determining the detailed extent of each of the above,and with this information, determining the actual existing condition of all the components of the line.This would allow for an optimum repair plan from the standpoint of both reliability and economics. One item not resolved in the above discussion,is ensuring that the conductor could not sag to a point where sufficient ground clearance would not be maintained.This,based on what we know at present,could be handled by an independent system.With a survey of the line,we feel certain spans may be determined as critical and guard structures (details "after”studies)could be installed to ensure clearances would be maintained.As we discussed,there were many lines in trouble during the storms,and your concern for maintaining clearance is a just and responsible one. Mr.Stanley E.Sieczkowski April 29,1991 Page 3 Our suggested survey plan would,first of all,involve a two-or three-day preliminary review (two people)to determine the structures and spans which involve distortion warranting a detailed survey.The detailed survey could readily be done by the use a total station instrument.The procedure would be to survey each structure (two setups per structure)and obtain coordinates to determine the extent of twisting,swinging and leaning of all components.We would also suggest determining the sags for correlation with the movements of all the components.The wrapping or twisting of the bundled conductors should receive special attention to determine the actual condition of the conductors from a damage and stress standpoint.In review,you would then know the exact condition of the line and from this,be able to obtain the most economical repair and restoration plan. We would estimate five hours (2 people)as the time required to survey a single structure.This would include set up and travel time by helicopter.A total of two structures per day is estimated.Then in four weeks of six ten-hour days,a total of approximately fifty structures or 11 miles of line could be completed.If certain sections of line have not been distorted as determined in the preliminary review,the four-week time could be shortened.Weather, however,could increase the time required. With the survey complete,we presume it would take two weeks to review the data and make a layout drawing showing the results of the survey.The drawing would provide the logic for the condition of the line as it now exists.It would also provide the basis for repair in specific locations.A report should then be written to summarize the conclusions. We believe a savings can be realized in the restoration costs,that will exceed the cost of the survey and study,and as a final result,you will have a restored line that will provide you withthereliabilityrequired.The status of the existing line will be known and an economical , reliable method of maintaining clearances under future extreme loadings can also be determined. Enclosed is a copy of our qualification document as you requested.We sincerely hope we are able to assist you in this complex and interesting project,especially since we are so familiar with the design.If we can provide you with a proposal,answer any questions,or if more information is required,please let me know. Yours very truly, ALASKA INTERTIE OPERATING COMMITTEE TUESDAY,MARCH 12,1991 (FAIRBANKS MUNICIPAL UTILITIES SYSTEM BOARD ROOM) MEETING MINUTES Present: James Hall Alaska Electric Generation &Transmission (AEG&T)/Matanuska Electric Assoc.(MEA) Stan Sieczkowski Alaska Energy Authority (AEA) Afzal H.Khan Alaska Energy Authority (AEA) Eric Marchegiani Alaska Energy Authority (AEA) John Cooley Anchorage Municipal Light &Power (AML&P) Tom Lovas Chugach Electric Association (CEA) Larry Colp Fairbanks Municipal Utilities System(FMUS) Bob Orr Golden Valley Electric Association (GVEA) Marvin Riddle Golden Valley Electric Association (GVEA) The meeting was called to order by Chairman John Cooley at 11:50 a.m.at the Fairbanks Municipal Utilities System Board Room. John Cooley stated that the January 11,1991 meeting minutes be corrected: page 3 second sentence of the last paragraph should read "In addition,the Dispatch subcommittee is to review the Outage Report Procedures,maintenance response and communications coordination among the area utilities and Technical Guidelines for Operation,Metering and Protective Relaying for Non- Utility Power Producers and Cogenerators and develop operating guides to go with them;"and page 4 under attachments,the paragraph should read "The following were distributed at the January 11,1991 meeting." Tom Lovas moved that the IOC adopt the January 11,1991 meeting minutes as corrected.Jim Hall seconded the motion.The motion was adopted unanimously. The March 12,1991 meeting agenda was adopted unanimously. Under Dispatch,Marvin Riddle stated that the subcommittee did not meet. Q1\IT0433(1) ALASKA INTERTIE OPERATING COMMITTEE March 12,1991 Meeting Minutes Page 2 of 9 Under Protection Coordination,Afzal Khan distributed the February 21,1991 subcommittee meeting minutes.He also distributed a PTI letter,dated February 1,1991,to AEA in which the PTI requested additional informations to complete the base case.There was a brief discussion regarding funding and study results of the PTI Contract "Underfrequency Load shedding Study." Under Machine/Rating Subcommittee,Chairman John Cooley stated that he will find out about the subcommittee's progress on updating the Machines Data Book from its subcommittee Chairman. Under Reliability/Criteria,Chairman John Cooley on behalf of Mike Massin distributed the March 1,1991 subcommittee meeting minutes.Chairman John Cooley briefly discussed the contents of the March 1,1991 subcommittee meeting minutes. Under Correspondence,John Cooley stated that he received the following: 1) 2) 3) GVEA letter,dated February 26,1991,to Chairman John Cooley. Reference:Reappointment of GVEA member to the Reliability/Criteria Subcommittee. MEA letter,dated February 22,1991,to AEA. Subject:Comments on the H.Brian White Report. GVEA memorandum,dated March 7,1991,to IOC. Reference:Potential Methods to Mitigate the Intertie Problems. Under Intertie Status,Afzal Khan distributed the following: 1) 2) 3) 4) FY92 Minimum Intertie Transfer Capability Rights (MITCR)Determination. Alaska Intertie Energy Usage (Mwh) AEA letter,dated January 31,1991,to GVEA. Subject:Outage and Maintenance Reports AEA letter,dated February 5,1991,to AML&P. Subject:Outage and Maintenance Reports Q1\IT0433(2) ALASKA INTERTIE OPERATING COMMITTEE March 12,1991 Meeting Minutes Page 3 of 9 5) 6) 7) 8) 9) 10) 11) 12) 13) 14) 15) GVEA letter,dated February 11,1991,to AEA. Subject:Bradley DECnet Interface. AML&P letter,dated February 19,1991,to AEA. Subject:Alaska Intertie Accounting GVEA letter,dated February 28,1991,to AEA. Subject:Alaska Intertie Accounting. GVEA letter with attachments,dated February 22,1991,to AEA. Reference:Proof of Insurance CEA letter with sketches,dated November 14,1990,to AEA. Reference:75 MVA autotransformer installation at Teeland substation to serve as an emergency to the MEA system. AEA letter,dated January 29,1991,to AEA. Reference:Proposal for Geotechnical Studies on Structure #749 Foundations. GVEA letter,dated January 16,1991,to AEA with attachments "Proposal for Geotechnical Studies on Structure #749 Foundations." GVEA letter,dated February 15,1991,to AEA. Subject:Intertie Tower #570,GVEA recommendation GVEA memorandum,dated February 14,1991,with attachments. Reference:AEA Tower #570 GVEA letter,dated January 12,1988,to AEA. Subject:Intertie Tower #570 Status GVEA Inter-Office Memo,dated January 11,1988. Reference:Intertie Tower #570 leaning at a right angle. There was a brief discussion on the H.Brian White report.Tne AEA,MEA,and GVEA submitted comments on the H.Brian White report. No visitors were present. Q1\IT0433(3) ALASKA INTERTIE OPERATING COMMITTEE March 12,1991 Meeting Minutes Page 4 of 9 The Operating Committee took a break from 1:00 p.m.to 1:15 p.m. The Operating Committee went into work session. Under Dispatch/Protection Coordination,Chairman John Cooley stated that these two subcommittees continue working on the underfrequency load shedding study.There was a brief discussion on the Underfrequency Load Shedding Study by PTI. Under Reliability/Criteria,Chairman John Cooley concurred with the subcommittee's decision to hold off any additional work on the Douglas substation reactor.The IOC members agree that each utility purchase the PTI PSS/E program. Under Intertie FY92 Budget,Afzal Khan distributed the AEA memorandum on the Alaska Intertie FY92 Budget. Under SVS,Bob Orr stated that the icing problem at the Goldhill substation SVS Building still exists.He also stated that according to structural engineer the SVS Building roof was designed for only 30 pound live load,which is less than the local codes require.There is a need to modify the existing structure to provide a cold roof and a 40 pound live load.Bob Orr Stated that the GVEA will make recommendations to the Energy Authority. Under T/L Structure and Conductor Evaluation,Bob Orr provided an update on the Intertie structure #749.Bob stated that the structure #749 rock anchors are in permafrost not in the rock.He said that there is no need for further discussion until we get the consultant's report. On the H.Brian White Report,Jim Hall stated that we need to pick one of the alternatives fisted in the report or to go with a small project or to cost out all of the listed alternatives.Tom Lovas stated that he will discuss with CEA engineers before CEA can make any comments on the H.Brian White report.Bob Orr stated that it is too early to pick an option.Bob Orr also stated that the first thing to do is to cost out all of the options before considering any option and GVEA is offering to do that without any cost to anyone.Tom Lovas stated that the |OC accept the GVEA offer to cost out each option.Stan Sieczkowski stated that the GVEA cost out each option for AEA's review and comments.Chairman John Cooley stated that the |OC accepts the GVEA offer to cost out each option for participants review and comments. Q1\IT0433(4) ALASKA INTERTIE OPERATING COMMITTEE March 12,1991 Meeting Minutes Page 5 of 9 There was a brief discussion on the Intertie Energy Rate and Capacity Rate. Under Bradley Project DECnet Interface,Tom Lovas stated that the CEA has no objection for having the Bradley data link between GVEA and ML&P. Under Formal Committee action/recommendation: Under Election of Officers,Chairman John Cooley requested nominations for Chairman and Vice Chairman.Tom Lovas nominated John Cooley for Chairman. Jim Hall seconded the nomination.Bob Orr nominated Tom Lovas for Chairman. No second for nomination.Chairman John Cooley moved that the nomination for Chairman be closed.The motion was passed unanimously.The members voting for John Cooley were Stan Sieczkowski,Tom Lovas,Bob Orr,Jim Hall John Cooley and Larry Colp.John Cooley was elected Chairman.Chairman John Cooley requested nominations for Vice Chairman.Bob Orr nominated Tom Lovas for Vice Chairman.Jim Hall seconded the nomination.There was no other nomination.The members voting for Tom Lovas were Stan Sieczkowski, Tom Lovas,Bob Orr,Jim Hall John Cooley and Larry Colp.Tom Lovas was elected Vice Chairman.Chairman John Cooley moved that Stan Sieczkowski be reconfirmed as Secretary.The motion was adopted unanimously. Bob Orr moved that the IOC accept the Minimum Intertie Transfer Capability Rights (MITCR)Determination calculations as submitted by the Energy Authority. Larry Colp seconded the motion.The motion was adopted unanimously. Bob Orr moved that the Railbelt utilities especially CEA,GVEA,ML&P and AEA purchase the PTI PSS/E program.Stan Sieczkowski seconded the motion.The motion was adopted Unanimously. Bob Orr moved that the IOC chooses not to purchase the PT]PSS/E program and computer hardware for use by the UAF.John Cooley seconded the motion. The motion was adopted unanimously. Stan Sieczkowski moved that the IOC ask UAF to provide a proposal describing what UAF can provide for research and training that can be used in the Railbelt utilities,the |OC,and Reliability/Criteria subcommittee.Jim Hall seconded the motion.The motion was adopted unanimously. Q1\IT0433(5) ALASKA INTERTIE OPERATING COMMITTEE March 12,1991 Meeting Minutes Page 6 of 9 Under Subcommittee Assignments,Chairman John Cooley directed the DISPATCH subcommittee to meet at the discretion of its Chairman to work on: Dispatch Training Plan;and underfrequency load shedding study,review the base case in a joint meeting with Protection Coordination subcommittee.In addition,the Dispatch subcommittee is to review the Outage Report Procedures, maintenance response and communications coordination among the area utilities and Technical Guidelines for Operation,Metering and Protective Relaying for Non-Utility Power Producers and Cogenerators and develop operating guides to go with them. Chairman John Cooley directed the MACHINES/RATING subcommittee to meet at the discretion of its Chairman to continue work on machines rating book. Chairman John Cooley directed the PROTECTION COORDINATION subcommittee to meet at the discretion of its Chairman to continue work on underfrequency load shedding study. THE NEXT REGULARLY SCHEDULED MEETING OF THE ALASKA INTERTIE OPERATING COMMITTEE WILL BE ON WEDNESDAY,MAY 8,1991,AT 10:00 A.M.AT THE ALASKA ENERGY AUTHORITY MAIN CONFERENCE ROOM, ALASKA. The Operating Committee set the agenda for the next meeting of the Operating Committee. Larry Colp moved for the meeting to adjourn,seconded by Stan Sieczkowski. The Operating Committee unanimously adopted the motion to adjourn at 2:45 p.m. Respectfully submitted, Stanley E.Sieczkowski,Secretary Alaska Intertie Operating Committee AHK:SES:it Q1\IT0433(6) ALASKA INTERTIE OPERATING COMMITTEE March 12,1991 Meeting Minutes Page 7 of 9 Attachments: 1. 2. May 8,1991 meeting agenda. lOC March 12,1991 meeting attendance sheet. The following were distributed at the March 12,1991 meeting: 3. 10. 11. 12. 13. 14. Protection Coordination Subcommittee February 21,1991 meeting minutes. Reliability/Criteria Subcommittee March 1,1991 meeting minutes with attachments. PTI letter,dated February 1,1991,to AEA. Reference:Load Shedding Study. Alaska Intertie Preliminary FY92 Budget. FY92 Minimum Intertie Transfer Capability Rights (MITCR)Determination. Alaska Intertie Energy Usage (Mwh). AEA letter,dated January 31,1991,to GVEA. Subject:Outage and Maintenance Reports. AEA letter,dated February 5,1991,to ML&P. Subject:Outage and Maintenance Reports. GVEA letter,dated February 11,1991,to AEA. Subject:Bradley DECnet Interface. ML&P letter,dated February 19,1991,to AEA. Subject:Alaska Intertie Accounting. GVEA letter,dated February 28,1991,to AEA. Subject:Alaska Intertie Accounting. GVEA letter with attachments,dated February 22,1991 to AEA. Reference:Proof of Insurance. Q1\!T0433(7) ALASKA INTERTIE OPERATING COMMITTEE March 12,1991 Meeting Minutes Page 8 of 9 15. 16. 17. 18. 19. 20. 21. 23. 24. 25. 26. CEA letter with sketches,dated February 19,1991,to AEA. Reference:75 MVA autoransformer installation at Teeland substation to serve as an emergency to the MEA system. GVEA letter,dated February 26,1991,to |OC Chairman John Cooley. Reference:Reappointment of GVEA member to the Reliability/Criteria Subcommittee. AEA letter,dated January 29,1991,to AEA. Reference:Proposal for Geotechnical Studies on Structure #749 Foundations. GVEA letter,dated January 16,1991,to AEA with attachment "Proposal for Geotechnical Studies on Structure #749 Foundations." GVEA letter,dated February 15,1991,to AEA. Subject:Intertie Tower #570,GVEA recommendation. GVEA memorandum,dated February 14,1991,with attachments. Reference:AEA Tower #570. GVEA letter,dated January 12,1988,to AEA. Subject:Intertie Tower #570 Status. GVEA Inter-Office Memo,dated January 11,1988. Reference:Intertie Tower #570 leaning at a right angle. MEA letter,dated February 22,1991,to AEA. Subject:Comments on the H.Brian White Report. GVEA memorandum,dated March 7,1991,to IOC. Reference:Potential Methods to Mitigate the Intertie Problems. AEA Memorandum,dated March 11,1991. Subject:On H.Brian White's Report Recommendations. H.Brian White's second report,dated February 18,1991,to AEA. Q1\IT0433(8) ALASKA INTERTIE OPERATING COMMITTEE March 12,1991 Meeting Minutes Page 9 of 9 27._H.Brian White letter,dated February 1,1991,to AEA. Reference:Report on Problems on Anchorage-Fairbanks Intertie. 28._H.Brian White Report dated January 31,1991 Reference:Wet Snow Problems on the Anchorage-Fairbanks Intertie Q1\IT0433(9) IV. ALASKA INTERTIE OPERATING COMMITTEE MEETING AGENDA WEDNESDAY,MAY 8,1991BEGINAT10:00 A.M. Adoption of prior meeting minutes Approval/modification of agenda Committee correspondence and reports A.Dispatch SubcommitteeB.Protection Coordination Subcommittee C.Machine/Rating Subcommittee D.Correspondence Received E. Intertie Status Update Visitors comments related to items on agenda Work Session Recess and work session DispatchProtection Coordination Machine/RatingSVS FY93 BudgetT/L Structure and Conductor EvaluationQMMO©>Formal Operating Committee action/recommendation Subcommittee Assignments Determine agenda for next meeting Meeting location:Alaska Energy Authority Main Conference Room P.O.Box 190869 701 East Tudor Road Anchorage,Alaska 99519(907)561-7877 Q1\IT0432(1) mindtes ALASKA INTERTIE OPERATINGCOPRITTEEMEETING In Attendance:Inte March t2,91 __hn Lonpany Phone No, wen Voolig |WIC+P QEBSYSO te Sc e¥me ALE LZ -Shl-2207 Agzae H.Kyaw |AEA |6.7977 Elie A Mavabssinp.'AeA oot Lavy Cdl "PAU S YSG-GAER (YatAin Rio ve Guaa 482 INT fe FRR LVER rT ae atl AECET 745-F 26% Fu Loves C EAS Ge e-4ry¥2 ML&P GENERAL MANAGER FAX NO,9072636204 P,O1 , OF FIVER oY \\l/ 0 D>1 MNT -6 P1343 WZC3MunicipalitycantaMunicipa:|Light &PowerNS7TomFink,Mayor La,1300 East ropaanAnchorage,Alaska 99501-16831907)270-7671,Telecoprars:(907)276-2961.277-9272 TRANSMITTAL SHEET MUNICIPAL LIGHT &POWER ADMINIS #:(907)263-8204KN MaR-6-91 WED 13:34 pe:3 E -FI FAX:SBI-8584|AREAL KAW,Aan ane nerend blenaiens FRM:Mes”Ase,Plann NG ENGiAzeR set:RSC Meeting minutes DRAFT THIS DOCUMENT CONTAINS 3 SHEETS ({NCLUDING THE COVER SHEET).IF YOU WISHOoTOVERIFYRECEIPTOFTHISDOCUMENTORYOUDIDNOTRECEIVEALLSHEETSINDICATED PLEASE CALL -§Mé AT (907)279-7671,EXT,SU4G,MANY THANKS! lease asview y Comment +LeTHeVv "To Me Via FAX.=THAwiea,=Mog Oo Putting Energy Into Anchorage 0 MAR-6-91 WED 13:35 ML&P GENERAL MANAGER FAX NO.9072635204 P,02 DR AFT ALASKA INTERTIE OPERATING COMMITTEE RELIABILITY SUBCONNITTEE MEETING AT +Chugach Electric Assoc, March 1,L971 BRRKHARSSBHHKEHBRREMERTING MINUTES48SERKERSERREKREE FRESENT: Mike Massin Chugach Electric Association Dave Burlingame Chugach Electric Association Jim Smith Golden ''alley Electric Associatien Jim Hall Manatuska Electric Associatian Afzal Khan Alaska Energy Authority Moe Aslam Anchorage Municipal Light &Power The meeting was called to order sy Chairman Mike Massin at 1315 PM in the CEA Engineering conference rocm.,The agenda items were resd by Mike as follows and the Subcommittee prateeded with the sessian. 1.Reactor'Load Resistcr at Douglas Substation, 2.Dynamic System Monitor Installation. 3.P.T.I.Transmission Analysis Software, Urder the first item Jim Hall reported thet As has been in contact with the Reastor manufaectwrer "TRENCH"whe have quoted a cost of $75,000 for the three 2.5 MUQR reactors.The installed cost estimateis$117,000.A feasibility etudy to verify the exact size is pending. Moe Aslan moved that the Subcommittee recommend to the [.0.C.to hald off additianal work on this subject till the Alaska State Legislature has selected the [nterie upgrades.Jim Hall seconded and the mation was adopted unanimoualy, Dave Eurlingame reported on the DSMs status.They have been orderedandareexpestedtoarriveinAprilorMay.Dave Burlingame af CEA and Jim Smith of GVEA added that their utilities have scheduled the DSM installations for July 1791 at Tealand and Goldhill subs. It was aleo noted thst she 1.0,C.will bear the costs. The Subcommittee eddressed the PTI software purchase and Dave Burlingame moved that a recommendation Be made to [.0.C.that the Intertie affected Utilities iointly purchase copies of the PT! Transmission analysis PC-3&6 tased software and discontinua the use of the Elestrocon VAX based software at the UAF by May 1,1991. Afzal Khan seconded and the woation was adopted unanimously- Jim Hall moved that the Subcommittees recommend to the [.0.C. not to renew the database manadqement contract with UAF,since Urilities will manage their own databases with PTI software. Jim Smith seconded ard the mation was adopted unanimously. 0 MAR-6-91 WED 13:36 ML&P GENERAL MANAGER FAX NO.9072636204 P,03 DRAFT Mike Massin added another item that 1.0.C.ask UAF to define some different role to the !.0.C.and the Reliability Subeommittes such as halding training seminars ang participation in the Alaska Annual engineering and Operations ctanference,eta.Mike Massin asked the members for commants.The mambers concurred that this recommendation should be forwarded to the 1.0.0,Moe Aslam seconded and the mation was sccepted unanimously. Moe Aslam summarized the formal recommendations to the I.0.C. as follows. 1.Held off any additional werk on the Reactor till the Legislature has decided on the Intertie options. 2.Propose to the Intertic affected Utilities,especially CEA,GVEA,NL&P and aleo AEA to jointly purshase the PTI Transmission Analysis saftware copies designed to run an PC-386 machine. 3,Do not renew the database management contract with the UAF. 4.Ask UAF to propese a different role in research and training for the Railbelt utilities,the [.0.C.and the Reliability Subcommittee. Mike Massin approved the recommendations and thse members concurred. Having completed the agenda items and discussions,Mike moved that the meeting be adjcurned.Dave seconded and the Subtommittes adjourned till the next meeting to be scheduled after the [.0.C. meets this month in Fairbanks. Anchorage,Alaska0RECEIVEDCHUGACHELECTRICASSOCIATION,INC.BAAD 31HAD0419 February 27,1991NaskaEnergyAuthority TO:Relay/Protection Subcommittee FROM:David W.Burlingame,Manager,pacilities Engineeringx SUBJECT:Meeting Minutes of February 21,1991 Below are the meeting minutes of February 21,1991 on the Underfrequency loadshedding study being done by Power Technologies, Inc.(PTI).Reference PTI letter dated February 1,1991: Attendees:D.Hall,ML&P .A.Khan,AEA L.Hembree,ML&P S.Haagenson,GVEA S.Matthews,HEA J.Hall,MEA D.Rogers,Chugach J.Doudna,PTI Chugach Electric Association,Inc.(Chugach)will supply a SCADA snapshot of its system,including Douglas,that will show all real and reactive power flows immediately preceding the event.Chugachwillalsoconfirmwhichofit's reactors and capacitors were on-Oo line and the MVAR output of the Teeland SVS.GVEA will confirmwhichofitsreactors/capacitors were on-line and the MVAR output of the northern SVS systems. ML&P confirmed that Sub 10 did not have any load at the time of thedisturbance. GVEA confirmed no generation was present at Healy at the time ofthedisturbance. GVEA gave the following tie line flows:UAF -open prior to,during,and following disturbance;Eilson 0 MW,0 MVAR prior to, tripped during event,had one 10 MW unit on-line,trip settings are at 59.8 with an 18 cycle delay;Ft.Wainwright 2.4 MW into GVEA, 1.4 MVAR into GVEA,1-5 MW unit and 1-2.5 MW unit on-line;Ft. Greely 2.2 MW and 1 MVAR out of GVEA,no units operating.Steve Haagenson will check on pump station 8 generation. HEA indicated Tesoro has one unit on-line and did not trip. All utilities will provide the base rating for each of the units in the study. PTI will try and use the data developed in the generation tests for Chugach #8.°If not,PTI will develop some coast downocharacteristicstheyfeelareappropriate.The utilities suggestedusing75%of the time constant developed in the tests as a conservative approach. Relay/Protection SubcommitteeFebruary21,1991 Meeting Minutes February 27,1991 Page 2 The simulation should be run for 60 seconds.ML&P can furnish a copy of a frequency chart for the event.oe 4.5 MW of Chugach load was shed at both University and International Substations.aa : GVEA supplied at the meeting an actual copy of the loadsheddingscheduleinserviceatthetime. GVEA gave a formula for determining the effect of AGC on unit set- points.Chugach and ML&P need to supply the equivalent. The formula for determining the spinning reserve requirement for each utility was given to PTI. In the priority of GVEA generation,the following schedule should apply;Zhender first,Zhender off and one North Pole on,then North Pole with one Zhender,then two North Pole with Zhender off,then two North Pole with Zhender.PTI should use this order in adjusting generation for each of the cases. It should be assumed for purposes of this study that all northern area spinning reserve requirements are carried by GVEA. GVEA supplied new generation schedule to be used to 0 the MW flow over the intertie. Case IIa will use two North Pole units Case IIb will use one North Pole,one Zhender with loadshed to meet spinning reserve at 59.7 Hz with a 2 second delay. Case IIIa -PTI will look at either reducing the load in the Fairbanks area to zero the tie or adding a 0 inertia turbine in the Fairbanks area to 0 the tie.All spinning reserve in the northern area will be by loadshed in one stage at 59.7 Hz at 2 seconds. PTI understood the intent of all three cases.They believe the cases could be run within 2 weeks of receiving the requested information. The utilities agreed the cases are not binding but will be used to develop further cases into loadshedding scenarios. DWB/pn DWB4:febld.shd cc:File 1060.01 -_"\r POWER TECHNOLOGIES,INC.ONE SIERRAGATE PLAZA SUITE 3408 ROSEVILLE,CA 95678 916 783-3566 TELEFAX 916 783-2086 TELEX 145498 0 February 1,1991 R ECE]VED Mr.Afzal Khan FEB 04 199] Alaska Energy AuthAldtka EnergyP.O.Box 190869 'Authority Anchorage,AK 99519-0869 Dear Afzal: RE:Load Shedding Study We have reviewed the November 21,1990 proposal signed by the Intertie Operating Committee concerning additional load shedding studies which PTI is to conduct.We discussed this a little in December,and I noted some additional information and clarification of a few items which I needed before the study proceeds.As per the meeting we had today,I am writing this letter is to clarify and more completely document our previous information request.I have morere)thoroughly reviewed the study proposal,and my information request has expanded somewhat. The first aspect of this additional load shedding study is to duplicate actual system performance during the August 29,1990 event.Therefore,we need to be sure that we correctly represent the system conditions which existed at 1300 hours on this date.To accomplish this,we need the following additional information: 1)What was the watt and var flow on the University to Daves Creek 115 kV line (at University)? 2)What was the watt and var flow on the Teeland to Cottle 115 kV line (at Teeland)? 3)Please indicate which reactors and capacitors were on-line.Please confirm reactor and capacitor Mvar amounts.Also confirm the status and var level on the three SVCs. 4)Please confirm which lines were open or out of service. 5)The AML&P flow diagram you provided does not specify a load value forOoSub10(either zero or non-zero).Please provide the correct amount of load to represent at Sub 10. CORPORATE OFFICES ¢1482 ERIE BOULEVARD *PO.BOX 1058 *SCHENECTADY,NY 12301-1058 ©518 374-1220 --"\pr- 0 Page 2 Mr.Afzal Khan February 1,1991 6) 7) 8) 9) No generation was indicated at Healy.Please confirm that this is correct. Total sales at Teeland going north was indicated to be 53 MW.Does this include power to serve the MEA load at Douglas? What was the var flow at Teeland on the 138 kV line? Please provide the net watt and var flow into the military bases and the university in the Fairbanks area.Please provide the amount of generation which was on-line at each location (i.e.,number of units and total generation). To facilitate running the actual study scenarios,we will need some additional information and clarification of a few items in the proposal.These are as follows: 1) 2) 3) 4) 5) 6) 7) Please provide a list of each Railbelt unit's base unit rating (MWs)for the time frame under consideration. Please provide the "coast down”characteristic you wish us to use for Beluga Unit 8. Please give an approximate indication of the length of simulation time we need to run.That is to say,in the actual situation,did load shedding occur within the first few seconds,tens of seconds or minutes following the unit trip?Can you provide us with a recorded time versus frequency plot for this event? The proposal indicates 4.5 MW of Chugach load was tripped at "each station”.We assume this means International and University.Is this correct? Should we assume that the GVEA/FMUS load which was shed was in the Fairbanks metro area rather than at the extremities of the system? Please provide us more information about the AGC control of governor set points.Which machines respond?Is it a single step change or a series of pulses?Please be as specific as possible as to how the AGC algorithm works. In the actual event,did the military bases and the university in the Fairbanks area remain with the system or did they separate from it?If they separated,please provide us with the details. ---"p- Page 3 Mr.Afzal Khan0February1,1991 8)For Cases II (a)&(b),is the Fairbanks area spinning reserve obligation the same (30 MW)?How do you calculate the Fairbanks area spinning reserve obligation? 9)For Case II (a),is there a "target"intertie flow value you are interested in or just what ever results from the generation changes indicated?Please indicate what you mean by "displace power flows over the northern intertie".To what level?I calculate only 7 MW of intertie flow if we use the suggested generation changes.This does not seem substantially different than the zero intertie flow condition in Case III (a). For Cases II &III,does the following summarize the information you are after?If so,it appears it would be possible to essentially combine Cases II &III. °Frequency response with Fairbanks area actual spin in excess of spinning reserve obligation and no load shedding of any type active anywhere in the Railbelt system °Frequency response with Fairbanks area actual spin only partiallyre]covering the spinning reserve obligation and the remainder provided through 2-second delay load shedding;load shedding elsewhere in the Railbelt system inactive e Same case as immediately above,but with load shedding elsewhere in the Railbelt system active °Frequency response with Fairbanks area actual spin equal to zero and all load shedding provided through 2-second delay load shedding; load shedding elsewhere in the Railbelt system inactive °Same case as immediately above,but with load shedding elsewhere in the Railbelt system active I believe the above cases will ferret-out whether or not 2-second delay load shedding: (a)can partially substitute for actual spin,or (b)is as good or better than actual spin. If the above is what you are after,it would be best to do all evaluations starting with the same intertie flow and the same Fairbanks area load.I need to give thisoOsomemorethought,but my initial idea for accomplishing this is as follows: --/\pr- Page 4OMr.Afzal KhanFebruary1,1991 (a)set up the loadflow with Chena 5 and North Pole (1 unit)at their maximum output level (b)then,scale the Fairbanks area load (limit load scaling to the metro area where the transmission system is more coherent)until the intertie flow (at Douglas)is zero This would be the "no Fairbanks spin"case. To simulate cases with Fairbanks spin,create a fictitious,high impedance,zero inertia,zero var output,classical machine at,say,the Ft.Wainwright 138 kV bus. Adjust the generation on this fictitious machine to provide spin on North Pole and Chena 5,and to allow Zender 1 to be brought on-line.This could be done while maintaining the same intertie flow.The fictitious machine would not affect system frequency decay and would have minimal affect on voltage. Please contact me if you have any questions or if you would like to discuss this project further.I will be out of the office February 6,7 and 8,but will be back theOo11th. Sincerely, John H.Doudna,P.E. Senior Engineer JHD: cc:H.K.Clark D.W.Burlingame S.H.Haagenson L.Hembree DATE: TO: FROM: SUBJECT: 01\N09981(1) Alaska Energy Authority February 26, MEMORANDUM 1991 Stanley £.Sieczkowski,Director Facilities Operations &Engineering Afzal H.Khan,Manager MeloEngineeringSupport Alaska Intertie Preliminary FY92 Budget Revised:2/26/91 f/'7 ut.cae The table below summarizes the budgeted expenditures by typefortheAlaskaIntertieduringFY92: Operations: Maintenance: ALASKA INTERTIE FY92 BUDGET Northern Area Controller (GVEA) Operation Labor SCADA Debt.Service SCADA Maintenance Southern Area Controller (ML&P) Operation Labor SCADA Debt.Service SCADA Maintenance Intertie Operating Committee Data Base ManagementAnalysisandReviewAlaskaEnergyAuthority (AEA) Northern Area Contractor (GVEA) Transmission Line Maintenance Substation Maintenance Southern Area Contractor (MEA) Transmission Line Maintenance Substation Maintenance Talkeetna Material StorageTeelandSub.Contractor (CEA) Miscellaneous:Transmission Service (MEA)! TOTAL lestimate AHK:SES:jd cc:Gloria Manni, Info.Services,Telecommunication Repair &Replacement Insurance Bill Sobolesky,Accountant $209,615 $65,723 $21,284 $216,906 $39,314 $24,534 $40,000 $80,000 136,935 40,364 $ $ $130,856 $ $ Director/Accounting &Administration $296,622 $280,754 $120,000 $184,763 $177,299 $147,236 $17,607 $100,225 $28,800 $125,000 $70,000 $1,548,306 FY1992 Minimum Intertie Transfer Capability Rights (MITCR) Determination Annual System Demand (MW) Three Years 1988-89 1989-90 1990-91 __Average_ cea4 216.0 199.6 213.8 209.8 AEG&T 163.8 HEAL 72.3 74.0 72.0 MEAS 100.3 86.3 86.6 ML&P2 146.0 140.0 142.0 142.7 Southern Group Utility Participant Total 516.3 GVEA 95.1 94.0 96.5 95.2 FMUS3 29.8 29.5 29.8 _29.7 Northern Group Utility Participant Total 124.9 Determination of the MITCR: CEA 209.8/516.3 =0.40 28.00 MW AEG&T 163.8/516.3 =0.32 22.40 MW AML&P 142.7/516.3 =0.28 19.60 MW GVEA 95.2/124.9 =0.76 53.20 MW FMUS 29.7/124.9 =0.24 16.80 MW 140.00 MW IHEA letter to Alaska Energy Authority dated January 31,1991.2ML&P letter to Alaska Energy Authority dated February 15,1991.2GVEA letter to Alaska Energy Authority dated February 14,1991.4cEA letter to Alaska Energy Authority dated February 12,1991.Sper Jim Hall,MEA,dated February 22,1991. Alaska Intertie Intertie Energy Usage (Mwh) FY1992 Month GVEA FMUS ML&P CEA Estimate Estimate July 1991 39,100 __ Aug 20,995 _ Sep 27,411 -_-. Oct 26,539 __ Nov 31,148 10 Dec 7,092 10 January 1992 7,894 10 Feb 2,310 10 Mar 29,573 __ Apr 22,506 -_- May 21,728 _ June 28,460 __ Total 264,756 0 0 40 Total intertie energy usage:265 Gwh N1\.1NNINK 19\ State 2f a asxaNNalter,='Ccxe@ 3c.e7s" Alaska Energy Authority A Public Corporation January 31,1991 Mr.Robert Orr Manager of System OperationsGoldenValleyElectricAssociation P.O.Box 71249 Fairbanks,Alaska 99707-1249 Subject:Anchorage-Fairbanks Intertie Outage and Maintenance Reports Dear Mr.Orr: The Energy Authority does not have all of the outage reports from pastoutagesontheIntertie.The Energy Authority would like to obtain al]past outage reports to be used in evaluating the current line problems.Also please provide outage reports for all future outages as required in the maintenance agreement.If a procedure for reporting outages andspecifyingtheinformationtoprovideneedstobedevelopedthenperhapsweshouldgettogetheranddiscuss. Please call me with any questions at 561-7877. Sincerely, Stanley é 4 owski,Director Facilities Operations &Engineering EM:SES:jd cc:Afzal H.Khan,Alaska Energy AuthorityEricMarchegiani,Alaska Energy Authority i)PO.Box AM Juneau,Alaska 99811 (907)465-3575 PO.Box 190869 704 East Tudor Road Anchorage,Alaska 99519-0869 (907)561-7877wnaat7ala\i-) pryrwthes State of AiaskaDNWaiterJHickeiGovernor Alaska Energy Authority A Public Corporation February 5,1991 Mr.John Cooley Municipal Light &Power 1200 E.First Avenue Anchorage,Alaska 99501 Subject:Anchorage-Fairbanks Intertie Outage and Maintenance Reports Dear Mr.Cooley: The Energy Authority does not have all of the outage reports from pastoutagesontheIntertie.The Energy Authority would like to obtain al]past outage reports to be used in evaluating the current line problems,along with providing future outage reports.If a procedure forreportingoutagesandtheinformationrequestingisneededtobedevelopedthenperhapsweshouldgettogetherandresolvetheissue. Please call me with any questions at 561-7877. Sincerely, Wope.1 Clean.heStanleyE.Sieczkowski,Director Facilities Operations &Engineering EM:SES:jd ccs [S PO.Box AM Juneau,Alaska 99811 (907)465-3575 weer 190869 701 EastTudor Road Anchorage,Alaska 99519-0869 (907)561-7877 GOLDEN VALLEY ELECTRIC ASSOCIATION INC.Box 71249,Fairbanks,Alaska 99707-1249,Phone 907-452-1151 RECEIVED FEB 15 499] Aiaska Energy Authority February 11,1991 Stan Sieczkowski Alaska Energy Authority P.O.Box 190869 Anchorage,AK 99519-0869 Subject:Bradley DECnet Interface After another review of our recommendations to put the Bradley linkbetweenCEAandAMLP,we have changed our minds.We feel a better choice would be to put the Bradley link between GVEA and AMLP. While the original recommendation appeared to be a logical placementofthenodeasfarasphysicalpathsareconcerned,we do not think it would be good for GVEA.Both the AMLP and CEA SCADA computers are small PDP's,and we are already experiencing long delays inestablishinglogicallinkstotheAMLPcomputer.Increased routing traffic would only slow that computer further.Additionally,we aretheBradleyparticipantvoicingthemostinterestinBradleydata.Therefore,I would ask to have Bradley added as an adjacent node to our SCADA computer.CEA would likely not oppose this because theywillhaveanRTUatBradley.AMLP would be relatively unaffected because their computer could also be an adjacent node to Bradley. Manager of System Operations cc:John Cooley -I0C Chairman Steve Haagenson Marvin Riddle Fred LeBeau Garo y CowPicueaT lon WY Municipal Light &Power 1200 East First Avenue Anchorage,Alaska 99501-1685 (907)279-7671,Telecopiers:(907)276-2961,277-9272 Mr.Stan Scieczkowski RECEIVED Alaska Power Authority P.O.Box 190869 FEB 9 2 1991 9 -08Anchorage,Alaska 9 piaska Caray Authority February 19,1991 Dear Stan: Subject:Alaska Intertie Accounting Upon review of the December 1990 Alaska Intertie Accounting Report,I noticed an error in the Accrued Liability/Expense section.Footnote 3 states "surplus apportioned by energy purchases."That is not correct as section 8.4.5 of the contract states: "Should APA's annual revenues received under Subsection 8.4.1 (which includes both capacity and energy payments)of this section exceed actual Intertie costs,revenues in excess of the Intertie costs shall be refunded to the contributing participants in proportion to the amount of dollars billed to Participants to the total dollars billed for use of the Intertie in the fiscal year in which the revenues were accrued." The underline portion was added for clarification.Therefore the surplus of $304,713 should be apportioned in relation to the Total expense,and ML&P's share would be approximately $8,652. Sincerely, \D800.John S.Cooley, Manager,Power Management cc:I0C members T.R.Stahr JC:jc Putting Energy Into Anchorage REO na Alaska mo oy muinority |J GOLDEN VALLEY ELECTRIC ASSOCIATION INC.Box 71249,Fairbanks,Alaska 99707-1249,Phone 907-452-1151 February 28,1991 Stan E.Sieczkowski,Director Facilities Operations &Engineering Alaska Energy Authority P.O.Box 190869 Anchorage,Alaska 99519-0869 Subjects John Cooley's February 19,1991 Letter Alaska Intertie Accounting John is incorrect in his interpretation of subsection 8.4.1.The key word here is "use"of the intertie. Refer to 8.4.1.1,the energy scheduled use of the intertie. Also,refer to 8.4.4,for billing purposes only the scheduled use of the intertie. AEA is properly interpreting the contract.The first year theintertiewasinserviceitwasagreedthatthemeaningwas'clearly based on excess revenues from scheduled use of the intertie,notcapacitypayments.Further,I was present during the negotiationsforthiscontract,and that was the intended meaning from the start. SEL .i ----Manager of System Operations ,_CORRESPONDENSE B STRIBUTION:ACTION: cc:I0C Members Mike Kelly Robert Hansen Marvin Riddle afurucipality of Anchorage Municipal Light &PowereTom:Tom Fink,Mayor 1200 East First Avenue Anchorage,Alaska 99501-1685(907)279-7671,Telecopiers.(907)276-2961,277-9272 RECEIVEDFebruary19,1991 Mr.Stan Scieczkowski Alaska Power Authority P.O.Box 190869 FEB 2 2 4991 Anchorage,Alaska 995 1 e Serenergy Authority Dear Stan: Subject:Alaska Intertie Accounting Upon review of the December 1990 Alaska Intertie Accounting Report,I noticed an error in the Accrued Liability/Expense section.Footnote 3 states "surplus apportioned by energy purchases."That is not correct as section 8.4.5 of the contract states: "Should APA's annual revenues received under Subsection 8.4.1 (which includes both capacity and ener ayments)of this section exceed actual Intertie costs,revenues in excess of the Intertie costs shall be refunded to the contributing participants in proportion to the amount of dollars billed to Participants to the total dollars billed for use of the Intertie in the fiscal year in which the revenues were accrued." The underline portion was added for clarification.Therefore the surplus of $304,713 should be apportioned in relation to the Total expense,and ML&P's share would be approximately $8,652. Sincerely,g./-4)= ,i Q mm \fog 6 John S.Cooley, y- Manager,Power Management TR pap Alarag,ppl OT cc:IOC members ppt"T.R.Stahr f oe pone egy Pn 4 on.Fo)°Lerton.on sai>ae ie LoePuttingEnergyIntoAnchorage!_,Va WA LtpeeTEDraeYa,: CO.LIAM fa2e .,RK Lar wor 'e0GY GOLDEN VALLEY ELECTRIC ASSOCIATION INC.Box 71249,Fairbanks,Alaska 99707-1249,Phone 907-452-1151 -_-/ RECEIVED FEB 28 1991February22,1991 a Energy Authoritypiask Mr.Donald L.Shira,Secretary Alaska Intertie Operating Committee Alaska Energy Authority PO Box 190869 Anchorage,AK 99519-0869 Dear Dons: Enclosed are GVEA's copies of current proof of insurance required to©)be submitted to AEA and the Intertie Operating Committee every year. If you have any questions,give me a call. Sincerely, Kibet KlannRobertJ.Hansen Manager of Administrative Services Enclosures -y ACORD.INSURANCE BINDER panel,0 DECEMBER 8,1990THISBINDER1SATEMPORARYINSURANCECONTRACT,SUBJECT TO THE CONDITIONS SHOWN ON THE REVERSESIDEOFTHISFORM. PRODUCER COMPANY BINDER NO. ARECA INSURANCE MANAGEMENT,INC.ARECA INSURANCE EXCHANGE "SEE BELOW703W.TUDOR ROAD,SUITE 200 DATE TIME DATE TIME AM 12:01 AANCHORAGE,ALASKA 99503 o1yors91 12:01 & gsystygn X28 THIS BINOER IS ISSUED TO EXTEND COVERAGE IN THE ABOVE NAMEDCODESUB-CODE COMPANY PER EXPIRING POLICY NO: DESCRIPTION OF OPERATIONS/VEHICLES/PROPEATY (Including Location) INSURED GOLDEN VALLEY ELECTRIC ASSOCIATION,INC.RURAL ELECTRIC COOPERATIVE P.O.BOX 1249 . FAIRBANKS,ALASKA 99707 RECEIVED COVERAGES ,SANS iSSt LIMITS TYPE OF INSURANCE COVERAGE/FORMS AMOUNT DEDUCTIBLE -COINSUR. PROPERTY CAUSES OF LOSS GVEA -Admin.ServicesBASICBROADSPEC. |GENERAL LIABAITY GENERAL AGGREGATE $2,000,000 COMMERCIAL GENERAL LIABILITY PRODUCTS -COMP/OP AGG.$2,000,000CLAIMSMADE=y_-:OCCUR PERSONAL &ADV.INJURY $1,000,000 OWNER'S &CONTRACTOR'S PROT.EACH OCCURRENCE 1,000,000 FIRE DAMAGE (Any one fire)$50,000 RETRO DATE FOR CLAIMS MADE:MED.EXPENSE (Any one person)$5.000OnaLIABILITYCOMBINEDSINGLELIMIT$1,000,000 4 ANY AUTO BODILY INJURY (Per person)$s ALL OWNED AUTOS BODILY INJURY (Per accident)$ SCHEDULED AUTOS PROPERTY DAMAGE $ X HIRED AUTOS MEDICAL PAYMENTS $s 5,000XNON-OWNED AUTOS PERSONAL INJURY PROT.-s $ GARAGE LIABILITY UNINSURED MOTORIST 5 1,000,000 $s AUTO PHYSICAL DAMAGE DEDUCTIBLE ALL VEHICLES SCHEDULED VEHICLES ACTUAL CASH VALUE COLLISION:STATED AMOUNT $ OTHER THAN COL:OTHER EXCESS LIABILITY EACH OCCURRENCE $ UMBRELLA FORM AGGREGATE OTHER THAN UMBRELLA FORM RETRO DATE FOR CLAIMS MADE:SELF-INSURED RETENTION =$ STATUTORY LIMITS WORKER'S COMPENSATION EACH ACCIDENT $500,000 EMPLOYER'S LIABILITY DISEASE-POUCY LIMIT $s 500 ,000 DISEASE-EACH EMPLOYEE $s SON O00 SPECIAL CONDITIONS/OTHER COVERAGES GL_EXCLUSIONS INCLUDE BUT NOT LIMITED TO:*POLICY NUMBERS AND ESTIMATED PREMIUMSABSOLUTE_POLLUTION ANTI-STACKING ENDORSEMENT GL9 10080091 237,850FAILURE_TO SUPPLY INVERSE CONDEMNATION AL9 10080092 26,612AIRCRAFTLIABILITYwC910080093$192,071 NAME&ADDRESS MORTGAGEE ADDITIONAL INSURED LOSS PAYEEOoLOAN AUTHORIZED REPRESENTATIVE ACORD 75-8 (7/90)©ACORD CORPORATION 1996 ISSUEDBY NY0ntce WORLDWIDE FACILITIES,INC. TELEX:67289 ASSURANCE LSA 3530 WILSHIRE BOULEVARD /LOS ANGELES,CALIFORNIA 90010 /PHONE (213)380-4670 sinver 15202 THIS IS TO CERTIFY that the undersigned have procured insurance as hereinafter specified from: General Star National Insurance Company Assured:Golden Valley Electric Association,Inc.(ARECA) Address:Post Office Box 1249,Fairbanks,Alaska 99707 Amount or Limits $5,000,000 Each occurrence and in the aggregate where applicableexcessofunderlying. Coverage:Follow Form Excess Liability .° Remarks:Assigned Policy Number:NXG 170413A Policy Period:January 1,1991 to January 1,1992 Policy Premium:$146,658.Flat,plus State Taxes* 25%Minimum Retained Premium *Broker is responsible for collecting and filing State Taxes applicable to the State of Alaska. NO FLAT CANCELLATION ALLOWED The above insurance is subject to the conditions and terms of the current Certificate(s)now in use by Underwriters and/or Insurance Companies.This BindermaybecancelledatanytimebytheAssuredortheUndersignedgivingtheothernoticeinwriting. Beginning at 12:01 A.M.onthe Ist day of January 1991 and ending at 12:01 A.M. the 14th dayof February 1991 Date of Issue 1-3-9]By DDM/zh Vill bn,INC.Producer:°Corroon &Black,Inc.By. CHUGACH ELECTRIC ASSOCIATION,INC.nga ASSOCIATION.INC.RECEIVED FEB 25 1991 Autnority Alaska Energy Authority ipsaska EnersyP,O.Box 190869 : Anchorage,Alaska 99519-0869 wee February 19,1991 Attn:Mr.Afzal Kahn RE:Preliminary Design for Teeland Substation -75MVA Transformer Installation CEA Account #107.194,90/91,WP#1000.084 Dear Mr.Kahn: Chugach Electric plans to install a 75 MVA,138/115/34.5 kV autotransformer to serve aS an emergency supply to the MEA 115 kV system,should the 250 MVA,230/115 kV main transformer fail.Construction is scheduled to begin in late August 1991, with a completion date of October 15,1991. The transformer is to be connected to the Alaska Energy Authority's 138 kV transmission line and the Chugach/MEA 115 kV transfer bus at Teeland Substation.Connections to the Alaska Energy Authority's 138 kV transmission line,modifications to other existing facilities and new construction are shown on the attached one-line, layout and elevation drawings. Please review the attached material and provide us with any necessary input you may have by February 28,1991. If you have any questions,please call our Project Manager,Dora Gropp at 762-4626. Sincerely, LN)o-Michael E.Massin,Director,Engineering CHUGACH ELECTRIC ASSOCIATION,INC. Attachments cc:Dora Gropp Scott Girard Dave Burlingame MEM/SG/ck SG095 5601 Minnesota Drive *PO.Box 196300 «Anchorage,Alaska 99519-6300 Phone 907-563-7494 «FAX 907-562-0027 7S MVA_Transfiaemer Tact.llatiaan vier te a motes secv ve ta manne -{|'Bh 138000/115.000- 45 [60f7S5000 KYAt ante 34 3B kV 34500 V yeu vvvY Wyn »2820,600/115.008-34,Seeu160720072e0nA3eseo/Sova TELAT.4,300-u whe F \ex aoaae tenn aia]te | il} N _]PEt -ES farsa 1b aleteiored gr etna gatncd 4 |pews bat ve 0 Prad qwes wa cannucnal ol oa =[ow nie w lee]wey )ot ots 3] ovation SERVIER $3.000-120/200"sry am em 4 soar oe)ns[7]wii LeGan)an - 9/64/84 MORRISON-KNUOSEN ENGINEERS.INC,. :ieee TEELANO 4705-16-01SereamewesantareceCheegachire,mre "230/11SKV SUBSTATION -us-w-perSWITCHINGDIAGRAMertyFa 42 381 50 SHEETS $$MM |LAGS 200 SHEETS 3 SSUARE see Fiquie 4N-t>For elesdhon 138KV To Douglas i Sub. Conf eel TO ensfieg SKY building teansfer bus-y e ad hae ZBokY Frew Pq.Vx microwaveMachen2i¢tower necgial(no 3 )P)aD P ahadwvT ro YON 1 Tnstul Dbl..;al le ;u -wd Decolend wert "<p-f 'os! {0°top.¢,YPy?3 4 *SadI¥2"los!\..\ . meting aad Iie heme ----Nae oe L a tet ee a a a ae ee we +>AEA xen?Proposed New Concteucdion SVS te.Contre!@!Cudding see Figure 3 for elevator Layout -Teeland Sub 7S MVA XFMR Tostelledio,NTS.T>AEA XFAIR. Figure 2 43302 180 Sues 3 SQUAREae42.389 200 SHEETS 5 SQUARENATIONALfeaude N mm K--_--28' 'Exshny 250Kv16AoncigrdLustellDetos43,4 5DeedeadunthPy,\40°hep mn ,> Caching hime ,Kastellh Wan Sdmia /bus Yj |Tm.)_Lvstull lSkev stain bus/hero Teei ee _.ne-4 Fimo] 34°-f a |24!;30 as al ;oe Lh ee ee |] vehicu for AS Loctan stee]Tastell ctee)4cemaretebe.Suppet Shots Install oliscouned sutch,becker,Trang[seaas cuppert ctraAasemeaninaned.Qnol bus Suppord Sirucfure K a 340°ce ceee ce eee Sectron A-A Elevation -Tealand Sub 7S MVA XFMR_Tastellotion NTS |<r)2 MSKY Strain Bus ry To existirg {US ky Transfer bus 28!min Tastell olisvonnect suntch cowl bus suppoet stucure. Sevtion B-B |Elevation -Teeland Sub.75 MUA VEMR Leshelledio ATS Fia ur.a MAR-13-91 WED 9:23 ML&P D.SPATCH FAX NO,9072762961 P,02 GY GOLDEN VALLEY ELECTRIC ASSOCIATION INC.Box 71249,Fairbanks,Alaska 99707-1249,Phone 907-452-1151 February 26,1991 Municipality of AnchorageMunicipalLightandPower Department1200EastFirstAvenue Anchorage AK 99501-1665 Attentions John CooleyIntertieOperating Committee -Chairman Re:Reappointment of Golden Valley membertotheReliabilitySubcommittee Dear Johns: Goldan Valley would like to change their representative on the I0CReliabilitySubcommitteefromStevénHaagensontoJamesR.Smith. Jim is a Professional Engineer whom has been with Golden Valley forthepast15years.Jim is presently a Senior Engineer in charge ofdesignandconstructionofallelectricalsubstations,interfaces,code compliance,and controls. I feel Jim will be a valuable addition to this I0C Subcommittee. Thank you for your attention to this matter. Sincerely, sORy-- Steven Haagenaon,P.E.Manager of Engineering Services SH :mnft Enclosures cc:Mike Kelly -GVEABobOrr-GVEA Jim R.Smith «GVEA SHimmf Alaska Energy Authority 4 Puolic Corperatior January 29,1991 Mr.Robert Orr Golden Valley Electric Association P.O.Box 71249 Fairbanks,Alaska 99707-1249 Subject:Proposal for Geotechnical StudiesonStructure#749 Foundations Dear Mr.Orr: Please reference Mr.Swift's letter of 1/16/91 (copy attached)to Mr.Remy Williams concerning the above subject and their recent conversation.We concur with the contractor's proposal and budget andagreetoyourproceedingtoinvestigatetheproblematstructure#749 thru this contractor. A savings can be realized if GVEA could administer the helicoptercontract.The overall cost could be reduced by the contractor's mark-up of $2,625.Please investigate and determine the feasibility of this approach. It is our assumption the funding for this and the repair will come fromtheRepairandReplacement(R&R)reserve account.This should bediscussedinmoredetailatthenextIntertieOperatingCommittee(I0C) meeting so all involved will be kept informed of investigation in repairs recommended and costs required to make the fix. Please provide progress reports of the investigation and recommendationsaswellasacopyofthefinalreport. Thanks for staying on top of this developing problem. Sincerely, Stanley E.VSi owski,Director Facility Operations &Engineering EM:SES:jd 'ad Energy AuthoritySteveSwift,Golden Valley Electric Association PO.Box AM Juneau,Alaska 99811 (907)465-3575 PO.x Box 1908469 704 EastTudorRoad Anchorage,Alaska 99519-0869 (907)561-7877 oY GOLDEN VALLEY ELECTRIC ASSOCIATION INC.Box 71249.Fairbanks,Alaska 99707-1249.Phone 907-452-1° January 16,1991 RECEIVED JAN 22 1991 Remy Williams Aisska Energy Authority Alaska Energy AuthorityP.O.Box 190869 Anchorage,Alaska 99519-0869 Dear Remy: Enclosed you will find a proposal for geotechnical studies of thesoilatStructure#749. Please review this document and get in touch with me at yourearliestconvenience.We need to discuss a plan and a timetable to address this problem. A Steve $wift Line Sgpt. Sip aot»ants<<35 Years ofEngineenngandAppliedGeosciencesExcellence 2055 Hill Road,P.O.Box 843 «Fairbanks,Alaska 99707 *Telephone (907)479-0600 ©Telefax:(907)479-5691 January 11,1991 K-1118 Golden Valley Electric Association P.O.Box 71249 Fairbanks,Alaska 99707 Attn:Mr.Steve Swift RE:PROPOSAL FOR GEOTECHNICAL STUDIES STRUCTURE NO.749 ANCHORAGE-FAIRBANKS INTERTIE Gentlemen: In accordance with your request,we are pleased to submit our proposal for conducting subsurface explorations and foundation engineering studies at Structure No.749 on the Anchorage-Fairbanks Intertie south of Healy,Alaska.We understand that this single pole structure developed a significant downhill list between August and early December of 1990.The purposeofthis study is to determine the subsurface conditions at the site and to assist in the design of stabilization measures and possibly the design of the foundation for a replacement structure. Structure No.749 is a single pole °SA*type tower founded on a ""SAR2°type concrete pier rock foundation.This foundation consists of a concrete pier with a concrete base and 16 Dywidag anchor bolts.A review of the constructiondataprovided suggeststousthatthe foundationwasconstructedonnon-thaw stable,sandy silt permafrostwhich contained excess ice. We believe that it is unlikely that the Dywidag anchors penetrated into bedrock and that they were grouted into silt permafrost. We understand that the site is accessible only by helicopter.We propose to explore the site with a skid mounted,SIMCO 2400 auger equipped with a hollow stem auger.The drill rig would be moved as a single pick with a Bell 212 helicopter.The drill rig and drill tools would be mobilized to the GVEA Healy,Alaska power plant on a flat bed truck.This truck would also carry drummed fuel for both the drill rig and the helicopter.For safety reasons,the rig would be moved only during daylight hours,however,the helicopter could transport the drill crew as long as snow does not obscure visibility. Fevearmm ¢Anchorage ¢Seams ¢®.Lous Ronn 0.Abbou,?.E.Thomas C.Kinney,P.€.Fred A.Brown,Jr..PE.Jonn E.Cronun.CPGSe.Vice Preedent and Manager Vice Preedent Vice Preadert Vice Premcem CONSULTANT Wiliam \..Shannon,?.2. Mr.Steve Swift K-1118 Page2 January 11,1991 At this ime we are uncertain if the crew will stay in Healy or will commute back and forth to Fairbanks via the helicopter.It has been our experience with the super conductor-super collider investigation west of Nenana that it was cost effective to return to Fairbanks every evening due to the daily minimum rate charged by the helicopter subcontractor. At the site our exploration crew would set timber blocking on the sidehill to provide a level platform from which to drill.The drill would then be slung from the helicopter and set on the timbers.The exact location of the borings would be determined in the field.At this time we anticipate drilling one boring well uphill but still within the right-of-way in the vicinity of a replacement structure or a guy anchor for the existing structure.Another boring would be drilled in relatively close proximity to the existing structure on the uphill side,and the third boring would be drilled on the downhill side of the structure. We anticipate drilling borings 25 to 35 feet in depth.The borings would be sampled with split- spoon drive samplers or with dry core rotary techniques on frozen fine-grained soils,as appropriate.If weathered bedrock is encountered,it would be penetrated as deep as possible with the auger.Depending upon what is encountered,we will be prepared to mobilize an air compressor and advance the boring deeper using air-rotary drilling techniques. The drilling and sampling would be observed by an experienced geotechnical engineer or geologist from our firm,who would visually classify all samples in the field and prepare descriptive soil logs for all borings.While at the site our engineer or geologist would also observed the hillside in the vicinity of the tower for evidence of slope movement which could also be a cause of the structure distress.All samples would be sealed in air-tight containers and returned to our Fairbanks laboratory for detailed visual classification and tests that would be pertinent to our studies,such as natural water content,density (frozen unit weight),specific gtavity,and grain-size analyses. The locations and elevations of all borings would be spotted on a map by our engineer or geologist after they had been drilled.This would be accomplished by tape and hand level referenced to the existing foundation pier.If precise surveying is desired it should be accomplished by a professional surveyor.The cost for precise surveying has not been included in our estimate. We plan on placing PVC casing and thermistor strings in at least two of the borings so that Mr.Steve Swift K-1118 Page 3 January 11,1991 ground temperatures at the site can be monitored.A report would be prepared which would describe the field explorations,the subsurface conditions encountered,summarize the laboratory testing results and present the results of engineering studies and analyses.As part of our design studies,we will attempt to contact the transmission line design engineer for the loads on the structure.Our engineering studies will be directed towards assisting GVEA in developing methods to stabilize the existing structure and,if necessary,to design the foundation for a replacement structure. We are prepared to undertake this work as outlined above on a time and expense basis.Our fee for the above work and the terms under which our services are offered would be in accordance with the attached Fee Schedules. Our estimated costs for the project are summarized below: Mob/Demob $2,500 Drilling and sampling $4,500 Field Engineer/Geologist $2,500 Laboratory Testing $1,000 Temperature monitoring instrumentation $1,000 Engineering Analysis and Report $5,000 Helicopter subcontract $17,500 Markup on subcontract $2,625 Estimated total $35,625 If you wish to contract for the helicopter directly you can do so.We have providedhourlyrates for personnel and equipment in the attached fee schedule.Weather may prevent us from working some days and the equipmenton site may become cold soaked and difficult to start. We will do our best to conduct the geotechnical studies in an efficientmannerhowever,this is a difficult site and it will have to be explored at a less than optimum time of year in order to have the design for remedial work ready for spring construction. Our proposed schedule is such that the field explorations could be accomplished during late January or early February.We estimate that the field work can be accomplished in 4 days, weather permitting.We anticipate that the report could be delivered to you within about 2 weeks after completion of the field work. Mr.Steve Swift K-1118 Page 4 January 11,1991 If this proposal meets with your approval,please sign in the space provided and return one signed copy of this letter,which will constitute your authorization for us to proceed with the exploration.The estimated fee for this work is firm for 60 days from the date of this proposal. Should acceptance and authorization for this work come after 60 days,we would want to review our estimated fee to determine if any price changes have occurred which would affect the estimated cost of the project. If you have any questions or comments,or wish to revise the scope of our services,please contact either Steve Adamezak or me.We look forward to the opportunity to work with you on this project and appreciate your continued confidence in our firm. Sincerely, SHANNON &WILSON,INC. py__Rokd,D)NOV aHRohnD.Abbott,P. Senior Vice President Encl:Fee Schedule H-90 &Laboratory Testing Fee Schedule I accept the above conditions and authorize the work to proceed. By Date ==()SHANNON 6 WILSON,INC.Atiacnment 16 and par of Letter Proposal Gectechiical Corsuitans Dated Sancary-tty-t33tAGREEMENTFORPROFESSIONALSERVICEStOrteBansofHestyRetestPonceaunKnownPoksewso«=.Ga lden_WalleySleceric_sscoeiat:P.O.Box 71249 Fairbanks,Ak 9970/7 1.JOMAL SERVICES BY STAFF AND OFFICE Attn:Mr.Steve Swift Fees for services are based on the number of hours expended on the project,including travel,by professional,technical,and defical personne:The fee wil be computed by muttptying the number of hours worked by each dass of personnel by the hourly rate isied below for hal dass See Attachment A and Laboratory Testing Fee Schedule 2 REIMOURSASLEEXPENSESExpensesotherthansalary costs that are directy attributable to our professional services wil be invoiced at our cost plus 15 percent Examoiesincludebutarenotimitedtoexpensesforout-of-town Pavel and living,information processing equipment,ins rumentation and fleid equpmentrental,special fees and permits,premurnsforadditonalorspecial insurance where required,long distance wwiephone charges,local mvieage and parting,use of rental vetices,taxi,reproducton,local and out-of-town delivery semice,express mad,photographs,film,laboratory equernent fees,and job-related shipping charges and supplies. 2.BORINGS,GEQCPHYSICAL SURVEYS AND OTHER EXPLORATIONS,MELO TESTS,LABORATORY TESTS,ANO OTHER CONTRACT SERVICESWhenweengageaconvactor(s)for aniing or offer exploration,les tng,and/or other conwact services,we wil invorce you for fhe convactr'sservicesplus15percentAnexceptonwouldbeworkperformedbyawholly-owned subsidiary of Shannon &Wilson,inc.Thea invoceswillbeincludedinourmvoicewithoutmarkup.Bonngs,geophysical surveys.pile loading wes,plate bearing tess,in situ tes and other feid essconductedusingourequipmentandpersonnelwilbebilledforiaborascomputedunderthefirs!paragraph of this schedule,plus he usage ofOurequipmentafourcurrentequipmentusagerate.Laboratory esis pecformed using our equipment and personne!will be billed at exher(1)the charge for labor,as computed under the frst paragraph of fhe schedse,piss $2 equipment fee for each person-hour of laboratory ws2ng.or (2)currentunitprices,@ specifiedintheproposal. ©YOE_OF SUBCONSLA TANTS AND CONSULTANTSRsagreedthatShannon&Wilson,inc.wil not Bsue subcont acts to subcorsuitants and/or consultants exceeding $10,000 for and part of ieworkhereunderwithoutyourporwnfienconsent,which consent shail not be unreasonably withheld.When sudconsultan'sand/or consuitansareused,fhe wial cost of Mew services wil be marked up 15 percent However,Mr.Witiam L.Shannon is reared fom the frm and «avasabie@88consuftantafarate,without markup,of $115 per hour.or af an otherwise agreed rate. i RIQHTOFENTRYUniessotherwae agreed,you as the "Ciient'wil furnash us with applicable permis and right-ol-eniry on he land and be resporsibie for heproprietyofheime,place and manner of our enty to fhe 610 where we are i make borings,surveys and other explorations.We wi miereasonableprecautionsminimizedamagewhesa@efromuseofequprnent,but Nave not included in ou proposed fee the cost of resiorazanofthesite.N you desire us i reemre the 849 ©1@ approximate former condition (i.e..compacton of beck Mill,pavement patching,resionng lawns.vegetation,et),we mill accomplish fis by contract sernices and add the cos!pius 15 percent to our fee.We mill ove you an estimate for suchfestoraiion,"requested.You agree wb hold us hermiess and defend us from any loss suffered by Shannon &Wilson,inc.arming in connectonwihofrelatedtoouracceestb,entry upon,or the restoravon of he sap,for the purposes described n Pus paragraph. SUREDSTRUCTURESANDUTEITEShereareanyburiedsyucaresandor Vales such a8 sewer,slectic,etc,on land where expiovaten(s)5 ip be made,you wil provide us with&plan showng few existing locators.We and our subconv actors wil we reasonable care and diligence 1 svoid contact wih sfuctres and.orutiitiesasshown.You wil hold us,your "Consultart,°consis ting of Shannon &Wilson,inc.,and our subconeuRansandsubconvactors.harmiess and detend us from any loss resulting fom inaccuracy of the plans,or lack of plans,reiatng to fhe locaton of underground structuresandorutites. 7,WORKMEN'S COMPENSATION INSURANCEWearesutpectibworkmen's compensation insurance (and/or employer's Lability insurance)as required by applicable state statute &.OENERAL LIABILITY AND LAMITATION THERGOFShannon&Wison,inc.agrees tp hotd you harmiees and to indemnify you on scoount of any labdity dus to bodily injury or property damagearteingdrectyoutofournegligentoperationalacts,but such hold harmless and indemnity wil be imted to hat covered by our comprehensivegenerallabdtyInsuranceandnotofherwise.We carry comprehensive general Lability insurance,which,subject to 43 imnss,terms.andconditions,provides protection againat liabity arising out of bodily injury and property damage fhat is he direct result of our operatonalnegligence.Al your request,we wil provide cerviicaise evidencing such coverage and wil purchase additional limuts of labiity hat you mayrequireas8separatecosttemWpbebornebyyou. Pege1of 1% 14, TS 16, ¢.CONTAMMATED EQUIPMENTAdlaboratoryandteiequipment contammnated in performung our services wil be cieanad at your (Cleet's)expense ContamenatedconsumanieswilbedisposedofandrepiacedatCient's expense.Equipment (inciuding pols)wivch Cannct beCecontemingiedshallbecometheproperyandresponsiblityofClientAllsuchequpmentshailbedeliveredim Clent or disposed of inamannersidestothatindicatedtorhazardoussarnpies.Cient agrees to pay the tar market value of any such equipment which cannotreasonablybedecontaminated. PAYWENTSTOENQMEERwreciceswilbesuomitied periodically for priar services.Payment wil be due upon receipt of mwoice.An sccoUnt wil become delinquent30daysaferdateofbling.ft ls agreed that a late charge wil be added to delinquent accouns at the rate of one-and-one-hall percent (1-1/2%)for each 30 days from the date of bing (provaied ihe rate of such late charge shall not exceed the maximum alowabie by the laws of the stateinwhechourofficesubmittingiheinvoiceiscated:and in that case,then the highest legal rate).if you fal to make payments to us witun 30Gaysofreceet,we may,after giving seven days written notce ib you,suspend services. ON-SITE JOS SAFETY OF PEASOIOGLft8understoodandagreedfiatShannon &Wilson has not been retained tp provide,nor will it be compensated for providing professionalservicesreiaiingibhepersonalsafetyofanyoneon-site other han Shannon &Wison employees and its authonzed agents.and hatStdannon&Wilson wil not be assuming any responsbility for providing such sernces. OTHER PROVIRIONSNeherpartyshatihotd the other responsibie for damages or delay in performance caused by weather and other acts of God,sinkes,lockout.acadens,of other events beyond the congol of the other or he other's employees and agents. This agreement shail be construed pursuant ip the laws of the state in which our office submitiing the proposal (confirming jeder)is located.intheeventanyprovisionofthisagreement«found to be unenforceabie,legal,or convary i public policy,fhe remaining portons of theagreementshallremainineffectandenforceable.One or more waivers by eather party of any provision,term,condition,or covenant,shail notbeconsrvedbytheotherpartyasawarverofasubsequentbreachofthesamebytheofferparty. in fhe overt here is &dispute between Shannon &Wilson,inc.and yourself concerning the performance of any provision in this agreement,he losing party shall pay the prevailing party all reasonable cosa incurred in connection wah the disouls.including staff ime,court coe,attorneys'lees.and other dispute-relatedexpenses. An opinion of construction cost prepared by us represents our judgrnent as a design profeesional and is supplied for your general gudance.Since we have no convo!over the cost of labor and matenal.or over competitive bidding or market conditions,we do not guarantee heaccuracyofouropinionascomparedtocontactorbidsofactualcosttotheowner. Where tests are performed within a borehole (such as a borehole logger,Goodman jack,seismic compression,and shear wave),it's poss biethatdamagetoorlossoftheboreholemayoccur.in such event,you agree ip release us from afl Sabiity for toss of borehole from any causewhileofafterourservicesareperformed.itis agreed that @ reasonable atternpt to recover he equement wil be made at your expensebeyondwhichweagreeibacceptihenekoflobesordamnagetourequipmentwhileinsertedinaborehole. Teat borings and west pas are an accepted and informative mears of subsurtace exploration.However,in fhe nature of things,hey cannotindicatewithabscivtecertantythenatureofhesubsuriaceconditionsbetweenandbelowthetestexplorations.Therefore,a report based ontweetSorings,est pits,or other exploration method cannot guarantee the nature of he suteurtace conditions between and below he wetexplorations.If conditions different fhan are indicated in our report come to your attendon after you recerve the report,R is recommended thatyoucontactShannon&Wilson,inc.immediately to authorize appropriate further evaluation and to nform Shannon &Wilson,inc.compietetyonwhatyouhavediscovered. TERMINATION This agreement may be terminated by eifher party by seven days written notice in the evert of substandal fedure ©pertorm in accordancewiththetermsoftheagreementbyfheofferpartythroughnofaultoftheterminatingpery.if fis agreement is terminated,it is agreed thatweshaibepaidforourtouchargesforlaterperformedfheterminationnoscedate,plus renbursable charges,plus terminationexperees.Termination experses are defined as 15 percent of our total charges for labor and reirnbursabies accumulated tp the time ofterminationtoaccountforowcosofreechedulingadjustments,reassignment of personnel,and retated coss incurred due ip lermnaton.Termination because politans are discovered is covered under Paragraph 10. Porm Me.PH-60 (08)Poge3of3 January 1990 ATTACHMENT A HOURLY LABOR RATES FOR PERSONNEL Fees for services are based on the number of hours expended on the project.The fee will be computed by multiplying the number of hours worked by each classification of personnel by the hourly rate listed below for that classification. PROFESSIONAL STAFF Classification Hourly Rate Principal,Region Director $115.00 Technical Vice President $98.00 Senior Associate $95.00 Associate $78.00 Senior Principal Engr./Geo./Hydro.$75.00 Principal Engr./Geo./Hydro.$72.00 Senior Engineer/Geo./Hydro $68.00 Engineer/Geologist IV $62.00 Engineer/Geologist Ill $$8.00 Engineer/Geologist II $$5.00 Engineer/Geologist I $$0.00 Information Resource Specialist/Program Analyst $60.00 SUPPORT STAFF Classificati Straight Ti Overti Clerical $35.00 $42.00 Sr.Technician/Drafter $45.00 $54.00 Technician/Drafter II $39.00 $47.00 Technician I $35.00 $42.00 Driller $60.00 $72.00 Driller's Helper $39.00 $47.00 Shannon &wilson,Inc.Fafesanks -Ancnorage oo... Unit Price [tem Cacaleg Run Sate 27-JUN-89 [tem Meo.[tee description Unit Cost /per Labor Aeet 1 WATER CONTENT (ASTM 0-2216)$0.50 /UNIT K-8001-15 2 ATTERBERG LIMIT,(1 PT.)$47.80 /K-0002-15 3s ATTERBERG LIMIT,(3 PT.)$65.00 /K=8003-15 5 GRAIN SIZE ANALYSIS 3/8°PLUS $62.50 /K-0005-15 $GRAIN SIZE AMALYSIS 3/8°OR LESS $47.50 /K-0006-15 1 GRAIN SIZE COMBINED ANALYSIS $120.00 /K-0007-18 @ GRAIN SIZE ANALYSIS PERCENT PASSING 8200 OWLY $25.00 /K-0008-15 9 GRAIN SIZE ANALYSIS FROST SUSCEPTIBILITY $60.00 /K-8009-18 10 SPECIFIC GRAVITY MINUS NO.4 SCREEN $49.50 /K-8010-1§ iB SPECIFIC GRAVITY PLUS NO.@ SCREEN $65.00 /K-0011-15 12 UNIT WEIGHT TUBE OR LINER $27.56 /K 0012-15 13 UNIT WEIGHT CHUNK OR FROZEN $37.50 /K-0013-15 14 ORGANIC CONTENT $30.00 /K-0016-1§ 1$PH $20.00 /K-0015-15 16 SALINITY $20.00 /K-0016-15 17 COMPACTIONS STANDARD (ASTM 0-698)4°MOLD $135.00 /K-8017-9§ 18 COMPACTIONS STANDARD (ASTM 0-698)6°MOLD $165.00 /K-0018-15 19 COMPACTIONS MODIFIED (ASTM 0-1957)4°MOLD $165.00 /K=8019-15 20 --COMPACTIONS MOOIFIED (ASTM 0-1557)§°MOLO $178.00 /K-8020-15 21 COMPACTIOWS OME PT.STAND.OR MOO.&°MOLD $45.00 /K-8021-1§ 22 COMPACTIONS ONE PT.STAND.OR MOO.6°MOLD $60.00 /K-8022-1§ 23 FAIRBANKS MOG (SAMPLE PICKUP)$27.80 /K-0023-15 26 FIELD DENSITY TEST SY RAINHART,YOLUMETER $85.00 /K-8024-15 25 FIELO DENSITY TEST BY NUCLEAR,FIRST $35.00 /K-002$-15 26 FIELD DENSITY TEST 8Y NUCLEAR,ADOL SAME TRIP $27.80 /K-8026-18 27 CALIFORNIA BEARING RATIO SOAKED PER PT.$125.00 /K-0027-18 28 CALIFORNIA BEARING RATIO UNSOAKED PER PT.$100.00 /K-6028-1§ rs ]CONSOLIDATION TESTS NORMAL/PERCENT COMPRESSION $250.06 /K-06029-18 30 CONSOLIOATION TESTS NORMAL WITH TIME SETTLEMENT $27§.00 /K-0030-15 1 CONSOLIDATION TESTS ADOITIONAL LOAO-UNLO CYL.$125.06 /K-0031-1§ 32 CONSOLIDATION TESTS -SWELL OR SWELL PRESSURE $150.00 /K-8032-15 33 THAW-CONSOLIDATION TESTS $200.06 /2 LOADS K-0033-15 34 CALC.OF PREMEABILITY FROM LOG TIME DATA $85.00 /K-8034-15 3 $0.00 /K-0S36-15 317 THAN CONSOLIDATION $150.00 /+LOAD K -8S37-15 40 COMPRESSIVE STRENGTH OF CONCRETE $12.80 /K-0140-1§ a1 CONCRETE SAMPLING SET OF 3 CYLINDERS $118.00 /K-8141-1$ 62 SAMPLING OF CONCRETE ADOTIOMAL CYLINOERS $12.50 /K-0142-15 43>CONCRETE SAMPLING EXTRA SLUMP TESTS $10.00 /R-6143-15 aa CONCRETE SAMPLING EXTRA AI®TESTS $12.50 /K-9144-1§ 45 CONCRETE SAMPLING °0°SLUMP CONCRETE $$.00 /K-016S-1§ 6 CONCRETE SAMPLING UNIT WEIGHT $12.90 /K-8146-15 47 «=CONCRETE SAMPLING UNIT WEIGHT HARDENED $25.50 /K-0147-18 ag CONCRETE SAMPLING SET OF 2 SEAMS $178.00 /K-8168-1§ 49 =CONCRETE SAMPLING FLEXURAL STRENGTH $50.00 /K-0149-18 50 COMPRESSION STRENGTH TRIMMING OF CORES $25.00 /K-0150-15 51 COMPRESSION STRENGTH TESTING CORES $25.00 /K -8151-18 $2 CORING &SAMPLING MINIMUM CHARGE $90.00 /K-0152-1§ 53 COMPRESSIVE STRENGTH SY SCHNIOT NAMMER $$0.00 /K-013$-15 54 CONCRETE MIX DESIGN $750.00 /BASIC MIX K-0184-15 SS COMCRETE MIX DESIGN ADOLTIOMAL AIX DESIGN $350.00 /K-6185-1§ Laboratory TestingFeeSchedule Sranron &Wilson.Inc.Fairbanks -Anchorage ......Rin Cate O7-JUN-89 Unit Price Irom Catalog Laboratory TestingFeeSchedule [tem Mo.[tem deserfetion Unit Cost /per Labor Acct S$CONCRETE BLOCK COMPRESSIVE STRENGTH $20.00 /K-0186-15@$7 CONCRETE BLOCK ABSORPTION &UNIT WEIGHT $62.50 /K-01$7-15 $8 CONCRETE LOCK,MOISTURE ComTENT $12.50 /K-0158-15 $9 MORTAR CUBES,SET OF 9 $65.00 /K-0189-15 $5 ASPHALT,S-INCH DIAMETER Cones $42.50 /K-0265-15 $6 ASPHALT,G-INCH DIAMETER Cones $45.00 /K-0266-15 $7 ASPHALT,@-INCH DIAMETER CORES $50.00 /X-0267°15 $8 ASPHALT,AOOITIOUAL 4-INCH DIAMETER CORES $17.50 /K-0268-15 69 ASPHALT,ADDITIONAL §-INCH DIAMETER CORES $20.00 /K-0269-15 10 ASPHALT,ADDITIONAL 8-INCH DIAMETER CORES $25.00 /K-8270-15 11 ASPHALT,TRAIL NIX ANO DESIGN,MARSHALL METHOD $700.00 /K-0271-15 12 BITUMEN CONTENT BY EXTRACTION $55.00 /K-0272-15 1)STEVE ANALYSIS OF EXTRACTED AGGREGATES $47.50 /K-8273-15 16 COMBINATION @ITUMEN &SIEVE ANSYLSIS $90.00 /K-8276-15 1$ASPHALT DENSITY OF CORE $25.00 /K-0275-15 16 ASPHALT,DENSITY OF CORE,WAX COATED $42.50 /K-0276-15 11 ASPAHLT,MARSHALL STABILITY &FLOM $87.50 /K-0277-15 18 AGGREGATE,SIEVE -FINE AGGREGATE $45.00 /K-0378-15 19 AGGREGATE,SIEVE,COARSE AGGREGATE $47.50 /K-0379-1§ 80 SPECIFIC GRAVITY &ABSORPTION FINE AGGREGATE $70.00 /K-0380-15 81 SPECIFIC GRAVITY &ABSORPTION COARSE AGGREGATE $70.00 /K-0381-15 $2 SOUNONESS AGGREGATE -FINE OR COARSE $275.00 /K-6302-15 83 OEGRADATIONS $100.00 /K-0383-15 84 LA ABRASION -LAB GRADED $125.00 /K-0386-1$ 86 UNIT WEIGHT LOOSE (DRY)$32.50 /K-0686-15 $7 UNIT WEIGHT =RODDED (ORY)$37.50 /K-0387-1§Oo 88 FRACTURE DET.+84 SIEVE OOUBLE FACE $27.50 /K-0308-15 89 FRACTURE DET.+86 SIEVE SINGLE FACE $30.00 /K-0389-1$ 90 FRACTURE DET.9816 $48.00 /K 8390-15 91 FLAT &ELONGATED COUNT $60.00 /K-0391-15 $2 LAB.CRUSHING OF ROCK OR AGGREGATE/HR.$65.00 /K-0392-15 $3 AGGREGATE SUITABILITY-ORGAMIC IMPURITIES $15.00 /K-6393-1$ 94 AGGREGATE SUITABILITY CLAY LUMPS &FRIABLES $20.00 /X-0394-15 95 AGGREGATE SUITABILITY CHERT (VISUAL)$45.00 /K-0395-1$ 96 AGGREGATE SUITABILITY SOFT PARTICLES $45.00 /K-0396-15 $7 COAL &ASH CONTENT $105.00 /K-0697-15 $8 OIL &ASH CONTENT $105.00 /K-R698-18 99 COAL MOISTURE CONTENT $8.00 /K-0599-15 Drilling Rate: Simco 2400 Drill Rig $135.00/hour RECEIVED - FEB 20 1991 |oy 0 praska energy Authority ! GOLDEN VALLEY ELECTRIC ASSOCIATION INC.Box 71249,Fairbanks,Alaska 99707-1249,Phone 907-452-1151 | J February 15,1991 Stan E.Sieczkowski,Director Facilities Operations &Engineering Alaska Energy Authority P.O.Box 190869 Anchorage,Alaska 99519-0869 Subject:Intertie Tower 570 We inspected intertie tower 570 on February 12,1991.Attached is an update on our monitoring of tower 570.Our recommendation is to continue with the monitoring for now. 0 LASPeRobertOrr Manager of System Operations cc:Remy Williams AEA Steve Swift GVEA GOLDEN VALLEY ELECTRIC ASSOCIATION Interoffice Memorandum February 14,1991 TO:Bob Orr FROM:Steve SwiftG% RE:AEA Tower #570 On February 12,1991 Greg Wyman and I flew in to tower site #570 tocheckforanyfurthermovementofthepilings.Our field workindicatedthatthetowerhas"jacked"an additional 9 inches from the last time we checked the elevations (July 19,1989). Again,I recommend no remedial action at this time.I will attempttohavetheelevationscheckedlaterintheyear.If necessary,we can schedule leveling the tower in 1992. 50SHEETS22-142100SHEETS22-144200SHEETS22-141oO.frLe]|asreesr ie. Cuevarion Cnreck @ Tower #570 FER NZ,AAV @)c >Yew 1S HL es euev OM "Tree”1o0.00 2S 190Z.SyU OD Sconkeln NODA We.Ade Lous)10%.eB €.vd Z2.10 00.45 Wele:"Tewec Wig,weve Bory WeseED , ©O]S TSM MAY HAVE Moved,SuT ole sementiAL PROC EMEWT saowS WEteT Cag 2.23 ET PAGHRES TRAD CZAGT LEG, aan BQ lh Rerenen WA OrFesA\.2-%8 0 .-) GOLDEN VALLEY ELECTRIC ASSOCIATION INC.Box 1249,Fairbanks,Alaska 99707-1249,Phone 907-452-1151 January 12,1988 Afzal Khan Director,Engineering Support Alaska Power Authority 701 East Tudor Road P.O.Box 190869 Anchorage,Alaska 99519-0869 Subjects:Tower 570 -Intertie Attached is a report by GVEA's Line Superintendent on the status of tower 570 on the Intertie. This information may be of some help to you in determining furtheraction,if necessary. Please see if you can get the foundation data requested in the last paragraph. ApfondRobertOrr Manager of System Operations cco:feet swity -GVEA Remy Williams -APA Intertie Maint.File INTER-OFFICE MEMO January 11,1988 To:Bob Orr From:Steve swit (GX Re:Tie Line Tower #570 On the most recent aerial patrol of the tie line we discovered that Tower #570,located a few miles south of Cantwell,appeared to be leaning at a right angle to the center line of the transmission line.A work request was initiated and sent to Golden Valley's Engineering Department.They were able to respond quickly and sent a crew to the site to determine how much the tower was leaning and what might have caused the problem.Their findings are as follows: 1)The tower appears to be leaning approximately 3 feet away from the center line and 2)the foundation supports on the west tower leg appear to have "jacked"out of the ground,thus causing the problem. Based on information I gathered from the shop drawings and the information submitted from Engineering,I was able to determine that the pilings would have had to have jacked approximately one foot to account for the magnitude of deflection calculated by Engineering(see attached). As for any remedial action at this time,I would recommend that we hold off until we are able to gather more data on the "field" situation.Remi Williams will be flying the line sometime in January and he will make a special effort to stop at Tower #570 and take pictures of the tower and the foundation.I will also be attempting to acquire data as to the piling set depth anda Narrative on the soil conditions at this site.This information will be necessary for us to determine what needs to be done,when, and will give us some direction as to the methods we will employ to effect the repairs. ¢ MAR-13-81 WED 9:23 ML&P DISPATCH FAX NO.907276296:P,03 Matanuska Electric Association,Inc. P.O.Box 2929 Palrer,Alaska 99645 Telephone:(907)745-3231 Fax:(907)745-9328 February 22,1991 Mr.Stanley E.SieczkowskiDirector .Facilities Operations &EngineeringAlaskaEnergyAuthorityP,O,Box 190869 Anchorage,Alaska 99519-0869 Dear Stan: SUBJECT:Comments on the H.Brian White Report We have reviewed the report on recent problems with the Alaska Intertie and thesolutionspresented. We believe that the ground wires should be removed from the structures from DouglasSubstationtoClearCreek.We have operated many miles of completely unshielded 115KVlineinthisgeographicareaformanyyears,and have experienced only one outagewhichwasprobablyrelatedtolighting.The very best shield wire system willexperiencesomefailures.We believe that the line will perform better without theshieldwire.The original installation of the shield was questioned,and the decision toinstallitwasbasedontheminimalcostandfavorablefinancing. The problem with clearance between phase conductors and ground is much moredifficult.We believe that the best proposal is the shortening of the insulator strings.This is based on the fact that each structure must be climbed in any case to resolve theshieldwireproblem.If every structure must be climbed.then we believe it will bemorecosteffectivetoshortedtheinsulatorstrings.then to increase line tension.Wealsobelievethattheincreasedtension.and the additional splices would be likely tocausemoreproblemsthanthedecreasedinsulationsystemwouldcause. incerely.Zp./fAAAaltJamesD.HallProjectsEngineer JH:BB 302A.022291.295AC ;ce:John Cooley,Chairman,Intertie Operating Committee piautes GOLDEN VALLEY ELECTRIC ASSOCIATION,INC. Interoffice Memorandum March 7,1990 TO:Bove TOC FROM:Steven Haagenson SHH RE:Potential Methods to Mitigate the Intertie Problems. Brian White has provided an overview of the sources of the conductorclearanceproblems,and also included several options to resolve the situation. Each solution will need to be reviewed for cost effectiveness, potential to limit the intertie outage time,and to evaluate theimpactsofdeletingcertainitems,such as static wire or portions of insulator bells. One solution which was not included is the installation of intermediate towers along the portion of line which is subjected to the differential icing.The intermediate towers would decrease the sag by a factor of four and thus minimize future wire sag problems. The strength of the intermediate towers would not be required to beasstrongastheexistingtowerssincethereducedloadingwouldbe equal to half of the original wind span and about half the originalweightspan.Intermediate towers would also allow for the continueduseoftheoverheadstaticline.The installation of driven H-piles for foundations may not be practical directly under the existing line,and may require alternate methods of support.The foundation work could be completed with the line energized,and de-energizedduringtheactualtowerplacementandinterconnection. The cost of mitigation will be highly dependent on the length of linewhichwillneedtobereworked,plus personnel and material access, allowed outage times,tower design,whose crews do the work,and the labor charge rate. Engineering is willing to provide the cost estimates,and evaluation for the comparison of the alternate methods.Prior to the cost estimates,it would be helpful to define a list of potential solutions from the intertie participants which warrant further investigation. cc:Mike Kelly Robert Hansen Greg Wyman pyunutel Alaska Energy Authority MEMORANDUM DATE:March 11,1991 TO:Stan Sieczkowski Director of Facilities Operations &Engineering FROM:Afzal Khan Manager/Engineering SupportBPEA.MarchegianiProjectManager SUBJECT:Anchorage-Fairbanks Intertie,Brian White's Report Recommendations After review of Brian White's Reports on_the Anchorage/Fairbanks Intertie,I would recommend'the following actions: *Removal of the static wire from all structures in the 12 mile area of concern with the exception of those structures where aerial marker balls are located between them. Resag the conductors for the 12 mile area of concern. Continue to investigate the spacers and_the potential problem with them.Take the necessary corrective actions once we know more about them. All three items above may be more effectively completed if done at the same time. AHK:EAM:skb 0 Frem >ABA H.BRIAN WHITE MESSAGE: FACSIMILE COVER SHEET H.BRIAN WHITE Consulting Transmission Line Engineer P.O.Box $39 Hudson,Quebec Canada JOP 1KO Tal:5§14-4§8-4329 FAX:614-468-4329 CATE:Monday,February 18,1991 To FAX No:1-907-561-6564 ATTENTION:Mr.Stanley E.SBieczkowsaki Director/Facilities Ops&Eng Alaska Energy Authority P.0.Box 190869 anchorage,Alaska 99513-0869 SENDER:Mr.H.Brian WHite No.of pages (including cover sheet):7 Please find enclosed our Second Report an Probleme on the Anchorage/Fairbanks Intertie. Original is being sent by mail. 9rom °HSL .Feb.i3.1991 91:55 Pm PQ@2 tH.BRIAN WH ITE Conrvliing Tronmmission |_ine Crngineer P.O.Box 939 - Tol.:514-458.4329 bisdssn,Quebez Canada JOD Ho February 18,1991 Mr.Stanley E.Steczkowski Director/Facilities Operations &Engineering Alaska Energy Authority P.O.Box 1908569 Anchorage,Alaska 99519-0869 Re:Second Report on Problems on A/F Intertie Dear Mr.Sleczkowski: We have given further thought to the current problems on the intertie and have no new concepts to add to those given in the report of January 31,1991. Tnere remains the problem of trying to give some sort of prioritytothemanyoptionsthatwareproposedandwewillgiveyouourideasatthistime. 1)Ground wire to conductor confiicts. This 16 the most difficult of the three problems on which to pass judgement because we have no knowledgs of the frequency of occurence of phase to ground outages caused by Tow ground wires andnodataonthaimpactofsuchanoutageoneystombehaviour. How much cost and effort is justified to reduces the frequency ofsuchcutagesOrtoeliminatethemcompletly? Are there any data on lightning outages in this line section that would indicate the effectiveness and need of the present shieldwireprotectionoristheKeraunicleveltrulysolowthattheangleofcovercouldbegreatlyincreasedwithnegligibleeffect onperformance?° Having acknowledged this lack of background data and presuming thattheproblemjustifiessomeaction,we have listed the three optionsintheorderoftheireffectontheproblem.This order is also the eatimated order of cost, a)Remove the 17"Vink in the ground wire suspension assembly andreplacewiththeshortestpracticallinkagewhichshouldbeabout4". Removing 1 foot from each assembly will reduce the potential dropofthegroundwiresbyabout12to15'under a single span loadingsuchasthatwhichmusthaveexistedatthetimeoftherecent flashover. 3re)From .BW Feb.10.1991 @1:55 Pm H._BRIAN WHITE 2, 0 This is the minimum action that can te taken that witli make sicbstantial improvement in the prasent situation. b)The cost of doing anything to the ground wire system will be largely that of getting men and some equipment to the peaks. If there is the opinion that the risk of further flashovers is so large that step a)will not be sufficient,then the added step ofreversingthegroundwirearmtotneinsidewillgiveanextra4.5' of horizontal specing between the ground wire and the outer phaces. A short temperary davit clamped to the peak can be used to support the load of the ground wire (about 400 Tbe.)while the link ia removed and shortened,the arm removed and rebolted in new position and then the wire reattached to the ceak.It becomes evident that something clever will have to be done to both support the wire and move it from the outside to the inside of the peak. cs)The third option would be the removal of the ground wires for the affected or threatened section. This has been done tn tre past by many utilities but done as a result of structural Gamage causec by excessive longitudinal loads. In each case it had been demonstrated to be almost impossibte to reinforce tne existing structures to resist anticipated future Joads.0 Tnts is not tha condition on the intertiea (based on the recent evidence)as the probiem is that of simple distortion of the system ANG we do have means of reducing the distortion as discussed above. Tne proposal cf a)will cause a smal)increase in loading of the peak but there appears to be enough flexibility left so that loads snould not break the peake. If subsequent storms exceed the resent ones and peake are broken, then the removal of the ground wires may become necessary. Removal of the ground wires would probably have little effect on lightning performance if the Keraunic level is as low as reported but that true situation is beyond our Knowledge.. Racommendation:Remove or shorten the suspension links and,as a next step,reverse the ground wire arms. 2)Conductor toe close to the ground, Tre problem 18 again caused by too much flexibility in the system and the solutions are a)and b),to shorten the insulator assemblies,c)to take some of the excessive slack out of the conductors or d)to restrain the longitudinal movement of the conductors with inverted V insulator arrangements. 0 Sram ¢HEU Feb.18.1991 @1:59 FM Pal H.BRIAN WHITE d. a)The present suspension assemblies are 12'tong and removal of the 12”link would marginalty reduce the flexibility of the system. A rough estimate of tne reduction in sag under the recent load -conditiona would be about 1 to 2'if the links were to be removed to which would be added to the link length for an improvement of two or three feet at most. Thus,there is little justification for taking this step by itself as the benefits are almost inconsequential,being within the variations of tne snow loadings. Db)AN adequate solution could be obtained by removing the links Dius about 6 insulator unite.The immediate result would be a raising of the conductors by abcut 4°and a reduction of the sag increase caused by differential snow or ice loading of another 4 to 5'for a total improvement of 8 to 9'. Our information is that the outer phases got within 4 to 6'of the snow and the snow thickness was estimated at 4'. 12 to 14'above the snow should be much more than enough to prevent accidents as long as the loads causing the system distortions are about the same as those recently encountered. All of thie leads so the questions of whether an intermediate voltage such as 220 kV could be the final voltage or whether areducedinsulationlevelat345kVcouldbecountenanced. Complete conversion to 138 kV clasa insulation is not necessary to solve the current problems.: If the links and some insulator units are removed,then the V assemdlies of the center pnase will have to be changed to 71 s. (To be noted in all of this discussion is the fact that completely normal and typical line desicns can take on very dangerous poatures or positions (clearances,etc.)when the system is approaching failure and after a failure there is never any discussion of the possibly dangerous condition just prior to the failuce. The racent conditions on the intertie did not appear to be threatening structural failure but the rarity of the unusual lcading event may equate to the frequency of an ultimate failure load and justify a comparable appraisal.) c)A significant part of the current problem can be attributed to the relatively low tensions in the conductores. The sag tables used to instal the conductore indicate a bare wire final horizontal teneion (H)of 4996 ibe or 19.3%of RTS giving a sag of 38.8'and elack per 1200'epan of 3.368'. 0 Feb.13.1951 91:59 Pm P22 H.BRIAN WHITE '. Having regard for the direction of tha line relative to prevailing winda,the protection given py the tree cover,the use of dampers and the fact that the line 1s bundled would,in our cpinion, juetify a 30F final tension of at least 23%with a sag of 32'and a elack reduced to 2.3'. This reduction of sag would improve ground clearance by 38.8'-32' or almost 7'while tne raduction of flexibility would reduce the sag shifting under unbalanced ice by about another 4°for a total improvement of more than 10°. Thus a resagging to @ nigher tension limit would give the aame measure of improvement as removing the links and about 6 insulator units that 18 dtscussed in b)above. A check would nave to be made of the effect of higher tensions on the capacities of tha angle towars but we would anticipate few sertous probleme. ad)We have obtained coste of inverted VY insulator arrangements that could be installed to restrict longitudinal movement of the clamp positions.The lowest estimates work out to about $1500 per pnase position to which woule have to be added the costs of installation and moving dampers etc.,the material costs thus exceading $5000 por Tower. This scheme could be very effective,would not require removal of the V assemblies at the center pnases but has been put aside at present for reasons of high cost of materials and for the fact that the dimensioning ef the V must be Gone very carefully in order to avoid precipitating tower failure. If decisions are made that removal of insulators as in b)or resagging as inc)are not accaptable,then a further lock at d) may be in order. {Subject to further study,a case might be made that effective restraint of slack snifting might be obtained by inetalling inverted V restraints at every second tower,thus cutting cosets by one half.) +s of Rosaggi Tha resagging of a long section of line would be a major undertaking but it would not compromise future operation at 345 KY. A resagging could be done in the conventional manner by placing Yong esctions back into travellers and retensioning. However there ie a possibility that the resagging could be done by working on sectione of four or five spans at a tima. Reducing sage by 20%will mean the removal of about 1.3°of conductor from each 1200°spar. 0 ="-om :HB Feb.19.1991 61:59 Bm Pes UW.BRIAN WHITE 5. In a 5 span section from A- B-C -0 -E -F,the conductors could be lowered at C and 0 so tnat about 8.5'could be cut out rear mid-epan where the conductor would be close to the ground (the exact amount depending on the span lengths of the section),the clamps slipped about 2.6'at towers C and D and the conductors raised back into position. whether the clamps would nave to be siipped at 8B and E would be a moot point,dependent upon the existing clearance conditions at spans A-3 and E-F. Thus by working only at 2 towers the sags could be corrected cn five spans and the work is concentrated tn dtstance so that the three phases of more than a mile langth might be completed in a weekend. Selection of bj}or ¢) At THiS point we fear we cannot go further in recommending options regarding improving the conductor behaviour under unbalanced ice or snow loadings. We do not know how real the risk is regarding electrical eafety for the snow usually is an insulant,the snow evente of the past winter may be no more frequent than the storms that could bring down the Tine,we know not of the coset of the several optione nor of theacceptabilityoflimitationsonfuturevoltagelevels,nor of the possibility of service outages that might permit or disallow theworkofreeaggingbyeitherofthetwomethods. In eummary,the two significant options are to remove the links and at Yeast §ineulator unite,(preferrably more)or to resag and reduce sage by about 20%and we require some reations from you orothersinAlaskabeforeproceedingfurther. 3)Bundle Twistirg We must await examination of a sample spacer before cefining theextentofthisoroblem, . If the spacers are deficient.tnen spacers may have to be raplaced over a considerable length of tine if not entirely. N.B.During an sariter flyover of this line we noticed and remarked on the very good sagging of the bundles as there appeared to be very few inclined bundles.The line wae very woll sagged in. Following the recent storms and not including the 9 permanently twisted phase spans,we noticed that there were very many partiallytwistedapans,evidence of the saverity of the loadinge and givingagoodindicaticnofthelengthoftheseverlyloadedsection. 0 H.BRIAN WHITE All bundled lines suffer sucn indignities during ice storme but we have never before noticed so much residual aistortion. We have given thought as to whether tnese twists are of real concern and whether efforta snculd be mada to correct them, eeoecially if any work is dene to resag the wires. Ws have discussed this with several associates and they all agrés that unless the position 18 more tnan sbout 60 degrees from horizontal,nothing should be attempted.Cresp and strain theory tells us that the lower conductors have been overloaded compared to the uppers but that the slightly higher tensions in the urpers will cause more lang term creep and oventually bring them down closer to the lowers. In any event,correcting such uneven sags within a bundle requires the juggling of very very small amounte of slack and even if the wires were to be brought back to the flat position,the different stress nistorites of the two (one hee already been stretched more than the other)would eventually find them uneven again. Stan,that is as far as we can go at this time. You now have our recommendations for the ground wire problem of either just removing the links or also reversing the arms;the conductor problem can be resolved by removing the links and some insulators or by resagging,neither of which is an easy decision. If we can be of futher help or explain or expand on the above,weremainatyourservice, with pest regards Yours very truly D.S.A very late thought about the tilted bundles. There is the possibility that the conductor twisted in the spacer grips during extremes of loading or during other twisting actions and the grips have retained a grip of the conductors in a non neutral poogition,that ie,that the spacers are responsible for retaining tha tilt. This could ve verified at the time of opacer removal. Such a finding of partial clamp slippage could account for theverylargenumberoftiltedspanenowintheline. RO LY.BRIAN WHITE Consulting Transmission |_ine Cngineer Tel.:514-458-4329inswanFAX:514-458-4329UdaSOn,ve Canada JOP IHo February 1,1991 Mr.Stanley E.Sieczkowski Director/Facilities Operations &EngineeringAlaskaEnergyAuthority P.O.Box 190869 Anchorage,Alaska 99519-0869 Re:Report on Problems on Anchorage to Fairbanks Intertie Dear Stan: I am enclosing a letter report about the problems on the Intertie. This has been prepared in a hurry as I leave tomorrow on a two weektripandIdidwanttogetsomethingintoyourhandsbeforedeparture. You may consider the report as background material that I have puttogethersothatallofuswillhaveabetterunderstandingofhowalithebitsandpiecesarereactingtotheloadsbeingapplied. It is a complex set of problems and a great difficulty is going tobethatofsortingoutorrankingthecontributionthateachbitandpiecemakestotheproblem(s),the cost of modifying that bit,and the least cost arrangement of bits and pieces to do what isnecessaryandsufficient. These decisions regarding technical adjustments will be added tothoseoftryingtodelineatethelengthoflinesectionoverwhichtheproblemsareexpectedtooccurandpossiblythegreatestpuzzleofall,which is to determine whether the recent events were justfreakoccurencesoraretheytypicalofthatterrain. Are the chacteristics of this line so different as to promote thisapparentlyrarebehavior,were the conditions so rare or is theareasounusualorisitsimplythatgreateraccesstorights-of-way by the public and more frequent observation from helicopterpatrolarefindingconditionsthatnavepassedunnoticedinthepast? I remain at your service and will contact you or Eric the week ofFebruarythe10th. With best regardsenc. oe Mp Be WH.BRIAN WHITE Consulting Transmission Line Crgineer D.O.Box 939 Tel.:514-458-4329 Ll udson,Quebec January 31,1991 Canada JoP iLIo Mr.Stanley E.Sieczkowski Director/Facilities Operations &Engineering Alaska Energy Authority P,O.Box 190869 Anchorage,Alaska 99519-0869 Re:Wet Snow Problems on the Anchorage to Fairbanks Intertie Dear Mr.Sieczkowski: We have made use of all the information and data available to us at this time and arrived at some findings and a few recommendations regarding the current state of the lower part of the Intertie. A few of the issues are clear cut and almost obvious but there are several problem areas where more study,possibly some testing and certainly more discussion of options will be needed. In order to properly organize our thoughts of the total situation, and then to transfer these findings to you,we have to break the subject into the following topics: 1)Discussion of the type of loading 2)Elastic or system distortion? 38a)Flexibility and disortion of the Ground wire system. 3b)Options for improving the Ground Wire system. 4a)Flexibility and distortion of the Conductor system. 4b)Options for improving the Conductor system 5)Twisting and locking of Bundles under ice or snow release. 6)Summary and Suggested Next Actions 1 T f j All evidence and reports verify that the loadings of the several events were of frozen snow,possibly the most destructive,damaging and frustrating type of natural vertical line loading just because of the fact that it strikes unexpectedly and without forewarning or foreknowledge. 0 UW.BRIAN WHITE . a)Precipitation icing or freezing rain can be a frequent occurence in temperate or cold climes;it falls on roads and sidewalks and recording instruments at airports and few such icing events occur without note and record being taken, The data taken by others can be transferred with fair accuracy into radial thicknesses as appropriate wire loadings. Freezing rain will form quite uniformally with few discontinuities and because of reasonably good adhesion.Under melting conditions it will tend to decrease uniformly until a thin shell is left,at which time it may fall off in relatively insignificant chunks. Freezing rain can produce great vertical loads that overstress the wire systems and lower the wires in what is simply an 'elastic distortion'. Freezing rain does not usually produce severe differences in loadings in adjacent spans such as to cause 'system distortions' whereby wires in one loaded span may be lowered very much while those of adjacent spans are lifted. The only recollections that we have of significant 'distortions of the wire systems'have been at times when ice has been large enough to break parts of structures or some of the wires;ie.at very close to ultimate load conditions. NOTE.Throughout all of the discussion of this subject of system distortion and wires down to or close to the ground,we should recognize that the frequency of snowmobiles running up and down and across the rights of way,and the more frequent patrolling by helicopter may just be increasing our awareness of something that has gone unobserved in the past. It is an important part of this work to try to determine if there really are factors in and about this line that are different from other apparently similar lines or is it just that an unusual combination of circumstances has produced the problems of the past month or so. b)'In cloud icing'.It is not necessary to discuss all the 'in cloud'characteristics except to note that 'in cloud'icing can produce great differences in formation of loadings on adjacent spans because the rate of ice deposit is a direct function of exposure to the moisture laden wind.However a line engineer building for exposure to 'in cloud °can forecast such problems and prepare defences. Stations are frequent where 'in cloud'data can be collected and extrapolations made to comparable sites. 0 HW.BRIAN WHITE . 'In cloud'icing was an original prime suspect of ours for these Intertie problems but the evidence and reports of all parties has pointed very definitely to frozen snow and from this point on all discussion will be of that kind of loading. ¢)Frozen snow.This form of loading has caused many line failures and problems and all are 'unexpected'because there just are no records kept of freezing snow deposits which really is seen simply as wet snow. Children are fond of it for rolling snowballs and making snowmen and it finds little favour with downhill skiers who would rather have dry powder snow but for all those who have wires in the air,once more it's just a wet snow fall. AS we are aware,if the moisture content and temperature are just right,the snow can adhere to almost anything. As was noted on the X towers of the tie line,the snow fell vertically without wind,building up on the tops of the crossarms and adhering to the inside surfaces of the upper arms of the X and to the steep outer legs of the lower X.There was no snow attached to fore or aft surfaces,a strictly vertical fall of very sticky wet snow. NOTE:In all of the calculations that we have made,an average span and a Ruling Span of 1200'has been used because a check of the Plan and Profiles of the affected section showed a very regular spacing of towers with little variance from 1200'.A temperature of 30 F has been assumed throughout. Furthermore,it should be recognized that Sag Tension calculations are not precise when working tensions exceed 50%of rated strengths.The errors involved are of the same order as those produced by the estimate we have made that the density of the frozen snow was about 0.3 compared to the usually used glaze ice value of 0.9. lasti r te stortion Attention was first given to the possibility that straight vertical overload could have produced enough stretch in the ground wires to have brought them down to the level of the conductors to produce flashovers,or stretch in the conductors to have brought them close to the ground. H.BRIAN WHITE 4. 0 The following table gives approximate 6ag values for both ground wires and conductors under a range of loadings,all at 30F. Loading Ground wires Conductors Separation ** Bare 30.'38.8'33.8' 3/4”ice 43.5'44.6'26.1'Alcoa data 1.5"snow 43'43'25' 2"snow -49'45'21' 2 1/2”snow 54'48'19' 3"snow 60'approx 50'approx 15' 3"snow 60'38.8'(bare)6' xx The ground wires at the towers are suspended 25'above the-conductors.The separation shown is this 25'plus or minus the difference in sags. re)a)Attention is given first to the ground wires and the condition that would have to exist to bring them down to approximate conductor level when slight wind action could bring them close enough for a 60 cycle flashover. On a span of 1200'at 30F and no ice load,the ground wire should be about 33'above the conductors at mid-span and even with 3/4" radial glaze ice on the ground wires,they should not get within 20'of unloaded conductors. Assuming 3"of 0.25 density frozen snow on the wires for a 6.4” overall diameter,(certainly larger than the largest estimate we heard of),the ground wire sag would only get down to within 6'of the unloaded conductors,still not close enough to produce a 60 cycle flashover. Even a snow thickness of 2.5”on the ground wires and bare conductors would have a vertical separation of about 10',such a snow load taking the ground wires beyond 75%of RTS. There is at least one photo record showing a ground wire below the level of the conductors and even if the conductors were bare (not known),the snow thickness would have to be greater than 3",a loading of about 4 1b.per foot which would certainly leave permanent extra sag that would be quite evident and would certainly re)have damaged peaks and fittings. We are not aware of any reports of overall diameters of more than 6",and that is the loading on the ground wires that would have been necessary to bring the ground wires below the conductors by 'elastic stretching'or simple overloading. 0 H.BRIAN WHITE 5. If this line of reasoning,(based as it is On approximations of loadings and sags)is agreed upon,then the problem becomes that of 'system distortion',whereby the problems are caused by much smaller loads that are unevenly distributed on adjacent spans. The loaded spans pull slack out of adjacent unloaded spans and depending on the flexibility of the support system,sags can increase or even decrease much more than with simple elastic changes. b)In some spans the conductor was reported to be close to the ground. The desigm standard was for a clearance of 30'at 143 F which equates to 37.6'clearance with a sag of 38.8'at 30 F. As noted in the table above,a 2 1/2"thickness of frozen snow will drop the conductors down about 9',a 3”loading about another 3', neither of which bring the conductor closer than about 25'above bare ground. It is evident that 'elastic deformation'will not bring the conductor down to where it was in the recent events. Once more the evidence points to 'system distortion'. 3a)Flexibility and Distortion of the Ground Wire System. It is of benefit to note several basic relationships of a supported wire in which: The slack,the difference between the length of the wire and the straight line distance between support points = 2 3 2 Slack =8 x Sag /3x Span =Span /24x C where C is the Catenary or Parabolic value of H/w. 2 Note that with constant span,the slack is a function of Sag or as expressed another way,with constant tension the slack is a 3 function of Span . Of more significance to this study is the first order relationship that the Sag will change by (3 x C /2 x Span)x change of slack. For the ground wire with 30'of sag in a 1200'span at 30F,and ac value of 1640 1bs./0,273 or 6000',the change of sag to change of slack ratio will be about 3 x 6000 /2 x 1200 =7.5 /1. If the suspension clamp at each end of a span moves inward by 1' for a total slack increase of 2',the span will drop by almost 15'. 0 H.BRIAN WHITE 5. The actual drop will be a little less than this because the reduction of tension will decrease the wire length but the 15' value is a fair number for this kind of study. Coincident with the drop in this span would be a lifting of the wire in the adjacent spans. The sags of the ground wires of this line are very consistent with usual practice,higher tensions would threaten vibration performance. The line is unusual in that the ground wires are suspended on aninsulatorassemblyof21"length that will readily permit:almost1.5 'of wire to move from one span to another. Most ground wires are clamped firmly at each tower or at most with a very short swing linkage of possibly 6” The only reason for the long linkage that we can imagine is that the designers were copying a trial insallation on a secton of Hydro Quebec line where unbalanced 'in cloud'loadings had broken several peaks.They added links of about 24"in an attempt to reduce the loads (and prevent structural damage and a permanent outage with the wires down between the conductors)but they recognized that there would be more movement span to span. The flexibility of the ground wire system is further increased by the torsionally flexible ground wire peaks and the support arm of about 24"that carries the wire. Reference to the report of the load tests carried out in Korea in 1983 shows that a longitudinal load of 3900 Ibs.moved the support point longitudinaly some 22.5 ”. It is difficult to separate the part of the movement attributed to the twisting of the peak from the overall deflection of the tower due to stretch of the guys but we will assume that most comes fron the peak itself. The differential loads that exist with the unbalanced ice loads of the recent events certainly were of the order of 4000 lbs.so that an assumption of total clamp movement into a loaded span of 3'or more at each end (from adjacent unloaded or lightly loaded spans) is easy to visualize. If we start with the 2”snow load condition with 49'of sag (see table above)when the sag to slack ratio will be about 2 =>3x C /2 Span and with C =H /w=Span /8 x sag or 3673', Change of sag =3 x 3670 /2 x 1200 =4.6 x Change of slack. If 3'were to be added at each end,the sag would increase by 6'x 4.6 or 27'which when added to the 49'gives a total of 76'. 0 H.BRIAN WHITE . This is much more than enough to bring the wires down into the bare or even lightly loaded conductors and far more than enough to bring them below conductors that may be higher than normal because there may be snow on the adjacent conductor spans. We have concluded by this point that the ground wire system has more than the usual amount of longitudinal flexibility and this is a major contributor to the flashover problem. Another contributor to the same problem is that in an attempt to provide almost perfect shielding with a cover angle of 15 degrees, the ground wire has been placed with only about 5.2',a small spacing if the wire drops below the conductor level at which time the smallest cross wind would bring them close enough for a flashover. 3b)Options for Improving the Ground Wire System a)The 21"suspension linkage as shown on Dwg.2007/2 can be shortened by about 12”while retaining the insulator but this -reduction would be accompanied by a modest increase in the load applied to the peak support point. The cost and effort to reduce the link length (each tower and peak must be climbed)would not be justified if it were to be done by itself but might be combined with 2). b)The suspension arm is unnescessarily long and the length adds greatly to the torque on the peak and the subsequent longitudinal movement. The best adjustment that could be made with this arm would be to remove them and shorten them or simply replace with a new plate drilled to fit the holes in the top of the present peak and accommodating a longitudinal U bolt offset 4 or 5"from the peak member. There is no need to worry about the 85 degree clearance condition that is shown on the concept drawing 2005/3. This reduction of the torque arm should reduce longitudinal movement by about 15”out of that 22.5"measurement although the overall longitudinal tower movement will not be changed. Combining 1)and 2)could produce a reduction of clamp movement of 2 to 3'at each end of a single loaded span which would lessen the midspan drop by from 4'x 4.6 or 18°to as much as 6'x 4.6 or 26'. We must be aware that this reduction in flexibility would result in an increase in the loads that unbalanced spans would apply to the peaks. 0 H.BRIAN WHITE 3. Without benefit of a detailed analysis (an actual pull test might be needed),our best estimate of the longitudinal capacity of the peak with reduced arm length would be between 5000 and 6000 Ibs. Such a load would be reached with from 2 to 2 1/2"of 0.3 density frozen snow on the span on one side and bare wire on the other. This would be a little more load than the original design target value of 3/4"radial glaze ice on but one span. c)<A more modest improvement in the problem of conflict between ground wires and conductors can be had by increasing the horizontal separation or offset of the two. The shortening of the arm could increase the present offset of 5.2'to maybe 7'but an even greater improvement would result from turning the arm to the inside while using the same bolting arrangement. Moving to the inside would increase the present 5.2'to about 10' if the arm were not shortened and might be enough to prevent clashes under modest winds if the wire does drop down to conductor level. The increase in shield angle would not have measureable effect on lightning performance as several recent studies have demonstrated that the shieid angle is but a very minor factor in aa rathercomplexrelationship. d)One frequently used solution to ground wire/heavy ice problems is to remove the wires in the affected line sections. The Bonneville Power Administration and B.C.Hydro long ago adopted a general policy of no ground wires in most heavy ice zones,relying on a low Keraunic level and with ground wires for but a few miles out from stations. We know of several other utilities in both N.A.and S.A.that have removed the wires after operations began but these were actions taken because the ice loads were causing structural failures of the peaks and permanent outages. We do not know of any who have removed the wires simply because of distortion problems. It may be noted that the problems with distortion of the ground wire system of this line seem to have resulted first of all from unequal span loads aggravated by several line characteristics that were introduced in an effort to make the line 'super safe'with regard to other matters. 0 H.BRIAN WHITE . The 15 degree shield angle (a conservative value for an icing area) brings the wires almost on top of the conductors,the long suspension arm provides much more than needed swing clearance for the wires (85 degrees)but increases longitudinal flexibility and the suspension string itself (possibly introduced to reduce peak loads)adds to the movement. 4a)Flexibility and Distortion of the Conductor system. The conductor system contains two design factors that make it somewhat more flexible than normal while the tower type seems to be a major contributor to the flexibility. Attention is given first to the conductor system. a)The suspension assemblies are longer than have been used on some similar 345 kV lines but this extra length plays only a small part in the overall problem. However,if the line were to be insulated for 138 kV operation,a reduction from the current 11'string length to possibly 5'or less would reduce the flexibility significantly. b)The conductors have been installed with the controlling tension of 25%RTS at -40F which results in a tension level at 60F Initial of 20%. The NESC control is set at 25%Initial at 60F. Thus the conductors have 25%more sag than called for by the Code and this 25%means an increase in slack of 56%. There is no argument that cold temperature conditions should not have influenced the tension level but having regard to the facts that the line is bundled,that two dampers are used per span and, above all,that prevailing winds are almost parallel to the line, the application of the NESC at -40F was not justified in our opinion. The benefit of hindsight shows that the conductors are also well sheltered from any transverse winds so that reducing sags should be a technical possibility.Slack would be reduced and everyday ground clearances would be increased. c)Our interpretation of the few photos at hand shows that the conductors that have dropped the most have been outer phases and it may be that twisting of the towers contributes to the outer phase problem. The guying system is yoked at the ground level (4'yoke)so that the tower has little initial resistance to the twisting that could be caused by an outside phase longitudinal load. 0 H.BRIAN WHITE 10. Because of the flexibility of the ground wire system as built,we doubt that there is the restraint that was allowed in the tower load schedule of Dwg 2005/2 for load case V.Thus,longitudinal deflections greater than those of the test report can be expected. 4b)Options for Improving the Conductor System The possibly excessive sags and the tower flexibility under torque loading certainly add to the system distortions under single span loadings. A resagging would greatly improve the situation by reducing system slackness and increasing basic ground clearances but would be expensive,even if done by cut out methods. There is not much to be done with the yoking system in the guys for although it may contribute somewhat to the problem,too many other good and valuable characteristics of this X tower are dependent on this same yoke arrangement. There remains the major problem of the flexibility of the suspension system,an 11'(or 10')linkage that just allows too much slack to pass from one span to another. If the insulation can be reduced to that of 138 kV,the conductor to ground problem would be solved but there would remain the ground wire to conductor problem that would have to be taken care of as in 3)above. If the insulation system were to be changed,the center phases could be converted to I strings. Another possible solution would involve conversion of the present suspension assemblies to inverted longitudinal V's by straight replacement or by adding the V's to the present strings. As presently envisaged,each leg of the V's would consist of a 2 section low strength non ceramic insulator at about 45 degrees,one or the other of the strings would pick up the load and restrict movement while the other one would go slack. This change would in effect convert the tower into a semi-strain type and could not be attempted without checking on the capacity of the towers to resist the changed loading conditions. A conversion to or the addition of V's would be expensive. The ground wire to conductor problem is potentially a serious one but its real impact on operations will only be known with passage of time.What will be the real frequency of outages caused by contacts or near contacts? H.BRIAN WHITE ll. 0 Tne conductor to ground problem is the more serious problem and possibly should receive first attention although,as a large part of the costs of any modification will be those of access to the tops of the towers,there may be value in trying to solve both problems at once. H.BRIAN WHITE >. 0 5)Twisting of Bundles During the inspection by helicopter on January 23,it was noted that at least 9 phase spans were twisted and remained locked,2 spans having either double or triple twists. This is a potentially dangerous condition for even modest wind action can cause the conductors to abrade at the crossover points. Furthermore it may be found quite difficult to bring the bundles back to their normal states. We have never seen more than the occasional single twisted span following a storm so that the large number on this occasion indicates that the ice (snow load)and accompanying activity was truly exceptional or that there is a serious design deficiency in the conductor system. At this time and with only limited knowledge of the spacer system (design and spacings)we tend to suspect that alithough the loadings were severe,the spacer system is not adequate for the conditions of this line. re)Background From 1955 to 1988 we were responsible for the design and construction of twin 345 kV lines north of Lac St.Jean in Quebec, lines using twin bundles for about the first time in N.A. Experiences and tests in Sweden,where bundles had been recently introduced,alerted us to this problem of twisted phases to the extent that we joined in a test program being carried out by the BPA at a site at Pullman,Wa. The BPA had the same concerns regarding bundle behaviour under ice loads and specially with ice release and,on the test span,sand bags were loaded and then released by electrical fusing to simulate ice dropping. With some spacer designs and some spacings,the bundles would remain twisted and with others,the phase might first twist but immediately return to the flat position. The secret to success was found to be that the clamps of the spacers must grip the conductors securely and not permit slipping or rotation which would release the torque that is needed to restore the conductors to their flat positions.This grip must be retained after many years and many temperature cycles and at the low temperatures coincident with ice on the conductors.Oo To our best knowledge ,the 345 kV lines built more than 30 years ago in Quebec have had many ice loadings but have never remained with twisted spans,the result of giving proper attention to the Qualities of the spacers that ensure retention of the torque in the conductor. H.BRIAN WHITE :13. The potential problem of bundle twist becomes even more serious with quad bundles so that,during the design studies of the many long crossings of the Hydro Quebec 735 kV system,a very involved study was made of the spacer system and of the needed qualities of the proposed spacers. As consultant to H.@.on the design of these lines,we performed the studies of spacer specifics and spacings,basing our work on theory developed by engineers of Sumitomo of Japan. This problem of bundle twist also arose on the large crossing of the Kooteney Lake in Western Canada several decades ago and the problems of restoring the heavy long spans of wires to neutral position made us aware that prevention is much better than constant attempts at repairing the situation.As much as is reasonable must be done to prevent occurances. Spacer Design The torque capacity of the clamps is a major item and it is usually one of the two prime matters in any specifications for spacers for lines subject to icing,the second being the strength or stiffness of the spacer body itself. The specifics usually refer to the needed torque capacity of the spacers which will vary with the J value or torsional stiffness of the proposed conductor and with the anticipated spacing of the spacers because the possible limit of torque will vary inversely as the length of the subspans.This torque capacity can be measured by clamping the spacer to a length of conductor and applying a torque sufficient to rotate a sub span length by a half turn. Our suspicions regarding the adequacy of the current spacer system (spacers and spacings)arise from a look at the design drawing of the spacers used on the intertie (dwg.no.2012/1)in which they appear to have very little if any method for tightning the grip on the conductor. Furthermore the Design Specifications accompanying the Invitation to Bid NO APA-83-R-0011 make no reference to required torque strength or gripping strength other than that 'they shall have sufficient bearing area so that in gripping the subconductor, there is no deformation of the aluminum strands'. There appeared to be no concern for the problems of spacer behaviour under icing activity and that lack of specifics, combined with the many recent twisted spans and the mere appearance of the spacer as in the design drawing,force the conclusion that the spacer system requires attention. 0 H.BRIAN WHITE a Recommendations. A program of tests is suggested for the spacer units,including testing of some units taken from the ends of some of the twisted sub spans of the recent event. The grip of these units is enforced through an elastomer insert of some material,rubber or neoprene or a relatively soft compound of some kind.The cold temperature behaviour,stiffness and especially the creep characteristics of this substance must be appraised as well as the method of bonding the two interfaces. Following this detailed study,the ability of the spacer as a whole to restore a flat position should be studied. If it appears that the spacers are not adequate for the needs, then the current units could be moved down closer to midspans and new more effective spacers applied near the ends of the spans where the duty is more severe. If our suspicions of inadequacy prove to be correct,modifications to the line will be costly (access and installation costs)and some judgements will be needed regarding the severity of the revisions and,above all,on the sections of line that should be modified. Vertical Bundies Some utilities use vertical twin bundles and the suggestion has been made that conversion to a vertical bundle might reduce or remove this twisting problem. The installation of a vertical bundle requires a bit greater sag in the lower conductor so that it in effect is slightly supported by the upper conductor.An icing or frozen snow event will still produce unequal wire loadings with the 'upper'sometimes brought below the 'lower'and there will still be about the same tendency to twist upon release of the ice. However if the 'lower'is now on the wrong side of the 'upper', the work of returning to the correct position will be greatly increased (almost impossible). We know of no one who has used a vertical bundle with success through a significant ice event. 0 H.BRIAN WHITE Span twists as 1 xemFEmheemEEMUMAOphase phase phase phase phase phase phase phase phase noted Jan.23,1991.(e &Oo e) 37-38 in the end sub span. 41-42 at about 150'from ends. 44-45 45-46 posssibly double or triple wrap 47-48 63-64 at about 150'from ends 70-71 83-84 150-151 appears to be a double twist 15. H.BRIAN WHITE 16. 6)Summary and Suggested Next Actions It has been found that the flashovers between wires and the very low conductors are the result of system distortions whereby unequal span loadings of frozen snow have moved slack from one span to another. Some conductors have dropped too close to the ground while ground wires have dropped to or below the level of the conductors. There have also been at least 9 cases of span flips with the bundles remaining in a locked position that is conducive to rapid abrasion of the aluminum wires. Some modifications that would reduce or possibly eliminate the problems have been described in the above pages. The next stage of work will be for those who have access to cost data to put some costs to the many options and to start to rate the many options with respect to these costs and their possible effectiveness. Judgements must be made as to which would or would best fit the future operation of the line. After all interested parties have reviewed the above and made these assessments of costs and preferences (related of course to degree of improvement)and then listed questions and requested clarifications,there may be need for further discussion to select and plan the next steps. We remain of course at your service for assistance in any way you need. We shall be away from Hudson until about Feb.16 but will attempt to contact you or Eric about the 10th to learn if there are any immediate problems or questions about this report. This report and the needed calculations have been prepared in rapid order and we trust that you will forgive any errors or lack of syntax that have not been caught. With best regards Yours very truly fsa bade nanaeaaaneneemnaaimeemnenl1.BRIAN WHITE | Consulting Transmission Line Cnginee D.C.Box 939 Tel.:514.458.432« Lludson,Quebec "FAX: Canada JOP iHo 514-458-432) February 1,1991 Mr.J.F."Mac"McIntosh Manager of Operations Matanuska Electric Association,Inc. P.O.Box 2929 Palmer,Alaska 99645 Re:Account of Mr.H.Brian White Re:Problems on Anchorage-Fairbanks Intertie Dear Mr.McIntosh: For Professional Services and Expenses of Mr.H.Brian White, Consulting Transmission Line Engineer, January 20 -February 1,1991 Services:9 days $7200.00 Expenses:2849.00 Total:$10,049.00 US Yours very truly enc.* cc:Mr.S.Sieczkowski February1,1991 Account of Mr.H.Brian White,Consulting Transmission Line Enginee1 January,1991 ALASKA ENERGY AUTHORITY Date Expense Services 1991 S.Jan.20 Airfare:Boi/Anc/Mtl $1312.25 +759.48 $2071.73 US l day Taxi:Anchorage 14.00 M.Jan.21 Taxi:10.50 Lunch 6.00 1 day T.Jan.22 l day W.Jan.23 Lunch 6.00 Dinner 20.00 1 day T.Jan.24 Hotel Westmark 615.86 1 day fe]Lunch 6.00 Dinner $§12.25C F.Jan.25 Hotel Relax Plaza 74.75C Taxi: Dorval-Hudson 35.00C x.86 $122.00 104.91 US M.Jan.28=°Report 4 day T.Jan.29 Report 1 day W.Jan.30 Report l day T.Jan.3l Report 1 day F.Feb.l Report 4 day $2849.00 US 9 days Services:9 days @ $800 US $7200.00 Expenses:2849.00 ©Total:$10049.00 US ALASKA INTERTTIE OPERATING COMMITTEE FRIDAY,JANUARY 11,1991 (ANCHORAGE MUNICIPAL LIGHT &POWER CONFERENCE ROOM) MEETING MINUTES Present: James Hall Alaska Electric Generation &Transmission (AEG&T)/Matanuska Electric Assoc.(MEA) J.F.McIntosh Matanuska Electric Assoc.(MEA) Stan Sieczkowski Alaska Energy Authority (AEA) Afzal H.Khan Alaska Energy Authority (AEA) John Cooley Anchorage Municipal Light &Power (AML&P) Doug -Hall Anchorage Municipal Light &Power (AML&P) Tom Lovas Chugach Electric Association (CEA) Bradley Evans Chugach Electric Association (CEA) Bob Orr Golden Valley Electric Association (GVEA) Marvin Ridle Golden Valley Electric Association (GVEA) The meeting was called to order by Chairman John Cooley at 9:15 a.m.at the Anchorage Municipal Light &Power Conference Room. John Cooley stated that the November 14,1990 meetingminutesberevised:add a sentence at the end of third paragraph on page 3 "A draft recommendation to the IOC was Gistributed."Tom Lovas moved that IOC adopt the November 14,1990 meeting minutes with the above mentioned revision. Bob Orr seconded the motion.The motion was adopted unanimously. The January 11,1991 meeting agenda was modified by adding Item V(I)-December 1990 and January 1991 outages and Item V(J)-Bradley Project DECnet.The modified agenda was adopted unanimously. Under Dispatch,Marvin Riddle stated that the subcommittee aid not meet. Under Protection Coordination,Afzal Khan distributed a CEA letter dated November 21,1990 in which GVEA,CEA,and ML&P agreed on base case generation dispatch at the November 14, 1990 meeting.He stated that the CEA letter was fax to Power Technologies,Inc (PTI)for comments.The next Protection Coordination meeeting will be held when comments are received from PTI. Under Machine/Rating Subcommittee,Afzal stated that the 1 subcommittee did not meet.The Machine/Rating subcommittee will meet on January 14,1991. Under Insurance,Chairman Stan Sieczkowski stated that the subcommittee did not meet. Under Reliability/Criteria,Chairman John Cooley on behalf of Mike Massin distributed the November 30,1990 subcommittee meeting minutes.Tom Lovas distributed a copy of CEA letter to I0C members,dated November 14,1990, regarding Railbelt Powerflow,Short Circuit,and Stability Databases and Software. Under Correspondence,John Cooley stated that he received the following: 1)CEA letter to AEA,dated November 12,1990,on the Joint Meeting of the Reliability Criteria and Protection Coordination subcommittees. 2)AEA letter,dated January 2,1991,regarding Bradley Project DECnet. Under Intertie Status,Afzal Khan distributed the following: 1)AEA Memorandum,dated December 7,1990,on Anchorage-Fairbanks Intertie,Structure #749 Shift. 2)AEA letter,dated December 10,1990,to GVEA on Anchorage-Fairbanks Intertie,Structure #749. 3)December 23,1990 Intertie Outage report by Doug Hall. 4)GVEA Memorandum "Brief Overview of the 1990 Christmas Outages,"dated January 8,1991. 5)Cantwell power transformer Gas Analysis Report,dated January 4,1991. 6)Cantwell power transformer Gas Analysis Report,dated January 10,1991. 7)Anchorage-Fairbanks Intertie Accounting Report, November 1990. There was a brief discussion on structure #749 shift.GVEA will work closely with AEA to address the foundation problems.There was also a brief discussion on ice loading problen.J.McIntosh expressed his concern of ice loading problem in the Caswell Lake area. )--u-FO Under UAF Computer Program,there was no discussion. No visitors were present. The Operating Committee took a break from 9:50 a.m.to 10:05 a.m. The Operating Committee went into work session. Mr.McIntosh discussed the possibility of removing static wire from dead ends.Bob Orr stated that the IOC should get engineering advice and I0C should get at least two recommendations.Stan Sieczkowski recommended that the MEA should put up warning signs.Bob Orr stated that we need somebody to investigate the icing problem-review video tapes,pictures,etc.to analyse the icing problen.The recent Intertie outages,coordination,and repairs were discussed. Under Dispatch/Protection Coordination,John Cooley stated that these two subcommittees continue working on the underfrequency load shedding study. Under Reliability/Criteria,John Cooley stated that this subcommittee contiue work on reactor for Douglas substation and Dynamic System Monitor installation.This subcommittee should recommend that each utility purchase PTI PSS/E program.This subcommittee is to finalize UAF discontinue the IOC data base mamangement with EII program. Under SVS,there was a brief discussion on SVS Building snow loading problems. Under Turbine/Generator Field Test Report Update,Afzal Khan distributed the revised pages incorporating all of the comments. Under Bradley Project DECnet Interface,Chairman John Cooley stated that the IOC concurs with the Energy Authority that the interface be located at both CEA and ML&P. Under Formal Committee action/recommendation,no action was taken. Under Subcommittee Assignments,Chairman John Cooley directed the DISPATCH subcommittee to meet at the discretion of its Chairman to work on:Dispatch Training Plan;and underfrequency load shedding study.In addition,the Dispatch subcommittee is to review the Outage Report Procedures and coordination among the area utilities and Technical Guidelines for Operation,Metering and Protective 3 Relaying for Non-Utility Power Producers and Cogenerators and develop operating guides to go with then. Chairman John Cooley directed the MACHINES/RATING subcommittee to meet on January 14,1991 to start reviewing machines rating book. Chairman John Cooley directed the PROTECTION COORDINATION subcommittee to meet at the discretion of its Chairman to continue work on underfrequecy load shedding study. Chairman John Cooley directed the RELIABILITY CRITERIA subcommittee to meet at the discretion of its Chairman to continue work on reactor for Douglas Substation.Chairman John Cooley also directed this subcommittee to jointly meet with the Protection Coordination subcommittee on Dynamic System Monitor installation for the Alaska Intertie. THE NEXT REGULARLY SCHEDULED MEETING OF THE ALASKA INTERTIE OPERATING COMMITTEE WILL BE ON TUESDAY,MARCH 12,1991,AT 9:30 A.M.AT THE FAIRBANKS MUNICIPAL UTILITIES SYSTEM BOARD ROOM,FAIRBANKS,ALASKA. The Operating Committee set the agenda for the next meeting of the Operating Committee. Tom Lovas moved for the meeting to adjourn,seconded by John Cooley.The Operating Committee unanimously adopted the motion to adjourn at 12:30 p.m. Respectfully submitted, Alaska Intertie Operating Committee Attachments: 1.March 12,1991 meeting agenda2.IOC January\!,1991 meeting attendance sheet. The following were distributed at the November 14,1990 meeting: 3 .CEA letter to AEA,dated November 21,1990,regarding Railbelt Loadshedding Study Base Case Generation Dispatch. 4.Reliability/Criteria Subcommittee November 30,1990 meeting minutes with attachments. 4 14. 15. CEA letter to IOC members,dated November 14,1990, regarding Railbelt Powerflow,Short Circuit,and Stability Databases and Software. CEA letter to AEA,dated November 12,1990,on the Joint Meeting of the Reliability Criteria and Protection Coordination subcommittees. Reactor For Douglas Substation-Cost Estimate AEA letter,dated January 2,1991,regarding Bradley Project DECnet. AEA Memorandum,dated December 7,1990,on Anchorage-Fairbanks Intertie,Structure #749 Shift. AEA letter,dated December 10,1990,to GVEA on Anchorage-Fairbanks Intertie,Structure #749. December 23,1990 Intertie Outage report by Doug Hall. GVEA Memorandum "Brief Overview of the 1990 Christmas Outages",dated January 8,1991. Cantwell power transformer Gas Analysis Report,dated January 4,1991. Cantwell power transformer Gas Analysis Report,dated January 10,1991. Anchorage Fairbanks Intertie Accounting Report, November 1990. IV. vi. vilI. VIII. IX. Meeting ALASKA INTERTIE OPERATING COMMITTEE MEETING AGENDA TUESDAY,MARCH 12,1991 BEGIN AT 9:30 A.M. Adoption of prior meeting minutes Approval/modification of agenda Committee correspondence and reports A.Dispatch Subcommittee B.Protection Coordination Subcommittee Cc.Machine/Rating SubcommitteeD.Reliability/Criteria Subcommittee E.Correspondence Received F.Intertie Status Update Visitors comments related to items on agenda Work Session A.Recess and work session B.Dispatch c.Protection Coordination D.Machine/Rating E.Reliability/Criteria F.SVS G.FY92 Budget H.Election of Officers I.T/L Structure and Conductor Evaluation Formal Operating Committee action/recommendation Subcommittee Assignments Determine agenda for next meeting Adjournment location:Fairbanks Municipal Utilities System Board Room 645 Fifth Avenue Fairbanks,Alaska 99507 (907)456-1000 Diinurtes ALASKA INTERTIE OPERATING COMMITTEE HEE TING In Attendance late San 11.91 Nane Lonpiy Phone Ha Sohn S Coo ae,Mote O35 SYS) Zz >|Le S96 Wher.a)A Cent fed /S™/ bem CT pros MEA W599} wl ty lebee |(A€ecdT PES-7269 >Heil Merl 262-375% Ficahley Eouny|CEA 762-4784 Tout JOE CéA4-mr -1 PY 2. Afzo [_[Chaow AEA Sé/-777 oo Seckoack LLLP Zol-7Z6/ CHUGACH ELECTRIC ASSOCIATION,INC. kececvyesl bec F,/7%0November21,1990 Alaska Energy Authority Department of Commerce &Economic Development State of Alaska 701 East Tudor Road Anchorage,AK 99503 Attention:Mr.Afzal Khan Subject:Railbelt Loadshedding Study Base Case Generation Dispatch Dear Afzal: The following dispatch scenario was chosen for use in the verification and initial loadshedding studies agreed upon October 25,1990.The case is a duplication of an August 29,1990 trip of Beluga units 7 and 8. Chugach Generation Beluga 1 6 MW Bernice Lake 3 18 MW 3 56 MW Bernice Lake 4 18 MW 5 55 MW 7 61 MW 8 23 MW Total CEA/HEA/MEA/Seward Load -217 MW AML&P Generation Golden Valley Generation AML&P 5 27 Mw ZNP2 16 MW AML&P 8 68 MW AML&P 3 14 MW FMUS Generation CH5 17 MW Eklutna 1 16 MW 2 16 MW Total sales as measured at Teeland were 53 MW going north. Trip Beluga Unit 7,coast down on unit 8 from initial load to trip in 3 minutes (4 minutes was actually recorded). ML&EP shed 9.5 MW of load at 59.2 Hz with a 3 cycle delay and 5 oO cycle breaker time. Chugach shed load at 59.3 Hz with a 30 &40 cycle time delay, 5601 Minnesota Drive P.O.Box 196300 *Anchorage,Alaska 99519-6300 Phone 907-563-7494 e FAX 907-562-0027 Page 2 Base Case Nov.21,1990 approximately 4.5 MW each station with a 2 cycle breaker time. GVEA/FMUS loadshed 12.5 MW of load at 59.3 Hz with a 7 cycle time delay including breaker time. Please use this actual case to perform the system studies agreed on. In each of the cases,all existing underfrequency relays between control areas should be disabled.Automatic Generation Control (AGC)should be modelled to change the governor set points after 2 seconds to fully utilize the available spin on each machine. It is our understanding the following cases are to be performed by PTI: Case I (a)-Duplication of the August 29,1990 event by the PTI software and generator models. Case I (b)-Same as Ia without loadshedding enabled,without spinning reserve by loadshed in Fairbanks Case I (c)-Same as Ia without loadshedding enabled,with spinning reserve by loadshed in Fairbanks at 59.7 Hz with a 2 second time delay.Fairbanks spinning reserve requirement is 20 MW. Case II (a)-Using same loads in the system as in case 1,displace power flow over the northern intertie by increasing Fairbanks (GVEA/FMUS)generation,trip units with all loadshedding disabled. ML&P/Chugach generation schedule would be changed as follows: Beluga 6 Bernice Lake 3 7 MW 53 52 61 GVEA Zehnder 1 -5 MW North Pole 41 MW (swing bus) FMUS CH5 17 MW 1 3 5 7 8 23 AML&P 3 5 8 S2323523Case II (b)-Same as case IIa,with Zehnder replaced by loadshed in lieu of spin.Total spinning reserve in Fairbanks is 30 MW. Spinning reserve shall be met by a combination rotating spin and loadshed at 59.7 Hz with a 2 second time delay. Case IIIa -Using the same base case as in I with generation changes in Case II,reduce the Fairbanks load such that 0 MW is flowing over the northern intertie prior to the event.Trip the unit.Fairbank's spinning reserve should be assumed to be met by loadshedding at 59.7 Hz with a 2 second delay.Plot frequency Page 3 Base Case Nov.21,1990 response assuming the loadshedding system presently in use is active. Case IIIb -Same as case IIIa,except the system loadshedding should be disabled to ascertain how low the frequency will drop prior to recovery.Loadshedding used for spinning reserve requirements should be in service. Any correspondence or clarifications regarding the studies should be copied to all utilities. Intertie Operating Committee -Protection Coordination Subcommittee Chugach Electric Association,Inc. Wb ob -- ot Da&ve Burléngaye Anchorage Municipal Light &Power nbhen ry Hembree Golden Valley Electric Association Le -Stéven*Haagenson DWB/ck File 1060.01 MI1OATLES Page 1 MUNICIPALITY OF ANCHORAGE MEMORANDUM DATE:December 19,1990 TO:Mike Massin,Director of Engineering CEA FROM:Moe Aslam,Planning Engineer ML&P Mee.Aline SUBJECT:1.0.C.Reliability Subcommittee (11-30-90)meeting minutes Attached are the minutes of the November 30,1990,meeting. Please let me know if you have any comments,thanks. Attachment:Minutes of Reliability Subcommittee 11-30-90 meeting. MTA/mb cc:Larry Hembree Mio Johnson John Cooley Page 2 ALASKA INTERTIE OPERATING COMMITTEE RELIABILITY SUBCOMMITTEE MEETING :UAF,Duckering Bldg NOVEMBER 30,1990 HHH E HH HHHHRH HERE EMEETING MINUTES#©©%0 0m ee eee ee PRESENT: Or.John Aspnes Mike Massin Dave Burlingame Tim Newton Steve Haagenson Jim Smith Jim Hall Afzal Khan Larry Colp Larry Hembree Moe Aslam University of Alaska Chugach Electric Association Chugach Electric Association Chugach Electric Association Golden Valley Electric Association Golden Valley Electric Association Manatuska Electric Association Alaska Energy Authority Fairbanks Municipal Utilities System Anchorage Municipal Light &Power Anchorage Municipal Light &Power The meeting commenced at 1:15 P.M.im the Duckering BuildingsconferenceroomoftheUniversityofAlaskaFairbankscampus. Chairman Mike opened the meeting by reading the agenda items as follows: 1.PTI and Electrocon (PSAVEII)softwares and Or.Aspnes proposals. 2.Load Reactor at Douglass substation. 3.Dynamic System Monitor installations. Mike asked DOr.Aspnes to go over his proposals at which time Dr.Aspnes distributed the copies of his three proposals (attached) and started with the presentation.The first proposal consisted of th Generator testing model conversion from PTI to EIT.Mike requested exclusion of this proposal since the utilities are intending to utilize the PTI software.Or.Aspnes also supported the use of PTI an added that he felt PTI software is more advanced than PSA/VEI!I softwar and the-PTI software offers a greater range of modelling and altewe the user to create additional models with basic knowledge of Fortran.The committee members seconded the use of PTI. The other proposals consisted of UAF database management contract renewal,PTI PC software and Hardware purchase by the [OC for UAF and the Workshops schedules.Or.Aspnes went over the costs (attached)an then briefly left the reaom so members have a chance to discuss the proposals.The members unanimously felt that it would be economical for them to maintain their own databases and cancel the contract with UAF.AEA would coordinate if database was needed for a study. Page 3 Members also felt that they would not be able to financially support UAF with the PTI software and Hardware purchase.Afzal Khan of AEA said the I0C has $142,000 in the General study fund for 1991.This fund is broken into $40k for Oatabase management,$592k for Analysis and $50k for Professional services. Mike,Dave and Larry suggested that a recommendation be made to the 10C to pay for a copy of the PTI PC software for UAF,equalized cost per tabulation from Tim Newton of CEA is $26,082 if ML&P,GUEA,AEA, CEA and UAF each got a copy.Utilities are planning on obtaining the necessary approvals from their managers for this purchase. Members seconded this motion and also added that [0C also grant to UAF $7,000 for the purchase of the PC and Hardware.The motion was passed.The members also agreed that the existing EII/"PSA software may remain on the UAF VAX for educational ete purposes. Or.Aspnes returned ta the room at this time and Mike summarized the committee's discussion and proposed recommendations to the IOC as follows: 1.UAF to discontinue the efforts of Database management with EII and [0C cancel the Database management contract with UAF. 2.Utilities take up their own Database managements using the PTI software being considered by the Utilities amd AEA. 3.IOC consider purchasing the PTI PC software for UAF and also allow up to $7,000 for the purchase of a 386 PC. 4.UAF to define some different role to the subcommittee such as holding training seminars and participating in the Alaska Annual Engineering and Operations conference,etc. 5S.Utilities joining EPRI may also create research opportunitiues for UAF. 6.Utilities also would like to cancel their computer accounts at UACN. 7.Utilities and the subcommittee is willing to support Dr.Aspnes and the EE dept to obtain funds from the University system or the State.Existing EII/"PSA may remain on the UAF VAX. Or.Aspnes acknowledged the contents in Chairman Mike's summary and the subcommittee proceeded on with the next item on the agenda, "Load reactor at Douglass substation". Jim Hall stated that TRENCH company has quoted a price of $90,000 for the 8 MVAR reactor which is being considered for installation. Purpose of the reactor is to hold voltage within limits when SUS at Teeland is started up.Jim and Moe added that there was ample space available at the Douglass sub and there is even a spare bay for the Reactor Breaker. Page 4 Afzal Khan of AEA recommended that a more detailed estimate of total installed cost be prepared at the time HEA finalizes the Intertie upgrades recommendations.Jim and Moe agreed to continue work in this area.The members seconded progress of this item and Mike asked Dave to give update on the last item on the agenda -OSMs. Dave reported that CEA has ordered its DSMs and they are due to arrive in May 1991.The OSMs are planned for installation at Teeland and Goldhill to monitor the intertie system performance. Mike asked that an update of the agenda items 2 and 3 be given at the next meeting.The meeting was adjourned at this time.The next meeting is planned after the I[0C meets in January 1991. Mike will contact the members to coordinate the time and place. Attachments:1.Or.Aspnes/'UAF proposals 2.Cost tabulation of PTI PC software by Tim Newton MTA/mb Lee Hevecce MLA DMX DANCE Steet Kabila ty.Sib nti,as at URE __./l--Fe-70, eee ee ee eens -_-_-.eo ee. !: wm Ate oon ae aa of a STH MADR GALse CVFA. 4=Spe,Gagan >UAL -=_Myke Masse _-CEAingPSfh:CGleFt ee_pn A hetge-Ahoy ||_feel H.Gan .AEA... Lary Cate.TIM...aw.Moe Arlime MteEP a ee (907)474-7775 FAX (907)474-6087UniversityorALASKAFAIRBANKSguy School of Engineering Institute of Northern Engineering 539 Duckering Building Fairbanks,Alaska 99775-0660 TO:Alaska Intertie Operating Committee FROM:John Aspnes 'tm Capra Electrical Engineering Dept. THROUGH:Reliability Subcommittee DATE:November 27,1990 SUBJECT:Power System Analysis Software and Attached Proposals Alaska Intertie Operating Committee (IOC)utility members are presently considering acquiring personal computer (PC)based software for power flow,graphics,fault analysis and transient stability (dynamic simulation).Proposals have been received from Electrocon International,Inc.(EII)andPowerTechnologies,Inc.(PTI). EIT Power System Analysis (PSA)software is currently resident on a VAX 8800 mainframe computer at the University of Alaska Fairbanks (UAF)campus.The University of Alaska Computer Network (UACN)maintains the system and access points elsewhere in Alaska.A data base for the railbelt utility system has been developed for power flow and transient stability utilizingthePSAsoftware. Recent field tests of railbelt generation systems have been modeled by PTI and a data base has been created reflecting those tests.This data base is compatible with PTI PSS/E-W analysis software and recent IEEE standard models.It is not directly compatible with PSA software models.Thus,in order for PSA software to utilize results of the field tests,either new models will need to be developed by EII or model translation between PTI and EII could be accomplished as an alternative.A proposal from UAF to the I0C titled "Model Conversion from PTI to EII formats"follows the second (system identification)approach. The PTI software proposal indicates that IOC members and UAF may acquirePSS/E-W software based on the lease fee schedule for single user multiple-téoptes.Thus,copy one is $48,000,copies two through seven are $14,400 each,and additional copies are $2,000 each.The PTI cover letter indicates that one $5,000 per year update fee will cover all users if new user manual pages are duplicated and distributed and disks containingsoftwaremodificationsareshared. The EII software proposal dated September 10,1990 for conversion from the VAX installation to PC-based code (TRANSMISSION 2000)provides credit for the purchase price of the VAX-installed software ($46,600).The first copyofTRANSMISSION2000software,including power flow,short circuit,one-line diagram,transient stability and power flow reduction/data conversion to UAF is 50%of the single copy price ($39,750 x 0.5 =$19,875).Additional copies to UAF are $200 each.A 37.5%discount is offered to utilities resulting in a purchase price of $39,750 x 0.625 =$24,843.75lesscreditsor$22,343.75 less credits if the power flow reduction/dataconversionprogramisnotpurchased.EII requires a maintenance feerenewalof$10,800 and is willing to waive a lapsed maintenance fee of $10,800 ordinarily charged since the VAX-based PSA software maintenance expired in 1988 and has not been renewed. In the following price comparison between PTI and EII software,I assume that Alaska Energy Authority (AEA),Anchorage Municipal Light and Power(AMLP),Chugach Electric Association (CEA),Fairbanks Municipal Utilities System (FMUS),Golden Valley Electric Association (GVEA),Homer Electric Association (HEA),and Matanuska Electric Association (MEA)want copies ofPT]software,I would like two copies for UAF,if PTI is agreeable to thisandtheIOCiswillingtocommittheresources.This totals nine copies.The cost of these is $138,400 or $15,378 each with an optional $5,000 total annual maintenance fee.The I0C an get to keep the existing EIIsoftwareifPTIsoftwareispurchased. If EII TRANSMISSION 2000 software is purchased and the existing VAX versionistradedin,the total cost of a like number of copies (9)becomes:5$21,875 (2 UAF copies)+$22,343.75 x 7 -$27,000 (CEA existing software}-$46,600 (initial cost of VAX software)+$10,800 (maintenance fee)=$114,481.25.We would lose the existing PSA software in one year underthisscenario.Annual maintenance fees are also apparently optional andtotal12%of the list price for utilities and half that for UAF. Therefore,the annual maintenance fee for all users is (0.12 x $35,750 x 7)+($2385 for the UAF copies)=$32,415. If the above numbers are valid,cost after one year of maintenance fees is $143,400 for PTI (9 copies)and $147,896.25 for EII (9 copies).The PSAprogramsarereturnedtoEIIoneyearafterconversiontoEIIPC-based software.All above numbers assume the EII power flow reduction/data conversion program is not purchased. I recommend that the PTI PSS/E-W software be acquired by the IOC for its members and UAF.I also propose that IOC provide one computer platform and output printer compatible with PSS/E-W to UAF so that it may be dedicated for future data base maintenance and upgrade,workshops,analysis projects for I0C and be used as a tool for enhancing the education of power engineering students at UAF so they can gain experience on PSS/E-W softwarepriortoemploymentwithrailbeltutilities.Since the investment has already been made in EII PSA software,I further recommend that IOC provide for its maintenance and that the railbelt data base be maintained for both EII and PTI formats and models.In making this last recommendation,IassumethatenoughfutureconsultantsforIOCmemberutilitieswillneed the EII data base to make the necessary model conversion and data base'Maintenance worthwhile. DRAFT PROPOSAL TO ALASKA INTERTIE OPERATING COMMITTEE FROM UNIVERSITY OF ALASKA FAIRBANKS INSTITUTE OF NORTHERN ENGINEERING MODEL CONVERSION FROM POWER TECHNOLOGIES,INC. TO ELECTROCON INTERNATIONAL,INC.FORMATS John Aspnes Principal InvestigatorUniversityofAlaskaFairbanks (907)474-6098. B.David Spell Principal InvestigatorUniversityofAlaskaFairbanks (907)474-7819 NOVEMBER 1990 John P.Zariing,Director Institute of Northern Engineering University of Alaska Fairbanks (907)474-6097 Jerome L.Trojan Vice Chancellor for Administration University of Alaska Fairbanks (907)474-7340 INTRODUCTION The railbelt utilities and the Alaska Energy Authority (AEA)have received results of generator,exciter,and governor field tests completed by Power Technologies,Inc.(PTI).The exciter and governor models used by PTI to input field data into PTI's analysis software are not directly compatible with Electrocon International,Inc.(EIT) models.This proposal is to convert PTI models to EII models and thus modify the existing data base residing on the University of Alaska Computer Network (UACN)VAX 8800 computer at the University of Alaska Fairbanks (UAF). PROJECT JUSTIFICATION This proposed project upgrades the data base developed and maintained under a sequence of successful previous projects.As noted in the introduction,this data base resides on the UACN VAX 8800 computer at UAF and is available for use by railbelt utilities and the AEA through their individual accounts.The data base has been used for past power system analysis projects completed by UAF for the utilities and by engineering consulting firms retained by the utilities and the AEA for major railbelt system studies.This upgrade ensures that the data base will continue to be useful in future system studies. This model conversion project will enhance the education of future power engineers for the Alaskan utility industry by providing an additional software tool (Matrix,)for UAF and increased student experience in system modeling. PROJECT SCOPE 1.Acquire one copy of Matrix,software package from Integrated Systems,Inc.,which provides the capability of identifying parameters of a new model,given input and output data from another model. 2.Convert PTI governor and exciter models to EII models.This is expected to require a family of operating point-dependent models in some cases in which nonlinearities exist. 3.Verify model compatibility and accuracy. 4.Provide the Intertie Operating Committee (IOC)with a final report which will give parameters for EII models and appropriate operating ranges. PROJECT SCHEDULE Timetable January 1991-May 1991 Acquire one copy of Matrix,software, purchase dedicated IBM 80386 PC with output printer having configuration compatible requirements for PTI's PSS/E- W18 software (provided for in separate proposal),gain expertise in Matrix, software,attend training class in Santa Clara,California ($900 normal fee,but free to a university that is purchasing software). June 1991-August 1991 Convert PTI models to EII models.Verify model compatibility,accuracy,and valid operating range. Write final report. September 30,1991 Present report to IOC. 3 January SALARIES 1.Principal Investigator J.Aspnes 80hrs @ $50.49/hr 2.Principal Investigator 8.0.Spel} 80 hrs @ $32.96/hr 80 hrs @ $32.96/hr 3.Graduate Research Students 560 hrs @ $10.30/hr 360 hrs @ $10.30/hr LEAVE BENEFITS 1.16.1%of A.1 and A.2 STAFF BENEFITS 1.28.3%of A.1,A.2,and 8.1 TRAVEL 1.One trip between Fairbanks,AK and Santa Clara,CA for training course. SERVICES 1.Photocopies, publication costs 2.Postage,telephone SUPPLIES 1.Photocopy and expendables 2.Floppy disks 3.Mailing costs EQUIPMENT 1,Matrix,software (Educational price shown is about 20%of the commercial price.) 2.Computer and output printer are needed and are shown on a companion proposal. OVERHEAD 1.43.0%of MTDC* (Direct less equipment and graduate student support.) PROJECT TOTAL *MTDC =Modified Total Direct Cost BUDGET 1991 -30 September 1991 FY91 FY92 TOTAL $4,039.20 $4,039.20 2,636.80 2,636.80 2,636,80 2,636.80 5,768.00 5,768.00 3,708.00 3,708.00 424.52 1,074.84 1,499.36 866.35 2,193.49 3,059.84 1,200.00 1,200.00 100.00 200.00 300.00 100.00 100.00 200.00 100.00 100.00 200.00 50.00 50.00 100.00 50.00 50.00 100.00 1,000.00 1,000.00 2,376.90 4,491.06 6,867.96 $14,672.58 $18,643.38 $33,315.96 DRAFT PROPOSAL TO ALASKA INTERTIE OPERATING COMMITTEE FROM UNIVERSITY OF ALASKA FAIRBANKS INSTITUTE OF NORTHERN ENGINEERING ALASKA INTERTIE DATA BASE MANAGEMENT AND WORKSHOP DEVELOPMENT AND PRESENTATION NOVEMBER 1990 John Aspnes Jerome L.Trojan Principal Investigator Vice Chancellor for Administration University of Alaska Fairbanks University of Alaska Fairbanks (907)474-6098 (907)474-7340 John P.Zarling,DirectorInstituteofNorthernEngineeringUniversityofAlaskaFairbanks (907)474-6097 INTRODUCTION This proposal requests support for four 3-day workshops for electric utility engineers to be held at the University of Alaska Fairbanks (UAF).These follow two successful 3-day workshops that were scheduled in January and May 1990.In addition,continuing support is requested for management and update of the data base developed and upgraded under three previous projects funded by railbelt utilities and the Intertie Operating Committee (I0C). PROJECT JUSTIFICATION The four proposed 3-day workshops will provide an instructional forum to encourage more effective use of analysis tools available to utility engineers.These workshops,as well as the continued management and upgrade of the railbelt utility data base,build upon tasks completed under three previous projects by UAF for the IOC.The data base in its present form is in Electrocon International,Inc.(EII)format and resides on the VAX 8800 computer operated by the University of Alaska Computer Network (UACN)at UAF.The Electrocon software and data base are available for use by railbelt utility and Alaska Energy Authority (AEA)personnel.The data base has been utilized for past system analysis projects at UAF and also by engineering consulting firms retained by Alaska utilities and the AEA for major railbelt system studies. This project.will help participating utilities to continue receiving dividends from their past investment in software acquisition and data base development.This will be true regardless of the primary software chosen by the utilities for future system analyses (Power Technologies, Inc.(PTI)or EIT). PROJECT SCOPE The first proposed workshop topic in chronological order is transient analysis of power systems utilizing the electromagnetic transients program (EMTP).It is tentatively scheduled for August 1991. The second and third proposed workshops will be similar to those held in January and May 1990 and are tentatively scheduled for January and May 1992.Topics will be power flow and fault analysis (January 1992)and transient stability analysis (May 1992).The railbelt data base in its most current form will be utilizedforhands-on computer-based analysis as in previous workshops. The fourth proposed workshop,tentatively scheduled for August 1992, will focus on power system component modeling for transient stability.- analysis.It is a natural outgrowth of the recent PTI study results and = the companion UAF proposal to convert PTI models to EII models.The Matrix,software described in that proposal will be utilized in the workshop,assuming the software will have been acquired and utilized for model conversion.Properties of linear and nonlinear systems,system identification,and other classical and modern control system-related topics will be included. Additional project tasks to be performed include management and periodic upgrade of the data base currently residing on the UACN computer.This includes making changes to the master copy of the data base three times (August 1991,May 1992,and December 1992)during the contract period using data supplied by each utility.Data base upgrades will be made in PTI and EIT format,assuming the IOC acquires the second (PTI)software package and computing platforms on which it may be run. After each data base upgrade,at least one power flow and one stability analysis case on PTI and EII software will be run with the revised data to ensure that the modified data base is acceptable to the computer programs.As in the past,each participating utility will have access to the master data base from its own UACN account but will not be able to directly modify it.Also,individual user account charges from UACN will continue to be the responsibility of each utility.If PTI software is purchased,a master data base will be maintained at UAF and copies will be sent via floppy disk to participating utilities. Project tasks also include providing ongoing support to the IOC and utility users in the remote usage of EII/PSA program and any program or data base updates.Similar support will be extended to PTI/PSS/E-W software users as UAF expertise is developed. I recommend that the utilities and the AEA purchase,for themselves and for UAF,the PSS/E-W programs offered by PTI,and IBM 80386 PCs and output printers as needed.I further recommend that the EII software, currently residing on the University of Alaska Computer Network (UACN) VAX 8800,be maintained and that UAF manage and upgrade the railbelt data base in both PTI and EII formats to provide maximum flexibility and - ability to meet the needs of future system studies,whether done by consultants,railbelt utilities,or UAF. PROJECT SCHEDULE Timetable May 1991-December 1992 Update and review system data base;verify new data base works with computer programs.These tasks will be performed three times during the contract period, with one revision to be completed by August 30,1991,a second revision to be completed by May 29,1992,and a third revision to be completed by December 31, 1992.This schedule assumes revised data base information will be received from all participating utilities by May 31,1991, March 31,1992,and October 30,1992 respectively for each of the three August 1991,January 1992, May 1992 and August 1992 revisions. Provide support to the IOC and utility users in the remote usage of the EII/PSA program and any program or data base updates.Similar support will be extended to PTI/PSS/E-W software users as UAF expertise is acquired. Four 3-day workshops to be held at UAF. Oo ad BUDGET 1 May 1991 -31 December 1992 FY 91 SALARIES 1.Principal Investigator J.Aspnes 340 hrs @ $50.49/hr 120 hrs @ $50.49/hr 2.Graduate Research Students 280 hrs @ $10.30/hr 2,884.00 1320 hrs @ $10.30/hr 640 hrs @ $10.30/hr 3.Technician 48 hrs @ $15.82/hr 16 hrs @ $15.82/hr LEAVE BENEFITS 1.16.1%of A.l 2.19.1%of A.3 STAFF BENEFITS 1.28.3%of A.1 and 8.1 2.24.2%of A.3 and 8.2 TRAVEL 1.One trip between Anchorage,AK and Fairbanks,AK (3 trips @ $250). SERVICES 1.Photocopies,publications costs 2.Postage,telephone 3.Computer rental for workshops if the School of Engineering is unable to provide them. SUPPLIES 1.Photocopy and expendab les 2.Matling costs EQUIPMENT 1.Computer;owtput printer,PTI software, EMTP softwere and Matrix,software are needed and are considered separately. OVERHEAD 1.43.0%of MTOC* (Direct less equipment and graduate student support.) PROJECT TOTAL 2,884.00 *MTOC =Modified Total Direct Cost FY 92 $17,166.60 13,596.00 759.36 2,783.82 145.04 5,640.31 218.86 500.00 1,000.00 300.00 12,768.42 56,058.41 FY 93 6,058.80 6,592.00 253.12 975.47 48.35 1,990.70 72.95 250.00 4,579.23 21,820.62 TOTAL $17,166.60 6,058.80 2,884.00 13,596.00 6,592.00 759.36 253.12 3,739.29 193.38 7,831.01 291.82 750.00 1,500.00 400.00 17,347.65 80,763.03 Oo Pooi Credits 46,600 (For VAX refund) 1/2 Price Pgms 21,875 (for UAF) Remaining Pool 24,725 Pool per Utility 3,532 Pool Pgm List 22,344 (62.5%Disgount price for PF,SC,TS,&OL programs) Pool Pgm Net 18,812 CEA Bonus 4,656 CEA Bonust Pool 8,188 Electrocon PF SC OL Ts Bonus |Back Maint List Discounted [Net of Pool |Modets*|NetAMLP8,500 8,500 6,250 0 0 2,700 23,250 17,231 13,699 0 13,699 GVEA 8,500 8,500 6,250 12,500 0 2,700 35,750 25,044 21,512 $,000 |26,512ABA8,500 8,500 6,250 12,500 0 2,700 35,750 25,044 21,512 $,000 |26,$12CBA00004,656 2,700 0 2,700 -5,488 5,000 488 UARF 0 0 0 0 0 0 0 0 0 0 0 *Chugach Estimate of Model Upgrade Cost =$15,000 total PTI (plus UAF) PR&OL}SC TS Discounted |Install Net AMLP 18,421 |3,947 0 22,368 375 22,743 GVEA 18,421 |3,947 |10,417 32,785 375 33,160 AEA 18,421 |3,947 7]10,417 32,785 375 33,160 CEA 18,421 3,947 |10,417 32,785 375 33,160 UAF 0 0 0 0 0 0 PTI (sans UAF)_ PF&OL]Sc TS [|Discounted |Install Net oe oe) AMLP 14,737.}3,158 0 17,895 375 18,270 are a GVEA 14,737 |3,158 7,813 25,707 375 26,082 ZUtveAEA14,737 |3,158 7,813 25,707 375 26,082 22 Son CBA 14,737 |3,158 7,813 25,707 375 26,082 2 2.Ret Chugach Planning &Rates ttn(EN_COST.XLS)11/29/90 wu niettS 0 January 8,1991 REACTOR FOR DOUGLAS SUBSTATION 24.9 KV,7500 KVA REACTOR $75,000 RECLOSER 9,000 CONCRETE FOOTER 1,000 RECLOSER ACCESSORIES FOR SCADA CONTROL 1,000 MISCELLANEOUS INSTALLATION HARDWARE 1,000 SCADA HARDWARE 500 INSTALLATION LABOR 6,000 Oo ENGINEERING 4,000 OVERHEADS 19,500 TOTAL $117,000 o JDH:BB 302A.010891.285AC Mynawes DRAFT Y) ELECTRIC ASSOCIATION.INC. aA Se oa360°VINNESO™CRIVE @ FD S28 (86500 ¢ANCHO FAGE 4_-SK=395°2-c ,iw)>\327 583-7435 FACSIMILE. 907-562-0027 November 14,1990 TO:Railbelt Intertie Operating Committee Members FROM:Tom Lovas,Chugach Electric Association SUBJECT:Railbelt Powerflow,Short Circuit,and Stability Databases and Software SUMMARY AND RECOMMENDATION: Chugach's consultant,Southern Engineering Company (SEC),has advised that to use Electrocon's Stability software for any Railbelt system studies,it will be necessary to get Electrocon to provide upgrades before their programs will adequately mode!Railbelt generators.Based on Electrocon's statements and Chugach's previous experience,upgrading Electrocon's Stability software will entail both considerable costs and delays.When and if such upgrades were ever completed and acquired,it is likely that Electrocon's software will nonetheless remain inferior to PTI's in numerous significant ways.Overall cost savings indicated in Electrocon's proposal will be countered by the additional costs and delays associated with procuring adequate generator models from Electrocon.Consequently,in light of the fact that PTI's software can provide immediate access to the accepted and paid-for Railbelt Stability models and databases,and since PTI currently demonstrates both a superior product and a superior commitment to product support,and finally,since PTI has offered the Railbelt utilities substantial cost savings for their software if purchased jointly,Chugach recommends that the IOC coordinate and fund the acquisition of PTT's software immediately for present and future Railbelt system modeling needs. BACKGROUND: In 1987 the IOC,in concert with the Railbelt utilities,acquired several analytic programs from Electrocon,including Powerflow,Short Circuit,and Transient Stability programs.The software was installed on the University of Alaska's mainframe computer,and remote access given to all Railbelt utilities via modem hookup.The software has seen only very limited direct use by the Railbelt utilities due to both the user constraints imposed by the remote hookup and the inherent user-unfriendliness of the software itself.At this point,the Electrocon software is further handicapped by the absence of accurate Electrocon-compatible stability models for Railbelt generators. Recently,Power Technologies,Inc.(PTI),has completed the modeling and parameterization of the Railbelt generation and transmission systems,using their own software,PSS/E.The Railbelt Intertie Operating Committee November 14,1990 Railbelt Powerflow,Short Circuit,and Stability Databases and Software resulting data have been provided to Railbelt utilities in PIT's unique model formats,adapted specifically for Railbelt generator peculiarities,and where possible,in the new (circa 1980) IEEE standard formats.These PTI models are presently available and running on PTT's PSS/E modeling programs.These programs are being used extensively by PTT to study the operation of Bradley Lake in conjunction with the rest of the Railbelt,to investigate underfrequency loadshedding practice on the Railbelt,and in several subsidiary investigations. The databases are generally thought by the Railbelt utilities to be the only accurate Stability representations presently available. PTI was requested to provide generator parameterizations compatible not only with the unique models they developed for Railbelt generator peculiarities,but also ones compatible with IEEE standard formats.PTI,however,provided IEEE standard models in the circa 1980 formats, not in the circa 1968 IEEE formats required by the Electrocon software.PTI claims that the topological differences between the newly derived models and the 1968 IEEE standard models are so far-reaching as to preclude the reliable usage of the older standards.Chugach's consultant in Long Range Planning studies,Southern Engineering Company (SEC),has arrived at the same conclusion.SEC informs Chugach that,consequently,the originally envisioned process of converting PTT's finished Stability database to a form usable by the Electrocon software may not be a viable approach.The problem is that the Electrocon Stability program accommodates none of the unique models which PTI has developed for the Railbelt generators,nor does it even accommodate the most recent (circa 1980)IEEE standard models. Thus,we are at an impasse with the present capabilities of the Electrocon software. Railbelt utilities have at least two options for acquiring in-house usage of suitable models of Railbelt generation.First would be to procure the needed model changes from Electrocon. Chugach has previously approached Electrocon,requesting that they modify their software to provide models compatible with the PTI study results.They have said that they could eventually provide models compatible with the "new"IEEE standard at nominal expense ($2,000 to $15,000),since it is something they believe they need to do anyway.However, Electrocon has indicated that to provide models which are compatible with the unique and more accurate PTI versions,and to provide the unique models required for the Bradley Lake project,would involve yet more time and expense. A second option is that Railbelt utilities combine their resources to purchase existing,up-to- date,and accurate Railbelt models and programs from PTI.This option has numerous advantages over merely adding the needed models to the Electrocon program,and few disadvantages.Enumerated below,are the primary advantages to pursuing this second option: (1)Working and Paid-For Databases are Already Available: The Railbeit utilities have already paid for the databases which PTI has developed,and which PTI is employing for completion of several important studies relating to the 1744.TIN DRAFT Railbelt Intertie Operating Committee November 14,1990 Railbelt Powerflow,Short Circuit,and Stability Databases and Software Bradley Lake and Railbelt Loadshedding issues,among others.Even though we give high credibility to the working,accepted,and paid-for PTI databases,we are considering attempting to re-create them simply because we cannot use them as is -since we don't have PTT's software.Currently,no software vendor supplies the required models except PTI.Aside from acquiring PTTs programs,we presently have no option but to use older models and databases which have recently been proven inaccurate by the recent dynamic tests performed on the Railbelt generators. (2)Software Vendor Product Support: Usage of the Electrocon Powerflow and One-Line programs at Chugach has uncovered several flaws,in our opinion.A recent demonstration at Chugach reveals that the PTT software explicitly addresses all but one of the major deficiencies of Electrocon's software.Their attention to these user-oriented details reflects PTT's stronger commitment to customer and product support. To date,Electrocon still has not provided the more recent (circa 1980)IEEE Standard models,nor have they committed to do so by any certain time,although they have expressed their intent to do so eventually.They have indicated a willingness to update their models within three months or so providing that users directly share the expense of modifying the software. In contrast,PTI has rightly considered accommodation of existing IEEE standards as an essential service to their existing customers,and has already provided the new IEEE standard models to all their customers.In practice,they typically go beyond this fundamental requirement -in the last year,for example,in having added the unique modeling capabilities required for certain Railbelt generators.Meanwhile,we are still waiting for Electrocon to update their models from the 1968 versions. (3)Possible Cost Savings: PTI has submitted an offer to permit a single entity,such as the IOC,to formally purchase several copies of PTT's software (beyond the first copy)at multi-user license prices,and then distribute the individual copies to participating utilities.The participating utilities would then pay equal fractions of the total cost.If only three utilities participate,the cost would be about $30,000 each.Should all Railbelt utilities participate,the cost per utility could drop to as low as $20,000.These costs compare to the single copy price of about $50,000. (4)Software Vendor Standardization on the Railbelt Benefits incidental to Railbelt-wide standardization on a single program and database 1744.TIN DRAFT Railbelt Intertie Operating Committee November 14,1990 0)Railbelt Powerflow,Short Circuit,and Stability Databases and Software include the ability to share commonly formatted,mutually accepted,and independently verifiable data.The standardization will further the cause of accuracy and reliability in any technical studies performed on the railbelt system,since all key participants will be better poised to offer up-to-date and readily usable data,and better poised to verify the accuracy of any purported study results. (5)Software Quality: In the last year and a half of using the Electrocon software,Chugach staff has accumulated several explicit notes of unresolved program deficiencies.During PTT's program demonstration at Chugach,staff determined the status of the PTI programs regarding seventeen.In only one of these seventeen cases was the PTI software deficient along with Electrocon's.In the other sixteen cases,PTT's software was not subject to the same deficiencies as Electrocon's.These statistics suggest a quantitative measure of the quality of PTT's software versus Electrocon's.These statistics also agree with the overall subjective opinion of Chugach staff. For example,a key provision of PTT's software is that signals internal to generator's exciters and governors can be easily extracted from the simulation cases.Furthermore, step inputs may be injected at selected internal modeling points.(The Electroconre)program provides no such capabilities.)With these capabilities,the PTI software provides an essential component of the means to maintain the Railbelt stability database,given occasional and unavoidable generator component modifications.It should be noted that some cost savings may accrue to Railbelt utilities from these capabilities,since they will allow us to do more of the generator parameterization analyses in-house,reducing our dependance upon outside consultants.In the opinion of Chugach staff,these kinds of significant technical differences pervade comparisons between Electrocon''s and PT1's software. 1744.TTN DRAFT CHUGACH ELECTRIC ASSOCIATION,INC. RECEI ven November 12,1990 haces : POR QVA Roper«_. my Alaska Energy Authority PO BOX 190869 Anchorage,AK 99519 Attention:Mr.Afzal Khan Reference:A.I.0.C.--Joint Meeting of the Reliability Criteria and Protection Coordination Subcommittees Dear Mr.Khan: This letter confirms the joint meeting of the ReliabilityCriteriaandProtectionCoordinationSubcommitteesofthe Alaska Intertie Operating Committee. The meeting is scheduled for 1:00 P.M.on Friday,November 30,1990,in Room 202 at the Duckering Building on the University ofAlaska,Fairbanks Campus. The agenda will include the three following items: A.Reactor/Load Resistor at Douglas Substation B.Coordinate Dynamic System Monitor Installations C.U.A.F.Data Base Management and User Workshops If for some reason you are unable to attend,please let me know. Sincerely, LitNil |arMichaelE.Massin Director,Engineering Division MEM/pn MEM1:\INTERTIE\RELYMEET.007 110990 cc:John Cooley,Chairman c/o Municipal Light and Power Tom Lovas,Chugach Electric Association,Inc. 5601 Minnesota Drive e P.O.Box 196300 *Anchorage,Alaska 99519-6300 Phone 907-563-7494 «FAX 907-562-0027 Oo " Alaska Energy Authority wo floe-rsSorae AEA/OTHR/1183 January 2,1991 Mr.Stan Sieczkowski Director Facilities Operations & Engineering Alaska Energy Authority P.O.Box 190869 Anchorage,Alaska 99519-0869 Subject:Bradley Lake DECnet Interface Dear Mr.Sieczkowski: As part of the Bradley Lake Hydroelectric Project,we are installinghardwareandsoftwaretointerfacetheBradleyLakeSCADASystemwith the existing utility DECnet loop.Our Design Engineer,Stone &Webster, has reviewed interfacing Bradley Lake with the DECnet loop and recommends that the interface be located at both Chugach ElectricAssociation(CEA),and Anchorage Municipal Light and Power (ML&P).This would provide the shortest microwave path distance for interconnectingwiththeAnchorage-Fairbanks Intertie network,and create two paths for data access and reliability. Please discuss this matter at the next meeting of the Intertie Operating Committee and advise us of the Committee's concurrence or an alternate interface preference.We would like to configure the microwave paths early in 1991.If you have any questions and/or comments please call. Sincerely, David R.Eberle Project Manager cc:N.Bishop,Stone &Webster Engineering Corp. °O Box AM Juneau Alasxa 9981!(9071 465-3575X_PO Box 190869 =70!East Tudor Road =Ancnorage.Alaska 99519-9869 1907}561-7377skb9752(1) MEMORANDUM STATE OF ALASKA To:File Date:December 7,1990From:EB MarchegianiProjectManager Subject:|Anchorage/Fairbanks Intertie,Structure #749 Shift I talked with Remy Williams who indicated that Steve Swift (GVEA,452-1151)had called earlier this morning concerning Structure #749.I returned Mr.Swift's call to discuss the situation with him.He indi¢ated that he had contacted Mr.Afzal Khan earlier and then proceeded to brief me on the situation. Mr.Swift had some of his line crew investigate the structure since it appeared to be leaning down hill somewhat.They found that the structure was approximately 3 inches out of plumb using a 4 foot level.They also used some shovels to clear away some of the snow from the concrete foundation and found that there was some gap between the soil and the foundation,where the foundation had separated from the soil due to the structure being out of plumb.Mr.Swift indicated that a possible cause was the high rains that we had this fall that may have saturated the soils in that area and may have allowed the shift.This structure is a single pole structure and it is approximately 15 or so structures south of the Healy Coal Plant. Mr.Swift thought that they would probably get by until the spring.They would like to go in while the ground is still frozen but at the end of the winter such that they will have better.day light and other conditions to make a repair.He indicated that they would probably place a deadman anchor and then guy the structure off to it.He requested any information that we had on the foundation,such as daily logs, foundation drawings,and any other information that would be helpful in understanding what the cause might be and how it may be corrected.I indicated that I would look through our files and send him something next week. EAM ce:Stan Sieczkowski,Alaska Energy Authority Afzal Khan,Alaska Energy Authority Remy Williams,Alaska Energy Authority \lon tne Ie I-N) Alaska Energy Authority A Plone Corpoorarion December 10,1990 Mr.Steve Swift Golden Valley Electric Association Inc. PO Box 1249 Fairbanks,Alaska 99707 Subject:Anchorage-Fairbanks Intertie,Structure #749 Dear Mr.Swift: Per our discussion on Friday (12/7/90)I have attachd all the information concerning the construction of Structure #749.In addition,I have attached a couple of drawings of the foundation and the location of the structure for your information. It my understanding that you plan to monitor this structure through the winter and prior to spring breakup GVEA would attempt to correct the present alignment of the structure.The proposed fix would include the installation of a "deadman"and guy the structure,such that it no longer leans down the slope.Once you have determined your schedule for this work,we would appreciate a copy so we may see the site if our schedule allows it. If we can be any further help please feel free to contact me. Sincerely, _=boob Eric A.Marchegiani Project Manager EAM cc:Stan Sieczkowski,Alaska Energy Authority Afzal Khan,Alaska Energy Authority T]PO.BoxAM Juneau,Alaska 99814 (907)465-3575XXPO.Box 190869 704 East Tudor Road Anchorage,Alaska 99519-0869 (907)561-7877 mn,3U Le:sal rm.r*MLéP DISPTCH27T6E--2961 FUz hyn wrted INTERTIE INFORMATION 12/26/90 0920 HOURS 12/23/90 1907 INTERTIE OPENED BETWEEN DOUGLAS AND HEALY. "A"PHASE TO GROUND FAULT.APX 35 MILES NORTH OF OOUGLAS SUB. 1944 DOUGLAS BREAKER Bl CLOSED. 12/25/90 1250 INTERTIE OPENED BETWEEN DOUGLAS AND HEALY. *C*PHASE TO GROUND FAULT.APX 46 MILES NORTH OF DOUGLAS SUB. 1252 DOUGLAS BREAKER Bl CLOSED. 12/25/99 1400 DOUGLAS CIRCUIT SWITCHER TD-200 OPENED. 1422 LOCKOUT RESET,MEA CLOSED TD-200. 12/25/90 1531 INTERTIE OPENED BETWEEN DOUGLAS AND HEALY. "C*PHASE TO GROUND FAULT.APX 35 MILES NORTH OF DOUGLAS SUB. INTERTIE LEFT OPEN BETWEEN DOUGLAS AND HEALY. 12/25/90 1638 BREAKER $38 AT TEELAND OPENED.NO TARGETS ON TEELAND OR DOUGLAS SCHWEITZERS. 1655 BREAKER 538 AT TEELAND CLOSED. The weather conditions that have were reported to this office indicate heavy wet snow and soma wind.A visual inspection of the Intertite at tower 70 from Caswell Lakes Road on Sunday night indlcated the conductors were free of ice and snow loading. Douglas W.Hall Chief Power Dispatcher,ML&P GOLDEN VALLEY ELECTRIC ASSOCIATION Interoffice Memorandum January 8,1991 TO:Bob Orr FROM:Marvin Riddle "MOK _RE:Brief Overview of the 1990 Christmas Outages POVILLA (ane The majority of the problems occurred between 12-21-90 and 12-31-90. I will attempt to break these into general blocks of time as thesnowworsened. Time of Time Out December 21,1990 Occurrence of Service MOS R1-R3-R4 01:58 8 min 69 KV phase/phase fault, attempted reclose.0O.K. STS R1-R3-R4,FXS Rl 05:26 1 min zehnder 69 KV B5 phase/phasefault,attempted reclose.O.K. MOS R1-R3-R4 07:27 3 min GHS B4 -ZNS B3 opened.Phase/Phase fault trip.GHS SVS tripped. GHS B4 -ZNS B3 opened.11:26 2 min Line crew unloading snow.Slapped phases. MOS R1 | 11:43 30 min Locked open -single shot for City Electric. December 22,1990 CPS Rl 03:20 1 min To remove tree. Consumers Affected 1806 2134 1806 1806 537 Eleven outages affected Steese,CHSR,Steese Hwy area,Chena PumpRoad. 1990 Christmas Outages Page 2 Planned outage on Plack/Hurst/Dawson area to correct overloadproblem-Engineering upgrade. Time of Time Out Consumers Occurrence of Service Affected DRS R4 *10:59 2 min 592 HPS Rl *11:40 1 min 771 (*to change opens) The cutover also affected approximately 100 consumers in the areaforperiodslastingfrom30minutestoapproximately2hours30 minutes. _December 23,1990 At 19:07 hours Healy B17 tripped and Douglas Bl tripped relayinformationshowedthefaulttobeapproximately40milesnorthofDouglas.Generation in service at the time of the trip was:Healywith25MW;Chena 5 with 18 MW:the FMUS tie was closed and we were supplying them 2 MW,the Ft.Wainwright tie was closed and they weresupplyingFt.Greely's load of 2 MW.The University of Alaska tie was open.The Eielson AFB tie was closed and zero.Alaska Intertie had 56 MW scheduled north. The loss of the transmission line left us without enough generationtocovertheload,frequency decayed and the following feeders tripped on underfrequency: Time of Time Out Consumers Occurrence of Service Affected BKS R2-R4 19:07 8 min 992 BRS R1-R2-R3-R4 19:07 7 min 2119 CPS R1-R4 19:07 3 min 877 CWS R1-R3 19:07 41 min 90 DRS R1-R2-R3-R4 19:07 5 min 1709 ETS R1-R3 19:07 '21 min 829 GHS Rl 19:07 21 min 167 HAS Rl 19:07 6 min 771 HAS R2 19:07 3 min 832 HAS R3 19:07 4 min 711 HLS R2 19:07 21 min 297 HPS Rl 19:07 6 min 1082 HPS R2-R3 19:07 17 min 613 IAS R2 19:07 .4 min 1003 IAS R3 19:07 17 min 298 JRS R2-R3 19:07 19 min 416 MOS R1-R3-R4 19:07 20 min 1800 NNS R1-R2 19:07 18 min 658 PGS R2-R3 19:07 18 min 1844 SFS R1-R2-R3 19:07 18 min 1464 STS R1-R3-R4 19:07 19 min 1980 UAS R1-R3 .19:07 19 min 1259 ZNS R3 19:07 19 min 1022 ZNS R4 19:07 20 min 1377 1990 Christmas Outages Page 3 The Dispatcher responded by starting generation and restoring load. The units could not handle all the load,so the following weremanuallyshedtostabilizethefrequency: Time Out of Consumers Opened Service Affected BKS R2-R4 19:18 7 min 992 BRS R1-R2-R4 19:19 5 min BRS R3 19:19 6 min 2119 3211 During the initial load shed,the system voltage went so high on theeasternendofthesystemthatJarvisCreektransformertrippedon.high voltage. JCS R1-R2-R3-R4 19:10 20 min 1252 While attempting to re-energize the Intertie,the DispatcheroperatedthemotoroperatedswitchesatHealyincorrectlyresultingintrippingofHealy1B16andHealy1B12.This also caused the Healy unit to trip due to loss of part of the plant station service. The following feeders were shed on underfrequency: Time Out of Consumers Opened Service Affected BKS R2-R4 19:35 2 min 992 BRS R1-R2-R3 19:35 2 min 2119 CPS R1-R4 19:35 2 min 877 DRS R1-R2-R3-R4 19:35 1 min 1709 ETS R1-R3 19:35 1 min 829 GHS Rl 19:35 5 min 167 HAS R1-R2=-R3 19:35 2 min 2314 HLS Rl 19:35 9 min 13 JCS R2-R3 19:35 3 min 92 JRS R2-R3 19:35 6 min 928 SFS R1-R2-R3 19:35 8 min 1464 ZNS R3 19:35 8 min 1022 12,526 The fault showed to be A phase to ground and we could not determinetheexactcause.Since it was impossible to patrol the line at that time because of the weather condition,it was decided to leave the North Pole GT in service through the Christmas holidays. December 24,1990 Took the Alaska Intertie out of service to check switches that were improperly operated. :Time Out of Consumers Opened Service Affected CWS R1-R3 12:13 8 min 90 oO 1990 Christmas Outages Page 4 Snow increased and outages got much worse in the afternoon. Time of Time Out Consumers Occurrence of Service Affected MOS 1R4 (locked opened)21:54 2 hr 25 min 247 BKS 1R4 11:32 14 min 467 to cut out trees CPS 1Rl 15:22 47 min 537 tree in main line IAS 1R1 (locked open)17:13 1 min 76 IAS 1R2 (locked open)17:03 30 min 1006 tree in line In addition to these lock-outs,we had 13 other recloser actions and 20 outages affecting approximately 200 consumers in the followingareas: Farmer's Loop,Airport Road,Chena Ridge,Goldstream Valley, CHSR,University Avenue,Steese Highway,Chena Pump Road, Nenana (north) Time Out of Consumers December 25,1990 Opened Service Affected NNS R1 (locked open)03:35 2 hr 6 min 357 phase down MOS R1-R3-R4 08:48 2 min 1706 ZNS B3 -GHS B4 relayed 69 KV phase to ground fault.Reclosed,held O.K. CWS R1-R3 12:50 2 min 90 HLS B17 -Douglas Bl tripped phase to ground fault approx.40 miles north of Douglas(same area as fault on 12/23)Reclosed,held O.K. CWS R1-R3 15:32 10 hr 53 min 90 HLS B17 =Douglas Bl tripped phase to ground (same area as previous 2 faults).The AK Intertie was left out of service when the transformer was checked out.The Tie was sectionalized at CWS and re-energized.CWS transformer differential relay locked out. BRS R1-R2-R3-R4 18:33 48 min 2122 HPS B2 -FWW B10 relayed 69 KV phase to ground fault.Tried toreclose,wouldn't hold. Isolated BKS tap to re-energize BRS. 1990 Christmas Outages Page 5 Time of Time Out Consumers Occurrence of Service Affected BKS R2-R4 18:33 2 hr 4 min 996 Tree cut out of line and tap re-energized. STS R1-R3-R4 FXS Rl 21:56 1 min 2194 ZNS B5 relayed 69 KV phase to ground fault.Reclosed, held O.K. In addition to these areas affected by transmission and locked out reclosers,we had 35 other outages affecting approximately 500consumersinthefollowingareas:. CHSR Ester/Loftus Road areas,Chena Ridge,Airport Road,Rich Hwy south of Johnson Rd,Nenana,Cantwell,Badger Road area,Freeman/Persinger,Dennis,Fairhill Subdivision off Steese,Gold Hill Rd/Old Nenana Hwy,Geist/Fairbanks St,Dale Road,Steele Creeke,Shaw Creek. Time Out of Consumers December 26,1990 Opened Service Affected ZNS R4 01:58 12 min 1099 Opened to replace cutout. FMUS Westgate Feeder 04:45 1 hr 4 min Locked open. BKS R2 18:47 2 hr 54 min 524 (Locked open -conductorshot,vandalism.)Conductor failed at 9.5 Mi CHSR Gold Rush Estates 15:00 45 min 40 Snow plow hit padmount. Sectionalized to restore power. Repaired damaged padmount 15:00 8 hr O min 9 at Gold Rush Estates In addition,approximately 20 outages affecting 50 consumers were handled. December 27,1990 00:05 North Pole Unit #1 tried to ramp itself off line,excitation to 15 MVAR incoming resulted in low system voltage. 00:23 Started NP Unit #2 1990 Christmas Outages Page 6 01:30 NP GT #1 trips 06:10 NP GT #2 IGV valves caused unit to swing,tried to start NP#1,won't start. Healy has a boiler tube leak.They will try to stay on lineuntilJanuary1,1991. 14:50 NP GT #2 has vibration trip problem. 15:02 NP GT #1 on line. 17:47 NP GT #2 tripped.High vibration (while trying to bypasstrip). 22:19 All NP units repaired and available for service. NOTE:ZNS GT #1 will not operate in remote,automatic damperproblems. Time of Time Out Consumers Occurrence of Service Affected GHS Rl 22:59 2 min 167 Locked open,reclosed O.K. December 28,1990 IAS R1-R2-R3 03:50 3 min 5557 SFS R1-R2-R3 CPS R1-R4 PGS R2-R3 SFS R1-R2-R3 FWS B9 -GHS B2 relayed 69 KV phase to ground fault.Reclosed,held O.K. MOS R1l-R3-R4 03:53 1 min 1706 ZNS B3 -GHS B4 relayed 69 KV phase to ground fault. Reclosed held O.K. STS R1-R3-R4 FXS Rl 04:30 1 min 2194 ZNS B5 relayed 69 KV phase to ground fault.Reclosed, held O.K. Ft.Greely Operator opened 04:50 tie.System too wild for him. ETS R3 09:59 1 hr 27 min 334 Locked,open,trees in line 1990 Christmas Outages Page 7 Time of Time Out Consumers Occurrence of Service Affected FXS R1 11:02 40 min 218 Open to repair phase down on ground. CPS Rl 11:15 2 hr 12 min 537 Trees in main line (ChenaPumpRoad) ETS R3 11:26 1 hr 1 min 334 Trees in line.When Ester Dome lost commercial power, generator would not hold adequate voltage so we lostF1/F2 on radio system.This is a very serious problem. CPS R4 14:19 1 min 342 Reclosed O.K. Healy Plant 15:38 Lost "B"mill to half load BRS R1-R2-R3-R4 16:02 43 min 2122 HPS B2 -FWS B10 69 KV phase to ground fault.Won't reclose.Sectionalized BKS tap. BKS R4 16:02 46 min 468 Picked up by tying to STS R4 BKS R2 16:02 2 hr 28 min 524 Patrolled line.No problem found.Suspect static wire. Teeland Douglas line 16:48 7 min Breaker 538.Relayed open. Reclosed O.K. STS R4 ,16:38 1 min 316 Reclosed O.K. STS R4 17:22 5 min 316 To remove trees. STS R4 17:33 6 min 316 To remove trees. In addition,47 other areas with approximately 160 consumers wereaffected.The areas included: Badger Road,Steese Hwy,Cleary Summit,CHSR,Fox area,Daleroad,McGrath Road area,Cripple Creek,Geist/Birch Lane area. 1990 Christmas Outages Page 8 December 29,1991 NP Unit #1 Tries to run off line. SFS 1R3 To remove trees. IAS R2 Tree tore down phase. Outages in 18 other areas following areas: Opened 14:11 15:52 16:03 affecting 50 Time Out of Consumers Service Affected 2 min 184 1 hr 18 min 1006 consumers were in the Old Valdez Trail,Badger Road,McGrath,'Hillcrest,CHSR,College Hills. December 30,1991 NP Unit #1 Goes into shutdown mode. Was able to stop shutdown. MOS Rl To remove trees from line. December 31,1991 ZNS GT #1 auto damper Problem repaired. Healy lost pulverizer to half load. CWS R1-R3 To return Alaska Intertie to service. Alaska Intertie back in service.CWS 3S1 closed. Healy B17 -Douglas Bl closed. January 1,1991 STS Rl To remove tree. North Pole RTU failed. No remote control of unit.° Healy Plant off line Boiler tube leak. 07:02 15:17 15:24 18:13 23:42 23347 18:21 19:43-21:32 21:36 5 min 901 6 min 90 3 min 993 RTU repaired. 1990 Christmas Outages Page 9 Problems: 1. ccs We could have responded to the problems in areas with deep snowifwehadanothertrackedvehiclesimilartotheBearcat.We should consider this in our planning and purchasing. The circuit diagrams are almost totally useless for dispatchingcrews.There are not enough trails,roads,etc.shown to helpdispatchthecrews.Taps and lines are not shown properly,fusesarenotshownproperly.It is impossible to help the crews locate problems from Dispatch with maps this inadequate.Wecouldhavereducedsomeoutagetimedramaticallyifwehad better system maps.Also,some way is needed to tie maps'tolocations(pole numbering?...something!). The Alaska Intertie has a serious problem with phase and staticwireice/snow loading that must be addressed. The following 69 KV transmission circuits must be looked at for improvements: a)Musk Ox tap -phase to phase contact occurring. b)Brockman tap -static wire problems,ROW problems.ROW toonarrowforsizeoftreesinthearea. c)Steese/Fox 69 KV line -phase to phase contact occurring. We must have a little more pre-planning for major outages.Itworkedout,but we could have improved it by use of better ways to track crews in Dispatch. The Rolm switch kept dropping off line during the outages.It appears we have a problem with the power source to the telephone.Solution to this is being worked on with EngineeringandOperations. We lost the F1/F2 repeater (VHF)radio at Ester Dome during some Major outages.We should look at upgrading the stand-by generation at Ester Dome and expediting radio replacement to provide for a more reliable system.This is absolutely criticalduringoutagessuchasthisone. M.Kelly F.Abegg V.Colonell S.Haagenson R.Hansen J.Killion F.LeBeau S.Swift Dispatch o- QOL/1O/91L 14238507 QR BUEFER Qj (BRS) CUAS) (ZNS) (ZNS) CZNS) CERES) CERS) (BRS) CIAS> (TAS) (CWS) (CWS) FOINT I.0. R4 K3 R2 k3 k4 Ke K3 kl QUTAGES REPORT aw RATE 01/09/91 01/10/91 01/10/91 01/10/91 01/10/91 01/10/91 01/10/91 91/10/91 01/10/91 01/10/91 01/10/91 01/10/91 TIME 04:40 142509 14:09 14209 14:09 14:09 14:09 14:09 143909 14:09 14:09 ARCHIVE 1 CE ga 250 cl c2¢ CONSUMER DURATION TYPE CONS.-HE 0 0 Z7TA 0.0 L 0 0 860 0.0 0 10 2 0.3 0 11 1022 197.4 0 13 1377 298.4 o 1 5 6.3 0 1 873 L4G 0 1 774 12.9 0 8 1003 133.7 0 8.298 39.7 0 18 27 Qed 0 18 63 19.9 -AGC4S-INTTEQS-LOCL --TRAN3O-COMMO4-CPUO2-DIST3IG-EMUSSG-CRITI7-ALLAA - TRANSALARMS EMT INIT cyS DIAG GENERAL ENT_VAL COFY_CRT AGC ll RECALL FG REV ARCHIVES PG FWD SUY_RECL CANC EL 3 -Sa,ttu/l wTsiad *% SERCH IVE O1/1O/91 Paracas QR BUFFER Ol VITAGES REFORT PAGE &OF 84 asC C1 C2 03 ae 4, CONSUMER POINT f.OG.LATE TIME DURATION TYFE CONS."HE (STS)ki 01/10/91 14209 0 9 7 992 148.8 (STS)K3 01/10/91 14:09 0 9 674 101.1 (STS)k4 01/10/91 14:09 Oo 10 314 Jews (HAS)Kl 01/10/91 14309 0 2 771 25.7 (HAS)K2 01/10/91 14209 0 2 B32 27.7 CHAS)3 01/10/91 14209 )2 71l ede? (PGS)R2 | 01/10/91 14:09 0 8 1585 241.3 (PSs K3 91/10/91 14:09 0 9 259 38.9 (BKS)ko 01/10/91 14209 Q 1 524 8.7 |(BRS)R4 01/19/91 14:09 0 1 468 -7.8 i ow "SFS)Ri 01/10/91 14209 0 9 817 122.6 'SPS?Ra 01/10/91 14:09 0)9 466 69.9 -ABC4S-INTIEQ3-LOCL---TRAN3O-COMM04-CPU02-DIST20-FMUSSG-CRITI7-ALLAA- ALARMS SYS_DIAG GENERAL AGC TRANS ARCHIVES StY_RECL ENT_INIT ENT_VAL COPY CRT D_RECALL PG_REY PG _FWE CANCEL POINT 1.DP. mor R3 - cOES)R1 (QRS)R2 'DRS)R23 (IRS)RA (GHS)RL (CPS)RL (CPS)B4 (MOS)R1 (MOS)B3 (MOS)kA "UAS)RI Mey Ae ¢ LATE O1/10/01 01/10/79] 01/1079) O1710/91 01/10/91 OL/1O/91 01/10/91 01/10/91 01/10/91 01/10/91 61/10/91 YL/10O/91 REPORT CAGE TIME 14209 14:09 14:09 Laio9g 14209 14:0) 14209 14:09 14:09 14:09 14209 14:99 ay aa DURATION TYPE 0 <>tsto14 14 14 CONS, vypel ARTH TUE 166.8 112.5 147.8 --AGC4S=[ATIE 92-LOSL---TRANS O-COMMO3 CPUSZ-DISTOS EMUSSG-CEILTI7-ALLAAS©© TRANS FG REV ALARAS homed ENT _INI? 3D TAG AENEFAL EMT _VAL CORY CRT ASC It!_RECALI.ARCHIVES BG Fur SLY RECL CANCEL 7;on OL/1O0/91 14:3a529 ORP BU FEFER 61 POINT I. QUTAanES REPORT CUAS) (HPS?) (HFS) CHES) CNNS) (NNS) CIRS) CIRS) (ETS) (ETS) (HLS) (SFS$) K3 Kl R2 R3 Rl ALARMS ENT_INIT ENT_VAL GENERAL DATE O1/10/91 01/10/91 01/10/91 01/10/91 01/10/91 01/10/91 01/10/9) 01/10/91 01/10/91 O1/10/9)1 O1/10/91 01/10/91 AGC COFY_CRT PAGE TIME 14:09 14:09 14509 14209 14:09 14209 14:09 14209 14:09 14:09 14:18 4 OF ©&4 ARCH TYE 2590 Cl m2 CONSUMER DURATION TYPE CONS."HR "0 100”"8p 149.3 x" 0 3 1082 34.1 0 3 7 17.9 0 3 1 33.5 0 8 360 48.9 0 8 2993 39.7 0 3 416 we 9 8 437 98.3 6 41S 496 124.0 QO 15 333 83.3 0 10 297 492% G17 TRANS[!RECALL FG REV ARCHIVES PG_E AGC4S INTIEC 2-LOCL- -TRAN3SO-COMMO3-CPU02-LISTOS-FMUSSG-CRITI7 ALLAA- $YS_[IAG SNY_RECLWEICANCEL LT eu May natles piace Andlytical Associates Inc vate:say=p .Hi ON Power Inn Rd.,Suite G Report Nor fyi 25EYNWiySacramento,CA 95826 Lab Control No.:167261 aleeneed (916)451-5034 Client Ref.No.; GOLDEN VALLEY ELECTRIC LOCATION:CANTWELL PWR XFMR OIL TEMP (C):25 QPERATIONS SUPT,SERIAL NO.:PES-0742+1 MFG.: P.O.BOX 1249 COMPANY NO.:TYPE OF UNIT: FAIRBANKS,AK 99707 BANK &PHASE:PH.3 SAMPLE CONTAINER NO.=10 ES BlaseivedOseieGitRialpaie See recent Cee DATE COLLECTED:35 pre.59 14 JUN _90HYDROGEN01 METHANE (CH,):'1 ETHANE (C,H,):0 0 ETHYLENE (C,H,):1 5 ACETYLENE (C,H,):0 0 CARBON MONOXIDE (CO);0 2 CARBON DIOXIDE (CO,):302 298 NITROGEN (N,):56132 73172 OXYGEN (0,):1349 851 TOTALGASES:57785 74331 TOTAL COMBUSTIBLE GAS:2 9 EQUIVALENT TCG READING (%):0.0018 0051 COMMENTS:=ALL GASES ARE WITHIN NORMAL LIMITS divx aane NO »NON »DETECTAOLE S,PTeae asSee ema udupnne tise Sa hal Sonu ngt ee ASTM Method DATE COLLECTED:25pre90 44 JUN 900-15338 MOISTLIRF IN OIL (ppm):6 120-971 INTERFACIAL TENSION (dynes/em):35 320-974 ACID NUMBER =(mg KOHI/g):013 002D-1500 COLOR NUMBER (Pelathve):v.>0.5 D 1624 VICUAL (Pwlative),CLR &SPK CLK &OFK 0-877.DIELECTRIC BREAKDOWN (KV):$1 >35 D-1816 DIELECTRIC BREAKDOWN (kV): 0-88 VISGASITY (SUIS):0-1268 SPECIFIC GRAVITY (Relative): 0-924 POWERFACTOR @ 25°C (%):048 .049 0-924 POWER FACTOR @ 100°C (%):=13 1.606 0-2668 =OXIDATION INHIBITOR (%):-«010 - D-1807 REFRACTIVE INDEX (Relative):0-1169 RESISTMITY (10°?g-em): 0-97 POUR POINT (°C): 0-92 FLASH POINT CC): 01275 CORROSIVE SULFUR (Relative): PGB CONTENT METALS IN OIL DETERMINATION (PPM)PPM AR A ALUMINUM COPPER IRON LEAQ SILVER JIN ZING faltiaunta Os aoe MO ew 8 =a fee Analytical Associates Inc.nate:ea /\See \SH (ae AON]Powor Inn Rel,Suile C Report No.cvea seeas#Sacramento,CA 95826 Lab Cantrat Na:167269mul(916)451-5034 ; Client Ref.No.: GOLDEN VALLCY CLECTRIC LQGATION: CLANIWELL LIC COMPART.OIL TEMP (°C):25 OPERATIONS SUPT.SERIAL NO.:PES$-0742-1 MFG.: P.O,BOX 1249 COMPANY NQ.:TYPE OF UNIT: FAIRGANKS,AK 99707 BANK&PHASE:pH,3 SAMPLE CONTAINER NO:=8 DATE COLLECTED:25 pet 90 HYDROGEN (H,):6 METHANE (CH,):2 ETHANE (C.H,):3 ETHYLENE (C,H,):0 ACETYLENE (CoH):0 CARBON MONOXIBE (CO):ry" CARBON DIOXIDE (CO,):1146 NITROGEN (N,):2 15¥U OXYGEN (0):oars TOTAL GASES:59064 TOTAL COMBUSTIBLE GAS:55 EQUIVALENT TCG READING (%):0.0788 COMMENTS:ALL GASES ARE WITHIN NORMAL LIMITS Core mre a od PIT CT ESE Dlg "1 URALSEMA Fa aainiien ASTM Methad DATE COLLECTED:25vey20D-18338 MOISTURE IN OIL (opm):10 0-971 INTERFACIAL TENSION (dynes/cm):30 0-974 ACID NUMBER -(mg KOH/g):016 D-1500 COLOR NUMBER (Relative):«7.0 0-1824 VISUAL (Relative):CLR &SPK D877 DIELECTRIC BREAKDOWN (kV):50 01816 DIELECTRIC BREAKDOWN (kV):0-88 VISCOSITY (SUS):D-1298 SPECIFIC GRAVITY _-(Relative):0-924 POWERFACTOR @ 25°C (%):.068 0-024 POWER FACTOR @ 100°C (%):4.337 0-2068 OXIDATION INMISITOR (%):. D187 REFRACTIVE INCEX -{Rretiative):. D-1169 RESISTIVITY (10?g-cm): 0-97 POUR POINI (PC):D-92 FLASH POINT CC): D-1275 CORROSIVE SULFUR (Relative): PCB CONTENT METALS IN O!L DETERMINATION (PPM)PPM ©AROCLOR ALUMINUM COPPER IRON LEAD SILVER JIN ZING NO @ NON -DETECTASLE Caltavata Crate Pawifiaatinn aes mine KE Analytical Associates Inc.Date:>10 JAN 914011PowerInnRd.,Suite G Report No.:avea s8989zzSacramento,CA.95826 Lab Control No.:167477 FA (914)451-5034 Client Ref.No.: GOLDEN VALLEY ELECTRIC LOCATION:CWS T1 CANTWELL PH.3 OIL TEMP (°C): OPERATIONS SUPT.SERIAL NO.:PES 0742-1 MFG.:WEST P.0.BOX 1249 COMPANY NO.:TYPE OF UNIT: FAIRBANKS,AK 99707 BANK &PHASE:SAMPLE CONTAINER NO.: 12A poll Analysis. DATE COLLECTED:_3.JAN.91 25 LE 9 HYDROGEN (H,):0 0 1 METHANE (CH,):4 1 1 ETHANE (C,H,):0 0 0 ETHYLENE (C,H,):5 1 5 ACETYLENE (C,H,):0 0 0 CARBON MONOXDE (CA):"1 4 2 CARBON DIOXIDE (CO,):7,302 298 NITROGEN (N,):56327 56132 73172 OXYGEN (0,):976 1349 851 TOTALGASES:57840 57785 7623 TOTAL COMBUSTIBLE GAS:19 2 9 EQUIVALENT TCG READING (%):9.0158 =0.0018 0051 COMMENTS:ALL GASES ARE WITHIN NOKMAL LIMLIS SaRALON ASTM Method OATE COLLECTED: 0-15338 MOISTURE IN OIL (ppm): D-971 INTERFACIAL TENSION (dynes/em): 0-974 ACID NUMBFR (mo KOH/):014 013 002 D-1600 COLON NUMDER (Retutlve);0.5 U.>0.5 01524 VISUAL (Relative);CLR &SPK CLR &SPK CLR &SPK 0-877 DIELECTRIC BREAKDOWN (kV):49 51 >35 0-1816 DIELECTRIC BNCAKDOWN (kV): D-88 VISCOSITY (SUS): 0.1298 SPECIFIC GRAVITY (Relative): 0-624 POWERFACTOR @ 25°C (%):068 069 0-924 POWER FACTOR @ 100°C (%):913 1,606 0-2668 OXIDATION INHIBITOR (%):<.010 0-180?REFRACTIVE INDEX (Relative): 0-1169 RESISTIVITY (10°?acm): 0-97 POUR POINT .(C): 0-92 FLASH POINT CC): 0 1275 CONROSIVE SULFUR -s_(Ralative): PCB CONTENT METALS IN OIL DETERMINATION (PPM)PPM AROCLOR ALUMINUM COPPER ION ,fAD SILVER Jiy ZING ND s NON :OETECTAGLE fito_,eenn /\NCIYTICAl Associates Inc.Date:Eat /\Sat/\'a [El AON Power Inn Rd.,Suite G ao,IOAN 9Bet]=a (|”Report No.:cvea 58988fao\t/an\i Jee Sacramento,CA 95826 Lab Control No.:167478 Seat (916)A51-5034 Client Ref.Nev: GOLDEN VALLEY ELECTRIC ©LOCATION:CWE T1-LTC CANTWELL O'L TCMP (°C): OPERATICNS SUPT.SERIALNO.:PEE C742*1 MPG:weary P.O.BOX 1249 COMPANY NO.:TYPE OF UNIT: FAIRBANKS,AK 99707 BANK &PHASE:PH.3 SAMPLE CONTAINER NO.:9A DATE COLLECTED:3 JAN 91 25 DEC 90 HYDROGEN (H,):8 6 METHANE (CH,):0 2 ETHANE (C,H,):0 3 ETHYLENE (C,H,):0 0 ACETYLENE (C,H,);0 0 - CARBON MONOXIDE (CO):52 bl CARBON DIOXIDE (CO,):981 1166 NITROGEN (N,):53076 $1390 OXYGEN (0,):13313 C473 TOTAL GASES:67431 59064 TOTAL COMBUSTIBLE GAS:60 55 EQUIVALENT TCG READING (%);0.0864 0.0788 COMMENTS:ALG GASES ARE WITHIN NORMAL LIMITS as Lk:Rat Samacee nian nn Cee ASTM Method DATE COLLECTED:3 JAN 91 25DEC900-1833B MOISTURE IN OIL (ppm):8 10 N.971 INTERFACIAL TENSION (dynes/cm):30 30 0-974 ACID NUMBER -(mg KOH/g):6011 014 D-low COLON NUMBEH (Relative):<2.0 <2.0 0-1524 VISUAL (Relative):CLR &SPK CLR &SPK 0-877 DIELECTRIC BREAKDOWN (kV):54 50 0-1816 DIELECTRIC BREAKDOWN (kV):0-68 viSCOSITY (SUS):0-129A SPECIFIC GRAVITY (Relative):0-924 POWERFACTOR @ 28°C (%):.068 0-924 POWER FACTOR @ 100°C (%):1,337 02668 OXIDATION INHIBITOR (%): D-1807 REFRACTIVE INOEX (Relative): D-1169 RESISTMITY (10"?a-em): 0-97 POUR PCINT (Cc):D-92 FLASH POINT CC):01275 CORROSIVE SIT FLIR =(Ralativn): PCB CONTENT METALS IN Ol,DETERMINATION (PPM)PPM AROCL ALUMINUM OPPER IRON LEAD SILVER JIN ZING ND =NON -DETECTAGLE California State Certification #214 r ANCHORAGE FAIRBANKS INTERTIE ACCOUNTING REPORT TOTAL REVENUE $3,491 $4,363 $2,618 $189,296 $3,054 $202,822 VAR TANCE NOVEMBER 1990 REVENUES==+-ocr c tree sere cence ee eeeeeene NOVEMBER --- --2-2-2 ee reece ese cennenee ENERGY ENERGY CAPACITY ESTIMATE ACTUAL VARIANCE REVENUE REVENUE utility MWH MWH AEG&T 0 0 *$0 $3,491 CEA 20 0 -100%$0 $4,363 FMUS 0 0 *$0 $2,618 GVEA 31,523 34,152 8%$181,006 $8,290 ML&P 0 0 *$0 $3,054 ror,81,838 ex $181,008 $21,816 EXPEND ITURES ---+2 -eeeeeeannenseceeeeens NOVEMBER-------+-2e+2+00e- CATEGORY CONTRACTOR BUDGET EXPENSE OPERATIONS Northern Area Controller (GVEA)$24,719 $26,719 Southern Area Controller (ML&P)$23,396 $23,396 Intertie Operating committee $11,833 $0 Alaska Power Authority $14,825 $16,941 Maint.Northern Area (GVEA)$14,775 $1,502 Southern Area (AEG&T)$11,493 $900 Teeland Substation (CEA)$1,467 $0 Misc.Transmission (MEA)$7,400 $12,978 Communications (DIVCOM)$2,400 $0 Repair &Replacement $10,417 $14,495 Insurance2 "$9,125 $4,925 Tora $131,850 $99,856 0% 0% yrunates BUDGET1 TO DATE $17,455 $21,921 $13,090 $711,651 $15,270 BUDGET $123,593 $116,981 $59,167 $74,126 $73,875 $57,465 $7,336 $37,000 $12,000 $52,083 $45,625 $659,249 YTD ACTUAL $17,455 $22,334 $13,090 $702,832 $15,270 ACTUAL $123,593 $116,981 $20,276 $67,909 $64,016 $6,522 $0 $47,457 $0 $34,616 $24,625 $505,993 UTILITY AEG&T CEA FMUS GVEA ML&P TOLAL Total Revene Total Expense Surplus (Deficit) ACCRUED3 TOTALS LIABILITY EXPENSE $0 $17,455 $0 $22,334 $0 $13,090 ($264,988)$437,844 $0 $15,270 ($264,988)$505,993 $770,981 $505,993 1 Based on energy purchase projections and MITCR payments. REVENUE ENERGY CAPACITY UTILITY AEGET CEA FMUS GVEA ML&P TOTAL 2 Insurance expense represents monthly increment of annual premium. 3 Deficit aportioned by MITCR,surplus aportioned by energy purchases. DOLLARS PER $661,901 $109,080 ENERGY MWH ESTIMATE 20 126,453 4 Accured liability,if any,plus energy and capacity revenue equal expenditures to-date. CENTAGE 86% 14% ACTUAL 98 VARIANCE "a% 0% 0% "1% 0%