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HomeMy WebLinkAboutIMC Sept 1, 2015Juneau iM ufarfa TA _/3--Comp LogSFGCalendar__moStaffCalendar4 "Oring Teo \ea2 x sulocomm tee st AD Meet pas, BPMC or IMC meeting availability BO Korning-GAl IMC .DeiF Brian GVEA ML&P CEA MEA AZA 10/12 - 10/13 _- 10/14 sie Zen)W204:30]Yes Yes . 10/15 prt Nes Yes '|Yes Yes B:BOpM-5.00 10/16 AL Nen t|Yes z yes yes10/20 |Pm €-!Transeo yes 3 pn? 10/21 |Barly Am <-+Vanseo Yes §yes BPMC GVEA ML&P CEA MEA Seward |HEA 11/17 ok Ok 11/18 Ok Ok 11/19 Ok ok 11/20 ok Ok 1-9 WAL Zl-Ee- OefedIntertieManagementCommittee Regular meeting MEETING MINUTES Tuesday,September 1,2015 Anchorage,Alaska 1.CALL TO ORDER ee Chair Joe Griffith called the meeting of the Intertie Management Committee to order on September 1,2015 at 9:00 a.m.A quorum was established. 2.ROLL CALL FOR COMMITTEE MEMBERS Brian Hickey Chugach Electric Association (CEA)eS Cory Borgeson Golden Valley Electric Association (GVEA) Joe Griffith Matanuska Electric Association (MEA)Gene Therriault Alaska Energy Authority (AEA)©. Jeff Warner Anchorage Municipal Ment &Power (Lar), 3.PUBLIC ROLL CALL Burke Wick (CEA);Ed Jenkins (MEA);Kirk Warren,Bryan Carey,and Teri Webster (AEA);MarkJohnstonandShalonHarrington(ML&P);Bob Day (Homer Electric Association (HEA));KirkGibson(McDowell Rackner &Gibson PoetDave Gillespie (ARCTEC);Allen Gray (GVEA);HenriDale;and Bernie Smith.i 4,AGENDA APPROVALMOTION:Mr.Hickey made aa motion to approve the agenda as presente Motion seconded by Mr.Borgeson.The agenda wwasas adopted without objection.rane 5. None 6."APPROVAL OF PRIORt MINUTES -'June 23,2015 MOTION:"Mr.Therriault made a motion to approve the prior minutes of June 23,2015.MotionsecondedbyMr.Borgeson.The motion was approved unanimously.7.OLD BUSIN ESS7A.Spin and Reserves Negotiations UpdateMr.Dale has been doing work on this topic for a while and Mr.Warner asked if the IMC could pay Mr.Dale for his time under the IMC Administration cost.The estimate for work done in July & August is $17,000.Mr.Hickey suggested to bring this topic to the Railbelt Utilities Group (RUG). Motion:Mr.Hickey made a motion to ask the Railbelt Utility Group to fund Mr.Henri Dale to study the Spin &Reserve issues in the Railbelt,negotiate a solution with the utilities,and bring back the result of such efforts to the IMC.Motion was seconded by Mr.Borgeson.A vote was called and the motion passed unanimously. The IOC gave an update on the negotiations.They are currently looking at dividing the spin 50/50 (load ratio/largest generator).The IOC is close to an agreement with a few qualifiers:percentage of spin allocated to the Railbelt utilities based on percentage of largest unit and largest load;how a shared unit is handled;and does the GSU failures count at the Eklutna generation station. IMC Meeting Minutes-September 1,2015 Page 2 of2 The contractual and technical documents are being work through. The committee stressed for these negotiations to be successful,it is imperative that all the IOC representatives have full authority to speak on behalf of their utility. The IMC committee asked for a resolution from the IOC be brought to the next meeting for voting. Mr.Griffith will report to the RCA that progress is being made on differing reliability standardsreconciliation. 7B.SVC Warranty Policy update Mr.Warren reviewed the procurement rules regarding obtaining a 15 year contract or a 25 year contract with Alstom on behalf of the IMC.According to the Department of Administration and procurement ru A can only enter into a contract up to a five-year term and has a potential toextendthecontractbyfivetermstoequal25years.However,thereis no guarantee that thelegislaturewillnotreappropriatethefundsallocatedtto>this project.: ML&P indicated that Alstom will be providing a five.year qUOK within a week.AEA was asked topresentacontractproposalatthenextmeeting.a 8.REPORTS 8A.Operators Report......SB.Intertie Operating committee reportMr.Warner gave the Operators and 10 reports.*9.COMMITTEE ASSIGNMENTSeIOCtocontinuespindiscussions and bring a resolution to the next IMC meeting.e ML&P to continue to work with Alstom and AEA regarding the SVC warranty.°Mr.Warner to update tthe ML&P Tepresentatives on the subcommittee member list.10.NEXT MEETING DATE. 12.ADJOURNMENT There being no further business of the IMC,the meeting adjourned at 10:57 a.m. Joe Griffith,Chairman Gene Therriault,Secretary To obtain an audio of the full meeting,contact Teri Webster (AEA)at 907-771-3074. From:Gene Therriault Sent:Monday,September 28,2015 12:14 PM To:Teri Webster Subject:RE:Please proof the IMC minutes Teri: |read the minutes over and do not see any item that needs to be changed. GeneT From:Teri Webster Sent:Monday,September 28,2015 11:35 AM To:Gene Therriault Subject:RE:Please proof the IMC minutes Reminder to please proof the attached minutes. Thanks, Teri From:Teri Webster Sent:Tuesday,September 08,2015 12:08 PM To:Gene Therriault (GTherriault@aidea.org)<GTherriault@aidea.org> Subject:Please proof the IMC minutes Can you please review the minutes of last week's IMC meeting and make any changes you want. Thank you, Teri :Cory neataHueHemunderOdminCost.thinks we have Maney wn the budget fee cf.MER Que? ;Brian Ast Mohn.Get proposes Fam Veni.seviass work or were frwand 7Henry-b Goth RUG +have Homer partir poke.Withdrae Mohan&UndFungto .wy :-Vblby ManagesMeeRUGapnereserve:rung loneto IME pa lty emp )eine boy Funds So vhe Reins £17,000 Pug -TelyatkZndSerizar\-utility 'ect be pursue So]So spelt pad lLaggest MER REQ Mayr FPlucuants” .bau ubltra,on board,Net 00%bang Comed.Pran-qualdy OF soin +3 tudhnesaeonNowlyPanto,ne $ahi "Y eScosvapvapyes.Tetole resul>whi Feu ©re a apm.Gene -Whak is penalty iF und dees More or less,Shan proposed ?Must pick up add|spin You sad,WentokeeFecukulake-you owe Yen Ww,win Month.Cabegery b penalty -Motrixe dune lot not approved -Can wehne ea nrator?yes F votre is approved.by (MC.Spin Bak ancing AaCcount wish wh»is AON eropany -Qo by actuale mdt Whol unpr TUnsGire?)fat chet same ad Fine.Deesit luk unit te what you say?Add|Ceqguirement to hose.whe pur povely open Ye sysiert :Zak comin en »Shed un leak sain is awed.GVEA ALP ro police .only looked OF spin bulk somMe Minor oer avrerencs.Yxpus gwverned *ROG look ot other issuas !Kee eather sokHYoFACDSuratetebangaddressonOnesACTZ¢Zug,AayWesuesoFCorstenHon_whet te Note am.Cortyacti onal &technigg)Cdourvent,Nol Peady yet jee Bol gee have fal,on w .;.He t&ie”ye 5Yso agreed "tS qual {s.Vow you handle ashaned wrk?Bradley is largest wad but shad.whoe£Ssypshoewilyoy0oresadGOS77Undconwoe'out a\\(ssues,Bring cesol umn,my& ay!aye sesyomLavat(ob tah interhie 16 laragst _Vere on nest Meding 'USo wlrt-wlAeted be incor porotedSVCKuk-25 &15 yr tern DOA APOE Conaty de Syr Hem enlerd up to Sermo<2s yrs Leh over BEuponYeyapenval.wl hear fin Mision vlin days.Wwe have Bye Warreshy ,Service wor 15 df Show ByeMinks4.5 wl is lefe.PePpaed OOO OC Tangument %Stele on bareF of IC.20.3 -eekand-Dougho extension.10M reqpprop SVC +SW SVC ARTEL (5M efi SEEM IOH:SHgone.Zhuo TM Loft cutoF ZOZM .Swrteher,Udg,ore ancied.Followvponan,RM "meAeonTefFtoreplaceLomonpuocamantleeGenewlreve -Burlingion studs,EFS drop}by endof Nov,UNI wel parka pte,wr dof,Fiowk Dec.Wn preanse IMC comments.Unites Lal do Seperate COMMONS.HEF toad do soukod well. tS] IMC:Sept 1,2015 Roll call from top to bottom ending with Chair ALASKA ENERGY AUTHORITY Intertie Management Committee BE oot go Roll Call Agenda Minutes Yes No Yes No-Yes No Yes No Golden Valley Electric Association Matanuska Electric Association Alaska Energy Authority Municipal Light &Power Chugach Electric Association NESTS]NTNTOTAL Roll call from top to bottom ending with Chair Yes No Yes No Yes No Yes No Yes No Golden Valley Electric Association Matanuska Electric Association Alaska Energy Authority Municipal Light &Power Chugach Electric Association |TOTAL Next Meeting: ALASKA INTERTIE MANAGEMENT COMMITTEE AGENDA Tuesday,Sept.1,2015 9:00 a.m.-11:00 am Alaska Energy Authority,Board Room 813 W.Northern Lights Boulevard,Anchorage,Alaska 1.CALL TO ORDER 2.ROLL CALL FOR COMMITTEE MEMBERS 3.PUBLIC ROLL CALL 4.AGENDA APPROVAL 5.PUBLIC COMMENTS 6.APPROVAL OF PRIOR MINUTES --June 23,2015 7.OLD BUSINESS A.SPIN and RESERVE NEGOTATIONS -UPDATE (IOC) B.SVC WARRANTY POLICY -UPDATE (AEA) 8.NEW BUSINESS 9.REPORTS A.OPERATORS REPORT --ML&P/GVEA B.INTERTIE OPERATING COMMITTEE REPORT 10.COMMITTEE ASSIGNMENTS 11.NEXT MEETING DATE 12.ADJOURNMENT To participate via teleconference,dial 1-888-585-9008 and use conference room code 467 050 126 RRO Contingency Reserves Policy V001 CONTINGENCY RESERVES POLICY Reserve Capacity Planning Criteria A-1.1 1.1.1 1.1.2 1.1.3 Each Load Serving Entity is expected to maintain responsibility to provide capacity for ts own firm load.As part of such responsibility,the Load Serving Entity shall maintain or otherwise provide for annually,Accredited Capacity,in an amount equal to or greater than ts maximum System Demand for such year plus the Load Serving Entity's Reserve Capacity Obligation,as set forth in Subsection A-1.1.2. The Reserve Capacity Obligation of a Load Serving Entity,for any year,shall be equal to thirty (30)percent of the projected Annual System Demand for that year for that Load Serving Entity.The Reserve Capacity Obligation of the Load Serving Entity may be adjusted from timeto time by the Regional!Reliability Organization. The Regional Reliabiity Organization may determine the annual Accredited Capacity for each Load Serving Entity. Responsibility for Operating Reserve B-2.1 Operating Reserve 2.1.1 2.1.3 Each Load Serving Entity and/or Generation Owner shalt provide,or contract for,Spinning Reserve and Non-Spinning Reserve as required by Section B-22 equal to or greater than the Operating Reserve Obligation of the entity.As soon as practicable,but not to exceed four hours,after the occurrence of an incident which uses Operating Reserves, each entity shall restore its Operating Reserve Obligation. Operating Reserves,Operating Reserve Obligation,System Reserve Basis and allocation calculations may be modified or changed by the Regional Reliabilty Organization. The System Reserve Basis (SRB)is equal to the Largest Generating Unit Contingency of the System as defined in Exhibit A1 or other such value such as loss of a transmission line,as determined by engineering studies and approved by the RRO. Single points of interconnection,such as,but not limited to,buses,collector feeders,step- up transformers,shall be evaluated in terms of asset class.Failure rates such that the asset class is involved in a failure at a rate of once per year will validate it as a single point of interconnection as discussed above.However,subject to the reasoning above,the Regional Reliability Organization may exercise judgment in such matters. RROCONTINGENCY RESERVES POLICY v001 B-22 2.2.1 An entity adding a unit whose LSGC 5 greater than a 20 MW will accrue the obligation above 20 MW on a one for one basis in addition to ts otherwise calculated spin obligation.This cap is subject to change bythe RRO. Total Operating Reserve Obligation The Total Operating Reserve Obligation at any time shall be an amount equal to 60 percent of the System Reserve Basis of the Railbeit Electric Grid 2.2.1.1 The Spinning Reserve portion of the Total Operating Reserve Obligation shall not be less than an amount equivalent to 100 percent of the System Reserve Basis. 2.2.1.2 The balance of the Total Operating Reserve Obligation shall be maintained with 2.2.2 2.2.3 B-23 Non-Spinning Reserve. Generating unit capability for Operating Reserves shall be determined by the following criteria: a.kt shall not be less than the load on the machine at any particular time nor greater than (b)below. b.t shall not exceed that maximum amount of load (MW)that the unit is capable of continuously supplying for a two-hour period,or quickly,through action of automatic governor contro'. The criteria specified in this section may be modified or changed by the Regional Reliability Organization. Allocation of Operating Reserve Obligations 2.3.1 The Operating Reserve Obligation of an Entity shall be that percentage of the Total B-2-4 2.4.1 2.4.2 Operating Reserve Obligation determined by the Regional Reliability Organization in accordance with the formulas described in exhibits B1,B2 and exhibit A3. Operating Reserve Calculation An Entity's Spinning Reserve shall be calculated at any given instant as the difference between the sum of the net capability of all generating units on line in the respective entity and the integrated Systems Demand of the system involved and other sources (for example,SILOS and BESS)or declared restrictions on spinning reserve (for example, Bradley Lake or tie line restrictions)as accepted by the Regional Reliability Organization. An Entiy's Spinning Reserve may be satisfied by an automatically controlled toad shedding program.The load shedding program shall assure that controlled load can be dropped to meet the requirement of Spinning Reserve in such a manner as to Page 2of 56 RROCONTINGENCY RESERVESPOLICY v001 2.4.3 2.4.4 2.4.5 2.4.6 2.4.7 maintain system stability and not cause degradation or cascading effects inthe Railbelt system. The Regional Reliabilty Organization may establish procedures to assure that the Operating Reserve of an entity is available on the Railbelt System at all times. Whenever an entity 8 unable to meet ts Operating Reserve Obligation,the entity will, within two hours,advise its Balancing Authority and make arrangements to restore is Operating Reserve Obligation. Prudent Utilty Practices shall be followed in distributing Operating Reserve,taking into account effective utilization of capacity in an emergency,time required to be effective, transmission limitations and local area requirements.Geographical constraints and remedies are defined in Exhibit A3. Subject to 2.4.4 above,an Entity may arrange for one or more other entities to supply part of,or its entire,Operating Reserve requirement. By mutual agreement between the parties,an Entity which has contracted or leased all of the Interconnected Value of a Generating Asset or Share ofa Generating Asset (energy,capacity,reactive-output dispatch-ability etc.)to another Railbelt Entity,such that this particular asset appears for all intents and purposes as Generating Asset of the Lessee's (contractee's)fleet,may have that asset counted among the Lessee's generating units and the Lessee may include this unit as any other in the Lessee's fleet for purposes of calculation operating reserve allocation. An example of this is the Bradley Lake Project.AEA and at various times other project participants have contracted to have the Interconnected Value of this Generating Asset or their respective Shares of this Generating Asset assigned to one another in different forms.In each case the assignor has been relieved of the assigned project share (as the assignor's potential LSGC)and that share has been assigned to the assignee's fleet. In an emergency,any Generator Owner,upon request by its Balancing Authority,shall supply to such Balancing Authority part or all of its Operating Reserve up to the full amount of its Available Accredited Capacity.An Entity experiencing an emergency is not required to maintain its Operating Reserve Obligation.There shall be no obligation of an Entity to supply Operating Reserve if the requesting entity isnot making full use of its own Available Accredited Capacity. Cc Responsibility for Regulating Reserve C-3.1 Regulating Reserve 3.1.1 Each Balancing Authority (BA)shall provide,or contract for,Regulating Reserve as Page 3of 56 RROCONTINGENCY RESERVES POLICY v001 C-3.2 3.2.1 3.2.2 3.2.3 required by Section C-3.2 equal to or greater than the Regulating Reserve Obligation of the party.Regulating Reserve may not overlap reserves dedicated for Spinning Reserve. Regulating Reserve (both up and down)is required to compensate for uncertainty in forecasting and is established during the unit commitment planning process,and as such the BA may then utilize its reserve as required during the course ofthe day.Fa BA exhausts its Regulating Reserve,it is required to procure or commit additional reserves immediately. Regulating Reserve Obligation The Regulating Reserve Obligation for each Balancing Authority shall initially be set by the Regional Reliabilty Organization. On an annual basis,after the year end CPS statistics are compiled,the Regional Reliability Organization will modify each Balancing Authority's Regulating Reserve by increasing/decreasing its current Regulating Reserve by the %deviation in its CPS1.The Regulating Reserve Obligations so calculated will be rounded up to the nearest nteger MW. The Regional Reliability Organization reserves the right to increase/decrease a BA's Regulating Reserve or require other measures at any time due to changes inthe system or repeat infractions.Spin Balancing Account records will be maintained as described in Exhibit A2. Page 4of 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit BI:Spinning Reserve Components Spinning Reserve Obligation will be allocated to an Entity based on a combination of its Monthly Peak Hour Load (MPHL)and the Entities'Largest Single Generating Contingency (including any combination of units with a single point of interconnection forming a single contingency as further discussed in 2.1.3.RAS applications which have been field demonstrated to successfully mitigate the LSGC and have been approved by the RRO may be applied to reduce the magnitude of the LSGC. Spinning Reserve Largest Contingency Ratio (SRLCR):This component shall be calculated as the ratio of an individual Entities'Largest Single Generating Contingency (LSGC)as compared to the sum of the LSGC's of all the Railbelt Entities. The Largest Single Generating Contingency will be based on the actual capacity of those unit(s)subject to the single contingency (regardless of RAS applications).An example of a Generating Contingency is a combined cycle unit;the loss of the combustion turbine will precipitate the loss of both the CT as well as the waste heat unit. If entities share a unit,an entities Share of such a unit could qualify as their LSGC if they have no unit(s) that are larger. Monthly Peak Hour Load Ratio (MPHLR):This component shall be calculated at the ratio of an individual Entities'MPHL as compared to the sum of the MPHL's of all the Railbelt Entities.The MPHL of an Entity shall be defined as the Monthly Peak Hourly Load from the month 1 year earlier.Adjustments for permanent loss,or expected increases due to large industrial lads may be made f agreed to by the RRO.Economy sales are not counted as loads,but non-firm/interruptible lads are. Page 5of 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit B2:Spinning Reserve Obligation Spinning Reserve Obligation for an Entity will be calculated summingthe weighted Spinning Reserve Components of each entity,and multiplyingthis by the System Reserve Basis as follows: SROe=50%{LSGCe}/(Xi (LSGCi)}*[SRB]+50%{MPHLe}/{>i (MPHLi)}*[SRB]+MUDe e =a particular Entity i =All Interconnected Entities MUDe=the difference between the 2.1.3 max unit limit and an entities largest unit if greater than the 2.1.3 cap. Page 6of 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit B3:Spinning Reserve Criteria In order to be counted as a producer of Spinning Reserve,the net response regardless of methods used (generator,SILOS,BESS,duct firing,etc.)must be able to meet the following minimum performance based criteria: Initial response:movement within 2 seconds 30 second response:50%usage ofits reported spin capability 60secondresponse:75%usage ofits reported spin capability 20secondresponse:100%usage ofits reported spin capability Page 7of 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit A1 -Methodology for a varying Largest Single Generating Contingency. For the Largest Single Generating Contingency (LSGC)for the Railbelt System 1)Each Entity will electronically share their hourly expected temperature compensated largest unit's output forecast during the day-ahead scheduling process.This may not be the same unit for each hour. 2)At this time,each utility will also share data on any forecasted excess spin that the Entity may wish to sell. 3)The next day and to the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was underestimated,the Entity which provided that forecast is obligated to make up the deficit spin in real time in order to keep the system protected.This includes forecasted unit startups. 4)To the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was overestimated,the difference in spin obligation will be pro rata credited to the remaining Entities in their Spin Balancing Account (SBA).This includes forecasted unit shutdowns. For the Largest Single Generating Contingency (LSGC)for an Entity 1)To the extent that the forecasted LSGC for an Entity's real time output was underestimated,the Entity which provided that forecast is obligated to credit the remaining Entities'SBA with the difference in spin in which they over carried due to the inaccurate forecast. 2)To the extent that the forecasted LSGC for an Entity's real time output was overestimated,no adjustments to the SBA will be made. Page 80f 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit A2 -Spin Balancing Account A Spin Balancing Account (SBA)will be created and kept by each Balancing Authority (BA)showing Date, Hour,To,From,and Quantity. Quantities must exceed a dead band to be recorded.Quantities 2 MW or larger qualify to be recorded. The entries will primarily reflect errors in forecasting and the consequential harm (in terms of amount of spin carried)caused to the other Entities due to these errors. Entities will net out their spin obligations with others in chronological order (oldest first)but at times may need to redeem their spin via scheduling from the utility owing them spin,at no cost for the spin, and at such time the owing utility has spin excess of its needs.The owing utility has no obligation to start additional generation to provide such spin. Each quarter,a BA will be selected as being the "master”to which the other entities will compare their own records.The "master”role will be rotated. Page 9of 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit A3 -Geographical Spin Methodology for the handling specific issues resultant from Railbelt Geography A:Kenai A single transmission line connects the generation on the Kenai with the rest of South Centra! Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Kenai Transmission Line; Not all spin originating on the Kenai can leave the Kenai; If spin can't leave the Kenai,the utilities north of the Kenai will need to make it up in order to satisfactorily protect the system; If spin can't leave the Kenai,it is inefficient to require an Entity to carry spin that can't be used; The Kenai isn't always constrained every hour; Spin originating on the Kenai can leave the Kenai; Entities on the Kenai should be required to carry their share of spin; To address this issue will require real time monitoring of the flows between the Kenai and the Anchorage Bowl.CEA has the live data which can be distributed via ICCP or equivalent. HEA/AEEC will be permitted to reduce their spin obligation (and consequently the other Entities will need to pro rata increase their spin obligation)during periods of constraint (and near constraint as appropriate).How much would need to be broadcast to all the utilities via CEA. During periods of constraint and during incidents requiring spin,both CEA and HEA/AEEC will need to monitor the Kenai Transmission Line and curtail the conversion of spin to MW if the emergency limit of the line is expected to be exceeded or is exceeded. CEA's Cooper Lake Plant may be providing spin for CEA which needs to be included in the constrained Kenai calculations.CEA may have certain rights as spelled out in the Bradley Contracts which must be upheld and are of a higher priority than these rules.HEA/AEEC has some amount of Bradley Lake Spin which generally can be expected to leave the Kenai. There may be times where the largest loss contingency in the system is the loss of the Kenai line itself.By definition,HEA/AEEC would not be able to contribute useful spin to such an incident. HEA/AEEC should be permitted to reduce their spin obligation (and consequently the other utilities will need to pro rata increase their spin obligation)so as to only cover the next largest Single Generating Unit Contingency subject to other restrictions of the Kenai Transmission line discussed above. Page 10of 56 RROCONTINGENCY RESERVESPOLICY v001 When the Kenai is islanded,the utilities north of the Kenai shall not be permitted to count their stranded Kenai spin towards their spin obligations. B:Interior A single transmission line connects the generation in the Interior with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Alaska Intertie Transmission Line; Not all spin originating in South Central can leave South Central; If the System LSGC is in the interior,South Central Entities share in providing spinning reserve to cover this unit; If spin can't leave the South Central,it is inefficient to require an Entity to carry spin that can't be used; South Central Entities should not count an Interior LSGC as the Systems'largest unit during periods when the Alaska Intertie is constrained or near constrained as appropriate. The Alaska Intertie isn't always constrained every hour; Spin originating on the South Central can leave South Central; Entities in South Central should be required to carry their share of spin for an Interior System LSGC; To address this issue will require real time monitoring of the flows between the Interior and the Anchorage Bowl.AMLP has live data which can be distributed via ICCP or equivalent.South Central Entities will be permitted to reduce their spin obligation during periods of constraint (and near constraint as appropriate)to cover the next largest South Central based contingency. Page 11 0f 56 RRO VO vs RRO V1 CONTINGENCY RESERVES POLICY Reserve Capacity Planning Criteria A-1.1 1.1.1 1.1.2 1.1.3 Each Load Serving Entity is expected to maintain responsibility to provide capacity for its own firm load.As part of such responsibility,the Load Serving Entity shall maintain or otherwise provide for annually,Accredited Capacity,in an amount equal to or greater than its maximum System Demand for such year plus the Load Serving Entity's Reserve Capacity Obligation,as set forth n Subsection A-1.1.2. The Reserve Capacity Obligation of a Load Serving Entity,for any year,_shall be equal to thirty (30)percent of the projected Annual System Demand for that year for that Load Serving Entity.The Reserve Capacity Obligation of the Load Serving Entity may be adjusted from time to time by the Regional Reliability Organization. The Regional Reliabiity Organization may determine the annual Accredited Capacity for each Load Serving Entity. Responsibility for Operating Reserve B-2.1 2.1.1 Operating Reserve Each Load Serving Entity and/or Generation Owner_shall provide,or contract for,Spinning Reserve and Non-Spinning Reserve as required by Section B-22 equal to or greater than the Operating Reserve Obligation of the entity.As soon as practicable,but not to exceed four hours,after the occurrence of an incident which uses Operating Reserves, each entity shall restore its Operating Reserve Obligation. Operating Reserves,Operating Reserve Obligation,System Reserve Basis and allocation calculations may be modified or changed by the Regional Reliabilty Organization. The System Reserve Basis (SRB)is equal to the Largest Generating Unit Contingency of the System as_defined in Exhibit A1 or other such value_such as loss of a transmission line,as determined by engineering studies and approved by the RRO. RROCONTINGENCY RESERVESPOLICY B-22 2.2.1 capabilly forthe duration that the-tower value 6 -declared Single points of interconnection, such_as,but not limited to,buses,collector feeders,step-up transformers,shall be evaluated in terms of asset class.Failure rates such that the asset class is involved in a failure at a rate of once per year will validate it as a single point of interconnection as discussed above.However,subject to the reasoning above,the Regional Reliability Organization may exercise judgment _in such matters. ate =ales AG oven ing An entity adding a unit whose LGUCLSGCr greater than a 20 MW-SRB-<ap will accrue the obligation above 20 MW on a one for one basis in addition to its otherwise calculated spin obligation.This cap is subject to change by the RRO. , Total Operating Reserve Obligation The Total Operating Reserve Obligation at any time shall be an amount equal to 60 percent of the System Reserve Basis of the Railbelt Electric Grid 2.2.1.1 The Spinning Reserve portion of the Total Operating Reserve Obligation shall not be less than an amount equivalentto 100 percent efheof the System Reserve Basis. 2.2.1.2 The balance of the Total Operating Reserve Obligation shall be maintained with Non-Spinning Reserve. 2.2.2.Generating unit capability for Operating Reserves shall be determined by the following criteria: a.kt shall not be less than the load on the machine at any particular time nor greater than (b)below. b.k shall not exceed that maximum amount of load (MW)that the unit is capable of continuously supplying for a two-hour period,or quickly,through action of automatic governor contro'. Page 42of 56 RROCONTINGENCY RESERVES POLICY 2.2.3 The criteria specified in this section may be modified or changed by the Regional Reliability Organization. B-23 Allocation of Operating ReservesReserve Obligations . Page 430f 56 RROCONTINGENCY RESERVES POLICY 2.3.1 The Operating Reserve Obligation of aLead Servingan Entity shall be that percentage of B-2-4 2.4.1 2.4.2 2.4.3 2.4.4 2.4.5 2.4.6 the Total Operating Reserve Obligation determined by the Regional Reliability Organization in accordance with the formulas described in exhibits 81B1,B2 and exhibit B3A3. Operating Reserve Catculation A-Lead ServiagAn Entity's Spinning Reserve shall be calculated at any given instant as the difference between the sum of the net capability of all generating units on line in the respective entity and the integrated Systems Demand of the system involved and other sources (for example,SILOS and BESS)or declared restrictions on spinning reserve (for example,Bradley Lake or tie line restrictions)as accepted by the Regional Reliability Organization. A-Lead SeringAn Entiy's Spinning Reserve may be satisfied by an automatically controlled load shedding program.The lad shedding program shall assure that controlled load can be dropped to meet the requirement of Spinning Reserve in such a manner as to maintain system stability and not cause degradation or cascading effects inthe Railbelt system. The Regional Reliabilty Organization may establish procedures to assure that the Operating Reserve -of-an entity is available on the Railbelt System at all times. Whenever an entity is unable to meet is Operating Reserve Obligation,that the entity will,within two hours,advise its Balancing Authority and make arrangements to restore ts Operating Reserve Obligation. Prudent Utility Practices shall be followed in distributing Operating Reserve,taking into account effective utilization of capacity inan emergency,time required to be effective, transmission limitations and local area requirements...Geographical constraints and remedies are defined in Exhibit A3. A -LeadSeringSubject to 2.4.4 above,an Entity may arrange for one or more other entities to supply part of,or its entire,Operating Reserve requirement-. By mutual agreement between the parties,an Entity which has contracted or leased all of the Interconnected Value of a Generating Asset or Share of a Generating Asset_(energy,capacity,reactive-output_dispatch-ability etc.)to another Railbelt Entity,such that this particular asset_appears for all intents and purposes as Generating Asset of the Lessee's (contractee's)fleet,may have that asset counted among the Lessee's generating units and the Lessee may include this unit as any other in the Lessee's fleet for purposes of calculation operating reserve allocation. Page 44of 56 RROCONTINGENCY RESERVESPOLICY An example of this is the Bradley Lake Project.AEA and at various times other project participants have contracted to have the Interconnected Value of_this Generating Asset_or their respective Shares of this Generating Asset_assigned_to one another in different_forms.In each case the assignor has been relieved of the assigned project share (as the assignor's potential LSGC)and that share has been assigned to the assignee's fleet. 2-4-62.4.7 In an emergency,any Generator Owner,upon request by its Balancing Authority,shall supply to such Balancing Authority part or all of its Operating Reserve up to the full amount of its Available Accredited Capacity.Atead-SerangAn Entity experiencing an emergency is not required to maintain its Operating Reserve Obligation.There shall be no obligation of an entityEntity to supply Operating Reserve if the requesting entity isnot makingfullmaking full use of its own Available Accredited Capacity. Page 450f56 RROCONTINGENCY RESERVES POLICY Cc Responsibility for Regulating Reserve C-3.1 Regulating Reserve 3.1.1 Each Balancing AuthertyAuthorty (BA})shall provide,or contract for,Regulating C-3.2 3.2.1 3.2.2 3.2.3 Reserve as required by Section C-3.2 equal to or greater than the Regulating Reserve Obligation of the party.Regulating Reserve may not overlap reserves dedicated for Spinning Reserve.Regulating Reserve (both up and down)is required to compensate for uncertainty in ferecastingforecasting and is established during the unit commitment planning process,and as such the BA may then utilize its reserve as required during the course of the day.If a BA exhausts its Regulating Reserve,it is required to procure or commit additional reserves immediately. Regulating Reserve Obligation The Regulating Reserve Obligation for each Balancing Authority shail intially be set by the Regional Reliabilty Organization. On an annual basis,after the year end CPS statistics are compiled,the Regional Reliability Organization will modify each Balancing Authority'sAuthority's Regulating Reserve by increasing/decreasing its current Regulating Reserve by the %deviation in its GPSICPS1. The Regulating Reserve ebligationsObligations so calculated will be rounded up to the nearest integer MW. The Regional Reliability Organization reserves the right to increase/decrease a BA's Regulating Reserve or require other measures at any time due to changes in the system or repeat infractions._Spin Balancing Account records will be maintained as described in Exhibit A2. Page 46 of 56 RROCONTINGENCY RESERVES POLICY v001 Page4 790 =n56 RROCONTINGENCY RESERVES POLICY v001 Exhibit Bl]:Spinning Reserve Components Spinning Reserve Obligation will be allocated to the Lead Seringan Entity based on a combination of its Monthly Peak Hour Load {MPHL)and the Entities'Largest Single Generating Contingency (including any combination of units with a single point of interconnection forming a single contingency as further discussed in 2.1.3.RAS applications which have been field demonstrated to successfully mitigate the LSGC and have been approved by the RRO may be applied to reduce the magnitude of the LSGC. Monthly Peak HourLoad {MHPLSpinning Reserve Largest Contingency Ratio (SRLCR):This component shall be calculated as the ratio of an entiy's MPRHLindividual Entities'Largest Single Generatin Contingency (LSGC)as compared to the Ren-ceincidenHeHLsum of the LSGC's of all the Railbelt-_ Entities. The Largest Single Generating Contingency will be based on the actual capacity of those unit(s)subject to the single contingency (regardless of RAS applications).An example of a Generating Contingency is a combined cycle unit:the loss of the combustion turbine will precipitate the loss of both the CT as well as the waste heat unit. If entities share a unit,an entities Share of such a unit could qualify as their LSGC if they have no unit(s) that are larger. Monthly Peak Hour Load Ratio (MPHLR):This component shall be calculated at the ratio of an individual Entities'MPHL as compared to the sum of the MPHL's of all the Railbelt Entities.The MPHL of an entity isEntity shall be defined as the measuredMPHLset-eaMonthly Peak Hourly Load from the-current month ene year earlier.Adjustments for permanent loss,_or expected increases due to large industrial loads may be made if agreed to by the RRO.Economy sales are not counted as loads,but non-firm/interruptible bads are. SoinMPHLe =MPHLe /4(MPHL) Page 48of56 RROCONTINGENCY RESERVES POLICY v001 Exhibit B2:Spinning Reserve Obligation Spinning Reserve Obligation for a-Lead Servingan Entity will be calculated summing the weighted Spinning Reserve Components of each entity,and multiplyingthis by the System Reserve Basis as follows: __SROe=A*SpinMPHLe*=50%{LSGCeW{5i (LSGCi)SRB-+]+50%{MPHLe/{5i (MPHL:)}*[SRB]+MUDe Where-_e =a particular Entity i=All Interconnected Entities MUDe4s=the difference between the 2.1.3 max unit deltaflimit and an entities targest unit if anyjforthat54-3:-greater than the 2.1.3 cap. Page 49 of 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit B3:Spinning Reserve Criteria In order to be counted as a producer of Spinning Reserve,the net response regardless of methods used (generator,SILOS,BESS,duct firing,etc.)must be able to meet the felewingfollowng minimum performance based-criteria: Initial response:movement within 2 seconds 30 second response:50%usage ofits reported spin capability 6O0secondresponse:75%usage ofits reported spin_capability ROsecondresponse:100%usage ofits reported spin_capability Page 500f56 RROCONTINGENCY RESERVES POLICY v001 Exhibit Al -Methodology for a varying Largest Single Generating Contingency. For the Largest Single Generating Contingency (LSGC)for the Railbelt System 1)Each Entity will electronically share their hourly expected temperature compensated largest unit's output forecast during the day-ahead scheduling process.This may not be the same unit for each hour. 2)At this time,each utility will also share data on any forecasted excess spin that the Entity may wish to sell, 3)The next day and to the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was underestimated,the Entity which provided that forecast is obligated to make up the deficit spin in real time in order to keep the system protected.This includes forecasted unit startups. 4)_To the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was overestimated,the difference _in spin obligation will be pro rata credited to the remaining Entities in their Spin Balancing Account (SBA).This includes forecasted unit shutdowns. For the Largest Single Generating Contingency (LSGC)for an Entity 1)To the extent that the forecasted LSGC for an Entity's real time output was underestimated,the Entity which provided that forecast is obligated to credit the remaining Entities'SBA with the difference in spin in which they over carried due to the inaccurate forecast. 2)To the extent that the forecasted LSGC for an Entity's real time output was overestimated,no adjustments to the SBA will be made. Page 51 of 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit A2 -Spin Balancing Account A Spin Balancing Account {SBA)will be created and kept by each Balancing Authority (BA)showing Date, Hour,To,From,and Quantity. Quantities must exceed a dead band to be recorded.Quantities 2 MW or larger qualify to be recorded. The entries will primarily reflect errors in forecasting and the consequential harm (in terms of amount of spin carried)caused to the other Entities due to these errors. Entities will net out their spin obligations with others in chronological order (oldest first)but at times may need to redeem their spin via scheduling from the utility owing them spin,at no cost for the spin, and at such time the owing utility has spin excess of its needs.The owing utility has no obligation to start additional generation toprovide such spin. Each quarter,a BA will be selected as being the "master”to which the other entities will compare their own records.The "master”role will be rotated. Page 520f 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit A3 -Geographical Spin Methodology for the handling specific issues resultant from Railbelt Geography A:Kenai A single transmission line connects the generation on the Kenai with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Kenai Transmission Line; Not all spin originating on the Kenai can leave the Kenai: If spin can't leave the Kenai,the utilities north of the Kenai will need to make it up in order to satisfactorily protect the system; If spin can't leave the Kenai.it is inefficient to require an Entity to carry spin that can't be used; The Kenai isn't always constrained every hour; Spin originating on the Kenai can leave the Kenai: Entities on the Kenai should be required to carry their share of spin: To address this issue will require real time monitoring of the flows between the Kenai and the Anchorage Bowl.CEA has the live data which can be distributed via ICCP or equivalent. HEA/AEEC will be permitted to reduce their spin obligation (and consequently the other Entities will need to pro rata increase their spin obligation)during periods of constraint (and near constraint as appropriate).How much would need to be broadcast to all the utilities via CEA. During periods of constraint and during incidents requiring spin,both CEA and HEA/AEEC will need to monitor the Kenai Transmission Line and curtail the conversion of spin to MW if the emergency limit of the line is expected to be exceeded or is exceeded. CEA's Cooper Lake Plant may beprovidingspin for CEA which needs to be included in the constrained Kenai calculations.CEA may have certain rights as spelled out in the Bradley Contracts which must be upheld and are of a higher priority than these rules.HEA/AEEC has some amount of Bradley Lake Spin which generally can be expected to leave the Kenai. There may be times where the largest loss contingency in the system is the loss of the Kenai fine itself.By definition,HEA/AEEC would not be able to contribute useful spin to such an incident. HEA/AEEC should be permitted to reduce their spin obligation (and consequently the other utilities will need to pro rata increase their spin obligation)so as to only cover the next largest Single Generating Unit Contingency subject to other restrictions of the Kenai Transmission line discussed above. Page 53 of 56 RROCONTINGENCY RESERVESPOLICY v001 When the Kenai is islanded,the utilities north of the Kenai shall not be permitted to count their stranded Kenai spin towards their spin obligations. B:Interior A single transmission line connects the generation in the Interior with the rest of South Centra! Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Alaska Intertie Transmission Line; Not all spin originating in South Central can leave South Central: if the System LSGC is in the interior,South Central Entities share in providing spinning reserve to cover this unit; If spin can't leave the South Central,it is inefficient to require an Entity to carry spin that can't be used; South Central Entities should not count an Interior LSGC as the Systems'largest unit during periods when the Alaska Intertie is constrained or near constrained as appropriate. The Alaska Intertie isn't always constrained every hour: Spin originating on the South Central can leave South Central: Entities in South Central should be required to carry their share of spin for an Interior System LSGC; To address this issue will require real time monitoring of the flows between the Interior and the Anchorage Bowl.AMLP has live data which can be distributed via ICCP or equivalent.South Central Entities will be permitted to reduce their spin obligation during periods of constraint (and near constraint as appropriate)to cover the next largest South Central based contingency. Page 540f56 AKRES 001-1 A.Introduction 1.Title:Reserve Obligation and Allocation 2.Number:AKRES-001-1 3.Purpose: This standard describes Reserve Obligations for all Entities interconnected to the Railbelt Grid. 4.Applicability: 4.1.Balancing Authorities 4.2.Load Serving Entities 4.3.Generation Owners (Generation Asset Owning Entities) 5.Effective Date:TBD B.Requirements RI.Reserve Capacity Requirement RI.1.Each Load Serving Entity is expected to maintain responsibility to provide capacity for its own firm load.As part of such responsibility,the Load Serving Entity shall maintain or otherwise provide for annually,Accredited Capacity,in an amount equal to or greater than its maximum System Demand for such year plus the Load Serving Entity's Reserve Capacity Obligation,as set forth in Subsection R1.2. RIL2.The Reserve Capacity Obligation of a Load Serving Entity,for any year,shall be equal to thirty (30)percent of the projected Annual System Demand for that year for that Load Serving Entity.The Reserve Capacity Obligation ofthe Load Serving Entity may be adjusted from time to time by the Intertie Management Committee (IMC). R13.The IMC may determine the annual Accredited Capacity for each Load Serving Entity. R2.Responsibility for Operating Reserve R2.1.Each Load Serving Entity and/or Generation Owner shall provide,or contract for, Spinning Reserve and Non-Spinning Reserve as required by Section R3 equal to or greater than the Operating Reserve Obligation of the entity.As soon as practicable,but not to exceed four hours,after the occurrence of an incident which uses Operating Reserves,each entity shall restore its Operating Reserve Obligation. R22.Operating Reserves,Operating Reserve Obligation,System Reserve Basis and allocation calculations may be modified or changed by the Intertie Management Committee. R2.3.The System Reserve Basis (SRB)is equal to the Largest Generating Unit Contingency of the System as defined in Exhibit Al or other such value such as loss of a transmission line,as determined by engineering studies and approved by the IMC. AKRES 001-1 R3.Total Operating Reserve Obligation R3.1.The Total Operating Reserve Obligation at any time shall be an amount equal to 150 percent of the System Reserve Basis of the Railbelt Electric Grid. R3.2.The Spinning Reserve portion of the Total Operating Reserve Obligation shall not be less than an amount equivalent to 100percent of the System Reserve Basis. R3.3.The balance of the Total Operating Reserve Obligation shall be maintained with Non-Spinning Reserve. R4.Generating Unit Capability- Generating unit capability for Operating Reserve shall be determined by the following criteria: R4.1.Itshall not be less than the load on the machine at any particular timenor greater than R42 below R4.2.It shall not exceed that maximum amount of load (MW)that the unit is capable of continuously supplying for a two-hour period,or quickly,through action of automatic governor controls. R4.3 In order to be counted as a producer of Spinning Reserve,the net response regardless of methods used (generator,SILOS,BESS,duct firing,etc.)must be able to meet the following minimum performance based criteria: Initial response:movement within 2 seconds 30 second response:50%usage of its reported spin capability 60 second response:75%usage of its reported spin capability 120 second response:100%usage of its reported spin capability R4.4.The criteria specified in this section may be modified or changed by the Intertie Management Committee. R5.Allocation of Operating Reserve Obligations The Operating Reserve Obligation of an Entity shall be that percentage of the Total Operating Reserve Obligation determined by the IMC in accordance with the formulas described in R5 through R7 R5.1.An Entity's Spinning Reserve shall be calculated at any given instant as the difference between the sum of the net capability of all generating units on line in the respective entity and the integrated Systems Demand of the system involved and other sources (for example,SILOS and BESS)or declared restrictions on spinning reserve (for example, Bradley Lake or tie line restrictions)as accepted by the IMC R5.2.An Entity's Spinning Reserve may be satisfied by an automatically controlled load shedding program.The load shedding program shall assure that controlled load can be dropped to meet the requirement of Spinning Reserve in such a manner as to maintain system stability and not cause degradation or cascading effects in the Railbelt system. R5.3.The IMC may establish procedures to assure that the Operating Reserve of an entity is available on the Railbelt System at all times.Whenever an entity is unable to meet its AKRES 001-1 Operating Reserve Obligation,the entity will,within two hours,advise its Balancing Authority and make arrangements to restore its Operating Reserve Obligation. R5.4.Prudent Utility Practices shall be followed in distributing Operating Reserve,taking into account effective utilization of capacity in an emergency,time required to be effective, transmission limitations and local area requirements.Available Transfer Capability (ATC)shall include a component (Capacity Benefit Margin)recognizing the need to move reserves between areas.Geographical constraints and remedies are defined in Exhibit A3. R5.5.Subject to R5.3 above,an Entity may arrange for one or more other entities to supply part of,or its entire,Operating Reserve requirement. R5.6.By mutual agreement between the parties,an Entity which has contracted or leased all of the Interconnected Value of a Generating Asset or Share of a Generating Asset (energy,capacity, reactive-output dispatch-ability etc.)to another Railbelt Entity,such that this particular asset appears for all intents and purposes as Generating Asset of the Lessee's (contractee's)fleet, may have that asset counted among the Lessee's generating units and the Lessee may include this unit as any other in the Lessee's fleet for purposes of calculation operating reserve allocation. An example of this is the Bradley Lake Project.AEA and at various times other project participants have contracted to have the Interconnected Value of this Generating Asset or their respective Shares of this Generating Asset assigned to one another in different forms.In each case the assignor has been relieved of the assigned project share (as the assignor's potential LSGC)and that share has been assigned to the assignee's fleet. R5.7.In an emergency,any Generator Owner,upon request by its Balancing Authority,shall supply to such Balancing Authority part or all of its Operating Reserve up to the full amount of its Available Accredited Capacity.An Entity experiencing an emergency is not required to maintain its Operating Reserve Obligation.There shall be no obligation of an Entity to supply Operating Reserve if the requesting entity is not making full use of its own Available Accredited Capacity. R6.Responsibility for Regulating Reserve R6.1.Regulating Reserve-each Balancing Authority (BA)shall provide,or contract for,Regulating Reserve as required by Section R6.2 equal to,or greater than,the Regulating Reserve Obligation of the party.Regulating Reserve may not overlap reserves dedicated for Spinning Reserve.Regulating Reserve (both up and down)is required to compensate for uncertainty in forecasting and is established during the unit commitment planning process,and as such the BA may then utilize its reserve as required during the course of the day.If a BA exhausts its Regulating Reserve,it is required to procure or commit additional reserves immediately. Available Transfer Capability (ATC)for Interconnecting Transmission lines shall recognize a component included in Transmission Reliability Margin (TRM)to allow for the delivery of Regulating Reserve between areas. R6.2.Reguhting Reserve Obligation-the Regulating Reserve Obligation for each Balancing Authority shall initially be set by the Intertie Management Committee. R6.3.On an annual basis,after the year end CPS statistics are compiled,the IMC will modify each Balancing Authority's Regulating Reserve by increasing/decreasing its current Regulating R7. R6.4. AKRES 001-1 Reserve by the %deviation in its CPS1.The Regulating Reserve Obligations so calculated will be rounded up to the nearest integer MW. The IMC reserves the right to increase/decrease a BA's Regulating Reserve or require other measures at any time due to changes in the system or repeat infractions. Spinning Reserve Components R7.1. R7.2. R7.3. R7.4. R75. R7.6. Spinning Reserve Obligation will be allocated to an Entity based on a combination of its Monthly Peak Hour Load (MPHL)and the Entities'Largest Single Generating Contingency (including any combination of units with a single point of interconnection forming a single contingency as further discussed in R7.6.RAS applications which have been field demonstrated to successfully mitigate the LSGC and have been approved by the IMC may be applied to reduce the magnitude of the LSGC. Spinning Reserve Largest Contingency Ratio (SRLCR):This component shall be calculated as the ratio of an individual Entities'Largest Single Generating Contingency (LSGC)as compared to the sum of the LSGC's of all the Railbelt Entities. The Largest Single Generating Contingency will be based on the actual capacity of those unit(s)subject to the single contingency (regardless of RAS applications). An example of a Generating Contingency is a combined cycle unit;the loss of the combustion turbine will precipitate the loss of both the CT as well as the waste heat unit. If entities share a unit,an entities Share of such a unit could qualify as their LSGC if they have no unit(s)that are larger. Monthly Peak Hour Load Ratio (MPHLR):This component shall be calculated at the ratio of an individual Entities'MPHL as compared to the sum of the MPHL's of all the Railbelt Entities.The MPHL of an Entity shall be defined as the Monthly Peak Hourly Load from the month 1 year earlier.Adjustments for permanent loss,or expected increases due to large industrial loads may be made if agreed to by the IMC.Economy sales are not counted as loads,but non-firm/interruptible loads are. Single points of interconnection,such as,but not limited to,buses,collector feeders,step-up transformers,shall be evaluated in terms of asset class.Failure rates such that the asset class is involved in a failure at a rate of once per year will validate it as a single point of interconnection as discussed in R7.1.However,subject to the reasoning above,the IMC may exercise judgment in such matters. R7.7.An entity adding a unit greater than 120 MW will accrue the obligation above 120 MW on a one for one basis in addition to its otherwise calculated spin obligation.This cap is subject to change by the IMC. R7.8.The Spinning Reserve Obligation (SRO)of each Obligated Entity shall be calculated as follows: SRO.=50%(LSGC.Y (Xi (LSGCi)}*[SRB]}+50%MPHL-}{2i(MPHL,)}*[SRB]+MUD, e=aparticular Entity C.Measures AKRES 001-1 i=All Interconnected Entities MUD-the difference between the R7.7 max unit limit and an entities largest unit if greater than the R7.7 cap. MI.Each Obligated Entity and Balancing Authority shall maintain: MI.1.Records of their Reserve Capacity at any point in time.These records will be updated as new Assets are added and other Assets are retired.These records will be available by for review by the Balancing Authority or Compliance Monitor with 1 business week written notice. Ml.2.Hourly records of Operating Reserve and Regulating Reserve (scheduled and actual)will be maintained by all Obligated Entities'.These will be made available in real-time to the Balancing Authority for archival and storage. MI.3.The Compliance Monitor will review the performance of each Balancing Authority and Obligated Entity at least annually.More frequent reviews shall be performed if spin obligation compliance warrants such reviews. MI.4.Spin Balancing Account records will be maintained as described in Exhibit A2. D.Compliance Monitoring 1. 2. Balancing Authorities IMC-Railbelt Regional Reliability Organization E.Non-Compliance Level 1. Version History Version Date Action Change Tracking AKRES 001-1 Exhibit Al -Methodology for a varying Largest Single Generating Contingency. For the Largest Single Generating Contingency (LSGC)for the Railbelt System 1)Each Entity will electronically share their hourly expected temperature compensated largest unit's output forecast during the day-ahead scheduling process.This may not be the same unit for each hour. 2)At this time,each utility will also share data on any forecasted excess spin that the Entity may wish to sell. 3)The next day and to the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was underestimated,the Entity which provided that forecast is obligated to make up the deficit spin in real time in order to keep the system protected.This includes forecasted unit startups. 4)To the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was overestimated,the difference in spin obligation will be pro rata credited to the remaining Entities in their Spin Balancing Account (SBA).This includes forecasted unit shutdowns. For the Largest Single Generating Contingency (LSGC)for an Entity 1)To the extent that the forecasted LSGC for an Entity's real time output was underestimated,the Entity which provided that forecast is obligated to credit the remaining Entities'SBA with the difference in spin in which they over carried due to the inaccurate forecast. 2)To the extent that the forecasted LSGC for an Entity's real time output was overestimated,no adjustments to the SBA will be made. AKRES 001-1 Exhibit A2 -Spin Balancing Account A Spin Balancing Account (SBA)will be created and kept by each Balancing Authority (BA)showing Date, Hour,To,From,and Quantity. Quantities must exceed a dead band to be recorded.Quantities 2 MW or larger qualify to be recorded. The entries will primarily reflect errors in forecasting and the consequential harm (in terms of amount of spin carried)caused to the other Entities due to these errors. Entities will net out their spin obligations with others in chronological order (oldest first)but at times may need to redeem their spin via scheduling from the utility owing them spin,at no cost for the spin,and at such time the owing utility has spin excess of its needs.The owing utility has no obligation to start additional generation to provide such spin. Each quarter,a BA will be selected as being the "master”to which the other entities will compare their own records.The "master”role will be rotated. AKRES 001-1 Exhibit A3 -Geographical Spin Methodology for the handling specific issues resultant from Railbelt Geography A:Kenai A single transmission line connects the generation on the Kenai with the rest of South Central Alaska. The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Kenai Transmission Line; Not all spin originating on the Kenai can leave the Kenai; If spin can't leave the Kenai,the utilities north of the Kenai will need to make it up in order to satisfactorily protect the system; If spin can't leave the Kenai,it is inefficient to require an Entity to carry spin that can't be used; The Kenai isn't always constrained every hour; Spin originating on the Kenai can leave the Kenai; Entities on the Kenai should be required to carry their share of spin; To address this issue will require real time monitoring of the flows between the Kenai and the Anchorage Bowl.CEA has the live data which can be distributed via ICCP or equivalent.HEA/AEEC will be permitted to reduce their spin obligation (and consequently the other Entities will need to pro rata increase their spin obligation)during periods of constraint (and near constraint as appropriate).How much would need to be broadcast to all the utilities via CEA. During periods of constraint and during incidents requiring spin,both CEA and HEA/AEEC will need to monitor the Kenai Transmission Line and curtail the conversion of spin to MW if the emergency limit of the line is expected to be exceeded or is exceeded. CEA's Cooper Lake Plant may be providing spin for CEA which needs to be included in the constrained Kenai calculations.CEA may have certain rights as spelled out in the Bradley Contracts which must be upheld and are of a higher priority than these rules.HEA/AEEC has some amount of Bradley Lake Spin which generally can be expected to leave the Kenai. There may be times where the largest loss contingency in the system is the loss of the Kenai line itself. By definition,HEA/AEEC would not be able to contribute useful spin to such an incident.HEA/AEEC should be permitted to reduce their spin obligation (and consequently the other utilities will need to pro rata increase their spin obligation)so as to only cover the next largest Single Generating Unit Contingency subject to other restrictions of the Kenai Transmission line discussed above. When the Kenai is islanded,the utilities north of the Kenai shall not be permitted to count their stranded Kenai spin towards their spin obligations. AKRES 001-1 B:Interior A single transmission line connects the generation in the Interior with the rest of South Central Alaska. The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Alaska Intertie Transmission Line; Not all spin originating in South Central can leave South Central; If the System LSGC is in the interior,South Central Entities share in providing spinning reserve to cover this unit; If spin can't leave the South Central,it is inefficient to require an Entity to carry spin that can't be used; South Central Entities should not count an Interior LSGC as the Systems'largest unit during periods when the Alaska Intertie is constrained or near constrained as appropriate. The Alaska Intertie isn't always constrained every hour; Spin originating on the South Central can leave South Central; Entities in South Central should be required to carry their share of spin for an Interior System LSGC; To address this issue will require real time monitoring of the flows between the Interior and the Anchorage Bowl.AMLP has live data which can be distributed via ICCP or equivalent.South Central Entities will be permitted to reduce their spin obligation during periods of constraint (and near constraint as appropriate)to cover the next largest South Central based contingency. AKRES-001 vs AKRES-000 A.Introduction 1.Title:Reserve Obligation and Allocation 2.Number:AKRES-001-91 3.Purpose: This standard describes Reserve Obligations for all Entities interconnected to the Railbelt Grid. 4.Applicability: 4.1.Balancing Authorities 4.2.Load Serving Entities 4.3.Generation Owners (Generation Asset Owning Entities) 5.Effective Date:TBD B.Requirements RI.Reserve Capacity Requirement R2. R11.Each Load Serving Entity is expected to maintain responsibility to provide capacity for its own finpfirm load.As part of such responsibility,the Load Serving Entity shall maintain or otherwise provide for annually,Accredited Capacity,in an amount equal to or greater than its maximum System Demand for such year plus the Load Serving Entities-Entity's Reserve Capacity Obligation,as set forth in Subsection R1.2. R12.The Reserve Capacity Obligation of a Load Serving Entity,for any year,shall be equal to thirty (30)percent of the projected Annual System Demand for that year for that Load Serving Entity.The Reserve Capacity Obligation of the Load Serving Entity may be adjusted from time to time by the Intertie Management Committee (IMC)). R13.The IMC may determine the annual Accredited Capacity for each Load Serving Entity, Responsibility for Operating Reserve R2.1.Each Load Serving Entity and/or Generation Owner shall provide,or contract for, Spinning Reserve and Non-Spinning Reserve as required by Section R3 equal to or greater than the Operating Reserve Obligation of the entity.As soon as practicable,but not to exceed four hours,after the occurrence of an incident which uses Operating Reserves,each entity shall restore its Operating Reserve Obligation. R22.Operating Reserves,Operating Reserve Obligation,System Reserve Basis and allocation calculations may be modified or changed by the Intertie Management Committee. R2.3.The System Reserve Basis (SRB)is equal to the Largest Generating Unit Contingency of the systemSystem as defined in Exhibit Al or other such value such as loss of a transmission line,as determined by engineering studies and approved by the IMC. AKRES-001 vs AKRES-000 R3.Total Operating Reserve Obligation R3.1.The Total Operating Reserve Obligation at any time shall be an amount equal to 150 percent of the SRBSystem Reserve Basis of the Railbelt_Electric Grid. R3.2.The Spinning Reserve portion of the Total Operating Reserve Obligation -shall not be less than an amount equivalent to 100percent of the SRB-System Reserve Basis. R3.3.The balance of the Total Operating Reserve Obligation shall be maintained with Non-Spinning Reserve-taka-Nen-Operatine Reserves}. R4.Generating Unit Capability- Generating unit capability for eperating reserveOperating Reserve shall be determined by the following criteria: R4.1.Itshall not be less thatthan the load on the machine at any particular time nor greater than R42 below R4.2.Itshall not exceed that maximum amount efleadof load (MW)that the unit is capable of continuously supplying for a two-hour period,or quickly,through action of automatic governor controls. R4.3_In order to be counted as a producer of Spinning Reserve,the net response regardless of methods used (generator,SILOS,BESS,duct firing,etc.)must be able to meet the following minimum performance based criteria: Initial response:movement within 2 seconds 30 second response:50%usage of its reported spin capability 60 second response:75%usage of its reported spin capability ==- --- 120 second response:100%usage of its reported spin capability R4.4.The criteria specified in this section may be modified or changed by the Intertie Management -Committee. RSRS5.Allocation of Operating Reserve Obligations The Operating Reserve Obligation of an Gbligated-Entity shall be that percentage of the Total Operating Reserve ebiigationObligation determined by the IMC in accordance with the formulas described in R5 through R7 RSRS5.1.An Entities'Entity's Spinning Reserve shall be calculated at any given instant as the difference between the sum of the net capability of all generating units on line in the respective entity and the integrated Systems Demand of the system involved and other sources (for example,SILOS and BESS)or declared restrictions on spinning reserve (for example,Bradley Lake or tie line restrictions)as accepted by the IMC RSRS5.2.An Entities'Entity's Spinning Reserve may be satisfied by an automatically controlled load shedding program.The load shedding program shall assure that AKRES-001 vs AKRES-000 controlled load can be dropped to meet the requirement of Spinning Reserve in such a manner as to maintain system stability and not cause degradation or cascading effects in the Railbelt system.-Fhe IMC-shal+eview-end_approvethe ¢at oave RSRS.3.The IMC may establish procedures to assure that the Operating Reserve of an entity is available on the Railbelt System at all times.Whenever an entity is unable to meet its Operating Reserve Obligation,thatthe entity will,within two AKRES-001 vs AKRES-000 'hours,advise its Balancing Authority and make arrangements to restore its Operating Reserve Obligation. RSRS5.4.Prudent Utility Practices shall be followed in distributing Operating -Reserve, taking into account effective utilization of capacity in an emergency,Respense Ratetime required to be effective,transmission limitations and local area requirements.Available Transfer Capability (ATC)shall include a component (Capacity Benefit Margin)recognizing the need to move reserves between areas. Geographical constraints and remedies are defined in Exhibit A3. R5.5.Subject to R5.3 above,an entityEntity may arrange for one or more other entities to supply part of,or its entire,Operating Reserve requirement. RSRS5.6.By mutual agreement between the parties,an Entity which has contracted or leased all of the Interconnected Value of a Generating Asset or Share of a Generating Asset (energy,capacity,reactive-output dispatch-ability etc.)to another Railbelt Entity,such that this particular asset appears for all intents and purposes as Generating Asset of the Lessee's (contractee's)fleet,may have that asset counted among the Lessee's generating units and the Lessee may include this unit as any other in the Lessee's fleet for purposes of calculation operating reserve allocation. An example of this is the Bradley Lake Project.AEA and at various times other project participants have contracted to have the Interconnected Value of this Generating Asset or their respective Shares of this Generating Asset assigned to one another in different forms.In each case the assignor has been relieved of the assigned project share (as the assignor's potential LSGC)and that share has been assigned to the assignee's fleet. RSRS5S.7.In an emergency,any Generator Owner,upon request by its Balancing Authority-tether-threuch-automatedfrequency_or-voltage_feedback-or-via SystemOperaterintervention),,shall supply to such Balancing Authority part or all of its Operating Reserve up to the full amount of its Available Accredited Capacity.An Entity experiencing an emergency is not required to maintain its Operating Reserve Obligation.There shall be no obligation of an Entity to supply Operating Reserve if the requesting entity is not making full use of its own Available Accredited Capacity. R6.Responsibility for Regulating Reserve R6.1.Regulating Reserve-each Balancing Authority (BA)shall provide,or contract for, Regulating Reserve as required by Section R6.2 equal to,or -greater -than,the Regulating Reserve Obligation of the party.Regulating Reserve may-not overlap reserves dedicated for Spinning Reserve.Regulating Reserve (both up and down) is required to compensate for uncertainty in forecasting and is established during the unit -commitment planning process,and as such the BA may then utilize theirits reserve as required during the course of the day.Half.a BA exhausts its Regulating Reserve,they-areit_is required to procure or commit additional reserves -immediately.-Available -Transfer -Capability 4ATC)for R7. AKRES-001 vs AKRES-000 Interconnecting Transmission lines shall recognize a component included in Transmission Reliability Margin (TRM)to allow for the delivery of Regulating Reserve between areas. R6.2.RegulatingReguhting Reserve Obligation-the Regulating Reserve Obligation for each Balancing Authority shall initially be sett by the -intertie¢ Management R6.3.On an annual basis,after the year end CPS -statistics are compiled,the IMC shalwill modify each Balancing Autherities'Authority's Regulating Reserve by increasing/decreasing its current Regulating Reserve by the %deviation in its EPS4ICPS1.The Regulating Reserve ebligatiensObligations so calculated will be rounded up to the nearest integer MW. R6.4.The IMC reserves the right to increase/decrease a BALsBA's Regulating Reserve or require other measures at any time due to changes in the system or repeat 'infractions. Spinning Reserve Components R7.1.Spinning Reserve Obligation will be allocated to an Entity based -on a combination of its Monthly Peak Hour Load (MPHL)and the EntittesEntities'Largest Single Generating Contingency (including any combination of units with a single point of interconnection forming a single contingency:_as further discussed in R7.6.RAS applications which have been field demonstrated to successfully mitigate the LSGC and have been approved by the IMC may be applied to reduce the magnitude of the LSGC. R7.2.Spinning Reserve Largest Contingency Ratio (SRLCR):This component shall be calculated as the ratio of an individual Entities'Largest Single Generating Contingency (LSGC)as compared to the sum of the LSGC's of all the Railbelt Entities. R7.3.The Largest Single Generating Contingency will be based on the maximum Declared-Capabilityactual capacity of those unit(s)subject to the single contingency (regardless of RAS applications;-when-eperated-at-the An example of a Generating Contingency is a combined cycle unit;the loss of the combustion turbine will precipitate the loss of both the CT as well as the waste heat unit. R7.4.If entities share a unit,an entities Share of such a unit could qualify as their LSGC if they &have no unit(s)that areLarger This component may change AKRES-001 vs AKRES-000 R7.5.Monthly Peak Hour Load Ratio (MPHLR):This component shall be calculated at the ratio of an individual Entities'MPHL as compared to the sum of the MPHL's of all the Railbelt Entities.The MPHL of an Entity shall be defined as the Monthly Peak Hourly Load from the month 1 year earlier.Adjustments for permanent loss,or expected increases due to large industrial loads may be made if agreed to by the IMC.Economy sales are not counted as loads,but non- firm/interruptible loads are. R7.6.Single points ofinterconnection,such astheremainderoftheSpinningReserve-contribution_oftheparticularunit(s}itis-auementine-It,but not limited to,.buses,collector feeders,Step-Up transformers,shall be the obligation of the- review documentationcvaluated iin termssofaasset class.Failure rates such:testing: bus feulte-or multiple nite om that the assetclass iis"involved jinaa failure at arate of once per year will validate it asa sing'e oie cree eee 3s a point ofof failure_in_a_fuel_supply_that_may sesultinterconnection ass discussed in the less-of-multiple-units-dees_net_necessarily-eonstitute-a-LSGE.R7.1.However, subject to the reasoning above,the IMC may exercise judgment in such matters. R+.&R7.7.An entity adding a unit greater than 120 MW will accrue the obligation above 120 MW on a one for one basis in addition to theirits otherwise calculated spin obligation.Fhe-aferementioned120MWThis cap is subject to change by the IMC. R+9:R7.8.The Spmning Reserve Obligation -{SRO)of each Obligated Entity shall be calculated as follows: ___SRO.4ESGE-V4{EHESGE-50%LLSGCLY {5 (LSGC)}*[SRB]+50%{MPHL.YV{3; (MPHL)}*[SRB]+MUD. e=i a particular Entity i=All Interconnected Entities MUD.-=the difference between the R7.7 max unit limit and an entities largest unit if greater than the R7.7 Hmitcap. C.Measures Ml.Each Obligated Entity and Balancing Authority shall maintain: MI.1.Records of their Reserve Capacity at any point in time.These records will be updated as new Assets are added and other Assets are retired.These records will be available by for review by the Balancing Authority or Compliance Monitor with 1 business week written notice. AKRES-001 vs AKRES-000 MI.2.Hourly records of Operating Reserve and Regulating Reserve (scheduled and actual)will be maintained by all Obligated Entities'.These will be made available in real-time to the Balancing Authority for archival and storage. MI.3.The Compliance Monitor will review the perfennanceperformance of each Balancing Authority and Obligated Entity at least annually.More frequent reviews shall be performed if spin obligation compliance warrants such reviews. ML4.Spin Balancing Account records will be maintained as described in Exhibit A2. Compliance Monitoring 1.Balancing Authorities AKRES-001 vs AKRES-000 2.IMC-Railbelt Regional Reliability Organization E.Non-Compliance. E.Level 1. VerstonHisterv Version Histor Version Date Action Change Tracking AKRES-001 vs AKRES-000 Exhibit A1 -Methodology for a varying Largest Single Generating Contingency. For the Largest Single Generating Contingency {LSGC)for the Railbelt System 1)Each Entity will electronically share their hourly expected temperature compensated largest unit's output forecast during the day-ahead scheduling process.This may not be the same unit for each hour. 2)At this time,each utility will also share data on any forecasted excess spin that the Entity may wish to sell. 3)The next day and to the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was underestimated,the Entity which provided that forecast is obligated to make up the deficit spin in real time in order to keep the system protected.This includes forecasted unit startups. 4)To the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was overestimated, the difference in spin obligation will be pro rata credited to the remaining Entities in their Spin Balancing Account (SBA).This includes forecasted unit shutdowns. For the Largest Single Generating Contingency (LSGC)for an Entity 1)To the extent that the forecasted LSGC for an Entity's real time output was underestimated,the Entity which provided that forecast is obligated to credit the remaining Entities'SBA with the difference in spin in which they over carried due to the inaccurate forecast. 2)To the extent that the forecasted LSGC for an Entity's real time output was overestimated,no adjustments to the SBA will be made. AKRES-001 vs AKRES-000 Exhibit A2 -Spin Balancing Account A Spin Balancing Account (SBA)will be created and kept by each Balancing Authority (BA)showing Date,Hour,To, From,and Quantity. Quantities must exceed a dead band to be recorded.Quantities 2 MW or larger qualify to be recorded. The entries will primarily reflect errors in forecasting and the consequential harm (in terms of amount of spin carried) caused to the other Entities due to these errors. Entities will net out their spin obligations with others in chronological order (oldest first)but at times may need to redeem their spin via scheduling from the utility owing them spin,at no cost for the spin,and at such time the owing utility has spin excess of its needs.The owing utility has no obligation to start additional generation to provide such spin. Each quarter,a BA will be selected as being the "master”to which the other entities will compare their own records. The "master”role will be rotated. AKRES-001 vs AKRES-000 Exhibit A3 -Geographical Spin Methodology for the handling specific issues resultant from Railbelt Geography A:Kenai A single transmission line connects the generation on the Kenai with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Kenai Transmission Line; Not all spin originating on the Kenai can leave the Kenai: If spin can't leave the Kenai,the utilities north of the Kenai will need to make it up in order to satisfactorily protect the system: If spin can't leave the Kenai,it is inefficient to require an Entity to carry spin that can't be used; The Kenai isn't always constrained every hour; Spin originating on the Kenai can leave the Kenai; Entities on the Kenai should be required to carry their share of spin: To address this issue will require real time monitoring of the flows between the Kenai and the Anchorage Bowl.CEA has the live data which can be distributed via JCCP or equivalent.HEA/AEEC will be permitted to reduce their spin obligation (and consequently the other Entities will need to pro rata increase their spin obligation)during periods of constraint (and near constraint as appropriate).How much would need to be broadcast to all the utilities via CEA. During periods of constraint and during incidents requiring spin,both CEA and HEA/AEEC will need to monitor the Kenai Transmission Line and curtail the conversion of spin to MW if the emergency limit of the line is expected to be exceeded or is exceeded. CEA's Cooper Lake Plant may be providing spin for CEA which needs to be included in the constrained Kenai calculations.CEA may have certain rights as spelled out in the Bradley Contracts which must be upheld and are of a higher priority than these rules.HEA/AEEC has some amount of Bradley Lake Spin which generally can be expected to leave the Kenai. There may be times where the largest loss contingency in the system is the loss of the Kenai line itself.By definition,HEA/AEEC would not be able to contribute useful spin to such an incident.HEA/AEEC should be permitted to reduce their spin obligation (and consequently the other utilities will need to pro rata increase their spin obligation)so as to only cover the next largest Single Generating Unit Contingency subject to other restrictions of the Kenai Transmission line discussed above. When the Kenai is istanded,the utilities north of the Kenai shall not be permitted to count their stranded Kenai spin towards their spin obligations. AKRES-001 vs AKRES-000 B:Interior A single transmission line connects the generation in the Interior with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Alaska Intertie Transmission Line; Not all spin originating in South Central can leave South Central. If the System LSGC is in the interior,South Central Entities share in providing spinning reserve to cover this unit; if spin can't leave the South Central,it is inefficient to require an Entity to carry spin that can't be used; South Central Entities should not count an Interior LSGC as the Systems'largest unit during periods when the Alaska Intertie is constrained or near constrained as appropriate. The Alaska intertie isn't always constrained every hour; Spin originating on the South Central can leave South Central: Entities in South Central should be required to carry their share of spin for an Interior System LSGC; To address this issue will require real time monitoring of the flows between the Interior and the Anchorage Bowl.AMLP has live data which can be distributed via ICCP or equivalent.South Central Entities will be permitted to reduce their spin obligation during periods of constraint (and near constraint as appropriate)to cover the next largest South Central based contingency. A Rie B IMC vs RRO CONTINGENCY RESERVES POLICY Reserve Capacity RequirementPlanning Criteria A-1.1 1.1.1 Ri+-£ach Load Serving Entity is expected to maintain responsibilityto provide capacity for ts own firm load.-As part of such responsibility,the Load Serving Entity shall maintain or otherwise provide for annually,Accredited Capacity,in an amount equal to or greater than its maximum System Demand for such year plus the Load Serving EntitysEntity's Reserve Capacity Obligation,as setforth in Subsection R4A-1.1.2. 1.1.2.The Reserve Capacity Obligation ofa Load Serving Entity,for any year,shall be equal to thirty (30)percent of the projected Annual System Demand for that year for that Load Serving Entity.-The Reserve Capacity Obligation of the Load Serving Entity may be adjusted from time to time by the fntertieManagementCommittee(H4G}-Regional Reliability Organization. 1.1.3.The #4GRegional_Reliability Organization may determine the annual Accredited Capacity for each Load Serving Entity. Responsibility for Operating Reserve R2 B-2.1--__OperatingReserve 2.1.1___Fach Load Serving Entity and/or Generation Owner shall provide,or contract for,Spinning Reserve and Non--Spinning -Reserve as required by Section R3B-22 equal to or greater than the Operating Reserve Obligation of the entity.As soon as practicable,but not to exceed IMC vs RRO four hours,after the occurrence of an incident which uses Operating Reserves,each entity shall restore its Operating Reserve Obligation. R22- 2.1.2 ___Operating Reserves,Operating Reserve Obligation,System Reserve Basis and allocation calculations may be modified or changed by the tntertie Management CommitteeRegional Reliabilty Organization. R23 2.1.3 The System Reserve Basis (SRB)is equal to the Largest Generating Unit Contingency of the System as defined in Exhibit Ai or other such value such as loss of a transmission line, as determined by engineering studies and approved by the IMGRRO. ingle point interconnection has,but not limited to,b oll r feeder -ransformer shall be evaluated in terms of asset class.Failure rates such that the asset class is involved in a failure at a f once per r will validate i a single point of interconnection as discussed RROCONTINGENCY RESERVES POLICY v001 above.However,subject to the reasoning above,the Regional ReliabilityOrganizationmayexercisejudqment_in such matters. An entity adding a unit whose LSGC «greater than a 20 MW will accrue the obligation above 20 MW_ona one for one basis in addition to ts otherwise calculated spin obligation.This cap is subject to change bythe RRO. B-22 Total Operating Reserve Obligation R3d- 2.2.1__The Total Operating Reserve Obligation at any time shall be an amount equal to 60 percent of the System Reserve Basis of the Railbelt Electric Grid- R32 2.2.1.1 The Spinning Reserve portion of the Total Operating Reserve Obligation shall not be less than an amount equivalent to 100 percent of the System Reserve Basis. R33 2.2.1.2 The balance of the Total Operating Reserve Obligation shall be maintained with Non-Spinning Reserve. 2.2.2 Generating unit capability for Operating ReserveReserves shall be determined by the following criteria: a,R4,4--k shall not be less than the load on the machine at any particular time nor greater than R42(b)below. b.R4,2-I shall not exceed that maximum amount of load (MW)that the unit is capable of continuously supplying for a two-hour period-,or quickly,through action of automatic governor contro'. 2.2.3 R4.4-The _criteria_specified_in this section may_be_modified or changed _by the intertie Management Gommittee_Regional Reliability Organization. Page 3of 56 RROCONTINGENCY RESERVES POLICY v001 oo.B-2.3_Allocation of Operating Reserve Obligations 2.3.1 The Operating Reserve Obligation of an Entity shall be that percentage of the Total Operating Reserve Obligation determined by the '$W4CRegional Reliability Organization in accordance with the formulas described in R5threugh-Rfexhibis B1 B2 andexhibitA3. B-2-4 Operating Reserve Calculation 2.4.1 An EntithsEntity's Spinning Reserve shall be calculated at any given instant as the difference between the sum of the net capability of all generating units on line in the respective entity and the integrated Systems Demand of the system involved and other sources (for example,SILOS and BESS)or declared restrictions on spinning reserve (for example,Bradley Lake or tie line restrictions)as accepted by the 44GRegional Reliability Organization. 2.4.2 An Entity's Spinning Reserve may be satisfied by an automatically controlled load shedding program.The bad shedding program shall assure that controlled load can be dropped to meet the requirement of Spinning Reserve in such a manner as to maintain system stability and not cause degradation or cascading effects inthe Railbelt system. 2.4.3 The t4iGRegional Reliabilty Organization may establish procedures to assure that the Operating Reserve of an entity _is available on the Railbelt System _at _all times.Whenever an entity is unable to meet ts Operating Reserve Obligation,the entity will,within two hours,advise its Balancing Authority and make arrangements to restore ts Operating Reserve Obligation. 2.4.4 Prudent Utility Practices shall be followed in distributing Operating Reserve,taking into account effective utilization of capacity inan emergency,time required to be effective, transmission limitations and local area requirements.Avatobie Tansier Capability ATC)reserves between areas Geographical constraints and remedies are defined iin Exhibit A3. 2.4.5 Subject to R5.32.4.4 above,an Entiy may arrange for one or more other entities to supply part of,or its entire,Operating Reserve requirement. 2.4.6 _R5.6-By mutual agreement between the parties,an Entity which has contracted or leased al]of the Interconnected Value of a Generating Asset or Share ofa Generating Asset (energy,capacity,reactive-output dispatch-ability etc.)to another Railbelt Entity,such that this particular asset appears for all intents and purposes as Generating Asset of the Lessee's (contractee's)fleet,may have that asset counted among the Lessee's generating units and the Lessee may include Page 4o0f 56 -4 RROCONTINGENCY RESERVESPOLICY v001 R5.7- this unit as any other in the Lessee's fleet for purposes of calculation operating reserve allocation. An example of this is the Bradley Lake Project.AEA and at various times other project participants have contracted to have the Interconnected Value of this Generating Asset or their respective Shares of this Generating Asset assigned to one another in different forms.In each case the assignor has been relieved of the assigned project share (as the assignor's potential LSGC)and that share has been assigned to the assignee's fleet. 2.4.7__In an emergency,any Generator Owner,upon request by its Balancing Authority,shall supply to such Balancing Authority part or all of its Operating Reserve up to the full amount of its Available Accredited Capacity.An Entity experiencing an emergency is not required to maintain its Operating Reserve Obligation.There shall be no obligation of an Entity to supply Operating Reserve if the requesting entity isnot making full use of its own Available Accredited Capacity. R6--Responsibility for Regulating Reserve C R6_C-3.1:,Regulating Reserve- each 3.1.1 Each Balancing Authority (BA)shall provide,or contract for,Regulating Reserve as required by Section R6C-3.2 equal to;or greater than;the Regulating Reserve Obligation of the party.Regulating Reserve may not overlap reserves dedicated for Spinning Reserve.Regulating Reserve (both up and down)is required to compensate for uncertainty in forecasting and is established during the unit commitment planning process,and as such the BA may then utilize its reserve as required during the course of the day.fa BA exhausts its Regulating Reserve,it is required to procure or commit additional reserves immediately._Available-Fransfer-Capability (A TG}fortaterconnesting oOmponan ad 2 nor On ba? RE6C-3.2-Regulating Reserve Obligation-the 3.2.1__The Regulating Reserve Obligation for each Balancing Authority shall intially be set by the Intertie Management GommitteeRegional Reliabilty Organization. 3.2.2 R6.3-On an annual basis,after the year end CPS statistics are compiled,the iMGRegional Reliability Organization will modify each Balancing Authority's Regulating Reserve by increasing/decreasing its current Regulating Reserve by the %deviation in ts CPS1.The Regulating Reserve Obligations so calculated will be rounded up to the nearest integer MW. 3.2.3.R6-4.-The-IMCThe Regional_Reliability Organization reserves the right to Page 5of 56 RROCONTINGENCY RESERVESPOLICY v001 increase/decrease a BA's Regulating Reserve or require other measures at any time due to changes inthe system or repeat infractions._SpinBalancingAccountrecordswill ;intained as described in ExhibitA2 Page 6of 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit BI:Spinning Reserve Components R44-Spinning Reserve Obligation will be allocated to an Entity based on a combination of its Monthly Peak Hour Load (MPHL)and the Entities'Largest Single Generating Contingency (including any combination of units with a single point of interconnection forming a single contingency as further discussed in R#6-2.1.3.RAS applications which have been field demonstrated to successfully mitigate the LSGC and have been approved by the MGRRO may be applied to reduce the magnitude of the LSGC. REZ Spinning Reserve Largest Contingency Ratio (SRLCR):This component shail be calculated as the ratio of an individual Entities'Largest Single Generating Contingency (LSGC)as compared to the sum of the LSGC's of all the Railbelt Entities. R7Z.3-The Largest Single Generating Contingency will be based on the actual capacity of those unit(s)subject to the single contingency (regardless of RAS applications). _An example of a Generating Contingency is a combined cycle unit;the loss of the combustion turbine will precipitate the loss of both the CT as well as the waste heat unit. R7.4.-/f entities share a unit,an entities Share of such a unit could qualify as their LSGC if they have no unit(s)that are larger. R#-5-Monthly Peak Hour Load Ratio (MPHLR):This component shall be calculated at the ratio of an individual Entities'MPHL as compared to the sum of the MPHL's of all the Railbelt Entities.The MPHL of an Entity shall be defined as the Monthly Peak Hourly Load from the month 1 year earlier.Adjustments for permanent loss,or expected increases due to large industrial bads may be made f agreed to by the #4G-RRO.Economy sales are not counted as loads,but non-firm/interruptible loads are. Page 7of 56 RROCONTINGENCY RESERVES POLICY v004 Exhibit B2:Spinning Reserve Obligation4$RO}-ef each-Gbligated-Entity shall_be calculated Spinning Reserve Obligation for an Entity will be calculated summingthe weighted Spinning Reserve Components of each entity,and multiplyingthis by the System Reserve Basis as follows: SROe=50%{LSGCe}/{di (LSGCi)}*[SRB]+50%{MPHLe}/{i (MPHLi)}*[SRB]+MUDe €=a particular Entity i=All Interconnected Entities MUDe=the difference between the R4+72.1.3 max unit limit and an entities largest unit if greater than the R4A72.1.3 cap. Page 8of 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit B3:Spinning Reserve Criteria Page 9of 56 Page 100f 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit A1 -Methodology for a varying Largest Single Generating Contingency. For the Largest Single Generating Contingency (LSGC)for the Railbelt System 1)Each Entity will electronically share their hourly expected temperature compensated largest unit's output forecast during the day-ahead scheduling process.This may not be the same unit for each hour. 2)At this time,each utility will also share data on any forecasted excess spin that the Entity may wish to sell. 3)The next day and to the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was underestimated,the Entity which provided that forecast is obligated to make up the deficit spin in real time in order to keep the system protected.This includes forecasted unit startups. 4)To the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was overestimated,the difference in spin obligation will be pro rata credited to the remaining Entities in their Spin Balancing Account (SBA).This includes forecasted unit shutdowns. For the Largest Single Generating Contingency (LSGC)for an Entity 1)To the extent that the forecasted LSGC for an Entity's real time output was underestimated,the Entity which provided that forecast is obligated to credit the remaining Entities'SBA with the difference in spin in which they over carried due to the inaccurate forecast. 2)To the extent that the forecasted LSGC for an Entity's real time output was overestimated,no adjustments to the SBA will be made. Page 110f56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit A2 -Spin Balancing Account A Spin Balancing Account (SBA)will be created and kept by each Balancing Authority (BA)showing Date, Hour,To,From,and Quantity. Quantities must exceed a dead band to be recorded.Quantities 2 MW or larger qualify to be recorded. The entries will primarily reflect errors in forecasting and the consequential harm (in terms of amount of spin carried)caused to the other Entities due to these errors. Entities will net out their spin obligations with others in chronological order (oldest first}but at times may need to redeem their spin via scheduling from the utility owing them spin,at no cost for the spin, and at such time the owing utility has spin excess of its needs.The owing utility has no obligation to start additional generation to provide such spin. Each quarter,a BA will be selected as being the "master”to which the other entities will compare their own records.The "master”role will be rotated. Page 120f 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit A3 -Geographical Spin Methodology for the handling specific issues resultant from Railbelt Geography A:Kenai A single transmission line connects the generation on the Kenai with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Kenai Transmission Line; Not all spin originating on the Kenai can leave the Kenai; If spin can't leave the Kenai,the utilities north of the Kenai will need to make it up in order to satisfactorily protect the system; If spin can't leave the Kenai,it is inefficient to require an Entity to carry spin that can't be used; The Kenai isn't always constrained every hour; Spin originating on the Kenai can leave the Kenai; Entities on the Kenai should be required to carry their share of spin; To address this issue will require real time monitoring of the flows between the Kenai and the Anchorage Bowl.CEA has the live data which can be distributed via ICCP or equivalent. HEA/AEEC will be permitted to reduce their spin obligation (and consequently the other Entities will need to pro rata increase their spin obligation)during periods of constraint (and near constraint as appropriate).How much would need to be broadcast to all the utilities via CEA. During periods of constraint and during incidents requiring spin,both CEA and HEA/AEEC will need to monitor the Kenai Transmission Line and curtail the conversion of spin to MW if the emergency limit of the line is expected to be exceeded or is exceeded. CEA's Cooper Lake Plant may be providing spin for CEA which needs to be included in the constrained Kenai calculations.CEA may have certain rights as spelled out in the Bradley Contracts which must be upheld and are of a higher priority than these rules.HEA/AEEC has some amount of Bradley Lake Spin which generally can be expected to leave the Kenai. There may be times where the largest loss contingency in the system is the loss of the Kenai line itself.By definition,HEA/AEEC would not be able to contribute useful spin to such an incident. HEA/AEEC should be permitted to reduce their spin obligation (and consequently the other utilities will need to pro rata increase their spin obligation)so as to only cover the next largest Single Generating Unit Contingency subject to other restrictions of the Kenai Transmission line discussed above. Page 130f 56 RROCONTINGENCY RESERVESPOLICY v001 When the Kenai is islanded,the utilities north of the Kenai shall not be permitted to count their stranded Kenai spin towards their spin obligations. B:Interior A single transmission line connects the generation in the Interior with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Alaska Intertie Transmission Line; Not all spin originating in South Central can leave South Central; If the System LSGC is in the interior,South Central Entities share in providing spinning reserve to cover this unit; If spin can't leave the South Central,it is inefficient to require an Entity to carry spin that can't be used; South Central Entities should not count an Interior LSGC as the Systems'largest- unit during periods when the Alaska Intertie is constrained or near constrained as appropriate. The Alaska Intertie isn't always constrained every hour; Spin originating on the South Central can leave South Central; Entities in South Central should be required to carry their share of spin for an Interior System LSGC; To address this issue will require real time monitoring of the flows between the Interior and the Anchorage Bowl.AMLP has live data which can be distributed via ICCP or equivalent.South Central Entities will be permitted to reduce their spin obligation during periods of constraint (and near constraint as appropriate)to cover the next largest South Central based contingency. Page 140f 56 Intertie Management Committee (IMC)Subcommittee Members Committee Representative Email Address Alternate Alternate email address Budget Subcommittee: Kirk Warren -AEA (Chair)kwarren@aidea.org Gene Therriault gtherriault@aidea.org Jeff Warner -ML&P warnerja@muni.org Ken Langford langfordkw@muni.org Matt Reisterer-MEA mattreisterer@mea.coop Deanna Hracha Deanna.hracha@mea.coop Cory Borgeson -GVEA cborgeson@gvea.com Ron Woolf rewoolf@gvea.com Jody Wolfe -CEA Sherri McKay-Highers sherri_mckay-highers@chugachelectric.comjody_wolfe@chugachelectric.com Jeff Wamer -ML&P (Chair)wamerja@muni.org .Ken Langford langfordkw@muni.org ,. Hank Gocke -MEA hank.gocke@mea.coop Eddie Taunton Eddie.taunton@mea.coopDispatchandSystemOperationsAllenGray-GVEA ajgray@gvea.com Mike Wright mjwright@gvea.comSubcommittee:John Johnson -CEA _john_johnson@chugachelectric.com Burke Wick burke_wick@chugachelectric.com Bob Day -HEA (Invitee).bday@homerelectric.com Aung Thuya -ML&P thuyaac@muni.org Al Mitchell mitchellaj@muniorgEngineering,Relay and Reliability Jim Brooks -MEA jim.brooks@mea.coop Robert Wilson Robert.wilson@mea.coop Subcommittee:Nathan Minnema -GVEA (Chair)|_njminnema@gvea.com Dan Bishop dbishop@gvea.com Adam Vogel -CEA adam_vogel@chugachelectric.com Luke Sliman luke_sliman@chugachelectric.com Ken Langford -ML&P (Chair)|langfordkw@muni.org Kevin Mitchell mitchellkl@muni.org Bruno Urcuyo -MEA bruno.urcuyo@mea.coop Gary Peers Gary.peers@mea.coop Machine Ratings Subcommittee:Paul Morgan -GVEA pcemorgan@gvea.com Colton Nyland cbnyland@gvea.com Dee Fultz -CEA dee_fultz@chugachelectric.com Aaron Love aaron _love@chugachelectric.com Bob Day -HEA (Invitee)bday@homerelectric.com Jeff Warner -ML&P (Chair)warnerja@muni.org Ken Langford langfordkw@muni.org Kirk Warren -AEA kwarren@aidea.org Gene Therriault gtherriault@aidea.org Operating Committee Gary Kuhn -MEA gary.kuhn@mea.coop Eddie Taunton Eddie.taunton@mea.coop Allen Gray -GVEA ajgray@pvea.com Dan Bishop drbishop@gvea.com Burke Wick -CEA burke_wick@chugachelectric.com Paul Risse Paul_Risse@chugachelectric.com Jeff Warner -ML&P (Chair)warnerja@muni.org Ken Langford langfordkw@muni.org Operations,Maintenance and Scheduling Jim Brooks -MEA jim.brooks@mea.coop Eddie Taunton Eddie.taunton@mea.coopSubcommittee:Allen Gray -GVEA ajgray@gvea.com Rich Piech rpiech@gvea.comBillBernier-CEA bill bernier@chugachelectric.com Burke Wick burke_wick@chugachelectric.com 1 of2 9/1/2015 Intertie Management Committee (IMC)Subcommittee Members Committee I Representative |Email Address Alternate Alternate email address Russ Lyday -ML&P (Chair)lydayrw@muni.org Mary Batten battenmi@muni.org SCADA and Telecommunications Keith Palchikoff -GVEA kepalchikoff@gvea.com Allen Sparks ARSparks@qvea.com Subcommittee:DI Carrington -MEA dj carrington@mea.coop Mike Humphrey Mike.humphrey@mea.coop_ Kirk Warren -AEA kwarren@aidea.org Gene Therriault gtherriault@aidea.org Paul Johnson -CEA paul_johnson@chugachelectric.com Bill Murray bill_murray@chugachelectric.com Mark Johnson -CEA (Chair)mark_johnson@chugachelectric.com Jeff Warner warmerja@muni.org Lou Agi-ML&P agile@muni.org Bruno Urcuyo bruno.urcuyo@mea.coop ..Gary Kuhn -MEA gary.kuhn@mea.coop Lance Roberts \jroberts@gvea.comStandardsComplianceSubcommitteeAllenGray-GVEA aipray@gvea.com Burke Wick burke wick@chugachelectric.com Dee Fultz -CEA dee _fultz@chugachelectric.com Kirk Gibson Kirk@mcd-law.com Jeff Warner -ML&P warnerja@muni.org Ken Langford langfordkw@muni.org Bruno Urcuyo -MEA bruno.urcuyo@mea.coop Gary Kuhn gary.kuhn@mea.coop Standards Committee Allen Gray -GVEA ajgray@pvea.com Dan Bishop drbishop@gvea.com Kirk Warren -AEA kwarren@aidea.org Gene Therriault gtherriault@aidea.org Brian Hickey -CEA brian_hickey@chugachelectric.com Paul Risse paul_risse@chugachelectric.com Aung Thuya -ML&P (Chair)thuyaac@muni.org Al Mitchell mitchellaj@muni.org Bruno Urcuyo -MEA bruno.urcuyo@mea.coop Gary Kuhn gary.kuhn@mea.coop System Studies Subcommittee:Keith Palchikoff -GVEA kepatchikoff@gvea.com Adam Saunders AJSaunders@qvea.com Russ Thornton -CEA Russ_Thornton@chugachelectric.com Adam Vogel adam_vogel@chugachelectric.com Jim Cross -HEA (Invitee)jcross@homerelectric.com Anna Henderson-ML&P (Chair)|hendersonac@muni.org Lou Agi +Jagile@muni.org Tariffs and Regulatory Affairs C itt David Pease -MEA david pease@mea.coop Matt Reisterer matt.reisterer@mea.coopareilsandregulatoryAlvairs\ommuitee Paula Ashbridge -GVEA pdashbridge@gvea.com Allen Gray ajgray@pvea.com Mark Johnson -CEA mark_johnson@chugachelectric.com Arthur Miller arthur_miller@chugachelectric.com 2 of2 9/1/2015 ALASKA INTERTIE MANAGEMENT COMMITTEE AGENDA Tuesday,Sept.1,2015 9:00 a.m.-11:00 am Alaska Energy Authority,Board Room 813 W.Northern Lights Boulevard,Anchorage,Alaska 1.CALL TO ORDER 2.ROLL CALL FOR COMMITTEE MEMBERS 3.PUBLIC ROLL CALL 4.AGENDA APPROVAL 5.PUBLIC COMMENTS 6.APPROVAL OF PRIOR MINUTES -June 23,2015 7.OLD BUSINESS A.SPIN and RESERVE NEGOTATIONS -UPDATE (IOC) B.SVC WARRANTY POLICY -UPDATE (AEA) 8.NEW BUSINESS 9,REPORTS A.OPERATORS REPORT -ML&P/GVEA 5 Camone c2po0rsB.INTERTIE OPERATING COMMITTEE REPORT /'Jor Twtune. 10.COMMITTEE ASSIGNMENTS 11.NEXT MEETING DATE 12.ADJOURNMENT To participate via teleconference,dial 1-888-585-9008 and use conference room code 467 050 126 ALASKA INTERTIE MANAGEMENT COMMITTEE AGENDA Tuesday,Sept.1,2015 9:00 a.m.-11:00 am Alaska Energy Authority,Board Room 813 W.Northern Lights Boulevard,Anchorage,Alaska 1.CALL TO ORDER 2.ROLL CALL FOR COMMITTEE MEMBERS 3.PUBLIC ROLL CALL 4.AGENDA APPROVAL 5.PUBLIC COMMENTS 6.APPROVAL OF PRIOR MINUTES -June 23,2015 7.OLD BUSINESS A.SPIN and RESERVE NEGOTATIONS -UPDATE (IOC) B.SVC WARRANTY POLICY -UPDATE (AEA) 8.NEW BUSINESS 9.REPORTS A.OPERATORS REPORT --ML&P/GVEA B.INTERTIE OPERATING COMMITTEE REPORT 10.COMMITTEE ASSIGNMENTS 11.NEXT MEETING DATE 12,ADJOURNMENT To participate via teleconference,dial 1-888-585-9008 and use conference room code 467 050 126 ALASKA INTERTIE MANAGEMENT COMMITTEE AGENDA Tuesday,Sept.1,2015 9:00 a.m.-11:00 am Alaska Energy Authority,Board Room 813 W.Northern Lights Boulevard,Anchorage,Alaska 1.CALL TO ORDER 2.ROLL CALL FOR COMMITTEE MEMBERS 3.PUBLIC ROLL CALL 4.AGENDA APPROVAL 5.PUBLIC COMMENTS 6.APPROVAL OF PRIOR MINUTES --June 23,2015 7.OLD BUSINESS A.SPIN and RESERVE NEGOTATIONS -UPDATE (IOC) B.SVC WARRANTY POLICY -UPDATE (AEA) 8.NEW BUSINESS 9.REPORTS A.OPERATORS REPORT --ML&P/GVEA B.INTERTIE OPERATING COMMITTEE REPORT 10.COMMITTEE ASSIGNMENTS 11.NEXT MEETING DATE 12,ADJOURNMENT To participate via teleconference,dial 1-888-585-9008 and use conference room code 467 050 126 *sarw\PeeWISXsys varNVoo¢<i8¥ ma) S&Leen) ATTENDANCE -IMC Sept 1,2015,9 am COMMITTEE MEMBERS ALTERNATE - Brian Hickey -'Burke Wick Jeff Warner :Mark Johnston _"Gene Therriault,Secretary/Treasurer Sara Fisher-Goad |4 Cory Borgeson |Allen Gray Phronr -Evan "Joe”Griffith,Chairman |Gary Kuhn ||| || Public Members | . COUNSEL | ;Bernie Smith |-|Kirk Gibson,McDowell Rackner & |Bob Day -HEA |Gibson PC ||_Brian Bjorkquist,Dept.of Law !i i !4 I \ AEA Staff Phong Jocelyn Garner Hen Ci ole Teri Webster Kirk Warren Dh \lon "LP-ZA nV mas eye Av\\2.Dave Giese |ANCTEL ened Th RRO Contingency Reserves Policy V001 CONTINGENCY RESERVES POLICY Reserve Capacity Planning Criteria A-1.1 1.1.1 1.1.2 1.1.3 Each Load Serving Entity is expected to maintain responsibility to provide capacity for ts own firm load.As part of such responsibility,the Load Serving Entity shall maintain or otherwise provide for annually,Accredited Capacity,in an amount equal to or greater than its maximum System Demand for such year pius the Load Serving Entity's Reserve Capacity Obligation,as setforth in Subsection A-1.1.2. The Reserve Capacity Obligation of a Load Serving Entity,for any year,shall be equal to thirty (30)percent of the projected Annual System Demand for that year for that Load Serving Entity.The Reserve Capacity Obligation of the Load Serving Entity may be adjusted from time to time by the Regional Reliability Organization. The Regional Reliability Organization may determine the annual Accredited Capacity for each Load Serving Entity. Responsibility for Operating Reserve B-2.1 Operating Reserve 2.1.1 Each Load Serving Entity and/or Generation Owner shall provide,or contract for,Spinning Reserve and Non-Spinning Reserve as required by Section B-22 equal to or greater than the Operating Reserve Obligation of the entity.As soon as practicable,but not to exceed four hours,after the occurrence of an incident which uses Operating Reserves, each entity shall restore its Operating Reserve Obligation. Operating Reserves,Operating Reserve Obligation,System Reserve Basis and allocation calculations may be modified or changed by the Regional Reliability Organization. The System Reserve Basis (SRB)is equal to the Largest Generating Unit Contingency of the System as defined in Exhibit A1 or other such value such as loss of a transmission line,as determined by engineering studies and approved by the RRO. Single points of interconnection,such as,but not limited to,buses,collector feeders,step- up transformers,shall be evaluated in terms of asset class.Failure rates such that the asset class is involved in a failure at a rate of once per year will validate it as a single point of interconnection as discussed above.However,subject to the reasoning above,the Regional Reliability Organization may exercise judgment in such matters. RROCONTINGENCY RESERVES POLICY v001 B-22 2.2.1 An entity adding a unit whose LSGC ks greater than a 20 MW will accrue the obligation above 20 MW on a one for one basis in addition to its otherwise calculated spin obligation.This cap is subject to change by the RRO. Total Operating Reserve Obligation The Total Operating Reserve Obligation at any time shall be an amount equal to 60 percent of the System Reserve Basis of the Railbelt Electric Grid 2.2.1.1 The Spinning Reserve portion of the Total Operating Reserve Obligation shall not be less than an amount equivalent to 100 percent of the System Reserve Basis. 2.2.1.2 The balance of the Total Operating Reserve Obligation shall be maintained with 2.2.2 2.2.3 B-23 Non-Spinning Reserve. Generating unit capability for Operating Reserves shall be determined by the following criteria: a.k shall not be less than the load on the machine at any particular time nor greater than (b)below. b.kt shall not exceed that maximum amount of load (MW)that the unit is capable of continuously supplying for a two-hour period,or quickly,through action of automatic governor contros. The criteria specified in this section may be modified or changed by the Regional Reliability Organization. Allocation of Operating Reserve Obligations 2.3.1 The Operating Reserve Obligation of an Entity shall be that percentage of the Total B-2-4 2.4.1 2.4.2 Operating Reserve Obligation determined by the Regional Reliability Organization in accordance with the formulas described in exhibits B1,B2 and exhibit A3. Operating Reserve Calculation An Entity's Spinning Reserve shall be calculated at any given instant as the difference between the sum of the net capability of all generating units on line in the respective entity and the integrated Systems Demand of the system involved and other sources (for example,SILOS and BESS)or declared restrictions on spinning reserve (for example, Bradley Lake or tie line restrictions)as accepted by the Regional Reliability Organization. An Entity''s Spinning Reserve may be satisfied by an automatically controlled bad shedding program.The load shedding program shall assure that controlled load can be dropped to meet the requirement of Spinning Reserve in such a manner as to Page 2o0f 56 RROCONTINGENCY RESERVES POLICY v001 2.4.3 2.4.4 2.4.5 2.4.6 2.4.7 maintain system stability and not cause degradation or cascading effects inthe Railbelt system. The Regional Reliabilty Organization may establish procedures to assure that the Operating Reserve of an entity is available on the Railbelt System at all times. Whenever an entity 8 unable to meet ts Operating Reserve Obligation,the entity will, within two hours,advise its Balancing Authority and make arrangements to restore is Operating Reserve Obligation. Prudent Utility Practices shall be followed in distributing Operating Reserve,taking into account effective utilization of capacity in an emergency,time required to be effective, transmission limitations and local area requirements.Geographical constraints and remedies are defined in Exhibit A3. Subject to 2.4.4 above,an Entity may arrange for one or more other entities to supply part of,or its entire,Operating Reserve requirement. By mutual agreement between the parties,an Entity which has contracted or leased all of the Interconnected Value of a Generating Asset or Share of a Generating Asset (energy,capacity,reactive-output dispatch-ability etc.)to another Railbelt Entity,such that this particular asset appears for all intents and purposes as Generating Asset of the Lessee's (contractee's)fleet,may have that asset counted among the Lessee's generating units and the Lessee may include this unit as any other in the Lessee's fleet for purposes of calculation operating reserve allocation. An example of this is the Bradley Lake Project.AEA and at various times other project participants have contracted to have the Interconnected Value of this Generating Asset or their respective Shares of this Generating Asset assigned to one another in different forms.In each case the assignor has been relieved of the assigned project share (as the assignor's potential LSGC)and that share has been assigned to the assignee's fleet. In an emergency,any Generator Owner,upon request by its Balancing Authority,shall supply to such Balancing Authority part or all of its Operating Reserve up to the full amount of its Available Accredited Capacity.An Entity experiencing an emergency is not required to maintain its Operating Reserve Obligation.There shall be no obligation of an Entity to supply Operating Reserve if the requesting entity isnot making full use of its own Available Accredited Capacity. Cc Responsibility for Regulating Reserve C-3.1 Regulating Reserve 3.1.1 Each Balancing Authorty (BA)shall provide,or contract for,Regulating Reserve as Page 3of 56 RROCONTINGENCY RESERVESPOLICY v001 C-3.2 3.2.1 3.2.2 3.2.3 required by Section C-3.2 equal to or greater than the Regulating Reserve Obligation of the party.Regulating Reserve may not overlap reserves dedicated for Spinning Reserve. Regulating Reserve (both up and down)is required to compensate for uncertainty in forecasting and is established during the unit commitment planning process,and as such the BA may then utilize its reserve as required during the course of the day.Fa BA exhausts its Regulating Reserve,it is required to procure or commit additional reserves immediately. Regulating Reserve Obligation The Regulating Reserve Obligation for each Balancing Authority shall intially be set by the Regional Reliabilty Organization. On an annual basis,after the year end CPS statistics are compiled,the Regional Reliability Organization will modify each Balancing Authority's Regulating Reserve by increasing/decreasing its current Regulating Reserve by the %deviation in its CPS1.The Regulating Reserve Obligations so calculated will be rounded up to the nearest integer MW. The Regional Reliability Organization reserves the right to increase/decrease a BA's Regulating Reserve or require other measures at any time due to changes in the system or repeat infractions.Spin Balancing Account records will be maintained as described in Exhibit A2. Page 4of 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit B1:Spinning Reserve Components Spinning Reserve Obligation will be allocated to an Entity based on a combination of its Monthly Peak Hour Load (MPHL)and the Entities'Largest Single Generating Contingency (including any combination of units with a single point of interconnection forming a single contingency as further discussed in 2.1.3.RAS applications which have been field demonstrated to successfully mitigate the LSGC and have been approved by the RRO may be applied to reduce the magnitude of the LSGC. Spinning Reserve Largest Contingency Ratio (SRLCR):This component shall be calculated as the ratio of an individual Entities'Largest Single Generating Contingency (LSGC)as compared to the sum of the LSGC's of all the Railbelt Entities. The Largest Single Generating Contingency will be based on the actual capacity of those unit(s)subject to the single contingency (regardless of RAS applications).An example of a Generating Contingency is a combined cycle unit;the loss of the combustion turbine will precipitate the loss of both the CT as well as the waste heat unit. If entities share a unit,an entities Share of such a unit could qualify as their LSGC if they have no unit(s) that are larger. Monthly Peak Hour Load Ratio (MPHLR):This component shall be calculated at the ratio of an individual Entities'MPHL as compared to the sum of the MPHL's of all the Railbelt Entities.Tne MPHL of an Entity shall be defined as the Monthly Peak Hourly Load from the month 1 year earlier.Adjustments for permanent loss,or expected increases due to large industrial bads may be made f agreed to by the RRO.Economy sales are not counted as loads,but non-firm/interruptible lbads are. Page 5of 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit B2:Spinning Reserve Obligation Spinning Reserve Obligation for an Entity will be calculated summingthe weighted Spinning Reserve Components of each entity,and multiplyingthis by the System Reserve Basis as follows: SROe=50%{LSGCe}/{Xi (LSGCi)}*[SRB]+50%{MPHLe}/{%i (MPHLi)}*[SRB]+MUDe e =a particular Entity i =All Interconnected Entities MUDe=the difference between the 2.1.3 max unit limit and an entities largest unit if greater than the 2.1.3 cap. Page 6of 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit B3:Spinning Reserve Criteria In order to be counted as a producer of Spinning Reserve,the net response regardless of methods used (generator,SILOS,BESS,duct firing,etc.)must be able to meet the following minimum performance based criteria: Initial response: 30 second response: 60secondresponse: 220 second response: movement within 2 seconds 50%usage ofits reported spin capability 75%usage of its reported spin capability 100%usage of its reported spin capability Page 7o0f 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit A1 -Methodology for a varying Largest Single Generating Contingency. For the Largest Single Generating Contingency (LSGC)for the Railbelt System 1)Each Entity will electronically share their hourly expected temperature compensated largest unit's output forecast during the day-ahead scheduling process.This may not be the same unit for each hour. 2)At this time,each utility will also share data on any forecasted excess spin that the Entity may wish to sell. 3)The next day and to the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was underestimated,the Entity which provided that forecast is obligated to make up the deficit spin in real time in order to keep the system protected.This includes forecasted unit startups. 4)To the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was overestimated,the difference in spin obligation will be pro rata credited to the remaining Entities in their Spin Balancing Account (SBA).This includes forecasted unit shutdowns. For the Largest Single Generating Contingency (LSGC)for an Entity 1)To the extent that the forecasted LSGC for an Entity's real time output was underestimated,the Entity which provided that forecast is obligated to credit the remaining Entities'SBA with the difference in spin in which they over carried due to the inaccurate forecast. 2)To the extent that the forecasted LSGC for an Entity's real time output was overestimated,no adjustments to the SBA will be made. Page 80f 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit A2 -Spin Balancing Account A Spin Balancing Account (SBA)will be created and kept by each Balancing Authority (BA)showing Date, Hour,To,From,and Quantity. Quantities must exceed a dead band to be recorded.Quantities 2 MW or larger qualify to be recorded. The entries will primarily reflect errors in forecasting and the consequential harm (in terms of amount of spin carried)caused to the other Entities due to these errors. Entities will net out their spin obligations with others in chronological order (oldest first)but at times may need to redeem their spin via scheduling from the utility owing them spin,at no cost for the spin, and at such time the owing utility has spin excess of its needs.The owing utility has no obligation to start additional generation to provide such spin. Each quarter,a BA will be selected as being the "master”to which the other entities will compare their own records.The "master”role will be rotated. Page 9of 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit A3 -Geographical Spin Methodology for the handling specific issues resultant from Railbelt Geography A:Kenai A single transmission line connects the generation on the Kenai with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Kenai Transmission Line; Not all spin originating on the Kenai can leave the Kenai; If spin can't leave the Kenai,the utilities north of the Kenai will need to make it up in order to satisfactorily protect the system; If spin can't leave the Kenai,it is inefficient to require an Entity to carry spin that can't be used; The Kenai isn't always constrained every hour, Spin originating on the Kenai can leave the Kenai; Entities on the Kenai should be required to carry their share of spin; To address this issue will require real time monitoring of the flows between the Kenai and the Anchorage Bowl.CEA has the live data which can be distributed via ICCP or equivalent. HEA/AEEC will be permitted to reduce their spin obligation (and consequently the other Entities will need to pro rata increase their spin obligation)during periods of constraint (and near constraint as appropriate).How much would need to be broadcast to all the utilities via CEA. During periods of constraint and during incidents requiring spin,both CEA and HEA/AEEC will need to monitor the Kenai Transmission Line and curtail the conversion of spin to MW if the emergency limit of the line is expected to be exceeded or is exceeded. CEA's Cooper Lake Plant may be providing spin for CEA which needs to be included in the constrained Kenai calculations.CEA may have certain rights as spelled out in the Bradley Contracts which must be upheld and are of a higher priority than these rules.HEA/AEEC has some amount of Bradley Lake Spin which generally can be expected to leave the Kenai. There may be times where the largest loss contingency in the system is the loss of the Kenai line itself.By definition,HEA/AEEC would not be able to contribute useful spin to such an incident. HEA/AEEC should be permitted to reduce their spin obligation (and consequently the other utilities will need to pro rata increase their spin obligation)so as to only cover the next largest Single Generating Unit Contingency subject to other restrictions of the Kenai Transmission line discussed above. Page 100f 56 RROCONTINGENCY RESERVESPOLICY v001 When the Kenai is islanded,the utilities north of the Kenai shall not be permitted to count their stranded Kenai spin towards their spin obligations. B:Interior A single transmission line connects the generation in the Interior with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Alaska Intertie Transmission Line; Not all spin originating in South Central can leave South Central; If the System LSGC is in the interior,South Central Entities share in providing spinning reserve to cover this unit; If spin can't leave the South Central,it is inefficient to require an Entity to carry spin that can't be used; South Central Entities should not count an Interior LSGC as the Systems'largest unit during periods when the Alaska Intertie is constrained or near constrained as appropriate. The Alaska Intertie isn't always constrained every hour; Spin originating on the South Central can leave South Central; Entities in South Central should be required to carry their share of spin for an Interior System LSGC; To address this issue will require real time monitoring of the flows between the Interior and the Anchorage Bowl.AMLP has live data which can be distributed via ICCP or equivalent.South Central Entities will be permitted to reduce their spin obligation during periods of constraint (and near constraint as appropriate)to cover the next largest South Central based contingency. Page 110f56 RRO VO vs RRO V1 CONTINGENCY RESERVES POLICY Reserve Capacity Planning Criteria A-1.1 1.1.1 1.1.2 1.1.3 Each Load Serving Entity is expected to maintain responsibility to provide capacity for ts own firm load.As part of such responsibility,the Load Serving Entity shall maintain or otherwise provide for annually,Accredited Capacity,in an amount equal to or greater than its maximum System Demand for such year plus the Load Serving Entity's Reserve Capacity Obligation,as set forth in Subsection A-1.1.2. The Reserve Capacity Obligation of a Load Serving Entity,for any year,shall be equal to thirty (30)percent of the projected Annual System Demand for that year for that Load Serving Entity.The Reserve Capacity Obligation of the Load Serving Entity may be adjusted from time to time by the Regional Reliability Organization. The Regional Reliability Organization may determine the annual Accredited Capacity for each Load Serving Entity. Responsibility for Operating Reserve B-2.1 2.1.1 Operating Reserve Each Load Serving Entity and/or Generation Owner_shall provide,or contract for,Spinning Reserve and Non-Spinning Reserve as required by Section B-22 equal to or greater than the Operating Reserve Obligation of the entity.As soon as practicable,but not to exceed four hours,after the occurrence of an incident which uses Operating Reserves, each entity shall restore its Operating Reserve Obligation. Operating Reserves,Operating Reserve Obligation,System Reserve Basis and allocation calculations may be modified or changed by the Regional Reliability Organization. The System Reserve Basis (SRB)is equal to the Largest Generating Unit Contingency of the System as defined in Exhibit A1_or other such value_such_as loss of a transmission line,as determined by engineering studies and approved by the RRO. RROCONTINGENCY RESERVES POLICY B-22 2.2.1 such as,but not limited to,buses,collector feeders,step-up transformers,shall be evaluated in terms of asset class.Failure rates such that the asset class is involved in a failure at_a rate of once per year will validate it as a single point of interconnection as discussed above.However,subject to the reasoning above,the Regional Reliability Organization may exercise judgment_in such matters. An entity adding a unit whose LGUGLSGC és greater than a 20 MW-SRB¢ap will accrue the obligation above 20 MW on a one for one basis in addition to its otherwise calculated spin obligation.This cap ls subject to change by the RRO. Total Operating Reserve Obligation The Total Operating Reserve Obligation at any time shall be an amount equal to 60 percent of the System Reserve Basis of the Railbelt Electric Grid 2.2.1.1 The Spinning Reserve portion of the Total Operating Reserve Obligation shall not be less than an amount equivalentto 100 percent eftheof the System Reserve Basis. 2.2.1.2 The balance of the Total Operating Reserve Obligation shall be maintained with Non-Spinning Reserve. 2.2.2 Generating unit capability for Operating Reserves shall be determined by the following criteria: a.kt shall not be less than the load on the machine at any particular time nor greater than (b)below. b.i shall not exceed that maximum amount of load (MW)that the unit is capable of continuously supplying for a two-hour period,or quickly,through action of automatic governor contros. Page 42o0f 56 RROCONTINGENCY RESERVESPOLICY 2.2.3.The criteria specified in this section may be modified or changed by the Regional Reliability Organization. B-23 Allocation of Operating ReservesReserve Obligations Page 430f 56 RROCONTINGENCY RESERVES POLICY 2.3.1 The Operating Reserve Obligation of aLead-Servingan Entity shall be that percentage of B-2-4 2.4.1 2.4.2 2.4.3 2.4.4 2.4.5 2.4.6 the Total Operating Reserve Obligation determined by the Regional Reliability Organization in accordance with the formulas described in exhibits BIB1,B2 and exhibit B3A3. Operating Reserve Calculation A-toad ServingAn Entity's Spinning Reserve shall be calculated at any given instant as the difference between the sum of the net capability of all generating units on line in the respective entity and the integrated Systems Demand of the system involved and other sources (for example,SILOS and BESS)or declared restrictions on spinning reserve (for example,Bradley Lake or tie line restrictions)as accepted by the Regional Reliability Organization. A-Lead-SeringAn Entiy's Spinning Reserve may be satisfied by an automatically controlled load shedding program.The lad shedding program shall assure that controlled load can be dropped to meet the requirement of Spinning Reserve in such a manner as to maintain system stability and not cause degradation or cascading effects inthe Railbelt system. The Regional Reliabilty Organization may establish procedures to assure that the Operating Reserve -of-an entity is available on the Railbelt System at all times. Whenever an entity is unable to meet ts Operating Reserve Obligation,that the entity will,within two hours,advise its Balancing Authority and make arrangements to restore ts Operating Reserve Obligation. Prudent Utility Practices shall be followed in distributing Operating Reserve,taking into account effective utilization of capacity in an emergency,time required to be effective, transmission limitations and local area requirements.__Geographical!l_constraints and remedies are defined in Exhibit A3. A-LoeadSeringSubject to 2.4.4 above,an Entity may arrange for one or more other entities to supply part of,or its entire,Operating Reserve requirement-. By_mutual agreement between the parties,an Entity which has contracted or leased _a//l of the Interconnected Value _of_a Generating Asset or Share ofa Generating Asset (energy,capacity,reactive-output dispatch-ability etc.)to another Railbelt Entity,such that this particular_asset_appears for all intents and purposes _as Generating Asset _of the Lessee's (contractee's)fleet,may have that asset counted among the Lessee's generating units and the Lessee may include this unit as any other in the Lessee's fleet for purposes of calculation operating reserve allocation. Page 44o0f 56 RROCONTINGENCY RESERVES POLICY An example of this is the Bradley Lake Project.AEA and at various times other project participants have contracted to have the Interconnected Value of this Generating Asset_or their respective Shares of this Generating Asset_assigned to one another in different forms.In each case the assignor has been_relieved_of the assigned project_share (as the assignor's potential LSGC)and that share has been_assigned to the assignee's fleet. 2-4.62.4.7 In an emergency,any Generator Owner,upon request by its Balancing Authority,shall supply to such Balancing Authority part or ail of its Operating Reserve up to the full amount of its Available Accredited Capacity.ALead-SeringAn Entity experiencing an emergency is not required to maintain its Operating Reserve Obligation.There shall be no obligation of an ertityEntity to supply Operating Reserve if the requesting entity isnot makingfulmaking full use of its own Available Accredited Capacity. Page 450f 56 RROCONTINGENCY RESERVESPOLICY Cc Responsibility for Regulating Reserve C-3.1 Regulating Reserve 3.1.1 Each Balancing AuthertyAuthorty (BA})shall provide,or contract for,Regulating C-3.2 3.2.1 3.2.2 3.2.3 Reserve as required by Section C-3.2 equal to or greater than the Regulating Reserve Obligation of the party.Regulating Reserve may not overlap reserves dedicated for Spinning Reserve.Regulating Reserve (both up and down)is required to compensate for uncertainty in forecastiagforecasting and is established during the unit commitment planning process,and as suchthe BA may then utilize its reserve as required during the course of the day.f a BA exhausts its Regulating Reserve,it is required to procure or commit additional reserves immediately. Regulating Reserve Obligation The Regulating Reserve Obligation for each Balancing Authority shall initially be set by the Regional Reliabilty Organization. On an annual basis,after the year end CPS statistics are compiled,the Regional Reliability Organization will modify each Balancing Autherity'sAuthority's Regulating Reserve by increasing/decreasing its current Regulating Reserve by the %deviation in its GRSICPS1, The Regulating Reserve ebligationsOblications so calculated will be rounded up to the nearest integer MW. The Regional Reliability Organization reserves the right to increase/decrease a BA's Regulating Reserve or require other measures at any time due to changes in the system or repeat infractions._Spin Balancing Account records will be maintained as described in Exhibit A2. Page 46 of 56 RROCONTINGENCY RESERVES POLICY v001 Page 47of 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit BI:Spinning Reserve Components Spinning Reserve Obligation will be allocated to the-LeadSeningan Entity based on a combination of its Monthly Peak Hour Load (MPHL)and the Entities'Largest Single Generating Contingency (including any combination of units with a single point of interconnection forming a single contingency as further discussed in 2.1.3.RAS applications which have been field demonstrated to successfully mitigate the LSGC and have been approved by the RRO may be applied to reduce the magnitude of the LSGC. MonthlyPeakHourlead(MHPL Spinning Reserve Largest Contingency Ratio (SRLCR):This component shall be calculated as the ratio of an entity's MPHLindividual Entities'Largest Single Generating Contingency (LSGC)as compared to the ner-ceincidentPHtsum of the LSGC's of all the Railbelt-_ Entities. The Largest Single Generating Contingency will be based on the actual capacity of those unit(s)subject to the single contingency (reqardless of RAS applications).An example of a Generating Contingency is a combined cycle unit;the loss of the combustion turbine will precipitate the loss of both the CT as well as the waste heat unit. If entities share a unit,an entities Share of such a unit could qualify as their LSGC if they have no unit(s) that are larger. Monthly Peak Hour Load Ratio (MPHLR):This component shall be calculated at the ratio of an individual Entities'MPHL as compared to the sum of the MPHL's of all the Railbelt Entities.The MPHL of an entity isEntity shall be defined as the measuredMPHEseteaMonthly Peak Hourly Load from the-currernt month ene year earlier.Adjustments for permanent loss,_or expected increases due to large industrial loads may be made ff agreed to by the RRO.Economy sales are not counted as loads,but non-firm/interruptible lads are. SpinMPHLe-MPHLeHAMPHL Page 48 of 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit B2:Spinning Reserve Obligation Spinning Reserve Obligation for aLeadServingan Entity will be calculated summing the weighted Spinning Reserve Components of each entity,_and multiplyingthis by the System Reserve Basis as follows: __SROc=A*SpinMPHLe*=50%{LSGCeW{5i (LSGCi)}[SRB-*]+50%{MPHLeW/{5i (MPHLi)}*ISRB]+MUDe Where e =a particular Entity i=All Interconnected Entities ______MUDe-is=the difference between the 2.1.3 max unit detalimit and an entities largest unit if any}forthatentitya6describedin2-+-3-Where the weighting factors are:dreater than the 2.1.3 cap. Page 49 of 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit B3:Spinning Reserve Criteria In order to be counted as a producer of Spinning Reserve,the net response regardless of methods used (generator,SILOS,BESS,duct firing,etc.)must be able to meet the fellow-ngfollowng minimum performance based-criteria: Initial response-:movement within 2 seconds- 30 second response:50%usage ofits reported spin capability 60secondresponse:75%usage ofits reported spin_capability @O0secondresponse:100%usage ofits reported spin_capability Page 50 of 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit Al -Methodology for a varying Largest Single Generating Contingency. For the Largest Single Generating Contingency (LSGC)for the Railbelt System 1)Each Entity will electronically share their hourly expected temperature compensated largest unit's output forecast during the day-ahead scheduling process.This may not be the same unit for each hour. 2)At this time,each utility will also share data on any forecasted excess spin that the Entity may wish to sell. 3)The next day and to the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was underestimated,the Entity which provided that forecast is obligated to make up the deficit spin in real time in order to keep the system protected.This includes forecasted unit startups. 4)_To the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was overestimated,the difference in spin obligation will be pro rata credited to the remaining Entities in their Spin Balancing Account (SBA).This includes forecasted unit shutdowns. For the Largest Single Generating Contingency (LSGC)for an Entity 1)To the extent that the forecasted LSGC for an Entity's real time output was underestimated,the Entity which provided that forecast is obligated to credit the remaining Entities'SBA with the difference in spin in which they over carried due to the inaccurate forecast. 2)To the extent that the forecasted LSGC for an Entity's real time output was overestimated,no adjustments to the SBA will be made. Page 51 of 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit A2 -Spin Balancing Account A Spin Balancing Account (SBA)will be created and kept by each Balancing Authority (BA)showing Date, Hour,To,From,and Quantity. Quantities must exceed a dead band to be recorded.Quantities 2 MW or larger qualify to be recorded. The entries will primarily reflect errors in forecasting and the consequential harm {in terms of amount of spin carried)caused to the other Entities due to these errors. Entities will net out their spin obligations with others in chronological order (oldest first)but at times may need to redeem their spin via scheduling from the utility owing them spin,at no cost for the spin, and at such time the owing utility has spin excess of its needs.The owing utility has no obligation to start additional generation to provide such spin. Each quarter,a BA will be selected as being the "master”to which the other entities will compare their own records.The "master”role will be rotated.top)Page 520f5 RRO CONTINGENCY RESERVESPOLICY v001 Exhibit A3 -Geographical Spin Methodology for the handling specific issues resultant from Railbelt Geography A:Kenai A single transmission line connects the generation on the Kenai with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Kenai Transmission Line; Not all spin originating on the Kenai can leave the Kenai; If spin can't leave the Kenai,the utilities north of the Kenai will need to make it up in order to satisfactorily protect the system; If spin can't leave the Kenai,it is inefficient to require an Entity to carry spin that can't be used; The Kenai isn't always constrained every hour; Spin originating on the Kenai can leave the Kenai; Entities on the Kenai should be required to carry their share of spin; To address this issue will require real time monitoring of the flows between the Kenai and the Anchorage Bowl.CEA has the live data which can be distributed via ICCP or equivalent. HEA/AEEC will be permitted to reduce their spin obligation (and consequently the other Entities will need to pro rata increase their spin obligation)during periods of constraint (and near constraint as appropriate}.How much would need to be broadcast to all the utilities via CEA. During periods of constraint and during incidents requiring spin,both CEA and HEA/AEEC will need to monitor the Kenai Transmission Line and curtail the conversion of spin to MW if the emergency limit of the line is expected to be exceeded or is exceeded. CEA's Cooper Lake Plant may be providing spin for CEA which needs to be included in the constrained Kenai calculations.CEA may have certain rights as spelled out in the Bradley Contracts which must be upheld and are of a higher priority than these rules.HEA/AEEC has some amount of Bradley Lake Spin which generally can be expected to leave the Kenai. There may be times where the largest loss contingency in the system is the loss of the Kenai line itself.By definition,HEA/AEEC would not be able to contribute useful spin to such an incident. HEA/AEEC should be permitted to reduce their spin obligation (and consequently the other utilities will need to pro rata increase their spin obligation)so as to only cover the next largest Single Generating Unit Contingency subject to other restrictions of the Kenai Transmission line discussed above. Page 530f 56 RROCONTINGENCY RESERVESPOLICY v001 When the Kenai is islanded,the utilities north of the Kenai shall not be permitted to count their stranded Kenai spin towards their spin obligations. B:Interior A single transmission line connects the generation in the Interior with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Alaska Intertie Transmission Line; Not all spin originatingin South Central can leave South Central: If the System LSGC is in the interior,South Central Entities share in providing spinning reserve to cover this unit; If spin can't leave the South Central,it is inefficient to require an Entity to carry spin that can't be used: South Central Entities should not count an Interior LSGC as the Systems'largest unit during periods when the Alaska Intertie is constrained or near constrained as appropriate. The Alaska Intertie isn't always constrained every hour; Spin originating on the South Central can leave South Central; Entities in South Central should be required to carry their share of spin for an interior System LSGC; To address this issue will require real time monitoring of the flows between the Interior and the Anchorage Bowl.AMLP has live data which can be distributed via ICCP or equivalent.South Central Entities will be permitted to reduce their spin obligation during periods of constraint (and near constraint as appropriate)to cover the next largest South Central based contingency.-HPage 540f 56 AKRES 001-1 Introduction 1.Title:Reserve Obligation and Allocation 2.Number:AKRES-001-1 3.Purpose: This standard describes Reserve Obligations for all Entities interconnected to the Railbelt Grid. 4.Applicability: 4.1.Balancing Authorities 4.2.Load Serving Entities 4.3.Generation Owners (Generation Asset Owning Entities) 5.Effective Date:TBD Requirements RI.Reserve Capacity Requirement R2. RII.Each Load Serving Entity is expected to maintain responsibility to provide capacity for its own firm load.As part of such responsibility,the Load Serving Entity shall maintain or otherwise provide for annually,Accredited Capacity,in an amount equal to or greater than its maximum System Demand for such year plus the Load Serving Entity's Reserve Capacity Obligation,as set forth in Subsection R1.2. RI.2.The Reserve Capacity Obligation of a Load Serving Entity,for any year,shall be equal to thirty (30)percent of the projected Annual System Demand for that year for that Load Serving Entity.The Reserve Capacity Obligation ofthe Load Serving Entity may be adjusted from time to time by the Intertie Management Committee (IMC). R13.The IMC may determine the annual Accredited Capacity for each Load Serving Entity. Responsibility for Operating Reserve R2.1.Each Load Serving Entity and/or Generation Owner shall provide,or contract for, Spinning Reserve and Non-Spinning Reserve as required by Section R3 equal to or greater than the Operating Reserve Obligation of the entity.As soon as practicable,but not to exceed four hours,after the occurrence of an incident which uses Operating Reserves,each entity shall restore its Operating Reserve Obligation. R22.Operating Reserves,Operating Reserve Obligation,System Reserve Basis and allocation calculations may be modified or changed by the Intertie Management Committee. R2.3.The System Reserve Basis (SRB)is equal to the Largest Generating Unit Contingency of the System as defined in Exhibit Al or other such value such as loss of a transmission line,as determined by engineering studies and approved by the IMC. AKRES 001-1 R3.Total Operating Reserve Obligation R3.1.The Total Operating Reserve Obligation at any time shall be an amount equal to 150 percent of the System Reserve Basis of the Railbelt Electric Grid. R3.2.The Spinning Reserve portion of the Total Operating Reserve Obligation shall not be less than an amount equivalent to 100percent of the System Reserve Basis. R3.3.The balance of the Total Operating Reserve Obligation shall be maintained with Non-Spinning Reserve. R4.Generating Unit Capability- Generating unit capability for Operating Reserve shall be determined by the following criteria: R4.1.Itshall not be less than the load on the machine at any particular timenor greater than R42 below R4.2.It shall not exceed that maximum amount of load (MW)that the unit is capable of continuously supplying for a two-hour period,or quickly,through action of automatic governor controls. R4.3 In order to be counted as a producer of Spinning Reserve,the net response regardless of methods used (generator,SILOS,BESS,duct firing,etc.)must be able to meet the following minimum performance based criteria: Initial response:movement within 2 seconds 30 second response:50%usage ofits reported spin capability 60 second response:75%usage of its reported spin capability 120 second response:100%usage of its reported spin capability R4.4.The criteria specified in this section may be modified or changed by the Intertie Management Committee. R5.Allocation of Operating Reserve Obligations The Operating Reserve Obligation of an Entity shall be that percentage of the Total Operating Reserve Obligation determined by the IMC in accordance with the formulas described in RS through R7 R5.1.An Entity's Spinning Reserve shall be calculated at any given instant as the difference between the sum of the net capability of all generating units on line in the respective entity and the integrated Systems Demand of the system involved and other sources (for example,SILOS and BESS)or declared restrictions on spinning reserve (for example, Bradley Lake or tie line restrictions)as accepted by the IMC R5.2.An Entity's Spinning Reserve may be satisfied by an automatically controlled load shedding program.The load shedding program shall assure that controlled load can be dropped to meet the requirement of Spinning Reserve in such a manner as to maintain system stability and not cause degradation or cascading effects in the Railbelt system. R5.3.The IMC may establish procedures to assure that the Operating Reserve of an entity is available on the Railbelt System at all times.Whenever an entity is unable to meet its AKRES 001-1 Operating Reserve Obligation,the entity will,within two hours,advise its Balancing Authority and make arrangements to restore its Operating Reserve Obligation. RS5.4.Prudent Utility Practices shall be followed in distributing Operating Reserve,taking into account effective utilization of capacity in an emergency,time required to be effective, transmission limitations and local area requirements.Available Transfer Capability (ATC)shall include a component (Capacity Benefit Margin)recognizing the need to move reserves between areas.Geographical constraints and remedies are defined in Exhibit A3. R5.5.Subject to R5.3 above,an Entity may arrange for one or more other entities to supply part of,or its entire,Operating Reserve requirement. R5.6.By mutual agreement between the parties,an Entity which has contracted or leased all of the Interconnected Value of a Generating Asset or Share of a Generating Asset (energy,capacity, reactive-output dispatch-ability etc.)to another Railbelt Entity,such that this particular asset appears for all intents and purposes as Generating Asset of the Lessee's (contractee's)fleet, may have that asset counted among the Lessee's generating units and the Lessee may include this unit as any other in the Lessee's fleet for purposes of calculation operating reserve allocation. An example of this is the Bradley Lake Project.AEA and at various times other project participants have contracted to have the Interconnected Value of this Generating Asset or their respective Shares of this Generating Asset assigned to one another in different forms.In each case the assignor has been relieved of the assigned project share (as the assignor's potential LSGC)and that share has been assigned to the assignee's fleet. R5.7.In an emergency,any Generator Owner,upon request by its Balancing Authority,shall supply to such Balancing Authority part or all of its Operating Reserve up to the full amount of its Available Accredited Capacity.An Entity experiencing an emergency is not required to maintain its Operating Reserve Obligation.There shall be no obligation of an Entity to supply Operating Reserve if the requesting entity is not making full use of its own Available Accredited Capacity. R6.Responsibility for Regulating Reserve R6.1.Regulating Reserve-each Balancing Authority (BA)shall provide,or contract for,Regulating Reserve as required by Section R6.2 equal to,or greater than,the Regulating Reserve Obligation of the party.Regulating Reserve may not overlap reserves dedicated for Spinning Reserve.Regulating Reserve (both up and down)is required to compensate for uncertainty in forecasting and is established during the unit commitment planning process,and as such the BA may then utilize its reserve as required during the course of the day.If a BA exhausts its Regulating Reserve,it is required to procure or commit additional reserves immediately. Available Transfer Capability (ATC)for Interconnecting Transmission lines shall recognize a component included in Transmission Reliability Margin (TRM)to allow for the delivery of Regulating Reserve between areas. R6.2.Reguhting Reserve Obligation-the Regulating Reserve Obligation for each Balancing Authority shall initially be set by the Intertie Management Committee. R6.3.On an annual basis,after the year end CPS statistics are compiled.the IMC will modify each Balancing Authority's Regulating Reserve by increasing/decreasing its current Regulating R7. R6.4. AKRES 001-1 Reserve by the %deviation in its CPS1.The Regulating Reserve Obligations so calculated will be rounded up to the nearest integer MW. The IMC reserves the right to increase/decrease a BA's Regulating Reserve or require other measures at any time due to changes in the system or repeat infractions. Spinning Reserve Components R7.1. R7.2. R7.3. R7.4. R7.5. R7.6. Spinning Reserve Obligation will be allocated to an Entity based on a combination of its Monthly Peak Hour Load (MPHL)and the Entities'Largest Single Generating Contingency (including any combination of units with a single point of interconnection forming a single contingency as further discussed in R7.6.RAS applications which have been field demonstrated to successfully mitigate the LSGC and have been approved by the IMC may be applied to reduce the magnitude of the LSGC. Spinning Reserve Largest Contingency Ratio (SRLCR):This component shall be calculated as the ratio of an individual Entities'Largest Single Generating Contingency (LSGC)as compared to the sum of the LSGC's of all the Railbelt Entities. The Largest Single Generating Contingency will be based on the actual capacity of those unit(s)subject to the single contingency (regardless of RAS applications). An example of a Generating Contingency is a combined cycle unit:the loss of the combustion turbine will precipitate the loss of both the CT as well as the waste heat unit. Ifentities share a unit,an entities Share of such a unit could qualify as their LSGC if they have no unit(s)that are larger. Monthly Peak Hour Load Ratio (MPHLR):This component shall be calculated at the ratio of an individual Entities'MPHL as compared to the sum of the MPHL's of all the Railbelt Entities.The MPHL of an Entity shall be defined as the Monthly Peak Hourly Load from the month 1 year earlier.Adjustments for permanent loss,or expected increases due to large industrial loads may be made if agreed to by the IMC.Economy sales are not counted as loads,but non-firm/interruptible loads are. Single points of interconnection,such as,but not limited to,buses,collector feeders,step-up transformers,shall be evaluated in terms of asset class.Failure rates such that the asset class is involved in a failure at a rate of once per year will validate it as a single point of interconnection as discussed in R7.1.However,subject to the reasoning above,the IMC may exercise judgment in such matters. R7.7.An entity adding a unit greater than 120 MW will accrue the obligation above 120 MW on a one for one basis in addition to its otherwise calculated spin obligation.This cap is subject to change by the IMC. R7.8.The Spinning Reserve Obligation (SRO)of each Obligated Entity shall be calculated as follows: SRO.=50%{LSGC.Y {Xi(LSGC))}*[SRB]+50%{MPHL.Y {+i(MPHL))}*[SRB]+MUD, e=a particular Entity AKRES 001-1 i=All Interconnected Entities MUD the difference between the R7.7 max unit limit and an entities largest unit if greater than the R7.7 cap. C.Measures MI.Each Obligated Entity and Balancing Authority shall maintain: MI.1.Records of their Reserve Capacity at any point in time.These records will be updated as new Assets are added and other Assets are retired.These records will be available by for review by the Balancing Authority or Compliance Monitor with 1 business week written notice. MI.2.Hourly records of Operating Reserve and Regulating Reserve (scheduled and actual)will be maintained by all Obligated Entities'.These will be made available in real-time to the Balancing Authority for archival and storage. ML3.The Compliance Monitor will review the performance of each Balancing Authority and Obligated Entity at least annually.More frequent reviews shall be performed if spin obligation compliance warrants such reviews. MI.4.Spin Balancing Account records will be maintained as described in Exhibit A2. D.Compliance Monitoring 1. 2. Balancing Authorities IMC-Railbelt Regional Reliability Organization E.Non-Compliance Level 1. Version History Version Date Action Change Tracking AKRES 001-1 Exhibit Al -Methodology for a varying Largest Single Generating Contingency. For the Largest Single Generating Contingency (LSGC)for the Railbelt System 1)Each Entity will electronically share their hourly expected temperature compensated largest unit's output forecast during the day-ahead scheduling process.This may not be the same unit for each hour. 2)At this time,each utility will also share data on any forecasted excess spin that the Entity may wish to sell. 3)The next day and to the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was underestimated,the Entity which provided that forecast is obligated to make up the deficit spin in real time in order to keep the system protected.This includes forecasted unit startups. 4)To the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was overestimated,the difference in spin obligation will be pro rata credited to the remaining Entities in their Spin Balancing Account (SBA).This includes forecasted unit shutdowns. For the Largest Single Generating Contingency (LSGC)for an Entity 1)To the extent that the forecasted LSGC for an Entity's real time output was underestimated,the Entity which provided that forecast is obligated to credit the remaining Entities'SBA with the difference in spin in which they over carried due to the inaccurate forecast. 2)To the extent that the forecasted LSGC for an Entity's real time output was overestimated,no adjustments to the SBA will be made. AKRES 001-1 Exhibit A2 -Spin Balancing Account A Spin Balancing Account (SBA)will be created and kept by each Balancing Authority (BA)showing Date, Hour,To,From,and Quantity. Quantities must exceed a dead band to be recorded.Quantities 2 MW or larger qualify to be recorded. The entries will primarily reflect errors in forecasting and the consequential harm (in terms of amount of spin carried)caused to the other Entities due to these errors. Entities will net out their spin obligations with others in chronological order (oldest first)but at times may need to redeem their spin via scheduling from the utility owing them spin,at no cost for the spin,and at such time the owing utility has spin excess of its needs.The owing utility has no obligation to start additional generation to provide such spin. Each quarter,a BA will be selected as being the "master”to which the other entities will compare their own records.The "master”role will be rotated. AKRES 001-1 Exhibit A3 -Geographical Spin Methodology for the handling specific issues resultant from Railbelt Geography A:Kenai A single transmission line connects the generation on the Kenai with the rest of South Central Alaska. The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Kenai Transmission Line; Not all spin originating on the Kenai can leave the Kenai; If spin can't leave the Kenai,the utilities north of the Kenai will need to make it up in order to satisfactorily protect the system; If spin can't leave the Kenai,it is inefficient to require an Entity to carry spin that can't be used; The Kenai isn't always constrained every hour; Spin originating on the Kenai can leave the Kenai; Entities on the Kenai should be required to carry their share of spin; To address this issue will require real time monitoring of the flows between the Kenai and the Anchorage Bowl.CEA has the live data which can be distributed via ICCP or equivalent.HEA/AEEC will be permitted to reduce their spin obligation (and consequently the other Entities will need to pro rata increase their spin obligation)during periods of constraint (and near constraint as appropriate).How much would need to be broadcast to all the utilities via CEA. During periods of constraint and during incidents requiring spin,both CEA and HEA/AEEC will need to monitor the Kenai Transmission Line and curtail the conversion of spin to MW if the emergency limit of the line is expected to be exceeded or is exceeded. CEA's Cooper Lake Plant may be providing spin for CEA which needs to be included in the constrained Kenai calculations.CEA may have certain rights as spelled out in the Bradley Contracts which must be upheld and are of a higher priority than these rules.HEA/AEEC has some amount of Bradley Lake Spin which generally can be expected to leave the Kenai. There may be times where the largest loss contingency in the system is the loss of the Kenai line itself. By definition,HEA/AEEC would not be able to contribute useful spin to such an incident.HEA/AEEC should be permitted to reduce their spin obligation (and consequently the other utilities will need to pro rata increase their spin obligation)so as to only cover the next largest Single Generating Unit Contingency subject to other restrictions of the Kenai Transmission line discussed above. When the Kenai is islanded,the utilities north of the Kenai shall not be permitted to count their stranded Kenai spin towards their spin obligations. AKRES 001-1 B:Interior A single transmission line connects the generation in the Interior with the rest of South Central Alaska. The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Alaska Intertie Transmission Line; Not all spin originating in South Central can leave South Central; If the System LSGC is in the interior,South Central Entities share in providing spinning reserve to cover this unit; If spin can't leave the South Central,it is inefficient to require an Entity to carry spin that can't be used; South Central Entities should not count an Interior LSGC as the Systems'largest unit during periods when the Alaska Intertie is constrained or near constrained as appropriate. The Alaska Intertie isn't always constrained every hour; Spin originating on the South Central can leave South Central; Entities in South Central should be required to carry their share of spin for an Interior System LSGC; To address this issue will require real time monitoring of the flows between the Interior and the Anchorage Bowl.AMLP has live data which can be distributed via ICCP or equivalent.South Central Entities will be permitted to reduce their spin obligation during periods of constraint (and near constraint as appropriate)to cover the next largest South Central based contingency. AKRES-001 vs AKRES-000 A. S-00]-91-Rese Introduction 1.Title:Reserve Obligation and Allocation 2.Number:AKRES-001-01 3.Purpose: This standard describes Reserve Obligations for all Entities interconnected to the Railbelt Grid. 4.Applicability: 4.1.Balancing Authorities 4.2.Load Serving Entities 4.3.Generation Owners (Generation Asset Owning Entities) 5.Effective Date:TBD Requirements Rl.Reserve Capacity Requirement R2. RL1.Each Load Serving Entity is expected to maintain responsibility to provide capacity for its own fipnfirm load.As part of such responsibility,the Load Serving Entity shall maintain or otherwise provide for annually,Accredited Capacity,in an amount equal to or greater than its maximum System Demand for such year plus the Load Serving Entities Entity's Reserve Capacity Obligation,as set forth in Subsection R1.2. R12.The Reserve Capacity Obligation of a Load Serving Entity,for any year,shall be equal to thirty (30)percent of the projected Annual System Demand for that year for that Load Serving Entity.The Reserve Capacity Obligation ofthe Load Serving Entity may be adjusted from time to time by the Intertie Management Committee (IMC). RI.3.The IMC may determine the annual Accredited Capacity for each Load Serving Entity, Responsibility for Operating Reserve R2.1.Each Load Serving Entity and/or Generation Owner shall provide,or contract for, Spinning Reserve and Non-Spinning Reserve as required by Section R3 equal to or greater than the Operating Reserve Obligation of the entity.As soon as practicable,but not to exceed four hours,after the occurrence of an incident which uses Operating Reserves,each entity shall restore its Operating Reserve Obligation. R22.Operating Reserves,Operating Reserve Obligation,System Reserve Basis and allocation calculations may be modified or changed by the Intertie Management Committee. R2.3.The System Reserve Basis (SRB)is equal to the Largest Generating Unit Contingency of the systemSystem as defined in Exhibit Al or other such value such as loss of a transmission line,as determined by engineering studies and approved by the IMC. AKRES-001 vs AKRES-000 R3.Total Operating Reserve Obligation R3.1.The Total Operating Reserve Obligation at any time shall be an amount equal to 150 percent of the SRBSystem Reserve Basis of the Railbelt Electric Grid. R3.2.The Spinning Reserve portion of the Total Operating Reserve Obligation -shall not be less than an amount equivalent to 100percent of the SRB-System Reserve Basis. R3.3.The balance of the Total Operating Reserve Obligation shall be maintained with Non-Spinning Reserve-faka-Nen-Operating Reserves}. R4.Generating Unit Capability- Generating unit capability for eperating reserveOperating Reserve shall be determined by the following criteria: R4.1.Itshall not be less thatthan the load on the machine at any particular time nor greater than R42 below R4.2.Itshall not exceed that maximum amount efleadof load (MW)that the unit is capable of continuously supplying for a two-hour period,or quickly,through action of automatic governor controls. R4.3_In order to be counted as a producer of Spinning Reserve,the net response regardless of methods used (generator,SILOS,BESS,duct firing,etc.)must be able to meet the following minimum performance based criteria: Initial response:movement within 2 seconds 30 second response:50%usage of its reported spin capability 60 second response:_75%usage of its reported spin capability 120 second response:100%usage ofits reported spin capability R4.4.The criteria specified in this section may be modified or changed by the Intertie Management -Committee. RSR5.Allocation of Operating Reserve Obligations The Operating Reserve Obligation of an Obligated-Entity shall be that percentage of the Total Operating Reserve ebigatienObligation determined by the IMC in accordance with the formulas described in RS through R7 RSR5.1.An Entities'Entity's Spinning Reserve shall be calculated at any given instant as the difference between the sum of the net capability of all generating units on line in the respective entity and the integrated Systems Demand of the system involved and other sources (for example,SILOS and BESS)or declared restrictions on spinning reserve (for example,Bradley Lake or tie line restrictions)as accepted by the IMC RSRS5.2.An Entities'Entity's Spinning Reserve may be satisfied by an automatically controlled load shedding program.The load shedding program shall assure that AKRES-001 vs AKRES-000 controlled load can be dropped to meet the requirement of Spinning Reserve in such a manner as to maintain system stability and not cause degradation or cascading effects in the Railbelt system.The MIG shall review "anc approve the RSR5.3.The IMC may establish procedures to assure that the Operating Reserve of an entity is available on the Railbelt System at all times.Whenever an entity is unable to meet its Operating Reserve Obligation,thatthe entity will,within two AKRES-001 vs AKRES-000 -hours,advise its Balancing Authority and make arrangements to restore its Operating Reserve Obligation. RSRS5.4.Prudent Utility Practices shall be followed in distributing Operating Reserve, taking into account effective utilization of capacity in an emergency,Respense Ratetime required to be effective,transmission limitations and local area requirements.Available Transfer Capability (ATC)shall include a component (Capacity Benefit Margin)recognizing the need to move reserves between areas. Geographical constraints and remedies are defined in Exhibit A3. R5.5.Subject to R5.3 above,an entityEntity may arrange for one or more other entities to supply part of,or its entire,Operating Reserve requirement. RSR5.6.By mutual agreement between the parties,an Entity which has contracted or leased all of the Interconnected Value of a Generating Asset or Share of a Generating Asset (energy,capacity,reactive-output dispatch-ability etc.)to another Railbelt Entity,such that this particular asset appears for all intents and purposes as Generating Asset of the Lessee's (contractee's)fleet,may have that asset counted among the Lessee's generating units and the Lessee may include this unit as any other in the Lessee's fleet for purposes of calculation operating reserve allocation. An example of this is the Bradley Lake Project.AEA and at various times other project participants have contracted to have the Interconnected Value of this Generating Asset or their respective Shares of this Generating Asset assigned to one another in different forms.In each case the assignor has been relieved of the assigned project share (as the assignor's potential LSGC)and that share has been assigned to the assignee's fleet. RSRS5S.7.In an emergency,any Generator Owner,upon request by its Balancing Authority_tetther-_threuch_autemated frequency-or-voltase_feedback-or-via SystemOperaterintervention);,shall supply to such Balancing Authority part or all of its Operating Reserve up to the full amount of its Available Accredited Capacity.An Entity experiencing an emergency is not required to maintain its Operating Reserve Obligation.There shall be no obligation of an Entity to supply Operating Reserve if the requesting entity is not making full use of its own Available Accredited Capacity. R6.Responsibility for Regulating Reserve R6.1.Regulating Reserve-each Balancing Authority (BA)shall provide,or contract for, Regulating Reserve as required by Section R6.2 equal to,or -greater -than,the Regulating Reserve Obligation of the party.Regulating Reserve may-not overlap reserves dedicated for Spinning Reserve.Regulating Reserve (both up and down) is required to compensate for uncertainty in forecasting and is established during the unit -commitment planning process,and as such the BA may then utilize theirits reserve as required during the course of the day.Half_a BA exhausts its Regulating Reserve,they-areit_is required to procure or commit additional reserves -immediately.-Available -Transfer -Capability ATC)-for R7. AKRES-001 vs AKRES-000 _Interconnecting Transmission lines shall recognize a component included in Transmission Reliability Margin (TRM)to allow for the delivery of Regulating Reserve between areas. R6.2.RegulatineReguhting Reserve Obligation-the Regulating Reserve Obligation for each Balancing Authority shall initially be sett by the -intertie¢ Management R6.3.On an annual basis,after the year end CPS -statistics are compiled,the IMC shaHwill modify each Balancing Autherities'Authority's Regulating Reserve by increasing/decreasing its current Regulating Reserve by the %deviation in its EPSICPS1.The Regulating Reserve ebligatiensObligations so calculated will be rounded up to the nearest integer MW. R6.4.The IMC reserves the right to increase/decrease a BAL'sBA's Regulating Reserve or require other measures at any time due to changes in the system or repeat infractions. Spinning Reserve Components R7.1.Spinning Reserve Obligation will be allocated to an Entity -based -on a combination of its Monthly Peak Hour Load (MPHL)and the Entities*Entities'Largest Single Generating Contingency (including any combination of units with a single point of interconnection forming a single contingency-as further discussed in R7.6.RAS applications which have been field demonstrated to successfully mitigate the LSGC and have been approved by the IMC may be applied to reduce the magnitude of the LSGC. R7.2.Spinning Reserve Largest Contingency Ratio (SRLCR):This component shall be calculated as the ratio of an individual Entities'Largest Single Generating Contingency (LSGC)as compared to the sum of the LSGC's of all the Railbelt Entities. R7.3.The Largest Single Generating Contingency will be based on the maximum DeclaredCapabityactual capacity of those unit(s)subject to the single contingency (regardless of RAS applications:"when "operated”"at the An example of a Generating Contingency is a combined cycle unit;the loss of the combustion turbine will precipitate the loss of both the CT as well as the waste heat unit. R7.4.lf entities share a unit,an entities Share of such a unit could qualify as their LSGC if they have nno unit(s)that aare°larger.This component nay shange AKRES-001 vs AKRES-000 R7.5._Monthly Peak Hour Load Ratio (MPHLR);This component shall be calculated at the ratio of an individual Entities”MPHL as compared to the sum of the MPHL's of all the Railbelt Entities.The MPHIL of an Entity shall be defined as the Monthly Peak Hourly Load from the month 1 year earlier,Adjustments for permanent loss,or expected increases due to large industrial loads may be made if agreed to by the IMC.Economy sales are not counted as loads,but non- firm/interruptible loads are. R7.6.Single points ofinterconnection,such asthe-remainder-ofthe Spinning Reserve-centribution_oftheparticularunit(s)++is -avementine ,but not limited to,.buses.collector feeders,.Step--upptransformers,shallI De the obligation of the: bus fale or multiple unite on that the asset+class jis"involved iina1 failure at a rate2 of once per year will validate it as a+single colisctor_feeder thay be considered -a¢n point ofof failure ina fuel_-supply_that_mey_resultinterconnection asas discussed jin the less-of-multiple-units-dees_not -necessarily_eonstitute-a-LSGE.R7.1.However, subject to the reasoning above,the IMC may exercise judgment in such matters. R+-&R7.7.An entity adding a unit greater than 120 MW will accrue the obligation above 120 MW ona one for one basis in addition to the#tits otherwise calculated spin obligation.Fhe-aferementioned120MWThis cap is subject to change by the IMC. R+9-R7.8.The Spinning Reserve Obligation-(SRO)of each Obligated Entity shall be calculated as follows: _SRO.ESGE-eHLHESGC-50%LSGCY {51 (LSGC)}*[SRB}50%{MPHL.YV{>; (MPHL,)}*[SRB]+MUD, =Obligateda particular Entity i=All Interconnected Entities MUD =the difference between the R7.7 max unit limit and an entities largest unit if greater than the R7.7 Hmsttcap. C.Measures MI.Each Obligated Entity and Balancing Authority shall maintain: MI.1.Records of their Reserve Capacity at any point in time.These records will be updated as new Assets are added and other Assets are retired.These records will be available by for review by the Balancing Authority or Compliance Monitor with 1 business week written notice. AKRES-001 vs AKRES-000 MI.2.Hourly records of Operating Reserve and Regulating Reserve (scheduled and actual)will be maintained by all Obligated Entities'.These will be made available in real-time to the Balancing Authority for archival and storage. MI.3.The Compliance Monitor will review the perfernnanceperformance of each Balancing Authority and Obligated Entity at least annually.More frequent reviews shall be performed if spin obligation compliance warrants such reviews. ML4.Spin Balancing Account records will be maintained as described in Exhibit A2. Compliance Monitoring 1.Balancing Authorities AKRES-001 vs AKRES-000 2.IMC-Railbelt Regional Reliability Organization E.Non-Compliance. E.Level 1. VerstonHistery Version History Version Date Action Change Tracking AKRES-001 vs AKRES-000 Exhibit A1 -Methodology for a varying Largest Single Generating Contingency. For the Largest Single Generating Contingency (LSGC)for the Railbelt System 1)Each Entity will electronically share their hourly expected temperature compensated largest unit's output forecast during the day-ahead scheduling process.This may not be the same unit for each hour. 2)At this time,each utility will also share data on any forecasted excess spin that the Entity may wish to sell. 3)The next day and to the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was underestimated,the Entity which provided that forecast is obligated to make up the deficit spin in real time in order to keep the system protected.This includes forecasted unit startups. 4)To the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was overestimated, the difference in spin obligation will be pro rata credited to the remaining Entities in their Spin Balancing Account (SBA).This includes forecasted unit shutdowns. For the Largest Single Generating Contingency (LSGC)for an Entity 1)To the extent that the forecasted LSGC for an Entity's real time output was underestimated,the Entity which provided that forecast is obligated to credit the remaining Entities'SBA with the difference in spin in which they over carried due to the inaccurate forecast. 2)To the extent that the forecasted LSGC for an Entity's real time output was overestimated,no adjustments to the SBA will be made. AKRES-001 vs AKRES-000 Exhibit A2 -Spin Balancing Account A Spin Balancing Account (SBA)will be created and kept by each Balancing Authority (BA)showing Date,Hour,To, From,and Quantity. Quantities must exceed a dead band to be recorded.Quantities 2 MW or larger qualify to be recorded. The entries will primarily reflect errors in forecasting and the consequential harm (in terms of amount ofspin carried) caused to the other Entities due to these errors. Entities will net out their spin obligations with others in chronological order (oldest first)but_at times may need to redeem their spin via scheduling from the utility owing them spin,at no cost for the spin,and at such time the owing utility has spin excess of its needs.The owing utility has no obligation to start additional generation to provide such spin. Each quarter,a BA will be selected as being the "master”to which the other entities will compare their own records. The "master”role will be rotated. AKRES-001 vs AKRES-000 Exhibit A3 -Geographical Spin Methodology for the handling specific issues resultant from Railbelt Geography A:Kenai A single transmission line connects the generation on the Kenai with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Kenai Transmission Line; Not all spin originating on the Kenai can leave the Kenai; If spin can't leave the Kenai,the utilities north of the Kenai will need to make it up in order to satisfactorily protect the system; If spin can't leave the Kenai,it is inefficient to require an Entity to carry spin that can't be used; The Kenai isn't always constrained every hour; Spin originating on the Kenai can leave the Kenai; Entities on the Kenai should be required to carry their share of spin; To address this issue will require real time monitoring of the flows between the Kenai and the Anchorage Bowl.CEA has the five data which can be distributed via ICCP or equivalent.HEA/AEEC will be permitted to reduce their spin obligation (and consequently the other Entities will need to pro rata increase their spin obligation)during periods of constraint (and near constraint as appropriate}.How much would need to be broadcast to all the utilities via CEA. During periods of constraint and during incidents requiring spin,both CEA and HEA/AEEC will need to monitor the Kenai Transmission Line and curtail the conversion of spin to MW if the emergency limit of the line is expected to be exceeded or is exceeded. CEA's Cooper Lake Plant may be providing spin for CEA which needs to be included in the constrained Kenai calculations.CEA may have certain rights as spelled out in the Bradley Contracts which must be upheld and are of a higher priority than these rules.HEA/AEEC has some amount of Bradley Lake Spin which generally can be expected to leave the Kenai. There may be times where the largest loss contingency in the system is the loss of the Kenai line itself.By definition,HEA/AEEC would not be able to contribute useful spin to such an incident._HEA/AEEC should be permitted to reduce their spin obligation (and consequently the other utilities will need to pro rata increase their spin obligation)so as to only cover the next largest Single Generating Unit Contingency subject to other restrictions of the Kenai Transmission line discussed above. When the Kenai is islanded,the utilities north of the Kenai shall not be permitted to count their stranded Kenai spin towards their spin obligations. AKRES-001 vs AKRES-000 B:Interior A single transmission line connects the generation in the Interior with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Alaska Intertie Transmission Line; Not all spin originating in South Central can leave South Central; If the System LSGC is in the interior,South Central Entities share in providing spinning reserve to cover this unit; If spin can't leave the South Central,it is inefficient to require an Entity to carry spin that can't be used; South Central Entities should not count an Interior LSGC as the Systems'largest unit during periods when the Alaska Intertie is constrained or near constrained as appropriate. The Alaska Intertie isn't always constrained every hour; Spin originating on the South Central can leave South Central; Entities in South Central should be required to carry their share of spin for an Interior System LSGC; To address this issue will require real time monitoring of the flows between the Interior and the Anchorage Bowl.AMLP has live data which can be distributed via ICCP or equivalent.South Central Entities will be permitted to reduce their spin obligation during periods of constraint (and near constraint as appropriate)to cover the next largest South Central based contingency. IMC vs RRO CONTINGENCY RESERVES POLICY A Reserve Capacity RequirementPlanning Criteria A-1.1 1.1.1 RbLt+-Each Load Serving Entity is expected to maintain responsibilityto provide capacity for is own firm load. As part of such responsibility,the Load Serving Entity shall maintain or otherwise provide for annually,Accredited Capacity,inan amount equal to or greater than ts maximum System Demand for such year plus the Load Serving EntitsEntity's Reserve Capacity Obligation,as set forth in Subsection RIA-1.1.2. 1.1.2 The Reserve Capacity Obligation ofaLoad Serving Entity,for any year,shall be equal to thirty (30)percent of the projected Annual System Demand for that year for that Load Serving Entity.-The Reserve Capacity Obligation of the Load Serving Entity may be adjusted from timeto time by the JatertieManagementCommitteeMG}Regional Reliability Organization. 1.1.3 The $MGRegional Reliability Organization may determine the annual Accredited Capacity for each Load Serving Entity. Responsibility for Operating Reserve B R2 B-2.1-____OperatingReserve 2.1.1 Each Load Serving Entity and/or Generation Owner shall provide,or contract for,Spinning Reserve and Non-Spinning -Reserve as required by Section R3B-22 equal to or greater than the Operating Reserve Obligation of the entity.As soon as practicable,but not to exceed IMC vs RRO four hours,after the occurrence of an incident which uses Operating Reserves,each entity shall restore its Operating Reserve Obligation. R22 2.1.2___Operating Reserves,Operating Reserve Obligation,System Reserve Basis and allocation calculations may be modified or changed by the Intertie-Management GommitteeRegional Reliability Organization. R23- 2.1.3_The System Reserve Basis (SRB)is equal to the Largest Generating Unit Contingency of the System as defined in Exhibit A1 or other such value such as loss of a transmission line, as determined by engineering studies and approved by the HMGRRO. ing!ints of interconnection h not limited ll rf r -ransform hall valuated in terms of asset class.Failur h that th lassisinvolved in_a failur: fon r rwill vali i ingl int of interconnection is RROCONTINGENCY RESERVESPOLICY v001 ..R3--above.However,subject to the reasoning above,the Reqional Reliability Organization may exercise judgment _in such matters. An entity adding a unit whose LSGC bs greater than a 20 MW will accrue the obligation above 0 MW _ona one for one basis in addition to ts otherwise calculated spin obligation.This capis subject to change bythe RRO. B-22 Total Operating Reserve Obligation R3-h- 2.2.1 _The Total Operating Reserve Obligation at any time shall be an amount _equal to 60 percent of the System Reserve Basis of the Railbelt Electric Grid; R32 2.2.1.1 The Spinning Reserve portion of the Total Operating Reserve Obligation shall not be less than an amount equivalent to 100 percent of the System Reserve Basis. R33 2.2.1.2 The balance of the Total Operating Reserve Obligation shall be maintained with Non-Spinning Reserve. R4-¢ino UnitC bili 2.2.2__Generating unit capability for Operating ReserveReserves shall be determined by the following criteria: a.R4.4--t shall not be less than the load on the machine at any particular time nor greater than R42(b)below. b.R4.2-K shall not exceed that maximum amount of load (MW)that the unit is capable of continuously supplying for a two-hour period.or quickly,through action of automatic governor contros. 2.2.3 _R4-4-The _criteria_specified _in this section may _be_modified _or changed _by the intertie Management Gommittee_Regional Reliability Organization. Page 30f 56 RROCONTINGENCY RESERVESPOLICY v001 _aB-2.3 Allocation of Operating Reserve Obligations 2.3.1 The Operating Reserve Obligation of an Entity shall be that percentage of the Total Operating Reserve Obligation determined by the 4MGRegional_Reliability Organization in accordance with the formulas described in RSthroughRfexhibis B1 B2 and exhibit A3. B-2-4 Operating Reserve Calculation 2.4.1._An Enatit¢sEntity's Spinning Reserve shall be calculated at any given instant as the difference between the sum of the net capabilty of all generating units on line in the respective entity and the integrated Systems Demand of the system involved and other sources (for example,SILOS and BESS)or declared restrictions on spinning reserve (for example,Bradley Lake or tie line restrictions)as accepted by the 44C@Regional Reliability Organization. 2.4.2__An Entity's Spinning Reserve may be satisfied by an automatically controlled load shedding program.The bad shedding program shall assure that controlled load can be dropped to meet the requirement of Spinning Reserve in such a manner as to maintain system stability and not cause degradation or cascading effects inthe Railbelt system. 2.4.3 The $MCRegional Reliabilty Organization may establish procedures to assure that the Operating Reserve of an entity _is available on the _Railbelt System _at _all times.Whenever an entity is unable to meet is Operating Reserve Obligation,the entity will,within two hours,advise its Balancing Authority and make arrangements to restore ts Operating Reserve Obligation. R5.4,- 2.4.4 Prudent Utilty Practices shall be followed in distributing Operating Reserve,taking into account effective utilization of capacity in an emergency,time required to be effective, transmission limitations and local area requirements.Avaitable-Fransfer Capability (ATG) reserves _betweer-areas-Geographical constraints and remedies are defined in Exhibi A3. R55 2.4.5 Subject to R5-32.4.4 above,an Entity may arrange for one or more other entities to supply part of,or its entire,Operating Reserve requirement. 2.4.6 R5.6-By mutual agreement between the parties,an Entity which has contracted or leased al]of the Interconnected Value of a Generating Asset or Share ofa Generating Asset (energy,capacity,reactive-output dispatch-ability etc.)to another Railbelt Entity,such that this particular asset appears for all intents and purposes as Generating Asset of the Lessee's (contractee's)fleet,may have that asset counted among the Lessee's generating units and the Lessee may include Page 4of 56 RROCONTINGENCY RESERVES POLICY v001 RSF this unit as any other in the Lessee's fleet for purposes of calculation operating reserve allocation. An example of this is the Bradley Lake Project.AEA and at various times other project participants have contracted to have the Interconnected Value of this Generating Asset or their respective Shares of this Generating Asset assigned to one another in different forms.In each case the assignor has been relieved of the assigned project share (as the assignor's potential LSGC)and that share has been assigned to the assignee's fleet. 2.4.7 __In an emergency,any Generator Owner,upon request by its Balancing Authority,shall supply to such Balancing Authority part or all of its Operating Reserve up to the full amount of its Available Accredited Capacity.An Entity experiencing an emergency is not required to maintain its Operating Reserve Obligation.There shall be no obligation of an Entity to supply Operating Reserve if the requesting entity isnot making full use of its own Available Accredited Capacity. R6--Responsibility for Regulating Reserve Cc R6_C-3.1-,Regulating Reserve- each 3.1.1 Each Balancing Authority (BA)shall provide,or contract for,Regulating Reserve as required by Section R6C-3.2 equal to;or greater than;the Regulating Reserve Obligation of the party.Regulating Reserve may not overlap reserves dedicated for Spinning Reserve.Regulating Reserve (both up and down)is required to compensate for uncertainty in forecasting and is established during the unit commitment planning process,and as such the BA may then utilize its reserve as required during the course of the day.fF a BA exhausts its Regulating Reserve,it is required to procure or commit additional reserves immediately._AvaiableTransferGapabilit(ATCHortatercennecting R6C-3.2-Regulating Reserve Obligation-the 3.2.1 The Regulating Reserve Obligation for each Balancing Authority shall intially be set by the Intertie Management GommitteeRegional Reliabilty Organization. 3.2.2 R6-3--On an annual basis,after the year end CPS statistics are compiled,the MCRegional Reliability Organization will modify each Balancing Authority's Regulating Reserve by increasing/decreasing its current Regulating Reserve by the %deviation in its CPS1.The Regulating Reserve Obligations so calculated will be rounded up to the nearest integer MW. 3.2.3.R6.4.-TheIMCThe Regional Reliability Organization reserves the right to Page 5of 56 RROCONTINGENCY RESERVES POLICY v001 increase/decrease a BA's Regulating Reserve or require other measures at any time due to changesin the system or repeat infractions._Spin BalancingAccountrecordswillbemaintainedasdescribedinExhibitA2, Page 6of 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit B1:Spinning Reserve Components R#.A-Spinning Reserve Obligation will be allocated to an Entity based on a combination of its Monthly Peak Hour Load (MPHL)and the Entities'Largest Single Generating Contingency (including any combination of units with a single point of interconnection forming a single contingency as further discussed in R#.6-2.1.3.RAS applications which have been field demonstrated to successfully mitigate the LSGC and have been approved by the }4GRRO may be applied to reduce the magnitude of the LSGC. RI Spinning Reserve Largest Contingency Ratio (SRLCR):This component shall be calculated as the ratio of an individual Entities'Largest Single Generating Contingency (LSGC)as compared to the sum of the LSGC's of all the Railbelt Entities. R#7.3-The Largest Single Generating Contingency will be based on the actual capacity of those unit(s)subject to the single contingency (regardless of RAS applications). _An example of a Generating Contingency is a combined cycle unit;the loss of the combustion turbine will precipitate the loss of both the CT as well as the waste heat unit. RZ4-If entities share a unit,an entities Share of such a unit could qualify as their LSGC if they have no unit(s)that are larger. R#.5.-Monthly Peak Hour Load Ratio (MPHLR):This component shail be calculated at the ratio of an individual Entities'MPHL as compared to the sum of the MPHL's of all the Railbelt Entities.The MPHL of an Entity shall be defined as the Monthly Peak Hourly Load from the month 1 year earlier.Adjustments for permanent loss,or expected increases due to large industrial lbads may be made #agreed to by the H4G-RRO.Economy sales are not counted as loads,but non-firm/interruptible bads are. Page 7of 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit B2:Spinning Reserve Obligation{SRO}-efeach-Obligated Entity shall be calculated Spinning Reserve Obligation for an Entity will be calculated summing the weighted Spinning Reserve Components of each entity,and multiplyingthis by the System Reserve Basis as follows: SROc=50%{LSGCe}/{Xi (LSGCi)}-[SRBJ+50%{MPHLe}/{di (MPHLi)}*[SRB]+MUDe €=a particular Entity i =All Interconnected Entities MUDe=the difference between the R#+-#2.1.3 max unit limit and an entities largest unit if greater than the RAF2.1.3 cap. Page 8o0f 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit B3:Spinning Reserve Criteria Page 9of 56 Page 10o0f 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit A1 -Methodology for a varying Largest Single Generating Contingency. For the Largest Single Generating Contingency (LSGC)for the Railbelt System 1)Each Entity will electronically share their hourly expected temperature compensated largest unit's output forecast during the day-ahead scheduling process.This may not be the same unit for each hour. 2)At this time,each utility will also share data on any forecasted excess spin that the Entity may wish to sell. 3)The next day and to the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was underestimated,the Entity which provided that forecast is obligated to make up the deficit spin in real time in order to keep the system protected.This includes forecasted unit startups. 4)To the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was overestimated,the difference in spin obligation will be pro rata credited to the remaining Entities in their Spin Balancing Account (SBA).This includes forecasted unit shutdowns. For the Largest Single Generating Contingency (LSGC)for an Entity 1)To the extent that the forecasted LSGC for an Entity's real time output was underestimated,the Entity which provided that forecast is obligated to credit the remaining Entities'SBA with the difference in spin in which they over carried due to the inaccurate forecast. 2)To the extent that the forecasted LSGC for an Entity's rea!time output was overestimated,no adjustments to the SBA will be made. Page 11 0f 56 RROCONTINGENCY RESERVESPOLICY v004 Exhibit A2 -Spin Balancing Account A Spin Balancing Account (SBA)will be created and kept by each Balancing Authority (BA)showing Date, Hour,To,From,and Quantity. Quantities must exceed a dead band to be recorded.Quantities 2 MW or larger qualify to be recorded. The entries will primarily reflect errors in forecasting and the consequential harm (in terms of amount of spin carried)caused to the other Entities due to these errors. Entities will net out their spin obligations with others in chronological order (oldest first)but at times may need to redeem their spin via scheduling from the utility owing them spin,at no cost for the spin, and at such time the owing utility has spin excess of its needs.The owing utility has no obligation to start additional generation to provide such spin. Each quarter,a BA will be selected as being the "master”to which the other entities will compare their own records.The "master”role will be rotated. Page 120f 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit A3 -Geographical Spin Methodology for the handling specific issues resultant from Railbelt Geography A:Kenai A single transmission line connects the generation on the Kenai with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Kenai Transmission Line; Not all spin originating on the Kenai can leave the Kenai; If spin can't leave the Kenai,the utilities north of the Kenai will need to make it up in order to satisfactorily protect the system; If spin can't leave the Kenai,it is inefficient to require an Entity to carry spin that can't be used; The Kenai isn't always constrained every hour; Spin originating on the Kenai can leave the Kenai; Entities on the Kenai should be required to carry their share of spin; To address this issue will require real time monitoring of the flows between the Kenai and the Anchorage Bowl.CEA has the live data which can be distributed via ICCP or equivalent. HEA/AEEC will be permitted to reduce their spin obligation (and consequently the other Entities will need to pro rata increase their spin obligation)during periods of constraint (and near constraint as appropriate).How much would need to be broadcast to all the utilities via CEA. During periods of constraint and during incidents requiring spin,both CEA and HEA/AEEC will need to monitor the Kenai Transmission Line and curtail the conversion of spin to MW if the emergency limit of the line is expected to be exceeded or is exceeded. CEA's Cooper Lake Plant may be providing spin for CEA which needs to be included in the constrained Kenai calculations.CEA may have certain rights as spelled out in the Bradley Contracts which must be upheld and are of a higher priority than these rules.HEA/AEEC has some amount of Bradley Lake Spin which generally can be expected to leave the Kenai. There may be times where the largest loss contingency in the system is the loss of the Kenai line itself.By definition,HEA/AEEC would not be able to contribute useful spin to such an incident. HEA/AEEC should be permitted to reduce their spin obligation (and consequently the other utilities will need to pro rata increase their spin obligation)so as to only cover the next largest Single Generating Unit Contingency subject to other restrictions of the Kenai Transmission line discussed above. Page 130f56 RROCONTINGENCY RESERVESPOLICY v001 When the Kenai is islanded,the utilities north of the Kenai shall not be permitted to count their stranded Kenai spin towards their spin obligations. B:Interior A single transmission line connects the generation in the Interior with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Alaska Intertie Transmission Line; Not all spin originating in South Central can leave South Central; If the System LSGC is in the interior,South Central Entities share in providing spinning reserve to cover this unit; If spin can't leave the South Central,it is inefficient to require an Entity to carry spin that can't be used; South Central Entities should not count an Interior LSGC as the Systems'largest unit during periods when the Alaska Intertie is constrained or near constrained as appropriate. The Alaska Intertie isn't always constrained every hour; Spin originating on the South Central can leave South Central; Entities in South Central should be required to carry their share of spin for an Interior System LSGC; To address this issue will require real time monitoring of the flows between the Interior and the Anchorage Bowl.AMLP has live data which can be distributed via ICCP or equivalent.South Central Entities will be permitted to reduce their spin obligation during periods of constraint (and near constraint as appropriate)to cover the next largest South Central based contingency. Page 140f 56 ALASKA INTERTIE MANAGEMENT COMMITTEE MEETING Tuesday,Sept.1,2015 -9:00 AM **PLEASE WRITE LEGIBLY** NAME Organization Ee aRC GB So)MS wel Rates SG BdJMetaSelesMuseJVRAALCONHARRINGTONML2ZP 4 Bex Sit [Ube AN bURAZ Wik aa VCO SK ie 'TE4BrnociesACHAGLA \ DL Krak LeaRkER AEN - /Beat Cwierg .PE gr +Bob Dau KZA V Dave Gillespie AReTeE? IOC Operator Report September 1,2015 1.Alaska Intertie Status Report MWH Usage at Douglas Substation Second quarter 2015:111,708 MWh July 2015:29,363 MWh August 2015 :33,299 MWh 2.System operation Second Quarter 2015 Intertie trips,6 trips: 4/16/2015 GVshed 44MW lOC#764 5/7/2015 HLS B17,GV shed 0.OMW lOC#770 5/7/2015 HLS B17,GV shed 0.OMW lOC#769 6/14/2015 GV shed 0.0MW,C phase to ground 6/27/2015 HLS B17,GV shed 10.6MW 6/27/2015 GV shed 39.7MW, We had two HLS B17 only trips that where due to the Healy SVC tripping off,therefore lowering the HLS B17 OV trip point and subsequently tripping B17 open.See #4 below. 3.Compliance Report a.none 4.Alaska Intertie SVC update a.All three SVCs have,for the most part,been operating well.Software upgrades at TLS, HLS and GHS to be completed mid-September to correct overly sensitive UV detection of 480v bus.SVC warranty being negotiated by AMLP. 5.Intertie Operating Committee a.Summer IOC meeting was at MEA on July 9,2015 b.Working on spinning reserve allocation reconciliation between AIARS and RRO. 6.Machine Ratings Subcommittee a.Update MRSC online data base -ongoing 7.Operations,Maintenance and Scheduling Subcommittee a.Meeting regular,no report 8.Dispatch and System Operations Subcommittee a.Reviewing outage reporting criteria necessary to provide useful information. b.Review and provide compliance reporting methodology 9.Budget Subcommittee a.Received budget from subcommittee,approved,passed to IMC 10.Engineering,relay and Reliability Subcommittee Review Douglas Substation Protection Upgrade Project,ongoing.IOC had site visit on 7/9/2015.MEA working on proposal for new infrastructure.In short term MEA is changing out ancient SEL121 relay with a newer model to provide protection looking north that will be remotely accessible. a. 11.System Studies Subcommittee a.UFLS Study Awarded to EPS. 12.SCADA and Telecommunications Subcommittee a.Snow Load Monitoring System quit working when AT&T upgraded cell system to 4G.EPS working ona fix. 'roponed Tu les RRO Contingency Reserves Policy V001 CONTINGENCY RESERVES POLICY Reserve Capacity Planning Criteria A-1.1 1.1.1 1.1.2 1.1.3 Each Load Serving Entity is expected to maintain responsibility to provide capacity for ts own firm load.As part of such responsibility,the Load Serving Entity shall maintain or otherwise provide for annually,Accredited Capacity,in an amount equal to or greater than ts maximum System Demand for such year plus the Load Serving Entity's Reserve Capacity Obligation,as setforth in Subsection A-1.1.2. The Reserve Capacity Obligation ofa Load Serving Entity,for any year,shall be equal to thirty (30)percent of the projected Annual System Demand for that year for that Load Serving Entity.The Reserve Capacity Obligation of the Load Serving Entity may be adjusted from time to time by the Regional Reliability Organization. The Regional Reliability Organization may determine the annual Accredited Capacity for each Load Serving Entity. Responsibility for Operating Reserve B-2.1 OperatingReserve 2.1.1 Each Load Serving Entity and/or Generation Owner shall provide,or contract for,Spinning Reserve and Non-Spinning Reserve as required by Section B-22 equal to or greater than the Operating Reserve Obligation of the entity.As soon as practicable,but not to exceed four hours,after the occurrence of an incident which uses Operating Reserves, each entity shall restore its Operating Reserve Obligation. Operating Reserves,Operating Reserve Obligation,System Reserve Basis and allocation calculations may be modified or changed by the Regional Reliabilty Organization. The System Reserve Basis (SRB)is equal to the Largest Generating Unit Contingency of the System as defined in Exhibit A1 or other such value such as loss of a transmission line,as determined by engineering studies and approved by the RRO. Single points of interconnection,such as,but not limited to,buses,collector feeders,step- up transformers,shall be evaluated in terms of asset class.Failure rates such that the asset class is involved in a failure at a rate of once per year will validate it as a single point of interconnection as discussed above.However,subject to the reasoning above,the Regional Reliability Organization may exercise judgment in such matters. RROCONTINGENCY RESERVESPOLICY v001 B-22 2.2.1 An entity adding a unit whose LSGC 5 greater than a 20 MW will accrue the obligation above 20 MW on a one for one basis in addition to ts otherwise calculated spin obligation.This cap subject to change by the RRO. Total Operating Reserve Obligation The Total Operating Reserve Obligation at any time shall be an amount equal to 60 percent of the System Reserve Basis of the Railbelt Electric Grid 2.2.1.1 The Spinning Reserve portion of the Total Operating Reserve Obligation shall not be less than an amount equivalentto 100 percent of the System Reserve Basis. 2.2.1.2 The balance of the Total Operating Reserve Obligation shall be maintained with 2.2.2 2.2.3 B-23 Non-Spinning Reserve. Generating unit capability for Operating Reserves shall be determined by the following criteria: a.kt shail not be less than the load on the machine at any particular time nor greater than (b)below. b.t shall not exceed that maximum amount of lad (MW)that the unit is capable of continuously supplying for a two-hour period,or quickly,through action of automatic governor contro'. The criteria specified in this section may be modified or changed by the Regional Reliability Organization. Allocation of Operating Reserve Obligations 2.3.1 The Operating Reserve Obligation of an Entity shall be that percentage of the Total B-2-4 2.4.1 2.4.2 Operating Reserve Obligation determined by the Regional Reliability Organization in accordance with the formulas described in exhibits B1,B2 and exhibit A3. Operating Reserve Calculation An Entity's Spinning Reserve shall be calculated at any given instant as the difference between the sum of the net capabilty of all generating units on line in the respective entity and the integrated Systems Demand of the system involved and other sources (for example,SILOS and BESS)or declared restrictions on spinning reserve (for example, Bradley Lake or tie line restrictions)as accepted by the Regional Reliability Organization. An Entiy's Spinning Reserve may be satisfied by an automatically controlled load shedding program.The load shedding program shall assure that controlled load can be dropped to meet the requirement of Spinning Reserve in such a manner as to Page 20f 56 RRO CONTINGENCY RESERVESPOLICY v001 2.4.3 2.4.4 2.4.5 2.4.6 2.4.7 maintain system stability and not cause degradation or cascading effects inthe Railbelt system. The Regional Reliability Organization may establish procedures to assure that the Operating Reserve of an entity is available on the Railbelt System at all times. Whenever an entity is unable to meet is Operating Reserve Obligation,the entity will, within two hours,advise its Balancing Authority and make arrangements to restore its Operating Reserve Obligation. Prudent Utilty Practices shall be followed in distributing Operating Reserve,taking into account effective utilization of capacity in an emergency,time required to be effective, transmission limitations and local area requirements.Geographical constraints and remedies are defined in Exhibit A3. Subject to 2.4.4 above,an Entity may arrange for one or more other entities to supply part of,or its entire,Operating Reserve requirement. By mutual agreement between the parties,an Entity which has contracted or leased all of the Interconnected Value of a Generating Asset or Share of a Generating Asset (energy,capacity,reactive-output dispatch-ability etc.)to another Railbelt Entity,such that this particular asset appears for all intents and purposes as Generating Asset of the Lessee's (contractee's)fleet,may have that asset counted among the Lessee's generating units and the Lessee may include this unit as any other in the Lessee's fleet for purposes of calculation operating reserve allocation. An example of this is the Bradley Lake Project.AEA and at various times other project participants have contracted to have the Interconnected Value of this Generating Asset or their respective Shares of this Generating Asset assigned to one another in different forms.In each case the assignor has been relieved of the assigned project share (as the assignor's potential LSGC)and that share has been assigned to the assignee's fleet. In an emergency,any Generator Owner,upon request by its Balancing Authority,shall supply to such Balancing Authority part or all of its Operating Reserve up to the full amount of its Available Accredited Capacity.An Entity experiencing an emergency is not required to maintain its Operating Reserve Obligation.There shall be no obligation of an Entity to supply Operating Reserve if the requesting entity isnot making full use of its own Available Accredited Capacity. Cc Responsibility for Regulating Reserve C-3.1 Regulating Reserve 3.1.1 Each Balancing Authorty (BA)shal!provide,or contract for,Regulating Reserve as Page 30f 56 RROCONTINGENCY RESERVES POLICY v001 C-3.2 3.2.1 3.2.2 3.2.3 required by Section C-3.2 equal to or greater than the Regulating Reserve Obligation of the party.Regulating Reserve may not overlap reserves dedicated for Spinning Reserve. Regulating Reserve (both up and down)is required to compensate for uncertainty in forecasting and is established during the unit commitment planning process,and as such the BA may then utilize its reserve as required during the course of the day.Fa BA exhausts its Regulating Reserve,it is required to procure or commit additional reserves immediately. Regulating Reserve Obligation The Regulating Reserve Obligation for each Balancing Authority shall intially be set by the Regional Reliability Organization. On an annual basis,after the year end CPS statistics are compiled,the Regional Reliability Organization will modify each Balancing Authority's Regulating Reserve by increasing/decreasing its current Regulating Reserve by the %deviation in its CPS1.The Regulating Reserve Obligations so calculated will be rounded up to the nearest integer MW. The Regional!Reliability Organization reserves the right to increase/decrease a BA's Regulating Reserve or require other measures at any time due to changes in the system or repeat infractions.Spin Balancing Account records will be maintained as described in Exhibit A2. Page 40f 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit B1:Spinning Reserve Components Spinning Reserve Obligation will be allocated to an Entity based on a combination of its Monthly Peak Hour Load (MPHL)and the Entities'Largest Single Generating Contingency (including any combination of units with a single point of interconnection forming a single contingency as further discussed in 2.1.3.RAS applications which have been field demonstrated to successfully mitigate the LSGC and have been approved by the RRO may be applied to reduce the magnitude of the LSGC. Spinning Reserve Largest Contingency Ratio (SRLCR):This component shall be calculated as the ratio of an individual Entities'Largest Single Generating Contingency (LSGC)as compared to the sum of the LSGC's of all the Railbelt Entities. The Largest Single Generating Contingency will be based on the actual capacity of those unit(s)subject to the single contingency (regardless of RAS applications).An example of a Generating Contingency is a combined cycle unit;the loss of the combustion turbine will precipitate the loss of both the CT as well as the waste heat unit. if entities share a unit,an entities Share of such a unit could qualify as their LSGC if they have no unit(s) that are larger. Monthly Peak Hour Load Ratio (MPHLR):This component shall be calculated at the ratio of an individual Entities'MPHL as compared to the sum of the MPHL's of all the Railbelt Entities.The MPHL of an Entity shall be defined as the Monthly Peak Hourly Load from the month 1 year earlier.Adjustments for permanent loss,or expected increases due to large industrial bads may be made f agreed to by the RRO.Economy sales are not counted as loads,but non-firm/interruptible bads are. Page 5of 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit B2:Spinning Reserve Obligation Spinning Reserve Obligation for an Entity will be calculated summing the weighted Spinning Reserve Components of each entity,and multiplyingthis by the System Reserve Basis as follows: SROc=50%{LSGCe}/{Xi (LSGCi)}*[SRB]+50%{MPHLe}/{%i (MPHLi)}*[SRB]+MUDe e =a particular Entity i =All Interconnected Entities MUDe=the difference between the 2.1.3 max unit limit and an entities largest unit if greater than the 2.1.3 cap. Page 6 of 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit B3:Spinning Reserve Criteria In order to be counted as a producer of Spinning Reserve,the net response regardless of methods used (generator,SILOS,BESS,duct firing,etc.)must be able to meet the following minimum performance based criteria: Initial response: 30 second response: 60secondresponse: 20second response: movement within 2 seconds 50%usage ofits reported spin capability 75%usage ofits reported spin capability 100%usage ofits reported spin capability Page 7of 56 RROCONTINGENCY RESERVES POLICY v004 Exhibit A1 -Methodology for a varying Largest Single Generating Contingency. For the Largest Single Generating Contingency (LSGC)for the Railbelt System 1)Each Entity will electronically share their hourly expected temperature compensated largest unit's output forecast during the day-ahead scheduling process.This may not be the same unit for each hour. 2)At this time,each utility will also share data on any forecasted excess spin that the Entity may wish to sell. 3)The next day and to the extent that the forecasted LSGC for the Railbeit Electric Systems'real time output was underestimated,the Entity which provided that forecast is obligated to make up the deficit spin in real time in order to keep the system protected.This includes forecasted unit startups. 4)To the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was overestimated,the difference in spin obligation will be pro rata credited to the remaining Entities in their Spin Balancing Account (SBA).This includes forecasted unit shutdowns. For the Largest Single Generating Contingency (LSGC)for an Entity 1)To the extent that the forecasted LSGC for an Entity's real time output was underestimated,the Entity which provided that forecast is obligated to credit the remaining Entities'SBA with the difference in spin in which they over carried due to the inaccurate forecast. 2)To the extent that the forecasted LSGC for an Entity's real time output was overestimated,no adjustments to the SBA will be made. Page 80f56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit A2 - Spin Balancing Account A Spin Balancing Account (SBA)will be created and kept by each Balancing Authority (BA)showing Date, Hour,To,From,and Quantity. Quantities must exceed a dead band to be recorded.Quantities 2 MW or larger qualify to be recorded. The entries will primarily reflect errors in forecasting and the consequential harm (in terms of amount of spin carried)caused to the other Entities due to these errors. Entities will net out their spin obligations with others in chronological order (oldest first)but at times may need to redeem their spin via scheduling from the utility owing them spin,at no cost for the spin, and at such time the owing utility has spin excess of its needs.The owing utility has no obligation to start additional generation to provide such spin. Each quarter,a BA will be selected as being the "master”to which the other entities will compare their own records.The "master”role will be rotated. Page 9of 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit A3 -Geographical Spin Methodology for the handling specific issues resultant from Railbelt Geography A:Kenai A single transmission line connects the generation on the Kenai with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Kenai Transmission Line; Not all spin originating on the Kenai can leave the Kenai; If spin can't leave the Kenai,the utilities north of the Kenai will need to make it up in order to satisfactorily protect the system; If spin can't leave the Kenai,it is inefficient to require an Entity to carry spin that can't be used; The Kenai isn't always constrained every hour; Spin originating on the Kenai can leave the Kenai; Entities on the Kenai should be required to carry their share of spin; To address this issue will require real time monitoring of the flows between the Kenai and the Anchorage Bowl.CEA has the live data which can be distributed via ICCP or equivalent. HEA/AEEC will be permitted to reduce their spin obligation (and consequently the other Entities will need to pro rata increase their spin obligation)during periods of constraint (and near constraint as appropriate).How much would need to be broadcast to all the utilities via CEA. During periods of constraint and during incidents requiring spin,both CEA and HEA/AEEC will need to monitor the Kenai Transmission Line and curtail the conversion of spin to MW if the emergency limit of the line is expected to be exceeded or is exceeded. CEA's Cooper Lake Plant may be providing spin for CEA which needs to be included in the constrained Kenai calculations.CEA may have certain rights as spelled out in the Bradley Contracts which must be upheld and are of a higher priority than these rules.HEA/AEEC has some amount of Bradley Lake Spin which generally can be expected to leave the Kenai. There may be times where the largest loss contingency in the system is the loss of the Kenai line itself.By definition,HEA/AEEC would not be able to contribute useful spin to such an incident. HEA/AEEC should be permitted to reduce their spin obligation (and consequently the other utilities will need to pro rata increase their spin obligation)so as to only cover the next largest Single Generating Unit Contingency subject to other restrictions of the Kenai Transmission line discussed above. Page 10of 56 RROCONTINGENCY RESERVESPOLICY v001 When the Kenai is islanded,the utilities north of the Kenai shall not be permitted to count their stranded Kenai spin towards their spin obligations. B:Interior A single transmission line connects the generation in the Interior with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Alaska Intertie Transmission Line; Not all spin originating in South Central can leave South Central; if the System LSGC is in the interior,South Central Entities share in providing spinning reserve to cover this unit; If spin can't leave the South Central,it is inefficient to require an Entity to carry spin that can't be used; South Central Entities should not count an Interior LSGC as the Systems'largest unit during periods when the Alaska Intertie is constrained or near constrained as appropriate. The Alaska Intertie isn't always constrained every hour; Spin originating on the South Central can leave South Central; Entities in South Central should be required to carry their share of spin for an Interior System LSGC; To address this issue will require real time monitoring of the flows between the Interior and the Anchorage Bowl.AMLP has live data which can be distributed via ICCP or equivalent.South Central Entities will be permitted to reduce their spin obligation during periods of constraint (and near constraint as appropriate)to cover the next largest South Central based contingency. Page 11 0f 56 AKRES 001-1 A.Introduction 1.Title:Reserve Obligation and Allocation 2.Number:AKRES-001-1 3.Purpose: This standard describes Reserve Obligations for all Entities interconnected to the Railbelt Grid. 4.Applicability: 4.1.Balancing Authorities 4.2.Load Serving Entities 4.3.Generation Owners (Generation Asset Owning Entities) 5.Effective Date:TBD B.Requirements RI.Reserve Capacity Requirement RI.1.Each Load Serving Entity is expected to maintain responsibility to provide capacity for its own firm load.As part of such responsibility,the Load Serving Entity shall maintain or otherwise provide for annually,Accredited Capacity,in an amount equal to or greater than its maximum System Demand for such year plus the Load Serving Entity's Reserve Capacity Obligation,as set forth in Subsection R1.2. R12.The Reserve Capacity Obligation of a Load Serving Entity,for any year,shall be equal to thirty (30)percent of the projected Annual System Demand for that year for that Load Serving Entity.The Reserve Capacity Obligation ofthe Load Serving Entity may be adjusted from time to time by the Intertie Management Committee (IMC). R13.The IMC may determine the annual Accredited Capacity for each Load Serving Entity. R2.Responsibility for Operating Reserve R2.1.Each Load Serving Entity and/or Generation Owner shall provide,or contract for, Spinning Reserve and Non-Spinning Reserve as required by Section R3 equal to or greater than the Operating Reserve Obligation of the entity.As soon as practicable,but not to exceed four hours,after the occurrence of an incident which uses Operating Reserves,each entity shall restore its Operating Reserve Obligation. R22.Operating Reserves,Operating Reserve Obligation,System Reserve Basis and allocation calculations may be modified or changed by the Intertie Management Committee. R2.3.The System Reserve Basis (SRB)is equal to the Largest Generating Unit Contingency of the System as defined in Exhibit Al or other such value such as loss of a transmission line,as determined by engineering studies and approved by the IMC. AKRES 001-1 R3.Total Operating Reserve Obligation R3.1.The Total Operating Reserve Obligation at any time shall be an amount equal to 150 percent of the System Reserve Basis of the Railbelt Electric Grid. R3.2.The Spinning Reserve portion of the Total Operating Reserve Obligation shall not be less than an amount equivalent to 100percent of the System Reserve Basis. R3.3.The balance of the Total Operating Reserve Obligation shall be maintained with Non-Spinning Reserve. R4.Generating Unit Capability- Generating unit capability for Operating Reserve shall be determined by the following criteria: R4.1.Itshall not be less than the load on the machine at any particular timenor greater than R42 below R4.2.It shall not exceed that maximum amount of load (MW)that the unit is capable of continuously supplying for a two-hour period,or quickly,through action of automatic governor controls. R4.3 In order to be counted as a producer of Spinning Reserve,the net response regardless of methods used (generator,SILOS,BESS,duct firing,etc.)must be able to meet the following minimum performance based criteria: Initial response:movement within 2 seconds 30 second response:50%usage of its reported spin capability 60 second response:75%usage of its reported spin capability 120 second response:100%usage of its reported spin capability R4.4.The criteria specified in this section may be modified or changed by the Intertie Management Committee. R5.Allocation of Operating Reserve Obligations The Operating Reserve Obligation of an Entity shall be that percentage of the Total Operating Reserve Obligation determined by the IMC in accordance with the formulas described in R5 through R7 R5.1.An Entity's Spinning Reserve shall be calculated at any given instant as the difference between the sum of the net capability of all generating units on line in the respective entity and the integrated Systems Demand of the system involved and other sources (for example,SILOS and BESS)or declared restrictions on spinning reserve (for example, Bradley Lake or tie line restrictions)as accepted by the IMC R5.2.An Entity's Spinning Reserve may be satisfied by an automatically controlled load shedding program.The load shedding program shall assure that controlled load can be dropped to meet the requirement of Spinning Reserve in such a manner as to maintain system stability and not cause degradation or cascading effects in the Railbelt system. R5.3.The IMC may establish procedures to assure that the Operating Reserve of an entity is available on the Railbelt System at all times.Whenever an entity is unable to meet its AKRES 001-1 Operating Reserve Obligation,the entity will,within two hours,advise its Balancing Authority and make arrangements to restore its Operating Reserve Obligation. R5.4.Prudent Utility Practices shall be followed in distributing Operating Reserve,taking into account effective utilization of capacity in an emergency,time required to be effective, transmission limitations and local area requirements.Available Transfer Capability (ATC)shall include a component (Capacity Benefit Margin)recognizing the need to move reserves between areas.Geographical constraints and remedies are defined in Exhibit A3. R5.5.Subject to R5.3 above,an Entity may arrange for one or more other entities to supply part of,or its entire,Operating Reserve requirement. R5.6.By mutual agreement between the parties,an Entity which has contracted or leased all of the Interconnected Value of a Generating Asset or Share of a Generating Asset (energy,capacity, reactive-output dispatch-ability etc.)to another Railbelt Entity,such that this particular asset appears for all intents and purposes as Generating Asset of the Lessee's (contractee's)fleet, may have that asset counted among the Lessee's generating units and the Lessee may include this unit as any other in the Lessee's fleet for purposes of calculation operating reserve allocation. An example of this is the Bradley Lake Project.AEA and at various times other project participants have contracted to have the Interconnected Value of this Generating Asset or their respective Shares of this Generating Asset assigned to one another in different forms.In each case the assignor has been relieved of the assigned project share (as the assignor's potential LSGC)and that share has been assigned to the assignee's fleet. R5.7.In an emergency,any Generator Owner,upon request by its Balancing Authority,shall supply to such Balancing Authority part or all of its Operating Reserve up to the full amount of its Available Accredited Capacity.An Entity experiencing an emergency is not required to maintain its Operating Reserve Obligation.There shall be no obligation of an Entity to supply Operating Reserve if the requesting entity is not making full use of its own Available Accredited Capacity. R6.Responsibility for Regulating Reserve R6.1.Regulating Reserve-each Balancing Authority (BA)shall provide,or contract for,Regulating Reserve as required by Section R6.2 equal to,or greater than,the Regulating Reserve Obligation of the party.Regulating Reserve may not overlap reserves dedicated for Spinning Reserve.Regulating Reserve (both up and down)is required to compensate for uncertainty in forecasting and is established during the unit commitment planning process,and as such the BA may then utilize its reserve as required during the course of the day.If a BA exhausts its Regulating Reserve,it is required to procure or commit additional reserves immediately. Available Transfer Capability (ATC)for Interconnecting Transmission lines shall recognize a component included in Transmission Reliability Margin (TRM)to allow for the delivery of Regulating Reserve between areas. R6.2.Reguhting Reserve Obligation-the Regulating Reserve Obligation for each Balancing Authority shall initially be set by the Intertie Management Committee. R6.3.On an annual basis,after the year end CPS statistics are compiled,the IMC will modify each Balancing Authority's Regulating Reserve by increasing/decreasing its current Regulating R7. R6.4. AKRES 001-1 Reserve by the %deviation in its CPS1.The Regulating Reserve Obligations so calculated will be rounded up to the nearest integer MW. The IMC reserves the right to increase/decrease a BA's Regulating Reserve or require other measures at any time due to changes in the system or repeat infractions. Spinning Reserve Components R7.1. R7.2. R7.3. R7.4. R7.5. R7.6. Spinning Reserve Obligation will be allocated to an Entity based on a combination of its Monthly Peak Hour Load (MPHL)and the Entities'Largest Single Generating Contingency (including any combination of units with a single point of interconnection forming a single contingency as further discussed in R7.6.RAS applications which have been field demonstrated to successfully mitigate the LSGC and have been approved by the IMC may be applied to reduce the magnitude of the LSGC. Spinning Reserve Largest Contingency Ratio (SRLCR):This component shall be calculated as the ratio of an individual Entities'Largest Single Generating Contingency (LSGC)as compared to the sum of the LSGC's of all the Railbelt Entities. The Largest Single Generating Contingency will be based on the actual capacity of those unit(s)subject to the single contingency (regardless of RAS applications). An example of a Generating Contingency is a combined cycle unit;the loss of the combustion turbine will precipitate the loss of both the CT as well as the waste heat unit. If entities share a unit,an entities Share of such a unit could qualify as their LSGC if they have no unit(s)that are larger. Monthly Peak Hour Load Ratio (MPHLR):This component shall be calculated at the ratio of an individual Entities'MPHL as compared to the sum of the MPHL's of all the Railbelt Entities.The MPHL of an Entity shall be defined as the Monthly Peak Hourly Load from the month I year earlier.Adjustments for permanent loss,or expected increases due to large industrial loads may be made if agreed to by the IMC.Economy sales are not counted as loads,but non-firm/interruptible loads are. Single points of interconnection,such as,but not limited to,buses,collector feeders,step-up transformers,shall be evaluated in terms of asset class.Failure rates such that the asset class is involved in a failure at a rate of once per year will validate it as a single point of interconnection as discussed in R7.1.However,subject to the reasoning above,the IMC may exercise judgment in such matters. R7.7.An entity adding a unit greater than 120 MW will accrue the obligation above 120 MW on a one for one basis in addition to its otherwise calculated spin obligation.This cap is subject to change by the IMC. R7.8.The Spinning Reserve Obligation (SRO)of each Obligated Entity shall be calculated as follows: SRO.=50%(LSGC.Y {Xi(LSGC)}*[SRB}+50%{MPHL-Y {>i(MPHL,)}*[SRB]+MUD, e=aparticular Entity C.Measures AKRES 001-1 i=All Interconnected Entities MUD.=the difference between the R7.7 max unit limit and an entities largest unit if greater than the R7.7 cap. MI.Each Obligated Entity and Balancing Authority shall maintain: MI.1.Records of their Reserve Capacity at any point in time.These records will be updated as new Assets are added and other Assets are retired.These records will be available by for review by the Balancing Authority or Compliance Monitor with 1 business week written notice. MI.2.Hourly records of Operating Reserve and Regulating Reserve (scheduled and actual)will be maintained by all Obligated Entities'.These will be made available in real-time to the Balancing Authority for archival and storage. MI1.3.The Compliance Monitor will review the performance of each Balancing Authority and Obligated Entity at least annually.More frequent reviews shall be performed if spin obligation compliance warrants such reviews. MI.4.Spin Balancing Account records will be maintained as described in Exhibit A2. D.Compliance Monitoring 1. 2. Balancing Authorities IMC-Railbelt Regional Reliability Organization E.Non-Compliance Level 1. Version History Version Date Action Change Tracking AKRES 001-1 Exhibit Al -Methodology for a varying Largest Single Generating Contingency. For the Largest Single Generating Contingency (LSGC)for the Railbelt System 1)Each Entity will electronically share their hourly expected temperature compensated largest unit's output forecast during the day-ahead scheduling process.This may not be the same unit for each hour. 2)At this time,each utility will also share data on any forecasted excess spin that the Entity may wish to sell. 3)The next day and to the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was underestimated,the Entity which provided that forecast is obligated to make up the deficit spin in real time in order to keep the system protected.This includes forecasted unit startups. 4)To the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was overestimated,the difference in spin obligation will be pro rata credited to the remaining Entities in their Spin Balancing Account (SBA).This includes forecasted unit shutdowns. For the Largest Single Generating Contingency (LSGC)for an Entity 1)To the extent that the forecasted LSGC for an Entity's real time output was underestimated,the Entity which provided that forecast is obligated to credit the remaining Entities'SBA with the difference in spin in which they over carried due to the inaccurate forecast. 2)To the extent that the forecasted LSGC for an Entity's real time output was overestimated,no adjustments to the SBA will be made. AKRES 001-1 Exhibit A2 -Spin Balancing Account A Spin Balancing Account (SBA)will be created and kept by each Balancing Authority (BA)showing Date, Hour,To,From,and Quantity. Quantities must exceed a dead band to be recorded.Quantities 2 MW or larger qualify to be recorded. The entries will primarily reflect errors in forecasting and the consequential harm (in terms of amount of spin carried)caused to the other Entities due to these errors. Entities will net out their spin obligations with others in chronological order (oldest first)but at times may need to redeem their spin via scheduling from the utility owing them spin,at no cost for the spin,and at such time the owing utility has spin excess of its needs.The owing utility has no obligation to start additional generation to provide such spin. Each quarter,a BA will be selected as being the "master”to which the other entities will compare their own records.The "master”role will be rotated. AKRES 001-1 Exhibit A3 -Geographical Spin Methodology for the handling specific issues resultant from Railbelt Geography A:Kenai A single transmission line connects the generation on the Kenai with the rest of South Central Alaska. The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Kenai Transmission Line; Not all spin originating on the Kenai can leave the Kenai; If spin can't leave the Kenai,the utilities north of the Kenai will need to make it up in order to satisfactorily protect the system; If spin can't leave the Kenai,it is inefficient to require an Entity to carry spin that can't be used; The Kenai isn't always constrained every hour; Spin originating on the Kenai can leave the Kenai; Entities on the Kenai should be required to carry their share of spin; To address this issue will require real time monitoring of the flows between the Kenai and the Anchorage Bowl.CEA has the live data which can be distributed via ICCP or equivalent.HEA/AEEC will be permitted to reduce their spin obligation (and consequently the other Entities will need to pro rata increase their spin obligation)during periods of constraint (and near constraint as appropriate).How much would need to be broadcast to all the utilities via CEA. During periods of constraint and during incidents requiring spin,both CEA and HEA/AEEC will need to monitor the Kenai Transmission Line and curtail the conversion of spin to MW if the emergency limit of the line is expected to be exceeded or is exceeded. CEA's Cooper Lake Plant may be providing spin for CEA which needs to be included in the constrained Kenai calculations.CEA may have certain rights as spelled out in the Bradley Contracts which must be upheld and are of a higher priority than these rules.HEA/AEEC has some amount of Bradley Lake Spin which generally can be expected to leave the Kenai. There may be times where the largest loss contingency in the system is the loss of the Kenai line itself. By definition,HEA/AEEC would not be able to contribute useful spin to such an incident.HEA/AEEC should be permitted to reduce their spin obligation (and consequently the other utilities will need to pro rata increase their spin obligation)so as to only cover the next largest Single Generating Unit Contingency subject to other restrictions of the Kenai Transmission line discussed above. When the Kenai is islanded,the utilities north of the Kenai shall not be permitted to count their stranded Kenai spin towards their spin obligations. AKRES 001-1 B:Interior A single transmission line connects the generation in the Interior with the rest of South Central Alaska. The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Alaska Intertie Transmission Line; Not all spin originating in South Central can leave South Central; If the System LSGC is in the interior,South Central Entities share in providing spinning reserve to cover this unit; If spin can't leave the South Central,it is inefficient to require an Entity to carry spin that can't be used; South Central Entities should not count an Interior LSGC as the Systems'largest unit during periods when the Alaska Intertie is constrained or near constrained as appropriate. The Alaska Intertie isn't always constrained every hour; Spin originating on the South Central can leave South Central; Entities in South Central should be required to carry their share of spin for an Interior System LSGC; To address this issue will require real time monitoring of the flows between the Interior and the Anchorage Bowl.AMLP has live data which can be distributed via ICCP or equivalent.South Central Entities will be permitted to reduce their spin obligation during periods of constraint (and near constraint as appropriate)to cover the next largest South Central based contingency. RRO VO vs RRO V1 CONTINGENCY RESERVES POLICY Reserve Capacity Planning Criteria A-1.1 1.1.1 1.1.2 1.1.3 Each Load Serving Entity is expected to maintain responsibility to provide capacity for ts own firm load.As part of such responsibility,the Load Serving Entity shall maintain or otherwise provide for annually,Accredited Capacity,in an amount equal to or greater than its maximum System Demand for such year plus the Load Serving Entity's Reserve Capacity Obligation,as set forth in Subsection A-1.1.2. The Reserve Capacity Obligation of a Load Serving Entity,for any year,_shall be equal to thirty (30)percent of the projected Annual System Demand for that year for that Load Serving Entity.The Reserve Capacity Obligation of the Load Serving Entity may be adjusted from time to time by the Regional Reliability Organization. The Regional Reliabiity Organization may determine the annual Accredited Capacity for each Load Serving Entity. Responsibility for Operating Reserve B-2.1 2.1.1 Operating Reserve Each Load Serving Entity and/or Generation Owner shall provide,or contract for,Spinning Reserve and Non--Spinning Reserve as required by Section B-22 equal to or greater than the Operating Reserve Obligation of the entity.As soon as practicable,but not to exceed four hours,after the occurrence of an incident which uses Operating Reserves, each entity shall restore its Operating Reserve Obligation. Operating Reserves,Operating Reserve Obligation,System Reserve Basis and allocation calculations may be modified or changed by the Regional Reliability Organization. The System Reserve Basis (SRB)is equal to the Largest Generating Unit Contingency of the System as_defined in Exhibit _A1_or other such value_such as loss of a transmission line,as determined by engineering studies and approved by the RRO. RROCONTINGENCY RESERVES POLICY such as,but not limited to,buses,collector feeders,step-up transformers,shall be evaluated in terms of asset class.Failure rates such that the asset class is involved in a failure at_a rate of once per year will validate it as a single point of interconnection as discussed above.However,subject to the reasoning above,the Regional Reliability Organization may exercise judqment_in such matters. An entity adding a unit whose LGUCLSGCxs greater than a 20 MW-SRB-eapwill accrue the obligation above 20 MW on a one for one basis in addition to its otherwise calculated spin obligation.This cap is subject to change by the RRO. B-22 Total Operating Reserve Obligation 2.2.1.The Total Operating Reserve Obligation at any time shall be an amount equal to 60 percent of the System Reserve Basis of the Railbelt Electric Grid 2.2.1.1 The Spinning Reserve portion of the Total Operating Reserve Obligation shall not be less than an amount equivalentto 100 percent efheof the System Reserve Basis. 2.2.1.2 The balance of the Total Operating Reserve Obligation shall be maintained with Non-Spinning Reserve. 2.2.2.Generating unit capability for Operating Reserves shall be determined by the following criteria: a.k shall not be less than the load on the machine at any particular time nor greater than (b)below. b.t shall not exceed that maximum amount of load (MW)that the unit is capable of continuously supplying for a two-hour period,or quickly,through action of automatic governor contros. Page 42of 56 RROCONTINGENCY RESERVES POLICY 2.2.3 The criteria specified in this section may be modified or changed by the Regional Reliability Organization. B-23 Allocation of Operating ReservesReserve Obligations Page 43 0f 56 RROCONTINGENCY RESERVES POLICY 2.3.1 The Operating Reserve Obligation of ateadServingan Entity shall be that percentage of B-2-4 2.4.1 2.4.2 2.4.3 2.4.4 2.4.5 2.4.6 the Total Operating Reserve Obligation determined by the Regional Reliability Organization in accordance with the formulas described in exhibits BIB1,B2 and exhibit B3A3. Operating Reserve Calculation A-tead ServiagAn Entity's Spinning Reserve shall be calculated at any given instant as the difference between the sum of the net capability of all generating units on line in the respective entity and the integrated Systems Demand of the system involved and other sources (for example,SILOS and BESS)or declared restrictions on spinning reserve (for example,Bradley Lake or tie line restrictions)as accepted by the Regional Reliability Organization. A-Lead-ServingAn Entiy's Spinning Reserve may be satisfied by an automatically controlled load shedding program.The bad shedding program shall assure that controlled load can be dropped to meet the requirement of Spinning Reserve in such a manner as to maintain system stability and not cause degradation or cascading effects inthe Railbelt system. The Regional Reliabilty Organization may establish procedures to assure that the Operating Reserve -of-an entity is available on the Railbelt System at all times. Whenever an entity is unable to meet ts Operating Reserve Obligation,thatthe entity will,within two hours,advise its Balancing Authority and make arrangements to restore ts Operating Reserve Obligation. Prudent Utility Practices shall be followed in distributing Operating Reserve,_taking into account effective utilization of capacity inan emergency,time required to be effective, transmission limitations and local area requirements.__Geographical_constraints and remedies are defined in Exhibit A3. A-LeadSeringSubject to 2.4.4 above,an Entity may arrange for one or more other entities to supply part of,or its entire,Operating Reserve requirement-. By_mutual agreement between the parties,an Entity which has contracted or leased all of the Interconnected Value _of_a Generating Asset or Share of a Generating Asset (energy,capacity,reactive-output dispatch-ability etc.)to another Railbelt Entity,such that this particular asset_appears for all intents and purposes as Generating Asset of the Lessee's (contractee's)fleet,may have that asset counted among the Lessee's generating units and the Lessee may include this unit as any other in the Lessee's fleet for purposes of calculation operating reserve allocation, Page 440f 56 RROCONTINGENCY RESERVESPOLICY An example of this is the Bradley Lake Project.AEA and at various times other project_participants have contracted to have the Interconnected Value of this Generating Asset or their respective Shares of this Generating Asset assigned to one another in different forms.In each case the assignor has been relieved of the assigned project share (as the assignor's potential LSGC)and that share has been assigned to the assignee's fleet. 2462.4.7 In an emergency,any Generator Owner,upon request by its Balancing Authority,shall supply to such Balancing Authority part or all of its Operating Reserve up to the full amount of ts Available Accredited Capacity.Atead-SeringAn Entity experiencing an emergency is not required to maintain its Operating Reserve Obligation.There shall be no obligation of an entityEntity to supply Operating Reserve if the requesting entity isnot makingfullmaking full use of its own Available Accredited Capacity. Page 450f 56 RROCONTINGENCY RESERVES POLICY Cc Responsibility for Regulating Reserve C-3.1 Regulating Reserve 3.1.1 Each Balancing AuthertyAuthoriy (BA})shall provide,or contract for,Regulating C-3.2 3.2.1 3.2.2 3.2.3 Reserve as required by Section C-3.2 equal to or greater than the Regulating Reserve Obligation of the party.Regulating Reserve may not overlap reserves dedicated for Spinning Reserve.Regulating Reserve (both up and down)is required to compensate for uncertainty in ferecastingforecasting and is established during the unit commitment planning process,and as such the BA may then utilize its reserve as required during the course of the day.f a BA exhausts its Regulating Reserve,it is required to procure or commit additional reserves immediately. Regulating Reserve Obligation The Regulating Reserve Obligation for each Balancing Authority shall initially be set by the Regional Reliabilty Organization. On an annual basis,after the year end CPS statistics are compiled,the Regional Reliability Organization will modify each Balancing Autherty'sAuthority's Regulating Reserve by increasing/decreasing its current Regulating Reserve by the %deviation in its CRSICPS1. The Regulating Reserve ebligationsObligations so calculated will be rounded up to the nearest integer MW. The Regional Reliability Organization reserves the right to increase/decrease a BA's Regulating Reserve or require other measures at any time due to changes in the system or repeat infractions._Spin Balancing Account records will be maintained as described in Exhibit A2. Page 46 of 56 RROCONTINGENCY RESERVES POLICY v001 Page 47 of 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit BI:Spinning Reserve Components Spinning Reserve Obligation will be allocated to the-LeadSendagan Entity based on a combination of its Monthly Peak Hour Load (MPHL)and the Entities'Largest Single Generating Contingency (including any combination of units with a single point of interconnection forming a single contingency as further discussed in 2.1.3.RAS applications which have been field demonstrated to successfully mitigate the LSGC and have been approved by the RRO may be applied to reduce the magnitude of the LSGC. Monthly Peak HourLoad {MHPL Spinning Reserve Largest Contingency Ratio (SRLCR):This component shall be calculated as the ratio of an entity's MRHLindividual Entities'Largest Single Generating Contingency (LSGC)as compared to the Rern-ceincident MPHLEsum of the LSGC's of all the Railbelt-_ Entities. The Largest Single Generating Contingency will be based on the actual capacity of those unit(s)subject to the single contingency (regardless of RAS applications).An example of a Generating Contingency is a combined cycle unit:the loss of the combustion turbine will precipitate the loss of both the CT as well as the waste heat unit. If entities share a unit,an entities Share of such a unit could qualify as their LSGC if they have no unit(s) that are larger. Monthly Peak Hour Load Ratio (MPHLR):This component shall be calculated at the ratio of an individual Entities'MPHL as compared to the sum of the MPHL's of all the Railbelt Entities.The MPHL of an entity isEntity shall be defined as the measured MPHLEset-erMonthly Peak Hourly Load from the-eurrent month ere year earlier.Adjustments for permanent loss,_or expected increases due to large industrial bads may be madeif agreed to by the RRO.Economy sales are not counted as bads,but non-firm/interruptible loads are. SpinMPHLe =MPHLe H(MPHL-)[o>]Page 480f 5 RROCONTINGENCY RESERVESPOLICY v001 Exhibit B2:Spinning Reserve Obligation Spinning Reserve Obligation for aLeadServiagan Entity will be calculated summingthe weighted Spinning Reserve Components of each entity,and multiplyingthis by the System Reserve Basis as follows: __SROc=A*SpinMPHLe*=50%{LSGCei/{Fi (LSGC)}[SRB-*]+50%{MPHLe/{5i (MPHL)}ISRB]+MUDe Where-_e =a particular Entity i=All Interconnected Entities MUDe-i6-=the difference between the.2.1 3 max unit delta-flimit and an entities largest unit if any)forthat- Page 49 of 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit B3:Spinning Reserve Criteria In order to be counted as a producer of Spinning Reserve,the net response regardless of methods used (generator,SILOS,BESS,duct firing,etc.)must be able to meet the felewingfollowng minimum performance based-criteria: Initial response-:movement within 2 seconds- 30 second response:50%usage ofits reported spin capability 60secondresponse:75%usage ofits reported spin_capability Osecondresponse:100%usage ofits reported spin_capability >Page 500f5 RROCONTINGENCY RESERVES POLICY v001 Exhibit A1 -Methodology for a varying Largest Single Generating Contingency. For the Largest Single Generating Contingency (LSGC}for the Railbelt System 1)Each Entity will electronically share their hourly expected temperature compensated largest unit's output forecast during the day-ahead scheduling process.This may not be the same unit for each hour. 2)Atthis time,each utility will also share data on any forecasted excess spin that the Entity may wish to sell. 3)The next day and to the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was underestimated,the Entity which provided that forecast is obligated to make up the deficit spin in real time in order to keep the system protected.This includes forecasted unit startups. 4)__To the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was overestimated,the difference in spin obligation will be pro rata credited to the remaining Entities in their Spin Balancing Account (SBA).This includes forecasted unit shutdowns, For the Largest Single Generating Contingency (LSGC)for an Entity 1)To the extent that the forecasted LSGC for an Entity's real time output was underestimated,the Entity which provided that forecast is obligated to credit the remaining Entities'SBA with the difference in spin in which they over carried due to the inaccurate forecast. 2)To the extent that the forecasted LSGC for an Entity's real time output was overestimated,no adjustments to the SBA will be made. Page 51 of 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit A2 -Spin Balancing Account A Spin Balancing Account {SBA)will be created and kept by each Balancing Authority (BA)showing Date, Hour,To,From,and Quantity. Quantities must exceed a dead band to be recorded.Quantities 2 MW or larger qualify to be recorded. The entries will primarily reflect errors in forecasting and the consequential harm (in terms of amount of spin carried)caused to the other Entities due to these errors. Entities will net out their spin obligations with others in chronological order (oldest first)but at times may need to redeem their spin via scheduling from the utility owing them spin,at no cost for the spin, and at such time the owing utility has spin excess of its needs.The owing utility has no obligation to start additional generation to provide such spin. Each quarter,a BA will be selected as being the "master”to which the other entities will compare their own records.The "master”role will be rotated.anPage 520f 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit A3 -Geographical Spin Methodology for the handling specific issues resultant from Railbelt Geography A:Kenai A single transmission line connects the generation on the Kenai with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Kenai Transmission Line; Not all spin originating on the Kenai can leave the Kenai: if spin can't leave the Kenai,the utilities north of the Kenai will need to make it up in order to satisfactorily protect the system; if spin can't leave the Kenai,it is inefficient to require an Entity to carry spin that can't be used; The Kenai isn't always constrained every hour; Spin originating on the Kenai can leave the Kenai: Entities on the Kenai should be required to carry their share of spin: To address this issue will require real time monitoring of the flows between the Kenai and the Anchorage Bowl.CEA has the five data which can be distributed via ICCP or equivalent. HEA/AEEC will be permitted to reduce their spin obligation (and consequently the other Entities will need to pro rata increase their spin obligation)during periods of constraint {and near constraint as appropriate).How much would need to be broadcast to all the utilities via CEA. During periods of constraint and during incidents requiring spin,both CEA and HEA/AEEC will need to monitor the Kenai Transmission Line and curtail the conversion of spin to MW if the emergency limit of the line is expected to be exceeded or is exceeded. CEA's Cooper Lake Plant may be providing spin for CEA which needs to be included in the constrained Kenai calculations.CEA may have certain rights as spelled out in the Bradley Contracts which must be upheld and are of a higher priority than these rules.HEA/AEFC has some amount of Bradley Lake Spin which generally can be expected to leave the Kenai. There may be times where the largest loss contingency in the system is the loss of the Kenai line itself.By definition,HEA/AEEC would not be able to contribute useful spin to such an incident. HEA/AEEC should be permitted to reduce their spin obligation (and consequently the other utilities will need to pro rata increase their spin obligation)so as to only cover the next largest Single Generating Unit Contingency subject to other restrictions of the Kenai Transmission fine discussed above. Page 53 0f 66 RROCONTINGENCY RESERVESPOLICY v001 When the Kenai is islanded,the utilities north of the Kenai shall not be permitted to count their stranded Kenai spin towards their spin obligations. B:Interior A single transmission line connects the generation in the Interior with the rest of South Central Alaska.The fine is constrained at times due to stability limits.The following issues should be addressed. Constrained Alaska Intertie Transmission Line: Not all spin originating in South Central can leave South Central: if the System LSGC is in the interior,South Central Entities share in providing spinning reserve to cover this unit: If spin can't leave the South Central,it is inefficient to require an Entity to carry spin that can't be used; South Central Entities should not count an Interior LSGC as the Systems'largest unit during periods when the Alaska Intertie is constrained or near constrained as appropriate. The Alaska Intertie isn't always constrained every hour; Spin originating on the South Central can leave South Central: Entities in South Central should be required to carry their share of spin for an Interior System LSGC; To address this issue will require real time monitoring of the flows between the Interior and the Anchorage Bowl.AMLP has live data which can be distributed via ICCP or equivalent.South Central Entities will be permitted to reduce their spin obligation during periods of constraint (and near constraint as appropriate)to cover the next largest South Central based contingency.(64)Page 540f 56 AKRES-001 vs AKRES-000 A.Introduction 1.Title:Reserve Obligation and Allocation 2.Number:AKRES-001-91 3.Purpose: This standard describes Reserve Obligations for all Entities interconnected to the Railbelt Grid. 4.Applicability: 4.1.Balancing Authorities 4.2.Load Serving Entities 4.3.Generation Owners (Generation Asset Owning Entities) 5.Effective Date:TBD B.Requirements RI.Reserve Capacity Requirement R2. R11.Each Load Serving Entity is expected to maintain responsibility to provide capacity for its own finnfirm load.As part of such responsibility,the Load Serving Entity shall maintain or otherwise provide for annually,Accredited Capacity,in an amount equal to or greater than its maximum System Demand for such year plus the Load Serving Eatities-Entity's Reserve Capacity Obligation,as set forth in Subsection R1.2. R12.The Reserve Capacity Obligation of a Load Serving Entity,for any year,shall be equal to thirty (30)percent of the projected Annual System Demand for that year for that Load Serving Entity.The Reserve Capacity Obligation ofthe Load Serving Entity may be adjusted from time to time by the Intertie Management Committee (IMC)). RI.3.The IMC may determine the annual Accredited Capacity for each Load Serving Entity. Responsibility for Operating Reserve R2.1.Each Load Serving Entity and/or Generation Owner shall provide,or contract for, Spinning Reserve and Non-Spinning Reserve as required by Section R3 equal to or greater than the Operating Reserve Obligation of the entity.As soon as practicable,but not to exceed four hours,after the occurrence of an incident which uses Operating Reserves,each entity shall restore its Operating Reserve Obligation. R22.Operating Reserves,Operating Reserve Obligation,System Reserve Basis and allocation calculations may be modified or changed by the Intertie Management Committee. R2.3.The System Reserve Basis (SRB)is equal to the Largest Generating Unit Contingency of the systeraSystem as defined in Exhibit Al or other such value such as loss of a transmission Jine,as determined by engineering studies and approved by the IMC. AKRES-001 vs AKRES-000 R3.Total Operating Reserve Obligation R3.1.The Total Operating Reserve Obligation at any time shall be an amount equal to 150 percent of the SRBSystem Reserve Basis of the Railbelt Electric Grid. R3.2.The Spinning Reserve portion of the Total Operating Reserve Obligation -shall not be less than an amount equivalent to 100percent of the SRB-System Reserve Basis. R3.3.The balance of the Total Operating Reserve Obligation shall be maintained with Non-Spinning Reserve-eka-Nen-Operating Reserves}. R4.Generating Unit Capability- Generating unit capability for eperatingreserveOperating Reserve shall be determined by the following criteria: R4.1.Itshall not be less thatthan the load on the machine at any particular time nor greater than R42 below R4.2.Itshall not exceed that maximum amount efleadof load (MW)that the unit is capable of continuously supplying for a two-hour period,or quickly,through action of automatic governor controls. R4.3_In order to be counted _as a producer of Spinning Reserve,the net response regardless of methods used (generator,SILOS,BESS,duct firing,etc.)must be able to meet the following minimum performance based criteria: Initial response:movement within 2 seconds 30 second response:50%usage of its reported spin capability 60 second response:75%usage of its reported spin capability <2 222.=--:2- 120 second response:100%usage of its reported spin capability R4.4.The criteria specified in this section may be modified or changed by the Intertie Management -Committee. RSRS5.Allocation of Operating Reserve Obligations The Operating Reserve Obligation of an Obligated-Entity shall be that percentage of the Total Operating Reserve ebligatienObligation determined by the IMC in accordance with the formulas described in R5 through R7 RSRS.1.An Entities'Entity's Spinning Reserve shall be calculated at any given instant as the difference between the sum of the net capability of all generating units on line in the respective entity and the integrated Systems Demand of the system involved and other sources (for example,SILOS and BESS)or declared restrictions on spinning reserve (for example,Bradley Lake or tie line restrictions)as accepted by the IMC RSR5.2.An Entities'Entity's Spinning Reserve may be satisfied by an automatically controlled load shedding program.The load shedding program shall assure that AKRES-001 vs AKRES-000 controlled load can be dropped to meet the requirement of Spinning Reserve in such a manner as to maintain system stability and not cause degradation or cascading effects in the Railbelt system.-FheIMC-shall review-and-apprevethe RSRS5.3.The IMC may establish procedures to assure that the Operating Reserve of an entity is available on the Railbelt System at all times.Whenever an entity is unable to meet its Operating Reserve Obligation,thatthe entity will,within two AKRES-001 vs AKRES-000 hours,advise its Balancing Authority and make arrangements to restore its Operating Reserve Obligation. RSR5.4.Prudent Utility Practices shall be followed in distributing Operating -Reserve, taking into account effective utilization of capacity in an emergency,Respense Ratetime required to be effective,transmission limitations and local area requirements.Available Transfer Capability (ATC)shall include a component (Capacity Benefit Margin)recognizing the need to move reserves between areas. Geographical constraints and remedies are defined in Exhibit A3. R5.5.Subject to R5.3 above,an entityEntity may arrange for one or more other entities to supply part of,or its entire,Operating Reserve requirement. RSRS5.6.By mutual agreement between the parties,an Entity which has contracted or leased all of the Interconnected Value of a Generating Asset or Share of a Generating Asset (energy,capacity,reactive-output dispatch-ability etc.)to another Railbelt Entity,such that this particular asset appears for all intents and purposes as Generating Asset of the Lessee's (contractee's)fleet,may have that asset counted among the Lessee's generating units and the Lessee may include this unit as any other in the Lessee's fleet for purposes of calculation operating reserve allocation. An example of this is the Bradley Lake Project.AEA and at various times other project participants have contracted to have the Interconnected Value of this Generating Asset or their respective Shares of this Generating Asset assigned to one another in different forms.In each case the assignor has been relieved of the assigned project share (as the assignor's potential LSGC)and that share has been assigned to the assignee's fleet. RSR5.7.In an emergency,any Generator Owner,upon request by its Balancing Authority-teither-threugh--automated-frequency_or-_voltage_feedback_or-via SystemOperaterintervention);,shall supply to such Balancing Authority part or all of its Operating Reserve up to the full amount of its Available Accredited Capacity.An Entity experiencing an emergency is not required to maintain its Operating Reserve Obligation.There shall be no obligation of an Entity to supply Operating Reserve if the requesting entity is not making full use of its own Available Accredited Capacity. R6.Responsibility for Regulating Reserve R6.1.Regulating Reserve-each Balancing Authority (BA)shall provide,or contract for, Regulating Reserve as required by Section R6.2 equal to,or -greater -than,the Regulating Reserve Obligation of the party.Regulating Reserve may-not overlap reserves dedicated for Spinning Reserve.Regulating Reserve (both up and down) is required to compensate for uncertainty in forecasting and is established during the unit -commitment planning process,and as such the BA may then utilize theirits reserve as required during the course of the day.Halfa BA exhausts its Regulating Reserve,they-areit_is required to procure or commit additional reserves -immediately.-Available -Transfer -Capability ATC)-for R7. AKRES-001 vs AKRES-000 _Interconnecting Transmission lines shall recognize a component included in Transmission Reliability Margin (TRM)to allow for the delivery of Regulating Reserve between areas. R6.2.ReguiatingReguhting Reserve Obligation-the Regulating Reserve Obligation for each Balancing Authority shall initially be set by the -Intertie -Management S rr G mo o wicere R6.3.On an annual basis,after the year end CPS -statistics are compiled,the IMC shaliwill modify each Balancing Autherities'Authority's Regulating Reserve by increasing/decreasing its current Regulating Reserve by the %deviation in its GPSICPS1.The Regulating Reserve ebligationsObligations so calculated will be rounded up to the nearest integer MW. R6.4.The IMC reserves the right to increase/decrease a BAL'sBA's Regulating Reserve or require other measures at any time due to changes in the system or repeat "infractions. Spinning Reserve Components R7.1.Spinning Reserve Obligation will be allocated to an Entity -based -on a combination of its Monthly Peak Hour Load (MPHIL)and the EntitiesEntities'Largest Single Generating Contingency (including any combination of units with a single point of interconnection forming a single contingency-_as further discussed in R7.6.RAS applications which have been field demonstrated to successfully mitigate the LSGC and have been approved by the IMC may be applied to reduce the magnitude of the LSGC. R7.2.Spinning Reserve Largest Contingency Ratio (SRLCR):This component shall be calculated as the ratio of an individual Entities'Largest Single Generating Contingency (LSGC)as compared to the sum of the LSGC's of all the Railbelt Entities. R7.3.The Largest Single Generating Contingency will be based on the maximum Deelared-Capabilityactual capacity of those unit(s)subject to the single contingency (regardless of RAS applications;-when-eperated-at-the empe ature-cerrespendine te the averace month =). An example of a Generating Contingency is a combined cycle unit;the loss of the combustion turbine will precipitate the loss of both the CT as well as the waste heat unit. R7.4.If entities share a unit,an entities Share of such a unit could qualify as their LSGC if they have no unit(s)that are larger._Fhis-compenent-may-change AKRES-001 vs AKRES-000 R7.5.Monthly Peak Hour Load Ratio (MPHLR):This component shall be calculated at the ratio of an individual Entities”MPHL as compared to the sum of the MPHL's of all the Railbelt Entities.The MPHL of an Entity shall be defined as the Monthly Peak Hourly Load from the month 1 year earlier.Adjustments for permanent loss,or expected increases due to large industrial loads may be made if agreed to by the IMC.Economy sales are not counted _as loads,but non- firm/interruptible loads are. R7.6.Single points ofinterconnection,such asthe remainder-ofthe Spinning Reserve-centributien_efthe-particularunit(s}itis-_auementine-It,but not limited to,"buses.collector feeders,step-up transformers,shall be the obligation of the- bus feuks or multiple units on-that the asset+class iis"involved iina1 failure at a rate ofonceperyearwillvalidateitasasinglecolisetorfeeder_may be considered a6 an point ofof failure_in-a_fuel_supply that-may seseltinterconnection asas discussed iin theless-of.multiple -units-dees-not_necessarily-constitute-a_LSGC.R7.L.1.However,subject to the reasoning above,the IMC may exercise judgment in such matters. R+.&R7.7.An entity adding a unit greater than 120 MW will accrue the obligation above 120 MW ona one for one basis in addition to theizits otherwise calculated spin obligation.Fae-aferementioned120 MWThis cap is subject to change by the IMC. R+9:R7.8.The Spinning Reserve Obligation (SRO)of each Obligated Entity shall be calculated as follows: SRO.=-LSGEC-SHEHESGE-50%LSGCY {i (LSGC)}*[SRBH-50%{MPHL.Y{5} (MPHL)}*[SRB]+MUD- e= Obi a particular Entity i=All Interconnected Entities MUD.=the difference between the R7.7 max unit limit and an entities largest unit if greater than the R7.7 limitcap. C.Measures Ml.Each Obligated Entity and Balancing Authority shal!maintain: ML1.Records of their Reserve Capacity at any point in time.These records will be updated as new Assets are added and other Assets are retired.These records will be available by for review by the Balancing Authority or Compliance Monitor with 1 business week written notice. AKRES-001 vs AKRES-000 MI.2.Hourly records of Operating Reserve and Regulating Reserve (scheduled and actual)will be maintained by all Obligated Entities'.These will be made available in real-time to the Balancing Authority for archival and storage. MI1.3.The Compliance Monitor will review the perfennanceperformance of each Balancing Authority and Obligated Entity at least annually.More frequent reviews shall be performed if spin obligation compliance warrants such reviews. MI.4.Spin Balancing Account records will be maintained as described in Exhibit A2. Compliance Monitoring 1.Balancing Authorities AKRES-001 vs AKRES-000 2.IMC-Railbelt Regional Reliability Organization E.Non-Compliance. E.Level 1. MVersten History Version Histor y Version Date Action Change Tracking AKRES-001 vs AKRES-000 Exhibit A1 -Methodology for a varying Largest Single Generating Contingency. For the Largest Single Generating Contingency ({LSGC)for the Railbelt System 1)Each Entity will electronically share their hourly expected temperature compensated largest unit's output forecast during the day-ahead scheduling process.This may not be the same unit for each hour. 2)At this time,each utility will also share data on any forecasted excess spin that the Entity may wish to sell. 3)The next day and to the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was underestimated,the Entity which provided that forecast is obligated to make up the deficit spin in real time in order to keep the systemprotected.This includes forecasted unit startups. 4)To the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was overestimated, the difference in spin obligation will be pro rata credited to the remaining Entities in their Spin Balancing Account (SBA).This includes forecasted unit shutdowns. For the Largest Single Generating Contingency (LSGC)for an Entity 1)To the extent that the forecasted LSGC for an Entity's real time output was underestimated,the Entity which provided that forecast is obligated to credit the remaining Entities'SBA with the difference in spin in which they over carried due to the inaccurate forecast. 2)To the extent that the forecasted LSGC for an Entity's real time output was overestimated,no adjustments to the SBA will be made. AKRES-001 vs AKRES-000 Exhibit A2 -Spin Balancing Account A Spin Balancing Account (SBA)will be created and kept by each Balancing Authority (BA)showing Date,Hour,To, From,and Quantity. Quantities must exceed a dead band to be recorded.Quantities 2 MW or larger qualify to be recorded. The entries will primarily reflect errors in forecasting and the consequential harm (in terms of amount of spin carried) caused to the other Entities due to these errors. Entities will net out their spin obligations with others in chronological order (oldest first)but at times may need to redeem their spin via scheduling from the utility owing them spin,at no cost for the spin,and at such time the owing utility has spin excess of its needs.The owing utility has no obligation to start additional generation to provide such spin. Each quarter,a BA will be selected as being the "master”to which the other entities will compare their own records. The "master”role will be rotated. AKRES-001 vs AKRES-000 Exhibit A3 -Geographical Spin Methodology for the handling specific issues resultant from Railbelt Geography A:Kenai A single transmission line connects the generation on the Kenai with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Kenai Transmission Line; Not all spin originating on the Kenai can leave the Kenai; if spin can't leave the Kenai,the utilities north of the Kenai will need to make it up in order to satisfactorily protect the system; If spin can't leave the Kenai,it is inefficient to require an Entity to carry spin that can't be used; The Kenai isn't always constrained every hour; Spin originating on the Kenai can leave the Kenai; Entities on the Kenai should be required to carry their share of spin: To address this issue will require real time monitoring of the flows between the Kenai and the Anchorage Bow!.CEA has the live data which can be distributed via ICCP or equivalent.HEA/AEEC will be permitted to reduce their spin obligation (and consequently the other Entities will need to pro rata increase their spin obligation)during periods of constraint (and near constraint as appropriate).How much would need to be broadcast to all the utilities via CEA. During periods of constraint and during incidents requiring spin,both CEA and HEA/AEEC will need to monitor the Kenai Transmission Line and curtail the conversion of spin to MW if the emergency limit of the line is expected to be exceeded or is exceeded. CEA's Cooper Lake Plant may be providing spin for CEA which needs to be included in the constrained Kenai calculations.CEA may have certain rights as spelled out in the Bradley Contracts which must be upheld and are of a higher priority than these rules.HEA/AEEC has some amount of Bradley Lake Spin which generally can be expected to leave the Kenai. There may be times where the largest loss contingency in the system is the loss of the Kenai line itself.By definition,HEA/AEEC would not be able to contribute useful spin to such an incident.HEA/AEEC should be permitted to reduce their spin obligation (and consequently the other utilities will need to pro rata increase their spin obligation)so as to only cover the next largest Single Generating Unit Contingency subject to other restrictions of the Kenai Transmission line discussed above. When the Kenai is islanded,the utilities north of the Kenai shall not be permitted to count their stranded Kenai spin towards their spin obligations. AKRES-001 vs AKRES-000 B:Interior A single transmission line connects thegeneration in the Interior with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Alaska Intertie Transmission Line; Not all spin originating in South Central can leave South Central: if the System LSGC is in the interior,South Central Entities share in providing spinning reserve to cover this unit; If spin can't leave the South Central,it is inefficient to require an Entity to carry spin that can't be used; South Central Entities should not count an Interior LSGC as the Systems'largest unit during periods when the Alaska Intertie is constrained or near constrained as appropriate. The Alaska intertie isn't always constrained every hour; Spin originating on the South Central can leave South Central; Entities in South Central should be required to carry their share of spin for an Interior System LSGC; To address this issue will require real time monitoring of the flows between the Interior and the Anchorage Bowl.AMLP has live data which can be distributed via ICCP or equivalent.South Central Entities will be permitted to reduce their spin obligation during periods of constraint (and near constraint as appropriate)to cover the next largest South Central based contingency. IMC vs RRO CONTINGENCY RESERVES POLICY A Reserve Capacity RequirementPlanning Criteria A-1.1 1.1.1 Rbk4+-E£ach Load Serving Entiy is expected to maintain responsibility to provide capacity for ts own firm load.-As part of such responsibility,the Load Serving Entity shall maintain or otherwise provide for annually,Accredited Capacity,in an amount equal to or greater than its maximum System Demand for such year plus the Load Serving Entity'sEntity's Reserve Capacity Obligation,as set forth in Subsection R4A-1.1.2. 1.1.2 The Reserve Capacity Obligation ofa Load Serving Entity,for any year,shall be equal to thirty (30)percent of the projected Annual System Demand for that year for that Load Serving Entity.-The Reserve Capacity Obligation of the Load Serving Entity may be adjusted from time to time by the IntetieManagementCommitteeHMC}Regional Reliability Organization. 1.1.3.The MGRegional Reliability Organization may determine the annual Accredited Capacity for each Load Serving Entity. Responsibility for Operating Reserve B R2 B-2.1-___OperatingReserve 2.1.1__Each Load Serving Entity and/or Generation Owner shall provide,or contract for,Spinning Reserve and Non--Spinning -Reserve as required by Section R3B-22 equal to or greater than the Operating Reserve Obligation of the entity.As soon as practicable,but not to exceed IMC vs RRO four hours,after the occurrence of an incident which uses Operating Reserves,each entity shall restore its Operating Reserve Obligation. Roa 2.1.2 Operating Reserves,Operating Reserve Obligation,System Reserve Basis and allocation calculations may be modified or changed by the tatertie-Management-CommitteeRegional Reliability Organization. R23- 2.1.3___The System Reserve Basis (SRB)is equal to the Largest Generating Unit Contingency of the System as defined in Exhibit A1 or other such value such as loss of a transmission line, as determined by engineering studies and approved by the #MGRRO. ingle points of interconnection,such as not limited tl r feeder -up transformer. hall be evaluated in terms of asset class.Failure rates such that th lass is involved in a failur f onc r r will validate i a sing!int of interconnection as discus RROCONTINGENCY RESERVES POLICY v001 ;.above.However,subject to the reasoning above,the Regional Reliability Organization may exercise judgment_in such matters. An entity adding a unit whose LSGC 5 greater than a 20 MW will accrue the obligation above 20 MW _ona one for one basis in addition to ts otherwise calculated spin obligation.This cap s subject to change bythe RRO. B-22 Total Operating Reserve Obligation 2.2.1__The Total Operating Reserve Obligation at any time shall be an amount equal to 0 percent of the System Reserve Basis of the Railbelt Electric Grid- R327 2.2.1.1 The Spinning Reserve portion of the Total Operating Reserve Obligation shall not be less than an amount equivalent to 100 percent of the System Reserve Basis. R373-- 2.2.1.2 The balance of the Total Operating Reserve Obligation shall be maintained with Non-Spinning Reserve. R4--C tine -Unit Capabili 2.2.2__Generating unit capability for Operating ReserveReserves shall be determined by the following criteria: a.R4-4-K shall not be less than the load on the machine at any particulartimenorgreaterthanR4-2(b)below. b.R4-2-I shall not exceed that maximum amount of lad (MW)that the uni is capable of continuously supplying for a two-hour period.or quickly,through action of automatic governor contro'. 2.2.3__R4:4-The _criteria_specified_in this section may_be,modified or changed _by the fatertietianagement Committee Regional Reliability Organization. Page 3of 56 RROCONTINGENCY RESERVESPOLICY v001 oo.B-23 Allocation of Operating Reserve Obligations 2.3.1 The Operating Reserve Obligation of an Entity shall be that percentage of the Total Operating Reserve Obligation determined by the #4GRegional Reliability Organization in accordance with the formulas described in R5threugh RZexhibis B1 B2 and exhibit A3. B-2-4___Operating Reserve Calculation 2.4.1 An Entity'sEntity's Spinning Reserve shall be calculated at any given instant as the difference between the sum of the net capability of all generating units on line in the respective entity and the integrated Systems Demand of the system involved and other sources (for example,SILOS and BESS)or declared restrictions on spinning reserve (for example,Bradley Lake or tie line restrictions)as accepted by the /MCRegional Reliability Organization. 2.4.2__An Entity's Spinning Reserve may be satisfied by an automatically controlled load shedding program.The bad shedding program shall assure that controlled lad can be dropped to meet the requirement of Spinning Reserve in such a manner as to maintain system stability and not cause degradation or cascading effects inthe Railbelt system. 2.4.3 The $4GRegional Reliabilty Organization may establish procedures to assure that the Operating Reserve of an entity _is available on the Railbelt System _at _all times.Whenever an entity is unable to meet is Operating Reserve Obligation,the entity will,within two hours,advise its Balancing Authority and make arrangements to restore its Operating Reserve Obligation. 2.4.4 Prudent Utility Practices shall be followed in distributing Operating Reserve,taking into account effective utilization of capacity inan emergency,time required to be effective, transmission limitations and local area requirements.ra teble Hanster Capability 440)reserves_between_areas-Geographical constraints "and remedies are defined iin Exhibit A3. 2.4.5 Subject to R5-32.4.4 above,an Entity may arrange for one or more other entities to supply part of,or its entire,Operating Reserve requirement. 2.4.6 R5.6-By mutual agreement between the parties,an Entity which has contracted or leased all of the Interconnected Value of a Generating Asset or Share ofa Generating Asset (energy,capacity,reactive-output dispatch-ability etc.)to another Railbelt Entity,such that this particular asset appears for all intents and purposes as Generating Asset of the Lessee's (contractee's)fleet,may have that asset counted among the Lessee's generating units and the Lessee may include Page 40f 56 RROCONTINGENCY RESERVESPOLICY v001 R5.7- this unit as any other in the Lessee's fleet for purposes of calculation operating reserve allocation. An example of this is the Bradley Lake Project.AEA and at various times other project participants have contracted to have the Interconnected Value of this Generating Asset or their respective Shares of this Generating Asset assigned to one another in different forms.In each case the assignor has been relieved of the assigned project share (as the assignor's potential LSGC)and that share has been assigned to the assignee's fleet. 2.4.7_In an emergency,any Generator Owner,upon request by its Balancing Authority,shall supply to such Balancing Authority part or all of its Operating Reserve up to the full amount of its Available Accredited Capacity.An Entity experiencing an emergency is not required to maintain its Operating Reserve Obligation.There shall be no obligation of an Entity to supply Operating Reserve if the requesting entity isnot making full use of its own Available Accredited Capacity. R6-Responsibility for Regulating Reserve Cc R6_C-3.1-_Regulating Reserve- R6C-3.2- 3.1.1 Each Balancing Authorty (BA)shall provide,or contract for,Regulating Reserve as required by Section R6C-3.2 equal to;or greater than;the Regulating Reserve Obligation of the party.Regulating Reserve may not overlap reserves dedicated for Spinning Reserve.Regulating Reserve (both up and down)is required to compensate for uncertainty in forecasting and is established during the unit commitment planning process,and as such the BA may then utilize its reserve as required during the course of the day.fa BA exhausts its Regulating Reserve,it is required to procure or commit additional reserves immediately.Available-FransferCapability(ATC Her tnterconnecting =aya bilityoOmponenacd2aYee! Regulating Reserve Obligation-the .2.1__The Regulating Reserve Obligation for each Balancing Authority shail intially be set by the intertie Management GCommitteeRegional Reliabilty Organization. 3.2.2 _R6-3--On an annual basis,after the year end CPS statistics are compiled,the iHM4GRegional Reliability Organization will modify each Balancing Authority's Regulating Reserve by increasing/decreasing its current Regulating Reserve by the %deviation in ts CPS1.The Regulating Reserve Obligations so calculated will be rounded up to the nearest integer MW. 3.2.3 R6.4.-ThetMCThe Regional Reliability Organization reserves the right to Page 5of 56 RROCONTINGENCY RESERVESPOLICY v001 ;increase/decrease a BA's Regulating Reserve or require other measures at any time due to changes inthe system or repeat infractions._Spin Balancing Account records will ;intained bed in ExhibitA2 Page 6of 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit Bl:Spinning Reserve Components R#.4-Spinning Reserve Obligation will be allocated to an Entity based on a combination of its Monthly Peak Hour Load (MPHL)and the Entities'Largest Single Generating Contingency (including any combination of units with a single point of interconnection forming a single contingency as further discussed in R#.6-2.1.3.RAS applications which have been field demonstrated to successfully mitigate the LSGC and have been approved by the H}AGRRO may be applied to reduce the magnitude of the LSGC. RI Spinning Reserve Largest Contingency Ratio (SRLCR):This component shall be calculated as the ratio of an individual Entities'Largest Single Generating Contingency (LSGC)as compared to the sum of the LSGC's of all the Railbelt Entities. R7.3.-The Largest Single Generating Contingency will be based on the actual capacity of those unit(s)subject to the single contingency (regardless of RAS applications). _An example of a Generating Contingency is a combined cycle unit;the loss of the combustion turbine will precipitate the loss of both the CT as well as the waste heat unit. R#4-f entities share a unit,an entities Share of such a unit could qualify as their LSGC if they have no unit(s)that are larger. R#5--Monthly Peak Hour Load Ratio (MPHLR):This component shall be calculated at the ratio of an individual Entities'MPHL as compared to the sum of the MPHL's of all the Railbelt Entities.The MPHL of an Entity shall be defined as the Monthly Peak Hourly Load from the month 1 year earlier.Adjustments for permanent loss,or expected increases due to large industrial bads may be made f agreed to by the H4C-RRO.Economy sales are not counted as lads,but non-firm/interruptible loads are. Page 7of 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit B2:Spinning Reserve Obligation4$RG}-of each-Obligated_Entity-shall be-caleulated Spinning Reserve Obligation for an Entity will be calculated summingthe weighted Spinning Reserve Components of each entity,and multiplyingthis by the System Reserve Basis as follows: SROe=50%{LSGCeW{Ei (LSGCi)}*[SRB]+50%{MPHLe}/{5i (MPHLi)}*[SRB]+MUDe €=a particular Entity i =All Interconnected Entities MUDe=the difference between the R#-72.1.3 max unit limit and an entities largest unit if greater than the R7F72.1.3cap. Page 80f 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit B3:Spinning Reserve Criteria Page 9of 56 Page 10o0f 56 RROCONTINGENCY RESERVESPOLICY v001 Exhibit Al -Methodology for a varying Largest Single Generating Contingency. For the Largest Single Generating Contingency (LSGC)for the Railbelt System 1)Each Entity will electronically share their hourly expected temperature compensated largest unit's output forecast during the day-ahead scheduling process.This may not be the same unit for each hour. 2)At this time,each utility will also share data on any forecasted excess spin that the Entity may wish to sell. 3)The next day and to the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was underestimated,the Entity which provided that forecast is obligated to make up the deficit spin in real time in order to keep the system protected.This includes forecasted unit startups. 4)To the extent that the forecasted LSGC for the Railbelt Electric Systems'real time output was overestimated,the difference in spin obligation will be pro rata credited to the remaining Entities in their Spin Balancing Account (SBA).This includes forecasted unit shutdowns. For the Largest Single Generating Contingency (LSGC)for an Entity 1)To the extent that the forecasted LSGC for an Entity's real time output was underestimated,the Entity which provided that forecast is obligated to credit the remaining Entities'SBA with the difference in spin in which they over carried due to the inaccurate forecast. 2)To the extent that the forecasted LSGC for an Entity's real time output was overestimated,no adjustments to the SBA will be made. Page 11 0f56 RROCONTINGENCY RESERVESPOLICY vo01 Exhibit A2 -Spin Balancing Account A Spin Balancing Account (SBA)will be created and kept by each Balancing Authority (BA)showing Date, Hour,To,From,and Quantity. Quantities must exceed a dead band to be recorded.Quantities 2 MW or larger qualify to be recorded. The entries will primarily reflect errors in forecasting and the consequential harm (in terms of amount of spin carried)caused to the other Entities due to these errors. Entities will net out their spin obligations with others in chronological order (oldest first)but at times may need to redeem their spin via scheduling from the utility owing them spin,at no cost for the spin, and at such time the owing utility has spin excess of its needs.The owing utility has no obligation to start additional generation to provide such spin. Each quarter,a BA will be selected as being the "master”to which the other entities will compare their own records.The "master”role will be rotated. Page 120f 56 RROCONTINGENCY RESERVES POLICY v001 Exhibit A3 -Geographical Spin Methodology for the handling specific issues resultant from Railbelt Geography A:Kenai A single transmission line connects the generation on the Kenai with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Kenai Transmission Line; Not all spin originating on the Kenai can leave the Kenai; if spin can't leave the Kenai,the utilities north of the Kenai will need to make it up in order to satisfactorily protect the system; If spin can't leave the Kenai,it is inefficient to require an Entity to carry spin that can't be used; The Kenai isn't always constrained every hour; Spin originating on the Kenai can leave the Kenai; Entities on the Kenai should be required to carry their share of spin; To address this issue will require real time monitoring of the flows between the Kenai and the Anchorage Bowl.CEA has the live data which can be distributed via ICCP or equivalent. HEA/AEEC will be permitted to reduce their spin obligation (and consequently the other Entities will need to pro rata increase their spin obligation)during periods of constraint (and near constraint as appropriate).How much would need to be broadcast to all the utilities via CEA. During periods of constraint and during incidents requiring spin,both CEA and HEA/AEEC will need to monitor the Kenai Transmission Line and curtail the conversion of spin to MW if the emergency limit of the line is expected to be exceeded or is exceeded. CEA's Cooper Lake Plant may be providing spin for CEA which needs to be included in the constrained Kenai calculations.CEA may have certain rights as spelled out in the Bradley Contracts which must be upheld and are of a higher priority than these rules.HEA/AEEC has some amount of Bradley Lake Spin which generally can be expected to leave the Kenai. There may be times where the largest loss contingency in the system is the loss of the Kenai line itself.By definition,HEA/AEEC would not be able to contribute useful spin to such an incident. HEA/AEEC should be permitted to reduce their spin obligation (and consequently the other utilities will need to pro rata increase their spin obligation)so as to only cover the next largest Single Generating Unit Contingency subject to other restrictions of the Kenai Transmission line discussed above. Page 130f 56 RROCONTINGENCY RESERVESPOLICY v001 When the Kenai is islanded,the utilities north of the Kenai shall not be permitted to count their stranded Kenai spin towards their spin obligations. B:Interior A single transmission line connects the generation in the Interior with the rest of South Central Alaska.The line is constrained at times due to stability limits.The following issues should be addressed. Constrained Alaska Intertie Transmission Line; Not all spin originating in South Central can leave South Central; if the System LSGC is in the interior,South Central Entities share in providing spinning reserve to cover this unit; If spin can't leave the South Central,it is inefficient to require an Entity to carry spin that can't be used; South Central Entities should not count an Interior LSGC as the Systems'largest unit during periods when the Alaska Intertie is constrained or near constrained as appropriate. The Alaska Intertie isn't always constrained every hour; Spin originating on the South Central can leave South Central; Entities in South Central should be required to carry their share of spin for an Interior System LSGC; To address this issue will require real time monitoring of the flows between the Interior and the Anchorage Bowl.AMLP has live data which can be distributed via ICCP or equivalent.South Central Entities will be permitted to reduce their spin obligation during periods of constraint (and near constraint as appropriate)to cover the next largest South Central based contingency. Page 140f 56 Intertie Management Committee (IMC)Subcommittee Members Committee Representative Email Address Alternate Alternate email address Kirk Warren -AEA (Chair)kwarren@aidea.org Gene Therriault gtherriault@aidea.org Jeff Warner -ML&P warnerja@muni.org Ken Langford langfordkw@muni.org Budget Subcommittee:Matt Reisterer-MEA mattreisterer@mea.coop Deanna Hracha Deanna.hracha@mea.coop Cory Borgeson -GVEA cborgeson@gvea.com Ron Woolf rewoolf@gvea.com Jody Wolfe -CEA jody _wolfe@chugachelectric.com Sherri McKay-Highers sherri_mckay-highers@chugachelectric.com Jeff Warner -ML&P (Chair)warnerja@muni.org Ken Langford langfordkw@muni.org Hank Gocke -MEA hank.gocke@mea.coop Eddie Taunton Eddie.taunton@mea.coopDispatchandSystemOperationsAllenGray-GVEA ajgray@gvea.com Mike Wright mjwright@gvea.comSubcommittee:John Johnson -CEA john_johnson@chugachelectric.com Burke Wick burke _wick@chugachelectric.com Bob Day -HEA (Invitee).bday@homerelectric.com Aung Thuya -ML&P thuyaac@muni.org Al Mitchell mitchelta@muniorg Engineering,Relay and Reliability Jim Brooks -MEA jim.brooks@mea.coop Robert Wilson Robert.wilson@mea.coop Subcommittee:Nathan Minnema -GVEA (Chair)}_njminnema@gvea.com Dan Bishop dbishop@gvea.com Adam Vogel -CEA adam_vogel@chugachelectric.com Luke Sliman luke_sliman@chugachelectric.com Ken Langford -ML&P (Chair)Jangfordkw@muni.org Kevin Mitchell mitchellkI@muni-.org Bruno Urcuyo -MEA bruno.urcuyo@mea.coop Gary Peers Gary.peers@mea.coop Machine Ratings Subcommittee:Paul Morgan -GVEA pemorgan@gvea.com Colton Nyland cbnyland@gvea.com Dee Fultz -CEA dee_fultz@chugachelectric.com Aaron Love aaron_love@chugachelectric.com Bob Day -HEA (Invitee)bday@homerelectric.com Jeff Warner -ML&P (Chair)warnerja@muni.org Ken Langford langfordkw@muni.org Kirk Warren -AEA kwarren@aidea.org Gene Therriault gtherriault@aidea.org Operating Committee Gary Kuhn -MEA gary.kuhn@mea.coop Eddie Taunton Eddie.taunton@mea.coop Allen Gray -GVEA ajgray@gvea.com Dan Bishop drbishop@gvea.com Burke Wick -CEA burke_wick@chugachelectric.com Paul Risse Paul Risse@chugachelectric.com Jeff Warner -ML&P (Chair)warnerja@muni.org Ken Langford langfordkw@muni.org Operations,Maintenance and Scheduling Jim Brooks -MEA jim.brooks@mea.coop Eddie Taunton Eddie.taunton@mea.coop Subcommittee:Allen Gray -GVEA ajgray@gvea.com Rich Piech rjpiech@gvea.com Bill Bernier -CEA bill bernier@chugachelectric.com Burke Wick burke_wick@chugachelectric.com 1 of2 9/1/2015 Intertie Management Committee (IMC)Subcommittee Members Committee Representative Email Address Alternate Alternate emai!address Russ Lyday -ML&P (Chair)tydayrw@muni.org Mary Batten battenmi@muni.org SCADA and Telecommunications Keith Palchikoff -GVEA kepalchikoff@gvea.com Allen Sparks ARSparks@aqvea.com Subcommittee:DJ Carrington -MEA dj .carrington@mea.coop Mike Humphrey Mike.humphrey@mea.coop Kirk Warren -AEA kwarren@aidea.org Gene Therriault gtherriault@aidea.org Paul Johnson -CEA paul_johnson@chugachelectric.com Bill Murray bill_murray@chugachelectric.com Mark Johnson -CEA (Chair)mark _johnson@chugachelectric.com Jeff Warner warnerja@mnuni.org Lou Agi-ML&P «agile@muni.org Bruno Urcuyo bruno.urcuyo@mea.coop ..Gary Kuhn -MEA gary.kuhn@mea.coop Lance Roberts ljroberts@gvea.comtandComplSubtt--.Standards Compliance Subcommittee Allen Gray-GVEA ajgray@gvea.com Burke Wick burke_wick@chugachelectric.com Dee Fultz -CEA dee_fultz@chugachelectric.com Kirk Gibson Kirk@mcd-law.com Jeff Warner -ML&P watnerja@muni.org Ken Langford langfordkw@muni.org Bruno Urcuyo -MEA bruno.urcuyo@mea.coop Gary Kuhn gary.kuhn@mea.coop Standards Committee Allen Gray -GVEA ajgray@gvea.com Dan Bishop drbishop@gvea.com Kirk Warren -AEA kwarren@aidea.org Gene Therriault gtherriault@aidea.org Brian Hickey -CEA brian_hickey@chugachelectric.com Paul Risse paul _risse@chugachelectric.com Aung Thuya -ML&P (Chair)thuyaac@muni.org Al Mitchell mitchellaj@muni.org Bruno Urcuyo -MEA bruno.urcuyo@mea.coop Gary Kuhn gary.kuhn@mea.coop System Studies Subcommittee:Keith Palchikoff -GVEA kepalchikoff@gvea.com Adam Saunders AJSaunders@qvea.com Russ Thornton -CEA Russ_Thornton@chugachelectric.com Adam Vogel adam_vogel@chugachelectric.com Jim Cross -HEA(Invitee)jcross@homerelectric.com Anna Henderson-ML&P (Chair)|hendersonac@muni.org Lou Agi -Jagile@muni.org ...David Pease -MEA david.pease@mea.coop Matt Reisterer matt.reisterer@mea.coopTariffsandRegulatoryAffairsCommitteePaulaAshbridge-GVEA pdashbridge@gvea.com Allen Gray ajgray@gvea.com Mark Johnson -CEA markjohnson@chugachelectric.com Arthur Miller arthur_miller@chugachelectric.com 2 of2 9/1/2015 ALASKA INTERTIE MANAGEMENT COMMITTEE AGENDA Tuesday,Sept.1,2015 9:00 a.m.-11:00 am Alaska Energy Authority,Board Room 813 W.Northern Lights Boulevard,Anchorage,Alaska 1.CALL TO ORDER 2.ROLL CALL FOR COMMITTEE MEMBERS 3.PUBLIC ROLL CALL 4.AGENDA APPROVAL 5.PUBLIC COMMENTS 6.APPROVAL OF PRIOR MINUTES -June 23,2015 7.OLD BUSINESS A.SPIN and RESERVE NEGOTATIONS -UPDATE (IOC) B.SVC WARRANTY POLICY -UPDATE (AEA) 8.NEW BUSINESS 9.REPORTS A.OPERATORS REPORT -ML&P/GVEA B.INTERTIE OPERATING COMMITTEE REPORT 10.COMMITTEE ASSIGNMENTS 11.NEXT MEETING DATE 12,ADJOURNMENT To participate via teleconference,dial 1-888-585-9008 and use conference room code 467 050 126 Intertie Management Committee Regular meeting MEETING MINUTES Tuesday,June 23,2015 Anchorage,Alaska 1.CALL TO ORDER Chair Joe Griffith called the meeting of the Intertie Management Committee to order on June 23, 2015 at 3:01 p.m.A quorum was established. 2.ROLL CALL FOR COMMITTEE MEMBERS .: Burke Wick Chugach Electric Association (Cc )ONE. Cory Borgeson Golden Valley Electric Association (GVEA) Joe Griffith Matanuska Electric Association (MEA) Gene Therriault Alaska Energy Authority,(AEA) Mark Johnston Anchorage Municipal Light &Power...(ML&P) PUBLIC ROLL CALL 6. MOTION:Mr.Therriault made a motion to approve the prior minutes of May 21,2015. Motion seconded by Mr.Johnston.The motion was approved unanimously. 7.OLD BUSINESS 7A.Spin and Reserves Negotiations Mr.Day gave a presentation on spin.Currently most utilities calculate their spinning reserve obligation based on their largest generator in use.Mr.Day explained HEA calculates its spinning reserve based upon load ratio to eliminate the penalizing effect on the utility with the largest unit, reduce "gaming"from largest unit,penalize poor operators,accommodate "de-rates",and IMC Meeting Minutes-June 23,2015 Page 1 of 3 considers credible events.HEA suggests that spin be calculated on the largest probable contingency based upon NERC statistics and the intertie history,spin on system size,agree on a maximum unit size,and always have spin on the system that is equal to the real load that could be lost by the contingency. Negotiations started in 2013 regarding dividing the spin 50/50 or 70/30 but discussions were handed off to the General Managers who decided to go with the 100 percent largest unit. The committee asked the IOC and HEA to restart discussions and bring back an answer in 90 year of who owed spin and what was it worth. 7B.ACEP Study on Transmission Management. before the deadline of June 17.A letter was notPe bmitied at the time ofthisMeeting and theplanistoaskforanextensionandsubmititthefollowingweek. by Mr.Johnston The motion Passed.9.REPORTS9A.Operators Report Recent forest fire activities did not cause any outages. 9B. Intertie Operating committee report No report was given.The Chairman asked for a report from IOC for the next meeting. 10.COMMITTEE ASSIGNMENTS e Restart spin discussions with IOC and Homer and give an update and estimated cost of owed spin at the next meeting. e AEA to present SVC warranty contract findings at the next meeting. e Once the spin issue is resolved have the Regulatory Affairs committee review the filing of the Reliability and Operating criteria with the RCA. IMC Meeting Minutes-June 23,2015 Page 2 of 3 11.NEXT MEETING DATE The Chairman asked that the next meeting be held roughly in 60 days. Mr.Therriault informed the committee that AEA will be giving an update to their Board on the Railbelt transmission issues at the AEA board meeting on June 25 in Fairbanks. 12,ADJOURNMENT There being no further business of the IMC,the meeting adjourned at 4:08 p.m. Joe Griffith,Chairman Gene Therriault,Secretary To obtain an audio of the full meeting,contact Teri Webster (AEA)at 907-771-3074. IMC Meeting Minutes-June 23,2015 Page 3 of 3 ALASKA INTERTIE MANAGEMENT COMMITTEE AGENDA Tuesday,Sept.1,2015 9:00 a.m.-11:00 am Alaska Energy Authority,Board Room 813 W.Northern Lights Boulevard,Anchorage,Alaska 1.CALL TO ORDER 2.ROLL CALL FOR COMMITTEE MEMBERS 3.PUBLIC ROLL CALL 4.AGENDA APPROVAL 5.PUBLIC COMMENTS 6.APPROVAL OF PRIOR MINUTES -June 23,2015 7.OLD BUSINESS A.SPIN and RESERVE NEGOTATIONS -UPDATE (IOC) B.SVC WARRANTY POLICY -UPDATE (AEA) 8.NEW BUSINESS 9.REPORTS A.OPERATORS REPORT -ML&P/GVEA B.INTERTIE OPERATING COMMITTEE REPORT 10...COMMITTEE ASSIGNMENTS 11.NEXT MEETING DATE 12.ADJOURNMENT To participate via teleconference,dial 1-888-585-9008 and use conference room code 467 050 126 lOC Operator Report September 1,2015 1.Alaska Intertie Status Report MWH Usage at Douglas Substation Second quarter 2015:111,708 MWh July 2015:29,363 MWh August 2015 :33,299 MWh 2.System operation Second Quarter 2015 Intertie trips,6 trips: 4/16/2015 GVshed 44MW 1OC#764 5/7/2015 HLS B17,GV shed 0.OMW 1OC#770 5/7/2015 HLS B17,GV shed 0.OMW lIOC#769 6/14/2015 GV shed 0.0MW,C phase to ground 6/27/2015 HLS B17,GV shed 10.6MW 6/27/2015 GV shed 39.7MW, We had two HLS B17 only trips that where due to the Healy SVC tripping off,therefore lowering the HLS B17 OV trip point and subsequently tripping B17 open.See #4 below. 3.Compliance Report a.none 4.Alaska Intertie SVC update a.All three SVCs have,for the most part,been operating well.Software upgrades at TLS, HLS and GHS to be completed mid-September to correct overly sensitive UV detection of 480v bus.SVC warranty being negotiated by AMLP. 5.Intertie Operating Committee a.Summer IOC meeting was at MEA on July 9,2015 b.Working on spinning reserve allocation reconciliation between AIARS and RRO. 6.Machine Ratings Subcommittee a.Update MRSC online data base -ongoing 7.Operations,Maintenance and Scheduling Subcommittee a.Meeting regular,no report 8.Dispatch and System Operations Subcommittee a.Reviewing outage reporting criteria necessary to provide useful information. b.Review and provide compliance reporting methodology 9.Budget Subcommittee a.Received budget from subcommittee,approved,passed to IMC 10.Engineering,relay and Reliability Subcommittee a.Review Douglas Substation Protection Upgrade Project,ongoing.IOC had site visit on 7/9/2015.MEA working on proposal!for new infrastructure.In short term MEA is changing out ancient SEL121 relay with a newer model to provide protection looking north that will be remotely accessible. 11.System Studies Subcommittee a.UFLS Study Awarded to EPS. 12.SCADA and Telecommunications Subcommittee a.Snow Load Monitoring System quit working when AT&T upgraded cell system to 4G.EPS working on a fix. Intertie Management Committee Regular meeting MEETING MINUTES Tuesday,June 23,2015 Anchorage,Alaska 1.CALL TO ORDER Chair Joe Griffith called the meeting of the Intertie Management Committee to order on June 23, 2015 at 3:01 p.m.A quorum was established. 2.ROLL CALL FOR COMMITTEE MEMBERS ... Burke Wick Chugach Electric Association (C )- Cory Borgeson Golden Valley Electric Association (GVEA) Joe Griffith Matanuska Electric Association (MEA) Gene Therriault Alaska Energy Authority:(AEA)Mark Johnston Anchorage Municipal Light &&Powe 7(ML&P) 3.PUBLIC ROLL CALL Mark Johnson,Paul Risse (CEA);Gary Kuhn (MEA);Jocelyn Garner,Kirk Warren,KelliVeech,and Teri Webster (AEA);Bob Day (Homer Electric Association (HEA))Bernie Smith(Regulatory Commission of Alaska (RCA)Kirk Gibson (MeDowell Rackner &Gibson PC); 4. MOTION:'Mr.Therriault made ia motion to'approve the agenda as presented.Motion secondedbyMr.J ohnston.The agenda wwas adopted without objection. 6. MOTION:Mr.Therriault made a motion to approve the prior minutes of May 21,2015. Motion seconded by Mr.Johnston.The motion was approved unanimously. 7.OLD BUSINESS 7A.Spin and Reserves Negotiations Mr.Day gave a presentation on spin.Currently most utilities calculate their spinning reserve obligation based on their largest generator in use.Mr.Day explained HEA calculates its spinning reserve based upon load ratio to eliminate the penalizing effect on the utility with the largest unit, reduce "gaming"from largest unit,penalize poor operators,accommodate "de-rates",and IMC Meeting Minutes-June 23,2015 Page 1 of 3 considers credible events.HEA suggests that spin be calculated on the largest probable contingency based upon NERC statistics and the intertie history,spin on system size,agree on a maximum unit size,and always have spin on the system that is equal to the real load that could be lost by the contingency. Negotiations started in 2013 regarding dividing the spin 50/50 or 70/30 but discussions were handed off to the General Managers who decided to go with the 100 percent largest unit. The committee asked the IOC and HEA to restart discussions andpng back an answer in 90yearofwhoowedspinandwhatwasitworth. 7B.ACEP Study on Transmission Management * At the last meeting it was discussed to submit apt ic comment letter 0 the RCA from the IMCbeforethedeadlineofJune17.A letter was notsubmitted at the time of thisMeeting and theplanistoaskforanextensionandsubmititthefollowingweek.ee 7C.SVC Warranty Policy Mr.Bjorkquist reviewed the policy and Preseted two option::1)!Have a stand-alone contract AEAis waiting on answers regarding procurement 'delegation authority and expects the answerbytheendofJune.This tto ic will b Addressed aatt the next IMC meeting for follow up. by Mr.Johnéton.The motion passed. 9.REPORTS”9A.Operators ReportRecentforestfireactivities did.not cause any outages. 9B. Intertie Operating committee report No report was given.The Chairman asked for a report from IOC for the next meeting. 10.COMMITTEE ASSIGNMENTS e Restart spin discussions with IOC and Homer and give an update and estimated cost of owed spin at the next meeting. e AEA to present SVC warranty contract findings at the next meeting. e Once the spin issue is resolved have the Regulatory Affairs committee review the filing of the Reliability and Operating criteria with the RCA. IMC Meeting Minutes-June 23,2015 Page 2 of 3 11,NEXT MEETING DATE The Chairman asked that the next meeting be held roughly in 60 days. Mr.Therriault informed the committee that AEA will be giving an update to their Board on the Railbelt transmission issues at the AEA board meeting on June 25 in Fairbanks. 12,ADJOURNMENT There being no further business of the IMC,the meeting adjourned at 4:08 p.m. Joe Griffith,Chairman Gene Therriault,Secretary To obtain an audio of the full meeting,contact Teri Webster (AEA)at 907-771-3074. IMC Meeting Minutes-June 23,2015 Page 3 of 3 Intertie Management Committee (IMC)Subcommittee Members Committee |Representative Email Address Alternate Alternate email address Kirk Warren -AEA (Chair)kwarren@aidea.org Gene Therriault gtherriault@aidea.org Jeff Warner -ML&P wamerja@muni.org Ken Langford langfordkw@muni.org Budget Subcommittee:Matt Reisterer-MEA mattreisterer@mea.coop Deanna Hracha Deanna.hracha@mea.coop Cory Borgeson -GVEA cborgeson@gvea.com Ron Woolf rewoolf@egvea.com Jody Wolfe -CEA Sherri McKay-Highers sherri_mckay-highers@chugachelectric.comjodywolfe@chugachelectric.com Jeff Warner -ML&P (Chair warnerja@muni.org Ken Langford langfordkw@muni.org ..Hank Gocke -MEA hank.gocke@mea.coop Eddie Taunton Eddie.taunton@mea.coopDispatchandSystemOperationsAllenGray-GVEA ajgray@gvea.com Mike Wright mjwright@gvea.comSubcommittee:John Johnson -CEA john_johnson@chugachelectric.com Burke Wick burke_wick@chugachelectric.com Bob Day -HEA (Invitee).bday@homerelectric.com Aung Thuya -ML&P thuyaac@muni.org Al Mitchel!mitcheltaj@muni_org Engineering,Relay and Reliability Jim Brooks -MEA jim.brooks@mea.coop Robert Wilson Robert.wilson@mea.coop Subcommittee:Nathan Minnema -GVEA (Chair)|njminnema@gvea.com Dan Bishop dbishop@zgvea.com Adam Vogel -CEA adam _vogel@chugachelectric.com Luke Sliman luke_sliman@chugachelectric.com Ken Langford -ML&P (Chair)|langfordkw@muni.org Kevin Mitchell mitchellki@muni.org Bruno Urcuyo -MEA bruno.urcuyo@mea.coop Gary Peers Gary.peers@mea.coop Machine Ratings Subcommittee:Paul Morgan -GVEA pcmorgan@gvea.com Colton Nyland cbnyland@gvea.com Dee Fultz -CEA dee_fultz@chugachelectric.com Aaron Love aaron _love@chugachelectric.com Bob Day -HEA (Invitee)bday@homerelectric.com Jeff Warner -ML&P (Chair)warnerja@muni.org Ken Langford langfordkw@muni.org Kirk Warren -AEA kwarren@aidea.org Gene Therriault gtherriault@aidea.org Operating Committee Gary Kuhn -MEA gary.kuhn@mea.coop Eddie Taunton Eddie.taunton@mea.coop Allen Gray -GVEA ajgray@gvea.com Dan Bishop drbishop@gvea.com Burke Wick -CEA burke _wick@chugachelectric.com Paul Risse Paul Risse@chugachelectric.com Jeff Warner -ML&P (Chair)warnerja@muni.org Ken Langford langfordkw@muni.org Operations,Maintenance and Scheduling Jim Brooks -MEA jim.brooks@mea.coop Eddie Taunton Eddie.taunton@mea.coopSubcommittee:Allen Gray -GVEA ajgray@gvea.com Rich Piech rjpiech@gvea.com Bill Bernier -CEA bill bernier@chugachelectric.com Burke Wick burke _wick@chugachelectric.com 1 of2 9/1/2015 Intertie Management Committee (IMC)Subcommittee Members Committee Representative Email Address Alternate Alternate email address Russ Lyday -ML&P (Chair)lydayrw@muni.org Mary Batten battenmi@muni.org SCADA and Telecommunications Keith Paichikoff -GVEA kepalchikoff@gvea.com Allen Sparks ARSparks@qvea.com Subcommittee:DJ Carrington -MEA dj.carrington@mea.coop Mike Humphrey Mike.humphrey@mea.coop Kirk Warren -AEA kwarren@aidea.org Gene Therriault gtherriault@aidea.org Paul Johnson -CEA _paul_johnson@chugachelectric.com Bill Murray bill_murray@chugachelectric.com Mark Johnson -CEA (Chair)markjohnson@chugachelectric.com Jeff Warner wamerja@muni.org Lou Api-ML&P 2 agile@muni.org Bruno Urcuyo bruno.urcuyo@mea.coop Gary Kuhn -MEA .. j Standards Compliance Subcommittee ary Kuhn gary kuhn@mea.coop Lance Roberts liroberts@gvea.comAllenGray-GVEA ajpgray@pvea.com Burke Wick burke_wick@chugachelectric.com Dee Fultz -CEA dee_fultz@chugachelectric.com Kirk Gibson Kirk@mcd-law.com Jeff Warner -ML&P warnerja@muni.org Ken Langford langfordkw@muni.org Bruno Urcuyo -MEA bruno.urcuyo@mea.coop Gary Kuhn gary.kuhn@mea.coop Standards Committee Allen Gray -GVEA ajgray@gvea.com Dan Bishop drbishop@pvea.com Kirk Warren -AEA kwarren@aidea.org Gene Therriault ptherriault@aidea.org Brian Hickey -CEA brian_hickey@chugachelectric.com Paul Risse paul_risse@chugachelectric.com Aung Thuya -ML&P (Chair)thuyaac@muni.org Al Mitchell mitchellaj@muni.org Bruno Urcuyo -MEA bruno.urcuyo@mea.coop Gary Kuhn gary.kuhn@mea.coop System Studies Subcommittee:Keith Palchikoff -GVEA kepalchikoff@gvea.com Adam Saunders AJSaunders@avea.com Russ Thornton -CEA Russ_Thornton@chugachelectric.com Adam Vogel adam vogel@chugachelectric.com Jim Cross -HEA (Invitee)jcross@homerelectric.com Anna Henderson-ML&P (Chair)}hendersonac@muni.org Lou Agi -[agile@muni.org Tariffs and Regulatory Affairs C itt David Pease -MEA david.pease@mea.coop Matt Reisterer matt.reisterer@mea.cooparlilsandRegulatoryAtlairs\ommaumee Paula Ashbridge -GVEA pdashbridge@gvea.com Allen Gray ajpray@pvea.com Mark Johnson -CEA mark_johnson@chugachelectric.com Arthur Miller arthur_miller@chugachelectric.com 2 of2 9/1/2015 Intertie Management Committee Regular meeting MEETING MINUTES Tuesday,June 23,2015 Anchorage,Alaska 1.CALL TO ORDER Chair Joe Griffith called the meeting of the Intertie Management Committee to order on June 23, 2015 at 3:01 p.m.A quorum was established. 2.ROLL CALL FOR COMMITTEE MEMBERS Burke Wick Chugach Electric Association (CEA) Cory Borgeson Golden Valley Electric Association (GVEA) Joe Griffith Matanuska Electric Association (MEA) Gene Therriault Alaska Energy Authority,(AEA)Mark Johnston Anchorage Municipal Light ¢&Power «(ML&P)ce 3.PUBLIC ROLL CALL Mark Johnson,Paul Risse (CEA);Gary'Kubn (MEA);Jocelyn Gamer,Kirk Warren,KelliVeech,and Teri Webster (AEA);Bob Day (Homer Electric Association (HEA))Bernie Smith(Regulatory Commission of Alaska (RCA));Kirk Gibson (McDowell Rackner &Gibson PC);Brian Bjorkquist (Dept.ofLaw);Henri Dale.©.4,AGENDA APPROVAMOTION:Mr.Therriault made a motion to approves the agenda as presented.Motion secondedbyMr.J ohnston.The agenda wwas adopted without objection.5.PUBLIC COMMENTS:* None 6.APPROVAL OF"PRIOR MINUTES-May 21,2015MOTION:Mr.Therriault made a motion to approve the prior minutes of May 21,2015. Motion seconded by Mr.Johnston.The motion was approved unanimously. 7.OLD BUSINESS 7A.Spin and Reserves Negotiations Mr.Day gave a presentation on spin.Currently most utilities calculate their spinning reserve obligation based on their largest generator in use.Mr.Day explained HEA calculates its spinning reserve based upon load ratio to eliminate the penalizing effect on the utility with the largest unit, reduce "gaming"from largest unit,penalize poor operators,accommodate "de-rates",and IMC Meeting Minutes-June 23,2015 Page 1 of 3 considers credible events.HEA suggests that spin be calculated on the largest probable contingency based upon NERC statistics and the intertie history,spin on system size,agree on a maximum unit size,and always have spin on the system that is equal to the real load that could be lost by the contingency. Negotiations started in 2013 regarding dividing the spin 50/50 or 70/30 but discussions were handed off to the General Managers who decided to go with the 100 percent largest unit. The committee asked the IOC and HEA to restart discussions and bring back an answer in 90daysandtogiveanupdateatthenextmeeting.CEA was asked to provide an estimate from last year of who owed spin and what was it worth., 7B.ACEP Study on Transmission ManagementAtthelastmeetingitwasdiscussedtosubmitapuic comment letter to the RCA from the IMCbeforethedeadlineofJune17.A letter was not submitted at the time of this meeting and theplanistoaskforanextensionandsubmititthefollowingweek: 7C.SVC Warranty Policy by the end of June.Thistopic will be addressed at 'the next IMC meeting for follow up. 8.NEW.BUSINESS8A.FY16 Budget Approval. MOTION:Mr.Therriault moved tto approve the budget as presented.Motion seconded 9.REPORTS os,9A.Operators ReportRecentforestfireactivities didnnot cause any outages. 9B._Intertie Operating committee report No report was given.The Chairman asked for a report from IOC for the next meeting. 10.COMMITTEE ASSIGNMENTS e Restart spin discussions with IOC and Homer and give an update and estimated cost of owed spin at the next meeting. e AEA to present SVC warranty contract findings at the next meeting. e Once the spin issue is resolved have the Regulatory Affairs committee review the filing of the Reliability and Operating criteria with the RCA. IMC Meeting Minutes-June 23,2015 Page 2 of 3 11.NEXT MEETING DATE The Chairman asked that the next meeting be held roughly in 60 days. Mr.Therriault informed the committee that AEA will be giving an update to their Board on the Railbelt transmission issues at the AEA board meeting on June 25 in Fairbanks. 12,ADJOURNMENT There being no further business of the IMC,the meeting adjourned at 4:08 p.m. Joe Griffith,Chairman Gene Therriault,Secretary To obtain an audio of the full meeting,contact Teri Webster (AEA)at 907-771-3074. IMC Meeting Minutes-June 23,2015 Page 3 of 3 From:Bjorkquist,Brian D (LAW)<brian.bjorkquist@alaska.gov> Sent:Wednesday,August 26,2015 3:21 PM To:Teri Webster Ce:Kirk H.Warren Subject:RE:SVC warranty update for Tuesday No,|will not be at the meeting. Kirk will give the update.I've been talking to Kirk about this.He is obtaining a status report from ML&P,and has information from AEA procurement.After Kirk hears from ML&P,we may prepare a memo to distribute before the meeting to outline the status. Brian Bjorkquist Senior Assistant Attorney General Labor and State Affairs (907)269-5150 -direct (907)258-4978 -fax CONFIDENTIAL ATTORNEY CLIENT COMMUNICATION/ATTORNEY WORK PRODUCT This e-mail message contains confidential information.If you received this message in error,please notify the sender immediately. From:Teri Webster [mailto:twebster@aidea.org] Sent:Wednesday,August 26,2015 3:15 PM To:Bjorkquist,Brian D (LAW) Subject:SVC warranty update for Tuesday Brian, This is on the agenda for an update.Will you be doing the update at the meeting? Thank you, Teri 771-3074 Intertie Management Committee meeting -Alaska Online Public Notices Page 1 of 1 STATUS:Active Intertie Management Committee meeting The Intertie Management Committee will hold a meeting on Tuesday,Sept.1,2015 at 9:00 a.m.The agenda is attached.For additional information contact Teri Webster at (907)771-3074. This meeting will be conducted by electronic media pursuant to AS 44.83.040(b)and AS 44.62.310 at the following location: Alaska Energy Authority Board Conference Room 813 West Northern Lights Boulevard Anchorage,Alaska A teleconference line has been set up for those unable to attend in person.Dial 1-888-585-9008,Enter conference room 467 050 126. The public is invited to attend.The State of Alaska (AEA)complies with Title I]of the Americans with Disabilities Act of 1990. Disabled persons requiring special modifications to participate should contact AEA staff at (907)771-3074 to make arrangements. Attachments,History,Details Attachments Details IMC Agenda.pdf .Commerce,Community andDepartment:Economic Development Revision History Category:Public Notices Created 8/25/2015 11:49:50 AM by Sub-Category:Advisory Committee Meeting tawebster Location(s):Statewide Modified 8/25/2015 11:52:00 AM by [Details]Project/Regulation #: tawebster Modified 8/26/2015 2:26:49 PM by [Details]Publish Date:8/25/2015 tawebster Archive Date:9/2/2015 Modified 8/26/2015 2:27:19 PM by [Details]tawebster Events/Deadlines: https://aws.state.ak.us/OnlinePublicNotices/Notices/View.aspx?id=178050 8/26/2015 Intertie Management Committee meeting -Alaska Online Public Notices Page 1 of 1 STATUS:Active Intertie Management Committee meeting The Intertie Management Committee will hold a meeting on Tuesday,Sept.1,2015 at 9:00 a.m.For additional information contact Teri Webster at (907)771-3074. This meeting will be conducted by electronic media pursuant to AS 44.83.040(b)and AS 44.62.310 at the following location: Alaska Energy Authority Board Conference Room 813 West Northern Lights Boulevard Anchorage,Alaska A teleconference line has been set up for those unable to attend in person.Dial 1-888-585-9008,Enter conference room 467 050 126. The public is invited to attend.The State of Alaska (AEA)complies with Title If of the Americans with Disabilities Act of 1990. Disabled persons requiring special modifications to participate should contact AEA staff at (907)771-3074 to make arrangements. Attachments,History,Details Attachments Details None .Commerce,Community andDepartment:Economic Development Revision History Category:Public Notices Created 8/25/2015 11:49:50 AM by ooeaegony Ad isory Committee Meetingtawebster, Modified 8/25/2015 11:52:00 AM by [Details]Project/Regulation #: tawebster Publish Date:8/25/2015 Archive Date:9/2/2015 Events/Deadlines: https://aws.state.ak.us/OnlinePublicNotices/Notices/View.aspx?id=178050 8/25/2015 Intertie Management Committee Regular meeting MEETING MINUTES Tuesday,June 23,2015 Anchorage,Alaska 1.CALL TO ORDER Chair Joe Griffith called the meeting of the Intertie Management Committee to order on June 23, 2015 at 3:01 p.m.A quorum was established. 2.ROLL CALL FOR COMMITTEE MEMBERS Burke Wick Chugach Electric Association (CEA)% Cory Borgeson Golden Valley Electric Association (GVEA Joe Griffith Matanuska Electric Association (MEA) Gene Therriault Alaska Energy Authority (AEA)Mark Johnston Anchorage Municipal Light &Power 2(ML&P) 3.PUBLIC ROLL CALL Mark Johnson,Paul Risse (CEA);Gary Kuhn (MBA):J ocelyn Garner,Kirk Warren,KelliVeech,and Teri Webster (AEA);Bob Day (Homer Electric Association (HEA))Bernie Smith(Regulatory Commission of Alaska (RCA));Kirk Gibson (McDowell Rackner &Gibson PC);Brian Bjorkquist (Dept.f Law);Henri Dale. 4,AGENDA APPROVAL MOTION:"Mr.Theriault made a motion to approve'the agenda as presented.Motion secondedbyMr.J ohnston.The agenda was adopted withoutobjection.5.PUBLIC.COMMENTS' None 6.APPROVAL OF.PRIOR MINUTES-May 21,2015MOTION:Mr.Therriault made a motion to approve the prior minutes of May 21,2015. Motion seconded by Mr.Johnston.The motion was approved unanimously. 7.OLD BUSINESS 7A.Spin and Reserves Negotiations Mr.Day gave a presentation on spin.Currently most utilities calculate their spinning reserve obligation based on their largest generator in use.Mr.Day explained HEA calculates its spinning reserve based upon load ratio to eliminate the penalizing effect on the utility with the largest unit, reduce "gaming"from largest unit,penalize poor operators,accommodate "de-rates",and IMC Meeting Minutes-June 23,2015 Page 1 of 3 considers credible events.HEA suggests to spin on the largest probable contingency based upon NERC statistics and the intertie history,spin on system size,agree on a maximum unit size,and always have spin on the system that is equal to the real load that was lost by the contingency. Negotiations started in 2013 regarding dividing the spin 50/50 or 70/30 but discussions were handed off to the General Managers who decided to go with the 100 percent largest unit. The committee asked the IOC and HEA to restart discussions and bring back an answer in 90 days and to give an update at the next meeting.CEA was asked to Provide an estimate from lastyearofwhoowedspinandwhatwasitworth.= 7B.ACEP Study on Transmission Management aAtthelastmeetingitwasdiscussedtosubmitapubliccomment letter to the RCA from the IMCbeforethedeadlineofJune17.A letter was not submitted at the time of this meeting and theplanistoaskforanextensionandsubmititthefollowingweek. 7C.SVC Warranty Policy between ML&P and Alstom and then have the IMC approve to move the contract to AEA tomanagethecontractdirectly...2)Have AEA sign a stand-alone contract directly with Alstom.AEAis waiting on answers regarding procurement delegation authority and expects the answerbytheendofJune.Thisis topic will be addressed at the next IMC.meeting for follow up. 8A.FY16 Budget ApprovalMOTION:Mr.Therriault moved to approve the budget as presented.Motion secondedbyMr.Johnston.The motionn passed.9.REPORTS9A.Operators ReportThefiresdidnotcauseany utages. 9B._Intertie Operating ommittee report No report was given.The Chairman asked for a report from IOC for the next meeting. 10.COMMITTEE ASSIGNMENTS e Restart spin discussions with IOC and Homer and give an update and estimated cost of owed spin at the next meeting. e AEA to present SVC warranty contract findings at the next meeting. e Once the spin issue is resolved have the Regulatory Affairs committee review the filing of the Reliability and Operating criteria with the RCA. 11.NEXT MEETING DATE IMC Meeting Minutes-June 23,2015 Page 2 of 3 The Chairman asked that the next meeting be held roughly in 60 days. Mr.Therriault informed the committee that AEA will be giving an update to their Board on the Railbelt transmission issues at the AEA board meeting on June 25 in Fairbanks. 12,ADJOURNMENT There being no further business of the IMC,the meeting adjourned at 4:08 p.m. Joe Griffith,Chairman Gene Therriault,Secretary To obtain an audio of the full meeting,contact Teri Webster (AEA)at 907-771-3074. IMC Meeting Minutes-June 23,2015 Page 3 of 3 ALASKA INTERTIE MANAGEMENT COMMITTEE List of Representatives Representative Alternate Utility Gene Therriault Sara Fisher-Goad Alaska Energy Authority Secretary/Treasurer 813 West Northern Lights Boulevard Anchorage,Alaska 99503 Teri Webster's ph:771-3074 Fax:771-3044 atherriault@aidea.org sfishergoad@aidea.org Jeff Warner Mark Johnston Anchorage Municipal Light &Power 1200 East First Avenue Anchorage,Alaska 99501 Linda Davidovic's ph:263-5201 Fax:263-5204 agile@muni.org iohnstonma@muni.org Brian Hickey Burke Wick Chugach Electric Association Vice Chairman 5601 Electron Drive Anchorage,Alaska 99518 Brian ph:762-4518 Connie Owens ph:762-4747 Fax:762-4514 Brian_Hickey@chugachelectric.com Burke_Wick@chugachelectric.com Cory Borgeson Allen Gray Golden Valley Electric Association P.O.Box 71249 Fairbanks,Alaska 99707-1249 Susan Redlin's ph:907-458-5721 Fax:458-5951 cborgeson@gqvea.com aja@qvea.com Evan "Joe”Griffith Gary Kuhn Matanuska Electric Association Chairman P.O.Box 2929 (163 Industrial Way) Palmer,Alaska 99645-2929 Dawn Baham's ph:907-761-9285 Fax:761-9368 joe.griffith@mea.coop gary.kuhn@mea.coop Kirk Gibson McDowell Rackner &Gibson PC 419 SW 11"Street,Suite 400 Portland,Oregon 97205 Phone:(503)290-3626 Fax:(503)595-3928 Kirk@mced-law.com Revised Date:August 24,2015 Intertie Management Committee Regular meeting MEETING MINUTES Thursday,May 21,2015 Anchorage,Alaska 1.CALL TO ORDER Chair Joe Griffith called the meeting of the Intertie Management Committee to order on May 21, 2015 at 9:00 a.m.A quorum was established. 2.ROLL CALL FOR COMMITTEE MEMBERS Brian Hickey Chugach Electric Association (CEA) Cory Borgeson Golden Valley Electric Association (GVEA) Joe Griffith Matanuska Electric Association (MEA) Gene Therriault Alaska Energy Authority (AEA) Lou Agi Anchorage Municipal Light &Power (ML&P) 3.PUBLIC ROLL CALL Burke Wick (CEA);(ML&P);Lee Thibert,Mark Johnson (CEA);Allen Gray (GVEA);Gary Kuhn (MEA);Jocelyn Garner,Kirk Warren,Teri Webster (AEA);Bernie Smith (Regulatory Commission of Alaska (RCA));Kirk Gibson (McDowell Rackner &Gibson PC);John Foutz (City of Seward);Henri Dale. 4.AGENDA APPROVAL MOTION:Mr.Borgeson made a motion to approve the agenda as presented.Motion seconded by Mr.Hickey.Two agenda items were added (8E &8F).The revised agenda was adopted without objection. 5.PUBLIC COMMENTS Bernie Smith announced his employment with RCA will end June 30"due to budget constraints. James Keen,Utility Engineering Analyst will take over the electrical side of the RCA and Bernie's'position is not being continued.All of the committee members expressed their appreciation of Mr.Smith's knowledge and involvement and it will be sorely missed.There was a discussion of writing a resolution to support a funding increase for the RCA for this position in the future. 6.APPROVAL OF PRIOR MINUTES --June 30,2014 MOTION:Mr.Borgeson made a motion to approve the prior minutes of Sept.18,2014. Motion seconded by Mr.Hickey.The motion was approved unanimously. 7.OLD BUSINESS 7A.Spin and Reserves Issues IMC Meeting Minutes-May 21,2015 Page 1 of 3 Mr.Borgeson asked that the spin issue be sent back to IOC to meet with Homer in an attempt to find an agreement that all the utilities can agree on regarding how to calculate spinning reserve obligations.Currently most utilities calculate their spinning reserve obligation based on their largest generator in use.Homer calculates it's spinning reserve on a percentage of their load. This creates a shortfall of reserve on the Railbelt system.The IOC is to report the result from their discussion with Homer back to the IMC.If the matter is still at an impasse,the IOC is requested to determine a dollar value for the reserve obligation that is being shifted to the Railbelt utilities. Also discussed was if the IMC should formally file the Reliability Standards with the RCA as a rule making or a tariff filing. 8.NEW BUSINESS 8A.Election of Vice-Chair Chugach Electric changed their designated representative to the IMC replacing Brad Evans with Brian Hickey.Mr.Evans held the office of Vice-Chair.Under the IMC Bylaws,the Committee must elect a successor to fill a vacant position at the meeting immediately following a resignation. Mr.Borgeson nominated Brian Hickey for Vice-Chair. MOTION:Mr.Borgeson moved to accept the nomination of Mr.Hickey for Vice-Chair. Motion seconded by Mr.Agi.The motion passed. 8B.Preliminary Budget Review The Budget Subcommittee presented the preliminary budget.There were no suggested changes to the amounts.The budget will be posted for public comments for 30 days before the IMC can approve it. 8C.SVC Warranty Mr.Agi reviewed the extended warranty on the SVC.This policy includes technical support, major preventative assessment every five years and training every five years.This is not a maintenance agreement but a support agreement.The committee approved to continue pursuing this and look at the 15 -25 year long term extended warranty.Brian Bjorkquist will look at the transition from ML&P to AEA for the finalizing of this policy. 8D.Douglas Relay Control House Mr.Griffith commented that since the structure containing the Douglas Relay controls is so old, it should be replaced when the protective relay schemes are upgraded.He suggested building a new control house off the existing location.Mr.Borgeson suggested we do a study of the cost to upgrade this facility and split that cost among all the utilities.A budget adjustment for the study will be done later. 8E.Anthony Scotts study on transmission issues Anthony Scott,senior economist and energy analyst at the Alaska Center for Energy and Power has been conducting presentations to the RCA regarding costs and benefits associated with grid IMC Meeting Minutes-May 21,2015 Page 2 of 3 management.The public comment period ends June 17 and Mr.Hickey will draft a joint letter from the utilities for submission. 8F.EGS Generation Incident Report On March 30 an outage occurred for 23 minutes due to human error.There was no load loss. 9.REPORTS 9A.Operators Report Allen Gray gave the operators report. 9B._Intertie Operating committee report Allen Gray gave the IOC report. 10.COMMITTEE ASSIGNMENTS IOC -Review the known necessary changes to the Reliability and Operating Criteria and present suggested changes and estimated cost of transfer payments.Present to the IMC for approval and then to coordinate with the Tariff and Regulatory Affairs committee on changes and recommendations on filing with the RCA. Mr.Gibson to meet with IOC and Operating committee to discuss MITR capacity rights. 11.NEXT MEETING DATE Not determined. 12,ADJOURNMENT There beipg no further business of the IMC,the meeting adjourned at 11:10 a.m. To obtain an audio of the full meeting,contact Teri Webster (AEA)at 907-771-3074. IMC Meeting Minutes-May 21,2015 Page 3 of3 How to Make a Correction to Corporate Board Minutes |Chron.com Page 1 of 3 How to Make a Correction to Corporate Board Minutes by Lori Hubbard,Demand Media an eae =A recording secretary tasked with taking minutes for a board ;meeting always wants to get it right,but sometimes a mistake is made.Minutes serve as the official record of business transacted ee ew ES a $,3.%@ and resolutions adopted at a corporation's board of director's .matin ama , meetings.They capture board actions such as approvals, delegations of authority and directives.In the event that an important point is missed or incorrectly recorded,corrections can be made by following a few steps. Meeting minutes capture the important actions of the board.Ads by Google Related Articles Free Corporate Mins Form 5 Different Types of Leadership Styles Customize a Legal Form in Minutes.Free Step-by-Step Guidance corporateminutes.rocketlawyer.com The Advantages &Disadvantages of Advertising on the Internet Ways to Change the Text Message Clarify Display on an iPhone When learning of a mistake,the first step is to make sure an error What Is the Difference Between CIF &actually occurred.Talk with the person who identified the error to FOB?ensure you fully understand the desired correction.Cross-check your notes and ask others if you are still unclear about the need or the wording for the proposed change.In cases of a simple mistake like a misspelled word,this step can be shortened or eliminated. List of Grants for African-American Women to Start a Business What Is a Good Typing Speed Per Minute?Rewrite and Redistribute After determining an error was made,reopen the meeting minute document and correct the mistake.Distribute the amended version to the board members.If mailing,attach a cover letter stating that the enclosed minutes are a revision and should replace the previous document.Write an introduction stating the same when attaching the document to an email distribution. Related Reading:Board Minutes Made Easy Corrections Made Before Approval When following parliamentary procedure,your minutes are approved and entered into the official record at the next subsequent meeting.If an error is pointed out before the following meeting,a motion is made to approve the minutes as corrected.It is not necessary to specify what the correction was,just that the version submitted for approval is a corrected version.After the motion is passed,the revised minutes are considered approved, signed by the secretary and entered into the official record. Corrections Needed After Approval http://smallbusiness.chron.com/make-correction-corporate-board-minutes-77 102.html 6/29/2015 How to Make a Correction to Corporate Board Minutes |Chron.com Page 2 of 3 Corrections to meeting minutes can be made when they are first distributed,considered for approval,or even after they have been approved.If the minutes have already been approved,then a "Motion to Amend Something Previously Adopted"will need to be made and considered at a subsequent meeting.If this motion is adopted, amend the previously approved minutes by making the appropriate correction.Since approved,the minutes are signed by the secretary of the board and thereafter become the official record of the meeting.The secretary maintains the minutes file for future access by the board or other members. Ads by Google Better Demand Planning Forecast using demand -Not Sales. Improve Demand Forecast Accuracy. www.demandsolutions.com/Free-Guide Meeting Minutes Software The Easiest &Fastest Way To Write Your Meeting Minutes.Try It Free! meetingking.com Corporate Travel Policies How to Develop a Corporate Travel Policy.Download Free GBTA Report www.ebta.org Resolution Template Download Board Resolution Templates Just Fill-in the Blanks &Print! board-resolution.biztree.com References (2)((#) About the Author Lori Hubbard has over 18 years of experience in the marketing and business field with a focus on marketing strategy and small business development.Hubbard holds a Master of Business Administration in marketing from the University of Cincinnati.An avid sports fan,Hubbard has coached high school and club volleyball for over 10 years. Photo Credits =Thomas Northcut/Digital Vision/Getty Images http://smallbusiness.chron.com/make-correction-corporate-board-minutes-77102.html 6/29/2015 Intertie Management Committee Regular meeting MEETING MINUTES Tuesday,June 23,2015 Anchorage,Alaska 1.CALL TO ORDER Chair Joe Griffith called the meeting of the Intertie Management Committee to order on June 23, 2015 at 3:01 p.m.A quorum was established. 2.ROLL CALL FOR COMMITTEE MEMBERS Burke Wick Chugach Electric Association (CEA) Cory Borgeson Golden Valley Electric Association (GVEA). Joe Griffith Matanuska Electric Association (MEA) Gene Therriault Alaska Energy Authority'(AEA)Mark Johnston Anchorage Municipal Light&Power(ML&P) 3.PUBLIC ROLL CALL Mark Johnson,Paul Risse (CEA);Gary Kuhn (MEA);Jocelyn Gamer,Kirk Warren,KelliVeech,and Teri Webster.(AEA);Bob Day (Homer ]Electric Association (HEA))Bernie Smith(Regulatory Commission of Alaska READ:Kirk Gibson (McDowell Rackner &Gibson PC); MOTION:2°Mr.Therriault made a motion to approve the agenda as presented.Motion secondedbyMr.Johnston.The agenda wwas adopted without objection.5.PUBLIC COMMEN None 6.APPROVAL OF PRIOR MINUTES-May 21,2015enoteMOTION:Mr.Therriault made a motion to approve the prior minutes of May 21,2015. Motion seconded by Mr.Johnston.The motion was approved unanimously. 7.OLD BUSINESS 7A.Spin and Reserves Negotiations Mr.Day gave a presentation on spin.Currently most utilities calculate their spinning reserve obligation based on their largest generator in use.Mr.Day explained HEA calculates its spinning reserve based upon load ratio to eliminate the penalizing effect on the utility with the largest unit, reduce "gaming"from largest unit,penalize poor operators,accommodate "de-rates",and IMC Meeting Minutes-June 23,2015 Page 1 of 3 considers credible events.HEA suggests to spin on the largest probable contingency based upon NERC statistics and the intertie history,spin on system size,agree on a maximum unit size,and always have spin on the system that is equal to the real load that was lost by the contingency. Negotiations started in 2013 regarding dividing the spin 50/50 or 70/30 but discussions were handed off to the General Managers who decided to go with the 100 percent largest unit. The committee asked the IOC and HEA to restart discussions and bring back an answer in 90 days and to give an update at the next meeting.CEA was asked to provide an estimate from lastyearofwhoowedspinandwhatwasitworth.a 7B.ACEP Study on Transmission Management ::” At the last meeting it was discussed to submit a public comment letter to the RCA from the IMCbeforethedeadlineofJune17.A letter was not submitted at the time of this meeting and theplanistoaskforanextensionandsubmititthefollowingweek. 7C.SVC Warranty Policy Mr.Bjorkquist reviewed the policy andpoetstwo options.D Have a stand-alone contract MOTIO!Mr.Therriault moved to approve the budget as presented.Motion secondedbyMr.Johnston.The motionn passed:9.REPORTS9A.Operators Report The fires did not causeany outages. 9B._Intertie Operating committee report No report was given.The Chairman asked for a report from IOC for the next meeting. 10.COMMITTEE ASSIGNMENTS e Restart spin discussions with IOC and Homer and give an update and estimated cost of owed spin at the next meeting. e AEA to present SVC warranty contract findings at the next meeting. e Once the spin issue is resolved have the Regulatory Affairs committee review the filing of the Reliability and Operating criteria with the RCA. 11.NEXT MEETING DATE IMC Meeting Minutes-June 23,2015 Page 2 of 3 The Chairman asked that the next meeting be held roughly in 60 days. Mr.Therriault informed the committee that AEA will be giving an update to their Board on the Railbelt transmission issues at the AEA board meeting on June 25 in Fairbanks. 12,ADJOURNMENT There being no further business of the IMC,the meeting adjourned at 4:08 p.m. Joe Griffith,Chairman Gene Therriault,Secretary To obtain an audio of the full meeting,contact Teri Webster (AEA)at 907-771-3074. IMC Meeting Minutes-June 23,2015 Page 3 of 3