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Approval of Reliability Standards IMC October 10, 2017 File Copy
Red .mm pez ; Lees,eigen 2 .z ayBashEeenapa a ed,Coad athee 4 ee:4 ae hee M genie EY Sit ee ile ADoteAheeeeerA.7 he te tn a Bt Ratt my Am 2 ,Bed rs ehi:3 IMC October 10,2017 FILE COPY ee .ey eeeBIaeyeieie Jom. oes TN $eFSCeeatotSpeta i aAee f5.y ¢EyKeycstie.Z iariot k j 3 "athaba44'i d E it |Pet ceNNane WHEREAS,these Intertie Management Committee Railbelt Operating and Reliability Standards are intended and therefore expected to be a living document that is to be continually updated and revised by the Alaska Intertie Management Committee when necessary. BE IT RESOLVED,the Intertie Management Committee's adopts these new and revised Railbelt Operating and Reliability Standards as presented by the Alaska Intertie Management Committee's Intertie Operating Committee. BE IT FURTHER RESOLVED THAT,the Alaska Intertie Management Committee's Intertie Operating Committee is charged with reviewing and monitoring the applicability and appropriateness of these Railbelt Operating and Reliability Standards and reporting to the Alaska Intertie Management Committee when changes and additions to these Railbelt Operating and Reliability Standards are recommended. Dated at Anchorage,Alaska this 10 day of October 2017. Chair ATTEST: ecretary {00029601.1}Page 2 of 2 -IMC Resolution 17-3 ALASKA INTERTIE MANAGEMENT COMMITTEE RESOLUTION NO.17-3 Intertie Management Committee's Railbelt Operating and Reliability Standards WHEREAS,the Intertie Management Committee's Railbelt Operating and Reliability Standards are the product of many years of work by various utility groups. WHEREAS,in October of 2013 the Intertie Management Committee adopted a set of reliability standards to govern operation of the Alaska Intertie between Anchorage and Fairbanks. WHEREAS,during the intervening time the Intertie Management Committee has developed new standards and revised existing standards within that document using the work of the North American Electric Reliability Corporation,modified to reflect the relatively small and lightly interconnected Alaska Railbelt Electric System (Alaska Railbelt). WHEREAS,the news standards proposed for adoption are,as follows: Alaska Standard AKBAL-502-0 -Planning Resource Adequacy Analysis, Assessment and Documentation Alaska Standard AKINT-001-0 -Interchange Information Alaska Standard AKMOD-025-2 -Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Alaska Standard AKMOD-026-1 -Verification of Models and Data for Generator Excitation Control System or Plant Volt/Var Control Functions Alaska Standard AKMOD-027-1 -Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions Alaska Standard AKMOD-028 -Total Transfer Capability Alaska Standard AKMOD-032-1 -Data for Power System Modeling and Analysis Alaska Standard AKMOD-033-1 -Steady-State and Dynamic System Model Validation Alaska Standard AKPRG-006 -Automatic Under-frequency Load Shedding Page 1 of 2 -IMC Resolution 17-3 ALASKA INTERTIE MANAGEMENT COMMITTEE TELEPHONIC MEETING Tuesday,October 10,2017 11:00 A.M. To participate in the meeting,dial-1-888-585-9008 -Conference room code 708 329 368 AGENDA CALL TO ORDER ROLL CALL FOR COMMITTEE MEMBERS PUBLIC ROLL CALL AGENDA APPROVAL PUBLIC COMMENTS NEW BUSINESS A.RESOLUTION 17-3 -Operating &Reliability Standards Approval COMMITTEE ASSIGNMENTS NEXT MEETING DATE --November 3,2017 ADJOURNMENT IOC Resolution 17-3 ALASKA INTERTIE MANAGEMENT COMMITTEE RESOLUTION NO.17-3 Intertie Management Committee's Railbelt Operating and Reliability Standards WHEREAS,the Intertie Management Committee's Railbelt Operating and Reliability Standards are the product of many years of work by various utility groups. WHEREAS,in October of 2013 the Intertie Management Committee adopted a set of reliability standards to govern operation of the Alaska Intertie between Anchorage and Fairbanks. WHEREAS,during the intervening time the Intertie Management Committee has developed new standards and revised existing standards within that document using the work of the North American Electric Reliability Corporation,modified to reflect the relatively small and lightly interconnected Alaska Railbelt Electric System (Alaska Railbelt). WHEREAS,the news standards proposed for adoption are,as follows: Alaska Standard AKBAL-502-0 -Planning Resource Adequacy Analysis, Assessment and Documentation Alaska Standard AKINT-001-0 -Interchange Information Alaska Standard AKMOD-025-2 -Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Alaska Standard AKMOD-026-1 -Verification of Models and Data for Generator Excitation Control System or Plant Volt/Var Control Functions Alaska Standard AKMOD-027-1 -Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions Alaska Standard AKMOD-028 -Total Transfer Capability Alaska Standard AKMOD-032-1 -Data for Power System Modeling and Analysis Alaska Standard AKMOD-033-1 -Steady-State and Dynamic System Model Validation Alaska Standard AKPRC-006 -Automatic Under-frequency Load Shedding Page 1 of 2-1MC Resolution 17-3 WHEREAS,these Intertie Management Committee Railbelt Operating and Reliability Standards are intended and therefore expected to be a living document that is to be continually updated and revised by the Alaska Intertie Management Committee when necessary. BE IT RESOLVED,the Intertie Management Committee's adopts these new and revised Railbelt Operating and Reliability Standards as presented by the Alaska Intertie Management Committee's Intertie Operating Committee. BE IT FURTHER RESOLVED THAT,the Alaska Intertie Management Committee's Intertie Operating Committee is charged with reviewing and monitoring the applicability and appropriateness of these Railbelt Operating and Reliability Standards and reporting to the Alaska Intertie Management Committee when changes and additions to these 'Railbelt Operating and Reliability Standards are recommended. Dated at Anchorage,Alaska this 10"day of October 2017. Chair ATTEST: Secretary Page 2 of 2-IMC Resolution 17-3 Railbelt Operating & Reliability Standards THE INTERTIE MANAGEMENT COMMITTEES'RAILBELT OPERATING AND RELIABILITY STANDARDS Updated October 10th,2017 Page 1 of 168 Introduction Shortly after the interconnection of the Railbelt Northern and Southern systems in 1985,the newly formed Intertie Operating Committee (IOC)reviewed,modified,and adopted the North American Electric Reliability Council's "Operating Guides for Interconnected Power Systems.” In 1992,these Operating Guides were subsumed into the Alaska Systems Coordinating Councils "Operating and Planning Guides.”In each case the planning and operating guides for the large heavily interconnected systems of the Lower 48,Canada,and Mexico required significant revision for application in the relatively small and lightly interconnected Railbelt Electric System.In the intervening years a number of changes ensued in the electric power systems of North America and,in 2005,the Railbelt Utility Group Managers (RUG)directed their respective operating managers to form an ad-hoc reliability committee tasked with reviewing the most recent version of the North American Electric Reliability Corporation's (NERC) "Reliability Standards for the Bulk Electric Systems of North America”and further with modifying them and updating the Railbelt's planning and operating standards. The "Ad-Hoc Railbelt Reliability Committee (RRC)”,as it was called,working with the State of Alaska's "Alaska Energy Authority”(AEA)formed committee working rules and open public process for the standards review.Over the following several years the RRC reviewed some 650 pages of NERC standards.Drawing on this body of knowledge and on the existing Railbelt operation and planning standards as well as current Railbelt practices selectively modified and updated the NERC standards.The following standards represent the output of this process. The group,the RRC has drafted these standards giving careful consideration to the many technical and operational issues involved with interconnecting entities to the Alaska Railbelt Electrical System (also referred to as the "Railbelt Interconnection”,"the "Railbelt Grid”or "The System')and with five overarching goals: e First,these standards set the minimum requirements for interconnection to The System, the local entity at the point of interconnection may have additional or more stringent interconnection standards. e Second,to the extent practical,these interconnection standards should be performance based rather than requirements based. e Third,to the extent practical,interconnecting entities should not be allowed to degrade the performance or reliability of The System.Such degradation in performance shall be determined by modeling the Railbelt Electrical System using the boundary dispatch cases against all category B and probable category C contingencies. e Fourth,interconnecting entities should not be required to build or improve System facilities beyond those necessary to meet the third overarching goal (above). Page 2 of 168 e Fifth,the interconnecting entity,as a condition of interconnection,shall abide by this and all other applicable Railbelt standards as they may be modified or implemented from time to time.A Balancing Authority having jurisdiction shall ascertain that the new entity agrees to these standards prior to interconnection or that another entity will absorb the new entity's obligations as additional obligations to their own.The new entity may have additional obligations imposed by the local Transmission Owner. Given the complex and technica!nature of the subject,the authors have worked diligently to maintain a high level of clarity throughout this document,in order to meet the needs of the participants,but they recognize that these standards are often based upon highly technical subject matter.To aid in this understanding a glossary of terms used in Railbelt reliability has been developed and included.If terms used in these standards are not defined in the attached glossary the reader should look to: e The specific contractual glossaries found in Railbelt agreements related to the subject under consideration i.e.,the Bradley Lake Agreements and The Alaska Intertie agreement as amended. e The Railbelt Glossary of Terms,modified from the "Glossary of Terms Used in NERC Reliability Standards” Further,to aid in understanding and implementing these requirements and criteria,the Intertie Management Committee (IMC)will require potential entities,where necessary,to obtain the assistance of qualified engineering professionals with specific expertise in the areas of electrical supply systems,power system analysis,protection,as well as control.Such professionals must have demonstrated experience in modeling,designing,constructing,commissioning and operating facilities on small,stability-limited interconnections. These guidelines are subject to revision,at any time,at the discretion of the IMC.This document is not intended to be a design specification. The essential documents are organized as follows: The first set of standards defines how entities must plan for and operate in a reliable electric system.These standards draw heavily on the work of NERC,but have been modified in many cases to recognize the lean nature of the Railbelt System,it's relatively light loading and stability limited nature. The AKBAL's and AKVAR's are the standards dealing with how balancing authorities (most of the Alaskan utilities are vertically integrated and are each their own balancing authority)work with each other.It is these standards that establish a requirement for reserve policies. The AKFAC's are the standards dealing with new construction,maintenance and ratings.These standards contain the requirements for interconnection standards.It should be noted that these interconnection standards are minimums Railbelt wide and that more stringent interconnection requirements may be imposed at the local level by the local entity. The AKINT's are the standards dealing with interchange scheduling. Page 3 of 168 The AKRES standard contains the reserves design of the Railbelt Grid.This standard draws heavily upon Exhibit H of the Amended and Restated Alaska Intertie Agreement.This standard sets the requirements for the resource adequacy,operating reserves,spinning reserves,and regulating reserves.Balancing Authorities with small units (less than 10 MW)but with non- dispatchable fuel sources may find that they have little to no spin obligation,but will likely have a large regulating obligation. The AKTPL's are the standards dealing with contingency categorization and reporting under normal and Emergency conditions. These standards are applicable to entities/equipment,where a single contingency (Category B) could result in the net change of 10 or more MW's ofgenerating capacity or load.This limit is based on our current system bias where loss of a 10 MW unit will cause the system frequency to drop 0.1 Hz.\n most of our control centers,this is the level where the first level of frequency alarms are initiated indicating a major system disturbance.As with other standards, the IMC may modify this limit as the Railbelt System changes over time. Finally,the Railbelt Glossary of Terms defines terms specific to these standards. While not specifically addressed in the standards,a prolonged interruption of the fuel supply to a generating plant is an unlikely but highly disruptive contingency.Such an event would likely be coincident to a loss of heating fuel as well and if occurring in the winter could be extremely disruptive and have significant life safety consequences. It is required that each generating entity have contingency plans for loss of the primary fuel supply.This may include but not be limited to use of alternate fuels,generation at alternate locations or Emergency power purchase agreements with other generators. Further,a significant attack on or interruption to critical Cyber-Assets could potentially cause wide spread System disruptions.To the extent practical systems of this nature must be adequately "fire-walled”or physically isolated from outside intrusion. The IMC is currently working on Critical Infrastructure Protection Standards to address these issues.They will be incorporated into the standards as soon as practical. These Railbelt standards supersede the previous reliability criteria found in the ASCC documents "ASCC Operating Guides for Interconnected Utilities and Alaska Intertie Operating Guides”and the "ASCC Planning Criteria for the reliability of interconnected electric utilities.”Where this document is silent,the ASCC documents should continue to be referenced. Sanctions for Levels of Non-Compliance when not otherwise described in the standards refer to the Sanctions Matrix for Non-Compliance.The IMC is authorized to change the sanctions as the needs may arise,but only for future infractions. All entities interconnected to the Railbelt System must fill out an Entity Function Matrix (Exhibit A)checking off the functions which they believe they will perform.The IMC will review and modify this as required and the document will be used to determine an entity's obligations as well as what areas it may participate in.Vertically integrated utilities may find themselves participating in most,if not all categories. Page 4 of 168 Unless addressed specifically in the standards,records will be kept a minimum of 5 years or if they are undergoing a review to address a question that has been raised regarding the data,the data are to be saved beyond the normal retention period until the question is formally resolved. Page 5 of 168 THE INTERTIE MANAGEMENT COMMITTEES' RAILBELT OPERATING AND RELIABILITY STANDARDS Table of Contents Alaska Standard AKBAL-001-1 -Real Power Balancing Control Performance Alaska Standard AKBAL-002-1 -Disturbance Control Performance Alaska Standard AKBAL-003-1 -Frequency Response and Bias Alaska Standard AKBAL-004-1 Time Error Correction Alaska Standard AKBAL-005-1 -Automatic Generation Control Alaska Standard AKBAL-006-1 -Inadvertent Interchange Alaska Standard AKBAL-502-0 -Planning Resource Adequacy Analysis, Assessment and Documentation Alaska Standard AKFAC-001-1 -Facility Connection Requirements Alaska Standard AKFAC-002-1 -Coordination of Plans for New Facilities Alaska Standard AKINT-001-0 -Interchange Information Alaska Standard AKMOD-025-2-Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Alaska Standard AKMOD-026-1 -Verification of Models and Data for Generator Excitation Control System or Plant Volt/Var Control Functions Alaska Standard AKMOD-027-1 -Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions Alaska Standard AKMOD-028 -Total Transfer Capability Alaska Standard AKMOD-032-1 -Data for Power System Modeling and Analysis Alaska Standard AKMOD-033-1 -Steady-State and Dynamic System Model Validation Alaska Standard AKPRC-006 -Automatic Under-frequency Load Shedding Alaska Standard AKRES-001-1 -Reserve Obligation and Allocation Alaska Standard AKTPL-001-1 -System Performance Under Normal Conditions Alaska Standard AKTPL-002-1 -System Performance Following Loss of a Single BES Element and Likely Subsequent Contingencies Alaska Standard AKTPL-003-1 -System Performance Following Loss of Two or More BES Elements Page 6 of 168 Exhibit A: Exhibit B: Exhibit C: Exhibit D: Exhibit E: Exhibit F: Exhibit G: Alaska Standard AKVAR-001-1 -Voltage and Reactive Control Alaska Standard AKVAR-002-1 -Generator Operation for Maintaining Network Voltage Schedules Entity Functional Assignments Railbelt Glossary of Terms Sanctions Matrix Railbelt Reliability Planning Guidelines Railbelt Under Frequency Load Shed Scheme ASCC Operating Guides -Interconnected Utilities -February 1992 ASCC Planning Criteria for Reliability of Interconnected Electric Utilities -May 1991 Page 7 of 168 Alaska Railbelt Standard AKBAL-001-1 -Real Power Balancing Control Performance A.Introduction 1. 2. 3. 5. Title:Real Power Balancing Control Performance Number:AKBAL-001-1 Purpose: To maintain Interconnection steady-state frequency within defined limits by balancing real power demand and supply in real-time. Applicability: 4.1.Balancing Authorities Effective Date:|4 months from package adoption B.Requirements RI.Each Balancing Authority shall operate such that,on a rolling 12-month basis,the average of the clock-minute averages of the Balancing Authority's Area Control Error (ACE)divided by 10B (B is the clock-minute average of the Balancing Authority Area's Frequency Bias)times the corresponding clock-minute averages of the Interconnection's Frequency Error is less than a specific limit.This limit €17 is a constant derived from a targeted frequency bound (separately calculated for each Interconnection)that is reviewed and set as necessary by the RRO. A VO period Ga *1ACE,>-108B,},AVG period -|*AF |Se)or si -108,}, The equation for ACE is: ACE =(NIa -NIs)-10B (Fa -Fs)-IME where: e NlIa is the algebraic sum of actual flows on all tie lines. e Nis is the algebraic sum of scheduled flows on all tie lines. e B is the Frequency Bias Setting (MW/0.1 Hz)for the Balancing Authority. The constant factor 10 converts the frequency setting to MW/Hz. e Fa is the actual frequency. e Fs is the scheduled frequency.Fs is normally 60 Hz but may be offset to effect manual time error corrections. e Ime is the meter error correction factor typically estimated from the difference between the integrated hourly average of the net tie line flows (NI)and the hourly net interchange demand measurement (megawatt-hour).This term should normally be very small or zero. Alaska Railbelt Standard AKBAL-00 1-1 -Real Power Balancing Control Performance Page 8 of 168 R2.Each Balancing Authority shall operate such that its average ACE for at least 90%of clock-ten-minute periods (6 non-overlapping periods per hour)during a calendar month is within a specific limit,referred to as Lio. AVG (ACE,)<Lig10-minute where: Lio=1.65 €104/(-10B:)(-10B:) £19 is a constant derived from the targeted frequency bound.It is the targeted root-mean-square (RMS)value of ten-minute average Frequency Error based on frequency performance over a given year.The bound,€10,is the same for every Balancing Authority Area within an Interconnection,and Bs is the sum of the Frequency Bias Settings of the Balancing Authority Areas in the respective Interconnection.For Balancing Authority Areas with variable bias, this is equal to the sum of the minimum Frequency Bias Settings. R3.Each Balancing Authority providing Overlap Regulation Service shall evaluate Requirement R1 (i.e.,Control Performance Standard 1 or CPS1)and Requirement R2 (i.e.,Control Performance Standard 2 or CPS2)using the characteristics of the combined ACE and combined Frequency Bias Settings. R4.Any Balancing Authority receiving Overlap Regulation Service shall not have its control performance evaluated (i.e.from a control performance perspective,the Balancing Authority has shifted all control requirements to the Balancing Authority providing Overlap Regulation Service). C.Measures M1.Each Balancing Authority shall achieve,as a minimum,Requirement |(CPS1) compliance of 100%. CPS]is calculated by converting a compliance ratio to a compliance percentage as follows: CPS1 =(2 -CF)*100% The frequency-related compliance factor,CF,is a ratio of all one-minute compliance parameters accumulated over 12 months divided by the target frequency bound: CF CF -=(€,) Where: €1 is defined in Requirement R1. Alaska Railbelt Standard AKBAL-001-1 -Real Power Balancing Control Performance Page 9 of 168 The rating index CFi2-month is derived from 12 months of data.The basic unit of data comes from one-minute averages of ACE,Frequency Error and Frequency Bias Settings. A clock-minute average is the average of the reporting Balancing Authority's valid measured variable (i.e.,for ACE and for Frequency Error)for each sampling cycle during a given clock-minute. A clock-minute average is the average of the reporting Balancing Authority's valid measured variable (i.e.,for ACE and for Frequency Error)for each sampling cycle during a given clock-minute. >A CE sampling cyclesin clock-minute |{ACE _ Teompling cyclesin clock-minute |0B clock-minute .10B AF _>AF.smpting eyclesin clock-minute clock-minute Tsmpling cyclesin clock-minute The Balancing Authority's clock-minute compliance factor (CF)becomes: CF sock-minute =(A)*AF vtockeminute710Bclock-minute Normally,sixty (60)clock-minute averages of the reporting Balancing Authority's ACE and of the respective Interconnection's Frequency Error will be used to compute the respective hourly average compliance parameter. >CF vsock-minute clock-minute samples in hour CF.clock-hour - The reporting Balancing Authority shall be able to recalculate and store each of the respective clock-hour averages (CF clock-hour average-month)as well as the respective number of samples for each of the twenty-four (24)hours (one for each clock-hour,i.e.,hour-ending (HE)0100,HE 0200,...,HE 2400). >[(CF oct -hour MA pne-minute samples in clock-hour )] CF __days-in-month clock-hour average-month >[71 .ne-minute samples in clock -hour ] days-in month >(CF ac -hour average -month YO one-minute samples in clock -hour averages )] __hours-in-dayCFonth >{72 ne-minute samples in clock -hour averages ]hours -in day The 12-month compliance factor becomes: Alaska Railbelt Standard AKBAL-001-1 -Real Power Balancing Control Performance Page 10 of 168 12 »(CF ronth-i N(one-minute samples in month -i )] CF =I 12-month 12 >[n (one-minute samples in month)-i ] i=l In order to ensure that the average ACE and Frequency Deviation calculated for any one-minute interval is representative of that one-minute interval,it is necessary that at least 50%of both ACE and Frequency Deviation samples during that one-minute interval be present.Should a sustained interruption in the recording of ACE or Frequency Deviation due to loss of telemetering or computer unavailability result in a one-minute interval not containing at least 50%of samples of both ACE and Frequency Deviation,that one-minute interval shall be excluded from the calculation of CPS1. M2.Each Balancing Authority shall achieve,as a minimum,Requirement R2 (CPS2) compliance of 90%.CPS2 relates to a bound on the ten-minute average of ACE.A compliance percentage is calculated as follows: Violations,an #100-Unavailabk Periods,,,..,)CPS2 =|1- -(Total Periods month The violations per month are a count of the number of periods that ACE clock-ten- minutes exceeded Lio.ACE clock-ten-minutes is the sum of valid ACE samples within a clock-ten-minute period divided by the number of valid samples. Violation clock-ten-minutes =Oif >,ACE S Ly n samples in 10-minutes =lif >)ACE >Ly n samples in 10-minutes Each Balancing Authority shall report the total number of violations and unavailable periods for the month.Lio is defined in Requirement R2. Since CPS2 requires that ACE be averaged over a discrete time period,the same factors that limit total periods per month will limit violations per month.The calculation of total periods per month and violations per month,therefore,must be discussed jointly. A condition may arise which may impact the normal calculation of total periods per month and violations per month.This condition is a sustained interruption in the recording of ACE. In order to ensure that the average ACE calculated for any ten-minute interval is representative of that ten-minute interval,it is necessary that at least half the ACE data Alaska Railbelt Standard AKBAL-001-1 -Real Power Balancing Control Performance Page 11 of 168 samples are present for that interval.Should half or more of the ACE data be unavailable due to loss of telemetering or computer unavailability,that ten-minute interval shall be omitted from the calculation of CPS2. D.Compliance 1.Compliance Monitoring Process 1.1. 1.2. 1.3. 1.4. Compliance Monitoring Responsibility Regional Reliability Organization. Compliance Monitoring Period and Reset Timeframe One calendar month. Data Retention The data that supports the calculation of CPS1 and CPS2 (Attachment 1-AKBAL- 001-0)are to be retained in electronic form for at least a one-year period.If the CPS1 and CPS2 data for a Balancing Authority Area are undergoing a review to address a question that has been raised regarding the data,the data are to be saved beyond the normal retention period until the question is formally resolved.Each Balancing Authority shall retain for a rolling 12-month period the values of:one- minute average ACE (ACE)),one-minute average Frequency Error,and,if using variable bias,one-minute average Frequency Bias. Additional Compliance Information None. 2.Levels of Non-Compliance -CPS1 2.1.Level 1:The Balancing Authority Area's value of CPS1 is less than 100%but greater than or equal to 95%. 2.2.Level 2:The Balancing Authority Area's value of CPS1 is less than 95%but greater than or equal to 90%. 2.3.Level 3:The Balancing Authority Area's value of CPS1 is less than 90%but- 2.4. greater than or equal to 85%. Level 4:The Balancing Authority Area's value of CPS1 is less than 85%. 3.Levels of Non-Compliance -CPS2 3.1.Level 1:The Balancing Authority Area's value of CPS2 is less than 90%but greater than or equal to 85%. 3.2.Level 2:The Balancing Authority Area's value of CPS2 is less than 85%but greater than or equal to 80%. 3.3.Level 3:The Balancing Authority Area's value of CPS2 is less than 80%but greater than or equal to 75%. 3.4.Level 4:The Balancing Authority Area's value of CPS2 is less than 75%. E.Regional Differences None identified. Alaska Railbelt Standard AKBAL-001-1 -Real Power Balancing Control Performance Page 12 of 168 Version History Version Date Action Change Tracking 0 June 7,2013 Original New 1 May 2,2016 Remove capacity/reserve graph Modify Attachment 1-AKBAL-001-1 CPS1 and CPS2 Data CPS1 DATA Description Retention Requirements £)A constant derived from the targeted frequency |Retain the value of €)used in CPS1 calculation. bound.This number is the same for each Balancing Authority Area in the Interconnection. ACE;The clock-minute average of ACE.Retain the 1-minute average values of ACE (525,600 values). B,The Frequency Bias of the Balancing Authority |Retain the value(s)of B;used in the CPS1Area.calculation. Fa The actual measured frequency.Retain the 1-minute average frequency values (525,600 values). Fs Scheduled frequency for the Interconnection.Retain the 1-minute average frequency values (525,600 values). CPS2 DATA Description Retention Requirements Vv Number of incidents per hour in which the Retain the values of V used in CPS2 absolute value of ACE clock-ten-minutes is calculation. greater than Lio. £10 A constant derived from the frequency bound.|Retain the value of €19 used in CPS2 It is the same for each Balancing Authority calculation. Area within an Interconnection, Bi The Frequency Bias of the Balancing Authority |Retain the value of B\used in the CPS2Area.calculation. B,The sum of Frequency Bias of the Balancing Retain the value of B,used in the CPS2 Authority Areas in the respective calculation.Retain the 1-minute minimum bias Interconnection.For systems with variable value (525,600 values). bias,this is equal to the sum of the minimum Frequency Bias Setting. U Number of unavailable ten-minute periods per |Retain the number of 10-minute unavailable hour used in calculating CPS2.periods used in calculating CPS2 for the reporting period. Alaska Railbelt Standard AKBAL-00 1-1 --Real Power Balancing Control Performance Page 13 of 168 Alaska Railbelt Standard AKBAL-002-1 -Disturbance Control Performance A.Introduction 1. 2. 3. 5. Title:Disturbance Control Performance Number:AKBAL-002-1 Purpose: The purpose of the Disturbance Control Standard (DCS)is to ensure the Balancing Authority is able to utilize its Contingency Reserve to balance resources and demand and return Interconnection frequency within defined limits following a Reportable Disturbance.Because generator failures are far more common than significant losses of load and because Contingency Reserve activation does not typically apply to the loss of load,the application of DCS is limited to the loss of supply and does not apply to the loss of load. Applicability: 4.1.Balancing Authorities 4.2.Reserve Sharing Groups (Balancing Authorities may meet the requirements of AKBAL-002-1 through participation in a Reserve Sharing Group.) 4.3.Regional Reliability Organizations Effective Date:|4 months from package adoption B.Requirements R1.Each Balancing Authority shall have access to and/or operate Contingency Reserve to respond to Disturbances.Contingency Reserve may be supplied from generation, energy storage systems,load shed,controllable load resources,other devices,or coordinated adjustments to Interchange Schedules. R1.1.A Balancing Authority may elect to fulfill its Contingency Reserve obligations by participating as a member of a Reserve Sharing Group.In such cases,the Reserve Sharing Group shall have the same responsibilities and obligations as each Balancing Authority with respect to monitoring and meeting the requirements of Standard AKBAL-002-1. Each Regional Reliability Organization,sub-Regional Reliability Organization or Reserve Sharing Group shall specify its Contingency Reserve policies,including: R2.1.The minimum reserve requirement for the group,as determined by coordinated Railbelt under frequency load shed/spinning reserve/droop coordination study. R2.2.Its allocation among members,as defined in the Reserve Policy,and as modified by coordinated Railbelt under frequency load shed/spinning reserve/droop coordination studies. R2.3.The permissible mix of Operating Reserve -Spinning and Operating Reserve - Supplemental that may be included in Contingency Reserve. R2.4.The procedure for applying Contingency Reserve in practice including recommendations on geographic dispersion. Alaska Railbelt Standard AKBAL-002-1 -Disturbance Control Performance Page 14 of 168 R2.5.The limitations,if any,upon the amount of interruptible load that may be included. R2.6.The same portion of resource capacity (e.g.reserves from jointly owned generation)shall not be counted more than once as Contingency Reserve by multiple Balancing Authorities. R3.Each Balancing Authority or Reserve Sharing Group shall activate sufficient Contingency Reserve to comply with the DCS. R3.1.Asa minimum,the Balancing Authority or Reserve Sharing Group shall carry at least enough Contingency Reserve to cover the most severe single contingency.All Balancing Authorities and Reserve Sharing Groups shall review,no less frequently than annually,their probable contingencies to determine their prospective most severe single contingencies. R4.A Balancing Authority or Reserve Sharing Group shall meet the Disturbance Recovery Criterion within the Disturbance Recovery Period for 100%of Reportable Disturbances.The Disturbance Recovery Criterion is: R4.1.A Balancing Authority shall return its ACE to zero if its ACE just prior to the Reportable Disturbance was positive or equal to zero.For negative initial ACE values just prior to the Disturbance,the Balancing Authority shall return ACE to its pre-Disturbance value. R4.2.The default Disturbance Recovery Period is 10 minutes after the start of a Reportable Disturbance.This period may be adjusted to better suit the needs of an Interconnection based on analysis approved by the RRO. R5.Each Reserve Sharing Group shall comply with the DCS.A Reserve Sharing Group shall be considered in a Reportable Disturbance condition whenever a group member has experienced a Reportable Disturbance and calls for the activation of Contingency Reserves from one or more other group members.(If a group member has experienced a Reportable Disturbance but does not call for reserve activation from other members of the Reserve Sharing Group,then that member shall report as a single Balancing Authority.)Compliance may be demonstrated by either of the following two methods: R5.1.The Reserve Sharing Group reviews group ACE (or equivalent)and demonstrates compliance to the DCS.To be in compliance,the group ACE (or its equivalent)must meet the Disturbance Recovery Criterion after the schedule change(s)related to reserve sharing have been fully implemented,and within the Disturbance Recovery Period. or R5.2..The Reserve Sharing Group reviews each member's ACE in response to the activation of reserves.To be in compliance,a member's ACE (or its equivalent)must meet the Disturbance Recovery Criterion after the schedule change(s)related to reserve sharing have been fully implemented,and within the Disturbance Recovery Period. R6.A Balancing Authority or Reserve Sharing Group shall fully restore its Contingency Reserves within the Contingency Reserve Restoration Period for its Interconnection. Alaska Railbelt Standard AKBAL-002-1 -Disturbance Control Performance . Page 15 of 168 R6.1.The Contingency Reserve Restoration Period begins at the end of the Disturbance Recovery Period. R6.2.The default Contingency Reserve Restoration Period is 50 minutes.This period may be adjusted to better suit the reliability targets of the Interconnection based on analysis approved by the RRO. C.Measures M1.A Balancing Authority or Reserve Sharing Group shall calculate and report compliance with the Disturbance Control Standard for all Disturbances involving all generating unit trips,transmission line trips,and distribution level disturbances that result in frequency deviation >.2 Hz.Regions may,at their discretion,require a lower reporting threshold.Disturbance Control Standard is measured as the percentage recovery (Ri). For loss of generation: oe ear if ACEa <0 awti ™Pavan then =40 sc ACE, os E,R -MW 55 max(0,ACE,ACE'y)¢ro q0%g * MW oss 100 , -120 ' if ACEa >0 no then °r on.Recovery imeR,=MW,,,, ™max(0,-ACEy ),100%3 val ACE, M W ross Q aor ACE. -60 80 -100 ra where: e MWy1oss is the MW size of the Disturbance as measured at the beginning of the loss, ACEa is the pre-disturbance ACE, ACE is the maximum algebraic value of ACE measured within the ten minutes following the Disturbance.A Balancing Authority or Reserve Sharing Group may,at its discretion,set ACEmM =ACE10 min,and The Balancing Authority or Reserve Sharing Group shall record the MWLoss value as measured at the site of the loss to the extent possible.The value should not be measured as a change in ACE since governor response and AGC response may introduce error. The Balancing Authority or Reserve Sharing Group shall base the value for ACEa on the average ACE over the period just prior to the start of the Disturbance (10 and 60 Alaska Railbelt Standard AKBAL-002-1 -Disturbance Control Performance Page 16 of 168 seconds prior and including at least 4 scans of ACE).In the illustration below,the horizontal line represents an averaging of ACE for 15 seconds prior to the start of the Disturbance with a result of ACEa =-25 MW.>Tt>The average percent recovery is the arithmetic average of all the calculated Ri's for Reportable Disturbances during a given quarter.Average percent recovery is similarly calculated for excludable Disturbances. D.Compliance 1.Compliance Monitoring Process Compliance with the DCS shall be measured on a percentage basis as set forth in the measures above. Each Balancing Authority or Reserve Sharing Group shall submit one completed copy of the DCS form,"Alaskan Railbelt Control Performance Standard Survey -All Interconnections”to its Reliability Assurer contact no later than the 10th day following the end of the calendar quarter (i.e.April 10th,July 10th,October 10th, January 10th). 1.1.Compliance Monitoring Responsibility Regional Reliability Organization. 1.2.Compliance Monitoring Period and Reset Timeframe Compliance for DCS will be evaluated for each reporting period.Reset is one calendar quarter without a violation. 1.3.Data Retention The data that support the calculation of DCS are to be retained in electronic form for at least a one-year period.If the DCS data for a Reserve Sharing Group and Balancing Authority Area are undergoing a review to address a question that has been raised regarding the data,the data are to be saved beyond the normal retention period unti!the question is formally resolved. 1.4.Additional Compliance Information Reportable Disturbances -Reportable Disturbances are contingencies involving any generating unit trips,transmission line trips,and distributionAlaskaRailbeltStandardAKBAL-002-1 -Disturbance Control Performance Page 17 of 168 level disturbances that result in frequency deviation >.2 Hz.A Regional Reliability Organization,sub-Regional Reliability Organization or Reserve Sharing Group may optionally reduce this criteria,provided that normal operating characteristics are not being considered or misrepresented as contingencies.Normal operating characteristics are excluded because DCS only measures the recovery from sudden,unanticipated losses of supply-side resources. Simultaneous Contingencies -Multiple Contingencies occurring within one minute or less of each other shall be treated as a single Contingency.Ifa multiple contingency event occurs within a time span greater than one minute the regional reliability organization will have at its discretion the option to consider it a single contingency.Ifthe combined magnitude of the multiple Contingencies exceeds the most severe single Contingency,the loss shall be reported,but excluded from compliance evaluation. Multiple Contingencies within the Reportable Disturbance Period - Additional Contingencies that occur after one minute of the start of a Reportable Disturbance but before the end of the Disturbance Recovery Period can be excluded from evaluation.The Balancing Authority or Reserve Sharing Group shall determine the DCS compliance of the initial Reportable Disturbance by performing a reasonable estimation of the response that would have occurred had the second and subsequent contingencies not occurred. Multiple Contingencies within the Contingency Reserve Restoration Period -Additional Reportable Disturbances that occur after the end of the Disturbance Recovery Period but before the end of the Contingency Reserve Restoration Period shall be reported and included in the compliance evaluation.However, the Balancing Authority or Reserve Sharing Group can request a waiver from the Resources Subcommittee for the event if the contingency reserves were rendered inadequate by prior contingencies and a good faith effort to replace contingency reserve can be shown. 2.Levels of Non-Compliance A representative from each Balancing Authority or Reserve Sharing Group that was non-compliant in the calendar quarter most recently completed shall provide written documentation verifying that the Balancing Authority or Reserve Sharing Group will apply the appropriate DCS performance adjustment beginning the first day of the succeeding month,and will continue to apply it for three months.The written documentation shall accompany the quarterly Disturbance Control Standard Report when a Balancing Authority or Reserve Sharing Group is non-compliant. 2.1.Level1:|Value of the average percent recovery for the quarter is less than 100%but greater than or equal to 95%. Alaska Railbelt Standard AKBAL-002-1 -Disturbance Control Performance Page 18 of 168 2.2.Level2:Value of the average percent recovery for the quarter is less than 95%but greater than or equal to 90%. 2.3.Level3:Value of average percent recovery for the quarter is less than 90% but greater than or equal to 85%. 2.4.Level4:Value of average percent recovery for the quarter is less than 85%. E.Regional Differences None identified. Version History Version Date Action Change Tracking 1 May 2,2016 45 minute recovery defined terms 2 October 20,Renamed the Reserve Policy change 2016 Alaska Railbelt Standard AKBAL-002-1 -Disturbance Control Performance Page 19 of 168 Alaska Railbelt Standard AKBAL-003-1 -Frequency Response and Bias A.Introduction 1.Title:Frequency Response and Bias 2.Number:AKBAL-003-1 3.Purpose: This standard provides a consistent method for calculating the Frequency Bias component of ACE. 4.Applicability: 4.1.Balancing Authorities 5.Effective Date:1 month from package adoption B.Requirements R1.Each Balancing Authority shall review its Frequency Bias Settings by January 1 of each year and recalculate its setting to reflect any change in the Frequency Response of the Balancing Authority Area. R1.1.The Balancing Authority may change its Frequency Bias Setting,and the method used to determine the setting,whenever any of the factors used to determine the current bias value change. R1.2.Each Balancing Authority shall report its Frequency Bias Setting,and method for determining that setting,to the RRO. R2.Each Balancing Authority shall establish and maintain a Frequency Bias Setting that is as Close as practical to,or greater than,the Balancing Authority's Frequency Response.Frequency Bias may be calculated several ways: R2.1.The Balancing Authority may use a fixed Frequency Bias value which is based on a fixed,straight-line function of Tie Line deviation versus Frequency Deviation.The Balancing Authority shall determine the fixed value by observing and averaging the Frequency Response for several Disturbances during on-peak hours. R2.2.The Balancing Authority may use a variable (linear or non-linear)bias value, which is based on a variable function of Tie Line deviation to Frequency Deviation.The Balancing Authority shall determine the variable frequency bias value by analyzing Frequency Response as it varies with factors such as load,generation,governor characteristics,and frequency. R3.Each Balancing Authority shall operate its Automatic Generation Control (AGC)on Tie Line Frequency Bias,unless such operation is adverse to system or Interconnection reliability. R4.Balancing Authorities that use Dynamic Scheduling or Pseudo-ties for jointly owned units shall reflect their respective share of the unit governor droop response in their respective Frequency Bias Setting. Alaska Railbelt Standard AKBAL-003-1 -Frequency Response and Bias Page 20 of 168 R4.1.Fixed schedules for jointly owned units mandate that Balancing Authority (A) that contains the Jointly Owned Unit must incorporate the respective share of the unit governor droop response for any Balancing Authorities that have fixed schedules (B and C).See the diagram below. R4.2._The Balancing Authorities that have a fixed schedule (B and C)but do not contain the Jointly Owned Unit shall not include their share of the governor droop response in their Frequency Bias Setting. Jointly Owned Unit R5.Balancing Authorities that serve native load shall have a monthly average Frequency Bias Setting that is at least 1%of the Balancing Authority's estimated yearly peak demand per 0.1 Hz change. R5.1.Balancing Authorities that do not serve native load shall have a monthly average Frequency Bias Setting that is at least 1%of its estimated maximum generation level in the coming year per 0.1 Hz change. R6.A Balancing Authority that is performing Overlap Regulation Service shall increase its Frequency Bias Setting to match the frequency response of the entire area being controlled.A Balancing Authority shall not change its Frequency Bias Setting when performing Supplemental Regulation Service. C.Measures M1.Each Balancing Authority shall perform Frequency Response surveys when called for by the RRO to determine the Balancing Authority's response to Interconnection Frequency Deviations. D.Compliance 1.Compliance Monitoring Process 1.1.Railbelt Regional Reliability Organization 2.Non-Compliance | Level 1. E.Regional Differences Alaska Railbelt Standard AKBAL-003-1 -Frequency Response and Bias Page 21 of 168 None identified. Version History Version Date Action Change Tracking l May 2,2016 no change in meaning defined terms Alaska Railbelt Standard AKBAL-003-1 -Frequency Response and Bias Page 22 of 168 Alaska Railbelt Standard AKBAL-004-1 -Time Error Correction A. E. Introduction 1.'Title:Time Error Correction 2.Number:AKBAL-004-1 3.Purpose: 5. The purpose of this standard is to ensure that Time Error Corrections are conducted in a manner that does not adversely affect the reliability of the Interconnection. Although encouraged,there is no obligation for an electrical island to obtain the same 'time error as a neighboring island prior to synchronization. Applicability: 4.1.Reliability Coordinators 4.2.Balancing Authorities Effective Date:-1 month from package adoption Requirements RI. R3. R4. Only a Reliability Coordinator shall be eligible to act as Interconnection Time Monitor.A single Reliability Coordinator in each Interconnection shall be designated by the RRO to serve as Interconnection Time Monitor. The Interconnection Time Monitor shall monitor Time Error and shall initiate or terminate corrective action orders in accordance with the Time Error Correction Procedure. Each Balancing Authority,when requested,shall participate in a Time Error Correction by one of the following methods: R3.1.The Balancing Authority shall offset its frequency schedule by 0.02 Hertz, leaving the Frequency Bias Setting normal;or R3.2.The Balancing Authority shall offset its Net Interchange Schedule (MW)by an amount equal to the computed bias contribution during a 0.02 Hertz Frequency Deviation (i.e.20%of the Frequency Bias Setting). Any Reliability Coordinator in an Interconnection shall have the authority to request the Interconnection Time Monitor to terminate a Time Error Correction in progress,or a scheduled Time Error Correction that has not begun,for reliability considerations. R4.1.Balancing Authorities that have reliability concerns with the execution of a Time Error Correction shall notify their Reliability Coordinator and request the termination of a Time Error Correction in progress. Measures Not specified. Non-Compliance Level 1 Regional Differences Alaska Railbelt Standard AKBAL-004-1 -Time Error Correction Page 23 of 168 None identified. Version History Version Date Action Change Trackin 0 June 7,2013 Original New 1 May 2,2016 No time zero prior to sync Modify Alaska Railbelt Standard AKBAL-004-1 -Time Error Correction Page 24 of 168 Alaska Railbelt Standard AKBAL-005-1 -Automatic Generation Control A.Introduction 1.'Title:Automatic Generation Control 2.Number:AKBAL-005-1 3.Purpose: This standard establishes requirements for Balancing Authority Automatic Generation Control (AGC)necessary to calculate Area Control Error (ACE)and to routinely deploy the Regulating Reserve.The standard also ensures that all facilities and load electrically synchronized to the Interconnection are included within the metered boundary of a Balancing Authority Area so that balancing of resources and demand can be achieved. 4.Applicability: 4.1.Balancing Authorities 4.2.Generator Operators 4.3.Transmission Operators 4.4.Load Serving Entities 5.Effective Date:1 month from package adoption B.Requirements R1.All generation,transmission,and load operating within an Interconnection must be included within the metered boundaries of a Balancing Authority Area. R1.1.Each Generator Operator with generation facilities operating in an Interconnection shall ensure that those generation facilities are included within the metered boundaries of a Balancing Authority Area. R1.2._Each Transmission Operator with transmission facilities operating in an Interconnection shall ensure that those transmission facilities are included within the metered boundaries of a Balancing Authority Area. R1.3.Each Load-Serving Entity with load operating in an Interconnection shall ensure that those loads are included within the metered boundaries of a Balancing Authority Area. R2.Each Balancing Authority shall maintain Regulating Reserve that can be controlled by AGC to meet the Control Performance Standard. R3.A Balancing Authority providing Regulation Service shall ensure that adequate metering,communications,and control equipment are employed to prevent such service from becoming a Burden on the Interconnection or other Balancing Authority Areas. R4.A Balancing Authority providing Regulation Service shall notify the Host Balancing Authority for whom it is controlling if it is unable to provide the service,as well as any Intermediate Balancing Authorities. Alaska Railbelt Standard AKBAL-005-1 -Automatic Generation Control Page 25 of 168 RS. R6. R7. R8. R9. R10. R11. R12. A Balancing Authority receiving Regulation Service shall ensure that backup plans are in place to provide replacement Regulation Service should the supplying Balancing Authority no longer be able to provide this service. The Balancing Authority's AGC shall compare total Net Actual Interchange to total Net Scheduled Interchange plus Frequency Bias obligation to determine the Balancing Authority's ACE.Single Balancing Authorities operating asynchronously may employ alternative ACE calculations such as (but not limited to)flat frequency control.Ifa Balancing Authority is unable to calculate ACE for more than 30 minutes,it shall notify its Reliability Coordinator. The Balancing Authority shall operate AGC continuously unless such operation adversely impacts the reliability of the Interconnection.If AGC has become inoperative,the Balancing Authority shall use manual control to adjust generation to maintain the Net Scheduled Interchange. The Balancing Authority shall ensure that data acquisition for and calculation of ACE occur at least every four seconds. R8.1.Each Balancing Authority shall provide redundant and independent frequency metering equipment that shall automatically activate upon detection of failure of the primary source.This overall installation shall provide a minimum availability of 99.95%. The Balancing Authority shall include all Interchange Schedules with Adjacent Balancing Authorities in the calculation of Net Scheduled Interchange for the ACE equation. R9.1.Balancing Authorities with a high voltage direct current (HVDC)link to _another Balancing Authority connected asynchronously to their Interconnection may choose to omit the Interchange Schedule related to the HVDC link from the ACE equation if it is modeled as internal generation or load. The Balancing Authority shall include all Dynamic Schedules in the calculation of Net Scheduled Interchange for the ACE equation. Balancing Authorities shall include the effect of ramp rates,which shall be identical and agreed to between affected Balancing Authorities,in the Scheduled Interchange values to calculate ACE. Each Balancing Authority shall include all Tie Line flows with Adjacent Balancing Authority Areas in the ACE calculation. R12.1.Balancing Authorities that share a tie shall ensure Tie Line MW metering is telemetered to both control centers,and emanates from a common,agreed-upon source using common primary metering equipment.Balancing Authorities shall ensure that megawatt-hour data is telemetered or reported at the end of each hour. R12.2.Balancing Authorities shall ensure the power flow and ACE signals that are utilized for calculating Balancing Authority performance or that are transmitted for Regulation Service are not filtered prior to transmission,except for the Anti- Aliasing Filters of Tie Lines. Alaska Railbelt Standard AKBAL-005-1 -Automatic Generation Control Page 26 of 168 R12.3.Balancing Authorities shall install common metering equipment where Dynamic Schedules or Pseudo-Ties are implemented between two or more Balancing Authorities to deliver the output of jointly owned units or to serve remote load. R13.Each Balancing Authority shall perform hourly error checks using Tie Line megawatt- hour meters with common time synchronization to determine the accuracy of its control equipment.The Balancing Authority shall adjust the component (e.g.,Tie Line meter)of ACE that is in error (if known)or use the interchange meter error (IME) term of the ACE equation to compensate for any equipment error until repairs can be made. R14.The Balancing Authority shall provide its operating personnel with sufficient instrumentation and data recording equipment to facilitate monitoring of control performance,generation response,and after-the-fact analysis of area performance.As a minimum,the Balancing Authority shall provide its operating personnel with real- time values for ACE,Interconnection frequency and Net Actual Interchange with each Adjacent Balancing Authority Area. R15.The Balancing Authority shall provide adequate and reliable backup power supplies and shall periodically test these supplies at the Balancing Authority's control center and other critical locations to ensure continuous operation of AGC and vital data recording equipment during loss of the normal power supply. R16.The Balancing Authority shall sample data at least at the same periodicity with which ACE is calculated.The Balancing Authority shall flag missing or bad data for operator display and archival purposes.The Balancing Authority shall collect coincident data to the greatest practical extent,i-e.,ACE,Interconnection frequency, Net Actual Interchange,and other data shall all be sampled at the same time. R17.Each Balancing Authority shall at least annually check and calibrate its time error and frequency devices against a common reference.The Balancing Authority shall adhere to the minimum values for measuring devices as listed below: Device Accuracy Digital frequency transducer <0.001 Hz MW,MVAR,and voltage transducer <0.25 %of full scale Remote terminal unit <0.25 %of full scale Potential transformer <0.30 %of full scale Current transformer <0.50 %of full scale C.Measures Not specified. D.Compliance 1.Compliance Monitoring Process 1.1.Compliance Monitoring Responsibility Alaska Railbelt Standard AKBAL-005-1 -Automatic Generation Control Page 27 of 168 1.2. 1.3. 1.4, Balancing Authorities shall be prepared to supply data to the RRO in the format defined below: 1.1.1. 1.1.2. Within one week upon request,Balancing Authorities shall provide the Regional Reliability Organization CPS source data in daily CSV files with time stamped one minute averages of:1)ACE and 2)Frequency Error. Within one week upon request,Balancing Authorities shall provide the Regional Reliability Organization DCS source data in CSV files with time stamped scan rate values for:1)ACE and 2)Frequency Error for a time period of two minutes prior to and thirty minutes after the identified Disturbance. Compliance Monitoring Period and Reset Timeframe Not specified. Data Retention 1.3.1. 1.3.2. Each Balancing Authority shall retain its ACE,actual frequency, Scheduled Frequency,Net Actual Interchange,Net Scheduled Interchange,Tie Line meter error correction and Frequency Bias Setting data in digital format at the same scan rate at which the data is collected for at least one year. Each Balancing Authority or Reserve Sharing Group shall retain documentation of the magnitude of each Reportable Disturbance as well as the ACE charts and/or samples used to calculate Balancing Authority or Reserve Sharing Group disturbance recovery values.The data shall be retained for one year following the reporting quarter for which the data was recorded. Additional Compliance Information Not specified. 2.Levels of Non-Compliance Level 2. E.Regional Differences None identified. Version History Version Date Action "|Change Tracking 1 May 2,2016 No change in meaning Defined terms Alaska Railbelt Standard AKBAL-005-1 -Automatic Generation Control Page 28 of 168 Alaska Railbelt Standard AKBAL-006-1 -Inadvertent Interchange A.Introduction 1. 2. 3. 5. Title:Inadvertent Interchange Number:AKBAL-006-1 Purpose: This standard defines a process for monitoring Balancing Authorities to ensure that,over the long term,Balancing Authority Areas do not excessively depend on other Balancing Authority Areas in the Interconnection for meeting their demand or Interchange obligations. Applicability: 4.1.Balancing Authorities Effective Date 6 months from package adoption B.Requirements R1. R2. R3. R4. Each Balancing Authority shall calculate and record hourly Inadvertent Interchange. Each Balancing Authority shall include all tie lines that connect to its Adjacent Balancing Authority Areas in its Inadvertent Interchange account.The Balancing Authority shall take into account interchange served by jointly owned generators. Each Balancing Authority shall ensure all of its Balancing Authority Area interconnection points are equipped with common megawatt-hour meters,with readings provided hourly to the control centers of Adjacent Balancing Authorities. Adjacent Balancing Authority Areas shall operate to a common Net Interchange Schedule and Net Actual Interchange value and shall record these hourly quantities, with like values but opposite sign.Each Balancing Authority shall compute its Inadvertent Interchange based on the following: R4.1.Each Balancing Authority,by the end of the next business day,shall agree with its Adjacent Balancing Authorities to: R4.1.1.The hourly values of Net Interchange Schedule. R4.1.2.The hourly integrated megawatt-hour values of Net Actual Interchange. R4.2.Each Balancing Authority shall use the agreed-to daily and monthly accounting data to compile its monthly accumulated Inadvertent Interchange for the On- Peak and Off-Peak hours of the month, R4.3.A Balancing Authority shall make after-the-fact corrections to the agreed-to daily and monthly accounting data only as needed to reflect actual operating conditions (e.g.a meter being used for control was sending bad data).Changes or corrections based on non-reliability considerations shall not be reflected in the Balancing Authority's Inadvertent Interchange.After-the-fact corrections to scheduled or actual values will not be accepted without agreement of the Adjacent Balancing Authorities. Adjacent Balancing Authorities that cannot mutually agree upon their respective Net Actual Interchange or Net Scheduled Interchange quantities by the 15th calendar day of the following month shall,for the purposes of dispute Alaska Railbelt Standard AKBAL-006-1 -Inadvertent Interchange Page 29 of 168 resolution,submit a report to their respective Regional Reliability Organization contact.The report shall describe the nature and the cause of the dispute as well as a process for correcting the discrepancy. R5.Reserved for future use. C.Measures None Specified D.Compliance Monitor Regional Reliability Organization E.Compliance 1.Compliance Monitoring Process 1.1.Each Balancing Authority shall maintain a monthly summary of Inadvertent Interchange available to the RRO upon request.These summaries shall not include any after-the-fact changes that were not agreed to by the Source Balancing Authority,Sink Balancing Authority and all Intermediate Balancing Authorities. 1.2.Inadvertent Interchange summaries shall include at least the previous accumulation,net accumulation for the month,and final net accumulation,for both the On-Peak and Off-Peak periods. 1.3.Each Balancing Authority shall perform an Area Interchange Error (AIE) survey as requested by the RRO to determine the Balancing Authority's Interchange error(s)due to equipment failures or improper scheduling operations,or improper AGC performance.Data for such surveys shall be collected for the time period as specified by the RRO. 2.Levels of Non Compliance A Balancing Authority that neither submits a report to the Regional Reliability Organization,nor supplies a reason for not submitting the required data,when such report is requested shall be considered level 1 non-compliant. F.Regional Differences None identified Version History Version Date Action Change Tracking 0 June 6,2013 Original New l May 2,2016 Remove special Bradley Loss language |Modify Alaska Railbelt Standard AKBAL-006-1 -Inadvertent Interchange Page 30 of 168 Alaska Standard AKBAL-502-Planning Resource Adequacy Analysis,Assessment and Documentation A.Introduction 1.'Title:Standard AKBAL-502-0 -Planning Resource Adequacy Analysis, Assessment and Documentation 2.,Number:AKBAL-502-0 3.Purpose:To establish common criteria for each BA for a planning methodology based on the single largest unit contingency and an appropriate reserve margin or reserve criteria.The analysis,assessment,and documentation of Resource Adequacy,shall include Planning Reserve Margins for meeting system load both real and reactive within the Railbelt System. 4.Applicability: 4.1.Balancing Authorities (BA) 4.2.Planning Coordinators 5.(Proposed)Effective Date:TBD Requirements R1.The goal of the Resource Adequacy analysis is to plan the system to meet the following requirements annually. R1.1.The Balancing Authority shall perform and document a Resource Adequacy analysis using one of the following two methods. Method 1:The total capability of each Balance Authority's system plus the total amount of interruptible loads must be equal to or greater than the summation of the following: e The capacity needed to serve the Forecasted Peak Demand for each period. e The capacity of the unit(s)scheduled for maintenance for each period;and e The capacity that would be lost by the Forced Outage of the largest unit/resource in service. N N yy +Lor 2 (Lpeak *Fru +y Nm +Nro) i=1 m=1 Where: e N,is the Normal Net Capability of available units. Alaska Railbelt Standard AKBAL-502-0-Planning Resource Adequacy Analysis, Assessment and Documentation Page 31 of 168 R1.2. R13. R1.4. ©Lpr is the amount of Interruptible Demand designated and measureable for the BA's interruption that can be interrupted for the entire period of the expected capacity shortfall. ®Lpeax is the estimated system peak load and losses served from the available generation. ¢Nm is the Normal Net Capability of units on scheduled maintenance. e Neg is the Normal Net Capability of the largest available unit(s)lost by Forced Outage. e Fry is the Reserve Margin multiplier and the BA must give consideration to using X percent (1.X)based on the reserve net capability.The Planning Coordinator shall set the required Reserve Margin multiplier (Frm)for use in the Resource Adequacy analysis using Method 1 with approval by the IMC However,in no case shall the selection of Fry in relationship to Normal Net Capability of the largest available unit(s)cause a shortage to serve the estimated system peak load and losses. Method 2:Calculate a Planning Reserve Margin that will result in the sum of the probabilities for the loss of Load for the integrated peak hour for all days of each planning year analyzed being equal to 0.X.(This is comparable to a "one day in X year”criterion).The Planning Coordinator shall set the minimum Loss of Load Expectation in days per year for use in the Resource Adequacy analysis using Method 2 with approval by the IMC. The Resource Adequacy analysis must document that the applicable Balancing Authority has developed a resource plan that meets the requirements of R1.1 Method 1 or R1.1 Method 2. R1.2.1.The utilization of Interruptible Demand must not contribute to the loss of Load probability. R1.2.2.The Planning Reserve Margin developed from R1.1 must be expressed as a percentage of the median'forecast peak Net Internal Demand (Planning Reserve Margin). Be performed or verified separately for each of the following planning years: R1.3.1.Perform an analysis for Year One. R1.3.2.Perform an analysis or verification at a minimum for one year in the 2 through 5 year period and at a minimum one year in the 6 through 10 year period. R1.3.2.1.If the analysis is verified,the verification must be supported by current or past studies for the same planning year. Include the following subject matter and documentation of its use: 'The median forecast is expected to have a 50%probability of being too high and 50%probability of being too low(50:50). Alaska Railbelt Standard AKBAL-502-0-Planning Resource Adequacy Analysis, Assessment and Documentation Page 32 of 168 R1.4.1.Load forecast characteristics: Median forecast peak Load. Load forecast uncertainty (reflects variability in the Load forecast due to weather and regional economic forecasts). Load diversity. Seasonal Load variations. Daily demand modeling assumptions (firm,interruptible). Contractual arrangements concerning curtailable/Interruptible Demand. Load response to frequency and short and long-term changes in voltage. R1.4.2.Resource characteristics: Historic resource performance and any projected changes. Seasonal resource ratings. Resource planned outage schedules,deratings,and retirements. Modeling assumptions of intermittent and energy limited resource such as wind,PV,and cogeneration. Criteria for including planned resource additions in the analysis Starting/loading time if resources are to be used as Contingency Reserves Frequency response characteristics Inertia response characteristics Frequency ride-through characteristics Voltage ride-through characteristics Short circuit current characteristics Dispatch characteristics (ramp rate,minimum values,regulation,etc) Mitigation resources required due to generation capacity resource characteristics R1.4.3.Transmission limitations that prevent the delivery of generation resources R1.4.3.1.Criteria for including planned Transmission Facility additions in the analysis R1.4.3.2.Criteria for remedial action systems employed in lieu of Transmission improvements R1.4.3.3.Resource additions to eliminate or increase transfer capacity between areas or through a transmission path. R1.5.Consider the following resource availability characteristics and document how and why they were included in the analysis or why they were not included: e =Availability and deliverability of fuel. e Common mode outages that affect resource availability e Environmental or regulatory restrictions of resource availability. Alaska Railbelt Standard AKBAL-502-0-Planning Resource Adequacy Analysis, Assessment and Documentation Page 33 of 168 R1.6. R1.7. R1.8. R19. e Any other demand (Load)response programs not included in R1.3.1. e Sensitivity to resource outage rates. e Impacts of extreme weather/drought conditions that affect unit availability. e Modeling assumptions for emergency operation procedures used to make reserves available. e Market resources not committed to serving Load (uncommitted resources) within each Balance Authority's Control Area. Consider Transmission maintenance outage schedules and document how and why they were included in the Resource Adequacy analysis or why they were not included Document that capacity resources are appropriately accounted for in its Resource Adequacy analysis Document that all Load in the Balance Authority's Area is accounted for in its Resource Adequacy analysis Provide a Corrective Action Plan to meet the Planning Reserve Margin where Resource Adequacy Analysis shows a shortfall. R1.9.1.Corrective Action Plan should consider transmission constraints when a generation asset is recommended. R1.9.2.The Corrective Action Plan should consider Transmission improvements to remove generation constraints. R1.9.2.1.If transmission improvements are part of the Resource Adequacy Corrective Action Plan,the Transmission improvements must be included in the appropriate Corrective Action Plan for the transmission system. Every five years or as determined by the IMC the BA must document the projected Load and resource capability,for each area or Transmission constrained sub-area identified in the Resource Adequacy analysis. R2.1.This documentation must cover each of the years selected for analysis or verification in R1.3.1 and R1.3.2. This documentation must include the Planning Reserve Margin calculated per requirement R1.1 for each of the three years in the analysis. The documentation as specified per requirement R2.1 and R2.2 must be publicly posted no later than 30 calendar days prior to the beginning of Year One. The documentation must include sufficient studies to show that the characteristics of proposed capacity addition do not result in a degradation of system performance. Alaska Railbelt Standard AKBAL-502-0-Planning Resource Adequacy Analysis, Assessment and Documentation Page 34 of 168 G.Measures. M1.The BA must possess the documentation that a valid Resource Adequacy analysis was performed or verified in accordance with RI Method 1 or R1 Method 2. 2.The BA must possess the documentation of its projected Load and resource capability,for each area or Transmission constrained sub-area identified in the Resource Adequacy analysis on an annual basis in accordance with R2.The documentation must include sufficient studies to determine that the characteristics of the proposed resource additions do not degrade system performance or reliability. H.Compliance 1.Compliance Monitoring Process 1.1.Compliance Enforcement Authority 1.1.1.Intertie Management Committee (or designee) 1.2.Compliance Monitoring Period and Reset Timeframe 1.2.1.One calendar year 1.3.Data Retention 1.3.1.The BA must retain information from the current analysis and the most recent analysis. The Intertie Management Committee (or designee)will retain any audit data for five years. 2.Levels of Non-Compliance for Requirement R1,Measure M1 2.1.Level 1 -The BA met one of the following conditions for Requirement R1 and Measurement M1.. 2.1.1.The BA Resource Adequacy analysis failed to consider 1 or 2 of the Resource availability characteristics subcomponents under R1.4 and documentation of how and why they were included in the analysis or why they were not included. 2.1.2.The BA Resource Adequacy analysis failed to consider 1 or 2 of the Resource availability characteristics subcomponents under R1.5 and documentation of how and why they were included in the analysis or why they were not included. 2.1.3.The BA Resource Adequacy analysis failed to consider Transmission maintenance outage schedules and document how and why they were included in the analysis or why they were not included per R1.6. 2.1.4.The Planning Authority did not provide the minimum Reserve Margin multiplier or the minimum Loss of Load Expectation. 2.2.Level 2 -The BA failed to meet all the requirements of Level 1 for Requirement R1 and Measurement M1. 3.Levels of Non-Compliance for Requirement R2,Measure M2 3.1.Level 1 -The BA failed to publicly post the documents as specified per requirement R2.1 and R2.2 later than 30 calendar days prior to the beginning of Year One per R2.3 for Requirement R2 and Measurement M2. Alaska Railbelt Standard AKBAL-502-0-Planning Resource Adequacy Analysis, Assessment and Documentation Page 35 of 168 3.2.Level 2 -The BA failed to meet all the requirements of Level 1 for Requirement R2 and Measurement M2. Version History Version Date Action Change Tracking 000 11-1-2015 Adapted from Hawaii BAL-502 Standard |Yes 001 12-29-2015 Internal EPS edits | Yes 002 1-4-2016 Submitted for IMC review Yes 003 1-25-2016 Submitted for IMC review Yes 004 2-3-2016 Submitted for IMC review Yes Final 2-12-2016 IMC Final Revision No Alaska Railbelt Standard AKBAL-502-0-Planning Resource Adequacy Analysis, Assessment and Documentation Page 36 of 168 Alaska Railbelt Standard AKFAC-001-1 -Facility Connection Requirements A.Introduction 1.Title:Facility Connection Requirements 2.Number:AKFAC-001-1 3.Purpose: To avoid adverse impacts on reliability,Transmission Owners must establish facility connection and performance requirements.All entity's proposing to interconnect and operate equipment connected to the transmission owners'facilities within the Railbelt will be required to adhere to these standards. 4.Applicability: 4.1.Transmission Owner 5.Effective Date:4 months from package adoption Requirements R1.The Transmission Owner shall document,maintain,and publish facility connection requirements that ensure compliance with the IMC Operating and Reliability Standards and applicable Regional Reliability Organization,sub-regional,power pool, and individual Transmission Owner planning criteria and facility connection requirements.The Transmission Owner's facility connection requirements shall address connection requirements for: R1.1.Generation facilities, R1.2.Transmission facilities,and R1.3.End-user facilities. R2.The Transmission Owner's facility connection requirements shall address,but are not limited to,the following items: R2.1.Provide a written summary of its plans to achieve the required system performance as described above throughout the planning horizon: R2.1.1.Procedures for coordinated joint studies of new facilities and their impacts on the interconnected transmission systems. R2.1.2.Procedures for notification of new or modified facilities to others (those responsible for the reliability of the interconnected transmission systems)as soon as feasible. R2.1.3.Voltage level and MW and MVAR capacity or demand at point of connection. R2.1.4.Breaker duty and surge protection. R2.1.5.System protection and coordination. R2.1.6.Metering and telecommunications. Alaska Railbelt Standard AKFAC-001-1 -Facility Connection Requirements Page 37 of 168 R2.1.7.Grounding and safety issues. R2.1.8.Insulation and insulation coordination. R2.1.9.Voltage,Reactive Power,and power factor control. R2.1.10.Power quality impacts. R2.1.11.Equipment Ratings. R2.1.12.Synchronizing of facilities. R2.1.13.Maintenance coordination. R2.1.14.Operational issues (abnormal frequency and voltages). R2.1.15.Inspection requirements for existing or new facilities. R2.1.16.Communications and procedures during normal and Emergency operating conditions. R3.The Transmission Owner shall maintain and update its facility connection requirements as required.The Transmission Owner shall make documentation of these requirements available to the users of the transmission system,the Regional Reliability Organization on request within five business days. C.Measures M1.The Transmission Owner shall make available to the Intertie Management Committee for inspection evidence that it met all the requirements stated in Reliability Standard AKFAC-001-1;R1. M2.The Transmission Owner shall make available to the Intertie Management Committee for inspection evidence that it met all requirements stated in Reliability Standard AKFAC-001-1;R2. M3.The Transmission Owner shall make available to the Intertie Management Committee for inspection evidence that it met all the requirements stated in Reliability Standard AKFAC-001-1;R3. D.Compliance 1.Compliance Monitoring Process 1.1.Compliance Monitoring Responsibility Compliance Monitor:Regional Reliability Organization. 1.2.Compliance Monitoring Period and Reset Timeframe On request (five business days). 1.3.Data Retention None specified. 1.4.Additional Compliance Information None. 2.Levels of Non-Compliance Alaska Railbelt Standard AKFAC-001-1 -Facility Connection Requirements Page 38 of 168 E.Regional Difference Level 3. 1.None identified. Version History Version Date Action Change Tracking 0 June 7,2013 Original New 1 May 2,2016 Remove IMC interconnect standards Modify Alaska Railbelt Standard AKFAC-001-1 -Facility Connection Requirements Page 39 of 168 Alaska Railbelt Standard AKFAC-002-1 -Coordination of Plans for New Facilities A.Introduction 1.='Title:Coordination of Plans for New Generation,Transmission,and End User Facilities 2.Number:AKFAC-002-1 Purpose: To avoid adverse impacts on reliability,Generator Owners and Transmission Owners and electricity end-users must meet facility connection and performance requirements. All entity's proposing to interconnect and operate within the Railbelt will be required to adhere to these standards. 4.Applicability: 4.1.Generator Owner. 4.2.Transmission Owner. 4.3.Distribution Provider. 4.4.Load-Serving Entity. )4.5.Transmission Planner. 4.6.Planning Authority. 5.Effective Date:4 months from package adoption B.Requirements R1.The Generator Owner,Transmission Owner,Distribution Provider,and Load-Serving Entity seeking to integrate generation facilities,transmission facilities,and electricity end-user facilities shall each coordinate and cooperate on its assessments with its Transmission Planner and Planning Authority.The assessment shall include: R1.1.Evaluation of the reliability impact of the new facilities and their connections on the interconnected transmission systems. R1.2.Ensurance of compliance with the Intertie Management Committee's reliability standards and applicable Regional,subregional,power pool,and individual system planning criteria and facility connection requirements. R1.3.Evidence that the parties involved in the assessment have coordinated and cooperated on the assessment of the reliability impacts of new facilities on the interconnected transmission systems.While these studies may be performed independently,the results shall be jointly evaluated and coordinated by the entities involved. R1.4.Evidence that the assessment included steady-state,short-circuit,and dynamics studies as necessary to evaluate system performance. Alaska Railbelt Standard AKFAC-002-1 -Coordination of Plans for New Facilities Page 40 of 168 R1.5.Documentation that the assessment included study assumptions,system performance,alternatives considered,and jointly coordinated recommendations. R2.The Planning Authority,Transmission Planner,Generator Owner,Transmission Owner,Load-Serving Entity,and Distribution Provider shall each retain its documentation (of its evaluation of the reliability impact of the new facilities and their connections on the interconnected transmission systems)for three years and shall provide the documentation to the Regional Reliability Organization(s)on request(within 30 calendar days). C.Measures M1.The Planning Authority,Transmission Planner,Generator Owner,Transmission Owner,Load-Serving Entity,and Distribution Provider's documentation of its assessment of the reliability impacts of new facilities shall address all items in Reliability Standard AKFAC-002-0;R1. M2.The Planning Authority,Transmission Planner,Generator Owner,Transmission Owner,Load-Serving Entity,and Distribution Provider shall each have evidence of its assessment of the reliability impacts of new facilities and their connections on the interconnected transmission systems is retained and provided to other entities in accordance with Reliability Standard AKFAC-002-0;R2. D.Compliance 1.Compliance Monitoring Process 1.1.Compliance Monitoring Responsibility Compliance Monitor:RRO. 1.2.Compliance Monitoring Period and Reset Timeframe On request (within 30 calendar days). 1.3.Data Retention Evidence of the assessment of the reliability impacts of new facilities and their connections on the interconnected transmission systems:Three years. 1.4.Additional Compliance Information None. 2.Levels of Non-Compliance 2.1.Level 1:Assessments of the impacts of new facilities were provided,but were incomplete in one or more requirements of Reliability Standard AKFAC- 002:R1. 2.2.Level2:=Not applicable. 2.3.Level3:=Not applicable. 2.4.Level4:|Assessments of the impacts of new facilities were not provided. E.Regional Differences Alaska Railbelt Standard AKFAC-002-1 -Coordination of Plans for New Facilities Page 41 of 168 1.None identified. Version History Version Date Action Change Tracking I May 2,2016 Remove gen &xmsn proforma Modify Alaska Railbelt Standard AKFAC-002-1 -Coordination of Plans for New Facilities Page 42 of 168 Alaska Railbelt Standard AKINT-001-0 -Interchange Information A.Introduction 1. 2. 3. 5. Title:Interchange Information Number:AKINT-001-0 Purpose:Scheduled interchange must be coordinated between Balancing Authorities to prevent frequency deviations and accumulations of inadvertent interchange,and prevent exceeding mutually established transfer limits. Applicability: 4.1.Purchase-Selling Entities. 4.2.Balancing Authorities. Effective Date:6 months from package adoption B.Requirements R1. R4. Interchange shall be scheduled only between Balancing Authorities having directly connecting facilities in service unless there is a contract or mutual agreement with another Balancing Authority to provide connecting facilities. Interchange schedules or schedule changes shall not cause any other system to violate established reliability criteria. R2.1._When Balancing Authorities are connected so that parallel flows present reliability issues,the combinations of Balancing Authorities shall develop multi-control area interchange monitoring techniques and pre-determined corrective actions to mitigate or alleviate potential or actual transmission system overloads. R2.2.Transfer limits shall be reevaluated and interchange schedules adjusted as soon as practicable if transmission facilities become overloaded or are out of service, or when changes are made to the bulk system which can affect these limits. The maximum net scheduled interchange between two Balancing Authorities shall not exceed: R3.1.The total capacity of the transmission facilities in service between the two Balancing Authorities owned by them or available to them under specific arrangements,contract,or mutual agreements. The sending,contract intermediary,and receiving Balancing Authorities that are parties to an interchange transaction shall agree on the following: R4.1,The schedule's magnitude,starting and ending times. R4.2._The schedule's magnitude and rate of change shall be equal and opposite and not exceed the ability of the systems to effect the change. Alaska Railbelt Standard AKINT-001-0 -Interchange Information Page 43 of 168 RS. R4.3.The scheduled generation in one Balancing Authority that is delivered to another Balancing Authority must be scheduled with all intermediate Balancing Authorities unless there is a contract or mutual agreement among the sending, contract intermediary,and receiving Balancing Authorities to do otherwise. Balancing Authorities shall develop procedures to disseminate information on interchange schedules and facilities out of service which may have an adverse effect on other Balancing Authorities not involved in the scheduled interchange and the involved parties shall predetermine schedule priorities,which will be used if a schedule reduction becomes necessary. C.Compliance Level 1 D.Regional Differences 1, 2. Version History Version |Date Action Change Tracking 0 May 2,2016 Original New Alaska Railbelt Standard AKINT-001-0 -Interchange Information Page 44 of 168 Alaska Railbelt Standard AKMOD-025-2-Verification and Data Reporting of Generator Real _and Reactive Power Capability and Synchronous Condenser Reactive Power Capability A.Introduction Title:Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Number:AKMOD-025-2 Purpose:To ensure that accurate information on generator gross and net Real and Reactive Power capability and synchronous condenser Reactive Power capability is available for planning models used to assess Bulk Electric System (BES)reliability. Applicability: R1.1.Functional Entities: R1.1.1.Generator Owner R1.1.2..Transmission Planner R1.1.3.Transmission Owner R1.2.Facilities: For the purpose of the requirements contained herein,Facilities that are directly connected to the Bulk Electric System (BES)will be collectively referred as an "applicable unit”that meet the following: R1.2.1.Generation in the Interconnection with the following characteristics: 1.2.1.1.Individual generating unit greater than 5 MVA (gross nameplate rating). 1.2.1.2.Individual generating plant consisting of multiple generating units that are directly connected at a common BES bus with total generation greater than 5 MVA (gross aggregate nameplate rating). R1.2.2.Synchronous condenser greater than 5 MVA (gross nameplate rating) directly connected to the Bulk Electric System. R1.2.3.Power Electronics Transmission Assets greater than 1 MVA directly connected to the Bulk Electric System. Effective Date: TBD (Standard should be implemented as a test and monitored for a minimum of 12 months to ascertain ability to comply and monitor) Alaska Railbelt Standard AKMOD-025-2 -Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Page 45 of 168 Requirements R1.Each Generator Owner or Transmission Owner shall provide any Transmission Planner with verification of the Real Power capability of its applicable Facilities as follows: 1.1.Verify,in accordance with Attachment 1,(i)the Real Power capability of its generating units and (ii)the Real Power capability of its Power Electronics Transmission Assets.;and 1.2.Submit a completed Attachment 2 (or a form containing the same information as identified in Attachment 2)to any Transmission Planner within 60 calendar days of either (i)the date the data is recorded for a staged test;or (ii)the date the data is selected for verification using historical operational data;or 1.3.|Submit a completed Attachment 3 (or a form containing the same information as identified in Attachment 3)to any Transmission Planner within 60 calendar days of either (i)the date the data is recorded for a staged test;or (ii)the date the data is selected for verification using historical operational data for Temperature Sensitive Units. Each Generator Owner or Transmission Owner shall provide any Transmission Planner with verification of the Reactive Power capability of its applicable Facilities as follows: 2.1.'Verify,in accordance with Attachment 1,(i)the Reactive Power capability of its generating units,(ii)the Reactive Power capability of its synchronous condenser units,and (iii)the Reactive Power capability of its Power Electronics Transmission Assets. 2.2.Submit a completed Attachment 2 (or a form containing the same information as identified in Attachment 2)to any Transmission Planner within 60 calendar days of either (i)the date the data is recorded for a staged test;or (i1)the date the data is selected for verification using historical operational data. B.Measures M1. M2. Each Generator Owner or Transmission Owner will have evidence that it performed the verification,such as a completed Attachment 2 or 3 or the Generator Owner or Transmission Owner form with the same information or dated information collected and used to complete attachments,and will have evidence that it submitted the information within 60 days to any Transmission Planner;such as dated electronic mail messages or mail receipts in accordance with Requirement R1.Each Generator Owner or Transmission Owner will have evidence that the Real Power capability was verified within the periodicity specified in Attachment 1. Each Generator Owner or Transmission Owner will have evidence that it performed the verification,such as a completed Attachment 2 or the Generator Owner or Transmission Owner form with the same information,or dated information collected Alaska Railbelt Standard AKMOD-025-2 -Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Page 46 of 168 and used to complete attachments and will have evidence that it submitted the information within 60 days to any Transmission Planner;such as dated electronic mail messages or mail receipts in accordance with Requirement R2.Each Generator Owner or Transmission Owner will have evidence that the Reactive Power capability was verified within the periodicity specified in Attachment 1. C.Compliance R1.Compliance Monitoring Process 1.1. 1.2. 1.3. Compliance Enforcement Authority Regional Coordinating Council Evidence Retention The following evidence retention periods identify a period of time an entity is required to retain specific evidence to demonstrate compliance.For instances where the evidence retention specified below is shorter than the time since the last compliance audit,the Compliance Enforcement Authority may ask an entity to provide other evidence to show that it was compliant for the full time period since the last audit. The Generator Owner and Transmission Owner shall each keep the data or evidence to show compliance as identified below,unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation: e The Generator Owner shall retain the latest AKMOD-025 Attachment 2 or 3 and the data behind Attachment 2 or 3 or Generator Owner form with equivalent information and submittal evidence for Requirements R1 and R2,Measures M1 and M2 for the time period since the last compliance audit. e The Transmission Owner shall retain the latest AKMOD-025 Attachment 2 and the data behind Attachment 2 or Transmission Owner form with equivalent information and submittal evidence for Requirements R3 and R4,Measure M3 and M4 for the time period since the last compliance audit. If a Generator Owner or Transmission Owner is found noncompliant,it shall keep information related to the noncompliance until mitigation is complete or for the time specified above,whichever is longer. The Compliance Enforcement Authority shall keep the last audit records and all requested and submitted subsequent audit records. Compliance Monitoring and Assessment Processes: Compliance Audit Self-Certification Alaska Railbelt Standard AKMOD-025-2 -Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Page 47 of 168 Spot Checking Compliance Investigation Self-Reporting Complaint 1.4,Additional Compliance Information None 2.Levels of Non-Compliance 2.1.Levels of Non-Compliance for Requirement R1,Measure M1 2.1.1. 2.1.2. 2.1.3. Level 1 -The Generator Owner or Transmission Owner failed to provide any Transmission Planner with verification of the Real Power capability verification of its applicable Facilities within 60 days. Level 1 -The Generator Owner or Transmission Owner failed to meet the periodicity requirements of Attachment 1 for verification of its applicable Facilities. Level 2 -The Generator Owner or Transmission Owner failed to retain evidence that it performed the Real Power capability verification of its applicable Facilities as required by Requirement R1. 2.2.Levels of Non-Compliance for Requirement R2,Measure M2 2.2.1. 2.2.2. 2.2.3. Version History Level 1 -The Generator Owner or Transmission Owner failed to provide any Transmission Planner with verification of the Reactive Power capability of its applicable Facilities within 60 days. Level 1 -The Generator Owner or Transmission Owner failed to meet the periodicity requirements of Attachment 1 for verification of its applicable Facilities. Level 2 -The Generator Owner or Transmission Owner failed to retain evidence that it performed the Reactive Power capability verification of its applicable Facilities as required by Requirement R2. Version Date Action ChangeTracking | WO NERCversion an 2 12-17-2016 EPS -initial edits .es ee ee23-16-2016 '_.......,EPS revision following 3/11/2016 meeting ==-|}_-s-Yes |3 |9-16-2016 _.._.....EPS revision following 8/25/2016 meeting ===--s|_-s-'Yes ___4__.11-18-2016 EPS revision,additionofRCC (ves Final 12-06-2016 Final Version no Alaska Railbelt Standard AKMOD-025-2 -Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Page 48 of 168 AKMOD-025 Attachment 1 -Verification of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Periodicity for conduction of a new verification: The periodicity for performing Real and Reactive Power capability verification is as follows: 1.For staged verification;verify each applicable Facility at least every five years or as approved by the RRO (with no more than 66 calendar months between verifications),or within 6 calendar months of the discovery of a change that affects its Real Power or Reactive Power capability by more than 10 percent of the last reported verified capability and is expected to last more than six months.The first verification for each applicable Facility under this standard must be a staged test. 2.For verification using operational data;verify each applicable Facility at least every calendar year or as approved by the RRO (with no more than 18 calendar months between verifications),or within 3 calendar months following the discovery that its Real Power or Reactive Power capability has changed by more than 10 percent of the last reported verified capability and is expected to last more than six months.For temperature sensitive units,verification of Real Power capability using operational data may require data over the course of several months.Operational data should be obtained within a string of consecutive months if allowable by ambient temperatures.If data for different points is recorded on different months,designate the earliest of those dates as the verification date,and report that date as the verification date on AKMOD-025, Attachment 2 for periodicity purposes.Units whose real power is verified using operational data shall confirm its Reactive Power using staged verifications. For either verification method,verify each new applicable Facility within 6 calendar months of its commercial operation date or within a timeline approved by the RRO.Existing units that have been in long term shut down and have not been tested for more than five years shall be verified within 6 calendar months or within a timeline approved by the RRO if the units are scheduled to return to regular service. It is intended that Real Power testing be performed at the same time as full load Reactive Power testing,however separate testing is allowed for this standard.For synchronous condensers, perform only the Reactive Power capability verifications as specified below.For all Power Electronics Transmission Assets perform Reactive Power capability verifications and perform real power verifications for Power Electronics Transmission Assets with real power capability. If the Reactive Power capability is verified through test,it is to be scheduled at a time advantageous for the unit being verified to demonstrate its Reactive Power capabilities while the Transmission Operator takes measures to maintain the plant's system bus voltage at the scheduled value or within acceptable tolerance of the scheduled value. Generators that have a current average Net Capacity Factor over the most recent three calendar years,beginning on January 1 and ending on December 31,of 5%or less are exempt.The equations for calculating the Net Capacity Factor are listed in AKMOD-027 Attachment 1 Note 4.The Generator Owner shall verify the capability within one year of the date of the capacity Alaska Railbelt Standard AKMOD-025-2 -Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Page 49 of 168 factor exemption expiration.The verification can be done by either a staged test or using operational data following the expiration of the capacity factor exemption. Verification specifications for applicable Facilities: 1.For generating units of 5 MVA or less that are part of a plant greater than 5SMVA in aggregate connected through a single contingency condition,record data either on an individual unit basis or as a group.Perform verification individually for every generating unit or synchronous condenser greater than 5 MVA (gross nameplate rating).Perform verification individually for every Power Electronics Transmission Asset greater than | MVA. 2.Verify all auxiliary equipment needed for expected normal operation is in service for both the Real Power and Reactive Power capability verification.Perform verification with the automatic voltage regulator in service for the Reactive Power capability verification.Operational data from within the 18 months prior to the verification date is acceptable for the verification of either the Real Power or the Reactive Power capability, as long as a)that operational data meets the criteria in 2.1 through 2.4 below and b)the operational data demonstrates at least 90 percent of a previously staged test that demonstrated at least 50 percent of the Reactive capability shown on the associated thermal capability curve (D-curve).If the previously staged test was unduly restricted (so that it did not demonstrate at least 50 percent of the associated thermal capability curve) by unusual generation or equipment limitations (e.g.,capacitor or reactor banks out of service),then the next verification will be by another staged test,not operational data: 2.1.Verify Real Power capability and Reactive Power capability over-excited (lagging)of all applicable Facilities at the applicable Facilities'normal (not emergency)expected maximum Real Power output at the time of the verifications. 2.1.1.Verify synchronous generating unit's maximum Real Power for one hour and lagging Reactive Power for a minimum of fifteen minutes. 2.1.2.Verify Power Electronics Transmission Asset maximum Real Power.The verification should use greater than 20%of the rated energy at the rated Real Power output.The verification may use less than 20%of the rated energy with approval from the Regional Reliability Organization. 2.1.2.1.Verify that Power Electronics Transmission Assets used for Contingency Reserve have the capability to provide Contingency Reserve at the Real Power level for the expected duration. 2.1.2.2.Verification of Power Electronics Transmission Assets used for Contingency Reserve may include staged tests or operational data. 2.1.3.Verify variable generating units,such as wind,solar,and run of river hydro,at the maximum Real Power output the variable resource can Alaska Railbelt Standard AKMOD-025-2 -Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Page 50 of 168 provide at the time of the verification.Perform verification of Reactive Power capability of wind turbines and photovoltaic inverters with at least 90 percent of the wind turbines or photovoltaic inverters at a site on-line. If verification of wind turbines or photovoltaic inverter Facility cannot be accomplished meeting the 90 percent threshold,document the reasons the threshold was not met and test to the full capability at the time of the test. Reschedule the test of the facility within six months of being able to reach the 90 percent threshold.Maintain,as steady as practical,Real and Reactive Power output during verifications. 2.2.Verify Reactive Power capability of all applicable Facilities,other than wind and photovoltaic,for maximum overexcited (lagging)and under-excited (leading) reactive capability for the following conditions: 2.2.1.At the minimum Real Power output at which they are normally expected to operate collect maximum leading and lagging reactive values as soon as a limit is reached.The Reactive Power capability of Power Electronics Transmission Assets shall be verified at a Real Power output of zero if such devices are expected to provide reactive support. 2.2.2.At maximum Real Power output collect maximum expected leading and lagging Reactive Power for 15 minutes. 2.3.For hydrogen-cooled generators,perform the verification at normal operating hydrogen pressure. 2.4.Calculate the Generator Step-Up (GSU)transformer losses if the verification measurements are taken from the high side of the GSU transformer.GSU transformer real and reactive losses may be estimated,based on the GSU impedance,if necessary. 3.Record the following data for the verifications specified above: 3.1.The value of the gross Real and Reactive Power generating capabilities at the end of the verification period. 3.2.The voltage schedule provided by the Transmission Operator,if applicable. 3.3.The voltage at the high and low side of the GSU and/or system interconnection transformer(s)at the end of the verification period.If only one of these values is metered,the other may be calculated. 3.4.The ambient conditions,if applicable,at the end of the verification period that the Generator Owner requires to perform corrections to Real Power for different ambient conditions such as: e Ambient air temperature e Relative humidity e Cooling water temperature Alaska Railbelt Standard AKMOD-025-2 -Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Page 51 of 168 Note 1: Note 2: e Other data as determined to be applicable by the Generator Owner to perform corrections for ambient conditions. 3.5.The date and time of the verification period,including start and end time in hours and minutes. 3.6.The existing GSU and/or system interconnection transformer(s)voltage ratio and tap setting. 3.7.The GSU transformer losses (real or reactive)if the verification measurements were taken from the high side of the GSU transformer. 3.8.|Whether the test data is a result of a staged test or if it is operational data. Develop a simplified key one-line diagram (refer to AKMOD-025,Attachment 2) showing sources of auxiliary Real and Reactive Power and associated system connections for each unit verified.Include GSU and/or system Interconnection and auxiliary transformers.Show Reactive Power flows,with directional arrows. 4.1.If metering does not exist to measure specific Reactive auxiliary load(s),provide an engineering estimate and associated calculations.Transformer Real and Reactive Power losses will also be estimates or calculations.Only output data are required when using a computer program to calculate losses or loads. If an adjustment is requested by the Transmission Planner,then develop the relationships between test conditions and generator output so that the amount of Real Power that can be expected to be delivered from a generator can be determined at different conditions, such as peak summer conditions.Adjust MW values tested to the ambient conditions specified by the Transmission Planner upon request and submit them to the Transmission Planner within 60 days of the request or the date the data was recorded/selected whichever is later. Under some transmission system conditions,the data points obtained by the MVAr verification required by the standard will not duplicate the manufacturer supplied thermal capability curve (D-curve)or power electronics capability curves.However, the verification required by the standard,even when conducted under these transmission system conditions,may uncover applicable Facility limitations;such as rotor thermal instability,improper tap settings or voltage ratios,inaccurate AVR operation,etc.,which could be further analyzed for resolution.The MVAr limit level(s)achieved during a staged test or from operational data may not be representative of the unit's reactive capability for extreme system conditions.See Note 2. While not required by the standard,it is desirable to perform engineering analyses to determine expected applicable Facility capabilities under less restrictive system voltages than those encountered during the verification.Even though this analysis will not verify the complete thermal capability curve (D-curve)or power electronics Alaska Railbelt Standard AKMOD-025-2 -Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Page 52 of 168 capability curves,it provides a reasonable estimate of applicable Facility capability that the Transmission Planner can use for modeling. Note 3:The Reactive Power verification is intended to define the limits of the unit's Reactive Power capabilities.If a unit has no leading capability,then it should be reported with no leading capability;or the minimum lagging capability at which it can operate. Note 4:Synchronous Condensers and Power Electronics Transmission Assets without Real Power capability only need to be tested at two points (one over-excited point and one under-excited point)since they have no Real Power output. Alaska Railbelt Standard AKMOD-025-2 -Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Page 53 of 168 AKMOD.-025 Attachment 2 One-line Diagram,Table,and Summary for Verification Information Reporting Note:If the configuration of the applicable Facility does not lend itself to the use of the diagram,tables,or summaries for reporting the required information,changes may be made to this form,provided that all required information (identified in AKMOD-025,Attachment 1)is reported. Company:Reported By (name): Plant:Unit No.:Date of Report: Check all that apply: Over-excited Full Load Reactive Power Verification Under-excited Full Load Reactive Power Verification Over-excited Minimum Load Reactive Power Verification Under-excited Minimum Load Reactive Power Verification Real Power Verification Staged Test Data OO0Oda0d0ango0Operational Data Simplified one-line diagram showing plant auxiliary Load connections and verification data: Point of interconnection e Positive numbers indocate power flow on detection of arrow,megativeF*y +p]aumbers indacate power flow in AGeneratorStepUpUl Opposite directionofsrtow. Auxiliary or!||Station Service Transformer(s)Other point(s)ofiRointerconnection yTr Unit Auxiliary 'a:(T°Transformer(s)[Eb 've Auxiliary or'Station Service Aux bus LidHaat |ano| ¥ Alaska Railbelt Standard AKMOD-025-2 -Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Page 54 of 168 Point Voltage Real Power Reactive Power Comment Sum multiple generators that are verified together or are part of the same unit.Report individual unit values separately whenever the verification measurements were taken at the individual unit. Individual values are required for units or synchronous condensers >5 MVA or Power Electronics Transmission Assets >1 MVA. Identify calculated values if any: B kv MW Mvar|Sum multiple unit auxiliary trans formers. Identify calculated values if any: Cc |kv|Mw|Mvar|Sum multiple tertiary Loads,ifany. Identify calculated values if any: Sum multiple auxiliary and station serviceDkvMwMvartransformers. Identify calculated values if any: If multiple points of Interconnection,describe E kV MW Mvar|these for accurate modeling;report points individually (sum multiple auxiliary trans formers). F kV MW Mvar|Net unit capability Identify calculated values ifany: Alaska Railbelt Standard AKMOD-025-2 -Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Page 55 of 168 AKMOD-025 -Attachment 2 (continued) Verification Data Provide data by unit or Facility as appropriate Data Type Data Recorded Last Verification (Previous Data; will be blank for the initial verification) Gross Reactive Power Capability (*Mvar) Aux Reactive Power (*Mvar) Net Reactive Power Capability (*Mvar)equals Gross Reactive Power Capability (*Mvar)minus Aux Reactive Power connected at the same bus (*Mvar) minus tertiary Reactive Power connected at the same bus(*Mvar) Gross Real Powr Capability (*MW) Aux Real Power (*MW) Net Real Power Capability (*MW)equals Gross Real Power Capability (*MW)minus Aux Real Power connected at the same bus (*MW)minus tertiary Real Power connected at the same bus (*MW) *Note:Enter values at the end of the verification period. GSU losses (only required if verification measurements are taken on the high side of the GSU -Mvar) Summary of Verification e Date of Verification ,Verification Start Time ©Scheduled Voltage e Transformer Voltage Ratio:GSU ,Unit Aux ,Verification End Time ,Station Aux ,Other Aux e Transformer Tap Setting:GSU ,Unit Aux ,station Aux ,Other Aux «Ambient conditions at the end for the verification period: 3.Air Temperature: 4.Humidity: 5.Cooling water temperature: 6.Other data as applicable: Alaska Railbelt Standard AKMOD-025-2 -Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Page 56 of 168 ®Generator hydrogen pressure at time of test (if applicable) Date that data shown in last verification column in table above was taken Remarks: Note:If the verification value did not reach the thermal capability curve (D-curve),describe the reason. AKMOD-025 -Attachment 3 The Real Power capability verification for Temperature Sensitive Units shall be performed as follows: 1.The Real Power capability verification for Temperature Sensitive Units shall occur annually or as approved by the RRO. 2.Real Power verification shall be performed for generating units 5 MVA or larger or generating units smaller than 5 MVA that are part of a plant greater than 5 MVA in aggregate connected through a single contingency condition. 3.Verify with all auxiliary equipment needed for expected normal operation in service for the Real Power capability verification. 3.1.Verify Real Power capability of all applicable Facilities at the applicable Facilities'maximum Real Power output for the ambient air temperature at the time of the verification. 3.1.1.Verify Temperature Sensitive Unit's maximum real power for a minimum of fifteen minutes. 3.1.2.Verification shall be performed at ambient air temperature increments of 10 degrees Fahrenheit from annual minimum temperature to the annual maximum temperature at the unit location. 3.1.3.Verification data shall include the Temperature Sensitive Unit's maximum real power,the temperature in Fahrenheit,and the time and date of test. 4.Record the following data for the verifications specified above: 4.1.The value of the gross Real Power generating capabilities at the end of the verification period. 4.2.The auxiliary power,temperature,date,and time of test for applicable Temperature Sensitive Unit. Alaska Railbelt Standard AKMOD-025-2 -Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Page 57 of 168 Data Type Data Recorded Temperature Date Time Gross Power Capability,Aux Power Mw,MW °F Gross Power Capability,Aux Power MW,MW °F Gross Power Capability,Aux Power Mw,MW oF Gross Power Capability,Aux Power Mw,MW oF Gross Power Capability,Aux Power MW,MW °F Gross Power Capability,Aux Power MW,MW °F Gross Power Capability,Aux Power MW,MW °F Gross Power Capability,Aux Power MW,MW °F Gross Power Capability,Aux Power Mw,MW °F Gross Power Capability,Aux Power MW,MW °F Alaska Railbelt Standard AKMOD-025-2 -Verification and Data Reporting of Generator Real and Reactive Power Capability and Synchronous Condenser Reactive Power Capability Page 58 of 168 Alaska Railbelt Standard AKMOD-026-1-Verification of Models and Data for Generator Excitation Control System or Plant Volt/Var Control Functions A.Introduction Title:Verification of Models and Data for Generator Excitation Control System or Plant Volt/Var Control Functions Number:AKMOD-026-1 Purpose:To verify that the generator excitation control system or plant volt/var control function?model (including the power system stabilizer model and the impedance compensator model)and the model parameters used in dynamic simulations accurately represent the generator excitation control system or plant volt/var control function behavior when assessing Bulk Electric System (BES)reliability. Applicability: R6.1.Functional Entities: R6.1.1.Generator Owner R6.1.2.Transmission Planner R6.1.3.Transmission Owner R6.2.Facilities: For the purpose of the requirements contained herein,Facilities that are directly connected to the Bulk Electric System (BES)will be collectively referred as an "applicable unit”that meet the following: R6.2.1.Generation in the Interconnection with the following characteristics: 6.2.1.1.Individual generating unit greater than 5 MVA (gross nameplate rating). 6.2.1.2.Individual generating plant consisting of multiple generating units that are directly connected at a common BES bus with total generation greater than 5 MVA (gross aggregate nameplate rating). R6.2.2.Synchronous condenser greater than 5 MVA (gross nameplate rating) directly connected to the Bulk Electric System. R6.2.3.Power Electronics Transmission Assets greater than 1 MVA directly connected to the Bulk Electric System. Effective Date: ?Excitation control system or plant volt/var control function: a.For individual synchronous machines,the generator excitation contro!system includes the generator, exciter,voltage regulator,impedance compensation and power system stabilizer. b.For an aggregate generating plant,the volt/var control system includes the voltage regulator &reactive power control system controlling and coordinating plant voltage and associated reactive capable resources. Alaska Railbelt Standard AKMOD-026-1-Verification of Models and Data for GeneratorExcitationControlSystemorPlantVolt/Var Control Functions Page 59 of 168 TBD (Standard should be implemented as a test and monitored for a minimum of 12 months to ascertain ability to comply and monitor) B.Requirements R7.Each Transmission Planner shall provide the following information to the Generator Owner or Transmission Owner within 30 calendar days of receiving a written request: e Instructions on how to obtain the list of excitation control system or plant volt/var control function models that are acceptable to the Transmission Planner for use in dynamic simulation, e Instructions on how to obtain the dynamic excitation control system or plant volt/var control function model library block diagrams and/or data sheets for models that are acceptable to the Transmission Planner,or ¢Model data for any of the Generator Owner's or Transmission Owner's existing applicable unit specific excitation control system or plant volt/var control function contained in the Transmission Planner's dynamic database from the current (in-use)models,including generator MVA base. R8.Each Generator Owner shall provide for each applicable unit,a verified generator excitation control system or plant volt/var control function model,including documentation and data (as specified in Part 2.1)to any Transmission Planner in accordance with the periodicity specified in AKMOD-026 Attachment 1.Transmission Owners shall provide the same documentation and data for applicable Power Electronics Transmission Assets. 8.1.Each applicable unit's model shall be verified by the Generator Owner or Transmission Owner using one or more models acceptable to the Transmission Planner.Verification for individual units less than 5 MVA (gross nameplate rating,|MVA for Power Electronics Transmission Assets)in a generating plant (per Section 4.2.1.2)may be performed using either individual unit or aggregate unit model(s),or both.Each verification shall include the following: 8.1.1.Documentation demonstrating the applicable unit's model response matches the recorded response for a voltage excursion from either a staged test or a measured system disturbance, 8.1.2.Manufacturer,model number (if available),and type of the excitation control system including,but not limited to static,AC brushless,DC rotating,and/or the plant volt/var control function (if installed), 8.1.3.Model structure and data including,but not limited to reactance,time constants,saturation factors,total rotational inertia,or equivalent data for the generator, 8.1.4.Model structure and data for the excitation control system,including the closed loop voltage regulator if a closed loop voltage regulator is installed or the model structure and data for the plant volt/var control function system, 8.1.5.Compensation settings (such as droop,line drop,differential compensation),if used,and 8.1.6.|Model structure and data for power system stabilizer,if so equipped, Alaska Railbelt Standard AKMOD-026-1-Verification of Models and Data for Generator Excitation Control System or Plant Volt/Var Control Functions Page 60 of 168 8.1.7.Model for plant control system,including control parameters used to control plant voltage/var output,including mode or control switching due to off-schedule voltage or var output. 8.2.Each Generator Owner or Transmission Owner shall provide model structure, data,and source code (if available)for any excitation control system or plant volt/var control function that requires a custom model that is not in the model list provided by the Transmission Planner. 8.2.1.|The Generator Owner or Transmission Owner shall document the need for using a custom model and provide the documentation to the Transmission Planner. R9.Each Generator Owner or Transmission Owner shall provide a written response to any Transmission Planner within 60 calendar days of receiving one of the following items for an applicable unit: e Written notification from any Transmission Planner (in accordance with Requirement R6)that the excitation control system or plant volt/var control function model is not usable, e Written comments from any Transmission Planner identifying technical concerns with the verification documentation related to the excitation control system or plant volt/var control function model,or e Written comments and supporting evidence from any Transmission Planner indicating that the simulated excitation control system or plant volt/var control function model response did not match the recorded response to a transmission system event. The written response shall contain either the technical basis for maintaining the current model,the model changes,or a plan to perform model verification'(in accordance with Requirement R2). R10.Each Generator Owner or Transmission Owner shall provide revised model data or plans to perform model verification (in accordance with Requirement R2)for an applicable unit to any Transmission Planner within 60 calendar days of making changes to the excitation control system or plant volt/var control function that alter the equipment response characteristic'. R11.Each Generator Owner and Transmission Owner shall provide a written response to any Transmission Planner,within 60 calendar days following receipt of a technically justified>unit request from the Transmission Planner to perform a model review of a unit or plant that includes one of the following: 3 If verification is performed,the 5-year period as outlined in AKMOD-026 Attachment 1 is reset.'Exciter,voltage regulator,plant volt/var or power system stabilizer control replacement including software alterations that alter excitation control system equipment response,plant digital control system addition or replacement,plant digital control system software alterations that alter excitation control system equipment response,plant volt/var function equipment addition or replacement (such as static var systems,capacitor banks, individual unit excitation systems,etc),a change in the voltage control mode (such as going from power factor control to automatic voltage control,etc),exciter,voltage regulator,impedance compensator,or power system stabilizer settings change.Automatic changes in settings that occur due to changes in operating mode do not apply to Requirement R4.>Technical justification is achieved by the Transmission Planner demonstrating that the simulated unit or plantresponsedoesnotmatchthemeasuredunitorplantresponse. Alaska Railbelt Standard AKMOD-026-1-Verification of Models and Data forGeneratorExcitationControlSystemorPlantVolt/Var Control Functions Page 61 of 168 e Details of plans to verify the model (in accordance with Requirement R2),or e Corrected model data including the source of revised model data such as discovery of manufacturer test values to replace generic model data or updating of data parameters based on an on-site review of the equipment. R12.Each Transmission Planner shall provide a written response to the Generator Owner or Transmission Owner within 30 calendar days of receiving the verified excitation control system or plant volt/var control function model information in accordance with Requirement R2 that the model is usable (meets the criteria specified in Parts 6.1 through 6.3)or is not usable. 12.1.The excitation control system or plant volt/var control function model initializes to compute modeling data without error, 12.2.A no-disturbance simulation results in negligible transients,and 12.3.For an otherwise stable simulation,a disturbance simulation results in the excitation control and plant volt/var control function model exhibiting positive damping. If the model is not usable,the Transmission Planner shall provide a technical description of why the model is not usable. C.Measures M13.The Transmission Planner must provide the dated request for instructions or data,the transmitted instructions or data,and dated evidence of a written transmittal (e.g., electronic mail message,postal receipt,or confirmation of facsimile)as evidence that it provided the request within 30 calendar days in accordance with Requirement R1. M14.The Generator Owner or Transmission Owner must provide dated evidence it verified each generator excitation control system or plant volt/var control function model according to Part 2.1 for each applicable unit and a dated transmittal (e.g.,electronic mail message,postal receipt,or confirmation of facsimile)as evidence it provided the model,documentation,and data to any Transmission Planner,in accordance with Requirement R2. M15.Evidence for Requirement R3 must include the Generator Owner's or Transmission Owner's dated written response containing the information identified in Requirement R3 and dated evidence of transmittal (e.g.,electronic mail message,postal receipt,or confirmation of facsimile)of the response. M16.Evidence for Requirement R4 must include,for each of the Generator Owner's or Transmission Owner's applicable units for which system changes specified in Requirement R4 were made,a dated revised model data or plans to perform a model verification and dated evidence (e.g.,electronic mail message,postal receipt,or confirmation of facsimile)it provided the revised model and data or plans within 60 calendar days of making changes. M17.Evidence for Requirement R5 must include the Generator Owner's or Transmission Owner's dated written response containing the information identified in Requirement R5 and dated evidence (e.g.,electronic mail message,postal receipt,or confirmation of facsimile)it provided a written response within 30 calendar days following receipt of a technically justified request. Alaska Railbelt Standard AKMOD-026-1-Verification of Models and Data for Generator Excitation Control System or Plant Volt/Var Control Functions Page 62 of 168 M18.Evidence of Requirement R6 must include,for each model received,the dated response indicating the model was usable or not usable according to the criteria specified in Parts 6.1 through 6.3 and for a model that is not usable,a technical description;and dated evidence of transmittal (e.g.,electronic mail message,postal receipt,or confirmation of facsimile)that the Generator Owner or Transmission Owner was notified within 30 calendar days of receipt of model information. D.Compliance R19.Compliance Monitoring Process 19.1.Compliance Enforcement Authority Regional Coordinating Council 19.2.Data Retention The following evidence retention periods identify the period of time an entity is required to retain specific evidence to demonstrate compliance.For instances where the evidence retention period specified below is shorter than the time since the last audit,the Compliance Enforcement Authority may ask an entity to provide other evidence to show that it was compliant for the full time period since the last audit. The Generator Owner,Transmission Owner,and Transmission Planner shall each keep data or evidence to show compliance as identified below unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation: e The Transmission Planner shall retain the information/data request and provided response evidence of Requirements R1 and R6,Measures M1 and M6 for three calendar years from the date the document was provided. e The Generator Owner or Transmission Owner shall retain the latest excitation control system or plant volt/var control function model verification evidence of Requirement R2,Measure M2. e The Generator Owner or Transmission Owner shall retain the information/data request and provided response evidence of Requirements R3 through R5,and Measures M3 through MS for three calendar years from the date the document was provided. If a Generator Owner,Transmission Owner,or Transmission Planner is found non-compliant,it shall keep information related to the non-compliance until mitigation is complete or approved or for the time specified above,whichever is longer. The Compliance Enforcement Authority shall keep the last audit records and all requested and submitted subsequent audit records. 19.3.Compliance Monitoring and Assessment Processes: Compliance Audit Self-Certification Spot Checking Alaska Railbelt Standard AKMOD-026-1-Verification of Models and Data ffor GeneratorExcitationControlSystemorPlantVolt/Var Control Functions ."Page 63 of 168 Compliance Investigation Self-Reporting Complaints 19.4. None E.Regional Variances None. F.Associated Documents None. Version History Additional Compliance Information ..ChangeVersionDateActionTracking ee _NERCversion_1 |2-23-2016 a EPS edit from NERC standard _/Yes 2 3:1620160 ____EPSedit ne Oe (ee 3 |9-16-2016 EPS edit following 8/25/2016 |meeting -«-_-_-_<<i Yes |4 '11-18-2016 _7 __EPS revision,additionofRCC YesFinal'12-06-2016 Final Version i no ne .rane E : :Function&'Model Verification Periodicity a i Row Number \'erification Condition Required Action 1 Establishing the mitial verification date for an applicable |Transmit the verified model,documentation and data to the Transmission unit.Planner on or before the Effective Date. Row 4 applies when calculating generation fleet compliance during the 5- (Requirement R2)year implementation period See Section A5 for Effective Dates. 2 wee .;Transmit the verified model,documentation and data to the TransmissionSubsequentverificationforanapplicableunit... :Planner on or before the 5-year anniversary of the last transmittal (per Note(Requirement R2)1) 3 Initial verification for a new applicable uni or for an existing applicable unit with new excitation control system [Transmit the verified model,documentation and data to the Transmission or plant volt/var control function equipment nstalled.Planner within 90 calendar days after the commissionmg date. (Requirment R2) Alaska Railbelt Standard AKMOD-026-1-Verification of Models and Data for Generator Excitation Control System or Plant Volt/Var Control Functions Page 64 of 168 AK)1OD-26 Attachment ]i.reerFunctionModelVerificationPeriodic Row Number Nentenion Cond ition Requireg Action 4 Existing applicable un thatis equivalent to another unit(s)[Document circumstance with a written statement and include with the at the same physical location.verified model,documentation,and data provided to the Transmission AND Pianner for the verified equivalent unit. Each applicable unit has the same MVA nameplate rating. AND Verify a different equivalent uni during each 5-year verification period. The namephte rating is <30 MVA or 2 MVA for Power Ekctronics Transmission Assets.Applies to Row 1 when cakulating generation fleet compliance during the 5- AND year implementation period. Each applicable unit has the same components and settings. AND The model for one of these equivalent applicable units has been verified. 5 The Generator Owner or Transmission Owner has submitted a verification plan.Transmit the verified model,documentation and data to the Transmission (Requirement R3,R4 or R5)Pianner within 60-calendar days after the model verification. Alaska Railbelt Standard AKMOD-026-1-Verification of Models and Data for GeneratorExcitationControlSystemorPlantVolt/Var Control Functions -noe Page 65 of 168 Verification ConditionRowNumber Required Action 6 New or existing applicable unit does not inchide an active closed loop voltage or reactive power control function. (Requirement R2) Requirement 2 is met with a writen statement to that effect transmitted to the Transmission Planner. Perform verification per the periodicity specified in Row 3 for a "New Generating Uni”(or new equipment)only if active closed loop function is established. See Footnote 1 (see Section A.3)for clarification of what constitutes an active closed loop function for both conventional synchronous machines (reference Footnote 1a)and aggregate generating plants (reference Footnote 1b). Existing applicable uni has a current average net capacity factor over the most recent three calendar years, beginning on January 1 and ending on December 31 of 5% or less. Existing Power Electronics Transmission Assets was available for less than 10%of the most recent one year, beginnmg on January |and ending on December 31. (Requirement R2) Requirement 2 is met with a written statement to that effect transmitted to the Transmission Planner. At the end of this 5-year timeframe,the current average three year net capacity factor (for years 3,4,and 5)can be examined to determine if the capacity factor exemption can be declared for the next 5-year period.If not eligible for the capacity factor exemption,then model verification must be completed within 365 calendar days of the date the capacity factor exemption expired. For the definition of net capacity factor,refer to Note 3. Row Number|Verification Condition ion Model Verification Periodi Required Action NOTES: NOTE 1:Establishing the recurring 5-year uni verification period start NOTE 2:Consideration for early compliance: period from the actual transmittal date if either of the following applies: at the time of model verification. NOTE 3:Net Capacity Factor Equations: Net Actual Generation PH *NMCEquation1:NCF =*100% Where: *NMC =Net Maximum Capacity do not simply average these factors.Follow Equation 2 Equation2:NCF = date: The start date is the actual date of submittal of a verified model to the Transmission Planner for the most recently performed unit verification. Existing generator excitation control system or plant volt/var control function model verification is sufficient for demonstrating compliance for a 5-year *The Generator Owner or Transmission Owner has a verified model that is compliant with the applicable regional policies,guidelines or criteria existing «The Generator Owner or Transmission Owner has an existing verified model that is compliant with the requirements of this standard. L(Net Actual Generation) ¥(PH *NMC)*100% *PH =Period Hours (Number of hours in the period being reported that the unit was in the active state) ¢Equation 2 is an energy-weighted equation.Use Equation 2 when cakculating for a group of units (or a unit that has a varying capacity value over time), Alaska Railbelt Standard AKMOD-026-1-Verification of Models and Data for GeneratorExcitationControlSystemorPlantVolt/Var Control Functions Page 66 of 168 Alaska _Railbelt Standard AKMOD-027-Verification of Models and _Data _for Turbine/Governor and Load Control or Active Power/Frequency Control Functions A.Introduction Title:Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions Number:AKMOD-027-1 Purpose:To verify that the turbine/governor and load control or active power/frequency control®model and the model parameters,used in dynamic simulations that assess Bulk Electric System (BES)reliability,accurately represent generator unit real power response to system frequency variations. Applicability: R19.5.Functional Entities: R19.5.1.Generator Owner R19.5.2.Transmission Planner R19.5.3.Transmission Owner R19.6.Facilities: For the purpose of the requirements contained herein,Facilities that are directly connected to the Bulk Electric System (BES)will be collectively referred to as an "applicable unit”that meet the following: R19.6.1.Generation in the Interconnection with the following characteristics: 19.6.1.1.Individual generating unit greater than 5 MVA (gross nameplate rating). 19.6.1.2.Individual generating plant consisting of multiple generating units that are directly connected at a common BES bus with total generation greater than 5 MVA (gross aggregate nameplate rating). R19.6.2.Power Electronics Transmission Assets with Real Power capabilities greater than 1 MVA directly connected to the Bulk Electric System. Effective Date: TBD (Standard should be implemented as a test and monitored for a minimum of 12 months to ascertain ability to comply and monitor) ®Turbine/governor and load control or active power/frequency control: a.Turbine/governor and load control applies to conventional synchronous generation. b.Active power/frequency control applies to inverter connected generators (often found at variable energy plants). Alaska Railbelt Standard AKMOD-027-1 Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions Page 67 of 168 Effective Date,TBD B.Requirements R20.Each Transmission Planner shall provide the following information to the Generator Owner or Transmission Owner within 30 calendar days of receiving a written request: e Instructions on how to obtain the list of turbine/governor and load control or active power/frequency control system models that are acceptable to the Transmission Planner for use in dynamic simulation, e Instructions on how to obtain the dynamic turbine/governor and load control or active power/frequency control function model library block diagrams and/or data sheets for models that are acceptable to the Transmission Planner,or e Model data for any of the Generator Owner's or Transmission Owner's existing applicable unit specific turbine/governor and load control or active power/frequency control system contained in the Transmission Planner's dynamic database from the current (in-use)models. e It is noted that digital governors with multiple modes of control and operation may require the Generation Owner or Transmission Owner to develop custom models to simulate the response of the unit.Such models will be based on standard models provided by the Transmission Planner to the extent possible. R21.Each Generator Owner shall provide,for each applicable unit,a verified turbine/governor and load control or active power/frequency control model,including documentation and data (as specified in Part 2.1)to any Transmission Planner in accordance with the periodicity specified in MOD-027 Attachment 1.Transmission Owners shall provide the same documentation and data for applicable Power Electronics Transmission Assets. 21.1.Each applicable unit's model shall be verified by the Generator Owner or Transmission Owner using one or more models acceptable to the Transmission Planner.Verification for individual units rated less than 5 MVA (gross nameplate rating,1 MVA for Power Electronics Transmission Assets)in a generating plant (per Section 4.2.1.2)may be performed using either individual unit or aggregate unit model(s)or both.Each verification shall include the following: 21.1.1.Documentation comparing the applicable unit's MW model response to the recorded MW response for either: e A frequency excursion from a system disturbance that meets MOD-027 Attachment 1]Note 1 with the applicable unit on- line, e A speed governor reference change with the applicable unit online,or o For staged tests,the governor reference change should occur at multiple operating points including minimum, Alaska Railbelt Standard AKMOD-027-1 Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions Page 68 of 168 Effective Date,TBD . peak load,and near peak load to show the impact that unit output has on the unit response to a reference change. o Staged tests shall include verification of governor performance for each mode transition,including transitions back from transient mode if applicable for system modeling. e A partial load rejection test,' 21.1.2.Type of governor and load control or active power control/frequency control®equipment, 21.1.3.A description of the turbine (e.g.for hydro turbine -Kaplan,Francis, or Pelton;for steam turbine -boiler type,normal fuel type,and turbine type;for gas turbine -the type and manufacturer;for variable energy plant -type and manufacturer;for Power Electronics Transmission Asset -type and manufacturer), 21.1.4.Model structure and data for turbine/governor and load control or active power/frequency control, 21.1.5.Description and recommended modeling method for any governor actions that would limit the active power or change governor control modes including,but not limited to: e Temperature limiters e Pressure limiters e Rate limiters 21.1.6.Description and recommended modeling method for any governor response resulting from a control mode change within the governor during on-line operations.All control mode changes must be included in the recommended modeling method. 21.1.7.Representation of the real power response effects of outer loop controls (such as operator set point controls,and load control but excluding AGC control)that would override the governor response 7 Differences between the control mode tested and the final simulation model must be identified,particularly when analyzing load rejection data.Most controls change gains or have a set point runback which takes effect when the breaker opens.Load or set point controls will also not be in effect once the breaker opens.Some method of accounting for these differences must be presented if the final model is not validated from on-line data under the normal operating conditions under which the model is expected to apply. 8 Turbine/governor and load control or active power/frequency control: a.Turbine/governor and load control applies to conventional synchronous generation. b.Active power/frequency control applies to inverter connected generators (often found at variable energy plants). Alaska Railbelt Standard AKMOD-027-1 Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions Page 69 of 168 Effective Date,TBD (including blocked or nonfunctioning governors or modes of operation that limit Frequency Response),if applicable. 21.2.Each Generator Owner or Transmission Owner shall provide model structure, data,and source code (if available)for any turbine/governor and load control or active power/frequency control function model that requires a custom model that is not in the model list provided by the Transmission Planner. 21.2.1.The Generator Owner or Transmission Owner shall document the need for using a custom model and provide the documentation to the Transmission Planner. R22.Each Generator Owner or Transmission Owner shall provide a written response to any Transmission Planner within 60 calendar days of receiving one of the following items for an applicable unit. e Written notification,from any Transmission Planner (in accordance with Requirement RS)that the turbine/governor and load control or active power/frequency control model is not "usable,” e Written comments from any Transmission Planner identifying technical concerns with the verification documentation related to the turbine/governor and load control or active power/frequency control model,or e Written comments and supporting evidence from any Transmission Planner indicating that the simulated turbine/governor and load control or active power/frequency control response did not approximate the recorded response for three or more transmission system events. The written response shall contain either the technical basis for maintaining the current model,the model changes,or a plan to perform model verification'(in accordance with Requirement R2). R23.Each Generator Owner or Transmission Owner shall provide revised model data or plans to perform model verification (in accordance with Requirement R2)for an applicable unit to any Transmission Planner within 60 calendar days of making changes to the turbine/governor and load control or active power/frequency control system that alter the equipment response characteristic!®. R24.Each Transmission Planner shall provide a written response to the Generator Owner or Transmission Owner within 30 calendar days of receiving the turbine/governor and load control or active power/frequency control system verified model information in accordance with Requirement R2 that the model is usable (meets the criteria specified in Parts 5.1 through 5.3)or is not usable. *If verification is performed,the 5 year period as outlined in MOD-027 Attachment 1 is reset.'0 Control replacement or alteration including software alterations or plant digital control system addition or replacement,plant digital control system software alterations that alter droop,and/or dead band,and/or frequency response and/or a change in the frequency control mode (such as going from droop control to constant MW control, etc). Alaska Railbelt Standard AKMOD-027-1 Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions Page 70 of 168 Effective Date,TBD 24.1.The turbine/governor and load control or active power/frequency control function model initializes to compute modeling data without error, 24.2.A no-disturbance simulation results in negligible transients,and 24.3.For an otherwise stable simulation,a disturbance simulation results in the turbine/governor and load control or active power/frequency control model exhibiting positive damping. If the model is not usable,the Transmission Planner shall provide a technical description of why the model is not usable. C.Measures M25.The Transmission Planner must provide the dated request for instructions or data,the transmitted instruction or data,and dated evidence of a written transmittal (e.g., electronic mail message,postal receipt,or confirmation of facsimile)as evidence that it provided the request within 30 calendar days in accordance with Requirement R1. M26.The Generator Owner or Transmission Owner must provide dated evidence it verified each generator turbine/governor and load control or active power/frequency control model according to Part 2.1 for each applicable unit and a dated transmittal (e.g., electronic mail message,postal receipt,or confirmation of facsimile)as evidence it provided the model,documentation,and data to any Transmission Planner,in accordance with Requirement R2. M27.Evidence for Requirement R3 must include the Generator Owner's or Transmission Owner's dated written response containing the information identified in Requirement R3 and dated evidence of transmittal (e.g.,electronic mail message,postal receipt,or confirmation of facsimile)of the response. M28.Evidence for Requirement R4 must include,for each of the Generator Owner's or Transmission Owner's applicable units for which system changes specified in Requirement R4 were made,dated revised model data or dated plans to perform a model verification and dated evidence of transmittal (e.g.,electronic mail message, postal receipt,or confirmation of facsimile)within 60 calendar days of making changes. M29.Evidence of Requirement R5 must include,for each model received,the dated response indicating the model was usable or not usable according to the criteria specified in Parts 5.1 through 5.3 and for a model that is not useable,a technical description that the model is not usable,and dated evidence of transmittal (e.g.,electronic mail messages, postal receipts,or confirmation of facsimile)that the Generator Owner or Transmission Owner was notified within 30 calendar days of receipt of model information in accordance with Requirement R5. C.Compliance R30.Compliance Monitoring Process 30.1.Compliance Enforcement Authority Alaska Railbelt Standard AKMOD-027-1 Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions Page 71 of 168 Effective Date,TBD Regional Coordinating Council 30.2.Data Retention The following evidence retention periods identify the period of time an entity is required to retain specific evidence to demonstrate compliance.For instances where the evidence retention period specified below is shorter than the time since the last audit,the Compliance Enforcement Authority may ask an entity to provide other evidence to show that it was compliant for the full time period since the last audit. The Generator Owner,Transmission Owner,and Transmission Planner shall each keep data or evidence to show compliance as identified below unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation: e The Transmission Planner shall retain the information/data request and provided response evidence of Requirements R1 and RS,Measures M1 and MS for 3 calendar years from the date the document was provided. e The Generator Owner or Transmission Owner shall retain the latest turbine/governor and load control or active power/frequency control system model verification evidence of Requirement R2,Measure M2. e The Generator Owner or Transmission Owner shall retain the information/data request and provided response evidence of Requirements R3,and R4 Measures M3 and M4 for 3 calendar years from the date the document was provided. If a Generator Owner,Transmission Owner,or Transmission Planner is found non-compliant,it shall keep information related to the non-compliance until mitigation is complete and approved or for the time specified above,whichever is longer. The Compliance Enforcement Authority shall keep the last audit records and all requested and submitted subsequent audit records. 30.3.Compliance Monitoring and Assessment Processes: Compliance Audit Self-Certification Spot Checking Compliance Investigation Self-Reporting Complaint 30.4.Additional Compliance Information None Alaska Railbelt Standard AKMOD-027-1 Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions .Page 72 of 168 Effective Date,TBD ee So, R31.Levels of Non-Compliance 31.1.Levels of Non-Compliance for Requirement R1,Measure M1 31.1.1. 31.1.2. Level 1 -The Transmission Planner failed to retain dated evidence that it provided the requested information within 30 calendar days in accordance with Requirement R1. Level 2 -The Transmission Planner failed to provide the Generator Owner or Transmission Owner with the requested information in accordance with Requirement R1. 31.2.Levels of Non-Compliance for Requirement R2,Measure M2 31.2.1. 31.2.2. Level 1 -The Generator Owner or Transmission Owner failed to retain dated evidence it provided the model,documentation,and data to any Transmission Planner,in accordance with Requirement R2. Level 2 -The Generator Owner,or Transmission Owner failed to provide the model,documentation,and data to any Transmission Planner,in accordance with Requirement R2. 31.3.Levels of Non-Compliance for Requirement R3,Measure M3 31.3.1. 31.3.2. Level 1 -The Generator Owner,or Transmission Owner failed to retain dated evidence showing it responded to the Transmission Planner and provided the information identified in Requirement R3. Level 2 -The Generator Owner,or Transmission Owner failed to respond to the Transmission Planner with the information identified in Requirement R3. 31.4.Levels of Non-Compliance for Requirement R4,Measure M4 31.4.1.Level 1 -The Generator Owner,or Transmission Owner failed to retain evidence which includes,for each of the Generator Owner's or Transmission Owner's applicable units for which system changes specified in Requirement R4 were made,dated revised model data or dated plans to perform a model verification. 31.5.Levels of Non-Compliance for Requirement R5,Measure M5 31.5.1. E.Regional Variances None Level 1 -The Transmission Planner failed to retain dated response to the Generator Owner or Transmission Owner which must include,for each model received,an indication that the model was usable or not usable according to the criteria specified in Parts 5.1 through 5.3. F.Associated Documents None Alaska Railbelt Standard AKMOD-027-1 Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions Effective Date,TBD Page 73 of 168 Version History :ChangeVersionDateAction:Tracking 0 fF oe NERC Version -sisi' 1 (2-23-2016 EPSeditfromNERCstandards =j==|_Yes 2 __|3-16-2016!_ss CEPSedit:--|Yes 3.|9-16-2016: =----s EPS edd following 8/25/2016 meeting =s--™/Yes _4 11-18-2016 __EPSrevision,additionofRCC |Yes Final 12-06-2016 Final Version no Row rtp out us .:Number Verification Condition Required Action 1 Transm the verified model,documentation and data to the Transmission Establishing the initial verification date for an applicable unit.Planner on or before the Effective Date. Row 5 applies when calculating generation fleet compliance during the 5 (Requirement R2)year implementation period. See Section AS for Effective Dates. 2 te ge .:Transmut the verified model,documentation and data to the TransmissionSubsequentverificationforanapplicableunit.:p tae :Planner on or before the 5-year anniversary of the last transmittal (per T(Requirement R2)2) 3 Applicable unit was not subjected to a frequency excursion per Note 1 with available generating capacity available to show Governor or Load Control response by the date otherwise ired t t the dat R 1,2,4,or 6.;:.requreqsomee €s per Rows 1,2,4,or 6 Requirement 2 is met with a written statement to that effect transmitted to (This row is only applicable ifa frequency excursion from a the Transmission Planner.Transmit the verified model,documentation and :;data to the Transmission Planner on or before 60 calendar days after asystemdisturbancethatmeetsNote1isselectedforthefr.Note 1 dth din .tverificationmethodandtheabilitytorecordtheapplicableunit's sce the anplicable 4 .©vous ane Me Fecoreng _real power response to a frequency excursion is installed and captures the applicable unk 's real power response as expecte expected to be available). (Requirement R2) 4 Initial verification for a new applicable unit or for an existing applicable unit with new turbine/governor and load control or Transmit the verified model,documentation and data to the Transmission active power/frequency control equipment installed.Planner within 90 calendar days after the commissioning date. (Requirment R2) Alaska Railbelt Standard AKMOD-027-1 Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions Effective Date,TBD Page 74 of 168 __ae /KM OD-27 Attachment 1 a 7 enmeers |_ :Governor and Load ControlorActive P ower /Frequency Control = Row rete gs a:.FNumberVerificationConditionRequiredAction 5 Exsting applicable unk that is equivalent to another applicable unit(s)at the same physical location. AND ..:.. Each applicable uni has the same MVA nameplate rating,Document circumstance with a written statement and include with theANDverifiedmodel,documentation and data provided to the Transmission The nameplate rating is <30 MVA or 2 MVA for Power Planner for the verified equivalent unit pia Transmission Assets.Verify a different equivalent uni during each 5-year verification period. pac Ppueabe unit has the same Components and settings;Applies to Row |when calculating generation fleet compliance during the 5- The model for one of these equivalent applicable units has been year implementation period. verified. (Requirement R2) 8 verification plan or Transmission Owner has submitted a Transmit the verified model,documentation and data to the Transmission (Requirement R3,R4 or RS)Planner within 60 calendar days after the model verification. 'a : bine/Governor and Load Controlor Active F atrol Mode!Periodicity aauepaaOaEa ca Row .es .. Number Verification Condition Required Action 7 Applicable unit is not responsive to both over and under frequency excursion events (The applicable unit does not operate in a frequency control mode,except during normal start up and shut down,that would result in a turbine/governor and load control or |Requirement 2 is met with a written statement to that effect transmitted to active power/frequency control mode response.);the Transmssion Planner. OR Perform verification per the periodicity specified in Row 4 for a "New Generating Uni”(or new equipment)only if responsive control mode Applicable unit ether does not have an installed frequency control operation for connected operations is established. system or has a disabled frequency control system. (Requirement R2) 8 Requirement 2 is met with a written statement to that effect transmitted to Existing applicable unit has a current average net capacity factor |the Transmssion Planner. over the most recent three calendar years,beginning on January 1 and ending on December 31 of 5%or less.At the end ofthis 5 calendar year timeframe,the current average three year net capacity factor (for years 3,4,and 5)can be examined to determine if Existing Power Electronics Transmission Assets was available for|the capacity factor exemption can be declared for the next 5 calendar year less than 10%of the most recent one year,beginning on January |period.If not eligible for the capacity factor exemption,then model 1 and ending on December 31.verification must be completed within 365 calendar days of the date the capacity factor exemption expired. (Requrement R2) For the definition of net capacity factor,refer to Note 4. Alaska Railbelt Standard AKMOD-027-1 Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions Page 75 of 168 Effective Date,TBD Row Number NOTES: NOTE 1:Uni model verification frequency excursion criteria: *20.30 hertz deviation (nadir pont)from scheduled frequency for the Interconnection with the applicable uni operating in a frequency responsive mode Verification Condition Required Action NOTE 2:Establishing the recurring 5 year unit verification period start date: *The start date is the actual date of submittal of a verified model to the Transmission Planner for the most recently performed uni verification. *The Generator Owner or Transmission Owner has an existing verified model that is compliant with the requirements of this standard. NOTE 3:Consideration for early compliance: Existing turbine/governor and load control or active power/frequency control model verification is sufficient for demonstrating compliance for a 5 year period from the actual transmittal date if either of the following applies: *The Generator Owner or Transmission Owner has a verified model that is compliant with the applicable regional policies,guidelines or criteria existing at the time of model verification *The Generator Owner or Transmission Owner has an existing verified model that is compliant with the requirements of this standard NOTE 4:Net Capacity Factor Equations: Net Actual Generation L(Net Actual Generation)tion 1:=Y i :=Equation1:NCF PH *NMC *100%Equation2:NCF T(PH =NMC)*100% Where: +PH =Period Hours (Number of hours in the period being reported that the unit was in the active state) *NMC =Net Maximum Capacry *Equation 2 is an energy-weighted equation.Use Equation 2 when calculating for a group of units (or a unit that has a varying capacity value over time),do not simply average these factors.Follow Equation 2 Alaska Railbelt Standard AKMOD-027-1 Verification of Models and Data for Turbine/Governor and Load Control or Active Power/Frequency Control Functions Page 76 of 168 Effective Date,TBD Alaska Railbelt Standard AKMOD-028--Total Transfer Capability A.Introduction Title:Total Transfer Capability Number:AKMOD-028 Purpose:To ensure that determinations of transmission system capability are completed in a manner that supports the reliable operation of the Bulk-Power System (BPS)and that the methodology and data underlying those determinations are disclosed to those registered entities that need such information for reliability purposes. Applicability: R31.6.Transmission Planner R31.7.Transmission Operator R31.8.Transmission Service Provider Effective Date: Immediately after approval of applicable regulatory authorities. B.Requirements R1.Each Transmission Planner shall develop a written methodology (or methodologies) for determining Total Transfer Capability (TTC)or Emergency Transfer Capability (ETC)values.The methodology (or methodologies)shall reflect the Transmission Operator's current practices. R1.1.Each methodology shall describe the method used to account for the following limitations in both the pre-and post-contingency state: R1.1.1.Facility ratings; R1.1.2.System voltage limits; R1.1.3.Transient stability limits; R1.1.4.Path Thermal Limits; R1.1.5.Voltage stability limits;and R1.2..Each methodology shall describe the method used to account for each of the following elements,provided such elements impact the determination of TTC or ETC: R1.2.1.The simulation of transfers performed through the adjustment of generation,load,or both; R1.2.2.Transmission topology,including,but not limited to,additions and retirements; R1.2.3.Planned outages; R1.2.4.Generator commitment; Alaska Railbelt Standard AKMOD-028-Total Transfer Capability Page 77 of 168 Effective Date,TBD R1.2.5. R1.2.6. R1.2.7. R1.2.8. R1.2.9. Parallel path (loop flow)adjustments; Transmission Reliability Margin; Contingency Reserve obligations of source area; Load forecast;and Generator dispatch,including,but not limited to,additions and retirements. R2.When calculating TTCs and ETCs,the Transmission Planner shall use a Transmission model which satisfies the following requirements: R2.1.The model utilizes data and assumptions consistent with the time period being studied and that meets the following criteria: R2.1.1. R2.1.2. R2.1.3. R2.1.4. R2.1.5. R2.1.6. R2.1.7. R2.1.8. R2.1.9. Includes all transmission lines and facilities rated at 69 kV and higher. Models all system Elements as in-service for the assumed initial conditions. Models all generation (may be either a single generator or multiple generators)that is greater than 5 MVA at the point of interconnection in the studied area. Models phase shifters in non-regulating mode,unless otherwise specified in the Total Transfer Capability Implementation Document (TTCID). Uses Load forecast by Balancing Authority. Uses Transmission Facility additions and retirements. Uses Generation Facility additions and retirements. Uses Special Protection System (SPS)models where currently existing or projected for implementation within the studied time horizon unless specified otherwise in the TTCID. Models series compensation for each line at the expected operating level unless specified otherwise in the TTCID. R2.1.10.Includes any other modeling requirements or criteria specified in the TTCID. R2.2.Uses Facility Ratings as provided by the Transmission Owner and Generator Owner R3.The Transmission Planner shall use the following process to determine TTC and ETC: R3.1.Except where otherwise specified within AKMOD-028,adjust base case generation and load levels within the updated power flow model to determine the TTC (maximum flow or reliability limit)that can be simulated on the path while at the same time satisfying all planning criteria contingencies as follows: Alaska Railbelt Standard AKMOD-028-Total Transfer Capability Effective Date,TBD Page 78 of 168 R3.1.1._When modeling normal and contingency conditions,the projected generation commitment for the study time period shall be used. R3.1.2._When modeling normal conditions,all transmission Elements will be modeled at or below 100%of their continuous rating. R3.1.3..When modeling contingencies,the system shall demonstrate transient, dynamic and voltage stability,with no transmission Element modeled above its Emergency Rating following the contingency. R3.1.3.1.The modeled contingencies shall include N-1 outages of generating units and transmission lines. R3.1.3.2.The Steady-State Transfer Limit shall be identified. R3.1.3.3.The Steady-State Transfer Capability shall be identified. R3.1.3.4.The Transient Transfer Limit shall be identified. R3.1.4.Uncontrolled separation shall not occur. R3.1.4.1.Separation is allowed for outages of a tie to a radial system or a tie between areas connected by one transmission Element. R3.2._For a path whose capacity is limited by contract,set TTC on the path at the lesser of the maximum allowable contract capacity or the reliability limit as determined by R3.1.. R3.3._For a path whose TTC varies due to simultaneous interaction with one or more other paths,develop a nomogram or chart describing the interaction of the paths and the resulting TTC under specified conditions. R3.4.The Transmission Planner shall identify when the TTC for the path being studied has an adverse impact on the TTC value of any existing path.Do this by modeling the flow on the path being studied at its proposed new TTC level simultaneous with the flow on the existing path at its TTC level while at the same time honoring the reliability criteria outlined in R3.1.The Transmission Planner shall include the resolution of this adverse impact in its study report. R3.5.Create a study report that describes the steps above that were undertaken (R3.1 -R3.4),including the contingencies and assumptions used,when determining the TTC and the results of the study. R4._The Transmission Operator shall operate the system such that each path is at or below its respective TTC. R4.1.In normal operating conditions all paths shall be operated below the minimum of: R4.1.1.Facility ratings R4.1.2.System voltage limit R4.1.3.Transient stability limit R4.1.4.Path thermal limit Alaska Railbelt Standard AKMOD-028-Total Transfer Capability Page 79 of 168 Effective Date,TBD R4.1.5.Voltage stability limit R4.2.Paths that are stability limited may be operated above the TTC in an Emergency. R4.2.1.The Emergency Transfer Capability is the minimum of: R4.2.1.1.ETC limited by Facility ratings R4.2.1.2.ETC limited by System voltage limit R4.2.1.3.ETC limited by Path thermal limit R4.2.2.The path must be restored below its TTC limit in accordance with the contingency reserve restoration period defined in AKBAL-002. RS.Within seven calendar days of the finalization of the study report,the Transmission Planner shall make available to the Transmission Operator and Transmission Service 'Provider of the path,the most current value for TTC and the TTC study report documenting the assumptions used and steps taken in determining the current value for TTC for that path. R6.Within 45 calendar days of receiving a written request that references this specific requirement from a Planning Coordinator,Reliability Coordinator,Transmission Operator,Transmission Planner,Transmission Service Provider,or any other registered entity that demonstrates a reliability need,each Transmission Planner shall provide: R6.1.A written response to any request for clarification of its TTC methodology.If the request for clarification is contrary to the Transmission Planner's confidentiality,regulatory,or security requirements then a written response shall be provided explaining the clarifications not provided,on what basis and whether there are any options for resolving any of the confidentiality, regulatory,or security concerns. R6.2.The TTC methodology. C.Measures M7.Each Transmission Planner that determines TTC shall provide its current written methodology (or methodologies)or other evidence (such as written documentation)to show that its methodology (or methodologies)contains the following: e A description of the method used to account for the limits specified in R1.1.Methods of accounting for these limits may include,but are not limited to,one or more of the following: o TTC being determined by one or more limits. o Simulation being used to find the maximum TTC that remains within the limit. Alaska Railbelt Standard AKMOD-028-Total Transfer Capability Page 80 of 168 Effective Date,TBD ©Monitoring a subset of limits and a statement that those limits are expected to produce the most severe results. o A statement that the monitoring of a select limit(s)results in the TTC not exceeding another set of limits. o A statement that one or more of those limits are not applicable to the TTC determination. e A description of the method used to account for the elements specified in R1.2, provided such elements impact the determination of TTC.Methods of accounting for these elements may include,but are not limited to,one or more of the following: o A statement that the element is not accounted for since it does not affect the determination of TTC. o A description of how the element is used in the determination of TTC. e Each Transmission Planner that determines TTC shall provide evidence that currently active TTC values were determined based on its current written methodology,as specified in Requirement R1. M8.Each Transmission Planner shall produce any Transmission model it used to calculate TTC,as required in R2,for the time horizon(s)to be examined.(R2) M8.1.The Transmission model produced must include all system elements rated 69 kV and higher.(R2.1) M8.2.The Transmission model produced must show the use of the modeling parameters stated in R2.1.2 through R2.1.10;except that,no evidence shall be required to prove:1)utilization of a Special Protection System where none was included in the model or 2)that no additions or retirements to the generation or Transmission system occurred.(R2.1.2 through R2.1.10) M8.3.The Transmission Planner must provide evidence that the models used to determine TTC included Facility Ratings as provided by the Transmission Owner and Generator Owner.(R2.2) M9.Each Transmission Planner shall produce the TTCID it uses to show where it has described and used additional modeling criteria in its TTCID that are not otherwise included in AKMOD-28 (R2.1.4,R2.1.9,and R2.1.10). M10.Each Transmission Planner shall produce as evidence the study reports,as required in R3.5,for each path for which it determined TTC for the period examined.(R3) M11.Each Transmission Operator shall provide evidence that it operated the system within the TTC or ETC,when appropriate,provided by the Transmission Planner.The evidence shall include,at a minimum,any and all instances when a path exceeded its TTC during normal operations or any and all instances when a path exceed its Emergency Transfer Capability.(R4) Alaska Railbelt Standard AKMOD-028-Total Transfer Capability Page 81 of 168 Effective Date,TBD M12.Each Transmission Planner shall provide evidence (such as logs or data)that it provided the TTC and its study report to the Transmission Service Provider within seven calendar days of the finalization of the study report.(R5) M13.Examples of evidence required in R6 include,but are not limited to: e Dated records of the request and the Transmission Planner's response to the request; e A statement by the Transmission Planner that they have received no requests;or e A statement by the Transmission Planner that they do not determine TTC. D.Compliance R14.Compliance Monitoring Process 14.1.Compliance Enforcement Authority Regional Coordinating Council 14.2.Compliance Monitoring Period and Reset Time Frame Not applicable. 14.3.Data Retention The following evidence retention periods identify the period of time a registered entity is required to retain specific evidence to demonstrate compliance.For instances in which the evidence retention period specified below is shorter than the time since the last audit,the Compliance Enforcement Authority may ask the registered entity to provide other evidence to show that it was compliant for the full time period since the last audit. e Implementation and methodology documents shall be retained for five years. e Components of the calculations and the results of such calculations for all values contained in the implementation and methodology documents. e Ifa Transmission Planner is found non-compliant,it shall keep information related to the non-compliance until mitigation is complete and approved. e The Compliance Enforcement Authority shall keep the last audit records and all requested and submitted subsequent audit records. -The Transmission Planner shall keep data or evidence to show compliance as identified below unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation: -The Transmission Planner shall have its latest models used to determine TTC for R2.(M2) Alaska Railbelt Standard AKMOD-028-Total Transfer Capability Page 82 of 168 Effective Date,TBD -The Transmission Operator shall retain documentation that it operated the system within the TTC and Emergency Transfer Capability.(M4) -The Transmission Operator shall retain the latest version and prior version of the TTC study reports to show compliance with R3.(M5) The Transmission'Operator shall retain evidence for the most recent three calendar years plus the current year to show compliance with R4.(M6) Ifa Transmission Planner or Transmission Operator is found noncompliant,it shall keep information related to the non-compliance until found compliant. The Compliance Enforcement Authority shall keep the last audit records and all requested and submitted subsequent audit records. 14.4.Compliance Monitoring and Enforcement Processes: The following processes may be used: -Compliance Audits -Self-Certifications -Spot Checking Compliance Violation Investigations -Self-Reporting -Complaints 14.5.Additional Compliance Information None. R15.Levels of Non-Compliance R15.1.Levels of Non-Compliance for Requirement R1,Measure M1 R15.1.1.Level 1 -The methodology did not reflect the Transmission Operator's current practices. R15.1.2.Level 1 -The methodology failed to describe the method used to account for an element in R1.2.1 through R1.2.6. R15.1.3.Level 2 -The methodology failed to describe the method used to account for an element in R1.1.1 through R1.1.4. R15.1.4.Level 2 -Transmission Operator failed to develop a written methodology for determining TTC values. R15.2.Levels of Non-Compliance for Requirement R2,Measures M2,M3 R15.2.1.Level 1 -The model used for calculating TTCs failed to account for up to two of the criteria specified in R2.1.1 through R2.1.10. R15.2.2.Level 2 -The model used for calculating TTCs failed to account for more than two of the criteria specified in R2.1.1 through R2.1.10. Alaska Railbelt Standard AKMOD-028-Total Transfer Capability Page 83 of 168 Effective Date,TBD R15.3. R15.4. R15.5. R15.6. R15.2.3.Level 2 -The TP failed to produce a TTCID. Levels of Non-Compliance for Requirement R3,Measure M4 R15.3.1.Level 1 -The study report did not account for one of the planning criterion listed in R3.1.1 through R3.1.4. R15.3.2.Level 1 -Either the study report 'did not account for:contractual limitations,simultaneous interactions with one or more other paths,or the study report did not account for adverse impacts on the TTC of any existing path. R15.3.3.Level 2 -A study report was not created to support TTC values. Levels of Non-Compliance for Requirement R4,Measure M5 R15.4.1.Level 1 -The TO failed to provide evidence that it operated the system within the TTC provided by the Transmission Planner. R15.4.2.Level 2 -The TO failed to take corrective action to reduce path flow below its TTC or Emergency Transfer Capability. Levels of Non-Compliance for Requirement R5,Measure M6 R15.5.1.Level 1 -The TP failed to make the most current TTC and TTC study report available to the TO and TSP for the path within 7 days of the report finalization. Levels of Non-Compliance for Requirement R6,Measure M7 R15.6.1.Level 1 -The TP failed to provide an acceptable response to a written request from a registered entity within 45 days. Version History .ChangeVersionDateActionTracking | 1 a 9162016 =.....EPS-ImitialRelease 2 11-18-2016 EPS-Revisions following 10/20/2016 Meeting =./Yes _ _3 12-06-2016 -_-_-saEEPS-Revisions following 12/05/2016 Meeting ==-_--iYes_- Final 12-06-2016 Final Version no Alaska Railbelt Standard AKMOD-028-Total Transfer Capability Page 84 of 168 Effective Date,TBD AKMOD-028 Attachment 1 Sample Total Transfer Capability Implementation Document (TTCID) This document should serve as a guideline when the Alaska Railbelt transmission planners create a TTCID as required in AKMOD-028. Transmission Planner's Total Transfer Capability Methodology and Implementation Document Base Case Creation The Transmission Planner will use regionally approved planning base cases as the starting point for the study.The base cases will include the winter peak,summer peak,and summer valley load conditions.Additional cases with different load levels are recommended to identify the full range of path transfer capabilities for a wide range of operating conditions. It is assumed that the modeling requirements listed in AKMOD-028 R2.1.1 through R2.1.5, R2.1.8,R2.1.9,and R2.2 are confirmed as part of the base case approval process.Alaska does not have phase shifting transformers and is exempt from AKMOD R2.1.4.To comply with AKMOD-028 R1.2.2 and R1.2.9 for cases focused on future time frames,the TP should confirm transmission and generation additions and retirements are modeled in the database, The transmission planner will verify that all transmission Elements are modeled at or below 100%of their continuous rating per R3.1.2 in the base cases. For operational studies that are studying the impact of a planned outage,remove the element from service for all base cases.If the planned outage is a generator,update the case using a commitment order as provided by the applicable BA.If the planned outage is a transmission line, remove the line from service and confirm the power flow case solves and identify if the change in system losses or transfers requires re-dispatch or re-commitment. Power Flow Analysis Power flow analysis (contingency analysis)shall be performed on the base cases.The contingency list should include all N-1 line contingencies rated at 69 kV and higher plus the largest generation contingency for each BA at a minimum.Confirm that at the post-contingency condition all transmission Elements remain below their emergency ratings,and all buses rated at 69 kV or higher shall have voltages that are between 0.95 and 1.05 per-unit voltage. The generation dispatch and commitment will be adjusted to increase transfers across the path(s) that are the focus of the analysis.The following steps will be used to increase the transfers: 1.Increase source area generation and decrease sink area generation in 5 MW increments. a.The next generating unit in the commitment order should be committed if the source area would have insufficient capacity to meet local demand,to source generation through the path,and to provide the required contingency reserves. b.The lowest generating unit in the commitment order should be de-committed if the sink area has sufficient capacity to meet local demand and to provide the required contingency reserves. Alaska Railbelt Standard AKMOD-028-Total Transfer Capability Page 85 of 168 Effective Date,TBD c.The Transmission Planner shall use the commitment order provided by each BA i.Each BA shall provide a commitment and dispatch philosophy if a commitment order is not provided. 2.Run power flow analysis a.Confirm that at the post-contingency condition all transmission Elements remain below their emergency ratings,and all buses rated at 69 kV or higher shall have voltages that are between 0.95 and 1.05 per-unit voltage.If post-contingency conditions meet requirements in 2.a,return to step 1. b.Ifthe flow on the transmission exceeds the emergency rating or a bus voltage is greater than 5%off its nominal voltage rating, i.Revert to the case with 5 MW less transfer and record the path's Steady- State Transfer Limit,record the generation commitment and dispatch of the source and sink areas,and save the pre-contingency case. 3.Repeat steps 1 and 2 for each of the following conditions to satisfy R1.2.4 a.Each generation commitment of interest b.'If not already included in 3.a,the source area has its largest committed generation unit out of service for maintenance i.Recommit generation to replace the lost capacity c.Ifnot already included in 3.a,the sink area has its largest committed generation unit out of service for maintenance i.Recommit generation to replace the lost capacity The Emergency Transfer Capability shall be set equal to the Steady-State Transfer Limit identified above.The following process will be used to identify the Steady-State Transfer Capability. 1.Subtract the source areas Contingency Reserve obligation for the largest single contingency outside the source area per AKBAL-002 R3. 2.Subtract Transmission Reliability Margin from result of 1.TRM is set to 5 MW unless specified by RRO. 3.The resulting number is the Steady-State Transfer Capability. Additional sensitivity cases should be created to analyze if the Steady-State Transfer Limit for the path in question (primary)varies due to simultaneous interaction with one or more other paths (secondary).If feasible,the generation commitment and dispatch should be adjusted so that the flow on the primary path is near its Steady-State Transfer Limit and the secondary path is near its Steady-State Transfer Limit. If it is not feasible to create a case with both primary and secondary paths near their Steady-State Transfer Limits,document why it is not feasible. Run the power flow analysis described above to determine if the planning criteria is violated with both primary and secondary paths at their Steady-State Transfer Limits (or reduced limits if Alaska Railbelt Standard AKMOD-028-Total Transfer Capability Page 86 of 168 Effective Date,TBD not feasible).If the cases satisfy the pre-and post-contingency planning criteria,no further analysis is needed because the path flows do not have simultaneous interaction.Neither nomogram nor chart is required.The sensitivity analysis will be performed as described below if the paths do have simultaneous interactions. Path interactions and nomogram/chart data generation 1.Use the case with the primary path at its Steady-State Transfer Limit and the secondary path at its Steady-State Transfer Limit,if feasible. Reduce flow on the secondary path until the case meets the pre-and post-contingency planning criteria. a.Record both primary and secondary path limits. b.Save power flow case Starting with the case used in step I,reduce flow on the primary path until the case meets the pre-and post-contingency planning criteria. a.Record both primary and secondary path limits. b.Save power flow case Create nomogram or chart using data generated in steps 1 through 3. a.An example is shown below with primary and secondary Steady-State Transfer Limits of 75 MW b.The secondary path can be loaded to 50 MW with the primary path at its Steady- State Transfer Limit c.The primary path can be loaded to 60 MW with the secondary path at its Steady- State Transfer Limit Alaska Railbelt Standard AKMOD-028-Total Transfer Capability Page 87 of 168 Effective Date,TBD Example Path Interaction Chart 80. 70-PrimarySteadyStateTransferLimit(MW)AOoi¢)10 20 30 40 50 60 70 80 Secondary Steady State Transfer Limit (MW) -@-=Primary Limit -O-Secondary Limit -@-Interaction Limit --@--Limits Without interaction Dynamic Stability Analysis The initial transient stability simulations should include an exhaustive list of N-1 contingencies. Future studies can use a subset of the most severe contingencies to reduce analysis burden.The analysis should progress in the following order. 1.Start with the power flow cases saved in the power flow analysis study including: a.Cases with primary path at its Steady-State Transfer Capability with secondary paths at nominal flows, b.Cases with largest generator in source and sink areas out of service. c.Sensitivity cases saved as part of the path interaction and nomogram/chart data generation. 2.Simulate all contingencies in the contingency list. 3.Confirm that the case is stable,well-damped,does not suffer uncontrolled separation,and that the voltages recover to near nominal. a.Ifall contingencies meet the requirements in step 3,the Transient Transfer Limit is larger than the Steady-State Transfer Capability and no more work is necessary. b.If one or more contingencies does not meet the requirements in step 3,reduce the transfers in the same manner as was used to increase the transfers in the power flow analysis. Alaska Railbelt Standard AKMOD-028-Total Transfer Capability Page 88 of 168 Effective Date,TBD i.Repeat step 2 until all contingencies result in a stable condition. ii.Record the Stability Limit at which all simulations were stable. iii.Set the Transient Transfer Limit equal to the Stability Limit minus the Transmission Reliability Margin. The TTC will be recorded as follows: 1.For paths that have simultaneous interactions with other paths, a.A nomogram or chart will describe the TTC of both the primary path and the secondary path. b.Set the TTC nomogram/chart equal to the minimum of the Transient Transfer Limit and Steady-State Transfer Capability. c.Set the ETC nomogram/chart equal to the Steady-State Transfer Limits. 2.For paths that do not have simultaneous interactions with other plants, a.The TTC will be the minimum of the Steady-State Transfer Capability and the Transient Transfer Limit. b.Set the ETC equal to the Steady-State Transfer Limit. Study Report Create a TTC study report documenting the assumptions used and steps taken in determining the current value for TTC and ETC for that path.Within one week of finalization,the report should be provided to the Transmission Operator. Alaska Railbelt Standard AKMOD-028-Total Transfer Capability Page 89 of 168 Effective Date,TBD Alaska Railbelt Standard AKMOD-032-1-Data for Power System Modeling and Analysis A.Introduction Title:Data for Power System Modeling and Analysis Number:AKMOD-032-1 Purpose:To establish consistent modeling data requirements and reporting procedures for development of planning horizon cases necessary to support analysis of the reliability of the interconnected transmission system. Applicability: R15.7,Functional Entities: R15.7.1.Balancing Authority R15.7.2.Generator Owner R15.7.3.Load Serving Entity R15.7.4.Planning Coordinator R15.7.5.Resource Planner R15.7.6.Transmission Owner R15.7.7.Transmission Planner R15.7.8.Transmission Service Provider Effective Date: TBD (Standard should be implemented as a test and monitored for a minimum of 12 months to ascertain ability to comply and monitor) B.Requirements R16.The Regional Reliability Council,in conjunction with each areas”Transmission Planner,shall develop steady-state,dynamics,and short circuit modeling data requirements and reporting procedures for the Planning Coordinator's planning area that include: R16.1.The data listed in Attachment 1. R16.2.Specifications of the following items consistent with procedures for building the Interconnection-wide case(s): R16.2.1.Data format; R16.2.2.Level of detail to which equipment shall be modeled; R16.2.3.Case types or scenarios to be modeled;and R16.2.4.A schedule for submission of data at least once every 13 calendar months. Alaska Railbelt Standard AKMOD-032-1-Data for Power System Modeling and Analysis Page 90 of 168 Effective Date,TBD R17. R18. R19. R16.3.Specifications for distribution or posting of the data requirements and reporting procedures so that they are available to those entities responsible for providing the data. Each Balancing Authority,Generator Owner,Load Serving Entity,Resource Planner, Transmission Owner,and Transmission Service Provider shall provide steady-state, dynamics,and short circuit modeling data to any Transmission Planner(s)and Planning Coordinator(s)according to the data requirements and reporting procedures developed by its Planning Coordinator and Transmission Planner in Requirement R1.For data that has not changed since the last submission,a written confirmation that the data has not changed is sufficient. Upon receipt of written notification from the Regional Coordinating Council regarding technical concerns with the data submitted under Requirement R2,including the technical basis or reason for the technical concerns,each notified Balancing Authority, Generator Owner,Load Serving Entity,Resource Planner,Transmission Owner,or Transmission Service Provider shall respond to the Regional Coordinating Council as follows: 18.1.Provide either updated data or an explanation with a technical basis for maintaining the current data; 18.2.Provide the response within 90 calendar days of receipt,unless a longer time period is agreed upon by the notifying the Regional Coordinating Council. Each Planning Coordinator shall make available models for its planning area reflecting data provided to it under Requirement R2 to the Regional Coordinating Council or its designee to support creation of the Interconnection-wide case(s)that includes the Planning Coordinator's planning area. C.Measures M20. M22. The Regional Coordinating Council shall provide evidence that it has jointly developed the required modeling data requirements and reporting procedures specified in Requirement R1. .Each registered entity identified in Requirement R2 shall provide evidence,such as email records or postal receipts showing recipient and date,that it has submitted the required modeling data to the Regional Coordinating Council;or written confirmation that the data has not changed. Each registered entity identified in Requirement R3 that has received written notification from the Regional Coordinating Council regarding technical concerns with the data submitted under Requirement R2 shall provide evidence,such as email records or postal receipts showing recipient and date,that it has provided either updated data or an explanation with a technical basis for maintaining the current data to the Regional Coordinating Council within 90 calendar days of receipt (or within the longer time period agreed upon by the notifying the Regional Coordinating Council). Alaska Railbelt Standard AKMOD-032-1-Data for Power System Modeling and Analysis Effective Date,TBD Page 91 of 168 M23.Each Planning Coordinator shall provide evidence,such as email records or postal receipts showing recipient and date,that it has submitted models for its planning area reflecting data provided to it under Requirement R2 when requested by the Regional Coordinating Council or its designee. D.Compliance R24.Compliance Monitoring Process 24.1. 24.2. 24.3. 24.4. Version History Compliance Enforcement Authority Regional Coordinating Council Data Retention The following data retention periods identify the period of time an entity is required to retain specific evidence to demonstrate compliance.For instances where the evidence retention period specified below is shorter than the time since the last audit,the Compliance Enforcement Authority may ask an entity to provide other evidence to show that it was compliant for the full time period since the last audit. The applicable entity shall keep data or evidence to show compliance with Requirements R1 through R4,and Measures M1 through M4,since the last audit,unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation. If an applicable entity is found non-compliant,it shall keep information related to the non-compliance until mitigation is complete and approved,or for the time specified above,whichever is longer. The Compliance Enforcement Authority shall keep the last audit records and all requested and submitted subsequent audit records. Compliance Monitoring and Assessment Processes: Refer to the NERC Rules of Procedure for a list of compliance monitoring and assessment processes. Additional Compliance Information None Alaska Railbelt Standard AKMOD-032-1-Data for Power System Modeling and Analysis Page 92 of 168 Effective Date,TBD Version Date Action Tracking _0 -Poo NERC Version w.. 1 |8-24-2016 i oo __EPS-Initial Edits Yes _2 [9162016 --_-_-EEPS-Revisions following 8/25/2016Meeting |_-Yes_--3 11-18-2016 _.____EPS -Revisions following 10/20/2016 Meeting ==:___'Yes __4 12-06-2016 -_-_--EPS-Revisions following 12/05/2016 Meeting _|Yes | Final 12-06-2016 Final Version ino Alaska Railbelt Standard AKMOD-032-1-Data for Power System Modeling and Analysis Page 93 of 168 Effective Date,TBD MOD-032-01 -ATTACHMENT 1: Data Reporting Requirements The table,below,indicates the information that is required to effectively model the interconnected transmission system for the Near-Term Transmission Planning Horizon and Long-Term Transmission Planning Horizon.Data must be shareable on an interconnection- wide basis to support use in the Interconnection-wide cases.A Planning Coordinator may specify additional information that includes specific information required for each item in the table below.Each functional entity1 responsible for reporting the respective data in the table is identified by brackets "[functional entity]”adjacent to and following each data item.The data reported shall be as identified by the bus number,name,and/or identifier that is assigned in conjunction with the PC,TO,or TP. steady-state (Items marked with an *indicate data that vary with system operating state or conditions.Those items may have different data provided for different modeling scenarios) dynamics (tf auser-written model(s)is submitted in place of a generic or library model,it must include the characteristics of the model,induding block diagrams,values and names for all model parameters,a list of all state variables,and source code of the model,if available) short circuit 1 Each bus [TO} a.nominal voltage b.area,zone and owner 2 Aggregate Demand?[LSE] a.real and reactive power* b.in-service status* 3 Generating Units'(GO,RP (for future planned resources only)] 'real power capabilities -seasonal (summer valley,summer peak, and winter peak)maximum and minimum values b reactive power capabilities -maximum and minimum values at*real power capabilities in 3aabove = station service auxiliary load for normal plant configuration ¢.(provide data in the same manner as that required for aggregate |Demand under item 2,above)._ ;TOP) _@.machine MVA base . generator step up transformer data (provide same data as that required for transformer under item 6,below} .generator type (hydro,wind,fossil,solar,nuclear,etc) .in-service status*”zo;d regulated bus*and voltage set point*{as typically provided by the 1 Generator (GO,RP (for future planned resources only)} 2 Excitation System [GO,RP(for future planned resources only)} 3 Governor [GO,RP(for future planned resources only)] real power capabilities -seasonal (summer valley,summer *peak,and winter peak)maximum and minimum values Power System Stabilizer {GO,RP(for future planned resources : only)] 5 Demand [LSE] Frequency dependence settings and documentation : "supporting the use of frequency dependent demand _ 7 Photovoltaic systems [GO] | 6 Wind Turbine Data [GO] 7 Photovoltaic systems (GO) Provide for all applicable elements in column "steady-state”[GO,RP,TO] a.Positive Sequence Data b.Negative Sequence Data c.Zero Sequence Data 2 Mutual Line impedance Data [TO] Fault current contribution from non- 3 synchronous(inverter,power electronics,etc} generation sources _ Other information requested by the Planni 4 Coordinator or Transmission Planner neces for modeling Alaska Railbelt Standard AKMOD-032-1-Data for Power System Modeling and Analysis Effective Date,TBD Page 94 of 168 steady-state (Items marked with an *indicate data that vary with system operating state or conditions.Those items may have different data provided for different modeling scenarios) dynamics (if a user-written model(s}is submitted in place of a generic or library model,it must include the characteristics of the model,including block diagrams,values and names for all model parameters,a list of all state variables,and source code of the model,if available) short circuit 4 AC Transmission Line or Circuit [TO]_ a.impedance p:(positi ) b.susceptance (line charging)_.oo. ©.seasonal ratings (summer valley,summer peak,winter peak)* d.in-service status* 5 OC Transmission systems [TO] 6 Transformer (voltage and phase-shifting)[TO] _@ nominal voltagesofwindings b.impedance(s}vee coe ¢.tap ratios (voltage or phase angle}*oe d.minimum and maximum tapp limits e.number of tap positions (for both the ULTC and NLTC) 8 Energy Storage Systems [GO] a.Fi y resp chari istics b.Contingency response characteristics . ¢Ability to simulate all modes of actual ESS operation _ 9 Static Var Systems and FACTS [GO,TO,LSE] 10 DC system models [TO] 11 Unit Protection Settings . a.Voltage Ride Through Settings b.Frequency Ride Through Settings,as determined by PRC-006 12 Special Protection Systems Other information requested by the Planning Coordinatoror_f.regulated bus (for voltage regulating transformers)*-BT Planner y for modeling purp [BA,GO,sot . '" (valley,peak,and winter LSE,TO,TSP]\;peak)rating*_:,i_hb.imservice status*®ow :oe 7 Reactive compensation (shunt capacitors and reactors)[TO]oe i a.admittances (MVars)of each capacitor and reactor step || b.regulated voltage band limits*(if mode of operation not fixed)i _¢mode of operation (fixed,discrete,continuous,etc.).. d.regulated bus®*(if mode of operation not fixed)_5 _@.in-servicestatus®oo.Lod _.ae A 8 Static Var Systems [TO]_.A .:- a.reactive limits ;ji b.voltage set point®_-.:wo _¢.fixed/switched shunt,if applicable _LG _ d.in-service status* ne ee Coe i eee PE _ Other information requested by the Planning Coordinator or : 9 ission Planner ¥for modeling purp .(BA,GO,LSE,i iiTO,TSP} 'cor purp of this ch the fi I entity ces are repr d by abbreviations as follows:Balancing Authority (BA),Owner (GO),Load Serving Entity {LSE},Planning Coordinator (PC),Resource Planner (RP),Transmission Owner (TO),Transmission Planner (TP),and Transmission Service Provider (TSP).. ?For purposes of this item,aggregate Demand is the Demand aggregated at each bus under item 1 that is identified by a Transmission Owner as a load serving bus.A Load Serving Entity is responsible for providing this information,generally through coo!3 including synch 4.and Alaska Railbelt Standard AKMOD-032-1-Data for Power System Modeling and Analysis Effective Date,TBD with theTi ission Owner. ped storage,and energy storage systems. Page 95 of 168 Alaska _Railbelt Standard AKMOD-33-1-Steady-State and Dynamic System Model Validation A.Introduction Title:Steady-State and Dynamic System Model Validation Number:AKMOD-033-1 Purpose:To establish consistent validation requirements to facilitate the collection of accurate data and building of planning models to analyze the reliability of the interconnected transmission system. Applicability: R24.5.Functional Entities: R24.5.1.Planning Coordinator R24.5.2.Reliability Coordinator R24.5.3.Transmission Operator Effective Date: AKMOD-033-1 shall become effective on the first day of the first calendar quarter that is 12 months after the date that the standard is approved by an applicable authority. Background: AKMOD.-033-1 exists in conjunction with AKMOD-032-1,both of which are related to system-level modeling and validation.Reliability Standard AKMOD-033-1 is a new standard,and requires the Regional Coordinating Council to implement a documented process to perform model validation for power flow and dynamics. Alaska Railbelt Standard AKMOD-033-1-Steady-State and Dynamic System Model Validation Page 96 of 168 Effective Date,TBD B.Requirements R1.The Regional Coordinating Council shall implement a documented data validation process that includes the following attributes: 1.1.Comparison of the performance of the existing system in a planning power flow model simulation compared to actual system behavior,represented by a state estimator case or other Real-time data sources,for at least the summer minimum,summer and winter maximum peak conditions,at least once every 24 calendar months; 1.2.Comparison of the performance of the existing system in a planning dynamic model to actual system response,through simulation of a dynamic event,at least once every 24 calendar months (use a dynamic event that occurs within 24 calendar months of the last dynamic event used in comparison,and complete each comparison within 24 calendar months of the dynamic event).If no dynamic event occurs within the 24 calendar months,use the next dynamic event that occurs; 1.2.1.Performance comparison simulations should include a generation trip and a transmission line fault,at a minimum. 1.2.1.1.By specifying these duties of the Regional Coordinating Council,it is the intent of the standard that until such a time that the Railbelt becomes more closely interconnected,that such verifications will be completed using a generation trip and a transmission line fault in each of the three major load/generation areas. 1.2.2.The dynamic event chosen must be able to be simulated with reasonable accuracy.Recordings and accurate description of the sequence of the event (power output of a unit that is tripped,or line from unit /plant,line flow of the line that was tripped,etc)must be available to accurately complete the comparison.Dynamic events that are a result of discreet action (unit breaker,line breaker)should be given priority over other events.Events such as unbalanced faults, unexplained unit /plant output reductions,and other obscure events should not be used for purposes of this comparison. 1.3.|Guidelines the Regional Coordinating Council will use to determine unacceptable differences in performance under Part 1.1 or 1.2,and ata minimum will include the following; 1.3.1.Bus frequency differences should not exceed 0.05 Hz at minimum frequency and 0.2 Hz at maximum frequency 1.3.2.Machine electrical power differences should not exceed 2 MW during the transient and 1 MW after the transient has occurred (5 seconds after event),and 0.5 MW during steady state conditions (power flow). Alaska Railbelt Standard AKMOD-033-1-Steady-State and Dynamic System Model Validation Page 97 of 168 Effective Date,TBD 1.3.3.Tie line flow differences should not exceed 5 MW after the transient event has occurred (5 seconds after event),and 0.5 MW during steady state conditions (power flow). 1.3.4.Voltage differences should not exceed +/-5%after the transient event has occurred (5 seconds after event),and +/-1%during steady state conditions (power flow). 1.4.Guidelines to resolve the unacceptable differences in performance identified under Part 1.3,and at a minimum will include the following; 1.4.1.Identification of equipment in an area for the source of a difference.If a machine,synchronous condenser,or Power Electronic Transmission Asset,response is found to be the source of the difference,the applicable owning body (Generator Owner or Transmission Owner)shall be required to verify the modeling data as required in the applicable modeling standard (MOD 25,MOD 26,or MOD 27).Otherwise facility inspections shall be completed to verify the accuracy of the equipment modeling (conductor or transformer impedances,etc).The validation shall be completed no later than 6 months after notification of the modeling deficiency is made to the applicable Owner or RRO. 1.4.2.Identification of area(s)/equipment where additional recording devices are required to determine source of difference.A plan must be developed to increase visibility /recordings for the area / equipment and be completed 12 months after identification from the comparison is made. Each Reliability Coordinator and Transmission Operator shall provide actual system behavior data (or a written response that it does not have the requested data)to the Regional Coordinating Council performing validation under Requirement R1 within 30 calendar days of a written request,such as,but not limited to,state estimator case or other Real-time data (including disturbance data recordings)necessary for actual system response validation. C.Measures M3. M4. The Regional Coordinating Council shall provide evidence that it has a documented validation process according to Requirement R1 as well as evidence that demonstrates the implementation of the required components of the process.Attachment 1 is provided as an example for the guidelines in Requirement R1I.3. The Regional Coordinating Council shall provide evidence,such as email notices or postal receipts showing recipient and date that it has distributed the requested data or written response that it does not have the data,to any Planning Coordinator performing validation under Requirement R1 within 30 days of a written request in accordance with Requirement R2;or a statement by the Regional Coordinating Council that it has not received notification regarding data necessary for validation by any Planning Coordinator. Alaska Railbelt Standard AKMOD-033-1-Steady-State and Dynamic System Model Validation Page 98 of 168 Effective Date,TBD C.Compliance RS. 6. Compliance Monitoring Process 5.1. 5.2. 5.3. 5.4. Compliance Enforcement Authority Regional Coordinating Council Evidence Retention The following evidence retention periods identify the period of time an entity is required to retain specific evidence to demonstrate compliance.For instances where the evidence retention period specified below is shorter than the time since the last audit,the Compliance Enforcement Authority may ask an entity to provide other evidence to show that it was compliant for the full time period since the last audit. The applicable entity shall keep data or evidence to show compliance with Requirements R1 through R2,and Measures M1 through M2,since the last audit,unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation. If an applicable entity is found non-compliant,it shall keep information related to the non-compliance until mitigation is complete and approved,or for the time specified above,whichever is longer. The Compliance Enforcement Authority shall keep the last audit records and all requested and submitted subsequent audit records. Compliance Monitoring and Assessment Processes: Compliance Audit Self-Certification Spot Checking Compliance Investigation Self-Reporting Complaints Additional Compliance Information None Levels of Non-Compliance 6.1.Levels of Non-Compliance for Requirement R1,Measure M1 6.1.1.Level 1 -The Regional Coordinating Council documented and implemented a process to validate data but did not address one of the four required topics under Requirement R1;or the Regional Coordinating Council did not perform simulation as required by part 1.1 within 24 calendar months but did perform the simulation within 30 calendar months;or the Regional Coordinating Council did not Alaska Railbelt Standard AKMOD-033-1-Steady-State and Dynamic System Model Validation Page 99 of 168 Effective Date,TBD 6.1.2. perform simulation as required by part 1.2 within 24 calendar months (or the next dynamic event in cases where there is more than 24 months between events)but did perform the simulation within 30 calendar months. Level 2 -The Regional Coordinating Council did not have a validation process at all or did not document or implement any of the four required topics under Requirement R1;or The Regional Coordinating Council did not validate its portion of the system in the power flow model as required by part 1.1 within 36 calendar months; or The Regional Coordinating Council did not perform simulation as required by part 1.2 within 36 calendar months (or the next dynamic event in cases where there is more than 24 months between events). 6.2.Levels of Non-Compliance for Requirement R2,Measure M2 6.2.1. 6.2.2. E.Regional Variances None F.Interpretations None F.Associated Documents None Level 1 -The Reliability Coordinator or Transmission Operator did not provide requested actual system behavior data (or a written response that it does not have the requested data)to a requesting Regional Coordinating Council within 30 calendar days of the written request,but did provide the data (or written response that it does not have the requested data)in less than or equal to 45 calendar days. Level 2 -The Reliability Coordinator or Transmission Operator did not provide requested actual system behavior data (or a written response that it does not have the requested data)to a requesting Regional Coordinating Council within 75 calendar days;or The Reliability Coordinator or Transmission Operator provided a written response that it does not have the requested data,but actually had the data. Alaska Railbelt Standard AKMOD-033-1-Steady-State and Dynamic System Model!Validation Effective Date,TBD Page 100 of 168 Guidelines and Technical Basis Requirement R1: The requirement focuses on the results-based outcome of developing a process for and performing a validation,but does not prescribe a specific method or procedure for the validation outside of the attributes specified in the requirement.For further information on suggested validation procedures,see "Procedures for Validation of Powerflow and Dynamics Cases”produced by the NERC Model Working Group. The specific process is left to the judgment of the Planning Coordinator,but the Planning Coordinator is required to develop and include in its process guidelines for evaluating discrepancies between actual system behavior or response and expected system performance for determining whether the discrepancies are unacceptable. For the validation in part 1.1,the state estimator case or other Real-time data should be taken as close to desired seasonal conditions as possible.While the requirement specifies "once every 24 calendar months,”entities are encouraged to perform the comparison on a more frequent basis.Until the model has been sufficiently verified to confirm its accuracy in varying load and generation conditions,each entity is encouraged to confirm the model following each major system disturbance. In performing the comparison required in part 1.1,the Planning Coordinator may consider, among other criteria: 1.System load; 2.Transmission topology and parameters; 3.Voltage at major buses;and 4.Flows on major transmission elements. The validation in part 1.1 would include consideration of the load distribution and load power factors (as applicable)used in the power flow models.The validation may be made using metered load data or state estimator cases.The comparison of system load distribution and load power factors shall be made on the substation level at a minimum but may also be made on a bus by bus basis within each substation,or smaller area basis as deemed appropriate by the Planning Coordinator. The validation required in part 1.2 may include simulations that are to be compared with actual system data and may include comparisons of: e Voltage oscillations at major buses e System frequency (for events with frequency excursions) e Real and reactive power oscillations on generating units and major inter-area ties Determining when a dynamic event might occur may be unpredictable,and because of the analytic complexities involved in simulation,the time parameters in part 1.2 specify that the comparison period of "at least once every 24 calendar months”is intended to both provide for at least 24 months between dynamic events used in the comparisons and that comparisons must be completed within 24 months of the date of the dynamic event used.This clarification Alaska Railbelt Standard AKMOD-033-1-Steady-State and Dynamic System Model Validation Page 101 of 168 Effective Date,TBD ensures that PCs will not face a timing scenario that makes it impossible to comply.If the time referred to the completion time of the comparison,it would be possible for an event to occur in month 23 since the last comparison,leaving only one month to complete the comparison.With the 30 day timeframe in Requirement R2 for TOPs or RCs to provide actual system behavior data (if necessary in the comparison),it would potentially be impossible to complete the comparison within the 24 month timeframe. In contrast,the requirement language clarifies that the time frame between dynamic events used in the comparisons should be within 24 months of each other (or,as specified at the end of part 1.2,in the event more than 24 months passes before the next dynamic event,the comparison should use the next dynamic event that occurs).Each comparison must be completed within 24 months of the dynamic event used.In this manner,the potential problem with a "month 23”dynamic event described above is resolved.For example,if a PC uses for comparison a dynamic event occurring on day 1 of month 1,the PC has 24 calendar months from that dynamic local event's occurrence to complete the comparison.If the next dynamic event the PC chooses for comparison occurs in month 23,the PC has 24 months from that dynamic event's occurrence to complete the comparison. Part 1.3 requires the PC to include guidelines in its documented validation process for determining when discrepancies in the comparison of simulation results with actual system results are unacceptable.The PC may develop the guidelines required by parts 1.3 and 1.4 itself,reference other established guidelines,or both.For the power flow comparison,as an example,this could include a guideline the Planning Coordinator will use that flows on 138 kV lines should be within 10%or 5 MW,whichever is larger.It could be different percentages or MW amounts for different voltage levels.Or,as another example,the guideline for voltage comparisons could be that it must be within 1%.But the guidelines the PC includes within its documented validation process should be meaningful for the Planning Coordinator's system.Guidelines for the dynamic event comparison may be less precise. Regardless,the comparison should indicate that the conclusions drawn from the two results should be consistent.For example,the guideline could state that the simulation result will be plotted on the same graph as the actual system response.Then the two plots could be given a visual inspection to see if they look similar or not.Or a guideline could be defined such that the rise time of the transient response in the simulation should be within 20%of the rise time of the actual system response.As for the power flow guidelines,the dynamic comparison criteria should be meaningful for the Planning Coordinator's system. The guidelines the PC includes in its documented validation process to resolve differences in Part 1.4 could include direct coordination with the data owner,and,if necessary,through the provisions of AKMOD-032-1,Requirement R3 (i.e.,the validation performed under this requirement could identify technical concerns with the data).In other words,while this standard is focused on validation,results of the validation may identify data provided under the modeling data standard that needs to be corrected.If a model with estimated data or a generic model is used for a generator,and the model response does not match the actual response,then the estimated data should be corrected or a more detailed model should be requested from the data provider. If the simulations can be made to match the actual system responses by reasonable changes to the data in the Planning Coordinator's area,then the Planning Coordinator should make Alaska Railbelt Standard AKMOD-033-1-Steady-State and Dynamic System Model Validation Page 102 of 168 Effective Date,TBD those changes in coordination with the data provider.The guidelines the Planning Coordinator included under Part 1.4 could cover these situations. Rationale for R1: Requirement R1 requires the Planning Coordinator to implement a documented data validation process to validate data in the Planning Coordinator's portion of the existing system in the steady-state and dynamic models to compare performance against expected behavior or response.The following items were chosen for the validation requirement: A.Comparison of performance of the existing system in a planning power flow model to actual system behavior;and B.Comparison of the performance of the existing system in a planning dynamics model to actual system response. Implementation of these validations will result in more accurate power flow and dynamic models.This,in turn,should result in better correlation between system flows and voltages seen in power flow studies and the actual values seen by system operators during outage conditions.Similar improvements should be expected for dynamics studies,such that the results will more closely match the actual responses of the power system to disturbances. Validation of model data is a good utility practice,but it does not easily lend itself to Reliability Standards requirement language.Furthermore,it is challenging to determine specifications for thresholds of disturbances that should be validated and how they are determined.Therefore,this requirement focuses on the Planning Coordinator performing validation pursuant to its process,which must include the attributes listed in parts 1.1 through 1.4,without specifying the details of "how”it must validate,which is necessarily dependent upon facts and circumstances.Other validations are best left to guidance rather than standard requirements. Rationale for R2: The Planning Coordinator will need actual system behavior data in order to perform the validations required in Rl.The Reliability Coordinator or Transmission Operator may have this data.Requirement R2 requires the Reliability Coordinator and Transmission Operator to supply actual system data,if it has the data,to any requesting Planning Coordinator for purposes of model validation under Requirement R1. This could also include information the Reliability Coordinator or Transmission Operator has at a field site.For example,if a PMU or DFR is at a generator site and it is recording the disturbance,the Reliability Coordinator or Transmission Operator would typically have that data. Alaska Railbelt Standard AKMOD-033-1-Steady-State and Dynamic System Model Validation .Page 103 of 168 Effective Date,TBD Version History Version Date Action ChangeTracking Dee NERC Version 1 3-21-2016 _._..EPSeditfromNERCstandards =Ve2°19-16-2016)___EPS-Revisions following 8/25/2016 Meeting =| -*Yes_- _3 11-18-2016 -_séEPS -Revisions following 10/20/2016 Meeting ===Yes | Final 12-06-2016 Final Version 'no Alaska Railbelt Standard AKMOD-033-1-Steady-State and Dynamic System Model Validation Page 104 of168 Effective Date,TBD AKMOD-033 -Attachment 1 Example Interconnection Model Validation Process and Guidelines: Alaska's primary concerns include loss of synchronism over the major tie lines,and the activation of UFLS in response to the loss of generation.The guidelines listed below were created for the Alaskan Railbelt.The validation sections below should serve as an example set of guidelines as required in Requirement 1.3. Power Flow Input Data The following items from the recorded snapshot data are transferred directly into the steady-state power flow case (state estimators may be a suitable source for this data): ¢Generators e Real power output e Reactive power output or voltage setting e Control mode (voltage control,power factor control) e Voltage regulation point (local or remote,if on voltage control) e Status e Measured real power at available granularity e Measured reactive power e Transmission Network e Network topology #Device statuses e Transmission lines e Breakers (may result in split buses) e Reactive shunt elements (Capacitor,Reactor) e Reactive series elements (Capacitor,Reactor) =Fixed-tap transformer tap positions *ULTC transformers -Fixed tap position and LTC voltage setting *Phase-shifting transformers -angle position or MW setting e Static VAR systems and fast-switched shunt devices -reactive output or voltage setting e DC lines -active power flow e Other devices present in system model ¢Wide-Area Control e Area interchange totals After data is inserted,a power flow solution is performed.After the initial power flow solution is performed,the following priority list should be used when comparing the power flow solution to the recorded values. Alaska Railbelt Standard AKMOD-033-1-Steady-State and Dynamic System Model Validation Page 105 of 168 Effective Date,TBD Validation 1.Minimize the tie flow error (recorded vs.simulation)between areas with a desired error of 0.5 MW or less. a.The tie flows should take top priority due to the transient stability concerns. b.May need to adjust recorded generation and/or area load. 2.Minimize generation error within +/-0.5 MW. a.Use recorded values to the extent possible.May need adjustment based on tie flows. b.May need to adjust area load so slack generator matches the recorded MW while keeping tie flows close to recorded values. 3.Adjust voltage setpoints to match recorded voltages within +/-1%.Minimize generation error within +/-1.0 MVAR. a.Engineering judgement should be used when balancing the voltage errors and generation reactive power errors. 4.Use recorded load MW,MVAR.. a.To match generation and tie flows the unobservable load should be adjusted b.Ifnecessary,the recorded load may need to be adjusted to match line flows,tie flows,and generation outputs. If using power flow case for transient stability analysis,the relative priority above may change based on the goals of the validation case.The generation output would take highest priority if a specific unit is going to be tripped as part of the transient stability validation.Whereas,the line flow would take priority when a transmission line fault and trip will be simulated as part of the transient stability validation process. Transient Stability Input Data Comparisons between simulation results from the model and measured dynamic data provide an indication of the collective validity of a large set of component dynamics models.The following data must be entered in the transient stability database,at a minimum: e Generator e Status of exciter e Status of PSS e Status of governor (Droop,temperature limits,etc.) e Control parameters (gains,feedback time constants,etc.) e Machine characteristics (inertia,time constants) ¢Load model e Real and reactive power under dynamic conditions ¢Transmission Network model e Reactive shunt dynamics models (automatic shunt switching) e SVC model characteristics e¢Dynamic Load Characteristics Alaska Railbelt Standard AKMOD-033-1-Steady-State and Dynamic System Model Validation Page 106 of 168 Effective Date,TBD pe, e Dynamic load characteristic models have never been utilized with the Railbelt model.In other islanded systems,the dynamic load characteristics can have a noticeable impact on the ability of the model to replicate actual system disturbances.Transient recorders at stations that serve load should be utilized to ascertain the dynamic response of load to changes in voltage and frequency characteristics.Often times,this characteristic will vary depending upon the time of day/season of the event.Estimates of load characteristics at stations with recorders should be used as a proxy for similar loads in the system. Validation Non-3-phase faults are going to be more difficult to validate since industry tools are positive sequence programs. 1.Match interconnection frequency response within 0.05 Hz at minimum frequency and 0.2 Hz at maximum frequency. a.In order to ensure proper margin it is preferable that the simulation response has an interconnection frequency that is slightly lower or equal to the recorded interconnection frequency response for under frequency events.Adjustments to the load characteristics may be made to get the load to match recorded load during the transient event after all other possible adjustments have been exhausted. 2.Match the recorded and simulated generation responses to within 2 MW during the transient and 1 MW after the transient has occurred (5 seconds after event). a.The primary goal of the validating is to match the interconnection frequency.The simulated generation response should match the recordings but preference should be given to the interconnection frequency.Multiple iterations alternating between matching the system load characteristics and generation output may be required to obtain close correlation between the simulation and recorded values. 3.Using engineering judgement,match the significant flows between areas within 5 MW after the transient has occurred (5 seconds after event). a.The stability limits along the tie from Kenai to Anchorage and from Anchorage to Fairbanks are a significant concern and dictate many operational limits.Ensuring simulations match the recorded tie-line flows will improve the confidence in the defined limits. 4.Using engineering judgement,match the recorded and simulated major bus voltages within +/-2%during pre and post-disturbance comparisons. Alaska Railbelt Standard AKMOD-033-1-Steady-State and Dynamic System Model Validation Page 107 of 168 | Effective Date,TBD Alaska Railbelt Standard AKPRC-006 Automatic Underfrequency Load Shedding Introduction 1.Title:Automatic Underfrequency Load Shedding 2.Number:AKPRC-006 3.Purpose: To establish design and documentation requirements for automatic underfrequency load shedding (UFLS)programs to arrest declining frequency,assist recovery of frequency following underfrequency events and provide last resort system preservation measures. 4.Applicability: 4.1.UFLS entities shall mean all entities that are responsible for the ownership, operation,or control of UFLS equipment as required by the UFLS program established by the Regional Coordinating Council.Such entities may include one or more of the following: 4.1.1.Planning Coordinators 4.1.2.Transmission Owners 4.1.3.Distribution Providers 5.Effective Date:TBD (Standard should be implemented as a test and monitored for a minimum of 12 months to ascertain ability to comply and monitor) Requirements The Regional Coordinating Council shall develop and document criteria within the Railbelt system,including consideration of historical events and system studies,to select load levels within the Distribution Provider's Area to form load shedding stages. R6.3.The UFLS program shall be designed for the system to survive the following imbalance scenarios (at a minimum)for all system load conditions. R6.3.1.Loss of generation or transfers as determined by the Maximum N-1 Contingency Criteria. R6.3.2.Loss of generation or transfers as defined in AKBAL-002 as a Reportable Excess Contingency. R6.3.3.Loss of largest plant. R6.4.The UFLS program shall be designed with a provision for a backup block of load (s)with an extended time delay to prevent extended low frequency operation. R6.5.The UFLS program shall be designed such that the loss of a contingency less than 75%of the Maximum N-1 Contingency Criteria should not result in the activation of the UFLS program. Alaska Railbelt Standard AKPRC-006 Automatic Underfrequency Load Shedding Page 108 of 168 Effective Date,TBD ;oe gS R6.6.The UFLS program shall consider severe scenarios of unit commitment and dispatch defined to limit reserve response and location. The Regional Coordinating Council shall design the UFLS with the requirements of the interconnected system and subsequently identify one or more islands to serve as a basis for designing its UFLS program during islanding conditions including: R6.7. R6.8. R6.9. Any portions of the BES designed to detach from the Interconnection (planned islands)as a result of the operation of a relay scheme or Special Protection System,and A single island that includes all portions of the BES in either the Regional Entity area or the Interconnection in which the Planning Coordinator's area resides. The load included in the UFLS for the protection of the interconnected system shall not be included in a SILOS program.Load included in an island's UFLS system designed to protect the area following islanding may be included in a SILOS program. The Regional Coordinating Council shall develop a UFLS program within the Railbelt system,including notification of and a schedule for implementation by UFLS entities within the interconnected system,that meets the following performance characteristics in simulations of underfrequency conditions resulting from an imbalance scenario, where imbalance =[(load -actual generation output)/(load)]. R6.10. R6.11. R6.12. R6.13. R6.14. Alaska Railbelt Standard AKPRC-006 Automatic Underfrequency Load Shedding Page 109 of 168 | Frequency shall remain within the bounds of the Underfrequency Performance Characteristic curve contained within Attachment 1,either for 60 seconds or until a steady-state condition between 59.5 Hz and 60.5 Hz is reached for any contingency less than or equal to the Maximum N-1 Contingency Criteria. Frequency shall remain within the bounds of the Underfrequency Performance Characteristic curve contained within Attachment 1,either for 60 seconds or until a steady-state condition between 59.3 Hz and 60.7 Hz is reached for any - contingency larger than the Maximum N-1 Contingency Criteria. The UFLS program shall be designed such that no UFLS program action results in an interconnected system frequency that exceeds 61.8 Hz for any contingency. R6.12.1.Portions of the BES designed to detach from the Interconnection as a result of the operation of a relay scheme or Special Protection System may exceed these frequency limits but should not exceed 63.0 Hz following a UFLS program activation. Simulated UFLS events shall not result in Volts per Hertz (V/Hz)exceeding the generator trip settings or equipment damage limits if no protection exists. Simulated UFLS events shall not result in an increase in transfers between areas that exceed the transfer limits of the transmission path. Effective Date,TBD The Regional Coordinating Council shall conduct and document a UFLS design assessment within the Railbelt system at least once every five years or upon any significant changes in Distribution Providers'resources or characteristics of the Bulk Electric Transmission System that may impact UFLS performance.The design assessment shall update the UFLS design as necessary to maintain the performance characteristics in Requirement R3 for each island identified in Requirement R2.The simulation shall model éach of the following: R6.15.Underfrequency trip settings of each generating unit /plant with a nameplate capability larger than or equal to 5 MVA directly connected to the BES through a single contingency interconnection that trips within the bounds of the Generator Underfrequency Trip Modeling curve in AKPRC-006 -Attachment 1. R6.16.Overfrequency trip settings of each generating unit /plant greater than 5 MVA (gross nameplate rating)directly connected to the BES througha single contingency interconnection that trips below the Generator Overfrequency Trip Modeling curve in AKPRC-006 -Attachment 1 R6.17.Any system action that impacts Interconnection frequency response including: R6.17.1.Any automatic load restoration that impacts frequency stabilization and operates within the duration of the simulations run for the assessment. R6.17.2.Any operation of a relay scheme or Special Protection System that impacts frequency stabilization and operates within the duration of the simulations run for the assessment. R6.17.3.Operation of plant controls that affect unit response and system frequency. R6.17.4.The best estimate of each Distribution Provider load's response to changes in system frequency or voltage. Each Planning Coordinator,whose area or portions of whose area is part of an island designed to detach from the BES as a result of the operation of a relay scheme or Special Protection System shall coordinate its UFLS program with the Regional Coordinating Council: e Develop a common UFLS program design and schedule for implementation per Requirement R3 among the Planning Coordinators whose areas or portions of whose areas are part of the same identified island,or e Conduct a joint UFLS design assessment per Requirement R4 among the Planning Coordinators whose areas or portions of whose areas are part of the same identified island,or e Conduct an independent UFLS design assessment per Requirement R4 for the identified island,and in the event the UFLS design assessment fails to meet Requirement R3,identify modifications to the UFLS program(s)to meet Requirement R3 and report these modifications as recommendations to the other Alaska Railbelt Standard AKPRC-006 Automatic Underfrequency Load Shedding Page 110 of 168 Effective Date,TBD ; Planning Coordinators whose areas or portions of whose areas are also part of the same identified island. Each Planning Coordinator shall maintain a UFLS database containing data necessary to model its UFLS program for use in event analyses and assessments of the UFLS program at least once each calendar year,with no more than 15 months between maintenance activities. Each Planning Coordinator shall provide its UFLS database containing data necessary to model its UFLS program to other Planning Coordinators within the Interconnection within 30 calendar days of a request. Each UFLS entity shall provide data to its Planning Coordinator(s)according to the format and schedule specified by the Planning Coordinator(s)to support maintenance of each Planning Coordinator's UFLS database. Each UFLS entity shall provide automatic tripping of Load in accordance with the UFLS program design and schedule for application determined by its Planning Coordinator(s) in each Planning Coordinator area in which it owns assets. Each Transmission Owner shall provide automatic switching of its existing capacitor banks, Transmission Lines,and reactors to control over-voltage as a result of underfrequency load shedding if required by the UFLS program and schedule for application determined by the Planning Coordinator(s)in each Planning Coordinator area in which the Transmission Owner owns transmission. The Regional Coordinating Council shall conduct and document an assessment for an event that results in system frequency excursions below the initializing set points of the UFLS program,within two (2)months of event to evaluate: R6.18.The performance of the UFLS equipment, R6.19.The effectiveness of the UFLS program. R6.20.If further analysis is not required,all documentation should be completed within two (2)months from the initial event. The Regional Coordinating Council shall conduct and document a UFLS design assessment as outlined in R4 to evaluate the event and UFLS response,when an UFLS initial event assessment (per R11)shows need for additional analysis,within six (6)months of the event.The analysis shall include,but not be limited to: R6.21.A description of the event including initiating conditions. R6.22.A review of the UFLS set points and tripping times. R6.23.A simulation of the event. R6.24.A summary of the findings. The Regional Coordinating Council shall respond to written comments submitted by UFLS entities and Transmission Owners following a comment period and before finalizing its UFLS program,indicating in the written response to comments whether changes will be made or reasons why changes will not be made to the following: R6.25.UFLS program,including a schedule for implementation Alaska Railbelt Standard AKPRC-006 Automatic Underfrequency Load Shedding Page 111 of 168 | Effective Date,TBD R6.26.UFLS design assessment R6.27.Format and schedule of UFLS data submittal Measures Each Planning Coordinator shall have evidence such as reports,or other documentation of its criteria to select portions of its system that may form load shedding blocks including how system studies and historical events were considered to develop the criteria per Requirement R1. Each Planning Coordinator shall have evidence such as reports,memorandums,e-mails,or other documentation supporting its identification of potential islands to serve as a basis for designing a UFLS program that meet the criteria in Requirement R2. Each Planning Coordinator shall have evidence such as reports,memorandums,e-mails, program plans,or other documentation of its UFLS program,including the notification of the UFLS entities of implementation schedule,that meet the criteria in Requirement R3. Each Planning Coordinator shall have dated evidence such as reports,dynamic simulation models and results,or other dated documentation of its UFLS design assessment that demonstrates it meets Requirement R4. Each Planning Coordinator,whose area or portions of whose area is part of an island identified by it or another Planning Coordinator shall have dated evidence such as joint UFLS program design documents,reports describing a joint UFLS design assessment, letters that include recommendations,or other dated documentation demonstrating that it coordinated its UFLS program design with all other Planning Coordinators whose areas or portions of whose areas are also part of the same identified island per Requirement RS. Each Planning Coordinator shall have dated evidence such as a UFLS database,data requests,data input forms,or other dated documentation to show that it maintained a UFLS database for use in event analyses and assessments of the UFLS program per Requirement R6 at least once each calendar year,with no more than 15 months between maintenance activities. Each Planning Coordinator shall have dated evidence such as letters,memorandums,e-mails or other dated documentation that it provided their UFLS database to other Planning Coordinators within the Interconnection within 30 calendar days of a request per Requirement R7. Each UFLS Entity shall have dated evidence such as responses to data requests,spreadsheets, letters or other dated documentation that it provided data to its Planning Coordinator according to the format and schedule specified by the Planning Coordinator to support maintenance of the UFLS database per Requirement R8. Each UFLS Entity shall have dated evidence such as spreadsheets summarizing feeder load armed with UFLS relays,spreadsheets with UFLS relay settings,or other dated documentation that it provided automatic tripping of load in accordance with the UFLS program design and schedule for application per Requirement R9. Alaska Railbelt Standard AKPRC-006 Automatic Underfrequency Load Shedding Page 112 of 168 Effective Date,TBD oe Each Transmission Owner shall have dated evidence such as relay settings,tripping logic or other dated documentation that it provided automatic switching of its existing capacitor banks,Transmission Lines,and reactors in order to control over-voltage as a result of underfrequency load shedding if required by the UFLS program and schedule for application per Requirement R10. Each Planning Coordinator shall have dated evidence such as reports,data gathered from an historical event,or other dated documentation to show that it conducted an event assessment of the performance of the UFLS equipment and the effectiveness of the UFLS program per Requirement R9. Each Planning Coordinator shall have dated evidence such as reports,data gathered from an historical event,or other dated documentation to show that it conducted a UFLS design assessment per Requirements R12 and R4 if UFLS program deficiencies are identified inR11. Each Planning Coordinator shall have dated evidence of responses,such as e-mails and letters,to written comments submitted by UFLS entities and Transmission Owners within the Interconnection following a comment period and before finalizing its UFLS program per Requirement R13. Compliance 1.Compliance Monitoring Process 1.1.Compliance Monitoring Responsibility Regional Coordinating Council 1.2.Data Retention Each Planning Coordinator and UFLS entity shall keep data or evidence to show compliance as identified below unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation: e Each Planning Coordinator shall retain the current evidence of Requirements R1,R2,R3,R4,R5,R12,and R13,Measures M1,M2,M3, M4,MS,M12,and M13 as well as any evidence necessary to show compliance since the last compliance audit. e Each Planning Coordinator shall retain the current evidence of UFLS database update in accordance with Requirement R6,Measure M6,and evidence of the prior year's UFLS database update. e Each Planning Coordinator shall retain evidence of any UFLS database transmittal to other Planning Coordinators in the Interconnection since the last compliance audit in accordance with Requirement R7,Measure M7. e Each UFLS entity shall retain evidence of UFLS data transmittal to the Planning Coordinator(s)since the last compliance audit in accordance with Requirement R8,Measure M8. Alaska Railbelt Standard AKPRC-006 Automatic Underfrequency Load Shedding Page 113 of 168 Effective Date,TBD e Each UFLS entity shall retain the current evidence of adherence with the UFLS program in accordance with Requirement R9,Measure M9,and evidence of adherence since the last compliance audit. e Transmission Owner shall retain the current evidence of adherence with the UFLS program in accordance with Requirement R10,Measure M10, and evidence of adherence since the last compliance audit. e Each Planning Coordinator shall retain evidence of Requirements R11, and R13,and Measures M11,and M13 for 6 calendar years. If a Planning Coordinator or UFLS entity is found non-compliant,it shall keep information related to the non-compliance until found compliant or for the retention period specified above,whichever is longer. The Compliance Enforcement Authority shall keep the last audit records and all requested and submitted subsequent audit records. 1.3.Compliance Monitoring and Assessment Process e Compliance Audit e =Self-Certification e Spot Checking e Compliance Violation Investigation e Self-Reporting e Complaint 1.4.Additional Compliance Information Not applicable. 2.Levels of Non-Compliance 2.1.Levels of Non-Compliance for Requirement R1,Measure M1 2.1.1.Level 1 -The Regional Coordinating Council developed and documented criteria but failed to include either the consideration of historical events or the consideration of system studies. 2.1.2.Level 2 -The Regional Coordinating Council failed to meet all the requirements of Level 1 for Requirement R1 and Measurement M1. 2.2.Levels of Non-Compliance for Requirement R2,Measure M2 2.2.1.Level 1-NA 2.2.2.Level 2 -The Regional Coordinating Council failed to identify islands to serve as a basis for designing its UFLS program as specified in Requirement R2. 2.3.Levels of Non-Compliance for Requirement R3,Measure M3 Alaska Railbelt Standard AKPRC-006 Automatic Underfrequency Load Shedding Page 114 of 168 Effective Date,TBD 2.3.1.Level 1 -The Regional Coordinating Council developed a UFLS program, including a schedule for implementation within its area where imbalance = (load -actual generation output)/(load),but failed to meet one (1)of the performance characteristic in Requirement Part R3.1 through Part R3.3 in simulations of underfrequency conditions. 2.3.2.Level 2 -The Regional Coordinating Council failed to meet all the requirements of Level 1 for Requirement R3 and Measurement M3. 2.4.Levels of Non-Compliance for Requirement R4,Measure M4 2.4.1.Level 1 -The Regional Coordinating Council conducted and documented a UFLS assessment at least once every five years that determined through dynamic simulation whether the UFLS program design met the performance characteristics in Requirement R3 for each island identified in Requirement R2 but the simulation failed to include one (1)of the items as specified in Requirement Part R4.1 through Part R4.4. 2.4.2.Level 2 -The Regional Coordinating Council failed to meet all the requirements of Level 1 for Requirement R4 and Measurement M4. 2.5.Levels of Non-Compliance for Requirement R5,Measure M5 2.5.1.Level 1 -The Planning Coordinator failed to retain dated evidence ofjoint UFLS program design documents,reports describing a joint UFLS design assessment,letters that include recommendations,or other dated documentation demonstrating that it coordinated its UFLS program design with all other Planning Coordinators whose areas or portions of whose areas are also part of the same identified island. 2.5.2.Level 2 -The Planning Coordinator failed to coordinate its UFLS program design with all other Planning Coordinators whose areas or portions of whose areas are also part of the same identified island. 2.6.Levels of Non-Compliance for Requirement R6,Measure M6 2.6.1.Level 1-N/A 2.6.2.Level 2 -The Planning Coordinator failed to perform maintenance on the UFLS database within 15 months of previous maintenance activity. 2.7.Levels of Non-Compliance for Requirement R7,Measure M7 2.7.1.Level 1 -The Planning Coordinator provided data more than 5 calendar days but less than or equal to 10 calendar days following the schedule specified by Requirement R7 to support maintenance of the UFLS database. 2.7.2.Level 2 -The Planning Coordinator failed to meet all the requirements of Level 1 for Requirement R7 and Measurement M7. 2.8.Levels of Non-Compliance for Requirement R8,Measure M8 2.8.1.Level 1 -The UFLS entity provided data more than 5 calendar days but less than or equal to 10 calendar days following the schedule specified by Requirement R8 to support maintenance of the UFLS database. Alaska Railbelt Standard AKPRC-006 Automatic Underfrequency Load Shedding Page 115 of 168 Effective Date,TBD 2.8.2.Level 2 -The UFLS entity failed to meet all the requirements of Level 1 for Requirement R8 and Measurement M8. 2.9.Levels of Non-Compliance for Requirement R9,Measure M9 2.9.1.Level 1 -The UFLS entity provided less than 100%but more than (and including)90%of automatic tripping of Load in accordance with the UFLS program design and schedule for application determined by the Requirement RI. 2.9.2.Level 2 -The UFLS entity failed to meet all the requirements of Level 1 for Requirement R9 and Measurement M9. 2.10.Levels of Non-Compliance for Requirement R10,Measure M10 2.10.1.Level 1 -The Transmission Owner provided less than 100%but more than (and including)90%automatic switching of its existing capacitor banks, Transmission Lines,and reactors to control over-voltage if required by the UFLS program and schedule for application determined by Requirement R10. 2.10.2.Level 2 -The Transmission Owner failed to meet all the requirements of Level 1 for Requirement R10 and Measurement M10. 2.11.Levels of Non-Compliance for Requirement R11,Measure M11 2.11.1.Level 1 -The Planning Coordinator,in which UFLS program deficiencies were identified per Requirement R9,conducted and documented a UFLS design assessment to consider the identified deficiencies greater than six months but less than or equal to 7 months of event actuation. 2.11.2.Level 2 -The Planning Coordinator failed to meet all the requirements of Level 1 for Requirement R11 and Measurement M11. 2.12.Levels of Non-Compliance for Requirement R12,Measure M12 2.12.1.Level 1 -The Planning Coordinator,in whose area an event results in a system frequency excursion below the initializing set points of the UFLS program,conducted an assessment of the UFLS event more than one (1) month but less than two (2)months after the initiating event. 2.12.2.Level 2 -The Planning Coordinator failed to meet all the requirements of Level 1 for Requirement R12 and Measurement M12. 2.13.Levels of Non-Compliance for Requirement R13,Measure M13 2.13.1.Level 1 -N/A 2.13.2.Level 2 -The Planning Coordinator failed to retain dated evidence of responses submitted by UFLS entities and Transmission Owners within the Interconnection. Regional Differences None identified. Alaska Railbelt Standard AKPRC-006 Automatic Underfrequency Load Shedding Page 116 of 168 Effective Date,TBD Version History Version Date Action Change Trackin ro)__2-12-2016 NOUIEWNPR{'|iensoenDSE|12-06-2016 Taneezes 7792-24-2015 3B.i 2016e226 292016 EPS- EPS- 44-18-2018 _..__.EPS:Revision Edits ___EPS-RevisionEdits Revision Following 1/19 Meeting = Revision Following 1/28 Meeting _Approved-{MC | _EPS-Initial Edits ___Final IMC Revision__7 _€PS-InclusionofRCC beeen Final _Yes -; Nes Yes Nes. Nes _No ae - Yes No Alaska Railbelt Standard AKPRC-006 Automatic Underfrequency Load Shedding Effective Date,TBD Page 117 of 168 AKPRC-006 -Attachment 1 Underfrequency Load Shedding Program Design Performance and Modeling Curves 65 we es -|..|j ne on " 64 !it ,:: |; :}-{. ++val i ae '3 63 Overfrequency Trip Settings Must |v4 -:--:: Be ModeledforGeneratorsThat ||i 1 Trip Below the Generator 4 ie :62 }-- - 1 OverfrequencyTrip Modeling Curve !--aaa ee re ee !i|pt T >i i=in:E 60 Simulated Frequency Must Remain,Overfrequency Modeling S Between the Overfrequencyand |==Over frequency Performance e Underfrequency Performance |===Underfrequency Performance"Characteristic Curves |wan Underfrequency Modeling . po {i i i Py ad ||;;baddies | |}|iti i |;:: j i :on ee one oe ee [ee ee a L ate ;Underfrequency Trip Settings Must Be Modeled :i : for GeneratorsThat Trip Above the Generator :-iUnderfreqTripModelingCurve:worn Ld.aoyeeealeonaseae_aes P|. oe oe oar :;|||Ti ||Pdi |55 rl 4 iit i i,i . 0.01 0.10 1.00 10.00 Time (seconds) 100.00 : Generator Overfrequency Trip Modeling |Generator Overfrequency Performance Characteristic t<2s t22s t<4s 60s>t24s5 t260s f=64Hz|f=-0.686*log(t)+62.41 Hz |f=61.8 Hz |f=-0.686*log(t)+62.21 Hz |f =60.7 Hz Generator Underfrequency Trip Modeling{Generator Underfrequency Performance Characteristic t<2s te2s t<2s 60s>t22s t260s f=56Hz}f=0.575*log(t)+57.63 Hz |f=57.5 Hz!f=0.915*log(t)+57.23 Hz |f=59.3 Hz Alaska Railbelt Standard AKPRC-006 Page 118 of 168 Alaska Railbelt Standard AKRES-001-1 -Reserve Obligation and Allocation A.Introduction 1.Title:Reserve Obligation and Allocation 2.Number:AKRES-001-1 3.Purpose: This standard describes Reserve Obligations for all Obligated Entities interconnected to the Railbelt Grid. 4.Applicability: 4.1.Balancing Authorities 4.2.Load Serving Entities 4.3.Generation Owners 5.Effective Date:12 months from package adoption B.Requirements R1.Reserve Capacity Obligation Requirement R1.1._Each Load Serving Entity (LSE)is expected to have and maintain responsibility to provide capacity for its own firm load.As part of such responsibility,the LSE 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'Reserve Capacity Obligation,as set forth in Subsection R1.2. R1.2.The Reserve Capacity Obligation of a Load Serving Entity,for any year,shall be equal to thirty (30)percent of the Annual System Demand (described in R1.4)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 RRO. R1.3.The RRO may determine the annual Accredited Capacity for each Load Serving Entity. R1.4.Reserve Capacity Obligation shall be determined by the one-hour average of peak electrical demand of the LSE as determined for each the average of the previous three calendar years of load data of the LSE.The LSE may petition the RRO to use a different value if their studies indicate a diffent value is warranted than that calculated as described above. R2.Responsibility for Operating Reserve R2.1.Each Load Serving Entity and/or Generation Owner shall provide,or contract for,Regulating Reserve,Spinning Reserve and Non-Spinning Reserve as required by Section R3 of this Standard equal to or greater than the Operating Reserve Obligation of the entity.As soon as practicable,but not to exceed four Alaska Railbelt Standard AKRES-001-1-Reserve Obligation and Allocation Page 119 of 168 hours,after the occurrence of an incident which uses Operating Reserves,each entity shall restore its Operating Reserve Obligation. R2.2.The System Reserve Basis (SRB)is equal to the declared Largest Single Generating Contingency of the system or other such value as determined by engineering studies and approved by the RRO.The SRB is determined on an hourly basis and may include critical infrastructure whose loss would deprive the majority of the system of multiple generating units as defined in the Reserves Policy. 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 Grid. R3.2.The Spinning Reserve portion of the Total Operating Reserve Obigation shall not be less than an amount equivalent to 100 percent of the System Reserve Basis. R3.2 the regulation amount of the Operating Reserve Obligation must be an amount of reserve responsive to Automatic Generation Control,which is sufficient to provide normal regulating margin. R3.3 The balance of the Total Operating Reserve Obligation shall be maintained with Non Spinning Reserve. R4.Generating Unit Capability Declared generating unit capability for operating reserve shall be determined by the following criteria: R4.1.It shall not be less than the load and reserves on the machine at any particular time nor greater than R4.2 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 through action of automatic governor controls.Alternatively,if the unit is not capable of continuously supplying for a two-hour period,it must be supplemented by other sources of reserves when it runs out.For example,a Battery Energy Storage System that is supplemented by a load shedding scheme. RS.Operating Reserve R5.1.An Obligated Entities'Spinning Reserve shall be calculated at any given instant as the difference between the sum of the net Declared 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 Alaska Railbelt Standard AKRES-001-1-Reserve Obligation and Allocation -Page 120 of 168 RS.2. R5.3. RS.4. RS5.5. R5.6. RS5.7. or tie line restrictions)as accepted by the RRO.See the Reserve Policy for spin performance criteria. An Obligated Entities'Spinning Reserve may be satisfied by an automatically controlled load shedding program (SILOS -Shed In Lieu of Spin).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. The load included in the Under Frequency Load Shed system (UFLS)for the protection of the interconnected system shall not be included in a SILOS program.Load included in an island's UFLS system designed to protect the area following islanding may be included in a SILOS program. The RRO may establish procedures to assure that the Operating Reserve of an entity is available on the Railbelt System at all times. 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 the Reserve Policy. Subject to R5.4 above,an entity may arrange for one or more other entities to supply part of,or its entire,Operating Reserve requirement. In an Emergency,any Generator Owner,upon request by its Balancing Authority shall supply such Balance Authority part or all of its Non Spinning Reserve up to the full amount of its available total Operating Reserve Obligation as indicated in R3. In an Emergency,any Generator Owner shall automatically supply to such Balancing Authority part or all of its Spinning Reserve obligation.An Obligated Entity experiencing an Emergency is not required to maintain its Operating Reserve Obligation.There shall be no obligation of an Obligated 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 shall provide,or contract for, Regulating Reserve 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 Alaska Railbelt Standard AKRES-001-1-Reserve Obligation and Allocation Page 121 of 168 commitment planning process,and as such the Balancing Authority may then utilize their reserve as required during the course of the day.If a Balancing Authority 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.On an annual basis,after the year end CPS statistics are compiled,the RRO shall modify each Balancing Authorities'Regulating Reserve by increasing/decreasing its current Regulating Reserve by multiplying by 5 the % deviation in its CPS1.The Regulating Reserve obligations so calculated will be rounded up to the nearest integer MW.For example,if an Obligated Entity's CPS1 reaches 5%deviation (level 1 violation),the Obligated Entity will be required to increase its Regulating Reserve obligation by 25%. R6.3.The RRO reserves the right to increase/decrease a Balancing Authorities' Regulating Reserve or require other measures at any time due to changes in the system or repeat infractions. R7.Spinning Reserve Components R7.1.The components determining the makeup of the spin obligation as well as the allocation is defined in the Reserve Policy. R7.2..The Spinning Reserve Obligation (SRO)shall be converted to energy and may be called upon for up to an hour when the system is experiencing a generating deficiency. C.Measures M1.Each Obligated Entity and Balancing Authority shall maintain: MI1.1.Records of their available Accredited Capacity at any point in time.These records will be updated as new Generating Assets are added and other Generating Assets are retired.These records will be available by for review by the Balancing Authority or Compliance Monitor with I business week written notice. M1.2.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. Alaska Railbelt Standard AKRES-001-1-Reserve Obligation and Allocation .Page 122 of 168 M1.3.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. M1.4. D.Compliance Monitoring 1. 2. Balancing Authorities Railbelt Regional Reliability Organization E.Non-Compliance Level 1. Version History Version Date Action Change Tracking 0 June 7,2013 Original New 1 May 2,2016 Per the IMC/RRO re-alignment Change 2 October 20,2016 Put allocation in Reserve Policy Move 3 April 24,2017 IOC Edits to Standard On Alaska Railbelt Standard AKRES-001-1-Reserve Obligation and Allocation Page 123 of 168 Alaska Railbelt Standard AKTPL-001-1 -System Performance Under Normal Conditions A.Introduction 1.Title:©System Performance Under Normal (No Contingency)Conditions (Category A) Number:AKTPL-001-1 3.Purpose: System simulations and associated assessments are needed periodically to ensure that reliable systems are developed that meet specified performance requirements with sufficient lead time,and continue to be modified or upgraded as necessary to meet present and future system needs. 4.Applicability: 4.1.Planning Authority 4,2.Transmission Planner 5.Effective Date:1 month from package adoption B.Requirements Rl.The Planning Authority and Transmission Planner shall each demonstrate through a valid assessment that its portion of the interconnected transmission system is planned such that,with all transmission facilities in service and with normal (pre-contingency) operating procedures in effect,the System can be operated to supply projected customer demands and projected Firm (non-recallable reserved)Transmission Services at all Demand levels over the range of forecast system demands,under the conditions defined in Category A of AKTPL-001 Table 1.To be considered valid,the Planning Authority and Transmission Planner assessments shall: R1.1.Be made when a triggering event such as a major modification or new;large load,transmission line,generating station or other need provided that the RRO requests it to be done. R1.2.._Be conducted for near-term (years one through five)and longer-term (years six through ten)planning horizons. R1.3.Be supported by a current or past study and/or system simulation testing that addresses each of the following categories,showing system performance following Category A of AKTPL-001 Table 1 (no contingencies).The specific elements selected (from each of the following categories)shall be acceptable to the associated Regional Reliability Organization(s). R.1.3.1.Cover critical system conditions and study years as deemed appropriate by the entity performing the study. R.1.3.2.Be conducted annually unless changes to system conditions do not warrant such analyses. Alaska Railbelt Standard AKTPL-001-1 -System Performance Under Normal Conditions Page 124 of 168 R.1.3.3. R.1.3.4, R.1.3.5. R.1.3.6. R.1.3.7. R.1.3.8. R.1.3.9. Be conducted beyond the five-year horizon only as needed to address identified marginal conditions that may have longer lead-time solutions. Have established normal (pre-contingency)operating procedures in place. Have all projected firm transfers modeled. Be performed for selected demand levels over the range of forecast system demands. Demonstrate that system performance meets AKTPL-001 Table 1 for Category A (no contingencies). Include existing and planned facilities. Include Reactive Power resources to ensure that adequate reactive resources are available to meet system performance. R1.4.Address any planned upgrades needed to meet the performance requirements of Category A. R2.When system simulations indicate an inability of the systems to respond as prescribed in Reliability Standard AKTPL-001-1;R1,the Planning Authority and Transmission Planner shall each: R2.1.Provide a written summary of its plans to achieve the required system performance as described above throughout the planning horizon. R2.1.1. R2.1.2. R2.1.3. Including a schedule for implementation. Including a discussion of expected required in-service dates of facilities. Consider lead times necessary to implement plans. Review,in subsequent assessments,(where sufficient lead time exists),the continuing need for identified system facilities.Detailed implementation plans are not needed. R3.The Planning Authority and Transmission Planner shall each document the results of these reliability assessments and corrective plans and shall provide these to its respective Regional Reliability Organization(s)if requested. C.Measures M1. M2. D.Compliance 1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective plans as specified in Reliability Standard AKTPL-001-1;R2.1 and AKTPL- 001-1;R2.3. The Planning Authority and Transmission Planner shall have evidence it reported documentation of results of its reliability assessments and corrective plans per Reliability Standard AKTPL-001-1;R2.2 and R3 if the plans were requested. Compliance Monitoring Process 1.1.Compliance Monitoring Responsibility Alaska Railbelt Standard AKTPL-001-1 -System Performance Under Normal Conditions Page 125 of 168 1.2. 1.3. 1.4. Compliance Monitor:Regional Reliability Organization. Each Compliance Monitor shall report compliance and violations to the IMC. Compliance Monitoring Period and Reset Timeframe Every two years. Data Retention None specified. Additional Compliance Information 2.Levels of Non-Compliance 2.1. 2.2. 2.3. 2.4. Level 1:Not applicable. Level 2:A valid assessment and corrective plan for the longer-term planning horizon is not available. Level 3:Not applicable. Level 4:A valid assessment and corrective plan for the near-term planning horizon is not available. E.Regional Differences None identified. Version History Version Date Action Change Tracking 0 June 7,2013 Original New l May 2,2016 Triggers Modify Alaska Railbelt Standard AKTPL-001-1 -System Performance Under Normal Conditions Page 126 of 168 AKTPL-001 Table 1.Transmission System Standards -Normal and Emergency Conditions Contingencies System Limits or ImpactsCategorygyP System Stable and both Thermal and |Loss of Demand tee ys .Voltage or CascadingInitiatingEvenndContingenc:.eps ::ating Event(s)and gency Limits within Curtailed Firm OutagesElement(s).Applicable Transfers Rating ? A All Facilities in Service Yes No No No Contingencies Single Line Ground (SLG)or 3-Phase (30)Fault, B with Normal Clearing:Yes No?No Event resulting in 1.Generator Yes No>No the loss ofa single 2.Transmission Circuit Yes No?No element.3.Transformer Yes No?No Loss of an Element without a Fault Single Pole Block,Normal Clearing®:b 4.Single Pole (dc)Line Yes No No .+€. c ste Fat eh Normal Clearing”:Yes Planned/No Event(s)resulting in .Controlled* the loss of two or :Yes Planned/No more (multiple)2.Breaker (failure or internal Fault)Controlled? elements.SLG or 3@ Fault,with Normal Clearing',Manual System Adjustments,followed by another SLG or 3@ Fault,with Normal Clearing”:Yes Planned/No 3.Category B (B1,B2,B3,or B4)Controlled* contingency,manual system adjustments, followed by another Category B (B1,B2, B3.or B4)contingency Bipolar Block,with Normal Clearing®:Planned/4.Bipolar (dc)Line Fault (non 3),with Yes Controlled®No Normal Clearing': 5.Any two circuits of a multiple circuit Yes Planned/No towerline'Controlled* SLG Fault,with Delayed Clearing®(stuck breaker or protection system failure):Yes Planned/No6.Generator 5Controlled' Yes Planned/No7.Transformer Controlled' _oo,Yes Planned/No8.Transmission Circuit Controlled p Yes Planned/No9.Bus Section Controlled® Alaska Railbelt Standard AKTPL-001-1 -System Performance Under Normal Conditions Page 127 of 168 D q 3 Fault,with Delayed Clearing e (stuck breaker or protection system conseaueneee andExtremeeventresultingin]failure):®May involve substantial loss oftwoormore(multiple)1.Generator 3.Transformer a .;customer Demand andelements.removed or 2.Transmission Circuit 4.Bus Section -: ..generation in a widespreadCascadingoutofservice. j ee area or areas. 3 Fault,with Normal Clearing”:®Portions or all of the 5.Breaker (failure or internal Fault)interconnected systems may or may not achieve a new, 6.Loss of towerline with three or more circuits stable operating point. sg..«Evaluation of these events may7.All transmission lines on a common right-of way require joint studies with 8.Loss of a substation (one voltage level plus transformers)neighboring systems. 9.Loss of a switching station (one voltage level plus transformers) 10.Loss of all generating units at a station 11.Loss of a large Load or major Load center 12.Failure of a fully redundant Special Protection System (or remedial action scheme)to operate when required 13.Operation,partial operation,or misoperation of a fully redundant Special Protection System (or Remedial Action Scheme)in response to an event or abnormal system condition for which it was not intended to operate 14.Impact of severe power swings or oscillations from Disturbances in another Regional Reliability Organization. a)Applicable Rating refers to the applicable Normal and Emergency facility thermal rating or system voltage limit as determined and consistently applied by the system or facility owner.Applicable Ratings may include Emergency Ratings applicable for short durations as required to permit operating steps necessary to maintain system control. b)Planned or controlled interruption of electric supply to radial customers or some local System customers,connected to or supplied by the Faulted element or by the affected area,may occur in certain areas without impacting the overall reliability of the interconnected transmission systems.To prepare for the next contingency,system adjustments are permitted,including curtailments of contracted Firm (non-recallable reserved)electric power Transfers. c)Depending on system design and expected system impacts,the controlled interruption of electric supply to customers (load shedding),the planned removal from service of certain generators,and/or the curtailment of contracted Firm (non- recallable reserved)electric power Transfers may be necessary to maintain the overall reliability of the interconnected transmission systems. d)A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission planning entity(ies)will be selected for evaluation.It is not expected that all possible facility outages under each listed contingency of Category D will be evaluated. e)Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected with proper functioning of the installed protection systems.Delayed clearing of a Fault is due to failure of any protection system component such as a relay,circuit breaker,or current transformer,and not because of an intentional design delay. f)System assessments may exclude these events where multiple circuit towers are used over short distances (e.g.,station entrance,river crossings)in accordance with Regional exemption criteria. Alaska Railbelt Standard AKTPL-001-1 -System Performance Under Normal Conditions Page 128 of 168 Alaska Railbelt Standard AKTPL-002-1 -System Performance Following Loss of a Single BES Element and Likely Subsequent Contingencies A.Introduction 1.Title:System Performance Following Loss of a Single Bulk Electric System Element (Category B)and Likely Subsequent Contingencies Number:AKTPL-002-1 3.Purpose: Given the limited robustness of the Railbelt Grid and the relatively lean nature of transmission investment in the Railbelt Grid,system simulations and associated assessments are needed periodically to ensure that reliable systems are developed that meet specified performance requirements with sufficient lead time,and continue to be modified or upgraded as necessary to meet present and future system needs. In instances where capital construction costs are beyond the current means of the Railbelt Interconnection,challenges to reliability must be well understood and to the degree practical mitigation strategies must be developed to maximize system performance and reliability within the range of existing assets or within the range of assets within the near terms means of the Railbelt Interconnection. Further,system operators must be made aware of potential pitfalls in operating scenarios which can lead to significant disruptions in electric service. 4.Applicability: 4.1.Planning Authority 4.2.Transmission Planner 4.3.Balancing Authorities 4.4,System Operators 5.Effective Date:1 month from package adoption B.Requirements R1.=The Planning Authority and Transmission Planner shall each demonstrate through a valid assessment that its portion of the interconnected transmission system is planned such that the System can be operated to supply projected customer demands and projected Firm (non-recallable reserved)Transmission Services,at all demand levels over the range of forecast system demands,under the contingency conditions as defined in Category B of AKTPL-001 Table 1.The loss of no single element of the Bulk Electric System (BES)should result in the loss of firm load or firm transfers. To be valid,the Planning Authority and Transmission Planner assessments shall: R1I.1.Be made whena triggering event such as a major modification or new;large load,transmission line,generating station or other need provided that the RRO requests it to be done. R1.2.Be conducted for near-term (years one through five)and longer-term (years six through ten)planning horizons. Alaska Railbelt Standard AKTPL-002-1 -System Performance Following Loss of a Single BES Element and Likely Subsequent Contingencies Page 129 of 168 R13. R1.4. R1.5. R1.6. R1.7. R1.8. R1.9. R1.10. R1.11. R1.12. R1.13. R1.14. R1.15. R1.16. R1.17. R1.18. Be supported by a current or past study and/or system simulation testing that addresses each of the following categories,showing system performance following Category B of AKTPL-001 Table 1 (single contingencies).The specific elements selected (from each of the following categories)for inclusion in these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s). Be performed and evaluated only for those Category B contingencies that would produce the more severe System results or impacts.The rationale for the contingencies selected for evaluation shall be available as supporting information.An explanation of why the remaining simulations would produce less severe system results shall be available as supporting information. Cover critical system conditions and study years as deemed appropriate by the responsible entity. Be conducted biannually unless changes to system conditions do not warrant such analyses. Be conducted beyond the five-year horizon only as needed to address identified marginal conditions that may have longer lead-time solutions. Have all projected firm transfers modeled. Be performed and evaluated for selected demand levels over the range of forecast system Demands. Demonstrate that system performance meets Category B contingencies. Include existing and planned facilities. Include Reactive Power resources to ensure that adequate reactive resources are available to meet system performance. Include the effects of existing and planned protection systems,including any backup or redundant systems. Include the effects of existing and planned control devices. Include the planned (including maintenance)outage of any bulk electric equipment (including protection systems or their components)at those demand levels for which planned (including maintenance)outages are performed. For the near-term (years one through five)under the contingencies conditions above,shall define the thermal and stability limit of each transmission line within each Balancing Authority and each Balancing Authority interconnection. Address any planned upgrades needed to meet the performance requirements of Category B of AKTPL-001 Table 1. Consider all contingencies applicable to Category B. Alaska Railbelt Standard AKTPL-002-1 -System Performance Following Loss ofa Single BES Element and LikelySubsequentContingencies Page 130 of 168 R2.When System simulations indicate an inability of the systems to respond as prescribed in Reliability Standard AKTPL-002-1;R1,the Planning Authority and Transmission Planner shall each: R2.1.Provide a written summary of its plans to achieve the required system performance as described above throughout the planning horizon and provide a written summary of the particular scenario with recommended operating procedures to avoid event triggers: R2.1.1 Including a schedule for implementation. R2.1.2 Including a discussion of expected required in-service dates of facilities. R2.1.3 Consider lead times necessary to implement plans. R2.2.Review,in subsequent annual assessments,(where sufficient lead time exists), the continuing need for identified system facilities.Detailed implementation plans are not needed. R3.The Planning Authority and Transmission Planner shall each document the results of its reliability assessments and corrective plans and shall bi-annually provide the results to its respective Regional Reliability Organization(s),as required by the Regional Reliability Organization., R4.Bi-annually the relevant scenarios will be reviewed with Balancing Authorities and System Operators to alert them to potential pitfalls in daily operating plans and to assist in development of system restoration procedures.Documentation regarding which scenarios are considered relevant and which are not considered relevant will be kept by the Planning Authority and Transmission Planner. C.Measures M1.The Planning Authority and Transmission Planner shall have a valid assessment and corrective plans as specified in Reliability Standard AKTPL-002-1;R1 and AKTPL- 002-1;R2. M2.The Planning Authority and Transmission Planner shall have evidence it reported documentation of results of its reliability assessments and corrective plans per Reliability Standard AKTPL-002-1;R3 and R4 M3.The Balancing Authority and System Operator shall have records of the implementation of risk mitigation strategies and systems. D.Compliance 1.Compliance Monitoring Process 1.1.Compliance Monitoring Responsibility Compliance Monitor Each Compliance Monitor shall report compliance and violations to the RRO. 1.2.Compliance Monitoring Period and Reset Timeframe Annually. Alaska Railbelt Standard AKTPL-002-1 -System Performance Following Loss of a Single BES Element and Likely Subsequent Contingencies Page 131 of 168 1.3.Data Retention None specified. 1.4.Additional Compliance Information 2.Levels of Non-Compliance None. 2.1.Level 1:Not applicable. 2.2.Level 2:A valid assessment and corrective plan for the longer-term planning horizon is not available. 2.3.Level3:Not applicable. 2.4.Level 4:A valid assessment and corrective plan for the near-term planning horizon is not available. E.Regional Differences 1.None identified. Version History Version Date Action Change Tracking 0 June 7,2013 Original New ]May 2,2016 Trigger,and R1.5 stop at Cat B Modify Alaska Railbelt Standard AKTPL-002-1 -System Performance Following Loss of a Single BES Element and Likely Subsequent Contingencies Page 132 of 168 Alaska Railbelt Standard AKTPL-003-1 -System Performance Following Loss of Two or More BES Elements A.Introduction 1.Title:System Performance Following Loss of Two or More Bulk Electric System Elements (Category C&D) Number:AKTPL-003-1 Purpose: Given the limited robustness of the Railbelt Grid and the relatively lean nature of transmission investment in the Railbelt Grid,system simulations and associated assessments are needed periodically to ensure that reliable systems are developed that meet specified performance requirements with sufficient lead time,and continue to be modified or upgraded as necessary to meet present and future system needs. In instances where capital construction costs are beyond the current means of the Railbelt Interconnection,challenges to reliability must be well understood and to the degree practical mitigation strategies must be developed to maximize system performance and reliability within the range of existing assets or within the range of assets within the near terms means of the Railbelt Interconnection. Further,system operators must be apprised of the existing weaknesses in the system,scenarios which can initiate large scale loss of load and possible cascading outages.Finally,operations mitigation plans and systems must be developed and put into place to minimize risk and maximize reliability until assets can be constructed to relieve system weaknesses. 4.Applicability: 4.1.Planning Authority 4.2.Transmission Planner 4.3.Balancing Authority 4.4.System operator 5.Effective Date:2 months from package adoption B.Requirements R3.The Planning Authority and Transmission Planner shall each demonstrate through a valid assessment which portions of the interconnected transmission systems can be operated to supply which portions of projected customer demands and projected Firm (non-recallable reserved)Transmission Services,at all demand Levels over the range of forecast system demands,under the contingency conditions as defined in Category C and D of AKTPL-003 Table 1 (attached).The controlled interruption of customer Demand,the planned removal of generators,or the Curtailment of firm (non-recallable reserved)power transfers may be necessary to meet this standard.To be valid,the Planning Authority and Transmission Planner assessments shall: R1.1.Shall be made as required by the RRO. Alaska Railbelt Standard AKTPL-003-1 -System Performance Following Loss of Two or More BES Elements Page 133 of 168 R1.2..Be conducted for near-term (years one through five)and longer-term (years six through ten)planning horizons. R1.3.Be supported by a current or past study and/or system simulation testing that addresses each of the following categories,showing system performance following Category C and D of AKTPL-003 Table 1 (multiple contingencies). The specific elements selected (from each of the following categories)for inclusion in these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s). R1.3.1..Be performed and evaluated only for those Category C &D contingencies that would produce the more severe system results or "impacts.The rationale for the contingencies selected for evaluation shall be available as supporting information.An explanation of why the remaining simulations would produce less severe system results shall be available as supporting information. R1.3.2.Cover critical system conditions and study years as deemed appropriate by the responsible entity. R1.3.3..Be conducted bi-annually unless changes to system conditions do not warrant such analyses. R1.3.4._Be conducted beyond the five-year horizon only as needed to address identified marginal conditions that may have longer lead- time solutions. R1.3.5.Have all projected firm transfers modeled. R1.3.6.Be performed and evaluated for selected demand levels over the range of forecast system demands. R1.3.7.Include existing and planned facilities. R1.3.8.Include Reactive Power resources to ensure that adequate reactive resources are available to meet System performance. R1.3.9.Include the effects of existing and planned protection systems, including any backup or redundant systems. R1.3.10.Include the effects of existing and planned control devices. R1.3.11.Include the planned (including maintenance)outage of any bulk electric equipment (including protection systems or their components)at those Demand levels for which planned (including maintenance)outages are performed. R1.4._Address any planned upgrades needed to meet the performance requirements of Category C and D. R1.5.Consider all contingencies applicable to Category C and D. R2.When system simulations indicate an inability of the systems to respond as prescribed in Reliability Standard AKTPL-003-1_R1,the Planning Authority and Transmission Planner shall each: Alaska Railbelt Standard AKTPL-003-1 -System Performance Following Loss of Two or More BES Elements Page 134 of 168 R2.1.Provide a written summary of the particular scenario,recommended operating procedures to avoid event triggers and plans to achieve the required system performance as described above throughout the planning horizon: R2.1.1.Including a schedule for implementation. R2.1.2.Including a discussion of expected required in-service dates of facilities. R2.1.3.Consider lead times necessary to implement plans. R2.1.4.|Provide summary to Balancing Authorities /System Operators, obtain feedback,and assist in Balancing Authority's development of risk mitigation strategies and systems. R2.1.5.Implement the strategies and systems of R 2.1.4 R2.2.Review,in subsequent annual assessments,(where sufficient lead time exists),the continuing need for identified system facilities.Detailed implementation plans are not needed. R3.The Planning Authority and Transmission Planner shall each document the results of these reliability assessments and corrective plans and shall annually provide these to its respective Regional Reliability Organization(s),as required by the Regional Reliability Organization. R4.Bi -annually the relevant scenarios will be reviewed with Balancing Authorities and System Operators to alert them to potential pitfalls in daily operating plans and to assist in development of system restoration procedures.Documentation regarding which scenarios are considered relevant and which are not considered relevant will be kept by the Panning Authority and Transmission Planner. C.Measures M1.The Planning Authority and Transmission Planner shall have a valid assessment and corrective plans as specified in Reliability Standard AKTPL-003-1_R1 and AKTPL- 003-0_R2.System restoration procedures including the Blackstart Capability Plan and training may be part of the plan. M2.The Planning Authority and Transmission Planner shall have evidence it reported documentation of results of its reliability assessments and corrective plans per Reliability Standard AKTPL-003-1_R3 and R4 M3.The Balancing Authority and System Operator shall have records of the implementation of risk mitigation strategies and systems. D.Compliance 1.Compliance Monitoring Process 2.Compliance Monitoring Responsibility Compliance Monitor Alaska Railbelt Standard AKTPL-003-1 -System Performance Following Loss of Two or More BES Elements Page 135 of 168 2.1.Compliance Monitoring Period and Reset Timeframe Bi-annually. 2.2.Data Retention None specified. 2.3.Additional Compliance Information None. 3.Levels of Non-Compliance 3.1.Level 1:Not applicable. 3.2.Level2:A valid assessment and corrective plan for the longer-term planning horizon is not available. 3.3.Level3:Not applicable. 3.4.Level 4:A valid assessment and corrective plan for the near-term planning horizon is not available.Practical risk mitigations strategies and systems have not been developed implemented and documented. E.Regional Differences 1.None identified. Version History Version Date Action Change Tracking 0 June 7,2013 Original ;New ]May 2,2016 Black Start as a plan Modify Alaska Railbelt Standard AKTPL-003-1 -System Performance Following Loss of Two or More BES Elements Page 136 of 168 AKTPL-003 Table 1.Transmission System Standards -Normal and Emergency Conditions Contingencies System Limits or ImpactsCategory&y P System Stable and both Thermal and |Loss of Demand wee gs .Voltage or Cascading °Initiati ent(s)and Contingenc Pevenararnr ..tiating Event(s)gency Limits within Curtailed Firm OutagesElement(s):Applicable Transfers Rating ? A All Facilities in Service Yes No No No Contingencies Single Line Ground (SLG)or 3-Phase (3@)Fault, B with Normal Clearing:Yes No>No Event resulting in 1.Generator Yes No?No the loss of a single 2.Transmission Circuit Yes No?No element.3.Transformer Yes No >No Loss of an Element without a Fault. Single Pole Block,Normal Clearing':b 4.Single Pole (dc)Line Yes No No LG Fault,wi al Clearing®:Cc s S aul,wath Norm faring Yes Planned/No Event(s)resulting in .Controlled* the loss of two or ..Yes Planned/No more (multiple)2.Breaker (failure or internal Fault)Controlled? elements.SLG or 3 Fault,with Normal Clearing*,Manual System Adjustments,followed by another SLG or 3@ Fault,with Normal Clearing':Yes Planned/No 3.Category B (B1,B2,B3,or B4)Controlled* contingency,manual system adjustments, followed by another Category B (B1,B2, B3,or B4)contingency Bipolar Block,with Normal Clearing®:Planned/4.Bipolar (dc)Tine Fault (non 3),with Yes Controlled?No Normal Clearing ®: 5.Any two circuits of a multiple circuit Yes Planned/No towerline!Controlled* SLG Fault,with Delayed Clearing®(stuck breaker or protection system failure):Yes Planned/No6.Generator cControlled Yes Planned/No7.Transformer Controlled' 8.Transmission Circuit Yes Planned/°c No Controlled :Yes Planned/No9.Bus Section Controlled® Alaska Railbelt Standard AKTPL-003-1 -System Performance Following Loss of Two or More BES Elements Page 137 of 168 p@ 3 Fault,with Delayed Clearing '(stuck breaker or protection system Evaluate for risks and consequences.Extreme event resulting in |failure):©May involve substantial loss oftwoormore(multiple)1.Generator 3.Transformer oe _.customer Demand andelementsremovedor2.Transmission Circuit 4.Bus Section Cascading out of service 3@ Fault,with Normal Clearing': Breaker (failure or internal Fault) generation in a widespread area or areas. ®Portions or all of the interconnected systems may or may not achieve a new, stable operating point. ®Evaluation of these events may require joint studies with neighboring systems. Loss of towerline with three or more circuits6 7.All transmission lines on a common right-of way 8.Loss of a substation (one voltage level plus transformers) 9.Loss of a switching station (one voltage level plus transformers) 10.Loss of all generating units at a station 11.Loss of a large Load or major Load center 12.Failure of a fully redundant Special Protection System (or remedial action scheme)to operate when required 13.Operation,partial operation,or misoperation of a fully redundant Special Protection System (or Remedial Action Scheme)in response to an event or abnormal system condition for which it was not intended to operate 14.Impact of severe power swings or oscillations from Disturbances in another Regional Reliability Organization. a)Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as determined and consistently applied by the system or facility owner.Applicable Ratings may include Emergency Ratings applicable for short durations as required to permit operating steps necessary to maintain system control.All Ratings must be established consistent with applicable IMC Reliability and Operating Standards addressing Facility Ratings. b)Planned or controlled interruption of electric supply to radial customers or some local System customers,connected to or supplied by the Faulted element or by the affected area,may occur in certain areas without impacting the overall reliability of the interconnected transmission systems.To prepare for the next contingency,system adjustments are permitted,including curtailments of contracted Firm (non-recallable reserved)electric power Transfers. c)Depending on system design and expected system impacts,the controlled interruption of electric supply to customers (load shedding),the planned removal from service of certain generators,and/or the curtailment of contracted Firm (non- recallable reserved)electric power transfers may be necessary to maintain the overall reliability of the interconnected transmission systems. d)A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission planning entity(ies)will be selected for evaluation.It is not expected that all possible facility outages under each listed contingency of Category D will be evaluated. e)Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected with proper functioning of the installed protection systems.Delayed clearing of a Fault is due to failure of any protectionsystemcomponentsuchasarelay,circuit breaker,or current transformer,and not because of an intentional design delay. f)System assessments may exclude these events where multiple circuit towers are used over short distances (e.g.,station entrance,river crossings)in accordance with Regional exemption criteria. Alaska Railbelt Standard AKTPL-003-1 -System Performance Following Loss of Two or More BES Elements Page 138 of 168 Alaska Railbelt Standard AKVAR-001-1-Voltage and Reactive Control A.Introduction 1. 2. 3. 5. Title:Voltage and Reactive Control Number:AKVAR-O001-1 Purpose: To ensure that voltage levels,reactive flows,and reactive resources are monitored, controlled,and maintained within limits in real time to protect equipment and the reliable operation of the Interconnection. Applicability: 4.1.Transmission Operators. 4.2.Purchasing-Selling Entities. Effective Date:1 month from package adoption. B.Requirements R1. R3. R4. Each Transmission Operator,individually and jointly with other Transmission Operators,shall ensure that formal policies and procedures are developed, maintained,and implemented for monitoring and controlling voltage levels and MVAR flows within their individual areas and with the areas of neighboring Transmission Operators. Each Transmission Operator shall acquire sufficient reactive resources within its area to protect the voltage levels under normal and Contingency conditions.This includes the Transmission Operator's share of the reactive requirements of interconnecting transmission circuits. The Transmission Operator shall specify criteria that exempt generators from compliance with the requirements defined in Requirement 4,and Requirement 6.1. R3.1.|Each Transmission Operator shall maintain a list of generators in its area that are exempt from following a voltage or Reactive Power schedule. R3.2.._For each generator that is on this exemption list,the Transmission Operator shall notify associated Generator Owner. Each Transmission Operator shall specify a voltage or Reactive Power schedule !at the interconnection between the generator facility and the Transmission Owner's facilities to be maintained by each generator.The Transmission Operator shall provide the voltage or Reactive Power schedule to the associated Generator Operator and direct the Generator Operator to comply with the schedule in automatic voltage control mode (AVR in service and controlling voltage). 'The voltage schedule is a target voltage to be maintained within a tolerance band during a specified period.The RRO will allow this up to the safe voltage/VAR limits of the equipment. Alaska Railbelt Standard AK VAR-001-1 -Voltage and Reactive Control Page 139 of 168 RS. R6. R7. R8. R9. R10. R11. R12. Each Purchasing-Selling Entity shall arrange for (self-provide or purchase)reactive resources to satisfy its reactive requirements identified by its Transmission Service Provider. The Transmission Operator shal!know the status of all transmission Reactive Power resources,including the status of voltage regulators and power system stabilizers. R6.1..When notified of the loss of an automatic voltage regulator control,the Transmission Operator shall direct the Generator Operator to maintain or change either its voltage schedule or its Reactive Power schedule. The Transmission Operator shall be able to operate or direct the operation of devices necessary to regulate transmission voltage and reactive flow. Each Transmission Operator shall operate or direct the operation of capacitive and inductive reactive resources within its area -including reactive generation scheduling;transmission line and reactive resource switching;and,if necessary,load shedding -to maintain system and Interconnection voltages within established limits. Each Transmission Operator shall maintain reactive resources to support its voltage under first Contingency conditions. Each Transmission Operator shall maintain reactive resources to support its voltage under first Contingency conditions. R9.1._Each Transmission Operator shall disperse and locate the reactive resources so that the resources can be applied effectively and quickly when Contingencies occur. Each Transmission Operator shall correct Interconnection Reliability Operating Limit (IROL)or System Operating Limit (SOL)violations resulting from reactive resource deficiencies (IROL violations must be corrected within 30 minutes)and complete the required IROL or SOL violation reporting. After consultation with the Generator Owner regarding necessary step-up transformer tap changes,the Transmission Operator shall provide documentation to the Generator Owner specifying the required tap changes,a timeframe for making the changes,and technical justification for these changes. The Transmission Operator shall direct corrective action,including load reduction, necessary to prevent voltage collapse when reactive resources are insufficient. C.Measures M1. M2. The Transmission Operator shall have evidence it provided a voltage or Reactive Power schedule as specified in Requirement 4 to each Generator Operator it requires to follow such a schedule. The Transmission Operator shall have evidence to show that,for each generating unit in its area that is exempt from following a voltage or Reactive Power schedule,the associated Generator Owner was notified of this exemption in accordance with Requirement 3.2. Alaska Railbelt Standard AKVAR-001-1 -Voltage and Reactive Control Page 140 of 168 M3.The Transmission Operator shall have evidence to show that it issued directives as specified in Requirement 6.1 when notified by a Generator Operator of the loss of an automatic voltage regulator control. M4.The Transmission Operator shall have evidence that it provided documentation to the Generator Owner when a change was needed to a generating unit's step-up transformer tap in accordance with Requirement 11 of AKVAR-001-1. D.Compliance 1.Compliance Monitoring Process 1.1.Compliance Monitoring Responsibility Regional Reliability Organization.| 1.2.Compliance Monitoring Period and Reset Time Frame One calendar year. 1.3.Data Retention The Transmission Operator shall retain evidence for Measures 1 through 4 for 12 months. The Compliance Monitor shall retain any audit data for three years. 1.4.Additional Compliance Information The Transmission Operator shall demonstrate compliance through self- certification or audit (periodic,as part of targeted monitoring or initiated by complaint or event),as determined by the Compliance Monitor. 2.Levels of Non-Compliance 2.1.Level 1:No evidence that exempt Generator Owners were notified of their exemption as specified under R3.2. 2.2...Level 2:There shall be a level two non-compliance if either of the following conditions exists: e No evidence to show that directives were issued in accordance with R6.1. e No evidence that documentation was provided to Generator Owner when a change was needed to a generating unit's step-up transformer tap in accordance with R11. 2.3.Level 3:There shall be a level three non-compliance if either of the following conditions exists: e Voltage or Reactive Power schedules were provided for some but not all generating units as required in R4. 2.4.Level 4:No evidence voltage or Reactive Power schedules were provided to Generator Operators as required in R4. E.Regional Difference Alaska Railbelt Standard AKVAR-001-1 -Voltage and Reactive Control Page 141 of 168 None identified. Version History Version Date Action Change Tracking 0 June 7,2013 Original New !May 2,2016 Voltage schedule range Modify Alaska Railbelt Standard AKVAR-001-1 -Voltage and Reactive Control Page 142 of 168 Alaska Railbelt Standard AKVAR-002-1 -Generator Operation for Maintaining Network Voltage Schedules A.Introduction 1.Title:Generator Operation for Maintaining Network Voltage Schedules 2.Number:AKVAR-002-1 3.Purpose:To ensure generators provide reactive and voltage control necessary to ensure voltage levels,reactive flows,and reactive resources are maintained within applicable Facility Ratings to protect equipment and the reliable operation of the Interconnection. 4.-_Applicability 4.1.Generator Operator. 4.2.Generator Owner. 5.Effective Date:1 month from package adoption B.Requirements R1.The Generator Operator shall operate each generator connected to the interconnected transmission system in the automatic voltage control mode (automatic voltage regulator in service and controlling voltage)unless the Generator Operator has notified the Transmission Operator. R2.Unless exempted by the Transmission Operator,each Generator Operator shall maintain the generator voltage or Reactive Power output (within applicable Facility Ratings')as directed by the Transmission Operator. R2.1.Whena generator's automatic voltage regulator is out of service,the Generator Operator shall use an alternative method to control the generator voltage and reactive output to meet the voltage or Reactive Power schedule directed by the Transmission Operator. R2.2.When directed to modify voltage,the Generator Operator shall comply or provide an explanation of why the schedule cannot be met. R3.Each Generator Operator shall notify its associated Transmission Operator as soon as practical,but within 30 minutes of any of the following: R3.1.__A status or capability change on any generator Reactive Power resource, including the status of each automatic voltage regulator and power system stabilizer and the expected duration of the change in status or capability. R3.2.__A status or capability change on any other Reactive Power resources under the Generator Operator's control and the expected duration of the change in status or capability. 'When a Generator is operating in manual control,reactive power capability may change based on stability considerations and this will lead to a change in the associated Facility Ratings. Alaska Railbelt Standard AKVAR-002-1 -Generator Operation for Maintaining Network Voltage Schedules Page 143 of 168 R4.The Generator Owner shall provide the following to its associated Transmission Operator and Transmission Planner within 30 calendar days of a request. R4.1.For generator step-up transformers and auxiliary transformers with primary voltages equal to or greater than the generator terminal voltage: R4.1.1.Tap settings. R4.1.2.Available fixed tap ranges. R4.1.3.|Impedance data. R4.1.4.The +/-voltage range with step-change in %for load-tap changing transformers. R5.After consultation with the Transmission Operator regarding necessary step-up transformer tap changes,the Generator Owner shall ensure that transformer tap positions are changed according to the specifications provided by the Transmission Operator,unless such action would violate safety,an equipment rating,a regulatory requirement,or a statutory requirement. R5.1._If the Generator Operator can't comply with the Transmission Operator's specifications,the Generator Operator shall notify the Transmission Operator and shall provide the technical justification. C.Measures M1.The Generator Operator shall have evidence to show that it notified its associated Transmission Operator any time it failed to operate a generator in the automatic voltage control mode as specified in Requirement 1. M2.The Generator Operator shall have evidence to show that it controlled its generator voltage and reactive output to meet the voltage or Reactive Power schedule provided by its associated Transmission Operator as specified in Requirement 2. M3.The Generator Operator shall have evidence to show that it responded to the Transmission Operator's directives as identified in Requirement 2.1 and Requirement 2.2. M4.The Generator Operator shall have evidence it notified its associated Transmission Operator within 30 minutes of any of the changes identified in Requirement 3. MS.The Generator Owner shall have evidence it provided its associated Transmission Operator and Transmission Planner with information on its step-up transformers and auxiliary transformers as required in Requirements 4.1.1 through 4.1.4 M6.The Generator Owner shall have evidence that its step-up transformer taps were modified per the Transmission Operator's documentation as identified in Requirement 5. M7.The Generator Operator shall have evidence that it notified its associated Transmission Operator when it couldn't comply with the Transmission Operator's step-up transformer tap specifications as identified in Requirement 5.1. Alaska Railbelt Standard AK VAR-002-1 -Generator Operation for Maintaining Network Voltage Schedules Page 144 of 168 D.Compliance 1.Compliance Monitoring Process 1.1.Compliance Monitoring Responsibility Regional Reliability Organization. 1.2.Compliance Monitoring Period and Reset Time Frame One calendar year. 1.3.Data Retention The Generator Operator shall maintain evidence needed for Measure |through Measure 5 and Measure 7 for the current and previous calendar years. The Generator Owner shall keep its latest version of documentation on its step-up and auxiliary transformers.(Measure 6) The Compliance Monitor shall retain any audit data for three years. 1.4.Additional Compliance Information The Generator Owner and Generator Operator shall each demonstrate compliance through self-certification or audit (periodic,as part of targeted monitoring or initiated by complaint or event),as determined by the Compliance Monitor. 2.Levels of Non-Compliance for Generator Operator 2.1.Level 1:There shall be a Level 1 non-compliance if any of the following conditions exist: 2.1.1 One incident of failing to notify the Transmission Operator as identified inR3.1,R3.2 or RS.1. 2.1.2 One incident of failing to maintain a voltage or reactive power schedule (R2). 2.2.Level 2:There shall be a Level 2 non-compliance if any of the following conditions exist: 2.2.1.More than one but less than five incidents of failing to notify the Transmission Operator as identified in R1,R3.1,R3.2 or R5.1. 2.2.2 More than one but less than five incidents of failing to maintain a voltage or reactive power schedule (R2). 2.3.Level 3:There shall be a Level 3 non-compliance if any of the following - conditions exist: 2.3.1 More than five but less than ten incidents of failing to notify the Transmission Operator as identified in RI,R3.1,R3.2 or RS.1. 2.3.2 More than five but less than ten incidents of failing to maintain a voltage or reactive power schedule (R2). Alaska Railbelt Standard AKVAR-002-1 -Generator Operation for Maintaining Network Voltage Schedules Page 145 of 168 3. 2.4.Level 4:There shall be a Level 4 non-compliance if any of the following conditions exist: 2.4.1 2.4.2 2.4.3 Failed to comply with the Transmission Operator's directives as identified in R2. Ten or more incidents of failing to notify the Transmission Operator as identified in RI,R3.1,R3.2 or R5.1. Ten or more incidents of failing to maintain a voltage or reactive power schedule (R2). Levels of Non-Compliance for Generator Owner: 3.1.1 3.1.2 3.1.3 3.1.4 Level One:Not applicable. Level Two:Documentation of generator step-up transformers and auxiliary transformers with primary voltages equal to or greater than the generator terminal voltage was missing two of the data types identified in R4.1.1 through R4.1.4. Level Three:No documentation of generator step-up transformers and auxiliary transformers with primary voltages equal to or greater than the generator terminal voltage. Level Four:Did not ensure generating unit step-up transformer settings were changed in compliance with the specifications provided by the Transmission Operator as identified in RS. E.Regional Differences None identified. Version History Version Date Action Change Tracking 1 January 15,2016 Effective Date New Alaska Railbelt Standard AK VAR-002-1 -Generator Operation for Maintaining Network Voltage Schedules Page 146 of 168 Exhibit A The following table lays out the functional assignments of Railbelt organizations.To the extent practical these assignments have been aligned with the NERC definitions,based on recent Railbelt history and the currently accepted operating plans of the Railbelt Utilities. The terms and entity functional assignments found in the left column entitled "Entity Function'> are found throughout the Railbelt Reliability Standards and are defined in the Railbelt Regional Reliability Standards Glossary. Entity Function AEA AMLP CEA GVEA MEA _IMC Balancing Authority Xx xX Xx Xx Compliance Enforcement Authority Xx Compliance Monitor x Distribution Provider x x Xx Xx Generator Operator x Xx X X Generator Owner X X Xx X X Generation Planner x Xx X X Interchange Authority X X X X Load-Serving Entity X X X X Market Operator (Resource Integrator) Obligated Entity X xX X X Reliability Coordinator Xx X Planning Authority X X x Xx X X Purchasing-Selling Entity X Xx X Xx Regional Reliability Organization x Reliability Assurer x Resource Planner X X X Xx Standards Developer X Transmission Operator X Xx X xX x Transmission Owner Xx x X x xX Transmission Planner x X xX Xx Xx X Transmission Service Provider X X X X X Page 147 of 168 Glossary of Terms Used in Railbelt Reliability Standards Updated January 21,2016 Introduction: This Glossary lists each term that was defined for use in one or more of Railbelt Reliability Standards. Railbelt-Wide Term Acronym Approved Date Definition Accredited Capacity 5/2/16 The total amount of generator nameplate capacity and firm energy contracts under contract to a Load Serving Entity. Adjacent Balancing Authority 11/18/10 A Balancing Authority Area that is interconnected with another Balancing Authority Area either directly or via a multi-party agreement or transmission tariff. Annual System Demand 10/13/11 The highest System Demand occurring during the 12-month period ending with the current month. Anti-Aliasing Filter 12/9/10 A filter installed at a metering point to remove the high frequency components of the signal over the AGC sample period. Area Control Error ACE 5/2/16 The instantaneous difference between a Balancing Authority's net actual and scheduled interchange,taking into account the effects of Frequency Bias and correction for meter error, Area Interchange Error AIE 5/2/16 The Balancing Authority's Interchange error(s)due to equipment failures or improper scheduling operations,or improper AGC performance. Automatic Generation Control AGC 12/9/10 Equipment that automatically adjusts generation in a Balancing Authority Area from a central location to maintain the Balancing Authority's interchange schedule plus Frequency Bias.AGC may also accommodate automatic inadvertent payback and time error correction. Available Transfer Capability ATC 5/2/16 A measure of the transfer capability remaining in the physical transmission network for further commercial activity over and above already committed uses.It is defined as Total Transfer Capability less existing Transmission commitments (including retail customer service),less a Capacity Benefit Margin,less a Transmission Reliability Margin,plus Postbacks,plus counterflows. Balancing Authority (Load Balancing Authority) BA/LBA 5/2/16 The responsible entity that integrates resource plans ahead of time,maintains load-interchange-generation balance within a Balancing Authority Area,and supports Interconnection frequency in real time. Glossary of Terms Used in Railbelt Reliability Standards Page 148 of 168 Railbelt-Wide Term Acronym Approved Date Definition Balancing Authority Area (Load Balancing Area) 5/2/16 The collection of generation,transmission,and loads within the metered boundaries of the Balancing Authority. The Balancing Authority maintains load-resource balance within this area. Blackstart Capability Plan 5/2/16 A documented procedure for a generating unit or station to go from a shutdown condition to an operating condition delivering electric power without assistance from the electric system.This procedure is only a portion of an overall system restoration plan. Bulk Electric System BES 5/2/16 As defined by its Regional Reliability Organization,the electrical generation resources,transmission lines, interconnections with neighboring systems,and associated equipment,generally operated at voltages of 69 kV or higher. Burden 12/9/10 Operation of the Bulk Electric System that violates or is expected to violate a System Operating Limit or Interconnection Reliability Operating Limit in the Interconnection,or that violates any other Railbelt, Regional Reliability Organization,or local operating reliability standards or criteria. Business Practices 5/2/16 Those business rules contained in the Transmission Service Provider's applicable tariff,rules,or procedures; associated Regional Reliability Organization or regional entity business practices. Capacity Benefit Margin CBM 5/2/16 The amount of firm transmission transfer capability preserved by the transmission provider for Load-Serving Entities (LSEs),whose loads are located on that Transmission Service Provider's system,to enable access by the LSEs to generation from interconnected systems to meet generation reliability requirements.Preservation of CBM for an LSE allows that entity to reduce its installed generating capacity below that which may otherwise have been necessary without interconnections to meet its generation reliability requirements.The transmission transfer capability preserved as CBM is intended to be used by the LSE only in times of emergency generation deficiencies. Compliance Monitor 5/2/16 The entity that monitors,reviews,and ensures compliance of responsible entities with reliability standards. Contingency 12/16/10 The unexpected failure or outage of a system component,such as a generator,transmission line, circuit breaker,switch or other electrical element. Glossary of Terms Used in Railbelt Reliability Standards Page 149 of 168 Railbelt-Wide Term Acronym Approved Date Definition Contingency Reserve 11/18/10 The provision of capacity deployed by the Balancing Authority to meet the Disturbance Control Standard (DCS)and other Railbelt and Regional Reliability Organization contingency requirements. Contingency Reserve Restoration Period 5/2/16 Begins at the end of the Disturbance Recovery Period and is 50 minutes.This period may be adjusted to better suit the reliability targets of the Interconnection based on analysis approved by its Regional Reliability Organization. Control Performance Standard CPS 11/18/10 The reliability standard that sets the limits of a Balancing Authority's Area Contro!Error over a specified time period. Curtailment 5/2/16 A reduction in the scheduled capacity or energy delivery of an Interchange Transaction. Deciared Capability 5/2/16 Declared Capability-not less than the load (MW)on the unit at any point in time and not more than the temperature compensated maximum amount of load (MW)the unit is capable of supplying for a two-hour period or immediately supplying through the actions of AGC. Demand 5/2/16 1.The rate at which electric energy is delivered to or by a system or part of a system,generally expressed in kilowatts or megawatts,at a given instant or averaged over any designated interval of time. 2.The rate at which energy is being used by the customer. Distribution Provider DP 5/2/16 Provides and operates the "wires”between the transmission system and the end-use customer.For those end-use customers who are served at transmission voltages,the Transmission Owner also serves as the Distribution Provider.Thus,the Distribution Provider is not defined by a specific voltage,but rather as performing the distribution function at any voltage. Disturbance 11/18/10 1.An unplanned event that produces an abnormal system condition. 2.Any perturbation to the electric system. 3.The unexpected change in ACE that is caused by the sudden failure of generation or interruption of load. Disturbance Control Standard DCS 11/18/10 The reliability standard that sets the time limit following a Disturbance within which a Balancing Authority must return its Area Control Error to within a specified range. Glossary of Terms Used in Railbelt Reliability Standards Page 150 of 168 Railbelt-Wide Term Acronym Approved Date Definition Disturbance Recovery Criterion 1/1/16 A Balancing Authority shall return its ACE to zero if its ACE just prior to the Reportable Disturbance was positive or equal to zero.For negative initial ACE values just prior to the Disturbance,the Balancing Authority shall return ACE to its pre-Disturbance value. Disturbance Recovery Period 5/2/16 The default Disturbance Recovery Period is 10 minutes after the start of a Reportable Disturbance.This period may be adjusted to better suit the needs of an Interconnection based on analysis approved by the Reliability Assurer. Dynamic Interchange Schedule or Dynamic Schedule 12/9/10 A telemetered reading or value that is updated in real time and used as a schedule in the AGC/ACE equation and the integrated value of which is treated as a schedule for interchange accounting purposes. Commonly used for scheduling jointly owned generation to or from another Balancing Authority Area. Emergency or BES Emergency 5/2/16 Any abnormal system condition that requires automatic or immediate manual action to prevent or limit the failure of transmission facilities or generation supply that could adversely affect the reliability of the Bulk Electric System. Emergency Transfer Capability TBD The amount of electric power that can be moved or transferred from one area to another area of the interconnected transmission systems by way of all transmission lines (or paths)between those areas under emergency conditions. End User 10/6/11 Greater than 10 MW aggregate load that may be an independent entity or part of a utilities service area. Facility Rating 5/2/16 The maximum or minimum voltage,current,frequency, or real or reactive power flow through a facility that does not violate the applicable equipment rating of any equipment comprising the facility. Firm Demand 5/2/16 That portion of the Demand that a power supplier is obligated to provide except when system reliability is threatened or during emergency conditions. Firm Generation or Firm Power TBD Power producing capacity intended to be available at all times during the period covered by a commitment even under adverse conditions. Firm Transmission Service 5/2/16 The highest quality (priority)service offered to customers under a filed rate schedule that anticipates no planned interruption. Glossary of Terms Used in Railbelt Reliability Standards - Page 151 of 168 Railbelt-Wide Term Acronym Approved Date Definition Forecasted Peak Demand TBD The highest peak demand of the BA's forecasted system load requirements for the specified portion of the planning year. Forced Outage 1/13/11 1.The removal from service availability of a generating unit,transmission line,or other facility for emergency reasons. 2.The condition in which the equipment is unavailable due to unanticipated failure. Frequency Bias 11/18/10 A value,usually expressed in megawatts per 0.1 Hertz (MW/0.1 Hz),associated with a Balancing Authority Area that approximates the Balancing Authority Area's response to Interconnection frequency error. Frequency Bias Setting 11/18/10 A value,usually expressed in MW/0.1 Hz,set into a Balancing Authority ACE algorithm that allows the Balancing Authority to contribute its frequency response to the Interconnection. Frequency Deviation 12/9/10 A change in Interconnection frequency. Frequency Error 5/2/16 The difference between the actual and scheduled frequency.(Fa -Fs) Frequency Regulation 12/9/10 The ability of a Balancing Authority to help the Interconnection maintain Scheduled Frequency.This assistance can include both turbine governor response and Automatic Generation Control. Frequency Response 12/9/10 (Equipment)The ability of a system or elements of the system to react or respond to a change in system frequency. (System)The sum of the change in demand,plus the change in generation,divided by the change in frequency,expressed in megawatts per 0.1 Hertz (MW/0.1 Hz). Generating Assets GA 5/2/16 Primarily refers to machines synchronously connected to the Railbelt Grid providing real and reactive power. In some specialized instances these may include assets that are asynchronously connected to the Railbelt.Or, devices that provide only reactive power (synchronous condensers,SVC's,cables,wind turbines,FACTS etc.). Generator Operator GOP 5/2/16 The entity that operates generating unit(s)and performs the functions of supplying energy and Interconnected Operations Services. Generator Owner GO 5/2/16 Entity that owns and maintains generating units. Glossary of Terms Used in Railbelt Reliability Standards Page 152 of 168 Railbelt-Wide Term Acronym Approved Date Definition Host Balancing Authority 12/9/10 1.A Balancing Authority that confirms and implements Interchange Transactions for a Purchasing Selling Entity that operates generation or serves customers directly within the Balancing Authority's metered boundaries. 2.The Balancing Authority within whose metered boundaries a jointly owned unit is physically located. Inadvertent Interchange 5/2/16 The difference between the Balancing Authority's Net Actual Interchange and Net Scheduled Interchange.(IA -Is) Interchange 5/2/16 Energy transfers that cross Balancing Authority boundaries. Interchange Authority 5/2/16 The responsible entity that authorizes implementation of valid and balanced Interchange Schedules between Balancing Authority Areas,and ensures communication of Interchange information for reliability assessment purposes. Interchange Schedule 11/18/10 An agreed-upon Interchange Transaction size (megawatts),start and end time,beginning and ending ramp times and rate,and type required for delivery and receipt of power and energy between the Source and Sink Balancing Authorities involved in the transaction. Interchange Transaction 11/18/10 An agreement to transfer energy from a seller to a buyer that crosses one or more Balancing Authority Area boundaries. Interconnected Operations Service 5/2/16 A service (exclusive of basic energy and transmission services)that is required to support the reliable operation of interconnected Bulk Electric System. Interconnected Value 5/2/16 The technical value of a generating asset to the Railbelt Grid and its subdivisions (LSE's,BAL's etc.)in terms of dispatch-ability,real and reactive power output and absorption,inertia,system response,operating and non- operating reserves,etc. Interconnection 11/18/10 When capitalized,the Alaska Railbelt Interconnection. Interconnection Reliability Operating Limit IROL 5/2/16 The value (such as MW,MVAr,Amperes,frequency or Volts)derived from,or a subset of the System Operating Limits,which if exceeded,could expose a widespread area of the Bulk Electric System to instability,uncontrolled separation(s)or cascading outages. Glossary of Terms Used in Railbelt Reliability Standards Page 153 of 168 Railbelt-Wide Term Acronym Approved Date Definition Intermediate Balancing Authority 5/2/16 A Balancing Authority Area that has connecting facilities in the Scheduling Path between the Sending Balancing Authority Area and Receiving Balancing Authority Area and operating agreements that establish the conditions for the use of such facilities. Interruptible Demand TBD Demand not under direct control of the system operator that the end-use customer makes available to its BA via contract or agreement for curtailment.Interruptible Demand may include interruptible load that is not available for use in reducing the BA's forecast demand requirements due to contractual or implementation restrictions. Largest Single Generation Contingency LSGC 5/2/16 The declared Capability of the largest generating unit contingency (or combination of units with a single point of interconnection forming a single contingency regardless of RAS applications)interconnected to the Railbelt Grid. Load Serving Entity LSE 5/2/16 An entity that secures energy and transmission service (and related Interconnected Operations Services)to serve the electrical demand and energy requirements of its end-use customers. Monthly Peak Hour Load MPHL 5/2/16 The MPHL of an entity shall be defined as the monthly peak hour 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 Reliability Assurer.Economy sales are not counted as loads,but non-firm/interruptible loads are. Net Actual Interchange 5/2/16 The algebraic sum of all metered interchange over all interconnections between two physically Adjacent Balancing Authority Areas. Net Interchange Schedule 5/2/16 The algebraic sum of all Interchange Schedules with each Adjacent Balancing Authority. Net Internal Demand TBD Total of all end-use customer demand and electric system losses within specified metered boundaries and period,and less Direct Control Load Management and Interruptible Demand. Net Scheduled Interchange 5/2/16 The algebraic sum of all Interchange Schedules across a given path or between Balancing Authorities for a given period or instant in time. Non-Spinning Reserve 12/9/10 1.That generating reserve not connected to the system but capable of serving demand within a specified time. 2.Interruptible load that can be removed from the system in a specified time. Glossary of Terms Used in Railbelt Reliability Standards Page 154 of 168 Railbelt-Wide Term Acronym Approved Date Definition Normal Net Capability TBD The maximum continuous rating of the resource minus the station service demand required to achieve the maximum continuous rating of the unit within the specified period.Station service or plant loads not attributable to the operation of the unit must not be included in the Normal Net Capability of the unit. Obligated Entity 5/2/16 A Railbelt entity who is obligated to provide operating and or non-operating reserves or reserve capacity. Off-Peak 12/9/10 Those hours between HE 2300 and HE 0600,weekdays and Saturdays and all hours Sunday.Also all hours on the following holidays;New Year's Day,Memorial Day, July 4th,Labor day,Thanksgiving and Christmas. On-Peak 12/9/10 Those hours or other periods that are not Off-Peak Operating Reserve 11/18/10 That capability above firm system demand required to provide for regulation,load forecasting error,equipment forced and scheduled outages and local area protection. It consists of spinning and non-spinning reserve. Operating Reserve -Spinning 11/18/10 The portion of Operating Reserve consisting of: ¢Generation synchronized to the system and fully available to serve load within the Disturbance Recovery Period following the contingency event within operational or procedural limitations;or *Load fully removable from the system within the Disturbance Recovery Period following the contingency event,for example SILOS. ¢Other approved sources. Operating Reserve - Supplemental 11/18/10 The portion of Operating Reserve consisting of: e Generation (synchronized or capable of being synchronized to the system)that is fully available to serve load within the Disturbance Recovery Period following the contingency event;or ¢Load fully removable from the system within the Disturbance Recovery Period following the contingency event. e Other approved sources. Overlap Regulation Service 5/2/16 A method of providing regulation service in which the Balancing Authority providing the regulation service incorporates another Balancing Authority's actual interchange,frequency response,and schedules into providing Balancing Authority's AGC/ACE equation. Glossary of Terms Used in Railbelt Reliability Standards Page 155 of 168 Railbelt-Wide Term Acronym Approved Date Definition Planning Authority PA 5/2/16 The responsible entity that coordinates and integrates transmission facility and service plans,resource plans,and protection systems. Planning Reserve Margin TBD The ratio of the total amount of planned available Firm Generation capacity divided by the Forecasted Peak Demand of the system minus 1.0,expressed in %for the specified period.The Planning Reserve Margin requirement must be calculated by each BA by system analysis. Point of Delivery POD 5/2/16 A location that the Transmission Service Provider specifies on its transmission system where an Interchange Transaction leaves or a Load-Serving Entity receives its energy. Point of Receipt POR 5/2/16 A location that the Transmission Service Provider specifies on its transmission system where an Interchange Transaction enters or a generator delivers its output. Postback 5/2/16 Positive adjustments to ATC as defined in Business Practices. Such Business Practices may include processing of redirects and unscheduled service. Power Electronics Transmission Asset TBD A device connected to the Bulk Electric system whose Real and Reactive Power outputs are controlled through the use of power electronics.Power Electronics Transmission Assets are not generation,but may produce Real and Reactive Power up to an energy limit.Power Electronics Transmission Assets include SVCs,STATCOMs,and Energy Storage Devices. Prudent Utility Practice 5/2/16 Shall mean at a particular time any of the practices, methods and acts which,in the exercise of reasonable judgment in light of the facts known at the time the decision was made,would have been expected to accomplish the desired result at the lowest reasonable cost consistent with reliability,safety and expedition,including but not limited to the regional practices,methods and acts engaged in or approved by a significant portion of the electrical utility industry prior thereto.In applying the standard of Prudent Utility Practices to any matter under these standards, equitable consideration should be given to the circumstances,requirements and obligations of each of the entities,and the fact that many of the entities are cooperatives,public corporations,or political subdivisions of the State of Alaska with prescribed statutory powers, duties and responsibilities.It is recognized that Prudent Utility Practice are not intended to be limited to the optimum practices,methods or acts to the exclusion of all others,but rather is a spectrum of possible practices, Glossary of Terms Used in Railbelt Reliability Standards Page 156 of 168 Railbelt-Wide Term Acronym Approved Date Definition methods or acts which could have been expected to accomplish the desired result at the lowest reasonable cost consistent with reliability,safety and expedition.Prudent Utility Practices include due regard for manufacturers' warranties and the requirements of governmental authorities having jurisdiction. Pseudo-Tie 12/9/10 A telemetered reading or value that is updated in real time and used as a "virtual”tie line flow in the AGC/ACE equation but for which no physical tie or energy metering actually exists.The integrated value is used as a metered MWh value for interchange accounting purposes. Purchasing-Selling Entity PSE 5/2/16 The entity that purchases or sells,and takes title to, energy,capacity,and Interconnected Operations Services.Purchasing-Selling Entities may be affiliated or unaffiliated merchants and may or may not own generating facilities. Railbelt (Railbelt Grid,Railbelt Interconnection, Railbelt System) 5/2/16 The interconnected generation and transmission system of Central Alaska,currently The Railbelt region extending from North of the Fairbanks area to the Kachemak bay area in the South.If used when describing an obligation,only those entities in the Railbelt that have IMC contractual responsibilities. Reactive Power VARS 5/2/16 The portion of electricity that establishes and sustains the electric and magnetic fields of alternating-current equipment.Reactive Power must be supplied to most types of magnetic equipment,such as motors and transformers.It also must supply the reactive losses on transmission facilities.Reactive Power is provided by generators,synchronous condensers,or electrostatic equipment such as capacitors and directly influences electric system voltage.It is usually expressed in kilovars (kVAr)or megavars (MVAr). Receiving Balancing Authority 12/16/10 The Balancing Authority importing the Interchange. Regional Coordinating Council TBD The responsible entity that enforces,coordinates,and integrates reliability standards used by the Regional Reliability Organizations. Regional Reliability Organization RRO 11/18/10 An entity that ensures that a defined area of the Bulk Electric System is reliable,adequate and secure. Regulating Reserve 12/9/10 An amount of reserve responsive to Automatic Generation Control,which is sufficient to provide normal regulating margin. Regulating Reserve Obligation 5/2/16 The minimum amount of regulating reserve required during day ahead planning. Glossary of Terms Used in Railbelt Reliability Standards Page 157 of 168 Railbelt-Wide Term Acronym Approved Date Definition Regulation Service 12/9/10 The process whereby one Balancing Authority contracts to provide corrective response to all or a portion of the ACE of another Balancing Authority.The Balancing Authority providing the response assumes the obligation of meeting all applicable control criteria as specified by its Regional Reliability Organization for itself and the Balancing Authority for which it is providing the Regulation Service. Reliability Assurer 5/2/16 Monitors and evaluates the activities related to planning and operations,and coordinates activities of responsible entities to secure the reliability of the bulk power system. Reliability Coordinator RC 5/2/16 The entity that is the highest level of authority who is responsible for the reliable operation of the Bulk Electric System,has the Wide Area view of the Bulk Electric System,and has the operating tools,processes and procedures,including the authority to prevent or mitigate emergency operating situations in both next-day analysis and real-time operations.The Reliability Coordinator has the purview that is broad enough to enable the calculation of Interconnection Reliability Operating Limits, which may be based on the operating parameters of transmission systems beyond any Transmission Operator's vision. Reliability Coordinator Area 5/2/16 The collection of generation,transmission,and loads within the boundaries of the Reliability Coordinator.Its boundary coincides with one or more Balancing Authority Areas. Remedial Action Scheme RAS 5/2/16 See "Special Protection System”. Reportable Disturbance 5/2/16 Contingencies involving any generating unit trips, transmission line trips,and distribution level disturbances that result in frequency deviation >.2 Hz.The definition of a reportable disturbance is specified by each Regional Reliability Organization.This definition may not be retroactively adjusted in response to observed performance. Reserve Capacity Obligation 5/2/16 For any year,shall be equal to thirty (30)percent of the projected Annual System Demand for that year for that Load Serving Entity. Glossary of Terms Used in Railbelt Reliability Standards Page 158 of 168 Railbelt-Wide Term Acronym Approved Date Definition Reserve Margin TBD The ratio of the actual total amount of available Firm Generation capacity,expressed in %,between the total available Firm Generation capacity divided by the Peak Demand of the system minus 1.0,expressed in %for the specified period. Reserve Sharing Group RSG 11/18/10 A group whose members consist of two or more Balancing Authorities that collectively maintain,allocate,and supply operating reserves required for each Balancing Authority's use in recovering from contingencies within the group. Scheduling energy from an Adjacent Balancing Authority to aid recovery need not constitute reserve sharing provided the transaction is ramped in over a period the supplying party could reasonably be expected to load generation in (e.g.,ten minutes).If the transaction is ramped in quicker (e.g.,between zero and ten minutes)then,for the purposes of the Disturbance Control Standard,the areas become a Reserve Sharing Group. Resource Adequacy TBD The ability of supply-side and demand-side resources to meet the aggregate electrical demand (including losses within a BA's area)at all times within the specified period taking into account scheduled and reasonably expected unscheduled outages of system elements. Resource Planner RP 5/2/16 The entity that develops a long-term (generally one year and beyond)plan for the resource adequacy of specific loads (customer demand and energy requirements)within a Planning Authority area. Schedule 12/9/10 (Verb)To set up a plan or arrangement for an Interchange Transaction. (Noun)An Interchange Schedule. Scheduled Frequency 12/9/10 60.0 Hertz,except during a time correction. Scheduling Entity 12/9/10 An entity responsible for approving and implementing Interchange Schedules. Scheduling Path 5/2/16 The Transmission Service arrangements reserved by the Purchasing-Selling Entity for a Transaction. Sending Balancing Authority 12/16/10 The Balancing Authority exporting the Interchange. Shed In Lieu Of Spin SILOS 11/18/10 Computer or relay based load shedding scheme with timing and frequency parameters approved by its Regional Reliability Organization.This is not to be confused with system coordinated under-frequency load shedding. Glossary of Terms Used in Railbelt Reliability Standards Page 159 of 168 Railbelt-Wide Term Acronym Approved Date Definition Sink Balancing Authority 12/16/10 The Balancing Authority in which the foad (sink)is located for an Interchange Transaction.(This will also be a Receiving Balancing Authority for the resulting Interchange Schedule.) Source Balancing Authority 12/16/10 The Balancing Authority in which the generation (source) is located for an Interchange Transaction.(This will also be a Sending Balancing Authority for the resulting Interchange Schedule.) Special Protection System (Remedial Action Scheme) SPS 5/2/16 An automatic protection system designed to detect abnormal or predetermined system conditions,and take corrective actions other than and/or in addition to the isolation of faulted components to maintain system reliability.Such action may include changes in demand,generation (MW and Mvar),or system configuration to maintain system stability,acceptable voltage,or power flows.An SPS does not include (a) underfrequency or undervoltage load shedding or (b) fault conditions that must be isolated or (c)out-of-step relaying (not designed as an integral part of an SPS). Also called Remedial Action Scheme. Spin Balancing Account SBA 5/2/16 Procedures to track small changes in spin obligations due to forecasting errors. Spinning Reserve 12/9/10 See Operating Reserve -Spinning Spinning Reserve Obligation SRO 5/2/16 The amount of spinning reserve an Obligated Entity is required to maintain. Stability Limit TBD The maximum power flow possible through some particular point in the system while maintaining stability in the entire system or the part of the system to which the stability limit refers. Steady-State Transfer Capability TBD The capability of a transmission system to reliably transfer electric power from one area to another by way of all transmission lines (or paths).The Steady-State Transfer Capability is equal to the Steady-State Transfer Limit minus Contingency Reserve obligations of source area and Transmission Reliability Margin. Steady-State Transfer Limit TBD The amount of electric power that can be moved or transferred from one area to another area of the interconnected transmission systems by way of all transmission lines (or paths)before a contingency event would result in unacceptable system response. Supplemental Regulation Service 12/9/10 A method of providing regulation service in which the Balancing Authority providing the regulation service receives a signal representing all or a portion of the other Balancing Authority's ACE. Glossary of Terms Used in Railbelt Reliability Standards Page 160 of 168 Railbelt-Wide Term Acronym Approved Date Definition System 5/2/16 A combination of generation,transmission,and distribution components. System Demand 10/13/11 That number of kilowatts which is equal to the kilowatt- hours required in any clock hour,attributable to energy required during such hour for supply of energy to an entities'consumers,including system losses,and wheeling losses occurring on other systems.System Demand excludes generating station uses. System Operating Limit SOL 5/2/16 The value (such as MW,MVAr,Amperes,frequency or Volts)that satisfies the most limiting of the prescribed operating criteria for a specified system configuration to ensure operation within acceptable reliability criteria. System Operating Limits are based upon certain operating criteria.These include,but are not limited to: ¢Facility Ratings (Applicable pre-and post- Contingency equipment or facility ratings) ©Transient Stability Ratings (Applicable pre- and post-Contingency Stability Limits) ©Voltage Stability Ratings (Applicable pre- and post-Contingency Voltage Stability) e System Voltage Limits (Applicable pre-and post- Contingency Voltage Limits). System Operator 5/2/16 An individual at a control center (Balancing Authority, Transmission Operator,Generator Operator,Reliability Coordinator)whose responsibility it is to monitor and control that electric system in real time System Reserve Basis SRB 5/2/16 The amount of Spinning Reserve required to prevent first stage load-shed.Generally determined by system studies of the frequency response of the system under various conditions for the loss of the Largest Single Generation Contingency. Temperature Sensitive Units TBD A generating unit whose maximum real power capability changes by more than 10 percent due to change in ambient air temperature.The 10 percent change in real power capability is based on the local average annual maximum and annual minimum ambient air temperatures. Tie Line 12/9/10 A circuit connecting two Balancing Authority Areas. Tie Line Bias 12/9/10 A mode of Automatic Generation Control that allows the Balancing Authority to 1.)maintain its Interchange Schedule and 2.)respond to Interconnection frequency error. Glossary of Terms Used in Railbelt Reliability Standards Page 161 of 168 Railbelt-Wide Term Acronym Approved Date Definition Tie Line Deviation 8/11/11 See Inadvertent Interchange. Time Error 12/9/10 The difference between the Interconnection time measured at the Balancing Authority(ies)and the time specified by the National Institute of Standards and Technology.Time error is caused by the accumulation of Frequency Error over a given period. Time Error Correction 12/9/10 An offset to the Interconnection's scheduled frequency to return the Interconnection's Time Error to a predetermined value. Time Monitor 5/2/16 The entity that monitors Time Error and initiates or terminates corrective action orders in accordance with the Time Error Correction procedure. Total Operating Reserve Obligation 5/2/16 At any time shall be an amount equal to 150 percent of the System Reserve Basis of the Railbelt Grid and may be composed of both spinning and non-spinning reserve. Total Transfer Capability TTC 5/2/16 The amount of electric power that can be moved or transferred reliably from one area to another area of the interconnected transmission systems by way of all transmission lines (or paths)between those areas under specified system conditions. Transient Transfer Limit TBD Stability Limit minus the Transmission Reliability Margin. Transaction 12/9/10 See Interchange Transaction. Transmission 12/9/10 An interconnected group of lines and associated equipment for the movement or transfer of electric energy between points of supply and points at which it is transformed for delivery to customers or is delivered to other electric systems.Generally operated at or above 69 kV. Transmission Constraint 12/9/10 A limitation on one or more transmission elements that may be reached during normal or contingency system operations. Transmission Customer 12/9/10 1.Any eligible customer (or its designated agent)that can or does execute a transmission service agreement or can or does receive transmission service. 2.Any of the following responsible entities:Generator Owner,Load-Serving Entity,or Purchasing-Selling Entity. Transmission Line 12/9/10 A system of structures,wires,insulators and associated hardware that carry electric energy from one point to another in an electric power system.Lines are operated at relatively high voltages varying from 69 kV up to 765 kV, and are capable of transmitting large quantities of electricity over long distances. Glossary of Terms Used in Railbelt Reliability Standards Page 162 of 168 Railbelt-Wide Term Acronym Approved Date Definition Transmission Operator TOP 12/9/10 The entity responsible for the reliability of its "local” transmission system,and that operates or directs the operations of the transmission facilities. Transmission Operator Area 12/9/10 The collection of Transmission assets over which the Transmission Operator is responsible for operating. Transmission Owner TO 5/2/16 The entity that owns and maintains transmission facilities. Transmission Planner TP 5/2/16 The entity that develops a long-term (generally one year and beyond)plan for the reliability (adequacy)of the interconnected bulk electric transmission systems within its portion of the Planning Authority area. Transmission Reliability Margin TRM 5/2/16 The amount of transmission transfer capability necessary to provide reasonable assurance that the interconnected transmission network will be secure.TRM accounts for the inherent uncertainty in system conditions and the need for operating flexibility to ensure reliable system operation as system conditions change. Transmission Service 12/9/10 Services provided to the Transmission Customer by the Transmission Service Provider to move energy from a Point of Receipt to a Point of Delivery. Transmission Service Provider TSP 5/2/16 The entity that administers the transmission tariff and provides Transmission Service to Transmission Customers under applicable transmission service agreements. Wide Area 5/2/16 The entire Reliability Coordinator Area as well as the critical flow and status information from adjacent Reliability Coordinator Areas as determined by detailed system studies to allow the calculation of Interconnection Reliability Operating Limits. Glossary of Terms Used in Railbelt Reliability Standards Page 163 of 168 Exhibit-C Sanctions Matrix for Non Compliance Number of Occurrences at a Given Level within Specified Period Level of Non-1 2 3 4 or more Compliance Level 1 Letter (A)Letter (A)Letter (A)Letter (B) Level 2 Letter (A)Letter (A)Letter (B)Letter (B) Level 3 Letter (A)Letter (A)Letter (B)Letter (B) Level 4 Letter (A)Letter (B)Letter (B)Letter (B) Letter (A)is letter to management Letter (B)is letter to Board Specified Period is calendar year Page 164 of 168 Exhibit D-Railbelt Reliability Planning Guidelines: During all excursions subsequent to the occurrence of Category B or probable Category C contingency,the following parameters should be maintained within applicable Emergency limits without system separation or instability: Quantity Level:Minimum Maximum First Power Swing:0.80 pu V 1.10 pu V(<0.5 sec.) Intermediate:0.92 pu V 1.05 pu V Steady State:0.95 pu V 1.05 pu V Frequency:58.8 Hz 61.5 Hz Page 165 of 168 Exhibit E-Railbelt Under Frequency Load shed Schedule Subsequent to the 1989 blackout of the Railbelt Grid,the Intertie Operating Committee (IOC) (the predecessor to the Intertie Management Committee/Operating Sub-Committee)directed its Relay and Reliability Sub-committee (RRSC)evaluate the load shed scheme in place at that time. The Pre-1993 scheme consisted of 13 shed points beginning at 59.3 Hz and ending with CEA/MEA Teeland separation at 57.7 Hz.The CEA/HEA separation at Quartz Creek had been disarmed by agreement with HEA in the late 1980's. Using Power Technologies Inc.(PTI)and their power system simulator/electrical (PSS/E) program to run the bulk of the studies,with the RRSC performing QA/QC,the RRSC undertook extensive system studies in both powerflow and dynamic stability.These studies were performed in concert with the Bradley Lake integration studies which were being performed at the same time.The Bradley Lake studies were performed under the auspices of the Technical Coordinating Sub-committee (TCC)of the Bradley Lake Project Management Committee (BPMC).As today,the members of both of these committees were much the same.The major difference Fairbanks Municipal Utilities Systems (FMUS)was a member of the IOC and not a Bradley participant,while SES was a Bradley participant and not a member of the IOC. The outcome of these studies is the load shed scheme delineated in Table -1 below,in the green Ld]cells.Subsequent modifications to the study were made by the IOC and following the system blackouts of 1994 and 1995 these are indicated by the values in the cells in goldenrod |Outside the Chugach system other undocumented changes may have been made in the intervening years. Page 166 of 168 Railbelt Underfrequency Loadshed Summary {As Adopted by the tntertie Operating Committee-3/19/1993)*Balancing Authority CEA |AMLP|CEA |CEA]GVEA GVEA fil GVEALoadServingEntiChugachAML&P HEA |MEA)GVEA %of MW Value CommentROC+Hz* Frequency Set Point DelayadSedStage(v2){Cyctes (%)(%)|(%)|(%)(%)(%) »SILOS 59.8 120 25%Spinning Reserve Obligation SILOS 59.7 120 25%Spinning Reserve Obligation 1OC Approved-August 1994 SILOS 59.4 120 25%25%Spinning Reserve Obligation tOC Approved-August 1994 ige |Supplemental 59.3 9 13%Totat toad ge t Supplemental 59.2 9 12%Total Load +SILOS 59.1 120 50%50%Spinning Reserve Obligation !OC Approved-August 1994 age |Suppl 1 59.1 9 10%Total Load SILOS 59.1 1 100%Spinning Reserve Obligation 1OC Approved-August 1994 Stage}59.0 6 10%10%}10%|10%10%Total Load ige tt Supplemental 58.9 6 10%Total Load ;58.8 6 Stage I!58.7 6 10%10%|10%|10%10%Total Load 58.6 6 12%Total Load Stage Ill 58.5 6 10%|10%|15%|10%Total Load Stage IV 58.5 30 7%Total Load implemented after 1994 Blackout No IOC Appr: 58.5 35 10%Total Load implemented after 1994 Blackout No IOC Appr. 58.5 40 9%Total Load implemented after 1994 Blackout No IOC Appr 58.5 45 TA)Total Load Implemented after 1994 Blackout No lOC Appr@ 58.5 50 7%Total Load Implemented after 1994 Blackout No 10C Appr@ 58.5 55 6%Total Load Implemented after 1994 Blackout No IOC Appr. 58.5 60 8%Total Load Implemented after 1994 Blackout No IOC Appr@ '58.4 6 Island Separate GVEA and Southern System :58.3 6 ge IV Supplemental 58.2 6 40%Total Load '58.1 6 58.0 6 2 57.9 6 i 57.8 6 :57.7 9 tsland AMLP and CHugach Implemented after 1995 Blackout No {OC Appr '57.6 6 '57.5 6 574 6 57.3 6 vith Known Changes Nithout BESS ROC Supervised for tntertie Trip 3 contributes to loadshed by virtue of a crossing tripping tie that opens the SES 115 line on Loss of the Kenai-Anch 115 kV line for Kenai Imports greater thatn 15 MW. val Page 168 of 168 Guidelines ALASKA SYSTEMS COORDINATING COUNCIL An association of Alaska's electric power systems promoting improved reliability through systems coordination ASCC OPERATING GUIDES FOR INTERCONNECTED UTILITIES and Alaska Intertie Operating Guides February 1992 ALASKA SYSTEMS COORDINATING COUNCIL ASCC OPERATING GUIDES FOR INTERCONNECTED UTILITIES AND ALASKA INTERTIE OPERATING GUIDES The Alaska Systems Coordinating Council (ASCC)is an association of Alaska's electricpowersystemspromotingimprovedreliabilitythroughsystemscoordinationandanaffiliate member of the North American Electric Reliability Council (NERC).In August,1990,the ASCC established a Reliability Criteria Committee composed of representatives of the ASCC members in Alaska's Railbelt region.The primary task of the Subcommittee was to complete efforts to develop,formulate in writing,and submit to ASCC for approval, coordinated interconnection planning and operating reliability criteria. The development ofinterconnection planning criteria culminated in the preparation of theinrtheRelinticUtilitiesasadoptedbytheASCConAprilre1991.At that time the ASCC also adopted,for operating reliability criteria,the previously developed Alaska Intertie Operating Guides,as modified and updated by the Alaska Intertie Operating Committee (OC).The Reliability Criteria Committee was directed to work with the IOC on appropriate modifications. The A!7 "ree,... are derived fromthe NERC operating muides,modified as necessary for conditions specifictotheAlaskainterconnectednetwork.The guides are designed to promote coordinated operation among interconnected systems and to achieve high levels of interconnected systems reliability and control.Application of the guides will promote the reliability of the bulk power system of the interconnected electric utilities of Alaska. Recommended by Reliability Criteria Committee:February 19,1991 Adopted by the Alaska Systems Coordinating Council:April 4,1991 Revised by Alaska Intertie Operating Committee:January 23,1992 weALASKA INTERTIE OPERATING GUIDES "Adopted by the Alaska Intertie Operating Committee" For Use by All Participating Utilities ALASKA INTERTIE OPERATING GUIDES TABLE OF CONTENTS INTRODUCTION TERMS USED IN THE GUIDES GUIDE 1.SYSTEMS CONTROL A.Generation Control 11 B.Voltage Control 13 C.Time and Frequency Control 14 D.Interchange Scheduling L6 E.Control Performance Criteria L8 F.Inadvertent Interchange Management.............-.---..1.9 G.Control Surveys.111i H.Control Equipment Requirements.Lil APPENDIX 1.C Time Error Correction Procedures APPENDIX LF Inadvertent Interchange Energy Accounting Practices GUIDE Il.SYSTEM SECURITY (%A.Real Power (MW)Supply.1 et B.Reactive Power (MVAR)Supply.........ccsecoeeoveee 1.2 C.Transmission Operation 1.3 D.Relay Coordination 10.4 E.Monitoring Interconnection Parameters.........-+--116 F.Information Exchange System Condition................IL8 G.Information Exchange Disturbance Reporting...........I1.8 H.Information Exchange Sabotage Reports......s.0--«110 I,Maintenance Coordination 11.10 APPENDIX ILG Reporting Requirements for Major Electric Utility System Emergencies GUIDE tl.EMERGENCY OPERATIONS A.Insufficient Generation Capacity........c0ssssses 11.2 B.Transmission -Overload,Voltage Control............HL2 C.Load Shedding TIL3 D.System Restoration II.4 E,Emergency Information Exchange TIL5 F,Special System or Control Area Action...IIL5 G.Control Center Backup TI1.6 Approved he C:7NERC1Revised'¥/s a " Table of Contents GUIDE IV.OPERATING PERSONNEL A.Responsibility and Authority...........-ssssessoe TV.1 B.Selection IV.1 C.Training IV.2 D.Responsibility to Other Operating Group.............[V.4 APPENDIX IV.C Suggested Items for Inclusion in a Training Course GUIDE V.OPERATIONS PLANNING A.Normal Operations.V.1 B.Planning for Short Term Emergency Conditions........V.2 C.Planning for Long Term Emergency Conditions.........V.2 D.Load Shedding.V.5 E.System Restoration V.6 GUIDE VI.TELECOMMUNICATIONS A.Facilities.VL1 B.System Operator Telecommunication Procedures........VL2 C.Loss of Telecommunications VL3 APPENDIX VIA Alaska Interconnect Communication APPENDIX VLB Notification of Solar Magnetic Disturbance Warnings approvesNERC2Revised -,L2.3/$%. VivearNORTH AMERICAN ELECTRIC RELIABILITY COUNCIL OPERATING GUIDES INTRODUCTION The NERC-OC Operating Guides (Guides)are designed to promote coordinated operationamonginterconnectedsystemsandtoachievehighlevelsofinterconnectedsystemsreliabilityandcontrol.The Guides specify how the basic operating policy of the NERC Operating Committee,contained in the Reliability Criteria for Interconnected Systems Operation (Criteria),is to be implemented.The Criteria and Guides are based on established technical rationale and matureoperatingexperienceandjudgment.System operator input is vital to the establishment andmaintenanceofgoodoperatingpolicy.The Criteria and Guides are reviewed and updated by theOperatingCommitteeasnecessarywithpresentandfutureInterconnectionandsystemrequirements in mind. In practice,certain Guide statements are more essential to reliable Interconnection operationthanothers.Therefore,the Guide statements have been classified as either Operating Requirements or Operating Recommendations. A NERC Operating Requirement is a written statement,duly adopted under the NERC Operating committee voting procedures,that describes the obligations of a control area and systemsfunctioningasapartofacontrolarea.An Operating Requirement may also specify whether there will be monitoring for compliance. A NERC Operating Recommendation isa written informational statement,duly adopted undertheNERCOperatingCommitteevotingprocedures,describing good operating practices.Theapplicationofrecommendationsmayvaryamongcontrolareastocoverlocalconditionsand individual system characteristics. The Guides are organized the same as the Criteria.A Criteria reference statement,extracted from the Reliability Criteria for Interconnected Systems Operation,is found at the beginning of each Guide subsection.Requirements,Recommendations,and Background categories are also included in each Guide subsection.A glossary of terms precedes the Guides;an appendix and revision procedure follow the Guides. Refer to the Reliability Criteria for Interconnected Systems Operation for complete set of Criteria statements. ALASKA TIE Approved NERC Revised =,/23/9z_ ?f omfo',¢ "omALASKA INTERTIE TERMS USED IN THE GUIDES Adequate Regulating Margin - The minimum on-line capacity that can be increased or decreased to allow the system to respond to all reasonable demand changes in order to be in compliance with the Control Performance Criteria. Adjacent Systemor Adjacent Control Area - Any system or control area either directly interconnected with,or affected by schedules ormeteringof,another system or control area. Area Control Error (ACE)- The instantaneous difference between actual and scheduled interchange,taking into account the effects of frequency bias (and time error or unilateral inadvertent if automatic correctionforeitherispartofthesystem's AGC). Automatic Generation Control (AGC)- Equipment which automatically adjusts a control area's generation from a central location to maintain its interchange schedule plus frequency bias. Bulk Electric System - The aggregate of electric generating plants,transmission lines,and related equipment.The term may refer to those facilities within one electric utility,or within a group of utilities in which the transmission lines are interconnected. Capacity Emergency - A capacity emergency exists when a system's or poo!'s operating capacity,plus firm purchases from the Interconnection,to the extent available or limited by transfer capability,are inadequate to mect its demand plus its regulating requirements. Comtrol Area - A system capable of regulating its generation in order to maintain its interchange schedule with other systems and contribute its frequency bias obligation to the Interconnection. Demand - The rate at which energy is being used by the customer. Disturbance - 1.Any perturbation to the electric system. 2.The unexpected change in ACE that exceeds three times L.d which is caused by the sudden loss of generation or interruption of load. Dynamics Schedule - A schedule that is continuously adjusted in real time to match an actual interchange. Commonly used for "scheduling'generation from another control area. ALASKA IE ApprovedNERCRevised ¢ifes[ee. TERMS USED IN THE GUIDES ALASKA INTERTIE Energy Emergency - An energy emergency exists when a system or pool does not have an adequate fuel supply (including water for hydro units)to provide its customer's expected energy requirement over a given period. Frequency Blas - A value,in MW/0.1 Hz,set into a control area's AGC equipment to represent a control area's response to frequency deviation from scheduled frequency,and to separate internal load/generation unbalance from external unbalance so that a control area may regulate its own load while contributing to Interconnection frequency regulation. Hourly Value - Data measured on a clock-hour basis. inadvertent interchange - The difference between the control are's net actual interchange and net scheduled interchange. Interconnection - When capitalized,any one of the four bulk electric system networks in North America: Eastern,Western,Texas,and Quebec.When not capitalized,the facilities that connect two systems or control areas. interruptable Load - Demand that can be interrupted by the supplying system in accordance with contractual provisions. Load - The amount of electric power delivered or required at any specified point or points on a system. Leap Second - A second of time added occasionally by the National Bureau of Standards to correct for the offset between the clock-hour day and the solar day. Metered Value - An electrical quantity measured that may be collected by telemetering SCADA,or other means. Neighboring System - An adjacent system,or system "electrically"close to a utility. Net Energy for Load - Net system generation plus interchange received minus interchange delivered. ALASKA TIE Approved ffNERCRevised'4VA 5 fee.oo. TERMS USED IN THE GUIDES ALASKA INTERTIE Non-spinning Reserve-That operating reserve not connected to the system but capable of serving demand within aspecifiedtime,or interruptable load that can be removed from the system in specified time. Operating Reserve- That capability above firm system demand required to provide for regulation,load forecasting error,equipment forced and scheduled outages and local area protection.It consists of spinning and non-spinning reserve. Region - One of the NERC Regional Reliability Councils. Subregion - A portion of a Region. SupervisoryContro!l and Data Acquisition (SCADA)-A system of remote control and telemetry used to monitor and control the transmission system. Special Protection System - A protection system designed to perform functions other than the isolation of electrical faults. Also called "remedial action scheme". Spinning Reserve- Unloaded generation which is synchronized and ready to serve additional demand. Station Service-The electric supply for the ancillary equipment used to operate a generating station or substation. Station Service Generator - A generator (usually found in hydro plants)used to supply electric energy for station service equipment. System - A combination of generation,transmission,and distribution components comprising an electric utility,or group of utilities. System Operator - A person who operates the electric system. ALASKA TIE ApprovedNERCRevised 3/92. 2ee=eeALASKA INTERTIE GUIDE |.SYSTEMS CONTROL A.GENERATION CONTROL Criteria Reference Requirements 1.Automatic Generation Control (AGC)shall compare total net actual interchange to total net scheduled interchange plus frequency bias contribution to determine the control area's Area Contro!Error (ACE),and respond to return the ACE to zero. 2.+'Each control area shal]maintain generating regulating capability,synchronized to theInterconnection,that can be increased or decreased by AGC to provide for adequate system regulation and Control Performance. 3.Each control area shall operate its AGC on tie-line frequency bias,unless such operation is adverse to system or Interconnection reliability.The requirements for tie-line bias contro] follow: 3.1.-The control area shall set its frequency bias (expressed in MW/0.1 Hz)as close as practical to the control area's frequency response characteristic.Frequency bias may be calculated several ways: 3.1.1.A fixed frequency bias value may be used which is based on a fixed, straight-line function of tie-line deviation versus frequency deviation. The fixed value shall be determined by observing and averaging the frequency response characteristic for several disturbances during on-peakhours., 3.1.2.A variable (linear or non-linear)bias value may be used which is based on a variable function of tie-line deviation to frequency deviation.The variable frequency bias value shall be determined by analyzing frequency response as it varies with factors such as load,generation,governor characteristics,and frequency. 3.2.The Performance Subcommittee shall set demonstration and performance standards for whichever frequency bias method is used. 3.2.1.In no case shall the monthly average frequency bias be less than 1%of the control area's estimated yearly peak demand per 0.1 Hz change as described in the Control Performance Criteria Training Document. 3.3.Each control area must be able to demonstrate and verify to the Performance ALASKA E Approved NERC olde Revised___. GUIDE 1.SYSTEMS CONTROL ALASKA INTERTIE A.GENERATION CONTROL Subcommittee that its frequency bias setting closely matches its system response. 3.4.Each contro]area shall review its frequency bias settings by January 1 of each year and recalculate its setting to reflect any change in area frequency response characteristic. 3.4.1,The bias setting,and the method used to determine the setting,may be changed whenever any of the factors used to determine the current bias value change. 3.4.2,Each control area shall report its frequency bias setting,and method fordeterminingthatsetting,to the Performance Subcommittee. Recommendations 1.AGC should remain in operation as much of the time as possible. 2 AGC may be suspended at frequencies above 60.2 Hz or below 59.8 Hz if continued control would result in generation changes that could endanger system reliability. 3.Turbine governors and control systems,including AGC,and HVDC control systems should be checked periodically to verify their correct operation. 4.Turbine governors and HVDC controls,where applicable,should be allowed to respond to system frequency deviation,unless there is a temporary operating problem. 5.The utility should establish normal and emergency rates of response for each generator andHVDCterminal. 6. Load-limiting devices should be applied only to restrict the extent of load change which might have an adverse effect on the generator or jeopardize transmission security. 7.Regulating margin should be distributed over as many units as possible. 8 Each control area should plan for future adequate contro!performance to meet expected changes in load characteristics and daily load patterns. 9.All generating units of consequential size should be equipped with AGC to ensure that the contro]area can continuously balance its generation with its demand plus net scheduledinterchange. Background Accurate and adequate generator control helps reduce time error,frequency deviations,and inadvertent interchange within the Interconnection. NERC -l2-Revised 2 GUIDE |.SYSTEMS CONTROL ALASKA INTERTIE A.GENERATION CONTROL Each control area will respond to frequency deviations according to its system response characteristic.Most of this response will be reflected in the control area's net tie flow to the Interconnection.By monitoring the interchange deviation from schedule,the frequency deviationfromschedule,and by using the control area's frequency response characteristic,the control area, through its AGC,can determine whether the imbalance in load and generation is internal or external to its control area.If internal,the AGC will adjust the generation to correct the imbalance.If external,no AGC action should occur;however,the system frequency response to the deviation should be allowed to continue until the external system with the generation surplus or deficiency corrects its imbalance and returns the frequency to schedule.Until actual system response can be continuously measured,it must be estimated.This estimate is the tie-line frequency bias setting.The closer the tie-line frequency bias matches the actual system frequency response,the better the AGC will be able to distinguish internal and external imbalances and reduce the number of unnecessary control actions.Therefore,the basic requirement of tie-line frequency bias is that it match the actual system response as closely as practicable. 8.VOLTAGE CONTROL Criteria Reference Requirements 1.Devices used to regulate transmission voltage and reactive flow shall be available for use by the system operator. 2.System operators shall monitor transmission system voltage for deviation from prearranged voltage levels and take corrective action to keep voltages within allowable limits. 2.1.Prearranged voltage levels,reactive control equipment settings,and changes in transmission configuration shall.be coordinated with neighboring systems. 2.2.Transfer or interchange limits shall reflect voltage or reactive restrictions. 2.3.System operators shall monitor and keep reactive power flow within established limits on tie-lines. Recommendations 1.'Important transmission lines should be kept in service during light-load periods as much as possible.They should be removed from service for voltage control measure.only after all reactive control measures are fully implemented and appropriate studies indicate that system _ reliability will not be degraded below acceptable levels.( ALASKA E ApprovedNERC-13-Revised GUIDE 1.SYSTEMS CONTROL ALASKA INTERTIE VOLTAGE CONTROL Automatic voltage regulators and power system stabilizers on generators and synchronous condensers should be kept in service as much of the time as possible. Devices used to regulate transmission voltage and reactive flow should be switchable without deenergizing other facilities. When a generator's automatic voltage regulator is out of service,field excitation should bemaintainedataleveladequateforstableoperation. Systems with dc transmission facilities should utilize reactive capabilities of converter terminal equipment for voltage control. TIME AND FREQUENCY CONTROL Criteria Reference Each Interconnection shall designate an Interconnection Monitor who shall monitor time error and shall initiate or terminate corrective action orders.when time error reaches predetermined limits as shown in Appendix LC. Time error corrections shall start and end on the hour or half-hour,and notice shall be given at least twenty minutes before the time error correction is to start or stop. Time error correction notifications shall be serialized alphabetically on a monthly basis. The time error correction offset shall be applied by either of the following two methods: 4.1.The frequency schedule may be offset by 0.02 Hz,leaving the bias setting normal,or 4.2.If the control frequency base setting cannot be offset,the Net Interchange schedule (MW)may be offset by an amount equal to the computed bias contribution during a 0.02 Hz frequency deviation (Le.,20%of the frequency bias setting). NERC lL4-Revised 2 GUIDE |.SYSTEMS CONTROL ALASKA INTERTIE C.TIME AND FREQUENCY CONTROL 5.A Regional Monitor shall be designated through which time error correction notifications originating with the Interconnection Monitor will be routed to each system in the Region by way of established Time Notification Channels. 6.The Interconnection Monitor shall periodically issue a notification of time error,accurate towithin0.1 second,to the Regional Monitors to assure uniform calibration of time standards. 7.Using the Time Notification Channels,the Regional Monitors shall,each hour,on the hour,notify all systems within their respective Regions of the accumulated time error within 0.1second.Time error notification shall be accompanied by the alphabetic designator if a time error correction is in progress. 8.Each control area shall at least annually check and calibrate its time error and frequency devices against a common reference. 9.|When one or more control areas has been separated from the Interconnection,uponreconnection,they shall adjust their time error devices to coincide with the Interconnection by one of the following methods: 9.1.Before connection,the separated area may institute a Time Error Correction Procedure to correct its accumulated time error to coincide with the indicated time error of the Interconnection Monitor,or , 9.2.After interconnection,the time error devices of the previously separated area may be recalibrated to coincide with the indicated time error of the Interconnection Monitor. A notification of adjusted time error shall be passed through Time Notification Channels as soon as possible after interconnection. 10.Standards of allowable time error are found in Appendix Lc. Recommendations 1.The control areas of an Interconnection may implement automatic time error control as a part of their AGC scheme. 1.1.If automatic time error correction is used,all control areas of the Interconnection should participate. 12.Automatic time error contro!should be suspended whenever an announced time correction is in progress. 2 Systems using time error devices that are not capable of automatically adjusting for leap- seconds should arrange to reccive advance notice of the leap-second and make the necessary manual adjustment in a manner that will not introduce a disturbance into their control system. NERC o15-Revised 2 GUIDE 1.SYSTEMS CONTROL ALASKA INTERTIE C.TIME AND FREQUENCY CONTROL Background The difference between load and generation resultsin frequency deviations from 60 Hz,andtheintegrateddeviationappearsasadeparturefromcorrecttime. The satisfactory operation of the Interconnected systems is dependent,in part,upon accurate frequency transducers and recorders and time error devices associated with AGC equipment. D.INTERCHANGE SCHEDULING 'Criteria Reference NERC AB.Revised 2. GUIDE i.SYSTEMS CONTROL ALASKA INTERTIE INTERCHANGE SCHEDULING Requirements 1.Interchange shall be scheduled only between control areas having directly connecting facilities in service unless there is a contract or mutual agreement with other control areas to provide connecting facilities. Interchange schedules or schedule changes shall not cause any other system to violate established reliability criteria. 21.When control areas are connected so that paralle]flows present reliability issues,the combinations of control areas shall develop multi-control area interchange monitoring techniques and pre-determined corrective actions to mitigate or alleviate potential or actual transmission system overloads. 2.2.Transfer limits shal!be reevaluated and interchange schedules adjusted as soon aspracticableiftransmissionfacilitiesbecomeoverloadedorareoutofservice,or when changes are made to the bulk system which can affect these limits. The maximum net scheduled interchange between two control areas shal]not exceed the lesser of two values: 3.1.The total capacity of the transmission facilities in service between the two control areas owned by them or available to them under specific arrangements,contracts,or mutual agreements,or 3.2.The mutually established First Contingency Total Transfer Capability of the two controlareasconsideringothertransmissionfacilitiesavailabletothemunderspecificatrangements.First Contingency Total Transfer Capabilityis definedin Appendix LD.,Transfer Capability,A Reference Document,NERC October 1980 The sending,contract intermediary,and receiving contro!areas that are parties to ainterchangetransactionshallagreeonthefollowing: 4.1.The schedule's magnitude,starting and ending times. 4.2,The schedule's magnitude and rate of change shall be equal and opposite and not exceed the ability of the systems to effect the change. 4.3.The scheduled generation in one control area that is delivered to another control area must be scheduled with all intermediate control areas unless there is a contract or mutual agreement among the sending,contract intermediary,and receiving control areas to do otherwise. Control areas shall develop procedures to disseminate information on interchange schedules and facilities out of service which may have an adverse effect on other control areas not involved in the scheduled interchange and the involved parties shall predetermine schedule priorities, which will be used if a schedule reduction becomes necessary. ALASKA E ApprovedNERC"17-Revised_)/23/62. GUIDE 1.SYSTEMS CONTROL ALASKA INTERTIE D.INTERCHANGE SCHEDULING ; Background Scheduled interchange must be coordinated between control areas to prevent frequencydeviationsandaccumulationsofinadvertentinterchange,and prevent exceeding mutually established transfer limits. E.CONTROL PERFORMANCE CRITERIA Criteria Reference Requirements 1.'Two criteria shall be used to continually monitor control performance during normal conditions (See the "Control Performance Criteria Training Document,"Section 2.1): 1.1.Al Criteria -The ACE most return to zero within ten minutes of previously reaching zero.Violations of this criteria count for each subsequent ten-minute period that the ACE fails to return to zero. 1.2. <A2 Criteria -The average ACE for each of the 6 ten-minute periods during the hour (ie.,for the ten-minute periods ending at 10,20,30,40,50,and 60 minutes past the hour)must be within specific limits,referred to as L,,that are determined from thecontrolarea's rate of change of demand characteristics.See the "Control Performance Criteria Training Document,”Section 2.1.2.1 for the methods for calculating L,. 2.Two criteria shall be used to continually monitor control performance during disturbance conditions (See the "Contro!Performance Criteria Training Document,"Section 2.2): 2.1.Bi Criteria -The ACE must return to zero within ten minutes following the start of the disturbance. 2.2.§B2 Criteria -The ACE must start to return to zero within one minute following the start of the disturbance. 3.The ACE used to determine compliance to the Control Performance Criteria shall reflect its actual value,and exclude short excursions due to transient telemetering problems or other influences such as contro!algorithm action. 4._All control areas shall respond to control performance surveys that are requested by thePerformanceSubcommittee. NERC L8-Revised 2 GUIDE i.SYSTEMS CONTROL ALASKA INTERTIE E.CONTROL PERFORMANCE CRITERIA Recommendations 1.Each control area should be in compliance with the Al and A2 Criteria at least 90%of the time. Background Control performance is the degree to which a control area matches its generation to its demandplusscheduledinterchangetakingintoaccounttheeffectsoffrequencybias.The NERC Operating Committee has established the Control Performance Criteria (CPC)which include standards of acceptable control performance.The CPC establish minimum standards for control performance andprovideameansformeasuringtherelativecontrolperformanceofeachcontrolarea.While these standards define the minimum acceptable performance,each contro!area shal]meet and strive to exceed these standards. F.INADVERTENT INTERCHANGE MANAGEMENT Crnteria Reference 1.Inadvertent interchange shall be calculated and recorded hourly and may accumulate as a credit or debit to the control area.(See the Inadvertent Interchange Accounting Training Document.) 2.All interconnections shall be included in the inadvertent interchange account.Interchange served through jointly owned facilities and interchange with borderline customers must be properly taken into account. 3.Inadvertent interchange accumulations shall be paid back by one or both of the following methods: 3.1.Method 1 -Inadvertent interchange accumulations may be paid back by scheduling interchange with another control area. 3.1.1.The other contro]area must have an inadvertent accumulation in the opposite direction. NERC eL.9-Revised z GUIDE i.SYSTEMS CONTROL ALASKA INTERTIE F.INADVERTENT INTERCHANGE MANAGEMENT 3.1.2.The amount of inadvertent payback scheduled shall be agreed upon by all involved systems. 3.2.Method 2 Inadvertent interchange accumulations may be paid back unilaterally by offsetting tie-line schedule when such action will aid in correcting the existing time error. 3.2.1.If time is slow and there is a negative accumulation (undergeneration),the AGC may be offset to overgenerate and pay back inadvertent interchange accumulation and reduce time error. 3.2.2.If time is fast and there is a positive accumulation (overgeneration),the AGC may be offset to undergenerate and pay back inadvertent interchange accumulation and reduce time error. 3.2.3.AGC offset may be made by either offsetting the frequency schedule up to 0.02 Hz,leaving the bias setting normal or offsetting the net tie-line schedule by up to 20%of the control area's bias or 5 MW,whichever is greater. 3.2.4.Inadvertent payback shall end when either the time error is zero or has changed signs,the accumulation of inadvertent interchange has been corrected to zero,or a scheduled time error correction begins,which takes precedence over offsetting frequency schedule to pay back inadvertent. 3.2.5.Control areas within Interconnections using automatic time error control techniques shall not use Method 2 to reduce their accumulations of inadvertent.Method 1 is the only acceptable way for these contro!areas to manually reduce their accumulations of inadvertent.... 4.Inadvertent interchange accumulated during "on-peak"hours shall be paid back during "on-peak"hours.Inadvertent interchange accumulated during "off-peak”hours shall be paidbackduring"off-peak"hours. 5.Each control area shall submit a monthly summary of inadvertent interchange as detailed in Appendix LF.,"Inadvertent Interchange Energy Accounting Practices.° 5.1.Inadvertent interchange summaries shall include at least the previous accumulation,net accumulation for the month,and final net accumulation,for both the "on-peak"and "off-peak"periods. 5.2.Each control area shall submit its monthly summary report to its Performance Subcommittee representative who will prepare a composite tabulation for distribution to all other Performance Subcommittee representatives. 5.3.Each Performance Subcommittee representative shall distribute summaries to their respective control areas as agreed upon. NERC =L.10-Revised 2 GUIDE |.SYSTEMS CONTROL ALASKA INTERTIE F. {§NADVERTENT INTERCHANGE MANAGEMENT Background Inadvertent interchange is the difference between the control area's net actual interchange and net scheduled interchange.The major cause of intentional inadvertent interchange is the bias response to frequency deviations occurring on the Interconnection.Causes of unintentional inadvertent interchange are instrument and contro]errors,improper control settings,generator response time,fluctuations in demand,etc. G.CONTROL SURVEYS Criterla Reference Requirements 1.Each Interconnection shall perform each of the following surveys,as described in the Control Performance Criteria Training Document,when called for by the Performance Subcommittee:71.1.Area Control Error survey to determine the contro!areas'interchange error(s)due to (-:equipment failures or improper scheduling operations,or improper AGC performance. 1.2,Area Frequency Response Characteristic survey to determine the control areas'response to changes in system frequency. 1.3.Control Performance Criteria survey to monitor the contro]areas'control performance during normal and disturbance situations. 2.The survey results will be reviewed by the Performance Subcommittee at each regular meeting, and by the Operating Committee as necessary,and distributed to all control areas and other appropriate parties in NERC. H.CONTROL EQUIPMENT REQUIREMENTS Criteria Reference NERC oLt1-Revised 2 GUIDE |.SYSTEMS CONTROL ALASKA INTERTIE 1,Each control area shall perform hourly control error checks using tie line MWh meters to determine the accuracy of its control equipment. 2.The system operator shall adjust control settings to compensate for any equipment error untilrepairscanbemade. 3.All tie-line flows between contro]areas shall be included in each control area's ACE calculation. 4.System operators shall be provided with a recording of those variables necessary to facilitate monitoring of control performance,generation response,and after-the-fact analysis of area performance.Asa minimum,area control error (ACE),system frequency,and net tie-line interchange data shall be continuously recorded. Recommendations 1.Adequate and reliable backup power supplies should be provided and periodically tested at the system control center and other critical locations to ensure continuous operation of AGC and vita]data recording equipment during loss of the normal power supply. 2.-Aill tie-line MW and MWH/Hr telemetry should be telemetered to both control centers,and should emanate from a common,agreed upon terminal psing common primary metering equipment. NERC el.12-Revised = Alaskan Intertie Unit Loss/Underfrequency Relay Operation SUMMARY SHEET Day/Date:Temp: Time: Brief Description of Event: UNIT _LOSS |UF_RELAY OPERATIONUnitLineBeforeAfterSub/FOR or B8KR MW Shed b|ist 59.2 2 Ml 3 u 4 2nd $8.8 &5 |6 7 3r@d_58.5 e |BELL |ist $9.2 2 3 4 5 6 7 |2nd_$9.0 ¢8 BL 1 2 3 3rd é [en __2.4th Er _2 3 2 /-LLL MMELLLLL Lee {WP}--|_ist $9.3 G 2 Viae t 2nd 59.2 risa 4 2 lard 59.3 Cnl2 lse $9.1 4 u 5 gs § BRADLEY?REA .ye Pyrs. Alaskan Intertie Transmission Line or Equipment Loss Report Line SectionLost Voltage HLEP: CEA: INTERTIE: BEAs BRADLEY LAKE: ALASKA INTERTIE OPERATING GUIDE NO.1 APPENDIX C ME ERROR RECTION PROCEDU INITIATION TERMINATION TIME ERROR-SECONDS TIME ERROR-SECONDS TIME -TIME OF ALASKA ALASKA CORRECTION _INITIAITON INTERTIE INTERTIE --ON DAYS HAVING PEAK PERIOD -- Slow Any +2 +1 Fast Any +2 +.1 **NOTE. The Interconnection Monitor may postpone or cancel a time correction if requested to do so by regions or systems comprising 30 percent or more of the total frequency bias in the interconnected area,or if warranted by the overall capacity situation. ALASKA TIE ApprovedNERC1Revised.,43f/ze 7 7 Pomme)ALASKA INTERTIE APPENDIX LF.INADVERTENT INTERCHANGE ENERGY ACCOUNTING PRACTICES A.INTRODUCTION These uniform accounting practices will provide 2 method for isolating and eliminating the source of accounting errors and aid in identifying the poor control performance that contributes to inadvertent interchange accumulations. B.RELATIONSHIP TO NERC REQUIREMENTS These practices outline the methods and procedures required to reconcile energy accounting and inadvertent interchange balances. In order for a control area to properly monitor and account for inadvertent interchange,the Reliability Criteria for Interconnected Systems Operation and the Operating Guides must be adhered to. These practices do not supercede any provisions in the NERC Operating Manual.The intentistobringtheseveralitemstogetherintoonedocument. C.SCHEDULES All hourly schedules and schedule changes shall be agreed upon between control areas involved prior to implementation in regard to magnitude,rate of change and common starting time. 1.Dynamic schedules integrated on an hourly basis shall be agreed upon by the control areasinvolvedsubsequenttothehour,but in such a manner as not to impact inadvertent accounts. D.ACCOUNTING PROCEDURES 1.Daily accounting -Each control area shall agree with adjacent control areas upon thefollowingquantitiesatleastonceeachday: 1.1.Scheduled interchange (MWh). 12.Actual interchange (MWh). 13.Totals during each day for on-peak and off-peak periods. 2.Monthly accounting -Having agreed on the on-peak and off-peak period scheduled and actual interchange each day,adjacent control areas shall verify that the accumulated values for the month balance. E.ADJUSTMENTS FOR ERROR 1.Periodic adjustments shall be made to correct for differences between hourly MWh metertotalsandthetotalsderivedfromregisterreadingsofthetic-line meters. ALASKA E ApprovedNERC-1-Revised ge beAPPENDIX LF.INADVERTENT INTERCHANGE ENERGY ALASKA INTERTIE ACCOUNTING PRACTICES 2.Adjacent contro!areas shall agree upon the difference determined above and assign this correction to the proper on-peak and off-peak period at the same times and in equal quantities in the opposite directions. 3.Any adjustments necessary due to known metering errors,franchised territories,transmission losses or other special circumstances shall be made in the same manner. APPENDIX LF.INADVERTENT INTERCHANGE ENERGY ALASKA INTERTIE NERC ACCOUNTING PRACTICES ON-PEAK AND OFF-PEAK PERIODS Aditional off-Peak days New Year's Day January 1 Memorial Day Last Monday of May Independence Day July 4 Labor Day First Monday of September Thanksgiving Day Fourth Thursday of November Chrisunas Day December 25 Daylight Saving Time Daylight Saving Time begins on first Sunday of April and ends on last Sunday of October. 11 On peak period HEO700-HE2300 for winter/summer seasons. ALASKA TIE Approved 3 Revised z GUIDEIL SYSTEM SECURITY ALASKAINTERTIE ALASKAINTERTIE GUIDEIL SYSTEMS SECURITY A.REALPOWER (MW)SUPPLY Criteria Reference 1 area shall i Ww rovi level reserve sufficient to account for such factors as errors in forecasting,peneration and transmission equipment wnavailability,number and si erati ni stem equipment for inten dule lating requirements,and regional 1 diversity. Following loss of resources or load,a control areg shall take appropriate steps to reduce its AreantrolErrortozerowithin10minuItshalltakepromptsteitselinstthe next contingency. h Region or Subregion ll_spectfy its operating re licies,including its allocarion among members,the permissible mix of spinning and nonspinning reserve,and procedure for j ing reservein i the limitations,if any,upon th Requirements 1.The system operator shall be kept informed of all generation and transmission resources ; available for use.(sy 2.The system operator shall have information,including weather forecasts and past load patterns,available to predict the system's near-term load pattern. 3.Each Region or Subregion shall provide,as a minimum,operating reserve as follows: 3.1 Operating reserves which include both spinning and nonspinning must equal 150%of interconnected system's largest single contingency. 3.2.An amount of spinning reserve,responsive to AGC,which is sufficient to provide normal regulating margin,plus as an additional amount equal to the loss of generation that would result from the most severe single contingency. 3.2.1 Interruptible load may be considered spinning reserve provided that it can be automatically interrupted. 3.3 Operating reserves that are nonspinning must be capable of being made effective within 45 minutes. 3.4 An additional amount of reserve shall be made available as soon as practicable to aid in reestablishing this minimum operating reserve after such reserve has been used. A I ASKA Meena Approved NERC -IL1-Revised GUIDEIL SYSTEM SECURITY ALASKAINTERTIE A.REALPOWER (MW)SUPPLY 4.Operating reserve shall be dispersed throughout the system and shall consider the effective .use of capacity in an emergency,time required to be effective,transmission limitations,and local area requirements. 5.All Regions,Subregions,and control areas shall frequently review probable contingencies to determine the adequacy of operating reserve. Recommendations 1.The effect of station service generators on area security should be considered before they are shut down for economy. B.REACTIVE POWER (MVAR)SUPPLY Criteria Reference ch control ar I vide for }i iy wer requir n 1 appropriater rote vol levels for contingency conditi is i des th Requirements 1.The system operator shall be provided information on all available generation and transmission reactive power resources. 2.Reactive sources shall be operated so that scheduled voltages are maintained for all normal and first contingency conditions. 3.Reactive reserve shall be dispersed and located electrically so that it can be applied effectively and quickly when contingencies occur. 4.Prompt Action shall be taken to restore reactive resources if they drop below acceptable levels. 5.System operators shall take corrective action,including load reduction,necessary to prevent voltage collapse when reactive resources are insufficient. Recommendations 1.Reactive reserves should be automatically applied in the event of an emergency. NERC -IL2-Revised 2 meGUIDE Il.SYSTEM SECURITY ALASKA INTERTIE B.REACTIVE POWER (MVAR)SUPPLY 2.Surveys to determine compliance with voltage and reactive guidelines should be made on a regular basis.. 3.Reactive reserve should be carried by rotating machinery and static var compensators which scan be applied automatically when contingencies occur. C.'TRANSMISSION OPERATION Criteria Reference Ts Requirements 1.The system operator shall monitor all critical transmission system parameters including compliance with normal and emergency ratings and voltage limits. 2.Scheduled transmission outages shall be coordinated with known systems that may be affected. 3.Forced transmission outages shall be communicated to any systems that may be affected. 3.1.Forced outages of key transmission facilities shall be communicated to all adjacent systems as expeditiously as possible,thereby increasing the ability to detect acts of multi-site sabotage.If multi-site sabotage activity is suspected,interregional telecommunications shal!be initiated for further detection. 4.Each control area shall use appropriate,up-to-date studies as a reference for establishing transmission operation procedures. Recommendations 1.Important transmission lines should be kept in service during light-load periods as much as possible.They should be removed from service for voltage control measure only after all other reactive contro]measures are fully implemented and appropriate studies indicate that system reliability will not be degraded below acceptable levels. ALASKA ! ApprovedNERC-113-Revised z GUIDE ll.SYSTEM SECURITY ALASKA INTERTIE D.RELAY COORDINATION Criteria Reference Requirements 1.Appropriate technical information concerning protective relays shall be available in each system control center. 2.'System operators shall be familiar with the purpose and limitations of protection system schemes, 3.If a protective relay or equipment failure reduces system reliability,the proper personnel shall be notified,and corrective action shall be undertaken as soon as possible. 4.All new protective systems and all protective system changes shall be coordinated among neighboring systems if the new and changed protective systems affect neighboring systems. 5.Protection systems on major transmission lines and interconnections should be coordinated with the interconnected systems. 6.Neighboring systems shall be notified in advance of changes in generating sources, transmission,load,or operating conditions which could require changes in their protection system. 7.The system operator shall monitor the status of each Special Protection System (SPS)and notify all affected systems of each change in status. Recommendations 1._-' Protection system design and operations should consider the following: 1.1 =Protection systems should be of minimum complerity consistent with achieving their purpose. 12 Protection systems should have redundancy to allow for their norma!maintenance and calibration. 1.3 Protection systems should not normally operate for minor system disturbances,brief overloads,or recoverable system power swings. ALASKA !{ Approved NERC oll A-Revised 2 GUIDE Il. D.RELAY 1.8 SYSTEM SECURITY ALASKA INTERTIE COORDINATION High-speed relays,high-speed circuit breakers,and automatic reclosing should be used where studies indicate the application will enhance stability margins.Single- pole tripping or reclosing may be appropriate on some lines. Automatic reclosing during out-of-step conditions should be prevented. Underfrequency load shedding relays should be coordinated with the generating plant off-frequency relays to assure preservation of system stability and integrity. Protection system applications,settings,and coordination should be reviewed periodically and whenever major changes in generating resources,transmission,load or operating conditions are anticipated. Adequacy of protection system communications channels should be reviewed periodically.Automated channel monitoring and failure alarms should be provided for protective system communications channels which could cause loss of generation, loss of load,or cascading outages in the event of misoperation or failure. Each system should implement protection system application,operation,and preventive maintenance procedures which will enhance their system reliability with the least adverse effect on the Interconnection.These protection system procedures should be provided to all appropriate system personnel and should provide for instruction and training where applicable.Each system should coordinate these procedures with any other systems that could be affected.These procedures should govern: 2.1 2.2 2.3 2.4 2.5 Planning and application of protection systems. Review of protection systems and settings. Intended functioning of protection systems under normal,abnormal,and emergency conditions. Regularly scheduled testing and preventive maintenance of relays,vital system protection equipment,and associated components. 2.4.1 The operation of the complete protection system should be tested under conditions as close to actual operating conditions as possible,including actual circuit breaker operation where feasible. 2.4.2 Testing protection system communication channels between systems should be coordinated with test results recorded.: Analysis of actual protection system operations. 3.A prompt investigation should be made to determine the cause of abnormal!protection system performance and correct any deficiencies in the protection scheme.- NERC ALASKA | Approved-IL5-Revised z () GUIDE il.SYSTEM SECURITY ALASKA INTERTIE D.RELAY COORDINATION 4.The system operator shall monitor the status of each Special Protection System (SPS)and notify all affected systems of any changes in status. 5.SPS should be designed for periodic testing without affecting the integrity of the protected power system.They should normally achieve at least the same high level of reliability as that provided by normal protection systems. 6.SPS should be designed with inherent security to minimize the probability of an improper operation,even with the failure of a primary component. 7.Each SPS should be reviewed frequently to determine if it is still required and will stil! perform the intended functions.Seasonal changes in power transfers may require changes in the SPS or its relay settings. 8 Each SPS operation should be reviewed and analyzed for correctness. 9.Prompt action should be taken to correct the causes of an improper operation. Background Protection systems greatly influence the operation of interconnected systems,especially under abnormal conditions.Protection systems used on tie points between interconnected systems for generator tripping and other remedial measures are of primary concern to the respective systems.However,internal system protection often directly,or indirectly,affects adjacent systems. Special Protection Systems,also known as Remedial Action Schemes,are relay configurations designed to perform functions other than isolation of electrical faults.These systems are usually instalied to maximize transfer capability.However,they may be used tomaintainsystemorunitstabilityortocontrolpowerandreactiveflowsoncriticalfacilitiesimmediatelyfollowingadisturbanceonasystem,or to separate a system or interconnection atpreplannedlocationstopreventcascading.The general design objective for any SPS shall be to perform its intended function in a dependable manner while refraining from unnecessary operation.An SPS can expose a system to greater reliability risk.The integrity of the powersystemmaydependonitscorrectoperation. E.BONITORING INTERCONNECTION PARAMETERS Criteria Reference NERC .oll.S-Revised 2. GUIDE Ul.SYSTEM SECURITY ALASKA INTERTIE E.SONITORING INTERCONNECTION PARAMETERS Requirements 1.Monitoring equipment shall be used to bring to the system operator's attention importantdeviationsinoperatingconditionsandtoindicate,if appropriate,the need for corrective action. 2.Each control area shall use sufficient metering of suitable range,accuracy and sampling rateGfapplicable)to ensure accurate and timely monitoring of operating conditions under bothnormalandemergencysituations. 3.System operators shall monitor transmission line status,MW and Mvar flows,voltage,LTC settings and status of rotating and static reactive resources. 4.System operators shall monitor system frequency. Recommendations 1._--'Reliable instrumentation,including voltage and frequency meters with sufficient range tocoverprobablecontingencies,should be available in each generating plant control room. 2.Automatic oscillographs and other recording devices should be installed at key locations and set to standard time to aid in post-disturbance analysis. 3.Because of possible system separation,frequency information from selected locations shouldbemonitoredatthecontrolcenter. 4.Monitoring should be sufficient,so that in the event of system separation,both the existence of the separation and the boundaries of the separated areas can be determined. 5.Transmission line monitoring should include a means of evaluating the effects of the loss of any significant transmission or generation facilities,both within and outside the control area. 6.Where practical,critical unmanned facilities should be monitored for physical security. 7.Scheduled outages of generation or transmission facilities should be considered in the monitoring scheme. 8.Voltage schedules should be coordinated from a central location within each control area and coordinated with adjacent control areas. Background The system operator must have information available to them at all times so that they can accurately picture the system under normal operating conditions,make effective decisionsfollowingtheoccurrenceofacontingency,and properly restore system integrity following adisturbance. . ALASKA | ApprovedNEAColll.7-Revised 2 (%.. are GUIDE il.SYSTEM SECURITY ALASKA INTERTIE E MONITORING INTERCONNECTION PARAMETERS INFORMATION EXCHANGE -SYSTEM CONDITIONS Requirements Each control area shal!disseminate information on actual and scheduled interchange, voltages,and facilities out of service which may have an adverse effect on other control areas. 1.System operators shall notify other systems of current or foreseen operating conditions which may affect interconnection reliability.Examples of operating conditions that may affect reliability are:critically loaded facilities,scheduled and forced equipment outages, new facilities,abnormal voltage conditions,new or degraded protective systems,acts of God (severe weather,fire,earthquake),and new or degraded communications, Recommendations 1.To assure that communication networks are functioning properly and that timely exchange of pertinent operating information is taking place,specific communication monitoring and testing procedures should be developed,documented and exercised between interconnected systems. INFORMATION EXCHANGE -DISTURBANCE REPORTING Requirements Major operating problems that could affect other systems shall be reported as soon as possible to adjacent systems.These operating problems include loss of generation or load or facilities failures. Bulk system disturbances affecting two or more systems shall be promptly analyzed by the affected systems. ALASKA Approved NERC oB-Revised waeeeeweeeweeGUIDEIL SYSTEM SECURITY ALASKAINTERTIE G.INFORMATION EXCHANGE-DISTURBANCE REPORTING 3.Based on the magnitude and duration of the disturbance or unusual occurrence,those systems responsible for investigating the incident shall provide oral,and if appropriate, written reports. 3.1.An oral report shall be made to the systems'power control centers within twenty- four hours after the disturbance.This oral report is in addition to the reporting requirements outlined in the Alaska Intertie Outage Report Instructions. 4.The U.S.Department of Energy's most recent Power System Emergency Reporting Procedures,shown in Appendix IG.are.the minimum requirements for reporting disturbances to NERC. Recommendations 1.If an operating problem cannot be corrected quickly,the probable duration and possible effects should be reported. 2.The system should provide written reports following a disturbance. 2.1 If appropriate,a preliminary written report should be available within several days of the disturbance. 2.2 -«If appropriate,a final written report should be available for review according to system policies. 3.If,in the judgment of the system(s)involved,such an "unusual occurrence”would be of interest to the electric utility industry,the incident should be reported to NERC whether or not it is reported under DOE Reporting Procedures. 4.When there has been a disturbance affecting the bulk system,the Region's OC representatives should make themselves available to the system or systems immediately affected in order to provide any needed assistance in the investigation. 5.Information concerning bulk system disturbances in other parts of the world can be of value in furthering the objectives of NERC.To the extent that relevant information can be obtained,it should be appropriately utilized. Background Other affected sytems must be kept informed of potential or actual operating probiems. Disturbances which result in substantial customer interruptions will attract news media.The event and its causes will also be of considerable interest to the elecric utility industry.It is expected that all systems will keep the IOC advised of potential system problems or actual disturbances.Disturbances will be discussed by the Operating Committee.Each disturbance should be viewed by system operators as a potential learning experience. NERC -IL9-Revised =oo OeewSmweOeOeOeOSCSOFCOBTBEESOHCSBOESOFCOHOMEBOOOSeanowGUIDE ll.SYSTEM SECURITY ALASKA INTERTIE G INFORMATION EXCHANGE --DISTURBANCE REPORTING H.INFORMATION EXCHANGE --SABOTAGE REPORTING Crteria Reference Requirements _ 1.System operators shall be provided with guidelines including lists of utility contact personnel, for reporting disturbances due to sabotage events. 2.Systems shall establish communications contacts with local Federal Bureau of Investigation (FBI)or Royal Canadian Mounted Police (RCMP)officials and develop reporting procedures as appropriate to their circumstances. Recommendations 1.Systems should establish procedures for supplying sabotage-related information to the media. Release of this information must be coordinated with the appropriate FBI or RCMP personnel. Background Prompt notification to other systems,law enforcement agencies,and regulatory bodies following disturbances caused by sabotage is essential in minimizing the adverse effects on the security of the Interconnection. &{MAINTENANCE COORDINATION Crteria Reference Requirements 1.Scheduled generator and transmission outages that may affect the reliability of interconnected operations shall be planned and coordinated among affected systems and control areas. Special attention shall be given to results of pertinent studies. 2.Scheduled outages of system voltage regulating equipment,such as automatic Voltageregulatorsongenerators,supplementary excitation control,synchronous condensers,shunt and series capacitors,reactors,etc.,shall be coordinated as required. ALASKA |!E Approved NERC oIl.10-Revised z GUIDE I.SYSTEM SECURITY ALASKA INTERTIE JZ MAINTENANCE COORDINATION 3.Scheduled outages of telemetering and control equipment and associated communication channels shall be coordinated between the affected areas. ALASKA ! ApprovedNERCoH.14-Revised z. ALASKA INTERTIE APPENDIX It.G. REPORTING REQUIREMENTS FOR MAJOR ELECTRIC UTILITY SYSTEM EMERGENCIES Every electric utility or other entity subject to the provisions of Section 311 of the FederalPowerAct,engaged in the generation,transmission,or distribution of electric energy for delivery and/or sale to the public shall expeditiously report to the U.S.Department of Energy's (DOE) Emergency Operation Center (EOC)any of the events described in the following.(A report or a part of a report required by DOE may be made jointly by two or more entities or by a Regional Council or power pool) A.LOSS OF FIRM SYSTEM LOADS 1.Any load shedding actions resulting in the reduction of over 100 megawatts (MW)of firm customer load for reasons of maintaining the continuity of the bulk electric power supplysystem. 2. Eguipment failures/system operational actions which result in the loss of firm system loads for a period in excess of 15 minutes,as described below: 2.3.Reports from entities with a previous year recorded peak load of over 3,000 MW are required for all such losses of firm loads which total over 300 MW. 2.2.Reports from all other entities are required for all such losses of firm loads which total over 200 MW or 50%of the total customers being supplied immediately prior to the incident,whichever is less. 3.Other events or occurrences which result in a continuous interruption for three hours or longer to over 50,000 customers,or more than 50%of the system load being served immediately prior to the interruption,whichever is less. NOTE:The DOE EOC shall be notified as soon as practicable without unduly interfering withservicerestorationand,in any event,within three hours after the beginning of the interruption. B.VOLTAGE REDUCTIONS OR PUBLIC APPEALS 1.Reports are required for any anticipated or actual system voltage reductions of three percent or greater for purposes of maintaining the continuity of the bulk electric power supply system. 2.Reports are required for any issuance of a public appeal to reduce the use of electricity for purposes of maintaining the continuity of the bulk electric power system. NOTE:The DOE EOC shall be notified as soon 28 practicable,but no later than 24 hours after initiation of the actions described in paragraph 2,above. C.VULNERABILITIES THAT COULD IMPACT BULK ELECTRIC POWER SYSTEM ADEQUACY OR RELIABILITY 1.Reports are required for any actual or suspected act(s)of physical sabotage (not vandalism) ALASKA INTE AppovedNERC"1-Revised 2. APPENDIX ILG.-REPORTING REQUIREMENTS FOR MAJOR ELECTRIC UTILITY SYSTEM EMERGENCIES or terrorism directed at the bulk electric power supply system in an attempt to either: 1.1.Disrupt or degrade the adequacy or service reliability of the bulk electric powersystemsuchthatloadreductionaction(s)or a special operating procedure is or may be needed. 1.2,Disrupt,degrade,or deny bulk electric power service on an extended basis to a specific:(1)facility (industrial,military,governmental,private),(2)service(transportation,communications,national security),or (3)locality (town,city,country).This requirement is intended to include only major events involving the supply of bulk power. D.REPORTS FOR OTHER EMERGENCY CONDITIONS OR ABNORMAL EVENTS 1,Reports are required for any other abnormal emergency system operating conditions or other events which,in the opinion of the reporting entity,could constitute a hazard to maintaining the continuity of the bulk electric power supply system.DOE has a special interest in actual or projected deterioration in bulk power supply adequacy and reliability due to any causes. Events which may result in such deterioration include,but are not necessarily limited to: natural disasters;failure of a large generator or transformer;extended outage of a major transmission line or cable;Federal or state actions with impacts on the bulk electric power system. NOTE:The DOE EOC shall be promptly notified as soon as practicable after the detection of any actual or suspected acts(s)or event(s)directed at increasing the vulnerability of the bulk electric power system.A 24-hour maximum reporting period is specified in the regulations;however, expeditious reporting,especially of sabotage or suspected sabotage activities,is requested. E.FUEL SUPPLY EMERGENCIES 1.Reports are required for any anticipated or existing fuel supply emergency situation which would threaten the continuity of the bulk electric power supply system,such as: 141.Fuel stocks or hydroelectric project water storage levels are at 50%or less of normal for that time of the year,and a continued downward trend is projected. 1.2.Unscheduled emergency generation is dispatched causing an abnormal use of aparticularfueltype,such that the future supply or stocks of that fuel could reach 2 level which threatens the reliability or adequacy of electric service. NOTE:The DOE EOC shall be notified as soon as practicable,or no later than three days after the determination is made. ALASKA INTE AppovedNERC-2-Revised 2 ALASKA INTERTIE GUIDE ill.EMERGENCY OPERATIONS A.INSUFFICIENT GENERATION CAPACITY Crnteria Reference Requirements L Operating agreements between neighboring systems or pools shall contain appropriate provisions for emergency assistance,including provisions to obtain emergency assistance from remote systems or pools. In the event of a capacity deficiency,generation and transmission facilities shall be used to the fullest extent practicable to promptly restore normal system frequency and voltage and return ACE to acceptable performance criteria as defined in Guide LE. 2.1.If automatic generation control (AGC)has become inoperative,manual contro!shall be used to adjust generation to maintain scheduled interchange. 2.2,The deficient system shall schedule all available assistance that is required with as mouch advance notice as possible. 2.3.The deficient system shall use the assistance provided by the Interconnection's frequency bias only for the time needed to accomplish the following: 2.3.1.Utilize its readily available operating reserve. 2.3.2,Analyze its ability to recover using only its own resources. 2.3.3.If necessary,determine the availability of assistance from other systems and schedule that assistance. If all other steps prove inadequate to relieve the capacity emergency,the system shall take immediate action which includes,but is not limited to,the following: 3.1.Schedule all available emergency assistance from other systems. ALASKA INTE Approved NERC efll.t-Revised 2 GUIDE Ill.EMERGENCY OPERATIONS ALASKA INTERTIE A.INSUFFICIENT GENERATION CAPACITY 3.2.Implement mannal load shedding. 4.Unilateral adjustment of generation to return frequency to normal by systems not experiencing capacity deficiencies,beyond that supplied through frequency bias action and interchange schedule changes,shall not be attempted.Such adjustment may jeopardize overloaded transmission facilities. Recommendations 1.Generators and their auxiliaries should be able to operate reliably at abnormal voltages and frequencies. 2.Where station service generators are used in parallel with the system,station auxiliary busses should be separated automatically from the system before the frequency has decayed sufficiently to adversely affect the station service units. 3.Plant operators should be supplied with instructions specifying the frequency and voltage below which it is undesirable to continue to operate generators connected to the system. 3.1.Protection systems should be considered for automatically separating the generators from the system at predetermined high and low frequencies. 3.2.If feasible,generators should be separated with some local,isolated load still connected.Otherwise,generators should be separated carrying their own auxiliaries. 4.Emergency sources of power should be available to facilitate safe shutdown,enable turning gear operation,minimize the likelihood of damage to either generating units or their auxiliaries,maintain communications,and expedite restarting. B.TRANSMISSION ---OVERLOAD,VOLTAGE CONTROL Criteria Reference ALASKA INTE KZApprovedNERCofll2-Revised 2 GUIDE fl.EMERGENCY OPERATIONS ALASKA INTERTIE B.TRANSMISSION +OVERLOAD,VOLTAGE CONTROL Requirements 1.2f an overload on a transmission facility or abnorma!voltage/reactive condition persists due to operations of another system,the affected system shall notify the neighboring or remote system(s)of the severity of the overload or abnormal voltage/reactive conditions and request appropriate relief. 2.If the overload on a transmission facility or abnormal voltage/reactive condition persists and equipment is endangered,the affected system or pool may disconnect the affected facility. Neighboring systems impacted by the disconnection shall be notified prior to switching,if practicable,otherwise,promptly thereafter. 3.Action to correct a transmission overload shall not impose unacceptable stress on internal generation or transmission equipment,reduce system reliability beyond acceptable limits,or unduly impose voltage or reactive burdens on neighboring systems.If all other means fails, corrective action may require load reduction. 4.Systems shall take all appropriate action up to and including shedding of firm load in order to keep the transmission facilities within acceptable operating limits. C.LOAD SHEDDING Criteria Reference 1.Automatic load shedding shall be coordinated throughout the Region or Subregion with other underfrequency isolation,such as generator tripping or isolation,shunt capacitor tripping, and other automatic actions which occur during abnormal frequency or voltage conditions. 2.Automatic load shedding shall be in steps related to one or more of the following:frequency, vate of frequency decay,voltage level,rate of voltage decay,or power flow. 3.After a system or control area separates from the Interconnection,if there is insufficient generating capacity to restore system frequency following automatic underfrequency load shedding,additional load shall be shed manually. Recommendations 1.Voltage reduction for load relief should be made on the distribution system.Voltagereductiononthesubtransmissionortransmissionsystemmaybeeffectiveinreducing load; ALASKA INTE 2ApprovedNERC-H3-Revised GUIDE fl.EMERGENCY OPERATIONS ALASKA INTERTIE C.LOAD SHEDDING however,voltage reduction should not be made on the transmission system unless the system has been isolated from the Interconnection. 2.In those situations where it will be beneficial,manual load shedding should be used to prevent imminent separation from the Interconnection due to transmission overloads or to prevent voltage collapse. D.SYSTEM RESTORATION Requirements 1.Each system shall have a restoration plan. 1.1.Operating personne!shall be trained in the implementation of the plan.Such training should include simulated exercises,if practicable., 1.2.The restoration plan shall be updated,as necessary,to reflect changes in the power system network and to correct deficiencies found during the simulated restoration exercises. 1.3.Telecommunication facilities needed to implement the plan shall be periodically tested. 2.Following a disturbance in which one or more system areas become isolated,steps shall begin immediately to return the system to normal: 2.1.The system operator shall determine the extent and condition of the isolated area(s). 2.2,The system operator shall then take the necessary action to restore system frequency tonormal,including adjusting generation,placing additional generators on line,or load shedding. 2.3.When voltage,frequency and phase angle permit,the system operator may resynchronize the isolated area(s)with the surrounding area(s),properly notifying ALASKA 1 Approved NERC wllL.4-Revised _,2 onGUIDE Ill.EMERGENCY OPERATIONS ALASKA INTERTIE D.SYSTEM RESTORATION adjacent systems,and considering the size of the area being reconnected and the capacity of the transmission lines effecting the reconnection. 2.4.Restoration of off-site power to nuclear stations shall be given high priority. E.EMERGENCY INFORMATION EXCHANGE Crtteria Reference Requirements 1.A system shall inform other systems in their Region or Subregion,through predetermined communication paths,whenever the following situations are anticipated or arise: 1.1.The system's condition is burdening other systems or reducing the reliability of the .Interconnection. 1.2 The system is unable to purchase capacity to mect its load and reserve requirements on a day-abead basis or at the start of any hour. 1.3.The system's line loadings and voltage/reactive levels are such that a single contingency could threaten the reliability of the Interconnection. 14.The system anticipates 3%or greater voltage reduction or public appeals because of an inability to purchase emergency capacity. 15.°The system has instituted 3%or greater voltage reduction,public appeals for load reduction,or load shedding for other than local problems. 1.6.The system suspects or has identified a multi-site sabotage occurrence,or single-site sabotage of a critical facility. 2.Refer to Appendix VLA.for information regarding the communication network for eachInterconnection.. fF.SPECIAL SYSTEM OR CONTROL AREA ACTION Crtteria Reference ; ALASKA |! Approved NERC -Til.5-Revised _,/2.3/7> GUIDE Ill.EMERGENCY OPERATIONS ALASKA INTERTIE 1.When an operating emergency occurs,a prime consideration shal]be to maintain parallel operation throughout the Interconnection.This will permit rendering maximum assistance to the system(s)in trouble. 2.If an area becomes separated during a disturbance,interchange schedules between contro) areas or fragments of contro]areas within the separated area shall be immediately reviewed and appropriate adjustments made in order to gain maximum assistance in restoration. Attempts shall be made to maintain the adjusted schedules whether generation contro!is manual or automatic. Recommendetions 1.If abnormal levels of frequency or voltage resulting from an area disturbance make it unsafetooperatethegeneratorsortheirsupportequipmentinparalielwiththesystem,theirseparationorshutdownshouldbeaccomplishedinamannertominimizethetimerequired tore-parallel and restore the system to normal. 2 AGC should remain operative if practicable. G.CONTROL CENTER BACKUP Criteria Reference 1.The standards of Guide I should be considered when developing the plan to continueoperationsothatthecontrolareawillnotbeaburdentotheInterconnectionifitsown control center becomes inoperable. 1.1.If the control area has a backup control center,it should be remote from the primary control center site. ALASKA !'ApprovedNERC II1.6-Revised 3/9 2 ALASKA INTERTIE GUIDE fV.OPERATING PERSONNEL A.RESPONSIBILITY AND AUTHORITY Criteria Reference Requirements 1.Each control area shall provide its operators with a clear definition of their responsibilities and authority. 2.Each control area shall make other system personnel aware of the authority of the system operator. B.SELECTION Criterla Reference Recommendstions 1.Personnel selected as system operators should be capable of directing other operating personnel in their own system,and at the same time,working compatibly with their counterparts in adjacent systems. 1.1.A system operator should bave a high level of intellectual ability,above-average reasoning,reasonable mechanical,electrical,and mathematica!aptitude,plus skills incommunications,supervision,and decision-making. 1.2.Successful performance in lower-level assignments is desirable in the selection of system operators. 2 To maintain an adequate level of capability and expertise in system operations,each system should implement a screening and selection procedure for its system operators which mayinclude: ALASKA INTE ApprovedNERCfV.1-Revised a oes.a=oeonooGUIDE {V.OPERATING PERSONNEL ALASKA INTERTIE B.SELECTION 2.1,Evaluation of candidates against a detailed job description. 2.2.Analysis of the candidate's past record including experience. 2.3.In-depth interview with cach candidate. 2.4.Evaluation of intelligence,logic,aptitude,mathematical and communications skills along with psychological fitness. 2.5.Educational background check. 2.6.Physical examination,including tests for hearing and vision. Cc.TRAINING Criteria Reference Requirements 1.Each control area shall provide its system operators with guidelines for solving problems that can be caused by realistic contingencies and known facility limitations. 2.Each system operator shall be thoroughly indoctrinated in the basic principles and procedures of interconnected systems operation as outlined in the NERC-OC Criteria and Guides as well as in Regional,pool,and control area operating policies. 3.Each control area shall have procedures for the recognition of and for making its system operators aware of sabotage events on its facilities and multi-site sabotage affecting larger portions of the Interconnection.Procedures shall also be established for the communication of information concerning sabotage events to appropriate parties in the Interconnection. Recommendations 1.Each system should implement a training program for its system operating personnel. 1.1.Training should include both classroom and on-the-job training. 1.2,Each system should periodically practice simulated emergency situations. 2.Each system should consider a power system simulation training program. ALASKA | Approved 7/6 NERC -IV.2-Revised,2 GUIDE IV.OPERATING PERSONNEL ALASKA INTERTIE C.TRAINING 3.Each system should consider the list of suggested items in Appendix IV.C.for inclusion in their training program. 4.Each system should consider sabotage awareness as part of their training program. Background The increasing sophistication of power system control centers,which include controlequipment,instrumentation and data presentation techniques,plus the closer integration of power systems through stronger interconnections,requires careful selection and training of system operating personnel.Proper action during a system emergency,as well as in the minute-to-minute operation of a complex system,depends upon human performance.Each system operator should be well qualified,adequately educated,mentally suited,and thoroughly indoctrinated in the principles and procedures of interconnected system operation.To achieve and maintain the necessary expertise,a well-defined training program for system operating personnel is essential, To operate a power system effectively,a system operator must have a thorough understanding of the basic principles of electricity.A power system consists of a variety of components,equipment,and apparatus.As with basic principles of electricity,a thorough understanding of this apparatus,its functions and characteristics,is essential,along with how these devices integrate into an operating system.The system operator should also have skills in supervision,communications and decision-making. The threat of sabotage to the facilities of the Interconnection requires special training of system operators to increase their awareness and ability to quickly communicate informationconcerningsuspectedorconfirmedsabotageevents. ALASKA INTE iApprovedNERC-IV.3-Revised z GUIDE iV.OPERATING PERSONNEL ALASKA INTERTIE C.TRAINING . BD.RESPONSIBILITY TO OTHER OPERATING GROUPS Criteria Reference Requirements 1.System and control area personnel shall be aware of the operating information needs of other systems,control areas,pools,Regions,and the NERC staff. 2.Procedures shal!be in place for the effective transfer of operating information between these other groups. Background A key ingredient of good system and Interconnection operation is the efficient transfer ofinformationbetweentheothervariousoperatingpersonnelduringnormalaswellasemergencyoperatingconditions. ALASKA INTE Approved NERC -IV4-Revised 2 ALASKA INTERTIE APPENDIX fV.C.SUGGESTED ITEMS FOR INCLUSION IN A TRAINING COURSE The following outline includes suggested items for inclusion in a training course.Thisoutlineisintendedtobeacomprehensivelistingtobeutilizedbyinterconnectedsystemsindesigningtrainingcoursestomeetthespecificneedsofsystemoperatingpersonnel. A NORMAL OPERATIONS 1.Power flow concepts,determination and control. Li 1.2, Alternating Current (sc) 1.1.1.Generation 1.1.2.Transmission 1.1.3.Transformation 1.1.4.Loads and effects on system 1.1.5.Phase angle 1.1.6.Phase shifting transformers 1.1.7.Reactors 1.1.8.Capacitors 1.1.9.Parallel flows Direct Current (dc) 1.2.1.Transmission 1.2.2.Interconnections 2 Voltage control concepts 2.1. 2.2, 2.3. 2.4, 2.5. 2.6. 2.7. 28. NERC Load characteristics Standards Schedules Causes for voltage deviations Generation excitation Transformer taps Reactive sources The need for and importance of: 2.7.1.Generators 2.7.2.Synchronous condensers 2.7.3.Capacitors 2.7.4.Reactors 2.7.5.Static var compensators Line and cable switching ofe ALASKA INTE Approved Revisedwe APPENDIX iv.C.SUGGESTED ITEMS FOR INCLUSION IN A TRAINING COURSE 3.Control concepts 3.1.Dispatching techniques 3.2.AGC and unit governor relationships 3.3.Area control error 3.4.Interchange control 3.5.Inadvertent interchange 3.6.Special operating program(s) 4.Economic operations concepts 4.1.Dispatching techniques 4.2.'Heat rates 43.Fuel costs 4.4.Start-up and shutdown costs 4.5.Pumped storage costs 46.Unit commitment 4.7.Economic loading 4.8.Transmission loss effect 49.Reactive flow 4.10.Utilization of limited energy capacity 4.11,Pumped storage capacity 4.12.Incremental and decremental costs 4.13.Accounting procedures 5.Operating guides and constraints 5.1.Operating Manual 3.2.Operating Guides 5.3 Contro]Performance Criteria 5.4.Reliability Criteria for Interconnected Systems Operation 5.5.Contingency assessments 5.5.1.Generator outage 5.5.2.Transmission outage 5.5.3.Transformer outage 5.5.4.Combination of above 5.6.Equipment capabilities and limits 5.6.1.Thermal 5.6.2.Voltage/reactive 5.6.3.Relay 5.6.4.Stability 5.7.Reserve requirements (special) 5.8,Time error and frequency 5.9.Voltage 5.10.Switching -voltage and redistribution of flow 6.Operating considerations 6.1. 6.2. 6.3. 6.4. 6.5. NERC Safety of personnel and equipment Synchronizing Line switching and clearance Ferroresonance Metering failures ALASKA INTERTIE Approved ALASKA INTE 2Revised APPENDIX 1V.C.SUGGESTED ITEMS FOR INCLUSION 6.6. IN A TRAINING COURSE Maintenance scheduling criteria 6.6.1.Generation 6.6.2.Transmission 6.6.3.Substation 6.6.4.Protection B.ABNORMAL OPERATIONS 1.Dynamic performance of system 111.2, 1.3. 1.4. 1.5. 1.6. Transient stability Oscillations Relay actionControl-initiated swingsCausesofdisturbances Special protection systems 2.Dynamic performance of equipment 21 2.2. 2.3. 2.4. 2.5. 2.6. Governor response Exciter response Relays and breakers Underfrequency relays 2.4.1.Special protection systems Metering Automatic controls 2.6.1.Plant 2.6.2.AGC 2.6.3.Voltage 2.6.4.Generator and load tripping 2.6.5.System separation 3.Recognition of abnormal conditions 3.1.Loss of load 3.2,Breaker operations 3.3.Line faults 3.4.Generator trips 3.5.Frequency deviations 3.6.Interchange amounts 3.7.Voltage levels 3.8.System separations 3.9.Communications with other plants and utilities 3.10.Parallel flows 3.11.Maulti-site sabotage 4.Remedial action 4.1.Islanding 4.2.Load shedding 4.3.Generator dropping 4.4.Shifting generation 4.5.Switching operations,including interconnection NERC =3- ALASKA INTERTIE APPENDIX IV.C.SUGGESTED ITEMS FOR INCLUSION IN A TRAINING COURSE 4.6.Isolating system operation 4.7.High-and low-frequency operation 4.8.High-and low-voltage operation ALASKA INTERTIE 5.Recovery 5.1...Generation start-up capabilities and pickup rates 5.2.°Sectionalizing 5.3.Load pickup priorities and problems 5.4.Low voltage networks §.5.Synchronizing within system and at interconnections 6.Multi-site sabotage awareness 6.1.Physical security of critical facilities 6.2.Multi-site sabotage techniques and strategies 6.3.Criteria for differentiating sabotage or vandalism from routine equipment outages 6.4.Operating considerations unique to multi-site sabotage attacks C.COMMUNICATIONS 1.'Facilities available 1.1.Common carrier systems 1.2.Private systems (microwave) 1.3.Radio 1.4.Power line carrier 1.5.Emergency power supplies 2.Information exchange 2.1.Standard terminology 2.2 Neighboring systems 2.3.Coordinating council offices 2.4.Power plants 2.5.Substations 2.6.Management 2.7,News Media 2.8.Governmental agencies D.INTERCONNECTED SYSTEM OPERATION 3.NERC and regional Operating Criteria and Guides 2._- Philosophy of operation2.1.Benefits 2.2,Obligations 2.3,Responsibilities 2.4.Authority 3.Effects on system performance 3.1.Frequeacy 3.2.Interchange ALASKA INTE Approved NERC =&-rat aAPPENDIX {V.C.SUGGESTED ITEMS FOR INCLUSION IN A TRAINING COURSE 3.3.Reserves 3.4.Mutual assistance 3.5.Pooling arrangements 3.6.Communications 3.7.Solar Magnetic Disturbance ALASKA INTERTIE Approved 4.Off-normal operations 4.1,Responsibilities 4.2,Actions required MODERN POWER SYSTEM CONTROL AIDS 1 Equipment 1.1.Man-machine interface 1.2.Supervisory control 13.Data acquisition 1.4.Failover and restart 2.Theory and use of application programs in normal and emergency operation. 2.1.Interaction of program results on systems and other programs 2.2.Effects of data errors 3.='Alternative control methods during equipment and program unavailability NERC <5."ageRevised APPENDIX IV.C.SUGGESTED ITEMS FOR INCLUSION iN A TRAINING COURSE 4.Typical application programs used 4.1.Economic dispatch 42,AGC 4.3.Unit commitment 4.4.Operator load flow 4.5.Contingency analysis 4.6.Corrective strategies 4.7.State estimation 4.8.Interchange accounting 4.9.Transaction evaluation4.10.Automated billing F.SUPERVISORY SKILLS J.Personnel supervision 2. On-the-job training preparation 3.Verbal communication 4.Decision-making 5.Stress influence NERC -6- ALASKA ALASKA ! Revis INTERTIE NTEApprovedthe,z= ALASKA INTERTIE GUIDE V.OPERATIONS PLANNING A.NORMAL OPERATIONS Crtteria Reference 1.Each control area shal!plan to be able to meet daily load patterns and changes in system load characteristics. 2.The results of system studies pertinent to operations shall be available to the system operators. Recommendations I,Reviews should be made with planning engineers periodically to ensure that the long-range plans will allow for compliance with the NERC Operating Committee Criteria and Guides. 2.Each control area should participate in studies with other systems,when required,to consider: The facilitics on each system which may affect the operation of the coordinated area.bEThe operating limitations of generating facilities. 2.3.The operating limitations of the system when all transmission facilities are in service. 2.4.The operating limitations of the system when transmission facilities are scheduled or forced out of service. 2.5.Voltage and reactive schedules. 3.Stadies should be made annually (or at such times as bulk system changes warrant)to determine the transfer capability between interconnected control areas. 4.Generating capability determination should include,among other variables,weather,ambient air and water conditions,and fuel quality and quantity. 5.Each control area should determine the power transfer capabilities of its transmission system and identify potentia]problems by conducting operating studies as required, 5.1.Thermal,stability,short-and long-term loading,and voltage limits,plus seasonal(temperature)characteristics,should be considered when determining the ratings on transmission facilities. §.2.Transfer capability studies should consider voltage,reactive,thermal,and stabilitylimitsofinternalandexternalsystemequipment.(Ref:*Transfer Capability,A ALASKA INTE 'ia 2 ApprovedNERCoV.1-Revised oameeGUIDE V.OPERATIONS PLANNING ALASKA INTERTIE &NORMAL OPERATIONS Reference Document,"NERC October 1980)Generating unit and transmission facility outage patterns should be considered.Studies should determine additional reactive requirements resulting from reasonable generation and transmission contingencies, 6.Computer models utilized for analyzing and planning system operations should be renewed and updated as necessary to ensure that they accurately and adequately represent the system. 7.Neighboring systems should use uniform line identifiers and ratings when referring to transmission facilities of an interconnected network. 5.PLANNING FOR SHORT-TERM EMERGENCY CONDITIONS Criteria Reference Requirements 1.Plans developed and maintained to cope with operating emergencies shall include procedures that can be executed by system operators. Recommendations 1.Appropriate governmental agencies should be apprised of the plans. C.PLANNING FOR LONG-TERM EMERGENCY CONDITIONS Criteria Reference Recommendations 1.Each system or pool should develop capacity and energy emergency plans that will enable it to mitigate,to the fullest extent possible,the effect of a capacity or energy emergency on itscustomers. 2.Appropriate governmental agencies should be apprised of the plans. 3.If existing interchange agreements cannot be used,new agreements should be arranged to provide for emergency capacity or energy transfers. 4.The energy emergency plan should include or consider the following items: ALASKA INTE Approved NERC -V.2-Revised 2 Po"fi GUIDE V.OPERATIONS PLANNING ALASKA INTERTIE C.LONG-TERM DEFICIENCIES 4.1. 4.2. 4.3. 4.4. 4.5. 4.6. 4.7. 4.8. 4.9. 4.10. 4.11. 4.12. 4.13 The functions to be coordinated with and among neighboring systems. An adequate fuel inventory plan which recognizes reasonable delays or problems in the delivery or production of fuel. Fuel switching plans and plans to seek removal of environmental constraints for generating units and plants. The reduction of the system's own energy use to a minimum. Appeals to the public through all media for voluntary load reductions and energy conservation including educational messages on how to accomplish such load reduction and conservation. Implementation of load management and voltage reductions,if appropriate. The operation of all generating sources to optimize the availability of the fuel in short supply. Appeals to large industrial and commercial customers to reduce non-essential energy use and maximize the use of customer-owned generation that rely on fuels other than the one in short supply. Use of interruptible and curtailable load to conserve the fuel in short supply. Requests to appropriate government agencies to implement programs to achieve necessary energy reductions. A mandatory load curtailment plan to use as a last resort.This plan should address the needs of critical loads essential to the health,safety,and welfare of the community. Notification of appropriate government agencies as the various steps of the emergency plan are implemented. Notification of cogeneration and independent power producers to maximize output and availability. 5.The capacity emergency plan should address the following items: 5.1 5.2 5.3. NERC The functions to be coordinated with and among neighboring systems. An adequate fuel supply plan which recognizes reasonable delays or problems in thedeliveryorproductionoffuel. Fuel switching plans for units for which fuel supply shortages may occur,e.g.gas andlightoil. -V3-Revised 2 omeeeeOeOROeweOFOeCeweOFOeweEeOemeOeOeBemeOeeeeeOeeeoeadueGUIDE V.OPERATIONS PLANNING ALASKA INTERTIE C.PLANNING FOR LONG-TERM EMERGENCY CONDITIONS 3.9 5.10 5.11 5.12 5.13 5.14 Plans to seek removal of environmental constraints for generating units and plants. The reduction of the system's own energy use to a minimum. Appeals to the public through all media for voluntary load reductions and energy conservation including educational messages on how to accomplish such load reduction and conservation. Implementation of load management and voltage reductions,as appropriate. The operation of all generating sources to maximize output and availability.This should include plans to winterize units and plants during extreme cold weather. Appeals to large industrial and commercial customers to reduce non-essential energy use and start any customer-owned back-up generation. Use of interruptible and curtailable customer load to reduce capacity requirements. Requests to appropriate government agencies to implement programs to achieve necessary energy reductions. A mandatory load curtailment plan to use as a last resort.This plan shonld address the needs of critical loads essential to the health,safety,and welfare of the community. Notification of appropriate government agencies as the various steps of the emergency plan are implemented.. Notification of cogeneration and independent power producers to maximize output and availability. Each Region,system,and/or pool should participate in the coordination of capacity andenergyemergencyplansandactionstomaximizemutualaidduringsuchemergencies.The following steps should be taken: 6.1. 6.2. NERC Establish and maintain reliable communications between interconnected systems. If a capacity or energy emergency is foreseen,contact neighboring systems as far in advance as possible to assess regional conditions and arrange for whatever relief is available or required. Coordinate transmission and generator maintenance schedules to maximize capacity or conserve the fuel in short supply.(This includes water for hydro generators). Arrange deliveries of electrical energy or fuel from remote systems through norma! operating channels. Continue to apprise the interconnected systems of the level of generating capacity or energy supply and future needs, ALASKA INTE Approved -VA4-Revised z Cy GUIDE V.OPERATIONS PLANNING ALASKA INTERTIE D.LOAD SHEDDING BD.LOAD SHEDDING Criteria Reference 1.Each system shall establish plans for automatic load shedding and shall give system operatorstheauthoritytoimplementmanualJoadsheddingwhennecessary. 1.2.Load shedding plans shall be coordinated among the interconnected systems. 1.2.Automatic load shedding shall be initiated at the time the system frequency or voltage has declined to an agreed-to level. 1.2.1.Automatic load shedding shall be in steps related to one or more of the following: frequency,rate of frequency decay,voltage level,rate of voltage decay or power flow levels. 1.2.2.The load shed in each step shall be established to minimize the risk of further uncontrolled separation,loss of generation,or system shutdown. 1.3.Automatic load shedding shall be coordizated throughout the Region with underfrequency isolation of generating units,tripping of shunt capacitors,and other automatic actions which will occur under abnormal frequency,voltage,or power flowconditions,; Recommendations 1.Automatic load shedding plans should be based on studies of system dynamic performance,simulating the greatest probable imbalance between load and generation. 1.1.Plans to shed load automatically should be examined to determine if unacceptable overfrequency,overvoltage,or transmission overloads might result. 1.1.1.If overfrequency is likely,the amount of load shed should be reduced or automatic overfrequency load restoration should be provided. 1.1.2.If overvoltages are likely,the load shedding program should be modified tominimizethatprobability. ALASKA INTE ApprovedNERC-V5-Revised _j/23/72- GUIDE V.OPERATIONS PLANNING ALASKA INTERTIE D.LOAD SHEDDING 2.When scheduling load to be shed automatically,the system should consider its local area Tequirements and transmission capabilities between areas. 3.A generation-deficient control area may establish an automatic isolation plan in lieu of automatic load shedding,if by doing so it removes the burden it has imposed on the Interconnection.This isolation plan may be used only with the consent of neighboring systems,and if it leaves the remaining bulk electric system intact. 4.A control area should consider isolating its generators to protect them from extended abnorma!voltage and frequency operation.If feasible,generators should be separated withsomelocal,isolated load still connected.Otherwise,generators should be separated carrying their own auxiliaries. £.SYSTEM RESTORATION Crneria Reference ALASKA INTE Approved NERC -VE-Revised 2 Fsa:a GUIDE V.OPERATIONS PLANNING ALASKA INTERTIE E.SYSTEM RESTORATION Requirements 1.Each system shall establish a restoration plan with necessary operating instructions and procedures to cover emergency conditions,including the loss of vital telecommunications channels. 1.1.Restoration plans must be developed with the intent of restoring the integrity of the Interconnection. 1.2,Restoration plans shall be coordinated with neighboring systems. 2.System restoration procedures shall be verified by actual testing or by simulation. Recommendations 1,Where an outside source of power is necessary for generating unit start-up,switching procedures should be prearranged and periodically reviewed with system operators and other operating personnel. 2.Periodic tests should be made to verify black-start capability. In order to systematically restore loads without overloading the remaining system,opening circuit breakers should be considered to isolate loads in blacked-out areas. 4.Load shed during a disturbance should be restored only when doing so will not have an adverse effect on the system or Interconnection. 4.1.Load may be restored manually or by supervisory control only by direct action or order of the system operator as generating and transmission capacity become available. 4.2.Automatic losd restoration may be used where feasible to minimize restoration time. 4.2.2.Automatic restoration should be coordinated with neighboring systems, coordinated areas,and Regions, 4.2.3.Automatic restoration should not aggravate system frequency excursions, overload tie lines,or burden any system in the Interconnection. 5.All synchroscopes should be calibrated in degrees,and phase angle differences at interconnection points should be communicated in degrees. 6.Reenergizing oil-filled pipe-type cables should be given special consideration,especially iflossofoi]pumps could cause gas pockets to form in pipes or potheads. 7.The following should be considered when trying to maintain normal transmission voltage during restoration:: ALASKA INTE ApprovedNERC-V7-Revised 2 GUIDE V.OPERATIONS PLANNING ALASKA INTERTIE E.SYSTEM RESTORATION 9. 10. 21. 12. 7.1.Removal of shunt capacitors or addition of reactors or addition of small blocks of isolated load to prevent excessive voltage when energizing long transmission lines. 7.2.Effects of energizing high-voltage cables at the end of a long,lightly-loaded system. 7.3.The capability of the generators to provide or absorb reactive power flows. System operators should know the preplanned synchronizing locations and procedures.Procedures should provide for alternative action to be takenin case of lack of information orlossofcommunicationchannelsthatwouldaffectresynchronizing. Each contro!area should have written plans for orderly start-up and shutdown of the generating units. 9.1.These plans should be updated when required. 9.2.Drills should be held periodically to assure that plant operators are familiar with the plans. Each generating plant should have a source of emergency power to expedite restarting. Hydroelectric plants should have internal provisions for restarting. Backup voice telecommunications facilities,including emergency power supplies andalternatetelecommunicationschannels,should be provided to assure coordinated control or operations during the restoration process. Control centers using SCADA systems should consider providing master trip points for each station to expedite the restoration process. Proper protection systems should be considered in the restoration sequence.Relay polarization sources should be maintained during the process. ALASKA INTE Approved NERC -VB-Revis 2I/F 2 a.=eowALASKA {NTERTIE GUIDE Vi.TELECOMMUNICATIONS 1.Reliable and secure telecommunications networks shall be provided within and among systems,control areas,pools,and Regions. 2.Exclusive telecommunications channels shall be provided between the system control center and the control center of each adjacent connecting system. 3.All telecommunications channels shall be tested regularly or monitored on-line.Special attention should be given to emergency telecommunications channels and channels not used for routine communications. Recommendations 1.Telecommunications networks should be provided for voice,AGC,SCADA,special protection systems,and protective relaying where appropriate. 2.Computer data exchange should be considered where appropriate. 3.Critical telecommunications channels should not require intermediate switching to complete the channel. 4.Alternate and physically independent telecommunications chanoels should be provided for emergency use to back up the circuits used for critical data and voice communications. 5.Restoration services on critical telecommunicationus channels should be available 24 hours perday. 6.Each control center should be able to take control of any telecommunications channel for system operator use when necessary. ALASKA ! ApprovedNERCVLI-Revised 1/23/72 GUIDE Vi.TELECOMMUNICATIONS ALASKA INTERTIE A.FACILMES Background ka addition to system,control area,poo!and Regional telecommunications channels,networks have been implemented within each of the NERC Interconnections.These networks provide telecommunications capabilities during emergency situations,or when adverse operating conditions appear likely. 1,The Eastern Interconnection uses a telephone network which connects the seven Eastern Regions for voice communications. 2.The Western Interconnection (WSCC)uses a combination voice and computerized message system to connect the four Subregions and the WSCC office. 3.The ERCOT Interconnection uses computer terminal]and telephone networks that tie each control area to its respective security center ---one in north Texas,and one in south Texas. Either security center can be tied into either network. Descriptions of the three telecommunication networks and the procedures for operating them arefoundinAppendixVLA. 8.SYSTEM OPERATOR TELECOMMUNICATION PROCEDURES Crheria Reference Requirements 1.Each coordinated area shall provide a means to coordinate telecommunications among the systems in the area.This shall include the ability to investigate and recommend solutions to telecommunications problems within the area and with other areas. Background The Eastern Interconnection has established procednres for notifying all Eastern systems ofsolarmagneticdisturbances.These procedures are found in Appendix VLB. ALASKA INTE Approved NERC Vi2-Revised 2 "GUIDE Vi.TELECOMMUNICATIONS C.LOSS OF TELECOMMUNICATIONS Criteria Reference Requirements ALASKA INTERTIE 1.Each control area shall have written operating instructions and procedures to enable continued operation of the system during loss of telecommunications facilities. NERC -VL3- ALASKA INTE Approved Revised a ALASKA TER NST COmmuae ATS °GYEA yo {\ i \ "Benotey .ae a ” :>D2ecf Radic Lint To silt MEA Gen,Onc APA CFE), 5.3 VS meA Easts ra \taif3ei/5 \ Cig \ i 4&: ]Ay '\ fee oy AmtPp .)Mc eswace/Lersed Lax cEA (> "para cic Di sCecr Radio Aw Te C)HEAHeAo-CEA ALASKA INTERTIE APPENDIX VIB.NOTIFICATION OF SOLAR MAGNETIC DISTURBANCE WARNINGS Solar Magnetic Disturbances (SMDs)are capable of causing serious disruptions toelectricpowersystemsespeciallyinthenorthernUnitedStatesandCanada. The National Oceanic and Atmospheric Administration's Space EnvironmentalServicesCenter,located in Boulder,Colorado,provides a solar disturbance forecasting service.Although they are unable to predict precisely when solar flares will occur,they are able todeterminewhenthedisturbanceisjustbeginning. The information from this forecasting service is made available to the AmericanElectricPowerServiceCorporation(AEP)of Columbus,Ohio,which has been designated toreceiveanddisseminatenotificationsofpossibleSMDstothesevenEasternRegions. Whenever AEP receives an SMD warning of K-5 or higher,the information will beroutedtoeachsystemviatheTimeNotificationChannels. ALASKA INTE ApprovedNERC-1-Revised 2 ALASKA SYSTEMS COORDINATING COUNCIL An association of Alaska's electric power systems promoting improved reliability through systems coordination ASCC PLANNING CRITERIA for the reliability of interconnected electric utilities May 1991 ALASKA SYSTEMS COORDINATING COUNCIL ASCC PLANNING CRITERIAFORTHERELIABILITYOFINTERCONNECTEDELECTRIC UTILITIES The Alaska Systems Coordinating Council (ASCC)is an association of Alaska's electric power systems promoting improved reliability through systems coordination and an affiliate member of the North American Electric Reliability Council (NERC).In August,1990,the ASCC established a Reliability Criteria Subcommittee composed of representatives of the ASCC members in Alaska's Railbelt region.The primary task of that Subcommittee was to complete efforts to develop,formulate in writing,and submit to ASCC for approval,coordinated interconnection planning and operating reliability criteria. prepared for |useby the "ASCC members jin:planning and designing generation andtransmissionnetworkfacilitiesoftheinterconnectedRailbeltutilities.In concert with the planning policies of NERC,the overall framework was provided by the NERC Planning Guides adopted by the NERC Engineering Committee in 1989 that describe good practices for bulk electric system planning.Individual ASCC planning criteria corresponding to the Guides were then developed specifically for the Alaskan interconnected bulk power system.._ The criteria provide guidance to the utilities in evaluating electric system performance over Maes the planning horizon and provide requirements and recommendations to be considered in planning and designing additions and modifications.Application of the criteria will promote the reliability of the bulk power system of the interconnected electric utilities of Alaska. Included herein are: NERC Planning Guides and corresponding ASCC Planning Criteria ....Page 1 The ASCC Planning Criteria .2.0...ec eee cece ee ccc cece ence Page 2 NERC Terms and Definitions ........0.cece cece cece cence eens Page 17 Recommended by Reliability Criteria Subcommittee:February 19,1991 Adopted by the Alaska Systems Coordinating Council:April 4,1991 ener North American Electric Reliability Council Planning Guides These Planning Guides describe the characteristics of a reliable bulk electric system.They are intended to provide guidance to the Regional Councils,Subregions,Pools,and/or the Individual Systems in planning their bulk electric systems. Le] ° 5 To the extent practicable,a balanced relationship is maintained among bulk electric system elements in terms of size of load,size of generating units and plants,and strength of interconnections.Application of this guide includes the avoidance of: Excessive concentration of generating capacity in one unit,at one location or in one area; Excessive dependence on any single transmission circuit,tower line,right-of-way,or transmission switching station;and Excessive burdens on neighboring systems. The system is designed to withstand credible contingency situations. Dependence on emergency support from adjacent systems is restricted to acceptable limits. Adequate transmission tics are provided to adjacent systems to accommodate planned and emergency power transfers. Reactive power resources are provided which are sufficient for system voltage control undernormalandcontingencyconditions,including support for a reasonable level of plannedtransfersandareasonablelevelofemergencypowertransfer. Adequate margins are provided in both real and reactive power resources to provideacceptabledynamicresponsetosystemdisturbances. Recording of essential system parameters is provided for both steady state and dynamicsystemconditions. System design permits maintenance of equipment without undue risk to system reliability. Planned ficxbility in switching arrangements limits adverse effects and permitsreconfigurationofthebulkpowertransmissionsystemtofacilitatesystemrestoration. Protective relaying equipment is provided to minimize the severity and extent of systemdisturbancesandtoallowformalfunctionsintheprotectiverelaysystemwithoutundue risk to system reliability. Black start-up capability is provided for individual systems. Fuel supply diversity is provided to the extent practicable. (NERC Planning Guides as approved by NERC Engineering Committee on February 28,1989) ASCC Planning Criteria ASCC criteria correspond to Planning Guides as follows: Criteria#1 Criteria #2 Criteria #3 Criteria #4 ASCC Planning Criteria #1:Balance Among System Elements A balanced relationship shall be maintained among bulk electric system elements so as to avoid excessive dependence on any one element. Requirements Planning for future development of the interconnected generation and transmissionsystemshallensureabalanceamongthesystemelementssuchthatthefollowingshall be avoided: 1.Excessive concentration of generating capacity in one unit,at one location,or in :one area. 2.Excessive dependence on any single transmission circuit,tower line,right-of-way, or transmission switching station. 3.Excessive burdens on neighboring systems. Recommendations 1.Utilities should conduct power flow and dynamic system studies to verify thatplansforadditionalgeneration,including their size and locations,do not adversely impact the interconnected system or individual utilities. 2.No more than one-fourth of the total interconnected installed generation shouldbelocatedatanyonegeneratingsite. 3.The maximum size of planned future generation units should be established such that system stability is maintained. 4.Generation should be distributed throughout the system so that loss of the largest generator will not cause system instabilities or uncontrolled cascading to blackout. 5.Plans for additional generation sites should include integrating transmission such that its full plant output can be maintained under any single transmission contingency. 6.Sufficient installed capacity reserves above loads should be planned such that the calculated loss of load probability does not exceed one day in ten years. 7.The system should have the ability.to provide adequate spinning reserves under automatic generation control (or accepted load-shedding schemes)such that individual interconnected areas will avoid outages cascading to total blackout whenever area intertie facilities experience outages. ASCC Planning Criteria #1,Page 1 of 2 2 a,\ 8.Generation or transmission system additions or improvements should be planned to come on-line at the time a transmission facility is projected to reach 90 percent of its continuous rated capability. (Remainder of page intentionally blank) ASCC Planning Criteria #1,Page 2 of 2 3 ASCC Planning Criteria #2:Contingencies Additions to the interconnected system shall be planned and designed to allow the interconnected system to withstand any credible contingency situation without excessive impact on the system voltages,frequency,load,power flows,equipment thermal loading, or stability. Requirements The following contingencies shall be used for planning and design of the interconnectedsystem: 1,Single Contingency: 1.1.Fault on any line end,assuming that the primary protection removes the faulted line section and has one unsuccessful reclose,if appropriate. 12.Loss of any single transformer or line. 13.Starting or loss of any generator or static Var system. 1.4.Acceptance or loss of a large load;e.g.that load being carried on an intertie or major load center. 15.Loss of any substation bus section. 2.Multiple Contingency: 2.1.Loss of entire generating station or transmission substation. 2.2.Loss of any double circuit structure. 2.3.Loss of all transmission lines in common right-of-way. 2.4.Acceptance or loss of a major load center,after first contingency. 2.5.Fault on any line end,assuming that the breaker or transfer trip fails and requires the operation of the back up relay scheme to remove the faulted section of line. "Recommendations 1.All facilities should remain below their emergency rating following any single or - 2. multiple contingency occurrence. All testing and verification studies should be performed at peak and off-peak load (_ and generation levels.= ASCC Planning Criteria #2,Page 1 of 2 4 3.There should be no loss of load on a system for the more common singlecontingencydisturbancesoriginatingonothersystems,except for load shedding tostabilizeextremefrequencydecaywhichwouldcauseuncontrolledarea-wide power interruptions.The uncontrolled loss of load is unacceptable even under the most adverse credible disturbances. 4.During all excursions subsequent to the occurrence of any single contingency,the following parameters should be maintained within applicable emergency limits without system separation or instability: 4.1.Voltage Level:Minimum Maximum First Power Swing:0.80 pu V 1.10 pu V (for 0.5 sec.) Intermediate:0.92 pu V 1.05 pu V Steady State:0.95 pu V 1.05 pu V 42.Frequency:58.8 Hz 615 Hz 5.Load-shedding should be planned for adequate system response to multiple contingencies to avoid system collapse. (Remainder ofpage intentionally blank) ASCC Planning Criteria #2,Page 2 of 2 5 ASCC Planning Criteria #3:Emergency Support Reserves should be provided such that emergency support from adjacent systems is restricted to acceptable limits as determined by studies of the interconnected system. Requirements Emergency support from adjacent systems shall be used only as a temporary source of emergency energy and system capacity is to be promptly restored so that the interconnected system will be prepared to withstand the next contingency. Recommendation A utility should not plan for the availability of routine or emergency support from an adjacent utility,except as specifically provided for in individual or joint utility agreements. (Remainder of page intentionally blank) ASCC Planning Criteria #3,Page 1 of 1 6 ASCC Planning Criteria #4:Support From Adjacent Systems Adequate transmission ties between adjacent systems shall be provided to accommodate planned and emergency power transfers. Requirements Transfer limits for planned emergency power transfers between adjacent systems shall beverifiedbystatic,dynamic,and voltage stability analyses to ensure compliance with all Planning Reliability Criteria. Recommendations 1.Transmission ties should be designed to carry emergency transfers following any Single contingency on the interconnected system. 2.Transmission ties should be retained between control areas to the maximum extent practical following a multiple contingency on the interconnected system. (Remainder of page intentionally blank) ASCC Planning Criteria #4,Page 1 of 1 7 ASCC Planning Criteria #5:Reactive Power Resources Each control area shall provide sufficient capacitive and inductive resources at proper levels to maintain system steady state and dynamic voltages within established limits, including support for reasonable levels of planned and emergency power transfers. Requirements 1.Devices shall be installed on each system to regulate the transmission voltage and reactive power flow levels,and to keep voltage levels within allowable limits. Devices shall be sized for response to dynamic excursions and to control voltageandpowerflowinastablestate,once the faulted section has been removed from the system. Sizing and location of static Var systems shall be such that any single contingency shall not result in the loss of the static Var system. All reactive resource equipment shall be capable of continuous operation during system frequency excursions resulting from credible contingencies. Reactive resources shall be sized and provided with controls sufficient to start, operate,and stop them without causing undue adverse system effects. Recommendations 1. ASCC Planning Criteria #5,Page 1 of 1 Each control area should be able to demonstrate and verify that the equipment has the capability and is responsive to the deficiencies resulting from credible system contingency disturbances,arresting any subsequent system deficiency,and maintaining the system in a stable operating mode. The size,number,and location of static Var systems,capacitor banks,and reactor banks should be considered in heavily compensated lines which could become unstable due to loss of one static Var system.Reactive resources should be sized and located to minimize the impacts of flicker due to starting,energizing,stopping or de-energizing the devices. Static Var systems should be designed to be capable of unconstrained use in the presence of credible harmonics,geomagnetic induced currents and credible frequency swings. Each system should plan and size all reactive supply devices for islanding,in total or in part,from interconnected resources,to control high voltage on open ended lines,and to maintain all voltages and power flows within appropriate limits. Reactive control devices should have the capability of being monitored or controlled through a supervisory control and data acquisition (SCADA)system.C ASCC Planning Criteria #6:Real and Reactive Power Margins Margins in both real and reactive power resources are provided for acceptable dynamic response to system disturbances. Requirements 1,Each system shall provide adequate responsive generation capable of providing adjustments in the area generation to return Area Control Error to zero,orreducearealoadtomatchareagenerationandthusreturnfrequencytonominal levels. 2.Each control area shall provide a method of regulating generation capability to provide for adequate system regulation. 3.Devices shall be provided in each system to keep voltage level and power flow within allowable limits. 4.Devices shall be sized for response to dynamic excursions and control frequency, voltage,and power flow in a stable state,once the faulted section has been removed from the system. Recommendations 1,Provisions to adjust real power should be provided to respond to crediblecontingenciesthroughtheuseofgenerationwithresponsiveautomaticgeneration control,load shedding,unit tripping,braking resistors,either individually or through the use of combinations of the above. 2.Provisions to adjust reactive power should be provided to respond to credible contingencies through the use of generation excitation response,automatically switched capacitors,reactors,static Var systems,either individually or through the use of combinations of the above. 3.Devices should be planned and sized to control expected voltage excursions while staying within their ratings without tripping from either thermal or "ceiling* limitations which could subsequently trip off the device. 4.Devices which are installed to provide response to disturbances should be operated at levels which will allow each deyice to supply the intended duty without tripping the device. ASCC Planning Criteria #6,Page 1 of 2 9 5.Each control area should be able to demonstrate and verify that the equipmentis _responsive to the deficiencies following credible system contingency disturbances,,- and capable of arresting any subsequent system deficiency and maintaining the system in a stable operating mode. 6.Based on the low system inertia and relatively fast frequency reduction following the loss of large generation blocks on the interconnected system,load shedding may be acceptable and required to control frequency decay. 7.Each area and control area should plan and size all real and reactive supply devices for islanding in total or in part from interconnected resources to maintain all voltages,frequencies,and power flows within appropriate limits. (Remainder of page intentionally blank) ASCC Planning Criteria #6,Page 2 of 2 10 ASCC Planning Criteria #7:Recording System Parameters Essential system parameters shall be recorded. Requirements 1.Adequate equipment shall be installed to record system conditions with respect to load,generation,transmission line loading,voltage and frequency as required to provide information to determine if system operation is within established limits. 2.System conditions shall be sufficiently recorded to allow determination of the cause of system outages or disturbances. Recommendations 1.SCADA systems should adequately verify steady state system operating parameters and provide alarms for significant parameters. 2.Equipment such as dynamic system monitors,event recorders,etc.,should be installed at potential stability problem areas and major interconnection points. Such devices should be capable of remote interrogation. 3.Consideration should be given to the utilization of automatic equipment to bring immediate attention to important deviations in system operating conditions and to indicate or initiate corrective action. (Remainder ofpage intentionally blank) ASCC Planning Criteria #7,Page 1 of 1 i1 ASCC Planning Criteria #8:Reliability During Maintenance System designs shall allow for equipment maintenance without unduly degrading reliability. Requirements The interconnected system shall be designed to withstand any credible contingency situation without excessive impact during scheduled maintenance. Recommendations 1.Design of all major system components should meet the above criteria. 2.Interconnected system planning should consider coordinated annual maintenanceschedulestominimizeexposuretosystemdisturbances. (Rernainder of page intentionally blank) ASCC Planning Criteria #8,Page 1 of 1 nS,ASCC Planning Criteria #9:Switching Flexibility Switching arrangements shall be provided to limit adverse effects and permit reconfiguration of the bulk power transmission system to facilitate system restoration. Requirements 1.All utilities shall provide for reconfiguration at critical facilities;that is,ring bus, auxiliary bus,or similar schemes shall be provided. 2.Switches shall be installed as required on long lines,reactors,capacitors,or other equipment that may require system reconfiguration for system restoration. Recommendations 1.Consideration should be given to providing emergency ties for backup for transmission or substation facilities which do not meet normal single contingency requirements. 2.Consideration should be given to SCADA control of switching within the bulk transmission system to aid in restoration. (Remainder of page intentionally blank) ASCC Planning Criteria #9,Page 1 of 1 13 ASCC Planning Criteria #10:Protective Relaying Provide sufficient relaying equipment such that the severity and extent of system disturbances is minimized and that malfunctions in the protective relay system do not jeopardize system reliability. Requirements 1.Protection schemes shall be designed so that relay operations will reliably remove faulted system components within the time frame required to maintain system stability,while at the same time avoiding unnecessary removal of unfaulted components. Primary and backup protective relays on the generation and transmission system shall be of complementary types and/or manufactures to minimize risks arising from common mode failures of identical instruments. Relaying shall be set to balance the protection of both individual generating units and the overall system. Railbelt utilities shall coordinate relay protection schemes and settings. All protective relaying components on the generation and transmission systemshallbeprovidedwithprovisionsforperiodictestingtoverifydesignedoperation. Recommendations 1.Any line protective relaying function required to maintain system stability shouldhavemultipleredundantprotectiverelayingschemes,the extent of such redundancy to be determined through studies of the specific relaying applications. Breaker failure relaying should be provided at both generation and transmission substations. (Remainder of page intentionally blank) ASCC Planning Criteria #10,Page 1 of 1 14 at,ASCC Planning Criteria #11:Black Start-up Black start-up capability is to be provided for individual systems. Requirements 1.&YoNEquipment for black starts shall be specified to cover emergency conditions, including the loss of communications between area control centers.Provisions for black starts shall be developed with the intent of restoring the integrity of the interconnected system. Planning for black starts shall be coordinated with adjacent systems. Control centers shall be provided with back-up power supplies for a sufficient period of time. Recommendations 1. 2. ASCC Planning Criteria #11,Page 1 of 1 When designing a generating unit,an outside source of power for generating unit Start-up should be included or adequate redundant transmission provided for emergency start-up capability. The following should be considered when planning transmission system voltage compensation. 2.1.Shunt capacitors or reactors should be placed on the electrical system toallowre-energization of lightly loaded transmission lines with the ability to compensate at the closest available location. 2.2.Effects of energizing high voltage cables at the end of a long,lightly loaded line should be considered when sizing reactors. 2.3.The capability of the generators to provide or absorb Vars should be considered when sizing dynamic or switched compensation. 24.The limits on the automatic voltage control devices and protective time delays should be considered when designing the transmission system. Adequate automatic synchronizing locations and equipment should be provided to enable system operators to readily respond to system disturbances. Each generating plant should have a source of emergency power to expedite restarting.Hydroelectric plants should have internal provisions for restarting. Back-up voice telecommunications facilities,including emergency power supplies and alternate telecommunication channels should be provided to assure coordinated control of operations during the restoration process. Control centers using SCADA systems should consider providing single point control for tripping and restoring each station to expedite restoration and shedding of load. ASCC Planning Criteria #12:Fuel Supply Pians for generation additions shall consider fuel supply diversity. Requirements 1,Fuel availability analyses and economic studies of alternate fuel types shall be performed whenever utility long-range planning indicates the need for additional generation.Such studies shall consider the likelihood and impacts of fuel price variations and fuel shortage scenarios. 2.Studies of the adequacy of fuel supplies for planned generation additions shall be conducted to verify that such supplies are sufficient for projected unit operations over the expected life of the planned unit(s). Recommendation Diversity of supply sources,transportation methods,and storage requirements should be considered in plans for future generation. (Remainder of page intentionally blank) ASCC Planning Criteria #12,Page 1 of 1 ,16 Automatic Underfrequency Load Shedding: Avallabllity: Avoided Cost: Biomass: Bulk Electric System: Capability: Capacity: Capacity Margin: Capacity with Full Reserve: Capacity without Reserve: Cogenerator: Coincident Peak Demand: Connecting Utility: Conservation: North American Electric Reliability Council (NERC)TermsandDefinitions Metered electricity that flows from one control area to another. The ability of the bulk power electric system to supply the aggregate electric powerandenergyrequirementsoftheconsumersatalltimes,taking into accountscheduledandunscheduledoutagesofsystemcomponents. To compare against a norm or standard or to compare among units of a group. The disconnectingof lines or transformers,and thereby customers,through the useofrelaysactuatedbyaloweringofthesystemfrequencybelow60Hz. Availabilityisaterm describing the readiness of a unit to generate electricity,eventhoughtheunitmaynotbegeneratingatthatmoment. The cost an electric utility would otherwise incur to gencrate power if it did notpurchaseelectricityfromanothersource. Any organic material not derived from conventional fossil fuels.Examples are animal waste,agricultural or forest by-products and municipal refuse. The generation and transmission network facilities of an electric system. Synonymous with capacity. A measure of the ability to generate electric power,usually expressed inmegawattsorkilowatts.Capacity can refer to the output of a single generator,aplant,an entire electric system,a Power Pool or a region. The difference between Capacity aud Peak Demand divided by Capacity.TheCapacityMarginisoftenexpressedinpercentbymultiplyingby100. The highest (in availability)form of capacity transaction.The systemisobligatedtodeliverpowerandenergyataspecificdegreeofreliability.The selling systemmustpurchasepowerortakeotherappropriateactionsbeforecurtailingthetransactions. A transaction in which the capacityis supplied when available from the aggregateofgeneratingunitsoftheseller.The seller does not have to deliver power andenergywhenevercertainsystemconditionsexistthatwouldimposeunduehardshipontheseller. Afacility which produces both electric energy and steam or forms of useful energy(such as heat)which are useful for industrial,commercialheatingorcooling purposes. The Peak Demand for a group of systems in combination,ie.,the Peak Demandonewouldsceifthegroupwereasinglesystem. The utility to which the non-utility generator is connected.(Often referred to as the "host utility'.) Implementation of measures that decrease energy consumption of targeted endusesresultinginbeneficialloadshapechanges,often by encouraging the use ofmoreefficientappliancesandequipment. NERC Terms and Definitions,Page 1 of 6 -17 Contingencies: Contingency: Control Area Utility: Control Area: Criteria: Demand or Load: Electric Utility: Electrical Energy: Extreme Contingencies: Forced (Unplanned)Outage: Fuel Cell: Inadvertent Interchange: Inoperable: Events on the bulk electric system which could adversely affect its reliability. The unexpected failure or outage of a system component (generator,transmissionline,breaker,switch,etc.). The utility operating the contro!area in which the non-utility generator is located - An electric system(s)capable of regulating generation to maintain interchange schedule(s)with other systems and to contribute its obligation to help maintain Toterconnection frequency. The measuring systems and performance standards used for assessing the actualorprojectedreliabilityofagivenbulkelectricsystem.Failure to attain a specifiedperformancestandardindicatesthemeedtoconsideraddingorrearrangingfacilities,changing operating modes or other responses.Examplesof criteria thatmightapplytoplanningforgenerationadequacyare: a)Generating Capacity Margin b)Loss-of-Load Probability c)Loss-of-Energy Probability Examples of criteria that might apply to simulated testing of the bulk electric system are: a)No cascading following any of a specified set of contingencies b)No overloaded facilities following a specified contingency c)Al voltages within prescribedlimits The instantancous electric requirement ofa power system,usually expressed inunitssuchasmegawatts(MW)or kilowatts (KW). Any entity owning and operating an electric system for the purposes of sale &.f resale to the end users. The generation or use of electric power by a device over a period of time,usuallyexpressedinwatthours,kilowatthours (Kwh),megawatthours (MWh),or gigawatthours (GWh). Events or combinations of events which have a low probability of occurring,wouldseverelystressthesystem,and have the potential to lead to a widespread cascading outage. (Generating Unit)The occurrence of an unplanned component failure (immediate,delayed,postponed)or other condition which requires that a generating unit beremovedfromserviceimmediatelyorbeforethenextweekend.A forced(unplanned)derating occurs when the load on a generatingunit mustbereducedimmediatelyorbeforethenextweekend. A device in which a chemical process is used to convert a fucl directly into The difference between a control arca's actual interchange and scheduled interchange. Capacity out of service for reasons such as being limited by environmentalrestrictions,legal or regulatory restrictions,extensive modifications or repairy”capacity specified as being in a mothballed state.Beet NERC Terms and Definitions,Page 2 of 6 18 Interchange: interconnection: Internal Demand: Interruptible Customer: Interruptible Load: Involved Utility: Load Management: Load Shedding: Loss (ASCC Reliability Criteria Subcommittee definition): Loss of Load Probability: Margin: More Probable Contingencies: Net Capacity: Net Demonstrated Capacity: Net Dependable Capacity: Non-coincident Peak Demand: Electricity that flows from one control area to another. When capitalized (Interconnection),any one of the four bulk electric systemnetworksinNorthAmerica:Eastern,Western,Quebec,and Texas,When not capitalized (interconnection),the facilities that connect two systems or contro! areas, The maximum integratedclockhoursum of the demandsofall customers whichasystemservices,plus the losses incidental to that service.Internal Demand isquantifiedbysummingthemetered(net)outputs of all generators within thesystem,plus the metered line flows into the system,minus the metered line flows out of the system. A utility customer that,by contract or tariff,can be shed by the utility before shedding other customers. Customer demand that can be curtailed,i.c.,interrupted,by action of the system operator in accordance with contractual arrangements. Any and all utilities that play a role in delivering electric energy from the non-utility generator to the purchasing utility.This may includs the connecting utility, one or more control area utilities,the wheeling utility,the purchasing utility,or any other utility impacted by the non-utility generator's operation. A procedure in which customer demand can be controlled through the direct action of the system operator through actual interruption of electric supply to individual appliances or equipment on the customer's premises. Disconnecting or interrupting the electrical supply to a customer load by the utility,usually to mitigate the effects of generating capacity deficiencies or transmission limitations. Unscheduled unavailability of a system component. A measure of the expectation that system demand will exceed capacity during agivenperiod,often expressed as the expected number of days per ycar. The difference between capacity and peak demand.Marginis usually expressedinmegawatts. Events which are more likely to occur,but which have a less severe impact on system reliability than extreme contingencies. The gross capacity of a generating unit as measured at the generator terminals lessthepowerrequiredfortheauxiliaryequipment(such as fan motors,pump motorsandotherequipmentessentialtooperatetheunit). Synonymous with Net Dependable Capacity. The maximum capacity modified for ambient limitations which a geucrating unit,power plant or system can sustain over a specified period of time,less the unitcapacityusedtosupplythedemandofthatunit's station service or auxiliary needs. The sum of individual systems'Peak Demands,regardless of when they occur, Non-coincident Peak Demand will always be greater than or equal to the Coincident Peak Demand. NERC Terms and Definitions,Page3of6 19 Non-utility Generator: Parallel Flow: Power Pool: Purchasing Utility: R/W (Right-of-Way): Rating: Reactive Power: Regional Council Criteria: Regional Council: Regional Reliability Council: NERC Terms and Definitions,Page 4 of 6 A general term embracing facilities named in the Public Utilities RegulataryPoliciesAct(cogencrators and small power producers)and any other non-utilitygeneratingfacilitiesconnectedtotheutilitysystem.Facilityforgeneratingelectricitywhichisnotexclusivelyownedbyanelectricutilityandwhichoperatesconnectedtoanelectricutilitysystem.foo; Electric flow oa a uilty's transmission system resulting from electricity flowsscheduledonanyothersystem.Electricity flows on all parallel paths in amountsinverselyproportionaltoeachpath's impedance. A buyer,producer,or wheeler of electricity in an interchange agreement or contract. The highest electric requirement experienced by a power system in a given periodoftime(eg.a day,month,scason or year).In practice,Peak Demand iscalculatedbydividingtheenergyusedoverashortperiodoftime,usually an hour,by the length of that period of time. Two or more interconnectedpowersystems operatedasasystem and pooling theirresourcestosupplythepowerandenergyrequirementsofthesystemsinareliable and economical manner. The utility that is purchasing electrical energy or capacity from another utilityornon-utility generator. The corridor of land within which transmissionlinesare routed and within whichtheowningutilityhascertainrightsofaccessandconstruction. The output capability of a generator determined under specified conditions.Th rating of a transmission lincis its capability to carry electric current,as determin”... under specified conditions.Ce.ie The portion of power that establishes and sustains the electric and magnetic ficldsrequiredtoperformusefulwork.Reactive power must be supplied to most typesofmagneticequipment,such as motors in refrigerators and air conditioners,andtoheavilyloadedtransmissionlines.It is suppliedbygenerators,synchronouscondensers,or electrostatic equipment,such as capacitors.It directly influencestheelectricsystemvoltage. Criteria applied within a Council to assess the interaction of the plans of individualutilitiesforthebulkelectricsystemfacilitieswithintheCouncil.These criteriaincludemethodsandproceduresforratinggeneratingunitsandotherfacilities,data systems and intersystem protection philosophies,and the specification ofsimulatedteststobeperformed.In some cases,these activities are carried out asfunctionofanareaorsubregionalgroupwithinaRegionalCouncil,in which casetherewouldbeareaorsubregionalcriteria. Onc of nine electric Reliability Councils that form the North American Electric Reliability Council (NERC).(NERC was formed in 1968 by the electric utility industry to promote the reliability and adequacy of the bulk power supply im the electric utility systems of North America.) One of nine electric Reliability Councils that form the North American Electric Reliability Council (NERC).-Mo Reliability: Standby Power: System Criteria: System: Unavailable Capacity: In a bulk electric system --the degree to which the performance of the elementsofthatsystemresultsinpowerbeingdeliveredtoconsumerswithinacceptedstandardsandintheamountdesired.The degree of reliability may be measuredbythefrequency,duration,and magnitude of adverse effects on consumer service.Reliability can be addressed by considering two basic and functional aspects of thebulkelectricsystem-adequacyandsecurity. The difference between Capacity and Peak Demand divided by Peak Demand.The Reserve Margin is often expressed in percent by multiplying by 100. Synonymous with Margin. Electricity scheduled to flow between control arcas,usually the net of all sales,purchases,and wheeling transactions between those parties at a given time. The ability of the bulk power electric system to withstandsuddendisturbancessuchaselectricshortcircuitsorunanticipatedJossofsystemcomponents. Designed to perform system protection functions other than the isolation ofelectricalshortcircuits.They are used to automatically reconfigure the electric system by disconnecting generators,opening lines,shedding load,and other actionstomaintainstabilityorcontrolpowerflowsonsurvivingcriticalfacilitiesimmediatelyfollowingadisturbanceonthesystem. Power used to serve customer demand in accordance with contractual arrangements to provide power and evergy to a customer (often for an industrial customer having his own generation)as a second source or backup for the outageoftheprimarysource.Standby Power is intended to be used infrequentlybyanygivencustomer. Criteria used by individual utilities,or other entities which have financialresponsibilityforcommitmentofnewfacilities,in planning facilities or assessingplans.These criteria include methodologies for testing and measuring systemperformanceandmayincludeindicesofsatisfactoryperformance. The physically connected generation,transmission,distributionandotherfacilitiesoperatedasanintegralunitunderonecontrol,management or operatingsupervision,often referred to as "electric system","electric power system"or"power system". A network of transmission lines and the substations to which the lines areconnected.' To disconnect a system component by opening the circuit breaker(s)or otherswitch(es)that connect it to the system,usually to isolate or disconnect a failedsystemelementtoprotectitandtherestoftheofsystemfromdamageortoperformmaintenance, The amount of Capacity that is known,expected or statistically predicted to be notavailabletomeetsystemdemandduringtheperiodoftimebeingconsidered.Known or expected Unavailable Capacity includes capacity out of service due toscheduledunitmaintenanceandderatings.Statistically predicted UnavailableCapacityincludesunplannedorforcedoutages,outages that are planned with a short lead time,and capacity limitations as a result of temporary operating conditions. NERC Terms and Definitions,Page 5 of 6 21 Unit Power: Voltage Reduction: Wheeling Customer: Wheeling Utility: Wheeling: NERC Terms and Definitions,Page 6 of 6 Power from one or more specific generating units.Unit Power purchases andsalesareformsofcapacitytransactionswithoutfullreserve.Capacityissoldfrononeormorespecificunitsforacertainperiodoftime.Delivery of power antenergyiscontingentontheunitbeingavailable.cee A means to reduce the demand on a utility by lowering the voltage.Usua.,:performed on the distribution or subtransmissionsystem. Any party contracting with a utility for wheeling service on that utility'stransmissionsystem.The party may eitherbe the producer or purchaser of theelectricitybeingwheeled. A utility providing transmission service for another party's electricity. The use of the transmission system facilitics of one or more partiestotransmit electricity for another party.