Interchange 1

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nibor222
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195944
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Interchange 1
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2013-04-18 06:18:27
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Interchange
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Interchange Term
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  1. Select the appropriate definition of Interchange:

    a. Transmission arrangements for moving energy across Balancing Authorities

    b. Transmission arrangements for moving energy between Transmission Operators

    c. Energy transfers that cross Balancing Authorities

    d. Energy transfers that cross Transmission Operators
    a. Transmission arrangements for moving energy across Balancing Authorities
  2. Continental North America is divided up into how many electrical interconnections:

    A. 1
    B. 3
    C. 4
    D. 2
    B. 3
    (this multiple choice question has been scrambled)
  3. Identify the benefits (select all that apply) to power systems being electrically interconnected:

    a. Efficiency
    b. Markets
    c. Reliability
    d. Large disturbances
    e. All of the above
    e. All of the above
  4. A Balancing Authority is:

    a. 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.

    b. 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.

    c. The entity responsible for the reliability of its “local” transmission system, and that operates or directs the operations of the transmission facilities.
    a. 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.
  5. A Transmission Operator is:

    a. 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.

    b. 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.

    c. The entity responsible for the reliability of its “local” transmission system, and that operates or directs the operations of the transmission facilities.
    c. The entity responsible for the reliability of its “local” transmission system, and that operates or directs the operations of the transmission facilities.
  6. A Purchasing-Selling Entity is:

    a. 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.

    b. 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.

    c. The entity responsible for the reliability of its “local” transmission system, and that operates or directs the operations of the transmission facilities.
    b. 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.
  7. T or F – A Transmission Service Provider is responsible for administering the transmission tariff and providing transmission services to Transmission Customers under applicable transmission service agreements.
    Answer: True
  8. BC Hydro is registered as the following, select all that apply:
    a. Purchasing-Selling Entity
    b. Balancing Authority
    c. Transmission Operator
    d. Transmission Service Provider
    e. Interchange Coordinator
    • b. Balancing Authority
    • c. Transmission Operator
    • d. Transmission Service Provider
  9. What is our neighbouring Balancing Authority to the East?
    Alberta Electric System Operator (AESO)
  10. What is our neighbouring Balancing Authority to the South?
    Bonneville Power Administration (BPA)
  11. What is a Path? How many paths does BC Hydro have with neighbouring Balancing Authorities and what are they identified as?
    A path is the connection between balancing authorities. There are two paths. Path 1 is the intertie with Alberta and path 3 is the intertie to the US.
  12. Which transmission facilities make up Path 1?
    • 5L94 Cranbrook - Langdon sub
    •  
    • 1L274 Natal - Pocaterra sub
    •   
    • 1L275 Natal - Coleman sub
  13. Which transmission facilities make up Path 3?
    • 5L51 & 5L52 Ingledow – Custer sub (west-side ties)
    •  
    • 2L112 Nelway – Boundary sub (east-side tie)

    L71 Waneta – Boundary sub (east-side tie, normally open)
  14. Define POR.
    A location that the Transmission Service Provider specifies on its transmission system where an Interchange Transaction enters or a Generator delivers its output.
  15. Define POD.
    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.
  16. Describe the internal paths that BC Hydro uses to move energy inside the province.
    Interior portions of BC to the Lower mainland. BC Hydro to FortisBC and also other IPP’s.
  17. What is a wheelthrough? On which paths do we have wheelthroughs?.
    A wheelthrough path again is a contractual path for the flow of energy across various transmission facilities. AB-US and US-AB
  18. What is the definition of TTC?
    Total Transfer Cabability


    • TTC is defined as the maximum amount of actual power that can be transferred over direct or parallel transmission elements comprising:
    •  
    • -       An interconnection from one Transmission Operator area to another Transmission Operator area.
    •  
    • -       A transfer path within a Transmission Operator area.
  19. T or F – BC Hydro follows the Rated System Path Methodology for the development of its TTCs from MOD-029
    True
  20. What is the maximum TTC for Path 1 in each direction?
    • East to West 1000 MW 
    • West to East 1200 MW
  21. What is the maximum TTC fro Path 3 in each direction?
    • North to South 3150 MW 
    • South to North 2000 MW
  22. Define Incremental Transfer Capability. Where are Incremental TTCs found for both Path 1 and Path 3 from a BC Hydro perspective?
    • During times when the system is not normal and the path transfer capability is not at the maximum, incremental transfer capabilities will be incorporated from system studies.
    •  
    • SOO 7T-17
    • SOO 7T-18
  23. T or F – The TTC that is set on an hour by hour basis is used as the foundation for the purchase of transmission service.
    True
  24. T or F – TTCs are entered by the Transmission Coordinator on the Effective TTC display in MODS.
    True
  25. Define TRMu.
    Transmission Reliability Margin Unreleased (TRMu) is an amount of transmission set aside to account for uncertainties in load forecasting and other errors.
  26. Define TRM.
    Transmission Reliability Margin (TRM) is an amount of transmission set aside to between the TTC limit and the ATC Firm Limit where ATC stands for the Available Transfer Capability.
  27. What is the definition of ATC?
    Available Transfer Capability
  28. What is the Scheduling Limit?
    The Scheduling Limit (SL) is the maximum amount of Net Scheduled Interchange that can exist across a path.
  29. What is Counterflow Energy Schedules and how does it impact the Scheduling Limit?
    CES are energy schedules flowing the opposite direction of the TTC direction. The CES MW are subtracted from the “Net Schedule”
  30. What is the definition of OTC? Is it synonymous with TTC from a BC Hydro perspective?
    Operating Transfer Capability is to be the maximum path rating which may be impacted by temporarily due to short duration outages of transmission elements.
  31. What is the calculation for the Scheduling Limit? Does this calculation ensure the net schedules for a path stay below the OTC/TTC limit?
    Scheduling Limit = TTC – TRMu (excluding counterflow). Scheduling Limit ensures net schedules are always equal or less than the OTC/TTC limit.
  32. Where is OTC monitored?
    OTC is monitored by the AREVA EMS.
  33. Do TTC limits from MODS get automatically entered in the OTC Monitoring display in AREVA?
    Yes they are automatically entered
  34. Can manually entered values in the OTC Monitoring display override the TTC entered from MODS for OTC monitoring?
    Yes they can override
  35. What happens if the actual schedule exceeds the TTC limit in the OTC monitoring display?
    A violation timer starts and alarms are received by the TC and GC.
  36. What is the maximum amount of time OTC can be violated for a stability constraint?
    20 minutes
  37. What is the maximum amount of time OTC can be violated for a thermal constraint?
    30 minutes
  38. Describe various reasons for OTC violations.
    Overscheduled, TRM violation or contingencies.
  39. Say you were importing energy from the US right up to the Scheduling Limit of 1950 import. If you are also exporting to AB and they are taking 75 MW more than they should be, could you end up in and OTC violation on the US path. Describe why this could happen.
    Yes it is possible. If we weren’t generating enough power than it could be pulled through the US to supply the AB export.
  40. T or F – Transmission Service is required for a customer to contractually move power across BC Hydro transmission facilities
    True
  41. Transmission Service is divided up into two types. What are they? What does Point-to-Point mean?
    Long Term Firm Point-to-Point is pre-scheduled (minimum one year term) and Short Term Point-to-Point is dealt with in RTO (service for a term less than a year)
  42. T or F – Real Time Operations only deals with Long Term Point-to-Point Transmission Service.
    False
  43. Briefly describe Ancillary Services.
    • Those services that are necessary to support the transmission of capacity and energy from resources to loads while maintaining reliable operation of the
    • Transmission Service Provider's transmission system in accordance with good utility practice.
  44. Transmission Service is broken down by different priority codes. List the priority codes from highest priority to lowest and describe each product by type.
    • 7F    - Firm including Conditional Firm Service
    • 6NN - Network (Type 1) 
    • 5NM – Non-Firm Monthly
    • 4NW – Non-Firm Weekly
    • 3ND – Non-Firm Daily
    • 6NN – Network (Type 2)
    • 2NH – Non-Firm Hourly
    • 1NS – Non-Firm Secondary
    • 0NX – Next Hour Market
  45. Where does BC Hydro post TTC / ATC information?
    On OASIS
  46. T or F – All Transmission Service Requests must be made through OASIS.
    True
  47. Briefly describe Ancillary Services.
    In smart grid technology, an ancillary service is anything that supports the transmission of electricity from its generation site to the customer. Services may include load regulation, spinning reserve, non-spinning reserve, replacement reserve and voltage support.
  48. What types of increments is Transmission Service sold in?
    Hourly, Daily, Weekly and Monthly
  49. Explain the TSR submission times for Short Term Firm transmission service offerings.
    Earliest request for monthly is 60 calendar days before start of service, weekly 14 calendar days, daily 2 working days, hourly 1 working day and real time 1 before start of service. Latest is 1 minute before start of service, or 1 minute before end of hour in real time
  50. Explain the TSR submission times for Short Term Non-Firm transmission service offerings.
    Earliest request for monthly is 60 calendar days before start of service, weekly 14 calendar days, daily 2 working days, hourly 1 working day and real time 1 before start of service. Latest is 1 minute before start of service, or 1 minute before end of hour in real time
  51. Explain how TSRs are validated.
    • BC Hydro validates each attribute on submitted TSRs, including but not limited to:
    • - Submission time
    • - Valid Path and POR/POD combination
    • - MW Requested
    • - Bid Price
    • - Service Increment
    • - Start/Stop time
    • - Pre-confirm
  52. What are Grandfathered Transmission Rights?
    Grandfathered rights come from the Kootney Canal Agreement and the fact that they had the original connection and scheduling rights
  53. What circuit does Teck-Cominco retain Grandfathered Transmission Rights on?
    L71 runs from WAN substation (FBC) to NLY (BC Hydro)
  54. T or F – the L71 Grandfathered Transmission Rights grant Teck-Cominco Firm import and Firm export transmission on Path 3
    True
  55. What is FortisBC responsible for doing from a day-ahead scheduling perspective with their Grandfathered Transmission Rights?
    Hourly amounts of transmission capacity within Teck Cominco Export Scheduling Rights and Import Scheduling Rights to be reserved for Teck Cominco Energy Schedules on the following day. Pre-schedule will reduce Teck Cominco rights and post the ATC to the market.
  56. T or F – FortisBC scheduling energy on the L71 Grandfathered Transmission Rights follows normal energy scheduling protocol
    True
  57. What is a Redirect? Describe the two types of Redirects.
    When a transmission customer wants to modify the POR, POD or both.
  58. What is a Resale and how is it done?
    Transmission Customers may sell, assign, or transfer all or a portion of its rights, but only to another Eligible Customer. Posted on OASIS
  59. What is a Transfer and how is it done?
    A Transfer is where a reseller transfers all of the rights and obligations under an existing, Confirmed Firm yearly and Confirmed Firm and Non-Firm monthly transmission service. Transfers must be posted and approved on OASIS and are subject to the rules in the Business Practices.
  60. What is an eTag? What information comes across in an eTag?
    An eTag is an electronic documentation of the energy transaction describing the source, sink, path, transmission contracts to be used, capacity profiles and parties to the transaction.
  61. Who is responsible for submitting eTags?
    The customer
  62. What system are eTags submitted through?
    OATI ETS system
  63. Etags must be on ___________ transmission service requests.
    CONFIRMED
  64. TSRs used on an eTag must satisfy what conditions for the eTag to be approved?
    • ·         be CONFIRMED and active in OASIS and BC Hydro’s scheduling system;
    • ·         in aggregate have sufficient available energy capacity to accommodate the energy schedule and the transmission allocation profile;
    • ·         must have the same POR and POD combination;
    • ·         the eTag transmission allocation profile must be greater than or equal to the energy profile; and
    • ·         must not cause a Reliability Limit infringement. If eTags had previously been approved, BC Hydro will deny the eTag for insufficient capacity.
  65. PSEs can use one of three different approaches to specify transmission on its eTags, what are they?
    • 1)    OASIS ID
    • 2)    Blanket Approach
    • 3)    Stacked Transmission Approach
  66. What are Product Codes used for on eTags?
    To track the type of transaction
  67. What is a PSE Assigned Cut Priority? What does this allow the customer to dictate?
    PSE Assigned Cut Priority is an assigned number dictating priority. Numbers with 1 are to be curtailed last, 2 is second highest priority, etc.
  68. For Real-time, what is considered “Late” with respect to an eTag?
    All ETAG’s must be received no later than 20 minutes prior to the start of the eTag
  69. What are some of the validation rules BC Hydro uses for eTags?
    • ·         submission time
    • ·         WECC reserve requirement
    • ·         Contingency reserve requirement
    • ·         source/sink
    • ·         market path
    • ·         start / stop time
    • ·         generation profile
    • ·         energy product code
    • ·         transmission assignment
  70. With respect to an eTag, what is a Modification?
    Transmission Customer may request modifications to an ARRANGED, PENDING, CONFIRMED or IMPLEMENTED eTag for non-reliability related issues according to the WECC timing requirements listed in the Business Practices.
  71. With respect to an eTag, what is a Correction?
    • A correction can only be made to a PENDING eTag. Corrections can be made to:
    •  
    • ·         POR and POD
    • ·         Designated transmission reservation
    • ·         Miscellaneous Information Value field on the Load or Generation Line Product Code in the Market Path
  72. With respect to an eTag, what is an Adjustment?
    • An adjustment can only be made to a CONFIRMED or IMPLEMENTED eTag. Adjustments can be made to:
    •  
    • ·         Generating Profile
    • ·         Transmission Profile
    • ·         Extension to the energy profile (to include hours not previously specified).
  73. What is an Interruptible Energy Schedule? How is it identified in MODS
    Interruptible Energy (Non-Firm energy) is energy that the PSE has specified may be interrupted for any reason, including reliability. With a G-NF in the Market Path
  74. What does a PSE have to enter in the eTag to make an energy schedule Interruptible?
    • Entering G-NF in the Market Path section in the Product Code drop-down List.
    •  
    • Entering the appropriate WECC reserve requirement – the reserve obligation multiplier should be set to 100%.
  75. What is a Capacity Schedule? How is it identified in MODS?
    Capacity Schedules are used to set aside transmission capacity which will ensure “Reserve” products can be delivered if dispatched by the entity requiring the reserves.
  76. What is a C-RE schedule? How is it identified in MODS?
  77. C-RE schedules are energy which is recallable within ten minutes of activation
    of reserves. They are separated out on the Interchange Summary
  78. What action must be taken on a C-RE “in-hour” adjustment?
    They must be approved in the C-RE cases.
  79. What is a Dynamic Schedule? How is it identified in MODS?
    • Dynamic Schedules are used to set aside transmission capacity which will ensure “Dynamic” products can be delivered if dispatched by the entity requiring the energy schedule.
    •  
    • They are actually labelled Dynamic Schedule and have a product code of 7-F
  80. What is CRO?
    Contingency Reserve Obligation

    5% of hydro generated and 7% of thermal
  81. What is SRO?
    Spinning Reserve Obligation

    50% of the CRO must be SRO
  82. What is CRR?
    Contigency Reserve Requirement

    CRR - Used CRs + Interruptible Import schedules, emained Contingency Reserve contracts, Spinning Reserve contracts, Regulating Reserve contracts, SSOR contract less SSOR delivery
  83. What is SRR?
    Spinning Reserve Requirement

    SRO + Spinning Reserve contracts
  84. What is the definition of NSI? How is NSI calculated for the BCHA Balancing Authority?
    • Net Scheduled Interchange is used to dictate, as a net, how much additional energy is required on line over and above the load to meet load plus interchange requirements.  
    •  
    • The Net Scheduled Interchange is the summation of the AESO Net Schedule and the BPA Net Schedule, where each is the sum of all the imports and exports on each.
  85. What is the definition of NAI? How is NAI calculated for the BCHA Balancing Authority?
    • Net Actual Interchange is the actual energy that flowed in the last hour. The overall Net Actual Interchange is not known until the end of hour.
    •  
    • Each tieline is measured and the overall MWh of each is calculated by each which adds up to the NAI.
  86. What is the ramp duration for the Western Interconnection? When does the ramp for HE16 start?
    The Western Interconnection ramp duration is 20 min.

    The ramp for the HE16 starts at 14:50
  87. When is the NSI passed over to the EMS from MODS for HE16 NSI?
    It is passed at 14:47
  88. If MODS has an NSI of -1885 for HE16 and all tags are approved, what should WIT say the NSI is?
    -1885 an overall net import
  89. What is Inadvertent Interchange? How is it calculated? What are the two accounts II can fall into and which hours fall into which account?
    • Inadvertent Interchange is defined as the difference between Net Scheduled Interchange and Net Actual Interchange.
    •  
    • Calculated as II = NSI – NAI
    •  
    • Two accounts are Light Load Hours being HE01-06 and HE23 and HE24 and Heavy Load Hours being all other hours
  90. How does NSI change after the hour is over and what must be done?
    The Net Schedules must be verified again with AESO and BPAT to factor in any Dynamic Energy deliveries or Capacity Reserve deliveries.
  91. When does a curtailment occur?
    • Occurs in the following two cases:
    •  
    • ·         A valid, higher class transmission reservation interrupts a lower-class transmission reservation
    •  
    • ·         A Non-Firm transmission reservation is purchased from unused capacity of Firm transmission and the Firm transmission owner schedules on their right
  92. What is the calculation for the Scheduling Limit?
    Scheduling Limit = TTC – TRMu – Existing Transmission Schedules – Reserves + Counterflow Energy Schedules
  93. How are eTags ranked in priority from highest to lowest?
    Dynamic, Reserves/Capacity, Normal/Uninterruptible and then Interruptible/Recallable
  94. Curtailments of eTags are performed according to what two factors?
    LIFO and pro-rata
  95. Once a cutlist has been Implemented, when would you expect to see a change to your Schedule?
    Once the curtailments have been approved by the source and sink.
  96. What are some of the reasons there may be a mid-hour curtailment?
    Insufficient reserves, Loss of generation facilities and Loss of a transmission facility that affects transmission limits
  97. When is BC Hydro responsible for making mid-hour curtailments?
    Only for problems within BC
  98. What is the procedure for processing a mid-hour curtailment?
    • 1)    Verify total amount being curtailed
    •  
    • 2)    Notify Generation Coordinator (GC) of Pending Schedule Change and amount of change.
    •  
    • 3)    Upon GC Approval, Manually Approve Curtailments in MODS.
    •  
    • 4)    Ensure the correct schedule is uploaded to EMS (note: MODS NSI will show the Integrated Value)
    •  
    • 5)    Checkout with adjacent BA’s for new schedule.
    •  
    • 6)    Log in hour curtailment in daily log. Adjust PI-DBVU numbers as necessary. 
  99. Besides the Interchange Scheduler, who should be aware of in hour curtailments?
    The GC must be notified
  100. What is an Integrated Value?
    Energy schedules that are curtailed mid-hour will have an integrated value associated with them that is less than the original value.
  101. What is the Integrated Value of a 100 MW schedule that is cut to zero at xx:39 and stays zero for the rest of the hour?
    (39/60)100 = 65
  102. What is a reload?
    • ·         A constraint that was affecting transmission limits has been lifted and energy schedules that were flowing but curtailed when the limit was put in place can be restored
    •  
    • ·         A generator comes back on line that was supporting a schedule
    •  
  103. What is the procedure for processing a reload?
    • 1)    Verify total amount being reloaded.
    •  
    • 2)    Notify Generation Coordinator (GC) of Pending Schedule Change and amount of change.
    •  
    • 3)    Upon GC Approval, Manually Approve Curtailments in MODS.
    •  
    • 4)    Ensure the correct schedule is uploaded to EMS (note: MODS NSI will show the Integrated Value)
    •  
    • 5)    Checkout with adjacent BA’s for new schedule.
    •  
    • 6)    Log in hour curtailment in daily log. Adjust PI-DBVU numbers as necessary.
    •  
    •  
  104. Define a Reserve Sharing group. Which reserve sharing group does BC Hydro belong to?
    A Reserve Sharing Group shares the Most Severe Single Contingency proportionately between Balancing Authorities.

    BCH is a member of the Northwest Power Pool (NWPP)
  105. If BCH was generating 4875MW of hydro generation and 1872MW of thermal generation, what would the CRO be? How much SRO?
    • 5% for hydro generation and 7% for thermal generation
    •  
    • CRO = (4875MW x 5%) + (1872MW x 7%) = 374.79MW
    •  
    • SRO = (374.79MW)0.5 = 187.4
  106. What might the GC ask the interchange scheduler to do to maintain BC Hydro’s CRO?
    Curtail export schedules
  107. BC has lost 400MW of generation. The CRO is at 300MW and there is 88MW of Spinning Reserve contracts in effect for this hour. What would the CRR be?
    CRR = CRO + Spinning Reserve contracts = 300 MW + 88 MW = 388 MW
  108. T or F – Before BCH can request Reserve Sharing, it must have committed all of its available CRO.
    True
  109. How would Alberta request a contracted spinning reserve from Hydro?
    They would request from Powerex and an etag would come through MODS for our manual approval.
  110. How are etags submitted for Contingency reserve requests? Are there Transmission Service Requests set aside for reserve deliveries?
    The etags are automatically generated. Yes there are TSR set aside for reserve deliveries.
  111. Who is responsible for recording all applicable transmission and energy schedules for reserve deliveries?
    Powerex
  112. When does Emergency Assistance Energy apply?
    NERC Energy Emergency Alert 2
  113. Before a request for emergency energy is made, what must the requesting party have done?
    Exhausted all available options in the market to address its needs
  114. T or F- The providing party will not risk reliability of its own system when asked for emergency energy.
    True
  115. How will the providing party determine the amount of emergency energy capacity available?
    • ·         The requested amount of emergency energy
    •  
    • ·         The amount of energy available from supplemental and excess spinning reserves
    •  
    • ·         The available capacity of the BC-AB intertie
    •  
  116. How is emergency energy paid back?
    • All emergency energy received under this Agreement will be returned in accordance with the following:
    •  
    • ·         It will be returned within one calendar week of its provision.
    •  
    • ·         Energy will be returned in kind of the amount and likeness of the energy received. For example, 50 MW Heavy Load Hours (HLH) for 50 MW HLH or 100 MW Light Load Hours (LLH) for 100 MW LLH.
    •  
    • ·         Each party will have the right to audit records of the other party pertaining to emergency energy assistance transactions.
  117. What will the interchange scheduler need to do in an Emergency assistance situation?
    • ·         Enter a manual Transmission Reservation in MODS for the capacity. Note “Emergency Assistance Energy” on the TSR.
    •  
    • ·         Consider manually approving emergency tags
    •  
    • ·         Help GC determine new Net Scheduled Interchange and confirm numbers with adjacent BA’s.
    •  
    • ·         Have Powerex submit a late e-tag after-the-fact within 1 hour to schedule the MWh on the Transmission Reservation.
    •  
  118. What is the General Wheeling Agreement?
    The General Wheeling Agreement was created to establish the terms and conditions for West Kootenay Power to wheel electricity on a firm basis over BC Hydro transmission facilities.
  119. What are the Points of Interconnection between BC Hydro and FortisBC to which electricity may be wheeled from the point of supply under the General Wheeling Agreement?
    • ·         FortisBC’s 230 kV bus at the Lambert Substation (the “Creston Point of Interconnection”).
    •  
    • ·         BC Hydro’s 230 kV bus at the Vernon Substation and FortisBC’s 230 kV bus at Vaseux Lake Terminal Station (collectively, the “Okanagan Point of Interconnection”).
    •  
    • ·         FortisBC’s tap on BC Hydro’s transmission line 1L251 near Princeton (the “Princeton Point of Interconnection”).
    •  
  120. What is the process for a Wheeling Nomination?
    Following receipt of the Nominated Wheeling Demands from FortisBC, BC Hydro shall respond within 30 days and shall either accept such Nominated Wheeling Demands or state the maximum amount that can be Wheeled by existing facilities and new facilities that are planned to be brought into service.
  121. Define Emergency Wheeling. What are BC Hydro’s responsibilities regarding Emergency Wheeling?
    • Under the General Wheeling Agreement, “Emergency Wheeling” means requirements for Wheeling which exceed the nominated Wheeling Demands due to unforeseen outages or other bona-fide emergencies on FortisBC’s system.
    •  
    • The GWA also states that BC Hydro shall provide Emergency Wheeling to the extent that normal operation of BC Hydro’s system and service to BC Hydro’s customers shall not be impaired. BC Hydro reserves the right to deny a request for Emergency Wheeling in situations which do not satisfy the GWA Definition of “Emergency Wheeling”.
  122. What are the possible causes for a change in the Net Schedule of a path for a given hour that would cause the requirement of a Post-Hour Checkout?
    If Alberta called on Spin Reserve or Contingency Reserve contracts within an hour, or in-hour curtailments would result in the need for a Post-Hour checkout.
  123. What is often the first indication that there is an issue with OASIS or that the system has failed?
    A phone call from the customer
  124. When is a callout of support staff required to deal with an OASIS disturbance
    If there is an issue with the customer and BCH after hours
  125. When e-Tags are displayed in OATI but MODS is not receiving the energy schedules or not approving the energy schedules, who should the Interchange Scheduler contact?
    • In the event of a disruption or failure with the MODS system, the best practice is to immediately contact the OATI Help Desk by either of the following methods:
    •                  
    • support@oati.net
    •  
    • 763-201-2020
  126. Why is a complete MODS application failure unlikely to occur?
    It has built-in active triple redundancy.
  127. If a communication disruption does occur with MODS, what is the best action for the Interchange Scheduler to take?
    AGC should be run based on interchange schedules received from BPAT and AESO.
  128. Describe the steps involved with switching from the corporate Internet cable to the back-up Shaw Internet cable in the event of an Internet disruption.
    • 1)    Close the MODs application on the Interchange PC
    •  
    • 2)    Locate the MODs computer under the Interchange desk and unplug the corporate internet cable
    •  
    • 3)    Locate the yellow Shaw Internet cable and plug it into the MODs computer
    •  
    • 4)    From your corporate windows desktop display, click “Start” and “Run”
    •  
  129. What is OASIS? Why was it developed?
    • The Open Access Same-Time Information System (OASIS) is a limited access Internet-based electronic tool used by Transmission Service Providers (TSPs) to allow Transmission Customers access to information on the transmission grid and to execute buy/sell transmission transactions.
    •  
    • OASIS was developed in compliance with the FERC order that all utilities that own or control transmission used to transmit electric energy in interstate commerce should participate in or have an OASIS.
  130. What positive effects does an OASIS system provide for the energy market?
    The result should be lower electricity prices for consumers, greater accessibility to other transmission systems and more competition for power in the wholesale market.
  131. What is webTag?
    Webtag Internet-based electronic tool used by TP's and BA's to allow PSE's to apply energy schedules on their transmission reservations.
  132. What is an eTag? Why were eTags developed?
    An eTag is an electronic documentation of the energy transaction describing the source, sink, path, transmission contracts to be used, capacity profiles and parties to the transaction. eTags were developed by the industry to maintain reliability by ensuring that all parties to interchange energy transactions receive relevant reliability information. The eTag system is used to communicate intent to schedule energy and approval or denial and modifications to schedules.
  133. The proper use of eTags ensures what two things?
    • 1)    Matching of an energy schedule to a verified transmission reservation via the use of OASIS reference numbers on all paths involved.
    •  
    • 2)    Instant messaging to all involved parties of any changes made to the energy schedule.
  134. Name and provide a brief description of three of the displays available in MODS that are beneficial for the Interchange Operator to routinely monitor?
    Interchange Summary, Realtime Summary, Tag Request Approval Monitor, Limit Monitor and Segment ATC Impact Summary
  135. What is the formula for firm ATC?
    ATC = TTC - TRM - CBM - ΣETC + ΣPB + ΣCF
  136. What is the formula for non-firm ATC?
    ATC = TTC - TRMu - CBM - ΣETC + ΣPB + ΣCF
  137. What is ATC?
    Available Transfer Capability (ATC) – The amount of transfer capability remaining in the transmission network available over and above committed uses.
  138. What does GCA stand for?
    Generation Control Area
  139. What does PSE stand for?
    Purchasing Selling Entity
  140. What does LCA stand for?
    Load Control Area
  141. What MODS screens are good to have up?
    • - LIMIT Monitor
    • - Realtime Summary
    • - Hourly Segment ATC
    • - Tag Request Approval Monitor
    • - Interchange Summary
  142. What is SL?
    System Operating Limit (SOL): 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.
  143. What is TTC?
    Total Transfer Capability (TTC): The amount of electric power than can be transferred over the interconnected transmission network in a reliable manner while meeting all of a specific set of pre-defined pre- and post-contingency system conditions.
  144. What is TRM?
    Transmission Reliability Margin (TRM): The amount of Total Transfer Capability necessary to ensure that the interconnected transmission network is secure under a possible range of uncertainties in system conditions.

    TRM is the Transmission Reliability Margin for the ATC Path during that period.

    TRMu is the Transmission Reliability Margin for the ATC Path that has not been released for sale (unreleased) as non-firm capacity by the Transmission Service Provider during that period.
  145. What are the transmission types?
    firm, non-firm, network economy and secondary service
  146. Explain grant remaining capacity?
    If the requested transmission is not available a counteroffer will come through offering the lower available amount. Customer has 5 min to confirm the lesser amount
  147. In the Portfolio manager what does the O, R, L, S and A stand for?
    Original, Remaining, Limit, Schedule and Available
  148. What are the energy product codes?
    • G-F Firm Energy
    • G-NF Non-Firm Energy
    • G-FC Firm Contingent
    • G-FP Firm Provisional Energy
    • G-F1 Hourly Firm Energy
    • C-SP Capacity for Spinning Reserve
    • C-NS Capacity for Non-Spinning Reserve
    • C-RE Capacity associated with energy recallable for reserves

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