Term2

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Term2
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  1. definition of Interchange
  2. Energy transfers that cross Balancing Authorities
  3. Continental North America is divided up into how many electrical interconnections:
    3
  4. A Balancing Authority is:
    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. Transmission Operator is
    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:
    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. A Transmission Service Provider is responsible for administering the transmission tariff and providing transmission services to Transmission Customers under applicable transmission service agreements
    True
  8. BC Hydro is registered as
    • Balancing Authority
    • Transmission Operator
    • Transmission Service Provider
  9. (OATT):
  10. Open Access Transmission Tariff - Sets out the terms and conditions by which BC Hydro conducts business with its customers
  11. (NAESB):
    North American Electric Standards Board - Serves as an industry forum for the development and promotion of standards which will lead to a seamless marketplace for wholesale and retail natural gas and electricity, as recognized by its customers, business community, participants, and regulatory entities.
  12. (BPS):
    Business Practices Subcommittee - charged with establishing the Business Practices for the exchange of wholesale electrical energy within North America
  13. What is our neighboring Balancing Authority to the East?
  14. Alberta Electric System Operator (AESO)
  15. What is our neighboring Balancing Authority to the South?
    Bonneville Power Administration (BPA)
  16. What is a Path? How many paths does BC Hydro have with neighboring Balancing Authorities and what are they identified as?
    A path is the transmission route used to transfer energy from one Balance Authority to another. BC Hydro has 2 paths with neighboring Balancing Authorities, identified as Path 1 and Path 3.
  17. Which transmission facilities make up Path 1?
  18. 500 kV Cranbrook - Langdon (5L94 or 1201L)
    • 138 kV Natal - Pocaterra (1L274 or 887L)
    • 138 kV Natal - Coleman (1L275 or 786L)
  19. Which transmission facilities make up Path 3?
  20. 500 kV Ingledow – Custer ties (5L51 and 5L52 - called west-side ties)
    • 230 kV Nelway – Boundary tie (2L112, an east-side tie)
    • 230 kV Waneta – Boundary tie (L71, an east-side tie, normally open)
  21. Define POR.
    Point of Receipt – Origin of the Transmission Service which is generally the generator location
  22. Define POD.
    (POD): Point of Delivery – Destination for energy transfer which would be the border of the BA.
  23. Describe the internal paths that BC Hydro uses to move energy inside the province
    Interior >LM (Internal) - This path is for the transmission facilities that deliver power from the interior portions of BC to the Lower Mainland.

    BCHA > BCHA (Internal) - These internal paths are for transmission services that do not leave the BC Hydro Balancing Authority but do cross various POR/PODs including from BC Hydro to FortisBC.
  24. What is a wheelthrough? On which paths do we have wheelthroughs?.
    A contractual path for the flow of energy across various transmission facilities. Path 1 and Path 3 would need to be used for this.
  25. What is the definition of TTC?
    Total Transfer Capability: the maximum amount of actual power that can be transferred over direct or parallel transmission elements comprising :
  26. What is the maximum TTC for Path 1 in each direction?
    • North to South: Up to 3150MW
    • South to North: Up to 2000MW
  27. 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
  28. TTCs for Paths can be found at:
  29. Path 1: SOO 7T-17
    Path 3: SOO 7T-18
  30. Define TRMu.
    (TRMu) : Transmission Reliability Margin Unreleased: is an amount of transmission set aside to account for uncertainties in load forecasting and other errors
  31. Define TRM.
    (TRM): Transmission Reliability Margin: 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.
  32. What is the definition of ATC?
    Available Transfer Capability
  33. What is the Scheduling Limit?
    (SL) Scheduling Limit: The maximum amount of Net Scheduled Interchange that can exist across a path The Scheduling Limit is a calculated value based on the TTC, the TRMu and Counter Flow Energy Schedules (CES)
  34. What is Counterflow Energy Schedules and how does it impact the Scheduling Limit?
    (CES): Counter Flow Energy Schedules: Schedules flowing in the opposite direction of the TTC direction. Any CES will increase the SL by the same amount
  35. OTC:
    Operating Transfer Capability: the maximum path rating which may be impacted by temporarily due to short duration outages of transmission elements.
  36. What is the definition of OTC? Is it synonymous with TTC from a BC Hydro perspective?
    OTC: Operating Transfer Capability: the maximum path rating which may be impacted temporarily due to short duration outages of transmission elements.

    OTC and TTC are synonymous within BC Hydro perspective.
  37. What is the calculation for the Scheduling Limit? Does this calculation ensure the net schedules for a path stay below the OTC/TTC limit?
  38. The TTC – the TRMu
  39. Where is OTC monitored?
    OTC monitoring is done by the AREVA Energy Management System
  40. Do TTC limits from MODS get automatically entered in the OTC Monitoring display in AREVA?
    The TSS value is the value from the Effective TTC Display in MODS. And is automatically entered
  41. What happens if the actual schedule exceeds the TTC limit in the OTC monitoring display?
    An OTC violation timer will start and alarms will be received by the Transmission and Generation Coordinator. Actual flows must be reduced within the OTC Limits within the allotted timeframes for compliance
  42. What is the maximum amount of time OTC can be violated for a stability constraint?
  43. 20 minutes for Stability limited paths.
  44. What is the maximum amount of time OTC can be violated for a thermal constraint?
    30 minutes for Thermal limited paths.
  45. Describe various reasons for OTC violations.
    • Overscheduled
    • TRM violation
    • Contingencies
  46. 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.
    This could be and Overscheduled OTC Violation on the AB Side. The Scheduling Limit may not have been accurately reflected in MODS and too much interchange was scheduled for what the path was good for.
  47. Transmission Service is divided up into two types. What are they? What does Point-to-Point mean?
    • Long Term Firm Point-to-Point (service for a minimum term of one year)
    • Short Term Point-to-Point (service for a term less than one year)
  48. Point to Point refers to the Origin and Destination of Energy
  49. Where does BC Hydro post TTC / ATC information?
    BC Hydro posts TTC and ATC for each Path and POR/POD combinations on OASIS
  50. What types of increments is Transmission Service sold in?
  51. Hourly, Daily, Weekly, Monthly
  52. 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
  53. What are Grandfathered Transmission Rights?
    Agreements honored by BC Hydro regarding transmission services previously arranged by a TSP and BC Hydro where BC Hydro is now in control of the Transmission Service.
  54. What circuit does Teck-Cominco retain Grandfathered Transmission Rights on?
    L71 from WAN (FBC) to NLY (BC Hydro) – path 3 in both directions
  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. If Teck Cominco later decides they require more transmission than they planned, they can purchase transmission (if ATC exists) via OASIS up to their scheduling rights at no cost. Transmission purchased in this manner will be subject to the normal curtailment procedures. Teck Cominco’s unused Firm and Non-firm Transmission Capacity within their entitlement may be resold on an hourly basis under the BCTC Scheduling Business Practices.
  57. What is a Redirect? Describe the two types of Redirects
    Transmission Customers purchasing Firm Point-to-Point Transmission Service have the right to request modification to the POR and POD, or both.
  58. · Firm : A Transmission Customer has the right to request modifications to the POR and/or POD of a Firm PTP transmission reservation on a Firm basis.
    · Non-Firm basis: A Transmission Customer has the right to request and alternate, or secondary, POR and/or POD on a Non‐Firm basis for a Firm Point‐to‐Point transmission reservation.
  59. 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
  60. A Resale is where a Reseller sells all or a portion of its scheduling rights associated with the POR and POD of a Confirmed Firm or Non-Form Point-to-Point transmission service request. Resales are posted on OASIS
  61. 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
  62. What is an eTag? What information comes across in an eTag? Submit with your assignment a marked up eTag indicating all the relevant information
  63. 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 help to maintain reliability by ensuring that all parties to interchange energy transactions receive relevant reliability information.
  64. Who is responsible for submitting eTags?
    Transmission Customers (PSE) make reservations for transmission service on the BCH transmission system through OASIS.
  65. What system are eTags submitted through?
    The OATI ETS system is used to submit, modify and approve or deny energy schedules (eTags), modify eTags.
  66. Etags must be on ___________ transmission service requests.
    Confirmed
  67. 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.
  68. PSEs can use one of three different approaches to specify transmission on its eTags, what are they?
  69. · OASIS ID Approach
    • · Blanket Approach
    • · Stacked Transmission Approach
  70. What are Product Codes used for on eTags?
    GPE (Generation-Providing Entity) and LSE (Load-Serving Entity) segments must include an Energy Product Code as a part of their creation profile.
  71. Describe each produce type:
  72. · Uninterruptible
    • · Interruptible
    • · Capacity and Dynamic
  73. What is a PSE Assigned Cut Priority? What does this allow the customer to dictate?
    A PSE can assign a “Cut_Priority” to each eTag. This is a numeric value that indicates to BC Hydro the curtailment order of eTags. “1” is the highest priority and will be curtailed last; “2” is the second highest priority, etc.
  74. For Real-time, what is considered “Late” with respect to an eTag?
    eTags should be submitted no later than 20 minutes prior to the start time of the eTag. eTags received after xx:40 for start time of next hour will be treated as late.
  75. What are some of the validation rules BC Hydro uses for eTags?
    BC Hydro validates each attribute on an eTag submitted including but not limited to:
  76. · submission time
    • · WECC reserve requirement
    • · Contingency reserve requirement
    • · source/sink
    • · market path
    • · start / stop time
    • · generation profile
    • · energy product code
    • · transmission assignment
  77. 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.
  78. With respect to an eTag, what is a Correction?
    A Correction can only be made to a PENDING eTag. Corrections can be made to:
  79. · POR and POD
    • · Designated transmission reservation
    • · Miscellaneous Information Value field on the Load or Generation Line
    • · Product Code in the Market Path
  80. With respect to an eTag, what is an Adjustment?
    Adjustment can only be made to a CONFIRMED or IMPLEMENTED eTag. Adjustments can be made to:
  81. · Generating Profile
    • · Transmission Profile
    • · Extension to the energy profile (to include hours not previously specified).
  82. Losses are attributable to all energy schedules that use the BC Hydro transmission system. What ways can a Transmission Customer make up for the losses associated with their energy schedules?
    Purchase Losses: The customer is charged for losses at the price provided daily by Pre-schedule.
  83. Self Supply Losses: The TC must purchase additional tx services for the delivery of losses to BC Hydro and schedule the loss energy under a separate e Tag. The losses can be delivered into the BC Hydro system from any direction regardless of the direction of the main energy schedule
  84. 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. They are essentially transmission capacities left unfilled from an energy perspective which are not resold as unused transmission
  85. Capacity eTags are created by selecting the eTag type as Capacity for ConRes or SpinRes. Per WECC Business Practices, a PSE wishing to schedule reserves must submit an eTag specifying the correct Firm OASIS ID (ARef) and energy type.
  86. What is a C-RE schedule? How is it identified in MODS?
    • Capacity for Recall schedules: are designated as Capacity associated with
    • energy recallable for reserves. Rrecallable within ten minutes of activation
    • of reserves and has been included in the Source Balancing Authorities reserves
    • resources
  87. What action must be taken on a C-RE “in-hour” adjustment?
    • Within the hour, the PSE may “interrupt” the schedule by submitting an
    • adjustment to the eTag energy profile. This will happen within the hour and
    • the Interchange Operator must approve the adjustment. Normally we do not
    • approve “in-hour” eTag adjustments, but in the C-RE case we must.
    • The adjustment will come into the MODS tag approval monitor, generating an
    • alarm and requiring manual action.
  88. What is a Dynamic Schedule? How is it identified in MODS?
  89. 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 essentially transmission capacities left
    • unfilled from an energy perspective which are not resold as unused
    • transmission. The energy is then dispatched through a dynamic signal that
    • allows for the energy profile to vary during the hour.
  90. Capacity eTags are created by selecting the eTag type as Dynamic and entering
    • DSConRes, DSSpinRes or DSRegRes. The full amount of Dynamic require
    • will be entered in the transmission allocation of the eTag. The expected
    • average energy amount will be entered in the energy schedule portion of the
    • eTag and will be ignored from a Net Schedule perspective until after the hour
    • and the official schedule is through a dynamic dispatch signal rather than the
    • eTag.
  91. What is the definition of NSI? How is NSI calculated for the BCHA Balancing Authority?
  92. (NSI): Net Scheduled Interchange - The net summation of all interchange schedules, import and export paths, for a Balancing Authority. The value passed over to AGC, and is either an increment or decrement to the amount of generation required on line to meet Load Responsibility, where responsibility equals load plus interchange.
  93. The Net Scheduled Interchange is the summation of the AESO Net Schedule and the PA Net Schedule, where each is the sum of all the imports and exports on each.
  94. What is the definition of NAI? How is NAI calculated for the BCHA Balancing Authority?
  95. (NAI): Net Actual Interchange: The actual net summation of all interchange schedules at the end of the hour. Each tieline is measured and the overall MWh of each is calculated by each which adds up to the NAI. The difference between the NSI and the NAI is the II.
  96. What is the ramp duration for the Western Interconnection? When does the ramp for HE16 start?
    The Western Interconnection ramp time is over the 20 minutes, starting at xx:50 of the previous hour and ending at xx:10 of the current hour.
  97. When is the NSI passed over to the EMS from MODS for HE16 NSI?
    Interchange Scheduler has seven minutes from xx:40 to verify the AESO and BPAT Net Schedule before the overall Net Schedule is passed over to AGC automatically at xx:47.
  98. If MODS has an NSI of -1885 for HE16 and all tags are approved, what should WIT say the NSI is?
    Confirmed at -1885
  99. 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 (II) is defined as the difference between Net Scheduled Interchange and Net Actual Interchange (NAI).
  100. Two accounts: One for Light Load Hours (HE01-6 and HE23 and HE24) and one for Heavy Load Hours (all other hours) with the II for each hour added to the overall bank account
  101. How does NSI change after the hour is over and what must be done?
    • The AESO and BPAT HE16 Net Schedules must both be verified again with AESO and BPAT respectively post-hour to factor in any Dynamic energy deliveries or Capacity Reserve deliveries.
    • Both Dynamic and Capacity deliveries in an hour will be factored into the Net Scheduled Interchange by the PSE submitting late adjustments to the eTag. Once approved by all parties on the transaction, the schedule will add into the NSI and checkouts can be re-verified.
  102. (ACE):
    Area Control Error
  103. (II) Inadvertent Interchange
    The difference between Net Scheduled Interchange and Net Actual Interchange (NAI).
  104. When does a curtailment occur?
  105. When an emergency or other unforeseen condition and/or commercial activity threatens to impair or degrade the reliability of the transmission system. Curtailments will be made on a non-discriminatory basis to relieve the constraint.
  106. What is the calculation for the Scheduling Limit?
  107. SL = TTC – TRMu – Existing Transmission Schedules – Reserves + Counterflow Energy Schedules
  108. · TTC is the Total Transfer Capability
    • · TRMu is the Transmission Reliability Margin unreleased
    • · CES (Counterflow Energy Schedules) is energy scheduled and flowing on the path but in the opposite direction
  109. How are eTags ranked in priority from highest to lowest?
  110. BC Hydro will assign each transmission reservation a NERC curtailment priority code (0-7), which will determine the transmission reservation order of Reliability Limits. If two transmission reservations are of the same NERC priority, the Reliability Limit will be based upon Last In-First Out (LIFO) methodology.
    • NERC Priority Codes:
    • 0NX — Next Hour Market |
    • 1NS — Non-Firm Secondary |
    • 2NH — Non-Firm Hourly |
    • 6NN — Network (Type 2) } LIFO
    • 3ND — Non-Firm Daily |
    • 4NW — Non-Firm Weekly |
    • 5NM — Non-Firm Monthly |
    • 6NN — Network (Type 1) --Pro-rata
    • 7F — Conditional Firm Service (Conditional Period) --Pro-rata
    • 7F — Firm including Conditional Firm Service (Non conditional period) –Pro-rata
  111. When does Emergency Assistance Energy apply?
    Only applies following the declaration of “NERC Energy Emergency Alert 2”.
  112. Before a request for emergency energy is made, what must the requesting party have done?
    When this happens, the party experiencing the emergency will exhaust all available options in the market to address its needs before the emergency energy is delivered.
  113. How will the providing party determine the amount of emergency energy capacity available?
  114. · 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
  115. How is emergency energy paid back?
    • · 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.
  116. 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.
  117. Define a Reserve Sharing group. Which reserve sharing group does BC Hydro belong to?
    The RSG is then responsible for maintaining, allocating, and supplying operating reserves required for each BA’s use in recovering from contingencies within their group. When a contingency happens, the BA is eligible to call upon reserves from the other BA’s in the group to help recover.
  118. The BC Hydro Balancing Authority is a member of a reserve sharing group, the Northwest Power Pool (NWPP).
  119. If BCH was generating 4875MW of hydro generation and 1872MW of thermal generation, what would the CRO be? How much SRO?
    • 4875 x .05 = 244MW hydro
    • 1872 x .07 = 131 MW Thermal Total CRO = 375MW not including non telemetered
  120. SRO = 0.5 x CRO = 187.5MW
    SRR = SRO + Spinning Schedule Contracts + Unused dynamic
  121. What might the GC ask the interchange scheduler to do to maintain BC Hydro’s CRO?
    The GC may ask the Interchange Scheduler to curtail energy schedules
  122. 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 + Scheduled Contracts + non used dynamic
    • CRR = 330MW + 88MW + 0 = 418MW
  123. How would Alberta request a contracted spinning reserve from Hydro?
  124. · Capacity e-Tag on Firm Transmission Reservation must be in place for the current and the next hour.
    • · The AESO SC will issue an AS Dispatch Directive (request delivery of the energy) to Powerex for the amount of reserve required.
    • · The AESO SC will contact the BC Hydro Generation Coordinator to advise that the reserves have been requested and an e-Tag adjustment is to be submitted. The BC Hydro Generation Coordinator will make the Interchange Scheduler aware of the pending request.
    • · When the tag adjustment is submitted in webTag, the BC Hydro Interchange Scheduler will review the Capacity e-Tag adjustment and advise the Generation Coordinator of the expected change in Interchange Schedule. With the Generation Coordinators approval, the Interchange Scheduler may approve the tag adjustment. When the e-Tag adjustment is Approved state, MODS will automatically calculate the new Net Interchange Schedule and export the new net schedule to the Alstom EMS.
  125. How are etags submitted for Contingency reserve requests? Are there Transmission Service Requests set aside for reserve deliveries?
    • · Capacity e-Tag on Firm Transmission Reservation must be in place for the current and the next hour.
    • · The AESO SC will issue an AS Dispatch Directive (request delivery of the energy) to Powerex for the amount of reserve required.
  126. Who is responsible for recording all applicable transmission and energy schedules for reserve deliveries?
  127. Interchange Scheduler is again responsible for approving tags and verifying the new NSI at the end of the hour based on integrated values for the Reserve Delivery.
  128. 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.
  129. 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?
  130. 1) FortisBC’s 230 kV bus at the Lambert Substation (the “Creston Point of Interconnection”).
  131. 2) 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”).
  132. 3) FortisBC’s tap on BC Hydro’s transmission line 1L251 near Princeton (the “Princeton Point of Interconnection”).
  133. What is the process for a Wheeling Nomination?
  134. During each year of the GWA that nominations are required, FortisBC will provide to BC Hydro a Nominated Wheeling Demand for each Point of Interconnection.
  135. 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. BC Hydro is not required to make changes to its transmission or substation plans under the Agreement, but may consider changes to accommodate FortisBC’s Wheeling requirements in cases where mutual agreement can be reached on the compensation to BC Hydro for the additional costs to be incurred
  136. Define Emergency Wheeling. What are BC Hydro’s responsibilities regarding Emergency Wheeling?
  137. 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. Emergency Wheeling does not include additional Wheeling requirements due to planned outages for maintenance and construction.
    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
  138. 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?
  139. A Dynamic Schedule, the amount of energy delivered throughout the hour is not a set value and thus the PSE must adjust the Dynamic Tag’s value which in turn will change the Net Schedule for that given hour. For this reason a Post-Hour Checkout must be completed with BPA.
  140. There are several other reasons for which the Net Schedules on each path may change, such as Capacity deliveries. For example, if Alberta were to call on a Spin Reserve or Contingency Reserve contract within the hour, this affect the Net Schedule for that hour and thus a Post-Hour Checkout would be required.
  141. What are some of the reasons there may be a mid-hour curtailment?
  142. May be initiated for many different reasons, with all being related to reliability in some fashion. For example:
  143. · Loss of a transmission facility that affects transmission limits
    • · Loss of generation facilities
    • · Insufficient reserves
  144. Mid-hour curtailments may be initiated by BC Hydro for problems within BC, and by external parties for problems outside BC.
  145. When is BC Hydro responsible for making mid-hour curtailments?
    For the following conditions:
  146. · A negative SL exists on a path, typically due to a TTC reduction in real-time
    • · A shortage of reserves as indicated by the GC
    • · Instructed by the GC to decrease import or export for system reliability
  147. What is the procedure for processing a mid-hour curtailment?
    All Current Hour Curtailments should follow a similar procedure:
  148. 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.
  149. Besides the Interchange Scheduler, who should be aware of in hour curtailments?
    • · GC – Generation Coordinator
    • · Adjacent BA’s
  150. 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.
  151. 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?
    To calculate the integrated value, start with the effective time of the curtailment, divide by 60 and multiply the original hourly tag value by that ratio.
  152. 39 / 60 = 65 MW
  153. What is a reload?
    BC Hydro will reload schedules when TTC constraints have been removed of Path 1 and/or Path 3 in the current hour. For the reload to take place, curtailments will have already had to take place (negative SL).
  154. What is the procedure for processing a reload?
    Once the facilities causing the constraint have been returned to service, the Transmission Coordinator can enter a new TTC value, which will generate a cutlist to reload the affected schedules. The Interchange Schedule is responsible for implementing reloads in the same fashion as the original curtailments.
  155. · Verify total amount being reloaded.
    • · Notify Generation Coordinator (GC) of Pending Schedule Change and amount of change.
    • · Upon GC Approval, Manually Approve Curtailments in MODS.
    • · Ensure the correct schedule is uploaded to EMS (note: MODS NSI will show the Integrated Value)
    • · Checkout with adjacent BA’s for new schedule.
    • · Log in hour curtailment in daily log. Adjust PI-DBVU numbers as necessary.
  156. What is often the first indication that there is an issue with OASIS or that the system has failed?
    The first indication that OASIS has failed is normally a call from a customer.
  157. When is a callout of support staff required to deal with an OASIS disturbance?
    When a customer has problems purchasing transmission through OASIS they should call the appropriate scheduling department to verify the source of the problem.
  158. 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?
  159. When the Pre-Schedule Office is staffed:
  160. · Notify Pre-Schedule immediately of the suspected cause.
    • · Pre-Schedule is responsible for the notification of the OATI Help Desk.
    • · Pre-Schedule is responsible for posting the outage information on the BCH website regardless of whether or not the problem is wesTTrans or BCH.
  161. When the Pre-Schedule Office is not staffed:
  162. · If wesTTrans is the suspected cause, the Interchange Operator will notify OATI to check the OASIS node.
    · If OATI confirms they are the cause and the estimated time of return is greater than ten minutes, a bulletin should be posted on the BCH website by the Interchange Scheduler notifying customers of the outage.
  163. Why is a complete MODS application failure unlikely to occur?
    With its built-in active triple redundancy, a complete MODS application failure is unlikely
  164. If a communication disruption does occur with MODS, what is the best action for the Interchange Scheduler to take?
    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
  165. Define a Reserve Sharing group. Which reserve sharing group does BC Hydro belong to?
    The RSG is then responsible for maintaining, allocating, and supplying operating reserves required for each BA’s use in recovering from contingencies within their group. When a contingency happens, the BA is eligible to call upon reserves from the other BA’s in the group to help recover.
  166. The BC Hydro Balancing Authority is a member of a reserve sharing group, the Northwest Power Pool (NWPP).

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