1. Define Interchange
    Energy transfers that crosses Balancing Authorities
  2. Continental North America is divided up into how many electrical interconnections?
  3. What are the benefits to power systems being electrically interconnected?
    • Efficiency
    • Markets
    • Reliability
  4. Define Balancing Authority
    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. Define Transmission Operator
    The entity responsible for the reliability of its "local" transmission system, and that operates or directs the operations of the transmission facilities.
  6. Define Purchasing-Selling Entity (PSE)
    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. define Transmission Service Provider
    Transmission Service Provider is responsible for administering the transmission tariff and providing transmission services to Transmission Customers under applicable transmission service agreements.
  8. BC Hydro is registered as:
    • Balancing Authority
    • Transmission Operator
    • Transmission Service Provider
  9. Define OATT
    • Open Access Transmission Tariff
    • The business rules BC Hydro uses to conduct business with its customers.
  10. What is our neighboring Balancing Authority to the East?
    Alberta Electric System Operator (AESO)
  11.  What is our neighboring Balancing Authority to the South?
    Bonneville Power Administration (BPA)
  12. What is a Path?
    Combination of lines that carry energy and connect to another Balancing Authority.
  13. What is the path with Alberta called?
    Path 1
  14. What is the path with US called?
    Path 3
  15. Which transmission facilities make up Path 1?
    • ·         500kV Cranbrook – Langdon (5L94 or 1201L)
    • ·         138kV Natal – Pocaterra (1L274 or 887L)
    • ·         138kV Natal – Coleman (1L275 or 786L)
  16. Which transmission facilities make up Path 3?
    • ·         500kV Ingledow – Custer ties (5L51 and 5L52 called west-side ties)
    • ·         230kV Nelway – Boundary (2L112, an east side tie)
    • ·         230kV Waneta- Boundary tie (L71, a normally open east side tie)
  17. Define POR
    Where the energy is picked up by the transmission system.
  18. Define POD
    Where the energy is dropped off by the transmission system.
  19. Describe the internal paths that BC Hydro uses to move energy inside the province.
    Used soley to transfer energy across transmission facilities withing the BCH Balancing Authority.

    • Interior > LM
    • Separated from the BC>US path because there is less transmission capacity than the BC>US path making it a congestion point.
    • BCHA > BCHA
    • For transmission services that do not leave the BCH BA but cross various POR/PODs
  20. What is a wheelthrough?
    • When energy uses a portion of our transmission system to fulfill a contract between different Balancing Authorities.
    • The energy never syncs with the BC Hydro system.

    It doesn't affect the NSI
  21. On which paths do we have wheelthroughs?.
    AB-US and US-AB
  22. Transmission is from..

    Energy is from...
    Transmission is from POR to POD

    Energy is from source to sink
  23. What is the definition of TTC?
    The amount of electric power than can be transferred over the interconnected transmission network in a reliable manner
  24.  BC Hydro follows the ________development of its TTCS from MOD-029
    Rated System Path Methodology
  25. What is the maximum TTC for Path 1 in each direction?
    • East to West: 1000MW
    • West to East: 1200MW
  26. What is the maximum TTC for Path 3 in each direction?
    • North to South: Up to 3150MW (all ties)
    • South to North: Up to 2000MW (all ties)
  27. Define Incremental Transfer Capability.
    Incremental Transfer Capability are used when the system is not normal and the path transfer capability is not at its maximum.
  28. Where are Incremental TTCs found for both Path 1 and Path 3 from a BC Hydro perspective?
    • Path 1: SOO 7T-17
    • Path 3: SOO 7T-18
  29. What is used as foundation for the purchase of transmission service.
    The TTC that is set on an hour by hour basis
  30. Where are TTC's entered by the Transmission Coordinator?
    Effective TTC display
  31. Define TRMu
    buffer between TTC and actual import/export. Makes up for missed load forecasts and frequency changes.

    • Prevents an OTC violation
    • Non-Firm Unreleased amount to marketers

    Difference between TTC and Non-Firm ATC

    • Path 1(AESO) = 65 MW
    • Path 3(BPA) = 50 MW
  32. define TRM
    • An amount of transmission set aside between the Total Transfer Capability(TTC) Limit and the Available Transfer Capability(ATC) Firm Limit
    • TRM = TTC - Firm ATC Limit
    • TRM is a calculated value that is not enterable in MODS

    ensure that the interconnected transmission network is secure under a possible range of uncertainties in system conditions.
  33. Define Firm ATC
    • Available firm capacity derived through system studies
    • System Normal less single largest contingency (N-1)
    • ATC Firm = TTC-TRM
  34. define ATC
    Available Transfer Capacity (ATC) is the amount of transfer capability remaining in the transmission network available over and above committed uses. ATC = TTC – TRM – Capacity Benefit Margin – sum of existing transmission commitments.
  35. define Scheduling Limit
    maximum amount of Net Scheduled Interchange that can exist across a path.

    SL = TTC - TRMu +CES
  36. What is Counterflow Energy Schedules and how does it impact the Scheduling Limit?
    Counter Flow Energy Schedules (CES) are energy schedules flowing the opposite direction of the TTC direction. CES ncreases the SL.
  37. OTC is________

    TTC is _____
    reliability driven

    market driven
  38. What is the definition of OTC? Is it synonymous with TTC from a BC Hydro perspective?
    maximum value of the most critical system operating parameter(s) which meets: (a) precontingency criteria as determined by equipment loading capability and acceptable voltage conditions, (b) transient criteria as determined by equipment loading capability and acceptable voltage conditions, (c) transient performance criteria, and (d) post-contingency loading and voltage criteria.

    • the OTC of a path is defined as the physical limit a related system imposes on the path, and is either a thermal limit or a stability limit. 
    • Yes
  39. Where is OTC monitored?
    AREVA Energy Management System.
  40. Do TTC limits from MODS get automatically entered in the OTC Monitoring display in AREVA?
  41. Can manually entered values in the OTC Monitoring display override the TTC entered from MODS for OTC monitoring?
    If it a lower value. This Path monitoring screen takes the minimum value
  42. 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.
  43. What is the maximum amount of time OTC can be violated for a stability constraint?
    20 minutes
  44. What is the maximum amount of time OTC can be violated for a thermal constraint?
    30 minutes
  45. Describe various reasons for OTC violations.
    • Overscheduled : If the Scheduling Limit is not accurately reflected in MODS and too much interchange is scheduled for what the path is good for. To resolve the effective TTC needs to be lowered to the correct value and schedules curtailed.
    • TRM violation : If frequency component of the Net Interchange Actual is greater than the TRMu and the Net Interchange Schedule is around the Scheduling Limit, the addition of the two will put the path into OTC violation. To resolve, generation needs to be ramped by pushing counterflow energy to the OTC violation.
    • Contingencies : Effective TTC may change during the hour due to contingencies. Contingencies may be a result of lost transmission. This will force a new Scheduling Limit which may lead to curtailments. Or the contingency could be because of loss of a generator while importing right up to the Scheduling Limit. The only resolution is to replace the lost generation or shed load.
  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.
    Yes, because the system is 75MW short  so it will draw more energy from the US, above the Scheduling Limit.
  47. How do you calculate Firm ATC?
    Firm ATC = TTC – TRM – Reserved Firm Transmission Service + Postbacks (recalled credits)

    System Normal less single largest contingency (N-1)
  48. How do you calculate Network Economy (Secondary Network) ATC?
    Network Economy (Secondary Network) ATC = TTC – TRMu – Reserved Firm Transmission Service – Reserved Network Economy Transmission Service + Postbacks (unscheduled Firm transmission service) + Counterflow
  49. How do you calculate Non-Firm ATC?
    Non-Firm ATC = TTC – TRMu - Reserved Firm Transmission Service – Reserved Network Economy Transmission Service – Reserved Non-Firm Transmission Service + Postbacks (unscheduled transmission service of higher priority tiers) + Counterflow
  50. How do you calculate Secondary Non-Firm ATC?
    Secondary Non-Firm ATC = TTC – TRMu - Reserved Firm Transmission Service – Reserved Network Economy Transmission Service – Reserved Non-Firm Transmission Service – Reserved Secondary Non-Firm Transmission Service + Postbacks (unscheduled transmission service of higher priority tiers) + Counterflow
  51. What are the two types of transmission service?
    • Long Term Firm Point-to-Point is service for a minimum of one year. Handled by Pre-Schedule office.
    • Short Term Point-to-Point is service for a term less than a year. Point-to Point is service provided to a Transmission Customer by the TSP to move energy from a POR to a POD.
  52. describe Ancillary Services.
    •  services necessary to support the transmission of electric power from seller to purchaser ie,
    • Scheduling, System Control and Dispatch
    • Reactive Supply and Voltage Control
    • Regulation and Frequency Response
    • Energy Imbalance
    • Operating Reserve--‐Spinning
    • Operating Reserve--‐Supplemental
    • Loss Compensation
  53. 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 (Non conditional period)
    • 7F- Conditional Firm Service (Conditional Period)
    • 6NN – Network (Type 1: higher class of transmission than non-firm and must pass both the economic test and utilization test per the Network Economy Business Practices)
    • 5NM – Non-Firm Monthly
    • 4NW- Non-Firm Weekly
    • 3ND- Non-Firm Daily
    • 6NN- Network (Type 2: the same class of transmission as Non-Firm)
    • 2NH- Non-Firm Hourly
    • 1NS – Non-Firm Secondary
    • 0NX- Next Hour Market
  54. Where does BC Hydro post TTC / ATC information?
    BC Hydro posts TTC and ATC information for the current month and next 12 months on OASIS.
  55. All Transmission Service Requests must be made through ________
  56. What types of increments is Transmission Service sold in?
    Service increments for Short Term Transmission Service Requests can be Hourly, Daily, Weekly, or Monthly service.
  57. Explain how TSRs are validated.
    • - Submission time
    • - Valid Path and POR/POD combination
    • - MW Requested
    • - Bid Price
    • - Service Increment
    • - Start/Stop time
    • - Pre-confirm
  58. Is the Interchange Scheduler allowed to “Annul” TSRs? If consulted to “Annul” a TSR, what action should the Interchange Scheduler take?
    The Interchange Scheduler is not authorized to annul TSRs. The Interchange Scheduler should instruct the PSE to contact After the Fact.
  59. What are Grandfathered Transmission Rights?
    The Line 71 Agreement between BCH and Teck Cominico documents and clairifies the grandfathered BC/US scheduling rights resulting from the Kootenany Canal Agreement.
  60. What circuit does Teck-Cominco retain Grandfathered Transmission Rights on?
    Line 71
  61. the L71 Grandfathered Transmission Rights grant Teck-Cominco what?
    Firm import and Firm export transmission on Path 3

    L71 transmission has priority above firm.
  62. 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.
  63. What is a Redirect?
    Transmission Customers purchasing Firm Point-to-Point Transmission Service can request modification to the POR and POD.
  64. Describe Redirect on a Firm basis
    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. This is referred to as a Redirect on a Firm basis.

    The new Firm TSR is classed as Firm Transmission Service which has the highest priority.

    If successfully processed, the original Firm TSR will be reduced, and the subsequent ATC posted for resale.
  65. Describe Redirect on a 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. This is referred to as a Redirect on a Non‐Firm basis. The new Non‐Firm TSR is classed as Hourly Secondary Transmission Service which has the lowest priority.

    If successfully processed, the original TSR will remain in, however the Transmission Customers rights to schedule on that TSR will be reduced by the amount being redirected. Should the Transmission Customer wish to relinquish the redirect they may do so up to the amount of the original TSR per the Business Practices.
  66. What is a Resale and how is it done?
    a Reseller sells all or a part of its scheduling rights associated with the POR and POD of a Confirmed Firm or Non-Firm Point-to-Point TSR. Resales are posted on OASIS
  67. What is a Transfer and how is it done?
    A Transfer is when a reseller transfers all 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.
  68.  What is often the first indication that there is an issue with OASIS or that the system has failed?
    A call from a customer is usually the first indication that OASIS has failed.
  69. When is a callout of support staff required to deal with an OASIS disturbance?
    Calling OATI is required when there is a BCH failure. Call the Pre-Schedule desk if they are staffed, if not call OATI
  70.  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?
    immediately contact OATI staff to investigate the problem.
  71. Why is a complete MODS application failure unlikely to occur?
    MODS has built-in active triple redundancy.
  72. 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.
  73. 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.      Unplug the corporate internet cable from the back of the MODS computer under the Interchange desk.
    • 3.      Plug the yellow shaw Internet cable into the MODS computer.
    • 4.      Click “Start” and “Run” on the corporate windows desktop display.
    • 5.      Type “cmd” in the “Run” window.
    • 6.      Type in “ipconfig/renew” in the command prompt
    • 7.      Relaunch MODS
  74. What is an eTag? What information comes across in an eTag?
    An eTag is an electronic documentation of the energy transaction.

    •  source,
    • sink, path,
    • transmission contracts to be used,
    • capacity profiles and
    • parties to the transaction.
  75. Who is responsible for submitting eTags?
  76. What system are eTags submitted through?
  77. Etags must be on ____ transmission service requests.
  78. TSRs used on an eTag must satisfy what conditions for the eTag to be approved?
    • ·         Be confirmed and active on OASIS
    • ·         Have sufficient available energy capacity in combination.
    • ·         Must have the same POR and POD combination.
    • ·         The eTag transmission allocation profile must be greater than or equal to the energy profile
    • ·         Must not cause a Reliability Limit infringement.  If a tag has been approved, BC Hydro will deny the tag for insufficient capacity.
  79. PSEs can use one of three different approaches to specify transmission on its eTags, what are they?
    • OASIS ID Approach – entering multiple or single valid, confirmed TSR numbers (ARef)
    • Blanket Approach -  enter an active confirmed TSR OASIS ID (ARef) and add B after the ID. BC Hydro uses all confirmed and active TSRs that match the parameters.
    • Stacked Transmission Approach – Combining two different confirmed TSRs with the same POR and POD to support the capacity required on the tag.
  80. What are Product Codes used for on eTags?
    Product Codes indicate what type of energy. (GF, G-NF, etc)
  81. What is a PSE Assigned Cut Priority? What does this allow the customer to dictate?
    A numeric value that indicates the curtailment order of tags. It allows the customer to dictate the order that the tags will be curtailed.

    In MISC of physical path on etag
  82. For Real-time, what is considered “Late” with respect to an eTag?
    Late eTags are submitted after xx:40.
  83. What are some of the validation rules BC Hydro uses for eTags?
    • ·         Submission time
    • ·         WECC reserve requirement
    • ·         Source/sink
    • ·         Market path
    • ·         Start/stop time
    • ·         Generation profile
    • ·         Energy product code
    • ·         Transmission assignment.
  84. With respect to an eTag, what is a Modification?
    Changes to an eTag for non-reliability related issues on ARRANGED, PENDING, CONFIRMED, or IMPLEMENTED eTags. 

    For an IMPLEMENTED eTag, you can only modify future hours.
  85. With respect to an eTag, what is a Correction?
    • On a pending eTag, corrections can be made to the:
    • ·         POR and POD
    • ·         Designated transmission reservation
    • ·         Miscellaneous Information Value field on the Load or Generation Line
    • ·         Product Code in the Market Path
  86. With respect to an eTag, what is an Adjustment?
    • On a confirmed or implemented eTag, adjustments can be made to:
    • ·         Generating Profile
    • ·         Transmission Profile
    • ·         Extension to the energy profile (to include extra hours)
  87. 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?
    They can self supply or purchase Loss Compensation from BC Hydro.
  88. What is an Normal Energy Schedule? How is it identified in MODS?
    Normal Energy Schedule is deemed uninterruptible. It should only be curtailed if there is a reliability constraint.

    In ITS Nets UnInt bucket in MODS

    You can put firm energy on non-firm transmission.
  89. What does a PSE have to enter in the eTag to make an energy schedule Normal?
    • ·         Transaction type: normal
    • ·         Enter G-F product code in the Market Path section.
  90. What is an Interruptible Energy Schedule? How is it identified in MODS?
    • Interruptible Energy is Non-Firm energy that can be interrupted for any reason. Identified
    • as Int in ITS NETS
  91. What does a PSE have to enter in the eTag to make an energy schedule Interruptible?
    • ·         Select Normal as the tag type
    • ·         Enter G-NF or F-FP in the product code in the Market Path section.
    • ·         Enter the appropriate WECC reserve requirement. The reserve multiplier should be 100%
  92. What is a Capacity Schedule? How is it identified in MODS?
    • Capacity schedules set aside Capacity for reserves for other Balancing Authorities that can be dispatched if the entity requires the reserves.
    • Identified in eTag as

    • transaction type: Capacity
    • product code: C-SP, C-NS
    • Firm transmission must be available.
  93. What is a C-RE schedule? How is it identified in MODS?
    A C-RE  is energy that is sold but if the Source Balancing Authority has a contingency, the energy can be recalled.

    • transaction type:  Recallable
    • Product Code: C-RE
  94. What action must be taken on a C-RE “in-hour” adjustment?
    must approve
  95. What is a Dynamic Schedule? How is it identified in MODS?
    •  Identified in MODS as transaction type: Dyanmic 
    • Product code: G-F
    • Contract: REGUP
    • A Dynamic Schedule has varying energy profiles during the hour.
  96. Can you schedule Firm energy on Non-Firm transmission?
  97. What is the definition of NSI?
    Net Scheduled Interchange (NSI)  is the net summation of all interchange schedules, import and export paths, for a Balancing Authority.
  98. How is NSI calculated for the BCHA Balancing Authority?
    BCHA NSI is the summation of the AESO Net Schedule and the BPA Net Schedule, which is the sum of all imports and exports on each.
  99. What is the definition of NAI?
    • Net Actual Interchange (NAI) is the algebraic sum of all metered Interchange over all interconnections between Balancing Authorities
    • calculated after the hour
  100. How is NAI calculated for the BCHA Balancing Authority?
    BCHA measures each tieline and the overall MWh of each is calculated which adds up to the NAI.
  101. What is the ramp duration for the Western Interconnection? When does the ramp for HE16 start?
    The ramp duration for the Western Interconnection is 20 minutes. HE16 ramp starts at 14:50.
  102.  When is the NSI passed over to the EMS from MODS for HE16 NSI?
    The NSI is passed over to the EMS every minute two hours in advance
  103. If MODS has an NSI of -1885 for HE16 and all tags are approved, what should WIT say the NSI is?
    If both parties have agreed to the Net Schedule, the NSI for WIT should also be -1885.
  104. What is Inadvertent Interchange? How is it calculated?
    Inadvertent Interchange (II) is the difference between the Balancing Authorities NSI and NAI. It is calculated by II  =  NAI – NSI
  105. What are the two accounts II can fall into and which hours fall into which account?
    Light Load Hours (HE01-6) and HE23/24

    Heavy Load Hours (all other hours)
  106. How does NSI change after the hour is over and what must be done?
    NSI can change because of Dynamic or Capacity Reserve deliveries. The PSE will submit late adjustments to the  eTag, all parties will approve, and the schedule will add to the NSI and be verified.

    Curtailments in the hour
  107. When does a curtailment occur?
    Curtailment occurs when there is an emergency or other unforeseen condition and/or commercial acitivity that threatens to impair or degrade the reliability of the transmission system.
  108. What is the calculation for the Scheduling Limit?
    SL = TTC –TRMu – existing Transmission Schedules – Reserves + Counterflow Energy Schedules
  109. How are eTags ranked in priority from highest to lowest?
    • Dynamic                                 - Highest
    • Reserves / Capacity
    • Normal / Uninterruptible
    • Interruptible / Recallable            - Lowest
  110. Curtailments of eTags are performed according to what two factors?
    • Product code
    • Priority set by PSE
  111. Once a cutlist has been Implemented, when would you expect to see a change to your Schedule?
    After the curtailments have been approved by both the Source and Sink, the NSI will reflect the changes.
  112. What are some of the reasons there may be a mid-hour curtailment?
    • All reasons for mid-hour curtailments are related to reliability.
    • ·         Loss of a transmission facility that affects transmission limits
    • ·         Loss of generation facilities
    • ·         Insufficient reserves
  113. When is BC Hydro responsible for making mid-hour curtailments?
    • ·         A negative SL exists on a path, usually due to a TTC reduction in real-time
    • ·         A shortage of reserves due to a Capacity & Energy Emergency
  114. What is the procedure for processing a mid-hour curtailment?
    • For internal consraints managing the cutlist for negative SL and curtail individual eTags
    • For external constraints, the Interchange Scheduler must inform the GC of the new NSI when curtailments are fully approved and confirming the new Net Scheduled Interchange with the adjacent Balancing Authorities through WIT.
    • The Interchange Scheduler shall
    • ·         Ensure the correct schedule is uploaded to the EMS
    • ·         Log in hour curtailment in daily log. Adjust PI-DBVU numbers.
    • ·         Verify the new Net Schedule in WIT post hour based on the integrated value.
  115. Besides the Interchange Scheduler, who should be aware of in hour curtailments?
    The interchange Scheduler must inform the GC of the new NSI when curtailments are fully approved.
  116. What is an Integrated Value?
    An integrated value is the amount of MW that flow in the hour.
  117. What is a reload?
    • Reloads happen when a constraint that was placing a Reliability Limit against transmission or a generator comes back online that was supporting a schedule.
    • If the Reliability Limit on the tag gets completely lifted, then it is a reload.
  118. What is the procedure for processing a reload?
    • The Interchange Scheduler:
    • ·         Verify total amount being reloaded
    • ·         Notify the GC of the upcoming change to the NSI and get approval
    • ·         Ensure the correct value is uploaded to EMS
    • ·         Log in hour curtailment in daily log. Adjust PI-DBVU numbers.
    • ·         Verify the new Net Schedule in WIT post hour based on integrated values.

    For external reloads tell the GC the new NSI
  119. Define a Reserve Sharing group. Which reserve sharing group does BC Hydro belong to?
    • When a BA is a member of a Reserve Sharing group, it only has to  maintain its proportionate share of the Most Severe Single Contingency.
    • A Reserve Sharing group maintains, allocates, and supplies operating reserves for each BA’s use in recovering from contingencies. If a contingency happens, a BA can call upon reserves from the other BA’s in the group.
    • BC Hydro belongs to NWPP (Northwest Power Pool).
  120. If BCH was generating 4875MW of hydro generation and 1872MW of thermal generation, what would the CRO be? How much SRO?
    CRO = 4875 MW * 5% + 1872 MW * 7% =  243.72 MW + 131.04 MW =  374.8 MW
  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 schedules to maintain adequate CRR and SRR.
  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?
  123. Before BCH can request Reserve Sharing, it must have committed all of its ___
    available CRO
  124. How would Alberta request a contracted spinning reserve from Hydro?
    Powerex submits an adjust to the eTag which will be seen as a Late Adjustment. The Late Adjustment should be approved and the Net Interchange Schedule will change.
  125. How are etags submitted for Contingency reserve requests? Are there Transmission Service Requests set aside for reserve deliveries?
    • When a NWPP member has a contingency greater than its CRO, it submits a Reserve Sharing request that is processed by NWPP. Other NWPP members would get a pro-rata of the CRO contributions.
    • Transactions are recorded automatically from e-tag data generated from the NWPP. No, transmission schedules are recorded automatically in MODS from e-tag data generated from the NWPP.
  126. Who is responsible for recording all applicable transmission and energy schedules for reserve deliveries?
    The BC Hydro Generation Dispatcher is responsible for recording all applicable transmission and energy schedules for reserve deliveries.
  127. What is a Capacity & Energy Emergency?
    when a Balancing Authority Area’s operating capacity, plus firm purchases from other systems that are available or limited by transfer capability, are inadequate to meet its demand plus its regulating requirements.
  128. How does the GC know if they are in a Capacity Shortfall?
    The GC notices a Capacity Shortfall when the Contingency Reserve Available (CRA) calculated in the Energy Management System (EMS) is close to the Contingency Reserve Requirement (CRR).
  129. What are the Interchange Schedulers duties under a Level 1?
    • ·         Curtail Interruptible export schedules under the direction of the GC, making the generation available to support reserve requirements
    • ·         Approve Late Emergency eTags, even without adequate transmission allocation to alleviate the Capacity & Energy Emergency
  130. What are the Interchange Schedulers duties under a Level 2?
  131. What are the Interchange Schedulers duties under a Level 3?
    • ·         Perform curtailments of Firm export schedules under the direction of the GC
    • Firm export energy schedules are considered for curtailment equally with domestic load.
  132. What is the General Wheeling Agreement?
    establishes the terms and conditions for FortisBC to wheel electricity on a firm basis over BC Hydro transmission facilities.
  133. 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?
    • Creston Point of Interconnection: FortisBC’s 230kV bus at Lambert Substation
    • Okanagan Point of Interconnection: BC Hydro’s 230 kV bus at Vernon Substation
    •                                                       FortisBC’s 230kV bus at Vaseux Lake Terminal Station
    • Princeton Point of Interconnection: FortisBC’s tap on BC Hydro’s transmission line 1L251 near Princeton
  134. What is the process for a Wheeling Nomination?
    • ·         Every year, FortisBC provides to BC Hydro a Nominated Wheeling Demand for each point of Interconnection.
    • ·         BC Hydro responds within 30 days either accepting the Wheeling Demand or stating the maximum that can be Wheeled by the facilities.
    • ·         BC Hydro is not required to make changes to its transmission or substation plans but may do so when a mutual agreement with FortisBC is made and BC Hydro is compensated for additional costs.
    • ·         Except for Emergency Wheeling, BC Hydro is not required to Wheel any electricity above the Nominated Wheeling Demands unless agreed to in advance in writing by BC Hydro. Without an agreement, the excess capacity and energy must be purchased under rates, terms and conditions as defined in the Power Purchase Agreement.
  135. Define Emergency Wheeling. What are BC Hydro’s responsibilities regarding Emergency Wheeling?
    • Emergency Wheeling: Requirements for Wheeling which exceed the Nominated Wheeling Demands due to unforeseen outages or other emergencies on FortisBC’s system.  *It does not include planned outages for maintenance and construction.
    • The GWA states that BC Hydro must provide Emergency Wheeling to the extent that normal operation of BC Hydro’s system and service to BCH customers is not impaired.
  136. 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?
    • ·         Dynamic Energy Schedules
    • ·         Capacity deliveries
    • ·         In-hour curtailments
  137. What is OASIS? Why was it developed?
    OASIS (Open Access Same-Time Information System) is a tool used by Transmission Service Providers (TSPs) to post information on the transmission grid and to execute buy/sell transmission transactions.
  138. What positive effects does an OASIS system provide for the energy market?
    • As the electric industry deregulates, OASIS will be the entry point to direct access and comparability for all its users. The benefits are:
    • ·         Lower electricity prices for consumers
    • ·         Greater accessibility to other transmission systems
    • ·         More competition for power in the wholesale market
  139. What is webTag?
    WebTag or Energy Trading System (ETS) is required by NERC and WECC and used by Transmission Service Providers (TSPs) and Balancing Authorities (BAs) to allow Purchasing Selling Entities to apply energy schedules on their transmission reserverations.
  140. What is an eTag? Why were eTags developed?
    • eTag is an electronic documentation of the energy transaction describing:
    • ·         Source
    • ·         Sink
    • ·         Path
    • ·         Transmission contracts to be used
    • ·         Capacity profies
    • ·         Parties in the transaction

    • eTags maintain reliability by ensuring that all parties to interchange energy transactions receive relevant reliability information.
    • The eTag system communicates intent to schedule energy and approval or denial and modifications to schedules.
  141. The proper use of eTags ensures what two things?
    • ·         The energy schedule is matched to a verified transmission reservation via the use of OASIS reference numbers on all paths involved
    • ·         Instant messaging to all involved parties of any changes made to the energy schedule.
  142. Explain the relationship between the MODS client at FVO and the OATI servers.
    MODS is web based and communicates with various OATI products through a web browser user interface.
  143. On which display(s) would you find the NSI required by AGC?
    • Interchange Summary
    • Realtime Summary (shows next hour NSI)
  144. On which display(s) would you find a summary of all TSRs for a specific customer and the eTags submitted against those TSRs?
    TSR Summary
  145. Referencing the Portfolio Manager, what does the O/R/S/L/A reference?
    • O is Original MW: MW requested or MW granted depending on status of request
    • R is Remaining MW: original MW value minus TSR assignments. This includes redirects, recalls, and resales.
    • L is Limited MW: Reliability limit set on the TSR. If no limit, it is N/A
    • E is Event ID: associated with Limit MW from the curtailment manager. If no limit, there is no event ID.
    • S is Scheduled MW: sum of the MW value of all schedules using the TSR or TSN. Depending on the filter, this value will come from energy profile on tag or transmission profile on the tag.
    • A is Available MW: Amount that is still available to be used for a schedule or TSR reassignment. Calculated using the lesser of the Remaining or Limit value and subtracting the Scheduled amount.
  146. What is the Effective TTC display? Who controls the data entered on this display?
    Displays the TTC, TRM, and TRMu for each path. The Transmission Coordinator (TC) enters the TTC to this display.
  147. What is the TSR Summary display? What can the Interchange Scheduler do from this display?
    • The interface for monitoring and managing TSRs.
    • ·         TSR details
    • ·         TSR validation results
    • ·         Link to e-Tag where TSR is being used
    • The Interchange Scheduler can re-run the validation for a TSR using the display that comes up when you click on the Aref number.
  148. What is the purpose of the Tag Summary display?
    Provides a summary of the e-Tags and their current status.
  149. What is the Tag Request Approval Monitor?
    • ·         Provides notification of incoming e-Tag requests requiring action from the approval entity.
    • ·         Displays tag validation results to assist in confirming or denying late tags
    • ·         Where late tags are approved
  150. At a high level discuss how internal curtailments for TTC impacts should work from a MODS perspective.
    • ·         The TC should lower the TTC in the Effective TTC display.
    • ·         SL becomes negative
    • ·         Curtailment manager that monitors for negative SOL triggers a pop-op alarm
    • ·         A cutlist is generated that the operator can implement
  151. 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 displays:
    • ·         Net Scheduled Interchange
    • ·         Uninterruptible schedules
    • ·         Interruptible schedules
    • ·         Reserve contracts
    • ·         Dynamic schedule details
    • ·         Net Actual Interchange
    • ·         Inadvertent Interchange
    • Tag Request Approval Manager: where you approve manual e-tags
    • Realtime Summary: displays the change in MW for the next hour and next hour Net Schedule Interchange.
  152. Fully explain WIT, including how it works and what it provides.
    WECC Interchange Tool  

    • WIT provides every Balancing Authority in WECC with their confirmed Net Scheduled Interchange by summing the appropriate eTags that are in stage IMPLEMENT.
    • ·         Each BA must compare WIT NSI with their own NSI delivered to AGC
    • ·         Has Net Actual Interchange
  153. define NAESB
    • North American Energy Standards Board
    • 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
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