Minutes Interchange Subcommittee

Transcription

1 Minutes Interchange Subcommittee May 26 27, 2010 Midwest ISO Office St. Paul, Minnesota A regular meeting of the North American Electric Reliability Corporation s (NERC) Interchange Subcommittee (IS) was held on May 26-27, 2010 at the Midwest ISO office in St. Paul, Minnesota. The meeting agenda and attendance list are attached as Exhibits A and B, respectively. There was one individual statement by Fred Kunkel on the 2010 NERC Goals, Exhibit C. There were no minority opinions. Interchange Subcommittee chair Joe Gardner presided and a quorum was present. Interchange Subcommittee Appreciation for Meeting Host Midwest ISO The Interchange Subcommittee acknowledges and appreciates the hospitality that the Midwest ISO Office, specifically Joe Gardner and Toni Schewe provided to the subcommittee as Midwest ISO hosted the IS meeting at its facility. Antitrust Compliance Guidelines Secretary Tom Vandervort acknowledged the NERC Antitrust Compliance Guidelines. Minutes of the Previous Meeting The subcommittee approved the February 10-11, 2010 meeting minutes by unanimous consent. Recognition of Service for James Michael Hansen Chair Gardner acknowledged James (Jim) Hansen for his long-term service to NERC on the Interchange Subcommittee and as the NERC Chairman of the Joint Electric Scheduling Subcommittee demonstrating his leadership, dedication, and contribution to improving the electronic tagging system in North America. The IS wishes Mr. Hansen success in all of his future endeavors NERC Goals and Objectives Secretary Vandervort gave an overview of the 2010 NERC Top 10 Performance Goals and Objectives, as an informational item. Chair Gardner expanded on Goal #4, Develop performance-based standards and improve timeliness of standards process, as they may Village Blvd. Princeton, NJ

2 relate to the Coordinate Interchange Standards Drafting Team. The 2010 NERC Performance Goals and Objectives are included in the IS meeting agenda. Interchange Subcommittee Sub-groups Joint Electric Scheduling Subcommittee JESS Co-chairs Bob Harshbarger and Clint Aymond summarized activities that the JESS is working on: Long-term NERC JESS Co-chair Jim Hansen stepped down as the co-chair, but remains on the JESS. Clint Aymond was appointed by the NERC OC Chair as the new NERC co-chair of the JESS. The JESS and the electronic tagging vendors implemented the e-tag Specifications V1.8.1 on March 30, The implementation was very successful with no problems reported. The IS complemented the JESS and the e-tag vendors for a very significant and successful transition to the new e-tag Specifications. NAESB staff is processing the Electric Industry Registry (EIR) request for proposal (RFP). Co-chair Harshbarger did not know the status of the RFP. The JESS will participate in the RFP evaluation as requested by NAESB. The e-tag specifications are being maintained by NAESB. To access the NAESB e- Tag Specifications and Schema, please visit the following NAESB protected web site: The JESS will review and revise the WEQ-004, Coordinate Interchange business practice standards in coordination with the NERC Coordinate Interchange Standards revision. This effort will ensure that the NERC and NAESB language is in sync and are correct for both organizations. A JESS conference call and webcast is scheduled for June 2, 2010 to begin the revision process. See the NAESB, JESS website for the conference call details. The JESS has requested all entities that use electronic tagging to change their common URLs to a secure URL (from http to https ). To this date, the transition has only been accomplished by approximately 50% of the e-tag balancing authorities. The JESS will is considering petitioning the e-tag vendors to make the change to all of their e-tag clients. The next JESS meeting will be at the NERC SERC Office in Charlotte, NC on July 14 15, The JESS is seeking active participants for its meetings and activities. Interchange Subcommittee Meeting Minutes May 26-27,

3 Eastern Interconnection Interchange Tool Task Force The Eastern Interconnection Interchange Tool Task Force (EIITTF) Chair Jeremy West reported that the EITTF was not active since the last IS meeting. Chair West will conduct EIITTF conference calls to finish the final report with conclusions and recommendations before the September, 2010 IS meeting. ACE Diversity Interchange Task Force The OC gave a charge to the NERC Resources Subcommittee, Operating Reliability Subcommittee (ORS), and the Interchange Subcommittee (IS) to review and respond to the Duke Energy request to evaluate ACE Diversity Interchange (ADI) impact on interconnections, regions, RC areas, and BA functions. IS members on the ADITF include Chair Gardner, Don Lacen, and Tom Vandervort. IS members Bob Harshbarger and Mike Oatts also participated in the last ADITF meeting in St. Louis in April. The goal of the ADITF is to complete its ADI review, evaluation, and write a white paper. The ADITF White Paper Outline with assignments is attached as Exhibit D. IS Operating Manual Documents Revisions Dynamic Transfer Reference Guidelines Drafting Team: Peter Harris, Cheryl Mendrala, Joe Gardner, Chris Pacella, Eric Grau The Dynamic Transfer Reference Guidelines drafting team brought the comments and responses as well as the revised Dynamic Transfer Guidelines to the IS for discussion. The team had a few comments that needed the IS to discuss prior to finalizing the guidelines. The IS and the drafting team worked collaboratively to address the final comments and to complete the guidelines revision. During the February, 2010 IS meeting, the IS decided that the changes were not significant enough to require another industry posting. Shane Jenson moved to present the documents to the NERC OC during the June, 2010 NERC OC meeting with a recommendation for the OC to approve the Dynamic Transfer Reference Guidelines and to post document in the NERC OC Operating Manual. The motion passed. The Dynamic Transfer Reference Guidelines and the commentsresponses are attached as Exhibit E and F. Interchange Reference Guidelines Drafting Team: Jeremy West, Bob Harshbarger, Eric Nehf, Shane Jenson, Don Lacen The drafting team is planning to have a couple of conference calls / webcasts to address the Interchange Reference Guidelines industry comments and to continue revising the guidelines before the September, 2010 IS meeting. NERC Coordinate Interchange Standards Revision SAR The NERC Coordinate Interchange Standard Drafting Team (CISDT) met in St. Paul, MN at the same Midwest ISO facility after the IS meeting. The CISDT draft INT standards are in NERC Standards Program review in preparation for industry posting and potential ballot. Interchange Subcommittee Meeting Minutes May 26-27,

4 The CISDT next meeting is planned to be a joint IS CISDT meeting in Holyoke, MA on September 8-9, The CISDT may have a number of conference calls prior to the meeting. For more information, see the NERC website for Project , Coordinate Interchange at: Joint Electric Scheduling Subcommittee Relationship to the IS The IS discussed the pros and cons to continue being the NERC parent subcommittee to the NERC NAESB Joint Electric Scheduling Subcommittee. Secretary Vandervort initiated the discussion with the following questions: a. JESS emphasis has shifted to NAESB, how much has the NERC role diminished? b. Would a liaison from NERC to the JESS be sufficient? c. What are the reliability implications for the IS to discontinue as NERC parent subcommittee to the JESS? d. What are the Pros and Cons to continue status quo? The IS consensus to the questions above was that with the IS should not divest its parenthood of the JESS because reliability is one of the core concerns of the electronic tagging process. The significant reason the IS gave was that electronic tagging is a reliability process at its core; it manages transmission loading relief; it facilitates business getting done. Individual Statement by Fred Kunkel on the 2010 NERC Goals Fred Kunkel presented his opinion of the current state of affairs within the NERC 2010 Goals, through his individual statement, See Exhibit C. Mr. Kunkel discussed his position and views with the IS. The IS did not endorse, support, or give an opinion to Mr. Kunkel s statement or perspective. Interchange Subcommittee Action Items List Secretary Vandervort updated the IS Action Items List. Each subcommittee member is to review, take action for his or her items, and update the action item list, which is affixed as Exhibit G. Dates and Locations of Future Meetings IS and CISDT Joint Meeting Wednesday, September 8, 2010 Thursday, September 9, a.m. 5 p.m. 8 a.m. 5 p.m. Location: Holyoke, MA or Boston, MA(tentative) Host: ISO-NE Office Peter Harris, point of contact IS and CISDT Joint Meeting 8 a.m. 5 p.m. Location: San Diego (tentative) Interchange Subcommittee Meeting Minutes May 26-27,

5 Wednesday, November 9, 2010 Thursday, November 10, a.m. 5 p.m. Host: SEMPRA Generation Office Jim Hansen, point of contact CISDT = Coordinate Interchange Standard Drafting Team * Dates and locations are to be coordinated by IS members with the respective regions or with utilities in the designated cities. Respectfully submitted, Tom Vandervort Thomas J. Vandervort Interchange Subcommittee Secretary Interchange Subcommittee Meeting Minutes May 26-27,

6 Exhibit A Agenda Interchange Subcommittee May 26, a.m. 5 p.m., CDT May 27, a.m. 5 p.m., CDT Midwest ISO Office 1125 Energy Park Dr. St. Paul, Minnesota Telephone: Administrative a. Membership and guests Joe Gardner Attachment: IS Roster (Attachment 1) b. Arrangements Tom Vandervort c. Approval of meetings minutes Joe Gardner Attachment: February 10-11, 2010 IS Meeting Minutes (Attachment 2) d. Approval of meeting agenda Joe Gardner e. Procedures i. Parliamentary Procedures Joe Gardner Attachment: Parliamentary Procedures (Attachment 3) ii. Antitrust Compliance Guidelines Tom Vandervort Attachment: Antitrust Compliance Guidelines (Attachment 4) f. Interchange Subcommittee Action Items List (Review prior to the meeting) Joe Gardner Attachment: IS Action Items List (Attachment 5) g. Interchange Scope Information Item i. IS Scope: NERC Goals and Objectives, Information Only Tom Vandervort a. Attachment: 2010 NERC Performance Goals and Objectives (Attachment 6) 3. Interchange Subcommittee Sub-groups a. Joint Electronic Scheduling Subcommittee (JESS) Bob Harshbarger, Clint Aymond b. Eastern Interconnection Interchange Tool Task Force (EIITTF) Jeremy West c. ACE Diversity Interchange Task Force (ADITF) Joe Gardner, Don Lacen, Tom Vandervort Village Blvd. Princeton, NJ

7 4. Operating Manual Documents Joe Gardner a. Dynamic Transfer Reference Guidelines, Industry Comments and Responses, and Revision Cheryl Mendrala b. Interchange Reference Guidelines, Industry Comments and Responses, and Revision Jeremy West Attachments: (1) Documents, comments, draft responses to be sent electronically to IS 5. Joint Electric Scheduling Subcommittee Relationship to IS Joe Gardner, Tom Vandervort a. JESS emphasis has shifted to NAESB, how much has the NERC role diminished? b. Would a liaison from NERC to the JESS be sufficient? c. What are the reliability implications for the IS to discontinue as NERC parent subcommittee to the JESS? d. What are the Pros and Cons to continue status quo? 6. Coordinate Interchange Standard Drafting Team, Project Joe Gardner a. NERC Project , Coordinate Interchange Standards Drafting Team Meeting, Joint Meeting with the IS Meeting Joe Gardner Attachments: (1) To be sent under separate cover 7. Future Meetings * a. September 8-9, 2010 IS and CISDT Joint Meeting Holyoke, MA or Boston, MA Host: ISO-NE Peter Harris Point of Contact b. November 9-10, 2010 IS and CISDT Joint Meeting San Diego Host: SEMPRA Generation Office Jim Hansen Point of Contact c IS Meetings to be Determined * Future IS meetings need to be held at region, utility, or volunteer facilities CISDT = Coordinate Interchange Standard Drafting Team, NERC Project Interchange Subcommittee Meeting Agenda May 26-27,

8 Exhibit B Attendance Interchange Subcommittee May 26-27, 2010 Midwest ISO Office St. Paul, Minnesota Attendance: Name Attendance Joseph Gardner, Chair Y Jeremy West, Vice Chair Y Joel Mickey Y Shane Jenson Y Peter Harris Proxy: Cheryl Mendrala Y Frederick Kunkel Y Christopher Pacella Y John Ciza Y Michael Oatts Y Donald Lacen Y Eric Nehf Y Paul Rice Y Robert Harshbarger Y Thomas Vandervort Y Clint Aymond, JESS Chair Bert Gumm David McRee Leslie Williams Y Y Y Y Village Blvd. Princeton, NJ

9 Exhibit C From: Fred Kunkel To: Interchange Subcommittee Date: May 26, 2010 Subject: Individual Statement on the 2010 NERC Goals I would like the IS to comment on the 2010 NERC goals and how they are effecting the NERC community. Also, would like the Sub-Committee to discuss whether NERC (and FERC) get back to developing a total game plan on where the Electric Industry needs to have a vision of where we need to be in the future. It appears to me we have SWISS CHEESE as a Superstructure and we are taking on water in every RRO ship compartment except the compliance end of the industry as it continues to grow in exponential proportion and this vista really bothers me and my company. We spend way too much of our fees for NERC activities that do not address a Reliability environment as the issues to me are: 1) We have 2-3 RTOS that encompass 40 to 50 % of all of our operation/planning whether daily or annual, etc and yet the FERC and NERC community have RTOS in multiple RRO regions and in those cases have different regional/national requirements. 2) NERC cannot even develop a simple Reserve requirement which is simplistic in view that transcends over the nation such as a MINIMUM REQT. 3) FERC has 1 RTO operate on as a capacity market, another as an ENERGY market and then some other RTO in some composite market let alone the rest of the country be governed differently. 4) We do not handle reserve requests uniformly across the US let alone the payment for this excess capacity in which one state might lean onto the other state for its reserve such as California vs. Arizona or Nevada.. As a member of the NERC I/S for many years, I am disheartened to the fact that we as an industry have NO FORMAL LONG TERM STRUCTURE on Reliability and Resource Planning Nationally versus the constant vista of COMPLIANCE hanging over your head and spending half your life justifying your existence and not in planning for a better Industry to protect the US in making sure we have a reliable operating system, uniform across the US with LESS LOWER CASE standards or UPPER CASE STANDARDS and not have 1200 potential standards staring you as a company for years to come. Have bread and butter standards not a fruit salad with thousands of salad dressing and flavoring.

10 Electric Companies need a better VISTA to plan where and what we are going to face in the future but ALL I SEE IS inconsistent application of numerous Standards and definitions such as the LSE definition as an example be stuck in standards that are at best complicated in making them useful let alone cost effective. NERC increased their staff for Compliance by 30%-40% last year, and all of our companies had to shrink in our budget. When ECAR, MAAC and MAIN were envisioned to be ONE RFC (RRO), the knowledge was it would be more cost effective but the end result was that our costs to operate the RRO went up dramatically let alone the previous members of those respective RROs went to SERC and left the ECAR,MAAC and MAIN fold which did not make any sense globally especially for the transition year which let companies go to another RRO such as AMEREN. I am not picking on AMEREN but just trying to illustrate the inconsistency of direction from FERC and NERC. A stake is put into the ground here and now to say enough is enough and I for one see a REAL NEED TO GET THE NERC COMMUNITY BACK ON TRACK and start righting the ship before everyone sets into complacency and NOT want to tackle the future but just go along with the Government mandates and not have a TEA PARTY and say taxation without good representation is INCONSISTENCY AND DUPLICITY let alone to have a company plan for its expenditures in transmission builds, generation resource planning and manpower requests to meet the business needs of meeting load with generation in a reliable manner. I would like the NERC I/S to really hone in on my darts of truth in which many people say these truths are in existence but few are willing to bring to the front burner where this needs to be. Frederick J. Kunkel NERC I/S Member RFC Representative (possibly after this request, may not be a member of the NERC I/S)

11 ADI White Paper Outline Exhibit D BACKGROUND Purpose of White Paper Definitions (from NERC Glossary of Terms, ADI definition, etc) Area Control Error ACE Inadvertent Inadvertent Interchange Primary Inadvertent Interchange Secondary Inadvertent Interchange Dynamic Transfer Dynamic Schedule Pseudo-Tie ACE Diversity Interchange (ADI) Regulating Reserve John Tolo John Tolo Starting Point End Point ADI PRACTICE AND ATTRIBUTES PROS/CONS Pros Cons Performance (improvements) - CPS1, CPS2: Unit Movement (Reduction) higher Efficiencies? Volunteer to write Doug Hills OTHER ISSUES Tariff Issues/Legal Issues: Equipment/Infrastructure Requirements Doug Hils Carol Opatrny, Tony Nguyen Impact Input/Export Capacity (Is ADI going to affect transmission?) Equity Issues Mike Potishnak? Volunteer to write Tracking Monitoring Interactions with market Complexity of issues Mike Potishnak, Jim Castle, Carol Opatrny Mike Potishnak, Jim Castle, Carol Opatrny Bob Staton, Steve Bruening, David Lemmons Carol Opatrny

12 Transmission Reservation vs. No Transmission Reservation FERC view Merchant Issues Transmission Tagging (should ADI be tagged as Pseudo-Tie or Dynamic Schedule) Existing Markets (conflicts or restrictions) Shari Brown? Volunteer to write Bob Staton Doug Hils Doug Hils? Volunteer to write Settlement? Volunteer to write Pros:? Volunteer to write Cons:? Volunteer to write ANALYSES Technical Discussion Necessary Attributes Constrained Paths Equal Benefits Implementation Additional Consideration Affects of ADI on Reliability? Volunteer to write? Volunteer to write Carol Opatrny? Volunteer to write? Volunteer to write? Volunteer to write? Volunteer to write CONCLUSION SUMMARY PARKING LOT ISSUES: How does ADI affect frequency response Compare the White Paper to Doug s Duke Energy ADI Concerns Letter

13 Exhibit E Dynamic Transfer Reference Guidelines Version 2 June 2010 Dynamic Transfer Reference Guidelines Version 2 June 2010

14 Dynamic Transfer Reference Guidelines Version 2 Table of Contents Table of Contents Chapter 1 Overview... 3 Purpose... 3 Terms... 3 Chapter Dynamic Schedule versus Pseudo-tie Fundamentals... 4 Chapter 3 Dynamic Transfer Implementation Considerations... 5 Table 1 - Assignment of BA Obligations... 8 Chapter 4 Dynamic Schedule... 9 Chapter 5 Pseudo-Tie Appendix A ACE Equation Implications of Dynamic Transfers Appendix B Supplemental Regulation Service as a Dynamic Schedule Appendix C Supplemental Regulation Service as a Pseudo-Tie Dynamic Transfer Reference Guidelines Version 2 June

15 Dynamic Transfer Reference Guidelines Version 2 Chapter 1 -- Overview Chapter 1 Overview Purpose The purpose of this document is to provide guidance and encourage consistency in the industry on the responsibilities, requirements, and expectations placed upon parties involved in establishing a dynamic transfer. It is not within the scope of this reference document to require any organization to modify any existing dynamic transfers. Terms ATTAINING BA A BA bringing generation or load into its effective control boundaries through dynamic transfer from the Native BA. DYNAMIC TRANSFER SIGNAL The electronic signal used to implement a pseudo-tie or dynamic schedule using either a metered value or a calculated value. INTEGRATION in the terms for dynamic schedule and pseudo-tie above means the value could be mathematically calculated or determined mechanically with a metering device. NATIVE BA A BA from which a portion of its physically interconnected generation and/or load is assigned from its effective control boundaries through dynamic transfer to the attaining BA. Dynamic Transfer Reference Guidelines Version 2 June

16 Dynamic Transfer Reference Guidelines Version 2 Chapter 2 -- Fundamentals Chapter 2 Dynamic Schedule versus Pseudo-tie Fundamentals The key difference between pseudo-ties and dynamic schedules is often viewed only as a system control issue. Discussions are typically limited to how the transfer is implemented in each BA s ACE equations and in the associated energy accounting process. Pseudo-ties are accounted for by all parties as actual interchange and dynamic schedules are accounted for as scheduled interchange. However, there are other factors that must be considered when determining which type of dynamic transfer should be utilized for a given situation. The descriptions provided in this document are based on practical experience where dynamic transfers have been successfully implemented. From a simple perspective, a dynamic schedule is a means of achieving a time-varying exchange of power where a traditional block scheduling is not sufficient. Examples might be the partial or complete exchange of regulating obligations (see Appendix B Supplemental Regulation Service as a Dynamic Schedule), the temporary provision of power under a reserve sharing agreement, or the exchange of power to serve a real-time demand signal. On the other hand, pseudo-ties are used (typically but not exclusively) to represent interconnections between two BAs at a generator or load similar to a physical tie line. These load/generators, however, are at locations where no other physical connection exists between the load/generation and the power system network of the responsible, Attaining BA s traditional control boundaries defined by its physical tie lines. In the instance of a pseudo-tie, the operational and procedural responsibility 1 for a load/generation is key. In addition to system control responsibility that is traditionally considered, the responsibilities related to a pseudo-tie extend to such requirements as Disturbance Control Standard (DCS) recovery, load shedding, transmission and ancillary services, load forecasting, etc. associated with the load/generation. Although both pseudo-ties and dynamic schedules involve time-varying quantities, unlike for a pseudo-tie, a dynamic schedule has no specific load/generation for which the attaining BA is operationally or procedurally responsible. The choice of a pseudo-tie versus dynamic schedule can be adapted to suit any implementation between the native and attaining BAs as long as both BAs agree which one is responsible for each of the obligations associated with the load/generation. For example, a pseudo-tie would typically be used to represent a generator owned by an attaining BA that is located within the physical tie line boundary of a native BA. However, a dynamic schedule implementation can be used in each BA s ACE equation as long as responsibility for obligations such as recovery during a DCS event are clearly understood and accepted by both BAs. 1 Procedural responsibility refers to which Balancing Authority Area s and/or which Reliability Region s requirements will apply to the generator or load Dynamic Transfer Reference Guidelines Version 2 June 2010

17 Dynamic Transfer Reference Guidelines Version 2 Chapter 3 Dynamic Transfer Implementation Considerations Chapter 3 Dynamic Transfer Implementation Considerations Dynamic transfers can be used for, but not limited to the following scenarios: Transfer all, or a portion of, actual output of a specific generator(s) to another BA in realtime, Enable resources in one BA to provide the real-time power requirements for a load physically located in another BA, or Enable generators, loads, or both in one BA to supply one or more interconnected operations services to generators, loads, or both in another BA, or Provide a mechanism for reserve sharing, or Provide supplemental regulation. The particular dynamic transfer method to be utilized for a specific operating arrangement may be dependent on some or all of the following: Desired service(s) to be provided, The capability to capture the dynamic transfer in system models, Responsibility for forecasting load, Responsibility for providing unit commitment and maintenance information, and EMS capability. Each BA is obligated to fulfill its commitment to the Interconnection and not burden other BA(s) in the Interconnection. The use of a dynamic transfer does not in any way diminish this responsibility. Before implementing the dynamic transfer, all parties to the dynamic transfer must agree on all implementation issues. Any errors resulting from an improperly implemented or operated dynamic transfer (including inadvertent interchange accumulations) must be resolved between the involved parties. Dynamic transfers must NOT include any control offsets that are not explicitly compliant with the requirements set forth in the NERC reliability standards (e.g., unilateral inadvertent payback, Western Interconnection automatic time error control, etc.). Applicable tariff requirements of all involved, or affected, transmission providers and BA(s) must be met (this includes proper handling and accounting for energy losses). Dynamic Transfer Reference Guidelines Version 2 June

18 Dynamic Transfer Reference Guidelines Version 2 Chapter 3 Dynamic Transfer Implementation Considerations If the dynamic transfer includes a pre-arranged calculated assistance (or distribution of responsibility) between the native BA and the attaining BA for recovery from the loss of generation, then both BAs are responsible for ensuring that their respective DCS compliance reporting requirements are met in accordance with NERC Standard BAL Disturbance Control Performance. The projected use of the transmission system for a dynamic transfer shall be modeled in the base case power flow study cases. Such modeling must be done for the dynamic transfer at each end of its range, and for as many other points within its range as required to ensure that the dynamic transfer will not cause reliability problems in real time. From a system modeling perspective, the assignment of load or generation into the control response of another BA must be appropriately captured in the reliability analysis tools. It is the obligation of each BA involved in the dynamic transfer to ensure that the dynamic transfer of load or generation is coordinated with their Reliability Coordinator so that the method of dynamic transfer can be considered in the system modeling of the generation or load affected, and necessary data provision requirements are met. To assure proper resource application, it is the responsibility of the attaining BA dynamically transferring load into its effective boundaries through pseudo-ties to ensure that load forecasts and subsequent BA reporting reflect the load incorporated within its BA boundaries. Conversely, when a dynamic schedule is used to serve load within another BA area, the BA where the load is electrically connected (native BA) must include that load in its BA load forecast and any subsequent reporting as needed. It is the responsibility of both the native BA and attaining BA to model any generation or load serving dynamic transfers in their respective, power flow models and security applications. This modeling is required to ensure that both affected BAs study the generation or load regardless of the control boundary designations. This modeling also is necessary to ensure that each BA can see the impact of the dynamic transfer on their systems.. Dynamic transfers must not affect reliability adversely. If the reliability impact of a dynamic transfer that has been implemented as a pseudo-tie cannot be addressed adequately without modeling it in the IDC or other applicable security analysis system models that use scheduled values, then the dynamic transfer must be performed via a dynamic schedule. FOR BOTH PSEUDO-TIES AND DYNAMIC SCHEDULES The BAs shall adjust the control logic that determines their frequency bias setting to account for the frequency bias characteristics of the loads and/or resources being assigned between BAs. o Frequency Bias Setting Each BA is required to review its Frequency Bias Setting on an annual periodicity. The BA may change its Frequency Bias Setting, and the method used to determine the setting, whenever any of the factors used to determine the current bias value change. Each BA, upon request from NERC, will report its Frequency Bias Setting, and the method for determining the setting. Dynamic Transfer Reference Guidelines Version 2 June 2010

19 Dynamic Transfer Reference Guidelines Version 2 Chapter 3 Dynamic Transfer Implementation Considerations The native, attaining, and intermediate BAs must carefully coordinate many aspects related to dynamic transfers. Failure to do so may result in the creation of reliability problems for the Interconnection, may create after-the-fact energy accounting and billing problems, and may cause violations of industry standards. Below is a list of items that the affected BAs should consider prior to implementing a new dynamic transfer.. Control offsets are compliant with applicable industry standards Tariff requirements are met DCS reporting requirements have been addressed Transmission service has been considered Need for inclusion in reliability tools has been addressed Transferred loads and/or generation are accounted for in energy dispatch Transferred loads and/or generation are still included in relevant security analysis tools Frequency Bias impacts have been addressed Contingency plans for loss of dynamic transfer signal have been addressed Contingency plans for network problems that prohibit the dynamic transfer Other industry compliance issues have been addressed Energy accounting practices are consistent, including losses Ancillary service provision has been addressed Impact on spinning reserve requirements have been addressed Impact on under-frequency load shedding relays have been addressed Table 1 describes and outlines the obligations associated with the typical historical application of pseudo-ties and dynamic schedules related to many of the topics addressed above. In practical application, however, both the native and attaining BAs can agree to exchange the obligations from that shown in the Table 1. Dynamic Transfer Reference Guidelines Version 2 June 2010

20 Dynamic Transfer Reference Guidelines Version 2 Chapter 3 Dynamic Transfer Implementation Considerations Table 1 - Assignment of BA Obligations BA s Obligation/modeling Pseudo tie Dynamic schedule Generation planning and reporting and outage coordination Attaining BA Typically, native BA but may be reassigned (wholly or a portion) to the attaining BA CPS and DCS recovery /reporting and RMS Attaining BA Attaining and/or native BA (depending on agreements) Operational responsibility Attaining BA Native BA BA services FERC OATT Schedules 3 6 and other ancillary services as required Attaining BA Native BA Ancillary services associated with transmission FERC OATT Schedules 1 2 and other ancillary services as required ACE frequency bias calc/setting Attaining/native BA (as agreed) The native and attaining BA(s) shall adjust the control logic that determines their frequency bias setting to account for the frequency bias characteristics of the loads and/or resources being assigned between BA(s) by the pseudo-tie Attaining BA Attaining/Native BA (as agreed) The attaining BA should include the load from its dynamic schedule as a part of its forecast load to set frequency bias requirement. The native BA should change its load used to set frequency bias setting by the same amount in the opposite direction. Native BA Load forecasting and reporting Manual load shedding during Attaining BA Native BA an Energy Emergency Alert (EEA) Note: This table contains the typical BA obligations that have been utilized throughout the industry for pseudo-ties and dynamic schedules. However, for any specific dynamic transfer implementation, both the native and attaining BAs can agree to exchange the obligations from that shown in the Table 1. Dynamic Transfer Reference Guidelines Version 2 June 2010

21 Dynamic Transfer Reference Guidelines Version 2 Chapter 4 Dynamic Schedule Chapter 4 Dynamic Schedule A dynamic schedule is implemented as an interchange transaction that is modified in real-time to transfer time-varying amounts of power between BAs. A dynamic schedule typically does not change a BA s operational responsibility; that is, the native BA continues to exercise operational control over, and provides basic BA services to, the dynamically scheduled resources. Dynamic schedules are to be accounted for as interchange schedules by the source, sink, and contract intermediary BA(s), both in their respective ACE equations, and throughout all of their energy accounting processes. Requirement to incorporate into the contract intermediary BA s ACE is subject to regional procedures. All dynamic schedules used for supplemental regulation or to assign the control of generation, loads, or resources from one BA to another must meet the following requirements: 1. Telemetry Appropriate telemetry must be in place and incorporated by all affected BA(s) in accordance with all NERC reliability standards, in particular the Disturbance Control Performance standard. 2. Transmission Service Prior to implementation of the dynamic schedule of load or generation, all applicable NERC interchange reliability standards need to be met, including ancillary services and provision of losses. If transmission service between the source and sink BA(s) is curtailed then the allowable range of the magnitude of the schedules between them, including dynamic schedules, may have to be curtailed accordingly. All BAs involved in a dynamic schedule curtailment must also adjust the dynamic schedule signal input to their respective ACE equations to a common value. The value used must be equal to or less than the curtailed dynamic schedule tag. Since dynamic schedule tags are generally not used as dynamic transfer signals for ACE, this adjustment may require manual entry or other revision to a telemetered or calculated value used by the ACE. 3. System Modeling When a dynamic schedule is used to serve load within another BA area, the BA where the load is electrically connected (native BA) must include that load in its BA load forecast for both energy dispatch and security analysis and any subsequent reporting as needed. This is necessary because the system models must adequately capture the projected demand on the system (load forecast), and the projected supply (provided by the electronic tagging system). Dynamic Transfer Reference Guidelines Version 2 June 2010

22 Dynamic Transfer Reference Guidelines Version 2 Chapter 4 Dynamic Schedule 4. Dynamic Schedule Coordination and Scheduling Implementation of a dynamic schedule must be through the use of an interchange transaction between BA(s). As such, all dynamic schedules shall be implemented in accordance with NERC interchange standards. Energy exchanged between the source, sink, and intermediary BA(s) as a dynamic schedule is the metered or calculated (obtained by the integration of the dynamic schedule signal) energy for the loads and/or resources. Agreements must be in place with the applicable transmission providers to address the physical or financial provision of transmission losses. The native BA must ensure that agreements are in place defining the responsibility for providing applicable ancillary/interconnected operations services. If the power flows associated with the dynamic schedule are expected to be bidirectional, two separate dynamic schedules are required (each schedule to be implemented as unidirectional following the gen-to-load direction convention). This expectation is a result of the fact that transmission service would be required for the dynamic schedules and most often import and export transmission services are provided as separate reservations. 5. Contingency Response Before implementation of the dynamic schedule, the involved BAs shall agree on a plan: To operate during a loss of the dynamic schedule telemetry signal such that all involved BAs are using the same value (including periods of time when the interconnection between them is unavailable). The BA(s) may agree to hold the last known good value, use an average load profile value, or have one party provide the other with a manual override value at some acceptable frequency of update. To serve the load during system conditions which prevent delivery of the dynamic schedule from the generation to the load. To redispatch the generation that had served the dynamically scheduled load prior to the system conditions which prevent delivery from the generation to the load. 6. Compliance with NERC Reliability Standards The implementation of a dynamic schedule may confer upon the attaining BA additional responsibilities for compliance with NERC reliability standards for the load or generation that has been transferred. Dynamic Transfer Reference Guidelines Version 2 June 2010

23 Dynamic Transfer Reference Guidelines Version 2 Chapter 5 Pseudo-Tie Chapter 5 Pseudo-Tie Pseudo-ties are often employed to assign generators, loads, or both from the BA to which they are physically connected into a BA that has effective operational control of them. Thus, pseudoties often provide for change of BA operational responsibility from the native to the attaining BA and at the same time make the attaining BA provider of BA services. In practice, pseudo-ties may be implemented based upon metered or calculated values. All BAs involved account for the power exchange and associated transmission losses as actual interchange between the BAs, both in their ACE equations and throughout all of their energy accounting processes. All pseudo-ties used to assign generation, loads, or resources from the native BA to the attaining BA must meet the following requirements: 1. Telemetry Prior to implementation of the pseudo-tie transfer of load or generation, all applicable NERC reliability standards need to be met, including: common metering points adequate communications infrastructure The requirement for common metering points and adequate communications infrastructure does not imply specific ownership of telemetry devices. 2. Transmission Service Prior to implementation of the pseudo-tie transfer of load or generation, each involved BA shall ensure that the dynamic transfer is implemented such that the tariff requirements of the applicable transmission provider(s), including applicable ancillary services and provision of losses, are met. If transmission service between the native and attaining BA(s) is curtailed, then the allowable range of the magnitude of the pseudo-ties between them must be limited accordingly to these constraints. Agreements must be in place with the applicable transmission providers to address the physical and/or financial provision of transmission losses. 3. System Modeling The attaining BA dynamically transferring load into its effective boundaries through a pseudo-tie shall ensure that load forecasts used for energy dispatch and subsequent BA reporting reflect the load incorporated within its BA boundaries. The native BA would continue to consider this load in load forecasts used for security analysis. Dynamic Transfer Reference Guidelines Version 2 June 2010

24 Dynamic Transfer Reference Guidelines Version 2 Chapter 5 Pseudo-Tie If the reliability impact of the pseudo-tie cannot be accurately captured in the IDC and/or any other security analysis system models of the reliability entities impacted by the dynamic transfer, then the dynamic transfer must be implemented as a dynamic schedule. 4. Pseudo-Ties Coordination and Scheduling Subsequent to moving load or resources into an attaining BA through pseudo-tie transfers, all interchange transactions or other energy transfers to the loads or from the resources must be coordinated among the attaining intermediary and native BAs in accordance with the NERC reliability standards. The attaining BA assumes responsibility for BA services required by the assigned loads and/or resources. The attaining BA assumes all regulation, contingency reserves, and other BA responsibilities for the loads and/or resources in question. Energy exchanged between the native and attaining BA(s) by the pseudo-tie method is accounted for by the associated revenue meter reading (if such meter exists at the dynamically assigned resource or load) or energy calculated by integrating the associated telemetered real-time signal. 5. Contingency Response Before implementation of the pseudo-tie transfer, the involved BAs shall agree on a plan: To operate during a loss of the pseudo-tie transfer telemetry signal such that all involved BAs are using the same value (including periods of time when the interconnection between them is unavailable). The BA(s) may agree to hold the last known good value, use an average load profile value, or have one party provide the other with a manual override value at some acceptable frequency of update. To serve the load during system conditions which prevent delivery of the pseudo-tie transfer from the generation to the load. To redispatch the generation that had served the pseudo-tie transfer load prior to the system conditions which prevent delivery from the generation to the load. 6. Compliance with NERC Operating Standards The implementation of a pseudo-tie transfers may confer upon the attaining BA additional responsibilities for compliance with NERC reliability standards for the load or generation that has been transferred. Dynamic Transfer Reference Guidelines Version 2 June 2010

25 Dynamic Transfer Reference Guidelines Version 2 Appendix A ACE Equation Implications of Dynamic Transfers Appendix A ACE Equation Implications of Dynamic Transfers ACE = {[Net Actual Interchange] [Net Schedule Intechange]} 10F b (F A F S ) I ME (1) ACE = {[NI A ] [NI S ]} 10F b (F A F S ) I ME (2) ACE = {[(NI a ) + (NI APTGE NI APTGI NI APTLE + NI APTLI + NI ARSE - NI ARSI )] [(NI s ) + ( NI SDSGE + NI SDSGI + NI SDSLE NI SDSLI NI SRSE + NI SRSI )] } 10F b (F A F S ) I ME (3) where: Net Actual Interchange (NIA) Affected by pseudo-ties/agc interchanges NI A = (SUM of Tie Lines) + (SUM of Pseudo-Ties) NI A = (NI a ) + (NI APTGE NI APTGI NI APTLE + NI APTLI + NI ARSE - NI ARSI ) where: NI a = Net sum of tie line flows NI APTGE = sum of AGC interchange generation external to the attaining BA. NI APTGI = sum of AGC interchange generation internal to the BA (native BA). NI APTLE = sum of AGC interchange load external to the BA (attaining BA). NI APTLI = sum of AGC interchange load internal to the BA (native BA). NI ARSE = supplemental regulation service external to the BA (BA purchasing the supplemental regulation service) via pseudotie. See Appendix C. NI ARSI = Supplemental regulation service internal to the BA (BA selling the supplemental regulation service) via pseudo-tie. See Appendix C. and where values for all generation and load terms are assumed to be positive quantities Dynamic Transfer Reference Guidelines Version 2 June 2010

26 Dynamic Transfer Reference Guidelines Version 2 Appendix A ACE Equation Implications of Dynamic Transfers Net Scheduled Interchange (NIS) Affected by dynamic schedules and supplemental regulation services. NI S = (SUM of non-dynamically scheduled transactions) + (SUM of Dynamic Schedules) NI S = (NI s ) + ( NI SDSGE + NI SDSGI + NI SDSLE NI SDSLI NI SRSE + NI SRSI ) where : NI s = Net sum of non-dynamically scheduled transactions, NI SDSGE = Sum of dynamically scheduled generation external to the attaining BA, NI SDSGI = Sum of dynamically scheduled generation internal to the native BA, NI SDSLE = Sum of dynamically scheduled load external to the attaining BA, NI SDSLI = Sum of dynamically scheduled load internal to the native BA, NI SRSE = Supplemental regulation service external to the BA (BA purchasing the supplemental regulation service). See Appendix B, NI SRSI = Supplemental regulation service internal to the BA (BA selling the supplemental regulation service). See Appendix B, and where values for all generation and load terms are assumed to be positive quantities. Terms Unaffected by Dynamic Transfers F b = BA Frequency Bias F A = Actual Frequency F S = Scheduled Frequency I ME = Meter Error Correction The following sections show which specific component should be used by each involved BA to reflect each type of dynamic transfer in its ACE equation. Dynamic Transfer Reference Guidelines Version 2 June 2010

27 Dynamic Transfer Reference Guidelines Version 2 Appendix A ACE Equation Implications of Dynamic Transfers Application of Pseudo-ties in ACE by BA(s) Balancing Authority A Balancing Authority B Balancing Authority C (A B) BA(s) A and B are Adjacent BA(s). (A C B) BA C is an Intermediate BA. (A C) BA(s) A and C are Adjacent BA(s). (A B C) BA B is an Intermediate BA. Table A-1 P1 Generator From A to B Path A B P2 Generator From A to B Path A C B P3 Generator From A to C Path A C P4 Generator From A to C Path A B C P5 Load From A to B Path A B P6 Load From A to B Path A C B P7 Load From A to C Path A C BA A BA B BA C A B NI APTGI NI APTGE A C C B NI APTGI NI APTGE NI APTGE NI APTGI A C NI APTGI NI APTGE A B B C NI APTGI NI APTGE NI APTGI NI APTGE A B NI APTLI NI APTLE A C C B NI APTLI NI APTLE NI APTLE NI APTLI A C NI APTLI NI APTLE Dynamic Transfer Reference Guidelines Version 2 June 2010

28 Dynamic Transfer Reference Guidelines Version 2 Appendix A ACE Equation Implications of Dynamic Transfers P8 Load From A to C Path A B C A B B C NI APTLI NI APTLE NI APTLI NI APTLE Application of Dynamic Schedules in ACE by BA(s) Balancing Authority A Balancing Authority B Balancing Authority C (A B) BA(s) A and B are Adjacent BA(s). (A C B) BA C is an Intermediary BA. (A C) BA(s) A and C are Adjacent BA(s). (A B C) BA B is an Intermediary BA. Table A-2 S1 Generator output From A to B Path A B S2 Generator output From A to B Path A C B S3 Generator output From A to C Path A C S4 Generator output From A to C Path A B C BA A BA B BA C A B NI SDSGI NI SDSGE A C C B NI SDSGI NI SDSGE NI SDSGE NI SDSGI A C NI SDSGI NI SDSGE A B B C NI SDSGI NI SDSGE NI SDSGI NI SDSGE Dynamic Transfer Reference Guidelines Version 2 June 2010

29 Dynamic Transfer Reference Guidelines Version 2 Appendix A ACE Equation Implications of Dynamic Transfers S5 Serve a Load In B from A Path A B S6 Serve a Load In B from A Path A C B S7 Serve a Load In C from A Path A C S8 Serve a Load In C from A Path A B C A B NI SDSLI NI SDSLE A C C B NI SDSLI NI SDSLE NI SDSLE NI SDSLI A C NI SDSLI NI SDSLE A B B C NI SDSLI NI SDSLE NI SDSLI NI SDSLE Numeric Examples BA West 100 Gen W Load X 50 Ties BA East Load Y Gen Z Assume: Net sum of tie flows = 0, Net sum of non-dynamically scheduled transactions = 0, F S = F A, and I ME = 0 In these examples, BA West will become the attaining BA for load Y and generator Z. Similarly, BA East will become the attaining BA for load X and generator W. Dynamic Transfer Reference Guidelines Version 2 June 2010

30 Dynamic Transfer Reference Guidelines Version 2 Appendix A ACE Equation Implications of Dynamic Transfers Using Dynamic Schedules Using Table A-2, rows S1 and S5, to obtain the correct net scheduled interchange terms for the dynamic schedules, the ACE equation for BA West becomes: ACE BA West = NI A NI S = NI A (NI s NI SDSGE + NI SDSGI + NI SDSLE NI SDSLI ) = NI A (NI s Gen Z + Gen W + Load Y Load X) Substituting the values in the example as positive quantities, the equation becomes: ACE BA West = 0 ( ) = 0 ( 75) = 75 Using Pseudo-Ties Using Table A-1, rows P1 and P5, to obtain the correct net actual interchange terms for the pseudo-ties, the ACE equation becomes: ACE BA West = NI A NI S = (NI a + Gen Z Gen W Load Y + Load X) NI S Substituting the values in the example as positive quantities, the equation becomes: ACE BA West = ( ) 0 = 75 Using both Dynamic Schedules and Pseudo-ties Assume that the generation will be modeled as dynamic schedules and the loads as pseudo-ties. Using Table A-2, Row S1 and Table A-1, Row P5 to obtain the correct Net Scheduled Interchange and Net Actual Interchange terms for the dynamic transfers, the ACE equation for BA West becomes: ACE BA West = NI A NI S = (NI a Load Y + Load X) (NI s Gen Z + Gen W) Substituting the values in the example as positive quantities, the equation becomes: ACE BA West = ( ) ( ) = ( 25) ( 100) = = 75 Note: In all cases the ACE value is the same regardless of the dynamic transfer method(s) used. Dynamic Transfer Reference Guidelines Version 2 June 2010

31 Dynamic Transfer Reference Document Version 2 Appendix B Supplemental Regulation Service as a Dynamic Schedule Appendix B Supplemental Regulation Service as a Dynamic Schedule Supplemental regulation service is when one BA provides part of the regulation requirements of another BA. The BA(s) implement a dynamic schedule incorporating the calculated portion of the ACE signal that has been agreed upon between them. This is accomplished by adding another component to the scheduled interchange component of the ACE equation for both BA(s). Care should be taken to maintain the proper sign convention to ensure proper control, with the BA purchasing regulation service subtracting the supplemental regulation service from the scheduling component of their ACE while the BA providing the service adds it to the scheduling component of their ACE. If the supplemental regulation service includes a calculated assistance between the native BA and the attaining BA for recovery from the loss of generation, then both BA(s) are responsible for assuring that DCS compliance reporting requirements are met in accordance with NERC Standard BAL-002 Disturbance Control Performance. ACE equation modifications required for supplemental regulation service: ACE Equation Modifications Typically: ACE = (NI A NI S ) 10F b (F A F S ) I ME where: NI A = Net Actual Interchange NI S = Net Scheduled Interchange Fb = BA Frequency Bias F A = Actual Frequency F S = Scheduled Frequency I ME = Meter Error Correction For a DYNAMIC SCHEDULE the NI A remains unchanged, but to implement supplemental regulation service, the NI S term becomes: NI S = NI s NI SDSGE + NI SDSGI + NI SDGLE NI SDSLI NI SRSE + NI SRSI where: NI s = Net sum of non-dynamically scheduled transactions NI SDSGE = sum of dynamically scheduled generation external to the BA (attaining BA) NI SDSGI = sum of dynamically scheduled generation internal to the BA (native BA) NI SDSLE = sum of dynamically scheduled load external to the BA (attaining BA) Dynamic Transfer Reference Document Version 2 May

32 Dynamic Transfer Reference Document Version 2 Appendix B Supplemental Regulation Service as a Dynamic Schedule NI SDSLI = sum of dynamically scheduled load internal to the BA (native BA) NI SRSE = Supplemental regulation service external to the BA (BA purchasing the supplemental regulation service) NI SRSI = Supplemental regulation service internal to the BA (BA selling the supplemental regulation service) and where supplemental regulation service for an overgeneration condition is assumed to be negative and for undergeneration it is positive to achieve the desired effect via NI S on ACE as described in the NAESB WEQ Area Control Error (ACE) Equation Special Cases Standards - WEQBPS Dynamic Transfer Reference Document Version 2 May

33 Dynamic Transfer Reference Document Version 2 Appendix B Supplemental Regulation Service as a Dynamic Schedule Supplemental Regulation as Dynamic Schedule - Numeric Example BA West 100 Gen W Load X 100 BA East Ties Load Y Gen Z Schedule = 20 Assume: Net sum of tie flows = 0, Net sum of non-dynamically scheduled transactions = 20 Mw from BA-West to BA-East, F S = F A, and I ME = 0 In this example, BA-West will become the BA purchasing 15 Mw of supplemental regulation. Similarly, BA-East will become the BA selling 15 Mw of supplemental regulation. Using the correct net scheduled interchange terms for supplemental regulation as a dynamic schedule, the ACE equation for BA-West becomes: ACE BA - West = NI A NI S =NI A (NI s NI SDSGE + NI SDSGI + NI SDGLE NI SDSLI NI SRSE + NI SRSI ) simplifying for applicable terms for this example yields, = NI A (NI s NI SRSE ) Since purchaser BA-West is in an undergenerating condition in this example, the Supplemental Regulation term is positive and substitution in the equation becomes: ACE BA - West = 0 (20 15) = 0 (5) = 5 Similarly, the ACE equation for BA-East becomes: ACE BA - East = NI A NI S =NI A (NI s NI SDSGE + NI SDSGI + NI SDGLE NI SDSLI NI SRSE + NI SRSI ) simplifying for applicable terms for this example yields, = NI A (NI s + NI SRSI ) Dynamic Transfer Reference Document Version 2 May

34 Dynamic Transfer Reference Document Version 2 Appendix B Supplemental Regulation Service as a Dynamic Schedule Again since purchaser BA-West is in an undergenerating condition in this example, the Supplemental Regulation term is positive and substitution in the equation becomes: ACE BA - East = 0 ( ) = 0 ( 5) = 5 Dynamic Transfer Reference Document Version 2 May

35 Dynamic Transfer Reference Document Version 2 Appendix C Supplemental Regulation Service as a Pseudo-Tie Appendix C Supplemental Regulation Service as a Pseudo-Tie Supplemental regulation service is when one BA provides all or part of the regulation requirements of another BA. The BA(s) implement a pseudo-tie incorporating the calculated portion of the ACE signal that has been agreed upon between them. This is accomplished by adding another component to the actual interchange component of the ACE equation for both BA(s). Care should be taken to maintain the proper sign convention to ensure proper control. If the supplemental regulation service includes a calculated assistance between the native BA and the attaining BA for recovery from the loss of generation, then both BA(s) are responsible for assuring that DCS compliance reporting requirements are met in accordance with NERC Standard BAL-002 Disturbance Control Performance. ACE equation modifications required for supplemental regulation service: ACE Equation Modifications Typically: ACE = (NI A NI S ) 10F b (F A F S ) I ME where: NI A = Net Actual Interchange NI S = Net Scheduled Interchange Fb = BA Frequency Bias F A = Actual Frequency F S = Scheduled Frequency I ME = Meter Error Correction For a PSEUDO-TIE with supplemental regulation, the NI S remains unchanged, but the NI A term becomes: NI A = NI a + (NI APTGE NI APTGI NI APTLE + NI APTLI + N ARSE - N ARSI ) where: NI a = Net sum of tie line flows NI APTGE = sum of AGC interchange generation external to the attaining BA. NI APTGI = sum of AGC interchange generation internal to the BA (native BA). NI APTLE = sum of AGC interchange load external to the BA (attaining BA). NI APTLI = sum of AGC interchange load internal to the BA (native BA). Dynamic Transfer Reference Document Version 2 May

36 Dynamic Transfer Reference Document Version 2 Appendix C Supplemental Regulation Service as a Pseudo-Tie NI ARSE = supplemental regulation service external to the BA (BA purchasing the supplemental regulation service) via pseudotie. NI ARSI = supplemental regulation service internal to the BA (BA selling the supplemental regulation service) via pseudo-tie. As with dynamic schedules, for both the purchasing and selling BAs, supplemental service being provided to alleviate overgeneration has a negative sign, while supplemental service being provided to alleviate undergeneration has a positive sign. Dynamic Transfer Reference Document Version 2 May

37 Dynamic Transfer Reference Document Version 2 Appendix C Supplemental Regulation Service as a Pseudo-Tie Supplemental Regulation as Pseudo-Tie - Numeric Example 100 Gen W BA West Load X 100 Ties BA East Load Y Gen Z Schedule = 20 Assume: Net sum of tie flows = 0, Net sum of non-dynamically scheduled transactions = 20 Mw from BA-West to BA-East, F S = F A, and I ME = 0 In this example, BA-West will become the BA purchasing 15 Mw of supplemental regulation. Similarly, BA-East will become the BA selling 15 Mw of supplemental regulation. Using the correct net actual interchange terms for supplemental regulation as a pseudo-tie, the ACE equation for BA-West becomes: ACE BA - West = NI A NI S = (NI a + NI APTGE NI APTGI NI APTLE + NI APTLI + N ARSE N ARSI ) NI S simplifying for applicable terms for this example yields, = (NI a + N ARSE ) NI S Since purchaser BA-West is in an undergenerating condition in this example, the Supplemental Regulation term is positive and substitution in the equation becomes: ACE BA - West = (0 + 15) 20 = = 5 Similarly, the ACE equation for BA-East becomes: ACE BA - East = NI A NI S = (NI a + NI APTGE NI APTGI NI APTLE + NI APTLI + N ARSE N ARSI ) NI S simplifying for applicable terms for this example yields, = (NI a N ARSI ) NI S Dynamic Transfer Reference Document Version 2 May

38 Dynamic Transfer Reference Document Version 2 Appendix C Supplemental Regulation Service as a Pseudo-Tie Again since purchaser BA-West is in an undergenerating condition in this example, the Supplemental Regulation term is positive and substitution in the equation becomes: ACE BA - East = (0 15) ( 20) = = 5 Dynamic Transfer Reference Document Version 2 May

39 Dynamic Transfer Reference Document Version 2 May

40 Exhibit F Name of Commenter(s) Page Heading Laura Lee 11 Dynamic Schedule Coordination and Scheduling Dynamic Transfer Reference Guidelines Subject of Comment (Clearly identify text, figure, table) Implementation of a dynamic schedule must be through the use of an interchange transaction between BA(s). As such, all dynamic schedules must be tagged and implemented in accordance with NERC interchange standards Comment (Error, typos, proposed enhancements, deletions, etc.) (If possible, include proposed solution) This guideline is going beyond the requirements of the INT Standards. The INT Standards state: R1. The Load-Serving, Purchasing-Selling Entity shall ensure that Arranged Interchange is submitted to the Interchange Authority for: R1.1. All Dynamic Schedules at the expected average MW profile for each hour. The Guideline is assuming that tagging is the means that the Arranged Interchange is to be submitted to the BA. This does not have to be the method as long as the Interchange information is communicated between Balancing Authorities and meets the data need for a Request For Interchange. Also, this requirement is not made in the new draft INT Standards that are currently out for comment. We recommend that the language be modified to say: As such, all dynamic schedules shall be implemented in accordance with NERC interchange standards. Responses We agree, the term 'tagged' is a generally understood term but not necessarily consistent with the standards language and will make the suggested change. Joe Gardner I do remember that one of the items in the table was inconsistent with what was in one of the BAL standards (something to do with transferring responsibility from the native BA to the acquiring BA no response is required Peter Harris Mike Potishnak General comment General comment Just need to ask a clarifying question. Is there a stipulation that says we can only address items raised by the comments received? Meaning, if during a subsequent review the IS discovers an error that was not identified through a comment, that it cannot address the error without going out for comment again? I can see this being a requirement for any substantive changes, but for minor editorial and/or error fixes I would hope the Committee has the latitude to do the right thing. If this is the case, perhaps we have a chance to catch these issue later if none of us can come up with the specifics right away. no response is required The efforts of the NERC IS in drafting this important document are appreciated. The following concerns need to be addressed with respect to dynamic transfers, and this document is an excellent initial effort in the process. Proper adjustments to the ACE equation, re-assignments of responsibility for economic dispatch, and backup plans for the loss of the ability to perform the dynamic transfer, are all necessary to assure system frequency and possibly tie line flows are not affected adversely. The accuracy of study mode security analysis tools must not be compromised by dynamic transfers. The TLR process probably needs to deal with substantially sized dynamic transfers with nonzero probable values, but it is probably non-productive to force all dynamic transfers (e.g., supplemental regulation whose probable value is zero and whose values in time do not persist for very long) to be observable by the TLR process. The reference document attempts to address these issues. Suggestions for improvements are provided below. no response is required 5 7 Dynamic Schedule versus Pseudo-tie fundamentals Chapter 2 Dynamic Transfer Implementation Considerations First paragraph, 5 th, 6 th, and 7 th sentences 3rd and 4th bullets on page (1st and 2nd of second section) Will reconsider the 'thoeretical' standpoint These sentences are not clear and seem ineffective. There is an attempt to develop a bright white presented to more clearly state the rational behind theoretical line between pseudo-ties and dynamic schedules, but it is not being communicated the recommended methods. We do see value in successfully. Perhaps the simplest thing to do is to drop them. The second paragraph on the page refers presenting a 'recommended' approach to promote to the practical reality of what presently exists, and maybe we do not need to emphasize the theoretical consistent use for those creating new dynamic differences at this point in the document. transfers. These bullets need to be considered at the same time, and they need to work together smoothly. I believe the basics are as follows, irrespective of whether a dynamic schedule or a pseudo-tie is used to do it: (a) the attaining BA needs to include the load or generation being dynamically transferred to it in its energy dispatch, and the entity performing security analysis for the attaining BA does not need to include it in the security analysis for the geographic footprint of the attaining BA. If the entity performing security analysis for the attaining BA also needs to model the portion of the native BA s system containing the load or generation being dynamically transferred, then it needs to include that load or generation for security analysis in that portion of its model. (b) The native BA needs to exclude the load or generation being transferred out of it from its energy dispatch, but the entity responsible for the security analysis of the native BA needs to include that load or generation in its security analysis. We agree that the language needs to be clarified Assuming that (a) and (b) above have the necessary and sufficient requirements, let s review the 3rd and and will consider your suggestion in the drafting 4th bullets. In the 3rd bullet, the first sentence does not state energy dispatch specifically, but if it is assumed that that is what is meant, then it is also true for generation not just load, and, it is also true for dynamic schedules not just pseudo-ties. So the 3rd bullet s first sentence is narrowly correct, but incomplete. However, I totally disagree with the second sentence, as the reliability requirements do not change when the dynamic transfer is accomplished using a different term in the ACE equation. The 4th bullet is reasonably consistent with (b) above in what it says. However, it does not explicitly Dynamic Transfer Guidelines Comments and Responses 1 6/1/2010

41 Name of Commenter(s) Page Heading Dynamic Transfer Reference Guidelines Subject of Comment (Clearly identify text, figure, table) Comment (Error, typos, proposed enhancements, deletions, etc.) (If possible, include proposed solution) assignments may be swapped. That is fine. I also agree with the intent of table 1. However, in most cases it is not clear as to why the obligations and modeling would change based on the dynamic transfer method selected. Perhaps further explanation is needed as to why we want to try to standardize. Perhaps brief statements as to why the recommendation in table 1 is being made, as opposed to the alternative choice. For the first obligation (generation planning, etc), the pseudo-tie recommendation seems correct, but it is not clear why it would change for a dynamic schedule. For the second obligation (CPS and DCS etc.), again the recommendation for pseudo-ties seems correct, but it is not clear why it would change for a dynamic schedule. Also, what do we mean by RMS? Maybe just drop it. Responses 8 and 9 Chapter 2 etc Table 1 The BA jurisdiction obligation seems too broad Chapter 3 Dynamic Schedule Chapter 3 Dynamic Schedule Chapter 3 Dynamic Schedule Chapter 4 Pseudo-Tie Appendix A Ace Equation 1 st paragraph, 2 nd sentence For the fourth and fifth obligations, again further description for what is recommended and why it is different across dynamic transfer methods would be useful. The ACE frequency bias calculation should be restructured to show which items are the same for either method of dynamic transfer. However, when a BA computes its actual frequency response, it uses its net actual interchange. So if the dynamic transfer is accomplished via a pseudo-tie, then no special The term jurisidiction has been modified, the note treatment is required. But if it is done via a dynamic schedule, a special adjustment to the actual net that was in the text prior to the table was moved interchange term may be needed so that the frequency response samples are computed correctly. inside the table to make the intent of the Table more visible. What do we mean by operational jurisdiction, or a BA s jurisdiction? Is the term too broad? Maybe early on in the document a short paragraph can be added to flesh out just what jurisdictional issues apply to this subject? And when we say typically, does it only mean what we ve commonly found thus far? The term jurisidiction has been clarified Or does it constitute a default position, from which a deviation requires a reason, or permission, or something else? 3 rd paragraph Does it also apply to supplemental regulation? Yes, this will be added to the list System modeling, first sentence, and second sentence too Change must include to may need to include and insert used for security analysis after BA load forecast. The first change would be needed only if we would allow interested parties to decide that the dynamic transfer has negligible impact as mentioned previously. The second sentence similarly could change to may be necessary. 4. Dynamic Schedule 3 rd paragraph Why isn t this the responsibility of both BAs? Coordination and Scheduling 4. Dynamic Schedule 4th paragraph Coordination and Scheduling Chapter 4 2 nd Insert the word often after the word pseudo-ties. Supplemental regulation can use pseudo-ties and sentence, first paragraph Agreed Pseudo-Tie there aren t jurisdictional issues. Chapter 4 System modeling Insert the phrase for energy dispatch after the words load forecast. Agreed Pseudo-Tie It is not clear why this should differ as a function of the dynamic transfer method. It does make sense Pseudo-ties coordination and scheduling, that the default arrangement should be with the attaining BA you asked for it, you got it, the whole first bullet thing including ancillary services. We disagree with the addition of "used for security analysis" because it needs to be reported for more than just security analysis; it also needs to be considered by the native BA for the energy dispatch. We do not believe a tolerance should be set as to whether the BA processes need to consider the dynamic schedule The native BA must ensure the agreements, which do involve other entities, are in place before they invoke the dynamic schedule. Does this require at least one of the scheduled values to be zero? If yes, is it obvious or should it be It is most likely that one of the directions would be stated explicitly? What about supplemental regulation that could be bidirectional? Should both values be zero at any point in time. However, we do not set to the most probable value, which is often 0? believe that it needs to be stated explicitly. Chapter 3 and 4 are written to be consistent with Table 1 17 Table A-2 S1 through S4 In P1 through P4 of table A-1 on page 16, it refers to generators, while S1 through S4 here refer to resources we should be consistent or explain why not. Agree to make consistent 23 Appendix B Final answer =+5, the result was left out Agreed 20 and 24 Appendix D 6 th and 7 th row in table Change to transferred loads and/or generation Agreed Pg 3 Appendices B and C 2 nd paragraph We might want to follow the effort of the recently formulated NERC ADI Task Force as it relates to DCS to help in this area. There are memebers on the IS that are following this group Dynamic Transfer Guidelines Comments and Responses 2 6/1/2010

42 Name of Commenter(s) Page Heading Brian Tuck Abbey Nulph Jamie Murphy Bart McManus John Anasis Eric Nehf Wes Hutchison David Kirsch Denise Koehn Pg 3 Pg 4 Pg 7 Chapter 1 - Overview Chapter 1 Overview, Terms section Chapter 1 Overview, Dynamic Schedule vs Pseudo-tie Fundamentals Dynamic Transfer Reference Guidelines Subject of Comment (Clearly identify text, figure, table) There are new terms (such as "Attaining BA") mixed in with standard NERC terms ("BA"). There are some terms (such as "Frequency Response" and "Pseudo-Tie") whose definitions are different from the standard NERC definitions. Comment (Error, typos, proposed enhancements, deletions, etc.) (If possible, include proposed solution) If all are to be included in the Terms section of the document, it would be helpful to note which are existing NERC terms, which are new terms, and which are existing NERC terms with changes or enhancements to the definitions. Suggest moving the Terms to a separate section, prior to the Overview. The "Dynamic Schedule vs Pseudo-tie Fundamentals" section includes a key concept (" the operational and It needs to stand out more, perhaps my moving the Terms section, it won t be buried. jurisdictional responsibility for a load/generation is key") that is lost when this section is buried under the Terms. Responses We agree that the Terms section of this document should only contain terms NOT already defined in the NERC Glossary We will consider the formatting We agree that by moving the terms this section will be move visible Albert DiCaprio Patrick Brown William Harm Pg 7 Chapter 2, Dynamic Transfer 2 nd Bullet (use of transmission service for Implementation a dynamic transfer. ) Considerations Appendix B 3 Purpose Supplemental Regulation Service as a Dynamic Schedule. Overall Comment An additional consideration when evaluating reliability is the effect of ramp rates and the unpredictability of the power profile during real-time operations. Ramp rates and uncertainty during real-time can impact voltage management and stability, switching duty of reactive devices and burden on dynamic reactive sources, operating and contingency procedures, and transmission system operator situational awareness. All aspects should be considered, as appropriate to the specific characteristics of the affected transmission paths, to ensure that reliable operation is sustained. The final equation in the example is missing the 5 after the equality sign. BPA believes that even though this document is a Guideline, it should still use the NERC defined terms that already exist in the NERC Glossary, not create new ones. If the NERC Glossary needs to be updated to reflect enhanced definitions, a note to that effect should be made. We agree these items should be considered but do not believe they need to be listed in this document; the general phrase 'reliability problems' in the bullet covers all of these. Agreed We agree NERC terms should not be redefined here. We do not agree that the remaining terms need to be incoroprated into the NERC Glossary unless standards are written. This location for posting of these documents is Overall Comment different because they are not part of the Standards BPA would also like to suggest that in the future, a broader communication forum needs to be used Process. However, the request for comment was such as a widely disseminated announcing that comments are being solicited. The manner is which sent to the NERC Roster, which would have been this was posted made it almost impossible to find, we found it completely by chance three days before everyone in the NERC database. We welcome a final comments were to be submitted. suggestion as to where a better location would be for the comment and final document Overall Comment Overall, BPA feels this document is pretty good and appreciates the opportunity to provide feedback. no response is required The reference document is needed to assure standardization. A reference document does not assure standardiztion. A reference document merely provides documentation of what can be done. From a reliability perspective it is imperative that ad hoc adjustements to the ACE equation only be done with an understanding of the effects that the change will make. However, the idea that a standarized practice to accomplish a given task eems to be more in the scope of NAESB than in the scope of NERC. NERC has the responsibility to ensure that the end product (in this case ACE) is properly defined and meets the technical understanding of the NERRC standards the use ACE. How those numbers are added or subtracted should not be a NERC concern. From an ACE perspective, adding a flow value to the net tie value has the same impact as subtracting that value from the net schedule value. NERC Reference Guides should focus on the reliability aspects and not the IT aspects. We agree that the use of the term "standardization" would be better served by using "guidance" or another siimilar term and will make this change. However, with regard to the other comments here, we disagree that this issue is only an ACE issue and this document attempts to much more comprehesively supply guidance to all aspects of the use of a dynamic schedule vs. pseudo-tie -- not just the control perspective. We also disagree that these other issues are IT aspects. 3 Terms Attaining BA; Native BA These terms give the impression that one BA has more or less responsibility than the other. In the case of Dynamic Transfers and Pseudo-Ties the responsibility is and must be equally shared. These two types of metering require that both parties understand and implement the data in the same fashion. While it may be easier to lay out a common approach for all to use, the fact of the matter is that as long as the values are addressed in a manner that results in equal and opposite ACE adjustements (and equal and opposite market adjustments) there is no one way (practically or theoretically) that must be followed. In short the addition of these two terms does nothing to further clarify responsibilities and indeed may result in one BA waiting on the other to take responsibility. We disagree that these terms do not add clarification. While we agree there is no 'one way' that must be followed the concept captured in these terms allows these simple phrases to be used throughout the document withouth providing lengthy descriptions each place the concept is discussed. Dynamic Transfer Guidelines Comments and Responses 3 6/1/2010

43 Name of Commenter(s) Page Heading 4 Terms Frequency Response Dynamic Schedule vs Pseudo-ties Dynamic Schedule vs Pseudo-ties Dynamic Schedule vs Pseudo-ties Chapter 2 (Considerations) Dynamic Transfer Reference Guidelines Subject of Comment (Clearly identify text, figure, table) Last paragraph First paragraph Last paragraph Section 1 6 Section 2 (methods) 6 Section 3 7 Chapter 2 (cont d) 7 Section 2 7 First two bullets on page 7 Comment (Error, typos, proposed enhancements, deletions, etc.) (If possible, include proposed solution) This definition is not appropriate. Frequecy Response is a term that applies to a variety of time frames. Even the cavet of deploys automatically has problems. The definition starts with the term capacity which is oftentimes understood to be a MW capability value, and not an energy flow value. Regarding automatically, does this mean automaically in the sense of governor response, or does it mean automically in the sense that there is no manual intervention as in AGC regulation? The fact that the definition includes the misleading phrase following a siignificant and sustained frequency deviation further blurs the meaning. Governors respond whether or not the deviation is significant. And regulating units respond to signals that may or may not be filtered for significant deviations Delete first and last sentence in the paragraph. The key difference is NOT a control issue. The key difference is mathmatical. The ACE value will be the same whether or not the flow is added into one side or it is subtracted from the other side of the equation. Control is not impacted at all. There is NO fixed definition in the sense implied by the last sentence. A flow value added into the actual interchange is a pseudo-tie. That same flow value subtracted from the net scheduled interchange would be a dynamic schedule. And lastly, it is possible (and has been implemented) where one BA baised its actual flow and the other BA biased it schedule. As long as the both parties agree on the concept and both agree on the sign conventions then there is no NERC reliability impact Delete the paragraph. The paragrapgh is unclear and in parts incorrect. There is no theorectical standpoint vis-à-vis dynamic schedules. This paragrapgh is an SDT standpoint. The example of Supplemental Regulation does not serve as a fundmental issue. The fundamental issue is how to make the ACE value correct. The first sentence of the last paragraph is the correct explanation of the fundamental issue. Suggest deleting the rest of that paragrapgh again because there is no therorectical standpoint and there is no basis for the sentence itself. Only one bullet is needed: Transfer all or portion of a resource in one BA to another BA in real time. The reason for the transfer is academic and not a NERC issue. It is true that the energy can be used to serve load or it can be used for regulation or any other energy need. Delete entire section as it is unclear and incorrect. There is no one method (i.e. there is no need for both BAs to use the same approach there is a need for both to use complementary approaches). The idea that a dynamic transfer implies load forecasting or unit commitment responsibilities is not necessarily true. The method is dependent not on the reason as much as it depends on the fact that the resulting ACEs must be consistent! Bullet 2 is confusing. By defintion an error WILL impact the Interconnection. It is redundant to state that errors must be resolved. Bullet 3 is incorrect. There are no offsets allowed in ACE (except as defined in the NERC defintion of ACE). Dynamic Transfers are not control offsets they are metering agreements. Bullet 4 is not a NERC issue. Responses We agree this does not need to be defined here as is already a NERC defined term. Will reconsider the thoeretical standpoint presented to more clearly state the rational behind the recommended methods. We do see value in presented a 'recommended' approach to promote consistent use for those creating new dynamic transfers. If the intent cannot be made clear, we think the language should be removed. same as previous comment same as previous comment While we agree that one bullet would cover all items, more examples provide additional useful information for an entity considering the use of dynamic transfers We do agree the resulting ACEs muts be consistent. We assert, however, that both BAs must use the same approach; there are differences between the two implementations that have implications beyond ACE and the items in this list should be considered when choosing their approach. Bullet 2: We will consider your comment in redrafting Bullet 3: We agree and believe the bullet is consistent with the ACE equation Bullet 4: While not directly a reliability issue it is an item that an entity would need to consider when establishing a dynamic transfer Delete bullet 1: DCS is not contingent on how the ACE incorporates metered values. BAs are responsible Bullet 1: We do not agree with deleting this bullet. for responding to contingencies on their assets (not on the location of the asset). If a resource is located BAL-002 specifies two DCS computational options in another area the owning BA is still responsible for responding to that loss. There may be agreements for response to contingencies that employ step to handle such events in different ways, but the DCS standards are based on each BA s own ACE. If the schedule changes. We believe the item as written ACE is computed properly then the BA with the loss will by defintion see the propoer deviation in its ACE. emphasizes the need to honor those requirements. Delete bullet 2: Transmission service is not something that is modeled in security analysis programs. SA programs model generators and loads. Transmission service is viewed only from the perspective of what can and cannot be shed on the same basis as load shedding. A Dynamic schedule does not move the resource s location from an electrical perspective. Again, a Dynamic schedule does not move the resource s location from an electrical perspective, and therefore has no meaning to reliability analysis tools. Bullet 1 is not a dynamic schedule issue; it is a load serving issue. Whether or not the load is in the ACE, does not obviate the BA who owns the load from meeting that load. Load and load forecasting is independent of ACE or what goes into the ACE equation. Bullet 2 again, a Dynamic schedule does not move the resource s location from an electrical perspective and therefore has no meaning to reliability analysis tools Bullet 2: We do not agree this should be deleted. We agree this should not be referring to 'transmission service'; suggest reword to 'projected use of the transmission system by...' If there is not agreement between the areas involved there wil be reliability impacts. These bullets are intended to provide examples of issues where agreement is required. Bullet 3 is an important issue as regards to TLR. As a dynamic schedule that schedule must be a FIRM schedule else it would seemingly be subject to TLRs. The idea that a BA that uses a Dynamic Schedules We agree with your comment, however see no as opposed to a pseudo-tie does not impact reliability (ACE is still correct) as much as it impacts financial changes required concerns. Pseudo ties must not be used as a way of avoiding transmission reservations. Dynamic Transfer Guidelines Comments and Responses 4 6/1/2010

44 Name of Commenter(s) Page Heading Melinda Montgomery Jeremy West Daniel Farmer Dynamic Transfer Reference Guidelines Subject of Comment (Clearly identify text, figure, table) 7 Frequency Bias Setting 7 Section 1 on page Paragraph beginning "From a system modeling perspective, the assignment of load or generation into the control response of another BA..." Comment (Error, typos, proposed enhancements, deletions, etc.) (If possible, include proposed solution) Delete Bullet 4 & 5. While FBS is an ACE issue, it is not a dynamic schedule issue. FBS is generally computed once a year and not adjusted. For BAs using variable bias, the ACE is the prime basis for the changes, not the way the ACE is computed. Delete first paragraph. Dynamic schedules do not impact intermediate BAs; it is an offset only by the two directly impacted BAs. Accounting and billing issues are not NERC issues. Given that there are various methods for implementing the bilateral agreement, a checklist does not really add value. Delete paragraph and Table. All of the listed items are functions of the bilateral Agreements made for each pseudo tie or dynamic schedule. Both BAs must agree and both must understand the obligations associated with the resource allocation. From a pseudo tie or dynamic schedule the only impact is with the ACE itself. As long as the methods used by the two BAs are complementary, then the ACE will be correct. The ACE doers not change who is responsible for its own assets. Delete Chapter 3 and replace Chapter 2 with the ideas in Chapter 4. Keep telemetry and keep transmission service ideas. Delete system modeling (this is wrong). Delete Contingency response (it says BAs must agree on what they want to accomplish. Put that up front.) Delete Compliance (it says nothing special) Responses We agree Bullet 4 is merely repeating NERC standard language and can be deleted. However, the frequency bias can be impacted by taking the load associated with the pseudo tie from one area into another. We disagree with deleting bullet 5; while this is already in a NERC standard, there is specific action required with respect to dynamic transfers to ensure that the load is not double counted in the two areas when determining min frequency bias setting. We plan to combine bullet 4 and 5 to clarify how these items a e impacted b d namic t ansfe s We disagree with deleting the checkilst. Even if they are not specific NERC related items the checklist provides general guidelines and see it providing benefit to parties setting up a dynamic transfer. We disagree with deleting the table as this provides guidance for the industry on the 'typical/historical' implmentation for someone establishing new dynamic transfers. We disagree with this proposal. The current layout discusses general concepts in Chapter 2 and details of each type of transfer in 3 and 4 respectively. It is the obligation of each BA associated with a dynamic transfer to coordinate with their own Reliability We agree with the comment; we will clarify Coordinator when participating in a dynamic transfer. It would be an undue burden and create confusion language to be clear that each BA must coordinate to have every participating BA coordinate with all RCs involved in such a transfer. with your RC, not with ALL RCs System Modeling Bullet beginning "The entity responsible for the native BA s transmission security " If the reliability impact of the pseudo-tie cannot be accurately captured in the IDC and/or any other It is the responsibility of both the native BA and attaining BA to model any generation or load serving dynamic transfers in their respective power flow models and security applications. This modeling is required to ensure that both affected BAs study the generation or load regardless of the control boundary designations. This modeling also is necessary to ensure that each BA can see the impact of the dynamic transfer on their systems. BAs that use pseudo-ties will coordinate their reliability impact with affected systems and their own Reliability Coordinator. If the Reliability Coordinators where the pseudo-tie transfer occurs are aware of it and model it in their security analysis tools, then it may not be necessary for all reliability entities to include it in their models. We agree that both the native and attaining BA must appropriately reflect the generation and load and will review this language for consistency We will clarify the language to address this comment Dynamic Transfer Guidelines Comments and Responses 5 6/1/2010

45 Exhibit G Interchange Subcommittee May 27, 2010 Meeting Open Action Item List Action Figure Subject Action Item/Assignment Due Date Completion Date Jeremy West and EIITTF EIITTF , The IS formed an Eastern Interconnection Interchange Tool Task Force (EIITTF) to consider the advantages found in having a single Eastern Interconnection decision-making organization and an electronic interchange tool such as the Western Interconnection s WIT Jeremy intends to populate the EIITTF with a subject matter expert from each NERC region. These new members will join the EIITTF made up of Jeremy West - Task Force Chair, Shane Jenson, Jim Hansen, and Tom Vandervort. The Eastern Interconnection Interchange Tool Task Force (EIITTF) will perform its evaluation, document its technical conclusions and recommendations, and forward them to the NERC Technology Committee, the NERC OC, to NAESB, and to the NERC Regional Managers Committee , The EIITTF will finalize an Eastern Interchange industry questionnaire requesting information on interchange tools being used and interest in an interconnection-wide interchange tool , The EIITTF is in the final stages of preparing to send out the EI Interchange Surveys to the EI BAs and RREs. Survey results are to be received by January 15, 2009 and compiled for the Feb, 2009 IS meeting , EIITTF is evaluating the survey responses and is writing the EIITTF Final Report. Conference calls / webcasts will be held by the EITTF before the Feb, 2009 IS meeting, to continue the drafting the EIITTF Final Report , The EIITTF will try to finish the final report with conclusions and recommendations in order to present a finished draft report to the IS at the - 1 -