Draft Recommendations from the August 14, 2003, Blackout … Highlights and Minutes DL/2005/It… · Enhance Standards for Rating Transmission Lines .....15 12. Improve and Validate

Draft Recommendations from the

August 14, 2003, Blackout Technical Report on Modeling, Dynamics, and Generation and

Transmission Performance

March 2, 2005

Prepared by the Blackout Investigation Team

of the North American Electric Reliability Council

Agenda Item 7

Table of Contents

i

Table of Contents

INTRODUCTION............................................................................................................. 1

EXISTING RECOMMENDATIONS ................................................................................. 2 1. Evaluate Relay Loadability Issues (Zone 3) and Implement Mitigation Measures.....................................2 2. Establish Guidelines on the Use of Remote Back-Up Protection Systems in EHV Networks ....................3 3. Modify the Interchange Distribution Calculator (IDC) to Increase Operational Awareness of the

Causes of Circuit Loading................................................................................................................................4 4. Improve Powerflow Modeling Techniques and Correct Discrepancies .......................................................5 5. Strengthen Standards on Tagging of Dynamic Schedules and Pseudo Ties ................................................6 6. Improve System Data Exchange to Update IDC and Other Reliability Analysis Systems.........................7 7. Evaluate and Implement Under-Voltage Load Shedding (UVLS) In Areas Susceptible to Voltage

Collapse..............................................................................................................................................................9

STRENGTHENED RECOMMENDATIONS .................................................................. 11 8. Evaluate and Strengthen Under-Frequency Load Shedding (UFLS) Standards to Enhance

Performance Under Severe System Conditions............................................................................................11 9. Clarify Generation Data Exchange Requirements and Evaluate Generator Protection to Ensure

Coordination with Transmission System Protection Functions..................................................................12 10. Standardize Disturbance Data Recorder Systems .......................................................................................14 11. Enhance Standards for Rating Transmission Lines ....................................................................................15 12. Improve and Validate Dynamic Models .......................................................................................................18 13. Improve Transactional Analysis and Generation Dispatch in Regional and Interregional Studies........20 14. Establish and Implement Mapping Requirements for Disturbance Analysis ...........................................20

NEW RECOMMENDATIONS ....................................................................................... 22 15. Establish EMS and SCADA Time Synchronization Standards..................................................................22 16. Evaluate and Implement “Defense in Depth” System Monitoring, Control, and Protection Measures to

Slow Down and Mitigate the Severity of Cascades ......................................................................................23 17. Review the Response of Switch-on-to-Fault Relay Functions to System Disturbances ............................24 18. Revise Industry Standards to Establish Under/Over Frequency Design Limits of Operation for

Distance Relays ...............................................................................................................................................24 19. Evaluate and Report on the Performance and Complexity of Protection and Control Schemes for

Three Terminal Lines .....................................................................................................................................25 20. Establish Guidelines on High Speed Reclosing.............................................................................................26 21. Require the Installation of Underfrequency Protection for Generators and Coordination with UFLS .26 22. Evaluate and Implement Coordination Requirements for Generator Backup Protection Responses in

Cohesive Generation Groups .........................................................................................................................27 23. Establish Regime for More In-Depth Analysis in Transmission Reliability Studies.................................28 24. Continue What If Analyses, Promote Research Based on the Blackout, and Preserve Forensic Analysis

Techniques.......................................................................................................................................................30

RELATED NERC AND U.S.-CANADA TASK FORCE RECOMMENDATIONS ............A NERC Recommendation 8 — Improve System Protection to Slow or Limit the Spread of Future Cascading

Outages .............................................................................................................................................................A NERC Recommendation 10 — Establish Guidelines for Real-Time Operating Tools.........................................B NERC Recommendation 12 — Install Additional Time-Synchronized Recording Devices as Needed ..............B NERC Recommendation 14 — Improve System Modeling Data and Data Exchange Practices.........................B U.S.–Canada Recommendation 11 — Establish Requirements for Collection and Reporting of Data Needed

for Post-Blackout Analyses .............................................................................................................................B

Table of Contents

ii

U.S–Canada Task Force Recommendation 14 — Establish a Standing Framework for the Conduct of Future Blackout and Disturbance Investigations ......................................................................................................B

U.S.–Canada Recommendation 21 — Make More Effective and Wider Use of System Protection Measures ..C U.S.–Canada Recommendation 22 — Evaluate and Adopt Better Real-Time Tools for Operators and

Reliability Coordinators..................................................................................................................................C U.S.–Canada Recommendation 24 — Improve Quality of System Modeling Data and Data Exchange

Practices............................................................................................................................................................C U.S.–Canada Recommendation 28 — Require Use of Time-Synchronized Data Recorders ...............................C U.S.–Canada Recommendation 30 — Clarify Criteria for Identification of Operationally Critical Facilities,

and Improve Dissemination of Updated Information on Unplanned Outages...........................................D

Introduction

1

Introduction The following is a summary of the technical recommendations (TR-1 through TR-24) contained in the Technical Report on Modeling, Dynamics, and Performance of Generation and Transmission Systems. Some of these recommendations were the detailed technical basis of the recommendations of NERC in the August 14, 2003 Blackout: NERC Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts, dated February 10, 2004, and the U.S.-Canada Power System Outage Task Force Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations, dated April 2004. The observations and discussion in this report document the intent and purpose of those recommendations. Other of these recommendations are expansions of the NERC and U.S.–Canada Task Force recommendations with more specificity, based on results of additional analysis. Still others are new recommendations based on detailed analysis of system dynamics and protective relaying systems. For convenience, all related NERC or U.S.-Canada Task Force recommendations are listed in Appendix A.

Existing Recommendations

2


1. Evaluate Relay Loadability Issues (Zone 3) and Implement Mitigation Measures

Observation The Sammis – Star 345 kV line tripped by zone 3 relay operation while loaded at about 120% of its emergency MVA rating. Similarly, it was determined that a total of 18 transmission lines tripped via zone 3 operation or by over-reaching distance relays. It is thought that a number of those trips tended to accelerate the cascade. Discussion The recommendation for mitigation of zone 3 relays operating under load is contained within NERC Recommendation 8a, Improve System Protection to Slow or Limit the Spread of Future Cascading Outages, and U.S–Canada Task Force Recommendation 21a, Make more effective and wider use of system protection measures. Recommendation TR–1 NERC Recommendation 8a All transmission owners shall, no later than September 30, 2004, evaluate the zone 3 relay settings on all transmission lines operating at 230 kV and above for the purpose of verifying that each zone 3 relay is not set to trip on load under extreme emergency conditions1. In each case that a zone 3 relay is set so as to trip on load under extreme conditions, the transmission operator shall reset, upgrade, replace, or otherwise mitigate the overreach of those relays as soon as possible and on a priority basis, but no later than December 31, 2005. Upon completing analysis of its application of zone 3 relays, each transmission owner may no later than December 31, 2004 submit justification to NERC for applying zone 3 relays outside of these recommended parameters. The Planning Committee shall review such exceptions to ensure they do not increase the risk of widening a cascading failure of the power system.

U.S.–Canada Recommendation 21a Task Force: Recommends that NERC broaden the review to include operationally significant 115 kV and 138 kV lines, e.g., lines that are part of monitored flowgates or interfaces. Transmission owners should also look for zone 2 relays set to operate like zone 3s.

1 The NERC investigation team recommends that the zone 3 relay, if used, should not operate at or below 150% of the emergency ampere rating of a line, assuming a .85 per unit voltage and a line phase angle of 30 degrees. The SPCTF later clarified the definition of emergency ampere rating — Emergency Ampere Rating — “The highest seasonal ampere circuit rating (that most closely approximates a 4-hour rating) that must be accommodated by relay settings to prevent incursion.” That rating will typically be the winter short-term (four-hour) emergency rating of the line and series elements. The line rating should be determined by the lowest ampere rated device in the line (conductor, airswitch, breaker, wavetrap, series transformer, series capacitors, reactors, etc) or by the sag design limit of the transmission line for the selected conditions. The evaluation of all Zone 3 relays should use whatever ampere rating currently used that most closely approximates a 4-hour rating.


3

2. Establish Guidelines on the Use of Remote Back-Up Protection Systems in EHV Networks

Observation The August 14, 2003 blackout report documents a number of trip operations of EHV transmission lines initiated by zone 3 phase relays responding to system power flows rather than transmission line faults. The function of the Zone 3 relay in these applications was generally for remote backup protection in addition to line protection. Discussion Remote backup protection is used to isolate power system faults not cleared within a defined zone of protection, such as a transmission line fault or a transformer internal fault. Often remote backup protection is used to detect and clear faults as a result of a circuit breaker or relay that has failed to protect its defined zone. Therefore, it is usually time delayed one second or more to allow the primary protection to operate. Remote backup protection, most often impedance measuring relays, must actuate even in the presence of all other fault current infeeds to the point of fault. Other fault current infeeds cause remote backup relays to measure higher impedance often called apparent impedance. As EHV networks become more tightly meshed, apparent impedance infeeds have required more sensitive settings be used in remote backup protection to detect faults. That results in increased responsiveness to operation due to power flow. Concerns over long clearing times causing generator instability have also rendered remote backup less effective. To protect the power system from contingencies such as breaker failure and relay failure on the EHV system, transmission owner/operators are turning toward dual high-speed relay protection, transfer trip, and local breaker backup in place of remote backup protection. Redundant relays, separate DC control circuits, dual communication channels, dual current transformer inputs, and separate voltage transformer inputs are all part of dual high speed relay protection systems, providing improved redundancy.

Related Recommendations The review of use of remote back-up protection systems in EHV networks was assigned to the System Protection and Control Task Force (SPCTF) by the Planning Committee and is related to NERC Recommendation 8a, Improve System Protection to Slow or Limit the Spread of Future Cascading Outages, and U.S–Canada Task Force Recommendation 21a, Make More Effective and Wider Use of System Protection Measures. Both recommendations are in Appendix A. Recommendation TR–2 TR-2a. NERC should review the pros and cons of using remote backup protection on EHV

lines, and provide guidelines when this protection function should be replaced with local backup protection and transfer trip, or other alternatives that do not respond to power flow during extreme contingency conditions such as load tolerant digital relays. This task should include the level of protection redundancy necessary when replacing the remote backup function. NOTE: This work has been underway by the SPCTF and is nearing completion at the time of this writing.

TR-2b. NERC should expand the scope of this work to include not only planning criteria, but also operating criteria to ensure stability under routine operational conditions.


4

3. Modify the Interchange Distribution Calculator (IDC) to Increase Operational Awareness of the Causes of Circuit Loading

Observations Early claims of heavy transactions across the Eastern Interconnection being causal in overloads were proven to be false. However, the heavy transactions were definitely in the mindset of the system operators and reliability coordinators on August 14. Therefore, the initial reaction was to call for a TLR on the lines that were overloading. The IDC studies showed that the entire impact of all transactions in the Eastern Interconnection had minimal impact on the lines being overloaded in northeast Ohio. Discussion The studies performed with the IDC on transactional impacts during the outages point out a need for increased operational awareness of the causes for loading on any given transmission system element. AEP system operators contacted their reliability coordinator (PJM) to initiate a TLR 3 on the South Canton – Star 345 kV line. Had the operators been aware that imports into the Cleveland/ Akron load centers were the primary cause of the heavy loadings, not inter area transactions, they would have understood that load shedding and redispatch would be the required and more expedient solution to relieve the overloads. Slight modifications can be made to the IDC to provide the requestor with immediate information on transactional versus load serving contributions to loading on the system elements requiring relief. That information could be provided graphically or in tabular form, but should include a breakdown by transmission service priorities to provide the TLR requestor with as much information as is practical. The following are some examples of displays that could be quickly implemented on the IDC before summer 2004.

Examples of Potential Transactional Awareness Displays for the IDC

Related Recommendations This recommended improvement to operational awareness is one of the operational tools generalized under NERC Recommendation 10, Establish Guidelines for Real-Time Operating Tools, NERC Recommendation 14, Improve System Modeling Data and Data Exchange

Relief MW

NON-FIRM

Relief available on Sammis–Star 345 kV for loss of South Canton–Star 345 kV3% cutoff for curtailment and redispatch

9501000

350300

450400

600

500

650

50

150100

200250

0

550

700750800850900

FIRM NNL

Available relief @ 15:15 EDTloss of Chamberlin-Harding 345 kV

Available relief @ 15:00 EDT

Available relief @ 15:35 EDTloss of Hanna-Juniper 345 kV

Available relief @ 15:45 EDTloss of South Canton-Star 345 kV

Prepared for NERC. Copyright © 2003 Open Access Technology International, Inc.

Relief MW

NON-FIRM

Relief available on Sammis–Star 345 kV for loss of South Canton–Star 345 kV3% cutoff for curtailment and redispatch

9501000

350300

450400

600

500

650

50

150100

200250

0

550

700750800850900950

1000

350300

450400

600

500

650

50

150100

200250

0

550

700750800850900

FIRM NNL

Available relief @ 15:15 EDTloss of Chamberlin-Harding 345 kVAvailable relief @ 15:15 EDTloss of Chamberlin-Harding 345 kV

Available relief @ 15:00 EDTAvailable relief @ 15:00 EDT

Available relief @ 15:35 EDTloss of Hanna-Juniper 345 kVAvailable relief @ 15:35 EDTloss of Hanna-Juniper 345 kV

Available relief @ 15:45 EDTloss of South Canton-Star 345 kVAvailable relief @ 15:45 EDTloss of South Canton-Star 345 kV


MW Contribution

Priority0

NX1

NS2

NH3

ND5

NM4

NW7 F

Contribution with impact ? 3%

Contribution with impact ? 0%

6 NN

Contribution on South Canton–Star 345 kV for loss of Hanna-Juniper 345 kV

19002000

700600

900800

1200

1000

1300

100

300200

400500

0

1100

14001500160017001800

NNL

Contribution with impact ? 5% (TLR)


MW Contribution

Priority0

NX1

NS2

NH3

ND5

NM4

NW7 F

Contribution with impact ? 3%Contribution with impact ? 3%

Contribution with impact ? 0%Contribution with impact ? 0%

6 NN

Contribution on South Canton–Star 345 kV for loss of Hanna-Juniper 345 kV

19002000

700600

900800

1200

1000

1300

100

300200

400500

0

1100

1400150016001700180019002000

700600

900800

1200

1000

1300

100

300200

400500

0

1100

14001500160017001800

NNL

Contribution with impact ? 5% (TLR)



5

Practices, and U.S–Canada Task Force Recommendation 22a, Evaluate and Adopt Better Real-Time Tools for Operators and Reliability Coordinators. All three recommendations are in Appendix A. Recommendation TR–3 TR-3. Modify the IDC to include an immediate information on transactional versus load

serving contributions to loading on the system elements requiring relief. This information may be presented graphically or in tabular form. This change should be implemented in the IDC prior to summer 2004. NOTE: This capability was added to the IDC prior to summer 2004.

4. Improve Powerflow Modeling Techniques and Correct Discrepancies

Observation In creating the powerflow models for the post outage analyses, a number of modeling discrepancies were found in the base case. The MEN and VEM study committees had used that case in performing their 2003 pre-seasonal interregional transmission studies. Discrepancies in load level and dispatch were expected because the case had been originally built as a peak load summer case. However, the System Modeling and Simulation Analysis Team found a number of other discrepancies:

• Line Ratings — A number of line ratings had to be changed to match those in use on August 14. Additionally, as discussed in the facilities rating recommendation of this report, there were discrepancies between ratings in the case and those in use by some control areas and reliability coordinators.

• Topology errors — Some duplicate lines were discovered and topology errors that hinder powerflow solution (not fatal) were found that had originally surfaced in previous base cases dating back to 1991.

• Power factor — reactive power loads in the Cleveland / Akron had to be significantly increased to match reactive flows, voltage profiles, etc. even though the load level on August 14 was below the projected. Similar optimism was found by PJM in their modeling following their 1999 voltage problems.

• Generator reactive limits — reactive limits for generators contained in the powerflow base case have never been tested.

Discussion The MMWG base case creation process perpetuates topology errors because it lacks a feedback to the originators of the modeling errors. MMWG at one time had proposed a powerflow creation database, but the Planning Committee did not approve it. Advances in database technology, computers, and data exchange protocols, such as the Common Information Model (CIM), may now make such a database feasible and appropriate. The power factor in the base case was overly optimistic. Similar optimism was found by PJM in their modeling following their 1999 voltage problems. Part of the problem rests in the modeling of shunt capacitors at lower voltage levels and their impacts. This is suspected to be a systemic


6

problem with most regional and interregional base cases. Periodic benchmarking to actual system readings or state estimators at a number of different load levels would help to correct this situation. CIM capabilities of new state estimators may help facilitate this activity and make it feasible. Following the western blackouts of 1996 and the voltage problems in PJM in 1999, over estimation of generator reactive capabilities were found to be pervasive. WECC (then WSCC) instituted mandatory testing of generator reactive capabilities, voltage regulators, and power system stabilizers. PJM is pursuing testing of generators to ensure they are capable of performing to their reactive ratings. Similarly, actual availability of shunt capacitors may not match the reactive capabilities modeled in the powerflow cases. Also, reactive capabilities and contractual obligations to supply reactive power may or may not be modeled correctly. Universal testing requirements and verification of reactive capability should be instituted to correct this ongoing modeling problem that can result in serious operational consequences.

Related Recommendations These recommendations to modeling improvements were generalized under NERC Recommendation 14, Improve System Modeling Data and Data Exchange Practices, and U.S–Canada Task Force Recommendation 24, Improve Quality of System Modeling Data and Data Exchange Practices. Both recommendations are in Appendix A. Recommendation TR–4 TR-4a. The MMWG should reinvestigate the feasibility of a powerflow creation database that

is CIM capable. This would help eliminate ongoing topology modeling problems, including consistency in equipment ratings, impedance, and connectivity.

TR-4b. NERC should create an initiative to improve overall powerflow modeling techniques. Education of transmission modelers on the effects of bad modeling on powerflow and state estimation solutions would help eliminate modeling that adversely impacts program solutions.

TR-4c. Powerflow cases should be periodically benchmarked to actual system conditions at various load levels. Use of state estimator readings should be linked with CIM capability to a more rigorous base case creation process including a topology database.

TR-4d. All generators should be periodically tested to ensure that their claimed MW and Mvar ratings are accurate and realizable. Testing should also be done to confirm the performance of generator dynamic controls and that their respective models in the MMWG System Dynamics Database are accurate.

5. Strengthen Standards on Tagging of Dynamic Schedules and Pseudo Ties

Observation Analysis conducted of the Eastern Interconnection tags for August 14 highlighted an ongoing discrepancy between the total interchange transactions between control areas and the electronic tags. A tag audit was conducted by NERC in conjunction with an Area Interchange Error (AIE) survey for a number of hours on August 14. That tag audit showed large discrepancies caused mostly by capacity transactions related to jointly-owned generating units and remotely metered


7

control area loads. For 15:00 EDT, the discrepancy for FirstEnergy imports was over 2,400 MW of untagged transactions for their shares of Beaver Valley nuclear plant and Seneca pumped storage plant. Discussion Such large discrepancies create errors in system security analyses of other system operators’ state estimators, and errors in the IDC solutions for TLR.

Related Recommendations This recommendations on tagging improvements was generalized under NERC Recommendation 10, Establish Guidelines for Real-Time Operating Tools, NERC Recommendation 14, Improve System Modeling Data and Data Exchange Practices, and U.S–Canada Task Force Recommendation 24, Improve Quality of System Modeling Data and Data Exchange Practices. All three recommendations are in Appendix A. Recommendation TR–5 TR-5. The standards for tagging of dynamic schedules and pseudo ties should be

strengthened to ensure that complete information is available to other operating entities for reliability analyses. Note: The Interchange Subcommittee is already working on this recommendation.

6. Improve System Data Exchange to Update IDC and Other Reliability Analysis Systems

Observation The failure of timely and accurate exchange of operational data concerning generation and transmission facility outages played an important role in the blackout of August 14. The MISO state estimator did not yet have a number of facilities that tripped during the course of the day mapped into its topology processor. Consequently, when the Stuart – Atlanta 345 kV line tripped, MISO’s state estimator failed to converge. Further, their flowgate monitoring tools were dependent on the System Data Exchange (SDX) system operated by NERC, which was not updated with those outages in a timely manner. Further, during the post-mortem modeling process, it was discovered that the SDX had a number of errors in it – generators that were on line listed as off, omissions of lines and generators that were out of service, etc. – and where lines such as Stuart – Atlanta were in the database, when they were entered was indeterminate. NOTE: MISO has since changed to using ICCP data exclusively for their state estimator. Discussion Developed in 1998, the SDX was never originally intended to be a real-time tool, but a method of keeping the topology up to date for the IDC and ATC calculations. The data consisted of control area peak loads, reserves, generation outages, transmission outages for the next seven days, following four weeks, and succeeding eleven months. Nine reliability authorities in the Eastern Interconnection use the SDX for collecting outage data from their members to perform day-ahead security analysis. A number of transmission providers use SDX in their topology determination for calculating ATCs. To keep pace with automation of processes by control areas and transmission providers, the SDX system was upgraded in May 2003 to accept automated data file submittals, perform error


8

checking, and automatically update the IDC. The reliability coordinator procedures indicate that the SDX should be updated at least daily. However, the new system is fully capable of multiple updates per hour. In fact, the planned PJM/MISO congestion management implementation plan calls for frequent updates (up to every five minutes) to keep the IDC topology in lock step with their locational marginal pricing calculator. Doing so will enable PJM and MISO to separately calculate their impacts on system loading in parallel to the IDC, and allow the concept of superposition to be applied in reaching TLR solutions for managing overloads. Thus, the SDX has been moving toward becoming a more real-time application.

Related Recommendations These recommendations on improved SDX operation were generalized under NERC Recommendation 10, Establish Guidelines for Real-Time Operating Tools, NERC Recommendation 14, Improve System Modeling Data and Data Exchange Practices, U.S–Canada Task Force Recommendations 22a, Evaluate And Adopt Better Real-Time Tools For Operators And Reliability Coordinators, and U.S.–Canada Recommendation 30 — Clarify Criteria for Identification of Operationally Critical Facilities, and Improve Dissemination of Updated Information on Unplanned Outages. All of these recommendations are in Appendix A. Recommendation TR–6 TR-6a. Require more timely updates to the SDX. Ideally, this process should be automated

with topology processors detecting a transmission or generation outage, initiating an update to the SDX. Practically, NERC should modify the reliability coordinator procedures to require manual update to SDX within a reasonable time (10−15 minutes) for forced outages, until more automated process can be implemented. NOTE: the reliability coordinators have already completed this recommendation,

TR-6b. Move to hourly updates of SDX data. To improve the overall quality of the data exchanges for ATC calculation and security analysis in the Eastern Interconnection, NERC should modify the procedures to require hourly updates of all other SDX data. NOTE: the reliability coordinators have already completed this recommendation,

TR-6c. Add date/time stamps to SDX data records. NERC should add a time synchronized date/time stamp to SDX data records when they are received, modified, or terminated. This will add an additional level of quality control to the data and aid in compliance monitoring.

TR-6d. Foster use of real-time ICCP level data exchange between control areas, reliability coordinators and transmission operators. Real-time data exchange with interfaces to topology processors is appropriate to expand the observability of real-time operations systems and personnel. However, it is important to provide those operators with processed information, not just raw data. NOTE: MISO has since changed to using ICCP data exclusively for their state estimator.


9

7. Evaluate and Implement Under-Voltage Load Shedding (UVLS) In Areas Susceptible to Voltage Collapse

Observation Throughout the first hour of the blackout events, voltages became severely depressed in parts of northeast Ohio as the 138 kV and 345 kV systems slowly cascaded. Later in the sequence of events, severe voltage depression in eastern Michigan ultimately resulted in that entire area loosing synchronism with the rest of the Interconnection. Discussion In the earlier stages of the cascade, powerflow analysis showed that judicious load shedding could have arrested, or at least slowed, the progress of the cascade. Analysis showed that shedding 1,000 MW of load in the Cleveland / Akron area after loss of the Hanna – Juniper 345 kV line (15:32 EDT) but before the loss of the South Canton − Star 345 kV line (15:41 EDT) would have greatly reduced the loading on the South Canton – Star line. The East Lima – Fostoria Central 345 kV line tripped by zone 3 action in response to an overload that could have been prevented by judicious application of UVLS in the Cleveland and Akron areas. As the cascade accelerated, pockets of low voltage characterized the system. System modeling showed that had sufficient UVLS been implemented in the Cleveland / Akron area prior to the loss of the Sammis – Star 345 kV line, the cascade might have been limited to a local area event. Also, there were several minutes after that event where voltages were severely depressed throughout northeast Ohio, where UVLS could have slowed or arrested the cascade. Similarly, after the loss of the East Lima – Fostoria Central 345 kV line, a second “defense in depth” opportunity to shed load under low voltages presented itself in order to slow the cascade. Per Recommendation 8b of the August 14, 2003 Blackout: NERC Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts dated February 10, 2004. The importance of automatic control and protection systems in preventing, slowing, or mitigating the impact of a large-scale outage cannot be stressed enough. It is not practical to expect operators will always be able to analyze a massive, complex system failure and to take the appropriate corrective actions in a matter of a few minutes. The NERC investigators believe that selective use of under-voltage load shedding would have been crucial in slowing or stopping the uncontrolled cascade on August 14. The bulk power system must be analyzed on a wide area basis to effectively understand the interaction of all of the system elements, and to determine the parts of the system that are susceptible to voltage collapse. Such studies must not only consider local import transfers, but also through-transfer implications. Once the critical voltages are determined for transmission switching stations, fast-acting (4-5 second) UVLS can be applied at that station or on lower voltage stations fed from it. This would protect that station from going into a local voltage collapse. This also would minimize motor stalls resulting in high inrush currents, and minimize inadvertent operation of distance relays due to low voltage. When such a philosophy is applied on a system-wide basis, the result is a naturally tiered protection system capable of arresting and localizing potential cascades. Fast-acting (4-5 second) UVLS systems are effective for contingency-based voltage collapse. However, the UVLS system must also protect against slow-speed voltage degradation on the transmission system. Under those situations, local sensing is ineffective because the lower


10

voltage system’s voltage controls and LTC action are still keeping those local voltages healthy. In such cases, detection of the slow-speed degradation must be done on the transmission system, and action must be taken based on those observations. Such system could involve the use of SCADA systems, system operator action, or, potentially, direct transfer trip functions. Note that UVLS systems are best applied on a local basis, and are most effective in areas that are susceptible to voltage collapse. However, some levels of UVLS may be appropriately applied as part of a backstop system to minimize inadvertent operation of distance relays due to low voltage.

Related Recommendations This recommendation on UVLS was generalized under NERC Recommendation 8b, Improve System Protection to Slow or Limit the Spread of Future Cascading Outages, and U.S–Canada Task Force Recommendations 21b, Make More Effective and Wider Use of System Protection Measures. Both recommendations are in Appendix A. Recommendation TR–7 TR-7. Evaluate all areas of the system to determine areas susceptible to voltage collapse, and

implement UVLS in those areas. NOTE: FirstEnergy has designed and is deploying a UVLS system for the Cleveland / Akron area.

Strengthened Recommendations

11


8. Evaluate and Strengthen Under-Frequency Load Shedding (UFLS) Standards to Enhance Performance Under Severe System Conditions

Observations Underfrequency load shedding is a system protection method that tries to bring generation and load into balance after electrical islands are formed. Several electrical islands were formed as a prelude to the blackout in Ontario, New York, Cleveland, southeast Michigan, and Detroit that did not return to a generation-to-load balance. Failure of those islands to regain balance was caused by many things. Among them were:

• Generation underfrequency protection and generator under/over speed controls tripped units before UFLS systems could arrest the frequency decline.

• Some UFLS relays were constrained from operating due to severe undervoltage, below their undervoltage supervision settings.

• Some UFLS relay time delay settings were too long to expediently arrest the frequency decline.

• Location of load targeted by UFLS systems in relation to generation locations. Discussion During the cascade, a number of UFLS systems misoperated due to low voltage conditions, proved to be uncoordinated with generator protection systems, or were inadequate to arrest load-generation imbalance in the islands that were formed. UFLS systems need to be constantly reviewed and examined to ensure that they keep pace with system growth. Further, whenever generation and transmission system additions are made, UFLS and UVLS systems need to be reviewed to determine the impact of the system addition on the effectiveness of those systems.

Related Recommendations This recommendation on UFLS review and coordination was only lightly mentioned in the background material (not in the recommendation itself) under NERC Recommendation 8b, Improve System Protection to Slow or Limit the Spread of Future Cascading Outages, and U.S–Canada Task Force Recommendations 21b, Make More Effective and Wider Use of System Protection Measures. Both recommendations are in Appendix A.


12

Recommendation TR–8 TR-8a. NERC and the Regions should conduct a comprehensive review of the underfrequency

load shedding protection system similar to that performed by WECC2 after their 1996 blackout, including: • Impact of varying island boundaries • Impact of dynamic conditions and sequential line trips during island formation on

UFLS performance • The need to coordinate with generator design, protection, and control systems • Over Frequency — the number, size, and frequency of generation trips and load

reinsertion • Under Frequency — the number, size, and frequency of load trip points • Coordination with UVLS systems to ensure proper operation under severe voltage

conditions • Coordination of UFLS systems between and among Regions and reliability

authorities/coordinators TR-8b. Standards should be set for generation design, controls, and protection systems

concerning tolerance of the full range of over and under frequencies specified as part of the UFLS programs.

9. Clarify Generation Data Exchange Requirements and Evaluate Generator Protection to Ensure Coordination with Transmission System Protection Functions

Observations Through out the data collection phase of the blackout investigation, when control areas were asked for information pertaining to all generation within their area, some data was frequently not supplied. Often the reason given was that the control area didn’t know the status or output of some independent generators at any given point in time. Another reason was the commercial 2 · The August 10, 1996 Disturbance Report recommended that the WECC underfrequency program be reviewed and revised to provide better coordination and performance within the main islands formed by the “Controlled Islanding Scheme” in WECC. A task force was formed to do the studies and make the recommendations. A couple of problems stemming from the August 10th disturbance were frequency stalling in PG&E’s system and a lack of coordination between generators tripping on underfrequency and load tripping by underfrequency load shedding. Several studies were done to simulate major loss of generation within the WECC region and a scenario that simulated controlled islanding (i.e., a triple line outage of the California – Oregon Intertie). After months of study the following recommendations were made:

• Trip load in five major blocks starting at 59.1 in .2 cycle decrements for a total of approximately 31% • Trip a small amount of load at 59.3 and 59.5 to prevent frequency stalling • Restore a small amount of load at 60.5 to 60.9 to prevent overshoot • Require a minimum of 30 minutes time delay for automatic load restoration • Require generators to coordinate their underfrequency tripping with load shedding program • Recommends a minimum of 14 cycle time delay including relay and breaker time which depending on the

specific relay used would mean 8 to 10 cycle external time delay


13

sensitivity of such data and it may be contractually prohibited from disclosure. Neither reason is acceptable in post-outage analyses or in real-time operations. Similarly, a number of common situations repeated themselves throughout the initial phase of generation protection performance analysis.

• Many generation owners/operators failed to report or inadequately reported the reason why their generators tripped.

• Many causes of generator trips appeared to be the result of miscoordination with the transmission system relays.

• Generator unit trip times were often inconsistently reported — confusion existed between trip times of the prime mover, turbine, and generator circuit breaker.

Discussion Control areas (balancing authorities) have a responsibility to have knowledge of and be in control of (thus the name control area) all generation in their area. Conversely, all generation must be in a control area. If the merchant plant operates its own control area, obviously the data reporting questions and responsibility falls to their own control area function. In the first 3 minutes following the trip of the Sammis – Star 345 kV line, four generators tripped by undervoltage relaying. Other examples that raised relay setting coordination concerns with transmission system relays are the undervoltage settings at Sumpter and the overcurrent settings at MCV. In many cases generator relaying responded before transmission system protective elements could have responded. Generator must be protected from system-initiated hazards, but with the proper coordination. As the industry has disaggregated, there has been a loss of accountability for the assurance of overall system coordination. There is no present obvious owner of this coordination responsibility. The Armstrong and Kinder Morgan generating units were reported to have tripped by excitation protection. Theoretically, excitation controls should perform the function of controlling rather than reliance on protective devices to perform control functions.

Related Recommendations This recommendation on generation protection coordination was only lightly mentioned in the background material (not in the recommendation itself) under NERC Recommendation 8b, Improve System Protection to Slow or Limit the Spread of Future Cascading Outages, and U.S.–Canada Task Force Recommendations 21b, Make More Effective and Wider Use of System Protection Measures. The generation data exchange requirements for modeling purposes relate to NERC Recommendation 14, Improve System Modeling Data and Data Exchange Practices, and U.S.–Canada Recommendation 24, Improve Quality of System Modeling Data and Data Exchange Practices. Post disturbance data collection is addressed in U.S.-Canada Task Force Recommendation 11, Establish Requirements for Collection and Reporting of Data Needed for Post-Blackout Analyses. All of these recommendations are in Appendix A.


14

Recommendation TR–9 TR-9a. Operational and planning data reporting requirements should be more clearly defined

in NERC standards for all generation and load serving entities within control areas and balancing authorities.

TR-9b. All reliability authorities/coordinators shall be responsible for the coordination of generation control and protection systems with the control and protection systems of the transmission system. This responsibility includes approval of coordination at the time of generation unit attachments to the transmission system.

TR-9c. Excitation protection and controls systems should be also evaluated for all generators connected to the 100 kV systems and above to assure that the over-excitation and under-excitation control functions coordinate with the corresponding system protection functions such as maximum excitation limiters, loss-of-field relays, and volts/hertz relays.

TR-9d. Reliability authorities/coordinators shall evaluate the coordination of generation protection and control function with the transmission system protection and control functions for all generators 10 MW and above and report their finding to NERC by December 31, 2006. Those reports will be reviewed by the NERC SPCTF, which will, in turn, report the findings to the NERC technical committees. Such reviews will be conducted whenever there are generating unit additions, setting changes, or significant transmission system changes or additions (including changes to the transmission control and protection systems or settings).

TR-9e. Reliability authorities/coordinators shall also be responsible for reporting causes and times of generation trips during system disturbances. Generation owners/operators are obligated to report those data to the reliability authority/coordinator.

10. Standardize Disturbance Data Recorder Systems Observation The quality of disturbance data recordings available for analysis of events during the blackout varied widely from the sophisticated, GPS synchronized Power System Data Recorders (PSDRs) in Ontario, to old paper strip recorders. A significant number of the data recordings were not time synchronized, requiring man-months of analysis time to line up traces and place events in the correct time for analysis. Discussion Disturbance recorder information was received by NERC in various formats, and generally not time synchronized. This resulted in extended analysis time and interpretation uncertainties. One trace absent in most DFRs was system frequency. In some cases, frequency had to be synthesized from other data from the DFRs (voltage traces). Fault recorder data ranged from old mechanical strip charts to state-of-the art long-period digital fault or event recorders (DFRs or DERs) that were synchronized to the National Institute of Standards and Technology (NIST). Many DFRs only recorded for a few seconds and may or may not have been triggered by any particular event, depending on its proximity to the recorder.


15

Related Recommendations This recommendation is partially the basis of NERC Recommendation 12a and b, Install Additional Time-Synchronized Recording Devices as Needed, and U.S.–Canada Task Force Recommendation 28, Require Use of Time-Synchronized Data Recorders. Both recommendations are in Appendix A. Recommendation TR–10 TR-10. NERC’s technical committees work with its regions and disturbance recorder software

and hardware manufacturers to provide a disturbance data recording system that will function reliably when large-scale disturbances occur.

Attributes of this product and process should be: • All relay, digital fault recorders, digital event recorders, power system disturbance

recorders, etc. should be time stamped at the point of observation with GPS time synchronization equipment

• All DFRs should include a frequency trace • All high-speed recording devices should be periodically checked for calibration

and operability • All files should be provided in IEEE/ANSI Comtrade standard C37.111-1999

format • File names should adopt the IEEE common naming convention • It is recommended that a digital readout of frequency be a requirement to the

Comtrade standard upon revision • The disturbance data recording system should facilitate data storage and archiving

capabilities

11. Enhance Standards for Rating Transmission Lines Observation A significant number of transmission lines tripped during the blackout well below their emergency MVA ratings. This called into question how those ratings were established and maintained. Also, a number of disagreements also existed in line ratings being used by the control areas and reliability coordinators. The following are two examples of line rating disagreements that point to a need for some method of uniform line rating methodology, and some way of ensuring universal application of those ratings in planning and operations. That is not to say that all assumptions of physical parameter (wind speed, temperature, etc.) are universal, but some checks against reasonable values are appropriate.

Sammis – Star 345 kV Line The rating on the Sammis – Star 345 kV line came into question during the investigation. First Energy was operating to a rating of 1,310 MVA for both summer normal and emergency ratings on August 14. This rating was established in May 2003. However, MISO was using ratings of 950 MVA normal and 1,076 MVA emergency. MISO had inherited these ratings from AEP which, up until May 2003 had been the Reliability Coordinator for First Energy. AEP still had the 950/1,076 MVA ratings in it state


16

estimator. Similarly, PJM was relying on AEP for its state estimation of that part of the system, therefore was effectively using the 950/1,076 MVA ratings. Further confusing this issue, the Sammis – Star 345 kV rating in the MEN 2003 summer base case used for pre-seasonal analysis was for a much higher 1,397 MVA normal and 1,554 MVA. The ECAR Transmission System Performance Panel also used this base case in their 2003 summer studies. These ratings discrepancies call into question the regional and interregional transfer limits determined by those studies. This disagreement in ratings, though not a factor during the outage itself, adds an unnecessary element of potential confusion between system planners, operators, regions, and the market. What is the correct rating for that line? Dale – West Canton 138 kV Line The rating on the Dale – West Canton 138 kV line came into question because it was 13% overloaded (above normal rating) in the 2003 MEN summer base case when adjusted to the conditions of August 14. This tie line between AEP and First Energy is officially rated at 185 MVA normal and 244 MVA as agreed to in the MMWG tie line database. That rating is based on a 500 kcm copper strain bus at the West Canton (AEP) end, but the emergency rating is a much higher 244 MVA. Its emergency rating is also listed as being able to be sustained for a 24-hour period. The conductor on the line is 605 ACSR with 24/7 stranding, capable of 235 MVA normal and 285 MVA emergency ratings, according to First Energy calculations. AEP’s state estimator noted the ongoing overload of the Dale – West Canton 138 kV line (over normal rating) and had it listed as an N-1 overload (above emergency rating) for loss of the Sammis – Star 345 kV line. The state estimator was using the strain bus rating of 185/245 MVA (1 MW higher on emergency). Because the 24-hour emergency rating was not being violated, there was no urgency to relieving the ongoing overload. The Dale – West Canton 138 kV line is important because it was the line that tripped immediately before the Sammis – Star 345 kV line that kicked off the higher speed portion of the blackout. That line tripped on zone 3 relay action. Contact with a blue spruce tree in Akron was listed as the cause of tripping on Dale – West Canton 138 kV. This is clearly an issue of the conductor sagging, not related to the strain bus conductor. Therefore, the modeling team used the conductor rating when graphing their study results. Richland – Ridgeville 138 kV Line The Richland – Ridgeville 138 kV line rating in the powerflow case was 120 MVA normal and 120 MVA emergency. In conducting the studies, it was discovered that that rating was based on a current transformer limit that had been alleviated since the case was created earlier in the year. The new ratings on the line are 153 MVA normal and 182 MVA emergency, based on bus leads. This change was recognized in the modeling analyses.

Discussion All entities should have the same ratings for a given transmission lines within their planning and operating databases. It is possible that an identical piece of equipment or conductor may have different ratings depending on transmission line design and the climate in which it operates.


17

Therefore, the line rating methods should be standardized for methods, with specific assumptions and design parameters subject to peer review. Some key points of commonality and review for transmission lines should be:

1. Ratings calculations should reference the same calculation standard with adherence to National Electric Safety Code clearance requirements or other applicable vegetation management standards.

2. Clearances should be inspected periodically as part of a peak load preparation plan. 3. Wind speeds used in the calculation should be geographically based with known

historical risk characteristics. 4. Line ratings should be calculated from “as built” rather than by “as designed” data.

Design records should be updated to reflect the “as built” configurations. Periodic inspection of clearances for the entire line should be conducted to ensure that there have been no clearance encroachments.

5. Limitations due to terminal equipment and relay loadability settings should be subject to peer review.

Related Recommendations These recommendations on circuit rating improvements was generalized under NERC Recommendation 14, Improve System Modeling Data and Data Exchange Practices, and U.S–Canada Task Force Recommendation 24, Improve Quality of System Modeling Data and Data Exchange Practices. Both recommendations are in Appendix A. Recommendation TR–11 TR-11a. NERC should enhance its Standard FAC-008-1 — Facility Ratings Methodology,

currently under development, to include periodic regional peer review of rating methodologies and assumptions.

TR-11b. NERC should enhance its standard on circuit rating methodology to include notification requirements for other operating entities. This recommendation is currently being implemented through the development of Standard FAC-009-1 — Establish and Communicate Facility Ratings. Each transmission owner/operator should also file their methodologies and assumptions with NERC.

TR-11c. NERC should develop a topology database for powerflow data for each interconnection. Any changes to line ratings would generate notifications to all powerflow case users throughout the interconnection.

TR-11d. NERC should periodically audit both the facility rating methodologies, assumptions, and the ratings themselves, for consistency and to ensure dissemination of correct ratings throughout the interconnection. Standard FAC-008-1 — Facility Ratings Methodology, and Standard FAC-009-1 — Establish and Communicate Facility Ratings, both include audit provisions.


18

12. Improve and Validate Dynamic Models Observations When a dynamics case was developed for the blackout investigation, it was discovered that a significant number of generator models had incorrect or, at least, questionable parameters. Some of the problems were uncovered during case initialization and testing, while others were not found until they manifested themselves well into the analysis, requiring re-running part of the analysis. Many of these errors do not show up in the testing of the powerflow cases, but prevent the dynamics case from solution.

• One family of exciter models was found to have an unstable step response. • Some units’ models were unstable due to bad data in the models.

Other information in the powerflow case that is required by the dynamics program was in error. Several adjustments were made to the powerflow case so that the dynamics simulation would initialize properly. Examples include:

• Generators dispatched beyond their real and reactive power limits • Incorrect machine MVA base values • Most small units do not have dynamics data in the MMWG case (generic generator data

was used for these units) The Major System Disturbance Task Force (MSDTF) experimented with a number of dynamic model modifications (generators, tap changers, and special protection systems) in order to mimic the measured behavior of the system. They also experimented with a number of different load models. Another issue arose from a lack of standardization of formats for powerflow and dynamics data between different programs, and, often, between different versions of a single program. Some companies use PTI’s PSS/E, while others use General Electric’s PSLF. The two file structures are not compatible and there are proprietary issues for special dynamics models that can’t be shared between the two programs. Similarly, between version 28 and version 29 of PSS/E, the program introduced new dialogue, data file format, and other program interface changes that rendered most of the user auxiliary tools useless. Discussion Dynamics analysis requires more detailed data for generator and other dynamic devices than is required for powerflow analysis. Problems like those uncovered in the dynamics case creation come from two sources, and are perpetuated in the Eastern Interconnection by the methods used for annual powerflow and dynamics case creation by the MMWG. There is currently no feedback loop to the originators of the models or data when problems are discovered. More importantly, the dynamics models contained in the MMWG cases for the Eastern Interconnection have never been validated against machine performance parameters that are observable under the stress of system disturbances. After the 1996 blackouts, WECC initiated a regime of generator testing and model validation using high-speed data recordings from system disturbances. In some cases, they even tripped generation to observe the response of other generators. This resulted in a significant improvement in the quality and accuracy of WECC dynamic models and cases.


19

The MSDTF fought the typical battle with load model representation in their forensic analysis. They ended up developing several new models to simulate phenomena not normally represented in standard dynamics program models. Additionally, MSDTF developed modifications to existing generator models to represent generator mechanical overspeed protection systems. Powerflow and dynamics data formats are a long-standing problem in the electric industry. Various powerflow vendors have introduced their own data formats for years, which they change at will with program versions to follow their own program enhancements. Whenever such format changes are made, backward compatibility is often a problem, and the user community must rewrite their own auxiliary tools necessary to work efficiently with the data. In the blackout investigation, the MSDTF members used PSS/E version 28 instead of the newer version 29 because of “burn in” issues with the new software and discrepancies in file format that would have caused them at least a month to make changes to their auxiliary toolset. Although PSS/E RAWD format has become a de facto standard format, it too is subject to change at the vendor’s discretion. A standardized file format should be developed by the industry to force vendors to gain industry consensus before file format changes can be made. Note: Although PTI has introduced version 30 of the PSS/E programs, MMWG is retaining the use of PSS/E version 29 for the 2005 series of powerflow and dynamics case development due to backward compatibility issues. File format discrepancies between PSS/E and PSLF hindered direct data transfers between FirstEnergy and the rest of MSDTF. A number of the special dynamics models used by the PSS/E community in MSDTF are considered proprietary by PTI and cannot be freely shared with PSLF users. This requires settling for translation to generic models for those very complex control systems (SVCs, HVDC converters, etc.), further hindering model sharing and, arguably, degrading the validity of the translated models.

Related Recommendations These recommendations on model improvements were very generalized under NERC Recommendation 14, Improve System Modeling Data and Data Exchange Practices, and U.S–Canada Task Force Recommendation 24, Improve Quality of System Modeling Data and Data Exchange Practices. Both recommendations are in Appendix A. Recommendation TR–12 TR-12a. NERC should create a feedback loop to the providers of the data in the powerflow and

dynamics case creation process for the MMWG. This would not only ensure data quality, but also foster better modeling practices by the generation and transmission system owners/operators. Use of a CIM compatible topology database should be investigated to ensure consistency.

TR-12b. NERC should initiate dynamic model validation regime of the generators and other dynamic responsive equipment in the Eastern Interconnection. This regime should use the WECC methods as a starting point.

TR-12c. NERC should partner with IEEE to codify a new standard for powerflow and dynamics data formats that would require agreement by the users in the industry for changes.

TR-12d. NERC should partner with IEEE and the industry to provide a forum for the ongoing development, testing, and validation of new and improved dynamic models.


20

TR-12e. NERC should partner with IEEE to improve the load modeling for more accurate powerflow and dynamics analysis. Whenever possible, benchmark load models to actual load response during system disturbances.

13. Improve Transactional Analysis and Generation Dispatch in Regional and Interregional Studies

Observation Regional and Interregional transmission studies typically are done using only firm transmission schedules to determine the transactions modeled in the powerflow base cases. No feedback loop exists from analyses of historical transactions in determining the levels and directions of transactions that should be studied. Also, a number of the interregional studies do not currently perform full simultaneous transfer analysis. Discussion Significant historical transaction information is available through the NERC tagging system to be analyzed and considered in determining base case transfers and the range of transfers that should be studied. Similarly, generation patterns could be monitored and collected as additional checks on powerflow case creation. NERC should develop an analysis regime to take advantage of that information for input to future planning and operational studies.

Related Recommendations These recommendations on transactional analysis and dispatch improvements was generalized under NERC Recommendation 14, Improve System Modeling Data and Data Exchange Practices, and U.S.–Canada Task Force Recommendation 24, Improve Quality of System Modeling Data and Data Exchange Practices. Both recommendations are in Appendix A. Recommendation TR–13 TR-13a. NERC should develop an ongoing analysis regime to provide regional and

interregional study groups with historical transaction trends as input to their studies and base case creation.

TR-13b. NERC should develop an ongoing analysis regime to provide regional and interregional study groups on generation dispatch patterns to ensure that planning and operational studies are closer to reality.

14. Establish and Implement Mapping Requirements for Disturbance Analysis

Observation The NERC Regions and transmission owners provided the maps used during the blackout investigation. Some were electronic while others were only available in hard copy. Some electronically provided maps used the bookmark feature of Adobe Acrobat to locate substations while others did not. In general, the maps were very cumbersome and time consuming to read.


21

Related Recommendations This recommendation on mapping requirements provides detail for and strengthens U.S.–Canada Task Force Recommendation 14, Establish a Standing Framework for the Conduct of Future Blackout and Disturbance Investigations. That recommendation is in Appendix A. Discussion Significant amounts of time were wasted in pursuit of adequate system maps and their interpretation. In times of emergency, the variety and varying levels of detail of system maps can hinder, rather than help, visualization by investigating entities such as regional councils, NERC, and government agencies. For future outage investigations, a standardized set of system maps should be made available to investigators. Recommendation TR–14 TR-14. NERC should specify a standard set of system maps to be maintained and supplied for

analysis of system disturbances. Maps should be regularly updated to reflect changes in system topology or generation facilities. Those maps should include: • Geographic representation of all voltage classes above 100 kV. Lower voltage

network maps should be available upon request. • Breaker level system switching diagrams, noting any normally open points. • Individual station switching diagrams, requested as necessary. • Keys for any transmission line or breaker number/nomenclature schemes that

match control room logs should be provided for the switching diagrams.

New Recommendations

22

New Recommendations

15. Establish EMS and SCADA Time Synchronization Standards Observation One of the biggest problems presenting itself to the blackout investigative team was the lack of time synchronization of the large amount of data that had to be analyzed. Because of the widespread nature of the outage, data from Ontario, New York, New England, the Maritimes, the Atlantic seaboard and the Midwest had to be collected an analyzed. Depending on the type of data being analyzed, it came with varying degrees of quality, periodicity, and synchronicity.

• Remote telemetry unit (RTU) data was generally time stamped when it came into the control center, or when the control center computer processed it. The data varied in scan rates from 2 seconds to 30 seconds.

• EMS and SCADA alarm logs and breaker actions were time stamped when the control center computer processed them.

• Some control center computers became overwhelmed with processing the myriad of alarms that resulted from the blackout, either completely failing, or skewing even their SCADA data by several seconds or, in some cases, minutes.

• Even the EMS computers were not necessarily time synchronized to NIST. Discussion These time skews made determining the sequence of events difficult even for the slower, non-dynamic portion of the blackout sequence. During the high-speed portions of the outage, events have to be sequenced down to the millisecond to properly analyze them. In the past, the best that could have been hoped for was local time synchronization of digital fault recorder (DFR) data for a local area. However, with today’s GPS technologies, it is possible to have data time stamped at its point of origin for digital recorders and by the local RTUs for SCADA systems. Every effort should be made to take advantage of today’s technology to accurately record and archive operational data for follow-on analysis. Recommendation TR–15 TR-15a. EMS hardware and software designs should be changed, over time, to accommodate

time stamps recorded by remote telemetry units (RTUs) at the substation. Each substation should have GPS synchronization capabilities for both RTUs and DMEs.

TR-15b. Additionally, all real-time data exchanged via ICCP data (volts, flow, frequency data, ACE) between operating entities should be similarly time stamped, and those time stamps should be included in all transmittals.

TR-15c. Data collection should be well monitored to detect equipment failures and data quality problems. All data transmitted via ICCP should include data quality flags.

TR-15d. Standards for data retention and archiving should be established for SCADA, ICCP, and disturbance event data.

New Recommendations

23

16. Evaluate and Implement “Defense in Depth” System Monitoring, Control, and Protection Measures to Slow Down and Mitigate the Severity of Cascades

Observation During the blackout, a number of generator control and protection systems, and transmission system controls and protections systems, including UFLS systems, interacted, not always to the betterment of the overall system health and resiliency. System monitoring, control, and protection systems are currently applied mostly on a transmission operator or control area basis. However, each Interconnection of the bulk power system is, in fact, a very large single system and should be analyzed, controlled, and operated as such. An overall defense in depth philosophy and integrated strategy is needed to protect today’s bulk power system from cascading blackouts. Such a system would have to integrate existing system monitoring, control, and protection systems with new measurement, analysis, and protection capabilities into the overall defense-in-depth strategy. All system elements have to be coordinated. Defense-in-depth should incorporate elements such as:

• Wide-area and local monitoring of system operating conditions • Wide-area, high-speed (phasor) measurements of overall system indicators such as

relative phase angles across the interconnection and across major transmission interfaces • Monitoring of inter-area, slow-speed oscillations • Priority based alarm processing and complete • State-estimation of existing system conditions, ensuring the operator’s view of the system

is unencumbered by monitoring discrepancies • Early-warning contingency analysis of the existing and potential system conditions to

ensure adherence to limiting system conditions • Pattern recognition of operationally dangerous system configurations

• Emergency operations plans for severe contingencies • Operator training, including severe condition scenarios, to enhance situational awareness

during emergencies • Coordinated UVLS and UFLS systems • System restoration plans that are adaptable to conditions existing after an outage

Such a system should be constantly updated to reflect system topology changes, and to take advantage of technical advances in monitoring equipment, computer calculation capabilities, state estimation, contingency analysis, and digital relays. Stimulation of research into this area is absolutely imperative.

New Recommendations

24

Recommendation TR-16. For each of the Interconnections, a defense-in-depth philosophy and integrated

strategy should be developed based on the characteristics of that interconnection to limit the impacts of potential cascading outages.

17. Review the Response of Switch-on-to-Fault Relay Functions to System Disturbances

Observation The Switch-on-to-Fault function was enabled and permitted the trip at Richland on the Richland – Ridgeville – Napoleon – Stryker 138 kV line. That line inadvertently re-tripped during re-energization of load due to this logic and the settings used. Discussion Switch-on-to-fault protection provides tripping in the event that a breaker is closed into a zero voltage bolted fault, such as when grounding chains are left on the line following maintenance. The primary reason for using this scheme is to supplement distance relaying protection for close-in, three-phase faults that may go undetected due to the location of voltage transducers, and the absence of memory action following line re-energization. This scheme also allows instantaneous tripping following reclosing into a permanent fault. The basic scheme first determines the breaker has been opened. Following a close, the scheme provides a window in which high-speed tripping can occur if a fault is detected. This scheme usually employs a non-directional overcurrent element to detect if a fault is present. Some schemes also use a voltage level detector for security and added selectivity to prevent operation on load pickup. Recommendation TR–17 TR-17. It is recommended that the SPCTF review the concept of “switch-onto-fault” logic and

settings in relaying systems, and prepare a report for the Planning Committee on its merits, deficiencies, and setting requirements.

18. Revise Industry Standards to Establish Under/Over Frequency Design Limits of Operation for Distance Relays

Observation Comparator logic, generally found in impedance relays, is prone to tripping as frequencies deviate from 60 Hz. Discussion Just after East Lima – Fostoria Central 345 kV line tripped, low voltage and rapidly declining frequency occurred in the Toledo area. Transmission lines in the area were carrying very little current with Fostoria Central, the major source now lost. Rapid frequency decline in the area (before Cleveland separated from Toledo) is the suspected reason for these transmission line relay operations. Several impedance relays tripped transmission lines while in this system condition. These relays, including digital and electromechanical, were from a number of different manufacturers and with different principles of frequency operation range for the relays.

New Recommendations

25

Although manufacturers inconsistently apply frequency operating range designs for relays, to maintain system integrity, all relays must operate properly throughout the entire frequency range of the UFLS programs and generator underfrequency tripping schemes. Recommendation TR–18 TR-18. Standardize a frequency floor and ceiling within which relays should not trip due to

deviations in system frequency. Such a frequency range should be coordinated with UFLS and generator underfrequency tripping schemes. Industry standards such as IEEE Standard C37.90 should be revised to include this limit.

19. Evaluate and Report on the Performance and Complexity of Protection and Control Schemes for Three Terminal Lines

Observation The Muskingum – Ohio Central – Galion 345 kV line is a complex line configuration primarily where the Ohio Central terminal is an autotransformer tapped to the middle of the line via a motor operated disconnect switch. Because of this configuration, each line relay terminal at Galion and Muskingum must be set to cover to the low side of the transformer, taking into consideration infeed from its other line terminal. This requires relay settings to be more sensitive to operation under emergency loading. Discussion The Muskingum – Ohio Central – Galion 345 kV line tripped initially due to a phase to ground fault. Over the next four minutes, 15 discreet automatic operations subsequently occurred on this line as breakers opened, reclosed, retripped, a motor operated switch opened, more reclosing, retripping. Then finally, the Ohio Central transformer, which is tapped directly off the line, was successfully reclosed to its 138 kV bus to restore supply. The Muskingum end of the line relayed by the Zone 3 relay on load encroachment because it had to look through the Ohio Central bank to protect against low side faults. This illustrates the difficulty and complexity of protecting three terminal lines. Impedance relays at all three ends must be set at much higher reaches to protect against end-of-line faults because of the infeed from the third terminal causing a higher apparent impedance. Because of this, back-up impedance relays at all three ends can be susceptible to load encroachment and lead to longer clearing times, compromising the reliability and security of the bulk power system. Three terminal lines on EHV systems should be regarded as one of the last alternatives in terms of reliability and security. Recommendation TR–19 TR-19. NERC should review and report on the advantages and disadvantages of the use of

multi-terminal line configurations on the EHV system, and any associated complex protection and control (sequential) schemes. Particular attention should be paid to the performance of such configurations and its protection during emergency operation conditions, including expected system swings.

New Recommendations

26

20. Establish Guidelines on High Speed Reclosing Observation The automatic reclosing on the Argenta – Battle Creek 345 kV line was unsuccessful because the line was attempting to reconnect two interconnected systems that were rapidly moving apart in phase angle. The resulting system perturbation placed additional stress on an already heavily stressed system in Michigan. Discussion High speed reclosing is very desirable on EHV systems where carrier/pilot or some form of high speed relaying is utilized. Since most faults are momentary, there is a high likelihood of reclosing successfully and reconnecting an important bulk transmission tie. The upside is improved dynamic performance of the bulk grid and less probability of causing an overload or voltage problem. The downside is that reclosing into a bolted fault on the line puts more stress on the EHV system and can adversely impact dynamic stability. Similarly, in the case of the Argenta – Battle Creek 345 kV line, high speed reclosing when two systems are pulling apart from one another can severely impact stability. Further, making a blind reclose without any kind of synch-check supervision can lead to equipment failure (reclosing at angles approaching 180 degrees will place two times the rated voltage applied to the poles of the breaker). So while high speed reclosing is desirable, it needs to be thought through very carefully in situations where tie lines are involved. Recommendation TR–20 TR-20. NERC should review and report on the advantages and disadvantages of auto-

reclosing methods on the EHV system including: • High speed automatic reclosing for multi-phase and single phase relay operation • Synchronism check reclosing

21. Require the Installation of Underfrequency Protection for Generators and Coordination with UFLS

Observation Only one generator in the Detroit area, Conners Creek 16, reported tripping by underfrequency. Underfrequency detection would be the expected protection for the conditions that occurred (rapidly declining system frequency, eventually falling as low as 23 Hz). A number of units remained connected to the system throughout that period, including some large generators. During this period of frequency decline, UFLS relays were inhibited from operating because the voltage was below their low voltage cutoff settings. Discussion With the advent of independent generation, generator underfrequency protection has become more universally applied. Generators that do not have such protection are under more risk of possible damage under islanding conditions. All such generator protection systems must be closely coordinated with UFLS systems to maintain load-to-generation balance in an island.

New Recommendations

27

Recommendation TR–21 TR-21. Underfrequency relaying should be installed on all generators, coordinated with the

underfrequency load shedding relays.

22. Evaluate and Implement Coordination Requirements for Generator Backup Protection Responses in Cohesive Generation Groups

Observation Generators that are electrically close to one another can behave as cohesive group, such as when islanded from the rest of the Interconnection. Generators can also remain in synchronism with each other within a zone and slip in frequency together with respect to the rest of the Interconnection when weakly tied to the Interconnection. Such was the case in southeast Michigan. In either case, protective relay functions can and did respond differently under such conditions. The cohesive generator group can experience lower voltage, underfrequency, and large power flows brought on by large angles across its ties to the Interconnection. During the cascade, in response to changes in the transmission system, a number of generator protection relaying schemes operated, although they are designed to protect against generator component failure. Examples include: inadvertent energization protection, volts/hertz overexcitation, voltage restrained overcurrent, undervoltage, and loss of excitation relays. The operations of these relays are sensitive to abnormal voltages and frequencies. A number of generators reported tripping operations from these devices:

Initiating Tripping Relay Number of Generators

Tripped

Inadvertent energization 6

Volts/Hertz 10

Voltage restrained overcurrent 4

Undervoltage 25

Overcurrent 15

Loss of excitation 11 Discussion Inadvertent energization is a protection scheme intended to detect an accidental energization of a unit at standstill or a unit not yet synchronized to the power system. Two schemes used to detect inadvertent energizing are frequency supervised overcurrent and voltage supervised overcurrent. In frequency supervised overcurrent schemes, the underfrequency relays are set to close their contacts when the frequency falls below a setting, which is in the range of 48–55 Hz, thus

New Recommendations

28

enabling the overcurrent relay. Voltage supervised overcurrent schemes use under and overvoltage relays with pick-up and dropout time delays to supervise instantaneous overcurrent tripping relays. The undervoltage detectors automatically arm the over-current relays when its generation is taken off-line. Overvoltage relays disable the scheme when the machine is put back in service. Volts/Hertz relays are used for overexcitation protection of generators. These relays become more prone to operation as frequency declines, given a particular voltage. Voltage restrained time-overcurrent relaying is remote backup protection used to protect generators for distant faults, and is not intended to trip on load. Undervoltage relays respond to system conditions especially when connected to transmission level voltage transformers. Overcurrent relays respond to faults and to some non-fault conditions such as system swings. Loss of excitation relays protect a generator in the event of an exciter failure. As with the Volts/Hertz relay, the loss of excitation relay should coordinate with generator excitation controls when these controls are functioning properly and exciter failures have not occurred. 51V Voltage Controlled Overcurrent protection is backup protection to use when overcurrent does not provide adequate sensitivity. It can discriminate between load current and steady state fault current. The latter can be smaller than full load current due to the large Xd and AVR constraints. It is susceptible to operation for sustained undervoltage conditions as confirmed during pre-blackout disturbance. Recommendation TR–22 TR-22. NERC should evaluate these protection schemes and their settings for appropriateness

including coordination of protection and controls when operating within a coherent generation weakly connected to an interconnection or in as an electrical island. Generators directly connected to the transmission system using a 51V should consider the use of an impedance relay instead.

23. Establish Regime for More In-Depth Analysis in Transmission Reliability Studies

Observation Most transmission studies are limited to evaluation of contingencies only to N-1 planning criteria. Similarly, NERC Operating Policies call for being able to survive N-1 contingencies (without violating voltage or emergency loading criteria) and to recover from such outages within 30 minutes. Further, pre-seasonal contingency analysis is often done for a prescribed set of selected contingencies, sometimes limited to EHV outages. The blackout of August 14 calls the adequacy of all of these practices into question. Discussion In the first hour of the blackout sequence of events, if FirstEnergy and MISO’s state estimator operated correctly, they would have identified the N-1 criteria violations and next critical contingencies following the Chamberlin – Harding 345 kV outage. The Hanna – Juniper 345 kV outage occurred only 26 minutes later, and the South Canton – Star 345 kV outage only some nine minutes later. There was no time to prepare for the next contingency, and the combination

New Recommendations

29

of those three outages probably had not been studied. Further, when the Sammis – Star 345 kV line tripped at 16:05, the state estimators did not necessarily have knowledge of the myriad of 138 kV outages that had taken place. Consequently, the state estimators would be assuming an existing N-3 condition, but in reality the system was facing a far more severe N-20 situation. While real-time determination of system vulnerability beyond N-1 may not be practicable in system operations and state estimators, more rigorous analysis could be carried out in pre-seasonal and operational planning analyses. More rigorous off-line analysis of NERC Table 1, Category C3 [Event(s) resulting in the loss of two or more (multiple) elements] contingencies should be conducted to help define how operators should readjust the system after an N-1 event within 30 minutes to prepare for the next worst contingency4. The off-line applications should expand their scope to perform analysis that supplements what can be done in real-time, such as expanded severe contingency analysis, voltage stability analysis, small-signal stability analysis (inter-area oscillations), and vulnerability state analysis. Off-line analysis contingency analysis capabilities of performing thousands of full AC contingencies, screened by exception reporting, should be taken advantage of to analyze a wider range of scenarios than can be considered in real-time applications. Pre-determination of potentially dangerous operating states by the off-line pre-seasonal studies should be pursued. The results of such studies could then be compared in real-time to the then-current state of the system (particularly in topology) and greatly enhance the operator’s situational awareness. Additionally, periodic analysis of more Table 1, Category D (multiple combinations) contingencies could be done to determine which combinations are the most severe. The knowledge base of severe combinations could then be used to improve reliability under developing adverse conditions. Transmission operators and reliability coordinators could then apply topology processors to monitor the system and alert them to potential development of those combinations of outages. Recommendation TR–23 TR-23a. NERC should re-examine the appropriateness of the 30-minute criteria for returning to

a safe operation following an outage. TR-23b. NERC, the Regions, and the ISO/RTOs should conduct a comprehensive analysis of

the bulk power system for identification of severe combinations of contingencies (both generation and transmission), and identify the susceptibility of the system to and consequences of such combinations of outages. Remedial actions available to operations personnel should also be identified.

TR-23c. NERC, the Regions, and the ISO/RTOs should develop study regimes that determine severe combinations of contingencies and develop the topology monitoring capability to identify potential development of those outage combinations.

3 Table I. Transmission System Standards — Normal and Emergency Conditions, contained in Standard TPL-003-0 — System Performance Following Loss of Two or More BES Elements 4 As specified under Standard TOP-004-0 — Transmission Operations

New Recommendations

30

24. Continue What If Analyses, Promote Research Based on the Blackout, and Preserve Forensic Analysis Techniques

Observations What if there was undervoltage load shedding implemented in the Cleveland/Toledo load center prior to the tripping of the Sammis – Star 345 kV line? What if the Sammis – Star 345 kV line did not trip? What if automatic load shedding had been implemented after large, steady state system angles were created due to the loss of the East Lima – Fostoria Central 345 kV line? What if the Michigan – Ontario ties had tripped when generators within eastern Michigan began to lose synchronism with Canada? Discussion A number of “what if” scenarios have been studied in the course of the technical studies. Additionally, the data collected and studies performed by the blackout investigation team suggest that a significant body of research should be done to take advantage of the unusual phenomena observed. There is significant potential for advances in generator control modeling, load modeling, and electric system forensic analysis techniques. The analysis techniques developed and used for the 1996 and 2003 blackouts should be documented and shared throughout the industry to avoid having to rediscover them when the next major system disturbance occurs. Recommendation TR–24 TR-24a. Evaluate significant “what-if” scenarios to learn how the overall system may have

performed given varying system conditions or different sequence of events. TR-24b. Research based on the detailed data collected during the blackout investigation should

be promoted to improve modeling and analysis techniques. TR-24c. NERC should document electric system forensic analysis techniques and prepare

training materials for the industry.

Appendix A — Related Recommendations

A

Related NERC and U.S.-Canada Task Force Recommendations These are the blackout recommendations related to those made in the Technical report. They are detailed in the August 14, 2003 Blackout: NERC Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts, dated February 10, 2004, and the U.S.-Canada Power System Outage Task Force Final Report on the August 14, 2003 Blackout in the United States and Canada: Causes and Recommendations, dated April 2004.

NERC Recommendation 8 — Improve System Protection to Slow or Limit the Spread of Future Cascading Outages NERC Recommendation 8a All transmission owners shall, no later than September 30, 2004, evaluate the zone 3 relay settings on all transmission lines operating at 230 kV and above for the purpose of verifying that each zone 3 relay is not set to trip on load under extreme emergency conditions5. In each case that a zone 3 relay is set so as to trip on load under extreme conditions, the transmission operator shall reset, upgrade, replace, or otherwise mitigate the overreach of those relays as soon as possible and on a priority basis, but no later than December 31, 2005. Upon completing analysis of its application of zone 3 relays, each transmission owner may no later than December 31, 2004 submit justification to NERC for applying zone 3 relays outside of these recommended parameters. The Planning Committee shall review such exceptions to ensure they do not increase the risk of widening a cascading failure of the power system. NERC Recommendation 8b Each regional reliability council shall complete an evaluation of the feasibility and benefits of installing under-voltage load shedding capability in load centers within the region that could become unstable as a result of being deficient in reactive power following credible multiple-contingency events. The regions are to complete the initial studies and report the results to NERC within one year. The regions are requested to promote the installation of under-voltage load shedding capabilities within critical areas, as determined by the studies to be effective in preventing an uncontrolled cascade of the power system. NERC Recommendation 8c The Planning Committee shall evaluate Planning Standard III – System Protection and Control and propose within one-year specific revisions to the criteria to adequately address the issue of slowing or limiting the propagation of a cascading failure. The board directs the Planning Committee to evaluate the lessons from August 14 regarding relay protection design and application and offer additional recommendations for improvement. 5 The NERC investigation team recommends that the zone 3 relay, if used, should not operate at or below 150% of the emergency ampere rating of a line, assuming a .85 per unit voltage and a line phase angle of 30 degrees. The SPCTF later clarified the definition of emergency ampere rating — Emergency Ampere Rating — “The highest seasonal ampere circuit rating (that most closely approximates a 4-hour rating) that must be accommodated by relay settings to prevent incursion.” That rating will typically be the winter short-term (four-hour) emergency rating of the line and series elements. The line rating should be determined by the lowest ampere rated device in the line (conductor, airswitch, breaker, wavetrap, series transformer, series capacitors, reactors, etc) or by the sag design limit of the transmission line for the selected conditions. The evaluation of all Zone 3 relays should use whatever ampere rating currently used that most closely approximates a 4-hour rating.


B

NERC Recommendation 10 — Establish Guidelines for Real-Time Operating Tools The Operating Committee shall within one year evaluate the real-time operating tools necessary for reliable operation and reliability coordination, including backup capabilities. The Operating Committee is directed to report both minimum acceptable capabilities for critical reliability functions and a guide of best practices.

NERC Recommendation 12 — Install Additional Time-Synchronized Recording Devices as Needed NERC Recommendation 12a The reliability regions, coordinated through the NERC Planning Committee, shall within one year define regional criteria for the application of synchronized recording devices in power plants and substations. Regions are requested to facilitate the installation of an appropriate number, type and location of devices within the region as soon as practical to allow accurate recording of future system disturbances and to facilitate benchmarking of simulation studies by comparison to actual disturbances. NERC Recommendation 12b Facilities owners shall, in accordance with regional criteria, upgrade existing dynamic recorders to include GPS time synchronization and, as necessary, install additional dynamic recorders.

NERC Recommendation 14 — Improve System Modeling Data and Data Exchange Practices The regional reliability councils shall within one year establish and begin implementing criteria and procedures for validating data used in power flow models and dynamic simulations by benchmarking model data with actual system performance. Validated modeling data shall be exchanged on an inter-regional basis as needed for reliable system planning and operation.

U.S.–Canada Recommendation 11 — Establish Requirements for Collection and Reporting of Data Needed for Post-Blackout Analyses FERC and appropriate authorities in Canada should require generators, transmission owners, and other relevant entities to collect and report data that may be needed for analysis of blackouts and other grid-related disturbances.

U.S–Canada Task Force Recommendation 14 — Establish a Standing Framework for the Conduct of Future Blackout and Disturbance Investigations The U.S., Canadian, and Mexican governments, in consultation with NERC, should establish a standing framework for the investigation of future blackouts, disturbances, or other significant grid-related incidents.


C

U.S.–Canada Recommendation 21 — Make More Effective and Wider Use of System Protection Measures U.S.–Canada Recommendation 21a Task Force: Recommends that NERC broaden the review to include operationally significant 115 kV and 138 kV lines, e.g., lines that are part of monitored flowgates or interfaces. Transmission owners should also look for zone 2 relays set to operate like zone 3s. U.S.–Canada Recommendation 21b Task Force: Recommends that NERC require the results of the regional studies to be provided to federal and state or provincial regulators at the same time that they are reported to NERC. In addition, NERC should require every entity with a new or existing UVLS program to have a well-documented set of guidelines for operators that specify the conditions and triggers for UVLS use.

U.S.–Canada Recommendation 22 — Evaluate and Adopt Better Real-Time Tools for Operators and Reliability Coordinators NERC’s requirements of February 10, 2004, direct its Operating Committee to evaluate within one year the real-time operating tools necessary for reliability operation and reliability coordination, including backup capabilities. The committee’s report is to address both minimum acceptable capabilities for critical reliability functions and a guide to best practices. The Task Force supports these requirements strongly. It recommends that NERC require the committee to: A. Give particular attention in its report to the development of guidance to control areas

and reliability coordinators on the use of automated wide-area situation visualization display systems and the integrity of data used in those systems.

U.S.–Canada Recommendation 24 — Improve Quality of System Modeling Data and Data Exchange Practices NERC’s requirements of February 10, 2004 direct that within one year the regional councils are to establish and begin implementing criteria and procedures for validating data used in power flow models and dynamic simulations by benchmarking model data with actual system performance. Validated modeling data shall be exchanged on an inter-regional basis as needed for reliable system planning and operation. The Task Force supports these requirements strongly. The Task Force also recommends that FERC and appropriate authorities in Canada require all generators, regardless of ownership, to collect and submit generator data to NERC, using a regulator-approved template.

U.S.–Canada Recommendation 28 — Require Use of Time-Synchronized Data Recorders In its requirements of February 10, 2004, NERC directed the regional councils to define within one-year regional criteria for the application of synchronized recording devices in key power plants and substations.


D

The Task Force supports the intent of this requirement strongly, but it recommends a broader approach: A. FERC and appropriate authorities in Canada should require the use of data recorders

synchronized by signals from the Global Positioning System (GPS) on all categories of facilities whose data may be needed to investigate future system disturbances, outages, or blackouts.

B. NERC, reliability coordinators, control areas, and transmission owners should determine where high speed power system disturbance recorders are needed on the system, and ensure that they are installed by December 31, 2004.

C. NERC should establish data recording protocols. D. FERC and appropriate authorities in Canada should ensure that the investments called

for in this recommendation would be recoverable through transmission rates.

U.S.–Canada Recommendation 30 — Clarify Criteria for Identification of Operationally Critical Facilities, and Improve Dissemination of Updated Information on Unplanned Outages NERC should work with the control areas and reliability coordinators to clarify the criteria for identifying critical facilities whose operational status can affect the reliability of neighboring areas, and to improve mechanisms for sharing information about unplanned outages of such facilities in near real-time.

Documents

Draft Recommendations from the August 14, 2003, Blackout … Highlights and Minutes DL/2005/It… · Enhance Standards for Rating Transmission Lines .....15 12. Improve and Validate