1. January 9, 2013 BAL-001-TRE-1 Primary Frequency Response Update for Texas RE RSC

2. 2 SAR-003 Standard Drafting Team BAL-001-TRE-1 RSC January 9, 2013 NameCompany Sydney Niemeyer (Chair)NRG Energy Ananth Palani (Vice-Chair)Optim Energy Pamela ZdenekInfigen Energy Vann WeldonERCOT Brenda HamptonLuminant Sandip SharmaERCOT (Non-voting SME)

3. 3 Submittal for RSC Approval ●Drafting Team has finished the standard and related documents.  Each active team member approved all documents. ●Request RSC to approve standard for Posting, Review and Balloting. BAL-001-TRE-1 RSC January 9, 2013

4. 4 Requirements Overview ●Applies to BA, GO and GOP function ●Provides requirements for:  Identifying Frequency Measureable Events (FME)  Calculating the Primary Frequency Response (PFR) of each resource in the Region  Calculating the Interconnection minimum Frequency Response  Monitoring the actual Frequency Response of the Interconnection  Setting Governor deadband and droop parameters  Providing Primary Frequency Response performance requirements. ●Importantly, the standard narrows the governor deadband and requires the droop curve to begin at the edge of the deadband with no step function. BAL-001-TRE-1 RSC January 9, 2013

5. 5 Generator PFR Performance Measures ●Under this standard, two Primary Frequency Response performance measures are calculated: “initial” and “sustained.”  The initial PFR performance (R9) measures the actual response compared to the expected response in the period from 20 to 52 seconds after an FME starts.  The sustained PFR performance (R10) measures the best actual response from t(46) to t(60), compared to the expected response at t(46). BAL-001-TRE-1 RSC January 9, 2013

6. 6 Increased Maintenance & Operating Costs? ●Generator Owners had concerns with smaller dead-bands increasing costs. ●Data from before dead-band and droop curve implementation compared to latest data indicates a significant cost savings. ●Significant increase in grid reliability. BAL-001-TRE-1 RSC January 9, 2013

7. 7 ERCOT Frequency Profile from 2008 BAL-001-TRE-1 RSC January 9, 2013 Prior to Nov 2008 nearly all generators implemented a +/- 0.036 Hz dead-band governor, many with a step-response at the dead-band. The frequency profile reflected this dead-band setting.

8. 8 ERCOT Frequency Profile from 2012 BAL-001-TRE-1 RSC January 9, 2013 By the end of October 2012 more than 20% of ERCOT generators had implemented the smaller +/- 0.017 Hz dead- band.

9. 9 How Does This Impact Generator Movement? BAL-001-TRE-1 RSC January 9, 2013 With the lower dead-band setting a similar size generator saw a 38% decrease in movement between 2008 and 2012.

10. 10 Not All Improvement Due to Dead-Band & Droop ●Approximately 20% of ERCOT Generators now meet R6 of this Standard. ●Other Changes Impacted Frequency Control  Change in Market from Zonal to Nodal Dispatch.  Many generators previously not providing PFR correctly are now working correctly but at the larger dead-band.  Wind Generators are now required to have PFR and governors in service. ●However, only the decrease in the dead-band can significantly improve the frequency profile inside the +/-0.036 Hz deviation range. BAL-001-TRE-1 RSC January 9, 2013

11. 11 Impact on ERCOT CPS1 Performance BAL-001-TRE-1 RSC January 9, 2013 Oct 2008 12 month avg. CPS1 = 122.03 Oct 2012 12 month avg. CPS1 = 160.17

12. 12 With All the Improvement Why BAL-001-TRE ●Fair and accurate measure of PFR.  12 month rolling average or minimum 8 event avg.  Allows for event exclusion due to equipment limits.  Accounts for generator ramping before the event.  Adjusts expected performance due to known generator delivery limitations.  Accounts for non-frequency responsive capacity like duct burner operation and other augmentation. ●Equal expectations for all generators.  Wider dead-band governors benefiting from generators with smaller dead-band.  With the standard all generators will move less and operate closer to their economic target. BAL-001-TRE-1 RSC January 9, 2013

13. 13 Field Trial Results ●28 generating units were evaluated in the trial, which included 7 coal, 4 gas, 2 simple cycle combustion turbine, 5 wind, and 10 combined cycle units. ●Based on 35 events from June 2011 to June 2012. ●No high-frequency events were evaluated. ●8-event average was not possible with some units. ●These results use NEW R10 calculation. BAL-001-TRE-1 RSC January 9, 2013

14. 14 Field Trial Results – Coal Units BAL-001-TRE-1 RSC January 9, 2013

15. 15 Field Trial – Gas Units BAL-001-TRE-1 RSC January 9, 2013

16. 16 Field Trial – Wind Units BAL-001-TRE-1 RSC January 9, 2013

17. 17 Field Trial – Combined Cycle Units BAL-001-TRE-1 RSC January 9, 2013

18. 18 Changes Made after Field Trial and Comments ●Changed Sustained Measure (R10) from average over several minutes to instantaneous at t(46).  Too much happens during former averaging window. ●Added 5 MW limit to the 2% exception criteria. ●Moved examples of “legitimate operating conditions that may support exclusion” from Measures to Requirements (R9 and R10). ●M7 re-written to focus on notice from GO to GOP of change in Governor status.  Avoids concern about 24/7 proof issue. ●Changed deadband setting from 0.01666 to 0.017 Hz. ●Reformatted R2 to break into sub-requirements. ●Added non-frequency responsive augmented capacity exclusion. BAL-001-TRE-1 RSC January 9, 2013

19. 19 Benefits of the Field Trial ●Presentations prepared and delivered to each participant.  One presentation for each generator with one graph for each event evaluated (generator on line during the event). Potentially 980 graphs total. Included Performance summary and critique. ●Reviewed performance with each participant through web conferences. ●Participants became familiar with the standard, proper PFR expectations and could easily see shortcomings in performance. BAL-001-TRE-1 RSC January 9, 2013

20. 20 Example of New R10 Measure BAL-001-TRE-1 RSC January 9, 2013 1) Frequency @ t(+46) sets the expected performance. 2) Based on Frequency @ t(+46) expected performance is calculated. 3) Generator performance is based on “best” performance between t(+46) through t(+60).

21. 21 Primary Frequency Response Reference Document ●This Primary Frequency Response Reference Document is not considered to be a part of the regional standard. ●This document will be maintained by Texas RE and will be subject to modification as approved by the Texas RE Board of Directors, without being required to go through the formal Standard Development Process.  This arrangement provides Regional flexibility in adjusting the technical details of the performance metric calculations.  The PFR Reference Document includes flowcharts that detail the calculations BAL-001-TRE-1 RSC January 9, 2013

22. 22 PFR Reference Document Revision Process ●A Revision Request may be submitted to the Texas RE Reliability Standards Manager ●The Reliability Standards Committee (RSC) will consider the request  The revision request will be posted in accordance with RSC procedures  The RSC shall discuss the revision request in a public meeting, and will accept and consider verbal and written comments pertaining to the request  The RSC will make a recommendation to the Texas RE Board of Directors ●The Board may adopt the revision request, reject it, or adopt it with modifications  Any approved revision to the Primary Frequency Response Reference Document shall be filed with NERC and FERC for informational purposes BAL-001-TRE-1 RSC January 9, 2013

23. 23 Implementation Plan ●12 months after Effective Date  The BA must be compliant with Requirement R1  At least 50% of the GO’s generating units/generating facilities must be compliant with Requirement R6 (if >1 unit/facility)  At least 50% of the GO’s generating units/generating facilities must be compliant with Requirement R7 (if >1 unit/facility)  The GOP must be compliant with Requirement R8 ●18 months after Effective Date  The BA must be compliant with Requirements R2, R3, R4, and R5  100% of the GO’s generating units/generating facilities must be compliant with Requirement R6  100% of the GO’s generating units/generating facilities must be compliant with Requirement R7 BAL-001-TRE-1 RSC January 9, 2013

24. 24 Implementation Plan ●24 months after Effective Date  At least 50% of the GO’s generating units/generating facilities must be compliant with Requirement R9 (if >1 unit/facility)  At least 50% of the GO’s generating units/generating facilities must be compliant with Requirement R10 (if >1 unit/facility) ●30 months after Effective Date  100% of the GO’s generating units/generating facilities must be compliant with Requirement R9  100% of the GO’s generating units/generating facilities must be compliant with Requirement R10 BAL-001-TRE-1 RSC January 9, 2013