1. 03-03-11 Commercial Operations Subcommittee Update to TAC Debbie McKeever COPs Chair 2011

2. COPs Working Group Activities in Progress CCWG Working to ensure the COPMG and other documentation supporting Commercial Operations accurately reflects Market processes PWG Continuing work to ensure Profiles are maintained and/or established to meet Market processes and changes including completing all annual profiling activities SEWG Developing Settlement Algorithms User Guide, responding to Market needs for Settlement Extract issues, providing updates/education as needed. 2

3. COPs Meeting Highlights continued… AND Voting Items for TAC LPGRR042. Updating of Weather Sensitivity Assignment, Suspension of Annual Validation for Advanced Meters, Addition of Load Research Sampling Documents, and Removal of Unused TOUS Codes - Approved LPGRR044, Addition of Distributed Generation (DG) Load Profiles - - Approved with recommendation to TAC to approve with Urgent Status

5. DISCUSSION POINTS FROM THE PWG MONTHLY CALL REGARDING ADJUSTMENT OF LOAD PROFILES FOR THE RECENT COLD WEATHER EVENT FEBRUARY 23, 2011

6. Discussions following Hurricane Rita resulted in load profiles not being adjusted because, after the fact, the mix of those so-called winners and losers would change. Plus there was no prior notice of adjustments so forecasts, hedging and supply schedules could be planned in the forward position. Load profiles were adjusted for Hurricane Ike because of the magnitude of the problem and relatively good estimated data. Also the PUCT authorized ERCOT to make settlements more accurate. Only the coast weather zone was adjusted to keep the other zones from subsidizing excess UFE not incurred in the area. Rolling outages were a much smaller event than Hurricane Ike. See the BOD presentation. (http://www.ercot.com/content/meetings/board/keydocs/2011/ 0214/Review_of_February_2,_2011_EEA_Event.pdf)http://www.ercot.com/content/meetings/board/keydocs/2011/ 0214/Review_of_February_2,_2011_EEA_Event.pdf

7. Adjusting the load profiles could and does create problems for billing systems where profiles are a part of process. Adjusting the load profiles could create confusion for customers. Though magnitude of rolling outages was relatively low, $3000/MWh could significantly hurt some REPs. Unknown at this time how rolling outages will affect UFE. Resource-intensive to determine adjustments to be made. Making adjustments to reduce load profiles might effectively allocate more UFE to IDRs if UFE is negative.

8. Making adjustments to load profiles might do more harm than good. No estimation process of how to calculate the outage with ERCOT or TDSP input can be shown to be accurate. So application of high level estimates for Non-IDR profiles may alter the accuracy of other intervals in the current settlement process. That is, any simple assumptions on adjustments are likely to be no more accurate than current settlement. Profile changes require 150 day notice and the stakeholder approval process with even an urgent request would push the effective date well past the true up settlement unless these timelines were suspended. A request by ERCOT to the PUCT for such timeline waver might be needed.

9. One market participant has noticed a dramatic increase in AMS metered load on Feb. 2, 2011 over their Non-IDR profiled customers. This supports that the event may show in hind site that profiles were short and UFE positive at final settlement similar to the event documented by SEWG for January 6-9, 2010. Page 14 of the Board Report shows the ERCOT dispatched events of the day. How this request for load changes translates to reductions in the profiles is problematic if not impossible to estimate accurately. ERCOT Staff believe the outage calculations would best be in the hands of the TDSPs. With new AMS meters now estimated to comprise one third of settlement load plus IDR load, perhaps as much as 50% of the market is settled on 15 minute interval data resulting in great improvement in settlement accuracy on Feb. 2.

10. Lowering the profiles in the high dollar intervals would not change the fact that a specific non-IDR load is calculated proportionately from the profiles with the same shape. Thus the 30 day meter read has the lost load from the outage spread over all 30 days of the meter read. The reduction in specific intervals for the morning of Feb. 2 would not mitigate the error in the load during the outages. A top down analysis of separating known metered load for IDR and AMS from generation is proposed to help estimate non-IDR profile contribution.

11. Settlement Observations – Post Nodal As evaluated and discussed at January 24 th SEWG meeting

12. 12 Settlement Observations- Load Zone to Hub January Meeting Title (optional)Date Row LabelsAverage of Average Column LabelsAverage of AverageColumn LabelsBasis HB_HOUSTO N$34.72Row LabelsLZRow LabelsHUB HB_NORTH$35.06LZ_HOUSTON$34.72HB_HOUSTON$34.72$0.00 HB_SOUTH$36.48LZ_NORTH$35.60HB_NORTH$35.06$0.55 HB_WEST$30.63LZ_SOUTH$41.48HB_SOUTH$36.48$5.00 LZ_HOUSTON$34.72LZ_WEST$31.17HB_WEST$30.63$0.54 LZ_NORTH$35.60Grand Total$35.75Grand Total$34.22 LZ_SOUTH$41.48 LZ_WEST$31.17 LZ_AEN$34.87 LZ_CPS$35.22 Grand Total$35.00

13. 13 Cost to Serve Load January 2011- –AS seems within Zonal values where price per MWh is $1.24 (up $0.07 from Dec) –BPD Uplift charges are a credit to Loads at less than $0.01 per MWh, total BPD charges to resources through is approximately $100K (comparable to Dec) –RUC Uplift Charges remain negligible as most charges are assigned to entities short at RUC periods Total RUC Charges to short entities $1.5 M (up by $0.4M from Dec) –Revenue Neutrality uplift to Loads currently a revenue of $0.07/MWh (down from Dec expense of $0.46/MWh) Settlement Observations- Cost to Serve Load January

14. 14 Impact of February Weather Events Market wide average RTSPPs (All Settlement Points), SEWG to evaluate Settlement Impact as soon as practicable –2/2/2011: $785.14 –2/3/2011: $135.20 –2/4/2011: $48.36 Meeting Title (optional)Date Average of AverageColumn Labels Row Labels2/2/2011 0:00 2/3/2011 0:00 2/4/2011 0:00Grand Total HB_BUSAVG$783.22$112.14$47.18$314.18 HB_HOUSTON$778.86$64.76$45.89$296.50 HB_HUBAVG$781.85$116.15$46.62$314.87 HB_NORTH$784.64$79.34$47.10$303.69 HB_SOUTH$784.91$238.75$50.51$358.06 HB_WEST$779.01$81.75$42.98$301.25 LZ_AEN$789.26$84.49$47.61$307.12 LZ_CPS$786.20$88.39$51.08$308.56 LZ_HOUSTON$781.15$70.91$45.78$299.28 LZ_LCRA$797.28$90.93$49.84$312.68 LZ_NORTH$797.27$79.64$47.11$308.01 LZ_RAYBN$796.76$79.43$47.08$307.76 LZ_SOUTH$803.46$696.07$56.26$518.60 LZ_WEST$781.20$82.59$42.99$302.26 Grand Total$787.51$140.38$47.72$325.20

15. 15 Preliminary Cost to Serve Load for February (based on RTM Settlements through 2/16/2011) –AS seems within Zonal values where price per MWh is $6.27, should normalize the further we go into February settlements after the weather event periods –BPD Uplift charges are a credit to Loads at less than $0.29 per MWh –RUC Uplift Charge trends as in December negligible RUC Shortfall Payments $1.7 M to entities short in the market –Revenue Neutrality uplift to Loads currently an revenue of $(0.14) MWh appears to be fluctuating with congestion, still needs explanation Settlement Observations- Cost to Serve Load February

16. Next COPs Meeting Tuesday, March 8 th Thank You