DSWG Update to WMS

1. DSWG Update to WMS March 22, 2006

2. 2006 Demand Side Working Group Goals

3. DSWG 2006 Goals

4. DSWG LaaR Bidding Update March 22, 2006

5. Special Task Force Formed • A Special Task Force was assembled to evaluate and propose long term solutions • Team consists of a range of market participants including: • Mary Anne Brelinsky – Reliant • Keith Emery – Tenaska • Clayton Greer – Constellation • Randy Jones – Calpine • Steve Krein – ERCOT • John Lightbourn – TXU • Task Force initially identified eight potential long term solutions and narrowed those down to four • Mark Patterson – ERCOT • Malcolm Smith – Energy Data Source • Randa Stephenson– TXU • Michael Walker – Exxon • Scott Wardle – Oxy Chem • Fred Young – Air Liquide

6. Long Term Solutions Evaluated Team reviewed eight potential long term solutions: • Revise settlement process and how defaults are processed • Revise credit provisions to require protection prior to bidding and create ability to monitor real time • Shift credit risk to Resources rather than QSEs • Create two separate markets, one for LaaRs and one for Gen • Maintain a single market clearing engine, but when LaaR is oversubscribed post separate clearing prices for LaaR and Gen • Pay all ancillary services as bid (both Gen and LaaR) • Modify current award mechanism for LaaRs; LaaRs offered at a price below MCPC are awarded • Eliminate sunset date on short term solution and modify system to reject negative offer prices A B C D

7. Long Term Solutions Evaluated Team reviewed eight potential long term solutions: • Revise settlement process and how defaults are processed • Revise credit provisions to require protection prior to bidding and create ability to monitor real time • Shift credit risk to Resources rather than QSEs • Create two separate markets, one for LaaRs and one for Gen • Maintain a single market clearing engine, but when LaaR is oversubscribed post separate clearing prices for LaaR and Gen • Pay all ancillary services as bid (both Gen and LaaR) • Modify current award mechanism for LaaRs; LaaRs offered at a price below MCPC are awarded • Eliminate sunset date on short term solution and modify system to reject negative offer prices A B C D E

8. A. Collateralization for Negative Bids Proposed Solution: Modify the ERCOT EAL credit program. EAL calculation would capture negative bidding by QSE and incorporate into QSE credit requirements. Solution creates a similar process as TEL but based on bidding behavior not clearing price. Negative bidding behavior could require 5 to 10 QSEs to post additional credit collateral based on their EAL calculation. QSE is responsible for establishing their own credit requirements with LaaR. Pros: • Credit based Solution that does not significantly impact market design • Similar process to Balancing Energy requirements now in place Cons: • Reduces but does not eliminate possible market disruption by negative clearing bid since EAL looks back on average 20 days historical behavior (during which negative bidding may not have taken place so "no" or "minimal" credit is required) • Possible reduction in LaaR participation in ERCOT auction from QSEs without collateral sufficient to support large negative bids.

9. Protocol Revision Required for Alternative A 16.2.7.1 Determination of Initial Total Estimated Liability ERCOT shall calculate the QSE’s initial Total Estimated Liability (TEL), using the following formula: TEL = (DES x BEF x AEP x 40) + (LRB x ARCP x 40) Where: TEL = Total Estimated Liability DES = Estimated Daily Actual Load Schedule (average MWh) plus estimated Daily Actual Generation Schedule initially provided by the QSE in its Service Filing BEF = Balancing Energy Factor is the greater of: (a) Twenty percent (20%) or the estimated actual Load imbalance or Resource imbalance percentage for QSEs that schedule only Load or Generation; or (b) The greater of ten percent (10%) or the estimated actual net Load imbalance and Resource imbalance percentage for QSEs that schedule both Load and Generation AEP = Average Energy Price in the market in the ERCOT Region. AEP is initially based upon on seasonal historic average prices for Balancing Energy LRB= Actual Amount of qualified LaaR that is eligible to offer into ERCOT RRS Ancillary Service Market ARCP= Average historical clearing price of ERCOT RRS Ancillary Service Market for past 20 days 16.2.7.3 Determination of Estimated Aggregate Liability This subsection applies to all QSEs. After a QSE receives its first Invoice, ERCOT shall monitor daily and calculate, at least weekly, the QSE’s Estimated Aggregate Liability (EAL) based on the formula below. Any QSE that is required to post security is responsible, at all times, for maintaining posted security at or above the amount of its EAL, minus the QSE’s Unsecured Credit Limit. EAL = Greater of ADTE or [Highest TEL or ADTE in effect during the previous 60-day period (adjusted for the SAF)] + OUT – TCRar + PUL - LRE LRE = LaaR Responsive Reserve Exposure shall be determined by the lesser of: (1) 0; and (2) Average historical LaaR offer quantity to ERCOT RRS Ancillary Service Market for the past 20 days multiplied by the Average historical RRS offer price to ERCOT RRS Ancillary Service Market for the past 20 days multiplied by 40 days.

10. C. Single RRS Bid Stack with Separate LaaR and Gen MCPCs if Oversubscribed Proposed Solution: Solution leverages ERCOT's existing clearing engines. If LaaR limit is reached a separate MCPC price for LaaR would be posted. To the extent the LaaR limit is not reached only one MCPC for both LaaR and Gen is cleared. = LaaR offer = Gen offer = Self Arranged More than 1,150 MWs of LaaRs Offered Below MCPC Less than 1,150 MWs of LaaRs Offered Below MCPC Gen MCPC Single MCPC 2,300 MW of RRS 2,300 MW of RRS = = LaaR MCPC Single Bid Stack Single Bid Stack

11. C. Single RRS Bid Stack with Separate LaaR and Gen MCPCs if Oversubscribed Proposed Solution: Solution leverages ERCOT's existing clearing engines. If LaaR limit is reached a separate MCPC price for LaaR would be posted. To the extent the LaaR limit is not reached only one MCPC for both LaaR and Gen is cleared. Pros: • If current LaaR participation levels persist, two separate RRS MCPCs would frequently occur; likely to result in a short term reduction in market RRS costs • Need for secondary RRS solicitations unlikely • Market based solution; bids should be more reflective of cost to provide service Cons: • Requires market participants to manage two MCPCs for Responsive Reserve and makes settlement more complex • May drive LaaR out of the RRS market if LaaR MCPC is consistently/significantly lower than Gen MCPC and result in higher total costs to market • Creates arbitrage opportunity for QSEs that self arrange large percentage of LaaR

12. Protocol Revision Required for Alternative C 6.6.3 ERCOT Day-Ahead Ancillary Service Procurement Process 6.6.3.1 General Procurement Requirements (8) ERCOT shall determine an hourly MCPC for each of the following Day-Ahead Ancillary Service markets: Regulation Up, Regulation Down and Non-Spinning Reserves. The hourly MCPC shall equal the highest-priced capacity reservation bid accepted in the Day Ahead market by ERCOT for that Ancillary Service for the hour. For Responsive Reserve Service, ERCOT shall determine a separate MCPC for LaaRs and Generation Resources. QSE’s representing LaaR and Generation Resources will be paid based on these separate MCPCs. A blended MCPC will be determined based on the formula’s and rules defined in Section 6.6.3.4 and QSEs representing LSEs with RRS obligations will be charged based on the blended MCPC. 6.6.3.4 Special Procurement Requirements for Responsive Reserve Service. 6.6.3.4.1 The MCPC for LaaR RRS and Generation Resources RRS shall be determined by the following rules/formula’s. RRS = LaaRSA + LaaRAward + GenSA + GenAward If LaaRSA + LaaRBid ≤ LaaRMax MCPCLaaR = MCPCGen = Highest Price in the bid stack for last MW of RRS Awarded Then, LaaRBid ≤ LaaRAward And MCPCBlended = MCPCLaaR = MCPCGen If LaaRSA + LaaRBid > LaaRMax Then, LaaRBid > LaaRAward And MCPCLaaR = Highest Price in the bid stack for last MW of LaaRAward And MCPCGen = Highest Price in the bid stack for last MW of GenAward MCPCBlended = (MCPCLaaR * LaaRAward ) + ( MCPCGen * GenAward ) LaaRAward + GenAward RRS = Total Amount of Responsive Reserves required (MW) LaaRMax = 50% of RRS or a lower amount as determined by a monthly engineering evaluation conducted by ERCOT staff LaaRSA = Amount of LaaR Self Arranged by QSE (MW) LaaRBid = Amount of LaaR Bids at or below the MCPCGen (MW) LaaRAward = Amount of LaaR Bids Awarded by the Market Clearing Engine-MCE (MW) GenSA = Amount of Generation Resources Self Arranged by QSE (MW) GenAward = Amount of Generation Resource Bids Awarded by the MCE (MW) MCPCLaaR = Market Clearing Price for LaaR ($/MW) MCPCGen = Market Clearing Price for Generation Resources ($/MW) MCPCBlended = Blended Market Clearing Price ($/MW)

13. D. LaaR RRS Offered Below MCPC is Prorated when Market Oversubscribed Proposed Solution: Solution awards LaaRs offered below the cleared MCPC and allocates LaaR RRS capacity across awards. Removes any incentive to submit negative bids. = LaaR offer = Gen offer = Self Arranged More than 1,150 MWs of LaaRs Offered Below MCPC Less than 1,150 MWs of LaaRs Offered Below MCPC Single MCPC Single MCPC 2,300 MW of RRS 2,300 MW of RRS = = Single Bid Stack Single Bid Stack

14. D. LaaR RRS Offered Below MCPC is Prorated when Market Oversubscribed Proposed Solution: Solution awards all LaaRs offered below the cleared MCPC and removes any incentive to submit negative bids. Solution was originally proposed by the Demand Side Working Group via PRR619 and was rejected by TAC in November. Pros: • Impact on ERCOT and Market Participants’ systems is minor and cost to implement is expected to be less than $50 K • Eliminates the incentive for LaaRs to bid negative • Need for secondary RRS solicitations unlikely Cons: • Requires QSEs to closely monitor LaaR awards and ensure that LaaRs “unarm” as required • Proration of all LaaR bids is likely and will be up to the QSEs bidding LaaR to manage the amount of LaaR armed at any one time to conform to Protocol limits (not perceived at this time to be a significant problem)

15. Protocol Revision Required for Alternative D 6.6.3.1 General Procurement Requirements (6) For each Ancillary Service procurement process, ERCOT shall select capacity bids submitted by QSEs, such that: (e) All QSE bids for RRS from LaaR, whose offer price is equal to or less than the MCPC, shall be awarded proportionately to meet the limit for LaaR providing RRS established in Section 6.5.4, Responsive Reserve Service.

16. High Level Overview of Solutions * Icon size represents relative impact when compared with other alternatives.

17. Next Steps • Narrow the field to two alternatives

18. Emergency Load Response Programs March 22, 2006

19. Emergency Load Response Program Update • DSWG given assignment to develop ELR Program for a 1 in 10 year loss of load event (LOLE); a probabilistic approach used to determine reserve margins & resource adequacy • ELR Program concept developed by ERCOT staff and market participants and presented to DSWG with mixed results • ELR concept presented to PUCT staff who were receptive to the idea; PUCT issues proposed Rule 25.505 (resource adequacy) • Proposed rule includes a “backstop” provision for emergency load response (ELR) contracts • ERCOT uses Projected Assessment of System Adequacy (PASA) analysis and reports need for ELR contracts • PASAs are done for Medium Term (looks out 3 years) and Short Term (7 days) • ELR contracts would be for no shorter than 90 days and no longer than 1 year • ELR Resources deployed thru EECP • Cost Recovery done on a System-wide Load Ratio Share • ELR Contracts do not replace other reliability based tools—Day Ahead AS Services, RUC, Black Start, and RMR/MRA

20. Emergency Load Response Program Update • ELR Resource Contracts require advance planning and procurement timelines • In general, ELR would not be used to respond to events outside of a peak resource adequacy condition such as • Cold Weather Fuel Curtailments • Shoulder month type events • Loss of multiple contingencies • Cost to provide coverage for expanded list of events may be prohibitive • RRS costs $130K per MW per year for 24x7 coverage • PUCT LM programs cover peak hours during the Summer and cost about $16K per MW for about 700 hours of coverage • Next steps: • Comment period is open for Proposed Resource Adequacy Rule • Stakeholder process will be used to develop implementation for Proposed Rule