TEXAS ELECTRIC MARKET: Issues Presently Confronted by a Restructured Electric Market in Transition

1. TEXAS ELECTRIC MARKET: Issues Presently Confronted by a Restructured Electric Market in Transition 2009 Oil, Gas, and Energy Law Symposium Marianne Carroll BROWN McCARROLL, LLP mcarroll@mailbmc.com

2. BACKGROUND • Texas Wholesale Market was restructured (rates deregulated) in 1995 • Texas Electric Restructuring Law (Senate Bill 7, 1999) • ERCOT becomes the Independent Organization, Grid Operator – 2001 • Retail Customer Choice introduced Jan. 1, 2002

3. Current Zonal Wholesale Market Design • Uses theoretically simplified assumptions for management of transmission congestion • Four zones, subject to annual changes • Portfolio bidding by resources • Interzonal congestion costs directly assigned • Intrazonal congestion costs uplifted to load

4. Current ERCOT Zonal Market

5. Problems with zonal market design • Fails to adequately reflect the actual operating characteristics of the transmission system • Provides incentives and opportunities for market manipulation • Forces cross-subsidization • Fails to provide adequate price signals for addition of new resources where needed

6. Nodal Markets • Nodal market – every generator bus is modeled and bids submitted to ERCOT on a unit-specific basis for centralized dispatch based on economic efficiency • All congestion costs directly assigned to resources • Loads settled based on an aggregation of the nodal prices within a zone • Load Serving Entities (LSEs) have new options to hedge against congestion costs through the use of Congestion Revenue Rights (CRRs), which are auctioned monthly and annually

7. Future Texas Nodal Market

8. Nodal Market Design • Based on management of congestion using 4000 nodes, resulting in 4000 Locational Marginal Prices (LMPs) • LMP is the offer-based marginal cost (including energy and congestion) of serving the next MW at a given node. • Because of this granularity, LMP markets provide a high level of market transparency, with directly observable consequences of market behaviors • Day ahead unit commitment plus real time unit-specific, 5-minute dispatch will yield operational benefits and vastly increased efficiency

9. Transition to a nodal market design • Three-year PUC process • Cost-benefit study • $900M annual savings for load • Additional $1B annual savings in production costs • One-time costs to implement = $150M • Benefits to customers in all zones • Stakeholder process to design the details • Nodal Protocols approved by PUC in March, 2006 • Implementation date Jan. 1, 2009

10. Nodal Market Implementation - Delayed • Joint decision by market participants and ERCOT to build a “best of breed” nodal solution, and to deploy nodal with a Common Information Model (CIM); special features for NOIEs • Program controls inadequate • Vendor deliveries missed; ERCOT staff missed requirements deadlines • Problems surfaced when integration of the several modules was attempted

11. Nodal Market Implementation - Delayed • PUC required that the 2004 Cost Benefit Analysis be “refreshed” • Revised “go live” date is December, 2010 • Revised cost: $660 million • Effect of additional Nodal Protocols Revision Requests (NPRRs)

12. 2008 Cost Benefit Analysis • Cost - $222 million to continue • Systemwide net benefits - $520 million • Consumer benefits - $5.6 billion • Other nodal market benefits include: • Reduced operational challenges for ERCOT • Increased efficiency through day-ahead unit commitment • Minimization of price excursions • Greater price transparency • Price signals for generation siting

13. Nodal Implementation Issues • Role of Transition Plan Task Force (TPTF) • Lock down on design changes? • Entering critical integration and testing phases • Field Marshall/Nodal Czar to bring nodal project in on time and on budget? • Nodal surcharge fee

14. CREZ Case (Parts I and II), Docket 33672 • Interim order, issued 11-6-07, designates: • Zones 5-6 (West Texas, near McCamey) • Zone 9A (near Abilene) • Zone 19 (just south of Panhandle) • Zones 2A and 4 (Panhandle; Zone 1 included in 2A) • ERCOT CREZ Transmission Optimization Study, filed April 2, 2008 • 4 Scenarios proposed: • 12.053 MW $2.95B • 18,456 MW $4.83B • 24,859 MW $6.22B • 24,419MW $5.46B • Scenario 2 chosen; Order issued 10-7-08

15. ERCOT CREZ Transmission Scenario 2

16. CREZ Case, Part III, Docket 35665 • Designation of Transmission Service Providers (TSPs) to construct segments of the CREZ Transmission Plan (CTP) • 6 IOUs, 5 new TSPs, 4 coops, 3 munis, 2 consumer groups, 20 wind developers • Hearing Dec. 1-5, 2008

17. Further CREZ-Related Proceedings • CTP CCN applications to be filed within 1 year of CREZ order by designated TSPs • Project 34577: • dispatch priority for CREZ wind projects • Posting of collateral by wind project developers (10% of pro-rata share of estimated capital costs of CTP)

18. Other Wind Generation Issues • Integration Issues (Need for additional quick-start capacity, better weather forecasting, voltage ride-through, reactive power requirements, VFTs, effects on MCPE) • Ancillary Services optimization (procurement and deployment) and assignment of costs (Responsive Reserves, Non-Spin and Regulation) • Project Siting Authority? • King Ranch/CHA Case

19. Retail Electric Providers • Several REPs failed in 2008 (high prices, poor business decisions) • Some customers lost fixed price contracts, moved to POLR or other providers • PUC proposed new rules for REP certification, including credit requirements and financial reporting, and disclosures to customers • New rulemaking project to address switching procedures

20. TXU NOV • Staff’s allegations included: • TXU’s actions raised prices in BES market by 11.4% • TXU’s profits from abuse were $18.8 million • TXU increased cost of BES by $57 million • Staff recommended administrative penalties of three times the increased cost (or damage) to the market, or $171 million • Settlement adopted by PUC: $15 million • Discussion points: energy offers expected to include a return component; staff’s penalty calculation should not be on a MW basis

21. Entergy • Project 32217: Entergy Integration Report by ERCOT, filed Dec. 2006 • Docket 33687 • Filed Jan. 2007 (costs and timeframe for infrastructure development; production cost estimates; required regulatory filings; impact on ERCOT’s CDR; PTB; milestones) • Commissioners ordered EGSI to provide analysis of costs/benefits of remaining in SERC, and to pay SPP to complete study; abates case • SPP study filed in Dec., 2008; case resumed Jan. 2008

22. Entergy • ERCOT Phase II study update: reliability project costs of $489 million; economic project costs $287 million. • SPP study: reliability project costs of $105 million; economic project costs of $240 million • Costs of staying in SERC: $161 million (if Cottonwood stays); $390 million (if Cottonwood goes to ERCOT)

23. Looking Forward: Issues for the Upcoming Legislative Session • Nodal Market Implementation • Electricity Prices, including single clearing price market • Address causes and effects of Retail Electric Provider (REP) failures • Wind generation siting and ancillary services costs • Transmission system “hardening” • Re-regulation