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

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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_at_mailbmc.com

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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

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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

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Current ERCOT Zonal Market
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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

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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

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Future Texas Nodal Market
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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

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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

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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

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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)

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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

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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

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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

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ERCOT CREZ Transmission Scenario 2
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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

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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)

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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

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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

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TXU NOV

• Staffs allegations included
• TXUs actions raised prices in BES market by
  11.4
• TXUs 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 staffs penalty
  calculation should not be on a MW basis

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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
  ERCOTs 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

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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)

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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