SUMMARY OF CPUC COMMENTS ON
ISO MARKET REDESIGN PROPOSAL

Framework

• ISO Redesign should address fundamental problems at root of recent crisis, to ensure reliable supply at reasonable prices.
   
• ISO procurement role should be minimized. ISO and CPUC procurement policies should ensure that spot market transactions are minimized, and that load-serving entities take responsibility for meeting load.
   
• ISO short run markets should not be the primary vehicle to recover capital costs. Suppliers should expect to recover the bulk of their capital costs through longer-term bilateral contracts.
   
• ISO focus should be on reliable management of grid. Rules should ensure ISO’s ability to do so. Zonal congestion management system should be replaced with congestion management system which expressly recognizes all system constraints, on the PJM model.

Critical Design Elements

Adopt "nodal" congestion management model, in an integrated day-ahead process, on the PJM model

• Integrated, co-optimized, day ahead process addressing congestion management, energy trades, Ancillary Services, unit commitment, least cost central dispatch.
  
  PJM performs least cost dispatch using suppliers’ marginal cost curves.
   
• Nodal pricing. Eliminate zones and current distinction between "intra" zonal and "inter" zonal transmission congestion.
   
• Incorporate generator ramping constraints and other performance constraints.
   
• Require suppliers to submit single, unit-specific, bid curve for all purposes for 24 hour period. No separate real time energy or Ancillary Services bids.
  
  Suppliers no longer permitted to game markets by submitting multiple bids for multiple purposes in multiple markets in single 24 hour period.
  
  As part of a single bid curve, suppliers can bid different prices for various hours, and can bid different prices for various ranges of output because production costs can change as more or less is produced. The important element of reform is that suppliers are not allowed to submit different sets of bids for various purposes at different times of the day.
  
  "Portfolio" biding without identifying the generating unit producing the power facilitates market manipulation, and should be prohibited.
  
  PJM uses a single bid curve. FERC’s chairman expressed concern at a recent FERC technical conference on market design that multiple bids enable suppliers to manipulate the market.

Rules must effectively replicate/make permanent must-offer and bid mitigation features of current mitigation plan

• Legally supportable: See Colton Power, 98 FERC ¶ 61, 059 (Jan. 30, 2002) (approving new market-based rates for Colton) ("Colton Power is exempt from the SMA screen and, instead, is governed by the specific thresholds and mitigation measures approved for the California ISO market. Those mitigation measures will expire on September 30, 2002. If there is not a sufficient Commission-approved superseding mitigation regime in place at that time, Colton Power and all other sellers into the California ISO market will need to undergo review of their market-based rate authority based on the SMA screen, or such other Commission-approved market power analysis in place at that time." (footnotes omitted and emphasis added)); See also Huntington Beach Development, L.L.C., 96 FERC ¶ 61,212, reh'g denied, 97 FERC ¶ 61,256 at 62,127 (2001) (same).
   
• Must-offer provision to prohibit physical withholding: 
  
  The ISO proposes a capacity/reserve obligation (called "ACAP") with availability features to replace the "must-offer" provision.
  
  The CPUC is the agency that should direct and oversee the jurisdictional investor-owned utilities’ resource planning and procurement activities. The CPUC is developing the needed rules in its procurement proceeding. Any ISO capacity mechanism must complement CPUC procurement policies.
  
  To the extent ISO proceeds with ACAP market necessary features must include:
  
    # participation requirements (e.g. all units in ISO control area must offer otherwise uncommitted capacity in capacity market);
  
    # availability requirements (all ACAP participants must be fully scheduled or bid into integrated day-ahead process);
  
  Capacity price cap or equivalent mechanism will be necessary to avoid pushing market power to capacity markets (particularly for units with locational market power)
  
  CPUC and ISO procurement/capacity rules should expressly provide for reserve-sharing
   
• Bid Mitigation mechanism to prohibit economic withholding
  
  ISO must establish marginal cost bid rules for energy markets. Both economic theory and FERC’s legal precedent provide support for this approach.
  
    # The theoretical validity of MCP pricing rests on the assumption that suppliers in a competitive market will bid their true marginal cost. Experience has shown that suppliers in the California market bid above their marginal cost most of the time. To ensure defensibility of the MCP, the ISO must require that suppliers bid their marginal cost.
  
    # PJM requires engineering cost curves and marginal cost bids for pre-1996 units and is considering expanding this requirement to all generating units.
  
    # Courts have held that competition must produce prices analogous to regulated prices. Regulation in turn attempts to administratively replicate competitive prices—that is, those produced by marginal cost bidding
  
    # Bid rules are not the same as price caps. Although FERC is generally not supportive of price caps, FERC has previously approved marginal cost-based bid rules in both California (never implemented prior to the crisis) and New England markets (New England Power Pool, 85 FERC ¶ 61,379 (1998), 1998 FERC LEXIS 2518 at *72, *113-114; Pacific Gas & Electric Company, 81 FERC ¶ 61,122 at 61,537-48 (1997)).
  
    # Supplier concerns about lack of contribution to fixed cost recovery under marginal cost bidding are misplaced. As volume in short term market is diminished, suppliers should expect longer term contracts to primarily contribute to fixed cost recovery. Infra-marginal sellers (all sellers except highest-cost seller setting MCP) will also receive contributions to fixed costs through spot market sales under marginal cost bidding rules with market clearing price mechanism.
  
    # Scarcity rents reflective of market power and so-called "opportunity costs" have no place in electricity markets. Scarcity value is accommodated under marginal cost bid rules as progressively higher marginal cost units are dispatched and the MCP rises to reflect such higher marginal costs.
  
  Marginal cost bid rules applicable to all suppliers in ISO spot energy and Ancillary Services markets, not just limited to units with recognized locational market power.
  
  Enhanced monitoring and real-time mitigation powers for DMA. (The NYISO has very effective monitoring and mitigation which might be used as a model).
  
  Consider a consistent approach throughout WSCC to address potential for renewed MW laundering.

Physical approach to grid management and markets

• Schedules must be real
  
  load must provide realistic schedules in integrated day ahead process within a range of accuracy (probably 5-10%).
  
  supply committed in integrated day process must in fact perform as scheduled.
   
• Dispatch must be enforceable and enforced – generators must perform in accordance with ISO dispatch instructions.
   
• Primary purpose of Firm Transmission Rights ("FTRs") is assuring transmission, not investment vehicle.

Consider adopting PJM approach to locational market power to replace RMR contracts

• PJM does not pay any fixed costs outside of the market to RMR plants. PJM mitigates their locational market power by requiring that these units bid their marginal cost. These units receive the system-wide locational marginal price (LMP) or 115% of their variable cost whichever is higher.

Simplify and hasten ISO settlements