- overview - need for iso market design

California Independent System Operator

A Comparison Between The CA ISO’s Market Design 2002 Proposal (MD02) and the FERC’s

Standard Market Design (SMD)

Presentation to The Committee on Regional Electric

Power Cooperation

Steve GreenleafDirector of Regulatory Policy

CA ISO

April 30, 2002San Diego, CA


CREPC CA ISO-FERC SMD April 30, 2002, page 2

- Overview -Need for ISO Market Design

• Current FERC price mitigation measures scheduled to end on September 30, 2002

• FERC December 19, 2001 Order required ISO to file revised Congestion Management and plan for a day-ahead energy market by May 1, 2002

• Fix existing design flaws to improve ISO’s ability to perform its core functions



Conformance with FERC Standard Market Design

• On March 15 & April 10, 2002 FERC issued Working Papers on Standard Market Design (SMD) – final Rulemaking expected in Summer, 2002

• ISO’s comprehensive MD02 proposal comports with the FERC design on key elements.



Conformance with FERC SMDDesign Element FERC SMD CAISO MD02

Transmission Service Network Access Service Yes Yes Transmission Rights (FTRs) Source-sink, simultaneous feasibility Yes Yes Allow Flowgate, Option rights in future as feasible Yes Yes

Preserve service quality of existing customers Yes Yes Accommodate Existing Transmission Contracts Yes Yes New Transmission Service – Network Access Service Yes Yes Long-term Generation Adequacy Measures to Ensure Adequacy Yes Yes Energy Markets Locational Marginal Pricing (LMP) Yes Yes Accommodates bilateral and self-schedules Yes Yes Accommodates Demand bidding Yes Yes Multi-part bidding in forward market Yes Yes Clearing Price Auction Yes Yes Uninstructed Deviation Penalties ? Yes Ancillary Service Markets Multi-part bidding in forward market Yes Yes Clearing Price Auction Yes Yes Accommodates Demand bidding Yes Yes Rational, least-cost procurement Yes Yes Congestion Management Simultaneous Transmission/Energy/AS procurement Yes Yes Bid-based, security constrained dispatch Yes Yes Market Monitoring & Mitigation Emphasis on market rules Yes Yes Local Market Power Mitigation Yes Yes



Comprehensive CA ISO Market Design Changes



Available Capacity (ACAP) ObligationRationale for ACAP• A root cause of the California crisis was the weakening

of the traditional "obligation to serve" – responsibility of load-serving entities (LSEs) to procure sufficient supply for peak loads and operating reserves

• The consequence was that responsibility fell on ISO as supplier of last resort – leading to a real-time scramble for resources to maintain reliability, and to extremely high prices in ISO markets and Out-Of-Market purchases – and resulted in over 13,000 OOM calls!

• Therefore, ISO proposes to address its needs – support of its core function, reliable grid operation – through Available Capacity (ACAP) Obligation



Key Objectives of ACAP Obligation

• Develop a mechanism that supports reliable operation of the system, consistent with the ISO’s statutory obligation under AB1890;

• Provide a vehicle through which market participants can contract, schedule and bid in the forward market, thus achieving two key goals of the market design– Moving operational decisions from real time to the

forward market.– Stabilizing spot-market prices by creating further

incentives for forward contracting and thus a platform for generation and demand-based investment.



Key Considerations in ACAP

• The ACAP proposal should be consistent with the ISO’s limited role in the energy market – that of supporting reliable system operation.

• Customers should not incur additional costs, through ACAP obligation, that do not enhance reliability.

• The ACAP obligation should not create a mechanism for exercising market power.

• ACAP should provide a platform for capital investment in the California energy market.



Integrated Forward Market Design

Centerpiece of the MD02 Design Proposal• Integrated Congestion Management, Energy Market, Ancillary

Services, Unit Commitment Service• Forward Congestion Management

– Locational Marginal Pricing (LMP) based on Full Network Model (FNM) – Enforcement of all network constraints ensures feasible schedules, consistent with physics of electricity flow

• Day Ahead and Hour Ahead Energy Markets– LMP-based congestion management requires energy trading to clear

congestion, thus creating a bid-based energy market– Eliminates Market Separation Rule and Balanced Schedule

Requirement– Accommodates optional balanced bilateral schedules

• Firm Transmission Rights (FTRs)– Point-to-point or "source-to-sink" rights needed to allow complete

hedging of risk under LMP congestion management



Locational Market Pricing (LMP)

• Provides hourly price signals that reflect physical constraints of system under all load and system conditions

• Locational price patterns indicate where additional generation and transmission upgrades are needed

• Nodal prices correctly charge grid users for their impacts on congestion

• Eliminates distinction between inter-zonal and intra-zonal congestion – manages ALL congestion in forward market to create feasible schedules

• For loads, locational price differentials will be mitigated by allocation of FTRs



Integrated Forward Market• Balanced schedules will be an option

– Physical bilaterals can obtain priority against curtailment for congestion via FTRs or as price takers for congestion charges

• Generator ramping schedules must be feasible• Simultaneous A/S market will procure Spin, Non-Spin

and Regulation– Replacement Reserve can be eliminated– Procurement based on Energy and Capacity bids

• Simultaneous Unit Commitment Service (UCS)– Self-commitment will be an option

• Energy, A/S, UCS – subject to transmission constraints• Residual Unit Commitment runs after integrated DA

market



Redesign of FTRs• LMP requires “source-to-sink” FTRs

– Hedge congestion charges calculated as nodal price differences– FTR specifies injection (source) and take-out (sink) points, ignoring

paths of flow– Requires "simultaneous feasibility" to define and allocate FTRs– End points may also be trading hubs or load aggregations– Physical scheduling priority still viable in day ahead

• Multiple FTR terms – 3-year, annual, monthly• FTRs are settled based on day-ahead prices• FTRs are "obligations" – failure to schedule may result

in liability for congestion charge in opposite direction– Proven algorithm for allocating rights– Strong incentives to buy FTRs consistent with expected use of grid– Considering need for "options" (no liability associated) and “flowgate”

rights in addition to basic source-sink obligations.



Redesign of FTRs• Allocation of FTRs

– FTRs to be allocated initially to Load Serving Entities (LSEs) on behalf of end-use consumers, based on historical use of the grid

• Allocation to LSEs hedges consumer risk of location-based pricing– Residual FTRs (FTRs in excess of those allocated to LSEs) will be

auctioned by the ISO with revenues allocated to Transmission Owners

• Converting ETCs to FTRs– Ultimate objective – all grid users subject to same scheduling procedures

and time line– Eliminate "phantom congestion" due to current ETC scheduling time line– Conversion may require more complex FTR model (obligations, options;

source-sink, flowgates), requiring unproven allocation algorithms• ETC rights not all the same – one conversion approach may not satisfy

all ETC holders

– Transitional approach may be to implement Recallable Transmission Service (RTS) to reduce phantom congestion impact, while pursuing ETC-to-FTR conversion on a longer time frame



Load Scheduling and SettlementISSUE – What is the appropriate granularity of load scheduling

and settlement? • Option A – most aggregated level – current congestion zones

(NP15, ZP26, SP15) or PTO areas (PG&E, SCE, SDG&E)– Proposed for trading hubs, but not for load scheduling because of

near total elimination of any locational price signal to loads

• Option C – finest level – nodal – Proposed as option for loads, but not requirement, because of

implementation difficulty

• Option B – intermediate – "Load Aggregations" – Existing Demand Zones and Load Groups– Custom aggregations to reflect a LSE's actual load pattern– => Modified Option B2 – provide FTRs (or FTR auction revenues) to

loads to hedge (or compensate) risk of congestion charges.

• Under all aggregations – congestion management distributes aggregate loads to nodes – aggregation prices are load-weighted averages of nodal prices.



Issues re Load Settlement• Primarily an equity issue

– Loads should not be at risk for price impacts of congested areas, because grid was not built under a locational-pricing paradigm and is not adequate to allow all areas of the grid to enjoy equal benefits of competitive generation supply.

– Will impose competitive disadvantage on non-utility LSEs and their Direct Access customers, since these LSEs are not able to average wholesale costs across large areas.

– Possible solutions:• Phase in granular pricing for loads in conjunction with transmission

upgrades in severely constrained areas.

• Provide FTRs (or FTR auction revenues) to loads in constrained areas as hedge or compensation for congestion risk.

• Proposal – Option B2 – settle at demand zones initially and provide FTRs to loads to mitigate locational price risk, AND, re-invigorate transmission planning process



Hour Ahead Market

• Revision of HA Market Time Line– Simultaneous congestion management, energy, AS and unit

commitment, same as DA

– ISO proposes to close HA and Real-time Markets at the same time, i.e., T-60 (60 minutes before start of Operating Hour)

– Energy bids not cleared in HA would become bid pool for real time imbalance energy

• Need for Hour Ahead Settlement– Only California ISO has 3-settlement system

– HA settlement provides a means to limit exposure to real-time imbalance energy charges and deviation penalties

– Allows late energy trades to schedule available transmission.



Real Time Economic Dispatch• Security-constrained, using Full Network Model

– Considers all transmission constraints, loop flows, local reliability needs, generator operating constraints, as well as imbalance energy needs.

– Same network model as forward markets; no distinction between inter-zonal and intra-zonal congestion.

• Produces real-time 10-minute nodal prices– Congestion costs implicit in nodal price differences

– Generators settle at nodal prices

– Real-time load deviations may settle at nodal prices or aggregation levels (demand zones)



Process Going Forward• May 1, 2002 – CA ISO files MD02 proposal at FERC, including

tariff language for October 1, 2002, elements.

• June 15, 2002 – CA ISO files balance of proposed tariff language at FERC – long-term elements.

• July 1, 2002 – FERC rules on elements of MD02 proposed to be in place on October 1, 2002, when West-wide mitigation terminates.

• Fall, 2002 – FERC rules on long-term elements of MD02, including ACAP, LMP, etc.

• Spring, 2003 – CA ISO implements second phase of redesign proposal, including integrated forward-market congestion management, energy and AS market (zonal).

• Fall, 2003 – CA ISO implements final phase of MD02 – full LMP model implemented.

- overview - need for iso market design

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