Comparison of RTOW, WestConnect, and CAISO Proposed Market Designs

with FERC’s Standard Market Design – April 26, 2002

 

FERC STANDARD MARKET DESIGN

WESTCONNECT PROPOSED

RTO West                    

CAISO PROPOSED (9/30/02)

CAISO PROPOSED (long-term)

 

NOTE: This is a summary of positive statements and questions posed in paper; blanks indicate no position articulated in paper.

NOTE:  The elements below describe the WestConnect proposals as contained in their October 2001 FERC filing.

Note: Based on 3/29/02 Filing. Blanks indicate those that no position was taking in the filing.

NOTE: The elements described below reflect the current status of a work in progress. 

NOTE: The elements described below reflect the current status of a work in progress. 

MARKET DESIGN

 

 

 

 

 

Prior to Day Ahead

 

 

 

 

 

Capacity Obligation &/or Market

State and Regional reliability authorities to coordinate setting long-term reserve margin to be maintained by LSEs subject to their jurisdiction.

No capacity obligation as such.  However, the requirement to submit Balanced Schedules and the penalties associated with under-scheduling and leaning on the Balancing Energy market should encourage the Scheduling Coordinators (SCs) to have sufficient capacity available to meet demand plus reserve obligations.

 

Available Capacity (ACAP) Obligation:

 

Load-serving entities (LSEs) will have an Available Capacity Obligation, defined as a margin above their monthly peak load, to be met by a combination of own generation, firm energy contracts, capacity contracts, and demand-side management. ISO will verify compliance monthly. At this time, no LSE penalty for failure to meet ACAP obligation is expected to be applied before April 1, 2003.

 

For the September 30, 2001 implementation, the ISO is considering a transitional ACAP the nature of which will depend on whether or not FERC extends the west-wide mitigation beyond Sep. 30; the ISO is also considering extending the “must offer” obligation to serve California in return for some type of capacity payment.

Available Capacity (ACAP) Obligation:

Load-serving entities (LSEs) will have an Available Capacity Obligation, defined as a margin above their monthly peak load, to be met by a combination of own generation, firm energy contracts, capacity contracts, and demand-side management. ISO will verify compliance monthly and assess penalties for any shortfall. Designated ACAP resources will be required to be fully scheduled or bid into ISO markets to serve ISO control area load (and specifically, except for Long Start Time units not scheduled in the day-ahead market for energy or A/S, and not committed in the Residual Unit Commitment, bid all unscheduled available capacity in ISO’s real-time market), and daily performance will be monitored. ISO verifies that load-serving entities meet their capacity obligations.

 

NOTE: The ISO has commissioned a consultant to work out the details of the ACAP design; ISO has discussed the detailed design for stakeholder feedback and plans to file with FERC in on May 1, 2002.

FTR Auction/Release

 

Financial or Physical

 

 

Financial

 

 

Physical.  Firm Transmission Rights (FTRs), Recallable Transmission Rights (RTRs), Non-firm Transmission Rights (NTRs) or Non-Converted Rights (NCRs – rights associated with Existing Contracts not converted to WestConnect service) (together simply referred to as FTRs or Transmission Rights) required to schedule use of FTR Interfaces (internal congested interfaces) and Scheduling Points (connections to other control areas).

 

Financial

 

Financial with a day-ahead physical scheduling priority

 

 

Financial (Considering day-ahead physical scheduling priority on point-to-point FTRs)

 

Option or Obligation

Both option and obligation for source to sink rights as well as Flowgate rights

N.A., as there is no revenue stream associated with holding an FTR.

 

Options (Called Financial Transmission Options or FTOs)

Option

Both option and obligation for point to point FTRs as well as FGRs (Flowgate Rights)

Revenue Stream/ or Offset CM Cost

Hedge for CM, not required for scheduling

 

Not applicable, as limiting the scheduling of the use of FTR Interfaces and Scheduling Points to those holding FTRs is designed to minimize congestion.  Intra-zonal congestion socialized.

 

Offset CM Cost

Revenue stream on specific path

Allowing purchase for revenue stream as well as hedging for scheduling

Duration

Not specified

 

Each FTR is for one hour.  Annual auction of annual blocks of FTRs, based on minimum number of FTRs available in any month.  Monthly, sub-monthly and daily auctions of any additional blocks of FTRs available.

 

 

Those from contract conversion, for the life of the contract.  Those from auction, term to be specified when auction designed.

Annual (individual hours can be traded in secondary market)

 

Three-year (30% of minimum ATC), Annual (45% of minimum ATC), and Monthly (the rest of ATC) ; allowing secondary trades of individual hours

Definition

 

Should offer both:

Ø   point-to-point (e.g. TCCS or NY/PJM FTRs) and

 “flowgate” or path-specific rights (closed loop)

A Transmission Right is the right to schedule the delivery of one (1) MW of Energy or Ancillary Services in a specific direction across an FTR Interface or Scheduling Point for one (1) hour

 

From Injection Points  to Withdrawal Points

Direction and path specific (open loop/contract path)

Direction specific (accounting for parallel path flows)

All of below:

Ø       point-to-point

Ø       point-to-hub

Ø       hub-to-hub

Ø       hub-to-point and

Ø       Considering additional “flowgate” or path-specific rights (closed loop)

Primary Release Mechanism

Possibility of initial allocation to customers that pay the embedded costs of the system. Also possibility of auction (with proceeds credited to customers who paid for the system)

Auction

 

Either by (1) conversion of rights in existing contracts and obligations or (2) purchase at auction from RTO West.

Rights pooled in Cataloged Transmission Rights (CTRS) for unconverted contracts and obligations which settle in the same manner as FTOs.  Parties with CTRs may exercise optionality and release capacity to RTO West auctions by early submit early schedules and accepting any resulting added congestion cost.

 

Auction

 

Auction

 

Secondary Market

Possibility for secondary trading with no RTO involvement.

Will not operate a secondary market.  Requires FTR holders to register final trades in secondary markets if they are to be recognized in the Balanced Schedule validation process.

 

 

Tradable for use by other Scheduling Coordinators

 

ISO does not operate a secondary market, but requires FTR holders to register secondary trades.

Will not operate a secondary market, require FTR holders to register secondary trades.

Day Ahead

 

 

 

 

 

Energy Spot Market

 

 

Integrated with Congestion Management; simultaneous forward Energy, Congestion and Ancillary Service markets (see below)

 

None.

None, Day-Ahead Congestion Clearing Market only.

 

No forward energy market facilitated by the ISO for the September 30, 2002 implementation.

 

 

Integrated with Congestion Management: Simultaneous forward energy, Congestion and Ancillary Service markets (see below)

 

 

Congestion Management Market

 

Model spatial granularity

 

 

 

 

Nodal pricing

 

 

 

Full network model used to define and manage inter- and intra-zonal congestion.

 

Nodal pricing

 

Zonal; radial model. Any congestion within zones is ignored in forward CM and mitigated in real time.

.

 

 

 

Full network model (3000 busses  including external loops)

 

Model objective function

Integrated with DA energy market (optimized simultaneously); bid cost minimization

Security constrained economic dispatch of balancing energy market, including dispatch to manage inter- and intra-zonal congestion and minimization of deviations from SC schedules.  Resources designated to provide operating reserves normally not dispatched unless there is a contingency.

Minimize cost of congestion clearing

DC optimal power flow with market separation

Optimal power flow (tending towards DC OPF with pre-computed GMMs) without market separation (allowing for voluntary market separation)

Schedule Components

Bid-based

 

Settlement based on nodal prices; possibility to define trading hubs

Requires a Balanced Schedule, including:

-    Generation;

-    Demand;

-    Imports/exports;

-    Inter-SC trades of energy and Ancillary Services;

-    Transmission & Distribution Losses;

-    Ancillary Services, self-provision and offers; and

-    Required Transmission Rights

 

Inc/Dec bids for congestion clearing from supply and demand-side.

Schedules may indicate  party’s desire to have schedule eliminated if congestion cost exceeds a threshold price set by the scheduler.

Day-Ahead Settlement on congestion clearing nodal prices when Day-Ahead schedules become firm commitments.

generation schedule at nodes at hourly intervals;

Loads schedule at Demand Zones at hourly intervals

optional inc/dec bids on generation and loads used for CM

Generation schedule (and settle) at nodes at hourly intervals; LPAs act as trading hubs;

Loads schedule (and settle) at LPA level at hourly intervals;

optional inc/dec bids on generation and loads used for both CM and energy trades

Provision for 3-part bids (cost-based start-up and minimum-load; bid-based energy)

Other Scheduling Requirements

 

Accepts balanced or unbalanced SC schedules. (No balanced schedule requirement)

 

Provides for local (out of merit order) market power mitigation

There are Day-Ahead auctions of unused FTRs as RTRs, release of NTRs, and a scheduling process for provision of Local Generation Resource (LGR) service.

 

Schedules submitted must be balanced.

 

Requires balanced schedule

Accepts balanced or unbalanced SC schedules.

Require generation feasibility.

Proxy prices to be on file for mitigating congestion with no competitive inc/dec bids.

Congestion Prices

Congestion Price (including losses) is calculated as difference between 2 locational prices;

 

Acceptance of schedule is physical transmission right – right to physically inject energy at a location and simultaneously physically withdraw energy at another location.

 

No congestion costs are socialized

The prices (through auctions or secondary markets) of the various types of FTRs required for scheduling, plus any socialized intra-zonal congestion.

Price difference between Injection Point and Withdrawal Point.  RTO West loss methodology for new and converted service yet to be determined.

All balanced schedules accepted subject to RTO West’s ability to clear congestion.

Congestion prices in forward market are the difference between marginal INC and DEC bids (of the marginal SC) accepted for redispatch to clear congestion across the interface

Congestion prices (including the cost of losses) in forward market are the difference between hourly nodal energy prices. 

Ancillary Service Market

Services

 

 

Operating Reserves Market required of RTO:  including at least AGC and 10-minute operating reserves.

 

 

Regulation, Load Following Up, Load Following Down, Spinning Reserves, Non-spinning Reserves, Balancing Energy, Supplemental Energy, Voltage Support, Scheduling & Dispatch, Black Start, Congestion Redispatch, and LGR.

 

Markets for Regulation and Frequency Response, Load Following Up, Load Following Down, Spinning Reserve, Non-Spinning Reserve, Replacement Reserve, Congestion Redispatch, Supplemental Energy, Balancing Energy, Voltage Support and Black Start

Spinning Reserves, Non-Spinning Reserves, Replacement Reserves,  Regulation Up, and Regulation Down

 

 

Spinning Reserves, Non-Spinning Reserves, and Regulation

 

ISO Acquisition or Self-provision

 

Both

 

Both for the first five above, at the SC’s discretion.  WestConnect provides the last seven (which it acquires on a competitive basis).

Both

Both, SC’s option

 

Both, SC’s option

 

Acquisition Mechanism

 

Simultaneously auction with DA energy and CM markets.

 

 

\

Bids.  Primarily Day-Ahead, but longer term for Voltage Support and Black Start.

 

Competitive bid

Auction after CM market closes; award based on capacity bids only; markets for Regulation (Up an Down), Spin, Non-spin, and Replacement cleared sequentially in that order; Rational Buyer procurement allows demand substitution, i.e., procurement of higher quality A/S in the sequence to substitute for the lower quality A/S when doing so reduces total A/S procurement cost.

Simultaneous auction with energy based on bid-cost minimization (rather than the Rational Buyer type payment minimization objective function)

Bid Components

Both generators and demand-side participants to offer products that meet requisite technical requirements

 

Permit submission of both capacity availability and energy bids

Daily capacity bids for Regulation, both Load Following and both Operating Reserves.  Daily energy bid curves for those five (5) Ancillary Services plus Supplemental Energy, Congestion Redispatch and, as applicable, LGR service.  To be developed for Voltage Support and Black Start.

Yet to be determined

Regulation and Reserves: Bidders submit capacity and energy bids; energy bids are not used in the A/S capacity auction; they can be changed following the capacity auction; energy bids (except for Regulation) will compete in the real-time market with supplemental energy bids to determine dispatch merit order.

Energy and capacity bids will both be considered in the simultaneous auction; once selected, energy bids associated with the selected A/S capacity would not be allowed to be modified

Centralized Unit Commitment.

 

 

RTO to provide Unit Commitment service allowing submission of multi-part energy bids, star-up, and minimum loads, and various operating constraints in conjunction with integrated Energy/Congestion Management market.

 

None.

None; voluntary self-commitment based on balanced schedules.  RTO will make its own load forecast to insure the adequate capacity is on line to meet load in Real-time.

 

 

Residual Unit Commitment (RUC):

Following the day-ahead market, ISO runs the Residual Unit Commitment “market”. If submitted schedules (final schedules clearing the day-ahead market) do not fully reflect ISO load forecast, ISO may commit additional units to ensure adequate capacity on-line. Designated ACAP resources are required to be available for unit commitment.

Resources committed by the CAISO will be guaranteed recovery of appropriate start-up and minimum load cost, using a net-of-market-revenues approach. Imports may compete with internal (or external) resources in the RUC. Competitive imports selected in RUC will be pre-dispatched for the real-time market operation; they will not be allowed to set the real-time price, but will be paid the bid price based on which they were selected in the RUC. To limit the impact of RUC import pre-dispatch on the real-time market operation, commitment to import energy in RUC will be limited such that the total supply clearing the day-ahead market plus the resource-specific minimum load and the RUC import energy do not exceed 95% of ISO’s load forecast.  

 

 

Day-ahead Unit Commitment Service (UCS); allowing submission of 3-part bids (cost-based or 6-month fixed start-up and minimum-load; bid-based energy), along with technical and inter-temporal constraints (start-up time, minimum run time, minimum down time, all based on technical parameters filed with the ISO). Resources committed by the CAISO (not self scheduled for any hour of the day-ahead market) will be guaranteed recovery of relevant start-up and minimum load cost, using a net-of-market-revenues approach.

 

Residual Unit Commitment (RUC):

Following the day-ahead market, ISO runs the Residual Unit Commitment “market”. If submitted schedules (final schedules clearing the day-ahead market) do not fully reflect ISO load forecast, ISO may commit additional units to ensure adequate capacity on-line. Designated ACAP resources are required to be available for unit commitment.

Resources committed by the CAISO will be guaranteed recovery of appropriate start-up and minimum load cost, using a net-of-market-revenues approach. Imports may compete with internal (or external) resources in the RUC. Competitive imports selected in RUC will be pre-dispatched for the real-time market operation; they will not be allowed to set the real-time price, but will be paid the bid price based on which they were selected in the RUC. To limit the impact of RUC import pre-dispatch on the real-time market operation, commitment to import energy in RUC will be limited such that the total supply clearing the day-ahead market plus the resource-specific minimum load and the RUC import energy do not exceed 95% of ISO’s load forecast.  

 

Release of Un-used Transmission Capacity after Close of DA Markets

 

 

Transmission capacity sold in DA that is not used by DA purchaser in RT should be made available for FT energy market

 

RTRs (i.e., unused NCRs, as allowed by the associated Existing Contract (EC) and FTRs sold Day-Ahead on a recallable basis) can be recalled until two (2) hours prior to the start of the Settlement Period (hour) for use by the original FTR holder.  NTRs can be recalled at anytime.

Rights are only congestion hedges and are not required to submit schedules.  FTOs and CTRs settle against Day-Ahead Market.

None (all transmission allocated in congestion management is firm)

 

Recallable Transmission Service:  Following allocation of firm transmission in CM, ISO runs recallable transmission service (RTS) using unscheduled ETC capacity.[1]

Hour Ahead

 

 

 

 

 

 

Timing

 

 

 

The Schedule Adjustment Process ends one (1) hour prior to the start of the Settlement Period.

 

 

 

Considering moving closer to real-time

 

 

 

Considering moving closer to real-time

[Considering simplification, and possibly making it advisory in the future when ISO implements a day-ahead unit commitment service with 3-part bids (for start-up, no-load/min-load, and energy)]

 

Energy Market

 

SCs can adjust their energy schedules so long as the overall schedule remains balanced and includes any required Transmission Rights.

 

None

See DA

Congestion Management Market

 

 

None, per se.  Continue required use of Transmission Rights to manage congestion on FTR Interfaces and Scheduling Points and use of Congestion Redispatch bids to manage intra-zonal congestion.

 

See DA

See DA

Ancillary Services Market

 

WestConnect will conduct an on-going Ancillary Services procurement process, as necessary, to meet additional requirements, including replacement of previously committed Ancillary Services

 

See DA