California ISO October 1, 2002 Market Design Elements California ISO - - PowerPoint PPT Presentation

California Independent System Operator 1

California ISO

California ISO October 1, 2002 Market Design Elements

California ISO Board of Governors Meeting April 25, 2002

Presented by Keith Casey Manager of Market Analysis and Mitigation ISO Department of Market Analysis

California Independent System Operator 2

California ISO

Board Action on April 9, 2002

1. Approved ISO Management’s recommendation to seek an extension

• f June 19, 2001 West-wide Mitigation Measures.

2. Approved “in concept” with some modification the October 1, 2002 Design Elements.

– Modifications

• Eliminated Transitional ACAP
• Changed penalty for negative Uninstructed Deviations from 25% to 50% of

BEEP interval Ex-post price.

3. Instructed ISO Management and ISO MSC to

• Provide additional justification for the proposed Damage Control Bid Cap
• Reexamine whether imports should be subject to AMP
• Reexamine whether AMP Bid Reference Levels should be bid-based or

cost-based.

• Provide an analysis of the impact of using a fixed percentage (e.g. 10%)

versus a fixed $/MWh amount (e.g. $5/MWh) as the trigger threshold for the 12-month Market Competitiveness Index.

California Independent System Operator 3

California ISO

Requested Board Action for April 25

1) Final approval of measures needed when June 19 Order expires:

a) Bid Screen Mitigation (AMP) b) Damage Control Bid Cap

2) Final approval of measures needed regardless of whether June 19 Order expires:

a) Residual Unit Commitment b) Single Energy Bid Curve (DA, HA, & RT Market) c) Real-time Economic Dispatch (Elimination of Target Price )

• Previously filed Amendment 42

d) Modified Must-Offer (limited to non-hydro PGA resources) e) 12-Month Market Competitive Index and Pre-authorized Additional Mitigation Provisions. f) Other measures

• Uninstructed Deviation Penalties (Previously filed Amendment 42)
• Negative Damage Control Bid Cap
• Recovery of Generator Emission Costs
• Local market power bid mitigation (Previously filed Amendment 42)

California Independent System Operator 4

California ISO

Presentation Outline

• Review major modifications to 10/1 Market Design Elements

– Damage Control Bid Cap (DCBC) – Negative Damage Control Bid Cap – Bid Screens and Automatic Mitigation Procedures (AMP) – 12-Month Market Competitiveness Index – Local Market Power Mitigation

• Review of other 10/1 Market Design Elements

– Real-time Economic Dispatch (Elimination of Target Price) – Uninstructed Deviation Penalties – Residual Unit Commitment Process – Single Energy Bid Curve (DA, HA, RT) – Modified Must-Offer – Recovery of Generator Emission Costs

• Request final approval of October 1 Design Elements

California Independent System Operator 5

California ISO

Damage Control Bid Cap (DCBC) & Automatic Mitigation Procedures (AMP) are Complementary Mitigation Measures

• DCBC

– Limits the magnitude of price spikes – Sets a limit on the maximum bid price the ISO will accept in its markets (energy & ancillary services). – Will start at a low level and increase over time as market conditions improve.

• AMP

– Limits the frequency of price spikes. – Compares bids with Reference Levels – If bids

• deviate significantly from

Reference Level (Screen 1) and

• have significant impact on

the market clearing price (Screen 2),

– then bids will be mitigated to the Reference Level

California Independent System Operator 6

California ISO

Damage Control Bid Cap (DCBC)

Original Recommendation

Max($250, 3*$(20*(Gas) + 6))

Revised Recommendation

Max($250, 2*$(20*(Gas) + 6))

California Independent System Operator 7

California ISO

Rationale for DCBC Recommendation

• Absent a West-wide Price Limit, the ISO is concerned that a

DCBC below this recommended level could result in insufficient supply bids being offered to the ISO Real-time Market during high demand periods.

• If the ISO has to make Out-of-Market (OOM) purchases above

the DCBC, supply may flee the Real-time Market in order to earn above DCBC payments via OOM.

• ISO OOM transactions are problematic for the ISO

– They undermine the market structure. – The ISO should not be in the role of shopping and negotiating bilateral energy transactions on behalf of LSEs. – They are operationally burdensome – They can compromise reliability if the ISO is unable to procure sufficient supply.

California Independent System Operator 8

California ISO

It is Difficult to Empirically Justify a DCBC Level

Comparison of Load Patterns and Average ISO RT Prices (A ugust-September 2000 & 2001) 25 50 75 100 125 150

20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44

Load Category # Hours 50 100 150 200 250 300 Average ISO RT Price ($/MWh) Load Frequency 2000 Load Frequency 2001 ISO RT Avg. Prc. 2000 ISO RT Avg Prc. 2001

Cannot predict how constraining any DCBC will be in Summer 2003 It will depend primarily on:

– Hydro Conditions

– Summer Weather Patterns – Conservation – Level of Forward Contracting

California Independent System Operator 9

California ISO

In Summer 1999, a $250/MWh Price Cap was generally only hit under very high load conditions.

Load Frequency and Average Prices June-September 1999 40 80 120 160 200 240

2 2 2 2 4 2 6 2 8 3 3 2 3 4 3 6 3 8 4 4 2 4 4 4 6

Total ISO load (GW) Number of Hours by Load Level 50 100 150 200 250 300 $/MWh Load Frequency PX Avg. Prc ISO RT Avg. Prc

California Independent System Operator 10

California ISO

In more recent months, the ISO’s Real- time price has seldom hit the cap.

Real-time Market Incremental Price Duration Curve 20 40 60 80 100 120 0% 10% 20% 30% 40% 50% 60% 70% 80% 90% 100% Percent of 10-Minute Intervals $/MWh NP15_RT INC_PRC (July-Sep 2001) NP15_RT INC_PRC (Jan-Mar 2002)

California Independent System Operator 11

California ISO

The ISO proposed DCBC should reduce the potential for Out of Market transactions above the DCBC.

Average Hourly Purchases Above the Price Cap During System Emergencies

500 1,000 1,500 2,000 2,500 3,000 3,500 4,000 S e p _ N

• v

_ D e c 7 _ D e c _ 8 _ 3 1 _ J a n _ 1 F e b _ 1 M a r _ 1 A p r _ 1 M a y _ 1 _ 2 8 _ 1 Avg Qty Purchased Above Cap (MWh) 100 200 300 400 500 600 700 800 Price Cap ($/MWh)

Avg Qty above Actual Cap Avg Qty above (20*(Gas) + 6) Avg Qty above 2*(20*(Gas) + 6)) Actual Cap ($/MWh) Cap = (20*(Gas) + 6) Cap = 2*(20*(Gas) + 6)

California Independent System Operator 12

California ISO

DCBC Summary

• Recommendation: Max($250, 2*$(20*(Gas) + 6))
• Rationale:

– Absent a West-wide Price Limit, a DCBC below this recommended level could result in insufficient supply bids being offered to the ISO Real-time Market during high demand periods. – If the ISO has to make Out-of-Market (OOM) purchases above the DCBC, supply may flee the Real-time Market in order to earn above DCBC payments via OOM. – ISO OOM transactions are problematic for the ISO

• They undermine the market structure.
• The ISO should not be in the role of shopping and negotiating bilateral

energy transactions on behalf of LSEs.

• They are operationally burdensome
• They can compromise reliability if the ISO is unable to procure sufficient

supply.

– The ISO remains concerned about the repercussions a DCBC lower than the ISO recommendation would have on:

• Forward contracting
• Demand Response
• New generation investment

California Independent System Operator 13

California ISO

Negative Damage Control Bid Cap

• Recommendation: -$30/MWh
• Not applicable for intra-zonal congestion –

– Local Market Power Bid Mitigation will address the DEC game.

• Pertains to “in-merit” zonal dispatches in the ISO RT Market.

– Over-generation conditions – Decremental bids used in real-time to manage inter-zonal congestion

• A negative Real-time MCP should be rare and very self-correcting.
• Potential justifications for a negative bid:

– Gas imbalance charges – Bilateral contract penalties – External Control Area transmission costs – Subsidy for load resources to consume additional energy

• The ISO does not believe it is reasonable to expect that such factors

could justify a negative energy bid below -$30/MWh.

California Independent System Operator 14

California ISO

Bid Screens and Automatic Mitigation Procedures (AMP)

Original Recommendation

• AMP Reference Level

– Cost-based bids for gas-fired – Historical accepted bids for all

• ther resources
• AMP Applicability

– All PGA & PLA Resources – All other resources eligible to set the Real-time MCP – Import bids excluded

• AMP applied all hours.

Revised Recommendation

• AMP Reference Level

– Historical accepted bids for all Resources – DMA will closely monitor bid patterns of AMP resources

• AMP Applicability

– All PGA & PLA Resources – All other resources eligible to set the Real-time MCP – Import bids included

• AMP not applied in hours

when ISO DA Load Forecast > 40,000 MW

California Independent System Operator 15

California ISO

Bid Screens and Automatic Mitigation Procedures (AMP) cont.

Original Recommendation

• AMP Bid Threshold

– 200% increase from Reference Level

• AMP Price Impact Threshold

– Min(200%, $50/MWh) increase in Real-time MCP.

Revised Recommendation

• AMP Reference Level

– Min(100%, $50/MWh) increase from Reference Level.

• AMP Price Impact Threshold

– Min(100%, $50/MWh) increase in Real-time MCP.

California Independent System Operator 16

California ISO

Bid Screens and Automatic Mitigation Procedures (AMP) cont.

Comparison of Average Bid Price Dispatched to Proxy Cost January-March 2002 (Peak Hours)

0.00 20.00 40.00 60.00 80.00 100.00 120.00 140.00 160.00 180.00 7 8 9 10 11 12 13 14 16 17 18 20 22 Incremental Heat Rate $/MWh 100,000 200,000 300,000 400,000 500,000 600,000 700,000 800,000 Quantity Dispatched (MWh)

Quantity Dispatched (Peak Hours) Estimated Proxy Cost Average Bid Price Accepted (Peak Hours)

California Independent System Operator 17

California ISO

12-Month Market Competitiveness Index (MCI)

Original Recommendation

• 12-Month Trigger Threshold

for Additional Mitigation

– 10% above 12 - Month Competitive Baseline Average Costs

Revised Recommendation

• 12-Month Trigger Threshold

for Additional Mitigation

– $5/MWh above 12 - Month Competitive Baseline Average Costs

Rationale for Change: – Similar to a performance based rate design. Will provide better incentives for generator cost reduction.

California Independent System Operator 18

California ISO

12-Month MCI: Potential Cost to Load Impact of a $5/MWh Threshold

• Estimated cost exposure is approximately $150

Million/Year.

a. Estimated Annual Net-Short = 55,123 GWh b. Total covered by long-term contracts and quarterly purchases = 25,056 GWh. c. Difference (a-b) = 30,067 GWh d. Estimated Cost = $150 Million/Year

California Independent System Operator 19

California ISO

12-Month Market Competitive Index

$(20.00) $- $20.00 $40.00 $60.00 $80.00 $100.00 $120.00 $140.00 $160.00 Apr-98 Jun-98 Aug-98 Oct-98 Dec-98 Feb-99 Apr-99 Jun-99 Aug-99 Oct-99 Dec-99 Feb-00 Apr-00 Jun-00 Aug-00 Oct-00 Dec-00 Feb-01 Apr-01 Jun-01 Aug-01 Oct-01 Dec-01 Feb-02 Apr-02 Jun-02 Aug-02 Oct-02 Dec-02 (2,000,000)

• 2,000,000

4,000,000 6,000,000 8,000,000 10,000,000 12,000,000 14,000,000 16,000,000 Short Term MWh Short Term Markup ($/MW h) 12 Month Markup ($/MW h) $ 5/MWh Threshold Hypothethical Data for illustration only (Mar to Dec)

California Independent System Operator 20

California ISO

Local Market Power Mitigation

• Local market power mitigation is a necessary permanent market design

element.

• ISO proposed a local market power mitigation approach in Amendment

42:

– Impose scheduling limits on resources within locally congested areas (interim forward intra-zonal congestion management) – Mitigate real-time energy bids when resources in local constrained areas are dispatched to relieve the localized transmission constraint.

• Alternative interim approaches to forward intra-zonal congestion will be

discussed at the FERC Stakeholder Conference (May 9-10)

• Recommendation

– Include local market power real-time market bid mitigation in the May 1 Filing and ask for Summer 2002 implementation. – Defer filing an interim forward intra-zonal congestion management approach until after the FERC Stakeholder Conference (May 9-10).

California Independent System Operator 21

California ISO

Real-time Economic Dispatch (Elimination of Target Price)

• Previously approved by the Board and filed in Amendment 42.
• On March 27, 2002, FERC rejected this element because it

believed it should be part of a comprehensive market design proposal.

• Critical long-term enhancement of real time market
• The ISO currently uses a Target Price as a mechanism to

eliminate price overlaps in its Real-time market. This approach is problematic in that it creates separate INC and DEC prices in each 10-minute interval.

• Real-time Economic Dispatch would provide a more

sophisticated approach to clearing the price overlap and would eliminate separate INC and DEC prices.

California Independent System Operator 22

California ISO

Uninstructed Deviation (UID) Penalties

• In Amendment 42, the ISO filed to penalize generators that fail to

follow dispatch instructions (uninstructed deviations).

• The proposal exempts deviations that are within a reasonable

range of the instructed level but penalizes excessive uninstructed deviations.

– Generator owners that engage in excessive negative UID (i.e. under-generation) are charge the real-time MCP plus 50%. – Generator owners that engage in excessive positive UID (i.e. over- generation) are paid the real-time MCP less 100% (i.e. no payment).

• Market Power Mitigation Benefit

– Should improve generation performance and reduce real-time market volatility. – Should reduce physical withholding associated with generation units failing to respond to dispatch instructions.

California Independent System Operator 23

California ISO

Residual Unit Commitment (RUC) Process

• Day-ahead process that enables the ISO to commit additional

generation resources and procure energy imports to meet forecasted loads.

• The ISO will, in the Day-Ahead RUC process

– Commit 100% of the capacity necessary to serve the next day’s ISO forecasted load; and – Procure up to 95% of the forecasted energy requirements (minimum load energy and imports)

• Once the ISO implements a Day-ahead Energy Market, only imports

identified as ACAP resources will be considered in the RUC process.

• Unloaded capacity that is selected in RUC will receive a capacity

payment for each MW of capacity that was committed but not dispatched.

– Payment withdrawn for each MW that is scheduled as an export in HA or RT. – Payment derived from cost-based proxy bid curve

California Independent System Operator 24

California ISO

Single Energy Bid Curve (DA, HA, & RT Market)

• Requirement for bidders to submit a single energy curve for all

services in each temporal market (i.e. DA, HA, RT).

– DA Market

• Single energy bid curve
• Can submit different capacity bids (Reg, Spin, Non-Spin, Repl.)

– HA Market

• Can submit new single energy bid curve for capacity not committed in

DA (e.g. capacity not committed in DA Ancillary Service, RUC).

• Can submit different capacity bids (Reg, Spin, Non-Spin, Repl.)

– RT Market

• Can submit supplemental energy bid for non-committed capacity.

California Independent System Operator 25

California ISO

Other 10/1 Elements

• Must-Offer Requirement for PGA resources

– Hydro resources would continue to be exempted – Uncommitted long-start units must be offered to the ISO’s Residual Unit Commitment Process – On-line units or quick start units must offer all available capacity to the ISO’s real-time market.

• Recovery of Emissions Costs

– Emission Costs are to be excluded from bids submitted to the ISO market and billed to the ISO as a separate uplift as is the case today under the FERC June 19 Order.

California Independent System Operator 26

California ISO

Board Motions