© ERCOT & Market Reform, 2010. Nodal Protocols Risk Assessment Presentation to the ERCOT Board 16 August 2010 Phase 1: Overall Assessment, Identification

© ERCOT & Market Reform, 2010.

Nodal Protocols Risk Assessment

Presentation to the ERCOT Board16 August 2010

Phase 1: Overall Assessment, Identification of Material Risks


Outline/Agenda

Assessment Criteria

2. Overall Assessment of the Protocols

Our Conclusions

3. Potential Market Design Weaknesses

4. Addressing the Risks

Needs Fixing Now

Likely to Need Fixing Soon

Must be Fixed Over Time

Page 2

Watch and Be Ready

1. Introduction1. Introduction

Scope of the Review and of this Report

• ERCOT has contracted with Market Reform to conduct a “broad”, “high-level [Phase 1] expert review and analysis of the ERCOT Nodal Protocols that:

a. “Assesses if the Protocols will deliver … the intended improvements … vis-à-vis

the current zonal market design …

b. “… assesses potential market design weaknesses …;

c. “Describes and suggests priorities for further analysis; and

d. “Provides a schedule … and cost estimate for a subsequent [Phase 2] review.” 1

Page 3

1 Nodal Protocol Review Statement of Work (SoW), Exhibit A

Page 3© ERCOT & Market Reform, 2010.

• This Report

– Deals with the substantive items (a) and (b) above

– Discusses item (c) from the perspective of risk assessment

– Does not cover item (d), which will be dealt with separately

Objectives and Approach• ERCOT has emphasized that the current Protocols have been agreed

among stakeholders and that implementation is well underway, with market start scheduled for December, so the objective of Phase 1:

– IS NOT to define an “ideal” market or propose changes solely for the purpose of

increasing market efficiency or elegance

– IS to identify issues that might pose material risk to the scheduled market start

date or to successful (particularly early) market operations.

Page 4

This Report summarizes the most important risks identified in the Review; it is not a comprehensive list of all the problems ERCOT will

face and does not prescribe solutions (other than as examples)


• Given this guidance, Market Reform has prepared a high-level assessment of the Protocols by:

– Reviewing the Protocols and associated documents (e.g. NPRRs)

– Consulting extensively with the ERCOT staff team assigned to advise the project

– Preparing, circulating and revising the evolving analysis of these problems

Frequently Used Technical Acronyms

• AS: Ancillary Service• CRR: Congestion Revenue Right• DA: Day-Ahead• DAM: Day-Ahead Market• DR: Demand Response• LMP: Locational Marginal Price• LZ: Load Zone• MCP: Market Clearing Price• MP: Market Participant• NOIE: Non-Opt-In Entity• PTP: Point-to-Point • QSE: Qualified Scheduling Entity• RT: Real Time• RUC: Reliability Unit Commitment• SCED: Security-Constrained Economic Dispatch• SWCAP: System-Wide Offer Cap• VDI: Verbal Dispatch Instruction

© ERCOT & Market Reform, 2010.Page 5

Assessment Criteria



Outline/Agenda


Our Conclusions



Needs Fixing Now


Page 6

1. Introduction

Watch and Be Ready

Assessment Criteria


Assessment Criteria

• “Intended Improvements of the Nodal Market vs. the current Zonal Market:

– “Reductions in congestion costs

– “Increased price transparency and liquidity in the marketplace

– “Increased locational price transparency for resources; and

– “Transparent and efficient RT dispatch”


1 Nodal Protocol Review Statement of Work (SoW), Schedule 1 to Exhibit A

As criteria for assessing the Protocols, ERCOT provided the following:1

• “Key features of the Nodal Market vs. the current Zonal Market”

– Both DAM and RT market for energy (vs. RT-only)

– AS in DAM to supplement self-arrangement (vs. all AS self-arranged)

– Nodal (vs. Zonal) offers, schedules and prices for Resources

– Resource-specific (vs. portfolio) offers and schedules

– Thousands of Potential CRRs (vs. six Flowgate Rights)


KEY FEATURE

Transparent Prices & Liquidity

Transparent Locational

Prices

Reduced Congestion

Costs

Transparent & Efficient

RT Dispatch

Energy DAM (vs. RT Only)

Many CRRs (vs. 6 FGRs)

AS in DAM (vs. Self-Arr.)

Nodal for Resources (vs. Zonal)

Resource-Specific (vs.

Portfolio)

INTENDED IMPROVEMENTS of NODAL vs. ZONAL

CRRs do not directly affect operations or pricing, but without them LMP may be

impractical

AS market is in DAM only and ignores location

Key Features and Intended Improvements

Only resources, not loads, face LMPs

Our Conclusions

Assessment Criteria



Outline/Agenda




Needs Fixing Now


Page 9

1. Introduction

Watch and Be Ready

Our Conclusions

Our Summary Conclusions

• The Nodal Protocols, as these are being implemented by ERCOT:

– Contain all the “key features” listed above

– Will improve market performance (vs. Zonal) in the intended areas

Page 10Page 10© ERCOT & Market Reform, 2010.

The market design weaknesses we have found are listed in the next slide, categorized by how soon they are likely to need to be fixed

• We have found:

– NOTHING suggesting the existence of large-scale gaming or market manipulation opportunities (although these exist to some extent in any market)

– ONE potential show-stopper – PTP Options in the DAM – that must be addressed before market start; and this has at least one technically easy, if politically difficult, fix: Limit PTP Options in the DAM

– SEVERAL market design weaknesses (compromises?) that:

o Will cause problems and create some risks unless/until they are fixed;

o Probably cannot be fixed without changes in the Protocols and systems; but

o Do NOT threaten market start or viability, at least in the short term


Market Design Weaknesses by Category

PTP Options in the DAM

Needs Fixing Now (before market start)

Load Zone Modelling/Pricing

Ancillary Services Deliverability

CRR Derating

Likely To Need Fixing Soon (after market start)

Scarcity Pricing

Must Be Fixed Over Time (within a few years)

Settlement at Shadow Prices

RUC and RUC Clawback

SCED and 2-Step Mitigation

Watch and Be Ready (if/when fix is needed)

Needs Fixing Now

Assessment Criteria



Outline/Agenda


Our Conclusions



Needs Fixing Now


Page 12

1. Introduction

Watch and Be Ready


Needs Fixing Now

PTP Options in the DAM – Summary• A NOIE can (in effect) bid in the DAM to buy a PTP Option settled in RT

– If it owns the same DAM-settled PTP Option

– For up to 110% of its forecast RT demand


One technically (if not politically) easy fix is to eliminate/limit PTP Options in the DAM; but other fixes may work also

Needs Fixing Now

• PTP Options in the DAM are a potential show-stopper for the Nodal Market

– Theory, experience elsewhere and ERCOT trials suggest the DAM can take hours to solve if PTP Option Bids involve > a hundred (or so) source-sink pairs

– If the DAM does not run, settlement can be based on RT prices – but this would surely be regarded as failure of the market if it happened more than rarely

• Clearing a nodal market with bids/offers for both energy and CRRs subject to Simultaneous Feasibility/Revenue Adequacy is, with modern technology:

– Practical with PTP Obligations, because these can be modelled as linked energy bids/offers in the single calculation of network flows needed for the optimization

– A very different matter with PTP Option Bids, because each source-sink pair in any Option Bid requires recalculating all network flows


No Block Bids No Unit

Commitment

Block BidsNo Unit

Commitment

Block Bidsand Unit

Commitment

Only CRR Obligation Bids

Seconds/a Minute

MinutesMany Minutes/

an Hour

≈ 100 CRR Option Bids

Minutes Many Minutes Hour(s)

Many CRR Option Bids

Many Minutes/an Hour

Hours(12-18 in PJM)

Many Hours/a Day

Representative Market-Clearing/Solution Times

The General Problem of PTP Options

• The difficulty of clearing an LMP market subject to CRR revenue adequacy/ simultaneous feasibility constraints depends critically on:

– The number and nature of integer variables – e.g., the three-part offers required for unit commitment, linked AS offers and block load bids

– Whether and how many PTP Option bids are submitted/allowed, because (in effect) the entire security-constrained dispatch problem must be resolved for each source-sink pair in any Option bid

Needs Fixing Now: PTP Options in the DAM

Assessment Criteria


Outline/Agenda


Our Conclusions



Needs Fixing Now


Page 15

1. Introduction


Watch and Be Ready


Load Zone Modelling/Pricing – Summary• ERCOT is divided into a few load zones (LZs), with every load within a LZ:

– Paying the same energy price = the average LMP within the LZ – which reduces market-driven DR and efficiency, but is probably tolerable for awhile/indefinitely

– Distributed for DAM purposes across all LZ buses using the same load distribution factors (LDFs) – a more serious problem that may need fixing soon

• When all DAM loads are spread proportionally across all buses in a LZ:– A DAM load bid from a large, price-sensitive point load may be rejected due to false

congestion, making the DAM unrealistic, increasing the need for RUC, etc.

– Congestion cannot be resolved by the loads that most affect it, because all loads anywhere in the LZ are assumed to affect it equally – a particularly serious problem in load pockets with no/little generation (weighted LZ shift factors ≈ 0)

• This may be a serious (show-stopping?) problem; possible fixes include:– Creating “custom LZs” for large loads/load pockets – done in (e.g.) CAISO, but not

allowed (at least for 3 years) under the ERCOT Nodal Protocols

– Ignoring in the DAM constraints with resource shift factors ≤ “epsilon” ≈ 0.00 – an ad hoc fix with uncertain effects and efficacy


More/smaller LZs are better than fewer/larger LZs


Ancillary Services Deliverability – Summary

• The Nodal Protocols allow QSEs to self-arrange AS as they do in the Zonal Market, but add some simple (even too-simple) AS markets


Zonal “worked” with self-arrangement and no AS market; but a market with bad incentives may be worse than no market at all


• The AS processes do not really co-optimize AS and energy

– The location of AS is ignored in self-arrangement, in the DAM, and in any post-

DAM SASM (Supplemental AS Market)

– ERCOT may not procure more of a better/lower cost AS in place of another AS

or switch capacity between energy and AS near RT (except in emergencies)

• The cost of AS reserves is low where energy LMPs are low, i.e., where energy (including reserve energy) cannot get to market, so:

– Rational QSEs and the DAM/SASM cost minimization will put too much AS

where it is undeliverable and too little in load pockets where it is most needed

– ERCOT will often(?) have to use near-RT VDIs to get AS to high-LMP load

pockets, where all capacity may already be self/DAM-scheduled for energy

CRR Derating – Summary• A CRR is derated for settlement purposes if it turns out to have been

“oversold” in a monthly CRR Auction, as determined by:

– The difference between the ERCOT Network Model used in the Auction and the

actual network capacity on the day – neither of which CRR Owners control

– A shift-factor calculation of dubious relevance


CRR derating may “only” create unnecessary complications and games, but it is more likely (also) to create large, counterproductive risks


• The effect – and presumably the intent – of derating is to impose on CRR Owners much of the cost and risk of network outages; but this:

– Stimulates no constructive actions by MPs either in CRR Auctions or in response

to network conditions on the day

– Undercuts one of the main purposes of CRRs, which is to give MPs a way to buy

insurance against the effects of network outages they cannot control

– Reduces the value of CRRs and hence the Auction revenues distributed to loads

– May encourage gaming of the “hedge values” that serve no purpose except to

limit the risks created by the derating itself

Assessment Criteria



Outline/Agenda


Our Conclusions



Needs Fixing Now


Page 19

1. Introduction

Watch and Be Ready


Scarcity Pricing – Summary

• An energy-only market like ERCOT needs energy (and AS) prices that can/will become very high (at least as high as the current SWCAP)

– When and where there is a critical need for more supply and/or less demand

– While allowing effective market power mitigation policies and mechanisms


ERCOT needs better scarcity pricing, at least for the long run

Must Be Fixed Over Time

• The Protocols do not provide adequate scarcity pricing– Generators are allowed/encouraged to bid up to SWCAP during scarcity periods

– The Protocol’s Scarcity Pricing Mechanism (SPM) is misnamed; its intent/effect is to keep prices down by reducing SWCAP at times

– The SWCAP and the 2-step mitigation in SCED will tend to depress prices

– With large LZs, load bids cannot produce congestion-driven scarcity prices

• The required “methodology for setting maximum Shadow Prices” (SPs) could be interpreted to allow SCED SP > SWCAP at times; but

– This does not seem to be the Protocols’ intent or ERCOT’s plan; and

– Even high Shadow Prices on SCED constraint violations will not produce high market prices if operators never let these constraints be violated

Assessment Criteria



Outline/Agenda


Our Conclusions



Needs Fixing Now


Page 21

1. Introduction

Watch and Be ReadyWatch and Be Ready

Settlement at Shadow Prices – Summary

• The Protocols often refer to “Shadow Prices [SPs] on constraints” or “… from the algorithm” as “Market Clearing Prices” (MCPs), and use these SPs/MCPs as settlement prices


ERCOT should be aware of the potential problems here, and be prepared to (e.g.) limit bids and offers or change pricing rules if necessary

Watch and Be Ready

• But the conflation of SPs with MCPs involves some implicit assumptions that are not always valid given provisions of the Protocols; in particular:

– The Protocols allow extensive use of “integer” variables, such as three-part offers

in the DAM and block bids/offers in the DAM and any SASM

– The resulting mixed integer programming (MIP) problems are inherently difficult

to solve, but modern technology can find a solution – the cleared bids and offers

– that (approximately) maximizes the gains from trade

– But the SPs from a MIP solution may not “clear the market”, i.e., settling all

trades at SPs may not equate demand to supply for individual MPs or overall

– And a small change in (e.g.) network conditions or a single bid/offer can make a

big difference in the SPs and the mix of cleared bids and offers

4

With Integers/Blocks, there May Be No MCPs

1 24

MWh

When Demand > D*,“B In” is Least-Cost

SPIN

1 2 3MWh

SPOUT

When Demand < D*,“B Out” is Least-Cost

B B

OPB

D* D*

B = All-or-None Block with Offer Price OPB

Demand Shadow Price = SPIN Demand Shadow Price = SPOUT

B should be IN, but cannot cover its costs @ settlement price = SPIN if it is IN, so will try to stay OUT

B should be OUT, but can make money @ settlement price = SPOUT if it is IN, so will try to avoid being OUT

OPB

The SP does not “clear the market”; in fact, no single price doesThe INs/OUTs and SPs are unstable and often inexplicableMPs will/must use strategies (games?) to try to get what they want

3


Watch and Be Ready: Settlement at Shadow Prices

RUC and RUC Clawback – Summary

• ERCOT’s Reliability Unit Commitment (RUC) process differs from, and involves more complex settlements than, RUC processes in other ISO markets. For example, the ERCOT process:

– Runs after the DAM to minimize RUC commitment costs only (like some ISOs but unlike others that include RUC units in the final DAM pricing run)

– “Claws back” some or all of a RUC unit’s offer-based profits (which no other ISO market does), with higher claw-back for units not offered in the DAM

– Allocates RUC costs to QSEs based on each QSE’s “capacity shortage”, with any final balance allocated to QSEs on a load-ratio share basis

Page 24

RUC will probably create risks and problems,1 but we have not studied it enough to know – and only testing/experience will really tell

1 See presentation to ERCOT by William Hogan, “Texas Nodal Market Design”, May 2, 2008, and testimony to PUC by David Patton, December 4, 2005, for discussions of RUC effects and risks.


Watch and Be Ready

• These complex arrangements are difficult to analyze, but they may create incentives (as examples only):

– For loads to understate demand in the DAM and rely on RT

– For generators to self-schedule to avoid claw-back

SCED and 2-Step Mitigation – Summary

• The SCED (Security-Constrained Economic Dispatch) process that determines RT dispatch instructions and RT energy prices has some problematic features, including (as examples only):

– Instantaneous optimization every 5 minutes based on then-committed resources, with no look-ahead (cannot commit units that will take more than 5 minutes to begin producing) or ramp rates (may call for energy that cannot be produced)

– No optimization of AS (capacity designated for AS in earlier processes cannot be used for energy in RT or vice versa)


Watch and Be Ready

The SCED (like RUC) will probably create risks and problems, but only testing/experience will really reveal what and how important they are

• The SCED also includes a 2-step offer price mitigation process that:– First computes LMPs with all network constraints ignored except those

determined earlier to be “competitive”, i.e., affected by many resources

– Then computes final/settlement LMPs considering all constraints but capping offer prices based on the first LMPs

– Is similar to such processes elsewhere, but also has some innovative features


Outline/Agenda


Our Conclusions



Needs Fixing Now


Page 26

1. Introduction

Assessment Criteria


Watch and Be Ready


Addressing the Risks

• This Review has identified some market design weaknesses that create risks; the fundamental questions for ERCOT management are now:

1. How material are these risks?

2. What can be done to deal with the risks judged to be material?


• Question #1 is assessed by considering (as illustrated on next slide):

– The likelihood of each risk

– Its impact should it occur

• Assessing question #2 above requires identification of:

– Mitigation actions that can be taken to reduce the likelihood and/or impact of the

risk, ideally bringing the risk down so that it is no longer material; and/or

– Contingency plans, for actions that can be taken should mitigation actions be

insufficient (or not taken) and hence the risk becomes reality

Risk Assessment

• The materiality of the risks created by the problems on our list is:


Negligible Minor Moderate Critical Extreme

Rare

Unlikely

Possible

Likely

Almost Certain

PTPOptionsin DAM

materialnot material

ERCOT has already begun assessing the materiality of some of these issues in its

market system testing processes

IMPACT

LIKELIHOOD

ZonalModelling/

Pricing AS Deliverability

CRR Derating

(Lack of) Scarcity Pricing


RUC & RUC Clawback

SCED & 2-Step Mitigation

– Already apparent for PTP Options in the DAM

– Likely for Zonal Modelling/Pricing

– Not yet clear for the others

• Where materiality is not yet clear, it can and should be assessed:

– Before market start, using analysis and market trials/simulation where practical; and/or

– After market start, with a well-planned monitoring and early-warning program; and/or

– Both before and after market start

Assessing Materiality


Source of Risk Questions To Be Addressed by Analysis/Trials/Simulations

PTP Options In DAM

The number of PTP Option source-sink pairs the DAM can handle; how many of these do NOIEs want/need

Load Zone Modelling/Pricing

Frequency/magnitude of load-pocket effects and DAM inefficiencies; effects of ignoring some constraints in DAM; feasibility of custom LZs

Ancillary Services (Un)deliverability of DAM/SASM AS schedules; feasibility of SASM within an hour; robustness/effects of ERCOT’s undeliverability determinations

CRR Derating Distribution of impacts via shift factors; frequency and size of CRR de-rating; ability to influence/game “hedge values”

Lack of Scarcity Pricing

Price distributions w. scarcity; effects of 2-step mitigation; effects of SCED constraint MSPs/penalty functions now & with reserve/DR constraints


Frequency/size of pricing inconsistencies and instabilities; market tolerance for and gaming incentives created by such inconsistencies/instabilities

RUC & RUC Clawback

Magnitude and costs of RUC commitments relative to market; likely incentive effects of RUC cost allocations and claw-back provisions

SCED & 2-Step Offer Mitigation

Inefficiencies/ anomalies created by lack of look-ahead, AS optimization, etc.; reasonableness and stability of offer price mitigation every 5 minutes

Mitigation Actions/Contingency Plans


Source of Risk Possible Mitigation Actions/Contingency Plans

PTP Options In DAM Demonstrate that NOIEs do not need any/many PTP Options

Load Zone Modelling/Pricing Create custom LZs; ignore some load-pocket constraints in DAM

Ancillary Services Add locational constraints to AS and SASM market models

CRR Derating Develop simpler, broader allocation of network outage costs

Lack of Scarcity Pricing Add operating reserve and DR constraints to SCED

Settlement at Shadow Prices Limit complexity of bids/offers; use (e.g.) “minimum uplift” pricing

RUC & RUC Clawback Depends on problems observed in trials/reality

SCED & 2-Step Offer Mitigation Depends on problems observed in trials/reality

ERCOT has already begun considering ways to reduce these potential risks as it implements the Protocols

ERCOT and Market Reform are now discussing what, if anything, should be included in Phase 2 of our Review of the ERCOT Nodal Protocols


Appendix

Detailed Analyses ofPotential Market Design Weaknesses

Page 31

PTP Options in the DAM – Summary• A NOIE can (in effect) bid in the DAM to buy a PTP Option settled in RT

– If it owns the same DAM-settled PTP Option

– For up to 110% of its forecast RT demand

• Clearing a nodal market with bids/offers for both energy and CRRs subject to Simultaneous Feasibility/Revenue Adequacy is, with modern technology:

– Practical with PTP Obligations, because these can be modelled as linked energy bids/offers in the single calculation of network flows needed for the optimization

– A very different matter with PTP Option Bids, because each source-sink pair in any Option Bid requires recalculating all network flows

• PTP Options in the DAM are a potential show-stopper for the Nodal Market

– Theory, experience elsewhere and ERCOT trials suggest the DAM can take hours to solve if PTP Option Bids involve > a hundred (or so) source-sink pairs

– If the DAM does not run, settlement can be based on RT prices – but this would surely be regarded as failure of the market if it happened more than rarely


One technically (if not politically) easy fix is to eliminate/limit PTP Options in the DAM; but other fixes may work also

Needs Fixing Now

How a NOIE Buys PTP Options in the DAM

• The Protocols do not refer to buying PTP Options in the DAM, but say that:

– A NOIE with a DAM-settled PTP Option can (for ≤ 110% of forecast RT demand):

• “Declare” that it wants to settle all or part of that Option at RT prices; and also

• Submit to the DAM a CRR Offer to sell that Option if its DAM price exceeds a

Minimum Reservation Price (MRP) with default value $2,000/MWh

• If the Option’s DAM “price” (i.e., settlement value) exceeds MRP, the Option is

“sold” (i.e., settled) in the DAM; otherwise, it is carried forward for RT settlement

• This is equivalent to a NOIE settling its original Option in the DAM and bidding to buy the same RT-settled Option in the DAM, except that:

– CRRs are derated prior to the DAM to reflect actual network capacity; and

– Bids for CRRs in the DAM are pro-rated down to reflect the same capacity

• The Protocols’ complicated/confusing description of this process:

– Would be unnecessary but for the complex CRR derating scheme – which also

creates other problems that are discussed elsewhere in this report

– Does not avoid the fundamental problems caused by PTP Options in the DAM© ERCOT & Market Reform, 2010.

Page 33


The PTP Option Problem in ERCOT

• As optimization methods have improved, LMP markets have allowed more integers and some CRR Options, but:

– ERCOT allows more integers than other markets, such as PJM, do– PJM’s monthly CRR auctions allow bids for DAM-settled CRR Options – and take

12-18 hours to solve with no unit commitment

– PJM allows NO PTP Options in the DAM (where unit commitment is begun)

– Leading academic and industry experts have (confidentially) expressed doubt that ERCOT can successfully allow more than a few PTP Options in the DAM

• ERCOT trials with the DAM software indicate that the DAM can:– Solve “fast enough” with up to about 100 PTP Option source-sink pairs

– Take many hours to solve with more than a few hundred such pairs

• Thus, if NOIEs try to buy (or “declare for RT settlement”) many PTP Options in the DAM, there is a serious risk that the DAM will not clear fast enough

– If the DAM does not clear, RT prices are used for settlement, but

– This would surely be seen as a serious failure of the market if/when it happened



Fixing the PTP Option Problem

• There is unlikely to be a technical fix to the PTP Option problem

– Capabilities will not improve enough soon enough to make much difference

– Extensive bids for Options in the DAM can create other problems, primarily fewer

CRRs clearing in the DAM

• The easiest/best/only? solution is to eliminate/limit NOIE’s demand for RT-settled PTP Options in the DAM

– It is not clear how many such Options NOIEs will want – or even why they should

want them when Obligations provide a better true hedge

– It may be that NOIEs will decide on their own, or can easily be persuaded, not to

bid for (many) PTP Options in the DAM

– But NOIEs apparently negotiated hard for the right to buy/convert RT-settled PTP

Options, so it may not be politically easy to limit that right


ERCOT must limit the demand for PTP Options in the DAM, ideally by persuading NOIEs they do not need them – which could solve the problem with no changes in the Protocols or market systems


Load Zone Modelling/Pricing – Summary• ERCOT is divided into a few load zones (LZs), with every load within a LZ:

– Paying the same energy price = the average LMP within the LZ – which reduces market-driven DR and efficiency, but is probably tolerable for awhile/indefinitely

– Distributed for DAM purposes across all LZ buses using the same load distribution factors (LDFs) – a more serious problem that may need fixing soon

• Distributing all DAM loads proportionally across all buses in a large LZ creates problems for congestion management and market clearing

– Small changes/errors in LDFs can create large changes/errors in DAM outcomes

– Congestion cannot be resolved by the loads that most affect it, because all are assumed to affect it equally – which increases congestion management costs

– A DAM load bid from a large, price-sensitive point load may be rejected due to false congestion, making the DAM unrealistic and increasing the need for RUC

• The resulting high congestion costs and poor DAM performance could:– Produce early demands for a fix to the DAM modelling problem

– Be mitigated by creating “custom LZs” for large loads (as, e.g., CAISO does)


More/smaller LZs are better than fewer/larger LZs


Ancillary Services Deliverability – Summary

• The Nodal Protocols allow QSEs to self-arrange AS as they do in the Zonal Market, but add some simple (even too-simple) AS markets

• The AS processes do not really co-optimize AS and energy

– The location of AS is ignored in self-arrangement, in the DAM, and in any post-

DAM SASM (Supplemental AS Market)

– ERCOT may not procure more of a better/lower cost AS in place of another AS or

switch capacity between energy and AS near RT (except in emergencies)

• The cost of AS reserves is low where energy LMPs are low, i.e., where energy (including reserve energy) cannot get to market, so:

– Rational QSEs and cost minimizing DAM/SASMs will put too much AS where it is

undeliverable and too little in load pockets where it is most needed

– ERCOT will often(?) have to use near-RT VDIs to get AS to high-LMP load

pockets, where all capacity may already be self/DAM-scheduled for energy


Zonal “worked” with self-arrangement and no AS market; but a market with bad incentives may be worse than no market at all


AS Location and (Un)deliverability

• The DA AS processes do not just ignore location, but actually have a systematic bias toward undeliverable AS; for each type of AS:

– All pre-DAM processes deal only with total AS MW without regard to location

– The DAM determines only a single non-locational MCP for AS

– Economic logic will tell QSEs to self-arrange and the DAM to purchase AS (at

least reserves) where LMPs are low because energy is less deliverable to load

• RUC cannot be used to buy AS unless AS Offers in the DAM are insufficient to meet the total (non-locational) AS Requirement

• After the DAM, ERCOT uses HRUC to define “undeliverable” AS capacity and can (if there is time) use a SASM to procure additional AS

– Each QSE must replace its undeliverable AS capacity using self-arrangement,

bilateral purchases or ERCOT purchases in a SASM

– But post-DAM trading of AS and any SASM ignore location, so even if there is

time for these the replacement/supplemental AS may be undeliverable


Likely to Need Fixing Soon: Ancillary Services Deliverability

Risks Created by the AS Provisions

• These AS processes will increase ERCOT interventions in the market and may create operational risks

– The “normal” pre-RT market AS processes will put too much AS in low-LMP generation pockets and (more importantly) too little in high-LMP load pockets

– The processes used to replace undeliverable AS capacity will not necessarily put it where it is needed (although ERCOT can offer “advice” about location)

– So ERCOT will sometimes (often?) find itself scrambling to use RT operator judgments and VDIs (verbal dispatch instructions) to get AS where it is needed

• These processes will also (compared to AS processes used in other markets) increase costs and be subject to gaming

– The non-substitution rule, lack of RT AS optimization, and ERCOT’s last-minute needs for AS will reduce competition and increase market power

– QSEs may challenge and try to game ERCOT’s non-market but commercially important decisions about which AS is “undeliverable” (when there are options)


Unless congestion is immaterial, the AS provisions are likely to create conflict, inefficiencies, gaming and perhaps even reliability problems

Likely to Need Fixing Soon: Ancillary Services Deliverability

CRR Derating – Summary• A CRR is derated for settlement purposes if it turns out to have been

“oversold” in a monthly CRR Auction, as determined by:

– The difference between the ERCOT Network Model used in the Auction and the

actual network capacity on the day – neither of which CRR Owners control

– A shift-factor calculation of dubious relevance to anything

• The effect – and presumably the intent – of derating is to impose on CRR Owners much of cost and risk of network outages; but this:

– Stimulates no constructive actions by MPs either in CRR Auctions or in response

to network conditions on the day

– Undercuts one of the main purposes of CRRs, which is to give MPs a way to buy

insurance against the effects of network outages they cannot control

– Reduces the value of CRRs and hence the Auction revenues distributed to loads

– May encourage gaming of the “hedge values” that serve no purpose except to

limit the risks that derating creates


CRR derating may be “only” an unnecessary and unproductive complication – or it may create large risks for not good reason

Likely to Need Fixing Soon: CRR Derating

CRR Derating and CRR Auctions• Derating reduces the value of a CRR to its Owner, so MPs will naturally

reduce/derate the prices in their CRR Bids in monthly auctions

– Large MPs may value CRRs using sophisticated option valuation models with

inputs from ERCOT’s Network Model, scheduled/historical outages, etc.

– Smaller MPs will use simpler methods to value deratable CRRs, potentially

increasing their competitive disadvantage relative to larger MPs

– The lower bids will lower MCPs in the CRR Auction and hence decrease the

auction revenue that is distributed to loads

• Derating also reduces the cost of a CRR to the settlement system– In principle, if X MW of firm CRRs passes the revenue adequacy test, something

more than X MW of deratable CRRs should also pass the test

– In practice, ERCOT is not taking derating into account in the CRR Auction (and it

is unclear whether/how they could), so “too few” CRRs will be sold


CRR derating has no effect on CRR Auctions except to complicate bidding strategies (and revenue adequacy tests?)

and reduce CRR bid prices, MCPs and revenues


CRR Derating and Mitigation Actions

• It has been suggested that CRR derating motivates mitigation actions

– “CRR Owners cannot just sit there and collect CRR revenue but must try to

anticipate an outage and then do something to cut their losses if it occurs”

– This view is inconsistent with both the concept and the reality of CRRs and LMPs

• When outage-created LMPs put a CRR “in the money”, a firm CRR pays the LMP differential no matter what the CRR Owner does, thereby:

– Reducing the financial loss due to events outside the CRR Owner’s control

– Exposing the Owner to the full incentive effects of the LMPs

• A CRR Owner whose CRR is derated just when it is most needed suffers a loss due to an event it should be able to insure against, but has:

– No incentive to take any mitigation actions not justified by the LMPs

– Some incentive to try to influence the derating scheme and its “hedge values”

– Less incentive to enter or stay in the market at all


CRR derating does nothing to reduce the probabilities or to mitigate the effects of network outages; it simply increases risks to MPs


CRR Derating, Location and “Hedge Values”

• CRR derating may be intended to discourage locating facilities where the network is unreliable, but is unneeded and poorly suited for this purpose

– Firm CRRs give “the right” incentives not to locate where network outages are

frequent, as the competitive prices of firm CRRs will increase to reflect such risks

– Derating puts outage risks on MPs while largely insulating Network Service

Providers (NSPs) who can actually do something to reduce outages

• The “hedge values” that limit CRR deratings will create conflict and games

– These “hedge values” depend on Protocol-specified min/max “prices” that

represent the deemed costs of generation from different technologies

– In some cases, CRR Owners can (e.g.) increase the minimum CRR payment by

installing a wind generator at the source and/or a diesel generator at the sink

– Such investments, and the inevitable disputes over their purpose and their

Protocol-specified min/max “prices”, will be counterproductive at best



What Will CRR Derating Do in Practice?

• At best, CRR derating will be an unnecessarily complex and potentially gameable form of uplift on CRR holders; this will be the case if:

– Outages are small, frequent and randomly distributed; and/or

– The shift-factor calculation spreads deratings broadly across many CRRs; and/or

– The “hedge values” limit deratings so much (perhaps because of manipulation)

that the deratings are de minimus; so that

– All CRRs suffer about the same (small) proportional derating each month (or so)

• But it is more likely that CRR derating will (in addition to being complex and gameable) create large risks for no good reason

– Some outages will be large and (one hopes) infrequent, and will hit some CRRs

much harder than others

– Unplanned outages will hit like (uninsurable) lightening, but even planned

outages will leave MPs uninsured against congestion risks during the outage

– Such uninsurable risks will increase costs and discourage market participation,

particularly for smaller players



What Might Be Done about CRR Derating?

• CRR derating can be left in place if turns out that:

– Deratings are spread more-or-less evenly across all CRRs, so derating is “only” an unnecessarily complex form of uplift on CRR holders; and

– Manipulation of the “hedge values” is unlikely to be profitable enough to become a serious problem

• But if CRR derating creates large risks for CRR Owners and/or significant gaming opportunities, it may have to be dropped or significantly modified

• If specific CRRs are not derated to reflect outages of specific network elements, it must be decided who should bear the risks of settlement deficits due to such outages; these deficits could be allocated to:

1. CRR Owners as a whole, via a proportional derating of all CRRs, on the grounds that this is closest to what the current derating method does

2. NSPs (Network Service Providers), on the grounds that they are in the best position to control outages

3. The loads who received the revenues from the CRR Auctions, on the grounds that those who collect the insurance premium should make good on the claims



Scarcity Pricing – Summary

• An energy-only market like ERCOT needs energy (and AS) prices that can/will become very high (at least as high as the current SWCAP)

– When and where there is a critical need for more supply and/or less demand

– While allowing effective market power mitigation policies and mechanisms

• The Protocols do not provide adequate scarcity pricing– Generators are allowed/encouraged to bid up to SWCAP during scarcity periods

– The Protocol’s Scarcity Pricing Mechanism (SPM) is misnamed; its intent/effect is to keep prices down by reducing SWCAP at times

– The SWCAP and the 2-step mitigation in SCED will tend to depress prices

– With large LZs, load bids cannot produce congestion-driven scarcity prices

• The required “methodology for setting maximum Shadow Prices” (SPs) could be interpreted to allow SCED SP > SWCAP at times; but

– This does not seem to be the Protocols’ intent or ERCOT’s plan; and

– Even high Shadow Prices on SCED constraint violations will not produce high market prices if operators never let these constraints be violated


ERCOT needs better scarcity pricing, at least for the long run

Must Be Fixed Over Time

Unlinking Scarcity Prices from Offer Prices

• Relying on high offer prices to produce scarcity prices is problematic

– The required offer strategies, such as offer prices well above costs and hockey-

stick offer curves, will look like (and may be) market power in action

– Resources cannot know for sure when RT scarcity will arise or how bad it will be,

so they must guess, which results in inefficient prices and dispatch

• Other markets use rules that increase market prices above offer prices when and to the extent scarcity appears in RT, so that:

– Resources can (be required to) offer at prices that reflect actual costs, not on

guesses about when RT scarcity will appear and how bad it will be

– Limits on offer prices (e.g., SWCAP) can be low enough to control market power

• This is usually done with constraint violation pricing/penalty functions that:

– Allow, but impute increasing costs to, constraint violations during scarcity

– Are tuned so that constraints are violated “in the right order” (e.g., reserves are

used before load is shed) and prices increase “appropriately” with scarcity


Defining such pricing/penalty functions requires high-level policy/ commercial judgments informed by technical and economic analysis

Must Be Fixed Over Time: Scarcity Pricing

ERCOT’s “Maximum Shadow Prices”• ERCOT is developing “the methodology for setting Maximum Shadow

Prices” (MSPs) for SCED constraints (with TAC consultation and for Board review/approval) in the form of pricing/penalty functions that would:

– Be a single MSP (in $/MW of violation) for each network constraint and an up-to-10-step function increasing to a MSP for the power balance constraint

– Increase the shadow price on any violated SCED constraint, thereby increasing LMPs (progressively with scarcity, for the power balance constraint)

• ERCOT has not yet proposed specific MSPs or steps, but the result will almost surely NOT produce effective scarcity pricing in ERCOT, because:

– ERCOT does not seem to be contemplating MSPs > SWCAP

– More importantly, in practice operators will respond to scarcity with non-SCED actions – e.g., they will issue an Energy Emergency Alert and then call NSR (Non-Spinning Reserve) and EILS (Emergency Interruptible Load Service) – to keep the system far from shedding load (which is what “violating the SCED power balance constraint” means)



The MSPs on SCED constraints will kick in too late to have any RT effect and too rarely to have any long-term effect

Implementing Scarcity Pricing in ERCOT

• ERCOT could develop an effective scarcity pricing mechanism

– By including operating reserves and EILS in the SCED, as resources that are

called at increasing prices – similar to the “pseudo resource” approach that was

proposed and rejected early in the market design process

– Perhaps easier as a short-term fix, by defining a non-SCED function that

increases prices as operators call on more reserves and EILS

– As such scarcity pricing is developed, the offer cap (SWCAP) can be decreased

enough to be effective against market power and a (much?) higher price cap

can be set to reflect the “value of lost load” (VoLL)

• The process of developing effective scarcity pricing

– Does not need to be completed immediately, at least not if ERCOT currently has

adequate generation and load resources and network capacity; but

– Will take time, so it should be started soon, well in advance of the actual need


ERCOT needs a transparent, high-level process to explain and get political support for effective scarcity pricing at least for the long run


Settlement at Shadow Prices – Summary

• The Protocols often refer to “Shadow Prices [SPs] on constraints” or “… from the algorithm” as “Market Clearing Prices” (MCPs), and use these SPs/MCPs as settlement prices

• But the conflation of SPs with MCPs involves some implicit assumptions that are not always valid given provisions of the Protocols; in particular:

– The Protocols allow extensive use of “integer” variables, such as three-part offers

in the DAM and block bids/offers in the DAM and any SASM

– The resulting mixed integer programming (MIP) problems are inherently difficult

to solve, but modern technology can find a solution – the cleared bids and offers

– that (approximately) maximizes the gains from trade

– But the SPs from a MIP solution may not “clear the market”, i.e., settling all

trades at SPs may not equate demand to supply for individual MPs or overall

– And a small change in (e.g.) network conditions or a single bid/offer can make a

big difference in the SPs and the mix of cleared bids and offers


ERCOT should be aware of the potential problems here, and be prepared to (e.g.) limit bids and offers or change pricing rules if necessary

Watch and Be Ready

4

With Integers/Blocks, there May Be No MCPs

1 24

MWh

When Demand > D*,“B In” is Least-Cost

SPIN

1 2 3MWh

SPOUT

When Demand < D*,“B Out” is Least-Cost

B B

OPB

D* D*

B = All-or-None Block with Offer Price OPB

Demand Shadow Price = SPIN Demand Shadow Price = SPOUT

B should be IN, but cannot cover its costs @ settlement price = SPIN if it is IN, so will try to stay OUT

B should be OUT, but can make money @ settlement price = SPOUT if it is IN, so will try to avoid being OUT

OPB

The SP does not “clear the market”; in fact, no single price doesThe INs/OUTs and SPs are unstable and often inexplicableMPs will/must use strategies (games?) to try to get what they want

3



The Effects of Settling at Simple SPs

• Using the Shadow Price (SP) from a MIP solution as the settlement price can have perverse effects; for example:

– Cleared offers and bids may be inconsistent with their prices and the SP; for

example, an offer to sell may be accepted even though the offer price was > SP,

implying the offerer will be required to sell at a loss

– The SP and the mix of cleared bids and offers can change significantly with small

changes in (e.g.) network conditions or a single bid or offer

• Such perverse and unstable price/quantity outcomes can:

– Be difficult/impossible to explain or justify to affected MPs and regulators

– Induce strategic bidding/offering and deviations from market outcomes (e.g.,

dispatch instructions), as MPs try to avoid selling at a loss or missing profit

opportunities

• Such problems:

– Can be ignored, in hopes that MPs will not complain or game too much

– May not be too bad if (e.g.) each block bid/offer is small relative to the total



How Important Is All This for ERCOT?

• For unit commitment, with three-part offers, it cannot be ignored

– Generators need make-whole payments to encourage voluntary participation in

the commitment process (or even to get/keep them in the market at all)

– But if loads pay only simple SPs for energy (as in ERCOT) they can have either

too much or too little incentive to reduce demand

• The problem may also be important in the AS Markets, which allow integer AS Offers but have no make-whole payments

– A Load Resource may have its Block RRS Offer taken even though the MCP for

RRS is below its bid-based costs

– Generation Resources may be allowed (ERCOT must decide) to submit AS

offers with complex either/or and all-or-none constraints [4.4.7.2(1)]

• It is unclear how important this will be in practice, but ERCOT should:

– Be careful when using simple SPs for settlement in complex situations

– Consider limiting the complexity of bids and offers to get better prices and/or

using more complex pricing rules such as “minimize uplift”



RUC and RUC Clawback – Summary

• ERCOT’s Reliability Unit Commitment (RUC) process differs from, and involves more complex settlements than, RUC processes in other ISO markets. For example, the ERCOT process:

– Runs after the DAM to minimize RUC commitment costs only (like some ISOs but unlike others that include RUC units in the final DAM pricing run)

– “Claws back” some or all of a RUC unit’s offer-based profits (which no other ISO market does), with higher claw-back for units not offered in the DAM

– Allocates RUC costs to QSEs based on each QSE’s “capacity shortage”, with any final balance allocated to QSEs on a load-ratio share basis

• These complex arrangements are difficult to analyze, but they may create incentives (as examples only):

– For loads to understate demand in the DAM and rely on RT

– For generators to self-schedule to avoid claw-back

Page 54

RUC will probably create risks and problems,1 but we have not studied it enough to know – and only testing/experience will really tell

1 See presentation to ERCOT by William Hogan, “Texas Nodal Market Design”, May 2, 2008, and testimony to PUC by David Patton, December 4, 2005, for discussions of RUC effects and risks.


Watch and Be Ready

SCED and 2-Step Mitigation – Summary

• The SCED (Security-Constrained Economic Dispatch) process that determines RT dispatch instructions and RT energy prices has some problematic features, including (as examples only):

– Instantaneous optimization every 5 minutes based on then-committed resources, with no look-ahead (cannot commit units that will take more than 5 minutes to begin producing) or ramp rates (may call for energy that cannot be produced)

– No optimization of AS (capacity designated for AS in earlier processes cannot be used for energy in RT or vice versa)

• The SCED also includes a 2-step offer price mitigation process that:– First computes LMPs with all network constraints ignored except those determined

earlier to be “competitive”, i.e., affected by many resources

– Then computes final/settlement LMPs considering all constraints but capping offer prices based on the first LMPs

– Is similar to such processes elsewhere, but also has some innovative features


Watch and Be Ready

The SCED (like RUC) will probably create risks and problems, but only testing/experience will really reveal what and how important they are

Documents

© ERCOT & Market Reform, 2010. Nodal Protocols Risk Assessment Presentation to the ERCOT Board 16 August 2010 Phase 1: Overall Assessment, Identification