marjket operations standing committee imo day ahead market design update market operations standing...

Marjket Operations Standing Committee

IMO Day Ahead Market Design Update

Market Operations Standing CommitteeSeptember 22, 2003Market Evolution Program

Long-Term Resource Adequacy UpdateJason Chee-Aloy

Market Operations Standing Committee of the IMO September 22, 2003 Slide 2

Long-Term Resource Adequacy Update

Agenda

Long-Term Resource Adequacy Chronology

Identified Paths and Long-Term Resource Adequacy Working Group Update

Next Steps


Long-Term Resource Adequacy (LTRA) - Chronology Summer 2002 - Market Participants identified resource adequacy as a high priority issue

in response to the IMO Straw-Plan for Market Evolution Fall 2002 - IMO 2003-2005 Business Plan states resource adequacy as a principle

objective in the evolution of Ontario’s electricity market February 2003 - work commences on the LTRA project March 2003 - first meeting of the LTRA Working Group (LTRAWG)

• Over 25 members (w/ diverse membership)

• LTRAWG meets every 2 weeks June 2003 - Feasibility Assessment published

• Identifies Paths/Options to address LTRA

• Contains several recommendations but does not champion a single Path/Option June 2003 - Market Advisory Council supported Feasibility Assesssment

recommendations July 2003 to Present - LTRAWG continuing discussion on specific recommendations to

address LTRA



Agenda


Identified Paths and Long-Term Resource Adequacy Working Group Update

Next Steps


Potential Paths to Address Long-Term Resource Adequacy

Path A: Complete the initial market design and structures without an explicit Resource Adequacy Requirement (RAR) Rely on results of improved energy and ancillary service markets alone (e.g. Pricing Team

work, day-ahead market, multi-interval optimization, etc.)

Path B: Create Load Serving Entities (LSE) and assign a RAR to these entities LSEs required to contract forward capacity requirements through bilateral contracts (different to

bilateral contracts for energy) IMO could administer a resource adequacy auction market (similar to NYISO and PJM) as a

complementary element to LSE capacity contracts

Path C: Allow a central agency to procure adequate resources and allocate the resource acquisition costs to loads IMO administers a resource adequacy auction market and secures forward capacity on behalf

of loads (NYISO, PJM and ISO NE are developing)


Long-Term Resource Adequacy Working Group Update

Key points from the current discussion:

• LTRA encompasses all interrelated aspects of the Ontario electricity market• Recommendations will contain necessary elements that will help Ontario

move toward a complete, workable and sustainable approach to addressing LTRA, under a competitive market framework

• Elements of the identified Paths (from the Feasibility Assessment) are likely not mutually exclusive

LTRAWG is now focussing on:• The high level detail how an explicit resource adequacy requirement may be

workable• Interim/transitional mechanisms that may be required



Agenda


Long-Term Resource Adequacy Working Group Update

Next Steps


Next Steps

LTRAWG continues to meet every 2 weeks

Update to IMO Board on LTRAWG on October 3, 2003

Update to Market Advisory Council on October 8, 2003


IMO Day Ahead Market Design Update

Market Operations Standing CommitteeSeptember 22, 2003Market Evolution Program

Day Ahead Market UpdateLeonard Kula


Day Ahead Market Design Update

Agenda

DAM Chronology

DAM Design and Features

DAM Pricing Options

DAM Benefits

Next Steps


Day Ahead Market (DAM) - Chronology Fall 2002 - IMO 2003-2005 Business Plan identifies that a DAM is a critical element

in creating a more effective, reliable and mature market January 2003 - work commences on the DAM project February 2003 - call for DAM Working Group (DAMWG) members

• ~ 28 members from all industry sectors (generators, loads, transmitter, distributors, marketers, OEB and OEFC)

• meet every ~10 days - 23 meetings to-date April 2003 - DAMWG recommends further development of a comprehensive DAM

• closely aligned with day ahead markets in neighbouring jurisdictions May 2003 - DAM hi-level design summary prepared June 2003 - broad stakeholder consensus obtained regarding design direction and

plan to continue to develop DAM (Market Advisory Council) July - Aug 2003 - DAMWG discusses hi-level design concepts and reviews hi-level

design strawman



Agenda

DAM Chronology


DAM Pricing Options

DAM Benefits

Next Steps


Day Ahead Market - Initial Options

R e a l T im eM a rke t o n ly

C u rre n t

No DAM

C le a r o ffe rs /b ids(ig n ore con g e stio n)

F in a nc ia l co m m itm e nt

O p tio n 1

Sim ple DAM(e.g. Energy Forw ard

M arket)

financial com mitm ent+ unit com m itm ent

(considers congestion)

real-tim e marketbecomes a

balancing market

sa m e se tt le m e nttre a tm en t as

cu rre n tre a l-t im e m a rke t

g e n era to rs re ce ive ...u n ifo rm p rice +

s id e p a ym e n ts fo rco n g e s tion (C M S C)

lo a ds pa y...u n ifo rm p rice +

u p lift fo rco n g e s tion (C M S C)

O p tio n 2u n ifo rm p rice m o d e l

g e n era to rs rece ive(a n d so m e loa d s p a y)

...n od a l p rice

(m o st) lo ad s pa y...u n ifo rm p rice

(w e ig h te d a vera geo f n od a l p rice s)

O ptio n 3An o d a l p rice m o d e l

g e n era to rs re ce ive ...n o d a l p rice

lo a ds pa y...n o d a l p rice

O ptio n 3Bn o d a l p rice m o d e l

Com prehensive DAM

Day Ahead Market (DAM) Evolution




C u rre n t

No DAM



O p tio n 1


M arket)




balancing market









...n od a l p rice







Com prehensive DAM





C u rre n t

No DAM



O p tio n 1


M arket)




balancing market

sam e settlem enttreatment as

currentreal-tim e market

generators receive...uniform price +

side payments forcongestion (CM SC)

loads pay...uniform price +

uplift forcongestion (CM SC)

Option 2uniform price m odel


...n od a l p rice







Com prehensive DAM



What Is Meant By A Comprehensive Day-ahead Market?The DAM WG recommended further development of a Comprehensive DAM (April 2003).

Key features include: A financial market administered by the IMO, which accepts supply offers

and demand bids and clears the market at day-ahead prices.• Creates a 2-settlement system, with the RTM a “balancing” market.

Integrates a 3-part bid process to optimize unit commitment for:• Supplies available to the DAM to meet loads buying in the DAM• Supplies available to the RTM to meet RTM forecast load

A multi-pass process for committing units, arranging DAM schedules, and defining DAM prices, plus indicative schedules for the RTM.

The use of uplifts to cover commitment costs not recovered from market revenues.

The simultaneous optimization of energy and operating reserves, and the optimization of the market over the 24 hour period.


DAM - Design And Features

The Proposed DAM would: Be based on...

• supply offers to sell and demand bids to purchase energy • supply offers to sell operating reserves

Be open to all MPs

Include imports and exports

Allow virtual offers and bids

Include an IMO-optimized unit commitment process

Use multiple commitment and/or dispatch passes to optimize results


A DAM Functions Before The RTM In A Two-Settlement System

Day Ahead MarketMPs offer to sell and bid to buy energy in real time.

Offers/bids used to define RT schedules and prices

IMO uses offers/bids to arrange constrained dispatch

2nd Settlement =

Quantity Deviations from DA purchases and sales times RT prices

PRT(QRT - QDA)

MPs offer to sell and bid to buy energy day ahead.

Offers/bids used to define DA schedules and prices

DA schedules are financial obligations to buy/sell energy at DA prices

1st Settlement =

DA purchases and sales times DA prices

(QDA x PDA)+

Real Time Market


Virtual Supply Offers And Load Bids Add Liquidity To DAM And Converge DAM And RTM Prices

Day Ahead Market

Participation unavoidable

Commitment to buy Q in RTM

Commitment to sell Q in RTM

Converge to expected RTM prices

Participation voluntary

• MPs submit virtual offers to sell Q in DAM =

• MPs submit virtual bids to buy Q in DAM =

• With virtual offers/bids, DAM prices tend to =>

Real Time Market


The Day Ahead Market Includes A Unit Commitment Process For DAM and RTM

Day Ahead Market

IMO-committed units from DA unit commitment are available for dispatch to meet RT loads

IMO arranges security-constrained economic dispatch from supply offers and demand bids

MPs submit 3-part price offers:

(1) Incremental energy

(2) Start-up costs

(3) Minimum generation costs

IMO optimizes commitment and commits units for:

(1) DAM bid-in load

(2) Forecast RT load

Bid Production Cost Guarantee (BPCG) - Generators made whole if DAM revenues don’t cover full bid-in costs

Real Time Market


DAM Uses Multiple Passes To Commit Units And Define Dispatch Schedules And Prices

Pass 2

Commit units to meet RT forecast

load

Pass 3

Optimize dispatch/define

schedules to meet DAM bid-in load

Pass 4

Dispatch to indicate schedules/prices for

RT forecast load

Pass 1

Commit units to meet DAM bid-in

load

(Optional)


Proposed DAM Uses Multiple Passes To Define Commitments For DAM And RTM

Pass 2

Pass 1 and Pass 2 optimize unit commitment using 3-part offers/bids

IMO optimizes and commits more units to meet forecast RT load

Constrained pass

Physical Suppliers Physical Loads Exports/Imports

No Virtuals

Pass 1

IMO optimizes commitment and commits units to meet bid-in DA load

Constrained pass

Physical Suppliers Physical Loads Exports/Imports

Virtual offers/bids

Results


Committed Units Are Used To Define Schedules And Prices For DAM (and RTM)

Given the units committed in Passes 1 & 2, Passes 3 & 4 define schedules and prices

Pass 4

IMO optimizes dispatch for forecast RT load

Defines indicative schedules & prices for RTM

Constrained pass

Pass 3

IMO optimizes dispatch over 24 hours for bid-in load

Defines DAM schedules and nodal prices

Constrained Pass


Committed Units May Not Recover Bid Costs From Market. Uplifts Are Needed

Pass 2

Principle: Those on whose behalf the commitment costs were incurred pay the associated uplift

Committed units entitled to bid-cost payment guarantee

Uplift for these units paid by net RT loads (those who chose not to participate in DAM)

Uplift based against DAM revenues

Pass 1

Committed units entitled to bid-cost payment guarantee

Uplift paid primarily by all physical RT loads

Uplift based against DAM revenues


Efficient Results Need Consistent Schedules and Price Formation Between DAM And RTM

Day Ahead MarketSchedules

From constrained dispatch.

Based on all units with closed breakers or able to close breakers within 5-minutes

Prices

From constrained dispatch.

Based on all units with closed breakers or able to close breakers within 5-minutes

Schedules

From Pass 3 = constrained, Includes all committed units

Prices

From Pass 3 = constrained

Limited to committed units and quick start units

Real Time Market

OK

OK


Moving Import & Export Trades To The DAM Should Reduce IOG Payments And Uplifts

Day Ahead Market

RTMs are 5-minutes

Imports offer to sell into RTM

Exports bid to buy from RTM

Imports/exports are cleared in the pre-dispatch, but settled at RTM prices

IMO must pay intertie trades at their offers if RTM prices are not enough to cover offer prices for pre-dispatch schedules

DAM is hourly

Imports offer to sell into DAM

Exports bid to buy from DAM

Imports/Exports are cleared in the DAM and settled at the DAM prices

No intertie offer guarantee payments are needed for DAM import/exports

Real Time Market


Imports And ExportsThe procedures proposed for the IMO to schedule imports and exports in the DAM are generally similar to the procedures that it uses to schedule internal generation and loads in the RTM.

Imports In The Reliability Commitment When it is necessary to commit additional generating capacity to ensure that the IMO will be able to meet its load forecast: Only the commitment costs of slow-starting generation will be

considered when determining whether it should be committed. In cases when the offer for an import is less than the commitment

costs of internal generation, selecting the imports can reduce the cost of committing additional units to cover forecast load.

The IMO will charge net real-time load for the cost of committing these imports.

Committing these imports can reduce the amount that real-time load needs to pay in these circumstances.


Transmission Rights Settlements

Once the DAM is implemented, TRs will need to be settled in the DAM.

Transmission rights could be options or obligations (still to be discussed in detail).

DAM schedules are obligations.

Settling TRs in the DAM will maintain revenue adequacy for the IMO.

The FTRs and the DAM schedules otherwise would constitute competing sets of claims on RTM congestion rents.



Agenda

DAM Chronology


DAM Pricing Options

DAM Benefits

Next Steps


A Day Ahead Market Based Upon Uniform Pricing?

The Comprehensive Day Ahead Market was expected to comprise a constrained schedule of resources and a uniform price methodology to determine prices for the DAM and RTM to converge, require consistent methods in

DAM and RTM to determine schedules and prices the current real-time market determines schedules on a

constrained basis the current real-time market determines price using a uniform

pricing methodology

The DAM WG examined the implications of employing a uniform pricing methodology in the DAM.


“Uniform” Pricing Is Misnamed. It Has Locational Differences, But The Wrong OnesA so-called “uniform” pricing system must pay different prices to generators at different locations whenever there is congestion.

During congestion, the value of energy necessarily varies at different locations, because transmission constraints prevent some cheaper generation from getting to some loads. • Lower-cost generators at some locations must be “constrained off” to

relieve constraints, while at other locations . . .• Higher-cost generators must be “constrained on” to meet load.

The IMO cannot manage congestion in a market without paying different prices to generators at different locations relative to the congestion. • Otherwise, generators would not follow dispatch instructions.

During congestion, uniform prices must therefore be augmented by side payments that vary by location, depending on the extent and location of the congestion and the prices that generators offer.


“Locational” Prices Under Uniform Pricing Are Not Efficient and Not “Market” PricesAlthough generators at different locations are paid different prices under uniform pricing whenever there is congestion, the resulting prices are not true market-clearing prices and are not efficient.

Generators paid “constrained-off” payments are usually paid more than their energy is worth (they are paid not to run or produce less).

• And they have an incentive to adjust their offers to maximize the side payments they receive for not running or producing less.

Generators paid “constrained-on” side payments are often not paid as much as their energy is worth. They’re paid “as bid.”

• So they have an incentive to adjust their offers to maximize the side payments to try to capture the market value, but they have to guess and will often be wrong, yielding inefficiency – there is no transparent market price.


A Uniform Pricing System Is Problematic

The current uniform pricing system is the root source of several problems. It creates price incentives that may:

Encourage supply and demand-side investments at the wrong locations.

Discourage supply and demand-side investments at the right locations.

Every US ISO that has tried uniform pricing had to develop extensive non-market mechanisms to counteract the undesired incentives from uniform pricing. Eventually, each such US ISO concluded that it must replace uniform pricing with nodal locational marginal pricing for generators.


Uniform Pricing “Simplicity” Is A MythA uniform pricing system is always more complex than the alternative of settling generators at their respective nodal prices. Requires a complex set of side payments that are non-transparent -- This

complexity will be magnified with a DAM, as shown in the July 28 presentation to the DAM WG. (Only 8 of 64+ cases were shown.)

Experience in other markets has shown that some generators can be encouraged to manipulate their offer prices to maximize the side payments. • This problem will substantially increase with a DAM if based on uniform

pricing. (See, California ISO web site re Enron practices)• Extensive administrative rules will be needed to monitor, limit and

counteract this behaviour

Conclusion of DAM working group (August 19, 2003): A Day Ahead Market under a uniform pricing regime would be costly to

implement and maintain, complex and confusing, and is not recommended


Day Ahead Market - Pricing Options


C u rre n t

N o D A M



O p tio n 1

S im p le D A M(e .g . E n e rg y F orw a rd

M a rke t)




balancing market








generators receive(and som e loads pay)

...nodal price

(m ost) loads pay...uniform price

(w eighted averageof nodal prices)

Option 3Anodal price m odel

generators receive...nodal price

loads pay...nodal price

Option 3Bnodal price m odel

Com prehensive DAM



Nodal Pricing Is Simpler, More Efficient

For Generators: Unlike uniform prices, the nodal prices make intuitive sense to generators – they are consistent with the generators’ offers.• If not dispatched, the nodal prices were below the offer• If partially dispatched, the nodal prices are consistent with the offer• If fully dispatched, the nodal prices will be at least as high as and possible

higher than the offer.

For Dispatchable Loads: Nodal pricing provides correct incentives for price-responsive demand • Sends correct price signals about the value of demand-side responses at

different locations

For the IMO: Unlike uniform prices (even with side payments), nodal prices are consistent with the actual dispatch.• So the price signals are consistent with what the IMO needs the

generators to do to maintain reliable operations.• So complex rules for side payments aren’t needed for reliability.


Nodal Pricing For Generators Can Coexist With ‘Uniform Pricing’ Applied To Loads

The nodal pricing framework used in US ISOs continues to settle most loads at “zonal” prices, which are averages of nodal prices for each utility’s service area.

This construct could be used in Ontario if it wishes to continue charging all consumers the same price for energy, as today. In this scenario, ‘uniform prices’ could be the weighted average price of all load nodes.

It should be understood that any averaging scheme introduces some inefficiency and inherently involves cost shifts. For reliability purposes, this is not a serious problem, except for those customers/loads that could participate in price-responsive demand opportunities.


Day Ahead Market - Nodal Price Model

Need to assess the impact of a nodal pricing solution before making recommendations: Market Participants

• While the DAM WG agrees that Uniform Pricing in a DAM is not workable, more analysis of nodal pricing is needed:

– pricing impact - historical and going-forward

– broad Market Participant education and stakeholdering

Impact upon DAM design• DAM based upon nodal pricing is simpler• System of transmission rights for internal congestion required

Impact upon RTM design• RTM would need to be settled on nodal basis - settlement system

changes



Agenda

DAM Chronology


DAM Pricing Options

DAM Benefits

Next Steps


Day Ahead Market - Benefits

Improved point of convergence for forward products DAM provides a transparent and predictable price that converges on the

RTM price

• Lower volatility - DAM price volatility lower than RTM price

• Greater liquidity - DAM explicitly allows non-dispatchable load bids and ‘virtual’ participation

• Price convergence - ‘virtual’ participants in DAM encourage price arbitrage between DAM and real-time market

DAM price better than RTM price as an index - facilitates forward price curve development contracting

Experience in other markets...

• Contracting in PJM and NY > 50% of market

• PJM futures activity setting volume records on NYMEX


Day Ahead Market - Benefits

Improved reliability Allows for direct participation of all loads in market

• Additional opportunity for demand-side response

Improved commitment process• Allows IMO to commit sufficient resources to meet forecast demand• Drivers to ensure committed resources ‘show-up in real-time’• Utilizes 3-part offer construct and provides BPCG

Imports and exports priced and scheduled day-ahead• Moves transactions from RTM to DAM and reduces intertie trading

uncertainty – Should reduce number of failed intertie transactions– Should reduce Intertie Offer Guarantee (IOG) uplift

payments



Agenda

DAM Chronology


DAM Pricing Options

DAM Benefits

Next Steps


DAM - Next Steps

Assess Impact of Nodal Pricing

• The DAM WG will continue to address DAM-related issues,

including those related to nodal pricing

• Need to determine appropriate vehicle to stakeholder issues

related to impact of nodal pricing in RTM

Complete DAM High Level Design Strawman

marjket operations standing committee imo day ahead market design update market operations standing...

Documents

dayahead market

market project draftlong

market participants

market evolutionfall

market project draftnext

resource acquisition

initial market design

market advisory council