challenges of the next generation energy market … lmp (nodal price) at bus i can be calculated...

Sponsored by the IEEE GREECE PES CHAPTER

By

Alex Papalexopoulos, Ph.D. President & CEO, ECCO International, Inc.

[email protected]

October 6, 2011 Athens, Greece

Challenges of the Next Generation Energy Market Design Structures

mailto:[email protected]

Copyright 2011, ECCO International, Inc. 2

Outline

Overview of the key competitive energy market models Current status of energy markets Major Challenges Competitive Energy Markets Face Today Capacity Markets Transmission and Infrastructure Investment Issues Renewable Energy Sources Market Issues Demand Response Markets Summary

Exchanges – NordPool, Australia, California (old design), Spain, Poland, Ontario)

Pools – Britain (until 2001), various markets in the USA, Chile, Alberta, Argentina, Columbia, Singapore, Greece

Central Optimization Bilateral 100% – Britain (since 2001) Bifurcated – NY, PJM 60% bilateral Self-Scheduled

40% Dispatched voluntarily Market Clearing, Self-Scheduling

Various Markets for Energy

3 Copyright 2011, ECCO International, Inc.

0

10

20

30

40

50

60

Self-supplied Bilateral transactions

Spot market Imports

Market type

Mar

ket s

hare

(%)

Year 2007 Year 2008

PJM Energy Markets


Presenter

Presentation Notes

PJM day-ahead energy market opens June, 2000

None – PJM (before 2001) Unit Commitment & Dispatch – California, NE,

NY, PJM, NZ, Greece, etc. TSO procures needs – if not self-provided Daily Procurement Auctions – All U.S. markets TSO controls dispatch of sufficient units

Long-Term Bilateral Contracts – Britain, Sweden, Poland, Cyprus TSO procures needs through annual contracts Reliability-Must-Run: California imposes contracts on these units Annual auctions for fast-start/ramp resources: New England

Markets for Ancillary Services


Transco's (ITCs) – Britain, NordPool, Poland, NZ, Chile

System Operators – Australia, Canada [power pools] U.S.: California, Texas, New England, NY, PJM

Zonal Pricing – NordPool, Australia, California (old model) Texas (old model)

TSO charges marginal cost of inter-zonal congestion Explicit market for adjustments to alleviate congestion

Nodal Pricing – California, NY, PJM, NE, Texas, NZ TSO charges marginal cost at every location

Markets Structure for Transmission


NONE – Some argue that Transmission = Public Good Better reliability, more competitive and liquid energy

markets TSOs can procure adjustment services via long-term

contracts as in Britain, Sweden, if congestion is infrequent ZONAL PRICING – Proponents argue for commercial

simplicity and forward sufficiency – but has been under severe attack – California and Texas have abandoning it Firm and Physical Transmission Rights and hedges remain

controversial The “DEC Game” in California & Texas was fatal; it

resulted in Billions of Dollars of losses to consumers

Key Principles of Various Transmission Markets


LOCATIONAL/NODAL PRICING – Preferred method in the USA Full transmission is part of the market clearing mechanism All resource, system, security and transmission constraints

are priced – thousands of prices are created and used for settlements

Financial Rights (i.e., locational hedges) are required (FTR market) Point-to-Point vs. explicit pricing of flow-gates Formation of secondary markets

Key Principles of Various Transmission Markets


The Impact of Congestion

A B

qAB pB

pA

p

qAB q1


Congestion Management vs Transmission Investments

Fundamental tradeoff: congestion vs. investment costs What’s optimal?


11

Zonal Market Design Flaws

Operationally infeasible plan Reliability problems Socialization of constraint mitigation cost Price reversals in reserve markets due to auction structure Un-priced inter-temporal products and constraints – Need

Unit Commitment Improper price signals for investments Sequential solution of simultaneous problems – Need Co-

optimization of Energy and Ancillary Services One settlement system As-bid pricing It does not support RES and Demand Response

Copyright 2011, ECCO International, Inc.

Why Nodal?

Market efficiency: minimization of production cost System-wide, incentive-compatible

System-wide and local reliability Advanced locational signal for buyers and sellers to match

next day needs and supplies Economic signal (LMP) to Generators and Demand

Response while protecting load Congestion risk management (CRR/FTR/TCC) and

transmission planning

12 Copyright 2011 ECCO International, Inc

Transition from Zonal To Nodal (LMP) Market

• No intra-zonal constraints enforced • Internal Congestion Zones – Constraints enforced between zones

• Full Network Model (All constraints enforced) • Locational Marginal Pricing at each node

North

South

Middle


Presenter

Presentation Notes

One of the major elements of the new market design is the implementation of the Full Network model. Today, congestion is solved only between the three internal zones (NP15, ZP26, and SP15) and at the interties. With the implementation of MRTU, the entire CAISO network will be modeled. Congestion on all transmission lines will be accounted for in the dispatch in both the DA Market and the Real Time Market. The modeling of all the network will allow for more accurate Day Ahead Schedules, will increase transparency since all network nodes will be taken into consideration and priced accordingly and will reduce the amount of out of sequence dispatching that currently occurs in Real Time.

Zonal Model • Few zones; solve inter- zonal congestion via markets • Congestion within the zones small and infrequent • Socialize intra-zonal congestion

Locational Marginal Pricing (LMP) • All nodes are priced (LMPs) • Nodal prices reflect cost of energy, congestion and transmission losses

Nodal Model • Models the entire TSO Grid • Simulates grid operation considering transmission limitations and energy schedules submitted • All scarce resources are priced

Zonal Pricing • Pricing only the zones • Does not address congestion within a zone


Copyright 2011, ECCO International, Inc 14


Physical Transmission Rights • Physical rights across borders only • They are obtained in auctions • They provide scheduling priority

Congestion Revenue Rights (CRRs) or FTRs • Financial rights available between any two points in the network • Annual CRRs • Monthly CRRs • Long Term CRRs • Separate from operations Sequential Markets

• Higher procurement costs • Price reversals • Can lead to scarcity

Integrated Forward Markets • Simultaneous optimization of Energy, Congestion Management and Ancillary Services 15 Copyright 2011, ECCO International, Inc

It is a forward contract in which the holder is entitled to receive the Locational Marginal Price difference (may be negative) between the point of ejection and point of injection, LMPb - LMPa

FTR Payoff (LMPb – LMPa) g

LMPb-LMPa

FTR holder pays TSO

TSO pays FTR holder

FTR – PTP Obligation


It is a forward contract in which the holder has the right (not obligation) to receive the Locational Marginal Price difference (if positive) between the point of ejection and point of injection, LMPb – LMPa

FTR Payoff (LMPb – LMPa) g

LMPb-LMPa FTR holder pays nothing to TSO

TSO pays FTR holder

FTR – PTP Option


LMPs can be split into 3 components: E + C + L

18 Copyright 2011, ECCO International, Inc

The LMP (nodal price) at Bus i can be calculated using the following equation

λi = λref - Li * λref - Σj (μj * SFji) where

λi = Nodal price at bus i λref = Nodal price at the reference bus Li = Marginal loss factor at bus i = (∂Ploss/∂Pi), Pi is injection at bus i and

Ploss is the system losses μ j = Shadow price of constraint j SFji = Shift factor for real load at Bus i (the reference bus (ref) is the

reference bus for this shift factor) on constraint j

LMP Price Determination

. Copyright 2011, ECCO International, Inc 19

Locational Marginal Prices in Nodal Markets


Extreme Congestion


Key Elements of an LMP Energy Market Design

Real-Time Markets

Transmission & Ancillary Services Markets

Reliability Unit Commitment (RUC)

Financial Transmission Rights (FTRs)

Forward Energy Markets/Bilateral Markets

Capacity Markets 22 Copyright 2011, ECCO International, Inc.

Virtual Markets

Virtual Markets: Incs (Virtual Supply)

An Increment Offer (INC) or virtual supply offer is an offer to sell a specified MW quantity in the DAM at a designated location (Hub, Zone, Node) if the Day Ahead Market LMP at that location is at or above the offer price

If the INC clears the Day Ahead Market, the Participant is a seller at that location at the Day Ahead LMP

Since the transaction is virtual, the Participant becomes a buyer of that same MW quantity at the Real Time market LMP for that location


Virtual Markets: Decs (Virtual Demand)

A Decrement Bid (DEC) or virtual demand bid is a bid to buy a specified MW quantity at a designated location (Hub, Zone, Node) in the Day Ahead Market (DAM) if the DAM LMP at that location is at or below the bid price

If the DEC clears the Day Ahead Market, the Participant is a buyer at that location at the Day Ahead Market LMP

Since the transaction is virtual, the Participant becomes a seller of that same MW quantity at the Real Time market for that location


LMPs & Ancillary Services Prices

When the market clears it produces along with the LMPs the Ancillary Services Marginal Prices for each region (RASMPs) and for each service

Energy and energy are coupled through the resource’s Capacity limit constraints

If these constraints are binding the LMPs are impacted The RASMPs for each service is the shadow cost of the AS constraint

for the service at the optimal solution All resources in the region are paid the same regional price (ASMP) Units that belong in more than one region are paid the summation of

the RASMPs of the over-lapping regions


Benefits of Energy-AS Co-optimization

Efficient Unit Commitment and Energy/AS schedule Lower overall cost

Efficient allocation of inter-tie transmission capacity Accurate representation of opportunity cost in LMP and AS

Marginal Price (ASMP) ASMP ≥ AS Bid + Opportunity Cost (OC)

Opportunity Cost = |LMP – Energy Bid| If LMP < Energy Bid → OC = 0 If a resource has not submitted an energy bid and is not under an

obligation to offer energy, then OC = 0


Presenter

Presentation Notes

Transmission capacity must be reserved on inter-ties for Ancillary Services imports. The most efficient solution is achieved by co-optimizing Energy and AS so that AS Capacity and Energy schedules can compete for inter-tie transmission capacity.

State of the Art Modeling

Start Up Cost & Unit Start Up Time Functions Forbidden Regions & Ramp Rate Functions Inter-temporal Constraints (Minimum Up/Down Constraints,

Start-Up Time, Maximum number of Daily Start-Ups, Daily Energy Limit, etc.)

Various types of network constraints (Full AC Power Flow Solution, Transmission Constraints, Inter-Tie Energy/AS Constraints, Nomograms, Contingency Constraints, etc.)

MIP based Security Constrained Unit Commitment for the co-optimization of the energy, ancillary services and transmission markets


Presenter

Presentation Notes


Mixed Integer Linear Programming (MILP) Separate power flows for each time interval Iterate with optimization engine that has a single power balance constraint

and the active inequality constraints for each time interval

Power Flow Power Flow Optimization Engine Power Flow Power Flow Power Flow Power Flow

Schedules

PTDFs Loss marginal rates

Current Dominant Solution Methodology


Presenter

Presentation Notes

Power flow and security analysis take place for each time period separately in parallel processors. Active constraints are identified (the ones that are either violated or are close to their limit) and their linearization is passed to the optimization engine.

MILP versus ALR Comparison

Capability MILP ALR Flexibility for adding new constraints and models Yes No Flexibility of modeling a large number of coupling constraints Yes No Dynamic ramp rates & Forbidden regions with crossing rules Yes No Advanced infeasibility detection Heuristics to achieve a feasible solution No Yes Block dispatchable transactions Yes No

Optimal automatic discrete relaxation of infeasible constraints

Yes No

Lower bound on the optimal solution Yes No

Performance fast enough fast


Next Generation of Energy Market Design

Develop Multi-Day Unit Commitment (issues: bid replication, performance)

Co-optimize Energy/AS/FTRs in the DAM to hedge congestion in RTM

Implement Nodal Pricing for Loads (issues: economic hardship on entities located in load pockets)

Co-optimize generation dispatch for congestion management and network reconfiguration, i.e., transmission switching (issue: network reconfiguration solution does not ensure revenue adequacy in the FTR market)


Presenter

Presentation Notes



Co-optimize Markets and Reliability (Co-optimize Energy, AS, Transmission & RUC products)

Develop Functional Capacity Markets Develop Transmission Markets and Policies for

Transmission Investments Develop Market Mechanisms to Manage High Penetration of

Renewable Energy Sources (RES) Develop Demand Respond Market Mechanisms


Presenter

Presentation Notes


32

DAM-RUC Co-Optimization

One integrated approach Two power balance constraints

Generation Schedule = Load Schedule Generation Schedule + RUC Capacity = Demand Forecast

Pros Only one pass Maximum efficiency Effective mitigation Better manage over-

generation conditions

Cons May be difficult to isolate RUC

commitment cost Congestion costs from RUC

capacity More complex to implement

Copyright 2011, ECCO International, Inc

33

DAM-RUC Co-Optimization

Minimize Start-Up Cost Minimum Load Cost Energy Schedule Cost Ancillary Services Procurement Cost RUC Capacity Procurement Cost

All other constraints similar to DAM and RUC Inter-temporal constraints (MUT, MDT, MDS, ramp rates, energy

limits) Forbidden operating regions AS regional constraints Inter-tie Energy/AS/RUC Capacity constraints

Copyright 2011, ECCO International, Inc







Presenter

Presentation Notes


Capacity Market Design

Capacity markets interact with and are part of organized electricity market design. The details differ in various implementations but there are certain common issues.

Missing Money. The most common justification of the need for capacity markets cites the fact that historically the money earned in “energy only” markets has been too little to justify new entry


PJM data show that a combustion turbine (1999-2010, per MW-Year) would have earned Average Net Energy Revenue = $40,943, versus Average Levelized Fixed Cost = $88,317

Better scarcity pricing design would mitigate the missing money problem and reduce the importance of capacity markets

Transmission Constraints. Locational requirements arise because of transmission constraints; This creates strong interactions across markets and can produce volatile capacity prices



Investment Timing. Transmission expansion, generation capacity expansion and demand response investments are partial substitutes on very different investment horizons. This creates a significant coordination problem

Market Power. The inherent nature of capacity market requirements with explicit and known demand curves and large changes in price for small changes in quantity creates a pervasive and inherent problem of market power and price manipulation




Withholding Supply. If a supplier could reduce net capacity or increase net demand in the formal capacity market, suppliers might profit on higher prices for

remaining sales in capacity market Withholding Demand. If load could reduce net demand or increase net supply, loads could benefit from lower prices on remaining purchases from the capacity markets








Presenter

Presentation Notes



Why Markets Cannot Support All Transmission Investments

North

South

K η0

PS

PN

Price

Quantity K0 K*

A

C

B

Congestion Rent Congestion Cost

No Congestion

Net Supply in North SN

Net Demand in South DS

Congestion Rents vs Congestion Costs

δK

Surplus S1

η0 η1

K1

η0 = shadow price, η0 * K0 = Congestion Rent, Triangle ABC = congestion costs η1 (K1 – K0) = ex-post congestion rents paid to transmission investors , S1 = Social Surplus

Since η1 (K1 – K0) < S1 → Under-incentive to upgrade the line

Lumpiness results in underinvestment in transmission like grid owners rewarded by congestion rents has suboptimal incentives to remove these congestion rents

Competition between transmission and generation projects raises pre-emption issues

Given the drastically different completion schedules, the transmission investor is at a strategic disadvantage

Also complementary transmission investments may give rise to wars of attrition in which no owner wants to move first by fear of being “under-dimensioned” by a rival owner



Assume two complementary projects with capacities KNM and KMS

The value of Point to Point Rights are: KNM (PM – PN) & KMS(PS – PM) The incentive for gaming comes for the fact that lower-capacity line grabs the entire rights’ value Suppose that KMS < KNM PM = PN & PS > PM

This gives rise to the game where each would like to have a slightly capacity than the other



North

M

South

PN

PN

PM

These detrimental behaviors can be only avoided through a centralized transmission process

The Merchant Transmission model in which investors build for anticipated need and take all the risks appears to have died

The challenge is to ensure a move to low carbon future, sustainable development and security of supply

These objectives require mandated transmission investments or as we call them public-policy driven investments


New Transmission Investments Environment

Implementation of a Hybrid Model Planning Process (allow a regional approach; top down

approach) Transmission Permitting (expand control of Federal

Government) Transmission Financing and Cost Allocation (current cost

allocation methods are inadequate; broad based “postage stamp” or “regionalization” approach is required)

Transmission System Modernization and the Smart Grid 44 Copyright 2011, ECCO International, Inc.

Infrastructure Investments: Road Map for the Future


Implementation of the Hybrid Model

Objective: Preserve the Merchant Transmission Model Principle: Regulated based, mandated transmission investments

should be limited to cases where the investment is inherently large and inherently lumpy

Test 1: Economic Justification. Ensure that the usual social welfare calculation that applies to all regulated investments under traditional regulation (aggregate benefit exceeds aggregate costs) is valid

Test 2: Market Failure Justification. The investment is large and lumpy enough to materially affect market prices, making the ex-post Financial Rights worth less than the cost of the investment


Transmission System

Modernization and the Smart Grid

Apply Smart Grid Concepts to Revolutionize the EHV Grid Increase Congressional Oversight of actual costs, benefits and performance

of smart grid investments A transmission solution for the 21st Century

high capacity transmission high technology platform foundation for an interstate electric high-way system wired to facilitate a highly reliable and smart electric grid wired to expand opportunities for new high technology generation supply and new high technology

demand-side options

Creating a Modern EHV Grid

Broad Grid Planning

Broad Cost Allocation

Federal Siting

Our Energy Future

Technology




Transmission Investments Develop Market Mechanisms to Manage High

Penetration of Renewable Energy Sources (RES) Develop Demand Respond Market Mechanisms


Presenter

Presentation Notes


RES Market Issues

Managing renewables today Grid Rule Changes Day Ahead Market Rules Changes Additional Forward Markets Additional Congestion Hedging Mechanisms Integration Costs of RES into the grid


Our Future?

Spanish renewables + Must Run exceed load in many hour

2010: Wind provides 16% of Spanish electricity Wind spillage rapidly growing (from .02% to 0.8% in one year)


Giving Renewables Absolute Priority Makes Neither Economic nor Environmental Sense

Can increase both costs and emissions


Managing Renewables Today

Renewable participation in Day-Ahead Markets is not consistent throughout US markets

Same in Europe: Renewable goals are country by country Renewables may not participate due to forecast uncertainties

and unfavorable market rules This may lead to renewables “showing up” in real-time

markets, causing inconsistencies from the Day-Ahead market Priority access or guaranteed access and dispatch for RES is

required by EU legislation 51 Copyright 2011, ECCO International, Inc.

Managing Renewables Today

But “priority” is interpreted differently: NL: Can’t ramp down, even voluntarily UK: Anyone can participate in balancing market: source blind Germany: Regulator has relieved grid of obligation when prices negative

Key objective: Implement markets rules to provide TSO operational flexibility and incorporate RES in the market process


Grid Rules for Renewables

Ensure that RES provide valuable Ancillary Services Ensure that grid rules require these capabilities from new

RES Promote electricity storage; Pumped-storage and others

(compressed air) A/S products could include: Black Start, Voltage Support,

Primary Governor Response, Load Following, Regulation Reserves, and Spinning Reserves


Day-Ahead Market Rules for Renewables

Day-ahead market rules should not be prejudiced against (or biased towards) any particular resource category; provide economic bids; minimize administrative measures

Economic bids enable the market optimization to efficiently dispatch the fleet, and efficiently curtail when necessary

The market products and rules should support grid reliability and overall economic efficiency of the grid

Production tax credits & other incentives should not adversely impact operation of markets



For example, wind generation often continues to produce at negative prices (e.g. -$30/MWh) because of external incentives

These prices do not reflect the “true” costs of operation (e.g. fuel, maintenance, …)

This behavior can have negative impacts on other resources in the grid

Participation in Day-Ahead Market by renewables is subject to additional uncertainty, due to wind/solar forecasting errors

Additional hedging mechanisms are required 55 Copyright 2011, ECCO International, Inc.


Provide incentives for increased dispatch capability (especially downward dispatchability) such as disallowing netting of deviations

Netting of deviations takes away the incentives for renewable developers to invest in dispatch capability

Substantially reduce energy bid floors to enable LMPs (or MCPs) to go lower, thus incenting resources to submit decremental bids and capturing the RES opportunity costs

Achieve flexible thermal generation



Implement market rules to increase operational flexibility, such as Performance-based Regulation, load following, etc.

Faster ramping resources provide more Area Control Error (ACE) correction than slower ramping resources

Netting regulation energy does not recognize the greater ACE correction faster ramping resources provide



We propose a two-part payment system Capacity Payment

Cross-product opportunity cost (Payment reflects cost of not participating in energy market)

Inter-temporal opportunity cost (The value a resource forfeits to provide regulation due to less flexibility to charge/discharge advantageously through the energy market)



Performance payment Mileage payment

Compensate for the work performed by a regulating unit Absolute value of up and down movement of a regulation resource

multiplied by a $/MW-ACE Correction Price ACE Correction Price: 1) preference is a market bid for ACE

correction; 2) establish admin price if market bid is unworkable Accuracy adjustment

Using telemetry, adjust the mileage payment based on how well a resource tracks the TSO AGC signal

Mileage payment multiplied by accuracy factor


Net Energy Vs. Mileage

Replace net energy payments by a mileage payment for ACE correction provided



RTD Timeline

Dispatch

LMP/MCP

1

T−7.5' RTED

2

T T−5' T+10' T+5' T−10'

T−2.5'

Design of a Flexible Ramping Product

Intemporal optimization of Real-Time Dispatch (RTD) optimizes over time to account for expected future ramp requirements, such as those associated with top of the hour changes in net-interchange, a pump storage unit going on or off-line, or a generation unit going on or off-line

Accommodating RES entails scheduling additional ramping capability to respond to ramp constraints that cannot be projected, but could arise because of unpredictable changes in load or intermittent generation output


Design of a Flexible Ramping Product

Use RTD to create additional upward (or downward) ramp capability. How?

Dispatch down (out of merit) resources whose available upward ramping capability is capacity limited, thus creating additional upward ramping capability (Their output is replaced with the output of higher cost units whose available ramping capability is not capacity constrained)

Conversely, additional downward ramp capability can be created by dispatching up out-of-merit resources whose downward ramping capability is limited by their minimum load


Additional Forward Markets (e.g. Hour Ahead Market)

Significant forecasting errors exist in the Day-Ahead for renewable resources

An additional forward market (e.g. 4-hours into the future) could be very beneficial Renewable resource forecasts become significantly better when the

timeframe becomes shorter Provide a scheduling opportunity to RES to establish a schedule as

the basis for measuring real-time deviations There is still time for other non-renewable resources (e.g. combined-

cycle plants) to respond to changes in RES (and load) forecasts


Additional Congestion Hedging Mechanisms

Energy Markets typically offer Financial Transmission Rights to allow hedging against congestion uncertainty Purchased months/years ahead and settled in the Day-Ahead

Renewable resources have significant uncertainty even after the close of the Day-Ahead Market Additional hedging mechanisms would allow for hedging of

congestion in the 4-Hour Ahead and Real-Time Markets


RES Integration with the Grid Issues

Integrating RES into grid operations is expected to drive several types of cost increases

Increased procurement of regulation Greater operational demands on conventional resources

(more starts, more ramping) Increased need for flexible, dispatchable capacity Potentially higher uplift charges Increased capacity payments to supplement declining

market prices and revenues 66 Copyright 2011, ECCO International, Inc.







Presenter

Presentation Notes


Demand Response: Impact on Cleared Demands

1,500

2,000

2,500

3,000

3,500

0 2 4 6 8 10 12 14 16 18 20 22 24 hour

without DRs with DRs

clea

red

dem

and

(MW

)


Demand Response: Impact on Clearing Prices

hour

30

35

40

45

50

clea

ring

pric

e ($

/MW

h)

0 2 4 6 8 10 12 14 16 18 20 22 24

without DRs with DRs


Demand Response: Existing Products

Typically we have two types of DR products, a) Price DR Products and b) Reliability (emergency) DR Products

Generally, Price DR products are activated when energy procurement prices are high or system resources are constrained

Reliability DR Products are activated programs to respond to severe resource constraints or grid emergencies

DR markets include, a) Capacity Market, b) Reserves & Regulation Market and c) Energy Markets



Current DR Bidding Modeling

Participating Load (PL) submits a three-part bid that includes the following: a) Load Curtailment Cost, b) Minimum Load Reduction Cost and c) Load Energy Bid

Aggregate PLs are modeled as aggregate controls in the optimization with a fixed distribution to the underlying nodes using LDFs

The Base Load is a Price Taker, i.e., it is charged the relevant aggregate LMP as any non-Participating Load

When the Participating Load is curtailed from the Base Load, it is eligible for recovering its Load Curtailment Cost and its hourly Minimum Load Reduction Cost

When the Participating Load is dispatched it is paid (in addition to the Base Load charge) its LMP for the load reduction

71


DR Bidding Modeling

Load Curtailment

MW

Base Load Schedule

$/MWh

Minimum Load Reduction

Minimum Load

72


Major Market Rules Changes are Required

The Current DR market model is not working

73

Presenter

Presentation Notes

Substation models can be quite elaborate but allow breaker modeling and dynamic bus configurations such as bus splitting. A full network model with detailed breaker modeling can absorb directly State Estimator solutions without conversion to bus-branch model and the associated conversion problems and approximations. Power flow limits, and to a lesser extend voltage limits, are not hard limits in power system operation. In a market using a full network model, these limits must be judiciously selected since they may have an impact on the LMPs. The process for updating and validating the network model needs to be carefully designed since it involves manual work and needs to be synchronized with the network model update in the EMS. Mapping of market resources, which could be aggregate resources and may include complex configurations including station load, to physical resources in the FNM can be a significant challenge. Market resources bid, schedule and are settled at the location of the revenue quality meter (Point of Delivery), but that location is not always unique.


DR Market Rules Changes

DR resources can arbitrage low Zonal prices and higher nodal prices; the potential “money pump” in which DR resources can exaggerate the load reduction is substantial

This strategy is likely to be profitable in locations and at times when the LMP is anticipated to be higher than the Zonal price

Define and implement much smaller Zones within which LMPs are fairly uniform

Require that DRs purchase their baseline at the nodal prices where the reductions are to occur

74

Presenter

Presentation Notes



DR Market Rules Changes

Implement Dynamic Pricing rules – Make the default retail price a pass-through of wholesale short-term energy prices

Lack of Dynamic Pricing prevents consumers from benefitting from a lower ANNUAL bill by reducing their consumption during hours of high prices and increasing their consumptions during hours of lower prices

Ensure “symmetric treatment” between generating and load resources

Set a Zero baseline for final consumers, as for suppliers, and charge for each of consumption the hourly price

75

Presenter

Presentation Notes



DR Market Rules Changes Paying for demand reductions is NOT working Paying consumers not to consume faces a serious challenge of

measuring what the consumer would have done without the payment (“baseline problem”)

This approach suffers from two major difficulties: The adverse selection problem (the buyer of the DR does not know

what the seller would have done in the absence of payment) The moral hazard problem (customers have a strong incentive of

inflating the level of baseline) Solution: develop a payment structure to set symmetric prices for

consumption and reductions 76

Presenter

Presentation Notes



Conclusions

Europeans are in denial with respect to LMP markets; they need to move to LMP based energy markets without delays

Integration of markets with reliability is an important requirement Capacity market design needs to be revisited and expanded Markets cannot solve the infrastructure investment problem (Federal

involvement/EU level involvement is required) Deep penetration of RES will come at a high costs and requires

substantial changes of the market design Change the DR market design is necessary with the ultimate objective

to achieve “symmetric treatment “ between generators and loads and between consumption and reductions

77

Presenter

Presentation Notes


challenges of the next generation energy market … lmp (nodal price) at bus i can be calculated...

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