Challenges of the Next Generation Energy Market Design Structures Sponsored by the IEEE GREECE PES CHAPTER By Alex Papalexopoulos, Ph.D. President & CEO, ECCO International, Inc. [email protected] October 6, 2011  Athens, Greece

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 

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Various Markets for Energy 

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 3

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PJM Energy Markets 60

Market share (%)

50 40 Year 2007

30

Year 2008

20 10 0 Self-supplied

Bilateral transactions

Spot market

Imports

Market type 4

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Markets for Ancillary Services 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 5

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Markets Structure for Transmission 

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



System Operators – Australia, Canada [power pools]

Chile

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 6

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Key Principles of Various Transmission Markets 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 

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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 8

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The Impact of Congestion

pB

qAB

p pA

A

B qAB 9

q1

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Congestion Management vs Transmission Investments 

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

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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 Cooptimization of Energy and Ancillary Services One settlement system As-bid pricing It does not support RES and Demand Response 11

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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 

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Transition from Zonal To Nodal (LMP) Market North

Middle

South

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

• No intra-zonal constraints enforced • Internal Congestion Zones – Constraints enforced between zones 13

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Transition from Zonal To Nodal (LMP) Market Zonal Model

Nodal Model

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

• Models the entire TSO Grid

• Simulates grid operation considering transmission limitations and energy schedules submitted • All scarce resources are priced

Locational Marginal Pricing (LMP)

Zonal Pricing • Pricing only the zones

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

• Does not address congestion within a zone

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Transition from Zonal To Nodal (LMP) Market Physical Transmission Rights

Congestion Revenue Rights (CRRs) or FTRs

• Physical rights across borders

•

only • They are obtained in auctions • They provide scheduling priority

• • • •

Sequential Markets

Financial rights available between any two points in the network Annual CRRs Monthly CRRs Long Term CRRs Separate from operations

Integrated Forward Markets

• Higher procurement costs

• Price reversals • Can lead to scarcity

• Simultaneous optimization of

Energy, Congestion Management and Ancillary Services 15

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FTR – PTP Obligation 

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

TSO pays FTR holder LMPb-LMPa

FTR holder pays TSO

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FTR – PTP Option 

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

TSO pays FTR holder LMPb-LMPa

FTR holder pays nothing to TSO

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

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LMP Price Determination 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

=

Nodal price at the reference bus

Li

=

μj SFji

= =

Marginal loss factor at bus i = (∂Ploss/∂Pi), Pi is injection at bus i and Ploss is the system losses Shadow price of constraint j Shift factor for real load at Bus i (the reference bus (ref) is the reference bus for this shift factor) on constraint j

λref

19

.

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Locational Marginal Prices in Nodal Markets

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Extreme Congestion

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Key Elements of an LMP Energy Market Design Forward Energy Markets/Bilateral Markets Transmission & Ancillary Services Markets Real-Time Markets Reliability Unit Commitment (RUC) Financial Transmission Rights (FTRs) Virtual Markets Capacity Markets 22

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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 

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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 

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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 25

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Benefits of Energy-AS Cooptimization 

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 26

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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 

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Current Dominant Solution Methodology 

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

Schedules

Optimization Engine PTDFs

Power Flow Power Flow Power Flow Power Flow Power PowerFlow Flow

Loss marginal rates 28

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MILP versus ALR Comparison Capability Flexibility for adding new constraints and models

MILP Yes

ALR No

Flexibility of modeling a large number of coupling constraints

Yes

No

Dynamic ramp rates & Forbidden regions with crossing rules Advanced infeasibility detection Heuristics to achieve a feasible solution Block dispatchable transactions

Yes

No

No Yes

Yes No

Optimal automatic discrete relaxation of infeasible constraints

Yes

No

Lower bound on the optimal solution

Yes

No

fast enough

fast

Performance

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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) 

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Next Generation of Energy Market Design 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 

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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 overgeneration conditions

   32

Cons May be difficult to isolate RUC commitment cost Congestion costs from RUC capacity More complex to implement Copyright 2011, ECCO International, Inc

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 

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Next Generation of Energy Market Design 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 

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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 35

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Capacity Market Design 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 

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Capacity Market Design 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 

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Capacity Market Design 



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 38

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Next Generation of Energy Market Design 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 

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Why Markets Cannot Support All Transmission Investments 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

Price

Congestion Rents vs Congestion Costs Congestion Rent Congestion Cost Surplus S1

North

A

PS

K

η0 PN

Net Supply in North SN

η1

η0

B Net Demand in South DS

C

South

No Congestion

K0

δK K1 K* 40

Quantity Copyright 2011, ECCO International, Inc.

Why Markets Cannot Support All Transmission Investments 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 

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Why Markets Cannot Support All Transmission Investments Assume two complementary projects with capacities KNM and KMS North PN  The value of Point to Point Rights are:  KNM (PM – PN) & KMS(PS – PM) M 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 South PN  This gives rise to the game where each would like to have a slightly capacity than the other 

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New Transmission Investments Environment 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 

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Infrastructure Investments: Road Map for the Future 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 

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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 expost Financial Rights worth less than the cost of the investment 45

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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 46

Technology

Our Energy Future

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Next Generation of Energy Market Design 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 

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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 

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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) 49

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Giving Renewables Absolute Priority Makes Neither Economic nor Environmental Sense

Can increase both costs and emissions

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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 

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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 52

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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 

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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 54

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Day-Ahead Market Rules for Renewables 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 

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Day-Ahead Market Rules for Renewables 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 

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Day-Ahead Market Rules for Renewables 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 

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Day-Ahead Market Rules for Renewables 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)

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Day-Ahead Market Rules for Renewables  

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 

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Net Energy Vs. Mileage Replace net energy payments by a mileage payment for ACE correction provided

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RTD Timeline

T−7.5' RTED

T−2.5'

Dispatch LMP/MCP 1

T−10'

T−5'

T

61

2

T+5'

T+10'

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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 

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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 

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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. combinedcycle plants) to respond to changes in RES (and load) forecasts 

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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

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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 

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Next Generation of Energy Market Design 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 

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Demand Response: Impact on Cleared Demands

cleared demand (MW)

with DRs

without DRs

3,500 3,000 2,500 2,000 1,500

0

2

4

6

8

18 20

22

24

10 12 14 hour

16

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clearing price ($/MWh)

Demand Response: Impact on Clearing Prices 50 without DRs

with DRs

45 40 35 30

0

2

4

8 10 12 14 16 18 20 22 24 hour

6 69

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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 

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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

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DR Bidding Modeling $/MWh

Load Curtailment

MW Minimum Load

Minimum Load Reduction

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Base Load Schedule

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Major Market Rules Changes are Required

The Current DR market model is not working

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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 

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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 

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DR Market Rules Changes  

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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

Copyright 2011, ECCO International, Inc.

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

Copyright 2011, ECCO International, Inc.