Public Utility Commission of Texas
Comparison of Market Designs
Market Oversight Division Report
Project 26376, Rulemaking Proceeding on Wholesale Market Design
Issues in the Electric Reliability Council of Texas
Principal Author: Sam Zhou, Ph.D.
Other Contributors:
Tony Grasso
Grace Niu
Editors:
David Hurlbut, Ph.D.
Richard Greffe
Team Leader: Eric S. Schubert, Ph.D.
Market Oversight Division
Public Utility Commission of Texas
January 7, 2003
Acknowledgement
As one of its main responsibilities, the Market Oversight Division feels that it is important to
monitor market operations and continue to improve market design and operating rules in order to
establish a successful and workably competitive electricity market in Texas. Helping market
participants to better understand the operation of competitive electricity markets, which are
designed differently and have different degree of emphasis on the importance of various market
elements, can be very beneficial in making a final decision about the future of market design in
the Electric Reliability Council of Texas. In particular, such an understanding can highlight
various trade offs and reasons beyond the decisions made by other markets to select a particular
path among existing potential options.
The Market Oversight Division Staff has prepared this Study Report to facilitate the Commission
discussion in this rulemaking proceeding, which will eventually lead to the establishment of a
successful competitive electricity market. Staff believes that the information provided in this
Study Report, addressing the fundamentals and presenting some measures of actual performance
by various competitive electricity markets across the world, will provide a solid ground for
detailed discussions that will follow in the near future.
I would like to take this opportunity to show appreciation for tireless efforts by Dr. Sam Zhou to
complete this comprehensive Study Report in a relatively short period of time. In addition, I
appreciate hard work by other team members, Tony Grasso and Grace Niu, who helped to
prepare some of the information used in this Study Report. Special thanks go to Dr. David
Hurlbut, Richard Greffe, and Dr. Eric Schubert for their excellent review, comments, and editing
to finalize this Study Report.
Parviz M. Adib, Ph.D.
Director of Market Oversight Division
Comparison of Market Designs
Market Oversight Division Report
Contents
Introduction ...................................................................................................................................................................1
I. FERC Standard Market Design.................................................................................................................................3
Detailed Requirements in FERC’s SMD ...................................................................................................................4
Suggested Benchmark Matrix of Market Implementation.........................................................................................6
II. Existing Markets and Planned Market Designs .......................................................................................................8
1. PJM Interconnection Market ............................................................................................................................9
2. New York Independent System Operator Market...........................................................................................17
3. ISO New England Market ..............................................................................................................................26
4. Electric Reliability Council of Texas Market .................................................................................................34
5. Northeast Regional Transmission Organization .............................................................................................41
6. California Independent System Operator Market ...........................................................................................44
7. Midwest Independent System Operator Market .............................................................................................47
8. Ontario Independent Electricity Market Operator Market..............................................................................49
9. Power Pool of Alberta Market ........................................................................................................................52
10. New Electricity Trading Arrangements Market of England and Wales .......................................................54
11. Nordic Power Exchange Market...................................................................................................................60
12. National Electricity Market of Australia.......................................................................................................65
13. New Zealand Electricity Market...................................................................................................................71
III. Preliminary Summary...........................................................................................................................................76
Preliminary Conclusions..........................................................................................................................................76
1. A Mandatory Centralized Dispatch Pool Market Invites Gaming Opportunities ........................................76
2. LMP Complicates Locational Market Power...............................................................................................77
3. Spot Energy Markets With Centralized Unit Commitment Can Be Problematic ........................................77
Energy Trading Results ...........................................................................................................................................78
Average Energy Comparison Between PJM, NYISO, and ISO-NE....................................................................79
Ancillary Services Prices of Various Markets .........................................................................................................81
Regulation Reserve Services Price ......................................................................................................................82
Spinning Reserve Service Prices .........................................................................................................................83
Non Spinning Reserve Prices ..............................................................................................................................85
Uplift and Congestion Costs of the U.S. Markets....................................................................................................88
Market Power Mitigation: Other Alternatives of Automated Mitigation Plan ........................................................89
IV. Options for ERCOT Market Design.....................................................................................................................90
Day-Ahead Market as a Spot Energy Market ..........................................................................................................92
Congestion Management .........................................................................................................................................93
Some Possible Options for ERCOT Market Design................................................................................................93
Appendix I: Summary of Market Design .................................................................................................................101
Appendix II: LMP Security-Constrained Dispatch Process .....................................................................................102
Appendix III: ERCOT Two-Step Dispatch Process .................................................................................................103
Appendix IV: Automated Ex Ante Market Power Mitigation Measure ...................................................................104
List of Figures
Figure 1: FERC SMD ...................................................................................................................................................5
Figure 2: Timeline and Bilateral Schedule of Major Deregulated Markets ..................................................................8
Figure 3: PJM Model..................................................................................................................................................10
Figure 4: NYISO Model .............................................................................................................................................18
Figure 5: ISO-NE Model ............................................................................................................................................28
Figure 6: ERCOT Model ............................................................................................................................................35
Figure 7: NERTO SMD 2.X Model............................................................................................................................42
Figure 8: CAISO MD02 Model..................................................................................................................................45
Figure 9: MISO Model ...............................................................................................................................................48
Figure 10: Ontario IMO Model ..................................................................................................................................50
Figure 11: Power Pool of Alberta Model....................................................................................................................53
Figure 12: England and Wales NETA Model.............................................................................................................55
Figure 13: NORD Pool Model....................................................................................................................................61
Figure 14: Australia NEM ..........................................................................................................................................66
Figure 15: NZEM .......................................................................................................................................................72
Figure 16: Problem of Centralized Dispatch ..............................................................................................................77
Figure 17: Monthly Average Energy Price Comparison ............................................................................................80
Figure 18: Energy Price Duration Curves for ISO-NE, PJM and NYISO, May 2001 – April 2002 ..........................81
Figure 19: Weighted Average Regulation Prices........................................................................................................82
Figure 20: Average Regulation Prices ........................................................................................................................83
Figure 21: Weighted Average Spinning Reserve Prices.............................................................................................84
Figure 22: Average Spinning Reserve Prices .............................................................................................................85
Figure 23: Weighted Average Non-Spinning Reserve Prices.....................................................................................86
Figure 24: Average Non-Spinning Reserve Prices .....................................................................................................87
Figure 25: Energy Market Functions ..........................................................................................................................91
Figure 26: Option 1.....................................................................................................................................................94
Figure 27: Option 2.....................................................................................................................................................97
Figure 28: Option 3.....................................................................................................................................................98
Figure 29: Option 4.....................................................................................................................................................99
Figure 30: LMP Dispatch Process ............................................................................................................................102
Figure 31: ERCOT Two-Step Dispatch Process.......................................................................................................103
Figure 32: Zonal-ERCOT-Nodal Mitigation Measure..............................................................................................105
List of Tables
Table 1: PJM Hourly Energy HHIs ............................................................................................................................14
Table 2: PJM Installed Capacity HHIs .......................................................................................................................14
Table 3: PJM Load-Weighted Average LMP ($/MWh) .............................................................................................14
Table 4: NYISO Unweighted Ancillary Services Prices ............................................................................................23
Table 5: Broad Indicators, 1999-2000, 2000-2001, 2001-2002..................................................................................31
Table 6: All-In Price of Wholesale Power (Load Weighted)......................................................................................31
Table 7: Ancillary Services Prices of NEISO (Aug. 01 – Aug. 02)............................................................................32
Table 8: HHIs for ERCOT Zones ...............................................................................................................................38
Table 9: Annual Weighted Average Prices for Balancing Energy .............................................................................38
Table 10: Average Ancillary Services Prices in ERCOT ...........................................................................................39
Table 11: Installed Generating Capacity in Nord Pool ...............................................................................................60
Table 12: Energy Trading in Various Markets ...........................................................................................................79
Table 13: Energy Market Clearing Prices of ERCOT, ISO-NE, NYISO, and PJM ...................................................79
Table 14: Ancillary Services Market Components.....................................................................................................81
Table 15: Weighted Average Regulation Price ($/MW) ............................................................................................82
Table 16: Average Regulation Services Prices ($/MW).............................................................................................83
Table 17: Weighted Average Prices of Spinning Reserve ($/MW) ............................................................................84
Table 18: Average Spinning Reserve Prices ($/MW).................................................................................................85
Table 19: Weighted Average Non Spinning Reserve Prices ($/MW) ........................................................................86
Table 20: Average Non Spinning Reserve Price ($/MW) ..........................................................................................87
Table 21: Uplift of PJM, NYISO, ISO-NE, and ERCOT ($ Millions) .......................................................................88
Table 22: Congestion Costs of the U.S. Markets (Millions).......................................................................................88
Table 23: Trade-offs of Major Components of Market Design ..................................................................................92
Table 24: Available Options of Market Design..........................................................................................................94
Table 25: Characteristic Comparison of Different Markets........................................................................................95
Introduction
Electricity market deregulation has been underway for more than a decade since the United
Kingdom opened a Power Pool in April 1990. Some markets such as Nord Pool and New
Zealand have been very successful, but others such as California and the pre-NETA UK market
have failed. Therefore, as ERCOT reevaluates its current market design, it is important to
consider the lessons learned from other markets. To that end, this report summarizes the energy
markets, operational processes, and performance benchmarks of ten existing electricity markets
and three proposed market designs as follows:
•
Existing markets
o Pennsylvania-New Jersey-Maryland Interconnect (PJM)
o New York ISO (NYISO)
o ISO-New England (NE-ISO)
o Electric Reliability Council of Texas (ERCOT)
o Independent Electricity Market Operator (IMO) of Ontario
o Power Pool of Alberta
o New Energy Trading Arrangement (NETA) of the United Kingdom
o Nordic Power Exchange (Nord Pool)
o National Electricity Market (NEM) of Australia
o New Zealand Electricity Market (NZEM)
•
Proposed markets
o Northeast Regional Transmission Operator (NERTO)
o California Market Design 2002 (MD02)
o Mid-West ISO (MISO)
Section I of this report describes the market design principles and required components of the
Standard Market Design (SMD) proposed by the Federal Energy Regulatory Commission
(FERC). A set of performance measures aligned to FERC’s Strawman SMD Staff Discussion
Paper on Market Metrics is identified to establish an objective benchmark when different
markets are evaluated.
With a brief introduction of each market, Section II of this report summarizes the market design
of different markets, describes the important components in each market, and assesses their
performance benchmarks. The benchmarks are primarily based on the respective 2001 annual
reports of the Market Monitoring Units for the respective markets. One can see that each market
has many good features, as well as some areas that could be improved such as high uplift, high
congestion costs, and high price correction rates. An important observation is that ERCOT has
the highest generation resource concentrations (HHI) in the United States and some similar
features of market structure to the NETA of the United Kingdom.
Section III of this report conducts a preliminary summary of various market models and
compares the energy prices, ancillary service prices, congestion costs, and uplift of PJM,
NYISO, ISO-NE, and ERCOT. One important observation is that the ancillary services in
ERCOT market have higher prices for several ancillary services products. Even though ERCOT
has a smaller percentage of balancing energy in the real-time market, it also has higher monthly
load weighted average energy prices compared to other U.S. deregulated electricity markets.
1
Possible reasons are the inherent characteristics such as high concentration ratios in the ERCOT
market.
The design of a competitive wholesale market is determined by two fundamental principles: 1)
competitive and efficient energy trading, and 2) reliable operation of the grid. From the
summary of different market structures presented in this report, it is evident that there are
significant differences in the design of energy trading and in the ways to conduct security
constrained economic dispatch. Some markets have a day-ahead market for spot trading and
some markets just have a day-ahead or an hour-ahead scheduling process to facilitate real time
operation. Most overseas markets adopt a zonal model, but a majority of U.S. markets use a
nodal model. If energy trading (primarily bilateral vs. day-ahead spot market) and congestion
management (zonal vs. nodal) are the most important market design elements, it is possible to
construct four options (combinations) for analysis. Section IV describes the market structures of
the four options and identifies their unique characteristics. Several key questions that should be
addressed in ERCOT market redesign are raised for further study and discussion.
2
I. FERC Standard Market Design
The Federal Energy Regulatory Commission (FERC), in its Working Paper1 on Standardized
Transmission Service and Wholesale Electric Market Design, states that:
1. The objective of standard market design for wholesale electric markets is to establish
a common market framework that promotes economic efficiency and lower delivered
energy costs, maintains power system reliability, mitigates significant market power
and increases the choices offered to wholesale market participants. All customers
should benefit from an efficient competitive wholesale energy market, whether or not
they are in states that have elected to adopt retail access.
2. Market rules and market operation must be fair, well defined and understandable to
all market participants.
3. Imbalance markets and transmission systems must be operated by entities that are
independent of the market participants they serve.
4. Energy and transmission markets must accommodate and expand customer choices.
Buyers and sellers should have options which include self-supply, long-term and
short-term energy and transmission acquisitions, financial hedging opportunities, and
supply or demand options.
5. Market rules must be technology- and fuel-neutral. They must not unduly bias the
choice between demand or supply sources nor provide competitive advantages or
disadvantages to large or small demand or supply sources. Demand resources and
intermittent supply resources should be able to participate fully in energy, ancillary
services and capacity markets.
6. Standard market design should create price signals that reflect the time and locational
value of electricity. The price signal – here, created by LMP – should encourage
short-term efficiency in the provision of wholesale energy and long-term efficiency
by locating generation, demand response and/or transmission at the proper locations
and times. But while price signals should support efficient decisions about
consumption and new investment, they are not full substitutes for a transmission
planning and expansion process that identifies and causes the construction of needed
transmission and generation facilities or demand response.
7. Demand response is essential in competitive markets to assure the efficient
interaction of supply and demand, as a check on supplier and locational market
power, and as an opportunity for choice by wholesale and end-use customers.
8. Transmission owners will continue to have the opportunity to recover the embedded
and new costs of their transmission systems. Consistent with current policy, merchant
transmission capacity would be built without regulatory assurance of cost recovery.
1
Federal Energy Regulatory Commission, Working Paper on Standardized Transmission Service and Wholesale
Electric Market Design, May 2002, pp 6-7.
3
9. Customers under existing contracts (real or implicit) should continue to receive the
same level and quality of service under standard market design. However,
transmission capacity not currently used and paid for by these customers must be
made available to others.
10. Standard market design must not be static. It must not inhibit adaptation of the market
design to regional requirements nor hinder innovation.
Detailed Requirements in FERC’s SMD
Under the stated goal of Standardized Market Design (SMD), “To enhance competition in
wholesale electric markets and broaden the benefits and cost savings to all wholesale and retail
customers,”2 the electricity wholesale market should meet the following requirements:
•
Each Regional Transmission Operator (RTO) should develop a day-ahead energy market,
a real-time spot energy market, a financial transmission rights market, and
simultaneously allow for bilateral contracts.
•
Market-clearing prices should be derived through bid-based, security-constrained
dispatch and be linked to the physical dispatch of the system through locational marginal
pricing.
•
Each RTO should seek to implement an energy market that, to the extent feasible,
imposes the least amount of additional cost to the public.
•
Each RTO should develop transparent rules and procedures that integrate and coordinate
system operation with market administration functions for energy, ancillary services, and
congestion management.
•
RTOs should acknowledge the role of state utility commissions and the regional
reliability authority in ensuring long-term supply adequacy and should coordinate with
these entities in implementing a market approach.
•
Load-serving entities should ensure that sufficient operating reserves and capacity are
committed to meet the adequacy obligation established by the regional reliability
authority or state commissions.
•
Each RTO, in coordination with transmission owners or Independent Transmission
Coordinators (ITCs) within the RTO, should manage or coordinate the operation of the
transmission system.
•
Limits may be necessary on bidding flexibility to mitigate market power. For example,
suppliers may be required to submit a start-up bid which would remain in place for a
period of several months (rather than re-bid every day). As more demand response
becomes available in a regional market, limits on supplier bidding flexibility can be
relaxed.
2
Federal Energy Regulatory Commission, “Working Paper on Standardized Transmission Service and Wholesale
Electric Market Design,” March 15, 2002, p. 1.
4
•
The demand side must be able to participate in the energy market. The demand side can
participate as buyers or sellers (e.g., offering to sell operating reserves). As a buyer, an
entity must be able to submit bids that indicate it is willing to vary the quantities it
purchases based on the prices that it may be charged.
The proposed SMD demonstrated in Figure 1 consists of:
1. Bilateral contract
2. Day-ahead and real time market
3. The day-ahead regulation and operating reserve markets (jointly optimize energy,
regulation, operating reserves, and transmission service.)
4. Locational marginal pricing (LMP)
5. Congestion Revenue Rights (CRR)
6. Long-term resource adequacy requirement such as Installed Capacity Market (ICAP)
7. Demand-side responsiveness
8. Market power mitigation (Optional Automated Mitigation Procedure (AMP))
The transmission provider may identify generating units that must run for reliability. Because
these units are required by reliability and security of grid operation and have locational market
power, the bids submitted by these units should be subject to mitigation. Similarly, market power
in load pockets must be mitigated with on-going behavioral mitigation, such as call options or
bid caps, unless structural solutions are possible.
Figure 1: FERC SMD
Demand-side
responsiveness
CRR Auction
Market
Capacity
Markets
Market Based
Bid curve
Bila
teral
cont
ract
$1000/MWh
LMP &
CRR value
Day-ahead
market
C
A
P
AMP
Real time A/S &
Balancing market
5
LMP &
reliability
Suggested Benchmark Matrix of Market Implementation
The SMD NOPR discusses some of the ways market monitors have measured the structure of
their markets and the conduct of market participants, and it requests comment on how the market
monitor should develop useful measures that permit interregional comparisons. A more detailed
discussion was conducted at the FERC SMD Staff Conference on Market Monitoring which was
held in October 2002. The FERC Staff prepared a strawman discussion paper3 which identified
the following categories to frame the discussion of specific metrics:
•
General market functioning
•
Assessment of market structure
•
Assessment of market performance
•
Evaluation of participant conduct
According to the strawman, metrics concerning the state of the markets start with a general
description of the market and changes over the year, emphasizing measures such as:
•
Energy market prices
•
Quantities delivered
•
Ancillary services prices
•
Transmission usage and pricing, and
•
Market ratios, such as a ratio of spot and forward prices.
Typical market structural indicators highlight the competitiveness and efficiency of the market in
the defined relevant markets. Structural indices may be controversial, however measures such as
Herfindahl-Hirschman Index (HHI) or a measure of pivotal supply can serve as indicators of the
state of the market structure and, if properly standardized, permit comparisons across markets.
Market performance measures typically focus on whether market outcomes are consistent with
outcomes expected in a competitive market. Aggregate market performance measures should
cover a wide range of markets (e.g., energy markets, ancillary services, and capacity revenue
rights), periods (e.g., day ahead and real time markets, longer term), and conditions (e.g., prices
in relation to costs, output in relation to capacity, market depth and liquidity). Since no single
measure will satisfy all the purposes of performance measurement, a balanced group of measures
will be needed. A Lerner index that indicates the price markup over cost could be used to assess
the competitive level of a market.
General measures may indicate a need for further investigation, but drawing a line between
outcomes that are caused by difficult to measure fundamentals (such as scarcity) and difficult to
measure undesirable behavior (such as economic withholding) remains a matter of analytic
judgment. Mitigation tools that can be employed ex ante may be preferable to ex post
monitoring, but metrics to monitor the behavior of individual participants will remain important.
3
Federal Energy Regulatory Commission, Strawman" Staff Discussion Paper on Market Metrics, SMD Staff
Conference on Market Monitoring, Docket No. RM01-12, October 2, 2002.
6
The number of Automated Mitigation Procedure (AMP) events or investigations of market
power abuse are good indications about market conduct.
Based on the FERC strawman on market metrics, the following measures will be used in this
paper for comparing the implementation of various markets:
1. Concentration ratio (HHI)
Concentration ratios are a summary measure of market shares, a key element of market structure.
The concentration ratio used here is the Herfindahl-Hirschman Index, which is calculated as the
sum of the squares of the market shares of the firms in a market. According to FERC’s Merger
Policy Statement, a market can be broadly characterized as unconcentrated when the market HHI
is below 1000 (the equivalent of 10 firms with equal market shares); as moderately concentrated
when the market HHI is between 1000 and 1800; and as highly concentrated when the market
HHI is greater than 1800 (the equivalent of between 5 and 6 firms with equal market shares).
2. Average energy price, or load-weighted average energy price adjusted by fuel cost and
trend
The overall level of prices is a good general indicator of market performance, although overall
price results must be interpreted carefully because of the multiple factors that affect them.
3. Ancillary services prices and capacity prices
4. Net revenue (load paid price minus operating costs)
Net revenue is an indicator of the profitability of an investment in generation.
5. Price-cost mark-up (Lerner index) and trend
The price-cost markup is a widely used measure of market power.
6. Congestion costs, percentage and trend
Congestion costs and trend is a combined measure for operation efficiency and market power
mitigation.
7. Market power abuse investigation and mitigation
A good market design could be immune from frequent market power abuse or prolonged high
prices.
8. Operational Issues
Operational issues such as noncompliance rate and price correction rate give a good indication
about operating efficiency of a market.
9. Retail competition (switching rate) and load participation (energy) rate
Reducing inelasticity of demand could help to mitigate market power.
10. New entry and capacity construction percentage
High levels of new entry and capacity construction percentage signal a long-term competitive
market.
7
II. Existing Markets and Planned Market Designs
This study reviews the market design and 2001 performance of ten existing markets (PJM,
NYISO, ISO-NE, ERCOT, IMO, Alberta, Nord Pool, NETA, NEM, and NZEM) and the market
design of three proposed markets (NERTO, MISO, MDO2). The following chart summarizes the
deregulation timeline and the major structural evolution of these markets:
Figure 2: Timeline and Bilateral Schedule of Major Deregulated Markets
Apr 1990:
UK Pool
opens
Overseas
Jan. 1991:
Norway
launches
Nordpool
1990
1992
Oct 1996:
New
Zealand
NZEM
Dec 1998:
Australia
NEM opens
Jan. 1996:
Sweden in
Nordpool
Jan. 1998:
Finland in
Nordpool
Jan. 2000:
Denmark in
Nordpool
1998
2000
1994
1996
North
America
Mar 2001:
NETA
replaces UK
Pool
Jan 1998:
PJM ISO
created
May 1999:
ISO-NE
opens
July 2001:
ERCOT
opens
Mar 1998:
Cal ISO
opens
Nov 1999:
NY ISO
launches
Jan. 2001:
Alberta
Pool opens
May
2002:
Ontario
IMO
launches
Physical Bilateral / Self- Schedule
UK Pool NE-ISO
Australia (40%Fin)
0 (Spot Market)
Max ISO
CAISO
0 ~10%
25%
NYISO
(50%)
PJM
(64%)
50%
Nord Pool
(71%)
75%
NETA
(98%)
ERCOT
(97%)
100%
Bilateral
Min ISO Contract
Market deregulation started a decade ago with a central dispatched pool structure with
competitive bids and offers. In such a market, suppliers would submit all of their generated
electricity output with associated prices and all buyers would submit bids to buy electricity. The
pool would be the only place to trade electric energy and settle the energy prices based on
demand-supply movement. Hence, both suppliers and buyers would be limited in their ability to
8
hedge against potential risks. The pool structure can suffer from various forms of market power
because 1) electricity demand is relatively inelastic and consumers as a whole have little
influence on the prices, 2) a large amount of energy trading provides strong incentive for
suppliers to raise prices by physical and economic withholding, and 3) market power can be
exercised in various situations that are difficult to monitor and correct in a timely manner such as
happened in the United Kingdom (pre-NETA) and California. There is a trend in recent market
designs to move away from the pool structure toward using bilateral contracts to mitigate market
power and hedge risks. One major example of this is the UK’s recent replacement of the pool
model with the bilateral oriented NETA. An important lesson from the California crisis is the
crucial role of managing risk through market design. In most other industries, risk bearing is
spread along the supply chain via long-term forward contracts or financial instruments for
hedging. This is generally accepted as the optimal behavior since a seller and a buyer have
common interests in mutual insurance against the volatility of spot prices. Similarly, electricity
markets have been successful everywhere that spot markets account for only a small fraction of
transactions.
1. PJM Interconnection Market
The Pennsylvania-New Jersey-Maryland (PJM) Interconnection serves about 9.6 million
customers with installed capacity of 59,000 MW.4 In the year 2000, PJM served 262,081 GWh
of energy, which represents about 7% of U.S. electric energy. PJM’s generation fleet has a fuel
mix of 31% coal, 27% oil, 22% nuclear, 6% natural gas, and 5% hydroelectric. PJM uses the
“tight pool model” rather than the “power exchange model.” PJM allows physical bilateral
scheduling that enables it to leverage its long-standing pool and its emerging bilateral markets.
PJM operates a day-ahead energy market, a real-time energy market, a daily capacity market,
monthly and multi-monthly capacity markets, a regulation market, and the monthly Financial
Transmission Rights (FTRs) auction market. PJM introduced nodal energy pricing with marketclearing prices in April 1998 and nodal market-clearing prices (see Appendix II) based on
competitive offers in April 1999. PJM implemented a competitive auction-based FTR market in
May 1999. Daily capacity markets were introduced in January 1999 and were broadened to
include monthly and multi-monthly markets in mid-1999. PJM implemented the day-ahead
energy market and the regulation market June 2000. PJM plans to add a spinning reserves market
in the near future. PJM currently calculates and posts LMPs for more than 1,750 buses located in
the PJM control area and an additional 600 buses located outside the PJM control area. LMPs are
also calculated for aggregate load buses and the PJM eastern and western hubs.
4
Information in this section is based on (1) PJM Interconnection State of the Market Report 2001 by Market
Monitoring Unit, PJM Interconnection, L.L.C. June 2001; and (2) The Amended and Restated Operating
Agreement of the PJM Interconnection, L.L.C. (“Operating Agreement”) setting forth procedures for a twosettlement system; Filing to Federal Energy Regulatory Commission, March 10, 2000. The section also contains
information from the PJM website: www.pjm.com.
9
Figure 3: PJM Model
Monthly FTR
Auction Market
Bilat
eral
contr
act,
64%
Load
Participation
Capacity
Markets
Day-ahead 15%
energy market &
Regulation market
ICAP 18%
Must offer
$100/MWh
LMP prices
& FTR value
$1000/MWh
c
a
P
Real time 21%
energy market
LMP prices
& Dispatch
*The difference between PJM model and SMD is that PJM model lacks an Automated Mitigation Procedure (AMP).
PJM’s two-settlement system consists of two markets – a day-ahead market and a real-time
balancing market. Separate accounting settlements are performed for each market. For the year
2001, real-time spot market activity averaged 6,563 MW during peak periods and 6,395 MW
during off-peak periods, or 21% of average loads. In the day-ahead market, spot market activity
averaged 4,794 MW on-peak and 4,877 MW off-peak, or 15% of average loads. The day-ahead
market is a financial market and thus may be used to provide a hedge against price fluctuations
in the real-time spot market. Also, for any generator that is scheduled in the day-ahead market,
the offer data submitted into the day-ahead market (before 12 noon) will automatically carry over
into the real-time market.
Day-ahead Market
The day-ahead market is a forward market in which clearing prices are calculated for each hour
of the next operating day based on generation offers, demand bids, bilateral transaction
schedules, and incremental and decremental bids, which are purely financial bids to supply and
demand energy in the day-ahead market. The day-ahead market uses exactly the same underlying
model of the system as the real time market.
PJM’s day-ahead market enables market participants to purchase and sell energy at binding dayahead prices. It further permits customers to schedule bilateral transactions at binding day-ahead
congestion charges based on the differences in the LMP between a transaction’s source and sink
locations. In the day-ahead market, Load Serve Entities (LSEs) will submit hourly demand
schedules, including any price sensitive demand bids, for the amount of demand that they wish to
lock-in at day-ahead prices. Generators that are designated as Capacity Resources5 must submit
5
A Capacity Resource is the net capacity from owned or contracted for generating facilities which are accredited
pursuant to the procedures set forth in the Reliability Assurance Agreement among Load Serving Entities in the PJM
Control Area.
10
an offer schedule into the day-ahead market unless they are self-scheduled or unavailable due to
outage. Non-capacity resources have the option to make offers into the day-ahead market, but are
not required to do so. Transmission customers may submit fixed or dispatchable bilateral
transaction schedules into the day-ahead market and may specify the maximum amount of
congestion charges they are willing to pay between the transaction sources and sink if congestion
occurs in the day-ahead schedule. FTRs are available to hedge congestion in the day-ahead
market.
Price sensitive demand bids are offered by entities with actual physical demand such as LSEs.
These bids allow a customer to place a bid to purchase a certain quantity of energy at a certain
location if the day-ahead price is at or below a certain price.
Decremental bids are similar to price-sensitive demand bids. They allow a marketer or other
similar entity without physical demand to place a bid to purchase a certain quantity of energy at a
certain location if the day-ahead price is at or below a certain price. Incremental bids are
essentially the flip side of decremental bids. The PJM day-ahead market allows all market
participants to use incremental and decremental bidding as financial hedging tools to provide
additional price certainty in a variety of situations.
“Up-to” congestion bids permit transmission customers to specify how much they are willing to
pay for congestion by bidding a certain maximum amount for congestion between the transaction
source and sink. If the congestion charges are less than the amount specified in the bid, then the
transaction will be reflected in the day-ahead schedule. The up-to bids protect transmission
customers from paying uncertain congestion charges by guaranteeing that they will pay no more
than the amount reflected in their bids. Transmission customers also may use an incremental and
decremental bid pair to accomplish the same type of hedging strategy, which further enhances
their price certainty options.
All spot purchases and sales in the day-ahead market are settled at the day-ahead prices. PJM
allows virtual bidding so market participants can submit bids that are purely financial in order to
arbitrage between the day ahead and real time market prices. Such bids are treated in the unit
commitment process as if they were physical. PJM calculates the day-ahead final schedule based
on the bids, offers, and schedules submitted. Day-ahead bids are of three types: energy bids by
generators that self-commit, virtual bids, and multidimensional bids including cost and operating
parameters by generators that want to be committed by PJM’s central unit commitment
algorithm. Generators that are committed by PJM are made whole on a 24-hour basis (i.e., PJM
guarantees cost recovery). All self-committed and centrally committed units are scheduled for
each hour in the day-ahead market through a security constrained bid-based dispatch, and the
corresponding hourly LMPs are calculated. The day-ahead scheduling process will incorporate
PJM reliability requirements and reserve obligations into the analysis. The resulting hourly
schedules and LMPs represent binding financial commitments to market participants.
Real-time Market
The real-time balancing market is based on actual real-time operations. As in the day-ahead
market, generators that are Capacity Resources must participate in the real-time balancing
market or may self-schedule. However, Capacity Resources that are available but were not
selected in the day-ahead scheduling may alter their bids for use in the balancing market. If a
generator chooses not to alter its bid, its original bid in the day-ahead market remains in effect.
11
The balancing market is the real-time energy market in which hourly clearing prices are
determined by the actual bid-based, least-cost, security constrained unit commitment dispatch.
LSEs will pay balancing prices (real-time LMP) for any demand that exceeds their day-ahead
scheduled amounts but will receive revenue (real-time LMP) for demand deviations below their
day-ahead scheduled amounts. Similarly, generators are paid balancing prices for any generation
that exceeds their day-ahead scheduled amounts and will pay for any generation deficit below
their day-ahead scheduled amounts. Transmission customers will pay congestion charges (or
may receive congestion credits) for bilateral transaction quantity deviations from day-ahead
schedules.
Ancillary Services Market
The PJM regulation market, introduced on June 1, 2000, supplanted an administrative and costbased regulation procurement mechanism that had been in place for many years. Market
participants can now acquire regulation in the regulation market in addition to self-scheduling
their own resources or purchasing regulation bilaterally. The market for regulation permits
suppliers to make offers of regulation subject to a bid cap of $100 per MW, plus opportunity
costs.
Capacity Market
An LSE has the obligation to own or acquire Capacity Resources greater than or equal to the
peak load that it serves plus a reserve margin of about 18%. LSEs have the flexibility to acquire
capacity in a variety of ways. Capacity can be obtained by building units, by entering into
bilateral arrangements, or by participating in the capacity credit markets operated by PJM.
Collectively, these arrangements are known as the Installed Capacity Market, or ICAP. The PJM
capacity credit markets are intended to provide the mechanism to balance the supply of and
demand for capacity not met via the bilateral market or via self-supply. Capacity credit markets
were created to provide a transparent, market based mechanism for new, competitive LSEs to
acquire the Capacity Resources needed to meet their capacity obligations and to sell Capacity
Resources when no longer needed to serve load. PJM’s daily capacity credit markets ensure that
LSEs can match Capacity Resources with changing obligations caused by daily shifts in retail
load. Monthly and multi-monthly capacity credit markets provide a mechanism that matches
longer-term capacity obligations with available Capacity Resources.
Financial Transmission Rights
PJM introduced Financial Transmission Rights (FTRs) in its initial market design in order to
provide a hedge against congestion for firm transmission service customers, who pay the costs of
the transmission system. PJM introduced the monthly FTR auction market to provide increased
access to FTRs and thus increased price certainty for transactions not otherwise hedged by
allocated FTRs. In PJM, firm point-to-point (PTP) and network transmission service customers
may request FTRs as a hedge against the congestion costs that can result from locational
marginal pricing. An FTR is a financial instrument that entitles the holder to receive revenues (or
charges) based on transmission congestion measured as the hourly energy locational marginal
price differences in the day-ahead market across a specific path. Transmission customers are
hedged against real-time congestion by matching real-time energy schedules with day-ahead
energy schedules. FTRs can also provide a hedge for market participants against the basis risk
12
associated with delivering energy from one bus or aggregate to another. An FTR holder does not
need to deliver energy in order to receive congestion credits. FTRs can be purchased with no
intent to deliver power on a path.
Price Cap
PJM’s mitigation consists of the $1,000/MWh bid cap in the PJM energy market and the
$100/MW bid cap in the PJM regulation market. To mitigate local market power, PJM limits the
offers of units which are dispatched out of merit order to relieve transmission constraints, to
marginal cost plus 10%. PJM has a number of additional rules designed and implemented in
order to limit market power. PJM is investigating other rules changes to reduce the incentives to
exercise market power.
PJM Market Monitoring Unit 2001 Market Report
• The Market Monitoring Unit (MMU) concludes that in 2001 the energy markets were
reasonably competitive, the capacity markets experienced a significant market power
issue in the beginning of the year, the regulation market was competitive, and the FTR
auction market was competitive.
•
The MMU concludes that the rule changes implemented by PJM addressed the immediate
causes of market power in the capacity market, that the PJM capacity market was
reasonably competitive later in 2001, but that market power remains a serious concern
given the extreme inelasticity of demand and the high levels of concentration in the
capacity credit markets.
•
The MMU concludes that there are potential threats to competition in the energy,
capacity and regulation markets that require ongoing scrutiny and in some cases may
require action in order to maintain competition. Under certain conditions, market
participants do possess some ability to exercise market power in PJM markets.
Performance Benchmark of PJM Market
Concentration ratio (HHI)
The results of the aggregate PJM HHI calculations for both the installed and the hourly measure
(Tables 1 and 2) indicate that the PJM energy market is, in general, moderately concentrated by
the FERC standards. Hourly energy market HHIs were calculated based on the real-time energy
output of generators located in the PJM control area, adjusted for hourly imports. The installed
HHIs were calculated based on the installed capacity of PJM generating resources, adjusted for
aggregate import capability. Overall market concentration varies from 975 to 2140 based on the
hourly measure and from 1155 to 1405 based on the installed measure.
13
Table 1: PJM Hourly Energy HHIs
Import level
Maximum
Average
Minimum
Overall Minimum
1885
1375
975
Overall Maximum
2140
1565
1275
Table 2: PJM Installed Capacity HHIs
Overall
Overall Minimum
1155
Overall Average
1280
Overall Maximum
1405
Average energy price and fuel-adjusted load-weighted average energy price
PJM load in 2001 was virtually identical to load in 2000 for slightly more than 90% of the hours.
The simple hourly average system wide LMP was 15.1% higher in 2001 than in 2000
($32.38/MWh versus $28.14/MWh) and 14.3% higher than in 1999. When hourly load levels are
reflected, the load-weighted LMP of $36.65/MWh in 2001 was 19.3% higher than in 2000 and
7.6% higher than in 1999 (Table 3 below). The load weighted result reflects the fact that market
participants typically purchase more energy during high price periods. However, when increased
fuel costs are accounted for, the average fuel cost adjusted, load-weighted LMP in 2001 was
7.6% higher than in 2000, that is, $33.05/MWh compared to $30.72/MWh.
Table 3: PJM Load-Weighted Average LMP ($/MWh)
1998
1999
2000
2001
Average
LMP
24.16
34.06
30.72
36.65
Median
LMP
17.60
19.02
20.51
25.08
Standard
Deviation
39.29
91.49
28.38
57.26
Year Over Year
Percent Change
Average
Median
Standard
LMP
LMP
Deviation
8.1%
-9.8%
19.3%
8.1%
7.8%
22.3%
132.9%
-69.0%
101.8%
Ancillary services prices and capacity prices
The MMU concluded that the regulation market functioned effectively and was competitive in
2001. The price of regulation in the market was approximately equal to the price under the
administrative and cost-based system, and the price exhibited the expected relationship to
changes in demand. There is the potential for various forms of non-competitive behavior in the
energy market to affect the regulation market, although there is no evidence of such an issue
during 2001.
In the last quarter of 2000, the available supply of capacity in PJM exceeded the obligation to
purchase capacity. Daily capacity prices were approximately zero from October 1, 2000 to
December 31, 2000. From January 1, 2001 through March 31, 2001, the capacity credit market
was much tighter and the daily capacity credit markets averaged about $177/MW-day for the
period. In late March the price began to decline, reaching zero in early April. From January
through the beginning of April 2001, the price in the daily PJM capacity credit market exceeded
the spread between the PJM West hub and both Cinergy and N.Y. Zone A, valued over 16 hours.
14
Net revenue (load paid price minus operating costs) and trend
Net revenue is an indicator of the profitability of an investment in generation. In 2001, the net
revenues would have more than fully covered the fixed costs of peaking units with operating
costs of about $45/MWh and which ran during all profitable hours. The results in 2001 reflect
both higher energy prices than in 2000 and higher capacity market prices that resulted in
significant part from the exercise of market power during the first quarter of 2001. Average
prices in 2001 exceeded those in both 2000 and 1999 for every marginal costs level, which
explains why the net revenue curve for 2001 is higher for marginal cost levels less than about
$35/MWh.
Generators receive capacity related revenues in addition to energy related revenues. In 2001,
PJM Capacity Resources received a weighted average payment from all capacity markets of
$95.34/MW-day, or $36,700/MW for the year. In 2000, the average payment from the capacity
markets was $60.55/MW-day or $23,308/MW-year.
Price-cost mark-up [(Price-marginal cost)/price] and trend
The price-cost markup is a widely used measure of market power. For the adjusted markup
index, the average markup in 2001 was 11% in 2001, with a maximum mark up of 13% in
January and a minimum markup of 9 % in October.
If the marginal unit is a combustion turbine with a price offer equal to $500/MWh and the
highest marginal cost of an operating unit is $130/MWh, the observed price-cost markup index
would be 74% ((500-130)/500). Coal and miscellaneous fuel units had average markups of
between 10% and 9% during 2001. In 2001, coal-fired units were on the margin 49% of the
time, petroleum-fired units 32% of the time, gas-fired units 18% of the time and nuclear units 1%
of the time. Petroleum-fired units’ share of marginal usage increased from 31% in 2000 to 32%
in 2001; the share of coal also increased by about 1%; the shares of nuclear; and the share of
natural gas was unchanged.
Congestion costs and trend
Congestion costs in PJM increased significantly, from $53M in 1999 to $271M in 2001. This
increase can be attributed to different patterns of generation, imports and load and, in particular,
the increased frequency of congestion at PJM’s Western Interface, which affects about 75% of
PJM load.
Market power abuse investigation and mitigation
The capacity markets experienced a significant market power issue in the beginning of the year.
This represented a price increase of 57.9% over 2000. The weighted average annual capacity
prices reflect the exercise of market power during the first portion of 2001.
Operation inefficiency
The need to procure day-ahead unit commitments to conduct security-constrained dispatch in the
day-ahead market could increase uplift significantly. Market participants can manipulate LMP
by submitting artificial schedules. About 21% energy trading at the real-time market, plus 40%
of dispatch noncompliance (in 2000), increase operational difficulty in the real-time and
15
probably increase regulation costs. Multi-solution of LMP and high price correction rate (4.6%
in 1999) reduce the benefit of LMP price signals.
Load participation
Active Load Management (ALM) reflects the ability of individual customers, under contract
with their local utilities, to reduce specified amounts of load when PJM declares an emergency.
ALM credits, measured in MW of curtailable load, reduce an LSE’s capacity obligation. In
2001, ALM credits averaged 1,851 MW, up slightly from the level of 1,819 MW in 2000.
New entry and capacity construction
From 1997 to 2000, annual capacity additions averaged almost 800 MW – a cumulative growth
rate of 4.2%. This growth was more than double the 2% average rate of peak demand growth
during this period. The short-term outlook for capacity additions sum to 23,339 MW by summer
of 2004 based on requested studies. Non-Load Serving Entities are supplying most new
generation additions. During 2001, Capacity Resources exceeded capacity obligation by
approximately 1,300 MW on average. PJM was capacity deficient for three days in January.
Potential Areas of Improvements in PJM Market
The MMU in PJM Annual Report recommended:
1. Evaluation of additional actions to increase demand side responsiveness to price in both
energy and capacity markets and actions to address institutional issues which may inhibit
the evolution of demand side price response.
2. Modification of the FTR allocation method to eliminate any barriers to retail competition.
3. Development of an approach to identify areas where transmission expansion investments
would relieve congestion where that congestion may enhance generator market power
and where such investments are needed to support competition.
4. Continued enhancements to the capacity market to stimulate competition, adoption of a
single capacity market design and incorporation of explicit market power mitigation rules
to limit the ability to exercise market power in the capacity market.
5. Retention of the $1,000/MWh bid cap in the PJM energy market and investigation of
other rules changes to reduce the incentives to exercise market power.
6. Retention of the $100/MW bid cap in the PJM regulation market.
MOD Staff observations
1. It is reported that market power exercises and threats exist in the ICAP market and spot
energy market. Larger energy trading in the spot energy market (energy pool) with
virtual trading provides gaming opportunities for generators to manipulate LMP and FTR
value by submitting schedules with misrepresentation of generator characteristics (i.e.,
ramping, minimum output). LMP makes market power mitigation more difficult since
changes of bid components have impact not only on a specific bus but on the whole
network as well.
16
2. The simple hourly average system wide LMP was 15.1% higher in 2001 than in 2000.
After accounting for both the actual pattern of loads and the increased costs of fuel,
average prices in PJM were 7.6% higher in 2001 than in 2000, which means suppliers’
profits increased 76% if we assume that they earned 10% margin in 2000.
3. Increased congestion costs ($53 million in 1999 to $271 million in 2001) indicate that
market participants did not change their scheduling behavior to avoid congestion based
on the day-ahead price signals.
4. The ISO needs to procure a large amount of day-ahead unit commitment to conduct
security-constrained dispatch in the day-ahead market, which could significantly increase
uplift to loads.
5. Twenty-one percent of energy trading at the real-time market plus 40% of dispatch
noncompliance (in 2000) significantly increases operational difficulties in real-time and
probably increase costs of regulation services.
2. New York Independent System Operator Market
The New York Independent System Operator (NYISO) is a non-profit organization formed as
part of the restructuring of New York State’s electric power industry.6 The NYISO officially
assumed control and operation of the state’s power grid on December 1, 1999, replacing the New
York Power Pool, which had operated the statewide, centrally-dispatched power pool for over 30
years. The NYISO is responsible for the operation of New York’s high-voltage transmission grid
and the administration of a wholesale electricity market in which power is purchased and sold at
market-based prices. NYISO supplies 157,000 GWh of electric loads annually with a peak load
of about 30,983 MW and installed capacity of more than 35,000 MW.
The NYISO operates both a day-ahead and a real-time energy market, which together are known
as the two-settlement system. Energy transactions and transmission usage scheduled in each of
these markets are settled using Locational Based Marginal Prices (LBMPs). The day-ahead
market determines LBMPs at each generator bus and for each load zone for each hour of the next
day with simultaneously procuring and optimizing ancillary services. The real-time market
determines the spot price used to settle real-time transactions and differences between day-ahead
schedules and real-time generation and load. In addition to a day-ahead market and a real time
energy market, the NYISO operates an hour-ahead Scheduling Model to facilitate market
operation. The Scheduling Model includes processes to dispatch generation, procure ancillary
services, schedule external transactions, and set market-clearing prices in the day-ahead and the
real-time markets based on supply offers and demand bids. The NYISO also administers separate
ICAP and Transmission Congestion Contract (TCC) markets.
6
Information in this section is based on (1) Feasibility Study for a Combined Day-Ahead Market in the Northeast by
John P. Buechler, Scott M. Harvey, Susan L. Pope, Robert M. Thompson, April 20, 2001; (2) 2001 Annual Report
on the New York Electricity Markets by David B. Patton and Michael T. Wander, Independent Market Advisor to
the New York ISO, June 2002; (3) NYISO Market Operations Report, Business Issues Committee Meeting, October
23, 2002, Agenda #4; and (4) DRAFT TREATMENT OF DISTRIBUTED RESOURCES, NYISO-DSM Focus
Group, Revised: November 16, 1998. Information was also found on the NYISO website:
http://www.nyiso.com/services/documents/mthly-reports/index_mthly-report.html.
17
Figure 4: NYISO Model
Monthly TCC
Auction
50%
Bila
teral
cont
racts
Load
Participation
Capacity
Markets
ICAP 18%
Must offer
$1000/MWh
Financial Day-ahead
Energy & A/S Market
LMP Prices
& TCC value
Hour-ahead
Schedule Mode
Real time energy
& A/S market
C
A
P
AMP
LMP Prices
& Dispatch
* The difference from SMD is the Hour-ahead Schedule Mode
Day-ahead Market
The NYISO administers the Day-ahead Market in which capacity, energy, and ancillary services
are scheduled and sold for the following day. The Day-ahead Market closes at 5:00 AM for the
following day. The New York Security-Constrained Unit Commitment (SCUC) simultaneously
conducts markets to commit generation to meet energy, operating reserve, and regulation
requirements based on the bids of market participants.
The Day-ahead Market is a forward market in which hourly clearing prices are calculated for
each hour of the next operating day based on Generation Offers, Demand Price Sensitive Bids,
Virtual Supply Offers, Virtual Demand Bids, and self schedules submitted into the Day-ahead
Market. Bilateral schedules are accepted in the day-ahead SCUC process and are accompanied
by incremental and decremental bids. The day-ahead scheduling process will incorporate
NYISO reliability requirements and reserve obligations into the analysis. Based on the load
forecast, NYISO will issue day-ahead unit commitment to meet forecast demand and reserve
requirements, and it establishes day-ahead schedules for each generator. The resulting day-ahead
hourly schedules and day-ahead LMPs represent binding financial commitments to the Market
Participants.
All generators that are installed Capacity Resources in New York are required to either bid into
the Day-ahead energy Market, be scheduled in a day-ahead bilateral transaction to serve load in
the New York Control Area, or be unavailable due to maintenance, forced outage, or temperature
derating.
The hourly energy prices, LBMPs, are calculated for each generator location within New York,
eleven load zones, and four proxy buses reflecting the regions bordering New York (PJM,
NEPOOL, Ontario and Hydro Quebec). Bilateral schedules pay a day-ahead transmission usage
18
charge to the ISO that is calculated from the difference between the LBMPs at the source and
sink locations. Day-ahead settlements for reserves and regulation are presently based on a single
market-clearing availability price. Financial Transmission Rights (FTRs) are accounted for at the
day-ahead LMP values.
Hour-ahead Schedule
The NYISO also has a “day-of” Balancing Market Evaluation (BME) that occurs 90 minutes
prior to each hour to allow market participants to adjust their day-ahead schedules and bids. The
hour-ahead scheduling process updates the day-ahead commitment of resources based on
forecast load for the next hour. This model also schedules non-dispatchable resources and
external transactions. The NYISO calculates LBMP prices during the BME process, but these
prices are presently used for settlements only for ancillary services availability payments and, in
certain circumstances, external transactions.7 Any new firm transactions will be scheduled by
BME which could displace some of the day-ahead non-firm transactions. The results are then
posted by 30 minutes before the hour as the schedule for the next hour.
Real-time Market
The NYISO administers the Real-time Market in which capacity, energy, and ancillary services
are sold for one-hour periods. The Real-time Market closes 75 minutes before the hour being
scheduled. The real-time energy market establishes the final dispatch of supply to meet demand
in each five-minute interval. Each of these markets utilizes locational marginal pricing that
reflects transmission constraints and losses. In the real-time dispatch, security constrained
dispatch (SCD) uses bid curves of the New York City Area (NYCA) generators to dispatch the
system to meet the load while observing transmission constraints. Bid curves will consist of a
combination of incremental bid curves provided by generators bidding into the LBMP market
and decremental bid curves provided by generators serving bilateral transactions.
The NYISO market allows virtual bidding by various resources. Virtual trading began in
November 2001, allowing entities that do not serve load to make purchases in the day-ahead
market. Such purchases are subsequently sold into the real-time spot market. Likewise, entities
without physical generating assets can make power sales in the day-ahead market that are
purchased in the real-time market. By making virtual energy sales or purchases in the day-ahead
market and settling the position in the real-time, any market participant can arbitrage price
differences between the day-ahead and real-time markets. For example, a participant can make
virtual purchases in the day-ahead if the prices are lower than it expects in the real-time market,
and then sell the purchased energy back into the real-time market. The result of this transaction
would be to raise the day-ahead price slightly due to additional demand and, thus, improve the
convergence of the day-ahead and real-time energy prices, due to additional supply in the realtime.
Although the virtual trading quantities remain relatively modest, NYISO assessed how virtual
trading is being used by market participants. Virtual bids and offers designed to arbitrage price
differences between the day-ahead and real-time markets or hedge the risk of trading in these
7
Feasibility Study for a Combined Day-Ahead Market in the Northeast by John P. Buechler, Scott M. Harvey,
Susan L. Pope, Robert M. Thompson, April 20, 2001.
19
markets should be price sensitive. Price insensitive bids that demonstrate a willingness to make
virtual purchases or sales at uneconomic prices relative to the expected real-time price may
signal a strategic attempt to influence day-ahead prices. Virtual trading activity has been
dominated by price sensitive bids and offers. Over the five-month time period studied, more than
98% of virtual demand bids were price sensitive while 89% of virtual supply offers were price
sensitive.
Transmission Congestion Contracts
The NYISO offers both firm and non-firm transmission service. Customers requesting firm
service agree to pay the congestion charges associated with their scheduled service. Non- firm
service is available for customers who do not want the ISO to schedule their transaction if it
would require payment of a congestion charge. Transmission service under the NYISO is made
available on a long-term fixed-price basis through the auction of Transmission Congestion
Contracts (TCCs). TCCs are financial transmission rights that can be used to hedge day-ahead
congestion costs incurred for a bilateral contract.
All requests for transmission service consist of an hourly bilateral schedule in MW, as well as an
hourly decremental bid for the generator supplying the bilateral transaction. The SCUC software
treats the decremental bid associated with a bilateral schedule identically to other generator bids
in the energy market, so that a bilateral generator may be dispatched so that its day-ahead energy
schedule falls below its bilateral schedule. When this occurs, the billing process records a
compensating purchase from the LBMP energy market to balance the bilateral transaction. Thus,
the decremental bidding provisions of the NYISO Tariff provide the opportunity for generators
participating in a bilateral transaction to buy energy from the LBMP market if it is cheaper than
generating to meet their bilateral commitment. The decremental bids of bilateral transactions
sourced from internal generation are determined directly from the generator’s incremental energy
bid curve. By submitting a large negative bid, the bilateral party can ensure that the generator
schedule will not be modified, except under extreme circumstances.
Ancillary Services Market
The Ancillary Services Market allows the NYISO to obtain adequate Operating Reserve Service
(including Spinning Reserve, 10-Minute Non-Synchronized Reserves and 30-Minute Reserves)
and Black Start Capability. The NYISO fully co-optimizes markets for ten-minute synchronized
reserves, ten-minute non-synchronized reserves, thirty-minute reserves, and regulation.
Capacity Market
The New York State Reliability Council (NYSRC) has determined that an installed reserve of
18% over the NY City Area for the year 2002 summer peak load is required to meet the
Northeast Power Coordinating Council reliability criterion. The NYSRC revisits the issue of the
installed reserve margin each year.
Price Cap and Automated Mitigation Procedure
There is currently a $1000/MWh bid cap for energy in New York which is expected to continue
for the immediate future. Day-ahead bid caps also apply to some generating units to mitigate
market power. There are FERC-approved caps on the bids of certain plants located within New
20
York City that have been divested by Consolidated Edison. These bid caps apply when certain
congestion patterns exist, and the applicability of these bid caps is determined in an initial step in
the SCUC software. There is also currently a $2.52/MWh bid cap on availability bid offers for
10-minute non-spinning reserves to mitigate market power in the 10-minute reserve market.
The Automatic Mitigation Procedure (AMP) is designed to prevent market abuse during times
when excess capacity in a geographic market is very low. The market may not be workably
competitive when one or more participants may have the ability to raise prices significantly by
withholding capacity. AMP is limited to the day-ahead market and implemented entirely within
the SCUC model. Supplier’s bids in the Day-ahead Market (DAM) will be automatically
reviewed to determine if they meet the following thresholds:
•
Conduct test examines bids to detect instances of economic withholding.
o Energy: $100 or 300 % higher than the energy reference price
o Start-up Cost: 200% above start-up cost reference
o Minimum Generation Cost: $100 or 300% above reference
•
Impact test determines if economic withholding makes a significant difference. Must
cause a price impact of $100 or a 200% increase.
•
Reference prices are computed based upon the lower of the mean or median of the
previous 90 days of accepted bids and are adjusted for fuel price changes.
When the AMP determines that a unit is economically withholding in the Day-ahead Market,
that unit’s bid price would be mitigated to its DAM reference price. Bids of hydro resources,
imports or suppliers withholding very small amounts would be excluded. A consultation process
would allow any supplier to provide a justification for an economically withheld resource in
advance. In order to minimize unnecessary mitigation, 50 MW of a portfolio are exempted from
mitigation:
•
The generation unit is subject to mitigation if one or more of the portfolios exceeds the
exemption.
•
All MW in the portfolio are subject to mitigation if the portfolio exceeds the exemption.
NYISO 2001 Annual Market Report8
1. The markets remained workably competitive, with limited instances of significant
withholding or other strategic conduct.
2. Lower fuel prices and reduced generation outages in Eastern New York led to lower
energy prices statewide and substantially less congestion.
8
Selected excerpts from (1) Annual Report on the New York Electricity Markets, David B. Patton and Michael T.
Wander, Independent Market Advisor to the New York ISO, June 2002, and (2) 2001 Annual Report on the New
York Electricity Markets, Presented to: Federal Energy Regulatory Commission, David B. Patton, Independent
Market Advisor, June 6, 2002.
21
3. Convergence between day-ahead and real-time prices improved between 3 and 6% in the
three zones (e.g., the difference in the Capital zone fell from a 7% premium in 2000 to
less than 1% in 2001).
4. The frequency of price corrections and reservations has decreased considerably in 2001,
improving the price certainty provided by the NYISO markets.
5. The New York ISO’s market power mitigation measures were sufficient to address
market power exercises. However, the Consolidated Edison (ConEd) mitigation
applicable to New York City (NYC) that is triggered on the presence of congestion into
NYC tended to mitigate energy offers excessively.
6. There continued to be significant differences in super-peak hours between the outcomes
of the hour-ahead commitment model that schedules external transactions and offdispatch generation and the real-time market model.
7. Day-ahead prices remain slightly higher on average than real-time prices. This can be
attributed to the fact that prices in the real-time market are more volatile than in the dayahead market.
Performance Benchmark Measurement
Concentration ratio (HHI) and trend
The HHI figure representing the overall market was not available. In the NYISO annual report,
the HHI of the 10-Minute NSR market was calculated using the maximum capability of each
unit, which yielded an HHI of approximately 4000. However, because the capabilities of the
suppliers can change from hour to hour as their ratings change or they are selected in other
markets, HHI was also computed based on available capability in peak hours and off-peak hours
for 2001, which were close to 3900 for both. These results indicate that the market remains
extremely concentrated. However, if several factors, such as substitution of 10-Minute spinning
reserves for non-synchronous reserves and the sizable amount of excess available capacity, are
not accounted for in these HHI statistics, the HHI in the peak and off-peak periods was reduced
to 2900 and 2800, respectively. These results suggest that the 10-Minute NSR market remains
highly concentrated.
Average energy price and fuel-adjusted load-weighted average price
Loads in 2001 were higher throughout most of the year compared to 2000. The higher loads
offset the declining energy prices to cause the total settlements through the NYISO markets to
remain virtually unchanged from 2000. Average energy prices in July and August 2001 rose
considerably despite the decline in fuel prices. Prices were particularly high in August as demand
established new records due to sustained hot weather early in the month. Prices on August 9th
alone raised the actual average energy prices for the month by 20%, with no evidence of strategic
withholding by suppliers. The energy prices in NYC would have been approximately 13% higher
during the summer, though this increase is largely offset by decreases in uplift charges.
Electricity prices in New York decreased 52% from January to December 2001. This is
primarily due to substantial decreases in the prices of input fuels over the same period, 40% for
fuel oil and 70% for natural gas.
22
Ancillary services prices and capacity market prices
Reserves costs were relatively steady over the course of 2001 with a slight rise in the summer
months when capacity was in short supply. However, the total costs remain close to 2% of total
market expenses, down significantly from 2000 when withholding caused ancillary services to
exceed 15% of the market expenses during the Spring. Table 4 summarizes the prices of
ancillary services in NYISO.
Table 4: NYISO Unweighted Ancillary Services Prices9
Day Ahead Market($/MW)
Aug-01
Sep-01
Oct-01
Nov-01
Dec-01
Jan-02
Feb-02
Mar-02
Apr-02
May-02
Jun-02
Jul-02
Aug-02
Spin
2.41
2.46
2.12
2.38
1.94
1.97
1.88
2.63
2.20
1.87
1.83
2.34
3.20
Non-Spin
2.14
2.19
1.93
1.55
1.62
1.51
1.47
1.52
1.48
1.43
1.39
1.41
2.03
30Min
1.21
1.72
1.91
1.50
1.14
1.09
1.11
1.13
1.19
1.20
1.17
1.24
1.90
Real time market($/MW)
Reg.
9.80
13.69
13.81
12.39
14.41
14.90
13.83
12.59
12.33
18.78
20.92
20.85
21.31
Spin
17.89
4.36
1.37
1.75
5.67
1.83
0.97
1.36
2.48
0.45
0.42
1.18
1.03
Non-Spin
16.75
3.58
1.28
0.72
4.36
0.61
0.54
0.53
1.63
0.33
0.35
0.87
0.66
30Min
15.57
2.74
1.27
0.69
2.16
0.52
0.47
0.40
1.07
0.28
0.17
0.01
0.18
Reg.
7.22
8.33
1.09
0.63
0.37
0.52
0.74
0.51
0.60
0.44
1.28
1.20
1.37
The capacity prices are consistent with the expectations. In the summer capability period, nearly
all of the capacity is scheduled to meet the state’s capacity requirements. Hence, the capacity
market was tight during this period and prices in the monthly auction cleared at levels
approaching the deficiency price of $9.60 per KW-Month. During the winter capability period, a
surplus of capacity emerged in the state as evidenced by the relatively large quantities of
capacity that remained unsold during the capability period. The monthly capacity prices fell
sharply to prices below $1 per KW-Month while the strip price for the capability period
remained at close to $2 per KW-Month. The prices in the strip auction cleared at much lower
levels, which may be attributable to the adoption of bidding strategies on behalf of loads and
generators that did not effectively anticipate conditions in the monthly market.
Congestion costs and trend
Congestion rents declined by 40% from 2000 ($517 million) to 2001($310 million). They are
defined as the difference between the payments to generators and revenue collected from loads
(excluding losses) plus net congestion payments made for bilateral transactions. The lower
congestion costs are attributable to the following factors:
9
http://www.nyiso.com/services/documents/mthly-reports/index_mthly-report.html
23
•
The return of Indian Point 2 (1000 MW) in Eastern New York;
•
Lower oil and gas prices that supply the generating units that are usually on the
margin in Eastern New York;
•
Increased imports offered from New England; and
•
Reduced imports into New York across the Hydro Quebec interface.
Total uplift costs increased about 40%, which is primarily due to increases in out-of-merit
dispatch of generation to maintain local reliability, typically in New York City. One of the
modifications to the market that is being made in 2002 is to modify the NYISO market models to
secure the transmission constraints within NYC that are now managed with out-of-merit
dispatch.
Market power abuse investigation and mitigation
As described in NYISO’s annual report, mitigation by the AMP in the day-ahead market,
occurred on four days. Mitigation under the ConEd Mitigation for New York City occurred in
all but 17 days for energy bids and all but four days for reserves bids. Mitigation in the real-time
energy market not related to Thunderstorm Alerts occurred on six days. Mitigation related to
Thunderstorm Alerts occurred on seven days. All thirteen cases occurred during the summer
2001. NYISO plans to replace the ConEd mitigation measures with measures that are consistent
with NYISO’s conduct-impact mitigation framework applicable to the rest of New York.
Because locational capacity or reserve is also required in the constrained areas, a pivotal
supplier(s) has the ability by withholding the excess supply to keep the market at the deficiency
price level. In most cases, it is rational for the pivotal supplier to bid in this manner – accepting a
higher price for a lower quantity of capacity sales rather than selling most or all of its capacity at
the marginal cost level. This is consistent with market outcomes in the New York City capacity
market during the Winter capability period, explaining why these outcomes diverged from
competitive expectations.
Operation inefficiency
The NYISO has missed its goal regarding price corrections for 2002. Price correction rates have
tended to increase with demand level. For example, in August and September 2002, the intervals
corrected were 11.2% and 9.6%, respectively, and the hours corrected were 18.4% and 14.9%,
respectively.10 However, in September an additional change was made to remedy the source of
the incorrect price calculations.
Total uplift costs were around $325 million in 2001, excluding $140 million of ISO operation
costs. Uplift costs increased about 40% from 2000.
Retail competition (switching rate) and load participation (energy) rate
NYISO’s load participation includes price sensitive load, price capped load, and dispatchable
load.
10
“NYISO Market Operations Report,” Business Issues Committee Meeting, November 14, 2002.
24
•
Price Sensitive Load - Energy consumption which is varied in real-time by a market
participant, but which is not dispatched by the NYISO. Thus, this is load with hourly
metering and billing that monitors real-time LBMP energy prices, and varies
consumption accordingly without direction from the NYISO.
•
Price Capped Load - Load which schedules its consumption day-ahead according to its
price preferences so that it receives a forward contract for a specific amount at a specific
price.
•
Dispatchable Load - NYISO Direct Customer Load which bids a price curve into the
energy market so that it is available for dispatch by the NYISO. Any amount bid dayahead that was selected is essentially Price Capped Load. Dispatchable Load may also
bid regulation as Dispatchable Load in the form of a resource supplier.
New entry and capacity construction percentage
The peak loads that are forecast for the NYCA for the years 2002 through 2021 show a
compound annual growth rate of 1.2%. The forecast net energy for the same twenty-year period
shows a compound annual growth rate of 1.1%. These forecasts are based on forecasts submitted
by the Transmission Owners. Existing capacity within the NYCA and known purchases and
sales with neighboring control areas provide sufficient capacity to meet the 18% installed reserve
margin through the year 2011. Beyond the year 2011, the NYCA is showing a deficiency in the
capacity reported to meet the 18% installed reserve margin. It is anticipated that the resources
necessary to meet the required installed reserve margin will be procured through the NYISO
installed capacity market. Approximately 6,220 MW of new capacity has been included in the
NYISO’s installed reserve margin calculation.
Potential Areas of Improvements in NYISO
Authors of the NYISO Annual Report recommended:
1. The real-time scheduling system (RTS) is planned to replace the current hour-ahead/realtime scheduling and dispatch system.
2. It is reasonable to continue to apply the offer requirement on 10-Minute NSR in Eastern
New York. The current requirement applies only to suppliers of capacity in the New
York market. However, the ability to exercise market power in the ancillary services
markets or other NYISO markets is not limited to suppliers of capacity.
3. The $2.52 offer cap was lifted. Also, for monitoring and mitigation purposes, reference
prices should be established for each 10-Minute resource as the lower of the level
determined on the basis of accepted offers under the MMM and the $2.52 level. This
change will allow increased offering flexibility on the part of the 10-Minute NSR
resources, relying on the market mitigation measures to address instances of economic
withholding that significantly affect prices.
4. This limitation in the applicability of the mandatory offer requirement has already
allowed a significant amount of non-capacity resources to be withheld from the 10Minute NSR market. Therefore, this exclusion should be re-evaluated to determine
whether it would be appropriate to expand the offer requirement to apply to all 10-Minute
NSR resources in Eastern New York.
25
MOD Staff Observed:
1. Lower forward energy trading (around 50% bilateral contract) before the day-ahead
market indicates a higher percentage of energy relies on the pool. This may undermine
the generally accepted market design philosophy that energy trading should be separate
from physical dispatch. Forward financial markets are needed to increase liquidity before
day-ahead.
2. Mandatory centralized unit commitment with virtual trading would provide gaming
opportunities in the spot energy market. Generators could manipulate LMP and FTR
value by submitting legitimate schedule and misrepresenting their generator
characteristics (i.e., ramping, minimum output). LMP makes market power mitigation
more difficult since changes of bid components have impacts not only on that specific
bus but on the whole network as well.
3. The NYISO needs to procure large amount of day-ahead unit commitment to conduct the
security-constrained dispatch in the day-ahead market. Total uplift costs were about
$325 million in 2001, excluding $140 million of ISO operation costs. This is an increase
of about 40% from 2000, which is primarily due to increases in out-of-merit dispatch of
generation to maintain local reliability, typically in New York City.
4. Very high congestion costs even though congestion rents declined by 40% from 2000
($517 million) to 2001($310 million).
5. There continue to be significant price differences in super-peak hours between the
outcomes of the hour-ahead commitment model that schedules external transactions and
off-dispatch generation and the real-time market model.
6. Relatively low participation in the ancillary services markets remains an issue that can
create significant inefficiencies under peak conditions
7. The ICAP results in New York City were not consistent with competitive expectations,
that is, prices did not reflect the substantial capacity surpluses that emerged in the winter
2001-2002.
3. ISO New England Market
The ISO New England (ISO-NE) was established as a non-profit, private corporation on July 1,
1997.11 ISO-NE is responsible for operating New England’s electric bulk power system and for
administering the region’s restructured wholesale electricity markets. Made up of more than 350
generating units (installed capacity of 28,000 MW) connected by more than 8,000 miles of
transmission lines, the ISO-NE serves more than 6.5 million New England customers. ISO-NE
experienced a record demand of 24,967 MW in Summer 2001. The fuel mix consists of 26.5% of
11
Information in this section is based on (1) Annual Markets Report, May 2001-April 2002, ISO New England Inc.
September 12, 2002; (2) ISO New England, Inc., Annual Markets Report, May 2001 – April 2002, Section 2,
Technical Review; and (3) ISO-NE, NYISO Joint Filing - Joint Petition for Declaratory Order Regarding the
Creation of a Northeastern Regional Transmission Organization - filed 8/23/2002. Information was also found on
the NE-ISO website: (1) http://www.iso-ne.com/historical_market_data/ancillary_market_monthly_totals/ and (2)
http://www.iso-ne.com/market_monitoring/monthly_market_report.
26
nuclear, 20.8% of gas, 12.3% of coal, 11.8% of oil/gas, 5.8% of wood/refuse, 5.4% of oil, 3.2%
of coal/oil, and 3.0% of conventional hydro.
Prior to ISO-NE’s formation, the New England Power Pool (NEPOOL), a voluntary association
of New England utilities, operated the region’s bulk power generating and transmission facilities
for 27 years. On May 1, 1999, ISO-NE began to administer a wholesale marketplace for energy,
automatic generation control, 10-minute spinning reserve, 10-minute non-spinning reserve, 30minute operating reserve, and operable capacity. With the exception of operable capacity, these
products are currently bought and sold daily, by the hour. Market participants bid their resources
into the market on the day before, submitting separate bids for each resource for each hour of the
day.
ISO New England expects to implement Standard Market Design (SMD) during the first half of
2003. Key market features of SMD include new congestion management and multi-settlement
systems (CMS and MSS) designed to reduce market inefficiencies and improve market
responses. CMS helps to fairly allocate the cost of producing and transmitting electricity, which
is currently socialized among wholesale market participants. The locational marginal pricing
feature included within CMS will provide economic incentives needed to stimulate the location
of new generating units, upgrades to transmission facilities, and participation in demand-side
management programs. MSS determines how participants bid and are paid in the market. The
two-part market settlement structure consists of “day-ahead” and “day-of ” settlements that allow
for greater financial certainty to market participants.
Early in 2003, New England will replace NEPOOL’s existing bid-based single-settlement system
with bid-based, security-constrained day-ahead and real-time hourly markets. The system will
include locational marginal pricing (LMP), Financial Transmission Right (FTRs), and Installed
Capability (ICAP). At the outset, LMPs in New England will employ a fully nodal approach for
supply, with a zonal approach for loads. All FTRs will be auctioned, with the revenues produced
by such auctions allocated to entities receiving Auction Revenue Rights (ARRs). NEPOOL’s
current Operating Reserve markets will be eliminated and a new spinning reserve market that is
currently under development by PJM is expected to be implemented in New England in 2003.
Similar to PJM, ISO-NE would schedule resources for energy to meet Operating Reserve
objectives. Cleared/accepted offers for pool-scheduled generation in the Day-Ahead and RealTime Markets would be guaranteed to recover their as-bid costs through the receipt of Operating
Reserve credits. SMD will also revise the ICAP arrangements for New England by adopting a
comprehensive new ICAP regime based upon the New York ICAP market.
27
Figure 5: ISO-NE Model
Current NEPOOL
Generator bids
Real time poolmarket
Price and
Dispatch
Move to SMD in Spring 2003
Monthly FCR
Auction
40%
Fin.
Bila
teral
cont
racts
Load
Participation
ICAP
Must offer
LMP process
& FTR value
Day-ahead energy
A/S Market
Real-time Energy
Regulation Market
LMP prices
& Dispatch
$1000/MWh
C
A
P
AMP
The proposed SMD is very similar to what is currently operating in New York ISO, but it does not operate an hour-ahead
schedule mode.
Day-ahead Market
The Day-ahead Energy Market will produce financially binding schedules. The Real-time
Market will address real-time differences in available resources, load, and contingencies from the
Day-ahead Schedule. Whereas NEPOOL’s current single-settlement system establishes prices
and schedules for five products, SMD will initially determine prices in the Day-ahead and Realtime Markets for only two distinct products: Energy and Regulation.
The ISO-NE will operate the day-ahead unit commitment and scheduling process under its multisettlement system (MSS) using software that performs a Security-Constrained Unit Commitment
(SCUC) based on the supply and demand bids of market participants. It is intended that the
NEPOOL SCUC will simultaneously commit generation to meet energy, operating reserve and
regulation requirements. The unit commitment will be based on bids from qualifying generation
and loads to supply energy, 10-minute spinning reserves, 10-minute non-spinning reserves, 30minute reserves, and four-hour reserves and regulation. Suppliers and customers external to New
England may submit energy bids at external buses located in neighboring control areas. Unlike
New York, NEPOOL participants will not schedule physical bilateral transactions in the dayahead market. Bilateral schedules will be purely financial and will not enter into the SCUC
process. The unit commitment will be performed using a complete model of the NEPOOL
transmission system and will reflect transmission constraints based on the expected grid
configuration.
28
The day-ahead unit commitment and scheduling process in New England will be based on supply
bids from generating units, dispatchable loads, and market participants who wish to import
energy into NEPOOL, and on demand bids from market participants serving load. All supply
bids internal to NEPOOL must be associated with specific generators. Virtual supply offers from
external resources are permitted. Virtual demand bids are permitted both within and outside of
NEPOOL. Demand bids may be submitted at any location by any market participant, including
all LSEs within NEPOOL and participants that wish to export energy from NEPOOL. The ISONE will monitor the market to determine whether the virtual demand bids create gaming
opportunities or give rise to persistent inconsistencies between day-ahead and real-time prices.
As in PJM and New York, NEPOOL will implement multi-part energy bidding (called a “threepart price system”) for generators in the day-ahead unit commitment and scheduling process. The
objective of the day-ahead scheduling process is to meet bid-in load at least cost, subject to
meeting reliability requirements. Thus, the SCUC software will minimize the as-bid cost of
serving load that has bid into the day-ahead market and ensure that sufficient generation is
scheduled to meet forecast load, reserve, and regulation requirements.
Real-time Market
The Real-time Energy Market will clear for any differences between the amounts of energy and
ancillary services scheduled day-ahead and reflect real-time load, participant re-offers (dayahead), hourly self-schedules, self-curtailments, and any changes in general system conditions.
Capacity Market
Consistent with the PJM design, NE-ISO SMD will also permit Demand Bids, Decrement Bids,
and Increment Offers, and it will require Supply Offers for all available output of NEPOOL
Resources receiving credit for Installed Capacity (ICAP Resources). Units not receiving credit
for ICAP in NEPOOL (non-ICAP Resources) must offer all available energy not offered to
another Control Area or to ISO-NE in the Real-time dispatch.
Financial Congestion Rights
Transmission service under CMS/MSS will be made available on a long-term fixed-price basis
through the auction of Financial Congestion Rights (FCRs). FCRs are financial transmission
rights that, like the FTRs in PJM and TCCs in New York, provide a hedge against congestion
charges. Market participants can lock in their congestion-related costs in advance between a
point of injection and a point of withdrawal by purchasing FCRs to offset payments for
congestion. FCRs will be ultimately available as both obligations and options. In technical terms,
obligations establish a right to collect, or an obligation to pay, congestion rents in the day-ahead
market for energy associated with a single megawatt of transmission between a designated point
of injection and a designated point of withdrawal. Options, on the other hand, do not require the
holder to pay the ISO when congestion is in the opposite direction of the FCR. As in New York
and PJM, each FCR will specify an origin, a destination, a number of MW, and a time during
which the FCR is in effect. The origin and destination of an FCR may be any location, including
a node, a load zone, or the hub.
29
Price Cap
Pursuant to the Amended Interim Rule approved by FERC, energy bids are capped at
$1000/MWh during all hours, rather than only during periods of capacity shortages. Hourly
clearing prices for reserves are now capped at the Energy Clearing Price (ECP) during all hours.
The Amended Interim Rule will remain in effect until SMD is implemented, at which time a
substantially similar safety net bid limitation regime is expected to take effect. New market rules
developed for SMD are intended to foster convergence of day-ahead prices to their real-time
values, so that inefficient price differentials will not be allowed to persist within a load zone.
Similarly, FTR revenues may be capped if necessary to prevent persistent differentials between
day-ahead and real-time LMPs for the same delivery and receipt locations within an hour.
Load Participation
ISO-NE anticipates that LSEs may still desire to manage their peak load. The ISO encourages
LSEs to develop with their customers peak-shaving programs that are fully controlled by the
LSE. Such programs would not involve the ISO-NE settlement process in any manner. In
submitting their Demand Bid in the Day-ahead Market, the LSE can decide either to incorporate
the managed load that they control or to wait for real-time to decide if they wish to activate it.
ISO-NE 2001 Annual Market Report12
• In summer 2001, ISO-NE faced the highest demand for electricity in New England
history and was able to meet the challenge with the addition of 3,000 megawatts of
generation, along with the implementation of an innovative and collaborative Load
Response Program designed to reduce consumption during peak periods of demand.
12
•
With respect to market operations, electricity prices were less volatile and on average
lower than in the previous year. In terms of market performance, average prices in ISONE’s real time energy market decreased nearly 31% from $51.86/MWh in FY 2000 to
$36.04/MWh in FY 2001. Lower oil and natural gas prices significantly contributed to
this price decrease.
•
Similar to the Energy Clearing Price, All–In Energy Prices, comprising capacity, energy,
ancillary services and uplift costs, decreased by approximately 30% from FY 2000 to FY
2001.
•
Uplift costs in FY 2001 decreased by 43% compared to the previous year's level. The
introduction of Net Commitment Period Compensation (NCPC) and Three-Part Bidding
has contributed to the reduction in uplift costs.
•
At high loads, there was an apparent inconsistency between load levels and clearing
prices, as the ECP did not efficiently reflect the corresponding scarcity in supply.
Furthermore, during these periods there was considerable variation in the ECP from one
hour to the next as external contracts were dispatched to relieve capacity shortages. ISONE’s initial review of the ECPs for this period indicated that in many hours prices had
been established at inefficient and counterintuitive levels.
Summary of Annual Markets Report, May 2001-April 2002, ISO New England Inc. September 12, 2002.
30
•
Independent market assessments conducted during the year show that the region’s
participants and markets generally behave consistently with competitive expectations.
Performance Benchmark Measurement
Concentration ratio (market share) and trend
The market-wide HHI showed a steady decrease during the first two years of the markets due to
asset divestitures and new generation owners entering and expanding New England’s generation
capacity. Since May 2001, the market-wide HHI has stabilized around 700, suggesting that
markets are not significantly concentrated.
Average energy price, or fuel adjusted load-weighted average energy price
The third year of the markets saw record-breaking demand during heat waves in July and August
2001 and relatively low demand during the warmest winter on record in New England. ECPs,
fuel prices, ICAP prices, and uplift were all substantially lower in FY 2001 than in the previous
year. The average load-weighted ECP declined by 30.5% from FY 2000 to FY 2001, while the
All-In Price of Wholesale Power declined by 30% during the same period.
The also witnessed, on average, substantially lower energy clearing prices than in 2000-2001.
This decrease is primarily attributable to lower fuel prices. The load-weighted average price
decreased by 31%, from $51.86/MWh to $36.04/MWh. The fuel adjusted load weighted ECP
was $34.8/MWh in 2001, compared to $33.20/MWh in FY2000 and $33.25/MWh in FY1999.
Table 5 provides a comparison of broad indicators from the first three years of market operation.
Table 5: Broad Indicators, 1999-2000, 2000-2001, 2001-2002
Indicator
Average ECP - Load Weighted
Average Hourly MW Load
Peak Hour MW Load
Percentage of system load met
through the Spot Market
1999-2000
33.26
14,399
22,523
16%
2000-2001
51.86
14,916
22,024
24%
2001-2002
36.04
14,792
24,967
26%
Table 6: All-In Price of Wholesale Power (Load Weighted)
Market
Energy
Ancillary (Reserves & AGC)
Uplift
Capacity (Bilateral ICAP)
Grand Total
May 1999-April 2000
33.26
86.6%
0.61
1.6%
1.19
3.1%
3.33
8.7%
38.40
100.0%
May 2000 - April 2001
51.86
90.5%
0.31
0.5%
1.67
2.9%
3.44
6.0%
57.27
100.0%
May 2001-April 2002
36.04
90.6%
0.33
0.8%
0.97
2.1%
2.57
6.5%
39.90
100.0%
Ancillary services prices and capacity market prices
The total value (the clearing price multiplied by the MW requirement) of the reserve markets
(Automatic Generation Control (AGC), Ten-Minute Spinning Reserve (TMSR), Ten Minute
Non-Spinning Reserve (TMNSR), Thirty-Minute Operating Reserve (TMOR)) in the third year
31
of market operations was roughly the same as in the second year of the markets. It decreased
1%, from about $19.0 million in the second year to $18.8 million in the third year. Except for
July and August 2001 in the TMOR and TMNSR markets, the volatility of reserve prices
decreased from FY2000 to FY2001.
The AGC market has continued to be relatively stable. Average daily prices over the three-year
period have ranged from about $2.50 to $5.95 per Regulation Hour. Volatility continued to
decrease slightly in the third year. The total value in the AGC market increased 13%, from
around $21.6 million in the second year to $24.4 million in the third year. This increase is due in
part to continued greater utilization of AGC resources under Electronic Dispatch.
Table 7: Ancillary Services Prices of NEISO (Aug. 01 – Aug. 02) 13
Average Price
Aug-01
Sep-01
Oct-01
Nov-01
Dec-01
Jan-02
Feb-02
Mar-02
Apr-02
May-02
Jun-02
Jul-02
Aug-02
AGC
5.43
5.20
5.31
5.93
5.77
5.94
5.91
5.54
5.08
4.89
5.43
5.73
5.54
TMSR
1.59
0.53
0.35
0.28
0.31
0.32
0.49
0.80
1.36
1.71
1.54
3.27
8.98
Weighted AVG
TMNSR
4.35
0.89
0.26
0.30
0.26
0.20
0.54
0.46
0.41
1.11
0.98
2.92
8.57
TMOR
2.98
0.67
0.10
0.10
0.06
0.04
0.11
0.15
0.17
0.96
0.92
2.74
8.29
TMSR
1.28
0.41
0.27
0.21
0.23
0.24
0.40
0.61
1.09
1.30
1.18
2.97
8.14
TMNSR
4.48
0.81
0.29
0.30
0.27
0.21
0.56
0.45
0.43
1.09
1.04
3.09
8.56
TMOR
2.50
0.60
0.11
0.11
0.06
0.04
0.11
0.15
0.18
1.03
0.81
2.01
4.32
Capacity payments are in the $12,000/MW-year to $15,000/MW-year range, while ancillary
services revenue might total $5,000/MW-year.
Net revenue (load paid price minus operating costs) and trend
At FY2001 prices and costs, generators’ net revenues are lower than what would be needed to
cover the fixed costs of a new entrant. This is consistent with the lack of announcements of new
plant sites and units in the early stages of construction.
A representative combined cycle natural gas-fired plant with a variable cost of $27/MWh and a
heat rate of 6,800 BTU/KWh would receive net energy revenues of $77,000 in FY2001.
Similarly, a typical combustion turbine (CT) unit with a heat rate of 10,500 BTU/KWh would
realize net energy revenues of $18,000/MW in FY 2001. The annual fixed costs of a new
combined cycle plant in New England, including a return on investment, are in the range of
$90,000/MW to $125,000/MW. The corresponding fixed costs for a CT plant are in the range of
$60,000/MW to $80,000/MW. Therefore, the above calculation suggests that neither CT nor
13
http://www.iso-ne.com/historical_market_data/ancillary_market_monthly_totals/ and
http://www.iso-ne.com/market_monitoring/monthly_market_report
32
combined-cycle plants burning natural gas at the delivered spot price in FY2001 would have
recovered their fixed costs from net energy market revenues alone.
Congestion costs, percentage and trend
Uplift costs in FY2001 were $125 million which was 43% less than FY2000. The NE-ISO
attributed the reduction in uplift to the introduction of NCPC and Three-Part Bidding. NCPC is
an uplift compensation method for energy that encourages generators to submit flexible unit
characteristics in their bids. Three-Part Bidding is a bidding protocol that allows discrete bids
for start-up costs, no-load costs, and incremental energy costs. Uplift includes the cost of out-ofmerit dispatch to relieve transmission congestion. The transmission infrastructure in Southwest
Connecticut (SWCT) is inadequate to ensure that supply will reliably meet load within that area.
Transmission limitations not only prevent the import of less expensive energy, but they also limit
the output of local generation, resulting in congestion uplift costs.
Market power abuse investigation and mitigation
The NE-ISO 2001 Annual Report summarized three studies that were conducted in the previous
year to assess the competitiveness of New England’s markets. In two of the studies, a
competitive benchmark was calculated to provide an estimate of the wholesale market price that
would result if each market participant acted as a price taker and the market operated efficiently.
In the third study, unit deratings and generator output levels were analyzed to determine if
physical or economic withholding occurred. All three studies found that the markets are
workably competitive.
Operation inefficiency
ISO-NE administered or modified a total of 1,039 hourly prices in the third year of market
operations, which is nearly 12% of the hours. The largest single category was a set of revisions
to energy clearing prices due to confusion over a FERC order on the ability of external bilateral
dispatchable contracts to set a floor price in the energy market. .
Two-hundred-sixty-nine reserve prices were revised under the Special Interim Market Rule,
which limits reserve prices to the ECP. Although ISO-NE implemented a software feature to
automatically limit the hourly reserve-clearing prices to the ECP, eliminating the need for ISO
staff to manually flag, review, and revise each hour when reserve clearing prices exceed the
ECP, there were still conditions when the caps had to be manually applied.
Retail competition (switching rate) and load participation (energy) rate
The summer of 2001 Load Response Program received subscriptions for a total of 65.6 MW.
The load response program is divided into Class I (Demand Response) and Class II (Price
Response). The Class I program is an emergency interruptible load program where end-users
offer a guaranteed level of interruption, responding within 30 minutes to system reliability
threats. The Class II program is a price responsive program where end-users are paid the value
of their foregone energy consumption when they respond to an ISO-NE notice. As of August
2002, the Load Response Program registered over 202 MW, of which 99 MW is in SWCT.
33
New entry and capacity construction percentage
New England continued to attract investment in new generation capacity, keeping pace with the
region's steadily growing demand for electric power and providing the economic and
environmental benefits of the latest generating technologies. Over 1,300 MW of new capacity
began operating during FY 2001. Similar levels of new generation are expected to come on-line
over the next couple of years.
Potential Areas of Improvements in ISO-NE Market
Identified in ISO-NE Annual Report:
1. During the summer of 2001, the expected relationship between the ECP and higher load
levels was not observed; the ECP was often set at inefficiently low levels, particularly
during times of high demand, due to the large amount of capacity operating out of merit
and ineligible to set the ECP.
2. The analysis of Summer 2001 pricing concluded that the inefficient ECPs were primarily
attributable to the then-existing market rules and procedures, namely:
a. A large amount of capacity dispatched out-of-merit order or otherwise ineligible
to set the ECP;
b. Lack of appropriate reserve prices; and
c. Significant impediments to efficient trading between New York and New England
during peak periods when price differences prevail.
3. The market rules introduced as part of the Reform Package address many of these
problems by increasing the pool of units eligible to set the ECP, payment of opportunity
costs in the reserve markets, and improved rules governing transactions with New York.
The operation of ISO New England is still under the market structure of New England Pool,
though ISO-NE expects to implement SMD during the first half of 2003.
4. Electric Reliability Council of Texas Market
The Electric Reliability Council of Texas (ERCOT) is a single control area based upon the zonal
model that uses both portfolio and unit specific dispatch instructions to resolve local
congestion.14 ERCOT conducts a residual energy market for Balancing Energy Service (3 % 5% of total energy of 300,000 MWh in 2001) and ensures the reliability of the Texas electric
grid. ERCOT is a Min-ISO, similar to that in the UK, which issues dispatch instructions only in
real-time operations for balancing and congestion management. On November 1, 2002, ERCOT
implemented Relaxed Balanced Schedules, and this market change is expected to increase the
percentage of Balancing Energy Service used to meet market energy needs.
14
Primary information sources for this section include (1) observations by MOD staff, (2) Application of
Competitive Solution Method to Data from ERCOT Ancillary Capacity Services Market Oversight Division Staff
Report David Hurlbut, Ph.D. Julie Gauldin, M.Sc., October 2002; and (3) Electricity Retail Competition: A
comparative analysis of markets in England/Wales, South East Australia, Texas and Ontario October 2002.
Additional information was found on the ERCOT website: www.ercot.com.
34
The Texas wholesale electricity market is based on long-term bilateral transactions. The basic
design comprises a bilateral market along with balancing energy and ancillary services markets.
ERCOT has operated the day-ahead ancillary services markets and the real-time balancing
energy market since July 31, 2001. ERCOT began auctioning monthly and annual Transmission
Congestion Rights (TCRs) in February of 2002. In addition, in compliance with state statutory
requirements governing electric industry restructuring, monthly and annual generation capacity
auctions have been conducted by incumbent utilities in ERCOT.
Figure 6: ERCOT Model
TCR
Auction
95%
Bila
teral
cont
ract
Loads Acting
As Resources
Day-ahead
Schedule &
A/S Market
Capacity
Auction
Capacity
Adequacy
Congestion
$1000/MWh
Generic Costs
MCPE, TCR
value &
Dispatch
Real-time
Balancing Market
c
a
p
Bilateral Contracts
The bilateral market consists of private electricity purchases and sales arranged directly between
sellers and buyers, and it represents the bulk of delivered energy in Texas. Prices are based on
mutual agreements between the parties, and are not known by ERCOT. These agreements are
incorporated into base energy schedules that are submitted to ERCOT on a daily basis. These
schedules account for about 95% to 97% of the end-user electric energy requirements in
ERCOT.
Day-ahead Ancillary Services Market
ERCOT day-ahead ancillary services include regulation up, regulation down, responsive
(spinning) reserves, and non-spinning reserve services. These ancillary services are procured on
an hourly basis. Market participants can self-provide their ancillary services requirements or
allow ERCOT to procure these services for them. The market system is designed to seek the
lowest-cost solution to maintaining system reliability consistent with ERCOT protocols. ERCOT
procures the ancillary services from Qualified Schedule Entities (QSEs) through a bid process,
which results in a Market Clearing Price of Capacity (MCPC) for each service. The day-ahead
market operates from 6:00 am to 6:00 pm on the day prior to the operating day.
35
Day-ahead Schedule
ERCOT requires QSEs to submit schedules for their bilateral transactions, conducts the securityconstrained analysis, and publishes system congestion information. ERCOT conducts a capacity
analysis on a day-ahead basis, which forms the basis for the procurement of Replacement
Capacity in the day-ahead. After the close of the Day-ahead period, the Adjustment Period
begins. QSEs can adjust their schedules and bids throughout the Adjustment Period. The
Adjustment Period ends when the Operating Period begins. The Operating Period is comprised
of the Operating Hour and the hour preceding the Operating Hour. Based on its analysis of
schedule changes, Resource Plans, load forecasts, and other system conditions, ERCOT may
procure additional ancillary services during the Adjustment Period by announcing the need to
procure additional services and opening subsequent markets.
Operating Period
ERCOT receives incremental and decremental Resource Premium bids for the real-time
balancing energy services (used to solve local congestion) as part of the day-ahead Resource
Plan submissions. During the Operating Period, ERCOT evaluates the availability of Balancing
Energy Services. If more than 95% of the available balancing energy has been deployed in a
zone, ERCOT deploys Non-Spinning Reserves. ERCOT procures Balancing Energy Services for
each 15-minute interval. If required, ERCOT will use resource-specific energy bids to resolve
local (i.e., intra-zonal) congestion. ERCOT can procure out of merit energy to resolve local
congestion or for voltage support, and it procures non-spinning reserves when extreme weather
or system conditions require increased capacity to be online.
Real-time Market
The Real-time balancing energy market clears 20 minutes prior to the operating interval, based
on projections obtained using short-term forecasting tools. The bid stack for balancing energy is
fixed for the entire hour, but the energy market clearing price is adjusted every 15 minutes and is
posted 15-20 minutes before the start of the operating interval. Balancing energy makes up the
difference between the total ERCOT electricity requirements and the sum of the base energy
schedules. It may also be used to manage transmission congestion. Bids are accepted in
ascending order of price until the total quantity required is obtained. The bid price of the last
quantity accepted for Balancing Energy Service sets the Market Clearing Price of Energy
(MCPE) for that 15-minute interval.
Capacity Adequacy
ERCOT currently has no formal capacity market comparable to an ICAP market. The Public
Utility Commission of Texas is in the process of developing a reserve margin mechanism.
ERCOT utilities have traditionally been required to maintain a planning reserve margin of 15%.
In mid-2002, the ERCOT Board approved a 12.5% reserve margin requirement. Comparatively
high reserve margins are necessary because the system cannot rely on imports, due to its
isolation from surrounding interconnections. In 2000 and 2001, the reserve margins at peak were
14% and 21%, respectively.
36
Congestion Management and Transmission Congestion Rights
ERCOT uses a zonal commercial model and solves zonal and local congestion in two steps, in
conjunction with a security-constrained dispatch (Appendix III). In the first step, ERCOT clears
the predefined commercially-significant-constraint (CSC) congestion, dispatches zonal balancing
energy, and determines the market clearing price for each congestion zone. The Balancing
Energy Service offers are procured by ERCOT in each zone for zonal load balancing and for
inter-zonal congestion relief. The MCPE is determined in each zone based on the zonal offer
curves for balancing energy. If there is no interzonal congestion, the MCPE is the same for the
entire ERCOT region. In the second step, ERCOT uses resource-specific premiums to clear
local constraints and to issue resource-specific instructions to relieve local congestion.
Generators submit resource-specific premiums that specify the additional payments (in addition
to the zonal MCPE) that they require for the deployment of incremental (INC) or decremental
(DEC) balancing energy from the associated, specific resource.
Transmission congestion rights (TCR) were implemented in ERCOT along with the
implementation of direct assignment of interzonal congestion charges in February of 2002.
ERCOT initially adopted a simple flow-based transmission right approach and flow-based
congestion charges. ERCOT is moving toward a combinatorial auction for TCRs. Congestion
charges are imposed on QSEs based on the flow that their scheduled interzonal transactions
induce on the three commercially significant constrained corridors. ERCOT runs annual- and
monthly- TCR auctions.
Price Cap and Competitive Solution Method15
The Public Utility Commission has established price caps of $1000/MWh and $1000/MW for
energy and capacity, respectively. The Commission’s Market Oversight Division (MOD) has
developed a competitive solution method (CSM) that could be used to limit prices if potentially
anticompetitive conditions exist. The CSM tests (a) that the total MW offered in the bid stack is
at least 115% of the capacity that ERCOT needs to procure for that interval, and (b) that a pivotal
bidder does not set the MCP. A bidder is pivotal if removing all of its capacity leaves the
remaining bid stack short of what ERCOT needs for that market interval. If the test fails, an
MCP limit is calculated by removing all pivotal bidders from the bid stack after extension of the
market, subtracting the most expensive 5% of the remaining capacity, and multiplying the
highest resulting offer price by 1.5. If all bidders are pivotal (in which case an MCP limit could
not be calculated), ERCOT would pay bidders on an out-of-merit (OOM) basis using verifiable
costs. All bidders are pivotal when ERCOT procures all, or nearly all, of the bid stack.
Retail Competition
Retail competition began in ERCOT on January 1, 2002, six years after wholesale competition
began in Texas. At present, there are 17 states with active retail markets serving an estimated
total load of 36,000 MW. Roughly 11,000 MW of that competitive retail load is served in Texas.
15
Application of Competitive Solution Method to Data from ERCOT Ancillary Capacity Services Market Oversight
Division Staff Report David Hurlbut, Ph.D. Julie Gauldin, M.Sc., October 2002
37
Performance Benchmark Measurements
Concentration ratio (HHI) and trend
The ERCOT market has a high concentration of generation assets, which means it has a high
potential for the exercise of market power. In particular, the North and South Zones have high
HHIs because the incumbents have retained most of their capacity. The HHIs for each zone are
as follows:
Table 8: HHIs for ERCOT Zones
Zones
North Zone
South Zone
West Zone
Houston Zone
HHI
2,844
1,270
3,205
4,443
Average energy price, or fuel-adjusted load-weighted average price
The ERCOT-wide daily weighted average price for balancing up energy closely follows the
ERCOT spot market price published in Megawatt Daily. Balancing energy prices stayed in the
range of $18 to $40 for 98% of the time during the first year. There have been a total of 330
intervals (15-minute) with price spikes to $1000/MWh. Annual weighted average balancing
energy prices for ERCOT from August 1, 2001 to July 31, 2002 are presented in the following
table.
Table 9: Annual Weighted Average Prices for Balancing Energy
UBES-2001
DBES-2001
UBES-2002
DBES-2002
NORTH
$38.13
$4.70
$35.46
$14.75
SOUTH
$30.40
($4.83)
$28.93
$8.38
WEST
$34.75
($1.92)
$33.68
$9.59
HOUSTON
NA
NA
$28.57
$16.85
Ancillary service prices
The ancillary services for the first year were stable with daily weighted average prices falling
within the $2 to $12 /MW range for 99% of the time. There were a few isolated price spikes to
$999/MW for Non-spinning Reserves, which pushed the annual average price for Non-spinning
Reserves to $16.79. ERCOT market participants are currently studying measures that will
mitigate the price spikes when pivotal bidders set the price or if there is bid stack insufficiency.
Average ancillary service prices and the amount of ancillary services procured by ERCOT from
August 1, 2001 to July 31, 2002 are presented in Table 10.
38
Table 10: Average Ancillary Services Prices in ERCOT
Products
REGUP
REGDN
RR
NSRS
Price
$6.81
$6.03
$6.81
$16.79
Procured
11.29%
11.15%
13.38%
18.33%
Congestion costs, percentage and trend
Inter-zonal and local congestion charges have been high. Inter-zonal congestion from July 31,
2001 to February 15, 2002 was $165 million; however, the direct assignment of inter-zonal
congestion charges reduced the congestion charge to only $30 million from February 15 to the
end of September 2002. Annual accrual of local congestion was about $100 million as of July
2002. The rapid increase in wind generation capacity continues to push up local congestion
charges. Direct assignment of local congestion charges is currently under consideration by the
Commission.
Market power abuse investigation and mitigation
The Market Oversight Division investigated load imbalance issues that occurred in August 2001,
the first month of ERCOT operation as a single control area. Payments for these load imbalances
resulted in very high charges for the Balancing Energy Neutrality Adjustment (BENA), which
were uplifted to all market participants. Overscheduling of load became an issue because market
rules allowed for the socialization of interzonal congestion costs. On February 15, 2002, market
rules were changed to require the direct assignment of Zonal congestion costs, and transmission
congestion rights were introduced to allow market participants to hedge their zonal congestion
costs.
Local congestion costs continue to be socialized, making it possible for market participants that
own generation on the constrained side of a local constraint to game the market using the “Dec”
game. As noted above, a mechanism for the direct assignment of local congestion charges is
currently being evaluated.
During the first few months of the market, price spikes occurred on several occasions in the
ancillary services market. In many instances, the high prices were due to insufficient
competition in the market. MOD has proposed a mitigation measure that would rely on a
Competitive Solution Method to test the competitiveness of the market. Under the proposal, if
the test found that competitive conditions did not exist, the price would be determined
administratively. MOD’s proposal is currently under consideration.
Operation inefficiencies
Operation inefficiencies have been identified in several areas. The most salient operations
problems that the stakeholders are currently attempting to resolve are described below.
•
Resource Plans are used to provide ERCOT with information on resource specific
capacity and potential energy available for system reliability purposes. The accuracy of
some of the information provided by QSEs in the Resource Plan is at issue. ERCOT
bases operational decisions on this information, and settlements are also often based on
39
this information. When the information is incorrect, or when a QSE changes the
information of its resources’ operational parameters after ERCOT has made certain
operational decisions, problems may ensue. The problem is compounded because
ERCOT does not currently have the ability to track changes made to the Resource Plan
by the QSEs.
•
Since ERCOT does not issue a unit commitment and does not dispatch all resources of
the commercial model, it has to make assumptions based on information made available
by the QSEs ahead of real-time to procure Balancing Energy Services, provide for
regulation capacity, and manage congestion. The assumptions are also used to issue
resource specific instructions for congestion management. These assumptions are not
always consistent with real-time operations because ERCOT lacks the details about the
QSEs’ internal dispatch rationales. Implementation of the State Estimator is needed to
improve ERCOT real time operational knowledge. The addition of a function that
integrates real-time system information into resource specific deployment decisions is
also needed to improve congestion management efficiency.
•
The relationship between ERCOT’s deployment of balancing energy and its deployment
of regulation has not been optimal and several steps have to be taken to improve it.
•
The integration of load as a resource in ERCOT markets has been slow because the
required software and technical capabilities were not available at the start of the market.
Retail competition (switching rate) and load participation (energy) rate16
So far, customers in Texas have enjoyed significant savings in the cost of electricity due to the
restructuring. The price-to-beat rates as of January 2002 were approximately 12–15% less than
the regulated rates offered on December 31, 2001. Furthermore, unaffiliated retailers are offering
rates that are 5–7% below the price-to-beat rates. As a result, customers have been switching
retailers at a high rate. The switching rate has been constrained by ERCOT’s ability to administer
customer registration. Overall, users representing 23% of the load (compared to August 2001
levels) have switched suppliers. In terms of volume, most of the switching activity has taken
place among the large industrial customers, who switched 55% of their load to competing
retailers.
Load participation is still limited, partly due to low energy prices that do not justify the
economics of the service. Currently ERCOT has 1,050 MW of load participation.
New entry and capacity construction
From 1995 to January 2001, twenty-two new generating plants, totaling more than 4,743 MW,
were built in the ERCOT region. This represents 10.9% of total generating capacity. During this
same period, peak demand grew by 24.5%. An additional 22 plants, totaling 15,160 MW, were
under construction and scheduled for completion by the end of 2002. Virtually all of the new
plants are fueled by natural gas, increasing the dominance of this fuel source in the region’s mix.
16
Review of the Current Status of Power, Market Reforms in the U.S. and Europe EPRI Project Manager, H. Chao,
Draft - June 14, 2002.
40
Potential Areas of Improvements in ERCOT Market
Several issues, as described below, have come to light after the first year of ERCOT operations,
including congestion management, the potential for the “Dec” game in local constrained areas,
and ERCOT operational issues. In addition, the annual zonal adjustments make long-term
contracts more risky, which may impact market liquidity.
1. In the first step in resolving congestion, ERCOT uses the commercial model with
portfolio bids to procure zonal balancing energy to clear zonal congestion. As a
simplified zonal model, ERCOT commercial model does not always provide an accurate
solution for CSC constraints. In the second step, ERCOT has to assume actual movement
for next dispatch interval to issue unit commitment instructions to solve local congestion
since QSEs perform the actual dispatch based on balancing energy awards and the
schedule. These assumptions are not always consistent with real time operations because
ERCOT lacks the details about the QSEs’ internal dispatch rationales. Implementation of
the State Estimator is needed to improve ERCOT real time operational knowledge, and
the addition of a function that integrates real time system information into resource
specific deployment decisions is needed to improve congestion management efficiency.
As a result, large amount of OOMC has to be procured for congestion management.
2. For local congestion in ERCOT, there is a potential for “Dec” gaming to occur because of
the lack of direct assignment of local congestion charges. Large amounts OOME Down
are currently required in local congestion management.
3. Other significant operational problems that the stakeholders are currently attempting to
resolve are problems associated with (1) inaccuracy in the Resource Plan and the way it
is utilized by ERCOT, (2) clearing of local congestion, (3) deployment of regulation, and
(4) integration of Load Resources in ERCOT markets.
4. ERCOT operations have been hampered by delays in acquiring needed computer
software. It is expected that when the state estimator and the simultaneous feasibility test
programs are functional, ERCOT will be able to better manage frequency fluctuations,
deployment of regulation, and local congestion problems.
5. Northeast Regional Transmission Organization
Note: The following section is included for comparison and discussion even though NYISO and
ISO-NE announced on November 22, 2002 that they would withdraw their petition for the
formation of NERTO.
The NYISO and ISO-NE proposed a merger to establish the Northeast Regional Transmission
Organization (NERTO) which was expected to reach its full implementation in the 2005/2006
timeframe.17 NERTO would have operational authority for the region’s bulk power system,
which includes 64,000 megawatts of generating capacity and 18,000 miles of transmission.
NERTO would have a number of interconnections with neighboring control areas, including
PJM (2,500 MW), Ontario (2,400 MW), Quebec (3,425 MW) and New Brunswick (700 MW).
17
Summary from ISO-NE, NYISO Joint Filing - Joint Petition for Declaratory Order Regarding the Creation of a
Northeastern Regional Transmission Organization - filed 8/23/2002.
41
The wholesale markets in the 21 NERTO regions would supply electricity to over 14 million
customers, with a 2001 peak load of over 58,000 MW.
Figure 7: NERTO SMD 2.X Model
Monthly FTR
Auction
Load
Participation
Capacity
Markets
ICAP
Must offer
$1000/MWh
Bila
teral
cont
ract
Day-ahead Energy
& A/S Market
Real-time Energy
& A/S Market
(Forward Looking)
LMP Prices
& FTR value
LMP Prices&
Dispatch
C
P
A
AMP
Day-ahead Market
The NERTO Market would include day-ahead and real time energy markets co-optimized with
regulation and reserves markets. It would include LMP-based dispatching and congestion
management, a system of FTRs, security-constrained unit commitment, nodal ex post pricing,
and a uniform ICAP market. Both physical and virtual bids and offers would be permitted in the
day-ahead energy market. The Day-ahead Market would be purely financial, but if it fell short of
needed reserve, the ISO could commit to satisfying the reserve requirements. This would allow
freedom of operation to the DAM without endangering reliability. Participants would be able to
engage in bilateral or self-supply transactions instead of participating in the NERTO Market.
Short-term Scheduling
Short-term commitment software would be employed to update the day-ahead commitment of
resources continuously based on forecast load and energy. This software would also schedule
fixed output resources such as block loaded combustion turbines (resources that cannot receive
updated dispatch instructions every five minutes) and external transactions.
Real-time Market
The NERTO real-time market would use a real-time scheduling and dispatch process consistent
with its day-ahead security constrained unit commitment (SCUC) model. This model includes a
real-time, security-constrained scheduling process that looks ahead three hours and executes at
15-minute intervals, and it includes a dispatch process that looks ahead one hour and executes on
42
five-minute intervals. The SCUC would replace the separate Balancing Market Evaluation and
Security Constrained Dispatch mechanisms currently used in New York.
Capacity Market
NERTO would also administer an ICAP market based on the unforced capacity design currently
used in New York and PJM, or a new design in line with the FERC SMD NOPR. Under its
SMD, NERTO would establish locational requirements for reserves and ICAP. It would also
employ prospective mitigation measures that will be incorporated into its software to remedy
market power abuses in the day-ahead market and in real-time.
Price Cap and Mitigation
NERTO would employ prospective mitigation measures incorporated into its software to remedy
market power abuses in the day-ahead market and in real-time in New York City.
Load Participation
NERTO would promote robust demand-side response mechanisms, including a day-ahead
demand response program based on the current New York model, to be expanded through the
Northeast. These demand-side mechanisms would ultimately include the ability for qualified
demand resources to participate in the ancillary services markets.
Implementation Plan
NYISO and NE-ISO developed a preliminary three-stage implementation for NERTO, that can
be described in terms of three sets of SMD rules: SMD 1.0, SMD 2.0, and SMD 2.X. The
proposed SMD 2.X for NERTO would include a number of sophisticated features that are
consistent with, but not included in, either SMD 1.0 or the current NYISO market design. In
Stage 1, ISO-NE would transition to SMD 1.0 market rules while NYISO continued to operate
under its current market rules. SMD 1.0 would include LMP pricing, nodal pricing, losses, a dayahead market, spinning reserve, and regulation markets. In addition, the SMD 1.0 market design
would include the following features:
•
Nodal pricing at load buses
•
Ex post real-time pricing
•
Ability to accommodate transaction changes at 15-minute intervals
•
“E-schedules” for internal transactions permitting changes up to the start of daily
settlement
•
Self-commitment by generation
•
Self-scheduling by generation
•
Ability to accept Short Notice External Transactions
During Stage 1, NYISO would work with its software vendors to enhance its market design. The
result of these enhancements – SMD 2.0 – would incorporate key market design features of SMD
1.0 plus certain other enhancements. The features of SMD 2.0 include:
43
•
Simultaneous co-optimization of ancillary services and energy in day-ahead and real-time
market commitment decisions
•
10-minute spinning and non-spinning day-ahead and real-time reserve markets
•
30-minute day-ahead and real-time operating reserve markets
•
Accommodation of demand-side participation in reserve markets
•
Automated ex ante mitigation procedures in day-ahead markets and in real-time in New
York City
•
Price-responsive day-ahead demand reduction program
•
Ability to bid negative prices
•
Locational reserves
•
Generator bids that may vary by hour
•
Generator bids that may change up to one hour in advance of real-time
In Stage 2, NYISO would transition to operation under SMD 2.0. The features of SMD 1.0 and
SMD 2.0 to be included in the NERTO SMD 2.X would be based on an assessment of the
performance of SMD 1.0 and SMD 2.0 as well as any FERC SMD requirements.
The Implementation Plan was phased to allow the NERTO to realize regional market benefits
from the elimination of export fees and seams and standardized New York and New England
markets, prior to any implementation of a single dispatch and common settlement. The early
phases of the plan also included the activities and tasks required to meet the minimum functional
requirements of an RTO (i.e., centralized TTC, ATC, OASIS, open-scheduling system and
Planning). These early phases were followed by integration of administrative functions seeking
synergies in the design, building, testing, and implementation activities.
6. California Independent System Operator Market
The California Independent System Operator (CAISO) is a not-for-profit corporation subject to
FERC regulation.18 CAISO serves a population of 34 million, which in 2000 had a peak demand
of about 53,000 MW and consumed total energy of 264 terawatt-hours. Combined generating
capacity in the CAISO area (1999) was 53.2 GW, which was dominated by natural gas (36.3%)
and hydro (26.5%). The three largest investor-owned utilities, Pacific Gas and Electric (PG&E),
Southern California Edison (SCE), and San Diego Gas and Electric (SDG&E), own 45.8% of the
total capacity, including all of the nuclear capacity (4.3 GW) and 96% of the hydro capacity
(13.6 GW).
In its Market Design 2002 (MD02), CAISO proposed a three-settlement system, including a dayahead market, an hour-ahead market, and a real-time market based on Locational Marginal
Pricing (LMP). The new market design also includes the Available Capacity (ACAP)
18
Information in this section is based on (1) California Independent System Operator Market Design 2002 Project
Comprehensive Market Design, Proposal April 19, 2002. Information was also found on the CAISO website:
www.caise.com/docs.
44
Obligations, Firm Transmission Rights (FTRs), Price Caps, and an Automated Mitigation Plan
(AMP), which are similar to features of the Northeastern ISOs.
Figure 8: CAISO MD02 Model
Demand-side
Participation
FTR/FGR
Auction Market
Capacity
Markets
Market Based
Bid curves
Bila
teral
cont
ract
Residual Unit
Commitment
Day-ahead market
A/S Market
ACAP
Must offer
$108/MWh
Damage Control
C
A
P
LMP prices
& FTR value
Bid Screen &
Mitigation
Hour-ahead market
A/S Market
Real time &
Balancing market
LMP prices
10 min LMP & Security
Constrained Dispatch
*The difference between MD02 model and SMD is that CAISO model has an additional hour-ahead market.
Day-ahead Market
The ISO proposes to use a fully accurate model of the ISO transmission grid to adjust generation
and load (and import and export) schedules to mitigate transmission overloads, ensure local
reliability and, in the process, produce locational marginal energy prices at each node of the grid.
With this change the ISO will eliminate the distinction between inter-zonal and intra-zonal
congestion and will accommodate commercial energy trading at a few key trading hubs. Under
the proposal, the ISO would evaluate whether day-ahead schedules include enough on-line
resources to meet the next day’s demand forecast, and if not, the ISO would be able to commit
additional units.
Hour-ahead Market
Market participants in California have expressed a need to move the hour-ahead market closer to
real time, to enable late energy trades and schedule changes to shape supplies as accurately as
possible to meet demand. The ISO is considering a simplified hour-ahead market that would
perform congestion management and energy trading, and would close to submissions perhaps as
late as 60 minutes before the start of the operating hour. This change would also satisfy a
45
longstanding demand by many parties for a 60-minute dispatch market, since real-time energy
bids submitted to the hour-ahead market could be matched against load bids for the next hour or
pre-dispatched by the ISO for imbalance energy.
Real-time Market
Every 10 minutes during each operating hour the ISO would run a security-constrained economic
dispatch program to determine which resources to dispatch at what operating levels to meet real
time needs. This approach would meet the ISO’s operating needs most accurately and efficiently
by fully taking into account all transmission constraints, local reliability needs, and generator
operating constraints, as well as system imbalance energy needs. This approach would produce
nodal real-time energy prices, which would be paid to supply resources but could be aggregated
to larger geographic areas for settling imbalance energy purchases by load serving entities.
Ancillary Services Markets
The ISO proposes to perform ancillary services procurement simultaneously with day-ahead
congestion management and the energy market to obtain Operating Reserves and Regulation.
The proposed MD02 will allow the ISO to eliminate Replacement Reserves.
Firm Transmission Rights
Firm Transmission Rights (FTRs) are financial instruments that allow participants to hedge the
risk of congestion charges. With the changes to congestion management under MD02, the ISO
will need to change the design of its FTRs from the current path-specific variety to a point-topoint design that specifies explicit generator and load locations without explicit reference to the
network pathways affected.
Price Cap and Automated Mitigation Plan
To mitigate excessive market power abuse, the ISO proposes a Damage Control Bid Cap
(DCBC) that will limit the maximum bid allowed in the ISO’s energy and ancillary services
capacity markets. Beginning on October 1, 2002 and until market conditions are competitive
enough to support a higher DCBC, the ISO proposes to set the DCBC at two times the estimated
variable cost of a gas-fired generating unit with an incremental heat rate of 20,000 or
$250/MWh, whichever is greater. The ISO plans to increase the level of the DCBC over time as
the structural elements necessary to support a competitive market improve, and it believes that
the DCBC could eventually be increased to $1,000/MWh, which is the bid cap level currently in
place in the Northeastern ISOs.
Also beginning on October 1, the ISO proposes to implement individual resource bid screens and
mitigation procedures in the day-ahead Residual Unit Commitment process and in the real-time
pre-dispatch process that occurs 45 minutes prior to the start of the operating hour. This
mitigation element is similar to the Automatic Mitigation Procedures (AMP) utilized by NYISO,
but would have more stringent bid and impact threshold levels. The CAISO recommends that bid
reference levels be based on historical bids for all resources. The ISO further proposes a bid
threshold equal to the lower of a 100% increase from a resource’s reference level or $50/MWh,
and a market impact threshold equal to the lower of a 100% increase or an increase of $50/MWh
in the projected real-time market clearing price. This procedure would apply to all bidders in the
46
markets to which the procedure is applied. As the ISO gains experience with the bid screen and
mitigation procedures, and if the overall competitiveness of the ISO markets improves, the ISO
will consider raising the bid and price impact threshold levels.
The CAISO’s Comprehensive Market Design includes mitigation measures against local market
power in both the forward and the real-time markets. The forward market mitigation of
incremental bids that are needed out of economic merit order due to locational needs follows the
same logic and principles regardless of the granularity of the underlying network model used.
Regarding local market power in the decremental bid market, nodal pricing should provide a
natural mitigation in the first settlement market (i.e., the day-ahead). However, short of strict
activity rules (such as precluding bidders from submitting arbitrary decremental bids after the
close of the day ahead-market), local market power in the supply of decremental bids can emerge
in the subsequent markets, again regardless of the granularity of the underlying network model.
Such activity rules can be implemented when the ISO starts a forward energy market.
Available Capacity Obligation
The main purpose of the Available Capacity (ACAP) Obligation is to enable the ISO to verify in
advance that adequate capacity is available on a daily basis to meet system load and reserve
requirements. As proposed, the ACAP Obligation would support reliable system operations by
requiring LSEs to procure, in a forward-market timeframe, resources sufficient to satisfy the
ISO’s peak daily operating requirements. Moreover, by requiring that such ACAP resources are
made available to the ISO in the day-ahead market, the ISO can satisfy its objective of moving
operating decisions from real time into the forward market. Recognizing that ACAP is a new
element of the California energy market, and that it places new responsibilities and requirements
on certain entities, the ISO proposes to transition over a four-year period to full ACAP
implementation.
7. Midwest Independent System Operator Market
The Midwest Independent System Operator (MISO or Midwest ISO) was formed in 1996 as a
voluntary association of electric transmission owners in the Midwest.19 On December 20, 2001,
MISO became the first FERC-approved RTO in the nation. MISO controls more than 100,000
miles of transmission lines and more than 100,000 megawatts of electric generation over
approximately 1.1 million square miles from Manitoba, Canada to Kentucky.
In 2003, MISO will implement a market that is a hybrid of FERC’s SMD NOPR. The MISO
approach will build upon existing LMP approaches for real time balancing, congestion
mitigation, and settlement. It will include Financial Transmission Rights (FTRs) for hedging
congestion costs. MISO’s market includes a day-ahead energy market, an hour-ahead scheduling
model, a real-time energy market, a daily security capacity assessment, and an auction market of
FTRs that are a combination of point-to-point and flow-gate rights. Both the day-ahead energy
market and the real-time energy market utilize locational marginal pricing that reflects
transmission constraints and losses.
19
Information sources for this section include (1) Midwest Transmission System Operator, “MISO Day-ahead and
Real-time Market Rules,” September 30, 2002, Draft Version 4; and (2) Midwest Transmission System Operator,
“MISO Long-term Market Design and Congestion Management Straw Proposal,” November 29, 2001, Draft Rev. 3.
47
Figure 9: MISO Model
FTR Auction
Markets
Price sensitive
Demand Bids
Daily Capacity
Assessment
Day-ahead Energy
& A/S Market
(Virtual bids)
LMP Prices
FTR value
$1000/MWh
Bila
teral
cont
ract
Hour-ahead
schedule model
C
P
A
AMP
Real-time Energy
& A/S Market
LMP &
Dispatch
Day-ahead Market
The Day-ahead Market is a forward market in which hourly clearing prices are calculated for
each hour of the next operating day based on Generation Offers, Demand Bids, Virtual Supply
Offers, Virtual Demand Bids and bilateral transaction schedules submitted into the Day-ahead
Market. The day-ahead scheduling process will incorporate MISO reliability requirements and
reserve obligations into the analysis. MISO will also schedule additional generation in a
reliability commitment as needed to satisfy the MISO Load Forecast and maintain operating
reserves based on minimizing the cost to procure such reserves. Approximately six months after
implementation, MISO will also schedule Generation Resources based on economics to control
potential transmission limitations that are binding in the Transmission Reliability analysis that is
performed in parallel with and subsequent to the Day-ahead Market analysis. The resulting Dayahead hourly schedules and Day-ahead LMPs represent binding financial commitments to the
Market Participants. FTRs are accounted for at the Day-ahead LMP values.
The Day-ahead Market enables Market Participants to purchase and sell energy at binding dayahead prices. It also allows Transmission Customers to schedule bilateral transactions at binding
day-ahead congestion charges based on the differences in LMPs between the transaction source
and sink. Load Serving Entities (LSEs) may submit hourly demand schedules, including any
price-sensitive demand, for the amount of demand that they wish to lock-in at day-ahead prices.
Generators have the option to bid into the day-ahead market. Transmission Customers may
submit fixed, dispatchable20 or “up-to” congestion bid bilateral transaction schedules into the
20
Dispatchable transactions are supply offers by resources external to the MISO that are dispatched based on the
LMP at an external proxy bus or internal MISO bus.
48
Day-ahead Market and may specify whether they are willing to pay congestion charges or wish
to be curtailed if congestion occurs in the Day-ahead Market. All spot purchases and sales in the
Day-ahead Market are settled at the day-ahead prices. After the daily bid period for the Dayahead Market closes, the MISO will calculate the day-ahead schedule based on the bids, offers
and schedules submitted, based on least-cost, security-constrained dispatch for each hour of the
next operating day. The day-ahead scheduling process will incorporate MISO reliability
requirements and reserve obligations into the analysis. The resulting day-ahead hourly schedules
and day-ahead LMPs represent binding financial commitments to the Market Participants. FTRs
are accounted for at the day-ahead LMP values.
A market participant may adjust the schedule of a resource under its dispatch control (SelfScheduled Generation Resource) on an hour-to-hour basis beginning at 22:00 of the day before
the Operating Day under the following conditions:
•
Subject to the right of the MISO to schedule and dispatch Self-Scheduled Generation
Resources in an Emergency.
•
Provided that the MISO is notified not later than 30 minutes prior to the hour in which
the adjustment is to take effect in the case of a new schedule or 20 minutes for an
adjustment to an existing schedule.
Real-time Market
In the real-time energy market, the clearing prices are calculated every five minutes based on the
actual system operations security-constrained economic dispatch. Separate accounting
settlements are performed for each market. The day-ahead market settlement is based on
scheduled hourly quantities and on day-ahead hourly prices. The real-time settlement is based on
actual hourly (integrated) quantity deviations from day-ahead scheduled quantities and on realtime prices integrated over the hour. The day-ahead price calculations and the real-time price
calculations are based on LMP.
The Real-time Energy Market is based on actual real-time operations. Generators may alter their
offer prices between the Day-ahead and Real-time Energy Market for any Generation Resource
These revised offer prices would be used in the determination of real-time LMPs. Real-time
LMPs are calculated based on actual system operating conditions as described by the state
estimator. LSEs will pay Real-time LMPs for any demand that exceeds their day-ahead
scheduled quantities (and will receive revenue for demand deviations below their scheduled
quantities). Generators are paid real-time LMPs for any generation that exceeds their day-ahead
scheduled quantities (and will pay for generation deviations below their scheduled quantities).
Transmission Customers pay congestion charges based on real-time LMPs for bilateral
transaction quantity deviations from day-ahead schedules. All spot purchases and sales in the
real-time market are settled at the real-time LMPs.
8. Ontario Independent Electricity Market Operator Market
The Ontario Independent Electricity Market Operator (IMO) is a nonprofit corporate entity that
administers Ontario's wholesale electricity markets and manages the reliability of the high-
49
voltage power system.21 The IMO opened its wholesale and retail markets in May 2002.
Generating capacity is about 30,000 megawatts, and the system has dual seasonal peak demands
of about 25,000 MW (25,500 MW in 2002). In Ontario electricity is transmitted across 29,000
kilometers of high-voltage transmission lines to a population of approximately 10.8 million. The
IMO’s generating plants include a mix of nuclear, hydroelectric, coal, oil and natural gas-fired
stations.
The wholesale market design allows trading in a central pool, however Market Participants also
can purchase or sell energy through physical bilateral contracts. The wholesale market jointly
optimizes energy and operating reserve to produce a province-wide market clearing price (MCP)
every 5 minutes. At present there is no day-ahead market nor is there locational marginal
pricing, although both may be considered in the future. The IMO auctions financial transmission
rights (FTRs) with which Market Participants can hedge the congestion charges between Ontario
and each external zone.
Figure 10: Ontario IMO Model
FTR for
Interregional
Bilateral
contract
Financial Market
Under review
Capacity Market
under Planning
Hour-ahead
Predispatch &
A/S Market
Congestion
Profit
limit
MCPE, TCR
value &
Dispatch
Real-time
Balancing Market
Financial Markets
FTRs and energy forward markets constitute IMO’s two financial mechanisms. The
Transmission Rights Market supports the import and export of electricity on the interconnection
lines between Ontario and its surrounding markets in Manitoba, Quebec, New York, Michigan
and Minnesota. No decision has been made about a financial forward market, however, although
it is under discussion.
21
Sources for this section include (1) 2001 Annual Report, Ontario Independent Electricity Market Operator (IMO);
and (2) Electricity Retail Competition: A comparative analysis of markets in England/Wales, South East Australia,
Texas and Ontario October 2002.
50
Pre-Dispatch
Starting at 12:00 p.m. on the day before each dispatch day, and each hour up to one hour before
real time, the IMO runs a pre-scheduling program based on the bids and offers that it has
received. The program is used to provide market information by way of hourly updates, which
include expected hourly schedules and prices to all market participants.
The pre-dispatch program is primarily a forecasting tool that provides the IMO and market
participants with advance information and projections necessary to plan the physical operation of
the electricity system. If the pre-dispatch schedules indicate that the IMO needs more energy or
operating reserves to maintain the reliability of the grid, it may open the window to allow the
submission of additional bids and offers from resources that can be made available within the
time required.
Real-Time Market
Ontario’s real-time market is based on offers and bids for incremental energy. Every five
minutes the IMO dispatches generators and loads based on their bids and offers and determines a
single unconstrained MCP for Ontario. With a few exceptions, the five-minute MCP and
dispatch quantities are used for five-minute settlements with generators and loads. External
schedules are determined from an hour-ahead pre-dispatch program. They are settled at the fiveminute MCP, adjusted for an hourly congestion charge between Ontario and the external zone
that is calculated in the hour-ahead pre-dispatch. Supply offers and demand bids into the
Ontario real-time market can be modified without restriction until four hours before the real-time
dispatch. Four hours before the dispatch, the IMO imposes a 10% limit on the magnitude of
further price and/or quantity changes. Bids become firm two hours before real time, although
changes may be made if approved by the IMO.
Ancillary Services Market
The IMO administers three separate operating reserve markets: 10-minute synchronized reserve,
10-minute non-synchronized reserve and 30-minute non-synchronized reserve. Boundary
entities, dispatchable consumers and dispatchable generators may offer into the 10-minute nonsynchronized and 30-minute non-synchronized markets; however, only generators can offer into
the 10-minute synchronized reserve market. The IMO creates offer stacks for each of the three
operating reserve markets and then selects the necessary resources to meet requirements. The
accepted offers are essentially standby payments, as all accepted offers are paid regardless of
whether the reserve is actually used. Every five minutes, a market price is determined for each
applicable class of operating reserve in Ontario and for each of twelve inter-tie zones with
neighbor markets. The IMO also enters into Reliability Must-Run Contracts with specific
resources that are required to be available, or to be dispatched out-of-merit, to address local area
transmission constraints or voltage requirements. Other types of ancillary services such as black
start are arranged by contract.
Congestion Management
The IMO sells FTRs to help Market Participants hedge the congestion charge between Ontario
and each external zone. The hour-ahead pre-dispatch process determines an hourly Inter-tie
Congestion Price (ICP) that the IMO uses to settle external transactions for that hour. The ICP
51
for an inter-tie is the external zone price at the inter-tie point minus the Ontario uniform price in
the hour-ahead pre-dispatch program.
Generators, loads and occasionally boundary entities may be paid a Congestion Management
Settlement Credit (CMSC) funded by uplift. When there is transmission congestion, the IMO
may need to dispatch supply offers that are higher than the MCP. These suppliers will receive a
“constrained-on” payment to compensate them for the difference between the MCP and their
offer. Similarly, when there is transmission congestion, some generators will not be dispatched,
even though the MCP is greater than their supply offer. In order to provide the appropriate
incentive for these generators to stay off-line, they will be paid “constrained-off” payments equal
to the difference between their offer and the MCP. “Constrained-off” payments may also be
made to loads if the IMO accepts demand bids to manage congestion. The quantities subject to
constrained-on or -off payments are determined ex post based on the differences between the
quantities dispatched in the unconstrained model and the actual constrained system dispatch.
Price Cap
The price for energy and operating reserves is capped at $C2,000. Market power mitigation plans
for Ontario Power Generation (OPG), the dominant generator in the province, provides for a
rebate on roughly 70% of its domestic sales when the average annual price exceeds $C38 per
MWh. OPG may price as it sees fit in the market; there is no cap on its offers.
Capacity Reserve
In anticipation of market opening, more than 6,000 MW of new generation projects have been
proposed. Of this amount, 3,000 MW are scheduled to come on stream over the next 18 months.
Retail Competition
By September 1, 2002, over 1.1 million customers had contracted with retailers for electricity
supply, which equates to approximately 25% of all customers in Ontario. Customer billing has
generally been working well, however some customers have received bills for zero energy
consumption. Customer complaints have more than doubled with the introduction of retail
competition to around 500 per month. Problems have occurred primarily in relation to retailer
sales agent conduct, difficulty in making price comparisons between retailers, failure to cancel
contracts on request, and disagreements about contracts entered into with retailers.
9. Power Pool of Alberta Market
The electric market in Alberta, Canada was deregulated in 2001.22 Power generation is sold
through the Power Pool of Alberta’s spot market, Power Purchase Arrangements (PPA), bilateral
contracts, and forwards contracts. Alberta has 11,590 MW of installed generation capacity to
supply a peak demand of 7,934 MW. Coal-fired and natural gas generation plants account for
about 80% of Alberta's installed capacity, with the remainder mostly hydro. About 1% is wind
22
Sources for this section include (1) Participants Manual, Power Pool of Alberta, July 5, 2002; and (2) Pool Rules,
Power Pool of Alberta, Revised July 25, 2002.
52
power and biomass. An additional 750 MW of generation capacity will be brought on line by the
end of 2002.
The Power Pool of Alberta co-ordinates and monitors all aspects of Alberta’s electricity market:
real-time power sales, PPA, imports and exports. All energy is dispatch through the pool, which
has the responsibility to provide real-time control and to operate the system safely, reliably, and
economically. The pool is also responsible for coordinating the operation of the interconnected
provincial power grid with neighboring jurisdictions. Generation holders and PPA holders make
offers to the Power Pool of Alberta. The spot price is based on the weighted average of the
highest price paid for energy required to balance the supply and demand for the hour.
Energy prices have been dropping since the market opened. The market has a $1,000 /MWh bid
cap.
Figure 11: Power Pool of Alberta Model
Capacity Auction
Power Purchase
Arrangements
Bilateral
contract
Locational Incentives
for new generation
(IOBC – LBC-SO)
Day Ahead
Preliminary
MCPE A/S
Day-ahead
Schedule
(Real-time spot)
Balancing Energy
Market
Watt Exchange
Forward Markets
Financial Market
$1000/MWh
C
A
P
MCPE & A/S
Requirements and
System Dispatch
Financial Market
Forwards are traded on the Watt Exchange, a futures market that trades electric power financial
contracts for 1 month, 3 month and 1 year out.
Day-ahead Schedule model
The Pool dispatches the required generation, import offers and demand bids to serve the actual
system demand and exports. Generating companies and PPA holders place offers to supply
hourly blocks of energy at specific prices. Offers are submitted for a seven-day period and offer
prices for the first trading day can't be changed. Electricity purchasers place bids to buy blocks of
energy at specific prices. Bids, like offers, are placed for each hour of the next day and for the
following six trading days with prices fixed for the next day.
For the next-day schedule, market participants must supply a unit specific schedule by 16:00 the
day ahead. Shortly after unit specific schedule is submitted a preliminary market clearing price
53
for energy is posted. Bids submit marginal prices on an hourly basis. Bids and schedules may
be adjusted before real-time to represent the actual state of available resources. The Pool ranks
offers and bids from least expensive to most expensive, and publishes a schedule for the next
trading day.
Real Time Market
In the real-time spot market, generation or PPA holders make offers to the Power Pool of
Alberta. Balancing energy deployment is kept to a minimum without impacting system
reliability. The spot price is based on the weighted average of the highest price paid for energy
required to balance the supply and demand for the hour. All power producers receive the hourly
Pool Price for power generated and all purchasers pay the Pool Price for power received. This is
the MCPE that is published for the hour. The market has a $1,000 /MWh bid cap.
Ancillary Services Market
System services to the Power Pool that are competitively obtained by the Transmission
Administrator. They include reserve requirements, both spinning and non-spinning (power-up),
and interruptible load services.
Congestion Management
The Alberta market uses a zonal congestion model. Invitation Offer to Bid Credits (IOBC) and
Location Based Credits Standing Offers (LBS_SO) provide incentives to encourage generation
development in zones that would reduce congestion. At the present time, the Transmission
Administrator uses bilateral contracts to procure Transmission Must-Run services in the more
isolated northwestern part of Alberta. The Alberta Energy & Utilities Board is currently
reviewing congestion management in Alberta.
10. New Electricity Trading Arrangements Market of England and Wales
The Electricity Pool of England and Wales, which served as the market for electricity trading in
England and Wales since March 1990, was replaced in March 2001 by the New Energy Trading
Arrangements (NETA).23 The Office of Gas and Electricity Markets (Ofgem), which regulates
the UK’s electricity industry, says that wholesale competition has increased significantly under
NETA. Its extension to Scotland, called the British Electricity Trading and Transmission
Arrangements (BETTA), starts in 2004.
England and Wales had a customer base of 29 million in 2000, representing an estimated
population of 59.5 million. Demand peaked at 51,012 MW on January 16, 2001. Total
generating capacity in England and Wales in the winter of 2000/2001 was 67,695 MW, giving
the area a reserve margin of 33%.
23
Sources include (1) Report of the Gas and Electricity Markets Authority for the period 1 April 20-01 to 31 March
2002, Office of Gas and Electricity Markets, July 2002; (2) Review of the Current Status of Power, Market Reforms
in the U.S. and Europe EPRI Project Manager, H. Chao, Draft - June 14, 2002; and (3) Electricity Retail
Competition: A comparative analysis of markets in England/Wales, South East Australia, Texas and Ontario
October 2002; The section also contains information from the website: http://www.ofgem.gov.uk.
54
During the operation of the Electricity Pool of England and Wales, fuel use for power generation
changed dramatically. While nuclear energy fluctuated between 21% and 29% of the total and
hydro held steady at a low level (less than 1%), the use of coal for power generation decreased
substantially – from 65% down to 36% – while oil decreased from 11% down to 2%. Natural gas
picked up the difference, rising from less than 1% in 1990 to more than 33% in 2000.
While it was in place, almost all electricity was bought and sold through the Electricity Pool of
England and Wales. In a 2001 report, however, Ofgem cited “fundamental weaknesses” of the
pool, including “wholesale electricity prices that had not fallen in line with reductions in
generators’ input costs; a lack of supply side pressure and demand side participation; and
inflexible governance arrangements that had prevented reform of the arrangements.”
Arrangements under the Electricity Pool also kept wholesale prices artificially high.
Figure 12: England and Wales NETA Model
98%
Bila
teral
cont
t
Options on capacity &
contracting balancing
& congestion
management services
Commodity
Energy Market
until Hour-ahead
3.5 Hour-ahead
schedule & A/S
2% Real-time
Balancing Market
NYMEX
Prices
Balancing
offers and bids
Dispatch
Firm Rights
Contract
£99/MWh
C
P
A
Under NETA, almost all electricity is bought and sold like any other commodity, by contracting
between willing buyers and sellers in over-the-counter (OTC) markets or in power exchanges. A
small amount of sales, about two percent, are made in the Balancing Mechanism, the tool that
National Grid Company (NGC) has as system operator to ensure that supply and demand match
on a second-by-second basis.
Active Financial Forward Markets
NETA was designed to allow a variety of markets to evolve, including bulk OTC trading,
standardized products, power exchange trades, options/swaps, other financial instruments, and
spot markets. The terms for these markets can range from several years to within the day.
Soon after NETA introduction, over-the-counter (OTC) power trading increased significantly.
The OM London Exchange established the UK Power Exchange (UKPX) and launched an
electricity futures market. Nine months later, as NETA was launched and the Electricity Pool
ceased operations, the UKPX added a spot market in which spot contracts for half-hour periods
are opened two days ahead and close one half hour before gate closure. At the same time, two
55
other independent power exchanges began operations: the UK Automated Power Exchange
(APX UK) opened a spot market, and the International Petroleum Exchange launched a futures
market.
Hour-ahead Schedule
In the balancing mechanism, by 11:00 am on the day before trading, market participants are
required to notify NGC of expected operating levels throughout the whole day for each half hour.
Notification is made by submitting “initial physical notifications” (IPNs). NGC uses these IPNs
to assess the potential needs of the power system. Load-service entities must declare their
positions by making Physical Notifications, up to 3.5 hours before physical delivery. NGC
purchases long-term options on capacity and purchases balancing services under long-term
contracts – in each case using open and competitive procedures.
Real-time Operation
NGC then works to ensure that the "lights stay on" – generation equals load and the system is
operating within security limits. NGC purchases long-term options on capacity and to purchase
balancing services via long-term contracts – in each case via open and competitive procedures. It
handles the provision of ancillary services (i.e., reactive power, hot standby, frequency control,
and black start capability) as part of the balancing mechanism. Under its performance-based rate
structure (PBR), NGC has a financial incentive to intervene in energy markets and to discipline
market participants by acting as a countervailing power to the monopoly power of some
generators.
An important motive for switching to the NETA design was to improve opportunities for risk
management. Private bilateral contracts (especially ones of long duration) have largely replaced
reliance on volatile market-clearing spot prices in a central pool. The expanded role of long-term
contracts is attracting new generation companies and increased investment in new generating
plants.
Transmission System Operation
The costs of operations, reserves, ancillary services, and congestion management incurred by
NGC are ultimately charged to users through simple postage-stamp usage charges for each of
several zones. The PBR incentives reward NGC for reducing these costs, subject to requirements
for a percentage of annual improvement in efficiency. Under NETA, NGC initially absorbs the
costs of grid operations, including losses, options on reserves and ancillary services purchased in
advance, and balancing and congestion management services purchased in its real-time
imbalance market.
Final proposals were put forward in February 2002 for enhancing existing system operator
incentives that will encourage NGC to operate the electricity transmission system more
efficiently and economically. Under Ofgem’s final proposals, NGC was given a single cost target
of £460 million for one year. Under the new scheme, NGC stands to gain greater financial
rewards if it reduces its costs below that target but faces penalties if the costs exceed the target.
56
Market Power Mitigation
Ofgem has enforcement powers as a regulator and as a Competition Authority. In addition,
Ofgem can publicize instances of bad behavior towards customers by the companies it regulates.
Ofgem may also use consumer protection powers, which it exercises concurrently with the
Office of Fair Trading (OFT). Specific powers include: license enforcement action, financial
penalties, ‘stop now’ orders when a company contravenes consumer legislation, and the power to
revoke a license granted under the Electricity Act 1989 or the Gas Act 1986.
Different Philosophy of Market Design
The UK’s adoption of NETA goes against current trends in the US, which are moving away from
the Nord Pool model and towards a single pool for energy trading based on centralized unit
commitment and dispatch of generators and locational marginal pricing. NETA presumes that
private markets are sufficient for efficient energy trading and that generator self-scheduling is
conducive to system operation efficiency assuming generators can hedge their financial risks.
NETA is designed to improve opportunities for risk management via private bilateral contracts
(especially ones of long duration) as opposed to a central pool where market-clearing spot prices
may be volatile. Long-term contracts could affect new generation companies and increase
investment in new generating plants.
2001 Annual Report of the Office of Gas and Electricity Markets24
• Successful operation, with greater competition and falling wholesale prices.
•
A combination of factors, including increased competition in generation, over capacity
and NETA, have seen wholesale prices fall by 40% since 1998, when the reform program
began. From April 2001 to February 2002 base-load prices have fallen by 19% and peak
prices by 27%.
•
Work progressed with smaller generators and demand-side participants to improve the
way they operate under NETA.
•
Progress made towards creating British-wide wholesale electricity trading & transmission
arrangements.
•
Reforms to electricity transmission network arrangements proposed to enhance long-term
security of supply and reduce losses on system.
•
New incentive arrangements introduced for National Grid Company (NGC) to operate
system more efficiently and economically.
24
Summary of Report of the Gas and Electricity Markets Authority for the period 1 April 20-01 to 31 March 2002,
Office of Gas and Electricity Markets, July 2002
57
Performance Benchmark Measurement
Average energy price, or fuel-adjusted load-weighted average price
Greater competition and a generator capacity margin saw prices fall by some 18% since NETA
began and by 40% since reforms were proposed in 1998.
In the past 12 months, liquidity in forward markets has increased by 150%. New NETA
governance arrangements have worked well to allow for adjustments to be made quickly as
issues arose. The NETA systems also proved robust when faced with the collapse of Enron, the
world’s largest energy trader, only nine months after NETA became operational.
These factors led to a significant reduction in price volatility. For instance, the difference
between the prices at which participants have to buy and sell electricity from NGC to balance
their positions fell from £70 per MWh at the time NETA became operational, to £17 per MWh
today.
Ancillary services prices
The NETA design presumes that the system operator should conduct a day-ahead optimization of
unit commitments and schedules to minimize the total cost of generation sufficient to meet the
predicted load plus sufficient reserves for ancillary services. NGC conducts short term demand
forecasting and procures ancillary services through long-term bilateral contracts, options on
reserves and ancillary services purchased in advance, and competitive bids.
Congestion costs, percentage and trend
In the UK, congestion is less prevalent than the US. For the first time, generators and shippers
will have firm rights, in the form of long-term contracts with NGC, to the transmission network.
These rights will provide NGC with better signals about when and where to invest in the
network. In addition, NGC has financial incentives to respond efficiently to these signals.
Market power abuse investigation and mitigation
The evidence over NETA’s first year that prices and price volatility have declined gives support
to the view that reliance on long-term contracting diminishes market power, and recently there
has been no evident abuse of market power, nor any significant abuse of procedural rules of the
market. The previous system was plagued with such abuses.
Ofgem devotes considerable resource to compliance and enforcement. For example, it monitors
daily prices and trends in the competitive wholesale markets as well as carrying out specific
investigations. An investigation was launched in October 2000 after system constraints forced
the repurchase of significant amounts of entry capacity from companies, often at very high
prices. It also addressed concerns about companies being involved in anti-competitive behavior
that could harm customers. As a result of the investigation, Ofgem concluded that all of the
companies investigated were able to provide satisfactory explanations for their conduct.
Operation inefficiency
Under Ofgem’s final proposals, NGC was set a single cost target of £460 million for one year.
Under the new scheme, NGC stands to gain greater financial rewards if it reduces its costs below
that target but faces penalties if the costs exceed the target.
58
Retail competition (switching rate) and load participation (energy) rate
During the year, some demand-side participants, typically large industrial customers who find it
more profitable to sell their electricity than use it, began to actively participate in balancing
energy services.
About 37% of domestic gas and 38% of domestic electricity customers have exercised their
choice to switch providers. Switching rates are higher than in many other competitive markets in
Britain and higher than achieved in any gas and electricity market anywhere else in the world.
All told, 15 million customers have switched suppliers – a level of switching second only to car
insurance.
New entry and capacity construction percentage
Installed capacity of the major power producers in the U.K. increased from about 64,000 MW in
1993 to 72,500 MW in 2000, which is an increase of 13% (1.8% on an annual basis). In the last
four years alone, the capacity of all generating companies in the U.K. has increased from 73,200
MW to 78,900 MW, which is an increase of 8% (1.8% annual). Overall, annual investment in the
electricity industry in the U.K. has fluctuated between £2 billion and £3 billion, adjusted to
constant 1995 dollars. From 1993 to 2000, power plant capacity of major power producers in
combined cycle gas turbines increase from about 1,400 MW to about 20,000 MW.
NETA was designed to improve electric competition by substantially altering the incentives of
market participants. The new structure encourages long-term contracting and hedging in private
markets, and has attracted entry and new investments. The first year operation shows that the
market for long-term contracts has expanded quickly and appears to be providing investors with
much improved opportunities for hedging. On the other hand, the overall price reduction may
send an adverse signal to hesitate the investment intention of investors.
Potential Areas of Improvements in UK NETA Market:
1. The major deficiency of NETA after the first year appears to be a dramatic decline in
energy from CHP units and a possible exit of investors from this sector. Ofgem had
targeted a 100% increase in CHP generation.
2. Attempts by Ofgem to introduce a Code of Behavior for market participants have failed,
although abusive behaviors such as the DEC game have not been significant problems in
the UK since NETA began.
3. The smaller generators’ report, which was published in August 2001, said that one of the
main obstacles preventing them from participating in NETA is the difficulty they face in
using consolidation services that allow smaller generators to aggregate their output to sell
it more competitively.
59
11. Nordic Power Exchange Market
Nord Pool ASA, the Nordic Power Exchange, is the world’s first multinational exchange for
trade in electric power contracts.25 Nordel is a cooperative body made up of the transmission
system operators (TSOs) in the Nordic countries (Denmark, Finland, Iceland, Norway, and
Sweden). The objective of the organization is to “create the conditions for, and to develop
further, an efficient and harmonized Nordic electricity market.”
The population of Norway, Sweden, Finland, and Denmark totals about 24 million, which is
about the same size as the PJM service territory (23 million) but significantly less than the
population of California (34 million). Yet these four countries consumed about 392 TWh of
electricity in 2000, compared to 262 TWh and 264 TWh in PJM and California, respectively.
Electric power production in Norway is almost 100% hydropower. Sweden and Finland use
hydropower, nuclear and fossil-fuel-powered generation plants. Over 90% of Denmark’s
electricity come from conventional thermal plants and combined heating and power (CHP)
facilities. The table below shows the generating capacity in the four countries that make up the
Nordic Power Exchange area served by Nord Pool. The table entry for Danish renewable power
sources represents wind power.
Table 11: Installed Generating Capacity in Nord Pool
Generation 2001 (TWh)
Sweden
Norway
Finland
Denmark
Total
Hydro
78.5
121
13
212.5
Thermal
10
1
36
32
79
Nuclear
69
Renewable
0.5
22
91
4
4.5
Total
158
122
71
36
387
Nord Pool operates the following marketplaces and market services:
•
A financial derivatives market –futures, forward, and option contracts (Eltermin,
Eloptions)
•
A day-ahead spot market for physical contracts (Elspot)
•
An hour-ahead spot market for physical contracts (Elbas)
•
Contracts for difference
•
Clearing services for financial electricity contracts – Nordic Electricity Clearing House
ASA (NECH)
25
Information in this section is based on (1) 2001 Annual Product Report of The Nordic Power Market; (2) Draft by
Bob Wilson, 5/6/02, revised 5/7/02 for Review of the Current Status of Power Market Reforms in the U.S. and
Europe; and (3) Review of the Current Status of Power, Market Reforms in the U.S. and Europe EPRI Project
Manager, H. Chao, Draft - June 14, 2002. The section also contains information from the website:
http://www.nordpool.com/.
60
•
The real-time market to serve as a tool for system operators to balance generation with
load at any time during real-time operations, and to provide a price for participants’
power imbalances.
Figure 13: NORD Pool Model
71%
NECH
Clearing
Services
OTC,
Bilateral
contracts
Financial Derivatives
Market (Eltermin/
CfD/Eloptions)
Contract for
Difference (CfD)
Day-ahead
Energy Market
(Elspot)
Day-ahead
Zonal MCPEs
Hour-ahead Energy
Market (Elbas)
Real-time
Regulation Market
Hour-ahead
Zonal MCPEs
Zonal Regulation
MCPE
Active Financial Forward Markets
The futures and forward markets are the financial markets for price hedging and risk
management. Through power derivatives traded at the Nordic Power Exchange, Exchange
Members can hedge purchases and sales of power with a time horizon of up to four years. Nord
Pool’s financial market operates in general competition with the bilateral market. Futures and
forward contracts are traded continuously, much as in other commodity markets. The financial
market at the Nordic Power Exchange has an electronic trading system. Most Exchange
Members are connected to the trading system and do their trading online. Others communicate
their bids by telephone to Nord Pool and trade via the Exchange’s help desk. All Exchange
Members receive real-time market information throughout the daily trading period, Nord Pool’s
electronic trading system and real-time information distributors.
Financial electricity contracts traded at the Nordic Power Exchange are standardized products
that are financially settled. There is no physical delivery of electric power. Settlement is
conducted between NECH’s clearing service and individual members.
Futures contracts consist of standardized day, week, and block contracts. As due dates approach,
blocks are split into week contracts, and week contacts are split into daily contracts. Product
specifications detail the timing of the splits and other contract features.
61
Forward contracts consist of year and season contracts. There is no splitting of forward contracts,
which are standardized in conformity with most Nordic OTC and bilateral market trade. NECH
clears all contracts traded on the Nordic Power Exchange and a substantial proportion of
financial contracts traded in the Nordic OTC and bilateral power markets. The total value of all
contracts cleared through Nord Pool has grown from NOK 40 billion in 1997 to NOK 124 billion
in 1999 and NOK 177 billion in 2000. The 1,634 TWh of total clearing volume in 2000 is more
than four times the electricity consumed in the four countries in that year.
Options were introduced as tradable products at the Nordic Power Exchange in late 1999. They
were launched to satisfy market demand, and represent an important element in the expanded
product line of the Nordic Power Exchange. Options, combined with futures or forward
positions, offer valuable strategies for managing power market risk.
The main features of options contracts traded at Nord Pool are:
•
The option contracts can only be exercised at the exercise date, which is stated in the
product specifications.
•
The option premium is quoted in Norwegian kroner (NOK) per MWh; premiums are
payable the following clearing day.
•
The energy-size of an option contract is the number of MW multiplied by the number of
hours in the underlying forward contract.
•
Upon listing of a new option, initial exercise (strike) prices are set by Nord Pool,
according to the price of the underlying instrument. Initially five strike prices are listed
•
New strike prices are automatically generated to reflect price movements of the
underlying forward instrument.
•
Strike price intervals depend on the price of the underlying forward instrument.
Options can be traded directly via Nord Pool’s electronic trading system or via Nord Pool’s help
desk. All combination strategies are conducted via the help desk.
Market participants that use financial market derivatives to hedge spot market prices remain
exposed to the risk that the System Price will differ from the actual area price of their spot
purchases or sales. To overcome this potential price differential risk, a new forward contract
product – Contracts for Difference (CfD) – was introduced for trading on the Nordic Power
Exchange in November 2000.
The System Price is the reference price for forward and futures contracts traded at the Nordic
Power Exchange, as well as non-exchange contracts. Nevertheless, the actual price paid for spot
market physical procurement is determined by actual area prices. The spot System Price is
identical to individual spot area prices only when there is no transmission grid congestion
(capacity bottlenecks) between spot bidding areas. Different spot area prices are established so
that price mechanisms relieve grid bottlenecks.
CfDs allow market participants to create a perfect hedge of a physical contract, even when the
market is split into price areas, by following a three-step process:
•
Hedge the System price with trade in forward contracts for the required volume.
62
•
Hedge any price differential between a particular area price and System Price by trade in
CfDs for the same period and volume.
•
Accomplish physical procurement of the contract volume in the spot market.
In addition to clearing all contracts traded on the Nordic Power Exchange, NECH clears
financially settled electricity contracts traded on Nordic OTC and bilateral markets. These
markets have a high level of activity, and NECH currently clears a substantial proportion of the
standardized financial contracts traded on them.
Day-ahead Market
Although most forward trading consists of bilateral contracts for physical delivery, Nord Pool’s
Elspot market also provides a day-ahead market. In this market, each participant submits a
supply or demand schedule for each hour of the next day. Then a tentative market-clearing price
is established on the assumption that there will be no inter-zonal congestion. If this assumption is
revealed to be false, then prices in the zones within Norway are adjusted to eliminate
congestion—for example, the price in an importing zone is raised and the price in an exporting
zone is decreased. Each participant is paid or receives the resulting price for its injections or
withdrawals within each zone. Elspot acts as the counterparty to each transaction. Trading is
based on an auction trade system. The spot concept is based on bids for purchase and sale of
power contracts of one-hour duration that cover all 24 hours of the next day. The market clearing
price or system price for a particular hour is first calculated using only the bids for purchase and
sale that participants have submitted. To do this, all purchase bids are summed to create a
demand curve, and all sales bids are summed to create a supply curve. The point where the two
curves intersect determines the system price for that hour.
Hour-ahead Market
The day-ahead physical market aspects of Elbas allow its market participants to trade one-hour
spot contracts after the Nordic Power Exchange’s Elspot market results are published (at noon)
to bids for next-day deliveries. Recent Elbas changes permit hour-ahead trading. (Previously the
gap was two hours before the closest delivery hour.
Real-time Market
Bids in the real-time market are submitted to a transmission system operator (TSO) after the spot
market has closed. Bids may be posted or changed close to the operational time, in accordance
with agreed rules. Real-time market bids are for upward regulation (increased generation or
reduced consumption) and downward regulation (decreased generation or increased
consumption). Both demand-side and supply-side bids are posted, stating prices and volumes.
Real-time markets are organized by TSOs; market participants must be able to commit
significant power volumes on short notice. TSOs list bids for each hour in priority order,
according to price. TSOs use the priority-ordered lists for each hour to balance the power system,
as needed. To resolve a grid power deficit, upward regulation is applied: the real-time market
price is set at the highest price of the units called upon from the priority listing. Similarly, in a
grid power surplus situation, downward regulation is applied: the lowest price of the units called
upon from the list sets the real-time price.
63
The specific rules for determining the hourly price of power imbalances, based on the real-time
market price, differs among the Nordic TSOs. Nevertheless, an imbalance always carries the risk
of a financial loss.
Ancillary Services Market
In Scandinavia, Nord Pool allocates to each member country the required amounts of regulation
and reserves, each of which contracts separately for these services. This practice ensures that
each control area contributes its fair share to maintain reliability of the system.
Zonal Congestion Management
The Nordic market is partitioned into separate bidding zones that can become separate price
areas if the contractual flow between bidding areas exceeds the capacity allocated by
transmission system operators (TSOs) for spot contracts. If there are no such capacity
constraints, the spot system price is also the spot price throughout the entire Nordic Power
Exchange area. If contractual flow exceeds a grid capacity limit, two or more zonal prices,
referred to as area prices, are calculated for each affected spot market delivery hour. Once spot
market prices and volumes are determined, the market is in balance according to predicted
generation and loads.
Within Norway, congestion is relieved by using various area prices (i.e., zonal price methods).
Within Sweden, Finland, and Denmark, grid congestion is managed by “counter-trade,” based on
bids from generators. Grid congestion that occurs in real time is managed by Nordic transmission
system operators, by calling on bids in the real-time market. Congestion can occur within a
Nordic country or between Nordic countries. For congestion that occurs between Nordic
countries, area prices are defined in various geographical bidding areas, and a new round of
Elspot calculations is conducted. In an iterative process, area prices are reduced or increased
until the power flow is altered to eliminate congestion. (Nord Pool, August 25, 2001) Six area
prices are typically defined: two for Norway, two for Denmark, one for Sweden, and one for
Finland. Nord Pool’s zones are adapted daily to recurring patterns of congestion.
Nord Pool eliminates congestion day-ahead only on the interfaces between major zones and
therefore imposes day-ahead usage charges only for transmission across these main interfaces.
This means that no charges are imposed day-ahead for intrazonal congestion.
Summary of Nordic Power Market 2001 Annual Report
The spot market’s traded volume in 2001 was 111 TWh, doubled Nord Pool’s spot market
volume in 1996. This growth was largely due to extension of the liberalized power market to
Sweden. Total annual Nordic consumption is about 380 TWh. Accordingly, some 29% of all
Nordic physical-delivery power was traded via the Nordic Power Exchange in 2001.
The marketplace for financially settled electricity contracts at the Nordic Power Exchange trades
futures, forward, and option contracts. The volume of financial contracts traded in 2001 was 910
TWh. Financial market traded volumes have increased substantially in recent years, more than
150% from 2000 until 2001. The market share of all cleared contracts is about 35%.
64
In 2001, a traded volume of 1,748 TWh from the OTC/bilateral market was reported to NECH
for clearing. NECH clears roughly 80% of financial electricity contracts traded in Nordic OTC
and bilateral markets. The remaining 20% is settled directly between the contractual parties.
Based on the above data for 2001, projections of the overall size of the Nordic market for
financial power contracts range from 2,600 TWh to 3,500 TWh, about seven to nine times total
Nordic annual generation or consumption of electricity. Similar characteristics are observed in
other commodity markets.
Market Review Summary26
Ample hydro resources obviate many of the operational problems faced by systems that depend
on thermal generation, and market power is a minor concern in Norway.
The mainly financial role of forward markets provides a means of risk management, and
therefore the prospect that energy trading might rely on bilateral contracting, only a minor
fraction of which is conducted in exchanges using standard contracts.
12. National Electricity Market of Australia
The National Electricity Market (NEM) of Australia began operation on December 13, 1998, as
part of the Australian power industry shift to deregulation.27 The NEM supplies electricity to 7.7
million Australian customers on an interconnected national grid that runs through five zones:
Queensland, New South Wales, the Australian Capital Territory, Victoria and South Australia.
Each region has a reference node where the Regional Reference Price (RRP), or regional spot
price is set. The regional reference node may be a major load center such as a city, or a major
generation center, such as the power plants in the Snowy region. Approximately $8 billion of
energy is traded through the NEM per year.
Wholesale trading in electricity is conducted as a spot market. The spot market allows
instantaneous matching of supply against demand. The National Electricity Market Management
Company Limited (NEMMCO) operates a wholesale market for trading electricity between
generators and electricity retailers in the NEM.
Under the NEM, regulation of transmission and interconnector assets moved from state
governments to the Australian Competition and Consumer Commission (ACCC). Regulated
interconnectors and transmission networks in general receive a fixed rate of return that takes into
account the value of their asset base. The amount of this return is determined by the ACCC and
reviewed every three-five years. Unregulated or entrepreneurial interconnectors (or merchant
links), however, rely on trading [the arbitrage between the RRP’s of the two interconnected
regions] in the wholesale market to derive their revenue. Unlike regulated interconnectors, they
may also enter into financial contracts, which are not part of the wholesale market arrangements.
26
Draft by Bob Wilson, 5/6/02, revised 5/7/02 for Review of the Current Status of Power Market Reforms in the
U.S. and Europe.
27
Information for this section was taken from (1) Australia National Electricity Code Administrator Limited Annual
Report 2000-01; and (2) Assessment of the market’s performance during summer 2000-01, National Electricity
Code Administration Limited (NECA). The section also contains information from the website:
http://www.neca.com.au/files/necacode/; and http://www.nemmco.com.au/operating/operating.htm.
65
Figure 14: Australia NEM
Settlement Residue
Auctions (SRAs)
Load
Participation
Capacity Market
(under-review)
US$5263/M
Value of lost load
Financ
ial
Bilater
al
Hedge
Day-ahead predispatch
Forecasted Spot
& A/S prices
Real time energy
market (100%)
Zonal MCPE
prices & SRA
c
a
p
Intervention
Price
A/S Service
dispatch algorithm
Financial Contracts
A Financial (Hedge) Contract is a financial instrument to manage the risk created by price
volatility in the market. Buyers and sellers of electricity may enter into long or short-term
contracts that set an agreed price for electricity outside the spot market and the involvement of
NEMMCO. Hedge contracts do not affect the operation of the power system in balancing supply
and demand in the pool and are not regulated under the Code.
The basic form of contract may be a bilateral hedge where two parties agree to exchange cash
against the spot price. In a two-way hedge contract, generators pay retailers the premium price
when the spot price is above the contracted price. If the spot price is below the contracted price,
retailers pay generators the amount of the discount. A one-way hedge contract manages the risk
of high pool prices while allowing wholesale buyers to take advantage of low prices. When the
pool price exceeds a certain level, generators pay retailers the difference between the pool price
and an agreed amount for the contracted amount of electricity.
Day-ahead Schedule – Predispatch
Predispatch is a short-term forecast of market activities used to estimate price, dispatch and
demand for the next trading day and energy flow across the interconnectors. Generators must
notify NEMMCO of the volume and price of electricity they are able to supply and NEMMCO
produces a demand forecast. This information is then collated to estimate total regional
capability, thereby enabling NEMMCO to assess potential supply shortages. Generators can
change their bids or submit re-bids according to a set of bidding rules. Only the availability
details can be changed in a re-bid; price cannot be changed.
66
Real-time Market
All the electricity output from generators is pooled and all electricity must be traded through the
spot market. NEMMCO calculates the spot price using the price offers and bids for each halfhour period during the trading day. The spot market is set and then settled by a centrallycoordinated dispatch process. Dispatch instructions are sent to each generator at five-minute
intervals. Prices are calculated for dispatch intervals in each region. The dispatch prices
calculated during each half-hour period are average to determine the spot price. This spot price is
used as the basis for billing participants within the NEM for all energy traded. Generators are
paid for the electricity they sell to the pool, and retailers and wholesale end-users pay for the
electricity they use from the pool.
Generators offer to supply the market with different amounts of energy at particular prices. From
all offers submitted, NEMMCO selects the generators required to produce power and at what
times throughout the day based on the most cost-efficient supply solution to meet specific
demand. Generators can change their bids or submit re-bids according to a set of bidding rules.
Inter-Regional Settlement Residue
The difference between the price of energy generated in one region and the price of that energy
once it has been transmitted to another is called the Inter-Regional Settlement Residue (IRSR).
The Settlement Residue Auctions (SRAs) are intended to improve the efficiency of the NEM by
promoting inter-regional trade. Only registered generators, market customers and traders are able
to participate in the SRA.
Ancillary Services Market
NEMMCO acquires some ancillary services under agreements. The prices for these non-market
ancillary services are determined in accordance with the relevant ancillary services agreements.
Other ancillary services are acquired by NEMMCO on the spot market. The prices for market
ancillary services are determined using the dispatch algorithm. The new frequency control
ancillary services market arrangements were implemented in September 2001.
Capacity Reserve
An intervention threshold capacity reserve (above a demand forecast with a 10% probability of
being exceeded) has been calculated by NEMMCO to achieve the minimum reliability standard.
Reserve levels in regions other than where the minimum is found have been calculated to
maintain a consistent market price signal to reserve capacity.
Price Cap and Market Power Mitigation
A price cap is automatically triggered when NEMMCO directs generation into the market or
when it directs Network Service Providers (NSPs) to interrupt customer supply in order to regain
a supply-demand balance. In this situation the spot price is referred to as the "Value of the Lost
Load." Until March 31, 2002, the cap was AU$5,000/MWh; as of April 1, 2002, it was
AU$10,000/MWh, subject to an annual review by the Reliability Panel. The market floor price,
which is applied to dispatch prices, is AU$-1,000/MWh.
67
NEMMCO also monitors the future adequacy of generating capacity based on plant availability
information supplied by generators and on interconnector availability provided by network
service providers. Projected deliverable capacity is compared against forecast electricity
demand. Because demand for electricity supply fluctuates, both week-ahead and two-year
forecast projections are made. These projections are called Projected Assessments of System
Adequacy (PASA). PASA projections assist generator operators to plan maintenance and help
NEMMCO assess whether there are adequate reserves. Each year NEMMCO also publishes a
Statement of Opportunities (SOO) which predicts market trends for the following 10 years.
Load Participation
The demand-side participation code changes attempt to improve the attractiveness of registering
as a scheduled load by increasing the flexibility of a load seeking to switch between scheduled
and market load, and assisting market customers manage non-conformance of scheduled loads.
In central dispatch default dispatch bids may be used as a back-up bid in the absence of a
submitted daily dispatch bid, as well as being applied by NEMMCO to address issues of nonconformance for scheduled loads.
Australia National Electricity Code Administrator Limited Annual Report 2000-0128
• Demand increased in 2000-01 by 5,300GWh, or 3%. The largest regional increases were
in Queensland and South Australia. There was no involuntary load shedding as a result of
supply shortfalls, although for the first time there was clear evidence of direct demandside response to prices.
•
Summer 2000-01 saw the market put under extreme stress. This was reflected in spot
prices. Even taking the year overall, spot prices increased by a third in New South Wales
and almost doubled in Victoria. South Australia and Queensland, on the other hand, saw
reductions in spot prices: by almost 5% in South Australia and more than double that in
Queensland.
•
An investigation into the price effect of generators’ bidding and rebidding strategies
sought to tackle short-term price spikes and the small number of bids and rebids that do
not represent rational outcomes.
•
The introduction of new market rules to achieve the efficient, competitive and reliable
operation must be accompanied by stringent monitoring, surveillance and enforcement.
NEMMCO enhanced its surveillance and monitoring capability by establishing a highlevel expert advisory group to provide strategic input into refining analytical techniques
in the key areas of the competitive, economic and price performance of the market.
Performance Benchmark Measurement
Average energy price, or fuel adjusted load-weighted average energy price
The 12-month average spot market price in Queensland was $45/MWh in 2000-2001, a reduction
of 10% on the previous year. The average in South Australia was $66/MWh, a reduction of 4%
28
Australia National Electricity Code Administrator Limited Annual Report 2000-01
68
on the previous year. In Victoria, plant breakdown and industrial action in the September quarter
and further industrial trouble in November saw prices almost double to an average of $49/MWh.
Prices in New South Wales were up by a third to $41/MWh.
These generally higher prices were against the background of extreme summer weather. Average
maximum temperatures were higher than long-term averages throughout the summer across all
regions, significantly increasing the demand for electricity. As a result, peak total demand
increased significantly in all regions. For the first time, the national peak demand shifted from
winter to summer, with a record-setting 27,500 MW in January 2001. The market’s total energy
requirement increased by 5% over the Summer. Comparing weekday periods this Summer to
last, average demand increased 1,500 MW, while generators presented an additional 1,675MW
of capacity.
Summer spot prices in New South Wales and Victoria averaged $49/MWh and $69/MWh
respectively, compared to $33/MWh and $27/MWh last summer. Prices in South Australia
averaged $112/MWh compared to $85/MWh. Queensland’s summer average price was down to
$52/MWh, the lowest since market launch. The period of intervention or “what-if” pricing on 7
and 8 February affected average prices. Excluding these two days this summer, prices would
have averaged $44/MWh in New South Wales, $50/MWh in Victoria and $77/MWh in South
Australia.29
The spot price in Queensland peaked at $1,796/MWh on February 12 when a number of
constraints there and in New South Wales were violated following the loss of input data to the
dispatch process. Maximum prices of $4,755/MWh and $4,427/MWh occurred in South
Australia and Victoria respectively on February 7 during the period of intervention pricing. In
New South Wales a maximum price of $5,000/MWh occurred on January 15 when New South
Wales separated from Victoria and South Australia.
Spot market price spikes highlight the volatility, spread and magnitude of price in each region.
Spot prices were above $500/MWh for around 14 hours in Queensland and New South Wales,
for 29 hours in Victoria and for 43 hours in South Australia. The top 100 hours of prices in each
region averaged around $320/MWh in Queensland and New South Wales, $666/MWh in
Victoria and $1,047/MWh in South Australia.
Ancillary services prices
NEMMCO’s report on ancillary services was implemented as amended in the light of
consultation, for example, for frequency or voltage control, under contract to NEMMCO or
through competitive bidding under the new market based ancillary services arrangements. By
coordinating the review with the introduction of the new ancillary services arrangements, it has
the potential to reduce ancillary services costs by more than $10 million a year. This is over and
above the $50 million or more a year savings in those costs in Queensland as a result of
interconnection. Ancillary services costs reduced significantly following the interconnection.
29
Assessment of the market’s performance during summer 2000-01, National Electricity Code Administration
Limited (NECA)
69
Congestion costs, percentage & trend
The difference between the price of energy generated in one region and the price of that energy
once it has been transmitted to another is called the Inter-Regional Settlement Residue (IRSR).
By making the settlement residue available to the market place, the risks of trading between
regions can be better mandated.
The settlements residue auctions offer participants access to the residues that accumulate on
interregional trade. Total residues increased to $140 million compared to $114 million in 19992000. The proceeds of the settlement residue auctions totaled $64 million while $99 million of
residues were distributed.
Market power abuse investigation and mitigation
An investigation into market events that occurred between August 28 and September 1
underlined the need to strengthen Code provisions on rebidding. The inquiry also confirmed the
potential for bidding and rebidding strategies to have a significant impact on prices. Prohibiting
bids or rebids that prejudice the underlying objectives of the efficient, competitive and reliable
operation of the market will bring the Australian market into line with other major markets
worldwide in addressing market behavior directly within the market rules. The proposed
prohibition will give market rules real teeth in terms of outlawing specific abuses of the
otherwise essential flexibility represented by rebidding.
An investigation into the performance of the market during summer highlighted evidence for the
first time of direct demand-side response to prices.
Operation inefficiency
NECA’s budgets for 2001-02, and the two successive years, represent real reductions on 19992000. The market fees for 2001-02 have also fallen for the second successive year, and will
continue to fall. They represent less than 0.26¢/MWh.
Retail competition (switching rate) and load participation (energy) rate
Customer switching statistics recorded by NEMMCO as at 25 September 2002 show 346,746
completed transfers in NSW and 294,959 completed transfers in Victoria. There have been
problems with duplicate transfers per day where multiple requests relate to the same customer. In
October 2002, retail company Australia Gas & Light (AGL) announced a 25 per cent price
increase in residential tariffs. They estimate that this will add $237 a year to an average
household power bill from January 1, 2003. Generators and distributors in the market have
denied that the bulk of this is related to increases costs from them. ETSA Utilities have stated
that nominal distribution costs on their network have increased by about $35 for an average
household to cover a $50 million investment in software systems to interface with the NEM.
New entry and capacity construction percentage
Significant new investment has been undertaken, or is planned or projected. New generating
capacity totaling over 1,100MW came on stream during 2000-01. Another 10,000MW is planned
or projected for the future. The lead-times for new investment have also been dramatically
reduced. The planned new investment includes a number of prospective new merchant
transmission links.
70
Potential Areas of Improvements in Australia NEM Market
Identified in Australia National Electricity Code Administrator Limited Annual Report 2000-01:
1. An investigation into generators’ bidding and rebidding strategies and their effect on
prices sought to tackle the short-term price spikes and the minority of bids and rebids that
have no basis in the underlying dynamics of the market. Such irrational outcomes are
only made possible by the current incomplete state of development of the market and the
lack, therefore, of a fully competitive outcome.
2. The number of rebids submitted during the year was the same as in 1999-2000, despite a
20% increase over the summer period. There was also an emerging trend in the new year
towards greater price volatility in response to relatively small changes in demand,
especially in Victoria, as some participants’ bidding strategies priced all capacity at either
very low or very high prices, significantly changing the supply characteristics.
3. There was also an emerging trend towards greater price volatility in response to relatively
small changes in demand, especially in Victoria, as some participants. Bidding strategies
priced all capacity at either very low or very high prices, significantly changing the
supply characteristics.
13. New Zealand Electricity Market
The New Zealand Electricity Market (NZEM) is a voluntary, self-regulating market, and the
place where most of New Zealand’s wholesale electricity is bought and sold.30 It serves 1.74
million customers and has an installed capacity of 8,415 MW. Peak load is 4,908 MW in the
winter. NZEM has operated as a full wholesale market since 1996, and all its activities are based
on a multilateral contract between Market Participants. While trading on the wholesale market
began in October 1996, NZEM did not become a truly competitive, multi-dimensional market
until April 1999. Scheduling and dispatch are done by Transpower, a state-owned enterprise.
Between 70% and 80% of New Zealand’s electricity is bought and sold through NZEM.
Generators offer electricity into the marketplace and retailers then buy electricity from NZEM to
supply their needs. Alternatively, generators and retailers or major users can enter into physical
bilateral agreements outside the market.
More than 60% of New Zealand’s generation capacity is hydro, using river flow systems and
water stored in natural or artificial lakes. Thermal generation (powered by natural gas or coal)
makes up most of New Zealand’s remaining generation capacity (744 MW combined cycle
generation). The country also has some geothermal power and a number of cogeneration
facilities that generate electricity as a by-product of industrial processes such as dairy production.
Climate has a noticeable impact on electricity supply and demand. Extremes of temperature
contribute to higher demand as heating and air conditioning units consume more power. The
amount of water stored upstream of New Zealand hydroelectric dams is dependent on inflows.
30
Information for this section is taken from (1) Annual Market Report January 2001 ~ December 2001, NZEM; and
(2) Electricity Retail Competition: A comparative analysis of markets in England/Wales, South East Australia,
Texas and Ontario October 2002. The section also contains information from the website:
http://www.nzelectricity.co.nz/.
71
Climatic highlights of 2001 included a severe summer-autumn drought across the country,
despite wet conditions in some areas in the last two months of the year. The other major feature
of the year was a big mid-winter freeze.
Figure 15: NZEM
Retail competition
Load Participation
Bilate
ral
contra
cts
Prudential
Security
Hedge contracts
Two-hour-ahead
energy schedule
Real time energy
market (75%~100%)
Real-time Serve Market
Contract A/S Service
Capacity Market
(under-review)
Forecast
prices
Dispatch LMP
prices & FTR
Final LMP
prices
*Day-ahead Market was dropped in 2000
Hour-ahead Schedule
Transpower provides pre-dispatch schedules every two hours, which set out detailed day-ahead
plans of how power stations are expected to be generating (dispatched) to meet the forecast
demand. The schedules are developed from Market Participant load bids and generation offers,
as well as non- NZEM-member load forecasts and generation profiles. Added to this is Grid
Operator information on transmission status. A new pre-dispatch schedule is produced at least
once every two hours. Once it is published, Participants can review forecast prices and revise
their bids and offers up to two hours before dispatch.
Real-time Market
Real-time dispatch began in full on July 1, after a trial phase that began in February 2001. Rule
changes in preparation for real-time dispatch have:
•
Allowed automated electronic dispatch to become the main means of providing dispatch
instructions – considered a necessity as the volume of dispatch instructions under realtime dispatch requires all processes to be automated
•
Separated the production of the real-time dispatch schedule from the dispatch process
•
Required the dispatcher to produce and publish this schedule as a service to the market.
72
Transpower is responsible for the real-time co-ordination of electricity transmission and ensures
that real-time demand and generation are matched. In providing both dispatch and scheduling
services, Transpower must also take into account generators and retailers that are not part of
NZEM but which still need to transport electricity across the national grid. Any deviation in the
dispatch schedule is documented to maintain the process’s transparency and integrity. The
dispatcher then issues generating instructions accordingly. The dispatcher gives market
participants instructions to ensure that demand, security and schedule requirements are met.
Instructions are also issued to meet reserve and reactive power requirements.
Through NZEM a price is established for each of 48 half-hour trading periods every day, at 244
connection nodes on the national grid. The price at each of these nodes is set according to the
cost of providing the electricity, which incorporates locational variations and the cost of
providing reserve. These locational variations can happen because of transmission system
outages, transmission losses and capacity constraints. Under this model the supply-meetsdemand calculation is done at 244 connection nodes around the country, creating a price/demand
pattern in each region. This helps to provide generators with the economic evidence to justify
investment in new plant and where to build it. Signals sent by nodal pricing are a key reason why
most generation capacity built since 1996 is located in the North Island, particularly near
Auckland. It has made the system more efficient in terms of transmission losses and enabled
supply to meet increasing demand for electricity. It has also reduced New Zealand’s reliance on
hydro generation.
Final prices are available by midday the day after physical dispatch (unless delayed for
corrections to metering and grid data). Final prices are used for settlement, which occurs on a
monthly basis.
The reduction in fees includes a proposal to close the Day Ahead Commitment Market, which
has not been used since the start of the wholesale market in October 1996. The total level of fees
charged by EMCO for the operation of the wholesale market will amount to approximately $8
million per annum.
Ancillary Services Market
To ensure that the power system is operated in a safe, secure and reliable manner, the Code
allows NEMMCO to purchase ancillary services from generators, such as frequency control,
voltage, network loading and system re-start. The following functions are managed by ancillary
services:
•
Automatic Generation Control – correction of system frequency between five-minute
targets to prevent overloading of network elements.
•
Governor Control – correction of system frequency within six or sixty-seconds.
•
Load Shedding - automatic disconnection of load in response to an extreme frequency
deviation within six to sixty-seconds.
•
Rapid Generator Unit Loading - automatic reduction of generation in order to preserve
stability under certain situations.
•
Reactive Power – control of system voltage by generation or absorption of reactive
power.
73
•
System Re-start – provides supply to the transmission system following a complete
system failure (Black start generation).
Payments for ancillary services are broken down into payments for availability, enabling usage
and compensation for the provision of the services. Costs for the services are allocated between
market customers and generators.
NZEM 2001 Annual Market Report31
• The New Zealand electricity market faced the biggest test of its five-year life in winter
2001, when dry weather raised the prospect of power shortages.
•
Thermal generators ran at full capacity while prices throughout the country rose. By late
July daily average prices briefly reached 40 cents per kilowatt hour – an increase of
1,400% on prices at the same period in 2000.
•
As 2001 unfolded, rising prices triggered a variety of responses from generators, retailers
and consumers. In response, the Government announced a nationwide “10% for 10
weeks” savings campaign in late July. By August most retailers were announcing reward
schemes for customer savings. By mid-August prices had dropped to 10.6 cents per
kilowatt hour as voluntary conservation efforts helped cut demand.
•
It is highly unlikely that a California-style crisis could happen in New Zealand. With an
efficient, working market, uncapped prices and an effective regulatory structure, New
Zealand does not – and is unlikely to – suffer from the ills characteristic of the
Californian market.
Performance Benchmark Measurements
Average energy price, or fuel-adjusted Load-weighted average price
In simple terms, the price is set by the intersection of the supply and demand curves for
electricity, which are established by offers from generators and metered demand volumes.
The colder winter months of 2001 saw demand levels up to 6% higher than the same month in
2000. Closing or reducing the output of some of these large facilities in the early part of the
“10%-for-10-weeks” campaign had a substantial and positive impact on the savings achieved.
During the campaign demand levels were lower than the corresponding period in 2000.
Congestion costs, percentage and trend
Every month there is a difference between what NZEM receives from purchasers and what it
pays to generators and service providers. This is the result of the impact of losses and constraints
on nodal prices. This ‘loss and constraints rental’ results in a surplus. Since the establishment of
NZEM, total surpluses have been between $50 million and $95 million per annum. Currently,
Transpower allocates the monthly rentals as rebates to grid users, including distributors, who
factor the rebates into their line charges.
31
Summary of Annual Market Report January 2001 ~ December 2001, NZEM
74
Market power abuse investigation and mitigation
On 8 June 2001 two Market Participants asked the MSC to investigate whether an “undesirable
situation” existed (see page 4). These Market Participants did not believe that the high spot
market prices were solely the result of increased demand, low inflows and low water storage
levels. They therefore alleged that other Market Participants had manipulated the market.
The undesirable situation did not exist, noting that the rules should not be used to shield Market
Participants from market forces. It also found no evidence that the high spot prices occurred as a
result of an opportunistic use of market power. The MSC is continuing to monitor this situation.
Operation inefficiency: incompliance rate, price correction rate
During 2001 NZEM continued to evaluate real-time pricing (also known as five minute pricing),
recognizing the prime importance of timely price signals in maximizing market participation and
efficiency. NZEM is committed to reducing transaction costs, increasing efficiency and
improving customer service.
New entry and capacity construction − long-term competitive market
New Zealand has sufficient generation to meet demand and more plant is currently planned or
under construction. A rule change was passed in late 2001 that will enable Market Participants
trading at a grid exit point to access information detailing the total quantity of electricity traded
by each Market Participant through that grid exit point, aggregated by month. This rule change,
which becomes effective in early 2002, is designed to increase transparency and help identify
any errors in reconciliation volumes. The information is confidential and can only be used for
restricted purposes
Potential Areas of Improvements in NZEM
Identified in Annual Market Report January 2001 ~ December 2001:
1. NZEM is currently assessing the pricing regime, the cycle of publishing prices and the
ability for the demand side to respond to them.
2. A review in 2000 showed that some Market Participants had been submitting inaccurate
files to the Reconciliation Manager. This adversely affected the whole market,
particularly incumbent retailers who absorbed any negative financial impacts. A new rule
now allows files submitted to the Reconciliation Manager to include estimated half-hour
metering information in exceptional circumstances and under strict conditions.
75
III. Preliminary Summary
Market deregulation started a decade ago with a central dispatched pool structure with
competitive bids and offers. Recent market designs have moved away from the pool structure
towards bilateral contracts to mitigate market power and hedge risks. For example, internal
bilateral transactions in PJM increased 27,801 MW (88.2%) between 2000 and 2001.4
The market structure of existing markets and planned market design is summarized in the
Appendix I. With a brief look, one can find some common features. All markets allow bilateral
contracts for energy trading, have real-time market for grid operation, and encourage load
participation. They differ with respect to congestion management and arrangements for energy
trading.
Congestion management is one of the most important elements in the market design. Most
overseas markets use a zonal model while a majority of U.S. markets use the nodal model. With
respect to energy trading, some markets mainly rely on bilateral contracts and a forward
electricity financial market while using day-ahead or hour-ahead scheduling to facilitate real time
operation. Other markets have large spot energy trading and use day-ahead unit commitment to
do security-constrained economic dispatch in the day-ahead market and the real-time market.
Preliminary Conclusions
From reviewing different market design and their performance, we can draw the following
preliminary conclusions.
1. A Mandatory Centralized Dispatch Pool Market Is Vulnerable to Gaming
Centralized unit commitment and dispatch had been believed to provide the most economical
dispatch by using a uniform market-clearing price derived from a marginal pricing mechanism.
Most deregulated markets in the earlier stage adopted a power-pool structure that accommodated
centralized unit commitment and dispatch. However, the abuses of market power by participants
in previous UK market and California market were notorious. From a decade’s worth of
experiences in electricity wholesale deregulation, it is clear that the mandatory centralizeddispatch pool model does not work. The California crisis, UK’s replacement of the pool model
with NETA, Australia NEM’s struggles with rebidding problems in summer peak period, and the
exercise of market power in PJM’s capacity pool market all suggest problems with the
mandatory centralized-dispatch pool model.
Although it does not cause market power, pool markets create a strong incentive for suppliers to
exercise their absolute, relative, and temporary market power. Electricity markets are generally
less competitive, highly seasonal, and inherently regional. Even though one market may have a
high capacity reserve, a tight supply would still occur at demand peak time or special locations.
In these instances, more expensive resources would set higher market clearing prices for all
generation resources in the market. A pool structure provides a strong incentive for withholding
and other market power abuses. As long as the bid curves that generators submit can deviate
from resource marginal cost curves and stringent compliance with dispatch instruction is not
required or enforced, the centralized dispatch will not produce most efficient results.
76
Figure 16: Problem of Centralized Dispatch
Centralized Dispatch ≠ Optimal Economic Solution
Generators may not be compliant
with dispatch instruction
Bid curve ≠
Marginal cost curve
Resource specific
bid curve ≠
Marginal curve
LP optimization
used for Prices
& dispatches
Actual dispatch may
not be the most
Economical Results
Private markets could suffice for efficient trading of energy. Self-scheduling could suffice for
operating efficiency of generators provided their contracts provide ample hedging of financial
risks. The efficient operations and low prices in the UK support the argument that highly
decentralized markets for energy and self-scheduling by each market participant work well.
2. LMP Complicates the Detection of Local Market Power
Locational Marginal Pricing (LMP, Appendix II) is a mechanism that could give efficient price
signals for each bus. On its own, however, it does not deal with market power. In essence, the
marginal pricing mechanism may work well at a generation pocket but not at a load pocket. At a
bus with local market power, the lack of competition can cause LMP to degrade to a pay-as-bid
market. Since an expensive resource could only influence its adjoining area, the prices at most
locations may not drive up due to locational high price. On the other hand LMP may enhance
local market power at load pockets. If there is a system-wide shortage as California faced in
2000 and 2001, any market with short supply would also be vulnerable to market power. An
advantage of LMP is that it can directly assign congestion costs and can signal resource
shortages at specific locations, therefore it could be used in real-time to conduct a securityconstrained dispatch.
With a partial energy pool structure, using LMP provides significant gaming opportunities for
generators in load pockets and local constrained areas to manipulate LMP and FTR values. LMP
makes market power mitigation more difficult to monitor. LMP makes market power mitigation
more difficult since changes of bid components have impact not only on a specific bus but on the
whole network as well. MOD’s senior consultant Dr. Oren had demonstrated the ways that
suppliers could manipulate LMPs by changing the bid parameters of generation resources at
November 1st 2002 Workshop.
3. Spot Energy Markets with Centralized Unit Commitment Can Be Problematic
The purpose of a spot energy market – which includes day-ahead and real-time markets - is to
increase market liquidity, provide price discovery, help real-time operations, reduce potential for
market power abuse, and facilitate load participation. Frequently the system operator conducts
centralized unit commitment in the day-ahead energy market to facilitate security-constrained
economic dispatch. However, having large-scale centralized unit commitment has increased
uplift and opened additional gaming opportunities in a number of deregulated markets. (See
77
Number 1 above regarding mandatory spot market.) For instance generators have used the
physical constraints of individual resources to game day-ahead energy markets. Such gaming
likely caused additional procurements in those day-ahead markets, which would have increased
costs to end users.
In the United States, several markets such as PJM, NYISO, and ISO-NE, adopted spot energy
markets with day-ahead centralized unit commitment. These markets have seen the exercise of
market power, as identified in reports published by Market Monitoring Units (MMUs) in these
markets. (References to these reports were provided when these markets were analyzed earlier
in this Report.) For instance:
•
PJM MMU reported that larger energy trading in the spot energy market (energy pool)
with virtual trading provides gaming opportunities for generators to manipulate LMP and
FTR values by submitting schedules with misrepresentation of generator characteristics
(i.e., ramping, minimum output).
•
NYISO MMU reported that there continued to be significant price differences in superpeak hours between the outcomes of the day-ahead, hour-ahead commitment model and
the real-time market model. The report also indicated that the NYISO needs to procure
large amount of day-ahead unit commitment to conduct the security-constrained dispatch
in the day-ahead market.
Therefore, it is important to address potential problems such as those listed above if we decide to
consider a day-ahead spot energy market with centralized unit commitment. In particular, an
important lesson from the California crisis is the crucial role of managing risk through market
design. In most other industries, risk bearing is spread along the supply chain via long-term
forward contracts or financial instruments for hedging. These arrangements are optimal since a
seller and a buyer have common interests in mutual insurance against the volatility of spot prices.
In electricity, a proven way to manage price risk is the bilateral market, which may explain why
centralized spot markets account for much less than half of all electricity procured in deregulated
markets.
Energy Trading Results
A pool market or energy spot market could provide price discovery for over-the-counter and
bilateral market and increase market liquidity or competition. The day-ahead market also
conducts a security-constrained economic dispatch to facilitate the real-time operation. On the
other hand, a pool market or energy spot market with centralized unit commitment provide
incentive and gaming opportunities for suppliers to manipulate electricity prices. The available
data shows that spot market price does provide a benchmark price for bilateral contract.
78
Table 12: Energy Trading in Various Markets
Name
PJM
NYISO
ISO-NE
CAISO
Nord Pool
UK
ERCOT
Bilateral
Schedule
64%
50%
40%
(financial)
10%
71%
97%
95-97%
Day-ahead
Real-time
Energy
Energy
15%
21%
50%
Balancing
100%
90%
29%
N/A
N/A
N/A
N/A
<1%
2-3%
3-5%
Average Energy Comparison Between PJM, NYISO, and ISO-NE
Table 12 shows the mix of bilateral contracts and centralized spot markets (i.e., day-ahead
energy and real-time energy markets). Prices in the pools of the northeastern U.S. are not strictly
comparable: PJM and NYISO are multi-settlement market systems with zonal or nodal pricing,
while ISO-NE has a single-settlement system with one clearing price for the entire control area.
Also note that the ERCOT spot market is a residual, real-time market, which is far more volatile
than the underlying ERCOT bilateral market for electricity. The prices shown are as follows:
•
ERCOT: Load-Weighted Average Balancing Energy Up Price
•
ISO-NE: Hourly Clearing prices.
•
PJM: Hourly Real-time unconstrained System Locational Marginal Price (LMP).
•
NYISO: Hourly Integrated Real-time Locational Bus Marginal Price. Values are the
average of 11 zonal prices weighted by forecasted load for each zone.
Table 13: Energy Market Clearing Prices of ERCOT, ISO-NE, NYISO, and PJM
MCPE
May-01
Jun-01
Jul-01
Aug-01
Sep-01
Oct-01
Nov-01
Dec-01
Jan-02
Feb-02
Mar-02
Apr-02
$28.94
$27.15
$27.63
$31.69
$20.27
$35.77
$76.10
$46.97
ERCOT
Standard
Deviation
$5.60
$11.86
$6.21
$27.83
$3.19
$20.74
$46.10
$27.13
ISO-NE
Average
Standard
ECP
Deviation
$41.01
$20.56
$35.41
$14.62
$52.24
$127.44
$43.34
$53.01
$33.45
$13.59
$30.95
$9.58
$25.61
$11.05
$27.18
$8.23
$25.49
$8.16
$25.10
$9.06
$30.84
$10.12
$30.07
$9.30
79
Average
ECP
$30.24
$31.71
$35.54
$62.67
$25.98
$23.90
$20.34
$19.96
$20.99
$20.19
$24.42
$26.69
PJM
Standard
Deviation
$18.23
$23.52
$50.96
$124.81
$14.41
$9.54
$8.58
$8.46
$8.26
$8.68
$11.36
$16.12
NYISO
Average
Standard
ECP
Deviation
$47.70
$50.90
$39.10
$38.70
$41.32
$33.55
$60.46
$67.74
$34.16
$21.38
$30.03
$9.48
$26.99
$12.43
$26.83
$10.29
$25.57
$7.93
$23.69
$7.15
$31.17
$17.51
$34.60
$22.40
Figure 17: Monthly Average Spot Energy Price Comparison
$80
ERCOT
$70
ISO-NE
PJM
$60
NYISO
$50
$/MWh
$40
$30
$20
$10
A
pr
-0
2
M
ar
-0
2
Fe
b02
Ja
n02
D
ec
-0
1
1
N
ov
-0
ct
-0
1
O
Se
p01
A
ug
-0
1
Ju
l-0
1
1
Ju
n0
M
ay
-0
1
$0
Month
Table 13 and Figure 17 show a pronounced increase in ERCOT’s monthly load-weighted
average real-time energy price for March 2002. This increase – more than double the average
price for any previous month of the market – was due to ten 15-minute price spikes on March 2,
2002 when the market clearing price surged to $999/MWh.
Figure 18 compares New England’s electricity market price duration curve with those of the
other Northeastern control areas (New York and PJM). For the highest 700 priced hours,
clearing prices in New England have been lower than those in New York and PJM. For the next
3300 highest prices hours, ECPs in New England were lower than those in the New York control
area. Finally, for the remaining 4800 (lowest priced) hours, New England and New York ECPs
were nearly equivalent. These differences largely reflect the generating mix available in each
market.
80
Figure 18: Energy Price Duration Curves for ISO-NE,
PJM and NYISO, May 2001 – April 2002
$100
$90
$80
Price ($/MWh)
$70
$60
$50
$40
$30
$20
$10
$0
0
1000
2000
3000
4000
5000
6000
7000
8000
9000
Hours
ISO-NE
PJM
NYISO
Ancillary Services Prices of Various Markets
Table 14 shows ancillary services that are common to various markets. The prices of regulation
reserve, spinning reserve, and non-spinning reserve may be compared among ERCOT, CAISO,
and NEISO on the basis of available monthly weighted average ancillary services prices, and
among ERCOT, NEISO and NYISO using monthly un-weighted average ancillary services
prices.
Table 14: Ancillary Services Market Components
Type of Ancillary Services
Regulation reserve
Ten-minute spinning reserve
Ten-minute non-spinning reserve
Thirty-minutes reserve
Replacement reserve
Reserves (no specific)
US Markets
PJM, NYISO, ISO-NE,
ERCOT, MISO, CAISO and
NERTO
NYISO, ISO-NE, ERCOT,
CAISO, NERTO
NYISO, ISO-NE, ERCOT,
CAISO, NERTO
NYISO, ISO-NE, ERCOT,
NERTO
ISO-NE, CAISO, ERCOT
Oversea Markets
UK, Nord Pool, NZEM,
Australia, Ontario, Alberta
NZEM, Ontario, Alberta,
Ontario, Alberta
Ontario
UK , Nord Pool, Australia
81
Regulation Reserve Services Price
Weighted Average Price
Since weighted average regulation services prices only available for ERCOT and CAISO (unit of
AGC in NEISO is different from others’), we only compare ERCOT day-ahead regulation up
and regulation down services prices with CAISO day-ahead markets’.
Table 15: Weighted Average Regulation Price ($/MW)
DATE
Aug-01
Sep-01
Oct-01
Nov-01
Dec-01
Jan-02
Feb-02
Mar-02
Apr-02
May-02
Jun-02
Jul-02
Aug-02
ERCOT
Reg. Up Reg. Dn
12.40
15.94
8.77
12.45
7.61
13.75
8.91
6.38
7.32
3.00
6.06
2.08
5.79
2.17
7.05
4.24
7.35
6.33
4.79
4.89
5.94
3.30
5.78
5.41
6.07
3.46
CAISO
Reg. Up Reg. Dn
46.00
27.00
21.00
17.00
13.00
13.00
12.00
12.00
14.00
11.00
14.00
14.00
14.00
14.00
9.02
8.35
12.73
14.92
14.08
16.51
16.22
18.27
14.95
16.58
10.32
11.69
Figure 19: Weighted Average Regulation Prices
50.00
45.00
40.00
35.00
30.00
25.00
20.00
15.00
10.00
5.00
0.00
Reg Up_ ERCOT
Reg Dn_ERCOT
Reg Up_CAISO
Reg Dn_CAISO
Au
g0
Se 1
p0
O 1
ct
-0
No 1
vDe 0 1
c0
Ja 1
n0
Fe 2
b0
M 2
ar
-0
Ap 2
rM 02
ay
-0
Ju 2
n02
Ju
l-0
Au 2
g02
$/MWh
Weighted Averge Regulation Prices
82
From the figure, we found that the weighted average regulation prices of ERCOT were lower
than CAISO from August 2001 to August 2002.
Average Regulation Services Prices
Table 16: Average Regulation Services Prices ($/MW)
Month
Aug-01
Sep-01
Oct-01
Nov-01
Dec-01
Jan-02
Feb-02
Mar-02
Apr-02
May-02
Jun-02
Jul-02
Aug-02
ERCOT
Reg. Up Reg. Dn
10.03
12.48
8.33
13.05
6.93
3.80
7.36
7.48
5.61
2.24
5.72
1.66
4.72
1.95
6.60
4.05
6.66
6.05
3.94
4.22
5.39
3.16
4.85
4.66
5.88
3.37
NYISO
Reg.
9.80
13.69
13.81
12.39
14.41
14.90
13.83
12.59
12.33
18.78
20.92
20.85
21.31
Figure 20: Average Regulation Prices
Average Regulation Prices
25.00
$/MWh
20.00
15.00
Reg Up_ERCOT
Reg Dn_ERCOT
Reg_NYISO
10.00
5.00
Au
g0
Se 1
p0
O 1
ct
-0
No 1
v0
De 1
c0
Ja 1
n0
Fe 2
b0
M 2
ar
-0
Ap 2
rM 02
ay
-0
Ju 2
n02
Ju
l-0
Au 2
g02
0.00
By this figure, we found that average regulation prices of ERCOT were lower than NYISO from
August 2001 to August 2002.
Spinning Reserve Service Prices
The responsive reserve service in ERCOT is similar to the spinning reserve services in other
markets. So in the following table and figure, we compare the spinning reserve service prices
(Weighted Average Price) of ERCOT, CAISO, NEISO and NYISO.
83
Table 17: Weighted Average Prices of Spinning Reserve ($/MW)
DATE
Aug-01
Sep-01
Oct-01
Nov-01
Dec-01
Jan-02
Feb-02
Mar-02
Apr-02
May-02
Jun-02
Jul-02
Aug-02
ERCOT
12.14
6.28
11.59
7.55
5.05
3.69
4.65
5.93
10.39
4.00
4.56
7.56
5.64
CAISO
12.00
3.00
3.00
2.00
2.00
2.00
2.00
3.15
3.40
4.43
6.61
10.82
5.06
NEISO
1.28
0.41
0.27
0.21
0.23
0.24
0.40
0.61
1.09
1.30
1.18
2.97
8.14
14.00
12.00
10.00
8.00
6.00
4.00
2.00
0.00
Spin_ERCOT
Spin_CAISO
Spin_NEISO
Au
g0
Se 1
p0
O 1
ct
-0
No 1
vDe 0 1
c0
Ja 1
n0
Fe 2
b0
M 2
ar
-0
Ap 2
rM 02
ay
-0
Ju 2
n0
Ju 2
l-0
Au 2
g02
$/MWh
Figure 21: Weighted Average Spinning Reserve Prices
By the graph, we found the weighted average spinning reserve prices of ERCOT were higher
than CAISO and NEISO from August 2001 to April 2002 and between them during May 2002
and August 2002. The weighted monthly spinning reserve prices in NEISO were lowest in these
three markets during almost last one year except Aug. 2002.
84
Average Spinning Reserve Prices
Table 18: Average Spinning Reserve Prices ($/MW)
DATE
Aug-01
Sep-01
Oct-01
Nov-01
Dec-01
Jan-02
Feb-02
Mar-02
Apr-02
May-02
Jun-02
Jul-02
Aug-02
ERCOT
9.43
5.43
7.10
6.50
3.72
3.22
4.11
5.39
8.47
3.51
4.25
7.16
5.57
NEISO
1.59
0.53
0.35
0.28
0.31
0.32
0.49
0.80
1.36
1.71
1.54
3.27
8.98
NYISO
2.41
2.46
2.12
2.38
1.94
1.97
1.88
2.63
2.20
1.87
1.83
2.34
3.20
Figure 22: Average Spinning Reserve Prices
Spin_ERCOT
Spin_NEISO
Spin_NYISO
Au
g0
Se 1
p0
O 1
ct
-0
No 1
v0
De 1
c0
Ja 1
n0
Fe 2
b0
M 2
ar
-0
Ap 2
rM 02
ay
-0
Ju 2
n02
Ju
l-0
Au 2
g02
$/MWh
10.00
9.00
8.00
7.00
6.00
5.00
4.00
3.00
2.00
1.00
0.00
By the graph, we found the average spinning reserve prices in ERCOT were higher than NEISO
and NYISO except Aug. 2002, which between them. The average spinning reserve prices in
NEISO were the lowest from Aug. 2001 to Jun. 2002.
Non Spinning Reserve Prices
The Non-Spinning reserve service prices of ERCOT, CAISO, NEISO and NYISO are listed in
following tables and graphs.
85
Weighted Average Prices
Table 19: Weighted Average Non Spinning Reserve Prices ($/MW)
DATE
Aug-01
Sep-01
Oct-01
Nov-01
Dec-01
Jan-02
Feb-02
Mar-02
Apr-02
May-02
Jun-02
Jul-02
Aug-02
ERCOT
5.89
0.69
*
0.05
0.03
0.42
0.84
0.54
35.78
8.42
1.17
7.81
6.26
CAISO
9.00
*
2.00
*
*
*
*
0.57
0.73
1.30
3.88
6.50
3.01
NEISO
4.48
0.81
0.29
0.30
0.27
0.21
0.56
0.45
0.43
1.09
1.04
3.09
8.56
Figure 23: Weighted Average Non-Spinning Reserve Prices
10.00
8.00
$/MWh
6.00
Non Spin_ERCOT
Non Spin_CAISO
Non Spin_NEISO
4.00
2.00
Au
g0
Se 1
p0
O 1
ct
-0
No 1
v0
De 1
c0
Ja 1
n0
Fe 2
b0
M 2
ar
-0
Ap 2
rM 02
ay
-0
Ju 2
n02
Ju
l-0
Au 2
g02
0.00
While ERCOT established the non-spinning reserve obligations, non-spinning reserves are
procured only for those days with projected temperatures in Texas forecast above 92 degrees, or
lows forecast below 30 degrees are not considered normal. Most generators did not interrupt
their scheduled outages since the shoulder months-April and May is when generators normally
schedule the major equipment outages in order to prepare for the hot summer months. This
resulted in a very thin non-spinning bid stack that leaves the market vulnerable to price spikes, as
was seen in the spring of 2002.
86
Average Prices
Table 20: Average Non Spinning Reserve Price ($/MW)
DATE
Aug-01
Sep-01
Oct-01
Nov-01
Dec-01
Jan-02
Feb-02
Mar-02
Apr-02
May-02
Jun-02
Jul-02
Aug-02
ERCOT
3.31
0.41
*
0.07
0.02
0.28
0.59
0.46
19.93
3.05
0.94
2.37
2.05
NEISO
4.35
0.89
0.26
0.30
0.26
0.20
0.54
0.46
0.41
1.11
0.98
2.92
8.57
NYISO
2.14
2.19
1.93
1.55
1.62
1.51
1.47
1.52
1.48
1.43
1.39
1.41
2.03
Figure 24: Average Non-Spinning Reserve Prices
Average Non Spinning Reserve Prices
10.00
Non Spin_ERCOT
Non Spin_NEISO
Non Spin_NYISO
$/MWh
8.00
6.00
4.00
2.00
Aug-02
Jul-02
Jun-02
May-02
Apr-02
Mar-02
Feb-02
Jan-02
Dec-01
Nov-01
Oct-01
Sep-01
Aug-01
0.00
The average non spinning reserve prices of ERCOT were close to NEISO and lower than NYISO
except April 2002 and May 2002 with price spike.
87
Uplift and Congestion Costs of the U.S. Markets
Table 21: Uplift of PJM, NYISO, ISO-NE, and ERCOT ($ Millions)
Markets
2000
2001
2002 until
September 30
Component
≈$240
(excluding
$155 ISO
fee)
$151
(excluding
ISO fee)
≈$330
(excluding
$140 ISO fee)
≈$225
(excluding $72
ISO fee)
Total uplift excluding ISO
Administration costs
$218
(excluding ISO
fee)
≈$13934
(excluding ISO
fee $26.6)
$125
(excluding ISO
fee)
≈$122.535
(excluding ISO
fee $40.8)
Energy, mitigated
Congestion, NCPC, RMR
uplift
Total uplift costs
excluding ISO
administration fee,
updated to 11/18/2002
PJM
NYISO32
ISO-NE33
(May ~ April)
ERCOT
(August ~ July)
NCPC: Net Commitment Period Compensation
Table 22: Congestion Costs of the U.S. Markets (Millions)
Markets
PJM
2000
$132
2001
$271
NYISO
$517
$310 *
ISO-NE
$165 (including
energy loss)
$166
$102 (including energy loss)
Costs
199919
$53
CAISO
FTR
Auction
$41
$30 (02/15/01
$165 (07/31/01
– 09/30/02)
-02/14/02)
OOMC: $97
OOME: $48.5 (07/31/01 9/30/02)
CSC
ERCOT
CAISO
$83
local
congestion
* Due to substantial decreases of fuel costs and procurement of Reliability-Must-Run (RMR) services and OOM dispatch (uplift
increase of 40%)
32
NYISO, Monthly Report, September 2002
ISO-NE, Annual market Report, May 2001 ~ April 2002, Technical Review
34
$139 million is rescaled based on $58 million Uplift for 5 months from 7/31/01 to 12/31/01, excluding possible
$12 million refund of BENA charge
35
$122.5 million is rescaled based on $156.6 million Uplift for 11.5 month from 01/01/02 to 11/18/02.
33
88
Market Power Mitigation: Alternatives for an Automated Mitigation Plan
Since market power abuse is much harder to detect under LMP than under a zonal model, having
some form of an automated mitigation plan is prudent to reduce the potential for market
manipulation. The nature of the AMP that FERC has proposed is a prospective automated ex
ante measure, built into the market design rather than retrospective. Its ex ante nature implies
that market participants avoid the regulatory risk and disruption to settlements and financial
accounting caused by refunds from ex post market mitigation measures.
Dr. Shams Siddiqi’s ZEN model could work as a good alternative to conduct automated ex ante
market power mitigation. The ZEN measure (See Appendix IV) attempts to provide a measure
of true legitimate scarcity by examining available capacity sufficiency within a zone. ZEN is a
built-in structural solution rather than a behavioral mitigation measure as is seen in the NYISO
AMP. ZEN may provide an alternative to Reliability Must Run (RMR) contracts on resources
used to control locational market power..
89
IV. Options for ERCOT Market Design
The design of a competitive wholesale market is determined by two fundamental principles: 1)
competitive and efficient energy trading, and 2) reliable operation of the grid. Competitive and
efficient energy trading is achieved by creating the robust energy market structure to ensure both
long-term market health and short-term efficiency. The reliable operation of the grid is achieved
through an effective scheduling process coupled with computer modeling that conducts securityconstrained economic dispatch (SCED). Each one maybe separately solved or integrated into
one process to fulfill its designed functions. Figure 25 demonstrates the processes of energy
trading and operation dispatch.
In the electricity industry, wholesale energy is traded through bilateral contracts, energy financial
markets, and day-ahead and real-time (or hour-ahead) spot markets. Table 23 summarizes some
trade-offs of major components of market design. Because of the operational requirements and
volatility of real-time prices in electricity markets, risk management using forward contract
hedges are the key to ensuring smooth operation and profitability of generation resources. In
stable electric power markets, the spot markets account for less than half of the energy delivered.
Competitive and efficient energy markets need to be liquid to provide the appropriate long-term
and short-term price signals. Regulators also need to develop mitigation measures that address
potential abuse of market power for real-time electricity markets.
Electricity is a unique commodity where grid operators have to ensure that supply and demand
for energy are in balance at every moment at every location. The reliable operation of the grid
requires that operators conduct security-constrained economic dispatch. In addition, the reliable
and efficient operation of the grid depends upon several factors:
1. Effective scheduling process to smooth real-time operation
2. Efficient use of transmission resources
3. Accurate price signals to the market.
The various market structures of existing markets and planned market designs are summarized in
the Appendix I. For a brief look, one can find that all markets allow bilateral contracts for
energy trading, have real-time markets for grid operation, and encourage load participation. The
big differences are how to design energy trading and how to conduct SCED. Some markets have
a day-ahead market for spot trading and some markets just have day-ahead or hour-ahead
scheduling process to facilitate real time operation. Most overseas markets use zonal models but
majority of U.S. markets are already using or are in the process of using nodal models.
90
Figure 25: Energy Market Functions
Energy Trading
Bilateral Contracts
FTR
Day-Ahead Market
Day-Ahead
Scheduling
Hour-Ahead Market
Hour-ahead
Scheduling
Real-Time Market
DA Unit Commitment
Day-Ahead Ancillary
Service Market
Physical Scheduling Process
Financial Hedge
Spot Energy Trading
FTR
Security-Constrained
Economic Dispatch
LMP, FTR Value
91
Security-Constrained
Economic Dispatch
Security-Constrained
Economic Dispatch
Spot Energy Trading
Balancing Energy
Trading
Table 23: Trade-offs of Major Components of Market Design
Component
Bilateral
Contracts
Forward
Energy
Market
Day-Ahead
Market
Real-Time
Market
LMP
Congestion
Management
Objective/Benefit
Weakness
Encourage long-term contracting and
hedging.
Consistent with customer choice and
marketing efficiency
Attract entry and new investments
Result in low transaction costs.
Provide freedom to engage in long-term
contracts
Diminish market power abuse
Freedom to contract among a wide variety
of parties
Easy to hedge risks
Low transaction costs
Allows for long-term business
relationships
Improved liquidity in short-term markets
Provides price discovery
Improves demand-side participation
Can facilitate real-time operation by
providing additional information to handle
transmission congestion
Maintains reliability of grid
Provides economic signals for location of
generation and load
Allows direct assignment of congestion
fees for all transmission lines
Allocates scarce transmission resources
Point-to-point rights can provide a
complete hedge for congestion costs
Can accommodate flowgate rights for
commercially significant constraints in
transmission system.
May not result in the most efficient
dispatch in real-time if bilateral contracts
are excluded from central dispatch
May be subject to market power if
resources are still bundled with loads.
May not fully account for transmission
congestion at any given moment
May result in counter-party credit risk
May involve confidentiality issues
If mandatory, will be kind of pool, subject
to market power abuse
May result in gaming of congestion rights
by false scheduling or virtual trading
System operator may need to procure large
amounts of capacity to serve net short.
Physical, not financial, market
May require additional mitigation
measures to address market power in load
pockets and local constrained areas
Provides gaming opportunities for
generators to manipulate LMP and FTR
values by submitting legitimate schedule
and misrepresenting generation
characteristics (i.e., ramping, minimum
output).
Under certain conditions, LMP may make
market power more difficult to detect.
Day-Ahead Market as a Spot Energy Market
An informal day-ahead scheduling process has worked well in ERCOT and other markets where
high percentage of energy trades takes place before the day-ahead period. Day-ahead trades take
place in the bilateral market in ERCOT. In November 2002 ERCOT instituted a relaxed
balanced schedule that would allow market participants to increase trading in the real-time
market.
Through additional price and operational information, a day-ahead market could increase market
liquidity, provide price discovery, help real-time operations, and encourage load participation. A
day-ahead market usually is a voluntary and financial binding market with a single clearing price
rather than a bulletin board of bilateral transactions. If it is a voluntary market, the day-ahead
92
market may result in a shortage of generation offers or an excess demand bids in the real time
operation (i.e., net short). If the day-ahead market is financial binding, a two-settlement system
is needed. Therefore, the day-ahead market has to be cleared based on the ISO's load forecast,
and the ISO may need to procure additional committed capacity to balance supply with its load
forecast. Centralized unit commitment on a large scale may provide generators opportunities to
game the electricity market by using ramp rates and other non-price elements of generation.
Congestion Management
The congestion management mechanism is main distinction between zonal and nodal model.
Zonal model is a simplified nodal system with implicit assumption that local congestion is
random and infrequent within zonal boundaries. If local congestion is limited, the zonal model
can work well. If there is substantial local congestion, the simplified assumptions imbedded in
the zonal model may break down, and pricing of a large number of transmission constraints may
be needed for efficient dispatch and location of new resources. (Please see related section in this
report regarding ERCOT model). To address local congestion issues within a zonal framework,
MOD has offered a proposal for direct assignment of local congestion fees.
The zonal model in ERCOT uses two steps to conduct congestion management (Appendix III):
(1) the system operator uses a group of zonal shift factors and commercial model to solve
congestion on zonal commercially-significant-constraints (CSC) and to set unified zonal market
clearing prices, and (2) the system operator relieves local congestion using operational model by
deploying INC or DEC balancing energy from specific resources using unit-specific shift factors
while maintaining the level of energy within the zone.
Nodal approach solves all constraints simultaneously using unit specific bid curves to conduct
security-constrained economic dispatch. The model determines Locational Marginal Prices
(LMP) for the nodes within the system. Congestion charges are based on the price differences
between injection nodes (hubs) and withdraw nodes (hubs). SCED is also used for dispatch in
day-ahead market as part of a two-settlement system to set day-ahead LMPs. The second
settlement takes place at the real time when the second set of LMPs is determined. The market
design can be flexible on this issue and allow full or partial central dispatch to take place within
security-constraint economic dispatch.
Some Possible Options for ERCOT Market Design
In late 2002 and early 2003, Commission Staff has set aside time at workshops in Project No.
26376 to focus on two market design elements: 1) a centralized day-ahead energy market and 2)
congestion management mechanism. Since competitive and efficient energy trading and reliable
operation of the grid are two fundamental market design issues, we focus on Bilateral with RealTime Balancing Energy or Bilateral with DA & RT Spot Market as the main choices for energy
market. In addition, we limit our choices between the zonal and nodal congestion management
mechanisms as the most important choices for market design. The four combinations along with
the list of electricity markets from across the world that have selected each specific option are
listed in Table 24.
93
Table 24: Available Options of Market Design
Options
1
2
3
4
Bilateral with RT
Balancing Energy /
Zonal
Bilateral with RT
Balancing Energy /
Nodal
Bilateral with DA &
RT Spot Market /
Nodal
Bilateral with DA &
RT Spot Market /
Zonal
Existing/Proposed Models
Characteristics
UK, ERCOT, Australia, Ontario,
Alberta
Min or limited ISO;
Assumes limited
local congestion
Nodal congestion
management
New Zealand
FERC SMD, PJM, NYISO, ISONE, MISO, CA MD02
Similar to Scandinavian Nord Pool
Moderate or Max
ISO; Assumes
significant local
congestion
Assumes limited
local congestion
Option 1 is the ERCOT current model with dominant bilateral contract, a residual real-time
balancing energy market, and zonal congestion management. The basic market components
comprise a bilateral market along with the day-ahead ancillary services markets and the real-time
balancing energy market, monthly and annual Transmission Congestion Rights (TCRs or
flowgate rights), and direct assignment of zonal congestion. An optional ISO-run active
financial market could also be used to improve market liquidity. The following flow chart
provides major component of Option 1.
Figure 26: Option 1 (ERCOT Current Model)
Loads Acting
As Resources
TCR
Auction
Mandated
Capacity
Auction
Reserve
Margin
Opt. ISO-run
financial market
95%
Bila
teral
cont
racts
Day-ahead
Schedule &
A/S Market
Congestion
Forecast
MCPE, TCR
Value &
Dispatch
Real-time
Balancing Market
$1000/MWh
Generic Costs
c
a
p
ERCOT is similar to UK’s New Energy Trading Arrangement (NETA) model. Both UK NETA
and ERCOT share the same philosophy in their electricity market design, i.e. minimum
94
involvement by the Independent System Operator (Min ISO), where the ISO just operates a
residual energy market instead of a centralized day-ahead energy market and lets market
participants entirely self-arrange their positions prior to real-time using bilateral contracts. The
difference between UK NETA and ERCOT is that UK ISO (National Grid Company) actively
intervenes in the market through PBR (performance-based regulation) that is rewarded for it to
reduce cost to consumers whereas in ERCOT the ISO is prohibited from doing so. The
underlying assumption of this market arrangement is that private bilateral markets are sufficient
for efficient energy trading and generator self-scheduling is consistent with system operation
efficiency.
In contrast, Max ISOs refer to electricity systems where the Independent System Operators are
heavily involved in the operations of their electricity markets. Table 25 compares the market
characteristics among UK NETA, ERCOT, PJM and NE-RTO.
Table 25: Characteristic Comparison of Different Markets
Characteristics
UK
ERCOT
PJM & NE-RTO
Extent of Role of
System Operator
Min “ISO”, actively intervening
in the RTmarket through longterm contracts under PBR
High
Low
51,012/67,695 MW
33%
98%
Min ISO, being prohibited
from intervening in the RT
market
High
Moderate
57,600/73,000 MW
21%
95%
Max ISO, being prohibited
from intervening in the RT
market
Moderate
High
52,930/59,000 MW
12%
≈ 64%
No
No
Yes
Yes
Relaxed
No
No
DC Ties
Yes
HHI
Congestion
Peak load/Capacity
Capacity Reserve
Bilateral Contract as
percent of energy
delivered
Day-Ahead Energy
Market
Balanced Schedule
Requirement
Interconnection with
other grid systems
Experience in other markets has shown that under the right circumstances, decentralized systems
can be as efficient as more centralized systems. Although data about NETA comes from only 18
months of recent experience, UK NETA appears to function smoothly and efficiently. Prices and
price volatility declined as market participants became more familiar with the system, and
trading increased in the private exchanges (e.g., UKPX) and especially in the over-the-counter
market for bilateral contracts.
ERCOT two step congestion management scheme suffers some operation inefficiencies. In its
first step, ERCOT uses the commercial model with portfolio bid to procure zonal balancing
energy to clear zonal congestion. As a simplified zonal model, ERCOT commercial model does
not always provide accurate solutions for CSC constraints. In the second step, ERCOT has to
assume actual movement for next dispatch interval to issue unit commitment instructions to
solve local congestion since QSEs’ conduct actual dispatch based on balancing energy awards
and its schedule. These assumptions are not always consistent with real time operations because
95
ERCOT lacks the details about the QSEs’ internal dispatch intentions. Implementation of the
State Estimator is needed to improve ERCOT real time operational knowledge, and the addition
of a function that integrates real time system information into resource specific deployment
decisions is needed to improve congestion management efficiency and reduce the amount of
OOMC procured for congestion management.
The current zonal congestion management system in ERCOT uplifts local congestion costs
which result in a “pay-as-bid” approach to relieve congested local constraints, provided that
market solution exists. (OOME payments can be thought of as bid caps for purposes of this
analysis) This approach leaves the relief of local congestion open to the “DEC” game, whereby
a market participant can make money by causing a local constraint to be congested and having
ERCOT pay the market participant to relieve that congested line. Because the current zonal
model does not allocated scarce transmission capacity within a zone, the market has
insufficiently granular price signals to site new generation appropriate. The installation of 750
MW of wind turbines behind a 400 MW constraint near the McCamey area is an example of this
lack of granularity in price signals.
MOD is proposing a method to directly assign local congestion fees, also known as “nodal when
you need it.” Under this approach, ERCOT would use the unit-specific bid premiums as inputs
to simultaneously clear local constraints in “Step 2” of the two-step ERCOT zonal model.
Resources would receive or pay local congestion fees based on their output, their shift factors
relative to the congested line, and the shadow prices of each congested line. The shadow prices
on the congested lines would be determined as the cheapest means to relieve all constraints given
the bid premiums submitted. MOD’s proposal for direct assignment of local congestion fees
could reduce “DEC” game significantly and make locational prices more granular.
Option 2 is similar to option 1 but nodal pricing is used to improve congestion management,
such as the market structure of New Zealand Wholesale Electricity Market (NZEM), where a
nodal congestion management system without a day-ahead energy market is in place. Like
Option 1, Option 2 mainly relies almost exclusively on bilateral contracts or an optional financial
market, a Day-Ahead Ancillary Services Market, a day-ahead scheduling model, a real-time
energy market with LMP dispatch, and the annually and monthly congestion rights market. This
option has some operational advantages. Since LMP is in essence an operation model to do
SCED, it could optimize the use of the available transmission grid and help accurately assign
congestion costs to direct users of the transmission lines.
96
Figure 27: Option 2
Capacity
Markets
FTR & Capacity
Auction Markets
Bila
teral
cont
racts
LAAR
Financial Energy
Market until
Hour-ahead
NYMEX
Prices
ICAP 12.5%
Must offer
$1000/MWh
C
A
P
Day-ahead
Schedule & A/S
AMP
Real-time
Balancing Market
LMP &
Dispatch
Key questions that need to be addressed about congestion management in Option 1 & 2
are:
1. Do the underlying assumptions of the zonal model – limited local congestion, similarity
of shift factors relative to a CSC, and the net benefits of deploying resources on a
portfolio basis – hold sufficiently for ERCOT to maintain a zonal approach to clearing
congestion in ERCOT?
2. In Order on Rehearing in Docket 23220, “Implementation of the ERCOT Protocols,” the
Commission determined that the direct assignment of local congestion fees would be
needed if the uplift of local congested costs reached a certain threshold. Should the
Commission maintain a zonal model and add MOD’s “nodal when you need it” approach
or move to a fully-developed nodal model (i.e., similar to those seen in the northeastern
United States)?
3. What is the quantifiable increase in economic efficiency in dispatch and price
transparency that would occur if the Commission ordered ERCOT to convert to a nodal
congestion management model? What criteria should the Commission use to judge the
effectiveness and success of a nodal model in ERCOT?
4. Are the costs of implementing a nodal model recouped in a reasonable amount of time to
justify the change in the congestion management scheme? Would the impacts of the
increased complexity of a nodal model reduce or enhance the value to market participants
of the buying and selling electricity in ERCOT?
97
Option 3 is consistent to FERC’s SMD which relies on both a centralized day-ahead energy
market and nodal congestion management. From Table 25, we can find that both PJM and
NYISO have about half to two-thirds of their energy delivered through bilateral contracts, with
the remainder in day-ahead or real-time energy markets.
One improvement would be to have a day-ahead market that simultaneously co-optimizes
ancillary services and energy. The real-time energy market has forward looking optimization
which is a real-time, security-constrained scheduling process that looks ahead three hours and
executes at 15- minute intervals and a dispatch process that looks ahead one hour and executes
on five- minute intervals.
Option 3 could also be integrated into ERCOT current zonal structure in the way that it includes
the co-optimized day-ahead energy and ancillary services markets, real-time energy market
which has forward looking optimization features, and the annual and monthly TCR auction
market. Both the day-ahead and real-time markets use locational marginal pricing that reflects
transmission constraints and losses with automated ex ante market power mitigation.
Figure 28: Option 3
TCR
Auction
Bilater
al
Contra
cts
Load Acting
As Resources
Capacity
Auction
Day-ahead energy
& A/S market
(Co-optimization)
LMP prices
Market
Reserve
Capacity
Markets
$1000/MWh
AMP
Real Time
Energy Market
(Forward-looking)
C
A
P
LMP Prices &
Dispatches
Option 4 is bilateral with voluntary day-ahead and real-time spot energy trading and zonal
congestion management. The use of zonal congestion management implicitly assumes that local
congestion is limited. If a zone experiences heavy local congestion, the Security-Constrained
Economic Dispatch may be difficult to be integrated with zonal structure in day-ahead market. If
day-ahead market cannot provide accurate locational prices within a zone, it becomes an energy
trading platform which is similar to power exchange. Such an arrangement will not provide the
appropriate information for efficient dispatch under transmission constraints.
98
Option 4 is similar to Nord Pool model. Nord Pool has an ISO who operates an active financial
derivatives market and has large portion of hydropower that could be used at lower costs. Nord
Pool is a successful electricity wholesale market but because of its particular mix of generation
and low population density may have limited applicability in other places.
Figure 29: Option 4
FTR/TCR
Auction
Bilateral
contracts
Load Acting
As Resources
Capacity
Auction
Market
Reserve 12.5%
Financial Derivatives
Markets
Contract for
Difference
Capacity
Markets
Day-ahead
Energy Market
Day-ahead
MCPE
$1000/MWh
C
A
P
Hour-ahead
Energy Market
Hour-ahead
MCPE
AMP
Real-time
Market
Real-time
MCPE
Key questions that need to be addressed about a day-ahead market in Option 3 & 4 are:
1. . Is there a need for the Commission to implement an ERCOT-run day-ahead energy
market?
2. What are the net benefits (costs) of implementing an ERCOT-run day-ahead energy
market? The potential benefits and costs include but are not limited to the following:
a. Increased market liquidity and efficiency and increased profits or reduced costs
for your business
b. A list of improved market or business practices resulting from the implementation
of an ERCOT-run day-ahead energy market
c. Implementation and additional operating costs for ERCOT
3. If the proposed day-ahead market consists of an additional settlement system, how does it
integrate with congestion management, especially in dealing with local congestion? If a
99
compromise approach is used, how could it be good enough to accomplish the desired
objectives?
4. The level of centralized unit commitment that a day-ahead market requires is a key
market design issue. ERCOT needs to be sure that it will have enough energy and reserve
capacity to deliver sufficient real-time energy, meet projected demand, and to resolve
congestion.
Would an ERCOT-run day-ahead energy market require an increased level of centralized
unit commitment compared to what ERCOT currently needs? If so, what type and costs
of centralized unit commitment would ERCOT need to run to meet the type of day-ahead
energy market that market participants would like to see?
5. Centralized unit commitment in a day-ahead market can be problematic. What is the
feasible approach to address some of the problems of centralized unit commitment with
virtual bidding?
a. Single vs. multiple-part bidding
b. Fixed generator characteristics (e.g., ramping, minimum output)
c. Different treatment of transmission constraints
100
Proposed
Market
Designs
ERCOT
Options
√
√
<25%
√
0
√
98%
√
64%
√
√
√
√
√
√
50%
√
√
√
√
√ √
√
√
√
√
√
TC
R
√
√
Profit
limit
√
√
√
England
PJM
√
√
NYISO
√
√
ISO-NE
Financial
hedge
40%
√
√
0
ERCOT
√
Schedule
√
97%
Ontario
√
Financial
√
√
Alberta
√
FERC SMD
Schedule
√
Private
√
√
√
36
√
√ √37
√
√
√
√
√ √
√
√
√
SRA
√
AMP
√
Price CAP
CfD
FTR
Retail Competition
71%
LAAR
√
ICAP
Market
Financial
hedge
√
Australia
Existing
Market
Designs
√
LMP
√
Bilateral /Self-schedule
New Zealand
Real-time Market
√
Hour-ahead Schedule
√
Day-ahead Market
Active Financial Market
NORD
POOL
Market
Bilateral Contract
Appendix I: Summary of Market Design
√
Schedule
√
√
√
√
√
√
√
√
√ √
NERTO
√
√
√
√
√
√
√
√ √
MISO
√
√
√
√
√
√
√
√ √
California
√
√
√
√
√
√
√
√ √
Option 1
(ERCOT)
√
TC
R
√
√ √
√
Option 2
√
Option 3
(SMD)
√
Option 4
√
√
△
Market
38
Schedule
√
△
Schedule
√
√
√
√
√
√ √
√
√
√
√
√
√
√
√ √
√
√
√
TC
R
√
√ √
√
△
36
high
√
Under consideration of some capacity support mechanism
Under consideration
38
Optional ISO-run active financial market to improve market liquidity
37
101
Appendix II: LMP Security-Constrained Dispatch Process39
Figure 30: LMP Dispatch Process
Resource
specific bid
curve
System
Economic
Dispatch Rates
State
Estimator
Operator
Input
39
LPA
preprocessor
Demand,
Generation,
Topology
LPA
Contingency
preprocessor
Flexible
Generating
Units & Bids
LMP
Engine
LMP price
& Dispatch
Binding
Transmission
Constraints
Implementation
40% noncompliance?
Locational Marginal Pricing Presentation by Andrew Ott, PJM Interconnection L.L.C, July 30, 1998
102
Appendix III: ERCOT Two-Step Dispatch Process
Figure 31: ERCOT Two-Step Dispatch Process
Step One
Load
Response
Bila
teral
cont
ract,
95%
Portfolio
Bids
Step Two
CSC
Contingenci
Day-ahead
schedule
SCADA
previous state
Resource
Specific Bids
Adjustment
Real time
Balancing market
Security
Analysis
Proportionally
Assign
MCPE and
balancing dispatch
Resource Specific
Dispatch
103
Appendix IV: Automated Ex Ante Market Power Mitigation
Measure40
The automated ex ante market power mitigation mechanism (ZEN) adopts a Structural solution
to mitigate market power. The ERCOT SMD-x structural solution to the locational market
power mitigation problem may be summarized as follows. Assuming that the Regional
Transmission Organization (RTO) utilizes an Optimal Power Flow (OPF) algorithm (typically
DC power flow) to resolve congestion as well as balance the system, whenever the transmission
system is congested:
1. The RTO would solve the regional OPF problem that includes all non-local constraints to
determine nodal Locational Marginal Prices (LMP) and reference output levels of all
resources.
2. The RTO would then re-solve the OPF problem that includes all constraints, including
local constraints, based on mitigated bid curves as described in (4) and (5) below to
determine the dispatch set points of all resources.
3. The RTO sets LMPs based on the first run of the OPF and sends dispatch instructions
based on the dispatch set points of the second run of the OPF.
4. At settlement, if the dispatch set point for a particular resource is higher than its reference
output level, which implies that the resource needed to be incremented to resolve some
local constraint(s), the resource is compensated for the incremental amount at the greater
of (1) the LMP at the resource node or (2) the lesser of the resource bid or the Mitigation
Price Cap. The Mitigation Price Cap would be technology specific and set at a level to
recover the marginal cost of all resources in that technology class.
5. At settlement, if the dispatch set point for a particular resource is lower than its reference
output level, which implies that the resource needed to be decremented to resolve some
local constraint(s), the resource must pay for the decremental amount at the lesser of (1)
the LMP at the resource node or (2) the greater of the resource bid or the Mitigation Price
Floor. The Mitigation Price Floor would be technology specific and set at a level to
offset the marginal cost of all resources in that technology class.
The advantages of the automated ex ante market power mitigation mechanism are
40
•
ERCOT SMD-x can distinguish between changes in bidding pattern due to true legitimate
scarcity in the market as opposed to artificial scarcity of locational market power.
•
The proposed mechanism is a prospective structural solution built into the market design
rather than retrospective behavioral mitigation as currently applied for locational market
power exercises.
•
The ERCOT SMD x mitigation mechanism also eliminates the need for the RTO to
impose Reliability Must Run contracts on resources in order to control its locational
market power, thus reduced overall uplift in ERCOT.
ERCOT Market Design in terms of the FERC Standard Market Design, Shams Siddiqi, Ph.D.
104
•
The prospective nature of the proposed mechanism implies that market participants avoid
the regulatory risk and disruption to settlements and financial accounting caused by
refunds.
Figure 32: Zonal-ERCOT-Nodal Mitigation Measure
State
Estimator
Resource
specific bid
curves & ramp
Zonal
Transmission
Constraints
LMP
Reference
Prices
LMP
Dispatch
instructions
Mitigated
LMP Prices &
Dispatches
105
Local
Transmission
Constraints