Exhibit 99.428
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE
Second Annual Report to the Federal Energy Regulatory Commission
California Power Exchange Corporation
Market Compliance
July 28, 2000
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
Table of Contents
1.1 Monitoring of Electricity Commodity Exchanges...................................................... 6
1.2 Key Messages of This Report................................................................... 8
1.2.1 The Markets Work........................................................................... 8
1.2.2 The Importance of Focusing on Rules........................................................ 8
1.3 Institutional Structure for Monitoring CalPX Markets.......................................... 10
1.4 Activities of the Compliance Unit Over the Past Year.......................................... 11
2.1 Introduction........................................................................................ 13
2.2 Structure of California's Electricity System.................................................. 14
2.2.1 The Institutional Framework................................................................... 14
2.2.2 Description of Auction Process................................................................ 15
2.2.3 Characteristics of California's Market System................................................. 16
2.2.4 The Value of California Electricity Commodity Markets......................................... 17
2.2.5 CalPX Markets in Relation to the Competition Transition Charge................................ 19
2.2.6 CalPX Markets in Relation to the WSCC Power Markets........................................... 21
2.3 Review of Significant Market and Institutional Changes........................................ 22
2.3.1 The Growth and Rapid Maturation of the Block Forwards Market.................................. 22
2.3.2 RMR Contract Revisions........................................................................ 22
2.3.3 Ancillary Services Redesign................................................................... 22
Congestion Effects................................................................................... 22
2.4 CalPX Markets in Year Two..................................................................... 22
2.4.1 Day-Ahead Market - Operations.............................................................. 23
2.4.1.1 Overview of Price Trends in the Day-Ahead Unconstrained Market
from Year 1 to Year 2 of CalPX Operations............................................... 23
2.4.1.2 Day-Ahead Unconstrained Price and Quantity................................................ 30
2.4.1.3 Post Close Quantity Match.................................................................. 34
2.4.1.4 Zero-Price Supply Bids versus Market Clearing Quantity.................................... 38
2.4.1.5 Market Share of Participants.............................................................. 40
2.4.1.6 Supply Resource Mix...................................................................... 44
2.4.1.7 Congestion................................................................................ 46
2.4.1.8 Path 26 and New Zone ZP26............................................................... 51
2.4.1.9 Zonal Quantity Effects................................................................... 54
2.4.1.10. Financial Impact of Congestion........................................................ 54
2.4.2 Day-Of Market................................................................................. 56
2.5 The Relationship Between the CalPX Day-Ahead Market and other Markets............................... 61
2.5.1 Market Share of CAISO......................................................................... 61
2.5.2 Price Spreads................................................................................. 63
2.5.3 Correlation Between Markets................................................................... 65
2.5.4 Ancillary Services Prices and Volume.......................................................... 68
2.5.5 Block Forwards Market......................................................................... 71
2.6 Measures of Market Value...................................................................... 73
3.1 Introduction....................................................................................... 76
3.2 Fundamental Models of Price Movements.............................................................. 77
3.2.1 Introduction................................................................................... 77
3.2.2 The Basic Form of the Fundamental Price Analysis Model......................................... 77
3.3 Technical Models Concerning Price Behavior in CalPX Markets................................... 86
3.3.1 Technical Price Movements and What They Communicate........................................... 86
3.3.2 Price Mean Reversion........................................................................... 86
3.3.3 Price Spike Behavior........................................................................... 87
3.3.4 Market Volatility.............................................................................. 88
3.4 Analysis of the Uncoupling of Wholesale and Retail Price
Elasticity in California Electricity Markets.................................................... 87
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 3
3.4.1 Overview...................................................................................... 88
4.1 Introduction........................................................................................ 90
4.1.1 Being Methodical in the Early Phase of Market Operations................................... 90
4.2 Market Monitoring Methods and Practices............................................................. 91
4.2.1 Organization and Responsibilities of the Compliance Unit...................................... 92
4.2.1.1 Market Monitoring Group.................................................................... 93
4.2.1.2 Economic Analysis Group................................................................... 94
4.2.1.3 Investigations and Inquiries.............................................................. 94
4.3 The Role of Compliance in Policy-Making............................................................. 96
4.4 Establishment of Institutional Disciplinary Infrastructure......................................... 96
4.4.1 The Problem................................................................................... 96
4.4.2 Proposed Solution............................................................................. 97
4.4.3 Roles of the MMC and Compliance with regard to the BCC........................................ 97
4.5 Rules Changes...................................................................................... 98
4.5.1 Compliance's Recommendation................................................................... 98
4.5.2 Current Rules Changes Being Contemplated....................................................... 99
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 4
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE
Second Annual Report to the Federal Energy Regulatory Commission
Executive Summary
The California Power Exchange (CalPX) markets continue to work
effectively and add value to the marketplace.
The CalPX Day-Ahead Market grew from an annual volume in the first year
of 189,000 GWh to 193,890 GWh in the second year, increasing its annual
dollar volume from $5 billion to $6.3 billion. The volume of the Block
Forwards contracts has increased steadily since the inception of the
market, moving from a contract volume of 1900 MWh for August of 1999 to
4700 MWh for August of 2000.
The focus of the CalPX Compliance Unit (Compliance) is shifting from an
emphasis on market design to monitoring market behavior. This involves
focusing on rules, both violations of effective rules and changes in
ineffective rules, to ensure that price signals are accurate and
transparent. In turn, this best promotes sound decision-making by the
private sector to make California's electricity markets truly
competitive.
Given this focus on price behavior, Compliance has conducted several
studies, the conclusions of which are:
- Market price increases over the past two years can be largely
explained by changes in natural gas prices, weather, plant
availability, load forecasts, and lagged quantities and
prices. This indicates that CalPX Day-Ahead Unconstrained
Market Clearing Price (UMCP) has been fairly derived for the
first two years of market operations.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 5
- Although price spikes do occur, a Compliance mean reversion
model indicates that prices typically return to mean price
levels in less than two days. This is another indication that
CalPX markets are working fairly, with minimal signs of market
power.
Compliance was involved in several investigations and many more
inquiries into possible rules violations over the second year of
operation. This compares with no investigations in the first year. This
engagement in investigations has led Compliance to examine the original
rules setting forth Compliance activities and to recommend several key
changes that Compliance will be taking public for comment this year.
The primary change being sought is to assure due process to protect the
rights of Participants under investigation and the rights of the CalPX
to conduct investigations, thereby helping to promote fair and orderly
markets. Existing rules do not make these provisions. A new
disciplinary procedure and the establishment of a Participant-run
Business Conduct Committee (BCC) are the key points of this recommended
rule change.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 6
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE
Second Annual Report to the Federal Energy Regulatory Commission
1.0 Introduction
1.1 Monitoring of Electricity Commodity Exchanges
The Federal Energy Regulatory Commission (FERC), as part of its
approval of California's electric industry restructuring, ordered both
the California Independent System Operator (CAISO) and the California
Power Exchange (CalPX) to maintain ongoing surveillance of their
respective markets.(1) The FERC also ordered the monitoring functions
of each institution to cooperate, recognizing the integrated character
of the CAISO and the CalPX markets. In addition, the FERC required an
annual report on market activities.(2) FERC emphasized the importance
of market monitoring in its recent Order 2000 where each newly
established Regional Transmission Organization (RTO) is required to
implement market monitoring. In respect of the FERC's order and its
emphasis on the importance of market monitoring, the following report
is presented.
In its first report to FERC, the CalPX Compliance Unit (Compliance)
emphasized the responsibility commodity exchanges have to their
participants and to the public to ensure that the markets are fair and
efficient. This requires ongoing monitoring of trading activities and
evaluation of structural factors that may impede achieving full
efficiency in the market.
In its first year, Compliance focused on tracking price movements,
explaining the variances in price movements, and investigating specific
complaints concerning alleged violations of rules and alleged
intentions to manipulate abusively the CalPX and CAISO markets.
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(1) Federal Energy Regulatory Commission. Docket No. EC96-19-001, et. al..
October 30, 1997. pp. 239 and 246.
(2) Ibid p. 240
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 7
The second year of market operations placed new challenges before
Compliance to ensure that the CalPX markets are fair and efficient. Bid
behavior has become more diverse and, in some cases, subtler, requiring
more refined analytical tools to understand and explain that behavior.
Fundamental factors influencing the movement of prices changed
considerably over the last year, causing prices to increase. Evidence
of significant price increases examined only by descriptive techniques,
however, could lead to concerns that competitive markets may not be as
effective as envisaged by their designers. The inclination to suggest
market power abuse is seductive, but may be premature without a
thorough analysis of what is actually contributing to the price
increases.
Accordingly, Compliance has emphasized developing better tools to
enable more sophisticated analyses of fundamental factors influencing
price in the subtler bid environment evident in the second year of
market operations. Together, these enhanced monitoring techniques tell
a more reassuring story - that price increases are reflective only of
fundamental changes and periodic price spikes are generally short-lived
and show no indications of deliberate attempts to abusively influence
prices during these events. In CalPX markets at least, this indicates
no significant or persistent assertions of market power.
Great emphasis has been placed on congestion dynamics in California
markets and potentially significant changes will be introduced before
the end of 2000. The CAISO has already instituted many amendments to
its Tariff and Protocols during the second year of operation, including
revisions of the Reliability Must Run (RMR) contracts and its Ancillary
Services (AS) markets. These changes will be discussed as part of the
descriptive review of market activity in Section 2.
When California's markets initially opened, Compliance focused on
ensuring a good market start up, establishing the basic information
systems needed for general monitoring, and considering issues related
to market power. Market power concerns received significant attention,
as the Second Report of the CalPX Market Monitoring Committee (MMC)
amply demonstrated.(3) Evaluation of market power concerns remains an
important focus of Compliance, perhaps even more so for the MMC.
Through the first year, market monitoring was necessarily guided by the
hypotheses of various economic theories because a behavioral basis did
not exist for evaluating market activities. However, after more than
two full years of market operations, Compliance is now fundamentally
focused on the behavior of market Participants and the price signals
resulting from this behavior. For example, during this period
Compliance conducted a major investigation into abusive market behavior
and made inquiries into several less significant cases, some resulting
in a determination that abuses had not occurred although they had been
suspected. In addition, the data infrastructure and the scope of
information are now so significant that analysis can be developed to
deal with real behavior rather than hypothesized behavior, which has
limited use in explaining whether particular behaviors are abusive or
contribute to market inefficiencies.
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(3) Second Report on Market Issues in the California Power Exchange Energy
Markets of the MMC. Sections V, VI and VII.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 8
The challenge of developing more sophisticated analytical capabilities
required the addition of economic analysts with responsibilities for
this task. The need for better explanations of daily and weekly market
events also required adding staff as well. These staffing and
organizational changes are discussed in Section 4.
1.2 Key Messages of This Report
1.2.1 The Markets Work
In the past year, the CalPX has continued to add Participants, a sure
sign that the system is working and adds value to the electricity
marketplace. Participants increased from 39 at the start of operations
on March 31, 1998 to 68 Participants in July 1999 to a current level of
74. During the last year approximately 232,800 GWh of electric power
were traded in the CalPX Day-Ahead Market and the CAISO Ancillary
Services and Real-Time Markets, involving $7 billion of transactions on
the buy and sells sides for a total of $14 billion in dollar volume.
The Day-Of Market(4) grew from an annual volume of 400 GWh last year to
731 GWh this year, achieving an annual dollar volume of $21 million. In
October 1999 alone, CalPX settled close to $800 million in both
markets. This implies an ability to handle a total transaction volume
(both buy and sell side) at an annual rate of close to $20 billion. Not
only does the CalPX handle this large volume of transactions; it has
processed and settled this large volume from both markets with less
than one-tenth of 1% of the transactions being disputed - a remarkable
effort for a new exchange.
Two new products were created last year. The Block Forwards Market
(BFM) for trading monthly block forward energy contracts opened on June
10, 1999. It has grown during the past year to a current monthly
average of 1,982 contracts with a total dollar volume from inception to
March 31, 2000 of $245 million. The Post Close Quantity Match ("PCQM")
service has also grown. It started on July 28, 1999 and traded a volume
of 339,386 MWh during the past year for a total dollar volume of $7.78
million. Two new products launched last year, the Book Out service and
Green Exchange service, have thus far been unsuccessful.
1.2.2 The Importance of Focusing on Rules
The U.S. Department of Energy (DOE) in its report Horizontal Market
Power in Restructured Electricity Markets,(5) expressed concern that
monopoly power was being exercised in California:
There is strong evidence that market power has been exercised
in the electricity context. In both the United Kingdom (U.K)
and California, where data from competitive electricity
generation markets are now available, researchers have found
that wholesale power prices have been as much as 75 % above
competitive levels at times.(6)
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(4) Formerly the Hour-Ahead Market
(5) Horizontal Market Power in Restructured Electricity Markets, March 2000,
Office of Economic, Electricity and Natural ass Analysis, Office of
Policy, U.S. Department of Energy, Washington, DC 20585/
(6) Ibid, Executive Summary, p. v.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 9
Concern about market power is understandable given that electric power
restructuring involves trying to make natural monopolies competitive. A
recent Compliance analysis shows that virtually all price increases in
the past two years can be explained by underlying known factors such as
weather, natural gas prices, and forecasts. This leaves only a small
percentage of variance that cannot be explained at least in CalPX
markets. The resulting prices suggest that the markets are not
influenced by exertions of market power and that restructuring is
working.(7) In addition to showing that most price increases are
explainable, the study also notes that price spikes quickly revert to
the average for the time period - within two days. This provides strong
evidence that market power is not a serious phenomenon in California
under the DOE definition: "Market power is the ability of a supplier to
profitably raise prices above competitive levels and maintain those
prices for a significant time period."(8)
Compliance's analysis is summarized in Section 3.
Apart from the lack of evidence of market power, there is the question
of whether it can be effectively measured in a manner useful to the
needs of ongoing monitoring of multiple markets.
The Federal Energy Regulatory Commission (FERC), for instance,
describes the difficulties of measuring market power in its State of
the Markets 2000 paper:
All types of quantitative market power analysis depend
critically upon appropriate definitions of the relevant
market, in terms of their services being offered and
geographic scope. This is an extremely complex and difficult
step, and there are fundamental uncertainties and judgment
calls involved. However, quantitative analysis offers insights
which customer perceptions and evidence cannot provide,
especially in the area of anticipating the effect of changes
on the potential for the exercise of market power.(9)
Even with an understanding of the basic mechanisms of price
formation and behavior in network industries, the
interpretation of price data is extremely difficult and
remains subject to uncertainty. The commission is not in a
position to create definitive or automatic procedures for the
analysis and interpretation of price information."(10)
Even in recognizing the difficulties, the FERC emphasizes the
importance of monitoring market power abuses. Compliance agrees.
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(7) During periods of unusual events where price spikes rapidly develop,
suppliers with low production costs can certainly benefit significantly.
This opportunity for extraordinary profits are not necessarily (and in
CalPX market do not appear under any case) excess of market power. Price
spike events reflect both fundamental and technical factors that create
them, and, to some degree, psychological factors that contribute to price
run-ups. There will always be important public policy debate over whether
such excess profits are appropriate. The analyses presented here are
intended to report on what is observed. The social, moral, political and
judicial implications are for other to consider.
(8) Op. Cit. P. v
(9) State of the Markets 2000: Measuring Performance in Energy Market
Regulation, Federal Energy Regulatory Commission, March 2000, James J.
Hoecker, Chairman, p. 39.
(10) Ibid, p. 27.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 10
1.3 Institutional Structure for Monitoring CalPX Markets
The first report to FERC included a general description of the
institutional structure and associated responsibilities that pertain to
market monitoring at the CalPX. This framework remains largely
unchanged. For purposes of thoroughness, the following paragraphs are
updated from the first report.
The CalPX included as part of its Tariff and Protocol filings with the
FERC the establishment of an independent Market Monitoring Committee.
If the CalPX were a traditional membership exchange, the function of
the Committee would be an internal part of the operation of the
exchange and Participants of the CalPX would likely serve on this
Committee.
The MMC currently has three independent members. The CalPX Governing
Board elects each member for a three-year position on the Committee.
The terms are staggered so that at least one member is subject to
renewal or replacement annually. Committee members cannot consult to
nor have affiliations with any Participants in CalPX markets. They are
restricted in the use of any private information they obtain as members
of the Committee.
The Compliance Unit carries out the monitoring and analysis of market
behavior in the CalPX markets. The Unit currently has a Vice President
in charge and staff groups reporting to him - Market Monitoring and
Economic Analysis. In addition, an Acting Director of Investigations
has been established to work through the caseload developed over the
last year. Depending on the ongoing level of investigations, this
Acting Director may become a full-time position in the following year,
or it may be eliminated as unnecessary.
In addition to daily monitoring of markets, the Compliance staff is
responsible for developing fundamental analyses of markets, models and
methods of effective monitoring, and for carrying out investigations of
market abuse. When complaints are filed with Compliance or the MMC,
Compliance undertakes the appropriate inquiries. Also, Compliance may
initiate investigations if evidence of market abuse is detected or
developed through analysis.
Completed investigations are reported to the CalPX Chief Executive
Officer (CEO) and the Chairman of the MMC. Based on findings, the CEO
may refer the investigation to the Governing Board of the CalPX and/or
appropriate Federal authorities.
Experience in the second year revealed certain weaknesses in the
institutional configuration for market monitoring. Specifically, the
judicial processes associated with investigations are inadequate and
require refinements to ensure that Participants are fairly treated and
inquiries and investigations are not pursued for frivolous or less than
fully substantiated reasons. The need for a code of conduct and for
sanctions and penalties was amplified by the investigations activities
conducted in the second year of market operations. These matters are
discussed in Section 4.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 11
1.4 Activities of the Compliance Unit Over the Past Year
The Compliance Unit has been monitoring the California electricity
markets since April 1998. In accordance with the California Power
Exchange Market Monitoring and Information Protocol (PMMIP), Compliance
activities have focused on practices or behaviors deemed to be
detrimental to efficient and fair operation of the markets. As noted in
Section 2 of the Protocol, practices subject to scrutiny include, but
are not limited to:
- Anomalous market behavior.
- Withholding of capacity.
- Unexplained re-declarations of the availability of resources.
- Unusual transactions.
- Bidding patterns not consistent with market conditions.
- Unusual activities associated with imports and exports of
energy.
- Market design flaws.
- Abuse of Reliability Must-Run status.
- Gaming.
- Market structure flaws.
During the second year of operation, the Compliance Unit accomplished
the following:
- 365 daily market reports analyzing and explaining market
prices.
- Nine monthly reports to the MMC and the Chief Executive
(converted to quarterly reports beginning in the fourth
quarter of 1999).
- Ten meetings of the Market Monitoring Committee.
- Support to the MMC for its report to FERC in response to a
1999 order to address questions concerning RMR contract
redesign and Ancillary Services redesign.
- Ongoing review of anomalous results criteria. No anomalous
results were triggered in the second year of market
operations.
- Substantial enhancement in the data infrastructure to support
market monitoring, including revisions to the data warehouse,
creation of new data marts, significant upgrades in computers
and storage systems for monitoring purposes.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 12
- Conduct of required investigations.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 13
2.0 California's Electricity Market System
2.1 Introduction
This section describes California's electric power system in its second
year of restructuring. Significant changes in the system, some related
to CAISO market redesigns and revisions to its rules, have had impacts
on CalPX markets this past year and are also discussed.
The principal areas of change are:
- Revisions to CAISO Ancillary Services markets and Reliability
Must-Run contracts.
- Introduction of the rational buyer regime.
- Addition of a new zone associated with Path 26.
- Modifications in the settlements process.
- Introduction of the Block Forwards Market.
- Expansion of the Post-Close Quantity Match.
In addition, market conditions changed considerably between the first
and second year. Principally, these changes involve significantly
increased congestion and evidence of a bifurcation in the California
market system, likely caused by congestion effects. In Year 1, the
correlation in prices was high between the northern terminus and the
southern terminus of Path 15 (NP15 and SP15 respectively) and the
unconstrained market clearing price (UCMP). However, in Year 2, they
are largely not correlated. These changes have strategic and economic
implications for California markets.
This section will summarize the behavior of CalPX market prices,
comparing the second year to the first year. Subsequent sections will
analyze and explain the price behavior. It begins with a description of
the structure of California's market system, followed by a discussion
of the principal changes in the design of markets in California. Other
institutional changes and associated issues will be discussed to ensure
readers have a context in which to appreciate both the descriptive and
analytical sections that follow.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 14
2.2 Structure of California's Electricity System
As noted in the first annual report, California restructured its
utility industry through a complex stakeholder process that brought
diverse interests together to build a consensus vision of the future
electricity industry. While the process of redesign continues, the core
structure and operation of the CalPX is largely unchanged in the second
year of market operations.
Nevertheless, in the second year of operations, several key
developments occurred in the CalPX markets, including:
- Steady growth in valid hours of operation of the Day-Of Market
(discussed in Section 2.4).
- Remarkable growth in participation and in volumes in the CalPX
Block-Forwards Market (reported in Section 2.4).
- Broadening of the Post-Close Quantity Match (discussed in
Section 2.4).
The CAISO has actively continued to change key aspects of its
operations.(11) The changes made thus far and those changes
contemplated for the future will be discussed in this and following
sections.
2.2.1 The Institutional Framework
For ease of reference, the description of the institutional framework
defining California's restructured electric power system is adapted
from the first Compliance report.
The California wholesale electricity marketplace has two principal
components - a market of contracts executed directly between buyers and
sellers (referred to as the bilateral market) and buy-sell transactions
executed through organized commodity-exchange type markets (referred to
as exchange-based markets).
During the mandated transition period in California, investor-owned
utilities (IOUs) are required by law to buy and sell their electricity
through the CalPX(12). The CalPX is a commodity exchange for
electricity; it runs a Day-Ahead Market, a Day-Of Market, and a
Block-Forwards Market. The Day-Ahead Market is an auction system of 24
hourly markets, bid for simultaneously and cleared at the same time.
The Day-Of Market is composed of 24 auctions conducted in three batches
over the course of a day. These allow
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(11) Changes made by the California ISO are detailed in the California ISO
Annual Report on Market Issues and Performance, prepared by the CAISO
Market Surveillance Unit, June, 1999.
(12) As of June 8, 2000 the California Public Utility Commission (CPUC)
effectively altered the terms and conditions of the transition period. In
a 3 to 2 vote, the CPUC approved an alternate decision to that recommended
by the appointed administrative law judge in a case involving requests by
one of the investor-owned utilities to exit from the transition period
early because its CTC had been recovered. The alternate decision redefined
the transition period to allow for multiple exchanges as vehicles for CTC
recovery, subject to CPUC approval as a qualified trading vehicle. Because
the implications of this decision are unclear in terms of impact, or the
effective timing of the emergence of alternative qualified trading
vehicles to the California Power Exchange, the discussion of the
transition period and the associated structure does not incorporate
consideration of this significant change in its terms and by implication
its duration.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 15
buyers and sellers to adapt to unexpected circumstances occurring the
day in which power is being delivered based on the preceding Day-Ahead
auction. The Block-Forwards Market began operating June 10, 1999, and
consists of a forward contract of 16 on-peak hours, traded in multiples
of 1 or 25 MWs. It allows participants to realize the benefits of
forward contracts while also participating in the efficient and
transparent CalPX Day-Ahead and Day-Of markets where delivery and
settlement are arranged.
The CalPX is also a Scheduling Coordinator (SC). SCs were established
as part of the California system to manage the transmission assets of
California's IOUs. SCs are qualified by the CAISO to submit balanced
schedules of electricity supply and demand for use of the transmission
network the CAISO administers. Access to the CAISO transmission network
is restricted to SCs.
The CAISO manages the transmission network in real time. Its mission is
to ensure at least as high reliability as the transmission owners
provided prior to its formation. Market mechanisms are used to ensure
continuously high reliability. To this end, the CAISO runs a Real-Time
Market, an auction that runs every 10 minutes around the clock, but is
settled hourly. This auction's purpose is to enable the CAISO to
acquire the power needed to ensure that the system stays in balance and
operates reliably.
System reliability is derived from various forms of reserves as well.
These are obtained through acquisition of capacity in four markets
referred to generically as the Ancillary Services (AS) Markets,(13) and
through contracts for system regulation and system reliability power
supply. The four generic Ancillary Services Markets are (1) Spinning
Reserves, (2) Non-Spinning Reserves, (3) Regulation and (4)
Replacement. In addition, the CAISO obtains local reliability related
resources through Reliability Must-Run contracts.(14)
Both the CalPX and the CAISO were created by the California Legislature
and operate as not-for-profit public benefit corporations under
California law. The Governing Board of each institution is made up of
stakeholders. Board members are asked to function as true corporate
board members, not as representatives of their constituents.
Assembly Bill 1890 established the Electricity Oversight Board (EOB) so
the State of California could retain an ongoing involvement in the new
electric market system. The Governor appointed the initial Electricity
Oversight Board, which then elected the original Governing Board
members for both the CAISO and the CalPX.
2.2.2 Description of Auction Process
Prior to 7 a.m., buyers and sellers submit to the Day-Ahead Market
their final portfolio energy supply and demand bids for each of the
next 24 hours. These bids are used to determine the intersection
between supply and demand, which sets the overall market-clearing price
and quantity. The auction for each of the 24 hours is conducted
individually. About 7:15 A.M., the CalPX notifies successful bidders of
the hourly market-clearing prices and quantities they were awarded.
- ------------
(13) The FERC in its July 17, 1998 order said that Replacement was not an
Ancillary Service.
(14) On April 2, 1999, a partial settlement to revise the structure of
Reliability Must-Run contracts was filed to the FERC in Docket ER98-441 et
al.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 16
By 9 a.m., generating (supply) participants submit to the CalPX their
Initial Preferred Schedules, providing details of the specific
generating units, imports, exports, SC transfers, and loads that
fulfill the aggregate awards from the auction. At this time, all
participants also submit their Schedule Adjustment Bids for inter-zonal
transmission congestion. By 9:30 a.m., generating participants submit
their bids for Ancillary Services.
By 10 a.m., the CalPX and other Scheduling Coordinators submit to the
CAISO their Initial Preferred Schedules for participants who have been
scheduled, along with Schedule Adjustment Bids and Ancillary Services
bids.
By 11 a.m., the CAISO completes the first iteration of its Congestion
Management across the various well-defined transmission zones. If no
inter-zonal congestion exists, the CAISO issues Final Day-Ahead
Schedules, including the schedules for Ancillary Services selected in
the CAISO's Ancillary Services auction. On the other hand, if
congestion occurs, the CAISO provides CalPX and other Scheduling
Coordinators with the estimated Day-Ahead Transmission Usage Charges, a
suggested Adjusted Day-Ahead Schedule, and a preliminary schedule and
prices for Ancillary Services.
By noon, if inter-zonal congestion exists, the CAISO permits Scheduling
Coordinators to submit Revised Preferred Day-Ahead Schedules. The CalPX
does not change the CAISO's adjusted Day-Ahead energy schedule that is
received by 11 a.m.. At 1 p.m., the CAISO performs the second iteration
of its congestion management establishing the Final Day-Ahead
Schedules, including the schedules and prices for Ancillary Services,
and the final Day-Ahead Transmission Usage Charge rates. Approximately
15 minutes later, the CalPX provides the hourly market-clearing prices
for all the congestion zones.
At approximately 1:30 p.m., the CAISO determines whether the Ancillary
Services auctions have any deficiencies and also evaluates Reliability
Must-Run requirements relative to the Final Day-Ahead Schedules.
The Day-Ahead Market process ends at approximately 5 p.m. when the
CAISO notifies participants of any changes in the Final Day-Ahead
Schedules. These changes may result from shortfalls in Ancillary
Services or from generation requirements for Reliability Must-Run.
2.2.3 Characteristics of California's Market System
The California energy auction process has two characteristics. First,
the CalPX, the CAISO and other Scheduling Coordinators interact closely
in matching participants' generation and loads and transmission needs.
Second, the adjustment process follows the bidding process. The CalPX
participants allocate their generation capacity according to their
perceived opportunity costs. The CalPX Market Monitoring Committee has
described the consequence of this sequencing:
Most participants will be eligible to bid in several of the
markets. The exact sequence of bids and market responses
affects how they will bid. Bids in the Day-Ahead energy market
are accepted before bids in the AS markets need to be placed.
If generators want to offer a larger quantity in any AS
market, they must offer a smaller amount of their given
capacity in the Day-Ahead market. They can implement this
directly, or they can offer the smaller quantity at
"reasonable" prices,
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 17
and then offer the rest at very high prices. Once the
Day-Ahead market results are revealed at 7:15 a.m., the
generators know how much capacity they actually can offer to
the AS markets.
By bidding for some of its capacity at a price sufficiently higher than
the predicted market-clearing price, a generation participant can be
assured that this capacity will not be awarded in the Day-Ahead Market.
The capacity will then be available for bidding in the later markets as
the participant follows the auction sequence. Holding capacity for this
later bid has the effect of reducing supply and therefore increasing
price in the Day-Ahead Market. This creates an inherent linkage among
the markets: capacity sold in an earlier-closing market is not
available for a later-closing market, and capacity held back to be bid
later is not available in an earlier market.
2.2.4 The Value of California Electricity Commodity Markets
The market structure in California is composed of seven distinct active
markets interacting in varying degrees under different
circumstances.(15) Table 1 and 2 below summarize the size of the
markets in each year of operation.(16)
- --------------
(15) If the four CAISO Ancillary Services markets for Hour-Ahead were included,
there would be 11 markets.
(16) See Appendix __ for details on how market values were calculated.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 18
TABLE 1: CALIFORNIA'S WHOLESALE ELECTRICITY MARKETS: APRIL 1998 - MARCH 1999
Market Annual Volume Annual Average Price Annual Dollar
(GWh) Volume
($ million)
-------------------------------------------------------------------------------
CalPX Day-Ahead 189,000 $24.44/MWh $5,033
CalPX 400 $29.34/MWh $21
Day-Of/Hour-Ahead(17)
CAISO Real-Time 10,000 $25.62/MWh(NP15) $296
$23.54/MWh (SP15)
CAISO AS - Spin 6,700 $13.43/MW $90
CAISO AS - Non-Spin 5,500 $7.27/MW $40
CAISO AS - 14,800 $34.0/MW $500
Regulation\
CAISO AS - 5,000 $13.80/MW $69
Replacement
Block Forwards
-------------------------------------------------------------------------------
Total 231,400 ---- $6,049
-------------------------------------------------------------------------------
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(17) Day-Of/Hour Ahead data are annualized. The market opened on August 1,
1998. Eight months of volume and value were divided by 8 and multiplied by
12. Average price was kept the same.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 19
TABLE 2 CALIFORNIA'S WHOLESALE ELECTRICITY MARKETS: APRIL 1999 - MARCH 2000
Waiting on ISO confirmation of volumes and prices for Real-time and AS
Market Annual Volume Annual Average Annual Dollar
(GWh) Price Volume
($ million)
-------------------------------------------------------------------------------
CalPX Day-Ahead 193,890 $32.43/MWh wgt. $6,288
Avg.
CalPX Day-Of/Hour-Ahead(18) 731 29.26 $21
CAISO Real-Time 2,000 NP 30.46/MWh 60
SP 29.52/MWh
CAISO AS - Spin 7,300 7.03/MWh 51
CAISO AS - Non-Spin 6,915 4.00/MWh 28
CAISO AS - Regulation 13,181 20.03/MWh 264
CAISO AS - Replacement 2,873 6.07/MWh 17
Block Forwards 5,940 $41.35/MWh $245
-------------------------------------------------------------------------------
Total 232,830 6,974
-------------------------------------------------------------------------------
Waiting for Settlement data
The CalPX received administrative fees totaling $XXXX for the period
April 1, 1999 through March 31, 2000.
2.2.5 CalPX Markets in Relation to the Competition Transition Charge
The Competition Transition Charge (CTC) remains a critical element in
the operation of CalPX during the transition period. While CalPX
markets have diversified and grown beyond merely functioning as a
mechanism for stranded cost recovery, this remains an important
function the institution performs through the transparency of its
markets. The discussion below is, again, extracted from the first
report because it is important to have a clear understanding of the
role of CTC recovery and how it works.
CTC is defined in detail in Section 367 of AB 1890:
The commission [California Public Utilities Commission (CPUC)]
shall identify and determine those costs and categories of
costs for generation-related assets
- ------------
(18) Day-Of/Hour Ahead data are annualized. The market opened on August 1,
1998. Eight months of volume and value were divided by 8 and multiplied by
12. Average price was kept the same.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 20
and obligations, consisting of generation facilities,
generation-related regulatory assets, nuclear settlements, and
power purchase contracts, including, but not limited to,
restructuring, renegotiations or terminations thereof approved
by the commission, that were being collected in
commission-approved rates on December 20, 1995, and that may
become uneconomic as a result of a competitive generation
market, in that these costs may not be recoverable in market
prices in a competitive market, and appropriate costs incurred
after December 20, 1995, for capital additions to generating
facilities existing as of December 20, 1995, that the
commission determines are reasonable and should be recovered,
provided that these additions are necessary to maintain the
facilities through December 31, 2001.
Section 367 addresses the stranded costs associated with restructuring.
Stranded costs are defined as generation plants approved by the CPUC
and built to serve the monopoly franchises held by IOUs prior to
restructuring that no longer hold a value at least equal to their
costs. AB 1890 accepted the prevailing argument concerning stranded
costs that without compensation IOU shareholders would have unfairly
shouldered the burden of associated losses when regulatory approvals
had been granted and plants built and placed in service for the benefit
of customers. The CTC allows for IOU recovery of such stranded costs.
AB 1890 allows for CTC to be collected from customers to offset these
costs, but only until December 31, 2001, with certain exceptions also
detailed in the law.
The CalPX is central to the collection of the CTC. As part of
restructuring, electricity rates were reduced by 10% and frozen at that
level until all of the CTC is collected or December 31, 2001, whichever
comes first. A CTC charge is shown on customer bills. The CTC charge,
however, is not fixed.(19) It fluctuates because it is the difference
between the rate cap and the utility's cost of buying power at the
CalPX (plus other charges such as transmission and distribution costs).
If the CalPX price goes up, the CTC is recovered more slowly because
electricity rates to the customer cannot change. If the CalPX price
goes down, the CTC is recovered more rapidly. The IOUs are obligated by
the CPUC and the FERC to sell and buy all their power through the CalPX
for a fixed transition period.(20) Stakeholders have various views on
the duration of the transition period. Some argue it ends at December
31, 2001, others that it ends when the CTC is fully collected.
One IOU, San Diego Gas & Electric (SDG&E) recovered its CTC earlier
than expected. Others may as well. One reason for this is that IOU
generation plants sold at higher than expected multiples of book value.
Consequently, the size of total CTC will be smaller, i.e., the IOUs
will be facing smaller losses, or, in some cases, earning profits, on
the sale of generating assets. Also, plant divestiture is proceeding at
a fast pace. For example,
- ---------
(19) The CTC calculation method was ordered by the California Public Utilities
Commission in D.97-08-056, Order 12.c., p. 65. It is calculated residually
by subtracting from the applicable rate all other charges, i.e.
distribution, generation, transmission, public purpose charges, and any
other surcharges. It is calculated for a specific time frame (e.g. weekly
or monthly) on an ex post basis as a rolling average for each time of use
period in a customer's billing period. Generation costs are based on an
average CalPX price. Averaging is done first on a weekly basis and then a
rolling average of usually four weeks is calculated to cover the different
monthly billing cycles for different customers. This total amount is
divided by the total number of hours for the time-period used to yield an
average hourly CTC charge. Details of how the charge is calculated, and
the reasoning behind the method chosen, can be found in Section VIII.B.1
of D.97-08-056.
(20) See, e.g., California Public Utilities Commission, D. 95-12-063, December
20, 1995 as modified by D. 96-01-009; 77 FERC p.61, 265.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 21
SDG&E, completed the sale of its fossil fuel plants late in 1998 and
terminated its rate freeze as of July 1999.
The significance of the collection of the CTC for the Day-Ahead Market
is important. At least during the transition period, the true impact of
the Day-Ahead Market on value actually exceeds its aggregate annual
value measured in dollar volume. CTC recovery alone makes this so. The
initial CPUC rate filings of California's IOUs estimated the total CTC
to be approximately $27 billion.(21)
Further, the CalPX market also influences, through contracts that use
CalPX prices as reference points, electricity prices throughout the
western United States, a power market of approximately 742 TWhs per
year.(22)
2.2.6 CalPX Markets in Relation to the WSCC Power Markets
In the two years since the opening of the CalPX markets, power trading
in the western states has evolved to adapt to the establishment and
effective operation of a deep and liquid commodity exchange for
electric power.
Prior to the restructuring in California, the Western Systems
Coordinating Council (WSCC) power markets were exclusively bilateral -
i.e., transactions took place between buyers and sellers without the
involvement of intermediaries, or multi-party transactions were
organized through a power-marketing intermediary, but not executed on a
formal commodity exchange.
In the past two years, exchange-based markets have been integrated into
the broader western states system in several ways:
- Northwest and Southwest buyers make use of CalPX markets not
only as demand centers offering opportunities for the sale of
power, but as a ready supply center during periods of high
demand in their own regions. Also these regions, in particular
the Northwest, rely on CalPX markets for unexpected supply
needs.
- Power marketers are using CalPX prices as reference or index
prices for their bilateral contracts, throughout the West.
- Traders and brokers are entering CalPX markets performing, de
facto, the role of market makers and speculators, especially
during periods of high market volatility and uncertainty.
- Bilateral traders are using all CalPX markets, and associated
liquidity, coupled with systematic exploitation of congestion
patterns in California (fully risk hedged through various
financial instruments) in the development
- ----------
(21) PG&E (Application 96-08-070) $11.4 billion, SCE (Application 96-08-71)
$13.8 billion, SDG&E (Application 96-08-072) $2.0 billion. Total $27.2
billion. The numbers reported most often in the press are $28 billion and
$28.5 billion, which were from the original filings. These were reduced
slightly where they did not conform to AB1890. As stated in the text, the
sales prices of plants could make the actual figure smaller.
(22) Source is WSCC Summary Information for 1998 at www.wscc.com/ wscc.pub.htm.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 22
and management of their portfolios. In other words,
exchange-based markets have been largely integrated into a
broadened trading system in the West.
While CalPX prices are having an impact throughout the western United
States, the Must-Buy/Must-Sell provisions of AB 1890 focused most of
the trading activity in California. Creating the CAISO placed an
additional institution between out-of-state users of California
transmission and California generators and buyers. Nevertheless,
California is firmly linked financially, as evidenced by the
aforementioned indexing to CalPX prices and the presence of marketers
who trade in CalPX markets as well as actively throughout the West.
2.3 Review of Significant Market and Institutional Changes
Several significant market and institutional changes occurred in the
second year of operations. These include:
- The growth and rapid maturation of the Block Forwards Market.
- The revision of RMR contracts and Ancillary Services markets
by the CAISO.
- The significant increase in congestion.
- These changes are discussed below.
2.3.1 The Growth and Rapid Maturation of the Block Forwards Market
[PLACE HOLDER]
2.3.2 RMR Contract Revisions
[PLACE HOLDER]
Report on Wolak study and MMC study, note differences, etc.
2.3.3 Ancillary Services Redesign
[PLACE HOLDER]
Congestion Effects
[PLACE HOLDER]
2.4 CalPX Markets in Year Two
This section describes in detail the price patterns and associated
characteristics of CalPX markets. The emphasis is on the second year of
market operations compared to the first year, and, in some cases,
cumulative two-year patterns.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 23
2.4.1 Day-Ahead Market - Operations
2.4.1.1 Overview of Price Trends in the Day-Ahead Unconstrained Market from
Year 1 to Year 2 of CalPX Operations
Prices changed significantly between the first and second year on a
nominal basis, reflecting a fairly dramatic upward movement. But almost
all of the increase in price is explained by fundamentals. Stripped
away, the unexplained variance in prices is small and appears to have
contributed nothing to the trends.
The Day-Ahead unconstrained market averaged $24.44/MWh for the first
year of operation covering the period from April 1, 1998 to March 31,
1999. The second year of operation, from April 1, 1999 to March 31,
2000, saw an increase in the average price to $30.90/MWh a 26%
increase. The maximum price was higher in the second year of operation
by $34/MWh, reaching $225/MWh. However, the standard deviation of the
price was lower in the second year by 15%, indicating less volatility
in the market.
FIGURE 1 DAY AHEAD UNCONSTRAINED MARKET CLEARING PRICE
[BAR CHART]
The UMCP is primarily influenced by several external factors including
temperature, load forecast, natural gas price, and resource
availability. Temperature and resource availability are more likely to
influence short-term price spikes for hours or days, while load
forecast and natural gas prices have greater influence on trends over
months or years.
A comparison of the monthly average UMCP for the first year and second
year of operation is shown in Figure 1. The average price for Year 2 is
higher in all months except July and August of 1999. Significant events
can be identified during the first two years that generally explain the
rise in the average price. For example, in May and June of 1998, the
oceanographic phenomenon called "El Nino" resulted in a surplus of
hydroelectric generation in California and about 150 hours with a UMCP
of $0/MWh. July and August of 1998 were extremely hot with average
temperatures seven degrees
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 24
above normal. The UMCP for October 1999 averaged 78% greater than
October of 1998 also because of unseasonably warm temperatures.
Compounding the unusually high load in October 1999 were three
additional factors: (1) an outage of Diablo 2 nuclear unit for the
entire month, (2) an increase on October 1, 1999 of the CAISO price cap
to $750 from $250, and (3) frequent and severe congestion on Path 15.
From January through March of 2000, the average UMCP prices were about
50% higher than the same months the year before. This higher UMCP for
the first three months of 2000 corresponds to proportionally higher
prices of natural gas. In addition, there was significantly less
hydroelectric power availability in January and February 2000.
The external factors that influenced prices in the Day-Ahead
unconstrained market will be described in more detail below.
FIGURE 2 PRICE DURATION CURVE
[LINE CHART]
The price duration curve shown in Figure 2 indicates that for
approximately 95% of the time, the Year 2 prices were higher than the
Year 1 prices by about $6/MWh. However, Year 1 appears to be more
volatile as seen by the greater number of high priced hours. Prices
were greater than $100/MWh in Year 1 for approximately 97 hours
compared to only 60 in Year 2. At the highest price range, prices were
above $150/MWh for only 42 hours in Year 1 but only 20 in Year 2. This
corresponds to the higher standard deviation for Year 1 as seen in
Figure 1
TEMPERATURE
Temperature spikes account for most of the price spikes in the
Day-Ahead unconstrained market. The number of other external factors
experienced at the same time has a compounding effect and greatly
influences the magnitude of the price spike. As temperatures approach
the 100 degree mark, the Day-Ahead market inevitably reaches
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 25
high price levels. The longer the heat wave, the higher the price
spike. In general, however, temperature spikes and price spikes do not
last more than a few days.
Figure 3 shows Year 1 of operations. The summer of 1998 experienced
four heat waves where daily maximum prices exceeded $150/MWh.
FIGURE 3 YEAR 1 DAILY UMCP RANGE VS. TEMPERATURE
[LINE CHART]
Severe cold weather can also create a price spike in the Day-Ahead
unconstrained market. The West Coast was overwhelmed by a cold front
for the five days before Christmas of 1998. Heating load was high in
California. Compounding the impact of the cold weather was an outage of
the Diablo nuclear unit. Also contributing to the high UMCP prices was
the high price of natural gas, prices peaked at about $7/MMBtu, due to
high demand in Northern California and the Pacific Northwest.
Figure 4 shows the relationship between UMCP and temperatures for Year
2 in which six episodes of price spikes above $100/MWh occurred. The
three summer spikes occurred at the beginning and end of the summer.
Three of the spikes occurred in October 1999. Although more frequent
episodes occurred in Year 2, the spikes were of shorter duration and
generally less severe.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 26
FIGURE 4 YEAR 2 DAILY UMCP RANGE VS. TEMPERATURE
[LINE CHART]
FORECAST LOAD
Figure 5 shows that the CAISO load forecast for Year 1 was consistently
lower than the load forecast for Year 2. The exception to this
observation is for the months of July and August 1998 when California
experienced an exceptionally hot summer. Year 2 forecast load was an
average of 3.7% higher than Year 1 forecast load, reflecting the
general economic growth in California.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 27
FIGURE 5 CAISO FORECAST LOAD - HOURLY AVERAGE BY MONTH (MWH)
[BAR CHART]
NATURAL GAS PRICE
Conventional natural gas fired generating units total over 18,000 MWs
in the state of California. PG&E Citygate prices are used to represent
the price of gas for approximately 6,200 MWs located in NP15 and ZP26.
SoCal Gas Citygate index prices are used to represent the 11,800 MWs
located in SP15. Figure 6 shows the monthly average gas prices at the
Citygate of the Southern California Gas Company and Pacific Gas and
Electric as reported by the industry publication, Gas Daily. These
figures display the increase in the gas price from Year 1 to Year 2.
The increase is as great as 50% from March 1999 to March 2000. The
increase in gas price is reportedly due to a decrease in natural gas
production as a result of lower prices in the first year and an
inability to quickly ramp up to meet high demand levels this year. The
high gas prices in the year 2000 do not appear to be the result of
natural gas storage inventory levels because the western region is in a
relatively healthy storage position.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 28
FIGURE 6 NATURAL GAS PRICES ($/MMBTU)
[SoCalGAS BAR CHART] [PG&E BAR CHART]
RESOURCE AVAILABILITY
The availability of certain types of resources can have a significant
impact on market clearing prices. About 6,000 MWs of nuclear and coal
units are scheduled through CalPX. In addition, Qualifying Resources
(QF), which are FERC-designated alternate or renewable resources, also
supply a considerable amount of energy. These base load resources
represent more than half of total supply to the CalPX Day-Ahead energy
market. Most of the energy from these units are must-run and therefore
bid as a price taker. An outage of these units would require that the
energy be replaced with higher cost gas or imports. Figure 7 shows the
average mix of resources by category and by month based on Final
Schedules (after congestion management).
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 29
FIGURE 7 - RESOURCE MIX BY TYPE - HOURLY AVERAGE BY MONTH (MW)
[BAR CHART]
Several periods of either planned or forced outages of nuclear
resources had a significant impact on market clearing prices. These
periods include one week in December 1998 when California and the
Pacific Northwest experienced a cold front and prices soared to
$164.63/MWh. Also, an outage of Diablo 2 (1,090 MW) in October 1999,
combined with unseasonably warm weather, caused several spikes above
$100/MWh and a monthly average of $47/MWh.
The availability of hydroelectric resources also has a significant
impact on market clearing prices. From Year 1 to Year 2, energy
scheduled from hydro resources decreased 23%. The effect of El Nino
contributed to the abundance of hydro energy in the May through June
1998 period, resulting in nearly 150 hours of a $0/MWh market-clearing
price. The impact of El Nino continued through mid-summer somewhat
mitigating the effect of the hot summer of 1998. Hydro resources again
had a significant impact on prices in the beginning of 2000. The
drought experienced in January and February of Year 2 contributed to
average prices for these months nearly 50% higher than in Year 1. The
reduction of hydro resources results in greater reliance on higher cost
gas and import resources. Together, these two resources increased by
34% from Year 1 to Year 2.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 30
In summary, the price trends from Year 1 to Year 2 in the CalPX
Unconstrained Day-Ahead market appear to be highly influenced by
external factors such as temperature spikes, increased demand, higher
gas prices, and resource availability. Often, the price spikes are
magnified when combinations of these factors occur simultaneously along
with market conditions such as transmission constraints and market
design or structural changes. As will be described later, Compliance
statistical model has determined that these fundamental external
factors explain approximately 88% of the price trends in this market.
2.4.1.2 Day-Ahead Unconstrained Price and Quantity
Figure 8 shows the hourly average Day-Ahead Unconstrained Price and
Quantity for the two years of the market beginning from the launch of
the market on April 1, 1998 to March 31, 2000.
FIGURE 8 DAY-AHEAD HOURLY AVERAGE MCP AND MCQ
[BAR CHART]
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The largest increase in average price occurred in the off-peak hours
which include the hours from 11:00 p.m. - 6:00 a.m. Monday through
Saturday, all day Sunday, and holidays. From Year 1 to Year 2, off-peak
prices increased an average of 39% compared to the 26% increase in all
hours.
Figure 9 and Table 3 show the increase in the off-peak prices was the
largest during the May through June period when 1999 prices were nearly
triple the 1998 off-peak prices. Off-peak price began a consistent
trend of higher prices starting in October 1999, which coincided with
the increase in natural gas prices and an outage of Diablo 2.
FIGURE 9 MONTHLY AVERAGE, ON-PEAK, AND OFF-PEAK PRICES ($/MWH)
[BAR CHART]
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 32
TABLE 3 WEIGHTED AVERAGE MONTHLY PRICES ($/MWH)
Year 1 Year 2 % Change from Year 1
Wgt Avg. Wgt Avg. Wgt Avg.
ALL HOURS UMCP UMCP UMCP UMCP UMCP UMCP
- -----------------------------------------------------------------------------------------
April $ 22.60 $ 23.32 $ 24.01 $ 24.67 6% 6%
May $ 11.65 $ 12.50 $ 23.61 $ 24.74 103% 98%
June $ 12.09 $ 13.25 $ 23.52 $ 25.76 95% 94%
July $ 32.42 $ 35.58 $ 28.92 $ 31.52 -11% -11%
August $ 39.53 $ 43.42 $ 32.31 $ 34.71 -18% -20%
September $ 34.01 $ 36.96 $ 33.91 $ 35.16 0% -5%
October $ 26.65 $ 27.28 $ 47.64 $ 49.00 79% 80%
November $ 25.74 $ 26.45 $ 36.91 $ 38.29 43% 45%
December $ 29.13 $ 29.98 $ 29.66 $ 30.16 2% 1%
January $ 20.96 $ 21.65 $ 31.18 $ 31.78 49% 47%
February $ 19.03 $ 19.59 $ 30.04 $ 30.40 58% 55%
March $ 18.83 $ 19.31 $ 28.80 $ 29.27 53% 52%
Total $ 24.44 $ 26.63 $ 30.90 $ 32.43 26% 22%
Year 1 Year 2 % Change from Year 1
Wgt Avg. Wgt Avg. Wgt Avg.
ON-PEAK UMCP UMCP UMCP UMCP UMCP UMCP
- ------------------------------------------------------------------------------------------
April $ 26.16 $ 26.36 $ 27.63 $ 27.77 6% 5%
May $ 16.72 $ 17.03 $ 29.50 $ 29.87 76% 75%
June $ 16.63 $ 17.31 $ 30.53 $ 31.95 84% 85%
July $ 42.47 $ 44.35 $ 36.86 $ 38.29 -13% -14%
August $ 50.55 $ 53.74 $ 38.94 $ 40.29 -23% -25%
September $ 41.44 $ 44.44 $ 38.40 $ 39.02 -7% -12%
October $ 29.92 $ 30.12 $ 53.47 $ 54.23 79% 80%
November $ 29.59 $ 29.86 $ 41.39 $ 41.87 40% 40%
December $ 31.74 $ 32.39 $ 32.14 $ 32.39 1% 0%
January $ 24.33 $ 24.57 $ 34.33 $ 34.53 41% 41%
February $ 22.07 $ 22.22 $ 32.11 $ 32.16 45% 45%
March $ 21.54 $ 21.64 $ 31.58 $ 31.63 47% 46%
Total $ 29.49 $ 31.51 $ 35.58 $ 36.59 21% 16%
Year 1 Year 2 % Change from Year 1
Wgt Avg. Wgt Avg. Wgt Avg.
OFF-PEAK UMCP UMCP UMCP UMCP UMCP UMCP
- ---------------------------------------------------------------------------------------------
April $ 17.73 $ 18.14 $ 19.07 $ 19.42 8% 7%
May $ 5.75 $ 5.98 $ 16.77 $ 17.20 192% 188%
June $ 5.89 $ 6.40 $ 13.94 $ 14.91 137% 133%
July $ 20.73 $ 22.07 $ 19.70 $ 20.62 -5% -7%
August $ 25.54 $ 26.46 $ 23.90 $ 24.93 -6% -6%
September $ 24.72 $ 25.21 $ 27.78 $ 28.32 12% 12%
October $ 22.12 $ 22.47 $ 40.24 $ 40.94 82% 82%
November $ 21.35 $ 21.71 $ 31.31 $ 32.70 47% 51%
December $ 24.81 $ 25.24 $ 26.78 $ 27.18 8% 8%
January $ 17.36 $ 17.85 $ 27.50 $ 27.85 58% 56%
February $ 15.35 $ 15.68 $ 27.24 $ 27.46 77% 75%
March $ 15.07 $ 15.37 $ 24.95 $ 25.29 66% 65%
Total $ 17.99 $ 18.89 $ 24.95 $ 25.78 39% 36%
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 33
While CAISO load forecast increased by an average of 3.6% from the
first year to the second year, the average Day-Ahead MCQ increased by
only 2.3%. This indicates that the difference in demand was satisfied
in the Day-Of Market or the Real-Time Market. Alternately, the
increased CAISO load forecast is a result of non-IOU demand supplied
outside the CalPX Day-Ahead auction. In any case, the ISO Load Forecast
and the CalPX Day-Ahead MCQ are highly correlated with a correlation
value of 0.94.
As shown in Table 4, the Hourly MCQ increased by an average of only 500
MW from Year 1 to Year 2. The annual peak demand of 34,811 MW for Year
2 was actually lower by 1,568 MWs from Year 1 due to the mild summer of
1999. The largest difference between Year 1 and Year 2 occurred in
October and November when the volume increased by 8% and 10%,
respectively in Year 2.
TABLE 4 DAY-AHEAD MARKET CLEARING QUANTITY
HOURLY AVERAGE MCQ BY MONTH (AVG MW)
Month Year 1 Year 2
- ----------------------------------------------------
April 19,913 19,778
May 19,050 19,924
June 21,398 21,934
July 25,393 25,459
August 25,900 25,823
September 23,792 23,768
October 21,170 22,848
November 20,792 22,850
December 21,460 21,721
January 20,309 21,125
February 19,533 19,725
March 20,027 19,812
Average of DAY AHEAD MCQ 21,579 22,077
Max of DAY AHEAD MCQ 36,376 34,811
Min of DAY AHEAD MCQ 14,542 13,879
StdDev of DAY AHEAD MCQ 3,830 3,887
PEAK DEMAND BY MONTH (MW)
Month Year 1 Year 2
- ------------------------------------------
April 24,847 24,175
May 23,008 25,988
June 28,499 31,600
July 35,774 34,459
August 36,376 34,811
September 33,584 30,550
October 25,625 29,276
November 26,014 27,781
December 26,332 27,151
January 25,611 26,786
February 24,309 24,532
March 24,390 24,383
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 34
As seen in Figure 10, the hourly MCQ falls between 16,000 MWh to
24,000 MWh for 75% of the hours.
FIGURE 10 MCQ DISTRIBUTION
[BAR CHART]
2.4.1.3 Post Close Quantity Match
The PCQM, or Post Close Quantity Match, was created to give
Participants a chance to round the quantity of their positions
scheduled in the CalPX markets after the initial market auction. In
this way, the CalPX Post Close period matches other commodity exchanges
such as the New York Mercantile Exchange and the Chicago Board of
Trade. In each of these exchanges (including CalPX), the Post Close
gives traders a chance to fill any bids unfilled at the close of the
market.
The PX differs, however, from other commodity exchanges in several
ways, making it necessary to customize this tool specifically to the
needs of market Participants. One unique difference is the inelasticity
of the buyer. Retail buyers do not receive price signals from the
market in time to make informed buying decisions. Sellers are able to
make timely and informed decisions based upon the wholesale market
price relative to the cost to produce. Until a market exists where
demand is more price-responsive, special measures are taken to ensure
that sellers do not take unfair advantage of buyers
Because the two sides of the California Electricity Market cannot be
equally price responsive, the PCQM has certain limitations to prevent
gaming opportunities. The most significant limitation is a bandwidth,
which dictates the quantity that each Participant is allowed to bid
into the PCQM for each hour. The schedule for bandwidth changes in the
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 35
Day-Ahead and Day-Of Markets is shown in Table 5. For an example of the
bandwidth calculation, see Appendix A.
TABLE 5 PCQM TIME-LINE FOR BANDWIDTH CHANGES
BANDWIDTH PERCENTAGE
DAY-AHEAD DAY-OF
Period Peak Off-Peak Peak Off-Peak
Start - 11/8/99 10% 15% 10% 15%
11/9/99 - 2/12/00 10% 15% 15% 20%
2/13/00 - 6/25/00 15% 20% 20% 20%
6/26/00 - Forward 50% 50% 50% 50%
As a precautionary measure, the PCQM was first implemented in the
Day-Of Market because its volume is a fraction of the Day-Ahead Market.
This occurred on July 27, 1999. When this experiment proceeded
satisfactorily, the PCQM was extended to the Day-Ahead Market on
September 2, 1999.
Following an evaluation in January 2000 of the performance of the
experimental PCQM, the CalPX decided to continue the PCQM on a
permanent basis. The analysis performed in the January evaluation
indicated that the PCQM program provided benefits to market
participants and improved market efficiency.
The opportunity for sellers to withhold supply and exert market power
did not seem to have increased with the implementation of the PCQM.
When PCQM first came about, there was some speculation that suppliers
might be motivated to reduce the supply bid into the Day-Ahead auction,
knowing that they had another chance to sell with PCQM. When suppliers
withhold generation from the market, the result is typically an
inflated UMCP. One analysis, which searches for evidence that suppliers
were successfully using the PCQM to manipulate the UMCP, involves
comparing quantities matched in the PCQM at various MCP price levels.
If quantity were only matched in PCQM when the MCP was relatively high,
this would be considered evidence that suppliers were able to
manipulate the MCP in order to sell more at that price in PCQM. Figure
11 shows a scatter graph with this comparison.
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 36
Figure 11
[SCATTER CHART]
Day-Ahead PCQM Matched Quantity vs. UMCP
Figure 11 shows that quantities are most often matched in the PCQM when
the MCP is in the $20 to $45 range, not when prices are high. This
supports the theory that for both supply and demand participants to
submit PCQM bids, they both must have been satisfied with the level of
the UMCP. For example, when the price was above $100, the graph shows
that hardly any quantity was matched. Similarly, little quantity was
matched when the MCP was low.
The PCQM market structure encouraged sellers to submit more elastic
(flatter) supply curves. The more horizontal a Participant's bid curve,
the greater the quantity available to that Participant in the PCQM
market. Since the creation of the PCQM, buyers submitted more elastic
bids, an indicator of improved market efficiency.
Figure 12 shows the PCQM in the Day-Ahead Market gradually increasing,
while Figure 13 displays the most active PCQM hours.
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 37
Figure 12 Day-Ahead Average Daily PCQM Adjustment by Month
[BAR CHART]
Figure 13 Average Day-Ahead PCQM Adjustments for Hour Ending 1-24 (September,
1999 - March 31, 2000)
[BAR CHART]
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 38
2.4.1.4 Zero-Price Supply Bids versus Market Clearing Quantity
Two major categories of resources are bid into the CalPX at zero
prices: Regulatory Must-Take Generation and Regulatory Must-Run
Generation.
Regulatory Must-Take generation units are resources identified by the
CPUC and not subject to competition. These resources include qualifying
facilities, nuclear plants, and pre-existing power-purchase contracts
with minimum energy-take requirements. Regulatory Must-Run Generation
units are hydro resources required by Federal and California laws to
maintain flow to support fish releases, water quality, irrigation and
water supply. In addition, other resources that may be bid at zero
price include imports, inter-schedule coordinator trades, and units
that must be online for operational or contractual reasons or those
units that are strategically on-line to serve the CAISO markets.
The CPUC requires that facilities with `take-or-pay' commitments prior
to restructuring must run and their output must be taken. The
generation output is bid at zero. Hence, the output of these facilities
is taken first, no matter what the Market Clearing Price.
Zero-priced bids comprise a significant part of supply to the CalPX
Day-Ahead Market. Table 6 shows the average Market Clearing Quantity
and average zero-price supply bids for each month of the year from
April 1998 to March 2000. On average since the beginning of the market,
zero bids have comprised 79% of the MCQ. The California IOUs have
supplied 88% of the zero bids. The remaining zero bids came from
Participants who have chosen to bid as a price taker due to operational
constraints or strategic considerations.
TABLE 6 AVERAGE ZERO PRICE BID AND HOURLY UNCONSTRAINED MCQ ($/MWH)
Hourly Zero- Hourly MCQ Zero Price Bids IOU Zero- Percent of
Price Bids Average as percent of Bids Price Zero Bids
Year Month (MWh) (MWh) MCQ (MWh) by IOUs
- ----------------------------------------------------------------------------------------------------------
1998 Apr 16,760 19,886 84% 16,046 96%
May 17,188 19,050 90% 16,353 95%
Jun 19,556 21,398 91% 18,823 96%
Jul 19,768 25,393 78% 18,702 95%
Aug 19,324 25,900 75% 17,939 93%
Sep 18,247 23,792 77% 17,076 94%
Oct 17,416 21,170 82% 16,055 92%
Nov 17,233 20,792 83% 16,061 93%
Dec 16,711 21,460 78% 15,641 94%
1999 Jan 15,597 20,309 77% 14,112 90%
Feb 14,980 19,533 77% 13,726 92%
Mar 15,779 20,027 79% 14,763 94%
April 14,757 19,751 75% 13,777 93%
May 15,814 19,924 79% 14,552 92%
June 17,738 21,934 81% 16,184 91%
July 20,332 25,459 80% 15,774 78%
August 20,121 25,823 78% 15,375 76%
September 18,242 23,768 77% 14,184 78%
October 15,321 22,848 67% 12,237 80%
November 17,759 22,850 78% 13,124 74%
December 16,529 21,721 76% 13,287 80%
2000 January 15,344 21,125 73% 12,607 82%
February 15,355 19,725 78% 12,900 84%
March 15,805 19,812 80% 13,855 88%
- ----------------------------------------------------------------------------------------------------------
Average 17,153 21,810 79% 15,131 88%
- --------------------------------------------------------------------------------
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 39
Short-term changes in the amount of zero-price bids are mostly caused
by plant outages, contractual restrictions, and changes in energy
output from non-dispatchable resources, like solar and hydro.
Figure 14 shows the zero supply bids during the on-peak and off-peak
periods as a percentage of the MCQ. For most of the months, the
off-peak share of zero bids is considerable larger than the on-peak.
This is because most zero bid resources are baseload resources of
nuclear, coal, cogeneration, and geothermal. Because these resource
operate at nearly the same quantity for all hours of the day, they are
a larger share of the off-peak period when loads are less.
FIGURE 14 ZERO PRICED BIDS ON-PEAK AND OFF-PEAK
[BAR CHART]
Table 7 shows the yearly average zero-price supply-bid profile for the
peak and off peak hours for the first and second years of CalPX's
operation and the percent change between the two. While there was a
slight decrease of zero bids for the off-peak period from Year 1 to
Year 2, the on-peak zero bid supply was unchanged.
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 40
TABLE 7 ZERO PRICED BIDS
YEAR 2 YEAR 1 % CHANGE
------------------- -------------------- -------------------
Peak Off Peak Peak Off Peak Peak Off Peak
- ---------------------------------------------------------------------------------------------------------
MARKET
% of Supply Bidding at Zero 78% 79% 76% 84% 2% -6%
Quantity of Supply Bid at Zero 18,479 15,023 18,535 16,113 0% -7%
Quantity of Non-Zero Bids 5,139 4,012 5,746 3,125 -11% 28%
Total Hourly MCQ 23,618 19,035 24,281 19,238 -3% -1%
- ---------------------------------------------------------------------------------------------------------
IOU'S
Supply Bid at Zero by IOUs 14,632 13,175 16,973 15,424 -14% -15%
% of Zero Bid by IOUs 79% 88% 92% 96% -14% -8%
In June 1999, the Block Forwards Market (BFM) was implemented. To
ensure delivery of BFM contracts, Participants must bid them into the
PX Market at price-taker levels. In other words, suppliers who held
contracts were obligated to deliver them into one of the PX markets at
a price of zero. Similarly, buyers who had an obligation to deliver
would bid their purchases into the PX at the PX cap price, or
$2,500/MWh. Initially, concern existed that this would cause an
increase in the number of zero bids in the CalPX market and had the
potential to distort the MCP. A study conducted by Compliance
determined that price-taker bids decreased concurrent with the
implementation of BFM delivery. Had they increased, the MCP would not
have been distorted anyway. Zero and cap-priced bids act like market
orders on other exchanges. Market orders do not distort price; on the
contrary, they are evidence that the market is at equilibrium. A market
order reflects the confidence in the buyer or seller that the price set
by the market is fair.
2.4.1.5 Market Share of Participants
As stated earlier, AB1890 required the three large investor owned
utilities (IOUs), San Diego Gas and Electric, Southern California
Edison, and Pacific Gas and Electric, to buy and sell their power
through the CalPX. These three IOUs comprised more than 90% of the
market share during the CalPX's first months of operation.
Between the first and second years of operation, the IOUs divested
generation units totaling 17,863 MWh. A summary of the capacity
divested is shown in Table 8. For details of the divestiture,
Participants and capacity, see Appendix B.
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 41
TABLE 8 DIVESTITURE OF GENERATION
Divested Capacity (MW)
April-98 4,106
May-98 3,956
June-98 2,645
July-98 1,500
Year 1 12,207
April-99 3,065
May-99 2,591
Year 2 5,656
================================================
Total 17,863
Table 9 compares the percentage of market share by Participant Category
for supply and demand. California IOUs decreased supply market share by
16% largely because of divestiture of gas resources. The New Generation
Owners (NGOs) and Power Marketers increased market share from 7% to
18%. Imports from the Southwest and Northwest also increased market
share from 5% to 7% of volume. On the demand side, the California IOUs
decreased their demand market share by 4 percentage points with little
change by other Participants.
TABLE 9 MARKET SHARE BY PARTICIPANT CATEGORY
ANNUAL VOLUME: SUPPLY SUPPLY DEMAND DEMAND
Category (MWh) % of Total (MWh) % of Total
- ----------------------------------------------------------------------------------------
1st Year Data
CA IOU 161,742,428 86% 170,307,564 90%
NGO 8,042,176 4% 1,000,194 1%
Pwr Mkt 4,985,464 3% 206,001 0%
CA Munit/Public 4,953,857 3% 5,714,302 3%
NW IOU/Public 3,024,551 2% 2,048,220 1%
SW ISO/Public 2,619,384 1% 9,063,033 5%
CA IOUs SC 1,846,160 1% 672,809 0%
NUG/IPP 1,798,105 1%
Total Day-Ahead Market 189,012,123 100% 189,012,123 100%
- -------------------------------------------------------------------------------------
2nd Year Data
CA IOU 135,564,129 70% 166,415,464 86%
NGO 16,970,918 9% 3,321,928 2%
Pwr Mkt 17,025,143 9% 9,060,604 5%
CA Muni/Public 9,852,570 5% 594,230 0%
NW IOU/Public 9,753,367 5% 102,976 0%
SW ISO/Public 3,218,424 2% 3,744,042 2%
CA IOUs SC 1,823,041 1% 10,968,347 6%
Total Day-Ahead Market 194,207,592 100% 194,207,592 100%
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 42
Table 10 shows the change in market share of the three IOUs over the
past two years on a month-by-month basis. Table 10 and Table 11 show
the IOU percentage of supply dropping in the second year because of
divestiture of generation.
TABLE 10 MARKET SHARE OF CALIFORNIA IOUS
Demand Supply
------------------------------- -----------------------------
California IOUs California IOUs
Percent in CalPX Percent in CalPX
Month Others Day-Ahead Market Others Day-Ahead Market
- ---------------------------------------------------------------------------------------------
Apr-98 4% 96% 10% 90%
May-98 5% 95% 10% 90%
Jun-98 6% 94% 7% 93%
Jul-98 8% 92% 16% 84%
Aug-98 10% 90% 18% 82%
Sep-98 11% 89% 15% 85%
Oct-98 15% 85% 13% 87%
Nov-98 14% 86% 12% 88%
Dec-98 13% 87% 15% 85%
Jan-99 10% 90% 20% 80%
Feb-99 9% 91% 19% 81%
Mar-99 12% 88% 15% 85%
Apr-99 12% 89% 19% 81%
May-99 11% 89% 22% 78%
Jun-99 12% 88% 21% 79%
Jul-99 16% 84% 33% 67%
Aug-99 17% 83% 34% 66%
Sep-99 15% 85% 34% 66%
Oct-99 14% 86% 39% 61%
Nov-99 19% 81% 37% 63%
Dec-99 15% 85% 33% 67%
Jan-00 15% 85% 35% 65%
Feb-00 14% 86% 29% 71%
Mar-00 16% 84% 22% 78%
Table 10 shows the market share of the New Generation Owners. Most of
the sale of IOU generation units was completed by May 1999. After this,
the NGO market share began to increase. Table 11 shows NGO activity at
its peak in October 1999 when a heat wave in the Los Angeles area and
an outage of a nuclear unit made it especially lucrative for gas-fired
plant owners to run their units at higher capacities.
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 43
TABLE 11 MARKET SHARE OF NEW GENERATION OWNERS
Month Volume Sold by NGOs CalPX Volume NGOs Volume as %
(MWh) (MWh) of CalPX Volume
- -----------------------------------------------------------------------------------------------
Apr-98 224,412 14,240,731 1.6%
May-98 220,490 14,065,420 1.6%
Jun-98 176,138 15,344,588 1.1%
Jul-98 1,432,546 18,705,678 7.7%
Aug-98 1,732,766 19,019,632 9.1%
Sep-98 1,017,868 16,878,088 6.0%
Oct-98 815,475 15,597,053 5.2%
Nov-98 475,241 14,858,725 3.2%
Dec-98 597,443 15,917,174 3.8%
Jan-99 597,015 15,036,200 4.0%
Feb-99 393,315 13,114,525 3.0%
Mar-99 343,563 14,827,843 2.3%
Apr-99 495,548 14,220,390 3.5%
May-99 909,711 14,823,629 6.1%
Jun-99 1,220,099 15,792,596 7.7%
Jul-99 1,291,272 18,941,466 6.8%
Aug-99 1,174,795 19,212,069 6.1%
Sep-99 1,264,279 17,122,621 7.4%
Oct-99 2,599,882 17,029,047 15.3%
Nov-99 2,290,226 16,473,517 13.9%
Dec-99 1,439,141 16,201,026 8.9%
Jan-00 1,653,143 15,770,496 10.5%
Feb-00 1,374,593 13,818,109 9.9%
Mar-00 1,258,231 14,810,070 8.5%
- ----------------------------------------------------------------------------------------
1st Year Total 8,026,272 187,605,657 4.3%
1st Year Monthly Average 668,856 15,633,805 4.3%
- ----------------------------------------------------------------------------------------
2nd Year Total 16,970,920 194,215,036 8.7%
2nd Year Monthly Average 1,414,243 16,184,586 8.7%
- ----------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 44
2.4.1.6 Supply Resource Mix
Figure 15 shows the composition of the total CalPX Day-Ahead supply
market by resource type. The amount of hydro available to supply the
market during 1998 was higher than the rest of the period primarily
because El Nino left reservoir levels high in California. As a result,
hydro units contributed a large portion of supply. In the first two
months of winter of 2000, however, the amount of hydro generation
dropped because of an unusual dry spell.
FIGURE 15 RESOURCE MIX BY RESOURCE TYPE
[BAR CHART]
Figure 16 shows the composition of the total CalPX Day-Ahead supply
market by Participant type. The IOUs have, by far, the largest market
segment. In June 1999, the NGO segment of the market started to grow as
did the Power Marketer segment. Much of this Power Marketer segment is
probably NGO volume, which has been sold through transactions in the
bilateral markets. The Power Marketers and NGOs combined with the rest
of the voluntary market segment(23) has been steadily growing over the
past two years.
- ---------
(23) Voluntary means all Non-Must-Run resources.
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 45
Figure 16 Resource Mix by Participant Type
[BAR CHART]
Figure 17 shows a break down of the voluntary market segment by
resource type. Imports remained fairly consistent over the period
covered. The SC Transfer In portion of the voluntary segment increases
dramatically starting in July 1999. This could be evidence of an
increase in bilateral market activity.
FIGURE 17 NON-MUST RUN RESOURCE MIX BY RESOURCE TYPE
[BAR CHART]
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 46
Figure 18 breaks down the voluntary market segment by Participant type.
The increase in Power Marketer activity in July 1999 parallels the
growth in SC Transfer In activity seen above in Figure 16. This is
because they are often the same. Power Marketers will make bilateral
transactions with other SCs and then pass their supply through the
CalPX market for pricing and scheduling. Some IOU activity is included
in this Figure. The Non-must take resources still scheduled by the IOUs
include hydro and import energy under pre-existing contracts.
Figure 18 Non-Must Run by Participant Type
[BAR CHART]
2.4.1.7 Congestion
HOURS OF CONGESTION ON MAJOR TRANSMISSION LINES
Table 12 shows the frequency of congestion on major transmission lines
and the average monthly usage charge for hours when congestion
occurred. There was little congestion for the first four months of
the market. Congestion on Path 15 in the first year of operation was
most frequent during the late summer through fall period with the
October 1998 being the most congested month. Congestion was most
frequent on the California-Oregon intertie (COI or NW1) during the
winter months when energy is exported from California into the Pacific
Northwest region. The second year of operation saw increased frequency
of congestion and larger average usage charges.
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 47
Table 12 Congestion Hours and Usage Charge on Major Transmission Paths
<Table>
<Caption>
YEAR 1 (APRIL 1998 - MARCH 1999) YEAR 2 (APRIL 1999 - MARCH 2000)
-------------------------------------------- -------------------------------------------
MONTH AZ2 AZ3 NP15 NW1 NW3 ZP26 AZ2 AZ3 NP16 NW1 NW3 ZP26
El Palo Path Path El Palo Path Path
Dorado Verde 15 COI NOB 26 Dorado Verde 15 COI NOB 26
------------------------------ ------------- -------------------------------------------
APRIL Number of Congestion Hours 0 0 0 1 3 N/A 162 12 12 200 82 N/A
Ave Transmission Charge ($/MWh) $0.00 $0.00 $0.00 $4.14 $250.00 N/A $8.36 $24.58 $4.60 $4.42 $2.65 N/A
Max Transmission Charge ($/MWh) $0.00 $0.00 $0.00 $4.14 $250.00 N/A $22.63 $27.29 $10.80 $30.78 $30.00 N/A
MAY Number of Congestion Hours 0 0 0 83 24 N/A 57 33 4 44 42 N/A
Ave Transmission Charge ($/MWh) $0.00 $0.00 $0.00 $11.03 $5.89 N/A $5.08 $4.92 $1.59 $1.49 $28.52 N/A
Max Transmission Charge ($/MWh) $0.00 $0.00 $0.00 $50.00 $11.65 N/A $14.50 $30.00 $7.72 $6.00 $69.72 N/A
JUNE Number of Congestion Hours 0 0 0 0 0 N/A 94 0 33 108 58 N/A
Ave Transmission Charge ($/MWh) $0.00 $0.00 $0.00 $0.00 $0.00 N/A $9.46 $0.00 $5.33 $9.69 $3.71 N/A
Max Transmission Charge ($/MWh) $0.00 $0.00 $0.00 $0.00 $0.00 N/A $30.00 $0.00 $17.81 $38.91 $11.75 N/A
JULY Number of Congestion Hours 7 0 28 0 0 N/A 56 41 200 378 148 N/A
Ave Transmission Charge ($/MWh) $15.60 $0.00 $22.78 $0.00 $0.00 N/A $4.61 $3.88 $9.20 $11.44 $13.25 N/A
Max Transmission Charge ($/MWh) $19.72 $0.00 $76.25 $0.00 $0.00 N/A $17.51 $18.01 $58.86 $58.47 $250.00 N/A
AUGUST Number of Congestion Hours 0 100 165 43 11 N/A 122 5 210 398 216 N/A
Ave Transmission Charge ($/MWh) $0.00 $3.77 $10.58 $2.71 $30.30 N/A $6.19 $9.87 $7.51 $16.64 $2.98 N/A
Max Transmission Charge ($/MWh) $0.00 $17.71 $80.27 $15.10 $80.86 N/A $57.99 $30.00 $76.10 $220.74 $29.12 N/A
SEPTEMBER Number of Congestion Hours 104 73 157 99 55 N/A 203 127 416 334 40 N/A
Ave Transmission Charge ($/MWh) $4.86 $1.88 $9.22 $3.87 $13.95 N/A $8.40 $10.19 $16.78 $11.28 $4.31 N/A
Max Transmission Charge ($/MWh) $20.52 $5.99 $136.74 $28.34 $27.16 N/A $48.51 $66.99 $104.24 $186.88 $18.34 N/A
OCTOBER Number of Congestion Hours 38 72 311 49 108 N/A 71 50 549 142 74 N/A
Ave Transmission Charge ($/MWh) $4.12 $11.20 $9.17 $1.12 $14.88 N/A $12.56 $10.57 $21.58 $37.33 $165.77 N/A
Max Transmission Charge ($/MWh) $50.00 $42.08 $30.29 $7.59 $90.21 N/A $44.80 $33.00 $696.07 $678.00 $714.73 N/A
NOVEMBER Number of Congestion Hours 27 53 261 32 0 N/A 32 119 455 399 12 N/A
Ave Transmission Charge ($/MWh) $6.85 $10.35 $11.93 $11.84 $0.00 N/A $14.91 $12.05 $13.07 $5.74 $0.03 N/A
Max Transmission Charge ($/MWh) $24.72 $34.10 $30.15 $18.47 $0.00 N/A $95.74 $60.29 $68.21 $35.51 $0.08 N/A
DECEMBER Number of Congestion Hours 43 48 216 111 0 N/A 95 232 312 376 29 N/A
Ave Transmission Charge ($/MWh) $4.12 $7.02 $13.30 $1.88 $0.00 N/A $6.89 $5.66 $3.60 $2.54 $0.03 N/A
Max Transmission Charge ($/MWh) $40.20 $45.21 $236.99 $6.48 $0.00 N/A $26.33 $40.00 $20.22 $28.13 $0.06 N/A
JANUARY Number of Congestion Hours 67 33 136 409 178 N/A 179 221 301 316 15 N/A
Ave Transmission Charge ($/MWh) $2.06 $2.42 $3.90 $4.41 $1.26 N/A $3.13 $5.81 $3.29 $2.61 $21.18 N/A
Max Transmission Charge ($/MWh) $6.58 $5.99 $11.78 $28.79 $7.82 N/A $15.00 $28.00 $58.50 $50.80 $45.01 N/A
FEBRUARY Number of Congestion Hours 101 121 14 189 108 N/A 226 234 44 211 170 123
Ave Transmission Charge ($/MWh) $1.99 $5.26 $0.50 $2.00 $0.55 N/A $5.99 $8.36 $2.27 $2.70 $1.81 $4.50
Max Transmission Charge ($/MWh) $5.41 $30.00 $1.57 $9.50 $2.16 N/A $25.96 $27.98 $22.99 $22.99 $25.18 $28.00
MARCH Number of Congestion Hours 457 13 32 305 198
N/A 208 315 105 122 192 179 Ave Transmission Charge ($/MWh)
$9.40 $2.21 $6.50 $4.92 $1.70 N/A $4.23 $7.48 $3.92 $6.47
$3.93 $8.85 Max Transmission Charge ($/MWh) $25.40 $5.29 $16.37 $31.14
$7.86 N/A $92.00 $55.02 $28.57 $92.00 $17.00 $57.14
</Table>
*The number of hours that zonal prices at NP15 and SP15 changed from the
unconstrained MCP due to congestion
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 48
PRICE IMPACT DUE TO CONGESTION
One measure of the impact of congestion on the market is the number of
hours in which the UMCP is altered by congestion. As shown in Table 13,
the number of hours that price was altered increased significantly in
Year 2. (This table is not to be confused with the hours of congestion
over an intertie as shown in Table 12). In Table 13, the number of
hours when congestion on any path or intertie changed the unconstrained
price is summarized for the major zones. The number of price impact
hours for external zones AX2, AZ3, NW1, and NW3 is large because these
external zones are connected with NP15 and SP15. A price change in NP15
or SP15 will likely change the price of these external zones as well.
In general, during the summer and fall months, congestion affected
prices an average of 60% of the time and as much as almost 90% of the
time in September 1999.
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 49
Table 13 Price Impact Hours by Zone
NUMBER OF PRICE IMPACT HOURS
MONTH (NP15) (SP15) (AZ2) (AZ3) (NW1) (NW3) (ZP26)
- ----------------------------------------------------------------------------------------------------------------------------
APRIL-98 68 68 68 68 68 78 NA
MAY-98 241 241 241 241 285 264 NA
JUNE-98 224 222 222 223 236 230 NA
JULY-98 289 284 292 284 320 273 NA
AUGUST-98 337 335 335 340 344 340 NA
SEPTEMBER-98 373 367 374 368 392 409 NA
OCTOBER-98 462 463 466 474 473 572 NA
NOVEMBER-98 397 398 398 422 397 398 NA
DECEMBER-98 378 378 395 399 395 378 NA
JANUARY-99 477 466 459 468 499 480 NA
FEBRUARY-99 259 256 291 293 303 270 NA
MARCH-99 563 563 616 562 594 549 NA
- ----------------------------------------------------------------------------------------------------------------------------
RESULTS FOR APRIL-1998 - MARCH 1999
TOTAL NUMBER OF IMPACT
HOURS 4,068 4,041 4,157 4,142 4,306 4,241 NA
PERCENT OF TOTAL HOURS 46% 46% 47% 47% 49% 48% NA
- --------------------------------------------------------------------------------------------------------------------------
APRIL-99 244 241 285 242 288 245 NA
MAY-99 140 140 150 152 150 161 NA
JUNE-99 149 151 158 151 172 146 NA
JULY-99 441 412 432 423 507 380 NA
AUGUST-99 496 503 517 503 538 488 NA
SEPTEMBER-99 624 609 626 617 621 613 NA
OCTOBER-99 421 550 581 569 438 581 NA
NOVEMBER-99 215 461 468 523 487 473 NA
DECEMBER-99 46 312 388 477 401 340 NA
JANUARY-00 24 302 415 449 326 313 NA
FEBRUARY-00 40 135 227 234 208 168 121
MARCH-00 104 191 207 315 121 191 178
- ----------------------------------------------------------------------------------------------------------------------------
RESULTS FOR APRIL-1999 - MARCH 2000
TOTAL NUMBER OF PRICE
IMPACT HRS. 2,944 4,007 4,454 4,655 4,257 4,099 299
PERCENT OF TOTAL HOURS 34% 46% 51% 53% 49% 47% 21%
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 50
Another measure of the impact of congestion is the magnitude of the
price change from the unconstrained market-clearing price to the zonal
or constrained price. Table 14 shows the average price impacts for NP15
and SP15. NP15 experienced the most dramatic price impacts during July
1999 to October 1999 with SP15 showing more congestion price impacts
from September 1999 to November 1999.
TABLE 14 PRICE IMPACT IN NP15 AND SP15
MCP NP15 SP15 NP15 SP15
UNCONSTRAINED AVERAGE ZONAL AVERAGE ZONAL PRICE PRICE
AVERAGE PRICE PRICE CHANGE CHANGE
MONTH ($/MWH) ($/MWH) ($/MWH) ($/MWH) ($/MWH)
- -----------------------------------------------------------------------------------------------------
APRIL-98 22.64 22.61 22.61 -0.03 -0.03
MAY-98 11.64 12.06 12.06 0.42 0.42
JUNE-98 12.09 12.25 12.34 0.16 0.25
JULY-98 32.42 32.52 33.14 0.1 0.72
AUGUST-98 39.52 38.8 39.96 -0.72 0.44
SEPTEMBER-98 34.01 33.97 33.25 -0.04 -0.76
OCTOBER-98 26.56 27.88 24.09 1.23 -2.56
NOVEMBER-98 25.74 27.24 22.92 1.5 -2.82
DECEMBER-98 29.13 30.44 26.76 1.31 -2.37
JANUARY-99 20.96 21.79 21.09 0.83 -0.13
FEBRUARY-99 19.03 19.19 19.19 0.16 0.16
MARCH-99 18.83 19.74 19.48 0.91 0.65
APRIL-99 - MARCH 2000 24.44 24.93 23.96 0.49 (0.52)
APRIL-99 24.01 24.21 24.29 0.20 0.28
MAY-99 23.61 24.07 24.06 0.46 0.45
JUNE-99 23.52 24.15 23.93 0.62 0.40
JULY-99 28.93 32.01 29.91 3.08 0.98
AUGUST-99 32.31 34.65 32.80 2.34 0.49
SEPTEMBER-99 33.91 38.98 29.28 5.06 (4.64)
OCTOBER-99 47.64 55.77 39.88 8.14 (7.76)
NOVEMBER-99 36.91 37.90 29.64 0.99 (7.27)
DECEMBER-99 29.66 29.70 28.19 0.04 (1.47)
JANUARY-00 31.18 31.38 30.05 0.21 (1.13)
FEBRUARY-00 30.04 29.97 29.93 (0.07) (0.11)
MARCH-00 28.80 28.25 29.02 (0.55) 0.22
APRIL-99 - MARCH 2000 30.90 32.62 29.27 1.71 (1.63)
Figure 19 shows a comparison of the monthly average price impact on
NP15 and SP15 and the number of price impact hours from Year 1 to Year
2. This figure highlights the increase in both the magnitude of the
price change due to congestion and the increase in frequency of
congestion. A price spread between the unconstrained and the zonal
price greater than zero indicates that prices increased after
congestion management. Similarly, a negative spread indicates that
prices were lower due to congestion. In general, during the summer and
fall months, congestion causes prices in SP15 to decrease and prices in
NP15 to increase. During the winter and spring, zonal prices in both
NP15 and SP15 are often increased from the unconstrained prices
indicating that the price change resulted from congestion on an
external intertie, usually the California-Oregon Intertie (COI or NW1).
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 51
FIGURE 19 PRICE IMPACT IN NP15 AND SP15
[LINE AND BAR CHART]
2.4.1.8 Path 26 and New Zone ZP26
New congestion zone ZP26 was created on February 1, 2000 to provide a
Day-Ahead market signal of congestion on transmission Path 26. This
zone is entirely located between the two existing zones, NP15 and SP15,
and has no interties allowing for imports.
From the date ZP26 was created through April 7, 2000, Path 26 was
congested for 183 hours or 11% of the time. The average usage charge on
Path 26 was $5.5/MWh. As seen in Figure 20 below, congestion on Path 26
occurred most frequently during the peak evening hours with an average
usage charge between $8/MWh and $12/MWh.
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 52
Figure 20 Congestion on ZP26
[LINE AND BAR CHART]
When the implementation of this zone was being considered, the
rationale was that the zonal price for ZP26 would always be the lower
of NP15 or SP15 zonal prices. This view stemmed from the following:
- If congestion occurs in the South to North direction in
California, Path 15 (the Northern-most of Path 15 and Path 26)
should be the constrained line. The resulting usage charge
should then cause the NP15 zonal price to be higher than the
SP15 and ZP26 zonal prices.
- If congestion occurs in the North to South direction, Path 26
(the Southern-most of Path 15 and Path 26) should be the
constrained line. The resulting usage charge should then cause
the SP15 zonal price to be higher than the NP15 and ZP26 zonal
prices.
However, as seen in the insert in Figure 22, the zonal price for ZP26
was higher than both NP15 and SP15 for 20 % of the total hours in
February and March 2000. The average ZP26 zonal price for the entire
period was higher than that of either NP15 or SP15.
When a constrained zone has a higher price than surrounding areas, it
is usually because the zone is importing energy and requires
incremental supply or decremental demand adjustments. That ZP26 has
higher zonal prices is odd, given that ZP26 is usually an exporting
zone because it has only 300 MWh of demand and 3,093 MWh of generation
capacity.
This report has only two months of data available for analysis. The
variance from expectations noted in this report may be a function of
limited data and the newness of ZP26. However, the variance signals a
need for careful tracking of ZP26 market effects.
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 53
FIGURE 21 ZP26 AND UMCP PRICE SPREAD
[LINE CHART]
FIGURE 22 COMPARISON OF ZONAL PRICES IN NP15, SP15, AND ZP26
[LINE CHART]
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 54
2.4.1.9 Zonal Quantity Effects
Table 15 shows the aggregate quantity change for the seven major
congestion zones from the Initial Preferred Schedules to the Final
Schedule as follows.
TABLE 15 QUANTITY CHANGE DUE TO CONGESTION
MARCH 2000 SUPPLY 1998-MARCH 1999 1999-MARCH 2000 MARCH 1999 DEMAND
ZONE (MWH) SUPPLY (MWH) DEMAND (MWH) (MWH)
- ----------------------------------------------------------------------------------------------------------------
NP15 (1,716,300) 169,469 (2,396,499) (550,690)
SP15 193,975 (708,951) 192,208 (854,441)
EL DORADO (80,632) (255,425) 48,387 10,543
PALO VERDE (140,589) (190,698) 16,965 211
COB (161,648) (295,822) 16,863 (5,913)
NOB (32,883) (50,250) 53,675 7,013
ZP26 (493) NA 10 NA
TOTAL NET CHANGE (1,938,570) (1,331,677) (2,068,391) (1,393,277)
The largest adjustments due to congestion occurred in NP15 for both
supply and demand. Suppliers from the Southwest (Palo Verde and El
Dorado) reduced their supplies by about 220,000 MWh while increasing
demand by about 65,000 MWh. Suppliers from the Northwest links (COB and
NOB) showed a reduction in schedules of about 195,000 MWh while
increasing demand by about 70,000 MWh.
2.4.1.10. Financial Impact of Congestion
Before congestion management, the Initial Preferred Schedules represent
the amount of energy scheduled through the CalPX based on the supply
and demand curves of Participants. After congestion management, Final
Schedules represent the willingness of buyers and sellers to adjust
prices and volume to resolve congestion. Last year, 189,014 GWh of
Initial Preferred Schedules were submitted through the CalPX Day-Ahead
auction with an annual hourly dollar volume of $5,033 million. This
year 194,207,592 GWh of Initial Preferred Schedules were submitted
through the CalPX Day-Ahead market with an annual hourly dollar volume
total of $6,278 million. Energy schedules rose from 1,407 GWh to 2,054
GWh. The impact of congestion on annual dollar volume increased from
$57 million last year to $133 million this year.
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 55
TABLE 16 ANNUAL CONGESTION COMPARISON
ANNUAL DOLLAR VOLUMES ($ MILLION) TOTAL ANNUAL QUANTITY
---------------------------------- ------------------------------------
APRIL 1999- APRIL 1998- APRIL 1999- APRIL 1998-
MARCH 2000 MARCH 1999 MARCH 2000 MARCH 1999
---------------------------------- ------------------------------------
BEFORE CONGESTION 6,278 5,033 194,207,592 189,013,000
AFTER CONGESTION 6,145 4,976 192,153,138 187,606,000
TOTAL CHANGE (133) (57) (2,054,454) (1,407,000)
For the seven major congestion zones, Table 17 shows the price change
from the Unconstrained MCP and the Net Financial Impact on buyers
(demand) and seller (supply). These Net financial impact figures are
calculated by taking the difference between the UMCP and the zonal
price multiplied by the final quantity for each hour in the zone. These
impacts only measure the impact of the change of zonal pricing on the
final constrained quantity. These figures do not consider the financial
impact of congestion on quantities.
TABLE 17 NET FINANCIAL IMPACT DUE TO CONGESTION
NET FINANCIAL IMPACT
-------------------------------------------------------------------------------
THIS YEAR: LAST YEAR: THIS YEAR: LAST YEAR:
APRIL 1999- APRIL 1998- APRIL 1999 APRIL 1998-
AVERAGE AVERAGE ZONAL MARCH 2000 SUPPLY MARCH 1999 MARCH 2000 DEMAND MARCH 1999
ZONE UMCP($/MWH) PRICE ($/MWH) ($ MILLION) SUPPLY ($ MILLION) ($ MILLION) DEMAND ($ MILLION)
- ------------------------------------------------------------------------------------------------------------------------------
NP15 $ 30.90 $ 32.61 95.4 19.4 135.47 28.0
SP15 $ 30.90 $ 29.27 (173.7) (38.7) (193.78) (40.3)
EL DORADO $ 30.90 $ 28.32 (19.5) (7.3) (0.95) (0.2)
PALO VERDE $ 30.90 $ 28.24 (30.1) (7.2) (0.66) (0.1)
COB $ 30.90 $ 29.56 (10.4) (3.5) (1.65) (0.1)
NOB $ 30.90 $ 29.95 (1.0) (1.1) (0.94) (0.6)
ZP26 $ 30.90 $ 28.71 (3.2) NA (1.10) NA
The net effect of congestion on zonal prices, excluding quantity
effects, for Northern and Southern California are as follows:
- Sellers in Northern California (NP15) realized an additional
$95 million of sales because of higher zonal prices as a
result of congestion. On the other hand, buyers in NP15 paid
an additional $135.
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 56
- Sellers in Southern California (SP15) lost $174 million in
revenue because of lower zonal prices. Buyers in SP15 saved
$194 million.
According to these figures, the net financial impact was more severe in
the second year. The net gain for suppliers in NP15 rose by about $75
million this year while the cost to buyers in NP15 rose by more than
$100 million. The net loss for suppliers in SP15 rose from last year by
about $135 million. But the savings for buyers in SP15 increased by
about $150 million
Congestion caused a net reduction in schedules of about 2,360 GWh. The
unmet energy demand in the Day Ahead market due to congestion was
likely satisfied in the CalPX Day-Of and the CAISO real-time markets.
2.4.2 Day-Of Market
The CalPX Day-Of market was originally launched on July 30, 1998 as the
Hour-Ahead market. It allows buyers and seller to adjust their
Day-Ahead positions for changes in demand caused by weather conditions,
resource outages, and other favorable price arbitrage opportunities.
The original market involved trading around the clock through 24
separate hourly auctions occurring within hours of the actual trading
hour. On January 17, 1999, the Hour-Ahead auction was renamed the
Day-Of market to reflect the change in the timing of the auctions. The
Hour-Ahead market and the Day-Of market will henceforth be called the
Day-Of for purposes of discussion. The change was implemented to reduce
the frequency of auctions from 24 to three, but maintain the benefits
of the market. Currently, the auctions take place at 4:00 p.m. for the
next day trades for Hours 1 - 7, 6 am, for the same day trades for
Hours 7 - 16, and noon for the same day trades for Hours 17 - 24. Shown
below in Figure 23 is a graph of Daily Average Volume and Daily Average
UMCP since the launch of the Hour-Ahead/Day-Of market.
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
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COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 57
FIGURE 23 DAY-OF UMCP AND DAILY VOLUME
[LINE AND BAR CHART]
The Day-Of market volume has remained flat since the market launch in
terms of quantity and has grown in terms of hours of transaction. The
relatively small volumes in this market, as compared to the Day-Ahead
market, means that supply and/or demand bids in some hours are not
sufficient to have an intersection of the supply and demand curves.
These hours are then considered "INVALID" and no trades take place. The
hours of transactions shown in Table 18 and Figure 24 indicate the
number of valid hours. As the market has grown in volume, the percent
of valid hours has increased to more than 90%.
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
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COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 58
TABLE 18 DAY-OF MARKET RESULTS
AVERAGE TOTAL AVERAGE QUANTITY HOURS WITH TRANSACTION HOURS
AS % OF
MONTH PRICE ($/MWH) QUANTITY PER DAY (MWH) TRANSCATIONS TOTAL HOURS
- ----------------------------------------------------------------------------------------------------------
August-98 49.00 91,225 2,943 462 62%
September-98 40.29 58,602 1,953 361 50%
October-98 31.33 23,564 760 224 30%
November-98 16.43 2,874 96 74 10%
December-98 38.83 19,745 637 164 22%
January 1-16 26.66 1,785 112 30 8%
January 17-30 15.78 26,032 1,735 280 78%
February-99 16.76 18,802 672 447 67%
March-99 19.63 24,774 799 418 56%
Average/Total 29.34 267,403 1,114 2,460 43%
- ----------------------------------------------------------------------------------------------------------
April-99 25.43 29,034 937 500 67%
May-99 26.22 22,883 738 382 51%
June-99 25.71 55,093 1,836 486 68%
July-99 30.31 79,804 2,574 558 75%
August-99 34.99 83,174 2,683 576 77%
September-99 30.45 87,954 2,932 608 84%
October-99 39.65 95,562 3,083 662 89%
November-99 31.01 62,305 2,077 594 83%
December-99 24.24 41,864 1,350 629 85%
January-00 26.67 77,193 2,490 695 93%
February-00 26.29 48,042 1,657 652 94%
March-00 28.06 46,377 1,496 587 79%
Average/Total 29.09 729,284 1,988 6,929 79%
- --------------------------------------------------------------------------------
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 59
FIGURE 24 COMPARISON OF DAY-AHEAD AND DAY-OF MARKET
[LINE AND BAR CHART]
A comparison of the Day-Ahead and Day-Of market prices show that
without exception, the monthly average Day-Ahead price is greater than
the monthly average Day-Of market price for the first two years of the
market. Figure 24 compares the Day-Ahead and Day-Of average prices for
only those hours when a valid auction took place in the Day-Of market.
The average spread between the Day-Ahead and Day-Of market is $3.20/MWh
with a maximum monthly spread of $8.50/MWh in October 1999. Prices in
the Day-Ahead and Day-Of market are expected to converge in the future
as the Day-Of market matures and gains in liquidity and as Participants
recognize the opportunities in the Day-Of market.
- --------------------------------------------------------------------------------
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 60
PCQM IN THE DAY-OF MARKET
The PCQM was implemented first in the Day-Of market and then in the
Day-Ahead. Figure 25 shows that PCQM activity in the Day-Of Market
dropped after the first couple of months. This is most likely because
PCQM had been implemented in the Day-Ahead market by September 1999. As
a result some PCQM activity shifted to the market where larger
adjustments could be made at better prices. In other words, the UMCP in
the Day-Ahead market is less volatile and more frequently at a level
where both buyers and sellers would choose to participate further.
However, the Day-Of PCQM adjustments typically hold a larger percentage
of the Day-Of volume than the Day-Ahead PCQM adjustments do of the
Day-Ahead volume because Day-Ahead volumes are relatively small.
FIGURE 25 DAY-OF AVERAGE DAILY PCQM ADJUSTMENT BY MONTH
[BAR CHART]
As was true with the Day-Ahead PCQM adjustments, the Day-Of PCQM
adjustments tend to reach their highest quantities during on-peak
hours, as seen in Figure 26.
The addition of both the Day-Ahead and Day-Of PCQM has provided two
more opportunities for Participants in the PX to adjust their schedules
as the dispatch hour nears. If they wish, participants can reduce their
risk in the CAISO Real-Time Markets by choosing to take advantage of
this mechanism in either or both CalPX markets.
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 61
FIGURE 26 AVERAGE DAY-OF PCQM ADJUSTMENTS FOR HE 1-24 (JULY 1999 - MARCH 31,
2000)
[BAR CHART]
2.5 The Relationship Between the CalPX Day-Ahead Market and other Markets
2.5.1 Market Share of CAISO
As seen in Table 19, the CalPX's market share of the CAISO has
decreased by about 2.5% between the first and second years of
operation. Most of this decrease occurred during on-peak hours.
- --------------------------------------------------------------------------------
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 62
TABLE 19 PX SHARE OF ISO MARKET
1998-1999 1999-2000 1998-1999 1999-2000 1998-1999 1999-2000
ALL HOURS CalPX CalPX CAISO CAISO CalPX % Share CalPX % Share
Day-Ahead Day-Ahead Day-Ahead Day-Ahead of CAISO of CAISO
Month Final Final Final Schedule Final Schedule Day-Ahead Day-Ahead
(MWh) (MWh) (MWh) (MWh) Final Schedule Final Schedule
- -------------------------------------------------------------------------------------------------------------------------
April 19,806 19,751 21,689 24,132 91.3% 81.8%
May 18,905 19,924 21,408 24,171 88.3% 82.4%
June 21,312 21,934 24,133 26,609 88.3% 82.4%
July 25,142 25,459 29,538 28,878 85.1% 88.2%
August 25,564 25,823 31,365 29,016 81.5% 89.0%
September 23,442 23,768 28,169 27,930 83.2% 85.1%
October 20,964 22,848 24,566 26,822 85.3% 85.2%
November 20,637 22,850 23,936 25,144 86.2% 90.9%
December 21,394 21,721 24,821 25,919 86.2% 83.8%
January 20,210 21,125 23,783 25,575 85.0% 82.6%
February 19,516 19,725 23,431 25,529 83.3% 77.3%
March 19,930 19,812 23,270 25,523 85.6% 77.6%
- -------------------------------------------------------------------------------------------------------------------------
Annual Average 21,419 22,062 25,028 26,271 85.8% 83.9%
- -------------------------------------------------------------------------------------------------------------------------
1998-1999 1999-2000 1998-1999 1999-2000 1998-1999 1999-2000
ON PEAK CalPX CalPX CAISO CAISO CalPX % Share CalPX % Share
Day-Ahead Day-Ahead Day-Ahead Day-Ahead of CAISO of CAISO
Month Final Final Final Schedule Final Schedule Day-Ahead Day-Ahead
(MWh) (MWh) (MWh) (MWh) Final Schedule Final Schedule
- -------------------------------------------------------------------------------------------------------------------------
April 21,585 21,501 23,692 26,741 91.1% 80.4%
May 20,746 22,043 23,583 27,171 88.0% 81.1%
June 23,152 24,175 26,510 29,871 87.3% 80.9%
July 28,316 29,214 33,784 32,537 83.8% 89.8%
August 28,331 29,392 35,514 32,776 79.8% 89.7%
September 25,719 26,425 31,341 31,414 82.1% 84.1%
October 22,785 24,784 26,888 30,166 84.7% 82.2%
November 22,607 25,339 26,167 27,865 86.4% 90.9%
December 22,921 23,096 26,693 28,706 85.9% 80.5%
January 22,185 23,127 25,766 28,588 86.1% 80.9%
February 21,329 21,468 25,475 28,210 83.7% 76.1%
March 21,559 21,456 25,196 28,237 85.6% 76.0%
- ----------------------------------------------------------------------------------------------------------------------
Annual Average 23,448 24,335 27,562 29,357 85.4% 82.7%
- -----------------------------------------------------------------------------------------------------------------------
1998-1999 1999-2000 1998-1999 1999-2000 1998-1999 1999-2000
OFF PEAK CalPX CalPX CAISO CAISO CalPX % Share CalPX % Share
Day-Ahead Day-Ahead Day-Ahead Day-Ahead of CAISO of CAISO
Month Final Final Final Schedule Final Schedule Day-Ahead Day-Ahead
(MWh) (MWh) (MWh) (MWh) Final Schedule Final Schedule
- -------------------------------------------------------------------------------------------------------------------------
April 17,364 17,355 18,939 20,564 91.7% 84.4%
May 16,765 17,460 18,878 20,683 88.8% 84.4%
June 18,794 18,867 20,881 22,146 90.0% 85.2%
July 21,452 20,696 24,601 24,623 87.2% 84.1%
August 22,055 21,295 26,102 24,247 84.5% 87.8%
September 20,595 20,447 24,205 23,164 85.1% 88.3%
October 18,442 20,394 21,350 22,581 86.4% 90.3%
November 18,386 20,004 21,387 21,744 86.0% 92.0%
December 19,457 19,977 22,447 22,678 86.7% 88.1%
January 18,104 18,797 21,668 22,072 83.5% 85.2%
February 17,320 17,369 20,958 21,907 82.6% 79.3%
March 17,674 17,536 20,603 21,766 85.8% 80.6%
- ----------------------------------------------------------------------------------------------------------------------
Annual Average 18,885 19,183 21,864 22,348 86.5% 85.8%
- ----------------------------------------------------------------------------------------------------------------------
When the CalPX came into existence in April 1998, few alternatives to
the CalPX existed for market participants. Since then, the bilateral
markets have become more vibrant, other Scheduling Coordinators have
joined the CAISO, and other power exchanges have been created. In light
of these changes, a 2.5% decrease in the CalPX's market share seems
relatively small.
The primary reason the CalPX has been able to retain its market share,
is because AB 1890 requires the IOUs to buy and sell their power
through the CalPX until March 2002. This is to facilitate the recovery
of the IOUs' stranded costs during the restructuring transition period.
However, as Table 20 shows, the IOU segment of the CalPX Day-Ahead
Market has decreased significantly on both the supply side and the
demand side.
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 63
TABLE 20 SHARE OF IOU IN PX DAY-AHEAD MARKET
----------------------------------------------------------------------------
PERCENTAGE OF PX DAY-AHEAD MARKET
----------------------------------------------------------------------------
YEAR 1 (APRIL 1998 - MARCH 1999) YEAR 2 (APRIL 1999 - MARCH 2000)
----------------------------------------------------------------------------
DEMAND SUPPLY DEMAND SUPPLY
----------------------------------------------------------------------------
Others IOU Others IOU Others IOU Others IOU
----------------------------------------------------------------------------
9.75% 90.25% 14.17% 85.83% 14.67% 85.42% 29.83% 70.17%
Non-IOU market Participants (Others) have voluntarily increased
their activity through the CalPX even with other options (such as
bilateral arrangements and activity with other exchanges)
available to them. While the IOU segment of the Day-Ahead has
decreased by 15%, CalPX's total market share has only decreased by
2.5%, indicating that the non-IOU segment of the CalPX market is
steadily growing.
2.5.2 Price Spreads
Table 21 and Table 22 compare several average price spreads
between the CalPX's first and second years of operation. Since the
PX holds 80% - 85% of the total California market share, its
prices are largely viewed as the benchmark for purchasing and
selling electricity in California. However, arbitrage theory
states that in an efficient market, two different price origins
based on the same underlying commodity ought to converge. The two
tables below show that the average differences in zonal prices in
NP15 and SP15 tracked more closely in the second year than in the
first.
TABLE 21 PRICE SPREAD COMPARISON CHART (YEAR 1)
- --------------------------------------------------------------------------------------------------------------
Day- Zonal Zonal
APRIL 1998 - Ahead Price Price DJ DJ Day-Of Real Time Real Time
MARCH 1999 UMCP NP15 SP15 COB PV UMCP NP15 SP15
- --------------------------------------------------------------------------------------------------------------
Avg Price $24.44 $24.93 $23.96 $24.43 $23.88 $28.97 $25.62 $23.54
- --------------------------------------------------------------------------------------------------------------
Day-Ahead UMCP $24.44
- --------------------------------------------------------------------------------------------------------------
Zonal Price NP15 $24.93 $0.49
- --------------------------------------------------------------------------------------------------------------
Zonal Price SP15 $23.96 -$0.48 -$0.97
- --------------------------------------------------------------------------------------------------------------
DJ - COB $24.43 -$0.01 -$0.50 $ 0.47
- --------------------------------------------------------------------------------------------------------------
DJ - PV $23.88 -$0.56 -$1.05 -$ 0.08 -$0.55
- --------------------------------------------------------------------------------------------------------------
Day-Of UMCP $28.97 $4.53 -$4.04 $ 5.01 $4.54 $5.09
- --------------------------------------------------------------------------------------------------------------
ISO Real Time NP15 $25.62 $1.18 $0.69 $ 1.66 $1.19 $1.74 -$3.35
- --------------------------------------------------------------------------------------------------------------
ISO Real Time S15 $23.54 -$0.90 -$1.39 -$ 0.42 -$0.89 -$0.34 -$5.43 -$2.08
- --------------------------------------------------------------------------------------------------------------
- --------------------------------------------------------------------------------
SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 64
TABLE 22 PRICE SPREAD COMPARISON CHART (YEAR 2)
<Table>
<Caption>
Day- Zonal Zonal
APRIL 1999 - MARCH Ahead Price Price DJ DJ Day-Of Real Time Real Time
2000 UMCP NP15 SP15 COB PV UMCP NP15 SP16
- ------------------------------------------------------------------------------------------------------------------------
Avg Price $30.90 $32.62 $29.28 $29.80 $28.77 $29.28 $33.11 $29.26
- ------------------------------------------------------------------------------------------------------------------------
Day-Ahead UMCP $30.90
Zonal Price NP15 $32.62 $1.72
Zonal Price SP15 $29.28 -$1.62 -$3.34
DJ - COB $29.80 -$1.10 -$2.82 $0.52
DJ - PV $28.77 -$2.13 -$3.85 -$0.51 -$1.03
Day of UMCP $29.28 -$1.62 -$3.34 $0.00 $0.62 $0.51
ISO Real Time NP15 $33.11 $2.21 $0.50 $3.84 $3.32 $4.35 $3.83
ISO Real Time SP16 $23.25 -$1.64 $3.36 $0.01 $0.54 $0.50 $0.02 $3.85
</Table>
Also, the average difference between the Day-Ahead and Day-Of UMCP
decreased significantly, from $4.53/MWh the first year, to $1.62/MWh
the second year. The average hourly Day-Of volume increased from 46 MWh
the first year to 83 MWh the second year, an increase of 81%. This
falls in line with arbitrage theory, in that if the markets are equally
robust, arbitrage and price convergence should happen more quickly and
efficiently.
Figure 27 shows a graphical portrayal of the CalPX Day-Ahead and CAISO
Real-Time zonal price spread. It is followed by Table 23 which shows
the figures in detail.
FIGURE 27 ZONAL PRICE COMPARISON BETWEEN PX DAY-AHEAD AND ISO REAL-TIME MARKETS
[BAR CHART]
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 65
Table 23 Monthly Spread Between CalPX Zonal Price and the ISO Real-time Price
NP 15 SP 15 SP 15
NP 15 AVERAGE AVERAGE AVERAGE AVERAGE
AVERAGE ZONAL ZONAL ZONAL ZONAL AVERAGE
MONTH CALPX CALPX ZONAL PRICE PRICE PRICE PRICE PRICE ZONAL PRICE
---------------------------- CAISO NP15 CALPX CAISO SP15
AVERAGE UMCP AVERAGE UMCP CALPX PRICE PRICE SPREAD PRICE PRICE SPREAD
APRIL-99 TO APRIL-98 TO
MARCH-00 MARCH-99 ($/MWH) ($/MWH) ($/MWH) ($/MWH) ($/MWH) ($/MWH)
- -----------------------------------------------------------------------------------------------------------------------------
APRIL-99 $ 24.01 $ 22.64 $ 24.21 $ 25.42 $ (1.21) $ 24.29 $ 25.42 $ (1.13)
MAY-99 $ 23.61 $ 11.64 $ 24.07 $ 19.66 $ 4.41 $ 24.06 $ 19.66 $ 4.40
JUNE-99 $ 23.52 $ 12.09 $ 24.15 $ 21.45 $ 2.69 $ 23.93 $ 21.45 $ 2.47
JULY-99 $ 28.93 $ 32.42 $ 32.01 $ 22.22 $ 9.79 $ 29.91 $ 22.22 $ 7.69
AUGUST-99 $ 32.31 $ 39.52 $ 34.65 $ 34.73 $ (0.08) $ 32.80 $ 34.20 $ (1.40)
SEPTEMBER-99 $ 33.91 $ 34.01 $ 38.98 $ 40.94 $ (1.97) $ 29.28 $ 33.06 $ (3.78)
OCTOBER-99 $ 47.64 $ 26.65 $ 55.77 $ 61.06 $ (5.28) $ 39.88 $ 42.42 $ (2.54)
NOVEMBER-99 $ 36.91 $ 25.74 $ 37.90 $ 47.89 $ (10.00) $ 29.64 $ 31.99 $ (2.36)
DECEMBER-99 $ 29.66 $ 29.13 $ 29.70 $ 32.59 $ (2.89) $ 28.19 $ 32.02 $ (3.82)
JANUARY-00 $ 31.18 $ 20.96 $ 31.38 $ 33.43 $ (2.04) $ 30.05 $ 31.36 $ (1.31)
FEBRUARY-00 $ 30.04 $ 19.03 $ 29.97 $ 29.26 $ 0.71 $ 29.93 $ 28.72 $ 1.21
MARCH-00 $ 28.80 $ 18.83 $ 28.25 $ 28.61 $ (0.36) $ 29.02 $ 28.43 $ 0.59
APRIL-99 -
MARCH 2000 $ 30.90 $ 24.44 $ 32.61 $ 33.11 $ (0.52) $ 29.27 $ 29.25 $ 0.00
2.5.3 Correlation Between Markets
As can be seen in Figure 28(24), the correlation with the Day-Ahead
unconstrained MCP decreases as you move to subsequent markets from
Day-Ahead zonal prices, then to Day-Of prices, then to Real Time
prices. This is expected since the different markets are asynchronous.
At each stage, the prices are being adjusted to reflect newer
information about constraints in the system. Also evident is an
across-the-board decrease in the correlation moving to Year 2.
Comparing Figure 29 and Figure 30, the correlation with NP15 decreased
more than for the SP15 region from Year 1 to Year 2.
- -----------
(24) Figure 28 through Figure 32 contain price correlation information for Year
1 and Year 2. All hours were used in calculating correlation between CalPX
and CAISO markets. In correlating with Dow Jones COB and PV prices, the
CalPX and CAISO prices were converted to 16 hour on-peak block
equivalents.
- --------------------------------------------------------------------------------
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 66
Figure 28 Correlation with Day-Ahead MCP
CORRELATION WITH DAY-AHEAD MCP
YEAR 1 AND YEAR 2
[BAR CHART]
FIGURE 29 CORRELATION WITH NP15 ZONAL PRICE
CORRELATION WITH ZONAL NP15
YEAR 1 AND YEAR 2
[BAR CHART]
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 67
FIGURE 30 CORRELATION WITH ZONAL SP15 PRICE
CORRELATION WITH ZONAL SP15
YEAR 1 AND YEAR 2
[BAR CHART]
Figure 31 and Figure 32 illustrate that Real Time prices are the least
correlated with the other markets, but that NP15 and SP15 Real Time
prices are still correlated since they are resolved on the same
information set.
FIGURE 31 CORRELATION WITH CAISO REAL-TIME PRICE - NP15
CORRELATION WITH ISO REAL TIME NP15
YEAR 1 AND YEAR 2
\
[BAR CHART]
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 68
FIGURE 32 CORRELATION WITH ISO REAL-TIME PRICE - SP15
CORRELATION WITH ISO REAL TIME SP15
YEAR 1 AND YEAR 2
[BAR CHART]
2.5.4 Ancillary Services Prices and Volume
The CAISO Ancillary Services markets interact with and influence the
CalPX markets. CAISO procures Ancillary Services on a Day-Ahead and
Hour-Ahead basis. Day-Ahead bids for Regulation Up, Regulation Down,
Spinning Reserves, Non-Spinning Reserves, and Replacement are submitted
simultaneous after the Day-Ahead unconstrained energy auction is
complete and resource schedules are submitted. The CAISO pays a
capacity payment or reservation charge to awarded participants.
These capacity reservations interact with CalPX markets because, each
market such as the CalPX Day-Ahead, CalPX Day Of, CAISO real-time and
CAISO Ancillary Services markets all compete for participation. For
example, if the Ancillary Services capacity markets are strong on a
daily basis, this will pull bids away from the CalPX Day-Ahead auction.
Traders and asset managers attempt to optimize resources and minimize
exposure and lost opportunity costs by employing the proper mix of
participation in various markets. Ancillary Services offers the chance
to benefit from a capacity charge whether or not the resource is called
by CAISO. If the resource is called by CAISO, the supplier is paid the
capacity payment in addition to the Real-Time price. As seen in Table
24, the volume of Ancillary Services compared to the CAISO Day-Ahead
scheduled volumes is quite substantial.
Starting in August 1999, CAISO began running separate simultaneous
auctions for Regulation Up and Regulation Down. Previously, CAISO
conducted a single auction for
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both services and the market-clearing price for the highest priced
service became the clearing price for both. In addition, CAISO
instituted the Rational Buyer procedure. This approach was installed to
allow CAISO to utilize bids from a lesser quality ancillary service if
it met the same technical needs as the higher quality service when the
lesser quality service was more cost effective. This helps prevent high
bids at the bottom of bid stacks for high quality ancillary services
from setting high market clearing price when another service, although
of lesser quality, would have been less expensive and would still have
satisfied the minimum reserve requirements.
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 70
TABLE 24 ANCILLARY SERVICES PRICES AND QUANTITY
NP15 REGULATION UP REGULATION DOWN SPINNING RESERVE NON-SPINNING RESERVE REPLACEMENT RESERVE
- -------------------------------------------------------------------------------------------------------------------------------
AVERAGE AVERAGE AVERAGE AVERAGE AVERAGE AVERAGE AVERAGE AVERAGE AVERAGE AVERAGE
HOURLY HOURLY HOURLY HOURLY HOURLY HOURLY HOURLY HOURLY HOURLY HOURLY
QTY PRICE QTY PRICE QTY PRICE QTY PRICE QTY PRICE
MONTH (MWH) ($/MWH) (MWH) ($/MWH) (MWH) $/MWH) (MWH) ($/MWH) (MWH) ($/MWH)
Apr-98 449 $ 11.55 N/A N/A 424 $ 7.75 76 $ 6.63 428 $ 7.90
May-98 462 $ 9.33 N/A N/A 341 $ 7.49 66 $ 7.30 453 $ 7.92
Jun-98 428 $ 33.65 N/A N/A 334 $ 33.15 28 $ 3.21 224 $ 3.82
Jul-98 640 $ 20.64 N/A N/A 383 $ 15.32 133 $17.23 186 $14.60
Aug-98 895 $ 12.83 N/A N/A 276 $ 35.71 117 $28.29 133 $22.45
Sep-98 949 $ 0.40 N/A N/A 312 $ 19.67 133 $12.78 134 $ 1.99
Oct-98 912 $ 7.41 N/A N/A 470 $ 2.60 108 $ 0.60 28 $ 0.33
Nov-98 1,000 -$1.43 N/A N/A 541 $ 3.32 81 $ 0.82 19 $ 0.49
Dec-98 1,065 $ 23.71 N/A N/A 593 $ 11.92 88 $ 3.22 26 $ 2.09
Jan-99 1,108 $ 16.02 N/A N/A 414 $ 3.91 62 $ 0.55 62 $ 0.69
Feb-99 1,050 $ 10.30 N/A N/A 328 $ 2.72 35 $ 0.73 69 $ 0.79
Mar-99 1,034 $ 14.50 N/A N/A 407 $ 4.04 72 $ 0.68 75 $ 0.58
Apr-99 823 $ 18.12 N/A N/A 454 $ 7.50 152 $ 2.11 36 $ 1.48
May-99 692 $ 16.44 N/A N/A 431 $ 4.81 186 $ 3.09 58 $ 1.64
Jun-99 472 $ 21.54 N/A N/A 278 $ 4.57 316 $ 2.70 37 $ 1.27
Jul-99 403 $ 26.71 N/A N/A 214 $ 8.57 171 $ 8.10 102 $ 8.11
Aug-99 200 $ 15.98 38 $12.93 193 $ 7.08 196 $ 3.22 18 $ 4.33
Sep-99 277 $ 15.77 81 $25.87 126 $ 5.89 174 $ 4.01 22 $ 3.61
Oct-99 284 $ 42.11 67 $20.18 179 $ 10.63 179 $ 4.76 44 $ 8.95
Nov-99 251 $ 11.22 117 $21.76 267 $ 3.48 203 $ 1.60 21 $ 1.23
Dec-99 373 $ 6.23 234 $11.96 432 $ 1.19 271 $ 0.51 53 $ 0.38
Jan-00 255 $ 7.97 157 $12.64 401 $ 1.26 271 $ 0.22 71 $ 0.23
Feb-00 211 $ 8.87 142 $10.52 367 $ 1.27 197 $ 0.37 91 $ 0.48
Mar-00 248 $ 10.98 242 $ 9.54 311 $ 2.82 176 $ 0.58 82 $ 0.65
SP15 REGULATION UP REGULATION DOWN SPINNING RESERVE NON-SPINNING RESERVE REPLACEMENT RESERVE
- -------------------------------------------------------------------------------------------------------------------------------
AVERAGE AVERAGE AVERAGE AVERAGE AVERAGE AVERAGE AVERAGE AVERAGE AVERAGE AVERAGE
HOURLY HOURLY HOURLY HOURLY HOURLY HOURLY HOURLY HOURLY HOURLY HOURLY
QTY PRICE QTY PRICE QTY PRICE QTY PRICE QTY PRICE
MONTH (MWH) ($/MWH) (MWH) ($/MWH) (MWH) $/MWH) (MWH) ($/MWH) (MWH) ($/MWH)
Apr-98 522 $ 11.55 N/A N/A 235 $ 7.75 598 $ 6.83 323 $ 7.91
May-98 732 $ 9.45 N/A N/A 355 $ 7.49 708 $ 7.30 566 $ 7.92
Jun-98 1,179 $ 34.29 N/A N/A 398 $39.59 842 $ 3.05 832 $ 3.65
Jul-98 1,197 $ 57.86 N/A N/A 496 $76.93 877 $18.61 354 $115.50
Aug-98 1,042 $ 16.84 N/A N/A 723 $50.23 715 $37.08 653 $ 35.04
Sep-98 845 $ 0.77 N/A N/A 612 $23.50 504 $15.64 532 $ 11.87
Oct-98 805 $ 7.41 N/A N/A 301 $ 2.58 374 $ 0.63 209 $ 0.39
Nov-98 661 -$1.37 N/A N/A 277 $ 3.32 406 $ 0.86 161 $ 0.54
Dec-98 688 $ 27.32 N/A N/A 335 $17.87 294 $ 5.01 278 $ 2.10
Jan-99 738 $ 17.64 N/A N/A 465 $ 4.22 332 $ 0.57 210 $ 0.71
Feb-99 773 $ 10.28 N/A N/A 519 $ 2.72 320 $ 0.73 160 $ 0.79
Mar-99 711 $ 14.50 N/A N/A 319 $ 4.04 167 $ 0.68 142 $ 0.61
Apr-99 950 $ 18.15 N/A N/A 329 $ 7.50 159 $ 2.11 226 $ 1.55
May-99 820 $ 16.59 N/A N/A 142 $ 6.29 257 $ 3.18 142 $ 1.62
Jun-99 723 $ 24.01 N/A N/A 165 $ 7.07 283 $ 2.71 92 $ 1.33
Jul-99 872 $ 26.92 N/A N/A 386 $ 8.57 310 $ 8.10 101 $ 8.29
Aug-99 658 $ 15.98 30 $12.93 231 $ 7.08 291 $ 3.22 72 $ 4.33
Sep-99 574 $ 11.05 420 $13.05 246 $ 5.82 252 $ 1.65 30 $ 2.08
Oct-99 425 $ 12.16 442 $19.10 174 $ 8.39 169 $ 3.34 64 $ 4.03
Nov-99 263 $ 10.32 363 $21.76 99 $ 3.47 190 $ 1.59 62 $ 1.00
Dec-99 176 $ 7.55 287 $12.02 44 $ 1.89 173 $ 0.54 74 $ 0.40
Jan-00 269 $ 9.56 339 $12.34 58 $ 5.89 172 $ 0.25 40 $ 0.25
Feb-00 197 $ 8.75 245 $10.28 33 $ 2.62 156 $ 1.36 49 $ 0.48
Mar-00 227 $ 11.65 192 $ 9.58 17 $ 2.82 202 $ 0.58 63 $ 0.74
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 71
2.5.5 Block Forwards Market
Launched in July of 1999, the CalPX Block Forwards Market (BFM)
provides market participants with longer term trading instruments to
hedge price risk, increase market efficiency, and allow for improved
generation production planning. Block Forwards buy/sell orders are
accepted each weekday, excluding Sundays and NERC holidays, for energy
delivery up to 12 months in advance of the current month. Contracts can
be made in block multiples of 25 or singly in any quantity. Through
March 31, 2000, contracts were specified for delivery in either the
Northern California zone (NP15) or the Southern California zone (SP15).
Delivery can be scheduled through the CalPX Day-Ahead market or through
a bilateral market. When the Day-Ahead market is used for delivery,
CalPX provides execution flexibility, which can be customized to fit
specific participant needs and operating profiles.
As seen in Table 25, the volume of block forwards contracts has
steadily increased since its inception. Since the BFM market launch,
Southern California Edison and Pacific Gas & Electric have been
successful in obtaining regulatory approval for increasing maximum
block forwards volume from a combined 1,600 contracts to 5,600. One
contract is equal to 1 MW for 16 hours per day, Monday through Saturday
for the entire month. As of the beginning of June, nearly 5,000
contracts had been traded for the summer of 2000. From the beginning of
the market through March 31, 2000, 14,175 contacts had been traded for
a total energy output of approximately 40 million MWh.
Also in Table 25, the average BFM contract price for the delivery month
is compared to the Day-Ahead UMCP, the Day-Of UMCP, and the CAISO
Real-time price. The table averages only the on-peak hours of all
markets to provide a consistent comparison across the markets. The
CalPX average prices are weighted by volume. This table shows that
there are some months when the block forwards hedges resulted in
significant savings to the buyer of the contract.
New block forward products have been introduced to the market since
inception to provide greater flexibility of time blocks and delivery
locations. Quarterly products began in December 1999, super-peak and
shoulder-peak contracts on March 1, 2000. New delivery locations were
added on April 1, 2000, including Mead in southern Nevada, Palo Verde
in Arizona, and COB at the California-Oregon border. Starting May 15,
2000, the CalPX offered continuous monthly trading of ancillary
services capacity contracts for delivery in the Day-Ahead market. Daily
blocks and balance-of-the-month contracts are expected to launch on
July 5, 2000.
Starting on May 1, 2000, orders for forward contracts can be entered
using the CalPX new electronic system called Click.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 72
TABLE 25 BLOCK FORWARDS MARKET COMPARISON
BFM Contract Price vs. UMCP, Day-Of, and Real-Time Prices
BFM BFM
NP15 SP15 CalPX
Average Average UMCP On- ISO RT ISO RT
BFM Contract Contract Peak Day-Of On-Peak On-Peak
Contract Contract Price * Price * Average * On-Peak* NP15 ** SP15 **
Month Volume ($/MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh) ($/MWh)
Aug-99 1900 $48.31 $ 48.70 $40.29 62.01 43.70 44.35
Sep-99 3175 $39.72 $ 40.15 $39.43 39.20 45.18 42.12
Oct-99 1150 $ 33.58 $54.23 53.78 75.38 50.61
Nov-99 1125 $39.12 $45.22 42.22 51.99 38.65
Dec-99 2175 $38.37 $ 31.69 $32.42 28.47 35.06 34.27
Jan-00 1525 $34.51 $ 29.10 $34.53 31.71 36.79 34.85
Feb-00 1025 $ 30.42 $32.16 27.93 29.63 29.08
Mar-00 2100 $31.91 $ 31.44 $31.63 30.10 32.05 32.18
Apr-00 1850 $33.52 $ 34.79 $31.83 50.56 34.69 50.82
May-00 2025 $33.18 $ 35.01 $62.63 165.82 60.25 86.53
Jun-00 2900 $38.36 $36.55
Jul-00 4850 $65.61 $61.69
Aug-00 4700 $65.61 $66.19
Sep-00 4600 $65.61 $60.33
Oct-00 75 $47.25 $52.00
Nov-00 75 $47.25 $52.00
Dec-00 75 $47.25 $52.00
* As of May 28, 2000, weighted average
** As of May 28, 2000, simple average
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 73
2.6 Measures of Market Value
Section 2.2.2 summarized the transaction volumes for CalPX markets for
Years 1 and 2 of market operations. Trade volumes through the first two
years remain robust with Block Forwards Market volumes significantly
increasing, indicating the value of electricity markets in California.
Two measures of market share also indicate value. First, non-utility
generators - the new entrants into California power markets - have
increased their participation in CalPX markets from Year 1 to Year 2,
albeit still primarily focused on summer months where peak prices
provide peak opportunities to earn. Figure 33 shows the market share of
non-utility generators.
FIGURE 33 CHART OF NON-UTILITY GENERATION (SC TRANSFER) PARTICIPATION AS A
PERCENT OF TOTAL CALPX VOLUMES FOR YEARS 1 & 2
SC TRANSFERS % OF FINAL DAY-AHEAD SCHEDULE
[BAR CHART]
Second, investor-owned utilities, though required to buy and sell through CalPX,
are significant participants and play a critical role in the exchange. Their
share of participation is a majority of the liquidity in the exchange. So their
continued participation, in particular as long as they remain the dominant
distributors, is an important element in ensuring CalPX markets remain vital.
Figure 34 shows the market share of the IOUs as a percent of the total CalPX
volumes.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 74
FIGURE 34 CHART OF IOU PARTICIPANTS AS A PERCENT OF TOTAL CALPX VOLUMES FOR
YEARS 1 & 2
[BAR CHART]
The recent settlement agreement negotiated with and San Diego Gas &
Electric, following completion of its CTC recovery, ensured an active
participation by this company following the end of the transition
period. The negotiated agreement represented further evidence that
CalPX markets are valued and that they are likely to remain fully
supported by key IOU participants (though nothing assures this other
than CalPX's performance as the best exchange service).
However, the CPUC's recent ruling allowing multiple exchanges as tools
for CTC recovery reflects the uncertainty of the regulatory environment
in which reliable trading services are to be offered.
Another important measure of value is the CalPX share of the ISO's
Day-Ahead Final Schedules as shown in Figure 35. During the two years
of operation, the CalPX remains the dominant Scheduling Coordinator in
the CAISO system. The Must-Buy/Must-Sell provisions guarantee this
circumstances, but it is, nevertheless, an important measure.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 75
FIGURE 35 PX SHARE IN THE ISO DAY-AHEAD MARKET APRIL 1998 - MARCH 2000
[BAR CHART]
These indicators of market value illustrate the importance of CalPX
markets, and CalPX as an institution, to California electric power
market restructuring. In turn, the market monitoring responsibilities
associated with these markets is significant
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 76
3.0 Price Analysis
3.1 Introduction
Transmission grids for electricity have been described as displacement
networks where the only physical requirement is that the quantity
removed from the network at the delivery point must equal the quantity
supplied (adjusted for losses) at the receipt point.(25) In developing
performance indicators, the FERC identified a number of important
characteristics of prices in network industries:
- Variability - Price responsiveness to market conditions.
- Step functions/threshold effects - Sudden changes in price due
to limits on the network to deliver the commodity.
- Locational interdependence of prices - The impact that prices
have in one area affects other areas linked by the
transmission system.
- Implicit value transportation constraints - Pricing
transmission constraints to determine the most economically
efficient alternatives: generation, transmission upgrades, and
demand responsiveness.
- Linkages between services and interactions between related
markets developing price relationships between different
products, e.g. energy and ancillary services.(26)
Compliance has developed several price analysis models to help quantify
network-pricing characteristics. Section 3.2 describes how a simple
model using fundamental economic data can explain much of the price
variation experienced in the California energy markets over the past
two years. The model is also useful in identifying anomalous price
behavior that warrants further investigation by the Market Monitoring
staff. Section 3.3 uses technical analysis to quantify variability and
the step functions/threshold effects of market prices. A mean reversion
model is described, and its outputs discussed in terms of market
volatility, and measures of magnitude and duration of price spikes.
- ---------
(25) The Governance of Energy Displacement Network Oligopolies, Discussion
Paper 96-08, Federal Energy Regulatory Commission, Office of Economic
Policy, October 1996, Revised May 1997, p28.
(26) State of the Markets 2000, Measuring Performance in Energy Market
Regulation, Federal Energy Regulatory Commission, March 2000, pp. 26-27.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 77
3.2 Fundamental Models of Price Movements
3.2.1 Introduction
The descriptive analysis presented in Section 2 showed that nominal
prices in CalPX markets have increased over the two-year operating
history of the exchange.
At the same time, prices for various inputs such as natural gas rose.
Load growth and changing weather patterns also contributed to price
increases. As a result, the explanation for this apparent increase in
prices is not simple. This section develops a model of CalPX Day-Ahead
Market prices that explains trends and variability of price in various
fundamental factors. The model explains about 88% of the variability in
prices, using a simple and limited set of variables. More importantly,
the apparent upward trend in prices disappears when fundamental
economic factors are taken into account.
3.2.2 The Basic Form of the Fundamental Price Analysis Model
Compliance has developed a model to analyze factors affecting prices as
part of an overall statistical market monitoring system.
Market-clearing prices are modeled as a function of various inputs:
- Previous day's UMCPs and UMCQs.
- CAISO load forecast.
- Natural gas prices for PG&E , SoCal, and San Diego citygates.
- Temperatures at San Francisco, Sacramento, Los Angeles, and
San Diego .
- Coal plant availability of the three IOUs.
- Nuclear availability of the three IOUs.
Figure 1 shows the basic form of the model.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 78
FIGURE 1: THE BASIC FORM OF THE PRICE ANALYSIS MODEL
[FLOW CHART]
Today's prices are a function of the fundamental information known at
the time of price formation, yesterday's prices and some unexplained
variation.(27) Because prices in the Day-Ahead market are determined
simultaneously, the model must solve simultaneously.(28) The model uses
hourly numbers for loads, prices, and quantities, and daily quantities
for gas prices, temperatures, and coal and nuclear availability.
Forecast loads enter the model through a squared term as well as a
linear term, and a gas-temperature interaction term is used as well.
- ------------
(27) The model lags temperatures and gas prices by two days to reflect the
information known when Day-Ahead bids are submitted. The model is actually
an AR-2, with the endogenous Day-Ahead prices lagged by 2.
(28) Technically, the model is a weighted vector autoregression. Principal
components analysis is used to reduce the dimensionality of the exogenous
variables and avoid problems of collinearity. An iterative weighting
procedure is used to accommodate the heteroskedasticity and
autocorrelation in prices.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 79
3.2.3 Fundamental Price Model Results
Compliance's price analysis model was run on data from the first two
years of market operation, April 1, 1998 to March 31, 2000.
FIGURE 2: MODEL RESULTS
% OF VARIATION EXPLAINED BY FUNDAMENTAL VARIABLES
[LINE CHART]
Hour Ending
Figure 2 shows the relative contribution of various fundamental factors
across each of the hours for the two years of market operations. (29)
Overall, the model explains about 88% of the variation in prices. The
top layer of the figure is the unexplained variation in the model. The
model can account for more of the variation on off-peak hours than for
on-peak hours.
As discussed earlier, the Day-Ahead unconstrained price has appeared to
trend upward during the first two years. Figures 3 and 4 show prices
for hours ending 4 and 16 for the first two years along with the trend
line.
- ----------
(29) The relative contributions were derived by running the model separately
for each exogenous variable. The resulting R(2) s were then weighted by
their relative contribution so that they equaled the R(2) for the full
model. These results indicate the relative importance of each variable's
contribution.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 80
FIGURE 3: TREND OF RAW PRICES FOR HOUR 4
UMCP, HE 04, 4/1/98 - 3/31/00
[LINE CHART]
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 81
FIGURE 4: TREND OF RAW PRICES FOR HOUR 15
UMCP, HE 16, 4/1/98 - 3/31/00
[LINE CHART]
The trend for hour 4 is greater than that for hour 16. The apparent
trends for on-peak hours were less than for off-peak hours.
However, when fundamental factors are taken into account, the raw price
trends largely disappear. Figures 5 and 6 show prices adjusted for
fundamentals(30) along with the trend line when the fundamentals are
taken into account. For both hours 4 and 16, the trend disappears.
- --------
(30) These are the residuals from the model estimation.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 82
FIGURE 5: PRICE TRENDS ADJUSTED FOR FUNDAMENTAL FACTORS FOR HOUR 4
UMCP, HE 04, Adjusted for Fundamentals
[LINE CHART]
FIGURE 6: PRICE TRENDS ADJUSTED FOR FUNDAMENTAL FACTORS FOR HOUR 16
UMCP, HE 16, Adjusted for Fundamentals
[LINE CHART]
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 83
Figure 7 illustrates the situation for all hours. The apparent price
trends indicate price increases ranging from about $5 to $8 per MWh.
When adjusted for fundamental factors, the overall annual increase is
about $1 per MWh. The remaining increase in hourly prices not explained
by the model may be due to other fundamental factors not considered,
such as: cost of other inputs, availability of units other than nuclear
and coal, hydro conditions, or precipitation. Figure 8 shows the
percentage price increase explained by fundamentals for each hour.
Overall, about 80% of the increase is reflected in the fundamental
factors used. In the afternoon hours, which had the lowest apparent
price increase, the model explained only about 60% of the trend. While
the off-peak prices represented the greatest increase in price, the
model explained 85% to 95% of this increase.
FIGURE 7: PRICE PATTERNS IN THE DAY-AHEAD MARKET FOR ALL HOURS FOR THE FIRST TWO
YEARS OF MARKET OPERATIONS
ANNUALIZED LINEAR INCREASE IN UMCP 4/1/98 - 3/31/00
[LINE CHART]
\
Hour Ending
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 84
FIGURE 8 % OF PRICE INCREASE EXPLAINED BY FUNDAMENTALS
[LINE CHART]
Hour Ending
The significance of this analysis for market monitoring purposes is
twofold. First, the analysis demonstrates that most CalPX Day-Ahead
Market price movements can be explained as a function of fundamental
factors. If fundamental factors can explain price movements, then it
would appear that the Day-Ahead market is functioning like other normal
commodities markets.
Second, the price model itself becomes useful as a means of automating
one aspect of concern when monitoring markets, i.e., how can variances
be explained? For purposes of illustration, normal is defined as a
bandwidth of three standard deviations from the price signal. If price
events fall outside this range, then Compliance devotes special
attention to explaining why this has occurred. Figure 9 below selects
one representative week in 1999 to illustrate how the monitoring
process is enhanced when using a price model with bandwidths to monitor
prices.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 85
FIGURE 9: STATISTICAL BANDWIDTH MONITORING OF PRICE MOVEMENTS IN CALPX'S
DAY-AHEAD MARKET
UMCP
[LINE CHART]
Day of 1999
A bandwidth of three standard deviations around the actual price and
the model's price prediction shows that high prices do not necessarily
trigger an alarm.(31) For example, in this week, an alarm was triggered
by several price events outside the bandwidth during relatively low
prices. This prompted Compliance to analyze more carefully these price
events.
This system identifies anomalous events on an ongoing basis. It does
not substitute for staff consistently and constantly watching price
movements and evaluating them daily. But it does provide enhanced
filtering tools, enabling Market Monitoring staff to focus on
particular price events.
Analysis of explainable variance derived from fundamental factors
coupled with the integration of this price model into ongoing market
monitoring has increased Compliance's confidence that CalPX markets are
operating effectively.
- ----------
(31) The bandwidth of three standard deviations is illustrative. Actual
bandwidths are confidential.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 86
3.3 Technical Models Concerning Price Behavior in CalPX Markets
3.3.1 Technical Price Movements and What They Communicate
While fundamental models capture the relationship between price and
external factors, technical analysis is concerned with describing
market behavior captured in the movement of market prices. From a
technician's perspective, if all information is reflected in the price
of a stock or commodity (a principle of the efficient market
hypothesis), why look for external fundamental information when an
analysis of price activity is sufficient in understanding market
behavior?
3.3.2 Price Mean Reversion
Price mean reversion is considered an appropriate technical model for
describing price behavior in energy markets.(32) Mean reversion models
assume that the commodity being modeled has some equilibrium price
level toward which market prices move. However, events can cause prices
to spike.(33) The mean reversion model measures the duration of price
spikes as well as the random noise, or volatility, around the
equilibrium price. Figure 11 illustrates the price behavior that this
mean reversion model attempts to capture. A summary description of mean
reversion model results is included in Appendix C.
- ----------
(32) Energy Risk, Valuing and Managing Energy Derivatives, Dragana Pilipovic,
McGraw-Hill, New York, 1997, p 30.
(33) Spikes are similar to the sudden changes in price described as step
functions and threshold effects in FERC's State of the Markets 2000. p. 8
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 87
FIGURE 10
ELEMENTS CAPTURED BY PRICE MEAN REVERSION
MODEL
[LINE CHART]
3.3.3 Price Spike Behavior
Table 1 shows the model derived alpha and the estimated number of days
required for prices to return to their mean price levels for the CalPX
Day Ahead UMCP, zonal price, the Day Ahead COB and PV on-peak prices,
and the CAISO real time zonal price. The CalPX and CAISO prices have
been converted to 6 X 16 on-peak block prices for comparison. Although
price spikes do occur, prices typically return to mean price levels in
about two days. From a market monitoring perspective, the speed of mean
reversion can be tracked over time to determine if prices can be
maintained over reversion levels for a sustained period of time. If the
mean reversion pattern changes, Compliance examines the spike more
carefully.
TABLE 1
Market Estimated Model Estimated # of Days to Daily Volatility of
(On-Peak) Parameter Alpha Return to Mean Price Returns- Sigma
UMCP 267.0 1.15 23%
NP15 Zonal 271.7 1.13 26%
SP15 Zonal 284.3 1.08 24%
NP15 Real Time 169.6 1.81 51%
SP15 Real Time 183.8 1.67 62%
COB 307.0 1.00 15%
PV 178.5 1.72 13%
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3.3.4 Market Volatility
The amount of noise measured in the model is also useful. The noise
(sigma) is measured as the annualized volatility of price returns. This
definition of volatility is used, for example, by market Participants
to value options (puts and calls) on energy. While market Participants
have expectations about what prices will be in the future, volatility
provides an indication of how wrong that expectation is likely to be.
The greater the volatility, the wider the distribution of prices around
the mean, and the more valuable the option.
Volatility is also used in portfolio analysis to estimate the risk in
returns on an asset or an open (unhedged) position in the market place.
The daily volatility of price returns is shown in Table 1. For hour
ending 4 p.m., daily volatility ranges from 35% to 40% in the CalPX Day
Ahead markets. For example, given a $50 per MWh expected price and 40%
volatility, prices are expected to range for $30 to $70 per MWh, 68% of
the time. The CAISO Real Time zonal prices are much more volatile even
though, as shown in section 2, average prices between the CalPX and
real time markets are about the same. Portfolio managers attempting to
minimize their risk will prefer forward markets to real time prices
given the relative measures of uncertainties.
This type of analysis is useful in quantifying relative values and
risks between different markets thereby establishing "interactions
between related markets". While not quantified here, this type of
analysis is also useful in valuing ancillary services such as a call on
spinning or replacement reserves. Compliance intends to expand its
analysis in these areas over the next year.
3.4 Analysis of the Uncoupling of Wholesale and Retail Price Elasticity in
California Electricity Markets
3.4.1 Overview
In the Second Report by the CalPX Market Monitoring Committee, the
Committee noted the importance of increasing demand responsiveness as
part of the remedy to Committee concerns expressed about the
inelasticity of demand observed in CalPX markets. Current demand
responsiveness programs have been unable to attract a large number of
consumers. Most retail customers are unable to see a market price
signal and respond. However, products are available in the wholesale
market that energy service providers can use to hedge a margin between
the revenues received from fixed price agreements with retail customers
and the market price risk incurred as a result of purchasing energy to
serve retail load.(34) The retail service provider can participate in
the CalPX Block Forward Market; Day Ahead, Day-of, and CAISO Real-Time
markets. The choice of which market to use and how much energy should
be purchased is a function of expectations about price and price
uncertainty (volatility) in each market. This choice among the four
markets has created a structural elasticity where the service provider
can purchase energy in a particular market or defer that choice to a
subsequent market.
- -----------
(34) These fixed prices were established as part of the legislated
restructuring.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 89
Compliance has analyzed CalPX Day-Ahead Market elasticity for the last
two years and found greater elasticity than that found in retail
elasticity studies. These findings are encouraging for several reasons:
- Increased wholesale market demand elasticity indicates a
market more responsive to price signals, which in turn is a
market less susceptible to manipulation or exertions of market
power.
- Evidence of a demand responsive market, coupled with evidence
that price moves, for the most part, on the basis of
fundamentals, reinforces the view that CalPX markets are
operating in a fashion similar to other commodities markets.
- Wholesale products are being created to help energy service
providers manage their price risks. These wholesale products
can also assist in the creation of new retail products that
may improve retail demand responsiveness, and hence retail
price elasticity, over time.
- These findings are helpful to Compliance's efforts to shift
from evaluating every price movement to focusing on exceptions
to well-defined norms of expected price behavior. This in turn
will help reduce the costs of ongoing market monitoring.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 90
4.0 CALPX COMPLIANCE ACTIVITIES
4.1 Introduction
A market monitoring function is essential for institutions involved in
operating electricity markets. The FERC emphasized the importance of
market monitoring in approving the start of California markets in
October 1997. Under FERC Order 2000, all RTOs are required to
incorporate market monitoring in their designs.
Under any circumstances, institutions should insist upon
self-regulation of its markets. To do so requires effective market
surveillance and compliance-related functions, which, in turn, require
that market monitoring becomes systematic.
This section describes CalPX market monitoring methods and practices
followed by a discussion of the role of Compliance in policy-making.
The section concludes with a proposal for creation of a Business
Conduct Committee and proposed rules changes.
4.1.1 Being Methodical in the Early Phase of Market Operations
Because the electricity markets are in their formative stages, market
monitoring requires care, thoughtfulness, patience, and commitment to
understanding trade behavior comprehensively before declaring rules
violations or various forms of market manipulation.
This is particularly important in California's market system because of
the complexity of its structure and operations. For example, suppose a
Generator allocates production between the Day-Ahead, Day-Of,
Real-Time, and Ancillary Services markets. What is withholding and what
is rational allocation? Because withholding is one of the paramount
forms of market manipulation, getting this right is important. But
proving that it is intentional manipulation - rather than rational
allocation based on sound business and bid strategy - is no small task.
Consider another example: Suppose a Participant has a scheduling
problem and gets help from the CalPX, or the CAISO, which may involve
getting other Participants to modify their adjustment bids. If ensuring
reliability is at the heart of the solution, is this market
coordination and collusion or is it ensuring system reliability?
Another example to illustrate the point: If a Participant places an
adjustment bid on a line with the deliberate intention of disciplining
the behavior of others who compete to use that line, how is this
treated? It could be a rules violation. It could be inappropriate
bidding behavior, not understanding that disciplining competitors is
not the job of other
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 91
Participants. It could be a form of coordination if the disciplined
Participant moves off the line and does not try to use it anymore. Or,
it could be just smart trading.
These examples also illustrate that market monitors may differ in their
actions, depending on when behavior:
- may be experimental;
- is associated with learning but not designed to damage the
market deliberately;
- is inappropriate;
- is a deliberate, intentional manipulation, and/or
- involves coordination that undermines fair market operations.
Because a considerable element of judgment is required, Compliance
staff need diverse backgrounds - engineering, economics, operations
research, legal, financial, power marketing, and trade floor
experience. A senior management with an understanding of
self-regulating commodities exchanges and power marketing operations is
also critical.
The judgment factor in the market monitoring process also takes into
consideration a diverse source of information outside typical data
analysis, including direct discussions with Participants. Compliance
also seeks to understand the market thoroughly - attending conferences,
monitoring various electronic forums and publications, talking to
people involved in the business, and communicating with market
monitoring staffs in other institutions, i.e., the CAISO Department of
Market Analysis.
4.2 Market Monitoring Methods and Practices
Methods for effective surveillance of trade behavior in the electricity
markets are in their earliest stages of development. Market monitoring
functions in RTOs, ISOs, and PXs need distinctive tracking systems as
well as judicial processes for investigating and prosecuting rules
violations. Structure and processes for interaction with various
governmental bodies and institutional governance need be tailored to
the unique characteristics of each system.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 92
4.2.1 Organization and Responsibilities of the Compliance Unit
Compliance is composed of three functional areas: market monitoring,
economic analysis, and investigations.
[ORGANIZATIONAL CHART]
In July 1999, Compliance consisted of the Market Monitoring Manager and
two analysts, with a part-time consultant serving as acting Director.
This level of staffing was inadequate. For example, Compliance received
the first formal complaints from Participants in May 1999, asking for
an investigation of a market event. The staff, involved in daily,
weekly, and monthly reports, could not be spared because they were the
primary means of keeping all CalPX market information flowing.
Compliance retained outside counsel and a consultant to investigate.
At the same time as the May incident, Compliance identified a need for
statistical models to help distinguish normal and abnormal market
behavior and decide if incidents merited investigation. Other models
help understand the interactions between the various CalPX, CAISO, and
bilateral markets. Without these models, significant trends indicating
rules violations or market power could not be distinguished from smart
trading. The same constraint, keeping the periodic reports flowing and
the need for modeling specialists, also kept Compliance from moving
forward on this important work
Recruitment for additional staff began in August 1999. The staff now
consists of the Vice President of Compliance, Audits and Regulatory
Affairs, overseeing the Director of Economic Analysis, the Market
Monitoring Manager, and the Acting Director of Investigations.
Market Monitoring still consists of the manager and two analysts and is
primarily responsible for identifying events that trigger further
inquiry, then providing the analysis and information regarding those
events to the Vice President, the CEO, and the Market Monitoring
Committee.
Economics Analysis consists of the Director and two analysts, an
economist and a mathematician. It is primarily responsible for building
the statistical and analytical systems. This team also provides special
analyses requested by the CEO and other CalPX officers, as well as
analytical support to the efforts of the MMC.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 93
Currently, the position of Director of Investigations is filled on an
acting basis because normal investigative workload will not be known
until the transition phase is completed. The Acting Director of
Investigations relies on both Economic Analysis and Market Monitoring
staff for investigation support, as well as outside counsel.
4.2.1.1 Market Monitoring Group
When the market first opened, the size of the Market Monitoring staff
was only sufficient to provide periodic reports with minimal analytical
content. Reports are now made on a daily, weekly, and quarterly basis
and have high analytical as well as statistical content, providing
insights into the workings of the markets.
The Market Monitoring Group is responsible for the daily monitoring of
trade behavior in all CalPX markets. During the first two years of
operations, the Market Monitoring Manager focused on upgrading data
systems to support the monitoring effort.
Market Monitoring and the other Compliance groups work with huge
databases, profoundly larger than databases in other markets. In
addition to buy and sell or bid/ask structures, the electric power
market data includes trades, schedules, congestion, settlements and
others. These data interact because the markets interact. Accordingly,
the market monitoring function analyzes data every hour of every day
for every Participant:
- in the Day-Ahead Market;
- in the Day-Of Market (because the valid transaction hours are
not equal to all hours of the day), and
- in the huge related files for settlements information,
CAISO-related information, and smaller, but important,
databases for Block Forwards and PCQM.
The data storage requirements have significantly exceeded expectations.
The software systems already have been upgraded. Ensuring that the data
is error-free is a time-consuming, ongoing challenge. Issues of
security and quick recovery of data from crashes have been important
challenges as well.
Sifting through trade and related data on a daily basis is further
complicated when modeling-related work is incorporated. The CalPX now
uses the data loads for the first two years of market operations daily.
Compliance plans to keep three years of data active before archiving
any material. The online live-time series may need to be extended
further, depending on what occurs in the third year of operations.
Significant progress has been made on improving the data warehouse and
associated data marts. With the core data challenges largely under
control, the task of monitoring is being made more efficient through
the automation of certain daily monitoring routines. The use of
statistical techniques to trigger alarms when critical variables fall
outside defined statistical norms is key to increasing monitoring
productivity.
As such, more sophisticated approaches to monitoring are also being
developed for use by Market Monitoring. For example, many Participants
use Mean Reversion and Option Valuation models to make decisions about
market participation. Compliance is now
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 94
developing similar models to develop a deeper understanding of
Participant behavior. Models seeking to better understand interactions
between markets are also being constructed. Most importantly, staff is
developing sophisticated statistical approaches to observe, and note
for possible inquiry, trends normally hidden in raw data.
4.2.1.2 Economic Analysis Group
The Economic Analysis Group is the primary lead on developing these
market models to help Market Monitoring sort explainable events from
events that indicate various forms of market manipulation or rules
violations.
Recently, Economic Analysis completed the first phase of a study
evaluating factors that explain price movements in the marketplace;
whether price movements can be explained by fundamentals, and, in turn,
whether price movements are influenced by undesirable design flaws,
market manipulations, or exertions of market power. Section 3 of this
report discusses these results.
Economic Analysis also is developing statistical process control
modeling that provides Compliance with enhanced tools for identifying
variances from normal trade behavior. The general parametrics being
used are based on bandwidths of deviations from the actual price
movement in the market.(35) For specifically sensitive variables,
tighter parameters are applied.
The above techniques do not exhaust the tools available to Compliance.
Generally, Compliance does not discuss the tools it uses, except in
general terms, to avoid contributing to what Compliance staff refers to
as the Iron Law of Manipulation. That is, once one knows how the game
is played, then the game can be manipulated for the benefit of one's
own self interest, no matter how often the rules of the game get
changed.
Economic Analysis is also developing models that help Compliance
understand market interactions and how these interactions may influence
buyer and seller decision-making. A richer understanding of how markets
interact helps in the complicated process of sorting rational bidding
and smart trading strategies from irrational or thoughtless behavior
and from deliberately manipulative behavior.
4.2.1.3 Investigations and Inquiries
Market monitoring is a key part of ensuring that CalPX markets operate
fairly. While some monitoring involves studies that may lead to MMC
market power mitigation, most of the effort involves ensuring that
Participants adhere to existing rules and that new rules are developed
for dealing with problems of abuses that are not problems of market
power. The principal process through which the concerns are addressed
is through the conduct of inquiries and investigations.
The Director of Investigations, utilizing the work of the Marketing
Monitoring and Economic Analysis groups, conducts investigations and
inquiries. The position is now filled on an acting basis until
Compliance determines whether a permanent position is warranted once
the transition period is terminated.
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(35) These bandwidths are confidential.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 95
Compliance performs many inquiries and far fewer investigations.
Inquiries are internal studies by Compliance to determine if a formal
investigation is warranted. Investigations are activated either by the
filing of a written complaint by a CalPX Participant or by Compliance
acting on its own. Compliance responds officially only to written
complaints that provide specific information as to the nature of the
suspected violation or event that the Participant desires Compliance to
investigate.
Compliance will respond to a formal written complaint in one of three
ways:
- Undertake a detailed investigation.
- Group the inquiry with other similar inquiries.
- Find the complaints warrant no action on Compliance's part.
Participants sometimes call Compliance informally, asking about certain
market events. Compliance responds to these calls with available
non-confidential information. However, Compliance has no obligation to
pursue the matter further. Any pattern in the types of calls that may
warrant further inquiry is noted. Staff also initiates an inquiry when
the CalPX notes exceptional behavior. If the initial inquiry finds
nothing suspicious, the matter is closed.
For inquiries that arouse suspicion of rule or market power violations,
a brief description of the findings is provided to the CEO and the MMC.
A decision is then made on making further inquiries that might lead to
a formal investigation.
Sending a letter to the Participant suspected of breaking CalPX market
rules formally opens an investigation.(36) In that letter, Compliance
describes what is being investigated and the CalPX rules that may have
been violated. Compliance then asks to interview the Participant on the
record.
After analyzing the results of the interview, as well as evidence
gathered from recorded telephone conversations and other sources,
Compliance recommends to the CEO whether a hearing should be held and
informs the MMC. If the CEO decides to proceed to a hearing, Compliance
sets a hearing date. Compliance will prepare a brief for the CEO four
weeks before the hearing with a copy sent to the Participant. The
Participant will then have two weeks to submit a rebuttal brief with a
copy sent to Compliance. Two weeks after that date, a hearing will be
held.(37)
At the hearing, Compliance and the Participant each have up to one hour
to make a verbal presentation to the CEO. A member of the Market
Monitoring Committee will act as advisor to the CEO throughout the
hearing. The CEO, the Participant, and Compliance all may choose to
have counsel present at the hearing. After the hearing is completed the
CEO will determine whether a violation of the rules has been proven and
will then take appropriate action as authorized under Schedule 5, of
the Tariff Section 2.3.2.
- ----------
(36) Violations of CalPX Operating Manual Rules, Tariff, Protocols and
Participation Agreements are collectively referred to as market rules.
(37) Based on advice of Compliance Legal Counsel, Compliance assumes that all
information presented in a brief to the CEO and the Participant is
discoverable.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 96
At any point in the investigation process, the CalPX and the
Participant may negotiate a settlement. In other commodities exchanges,
more than 90% of investigations are settled before coming to a formal
hearing.
These procedures were developed in the course of several inquiries and
one investigation in the second year and comply with the authority now
granted under the current Tariff and Rules.
4.3 The Role of Compliance in Policy-Making
In the first two years of market operations, Compliance worked to
define its proper role in the CalPX. Compliance was asked periodically
to become involved in public and institutional policy matters, such as:
- Compliance's view on a particular Participant's asset
disposition plans.
- Recommendations for the bandwidths on the Post Close Quantity
Match.
- Championing rules changes.
From the start of the market monitoring effort, Compliance took the
position that it should not be involved in policy-making except as an
advisor concerning questions that should be addressed as policies are
formulated. Such questions draw Compliance into policy-making arenas
that, if Compliance were to respond, would compromise its objectivity
as an independent evaluator and monitor of market activities.
To ensure its objective position, Compliance emphasized the importance
of obtaining formal approvals for its activities from the CEO and, as
appropriate, the MMC. Associated with this commitment to objectivity is
Compliance's current effort to refine and formalize the disciplinary
procedures to be followed as it investigates allegations of misconduct.
In an uncertain and rapidly changing environment, market monitors must
be clear and deliberate about roles and responsibilities. The
importance of careful and deliberate design and implementation of
market monitoring disciplinary systems cannot be over-emphasized given
the extraordinary diverse institutional and market designs in operation
in the United States. With market monitoring a required element of
responses to FERC's RTO initiative due this fall, careful thinking now
is even more critical.
4.4 Establishment of Institutional Disciplinary Infrastructure
To ensure due process for CalPX participants, Compliance is proposing
the creation of a Business Conduct Committee (BCC) and a disciplinary
process. This section outlines the reasons for this proposal and the
relationship that would exist under the new disciplinary process
between the proposed BCC, the current Market Monitoring Committee
(MMC), and Compliance.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 97
4.4.1 The Problem
Under current CalPX market rules governing Market Monitoring, the CalPX
CEO now sits in judgment on any disciplinary case brought forward by
Compliance. The MMC as a group, or the Chair of the MMC alone, may
advise the CEO. This system places the CEO in an untenable position.
First, he must balance his role as the leader of the institution and
his role as judge in an investigation proceeding. Second, he is
vulnerable to accusations of partiality.
Under existing procedures, a respondent does not break any rules by
lobbying the CEO, as well as other officers of the CalPX, to counteract
or nullify the efforts of Compliance. If the CEO listens, he becomes
compromised as a judge of the case. If the CEO does not listen, he
becomes vulnerable to accusations by the respondent of being biased.
The issue of due process for the respondent also arises. The ultimate
manager of the Compliance function is currently the CEO, who sits in
judgment. Under these circumstances, respondents could rightly feel it
would be difficult to get a fair hearing.
4.4.2 Proposed Solution
The CalPX is in the process of proposing the establishment of a BCC to
solve the above problems.
If the proposals are ultimately approved, the BCC will be composed of
seven to nine members nominated by the CEO for their industry
experience and respect among peers. The nominations will be submitted
to the Board for approval. BCC members will be required to sign strict
confidentiality agreements. The Chair of the Governing Board selects
the Chair of the BCC. The Chair of the BCC may select one, several, or
all of the BCC members as a hearing panel to hear the case from
Compliance and the rebuttal by the respondent. The nature and size of
the case will determine who and how many BCC members are selected. This
BCC group will then determine whether Compliance has made its case,
whether a penalty should be assessed, and the nature of the penalty.
As a new committee, the BCC's relationship to the existing market
monitoring system needs to be considered carefully, particularly its
relationship to the MMC and Compliance.
4.4.3 Roles of the MMC and Compliance with regard to the BCC
In keeping with Compliance's emphasis on behavior and rules, Compliance
is proposing to create a second track for the adjudication of rules
violations, while leaving intact the existing approach that is
primarily focused on issues of market power and market design.
The proposed new track, focused on rules violations, will be the
responsibility of the BCC. The MMC will deal with issues of market
power as they relate to changes of rules or market design. Another way
of characterizing the difference in roles is that the BCC will be
dealing primarily with judicial issues and application of sanctions and
penalties, if approved, with Compliance acting as the prosecutor. The
MMC will be kept informed of BCC actions. The MMC will continue to
focus primarily on policy issues related to market power and market
structure, making referrals to other authorities for penalties with
Compliance providing supporting analysis.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 98
Nothing precludes the same incident from being the focus of proceedings
on both paths simultaneously.
At any point in the process, the MMC or the CalPX Board can refer
anti-trust violations or violations of other pertinent federal or state
law to the relevant authorities.
4.5 Rules Changes
As a result of the second year's experience, Compliance recommended
rules changes to CalPX management to address problems identified
through inquiries and investigations. These changes involve both
procedural rules, as well as market operating rules that would require
changes at the CAISO as well as the CalPX. CalPX management is
currently reviewing these recommendations. They will come before the
FERC after a thorough public process.
One major problem is that existing rules are vague, at best, in
describing the procedures to be followed in rulemaking. For example,
neither the Tariff nor the By-laws address how a new Tariff section is
to be adopted or an existing section is to be amended.
One serious omission is that a Participant does not have the right to
request that the CalPX undertake a rulemaking. Involvement of all
interested parties is important to the success of any rulemaking. As
currently worded, the rules do not explain what consulting with
Participants means. By-law Section 4.4 authorizes the Board to
designate a Technical Advisory Committee to advise the Board "on
additions and revisions to its rules and protocols, tariffs,
reliability and operating standards and other technical matters."
One approach would be to create a parallel committee of Participants to
advise the CEO on additions and revisions to rules. In addition,
non-exchange working groups, such as the Western Power Trading Forum
(WPTF), have been useful in focusing industry attention on certain
aspects of the rules, but they lack a formal mechanism for bringing
their recommendations to the exchange. This oversight should be
remedied in any revision of the rules.
Compliance recommends the early establishment of a rulemaking procedure
as outlined below. After a thorough review by both the CalPX management
and Participants, Compliance anticipates submitting a detailed
recommendation to the FERC.
4.5.1 Compliance's Recommendation
Compliance recommends creating a permanent Advisory Committee on Rules
(ACR) with responsibility for developing, at the request of the CEO,
recommendations for changes and additions to the Tariff and Protocols.
The ACR should:
- consist of representatives from seven Participants selected by
the CEO;
- be chaired by a Participant selected by the CEO;
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 99
- be staffed by Compliance, which will undertake empirical
research where needed and prepare related documents at the
direction of the RC, and
- recommend rule changes to the CEO.
At the CEO's discretion, the recommended rules changes will be
submitted to the Board for its approval. Upon Board approval, the CalPX
will file the rule changes with the FERC. The submission will contain
material dissenting comments, if any, from Participants or Board
members;
As a first order of business, the new ACR should recommend the
establishment of a process for making rule changes and modify the
Tariff and relevant Protocol sections to reflect the addition of the
ACR.
4.5.2 Current Rules Changes Being Contemplated
As a result of investigations undertaken in the second year of
operations, Compliance will be recommending rules changes to the CalPX
Board of Governors. If approved, the proposed changes will undergo a
formal public process for review and comment before submitting the
changes to the FERC. Basically, the rule change itself is
self-explanatory for the behavior that Compliance wishes to see stopped
and for which it feels current rules are inadequate.(38)
1. No Participant shall submit a schedule that exceeds the rated
capacity of a transmission line without a reasonable
expectation [based on historical data] of a counterflow equal
to the difference between the rated capacity of the line and
the amount scheduled for delivery on that line.
2. Scheduling on a zero-rated line shall constitute a per se
violation of (1) above.
3. No Participant shall submit adjustment bids that exceed the
rated capacity of a transmission line without a reasonable
expectation [based on historical data] of a counterflow equal
to the difference between the rated capacity of the line and
the amount of the adjustment bids.
4. No Participant shall submit adjustment bids on a zero-rated
line.
5. No Participant shall act with the primary purpose of
deliberately creating congestion for purposes of benefiting
individual self-interest.
6. No Participant shall supply information to the CalPX, whether
as a part of a required report, at the request of the CalPX or
on its own initiative, which the Participant knew or should
have known was false.
7. No Participant shall impede or delay a CalPX investigation.
In addition to the above rules, once a formal investigative procedure
is established that guarantees Participants' rights to due process and
protects the CalPX's need to conduct
- -----------
(38) Details of how these recommended rules changes arose from investigations
and inquiries are omitted to protect the confidentiality of CalPX
Participants.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 100
efficient and orderly investigations, Compliance will recommend that
sanctions and penalties be established for failure to comply to rules.
All commodities markets in the world have experience with participants
attempting to circumvent exchange rules. No commodities exchange has
managed to halt effectively the attempts of miscreant participants to
circumvent exchange rules without having the power to impose penalties
for violations. As the CalPX markets grow and evolve, it will be no
different.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 101
APPENDIX A
HOW PCQM WORKS:
The place where these bandwidths, which were taken above and below the
MCP, intersected a Participant's bid curve would determine the quantity
that that particular Participant was able to bid into the PCQM. The
following example illustrates this for a supplier.
EXAMPLE 1
HOW THE BANDWIDTH WORKS
ASSUMPTIONS:
- ------------
SUPPLY BIDS: 0MWh @ $0
Quantity @ $25 = 25MWh
25MWh @ $25
50MWh @ $50
MCP = $25/MWh Market= Day-Ahead
Hour = 16 Bandwidth = 15%
Calculations:
- -------------
MCP + 15% = $28.75
Quantity at $28.75 = 28.75MWh
Eligible PCQM Bid = 3.75MWh
Figure 1 shows Example 1 graphically.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 102
FIGURE 1 OF APPENDIX A
GRAPH OF EXAMPLE 1
[GRAPH]
Quantity (MWh)
For a buyer, the bandwidth would be calculated below the MCP.
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SECOND ANNUAL REPORT TO THE FEDERAL ENERGY REGULATORY COMMISSION
CALIFORNIA POWER EXCHANGE CORPORATION MARKET COMPLIANCE UNIT
COMBINED 1ST DRAFT - JUNE 15, 2000
ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 103
APPENDIX B
STILL PENDING
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ELECTRICITY MARKETS OF THE CALIFORNIA POWER EXCHANGE PAGE 104
APPENDIX C
Dynamic stochastic models of prices are used for both market analysis
and asset pricing in the financial and energy markets. The models used
in the energy markets and especially in the power market often contain
mean-reversion terms, i.e., the dynamic models possess features that do
not allow prices to grow unchecked, but instead tend to move prices
over time to some normal level. The current work has applied two models
to power prices: The first is a mean-reverting model with one
stochastic element. The parameters in the model provide two measures.
The first is an estimate of how long it takes for prices to return to
normal levels once they have moved away. This provides a measure of how
long price departures are sustained from what would be considered
normal levels. The second parameter provides a measure of the
volatility, or level of variability, present in the market. The second
model considered contains a mean-reversion term, but it also provides a
term that models the jumps that occur in power prices. One of the
characteristics of power prices is that prices periodically spike to
abnormal levels. This model also captures a measure of time departure
from normal levels and a measure of volatility as in the first model.
In addition, it separates the volatility into two terms, one that
represents the normal variation of the power prices, and a term that is
the volatility present during price jumps. The model also measures a
parameter representing the probability of a price event. The models
were applied to data from the California Power exchange (CalPX),
Real-Time, and bilateral markets. The time period of the data is over
the first two years of the existence of the CalPX, from 4/1/98 through
3/31/00. To compare similar products to the California-Oregon-Border
(COB) and Palo Verde (PV) markets, CalPX and Real-Time hourly prices
were averaged over the 6 x 16 on-peak hours in the time period to
produce what would be an on-peak price. Specifically, for each on-peak
day in the period, 16 hourly prices were averaged to produce a single
value in each of the UMCP, NP15 Zonal, and SP15 Zonal price series in
the CalPX, and the NP15 and SP125 CAISO Real-Time price series. The COB
and PV prices are based upon the Dow Jones published day-ahead prices
for on-peak power. Table 1 contains the results from the mean reversion
model with one source of stochastic variation. The first column
represents an estimate of the percent of the deviation from normal
levels that is recovered in 1 day. The second column estimates how many
days are required to recover 75% of a deviation from the normal level,
assuming new information has not impacted prices. The third column is
the estimate of volatility over one day, and the fourth is the average
price.
1 Day Movement # of Days Daily Volatility Average Price
UMCP 58% 1.59 23% 32.61
NP15 Zonal 59% 1.57 26% 33.60
SP15 Zonal 60% 1.50 24% 32.06
NP15 Real Time 42% 2.51 51% 34.22
SP15 Real Time 45% 2.32 62% 31.94
COB 63% 1.39 15% 30.50
PV 44% 2.38 13% 31.35
Table 1
Departures from average conditions are not sustained for very long in
the CalPX and bilateral markets, a little longer in the Real-Time
market.
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Table 2 contains the results for the mean-reversion model that also
models the price spikes. The first column contains an estimate of the
percent of the deviation from normal levels that is recovered in 1 day.
Column 2 contains a measure of normal variation, column 3 contains a
measure of variation if a price spike occurs, and column 4 contains the
probability of a price spike for a given day.
1 Day Movement Daily Volatility Jump Volatility Prob. of Jump
UMCP 55% 7% 35% .374
NP15 Zonal 56% 9% 45% .299
SP15 Zonal 58% 8% 36% .400
NP15 Real Time 37% 26% 125% .123
SP15 Real Time 37% 28% 181% .097
COB 63% 6% 20% .423
PV 42% 4% 17% .438
Table 2
The parameter measuring the speed at which prices return to normal
levels has not changed significantly over the results from the first
model. The significant increase in volatility in column 3 over column 2
indicates that much of the volatility measured in prices is due to the
spikes. Column 4 measures a much lower probability of a price spike in
the Real-Time market over the other markets. One possible explanation
is that the Real-Time prices tend to have a much greater spread, which
makes it easier to distinguish between normal prices and event prices.
In contrast, the other markets have prices that do not vary as much,
thus it is not as easy to differentiate between normal prices and jump
prices.
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APPENDIX D
Correlation between assets plays an important role in portfolio theory
and risk management. Markowitz portfolio theory uses correlation to
determine how to allocate capital between different investments to
minimize risk, where risk is measured as the standard deviation of
returns. Value-At-Risk (VAR) is widely used in the market place as a
risk measurement tool. VAR is a summary measure of the variability of a
portfolio's value over a given time interval, and relies on correlation
in its computation.
Given two random variables X and Y, the correlation between X and Y,
usually denoted by the symbol (Rho), measures how the two variables
move relative to each other. Specifically, how linear is the
relationship between X and Y. It's well known that the value of (Rho)
will be greater than or equal to - 1 and less than or equal to +1. If
(Rho) = 1, X and Y are said to be perfectly correlated. This means that
as X and Y change, their changes are in the same direction and always
in the same proportion. This has a simple graphical interpretation. If
X and Y are graphed as ordered pairs, then the points would fall along
a line with a positive slope, as shown in Figure 1. Perfect negative
correlation occurs if (Rho) = -1 and means X and Y change
proportionally in opposite directions. In this case, the pairs (X,Y)
lie along a line of negative slope. As seen in Figure 1, the linear
relationship begins to breakdown for a smaller (Rho), such as .7 As the
correlation approaches zero, the appearance of the plot becomes a
random scatter of points.
CORRELATION
[SCATTER CHART]
Figure 1
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Two characteristics of the California power market that can lower
correlation between the different products are asynchronous timing and
asymmetric information. For example, the Dow Jones COB and PV prices
for on-peak Day-Ahead power are an average of bilateral deals made
before the submission of bids to the CalPX. In the interim, those
entities bidding into the CalPX may have received new information
concerning unit availability and anticipated loads which may affect
their bids. The zonal prices diverge further by incorporating
transmission constraints, and finally the Real-Time market resolves the
final information set into prices. The correlation structure observed
in the market is consistent with this.
As a highly simplified example of how correlation plays a role in
portfolio analysis for the power industry, consider a power marketer
with a forward position that must be sold into the Day-Ahead or the
Real-Time NP15 market. The power marketer assumes the averages and
standard deviations of prices ($/MWH) are as given in Table 1:
Zonal NP15 Real-Time NP15
Average 32.62 33.11
Standard Deviation 22.28 32.63
Table 1
If the marketer sells all of the position into the Real-Time market,
the expected revenue is $33.11 per MWH, but the risk of actually
receiving this amount is great due to the size of the standard
deviation relative to the average. More specifically, for most
distributions a significant probability exists that a random event will
be less than one standard deviation below the mean. For the NP15
Real-Time price above, this means that a price below 33.11 - 32.63 = 38
cents should not be uncommon. In fact, Real-Time prices in NP15 have
been a dollar or less about 5% of the time, with a low of negative
$249, while the zonal prices have been less than a dollar only about 1%
of the time, with a low of $0.
Alternately, the marketer could reduce risk substantially by selling
into the Day-Ahead market, with a slight reduction in expected revenue.
The question is can the risk be reduced further without a corresponding
reduction in revenue? The answer is yes, if the objective is to
minimize the standard deviation of the revenue.
Consider the alternative of selling a portion of the power in each
market. Let w[1] and w[2] be the proportions of the power sold in the
Day-Ahead and Real-Time market, respectively. The total revenue per MWh
is then the sum of the revenues in each market multiplied by their
respective allocations:
Revenue = w[1] x 32.62 + w[2] x 33.11,
with w[1] + w[2] = 1. The standard deviation for the portion sold in
the Day-Ahead market is just w[1] x 22.68, and similarly for the
Real-Time portion, but the standard deviation of the combined portfolio
includes an extra term that depends on the correlation between the two
markets. It is this correlation term that allows the marketer to
decrease the risk even
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further. Assuming a correlation of .456, if the marketer chooses w[1]
to minimize the standard deviation of the portfolio revenue, he finds
that w[1] = .816 and w[2] = .184.
Table 2 summarizes the three different possible power sale strategies:
selling all in the Real-Time market (w[1] = 0), selling all in the
Day-Ahead market (w[1] = 1), and selling at the risk minimizing
allocations (w[1] = .816).
Real-Time Only Day-Ahead Only Portfolio
Expected Revenue $ per MWH 33.11 32.62 32.71
Standard Deviation 32.63 22.28 21.58
Table 2
The risk using the portfolio strategy is not only smaller than the risk
assumed by selling all power into the Day-Ahead market, but the
expected revenue is greater. The increased expected return is due to
the portion of the portfolio sold into the Real-Time market, which has
higher expected revenue. The reduction in risk is due to a
diversification effect that occurs when a portfolio contains assets
that are not perfectly correlated. Diversification is the practice of
spreading investments across assets that are not perfectly correlated,
so if one investment loses value, this may be offset by a gain in
another asset, weakly correlated with the first. Generally the lower
the correlation between the assets, the greater the reduction in risk.
A power producer's allocation of resources is much more complicated
problem than in this simple example, but it illustrates how risk
reduction through diversification of assets may still be achieved.
Value-At-Risk has become an important risk management tool for many
industries. The banking industry was one of the first industries to
recognize VAR as a valuable tool for risk management and is endorsed by
the Bank for International Settlements. As VAR became well know,
particularly through such methodologies such as J.P. Morgan's
RiskMetrics(TM), many energy companies have subsequently followed
suit. VAR is used as a tool to measure how much exposure to dollar loss
a firm has through the variation of its portfolio value over a
specified time period such as a day or a week. A statistical
distribution of values that the change in a portfolio can have over
this time period is posited, then a percentile level such as 5% is
chosen as the measurement point of VAR. The interpretation of a weekly
VAR of $3 million would mean that the company expects that weekly
losses greater than $3 million should only occur in 5% of the weeks.
The simplest implementation of VAR assumes that returns on a portfolio
are normally distributed with mean zero. Because the distribution is
symmetric, a 5% VAR level is equivalent to the left value of a 95%
confidence interval of portfolio gains/losses. If (Delta) is the weekly
volatility of returns on a portfolio, a 5% percentile level is
equivalent to approximately -1.96 standard deviations thus the weekly
VAR would be -1.96*(Delta)*P where P is the mark-to-market value of the
portfolio. Because VAR is quoted as a potential loss, the negative is
ignored. For a mark-to-market portfolio value of $50 million and a
weekly (Delta) = .06, the weekly VAR would be 1.96*.06*$50 million, or
$5.88 million.
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Correlation plays an important role in calculating VAR, not utilizing
it can result in over estimating VAR which limits a portfolio manager's
activity while operating under a VAR ceiling. For example, suppose a
portfolio in the power market consists of a long forward position at
COB with a weekly VAR value of $1 million and a long forward position
at PV with a weekly VAR value of $.6 million, calculated individually.
Addition of these values to obtain a portfolio VAR value of $1.6
million would ignore correlation and result in a higher VAR. It would
also be inconsistent with the definition of risk as a standard
deviation. If the correlation between COB and PV is (Rho) = .7, the
appropriate VAR would be
[FORMULA] million,
=$ 1.48 million. If the PV position were a short position, its VAR would still
be $.6 million, but now the correlation is negative .7, thus the portfolio VAR
is
[FORMULA OMITTED]million,
= $.72 million. Clearly, correlation plays an important role in Value-At-Risk,
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