EXHIBIT 99.364
DRAFT
July 11, 2000
[CALIFORNIA ISO LOGO]
CONGESTION MANAGEMENT
REFORM RECOMMENDATION
TABLE OF CONTENTS
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1. INTRODUCTION......................................................................................1
2. THE CONGESTION MANAGEMENT REFORM PROCESS..........................................................3
2.1 Role of this Draft CMR Recommendation Document in the Congestion Management Reform
Project......3
2.2. Stakeholder Process.............................................................................4
2.3 Empirical Studies...............................................................................5
2.4 Crafting the Recommendation Package.............................................................5
3. CONGESTION MANAGEMENT REFORM: BACKGROUND AND MOTIVATION...........................................6
3.1 CAISO Role in Restructured Market...............................................................6
3.1.1 California Restructuring.................................................................6
3.2 CAISO Implementation of Congestion Management...................................................7
3.2.1 Long Forward Transmission Allocation: Firm Transmission Rights...........................7
3.2.3 The Real-Time: Balancing and Transmission Allocation -...................................9
3.2.3 The Real-Time: Balancing and Transmission Allocation -...................................9
3.3 Deficiencies that Motivate Congestion Management Reform.........................................9
3.3.1 Forward CM Transmission Representation and Pricing .....................................10
3.3.2 Failure to Explicitly Distinguish Competitive and Non-Competitive Circumstances for
Congestion Relief -.....................................................................11
3.3.3 Inaccurate Pricing in the Real-Time Market -............................................13
3.3.4 Insufficient Information and Tools Required for Market Participants to Make Efficient
Decentralized Decisions -...............................................................13
3.3.5 Other Concerns and Calls for Improvement................................................13
3.4 Congestion Management Reform: Systematically Correcting Current Deficiencies...................14
4. CONGESTION MANAGEMENT REFORM DESIGN FRAMEWORK AND CRITERIA.......................................14
4.1 Design Framework...............................................................................15
4.1.1 Reaffirmation of the Original California Design Principles..............................15
4.1.2 Functional Unbundling...................................................................16
4.1.3 Decentralized Decision Making...........................................................17
4.1.4 The Original Design Principles as the Basis for Congestion Management Reform............17
4.2 Design Criteria................................................................................19
4.2.1 Reliable Operations -...................................................................19
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4.2.2 Economic Efficiency -...................................................................19
4.2.3 Market Efficiency -.....................................................................19
4.2.4 Institutional Factors...................................................................20
4.2.5 Evaluation Criteria Adopted at the May 10-11 Stakeholder Meeting:.......................20
4.3 Current Impediments to Competitive Market Development..........................................21
5. REAL-TIME OPERATIONAL REQUIREMENTS...............................................................22
5.1 Introduction...................................................................................22
5.2 Physical Characteristics Of The Western Transmission System....................................22
5.3 Operational Requirements Of The Western Transmission System....................................23
5.4 California ISO Operating Procedures and Nomograms..............................................24
6. OVERVIEW OF THE REFORM PROPOSAL..................................................................25
6.1 Design Approach................................................................................25
6.2 Real-Time Operation As The Basis For Creating Locational Price Areas (LPAS)....................26
6.2.1Definition of Locational Price Areas...........................................................28
6.3 Real-Time Operation............................................................................28
6.4 Forward (Day-Ahead And Hour-Ahead) Congestion Management.......................................29
6.5 Long Forward (Beyond Day-Ahead) Activities.....................................................31
6.5.1 Local Reliability Service (LRS) Procurement.............................................31
6.5.2 Design of FTRs:.........................................................................32
6.6 Timeline Of Market Activities..................................................................33
7. THE LONG-FORWARD MARKET..........................................................................35
7.1 LPA Definition and Creation....................................................................35
7.1.1 Introduction............................................................................35
7.1.2 LPA Definition..........................................................................35
7.1.2.1 Defining LPAs Using Nomograms...................................................35
7.1.3 Creating New LPAs.....................................................................35
7.1.3.1 LPA-Creation Criteria...........................................................35
7.1.4 Other Options Considered..............................................................36
7.1.5 Open Issues...........................................................................38
7.2 Firm Transmission Rights......................................................................39
7.2.1 Background on Current FTR Product.....................................................39
7.2.2.1 100% Release....................................................................40
7.2.2.2 FTR Term and Auction............................................................40
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7.2.3 Impact of and Issues Regarding Proposed Changes.......................................40
7.2.3.1 FTRs Under a Looped Network Model...............................................40
7.2.3.2 FTR Monitoring..................................................................41
7.2.3.3 FTRs and LPA Changes............................................................41
7.2.4 Other Options Considered..............................................................43
7.2.5 Open Issues...........................................................................43
7.3 Local Reliability Service......................................................................44
7.3.1 Introduction..........................................................................44
7.3.2 Operational Aspects of Satisfying Local Reliability Requirements......................44
7.3.3 The Existing RMR Approach.............................................................45
7.3.4 Alternative Options for Satisfying Local Reliability Requirements.....................45
7.3.5 Open Issues...........................................................................51
8. THE DAY- AND HOUR - AHEAD MARKET.....................................................................51
8.1 Day-Ahead Congestion Management................................................................51
8.1.1 Introduction..........................................................................51
8.1.2 Similarities with the Existing DA CM Approach.........................................51
8.1.3 New Features of Congestion Management.................................................52
8.1.4 The Commercial Model..................................................................53
8.1.5 Network Representation................................................................53
8.1.6 The Modeled Constraints...............................................................54
8.1.6.1 Other Options Considered........................................................56
8.1.7 Pricing (Including Cost Allocation)...................................................56
8.1.8 Open Issues...........................................................................57
8.1.9 Other Options Considered..............................................................58
8.2 Hour-Ahead Congestion Management and Day-of LRS................................................59
8.2.1 HA CM.................................................................................59
8.2.2 Day-Of LRS............................................................................59
8.2.3 Open Issues...........................................................................59
8.3 Ancillary Services in Congestion Management....................................................59
8.3.1 Background............................................................................60
8.3.2 An Alternative Approach...............................................................60
8.3.3 Other Options Considered..............................................................60
8.4 Recallable Transmission........................................................................62
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8.4.1 Other Options Considered..............................................................64
9. THE REAL TIME MARKET.............................................................................65
9.1 Network Representation.........................................................................65
9.2 Imbalance Energy Procurement and Congestion Management.........................................65
9.3 Pricing and Cost Allocation....................................................................68
10. ECONOMIC SIGNALS, REVENUE ALLOCATION, AND COST OBLIGATION........................................71
10.1 Introduction...................................................................................71
10.2 Summary of Pricing and Allocation of Costs and Revenues........................................73
10.3 Economic Signals in the Proposed Pricing and Cost Allocation Methods...........................74
10.3.1 Feasibility of Schedules..............................................................74
10.3.2 Locational Price Signals..............................................................74
10.3.3 Unresolved Issues.....................................................................76
10.4.Linkages Between Congestion Management Reform, Long-Term Grid Planning, and New Generation
Inter-connection Policy........................................................................76
10.4.1 Long-Term Grid Planning...............................................................77
10.4.2 New-Generator Interconnection Policy..................................................78
11. FERC's ORDER 2000................................................................................80
11.1 Order No. 2000 and Congestion Management..............................................80
11.2 Order No. 2000 and Interregional Coordination.........................................81
11.3 Order No. 2000 and the Recommendation Package.........................................82
12. CONCLUSION.......................................................................................83
APPENDIX A - TERMINOLOGY AND ACRONYMS..................................................................1
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1. INTRODUCTION
The California Independent System Operator (CAISO or ISO) and Market
Participants in California have embarked on a comprehensive review and redesign
of the CAISO's Congestion Management (CM) processes and protocols. The redesign
effort emerges from knowledge gained through operational experience over the
past two years. This draft Congestion Management Reform (CMR) recommendation
responds to both explicit directives from the Federal Energy Regulatory
Commission (FERC) to correct certain deficiencies in the CAISO's CM processes,
as well as to the CAISO's and Stakeholders' identification of changes necessary
to generally improve the CAISO's operational and market functions.
This CMR process has involved a comprehensive examination of Congestion
Management relative to other CAISO responsibilities, as well as a review of the
CAISO's functioning in the larger California electric industry. Electric
industry restructuring is the replacement of governance by regulated,
vertically-integrated firms with governance by markets in order to stimulate
efficient investment in generation, demand response, and transmission.
Restructuring involves replacing direct commands and controls to elicit actions
with price signals and rules of behavior intended to induce parties to behave in
the desired manner. Most basically, this draft CMR recommendation seeks to
improve the accuracy and strength of price signals in California electric energy
and transmission markets.
This document is the CAISO's draft recommendation regarding how to
reform the Congestion Management process and related features of the CAISO
business and operations. This document is a draft, albeit one that we believe
reflects significant effort and thought on the part of both the stakeholders who
provided the initial input and the interdisciplinary design team that drafted
this document.
This CMR recommendation is organized as follows. Sections 2 through 5
provide background information and relate the approach to the market design that
informed the development of this recommendation package. Sections 6 through 9
contain detailed descriptions of the specific elements that make up this
package. [NOTE: Section 6 comprises an overview of this draft Congestion
Management Reform Recommendation. It is an Executive Summary.] Sections 10 and
11 synthesize the economic and policy implications of this CMR recommendation.
Following is a section-by-section summary.
o SECTION 2 THE CONGESTION MANAGEMENT REFORM PROCESS - Describes the CMR
process, including the stakeholder process, the role of this draft
recommendation, and how this document was crafted.
o SECTION 3 CONGESTION MANAGEMENT REFORM: BACKGROUND AND MOTIVATION --
Provides background information on the CAISO's role in the restructured
California electric market, with a focus on the CAISO's existing
implementation of Congestion Management. Summarizes the deficiencies with
existing Congestion Management mechanisms that motivate the CMR project, as
identified by FERC, Market Participants, and the CAISO.
o SECTION 4 MARKET DESIGN APPROACH TO CRAFTING THE CMR RECOMMENDATION --
Describes the criteria utilized to develop and assess the CMR
recommendation and articulates the conceptual framework or design approach
the CAISO utilized in understanding how CM should work and what changes
would best accomplish this.
o SECTION 5 REAL-TIME OPERATIONAL REQUIREMENTS -- Describes fundamental
features of the western electric transmission grid and how those features
are reflected in the CAISO Operating procedures and nomograms. These
operating procedures and nomograms are the operational reality around which
this CMR recommendation crafts markets.
1
o SECTION 6 OVERVIEW OF CONGESTION MANAGEMENT REFORM RECOMMENDATION --
Provides a general summary of the recommendation package, starting with the
real-time operational needs that form the basis for the various reforms
proposed in the package and provides a summary of the impact of these
reforms in the Day-Ahead and Long-Forward time-frames.
o SECTION 7 THE LONG-FORWARD MARKET -- Describes aspects of the
recommendation package affecting activities before the Day-Ahead
time-frame, including the definition and creation of Zones (or LPAs), the
impact of various proposals on FTRs, and the procurement of a new Local
Reliability Service.
o SECTION 8 THE DAY-AHEAD AND HOUR-AHEAD MARKETS -- Describes aspects of the
recommendation package affecting activities during the Day-Ahead and
Hour-Ahead time-frame, including Day-Ahead and Hour-Ahead management of
Congestion, the impact of the Ancillary Services markets, and the
implementation of a Recallable Transmission product.
o SECTION 9 THE REAL-TIME MARKET -- Describes aspects of the recommendation
package affecting activities during real-time and thereafter, including the
network representation to be used in real-time; the procurement of
Imbalance Energy and management of Congestion in real-time; and pricing and
cost allocation impacts.
o SECTION 10 ECONOMIC SIGNALS, REVENUE ALLOCATION, AND COST OBLIGATION --
Provides an overview of the economic foundation for the recommendations
package, including a preliminary assessment of the price signals that will
be sent under the proposed reforms and the interaction of the
recommendation package with the CAISO's Long-Term Grid Planning and New
Generator Interconnection Policies.
o SECTION 11 CONGESTION MANAGEMENT AND RTO DEVELOPMENT -- Focuses on the
consistency of the recommendation package with the requirements of FERC
Order No. 2000 on Regional Transmission Organizations concerning Congestion
Management and interregional coordination.
o SECTION 12 CONCLUSION
In addition to the main body of the recommendation package, a number of
appendices are attached to this package to provide stakeholders, and
ultimately the ISO Governing Board, with additional information related to
the Congestion Management Reform process. Only two appendices are provided
with this initial draft. Those appendices are:
o APPENDIX A TERMINOLOGY AND ACRONYMS -- A glossary of various terms and
acronyms used throughout the CMR recommendation package.
o APPENDIX B LOCATIONAL PRICE DISPERSION STUDY - Summarizes the areas of
empirical study in which the CAISO is currently engaged and describes the
objective, design, and preliminary results of the CAISO's analysis of the
dispersion of locational prices throughout the ISO Control Area. (Because
the study is ongoing, additional results of the analysis will be provided
with subsequent CMR materials.)
In the next draft of the recommendation package, to be publicly distributed
by July 21, 2000, the following additional appendices will be provided:
o MARKET SEPARATION STUDY --The objectives, design, and preliminary results
of the other ongoing study being undertaken in connection with the
Congestion Management Reform process.
o ASSESSMENT OF CMR RECOMMENDATION WITH RESPECT TO STAKEHOLDER EVALUATION
CRITERIA
2
o DISCUSSION OF CONGESTION MANAGEMENT REDESIGN OPTIONS NOT ADOPTED IN CMR
RECOMMENDATION -- A summary of other CMR proposals submitted by various
stakeholders and the CAISO's assessment and use of those proposals in
preparing this recommendation package.
o STAKEHOLDER COMMENTS ON RECOMMENDATION PACKAGE -- A summary of all
stakeholder comments received to date on the various proposals and concepts
incorporated into this recommendation package.
o SYSTEM IMPACTS -- A summary of the anticipated impacts of the various
aspects of the CMR recommendation package on CAISO and Market Participant
business and operations.
o SEVERAL APPENDICES -- Regarding considerations and tools for Forming New
Locational Pricing Areas (e.g., Shift Factors, RMR Utilization).
2. THE CONGESTION MANAGEMENT REFORM PROCESS
2.1 ROLE OF THIS DRAFT CMR RECOMMENDATION DOCUMENT IN THE CONGESTION
MANAGEMENT REFORM PROJECT
This CMR recommendation represents an essential milestone in the
broader Congestion Management Reform Project. As described below, the first
stage of that project was focused on obtaining stakeholder input through
numerous meetings, proposals, written comments, postings on bulletin boards, and
other forms of communication. This initial stage resulted in the compilation of
ideas for redesigning numerous elements of the CAISO's Congestion Management
process. A large level of stakeholder consensus on the criteria that should be
used to assess any Congestion Management redesign proposals were also developed
in this first stage.1
The disparate nature of the concepts presented during the initial stage
of the project provided many promising ideas, but also illustrated the need to
focus further CMR discussions on the package of reforms, on the linkages between
numerous changes. Towards this end, the CAISO has developed this document,
intended both to reflect certain areas of agreements among the majority of the
stakeholders during the initial stage of the project and to incorporate proposed
reforms into a single, coherent, and internally consistent package. We emphasize
that, although we believe this recommendation package to be a necessary
milestone in the Congestion Management Reform Project, it is not intended to be
dispositive of the final design. We anticipate receiving extensive stakeholder
comments and critiques concerning this recommendation over the coming weeks.
Such comments and criticism are not only welcome, but encouraged. The CAISO is
open to all reactions, including suggestions that significantly diverge from the
changes proposed in this document.
Once the next round of stakeholder input has been assessed, the CAISO
will revise this CMR recommendation. The revised recommendation will be
presented to the ISO Governing Board for approval on September 6 & 7. The CMR
recommendation approved by the ISO Governing Board will then be further
developed in Stakeholder processes to form the basis of the final Tariff filing
to FERC in November.
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1 These criteria are described in Section 4.1 of this recommendations package.
3
2.2. STAKEHOLDER PROCESS
Within weeks of the January 7, 2000 FERC order directing the CAISO to
undertake a review of its Congestion Management process, the CAISO began
soliciting and receiving stakeholder input regarding how to reform the
Congestion Management process. Initially, this input took the form of both
general "thoughts" on Congestion Management Reform and preliminary proposals
submitted by Market Participants and other interested parties.
The formal Congestion Management Reform Stakeholder Process began on
March 6, 2000 with a Congestion Reform "Kickoff" meeting. Since the Kickoff
meeting, there have been five additional full-day stakeholder meetings and
numerous meetings of smaller working groups. Significant meetings since the
March 6 meeting include the following:
o MARCH 13, 2000 MEETING OF THE CONGESTION MANAGEMENT TECHNICAL STUDY
GROUP;
o APRIL 3, 2000 CONGESTION REFORM STAKEHOLDER MEETING;
o APRIL 20, 2000 MEETING OF THE "ZONAL FORWARD" WORKING GROUP;
o APRIL 28, 2000 CONGESTION REFORM STAKEHOLDER MEETING;
o MAY 10-11, 2000 CONGESTION REFORM STAKEHOLDER MEETINGS; AND
o JUNE 8, 2000 CONGESTION REFORM STAKEHOLDER MEETING.
Stakeholder comments, presented at these meetings in a variety of
media, provided a foundation for the development of this recommendation package.
These comments are posted on the ISO Home Page at
http://www.caiso.com/clientserv/congestionreform.html. Other forms of
stakeholder input taken into account in the development of this package include
the various reform proposals offered by Market Participants and other interested
parties and stakeholder comments on such proposals.2 This includes comments on
the "Zonal Forward" white paper released in April 2000 by the CAISO.
In addition to the formal group Stakeholder meetings on CMR just
described, ISO Management have meet with individual Market Participants to
discuss these various options and issues relating to Congestion Management
Reform. These meetings (approximately 15) with numerous Market Participants
began in February and have continued through June. These meetings have helped us
to gain a better understanding of stakeholder priorities as we redesign this
basic function of the CAISO.
With the publication of this draft CMR Recommendation, the next stage
of the stakeholder process will commence. Stakeholder meetings are scheduled for
July 13 and 14. The CAISO is also actively soliciting any comments on this
package, as well as any suggestions or proposals that go beyond the scope of the
proposals considered in this package. A weekly schedule of Stakeholder meetings
will be set for August to develop implementation details of the adopted proposal
and to discuss tariff language in preparation of the filing to FERC.
- ----------
2 A summary of other CMR proposals submitted by various stakeholders and the
CAISO's assessment and use of those proposals in preparing this CMR
recommendation will be provided as an appendix to be released subsequent to
the release of this document.
4
2.3 EMPIRICAL STUDIES
Empirical studies currently being conducted are an important part of the
Congestion Management Reform effort. The CMR effort is supported by empirical
analyses in three major areas: 1) Locational cost and price variation within the
ISO system; 2) The economic impact of the Market Separation Rule (MSR); and, 3)
The historical costs of mitigating Intra-Zonal Congestion. Appendix A (as
appended to this document) provides a summary of all of the empirical studies
and presents preliminary results in the Locational Price Dispersion Study (area
1). The remaining studies will be released during July.
2.4 CRAFTING THE RECOMMENDATION PACKAGE
As explained above, this recommendation was crafted as a package, based
on the ideas that have been developed by and/or with stakeholders since the
beginning of this year. These ideas have taken the form of complete reform
proposals as well as options for reforming certain elements of the Congestion
Management process. Beginning in late May, ISO Management assigned a CMR design
team and gave it the task of forming a recommendation. This design team was
interdisciplinary, comprised of members from all the critical departments:
Market Operations, Client Services, Market Analysis, Grid Operations,
Settlements and Billing, Information Technology, Legal and Regulatory, and
Strategy Development and Communications. In addition, Professor Robert Wilson,
Professor of Economics at Stanford University, provided direction to this design
team on the economic foundation of this proposal. Professor Frank Wolak, Chair
of the CAISO's Market Surveillance Committee, was consulted throughout this
design process.
This design team engaged in one- or two-day long intensive design
sessions each week. The design team focused on weaving together elements into a
coherent CMR package. This was an exercise in identifying linkages and
dependencies in order to understand what options for treating one element would
fit with options for treating another element. The market design approach
described in Section 4 provided guidance for this analysis. In this document,
the CAISO's preference for certain options and specific proposals is stated in
some area. In other areas, the CAISO presents alternative options, requiring
input from Market participants to select among them. Despite the stated
preferences for certain options set forth in the following, the CAISO looks
forward to receiving comments on all elements and aspects of the recommendation.
Ultimately, idea development with Stakeholders and CAISO design
intensives have focused on crafting a CMR recommendation that is:
o Internally consistent with respect to both operational and economic
considerations
o Systematically corrects the identified deficiencies (not piece by piece)
o Balances other design criteria developed with stakeholders
In the next section, current Congestion Management processes are described
in the context of the CAISO's function in the newly restructured electric
industry. Major deficiencies in the current CM processes, as revealed over the
last two years of operations, are then reviewed. These deficiencies have
motivated Congestion Management reform.
5
3. CONGESTION MANAGEMENT REFORM: BACKGROUND AND MOTIVATION
This CMR effort has included a comprehensive examination of the role of
Congestion Management (CM) in the context of the CAISO's overall mission and
responsibilities, as well as a review of the CAISO's functioning within the
larger context of the restructured California electric industry. This section
provides background on California electric industry restructuring, the CAISO's
role in the new industry structure, how CM has been implemented as one of the
CAISO's responsibilities, and the deficiencies in CM and related functions that
have become apparent over the past two years of market operations under this new
industry structure.
3.1 CAISO ROLE IN RESTRUCTURED MARKET
3.1.1 CALIFORNIA RESTRUCTURING- The main objective of California's
electric restructuring is to improve long-run efficiency of the industry by
stimulating innovation and investment, particularly investment in new generation
facilities (to replace and augment the existing stock) and demand-side measures.
Prudent investment in new infrastructure will ultimately reduce rates to end-use
customers (as compared to the absence of new investment). To accomplish this,
California restructured its electric industry to create a competitive energy
market (i.e., wholesale energy and retail energy service markets). Central to
facilitating a competitive market is ensuring open, non-discriminatory access to
the transmission system.
The unique aspect of California's design, in contrast to the eastern
ISOs such as PJM, is the emphasis on: 1) Separation of Forward Energy markets
from forward transmission markets; and, 2) Decentralized decision-making
(particularly with respect to forward commitment and scheduling of resources and
loads, and real-time dispatch of resources) . Market Participants involved in
the restructuring process believed it was critically important to separate
decisions regarding the competitive provision of electricity to end-use
customers from decisions regarding the provision of regulated services, in
particular, transmission. Such division of functions and responsibilities not
only served to implement FERC's functional unbundling directive, but also served
notice to those who may participate in the market that California was committed
to an open and unfettered (by regulatory oversight and intervention) energy
market. Additionally, it was believed that decentralized decision-making (and
related variety in contracting) would lead to greater innovation in the
marketplace. To the extent that market participants could not rely on the ISO to
centrally provide certain services or achieve certain efficiencies in the
forward energy markets,, the market itself would develop means to do so.
The separation of energy and transmission markets and decentralized
decision-making were manifest in California's restructured market in two main
ways:
- Separation of the CAISO (transmission service provider) from the
California Power Exchange (PX, operator of a Forward Energy pool
market)
- Instituting the "market separation rule" (i.e., requiring that each
Scheduling Coordinator [SC] submit balanced schedules, and that the
CAISO keep each SC schedule in balance in performing CM). As a result,
each SC is required to optimize within its own portfolio of resources
and thererby limits the CAISO only to pricing transmission (through the
use of economic bids for the use of frequently congested pathways)
6
In order to facilitate decentralized decision-making, the original market
design also provided for the creation of certain tools that would be
available to SCs to facilitate inter-SC trades. Such tools were to
include the ability to perform inter-SC trades of Energy, Ancillary
Services, and Adjustment Bids, and the Congestion iteration of the
ISO's DA market.3
In this new industry structure, the ISO's core function is to reliably
operate the transmission system. While accomplishing this mission, the CAISO is
designed to minimize its involvement in the Forward Energy market. The specific
core functions of the ISO are as follows:
o Provide non-discriminatory access to transmission service
o Efficiently allocate use of the grid among potential users when
transmission capacity is scarce (Congestion Management)
o Procure ancillary and local reliability services, through competitive
mechanisms (e.g. auctions) to the extent possible, as a means to
operate the transmission grid reliably; and
o Operate a real-time Imbalance Energy market to balance generation and
load while reliably operating the transmission grid
The next section provides an overview of how the ISO currently
accomplishes the second of these functions, CM. However, in the context of
developing a comprehensive redesign proposal, we must focus on the
interrelationship and interdependencies among all of the ISO's core functions.
3.2 CAISO IMPLEMENTATION OF CONGESTION MANAGEMENT
This section describes some of the main elements concerning how the
allocation of transmission capacity is currently managed by the ISO. In
preparation for the subsequent section on the deficiencies that have motivated
this redesign initiative, this section also mentions some of the ways the
current design is vulnerable to manipulation.4
3.2.1 LONG FORWARD TRANSMISSION ALLOCATION: FIRM TRANSMISSION RIGHTS-
The ISO uses different methods in a sequence of markets to allocate
transmission. First, the ISO conducts an annual auction of Firm Transmission
Rights (FTRs) which offers transferable property rights. The purchaser of an FTR
obtains (for every delivery hour) Day-Ahead scheduling priority and a financial
payment equal to a portion of the ISO's Day-Ahead and Hour-Ahead Usage Charge
revenues (thus providing a hedge against the Usage Charges associated with that
portion of its Schedule for which it has FTRs). The Day-Ahead Congestion
Management (CM) process establishes prices, or Usage Charges, for Inter-Zonal
transfers and charges each Scheduling Coordinator (SC) for the amount scheduled
in the direction of Congestion. This process is repeated Hour-Ahead: new prices
are established, and each SC is charged/credited for the Hour-Ahead deviations
from its Day-Ahead schedule. Each price is calculated as the marginal cost of
counterflows sufficient to alleviate Congestion. The ISO absorbs part of the
cost of alleviating residual Intra-Zonal Congestion in the real-time market. If
potential Congestion can be eliminated using bids in merit order, then the
marginal bid sets the real-time price and each SC pays this price for each MWh
of its
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3 Inter-SC trades of Energy and Ancillary Services are available to SCs now,
inter-SC trade Adjustment Bids are anticipated to be available in August
2000. The Congestion iteration has been functioning since start-up, but thus
far the PX has not participated in it. It is premature to draw definitive
conclusions regarding California's decentralized approach to
restructuring-which attempts to go further than any other ISO in relying on
markets-until we have provided to the market all the tools that were part of
the original design.
4 There are those who would argue that use of the words "manipulation" or
"gaming" is misplaced and that the behavior exhibited is predictable and
largely an artifact of the incentives created by the market rules.
7
deviation from its Hour-Ahead schedule. The key feature is that the extra cost
of using bids out of merit order to prevent Congestion is absorbed entirely by
the ISO-and ultimately paid by loads and exports in the Zone via an uplift
charge (i.e., the Grid Operations Charge or GOC).
3.2.2 SHORT FORWARD TRANSMISSION ALLOCATION: DAY- AND HOUR-AHEAD
CONGESTION MANAGEMENT- The purpose of the ISO's CM in forward markets is to
allocate use of the main transmission paths in advance so that only minor
Congestion remains to be resolved in real-time operations, depending on the
contingencies that arise. One motivation for undertaking this redesign
initiative is that the prediction of minor Congestion on other transmission
facilities in real-time has not materialized. Indeed, significant Congestion
problems have spilled over into the real-time market.
There are two forward markets, one Day-Ahead (DA) and one Hour-Ahead
(HA) of real-time operations. These markets operate similarly except for their
time frames, so only the DA market is described in detail. The DA markets for
all 24 hours of the next day are conducted simultaneously and largely
independently, so the market for a single delivery hour is described.
One key feature of this forward market is that it establishes prices
(called Usage Charges) only for transmission between Zones (Inter-Zonal
Congestion Management [RZCM]), DA, or HA, to distinguish it from Intra-Zonal
Congestion Management (AZCM), which is mitigated in real-time. As noted,
transmission within Zones (AZC) is not explicitly priced, thus transmission
between buses within Zones is not priced, nor are effects on reserve
requirements, voltage support, and loop flow. For this reason, the ISO's pricing
of Congestion is often criticized as incomplete and the locational signals
coarse.5
A second key feature of the ISO's DA CM process is that Usage Charges
are based on the marginal cost of purchasing sufficient counterflows to
eliminate Congestion, as determined by Adjustment Bids submitted by SCs. When an
SC submits an initial Day-Ahead Preferred Schedule, the SC can submit a
collection of Adjustment Bids (for suppliers, "incs" are offers to increment
generation, whereas "decs" are bids to decrement [reduce] generation,
interpreted as buying back Energy previously sold in the Energy market). These
Adjustment Bids are the tool by which the ISO constructs counterflows to
eliminate Congestion. For instance, if the SCs' schedules indicate that
aggregate demand for transfers from Zone A to B exceeds the feasible transfer
capacity, then the ISO might construct a counterflow from a particular SC's
collection of Adjustment Bids. The counterflow increments generation in Zone B
at an Energy cost of $30/MWh and decrements an equal amount of generation in
Zone A at $20, so that the net cost is $30-20 = $10/MWh. Multiple counterflows
can be constructed, but in each case, the ISO uses Adjustment Bids6 from a
single SC.
The actual implementation of the counterflow markets uses
optimal-power-flow (OPF) software designed to minimize the SCs' total net cost
of adjustments, subject to the constraint that each SC's revised schedule
remains Energy-balanced overall. Application of an energy-balance constraint to
each SC individually is referred to as the Market Separation Principle, but it
can also be seen as a necessary implication of the unbundling of transmission
from Energy. The Market Separation Principle ensures that the ISO's CM process
is a market only for counterflows to eliminate Congestion, rather than an
additional market for Energy per se in competition with the SCs' Energy
markets.(7) A major feature of the original
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5 The original market design did contemplate forward-market management of
AZCM. However, we do not believe that managing AZCM in the forward market
would completely eliminate the known "gaming" problems.
6 In order to honor the Market Separation Rule, the CAISO must utilize
matching pairs of incremental and decremental bids from the same SC.
7 FERC has suggested that this feature might prevent full efficiency of the
market outcome, since it precludes the ISO from constructing counterflows
from the Adjustment Bids of multiple SCs-such as an "inc" from one and a
8
market design is that SCs retain options to avoid Usage Charges. There are no
charges if there is no Congestion, or if a schedule is Energy-balanced within
each Zone. More importantly, if all SCs alter their schedules sufficiently to
eliminate Congestion (through the iteration), the ISO would not impose Usage
Charges.
3.2.3 THE REAL-TIME: BALANCING AND TRANSMISSION ALLOCATION - The
real-time market was originally conceived as encompassing a supplemental Energy
market for deviations from Hour-Ahead schedules, a parallel market for AZCM, and
a resource for operators to draw upon for load following and reliability
assurance. However, these distinctions were quickly seen as irrelevant, and in
practice there is a single consolidated real-time market for Energy usable for
any purpose. The key feature is that if there is no Congestion, then a single
real-time price is used to settle all Energy transactions conducted according to
the merit order. If there is Congestion, then the market is divided regionally
into Zones and a real-time energy price is established for each Zone. The ISO's
real-time market does not settle all transactions at the real-time energy price.
If transmission or reliability constraints cannot be met by using bids in merit
order, then it calls other bids "out-of-sequence" (OOS) that are settled at the
price bid. If the bids available are insufficient, then the ISO can exercise its
authority to issue dispatch instructions and call resources "out-of-market",
that are settled at either the hourly ex post price or a price based on certain
market indicators. If Reliability-Must-Run (RMR) generation is available, then
the ISO can also call on those resources.
3.3 DEFICIENCIES THAT MOTIVATE CONGESTION MANAGEMENT REFORM
The purpose of this section is to provide an overview of the main
problems plaguing the CAISO's Congestion Management process. In order for the
ISO to develop, file at FERC, and implement a comprehensive review and redesign
of its Congestion Management protocols, we believe it is essential that the ISO
and Market Participants develop a complete list of problems with the current
system. The following section details the flaws identified by FERC, Market
Participants, and the ISO that must be corrected through this comprehensive
Congestion Management reform. These flaws collectively result in locationally
inaccurate and weak price signals to participants in all of the energy and
transmission-related electricity markets in California. Without accurate and
strong price signals, California will not be able to achieve its main objective
in restructuring: motivating efficient new investment in generation, demand
responsiveness, and transmission to replace and augment the existing
infrastructure. The four primary deficiencies are:
o Representation of the transmission system used for Congestion Management in
the forward markets is does not adequately reflect how the actual
transmission system managed in real-time, resulting in forward schedules
that may be infeasible in real-time;
o The lack of competitive markets for Congestion relief in certain locations
(local market power in Intra-Zonal Congestion Management) is not adequately
addressed
o The merit order of offered bids in the Imbalance Energy market does not
reflect the transmission constraints observed in real-time (the "merit
order" does not take into account each bid's effectiveness in resolving
particular transmission constraints)
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"dec" from another (81 FERC P. 61,122 at 61,482). FERC approved the ISO's
original design in 1997 based on assurances that the ISO would enable,
encourage, and facilitate a market for inter-SC trades of Adjustment Bids
that would realize the full potential for gains from constructing
counterflows using Adjustment Bids from different SCs.
9
o The CAISO does not provide all of the necessary information and tools
required for Market Participants to make efficient decentralized decisions
regarding operation and investment related to generation, demand,
responsiveness, and transmission.
In the following subsections, each of these deficiencies is briefly
described and the consequences or symptoms of these flaws are summarized.
3.3.1 FORWARD CM TRANSMISSION REPRESENTATION AND PRICING - This is one
of the "fundamental flaws" identified by FERC in its January 7, 2000 order on
Amendment No. 23 to the ISO Tariff (January 7 Order)8. The representation of the
transmission system used to price transmission usage in Congestion Management in
the forward markets is not as detailed (or granular) as the actual transmission
system managed in real-time. As a result, transmission schedules accepted and
priced in the forward markets will not be feasible in real-time. The following
passage from the January 7 order captures FERC's concerns regarding infeasible
schedules and the resulting "gaming opportunities" in the real-time market9:
"We agree with intervenors that there is nothing wrong with prices
increasing during times of real scarcity. There is something wrong,
however, when the method adopted to manage congestion allows generators
to create artificial scarcity in order to create congestion revenues
that will be paid to them. We agree with the ISO's assessment that
there is a serious flaw in the existing intrazonal management scheme.
The existing congestion management approach relies on the existence of
a competitive market to determine the cost of managing congestion. Yet
the bidding rules allow generators to profit by offering distorted bids
that create artificial congestion, and this problem is exacerbated to
the extent that market power exists. As intervenors note, the ISO's
proposal fails to send price signals to encourage new generators to
enter into areas where there are constraints, which could help
alleviate any market power that exists. The problem facing the ISO is
that the existing congestion management method is fundamentally flawed
and needs to be overhauled or replaced. In this respect, the ability of
generators to create fictional congestion follows directly on another
premise underlying intrazonal congestion management, i.e., that the ISO
is required to accept all transmission schedules without verifying that
all of those schedules are feasible. In accepting transmission
schedules that bear no resemblance to physical reality, this congestion
management scheme creates the opportunities for fictional congestion."
This deficiency is admittedly a flaw in original design of CM as a
two-stage process, in which Inter-Zonal Congestion Management (RZCM) is
performed first and establishes usage charges, and Intra-Zonal Congestion
Management (AZCM) is performed second and subject to the requirement to maintain
the Inter-Zonal flows scheduled in the RZCM process. The original California
market design would have partially mitigated this problem by performing AZCM in
the forward markets. 10 In addition, Intra-Zonal Congestion was anticipated to
be small and infrequent, so that the inefficient financial consequences of the
two-stage design would be trivial. Unfortunately, due to software constraints,
the ISO was not able to implement forward-market AZCM, and Intra-Zonal
Congestion has proven to be more significant and frequent than anticipated. Had
the ISO incorporated AZCM into forward-market Congestion Management, any
Intra-Zonal constraint violations in Scheduling Coordinators' forward schedules
would be detected and mitigated in advance of real-time and, more importantly,
their forward schedules would incorporate re-dispatch to mitigate AZC ad would
be financially binding. Related to this deficiency in what is currently
- ----------
8 January 7 Order, 90 FERCP. 61,006.
9 January 7 Order, 90 FERCP. 61,006 at 61,013-14.
10 Forward-market AZCM would not however, completely eliminate the problems
with AZCM.
10
represented and priced in the forward markets, FERC as well as many Market
Participants believe that the current criteria for establishing new Congestion
Zones are not rational and should be reexamined. (In addition, many believe that
the distribution of Usage Charges revenues is unfair and creates disincentives
for expansion.) As part of the redesign effort, Market Participants believe that
it is essential that we revisit the Zone Creation/activation criteria and that
instead of an arbitrary threshold (e.g., 5% of the capacity costs of a
transmission line), the ISO should attempt to identify at what level Congestion
becomes "commercially significant" and therefore should be explicitly priced.
Market Participants believe that in order to facilitate commerce, the ISO must
ensure that there is appropriate pricing of transmission constraints, which
means that if there is "significant" Congestion on the grid, the ISO should
price it.
3.3.2 FAILURE TO EXPLICITLY DISTINGUISH COMPETITIVE AND NON-COMPETITIVE
CIRCUMSTANCES FOR CONGESTION RELIEF - This is also one of the "fundamental
flaws" identified by FERC in its January 7, 2000 order. FERC articulates its
concerns regarding the exercise of local market power in Congestion Management:
"While the ISO has identified a serious problem in implementing its
intrazonal Congestion Management mechanism, we are not convinced that
this is the appropriate remedy. The ISO's proposal does not address
what the ISO has identified as a fundamental flaw in the overall
congestion management scheme, i.e., the intrazonal congestion program
approved for ISO is premised on competitive market solutions and now
the ISO has learned that there may never be a competitive market in any
circumstance involving intrazonal congestion. This is certainly not a
simple clarification. In fact it is a recognition that a competitive
solution may simply not be feasible for intrazonal congestion. This
strikes at the heart of the existing approach and calls out for the
design of a comprehensive replacement congestion management approach.
Moreover, this redesign should be pursued with input from all
stakeholder groups, as well as from the Market Surveillance Committee."
Broadly, the problem is that the CAISO's transmission management
processes do not adequately distinguish between situations with and without
competitive circumstances. Absent this, pricing and cost allocation has been
distorted. A pricing regime that does not distinguish situations in which market
power is present, results in prices that are too high and that promote too much
generation and transmission expansion in the wrong locations. The mechanism that
the CAISO has used for addressing market power (use of RMR Generation) results
in an allocation of costs that is too broad and does not provide a sharp signal.
These two effects are elaborated on below.
Failure to adequately distinguish and appropriately price situations
where there is local market power results in price signals that are too strong,
inappropriately incenting the siting of new generation. In its order rejecting
the CAISO's proposed New Generator Interconnection Policy (NGIP) (Amendment No.
19), FERC emphasizes this point. FERC stated that it was inappropriate for the
ISO to impose costs on new generators that are the result of non-competitive
situations (i.e., Intra-Zonal Congestion).(11) In its September 15, 1999 order
(September 15 Order), FERC stated that, "...the proposal is based on prices
exacted by existing generators in noncompetitive markets which may be too high
and may lead to poor economic decisions (e.g., inefficient transmission
expansion)."(12),(13)
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11 In Amendment No. 19, the ISO proposed that new generators that locate in
areas where there is not a competitive supply of bids to manage Intra-Zonal
Congestion and that cause a significant increase (5%) in Intra-Zonal
Congestion be required to mitigate that Congestion.
12 September 15 Order, 88 FERC P. 61,221 at 61,729. While FERC did not
explicitly so state, we presume that
11
FERC also stated that the ISO's proposal would result in inflated
Congestion costs and would fail to result in the creation of new Zones that
"would enhance incentives for new generators to enter the market and increase
competition."14
Intra-Zonal Congestion Management in real-time has been the point at
which localized Congestion has been managed; thus, it is the point at which the
exercise of local market power has been observed. As noted earlier, Intra-Zonal
Congestion has been both greater in magnitude and more frequent than originally
anticipated. To date, the increased level of Intra-Zonal Congestion has been
largely masked by RMR Generation. That is, as a result of the need to rely on
RMR Generation to maintain local reliability and mitigate local market power,
the ISO has been able to manage Congestion that otherwise would be characterized
as Intra-Zonal and therefore managed through the market. Since start-up, the ISO
has been able to call on RMR units to simultaneously alleviate a significant
amount of Intra-Zonal Congestion (i.e., congestion that, if left unmitigated,
would result in a degradation of system reliability) and prevent the exercise of
local market power. The ISO accomplished this by both pre-dispatching RMR in the
Day-Ahead Scheduling process and by calling on RMR units in real time.
To the extent that the ISO calls on RMR Generation, the costs
associated with RMR are segregated and separately billed to the applicable
Participating Transmission Owner (PTO), or "Responsible Utility" in this
context. Therefore, RMR-related costs are not included in the Grid Operations
Charge, which is the vehicle for recovering Intra-Zonal Congestion costs from
all Load within a given Congestion Zone. Thus, these costs for local reliability
do not contribute to the locational price signal of Congestion Management.
Similarly, only the AZCM costs included in the Grid Operations Charge are
currently used to determine if the criteria for the creation of a new Congestion
Zone have been satisfied. Earlier this year, the ISO determined that AZC costs
included in the Grid Operations Charge on one Intra-Zonal path, Path 26, were
significant and therefore warranted the creation of a new Congestion Zone, ZP26.
An assessment of RMR-related costs incurred by the ISO indicates that if
RMR-related costs were included in recorded Intra-Zonal Congestion costs, the
ISO could have created a minimum of four additional Congestion Zones.15
Market Participants emphasize that a new market power mitigation regime
must provide accurate price signals to resources, as well as offer institutional
means for load to effectively respond to that price signal.
3.3.3 INACCURATE PRICING IN THE REAL-TIME MARKET -There is one main
problem with the current design of the real-time market16. The merit order of
offered bids in the Imbalance Energy market does not reflect the transmission
constraints observed in real-time because the "merit order" does not take into
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FERC believed that the "uneconomic" price from the existing generator would
inappropriately skew the decision of the new generator as to which
"mitigation option" to select. In other words, if the new generator relied
on the payment price to the existing generator in deciding to expand the
grid, that might not be the right decision if the payment price to the old
generator is excessive and results from non-competitive situations (even
with the other options available).
13 In its orders on Amendment No. 18 and 26, FERC also raised concerns that the
ISO's market for managing AZCM was not competitive.
14 Id.
15 The ISO Tariff provides that if Intra-Zonal Congestion costs exceed 5% of
the capacity costs of the associated transmission path and there is workable
competition on each side of the path, the ISO may create a new Congestion
Zone (ISO Tariff Section 7.2.7.2). In the case of these 4 additional Zones,
while the 5% criterion may have been satisfied, it is likely that the
"workable competition" criterion would not have been satisfied.
16 The "DEC" game is realized in the real-time, but is caused by a flaw in
forward Congestion Management.
12
account each bid's effectiveness in resolving particular transmission
constraints. Currently, if transmission or reliability constraints cannot be met
by using bids in the merit order, then the operator calls other bids
"out-of-sequence" (OOS) that are settled at the price bid. If the bids available
are insufficient, then the ISO can exercise its authority to issue dispatch
instructions and call resources "out-of-market", that are settled at either the
hourly ex post price or a price based on certain market indicators.
3.3.4 INSUFFICIENT INFORMATION AND TOOLS REQUIRED FOR MARKET
PARTICIPANTS TO MAKE EFFICIENT DECENTRALIZED DECISIONS - Market Participants
must have information and tools available to them to identify and consummate
potential trading opportunities. Many have consistently requested that the CAISO
provide more information and tools to: 1) Allow them to better understand how
the CAISO is making decisions; and, 2) Coordinate among themselves. Requests
relate to:
o Ability to duplicate the ISO's Congestion Management protocols.
(Participants generally believe that Congestion Management software should
either be simplified or that the current proprietary software should be
released.)
o The ability of SCs to perform inter-SC trades of Energy and Ancillary
Services and the ability to have Adjustment Bids on such inter-SC trades.
(These were some of the tools that were originally anticipated to be
available to Market Participants, but they have not been available for most
of the first two years of operating experience.)
o The ability to identify trading opportunities among SCs. (Unused Adjustment
Bids were also anticipated to be available to Market Participants, but they
have not been available.) Market Participants continue to believe that the
provision of such information is essential. The ISO agrees. Moreover, from
a policy perspective, FERC believes that the ISO should not only publish
such information, but if requested, should also consummate trades between
SCs.
3.3.5 OTHER CONCERNS AND CALLS FOR IMPROVEMENT
In Congestion Management Reform stakeholder meetings, Market
Participants have voiced these and other concerns with the ISO's Congestion
Management process. In general, a large majority of Market Participants believe
that these must be corrected, but attribute them to failures in implementation
rather than to errors in the original market structure and design principles.
Most have articulated a belief that the original market structure and design
principles should not be abandoned.
3.4 CONGESTION MANAGEMENT REFORM: SYSTEMATICALLY CORRECTING CURRENT
DEFICIENCIES
This draft CMR recommendation sets out to systematically correct these
deficiencies by ensuring that the new design:
o Embodies the principle that operating procedures and resource constraints
must be reflected accurately in the real-time market (price signals and
cost allocation), and further, that the real-time market must be the model
for the forward markets to ensure that forward schedules do not violate any
real-time operating constraints in the transmission system;
13
o Distinguishes circumstances in which market power precludes reliance on
competitive market incentives to inducedesired behavior, from circumstances
in which competitive markets and prices are effective; and
o Provides more information and tools to Market Participants to facilitate
efficient decentralized decision-making.
Market designs that accomplish these three objectives will provide accurate,
strong locational price signals. This means prices that reflect differences in
the cost of delivering energy imposed by the physical locations of generating
resources and loads with respect to constraints in the transmission grid, and
that are not inflated by the exercise of location market power. These three
objectives comprise the foundation of the market design approach used to develop
this CMR recommendation. Section 4 provides a full description of the CMR
conceptual framework and design strategy.
In addition to the primary deficiencies discussed in this section,
Market Participants have identified other considerations to be weighed in the
design process and used to evaluate alternative design options and reform
recommendations. In Section 4, these other considerations and criteria are
identified and summarized.
4. CONGESTION MANAGEMENT REFORM DESIGN FRAMEWORK AND CRITERIA
The purpose of this section is to present the conceptual framework and
design criteria upon which this CMR proposal is based. The framework and
criteria are presented here only in general terms, as the substance of the
proposal is presented in great detail in sections 5 through 9. Subsection 4.1
describes the overall design framework underlying the development of this
proposal, starting from the deficiencies of the current CM design as discussed
in the previous section, and then utilizing the original design principles of
the restructured California market to define a strategy for eliminating the
identified deficiencies while enhancing the operational reliability of the
system and the efficiency of the congestion management markets. This strategy
then becomes the basis for the CMR proposal that is summarized in Section 6. At
the end of 4.1 we discuss an alternative design approach based on locational
marginal pricing. Subsection 4.2 then summarizes the various design criteria
that have guided the numerous design decisions made in the course of developing
this proposal, and talks briefly about the use of these criteria for evaluating
alternative design options. Finally, Subsection 4.3 describes some of the
deficiencies of the current market structure that inhibit the development of
fully competitive markets, some of which are beyond the ability of the CAISO to
correct.
4.1 DESIGN FRAMEWORK
The conceptual framework adopted for developing this proposal is based
on the recognition that: (1) reliable operation of the grid in real time is
absolutely crucial to the ISO's mission of supporting a competitive electricity
market; and (2) forward congestion management (CM) must be consistent with and
must support real-time operating needs. These observations imply that, for the
new design to be successful, the ISO's CM procedures should manage and price all
scarce transmission resources in a consistent manner across all markets, from
forward scheduling and procurement of services to real-time operations.
Starting from this general design principle, the CMR proposal presented
in this document addresses the deficiencies of the current CM approach as
described at the end of section 3. Specifically, the proposed CM approach:
14
[] Allocates and prices transmission resources in the forward
markets in a way that is consistent with the ISO's real-time
operating needs;
[] Clearly distinguishes between competitive and non-competitive
situations for managing transmission congestion, particularly
to ensure that resources needed at specific locations for
reliability will not be able to exercise market power;
[] Ensures accurate locational pricing in the imbalance energy
market when congestion occurs in real time; and
[] Provides sufficient information and tools to allow market
participants to identify and execute efficient trading
opportunities, in particular, to effectively self-manage
congestion.
In addressing the identified problems, the present design framework
reaffirms the fundamental original design principles of the California approach
to restructuring as discussed in section 3; i.e., the proposed CMR approach:
[] Separates pricing and allocation of scarce transmission
resources (performed by the ISO) from the pricing of forward
energy (performed by the SCs);
[] Relies on decentralized production decisions (unit commitment
and dispatch) in the forward markets, rather than allowing or
requiring the ISO to make involuntary trades between distinct
forward energy markets (SCs); and
[] Unbundles services in a logically consistent manner, to
maximize transparency and stimulate market innovation, and to
allocate costs efficiently to the responsible entities.
4.1.1 REAFFIRMATION OF THE ORIGINAL CALIFORNIA DESIGN PRINCIPLES
In the course of the CMR effort we have revisited the original goals of
electric restructuring and the design principles that guided the California
approach to restructuring. These principles are captured most succinctly in two
concepts: (1) full separation of competitive forward energy markets from
monopoly transmission service, and (2) decentralized production decisions (unit
commitment, dispatch, generation investment). We considered how the California
market might be redesigned by departing from these principles, but could find no
compelling reason to depart from them, no evidence that they are flawed or that
some other principles would lead to deeper and more efficient markets, or to
greater efficiency or innovation.
The California design principles, we believe, are fully consistent with
the primary goal of electricity restructuring - to lower delivered Energy costs
in the long run by providing incentives and opportunities for efficient
production, consumption and investment decisions, and by stimulating innovation
in business practices and service offerings to consumers. Early in the
restructuring process, industry experts and policy makers were virtually
unanimous in identifying the optimal strategy for achieving this goal, namely,
to develop competitive markets for generation services (and for related
wholesale and retail marketing activities), while maintaining a regulated
monopoly structure for the transportation services (transmission and
distribution), and ensuring that these monopoly services be operated as
independent, common carriers to support the generation market.
The original California design principles were an attempt to implement
as fully as possible this key strategy of restructuring, and to a large extent
California has been extremely successful in developing a market structure that
allows generators to compete to provide a wide variety of services, including
both forward Energy sales to customers and services needed by the ISO to provide
reliable transmission service. The ISO, in particular, has structured its own
operation to unbundle its service needs and rely on
15
competitive markets as far as possible to meet those needs, while staying out of
the markets that supply Energy to wholesale buyers and end-use consumers. And
while it is true that the present CMR effort was stimulated by significant flaws
in the design and operation of the ISO's CM market, these flaws do not call into
question the original California market design principles. Quite the contrary,
this CMR proposal returns to these principles as a foundation, and based on them
it addresses and eliminates the flaws identified in the present CM approach and
provides for further improvements to the ISO's performance of its functions.
4.1.2 FUNCTIONAL UNBUNDLING
In Order No. 888, FERC found that the "functional unbundling" of
wholesale generation and transmission services (i.e., separate pricing of
discreet services, such as Energy, transmission and Ancillary Services) was
necessary to implement non-discriminatory open-access transmission. From an
economic perspective, unbundling of Energy and transmission is a prerequisite if
markets are to establish accurate price signals for these distinct services.
FERC stated at that time that it would continue to observe the evolution of
competitive power markets and the progress of industry participants in adapting
their structures to be consistent with the functional unbundling requirement for
competitive markets. FERC stated that to the extent it observed that its mandate
for functional unbundling was inadequate, it would decide if other structural
mechanisms such as ISOs were required. The original California market design
aggressively complied with the intent of Order No. 888 by adopting a structural
solution whereby the forward Energy market was completely separated from the
forward transmission market via the creation of a separate PX and ISO.
We believe it is necessary and appropriate to reaffirm this approach in
the redesign of CM. If the ISO were to become involved in consummating
forward-market trades of Energy, the ISO would unnecessarily interfere with the
establishment of accurate prices for Energy and transmission. Such interference
would also undermine the objective of fostering innovation in business practices
and service offerings by diluting the rewards that the most innovative firms
would be able to capture in a robust competitive market. These concerns
necessarily exclude the ISO from conducting Energy markets or engaging in any
unnecessary market transactions that could distort competitive outcomes due to a
blurring of the boundary between competitive market activities and monopoly
services. The scope of the ISO's activity should therefore be confined to
transmission management, including forward and real-time allocation and pricing,
real-time operation, and long-term planning.
16
4.1.3 DECENTRALIZED DECISION MAKING
An essential strategy of electric structuring was to replace the direct
command and control paradigm of the vertically integrated electric utility with
a system of price signals and rules of behavior intended to induce parties to
behave in a manner that will enhance economic efficiency. The premise of this
market-based strategy is that the market-clearing prices derived from bids in
well-designed wholesale markets are the best economic signals for the following:
[] Coordinating daily operations among independent suppliers and
consumers
[] Stimulating profitable investments and innovation.
Examples of market innovation are already evident in the West. The deep
and liquid forward Energy trading hubs that have developed at Palo Verde, the
California-Oregon Border (COB) and Mid-Columbia are examples of participants
recognizing trading opportunities and stepping forward to facilitate the market.
The California PX has also responded to the needs of the marketplace
and has, over the past year, implemented a number of new features and markets.
Not only does the PX operate a Day-Ahead market for Energy, but the PX has also
implemented and now provides a block-forward market and a Day-of market for
Energy. In response to its participants, the PX has also recently implemented
the ability to self-supply its AS obligations.
The California PX is not the only Energy exchange that operates in the
West. The Automated Power Exchange (APX) facilitates a sizeable and growing
share of Energy transactions through its innovative continuous-trading system.
To the extent that the three investor-owned utilities participate outside of the
PX in the future, trading organizations like the APX are likely to see increased
trading volumes and an increased share of the forward Energy market.
The ISO has also seen Market Participants respond to and take advantage
of other markets. For example, in the ISO's Summer 2000 Demand Relief Program
(DRP) a number of Market Participants have stepped forward to facilitate and
avail themselves of opportunities in the fledgling demand-responsive market. The
demand side of the market is one area where there are ample opportunities for
innovation and investment. Unfortunately, this is one area where structural and
procedural impediments stand in the way of market innovation.
4.1.4 THE ORIGINAL DESIGN PRINCIPLES AS THE BASIS FOR CONGESTION
MANAGEMENT REFORM
Reaffirmation of the original California design principles will
undoubtedly be somewhat controversial, as there are some parties who believe the
ISO should perform centralized unit commitment and optimal dispatch of
generating units. Instead, this CMR proposal advocates separating the monopoly
transmission service from the competitive supply of electricity as far as
possible, as long as there is no compromise of the ISO's mission to provide
non-discriminatory access and reliable operation to support the competitive
energy market.
As part of its design strategy, this CMR effort has included a
comprehensive examination of the role of CM in the context of the ISO's overall
mission and responsibilities, as well a review of the ISO's function within the
larger context of the restructured California electric industry. In developing
this proposal, then, we have sought to ensure consistency between CM and these
larger contexts, as well as internal consistency within the CMR proposal itself.
This design approach has resulted, we believe, in a CMR proposal that enhances
operating reliability and market efficiency, while effectively separating the
generation and transmission functions of the industry. The proposal achieves
this result by following the
17
principle articulated at the beginning of this section; namely, to manage and
price all scarce transmission resources in a consistent manner across all
markets, from forward scheduling and procurement of services to real-time
operations. The proposal accomplishes this by:
[] Using best-practice engineering standards for operating the ISO system
in real time
[] Designing the real-time market to price scarce transmission accurately
when there is real-time congestion;
[] Designing the day-ahead and hour-ahead markets to establish consistent
forward prices for the same transmission resources that are priced in
real-time, based on the same operating practices actually followed in
real time, thus ensuring that forward schedules are simultaneously
feasible in real time (based on system conditions at the time these
markets are run);
[] Effectively mitigating locational market power in procuring resources
needed at specific locations for reliability;
[] Issuing a mix of long-term and short-term firm transmission rights
(FTRs) for the same transmission resources, in substantially greater
quantities than today, to allow efficient hedging of transmission costs
and to stimulate deep markets for secondary trading of these rights;
[] Providing market information and tools to enhance the ability of market
participants to make efficient decentralized decisions, e.g., inter-SC
trades for self-managing of congestion by the market.
AN ALTERNATIVE DESIGN APPROACH -- LOCATIONAL MARGINAL PRICING
One additional important design objective that has not been explicitly
discussed in this section is the need to create accurate locational price
signals, a theme that has been emphasized by nearly all parties involved in the
CMR effort. The concept of accurate locational price signals entails two
essential features. Locational price differentials:
1. should reflect differences in the cost of delivering energy
imposed by the physical locations of generating resources and
loads with respect to constraints in the transmission grid;
and
2. should not be inflated by the exercise of locational market
power.
Some parties believe that to achieve accurate locational price signals
the ISO must implement what is known as locational marginal pricing of energy
(LMP for short). We believe, in contrast, that it is possible, indeed preferable
in the California context, to create accurate locational price signals without
involving the ISO in the business of pricing Energy in the forward markets. (We
do, however, create locational prices for Imbalance Energy in the real-time
market, as discussed in sections 6 and 9.)
The approach recommended in this proposal is to reverse the pricing
sequence commonly used in LMP approaches, which first prices Energy at each
location on the grid (generally an individual bus or node), and then uses the
difference between any two Energy prices to price transmission service between
the corresponding two locations. Under the California design approach, however,
forward Energy pricing is the business of SCs, who operate forward markets or
manage bilateral forward contracts for Energy. Consistent with the principle of
separating the competitive forward Energy markets from the regulated monopoly
transmission service, the CAISO only prices transmission service, and allows SCs
to use these transmission prices in whatever ways are consistent with their own
business practices to determine prices for forward energy at various locations.
The challenge for the CAISO, then, which this proposal addresses, is to price
transmission in such a way that the transmission prices represent accurate
locational price signals to the users of the transmission system. That is,
following the definition given earlier, the transmission prices resulting from
the ISO's CM must reflect the cost of moving Energy across (or into or out of)
constrained areas of the grid, as determined by an open, nondiscriminatory and,
wherever possible, competitive process for allocating the use of the grid, and
these prices must not in any instance be inflated by the exercise of market
power. Sections 6 through 9 explain in detail how the present CMR proposal
accomplishes this.
18
4.2 DESIGN CRITERIA
This subsection summarizes the design criteria adopted in crafting the
present proposal, organized in such a way as to convey the CMR design logic that
will be discussed more fully in section 6. At the end of this subsection, we
restate the eleven "Criteria for Evaluating Proposed Solutions" discussed at the
May 10-11 stakeholder meetings, and describe how they will be used to evaluate
this proposal and the alternative design options we considered. The May 10-11
criteria are, with one exception, captured in the design criteria laid out below
(as indicated by the shorthand SH#1, etc.).
4.2.1 RELIABLE OPERATIONS - Fundamental to the CMR effort is the ISO's
primary mission of operating the transmission grid reliably in real time. The
CMR proposal must therefore enhance the ability of operators to operate the
system reliably, by providing tools for more effective real-time operation and
by designing forward Congestion Management (CM) to produce schedules and provide
market incentives that are consistent with and supportive of real-time
reliability. A related requirement is that the CMR proposal must be appropriate
to the structure of the power system in California and the WSCC region.
4.2.2 ECONOMIC EFFICIENCY - Economic efficiency emphasizes outcomes;
specifically, achieving the required level of operational reliability at the
least social cost (i.e., the least expenditure of society's resources). This
involves reducing the delivered cost of electricity (which entails reducing
transaction costs, and reducing production costs through more efficient
long-term investments and turnover of capital stock) and stimulating innovation.
(SH#10)
4.2.3 MARKET EFFICIENCY - Market efficiency focuses on the performance
of markets as the means to achieve the stated economic efficiency objectives
(SH#1). Market efficiency is concerned with creating market incentives that
align with operational objectives and result in competitive outcomes. To do
this, the market mechanisms we design must be compatible with the physical laws
of electricity transmission. Market efficiency has a number of dimensions that
have been identified in the course of the CMR process, including:
[] Provide accurate locational price signals (SH#2). One measure
of accuracy is that prices should reflect conditions of
scarcity and should not be distorted by market power.
[] Provide effective investment incentives (SH#3).
[] Mitigate market power (SH#4). Prevent a single market
participant (or collusion among several participants) from
determining market prices or earning exorbitant payments for
any significant time period. The market power mitigation
approach must distinguish between market power exercise and
genuine scarcity.
[] Provide transparency and simplicity (SH#5).
[] Rely on market mechanisms (SH#6). Emphasize market incentives
rather than administrative mechanisms such as price caps.
[] Reduce barriers to entry (SH#7).
[] Minimize transaction costs, as distinct from production costs
(compare SH#9, enhance commercial transactions). This
includes, for example, provision of adequate information to
market participants to facilitate efficient trading and
bidding behavior.
19
[] Allow market participants to hedge their risks in the forward
markets (SH#11). The FTR market is an example of an
ISO-provided infrastructure that enables participants to hedge
transmission cost risk to meet the objective of "transmission
price certainty" stated in FERC Order 888.
[] Eliminate arbitrage opportunities that are not consistent with
market efficiency and system reliability (i.e., gaming).
[] Internal consistency (compare SH#5, internal consistency of design).
For example, the financial incentives of various design elements should
be mutually reinforcing, not antagonistic or mutually nullifying, and
they should reinforce behavior consistent with market rules and system
reliability.
4.2.4 INSTITUTIONAL FACTORS
[] The proposal must address the full range of stakeholder
concerns, including all ongoing impacts of the proposed
redesign, such as cost allocation on various stakeholder
groups. Included in this factor are distributional equity
issues.
[] The proposal should be responsive to FERC's order to design "a
comprehensive replacement congestion management approach."
(January 7, 2000 Order, p. 10)
[] The proposal should satisfy the Congestion Management
requirements in FERC's Order 2000 on RTOs.
[] There should be consistency with California's high-level
market restructuring principles. When the California market
was first restructured, its design was based on a few
high-level principles which distinguish the California
approach from electric restructuring approaches adopted in
other jurisdictions. These principles are:
[] Separation of competitive generation markets from
regulated transmission service.
[] Facilitation of decentralized supply decisions
(short-term unit commitment and dispatch, and
long-term generation investment).
[] Maximum unbundling of functions for transparency and
to facilitate innovation and learning by market
participants.
4.2.5 EVALUATION CRITERIA ADOPTED AT THE MAY 10-11 STAKEHOLDER MEETINGS
- - At the May 10-11 stakeholder meetings, participants agreed to the following
set of evaluation criteria to be used in the CMR effort: SH#1. Promote market
efficiency.
SH#2. Provide accurate locational price signals.
SH#3. Provide effective investment incentives (for generation,
transmission, DSM).
SH#4. Mitigate market power.
SH#5. Provide transparency, simplicity, and internal consistency
of design.
SH#6. Rely on market mechanisms.
SH#7. Reduce barriers to entry.
SH#8. Offer a complete cost/benefit evaluation.
SH#9. Enhance commercial transactions.
20
SH#10. Promote economic efficiency ("economic efficiency" is
currently undefined).
SH#11. Allow market participants to hedge their risks in the
forward markets.
All of these criteria except SH#8 are captured in the design criteria
described above. In the course of the CMR design effort, we will use these
criteria to evaluate the proposal presented here as well as alternative design
options that were proposed and considered. Regarding SH#8, we believe that doing
a full economic cost-benefit analysis would be extremely difficult, if not
impossible, particularly because of the arbitrariness involved in quantifying
benefits. Instead, we propose to assess the implementation impacts on market
participants and the ISO, and to develop reasonable estimates of the ISO's
implementation costs and time frame for the proposed approach.
4.3 CURRENT IMPEDIMENTS TO COMPETITIVE MARKET DEVELOPMENT
There exist today a number of impediments to further market
development. These obstacles exist in part because of the need to transition
smoothly from the traditional vertically-integrated utility paradigm to the new
market structure. They include the following:
o THE RETAIL RATE FREEZE - One of the main inefficiencies of the
integrated utility paradigm that electric restructuring sought to
change was the fact that production costs varied in response to
changing load, weather and system conditions, while most consumers paid
flat rates regardless of when they consumed. One obstacle to market
development today is that this inefficiency has not yet been
eliminated. In an effort to ensure that competitive restructuring would
not lower electricity rates to an extent that would jeopardize or
excessively lengthen the time needed for recovery of stranded costs by
the investor-owned utilities, the California Public Utilities
Commission (CPUC) imposed a freeze on retail rates that was to last
until the earlier of April, 2002 or when the utilities recovered their
stranded costs. While we recognize the necessity and propriety of such
an approach, the retail rate freeze has effectively inhibited
development of a responsive demand side of the market by insulating
consumers from the time variation in wholesale electricity prices. The
rate freeze has significantly dampened the price signals that a
competitive market relies upon to signal when and where investment is
needed, and until it ends retail customers will have little motivation
to reduce their consumption in response to higher Energy prices.
o LACK OF HEDGING INSTRUMENTS - Related to the issue above, the CPUC has
limited the ability of the IOUs to actively participate in the forward
contracting or "hedging." Forward contracts for Energy enable Market
Participants to hedge against the risk of higher or volatile Energy
prices. The inability of the IOUs, who represent a large share of the
Load in the market, to participate fully in this market has hampered
the development of hedging instruments. Moreover, their inability to
hedge has led them to arbitrage (hedge their risk) between the
Day-Ahead and real-time Energy markets and thereby given rise to
certain of the real-time operational difficulties experienced by the
ISO over the past two years. We believe that if they had an opportunity
to forward contract to the fullest extent possible, Load would be
effectively hedged in the forward markets and have less incentive to
show up in real time. That is, consistent with the new market design
approach, Market Participants would be able to effectively self-manage
their energy needs in the long or Day-Ahead markets and would therefore
be scheduled in the forward markets and reduce the complexity of the
ISO's real-time operations.
o THE NEED FOR MARKET INFORMATION - While not necessarily a tool the ISO
has to provide, there are some types of information the ISO could
provide to the market to assist Market Participants in identifying
trading opportunities and managing their affairs in the forward
markets. This is a critical feature of the new market design. To date,
while the ISO publishes a large amount of information via
21
its Public Market Information (PMI) site on the ISO Home Page, the ISO
does not purposefully publish information that may assist in
facilitating trades between SCs. It is essential that Market
participants step forward and identify the type of information they
need in order to accomplish this task. While we continue to believe
that the ISO should not be involved in consummating trades, we
understand that the ISO is the repository of information that may be
useful, if not critical, to the facilitation of Inter-SC trades.
The above list is not intended to be a comprehensive list of the
impediments to a fully competitive Energy market. Until these impediments are
removed or addressed, however, we believe that the ability of the market to
achieve the efficiency and innovation goals of electric restructuring will be
hampered. We continue to believe that a decentralized energy market, where
competitive energy production decisions are separated from the provision of
monopoly transmission service, is workable and necessary to foster the
development of truly competitive Energy market. The ISO's efforts alone,
however, cannot achieve this outcome.
5 REAL-TIME OPERATIONAL REQUIREMENTS
5.1 INTRODUCTION
The business of providing electricity transmission services is
undergoing sweeping changes nationwide. Historically, transmission services were
provided by vertically integrated utilities that produced, transmitted and
delivered electricity to the consumers. The overall goal of the transmission
system designers was to plan an integrated system of generators, transmission
components and distribution equipment to provide service to native load
customers at adequate levels of reliability while minimizing the combined costs
of generation, transmission and distribution. The principal reasons for adding
new transmission facilities were: a) to allow larger generating stations to
serve larger loads over longer distances thereby reducing the need to construct
generation facilities near urban load centers, b) to network existing
transmission paths to increase reliability and continuity of service, and c) to
interconnect to other control areas to facilitate economical transactions, share
reserves and provide emergency backup.
While the purpose for providing transmission service is the same in the
restructured marketplace as it was before - to reliably deliver Energy to Load -
transmission system operators are no longer able to rely on generators and other
resources to the same extent they once could. As opposed to the vertically
integrated utility paradigm, transmission system operators must use market
incentives to get the necessary response from market resources (except, of
course, in instances of system emergencies) while continuing to operate the grid
to the existing reliability standards. As part of the ISO's Congestion
Management redesign effort, it is therefore important to understand the
interrelationship between the structure of the transmission grid, the methods a
transmission system operator uses to operate the grid and the resources
available to that operator from the market.
5.2 PHYSICAL CHARACTERISTICS OF THE WESTERN TRANSMISSION SYSTEM
The configuration of bulk power transmission systems vary from region
to region across the United States. This section is intended to highlight
critical features of the bulk power transmission system in California and the
Western United States that give rise to the operational requirements met by the
CAISO to ensure reliable and secure operations. In contrasting the
characteristics of transmission system operation in general, and congestion
management in particular, between Eastern and Western United States, it is
important to realize that bulk power transmission systems in the Eastern United
States are configured quite differently that those in the West. Ultimately, this
CMR recommendation seeks to structure markets (real-time and forward) around the
operational requirements of the bulk power transmission
22
system in California, and its impacts on neighboring control areas, with a view
to seamless operation in the broader context of a Western Interconnection RTO,
or multiple Western RTOs.
The high voltage transmission system in California and the West spans
hundreds of miles to connect Generation resources to Load centers, and thus is
not heavily meshed throughout the State as it typically is in the eastern
states. The vast majority of the 230 and 500 kV systems run from the Pacific
Northwest to Southern California and from the Southwest to Southern California.
The California ISO controls approximately 75 percent of the California
grid. The transmission grid under ISO's control includes the transmission
systems formerly operated by the three investor-owned utilities in the state
(Pacific Gas and Electric Company, Southern California Edison Company and San
Diego Gas & Electric Company). These utilities were pursuing their own economic
interests, while abiding by the NERC and WSCC operational requirements to
preserve system reliability. In contrast, the Eastern Interconnection
transmission system was designed and developed to support a tight power pool.
This difference is manifested in the highly meshed networks in the Eastern
Interconnection, as opposed to a relatively sparse donut shaped transmission
system with major radial corridors surrounding California.
5.3 OPERATIONAL REQUIREMENTS OF THE WESTERN TRANSMISSION SYSTEM
The NERC and WSCC have developed technical operating and planning
criteria to serve as standards for transmission design and operation to protect
the system against the occurrence of system failure. The operating procedures
used by the ISO are based on the application of Minimum Operating Reliability
Criteria (MORC) to the ISO system. These MORC criteria have been developed by
WSCC and NERC and must be satisfied at a minimum however, the local operating
criteria used by the CAISO may be more stringent than MORC. The WSCC MORC are
divided into the following criteria: a) Generation Control and Performance, b)
Transmission, c) Interchange, d) System Coordination, e) Emergency Operations,
f) Operations Planning, g) Telecommunications and h) Operating Personnel and
Training.
These operating and planning criteria are fundamental to the operation
of the transmission grid. They reflect the physical limitations imposed by the
existing hardware and the physical laws governing the flow of electricity. They
are crucial to the operating decisions operators make in real-time irrespective
of economic considerations. Therefore, they represent a reference base point for
the feasibility of any congestion management procedure. Among these, the
operating criteria related to transmission and interchange for network security
and local reliability deserve further explanation.
In the daily operation of any power system, overall system security as
well as local reliability requirements are determined so as to guard against
thermal overloads, voltage violations, angular instability, and voltage
instability in the event of credible contingencies. Based on the accepted WSCC
and NERC criteria, a credible contingency may include the forced (unplanned)
outage of a single major element such as a line, transformer, or on-line
generator (n-1 contingency), simultaneous outage of two major elements (n-2
contingency), and in rare cases, outage of more than two elements.
Thermal overload and voltage violations are steady-state phenomena.
Under steady-state conditions both before and after a contingency, transmission
line flow levels and substation voltages must stay within specified limits.
Angular instability and voltage instability are dynamic phenomena. Even if a
feasible post-contingency steady-state may exist, angular instability or voltage
instability may prevent transition to such a state, and result in loss of
synchronism, cascading outages, or voltage collapse.
Voltage collapse can occur when a load and the associated transmission
system require a very large amount of reactive power (compared to the real power
component of the load) that exceeds the capability of the reactive power
sources. Under this condition, any increase in load is accompanied by a
23
drastic voltage drop and the voltage "collapses." This condition is usually
triggered by some form of disturbance which creates an increased demand for
reactive power.
Angular instability occurs when, following a disturbance, generator
oscillations are not restored to a stable, steady and secure operating
condition. In addition, if transmission equipment fails, other circuits may
overload and in turn may trip out of service, which then leads to more overloads
and the potential condition of system instability.
Any of the three conditions, mentioned above, can lead to system
segmentation and/or failure, and interruption of service to customers. Systems
with highly meshed networks are predominantly constrained by thermal limits,
whereas systems with sparse transmission networks may be limited by a
combination of thermal, angular stability, and voltage security limits.
Although the state of the art of on-line network security analysis
permits on-line determination of secure operating limits to guard against
thermal overloads in the event of credible contingencies, it does not yet have
the capability for on-line determination of secure operating limits to guard
against angular and voltage instability due to excessive computational
requirements. A large number of off-line studies are therefore conducted (over a
period of months or years) for different system conditions, and the secure
operating limits for each system condition are compiled in the form of operating
Nomograms and procedures. As new situations arise, these operating Nomograms and
procedures are updated.
5.4 CALIFORNIA ISO OPERATING PROCEDURES AND NOMOGRAMS
In general, a Nomogram defines an area of reliable operating conditions
relating two (or more) interdependent transmission quantities. Only the most
significant parameters are included in the Nomogram. The Nomograms are developed
for conditions with all transmission equipment in-service, as well as conditions
with equipment out of service. In certain areas of the system, the operating
criteria may be more stringent than in others, but at all times they meet the
MORC. The ISO currently has nearly 50 transmission operating procedures and
nearly 10 generation control procedures.
[NOMOGRAM EXAMPLE GRAPH]
24
The graph above illustrates a simple Nomogram of two transmission
quantities. The non-simultaneous ratings of Path 1 and 2 are 1000 MW. However,
both paths cannot be simultaneously loaded at 1000 MW. The two paths interact
and the actual operation of the paths must remain to the left of the Nomogram
line. As an example, if Path 1 is operating at 800 MW, Path 2 may not exceed 700
MW.
The Nomogram may also be a function of other key parameters, such as
load, generation, inertia, or Remedial Action Schemes (RAS). As a result, a
Nomogram may have numerous lines, or families of curves that describe the
relationship under many operating conditions.
The Nomograms are used to operate the transmission paths reliably. When
performing operations planning (three days before up to the day-ahead of the
operating day), the path limits are based on the projected operating conditions
for the operating day based on the most recent operating conditions, which
affect the parameters of the Nomogram. The Nomograms are then used by the
real-time system dispatchers to monitor the transmission system.
Also embedded into some of these operating procedures are the
procedures for operating the system within and at the Interface of Local
Reliability Areas. These procedures state that certain generation must stay on
line with enough capacity in case of a derating of the interface (one facility
or at times two facilities). This is to ensure there is enough capacity on-line
that can respond, in the needed time frame, to prevent the degradation of system
adequacy and security.
These Operating Procedures and Nomograms define the operating
requirements around which this CMR recommendation structures real-time and
forward markets. Operating constraints reflected in the operating procedures and
Nomograms will be monitored and enforced in all time frames and constraints that
are binding will be priced. These Operating Procedures and Nomograms underly all
elements of this CMR: Local Reliability Service Procurement, FTRs, LPA
definition and creation, DA- and HA-Congestion Management and, the real-time
markets operated by the CAISO. Section 6 summarizes the entire proposal and
Chapters 7,8, and 9 provide detail on recommendations for changes in each of
three time-frames: long-forward (greater than day-ahead), between day-Ahead and
real-time, and in real-time, respectively.
6. OVERVIEW OF THE REFORM PROPOSAL
NOTE TO READERS: For the sake of brevity this overview section does not
identify the alternative design options that were considered in developing this
proposal. The alternatives are presented in sections 5-7, accompanying the more
detailed description of options we are recommending.
6.1 DESIGN APPROACH
The design approach adopted in this proposal is based on the
recognition the following concepts:
1) Reliable operation of the grid in real time is absolutely
crucial to the ISO's mission of supporting a competitive
electricity market.
2) Forward congestion management (CM) must be consistent with and
must support real-time operating needs.
Point 1) should be self-evident, but by itself it offers insufficient
guidance on how to design forward CM. When point 2) is added, however, some
important design implications emerge. Specifically, THE ISO'S CM PROCEDURES
SHOULD MANAGE AND PRICE ALL SCARCE TRANSMISSION RESOURCES IN A CONSISTENT MANNER
ACROSS ALL MARKETS, FROM FORWARD SCHEDULING AND PROCUREMENT OF SERVICES TO
REAL-TIME OPERATIONS.
As the first two years of operation have shown, failure to follow this
principle provides opportunities and incentives for Market Participants to
schedule and operate in ways that are not consistent with market
25
efficiency and reliability. For example, this principle is violated under the
present CM design, which ignores Intra-Zonal Congestion in the forward markets
and then requires the ISO to call upon resources in real time to relieve
Intra-Zonal constraints. Thus market participants are allowed to submit
infeasible schedules in the forward markets and then receive payments in real
time to resolve the problems their forward schedules created.
Based on these observations, the CM design proposed herein starts with
real-time operating requirements and works backwards in time to identify a
sequence of activities and decisions by Market Participants and the ISO, all of
which must comprise an internally-consistent process leading to reliable,
efficient real-time operation. In the integrated utility structure, where
planning and operating decisions were all centralized, the coordination needed
for reliable system operation was achieved through a hierarchical command and
communication structure. In the competitive market structure, and particularly
in the California approach, multiple entities are making independent operating
decisions that are not centrally controlled. In this new structure, the
coordination needed to achieve reliability and market efficiency must be
designed into the system of financial incentives (such as price signals) and
market rules. In the context of CM, this means that CMR must establish
incentives and procedures that will lead to final schedules that are feasible in
real time and that represent as closely as possible what Generators and Loads
actually intend to produce and consume in real time.
In this section, we describe the overall logic of the design starting
from real time and moving backward in time, to show how the design of forward CM
is driven by real-time operating needs overlaid with economic considerations. We
start with an overview of real-time operations, followed by day-ahead and
hour-ahead CM for the major interfaces within the ISO grid and the inter-ties
with neighboring control areas, followed by the proposed two-day-ahead
procurement of Local Reliability Service to meet locational needs within the ISO
system. Using this section as a roadmap, the sections 5-7 move forward in time,
taking the viewpoint of a market participant and walking through the actual
sequence of activities and decisions that would occur leading up to each Trading
Day. A comprehensive overview of the whole sequence is presented in Section 4.6
in the form of a timeline.
Readers of this CMR proposal will likely note that in order to make
this proposal workable, ISO will need to provide certain kinds of information to
market participants that it does not provide today,. For example, the market
will need to have general information about Operating Procedures in various
local areas of the ISO grid, as well as daily information on applicable nomogram
constraints. In this proposal these new information requirements are identified
only in the most general terms, and much work remains to be done to fully
specify the requirements and develop appropriate mechanisms for publishing the
needed market information.
6.2 REAL-TIME OPERATION AS THE BASIS FOR CREATING LOCATIONAL PRICE AREAS
(LPAS)
In real time operation, the ISO operators issue dispatch instructions
to generating resources and Loads to adjust their operating levels to meet local
reliability requirements and system-wide or zone-wide energy imbalances.17 In
this process the operators must observe multiple reliability constraints imposed
by thermal limits on lines, local voltage support requirements, minimum
generation requirements, and stability and security (i.e., contingency)
requirements. These constraints are expressed in formal Operating
- ----------
17 To some extent these real-time needs can be anticipated, for example when
the level of load and generation scheduled in the forward market is much
less than the load forecast. In many instances, however, real-time needs
result from unanticipated causes including outages of generating units and
transmission lines, and load forecast errors.
26
Procedures (OPs) and nomograms(18), which operators use to determine the correct
dispatch instructions to issue to resources within each local reliability
area(19) (LRA) within the ISO system.
The OPs and nomograms, and their corresponding LRAs, are essentially
two sides of the same coin. Both are derived from the physical properties of the
grid, including the capacities of lines and other transmission facilities and
the locations of generating units and loads relative to transmission facilities
and constraints. The LRA is a geographic area where transmission is limited or
vulnerable, while the OPs and nomograms prescribe the actions operators must
take to ensure that the grid operates reliably within that LRA and on the links
between that LRA and the rest of the grid.
6.2.1 DEFINITION OF LOCATIONAL PRICE AREAS Since real-time operating
needs form the starting place of this design proposal, it is therefore natural
that LRAs, OPs and nomograms be used to define the locational price areas (LPAs)
into which the ISO system will be divided. The LPAs will be used for the
purposes of allocating scarce transmission capacity in the forward markets,
procuring real-time imbalance energy and relieving real-time congestion. Under
this proposal, LPAs are of two types, one based on local reliability
considerations (i.e., LRAs, OPs and nomograms), and another based on major
transmission interfaces (i.e., Path 15, Path 26, and the inter-ties connecting
the ISO grid to neighboring control areas). For each local-reliability-based
LPA, the associated OPs and nomograms are used to define the Inter-LPA
constraints which link it to adjacent LPAs and which represent limits on the
energy flows between two adjacent LPAs. Under this proposal these constraints
and the major transmission interfaces are allocated and priced in the forward CM
markets.
The local-reliability approach to forming LPAs relies on certain
properties of the ISO grid and the physics of electricity transmission that are
captured in OPs and nomograms:
[] OPs/nomograms can be translated into Inter-LPA flow constraints that can be
allocated and priced in forward CM.
[] We can designate a set of 10-15 nomogram constraints (exact number to be
determined), plus inter-ties20 between the ISO and adjacent control areas,
which if managed in forward CM will ensure that final schedules are
feasible in real time. Feasibility in this context means transmission
feasibility - both Inter-LPA and within LPAs - but does not consider the
generator performance aspect of feasibility. This means that if system
conditions do not change between the time of forward CM and real time there
will be no violations of constraints either between or within LPAs.
(Generator performance feasibility is taken into account in real-time
operation, as discussed below.)
- --------
18 Nomograms are graphs that express simultaneous relationships between
generation levels, load levels, and transmission capacities, and use these
relationships to define "safe" and "unsafe" combinations of these variables
from a reliability point of view. For example, a nomogram for a specific LRA
might define the minimum level of internal generation for each level of
load, or the transfer capacity into the LRA for each level of internal
generation, or a minimum level of unloaded internal generation capacity for
each level of load.
19 Local Reliability Areas (LRAs) are geographic areas that are currently
defined and used by the ISO for assessing needs for local generation
services to support reliability, both on a forward basis (e.g., for RMR
designation and dispatch) and on a real-time basis (e.g., for identifying
Intra-Zonal congestion). Operating Procedures and nomograms are then the
tools operators use to manage these LRAs in real time.
20 The present designation of branch groups for managing congestion on
inter-ties will likely need some modification to be consistent with the new
LPAs being created within the ISO control area under this proposal. At the
time of preparation of this proposal, the exact changes needed are still
under discussion.
27
[] Forward management of Inter-LPA constraints to ensure feasibility generally
involves procuring specific, binding resource commitments (available
capacity plus minimum energy out of that capacity scheduled day-ahead)
within each LPA - see section 4.5 for details.
[] LPAs can be defined in such a way that all resources within a given LPA
will have equivalent shift or distribution factors for purposes of forward
scheduling of Inter-LPA flows and FTRs.
[] LPAs can be defined in such a way that all resources within a given LPA
have equivalent effectiveness factors for mitigating real-time violations
of Inter-LPA constraints.21
[] LPAs can be defined in such a way that, if the associated OPs and nomograms
are satisfied, there will be no intra-LPA congestion. (There are, however,
certain types of less prevalent constraints (such as clearances on
gen-ties) that may not be incorporated in a nomogram but that would impose
maximum generation limits on particular resources. The resource owners
would know about these constraints, and the ISO's schedule validation
procedures would ensure that submitted schedules observed them.)
6.3 REAL-TIME OPERATION
THE MAIN OBJECTIVE OF THE REAL-TIME CHANGES PROPOSED HEREIN IS TO
FORMALIZE AND MAKE TRANSPARENT THE PRACTICES OPERATORS FOLLOW TODAY, BASED ON
THEIR KNOWLEDGE AND EXPERIENCE, TO ENSURE THAT ALL CONSTRAINTS (AS EXPRESSED IN
OPS AND NOMOGRAMS) ARE SATISFIED DURING THE PROCESS OF MAINTAINING SYSTEM
BALANCE IN REAL TIME.22
Even though forward schedules are managed to be fully feasible with
regard to their use of transmission, congestion between or within LPAs can occur
in real time due to departures from schedule, random errors in the ISO's demand
forecast, or last-minute changes in line ratings and resource availability.
Therefore, in real time the operator will be faced with several types of
situations, which we propose to have the operator resolve as shown in the table
below. Situation (a) represents the simplest case, procurement of system-wide
imbalance energy when there is no existing or imminent congestion condition, and
its management is not materially different from today's approach. Situations
(b), (c) and (d), however, represent congestion conditions, in the form of
either existing constraint violations that need to be mitigated ([b] and [c]),
or needs for imbalance energy where dispatching resources in merit order would
create congestion that did not previously exist ([d]). The table provides a
summary; the details are provided below.
<Table>
<Caption>
- ------------------------------------------------------------- -----------------------------------------------------------------
SITUATION OPERATOR ACTION
- ------------------------------------------------------------- -----------------------------------------------------------------
(a) Imbalance energy need for which merit-order dispatch Dispatch BEEP resources in merit order similar to today, but
will not create any congestion problems use OPF approach to determine optimal dispatch.
- ------------------------------------------------------------- -----------------------------------------------------------------
- ------------------------------------------------------------- -----------------------------------------------------------------
(b) Real-time violation of an Inter-LPA or inter-tie Split BEEP at the constraint and set different real-time
constraint market-clearing prices (MCPs) on each side of the constraint.
Select resources to mitigate the violation based on their
effectiveness.
- ------------------------------------------------------------- -----------------------------------------------------------------
- ------------------------------------------------------------- -----------------------------------------------------------------
(c) Real-time violation of an Intra-LPA constraint Pay resources asbid to relieve the constraint violation, using
bids submitted with the forward Local Reliability Service (LRS)
procurement (details below).
- ------------------------------------------------------------- -----------------------------------------------------------------
</Table>
- ----------
21 An effectiveness factor for a particular resource and constraint is a number
between 0 and 1 indicating the share of each MW generated by the resource
that will impact the constraint. For example, if a 1 MW increase in the
output of Generator A causes a 0.2 MW increase in the flow over constraint
B, the effectiveness of A with respect to B is 0.2 or 20 percent.
22 Of course, the difference from today is that the number of LPAs will be
greater than the present number of zones, and the ISO will publish adequate
information on OPs and nomograms to enable the market to schedule and bid
efficiently.
28
<Table>
<Caption>
- ------------------------------------------------------------- -----------------------------------------------------------------
SITUATION OPERATOR ACTION
- ------------------------------------------------------------- -----------------------------------------------------------------
- ------------------------------------------------------------- -----------------------------------------------------------------
(d) Imbalance energy need for which merit-order dispatch (d-1) Same as (b).
would create:
(d-2) Same as (c).
(d-1) Violation of Inter-LPA or inter-tie
constraint
(d-2) Violation of intra-LPA constraint
- ------------------------------------------------------------- -----------------------------------------------------------------
</Table>
To resolve situation (a), (b) and (d-1), the operator will use an
optimal power flow (OPF) model, that is based on a simplified commercial network
model having one bus to represent each LPA. The simplified network model will
represent the larger WSCC area by including LPAs outside the ISO control area
(i.e., across each of the inter-ties), as well as all LPAs within the ISO and
all branch groups inter-connecting the LPAs. Using this network model, the OPF
will determine, every ten minutes, the optimal dispatch of BEEP resources to
meet the needs identified by (a), (b) and (d-1). This optimal dispatch will take
into account all generation feasibility constraints (e.g., ramp rates) as well
as transmission constraints.
One result of using such an OPF for real-time operation will be the
setting of different real-time imbalance energy prices in different LPAs. Real
time imbalance energy prices could potentially be different in all LPAs when
there is real-time congestion on one or more of the Inter-LPA interfaces.
Another result will be elimination of the need for the "target price" mechanism,
which is currently used to adjust bids in BEEP to prevent the ISO from executing
economic inc-dec trades to reduce real-time energy costs. The proposed real-time
OPF approach will in fact execute energy trades whenever dec bids exceed inc
bids, and thus will minimize total imbalance energy costs on a 10-minute basis,
subject to generation and transmission constraints.
To resolve situations (c) and (d-2) the operator will rely on telemetry
data and the usual dispatch power flow (DPF) model to identify real-time
violations or impending violations of Intra-LPA constraints. The operator will
dispatch resources as needed to relieve or prevent these violations, and will
pay the resources as bid, without any effect on the real-time MCP for the LPA.
6.4 FORWARD (DAY-AHEAD AND HOUR-AHEAD) CONGESTION MANAGEMENT
NOTE TO READERS: This section focuses primarily on day-ahead CM, as
hour-ahead CM is quite similar conceptually. For more detail on how hour-ahead
CM will work see section 6.
THE PURPOSE OF FORWARD CM IS TO VALIDATE AND AGGREGATE ALL SC SCHEDULES
AND ADJUST THEM AS NEEDED TO ENSURE THAT FINAL SCHEDULES ARE FULLY FEASIBLE IN
REAL TIME. FEASIBILITY IN THIS CONTEXT IS DEFINED WITH RESPECT TO THE
TRANSMISSION CONSTRAINTS THAT ARE EXPECTED TO APPLY IN REAL TIME, BASED ON THE
KNOWLEDGE AVAILABLE TO THE ISO AND THE MARKET AT THE TIME THE FORWARD MARKETS
ARE RUN. Thus if forward CM is completely successful, the only needs for
real-time re-dispatch of resources will be due to departures from schedules,
errors in the load forecast, and unanticipated network changes such as forced
transmission or generation outages.
Under this proposal, forward CM will have the following features:
[] The same constraints that apply in real time (OPs and nomograms, plus
limits on major interfaces and inter-ties) will be allocated and priced in
the forward markets, within the limits of our knowledge of these
constraints at the time the forward markets are run.
29
[] Allocation and pricing of constraints in the forward markets will be done
using adjustment (inc and dec) bids, as it is done today.
[] The market separation rule will apply as it does today, to maintain each
SC's schedule in balance as CM selects inc and dec bids to resolve
congestion.
[] The Congestion Management software (CONG) will employ the same simplified
commercial network model as is used for optimal dispatch in real time, as
described in the previous subsection. However, SCs will be required to
schedule at the node level, as they do today. A pre-processor will then
aggregate the submitted schedules to the LPA level for running CONG.
[ISSUE: THE PROPOSAL SHOULD HAVE SOME EXPLICIT DISCUSSION OF THE QUESTION
OF COMPARABILITY BETWEEN GENERATORS AND LOADS (ALSO DISCUSSED IN SECTION
8), AND WHAT COMPARABILITY OR EQUAL TREATMENT BY THE ISO IMPLIES FOR THE
SCHEDULING REQUIREMENTS ON LOADS.]
[] CONG will also run a full network model (3000 busses) utilizing all actual
constraints in the system, for the following two purposes:
1) To ensure on a forward basis, that there are no violations of
constraints within LPAs or in areas that are not managed by forward CM.
2) For study purposes, to evaluate the performance of the current
configuration of LPAs, and to assess whether that configuration needs
to be modified.
[ISSUE: THE RUNNING OF CONG ON THE SIMPLIFIED NETWORK MODEL IMPLIES THAT
THE INC AND DEC BIDS ACCEPTED BY CONG WILL NOT BE RESOURCE-SPECIFIC. THIS
ALLOWS SCS TO ALLOCATE THEIR ACCEPTED INCS AND DECS ANY WAY THEY CHOOSE
AMONG RESOURCES IN THE SAME LPA, BUT WHICH ALSO MEANS THAT THE ISO'S
"FINAL" SCHEDULES WILL NOT BE RESOURCE-SPECIFIC. AT SOME POINT THE ISO
NEEDS TO OBTAIN FINAL RESOURCE-SPECIFIC SCHEDULES IN ORDER TO RUN THE FULL
NETWORK MODEL TO IDENTIFY ANY INTRA-LPA CONGESTION. THUS FAR WE HAVE MADE
NO PROVISION FOR THIS.]
[] As noted in the discussion of real time, the representation of the
inter-ties will be somewhat different from today to reflect the topology of
the new LPAs. The details of how this is to be done are presently being
developed.
[] The congestion iteration of today's day-ahead market would be retained.
Adjustment bids that are not used in the first iteration would be published
on a voluntary basis, to facilitate inter-SC trading to relieve congestion.
A new activity rule would be implemented that would select the results of
either the 1st or 2nd iteration as the final schedules, depending on which
had lower total Inter-LPA congestion costs.
[] A/S would not be procured at the LPA level, but only system-wide or within
today's competitive zones. [ISSUE: WE MAY HAVE TO CONSIDER MORE LOCAL A/S
PROCUREMENT IF INTER-LPA CONGESTION MAKES IT IMPOSSIBLE TO MOVE A/S ENERGY
INTO THE LPA WHEN NEEDED, AND THIS VIOLATES A WSCC RELIABILITY
REQUIREMENT.]
[] FTRs would be required to guarantee scheduling of A/S on inter-ties
(although in the absence of congestion A/S could be scheduled on unused
inter-tie capacity).
[] FTRs would have priority for use of congested interfaces in the event of
curtailment, if attached to day-ahead schedules, the same as today.
[] Some additional schedule validation elements would apply to submitted
schedules, to ensure that local reliability resources have been scheduled
as committed (see next section), and that certain types of
30
less prevalent constraints that are not captured in the nomograms (e.g.,
clearances on gen-ties) are not violated.
[] Following the running of the usual CM for firm schedules, the ISO would run
a market for Recallable Transmission Service (RTS). See section 6 for
details.
6.5 LONG FORWARD (BEYOND DAY-AHEAD) ACTIVITIES
6.5.1 LOCAL RELIABILITY SERVICE (LRS) PROCUREMENT Each LRA has certain
local reliability needs that must be met in real time for the system to operate
reliably. In using LRAs, OPs and nomograms to define new LPAs, a method is
needed to ensure that essential local reliability resources will be provided in
real time. The method proposed here is to procure these resources through a
two-day-ahead (2DA) Local Reliability Service auction in which resources
selected will be paid a capacity payment to guarantee that a certain amount of
capacity will either be available to the ISO to call in real time or will be
operating in real time. Additionally a specified "minimum energy" portion of
this capacity will be scheduled in the day-ahead market to provide energy,
either through the PX or a bilateral contract. This auction has the following
features:
[] The capacity payments would be capped to mitigate market power, recognizing
that in most cases only one or two suppliers would be able to provide the
needed capacity in each LPA. The caps would be related to actual costs of
supplying generation in each LPA to provide a locational price signal for
new entry. Although the caps should be high enough provide incentive to
resources to show up for this auction, there will be a need for standing
bids and availability standards to ensure that the resources would always
be available when needed. [UNRESOLVED: ACTUAL FORMULA FOR THESE CAPS NEEDS
TO BE DETERMINED.]
[] Substantial penalties would apply to resources that sold capacity in this
auction and failed to deliver.
[] The minimum energy requirement would have to be scheduled day-ahead against
load within the same LPA, and the resource could not submit DEC bids on
this energy schedule. The minimum energy could be scheduled through the
unit owner's choice of bilateral contract or by being a price-taker in the
PX market.
[] The minimum energy requirement would be defined by the nomogram
corresponding to the system conditions anticipated to exist on the relevant
Trading Day. More specifically, the minimum energy would be adequate to
maintain system reliability under N-1 outage conditions, relative to the
steady state conditions known at the time of the LRS auction.
[] The additional capacity procured above the minimum energy requirement would
be determined by the applicable local reliability criteria. This additional
capacity would not have to be unloaded in real time. It could be scheduled
to provide energy, or could bid A/S or Supplemental Energy. If it is
selected for A/S it would forfeit the local reliability (LR) payment for
the amount of capacity sold for A/S.
[] No price caps or bid caps would apply to the energy bids associated with
this capacity (except, of course, for any caps that are in effect on a
system-wide basis at the time). However, the resource would be required to
submit an energy bid along with its LRS capacity bid. This energy bid would
apply to energy dispatched out of the additional LRS capacity that is not
scheduled in day-ahead, no matter which market that capacity appeared in.
This allows the resource to submit the additional LRS capacity to the A/S
or Supplemental Energy markets, as long as its energy bids for this amount
of capacity are not different from bids submitted to the LRS auction. For
any additional capacity the unit wishes to offer beyond the total LRS
capacity, there would be no caps other than system-wide caps in effect at
the time.
31
[] The allocation of the cost of the LRS procurement has not yet been
determined. The options are to allocate the cost to the following:
[] All load within the LPA
[] All load within a larger area (ranging from PTO territory to
system-wide)
[] The PTO.
[] AN OPEN ISSUE AT THIS TIME IS WHETHER THERE WOULD BE AN ADDITIONAL LRS
PROCUREMENT ON THE TRADING DAY (HOURLY, OR PERHAPS TWO OR THREE DAY-OF
MARKETS), TO MEET NEEDS THAT ARISE AFTER THE 2DA PROCUREMENT DUE TO LINE
DE-RATINGS, OUTAGES, OR LOAD FORECAST REVISIONS.
6.5.2 DESIGN OF FTRS Under this proposal, FTRs will retain many of the
properties they have today. In particular, they will be defined for specific
interfaces. They will earn both day-ahead and hour-ahead usage revenues. They
will have scheduling priority when used with day-ahead schedules, and they will
not be required for scheduling. Also, as is the case today, there will be no
position limits and the current reporting and monitoring provisions will be
retained. The major new features are as follows:
[] The total amount of FTRs auctioned would be "100 percent". This is defined
as the difference between the WSCC non-simultaneous path rating (where it
exists) and the amount of reserved ETC capacity. Where no WSCC rating
exists (i.e., for new LPAs to be created), the ISO would develop ratings to
be used for FTR allocation and for CM in general. The question of how to
allocate ETC rights to these new paths has yet to be addressed.
[] A long-term (tentatively three-year) auction would release 50% of this
amount. A short-term (monthly) auction would release an amount equal to the
difference between the initial 50% and the minimum hourly value of [ATC -
ETC] for the month, based on a forecast of ATC for the month. The remainder
would be reserved for the adjustment bid market.
[] Because existing FTRs expire on March 31, 2001 and CMR is unlikely to be
implemented by then, the next auction of FTRs would be applicable for only
9 months (to December 31, 2001). The first long-term auction would take
place in fall of 2001 and the results would be effective January 1, 2002.
[] Scheduling priority of FTRs would expire after the close of the day-ahead
market, as they do today.
[] Allocation of FTR auction revenues and congestion usage charge revenues
obtained from New Firm Use (NFU) capacity in excess of the amount of FTRs
remains to be determined. The options for allocation of these revenues are
as follows:
[] The PTOs, as is the case today
[] A path-specific transmission upgrade fund
[] Loads within the congested LPA, to offset other locational cost
impacts such as the cost of LRS procurement.
[] The question of how to create new LPAs in the middle of a long-term FTR
auction cycle is still being considered. Two important and somewhat
conflicting principles have been identified, but in some instances it may
not be possible to fully respect both. These principles are:
[] The FTR holder should not have to purchase additional new FTRs in
order to maintain the same congestion hedge as before the new LPA was
created.
32
[] We should not deviate from the underlying FTR model. In particular,
when a new LPA is created, there should be no deviation from the 50%
level of the long-term auction and the amount of ATC remaining for the
monthly auctions and daily CM.
6.6 TIMELINE OF MARKET ACTIVITIES
The following table presents the elements discussed above, in the
sequence in which they would occur. It also identifies some of the information
the ISO would need to provide to the market to make these activities workable.
WAY AHEAD OF TRADING DAY
- --------------------------------------------------------------------------------
Inter-LPA Interface Information ISO publishes market information on
all Inter-LPA pathways and inter-ties
that will be managed in forward
markets. This information will change
infrequently, perhaps seasonally, and
certainly when there are permanent
changes to facilities or network
configuration. Clearances (i.e.,
planned outages for maintenance)
could dictate frequent changes, but
these will be noticed to the market
on a daily basis.
FTR Market ISO conducts long-term (yearly or
multi-year) and medium-term (monthly)
FTR auctions for pre-specified shares
of [path rating - reserved ETC
capacity] for each Inter-LPA
interface.
2 DAYS AHEAD OF TRADING DAY
By 12:00 PM approx. (PRECISE TIMINGS ISO publishes forecasts of load by
OF 2DA ACTIVITIES TO BE DETERMINED) LPA, local reliability capacity and
energy requirements, ATC for each
Inter-LPA interface, maximum
generation limits for clearances on
gen-ties, GMMs and shift factors.
By 3:00 PM approx. ISO receives bids for local
reliability (LR) capacity and energy,
and conducts procurement.
3:00 to 4:00 PM ISO conducts LR procurement and
publishes results, specifying for
each unit selected, the minimum level
of energy to be scheduled in DA
market and minimum additional
capacity to be available for
contingencies (must be scheduled, or
win in A/S market, or bid into
Imbalance Energy).
DAY-AHEAD MARKET
By 5:00 AM Any changes in system conditions must
be made public; system conditions as
announced at this time will be used
for running DA market, even if new
changes take place in the mean time.
Changes occurring after 5 AM will be
published after running the DA market
and will be used in running the HA
markets.
6:00 to 6:30 AM ISO receives SC load forecasts;
aggregates Direct Access Customer
(DAC) loads; sends aggregated DAC
loads to UDCs.
7:00 AM SCs submit nominations for scheduling
ETCs, and register all FTR scheduling
assignments that will be applicable
in the day's DA markets.
By 10:00 AM ISO receives & validates preferred
energy schedules & adjustment bids,
self-provided A/S schedules, & A/S
bids from all SCs. Validation
includes scheduling requirements on
LRS resources and any applicable
generation limits due to gen-tie
clearances.
10:00 to 11:00 AM - ISO runs CONG using simplified
network model for Inter-LPA CM
- ISO runs CONG using full network
model run to check for Intra-LPA
violations
- Determines A/S deferment to HA
(total A/S requirements determined
based on
33
ISO load forecast), and runs DA
A/S market
- Publishes adjusted energy
schedules, A/S schedules & MCPs,
estimated congestion charges, and
unused adjustment bids on a
voluntary basis to facilitate
inter-SC trading to relieve
congestion. NOTE: schedules will be
Final at this time if CONG finds no
congestion.
By 12:00 PM If 10 AM schedules had congestion,
ISO receives and validates revised
preferred energy schedules and
adjustment bids, self-provided A/S
schedules, and A/S bids from SCs.
12:00 PM to 1:00 PM - ISO runs CONG
- Determines A/S deferment to HA and
runs DA A/S market - Runs auction
for Recallable Transmission Service
(RTS)
- Publishes final DA energy
schedules, A/S schedules & MCPs,
congestion charges, and RTS
allocations and prices. The results
of the 1st or 2nd iteration would
be used for final DA schedules,
depending on which had lower total
cost of congestion.
1:00 PM Control Area Check-out - to verify
agreement on inter-tie ATCs
HOUR AHEAD MARKET
Time to be determined ISO runs additional LRS procurement
to meet needs due to changes in
system conditions or load forecast
(may be done intra-day but not
necessarily every hour).
By 4 hours ahead approx. ISO publishes any revisions to ATCs
and load forecast.
By 3 hours ahead approx. SCs submit nominations for HA
scheduling of ETCs.
By 2 hours ahead ISO receives and validates energy
schedules and adjustment bids,
self-provided A/S schedules, and A/S
bids.
2 hrs to 1 hr ahead - ISO runs CONG
- Runs A/S market
- Runs Recallable Transmission
Service (RTS)
- Publishes final HA energy
schedules, A/S schedules and MCPs,
congestion charges, GMMs, and RTS
allocations & charges.
REAL-TIME - PRIOR TO OPERATING HOUR
By 60 min ahead of operating hour ISO pre-dispatches needed Replacement
Reserve units.
By 45 min ahead Receives supplemental energy bids for
real-time market, and creates BEEP
stack using supplemental energy,
adjustment, and A/S energy bids
(excluding Regulation)
By 20 min ahead Accepts ETC schedules not already
scheduled in DA or HA markets (for
those ETC holders who have not joined
the ISO and adopted ISO scheduling
protocols).
REAL-TIME - WITHIN OPERATING HOUR
By 10 minutes ahead of operating instant ISO receives telemetry data on actual
system load and MW generation, and
runs OPF to determine optimal
dispatch for imbalance energy and
Inter-LPA congestion.
10 min. ahead to operating instant ISO dispatches resources per OPF
output to meet imbalance energy and
Inter-LPA needs, and dispatches other
local resources as needed for
intra-LPA constraints.
34
7. THE LONG-FORWARD MARKET
7.1 LPA DEFINITION AND CREATION
7.1.1 INTRODUCTION - As noted in Section 1.3.1, a significant
deficiency in the ISO's existing CM design is the lack of locational price
signals. This deficiency is in large part related to the fact that the current
CM design allocates and prices different transmission facilities in the forward
and real-time markets. Thus, the main thrust of our redesign efforts must be to
establish consistency between the forward and real-time markets. This will
require that the tools and methods used for real-time CM must match the LPAs
used in the forward markets. Absent consistency between the pricing and
allocation of transmission between the real-time and forward markets, it will be
impossible for the ISO to establish clear and proper locational price signals
that will encourage the efficient use of the transmission system and provide the
necessary incentives for long-term generation investment.
This section outlines a proposal that we believe will address
the deficiencies in the ISO's existing Zonal methodology and will establish
meaningful locational price signals. The basic approach is to construct
Day-Ahead and Hour-Ahead markets that establish forward prices for the same
transmission facilities priced in the real-time market.
7.1.2 LPA DEFINITION The definition of LPAs is the cornerstone of an
LPA-based Congestion model. In order to ensure that the DA and HA CM processes
price and allocate the relevant transmission facilities, LPAs must be defined in
a manner that is consistent with the characteristics of the transmission grid
and how it is operated. As explained in Section 5, the bulk power transmission
system in California is comprised of long transmission lines that interconnect
concentrated Load pockets in San Francisco, Los Angeles, Sacramento, and San
Diego. These Load pockets also represent the areas for which the operators have
developed detailed Nomograms that guide their real-time operation of the system.
7.1.2.1 DEFINING LPAS USING NOMOGRAMS Since Nomograms are the primary
tool used by operators to run the system, it is logical that Nomograms should be
used to define any new LPAs. As a consequence, the new LPAs should match the
LRAs that the ISO currently uses in real-time operations. Another important
consequence of using Nomograms to define LPAs it that it will ensure that there
is no residual Intra-LPA Congestion and therefore no gaming opportunities
between the Inter-LPA and Intra-LPA markets, as exists today (i.e., it ensures
that Schedules that are feasible in the forward markets are also feasible in
real-time, except for unpredictable events and forecast errors).
7.1.3 CREATING NEW LPAS As important as defining LPAs, the methodology
for creating new LPAs is critical to ensuring that the ISO continues to send
meaningful locational price signals. To the extent that the ISO is not vigilant
in updating the Nomograms to accurately reflect changes in system conditions and
the network topology, we may create inconsistencies between the pricing of
resources in the forward and real-time markets and thereby opportunities for
gaming.
There are a number of important factors that must be considered when
determining whether to create a new LPA. As a general rule, the ISO must
evaluate whether changes to its operating nomograms, and therefore the number
and configuration of LPAs, is required whenever the nature of the transmission
system changes as a result of any of the following:
o Transmission facility upgrades or expansions
o Addition of new Generation;
35
o Significant changes in consumption (Load) patterns
o Changes to the External System
o Changes in Reliability Operating Criteria
However, there are also other important factors that should be
considered.
7.1.3.1 LPA-CREATION CRITERIA - Based on a Nomogram-driven LPA
definition, there are certain tools available to the ISO and Market Participants
that may assist in determining when it is appropriate to create a new LPA. At
this time, we have not concluded that all or any of these tools are appropriate
or necessary for guiding LPA creation decisions. Ultimately, whatever method is
chosen, the methodology must reflect operational realities and be workable from
a Market Participant standpoint (i.e., the proposal must ensure that LPAs are
stable and their creation predictable). Therefore, it is critical that the ISO
work with Market Participants to develop an acceptable LPA creation criteria.
7.1.3.1.1 COMMERCIAL SIGNIFICANCE - If Congestion on transmission
interfaces within an LPA is relatively frequent and its associated cost over a
certain time period exceeds a specified threshold, the ISO could make a
determination that a new LPA should be created. There are a variety of options
for defining "Commercial Significance":
OPTION 1 - THE EXISTING ZONE CREATION CRITERIA - The ISO's current Zone
creation criteria provides that if Intra-Zonal Congestion costs exceed a
specific threshold, the ISO will determine whether it is appropriate to create a
new Congestion Zone.23 We note that the ISO's current Zone creation criteria has
been the subject of much debate. Specifically, Market Participants have asserted
that the 5% criterion is arbitrary and that the "workable competition" criterion
is unworkable.24
While the ISO continues to believe that the existing Zone creation
criteria was appropriate for start-up due to the lack of operational experience,
we believe reexamination of the specific criterion is appropriate. The ISO is in
the process of further studying the appropriateness of the 5% criterion and
intends to release the results of that study in the near future. However,
recognizing the possible limitations of the existing criterion, we nonetheless
believe that application of the criterion for purposes of LPA validation may be
useful.
As detailed in Appendix C, which will be provided to Market
Participants on July 21, if the 5% criterion was applied to existing Intra-Zonal
transmission paths, the following new LPAs would be created:
1. Humboldt,
2. San Francisco,
3. Greater Bay Area
4. North Bay (Geysers)
5. Los Angeles - South Bay (under evaluation)
- ----------
23 The ISO Tariff provides that if Intra-Zonal Congestion costs exceed five
percent of the capacity costs of the associated transmission path and there
is workable competition on each side of the path, the ISO may create a new
Congestion Zone (ISO Tariff Section 7.2.7.2).
24 On December 1, 1999, the ISO submitted a study to FERC on the
appropriateness of the 5% criterion. FERC has not yet acted upon that study.
The ISO is in the process of further studying the appropriateness of the 5%
criterion and intends to release the results of that study in the near
future.
36
6. San Diego.
These LPAs would be in addition to the existing LPAs, NP15, ZP26 and
SP15. Not surprisingly, the new LPAs coincide with the existing LRAs (as defined
by Nomograms).25
7.1.3.1.2 LOCATIONAL PRICE DISPERSION - Appendix A to this
recommendations package includes a Locational Price Dispersion (LPD) Study. The
purpose of the LPD study is to analyze, under certain conditions of Congestion,
the dispersion of locational prices throughout the ISO Control Area. Given that
the premise of the existing Zonal structure is that Congestion within Zones is
small and infrequent, the ISO sought, through the LPD study, to determine the
following:
1) If the locational prices within a Zone are all within a given tolerance
of the average Zonal price
2) If the existing Zone boundaries are at all similar to the boundaries
established by the distinct price differences produced by the study.
The objective of this study is to provide additional information that
will either confirm the new LPA configuration, or provide further evidence that
modification to the proposed LPAs may be necessary.
One possible method for determining the need for a new LPA on
a going forward basis is for the ISO to periodically perform a similar or
modified price dispersion study to determine if prices within a LPA are
relatively uniform. A comparison of prices at each node within a LPA will ensure
that the LPA boundaries reflect the most binding constraints. Under this method,
if the locational price dispersion exceeds a threshold, the ISO would make a
determination on the need to create additional LPAs.
7.1.3.1.3 HIFT FACTOR ANALYSIS - Shift Factors are numerical
representations that describe the physical power flow changes on Inter-LPA
transmission lines (and tie lines to areas external to the Control Area) caused
by an injection at a bus in an LPA. Shift Factors are defined entirely by the
topological characteristics of the grid and impedance of the lines comprising
the system. To the extent that LPAs are defined per discrete Nomograms that
represent the operational constraints of the system in a given area, it is
reasonable to assume that the Shift Factors for resources located within that
area are close to one another.
Based on that assumption, the ISO could perform periodic monitoring of
the dispersion of Shift Factors within a LPA. If the Shift Factor dispersion
exceeds a certain threshold, the ISO could make a determination on the need to
create additional LPAs. The ISO is in the process of developing a network-based
LPA creation study using Generation Shift Factors. The results of this study
will be provided at a later time.
- ----------
25 At this time, we believe that the Fresno area would also need to be a
LRA/LPA.
37
7.1.4 OTHER OPTIONS CONSIDERED - Certain options that were considered
by the ISO but not selected are outlined below. We have attempted to briefly
identify the option and provide our reason for not selecting the option.
o PRICING TRANSMISSION BETWEEN BUSES OR NODES. This option was
rejected because real-time operations are not described
accurately by constraints on transmission between individual
buses. The constraints derived from requirements for
stability, security, and voltage support are binding over
areas with limited energy imports over high-voltage
branch-groups of transmission lines. These "local reliability
areas" reflect the finest spatial differentiation that is
meaningful and useful in operations.
o PRICING TRANSMISSION BETWEEN AREAS LARGER THAN LOCAL
RELIABILITY AREAS. This option was rejected because it does
not match the way congestion is managed in real-time
operations. In particular, it ignores relevant constraints at
the LRA level and therefore does not price some scarce
resources.
o JOINT OPTIMIZATION OF TRANSMISSION ALLOCATION AND DISPATCH OF
ENERGY GENERATION, as done in the Eastern Interconnection by
NYISO, or PJM's similar dispatch-based pricing in which at
each node the price is the highest marginal cost among the
generator(s) dispatched there. This option was rejected
because it bundles transmission and energy into nodal prices
that hide where transmission constraints are binding and which
ones (even knowing the shift factors, nodal prices are
insufficient to identify the usage charges on transmission
lines or branch groups affected by flowgate constraints).
There are also substantial disadvantages in terms of
incentives. The new design accomplishes all intended purposes
of the Congestion Management reform project without any
evident need to violate the "market separation" principle of
the California system. Without any compensating advantages
there was no reason to re-bundle transmission and energy, nor
to intrude into the energy markets of the SCs, nor to assume
scheduling and dispatch authority. The new design interprets
the scope of the ISO's forward markets as comprising
allocation of transmission capacity via FTRs and its DA/HA
Congestion Management process, and procurement auctions for
ancillary services not self-provided by SCs.
7.1.5 OPEN ISSUES - While we are convinced that a Nomogram-based
approach to LPA definition is workable and accurate, we recognize that there are
a number of outstanding issues regarding LPA creation on a going forward basis.
Certain of these issues include:
o The need to verify that the Shift Factors for resources within a given
LPA are close to one another.
o The need to appropriately define when Congestion is "commercially
significant".
o The need to determine the threshold triggers for both the Shift Factor
and LPD analysis.
o The required coordination between LPA creation and the release and
auction of FTRs.
38
7.2 FIRM TRANSMISSION RIGHTS
Consistent with the intent of the original California market design,
one of the objectives of the Congestion Management reform initiative is to
facilitate decentralized decision making and to provide Scheduling Coordinators
(SCs) with the tools necessary to actively participate in the forward markets.
Firm Transmission Rights (FTRs) are such a tool. FTRs provide SCs with an
ability to manage their transmission requirements in the forward market and
thereby reduce the need for the ISO to manage transmission Congestion both in
the forward markets and in real time. As explained earlier, by placing a greater
emphasis on forward-market management by SCs, the ISO hopes to reduce the need
for it to take actions in real-time that may be contrary to the forward-market
positions of Market Participants and thereby reduce the complexity of real time
operations and improve reliability. Therefore, a primary objective of this
redesign effort has been focused on ways to increase the number of FTRs
available to SCs.
7.2.1 BACKGROUND ON CURRENT FTR PRODUCT The ISO's existing FTRs are
both a financial and a physical tool. The purchaser of an FTR obtains (for every
delivery hour) Day-Ahead scheduling priority and a financial payment equal to a
portion of the ISO's Day-Ahead and Hour-Ahead Usage Charge revenues (thus
providing a hedge against the Usage Charges associated with that portion of its
Schedule for which it has FTRs). If the ISO is unable to relieve the Day-Ahead
Inter-Zonal Congestion using Adjustment Bids, the ISO will allocate Day-Ahead
Inter-Zonal transmission capacity according to the following priority:
1) First to Market Participants that are using Existing Transmission
Contracts (ETCs)
2) FTR Holders that have indicated to the ISO that they wish to
exercise their scheduling priority option
3) The ISO will allocate any remaining transmission capacity to
remaining Market Participants pro-rata
The scheduling priority of FTR Holders does not apply in the Hour-Ahead
market or in the real-time dispatch and operation of the ISO Controlled Grid.
The priority scheduling rights of FTR Holders will remain constant to
the extent that the total scheduling rights of FTR Holders does not exceed the
total interface scheduling capability after ETCs have been taken into account.
In the case where the total interface scheduling capability is less than the
total scheduling capability, after accounting for ETCs, the financial
transmission entitlements for the available transmission capacity will be
allocated to FTR Holders pro-rata, and the scheduling capability will be
allocated pro rata to the SCs exercising the scheduling priority of FTRs.
7.2.2 INTRODUCTION TO PROPOSED CHANGE We propose to retain both the
financial and physical characteristics of the existing FTRs. However, as noted
above, one objective of this redesign initiative is to ensure that SCs have a
greater ability to self-manage their affairs in the forward market. Therefore,
we propose that the ISO release 100% of ATC as FTRs. Moreover, consistent with
the direction provided by both FERC and Market Participants, the ISO proposes to
auction long-term (3-yr.) FTRs, as well as monthly FTRs. In addition, as
discussed further in Section 8, in order to provide A/S providers with an
opportunity to compete for transmission capacity we propose that FTRs be
available to import A/S over the ties.
Significantly, as explained in Section 11, we also believe that the
ISO's recommended approach is consistent with propose design of the markets in
neighboring regions. While we believe that this proposal is a significant step
in the right direction, there are a large number of challenging unresolved
issues that must be addressed by the ISO and Market Participants before this CMR
package is complete.
39
7.2.2.1 100% RELEASE - We propose to release an amount of FTRs equal to
one hundred percent of New Firm Use capacity (i.e., ATC). The 100% would be
based on the difference between the applicable WSCC path rating and the
allocated ETC rights. Fifty percent (50%) of this amount would be auctioned on a
long-term basis, while most of the remaining capacity would be auctioned on a
monthly basis.
7.2.2.2 FTR TERM AND AUCTION We propose that FTRs be auctioned on a
three-year and monthly basis. The quantity to be auctioned on a three-year basis
would be determined from historical data, while the monthly quantity would be
determined based on forecasted availability reflecting, among other things,
scheduled outages and seasonal factors.
For example, let us assume Inter-Zonal interface AB has a path rating
(or a total transfer capability when there is no path rating) of 1000MW and a
ETC level of 400MW at the 1000MW capability. Under the proposed design, the ISO
would auction three-year FTRs based on 50% of the available ATC, which, in the
above example would be:
1000MW TTC - 400MW ETC = 600MW ATC / 2 = 300MW
On monthly basis, all (100%) of the remaining capacity would be
auctioned based on forecasted system conditions. Continuing with the above
example, assume we have for month X a minimum monthly TTC of 900MW that is based
on a forecast of planned outages/derates, an ETC level of 350MW at the 900MW TTC
and long term FTRs of 300MW. We propose to auction 15 days before the beginning
of month X an amount of FTRs equal to:
900MW of TTC - (350MW of ETC + 300MW of 3-year FTRs) = 250MW of Monthly
FTRs
For the remainder of the month, where the TTC is above 900MW but less
than 1000MW, the ISO will include the residual NFU capacity in the Adjustment
Bid market. For example, if the TTC in an hour is 950 MW and the corresponding
ETC volume is 375 MW, the residual NFU capacity made available in the Adjustment
Bid market will be:
950MW - (375MW + 300MW + 250MW) = 25MW
7.2.3 IMPACT OF AND ISSUES REGARDING PROPOSED CHANGES - The changes
proposed above will have certain impacts on the way SCs obtain and use FTRs.
Outlined below are some of the more significant implications for the new FTR
design.
7.2.3.1 FTRS UNDER A LOOPED NETWORK MODEL - Because the ISO is
proposing to use a looped network model (as necessitated by the creation of
additional LPAs), SCs will now be required to procure FTRs on a somewhat
different basis. While a looped LPA configuration does not require the redesign
of FTRs or the FTR auction, Market Participants will need to use Power
Transmission Distribution Coefficients (PTDCs or Shift Factors) to determine the
required amount and combination of FTRs necessary to hedge against Usage
Charges. This is because in a looped model, power flows over various
transmission paths based on the topology of the transmission system. Therefore,
it is no longer adequate to specify or acquire FTRs over a single path to
schedule from one LPA to a contiguous LPA. The reality is that power will flow
over multiple paths to get from one LPA to another. In order to facilitate the
use and acquisition of the new FTRs, the ISO will publish PTDCs that are
consistent with the network model used for Congestion Management.26 Market
Participants will thus have an ability to determine the number of FTRs they
require to accommodate their schedules.
- ----------
26 Currently, the CM network model is updated seasonally. A looped network
model with external equivalents will likely require more frequent updates.
40
7.2.3.2 FTR MONITORING - The ISO does not propose to impose position
limits on FTR ownership, but does propose to continue with all existing
conditions and requirements for the sale or transfer of FTRs.
When the ISO first auctioned FTRs in November of 1999, a number of
Market Participants and members of the ISO Governing Board were concerned that
by auctioning 99.5% of ATC, certain entities would be able to obtain a
significant share of the FTRs over a given path and thereby exercise market
power and control over that path. At that time, the Board considered imposing
limits on the amount of FTRs one entity (and its affiliates) could own over a
path. The Board ultimately decided not to impose position limits based in part
on the limited initial release of FTRs. However, the Board did authorize ISO
management to monitor the FTR Market and require that all FTR Holders identify
all affiliated entities that are also FTR Holders or Market Participants.
Finally, in order to ensure the proper transfer of FTR scheduling priority
rights, the ISO requires that both the buyer and seller of an FTR register the
sale or transfer with the ISO.
Although we are now proposing to release 100% of ATC as FTRs, we
believe that there is no need to impose position limits. We believe that a
significant number of FTRs will be available on a monthly basis under this
proposal and therefore that it will be difficult for any one entity to control
access or the price over a given interface. However, in order to satisfy the
ISO's continuing monitoring obligation, we propose to retain the existing
registration and reporting requirements.
7.2.3.3 FTRS AND LPA CHANGES - As discussed in Section 6.1, the
existing LPA configuration will be updated as needed to reflect changes in
transmission system operations and configuration. When this occurs there may be
a corresponding impact on existing FTRs. The ISO Tariff currently provides that
the ISO will not create any new Congestion Zones prior to the expiration date of
any outstanding FTRs and that any additional FTRs auctioned as a result of
changes in the ISO's defined Inter-Zonal Interfaces shall not affect existing
FTRs.27 The ISO will use best efforts to hold all existing long-term FTRs
harmless from LPA changes. However, in light of our proposal to issue three-year
FTRs (and, ultimately, perhaps longer-term FTRs), the ISO and Market
Participants need to develop an approach whereby the ISO can honor existing FTRs
to the greatest extent possible, while still updating the existing LPA
configuration to reflect changed operating conditions. The next subsection
outlines two approaches. We urge Market Participants to identify alternative
approaches.
7.2.3.3.1 OPTION 1 FOR HONORING FTRS AND MODIFYING LPAS - One approach
whereby the ISO could honor existing FTRs and still modify, as necessary, the
LPA configuration of the system, is to provide existing FTR Holders with an
automatic entitlement to FTRs over a new Inter-LPA Interface. In general, under
this proposed methodology the ISO would allocate new FTRs pro rata to all
existing FTR Holders up to the total available amount. Any additional FTRs would
become available in the monthly auctions.
For example, assume that X MW of long-term FTRs have been sold on an
Inter-Zonal Interface from LPA A to LPA B, and vice versa, and that later LPA B
is divided into two distinct LPAs: B1 and B2. There are two likely
configurations (shown in Figure 1):
RADIAL CONFIGURATION (CASE 1): Assume that a total of Y MW is available
for long-term FTRs from B1 to B2. All X MW of FTRs from A to B1, and the lower
of X or Y MW of FTRs from B1 to B2 will be distributed pro rata as long-term
FTRs to the previous holders of long-term FTRs from A to B. Similarly, all X MW
of FTRs from B1 to A, and the lower of X or Y MW of FTRs from B2 to B1 will be
distributed pro rata as long-term FTRs to the previous holders of long-term FTRs
from B to A. Any remaining long-term FTRs from B1 to B2, and from B2 to B1 will
be auctioned off.
- ----------
27 ISO Tariff Sections 9.2.2.1 and 9.2.2.2.
41
LOOP CONFIGURATION (CASE 2): Assume that the original X MW of long-term
FTRs from A to B is comprised of X1 MW from A to B1 and X2 MW from A to B2, and
a total of Y MW is available for long-term FTRs from B1 to B2 and vice versa.
All X1 MW of FTRs from A to B1, all X2 MW of FTRs from A to B2, and as much as
the lower of X1 or Y MW of FTRs from B1 to B2, and the lower of X2 or Y MW of
FTRs from B2 to B1 will be distributed pro rata as long-term FTRs to the
previous holders of long-term FTRs from A to B. Similarly, all X1 MW of FTRs
from B1 to A, all X2 MW of FTRs from B2 to A, and as much as the lower of X2 or
Y MW of FTRs from B1 to B2, and the lower of X1 or Y MW of FTRs from B2 to B1
will be distributed pro rata as long-term FTRs to the previous holders of
long-term FTRs from B to A. Any remaining long-term FTRs from B1 to B2, and from
B2 to B1 will be auctioned off.
[GRAPHIC OMITTED]
FIGURE 1. LPA Division
In the case of LPA merging, the FTRs between the former distinct LPAs
will be retired.
7.2.3.3.2 OPTION 2 FOR HONORING FTRS AND MODIFYING LPAS - Another
approach whereby the ISO could honor existing FTRs and still modify, as
necessary, the LPA configuration of the system, is to provide existing FTR
Holders with a "right of first refusal" to purchase FTRs over a new interface.
Under this approach, the ISO would provide that existing FTR Holders whose FTRs
are impacted by the creation of a new LPA have the right to purchase (at the
applicable clearing price) an amount of FTRs over the new interface necessary
for them to maintain their existing ability to schedule from one LPA to another.
42
7.2.4 OTHER OPTIONS CONSIDERED - Certain options that were considered
by the ISO but not selected are outlined below. We have attempted to briefly
identify the option and provide our reason for not selecting the option.
o REQUIRE FTRS FOR SCHEDULING - This proposal is similar to implementing a
full physical rights model whereby the ISO is effectively removed from the
forward transmission market. While this approach is comparable to that
being considered in neighboring systems, we believe that it would be
difficult to foster meaningful and transparent locational price signals
under this approach. We therefore did not consider this proposal since it
is inconsistent with the objective of creating or enhancing locational
price signals.
o FINANCIAL RIGHTS TO EXPIRE AFTER THE DA MARKET - This feature was proposed
in order to facilitate the creation of a deep and liquid market in FTRs.
The basis of the proposal is that if FTR Holders know that their financial
rights will expire after the DA market closes if their FTR goes unused,
they will have an incentive to sell their FTR in a secondary market if they
do not intend to schedule with it. We did not select this option because we
are confident that with 100% release and a monthly market for FTRs that
there will be a liquid market for FTRs.
o NON-CONTIGUOUS, LPA-TO-LPA FTRS - This proposal basically provides for
point-to-point FTRs. This option was not selected because it is
inconsistent with the existing definition of FTRs and ETC rights and is
more complicated to implement. Moreover, we believe that our proposal will
permit SCs to obtain equivalent protection from Usage Charges and
scheduling priority to that proposed here.
7.2.5 OPEN ISSUES - There are obviously a number of issues that must be
addressed before this proposal can be implemented. Listed below are certain of
these issues. We urge Market Participants to identify additional issues and to
propose solutions to those issues identified below.
o How to auction long-term FTRs while still changing, as necessary, LPA
configuration
o Should there be an activity rule that would provide that FTRs not scheduled
as part of an SC's Initial Preferred Schedule cannot then be scheduled in
that SC's Revised Preferred Schedule?
o How to define the TTC of a path
o Use of the WSCC non-simultaneous path rating
o How to determine transfer capabilities and calculate TTC for paths not
rated by WSCC
o How to allocate FTR auction and Usage Charge revenues
o FTR Auction Design could be enhanced by introducing "packaged bidding"
(i.e. bid on PV and COI as one item simultaneously instead of two
individual items). Existing software can accommodate this with minor
changes. Is this an attractive option?
o How to accomplish ETC to FTR conversions under the new approach?
o Implementation difficulty in defining/tracking ETC rights under the new
approach?
43
o How often should Shift Factors be updated and posted? (i.e., what is the
appropriate balance between the need to update Shift Factors to reflect
operational reality versus the market's desire for certainty and ex ante
price certainty?)
7.3 LOCAL RELIABILITY SERVICE
7.3.1 INTRODUCTION - Another feature of the ISO's Long-Forward Market
is LRS procurement. A central issue in this redesign effort is whether to reform
the existing approach (the RMR Generation paradigm) to satisfy the ISO's local
reliability requirements. The reason that LRS is a key element of this CMR
recommendations package is the pivotal role the LRAs play in determining the
actual Operating Procedures and Nomograms that are the basis of the new LPAs.
Why are LRAs so important? The reason lies in the fact that it is in these
transmission-constrained areas that the usual thermal constraints on line
capacities must be augmented by other constraints that are often binding. These
include stability constraints, N-1 and N-2 security constraints, sufficient
voltage support and reactive power, all of which apply over these local areas.28
It is also in these areas that generation is necessary and therefore measures to
control market power are needed.
We believe that the design outlined below directly addresses the market
power of existing RMR units, since in each LRA the Nomogram specifies explicitly
how the predicted load translates into the required Generating Unit commitments,
minimum and maximum schedules, and options on additional generation to meet
contingencies. We believe that the approach creates clear and strong incentives
for Load-serving entities to reduce the costs of these measures by investing in
more transmission or local generation.
7.3.2 OPERATIONAL ASPECTS OF SATISFYING LOCAL RELIABILITY REQUIREMENTS
- - In the daily operation of the power system, overall system security as well as
local reliability requirements are determined so as to guard against thermal
overloads, angular instability, and voltage instability in the event of credible
contingencies. Based on the accepted WSCC and NERC criteria, a credible
contingency may include the forced (unplanned) outage of a single major element
such as a line, transformer, or on-line generator (N-1 contingency),
simultaneous outage of two major elements (N-2 contingency), and in rare cases,
outage of more than two elements.
Although the state of the art of on-line network security analysis
permits on-line determination of secure operating limits to guard against
thermal overloads in the event of credible contingencies, it does not yet have
the capability for on-line determination of secure operating limits to guard
against angular and voltage instability due to excessive computational
requirements. As described in Section 5, a large number of off-line studies are
therefore conducted (over a period of months or years) for different system
conditions, and the secure operating limits for each system condition are
compiled in the form of Operating Procedures and Nomograms. As new situations
arise, these Operating Procedures and Nomograms are updated.
For local reliability, the operating limits may involve limits on net
import (transmission line flow) into the local area, minimum amount of local
generation, maximum allowable amount of local generation, or minimum on-line
local generation capacity. These limits may be a function of the load in the
local area.
- ----------
28 It is worth mentioning that the N-1 and N-2 criteria (and off-line analysis
of thermal, angular, and voltage security) are also used for system-wide
determination of secure operating points (such as the Southern California
Import Transmission limit, SCIT). However, since these operating limits
encompass a wide competitive area, they should be handled relying on the
competitive market rather than RMR Units or an alternative approach.
44
For a given hour, the Nomogram that best matches the actual system condition is
used to identify the safe operating limits. In the forward market, the ISO must
ensure that adequate resources are scheduled or otherwise available to enable
the ISO to meet local reliability conditions in actual operation, based on its
forecast of system conditions. For each LRA, only a very limited number of
resources are able to provide the required LRS. In other words, the local
reliability service is seldom amenable to procurement through a competitive
market.
7.3.3 THE EXISTING RMR APPROACH - At present the ISO relies primarily
on the RMR contracts to satisfy local reliability requirements. The RMR units
are scheduled in the forward market to ensure that at least the minimum amount
of local generation capacity is on-line and that the minimum amount of Energy is
scheduled locally. In many cases, satisfying these requirements may also
alleviate or reduce potential Congestion into, out-of, or within the local
reliability area. To the extent that an unpredictable need for additional RMR
Generation arises in real-time, the ISO can call on the unloaded capacity of the
RMR Units (or have a fast-start RMR Unit start up).
At present, there are two types of RMR Units, "condition-1" RMR units
and "condition -2" RMR units. "Condition-1" RMR Units can run efficiently and
compete in the broader (system-wide) Energy, Ancillary Service, and real-time
markets. "Condition-2" RMR Units ostensibly cannot recover enough of their costs
from market revenues to support their continued operation. The RMR Units are
paid an up front payment based on the forecast of the difference between their
going forward annual fixed costs and their projected market revenues, or a
negotiated payment that may be informed by, but not necessarily set by, such
estimate. For Energy payments in the forward market they can elect to receive
the market clearing price or the RMR Contract price (variable cost).
7.3.4 ALTERNATIVE OPTIONS FOR SATISFYING LOCAL RELIABILITY REQUIREMENTS
- - As noted above, a significant issue in this redesign initiative is whether and
how to eliminate the existing RMR Contracts. Over the past several months
several options have been proposed for transitioning away from the existing RMR
paradigm. As we move forward in this process, an important consideration is
whether there are sufficient rewards, in light of the risk, for moving away from
the current RMR Contract structure. The following section outlines three options
to satisfy local reliability requirements. Option 1 is the present RMR approach.
Option 2 procures needed resources on a daily basis and pays a capacity payment
for the required amount of local reliability capacity. Option 3 does not provide
for any up-front capacity payment, but simply provide an Energy payment for the
required amount of Energy.
OPTION 1 - EXISTING RMR APPROACH - Continue to rely on RMR Generation
to ensure that all local market power is mitigated and that the minimum number
of local reliability resources are committed to provide LRS. If this option is
considered, we may want to reconsider the number of RMR resources we designate
and how RMR-related costs are allocated (i.e., whether RMR-related costs should
continue to be allocated to the applicable PTO or whether such costs should be
born by the Load in the LRA). Option 1 is the only option that would guarantee
fixed cost recovery for those resources presently under Condition 2 RMR
Contracts.
OPTION 2 - TWO-DA LOCAL RELIABILITY SERVICE PROCUREMENT - Based on
ISO's Load forecast, and the forecast of system conditions two days before the
operating day, the Operating Procedures and Nomograms would be used to determine
the secure operating limits for each LRA. The Nomograms would then be used to
determine the minimum amount of local Generation capacity as well as the minimum
amount of local Energy that are needed for each LRA. These minimal quantities
characterize the LRS requirement in each LRA.
45
THE LRS PROCUREMENT METHODOLOGY - The LRS requirements will be
published two days before the operating day, and procured for each LRA, subject
to a bid cap, with the following provisions:
THE LRS CAPACITY PAYMENT - The ISO will procure LRS capacity
from the resources within each LRA. To the extent that there is a sufficient
number of suppliers, the ISO will conduct a competitive "auction" for this
capacity, whereby each resource selected will receive the clearing price in the
capacity auction. If there is not a competitive market for LRS in an LRA, which,
at least initially, is likely the case for most of the LRAs, the ISO will
procure the necessary LRS capacity from the resources within the LRA at capped
prices. The levels of these caps will be different for each LRA, but will be the
same for all resources within an LRA. The LRS provider will be paid for the LRS
capacity only. Any LRS resource whose unloaded LRS capacity is bid and selected
in the A/S markets will offset its LRS capacity payment by the A/S capacity
payment and will therefore not receive the LRS capacity payment for that portion
of its unloaded LRS capacity.
THE CAPACITY AUCTION BID CAP - The ISO has examined a number
of options for determining the level of the bid cap. We have outlined below
certain of those options.
ALTERNATIVE 1 - The bid cap would apply to the minimum
reliability capacity., It would be high enough to permit recovery of incremental
capital and fixed costs of a new generator in the local area compared to
elsewhere in the system, taking into account the estimated utilization factor
for LRS, as well as the estimated opportunity cost associated with the minimum
reliability Energy. Under this option, the level of the cap would be determined
ex ante.
ALTERNATIVE 2 - The bid cap would be set equal to the variable
cost of the highest-cost resource within the LRA. Under this option, the cap
would be known ex ante, but any opportunity or verifiable start-up costs would
be determined ex poste.
At this point in time, assuming that the two-day-ahead LRS option is
adopted, our preference is Alternative 2. While these matters are still under
active consideration, certain possible features of this approach include:
o The cap will apply to the minimum reliability capacity and will be
LRA-specific (but not resource specific)
o The level of the cap ($/MWh) in each LRA will be commensurate with
the variable cost of the most expensive unit needed for LRS in the
LRA, adjusted for fuel prices.
o Any of the unloaded LRS capacity selected in the A/S auctions will
be netted against the LRS capacity payment (i.e., the portion
winning in the A/S capacity market will not receive the LRS
capacity payment, not make the LRS reimbursement for that
portion).
o An uplift will be paid for verifiable start-up costs of the
resource incurred as a result of the ISO's LRS commitment. For
each verifiable start-up cycle, the payment will include a
fraction of the start-up cost based on the ratio of MWh of Energy
from LRS capacity to total MWh generated by the resource during
that cycle.
In addition, we believe that certain hourly adjustment would have to be
made for the "opportunity costs" and "offsetting market profits" associated with
this methodology. Therefore, this approach could include the following, or some
variation thereof:
46
o A reimbursement to the ISO per MWh of LRS capacity awarded, at the
lower of the unit's variable cost or an agreed upon "reference
Energy price" (a default reference Energy price could be the PX
constrained price in the LPA containing the unit).
o An opportunity cost payment to the resource owner per MWh of
minimum LRS Energy pre-dispatched by the ISO, as a rate equal to
the difference, if positive, between the average of A/S capacity
prices for Non-spinning and Replacement Reserves and the
difference between the LRS price and the higher of the reference
Energy price and the resource's variable cost.
THE SCHEDULING REQUIREMENTS - In order to ensure that the necessary
reliability Energy will be available as needed, the following scheduling
requirements will apply to the LRS resources selected in the two day ahead
capacity procurement.
o The LRS provider will be obligated to schedule at least the minimum
reliability Energy in the Day-Ahead market, either in a bilateral contract,
or as a price taker in the PX market.
o The LRS provider is prohibited from submitting an Adjustment Bid for the
minimum reliability Energy portion of its Schedule in the Day-Ahead market
and must ensure that the ISO's CM will not adjust the LRS provider's
schedule below that level.29 If this portion is ultimately adjusted via the
CM software, the applicable penalties will apply.
o The LRS provider can leave the remaining portion of the LRS capacity
unloaded, schedule it against load in the Day-Ahead market, bid it into the
PX market, the Adjustment Bid market, or the A/S markets, or the Imbalance
Energy market.
o An Energy price curve must be submitted for the LRS capacity above the
Lower Operating Energy (LOE) level of the unit (i.e., the minimum level
below which the unit cannot operate), and up to the total LRS capacity
procured. The LRS provider must submit an Energy price curve regardless of
whether part of the LRS capacity is unloaded or bid into the Day-Ahead
Energy, Congestion Management, or A/S markets. There will be no Energy bid
cap (other than any prevailing system-wide price caps), but the Energy bid
submitted in the Day-Ahead Market for LRS capacity can not be modified in
the subsequent markets.
o For the portion of the Generation capacity above the LRS capacity, the
provider is free to schedule or bid into any market and change the bid
price between markets, with the requirement that the overall Energy bid
curve for the entire capacity of the unit remains monotone non-decreasing.
The LRS capacity and the quantity that must be scheduled as Energy
would be announced for each hour of the operating day and each LRA two days
ahead of the operating day, and several hours in advance of the LRS procurement.
The ISO would also specify if the minimum requirement in each LRA must be
satisfied from specific units or combination of units. The ISO would then
conduct an LRS procurement "auction" before opening its Day-Ahead Market. In
most cases, there may really be no auction since there may be only one specific
unit or owner that can provide the service. In such a case, the "auction" may
"clear" at the LRS bid cap. In other cases, there may be more than one supplier,
and some limited degree of competition may clear the LRS market below the bid
cap. Since the units with LRS capacity at their minimum operating point will
have to be scheduled against Load at least at that level, in
- ----------
29 The LRS provider can assure that the minimum reliability Energy portion of
its Schedule will not be reduced by not submitting an Adjustment Bid for
that portion and by matching that minimum Energy requirement with an Energy
sink (Load or fixed Inter-SC trade) within the same LRA.
47
cases where more than one resource can satisfy the requirements, the LRS auction
will determine both the LRS capacity and the reliability Energy from each unit.
STANDING BID REQUIREMENT - Each generating unit in each LRA would be
required to submit a standing bid for the LRS capacity and Energy. The standing
bid would prevail unless a LRS bid (capacity and Energy) is submitted for the
relevant operating day or hour, or the unit is on scheduled maintenance.
PENALTY AND AVAILABILITY PROVISIONS - Penalties would apply if the LRS
procured is not Scheduled or bid into the relevant forward markets. The penalty
would be commensurate with the cost imposed on the market due to ISO's
procurement of the LRS from another (possibly more costly) resource or invoking
other Operating Procedures to rectify the LRS deficiency.
To ensure system reliability, Availability Standards would apply. In
view of the standing bid requirement, and the penalty for non-delivery of the
LRS as stated above, a unit that violates the Availability Standards could incur
LRS-related penalties as part of (or in addition to) other penalties that it may
incur in view of any system-wide Availability Standard violation penalties30.
The LRS-related component of unavailability penalties would be computed as if
the unit were selected in the LRS market based on its standing bid, and did not
deliver the LRS so awarded.
INTERPLAY BETWEEN LRS AND DA MARKET - The Operating Procedures and
Nomograms applied above may include limits on maximum amount of Generation from
a unit or set of units. Such limits will also be announced two-days before the
operating day and used in the Day-Ahead Market as part of schedule and bid
validation process.
The Operating Procedures and Nomograms (including limits on Generation
and transmission embodied in the Nomograms) would be incorporated in the ISO's
CM software. It is, however, expected that due to LRS procurement, these
constraints, as well as other "Intra-LPA" constraints would not be binding. All
Nomogram constraints would be priced in the software in case they become binding
because of ISO forecast changes from two days ahead to the Day-Ahead Market.
However, since such occurrences are expected to be rare and unpredictable, the
potential for gaming and exercise of market power is expected to be small enough
not to warrant imposition of "Energy bid caps". Of course, any system-wide price
caps (or bid caps) would still be honored.
The ISO's forecast of system conditions and Load can change after close
of the two-day ahead LRS procurement. In that case, any corresponding changes in
the LRS requirements would be published, and the incremental LRS would be
procured through a "Day-of" LRS market. The "Day-of" LRS procurement may be
conducted with sufficient lead time prior to the corresponding Hour-Ahead
Markets.
The cost of LRS capacity for each LRA would be allocated to the metered
Load in the corresponding LRA31.
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30 Availability Standards in the context of Congestion Management pertain to
local reliability only. However, the ISO is considering development and
implementation of system-wide Availability Standards that may apply under
specified system conditions (e.g., system Load above 38,000 MW).
31 This is economically justifiable since in the absence of LRS procurement, the
load in the LRA would pay a higher price. Another alternative would be to
spread the LRS cost to all Load within the corresponding Transmission Owner
`s Service Area, as is done with RMR costs today. This would diffuse
locational price signal to the LRA Load, but would probably be more
politically feasible.
48
DISCUSSION OF THE PROPOSED SOLUTION - The main difficulty in
implementing the LRS procurement methodology as described above is the
determination of the LRS price (bid) cap. As envisaged, the cap would be
determined separately for each LRA. Since the different units in each LRA have
different fixed and operating costs, the level of the cap in each LRA would have
to be high enough to ensure equitable compensation for the provision of LRS.
This may prove to be more costly than relying on RMR-type contracts
(particularly, those with option payments based on incremental cost of service
rather than a percentage of the going forward fixed costs) for local
reliability. In fact, a critical question regarding the LRS procurement is how
it would compare to a design that would rely on RMR-type contracts (long-term
contract with fixed option payment and unit-specific Energy bid caps based on
fuel-adjusted variable cost) for a comparable service. We are continuing to
analyze the potential risks and rewards of the two-day ahead LRS procurement and
will provide our analysis as soon as it is complete.
The advantages of the proposed daily auction for LRS over long-term
RMR-type contracts can be summarized as follows:
o Reliance on RMR-type contracts for LRS would practically require
all in-state units to be designated as RMR Units. This would be
against the expressed objective stated in the Tariff, and the
stated policy of the ISO Board.
o In order to ensure reliability, the ISO would have to procure more
capacity on an annual basis (through the option payment) than it
would on a daily basis (through the daily LRS capacity payment).
o The proposed LRS would entail lower payment for the minimum
reliability Energy. Under the RMR Contract provisions, the RMR
Condition-1 units can elect to receive their contract price
(variable cost) rather than the market-based Energy price during
any hour that they specify prior to the start of the Day-Ahead
Market. For the off-peak hours, where market-based Energy prices
are lower than their variable cost, they would earn higher
payments for the minimum reliability Energy under the RMR
Contracts than they would under the proposed LRS procurement.
The disadvantages of the proposed daily auction compared to RMR-type
contracts can be summarized as follows:
o Unless Alternative 2 is adopted, it would be very difficult to set
an appropriate level for the LRS bid cap for a LRA. The level may
have to be set high enough to allow equitable cost recovery for
all units within a LRA. That would make the daily LRS procurement
more costly than RMR.
o The ISO would have less control on maintenance schedules of the
Generating Units under the daily LRS auction compared to RMR
Contract provisions.
Among the advantages and disadvantages listed above, the difficulty of setting
the LRS capacity cap is so serious at this time that we have identified an
alternative design as a fallback. The following option is an attempt to address
this issue.
OPTION 3 - LOCAL RELIABILITY SERVICE WITH DAILY SERVICE COMPENSATION -
This alternative design does not involve an RMR-type up front annual payment or
a LRS capacity payment. Instead, it allows recovery of both Generation cost
(start-up and variable), and opportunity costs on a daily basis. Its main
elements are as follows:
49
o The ISO will pre-dispatch LRS requirements (minimum LRS
generation along with minimum LRS capacity) before the
Day-Ahead Market.
o The LRS provider will be obligated to schedule at least the
minimum reliability Energy in the Day-Ahead Market, either in
a bilateral contract, or as a price taker in the PX market.
o The LRS provider is prohibited from submitting an Adjustment
Bid for the minimum reliability Energy portion of its Schedule
in the Day-Ahead market and must ensure that the ISO's CM will
not adjust the LRS provider's schedule below that level.32 If
this portion is ultimately adjusted via the CM software, the
applicable penalties will apply.
o The LRS provider can leave the remaining portion of the LRS
capacity unloaded, schedule it against load in the Day-Ahead
Market, bid it into the PX market, the Adjustment Bid market,
the A/S markets, or as Supplemental Energy.
o There will be "bid caps" on Reliability Energy (both the
minimum LRS Energy and the Energy from the minimum LRS
capacity). The bid caps will be unit-specific, based on unit
variable costs filed with the ISO, adjusted for fuel prices.
The bids at (or below) the bid cap can set market clearing
prices. If the market clears above the bid cap (in any ISO
market), the unit will be paid the relevant market-clearing
price.
o For the minimum LRS Energy that the owner must schedule
against Load in the Day-Ahead market, the owner will be paid
an hourly uplift per MWh of reliability Energy equal to the
difference (if positive) between the highest bid cap of the
pre-dispatched units in the same LRA and the lower of its own
bid cap or the PX price.33
[Note: In order to compensate for the opportunity costs
associated with minimum reliability Energy, we could allow the
hourly uplift to be based on the higher of the average of all
A/S capacity prices, or the difference (if positive) between
the highest bid cap of the pre-dispatched units in the same
LRA and the lower of the unit's cap or the PX price. For
example, assume there are 3 units in the LRA, all dispatched
at their minimum Energy levels with variable costs of $40,
$45, and $50 respectively, and that the PX price in the LPA
containing the LRA is $30. Consider two cases: Case a) the
average of the A/S MCPs for the hour in the LPA containing the
LRA is $15/MWh. In this case, the hourly uplift is max
($50-$30, $15) = $20. Case b) the average of the A/S MCPs for
the hour in the LPA containing the LRA is $25/MWh. In this
case, the hourly uplift is max ($50-$30, $25) = $25.]
o To ensure the recovery of all operating costs on a daily
basis, a daily uplift would be paid if needed. The uplift may
be needed in cases where the daily market revenues (pricing
any bilateral schedules at the relevant market MCP) are
inadequate to recover demonstrable costs (including
fuel-adjusted start-up cost, gas imbalance cost, and other
demonstrable costs).
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32 As noted previously, the LRS provider can assure that the minimum
reliability Energy portion of its Schedule will not be reduced by not
submitting an Adjustment Bid for that portion and by matching that
minimum Energy requirement with an Energy sink (Load or fixed Inter-SC
trade) within the same LRA.
33 If the PX price is not acceptable as a reference, any other reference
Energy price index agreed upon beforehand (for each LRA, or all LRAs)
can be used instead.
50
NOTE:
A variant of this alternative design would be to allow the units in a
LRA not to necessarily schedule the minimum LRS Energy against Load, but submit
capped Adjustment Bids to permit the Day-Ahead Congestion Management process to
adjust their schedules to ensure adequate LRS Energy (minimum generation
constraint in each LRA). This would make hourly uplift payments unnecessary.
This approach would, however, not work with the Market Separation Rule, as it
would provide new gaming opportunities. However, if the Market Separation Rule
is relaxed in the ISO's CM software for LRS constraints (i.e., all LRS
constraints are handled through a fictitious SC), this could be a viable
solution, leading to LRS-related locational price differences determined in the
CM software.
7.3.5 OPEN ISSUES - other than those noted above, there are a number of
outstanding issues, which we have not addressed in this section. They include,
but are not limited to, the following:
o Should the LRS Capacity Bid Cap be escalated or adjusted over
time?
o Should the LRS Capacity Bid Cap sunset at a certain date or
after a fixed amount of time?
8. THE DAY- AND HOUR - AHEAD MARKET
8.1 DAY-AHEAD CONGESTION MANAGEMENT
8.1.1 INTRODUCTION - At the beginning of this redesign proposal we
identified certain deficiencies with the ISO's current DA CM process. We stated
that the existing approach failed to accurately model and price the same
facilities modeled and priced in the real-time market. As a result, the ISO
failed to establish meaningful locational price signals. Therefore, the primary
purpose of the DA CM redesign should be twofold; a) to ensure that the DA and HA
Markets are modeled based on the real-time market which, in turn, accurately
reflects operational realities and best-practice engineering standards, and,
thereby b) to improve efficiency and eliminate gaming by producing accurate
pricing signals in Locational Price Areas (LPAs) that very closely conform to
Local Reliability Areas (LRAs) that are currently used in real-time operations.
8.1.2 SIMILARITIES WITH THE EXISTING DA CM APPROACH - Most of the other
elements of the CM process will remain the same. The most significant change to
the ISO's current DA-HA CM process is the basis of and what is priced.
THE DA CM PROCESS - We propose to maintain the same timeline for the CM
process and the Congestion iteration. During the first stage of the Day-Ahead
scheduling process, an SC would submit a Schedule of resources and Loads at
individual locations, consistent with the current practices. The ISO would then
map (via a preprocessor) these resources and Loads at the single equivalent
buses of the Simplified Commercial Model that represent the various LPAs. An
Adjustment Bid curve could be submitted for each resource and Load. If there is
no Congestion, the submitted Schedules will not be adjusted. If there is
Congestion, the ISO will then use its CM algorithm, the simplified LPA-based
model, and the SCs' resources to determine suggested operating points and
tentative Inter-LPA Schedules. This is the same method as is done today. SCs'
could adjust their Schedules and resubmit them, after which the ISO would
determine Final Schedules and net Generation in each LPA, and net Inter-LPA
Schedules for each SC. SCs will have the opportunity, after reviewing the
advisory schedules and transmission prices of the first iteration, to modify
their unit commitment, conduct inter-SC trades, and revise their schedules and
their Adjustment Bids for submission in the second iteration. To further enhance
the usefulness of the
51
DA CM iteration and to facilitate SC trading, the ISO proposes the voluntary
publication of unused Adjustment Bids after the first iteration. The ISO would
publish these bids with SC approval. The CM iteration will also assist SCs in
managing the requirements of the Market Separation Rule, as described below.
ETC/FTR SCHEDULING PRIORITY - The proposed DA-HA CM process honors the
existing scheduling priority of ETCs and FTRs. ETC schedules receive the highest
scheduling priority in both forward markets over their respective contract
paths. Additionally, ETC schedules are exempt from Usage Charges in the forward
markets. Furthermore, unscheduled ETC capacity is reserved in the Day-Ahead
Market for possible use in the Hour-Ahead Market, according to the terms of each
contract. FTR Schedules receive the second highest scheduling priority, after
ETCs, but only in the Day-Ahead Market, on their respective Inter-LPA interfaces
and directions.
8.1.3 NEW FEATURES OF CONGESTION MANAGEMENT - There are a number of new
features to the ISO's DA CM process that are recommended to be implemented as a
result of this redesign process. They include:
THE NEW CONGESTION MANAGEMENT ACTIVITY RULE - The new ISO proposal
adopts an element of the original design that has not yet been implemented --
the Congestion Management Activity Rule. According to that rule, the Final
Day-Ahead Schedules and transmission prices would be determined either after the
first or the second iteration, depending on which solution results in lower
total Congestion cost. This activity rule will safeguard against gaming since
the submitted Adjustment Bids would likely be cost-reflective because the
solution of the first iteration may become final. Implementation of this rule is
necessary because the CM iteration introduces the possibility of gaming if the
results of the first iteration are not binding. This is true since there is no
risk in submitting bids that may not be cost-reflective. This situation is
somewhat mitigated by the fact that there will be no iteration if there is no
Congestion. Nevertheless, an SC may easily cause Congestion by submitting
schedules designed for that purpose.
LRS ENERGY SCHEDULING - As explained in Section 6.3, SCs will be
required to schedule the minimum Energy amount specified in the winning LRS bid
(which is a portion of the capacity awarded in the reliability auction) in the
Day-Ahead Market. The minimum reliability Energy amount will be scheduled
against Load in the same LPA. SCs will submit the Schedule to the ISO by 10:00
AM in the Day- Ahead according to the existing timeline.
As noted in Section 6.3, SCs will be assessed penalties if they fail to
schedule the rewarded minimum Energy amount. Furthermore, validation procedures
will be established and implemented in the ISO's SI system to ensure that
specific resources operate within certain operating limits for reliability
purposes as specified by the ISO as a result of the daily capacity auction.
Failure to observe these limits will disqualify the SCs' schedules.
PRICE-RESPONSIVE INTER-SC TRADES - The ability to submit Adjustment Bid
on Inter-SC trades is another tool this proposal offers to SCs. The current
software for Inter-Zonal CM allows Adjustment Bids to be placed on imports,
exports, Loads, and Generation. However, trades are fixed with no Adjustment
Bids. This limitation can force SCs that participate in these trades to be
"price-takers" for transmission if their submitted Schedules do not include
other resources that can submit Adjustment Bids. As discussed
52
earlier this year, the ability of placing an Adjustment Bid on a trade among the
SCs will be available by late Summer 2000.34
8.1.4 THE COMMERCIAL MODEL - Similar to that used in real-time, the DA
CM process will rely on a nomogram-driven LPA-based model for pricing
transmission. The LPA-based model is a commercial approximation of real-time
operations and engineering practices and will be the basis for Inter-LPA pricing
and settlement. The limited dimensionality of the commercial model will enable
transparent access and pricing, thereby permitting grid users to ascertain the
value of Inter-LPA rights, manage their transportation costs, and make informed
assessments and tradeoffs between generation and transportation. It would allow
Scheduling Coordinators to make trade-offs between resources within a LPA.
Furthermore, it would be the basis upon which the ISO would issue FTRs. The
proposed model balances commercial and reliability needs. It accomplishes this
very important objective by integrating a simple commercial overlay onto the
detailed operational processes that are currently used to manage the system in
real-time. Enforcing the Operating Procedures and the Nomograms satisfies the
reliability needs, while the commercial needs are met by using a simple
LPA-based model for inter-LPA access.
For the purpose of Inter-LPA transmission access, all resources within
a LPA would be deemed to be at the same "virtual" location, and the only
relevant factors would be a resource's LPA and its Adjustment Bid prices. That
is, the proposed model will treat all resources in a LPA identically, without
locational bias, for the purpose of Inter-LPA access and real time dispatch. 35
Therefore, identical Adjustment Bids submitted resources within the same LPA
will result in the same allocations of Inter-LPA rights, consistent with the FTR
model, and the SCs' operational flexibility rights. Network limitations within
the LPAs, such as thermal limits, voltage problems, other stability and security
constraints will not be ignored. These limitations will be managed through the
Operating Procedures and Nomograms that the ISO is currently using in real-time
to operate the system reliably. As explained in Section 6.3, the availability of
resources to resolve these reliability-related problems can be secured via a
2-Day-Ahead capacity auction. Moreover, the Day-Ahead CM process will
incorporate the constraints included in the Operating Procedures and Nomograms
to ensure that they are indeed satisfied.
8.1.5 NETWORK REPRESENTATION - The Simplified Commercial Model will be
created by developing a reduced network model for California and the entire
WSCC. This would be a genuine effort to depart from the "black box" optimization
model and provide Market Participants with the ability to run their own CM
simulations and validate the results of the ISO's computations.
THE INTERNAL SYSTEM - The new proposed Congestion model is
based on a simple commercially viable representation of the Inter-LPA market.
While, as explained below, the ISO will continue to monitor the validity of the
network representation using the more detailed operational model, DA CM will
utilize a simplified representation of the system. Thus, each LPA in the
Internal System will be represented as a single bus connected to the other LPAs
by Inter-LPA paths.
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34 FERC recently approved, in its order on Amendment No. 29 (Docket No.
ER00-2383-000) to the ISO Tariff, the tariff provisions related to
Inter-SC trade Adjustment Bids (FERC order dated June 28, p.14).
35 This is because, by satisfying the Nomogram for a specific LRA the ISO
effectively (except in rare circumstances) eliminated all Intra-LPA
Congestion.
53
Such a representation will require the use of Generation Shift
Factors.36 Use of Shift Factors is necessary and is a result of moving to a
looped-LPA model.37 These Shift Factors will affect the pricing of the Inter-LPA
paths as well as the use of FTRs.
Shift Factors will be calculated for various representative network
states and for every Load and Generator bus with respect to every Inter-LPA
path. It is important to recognize that Shift Factors are determined by the line
reactance of the network only and are not affected by the actual bilateral
Schedules from Generators to Loads, or from Generation and Load levels, or the
season of the year. Shift Factors are only affected by the topology of the
transmission system itself. If transmission lines are added or taken out of
service, the Shift Factors will change. Therefore, in a loop LPA configuration,
Shift Factors provide valuable information that can be used to anticipate Usage
Charges assessed for given power transfers, as well as calculating the required
transmission rights to hedge against these charges.
The ISO proposes to publish a library of the Shift Factors that will
include a separate set of Shift Factors for each major network state associated
with main transmission maintenance outages, and the switching of important
network elements (e.g. Path 15 element on maintenance outage, Path 26 element on
maintenance, Path 26 series capacitor bypass/insertion, etc.). The library of
Shift Factors will be updated on a seasonal basis or more frequently as required
to reflect the operational realities of the system.38 The Shift Factors
applicable for each operating day will be published along with other Public
Market Information two days before the Operating Day. To maintain the stability
of the Commercial Model, the Shift Factors published two days ahead will be used
in the Day-Ahead and the Hour-Ahead Markets, even if there may be changes in
maintenance schedules after the PMI is published.
We recognize that Market Participants may want to keep the Shift
Factors constant throughout the year or through each season in order to obtain
some measure of certainty. However, the desire for stability and price certainty
has to be balanced against the need to consistently update Shift Factors when
updates to the network model take place. It is essential that we receive
feedback on this issue from Market Participants.
THE EXTERNAL SYSTEM (WSCC) - The proposed model will contain a
simplified representation of the WSCC system.39 The Internal System contains a
simplified representation of the California transmission system and a very small
portion of the other systems which are "electrically closed" to the California
system. While the External System is usually unmetered and "electrically more
distant", it is important to model the response of the External System on the
Internal System (i.e., recognize and model loop flows).
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36 A Shift Factor for bus i and line l connecting busses m and n is the
per unit change in power flow over line l when power is increased at
bus i. The power injection at bus i is compensated by an equal amount
of power decrease at the reference bus. All Shift Factors are unity in
a radial LPA configuration. However, in a loop LPA configuration the
Shift Factors are less than 100% due to Loop Flow (i.e., Energy flows
from source to sink over more than just the scheduled path).
37 As explained later, the simplified representation of the rest of the
WSCC transmission system (External Model) will also create loops
between the new LPAs.
38 If and when the ISO implements its State Estimator (as originally
specified in the PMS as a stage 2 application), the Shift Factors can
be computed on-line.
39 The WSCC region encompasses approximately 1.8 million square miles,
representing a service area equivalent to more than one-half of the
contiguous area of the United States. The power flow model for the WSCC
is comprised of nearly 8,000 buses and nearly 10,000 transmission lines
including transformers. The ISO currently has nearly 30 tie-points for
scheduling outside of the ISO Control Area.
54
The ISO plans to use standard methods to produce a reduced equivalent
representation of the External System. Based on the accumulated industry
experience of the last decade, these methods are accurate enough to ensure that
the performance of various network applications is not compromised. If
necessary, modifications to these techniques will be made to ensure the validity
of the optimization results for the reduced equivalent model.
8.1.6 THE MODELED CONSTRAINTS - A Simplified Commercial Model will used
to allocate Inter-LPA transmission rights to the SCs via the Adjustment Bid
market. The DC OPF software that will be used to solve the Simple Commercial
Model will include various constraints that reflect the physical limitations of
the transmission grid. Additional constraints, as represented by Operating
Procedures and nomograms, will also be enforced. The CM software will also model
physical limitations, including limits on the Inter-LPA paths and limits on the
Generators located within an LPA. Finally, the CM software will enforce the
Market Separation Rule. In the following, we briefly discuss the nomogram
constraints and the Market Separation Rule.
NOMOGRAM-BASED CONSTRAINTS - As explained in detail in Section 5, the
operation and configuration of the existing LRAs is based on Operating
Procedures and nomograms. Nomograms are developed to illustrate the relationship
between the two or more interdependent paths and may also be a function of other
key parameters, such as Load, Generation, inertia, or Remedial Action Schemes
(RAS). As a result, a nomogram may have numerous lines, or families of curves
that describe the relationship between factors and transmission under many
operating conditions. Therefore, it is upon that basis that it is critical that
these nomograms be explicitly modeled in the ISO's DA CM software. Since the
LPAs represented in the Simplified Commercial Model are, for the most part,
based on the nomogram-derived LRAs, it is very important to keep the nomograms
up to date.
THE MARKET SEPARATION RULE - The proposed design achieves all the
objectives of the Congestion Management reform project without the need to
violate the Market Separation Rule. The proposal is consistent with the
fundamental design principle that the ISO should maintain each SC's individually
balanced Schedule when allocating transmission capacity in Inter-LPA CM. This
principle is consistent with the separation of Energy and transmission markets,
since it prevents the ISO from creating involuntary Inter-SC Energy trades for
the purpose of managing Inter-LPA Congestion. This goal is left to the Market
Participants with the understanding that they must have available the necessary
tools to achieve such an outcome. One important concern is that an increased
number of Congestion areas may segment the transmission market to the point that
an economic solution would be difficult to obtain. This proposal includes
mechanisms that would facilitate trades among SCs, encourage participation in
the Congestion Iteration, and post voluntary trades in order to address this
concern.40
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40 FERC and the ISO Governing Board have requested that the ISO identify
trading opportunities that may have been foregone as a result of the
Market Separation Rule. As explained in SECTION 3, the ISO is currently
evaluating the cost impact of the Market Separation Rule and will
present the results of that analysis shortly. Included in that analysis
will be further explanation of and justification for maintaining the
rule.
55
8.1.6.1 OTHER OPTIONS CONSIDERED - One option that we are
still actively considering is outlined below. We have attempted to
briefly identify the option and how we think this option could be
implemented.
"VOLUNTARY" RELAXATION OF THE MARKET SEPARATION RULE. Certain
Market Participants have advocated the "voluntary" relaxation of the
Market Separation Rule. Under this approach, SCs would voluntarily
designate, or "flag" on their Schedules, whether they want the ISO to
relax Market Separation for their Schedules. That is, SCs would have
the ability to specify whether they want the ISO to arrange trades with
other SCs. One approach we could implement is to make the ISO a
"provider of last resort" and activate this feature only during the
second iteration of the ISO's CM process.
We believe this proposal merits further consideration. While
we continue to believe in the need to keep the ISO out of the forward
Energy market, we believe that the ISO could stand ready as a "provider
of last resort" (after SCs have fully availed themselves of
opportunities for trading in the forward markets) without necessarily
compromising or unduly impacting the Energy market. Because of our
recommended approach on FTRs and our overall emphasis on SC
forward-market management of their requirements, we believe that the
residual Energy requirement associated with this proposal would be
small.
Obviously, this issue requires careful and thoughtful
deliberation. It is imperative that Market Participants express their
views on this matter in order to inform our future consideration of
this issue.
MONITORING AND VALIDATION - The current Zonal pricing methodology is
based on a 3,000 bus model that produces transmission prices as Zonal price
differentials. That is, the Zonal price is calculated as the Energy injection
weighted average of all locational prices in each Zone. Therefore, the existing
methodology is fully applicable in a looped-LPA configuration where the
locational prices within a LPA will vary if there is Congestion on any Inter-LPA
interface.41 With a simplified commercial network model, there would be no need
for any locational price averaging since the LPAs would collapse to single
equivalent buses. Nevertheless, for purposes of monitoring the validity of
defined LPAs, we propose to obtain the locational solution (based on a 3000-bus
model) to continuously examine the locational and LPA-based price dispersion.
Moreover, as part of the Day-Ahead (and Hour-Ahead) scheduling timeline, the
detailed network model will be executed after completion of Congestion
Management to validate that the Day-Ahead schedules do indeed satisfy the
Intra-LPA operating constraints.
8.1.7 PRICING (INCLUDING COST ALLOCATION) - A key issue of concern in
this redesign process has been the allocation of Congestion costs and revenues.
As explained in Section 9, the proper allocation of these costs and revenues
bears directly on the ISO's ability to send meaningful locational price signals.
Outlined below are certain of the options we considered for allocating
Congestion costs and revenues.
- ----------
41 Of course, as mentioned earlier, the locational price dispersion within
a LPA should be sufficiently small.
56
OPTION 1 - Adopt the existing Congestion cost and revenue allocation
for Inter-Zonal Congestion Management, under which the marginal cost of
Congested Inter-Zonal transmission is charged to the users of the congested path
and the revenues are paid to the applicable FTR Holders and PTOs. The PTOs in
turn, offset their respective Transmission Access Charge (TAC) by the revenues
collected from the FTR auctions and Usage Charge revenues associated with
Inter-Zonal Congestion. Thus, under this allocation scheme, the Usage Charge and
FTR auction revenues are ultimately distributed pro rata among all loads in each
PTO's Service Area.
OPTION 2 - Alternatively, since the effect of Congestion on a
transmission interface into a LPA is an increased Energy price within the LPA
and decreased Energy prices outside of the LPA, we may want to consider a
different revenue allocation so that the benefit (i.e., reduced transmission
rates) would go to the Load in the applicable LPA. For example, the FTR auction
revenues and residual (net non-FTR) Inter-LPA Congestion revenues resulting from
the use of congested Inter-LPA interfaces leading into LPAs could be distributed
to the Loads in these LPAs. Before adopting this alternative, however, several
issues would need to be addressed. First, is it appropriate to withhold a share
of these revenues from other Loads that are bearing an allocable share of the
embedded costs of the congested Inter-LPA interfaces? Second, would allocating
these revenues entirely to Loads in a LPA unduly distort the price signal that
the higher Energy price sends? Furthermore, in a looped configuration it is
unclear how the Congestion revenues are allocated to the Loads of the various
LPAs.
OPTION 3 - Another alternative would be to create a transmission
upgrade fund using the FTR auction revenues and the PTO shares of the Usage
Charge revenues (the Usage Charge revenues allocable to FTR Holders would of
course continue to be allocated to them). The PTOs would still collect their
Revenue Requirements from the TAC and would not be harmed by this alternative.
The benefit of such a fund would be to encourage upgrades to frequently
congested Inter-LPA pathways.
At this point in time, we recommend Option 1. However, we also see the
appeal of Option 3, especially as it would facilitate the necessary expansion of
the grid in areas experiencing Congestion. We encourage Market Participants to
identify other alternative options and to provide feedback as to which option
they believe is appropriate and viable.
8.1.8 OPEN ISSUES
o When to update and publish new Shift Factors?
o What to do if the detailed model executed after Congestion
Management shows that some Intra-LPA operating constraints are
violated?
57
8.1.9 OTHER OPTIONS CONSIDERED - Certain options that were considered
by the ISO but not selected are outlined below. We have attempted to briefly
identify the option and provide our reason for not selecting the option.
o PRICING TRANSMISSION BETWEEN BUSES OR NODES. This option was rejected
because real-time operations are not described accurately by
constraints on transmission between individual buses. The constraints
derived from requirements for stability, security, and voltage support
are binding over areas with limited energy imports over high-voltage
branch-groups of transmission lines. These "local reliability areas"
reflect the finest spatial differentiation that is meaningful and
useful in operations.
o JOINT OPTIMIZATION OF TRANSMISSION ALLOCATION AND DISPATCH OF ENERGY
GENERATION, as done in the Eastern Interconnection by NYISO, or PJM's
similar dispatch-based pricing in which at each node the price is the
highest marginal cost among the generator(s) dispatched there. This
option was rejected because it bundles transmission and energy into
nodal prices that hide where transmission constraints are binding and
which ones (even knowing the shift factors, nodal prices are
insufficient to identify the usage charges on transmission lines or
branch groups affected by flowgate constraints). There are also
substantial disadvantages in terms of incentives. The new design
accomplishes all intended purposes of the Congestion Management reform
project without any evident need to violate the "market separation"
principle of the California system. Without any compensating advantages
there was no reason to re-bundle transmission and energy, nor to
intrude into the energy markets of the SCs, nor to assume scheduling
and dispatch authority. The new design interprets the scope of the
ISO's forward markets as comprising allocation of transmission capacity
via FTRs and its DA/HA Congestion Management process, and procurement
auctions for ancillary services not self-provided by SCs.
The basis of the California market design is that the market
(i.e., SCs) should maximize market efficiency, not the ISO. SCs value
the ability to control their schedules and if this ability is
compromised by centralized optimization, they may submit fewer
Adjustment Bids potentially resulting in increased Congestion costs.
Furthermore, elimination of the Market Separation Rule may compromise
the value of the bilateral contracts since the ISO's optimal redispatch
would ignore the terms of these contracts. Consider, for example, the
case of a Green Energy supplier that is scheduled off because of the
ISO's dispatch of cheaper Brown Energy. Moreover, without market
separation, there is no need for Balanced Schedule submission since the
ISO would optimally balance the system. Without balanced schedules, the
concept of transmission allocation becomes moot (what transmission does
an unmatched Load schedule use?). Furthermore, Congestion Management
changes from a transmission capacity auction into a constrained forward
Energy market. In this paradigm, the ISO would assume the central role
of an Energy clearinghouse, intruding into the Energy markets of the
Power Exchange, and the SCs in general. In summary, the new ISO design
maintains the enforcement of the Market Separation Rule for the
following reasons (for more details see Appendix [ ]):
1. Market Participants are fully capable of optimizing among themselves
and the ISO should not take it upon itself to overrule their decisions.
58
2. If, for the sake of argument, there were inefficiencies
associated with the implementation of the Market Separation
Rule (i.e. no central dispatch), new market-sponsored
institutions will be better able to resolve those problems
than would non-market institutions.
3. The ISO should focus its attention on its statutory
obligations (maintaining reliability and system security)
rather than optimizing the market.
4. The Market Separation Rule forces SCs to optimize their own
portfolios and thereby creates the necessary incentive for
them to develop market tools and mechanisms to
facilitate/achieve such optimization.
5. The creation of a bundled Energy and Transmission market (a
result of central optimization results) is at odds with the
central tenet of a competitive market - the unbundling of the
transportation and production functions, and is at odds with
the functional unbundling requirement of FERC Orders 888 and
889.
8.2 HOUR-AHEAD CONGESTION MANAGEMENT AND DAY-OF LRS
8.2.1 HA CM - The ISO's HA CM process will remain largely unchanged. In
the Hour-Ahead, the ISO will only accept new Schedules which can be accommodated
through scheduling adjustments using resources that have submitted price bids
for redispatch. Beginning one hour before the hour of consumption, the ISO will
take the new Hour-Ahead Preferred Schedules and run its simplified CM function
to relieve Inter-LPA Congestion and then price it, recognizing the Shift Factors
among the LPAs and the External Network. The resulting prices for use of
congested Inter-LPA Interfaces will be used as the basis for Hour-Ahead
Congestion settlements.
8.2.2 DAY-OF LRS - The ISO will also conduct a Day-of LRS procurement
auction to procure any additional capacity and Energy for each LPA it may need
as a result of forecasting errors or other unanticipated events. As provided in
Section 6.3, if there is not sufficient competition, the auction will clear at
the LRS price cap. The minimum amount of reliability Energy (a fraction of the
LRS capacity) will again be Scheduled against incremental load in the LPA. The
Day-of LRS procurement will select among pre-committed resources (i.e., units
that either have selected in the 2-DA Auction or units already committed through
the DA Ancillary Services market).
8.2.3 OPEN ISSUES
o When and how often should the ISO conduct the Day-of
LRS (i.e., should the auction occur two, three, four
times a day?
8.3 ANCILLARY SERVICES IN CONGESTION MANAGEMENT
Ever since the ISO began operations, Market Participants have raised
concerns that A/S cannot participate in the ISO's CM process. Currently, A/S
procurement takes place after Inter-Zonal CM (i.e., after all New Firm Use
capacity is allocated). Consequently, in a given forward market, Energy
Schedules
59
have scheduling priority over A/S.42 The latter can reserve only the
transmission capacity that remains unused after Inter-Zonal CM.43 Usage Charges
are therefore not assessed for transmission capacity that is reserved for A/S,
although that capacity has a value and it can command a price.
Market Participants have indicated that the different treatment of A/S
and Energy Schedules is discriminatory and artificially reduces the liquidity of
the A/S markets. While the ISO has long planned to implement the integration of
A/S procurement and CM (A/S-CONG Integration), to date other projects have had a
higher priority. This CM redesign exercise has provided an opportunity for the
ISO and Market Participants to reexamine the necessity and timing of A/S-CONG
integration.
8.3.1 BACKGROUND - A/S are currently procured either system-wide, or
regionally, in at most two regions (separated by either Path 15 or Path 26) when
real-time Congestion is expected on these Inter-Zonal Interfaces. Therefore,
A/S-CONG Integration mainly concerns the ability to reserve transmission
capacity for A/S imports, either for self-provision or for bidding into the
ISO's A/S auctions. The ability to import such products would also provide
access to the real-time Imbalance Energy Market to suppliers outside of the ISO
Control Area that would otherwise be shut out because of Congestion on the
inter-ties.44 To a lesser extent, reserving transmission capacity on Path 15 or
Path 26 for A/S may also be an issue for a more efficient use of the
transmission system and overall A/S procurement.
8.3.2 AN ALTERNATIVE APPROACH - We propose to address the main issue of
reserving transmission capacity for A/S imports with a simpler and more modest
approach. We recognize, however, that this approach may lose some of the
efficiencies that might be achieved from a more comprehensive approach.
Under this simpler approach, A/S suppliers would reserve transmission
capacity on inter-ties as price-takers in the Day-Ahead CM process by scheduling
their FTRs on the inter-ties for A/S use.45 This would be achieved by indicating
the corresponding FTR sources and sinks as A/S resources. Congestion Management
would treat these Schedules similar to non-firm Energy import schedules46 with
FTR scheduling priority in the Day-Ahead market. Therefore, the corresponding
transmission capacity reservation would be assessed Usage Charges as if it were
used for a New Firm Use (NFU). However, this will enable the A/S supplier to
either self-provide or bid into the ISO's A/S auctions in the Day-Ahead Market,
up to the reserved capacity, even when the inter-tie is Congested in the import
direction. If the A/S supplier is not selected in the Day-Ahead A/S procurement,
the associated reserved transmission capacity will be released in the Hour-Ahead
Market, consistent with the expiration of the FTR scheduling priority, and any
Day-Ahead Usage charges will not be refunded.
- ----------
42 Transmission capacity reserved on inter-ties for A/S imports in the
Day-Ahead market is not released for Energy Schedules in the Hour-Ahead
market. Therefore, Day-Ahead A/S have scheduling priority over
Hour-Ahead Energy Schedules. This is consistent with the market
structure according to which the Hour-Ahead Market is an incremental
market on top of the Day-Ahead Market.
43 If an inter-tie is derated two hours prior to the Hour-Ahead Market,
transmission capacity reserved for A/S may be reduced and the affected
A/S suppliers would buy back the corresponding A/S in the Hour-Ahead
market at the same price that it was sold for in the Day-Ahead Market.
44 Energy bids that accompany selected A/S capacity (except for
Regulation) and Supplemental Energy bids are used in real time to
procure Imbalance Energy in merit order.
45 This would provide higher scheduling priority over all NFU Energy
Schedules without FTRs.
46 The formulation of the constraints on Inter-Zonal Interfaces would be
modified to preclude non-firm Energy Schedules on inter-ties from
accommodating firm Energy schedules in the counterflow direction.
Similarly, transmission capacity reservation for A/S imports would not
accommodate any Energy exports, either firm or non-firm.
60
The major shortcoming of this approach is that it requires A/S
providers to secure the requisite number of FTRs over various paths (based on
Shift Factors, as described in Section 6.2). Another shortcoming is that this
approach would not be applicable in the Hour-Ahead Market since there is no FTR
scheduling priority in that market. Finally, there is a risk that any Usage
Charges paid for reserving transmission capacity for A/S will be wasted if the
A/S supplier is not selected in the Day-Ahead A/S procurement.
8.3.3 OTHER OPTIONS CONSIDERED - Another option that the ISO considered
but did not select is outlined below. We have attempted to briefly identify the
option and provide our reason for not selecting it.
FULL A/S-CONG INTEGRATION - To allow A/S to compete with Energy for
transmission capacity on an equal basis, Inter-LPA CM and A/S procurement would
have to be integrated into a single optimization process. In that process, A/S
would bid for and acquire transmission capacity in the same way that Energy
Schedules do. The market clearing price (MCP) for transmission capacity would
apply equally to Energy Schedules that use it and to A/S that reserve it. For
A/S self-provision, the reservation charge for transmission capacity would be
charged to the corresponding SC. For A/S imports that are selected in the ISO's
A/S auctions, the reservation charge for transmission capacity on inter-ties
would be charged to the corresponding supplier. Similarly, the Congestion
revenues collected from reservation charges and from A/S regional MCP
differentials would be paid to FTR Holders and PTOs, as if the corresponding
transmission capacity were used by Energy Schedules. In this integrated process,
FTRs may be used to hedge against Congestion charges, irrespective of whether
these charges are Usage Charges for Energy schedules or reservation charges for
AS.
THIS INTEGRATION EFFORT WOULD REQUIRE SEVERAL PROGRESSIVE STEPS:
1) At first, the currently sequential A/S procurement would need
to be converted to a simultaneous auction for all Ancillary
Services. The current Rational Buyer1 mechanism would need to
be modified and integrated in the simultaneous A/S auction.
The objective of the Rational Buyer mechanism would be
achieved by modifying the A/S demand constraints in the
simultaneous auction
2) Next, a simplified network model would be added to include
transmission constraints in the A/S auction.
3) Finally, CM and A/S procurement would be combined into a
single optimization model.
The integration described above is a major undertaking and would likely
require considerable time to complete. Since the volume of the A/S markets is
only a small fraction of the volume of the Energy markets, most transmission
capacity is more valuable for Energy rather than A/S. Therefore, Energy
Schedules would probably acquire scheduling priority over A/S anyway.
Furthermore, the A/S-CONG integration may adversely impact the transparency of
the markets, a major objective of California restructuring. Consequently, the
A/S-CONG Integration is of questionable value compared to the cost and
complexity of implementation.
61
8.4 RECALLABLE TRANSMISSION
INTRODUCTION - One of the core functions of the ISO is to ensure
efficient operation of the ISO Controlled Grid. As such, the ISO continually
strives to maximize throughput and efficient utilization of scarce transmission
capacity. Unfortunately, to date the ISO has been unsuccessful in fully
utilizing the existing transmission system because of the occurrence of "Phantom
Congestion." As described below, Phantom Congestion is an artifact of the ISO's
existing and ongoing obligation to honor all ETCs and gives rise to
circumstances where transmission customers are assessed Usage Charges for
Congestion that does not, in reality, exist. In an effort to remedy this problem
and yet still honor all ETCs, the ISO and Market Participants last year began
exploring the idea of making unused ETC capacity available to all users on a
"recallable" basis.
THE EXISTING TRANSMISSION ALLOCATION METHODOLOGY - Currently, the
Inter-Zonal CM process allocates a single transmission capacity product, firm
transmission, to New Firm Users of the ISO Controlled Grid in merit order
according to their valuation of transmission capacity. The "value" is imputed by
pairing up Adjustment Bids submitted by SCs for schedules across Inter-Zonal
Interfaces. Schedules without Adjustment Bids are given scheduling priority as
transmission price-takers. Schedules associated with ETCs are given the highest
scheduling priority in both Day-Ahead and Hour-Ahead Markets and they are not
assessed Usage Charges. Schedules associated with Firm transmission Rights
(FTRs) are given the second highest scheduling priority in the Day-Ahead Market
only and Day-Ahead Final Schedules are given the second highest scheduling
priority in the Hour-Ahead market.
"PHANTOM CONGESTION" - Many ETCs have scheduling timelines that are
inconsistent with the ISO's deadline for submitting Schedules. To accommodate
the scheduling of ETCs after the Day-Ahead Market, and for some ETCs after the
Hour-Ahead Market, transmission capacity that corresponds to the unscheduled
portion of ETCs is reserved in Day-Ahead and Hour-Ahead Inter-Zonal CM and is
not made available to New Firm Users. To the extent that ETC holders do not use
this reserved transmission capacity, this creates an inefficiency in the
transmission capacity allocation in the forward markets. The reserved
transmission capacity is ultimately released in real time; however, its
unavailability in the forward markets may aggravate Congestion and may
artificially elevate Usage Charges. At the extreme, Congestion may be present
"on paper" in the forward markets without actually materializing in real time.
This phenomenon is often referred to as "financial congestion" or "Phantom
Congestion."
A review of historical Day-Ahead ETC scheduling activity revealed that
unscheduled ETC capacity in 1999 was on average greater than the unmet demand47
on certain Inter-Zonal Interfaces. Had the reserved ETC capacity been released,
there would have been no Congestion during many hours. Examples of financial
congestion during 1999 are shown in Figures 4 and 5 for imports over the
California-Oregon Intertie (COI) and Palo-Verde Intertie, respectively. Detailed
information about unscheduled ETC capacity for 1999 will be provided in the near
future for all Inter-Zonal Interfaces by direction.48
THE SOLUTION - This efficiency issue can be addressed by creating an
additional transmission product: recallable transmission capacity. This product
can be made available after the allocation of New Firm Use capacity in CM by
auctioning, on a recallable basis, the unused ETC capacity that was reserved
- ----------
47 Volume of Schedule adjustments due to Congestion.
48 For inter-ties, positive direction indicates imports into the ISO
Control Area. For Path 15, positive direction indicates flow from south
to north.
62
in CM. The most efficient and simple way to do this is to repeat CM after
releasing the reserved ETC capacity, while locking-in the previous allocation of
NFU transmission.49 SCs would optionally participate in the allocation of
recallable transmission capacity with their remaining unused Adjustment Bids.
The Usage Charge (marginal cost) for using recallable transmission would be no
greater, but likely less, than the Usage Charge for NFU since the remaining
unused Adjustment Bids impute lower transmission capacity valuations. In the
event that ETC holders claim their right to schedule on their unused ETC
capacity at some point later in the scheduling process, Schedules using
recallable transmission could be adjusted accordingly to accommodate ETC
schedules.
[CHART]
FIGURE 4
- ----------
49 The second pass of Congestion Management for the allocation of
recallable transmission may take place immediately after the first pass
for the allocation of NFU transmission, or after the A/S procurement.
The first option is straightforward. The second option would give
scheduling priority to A/S over NFU capacity that may be required to
support recallable schedules due to non-unity Shift Factors in a looped
LPA network configuration. However, as discussed in Section 7.2, A/S
are not assessed Usage Charges for transmission capacity reservation,
but recallable Energy Schedules are.
63
[CHART]
FIGURE 5
As noted, recallable transmission would be priced as bid and it would
be recalled in merit order of increasing price. With this option, SCs may also
settle forward Energy associated with recallable transmission as bid. The
Congestion revenues from recallable transmission will be paid to the
corresponding PTOs or ETC holders, but they will be refunded in full if the
associated transmission capacity is recalled later.
8.4.1 OTHER OPTIONS CONSIDERED - An alternative option is to price
recallable transmission on the margin and recall it pro rata. With this option,
SCs may also settle forward Energy associated with recallable transmission on
the margin. This option is more complex since it increases the number of
schedule and settlement adjustments in the event of a recall. It is also not
equitable since it is impossible to distinguish between allocations in the
Day-Ahead and Hour-Ahead Markets according to the respective market clearing
prices. Therefore, this option is not recommended.
64
9. THE REAL TIME MARKET
INTRODUCTION - As we discussed in Section 7, the basic objective of the
CM redesign is to provide incentives to ensure physical feasibility of forward
scheduling, provide proper price locational signals and eliminate gaming between
forward and real-time markets. The proposed design achieves the above objectives
and offers several advantages including improved reliability and market
efficiency. A fundamental principle of the new design that helps achieve the
stated objectives is that the forward and the real-time markets model and price
the same resources consistently.
9.1. NETWORK REPRESENTATION
SECTION 8.1 presents in detail the Simplified Commercial Model that
will be used in the forward markets. The same model will be used in the
real-time markets. This model will be represented by LPAs that match the LRAs
currently used by the ISO to operate the system in real-time. The paths that
connect the LPAs will include loops to reflect transmission realities and the
impact of the External System on the ISO Controlled Grid. The ISO will allocate
Inter-LPA transmission rights in both markets in a consistent manner. The
proposed design ensures that, in almost all cases, there will be no Intra-LPA
Congestion.
The proposed network model is necessarily more complicated than the
current approach since it has to capture the network effects in selecting among
the most economic Energy bids. The effectiveness of each resource will impact
not only the quantity of the resource that may be procured but also the merit
order of bids used to determine the dispatch order. The real time model will be
solved using established optimization techniques similar to the ones used in the
forward markets. The objective function of the optimization will be the
minimization of the Imbalance Energy costs subject to all inter-LPA constraints
and other resource-based constraints. The Market Separation Rule will be relaxed
in the real-time market (See Section 8). The real-time network model will be
updated often based on real-time information as it becomes available from
various EMS functions, such as the State Estimator.
9.2 IMBALANCE ENERGY PROCUREMENT AND CONGESTION MANAGEMENT
INTRODUCTION - As described in SECTION 4 of this proposal, the
conceptual approach to this redesign effort has been to accurately reflect, in
both the forward and real time markets, the actual requirements of real time
operations, as determined by best engineering practices. Based on an examination
of the ISO's current real time Energy market, we determined that certain changes
to that market are necessary to:
1) Accurately capture or model the real-time operating
requirements of the ISO
2) Establish the necessary incentives for Market Participants to
behave in real time, in a manner that enables the ISO to
satisfy its real time operating requirements
3) Make the actions of the ISO transparent in real time
These changes are outlined below.
THE EXISTING IMBALANCE MARKET - Currently, the ISO's Imbalance Energy
market is based on a merit order stack of Energy bids that are supplied by
either resources that are selected in the forward markets to provide Ancillary
Services,50 or by Supplemental Energy bids submitted for use in real time.51
- ----------
50 Energy bids from resources that provide Regulation are not used in the
Imbalance Energy merit order stack. These bids are only used in AGC.
Regulation is a control rather than an Energy service. The Energy
supplied by
65
The AGC function of the EMS maintains the frequency and net area interchange by
correcting the Area Control Error (ACE) in real time. AGC resources respond
within seconds to variations in the supply and demand, keeping them in balance.
In performing this function, the units that provide Regulation depart from their
Preferred Operating Point (POP). Every ten minutes, the ISO performs an auction
for the Imbalance Energy that is required to return the AGC units to their POP
and thereby restore their regulating margin. The ISO selects the winning bids in
merit order from the Imbalance Energy stack and issues Dispatch instructions to
the corresponding resources through the Automated Dispatch System (ADS). The
real time price for Imbalance Energy in a given 10-minute interval is the Market
Clearing Price (MCP) that results from the corresponding Imbalance Energy
auction. Figure 1 illustrates the Imbalance Energy procurement in real time.
REAL-TIME CONGESTION MANAGEMENT - The ISO currently mitigates real-time
Inter-Zonal Congestion by dividing the Imbalance Energy market (and the merit
order stack accordingly) into Congestion regions, and procuring Imbalance Energy
separately in each region. Congestion regions are unions of Congestion Zones
where the interconnecting Inter-Zonal Interfaces are free from Congestion, but
the interfaces between regions are congested. In real time, Congestion regions
may differ for each 10-minute dispatch interval. The effect of the division of
the Imbalance Energy market is that the 10-minute MCPs for Imbalance Energy may
differ by Congestion region. The price differential between any two Congestion
regions is a manifestation of real-time Congestion between these regions.
SETTLEMENT OF REAL-TIME CONGESTION MANAGEMENT - The settlement of
Inter-Zonal Congestion Management in real time is handled through the Imbalance
Energy market. Revenues are obtained from Imbalance Energy consumers (those with
negative deviations) and paid to Imbalance Energy suppliers (those with positive
deviations). The difference between payments to suppliers and charges to
consumers is allocated to metered demand as part of the neutrality charge.
SPLITTING THE BEEP STACK - Currently, the ISO divides the Imbalance
Energy market only across internal Inter-Zonal Interfaces and not across
inter-ties. Therefore, the 10-minute MCPs for Imbalance Energy at an inter-tie
cannot differ from the MCP of the adjoining Congestion Zone, even if the
inter-tie is congested. This situation does not provide accurate locational
price signals for the value of Imbalance Energy and is inconsistent with the
forward market CM protocol. Additionally, this limitation allows opportunities
for gaming and does not provide incentives for proper bidding behavior. For
example, inter-tie bids may be extremely negative to acquire first position in
the Imbalance Energy merit order stack without the risk of setting the real time
MCP that will be used for their payment when called upon.
- ----------
resources providing Regulation is expected to be small since
Load-following is achieved by dispatching resources from the Imbalance
Energy merit order stack. Consequently, regulating Energy is a
price-taker in real time.
51 The merit order stack is often referred to as the "BEEP stack" or the
Balancing Energy and Ex Post Pricing stack.
66
[CHART]
FIGURE 1
AN "EFFECTIVE" DESIGN - The ISO proposes to modify its real-time
Imbalance Energy procurement software to allow for the division of Imbalance
Energy market across any Inter-Zonal Interface, including the inter-ties. This
would permit different 10-minute MCPs at the inter-ties and the adjoining
Congestion Zones. These MCPs would provide accurate price signals, improve
market efficiency, and would reduce opportunities for gaming.
The proposed design presents a significant departure from the current
real-time model. The representation will be necessarily more complicated since
it has to capture the network effects in selecting among the most economic
Energy bids (i.e., incorporate and reflect Effectiveness Factors). The
effectiveness of each resource in resolving Congestion or addressing other
system requirements will impact not only the quantity of the resource that may
be procured but also the merit order of bids used to determine the dispatch
order. The real time model will be solved using established optimization
techniques similar to the ones used in the forward markets. The objective
function of the optimization will be the minimization of the Imbalance Energy
costs subject to all Inter-LPA constraints and other resource-based constraints.
The Market Separation Rule will continue to be relaxed in the real-time market
(See Section 8.1.). The real-time network will be updated, as real-time
information becomes available from various EMS functions, such as the State
Estimator.
THE NEW APPROACH - Currently, the Imbalance Energy merit order stack is
based solely on the bids and the physical capability of the participating
resources. The efficiency of these resources in mitigating Congestion on a given
Inter-Zonal Interface does not factor into the merit order selection. Resource
efficiency varies due to the location of the resources in the network. As a
result of this omission, the selection of winning bids in the Imbalance Energy
auction may not be adequately effective in mitigating Congestion. This issue can
be addressed by calculating the efficiency of resources in resolving Congestion
on a given Inter-Zonal Interface and factoring this efficiency into the
Imbalance Energy merit order stack. The resource efficiency factor can be easily
obtained from a sensitivity analysis of a network solution. The
efficiency-weighted merit order stack can be constructed by dividing the Energy
bid prices by the corresponding efficiency factors, prior to sorting them. Since
the resource efficiency factors differ by
67
Inter-Zonal Interface, a different merit order stack would be constructed for
each interface at each 10-minute dispatch interval.
In a radial network, the real time Imbalance Energy procurement and CM
can be easily achieved by the previously described efficiency-weighted merit
order stack. However, in a looped network, as is proposed here, the possibility
of simultaneous Congestion on multiple Inter-LPA Interfaces makes this task
increasingly difficult. In this situation, the calculation of resource
Efficiency Factors can be combined with the Imbalance Energy auction into a
single network optimization function. The objective of this optimization would
be to procure the required amount of Imbalance Energy at least cost without
violating Inter-LPA Interface constraints or participating resource physical
capabilities, such as ramp limits and time delays, as well as responses to
multiple Dispatch instructions for various services. The required network model
would be similar to the simplified commercial model used in the forward market
CM assuming that the Efficiency Factors of resources within a LPA are very
close. One difference would be that the real-time simplified network model might
take advantage of real-time information provided by the State Estimator.
The proposed real-time optimal dispatch method would inevitably
eliminate any price overlap between submitted decremental and incremental Energy
bids, thereby putting the target price issue at rest permanently. The
formulation of the optimization problem would be similar to the forward market
Congestion Management, except that Energy would be priced in addition to
transmission capacity, and there would be no Market Separation Rule. Additional
constraints (e.g., ramp limits) would model the complexities of the real-time
dispatch environment.
The previously described process for Imbalance Energy procurement and
Congestion Management does not address Intra-LPA Congestion. As mentioned in
Section 7, the incorporation of Nomograms and Operating Procedures into the
forward market CM process would virtually eliminate Intra-LPA Congestion.
Intra-LPA Congestion in real time would be small or infrequent, caused by
unavoidable errors in load forecasts, and unanticipated system conditions such
as improbable contingencies, switching errors, loop flows, etc. Under these
conditions, the ISO would resolve Intra-LPA Congestion by dispatching resources
out of merit as needed.
9.3 PRICING AND COST ALLOCATION
The real-time optimal dispatch method discussed in the previous section
will also calculate MCPs for Imbalance Energy in each LPA, for each Dispatch.
These MCPs are the marginal cost for providing Imbalance Energy in each LPA, for
a given power dispatch.52 However, these prices may not be suitable for pricing
Imbalance Energy that would be calculated as the integral of the expected output
of resources that acknowledge Dispatch instructions, that take into account the
following:
1) The ramp limit
2) Any time delay
3) The physical capability of participating resources
4) Responses to multiple Dispatch instructions for various
services.
For example, dispatching of resources that were previously called upon
to provide Imbalance Energy might result in a MCP that is much lower than the
Energy bids of some of these resources. This would not be a problem if these
resources could immediately (with infinite ramp) transition to the newly
- ----------
52 Dispatch instructions are incremental or decremental power output (MW)
instructions that refer to the previously accepted Dispatch
instructions, or the Final Hour-Ahead Schedule if no instructions are
previously accepted within the same hour.
68
instructed operating point. However, because of finite ramp rate limitations,
these resources will provide Imbalance Energy for several minutes until the new
instructed operating point is achieved. This Imbalance Energy, being the result
of following ISO Dispatch instructions, provides the service that was bid for in
the Imbalance Energy market and it should not be paid below the respective bid.
Furthermore, multiple dispatches may take place within a given 10-minute
interval, whereas a single incremental and a single decremental MCP are needed
for settlement in that interval. Therefore, the complexities of the real-time
dispatch warrant a pricing approach that should follow the principles of the
10-minute Dispatch and Settlement design, as filed and recently accepted by FERC
in Tariff Amendment 29.53
THE 10-MINUTE DISPATCH AND SETTLEMENT - Under the proposed design, all
of the features of the 10-minute Dispatch and Settlement design would all be
retained.54 The only exception would be the methodology for calculating the
incremental and decremental MCPs in each LPA and 10-minute interval.
According to the 10-minute Dispatch and Settlement design, the
incremental and decremental MCPs in each Congestion region and 10-minute
interval would be calculated as follows:
o The incremental MCP would be the highest bid price of
Imbalance Energy expected in that interval as a result of
following in-merit acknowledged incremental Dispatch
instructions for that interval.55
o The decremental MCP would be the lowest bid price of Imbalance
Energy that is expected in that interval as a result of
following in-merit acknowledged decremental Dispatch
instructions for that interval.
o If only incremental Dispatch instructions are acknowledged,
the decremental MCP would be equal to the incremental MCP.
o If only decremental Dispatch instructions are acknowledged,
the incremental MCP would be equal to the decremental MCP.
o If no Dispatch instructions are acknowledged, the incremental
MCP would be equal to the lowest incremental bid price and the
decremental MCP would be equal to the highest decremental bid
price in the stack. The decremental MCP would never be higher
than the incremental MCP due to the application of the target
price mechanism.
In the presence of Inter-Zonal Congestion, the incremental and
decremental MCPs may be different for each Congestion region.
THE MODIFIED 10-MINUTE DISPATCH - This methodology is appropriate for a
radial Zonal configuration where the regional separation of the market simulates
CM in a simple network model. However, in a looped LPA-based configuration, the
calculation of the incremental and decremental MCPs in each LPA and 10-minute
interval will be based on the marginal Energy prices that would be calculated by
the real-time optimal dispatch, as follows:
- ----------
53 FERC order dated June 28, 2000 in Docket No. ER00-2383-000. The
10-minute market and settlement design is anticipated to be implemented
on or around August 1, 2000.
54 The transition to a real time optimal dispatch using a simplified
looped-LPA network model does not negate the concerns that led to the
10-minute Dispatch and Settlement design.
55 An acknowledged Dispatch instruction stays in effect until it is
explicitly reversed, or until the end of the hour. Reversed Dispatch
instructions cannot be declined; they are deemed immediately
acknowledged.
69
o An optimal Dispatch will take place at the beginning of each
hour regardless of Imbalance Energy requirements.
o The incremental MCP would be the highest marginal Energy price
of all optimal dispatch solutions in the interval, but not
lower than the marginal price of the last optimal Dispatch
solution in the previous interval of the same hour.56
o The decremental MCP would be the lowest marginal Energy price
of all optimal Dispatch solutions in the interval, but not
higher than the marginal price of the last optimal Dispatch
solution in the previous interval of the same hour.56
In the presence of Inter-Zonal Congestion, the incremental and
decremental MCPs may be different for each LPA.
Instructed Imbalance Energy from resources that acknowledge Dispatch
instructions would be paid or charged the appropriate MCP:
o Positive instructed deviations57 would be paid the incremental
MCP for the corresponding LPA and interval;
o Negative instructed deviations would be charged the
decremental MCP for the corresponding LPA and interval
o Positive Uninstructed Energy deviations will be paid the
decremental MCP
o Negative Uninstructed Energy deviations will be charged the
incremental MCP, for the corresponding LPA and interval.
o Ramping Energy58 would not be paid or charged since it is an
attribution of forward Energy that is settled in the SCs'
forward Energy markets.
o Positive Residual Imbalance Energy59 will be paid the
incremental MCP for the corresponding LPA and the interval in
which the associated Dispatch instruction was issued.
o Negative Residual Imbalance Energy will be charged the
decremental MCP for the corresponding LPA and the interval in
which the associated Dispatch instruction was issued.
Instructed Energy produced or consumed as the result of following an
out-of-merit Dispatch instruction, e.g., for Intra-LPA CM, would be paid or
charged as bid accordingly. The net cost of Intra-LPA Congestion would be
allocated to metered demand in the respective LPA through the Grid Operations
Charge. Instructed Energy produced as the result of following an out-of-market
(OOM) Dispatch instruction would be paid according to the OOM protocol and the
associated cost would be allocated according to that protocol.
Provisions implementing non-payment for uninstructed deviations, or "No
Pay" would normally apply to the following situations:
- ----------
56 For intervals two to six.
57 Real-time deviations are measured from the Final Hour-Ahead schedules.
58 Ramping Energy is the instructed energy deviation that is required for
a smooth 20-minute linear ramp between hourly energy schedules at the
top of each hour.
59 Residual Imbalance Energy is the instructed Energy that is produced or
consumed as the result of following a Dispatch instruction that
reverses a previously acknowledged Dispatch instruction in the opposite
direction in the previous interval of the current hour, or the last
interval of the previous hour.
70
a) Uninstructed Energy deviations that expend Ancillary Services
capacity that should remain in reserve
b) Declined Dispatch instructions
c) Undelivered Energy for acknowledged Dispatch instructions.
10. ECONOMIC SIGNALS, REVENUE ALLOCATION, AND COST OBLIGATION
10.1. INTRODUCTION
Any discussion of revenue and cost allocation by the ISO must begin
with a clear understanding of the limitations the ISO faces in allocating costs
and revenues. The ISO deals directly only with Scheduling Coordinators (SCs) and
Participating Transmission Owners (PTOs). This means, for example, that when we
talk about assigning a specific cost obligation to loads within a specific LPA,
we really mean assigning the cost to SCs based on their load (metered or
scheduled) within that LPA. Whether or not the cost is actually assigned to
those customers depends on the business practices of the SC and its client
retailers (electric service providers or ESPs). These practices are generally
not known to the ISO, nor are they within its sphere of influence. The
underlying assumption, however, is that the methods used to allocate specific
costs and revenues to SCs and PTOs will create incentives for those entities
that are at least consistent with, if not exactly the same as, the incentives
those methods would create for consumers and producers if applied to them
directly. In the remainder of this section, we talk about assigning costs and
revenues to loads or generators with the understanding that the assignment is
really to SCs in the corresponding proportions.
On the subject of incentives, a key point to bear in mind when
assigning the legal obligation for payment for a given energy or capacity
product or grid service is that the money for all these payments ultimately
comes from revenues collected from final customers for their energy consumption.
The incentives created by cost and revenue allocation depend significantly on
which specific customers bear which specific costs. For example, assigning
Congestion charges to the users of a congested interface (loads on the import
side of the interface, or generators serving such loads from the opposite side)
will dramatically affect near-term consumption and production decisions as well
as the location decisions of new generators.
Closely intertwined with incentive effects is the principle of cost
causation, i.e., the principle that costs should be borne by entities that
contribute to creating those costs. The cost causation principle requires that
we avoid creating or perpetuating cross-subsidies from one segment of the market
to another. The principle is thus closely tied to the requirement that the ISO
provide open access to and nondiscriminatory pricing of transmission service, in
the sense that assigning costs caused by one segment of the market to another
segment would discriminate in favor of the subsidized segment. The cost
causation principle is particularly important in developing a robust competitive
market, because transferring cost obligations from those who cause the costs to
those who do not can change the competitive balance among these market
participants. Adhering to the cost causation principle is thus a necessary
element of creating effective market incentives.
Based purely on a consideration of economic signals and incentives we
would state the following principle: THE ASSIGNMENT OF OBLIGATIONS FOR PAYMENTS
AND RIGHTS TO REVENUES TO SUPPLIERS OF ENERGY, CAPACITY, AND GRID SERVICES AND
FINAL CONSUMERS OF ELECTRICITY SHOULD CREATE INCENTIVES FOR EFFICIENT OPERATION
OF AND INVESTMENT IN THE CALIFORNIA ELECTRICITY MARKET.
71
The question of cost and revenue allocation involves other factors,
however, which may require us to modify the result we would obtain from focusing
purely on incentives and cost causation. One of the most significant of these is
the fact that electric restructuring has created local market power situations
which did not exist under the previous regulated utility regime, and which
severely impact the consumers in particular geographic areas within the ISO
system. These market power situations result from the existence of physical
constraints in the transmission grid and the strategic locations of generators
with respect to those constraints. Under the regulated utility regime, local
market power was not an issue because of the vertically integrated structure of
the utilities.
Under the previous structure, the utility performed integrated planning
of generation and transmission to determine the most cost-effective combination
of capacity investments to undertake, with the assumption that the utility would
also be the operator of all generation and transmission facilities in its
control area. Under this structure, the regulatory paradigm ensured that any
geographic cost differentials due to grid constraints and generator locations
would not affect final consumers, and the system was designed and built with
this expectation.
Electric restructuring has changed the paradigm, however, so that
generation and transmission are now planned and operated independently, with
generation being a competitive market and transmission being a regulated
monopoly service. Electric restructuring thus created the potential for certain
generators to exercise market power because their locations made them essential
for reliability. To allocate the full costs of local reliability to the
consumers in constrained areas would in effect hold those consumers singularly
responsible for the local limitations of an electric network they had no
particular role in developing. One could argue, in this light, that the
principle of cost causation is not perfectly aligned with the objective of
creating accurate locational price incentives, because the causes of the costs
in question stem largely from the effect of electric restructuring on the
control and operation of the pre-existing transmission and generation facilities
in the California system.
At this time, this CMR proposal does not take a position on whether or
not it is appropriate to fully allocate locational costs and price differentials
to loads in congested areas. Rather, the intention is to describe and raise for
discussion the tradeoff between creating the most effective locational signals
versus interpreting cost causation in a historical light and applying an
alternative cost allocation scheme. The alternatives to be considered include:
1) Pure locational pricing, under which loads in a congested LPA would be
assessed any real-time energy price differential applicable to the LPA plus the
costs of both the LRS procurement and forward Congestion into the LPA; and, 2)
Various options for averaging prices to loads across larger areas.
In the following sections, we first present an overview table of the
pricing and cost and revenue allocation elements of this CMR proposal. Next, we
discuss locational price signals, and the effectiveness of the proposed local
reliability service (LRS) procurement in preserving locational price signals
while mitigating the market power associated with locational needs. Finally, we
discuss the linkages between CMR and the Long-term Grid Planning (LTGP) and New
Generator Interconnection Policy (NGIP) efforts, with emphasis on the
consistency of economic signals and incentives in all three areas.
72
10.2. SUMMARY OF PRICING AND ALLOCATION OF COSTS AND REVENUES
<Table>
<Caption>
REAL-TIME
- ------------------------------------------- --------------------------------------------------------------------------
Imbalance Energy, no actual or imminent Pricing and settlement as specified in Amendment 29 filing (10-minute
Congestion dispatch and settlement).
Actual or imminent Congestion on an LPAs will have different real-time energy prices.
Inter-LPA Pathway
Generators within each LPA will receive the applicable locational price.
Pricing for load deviations within the LPA to be determined; options are:
o Charge same LPA-specific-price that is paid to generators, or
o Average price over larger area
Actual or imminent violation of a Resources needed out-of-merit will be paid as bid (using bids submitted
constraint within an LPA at the time of LRS procurement) without affecting real-time MCP.
Allocation of incremental out-of-merit cost to be determined; options are:
o To loads, within the LPA or averaged over a larger area, or
o To the PTO
DAY-AHEAD AND HOUR-AHEAD
- ------------------------------------------- --------------------------------------------------------------------------
Congestion Charges for Inter-LPA As today, charges determined by Adjustment Bids, assessed to SCs per
Pathways MWh scheduled flow across congested pathways.
Revenues allocated to:
o FTR holders for capacity equal to auctioned amount of FTRs, and
o PTOs. loads in congested areas, or transmission upgrade fund, for
any NFU capacity allocated in excess of auctioned amount of FTRs.
Recallable Transmission Service Charges based on Adjustment Bids used (i.e., flows curtailed) in
allocating firm transmission in CONG, and assessed to SCs per MWh
scheduled flow across congested pathway.
Revenues allocated to PTOs/ETC rights holders.
TWO-DAY-AHEAD
- ------------------------------------------- --------------------------------------------------------------------------
Local Reliability Service (LRS) Auction Payment to selected resources per MW of committed capacity.
Allocation of costs to be determined; options are:
o To loads, within the LPA or averaged over a larger area, or
o To the PTO
WAY AHEAD
- ------------------------------------------- --------------------------------------------------------------------------
FTR Auctions - long-term and monthly Revenues to be allocated to relevant PTOs, loads in congested areas, or
transmission upgrade fund.
</Table>
73
10.3. ECONOMIC SIGNALS IN THE PROPOSED PRICING AND COST ALLOCATION METHODS
The concept of accurate locational prices has two distinct aspects.
Locational price differentials:
1) Should reflect differences in the cost of delivered energy
imposed by the physical locations of generating resources and
loads with respect to constraints in the transmission grid;
and
2) Should not be inflated by the exercise of locational market
power.
The discussion below explains how this proposal, by using real-time
operating requirements as a starting point for procuring locational resources
and managing Congestion on a forward basis, creates accurate locational price
signals for generation production and investment decisions. In addressing aspect
2, above, it uses a transparent mitigation mechanism that separates locational
market power mitigation from the pricing of competitive energy and Ancillary
Services, consistent with the California design principle of separating the
monopoly transmission service from the competitive Forward Energy markets.
10.3.1. FEASIBILITY OF SCHEDULES
Significant opportunities to profit from market power exercise have
emerged under the ISO's current CM protocols, particularly due to the fact that
final schedules may contain constraint violations that render them infeasible in
real time. The proposed CM protocols differ from the current ones in explicitly
utilizing the best available information on expected loads, transmission
constraints, and generation unit status, to procure in forward markets the local
resources that will be needed for reliable real-time operation. Under the
proposed protocols, if there is no difference between scheduled and actual load
and generation, and no unplanned transmission line de-ratings or generating unit
outages, then all final forward schedules will be feasible in real-time without
violating transmission constraints.60 Moreover, even if load and generation
substantially under-schedule, the ISO's procurement of Local Reliability Service
(LRS) will be adequate to ensure real-time compliance with the applicable local
reliability criteria. Under this CMR proposal, real-time feasibility of forward
schedules is ensured by explicitly honoring the OPs and nomograms used in
real-time operations in establishing final Forward Energy schedules. Thus, the
proposed CM approach will eliminate one source of market power exercise that
could otherwise distort locational prices.
10.3.2. LOCATIONAL PRICE SIGNALS
There are three sources of locational price signals under the CMR
proposal:
1) The LRS procurement will offer hourly payments to generating
resources for providing scheduled energy and additional
available capacity;
2) Forward Congestion (Day-Ahead and Hour-Ahead) between LPAs
will result in a usage charge for moving energy across
congested pathways; and,
3) Real-time Congestion between LPAs will result in different
imbalance energy prices, possibly for all LPAs in any given
10-minute interval.
LRS PROCUREMENT. The LRS procurement proposed in this CMR package
effectively separates the cost of mitigating locational market power from the
pricing of energy. The resource supplying QLRS MW
- ----------
60 As noted previously, in the forward scheduling time-frame "feasibility"
is ensured with regard to transmission constraints only. In the forward
markets, the ISO does not assess whether generating units are capable
of performing to meet their hourly schedule changes. In the real-time
market, however, the optimal power flow model used for real-time
dispatch takes account of generator performance capabilities as well as
transmission constraints to ensure feasibility from both perspectives.
74
of LRS capacity will be paid a capped price PLRS per MW, in return for the
commitment to submit a Day-Ahead schedule for a portion Qmin of that capacity,
and an uncapped energy bid that will apply to the remaining capacity (QLRS -
Qmin). Once this resource is selected, its energy bid must remain unchanged
through real time, even if the resource bids into and is selected to provide
A/S.61 For any capacity above QLRS, the unit is of course free to schedule and
bid as it chooses. For the scheduled Qmin MWh, the unit is also free to earn
whatever energy price it can obtain as long as it shows up in a Day-Ahead
schedule. Thus, it can bid into the PX as a price taker or enter a bilateral
agreement, for example, a long-term contract with load within the congested LPA
that requires the unit's reliability service.
The amount (QLRS * PLRS) may be interpreted in several ways. First and
foremost, it is the cost of obtaining unit commitment from a generating resource
that it is known will be needed in real time for local reliability. It is also,
however, the compensation paid to the resource for its local market power. This
compensation will not be unlimited, however, as the proposal is to set a bid cap
on PLRS for each LPA to mitigate local market power, but to set it at a high
enough level to ensure that the LRS capacity payment provides a meaningful
locational price signal.
By separating the cost of local market power mitigation from the
pricing of competitive energy, the LRS mechanism for mitigating local market
power eliminates the need for cost-based caps on bids into the real-time energy,
A/S, and forward CM markets. Because the retail rate freeze is still in force in
the PG&E and SCE service territories, there is a strong economic argument for
keeping a damage control price cap on these markets. At the same time, because
the best estimates of the real-time nomogram constraints are honored in
constructing Day-Ahead energy schedules, there is a very small likelihood that a
unit will be able to exercise its local market power in real-time. Because the
energy bids associated with LRS capacity are fixed for the Trading Day at the
time the LRS capacity is procured, the unit owner faces a high risk of not being
dispatched if its energy bid is set extremely high with the idea of exploiting
market power in real time. By eliminating all bid caps except a uniform damage
control cap, the possibility still exists for generators to earn very high
energy prices when there is system-wide scarcity of generation capacity.
However, the presence of the LRS market with its bid caps prevents any unit
owner from leveraging its local market power to the larger zonal or state-wide
energy market.
On the load side of the price signal question, one view of transmission
upgrade incentives suggests that the entities with the greatest incentive to
reinforce the grid in costly LPAs will be the loads inside those LPAs. The pure
economics suggests, then, that in order to provide the appropriate locational
price signals to loads, loads in each LPA should be liable for all LRS payments
for that LPA in addition to any forward and real-time differentials in the cost
of energy. In order for loads to be willing to support transmission upgrades and
new generation in their area, they must see a significant benefit, i.e., a
reduction in the cost of delivered electricity in their LPA through the
reduction of these locational costs. Under this cost allocation scheme, loads
will benefit from both transmission upgrades and new generation entry through
lower LRS payments and locational energy prices. As noted above, however, this
purely economic view needs to be balanced against the fact that the loads in
constrained LPAs have inherited a market power problem that did not exist when
the regulated utilities owned and controlled all the local reliability
resources. Since electric industry restructuring created the present market
power potential, it may well be in the collective interests of the market to
spread some of the mitigation costs over larger geographic areas.
- ----------
61 To prevent double payment, the unit would forfeit the LRS capacity
payment for any portion of committed LRS capacity that was accepted in
the A/S auctions.
75
FORWARD CONGESTION CHARGES AND LOCATIONAL REAL-TIME IMBALANCE ENERGY
PRICES. Even though the LRS market guarantees that sufficient local energy is
scheduled on a forward basis to achieve system-wide feasibility of final energy
schedules, the CM process can still result in a positive price for the use of
transmission capacity between adjacent LPAs. This is clearly true for major
internal interfaces (Paths 15 and 26) and the interties, for which there would
be no LRS procurement. For the new LPAs created based on local reliability areas
(LRAs), Congestion in the forward market would be infrequent, but could occur in
Hour-Ahead when line de-ratings and generation unit outages occur after the
Day-Ahead market. In these cases, SCs with scheduled flows across these
interfaces would be assessed the usage charge.
Similarly, real-time Congestion between LPAs can occur simply due to
uninstructed deviations, as well as to forced outages and line de-ratings. When
such Congestion occurs, the optimal power flow model used for real-time dispatch
will create locational real-time prices, which potentially can differ in each
LPA and each 10-minute interval. These prices will represent location-specific
costs to real-time deviations in each LPA.
10.3.3. UNRESOLVED ISSUES
SUNSET OF BID CAPS FOR LRS. One way to reinforce the incentive effect
of locational prices is to phase out the bid caps on the LRS market over time,
in order to stimulate new generation investment and transmission upgrades at
locations with the most severe local market power problems. In effect, the
locational price signal of the LRS procurement is strengthened by an explicit
provision for sunset of the LRS bid caps after the minimum number of years
necessary for new generation to enter or transmission to be upgraded, or
somewhere between two and four years after the implementation of the new LPA. An
explicit pre-set end date for bid caps on the LRS market increases the urgency
for loads to undertake new transmission and generation investments or sign
long-term forward financial contracts with local generation for the provision of
the LRS services. Without this end date and the associated risk of facing very
high future LRS costs, loads will have little incentive to take the steps
necessary to eliminate the local market power that led to the imposition of bids
caps on the local LRS market.
SYMMETRIC TREATMENT OF GENERATORS AND LOADS. The potential for high
zonal energy prices also creates incentives for loads to make the investments
needed to become more price-responsive. As loads become more price-responsive,
the distinction between load and generation becomes less clear; i.e., a load
that can credibly respond to Day-Ahead and real-time energy prices is not very
different from a generating unit. For this reason, it may be important to treat
load and generation the same way in the redesigned CM process. For example,
rather than allowing loads to schedule anywhere within a given LPA or demand
zone, perhaps the ISO should require loads to schedule at the transmission grid
bus level, as generation units currently do. Symmetric treatment of load and
generation will better allow the ISO to manage the entry of behind-the-meter
distributed generation facilities that serve the on-site needs of industrial
customers. The presence of more customers with this sort of price-responsiveness
will significantly enhance the competitiveness of the ISO's markets.
10.4. LINKAGES BETWEEN CONGESTION MANAGEMENT REFORM, LONG-TERM GRID PLANNING,
AND NEW GENERATION INTER-CONNECTION POLICY
As part of this comprehensive Congestion Management Reform (CMR)
effort, the ISO must develop explicit linkages with Long-Term Grid Planning
(LTGP) and New-Generator Inter-connection Policy (NGIP). All three are
complementary aspects of the ISO's mission of providing a reliable transmission
76
infrastructure to support the competitive electricity market. All three must
therefore incorporate consistent economic signals and incentives, and must
represent a unified approach in delineating the optimal boundary between those
activities best suited to the competitive market and those belonging to the
regulated monopoly transmission function.
This section describes how the linkages between CMR, LTGP, and NGIP are
currently being thought of in the context of the CMR effort. The discussion
takes, as a point of departure, the fundamental objectives of electric
restructuring and principles of the California design approach that were
presented in Sections 3 and 4 of this proposal. For the sake of brevity we do
not restate those ideas here.
10.4.1. LONG-TERM GRID PLANNING
In thinking about the effectiveness of incentives in the context of
LTGP and NGIP, there are certain basic questions we must raise.
First, do we believe that in the near-to-medium term there will be
sufficient economic incentives (i.e., anticipated Congestion and wheeling access
charge revenues, FTR auction revenues, etc.) accruing to the potential
transmission investor to obtain adequate grid expansion to support an efficient,
competitive generation market?
If not, the next logical question is how to refocus LTGP activities and
efforts to best support the ISO's mission of providing a reliable grid with
adequate capacity to accommodate all users of the grid, rather than perpetuating
an expectation that we can rely on the market to expand the grid to meet the
transmission infrastructure needs of the competitive market. A related question
is whether we should abandon the possibly unproductive distinction between
"reliability" and "economic" transmission upgrades, and re-direct our efforts
toward establishing a reliable "interstate highway" transmission system that
will facilitate a broad regional energy market.
Alternatively, if we believe there is or can be a market for
transmission upgrades, how do we facilitate such a market in the near term and
create sufficient incentives to ensure that transmission facilities do not
become a bottleneck to competition in generation?
Second, regardless of how we answer the first question, we need to ask
whether transmission, generation, and demand-based projects can compete on an
equal basis, i.e., provide equally effective solutions to transmission system
expansion needs. We suspect the answer will depend on the type of project being
considered; for example, a project that serves only local reliability needs,
versus one that provides benefits to the system as a whole. In any event, if the
answer is affirmative for any type of project, we must ask how the ISO can
subject these alternatives to a fair and objective comparative evaluation.
At this juncture, we remain unconvinced that the market will step
forward to expand the grid to meet the needs of the still-developing competitive
generation market. Nor do we see an established process and authority for
ensuring that transmission facilities are expanded as needed to support the
fundamental restructuring objective of creating a robust competitive generation
market. We believe, therefore, that it is essential for the ISO to assume a
proactive role in ensuring that the transmission system can accommodate all
current and prospective users and can be operated in a reliable and efficient
manner. In addition, we believe that the ISO should ensure access to the
transmission system by new entrants, which requires reducing potential barriers
to entry and providing reasonable ex ante certainty to potential new entrants
regarding their costs of connecting to and utilizing the transmission grid. The
remainder of this section articulates and expands upon these principles.
PRINCIPLE 1: THE ISO SHOULD TAKE A PROACTIVE ROLE IN ENSURING THAT THE
ISO CONTROLLED GRID IS EXPANDED IN A MANNER THAT SATISFIES THE ISO'S GRID
PLANNING AND OPERATING CRITERIA.
77
Earlier in this section, we discussed the fact that the restructured
electricity market inherited a grid system that was designed under a different
set of incentives than those of the restructured industry. As a result, we face
a tradeoff between economic efficiency and historical cost causation in trying
to implement strong economic incentives for loads in constrained areas to
sponsor grid upgrades, particularly in areas where there is high reliance today
on RMR resources, and where there will be high costs for LRS procurement under
this CMR proposal.
We believe, therefore, that the ISO should, in conjunction with the
PTOs, develop an integrated plan for the state that ensures that the ISO
Controlled Grid satisfies the ISO's Grid Planning Criteria and reduces the need
for local reliability generating resources. Part of the LTGP process approved by
the ISO Governing Board last year is consistent with that approach. Part I of
the two-part planning process approved by the Board provided that the ISO will
develop an integrated transmission plan for the entire ISO Controlled Grid.
Development of the integrated plan would provide a means for the ISO to ensure
that the grid is configured and expanded in a manner consistent with Principle
1.
PRINCIPLE NO. 2: THE ISO SHOULD TAKE A PROACTIVE ROLE IN IDENTIFYING
AND EXPANDING CONSTRAINED AREAS OF THE GRID IN ORDER TO ENSURE A RELIABLE AND
EFFICIENT REGIONAL TRANSMISSION NETWORK THAT WILL FACILITATE GENERATION
COMPETITION IN CALIFORNIA AND ACCESS TO REGIONAL ENERGY MARKETS.
The ISO should proactively expand the grid and ensure that the grid is
reliable and can accommodate all market participants, including new resources
wishing to interconnect to the system. We believe that such an approach will
ensure that the grid will be expanded in a manner that is reliable and that will
support the needs of the market. This approach is consistent with: 1) The ISO's
TAC filing, which provides for the transition to an ISO grid-wide Access Charge
for the high-voltage transmission system; and, 2) The vision of a high-voltage
interstate transmission system that is administered by one or more Regional
Transmission Organizations for the western interconnection. This approach is
also consistent with the concept, upon which the TAC filing was based, that the
high-voltage transmission network and enhancements to it have system-wide
benefits that in many instances cannot be readily quantified, much less captured
by a potential private investor. It may therefore be incumbent on the ISO to
take the lead, at least for projects that offer clear system-wide benefits.
Moreover, we believe that such an approach is practical and realistic
given the current lack of incentives (and the presence of disincentives) for
market participants to step forward and build transmission. We recognize that
this approach, by placing leadership responsibility for grid expansion upon the
ISO, may reduce or eliminate the incentives for market participants in
high-price areas from stepping forward to expand the grid. In other words, if
market participants know that the ISO will ensure that facilities are built,
then they will not do so. As noted above, however, the system-wide benefits
inherent in such upgrades may make it inappropriate to rely completely on local
incentives to induce the needed investments.
10.4.2. NEW-GENERATOR INTERCONNECTION POLICY
Similar to LTGP, the optimal specification of a NGIP is highly
dependent on the outcome of the policy issues raised above. If the ISO's goal is
to ensure a reliable, efficient, and robust transmission system to facilitate a
competitive generation market, it needs a NGIP policy that ensures access to a
reliable grid at minimum cost, i.e., one that reduces barriers to entry.
Alternatively, a more limited role for the ISO in grid expansion may require
that new generators wishing to interconnect to the system be responsible for
certain grid upgrades beyond those required for direct connection, and may
create greater uncertainty about what those costs will be. The pros and cons to
each approach need to be fully debated.
78
We believe, however, that there are certain guiding principles, consistent with
this CMR proposal, that should be followed in developing a NGIP to further the
goals of restructuring and to facilitate the addition of new capacity to the
California market.
PRINCIPLE 3: THE ISO SHOULD TAKE A PROACTIVE ROLE IN ENSURING THAT EACH
NEW OR REPOWERED GENERATOR OR RESOURCE IS ABLE TO INTERCONNECT TO THE GRID WITH
MINIMAL INTERCONNECTION COSTS, THEREBY ENSURING ACCESS TO THE MARKET AND
REDUCING POTENTIAL BARRIERS TO ENTRY.
This approach would require that the ISO and the PTOs collaboratively
plan and enhance the transmission system to accommodate new entrants. The cost
of new transmission upgrades or expansions, even those whose primary purpose is
to accommodate new entrants (with the exception of the direct connections of new
units to the grid), would then be paid by all transmission customers (load)
within the ISO system. Under this approach, the ISO and the PTOs would actively
identify and plan transmission system upgrades needed to eliminate bottlenecks
on the system when those upgrades are economically justified (for example, when
Congestion would essentially negate any net additional generation capacity the
new entrant would bring to the market by placing it into direct competition with
existing generation for the same limited transmission capacity).
This approach ensures that resources are able to interconnect to the
grid at reasonable and predictable costs, thereby reducing barriers to entry and
potentially lowering overall energy costs by increasing market liquidity. We
believe that this approach is consistent with the fundamental objective of
restructuring: to guarantee open and non-discriminatory access to the
transmission system in order to facilitate a competitive generation market. This
approach places the burden of planning and expanding the grid on the ISO and the
PTOs and their customers. At the same time, we recognize that an approach
whereby the costs of all economic transmission upgrades are rolled-in may not
provide strong incentive for new generators to locate in areas where
interconnection costs, including those beyond the first point of
interconnection, will be minimal.
PRINCIPLE 4: THE ISO SHOULD PROVIDE NEW ENTRANTS WITH REASONABLE EX
ANTE PRICE CERTAINTY REGARDING THEIR COSTS OF INTERCONNECTING TO AND UTILIZING
THE ISO CONTROLLED GRID.
A number of Market Participants have previously stated that ex ante
price certainty is a critical issue for them. In terms of obtaining the
necessary financing for their projects, project developers have stated that they
need to know, up front, what kinds of costs (type and level) they are likely to
be responsible for when interconnecting to the ISO Controlled Grid. It is fairly
easy to provide new entrants with an accurate estimate of direct-connection
costs, and such estimates are routinely provided as part of performing the
required system-impact and facility studies. It is not as easy to provide new
entrants with an accurate estimate of Congestion costs. The provision of FTRs
(and their availability in the secondary market) can help provide new entrants
with the necessary price certainty, at least with respect to potential
transmission Congestion costs. One complication is that the interconnection of
the new generator may, by changing the configuration of the network and the
relevant Operating Procedures and nomograms, create Congestion on a path that
was not previously designated for Congestion Management and FTRs.
79
11. FERC'S ORDER 2000
11.1 ORDER NO. 2000 AND CONGESTION MANAGEMENT - FERC's most recent and
comprehensive statement on CM by regional transmission organizations (RTOs),
which could include ISOs, is found in its Order No. 2000.62 In Order No. 2000,
the Commission described the requirements for an RTO's CM approach. It stated
that an RTO must ensure the development and operation of market mechanisms to
manage Congestion. It used the word "ensure" because the RTO may either develop
and operate these mechanisms itself, or delegate these responsibilities to a
separate entity not affiliated with any Market Participant.63 The Commission
found that market mechanisms were superior to various administrative curtailment
procedures that fail to take into account the value of different transactions.64
The market mechanisms developed must be closely coordinated with the RTO's
day-to-day and moment-to-moment operational activities.65 The RTO's CM market
may be operated on either a centralized or decentralized basis.66 Any acceptable
CM market would need to include a mechanism to provide customers with efficient
price signals regarding the consequences of their transmission use decisions.
Additionally, any proposals for Congestion pricing should provide that:
o "[G]enerators that are dispatched in the presence of transmission
constraints are those that can serve system loads at least cost."
o "[L]imited transmission capacity is used by Market Participants that
value that use most highly."67
The key criteria laid down in Order 2000 for a CM system are thus:
o Relying on market-based mechanisms
o Promoting efficient use of the grid by entities that place the highest
value on that use
o Sending accurate price signals to encourage efficient expansion of the
grid to relieve Congestion
The Order does not prescribe a specific Congestion pricing method,
noting that the particular circumstances of an individual RTO will dictate the
method best suited for it.68 Nonetheless, the Order makes it clear that FERC
views locational marginal pricing ("LMP") with particular favor. This is the
method most closely identified with the Pennsylvania-New Jersey-Maryland ISO
("PJM") and, with the California ISO's Inter-Zonal Congestion Management,. FERC
found:
LMP assesses congestion charges directly to transmission customers in a
manner consistent with each customer's actual use of the system and the
actual dispatch that its transactions cause. In addition, LMP
facilitates the creation of financial transmission
- ----------
62 Regional Transmission Organizations, Order No. 2000, FERC Stats. and
Regs.P. 31,089 (December 20, 1999), order on reh'g, Order No. 2000-A,
90 FERCP. 61,201 (February 25, 2000) ("Order 2000"). In an order on the
Southwest Power Pool ISO proposal issued on May 17, 2000, the
Commission reiterated the CM criteria it had developed in Order No.
2000. See Southwest Power Pool, 91 FERCP. 61,137 (2000), slip op. at
11.
63 Order 2000 at 31,126.
64 Id.
65 Id.
66 Id.
67 Order 2000 at 31,109.
68 Order 2000 at 31,127.
80
rights, which enable customers to pay known transmission rates and to
hedge against congestion charges.69
FERC acknowledged, however, that LMP could be "costly and difficult to
implement", and might be more suitable for entities that were formed from
pre-existing tight power pools.
FERC did not reject out of hand the method it termed the principal
alternative to LMP, i.e., the trading of physical transmission rights in a
secondary market. FERC speculated that such an approach might work "in regions
where congestion is minor or infrequent".70
With regard to physical curtailment, FERC stated that while the RTO
must have the ability to curtail transmission transactions at times when the CM
market fails to achieve favorable results, the Commission would not require an
RTO to redispatch any Generation solely for the purpose of managing
Congestion.71 Finally, FERC decided that while an RTO must have "effective
protocols for managing congestion" in place at its startup, it would allow the
RTO one year after startup for implementation of the market mechanisms required
by the Order.72
11.2 ORDER NO. 2000 AND INTERREGIONAL COORDINATION - FERC's vision in order no.
2000 is clearly one in which the transmission systems of entire regions or
interconnections are overseen by a single RTO. A single RTO for an entire
interconnection would ensure that access to the transmission systems in that
region was open and provided under a consistent and uniform set of terms and
conditions. Moreover, a single RTO could, while recognizing state-by-state
differences, ensure a seamless market interface within the region. Obviously,
while all affected parties should aggressively pursue the creation of such an
entity, it is necessary to ensure that all interim proposals are developed so as
to recognize and reflect the need for interregional coordination. As FERC
stated, "coordination activities among regions is a significant element in
maintaining a reliable bulk transmission system and for the development of
competitive markets."73
In Order No. 2000, FERC required RTOs, "to develop mechanisms to
coordinate its activities with other regions whether or not an RTO exists in
these other regions"74 and stated that, "We expect the RTO to work closely with
other regions to address inter-regional problems and problems at the 'seams'
between the RTOs."75 (Note: Usually a quote within a quote is set off with
apostrophes.) Specifically, FERC stated that the eighth functional requirement
of an RTO is:
(8) Interregional Coordination: The Regional Transmission Organization
must ensure the integration of reliability practices within an
interconnection and market interface practices among regions.76
Recognizing this requirement and the basic necessity of interregional
coordination, it is imperative that the ISO and Market Participants consider, as
part of developing a comprehensive CMR proposal, the initiatives currently
underway in neighboring regions such as the desert Southwest, the Pacific
Northwest, and Nevada. While FERC's eighth functional requirement requires both
the integration of reliability
- ----------
69 Id.
70 Order 2000 at 31,127.
71 Id.
72 Id. at 31,128.
73 Id. at Order 2000 at 31,167
74 Id.
75 Id.
76 Id.
81
requirements and market interface practices, we focus on the latter in this
discussion. While more work must certainly be done regarding the integration of
reliability practices in the West, until the formation of an RTO for the Western
interconnection, we believe the appropriate forum for addressing this issue is
the WSCC and its various subcommittees.
As outlined in its draft tariff, Desert STAR, the transmission
organization forming in the desert Southwest, is proposing to implement a system
based primarily on physical rights, whereby a transmission user will be required
to have a FTR to schedule energy over transmission paths. As we understand their
proposal, the Southwest does not intend to create a formal Energy exchange, but
instead to place a heavy emphasis on and facilitate a liquid bilateral market.
On a fundamental level, we believe this approach is fully consistent with
California's decentralized market-design approach. Moreover, while the Southwest
appears to be heading towards implementing a physical-rights transmission
system, we believe their basic approach is compatible with this proposal. As we
explained in Section 7.2, we propose to issue 100% FTRs with a physical
scheduling priority feature. The purpose of our FTR-design approach is to
emphasize and facilitate forward-market management of transmission by SCs. While
the CMR proposal does not propose to require FTRs for scheduling transmission,
as does the Southwest, we believe the conceptual approach is similar and
compatible.
We are less clear as to what type of Ancillary Service (AS) markets the
Southwest intends to implement. However, AS markets must be structured at a
minimum to provide certain basic services, such as Regulation and Operating
Reserve. Moreover, whether the Southwest implements a daily auction for AS or a
longer-term bilateral market, we believe their AS markets will be compatible
with California's.
Similar to the Southwest, Nevada has proposed a structure that places a
heavy emphasis on a decentralized bilateral market. As expressed in the Mountain
West Independent System Administrator's (MWISA) tariff filing at FERC, Nevada
proposes to rely heavily on a market for FTRs for transmission service. In light
of Nevada's possible participation in the Pacific Northwest's initiative to form
a regional transmission organization, we believe it is premature to focus on
their efforts.
We believe it is also premature to focus too heavily on the efforts of
the Pacific Northwest's initiative (RTO West). While the formation of RTO West
is proceeding, that initiative has not progressed to the point where it has
specified its preferred or recommended method for providing transmission
service, including CM. The ISO and Market Participants must continue to evaluate
how this CMR package relates to these other initiatives as the form and nature
of the market structures develop in the Northwest and Southwest.
11.3 ORDER NO. 2000 AND THE RECOMMENDATION PACKAGE - An important consideration
in crafting a CMR recommendation is whether the proposed package satisfies the
basic requirements of Order No. 2000. As noted above, any cm system must ensure
that scarce transmission is used by those that value its use most highly and
that those generators that are dispatched in the presence of transmission
constraints are those that can serve system loads at least cost. We believe that
the recommendation outlined above satisfies these basic requirements.
First, FERC stated that CM mechanisms developed "must be closely
coordinated with the RTO's day-to-day and moment-to-moment operational
activities." The recommendation package outlined in Sections 6 through 9 is
rooted in the ISO's real-time operational requirements and the tools used by the
operators to ensure a reliable transmission system. As explained in Sections 3
and 4, this is the critical underpinning of the ISO's draft recommendation
package. Secondly, the recommendation package provides that all significant
transmission constraints will be modeled and priced. Therefore, scarce
82
transmission capacity will be allocated to those that value it most highly;
i.e., transmission will be allocated to those SCs that value the transmission
the most, as expressed through Adjustment Bids.
As explained in Section 8, the combination of the proposed LRS
procurement and the revised DA CM process will ensure that the Generation
dispatched in the presence of Congestion is adequate to serve system Load at
least cost (as represented by the bids submitted by SCs), recognizing
operational reality. That is, the proposed LRS procurement methodology will
ensure that the resources necessary to operate the system reliably within LRAs
will run and that, combined with the proposed DA CM process, will ensure that
all incremental Load above that served by the LRS resources will be served by
the most economical resources, as expressed by their bids to supply and the
value they place on use of the transmission system through Adjustment Bids. As
further detailed in Section 10, constructing markets around an accurate
representation of operational requirements will create the appropriate price
signals for grid and resource investment. As required by Order No. 2000, the ISO
and Market Participants will continue to monitor the market developments in
neighboring regions to assess whether the ISO's CMR package is compatible with
these other markets.
12. CONCLUSION
The Congestion Management reform recommendation contained in this
document was developed to systematically address known deficiencies in the ISO's
CM process. By constructing markets around an accurate representation of
operational requirements, we believe that this market re-design corrects these
deficiencies, providing accurate, strong locational price signals. That is, it
results in prices that reflect differences in the cost of delivering energy
imposed by the physical locations of generating resources and loads with respect
to constraints in the transmission grid, and that are not inflated by the
exercise of locational market power. These are the price signals that give
Market Participants the incentive to behave in a manner that is consistent with
the CAISO's operational requirements, enabling the CAISO to accomplish its core
function through markets: providing open, non-discriminatory, and reliable
transmission service.
The recommendation package also relies heavily on certain tenets of
California restructuring - emphasizing decentralized decision-making and relying
on SCs to self-manage in the forward markets. Therefore, the proposal requires
the ISO to publish and provide as much information as possible to facilitate
market transactions, recognizing that absent such information, the market will
be forced to rely on the ISO to consummate trades.
We cannot over-emphasize the importance of stakeholder participation in
this process as we move forward. The elements of this package were created and
developed by and/or with stakeholders over the last several months. These ideas
have either taken the form of complete reform proposals or options for reforming
certain elements. As we move forward on CM reform, it is essential that we
incorporate and reflect on the feedback the ISO receives on this proposal from
Market Participants. The final recommendation on CM reform must be workable from
a Market Participant perspective.
Finally, as we move forward on drafting and finalizing the CM reform
recommendation, we must consider the impact and compatibility of such a proposal
on neighboring regions. We all recognize the importance of creating a seamless
market in the West. If we create a package that is not compatible with the other
transmission systems and market institutions in the West, we have done nothing
to further the development of a truly expansive competitive Energy market. The
ISO's proposal must ultimately be sustainable before FERC and therefore satisfy
the basic requirements of Order No. 2000.
83
APPENDIX A - TERMINOLOGY AND ACRONYMS
The following is a glossary of terms and acronyms used in the Congestion
Management Reform recommendations package. Terms and definitions in plain text
are excerpted from the Master Definitions Supplement, Appendix A to the ISO
Tariff. Terms, definitions, and acronyms in italics are specific to this
proposal. In certain instances, an additional definition (in italics) is
provided for terms already defined in the ISO Tariff in order to provide the
reader with additional information on how those terms are used in the context of
this proposal.
ACCESS CHARGE A charge paid by all UDCs, MSSs and, in
certain cases, Scheduling Coordinators,
delivering Energy to Gross Load, as set
forth in Section 7.1. The Access Charge
includes the High Voltage Access Charge, the
Transition Charge and the Low Voltage Access
Charge. The Access Charge will recover the
Participating TOs' Transmission Revenue
Requirement in accordance with Appendix F,
Schedule 3. A Participating TO that has no
transmission customers need not develop an
Access Charge.
ACE Area Control Error
ACTIVE ZONE The Zones so identified in Appendix I to the
ISO Tariff.
ADJUSTMENT BID A bid in the form of a curve defined by (i)
the minimum MW output to which a Scheduling
Coordinator will permit a resource
(Generating Unit or Dispatchable Load) to be
redispatched by the ISO; (ii) the maximum MW
output to which a Scheduling Coordinator
will permit the resource to be redispatched
by the ISO; (iii) up to a specified number
of MW values in between; (iv) a preferred MW
operating point; and (v) for the ranges
between each of the MW values greater than
the preferred operating point, corresponding
prices (in $/MWh) for which the Scheduling
Coordinator is willing to increase the
output of the resource and sell Energy from
that resource to the ISO (or, in the case of
a Dispatchable Load, decrease the Demand);
and (vi) for the ranges between each of the
MW values less than the preferred
Appendix A, Page 1
operating point, corresponding prices (in
$/MWh) for which the Scheduling Coordinator
is willing to decrease the output of the
resource and purchase Energy from the ISO at
the resource's location (or, in the case of
a Dispatchable Load, increase the Demand).
This data for an Adjustment Bid must result
in a monotonically increasing curve.
ADS Automated Dispatch System
AGC (AUTOMATIC GENERATION CONTROL) Generation
equipment that automatically responds to
signals from the ISO's EMS control in real
time to control the power output of electric
generators within a prescribed area in
response to a change in system frequency,
tieline loading, or the relation of these to
each other, so as to maintain the target
system frequency and/or the established
interchange with other areas within the
predetermined limits.
ANCILLARY SERVICES Regulation, Spinning Reserve, Non-Spinning
Reserve, Replacement Reserve, Voltage
Support and Black Start together with such
other interconnected operation services as
the ISO may develop in cooperation with
Market Participants to support the
transmission of Energy from Generation
resources to Loads while maintaining
reliable operation of the ISO Controlled
Grid in accordance with Good Utility
Practice.
APPLICABLE RELIABILITY CRITERIA The reliability standards established by
NERC, WSCC, and Local Reliability Criteria
as amended from time to time, including any
requirements of the NRC.
A/S OR AS Ancillary Services, as defined in the ISO
Tariff.
ATC Available Transfer Capability, as defined in
the ISO Tariff.
Appendix A, Page 2
AVAILABLE TRANSFER CAPACITY For a given transmission path, the capacity
rating in MW of the path established
consistent with ISO and WSCC transmission
capacity rating guidelines, less any
reserved uses applicable to the path.
AZC Intra-Zonal Congestion, as defined in the
ISO Tariff.
AZCM Intra-Zonal Congestion Management, as
defined in the ISO Tariff.
BALANCED SCHEDULE A Schedule shall be deemed balanced when
Generation, adjusted for Transmission Losses
equals forecast Demand with respect to all
entities for which a Scheduling Coordinator
schedules.
BEEP SOFTWARE The balancing energy and ex post pricing
software which is used by the ISO to
determine which Ancillary Service and
Supplemental Energy resources to Dispatch
and to calculate the Ex Post Prices.
CMR Congestion Management Reform
CONG The ISO's Congestion Management software
CONGESTION A condition that occurs when there is
insufficient Available Transfer Capacity to
implement all Preferred Schedules
simultaneously or, in real time, to serve
all Generation and Demand. "Congested" shall
be construed accordingly.
CONGESTION MANAGEMENT The alleviation of Congestion in
accordance with Applicable ISO Protocols and
Good Utility Practice.
CONSTRAINTS Physical and operational limitations on the
transfer of electrical power through
transmission facilities.
CONTINGENCY Disconnection or separation, planned or
forced, of one or more components from an
electrical system.
Appendix A, Page 3
CONTROL AREA An electric power system (or combination of
electric power systems) to which a common
AGC scheme is applied in order to: i) match,
at all times, the power output of the
Generating Units within the electric power
system(s), plus the Energy purchased from
entities outside the electric power
system(s), minus Energy sold to entities
outside the electric power system, with the
Demand within the electric power system(s);
ii) maintain scheduled interchange with
other Control Areas, within the limits of
Good Utility Practice; iii) maintain the
frequency of the electric power system(s)
within reasonable limits in accordance with
Good Utility Practice; and iv) provide
sufficient generating capacity to maintain
operating reserves in accordance with Good
Utility Practice.
CONVERTED RIGHTS Those transmission service rights as defined
in Section 2.4.4.2.1 of the ISO Tariff.
DA Day-Ahead, as defined in the ISO Tariff.
DAY-AHEAD Relating to a Day-Ahead Market or Day-Ahead
Schedule.
DAY-AHEAD MARKET The forward market for Energy and Ancillary
Services to be supplied during the
Settlement Periods of a particular Trading
Day that is conducted by the ISO, the PX and
other Scheduling Coordinators and which
closes with the ISO's acceptance of the
Final Day-Ahead Schedule.
DAY-AHEAD SCHEDULE A Schedule prepared by a Scheduling
Coordinator or the ISO before the beginning
of a Trading Day indicating the levels of
Generation and Demand scheduled for each
Settlement Period of that Trading Day.
Appendix A, Page 4
DEMAND The rate at which Energy is delivered to
Loads and Scheduling Points by Generation,
transmission or distribution facilities. It
is the product of voltage and the in-phase
component of alternating current measured in
units of watts or standard multiples
thereof, e.g., 1,000W=1kW, 1,000kW=1MW, etc.
DEMAND FORECAST An estimate of Demand over a designated
period of time.
DISPATCH The operating control of an integrated
electric system to: i) assign specific
Generating Units and other sources of supply
to effect the supply to meet the relevant
area Demand taken as Load rises or falls;
ii) control operations and maintenance of
high voltage lines, substations, and
equipment, including administration of
safety procedures; iii) operate
interconnections; iv) manage Energy
transactions with other interconnected
Control Areas; and v) curtail Demand.
EFFECTIVENESS FACTOR An Effectiveness Factor for a particular
resource and constraint is a number between
0 and 1 indicating the share of each MW
generated by the resource that will impact
the constraint. For example, if a 1 MW
increase in the output of Generator A causes
a 0.2 MW increase in the flow over
constraint B, the effectiveness of A with
respect to B is 0.2 or 20 percent.
EMS (ENERGY MANAGEMENT SYSTEM) A computer control system used by electric
utility dispatchers to monitor the real time
performance of the various elements of an
electric system and to control Generation
and transmission facilities.
END-USE CUSTOMER OR END-USER A purchaser of electric power who purchases
such power to satisfy a Load directly
connected to the ISO Controlled Grid or to a
Distribution System and who does not resell
the power.
Appendix A, Page 5
ENERGY The electrical energy produced, flowing or
supplied by generation, transmission or
distribution facilities, being the integral
with respect to time of the instantaneous
power, measured in units of watt-hours or
standard multiples thereof, e.g., 1,000
Wh=1kWh, 1,000 kWh=1MWh, etc.
ENERGY BID The price at or above which a Generator has
agreed to produce the next increment of
Energy.
ESP Electric Service Provider
ETC (EXISTING TRANSMISSION
CONTRACT) Synonymous with "Existing Contract," as
defined in the ISO Tariff.
EX POST PRICE The Hourly Ex Post Price or the BEEP
Interval Ex Post Prices.
EXISTING CONTRACTS The contracts which grant transmission
service rights in existence on the ISO
Operations Date (including any contracts
entered into pursuant to such contracts) as
may be amended in accordance with their
terms or by agreement between the parties
thereto from time to time.
FINAL DAY-AHEAD SCHEDULE The Day-Ahead Schedule which has been
approved as feasible and consistent with all
other Schedules by the ISO based upon the
ISO's Day-Ahead Congestion Management
procedures.
FINAL HOUR-AHEAD SCHEDULE The Hour-Ahead Schedule of Generation and
Demand that has been approved by the ISO as
feasible and consistent with all other
Schedules based on the ISO's Hour-Ahead
Congestion Management procedures.
FINAL SCHEDULE A Schedule developed by the ISO following
receipt of a Revised Schedule from a
Scheduling Coordinator.
Appendix A, Page 6
FTR (FIRM TRANSMISSION RIGHT) A contractual right, subject to the terms
and conditions of the ISO Tariff, that
entitles the FTR Holder to receive, for each
hour of the term of the FTR, a portion of
the Usage Charges received by the ISO for
transportation of energy from a specific
originating Zone to a specific receiving
Zone and, in the event of an uneconomic
curtailment to manage Day-Ahead congestion,
to a Day-Ahead scheduling priority higher
than that of a schedule using Converted
Rights capacity that does not have an FTR
FTR HOLDER The owner of an FTR, as registered with the
ISO.
FTR MARKET A transmission path from an originating Zone
to a contiguous receiving Zone for which
FTRs are auctioned by the ISO in accordance
with Section 9.4 of the ISO Tariff.
GENERATING UNIT An individual electric generator and its
associated plant and apparatus whose
electrical output is capable of being
separately identified and metered or a
Physical Scheduling Plant that, in either
case, is:
(a) located within the ISO Control
Area;
(b) connected to the ISO Controlled
Grid, either directly or via
interconnected transmission, or
distribution facilities; and
(c) that is capable of producing and
delivering net Energy (Energy in
excess of a generating station's
internal power requirements).
GENERATOR The seller of Energy or Ancillary Services
produced by a Generating Unit.
GMM (GENERATION METER
MULTIPLIER) A number which when multiplied by a
Generating Unit's Metered Quantity will give
the total Demand to be served from that
Generating Unit.
Appendix A, Page 7
GOOD UTILITY PRACTICE Any of the practices, methods, and acts
engaged in or approved by a significant
portion of the electric utility industry
during the relevant time period, or any of
the practices, methods, and acts which, in
the exercise of reasonable judgment in light
of the facts known at the time the decision
was made, could have been expected to
accomplish the desired result at a
reasonable cost consistent with good
business practices, reliability, safety, and
expedition. Good Utility Practice is not
intended to be any one of a number of the
optimum practices, methods, or acts to the
exclusion of all others, but rather to be
acceptable practices, methods, or acts
generally accepted in the region.
GRID OPERATIONS CHARGE An ISO charge that recovers redispatch costs
incurred due to Intra-Zonal Congestion in
each Zone. These charges will be paid to the
ISO by the Scheduling Coordinators, in
proportion to their metered Demand within,
and metered exports from, the Zone to a
neighboring Control Area.
HA Hour-Ahead, as defined in the ISO Tariff.
HOUR-AHEAD Relating to an Hour-Ahead Market or an
Hour-Ahead Schedule.
HOUR-AHEAD MARKET The forward market for Energy and Ancillary
Services to be supplied during a particular
Settlement Period that is conducted by the
ISO, the PX and other Scheduling
Coordinators which opens after the ISO's
acceptance of the Final Day-Ahead Schedule
for the Trading Day in which the Settlement
Period falls and closes with the ISO's
acceptance of the Final Hour-Ahead Schedule.
HOUR-AHEAD SCHEDULE A Schedule prepared by a Scheduling
Coordinator or the ISO before the beginning
of a Settlement Period indicating the
changes to the levels of Generation and
Demand scheduled for that Settlement Period
from that shown in the Final Day-Ahead
Schedule.
Appendix A, Page 8
HOURLY EX POST PRICE The price charged or paid to Scheduling
Coordinators Responsible for Participating
Generators and Participating Buyers for
Imbalance Energy in each Zone. The price
will vary between Zones if Congestion is
present. The Hourly Ex Post Price is the
Energy weighted average of the BEEP Interval
Ex Post Prices in each Zone during each
Settlement Period.
IMBALANCE ENERGY Imbalance Energy is Energy from Regulation,
Spinning and Non-spinning Reserves, or
Replacement Reserve, or Energy from other
Generating Units, System Units, System
Resources, or Loads that are able to respond
to the ISO's request for more or less
Energy.
INACTIVE ZONE All Zones which the ISO Governing Board has
determined do not have a workably
competitive Generation market and as set out
in Appendix I to the ISO Tariff.
INSTRUCTED IMBALANCE ENERGY The real time change in Generation output or
Demand (from dispatchable Generating Units,
System Units, System Resources or Loads)
which is instructed by the ISO to ensure
that reliability of the ISO Control Area is
maintained in accordance with Applicable
Reliability Criteria. Sources of Imbalance
Energy include Spinning and Non-Spinning
Reserves, Replacement Reserve, and Energy
from other dispatchable Generating Units,
System Units, System Resources or Loads that
are able to respond to the ISO's request for
more or less Energy.
INTER-LPA CONSTRAINTS Transmission system constraints that limit
flows between Locational Price Areas (LPAs)
in order to prevent violations of thermal,
stability, or voltage criteria.
INTER-SCHEDULING COORDINATOR Ancillary Service transactions between
ANCILLARY SERVICE TRADES Scheduling Coordinators.
Appendix A, Page 9
INTER-SCHEDULING ENERGY Energy transactions between Scheduling
COORDINATOR TRADES Coordinators.
INTER-ZONAL CONGESTION Congestion across an Inter-Zonal Interface.
INTER-ZONAL INTERFACE The (i) group of transmission paths between
two adjacent Zones of the ISO Controlled
Grid, for which a physical, non-simultaneous
transmission capacity rating (the rating of
the interface) has been established or will
be established prior to the use of the
interface for Congestion Management; (ii)
the group of transmission paths between an
ISO Zone and an adjacent Scheduling Point,
for which a physical, non-simultaneous
transmission capacity rating (the rating of
the interface) has been established or will
be established prior to the use of the
interface for Congestion Management; or
(iii) the group of transmission paths
between two adjacent Scheduling Points,
where the group of paths has an established
transfer capability and established
transmission rights.
INTERCONNECTION Transmission facilities, other than
additions or replacements to existing
facilities that: i) connect one system to
another system where the facilities emerge
from one and only one substation of the two
systems and are functionally separate from
the ISO Controlled Grid facilities such that
the facilities are, or can be, operated and
planned as a single facility; or ii) are
identified as radial transmission lines
pursuant to contract; or iii) produce
Generation at a single point on the ISO
Controlled Grid; provided that such
interconnection does not include facilities
that, if not owned by the Participating TO,
would result in a reduction in the ISO's
Operational Control of the Participating
TO's portion of the ISO Controlled Grid.
INTRA-ZONAL CONGESTION Congestion within a Zone.
ISO CONTROLLED GRID The system of transmission lines and
associated facilities of the Participating
TOs that have been placed under the ISO's
Operational Control.
Appendix A, Page 10
ISO HOME PAGE The ISO internet home page at
http://www.caiso.com or such other internet
address as the ISO shall publish from time
to time.
ISO MARKET Any of the markets administered by the ISO
under the ISO Tariff, including, without
limitation, Imbalance Energy, Ancillary
Services, and FTRs.
ISO TARIFF The California Independent System Operator
Corporation Operating Agreement and Tariff,
dated March 31, 1997, as it may be modified
from time to time.
LOAD An end-use device of an End-Use Customer
that consumes power. Load should not be
confused with Demand, which is the measure
of power that a Load receives or requires.
LOAD SHEDDING The systematic reduction of system Demand by
temporarily decreasing the supply of Energy
to Loads in response to transmission system
or area capacity shortages, system
instability, or voltage control
considerations.
LOCAL RELIABILITY CRITERIA Reliability criteria established at the ISO
Operations Date, unique to the transmission
systems of each of the Participating TOs.
LONG-FORWARD MARKETS Any market that occurs prior to the ISO's
Day-Ahead Markets (e.g., the proposed LRS or
Local Reliability Service market)
LOOP FLOW Energy flow over a transmission system
caused by parties external to that system.
LPA (LOCATIONAL PRICE AREA) A portion of the ISO Controlled Grid into
which the ISO system would be divided under
the CMR proposal for purposes of allocating
scarce transmission capacity in the forward
markets and for procuring real-time
Imbalance Energy and relieving real-time
Congestion.
Appendix A, Page 11
LPD Locational Price Dispersion
LRA (LOCAL RELIABILITY AREA) A portion of the ISO Controlled Grid that is
currently defined and used by the ISO for
assessing needs for local generation
services to support reliability, both on a
forward basis (e.g., for RMR designation and
Dispatch) and on a real-time basis (e.g.,
for identifying Intra-Zonal Congestion).
Operating Procedures and Nomograms are the
tools operators use to manage these LRAs in
real time.
LRS (LOCAL RELIABILITY SERVICE) A service which the ISO would procure under
the CMR proposal under which the ISO will
procure capacity and Energy in the
Long-Forward Markets and forward markets to
address local reliability needs
LTGP Long-Term Grid Planning
MARKET CLEARING PRICE The price in a market at which supply equals
Demand. All Demand prepared to pay at least
this price has been satisfied and all supply
prepared to operate at or below this price
has been purchased.
MARKET PARTICIPANT An entity, including a Scheduling
Coordinator, who participates in the Energy
marketplace through the buying, selling,
transmission, or distribution of Energy or
Ancillary Services into, out of, or through
the ISO Controlled Grid.
MARKET SEPARATION CONSTRAINT OR An element of the original California market
RULE design which requires that each Scheduling
Coordinator submit a balanced schedule,
thereby requiring each Scheduling
Coordinator to optimize within it's own
portfolio of Resources.
MCP Market Clearing Price, as defined in the ISO
Tariff.
Appendix A, Page 12
MINIMUM COST REDISPATCH A strategy for managing real-time Congestion
that minimizes the total dollar cost for
resolving real-time Congestion.
MINIMUM SHIFT REDISPATCH A strategy for managing real-time Congestion
that minimizes the total MW shift from the
forward schedules submitted by Scheduling
Coordinators.
MORC (MINIMUM OPERATING Reliability criteria established by the
RELIABILITY CRITERIA) Western Systems Coordinating Council (WSCC)
and the North American Electric Reliability
Council (NERC).
N-1 CONTINGENCY The forced (unplanned) outage of a single
major system element such as a line,
transformer, or generator.
N-2 CONTINGENCY The simultaneous forced (unplanned) outage
of two major system element such as a line,
transformer, or generator.
NERC The North American Electric Reliability
Council or its successor.
NFU (NEW FIRM USE) The portion of transmission capacity which
is available for scheduling through the ISO
that is not associated with an Existing
Contract. For purposes of the CMR proposal,
the term NFU is often used interchangeably
with Available Transfer Capability, or ATC.
NGIP New Generator Interconnection Policy
NOMOGRAM A set of operating or scheduling rules which
are used to ensure that simultaneous
operating limits are respected, in order to
meet NERC and WSCC operating criteria.
Nomograms generally take the form of graphs
that express simultaneous relationships
between generation levels, load levels, and
transmission capacities, and use these
relationships to define "safe" and "unsafe"
combinations of these variables from a
reliability point of view. [
Appendix A, Page 13
NON-SPINNING RESERVE The portion of off-line generating capacity
that is capable of being synchronized and
ramping to a specified load in ten minutes
(or load that is capable of being
interrupted in ten minutes) and that is
capable of running (or being interrupted)
for at least two hours
OP Operating Procedure, as defined in the ISO
Tariff.
OPERATING PROCEDURES Procedures governing the operation of the
ISO Controlled Grid as the ISO may from time
to time develop, and/or procedures that
Participating TOs currently employ which the
ISO adopts for use. These procedures include
a series of condition, Nomograms and/or
instructions that operators use to ensure
that real-time operations conform with
applicable reliability criteria, including
WSCC Minimum Operating Reliability Criteria
(MORC).
OPERATING RESERVE The combination of Spinning and Non-Spinning
Reserve required to meet WSCC and NERC
requirements for reliable operation of the
ISO Control Area.
OPERATIONAL CONTROL The rights of the ISO under the Transmission
Control Agreement and the ISO Tariff to
direct Participating TOs how to operate
their transmission lines and facilities and
other electric plant affecting the
reliability of those lines and facilities
for the purpose of affording comparable
non-discriminatory transmission access and
meeting Applicable Reliability Criteria.
OPF (OPTIMAL POWER FLOW) A computer optimization program which uses a
set of control variables (which may include
active power and/or reactive power controls)
to determine a steady-state operating
condition for the
Appendix A, Page 14
transmission grid for which a set of system
operating constraints (which may include
active power and/or reactive power
constraints) are satisfied and an objective
function (e.g. total cost or shift of
schedules) is minimized.
OUTAGE Disconnection or separation, planned or
forced, of one or more elements of an
electric system.
PARTICIPATING TO (PARTICIPATING A party to the TCA whose application under
TRANSMISSION OWNER) Section 2.2 of the TCA has been accepted and
who has placed its transmission assets and
Entitlements under the ISO's Operational
Control in accordance with the TCA. A
Participating TO may be an Original
Participating TO or a New Participating TO.
POP Preferred Operating Point
POWER FLOW MODEL The computer software used by the ISO to
model the voltages, power injections and
power flows on the ISO Controlled Grid and
determine the expected Transmission Losses
and Generation Meter Multipliers.
PREFERRED DAY-AHEAD SCHEDULE A Scheduling Coordinator's Preferred
Schedule for the ISO Day-Ahead scheduling
process.
PREFERRED HOUR-AHEAD SCHEDULE A Scheduling Coordinator's Preferred
Schedule for the ISO Hour-Ahead scheduling
process.
PREFERRED SCHEDULE The initial Schedule produced by a
Scheduling Coordinator that represents its
preferred mix of Generation to meet its
Demand. For each Generator, the Schedule
will include the quantity of output, details
of any Adjustment Bids, and the location of
the Generator. For each Load, the Schedule
will include the quantity of consumption,
details of any Adjustment Bids, and the
location of the Load. The Schedule will also
specify quantities and location of trades
between
Appendix A, Page 15
the Scheduling Coordinator and all other
Scheduling Coordinators. The Preferred
Schedule will be balanced with respect to
Generation, Transmission Losses, Load and
trades between Scheduling Coordinators.
PTDF Power Transmission Distribution Factor. For
purposes of the CMR proposal, this term is
used interchangeably with the term "Shift
Factor."
PX (POWER EXCHANGE) The California Power Exchange Corporation, a
state chartered, nonprofit corporation
charged with providing a Day-Ahead forward
market for Energy in accordance with the PX
Tariff. The PX is a Scheduling Coordinator
RAMPING Changing the loading level of a Generating
Unit in a constant manner over a fixed time
(e.g., ramping up or ramping down). Such
changes may be directed by a computer or
manual control.
RAMPING ENERGY The instructed Energy deviation that is
required for a smooth 20-minute linear ramp
between hourly Energy schedules at the top
of each hour.
RAS (REMEDIAL ACTION SCHEMES) Protective systems that typically utilize a
combination of conventional protective
relays, computer-based processors, and
telecommunications to accomplish rapid,
automated response to unplanned power system
events. Also, details of RAS logic and any
special requirements for arming of RAS
schemes, or changes in RAS programming, that
may be required.
REAL TIME MARKET The competitive generation market controlled
and coordinated by the ISO for arranging
real time Imbalance Energy.
Appendix A, Page 16
RECALLABLE TRANSMISSION A proposed capacity product that the ISO
SERVICE (RTS) would make available after the allocation of
New Firm Use capacity in the Congestion
Management process by auctioning, on a
recallable basis, the unused ETC capacity
that was reserved in the Congestion
Management process.
REDISPATCH The readjustment of scheduled Generation or
Demand side management measures, to relieve
Congestion or manage Energy imbalances.
REGULATION The service provided either by Generating
Units certified by the ISO as equipped and
capable of responding to the ISO's direct
digital control signals, or by System
Resources that have been certified by the
ISO as capable of delivering such service to
the ISO Control Area, in an upward and
downward direction to match, on a real time
basis, Demand and resources, consistent with
established NERC and WSCC operating
criteria. Regulation is used to control the
power output of electric generators within a
prescribed area in response to a change in
system frequency, tieline loading, or the
relation of these to each other so as to
maintain the target system frequency and/or
the established interchange with other areas
within the predetermined limits. Regulation
includes both the increase of output by a
Generating Unit or System Resource
("Regulation Up") and the decrease in output
by a Generating Unit or System Resource
("Regulation Down"). Regulation Up and
Regulation Down are distinct capacity
products, with separately stated
requirements and Market Clearing Prices in
each Settlement Period.
RELIABILITY CRITERIA Pre-established criteria that are to be
followed in order to maintain desired
performance of the ISO Controlled Grid under
contingency or steady state conditions.
Appendix A, Page 17
RELIABILITY MUST-RUN CONTRACT A rate schedule on file at FERC and in
(RMR CONTRACT) effect, or a contract between the ISO and a
Generator, giving the ISO the right to call
on the Generator to generate Energy or
provide Ancillary Services from the
Generating Unit as and when required to
ensure the reliability of the ISO Controlled
Grid, in return for certain payments.
RELIABILITY MUST-RUN GENERATION Generation that the ISO determines is
(RMR GENERATION) required to be on line to meet Applicable
Reliability Criteria requirements. This
includes i) Generation constrained on line
to meet NERC and WSCC reliability criteria
for interconnected systems operation; ii)
Generation needed to meet Load demand in
constrained areas; and iii) Generation
needed to be operated to provide voltage or
security support of the ISO or a local area.
RELIABILITY MUST-RUN UNIT A Generating Unit which is the subject of a
(RMR UNIT) Reliability Must-Run Contract.
REPLACEMENT RESERVE Generating capacity that is dedicated to the
ISO, capable of starting up if not already
operating, being synchronized to the ISO
Controlled Grid, and ramping to a specified
Load point within a sixty (60) minute
period, the output of which can be
continuously maintained for a two hour
period. Also, Curtailable Demand that is
capable of being curtailed within sixty
minutes and that can remain curtailed for
two hours.
RESPONSIBLE UTILITY The utility which is a party to the TCA in
whose Service Area the Reliability Must-Run
Unit is located or whose Service Area is
contiguous to the Service Area in which a
Reliability Must-Run Unit owned by an entity
outside of the ISO Controlled Grid is
located.
REVENUE REQUIREMENT The revenue level required by a utility to
cover expenses made on an investment, while
earning a specified rate of return on the
investment.
Appendix A, Page 18
REVISED SCHEDULE A Schedule submitted by a Scheduling
Coordinator to the ISO following receipt of
the ISO's Suggested Adjusted Schedule.
SC Scheduling Coordinator, as defined in the
ISO Tariff.
SCHEDULE A statement of (i) Demand, including
quantity, duration and Take-Out Points and
(ii) Generation, including quantity,
duration, location of Generating Unit, and
Transmission Losses; and (iii) Ancillary
Services which will be self provided, (if
any) submitted by a Scheduling Coordinator
to the ISO. "Schedule" includes Preferred
Schedules, Suggested Adjusted Schedules,
Final Schedules and Revised Schedules.
SCHEDULING COORDINATOR An entity certified by the ISO for the
purposes of undertaking the functions
specified in Section 2.2.6 of the ISO
Tariff.
SERVICE AREA An area in which, as of December 20, 1995,
an IOU or a Local Publicly Owned Electric
Utility was obligated to provide electric
service to End-Use Customers.
SETTLEMENT Process of financial settlement for products
and services purchased and sold undertaken
by the ISO under Section 11 of the ISO
Tariff. Each Settlement will involve a price
and a quantity.
SHIFT FACTOR Numerical representations, that describe the
physical flows on inter-LPA transmission
lines (and tie lines to zones external to
the Control Area) caused by an injection at
a bus in an LPA. Shift Factors are defined
entirely by the characteristics of the grid,
such as the topology of connecting lines and
the impedances of the lines comprising the
system.
SIMPLIFIED COMMERCIAL MODEL A representation of the ISO Controlled Grid,
used for commercial activities. In the
context of the CMR proposal, the Simplified
Appendix A, Page 19
Commercial Model would treat all Energy
within a Locational Price Area or LPA
identically, without locational bias, for
the purposes of Inter-Zonal or Inter-LPA
access and real-time Dispatch.
SPINNING RESERVE The portion of unloaded synchronized
generating capacity that is immediately
responsive to system frequency and that is
capable of being loaded in ten minutes, and
that is capable of running for at least two
hours.
SUGGESTED ADJUSTED SCHEDULE The output of the ISO's initial Congestion
Management for each Scheduling Coordinator
for the Day-Ahead Market ("Suggested
Adjusted Day-Ahead Schedule") or for the
Hour-Ahead Market ("Suggested Adjusted
Hour-Ahead Schedule"). These Schedules will
reflect ISO suggested adjustments to each
Scheduling Coordinator's Preferred Schedule
to resolve Inter-Zonal Congestion on the ISO
Controlled Grid, based on the Adjustment
Bids submitted. These schedules will be
balanced with respect to Generation,
Transmission Losses, Load, and trades
between Scheduling Coordinators to resolve
Inter-Zonal Congestion.
SUPPLEMENTAL ENERGY Energy from Generating Units and other
resources which have uncommitted capacity
following finalization of the Hour-Ahead
Schedules and for which Scheduling
Coordinators have submitted bids to the ISO
at least half an hour before the
commencement of the Settlement Period.
SYSTEM EMERGENCY Conditions beyond the normal control of the
ISO that affect the ability of the ISO
Control Area to function normally including
any abnormal system condition which requires
immediate manual or automatic action to
prevent loss of Load, equipment damage, or
tripping of system elements which might
result in cascading outages or to restore
system operation to meet the minimum
operating reliability criteria.
Appendix A, Page 20
SYSTEM RELIABILITY A measure of an electric system's ability to
deliver uninterrupted service at the proper
voltage and frequency.
TAC (TRANSMISSION ACCESS Synonymous with "Access Charge" as defined
CHARGE) in the ISO Tariff.
TCA (TRANSMISSION CONTROL The agreement between the ISO and
AGREEMENT) Participating TOs establishing the terms and
conditions under which TOs will become
Participating TOs and how the ISO and each
Participating TO will discharge their
respective duties and responsibilities, as
may be modified from time to time.
TO (TRANSMISSION OWNER) An entity owning transmission facilities or
having firm contractual rights to use
transmission facilities.
TRADING DAY The twenty-four hour period beginning at the
start of the hour ending 0100 and ending at
the end of the hour ending 2400 daily,
except where there is a change to and from
daylight savings time.
TTC Total Transfer Capability
UDC (UTILITY DISTRIBUTION An entity that owns a Distribution System
COMPANY) for the delivery of Energy to and from the
ISO Controlled Grid, and that provides
regulated retail electric service to
Eligible Customers, as well as regulated
procurement service to those End-Use
Customers who are not yet eligible for
direct access, or who choose not to arrange
services through another retailer.
UNINSTRUCTED IMBALANCE ENERGY The real time change in Generation or Demand
other than that instructed by the ISO or
which the ISO Tariff provides will be paid
at the price for Uninstructed Imbalance
Energy.
Appendix A, Page 21
UNIT COMMITMENT The process of determining which Generating
Units will be committed (started) to meet
Demand and provide Ancillary Services in the
near future (e.g., the next Trading Day).
USAGE CHARGE The amount of money, per 1 kW of scheduled
flow, that the ISO charges a Scheduling
Coordinator for use of a specific congested
Inter-Zonal Interface during a given hour.
VOLTAGE LIMITS For all substation busses, the normal and
post-contingency Voltage Limits (kV). The
bandwidth for normal Voltage Limits must
fall within the bandwidth of the
post-contingency Voltage Limits. Special
voltage limitations for abnormal operating
conditions such as heavy or light Demand may
be specified.
VOLTAGE SUPPORT Services provided by Generating Units or
other equipment such as shunt capacitors,
static var compensators, or synchronous
condensers that are required to maintain
established grid voltage criteria. This
service is required under normal or system
emergency conditions.
WHEELING Wheeling Out or Wheeling Through.
WHEELING ACCESS CHARGE The charge assessed by the ISO that is paid
by a Scheduling Coordinator for Wheeling in
accordance with Section 7.1. Wheeling Access
Charges shall not apply for Wheeling under a
bundled non-economy Energy coordination
agreement of a Participating TO executed
prior to July 9, 1996. The Wheeling Access
Charge may consist of a High Voltage
Wheeling Access Charge and a Low Voltage
Wheeling Access Charge.
WHEELING OUT Except for Existing Rights exercised under
an Existing Contract in accordance with
Sections 2.4.3 and 2.4.4, the use of the ISO
Controlled Grid for the transmission of
Energy from a Generating Unit
Appendix A, Page 22
located within the ISO Controlled Grid to
serve a Load located outside the
transmission and distribution system of a
Participating TO.
WHEELING THROUGH Except for Existing Rights exercised under
an Existing Contract in accordance with
Sections 2.4.3 and 2.4.4, the use of the ISO
Controlled Grid for the transmission of
Energy from a resource located outside the
ISO Controlled Grid to serve a Load located
outside the transmission and distribution
system of a Participating TO.
WSCC (WESTERN SYSTEM
COORDINATING COUNCIL) The Western Systems Coordinating Council or
its successor.
ZONE A portion of the ISO Controlled Grid within
which Congestion is expected to be small in
magnitude or to occur infrequently. "Zonal"
shall be construed accordingly.
Appendix A, Page 23