EXHIBIT 99.383
PREEMPT
PREEMPTIVE ENERGY MANAGEMENT WITH
PHYSICAL TRANSMISSION RIGHTS
CALIFORNIA POWER EXCHANGE
AUGUST 14, 2000
DRAFT
TABLE OF CONTENTS
INTRODUCTION.............................................................. 3
I. MARKET STRUCTURE.................................................... 4
1. DESIGN APPROACH..................................................... 4
2. PHYSICAL RIGHTS MODEL............................................... 4
2.1 Preemptive Congestion Management.............................. 5
2.2 The Forward Transmission Representation....................... 5
2.3 Market Exchanges.............................................. 8
3. HUB AND BASIS-DIFFERENTIAL FINANCIAL OVERLAY........................ 9
3.1 Physical Basis for BDs........................................ 10
3.2 Locational Pricing Areas (LPAs)............................... 11
3.3 "Into California" Hub......................................... 11
II. MARKET OPERATION.................................................... 12
1. LONG FORWARD MARKETS................................................ 12
2. DAY-AHEAD/HOUR-AHEAD MARKETS........................................ 12
3. REAL-TIME MARKETS................................................... 13
4. ROLE OF THE PX...................................................... 13
III. ALTERNATIVES CONSIDERED............................................. 14
1. COMET PROPOSAL...................................................... 14
2. CA ISO REFORM PROPOSAL WITH TRADING HUBS............................ 14
IV. COMPARISON WITH CA ISO REFORM PROPOSAL.............................. 14
Tabors Caramanis & Associates 2 of 2
INTRODUCTION
This proposal presents a congestion management approach whose objective is to
maximize the efficiency of forward markets and allow market participants to
resolve congestion through decentralized trading. Two fundamental components
characterize this proposal. The first is a central trading hub-based market in
California. Transportation would be purchased as a basis differential (BD) to
and from the hub in a manner analogous to the natural gas industry. The second
is a preemptive congestion management system based on trading physical
transmission rights in the forward market. The CA ISO would actively manage
congestion only in real-time, due to unforeseen system conditions and energy
imbalances.
This system uses the commercial model of the transmission system developed by
the CA ISO Congestion Management Reform Proposal, and supports its recommended
methodology and tools for managing real-time congestion. The key difference in
the two proposals is that this physical rights-based approach eliminates the
need for the day-ahead congestion management process (CONG). Market participants
continuously trade energy and transmission in exchanges. Participants have to
submit necessary transmission rights with day-ahead schedules, which are
therefore congestion-free. Schedule adjustments are permitted until the close of
the forward market, as long as the changes have the required physical
transmission rights and therefore create no additional congestion. This market
structure ensures that in the absence of unforeseen system outages, congestion
will be managed in advance by market participants themselves. This is achieved
through initial purchase (at the ISO's auction) and subsequent trading (outside
of the ISO) of physical transmission rights (PTRs).
This proposal allows for the expansion of the PX role in the market. The PX will
operate an exchange facilitating continuous trading among market participants
rather than running a single day-ahead energy pool. The PX will offer secondary
transmission, BDs, and several energy products.
The following sections describe the basic design of this proposal. Section I
describes the physical rights model and the central hub-based market. Section II
briefly describes market operation to illustrate these concepts. Section III
presents the key differences between this proposal and the CA ISO Reform
proposal, in the context of the objectives of congestion management reform in
California.
Tabors Caramanis & Associates 3 of 3
I. MARKET STRUCTURE
1. DESIGN APPROACH
The proposed market structure is based first and foremost on addressing the
deficiencies in California's congestion management process. In addition, the
following principles motivate this proposal:
- - A deep and vibrant forward market underlies any well-functioning competitive
market;
- - A hub-based financial market will encourage high liquidity;
- - Preemptive congestion management will enable advance price certainty and
decentralized decision-making in the forward market;
- - Physical transmission rights (PTRs) form the basis of preemptive congestion
management while ensuring that the forward market is closely aligned to
real-time conditions; and
- - The approach adopted by California should be compatible and seamless with
neighboring RTOs developing across the WSCC.
The focus of this proposal therefore is to build the framework for an efficient
and transparent forward market that will explicitly recognize transmission as a
separate but integral component of energy trading, thereby reducing the need for
real-time congestion management. This framework has two key foundations:
(1) A liquid, trading hub allowing for tradable basis differentials (BDs); and
(2) A framework for physical, tradable transmission rights.
The rest of this section focuses on these two aspects of the market structure.
This proposal only briefly addresses other aspects of the market, such as
real-time congestion management, since it supports and adopts most of the other
features of the CA ISO Congestion Management Reform proposal.
2. PHYSICAL RIGHTS MODEL
PTRs have several basic properties. PTRs give their purchaser / owner the right
to a fixed quantity (MW) of transfer capability across an interface for all
hours within a specific period. These provide a means of delivery certainty to
market participants and protect them from congestion. Market participants are
thus able to secure PTRs of known quantity and price, ex ante, before committing
to a transaction. The physical aspect of PTRs gives market participants
certainty for scheduling transactions. PTRs have to be accompanied by schedules
in the day-ahead scheduling process; otherwise these rights are released into
the market. This will ensure that holders of PTRs will not have the ability to
withhold those rights as a means to influence market prices. Market participants
holding unneeded PTRs would be free to sell them prior to the ISO's day-ahead
deadline for balanced schedule and PTR submission.
Tabors Caramanis & Associates 4 of 4
Two important aspects distinguish the physical rights approach from the current
system in California. First, participants will be required to submit applicable
transmission rights with their energy schedules. Second, in addition to Path 15,
several interfaces and LPA paths will have tradable rights. Thus, participants
may have to purchase PTRs on several interfaces in order to fully hedge
congestion risk.
2.1 Preemptive Congestion Management
The requirement to purchase transmission in order to schedule energy
transactions with the ISO essentially allows for congestion avoidance. This is
because PTRs will be released in accordance with the capacity available on
interfaces. Participants will purchase PTRs in accordance with their impacts on
these interfaces (See Section 2.2). Thus, all schedules submitted when markets
close will respect the limits of the transmission system.
Note that in both this proposal and the CA ISO Reform proposal market
participants hedge transmission risk by purchasing transmission rights on
multiple interfaces based on flow impacts of their transactions. The distinction
is that these purchases are optional in the CA ISO Reform proposal. The
implication of this distinction is that in the CA ISO proposal market
participants don't know the value of congestion until day-ahead, since the
amount and value of congestion is determined day-ahead based on the ISO's
day-ahead congestion management process. In this proposal, market participants
know the value of congestion in advance. Because market participants have to
submit PTR purchases with their schedules, they will have the incentive to trade
PTRs in advance. Therefore, the value of congestion is the price at which the
PTRs of an interface are traded in the secondary market.
The benefit of this approach is twofold. First, market participants have greater
price certainty, since the congestion value is known in advance. Second, the set
of schedules that are submitted to the CA ISO day ahead are almost
congestion-free, barring unforeseen changes or minor deviations of real-time
conditions from the forward transmission representation. This will eliminate the
need for the CA ISO to clear congestion on a day-ahead basis, and allow it to
focus only on real-time congestion management (however real-time may be defined
- - either hour-ahead, or several hours ahead). In order to accomplish this, the
market requires a physical transmission representation that aligns closely with
realistic congestion expectations.
2.2 The Forward Market Transmission Representation
Participants will require PTRs on all the interfaces that are materially
affected by a transaction between any two points on the grid. The measure of
such an effect is a metric called the shift factor. The shift factor is a
property of the combination of a transaction point of injection (POI) and point
of withdrawal (POW) and a particular interface. Every transaction has a shift
factor on every interface. This means that if a one MW transaction from A to B
will cause a flow of 0.2 MW on an interface 'C', it will have a shift factor of
0.2 on 'C'. Thus, any transaction will need to be supported by PTRs equivalent
to the shift factors on all the interfaces that are impacted by it. As discussed
further below, this
Tabors Caramanis & Associates 5 of 5
proposal supports the aggregation of nodes into Local Pricing Areas (LPAs),
using the terminology proposed in the CA ISO Reform proposal.
The CA ISO will post PTR requirements in a shift factor matrix to the
exchanges.(1) This shift factor matrix will be set for the duration of auction
periods, which would likely be three months or a season (See PTR Auctions
below). This would ensure advance price certainty to market participants, since
they will not have to worry about adjusting their portfolios closer to real
time. The CA ISO Reform proposal suggests posting updated shift factor matrices
two days ahead of scheduling. Although this allows greater flexibility in
aligning the market with the transmission system, fixing shift factors for the
auction period provides greater forward market price certainty.
Interface Selection
The first step in the development of the transmission representation for the
forward market is the selection of interfaces. One of the problems plaguing the
market currently is that only rights on Path 15 are traded. Congestion costs on
all other interfaces are socialized. This proposal suggests a more detailed
forward representation along the lines of the CA ISO Reform proposal that
captures all the commercially significant interfaces (CSIs) by factoring in all
operating procedures, nomograms and Local Reliability Areas (LRAs) that are
presently used by operators. In addition, this proposal encourages the
development of criteria for commercial significance on the basis of which
interfaces should be selected for trading. However, no independent analysis has
been conducted here either to suggest specific interfaces or to suggest other
selection criteria. This is because there is no reason to dispute the
methodology proposed by the CA ISO Reform proposal, which has a detailed
analysis of LPAs, LRAs and interfaces.
Defining Interface Capacities
Since PTRs will be traded on each interface individually, capacities available
to the market need to respect simultaneous transfer limitations between
interfaces and only sell an amount of capacity that can simultaneously be
delivered on all elements of the transmission system. Thus, the CA ISO will
determine PTR capacities based on simultaneously feasible flow limitations
expressed in nomogram relationships.
There will likely be several possible combinations of simultaneously feasible
capacities, as shown in Figure 1. The CA ISO has several options for releasing
capacity in primary markets, of which the following approaches may be used:
1) The CA ISO may release the least simultaneously feasible capacity. Using a
simple simultaneous transfer limitation between two elements as an example shown
in Figure 1, this would be represented by x' and y'. The CA ISO can then release
the incremental capacity as a firm, but mutually exclusive, combined product.
That is, one MW of capacity on C-D will correspond to an equivalent purchase of
capacity on A-B in proportion to their simultaneous interaction (mathematically
the slope of the diagonal).
- ------------------
(1) This matrix will be a 'K' by 'N' matrix, where 'K' is the number of
interfaces, and 'N' is the number of LPAs. Any participant can calculate PTR
requirements for any transaction by simple algebraic calculation using this
matrix.
Tabors Caramanis & Associates 6 of 6
During scheduling, the rights holder can schedule on either one of the
interfaces, but not both. For example, assume that the distance x'-x on Figure 1
corresponds to 20 MW on A-B and the distance y'-y corresponds to 30 MW on C-D.
This implies that the relationship between capacity on A-B and C-D is 2:3. Thus,
above x', y', the ISO will sell the mutually exclusive, combined product of
either 1 MW on A-B or 1.5 MW on C-D. Assume, for simplicity, that two traders,
T1 and T2, bid on this combined product. Assume that T1 sells into a load center
that requires PTRs on A-B, and T2 sells into an area that requires PTRs on only
C-D. Assume that T1 has the highest bid of $120 for the 20 MW on A-B, outbidding
a bid of $100 by T2 for the 30 MW on C-D. T1 will win the rights to use either
20 MW on A-B or 30 MW on C-D. T1 may schedule on either interface, but not both,
or sell it into the secondary market.
Figure 1: PTR Capacity - Simultaneous Feasibility Limits
[LINE GRAPH AND DIAGRAM]
2) The second option is to sell capacity equivalent to x' and y' on a firm
basis, and sell the entire amounts of y'-y and x'-x in the primary auctions on a
non-firm basis. Within a certain range of schedules, the risk of curtailments
would be low. Beyond this, in the event of infeasible schedules or a sudden
reduction of combined transfer capability, the ISO would need a curtailment
allocation. One method would be to choose the most efficient reduction, which is
a curtailment allocation that would require the least total reduction in MW to
reach a feasible point of operation (mathematically this is the projection of
the infeasible point on the line of feasible operation). Since nomograms may get
complicated and have unique characteristics, alternate methods may be chosen on
a case-by-case basis.
3) Finally, the ISO could release capacity somewhere between y' and y, and x'
and x (x", y" in Figure 1) on a firm basis, and have a similar mechanism for
dealing with scheduling conflicts as in (2). This may represent the best
combination of providing the most capacity on a firm basis and reducing the
likelihood of non-firm curtailments.
For interfaces that have minimal or no simultaneous limits (i.e., little or no
interactivity with other interfaces), capacity will be sold based on the lower
of their Thermal limit, Voltage Limit and Stability Limit.
Tabors Caramanis & Associates 7 of 7
PTR Auctions
The CA ISO will auction PTRs on all interfaces periodically, e.g., once per
year, for capacity available on the existing system, as they do with FTRs.
However, one significant different is that rights will be valid for shorter
periods than a year, either for a season or for three months, in order to allow
the ISO to release transmission capacity commensurate with the actual system and
system conditions as much as possible. The auction process itself, however, need
not be different from the current FTR auction process.
Since transfer capability and simultaneous transfer restrictions can vary
seasonally and with different operating conditions, the CA ISO will release
different levels of capacity in primary auctions and release incremental
capacity based on availability. This will result in the existence of a
short-term "primary" capacity rights market, which will augment the secondary
market for PTRs and thereby allow full economic utilization of the transmission
system.
Release of incremental quantities of PTRs can occur at different intervals; for
example, possibilities include monthly, weekly, two-day ahead, day-ahead, and
day-of; and such release can follow either similar or streamlined auction
procedures compared to the annual PTR auction process. As the ISO obtains
greater certainty of likely real-time transmission system conditions - e.g., via
confirmed T and G outage schedules, updated water flow data, and ultimately
short-term weather forecasts - it can determine the combination of release times
and quantities that best promotes PTR market liquidity (and thus transmission
system utilization), while minimizing the likelihood of releasing "too much",
which results in greater real-time efforts to balance the system while
respecting transmission limits.
2.3 Market Exchanges
The secondary PTR market will be administered by one or more independent
commercial entities, such as the California Power Exchange (PX) and Automated
Power Exchange (APX). The exchanges will be the source of price information
needed by market participants to value congested or potentially congested
transmission paths. The CA ISO will have a supervisory role over the PTR
markets.
The effect of these independent exchanges will be that the CA ISO will not
intervene in the market, which will set prices for tradable products through a
series of bilateral transactions in exchanges. The prices are known in advance
(ex-ante) and transactions can be adjusted through the close of the last hourly
scheduling window. The creation of a well-defined, small set of transmission
products (the interfaces) enables a liquid (high-volume) market for transmission
and, by extension, for energy. This high liquidity will in turn provide for
greater price certainty and price stability.
Exchange software will enable participants to obtain bid/offer prices for any
given pair of LPAs within the system. It is most likely that the PTRs will be
grouped based on purchaser requests to the exchanges so as to represent the
needed interface transfer capability for common transactions between LPAs. The
purchasing process can thus be
Tabors Caramanis & Associates 8 of 8
automated. Sets of transmission rights for transactions can be sold as
'packages' and market participants can maintain and trade portfolios of
transmission rights with ease and without necessarily needing detailed knowledge
of purchase requirements for every transaction. Given the fairly linear nature
of transaction flows in California, it is unlikely that any transaction would
require PTR purchases for more than 2-4 flowgates.
All information concerning interface capacities and flow impacts will be
publicly available; market participants can thus independently verify CA ISO
calculations. The transmission exchange will post currently traded prices for
all interfaces. All independent exchanges will not participate in the market,
and therefore will be no more than "honest brokers".
3. HUB AND BASIS-DIFFERENTIAL FINANCIAL OVERLAY
The second component of this proposed market structure is the establishment of a
central trading hub within California. All LPAs in California would trade at a
basis differential (BD) away from this central hub (See Figure 2 below). The
exchanges would offer futures contracts at this hub, and offer futures contracts
for the BDs, which would represent the congestion-related transportation cost
(which excludes loss and embedded cost responsibilities) from the central hub to
each LPA.
Figure 2: Central Hub-based Market Illustration
[MAP OF CALIFORNIA]
This would create a single California energy price and separate the
transportation component. Why is this useful? Because transmission congestion
value in California energy prices (price difference between SP15 and NP15) and
its volatility are small relative to the total energy price and "flat" price
volatility. The creation of a hub-and-BD financial market would expose these
components and allow traders to hedge the flat price
Tabors Caramanis & Associates 9 of 9
risk separately from transportation. Since California is a net importer and a
major sink for power flows in the WSCC, a single price index against which
market participants can trade and manage risk would enhance inter-regional
market liquidity significantly.
Either Midway or Vincent, which are the southern terminuses of Path 15 and Path
26 respectively, would be a suitable choice for this hub. The hub price would
actually be the LPA price within which the chosen bus is located, and the LPA
would be a reduced form of what SP15 (or ZP26) is today, since they may not
retain their current boundaries in a more granular zonal scheme. Vincent (SP15)
is located near the largest load concentration in California, and can be
accessed directly from Nevada, Arizona, and the Pacific Northwest at NOB. Thus
it has the advantage of almost being a de facto "into California" hub (See
Section 3.1). Midway (ZP26), on the other hand, has the benefit of being
electrically more central. Both locations would be appropriate centers to "dump"
energy coming into California. SP15 is a natural choice for this hub because it
sets the price for most of the WSCC in today's bilateral markets, due to its
ability to absorb large supplies (high import ratings) and its proximity to
major WSCC paths.
For discussion purposes it is assumed that the LPA around Vincent (SP15) will
be the central hub. Any transaction in California therefore would require at
most two financial transactions; one to SP15 and another to the delivery LPA.
Any import from external areas would obviously require one additional segment of
transportation into California.
3.1 Physical Basis for BDs
Just as in the natural gas industry, the BDs will have physical underpinnings
that represent the `transportation', or marginal transmission, cost associated
with delivery within California. The value of a BD from (to) SP15 to (from) any
LPA will be the weighted prices of the PTRs in the secondary market, where the
weights are the shift factor contributions of that transaction (See Table 1
below) on the interfaces. Due to the linear nature of the California system, it
is unlikely that more than 2-4 interface PTRs would underlie any BD.
These BDs will likely be symmetrical. That is, the value of the BD from SP15 to
any LPA will be the negative of the BD from the LPA to SP15. Note that shift
factor contributions need not be symmetrical. That is, the shift factors from
any LPA to SP15 may not be the same as those from SP15 to the LPA. However,
the value of the unidirectional PTRs underlying the BDs will self-adjust in the
market so that the BDs will in fact be symmetrical. That is, a trader would just
arbitrage between PTRs from SP15 to an LPA and back until transactions in both
directions had the same value. Note that due to the significant change in
seasonal flow directions in California due to the dominance of hydro in N.
California, some BDs could alter values significantly from season to season.
Tabors Caramanis & Associates 10 of 10
Table 1: Basis Differential Calculation Example (Summer Season)
PATHS TO PATH 15 PATH 26 SD SF EAST PV PATH PATH 46-
SP15: SOUTH SOUTH NORTH TO NP15 INTO PV INTO
TO SP15 SOCAL SO CAL
Shift Factor:
San Francisco 1.0 1.0 0.0 1.0 0.0 0.0
NP15 1.0 1.0 0.0 0.0 0.0 0.0
San Diego 0.0 0.0 1.0 0.0 0.0 0.0
PV (External) 0.0 0.0 0.0 0.0 .67 .33
Assumed Price
of PTR: $2 $1 -$7 -$3 $6 $5
BD Calculation: BD (=
Price*ShFct sum of
Weight columns)
San Francisco 1.0*$2 1.0*$1 0.0*(-$7) 1.0*(-$3) 0.0*$6 0.0*$5 $0
NP15 1.0*$2 1.0*$1 0.0*(-$7) 0.0*(-$3) 0.0*$6 0.0*$5 $3
San Diego 0.0*$2 0.0*$1 1.0*(-$7) 0.0*(-$3) 0.0*$6 0.0*$5 -$7
PV (External) 0.0*$2 0.0*$1 0.0*(-$7) 0.0*(-$3) 0.67*$6 0.33*$5 $5.65
Note: Shift factors and PTR prices representative only.
The exchanges would post BD prices continuously and offer futures on BDs, just
as they would for energy at the hub. Purchasers buying transportation to any LPA
would essentially buy the packaged PTRs underlying the BD, based on the PTR
bid/ask offers continuously posted at the exchanges (See Section II below for an
example). However, market participants may treat the BDs as purely financial
instruments and trade against them without necessarily taking trades to
delivery.
3.2 Locational Pricing Areas (LPAs)
This proposal supports the creation of LPAs based on shift-factor clustering and
price dispersion of nodes, as described in detail in the CA ISO Reform proposal.
These LPAs will have single prices, both in the real-time balancing market and
in forward markets. In the latter, each LPA will serve as a satellite hub in the
exchange. That is, market participants will be able to trade at these hubs
directly rather than having to purchase energy at the central hub (SP15) and
buying transportation (BDs) separately. This is similar to city gate spot market
purchases in the gas industry. The liquidity in these satellite hubs will vary,
depending on their relative size.
3.3 "Into California" Hub
An "into California" hub would be one into which traders could sell with the
choice of delivering to any border point, such as COB or Palo Verde. The buyer
would then assume the delivery risk from the border. In this proposed market
structure, SP15 serves almost naturally as such a hub, because almost every
inter-regional intertie feeds into this LPA, including delivery from NOB,
Nevada, Arizona and Mexico. The total simultaneous import capability into
Southern California, on the order of 13,000 MW, should allow for considerable
market liquidity; it excludes only a portion of the delivery capability over
Tabors Caramanis & Associates 11 of 11
COI, which is separated from SP15 by Path 15 and Path 26. This would restrict
the ability for SP15 to be a pure "into California" hub.
The central hub at SP15 would provide almost the same convenience to
inter-regional traders, since the BD financial instrument would allow traders
who want to import/export at COB to access the hub with just one additional
product, even though that product will likely entail purchase across several
transmission paths (e.g., Path 15 and Path 26 to get to SP15).
II. MARKET OPERATION
1. LONG FORWARD MARKETS
The PX will provide an exchange for long forward transactions (those prior to
Day Ahead), allowing trading of numerous products as desired by the marketplace.
Core products will likely include:
- Energy for delivery into / receipt from the California Hub ("into
California") for pre-determined blocks, such as 16 hours per day, 5 days
per week ("5x16") or 7x24.
- Energy for delivery into / receipt from the major local pricing areas
(LPAs), in similar block configurations.
- Energy for delivery into / receipt from other local pricing areas
(LPAs), if volume demands support separate products.
- Physical transmission rights (PTRs) across individual CSIs throughout
California, both major CSIs (e.g., path 15) and minor CSIs (smaller
LPAs, e.g. Humbolt, and smaller external ties, e.g. Sierra Pacific -
PG&E tie, path 24 - Drum).
- BDs, which are essentially proportioned packages of PTRs that provide a
full complement of PTRs for a particular LPA-to-LPA transaction.
Long forward markets will be run as continuous bid/ask markets, with clearing of
individual bids and asks and continuous and updated posting of prices as each
cleared transaction is booked.
Exchange users are responsible for obtaining PTRs or BDs to allow transactions
to come to physical delivery, if desired, beginning with the requirement to
submit balanced schedules and accompanying PTRs to the ISO at the Day Ahead
schedule submittal deadline.
2. DAY-AHEAD/HOUR-AHEAD MARKETS
The PX's set of Day Ahead markets will consist of the same continuous bid/ask
markets instituted as long forward markets. The PX will close all long forward
markets just prior to the day-ahead deadline for SC submission of balanced
schedules to the ISO.
Tabors Caramanis & Associates 12 of 12
The PX will subsequently run continuous bid/ask markets in the hours preceding
the ISO's real-time schedule submittal/change deadlines. Participants who wish
to update or refine day-ahead submitted schedules can do so through the PX's
hourly markets. The same restrictions apply: if participants wish to schedule
updated transactions with the ISO, purchase of PTRs must be made, to accompany
energy schedule changes.
3. REAL-TIME MARKETS
This proposal supports and is fully compatible with the real-time congestion
management approach proposed by the CA ISO in its Reform proposal. An open issue
is whether the ISO should employ the market separation rule in real-time
congestion management. The CA ISO Reform proposal entails relaxing this rule in
real-time, but enforcing it in the day-ahead congestion management process. As
an alternative to relaxing the rule completely, the ISO could ask market
participants to specify whether they are willing to allow the ISO to create
trades between them in order to create a more efficient real-time dispatch
solution. The inefficiencies from enforcement of the market separation rule are
not expected to be as significant in this proposal relative to the current
system, since schedules are likely to be more closely aligned with physical
constraints. Thus, voluntary participation in inter-market participant trades
may be sufficient to achieve an acceptable level of efficiency in real-time
congestion management. At this stage, a specific recommendation has not been
developed, and this issue needs further input from stakeholders.
4. ROLE OF THE PX
This new proposal offers a different but expanded role for the PX. This proposal
creates new possibilities for product offerings and regional expansion. The PX
role in the market can be characterized as follows:
- - The PX will (potentially along with other exchanges) run continuous
exchanges where it will continuously match up and post bid/ask offers for
its products and post currently traded prices.
- - The market will no longer require a day-ahead pool, since buyers and sellers
will continuously trade up until real-time.
- - The PX will operate a central hub, and allow for trading basis differentials
(BDs) to and from the hub.
The PX will be able to market these services and software packages in other
RTOs, both in the WSCC and in the Eastern Interconnection, that are considering
the adoption of physical rights-based forward markets.
The PX will offer several new products, including the following:
- - Secondary transmission (PTRs).
- - BDs for hub-to-LPA and LPA-to-hub transactions, which will derive from shift
factor-weighted averages of the underlying transmission product prices.
- - Packaged PTR purchases for LPA-to-LPA transactions based on current bid/ask
offers for the underlying transmission products.
Tabors Caramanis & Associates 13 of 13
- - Monthly energy futures, and potentially additional energy products such as
weekly blocks.
III. ALTERNATIVES CONSIDERED
1. COMET PROPOSAL
2. CA ISO REFORM PROPOSAL WITH TRADING HUBS
This alternative builds on the CA ISO Reform proposal, which defines financial
transmission rights, where transmission is not required to be purchased in the
forward market, and congestion is cleared and priced day ahead by the ISO. A
hub-based structure can, however, overlay this market design.
- - The hub could function as an "into California" hub, with the hub price set
by the daily UCMP.
- - The BDs would be the differences between the LPA clearing prices and the
UCMP developed by the ISO using adjustment bids.
- - Thus, the PX would retain the role of managing an energy pool, and
developing day-ahead UCMPs.
- - All imports could therefore sell directly into this hub without having to
buy a BD to the hub.
The benefit of this approach is that market participants will have more
flexibility in 'floating' transactions and accepting congestion risk without
having to purchase transmission.
However, the market as a whole would lose some of the benefits of preventive
congestion management, including the price certainty and the reduced role of
congestion management in real time.
The BD prices would also be based essentially on model-based outputs of the ISO,
which may have more volatility and unpredictability than the continuously traded
secondary transmission and energy markets.
Tabors Caramanis & Associates 14 of 14
IV. COMPARISON WITH CA ISO REFORM PROPOSAL
MARKET ASPECT CURRENT IMPLEMENTATION CA ISO REFORM PROPOSAL CA PX PROPOSAL
PROBLEMS MOTIVATING
REFORM
- ------------------------------------------------------------------------------------------------------------------------------------
Commercial - Forward markets are not - Employ sophisticated interface - Retain LPA and interface selection
Transmission System aligned with real-time selection process using nomograms, methodology from CA ISO Reform
Representation market - masks significant LRAs and interties. These Proposal.
intra-zonal congestion. interfaces will account for most - Adopt preemptive congestion
- Not enough price granularity congestion, thereby assuring management. Force schedules to
to attract new generation. minimal intra-LPA congestion. respect transmission system limits.
- Provide shift matrix with flow Sell physical rights (PTRs) and
impact contributions of require PTR purchases with schedules
transactions for optional FTR (based on shift factor-based flow
purchases. impacts).
- Restrict PTR to short terms
(seasons, 3-months) to align
commercial with physical. Conduct
simultaneous auctions for multiple
periods to provide long-term rights.
Long Forward Market - FTR secondary market has low - Release 100% of FTRs net of - Develop central trading hub and
liquidity, due to limited existing contracts - 50% 3 yrs basis differentials (BDs) to enhance
FTR released (50% of ahead, and the rest monthly. forward market liquidity. BDs can be
capacity net of existing used as financial instruments or to
contracts). buy packaged PTRs.
- Release 100% of PTRs net of
existing contracts, mostly in annual
auctions, and the remaining in
short-term capacity auctions.
- Allow continuous trading of energy,
secondary transmission and BDs in
exchanges.
Tabors Caramanis & Associates 15 of 15
MARKET ASPECT CURRENT IMPLEMENTATION CA ISO REFORM PROPROSAL CA PX PROPOSAL
PROBLEMS MOTIVATING
REFORM
- ------------------------------------------------------------------------------------------------------------------------------------
Day Ahead - Gaming potential between two - Run a simplified commercial model - Require day-ahead submission of
Scheduling and iterations exists, since (LPAs as nodes) to clear inter-LPA balanced schedules with PTRs, which
Adjustment Period first iteration is not congestion, which will model the are congestion-free (eliminates need
binding. whole WSCC in simplified form. for day-ahead settlement and CONG
- Can lead to fictional - Congestion Management Activity process).
congestion, because ISO will make both iterations binding - Allow schedule adjustments up until
accepts all schedules (No - ISO will select the cost- real-time (however defined), which
intra-zonal congestion effective of the two. coincides with the close of forward
management (AZCM) done). - Even though intra-LPA congestion markets.
- Exacerbated by local market is not expected, run full network - Release capacity from unscheduled
power, and AZCM may not have model to ensure this (leaves open ETCs as recallable capacity.
a competitive solution. the course of action if intra-LPA - Release capacity from unused PTRs as
constraints are violated). firm PTRs.
- Release unscheduled ETC capacity - Award PTRs to participants with
as recallable transmission scheduled counterflows, which can be
capacity. sold in the exchanges until
real-time.
Real-Time Balancing - Efficiency of bids to - Develop efficiency-weighted BEEP - Employ same algorithms and tools as
Market alleviate congestion is not stack using shift factors to proposed in the CA ISO Reform
taken into account. indicate efficiency. proposal to clear real-time
- RMR units used - Institute 2 day-ahead market for congestion, both within LPAs and on
indiscriminately to clear local reliability requirements. inter-LPA interfaces.
AZCM. - Calculate marginal prices at - Retain 2 day-ahead market for local
- Local market power is interties separate from LPAs. reliability requirements.
observed only as late as RT, - Relax market separation rule to
AZCM cost is high. allow efficient imbalance energy
pricing and dispatch.
Seams - Interaction - Potential gaming at seams - - BEEP will be split at the - PTRs will be sold on bordering
with Neighbors BEEP is not split for bordering interties, reducing interties, and will be treated the
intertie congestion. gaming potential. same as intra-CA interfaces.
- Relatively low liquidity. - High likelihood that neighbors will
adopt a physical rights model, in
which case integration will be
seamless.
- The institution of a trading hub
will facilitate increased inter-
regional trading.
Tabors Caramanis & Associates 16 of 16