Exhibit 99.403

Introduction:

This document presents proposed modifications to the ISO's Congestion Management
Reform Recommendation that has been developed by the PX and other market
participants. It incorporates concerns previously raised with the ISO's proposal
while remaining consistent with the ISO's overall principles.

Revisions to specific portions of the ISO's recommendations are described this
paper. It is not intended to replace the ISO's entire proposal. Instead, it
describes how certain modifications to the ISO's recommendations should be to be
implemented to meet the needs of the market. We believe that these changes can
be effectively integrated into the ISO's proposal.

Much of the Comprehensive Market Reform design can and should be retained. The
decisions to build upon the existing California market structure and to uphold
the original fundamental design principles have significant value, as does the
proposed use of a consistent network model throughout the Real-Time and forward
markets. Another principle that should be adopted is to permit the market to
solve problems and "self provide" wherever possible.

The introduction of a single commercial network model should eliminate most of
the inconsistencies that currently exist between the forward and real time
markets. The introduction of additional LPAs along with the enforcement of
nomograms in the forward markets should facilitate the reduction of forward
intra-zonal congestion, and thereby reduce Real-Time intra-zonal congestion. We
are concerned, however, that much of the information provided by the ISO to date
on the integration of nomograms, LPAs and distribution factors has been
illustrative; we believe that it is vital that market participants have access
to meaningful market proposals that are more then illustrative examples of how
it "might" work as soon as possible. It should be made available in time for the
market to evaluate it before market participants have to prepare FERC filings.

Design consistency should extend beyond the network model. When finalizing the
details of their recommendation the ISO should make certain that policies are
uniform across markets and do not discriminate against any single class of
stakeholder.

Forward congestion will be better managed with the introduction of nomograms in
CONG (the ISO's congestion management software). The creation of new LPAs and
the enforcement of nomograms will allow the market to eliminate much of the
current intra-zonal congestion in the forward markets. The use of consistent
nomograms in the forward and Real-Time markets and operations should further
contribute to a reduction in Real-Time congestion.

Utilizing recallable transmission will potentially further enhance congestion
management efficiency. We support the concept of a product that provides the
market access to non-firm transmission capacity that is currently reserved for
Existing Transmission Contract (ETC) holders. However, more details of the
proposed market are required to fully judge

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its impact. Specifically, the ISO should address the Operating or Replacement
Reserve requirements of users of recallable transmission capacity, and what role
the ISO will play in this regard. If greater Reserve is required, an assessment
of likely impact on the current Ancillary Services market should be performed.

When defining market mechanics it is important that the ISO pursue the simplest
workable solution. Unnecessary levels of complexity are significant barriers to
market participation and thus, market liquidity and efficiency. The ISO should
also seek to avoid market proliferation. Increasing the number of markets into
which the same energy or capacity can be sold fragments the markets and may
adversely affect liquidity and efficiency. Those aspects of the ISO's proposal
that have been identified as overly complex or fragmented are simplified in the
enclosed recommendations.


Comments on the Long Forward Market:

The Long Forward market design doesn't consistently conform to the ISO's
self-stated goals of enhancing market efficiency through decentralized decision
making. Instead, the market structure includes processes that abandon market
solutions - even in situations when the marketplace is best suited to
efficiently resolve reliability requirements.

One such process is Local Reliability Service (LRS) procurement. The ISO's
proposal relies on the introduction of a new process that includes a
two-day-ahead "auction" to procure generation within each Local Reliability Area
(LRA). This process abandons existing market structures and instead,
unnecessarily increases the ISO's presence in the forward markets. For example,
without affording sufficient opportunity for loads to self provide needed
reliability capacity and energy, the ISO plans to acquire these services on
their behalf based in its forecasts, and require that energy related to portions
of the purchased capacity be scheduled in the Day-Ahead. Capacity purchased by
the ISO in the 2-Day-Ahead market, but not identified as "Minimum Reliability
Energy" (and thus required to be scheduled in Day-Ahead) may be dispatched by
the ISO as needed through Real-Time.

In reality, two distinct and separate products are being acquired by the ISO in
this process. Purchased capacity that is scheduled as Minimum Reliability Energy
(MRE) in the forward market is not really capacity. It is instead, locational
firm energy and should be treated as such. And, since it is afterall energy, it
is susceptible to bilateral contracts and self provision. Additional committed
capacity that is reserved by the ISO for potential dispatch through Real-Time
should be obtained through existing processes such as the Day-Ahead and
Hour-Ahead Ancillary Services markets. This capacity is nothing more then
locational Reserve, with a few less WSCC/NERC constraints around minimum
requirements. Furthermore, like other Reserves, it should be something that the
loads as well as generators can provide.

The decision to schedule MRE is a forward energy allocation decision. Thus, if
the ISO is to remain consistent with it's goals of maintaining the decentralized
decision making

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process, it should let SCs complete this task. SCs should be responsible for
scheduling load and generation within LRAs according to current Day-Ahead and
Day-Of timelines and plans for introducing a 2-Day-Ahead auction should be
abandoned.

All relevant nomogram constraints and other operating requirements should be
placed in CONG, which should validate whether enough generation within each LRA
has been scheduled to meet daily load requirements. If insufficient LRA
generation has been scheduled, CONG should either increment the necessary
generators based on their adjustment bids, or it should decrement those loads
that exceed the nomogram limitations. However, to the extent that all LRS
generators are required to offer incremental adjustment bids, as has been
suggested by some parties, there should not be a need to decrement load.

CONG will ensure that scheduled generation and load satisfy each nomogram on a
market-wide basis rather than by SC. Inter-SC trades and LRS adjustment bids
could increase competition and efficiency. Also, CONG would determine "usage
charges" for flows across nomogram constraints. SCs would pay usage charges for
bringing power across nomograms. Conversely, SCs whose schedules allow other SCs
to import more across nomograms would be paid the usage charges for their
counter-flow. This is necessary to conform to nomogram requirements efficiently.

Qualified market operators could facilitate the forward procurement of MRE and
CC by running markets to help participants develop schedules that meet nomogram
requirements and avoid the associated usage charges. Buyers and sellers would be
able to trade MRE and CC using many different contract types and would
self-provide the resulting positions in the Day-Ahead market.

Nomograms simply represent another scheduling constraint: one that can and
should be expressly valued by the marketplace. Releasing Nomogram rights in the
same primary auction format as FTRs would allow the market, rather than the ISO,
to value them. This would also them to be traded in the secondary markets. If
the ISO did release nomogram rights, loads could purchase the rights to hedge
against the Locational Price Areas (LPAs), avoid the cost of expensive in-area
generation and enhance market efficiency. Nomogram rights, like FTRs would be
both physical and financial.

If this structure were introduced, loads within LRAs would have sufficient
incentives to acquire nomogram rights and to schedule in the forward markets to
hedge against ISO charges. The ISO would remain consistent with its stated goals
and would not need to implement a totally new market whose effects on existing
market are potentially detrimental.

A substantial benefit of adopting this method of market power mitigation is that
it preserves the financial value of FTRs. This is not the case with the ISO's
proposal. Implementation of the ISO's LRS procurement process will result in the
purchasing of substantial amounts of generation within each LRA in advance of
the Day-Ahead market. This would significantly reduce or eliminate congestion on
paths flowing into LRAs, and

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as a result, distort the financial value of FTRs. Adoption of the ISO's proposal
will result in FTR purchasers having to value FTRs based on their expectations
of the ISO's ability to make accurate forecasts rather than on historical market
information. However, because the PX's proposal relies on standard Day-Ahead
congestion management processes to correctly allocate generation to in-LRA load,
the proper financial signals will be sent to FTR holders in the form of usage
charges.

If after running Day-Ahead and / or Day-Of congestion management, the ISO felt
that an insufficient amount of minimum reliability energy had been scheduled it
would acquire "committed capacity" (CC), which would be dispatched, if needed,
through Real-Time. The ISO could also procure CC if it expected additional
in-LRA load appear in Real-Time). The ISO would obtain committed capacity by
having generators bid to supply it as an additional Ancillary Service.

The Committed Capacity ancillary service will be treated in the same fashion as
existing A/S types with the exception that CC will be purchased on a zonal / LPA
basis rather than a market-wide basis. Like other A/Ss, it would be downward
substitutable if it less expensive the other Reserve bids. SCs will be allowed
to self-provide the service according to the same rules that govern
self-provision today. SCs who have available capacity will be able to submit
bids to supply CC to the ISO, which would procure it along with its other
Ancillary Services. As with minimum reliability energy, SCs will have the
incentive to self-provide this service to hedge against ISO charges.

Because some level of market power will exist within LRAs until new generation
or transmission is built, market power issues must be addressed. Market power
issues are the same regardless if the ISO adopts the PX's recommendations or
not: a backstop price must be determined that protects loads from undue market
power, provides sufficient revenues to generators and provides locational price
signals in accordance with FERC requirements. The PX feels that the ISO and its
stakeholders are capable of developing a workable solution to this issue and
thus does not(?) offer a specific price cap proposal at this time.

While this approach differs from the one proposed by the ISO, it contains enough
benefits to warrant adoption. This model's primary advantage is its greater
consistency with the original California design principles. In it, the ISO's
primary roles are information supplier (to facilitate the efficient scheduling
of load and generation) and supplier of last resort (in situations where
insufficient generation was scheduled or additional load was expected to appear
in Real-Time). Physical forward scheduling is accomplished through decentralized
decision making.

The ISO staff proposes to be responsible for both forecasting and obtaining MRE
and CC. While the ability for SCs to self-provide these services has been added
to their proposal, the proposed timelines make it more likely that the majority
of scheduling decisions will be made by the ISO. This is because the proposal
requires SCs to finalize LRA schedules one day in advance of the Day-Ahead
market. In addition, it is not clear

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that the ISO's proposed cost allocation mechanism would provide sufficient
incentives for self-provision.

The PX's approach relies existing market mechanisms to efficiently allocate LRA
resources within existing timelines. This ensures that procurement of MRE and CC
does not interfere with or distort other Day-Ahead scheduling decisions. When
the amount of energy and capacity that is likely to be allocated through this
process is considered, the importance of adopting an approach that compliments,
rather than supplants existing market structures is made clear. ISO statements
that the procurement of MRE and CC could even extend to competitive LPAs in
certain situations only underscores the importance of adopting the PX's
approach.


Comments on FTRs:

The ISO staff is to be commended for responding to stakeholder input and
limiting the term of FTRs to one year. This will provide required price
certainty, as the market becomes familiar with the implications of new zonal
boundaries and the interactions of loops in the transmission model as well as
the use of nomograms. Additionally, it is easier to link annual FTRs to zone
creation and redefinition policies. As boundaries solidify, the sale of
longer-term rights should again be examined, however.

Some modifications to the ISO's proposed transmission rights policies are
required though. The ISO should release all ATC as FTRs in their annual primary
auction. The specific percentage should depend on the amount of rights that can
be released with a predetermined annual level of certainty. If this is done,
secondary markets will develop to reallocate transmission rights. The ISO can
compliment this process by releasing shorter-term seasonal FTRs, as they become
available.

Shorter-term FTRs may help the market adjust for seasonal variances in
transmission capacity. However, questions must be addressed before the nature
and amount of shorter-term FTRs to be released is determined. How significant of
a barrier to the development of liquid secondary markets are shorter-term FTRs?
How often is transmission capacity significantly affected by weather or other
considerations (are monthly auctions required or are longer terms such as
quarterly better)? How much of a change in transmission capacity is needed and
how long must the new levels be sustained before the ISO determines that the
capacity in question can be auctioned as an FTR? These questions will be able to
be answered only if the ISO releases its criteria for determining Available
Transmission Capacity.

Of additional concern is the ISO's proposed method of allocating costs to FTR
holders. The ISO has stated that in the event of topology or operating transfer
limit changes they intend to "keep market participant's financially whole by
creating a balancing account of net gains and losses." Balancing accounts are to
be cleared by each applicable PTO on a monthly basis. The details of this
proposed arrangement need to be provided, but an initial examination of the
information reveals deep concerns.

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If the ISO publishes a "library" of shift factors as is stated in their
proposal, and the factors are published in advance of the primary auction, SCs
should be capable of planning for and reacting to system changes. For instance,
SCs could purchase enough FTRs in the primary auctions to cover the range of
potential shift factor changes. Those who were unwilling or unable to purchase
rights in the primary auction could bid to purchase required FTRs in the
secondary markets that will be provided by such qualified exchanges as the PX.

If SCs are given information about shift factor changes in time to adjust their
schedules and transmission rights, they are capable of making educated business
decisions and dealing with the resulting financial implications. Having a
central balancing account where profits are used to offset others losses is not
only unnecessary, it is contrary to the most fundamental free-market concepts.

Instead of pursing this course, the ISO should treat financial rights in the
same manner as they propose to resolve scheduling priorities: SCs should be
responsible for procuring additional FTRs when the ISO implements new sets of
shift factors. Those who choose not to hedge by purchasing additional FTRs on
the secondary market would expose portions of their schedules to both financial
and physical delivery risks.


Comments on the Forward Market:

We support the efforts of the ISO to preserve the original design concepts of
the deregulation process, which we feel are well represented in the proposed
enhancements to the forward market. However, certain changes are required to
further improve the recommended modifications.

A change that is supported is the introduction of Inter-SC adjustment bids.
While the implementation of this functionality is outside the scope of the
congestion reform project, its effects are not. The ISO's market separation
study clearly shows that the existing market structure is an efficient one.
However, Inter-SC trade adjustment bids can only enhance efficiency for those
SCs who choose to use them. When the efficiency of the existing market structure
is combined with the fact that decentralized decision making remains a
cornerstone of California's proposed deregulation model, arguments against
additional relaxation of market separation become overwhelming.

There is a proposed enhancement that would threaten market efficiency, however.
Implementation of the ISO's proposed congestion activity rule would create as
many, if not more, issues than it would resolve. While it is understood that
this rule was designed to provide the ISO with the opportunity to always select
the lowest cost scheduling iteration, it is not the appropriate way to insure
against potential market behavior. Rather than reducing the potential for
damaging market behavior, the congestion activity rule would simply increase the
likelihood that both iterations would become distorted. The level of uncertainty
that the implementation of the activity would introduce increases this

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tendency. Stakeholders will be less willing to enter into new, binding
transactions if there is the danger that the ISO will force them to be cancelled
with any degree of frequency. If the ISO is concerned about limiting the
potential gaming affects of having two congestion management iterations, it
should either adopt different activity rules or consider eliminating the second
iteration entirely.


Comments on Real-Time:

Based on our current understanding, the PX supports the ISO's proposed Real-Time
changes. However, more information is required to fully evaluate them. For
instance, the anticipated dispatch model hasn't been adequately defined and
should be released to the marketplace for examination. Additionally, since the
ISO is proposing to move to a transmission constrained economic dispatch
optimization model to dispatch Real-Time energy, references to Real-Time bid
stacks should be removed from the draft proposal to eliminate confusion. The PX
support of a Real-Time optimization model is predicated on the understanding
that only Real-Time bids will be optimized.

If the optimization model is used to re-dispatch previously scheduled energy
that doesn't have explicit bids (other than in system or local emergencies) many
of the fundamental principles of California's deregulation process will be
undermined.


Conclusion:

The PX commends the ISO for their efforts to develop a comprehensive congestion
management solution. However, we urge the ISO to incorporate these modifications
into their proposal. The integration of these concepts with the ISO's existing
proposal will ensure that the maximum benefits of any reform are enjoyed by all
Californians. Failure to do so, however, will significantly blunt the benefits
of any changes.

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