Exhibit 99.224
Introduction:
This document represents an alternative 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 need to be
implemented. 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. 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. Using the commercial model for all aspects of the ISO's grid
management process will help maximize market transparency and liquidity. 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 should further contribute to a reduction in
Real-Time congestion.
Utilizing recallable transmission (RT) 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 RT market and its interaction with other ISO markets and
processes are required to fully judge its impact. The ISO must ensure that the
changes it proposes to improve one aspect of its processes would not have
significant adverse effects on changes that it is proposing to improve other
aspects of its processes.
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
adversely affects 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.
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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,
rather than affording loads sufficient opportunity to acquire needed reliability
capacity and energy, the ISO plans to acquire these services on their behalf
based in its forecasts, and require that 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. Additional contingency 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.
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 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.
If ISO requires that particular resources be committed based on its forecasts.
It can notify the units that they must commit. Actually scheduling the energy
from the resources should be done in existing Day-Ahead and Hour-Ahead markets.
Generators would be able to bid in ISO Day-Ahead and Hour-Ahead CC markets, or
sell CC to other SCs.
CONG will ensure that scheduled generation and load satisfy each nomogram on a
market-wide basis rather than by SC. Inter-SC trades and adjustment bids could
increase
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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 energy
and Contingency Capacity (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 energy 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. By incorporating nomogram and
operating procedures into the determination of available transmission capacity,
buying FTRs based on those limitations would allow the market, rather than the
ISO, to determine the value of capacity. This would allow holders to purchase
hedges against expensive in-area generation and thus enhance market efficiency.
FTRs would continue to be both physical and financial.
If this structure were introduced, loads within LRAs would have sufficient
incentives to acquire FTRs 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 enforcing nomograms and pricing
flows across nomograms 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 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 this 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 "contingency capacity" (CC), which would be dispatched, if needed,
through Real-Time. The ISO could also procure CC if it expected additional
in-LRA load to appear in Real-Time. The ISO would obtain contingency capacity by
having generators bid to supply it as an additional Ancillary Service.
The Contingency 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
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rather than a market-wide basis. 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.
The key to self-provision of reliability energy and capacity is the ISO's
commitment to provide the information needed by market participants to acquire
and manage reliability products. Rather than designing a new product and
determining how to run a residual market, the ISO should focus on effectively
providing the needed information on nomogram constraints and local resource
requirements for SCs to make their own arrangements.
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 of whether the ISO adopts these 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.
We believe that it is unlikely that market participants will be able to develop
a consensus position on bid caps or other mechanisms for market power
mitigation. Thus, we recommend the following mitigation process, which would
require price determination by FERC.
For generators that are specifically required to provide local reliability
service:
Option 1: Non-competitive generators would contract with the ISO (or other
entities) for cost of service recovery comparable to current "Condition 2"
units.
Option 2: Other "required" units would be subject to either a standing
adjustment bid curve or a bid cap, and would include unit commitment and
contingency capacity caps, that would be filed and approved by FERC. All bids to
ISO (adjustment bids or CC bids) would be capped at FERC-approved rates, and the
resource would be required to submit bids for its full available capacity in all
markets.
Generators that are not specifically required to provide local reliability
service (located in LRAs with minimal requirements or multiple potential
providers) would only be subject to whatever overall caps the ISO is authorized
to set. (To mitigate occasional market power exercise by these resources,
load-serving SCs could enter into forward contracts with the generator owner.)
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
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additional load was expected to appear in Real-Time). Physical forward
scheduling is accomplished through decentralized market solutions.
The ISO intends 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 ISO's proposal
requires SCs to finalize LRA schedules one day in advance of the Day-Ahead
market. In addition, it is not clear that the ISO's proposed cost allocation
mechanism would provide sufficient incentives for self-provision.
This approach relies on 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 complements,
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 this
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. 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 ATCs that can be predetermined
annually based on specified level of certainty 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 the annual release of FTRs 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?
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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.
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 a range of
potential shift factor changes. Those who were unwilling or unable to purchase
rights in the primary auction could bid to purchase desired 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 pursuing this course, the ISO should treat financial rights in the
same manner as they propose to resolve scheduling priorities: SCs who wish to
hedge their congestion costs 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 congestion management process 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
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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 tendency.
Stakeholders will be less willing to enter into new transactions during the
iteration 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, we support 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. Our
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:
We commend the ISO for their efforts to develop a comprehensive congestion
management solution. However, we urge the ISO to incorporate our 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.
The California Power Exchange
Western Power Trading Forum
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