EXHIBIT 99.362
REFORM OF THE CALIFORNIA ELECTRICITY MARKET
A PATH FORWARD
Over the past year the California ISO has addressed a series of seemingly
unrelated market problems through a sequence of proposed amendments to the
market design. These proposed amendments have pertained to generator
interconnection (Amendment 19), intra-zonal congestion management (Amendments 18
and 23), RMR scheduling (Amendment 26), and providing incentives for generator
construction and transmission expansion in transmission constrained areas
(Amendment 24). However, it is now apparent, and clear from recent FERC
decisions, that these are not disconnected issues. In fact, all of these
problems have a common origin in fundamental market design flaws of the current
pricing system. Fundamental problems require solutions that are comprehensive
and go to the fundamental issue.
The need for comprehensive and fundamental reform of the California congestion
management system has been recognized by the FERC, which has directed the ISO to
design a comprehensive replacement congestion management approach. The purpose
of the current stakeholder process should be to develop such a comprehensive
approach that addresses the fundamental flaws in the overall congestion
management scheme.
Almost by definition, the current pricing rules cannot "get the locational
prices right." Instead, the current zonal pricing system suppresses commercially
significant locational price differences. Inevitably, the disconnect between the
resulting zonal prices and true market clearing prices and opportunity costs
means that the zonal prices cannot support efficient operating or investment
decisions in a competitive market. Because the current zonal pricing system does
not get the prices right, there is too little incentive to build new generation
or transmission where it is needed, too little incentive to start and operate
existing generation in constrained areas, too much incentive to build and
operate generation in some constrained down areas, and the marketplace incurs
excessive redispatch costs in maintaining reliability.
These problems must be addressed, and a fundamental choice confronts the ISO and
market participants in deciding how they will be addressed. The alternatives are
to address these problems by imposing additional restrictions on the market and
moving to greater reliance on centralized decision making and command and
control, both in maintaining short-term reliability and making long-term
investments; or to move to enable decentralized decision making, in both the
short-term market and with respect to long-term investments, by getting the
prices right. We support the latter approach and are proposing reforms of the
California market that are intended to promote reliance on market mechanisms for
congestion management in both the long and short-run.
In proposing an integrated fundamental reform of congestion pricing in the
California electricity market, it is important to be clear about the core
elements of the interconnected components. We recognize that it will be
necessary to move in an orderly manner from
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the current system to the intended end state. Nevertheless, we share the view
that the ISO's congestion management reforms must move expeditiously and
strongly in the direction of using market-based prices, rather than non-market
prices and command and control measures, to manage congestion on the California
grid. Consistent with this view, we are united in our belief that the ISO must
use pricing mechanisms that accurately reflect the actual market value of energy
at each location, including the effect of congestion and redispatch costs on
that market value. We believe that more accurate pricing will provide the
short-term and long-term price signals that will permit reliance on a market
driven approach to managing congestion, while substantially reducing the need
for non-market intervention by the ISO in either short-term operating decisions
or long-term investment decisions. Only when the transmission prices that market
participants face are aligned with grid realities and congestion redispatch
costs will the market begin to respond naturally to prices in ways that are
consistent with relieving congestion and maintaining reliability.
Furthermore, we share the belief that the market can have greater commercial
flexibility, and the ISO will have substantially less need for intervening in
the market, only when the market has the proper price incentives to make these
goals possible. Unless all commercially significant price differences are
reflected in the ISO's transmission pricing system, the ISO will have a
continuing need to rely on command and control mechanisms for congestion
management. The goal of providing better and more accurate pricing that reflects
all commercially significant price differences should therefore be the North
Star guiding the ISO's efforts to reform its congestion management system.
We recognize that mitigation of locational market power must be a component of
any reform of the California market and congestion management system. Our
proposal includes a comprehensive framework for addressing locational market
power. Moreover, this proposal will create a more liquid competitive market in
which it will be more difficult to exercise any form of market power.
We understand that any fundamental redirection of the ISO's congestion
management approach will require a significant effort by all concerned. Some of
the mechanisms needed to price congestion more accurately may not yet be
available to the ISO and may require time to develop. Similarly, metering
limitations may limit the degree to which many loads within California can
accept and respond to price signals. A phased approach, grounded in what can
realistically be accomplished in each phase, will be necessary. The limitations
applicable to particular generators or consumers should not, however, foreclose
options to other generators or consumers to whom those limitations are not
applicable. Moreover, it is necessary that the reform effort be consistently
guided towards ensuring that commercially significant transmission cost
differences are reflected in transmission prices and in promoting reliance on
market based mechanisms for congestion management.
We foresee two transition phases in the reform of the California ISO's
transmission pricing system. During the Immediate Phase, the ISO will shift its
philosophy toward
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reliance on market based congestion management systems. This phase could begin
immediately. In particular, it need not wait until every element of the ultimate
reform package is filed at FERC. The ISO will also begin to modify elements of
its software and accounting system so as to improve its ability to manage
transmission congestion on a market-price basis and to provide pricing
flexibility to its transmission customers. Here too, the ISO need not wait until
every element of the ultimate reform package is filed at FERC to begin
developing the more flexible software that may be required by a market based
congestion management system. In the Near Term Implementation Phase, customers
will be provided flexibility in choosing among transmission pricing systems,
ensuring that all customers capable of responding to commercially significant
price differences have the opportunity to do so. The market will then gradually
evolve towards the end state to the degree required by the commercial interests
of the market participants.
The significant elements of these transition phases are described briefly below.
IMMEDIATE PHASE (2000)
1. Energy and ancillary service prices, and locational differences in prices,
will provide the market incentive for needed generation and transmission
investments.
o Non-wires investments will be based on market decisions and will not be
included in the regulated rate base.
o When there are substantial free-rider problems or other market failures,
investment in new transmission wires could be made under a regulatory
backstop designed to maintain the system's ability to serve price
inelastic load. In addition to the reliability backstop approach, recovery
in the access charge of costs associated with new transmission investments
would be allowed if the proponent is able to demonstrate both that the
investments are economically justified and that free rider effects prevent
the recovery of these costs in the market.
2. Congestion zones will be split to permit reliance on inter-zonal congestion
management mechanisms whenever intra-zonal congestion becomes commercially
significant. If the ISO concludes that the intra-zonal congestion management
system is not working or is failing to provide needed incentives, the ISO
will be required to address the problem by splitting zones, not through Out
of Market (OOM), Out of Sequence calls (OOS), restrictions on entry,
subsidies or other extra-market devices for managing intra-zonal congestion.
The rule will be that if the intra-zonal congestion pricing system does not
work well, the ISO will split the zone. Implementation of this policy prior
to the expiration of current FTRs will require resolution of the treatment of
those FTRs.
During this phase, it is intended that the ISO will basically rely on the
current congestion management system. The most important change is one of
philosophy: The ISO will be directed to manage transmission congestion on a
price basis and will
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not supplant the price system with command and control based congestion
management mechanisms. In instances in which the current intra-zonal pricing
system does not provide the incentives required to reliably and efficiently
manage transmission congestion, the ISO will manage congestion on a price
basis by splitting the zone.
3. Real time prices at existing ISO pricing locations (zones and boundaries)
will be consistent with marginal cost principles and determined by the use of
the ISO's inter-zonal congestion management mechanism.
4. Generator interconnection requirements will be limited to those required to
enable the generator to reliably deliver power to the grid. The congestion
management system will treat new and existing generators alike.
5. One or more trading hubs internal to California will be established and the
buses comprising the hubs determined. Hub prices based on the average of the
zonal prices at the buses comprising the hub will be posted.
This means that if the buses comprising the trading hub fall within a single
zone, the posted hub price will be equal to the underlying zonal price. If
the buses comprising the trading hub straddle two or more zones, the posted
hub price will be an average of the applicable zonal prices.
6. FTRs will continue to be defined and auctioned on a zone to zone basis, but
each inter-zonal FTR sold in future auctions will have a reference bus origin
and destination that will define its new origin and destination zone in the
event that the original origin or destination zone is split.
The steps envisioned by principles 5 and 6 will not entail changes in the
operation of the market during the initial phase, but are intended to smooth
future transitions as zones are split. FTRs will continue to settle based on
zonal price differences and congestion collections, but the origin and
definition points will be specified within these zones to define how these
FTRs would settle if the affected zones were to be split in the future.
Similarly, it is likely that all of the locations comprising each of the
trading hubs would initially be located within a single zone. The trading
hubs will nevertheless be established and defined on a point by point basis
so that the definition of the trading hubs will remain stable over time as
zones are split. This will enable market participants to begin writing
forward contracts based on the trading hub prices to the degree and at the
point in time that they find commercially appropriate.
7. Whenever restrictions on participation in the congestion management market,
including rules relating to balanced schedules, would prevent reliance on
market based congestion management, the ISO will initiate the process to
change the tariff to allow reliance on a market based congestion management
system.
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This principle does not require that restrictions on participation in the
congestion management necessarily be eliminated in the Immediate Phase, but
it does require that these rules not be permitted to stand in the way of
movement to a market based congestion management system. Adherence to
principles 1 and 2 will take precedence over maintaining these restrictions.
8. Entities paying for transmission expansions will be awarded FTRs
corresponding to the change in transfer capability associated with their
investment in the transmission system.
The changes described in the Immediate phase need not be implemented
simultaneously and will be implemented as the ISO and the market are prepared to
implement them. During this phase, the ISO will be preparing its systems for the
Near-Term Implementation Phase.
NEAR-TERM IMPLEMENTATION PHASE (2000/2001)
1. The ISO's commercial software will incorporate a load flow model able to
calculate LMP prices at each bus within the zones. LMP prices for each
generator bus and for significant load buses will be posted.
2. As in the Initial Phase, Zones will be divided as required to manage
transmission congestion. Zone splitting will be facilitated by calculating
zonal prices based on the weighted average of the bus prices within the zone.
The Near-Term Implementation Phase will continue the market on the path of
gradual evolution and the changes described need not be implemented
simultaneously. One of the changes will be that the ISO will begin to
calculate and post LMP prices for all generator locations and significant
load locations. After this software is operating smoothly, the ISO will shift
to calculating zonal prices based on the weighted average of the prices
within the zones. This change is anticipated to be desirable at this point in
time to better accommodate zone splitting and avoid anomalous outcomes.
3. Market participants will be allowed, but not required, to provide bids for
congestion management without regard to balanced schedules.
4. Real-time locational pricing will be based on marginal pricing principles and
will be consistent with the bids used in the actual real time dispatch of
resources by the ISO.
5. Generators with appropriate time of use metering will be able to choose to be
paid the LMP price at their location. Generators not selecting this option
will be paid the zonal price for their location, calculated as the weighted
average bus prices for energy injections subject to zonal pricing in that
zone.
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6. Generators electing to be paid the LMP price at their location will not be
eligible to receive constrained off payments.
7. Loads with appropriate time of use metering will be able to choose to pay
the LMP price at their location. Loads not selecting this option will pay
the zonal price for their location, calculated as the weighted average bus
price for energy withdrawals subject to zonal pricing in that zone.
Principles 5 and 7 ensure that the congestion pricing system will reflect
all commercially significant congestion. To the extent that the splitting of
zones by the ISO fails to capture the effects of congestion that is
commercially significant from the perspective of market participants, those
market participants will be able to choose to settle their transactions
based on LMP prices.
8. FTRs will be sold in periodic auctions administered by an impartial
auctioneer supervised by the ISO, and all FTRs that are simultaneously
feasible in conjunction with already outstanding FTRs will be available for
purchase and sale in these auctions.
9. Market participants will be able to acquire FTRs defined on a point-to-point
basis that will hedge congestion based on the corresponding zonal or
locational price at each point.
10. Market participants will be able to acquire FTRs defined as obligations in
the FTR auction and will be able to buy negatively priced FTRs in these
auctions, i.e. to sell congestion management forward through the FTR
auction.
11. Energy, ancillary service and transmission prices will include the cost of
incremental losses.
12. All market participants will be permitted to submit negative adjustment
bids.
13. The buses included in the trading hubs will remain unchanged, but the
trading hub prices will be calculated based on the average of the LMP prices
at those buses.
In this phase, the locations comprising the trading hubs may come to be
located in more than one zone and the trading hub prices will be calculated
based on the appropriate weighted average of the LMP prices at the buses
included in the trading hub.
14. RMR contracts will to the extent possible be called as part of the ISO
coordinated congestion management market -- not before, not after. RMR
contract calls will be integrated into the congestion management system and
will be able to determine market prices.
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This principle intends that the constraints requiring the operation of RMR
units be reflected to the degree practical in zonal definitions and that
the scheduling of RMR units be encompassed within the inter-zonal
congestion management system, although the bid prices of the RMR units may
be subject to continued market power mitigation rules.
15. Reliability will be maintained and congestion managed through market
incentives to the extent possible. In situations in which it is necessary
to mitigate market power, this mitigation will be implemented to the extent
possible through bid caps or financial instruments with a defined quantity
and term.
The development of more effective, efficient, and market based methods for
mitigating market power is an important task for the ISO, regulators and
market participants. It should be recognized, however, that except to the
extent that a particular proposal creates market power where none need
exist,(1) the need to mitigate market power arising from transmission
constraints and market concentration will be common to all proposals for
reforming congestion pricing.
It is proposed that the transmission constraints currently mitigated by RMR
contracts, as well as other intra-zonal congestion, be managed on a price
basis by splitting zones as required. In circumstances in which locational
market power currently exists, it is proposed that this market power be
mitigated through the negotiation of bid caps and/or CFD or FTR options
covering energy and reserves. The prices embodied in these bid caps, or
options would generally be higher for higher amounts of output. The amount
of output and reserves covered by these contracts would at minimum be
sufficient to enable the ISO to dispatch resources to meet current load,
and the amount of output covered would escalate in the short-term to cover
short-term load growth. Beyond this transition phase, the incremental
output required to meet future load growth would be priced in the market.
The bid cap approach would require a generator subject to the bid cap to
offer a specified quantity of output and/or reserves into the market at
specified locations at prices less than or equal to the bid cap. The CFD
option approach would require the generator subject to the market power
mitigation to pay the CFD option holder the difference between the day
ahead locational price (whether zonal or LMP) and the CFD price at the
specified location for specified quantities of output or reserves when the
difference was positive. No payment would be required by the option holder
when the locational price is less than the option price. The generator
would in effect sell an option on sufficient output or reserves forward to
the CFD holder to mitigate the generator's market power and the generator
could choose the least cost method to cover the call of this option. The
CFD option would be auctioned to load serving entities and other market
participants not affiliated with the seller, with the proceeds
- ----------
(1) The current congestion management system, for example, has the potential to
create market power where none need exist both in the hypothetical day ahead
zonal dispatch and in the intra-zonal redispatch in real time.
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credited against the access charge within the transmission constrained
region. The FTR option approach would require the generator subject to
market power mitigation to pay the FTR option holder the difference between
the day ahead locational price at a specified location (whether zonal or
LMP) and the day ahead locational price at a specified market hub when the
price at the specified location exceeds a specified trigger price. The
generator would in effect sell a specified quantity of redispatch energy
whenever the locational price at a specified location exceeded the trigger
price. The FTR options would be auctioned to load serving entities and
other market participants not affiliated with the seller, with the proceeds
credited against the access charge within the transmission constrained
region.
In transmission constrained regions within which reliability criteria cause
the ISO to attempt to schedule target quantities of reserves, the ISO would
attempt to schedule these target reserve quantities in the day ahead
market. The pricing system would recognize that it is not economic to
maintain this target level of reserves under all demand conditions, and the
amount of locational reserves actually scheduled by the ISO would be
reduced when the locational cost of such reserves exceeds their economic
value. These economic values would be specified in advance, applied on an
objective basis by the ISO in the day ahead market, and would set the price
of reserves when the target level of reserves is not met either day ahead
or in real time. In addition the locational price of energy within the
transmission constrained region would reflect the price of reserves at
times when the region is reserve constrained.
END-STATE
The core of the end-state pricing system for the California electricity market
to which the market is expected to evolve over time is described by the
following elements:
1. The ISO's congestion management system will be based on the principles of
bid-based economic dispatch and market clearing prices for energy and
ancillary services. Energy, ancillary services, and transmission pricing
will be based on locational marginal pricing.
2. Energy and ancillary service prices, and locational differences in prices,
will provide the market incentive for needed generation and transmission
investments.
o Non-wires investments will be based on market decisions and will not be
included in the regulated rate base.
o When there are substantial free-rider problems or other market failures,
investment in new transmission wires could be made under a regulatory
backstop designed to maintain the system's ability to serve price
inelastic load. In addition to the reliability backstop approach, recovery
in the access charge of costs associated with new transmission investments
would be allowed if the proponent is able to demonstrate both that the
investments are economically justified and that free rider effects prevent
the recovery of these costs in the market.
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3. Financial transmission rights will be established in the form of point to
point FTRs. Ownership of an FTR will entitle the holder to receive, or in
the case of FTR obligations, require the holder to make, a payment equal to
the difference in spot prices between the destination and origin points of
the FTR.
4. FTRs will be sold in periodic auctions administrated by an impartial
auctioneer supervised by the ISO, and all FTRs that are simultaneously
feasible in conjunction with already outstanding FTRs will be available for
purchase and sale in these auctions.
5. Entities paying for transmission expansions will be awarded FTRs
corresponding to the change in transfer capability associated with their
investment in the transmission system.
6. Loads with appropriate time of use meters will pay locational prices and
will be able to provide ancillary services (such as 10 and 30 minute
reserves).
7. Energy, ancillary services and transmission prices will include the cost of
incremental losses.
8. Generator interconnection requirements will be limited to those required to
enable the generator to reliably deliver power to the grid. The congestion
management system will treat new and existing generators alike.
9. One or more trading hubs internal to California will be established and the
locations comprising the hubs determined. Day ahead and real time hub prices
based on the average of the LMP prices at the locations included in the
trading hub will be posted.
10. Reliability will be maintained and congestion managed through market
incentives to the extent possible. In situations in which it is necessary to
mitigate market power, this mitigation will be implemented to the extent
possible through bid caps or financial instruments with a defined quantity
and term.
CRITERIA FOR A COMPREHENSIVE SOLUTION
We propose that the following criteria be adopted in evaluating market reform
proposals:
MINIMUM REQUIREMENTS:
1. Reliability is maintained and congestion managed through market incentives
based on energy, transmission and ancillary services prices, not command and
control.
2. Energy and ancillary services prices, and locational differences in prices,
reflect actual transmission limitations and market conditions and provide
the market incentive for needed generation and transmission investments.
3. Non-wires investments are based on market decisions and are not included in
the regulated rate base.
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4. The congestion management system treats new and existing generators alike.
5. Suppliers are able to hedge themselves against congestion arising after the
entry of new generators, or after upgrading of existing generation, through
the acquisition of a financial transmission right from their location to a
trading hub or customer location
6. Consumers are able to hedge themselves against congestion arising after the
entry of new loads or following future load growth through the acquisition
of a financial transmission right from a generator or trading hub to the
location of their load.
7. All commercially significant transmission congestion is reflected in
transmission prices. The transmission pricing system ensures that market
participants are able to respond to cost and revenue differences that they
find commercially significant.
8. The potential for the exercise of locational market power is mitigated
through mechanisms which are compatible--to the extent possible--with the
principle of bid-based marginal cost pricing and market based congestion
management.
DESIRABLE FEATURES:
1. Market participants are able to buy and sell financial transmission rights
in periodic auctions supervised by the ISO. Financial transmission rights
supported by 100% of the transfer capability of the transmission system on a
simultaneous feasibility basis should be available for sale in the auctions.
2. Financial transmission rights are available for purchase in the auction at
market clearing prices in the form of either options or obligations.
3. In situations in which it is necessary to mitigate market power, this
mitigation is implemented to the extent possible through financial
instruments with a defined quantity and term rather through ongoing physical
call contracts (e.g. RMR contracts).
4. All loads with appropriate metering are able to participate in day ahead and
real time energy, congestion management and ancillary service markets.
5. All suppliers with appropriate metering and capabilities are able to
participate in day ahead and real time energy, congestion management and
ancillary service markets.
The undersigned parties believe that this proposal represents a comprehensive
solution that provides a means to solve the problems that confront the market
participants through reliance on market mechanisms for congestion management and
provides the fundamental reform that FERC has mandated. We intend, however, to
listen to the proposals of others and are ready to make improvements suggested
by others or to adopt proposals that better achieve the objectives we have
described.
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Reliant Energy
Sempra Energy
Southern Energy
TURN
UCAN
Williams Energy Marketing & Trading
March 30, 2000
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