EXHIBIT 99.366
MARCH 14,
2000 DRAFT
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.
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 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
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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 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 forsee three transition phases in the reform of the California ISO's
transmission pricing system. During the Initial Phase, the ISO will shift its
philosophy toward 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. In the Near Term
Implementation Phase, the ISO will 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. Finally, in
the Intermediate Implementation Phase, customers will be provided flexibility in
choosing among transmission pricing systems, ensuring that all customers are
able to respond to commercially significant price differences. The market will
then gradually evolve towards the end state to the degree required by the
commercial interests of the market
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participants. The significant elements of these transition phases are described
briefly below.
INITIAL PHASE
1. Energy prices, and locational differences in energy 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 or distribution wires would be
made under a regulatory backstop. Recovery in the access charge of
costs associated with new transmission investments will require a
demonstration 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 facilitate inter-zonal congestion
management whenever intra-zonal congestion becomes commercially
significant. If the ISO concludes that the intra-zonal congestion
management system is not working or failing to provide needed
incentives, the ISO will be required to address the problem by
splitting zones, not through OOM, 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.
3. Generator interconnection requirements will be limited to those
required to enable the generator to reliability deliver power to the
grid. The congestion management system will treat new and existing
generators alike.
4. One or more trading hubs internal to California will be established and
the buses comprising the hubs determined. The ISO will post hub prices
based on the average of the zonal prices at these buses.
5. FTRs will continue to be defined and auctioned on a zone to zone basis,
but each inter-zonal FTR 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.
6. Restrictions on participation in the congestion management market,
including rules relating to balanced schedules, will be eliminated as
required to permit reliance on market based congestion management.
7. Entities paying for transmission expansions will be awarded FTRs
corresponding to the change in transfer capability associated with
their investment in the transmission system.
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8. RMR contracts will to the extent possible be called as part of the ISO
coordinated inter-zonal 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.
9. All market participants will be permitted to submit negative adjustment
bids.
NEAR-TERM IMPLEMENTATION PHASE
1. Zones will continue to 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 ISO's commercial software will be able to calculate LMP prices at
each bus within the zones.
2. FTRs will be sold in periodic auctions administered 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.
3. 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.
4. 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.
5. Energy and transmission pricing will include the cost of incremental
energy losses.
6. The locations included in the trading hub will remain unchanged, but
the trading hub price will be calculated based on the average of the
LMP price at the locations included in the hub rather than the average
of the zonal prices at those locations.
7. Reliability will be maintained and congestion managed through market
incentives to the extent possible. In situations in which it is
necessary to mitigated market power, this mitigation will be
implemented to the extent possible through financial instruments with a
defined quantity and term rather than through physical call contracts.
INTERMEDIATE IMPLEMENTATION PHASE
1. 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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2. Generators electing to be paid the LMP price at their location will not
be eligible to receive constrained off payments.
3. 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.
The core of the end-state pricing system for the California electricity market
is described by the following elements:
END-STATE
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 services 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 or distribution wires
would be made under a regulatory backstop. Recovery in the
access charge of costs associated with new transmission
investments will require a demonstration both that the
investments are economically justified and that free rider
effects prevent the recovery of these costs in the market.
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 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 pricing will include the
cost of incremental losses.
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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. The ISO will post day
ahead and real time hub prices based on the average of the prices at
the locations included in the trading hub.
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 financial instruments with a defined
quantity and term rather than through ongoing physical call contracts
(e.g. RMR contracts).
Reliant Energy
Sempra Energy
Southern Energy
TURN
UCAN
Williams Energy Marketing & Trading
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