EXHIBIT 99.361
PRINCIPLES FOR CONGESTION PRICING REFORM
USING VOLUNTARY BALANCED SCHEDULES AND VOLUNTARY ZONAL PRICING
PROPOSED BY REFORM COALITION
May 9, 2000
This document provides an expansion of the discussion and recommendations for
congestion management and pricing reform originally put forward by the Reform
Coalition.(1) The document describes the elements of a day-ahead market that
would feature voluntary balanced schedules and voluntary zonal pricing, features
that would expand the choices available to the market and to the ISO for
managing and pricing congestion. In addition, this document describes the
elements of the ISO's real-time market that would be necessary to facilitate and
support the voluntary aspects of the forward market while ensuring reliability
in real time. Finally, the document describes how FTRs would be defined and
settled to support trading within these markets and offers suggestions on the
allocation of FTRs to deal with equity issues that may arise as more accurate
locational pricing is applied in California.
I. THE DAY-AHEAD MARKET
A. WHAT WOULD/COULD MARKET PARTICIPANTS DO IN THE DAY-AHEAD MARKET?
1. Market participants (MPs) would submit schedules and bids to the ISO.
a. The schedules would indicate the amounts and locations of their injections
and withdrawals
b. A schedule could include bids indicating the price(s) at which the MP
would be willing to adjust its schedule
c. Bids by generators would indicate the prices at which they would be
willing to provide/sell energy in the market
d. Bids by loads would indicate the prices at which they would be willing to
take/buy energy in the market
2. Participants would have the right/choice to submit balanced schedules.
a. Market participants could submit balanced schedules with instructions to
the ISO that any adjustments it made using the participant's adjustment
bids must keep the participant's portfolio of schedules in balance
b. Market participants could submit balanced schedules without adjustment
bids
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(1) See, the Reform Coalition Statement, "Reform of the California Electricity
Market: A Path Forward," dated March 30, 2000 (attached).
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3. Schedules without a balanced requirement would also be an alternative.
a. Market participants could submit schedules with bids by which each
schedule could be adjusted, without requiring that the adjusted schedules
(or the MP's portfolio of schedules) remain balanced
b. Generators/sellers could submit bids to provide/sell energy, without a
load, equivalent to an incremental bid with a zero schedule
c. Loads/buyers could submit bids to take/buy energy, without a generator,
equivalent to a decremental bid with a zero schedule
d. A market participant could submit both generator and load bids, without
regard to whether the generator and load bids were balanced
B. WHAT WOULD/COULD THE ISO DO IN THE DAY-AHEAD MARKET?
1. The ISO congestion management and pricing system would respect the physics
and the requirements for reliability. The model of the grid used by the ISO
for managing congestion and pricing power in the day-ahead market would be
consistent with the model used to maintain reliability in real time.
2. The ISO would use this model, in conjunction with the bids, for balancing the
system while meeting all security constraints (i.e, for resolving
congestion).
3. The ISO would use an integrated process for solving the balancing/security
constraint problem and for pricing.
a. The same process would apply to inter-zonal and intra-zonal congestion;
there would not be two different processes using two different models of
the grid
b. A "one-step" process would apply. That is, there would not be two or more
sequential steps, such as solving inter-zonal congestion first, then
solving intra-zonal congestion
4. The ISO's objective would be to solve the balancing/security problem at the
lowest as-bid cost (i.e., to clear the market), given the market
participants' schedules and bids, in accordance with the market participants'
bid instructions (See A above).(2) In effect, this would be a "voluntary
redispatch."
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(2) This is not a mechanical solution dictated by the ISO's model. It is
recognized that the system operators would use the model's solution as the
general guide, but when required to ensure reliability they would also exercise
judgment based on operator experience and superior knowledge of system
characteristics. Within this operating framework, the ISO's objective would be a
lowest as-bid cost solution, consistent with the bids and with maintaining
reliability. This solution is sometimes referred to as a "security-constrained
economic dispatch" ("dispatch"). The approach is common to most restructured
markets.
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5. Given the dispatch solution defined by the ISO from participants' bids, the
ISO would determine the marginal cost prices at each location that were
consistent with the dispatch solution and the participants' bids.
6. The ISO would (frequently) post the locational prices for the market's
information.
7. For each zone the ISO would aggregate the locational prices by calculating
the weighted average of the locational prices within the zone.(3)
a. The zone price for loads would be the weighted average of the locational
prices for loads in the zone who elected zonal pricing, with the weight
for each location proportional to these loads' actual (metered or
estimated) usage at each location
b. The zone price for generators would be the weighted average of the
locational prices for generators in the zone who elected zonal pricing,
with the weight for each location proportional to these generators' actual
(real-time metered or day-ahead scheduled) injections at each location
8. Once the day-ahead market schedules/dispatch and corresponding prices were
defined as above, the participants in the day-ahead market would have binding
financial commitments for the amounts scheduled in the day-ahead market at
the day-ahead market prices.
9. The ISO would use the zonal prices and the locational prices for settlements
of the day-ahead market, according to the elections of the participants.
a. The ISO would apply the appropriate day-ahead zone price to each
participant within the zone that had elected to be settled at the zone
price
b. The ISO would apply the day-ahead locational price at a participant's
location to each participant within the zone that had elected be settled
at its locational price
c. Each market participant would make an election to be settled in the
day-ahead market at the appropriate zone price or its locational price
d. The election would be made on a periodic basis and apply during each
election period. (E.g., elections could be made at the beginning of each
(monthly?) billing cycle, since this is essentially a settlement/billing
issue. How often the participants would be allowed to make their elections
is a matter that should be discussed.)
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(3) We continue to use the term "zone" as that term has been used in the
California market for an area in which the price is presumed to be the same. In
some ISO meetings, the term "locational pricing area" or "LPA" has also been
used to refer to zone.
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10. The ISO would still need to make constrained-on and constrained-off payments
in the day-ahead market to generators that had elected zonal pricing and
that were needed for congestion management.
a. The costs of these constrained-on/off payments would be recovered by the
ISO through an uplift that would be charged to all loads.
b. Note that the calculation of zone prices for generators and loads would
itself produce congestion rents, since the aggregate of the zone prices
paid by loads would be greater than the aggregate of the zone prices paid
to generators. This rent could be used to offset the uplift charges to
loads.
c. The ISO would not make day-ahead constrained-on and constrained-off
payments to generators that had elected to be settled at their respective
locational prices, as these prices would be consistent with their bids.
That is, all such generators scheduled would receive the day-ahead
market-clearing price at their location, which would be at least as high
as their bid; all such generators not scheduled would face a day-ahead
market-clearing price at their location either at or below their bid.
11. The marginal-cost locational prices would be used to define congestion
charges (i.e., the transmission usage charges) for transactions between
locations or zones, as appropriate.
a. For a transaction between participants that both elected zonal pricing
for settlements -- The congestion/usage charge for a schedule between
Zone 1 and Zone 2 would be the difference between the zone prices:
Usage charge = Q * (Price at Zone 2 minus Price at Zone 1)
b. For a transaction between participants that both elected their respective
locational price for settlements, the congestion charge (usage charge for
transmission) for a schedule would be the difference in locational
prices:
Usage charge = Q * (Price at Withdrawal location minus Price at Injection
location)
c. For transactions between participants with different elections, the same
principle would apply, using the corresponding prices for the settling
parties. For example:
Usage charge = Q * (Price at Withdrawal location minus Price at Zone 1)
or
Usage charge = Q * (Price at Zone 2 minus Price at Injection location)
d. Note that even if more zones were created, transactions "across" multiple
zones would not have to pay multiple usage charges. That is, if a
transaction "crossed" from Zone 1 through Zone 3 to Zone 2, the
congestion/usage charge would be based on the difference between the Zone
2 and Zone 1 prices. (Another way of saying this is that adding the
charge for Zone 1 to Zone 3, plus the charge for
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Zone 3 to Zone 2 would produce the same result.). The same principle
would apply to those electing to pay/receive their respective locational
prices.
12. FTRs would be defined from location to location.
a. FTRs would no longer be defined as rights across a given inter-zonal
interface, because:
(1) As new zones were created, inter-zonal interface rights would
become increasingly difficult to sustain and trade
(2) Such FTRs would have to be redefined every time a new zone was
created
(3) Location-to-location FTRs would remain viable if new zones were
created
(4) Location-to-location FTRs could be defined for longer terms
b. The ISO would settle all FTRs in the forward market.
c. FTRs would be settled based on the difference in the locational prices
II. PRINCIPLES APPLICABLE TO THE ISO'S REAL-TIME MARKET
A. IN ORDER TO BE ENSURE RELIABILITY IN REAL TIME, AND TO BE CONSISTENT WITH THE
PRINCIPLES APPLIED IN THE FORWARD MARKET, THE FOLLOWING PRINCIPLES WOULD
APPLY IN THE REAL-TIME MARKET. IN GENERAL, MOST OF THE SAME PRINCIPLES
DESCRIBED ABOVE FOR THE FORWARD MARKET WOULD ALSO APPLY TO THE ISO'S
REAL-TIME MARKET, EXCEPT THAT TO ENSURE PRICE SIGNALS CONSISTENT WITH
REAL-TIME RELIABILITY REQUIREMENTS, THE ISO WOULD USE LOCATIONAL PRICES FOR
REAL-TIME SETTLEMENTS.
1. The market participants would have the same choices with respect to
balanced schedules and submission of bids and schedules (See, I. A. 1-3)
2. The ISO would have the same task with respect to solving the integrated
balancing/security constraint problem (security-constrained economic
dispatch; see I. B. 1-4)
3. The ISO would solve the "dispatch" for the real-time market using the
market participants' bids (I. B. 4)
4. Given the real-time dispatch, the ISO would define and publish the
locational prices consistent with the participants' bids (I. B. 5 and 6)
5. Because constrained on/off payments were made in the day-ahead market,
they should not be repeated in the real-time market. Hence, the ISO would
use real-
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time locational prices for settlements of all deviations from forward
schedules in the real-time market.(4)
6. The ISO would assess usage charges for schedules submitted for the
real-time market, but not committed to in the day-ahead market.
7. As noted above, the ISO would not make zonal constrained-on/off payments
in the real-time market. The locational market-clearing prices used for
settlements would be consistent with participants' bids and with
maintaining reliability.
III. ALLOCATION/AUCTIONS OF FTRS
1. The ISO would revise the manner in which it determines how many and which
FTRs to allocate through its periodic auctions.
a. Currently, the ISO defines an FTR as across a specified interface
b. Currently, the ISO determines in advance how many FTRs it will allocate
across each interface
c. Currently, FTRs are defined only as "options," but not as "obligations"
2. Under the reform proposal, the ISO could also allocate FTRs as obligations.
a. An obligation FTR entitles the holder to receive the difference between
the locational prices at the points of withdrawal and injection when this
difference is positive
b. An obligation FTR obligates the holder to pay the difference between the
locational prices at the points of withdrawal and injection when this
difference is negative
c. Obligation FTRs provide a means to sell congestion management services
forward - that is, an MP's bid to acquire an FTR that is expected to have
"negative" locational price differences means: "If you pay me at least my
bid price to take this FTR, I will assume the financial obligation to pay
the ISO for the FTR when the price differences are negative."(5) In
effect, the bidder is saying it will either provide congestion management
(so-called "counterflows" for which
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(4) Some loads may not have the appropriate meters to handle and respond to
individual locational prices at their respective busses. For some interim
period, the ISO could aggregate locational prices for such loads, allowing these
loads to be settled at the weighted average of the locational prices within some
defined area or region. The regions could be defined in various ways, such as a
municipal service area, or the SF peninsula, etc. These need not be the same as
congestion zones. Using this approach, many loads would pay area averages of
locational prices, but from the standpoint of the ISO, all loads would be
settled at the locational prices.
(5) There would also be occasions when the price differences were positive, in
which case the FTR holder would receive the differences in locational prices.
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it will be compensated at the locational price differences) at that time
or it will pay the marginal cost of redispatching the system (the
difference in locational prices.
d. Because some of these FTRs may result in a payment obligation, the ISO can
auction FTRs up to 100 percent of the grid capacity, without the risk that
there will be insufficient funds collected from congestion charges to fund
all "positive" FTRs.
e. Given these features, the amount of FTRs that can be allocated through the
auction need not be defined in advance by the ISO.
f. In an auction for such FTRs, the ISO would not predefine how many FTRs it
would allocate. Instead, it would accept bids/offers for FTRs from the
market. It would award that set of FTRs that maximizes the value of the
awarded FTRs to the market participants, given their bids/offers, and that
are still simultaneously feasible. That is, the awarded set could be
implemented as corresponding injections and withdrawals without violating
any security constraint.
3. It may be possible for the ISO to allocate both "option" FTRs and
"obligation" FTRs, thus facilitating the forward trading of congestion
management services. The market participants, through their auction bids and
secondary trades, would likely assign different values/prices to these
different FTRs, depending on their perceptions of the relative value/risks of
each type of hedge. The market participants would decide how much of each
type of FTR they wished to bid for and hold.
IV. EQUITY ALLOCATIONS OF FTRS
1. Various parties may have equitable claims on the value of the grid. These
parties have been paying for the grid, either through payment of the grid
access charges or through prior contracts
2. Parties that might become subject to new zones will have these equitable
claims (e.g., customers on the SF peninsula, if a new SF zone is created).
3. Some mechanism would be needed to allocate FTRs to these customers (or their
LSE) to satisfy these equity claims.
4. For example, a sufficient number of FTRs could be awarded to SF peninsula
customers (or their LSE) to satisfy their equitable claim to receive
something like the PG&E average price, rather than a potentially higher SF
price when the peninsula transmission is constrained.
5. These claims could be dealt with either by:
a. Allocating FTRs in advance to these parties
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b. Allocating "auction revenue rights" - that is, the right to receive a
share of the revenues from the FTR auctions for rights ending at their
locations, as an offset against their access charges.
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ATTACHMENT
Initial Statement of Reform Coalition
March 30, 2000
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.
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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 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.
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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 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.
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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 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
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based congestion management, the ISO will initiate the process to change the
tariff to allow reliance on a market based congestion management system.
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,(6) 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 credited
against the access charge within the transmission constrained region. The
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(6) 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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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.
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
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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.
4. The congestion management system treats new and existing generators alike.
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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
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proposals of others and are ready to make improvements suggested by others or to
adopt proposals that better achieve the objectives we have described.
Reliant Energy
Sempra Energy
TURN
UCAN
Williams Energy Marketing & Trading
March 30, 2000
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