E. The
New Congestion Management System
1. Under Network
Access Service, all transmission customers may request transmission
service. The Independent Transmission
Provider must honor all valid transmission requests where there is sufficient
capability, i.e., when there is no transmission congestion. However, when there is transmission
congestion we propose to require that all Independent Transmission Providers
allocate scarce transmission capability using a price system. Specifically, we propose to require that all
Independent Transmission Providers manage congestion using a system of LMP and
Congestion Revenue Rights. Under LMP,
the price to transmit energy between any receipt point and delivery point
reflects the marginal cost (including the marginal opportunity cost) of such
transmission service, and the price of energy at each location reflects the
marginal cost (as reflected in participants' bids) of producing energy and
delivering it to that location.
1. Locational Marginal Pricing
2. LMP is the method
that is currently used for managing congestion in the regional markets run by
both PJM and New York ISO. It is also
proposed to be adopted as the congestion management system for ISO-New England
in 2003 and for the California ISO in its proposed market redesign.115
Marginal pricing, a fundamental concept in economics, is the basis for
LMP.116 Marginal pricing is the
idea that the market price should be the cost of bringing the last unit to
market (the one that balances supply and demand). LMP in electricity recognizes that the marginal price may differ
at different locations and times.
Differences result from transmission congestion which limits the
transfer of electricity between the different locations.117
The marginal price of energy at a particular location and time – that
is, the energy LMP – is the additional cost of procuring the last unit of
energy supply that buyers and sellers at that location willingly agree on to
meet the demand for energy. That is, it
is the price that "clears the market" for energy.118
3. LMP is a
market-based method for congestion management.
Congestion is managed through energy prices and transmission usage
charges (congestion and loss charges) determined in a bid-based market. When there is no congestion anywhere on the
system (when there is enough transmission capacity to get power from the
cheapest available generators to all potential buyers) there will be only one
energy price in the transmission system, the price bid by the last, or
marginal, generator that provides energy or load that offers to reduce its
demand.119 When there is congestion,
the cheapest generators may be unable to reach all their potential buyers. Consequently, when there is congestion there
may be many different energy prices across the transmission system.120
Under LMP, the Independent Transmission Provider will establish separate
energy prices at each node on the transmission grid and separate prices to
transmit energy between any two nodes (receipt and delivery points) on the
grid. These prices reflect the cost of
congestion. LMP relies on economic
redispatch in managing congestion.
Redispatching means decreasing the energy the Independent Transmission
Provider obtains in front of the constraint (where the power is flowing from)
and increasing the energy the Independent Transmission Provider obtains behind
the constraint (where the power is flowing to). The cost of redispatch is the basis for the congestion charges
under LMP. If a customer is willing to
pay the marginal cost of redispatch, which it signals through its bids, the
Independent Transmission Provider will schedule the transmission service.
4. For example,
assume there is congestion or a constraint on one transmission interface. Some low-cost generators may not be able to
deliver energy to load on the other (import) side of the constraint. So, they will need to reduce their
production because of the constraint.
To signal these generators to reduce their production, the energy price
that these generators would receive would be lowered. To replace the low-cost generation, more expensive generators on
the other side of the constraint (export) must be dispatched. To signal to these higher cost generators
that they should increase their production, the energy price they would receive
would increase. As a result the energy
price on each side of the transmission constraint would be different. The energy price would be lower on the side
where more suppliers are trying to sell out of the region than can be
accommodated by the transmission capacity.
The energy price would be higher on the side where more expensive local
generation must be used because of the transmission constraint. As discussed further in Section IV.F., for
purchasers of energy in the Independent Transmission Provider-run spot markets,
the LMP at the node closest to them is their delivered power cost (energy
charge plus transmission charge). The
generators are then paid the LMP at the nodes closest to them.
1. For customers
buying energy through bilateral contracts rather than in spot markets, the
transmission usage charge would reflect the marginal cost of transmission
between a receipt point and a delivery point.121
In the above example, the difference would be the marginal cost of
moving energy from the import to the export side of the constraint which should
equal the difference in the energy price on the import and the export side of
the constraint. In other words, the
transmission usage charge for bilateral transactions would be the difference
between the LMP at the receipt point and the delivery point. When congestion exists, the difference in
energy prices to transmission users is a price signal that reflects the
marginal cost of economic dispatch of resources necessary to accommodate the
transmission service. Those who place a
higher value on the transmission capacity and the value of the ultimate
delivered electricity, will be willing to pay higher transmission usage
charges. Also, because transmission
usage charges for bilateral transactions are based on the differences in spot
market energy prices, the proposed congestion management system would not bias
a customer's choice between purchasing energy through the spot market versus a
bilateral transaction.
1. LMP uses a
financial instrument called a Congestion Revenue Right to provide customers
with price certainty for transmission
service.122 A Congestion Revenue
Right is a financial tool that allows a customer to protect itself against the
costs of congestion. A Congestion
Revenue Right ensures that the holder of that right will be protected against
congestion costs for the transmission service covered by that right in the
day-ahead market.123 Once the day-ahead market
closes, all customers pay for the service requested and, if they hold
Congestion Revenue Rights, are paid congestion costs associated with those
rights. Thus, the customer has bought
and paid for a quantity of transmission at a specified price.
2. Any changes a
customer wants to make to the transmission service it has scheduled in the day-ahead
market must be accomplished in the real-time market at real-time prices, which
may be different from the day-ahead prices.
A customer wanting less transmission service than it requested and
received in the day-ahead market would effectively sell back to the market the
amount of unused service. Conversely, a
customer needing an additional amount of transmission service could buy the
additional amount of service in the real-time market. No congestion revenues are paid to Congestion Revenue Rights
holders for transactions made in real-time market.124
3. The LMP system
for congestion management is better suited to manage congestion in a
competitive market than the congestion management system under the Order No.
888 pro forma tariff (pro rata curtailment) because
LMP allocates scarce transmission capacity to those who value it most and it
relies on an incentive system (i.e., it assigns congestion costs to the
transactions that cause the congestion) that encourages market participants to
buy and sell power in a manner that is consistent with the reliable operation
of the system. Under an LMP system,
market participants have greater commercial flexibility in arranging
transactions. Market participants have
the ability to signal whether they are willing to buy their way through
transmission constraints. Under the
current system they do not have the ability to do that, in part because
transmission providers do not have a mechanism for recovering the cost of
economic redispatch. Currently, these
types of transactions would not be scheduled because of the existence of
congestion. Also, Network Access
Service customers would have the ability to voluntarily resell their Congestion
Revenue Rights when others value them more highly. Because market participants will see and be responsible for the
full effect of their decisions on congestion costs, each have an incentive to
manage its own transactions in a way that is consistent with a least-cost
dispatch consistent with reliable system operations.
4. The proposed
SMD Tariff lays out the general framework and the basic rules for LMP. It is based on the best practices we have
seen. We recognize that in certain
regions there may need to be additional rules or changes to accommodate
specific regional requirements. We also
recognize that over time there likely will be a need to update the tariff
provisions to offer new service options or to further refine the market
rules. The pro forma
tariff is not intended to be a static document, but rather one that will evolve
over time and meet the needs of the marketplace. We seek comment on how best to recognize this need for regional
variation and the need for continued refinement in the rules.
5. One concern
that has been expressed in the Standard Market Design conferences and in
comments on the Working Paper is that while LMP may work well with systems that
are dominated by thermal plants, it may not work in systems that primarily rely
on hydroelectric resources. In
particular, the Pacific Northwest is concerned that an hourly bid-based system
with LMP may be in conflict with Northwest resource uses, practices and
obligations, which are dominated by hydroelectric generation. Much of this is from
"run-of-river"125 facilities that cannot store water, and at which energy is lost
if a generator does not run when water is available. Because the decision to run is virtually automatic, many
Northwest parties see no need for a bidding system. Also, many of the hydroelectric facilities of the Columbia River
System must coordinate their operations; whether a downstream facility runs
depends on whether an upstream dam runs and releases water. Some of this coordination is among
facilities in the United States and Canada and is subject to international
treaties. There is a concern that a
bid-based system with LMP, which requires individual generators to bid
independently against one another, ignores this cooperation or even would view
such cooperation as collusion in a market system. Some coordination agreements assure that low-cost transmission
will be made available to implement the coordination, and there is a concern
that LMP congestion pricing may be incompatible with these agreements.
6. Northwest
parties note that while annual costs in a thermal system are minimized simply
by minimizing the costs in every individual hour the same does not hold true in
a hydropower system. A hydroelectric
dam with stored water has a marginal running cost close to zero, however, this
does not mean that it should be dispatched first every hour. Rather, the value of hydropower over time
depends on when that stored energy system can best be released to minimize
costs over a season, an year, or even a multi-year period. Thus, there is a concern that in a hydropower
system, a congestion management and energy spot market designed to minimize
hourly costs will not minimize costs over a longer period.
7. Moreover,
commenters have noted that decisions about water use in the Northwest are based
on more than electric power cost minimization.
Decisions about use of hydropower facilities involve coordinated
trade-offs among power needs, the needs of fish and wildlife, irrigation, flood
control, recreation and other factors, which may be difficult to reflect in the
bids of individual units. Some parties
in the Northwest acknowledge that a bid-based LMP system could be adapted to
meet the objections above but are concerned either that such a system may be
imposed without adaptation or that the adaption will be done poorly. There is also concern that adaptation to a
bid-based security-constrained system may reopen such issues as transmission
priorities and preference power allocations that have been settled over many
years of negotiation based on factors other than market efficiency. Finally, Northwest parties worry about
obtaining sufficient Congestion Revenue Rights to protect against congestion charges.
8. We believe that
the proposed Standard Market Design would work well in every region and for all
types of fuel sources; we believe that the concerns expressed by participants
in the Pacific Northwest can be accommodated within the LMP system we
propose. First, use of the Independent
Transmission Provider's bid-based spot energy markets would be optional. No one would be required to bid into these
markets (except when market power mitigation is imposed).126
Hydropower generators could choose to self-schedule without submitting a
price bid. As a result, the bilateral
contractual energy arrangements of the Northwest would be unaffected. Thus, for
example, hydropower facilities along a common waterway that wish to develop a
coordinated schedule without submitting energy price bids would be free to do
so. Also, hydropower facilities that
must consider non-price factors such as the needs for irrigation, flood control,
and fish and wildlife in their scheduling decisions could do so through the
self-scheduling feature.
9. For hydropower
generators that wish to participate in the Independent Transmission Provider's
spot energy markets, the Standard Market Design that we propose can accommodate
the special features of hydropower facilities.
Suppliers would be allowed to reflect their opportunity costs in their
bids; bids need not be limited to marginal running costs. Also, generators such as hydropower
facilities would have the option (but not the requirement) of requesting the
Independent Transmission Provider to schedule the generator's designated MWhs
over the highest priced hours of the day, to economically optimize hydropower
production over the day. LMP is a result
of a least-cost dispatch of the resources available to the transmission system
in a manner that recognizes both the operational limits of those resources and
the operational limitations of the transmission system. As a result, customers' loads can be met at
the lowest total cost (as reflected in the submitted bids) consistent with the
reliable operation of the system, which should be the objective on any system
regardless of the resource base of the transmission system.
10. In
short, we see no reason why the proposed Standard Market Design would prevent
hydropower generators from operating in a way that accommodates their special
features. Indeed, we believe that the
LMP system would aid hydropower generators in optimizing the economic value of
their resources within their legitimate operational constraints, because the
prices for energy and transmission would signal the economic costs of providing
energy and transmission service at different locations and time periods.
11. Finally,
our proposal here would not abrogate existing pre-Order No. 888 transmission
contracts, so customers holding these rights could continue their existing
services under the existing contractual provisions. In addition, this proposal would allocate Congestion Revenue
Rights or auction revenues to parties based on their recent historical usage of
transmission. Thus, customers receiving
transmission service under the Order No. 888 pro forma tariff, as
well as entities previously serving bundled retail load outside the pro forma
tariff, would receive Congestion Revenue Rights to protect against congestion
charges.
12. We
agree that the operational limits of both the resources and the transmission
systems need to be fully considered in the design of the specific market
rules. For example, there is likely a
need to calculate opportunity costs for hydroelectric resources differently
from thermal plants. These differences
can affect market mitigation measures.
However, we are concerned about whether different market designs can be
in place in the Northwest and the rest of the West, and ask for comment on
whether the entire West must have a common set of market rules to eliminate
seams and prevent manipulation.
13. In
the SMD Tariff we propose to include several different types of Congestion Revenue
Rights to allow customers to protect against congestion costs. For example, one concern that we have heard
from customers and suppliers in the Northwest is that a receipt
point-to-delivery point Congestion Revenue Right may not work to effectively
manage congestion on a system that utilizes several different hydroelectric
facilities on a contingent basis to serve the same delivery points. A Congestion Revenue Right that recognized
the contingent nature of the supply sources would be more valuable to customers
in this instance. We believe that
developing these types of Congestion Revenue Rights is possible and we propose
to work with the regions to develop variations to meet regional needs. The congestion management system that we
propose is flexible enough to accommodate these types of regional
variations. Such variation and
flexibility should not impinge on the development of a seamless electric grid.
14. To
implement LMP, the Independent Transmission Provider must operate an energy
market to determine the marginal cost of redispatch. We propose to require that the Independent Transmission Provider
operate both a day-ahead and a real-time energy market to manage congestion.
15. The
Commission proposes to use real-time markets for energy to resolve energy
imbalances. Under the proposal, the
transmission customer would be charged the real-time price of energy for any
imbalance, i.e., the difference between the energy the transmission
customer schedules a day ahead on the system and the amount that it takes off
the system in real time. The real-time
price of energy is determined through a security-constrained, bid-based energy
market run by the Independent Transmission Provider. The Independent Transmission Provider uses the bids to select the
lowest-cost energy within the operational limitations of the transmission
system. These same procedures will be
used to resolve imbalances for all users of the transmission system.
16. The
Commission also proposes that the Independent Transmission Provider operate a
security-constrained, financially binding day-ahead energy market that is
operated together with a day-ahead scheduling process for transmission service.127
The day-ahead market for energy will allow the Independent Transmission
Provider to manage congestion that arises in the day-ahead scheduling process.128
17. The
day-ahead energy market is a bid-based market.
Sellers submit bids that indicate the quantities of power they will
offer for sale in each hour of the next day and the price for that power at
each location (node).129 The price for the power
may vary based on the quantities that are offered for sale. The differences in bid prices recognize that
a generator's marginal cost of producing power can vary at different quantity
levels because it operates more efficiently at certain output levels than
others. Also, at the highest output
levels, there may be additional opportunity costs because of an increased risk
of a unit outage. Buyers also submit
bids indicating the quantities they desire to purchase in each hour of the
day. Buyers may also indicate the
maximum price they are willing to pay for those quantities.
18. Under
the Commission's proposal, buyers are not required to procure energy through
the day-ahead energy market. A
load-serving entity may procure all of its power through bilateral
transactions, in the transmission provider's spot markets, or by generating its
own power.130 However, a load-serving
entity may use the day-ahead market if it needs to acquire additional power or
the price of power through the day-ahead energy market is lower than the price
of power under an existing bilateral contract or the cost of generating its own
power. A generator may also buy power
through the day-ahead market. It would
do this if it could buy the power more cheaply than generating to satisfy a
bilateral contract obligation or if a forced outage requires it to procure
power to satisfy a contract obligation.
19. The
Commission proposes to require Independent Transmission Providers to allow
buyers and sellers to submit purely financial bids, a feature that currently
exists in the day-ahead markets run by PJM and New York ISO. These financial bids to buy or sell power
are not backed by actual generation resources nor are they backed by actual
load. Rather, these transactions are
used to bring the prices in the day-ahead market and in the real-time market
closer together. For example, suppose
that the day-ahead price is consistently lower than the corresponding real-time
price. Entities may therefore want to
submit financial bids to buy energy in the day-ahead market at the lower price,
and submit a corresponding bid to sell in the real-time market at the higher
price, thereby making a net profit on the two transactions. The additional buyer bids in the day-ahead
market would tend to increase day-ahead prices, while the additional supply
bids in the real-time market would tend to reduce the real-time prices. The result is that the price differences in
the two markets would shrink, as would the profits of sale. This process benefits the market. It helps market participants make better
decisions in advance – in the day-ahead time frame – that will affect how much
electricity they will sell or buy, because the day-ahead price becomes a more
accurate gauge of what the real-time price will be.
20. The
day-ahead energy market is operated together with the congestion management
system and the day-ahead scheduling process for transmission service. The Independent Transmission Provider will
determine market clearing prices for each hour in the day-ahead energy market
based on the sale and purchase bids that are submitted. The market clearing price is the bid of the
last unit of supply needed to satisfy the demand, i.e., the highest bid
that is accepted. The market clearing
price at a location is paid to all suppliers at that location that are selected
in the auction and is paid by all buyers at that location that purchase through
the auction.
21. We
believe there are important differences between Standard Market Design and the
market design that was in effect in the California ISO when it experienced
problems in the energy markets in 2000 and 2001. First, Standard Market Design is premised on the use of bilateral
contracts. While LSEs may purchase
energy in the spot markets, these purchases should constitute a small
percentage of their actual purchases.
In contrast, the California market design required the LSEs to purchase
the bulk of their energy needs through the spot markets. Second, Standard Market Design includes a
forward-looking long-term resource adequacy requirement to avoid the types of
supply shortages that adversely affected California. Third, as discussed in more detail in Appendix E, Standard Market
Design includes trading rules, a congestion management system, market power
mitigation measures, and market power monitoring to address the manipulation
strategies encountered in the California markets.
22. In
determining market clearing prices, the Independent Transmission Provider
factors in the operational limitations of the transmission capacity, such as
congestion and reactive power needs, to ensure that the units that set the
market clearing prices are consistent with the transmission system operations (i.e.,
a security-constrained dispatch).131
Because LMP is used as the congestion management system, the market
clearing prices are the prices for energy delivered to each location or node on
the system. If there is no congestion
on the transmission system, the same market clearing price for energy will
apply throughout the system.
23. The
day-ahead market would be financially binding.
This means that a seller that is selected in the day-ahead market is obligated
to actually provide the power in real time or in real time it will be charged
the cost of procuring the shortfall through the real-time market.132
The day-ahead market is also financially binding on buyers.133
This reduces certain opportunities for strategic bidding and thus,
market manipulation.
24. Years
of experience with organized markets makes it clear that a day-ahead market is
a best practice that must be included in the Standard Market Design. The development of a day-ahead schedule for
energy and transmission service, including certain ancillary services, provides
reliability benefits. It allows the
Independent Transmission Provider to have advance warning to ensure that
sufficient units are committed to serve the projected load. For example, if the Independent Transmission
Provider believes that load has not scheduled sufficient transmission service
or energy purchases in the day-ahead markets, it can commit additional units to
be available in real time. Because of
their operating characteristics, different types of generation units have
differing levels of start-up costs as well as different lead times to be
available in real time. The day-ahead
market gives the Independent Transmission Provider information on unit
availability, costs and system needs well before real time so the Independent
Transmission Provider has more options available to ensure reliability and
reduce costs in the real-time market.
25. Finally,
the day-ahead market provides an important platform for market power mitigation. We propose several mitigation measures to
ensure that there is a well-functioning spot market for wholesale power. These spot markets will result in price
transparency, so buyers and sellers can see that market clearing prices are set
in a fair and predictable manner. While
the real-time market will be a transparent market, real-time prices may not be
known until after the fact or at most five to ten minutes before real
time. This gives buyers and sellers
little chance to react to prices. In
contrast, a day-ahead market provides a transparent spot market that allows
buyers and sellers to engage in additional commercial transactions before real
time. Thus, a day-ahead market helps
liquidity and is likely to be less volatile than the real-time market.
26. The
Independent Transmission Provider will also establish hourly prices for certain
ancillary services, which may differ by location to the extent that ancillary
service requirements differ by location.
Since the same supply resources can often be used to provide either
energy or ancillary services, energy and ancillary services should have
compatible market designs. Otherwise,
there would be an incentive to sell one type of product over another. Since both are needed, a compatible system
allows the supplier to sell energy or ancillary services, whichever is the most
efficient use of the supply resources.
This yields the lowest total costs to customers.
27. As
explained further below, the Independent Transmission Provider will need to
manage congestion in two time frames:
(1) during the day-ahead scheduling process, and (2) during real-time
operations. The Independent
Transmission Provider will conduct separate auctions to manage congestion in
each time frame. In the day-ahead
auction, for each hour of the following day the Independent Transmission
Provider will take bids to buy and sell energy, to provide certain ancillary
services, and to purchase transmission service between identified receipt and
delivery points. The Independent
Transmission Provider will consider the bids for energy, transmission service
and ancillary services simultaneously.
Based on those bids, the Independent Transmission Provider will develop
a schedule that maximizes the economic value (as reflected in the bids) of the
transactions over the entire day-ahead period, in light of the amount of
Available Transfer Capability and any resulting transmission congestion and
losses. The Independent Transmission
Provider will also establish prices for transmission service, energy and ancillary
services that clear the markets.
28. Under
LMP, transmission usage prices will vary based on the price of relieving
transmission congestion and losses.
Rather than using a system of physical reservations, a system of financial rights called
Congestion Revenue Rights will be used to give customers the ability to protect
themselves against congestion costs.
29. The
initial allocation process for Congestion Revenue Rights will be done through
compliance filings that allow for different treatment within each region. Since this must occur before Standard Market
Design is implemented, we have not addressed initial allocation in the SMD
Tariff, but it is discussed in Section IV.E.3.e below. This section describes allocation processes
that would be used after the initial allocation has been done.
a. General
Features
30. We
propose to require that Independent Transmission Providers offer Congestion
Revenue Rights of several types (one that we will mandate now and others that
should be offered upon customer request when technically feasible) that allow
transmission customers to obtain protection against uncertain future congestion
charges. We have added a new section to
the SMD Tariff that describes the types of Congestion Revenue Rights that would
be available, how one acquires Congestion Revenue Rights after the initial
allocation and how Congestion Revenue Rights provide protection against
congestion costs (Part II.D., Congestion Revenue Rights). The proposed provisions are discussed
below.
31. The
Independent Transmission Provider would be required to offer Congestion Revenue
Rights for all of the transmission transfer capability on the grid, but it
would not be allowed to sell more rights than can be accommodated. Congestion Revenue Rights would be available
over a variety of terms, such as weekly, monthly, yearly and perhaps for longer
terms. If an entity pays to construct
new generation or transmission facilities that add transfer capability, and the
costs of the upgrade are not rolled in, the entity would receive the Congestion
Revenue Rights associated with the new transfer capability. In the past the Commission has allowed
credits for upgrades; is there still a role for credits under Standard Market
Design?
32. Customers
that have not acquired Congestion Revenue Rights in advance could schedule
transmission service in the day-ahead market, but they would not have the
Congestion Revenue Rights protection against congestion costs.
33. We
propose that Congestion Revenue Rights be made available first in the form of
receipt point-to-delivery point obligation rights, which we propose to
mandate now, and later in the form of receipt point-to-delivery point option
rights and flowgate rights.
Currently, in PJM and New York ISO only receipt point-to-delivery point
obligations are offered. However, there
has been considerable interest expressed by market participants in other types
of Congestion Revenue Rights. For
example, the Midwest ISO is considering offering a package of Congestion Revenue
Rights that are similar to what we are proposing. Also, PJM is considering offering receipt point-to-delivery point
options. Offering several different
types of Congestion Revenue Rights would make the system more flexible and
better able to adapt to the needs of specific customers. Also, certain types of Congestion Revenue
Rights may be more valued in different regions of the country based on the
physical configuration of the transmission system and the types of resources
connected to that system. Various
technical papers over the last few years have examined offering these alternate
rights simultaneously and concluded that it is feasible under the conditions
now specified in the SMD Tariff.134 Therefore, we believe the tariff should
provide this flexibility.
b. Types of Congestion Revenue Rights
34. The
SMD Tariff describes the characteristics of each of the types of Congestion
Revenue Rights. These descriptions are
summarized below.
(1) Receipt Point-to-Delivery Point Rights.
35. A
receipt point-to-delivery point right is a right that is specified by a receipt
point (which can be a generator node, an aggregation of generator nodes, an
interface, a trading hub, or any other collection of nodes) and a delivery
point (which can be a delivery node, an aggregation of delivery nodes, an
interface, or a trading hub), and the power in MW that is transmitted from the
receipt point to the delivery point for a period of time (e.g., one
hour).
36.
A receipt point-to-delivery point right entitles the holder to the day-ahead
congestion revenues associated with transmission service from the receipt point
to the delivery point.135 In addition, during any
period when the demand for transmission service cannot be met with Available
Transfer Capability (i.e., because there are too many customers who have
indicated that they want transmission service at any price), holders of receipt
point-to-delivery point rights would receive priority over other market
participants in scheduling transmission service between the receipt point and
delivery points designated in their rights.
37. A
receipt point-to-delivery point right would provide the holder with the right
to schedule transmission service of the specified amount of power (MW) in the
day-ahead market from the receipt point to the delivery point without paying
any net charges for congestion (although the holder would need to pay a charge
for losses). The reason is that every
customer would be entitled to inform the Independent Transmission Provider to
schedule its transmission service regardless of the congestion charge. In that case, the customer would be charged
for congestion (as well as for losses).
But a self-scheduled customer holding a receipt point-to-delivery point
right for at least the same amount of power between the same receipt and
delivery points would receive congestion revenues that fully offset the
congestion charge.
(2) Obligations and Options
38. Receipt
point-to-delivery point rights can take the form of obligations or
options. The difference between
obligations and options becomes important when congestion occurs in the
opposite direction from the right, that is, when there is congestion from the
delivery point to the receipt point. In
this case, congestion revenues in the direction of the right are negative. Under a receipt point-to-delivery point
obligation, the Congestion Revenue Rights holder in that case would be required
to pay the negative congestion revenues to the Independent Transmission
Provider. Under a receipt point-to-delivery
point option, the Congestion Revenue Rights holder would not be required to pay
the negative congestion revenues to the Independent Transmission Provider. Existing firm point-to-point transmission
contracts under the Order No. 888 pro forma tariff do not require
contract holders to transmit energy and, thus, are similar to Congestion
Revenue Rights that are options.
(3) Flowgate Rights
39. A
flowgate is a particular transmission facility or group of facilities (e.g.,
an interface). A flowgate right
specifies a portion of the transmission capacity over that flowgate in a
specified direction. A flowgate right
entitles the holder to the day-ahead congestion revenues associated with the
specified power flows over the flowgate in the specified direction.136
Unlike a receipt point-to-delivery point obligation, a flowgate right
would never require the holder to make congestion payments. The congestion revenue associated with a flowgate
in a specified direction would equal the additional net economic value to
market participants that would result by incrementally increasing the
flowgate's capacity in the specified direction. That additional net economic value may be either positive (i.e.,
when the flowgate is congested) or zero (i.e., when the flowgate is not
congested), but it would never be negative.
40. Receipt-point-to-delivery-point
rights offer the transmission customer with long-term energy contracts the best
way to protect itself against hourly congestion costs. However, many transmission customers may be
meeting their loads' needs with a portfolio of generators scattered around a
regional electricity market. Such
customers may be seeking a more flexible type of right than the
receipt-point-to-delivery point right (which is typically only reconfigured on
a monthly basis and which can be traded on the secondary market most easily if
another customer requires the same points as specified in the right). The major market advantage of the flowgate
right is that since there are fewer congested flowgates than possible under
receipt-point-to-delivery-point rights, transmission customers can focus their
rights on the key congested flowgates.
This allows for coverage of much of the congestion charges (in some
estimates, between 80 percent to 90 percent).
However, the flowgate rights may not provide a complete protection
against congestion charges for a receipt point-to-delivery point energy
transaction, since the congestion revenues may differ from the congestion
charges.
c. Requirement for
Offering Rights
41. At
the start of Network Access Service, the Independent Transmission Provider
would be required to offer receipt point-to-delivery point obligations. These rights are the easiest to implement
because they are already in wide use.
While we want the market to develop additional choices for customers, we
are concerned about requiring implementation of numerous types of rights,
including types of Congestion Revenue Rights that have not yet been tested by
an ISO or RTO, when Standard Market Design is first implemented. Because there is no experience with the
other types of rights, we propose not to require the Independent Transmission
Provider to offer them initially.
However, upon the request of market participants, the Independent
Transmission Provider would be required to offer receipt point-to-delivery
point options and flowgate rights as soon as technically feasible.
42. Additionally,
Congestion Revenue Rights could be offered for various terms, e.g., one
month or five years. Some customers may
desire Congestion Revenue Rights with multi-year terms to correspond to the
terms of long-term power contracts, including contracts used to satisfy the
resource adequacy requirement discussed in Section J. At the same time, it may be difficult for the market to value
long-term Congestion Revenue Rights until a region has actual operating
experience under an LMP congestion management system. This could create problems in an area that auctions all
Congestion Revenue Rights and allocates the auction revenue rights to load. We seek comment on whether the Commission
should require the Independent Transmission Provider to offer multi-year
Congestion Revenue Rights when Standard Market Design is first implemented. Additionally, we seek comment on whether the
Independent Transmission Provider should be required to offer Congestion
Revenue Rights with terms tied to the planning horizon used in the region to
satisfy the resource adequacy requirement.
d. Funding for the Congestion Revenue Rights
43. As
explained above, holders of Congestion Revenue Rights would be entitled to
receive congestion revenues associated with transmission congestion in each
hour of the day-ahead market. The
aggregate amount of Congestion Revenue Rights issued by the Independent
Transmission Provider would be the amount simultaneously feasible based on
Available Transfer Capability under normal operating conditions. As a result, during normal operating
conditions, the Independent Transmission Provider would collect enough
congestion charge revenue from users of transmission service in the day-ahead
market to fully pay the day-ahead congestion revenues owed to holders of
Congestion Revenue Rights. Indeed, the
Independent Transmission Provider might collect a surplus of revenue in some
hours during normal operating conditions.
However, when a significant amount of transmission facilities are out of
service, so that less transmission service can be provided, the Independent
Transmission Provider may collect less congestion charge revenue from transmission
users than the amounts owed to Congestion Revenue Rights holders.
44. There
are two ways to handle this revenue shortfall.
First, the amount of congestion revenues paid to the holders of
Congestion Revenue Rights may have to be reduced. As a result, the customer may only be able to protect against a
portion (e.g., 95 percent) of its congestion costs in the day-ahead
market. Alternatively, the customer
that has a Congestion Revenue Right could receive full protection against
congestion costs and the revenue shortfall would be assigned to the
transmission owner. We propose to use
the latter approach. When such revenue
deficits arise, we propose that such deficits be made up by transmission owners
whose transmission facilities are out of service. We would, however, include an exception for outages due to force
majeure events, since our intent is to reward transmission owners for
proactively maintaining their transmission facilities.137
Assigning revenue deficits in this way would encourage transmission owners
to take steps to minimize forced transmission outages and to schedule
maintenance outages so as to minimize their effect on congestion costs. Assigning congestion revenue surpluses to
transmission owners may also encourage them to minimize outages. However, such a policy may also create an
interest on the part of transmission owners in maintaining congestion, and thus
may discourage them from building needed transmission expansions. We propose that any revenue surpluses be
paid to transmission owners, but we seek comment on the potential of this
policy to discourage transmission expansions and if alternative mechanisms
should be used to distribute the revenue surpluses.
e. Auctions and Resales of Congestion
Revenue Rights
45. We
believe it is important that there be an active secondary market for Congestion
Revenue Rights. This will allow a
market mechanism for customers that have Congestion Revenue Rights to acquire
new ones or to sell Congestion Revenue Rights they no longer need. Additionally, this provides a way for market
participants that do not have Congestion Revenue Rights to acquire them. Market participants would be allowed to
resell any Congestion Revenue Rights that they have been awarded for the full
term of the rights or for a part of the term.
Resales could be transacted bilaterally between willing buyers and
sellers. In addition, we propose to
require that the Independent Transmission Provider conduct periodic auctions of
Congestion Revenue Rights. The
Independent Transmission Provider's auction would allow holders of rights to
resell their Congestion Revenue Rights in an organized market. This would provide greater price
transparency for these rights than if all sales were conducted through
bilateral transactions. Moreover, the
auctions would provide the ability to reconfigure Congestion Revenue Rights
into different receipt and delivery points, or into different types of rights (e.g.,
receipt point-to-delivery point options, obligations, or flowgate rights). This would allow Congestion Revenue Rights
holders to change their Congestion Revenue Rights if for example they decided
to switch suppliers. The auctions would
also allow Congestion Revenue Rights associated with other transmission
capacity that becomes available (such as through the expiration of previously
issued Congestion Revenue Rights) to be sold.
46. In
the auctions, buyers and sellers would submit bids that specify the type of
Congestion Revenue Rights desired to be bought or sold, the location, term and
price. The Independent Transmission
Provider would select the combination of bids that maximizes the economic value
of the transactions for the participants.
In so doing, the Independent Transmission Provider must reconfigure the
Congestion Revenue Rights offered for sale in a way that maintains the
simultaneous feasibility of the Congestion Revenue Rights. That is, the types and/or locations of the
Congestion Revenue Rights offered for sale may differ from those that are purchased. The Independent Transmission Provider would
establish market-clearing prices for each Congestion Revenue Right bought or
sold. Each seller would receive the
market-clearing price for the rights that it sold, and each buyer would pay the
market-clearing price for the rights that it purchased.
f. Including
Energy and Ancillary Services in the Congestion Revenue Rights Auctions
47. The
time period covered by the Congestion Revenue Rights sold in auctions would be
a month or longer. We propose that an
Independent Transmission Provider would be permitted, but not required, to
conduct pre-day-ahead auctions for energy and ancillary services. Under such auctions, market participants
could offer to buy and sell energy and ancillary services at specific locations
on a forward basis for a specified time period, such as for a month or a
year. Participation in these pre-day
ahead markets, as in all markets, would be on a voluntary basis. Such purchases and sales of energy and
ancillary service would require use of the transmission system, just as sales
of Congestion Revenue Rights would.
Thus, in conducting pre-day-ahead auctions, the Independent Transmission
Provider would allocate transmission capacity among competing demands for
Congestion Revenue Rights, forward energy and forward ancillary services so as
to maximize the economic value of the winning bids. The Independent Transmission Provider would establish
market-clearing prices for forward energy and ancillary services at each
location, as well as market-clearing prices for Congestion Revenue Rights.
A potential benefit of pre-day-ahead auctions is that they could more easily maximize the economic benefits of transmission capability by considering a greater array of competing uses of the transmission grid. They could also provide a convenient, central market forum for buyers and sellers to arrange forward trades of energy and ancillary services. They could provide transparency and liquidity (and thus protection against manipulation) in long-term markets where liquidity has recently been reduced.
115See California ISO's Comprehensive Market Design Proposal, Docket No. ER02-1656-000 (May 1, 2002); see also California Independent System Operator Corp., 100 FERC ¶ 61,060 (2002).
116It is a widely accepted principle of economics that markets work efficiently when prices reflect marginal costs. See Alfred E. Kahn, The Economics of Regulation: Principles and Institutions, The MIT Press, Cambridge, Massachusetts, reprinted 1988, pp. 63-70. The economic rationale for applying marginal cost pricing to an electricity network using the concepts of LMP was presented in Schweppe, F.C., et al., Spot Pricing of Electricity, 1988, Norwell, MA, Kluwer Academic Publishers; and Hogan, William W., "Contract Networks for Electric Power Transmission," Journal of Regulatory Economics, 1992, vol. 4, pp. 211-242.
117Prices may also vary based on transmission losses. For purposes of simplification this discussion focuses on the differences due to energy prices alone.
118Under LMP, all suppliers selling at a location receive the market clearing price, including those who offer in their bids to sell for less. Similarly, all buyers purchasing at the location pay the market clearing price, including those who offer in their bids to purchase at a higher price. An alternative policy would be to pay each seller its bid price (and perhaps, to charge each buyer its bid price). We propose a single market clearing price for several reasons. First, it encourages sellers to submit bids that reflect their marginal costs (and thus, the sellers selected in the energy auction are more likely to be the sellers with the lowest actual costs). Sellers without market power could not increase the market price by increasing their bids, so bidding above their marginal costs would have no benefit to them. Bidding above marginal cost would merely create the risk that the seller would lose in the auction when the market price was higher than the seller’s marginal costs, and thus, the seller could have earned a profit. Moreover, by paying all sellers the market clearing price, sellers with marginal costs below the market clearing price would receive revenues to help recover their fixed costs. A policy of paying each seller its bid would encourage sellers to bid above their marginal costs, since doing so would be the only way for them to earn a profit. As a result, the sellers selected in the auction would not necessarily be the sellers with the lowest actual costs. Moreover, if the pay-as-bid policy were applied only to sellers (and not to buyers), so that buyers were charged the average payment made to sellers, buyers would face a price that was lower than the highest accepted seller’s bid. This result would encourage inefficient purchases and poor demand response. For example, on a hot day when the highest accepted seller’s bid is $1000/MWh but the average payment to sellers is $400/MWh, charging buyers $400/MWh under pay-as-bid would encourage less demand response than a market clearing price policy of charging $1000/MWh. If the pay-as-bid policy were applied to both sellers and buyers, then the revenue collected from buyers would usually differ from the revenue paid to sellers.
119The operation of the bid-based auction for energy is described further in Section IV.
120Because the transmission grid is a network, reducing transmission service between one receipt point - delivery point pair (e.g., from A to B) may free up transmission capability for transmission service between a different receipt point - delivery point pair (e.g., from C to D), albeit not necessarily on a MW-for-MW basis. For example, reducing service from A to B by 2 MW may allow an additional 1 MW of transmission service from C to D. If so, the price to transmit 1 MWh of energy from C to D must reflect at least what a customer denied 2 MW of service from A to B would have been willing to pay.
121Transmission losses will also be recovered through the transmission usage charge and included in the energy prices under LMP.
122As discussed above, we also propose that Congestion Revenue Rights would provide a scheduling priority in certain circumstances.
123For example, a customer holding Congestion Revenue Rights could be charged the congestion costs (e.g., $10 MWh) and then receive a credit on the same bill for congestion revenues (e.g., $10 MWh). So, the net congestion costs paid by the customer is $0. The customer, however, would have to pay for transmission losses.
124For example, a customer schedules and receives 100 MW of transmission service the day ahead at a congestion cost of $2/MW. The customer pays the $2/MW of congestion charges to the Congestion Revenue Rights holder (which could be itself). The customer may later decide it only needs 90 MW. It could then sell in the real-time market the unneeded 10 MW. If congestion in the real-time market is $3, the seller would receive $3/MW (or $30) for the sale of the 10 MW of transmission service from the buyer of the transmission service.
125Run-of-river facilities use the natural flow of the river to generate electricity. They typically divert water from a natural channel, run the water through a turbine to produce energy and then return the water to the natural channel downstream of the turbine.
126The market power mitigation measures would be developed on a regional basis and would take into account the special characteristics of hydropower.
127The operation of both a financially binding day-ahead market in conjunction with a financially binding real-time market is also known as a multi-settlement system.
128Such markets are currently operated by the New York ISO and PJM. California ISO and ISO-New England are planning on adding this feature to their market design.
129The bids usually take the form of a bid curve that shows the bid price and quantity between the unit’s minimum output and its maximum output. Usually the prices are relatively flat over the normal operating range of the unit. As quantities approach the maximum output the prices usually increase very rapidly.
130These transactions must still be scheduled through the day-ahead market and are subject to congestion costs if they do not have Congestion Revenue Rights.
131It is important that the schedule developed through the day-ahead market be physically feasible, i.e., consistent with reliable transmission limitations. If it were not, then it would be necessary to make separate congestion payments to suppliers in real time to change their output so that the real-time schedule was consistent with reliable transmission limitations. This would provide an incentive for suppliers to create congestion in the day-ahead market so that they could receive payments in real time to relieve congestion.
132For example, assume in the day-ahead market a generator agreed to sell 50 MW for the hour running from 9:00 am to 10:00 am at a price of $30 Mwh. In the day-ahead market the generator would receive $1,500 ($30 times 50) for that sale. In real time, the generator only delivered 20 MW during that hour. The real-time price of energy in that hour was $40 MWh. The generator would be charged $1200 for its 30 MW shortfall in real time (30 times 40). Thus, the generator would receive a total net payment of $300.
133For example, assume that a load-serving entity buys 40 MW in the day-ahead market for the hour 10:00 am to 11:00 am at a price of $30 Mwh. In the day-ahead market the load-serving entity would pay $1200 (40 times 30) for that purchase. In real time the load-serving entity only took 35 MW in that hour. The real-time price of energy for that hour was $25. The load-serving entity would effectively sell back the excess power (5 MW) at the real-time price ($25), $125. Thus, the load-serving entity would pay a net total of $1075.
134See, e.g., Hogan, William W., Financial Transmission Rights Formulations, Center of Business and Government, John F. Kennedy School of Government, Harvard University, Cambridge, MA (March 31, 2002); Chao, Hung-Po, Peck, Stephen and Wilson, Robert, Flow-based Transmission Rights and Congestion Management, The Electricity Journal, pp. 8, 13 and 38-58 (2000); and Chao, Hung-Po and Peck, Stephen, A Market Mechanism for Electric Power Transmission, Journal of Regulatory Economics (July 1996).
135The right is direction-specific. The holder is entitled to congestion revenues from the receipt to delivery point, not from the delivery point to the receipt point.
136Consider,
for example, a very simplified transmission network that connects two points, A
and B, with two different but interconnected transmission lines, a northern
line and a southern line, as shown below:
North Flowgate
A o----------------------------------------o
| |
o----------------------------------------o B
South Flowgate
Each transmission line could be a separate transmission or flowgate, and separate flowgate rights could be issued for each line. The holder of a flowgate right on the northern line from west to east would be entitled to the congestion revenues associated with that line in the west-to-east direction. However, holding a flowgate right on the northern line would not entitle the holder to congestion revenues associated with the southern line. Hence, if transmission service results in energy flows over several flowgates, the buyer must obtain sufficient rights on each flowgate to obtain protection from congestion charges. By contrast, the holder of a receipt point-to-delivery point right from west-to-east (i.e., from A to B) would be entitled to congestion revenues in the west-to-east direction regardless of whether the northern or the southern lines were congested and thus would have a complete hedge for this transaction
137As a result, in the event of force majeure the Congestion Revenue Rights would not be fully funded.