An Introduction to Financial
Transmission Rights
Financial transmission rights are superior to physical
transmission rights, particularly in markets employing
locational prices; however, many issues regarding FTR
allocation have not yet been resolved.
Karen Lyons, Hamish Fraser, and Hethie Parmesano
Karen Lyons is an Associate Analyst
at National Economic Research
Associates (NERA), San Francisco.
She specializes in economic analysis
and research of the electric industry
with an emphasis on restructuring.
Hamish Fraser is a Senior Consultant
at NERA’s New York office, where he
specializes in market restructuring and
economic analysis in the electric utility
industry. His work has included
leading a number of computer
modeling and market power
analyses in the industry.
Hethie Parmesano is Vice President
of NERA, Los Angeles, where she has
worked on numerous issues involving
electricity industry costing, pricing,
structure, and regulation. She also
teaches seminars on costing and
pricing topics, and directs a NERAsponsored industry group called the
Marginal Cost Working Group.
December 2000
T
ransmission rights are valuable
in electricity markets because
they (1) define property rights; and
(2) are a mechanism to hedge transmission price risk. Property rights entitle
market participants to the benefits
of using a transmission system by
reserving capacity on the line for
their exclusive use and/or by providing them with the financial benefits of the line. Property rights also
encourage market participants to
make investments in the transmission grid: They know their investments are protected because they
receive something fixed in return
that they can value and trade. The
ability to hedge transmission price
risk is an important tool in facilitating an efficient electricity market. It
allows market participants to lock
in the price of transmission usage,
rather than paying variable prices
for congestion.
There are two types of transmission rights: physical transmission
rights (PTRs) and financial transmission rights (FTRs).1 While both
of these provide the benefits
described above, FTRs are often
considered superior in electricity
markets with locational prices2
because the use of PTRs in these
markets can lead to serious problems. In order to better understand the distinction between
FTRs and PTRs, the next section of
this article will briefly discuss
PTRs, including their role in
transmission expansion and allocation methods, before the discussion moves on to FTRs.
© 2000, Elsevier Science Inc., 1040-6190/00/$–see front matter PII S1040-6190(00)00164-0
31
I. Physical Transmission
Rights
Physical transmission rights are
simple in theory. They involve the
exclusive right to transport a
predefined quantity of power
between two locations on the network, and accordingly, the right to
deny access to the network by
market participants who do not
hold the rights.
PTRs provide the necessary features of transmission rights. First,
they provide clearly defined “property rights” because it is necessary
to hold a PTR between two locations in order to transport energy.
This means that once a market participant pays for capacity on a
transmission line, it can be assured
that this capacity will be reserved
exclusively for its use. Alternatively, in times of high demand for
transmission, it can sell the right to
use the line. This will allow the PTR
owner to supplement the return on
its investment by selling (or “subletting”) the capacity when it is not
being used, or when the congestion-induced market prices for
capacity are greater than the owners’ alternative options. The latter
opportunity is particularly likely
to arise when someone else needs
to buy transmission capacity at
short notice.
econd, with a PTR the cost of
transmission usage can be
determined in advance of usage.
Market participants can acquire
PTRs by building transmission or
by buying them from others who
already have them.
Physical transmission rights,
however, can have potential prob-
S
32
lems. The most serious of these is
that the right of a PTR owner to
self-dispatch can interfere with the
system operator’s efforts to schedule and dispatch the system efficiently.3 If market participants
must hold physical rights to be dispatched, the rights need to be
tradable in very short time periods,
so that output from one plant may
be substituted for output from
another in real time. However, as
the moment of actual dispatch
With a PTR,
the cost of
transmission
usage can be
determined in
advance of usage.
approaches and many market participants use the spot market for
their trading needs, it is not easy—
nor necessarily even possible—for
them to identify their exact transmission needs in advance. They
will, therefore, not be able to make
PTR trades fast enough. Thus, PTR
holders, and not the system operator, end up dictating the use of the
transmission system.4
Another problem is the incompatibility of PTRs and locational
energy prices.5 PTRs could allow
market participants to raise prices
to uncompetitive levels in some
locations and/or to depress them
in others by withholding access.
© 2000, Elsevier Science Inc., 1040-6190/00/$–see front matter PII S1040-6190(00)00164-0
For example, a holder of PTRs
from A to B who has generation at
B might prevent generators at A
from using the transmission system. The holder of PTRs would do
this to maintain a high price at B.
Withholding access could thus
lead to production inefficiencies.
In the scenario above, the most
efficient and cheapest generators
might be located at A, but as long
as generator B withholds its transmission capacity from them, they
will not be able to participate in
the market.
n practice, regulators would
develop rules that would
impede such a situation from arising. In order to make PTRs compatible with locational prices,
they would implement rigid eligibility standards for PTR holders
(i.e., market participants that are
in a position to exercise market
power would be ineligible) or
strict rules concerning the use of
PTRs. In either case, these would
be difficult to determine and
equally difficult to enforce.
I
II. Financial Transmission
Rights
Financial transmission rights can
deal with both of the potential PTR
problems listed above. FTRs are
contracts that exist between a market participant—in fact, any individual or organization—and the
system operator. FTRs are defined
in a way similar to physical transmission rights: from a source location to a destination location. They
are also denominated in a MW
amount corresponding to the transfer capability between these loca-
The Electricity Journal
tions. However, FTRs do not entitle
their holders to an exclusive right to
use the transmission system.
Instead, FTRs exist in an environment of open access to the transmission system for all market
participants—regardless of whether
they hold a transmission right.
FTRs solve both of the problems
of PTRs discussed above. First,
FTRs do not lead to inefficient dispatches, but rather to efficient dispatches. New generators are not
stopped from bidding below existing generators and open access is
not denied to anyone on the transmission system. The system operator does not even need to take FTRs
into account in its operation of the
system because FTRs are purely
financial instruments that can be
settled outside of the spot market.
TR payments represent exactly
the financial benefit that
would accrue to a market participant that owned its own line, or to
the owner of a PTR that sold its
right to the highest bidder.6 In
effect, FTRs are tradable rights that
are automatically assigned to those
users who provide the system with
the highest value. For example, if
the holder of an FTR is a generator
that does not have a low-enough
offer price to be dispatched, the
generator will nonetheless receive
the financial equivalent of having
sold the right to the generator that
does get dispatched. And the FTR
holder receives this payment without having to scurry about to find
a participant to buy the right.
Rents are paid irrespective of who
uses the transmission system.
Second, FTRs are completely
compatible with locational mar-
F
December 2000
ginal prices and, in fact, are dependent upon them. FTRs give their
holders the right to payments
equal to the energy price
difference7 between the source
location and the destination location for the denominated MW.
These payments are funded by the
natural “congestion rent” that
arises when energy is purchased
from lower-priced regions and
transmitted to and sold in higherpriced regions. Therefore, there
FTRs are also beneficial
because they provide
a convenient way to
deal with congestion
rents that the system
operator collects.
must be price differences between
locations, i.e., a locational price system. In a single-price system, FTRs
have no meaning, since these price
differences will not formally exist.
FTRs are also beneficial because
they provide a convenient way to
deal with these congestion rents
that the system operator collects.
In a worst-case scenario, the system operator would be allowed to
keep the congestion rents. This
would give the system operator an
incentive to dispatch the system
inefficiently, and impede grid
expansion in an attempt to
increase congestion and thus its
revenue. While this situation
would never be permitted by regulators, congestion rents do arise, as
does the need to decide how to
allocate them. FTRs provide a
simple solution to this problem.
A. Property Rights and
Transmission Expansion
In the same way that locational
prices of energy give new generators the right incentives for where
and when to build, the payment of
congestion rents gives market participants the incentives to build
new transmission where and when
it is cost-effective to do so.8 Marketdriven transmission expansion
will occur when payments of congestion rents are sufficiently high;
at that time, market participants
will prefer to invest in new transmission to reduce or eliminate congestion, rather than to continue to
pay congestion rents.
In the short term, the builders of
new transmission capacity will no
longer have to pay congestion
charges (or have their low-cost
generation sit idle) because, once
the new capacity is built, their
paths will no longer be congested.
Therefore, at least initially, the
FTRs they received in exchange
for building the new capacity generate no congestion payments. In
the long term, however, these
FTRs can become very important.
The FTRs give their holders a
guarantee that if the new transmission lines become congested
(and the price of transmission
usage rises again), they will still
receive the benefits of the line
through the collection of congestion rents. This point is illustrated
in Example 1.
© 2000, Elsevier Science Inc., 1040-6190/00/$–see front matter PII S1040-6190(00)00164-0
33
Example 1
In Figure 1, the variable costs ($/MWh) and capacities (MW) of
each generator are given. System load is 2,700 MW, including 200
MW located at A and 2,500 MW located at B. The capacity of the
transmission line is 1,000 MW. The price at A is equal to $15, the
variable cost of GeneratorA2.9 This is because a load increase of 1
MW at A would be met by GeneratorA2, the cheapest available generator that is not fully utilized. The price of electricity at B is $30
since an extra MW of load at B could only be served by Generator B.
Figure 1: Line is Congested
Now suppose that an extra 1,000 MW of new capacity is constructed (Figure 2) and that the amortized construction cost of the
line is $5/MWh. GeneratorA110 builds and pays for the line since it
will benefit from a $15/MWh higher market price when the line is
built and congestion is eliminated. In return for paying for the line,
GeneratorA1 also receives FTRs for 1,000 MW from A to B. These
FTRs entitle it to the congestion rents from A to B for 1,000 MW.
The line is cost-effective to the system as a whole because the
average benefit of the new line is greater than the expansion cost
($9.50/MWh vs. $5/MWh).11 Immediately after the link is built, the
price at both A and B is $30/MWh (if load increased by 1 MW at
either A or B, only GeneratorB could meet it). The prices are equalized in each location since all congestion is relieved and, therefore, there is initially no congestion rent.
Figure 2: Congestion is Eliminated
But this situation may not be permanent. Continuing with the
example, another generator (Generator A4) builds a 1,000 MW
plant at A, causing the line to become congested again (Figure
3). GeneratorA4 bids energy into the market at a lower price than
GeneratorA1 (who built the line). Although Generator A1’s output
remains the same, the price at A is reduced to the price before
the expansion ($15/MWh). However, since GeneratorA1 has FTRs
for 1,000 MW, it receives congestion rents of $15/MWh, the difference in prices between the two locations. Generator A1 continues to receive the value of the transmission it paid for, even
though someone else is using the line.
Figure 3: Line Is Once Again Congested
It is as if GeneratorA1 sold the FTR temporarily to Generator A4
for its value. FTRs act as tradable transmission rights that are in
fact traded, but the trading is automatic. Generator A1 receives
the rents from holding the FTR, irrespective of who uses the line
and when the line is used.
FTRs bestow the correct incentives on market participants. By
defining FTRs as the property rights that match transmission ownership with transmission benefits, market participants have eco-
34
nomically efficient incentives. Without FTRs, transmission owners
run the risk that the benefits of their investments will be captured
by others, such as GeneratorA4 in this example. To better illustrate
this, assume that it was GeneratorA3 that built the additional
capacity in order to be dispatched. Without FTRs, GeneratorA4
captures the benefits by using all of the new capacity. GeneratorA3
is no longer dispatched, but continues to pay for the line.
© 2000, Elsevier Science Inc., 1040-6190/00/$–see front matter PII S1040-6190(00)00164-0
The Electricity Journal
B. Price Hedging
With FTRs, traders in the wholesale markets for electricity have the
means at hand to hedge against the
risk of locational price differences.
Holders of FTRs are able to enter
into contracts with other market
participants without taking on the
risk of transmission price fluctuations. For instance, a generator at A
and a purchaser at B could enter
into a fixed-price supply contract.
The transaction could be hedged
against the risk of transmission
price fluctuations between A and B
with the purchase of an FTR
between A and B that matched the
MW size of the transaction. The
congestion charges—namely the
price at B minus the price at A—
would be exactly offset by the FTR
payments. Example 2 illustrates the
hedging properties of FTRs.
TRs that are used to hedge
transmission price uncertainty
do not distort the marginal signals
for the efficient use of the transmission system. Generators still have
incentives to be dispatched economically. Market participants that
transact with each other, but hold
fewer FTRs than their transaction’s
MW quantity, will still pay the
opportunity cost of transmission to
the extent they are unhedged. To the
extent market participants hold
FTRs that exceed their transaction
hedging requirements, they will still
receive the opportunity cost of the
transmission capacity they implicitly made available to someone else.
F
C. Allocation of FTRs
One aspect of FTR allocation has
already been discussed in this arti-
December 2000
cle, albeit not directly: FTRs should
be given to those who invest in
transmission expansion. Allocation of FTRs in this way provides
incentives for efficient investment
in the transmission system. There
are, however, many other issues
regarding FTR allocation that have
not yet been addressed, such as eligibility requirements for FTR
ownership, allocation of FTRs for
the existing transmission system,
and secondary markets for FTRs.
These issues are more difficult to
discuss because there is no one correct way to handle them; rather,
the appropriate solution ultimately
depends on the structure of the
market and on the decisions made
in that market.
Before FTRs can be allocated,
potential FTR holders must first be
defined. FTRs could be given only
to transmission owners or only to
generators. They could be given to
both generators and distributors.
They could be made available to
all market participants and/or
people outside of the market. They
could be also be given to a combination of any of the above.
Once eligibility requirements
have been defined, FTRs for existing transmission capacity could be
allocated in a number of different
ways. They could be assigned
based on existing transmission
rights or agreements, auctioned
off, or allocated so that their benefits offset the redistribution of economic rents arising from tariff
reforms.
f an auction is used, the issue
of what do to with the ensuing
revenues arises. There are many
ways to handle this, but by far the
I
Example 2
A generator at A and a purchaser
at B wish to hedge against transmission price risk by locking in the
price of energy at the buyer’s location. The generator’s variable cost
of energy at A is $15/MWh, and it
purchases an FTR between A and
B for a price equivalent to $10/
MWh; the FTR is equal in MW size
to his generating capacity. The
generator is therefore able to guarantee that the delivered cost to B
will never be more than $15, plus a
fixed rate ($10/MWh) for the FTR 5
$25/MWh in total;
• In one hour, the market price
at A is $14/MWh. The generator
does not operate and buys
replacement energy from the market at a $1/MWh saving. The FTR
guarantees that energy can be
withdrawn at B, where the price is
$27/MWh, with no net charge for
transmission except for the $10/
MWh fixed fee. The total cost is
therefore $14 plus $10 5 $24/
MWh. (An equivalent way of looking at the transaction is that the
energy can be withdrawn at B for
$27/MWh, but the $13/MWh value
of the FTR (the difference between
the spot prices at A and B) means
the net cost of the transaction to
the supplying generator is $27
minus $13 5 $14, plus the $10
cost of the FTR 5 $24/MWh).
• In another hour, the market
price at A is $18/MWh. The generator operates since it is economical
to run. There may or may not be
congestion, but in either case there
is no additional transmission cost
because of the FTR. The net cost to
the generator (excluding its lost
opportunity of making a market sale)
is its production cost of $15, and
the cost of the FTR of $10. The
delivered cost to B is therefore
$25/MWh.
In neither case does the generator’s cost to supply electricity at B
exceed $25/MWh.
© 2000, Elsevier Science Inc., 1040-6190/00/$–see front matter PII S1040-6190(00)00164-0
35
36
© 2000, Elsevier Science Inc., 1040-6190/00/$–see front matter PII S1040-6190(00)00164-0
The Electricity Journal
FTRs were initially allocated to Network Integration
Service customers.
Initial allocation
PJM 5 Pennsylvania–New Jersey–Maryland interconnection.
FTR auction revenues, net of payments to FTR
sellers, are allocated among the regional
transmission owner in proportion to their respective
transmission revenue requirements.
• For 1 and 2: Must be a PJM Firm Transmission
Service customer.
• For 3 and 4: Must be a PJM member or a
transmission customer.
• For 5: Only one party needs to be a PJM member.
Distribution of
revenues
New York
Transmission Congestion Contracts (TCCs)
California
Firm Transmission Rights (FTRs)
All revenues received by transmission owners from
the sale of Grandfathered TCCs and Residual TCCs,
as well as excess auction revenues, are credited
against the transmission owner’s cost of service to
reduce the transmission service charge.
Prior to the formation of the NYISO, there was an initial
allocation of TCCs. In the first stage of the allocation,
customers receiving service under Existing
Transmission Agreements (ETA) were given the choice
of converting their existing rights into either
Grandfathered Rights or into Grandfathered TCCs.
After these rights had been allocated and accounted
for, Existing Transmission Capacity for Native Load
(ETCNL) was allocated to some transmission owners.
Once all of these had been accounted for, Residual
TCCs were allocated to the Transmission Owners.
• All market participants may participate.
The primary auction proceeds went to the
participating transmission owners. Each participating
transmission owner credited its FTR auction
proceeds against its access charge (in order to pay
off their transmission system investments).
The initial allocation was through a primary auction
in November of 1999, in which FTRs equal to 100%
of the operating limit at 99.5-percent availability
were auctioned off. These FTRs are valid for a
period of 14 months, from February 1, 2000 until
March 31, 2001.
• Anyone (including non-market participants) may
participate.
1. Primary Auction: The ISO will conduct annual
1. Network Integration Service: The network customer 1. Centralized TCC Auctions: Auctions conducted
primary auctions approximately two months before
under the direction of the ISO. The first TCC auction
has the option to request FTRs for all or any portion
the beginning of the term of the FTRs.
(the “Transitional Auction”) took place in September
of its generations resources.
of 1999 to provide all transmission customers with 2. Secondary Market: FTR holders can sell their FTRs
2. Firm Point-to-Point Service: PJM allocates FTRs to
in the Day-Ahead market, at a price they specify,
an opportunity to purchase TCCs for use on day one
Firm Point-to-Point Service customers for approved
using adjustment bids.
of NYISO operations. Long-term TCCs began to be
service requests. The duration of the FTR is the same
auctioned off by the ISO in March of 2000. The first 3. Investment in the Transmission System: First, an
as for the associated service request.
entity must build an incremental transmission
round of auctions allocated TCCs with a validity of
3. FTR Auction: PJM conducts separate auctions each
facility identified by the ISO as one needed for
2 years. The second round of auctions, which took
month for FTRs for on-peak and off-peak periods. The
inter-zonal interface. It then must file with the
place in April of 2000, allocated TCCs with a validity
FTR auction offers for sale any residual transmission
FERC and become a Participating Transmission
of 6 months. Reconfiguration auctions, which allow
entitlement that is available after Network and longOperator (PTO). Once this is done, the ISO will
participants to sell and purchase short-term FTRs
term Point-to-Point Transmission Service FTRs are
auction the appropriate amount of FTRs
(valid for one month), have also begun to take place
awarded. The auction also allows market participants
attributable to this grid expansion and provide the
monthly.
an opportunity to sell FTRs that they are currently
proceeds to this new PTO.
2. Direct Sales: Sales by the primary Transmission
holding. FTRs are for a term of one month.
Owner to a buyer.
4. Secondary Market: This is a bilateral trading system
that facilitates trading of existing FTRs through eFTR, 3. Secondary Markets: Market in which both primary
and secondary holders may sell their TCCs.
a bulletin board system.
5. Independently: PJM has no knowledge of such trades.
PJM
Fixed Transmission Rights (FTRs)
Eligibility rules
Ways of
obtaining FTRs
Name
Table 1: How Fixed Transmission Rights are Handled in Different U.S. Markets
most common approach is to allocate them to the transmission
owners. The transmission owners
may then decide how to use these
revenues: In California, transmission owners use them to pay off
their transmission system investments, and in New York they are
used to reduce the transmission
service charge.
fter the initial allocation of
FTRs has taken place, FTRs
could be bought and sold in secondary markets, much like any
other financial instrument. Parties
initially awarded the FTRs could
resell them to market participants
for hedging against transmission
price risk. FTRs would hedge
against congestion costs by fixing
the price of congestion at the price
of obtaining an FTR. The price of
obtaining an FTR would reflect
the expected net present value of
congestion costs for the contract
duration. The initial FTR owners
would therefore be able to capture
the FTR value of their transmission investment (or entitlement)
either as a stream of future congestion payments or as a lumpsum payment up front. FTR contracts could also be broken up
and sold for different time periods. For example, FTRs could
be sold for a week or a month,
or in the case of providing price
certainty for long-term investments, for many years. FTRs
could also be sold for different
times of day, or for peak versus
off-peak usage.
Table 1 shows how these
issues have been handled in the
PJM, New York, and California
markets.
A
December 2000
III. Conclusion
There is no one-size-fits all
model for financial transmission
rights: They have been allocated in
a number of different ways to a
number of different people. This is
to be expected, though, given the
diversity that exists in electricity
markets across the country. But no
matter how different FTRs may be
from one another, they are still
very useful tools in electricity markets with locational pricing. j
Endnotes:
1. Financial transmission rights are
known by a variety of names. In the
Pennsylvania-New Jersey-Maryland
Interconnection they are referred to as
fixed transmission rights (FTRs); in the
New York Power Pool, as transmission
congestion contracts (TCCs), in California, as firm transmission rights (FTRs),
and in the New England Market, as
financial congestion rights (FCRs).
2. Although it is true that many restructured markets, such as Spain, Alberta,
and England and Wales, do not have
locational prices, locational prices have
become increasingly standard in the
electricity industry and the disadvantages of “single-price” models have
become increasingly apparent.
3. The possibility of this problem occurring, and the severity of it, increase as
the number of market participants
increases. While today there are markets
in which PTRs are used that do not suffer from system inefficiency due to the
right to self-dispatch, these generally do
not have many market participants.
When there are many market participants—and subsequently many PTR
holders—the number of transactions (or
trades) that need to take place increases
greatly, putting the efficiency of the system at risk.
4. One way to maintain reliability with
PTRs would simply be to issue fewer of
them than the transmission system is
capable of bearing; that way the risk of
overloading the transmission system—
under constantly changing configurations of usage—is lowered. This clearly
has the problem of being inefficient. On
many occasions, cost-saving opportunities to increase output in cheap locations
and decrease output in expensive ones
would be lost.
5. This incompatibility exists as long as
these PTRs give their holders the ability
to exclude users from the use of transmission capacity. Other types of PTRs
may exist, such as “use or lose” PTRs.
With these, the owner of the PTR must
tell the system operator whether it
intends to make use of its right before a
certain set time. If it is not going to use it,
or if it does not inform the system operator by the time deadline, it will lose its
right to use the transmission system. In
this case, the ability of the generator to
raise prices would be significantly
diminished.
6. This is provided the highest bidder
accurately predicted the value of being
able to move power from, for example, A
to B.
7. The energy price difference is the net
of the difference of the component of
prices representing marginal losses.
8. A detailed description of transmission system expansion incentives in
restructured markets is beyond the
scope of this article. However, in simplified terms, when the energy re-dispatch savings of transmission expansion exceed the costs of the expansion,
transmission usage fees (differences in
locational prices) will exceed the amortized expansion costs.
9. In a competitive market with strategic
bidding, the assumption of bids equal to
variable cost might not hold. For reasons
of simplicity, though, this assumption
will be used in this example.
10. It could be a coalition of generators at
A, and perhaps consumers at B.
11. The average benefit of the line is calculated as the redispatch savings from
building the line, divided by the capacity
of the line. In the example above, this is
equal to (300?$15 1 500?10)/1,000 5
$9.50/MWh.
© 2000, Elsevier Science Inc., 1040-6190/00/$–see front matter PII S1040-6190(00)00164-0
37