An Introduction to Financial Transmission Rights

December 2000

© 2000, Elsevier Science Inc., 1040-6190/00/$–see front matter PII S1040-6190(00)00164-0

31

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

ransmission rights are valuable in electricity markets because

they (1) define

property rights

; and (2) are a

mechanism to hedge transmis-sion 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 pro-viding them with the financial ben-efits of the line. Property rights also encourage market participants to make investments in the transmis-sion grid: They know their invest-ments 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 facilitat-ing 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 transmis-sion rights: physical transmission rights (PTRs) and financial trans-mission rights (FTRs).

1

While both of these provide the benefits described above, FTRs are often considered superior in electricity markets with locational prices

2

because the use of PTRs in these markets can lead to serious prob-lems. In order to better under-stand the distinction between FTRs and PTRs, the next section of this article will briefly discuss PTRs, including their role in transmission expansion and allo-cation methods, before the discus-sion moves on to FTRs.

Karen Lyons

is an Associate Analystat National Economic Research

Associates (NERA), San Francisco.She specializes in economic analysisand research of the electric industrywith an emphasis on restructuring.

Hamish Fraser

is a Senior Consultantat NERA’s New York office, where he

specializes in market restructuring andeconomic analysis in the electric utility

industry. His work has includedleading a number of computer

modeling and market poweranalyses in the industry.

Hethie Parmesano

is Vice Presidentof NERA, Los Angeles, where she hasworked on numerous issues involving

electricity industry costing, pricing,structure, and regulation. She also

teaches seminars on costing andpricing topics, and directs a NERA-sponsored industry group called the

Marginal Cost Working Group.

T

32


The Electricity Journal

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 net-work, and accordingly, the right to deny access to the network by market participants who do not hold the rights.

PTRs provide the necessary fea-tures of transmission rights. First, they provide clearly defined “prop-erty rights” because it is necessary to hold a PTR between two loca-tions in order to transport energy. This means that once a market par-ticipant pays for capacity on a transmission line, it can be assured that this capacity will be reserved exclusively for its use. Alterna-tively, 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 “sub-letting”) the capacity when it is not being used, or when the conges-tion-induced market prices for capacity are greater than the own-ers’ 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-

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 sched-ule and dispatch the system effi-ciently.

3

If market participants must hold physical rights to be dis-patched, 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

For example, a holder of PTRs from A to B who has generation at B might prevent generators at A from using the transmission sys-tem. 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 trans-mission 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 aris-ing. In order to make PTRs com-patible with locational prices, they would implement rigid eligi-bility 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.

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 mar-ket participant—in fact, any indi-vidual or organization—and the system operator. FTRs are defined in a way similar to physical trans-mission rights: from a source loca-tion to a destination location. They are also denominated in a MW amount corresponding to the trans-fer capability between these loca-

With a PTR,the cost of

transmissionusage can be

determined in

advance of usage.

approaches and many market par-ticipants use the spot market for their trading needs, it is not easy—nor necessarily even possible—for them to identify their exact trans-mission needs in advance. They will, therefore, not be able to make PTR trades fast enough. Thus, PTR holders, and not the system opera-tor, end up dictating the use of the transmission system.

4

Another problem is the incom-patibility 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.

I

S

December 2000


33

tions. However, FTRs do not entitle their holders to an exclusive right to use the transmission system. Instead, FTRs exist in an environ-ment of open access to the trans-mission 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 dis-patches, but rather to efficient dis-patches. New generators are not stopped from bidding below exist-ing generators and open access is not denied to anyone on the trans-mission system. The system opera-tor 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 partici-pant 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 with-out 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-

ginal prices and, in fact, are depen-dent upon them. FTRs give their holders the right to payments equal to the energy price difference

7

between the source location and the destination loca-tion 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 higher-priced regions. Therefore, there

would never be permitted by regu-lators, 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 genera-tors the right incentives for where and when to build, the payment of congestion rents gives market par-ticipants the incentives to build new transmission where and when it is cost-effective to do so.

8

Market-driven transmission expansion will occur when payments of con-gestion rents are sufficiently high; at that time, market participants will prefer to invest in new trans-mission to reduce or eliminate con-gestion, 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 gen-erate 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 trans-mission lines become congested (and the price of transmission usage rises again), they will still receive the benefits of the line through the collection of conges-tion rents. This point is illustrated in

Example 1

.

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 sys-tem. 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 sys-tem 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

F

34



Example 1

In Figure 1, the variable costs ($/MWh) and capacities (MW) ofeach generator are given. System load is 2,700 MW, including 200MW located at A and 2,500 MW located at B. The capacity of thetransmission 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 1MW at A would be met by GeneratorA2, the cheapest available gen-erator that is not fully utilized. The price of electricity at B is $30since an extra MW of load at B could only be served by GeneratorB.

Now suppose that an extra 1,000 MW of new capacity is con-structed (Figure 2) and that the amortized construction cost of theline is $5/MWh. GeneratorA1

10 builds and pays for the line since itwill benefit from a $15/MWh higher market price when the line isbuilt and congestion is eliminated. In return for paying for the line,GeneratorA1 also receives FTRs for 1,000 MW from A to B. TheseFTRs 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 theaverage benefit of the new line is greater than the expansion cost($9.50/MWh vs. $5/MWh).11 Immediately after the link is built, theprice at both A and B is $30/MWh (if load increased by 1 MW ateither A or B, only GeneratorB could meet it). The prices are equal-ized in each location since all congestion is relieved and, there-fore, there is initially no congestion rent.

Figure 1: Line is Congested

Figure 2: Congestion is Eliminated

But this situation may not be permanent. Continuing with theexample, another generator (GeneratorA4) builds a 1,000 MWplant at A, causing the line to become congested again (Figure3). GeneratorA4 bids energy into the market at a lower price thanGeneratorA1 (who built the line). Although GeneratorA1’s outputremains the same, the price at A is reduced to the price before

the expansion ($15/MWh). However, since GeneratorA1 has FTRsfor 1,000 MW, it receives congestion rents of $15/MWh, the dif-ference in prices between the two locations. GeneratorA1 contin-ues to receive the value of the transmission it paid for, eventhough someone else is using the line.

It is as if GeneratorA1 sold the FTR temporarily to GeneratorA4

for its value. FTRs act as tradable transmission rights that are infact traded, but the trading is automatic. GeneratorA1 receivesthe rents from holding the FTR, irrespective of who uses the lineand when the line is used.

FTRs bestow the correct incentives on market participants. Bydefining FTRs as the property rights that match transmission own-ership with transmission benefits, market participants have eco-

nomically efficient incentives. Without FTRs, transmission ownersrun the risk that the benefits of their investments will be capturedby others, such as GeneratorA4 in this example. To better illustratethis, assume that it was GeneratorA3 that built the additionalcapacity 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.

Figure 3: Line Is Once Again Congested

December 2000


35

B. Price Hedging

With FTRs, traders in the whole-sale 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 fluctua-tions. 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 transmis-sion system. Generators still have incentives to be dispatched econom-ically. 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 implic-itly made available to someone else.

C. Allocation of FTRs

One aspect of FTR allocation has already been discussed in this arti-

cle, albeit not directly: FTRs should be given to those who invest in transmission expansion. Alloca-tion 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 eli-gibility 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 cor-rect 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 combi-nation of any of the above.

Once eligibility requirements have been defined, FTRs for exist-ing 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 bene-fits offset the redistribution of eco-nomic 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

Example 2

A generator at A and a purchaser at B wish to hedge against trans-mission price risk by locking in the price of energy at the buyer’s loca-tion. 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 guar-antee 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 mar-ket 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 look-ing 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 genera-tor 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 genera-tor’s cost to supply electricity at B exceed $25/MWh.

F

I

36



Tabl

e 1:

How

Fix

ed T

rans

mis

sion

Rig

hts

are

Hand

led

in D

iffer

ent U

.S. M

arke

ts

Nam

ePJ

MFi

xed

Tran

smis

sion

Rig

hts

(FTR

s)Ne

w Y

ork

Tran

smis

sion

Con

gest

ion

Cont

ract

s (T

CCs)

Calif

orni

aFi

rm T

rans

mis

sion

Rig

hts

(FTR

s)

Way

s of

ob

tain

ing

FTRs

1. 2. 3. 4. 5.

Netw

ork

Inte

grat

ion

Serv

ice:

The

net

wor

k cu

stom

er

has

the

optio

n to

requ

est F

TRs

for a

ll or

any

por

tion

of it

s ge

nera

tions

reso

urce

s.Fi

rm P

oint

-to-

Poin

t Ser

vice

: PJM

allo

cate

s FT

Rs to

Fi

rm P

oint

-to-

Poin

t Ser

vice

cus

tom

ers

for a

ppro

ved

serv

ice

requ

ests

. The

dur

atio

n of

the

FTR

is th

e sa

me

as fo

r the

ass

ocia

ted

serv

ice

requ

est.

FTR

Auct

ion:

PJM

con

duct

s se

para

te a

uctio

ns e

ach

mon

th fo

r FTR

s fo

r on-

peak

and

off-

peak

per

iods

. The

FT

R au

ctio

n of

fers

for s

ale

any

resi

dual

tran

smis

sion

en

title

men

t tha

t is

avai

labl

e af

ter N

etw

ork

and

long

-te

rm P

oint

-to-

Poin

t Tra

nsm

issi

on S

ervi

ce F

TRs

are

awar

ded.

The

auc

tion

also

allo

ws

mar

ket p

artic

ipan

ts

an o

ppor

tuni

ty to

sel

l FTR

s th

at th

ey a

re c

urre

ntly

ho

ldin

g. F

TRs

are

for a

term

of o

ne m

onth

. Se

cond

ary

Mar

ket:

This

is a

bila

tera

l tra

ding

sys

tem

th

at fa

cilit

ates

trad

ing

of e

xist

ing

FTRs

thro

ugh

eFTR

, a

bulle

tin b

oard

sys

tem

. In

depe

nden

tly: P

JM h

as n

o kn

owle

dge

of s

uch

trade

s.

1. 2. 3.

Cent

raliz

ed T

CC A

uctio

ns: A

uctio

ns c

ondu

cted

un

der t

he d

irect

ion

of th

e IS

O. T

he fi

rst T

CC a

uctio

n (th

e “T

rans

ition

al A

uctio

n”) t

ook

plac

e in

Sep

tem

ber

of 1

999

to p

rovi

de a

ll tra

nsm

issi

on c

usto

mer

s w

ith

an o

ppor

tuni

ty to

pur

chas

e TC

Cs fo

r use

on

day

one

of N

YISO

ope

ratio

ns. L

ong-

term

TCC

s be

gan

to b

e au

ctio

ned

off b

y th

e IS

O in

Mar

ch o

f 200

0. T

he fi

rst

roun

d of

auc

tions

allo

cate

d TC

Cs w

ith a

val

idity

of

2 ye

ars.

The

sec

ond

roun

d of

auc

tions

, whi

ch to

ok

plac

e in

Apr

il of

200

0, a

lloca

ted

TCCs

with

a v

alid

ity

of 6

mon

ths.

Rec

onfig

urat

ion

auct

ions

, whi

ch a

llow

pa

rtici

pant

s to

sel

l and

pur

chas

e sh

ort-

term

FTR

s (v

alid

for o

ne m

onth

), ha

ve a

lso

begu

n to

take

pla

ce

mon

thly

. Di

rect

Sal

es: S

ales

by

the

prim

ary

Tran

smis

sion

Ow

ner t

o a

buye

r. Se

cond

ary

Mar

kets

: Mar

ket i

n w

hich

bot

h pr

imar

y an

d se

cond

ary

hold

ers

may

sel

l the

ir TC

Cs.

1. 2. 3.

Prim

ary

Auct

ion:

The

ISO

will

con

duct

ann

ual

prim

ary

auct

ions

app

roxi

mat

ely

two

mon

ths

befo

re

the

begi

nnin

g of

the

term

of t

he F

TRs.

Se

cond

ary

Mar

ket:

FTR

hold

ers

can

sell

thei

r FTR

s in

the

Day-

Ahea

d m

arke

t, at

a p

rice

they

spe

cify

, us

ing

adju

stm

ent b

ids.

In

vest

men

t in

the

Tran

smis

sion

Sys

tem

: Firs

t, an

en

tity

mus

t bui

ld a

n in

crem

enta

l tra

nsm

issi

on

faci

lity

iden

tifie

d by

the

ISO

as o

ne n

eede

d fo

r in

ter-

zona

l int

erfa

ce. I

t the

n m

ust f

ile w

ith th

e FE

RC a

nd b

ecom

e a

Part

icip

atin

g Tr

ansm

issi

on

Oper

ator

(PTO

). On

ce th

is is

don

e, th

e IS

O w

ill

auct

ion

the

appr

opria

te a

mou

nt o

f FTR

s at

trib

utab

le to

this

grid

exp

ansi

on a

nd p

rovi

de th

e pr

ocee

ds to

this

new

PTO

.

Elig

ibili

ty ru

les

• • •

For 1

and

2: M

ust b

e a

PJM

Firm

Tra

nsm

issi

on

Serv

ice

cust

omer

.Fo

r 3 a

nd 4

: Mus

t be

a PJ

M m

embe

r or a

tra

nsm

issi

on c

usto

mer

. Fo

r 5: O

nly

one

party

nee

ds to

be

a PJ

M m

embe

r.

•Al

l mar

ket p

artic

ipan

ts m

ay p

artic

ipat

e.•

Anyo

ne (i

nclu

ding

non

-mar

ket p

artic

ipan

ts) m

ay

parti

cipa

te.

Initi

al a

lloca

tion

FTRs

wer

e in

itial

ly a

lloca

ted

to N

etw

ork

Inte

grat

ion

Serv

ice

cust

omer

s.Pr

ior t

o th

e fo

rmat

ion

of th

e NY

ISO,

ther

e w

as a

n in

itial

al

loca

tion

of T

CCs.

In th

e fir

st s

tage

of t

he a

lloca

tion,

cu

stom

ers

rece

iving

ser

vice

unde

r Exis

ting

Tran

smiss

ion

Agre

emen

ts (E

TA) w

ere

give

n th

e ch

oice

of

con

verti

ng th

eir e

xistin

g rig

hts

into

eith

er

Gran

dfat

here

d Ri

ghts

or i

nto

Gran

dfat

here

d TC

Cs.

Afte

r the

se ri

ghts

had

bee

n al

loca

ted

and

acco

unte

d fo

r, Ex

istin

g Tr

ansm

issio

n Ca

paci

ty fo

r Nat

ive L

oad

(ETC

NL) w

as a

lloca

ted

to s

ome

trans

miss

ion

owne

rs.

Once

all

of th

ese

had

been

acc

ount

ed fo

r, Re

sidua

l TC

Cs w

ere

allo

cate

d to

the

Tran

smiss

ion

Owne

rs.

The

initi

al a

lloca

tion

was

thro

ugh

a pr

imar

y au

ctio

n in

Nov

embe

r of 1

999,

in w

hich

FTR

s eq

ual t

o 10

0%

of th

e op

erat

ing

limit

at 9

9.5-

perc

ent a

vaila

bilit

y w

ere

auct

ione

d of

f. Th

ese

FTRs

are

val

id fo

r a

perio

d of

14

mon

ths,

from

Feb

ruar

y 1,

200

0 un

til

Mar

ch 3

1, 2

001.

Dist

ribut

ion

of

reve

nues

FTR

auct

ion

reve

nues

, net

of p

aym

ents

to F

TR

selle

rs, a

re a

lloca

ted

amon

g th

e re

gion

al

trans

mis

sion

ow

ner i

n pr

opor

tion

to th

eir r

espe

ctiv

e tra

nsm

issi

on re

venu

e re

quire

men

ts.

All r

even

ues

rece

ived

by

trans

mis

sion

ow

ners

from

th

e sa

le o

f Gra

ndfa

ther

ed T

CCs

and

Resi

dual

TCC

s,

as w

ell a

s ex

cess

auc

tion

reve

nues

, are

cre

dite

d ag

ains

t the

tran

smis

sion

ow

ner’s

cos

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December 2000


37

most common approach is to allo-cate them to the transmission owners. The transmission owners may then decide how to use these revenues: In California, transmis-sion owners use them to pay off their transmission system invest-ments, 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 sec-ondary 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 transmis-sion investment (or entitlement) either as a stream of future con-gestion payments or as a lump-sum payment up front. FTR con-tracts could also be broken up and sold for different time peri-ods. For example, FTRs could be sold for a week or a month, or in the case of providing price certainty for long-term invest-ments, 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.

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 mar-kets 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 Califor-nia, as firm transmission rights (FTRs), and in the New England Market, as financial congestion rights (FCRs).

2.

Although it is true that many restruc-tured 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 disadvan-tages of “single-price” models have become increasingly apparent.

3.

The possibility of this problem occur-ring, 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 suf-fer from system inefficiency due to the right to self-dispatch, these generally do not have many market participants. When there are many market partici-pants—and subsequently many PTR holders—the number of transactions (or trades) that need to take place increases greatly, putting the efficiency of the sys-tem 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 configura-tions of usage—is lowered. This clearly has the problem of being inefficient. On many occasions, cost-saving opportuni-ties 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 trans-mission 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 opera-tor 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 transmis-sion system expansion incentives in restructured markets is beyond the scope of this article. However, in sim-plified terms, when the energy re-dis-patch savings of transmission expan-sion exceed the costs of the expansion, transmission usage fees (differences in locational prices) will exceed the amor-tized 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 cal-culated 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.

A

Documents

An Introduction to Financial Transmission Rights