UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Long Term Transmission Rights in Docket No. AD05-7-000 

Markets Operated by 

Regional Transmission Organizations 

 and Independent System Operators 

NOTICE INVITING COMMENTS ON ESTABLISHING LONG TERM 

TRANSMISSION RIGHTS IN MARKETS WITH LOCATIONAL PRICING 

(May 11, 2005) 

The Commission invites all interested persons to file comments addressing 

establishing long term transmission rights in electricity markets operated by Regional 

Transmission Organizations (RTOs) and Independent System Operators (ISOs). 

An important cost of transmission service is the congestion cost that customers 

incur when, due to the physical limitations of the grid, they are unable to obtain energy 

from the lowest cost generation resources. In markets with locational pricing, 

participants can hedge against congestion costs by holding Financial Transmission Rights 

(FTRs), which are generally allocated to historical users of the grid. Currently, the 

longest term FTR offered in any of the RTO or ISO markets is one year. 

The Commission is aware of interest by some market participants and others to 

obtain transmission service at a known price for periods longer than one year in markets 

that use locational pricing. In response, the Commission staff has conducted informal 

outreach to get informal views on the need for, and issues raised by, establishing long 

term transmission rights. At this point, the Commission desires to obtain written 

comments by all interested parties. The Commission is particularly interested in 

comments that address the following: 

• The need for long term transmission rights and the problems caused by the lack of 

them. Are such rights needed more by certain types of entities or in markets in 

certain regions? 

• The impacts of introducing long term rights. What specific impediments or 

problems must be addressed? 

• The plans of specific RTOs and ISOs to address long term transmission rights. 

• Substantive and procedural options for the Commission to address long term 

transmission rights. 
- 2 - 

The Commission is aware that the adequacy of long term transmission rights may 

be an issue in markets that do not use locational pricing but believes that there are unique 

issues in markets with locational pricing that are best addressed separately. 

A Commission staff document is available online at http://www.ferc.gov to assist 

parties in providing comments, but will not be published in the Federal Register. The 

staff document provides background on the need for long term transmission rights and 

the issues that must be addressed in introducing them into markets. The document also 

provides specific questions to address as well as general background on locational pricing 

and on FTR allocation methods in the existing RTOs and ISOs. 

For further information, contact: 

Wilbur Earley 

Office of Markets Tariffs and Rates 

202-502-8087 

wilbur.earley@ferc.gov

Udi Helman 

Office of Markets Tariffs and Rates 

202-502-8080 

udi.helman@ferc.gov

Jeffery Dennis 

Office of General Counsel 

202-502-6027 

jeffery.dennis@ferc.gov

 

The Commission encourages electronic submission of comments in lieu of paper 

using the “eFiling” link at http://www.ferc.gov. Persons unable to file electronically 

should submit an original and 14 copies of the comment to the Federal Energy 

Regulatory Commission, 888 First Street, N.E., Washington, D.C. 20426. 
- 3 - 

All filings in this docket are accessible on-line at http://www.ferc.gov, using the 

“eLibrary” link and will be available for review in the Commission’s Public Reference 

Room in Washington, D.C. There is an “eSubscription” link on the web site that enables 

subscribers to receive email notification when a document is added to a subscribed 

docket(s). For assistance with any FERC Online service, please email 

FERCOnlineSupport@ferc.gov, or call (866) 208-3676 (toll free). For TTY, call (202) 

502-8659. 

Comment Date: 5:00 pm Eastern Time on June 27, 2005. 

Linda Mitry 

Deputy Secretary 
Long-Term Transmission Rights Assessment 

FERC Staff Discussion Paper 

May 11, 2005 

Introduction 

In recent months, there has been an interest among various participants in the RTO 

and ISO1

 markets to obtain long-term rights for transmission usage; that is, rights with 

terms of more than one year. RTOs manage transmission congestion by using 

“locational” pricing, which establishes the transmission usage cost due to congestion (and 

possibly also transmission losses). Congestion costs can be highly volatile. In 

conjunction with congestion pricing, RTOs offer transmission rights which are financial 

instruments that entitle participants to a refund of congestion costs. These instruments 

are generally not made available for terms greater than one year, but are instead allocated 

again each year to eligible transmission users subject to availability. 

Some market participants have concerns that sufficient transmission rights may 

not be available each year to adequately cover their congestion cost exposure. They 

argue that the combination of potentially volatile congestion costs, variability in the 

annual allocation, and the inability to secure a known quantity of transmission rights for 

multiple years introduces an unacceptable degree of uncertainty into resource planning 

and investment. As a result, some participants want the ability to obtain long-term 

transmission rights or service at a price certain. 

Providing such long-term rights presents challenges. One such challenge is that to 

the extent that the RTO hands out transmission rights over multiple years but actual grid 

conditions are different than those anticipated, the RTO could collect insufficient 

congestion revenues to pay the FTR holders. Decisions must then be made regarding 

who will bear the revenue shortfall. As might be expected, the longer the instrument’s 

term, the greater the probability that grid conditions will be different than forecast. 

Long-term transmission rights could alternatively be created by exempting certain 

transmission users from the RTO’s price-based congestion management system. These 

customers would retain the right to physically schedule their power but would not pay 

congestion charges nor receive financial transmission rights. Most RTOs have 

“grandfathered” some prior transmission rights in this fashion. This approach could 

provide the transmission customer with long-term price stability, but could also reduce 

 

1

 Henceforth, the term RTO will be used to refer also to ISOs, except when a 

specific ISO is being discussed. 

1
economic efficiency and shift costs to those that remain within the RTO congestion 

pricing and financial transmission rights system. 

Many market participants noted that in some regions, transmission infrastructure is 

insufficient to address their needs. The more robust the grid, the greater the potential for 

congestion hedges that have long-term stability. Although the staff team did not explore 

barriers to transmission investment, this was a recurrent theme that closely intersects with 

the issue of long-term transmission rights. 

In short, long-term transmission rights can be established in RTO markets in 

various ways, but each of these requires trade-offs in cost and risk. A clear 

understanding of these trade-offs is necessary for making policy and market design 

decisions that support market competition, economic efficiency and system reliability. 

The purpose of the paper is to elicit public comments on the need for longer term 

rights, the issues that need to be considered, and how the Commission should go about 

addressing these issues. The paper builds on the staff team’s review of existing RTO 

market rules and informal dialogue with market participants, market operators, state 

regulators, and experts in market design and finance. 

The paper is organized as follows. The first sections of the paper provide 

background on locational pricing and financial transmission rights, the interest in longterm rights, comparison of financial rights with the transmission rights that existed before 

the RTO markets, and impediments to implementation of long-term financial rights. We 

then examine some design issues that could be a consideration when offering long-term 

financial transmission rights, such as who is eligible for the rights, what term should they 

be, whether they should be obligations or options or both, whether they should be directly 

allocated or bought through an auction, and what the rules should be when the RTO’s 

congestion revenues are not adequate to fully cover its payment obligations to rights 

holders. We also provide some initial views on the relationship of infrastructure 

financing and availability of long-term rights. Finally, we discuss alternative methods for 

providing transmission customers with long-term transmission scheduling rights in RTO 

markets. In most sections of the paper, we identify questions for public comment, but 

this list is not intended to be exhaustive. 

Defining terms and design concepts is important, because parties’ understanding 

of these can differ. To this end, Appendix A offers definitions and background on 

locational pricing and financial instruments, and the basic allocation and auction rules. 

This appendix also summarizes some of the differences among the existing RTO and ISO 

markets, because these differences will matter to how long-term rights are introduced. 

Appendix B then examines the individual RTO market rules in greater detail. 

2
Locational Pricing and Financial Hedging Instruments 

All RTOs approved by the Commission have implemented or planned for a 

congestion management system based on locational pricing of energy, mostly using 

locational marginal pricing (LMP), and the allocation or auction of financial transmission 

rights (FTRs).2

 Locational pricing establishes the difference in cost between purchasing 

energy at different locations in the spot market due to congestion and losses; in this paper 

we will concern ourselves only with congestion. The congestion charge associated with 

injecting power at one location (e.g., a generator) and withdrawing it at another location 

(e.g., a load) is equal to the difference in the LMPs at the two locations. If the price 

difference is zero, then there is no congestion charge. While the transmission user can 

estimate congestion charges ahead of time, the actual congestion charge is only known 

when the spot market locational prices are calculated. 

 

An FTR is an instrument for returning the congestion charges collected by the 

RTO through LMP settlements to the market participants that hold the rights. FTRs thus 

can be used to hedge congestion charges associated with energy contracts or purchasing 

strategies. In other words, an FTR can refund all congestion charges faced by the holder 

of the FTR if the specification of the rights matches the transmission schedule. It is 

important to keep in mind, however, that the quality of the congestion hedge depends on 

the specification of the right (e.g., whether an option or obligation) and the rules for FTR 

market settlement. In general, FTRs are provided to load-serving entities (LSEs)

3

 and 

others that pay fixed cost transmission rates, either through direct allocation or through an 

auction process in which the LSE is allocated auction revenue rights (ARRs) that can be 

used to purchase FTRs.

4

 ARRs and FTRs can also be allocated to any party that invests 

in transmission upgrades or expansion. FTRs can also be traded in annual and monthly 

RTO auctions or on a bilateral basis by any entity. 

As noted, RTOs currently offer ARRs and FTRs with terms of one year or less. 

LSEs that have met the RTO eligibility requirements have each year the right to nominate 

ARRs or FTRs up to some measure of their peak load. However, the quantities awarded 

of ARRs or FTRs may change each year due to factors outside the control of the LSE 

(such as changes in the network or the FTR nominations of other participants). We will 

 2

 We will use the term FTR to refer generally to the various types of financial 

transmission rights available in the RTO markets. 

3

 An LSE is any entity that serves retail load. 

4

 ARRs confer the right to collect revenues from the subsequent FTR auction. For 

example, the holder of an ARR between location A and location B knows that it will 

collect revenues equal to the market clearing price of an FTR between location A and 

location B. An ARR can exactly match an FTR, but does not need to; for details, see 

appendices A and B. 

3
discuss some of the reasons for this in subsequent sections. Most RTOs do provide longterm transmission rights (i.e., rights with terms greater than one year) for transmission 

upgrades or expansion that increase transmission capability. These long-term 

transmission expansion rights merit extensive discussion in themselves, but the paper will 

focus on long-term rights to existing transmission capacity. 

The Interest in Long-Term Transmission Rights 

The interest in long-term transmission rights has arisen for a number of reasons. 

One general reason is that certain transmission users, particularly those with long-term 

generation resource commitments and load, perceive that LMP volatility has increased 

congestion risk. They believe that a long-term ARR or FTR will let them lock in a 

congestion hedge, whereas the uncertainty of annual FTR and ARR allocations leads to 

greater price risk. This perception appears to be more acute in some regions than in 

others.5

 

Another reason for interest in long-term rights is that some parties investing in 

new generation to serve load want to ensure a fixed quantity of transmission rights 

associated with the delivery of power from the new generator for a term equivalent to the 

expected term of financing for the investment or to the life of the asset. They contend 

that the lack of long-term transmission rights could be problematic for the firm’s credit 

rating or for the ability to undertake project financing. The long-term right thus provides 

the certainty some participants believe is needed to support rational resource planning 

and acquisition. 

Not all market participants agree that there is a pressing need for long-term 

transmission rights nor on what the appropriate term of such rights should be if they are 

offered. For such participants, there seems to be general satisfaction with the rights 

awarded through the annual allocation process in some RTO markets. However, if the 

benefits and costs are assigned appropriately so that the introduction of long-term 

financial rights does not create significant equity issues, most market participants 

consulted by the team were not opposed to them. 

• What are the needs of market participants for long-term transmission rights 

 5

 For example, in the Midwest ISO there was some initial concern as the ISO 

began to model the transmission system and assign FTRs to market participants that the 

modeling was not reflective of how transmission rights had been sold historically and that 

as such the resulting FTRs did not protect historical transmission users. Many of those 

issues were addressed by the Commission in its orders on the Midwest ISO market 

design. 

4
in RTO markets? What has been the experience with congestion pricing 

and transmission rights of market participants in RTO markets? Have 

financial right allocations been sufficient to meet participants’ needs for 

congestion hedging and long-term resource planning and acquisition? 

Comparison of Prior Transmission Rights to Financial Rights 

For some transmission customers seeking long-term transmission rights in RTO 

markets, the objective is to restore long-term transmission service that has scheduling, 

pricing and risk properties akin to the transmission service that they had before the start 

of the RTO market (with LMP and FTRs). Hence, to understand the expectations of such 

transmission customers, it is useful to review the characteristics of the prior transmission 

service and ask what the differences are with the current transmission rights and whether 

they are reconcilable. 

Prior to the implementation of RTO markets, transmission service for customers in 

those regions was governed by either pre-Order No. 888 Open Access Transmission 

Tariff (OATT) contracts or the OATT.6

 Under the OATT, there are two types of 

transmission service – network integration transmission service (network service), which 

is a long-term firm transmission service, and point-to-point transmission service, which 

can be provided on a firm or non-firm basis and on a long-term (one year or longer) or 

short-term basis. Long-term firm transmission customers have the right to continue to 

take transmission service from the transmission provider when the contract expires, rolls 

over or is renewed (rollover right). 

Point-to-point transmission service is for the receipt of capacity and energy at 

designated points of receipt and the transmission of such capacity and energy to 

designated points of delivery. A firm point-to-point transmission customer pays a 

monthly demand charge based on its reserved capacity. 

Network service provides the customer with flexibility to integrate, economically 

dispatch and regulate its current and planned network resources (i.e., generation) to 

service its network load in a manner comparable to that in which the transmission 

provider utilizes its transmission system to serve its native load customers.7

 The network 

 6

 Most pre-OATT transmission contracts were grandfathered into the RTO 

markets, hence will not be discussed further. 

7

 A network customer must designate network resources, including all generation 

owned, purchased or leased by the network customer to serve its designated load. A 

network customer also must designate the individual network loads on whose behalf the 

transmission provider will provide network service. 

5
customer generally pays a monthly demand charge based on its load ratio share of fixed 

costs. 

As a condition of receiving network service, a network customer agrees to 

redispatch its network resources as requested by the transmission provider pursuant to the 

terms of the OATT.8

 The transmission provider must plan, construct, operate and 

maintain its transmission system in order to provide the network customer with network 

service over the transmission provider’s system, and must designate resources and loads 

in the same manner as any network customer. If the transmission provider needs to 

redispatch the system due to congestion to accommodate a network customer’s schedule, 

the costs of redispatch are passed through to the transmission provider’s native load and 

to network customers on a load-ratio basis. Transmission providers are not obligated to 

redispatch to accommodate a point-to-point customer’s schedule. 

If a curtailment on the transmission provider’s system is required to maintain 

reliable operation of the system, curtailments are made on a non-discriminatory basis to 

the extent practicable and consistent with good utility practice, with firm service having 

the highest priority and non-firm generally having the lowest priority. 

OATT transmission service greatly increased access to the transmission grid and 

hence facilitated the growth in wholesale power trading across the country. OATT 

service – typically provides long-term price stability. However, the Commission has 

noted problems of continuing undue discrimination by transmission providers outside 

RTOs. 9 Moreover, as usage of the grid has grown, in many areas curtailment of 

transmission schedules to manage congestion has resulted in growing market 

inefficiency. 

Finally, OATT network integration transmission service is not readily tradable, 

whereas in many regions, especially those with retail competition and where vertically 

integrated utilities had divested their generation holdings to merchant operators, a 

tradable right would enable potential users of the grid to obtain rights from willing 

sellers. 

RTOs are essentially physical transmission scheduling entities on a much larger 

 8

 Redispatch means that, due to congestion, the utility changes the output of its 

generators to maintain the energy balance. The output of some generators may be 

increased while the output of others may decrease. 

9

 E.g., Regional Transmission Organizations, Order No. 2000, 65 Fed. Reg. 809 

(January 6, 2000), FERC Stats. & Regs. ¶ 31,089 (1999), order on reh'g, Order No. 2000-

A, 65 Fed. Reg. 12,088 (February 25, 2000), FERC Stats. & Regs ¶ 31,092 (2000), 

petitions for review dismissed, Public Utility District No. 1 of Snohomish County, 

Washington v. FERC, 272 F.3d 607 (D.C. Cir. 2001). . 

6
scale than a single public utility. RTO market participants that are serving load can 

schedule their generation and load through either the RTO day-ahead or real-time 

(dispatch) markets. In general, scheduling (or simply withdrawing power from the grid) 

in real-time can impose additional costs, such as the costs of generation that the RTO puts 

on stand-by when it forecasts that load has under-scheduled day-ahead. Unlike 

transmission providers in non-RTO regions, RTOs with LMP rely on price-based 

congestion management. That is, LMP makes explicit the cost of redispatch service. 

These features allow for a coordinated, efficient dispatch over a large region, and 

significantly reduce the need for curtailments as compared to those that occur when 

individual public utilities are scheduling transmission service on a non-price basis. 

There are important differences between OATT transmission rights and FTRs. 

Unlike the OATT approach to transmission scheduling, which gives a scheduling priority 

to firm customers, in LMP markets all scheduling requests are treated as firm, but subject 

to congestion charges. FTRs are allocated to protect against congestion charges, but they 

are not required to physically schedule. Moreover, FTRs are settled financially whether 

the party that holds them physically schedules or not. That is, a party that holds an FTR 

from point A to point B does not have to schedule power between those points to collect 

FTR revenues (the incentive properties of such rights are discussed in Appendix A). 

 

As has been discussed, all ISOs and RTOs began market operations with a oneyear cycle of ARR or FTR allocations. With one exception, the terms of the financial 

rights were restricted to the one-year term or less, subject to renewal the next year.10 This 

appears to have reflected the preference of market participants at the time. Market 

participants are allocated rights typically based partly on their historical uses of the 

system and also with some flexibility to choose among eligible transmission paths. The 

details vary by RTO, as reviewed in the appendices. Since the state of the system and 

market prices change from year to year, the market participants are allowed to reconfigure their transmission rights requests each year, taking advantage of their market 

experience. The annual reconfiguration of rights also helps the RTO to manage exposure 

to situations of revenue shortfalls where payments to FTR holders exceed FTR revenues 

as a result of changes in the transmission grid or in the availability of generators that have 

a major impact on power flows. If such changes appear to be long-term, the RTO will 

adjust the quantity of rights handed out in the next annual cycle. 

In conclusion, OATT transmission service, once obtained, appears to provide 

better long-term price certainty than the current RTO transmission service. But 

congestion management could be inefficient and network transmission rights are not 

 

10 The exception is New York ISO, which offered FTRs with 2 year and 5 year 

terms during the Fall 2000 FTR auction. These multi-year rights were not offered 

subsequently. See discussion in Appendix B.

7
easily traded and reconfigured, such that those who value them most highly can obtain 

them from willing sellers. The RTO transmission service greatly improves access, 

provides price-based congestion management that is generally efficient, and allows 

auctions and secondary markets for trade in transmission rights that are increasingly 

flexible in terms of locations and time periods covered. On the other hand, there are 

concerns that FTR allocations do not always offer long-term price stability, that is, 

adequate coverage of congestion charges. The policy issue is thus whether parties should 

be allowed to revert to some version of the prior OATT service within the RTO markets 

with LMP and FTRs or whether the FTR model can be modified to provide the type of 

congestion cost coverage that such parties seek. 

Long-term Financial Transmission Rights 

One avenue for providing less price uncertainty for transmission customers is to 

provide long-term financial transmission rights. A long-term right may be defined as 

either an FTR or an ARR with a term of more than one year. In general, long-term 

financial rights would decrease market participants’ uncertainty about exposure to 

congestion costs over the period of the rights and for the quantity specified. In this 

section, we examine issues that may be raised by introduction of long-term financial 

rights. In a subsequent section, we examine the implications of other approaches to longterm rights in RTO markets. 

Impediments to long-term financial rights in RTO markets 

In discussions with market participants and RTO market operators, staff heard a 

number of reasons why multi-year financial rights have not heretofore been a standard 

component of the RTO transmission markets. Some of these impediments are a factor in 

providing long-term transmission service in markets without locational pricing, but they 

may pose greater challenges in markets with locational pricing. 

First, as noted above, financial rights are currently allocated based on a snapshot 

of the transmission grid’s capability for the year ahead. Uncertainty about future changes 

to the transmission network and to major generation resources make it difficult for the 

RTO to forecast accurately the available transmission many years into the future. 

Another source of grid uncertainty is changes in generation dispatch patterns over time. 

All of these factors affect the set of FTRs that are simultaneously feasible and thus the 

supply of FTRs. 

Second, congestion prices and patterns in RTO markets have been difficult to 

predict and can change dramatically year to year. While this is not an impediment to 

issuing long-term transmission rights, it does make it difficult for participants to value 

8
such rights. 

Third, given these uncertainties, there is the prospect for significant financial gains 

or losses associated with long-term financial rights. The creditworthiness of market 

participants that are allocated long-term financial rights or purchase them through an 

auction must therefore be ascertained by the RTO, although this will be difficult. 

 

Fourth, in RTO regions with retail choice states, LSEs facing competition 

typically do not seek transmission rights beyond the terms of their energy contracts. New

contracts could require a different set of FTRs. By tying up valuable hedging instruments 

over many years, allocating long-term transmission rights could become a barrier to 

entry. 

Fifth, there are concerns that long-term FTRs will be less liquid than annual or 

shorter term FTRs, resulting in a less efficient market for congestion hedges. 

Based on the staff team’s discussions, it appears that these factors, rather than 

design or implementation, present the greatest impediments to introduction of long-term 

rights. Staff notes, however, that some of the impediments have not been analyzed in 

great detail. A clear understanding of the nature and significance of any impediments, as 

well as measures to mitigate their effects, are critical to evaluating the efficacy of longterm financial rights 

• Have RTOs or market participants quantified the probability of significant 

changes in network topology over time due to transmission line outages or 

outages of major generators? Put another way, how stable are network 

topologies over time? What are the implications for revenue adequacy of 

long-term financial transmission rights? How significant is the role of 

changes in generation dispatch over time to the feasibility of long-term 

financial rights? 

Market design issues 

Market design refers to the rules governing transmission rights. Several aspects of 

market rules governing FTRs and ARRs will affect long-term financial rights. Based on 

the staff team’s initial review and discussions, the following market design issues were 

identified as being of primary concern to market participants and market operators: 

eligibility criteria, the term of long-term rights, whether the rights are obligations or 

options, how the rights are initially awarded (allocation or auction), and what insurance 

the rights have under revenue inadequacy conditions. 

Eligibility Criteria 

9
All participants seeking ARRs and FTRs in the current RTO markets must meet 

basic eligibility requirements. Parties eligible for allocation of FTRs or ARRs must be 

transmission customers of the RTO; that is, those parties that pay the fixed costs of the 

transmission system through access charges. In general, an LSE is eligible only for rights 

up to its peak annual load (which is the usual billing determinant for transmission 

service). A point-to-point customer is typically eligible up to its transmission 

reservation.11 Another requirement for participation in the FTR auctions is 

creditworthiness. This is to ensure that buyers and sellers in the auction have sufficient 

credit to cover their settlement obligations for the duration of the right. These basic 

eligibility requirements presumably would carry over to the allocation of long-term 

rights. 

Some market participants and market operators have suggested that the allocation 

of long-term financial rights raises several eligibility issues. One is whether long-term 

rights are available to all market participants currently eligible for ARRs or FTRs in the 

RTO system or whether priority is given to some participants on the basis of historical 

contracts or resource usage. Priority might be a consideration when an equitable 

allocation of long-term rights is difficult to achieve for all parties simultaneously. For 

example, a priority in the allocation of long-term rights has been proposed for 

transmission customers that held long-term transmission rights before the RTO began 

operations. 

Another approach to the problem of availability might be not to restrict access to 

long-term rights on the basis of historical contracts, but rather to adopt a basis for all 

RTO participants to qualify. For example, long-term rights might only be available to 

cover generation resources that were used as base-load over some prior period of time, or 

planned as base-load in future. Alternatively, long-term rights could be allowed for any 

resource but restricted to a percentage of a market participant’s total eligible number of 

rights. It should be noted that these types of eligibility criteria are difficult to implement 

in practice without greatly complicating the allocation process. 

A second eligibility issue is whether all parties that request long-term rights should 

be subject to creditworthiness requirements for the life of the right and how such an 

assessment should be conducted. As the market operator, the RTO must evaluate the 

increased credit risk when selling long-term FTRs, especially for obligation FTRs that 

could have sustained periods of net payments (see discussion of obligation rights below 

 11 Some RTOs have given network customers the first chance to obtain FTRs (as 

PJM did for several years), but recently the Commission has required that network and 

point-to-point rights be allocated on equal footing. Some RTOs give historical resources 

the first chance to obtain FTRs (e.g., PJM), while others set aside capacity for FTRs for 

native load (e.g., New York). 

10
and in appendix A). That is, if the payments become too large, the FTR holders could 

default and the RTO could have to recover those payments from other parties. 

• Should there be eligibility criteria for allocation or purchase of long-term 

rights? Should some transmission customers have preferential access to 

such rights based on their historical transmission rights? Should such rights 

be reserved for particular generation resources, such as base-load plants? 

Should a limited quantity of the rights be offered? What should be the 

credit requirements for obtaining such rights? 

Term 

The term of long-term financial rights desired by market participants is likely to 

vary by the type of firm seeking the rights. LSEs seeking to hedge transmission charges 

associated with their own generation assets or long-term contracts and long-term load 

may desire terms on the order of decades. Other LSEs face retail competition and hence 

may seek terms of a few years at most to provide greater flexibility to change their 

transmission coverage when the location of load changes.12 Yet other market participants 

may be entering the FTR market to maximize FTR revenues, and will thus seek FTRs in 

locations and for terms that fit their expectations about future congestion charges. 

The staff team has heard of no software limitation in conducting an auction with 

multi-year ARRs or FTRs of various terms. The trend among RTOs is to offer more 

“granular”13 terms for the current annual rights, with the shortest term currently being one 

month with the choice of daily peak or off-peak hours. The time increment could in 

theory be very granular and defined by the transmission user, within the term limits 

imposed by the RTO on the particular transmission user or on the market as a whole. 

Increased granularity could increase the ability to tailor long-term rights to long-term 

needs. 

If there are limits on the terms of ARRs or FTRs, then they are likely to be the 

result of financial constraints and/or concerns about fairness, as discussed elsewhere in 

this section. 

• What term of long-term rights is desirable? Should the available terms be 

 

12 In general, the revenues from ARRs or FTRs will follow the load when it 

changes suppliers. The details of how this is done vary by RTO, as detailed in Appendix 

B. 

13 That is, shorter time periods or more choice in terms of hours of the day (e.g., 

off-peak and peak hours). 

11
defined on a standard basis by the RTO or should transmission customers 

define the terms that they desire (within the eligibility criteria and term 

constraints imposed by the RTO market)? How granular should long-term

rights be (week, month, season, year)? Are there technical impediments to 

the modeling of long-term rights? 

Obligations versus options 

Obligation rights grant the holder the right to collect positive congestion revenues 

associated with the points of injection and withdrawal specified in the right, but also 

carry the obligation to pay negative congestion revenues. Negative congestion revenue 

occurs when the LMP at the right’s injection location is higher than the LMP at the 

right’s withdrawal location.14 In contrast, option rights grant the right to collect positive 

congestion revenues, but not the obligation to pay negative congestion revenues. In 

general, the option right is a financially less risky instrument, but also reduces the total 

quantity of rights available on the system.15 The option right is thus a more valuable 

right to the holder. For more discussion of these properties, see Appendix A. 

In a long-term financial right, the financial risk associated with the obligation right 

can potentially become amplified. If the situation arises that the holder of an obligation 

right faces obligation FTR payments and cannot manage this exposure through 

generation or load, then holding such an instrument over a longer term becomes a greater 

potential liability than it might be for a right that expires after one year.16 In the annual 

 14 The obligation FTR holder’s exposure to congestion changes will depend on 

whether it is operating a generator consistently with the FTR. If it can operate a 

generator at the source point of the FTR, then the obligation FTRs payment obligations 

will be equal to or less than the generator’s LMP revenues. 

15 The basic reason why option rights reduce the amount of FTRs that can be 

allocated is because the RTO cannot assume that the financial “counterflow” payments 

embodied in the obligation FTR are available for revenue adequacy. Hence, these 

counterflows cannot be included in the allocation model. 

16 Consider the following hypothetical example. A utility that has built a remote 

generator in a low price location to serve load in a high price location holds a 20 year 

FTR obligation. In year 5, the utility decides to sell its remote generator because it has 

joined in a large new plant closer to its load. But it can’t reconfigure its FTR, because the 

counterflows from the right are being used to support other parties’ FTRs and they are 

not willing to reconfigure, nor can it sell its FTR, which regardless is still paying positive 

FTR revenues. However, in year 7, changes in fuel prices, generation locations and 

transmission expansion have reversed the prices at the locations in the FTR and it is now 

a liability. Because the utility no longer owns the remote generator, it cannot run it to 

offset the negative FTR revenues. 

12
allocation cycle, such liabilities can be minimized by not requesting the FTR in the next 

allocation. A long-term obligation right, on the other hand, could be more difficult to 

return, reconfigure or sell if it became a liability. 

Option rights are one way to address some of the risks of long-term obligation 

rights. However, as discussed above, option rights restrict the quantity of transmission 

rights that can be allocated; if bought through an auction, they are more expensive than 

obligation rights. Some utilities may have assets and load located in such a fashion that 

they would clearly benefit from holding options in the long-term, but others could find 

that as power flows change, their ability to hedge congestion charges is made less flexible 

year to year by the introduction of a long-term option right. As such, the RTO may have 

to establish rules that limit the allocation of option rights, if these are directly allocated 

rather than bought voluntarily through an auction. 

• Should long-term transmission rights be obligations or options or both? If 

the rights are being allocated directly (i.e., not through an auction), on what 

basis should parties be eligible to nominate options and how should the 

RTO address fairness issues that may arise in the allocation? 

Allocation and auction of rights 

Each current RTO has slightly different rules for allocation of FTRs or ARRs and 

the subsequent FTR auctions. The differences in these rules will have implications for 

the properties of long-term rights introduced into the market. If long-term rights were 

introduced, then there are currently two basic approaches that would be used to allocate 

them: (1) direct allocation of FTRs, or (2) direct allocation of ARRs followed by auction 

of FTRs. In direct allocation of FTRs, the eligible market participants are given FTRs, 

typically in a series of allocation rounds that may give higher initial priority to historical 

resources. Alternatively, the participants could be directly allocated ARRs and would 

then have to purchase the FTRs that they want in the auction. There are somewhat 

different rules for these procedures in each RTO; these rules are reviewed in more detail 

in appendices A and B.

 

Direct Allocation of FTRs. In this approach, long-term FTRs would be directly 

assigned to market participants, based on eligibility requirements, such as those discussed 

above. The advantage of direct allocation of long-term FTRs is that it does not require 

the LSE receiving the rights to estimate their value and directly compete in an auction 

with other parties that may be seeking the same rights (although ARRs in most cases 

allow the holder to outbid any competitor if she chooses). This may suit parties that are 

seeking a congestion hedge of a fixed amount for long-term resources and load. 

 

13
There are also possible disadvantages to direct allocation. Some observers argue 

that it may not encourage FTR valuation among risk-averse holders of the rights and 

hence there may be a concern that the transmission users with the highest value uses of 

the grid will not be able to obtain transmission rights. 

Allocation of ARRs with FTR auctions. Most RTOs currently allocate ARRs and 

then allow transmission customers and others to purchase FTRs through an annual 

auction. In general, the auction model is intended to prompt more careful valuation of 

FTRs than direct allocation of FTRs, and hence to promote market liquidity by bringing 

more sellers into the market. However, when considering long-term rights, especially 

those with terms longer than a few years, there may be considerable uncertainty over the 

long-term value of the FTR. Market participants have suggested to the staff team that 

this potentially creates an informational asymmetry that favors larger firms that can better 

internalize the risks of estimating FTR values over multiple years.17 

Moreover, some transmission customers may seek a fixed long-term hedge 

regardless of its expected market value and are wary of the concept of having to compete 

for such rights in an auction, even with ARRs.18 First, as with direct allocation of FTRs, 

direct allocation of ARRs may not give them the potential coverage of their transmission 

usage that they desire (i.e., ARRs themselves may be pro-rationed). Second, the outcome

of an FTR auction, in terms of the quantity of rights allocated, will be entirely dependent 

on the bid and offer behavior of the auction participants and the resulting modeled power 

flows. Hence, as with the direct allocation of FTRs, some parties that seek long-term 

obligation rights may not obtain them via the auction process. For these reasons, some 

RTOs (e.g., PJM) allow parties to directly convert ARRs into FTRs, bypassing the 

auction. 

• Should long-term FTRs be awarded through direct allocation? Should 

long-term FTRs be available through annual auctions? Are particular ARR 

allocation approaches (i.e., those taken by different RTOs) more suited to 

long-term rights than others? Are designs that allocate long-term rights to 

some parties but require others purchase FTRs through an auction possible 

 17 For example, market participants noted that when the New York ISO offered 2 

year and 5 year rights in the 2000 fall auction, only a few parties did well in the longterm auction, capturing valuable rights cheaply. For this reason, multi-year rights were 

not offered subsequently, although the ISO is planning to re-introduce such rights. 

18 The way in which the ARR is specified – i.e., point-to-point (e.g., PJM and New 

York ISO) or to a share of the transmission path from each of the RTO market generators 

to the customer’s load (e.g. ISO New England) – may contribute to perceptions that the 

quantity of resulting FTRs may be uncertain. 

14
or desirable? 

Rules for FTR payments when RTO is not revenue adequate 

RTOs assign ARRs and FTRs to transmission users only to the extent that they are 

expected to be simultaneously feasible. This means that all the injections and 

withdrawals being modeled when assigning rights can take place simultaneously while 

respecting the physical and reliability limits on the network (as assumed in the RTO’s 

“snapshot” of the period being modeled). As long as the aggregate set of ARRs and 

FTRs issued are simultaneously feasible in this analysis, the RTO is assured that it can 

collect at least enough congestion revenues from users of the grid to pay the holders of 

the rights when they are settled financially in the day-ahead market. This revenue 

adequacy holds as long as the network transfer capability does not change such that the 

RTO collects insufficient congestion revenues to pay the rights. 

However, all RTOs experience transmission deratings or outages, changes in 

generator availability that affect the feasible power flow, and unexpected loop flow from 

contiguous RTOs or other balancing authorities. Such events that were not in the model 

used to identify the feasible set of rights can reduce congestion revenues collected below 

the level needed to pay existing FTR holders. When this happens, rules are needed to 

determine whether and how much FTR holders are paid. For example, PJM sets aside 

surplus congestion revenues each month (i.e., any congestion revenues left over after 

paying FTR holders) and uses this fund to pay FTR holders when the grid capability is 

reduced. When the fund runs out, FTR holders are paid a pro-rata share of their actual 

FTR entitlements. In contrast, New York ISO fully funds FTRs, and assigns any 

payments not covered through congestion revenues to transmission owners, which can 

then pass the costs through to their transmission customers through access charges. 

Different payment rules thus create hedges with different properties and have financial 

implications for cost assignment. 

Because the probability of revenue insufficiency is likely to be greater with longterm financial rights, how such costs are assigned when the RTO is revenue inadequate 

could be more of an issue than in the annual allocation cycle. 

• Should long-term financial rights be fully funded or subject to revenue 

shortfalls due to transmission network changes? How should potential 

revenue shortfalls be allocated? 

• If long-term financial rights are awarded based on forecast grid conditions, 

but maintenance of the grid declines, resulting in future infeasibility, which 

parties should be responsible for maintaining the revenue adequacy of the 

rights? 

15
Long-term financial rights and infrastructure financing 

Our preliminary discussions with merchant generators, transmission-dependent 

utilities, credit rating agencies and financial advisors, allow a few observations to be 

made about the relationship between the availability of long-term transmission rights and 

financing of new infrastructure. These observations vary by type of firm and type of 

infrastructure project. 

One concern raised by transmission dependent utilities is that not having a longterm transmission right could adversely affect their ability to finance new generation 

projects, specifically those remote to load (because of uncertainty from year-to-year 

about the cost of delivering the power to load). If such utilities finance investments by 

borrowing against the firm’s overall assets and revenues (in contrast to project financing 

typically undertaken by merchant entities, in which the projected sales revenues are used 

to secure financing), then it appears that the unavailability of long-term FTRs may not 

have a direct impact on their ability to finance a new facility. Instead, the lack of longterm rights could have an impact on the overall credit risk profile of the utility, and thus 

their overall financial flexibility and ability to make the strategic decision to invest in 

new generation (instead of, for example, to purchase power through a contract). 

For other types of firms, the availability of long-term FTRs is apparently less 

important in the financing decision. For example, staff’s discussions suggest that, despite 

the fact that long-term hedging instruments are awarded in many RTOs in exchange for 

investments in transmission infrastructure, developers of merchant transmission may not 

consider long-term financial rights a reliable and sufficient source of revenue to obtain 

financing for new projects. FTR values are too difficult to forecast over a long period 

because of the challenges in accounting for changes to the generation resources and 

transmission system over time. In addition, new lines destroy a portion of the basis 

differentials that the FTRs reflect and are not therefore captured by FTR holders unless a 

contract party that benefits from the decline in basis pays in advance for them through a 

long-term contract. 

Merchant generators in the current environment typically are able to obtain 

financing only if they have long-term power purchase or tolling contracts with creditworthy counterparties, and may not have a strong interest in long-term FTRs. Because 

the long-term power purchase agreements that they typically enter into call for power 

delivery at (and pricing based on) the generator’s interconnection point, such generators 

typically do not take transmission risk but leave it to their counterparties. When they

considered accepting transmission risk as part of a contract, generators were more 

interested in obtaining short-term FTR options than in obtaining long-term FTR 

obligations. 

16
Another source of uncertainty for merchants is regulatory policy. From the 

merchant perspective, market rules have changed sufficiently frequently in the existing 

RTO markets that long-term financial rights, particularly those with terms of decades, 

would not be seen as guaranteed revenue sources (regardless of the difficulty of 

valuation) when undertaking financial analysis. Again, particularly for project financing,

the conclusion was that investors would be very conservative when factoring revenues 

from transmission rights into their lending decisions. 

Other Approaches to Long-Term Transmission Rights in RTO Markets 

There are ways to provide transmission customers in RTO markets with the long 

term stability of transmission service at a known price that do not require those customers 

to be exposed to congestion charges or hold financial transmission rights. For example, 

some transmission users in RTO markets have expressed interest in physical transmission 

scheduling rights akin to the Order 888 OATT rights.19 Although there are various 

proposals for how to implement such rights under RTOs, in essence, such transmission 

customers would pay an RTO access charge and then, to the extent that they remain 

within their reserved transmission usage, they would not be subject to the uncertainties of 

hourly congestion charges and the annual allocations of FTRs.20 However, in the 

presence of congestion, such customers could be subject to physical curtailment under 

rules similar to the rules outside RTO markets.21 Alternatively, there could be rules 

specifying ahead of time the total redispatch charges that such a customer would be 

willing to pay. Unlike FTRs, such physical scheduling rights would not pay revenues 

when transmission is not scheduled, nor have payment obligations (apart from the initial 

charge for obtaining the rights). 

Such scheduling rights could apply only to a subset of the market or to the entire 

market. Regarding the latter case, SPP has recently proposed a market design in which 

parties with OATT rights are given FTRs on a daily basis, exempting them from 

 

19 It is important to note that in RTO markets, all transmission customers have the 

right to physically schedule subject to congestion charges. The difference here is that the 

customer would have the right to physically schedule but not be subject to congestion 

charges, although it might be subject to other congestion management rules, as discussed 

below. 

20 Because congestion costs are difficult to forecast, there is always the possibility 

that there would be some degree of ex post redispatch charges even under this type of 

scheme. 

21 Also, when such a transmission customer was out of balance, then it would pay 

the RTO market’s congestion charges based on LMPs. 

17
congestion charges, and then settle imbalances using locational pricing. 

 

In this section, we discuss some of the implications of long-term physical 

scheduling rights with the general characteristics discussed above for the FTR market in 

the case that only a subset of the market participants is eligible for such rights. Details of 

the proposed SPP market design are provided in Appendix B. 

Scheduling rights based on “carve-out” 

A fundamental issue that the RTO faces if eligible parties elect to maintain (or 

revert to) an OATT-type physical scheduling rights in lieu of FTRs is how to allocate 

transmission capacity to those parties that nominate for FTRs. In this first approach, the 

RTO would reserve, or “carve-out”, some percentage of the transmission capacity that 

would be used for scheduling entities with the pre-RTO scheduling rights when it 

allocates FTRs. For example, if a party elected OATT-type rights for scheduling 100 

MW from a generator at location A to its load at location B, and this required 50 MW of 

power to flow on transmission line X in the direction of B, the RTO would reduce the 

available transmission capability assumed for line X in the appropriate direction when it 

considered how much transmission capacity might be available for LMP/FTR customers. 

There are impacts on the market and other participants in the RTO markets that 

must be kept in mind when considering the “carve out” approach. In general, if only a 

subset of the market is eligible, then there is potentially an equity issue, because those 

parties could get the benefit of less uncertainty over physical delivery due to the RTO 

market redispatch but not share in the costs of such redispatch. Moreover, because the 

transmission capacity needed for the customer’s service is removed from that available 

for FTRs, any counterflow service that might be enabled by using that capacity would not 

be considered feasible in the FTR model and thus fewer overall FTRs will be available to 

the market. This could result in less efficient use of the grid than possible and cost shifts 

to parties that would be exposed to LMP-based congestion charges. Parties with these 

OATT-type scheduling rights also may have less incentive to redispatch their generators 

through the RTO spot market because they are not exposed to congestion charges and 

thus may be less interested in buying from the RTO market. This could reduce the 

RTO’s ability to redispatch the system through prices and increase the possibility that it 

will rely on physical curtailments to manage congestion. While these problems may be 

manageable by the RTO for some amount of long term OATT-type physical scheduling 

rights, there may be a limit beyond which the integrity of the price-based congestion 

management regime is too compromised. 

18
Transmission customer is granted physical scheduling rights but financial 

rights are taken by seller of the historical transmission service 

In this second approach, the transmission capacity needed for the customer’s 

physical scheduling reservation is not excluded from the transmission capacity that is 

available for FTRs. As such, this method avoids the downsides of a carve-out described 

above. However, because the transmission customer is granted the right to schedule its 

transactions without exposure to congestion costs, some entity must take on the 

obligation to pay congestion costs and possibly hold FTRs. While the entity would bear 

the risk of paying any congestion not covered by the FTRs allocated, it would also 

receive any congestion revenues associated with the FTRs. An additional rate charged by 

the holder of the FTRs to the purely physical customer (in addition to the access charge) 

may be needed to compensate for the congestion risk undertaken. 

One possible candidate for the risk bearing entity might be the transmission owner 

on whose system the FTRs are awarded. If the service for which the long term 

scheduling rights are awarded was provided before the start of the RTO market, the 

transmission owner committed to the service and managed the congestion risk in the past 

and should be able to manage it now.22 If the service is new, the transmission owner may 

be in the best position of all the parties involved (customer, RTO, and transmission 

owner) to identify improvements in system operation or facility expansion to manage any 

congestion that could impact the service in question. On the other hand, transmission 

owners in the RTO market may not have the option that they had in the pre-RTO market 

of passing through redispatch costs into their rate base, hence may not find this approach 

equitable. 

• Are purely physical scheduling rights necessary as an alternative to 

financial rights to ensure stable transmission prices over the long-term? If 

so, which model of such rights is the most appropriate to the RTO market 

context? What rules for transmission scheduling and RTO market 

participation should be required for holders of such rights? 

 22 In the Midwest ISO, the Commission did require this type of arrangement for 

“slice of system” purchase contracts that were in place prior to the RTO market. This 

was because in such contracts, the utility selling the system power controls the generators 

used to provide the power. If the buyer of the system power held FTRs but did not 

control the generators at the source points, it could not easily manage congestion risk. 

19
APPENDIX A: Background on LMP and Transmission Rights 

The rules for allocation and settlement of financial transmission rights vary among 

RTOs and ISOs. In each case, they reflect the market’s historical starting point, market 

participants’ views on management of congestion risk and insurance for the FTRs, and 

market changes that have taken place since restructuring. How long-term FTRs might be 

introduced in the context of the existing market rules, and their resulting properties as 

financial instruments, will thus also vary from market to market. This appendix reviews 

the general features of ARR and FTR allocation procedures and FTR auction markets, 

and highlights some alternative approaches. Appendix B describes the market rules of 

each RTO and ISO. 

LMP and Congestion Pricing 

Locational Marginal Pricing (LMP) is a pricing method for energy (both dayahead and in real-time) that determines a price for energy at various locations (for 

example, “nodes” or zones) within the RTO market area. If there were no congestion or 

line losses, all prices would be the same. However, LMP yields a different market price 

at each location when transmission congestion or line losses cause the price of delivered 

power to be different at those locations. In this appendix, we will ignore the marginal 

cost of losses, which are generally small, and consider only marginal congestion pricing. 

The explicit congestion charge associated with any set of injections and 

withdrawals in such a market is the difference between the price at the point of injection 

and the price at the point of withdrawal multiplied by the quantity injected and 

withdrawn. Note that, for buyers and sellers in the RTO energy market, neither side 

pays “congestion” explicitly; rather, the cost of congestion is reflected in what the RTO 

collects when it pays the market sellers less than what it receives from the buyers. If 

there is no congestion, and all prices are the same, the RTO receives from buyers exactly 

what it pays to sellers. If there is congestion, then the RTO will collect more from buyers 

than it pays to sellers. This “surplus” is used in part to pay holders of financial 

transmission rights. 

The cost of congestion is positive if the price at the injection point is less than the 

price at the withdrawal point. For example, if the price at the generator’s location is 

$15/MWh and the price at the load’s location is $20/MWh, then the cost of congestion is 

$5/MWh. Conversely, the cost of congestion is negative if the price at the injection point 

is more than the price at the withdrawal point. For example, continuing with the same 

generator and load, if the price at the generator is $20/MWh and the price at the load is 

$15/MWh, then the congestion charge is a negative $5/MWh. 

1
FTR Definition and Specification 

An FTR is specified by means of a point of injection, a point of withdrawal, and a 

MW quantity. The points of injection and withdrawal are typically electrical busses 

designated as pricing locations for LMP. In general, 1 MW = 1 FTR. An FTR can be 

divided over multiple points of injection and withdrawal; these are sometimes called 

“zonal” or “hub” FTRs.23 

There are two basic types of FTR: the obligation right and the option right. An 

obligation right entails the right to receive congestion revenues when congestion is 

positive (i.e., the price at the withdrawal point exceeds the price at the injection point), 

but also the obligation to pay congestion revenues when congestion is negative. Thus, if 

a market participant holds a given quantity of obligation FTRs, and injects that quantity 

of power at the point of receipt and withdraws the same quantity at the point of 

withdrawal, the obligation FTRs provide compensation (positive or negative) that exactly 

offsets the cost of congestion (positive or negative) that the market participant incurs. In 

contrast, the option FTR entails the right to collect positive congestion revenues 

associated with the FTR’s point of injection and point of withdrawal, but not the 

obligation to pay negative congestion revenues. 

In determining how many FTRs can be offered to transmission customers, the 

RTO will model its system assuming that, for a given quantity of obligation FTRs, the 

same quantity of power is actually injected at the point of injection and withdrawn at the 

point of withdrawal. In this way, the RTO can assume that “counterflows” will be 

present that would make other injections and withdrawals, and hence FTRs, feasible. The 

option FTR does not assume that the modeled power flow can be used for counterflow; 

put another way, the holder of the option FTR has the option not to inject or withdraw 

power, and as a result, the option FTR effectively encumbers a greater amount of system 

capacity than does the obligation FTR. 

FTR Settlement 

Regardless of how they are obtained (which is discussed next), FTRs are settled in 

the RTO day-ahead market at the prices associated with their points of injection and 

withdrawal. That is, for each hour of the relevant day, the FTR holder would receive (or 

pay, if applicable) congestion revenues equal to the difference in the prices for that hour 

multiplied by the quantity of FTRs that it holds. 

 23 For example, if a utility has decided to spread its FTRs over its 5 network 

generator resources based on an analysis of the annual usage of each resource, then for 

each 1 MW of FTR sourced in the zone, 40 % will be assigned to generator A, 30 % to 

generator B, 20 % to generator C, and 5 % each to generators D and E. 

2
FTR Auctions 

In addition to direct allocation, discussed below, RTOs typically make available 

FTRs through monthly and annual auctions. An FTR auction is organized as a uniform, 

second price (locational) clearing price auction in which buyers and sellers can bid for or 

offer FTRs between any two locations or aggregations of locations in the RTO network. 

A bid in an FTR auction is defined as the dollar value willingness-to-pay for the injection 

of a MW quantity at a location and the withdrawal of that quantity at another location. 

For example, Party A is willing to pay up to $5/FTR for up to 100 FTRs from a location 

in PJM West to a location in PJM East. Party B is willing to pay $4.25/FTR for the same 

FTRs. An offer in an FTR auction is defined as the dollar value minimum sale price for 

an FTR, again specified as the injection of a MW quantity at a location and the 

withdrawal of that quantity at another location. For example, Party C is offering for sale 

100 FTRs at $4/MW from the same location in PJM West to the same location in PJM 

East. For any pair of injection and withdrawal points, the auction clears at a single price 

and the winning bids all pay the price bid by the second highest bid. In the example, the 

bidder willing to pay $5/FTR would win the FTRs and would pay $4.25/FTR. In an 

actual FTR auction, the physics of the power flows being modeled means that the 

clearing prices do not necessarily correspond exactly to particular offers and bids, but for 

any particular awarded right, they can never be higher than the prices in the winning bids 

or lower than the prices in the winning offers. 

In an FTR auction, the type of FTRs being bought and sold – obligation or option 

– will have an impact on the market clearing FTR prices. This is because the option right 

does not include the “counterflow” assumptions that the obligation right does, as 

discussed above. In essence, the option right reserves more of the total transmission 

transfer capability than does the obligation right, and because of its financial settlement 

properties, the former is a higher quality right than the latter. As a result, option rights 

trade at higher prices than obligation rights and the auction typically produces fewer 

option rights than obligation rights in many RTO regions. 

ARR Definition and Specification 

An auction revenue right (ARR) is the right to the revenues from the sale of an 

FTR between a specific injection point and a specific withdrawal point in the RTO’s FTR 

auction. Each ARR, like each FTR, is direction specific. Also like FTRs, ARRs are 

allocated to LSEs and others that pay the fixed costs of the transmission system. A 

market participant that wishes to purchase FTRs in the RTO’s auction can use its 

allocated ARR revenues to fund these purchases. Thus, an ARR can reduce to zero the 

net cost of purchasing an FTR. In some instances (such as in PJM), an ARR can be 

converted directly into an FTR with the same injection and withdrawal points. 

3
In sum, the procedure is as follows: 

• ARRs are defined and allocated to parties 

• Parties cash out their ARRs in an annual FTR auction 

• The FTR auction results in awards of FTRs 

• ARR proceeds are awarded on a monthly basis; FTRs are settled daily 

against day-ahead locational prices 

Simultaneous Feasibility Test 

When determining how many FTRs or ARRs it can allocate, the RTO must ensure 

that it will be “revenue adequate”; that is, it must ensure that it will collect enough 

congestion revenues to compensate the holders of the FTRs or ARRs. In general, this can 

be done by ensuring that the implied dispatch underlying the set of rights is physically 

feasible. This means that, in its modeling of the transmission network for the periods 

over which it is defining the rights, the RTO must establish that the injections and 

withdrawals being modeled for the rights do not violate system constraints. This is 

known as a “simultaneous feasibility test” (SFT). Performing this test guarantees that, as 

long as the network transfer capability is not reduced in a manner that violates the 

feasibility of the existing rights, the RTO will always collect at least enough congestion 

charges through locational pricing to pay the holders of FTRs. When the network does

change in a manner that violates the feasibility of the existing rights -- e.g., if a major 

transmission line is removed from service -- the RTO may not have enough congestion 

revenues to pay the existing rights. In that case, the RTOs have rules to determine how 

the available revenues are distributed to FTR holders, or how the shortfall is to be made 

up, as discussed below.

Allocation of Rights to Existing Transmission Capacity 

There are two general models for allocation of rights to existing transmission 

capacity, and within each model, several variations. 

Direct Allocation of FTRs. The first model uses an administrative process to 

directly allocate FTRs to LSEs on an annual basis. This was the approach first adopted 

by PJM (1999) and later by MISO (2005). The FTRs are not allocated on the basis of 

value or willingness to pay (i.e., congestion revenues they are expected to collect), but on 

the basis of an administrative determination of eligibility. LSEs with network rights are 

typically eligible to receive FTRs between network resources and network loads. Parties 

with point-to-point rights are eligible to receive FTRs corresponding to the points of 

injection and withdrawal in their rights. 

Direct Allocation of ARRs with FTR auction. The second model uses an 

administrative process first to directly allocate ARRs, but then allows parties to choose 

4
how to “spend” their ARRs in an FTR auction. A party receiving ARRs is not limited to 

purchasing FTRs that correspond to the party’s ARR points. Instead, it has a choice: it 

may use its ARRs to purchase FTRs that hedge its expected transactions or schedules, or 

it may use its ARRs to purchase FTRs that it considers valuable rights to hold. 

Reconfiguration 

The holder of a right from point A to point B may prefer to hold the right from 

point C to point D, or the holder may want to change the MW quantity of the right. 

RTOs allow market participants to reconfigure their FTRs by submitting appropriate bids 

and offers in the monthly auctions. The RTO will permit the reconfiguration as long as it 

does not affect the simultaneous feasibility of all other outstanding rights. 

Current Rules for Allocation of Rights to New Transmission Capacity 

When a market participant pays for an expansion of the transmission system, the 

RTO will allocate to the market participant the FTRs that are made possible by the 

capacity expansion. Although the specific rules for these allocations vary among RTOs, 

the FTRs that are awarded typically are of longer duration than those available from 

existing capacity. The market participant may be able to decline the award of any FTRs 

whose value is negative, and it may be able to turn back FTRs if their value becomes 

negative in the future. 

Rules for FTR Settlement When the RTO is Not Revenue Adequate 

In general, if the RTO accurately models the transmission network when it assigns 

FTRs and ARRs, and if the configuration of the network does not change for the duration 

of the rights, then the RTO will always collect sufficient congestion revenues to pay 

holders of the rights. When the network configuration does change in a way that makes 

the existing rights no longer simultaneously feasible, then the RTO may not collect 

sufficient congestion charges to pay the holders of the rights. Rules for addressing this 

revenue shortfall vary among RTOs. One approach is simply to allocate the available 

revenues to FTR holders on a prorated basis according to the MW quantity of the FTR 

holdings. A second approach is to provide each FTR holder with a payment equal to its 

full entitlement, and make up the resulting revenue shortfall by assessing an 

administrative “up-lift” charge to market participants or transmission owners. These 

rules obviously affect the hedging properties of the rights, because holders of the rights 

may be exposed to additional charges after the fact (ex post). 

Creditworthiness Requirements 

When FTRs are offered through auction, creditworthiness becomes an important 

requirement of the transmission rights market. In general, auction participants must 

5
establish credit limits with the RTO prior to buying and selling through the RTO 

auctions. 

Rules for ARRs/FTRs in Retail Choice States 

In regions where states have implemented retail choice programs, a retail customer 

typically is allowed to switch its retail energy provider on relatively short notice. If retail 

energy providers could obtain FTRs or ARRs only through infrequent allocations or 

auctions, they might find it difficult to compete with incumbent utilities to serve retail 

customers, and competition in retail markets could suffer as a result. Consequently, all 

RTOs that serve states with retail choice programs have established rules that allow 

ARRs or FTR to follow the movement of retail customers from one retail energy provider 

to another on a daily basis. These rules are designed to reduce financial risk for retail 

energy providers and thereby increase competition in the retail markets. 

6
APPENDIX B: Review of Current and Proposed RTO/ISO Rules for 

Financial Transmission Rights 

This appendix provides a summary of the current rules for allocating, auctioning 

and trading transmission rights in the current RTO and ISO markets. In most cases, these 

markets use a common framework of a day-ahead energy market with locational marginal 

pricing (LMP). The principal exception is the California ISO, which currently uses zonal 

pricing and zone-to-zone transmission rights. The re-designed California ISO market 

will implement LMP. 

As readers will observe, each market uses slightly different terms for financial 

transmission rights. The fundamental properties of the financial rights remain the same, 

but differences in rules can affect the value of the rights. 

PJM RTO

PJM began its cost-based LMP market with Fixed Transmission Rights (FTRs) on 

April 1, 1998; the energy market became bid-based on April 1, 1999. Until 2003, 

obligation FTRs with an annual term were allocated directly to network customers; any 

remaining FTRs were made available to point-to-point customers. Customers were 

allowed to refuse any FTRs allocated to them. A monthly FTR auction was then 

established for the sale of FTRs on any residual transmission capacity and for 

reconfiguration and trade of allocated FTRs. On June 1, 2003, PJM made the transition 

to an annual allocation of Auction Revenue Rights (ARRs) with an annual FTR auction 

of all transmission capacity. Also in 2003, PJM introduced option FTRs as an alternative 

to obligation FTRs. 

Annual ARR Allocation 

Auction Revenue Rights are allocated to customers with network resource 

integration service up to their total annual load and to customers with firm point-to-point 

service up to the quantity specified in the transmission reservation and for the period of 

the reservation. ARRs are defined as a point of injection, a point of withdrawal and a 

quantity, which can be specified to the nearest 0.1 MW. ARRs are nominated by eligible 

transmission customers and their award is subject to a simultaneous feasibility test.24 

The ARR allocation is implemented in two stages. In Stage 1, load serving 

entities (LSEs) are eligible to nominate ARRs from generation resources that historically 

served load in each transmission zone. In Stage 2, market participants are not restricted 

 24As with FTRs, allocation of ARRs may be prorated. For example, in PJM’s 

2003 ARR allocation process, 28,933 MW of ARRs were allocated, which represents 73 

percent of the 39,888 MW requested. 

1
to historical resources. There are four rounds in which 25 percent of the remaining 

transmission capacity is allocated in each round. Participants can assign priorities, from 

1 to 4, for the ARRs nominated in these rounds. They can also view the results of each 

round before proceeding to the next round. 

FTR Auctions 

PJM conducts both annual and monthly FTR auctions. In the annual auction, 

FTRs with terms of one year are traded. These can be obligations or options and can be 

specified for the daily off-peak hours, the daily peak hours or all 24 hours. The annual 

auction has four rounds in each of which 25 percent of the feasible transmission capacity 

is made available. A participant that purchases an FTR in one round may offer it for sale 

in subsequent rounds. 

Holders of ARRs have the option to convert them directly to FTRs by “selfscheduling” them in the first round of the annual FTR auction. Holders of ARRs are not

required to bid for FTRs on the transmission paths associated with the ARR; they may 

bid on alternative paths or alternative products. For example, they may use an obligation 

ARR to purchase an option FTR. 

Annual auction revenues are distributed to holders of ARRs. ARR revenues may 

be prorated. The annual auction settlements and the corresponding ARR settlements take 

place on a monthly basis. 

Monthly auctions are conducted for any residual transmission capability not sold 

through the annual auctions for FTRs offered for sale. The monthly auctions sell 

monthly FTRs. 

Market participants must establish an auction credit limit prior to participating in 

an auction and their bids in the auctions cannot exceed this limit. ARR revenues are 

taken into account in determining credit limits. 

Incremental ARRs for Network Upgrades and Transmission Expansion 

Incremental, multi-year ARRs are assigned for transmission expansions associated 

with generator interconnections and merchant transmission projects. The term of the 

ARRs is thirty years or the life of the facility or upgrade, whichever is less. The ARRs 

are awarded in three rounds in each of which the party requesting the rights can nominate 

a different point-to-point path if it chooses. The ARRs nominated by the third round 

become final. 

Market participants awarded such multi-year ARRs have a one-time option to 

switch to an annual allocation of their eligible ARRs. They may also turn back any 

2
multi-year rights that they no longer desire to hold, as long as this does not affect the 

feasibility of the ARRs of other parties. 

New York ISO

New York ISO began market operations in November 1999 with an LMP energy 

market and point-to-point obligation FTRs that are called Transmission Congestion 

Contracts (TCCs). New York ISO was the first organized market to introduce an annual 

auction for financial rights. 

Before the first TCC auction took place in September 1999, several kinds of 

existing rights had to be translated into the new system. The holders of existing 

transmission rights, including Transmission Wheeling Agreements and Transmission 

Facilities Agreements, were given the opportunity either to retain grandfathered rights or 

to convert them into Grandfathered TCCs which remain active until the time the original 

right would have expired. Transmission owners that had obligations to serve load were 

allocated Existing Transmission Capacity for Native Load (ETCNL) rights. Before each 

bi-annual Initial Auction, a portion of these ETCNL rights can be converted to ETCNL 

TCCs (6-month TCCs). ETCNL rights that are not converted are sold in the Initial 

Auctions and function like Auction Revenue Rights in that they entitle the owner to the 

revenues resulting from the sale of the corresponding TCCs in the New York ISO-run 

auctions. Any remaining transmission capacity was allocated to transmission owners as 

Original Residual Capacity. 

Bi-Annual TCC Allocation 

Prior to each Initial (bi-annual) Auction, New York ISO allocates Residual 

Capacity Reservation Rights (RCRR) to transmission owners taking into consideration 

existing grandfathered rights, ETCNL rights, and valid TCCs. Transmission owners can 

then convert a portion of their RCRRs to 6-month TCCs and sell the remaining rights into 

the Initial Auction. 

TCC Auctions 

The New York ISO holds a number of auctions each year to facilitate the liquidity 

of the TCC market. At Initial Auctions, held twice a year, the NYISO releases TCCs, 

including non-converted ETCNL rights, Original Residual Capacity and RCRRs, plus 

expired grandfathered rights, for sale in two stages of multi-round auctions. During the 

first stage, a certain percentage of all the TCCs for sale are released in each of the four 

rounds. The second stage allows TCC holders to resell rights they purchased through the 

first stage. Currently the effective period of the auctioned TCCs is determined by the 

ISO, and is either 6 months or one-year. At the discretion of the New York ISO, multiyear TCCs are offered, with the longest being five years. The price is determined by the 

3
lowest winning bid for a particular TCC point-to-point pair in a specific round. The New 

York ISO also holds monthly Reconfiguration Auctions in which TCC holders can offer 

to sell their TCCs for the subsequent month. 

TCCs for Network Upgrades 

Parties who invest in transmission expansion are entitled to 20-year Expansion 

TCCs, commencing when the new transmission facility begins operation. The Expansion 

TCCs consist of only the new TCCs made feasible as a result of the transmission 

expansion. 

ISO New England

ISO New England began market operations on May 1, 1999. The initial phase of 

the energy market relied on a congestion management system using a redispatch 

algorithm that resulted in a two-part pricing system under which “in-merit” generators 

were paid a single New England market clearing price and “out-of-merit” generators – 

those dispatched to a higher output level due to congestion – were paid their offer price, 

after market power mitigation had been taken into consideration. Today, ISO New 

England implements a market design with LMP, ARRs and an FTR auction. The ARR 

methodology is unique to New England. 

Annual ARR Allocation 

ARRs are allocated monthly first to the entities that pay for transmission upgrades 

that increase transfer capability on the NEPOOL transmission system, making possible 

the award of additional FTRs in the FTR auction. The remaining auction revenues are 

allocated to each congestion-paying LSE in proportion to its load ratio share.25 Any 

ARRs assigned that have negative values in the FTR auctions are eliminated. The 

remaining ARRs are reduced proportionally26 until a solution is reached in which all the 

ARRs are simultaneously feasible given the other rights, including the excepted 

transactions, NEMA rights, and Quality Upgrade Awards, which are discussed below. In 

general, an entity receiving ARR revenues does not know its ARR position before the 

FTR auctions are held, as the dollar value of its ARR allocation is contingent on the MW 

 

25For example, assume a load (Load Z) has a demand of 100 MW, which is 5 

percent of the total network load of 2000 MW. If there were 400 MW and 300 MW of 

generation at nodes A and B, respectively, Load Z would be assigned ARRs from each 

generation node to its load node (z) proportional to the amount of generation. 

26 Reductions are based on which constraint whose relief would require the largest 

proportionate reduction in all the ARRs. 

4
amounts resulting from the four stage ARR allocation process and the auction clearing 

prices associated with the ARR paths. 

ARRs are made available on a long-term basis to certain entities, such as holders 

of Excepted Transactions (grandfathered contracts) and “NEMA” (Northeast 

Massachusetts) contracts. Excepted Transactions are given the option to receive ARRs 

from the generator to the specified load location. The Excepted Transactions consist 

primarily of transmission agreements for certain point-to-point wheeling transactions 

across or out of the network and are assigned either to entities serving load to which 

energy is delivered or to entities making an external sale. To date, about 0.5 percent of 

the ARR revenues have gone to entities with rights associated with Excepted 

Transactions. 

ARRs for Network Upgrades 

Auction revenues are made available on a long-term basis to entities that construct 

transmission upgrades that increase the transfer capability of the NEPOOL transmission 

system. These are referred to as “Qualified Upgrade Awards” (QUAs). Qualified 

Upgrades, which normally are new expansions to the transmission system, are awarded 

rights to receive FTR auction revenues. The FTR bids and revenues are first determined 

with the upgrade and then without each upgrade. The difference in revenues between the 

two (which can be interpreted as the value the upgrade brings to the system) is awarded 

to those entities which provided the upgrade. Qualified Upgrade payments are made as 

long as the entity is paying for the upgrade, or for the life of the asset, whichever is 

shorter. To date, approximately 1.5 percent of the total FTR revenues have been assigned 

to Qualified Upgrades. 

FTR Auctions 

New England holds FTR auctions for peak and off-peak periods. Fifty percent of 

the total transmission capacity is made available in an annual month auction, and the 

residual transmission is sold in monthly auctions. The ISO’s FTR auction maximizes the 

total value to the bidders, subject to the FTRs being simultaneously feasible, given 

previously allocated FTRs and transmission constraints. The recipient of each FTR pays 

a clearing price which is the marginal opportunity cost of the FTR being awarded. 

Midwest ISO

The Midwest ISO (MISO) Day 2 market started on April 1, 2005. FTR allocation 

was a contentious issue in the development of the market design, in part because the 

existing pre-OATT and OATT transmission rights in the MISO footprint did not appear 

to convert easily into FTRs that market participants believed would be sufficient to hedge 

their long-term contracts or investments. A larger percentage of the network than in 

5
other RTOs was also set aside for grandfathered rights. 

Initial FTR Allocation 

FTRs are allocated directly to existing users of the transmission network. In the 

stakeholder process on market design, a number of different approaches were assessed 

including an ISO proposal to assign a certain percentage of the FTRs based on historical 

uses of network resources, and a stakeholder proposal that all FTRs be nominated 

voluntarily by market participants between their eligible points of injection and 

withdrawal. The market rules that were finally approved by the Commission set out a 

“compromise proposal” for the annual allocation, developed in consultation with market 

participants and with substantial input from the Organization of Midwest States (OMS). 

The compromise allows parties to voluntarily nominate FTRs between their eligible 

points of delivery and receipt. However, all parties remain eligible to receive a full 

allocation of nominated FTRs from resources they use to serve base load (with criteria to

determine base load). To the extent that this full allocation is not achieved in the flexible 

phase of the allocation, counterflow FTRs are assigned (to parties providing existing 

transmission service) to ensure that the base load FTRs are “restored.” This restoration 

process is described further below. 

FTRs can be nominated from Network Resources based on the Forecast Peak Load 

served under Network Integration Transmission Service, and from the points of delivery 

and receipt in Point-to-Point Transmission Service of annual duration or longer. The 

maximum quantity eligible for nomination is the sum of these existing entitlements for 

network service and the total quantity in each point-to-point service. 

The FTR allocation process takes place over four successive and cumulative tiers. 

In each tier, a Market Participant is allowed to nominate up to a percentage of its 

maximum nomination eligibility less the FTRs awarded in the prior tier. The cumulative 

Tier Factors are: Tier I, 35 percent; Tier II, 50 percent; Tier III, 75 percent; and Tier IV, 

100 percent. 

For a period of five years following the start of the Day 2 market, any eligible 

FTRs that were prorated in the first two tiers are eligible to be restored. Eligibility 

requires that, if the nominated FTR is from a network resource, that network resource has 

an average historical capacity factor of at least 70 percent, and if the nominated FTR is to 

convert existing point-to-point service, that service has a historical scheduling factor of at 

least 70 percent. To restore the prorated FTRs, the Midwest ISO will define Counter 

Flow FTRs sufficient to make the eligible nominated FTRs simultaneously feasible. 

Counter Flow FTRs are defined as eligible base-load FTRs that were either not 

nominated by a Market Participant or not awarded in the first two tiers, but if assigned, 

would provide counterflow in the FTR model for restoration of other nominated FTRs. 

The Midwest ISO will choose the minimal set of Counter Flow FTRs needed for 

6
restoration. The Counter Flow FTRs are allocated directly to the Market Participant that 

was eligible to nominate them. They are settled like other FTRs, except in the event of a 

unit outage, in which case they are not settled. (That is, if the unit is not physically 

available to provide counter flow, it will not be held financially responsible.) Any 

resulting shortfall in congestion revenues will reduce payments to FTR holders on a prorata basis. 

MISO market participants were concerned that insufficiency of FTRs would have 

a particular impact on parties that are within persistent load pockets and hold existing 

transmission contracts to support imports from generators outside the load pocket. In 

MISO, such load pockets are called “Narrow Constrained Areas” (NCAs) and are defined 

as locations in which imports were affected by a transmission constraint for 500 hours or 

more in the prior year. The Commission determined that parties in NCAs, to the extent 

that they hold existing firm transmission contracts for imports, should be allocated 

sufficient FTRs to cover those contracts for a five-year period. In other words, they 

would be held harmless from congestion charges. This rule would extend to any NCA 

defined within the first six months of MISO market operations. 

FTRs for Network Upgrades 

Under its current tariff, MISO directly allocates incremental FTRs for network 

upgrades. Entities can select FTRs from any set of injection and withdrawal points in the 

network as long as the quantity reflects the incremental capacity that has been made 

available and the FTRs are jointly feasible with the outstanding FTRs. The maximum 

term of such awards is one year. In each subsequent allocation, the FTRs are reevaluated based on any changes in the incremental transmission capacity created by the 

upgrade. When there are monthly differences in the incremental capacity, MISO may 

issue some incremental FTRs for only the months in which the capacity is available. 

When multiple parties contribute to a transmission upgrade, FTRs are awarded in 

proportion to their financial share of the upgrade costs. The parties are encouraged to 

agree beforehand on their relative contributions. 

Planned Changes in FTR Markets 

There will be a number of major changes in the Midwest ISO transmission 

markets over the coming years. First, after five years, the provisions for non-voluntary 

assignment of counterflow FTRs are due to expire. Second, Midwest ISO plans to begin 

development of ARRs after the start of the Day 2 markets. Third, the Commission has 

required Midwest ISO to begin planning for allocation of long-term rights. 

7
California ISO

The CAISO has been in operation since April 1998. FTRs were first made 

available to market participants in an auction in 1999 to take effect on Jan 1, 2000. All 

FTRs have been options, not obligations. In defining FTRs, the CAISO has made 

available 100 percent of Available Transmission Capacity at a 99 percentile availability 

level in each direction of an interface, net of grandfathered existing contracts. As 

grandfathered contracts expire, the quantity of FTRs made available to the market is 

likely to increase. Until recently, no FTRs were available on Path 15, one of the major 

constraints within the CAISO. 

FTR Auctions 

The CAISO has held annual auctions for FTRs since 1999, with FTR term lengths 

of one year and in some cases 13 or 14 months. All auctions have used a multiple round 

format with FTRs defined on inter-zonal interfaces and on interties with external areas. 

There have been roughly 10,000 MW of FTRs sold annually with annual auction 

revenues approaching $100 million in recent years. Auction revenues are credited back 

to transmission owners who use them to offset transmission access charges. 

Planned Changes in FTR Markets 

The CAISO is currently redesigning its markets to incorporate a nodal LMP 

approach where FTRs will be closer to the point-to-point design used by eastern RTOs. 

The LMP market is currently expected to start in 2007. In the new market, FTR 

allocations will be for 12 months of monthly FTR quantities, with both peak-hour and 

off-peak-hour varieties and potentially different quantities for each month to enable 

parties to hedge time-of-use and seasonal variation in expected congestion costs. For the 

purpose of the annual release, the CAISO would limit total quantities to 75 percent of 

available transmission capacity. In addition, there would be monthly "true-up" allocation 

or auction processes, conducted before the start of each month, in which the remaining 

transmission capacity could be released to parties based on their revised estimates of their 

needs and accounting for planned transmission outages. Long-term FTRs are likely to be 

considered after the start of the new market. 

Proposed SeTrans

Prior to withdrawing their proposal to form the SeTrans RTO, the SeTrans 

participants had developed a comprehensive proposal for long-term financial rights. Staff 

reviewed this proposal to identify design concepts that may be of use to existing ISOs 

and RTOs. 

8
Multi-Year FTR Allocation 

SeTrans proposed to conduct a one-time, initial allocation of Long Term FTRs at 

the start of its Day Two market. The purpose of this initial allocation was to identify who 

is currently obligated to pay for the existing transmission system, and to ensure that these 

parties will continue to receive the economic value of the transmission grid. In this initial 

allocation certain parties would be allocated “R-FTRs,” or reserved FTRs, that could then 

be nominated in subsequent years. These R-FTRs would have an unlimited term, 

meaning they would never expire. Parties eligible to receive R-FTRs were: network load 

(which would be required to designate the network resources they are relying on), entities 

that have existing long term point-to-point transmission service, and any remaining 

grandfathered service customers that had not converted to point-to-point service. 

The one-time Long Term Allocation would have consisted of 10 rounds that 

represent 10 years of load growth on the existing transmission system. The first round 

would attempt to replicate current system usage patterns of the three entities identified 

above, and allocate R-FTRs up to each entity’s current peak load or contracted generation 

(to account for counter-flow), while remaining simultaneously feasible. In subsequent 

rounds, each entity’s peak load would be increased by the forecasted amount, and an 

attempt would be made to cover the peak load of all entities with R-FTRs. FTRs would 

be prorated to ensure simultaneous feasibility. FTRs from previous rounds or FTRs from 

grandfathered rights would not be subject to prorating. 

Annual FTR Allocations and Auctions 

The proposal would have required the following annual process to convert RFTRs into FTRs for each year. First, the owners of R-FTRs would nominate which of 

those rights (allocated to them through the one-time auction) they wished to hold as FTRs 

for that year. Next, the FTRs not nominated would be awarded to any new long-term 

firm transmission customers. Finally, FTRs not nominated by their owners or allocated 

to new transmission customers would be released into yearly or monthly auctions, where 

anyone could bid to buy the rights. Original R-FTR owners would be able to specify a 

positive strike price, below which they would not sell their right; they would also be able 

to specify a negative price they are willing to pay in order to rid themselves of an 

obligation right. For any rights sold, the R-FTR owner would receive the auction 

clearing price. 

FTRs for Network Upgrades 

Expansion of the transmission system results in an increase in the number of 

transmission rights available. In SeTrans, these Incremental FTRs, or I-FTRs, would 

9
have been allocated to the investors in the expansion only if the expansion made the IFTRs possible and feasible. The proposed transmission expansion would be monitored 

for potential degradation of the quantity of existing FTRs, which either would not be 

allowed or would require compensation payments. Under this proposal, a transmission 

expansion that resulted in economic degradation, or a decrease in the value of an FTR, 

would not necessarily be prohibited. 

10