UNITED STATES OF AMERICA 114 FERC ¶ 61,097 

FEDERAL ENERGY REGULATORY COMMISSION 

18 CFR Part 40 

(Docket Nos. RM06-8-000 and AD05-7-000) 

Long-Term Firm Transmission Rights in Organized Electricity Markets 

Long-Term Transmission Rights in Markets Operated by Regional Transmission 

Organizations and Independent System Operators 

February 2, 2006 

AGENCY: Federal Energy Regulatory Commission. 

ACTION: Notice of Proposed Rulemaking 

SUMMARY: The Federal Energy Regulatory Commission is proposing to amend its 

regulations to require transmission organizations that are public utilities with organized 

electricity markets to make available long-term firm transmission rights that satisfy 

certain guidelines established in this proceeding. The Commission is taking this action 

pursuant to section 1233(b) of the Energy Policy Act of 2005, Pub. L. No. 109-58, 

§ 1233(b), 119 Stat. 594, 960 (2005). 

DATES: Comments are due March 13, 2006. Reply comments are due March 27, 2006. 
Docket Nos. RM06-8-000 and AD05-7-000 

2

FOR FURTHER INFORMATION CONTACT: 

Udi E. Helman (Technical Information) 

Office of Energy Markets and Reliability 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, DC 20426 

(202) 502-8080 

Roland Wentworth (Technical Information) 

Office of Energy Markets and Reliability 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, DC 20426 

(202) 502-8262 

Wilbur C. Earley (Technical Information) 

Office of Energy Markets and Reliability 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, DC 20426 

(202) 502-8087 

Harry Singh (Technical Information) 

Office of Market Oversight and Investigations 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, DC 20426 

(202) 502-6341 

Jeffery S. Dennis (Legal Information) 

Office of the General Counsel 

Federal Energy Regulatory Commission 

888 First Street, N.E. 

Washington, DC 20426 

(202) 502-6027 

SUPPLEMENTARY INFORMATION: 
UNITED STATES OF AMERICA 

FEDERAL ENERGY REGULATORY COMMISSION 

Before Commissioners: Joseph T. Kelliher, Chairman; 

 Nora Mead Brownell, and Suedeen G. Kelly. 

Long-Term Firm Transmission Rights in Organized 

Electricity Markets 

Long-Term Transmission Rights in Markets Operated 

by Regional Transmission Organizations and 

Independent System Operators 

Docket No. 

Docket No. 

RM06-8-000 

AD05-7-000 

NOTICE OF PROPOSED RULEMAKING 

February 2, 2006 

I. Introduction

1. On August 8, 2005, the Energy Policy Act of 2005 (EPAct 2005)1

 became law. 

Pursuant to the requirement in section 1233 of EPAct 2005,2

 which added a new section 

217 to the Federal Power Act (FPA), the Commission is proposing to amend its 

regulations to require each transmission organization that is a public utility with one or 

more organized electricity markets to make available long-term firm transmission rights 

that satisfy guidelines established by the Commission in this rulemaking. The 

Commission proposes to require each such transmission organization to file, no later than 

[INSERT DATE 180 DAYS AFTER PUBLICATION OF FINAL RULE IN THE 

FEDERAL REGISTER], either: (1) tariff sheets and rate schedules that make available 

 1

 Pub. L. No. 109-58, 119 Stat. 594 (2005). 

2

 Pub. L. No. 109-58, § 1233(b), 119 Stat. 594, 960. 
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long-term firm transmission rights that are consistent with the guidelines set forth in 

the Final Rule; or (2) an explanation of how its current tariff and rate schedules already 

provide long-term firm transmission rights that are consistent with the guidelines set forth 

in the Final Rule. Transmission organizations that are approved by the Commission after 

[INSERT DATE 180 DAYS AFTER PUBLICATION OF FINAL RULE IN THE 

FEDERAL REGISTER] must meet the requirements of the proposed rule before 

commencing operation. 

2. New section 217(b)(4) of the FPA provides: 

The Commission shall exercise the authority of the Commission under this Act in 

a manner that facilitates the planning and expansion of transmission facilities to 

meet the reasonable needs of load-serving entities to satisfy the service obligations 

of the load-serving entities, and enables load-serving entities to secure firm 

transmission rights (or equivalent tradable or financial rights) on a long-term basis 

for long-term power supply arrangements made, or planned, to meet such needs.3

Section 1233(b) of EPAct 2005 requires: 

Within 1 year after the date of enactment of this section and after notice and an 

opportunity for comment, the Commission shall by rule or order, implement 

section 217(b)(4) of the Federal Power Act in Transmission Organizations, as 

defined by that Act with organized electricity markets.4

3. In this Notice of Proposed Rulemaking (NOPR), we propose guidelines for the 

design and administration of long-term firm transmission rights that transmission 

3

 Pub. L. No. 109-58, § 1233, 119 Stat. 594, 958. 

4 Id. at 960.
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organizations with organized electricity markets5

 would make available to all 

transmission customers. As described in more detail below, the Commission will allow 

regional flexibility in setting the terms of the rights, but long-term firm transmission 

rights must be made available with terms (and/or rights to renewal) that are sufficient to 

meet the needs of load-serving entities to hedge long-term power supply arrangements 

made or planned to satisfy a service obligation. While we propose that long-term firm 

transmission rights be made available to all transmission customers, in the event that a 

transmission organization cannot accommodate all requests for long-term firm 

transmission rights over existing transmission capacity, we propose to require that a 

preference be given to load-serving entities with long-term power supply arrangements 

used to meet service obligations. The other properties we believe long-term firm 

transmission rights must have are discussed in the proposed guidelines below. These 

guidelines will give transmission organizations, in consultation with market participants, 

the flexibility to propose alternative designs that reflect regional preferences and 

accommodate the regional market design, while also ensuring that the objectives of 

Congress expressed in new section 217(b)(4) of the FPA are met. 

4. In proposing this rule, the Commission seeks to provide increased certainty 

regarding the congestion cost risks of long-term transmission service in organized 

electricity markets that will help load-serving entities and other market participants make 

5 See “Definitions” below. 
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new investments and other long-term power supply arrangements. We understand 

that specifying and allocating long-term firm transmission rights supported by existing 

transfer capability will raise difficult issues that must be addressed in this rulemaking and 

in its implementation over time. We note, however, that long-term rights are available to 

market participants in a direct manner, namely by supporting an expansion or upgrade of 

grid transfer capability. As described in more detail below, the Commission’s policy is 

that market participants that request and support an expansion or upgrade in accordance 

with their transmission organization’s prevailing rules for cost responsibility and 

allocation must be awarded a long-term firm transmission right for the incremental 

transfer capability created by the expansion or upgrade. Such a long-term transmission 

right must be for a term equal to the life of the new facilities, or for a lesser term if 

requested by the funding entity. The transmission organization tariffs must clearly and 

specifically provide for this arrangement, if they do not already. 

II. Definitions

5. The Commission proposes several definitions in this NOPR. We set forth those 

proposed definitions in this section, since these defined terms are used extensively in the 

background discussion and proposed guidelines that follow. The Commission seeks 

comment on whether these definitions are appropriate. 
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A. Transmission Organization

6. The Commission proposes a definition for “transmission organization” that is 

similar to the definition provided in EPAct 2005.6

 Specifically, we propose to include 

the word “independent” in the last clause of the EPAct 2005 definition, such that 

transmission organization would mean “a Regional Transmission Organization, 

Independent System Operator, independent transmission provider, or other independent

transmission organization finally approved by the Commission for the operation of 

transmission facilities.”7

 We make this clarification to the definition in EPAct 2005 

because we interpret section 1233(b) of the legislation to require that long-term firm 

transmission rights be made available in the currently existing independent entities 

approved to operate transmission facilities that have organized electricity markets (as 

defined below), and any such independent entities that are created in the future.8

 We 

seek comments on whether this definition appropriately captures the intent of section 

1233(b) of EPAct 2005. 

 6

 Pub. L. No. 109-58, § 1233, 119 Stat. 594, 985. 

7 See id. at 942, 985. 

8

 The transmission organizations that currently have an organized electricity 

market are ISO New England, Inc. (ISO-NE), New York Independent System Operator, 

Inc. (New York ISO), PJM Interconnection, Inc. (PJM), California Independent System 

Operator, Inc. (CAISO), and Midwest Independent Transmission System Operator, Inc. 

(Midwest ISO). Southwest Power Pool is currently developing its market. 
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B. Load-Serving Entity and Service Obligation

7. The Commission proposes to define the terms “load-serving entity” and “service 

obligation,” for purposes of the proposed rule, exactly as they are defined in section 217 

of the FPA. Specifically, we propose to define load-serving entity to mean “a distribution 

utility or electric utility that has a service obligation.”9

 We propose to define service 

obligation to mean “a requirement applicable to, or the exercise of authority granted to, 

an electric utility under Federal, State or local law or under long-term contracts to 

provide electric service to end-users or to a distribution utility.”10 We seek comment on 

whether it is necessary to expand or clarify these definitions in the Final Rule. 

C. Organized Electricity Market

8. EPAct 2005 and section 217 of the FPA do not define “organized electricity 

market.” The Commission proposes to define organized electricity market as “an 

auction-based market where a single entity receives offers to sell and bids to buy electric 

energy and/or ancillary services from multiple sellers and buyers and determines which 

sales and purchases are completed and at what prices, based on formal rules contained in 

Commission-approved tariffs, and where the prices are used by a transmission 

organization for establishing transmission usage charges.” We intend for the Final Rule 

 9 See id. at 957. In section 1291 of EPAct 2005, “electric utility” is defined as “a 

person or Federal or State agency (including an entity described in section 201(f) [of the 

FPA]) that sells electric energy.” Id. at 984. 

10 See id. at 958. 
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we develop in this proceeding to apply to any transmission organization with a dayahead and/or real-time (or “spot”) bid-based energy market that is the transmission 

provider in its region.11 These markets could either be administered by the transmission 

organization itself or by another entity. The definition we propose here is intended to 

ensure that the Final Rule covers all such transmission organizations, either existing or 

developed in the future. We seek comment on whether the scope of this definition is 

appropriate or whether it should be revised. 

D. Long-Term Power Supply Arrangement

9. Section 217(b)(4) of the FPA requires the Commission to exercise its authority to 

enable load-serving entities to obtain firm transmission rights on a long-term basis “for 

long-term power supply arrangements made . . . or planned” to meet service 

obligations.12 While “long-term power supply arrangements” is not defined in the 

legislation, section 217(b)(1)(A) of the FPA suggests that a load-serving entity has a 

long-term power supply arrangement if it “owns generation facilities, markets the output 

of Federal generation facilities, or holds rights under one or more wholesale contracts to 

purchase electric energy, for the purpose of meeting a service obligation.” For purposes 

of this proposed rule, we propose to use similar language to define “long-term power 

 11 As noted above, the transmission organizations that currently have an organized 

electricity market are ISO-NE, New York ISO, PJM, CAISO, and Midwest ISO. 

Southwest Power Pool is currently developing its market. 

12 Pub. L. No. 109-58, § 1233, 119 Stat. 594, 958 (emphasis added). 
Docket Nos. RM06-8-000 and AD05-7-000 - 8 -

supply arrangements.” Specifically, we propose to define “long-term power supply 

arrangements” to mean “the ownership of generation facilities, rights to market the output 

of Federal generation facilities with a term of longer than one year, or rights under one or 

more wholesale contracts to purchase electric energy with a term of longer than one year, 

for the purpose of meeting a service obligation.”13

III. Background

A. The Development of ISOs and RTOs

10. In Order No. 888, the Commission found that undue discrimination and 

anticompetitive practices existed in the provision of electric transmission service in 

interstate commerce, and determined that non-discriminatory open access transmission 

service was one of the most critical components of a successful transition to competitive 

wholesale electricity markets.14 Accordingly, the Commission required all public 

utilities that own, control or operate facilities used for transmitting electric energy in 

 13 While we consider long-term as “more than one year” in the context of defining 

a long-term power supply arrangement, later in this NOPR we note that we consider 

“long-term” in the context of the appropriate terms for long-term firm transmission rights 

to be terms and/or renewal rights that cover the multiple years necessary to support a 

long-term power supply arrangement. See infra at P 55. 

14 Promoting Wholesale Competition Through Open Access Non-discriminatory 

Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities 

and Transmitting Utilities, Order No. 888, 61 FR 21540 (May 10, 1996), FERC Stats. & 

Regs. ¶ 31,036 at 31,682 (1996), order on reh’g, Order No. 888-A, 62 FR 12274 (March 

14, 1997), FERC Stats & Regs. ¶ 31,048 (1997), order on reh’g, Order No. 888-B, 81 

FERC ¶ 61,248 (1997), order on reh’g, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff’d 

in relevant part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 

667 (D.C. Cir. 2000), aff’d sub nom. New York v. FERC, 535 U.S. 1 (2002). 
Docket Nos. RM06-8-000 and AD05-7-000 - 9 -

 

interstate commerce to file open access transmission tariffs (OATTs) containing 

certain non-price terms and conditions and to “functionally unbundle” wholesale power 

services from transmission services.15

11. In addition, the Commission found in Order No. 888 that Independent System 

Operators (ISOs) had the potential to aid in remedying undue discrimination and 

accomplishing comparable access.16 To guide the voluntary development of ISOs, Order 

No. 888 set forth 11 principles for assessing ISO proposals submitted to the 

Commission.17 Following Order No. 888, several voluntary ISOs were established and 

approved by the Commission. 

12. In light of the creation of these ISOs and other changes in the electric industry, the 

Commission issued Order No. 2000.18 In that order, the Commission concluded that 

traditional management of the transmission grid by vertically integrated electric utilities 

was inadequate to support the efficient and reliable operation of transmission facilities 

15 Under functional unbundling, the public utility is required to: (1) take wholesale 

transmission services under the same tariff of general applicability as it offers its 

customers; (2) state separate rates for wholesale generation, transmission and ancillary 

services; and (3) rely on the same electronic information network that its transmission 

customers rely on to obtain information about the utility’s transmission system. Id. at 

31,654. 

16 Order No. 888 at 31,655; Order No. 888-A at 30,184. 

17 Order No. 888 at 31,730. 

18 Regional Transmission Organizations, Order No. 2000, FERC Stats. & Regs. 

¶ 31,089 (1999), order on reh’g, Order No. 2000-A, FERC Stats. & Regs. ¶ 31,092 

(2000), aff’d sub nom. Public Utility District No. 1 of Snohomish County, Washington v. 

FERC, 272 F.3d 607 (D.C. Cir. 2001). 
Docket Nos. RM06-8-000 and AD05-7-000 - 10 -

 

that is necessary for continued development of competitive electricity markets.19 

The Commission also found that even after functional unbundling of electric utilities 

under Order No. 888, opportunities for undue discrimination continued to exist.20 As a 

result, the Commission adopted rules intended to facilitate the voluntary development of 

Regional Transmission Organizations (RTOs). The Commission concluded that RTOs 

would provide several benefits, including regional transmission pricing, improved 

congestion management, and more effective management of parallel path flows.21

13. In Order No. 2000, the Commission established the minimum characteristics and 

functions that an RTO must satisfy to gain Commission approval. Minimum 

characteristics of an RTO include independence from market participants and operational 

authority over transmission facilities under its control.22 Minimum functions of an RTO 

include ensuring the development and operation of market mechanisms to manage 

transmission congestion, development and implementation of procedures to address 

parallel path flow issues, and market monitoring.23 Under Order No. 2000, the 

Commission has approved the voluntary formation of a number of RTOs. 

19 Order No. 2000 at 30,992-93 and 31,014-15. 

20 Id. at 31,015-17. 

21 Id. at 31,024. 

22 Id. at 31,046 et seq. 

23 Id. at 31,106 et seq. 
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14. Most of the RTOs and ISOs operate organized markets for energy and/or 

ancillary services in addition to providing transmission service under a single 

transmission tariff. As described in more detail below, most of these markets utilize a 

congestion management system based on Locational Marginal Pricing (LMP). 

Congestion is defined as the inability to inject and withdraw additional energy at 

particular locations in the network due to the fact that the injections and withdrawals 

would cause power flows over a specific transmission facility to violate the reliability 

limits for that facility. The market operator manages congestion by scheduling and 

dispatching generators that can meet load in the presence of congestion. Financially, in 

LMP markets the price of congestion is measured as the difference in the cost of energy 

in the spot market at two different locations in the network.24 When such price 

differences occur, a congestion charge is assessed to transmission users based on their 

nodal injections and withdrawals. These price differences can be variable and difficult to 

predict. In order to manage the risk associated with the variability in prices due to 

transmission congestion, these markets use various forms of Financial Transmission 

Rights (FTRs) (described in more detail below) to allow market participants who hold the 

rights to protect against such price risks. In most cases, these FTRs have terms of one 

year or less. The use of FTRs and their terms is also discussed in more detail below.25

24 See infra at P 21-22. 

25 See infra at P 23-28. 
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B. Currently Available Transmission Rights

15. In recent years, interest in long-term transmission rights in organized electricity 

markets has increased, stemming in large part from a desire of some market participants 

to obtain rights that replicate the transmission service that was available to them prior to 

the formation of the organized electricity markets and remains available today in regions 

without organized electricity markets. The principal concern of these market participants 

is the inability to obtain a fixed, long-term level of service under pricing arrangements 

that hedge the congestion cost risk that they face in the organized electricity markets. 

This section describes the transmission rights that are available in regions with and 

without organized electricity markets, and concludes with a comparison of the two types 

of rights. 

1. Transmission Rights in Regions without Organized Electricity 

Markets

16. In general, in regions without organized electricity markets, transmission service is 

provided to customers under the terms of the Order No. 888 OATT, or under terms of 

contracts that predate the OATT. The OATT offers 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 is available 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 taking service under the OATT have the right to continue to 

take transmission service from the transmission provider when their contract expires 
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(rollover right). Transmission providers are required to expand facilities to satisfy 

network and point-to-point customer needs.26

17. Firm point-to-point transmission service provides for the transmission of energy 

between designated points of receipt and designated points of delivery. A customer 

taking firm point-to-point transmission service generally pays a monthly demand charge 

based on its reserved capacity, and it may resell the service to another customer.27

18. Network service provides the customer with flexibility to utilize its current and 

planned generation resources to serve its network load in a manner comparable to that in 

which the transmission provider utilizes its generation resources to serve its native load 

customers. 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. The network customer 

26See Order No. 888 pro forma OATT at sections 13.5, 15.4 and 28.2. 

27 Under the Commission’s transmission pricing policy, the demand charge may 

reflect the higher of the transmission provider’s embedded costs or incremental 

expansion costs. Also, if the transmission system is constrained, the demand charge may 

reflect the higher of embedded costs or “opportunity” costs, with the latter capped at 

incremental expansion costs. See Inquiry Concerning the Commission’s Pricing Policy 

for Transmission Services Provided by Public Utilities Under the Federal Power Act, 

Policy Statement, 69 FERC ¶ 61,086 (1994). In practice, the demand charge is almost 

always determined on basis of the transmission provider’s embedded costs. 
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pays a monthly charge for basic service based on its load ratio share of the 

transmission provider’s transmission revenue requirement. 

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

redispatch its network resources as requested by the transmission provider.28 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 its own resources and loads in the same manner as 

a 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 network customers, including its own 

native load, on a load-ratio basis. If a curtailment on the transmission provider’s system 

is required to maintain reliable operation of the system, curtailments are made on a nondiscriminatory 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. 

20. The price that a transmission customer pays for OATT transmission service is 

usually predictable and relatively stable over the long-term. For example, a load-serving 

entity that has a generating facility at one location that it wishes to use to serve load at a 

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

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

increased while the output of others may decrease. 
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second location can contract for long-term point-to-point transmission service from 

the generator to the load. For this service, the load-serving entity pays only a demand 

charge that is known in advance. Although the load-serving entity must pay the demand 

charge whether or not it uses its full reservation, it does not have to pay additional costs 

associated with transmission congestion for point-to-point transmission service even 

when the transmission provider must redispatch its generators to honor the firm service 

commitment. If the load-serving entity has generators and loads at multiple locations, it 

can request network service and dispatch of its generators to serve its loads in a least cost 

manner. The load-serving entity must pay a load ratio share of the transmission 

provider’s Commission-approved transmission revenue requirement but, again, is not 

directly assigned any congestion costs. If either the transmission provider’s or the loadserving entity’s generators have to be redispatched to relieve congestion, then the cost of 

redispatch is shared by the transmission provider and all network customers on a load 

ratio basis. Thus, whether it takes firm point-to-point transmission service or network 

service, the load-serving entity faces transmission costs that are relatively stable and 

predictable over the term of its service agreement. 

2. Transmission Rights in Organized Electricity Markets

21. Each of the transmission organizations that exist today has implemented or is 

planning to implement an organized electricity market that uses locational pricing for 

electric energy. In most cases, the locational pricing system that is used is LMP. Under 

LMP, the price at each location in the grid at any given time reflects the cost of making 
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available an additional unit of energy for purchase at that location and time. In the 

absence of transmission congestion, all locational prices at a given time are the same.29 

However, when congestion is present, locational prices typically will not be the same, 

and the difference between any two locational prices represents the cost of congestion 

between those locations. 

22. Because locational spot prices can vary significantly over time, a market 

participant potentially faces some degree of price uncertainty. Consider a load-serving 

entity that has a generator at one location and load at another. If there is no congestion, 

the generator and the load will see the same locational prices just as if they were at the 

same location. However, when congestion arises, locational prices will differ, and the 

price that the load-serving entity’s generator receives typically will not be the same as the 

price that its load must pay.30 This difference in prices is the congestion cost, and the 

load-serving entity must pay this cost to the transmission organization whenever power is 

injected and withdrawn at different locations in the transmission system under 

constrained conditions. 

29 The inclusion of marginal losses can cause locational prices to differ across 

locations even in the absence of congestion. For purposes of this discussion, we will 

consider only the congestion component of locational price differences. 

30 It is important to note that, depending on the relative magnitude of the prices at 

the generator’s location and the load’s location, congestion costs can be positive or 

negative. 
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23. To reduce the uncertainty due to congestion, transmission organizations that 

use locational marginal pricing make FTRs available to their market participants.31 An 

FTR is a right to receive the congestion costs paid by grid users and collected by the 

transmission organization for one megawatt of electricity delivered from a specified point 

of receipt to a specified point of delivery. The holder of an FTR receives in each hour a 

payment that is calculated by subtracting the price at the point of receipt from the price at 

the point of delivery, and multiplying the difference by the megawatt quantity. 

24. In an LMP system, all spot power is purchased and sold at locational prices and all 

scheduled injections and withdrawals are subject to congestion charges. When there is no 

congestion, the prices are the same and the payments to FTR holders are zero. However, 

when congestion is present, prices will differ; prices for withdrawals are generally higher 

than prices for injections, creating a source of funds to pay the FTR holders. To ensure 

that the excess revenue is sufficient to meet its FTR payment obligations under normal 

operating conditions, the transmission organization generally subjects any award of FTRs 

to a simultaneous feasibility test. The simultaneous feasibility test requires that, before 

specific FTRs can be awarded, the transmission organization must demonstrate that the 

transmission system is capable of physically delivering the power flows represented by 

31 We use the term FTR in this NOPR to refer generally to the financial 

transmission instruments used in the various organized electricity markets that currently 

exist. In some markets, these financial instruments are called transmission congestion 

contracts or congestion revenue rights. 
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the FTRs simultaneously with the power flows represented by all concurrently or 

previously awarded FTRs. Although FTRs do not convey a physical right (or obligation) 

to use the transmission system, the transmission organization will be at risk of not 

receiving sufficient revenues to meet all of its FTR payment obligations under normal 

operating conditions if any awarded FTRs do not meet the simultaneous feasibility test. 

Any time that revenues are not sufficient, the transmission organization is said to be 

“revenue inadequate.”32

25. The most common type of FTR, which is known as an FTR “obligation,” provides 

for a payment to the holder when congestion cost is positive, but also requires the holder 

to make a payment to the transmission organization whenever the cost is negative. 

Because of this feature, some transmission organizations also offer FTR “options,” which 

do not place a payment obligation on the rights holder. However, because FTR options 

require more transmission capacity than FTR obligations to meet the simultaneous 

32 It should be noted that, even when all awarded FTRs meet the simultaneous 

feasibility test, the Transmission Organization may at times be revenue inadequate as a 

result of unexpected events, such as a line outage or transmission system disruption that 

reduces transfer capability. 
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feasibility test, their availability is limited.33 Therefore, for purposes of the 

discussion in this section, we will assume that FTRs are limited to FTR obligations.34

26. If a load-serving entity holds an FTR that matches its injections and withdrawals 

exactly, it pays no net congestion cost.35 A load-serving entity may also reduce its 

congestion cost risk by holding an FTR that provides a partial hedge. Typically, the 

FTRs that load-serving entities hold do not exactly match their use of the transmission 

system in each hour, but the “over” and “under” financial coverage provided by the FTRs 

evens out over time to provide a sufficient hedge. 

27. In general, transmission organizations provide FTRs on an annual basis to loadserving entities and others that pay access charges or fixed transmission rates. Loadserving entities receive FTRs either through direct allocation or through a two-step 

process in which the load-serving entity first is allocated auction revenue rights (ARRs) 

and then purchases FTRs in an auction.36 The revenues from the auction flow back to the 

33 The need for more capacity is due to the fact that the Transmission Organization 

cannot assume that the FTR options will provide any “counterflows” when it conducts 

the simultaneous feasibility test. 

34 See infra at P 72-79 for a more complete discussion of the properties of FTR 

obligations and FTR options. 

35 This net result is reached because congestion charges billed to the load-serving 

entity (or any other party that holds FTRs) are exactly offset by FTR payments. 

36 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, but does not need to, exactly match an FTR. In some 

Organized Electricity Markets, a market participant must submit a bid for FTRs in the 

(continued) 
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load-serving entity and other ARR holders and thus defray the cost of purchasing 

the FTRs in the auction. Transmission organizations currently offer ARRs and FTRs 

with terms of one year or less. Although details vary by transmission organization, the 

allocation is based largely on historical uses of the system as measured by peak loads, but 

also allows market participants some flexibility to choose among transmission paths. 

Most transmission organizations also allocate long-term ARRs and FTRs to any party 

that invests in transmission upgrades that increase transmission capability. FTRs can be 

traded in annual and monthly transmission organization auctions or bilaterally outside the 

auction. 

28. Since the state of the transmission system and market prices change from year to 

year, the annual allocation allows market participants to re-configure their transmission 

rights requests each year to reflect such changes. The annual reconfiguration also helps 

the transmission organization to manage exposure to situations where payments to FTR 

holders can exceed congestion revenues. Revenue shortfalls can occur due to changes in 

the transmission grid or in the availability of generators that have a major impact on 

power flows. If such changes are expected to be long-lasting, the transmission 

organization is able to adjust the quantity and configuration of rights made available in 

the next annual cycle. However, a load-serving entity may receive fewer FTRs or ARRs 

auction to convert its ARRs to FTRs, while in other Organized Electricity Markets a 

market participant can convert its ARRs to FTRs directly and is not required to bid in the 

auction. 
Docket Nos. RM06-8-000 and AD05-7-000 - 21 -

than it requests due to factors outside of its control, such as changes in the network, 

the network flow assumptions or the FTR nominations of other participants. As a result, 

load-serving entities are uncertain from year to year whether they will obtain the FTRs 

needed to support long-term power supply arrangements, including investment in 

generation resources. 

3. Comparison of Transmission Rights in Regions with and without 

Organized Electricity Markets

29. There are several important differences between transmission service under the 

OATT and transmission rights in organized electricity markets that use LMP and FTRs. 

However, the differences that are most relevant for purposes of this NOPR concern the 

management of congestion, the recovery of congestion costs and the availability of longterm service arrangements. 

30. Under the OATT, the transmission provider manages congestion by redispatching 

its own or its customers’ network resources as needed to accommodate a transmission 

constraint; the OATT provides no mechanism by which firm point-to-point transmission 

customers can participate directly in congestion management. However, in organized 

electricity markets, the transmission organization manages congestion through the use of 

locational prices. This means that all available resources under an LMP system can 

participate in redispatch for congestion management because they all receive the 

congestion price signal. As a result, a transmission organization in a region with an 

organized electricity market is less likely to have to invoke transmission loading relief 
Docket Nos. RM06-8-000 and AD05-7-000 - 22 -

(TLR) procedures and service curtailments than a transmission provider under the 

OATT. 

31. The recovery of congestion costs also differs greatly between regions with and 

without organized electricity markets. In regions where transmission service is provided 

under the OATT, a transmission customer that takes network service or firm point-topoint transmission service is not charged directly for the costs of the redispatch that may 

be required to accommodate its use of the transmission system. For example, a firm 

point-to-point transmission customer is allowed to take service up to its contractual 

entitlement while paying only a fixed demand charge. Also, although a network 

customer must pay a share of any redispatch costs that the transmission provider and 

other network customers incur, its cost responsibility is determined after the fact as a load 

ratio share of the total redispatch costs that are incurred on behalf of all users of the 

system over a given time period. While this type of pricing may not present the customer 

with a price signal that accurately reflects all of the costs occasioned by the customer’s 

use of the system, it lowers the transmission customer’s price uncertainty. In addition, 

both network service and firm point-to-point transmission service can be obtained under 

long-term contracts. These attributes of OATT transmission service result in a less 

volatile price for transmission service over a long-term, which in turn can help facilitate 

the planning and financing of large generation facilities and other long-term power 

supply arrangements. 
Docket Nos. RM06-8-000 and AD05-7-000 - 23 -

32. In contrast, a transmission organization in a region with an organized 

electricity market recovers congestion costs through the locational pricing of energy. 

Because locational prices include a congestion cost component (which can be positive, 

negative or zero), a participant in an organized electricity market faces the prospect of 

paying a congestion charge for many of its transactions. For example, as explained 

above, a load-serving entity that has generation at one location and load at another, but 

does not hold FTRs, is at risk of incurring congestion costs, which may not be 

predictable. Also, although that load-serving entity can avoid congestion costs by 

holding FTRs, it still faces a congestion price risk if its spot sales and purchases or 

scheduled injections and withdrawals do not correspond exactly to its allocated (or 

purchased) FTRs. Clearly, locational pricing and price-based congestion management 

provide the market participant with much of the information it needs to make cost 

effective decisions regarding energy consumption and use of the transmission system (as 

well as investment in new generation and transmission upgrades). However, the FTRs 

that transmission organizations currently provide to hedge congestion charges for using 

existing transmission capacity (as opposed to incremental transmission expansions) are 

generally available for terms of only one year or less. This can create uncertainty for the 

market participant because, in any given year, its award of FTRs may not be sufficient to 

meet its needs. Some market participants have expressed concern that this uncertainty 

makes it more difficult to finance long-term power supply arrangements. 
Docket Nos. RM06-8-000 and AD05-7-000 - 24 -

33. The Commission believes that some of the problems of uncertainty in 

organized electricity markets can be overcome and the objectives of section 217(b)(4) of 

the FPA can be met through the introduction of long-term firm transmission rights. 

However, for a variety of reasons that are discussed below, transmission rights in 

organized electricity markets cannot always be designed in a way that captures all of the 

features of the transmission rights that have long been available under the OATT. 

Consequently, the Commission’s objective in issuing this NOPR is to present a 

framework within which transmission organizations and their market participants can 

design and implement long-term firm transmission rights in the organized electricity 

markets that are compatible with the design of those markets, in particular retaining the 

advantages of price-based congestion management, and meet the reasonable needs of 

market participants. 

C. Staff Paper on Long-Term Transmission Rights

34. Prior to the enactment of EPAct 2005, the Commission released a Staff Paper that 

provided background and solicited comments on whether long-term transmission rights 
Docket Nos. RM06-8-000 and AD05-7-000 - 25 -

 

were needed in the ISO and RTO markets, and if so, how to implement them.37 

This section provides an overview of the comments to the notice. 

35. With respect to the need for and design of long-term transmission rights, the views 

of the respondents tended to fall into three general groups. The first group consisted of 

advocates of long-term transmission rights with terms in the range of 5-30 years.38 These 

parties argue that the failure of transmission organizations to offer transmission rights 

with terms greater than one year is a key deficiency in the markets that produces 

increased financial risk due to congestion price uncertainty, the failure of forward energy 

markets to form, and barriers to investment in new generation capacity. The core problem 

expressed by these parties is that annual allocations of rights may not provide sufficient 

rights year-to-year to adequately cover potentially volatile congestion cost exposure. In 

turn, the inability to secure a known quantity of transmission rights for multiple years 

introduces an unacceptable degree of uncertainty into resource planning, investment and 

contracting. 

37 Notice Inviting Comments On Establishing Long-Term Transmission Rights in 

Markets With Locational Pricing and Staff Paper, Long-Term Transmission Rights 

Assessment, Docket No. AD05-7-000 (May 11, 2005) (Staff Paper). While we are 

issuing this NOPR in both Docket No. RM06-8-000 and Docket No. AD05-7-000, we 

expect to issue our Final Rule in only Docket No. RM06-8-000. Comments in response 

to this NOPR should be filed in Docket No. RM06-8-000. 

38 See, e.g., Comments on Staff Paper of the American Public Power Association 

(APPA) at 1, 8, 19; Comments on Staff Paper of the Transmission Access Policy Study 

Group (TAPS) at 19-21; Comments on Staff Paper of the National Rural Electric 

Cooperative Association (NRECA) at 17-19; Comments on Staff Paper of the Electricity 

Consumers Resource Council (ELCON) at 9-10. 
Docket Nos. RM06-8-000 and AD05-7-000 - 26 -

36. Most of the parties in this first group stressed that not all transmission 

capacity should be given over to long-term rights, but that there should be an amount 

sufficient to cover at least base-load generation resources and perhaps renewable energy 

generators.39 These commenters argue that long-term rights should be FTR obligations 

only under certain conditions that limit financial exposure of the rights holder. Several 

proposed that the long-term rights should be FTR options. Otherwise, the rights could be 

physical rights40 or modified FTRs (e.g. financial rights with physical characteristics, 

such as “use-or-lose” rights) designed to alter the financial settlement properties of 

traditional FTRs so as to reduce congestion risk.41 

 39 See Comments on Staff Paper of APPA at 31; Comments on Staff Paper of 

TAPS at 17-19. However, other parties supportive of long-term transmission rights 

argued that their allocation should not be tied to particular classes of generator. See, e.g., 

Comments on Staff Paper of ELCON at 8-9. 

40 See Comments on Staff Paper of Sacramento Municipal Utility District 

(SMUD) at 12-16; Comments on Staff Paper of City of Santa Clara, California, Silicon 

Valley Power (SVP) at 14-18. 

41 For example, a right that only provides a financial hedge when the holder 

submits a physical schedule (a type of “use or lose” right). See, e.g., Comments on Staff 

Paper of the Transmission Access Policy Study Group (TAPS) at 21-25; Comments on 

Staff Paper of the Electricity Consumers Resource Council (ELCON) at 12-13. Note also 

that several commenters argued that ISOs with LMP and financial rights should not 

revert to physical rights to provide long-term transmission service, nor should they allow 

such ISOs to offer combinations of physical and financial rights (with the exception of 

already awarded grandfathered rights). See, e.g., Comments on Staff Paper of ABATE at 

10-11; Comments on Staff Paper of American Electric Power (AEP) at 3; Comments on 

Staff Paper of Cinergy at 13-14; Comments on Staff Paper of Edison Electric Institute 

(EEI) at 3; Comments on Staff Paper of Electric Power Supply Association (EPSA) at 6-

8; Comments on Staff Paper of FirstEnergy Solutions at 8; Comments on Staff Paper of 

ISO/RTO Council at 2-3. 
Docket Nos. RM06-8-000 and AD05-7-000 - 27 -

 

37. A second group of commenters largely agreed with the first that long-term 

rights should be introduced, but argued that this should take place within the framework 

of existing FTR market designs and follow a cautious, incremental approach. These 

parties, which included most of the ISOs and RTOs that submitted comments as well as 

many stakeholders, argued that rights of greater than one year duration would indeed find 

a role in the markets, but that care was needed in the design of the rights.42 Most of these 

parties were supportive of straightforward extensions of the current FTR market design to 

include FTR obligations of longer terms, although perhaps with modified 

creditworthiness requirements and other rule changes to reflect the different risks 

embodied in such rights. In general, they proposed terms for such FTRs of between 2 to 

5 years. They also supported limiting the quantity of system capability given over to 

long-term FTRs for at least an initial period. 

42 See generally Comments on Staff Paper of California ISO; Comments on Staff 

Paper of ISO New England; Comments on Staff Paper of New York ISO; Comments on 

Staff Paper of PJM; Comments on Staff Paper of ISO/RTO Council. See also generally

Comments on Staff Paper of New York Public Service Commission (NY PSC) and the 

Organization of Midwest States (OMS). On appropriate term lengths, see Comments on 

Staff Paper of Cinergy at 10; Comments on Staff Paper of Coral Power at 3,6; Comments 

on Staff Paper of DC Energy at 4-5; Comments on Staff Paper of Edison Electric Institute 

(EEI) at 10; Comments on Staff Paper of Electric Power Supply Association (EPSA) at 

11; Comments on Staff Paper of Midwest Transmission Owners at 11; Comments on 

Staff Paper of Morgan Stanley at 7; Comments on Staff Paper of National Grid at 15; 

Comments on Staff Paper of Pacific Gas & Electric (PG&E) at 5. 
Docket Nos. RM06-8-000 and AD05-7-000 - 28 -

 

38. Finally, some respondents felt that long-term rights should not be introduced 

at this time.43 These parties argued that the current procedures for annual allocations of 

FTRs with terms of one year or less were well-established and that transmission rights 

markets were efficient and maturing around this design. They were concerned that the 

introduction of multi-year rights could introduce inequity and inefficiency into the 

organized electricity markets, because they believe such rights will reduce the availability 

of FTRs with terms of one year or less that can be used to hedge shorter-term 

transactions. They also assert that introducing long-term rights could cause cost shifts if 

holders of long-term rights are given congestion risk coverage greater than that accorded 

to other parties. Some respondents that supported this position were from retail choice 

states, reflecting concerns that long-term rights could adversely affect their ability to 

acquire and trade transmission rights used to hedge shorter-term contracts. 

39. In general, those responding to the Staff Paper did not favor a uniform, “one size 

fits all” approach to long-term rights. Instead, they stressed that the development of longterm transmission rights should take place in a regional context, which would allow 

stakeholders to balance the different needs of transmission users and reflect the 

characteristics of the regional grid and generation resources. Also, those responding 

provided suggestions on many other aspects of long-term transmission right design and 

43 See, e.g., Comments on Staff Paper of Cinergy at 3; Comments on Staff Paper 

of Coral Power at 7. However, many of these respondents did articulate views on how 

long-term rights should be specified in the event that the Commission required them. 
Docket Nos. RM06-8-000 and AD05-7-000 - 29 -

implementation. We will refer to those suggestions where relevant in some of the 

discussion that follows. 

IV. Proposed Guidelines for Design and Administration of Long-term Firm 

Transmission Rights in Organized Electricity Markets

A. The Commission’s Proposed Approach

40. To satisfy the requirements of section 1233(b) of EPAct 2005, and to address the 

concerns expressed by market participants, the Commission proposes to establish a set of 

guidelines for the design and administration of long-term firm transmission rights in 

organized electricity markets. The Commission proposes to require each transmission 

organization that is a public utility with one or more organized electricity markets44 to 

file with the Commission, within 180 days, either proposed tariff sheets that make 

available long-term firm transmission rights that are consistent with the guidelines, or an 

explanation of how the transmission organization already makes such rights available. 

The proposed compliance procedures are discussed in more detail below. 

41. The Commission recognizes that there may be many possible approaches to 

fulfilling this requirement of EPAct 2005. Parties commenting on the Staff Paper 

suggested a number of possible approaches to designing and implementing long-term 

transmission rights. The Commission believes that establishing guidelines for the design 

 44 As noted elsewhere, this proposed rule would apply whether the Organized 

Electricity Markets are administered by the Transmission Organization itself, or whether 

the Organized Electricity Markets are administered by another entity. 
Docket Nos. RM06-8-000 and AD05-7-000 - 30 -

 

and administration of long-term firm transmission rights in this rulemaking, 

followed by development of specific long-term firm transmission right designs within the 

stakeholder process of each Transmission Organization with an organized electricity 

market, is the most appropriate course for complying with the directive of section 

1233(b) of EPAct 2005. We agree with many of those commenting on the Staff Paper 

that a “one size fits all” long-term firm transmission right design is not appropriate, and 

that long-term transmission rights should be developed through regional stakeholder 

discussion.45 

42. This flexible regional development of long-term firm transmission rights must, 

however, occur within certain guidelines. Accordingly, the Commission proposes 

guidelines for the design and administration of long-term firm transmission rights that 

ensure that those rights have certain properties that we believe are fundamental to 

meeting the objectives of section 217(b)(4) of the FPA. For example, we propose below 

that long-term firm transmission rights be made available with terms (and/or rights to 

renewal) that are sufficient to meet the needs of load-serving entities to hedge long-term 

power supply arrangements made or planned to satisfy a service obligation.. 

Additionally, as described in more detail in the guidelines that follow, we propose that 

45 See, e.g., Comments on Staff Paper of APPA at 23-24; Comments on Staff 

Paper of Association of Businesses Advocating Tariff Equity (ABATE) and Coalition of 

Midwest Transmission Customers at 11-12; Comments on Staff Paper of New York ISO 

at 3-4; Comments on Staff Paper of New York Transmission Organizations at 3-4. 
Docket Nos. RM06-8-000 and AD05-7-000 - 31 -

transmission organizations be required to award long-term firm transmission rights 

to market participants that request and support an expansion or upgrade to the 

transmission system in accordance with the transmission organization’s prevailing rules 

for cost allocation. Such long-term firm transmission rights must be for a term equal to 

the life of the new facilities, or for a lesser term if requested by the funding entity. Also, 

as described in more detail below, while long-term firm transmission rights should be 

made available to all transmission customers, in the event that a transmission 

organization cannot accommodate all requests for long-term firm transmission rights over 

existing transmission capacity, we propose that the approach most consistent with section 

217(b)(4) of the FPA is to require that a preference be given to load-serving entities with 

long-term power supply arrangements used to meet service obligations. 

43. While we believe these and the other properties outlined in the guidelines below 

are critical to the successful implementation of long-term rights, we intend for the 

guidelines to form only a framework for further, more specific development of long-term 

firm transmission rights by each transmission organization. Accordingly, the guidelines 

should provide enough flexibility to allow each region to develop, through its usual 

stakeholder process, a specific long-term firm transmission right design that fits the 

prevailing market design and best meets the needs of market participants in that region. 

44. Although we propose to allow regional flexibility in the development of long-term 

firm transmission rights, we recognize that allowing transmission organizations with 

organized electricity markets to implement different rules for these rights could lead to 
Docket Nos. RM06-8-000 and AD05-7-000 - 32 -

regional seams issues. We seek comments on our proposal to provide regional 

flexibility. In particular, we ask commenters to identify features of long-term firm 

transmission rights that, if not consistent across transmission organizations, may interfere 

with the effective operation of regional markets. 

B. Proposed Guidelines

Guideline (1): The long-term firm transmission right should be a pointto-point right that specifies a source (injection node or nodes) and sink 

(withdrawal node or nodes), and a quantity (MW). 

45. Section 217(b)(4) of the FPA requires that long-term firm transmission rights be 

available to support long-term power supply arrangements. Hence, we propose that the 

transmission rights must be specified such that they can hedge the congestion costs that 

may be incurred in delivering the output of particular generation resources to particular 

loads.46 The source nodes can correspond to a single generator or a set of generators 

(e.g., a zone). Similarly, the sink nodes can specify a single node or set of nodes.47 This 

 46 APPA states that, because ISO-NE offers only general system-wide ARRs, there 

is no direct relationship between the ARRs that a market participant receives and the 

FTRs that the market participant may desire, given the location of its resources. See

Comments on Staff Paper of APPA, attached Concept Paper - Long-Term Transmission 

Rights, at 16, n. 22. 

47 It is thus possible to define a form of network service that consists of a set of 

point-to-point rights, each of which specifies a source, a sink and a megawatt quantity. 

This, however, would differ from network service under the OATT, which does not 

require the customer to reserve a specific amount of capacity between its network 

resources and network loads. 
Docket Nos. RM06-8-000 and AD05-7-000 - 33 -

guideline is not intended to preclude flowgate rights so long as they are designed 

with the same hedging properties as an equivalent long-term point-to-point right. 

46. Section 217(b)(4) recognizes that there may be alternative designs for long-term 

firm transmission rights.48 For many transmission organizations and their market 

participants, the most straightforward method to develop long-term firm transmission 

rights would be to extend the term of the auction revenue rights or FTRs that they 

currently allocate. These may require additional market rules, such as modified 

creditworthiness standards. However, we do not preclude alternative designs for longterm rights. Some possible designs are compared in Section IV.C of this NOPR. 

Guideline (2): The long-term firm transmission right must provide a 

hedge against locational marginal pricing congestion charges (or other 

direct assignment of congestion costs) for the period covered and 

quantity specified. Once allocated, the financial coverage provided by 

the right should not be modified during its term except in the case of 

extraordinary circumstances or through voluntary agreement of both 

the holder of the right and the transmission organization. 

47. In most existing organized electricity markets, LMP is used to manage congestion. 

The FTRs currently offered in the organized electricity markets provide a hedge against 

these charges, but are only offered in terms of one year or less. Because of this short 

term, market participants with long-term power supply arrangements are at risk of having 

the ARRs or FTRs that they are eligible for to hedge congestion charges associated with 

 48 In particular, that provision states that the Commission shall exercise its 

authority “to enable load-serving entities to secure firm transmission (or equivalent 

tradable or financial rights) on a long-term basis” (emphasis added). 
Docket Nos. RM06-8-000 and AD05-7-000 - 34 -

 

delivery of that power prorated during the course of the power supply arrangement. 

As noted above, one criticism of the current FTR market rules is that the annual FTR 

allocation may produce different results from year to year in the quantity of FTRs 

allocated to eligible load-serving entities. APPA, for example, argues that there is a need 

for a mechanism to keep long-term firm transmission rights feasible in the “out” years.49 

48. To address this concern, we propose that the transmission organization ensure that 

the long-term firm transmission rights it offers provide a hedge against congestion costs 

for the entire term of the right, and for the entire quantity of the right. In proposing that 

the financial coverage offered by the long-term rights, once awarded, not be modified, we 

seek to establish rights that provide a high degree of stability in terms of payments from 

year to year, rather than subject to uncertainty over the possibility of significant prorationing in the event of revenue inadequacy. We interpret the intent of section 217(b)(4) 

of the FPA to be that the Commission ensure the availability in organized electricity 

markets of long-term firm transmission rights that provide price stability to load-serving 

entities with long-term power supply arrangements used to satisfy their service 

obligations. 

49. When conditions arise that cause the transmission organization to receive 

congestion revenues that are not sufficient to meet payment obligations to FTR holders, 

the transmission organization must have in place a mechanism to fully fund the rights by 

49 Comments on Staff Paper of APPA at 21. 
Docket Nos. RM06-8-000 and AD05-7-000 - 35 -

 

collecting the needed revenues from a set of market participants. We will not 

specify here how that funding should be allocated among market participants, which is a 

subject for stakeholder discussion, but note that ideally the rules for funding of the rights 

should be designed to create and improve incentives for the maintenance and expansion 

of the transmission system that is needed to ensure the feasibility of the long-term rights 

that are allocated. This might be accomplished, for example, by placing the entities that 

are ultimately responsible for system maintenance and expansion at risk (wholly or 

partially) for funding revenue shortfalls that are due to inadequate maintenance or 

expansion practices. The transmission organization might also define rules for 

transmission upgrades and expansion to support the feasibility of long-term rights.50 The 

Commission seeks comments on funding revenue shortfalls related to the provision of 

long-term firm transmission rights, particularly with regard to how any necessary charges 

should be allocated. Should such charges be allocated to a transmission owner that is 

responsible for maintaining and expanding the capacity supporting the long-term firm 

transmission rights where the revenue shortfalls are due to inadequate maintenance or 

expansion? Are there appropriate methods for allocating such charges that also provide 

appropriate short-term and long-term incentives for transmission usage, maintenance and 

expansion? 

50 We discuss this issue in Section V, infra. 
Docket Nos. RM06-8-000 and AD05-7-000 - 36 -

50. Also, there may be extraordinary circumstances under which the requirement 

for full funding should be relaxed. For example, one such extraordinary circumstance 

may be a sustained, unplanned outage of a large transmission line. Such circumstances 

may require alternative rules for sharing of congestion cost risk than would otherwise 

apply. 

Guideline (3): Long-term firm transmission rights made feasible by 

transmission upgrades or expansions must be available upon request to

any party that pays for such upgrades or expansions in accordance 

with the transmission organization’s prevailing cost allocation methods 

for upgrades or expansions. The term of the rights should be equal to 

the life of the facility (or facilities) or a lesser term requested by the 

party paying for the upgrade or expansion.

51. Most transmission organizations today allow entities that pay for network 

upgrades or expansions to receive the long-term firm transmission rights that would not 

be feasible but for those expansions. The Commission believes that this policy is fair to 

both new and existing users of the transmission system, promotes efficient capacity 

expansions by allowing users that fund the expansions to compare directly any 

congestion cost savings with the cost of the necessary upgrades, and provides the longterm hedge against congestion costs desired by transmission customers wishing to enter 

into long-term power supply arrangements. We note that the pro forma OATT adopted 

by the Commission in Order No. 888 requires public utility transmission providers to 

expand capacity, if necessary, to satisfy the needs of transmission customers.51 

 51 See pro forma OATT at sections 13.5, 15.4 and 28.2. 
Docket Nos. RM06-8-000 and AD05-7-000 - 37 -

 

Accordingly, the tariffs of transmission organizations must clearly and specifically 

provide for the award of long-term firm transmission rights (as described in this proposed 

rule) to entities that support an expansion or upgrade in accordance with the transmission 

organization’s prevailing cost responsibility or allocation rules. The long-term firm 

transmission rights would be equal to the amount of transfer capability created by the 

expansion or upgrade. We propose that such rights be for a term equal to the life of the 

facility (or facilities), or for a lesser term if requested by the funding party. 

52. An issue that arises in this context concerns the possibility that granting a longterm firm transmission right that uses expanded capacity may encumber some existing 

transmission capacity as well. Given the integrated nature of the grid, any point-to-point 

transmission right made possible by a capacity expansion is likely to require use of at 

least some existing transfer capability in order for the right to be feasible. If the entity 

that has funded a capacity expansion does not have a priority to obtain long-term rights to 

existing capacity as proposed in guideline (5) in this NOPR,52 the transmission 

organization must propose a procedure by which such an entity can obtain rights to 

existing capacity when such rights are needed to make the incremental expansion rights 

feasible. We ask for comment on the appropriate rules in such cases. 

52 See infra at P 58-61. 
Docket Nos. RM06-8-000 and AD05-7-000 - 38 -

Guideline (4): Long-term firm transmission rights must be made 

available with term lengths (and/or rights to renewal) that are 

sufficient to meet the needs of load-serving entities to hedge long-term 

power supply arrangements made or planned to satisfy a service 

obligation. The length of term of renewals may be different from the 

original term. 

53. The Commission proposes to require each transmission organization to make longterm firm transmission rights available to market participants. Doing so is consistent 

with section 217(b)(4) of the FPA, which requires that load-serving entities be able to 

secure firm transmission rights on a long-term basis to support long-term power supply 

arrangements made or planned to meet a service obligation. This requirement raises a 

number of issues. First, we note that the FPA (and EPAct 2005) do not define “longterm.” Commenters on the Staff Paper expressed a wide range of views on the 

appropriate term for long-term transmission rights. Some commenters prefer to proceed 

cautiously, suggesting that a two year FTR obligation would be a reasonable, 

conservative starting point for implementation of long-term rights.53 A number of 

commenters also support initial experimentation with shorter term FTRs, but are willing 

to consider longer terms, typically up to three to five years.54

 53 See, e.g., Comments on Staff Paper of California ISO at 5; Comments on Staff 

Paper of New York Public Service Commission at 3. 

54 See, e.g., Comments on Staff Paper of Cinergy at 10; Comments on Staff Paper 

of Edison Electric Institute at 10. 
Docket Nos. RM06-8-000 and AD05-7-000 - 39 -

 

54. Other commenters argued that the initial assignment of long-term rights 

should consider much longer time-frames, on the order of decades. For example, 

NRECA argues that the term of the rights should be matched to the RTO planning 

process, which is typically 5 or 10 years.55 TAPS argues that long-term rights consistent 

with its specifications should be made available for 10 year terms with the unconditional 

right to renew.56 APPA states that a party making an investment in a generation asset 

should be able to obtain a long-term right for the duration of the financing terms, which 

could be 20 to 30 years, or even for the duration of the asset’s operating life. APPA notes 

that there should be flexibility in the term of the long-term right, but that perhaps there 

should be a minimum term that matches the transmission organization’s planning and 

construction horizon.57

55. The Commission believes that it is reasonable to allow transmission organizations 

to individually develop and propose the terms of the long-term firm transmission rights 

they offer.58 However, we consider long-term, for purposes of this rulemaking, to mean 

terms on the order of multiple years, sufficient to meet the needs of load-serving entities 

55 See Comments on Staff Paper of NRECA at 18. 

56 See Comments on Staff Paper of TAPS at 19-21. 

57 See Comments on Staff Paper of APPA at 33. 

58 We expect that transmission organizations will develop their proposals in 

consultation with stakeholders. 
Docket Nos. RM06-8-000 and AD05-7-000 - 40 -

 

with service obligations.59 The Commission’s primary concern here is to be 

responsive to the needs of load-serving entities, other market participants, and the 

requirements of section 217(b)(4) of the FPA. In particular, our goal is to ensure that 

long-term firm transmission rights are available for those who wish to obtain a more 

stable, long-term firm transmission right to meet their service obligations, and for those 

who need longer-term transmission rights to finance investments in new generation or 

long-term power purchase contracts. To achieve this goal, we propose this guideline, 

which would require that the specific rights proposed by each transmission organization 

in compliance with this rulemaking have term lengths (and/or rights to renewal) that are 

sufficient to meet the needs of transmission customers to hedge long-term power supply 

arrangements made or planned to satisfy a service obligation. Because market 

participants in different transmission organizations may have different needs, we decline 

to propose a specific term length or set of term lengths. New section 217(b)(4) of the 

FPA makes clear, however, that transmission organizations with organized electricity 

markets must meet the needs for long-term firm transmission service of load-serving 

entities with long-term power supply arrangements made, or planned, to meet their 

service obligations. Hence, this guideline would require that transmission organizations 

59 Defining long-term in this manner, for purposes of this proposed rule, differs 

from our previous practice of defining long-term as “one year or more.” We propose 

defining long-term differently in this context because the transmission organizations 

subject to this rulemaking already provide transmission rights with a term of one year. 
Docket Nos. RM06-8-000 and AD05-7-000 - 41 -

with organized electricity markets offer long-term firm transmission rights with 

terms that meet such needs. The Commission expects that multiple-year terms will be 

necessary to ensure that the rights will support the financing of new generation 

investments or power purchase contracts.60 Our view of long-term as terms of multiple 

years is intended to provide a range to allow transmission organizations the flexibility to 

individually develop and propose term lengths, subject to review by the Commission to 

ensure that the terms each transmission organization proposes meet the goals described 

above and expressed by Congress in section 217(b)(4) of the FPA. 

56. We seek comments regarding the length of terms of long-term firm transmission 

rights. For example, we seek comments on whether regional flexibility is needed on the 

length of term, or whether a more specific set of terms should be included in the Final 

Rule. Further, we note that the issue of term length is linked to the length of the 

transmission organization’s transmission planning and expansion cycle. As a result, we 

seek comments on how longer-term long-term firm transmission rights (i.e. 20 to 30 

years) relate to the transmission organization’s planning cycle, how such longer-term 

rights can be guaranteed beyond the length of the planning cycle, and whether the 

planning cycles of transmission organization’s must be modified or extended to 

accommodate terms that are sufficient to meet the needs of load-serving entities to hedge 

 60 The ability to renew the long-term firm transmission rights will also help ensure 

that term lengths will be appropriate. 
Docket Nos. RM06-8-000 and AD05-7-000 - 42 -

long-term power supply arrangements made or planned to satisfy a service 

obligation.61 

57. With regard to rights to renew long-term firm transmission rights, the transmission 

organization may propose reasonable criteria regarding the availability of renewal rights, 

and the price at which rights may be renewed. For example, the right to renew long-term 

firm transmission rights may be limited to a load-serving entity that can demonstrate that 

the renewal right is needed to allow the load-serving entity to match the term of its 

transmission rights to the term of a particular long-term power supply arrangement. In 

addition, the transmission organization may require minimum notice periods for 

initiation, renewal, cancellation or conversion that accommodate the transmission 

organization’s planning cycle or other administrative considerations. We seek comments 

on the relationship between the right to renew a long-term firm transmission right and 

transmission system planning. 

Guideline (5): Load-serving entities with long-term power supply 

arrangements to meet a service obligation must have priority to 

existing transmission capacity that supports long-term firm 

transmission rights requested to hedge such arrangements. 

58. When finalized, this rulemaking will require that transmission organizations with 

organized electricity markets make long-term firm transmission rights available to 

transmission customers. As noted above, section 217(b)(4) of the FPA requires the 

 61 This NOPR also explores transmission planning and expansion in Section V, 

infra. 
Docket Nos. RM06-8-000 and AD05-7-000 - 43 -

Commission to exercise its authority to enable “load-serving entities to secure firm 

transmission rights (or equivalent tradable or financial rights) on a long-term basis for 

long-term power supply arrangements made, or planned, to meet such needs.” As we 

discuss elsewhere in this NOPR, in regions where existing transmission capacity is 

limited, transmission organizations may not be able to accommodate all requests for 

long-term firm transmission rights. While section 217 does not require that long-term 

firm transmission rights be made available only to load-serving entities with service 

obligations, we interpret that section to require the Commission to give load-serving 

entities with long-term power supply arrangements to satisfy a service obligation a 

preference in securing long-term firm transmission rights. In accordance with this 

interpretation, if there is a conflict (infeasibility) in awarding long-term rights from 

existing capacity (or capacity created by incremental reliability upgrades) to all parties 

eligible to receive them, we propose to require the transmission organizations to address 

this infeasibility by first giving load-serving entities with long-term power supply 

arrangements used to meet service obligations priority in the allocation of the rights. 

59. When rights requested by eligible parties with priority (or parties without priority 

that are being accommodated) are not simultaneously feasible given existing transmission 

capacity, the transmission organization may adopt methods to allocate the requested 

rights to the parties prior to granting such rights. We seek comments on such methods 

and whether and to what extent it may be appropriate to allow transmission organizations 

to adopt limits on the amount of capacity they will allocate to long-term rights before 
Docket Nos. RM06-8-000 and AD05-7-000 - 44 -

such rights are allocated. In particular, we seek comments on whether section 1233 

of EPAct 2005 and new section 217(b)(4) of the FPA, read in their entirety, support such 

reasonable limits. Section 217(b)(4) states that the Commission must exercise its 

authority to meet the “reasonable needs” of load-serving entities to satisfy their service 

obligations. Additionally, that section requires that the Commission enable load-serving 

entities to secure long-term firm transmission rights for “power supply arrangements 

made, or planned,” to meet their service obligations. 

60. In making available long term firm transmission rights for power supply 

arrangements “made or planned” to meet service obligations, transmission organizations 

may have to incorporate estimates of load growth into the award of such rights. This 

raises the concern that to the extent that the load growth assumptions made by loadserving entities as a basis for nominating transmission rights are overstated, some load 

serving entities could be awarded more long-term firm transmission rights than needed to 

meet service obligations, and the associated transmission capacity would not be available 

for allocation of transmission rights to others. The Commission seeks comment on this 

issue and any rules or other safeguards that address it. 

61. We also seek comments on the other issues raised by this guideline. Particularly, 

we seek comment on how the transmission organization should allocate long-term firm 

transmission rights from existing capacity in light of the priority we propose in this 

guideline. 
Docket Nos. RM06-8-000 and AD05-7-000 - 45 -

Guideline (6): A long-term transmission right held by a loadserving entity to support a service obligation should be re-assignable to 

another entity that acquires that service obligation.

62. The Commission believes that in general, it is appropriate to require that long-term 

firm transmission rights, once allocated to or obtained by a load-serving entity, be 

reassignable to a successor load-serving entity which, in turn, would assume any cost 

responsibility that holding the rights entails. This proposal is consistent with section 

217(b)(3)(A) of the FPA, which requires that transmission rights held by a load-serving 

entity as of the date of enactment of EPAct 2005 for the purpose of delivering energy it 

has purchased or generated to meet a service obligation be transferred to a successor 

load-serving entity.62 Specifically, section 217(b)(3)(A) provides: 

To the extent that all or a portion of the service obligation covered by the firm 

transmission rights or equivalent tradable or financial transmission rights is 

transferred to another load-serving entity, the successor load-serving entity shall 

be entitled to use the firm transmission rights or equivalent tradable or financial 

transmission rights associated with the transferred service obligation. 

This guideline would apply when a service obligation is transferred to a new load-serving 

entity. Such a transfer of a service obligation might occur pursuant to a state commission 

order, or might occur in a state with retail competition if load chooses a new supplier. 

The Commission seeks comments regarding whether the reassignability we propose to 

 62 We note that the short-term transmission rights currently offered by 

transmission organizations are generally reassignable to successor load-serving entities, 

consistent with this statutory language. See, e.g., PJM Manual 06, Financial 

Transmission Rights (Revision 7, effective April 15, 2005), at

http://www.pjm.com/contributions/pjm-manuals/pdf/m06v071.pdf
Docket Nos. RM06-8-000 and AD05-7-000 - 46 -

require in this guideline, consistent with section 217, should apply to all long-term 

firm transmission rights, regardless of how those rights were obtained. For example, 

what, if any, compensation should a holder of long-term rights receive when its rights are 

reassigned to a successor load-serving entity? 

63. Section 217(b)(4) of the FPA does not discuss whether long-term firm 

transmission rights should be fully tradable among market participants. Allowing such 

rights to be fully tradable could raise issues of equity, since a load-serving entity who 

acquired the rights through the preference we propose in this rulemaking could then 

possibly sell or trade the rights at a profit. This might give load-serving entities the 

incentive to acquire excess long-term firm transmission rights in order to take advantage 

of profit opportunities through arbitrage. However, full tradability may bring benefits to 

the market, and allow those who could not obtain long-term rights in the initial allocation 

to obtain such rights later. We seek comment on these issues. Particularly, we seek 

comment on whether the equity issues we note above could be addressed by only 

permitting holders of long-term firm transmission rights to return their rights to the 

transmission organization at the price paid, or whether these issues could be addressed in 

some other manner. 

Guideline (7): The initial allocation of the long-term firm transmission 

rights shall not require recipients to participate in an auction.

64. As is currently done in most transmission organization markets, the first stage in 

awarding transmission rights is to allocate the rights directly to eligible parties or to 
Docket Nos. RM06-8-000 and AD05-7-000 - 47 -

allocate auction revenue rights directly and subsequently conduct an auction for 

transmission rights (in which parties with and without allocated rights can participate). If 

an auction model is adopted or continued by the transmission organization, we will 

require that any long-term rights allocated as auction revenue rights can be directly 

converted to transmission rights without participation in the auction.63 This allows any 

party that feels uncertain about valuing its rights commercially to de facto have them 

allocated directly. This guideline does not preclude interested parties with long-term 

rights from participating in the auction if they choose. 

Guideline (8): Allocation of long-term firm transmission rights should 

balance any adverse economic impact between participants receiving 

and not receiving the right.

65. The provision of long-term firm transmission rights may have adverse impacts on 

markets participants not receiving such rights. For example, to the extent that the 

capacity of the transmission system is encumbered by entities holding long-term firm 

transmission rights, entities that prefer to hold short-term transmission rights, such as 

load-serving entities operating in retail states,64 will have fewer rights available to them 

than they have under annual allocation schemes that are now used. In addition, to the 

 63 For example, under the rules for allocation of transmission rights on file for 

PJM, awarded ARRs can be directly converted to FTRs in the subsequent annual auction 

without submission of price offers. 

64 Because load-serving entities in retail access states may prefer a business model 

that is based upon having only short-term supply arrangements, they may prefer to hold 

only short-term transmission rights. 
Docket Nos. RM06-8-000 and AD05-7-000 - 48 -

extent awarded long-term rights become infeasible due to major unforeseen changes 

in the physical properties of the transmission system, the payment obligations to holders 

of long-term firm transmission rights would have to be funded by others. 

66. Although some of these impacts may be unavoidable, the Commission believes, in 

general, that it is possible for a transmission organization to introduce long-term firm 

transmission rights in a way that balances their economic impact between those receiving 

and not receiving the rights. For example, the transmission organization could place a 

limit on the amount of system capacity that is available to support long-term rights. This 

would reduce the likelihood that the rights may become infeasible due to major 

unforeseen changes in physical properties of the transmission system, which in turn 

would reduce the possibility that the burden of funding the allocated rights would 

eventually fall onto other market participants. The Commission seeks comment on this 

issue. 

67. Second, to the extent that the long-term right relieves the holder of the obligation 

to pay congestion costs, the value of that congestion hedge should be reflected in the 

price of the long-term right, insofar as possible. For example, where FTR options are 

offered to provide a better congestion hedge, and the FTR option encumbers more system 

capacity than an FTR obligation, the load-serving entity that requests such a right could 

be required to assume greater cost responsibility than it would if it received an FTR 

obligation. The additional payment may, for example, be in the form of a requirement to 

pay a larger share of the transmission revenue requirement. 
Docket Nos. RM06-8-000 and AD05-7-000 - 49 -

 

68. Third, the transmission organization might provide for a secondary market or 

auction by which long-term rights holders can offer their rights for sale or reconfigure 

their rights, subject to any restrictions on trading that may be deemed necessary. This 

would provide an opportunity for transmission customers to obtain long-term rights on 

either a long-term or short term basis from those holding long-term rights. However, as 

we noted above in our discussion of guideline (6), allowing this kind of tradability could 

raise equity issues and could give load-serving entities with a preference the incentive to 

acquire excess long-term rights and later sell them at a profit.65 We seek comment on 

these issues. 

69. Finally, with regard to the pricing of long-term rights in general, the Commission 

proposes not to prescribe a specific methodology, whether the rights are available from 

existing capacity or require capacity expansion. In particular, the Commission does not 

propose to require a rolled-in pricing policy for long-term firm transmission rights. 

Rather, consistent with current policy, the Commission proposes to allow the 

transmission organization flexibility to propose methods for pricing transmission rights 

and related services that are appropriate for its region and are the product of a stakeholder 

process. 

70. We seek comment on ways that transmission organizations may balance any 

adverse economic impacts of allocating long-term firm transmission rights between 

65 See supra at P 63. 
Docket Nos. RM06-8-000 and AD05-7-000 - 50 -

participants receiving and not receiving such rights. We also seek comment on any 

measures that should be adopted to protect against actions by long-term firm transmission 

rights holders. For example, a holder of a long-term firm transmission obligation type of 

right may leave the transmission organization. The allocation of other transmission rights 

may have depended on that holder’s counterflows on the grid or its payments to fulfill its 

obligation to the transmission organization. Are measures needed to address this 

situation? 

C. Alternative Designs

71. The guidelines above are sufficiently general to allow for a range of proposals for 

the design of long-term firm transmission rights. To assist parties in formulating those 

proposals, we discuss three alternative designs that are possible under the guidelines: 

long-term ARR or FTR obligations, FTR options, and rights with modifications of FTR 

settlement or physical scheduling requirements, such as “use or lose” rights. Consistent 

with proposed Guideline (7), we expect that the first step under any proposed design will 

be a direct allocation, rather than an auction (followed possibly by voluntary participation 

in an auction). The prevailing design for initial allocation of ARRs or FTRs has been to 

assign obligation rights. At the Commission’s urging and in response to market interest, 

in at least one current market (PJM), ARRs can subsequently be used to purchase FTR 

options as well as obligations through an FTR auction. 
Docket Nos. RM06-8-000 and AD05-7-000 - 51 -

1. Long-Term ARR or FTR Obligations

72. We begin with the advantages and disadvantages of the prevailing designs for 

transmission rights in current organized electricity markets. As noted above, allocated 

transmission rights, whether as ARRs or FTRs, are modeled as obligation rights. The 

major advantage of obligations is that they allow the transmission organization to 

maximize the coverage of the allocated point-to-point transmission rights made available 

to eligible parties. As explained above, in the modeling of the transmission system power 

flows that supports the initial allocation, obligation rights are represented under the 

assumption that the counterflows associated with injections and withdrawals will be 

present. This limits the need to “pro-ration” eligible transmission rights, although most 

transmission organizations have rules for how such pro-rationing will occur if necessary 

(e.g., by having stages of the allocation with higher priority given to rights nominated in 

early stages). 

73. In existing systems that directly allocate FTR obligations, allocating multi-year 

FTRs could be a fairly straightforward extension of the existing market design, with the 

need for additional rules to cover the additional risks of a multi-year financial instrument 

that could entail payment obligations, such as creditworthiness requirements. 

74. In systems that directly allocate ARRs, the rules would be slightly different. A 

long-term ARR obligation would mean that for the term defined in the right, the loadserving entity would receive the right to auction revenues associated with a fixed quantity 

of injections and withdrawals in the FTR auction. The load-serving entity could then 
Docket Nos. RM06-8-000 and AD05-7-000 - 52 -

either directly convert the ARRs to FTR obligations on an annual basis or it can use 

the expected revenues to purchase FTRs of greater than one year based on the assumption 

that its ARR revenue eligibility will be fixed for multiple years (or it could choose not to 

purchase long-term FTRs but simply collect auction revenues each year). In contrast, 

under a direct allocation of long-term FTR obligations, the party with the rights will hold 

the rights for the term specified. Hence, a design that provides ARR obligations on a 

long-term basis will be somewhat more flexible than the allocation directly of FTRs, 

because it gives the parties the choice of purchasing a fixed quantity of FTRs annually or 

holding a longer-term FTR obligation. Thus, the directly allocated long-term ARR 

obligation gives a similar degree of financial certainty as the directly allocated long-term 

FTR obligation, but more flexibility to change actual holdings of FTRs from year to year. 

75. On the other hand, under some conditions, obligations of either type – ARR or 

FTR -- may not provide the price certainty desired in a long-term firm transmission right. 

Transmission system conditions change over time -- including resource ownership and 

perhaps load -- such that the long-term FTR obligation may be difficult to manage 

financially through physical scheduling. At times, FTR obligations may become a 

financial liability, as noted above. ARR obligations can also become negative sources of 

income – a negative ARR would require the holder to pay the auction rather than collect 

revenues from it. It is these properties that have stimulated interest in other types of 

rights without the likelihood of negative payment obligations. 
Docket Nos. RM06-8-000 and AD05-7-000 - 53 -

76. Before turning to alternative rights, we note that there could be market rules 

that, while not turning obligations into options, reduce the extent of the exposure to 

potential long-term payment obligations. As an example, long-term FTR obligations are 

currently awarded for incremental transmission expansions, and such rights also have 

potential negative payment obligations. Because parties that build transmission may not 

own generation with which to manage such FTR payment risk (e.g., merchant 

transmission operators), some organized electricity market rules (e.g., PJM) currently 

allow for such long-term incremental rights to be “turned back” to the transmission 

organization without penalty at the end of each annual allocation cycle, thus creating an 

option-like feature. To the extent that long-term incremental transmission rights support 

only a limited reliance on counterflow used by other parties in subsequent allocations of 

rights, such a rule may have no or limited financial impact on other parties, but if the 

transmission organization applied such a rule to long-term obligation rights to existing 

capacity, such a “turn back” rule could have more substantial financial implications – that 

is, require uplift charges – in some circumstances. This is a “socialization” of risk 

decision that is best made by stakeholders in tandem with other such decisions, such as 

how many long-term rights to allocate. Such socialization may assist in developing rules 

for long-term ARR or FTR obligations that have more desirable properties for market 

participants. 
Docket Nos. RM06-8-000 and AD05-7-000 - 54 -

2. Long-Term FTR Options

77. For many parties seeking long-term rights (including long-term rights obtained for 

transmission upgrades and expansions), FTR option rights have attractive financial 

properties. As noted above, in contrast to the obligation right, the FTR option payment is 

made only when the congestion charge between the points is positive. When the 

congestion charge is negative, the FTR option neither pays revenues nor requires 

payment equal to the negative charge. As such, the holder will never face negative 

payment obligations. 

78. The primary difficulty in allocating long-term (or short-term) FTR options is that 

because the counterflows are not included when modeling for revenue adequacy, the 

transmission organization will be able to directly allocate fewer FTR options to eligible 

parties than it would be able to allocate FTR obligations that assume counterflows (see 

discussion next). This increases the likelihood that the transmission organization would 

not be able to fulfill all requests for FTRs. The potential shortfall in available FTRs 

could be significant in some locations and rules for equitable pro-rationing could be 

difficult to develop.66 As a result some parties would be exposed to congestion charges 

for transmission usage in excess of their FTR allocation. 

 66 The pro-rationing of FTR obligations has also created conflict over the 

appropriate rules in some organized markets, but the scale of the equity problem in the 

case of FTR options could be much greater. 
Docket Nos. RM06-8-000 and AD05-7-000 - 55 -

79. The allocation issues posed by long-term FTR options may be mitigated in a 

number of ways. If parties sufficiently desire the financial risk characteristics and 

revenues associated with FTR options, they may be willing to accept pro-rationing with 

the attendant possibility of congestion charge exposure. Depending on grid capability, it 

is possible that the resulting exposure may be minimal. Another possibility is that, if 

eligibility requirements are restrictive, sufficiently few long-term FTR options will be 

allocated such that there is enough transmission system capability to satisfy the remaining 

needs for congestion hedges through FTR obligations. Another approach, similar to that 

currently followed in PJM for annual rights, is to assign long-term auction revenue rights 

modeled as obligations, and then let holders of such rights decide whether to purchase 

long-term FTR options or obligations in a subsequent auction. This method requires the 

party eligible for the long-term right to make financial decisions up-front that it may 

prefer not to make, however. Yet another policy option is to make sufficient investments 

in transmission expansion to make the desired long-term FTR options feasible. This 

course could be taken if the market participants determine that such investments are less 

expensive than any congestion cost exposure or insurance through uplift charges 

associated with other transmission rights schemes, some of which are discussed below. 

3. Other Approaches to Long-Term Firm Transmission Rights

80. The features of long-term FTR options and FTR obligations have driven some 

parties to propose alternative types of long-term transmission rights, some having 

financial settlement properties that are different from current FTRs and others combining 
Docket Nos. RM06-8-000 and AD05-7-000 - 56 -

physical and financial features.67 We review these alternative approaches simply 

for illustrative purposes. 

81. Some transmission organizations have implemented types of multi-year 

transmission rights with combined financial and physical properties to solve certain 

transmission rights allocation problems. For example, in the Midwest ISO, parties with 

pre-Order 888 OATT rights were eligible for Grandfathered Agreements (GFAs) that 

exempted the holders from congestion charges based on locational marginal prices. 

Typically, such rights would be accommodated in transmission rights markets through 

physical set-asides or “carve-outs” that basically reserved enough transmission capacity 

on an “option” basis (i.e., not considering counterflows) to accommodate them. 

However, in the Midwest ISO footprint, there were enough of these eligible GFAs so that 

treating them all in this fashion would have greatly reduced the allocation of FTRs to 

other parties and possibly threatened the integrity of the LMP energy markets and the 

FTR allocation to other parties. One of the interim solutions devised by the Midwest ISO 

was to create the GFA “Option B” right.68 The Midwest ISO models this right as an FTR 

obligation in the FTR allocation process, thus allowing it to capture the counterflows 

associated with the rights. However, instead of assigning the FTR obligation to the 

 67 See generally Comments on Staff Paper of APPA; Comments on Staff Paper of 

TAPS. 

68 See section 38.8.3(b), Midwest ISO Open Access Transmission and Energy 

Markets Tariff (TEMT), Second Revised Sheet No. 447. 
Docket Nos. RM06-8-000 and AD05-7-000 - 57 -

 

eligible party, the Midwest ISO holds the right for settlement purposes. The GFA 

Option B holder is required to schedule transmission in the day-ahead market, upon 

which the congestion revenues accumulated by the right are used to “pay” its congestion 

charges; the holder is not assessed negative congestion charges (in most cases, the holder 

of such a right would not schedule power if LMPs were to create negative congestion 

charges, but this might not be foreseeable at all times).69 If there is a revenue 

inadequacy, the Midwest ISO charges uplift to all market participants on a pro-rata basis, 

based on their load ratio share in the Midwest ISO market. This is thus a type of use-orlose right that does not allow the holder to accumulate revenues in excess of congestion 

charges from transmission rights but does not expose the holder to negative congestion 

charges. However, the allocation of such rights is based on system-wide insurance, in the 

form of uplift, to cover any resulting revenue inadequacies. 

82. Also in the Midwest ISO, the Commission created a related type of interim longterm congestion cost hedge for parties in persistent load pockets (called “Narrow 

Constrained Areas” or NCAs) that previously had firm transmission service that covered 

generation resources or contracts outside the load pocket. 70 This is called the “Expanded 

Congestion Cost Hedge.” The concern was that the FTR allocation would not be 

69 Holders of GFA Option B rights are also exempted from marginal loss charges. 

70 See section 43.2.6, Midwest ISO TEMT, Substitute Second Revised Sheet No. 

630. 
Docket Nos. RM06-8-000 and AD05-7-000 - 58 -

sufficient to always cover the quantities of transmission imports covered by these 

parties’ prior transmission rights, thus leaving them potentially exposed to high 

congestion charges (reflecting the expectation that LMPs in a load pocket could be 

substantially higher than LMPs outside the load pocket). In this case, the purpose of the 

right was to provide such parties with a fixed quantity of transmission service covered by 

a congestion hedge, even if such rights were not awarded through the FTR allocation 

process (that is, were not simultaneously feasible with all other nominated FTRs).71 This 

right also requires that the holder schedule through the day-ahead market. Unlike the 

Midwest ISO’s “Option B” GFA, this arrangement does not protect the holder from 

negative congestion charges associated with its allocated FTRs, but it does guarantee that 

the holder will receive revenues from the Midwest ISO sufficient to cover any positive 

congestion charges not covered through its allocated FTRs. If the Midwest ISO 

experiences revenue inadequacy due to these payments, it again charges uplift to all 

market participants on a pro-rata basis, based on their load ratio share in the Midwest ISO 

market. 

 71 This expanded hedge was made available as a market start safeguard for five 

years from the start of the market. Since only one region of the Midwest ISO was 

designated as an NCA at the start of the market, the hedge was also made available 

during the safeguard period for parties in any area subsequently designated as an NCA. 
Docket Nos. RM06-8-000 and AD05-7-000 - 59 -

4. Combining Different Types of Long-Term Firm Transmission 

Rights

83. Most existing transmission organizations do retain some quantity of non-FTR 

transmission rights on their transmission systems, typically grandfathered pre-Order 888 

OATT rights that are treated as physical scheduling rights. In most of these markets, 

these physical transmission rights do not require that a large amount of transmission 

capability is reserved, hence they do not greatly affect the allocation and trading of FTRs. 

However, as noted above, the Midwest ISO has had to accommodate a greater number of 

such rights than other transmission organizations and has done so on an interim basis 

through creation of alternative types of financial rights or other arrangements. It has 

sought to minimize the impact of such rights on the FTR allocation and on the exposure 

of market participants to uplift.

84. In the event that stakeholders’ interests in different types of transmission rights are 

difficult to reconcile, transmission organizations may need to consider the development 

of different types of long-term rights simultaneously. We believe that regional 

stakeholder discussions are the appropriate forum for such decision-making. 

85. If the transmission organization and stakeholders are considering more than one 

type of transmission right, we further encourage them to establish mechanisms by which 

holders of one kind of long-term firm transmission right can convert their rights into 

other rights with other characteristics offered by the transmission organization that rely 

on the same amount of transmission capacity. For example, a long-term right initially 
Docket Nos. RM06-8-000 and AD05-7-000 - 60 -

awarded as an obligation could be subsequently converted to an option. However, 

since more transmission capacity may be necessary to support an option than to support 

and obligation, the holder may receive fewer options than obligations. 

V. Planning and Expansion of Transmission Facilities

86. As noted above, section 217(b)(4) of the FPA requires the Commission to exercise 

its authority “in a manner that facilitates the planning and expansion of transmission 

facilities to meet the reasonable needs of load-serving entities to satisfy the service 

obligations of the load-serving entities.”72 

87. Additionally, many of those commenting on the Staff Paper argued that 

implementation of long-term firm transmission rights will not be possible unless the 

transmission organization has adequate transmission planning and expansion procedures 

in place.73 According to some commenters, the inadequacy of the physical transmission 

system and the lack of a reliable mechanism for transmission organizations to plan and 

require the construction of transmission facilities are the prime impediments to both 

introducing long-term firm transmission rights in the organized electricity markets and 

ensuring that they remain simultaneously feasible over their entire term.74 Several of 

 72 Pub. L. No. 109-58, § 1233, 119 Stat. 594, 958. 

73 See, e.g., Comments on Staff Paper of NRECA at 9-10; Comments on Staff 

Paper of Midwest TDUs at 5; Comments on Staff Paper of ELCON at 3; Comments on 

Staff Paper of National Grid at 1-2 and 9. 

74 See, e.g., Comments on Staff Paper of NRECA at 9; Comments on Staff Paper 

of APPA at 21-22. 
Docket Nos. RM06-8-000 and AD05-7-000 - 61 -

 

those providing comments on the Staff Paper recommended specific attributes that 

should be included in transmission organization planning and expansion procedures.75 

For example, TAPS argues that transmission organizations should have clear authority to 

mandate the construction of transmission facilities by transmission owners or others.76 

Also, commenters asserted that transmission planning and expansion procedures adopted 

by transmission organizations should plan for “economic” upgrades as well as upgrades 

needed for reliability.77 

88. We propose in this NOPR to require that transmission organizations ensure that 

the long-term firm transmission rights they offer remain viable and are not modified or 

curtailed over their entire term. In particular, the proposed guidelines would require that 

transmission organizations guarantee the financial coverage of the long-term firm 

transmission rights over their entire term.78 Accordingly, transmission organizations will 

need to have effective planning and expansion regimes in place, and may need to expand 

the system where necessary to ensure that the long-term firm transmission rights can be 

accommodated over their entire term without modification or curtailment. Without 

75 See, e.g., Comments on Staff Paper of NRECA at 11-13; Comments on Staff 

Paper of City of Santa Clara, California at 18-19; Comments on Staff Paper of APPA, 

attached Concept Paper; Comments on Staff Paper of National Grid at 8-10. 

76 Comments on Staff Paper of TAPS at 32. 

77 See, e.g., Comments on Staff Paper of TAPS at 32; Comments on Staff Paper of 

NRECA at 12; Comments on Staff Paper of National Grid at 10. 

78 See discussion of guideline (2), supra. 
Docket Nos. RM06-8-000 and AD05-7-000 - 62 -

appropriate planning and expansion of the system where necessary, it may be 

difficult to ensure that long-term firm transmission rights remain financially viable 

without significant charges to some set of participants. 

89. While we agree in general with those comments on the Staff Paper that stress the 

necessity of tying the availability of long-term firm transmission rights to adequate 

planning and expansion procedures, we will not propose specific procedures in this 

NOPR. The Commission believes that each transmission organization and its 

stakeholders should develop appropriate methods for ensuring that long-term firm 

transmission rights are supported by adequate planning and expansion procedures. While 

we do not propose specific requirements in this regard, we expect that such planning and 

expansion procedures will be a necessary complement to long-term firm transmission 

rights. The Commission encourages transmission organizations to propose such 

procedures as part of their filings in compliance with the Final Rule in this docket, and 

the Commission will consider them in light of the charge in section 217(b)(4) of the FPA 

that we “facilitate . . . the planning and expansion of transmission facilities to meet the 

reasonable needs of load-serving entities to satisfy the service obligations of the loadserving entities.” We seek additional comments regarding the relationship between longterm firm transmission rights and planning and expansion procedures in the organized 

electricity markets operated by transmission organizations. In particular, we seek 

comment on whether the Commission should require that transmission organizations file 

their transmission planning and expansion procedures and specific plans. We also seek 
Docket Nos. RM06-8-000 and AD05-7-000 - 63 -

comment on whether, alternatively, the Commission should require that 

transmission organizations file such procedures for informational purposes, as a means 

for the Commission to monitor the adequacy of such plans and procedures for ensuring 

the adequacy of long-term firm transmission rights. 

90. Additionally, we note that the pro forma OATT adopted by the Commission in 

Order No. 888 requires public utility transmission providers to expand capacity, if 

necessary, to satisfy the needs of network transmission customers and point-to-point 

transmission service customers.79 In comments submitted in response to the Staff Paper, 

several entities suggested that this obligation does not exist, or is not carried out, in the 

organized electricity markets operated by ISOs and RTOs.80 The Commission’s recent 

Notice of Inquiry concerning the pro forma OATT sought responses from interested 

parties on several specific questions relating to this requirement in the pro forma OATT, 

including; (1) whether this provision has met transmission customers’ needs, and (2) 

whether public utility transmission providers have fulfilled these obligations.81 In this 

proceeding, the Commission seeks comments addressing these questions in the specific 

context of transmission organizations with organized electricity markets that are the 

 79 See pro forma OATT at sections 13.5, 15.4 and 28.2. 

80 See, e.g., Comments on Staff Paper of APPA at 10; Comments on Staff Paper of 

ABATE and Midwest Transmission Customers at 4-6; Comments on Staff Paper of 

Peabody Energy Corporation at 6. 

81 Preventing Undue Discrimination and Preference in Transmission Services, 

Notice of Inquiry, 112 FERC ¶ 61,299 at P 21 (2005) (NOI). 
Docket Nos. RM06-8-000 and AD05-7-000 - 64 -

 

subject of this rulemaking. Where appropriate, responses should address the 

arguments made in response to the Staff Paper, and noted above, concerning the 

obligation of transmission providers to expand capacity to meet the needs of network and 

point-to-point transmission service customers. 

91. The Commission also emphasized in the NOI that it is not proposing to change the 

native load preference established in Order No. 888.82 The Commission sought 

comments, however, on whether the definition of native load service obligation in section 

1233 of EPAct 2005 is the same as the approach the Commission took in Order No. 

888.83 In this docket, the Commission seeks comments on this question with particular 

emphasis on how the native load preference has been applied in the organized electricity 

markets that are the subject of this rulemaking. 

92. Finally, many of the comments received on the Staff Paper stressed a need for 

appropriate incentives for transmission organizations, transmission owners and market 

participants to construct needed upgrades and expansions to the transmission system. As 

we discuss above, the potential for additional charges in ensuring that the financial 

coverage of the long-term firm transmission rights remains intact for their entire term 

should provide an incentive for planning and expanding the transmission system. 

Additionally, we note that in Docket No. RM06-4-000, the Commission issued a NOPR 

82 Id. at P 9. 

83 Id. 
Docket Nos. RM06-8-000 and AD05-7-000 - 65 -

proposing amendments to the Commission’s existing regulations to promote reliable 

and economically efficient transmission and generation of electricity by providing 

incentives for increased capital investment in transmission facilities.84 The Commission 

will consider the issues surrounding appropriate incentives for expansion of transmission 

facilities in that rulemaking. 

VI. Proposed Compliance Procedures

93. The Commission proposes to direct each public utility that is a transmission 

organization with an organized electricity market, within 180 days of the publication of a 

Final Rule in the Federal Register, to either: (1) file with the Commission tariff sheets 

and rate schedules that make available long-term firm transmission rights that are 

consistent with the guidelines set forth in section (d) of the Final Rule; or (2) file with the 

Commission an explanation of how its current tariff and rate schedules already provide 

for long-term firm transmission rights that are consistent with the guidelines set forth in 

paragraph (d) of the Final Rule. The Commission intends that during this 180-day time 

period, such transmission organizations will work with their stakeholders to develop a 

long-term firm transmission right that will harmonize the prevailing market design with 

the guidelines set forth in this Final Rule. We do not propose any specific stakeholder 

process, and intend that the transmission organization will use its usual process for 

 84 See Promoting Transmission Investment Through Pricing Reform, Notice of 

Proposed Rulemaking, 113 FERC ¶ 61,182 (2005). 
Docket Nos. RM06-8-000 and AD05-7-000 - 66 -

receiving stakeholder input and filing tariff changes with the Commission. For any 

transmission organization that is approved by the Commission after the 180-day time 

period, the Commission proposes that the transmission organization satisfy the 

requirements set forth in this rule before commencing operation. 

VII. Information Collection Statement

94. The Office of Management and Budget (OMB) regulations require approval of 

certain information collection requirements imposed by agency rules.85 Upon approval 

of a collection(s) of information, OMB will assign an OMB control number and an 

expiration date. Respondents subject to the filing requirements of this rule will not be 

penalized for failing to respond to these collections of information unless the collections 

of information display a valid OMB control number. This NOPR amends the 

Commission’s regulations to implement some of the statutory provisions of section 1233 

of EPAct 2005. Particularly, section 1233 of EPAct 2005 enacts a new section 217 of 

the FPA. New section 217(b)(4) requires the Commission to exercise its authority in a 

manner that facilitates the planning and expansion of transmission facilities to meet the 

reasonable needs of load-serving entities to satisfy their service obligations, and enables 

load-serving entities to secure long-term firm transmission rights to meet their service 

obligations. Section 1233(b) of EPAct 2005 directs that Commission to, by rule or order, 

implement this new provision in the FPA. This proposed rule would require transmission 

 85 5 CFR 1320.13 (2005). 
Docket Nos. RM06-8-000 and AD05-7-000 - 67 -

organizations with organized electricity markets to either file tariff sheets making 

long-term firm transmission rights available that are consistent with guidelines 

established by the Commission, or to make a filing explaining how their existing tariffs 

already provide long-term firm transmission rights that are consistent with the guidelines. 

Such filings would be made under Part 35 of the Commission’s regulations. The 

information provided for under Part 35 is identified as FERC-516. 

95. The Commission is submitting these reporting requirements to OMB for its review 

and approval under section 3507(d) of the Paperwork Reduction Act.86 Comments are 

solicited on the Commission’s need for this information, whether the information will 

have practical utility, the accuracy of provided burden estimates, ways to enhance the 

quality, utility, and clarity of the information to be collected, and any suggested methods 

for minimizing the respondent’s burden, including the use of automated information 

techniques. 

Burden Estimate: The Public Reporting burden for the requirements contained in the 

NOPR is as follows: 

 86 44 U.S.C. 3507(d) (2000). 
Docket Nos. RM06-8-000 and AD05-7-000 - 68 -

Data Collection 

Number of 

Respondents 

No. of 

Responses 

Hours Per 

Response 

Total Annual 

Hours 

FERC-516 

Transmission 

Organizations 

with Organized 

Electricity 

Markets 

 6 1 1180 7,080 

Total Annual hours for Collection: (Reporting + recordkeeping, (if appropriate) = 7,080 

hours. 

Information Collection Costs: The Commission seeks comments on the costs to comply 

with these requirements. It has projected the average annualized cost to be the total 

annual hours of 7,080 times $150 = $1,062,000. 

Title: FERC-516 “Electric Rate Schedule Filings” 

Action: Proposed Collections 

OMB Control No: 1902-0096 

Respondents: Business or other for profit, and/or not for profit institutions. 

Frequency of Responses: One time to initially comply with the rule, and then on 

occasion as needed to revise or modify. 

Necessity of the Information: This proposed rule, if adopted, would implement the 

Congressional mandate of the Energy Policy Act of 2005 to make long-term transmission 

rights available in transmission organizations with organized electricity markets. This 

mandate addresses an identified need for transmission organizations with organized 

electricity markets to provide longer-term transmission rights that can aid load-serving 
Docket Nos. RM06-8-000 and AD05-7-000 - 69 -

entities in financing long-term power supply arrangements to meet their service 

obligations. Making long-term firm transmission rights available will also provide 

increased certainty regarding the long-term costs of transmission service in organized 

electricity markets. As a result, long-term firm transmission rights will allow loadserving entities to more effectively plan their power supply portfolios, and encourage 

load-serving entities and other participants in organized electricity markets to make longterm investments in power supply arrangements. 

Internal review: The Commission has reviewed the requirements pertaining to 

transmission organizations with organized electricity markets and determined the 

proposed requirements are necessary to meet the statutory provisions of the Energy 

Policy Act of 2005. 

96. These requirements conform to the Commission’s plan for efficient information 

collection, communication and management within the energy industry. The 

Commission has assured itself, by means of internal review, that there is specific, 

objective support for the burden estimates associated with the information requirements. 

97. Interested persons may obtain information on the reporting requirements by 

contacting: Federal Energy Regulatory Commission, 888 First Street, N.E., Washington, 

D.C. 20426 [Attention: Michael Miller, Office of the Executive Director, Phone: 

(202) 502-8415, fax: (202) 273-0873, e-mail: michael.miller@ferc.gov]. Comments on 

the requirements of the proposed rule may also be sent to the Office of Information and 

Regulatory Affairs, Office of Management and Budget, Washington, D.C. 20503 
Docket Nos. RM06-8-000 and AD05-7-000 - 70 -

[Attention: Desk Officer for the Federal Energy Regulatory Commission], e-mail: 

oira_submission@omb.eop.gov. 

VIII. Environmental Analysis

98. The Commission is required to prepare an Environmental Assessment or an 

Environmental Impact Statement for any action that may have a significant adverse effect 

on the human environment.87 The Commission has categorically excluded certain 

actions from this requirement as not having a significant effect on the human 

environment. Included in the exclusion are rules that do not substantially change the 

effect of legislation.88 The rule proposed in this NOPR falls within this categorical 

exemption because it implements the requirements of EPAct 2005 relating to long-term 

firm transmission rights in organized electricity markets. Accordingly, neither an 

environmental impact statement nor environmental assessment is required. 

IX. Regulatory Flexibility Act Certification

99. The Regulatory Flexibility Act of 198089 generally requires a description and 

analysis of rules that will have significant economic impact on a substantial number of 

small entities. Most, if not all, of the transmission organizations to which the 

 87 Regulations Implementing the National Environmental Policy Act, Order No. 

486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. Preambles 1986-1990 ¶ 30,783 

(1987). 

88 18 C.F.R. § 380.4(2)(ii) (2005). 

89 5 U.S.C. §§ 601-12 (2000). 
Docket Nos. RM06-8-000 and AD05-7-000 - 71 -

requirements of this rule would apply do not fall within the definition of small 

entities.90 Therefore, the Commission certifies that this rule will not have a significant 

economic impact on a substantial number of small entities. Accordingly, no regulatory 

flexibility analysis is required. 

X. Comment Procedures

100. The Commission invites interested persons to submit comments on the matters and 

issues proposed in this notice to be adopted, including any related matters or alternative 

proposals that commenters may wish to discuss. Comments are due March 13, 2006. 

Reply comments are due March 27, 2006. Comments and reply comments must refer to 

Docket No. RM06-8-000,91 and must include the commenter's name, the organization 

they represent, if applicable, and their address in their comments. Comments and reply 

comments may be filed either in electronic or paper format. 

101. Comments and reply comments may be filed electronically via the eFiling link on 

the Commission's web site at http://www.ferc.gov. The Commission accepts most 

standard word processing formats and commenters may attach additional files with 

 90 The RFA definition of “small entity” refers to the definition provided in the 

Small Business Act, which defines a “small business concern” as a business that is 

independently owned and operated and that is not dominant in its field of operation. See

15 U.S.C. § 632 (2000). 

91 While we are issuing this NOPR in both Docket No. RM06-8-000 and Docket 

No. AD05-7-000, we expect to issue our Final Rule in only Docket No. RM06-8-000. 

Comments in response to this NOPR should be filed in Docket No. RM06-8-000 only. 
Docket Nos. RM06-8-000 and AD05-7-000 - 72 -

supporting information in certain other file formats. Commenters filing 

electronically do not need to make a paper filing. Commenters that are not able to file 

comments and reply comments electronically must send an original and 14 copies of their 

comments to: Federal Energy Regulatory Commission, Office of the Secretary, 888 First 

Street, N.E., Washington, D.C., 20426. 

102. All comments and reply comments will be placed in the Commission's public files 

and may be viewed, printed, or downloaded remotely as described in the Document 

Availability section below. Commenters on this proposal are not required to serve copies 

of their comments and reply comments on other commenters. 

XI. Document Availability

103. In addition to publishing the full text of this document in the Federal Register, the 

Commission provides all interested persons an opportunity to view and/or print the 

contents of this document via the Internet through the Commission’s Home Page 

(http://www.ferc.gov) and in the Commission’s Public Reference Room during normal 

business hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, N.E., Room 2A, 

Washington D.C. 20426. 

104. From the Commission's Home Page on the Internet, this information is available in 

the Commission’s document management system, eLibrary. The full text of this 

document is available on eLibrary in PDF and Microsoft Word format for viewing, 

printing, and/or downloading. To access this document in eLibrary, type the docket 

number excluding the last three digits of this document in the docket number field. 
Docket Nos. RM06-8-000 and AD05-7-000 - 73 -

105. User assistance is available for eLibrary and the Commission's website 

during normal business hours. For assistance, please contact FERC Online Support at 1-

866-208-3676 (toll free) or (202)502-8222 (e-mail at FERCOnlineSupport@FERC.gov), 

or the Public Reference Room at (202) 502-8371, TTY (202)502-8659 (e-mail at 

public.referenceroom@ferc.gov ). 

List of Subjects in 18 C.F.R. Part 40

Electric power rates; Electric utilities. 

By direction of the Commission. 

 Magalie R. Salas, 

 Secretary. 

 
In consideration of the foregoing, the Commission proposes to amend Subchapter 

B, Chapter I, Title 18, Code of Federal Regulations, by adding a new Part 40 as follows: 

* * * * * 

SUBCHAPTER B – REGULATIONS UNDER THE FEDERAL POWER ACT 

* * * * * 

PART 40 – LONG-TERM FIRM TRANSMISSION RIGHTS IN ORGANIZED 

ELECTRICITY MARKETS 

Sec. 

40.1 – Requirement that Transmission Organizations with Organized Electricity Markets 

offer Long-Term Transmission Rights

 AUTHORITY: 16 U.S.C. § 791a – 825r and section 217 of the Federal Power Act, 

16 U.S.C. §____. 

§ 40.1 Requirement that Transmission Organizations with Organized Electricity 

Markets Offer Long-Term Transmission Rights.

 (a) Purpose. This section requires a transmission organization with one or more 

organized electricity markets (administered either by it or by another entity) to make 

available long-term firm transmission rights, pursuant to section 217(b)(4) of the Federal 

Power Act, that satisfy the guidelines set forth in paragraph (d) of this section. This 

section does not require that a specific type of long-term firm transmission right be made 

available, and is intended to permit transmission organizations flexibility in satisfying the 

guidelines set forth in paragraph (d) of this section. 
Docket No. RM05-4-000 - 2 - 

 (b) Definitions. As used in this section: 

 (1) Transmission Organization means a Regional Transmission Organization, 

Independent System Operator, independent transmission provider, or other independent 

transmission organization finally approved by the Commission for the operation of 

transmission facilities. 

 (2) Load-serving entity means a distribution utility or an electric utility that has a 

service obligation. 

 (3) Service obligation means a requirement applicable to, or the exercise of authority 

granted to, an electric utility under Federal, State, or local law or under long-term 

contracts to provide electric service to end-users or to a distribution utility. 

 (4) Organized Electricity Market means an auction-based market where a single entity 

receives offers to sell and bids to buy electric energy and/or ancillary services from 

multiple sellers and buyers and determines which sales and purchases are completed and 

at what prices, based on formal rules contained in Commission-approved tariffs, and 

where the prices are used by a transmission organization for establishing transmission 

usage charges. 

 (5) Long-term power supply arrangements means the ownership of generation facilities, 

rights to market the output of Federal generation facilities with a term of longer than one 

year, or rights under one or more wholesale contracts to purchase electric energy with a 

term of longer than one year, for the purpose of meeting a service obligation. 

 (c) General rule. 
 (1) Every public utility that is a transmission organization and that owns, operates or 

controls facilities used for the transmission of electric energy in interstate commerce and 

has one or more organized electricity markets (administered either by it or by another 

entity) must file with the Commission, no later than [INSERT DATE 180 DAYS 

AFTER PUBLICATION OF FINAL RULE IN THE FEDERAL REGISTER], one 

of the following: 

 (i) Tariff sheets and rate schedules that make available long-term firm transmission 

rights that are consistent with the guidelines set forth in paragraph (d) of this section; or 

 (ii) An explanation of how its current tariff and rate schedules already provide for longterm firm transmission rights that are consistent with the guidelines set forth in paragraph 

(d) of this section. 

 (2) Any transmission organization that is approved by the Commission for operation 

after [INSERT DATE 180 DAYS AFTER PUBLICATION OF FINAL RULE IN 

THE FEDERAL REGISTER] and has one or more organized electricity markets 

(administered either by it or by another entity) must satisfy this general rule before 

commencing operation. 

 (d) Guidelines for Design and Administration of Long-term Firm Transmission Rights. 

Transmission organizations subject to paragraph (c) of this section must make available 

long-term firm transmission rights that satisfy the following guidelines: 

 (1) The long-term firm transmission right should specify a source (injection node or 

nodes) and sink (withdrawal node or nodes), and a quantity (MW). 

 (2) The long-term firm transmission right must provide a hedge against day-ahead 
locational marginal pricing congestion charges (or other direct assignment of congestion 

costs) for the period covered and quantity specified. Once allocated, the financial 

coverage provided by the right should not be modified during its term except in the case 

of extraordinary circumstances or through voluntary agreement of both the holder of the 

right and the transmission organization. 

 (3) Long-term firm transmission rights made feasible by transmission upgrades or 

expansions must be available upon request to any party that pays for such upgrades or 

expansions in accordance with the transmission organization’s prevailing cost allocation 

methods for upgrades or expansions. The term of the rights should be equal to the life of 

the facility (or facilities) or a lesser term requested by the party paying for the upgrade or 

expansion. 

 (4) Long-term firm transmission rights must be made available with terms (and/or 

rights to renewal) that are sufficient to meet the needs of load-serving entities to hedge 

long-term power supply arrangements made or planned to satisfy a service obligation. 

The length of term of renewals may be different from the original term. 

 (5) Load-serving entities with long-term power supply arrangements to meet a service 

obligation must have priority to existing transmission capacity that supports long-term 

firm transmission rights requested to hedge such arrangements. 

 (6) A long-term transmission right held by a load-serving entity to support a service 

obligation should be re-assignable to another entity that acquires that service obligation. 
 (7) The initial allocation of the long-term firm transmission rights shall not require 

recipients to participate in an auction. 

 (8) Allocation of long-term firm transmission rights should balance any adverse 

economic impact between participants receiving and not receiving the right.