Federal Register / Vol. 71, No. 27 / Thursday, February 9, 2006 / Proposed Rules

Federal Register / Vol. 71, No. 27 / Thursday, February 9, 2006 / Proposed Rules

intended to prevent centrifugal compressor

intake wheel blade cracks, which can result

in engine in-flight power loss, engine

shutdown, or forced landing.

Compliance

(e) You are responsible for having the

actions required by this AD performed within

the compliance times specified unless the

actions have already been done.

Engine Modification Before Further Flight

(f) For engines modified to the TU 197

standard but not to the TU 191 or TU 224

standard, before further flight, remove the TU

197 standard and install the TU 224

standard.

Initial Inspections

(g) For all engines, borescope-inspect, and

either eddy current-inspect (ECI) or

6693

ultrasonic-inspect (UI) the centrifugal

compressor intake wheel blades using

paragraphs 2.B.(1)(a) through 2.B.(1)(g) of

Turbomeca Mandatory Service Bulletin A249

72 0100, Update No. 5, dated February 25,

2005, and the criteria in the following Table

1:

TABLE 1.—INSPECTION CRITERIA

If engine modification level is:

(1) Pre TU 191 and Pre TU 224 ....

Then borescope-inspect centrifugal compressor intake wheel

blades:

Were traces of corrosion found at

borescope-inspection?

Then confirm corrosion by performing ECI or UI within:

Within 200 flight hours-since-last

inspection.

(i) Yes ...........................................

Six months-or 50 flight hourssince-borescope

inspection,

whichever occurs first.

Two hundred flight hours-sinceborescope inspection.

Six months-or 50 flight hourssince-borescope

inspection,

whichever occurs first.

One thousand flight hours-sinceborescope inspection.

(ii) No ............................................

(2) Post TU 191 or Post TU 224 ...

Within 1,000 flight hours-since-last

inspection.

(i) Yes ...........................................

(ii) No ............................................

(h) Thereafter, perform repetitive

inspections using the criteria in Table 1 of

this AD.

(i) Remove centrifugal compressor intake

wheel blades confirmed cracked or pitted.

(j) The Manager, Engine Certification

Office, has the authority to approve

alternative methods of compliance for this

AD if requested using the procedures found

in 14 CFR 39.19.

Related Information

(k) Direction Generale de L’Aviation Civile

airworthiness directive F–2005–037, dated

March 2, 2005, also addresses the subject of

this AD.

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BILLING CODE 4910–13–P

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Federal Energy Regulatory

Commission

18 CFR Part 40

Alternative Methods of Compliance

Issued in Burlington, Massachusetts, on

February 3, 2006.

Peter A. White,

Acting Manager, Engine and Propeller

Directorate, Aircraft Certification Service.

[FR Doc. E6–1768 Filed 2–8–06; 8:45 am]

DEPARTMENT OF ENERGY

[Docket Nos. RM06–8–000 and AD05–7–000]

Long-Term Firm Transmission Rights

in Organized Electricity Markets; LongTerm 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, Public Law No. 109–58, section

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

DATES: Comments are due March 13,

2006. Reply comments are due March

27, 2006.

FOR FURTHER INFORMATION CONTACT:

Udi E. Helman (Technical Information),

Office of Energy Markets and

Reliability, Federal Energy Regulatory

Commission, 888 First Street, NE.,

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Washington, DC 20426, (202) 502–

8080.

Roland Wentworth (Technical

Information), Office of Energy Markets

and Reliability, Federal Energy

Regulatory Commission, 888 First

Street, NE., Washington, DC 20426,

(202) 502–8262.

Wilbur C. Earley (Technical

Information), Office of Energy Markets

and Reliability, Federal Energy

Regulatory Commission, 888 First

Street, NE., Washington, DC 20426,

(202) 502–8087.

Harry Singh (Technical Information),

Office of Market Oversight and

Investigations, Federal Energy

Regulatory Commission, 888 First

Street, NE., Washington, DC 20426,

(202) 502–6341.

Jeffery S. Dennis (Legal Information),

Office of the General Counsel, Federal

Energy Regulatory Commission, 888

First Street, NE., Washington, DC

20426, (202) 502–6027.

SUPPLEMENTARY INFORMATION:

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

1 Pub. L. 109–58, 119 Stat. 594 (2005).

2 Pub. L. 109–58, § 1233(b), 119 Stat. 594, 960.

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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 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 loadserving 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:

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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

organizations with organized electricity

markets 5 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 long3 Pub. L. 109–58, section 1233, 119 Stat. 594, 958.

4 Id. at 960.

5 See ‘‘Definitions’’ below.

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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 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

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on whether these definitions are

appropriate.

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.

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 loadserving 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

6 Pub. L. No. 109–58, section 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.

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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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

we develop in this proceeding to apply

to any transmission organization with a

day-ahead 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.

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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 supply arrangements.’’

Specifically, we propose to define

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, section 1233, 119 Stat. 594,

958 (emphasis added).

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‘‘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 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

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).

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.

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6695

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 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.

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

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).

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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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

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B. Currently Available Transmission

Rights

15. In recent years, interest in longterm 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

24 See infra at P 21–22.

25 See infra at P 23–28.

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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. Longterm 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 (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 pointto-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 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,

26 See 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.

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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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 non-discriminatory basis to the extent

practicable and consistent with good

utility practice, with firm service having

the highest priority and non-firm

generally having the lowest priority.

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 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-topoint transmission service even when

the transmission provider must

redispatch its generators to honor the

firm service commitment. If the loadserving 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 Commissionapproved 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.

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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 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.

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

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.

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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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 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

feasibility test, their availability is

limited.33 Therefore, for purposes of the

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.

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.

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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 load-serving entities and

others that pay access charges or fixed

transmission rates. Load-serving 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 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 re34 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 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.

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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 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 long-term 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 (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

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markets. In regions where transmission

service is provided under the OATT, a

transmission customer that takes

network service or firm point-to-point

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.

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 loadserving 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 loadserving 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 pricebased 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

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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.

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 longterm transmission rights 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 longterm transmission rights with terms in

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.

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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.

36. Most of the parties in this first

group stressed that not all transmission

capacity should be given over to longterm rights, but that there should be an

amount sufficient to cover at least baseload 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 rights 40 or

modified FTRs (e.g. financial rights with

physical characteristics, such as ‘‘useor-lose’’ rights) designed to alter the

financial settlement properties of

traditional FTRs so as to reduce

congestion risk.41

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.

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

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37. A second group of commenters

largely agreed with the first that longterm 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 longterm FTRs for at least an initial period.

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 longAmerican 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.

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.

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.

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6699

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 long-term 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

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 markets 44 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

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.

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establishing guidelines for the design

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

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 loadserving entities with long-term power

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.

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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 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 point-to-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 guideline is not

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

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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 longterm 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 long-term 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 longterm power supply arrangements are at

risk of having the ARRs or FTRs that

they are eligible for to hedge congestion

charges associated with 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

amount of capacity between its network resources

and network loads.

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 longterm basis’’ (emphasis added).

49 Comments on Staff Paper of APPA at 21.

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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 longterm 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

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. Also, there may be extraordinary

circumstances under which the

50 We discuss this issue in Section V, infra.

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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 long-term 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

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

long-term 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

51 See pro forma OATT at sections 13.5, 15.4 and

28.2.

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6701

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.

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 long-term 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 ‘‘long-term.’’

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

54. Other commenters argued that the

initial assignment of long-term rights

should consider much longer timeframes, 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 longterm rights consistent with its

specifications should be made available

for 10 year terms with the unconditional

52 See infra at P 58–61.

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.

55 See Comments on Staff Paper of NRECA at 18.

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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 loadserving entities 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 longterm 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

56 See Comments on Staff Paper of TAPS at 19–

21.

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57 See Comments on Staff Paper of APPA at 33.

58 We expect that transmission organizations will

develop their proposals in consultation with

stakeholders.

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.

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arrangements made, or planned, to meet

their service obligations. Hence, this

guideline would require that

transmission organizations with

organized electricity markets offer longterm 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

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 longterm 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 longterm power supply arrangement. In

addition, the transmission organization

60 The ability to renew the long-term firm

transmission rights will also help ensure that term

lengths will be appropriate.

61 This NOPR also explores transmission

planning and expansion in Section V, infra.

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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 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 longterm 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

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transmission organizations to adopt

limits on the amount of capacity they

will allocate to long-term rights before

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 loadserving 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 load-serving

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.

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Guideline (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.

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 loadserving 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

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6703

load-serving entity.62 Specifically,

section 217(b)(3)(A) provides:

require recipients to participate in an

auction.

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.

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 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.

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 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 longterm 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

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.

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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 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

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.

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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.

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 longterm 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 loadserving 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.

65 See supra at P 63.

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70. We seek comment on ways that

transmission organizations may balance

any adverse economic impacts of

allocating long-term firm transmission

rights between 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: longterm 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.

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

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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 load-serving 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 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

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rights without the likelihood of negative

payment obligations.

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 longterm 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.

2. Long-Term FTR Options

77. For many parties seeking longterm 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

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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.

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 longterm 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 physical and financial

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.

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6705

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 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 useor-lose 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

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.

69 Holders of GFA Option B rights are also

exempted from marginal loss charges.

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uplift, to cover any resulting revenue

inadequacies.

82. Also in the Midwest ISO, the

Commission created a related type of

interim long-term 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 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.

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4. Combining Different Types of LongTerm 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

70 See section 43.2.6, Midwest ISO TEMT,

Substitute Second Revised Sheet No. 630.

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.

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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 decisionmaking.

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 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 an 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

72 Pub. L. 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.

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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 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 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

74 See, e.g., Comments on Staff Paper of NRECA

at 9; Comments on Staff Paper of APPA at 21–22.

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.

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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 load-serving

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 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

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.

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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 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

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.

81 Preventing Undue Discrimination and

Preference in Transmission Services, Notice of

Inquiry, 112 FERC ¶ 61,299 at P 21 (2005) (NOI).

82 Id. at P 9.

83 Id.

84 See Promoting Transmission Investment

Through Pricing Reform, Notice of Proposed

Rulemaking, 113 FERC ¶ 61,182 (2005).

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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 longterm 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 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 loadserving entities to secure long-term firm

transmission rights to meet their service

85 5 CFR 1320.13 (2005).

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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 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:

Data collection

Number of

respondents

Number 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 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, longterm firm transmission rights will allow

load-serving entities to more effectively

plan their power supply portfolios, and

encourage load-serving entities and

other participants in organized

electricity markets to make long-term

investments in power supply

arrangements.

86 44 U.S.C. 3507(d) (2000).

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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, NE. Washington, DC 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, DC 20503 [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

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).

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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

1980 89 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 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

88 18 CFR 380.4(2)(ii) (2005).

89 5 U.S.C. 601–12 (2000).

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.

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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 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, NE., Washington, DC,

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.

8371, TTY (202) 502–8659 (e-mail at

public.referenceroom@ferc.gov).

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 p.m.

eastern time) at 888 First Street, NE.,

Room 2A, Washington, DC 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.

105. User assistance is available for

eLibrary and the Commission’s Web site

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–

(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.

(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.

RM06–8–000. Comments in response to this NOPR

should be filed in Docket No. RM06–8–000 only.

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List of Subjects in 18 CFR 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.

§ 40.1 Requirement that Transmission

Organizations with Organized Electricity

Markets Offer Long-Term Transmission

Rights.

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(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 long-term 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 longterm 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-

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Federal Register / Vol. 71, No. 27 / Thursday, February 9, 2006 / Proposed Rules

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 loadserving 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 longterm 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 reassignable to another entity that

acquires that service obligation.

(7) The initial allocation of the longterm 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.

[FR Doc. 06–1195 Filed 2–8–06; 8:45 am]

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DEPARTMENT OF HEALTH AND

HUMAN SERVICES

Food and Drug Administration

21 CFR Part 888

[Docket No. 2006N–0019]

Orthopedic Devices; Reclassification

of the Intervertebral Body Fusion

Device

AGENCY: Food and Drug Administration,

HHS.

ACTION: Proposed rule.

SUMMARY: The Food and Drug

Administration (FDA) is proposing to

reclassify intervertebral body fusion

devices that contain bone grafting

material, from class III (premarket

approval) into class II (special controls),

and retain those that contain any

therapeutic biologic (e.g., bone

morphogenic protein) in class III.

Elsewhere in this issue of the Federal

Register, FDA is announcing the

availability of a draft guidance

document that would serve as the

special control if FDA reclassifies this

device. The agency is proposing this

reclassification based on the

recommendation of the Orthopaedic and

Rehabilitation Devices Panel (the Panel).

DATES: Submit written or electronic

comments by May 10, 2006. See section

X of this document for the proposed

effective date of a final rule based on

this proposed rule.

ADDRESSES: You may submit comments,

identified by Docket No. 2006N–0019,

by any of the following methods:

Electronic Submissions

Submit electronic comments in the

following ways:

• Federal eRulemaking Portal: http://

www.regulations.gov. Follow the

instructions for submitting comments.

• Agency Web site: http://

www.fda.gov/dockets/ecomments.

Follow the instructions for submitting

comments on the agency Web site.

Written Submissions

Submit written submissions in the

followings ways:

• FAX: 301–827–6870.

• Mail/Hand delivery/courier (for

paper, disk, or CD–ROM submissions):

Division of Dockets Management (HFA–

305), Food and Drug Administration,

5630 Fishers Lane, rm. 1061, Rockville,

MD 20852.

To ensure more timely processing of

comments, FDA is no longer accepting

comments submitted to the agency by email. FDA encourages you to continue

to submit electronic comments by using

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the Federal eRulemaking Portal or the

agency Web site, as described in the

Electronic Submissions portion of this

paragraph.

Instructions: All submissions received

must include the agency name and

docket number for this rulemaking. All

comments received may be posted

without change to http://www.fda.gov/

ohrms/dockets/default.htm, including

any personal information provided. For

additional information on submitting

comments, see the ‘‘Comments’’ heading

of the SUPPLEMENTARY INFORMATION

section of this document.

Docket: For access to the docket to

read background documents or

comments received, go to http://

www.fda.gov/ohrms/dockets/

default.htm and insert the docket

number, found in brackets in the

heading of this document, into the

‘‘Search’’ box and follow the prompts

and/or go to the Division of Dockets

Management, 5630 Fishers Lane, rm.

1061, Rockville, MD 20852.

FOR FURTHER INFORMATION CONTACT: Jodi

N. Anderson, Center for Devices and

Radiological Health (HFZ–410), Food

and Drug Administration, 9200

Corporate Blvd., Rockville, MD 20850,

301–594–2036, ext. 186.

SUPPLEMENTARY INFORMATION:

I. Background (Regulatory Authorities)

The Federal Food, Drug, and Cosmetic

Act (the act) (21 U.S.C. 301 et seq.), as

amended by the Medical Device

Amendments of 1976 (the 1976

amendments) (Public Law 94–295), the

Safe Medical Devices Act of 1990

(Public Law 101–629), the Food and

Drug Administration Modernization Act

of 1997 (Public Law 105–115), and the

Medical Device User Fee and

Modernization Act of 2002 (Public Law

107–250), established a comprehensive

system for the regulation of medical

devices intended for human use.

Section 513 of the act (21 U.S.C. 360c)

established three categories (classes) of

devices, depending on the regulatory

controls needed to provide reasonable

assurance of their safety and

effectiveness. The three categories of

devices are class I (general controls),

class II (special controls), and class III

(premarket approval).

Under section 513 of the act, devices

that were in commercial distribution

before May 28, 1976 (the date of

enactment of the 1976 amendments),

generally referred to as preamendments

devices, are classified after FDA has

done the following: (1) Received a

recommendation from a device

classification panel (an FDA advisory

committee); (2) published the panel’s

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