[Federal Register Volume 71, Number 27 (Thursday, February 9, 2006)]
[Proposed Rules]
[Pages 6693-6710]
From the Federal Register Online via the Government Publishing Office [www.gpo.gov]
[FR Doc No: 06-1195]


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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 40

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


Long-Term Firm Transmission Rights in Organized Electricity 
Markets; Long-Term Transmission Rights in Markets Operated by Regional 
Transmission Organizations and Independent System Operators

February 2, 2006.
AGENCY: Federal Energy Regulatory Commission.

ACTION: Notice of Proposed Rulemaking.

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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., 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

[[Page 6694]]

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.
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    \1\ Pub. L. 109-58, 119 Stat. 594 (2005).
    \2\ Pub. L. 109-58, Sec.  1233(b), 119 Stat. 594, 960.
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    2. New section 217(b)(4) of the FPA provides:

    The Commission shall exercise the authority of the Commission 
under this Act in a manner that facilitates the planning and 
expansion of transmission facilities to meet the reasonable needs of 
load-serving entities to satisfy the service obligations of the 
load-serving entities, and enables load-serving entities to secure 
firm transmission rights (or equivalent tradable or financial 
rights) on a long-term basis for long-term power supply arrangements 
made, or planned, to meet such needs.\3\

    Section 1233(b) of EPAct 2005 requires:

    Within 1 year after the date of enactment of this section and 
after notice and an opportunity for comment, the Commission shall by 
rule or order, implement section 217(b)(4) of the Federal Power Act 
in Transmission Organizations, as defined by that Act with organized 
electricity markets.\4\
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    \3\ Pub. L. 109-58, section 1233, 119 Stat. 594, 958.
    \4\ Id. at 960.

    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 long-
term firm transmission rights be made available to all transmission 
customers, in the event that a transmission organization cannot 
accommodate all requests for long-term firm transmission rights over 
existing transmission capacity, we propose to require that a preference 
be given to load-serving entities with long-term power supply 
arrangements used to meet service obligations. The other properties we 
believe long-term firm transmission rights must have are discussed in 
the proposed guidelines below. These guidelines will give transmission 
organizations, in consultation with market participants, the 
flexibility to propose alternative designs that reflect regional 
preferences and accommodate the regional market design, while also 
ensuring that the objectives of Congress expressed in new section 
217(b)(4) of the FPA are met.
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    \5\ See ``Definitions'' below.
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    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 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.
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    \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.
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B. Load-Serving Entity and Service Obligation

    7. The Commission proposes to define the terms ``load-serving 
entity'' and ``service obligation,'' for purposes of the proposed rule, 
exactly as they are defined in section 217 of the FPA. Specifically, we 
propose to define load-serving entity to mean ``a distribution utility 
or electric utility that has a service obligation.'' \9\ We propose to 
define service obligation to mean ``a requirement applicable to, or the 
exercise of authority granted to, an electric utility under Federal, 
State or local law or under long-term contracts to provide electric 
service to end-users or to a distribution utility.'' \10\ We seek 
comment on whether it is necessary to

[[Page 6695]]

expand or clarify these definitions in the Final Rule.
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    \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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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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    \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.
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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 ``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\
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    \12\ Pub. L. No. 109-58, section 1233, 119 Stat. 594, 958 
(emphasis added).
    \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.
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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\
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    \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.
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    11. In addition, the Commission found in Order No. 888 that 
Independent System Operators (ISOs) had the potential to aid in 
remedying undue discrimination and accomplishing comparable access.\16\ 
To guide the voluntary development of ISOs, Order No. 888 set forth 11 
principles for assessing ISO proposals submitted to the Commission.\17\ 
Following Order No. 888, several voluntary ISOs were established and 
approved by the Commission.
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    \16\ Order No. 888 at 31,655; Order No. 888-A at 30,184.
    \17\ Order No. 888 at 31,730.
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    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\
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    \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.
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    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.
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    \22\ Id. at 31,046 et seq.
    \23\ Id. at 31,106 et seq.
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    14. Most of the RTOs and ISOs operate organized markets for energy 
and/or ancillary services in addition to providing transmission service 
under a single transmission tariff. As described in more detail below, 
most of these markets utilize a congestion management system based on

[[Page 6696]]

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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    \24\ See infra at P 21-22.
    \25\ See infra at P 23-28.
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B. Currently Available Transmission Rights

    15. In recent years, interest in long-term transmission rights in 
organized electricity markets has increased, stemming in large part 
from a desire of some market participants to obtain rights that 
replicate the transmission service that was available to them prior to 
the formation of the organized electricity markets and remains 
available today in regions without organized electricity markets. The 
principal concern of these market participants is the inability to 
obtain a fixed, long-term level of service under pricing arrangements 
that hedge the congestion cost risk that they face in the organized 
electricity markets. This section describes the transmission rights 
that are available in regions with and without organized electricity 
markets, and concludes with a comparison of the two types of rights.
1. Transmission Rights in Regions Without Organized Electricity Markets
    16. In general, in regions without organized electricity markets, 
transmission service is provided to customers under the terms of the 
Order No. 888 OATT, or under terms of contracts that predate the OATT. 
The OATT offers two types of transmission service: Network integration 
transmission service (network service), which is a long-term firm 
transmission service, and point-to-point transmission service, which is 
available on a firm or non-firm basis and on a long-term (one year or 
longer) or short-term basis. Long-term firm transmission customers 
taking service under the OATT have the right to continue to take 
transmission service from the transmission provider when their contract 
expires (rollover right). Transmission providers are required to expand 
facilities to satisfy network and point-to-point customer needs.\26\
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    \26\ See Order No. 888 pro forma OATT at sections 13.5, 15.4 and 
28.2.
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    17. Firm point-to-point transmission service provides for the 
transmission of energy between designated points of receipt and 
designated points of delivery. A customer taking firm point-to-point 
transmission service generally pays a monthly demand charge based on 
its reserved capacity, and it may resell the service to another 
customer.\27\
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    \27\ Under the Commission's transmission pricing policy, the 
demand charge may reflect the higher of the transmission provider's 
embedded costs or incremental expansion costs. Also, if the 
transmission system is constrained, the demand charge may reflect 
the higher of embedded costs or ``opportunity'' costs, with the 
latter capped at incremental expansion costs. See Inquiry Concerning 
the Commission's Pricing Policy for Transmission Services Provided 
by Public Utilities Under the Federal Power Act, Policy Statement, 
69 FERC ] 61,086 (1994). In practice, the demand charge is almost 
always determined on basis of the transmission provider's embedded 
costs.
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    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, 
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.
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    \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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    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-to-point 
transmission service even when the transmission provider must 
redispatch its generators to honor the firm service commitment. If the 
load-serving entity has generators and loads at multiple locations, it 
can request network service and dispatch of its generators to serve its 
loads in a least cost manner. The load-serving entity must pay a load 
ratio share of the transmission provider's Commission-approved 
transmission revenue requirement but, again, is not directly assigned 
any congestion costs. If either the transmission provider's or the 
load-serving 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.

[[Page 6697]]

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.
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    \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.
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    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.
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    \30\ It is important to note that, depending on the relative 
magnitude of the prices at the generator's location and the load's 
location, congestion costs can be positive or negative.
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    23. To reduce the uncertainty due to congestion, transmission 
organizations that use locational marginal pricing make FTRs available 
to their market participants.\31\ An FTR is a right to receive the 
congestion costs paid by grid users and collected by the transmission 
organization for one megawatt of electricity delivered from a specified 
point of receipt to a specified point of delivery. The holder of an FTR 
receives in each hour a payment that is calculated by subtracting the 
price at the point of receipt from the price at the point of delivery, 
and multiplying the difference by the megawatt quantity.
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    \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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    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\
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    \32\ It should be noted that, even when all awarded FTRs meet 
the simultaneous feasibility test, the Transmission Organization may 
at times be revenue inadequate as a result of unexpected events, 
such as a line outage or transmission system disruption that reduces 
transfer capability.
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    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 discussion 
in this section, we will assume that FTRs are limited to FTR 
obligations.\34\
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    \33\ The need for more capacity is due to the fact that the 
Transmission Organization cannot assume that the FTR options will 
provide any ``counterflows'' when it conducts the simultaneous 
feasibility test.
    \34\ See infra at P 72-79 for a more complete discussion of the 
properties of FTR obligations and FTR options.
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    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.
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    \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.
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    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.
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    \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.
---------------------------------------------------------------------------

    28. Since the state of the transmission system and market prices 
change from year to year, the annual allocation allows market 
participants to re-

[[Page 6698]]

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 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 load-serving entity that has generation at one 
location and load at another, but does not hold FTRs, is at risk of 
incurring congestion costs, which may not be predictable. Also, 
although that load-serving entity can avoid congestion costs by holding 
FTRs, it still faces a congestion price risk if its spot sales and 
purchases or scheduled injections and withdrawals do not correspond 
exactly to its allocated (or purchased) FTRs. Clearly, locational 
pricing and price-based congestion management provide the market 
participant with much of the information it needs to make cost 
effective decisions regarding energy consumption and use of the 
transmission system (as well as investment in new generation and 
transmission upgrades). However, the FTRs that transmission 
organizations currently provide to hedge congestion charges for using 
existing transmission capacity (as opposed to incremental transmission 
expansions) are generally available for terms of only one year or less. 
This can create uncertainty for the market participant because, in any 
given year, its award of FTRs may not be sufficient to meet its needs. 
Some market participants have expressed concern that this uncertainty 
makes it more difficult to finance long-term power supply arrangements.
    33. The Commission believes that some of the problems of 
uncertainty in organized electricity markets can be overcome and the 
objectives of section 217(b)(4) of the FPA can be met through the 
introduction of long-term firm transmission rights. However, for a 
variety of reasons that are discussed below, transmission rights in 
organized electricity markets cannot always be designed in a way that 
captures all of the features of the transmission rights that have long 
been available under the OATT. Consequently, the Commission's objective 
in issuing this NOPR is to present a framework within which 
transmission organizations and their market participants can design and 
implement long-term firm transmission rights in the organized 
electricity markets that are compatible with the design of those 
markets, in particular retaining the advantages of price-based 
congestion management, and meet the reasonable needs of market 
participants.

C. Staff Paper on Long-Term Transmission Rights

    34. Prior to the enactment of EPAct 2005, the Commission released a 
Staff Paper that provided background and solicited comments on whether 
long-term transmission rights 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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    35. With respect to the need for and design of long-term 
transmission rights, the views of the respondents tended to fall into 
three general groups. The first group consisted of advocates of long-
term transmission rights with terms in

[[Page 6699]]

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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    36. Most of the parties in this first group stressed that not all 
transmission capacity should be given over to long-term rights, but 
that there should be an amount sufficient to cover at least base-load 
generation resources and perhaps renewable energy generators.\39\ These 
commenters argue that long-term rights should be FTR obligations only 
under certain conditions that limit financial exposure of the rights 
holder. Several proposed that the long-term rights should be FTR 
options. Otherwise, the rights could be physical rights \40\ or 
modified FTRs (e.g. financial rights with physical characteristics, 
such as ``use-or-lose'' rights) designed to alter the financial 
settlement properties of traditional FTRs so as to reduce congestion 
risk.\41\
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    \39\ See Comments on Staff Paper of APPA at 31; Comments on 
Staff Paper of TAPS at 17-19. However, other parties supportive of 
long-term transmission rights argued that their allocation should 
not be tied to particular classes of generator. See, e.g., Comments 
on Staff Paper of ELCON at 8-9.
    \40\ See Comments on Staff Paper of Sacramento Municipal Utility 
District (SMUD) at 12-16; Comments on Staff Paper of City of Santa 
Clara, California, Silicon Valley Power (SVP) at 14-18.
    \41\ For example, a right that only provides a financial hedge 
when the holder submits a physical schedule (a type of ``use or 
lose'' right). See, e.g., Comments on Staff Paper of the 
Transmission Access Policy Study Group (TAPS) at 21-25; Comments on 
Staff Paper of the Electricity Consumers Resource Council (ELCON) at 
12-13. Note also that several commenters argued that ISOs with LMP 
and financial rights should not revert to physical rights to provide 
long-term transmission service, nor should they allow such ISOs to 
offer combinations of physical and financial rights (with the 
exception of already awarded grandfathered rights). See, e.g., 
Comments on Staff Paper of ABATE at 10-11; Comments on Staff Paper 
of American Electric Power (AEP) at 3; Comments on Staff Paper of 
Cinergy at 13-14; Comments on Staff Paper of Edison Electric 
Institute (EEI) at 3; Comments on Staff Paper of Electric Power 
Supply Association (EPSA) at 6-8; Comments on Staff Paper of 
FirstEnergy Solutions at 8; Comments on Staff Paper of ISO/RTO 
Council at 2-3.
---------------------------------------------------------------------------

    37. A second group of commenters largely agreed with the first that 
long-term rights should be introduced, but argued that this should take 
place within the framework of existing FTR market designs and follow a 
cautious, incremental approach. These parties, which included most of 
the ISOs and RTOs that submitted comments as well as many stakeholders, 
argued that rights of greater than one year duration would indeed find 
a role in the markets, but that care was needed in the design of the 
rights.\42\ Most of these parties were supportive of straightforward 
extensions of the current FTR market design to include FTR obligations 
of longer terms, although perhaps with modified creditworthiness 
requirements and other rule changes to reflect the different risks 
embodied in such rights. In general, they proposed terms for such FTRs 
of between 2 to 5 years. They also supported limiting the quantity of 
system capability given over to long-term FTRs for at least an initial 
period.
---------------------------------------------------------------------------

    \42\ See generally Comments on Staff Paper of California ISO; 
Comments on Staff Paper of ISO New England; Comments on Staff Paper 
of New York ISO; Comments on Staff Paper of PJM; Comments on Staff 
Paper of ISO/RTO Council. See also generally Comments on Staff Paper 
of New York Public Service Commission (NY PSC) and the Organization 
of Midwest States (OMS). On appropriate term lengths, see Comments 
on Staff Paper of Cinergy at 10; Comments on Staff Paper of Coral 
Power at 3, 6; Comments on Staff Paper of DC Energy at 4-5; Comments 
on Staff Paper of Edison Electric Institute (EEI) at 10; Comments on 
Staff Paper of Electric Power Supply Association (EPSA) at 11; 
Comments on Staff Paper of Midwest Transmission Owners at 11; 
Comments on Staff Paper of Morgan Stanley at 7; Comments on Staff 
Paper of National Grid at 15; Comments on Staff Paper of Pacific Gas 
& Electric (PG&E) at 5.
---------------------------------------------------------------------------

    38. Finally, some respondents felt that long-term rights should not 
be introduced at this time.\43\ These parties argued that the current 
procedures for annual allocations of FTRs with terms of one year or 
less were well-established and that transmission rights markets were 
efficient and maturing around this design. They were concerned that the 
introduction of multi-year rights could introduce inequity and 
inefficiency into the organized electricity markets, because they 
believe such rights will reduce the availability of FTRs with terms of 
one year or less that can be used to hedge shorter-term transactions. 
They also assert that introducing long-term rights could cause cost 
shifts if holders of long-term rights are given congestion risk 
coverage greater than that accorded to other parties. Some respondents 
that supported this position were from retail choice states, reflecting 
concerns that long-term rights could adversely affect their ability to 
acquire and trade transmission rights used to hedge shorter-term 
contracts.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

[[Page 6700]]

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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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 load-serving entities 
with long-term power supply arrangements used to meet service 
obligations.
    43. While we believe these and the other properties outlined in the 
guidelines below are critical to the successful implementation of long-
term rights, we intend for the guidelines to form only a framework for 
further, more specific development of long-term firm transmission 
rights by each transmission organization. Accordingly, the guidelines 
should provide enough flexibility to allow each region to develop, 
through its usual stakeholder process, a specific long-term firm 
transmission right design that fits the prevailing market design and 
best meets the needs of market participants in that region.
    44. Although we propose to allow regional flexibility in the 
development of long-term firm transmission rights, we recognize that 
allowing transmission organizations with organized electricity markets 
to implement different rules for these rights could lead to 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 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\ APPA states that, because ISO-NE offers only general 
system-wide ARRs, there is no direct relationship between the ARRs 
that a market participant receives and the FTRs that the market 
participant may desire, given the location of its resources. See 
Comments on Staff Paper of APPA, attached Concept Paper--Long-Term 
Transmission Rights, at 16, n. 22.
    \47\ It is thus possible to define a form of network service 
that consists of a set of point-to-point rights, each of which 
specifies a source, a sink and a megawatt quantity. This, however, 
would differ from network service under the OATT, which does not 
require the customer to reserve a specific amount of capacity 
between its network resources and network loads.
---------------------------------------------------------------------------

    46. Section 217(b)(4) recognizes that there may be alternative 
designs for long-term firm transmission rights.\48\ For many 
transmission organizations and their market participants, the most 
straightforward method to develop long-term firm transmission rights 
would be to extend the term of the auction revenue rights or FTRs that 
they currently allocate. These may require additional market rules, 
such as modified creditworthiness standards. However, we do not 
preclude alternative designs for long-term rights. Some possible 
designs are compared in Section IV.C of this NOPR.
---------------------------------------------------------------------------

    \48\ In particular, that provision states that the Commission 
shall exercise its authority ``to enable load-serving entities to 
secure firm transmission (or equivalent tradable or financial 
rights) on a long-term basis'' (emphasis added).

    Guideline (2): The long-term firm transmission right must 
provide a hedge against locational marginal pricing congestion 
charges (or other direct assignment of congestion costs) for the 
period covered and quantity specified. Once allocated, the financial 
coverage provided by the right should not be modified during its 
term except in the case of extraordinary circumstances or through 
voluntary agreement of both the holder of the right and the 
---------------------------------------------------------------------------
transmission organization.

    47. In most existing organized electricity markets, LMP is used to 
manage congestion. The FTRs currently offered in the organized 
electricity markets provide a hedge against these charges, but are only 
offered in terms of one year or less. Because of this short term, 
market participants with long-term power supply arrangements are at 
risk of having the ARRs or FTRs that they are eligible for to hedge 
congestion charges associated with 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\
---------------------------------------------------------------------------

    \49\ Comments on Staff Paper of APPA at 21.
---------------------------------------------------------------------------

    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

[[Page 6701]]

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 pro-rationing in the event of revenue 
inadequacy. We interpret the intent of section 217(b)(4) of the FPA to 
be that the Commission ensure the availability in organized electricity 
markets of long-term firm transmission rights that provide price 
stability to load-serving entities with long-term power supply 
arrangements used to satisfy their service obligations.
    49. When conditions arise that cause the transmission organization 
to receive congestion revenues that are not sufficient to meet payment 
obligations to FTR holders, the transmission organization must have in 
place a mechanism to fully fund the rights by collecting the needed 
revenues from a set of market participants. We will not specify here 
how that funding should be allocated among market participants, which 
is a subject for stakeholder discussion, but note that ideally the 
rules for funding of the rights should be designed to create and 
improve incentives for the maintenance and expansion of the 
transmission system that is needed to ensure the feasibility of the 
long-term rights that are allocated. This might be accomplished, for 
example, by placing the entities that are ultimately responsible for 
system maintenance and expansion at risk (wholly or partially) for 
funding revenue shortfalls that are due to inadequate maintenance or 
expansion practices. The transmission organization might also define 
rules for transmission upgrades and expansion to support the 
feasibility of long-term rights.\50\ The Commission seeks comments on 
funding revenue shortfalls related to the provision of long-term firm 
transmission rights, particularly with regard to how any necessary 
charges should be allocated. Should such charges be allocated to a 
transmission owner that is responsible for maintaining and expanding 
the capacity supporting the long-term firm transmission rights where 
the revenue shortfalls are due to inadequate maintenance or expansion? 
Are there appropriate methods for allocating such charges that also 
provide appropriate short-term and long-term incentives for 
transmission usage, maintenance and expansion?
---------------------------------------------------------------------------

    \50\ We discuss this issue in Section V, infra.
---------------------------------------------------------------------------

    50. Also, there may be extraordinary circumstances under which the 
requirement for full funding should be relaxed. For example, one such 
extraordinary circumstance may be a sustained, unplanned outage of a 
large transmission line. Such circumstances may require alternative 
rules for sharing of congestion cost risk than would otherwise apply.

    Guideline (3): Long-term firm transmission rights made feasible 
by transmission upgrades or expansions must be available upon 
request to any party that pays for such upgrades or expansions in 
accordance with the transmission organization's prevailing cost 
allocation methods for upgrades or expansions. The term of the 
rights should be equal to the life of the facility (or facilities) 
or a lesser term requested by the party paying for the upgrade or 
expansion.

    51. Most transmission organizations today allow entities that pay 
for network upgrades or expansions to receive the long-term firm 
transmission rights that would not be feasible but for those 
expansions. The Commission believes that this policy is fair to both 
new and existing users of the transmission system, promotes efficient 
capacity expansions by allowing users that fund the expansions to 
compare directly any congestion cost savings with the cost of the 
necessary upgrades, and provides the 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.
---------------------------------------------------------------------------

    \51\ See pro forma OATT at sections 13.5, 15.4 and 28.2.
---------------------------------------------------------------------------

    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 least some existing transfer capability in order for 
the right to be feasible. If the entity that has funded a capacity 
expansion does not have a priority to obtain long-term rights to 
existing capacity as proposed in guideline (5) in this NOPR,\52\ the 
transmission organization must propose a procedure by which such an 
entity can obtain rights to existing capacity when such rights are 
needed to make the incremental expansion rights feasible. We ask for 
comment on the appropriate rules in such cases.
---------------------------------------------------------------------------

    \52\ See infra at P 58-61.

    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\
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    54. Other commenters argued that the initial assignment of long-
term rights should consider much longer time-frames, on the order of 
decades. For example, NRECA argues that the term of the rights should 
be matched to the RTO planning process, which is typically 5 or 10 
years.\55\ TAPS argues that long-term rights consistent with its 
specifications should be made available for 10 year terms with the 
unconditional

[[Page 6702]]

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\ See Comments on Staff Paper of NRECA at 18.
    \56\ See Comments on Staff Paper of TAPS at 19-21.
    \57\ See Comments on Staff Paper of APPA at 33.
---------------------------------------------------------------------------

    55. The Commission believes that it is reasonable to allow 
transmission organizations to individually develop and propose the 
terms of the long-term firm transmission rights they offer.\58\ 
However, we consider long-term, for purposes of this rulemaking, to 
mean terms on the order of multiple years, sufficient to meet the needs 
of load-serving entities with service obligations.\59\ The Commission's 
primary concern here is to be responsive to the needs of load-serving 
entities, other market participants, and the requirements of section 
217(b)(4) of the FPA. In particular, our goal is to ensure that long-
term firm transmission rights are available for those who wish to 
obtain a more stable, long-term firm transmission right to meet their 
service obligations, and for those who need longer-term transmission 
rights to finance investments in new generation or long-term power 
purchase contracts. To achieve this goal, we propose this guideline, 
which would require that the specific rights proposed by each 
transmission organization in compliance with this rulemaking have term 
lengths (and/or rights to renewal) that are sufficient to meet the 
needs of transmission customers to hedge long-term power supply 
arrangements made or planned to satisfy a service obligation. Because 
market participants in different transmission organizations may have 
different needs, we decline to propose a specific term length or set of 
term lengths. New section 217(b)(4) of the FPA makes clear, however, 
that transmission organizations with organized electricity markets must 
meet the needs for long-term firm transmission service of load-serving 
entities with long-term power supply arrangements made, or planned, to 
meet their service obligations. Hence, this guideline would require 
that transmission organizations with organized electricity markets 
offer long-term firm transmission rights with terms that meet such 
needs. The Commission expects that multiple-year terms will be 
necessary to ensure that the rights will support the financing of new 
generation investments or power purchase contracts.\60\ Our view of 
long-term as terms of multiple years is intended to provide a range to 
allow transmission organizations the flexibility to individually 
develop and propose term lengths, subject to review by the Commission 
to ensure that the terms each transmission organization proposes meet 
the goals described above and expressed by Congress in section 
217(b)(4) of the FPA.
---------------------------------------------------------------------------

    \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.
    \60\ The ability to renew the long-term firm transmission rights 
will also help ensure that term lengths will be appropriate.
---------------------------------------------------------------------------

    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\
---------------------------------------------------------------------------

    \61\ This NOPR also explores transmission planning and expansion 
in Section V, infra.
---------------------------------------------------------------------------

    57. With regard to rights to renew long-term firm transmission 
rights, the transmission organization may propose reasonable criteria 
regarding the availability of renewal rights, and the price at which 
rights may be renewed. For example, the right to renew long-term firm 
transmission rights may be limited to a load-serving entity that can 
demonstrate that the renewal right is needed to allow the load-serving 
entity to match the term of its transmission rights to the term of a 
particular long-term power supply arrangement. In addition, the 
transmission organization may require minimum notice periods for 
initiation, renewal, cancellation or conversion that accommodate the 
transmission organization's planning cycle or other administrative 
considerations. We seek comments on the relationship between the right 
to renew a long-term firm transmission right and transmission system 
planning.

    Guideline (5): Load-serving entities with long-term power supply 
arrangements to meet a service obligation must have priority to 
existing transmission capacity that supports long-term firm 
transmission rights requested to hedge such arrangements.

    58. When finalized, this rulemaking will require that transmission 
organizations with organized electricity markets make long-term firm 
transmission rights available to transmission customers. As noted 
above, section 217(b)(4) of the FPA requires the Commission to exercise 
its authority to enable ``load-serving entities to secure firm 
transmission rights (or equivalent tradable or financial rights) on a 
long-term basis for long-term power supply arrangements made, or 
planned, to meet such needs.'' As we discuss elsewhere in this NOPR, in 
regions where existing transmission capacity is limited, transmission 
organizations may not be able to accommodate all requests for long-term 
firm transmission rights. While section 217 does not require that long-
term firm transmission rights be made available only to load-serving 
entities with service obligations, we interpret that section to require 
the Commission to give load-serving entities with long-term power 
supply arrangements to satisfy a service obligation a preference in 
securing long-term firm transmission rights. In accordance with this 
interpretation, if there is a conflict (infeasibility) in awarding 
long-term rights from existing capacity (or capacity created by 
incremental reliability upgrades) to all parties eligible to receive 
them, we propose to require the transmission organizations to address 
this infeasibility by first giving load-serving entities with long-term 
power supply arrangements used to meet service obligations priority in 
the allocation of the rights.
    59. When rights requested by eligible parties with priority (or 
parties without priority that are being accommodated) are not 
simultaneously feasible given existing transmission capacity, the 
transmission organization may adopt methods to allocate the requested 
rights to the parties prior to granting such rights. We seek comments 
on such methods and whether and to what extent it may be appropriate to 
allow

[[Page 6703]]

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 load-serving entities to satisfy their service obligations. 
Additionally, that section requires that the Commission enable load-
serving entities to secure long-term firm transmission rights for 
``power supply arrangements made, or planned,'' to meet their service 
obligations.
    60. In making available long term firm transmission rights for 
power supply arrangements ``made or planned'' to meet service 
obligations, transmission organizations may have to incorporate 
estimates of load growth into the award of such rights. This raises the 
concern that to the extent that the load growth assumptions made by 
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.

    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 load-serving entity, be reassignable to a successor load-
serving entity which, in turn, would assume any cost responsibility 
that holding the rights entails. This proposal is consistent with 
section 217(b)(3)(A) of the FPA, which requires that transmission 
rights held by a load-serving entity as of the date of enactment of 
EPAct 2005 for the purpose of delivering energy it has purchased or 
generated to meet a service obligation be transferred to a successor 
load-serving entity.\62\ Specifically, section 217(b)(3)(A) provides:
---------------------------------------------------------------------------

    \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.

    To the extent that all or a portion of the service obligation 
covered by the firm transmission rights or equivalent tradable or 
financial transmission rights is transferred to another load-serving 
entity, the successor load-serving entity shall be entitled to use 
the firm transmission rights or equivalent tradable or financial 
transmission rights associated with the transferred service 
---------------------------------------------------------------------------
obligation.

    This guideline would apply when a service obligation is transferred 
to a new load-serving entity. Such a transfer of a service obligation 
might occur pursuant to a state commission order, or might occur in a 
state with retail competition if load chooses a new supplier. The 
Commission seeks comments regarding whether the reassignability we 
propose to require in this guideline, consistent with section 217, 
should apply to all long-term firm transmission rights, regardless of 
how those rights were obtained. For example, what, if any, compensation 
should a holder of long-term rights receive when its rights are 
reassigned to a successor load-serving entity?
    63. Section 217(b)(4) of the FPA does not discuss whether long-term 
firm transmission rights should be fully tradable among market 
participants. Allowing such rights to be fully tradable could raise 
issues of equity, since a load-serving entity who acquired the rights 
through the preference we propose in this rulemaking could then 
possibly sell or trade the rights at a profit. This might give load-
serving entities the incentive to acquire excess long-term firm 
transmission rights in order to take advantage of profit opportunities 
through arbitrage. However, full tradability may bring benefits to the 
market, and allow those who could not obtain long-term rights in the 
initial allocation to obtain such rights later. We seek comment on 
these issues. Particularly, we seek comment on whether the equity 
issues we note above could be addressed by only permitting holders of 
long-term firm transmission rights to return their rights to the 
transmission organization at the price paid, or whether these issues 
could be addressed in some other manner.

    Guideline (7): The initial allocation of the long-term firm 
transmission rights shall not require recipients to participate in 
an auction.

    64. As is currently done in most transmission organization markets, 
the first stage in awarding transmission rights is to allocate the 
rights directly to eligible parties or to 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.
---------------------------------------------------------------------------

    \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.

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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

[[Page 6704]]

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 long-term 
rights on either a long-term or short term basis from those holding 
long-term rights. However, as we noted above in our discussion of 
guideline (6), allowing this kind of tradability could raise equity 
issues and could give load-serving entities with a preference the 
incentive to acquire excess long-term rights and later sell them at a 
profit.\65\ We seek comment on these issues.
---------------------------------------------------------------------------

    \65\ See supra at P 63.
---------------------------------------------------------------------------

    69. Finally, with regard to the pricing of long-term rights in 
general, the Commission proposes not to prescribe a specific 
methodology, whether the rights are available from existing capacity or 
require capacity expansion. In particular, the Commission does not 
propose to require a rolled-in pricing policy for long-term firm 
transmission rights. Rather, consistent with current policy, the 
Commission proposes to allow the transmission organization flexibility 
to propose methods for pricing transmission rights and related services 
that are appropriate for its region and are the product of a 
stakeholder process.
    70. We seek comment on ways that transmission organizations may 
balance any adverse economic impacts of allocating long-term firm 
transmission rights between participants receiving and not receiving 
such rights. We also seek comment on any measures that should be 
adopted to protect against actions by long-term firm transmission 
rights holders. For example, a holder of a long-term firm transmission 
obligation type of right may leave the transmission organization. The 
allocation of other transmission rights may have depended on that 
holder's counterflows on the grid or its payments to fulfill its 
obligation to the transmission organization. Are measures needed to 
address this situation?

C. Alternative Designs

    71. The guidelines above are sufficiently general to allow for a 
range of proposals for the design of long-term firm transmission 
rights. To assist parties in formulating those proposals, we discuss 
three alternative designs that are possible under the guidelines: long-
term ARR or FTR obligations, FTR options, and rights with modifications 
of FTR settlement or physical scheduling requirements, such as ``use or 
lose'' rights. Consistent with proposed Guideline (7), we expect that 
the first step under any proposed design will be a direct allocation, 
rather than an auction (followed possibly by voluntary participation in 
an auction). The prevailing design for initial allocation of ARRs or 
FTRs has been to assign obligation rights. At the Commission's urging 
and in response to market interest, in at least one current market 
(PJM), ARRs can subsequently be used to purchase FTR options as well as 
obligations through an FTR auction.
1. Long-Term ARR or FTR Obligations
    72. We begin with the advantages and disadvantages of the 
prevailing designs for transmission rights in current organized 
electricity markets. As noted above, allocated transmission rights, 
whether as ARRs or FTRs, are modeled as obligation rights. The major 
advantage of obligations is that they allow the transmission 
organization to maximize the coverage of the allocated point-to-point 
transmission rights made available to eligible parties. As explained 
above, in the modeling of the transmission system power flows that 
supports the initial allocation, obligation rights are represented 
under the assumption that the counterflows associated with injections 
and withdrawals will be present. This limits the need to ``pro-ration'' 
eligible transmission rights, although most transmission organizations 
have rules for how such pro-rationing will occur if necessary (e.g., by 
having stages of the allocation with higher priority given to rights 
nominated in early stages).
    73. In existing systems that directly allocate FTR obligations, 
allocating multi-year FTRs could be a fairly straightforward extension 
of the existing market design, with the need for additional rules to 
cover the additional risks of a multi-year financial instrument that 
could entail payment obligations, such as creditworthiness 
requirements.
    74. In systems that directly allocate ARRs, the rules would be 
slightly different. A long-term ARR obligation would mean that for the 
term defined in the right, the 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

[[Page 6705]]

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 long-term payment 
obligations. As an example, long-term FTR obligations are currently 
awarded for incremental transmission expansions, and such rights also 
have potential negative payment obligations. Because parties that build 
transmission may not own generation with which to manage such FTR 
payment risk (e.g., merchant transmission operators), some organized 
electricity market rules (e.g., PJM) currently allow for such long-term 
incremental rights to be ``turned back'' to the transmission 
organization without penalty at the end of each annual allocation 
cycle, thus creating an option-like feature. To the extent that long-
term incremental transmission rights support only a limited reliance on 
counterflow used by other parties in subsequent allocations of rights, 
such a rule may have no or limited financial impact on other parties, 
but if the transmission organization applied such a rule to long-term 
obligation rights to existing capacity, such a ``turn back'' rule could 
have more substantial financial implications--that is, require uplift 
charges--in some circumstances. This is a ``socialization'' of risk 
decision that is best made by stakeholders in tandem with other such 
decisions, such as how many long-term rights to allocate. Such 
socialization may assist in developing rules for long-term ARR or FTR 
obligations that have more desirable properties for market 
participants.
2. Long-Term FTR Options
    77. For many parties seeking long-term rights (including long-term 
rights obtained for transmission upgrades and expansions), FTR option 
rights have attractive financial properties. As noted above, in 
contrast to the obligation right, the FTR option payment is made only 
when the congestion charge between the points is positive. When the 
congestion charge is negative, the FTR option neither pays revenues nor 
requires payment equal to the negative charge. As such, the holder will 
never face negative payment obligations.
    78. The primary difficulty in allocating long-term (or short-term) 
FTR options is that because the counterflows are not included when 
modeling for revenue adequacy, the transmission organization will be 
able to directly allocate fewer FTR options to eligible parties than it 
would be able to allocate FTR obligations that assume counterflows (see 
discussion next). This increases the likelihood that the transmission 
organization would not be able to fulfill all requests for FTRs. The 
potential shortfall in available FTRs could be significant in some 
locations and rules for equitable pro-rationing could be difficult to 
develop.\66\ As a result some parties would be exposed to congestion 
charges for transmission usage in excess of their FTR allocation.
---------------------------------------------------------------------------

    \66\ The pro-rationing of FTR obligations has also created 
conflict over the appropriate rules in some organized markets, but 
the scale of the equity problem in the case of FTR options could be 
much greater.
---------------------------------------------------------------------------

    79. The allocation issues posed by long-term FTR options may be 
mitigated in a number of ways. If parties sufficiently desire the 
financial risk characteristics and revenues associated with FTR 
options, they may be willing to accept pro-rationing with the attendant 
possibility of congestion charge exposure. Depending on grid 
capability, it is possible that the resulting exposure may be minimal. 
Another possibility is that, if eligibility requirements are 
restrictive, sufficiently few long-term FTR options will be allocated 
such that there is enough transmission system capability to satisfy the 
remaining needs for congestion hedges through FTR obligations. Another 
approach, similar to that currently followed in PJM for annual rights, 
is to assign long-term auction revenue rights modeled as obligations, 
and then let holders of such rights decide whether to purchase long-
term FTR options or obligations in a subsequent auction. This method 
requires the party eligible for the long-term right to make financial 
decisions up-front that it may prefer not to make, however. Yet another 
policy option is to make sufficient investments in transmission 
expansion to make the desired long-term FTR options feasible. This 
course could be taken if the market participants determine that such 
investments are less expensive than any congestion cost exposure or 
insurance through uplift charges associated with other transmission 
rights schemes, some of which are discussed below.
3. Other Approaches to Long-Term Firm Transmission Rights
    80. The features of long-term FTR options and FTR obligations have 
driven some parties to propose alternative types of long-term 
transmission rights, some having financial settlement properties that 
are different from current FTRs and others combining physical and 
financial features.\67\ We review these alternative approaches simply 
for illustrative purposes.
---------------------------------------------------------------------------

    \67\ See generally Comments on Staff Paper of APPA; Comments on 
Staff Paper of TAPS.
---------------------------------------------------------------------------

    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 use-or-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

[[Page 6706]]

uplift, to cover any resulting revenue inadequacies.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \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.
---------------------------------------------------------------------------

4. Combining Different Types of Long-Term Firm Transmission Rights
    83. Most existing transmission organizations do retain some 
quantity of non-FTR transmission rights on their transmission systems, 
typically grandfathered pre-Order 888 OATT rights that are treated as 
physical scheduling rights. In most of these markets, these physical 
transmission rights do not require that a large amount of transmission 
capability is reserved, hence they do not greatly affect the allocation 
and trading of FTRs. However, as noted above, the Midwest ISO has had 
to accommodate a greater number of such rights than other transmission 
organizations and has done so on an interim basis through creation of 
alternative types of financial rights or other arrangements. It has 
sought to minimize the impact of such rights on the FTR allocation and 
on the exposure of market participants to uplift.
    84. In the event that stakeholders' interests in different types of 
transmission rights are difficult to reconcile, transmission 
organizations may need to consider the development of different types 
of long-term rights simultaneously. We believe that regional 
stakeholder discussions are the appropriate forum for such decision-
making.
    85. If the transmission organization and stakeholders are 
considering more than one type of transmission right, we further 
encourage them to establish mechanisms by which holders of one kind of 
long-term firm transmission right can convert their rights into other 
rights with other characteristics offered by the transmission 
organization that rely on the same amount of transmission capacity. For 
example, a long-term right initially 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\
---------------------------------------------------------------------------

    \72\ Pub. L. 109-58, Sec.  1233, 119 Stat. 594, 958.
---------------------------------------------------------------------------

    87. Additionally, many of those commenting on the Staff Paper 
argued that implementation of long-term firm transmission rights will 
not be possible unless the transmission organization has adequate 
transmission planning and expansion procedures in place.\73\ According 
to some commenters, the inadequacy of the physical transmission system 
and the lack of a reliable mechanism for transmission organizations to 
plan and require the construction of transmission facilities are the 
prime impediments to both introducing long-term firm transmission 
rights in the organized electricity markets and ensuring that they 
remain simultaneously feasible over their entire term.\74\ Several of 
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\
---------------------------------------------------------------------------

    \73\ See, e.g., Comments on Staff Paper of NRECA at 9-10; 
Comments on Staff Paper of Midwest TDUs at 5; Comments on Staff 
Paper of ELCON at 3; Comments on Staff Paper of National Grid at 1-2 
and 9.
    \74\ See, e.g., Comments on Staff Paper of NRECA at 9; Comments 
on Staff Paper of APPA at 21-22.
    \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.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \78\ See discussion of guideline (2), supra.
---------------------------------------------------------------------------

    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

[[Page 6707]]

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 long-term 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 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.
---------------------------------------------------------------------------

    \79\ See pro forma OATT at sections 13.5, 15.4 and 28.2.
    \80\ See, e.g., Comments on Staff Paper of APPA at 10; Comments 
on Staff Paper of ABATE and Midwest Transmission Customers at 4-6; 
Comments on Staff Paper of Peabody Energy Corporation at 6.
    \81\ Preventing Undue Discrimination and Preference in 
Transmission Services, Notice of Inquiry, 112 FERC ] 61,299 at P 21 
(2005) (NOI).
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \82\ Id. at P 9.
    \83\ Id.
---------------------------------------------------------------------------

    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.
---------------------------------------------------------------------------

    \84\ See Promoting Transmission Investment Through Pricing 
Reform, Notice of Proposed Rulemaking, 113 FERC ] 61,182 (2005).
---------------------------------------------------------------------------

VI. Proposed Compliance Procedures

    93. The Commission proposes to direct each public utility that is a 
transmission organization with an organized electricity market, within 
180 days of the publication of a Final Rule in the Federal Register, to 
either: (1) File with the Commission tariff sheets and rate schedules 
that make available long-term firm transmission rights that are 
consistent with the guidelines set forth in section (d) of the Final 
Rule; or (2) file with the Commission an explanation of how its current 
tariff and rate schedules already provide for long-term firm 
transmission rights that are consistent with the guidelines set forth 
in paragraph (d) of the Final Rule. The Commission intends that during 
this 180-day time period, such transmission organizations will work 
with their stakeholders to develop a long-term firm transmission right 
that will harmonize the prevailing market design with the guidelines 
set forth in this Final Rule. We do not propose any specific 
stakeholder process, and intend that the transmission organization will 
use its usual process for receiving stakeholder input and filing tariff 
changes with the Commission. For any transmission organization that is 
approved by the Commission after the 180-day time period, the 
Commission proposes that the transmission organization satisfy the 
requirements set forth in this rule before commencing operation.

VII. Information Collection Statement

    94. The Office of Management and Budget (OMB) regulations require 
approval of certain information collection requirements imposed by 
agency rules.\85\ Upon approval of a collection(s) of information, OMB 
will assign an OMB control number and an expiration date. Respondents 
subject to the filing requirements of this rule will not be penalized 
for failing to respond to these collections of information unless the 
collections of information display a valid OMB control number. This 
NOPR amends the Commission's regulations to implement some of the 
statutory provisions of section 1233 of EPAct 2005. Particularly, 
section 1233 of EPAct 2005 enacts a new section 217 of the FPA. New 
section 217(b)(4) requires the Commission to exercise its authority in 
a manner that facilitates the planning and expansion of transmission 
facilities to meet the reasonable needs of load-serving entities to 
satisfy their service obligations, and enables load-serving entities to 
secure long-term firm transmission rights to meet their service

[[Page 6708]]

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.
---------------------------------------------------------------------------

    \85\ 5 CFR 1320.13 (2005).
---------------------------------------------------------------------------

    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:

----------------------------------------------------------------------------------------------------------------
                                                 Number of        Number of        Hours per       Total annual
               Data collection                  respondents       responses         response          hours
----------------------------------------------------------------------------------------------------------------
FERC-516--Transmission Organizations with                  6                1             1180            7,080
 Organized Electricity Markets..............
----------------------------------------------------------------------------------------------------------------

    Total Annual Hours for Collection: (Reporting + recordkeeping, (if 
appropriate) = 7,080 hours.
---------------------------------------------------------------------------

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

    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, long-term 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.
    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: [email protected]]. 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: [email protected].

VIII. Environmental Analysis

    98. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\87\ The 
Commission has categorically excluded certain actions from this 
requirement as not having a significant effect on the human 
environment. Included in the exclusion are rules that do not 
substantially change the effect of legislation.\88\ The rule proposed 
in this NOPR falls within this categorical exemption because it 
implements the requirements of EPAct 2005 relating to long-term firm 
transmission rights in organized electricity markets. Accordingly, 
neither an environmental impact statement nor environmental assessment 
is required.
---------------------------------------------------------------------------

    \87\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. 
Preambles 1986-1990 ] 30,783 (1987).
    \88\ 18 CFR 380.4(2)(ii) (2005).
---------------------------------------------------------------------------

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.
---------------------------------------------------------------------------

    \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).
---------------------------------------------------------------------------

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\

[[Page 6709]]

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.
---------------------------------------------------------------------------

    \91\ While we are issuing this NOPR in both Docket No. RM06-8-
000 and Docket No. AD05-7-000, we expect to issue our Final Rule in 
only Docket No. RM06-8-000. Comments in response to this NOPR should 
be filed in Docket No. RM06-8-000 only.
---------------------------------------------------------------------------

    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.

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 [email protected]), or the Public Reference Room at 
(202) 502-8371, TTY (202) 502-8659 (e-mail at 
[email protected]).

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.


Sec.  40.1  Requirement that Transmission Organizations with Organized 
Electricity Markets Offer Long-Term Transmission Rights.

    (a) Purpose. This section requires a transmission organization with 
one or more organized electricity markets (administered either by it or 
by another entity) to make available long-term firm transmission 
rights, pursuant to section 217(b)(4) of the Federal Power Act, that 
satisfy the guidelines set forth in paragraph (d) of this section. This 
section does not require that a specific type of long-term firm 
transmission right be made available, and is intended to permit 
transmission organizations flexibility in satisfying the guidelines set 
forth in paragraph (d) of this section.
    (b) Definitions. As used in this section:
    (1) Transmission Organization means a Regional Transmission 
Organization, Independent System Operator, independent transmission 
provider, or other independent transmission organization finally 
approved by the Commission for the operation of transmission 
facilities.
    (2) Load-serving entity means a distribution utility or an electric 
utility that has a service obligation.
    (3) Service obligation means a requirement applicable to, or the 
exercise of authority granted to, an electric utility under Federal, 
State, or local law or under long-term contracts to provide electric 
service to end-users or to a distribution utility.
    (4) Organized Electricity Market means an auction-based market 
where a single entity receives offers to sell and bids to buy electric 
energy and/or ancillary services from multiple sellers and buyers and 
determines which sales and purchases are completed and at what prices, 
based on formal rules contained in Commission-approved tariffs, and 
where the prices are used by a transmission organization for 
establishing transmission usage charges.
    (5) Long-term power supply arrangements means the ownership of 
generation facilities, rights to market the output of Federal 
generation facilities with a term of longer than one year, or rights 
under one or more wholesale contracts to purchase electric energy with 
a term of longer than one year, for the purpose of meeting a service 
obligation.
    (c) General rule.
    (1) Every public utility that is a transmission organization and 
that owns, operates or controls facilities used for the transmission of 
electric energy in interstate commerce and has one or more organized 
electricity markets (administered either by it or by another entity) 
must file with the Commission, no later than [INSERT DATE 180 DAYS 
AFTER PUBLICATION OF FINAL RULE IN THE FEDERAL REGISTER], one of the 
following:
    (i) Tariff sheets and rate schedules that make available long-term 
firm transmission rights that are consistent with the guidelines set 
forth in paragraph (d) of this section; or
    (ii) An explanation of how its current tariff and rate schedules 
already provide for 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 long-term firm transmission 
rights that satisfy the following guidelines:
    (1) The long-term firm transmission right should specify a source 
(injection node or nodes) and sink (withdrawal node or nodes), and a 
quantity (MW).
    (2) The long-term firm transmission right must provide a hedge 
against day-

[[Page 6710]]

ahead locational marginal pricing congestion charges (or other direct 
assignment of congestion costs) for the period covered and quantity 
specified. Once allocated, the financial coverage provided by the right 
should not be modified during its term except in the case of 
extraordinary circumstances or through voluntary agreement of both the 
holder of the right and the transmission organization.
    (3) Long-term firm transmission rights made feasible by 
transmission upgrades or expansions must be available upon request to 
any party that pays for such upgrades or expansions in accordance with 
the transmission organization's prevailing cost allocation methods for 
upgrades or expansions. The term of the rights should be equal to the 
life of the facility (or facilities) or a lesser term requested by the 
party paying for the upgrade or expansion.
    (4) Long-term firm transmission rights must be made available with 
terms (and/or rights to renewal) that are sufficient to meet the needs 
of load-serving entities to hedge long-term power supply arrangements 
made or planned to satisfy a service obligation. The length of term of 
renewals may be different from the original term.
    (5) Load-serving entities with long-term power supply arrangements 
to meet a service obligation must have priority to existing 
transmission capacity that supports long-term firm transmission rights 
requested to hedge such arrangements.
    (6) A long-term transmission right held by a load-serving entity to 
support a service obligation should be re-assignable to another entity 
that acquires that service obligation.
    (7) The initial allocation of the long-term firm transmission 
rights shall not require recipients to participate in an auction.
    (8) Allocation of long-term firm transmission rights should balance 
any adverse economic impact between participants receiving and not 
receiving the right.

[FR Doc. 06-1195 Filed 2-8-06; 8:45 am]
BILLING CODE 6717-01-P