[Federal Register: February 9, 2006 (Volume 71, Number 27)]
[Proposed Rules]
[Page 6693-6710]
[DOCID:fr09fe06-18]

=======================================================================
-----------------------------------------------------------------------

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.

-----------------------------------------------------------------------

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,<PHONE_NUMBER>.
Roland Wentworth (Technical Information), Office of Energy Markets and
Reliability, Federal Energy Regulatory Commission, 888 First Street,
NE., Washington, DC 20426,<PHONE_NUMBER>.
Wilbur C. Earley (Technical Information), Office of Energy Markets and
Reliability, Federal Energy Regulatory Commission, 888 First Street,
NE., Washington, DC 20426,<PHONE_NUMBER>.
Harry Singh (Technical Information), Office of Market Oversight and
Investigations, Federal Energy Regulatory Commission, 888 First Street,
NE., Washington, DC 20426,<PHONE_NUMBER>.
Jeffery S. Dennis (Legal Information), Office of the General Counsel,
Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426,<PHONE_NUMBER>.

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

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

    \1\ Pub. L. 109-58, 119 Stat. 594 (2005).
    \2\ Pub. L. 109-58, Sec.  1233(b), 119 Stat. 594, 960.
---------------------------------------------------------------------------

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

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

    Section 1233(b) of EPAct 2005 requires:

    Within 1 year after the date of enactment of this section and
after notice and an opportunity for comment, the Commission shall by
rule or order, implement section 217(b)(4) of the Federal Power Act
in Transmission Organizations, as defined by that Act with organized
electricity markets.\4\
---------------------------------------------------------------------------

    \3\ 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.
---------------------------------------------------------------------------

    \5\ See ``Definitions'' below.
---------------------------------------------------------------------------

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

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

B. Load-Serving Entity and Service Obligation

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

expand or clarify these definitions in the Final Rule.
---------------------------------------------------------------------------

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

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

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

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

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

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

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

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

    \16\ Order No. 888 at 31,655; Order No. 888-A at 30,184.
    \17\ Order No. 888 at 31,730.
---------------------------------------------------------------------------

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

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

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

    \22\ Id. at 31,046 et seq.
    \23\ Id. at 31,106 et seq.
---------------------------------------------------------------------------

    14. Most of the RTOs and ISOs operate organized markets for energy
and/or ancillary services in addition to providing transmission service
under a single transmission tariff. As described in more detail below,
most of these markets utilize a congestion management system based on

Locational Marginal Pricing (LMP). Congestion is defined as the
inability to inject and withdraw additional energy at particular
locations in the network due to the fact that the injections and
withdrawals would cause power flows over a specific transmission
facility to violate the reliability limits for that facility. The
market operator manages congestion by scheduling and dispatching
generators that can meet load in the presence of congestion.
Financially, in LMP markets the price of congestion is measured as the
difference in the cost of energy in the spot market at two different
locations in the network.\24\ When such price differences occur, a
congestion charge is assessed to transmission users based on their
nodal injections and withdrawals. These price differences can be
variable and difficult to predict. In order to manage the risk
associated with the variability in prices due to transmission
congestion, these markets use various forms of Financial Transmission
Rights (FTRs) (described in more detail below) to allow market
participants who hold the rights to protect against such price risks.
In most cases, these FTRs have terms of one year or less. The use of
FTRs and their terms is also discussed in more detail below.\25\
---------------------------------------------------------------------------

    \24\ See infra at P 21-22.
    \25\ See infra at P 23-28.
---------------------------------------------------------------------------

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

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

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

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

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

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

    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.

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

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

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

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

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

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

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

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

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

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

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

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

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

    \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-

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

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

    \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

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

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

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

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

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

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

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

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

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:<PHONE_NUMBER>, fax: (202)
273-0873, e-mail<EMAIL_ADDRESS>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_ADDRESS>
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.