[Federal Register: August 1, 2006 (Volume 71, Number 147)]
[Rules and Regulations]
[Page 43563-43620]
[DOCID:fr01au06-15]

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Part II

Department of Energy

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Federal Energy Regulatory Commission

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18 CFR Part 42

Long-Term Firm Transmission Rights in Organized Electricity Markets;
Final Rule

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

18 CFR Part 42

[Docket No. RM06-8-000; Order No. 681]

Long-Term Firm Transmission Rights in Organized Electricity
Markets

Issued July 20, 2006.
AGENCY: Federal Energy Regulatory Commission.

ACTION: Final rule.

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SUMMARY: The Federal Energy Regulatory Commission is amending its
regulations under the Federal Power Act to require transmission
organizations that are public utilities with organized electricity
markets to make available long-term firm transmission rights that
satisfy certain guidelines adopted by the Commission in this Final
Rule. The Commission is taking this action pursuant to section 1233(b)
of the Energy Policy Act of 2005, [Pub. L. 109-58, Sec.  1233(b), 119
Stat. 594, 960 (2005).]

DATES: Effective Date: This Final Rule will become effective August 31,
2006.

FOR FURTHER INFORMATION CONTACT: Udi E. Helman (Technical Information),
Office of Energy Markets and Reliability, Federal Energy Regulatory
Commission, 888 First Street, NE., Washington, DC 20426. (202) 502-
8080.
    Roland Wentworth (Technical Information), Office of Energy Markets
and Reliability, Federal Energy Regulatory Commission, 888 First
Street, NE., Washington, DC 20426.<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 Enforcement,
Division of Energy Market Oversight, Federal Energy Regulatory
Commission, 888 First Street, NE., Washington, DC 20426. (202) 502-
6341.
    Jeffery S. Dennis (Legal Information), Office of the General
Counsel, Federal Energy Regulatory Commission, 888 First Street, NE.,
Washington, DC 20426.<PHONE_NUMBER>.

SUPPLEMENTARY INFORMATION:

Table of Contents

                                                               Paragraph
                                                                 Nos.

I. Background...............................................          3.
    A. The Development of ISOs and RTOs.....................          3.
    B. Interest in Long-Term Firm Transmission Rights.......          6.
    C. Staff Paper on Long-Term Transmission Rights.........         11.
    D. Energy Policy Act of 2005............................         14.
    E. Notice of Proposed Rulemaking........................         15.
II. Discussion..............................................         16.
    A. Overview.............................................         16.
    B. Definitions..........................................         24.
        1. Organized Electricity Market.....................         24.
        2. Load Serving Entity and Service Obligation.......         34.
        3. Long-Term Power Supply Arrangement...............         55.
        4. Transmission Organization........................         63.
    C. Commission Interpretation of EPAct 2005 Requirements.         70.
    D. Commission's Approach, Regional Flexibility, and              84.
     Regional Seams Issues..................................
    E. Guidelines for the Design and Administration of Long-        108.
     Term Firm Transmission Rights in Organized Electricity
     Markets................................................
        Guideline (1)--Specify Source, Sink and Quantity....        108.
        Guideline (2)--Long-Term Hedge That Cannot Be               122.
         Modified...........................................
        Guideline (3)--Rights Made Available by Expansions          185.
         Go to Parties That Pay for the Upgrade.............
        Guideline (4)--Term of Rights Must be Sufficient to         217.
         Hedge Long-Term Power Supply Arrangements..........
        Guideline (5)--Load Serving Entities with Long-Term         273.
         Power Supply Arrangements Have Priority to the
         Existing System....................................
        Guideline (6)--Rights are Reassignable to Follow            331.
         Load...............................................
        Guideline (7)--Auction Not Required.................        361.
        Guideline (8)--Balance Adverse Economic Impacts.....        394.
    F. Transmission Planning and Expansion..................        429.
    G. Alternative Designs for Long-Term Firm Transmission          458.
     Rights.................................................
    H. Miscellaneous Comments...............................        477.
    I. Implementation of the Final Rule and Compliance              479.
     Issues.................................................
III. Information Collection Statement.......................        496.
IV. Environmental Analysis..................................        500.
V. Regulatory Flexibility Act Certification.................        501.
VI. Document Availability...................................        502.
VII. Effective Date and Congressional Notification..........        505.

Before Commissioners: Joseph T. Kelliher, Chairman; Nora Mead Brownell,
and Suedeen G. Kelly; Order No. 681; Final Rule

    1. In this Final Rule, the Commission is amending 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 each of the guidelines
established by the Commission in this Final Rule. We take this action
pursuant to section 1233 of the Energy Policy Act of 2005 (EPAct 2005),
which added new section 217 to the Federal Power Act (FPA).\1\ This
Final Rule will require each transmission organization subject to its
requirements to file with the Commission, no later than January 29,
2007, either (1) tariff sheets and rate schedules that make available
long-term firm transmission rights that satisfy each of the guidelines
set forth in the final regulations, or (2) an explanation of how its
current tariff and rate schedules already provide for long-term firm
transmission rights that satisfy each of the guidelines. A transmission
organization approved by the Commission for operation after January 29,
2007 will be required to satisfy the requirements of this Final Rule.
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    \1\ Pub. L. 109-58, Sec.  1233, 119 Stat. 594, 957 (2005).
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    2. The guidelines adopted in this Final Rule will give transmission
organizations the flexibility to propose designs for long-term firm
transmission rights that reflect regional preferences and accommodate
their regional market designs, while also ensuring that the objectives
of Congress expressed in new section 217(b)(4) of the FPA are met. 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 reasonable needs of load
serving entities to support long-term power supply arrangements used to
satisfy their service obligations.

I. Background

A. The Development of ISOs and RTOs

    3. In Order No. 888, the Commission found that undue discrimination
and anticompetitive practices existed in the provision of electric
transmission service in interstate commerce.\2\ 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.\3\ 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 \4\ and set out 11 principles for
assessing ISO proposals submitted to the Commission.\5\ Following Order
No. 888, several voluntary ISOs were established and approved by the
Commission.
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    \2\ 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).
    \3\ 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.
    \4\ Order No. 888 at 31,655; Order No. 888-A at 30,184.
    \5\ Order No. 888 at 31,730.
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    4. In light of the creation of these ISOs and other changes in the
electric industry, the Commission issued Order No. 2000.\6\ 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 necessary for continued development of
competitive electricity markets \7\ and that opportunities for undue
discrimination continued to exist.\8\ As a result, the Commission
adopted rules 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.\9\ In Order No. 2000, the Commission
established the minimum characteristics and functions that an RTO must
satisfy to gain Commission approval.\10\ Under Order No. 2000, the
Commission has approved the voluntary formation of a number of RTOs.
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    \6\ 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).
    \7\ Order No. 2000 at 30,992-93 and 31,014-15.
    \8\ Id. at 31,015-17.
    \9\ Id. at 31,024.
    \10\ Id. at 31,106 et seq.
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    5. 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. 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. 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) \11\ 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. In general, load serving entities receive FTRs
through either direct allocation or through a two-step process in which
the load serving entity is first allocated auction revenue rights
(ARRs) and then either uses those rights to purchase FTRs, or has the
ability under the transmission organization tariff to convert them to
FTRs.\12\
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    \11\ While ``FTR'' is sometimes used to refer to ``firm
transmission rights,'' in this Final Rule we use this acronym to
refer to the various forms of financial transmission rights that
exist in organized electricity markets. In some markets, these are
referred to as congestion revenue rights or transmission congestion
contracts.
    \12\ For a more detailed discussion, see Long-Term Firm
Transmission Rights in Organized Electricity Markets, Notice of
Proposed Rulemaking, 71 FR 6693 (Feb. 9, 2006), FERC Stats. & Regs.
] 32,598 at P 27 (2006) (NOPR). As we noted in the NOPR, ARRs confer
the right to collect revenues from the subsequent FTR auction.
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B. Interest in Long-Term Firm Transmission Rights

    6. In recent years, interest in long-term firm 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.
    7. There are several important differences between transmission
service under the Order No. 888 pro forma Open Access Transmission
Tariff (OATT) and transmission rights in organized electricity markets
that use LMP and FTRs.\13\ However, the differences that are most
relevant for purposes of this Final Rule concern the management of
congestion, the recovery of congestion costs and the availability of
long-term service arrangements.
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    \13\ A detailed discussion of transmission rights in traditional
and organized markets was presented in the NOPR at P 15-33.
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    8. Under the OATT, the transmission provider in the first instance
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.\14\
However, in the organized electricity markets that use LMP, the
transmission organization manages congestion through the use of
locational prices that are determined by bids and offers by markets
participants at given locations. 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 procedures and service curtailments than a
transmission provider under the OATT.
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    \14\ The transmission provider may also need to curtail service
to certain customers.
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    9. 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 does provide price certainty. 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 the long-term, which in turn can help facilitate the
planning and financing of large generation facilities and other long-
term power supply arrangements.
    10. In contrast, a transmission organization in a region with an
organized electricity market recovers congestion costs measured as
differences in the locational price 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. 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 who wants to
procure supplies on a long-term basis because it will not know from
year to year with any degree of certainty whether its award of FTRs
will 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.

C. Staff Paper on Long-Term Transmission Rights

    11. In May 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.\15\ A number of commenters on the Staff Paper
argued 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. Most of
the parties in this 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.
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    \15\ 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).
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    12. A second group of commenters on the Staff Paper 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. They also
supported limiting the quantity of system capability given over to
long-term FTRs for at least an initial period.
    13. Finally, some respondents felt that long-term rights should not
be introduced at this time. These parties were concerned that the
introduction of multi-year rights could introduce inequity and
inefficiency into the organized electricity markets because 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.

D. Energy Policy Act of 2005

    14. On August 8, 2005, EPAct 2005 \16\ became law. As noted above,
section 1233 of EPAct 2005 added a new section 217 to the FPA, which
provides:
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    \16\ Pub. L. 109-58, 119 Stat. 594

    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.\17\
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    \17\ Pub. L. 109-58, Sec.  1233, 119 Stat. 594, 958.

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    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.\18\
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    \18\ Id. at 960. Transmission organization is defined in EPAct
2005 as ``a Regional Transmission Organization, Independent System
Operator, independent transmission provider, or other transmission
organization finally approved by the Commission for the operation of
transmission facilities.'' Pub. L. 109-58, Sec.  1291, 119 Stat.
594, 985. Below, we adopt this definition with a minor modification
for purposes of this Final Rule.

E. Notice of Proposed Rulemaking

    15. On February 2, 2006, the Commission issued a NOPR that proposed
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.\19\ As discussed in more
detail below, the NOPR proposed eight guidelines, and sought comments
on various issues raised by the introduction of long-term firm
transmission rights in the organized electricity markets.
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    \19\ See supra note 12.
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II. Discussion

A. Overview

    16. In adopting this Final 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. The
guidelines we adopt in this Final Rule are designed and intended
primarily to ensure that

the long-term firm transmission rights that are made available by
transmission organizations that are subject to the rule have
characteristics that will support a long-term power supply arrangement.
These guidelines provide 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.
    17. Many of the comments received by the Commission express concern
that the provision of long-term firm transmission rights will result in
a drastic redistribution of transmission rights, with transmission
organizations required to provide long-term rights to load serving
entities regardless of feasibility or impact on other market
participants. This concern is unfounded. While this Final Rule
unequivocally requires transmission organizations to offer long-term
firm transmission rights with characteristics that will support long-
term power supply arrangements, in most cases, offering such rights
should not require major changes in allocations or allocation
procedures.\20\ Our intent with regard to the existing transmission
system is that load serving entities be able to request and obtain
transmission rights up to a reasonable amount on a long-term firm
basis, instead of being limited to obtaining exclusively annual
rights.\21\ Offering such rights should not force transmission
organizations to provide rights to the existing system to one party
that are infeasible. We expect that transmission organizations will be
able to integrate long-term firm transmission rights into their
existing procedures for assessing the feasibility of requests for
transmission service.
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    \20\ As we discuss in more detail below, while we do not believe
major changes to existing allocation procedures will be necessary,
Congress did not intend to protect existing or future allocation
methodologies from the implementation of section 217(b)(4) of the
FPA. See new section 217(c) of the FPA, Pub. L. 109-58, Sec.  1233,
119 Stat. 594, 958-59.
    \21\ Capacity available would be limited to that which is
generally available and excludes capacity that is the exclusive
right of a participant, e.g., a participant that paid for such
capacity and obtained FTRs for that payment.
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    18. While it is difficult to generalize, given the flexibility
afforded in this Final Rule, we expect that in most transmission
organizations with organized electricity markets the process for
obtaining a long-term firm transmission right will not be substantially
different from the current procedures. Most transmission organizations
will be able to use their current allocation/auction systems to allow
load serving entities to nominate source-to-sink transmission rights on
a longer-term basis than is currently available. Transmission
organizations will then assess those requests for feasibility and award
a feasible set of transmission rights, as they do today. This Final
Rule also allows the transmission organization to place reasonable
limits on the total amount of capacity it will offer as long-term
rights. Thus, this Final Rule does not necessarily guarantee that a
load serving entity will be able to obtain long-term firm transmission
rights to hedge its entire resource portfolio or be able to obtain all
the long-term firm transmission rights it requests. Once long-term
rights are awarded to a load serving entity, however, this Final Rule
requires that they be fully funded over their entire term, as discussed
in guideline (2) below.
    19. As we noted in the NOPR and reaffirm in this Final Rule,
transmission organizations must provide the opportunity for market
participants to obtain long-term firm transmission rights that are not
currently available by supporting an expansion or upgrade of grid
transfer capability. 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. The transmission organization tariffs must
clearly and specifically provide for this arrangement, if they do not
already. Guideline (3) addresses this requirement. This will enable
load serving entities to obtain long-term rights that they may have
requested but not received due to infeasibility.
    20. Moreover, in this Final Rule we also require transmission
organizations with organized electricity markets to explain how their
transmission system planning and expansion policies will ensure that
long-term firm transmission rights, once allocated, remain feasible
over their entire term.
    21. Together, these provisions will ensure that transmission
systems are expanded where necessary to ensure the continued
feasibility of allocated long-term firm transmission rights, while also
giving market participants an explicit right to obtain new incremental
transmission rights on a long-term basis, in accordance with the
prevailing cost allocation methodology in the region.\22\
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    \22\ We are not requiring any ``obligation to build'' that does
not already exist under Order No. 888.
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    22. We understand that specifying and allocating long-term firm
transmission rights supported by existing transfer capability will
raise difficult issues that must be addressed by transmission
organizations and their stakeholders as proposals are developed to
comply with this Final Rule. As we discuss in more detail, we believe
that the approach we adopt in this Final Rule will give transmission
organizations and their stakeholders sufficient flexibility to design
long-term firm transmission rights that fit their prevailing market
design while also ensuring that the rights have certain fundamental
properties necessary to achieve Congress's objectives in section
217(b)(4) of the FPA. We also clarify below that while each guideline
permits flexibility in its implementation, transmission organizations
with organized electricity markets must satisfy each of the guidelines
in this Final Rule.
    23. This Final Rule largely adopts the overall approach as well as
the specific guidelines and definitions proposed in the NOPR. In
response to the comments received, however, the Commission has made the
following changes to the proposal, as discussed in this preamble:

     Guideline (3) (Rights Made Available by Expansion Go to
Parties That Pay for the Upgrade): We have removed the requirement
that the term of long-term rights from expansion be equal to life of
facility or a lesser term requested by the party paying for the
upgrade. Based on the comments on the difficulty of defining life of
facility, we will defer to transmission organizations to develop
terms based on existing market rules and stakeholder needs. We
encourage transmission organizations to harmonize the terms for
long-term rights awarded for new capacity with the terms of long-
term rights to existing transmission capacity as much as possible.
     Guideline (4) (Term of Rights Must Be Sufficient To
Hedge Long-Term Power Supply Arrangements): We have added a
provision that transmission organizations and stakeholders may
determine the length of terms and use of renewal rights to provide
long-term transmission rights, but must offer coverage for at least
a 10-year sequence. Our objective is to balance regional flexibility
in defining terms of rights with the need to ensure that those terms
are sufficient to allow load serving entities to hedge their long-
term power supply arrangements.
     Guideline (5) (Load Serving Entities With Long-Term
Power Supply Arrangements Have Priority to the Existing System): We
have revised this guideline in two respects. First, we have
eliminated the preference for load serving entities with long-term
power

supply arrangements and replaced it with a broader preference for
load serving entities in general vis-[agrave]-vis non-load serving
entities. This broader preference is fully supported by the statute
and better meets the needs of organized electricity markets. We
believe that Congress's intent in enacting section 217 was to
provide long-term firm transmission service to load serving entities
and that load serving entities in general should be ``first in
line'' for long-term transmission rights when existing capacity is
limited. As originally proposed, guideline (5) could have
disadvantaged load serving entities who do not engage in long-term
power supply arrangements, a result that we do not believe Congress
intended. Proposed guideline (5) could have also presented difficult
administrative burdens for transmission organizations, including the
burden of evaluating power supply contracts to determine if they
qualify for the preference. In addition to addressing these
concerns, broadening the preference also makes it possible for
transmission organizations to apply the same basic principles for
allocating long-term firm transmission rights that they currently
use for the initial allocation of short-term firm transmission
rights, or auction revenue rights. As a result of this change in the
guideline, load serving entities will not be required to provide
evidence of a long-term power supply arrangement.
    We have also revised guideline (5) to allow transmission
organizations to place reasonable limits on the amount of existing
transmission capacity made available for long-term firm transmission
rights. We have done so in recognition of the expected reluctance of
transmission organizations to commit all of their existing grid
capacity to long-term firm transmission rights due to uncertainty
regarding load growth, changes in power flows and the full funding
requirement of this Final Rule. This will also help to accommodate
load serving entities that prefer short-term rights. In addition,
commenters claim that the principal need for long-term firm
transmission rights is to support long-term power supply
arrangements for base load generation, not peaking or intermediate
generation.
     Guideline (8) (Balance Adverse Economic Impacts): We
have elected not to adopt this guideline in the Final Rule. This
guideline is not needed as it requires, in effect, nothing more than
adherence to the FPA requirement that public utility tariffs must be
just and reasonable and not unduly discriminatory. Moreover, it
could have been misinterpreted to require long-term firm
transmission right proposals to meet a different or higher standard,
something the Commission did not intend or believe that Congress
intended.
     Definition of ``Long-Term Power Supply Arrangement'':
Because we have deleted the reference to ``long-term power supply
arrangements'' from guideline (5), that term is only used in
guideline (4), relating to the term of long-term firm transmission
rights. The Final Rule removes the specific definition of long-term
power supply arrangements proposed in the NOPR, and addresses issues
related to our definition of long-term power supply arrangements
under guideline (4).
     Transmission Planning and Expansion: This Final Rule
requires that each transmission organization with an organized
electricity market implement transmission system planning and
expansion procedures to accommodate long-term firm transmission
rights that are allocated or awarded to ensure that they remain
feasible over their entire term. We also require each such
transmission organization to make its planning and expansion
practices and procedures publicly available, including both the
actual plans and any underlying information used to develop the
plans.

B. Definitions

1. Organized Electricity Market
    24. In the NOPR, the Commission proposed 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.'' \23\ The Commission stated that it
proposed this definition to ensure that the Final Rule in this
proceeding applies to any transmission organization that is the
transmission provider in its region and has a day-ahead and/or real-
time bid-based energy market, administered by the transmission
organization itself or by another entity. We sought comment on the
scope of this proposed definition.
---------------------------------------------------------------------------

    \23\ NOPR at P 8.
---------------------------------------------------------------------------

Comments
    25. AMPA \24\ and Public Power Council both argue that the proposed
definition is too narrow and should be expanded to include ``Day 1''
RTO/ISO markets, non-RTO/ISO markets, and other forms of ``organized
markets'' (which can include bilateral markets that use a form
contract).\25\ Public Power Council argues that the proposed definition
could lock the Commission into adopting the types of markets described
in the definition to the exclusion of other types of markets, and that
section 217 of the FPA does not support the Commission's narrow
reading.
---------------------------------------------------------------------------

    \24\ A list of commenters on the NOPR and the acronyms used to
refer to them in this preamble is attached as Appendix A.
    \25\ NRECA, while not recommending any change to the proposed
definition, notes that the issues raised over the availability of
long-term firm transmission rights also arise in transmission
organizations without Day 2 markets and on the systems of non-
independent entities.
---------------------------------------------------------------------------

    26. Other commenters argue that the definition should be narrowed.
TAPS, for example, asserts that the Final Rule should not apply in
regions where the OATT provides for long-term physical transmission
rights, particularly the Southwest Power Pool. According to TAPS, the
last clause of the definition of organized electricity markets (``where
the prices are used by a transmission organization for establishing
transmission usage charges'') excludes SPP because the prices produced
by its imbalance market will not establish transmission usage charges.
TAPS requests that the Commission clarify that as currently designed
SPP will not be subject to the Final Rule.
    27. PG&E, EPSA and TAPS all state that because the proposed rule
primarily addresses markets that use locational market-based congestion
management mechanisms like LMP and have FTRs, the Final Rule should
clearly state that it only applies to those markets, and only addresses
long-term financial transmission instruments. PG&E recommends that the
Commission issue a parallel rule providing for long-term transmission
rights in markets that do not use a market-based congestion management
mechanism.
    28. In reply comments, NRECA opposes proposals to narrow the
definition of organized electricity market, arguing that the need for
long-term firm transmission rights and the language of the statute are
not limited to transmission organizations with locational pricing
structures.
    29. APPA states that it supports the proposed definition of
organized electricity market, but suggests that it be revised to
replace ``auction-based market'' with ``a centralized market'' because
use of ``auction-based'' implies that buyers and sellers in RTO markets
have more choice and autonomy than they do in practice.
Commission Conclusion
    30. We will adopt the definition of organized electricity market
proposed in the NOPR with one modification. Specifically, we modify the
first clause of the definition to state that organized electricity
market ``means an auction-based day ahead and real time wholesale
market * * *.'' We make this modification to clarify the application of
this Final Rule and ensure that the definition captures the
transmission organizations with organized electricity markets using LMP
and FTRs to which Congress directed the Commission to apply this Final
Rule to in section 1233(b) of EPAct 2005. Today, those electricity
markets do not offer financial transmission instruments supported by

existing capacity with terms longer than one year, and thus entities
are not able to obtain a ``firm'' transmission right on a long-term
basis in those markets as section 217(b)(4) of the FPA directs. As a
result, they are appropriately the focus of this Final Rule.
    31. The Commission will not expand the definition to include other
RTO/ISO regions (sometimes called ``Day 1'' markets), non-RTO/ISO
transmission providers, or any other electricity market structure.
Applying the Final Rule to non-RTO/ISO markets would not be appropriate
because EPAct 2005 requires us to implement section 217(b)(4) in this
rulemaking in ``transmission organizations with organized electricity
markets,'' and non-RTO/ISO transmission providers by definition are not
transmission organizations.\26\ And while Public Power Council is
correct that there may be other electricity market structures, the
definition we adopt here is only for the purposes of this Final Rule
and is crafted to ensure that the appropriate entities are subject to
the Final Rule. Additionally, as we noted in the NOPR, non-RTO/ISO
transmission providers and other RTO/ISOs offer long-term physical
transmission service under the Order No. 888 OATT without rates that
vary with congestion costs.\27\ The Commission recently issued a NOPR
in Docket Nos. RM05-25-000 and RM05-17-000 that would institute reforms
to the OATT. It is more appropriate to consider in that rulemaking any
issues related to the application of section 217(b)(4) of the FPA to
the other markets identified by commenters, particularly issues related
to coordinated, open and transparent transmission system planning.
---------------------------------------------------------------------------

    \26\ This is not to say that there might not in the future be
types of transmission organizations other than ISOs and RTOs
approved by the Commission that operate transmission facilities and
provide transmission service. The new FPA definition of transmission
organization leaves open this possibility. At the current time,
however, RTOs and ISOs are the only such organizations approved by
the Commission.
    \27\ While transmission organizations with organized electricity
markets are also expected to have OATTs that meet the requirements
of Order No. 888, the total cost of transmission service in those
transmission organizations varies with the cost of congestion, and
such transmission organizations only offer FTRs to hedge congestion
costs with short-terms.
---------------------------------------------------------------------------

    32. In response to TAPS, we clarify that SPP is not subject to this
Final Rule because its current market design does not fit within the
definition of organized electricity market that we adopt for purposes
of this rule.
    33. Finally, we decline to revise the ``auction-based'' language as
APPA requests. This language simply recognizes that the organized
electricity markets Congress intended to be subject to this Final Rule
are those that utilize auction mechanisms for the buying and selling of
electric energy. We note that we are adopting this definition for the
purposes of this Final Rule only, and do not intend that it will
necessarily apply in other contexts.
2. Load Serving Entity and Service Obligation
    34. We proposed to define ``load serving entity'' and ``service
obligation,'' for purposes of the proposed rule, exactly as Congress
defined those terms in new section 217 of the FPA. Specifically, we
proposed to define load serving entity as ``a distribution utility or
electric utility that has a service obligation.'' \28\ We proposed to
define service obligation as ``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.'' \29\
---------------------------------------------------------------------------

    \28\ NOPR at P 7, citing Pub. L. 109-58, Sec.  1233, 119 Stat.
594, 957. EPAct 2005 defines electric utility as ``a person or
Federal or State agency (including an entity described in section
210(f)) that sells electric energy.'' Pub. L. 109-58, Sec.  1291,
119 Stat. 594, 984.
    \29\ NOPR at P 7, citing Pub. L. 109-58, Sec.  1233, 119 Stat.
594, 958.
---------------------------------------------------------------------------

Comments
    35. APPA, E.ON, NRECA, PG&E and Public Power Council all express
support for the proposed definitions.
    36. Several commenters (including Industrial Consumers, CAISO,
NARUC, National Grid and SDG&E) argue that the proposed definitions in
the NOPR would exclude several entities that should be eligible for
long-term firm transmission rights because they are not a
``distribution utility'' or ``electric utility.'' These entities
include industrial customers who serve their own load pursuant to state
law, several types of retail service providers, community aggregators,
and various non-public utilities. The comments generally seek
clarification that all of these various entities are ``load serving
entities'' for purposes of this rule.
    37. More specifically, Industrial Consumers and Alcoa explain that
while many large industrial customers are permitted under state law to
self-supply their own load, usually by registering as a retail
provider, not all of these states use the term ``load serving entity.''
Industrial Consumers argue that entities who have qualified as retail
electric providers under state law meet the definition of ``electric
utility'' under EPAct 2005, and request that the Commission
unambiguously state that entities who are qualified to serve retail
load under state law, including those self-supplying, are load serving
entities for purposes of the Final Rule and thus qualify for long-term
firm transmission rights.
    38. Regarding retail service providers, several commenters
(including CAISO, EEI, NARUC and National Grid) seek clarifications
regarding whether various types of service providers in retail access
states are load serving entities under the proposed definition. NARUC
notes that states with retail choice programs either may have multiple
sellers of electricity to end users, or may use an auction process
whereby the distribution utility takes delivery of the power supply and
bills the cost to customers, making it the only seller.\30\ To protect
and accommodate these choices made by the states, and to be consistent
with Congress' intent that the protections in section 217 of the FPA be
available to all customers, it asks the Commission to clarify that all
of these entities are ``electric utilities'' and/or ``distribution
utilities,'' thereby making them load serving entities and eligible to
obtain long-term firm transmission rights.\31\ OMS, noting specifically
that Illinois utilities will soon be required to use an auction process
to procure supply and that auction winners under this format would not
meet either definition, asks the Commission to revise the definition of
load serving entity to replace ``a distribution utility or electric
utility'' with ``an entity,'' and revise the definition of service
obligation to replace ``electric utility'' with ``entity.'' EEI and
National Grid both note that under certain retail access structures
service obligations (including the default service obligation) may be
reassigned for terms that are less than the term of long-term firm
transmission rights. EEI asserts that the proposed definition of load
serving entity should be clarified to be simply the distribution
utility, unless its service obligation has been reassigned, while
National Grid suggests that the load serving entity

should be the electric utility when it holds the service obligation,
and the distribution utility in the first instance. National Grid also
asserts that the Commission should clarify that the term ``electric
utility'' is defined in section 3(22) of the FPA (any ``person or
Federal or State agency * * * that sells electric energy''), which
would encompass both municipal utilities and merchant suppliers not
normally subject to state regulation.
---------------------------------------------------------------------------

    \30\ National Grid notes that pursuant to state law, its
distribution utilities have at various times been required to
contract with wholesale suppliers to meet their load obligations
(including congestion cost exposure), while in other retail choice
programs those responsibilities have been directly assigned to
retail suppliers.
    \31\ In its reply comments, NARUC reiterates its request,
further stating that the Commission should clarify that vertically-
integrated utilities, municipal utilities and cooperatives in
traditionally regulated states, power suppliers in retail states,
and distribution utilities or auction winners in other states are
all ``electric utilities'' and/or ``distribution utilities,'' and
thus eligible to obtain long-term firm transmission rights.
---------------------------------------------------------------------------

    39. Santa Clara asserts that the definition of load serving entity
should include non-public utilities (as defined in section 201(f) of
the FPA), subsidiary agencies of non-public utilities, and entities in
which non-public utilities hold an interest (such as joint action
agencies), since each either serve load under statutory obligations to
serve or facilitate such service. Similarly, California DWR and MWD
argue that the Commission should revise the definition of load serving
entities to include water pumping entities.\32\ They assert that in new
section 217(g) of the FPA, Congress recognized a need to expand the
definition of load serving entity to include such entities.\33\ To
comply with section 217(g), California DWR and MWD contend that the
Commission should revise the proposed definition to define load serving
entity to mean ``a distribution utility, or an electric utility that
has a service obligation, or other wholesale transmission user that
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.'' \34\
---------------------------------------------------------------------------

    \32\ MWD notes that its water pumping operations require large
amounts of power (roughly 2-3 percent of California's total energy
requirement), and that these operations require long-term
transmission rights to achieve reliable water delivery.
    \33\ Specifically, section 217(g) provides that ``[t]he
Commission shall ensure that any entity described in section 201(f)
that owns transmission facilities used predominately to support its
own water pumping facilities shall have, with respect to the
facilities, protections for transmission service comparable to those
provided to load serving entities pursuant to this section.'' See
Pub. L. 109-58, Sec.  1233, 119 Stat. 594, 959.
    \34\ Reply Comments of California DWR at 9.
---------------------------------------------------------------------------

    40. MSATs seek clarification that as stand-alone transmission
companies that do not own generation or distribution facilities, buy or
sell energy, serve loads or act as transmission customers or market
participants, they are not considered load serving entities under the
Commission's proposed regulations.
    41. Ameren asks the Commission to clarify that the definition of
service obligation includes future obligations, and not just
obligations existing at the effective date of the Final Rule, which it
states will provide certainty and reassure load serving entities that
long-term firm transmission rights will continue to be made available
in the future.
    42. Commenters (including CAISO, PG&E and NU) also raise issues and
seek clarification specifically with regard to the application of the
service obligation definition in retail access frameworks, and
particularly seek clarification as to whether a default service
obligation is a ``service obligation.'' According to CAISO, these
clarifications are important because they will impact the eligibility
rules for long-term firm transmission rights and the rules for
transferring those rights as end-users switch providers. Commenters
such as PG&E assert that entities holding the default service
obligation, even though they may not be serving the load now, must be
able to plan to meet that load should they be required to serve it in
the future. Coral Power states that the definition of service
obligation should be expanded because as proposed by the Commission, it
only applies to distribution companies or entities that provide
electric service to end-users under contracts. It argues that the
definition should include wholesale power suppliers that provide
hedging services to competitive retail suppliers or that have assumed
load obligations under default service or retail access programs.
    43. Commenters (including NU and PG&E) also raise issues with the
``long-term contracts'' language in the definition, arguing that it has
the potential to discriminate against load serving entities in retail
access jurisdictions, since such entities do not typically enter into
long-term power supply contracts. NU argues that in New England, the
definition would favor municipal utilities (whose customers are not
included in retail access programs) and utilities from outside the
region that serve load through New England resources.\35\ Accordingly,
it asks that the Commission narrow the definitions to limit eligibility
for long-term firm transmission rights to entities that serve customers
within the same region.
---------------------------------------------------------------------------

    \35\ Comments of NU at 3-4.
---------------------------------------------------------------------------

Commission Conclusion
    44. In the Final Rule, the Commission is adopting the definitions
of load serving entity and service obligation provided by Congress in
EPAct 2005 and proposed in the NOPR. We believe using these definitions
as Congress provided them will most closely effectuate the intent of
Congress in section 217(b)(4) of the FPA. We will, however, offer
several clarifications.
    45. At the outset, we note that the definition of load serving
entity is important in this Final Rule only in that it establishes a
priority in the allocation of long-term firm transmission rights when
necessary under guideline (5). It does not determine eligibility for
long-term firm transmission rights, as some commenters suggest. All
market participants are eligible for long-term firm transmission
rights.
    46. In response to National Grid, we clarify that the term
``electric utility,'' as used in the definition of load serving entity,
is defined in section 3(2) of the FPA as ``a person or Federal or State
agency (including an entity described in section 201(f)) that sells
electric energy.'' \36\ This expansive definition will cover many of
the entities for which commenters seek clarification as to their status
as load serving entities.
---------------------------------------------------------------------------

    \36\ 16 U.S.C. 796(22) (2000), as amended by EPAct 2005, Pub. L.
109-58, Sec.  1291(b)(1), 119 Stat. 594, 984.
---------------------------------------------------------------------------

    47. With regard to large industrial customers who self-supply their
own load, while some of these entities may not technically ``sell * * *
electric energy,'' we construe them to be load serving entities for
purposes of this Final Rule, to ensure that Congress's objectives in
section 217 of the FPA are fulfilled. Thus, transmission organizations
should treat them as such when complying with this rule.
    48. With regard to non-public utilities, the Commission notes that
the definition of electric utility discussed above, as amended by EPAct
2005, includes ``an entity described in section 201(f)'' of the FPA,
i.e. non-public utilities. As a result, they are within the definition
of load serving entity, provided, of course, that they have a service
obligation. Additionally, in response to California DWR and MWD, we
note that the definition of load serving entity provided by Congress
appears to already capture water pumping entities, which are non-public
utilities. New section 217(g) of the FPA provides that ``[t]he
Commission shall ensure that any entity described in section 201(f)
that owns transmission facilities used predominately to support its own
water pumping facilities shall have, with respect to the facilities,
protections for transmission service comparable to those provided to
load serving entities pursuant to this section.'' \37\ In light of this
Congressional

directive, we clarify, to the extent necessary, that water pumping
entities with the characteristics described in section 217(g) are load
serving entities for purposes of this Final Rule.
---------------------------------------------------------------------------

    \37\ Pub. L. 109-58, Sec.  1291(b)(1), 119 Stat. 594, 984.
---------------------------------------------------------------------------

    49. MSATs request that we clarify that stand-alone transmission
companies are not load serving entities for purposes of this rule. We
clarify that as described by MSATs, stand-alone transmission companies
that do not own generation or distribution facilities, buy or sell
energy, serve loads or act as transmission customers are not load
serving entities for purposes of this Final Rule. We emphasize,
however, that this clarification should not be read broadly to suggest
that other types of stand-alone transmission companies (either existing
or that might be developed) with different characteristics from those
described by MSATs will not be load serving entities under this Final
Rule. The Commission will consider these issues on a case-by-case
basis, as necessary.
    50. In response to those seeking clarifications regarding various
types of retail service providers, we note that many retail service
providers will be a ``person * * * that sells electric energy,'' thus
making it an electric utility and, consequently, they can be a load
serving entity provided they have a service obligation. The Commission
cannot decide here, however, whether each possible entity operating in
state retail electric markets will meet the definition of load serving
entity. We agree with NARUC, however, that Congress intended to broadly
protect the ability of load serving entities with service obligations
to obtain transmission service. Thus, transmission organizations should
ensure that different types of retail service providers that have
service obligations are accommodated when implementing the Final Rule.
    51. As noted above, commenters raising issues regarding the
application of the service obligation definition in retail access
frameworks focus primarily on the default service obligation, which
generally (with variation from state-to-state) requires the entity
subject to that obligation to provide electric service to customers who
do not have another supplier (either because they did not choose one or
because their supplier left the market). Under the definition provided
by Congress, a default service obligation only becomes a service
obligation for purposes of this rule when the entity holding the
default obligation is actually required to serve the load, i.e. when
the competitive supplier either stops serving the load or the load
switches to the default supplier. A default service obligation only
becomes ``a requirement applicable to, or the exercise of authority
granted to'' the default supplier when it must actually serve the load.
We understand the concerns expressed by PG&E and others that a utility
holding the default service obligation must plan to serve that load
should it be required to do so in the future. Transmission organization
rules currently provide that auction revenue rights (ARRs) or FTRs will
generally ``follow the load'' in instances where load switches
suppliers; guideline (6), discussed below, also requires that long-term
firm transmission rights allocated to load serving entities be
reassignable. As a result, when default suppliers assume the service
obligation, they will receive transmission rights that they can use to
serve the default load. While we are aware that those transmission
rights may not match the resources that the default supplier will use
to serve the load, this is a problem that already exists today, and is
not a result of our adoption of Congress's definition of service
obligation. Transmission organizations may consider whether any rules
are necessary (such as allowing or requiring holders of long-term
transmission rights to turn back those rights for reallocation) to deal
with this problem.
    52. We decline to revise the definitions of load serving entity and
service obligation to replace ``distribution utility or electric
utility'' and ``electric utility'' with ``an entity,'' as requested by
OMS. Congress chose to use these terms to limit these definitions, and
we are not persuaded to change them here, and do not believe such a
change is necessary to address OMS's concern. While OMS may be correct
that auction winners under Illinois' procurement mechanism may not meet
these definitions, the Illinois utilities that procure electric energy
under this mechanism and resell it to their customers (under their
service obligation) presumably meet the definitions of load serving
entity and service obligation, and thus should be able to obtain long-
term firm transmission rights to deliver that energy to load.
Similarly, we decline to define load serving entity to be only the
distribution utility, unless its service obligation has been
reassigned, as requested by EEI, or to be the distribution utility in
the first instance, as requested by National Grid. This would limit the
definition provided by Congress, which chose to include electric
utilities (other than distribution utilities) that have service
obligations in the definition, and we are unsure how these revisions
would address EEI and National Grid's concerns. As we note above, when
load serving obligations are reassigned, the new entity serving that
load will be a load serving entity and have a service obligation under
the definitions in this Final Rule, and associated transmission rights
will ``follow'' that load. Any problems associated with transmission
rights whose term is longer than the transferred service obligation may
be addressed in proposals to implement this rule; revising these
definitions do not appear to resolve such concerns.
    53. In response to Ameren, we clarify that the definition of
service obligation, as written by Congress and adopted by the
Commission in this Final Rule, includes future service obligations and
not simply those existing on the effective date of this rule. Nothing
in that definition, or in section 217(b)(4)'s charge that the
Commission exercise its FPA authority in a manner that facilitates the
planning and expansion of transmission facilities and enables load
serving entities to obtain long-term firm transmission rights, suggests
that service obligations should be limited to those existing as of the
effective date of this rule.
    54. Finally, we will not revise the definition in response to the
concerns raised by NU and PG&E regarding the ``long-term contracts''
language in the definition of service obligation. The definition
provides that a service obligation is either ``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 * * *.''
(emphasis added). Thus, having a long-term contract to serve load is
not necessary to have a service obligation under this definition. Load
serving entities in retail access jurisdictions will be interpreted to
have a service obligation under this rule if they are either required,
or have been given authority, under state law to provide electric
service. Thus, we do not believe the definition results in any
discrimination against load serving entities in those jurisdictions or
gives any favor to municipal utilities not included in retail access
programs.
3. Long-Term Power Supply Arrangement
    55. We noted in the NOPR that while new section 217(b)(4) of the
FPA requires the Commission to exercise its authority to enable load
serving entities to obtain long-term firm transmission rights ``for
long-term power supply arrangements made * * * or planned''

to meet service obligations, Congress did not define ``long-term power
supply arrangements'' in the legislation.\38\ Based on language in
section 217(b)(1) of the FPA, we proposed to define long-term power
supply arrangements as ``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.'' \39\
---------------------------------------------------------------------------

    \38\ NOPR at P 9 citing Pub. L. 109-58, Sec.  1233, 119 Stat.
594, 958.
    \39\ NOPR at P 9.
---------------------------------------------------------------------------

Comments
    56. NRECA and PG&E support the proposed definition. Public Power
Council also supports the proposed definition with two ``editorial
suggestions.'' First, it suggests removing the phrase ``with a term of
longer than one year'' after ``Federal generation facilities'' because
it is redundant. Second, it suggests replacing the word ``rights''
where it appears before the phrase ``to market the output of Federal
generation facilities'' with ``authority or obligation,'' since federal
Power Marketing Agencies (like BPA) have a statutory obligation, rather
than a ``right,'' to market the output of their facilities.\40\
---------------------------------------------------------------------------

    \40\ Public Power council notes that the Commission could also
interpret rights as a description of these statutory obligations.
---------------------------------------------------------------------------

    57. Commenters taking issue with the proposed definition addressed
three primary issues: (1) The ``longer than one year'' language, (2)
whether the definition should include specific criteria, and (3)
whether the definition unduly discriminates against load serving
entities in retail access states.
    58. APPA argues that the Commission should not define ``long-term
power supply arrangements'' as ``longer than one year,'' and should
instead harmonize this definition with minimum term of long-term firm
transmission rights discussed in guideline (4). PJM and TAPS also state
that this language is unreasonable, and argue that ``long-term power
supply arrangements'' should be defined as those with a minimum term of
10 years. According to TAPS, this change would appropriately limit the
availability of long-term rights to those long-term power supply
arrangements most poorly served by annual FTRs, particularly baseload
and renewable power arrangements with terms longer than 10 years.
    59. Some commenters suggest that the Commission revise the
definition of ``long-term power supply arrangements'' to require that
they have certain specific characteristics. CAISO and PG&E, for
example, suggest that to make more transparent the process of
validating requests for long-term rights, ``long-term power supply
arrangements'' should designate specific resources. Others argue that
to prevent inefficient allocations of long-term firm transmission
rights, the Commission's definition should require ``long-term power
supply arrangements'' to be firm for their entire term, specify
specific amounts of energy, and be for both capacity and energy.
Wisconsin Electric suggests that the definition exclude peaking
facilities. Wisconsin Electric also asks that the Commission clarify
that long-term leasing arrangements or other arrangements, in addition
to ownership, qualify as ``long-term power supply arrangements.''
    60. In response to CAISO, CMUA states that while it agrees that
contracts with flexible points of delivery are an implementation issue
that must be addressed, it is concerned that CAISO's proposed
modification is too narrow. According to CMUA, if CAISO's proposed
modification would make long-term transmission rights available only
for unit contingent contracts, it would create upheaval in the
bilateral markets of the West, where power supply contracts with
multiple resources are common.
    61. NSTAR suggests that the combination of this definition and
guideline (5) results in a long-term firm transmission right that is
not available to (and thus unduly discriminates against) load serving
entities that provide default service in retail access states because
such entities do not enter into ``long-term power supply
arrangements,'' as defined in the rule. According to NSTAR, these
entities do not generally own generation and do not enter into long-
term power supply contracts either because of the variable nature of
their service obligation from year to year or because state regulatory
requirements limit them to short-term power purchase agreements.
According to NSTAR, requiring long-term power supply arrangements
(including generation ownership or purchased power contracts) would
conflict with section 217's overall purpose to protect the transmission
rights of all end users and deal a blow to competitive retail electric
markets by benefiting long-term rights holders at the expense of retail
access loads holding shorter-term rights. NSTAR suggests that the
Commission correct this problem by adding ``or other arrangements for
the purpose of meeting a service obligation on a long-term basis'' to
the definition.
Commission Conclusion
    62. As discussed in more detail below, the Commission is removing
from guideline (5) the requirement that, in order to have priority in
the allocation of long-term firm transmission rights from existing
capacity, a load serving entity must hold long-term power supply
arrangements. Therefore, that term is only used in the final
regulations in guideline (4), relating to the term of long-term firm
transmission rights. Accordingly, we are removing the definition of
long-term power supply arrangements from the Final Rule, and will
generally discuss issues related to our definition of long-term power
supply arrangements under guideline (4), particularly with regard to
the length of such arrangements. The discrimination arguments raised by
certain parties in response to the proposed definition are discussed
under guideline (5).
4. Transmission Organization
    63. In the NOPR, we proposed to define ``transmission
organization'' as ``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.'' \41\ This
proposed definition is similar to the definition of transmission
organization provided by Congress in EPAct 2005, except that we added
the term ``independent.'' We explained in the NOPR that we added
``independent'' because we interpret section 1233(b) of EPAct 2005 to
require that long-term firm transmission rights be made available by
independent entities that are approved by the Commission (either
currently or in the future) to operate transmission facilities and have
organized electricity markets.
---------------------------------------------------------------------------

    \41\ NOPR at P 6.
---------------------------------------------------------------------------

Comments
    64. EPSA, PG&E and PJM all support the Commission's proposal to
include ``independent'' in the definition of transmission organization.
    65. APPA and AMPA, while supportive of the Commission's addition of
the word ``independent'' to the definition of ``transmission
organization'' provided by Congress, note that this addition raises
questions regarding the level of independence required to be considered
a ``transmission organization.'' Both raise

the question of whether ICT's are ``transmission organizations.'' APPA
argues that an ICT should not be considered an independent transmission
organization because it is employed and paid solely by the
transmission-owning utility. APPA adds, however, that it assumes the
Commission will apply a ``flexible, yet vigilant'' standard to
determine the independence of transmission organizations.\42\ AMPA, for
its part, asserts that given the broad intent of EPAct 2005, the
Commission should consider applying the NOPR to all organized
electricity markets with independent transmission providers, to ensure
that all load serving entities will receive protection for their
service obligations and long-term price certainty.
---------------------------------------------------------------------------

    \42\ Comments at APPA at 11.
---------------------------------------------------------------------------

    66. Public Power Council, on the other hand, specifically opposes
the addition of the word ``independent,'' arguing that it unduly
restricts the definition adopted by Congress, which intended that any
organization finally approved by the Commission for the operation of
transmission facilities (whether or not independent) would fall under
the statute. According to Public Power Council, Congress instead chose
to qualify ``other transmission organization'' with the phrase
``finally approved by the Commission for the operation of transmission
facilities,'' meaning any such transmission organization falls under
the statute whether or not it is independent.
Commission Conclusion
    67. The Commission will adopt the definition of transmission
organization proposed in the NOPR. In section 1233(b) of EPAct 2005,
Congress narrowed the Commission's implementation efforts to
``Transmission Organizations * * * with organized electricity
markets,'' even though the overall directive of section 217(b)(4)
applies more broadly. We believe that it is reasonable to interpret the
more focused directive in section 1233(b) as principally requiring that
the Commission implement section 217(b)(4), through rulemaking, in the
current independent RTOs and ISOs that operate centralized markets for
the purchase of electric energy and/or ancillary services, and any
similar transmission organizations that are created in the future. This
does not mean, however, that the requirements of section 217(b)(4) will
not apply to other transmission providers. The Commission is simply
adopting a definition of transmission organization for purposes of this
Final Rule that it believes comports with Congress's intent, expressed
in section 1233(b) of EPAct 2005, that the Commission act specifically
with regard to transmission organizations with organized electricity
markets.
    68. In response to comments concerning the level of independence
required to be a transmission organization, we note that prior to
approving transmission organizations (such as RTOs and ISOs) with
organized electricity markets, the Commission makes specific findings,
based on established standards, that the entity is independent from
market participants. We do not believe any further determination or
separate standard is required for purposes of this rule.
    69. With regard to comments seeking to clarify whether proposed
independent coordinators of transmission are transmission organizations
under this Final Rule, we note that these proposals are still
developing. Moreover, to date none of these proposed entities has
proposed to implement an organized electricity market as defined in
this Final Rule. As a result, the Commission will not address whether
such entities meet the definition of transmission organization unless
and until such time as they propose to establish an organized
electricity market.

C. Commission Interpretation of EPAct 2005 Requirements

    70. In addition to the comments below regarding our flexible
approach in the NOPR, several entities submitted comments generally
addressing our interpretation of the requirements of new section
217(b)(4) of the FPA and section 1233(b) of EPAct 2005 with respect to
long-term firm transmission rights in organized electricity markets.
Comments regarding specific interpretations of the statutory
requirements that we made in connection with the proposed guidelines
are addressed elsewhere in this Final Rule.
Comments
Long-Term Transmission Rights from Existing Capacity
    71. Some commenters, particularly Cinergy, Coral Power and NYISO,
argue that the Commission misinterprets section 217(b)(4) and section
1233(b) of EPAct 2005 as requiring the long-term firm transmission
rights be made available from existing capacity. They assert that those
provisions only require the Commission to exercise its authority to
facilitate the planning and expansion of transmission facilities in a
manner that allows load serving entities to secure long-term
transmission rights. Thus, they contend that the Commission
inappropriately gives independent effect to the second clause of the
statute (``enables load serving entities to secure firm transmission
rights * * * on a long-term basis''), when the true thrust of the law
is its first clause (``[t]he Commission shall exercise * * * [its]
authority * * * in a manner that facilitates the planning and expansion
of transmission facilities * * *''). The second clause, they contend,
only modifies the first.
    72. In reply comments, APPA, New England Public Systems, NRECA,
Peabody, and TAPS urge the Commission to reject Cinergy's
interpretation of the statute. In general, they state that the
Commission correctly reads section 217(b)(4) as providing two
directives: (1) Facilitating transmission planning and expansion, and
(2) enabling load serving entities to obtain long-term transmission
rights for their long-term power supply arrangements. TAPS argues, for
example, that nothing in the statute's long-term rights clause
restricts such rights to new capacity, as Cinergy and others suggest,
and further asserts that such a reading would inappropriately ``sell
short'' and render both the long-term rights and planning provisions a
nullity. Similarly, APPA contends that if planning and expansion were
all Congress sought to address, it would not have included the second
clause of section 217(b)(4).
Need To Require Long-Term Financial Rights
    73. Cinergy and others note a difference between long-term
transmission rights and long-term FTRs. According to Cinergy, load
serving entities can already acquire long-term transmission rights, and
Congress would have used ``and'' instead of ``or'' if it intended to
require RTOs to also provide long-term FTRs.\43\ IPL similarly argues
in its reply comments that the creation of long-term firm transmission
rights or long-term financial transmission rights is not statutorily
mandated, and as a result must be justified in the record, since it is
a ``stark departure from past practices.'' \44\ IPL states that section
217(b)(4) is properly implemented by ensuring that load serving
entities can obtain either firm or financial transmission rights on a
long-term basis.
---------------------------------------------------------------------------

    \43\ Comments of Cinegry at 14.
    \44\ Reply comments of IPL at 7.
---------------------------------------------------------------------------

    74. In response to these arguments, APPA argues that the term
``firm

transmission rights'' was meant to refer to the physical transmission
rights that exist in non-transmission organization markets (since the
statute covers all regions), and that the inclusion of the phrase ``or
equivalent tradable or financial rights'' was intended to address the
FTRs used in transmission organization markets. According to APPA, the
network service contract and associated payment toward the fixed cost
of the transmission system does not cover transmission congestion
costs. Only an FTR covers these costs and ``firms up'' the total cost
of transmission service, APPA contends. Finally, it, along with NRECA
and TAPS, state that if Cinergy's assertion that transmission
organizations already provide long-term transmission rights in
compliance with the statute is correct, then section 217(b)(4) was
unnecessary and did nothing.
Disruption of Current Market Designs or Allocation Methods
    75. Some entities, including IPL, Midwest ISO and NYISO, argue that
Congress did not intend for the Commission, when implementing section
217(b)(4), to disrupt current market designs or existing transmission
rights allocation methodologies. Of these entities, some argue that
nothing in section 217 suggests that the Commission require major
changes to the existing auction-based FTR systems, and that it would be
consistent with section 217 for the Commission to allow transmission
organizations to retain their current systems so long as they offer
long-term financial transmission rights. Midwest ISO, for example,
asserts that section 1233(c) of EPAct 2005 provides that Congress did
not intend for the Commission to disrupt existing market designs that
already offer long-term FTRs. Similarly, NYISO asserts that nothing in
section 217 requires major changes to auction-based FTR systems, noting
that this section expressly recognizes that financial rights can be
equivalent to physical rights and expressly protects established FTR
allocation systems. According to NYISO, the Commission could,
consistent with section 217, allow transmission organizations and their
stakeholders to retain their current systems so long as they offer
long-term FTRs. IPL states, in part, that Congress was aware of the
current transmission rights constructs in the organized markets, and by
using the phrase ``or equivalent tradable or financial rights,'' ``at
the very least left open the possibility that the Commission might use
existing financial rights designs to achieve the statutory
objectives.'' \45\ NYISO also contends that nothing in section 217
requires transmission organizations to offer any rights with longer
terms than they already do, noting that section 217 only requires that
rights be ``long-term'' without saying what that means. PJM, while
generally supportive of the Commission's NOPR, nevertheless notes that
section 217(c) preserved existing FTR allocation methodologies, and
argues that Congress sought to complement rather than replace current
transmission rights allocation methods.
---------------------------------------------------------------------------

    \45\ Id.
---------------------------------------------------------------------------

    76. NYAPP, in reply comments, objects to NYISO's contention that
nothing in section 217 requires transmission organizations to offer any
rights with longer terms than they already do, arguing that this
interpretation would render section 217(b)(4) a nullity.
    77. Midwest TDUs notes in its reply comments that Midwest ISO is
subject to a specific directive to consider the preservation of
existing transmission rights. Specifically, Midwest TDUs point out that
under section 217(c), which shields the other established transmission
organizations from the impact of section 217(b)(1) through (b)(3),
Midwest ISO is subject to that section's ``provided, however'' clause,
thus requiring the Commission to take into account existing rights held
by a load serving entity as of January 1, 2005 (prior to the
commencement of the Midwest ISO organized electricity market).
Commission Conclusion
    78. As noted above, many of the specific interpretations of section
217(b)(4) of the FPA made by the Commission are discussed below with
regard to the guidelines adopted in this Final Rule. However, in this
section we address more general comments regarding our interpretation
in the NOPR of the requirement of section 217(b)(4) and section 1233(b)
of EPAct 2005.
    79. First, the Commission believes it correctly interpreted section
217(b)(4) of the FPA as containing two separate directives: (1) To
exercise its authority to facilitate planning and expansion of
transmission facilities, and (2) to enable load serving entities with
long-term power supply arrangements used to meet their service
obligations to obtain firm transmission rights on a long-term basis. We
conclude that this interpretation of the statute is the most
reasonable.\46\ Cinergy's interpretation of the relevant statutory
language as requiring only that the Commission facilitate planning and
expansion of transmission facilities in a manner that that allows load
serving entities to secure long-term transmission rights is
unreasonable in light of the actual statutory language used by
Congress. When it drafted section 217(b)(4), Congress separated the
first clause (requiring that the Commission exercise its FPA authority
to facilitate the planning and expansion of transmission facilities)
and the second clause (``and enables load serving entities to secure
firm transmission rights * * * on a long-term basis'') with a comma,
indicating two separate requirements. The comma is also followed with
the word ``and,'' further suggesting that Congress intended them as two
separate directives. No language in the statute suggests that the two
clauses are part of a single directive to the Commission.
---------------------------------------------------------------------------

    \46\ See e.g., Chevron, U.S.A., Inc. v. NRDC, Inc., 467 U.S.
837, 844-45 (1984) (noting that where Congress has expressly left a
gap for an agency to fill, the agency's interpretation of the
statute is giving weight unless it is ``arbitrary, capricious, or
manifestly contrary to the statute''); see also Acosta v. Gonzales,
439 F.3d 550, 552-53 (9th Cir. 2006) (noting that courts defer to
agency regulations that are based on a permissible construction of
the statute).
---------------------------------------------------------------------------

    80. Moreover, a reading of section 217 in its entirety suggests
that Congress intended for the Commission to both facilitate planning
and expansion and enable that load serving entities can obtain long-
term firm transmission rights. As a whole, section 217 is directed to
protecting the ability of load serving entities with native load
service obligations to obtain firm transmission service to satisfy
those service obligations.\47\ Directing transmission organizations
with organized electricity markets to provide long-term firm
transmission rights from both new and existing capacity is fully
consistent with this statutory directive. Furthermore, if Congress only
intended to direct the Commission to facilitate planning and expansion
of transmission facilities in a manner that enables load serving
entities to obtain long-term firm transmission rights, it would not
have included the long-term firm transmission rights language in a
second, separate clause. Finally, the directive in section 1233(b) of
EPAct that the Commission implement this provision within one year in
transmission organizations with

organized electricity markets (where only annual rights to existing
capacity are available) strongly suggests that Congress intended for
the Commission to direct such transmission organizations to begin
offering long-term rights from existing capacity. A reasonable
interpretation is that Congress believed FTRs to capacity at the time
of enactment were not sufficiently long, and therefore directed the
Commission to make longer-term rights to existing capacity available.
---------------------------------------------------------------------------

    \47\ Common principles of statutory interpretation support
reading section 217 as a whole to ascertain its intent. See. e.g.,
United States v. Andrews, 441 F.3d 220, 223, (4th Cir. 2006) (noting
that statutory phrases are not construed in isolation, and are
instead read as a whole).
---------------------------------------------------------------------------

    81. We disagree with comments suggesting that section 217(c)
immunizes existing market designs and transmission rights allocation
methods from the implementation of section 217(b)(4). The ``savings
clause'' in section 217(c) specifically provides that ``[n]othing in
subsections (b)(1), (b)(2), and (b)(3)'' of section 217 shall affect
the existing or future methodologies of certain transmission
organizations; that clause expressly omits subsection (b)(4) from its
protections. As a result, section 217 permits the Commission to require
changes to existing market designs and transmission rights allocation
methods if necessary to implement section 217(b)(4). This does not mean
that the Commission will require such changes or that section 217(b)(4)
requires changes to existing designs and allocations in all cases; if a
transmission organization can offer long-term firm transmission rights
that satisfy each of the guidelines in this Final Rule while retaining
its current systems, it may do so. We emphasize, however, that
transmission organizations must provide long-term firm transmission
rights that satisfy each of the guidelines in this Final Rule even if
doing so requires changes to existing systems.
    82. Additionally, we disagree with suggestions that transmission
organizations already provide long-term firm transmission rights, and
that creation of long-term financial transmission rights in this
rulemaking is unnecessary. While transmission organizations may provide
firm ``physical'' transmission rights on a long-term basis, the cost of
transmission service in transmission organizations that use LMP to
manage congestion is dependent on the cost of that congestion. We agree
with APPA that for a transmission right to be ``firm,'' it must be firm
as to both quantity and price. In the LMP context, this means ``firm
transmission rights'' must be firm as to both the ``physical''
component of the right and the ``financial'' component of the right.
FTRs can hedge congestion costs (when matched to the physical path of
the transmission right) and make transmission rights in an LMP system
``firm,'' but are currently only available for one year. As a result,
to comply with the directives of section 217(b)(4) and section 1233(b)
of EPAct 2005, transmission organizations with LMP and FTRs will need
to offer FTRs with longer terms to truly enable load serving entities
to secure firm transmission rights on a long-term basis. Further, we
disagree with Cinergy's contention that the ``or equivalent tradable or
financial rights'' language in the statute suggests that transmission
organizations can offer either long-term physical rights or long-term
financial rights. Rather, we agree with APPA that this language was
intended to address the FTRs used in transmission organizations with
organized electricity markets and congestion management systems
(primarily LMP) that impact the cost of transmission service. We read
this language as requiring the Commission to exercise its FPA authority
to enable all load serving entities to obtain firm transmission rights
on a long-term basis, whether they are located in a region with more
traditional ``physical'' transmission rights or a region that uses LMP
and FTRs.
    83. Finally, we disagree with NYISO's contention that section 217
does not require transmission organizations to offer transmission
rights with longer terms than those they currently offer. While some
transmission organizations could in theory have sufficiently long-term
transmission rights and thus would not be required to offer longer
terms, if the current transmission rights offered by all transmission
organizations were sufficient, it is unclear why Congress would have
included the second clause of section 217(b)(4) at all. Moreover, it is
reasonable to conclude that Congress believed not all transmission
organizations were offering sufficient long-term firm transmission
rights given that it focused the Commission's attention in section
1233(b) of EPAct 2005 on those entities, and given the fact that long-
term firm transmission rights are available today in regions without
transmission organizations with organized electricity markets. We
believe it is reasonable to conclude that Congress was aware that the
current terms for transmission rights offered by transmission
organizations were insufficient and drafted section 217(b)(4) of the
FPA and section 1233(b) of EPAct 2005 together to require that they
offer rights with longer terms.

D. Commission's Approach, Regional Flexibility, and Regional Seams
Issues

    84. In the NOPR, the Commission proposed a flexible regional
approach to satisfying the requirements of section 1233(b) of EPAct
2005. Specifically, we proposed to establish a set of guidelines for
the design and administration of long-term firm transmission rights in
organized electricity markets. Following the establishment of these
guidelines in the Final Rule, we proposed to allow each transmission
organization subject to the rule to develop specific long-term firm
transmission right designs through its usual stakeholder process that
would fit the prevailing regional market design.
    85. We stated that this flexible approach was appropriate because
there is no ``one size fits all'' long-term firm transmission right
design that could be implemented in each of the various transmission
organization markets. However, we stated further that flexible regional
development must occur within guidelines, to ensure that the specific
long-term firm transmission rights ultimately proposed by transmission
organizations have certain properties that are fundamental to meeting
the objectives of section 217(b)(4) of the FPA. Nonetheless, the NOPR
stated our intent that the guidelines form only a framework for
further, more specific development of long-term firm transmission right
designs through the usual stakeholder process of each transmission
organization, and noted that the guidelines should provide enough
flexibility to allow transmission organizations and their stakeholders
to develop a specific long-term firm transmission right design that
fits the prevailing market design and meets the needs of market
participants in that region.
    86. Finally, we noted the potential that this flexible regional
approach could lead to regional seams issues, and sought comments on
any features of long-term firm transmission rights that, if not
consistent across transmission organizations, could interfere with the
effective operation of regional markets.
Comments
    87. Several commenters, including Industrial Consumers, Kentucky
PSC, LADWP, LIPA, Midwest ISO, MSATs, NARUC, National Grid, NYDPS,
NYISO, PJM, Public Power Council, SoCal Edison, and Wisconsin Electric
all support the Commission's proposal to develop guidelines, as opposed
to specific long-term firm transmission rights designs, to allow for
regional flexibility. Many of these commenters argue that regional
flexibility is essential, given that each transmission organization has
developed its own market design to meet the needs of its stakeholders
and to accommodate regional differences (including different

operating practices). They contend that regional flexibility is also
necessary to honor the transitions already agreed to by transmission
organization stakeholders.
    88. While the commenters were virtually unanimous that a ``one-size
fits all'' approach to implementing long-term firm transmission rights
would not be appropriate, the comments raise issues regarding the
amount of flexibility that the Commission should provide. Some
commenters, including Dominion, EEI, ISO-NE, and NSTAR argue for more
flexibility, including flexibility within the requirements of each
guideline. For example, EEI states that the Commission should issue
only ``basic principles'' that focus on ``reasonable outcomes,'' and
should treat the guidelines as ``a general direction for future
action'' instead of imposing them as prescriptive requirements.\48\ EEI
also suggests that the Commission alter the general direction under
section (d) of the proposed regulations to provide that
``[t]ransmission organizations * * * should to the extent they find
reasonable given their existing arrangements make available long-term
transmission rights that satisfy the following guidelines.'' \49\
Further, EEI contends that no single guideline can or should be
mandatory, and that transmission organizations and their stakeholders
should be given the first opportunity to balance the guidelines to best
meet market participant needs. ISO-NE argues that section 217(b)(4)
permits substantial flexibility, since it does not require several
design features (including creating a ``perfect hedge'' for load
serving entities, a particular length of term, or a priority
mechanism.) New York Transmission Owners argue that the Commission
should clarify that the guidelines are not binding or mandatory
obligations, and that they do not predetermine any particular result or
design for long-term firm transmission rights.
---------------------------------------------------------------------------

    \48\ Comments of EEI at 11.
    \49\ Id. at 18.
---------------------------------------------------------------------------

    89. Some commenters in New England and New York, including NU and
Coral Power, note that there has not been great demand for long-term
firm transmission rights in those regions. Accordingly, NU argues that
the Commission should allow regional flexibility in determining the
extent to which such rights are needed.\50\ In reply, New England
Public Systems assert that the clear statutory directive makes
arguments regarding the lack of interest in long-term rights or the
lack of need for such rights irrelevant.\51\
---------------------------------------------------------------------------

    \50\ NU notes in reply comments that a working group has been
formed within NEPOOL to ``address whether the development of [long-
term transmission rights] in New England can be accomplished.''
Reply Comments of NU at 1.
    \51\ Reply Comments of New England Public Systems at 6-7.
---------------------------------------------------------------------------

    90. NSTAR states more generally that imposing a Final Rule on long-
term firm transmission rights that is inconsistent with the structure
of a transmission organization market, particularly a well-developed
market reflecting an extensive history of market operations, would be
``disruptive and counter-productive.'' \52\ Accordingly, NSTAR
advocates that the Final Rule allow the greatest latitude possible to
stakeholders in established transmission organization markets to
develop rules for long-term firm transmission rights. It argues that
section 217(c) of the FPA (stating that subsections (b)(1), (b)(2) and
(b)(3) do not affect existing or future transmission right allocation
methodologies) recognizes the historical practices followed by
transmission organizations and permits the Commission to defer to such
practices, even if they are deemed to differ from practices embodied in
subsections (b)(1) through (b)(3) of section 217.\53\
---------------------------------------------------------------------------

    \52\ Comments of NSTAR at 11.
    \53\ New England Public Systems argues in response to NSTAR that
section 217(c) does not provide any basis for the wide flexibility
NSTAR advocates, since that section expressly omits reference to
section 217(b)(4).
---------------------------------------------------------------------------

    91. Reliant states that the Commission should recognize ongoing
stakeholder-driven efforts in several existing transmission
organizations to develop long-term firm transmission rights, and
provide sufficient leeway for such markets to provide access to long-
term rights.
    92. BPA states that in general it supports the Commission's
flexible approach, and states that the Commission should allow
sufficient flexibility so as not to preclude formation of transmission
organizations with regionally-developed characteristics, such as the
developing proposals in the Northwest.\54\ It argues that the Final
Rule should address how the guidelines will apply to transmission
organizations in the process of forming organized electricity markets.
---------------------------------------------------------------------------

    \54\ See also Reply Comments of BP Energy at 10 (agreeing).
---------------------------------------------------------------------------

    93. Midwest ISO states that the Commission should consider the
detrimental effect some of the proposed guidelines could have on
Midwest ISO market participants and should ensure that the terms it
ultimately adopts allow sufficient flexibility to ensure that they can
work in the Midwest ISO markets.
    94. Others, including APPA, New England Public Systems and TAPS,
argue that regional flexibility should not be offered too broadly. They
assert that the Commission should make clear that the Final Rule gives
regions the flexibility to decide how to implement long-term rights,
but not the flexibility to decide whether to implement them at all.
NRECA also supports some regional flexibility, but states that there
must be adequate minimum guidelines to ensure that the objectives of
section 217 of the FPA are met. APPA and TAPS both assert that the
Commission explicitly require transmission organizations to fully
comply with the provisions of the Final Rule, and also suggest that the
Commission consider renaming the guidelines ``requirements'' or
``standards'' to ensure that there is no implication that the
guidelines are only advisory and may be disregarded. Similarly, PG&E,
while also supportive of the Commission's approach, recommends that the
Commission further require transmission organizations ``to fulfill the
guidelines of the ultimate rule to the maximum extent compatible with
the realities of their market and legal environment.'' \55\
---------------------------------------------------------------------------

    \55\ Comments of PG&E at 5.
---------------------------------------------------------------------------

    95. Some commenters, including Midwest TDUs and Industrial
Consumers, express concern that the use of stakeholder procedures will
not result in the development of long-term firm transmission rights
that satisfy the intent of the Commission and Congress. Midwest TDUs
express concern that ``the stakeholder process will be used to
eviscerate long-term rights'' given the Midwest ISO's ``evident
resistance to long-term rights'' and the opposition of some Midwest ISO
stakeholders.\56\ They state further that ``[i]mplementation of these
Congressionally-mandated rights in a manner that achieves their crucial
purpose cannot depend on TDU's ability to overcome Midwest ISO's
resistance or out-vote other stakeholders.'' \57\ Industrial Consumers
state that they and other industrial and customer groups have had
concerns that some transmission organization stakeholder processes do
not have the proper balance to guard against one side of the market
gaining an upper hand over the other. Accordingly, Industrial Consumers
recommend that the Commission provide guidance to ensure that the
stakeholder processes used to develop long-term firm transmission
rights will include a balanced composition of stakeholders, and require
each compliance filing to

include a statement by the transmission organization that the
stakeholder process was fair and impartial and did not discriminate
against load and load serving entities.
---------------------------------------------------------------------------

    \56\ Reply Comments of Midwest TDUs at 6-7.
    \57\ Id. at 7.
---------------------------------------------------------------------------

    96. With regard to the potential for the Commission's flexible
approach to create regional seams issues, comments address both the
potential for seams between transmission organizations and between
transmission organization regions and non-transmission organization
regions. Some commenters, including APPA and PG&E, note that different
term lengths for long-term firm transmission rights and different
processes for the allocation of long-term rights (including different
timetables) are two areas where seams could arise. TAPS states that the
Commission should require transmission organizations to provide a
mechanism that allows load serving entities to obtain long-term
transmission rights that cross seams and ensure that those rights
continue if new or different seams emerge, and should require
transmission organizations to coordinate their schedules for allocating
long-term rights that cross seams. BPA also notes the possibility that
a load serving obligation might be met with a resource outside the
transmission organization, and states that in such situations ``the
transmission organization should continue to provide long-term
transmission service for such deliveries under existing and renewed
transmission contracts.'' \58\
---------------------------------------------------------------------------

    \58\ Comments of BPA at 5.
---------------------------------------------------------------------------

    97. TAPS and Wisconsin Electric express specific concerns regarding
the potential for seams to develop between Midwest ISO and PJM. TAPS
contends that the Commission should require close coordination between
Midwest ISO and PJM with regard to the definition of long-term firm
transmission rights and the process for obtaining such rights, arguing
that a load serving entity should be able to obtain rights crossing the
border on a consistent timeline (ideally through a single process) to
support a commitment to baseload resources needed in both transmission
organization regions. Wisconsin Electric argues that there must be
consistency between the two regions with regard to the allocation of
long-term firm transmission rights to ensure that a ``financial wall''
does not develop, which would inhibit the ability to flow energy under
long-term contracts between the regions.
    98. MidAmerican states that the Commission should require
compliance filings to address resulting seams and how they will be
resolved. MidAmerican, as well as NARUC, also note that these issues
can and should be addressed in the Joint Operating Agreements and Seams
Operating Agreements between transmission organizations. NARUC urges
the Commission to clarify that tariff provisions designed to award
long-term transmission rights will not adversely impact these seams
agreements, and clarify that long-term rights granted within a
transmission organization will not confer rights on the holder outside
that market. According to NARUC, these clarifications are necessary to
ensure that costs for upgrades or expansions are not transferred
between transmission organizations or a transmission organization and
non-transmission organization utility and to ensure that transmission
rights in other regions are not adversely impacted.
    99. Comments also generally addressed seams that might arise
between transmission organizations and non-transmission organization
regions. APPA, for example, notes that non-transmission organization
regions use physical rights, and as a result financial and physical
rights must coexist to ensure that future power supply and transmission
service arrangements are not adversely impacted. CMUA states that
because CAISO operates a market based on financial rights, while the
rest of the Western Interconnection consists of bilateral markets with
physical rights, any regional stakeholder process to develop long-term
firm transmission rights in CAISO should include the Western
Electricity Coordinating Council (WECC), neighboring control areas and
relevant transmission owners in the West.\59\
---------------------------------------------------------------------------

    \59\ In response, CAISO notes that it has not and will not
discourage such parties from participating.
---------------------------------------------------------------------------

Commission Conclusion
    100. In this Final Rule, the Commission adopts the guidelines
approach and the allowance for regional flexibility set forth in the
NOPR. This approach will appropriately recognize regional differences
in market design, while ensuring that long-term firm transmission
rights have certain properties that are fundamental to satisfying the
mandate of Congress in section 217(b)(4).
    101. In response to comments seeking additional flexibility, we
emphasize that we are adopting the guidelines approach to ensure that
transmission organizations have the flexibility to design long-term
firm transmission rights that fit their prevailing market design. This
flexibility is not intended and should not be interpreted to allow
transmission organizations the latitude to decide whether long-term
firm transmission rights should be implemented at all. Congress has
directed in both section 217(b)(4) of the FPA and section 1233(b) of
EPAct 2005 that load serving entities have the ability to obtain long-
term firm transmission rights to meet their reasonable needs to satisfy
their service obligations. Congress also specifically directed that
such rights be implemented in the transmission organizations with
organized electricity markets, through section 1233(b)'s charge that
the Commission implement section 217(b)(4) within one year in those
regions. As a result, the implementation of long-term firm transmission
rights by transmission organizations with organized electricity markets
is mandatory.
    102. We reject comments suggesting that the guidelines be treated
as merely general directives. As noted above, the guidelines are
intended to ensure that long-term firm transmission rights have certain
properties we believe are necessary to fulfill Congress' directives.
Particularly, the guidelines are designed to ensure that the long-term
firm transmission rights are truly ``long-term'' and ``firm,'' and that
they can be used to deliver the output of long-term power supply
arrangements to load serving entities, as section 217(b)(4) requires.
As a result, transmission organizations must satisfy each of the
guidelines when complying with the Final Rule. We have modified the
proposed regulatory text to clarify this requirement.
    103. With regard to flexibility within each guideline, the
Commission believes that each of the guidelines already provides
sufficient flexibility to allow transmission organizations to satisfy
them in a manner that fits their individual market design. Each of the
guidelines state basic, fundamental properties that long-term firm
transmission rights must possess, but are not prescriptive market
design mandates. Thus, while proposals to comply with this Final Rule
must satisfy each of the guidelines, we believe each of the guidelines
may be satisfied in any number of ways, and we do not intend that the
guidelines predetermine any particular design.
    104. In response to comments suggesting that there has been little
demand for long-term firm transmission rights in New York and New
England, we note that we agree with New England Public Systems that
regardless of the level of interest in such rights, Congress has
mandated that they be available to meet load serving entities

reasonable needs. Thus, while we are adopting a flexible approach, that
flexibility does not extend to deciding whether such rights are needed,
as NU suggests it should. The fact that only a few stakeholders in a
particular region seek long-term firm transmission rights can be a
design consideration, however, as we discuss in more detail elsewhere
in this Final Rule.
    105. BPA asks that the Commission address how the guidelines will
apply to transmission organizations with organized electricity markets
that are being developed, and asks that we retain sufficient
flexibility so that regional efforts to develop a transmission
organization in the Northwest are not precluded. As we state above, we
conclude that the guidelines approach in the Final Rule provides enough
flexibility to ensure that long-term rights can be developed with
regional characteristics while still meeting the statutory objectives
of section 217(b)(4). Entities in the process of forming transmission
organizations should take into account the requirements of this Final
Rule and how the market designs they file will satisfy the rule.
    106. In response to the comments of Industrial Consumers and
Midwest TDUs regarding the use of stakeholder procedures to develop
specific long-term firm transmission rights proposals, we do not
believe it is necessary to specifically direct that any particular
stakeholder procedures be used. Transmission organizations have
Commission-approved procedures in place that specify the stakeholder
process and conditions and criteria by which they may file proposals
with the Commission. Comments suggesting that such procedures are
flawed are outside the scope of this proceeding.
    107. Regarding the potential for regional seams, the comments
indicate that seams are most likely to develop where the terms of long-
term rights and the procedures (including timelines) for allocating
such rights are not sufficiently coordinated. We agree with commenters
that transmission organizations should consider these issues when
complying with the Final Rule. Additionally, we agree that revising the
already existing seams agreements between transmission organizations,
if necessary, could be one vehicle to address seams issues related to
long-term rights that arise between transmission organizations.
Accordingly, we direct each transmission organization to explain in its
compliance filing how its proposal addresses potential seams issues,
particularly with regard to the term of the long-term rights offered
and the procedures and timelines for obtaining such rights. With regard
to potential seams between transmission organizations, each
transmission organization should also explain why it has or has not
elected to revise its seams agreements.

E. Guidelines for the Design and Administration of Long-Term Firm
Transmission Rights in Organized Electricity Markets

Guideline (1)--Specify Source, Sink and Quantity
    108. As proposed in the NOPR, guideline (1) stated that 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). The discussion of this guideline
pointed out that flowgate rights were not precluded from consideration
as long as they could hedge a point-to-point transmission schedule.
Comments
    109. Guideline (1) is generally supported by commenters. Most
commenters recognize that current transmission organization market
designs for specifying and allocating transmission rights largely adopt
the source point and sink point requirements of guideline (1). But
there are exceptions. In particular, some commenters note that ISO-NE
does not allocate auction revenue rights on a point-to-point basis.
Flexibility in Source and Sink Designation
    110. Several commenters request that guideline (1) explicitly
recognize nodal aggregations, such as zones or hubs, as sources and
sinks.\60\ ISO-NE notes that spot market purchases by load are priced
on a zonal basis in its system and that allocation of zone-to-zone
long-term transmission rights would be more desirable than allocation
of point-to-point rights. PJM Public Power Coalition, Public Power
Council and Strategic Energy request that guideline (1) should not be
interpreted to require that long-term rights are tied to specific
generation resources, but rather to points or aggregates on the
transmission system. Several commenters note that the boundary nodes
can serve as sources or sinks.
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    \60\ See, e.g., AEP, Coral Power, IPL, ISO-NE, NEPOOL, Reliant
and TAPS.
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    111. Other source/sink designation issues pertaining to guideline
(1) were raised by commenters that are, or will be, transmission
customers but that are located outside the transmission organization
markets. SMUD stresses that in California, long-term rights must be
developed for transmission customers that use through and out service.
SMUD argues that the Commission should require that allocation criteria
for long-term rights will not be dependent upon where load is located,
but rather on whether, by its use of the system, the customer will make
substantial contribution to recovery of the transmission system's fixed
costs.
Consistency of Current Market Rules With Guideline 1
    112. Some commenters state that the current rules for allocating
ARRs and auctioning FTRs in ISO-NE are not consistent with guideline
(1) in combination with guideline (7). New England Public Systems notes
that under the ISO-NE market rules, most ARRs are allocated among
congestion-paying load serving entities on a zonal load ratio share
basis. Each such load serving entity is paid the auction clearing price
of an average FTR in the zone times the ratio of its peak load to the
zonal peak load. This rule does not offer assurance that the revenues
received will be sufficient to enable the load serving entity to
acquire a specific point-to-point FTR across a particular congested
path. New England Public Systems thus requests that the Commission
confirm that in New England, FTRs awarded under the current rules
cannot simply be extended in term. Instead, under guidelines (1) and
(7), ISO-NE should provide either the allocation of point-to-point
long-term transmission rights or point-to-point long-term ARRs that can
be converted to long-term transmission rights.
Other Issues
    113. CMUA, NRECA and SMUD argue that guideline (1) should be
modified and clarified so that it does not rule out long-term rights
with properties of Order No. 888 network service rights for network
transmission customers. In particular, these commenters argue that
long-term firm transmission rights should afford the customer the
flexibility to change receipt and delivery points without penalty. In
contrast, Cinergy argues that long-term rights should not be allowed to
have characteristics of Order No. 888 network rights.
    114. CMUA and SMUD request that guideline (1) not limit the ability
of transmission organizations to consider other types of rights that
meet the commercial needs of load serving

entities. In particular, they discuss contractual rights that are
``bidirectional'' in nature to support seasonal power supply
arrangements in the West and for which they propose option transmission
rights in each direction of the transaction.
    115. There were several miscellaneous comments on guideline (1).
PJM states that the Final Rule would benefit from clarification that
there are no requirements with respect to the nature of the right--
i.e., physical versus financial--and explicitly state that this issue
will be determined by the regions. We address this issue in Section
II.F, ``Alternative Designs for Long-Term Firm Transmission Rights.''
APPA requests that as part of compliance with guideline (1), each
transmission organization should be required to establish rules that
prevent gaming of the long-term rights allocation by swapping of
generation resources. This issue was raised by several other parties in
conjunction with guideline (5) and we address it there.
Commission Conclusion
    116. We will adopt guideline (1) without modification. The primary
objective of guideline (1), consistent with section 217(b)(4), is to
allow a load serving entity to obtain a long-term firm transmission
right for purposes of hedging congestion charges associated with
delivery of power from a long-term power supply arrangement to its
load. Moreover, as several commenters noted, guideline (1) is largely
consistent with existing designs for FTRs in the organized electricity
markets operated by transmission organizations.
Flexibility in Source and Sink Designation
    117. We clarify that guideline (1) permits specification of long-
term firm transmission rights to hedge zonal or hub pricing where, for
example, congestion prices are calculated using a weighted average of
the locational marginal prices within a zone. Guideline (1) also
permits specification of long-term transmission rights from points on
the network, such as boundary locations, that are not the locations of
specific generators. For customers with through and out service, we
would expect that transmission organizations will establish long-term
firm transmission rights corresponding to the terms and conditions of
existing transmission contracts. However, if quantity limits are
established for the allocation of long-term firm transmission rights,
then rules may be needed to determine the eligibility of through and
out service, based, for example, on historical usage patterns.
Consistency of Current Market Rules with Guideline (1)
    118. Based on the comments, only ISO-NE has adopted a financial
rights model for transmission rights that does not directly allocate
rights that are point-to-point to eligible market participants. We will
require ISO-NE to adopt rules for allocation of long-term firm
transmission rights that are consistent with guidelines (1) and (7).
However, as discussed below, we note that ISO-NE does not have to
provide the same allocation rules for short-term rights as it does for
long-term rights.
    119. We understand that in some organized electricity markets,
particularly in regions with substantial divestiture of generation
capacity and retail choice such as that of ISO-NE, hedging particular
generation resources with financial transmission rights is not the
prevailing approach; rather, buyers and sellers have adopted portfolio
approaches to power supply contracts and hold financial transmission
rights based on their expected revenues from congested transmission
paths rather than on their ability to hedge specific resources. We do
not intend for this Final Rule to obstruct that business model, but
note that other entities in these regions are not following such a
business model. As a result, they seek transmission rights that hedge
congestion charges associated with delivering power from particular
generators to their load. Guideline (1) is intended to support the
ability of load serving entities to obtain point-to-point long-term
transmission rights that will hedge particular long-term power supply
arrangements. Guideline (7) is intended to support the ability of load
serving entities to obtain such rights without having to purchase the
rights in an auction. We will thus require all transmission
organizations to offer long-term firm transmission rights that are
consistent with these guidelines. This is not to say that transmission
organizations like ISO-NE must adopt new allocation rules and apply
them for both short-term rights and long-term rights. To the extent
that a transmission organization can satisfy requests for long-term
firm transmission rights under these guidelines, but stakeholders
prefer remaining with existing rules for short-term rights, we will
consider proposals that use such a ``two-track'' approach. At the same
time, as we discuss in guideline (2), there might be advantages to
harmonizing at least some rules between short-term and long-term rights
to ensure that the rules encourage efficient nominations and equitable
allocations.
Other Issues
    120. We will not modify guideline (1) to require allocation of