Document ID: FERC-2006-1480-0001
Agency: ferc
Document Type: Rule
Title: Long-Term Firm Transmission Rights in Organized Electricity Markets
Posted Date: 2006-08-01T04:00Z

[Federal Register: August 1, 2006 (Volume 71, Number 147)]
[Rules and Regulations]               
[Page 43563-43620]
From the Federal Register Online via GPO Access [wais.access.gpo.gov]
[DOCID:fr01au06-15]                         

[[Page 43563]]

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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. (202) 502-8262.
    Wilbur C. Earley (Technical Information), Office of Energy Markets 
and Reliability, Federal Energy Regulatory Commission, 888 First 
Street, NE., Washington, DC 20426. (202) 502-8087.
    Harry Singh (Technical Information), Office of 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. (202) 502-6027.

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.

[[Page 43565]]

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

[[Page 43566]]

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

[[Page 43567]]

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

[[Page 43568]]

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

[[Page 43569]]

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

[[Page 43570]]

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

[[Page 43571]]

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''

[[Page 43572]]

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

[[Page 43573]]

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

[[Page 43574]]

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

[[Page 43575]]

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

[[Page 43576]]

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

[[Page 43577]]

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

[[Page 43578]]

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

    \60\ See, e.g., AEP, Coral Power, IPL, ISO-NE, NEPOOL, Reliant 
and TAPS.
---------------------------------------------------------------------------

    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

[[Page 43579]]

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 
long-term transmission rights with properties of Order No. 888 network 
service, as requested by NRECA and SMUD. In general, we have not 
precluded any design that stakeholders could agree on, but we do 
require that designs support equitable allocation of transmission 
rights (see discussion in Section II.F, ``Alternative Designs for Long-
Term Firm Transmission Rights''). The right to change receipt and 
delivery points without penalty could, under most rules for allocation 
of financial transmission rights, deprive other load serving entities 
of their eligible rights.\61\ Hence, the rules in organized electricity 
markets generally require parties that are converting Order 888 network 
rights to financial rights to select a fixed distribution of source 
points for their total MW eligibility over their network resources.
---------------------------------------------------------------------------

    \61\ For example, consider a load serving entity that is 
eligible for 100 MW of FTRs and that requests that the entire 
quantity is sourced at each of four network resources that it has 
historically used, each of which is capable of providing the full 
amount, thus encumbering up to 400 MW of transmission capacity.
---------------------------------------------------------------------------

    121. We will not modify guideline (1) to explicitly support 
``bidirectional'' transmission rights. CMUA defines such rights as 
``option'' rights in either direction. We discuss the difficulties in 
allocating option rights equitably in Section II.F, ``Alternative 
Designs for Long-Term Firm Transmission Rights.'' There are other 
solutions. Sufficient granularity of the transmission rights specified 
as obligation rights would allow the rights to better track the power 
flows in contractual arrangements. Guideline (1) also does not preclude 
flowgate rights, which have option properties. All of these approaches, 
and possibly others, could be used to address situations where power 
flows change direction on a regular basis.
Guideline (2)--Long-Term Hedge That Cannot Be Modified
    122. As proposed in the NOPR, guideline (2) stated that the long-
term firm transmission right must provide a hedge against locational 
marginal pricing congestion charges (or other direct assignment of 
congestion costs) for the period covered and quantity specified. Once 
allocated, the financial coverage provided by the right should not be 
modified during its term except in the case of extraordinary 
circumstances or through voluntary

[[Page 43580]]

agreement of both the holder of the right and the transmission 
organization. We refer to the provision that the payments from the 
rights should not be prorationed (with the exceptions as mentioned) as 
``full funding.''
    123. The NOPR sought comments on how to fully fund the long-term 
rights. Since the transmission organization is revenue neutral, fully 
funding the rights requires that a revenue shortfall is collected from 
some set of market participants to make holders of the rights whole. 
The NOPR asked whether such charges should be allocated to transmission 
owners that are responsible for maintaining and expanding the 
transmission capacity supporting the long-term firm transmission rights 
when the revenue shortfalls are due to inadequate maintenance or 
expansion. The NOPR further asked for comment on whether there are 
appropriate methods for allocating such charges that also provide 
appropriate incentives for transmission usage, maintenance and 
expansion. The NOPR also noted that payments to already awarded long-
term rights may be prorationed in the case of extraordinary 
circumstances, such as a sustained unplanned outage of a large 
transmission line. Such situations may require alternative rules for 
financial settlement of the rights.
Comments
    124. Guideline (2) drew strongly opposing views with regard to full 
funding for the term of the long-term transmission right and the 
question of who should pay to support full funding. Some commenters 
opposed full funding, arguing that it is not a viable option. Those who 
held this view also typically argued that full funding should be an 
option to be determined on a regional basis, and should not be mandated 
by the Commission. Other commenters strongly supported full funding. 
Among the latter commenters, and among those that opposed full funding 
but recognized that the Commission may nevertheless require it, there 
was significant disagreement over the set of market participants that 
should pay to provide the full funding guarantee and under what 
conditions. In particular, transmission owners were strongly against 
the proposal that they should provide a ``backstop'' to support full 
funding and rejected arguments that such a rule would have a positive 
incentive effect on transmission maintenance and investment.
    125. There was general support for the proposal that extraordinary 
circumstances may result in a suspension of full funding, but several 
commenters requested clarification on what constitutes such 
circumstances.
Full Funding: Criticisms and Alternative Proposals
    126. Several commenters oppose the proposed full funding 
requirement.\62\ OMS and Midwest ISO state that full funding is 
inequitable, would cause significant cost shifting between market 
participants, and is beyond the scope of section 217(b)(4). Midwest ISO 
argues that requiring a ``perfect'' hedge clearly exceeds a load 
serving entity's ``reasonable'' needs. Moreover, cost shifting would 
take place because, if entities eligible for long-term firm 
transmission rights have priority in the allocation of transmission 
rights (as proposed in guideline (5) in the NOPR), they may limit the 
quantity of short-term rights available. Further, Midwest ISO is 
concerned that other parties may have to pick up revenue shortfalls 
associated with the long-term rights.
---------------------------------------------------------------------------

    \62\ These include CAISO, EEI, IPL, ISO-NE, Midwest ISO, MSATs, 
NU, OMS, SoCal Edison and Xcel.
---------------------------------------------------------------------------

    127. EEI, IPL, Midwest ISO, MSATs and OMS argue that full funding 
is a higher level of certainty for transmission rights than was 
available historically. Outside the organized markets, firm point-to-
point and network transmission service have never been fully 
guaranteed. Rather, they have always been subject to potential 
curtailment through TLRs. They have also been subject to rate increases 
and redispatch costs. EEI argues that a long-term right that strives to 
provide a ``perfect hedge'' would be too expensive and that the 
Commission should instead aim for balance in the protection offered. 
IPL argues that section 217(b)(4) does not mandate a zero-risk solution 
for load serving entities, but rather to address their reasonable 
needs. IPL suggests that the Commission interpret what properties of 
financial transmission rights would provide reasonable risk mitigation 
equivalent to firm transmission rights under the OATT.
    128. TAPS replies to such arguments by noting that it is seeking 
full funding only for long-term firm transmission rights used to 
deliver the output of baseload resources. Hence, for the remaining 
transmission usage, the holder would be exposed to uncertainty over the 
allocation of rights and hence congestion cost exposure.
    129. Midwest ISO argues that full funding is not always necessary 
to provide a full hedge. This is because the revenues from point-to-
point FTRs used to hedge congestion charges associated with a 
particular resource or portfolio of resources can be either greater 
than or less than the congestion charges paid by transmission 
customers.
    130. CAISO argues that each transmission organization should be 
allowed to determine the rules for revenue sufficiency of financial 
transmission rights in a manner that best weighs the equities in each 
regional market. Similarly, CPUC is concerned that establishing a long-
term revenue guarantee at the start of the CAISO's LMP markets will 
``tie the hands'' of the CAISO if it needs to adjust the market design 
to improve implementation.
    131. ISO-NE, which does not currently fully fund transmission 
rights, emphasizes the difficulty of assigning funding responsibility. 
ISO-NE urges the Commission to conserve stakeholder, transmission 
organization and Commission resources by not creating new sources of 
conflict in a region.
    132. AEP argues that by creating fully funded long-term rights, 
guideline (2) does not provide flexibility to recognize system changes 
over the long-term. Similarly, IPL states that locking in rights shifts 
risks between parties rather than mitigating risk and may create 
greater risks over time. The transmission organization should be 
allowed to pre-define methodologies to adapt the rights to changing 
circumstances.
    133. A number of commenters argue that full funding could provide 
disincentives for investment in transmission. For example, AEP argues 
that when doing proper planning and with the right incentives, the 
transmission organization must be continuously revising its forecasts 
of transmission and generation availability (e.g., additions and 
retirements) to meet load growth. This will change the electrical 
configuration of the grid. By fixing transmission rights over the long-
term with the full funding revenue requirements, the transmission 
organization could inhibit construction of new facilities that would 
provide greater benefits to customers.
    134. Xcel argues that providing full funding in the event of a 
long-term change in grid capability could result in a perpetuation of 
windfall revenues or severe losses for holders of transmission rights 
and unjust socialization of those costs across the industry.
    135. AF&PA believes that guideline (2) may be extremely difficult 
to implement in a nondiscriminatory fashion because of valuation issues 
associated with estimates of congestion cost for extended periods.
    136. As an alternative to full funding, several commenters argue 
that in the event of revenue shortfalls, prorationing

[[Page 43581]]

of payments should be the rule for long-term rights (as it is currently 
for annual FTRs in organized markets other than NYISO). NU argues that 
treating long-term rights differently from short-term rights would be 
discriminatory. Reliant argues that any prorationing of transmission 
rights payments due to revenue shortfalls should be allocated on a MW 
by MW basis to all transmission rights regardless of their terms. 
Beyond this principle, the Commission should let regional approaches 
determine the details. Cinergy and SoCal Edison state that in the event 
of revenue shortfalls, payments to holders of long-term rights should 
be rationed on a pro-rata basis. SoCal Edison argues that holders of 
long-term rights should factor the risk of revenue prorationing into 
the prices that they pay to procure those rights and into their long-
term energy and capacity contracts.
    137. In light of these concerns, a number of commenters argue, for 
various reasons, that the Commission should not mandate full funding, 
but rather leave it to regions to determine whether or not to pursue 
full funding.\63\
---------------------------------------------------------------------------

    \63\ See, e.g., CAISO, CPUC, EEI, IPL, NEPOOL, NU, OMS, and 
Reliant.
---------------------------------------------------------------------------

    138. MSATs propose that full funding could be a voluntary insurance 
made available by third-party providers for an insurance premium. MSATs 
request that this option be considered in the Final Rule.
    139. OMS argues that the full funding guarantee for long-term 
rights will make such rights more valuable relative to annual rights, 
assuming that the latter remain subject to prorationing. OMS argues 
that there could be two possible consequences: First, transmission 
organizations will be extremely conservative in the quantity of long-
term rights that they allocate, and second, there will be a significant 
reduction in rights available for the annual allocation. Load serving 
entities will seek long-term rights and if the transmission 
organization cannot honor all requests, significant cost shifts will 
result. Hence, OMS proposes that fully funded long-term rights should 
be assessed a risk premium.
    140. Ameren argues that rather than attempt to address the issue of 
revenue insufficiency through full funding guarantees, the solution is 
to address flaws in the transmission organization's simultaneous 
feasibility model. Ameren argues that if the modeling was more 
accurate, the allocation of financial transmission rights would be less 
likely to become revenue inadequate and uplift would be minimized. 
Ameren prefers that any remaining uplift associated with transmission 
rights should be assigned pro rata over all financial transmission 
rights holders.
Full Funding: Support and Clarification
    141. A number of commenters are supportive of full funding of long-
term rights.\64\ However, there were differences in the scope of 
coverage that they proposed and how the costs of full funding would be 
allocated.
---------------------------------------------------------------------------

    \64\ See, e.g., Alcoa, Allegheny, APPA, BP Energy, CMUA, Coral 
Power, Industrial Consumers, New England Public Systems, NCPA, 
NRECA, NYISO, Peabody, PJM, PG&E, and TAPS.
---------------------------------------------------------------------------

    142. NYISO states that it is already in compliance with guideline 
(2) because its financial transmission rights (Transmission Congestion 
Contracts) are already fully funded, with transmission owners paying 
any revenue shortfalls. However, New York Transmission Owners argue 
that the transmission rights allocated in New York to support native 
load are not currently consistent with guideline (2) because they are 
allocated annually and the quantities may not be the same each year. To 
fix the quantities from year to year, they argue that NYISO would 
presumably have either to reduce the quantity allocated, create 
counterflow rights, or eliminate the simultaneous feasibility test, all 
of which could create congestion rent shortfalls in the day-ahead 
market. New York Transmission Owners argue that each of these choices 
is ``unpalatable'' and would upset the result of negotiations among 
them that led to the current allocation methodology. Hence, they argue 
that it is critical that the Commission ensure that NYISO and 
stakeholders have flexibility in the development of the rules for long-
term rights.
    143. TAPS argues that the full funding guarantee would place the 
burden on the transmission organizations to be accountable for the 
performance of the transmission rights that they allocate. TAPS further 
argues that to provide true certainty, guideline (2) should be paired 
with ``requirements that (1) the full cost associated with securing 
long-term rights (and applicable renewals) be established with 
reasonable certainty up front; and (2) RTOs broadly allocate 
responsibility for funding revenue shortfalls for long-term rights 
consistent with guideline (2)'s price stability goal.'' \65\
---------------------------------------------------------------------------

    \65\ Comments of TAPS at 15.
---------------------------------------------------------------------------

    144. New England Public Systems argue that full funding is 
consistent with the underlying principles of Order No. 888 and with 
section 217(b)(4). Under Order No. 888, holders of transmission 
contracts have the right to renew service when contracts expire, and 
transmission providers are required to plan and expand facilities to 
meet transmission customer needs. Transmission providers also bear 
redispatch costs, which provided a further incentive to expand 
transmission capacity to accommodate known or predictable uses. APPA 
similarly argues that full funding is consistent with section 
217(b)(4). This is because that requirement is intended to provide 
financial certainty over the transmission component of the ``all in'' 
cost of a long-term generation resource.
    145. A number of commenters, including TAPS, Public Power Coalition 
and Wisconsin Electric, propose that long-term rights should be 
allocated for a limited quantity of load serving entities'' load, 
specifically base-load. A few commenters, such as TAPS, also include 
rights to renewable generation resources. Hence, full funding would 
only extend to that quantity of rights. PJM agrees that a limited 
application of full funding is feasible.
    146. A number of parties note that full funding will require a 
consistent approach to transmission planning and expansion to minimize 
the potential for cost shifting. We address the relationship of long-
term firm transmission rights and transmission planning and expansion 
in Section II.E, ``Transmission Planning and Expansion.''
    147. BPA suggests that while locational marginal pricing may not be 
the congestion pricing model adopted in the Pacific Northwest, the 
principles underlying guideline (2) should be upheld. BPA argues that 
cost stability for long-term transmission should prevail over concerns 
about equity and fairness of the allocation of long-term rights and 
associated costs among market participants.
Full Funding Cost Allocation
    148. On the proper allocation of responsibility for revenue 
shortfalls, several commenters supporting full funding argue that some 
or all of the revenue shortfalls encountered by long-term rights should 
be funded by transmission owners. Industrial Consumers argues that 
transmission organizations cannot manage risks associated with 
financial transmission rights, and that such risks can only be managed 
by transmission owners.
    149. A few commenters that support the assignment of full funding 
uplift to transmission owners argue for limits on the obligations of 
transmission owners. PJM Public Power Coalition states that 
transmission owners should be held accountable for inadequate 
maintenance

[[Page 43582]]

practices or poor system planning and any resulting long-term rights 
funding shortfall should be assigned to them. Similarly, BP Energy 
argues that revenue shortfalls should be assigned to transmission 
owners only if they are due to negligence. NRECA and TAPS argue that 
the assignment of revenue shortfalls to transmission owners is 
appropriate only if the transmission owner fails to fulfill in good 
faith the transmission organization's instruction to plan and construct 
transmission facilities. Absent that situation, TAPS argues that 
funding responsibility should be broadly shared by all users of the 
transmission grid on a pro rata basis, since the failure is the 
transmission organization's failure to plan and expand the system.
    150. Most transmission owning utilities and some other commenters 
argue that transmission owners should not be required to fully fund 
long-term rights (under most circumstances).\66\ First, several of 
these commenters note that when a transmission owner joins a 
transmission organization, it cedes short-term control (e.g., 
redispatch) of the transmission system, and as a result cannot manage 
any parties' exposure to congestion charges. Second, in the planning 
process, it is the transmission organization that must undertake the 
planning for upgrades and approve new transmission facilities to reduce 
congestion. Third, decisions of siting authorities and input of 
stakeholders significantly affect location of new facilities and when 
they are brought on-line. Fourth, due to the nature of power flows in a 
large regional transmission organization, it may be difficult to 
determine exactly which transmission owners are responsible for changes 
in transmission capability. Fifth, just as important to revenue 
adequacy as building new facilities is the design of the transmission 
rights and the modeling used in their allocation. Under most 
transmission organization rules, transmission owners cannot directly 
reduce the quantity of rights that are allocated or auctioned to manage 
their exposure to full funding uplift charges (although some commenters 
note that guideline (2) may create an incentive for the transmission 
owner to do so indirectly by providing the transmission organization 
with conservative ratings for transmission facilities). Moreover, 
transmission organizations control the development and implementation 
of the models that underlie FTR allocation. Sixth, transmission 
transfer capability is often affected by factors outside the 
transmission owners' and transmission organization's control, such as 
loop flow. Seventh, transmission owners would need the ability to raise 
transmission rates to cover funding obligations, through FERC and/or 
state commissions. IPL notes that since a proposed transmission 
facility (required for purposes of transmission rights held by others) 
may have limited local benefits, state approvals may be difficult to 
obtain.\67\ Finally, IPL and PG&E argue that requiring transmission 
owners to fully fund long-term rights would serve as an incentive for 
transmission owners to leave transmission organizations.
---------------------------------------------------------------------------

    \66\ See, e.g., AEP, Ameren, BP Energy, Constellation, Dominion, 
Duquesne, EEI, IPL, Midwest ISO, MSATs, NU, NSTAR, PG&E, SoCal 
Edison and Xcel.
    \67\ For example, Allegheny argues that if the Commission 
requires full funding by transmission owners, it must also establish 
a mechanism that allows for automatic pass-through of the costs to 
ratepayers.
---------------------------------------------------------------------------

    151. IPL and Reliant argue that the Commission should not attempt 
to use the revenue sufficiency rules for long-term rights as an 
incentive for transmission investment, which is better addressed 
through separate incentives.\68\ MSATs argue that the Commission cannot 
shift costs to transmission owners ``based solely on the mere theory 
that doing so might create some potentially worthwhile incentives.'' 
\69\ MSATs argue that those supporting making transmission owners the 
``backstop'' funders of long-term rights have failed to provide a 
``sustainable justification'' for such a requirement.\70\ Ameren argues 
that second guessing transmission owners' business decisions after a 
transmission outage or bottleneck would only distract attention and 
effort from planning, funding and designing needed expansions and 
repairs. For the reasons stated above, IPL and PG&E state that 
assigning full funding to transmission owners is arbitrary and 
unreasonable because it not consistent with cost causation principles.
---------------------------------------------------------------------------

    \68\ For example, IPL cites the Commission's rulemaking efforts 
with regard to establishing Electric Reliability Organizations and 
Transmission Pricing Reform, and also the work of Midwest ISO's 
Regional Expansion Criteria and Benefits (RECB) Task Force. Comments 
of IPL at 6.
    \69\ Comments of MSATs at 11 (citing North Carolina v. FERC, 584 
F.2d 1003, 1014 (D.C. Cir. 1978) (emphasis in the original)).
    \70\ Reply Comments of MSATs at 9.
---------------------------------------------------------------------------

    152. MSATs note that transmission owners that are transcos (firms 
that own regulated transmission assets only) would be particularly 
problematic because such firms do not hold FTRs. MSATs ask that the 
Commission recognize that such a requirement would directly conflict 
with the transco business model for two primary reasons. First, 
transcos are neither transmission customers nor market participants. 
Hence, requiring transcos to take a position in the transmission rights 
markets would be inconsistent with their business model. It would also 
be inequitable to transcos. Second, transcos rely on a revenue stream 
that is far more concentrated than that of a vertically integrated 
utility. MSATs claim that the liability associated with underfunded 
transmission rights could exceed a transco's total transmission 
service-dependent revenue in some cases.
    153. Allegheny argues that while it can support full funding, the 
transmission organization should be responsible for providing full 
funding through its transmission customers. Allegheny recommends that 
this charge be assessed on all long-term firm and network transmission 
customers. In a similar vein, PG&E argues that while full funding is 
desirable, it should be allocated to transmission organization 
customers, who benefit from long-term investment in energy 
infrastructure.
    154. Several commenters propose that only the holders of long-term 
transmission rights be collectively allocated the costs of any revenue 
inadequacy associated with the rights.\71\ For example, Duquesne 
recommends that holders of transmission rights be allocated any costs 
associated with deficiencies in transmission revenues, because these 
parties benefit from the transmission rights markets. IPL argues that 
pro rata sharing of funding shortfalls by all load serving entities 
with long-term rights is the only reasonable approach in the absence of 
a clear cost-causation relationship.
---------------------------------------------------------------------------

    \71\ See, e.g., Duquesne, E.ON, IPL, MSATs, NSTAR, and SoCal 
Edison.
---------------------------------------------------------------------------

    155. Midwest ISO proposes that to the extent that market 
participants should be responsible for long-term rights revenue 
shortfalls, a mechanism to ensure such cost recovery should be made 
part of ``economic'' transmission upgrades. Economic upgrades should be 
defined to include those required to maintain FTR feasibility based on 
a cost-benefit analysis. In contrast, APPA argues that the transmission 
planning process should take account of long-term rights and designate 
transmission facilities to maintain the feasibility of the rights as 
``reliability'' upgrades.
    156. TAPS argues that assignment of revenue shortfalls to holders 
of long-term rights would be the equivalent of pro-rationing the 
rights. Similarly, in its reply comments, APPA argues that holders of 
long-term rights should not be assigned funding shortfalls due to the

[[Page 43583]]

failure of the transmission organization to plan for and ensure 
construction of necessary transmission facilities. APPA also notes that 
holders of long-term rights that are not transmission owners are least 
able to ensure that the transmission system can support them.
    157. A number of parties express concern that funding of 
transmission rights may not be equitable between long-term and short-
term rights.\72\ CAISO argues that when considering rules for revenue 
inadequacy, long-term rights should not have elevated status over 
short-term rights. They maintain that even holders of long-term rights 
will typically hold some level of short-term rights. In parts of the 
West, where patterns of supply have a great deal of annual variability, 
giving longer-term rights preferential status will be inequitable with 
respect to the holders of short-term rights.
---------------------------------------------------------------------------

    \72\ See, e.g., CAISO, Cinergy, Midwest ISO, NSTAR, Reliant and 
Suez.
---------------------------------------------------------------------------

    158. Cinergy, Midwest ISO and Suez are concerned that the funding 
guarantees in guideline (2) will shift costs from long-term contract 
holders to short-term contract holders. They argue that such cost-
shifting will be unduly discriminatory and preferential and violate the 
Federal Power Act. Reliant agrees that cost-shifting will occur and 
proposes that the Commission provide a forum for discussion of ``best 
practices'' to maximize the availability of short-term and long-term 
rights to all customers.
    159. In reply, APPA argues that because long-term firm transmission 
rights support long-term power supply arrangements, and the holders of 
such rights would be committed to paying a share of transmission fixed 
costs over the period of the rights, there is a legal and policy 
rationale for giving long-term rights more protection from proration or 
revenue insufficiency than holders of short-term rights.
Definition of Extraordinary Circumstances
    160. Several commenters supported generally the inclusion of the 
exception to full funding under ``extraordinary circumstances.'' \73\ 
No commenters argued against such an exception, although several asked 
for clarification. ISO-NE encourages the Commission to clarify the 
definition of ``extraordinary circumstances'' that would permit 
modification of the financial coverage provided by long-term 
transmission rights.
---------------------------------------------------------------------------

    \73\ In support, see BP Energy, NYISO, and PJM Public Power 
Coalition.
---------------------------------------------------------------------------

    161. TAPS asks that the definition of ``extraordinary 
circumstances'' be clarified such that it is only applied in the event 
of a catastrophic regional problem such as a widespread blackout or a 
massive force majeure event. TAPS argues that the example in the NOPR 
of a sustained unplanned outage of a large transmission line is 
``precisely the type of situation when an LSE should not be stripped of 
its long-term rights.'' \74\ TAPS argues that in the event of a 
sustained line outage, long-term rights should remain fully funded and 
the shortfall uplifted, for example, on a load ratio basis. Similarly, 
APPA argues that the suspension of full funding should take place only 
if the situation should be ``truly extraordinary'' and not a 
contingency that should have been anticipated in routine transmission 
planning.
---------------------------------------------------------------------------

    \74\ Comments of TAPS at 16.
---------------------------------------------------------------------------

    162. NRECA is concerned that the exception for ``extraordinary 
circumstances'' will undermine the certainty that guideline (2) is 
supposed to confer. NRECA requests that the Commission clarify when 
this exception would apply or remove it from the guideline.
Other Issues
    163. BP energy argues that the full funding rule could result in 
market gaming in the event of a transmission outage. BP Energy suggests 
that the Commission consider the methodology to limit gaming adopted by 
ERCOT and the Texas PUC. When there is a revenue insufficiency, ERCOT 
limits the payment on an oversold FTR to its ``legitimate hedge'' value 
as established by substituting the resource's marginal cost for the LMP 
at the source (generation) node of the FTR. Any remaining revenue 
shortfall is uplifted to all FTR holders.
Proposed Revisions of Guideline 2
    164. Several commenters propose revisions to guideline (2). EEI 
proposes to revise the guideline to state that the rights are 
financial, apply only to day-ahead congestion charges, and are subject 
to the transmission organization's rules and terms established prior to 
the introduction of long-term rights. EEI suggests that the guideline 
specify that the long-term right ``should'' rather than ``must'' 
provide a fully funded hedge.
    165. In their reply comments, APPA, NRECA and TAPS oppose EEI's 
proposed revisions, arguing that they seek to weaken guideline (2) and 
frustrate Congress's purpose in enacting section 217(b)(4). In 
particular, they argue that EEI seeks to make full funding non-
mandatory and subject to the transmission organization's existing rules 
rather than the Commission's guideline. In addition, NRECA argues that 
the rights should not be limited to financial rights or to day-ahead 
markets.
    166. In addition to removing the requirement of full funding, IPL 
proposes adding the requirement that ``revenue shortfall funding shall 
be shared by all load serving entities that receive allocations of 
long-term financial transmission rights unless the transmission 
organization identifies a clear cost causation relationship that 
warrants other treatment and develops an appropriate allocation 
methodology through the stakeholder process and specifies that 
methodology in its tariff and contractual arrangements.'' \75\
---------------------------------------------------------------------------

    \75\ Comments of IPL at 8.
---------------------------------------------------------------------------

    167. PJM proposes that guideline (2) be revised such that the 
``quantity specified'' in the guideline is modified by ``such quantity 
to reflect, at a minimum, the baseload requirements of LSEs, as 
determined by the respective transmission organization/ISO regions.'' 
\76\
---------------------------------------------------------------------------

    \76\ Reply Comments of PJM at 4.
---------------------------------------------------------------------------

Commission Conclusion
    168. We will adopt guideline (2) with minor modifications.\77\ 
Given that the term full funding has become shorthand for the financial 
coverage requirements of this guideline, we add this term in 
parentheses. Finally, because under market designs approved heretofore 
it is financial rights that provide revenues explicitly, we specify 
that the full funding requirement applies to financial long-term 
rights.
---------------------------------------------------------------------------

    \77\ PJM's suggestion that the guideline incorporate quantity 
restrictions on the allocation of long-term firm transmission rights 
is addressed under guideline (5).
---------------------------------------------------------------------------

    169. Thus guideline (2) as adopted in this Final Rule reads as 
follows:

    The long-term firm transmission right must provide a hedge 
against locational marginal pricing congestion charges or other 
direct assignment of congestion costs for the period covered and 
quantity specified. Once allocated, the financial coverage provided 
by a financial long-term transmission right should not be modified 
during its term (the ``full funding'' requirement) except in the 
case of extraordinary circumstances or through voluntary agreement 
of both the holder of the right and the transmission organization.
Requirement of Full Funding
    170. We believe that the full funding requirement satisfies 
Congress' express directive in section 217(b)(4) that load serving 
entities with service obligations be able to obtain ``firm'' 
transmission rights or their equivalent on a long-term basis. In our 
view, ``firmness'' in this

[[Page 43584]]

context refers primarily to two properties of the long-term 
transmission rights: stability in the quantity of rights that a load 
serving entity is allocated over time and ``price certainty'' for the 
load serving entity that seeks to hedge congestion charges associated 
with a particular generation resource or transmission path. If the 
rights are financial, which they are in almost all organized 
electricity markets, the latter property essentially requires 
minimizing the uncertainty in the ability of the rights' holders to 
cover congestion charges with the revenue from their transmission 
rights over the term of the rights. In our view, the objective of less 
uncertainty in revenues over the period of financial long-term rights 
will be aided by full funding. Hence, we find that full funding is 
consistent with the objectives of section 217(b)(4).
    171. Full funding may have additional positive effects. By 
stabilizing the expected congestion hedge offered by the right, full 
funding should assist in financing generation investments that are 
dedicated to particular loads and assume consistent use of particular 
transmission paths over long periods, such as base-load plants. 
Stabilizing the expected value of the long-term rights may also improve 
their tradability. Further, the transmission organization and 
transmission owners may have incentives to minimize any resulting 
uplift through improved transmission system operations, planning and 
investment. We recognize that there may also be negative incentives 
from full funding, depending on how any uplift costs are allocated. For 
example, a transmission owner with long-term rights that poorly 
maintains its transmission network and causes more instances of 
deratings that result in congestion revenue shortfalls could be 
partially subsidized by other transmission owners that have better 
maintained systems. As we discuss below, transmission organizations and 
their stakeholders have latitude to propose a full funding uplift 
allocation to provide better transmission maintenance incentives, if 
they so choose.
    172. There are also methods that could be used to minimize exposure 
to uplift caused by full funding. First, all current organized 
electricity markets that allocate financial transmission rights bank 
congestion surpluses (congestion revenues collected in excess of 
payments owed to transmission right holders) in a reserve fund over 
time so as to pay transmission rights in periods of congestion revenue 
shortfall. For example, in PJM, payments to transmission rights are 
only pro-rationed when the surplus fund is exhausted. If there is 
surplus remaining at the end of the year, it is distributed to market 
participants. This same principle could be applied to long-term 
financial rights, except that the surplus would be retained across 
multiple years. Second, as a few commenters suggested, a premium could 
be charged for fully funded long-term rights, which the transmission 
organization could additionally apply to such a reserve fund to 
minimize uplift charges or to set up an insurance policy for the rights 
holders themselves. Finally, as we discuss elsewhere in this Final 
Rule, transmission expansion provides a hedge against congestion 
revenue shortfalls.
    173. A number of commenters, including AEP and IPL, are concerned 
that full funding will reduce the transmission organization's 
flexibility in adjusting holdings of transmission rights over time as 
system conditions change and perhaps render some rights infeasible. AEP 
is concerned that this might adversely affect transmission investment. 
While we appreciate these concerns, we must note that the purpose of 
this Final Rule is to provide more assurance regarding congestion 
charge hedges over a longer time frame than is available now. This 
necessarily implies a decreased ability to adjust holdings of 
transmission rights over time. This Final Rule allows substantial 
latitude to transmission organizations regarding such things as setting 
terms and renewal rights for long-term firm transmission rights, 
placing limits on the amount of capacity made available to those 
rights, and allowing full funding to be relaxed under extraordinary 
circumstances. We believe this strikes an appropriate balance between 
assuring long term congestion charge hedges and reliable operation of 
the grid. We encourage transmission organizations and stakeholders to 
consider other measures that allow the transmission organization to 
deal with revenue insufficiencies over time.
    174. Several commenters argue that the Commission should not 
establish financial rights that offer some load serving entities a 
``perfect hedge'' financially that is superior to the physical rights 
that they held prior to the formation of the organized market. We 
agree. We do not envision full funding as a perfect hedge. Since the 
transmission organization is revenue neutral, costs associated with the 
full funding guarantee must be allocated on some basis among market 
participants. Our guidelines do not establish a subset of load serving 
entities that would be exempt from such costs, although we discuss how 
the costs should be distributed in the paragraphs that follow.
Full Funding Cost Allocation
    175. In general, we will allow transmission organizations the 
discretion to propose a method for allocating any uplift charges that 
result from fully funding long-term firm transmission rights. However, 
certain options proposed by commenters could result in unreasonable 
outcomes. We discuss some of these below.
    176. One approach proposed by commenters would be to charge uplift 
necessary to support full funding directly to the load serving entities 
that hold the long-term firm transmission rights that have been made 
infeasible. Such a rule would largely undercut the relative congestion 
price certainty provided by full funding and would hence probably not 
be a reasonable outcome.
    177. A second related approach would be to charge uplift to support 
full funding to a subset or the full set of load serving entities that 
hold long-term firm transmission rights. In this case, the degree to 
which the full funding requirement was adversely impacted would depend 
on the size of the set. In some regions, a small group of load serving 
entities may opt for long-term rights, in which case this rule could 
have almost the same impact as assignment of uplift directly to the 
holders of the rights made infeasible. On the other hand, if most load 
serving entities in a region opted for long-term rights (up to their 
eligibility), then the distribution of uplift charges over the set of 
rights holders would have a lesser impact and could be reasonable from 
all parties' perspective. Further, if transmission organizations decide 
to apply full funding also to short-term transmission rights, as 
discussed below, another potentially reasonable approach would be to 
distribute uplift charges over holders of both short- and long-term 
rights.
    178. Both the NOPR and many of the comments on the NOPR discussed 
the possible assignment of uplift necessary to support full funding to 
transmission owners. Commenters discussed several variants, including 
the current NYISO rules that assign all or most of such uplift to 
support full funding of annual FTRs to transmission owners, and other 
more targeted proposals, such as the assignment of uplift costs in 
relation to performance of transmission maintenance. The Commission 
will allow regional discretion on these options and will examine the

[[Page 43585]]

reasonableness of such proposals on a case-by-case basis.
    179. Some commenters argue that full funding of long-term rights 
would cause cost-shifting that would be unduly discriminatory and 
preferential with respect to short-term rights holders. We find that 
section 217(b)(4) can be reasonably interpreted to establish a due 
preference for load serving entities that seek to obtain long-term firm 
transmission rights. We have explained our interpretation of the 
relationship of firmness and full funding. However, as noted above, we 
encourage transmission organizations to evaluate whether the 
requirement to fully fund long-term rights, should be paired with full 
funding of short-term rights. Currently, most transmission 
organizations pro-ration payments to short-term FTRs in the event of a 
revenue shortfall. When fully funded long-term firm transmission rights 
become available, entities that would prefer to hold short-term rights 
may have an incentive to seek longer-term rights if the former are not 
fully funded and depending also on any other rules that affect the 
properties of transmission rights. Providing the same funding guarantee 
to all financial transmission rights and focusing on mechanisms to 
minimize the potential for uplift, as discussed above, could help load 
serving entities choose rights with term lengths that best suit their 
needs.
Definition of Extraordinary Circumstances
    180. As noted above, we will adopt the provision in guideline (2) 
that allows for full funding of long-term firm transmission rights to 
be suspended in the event of extraordinary circumstances. This 
exception was intended to relieve the burden on parties that could be 
unreasonably impacted by the full funding requirement in such 
situations. There was general support for this provision, although a 
number of commenters sought further definition and clarification of 
extraordinary circumstances so that the exception would not be used to 
unreasonably narrow the application of the full funding requirement.
    181. We agree with commenters that if the extraordinary 
circumstances exception is defined too broadly, it could be used to 
unreasonably diminish the value of full funding. Accordingly, we 
clarify that the definition of extraordinary circumstances, for 
purposes of this Final Rule, is limited to force majeure events that 
both render the set of outstanding long-term transmission rights 
infeasible and leave the transmission organization revenue inadequate, 
including both revenues from collection of congestion charges and 
availability of funds from a congestion charge surplus fund.
    182. In response to APPA, we further clarify that transmission 
system contingencies that were considered in the allocation of 
transmission rights should be excluded from the definition of 
extraordinary circumstances. In general, the allocation of transmission 
rights will be subject to a contingency-constrained simultaneous 
feasibility test and hence such contingencies should not lead to 
revenue inadequacy if they occur as expected in the modeling 
assumptions. We recognize that the set of contingencies modeled by the 
transmission organization may change over time and this should be taken 
into account in the allocation of transmission rights. There may be 
further restrictions on the definition of extraordinary circumstances 
that are needed, and we will consider these as they are presented in 
compliance proposals.
    183. TAPS argues that the conditions for suspension of full funding 
or application of alternative funding rules should be limited to 
``catastrophic'' regional problems. TAPS is concerned that otherwise, 
holders of long-term rights will be exposed to congestion charge risk 
in periods when they most need coverage. While we recognize TAPS' 
concern, there is no obvious standard approach to this issue and so we 
find it more appropriate to allow transmission organizations and 
stakeholders to develop proposals. For example, in the event of 
extraordinary circumstances there could be a dollar amount that the 
transmission organization stakeholders agree to as an upper limit for 
full funding uplift before pro-rationing of payments to transmission 
rights holders begins. In addition, the rules for pro-rationing 
payments may themselves include averaging of uplift similar to full 
funding. Finally, in all likelihood, system emergencies that are 
catastrophic will lead to a suspension of market pricing and financial 
settlement rules and long-term transmission rights would presumably 
fall under those rules.
Other Issues
    184. In response to BP Energy's concerns about market gaming 
associated with fully funded transmission rights in the event of a 
transmission outage, we will not endorse the methods being adopted by 
ERCOT, but will consider any approach that transmission organizations 
propose to ensure that the full funding guarantee is not subject to 
market manipulation.
Guideline (3)--Rights Made Available by Expansions Go to Parties That 
Pay for the Upgrade
    185. As proposed in the NOPR, guideline (3) stated that long-term 
firm transmission rights made feasible by transmission upgrades or 
expansions must be available upon request to any party that pays for 
such upgrades or expansions in accordance with the transmission 
organization's prevailing cost allocation methods for upgrades or 
expansions. The term of the rights should be equal to the life of the 
facility (or facilities) or a lesser term requested by the party paying 
for the upgrade or expansion. We also sought comment on the appropriate 
rules in the event that an entity that funds a capacity expansion seeks 
rights on existing transmission capacity to support a request for long-
term rights.
Comments
    186. Guideline (3) was generally supported by commenters, a number 
of whom noted that it roughly paralleled the existing rules for awards 
of transmission rights to parties that fund transmission upgrades and 
expansions. Of the existing transmission organizations, ISO-NE and PJM 
already provide long-term incremental rights for transmission upgrades, 
although their rules for assignment of such rights differ. New York ISO 
and Midwest ISO are developing such rules.
    187. ISO-NE states that it awards auction revenue rights for 
transmission upgrades consistent with the intent of guideline (3) and 
that their term continues as long as the costs of the upgrades are 
supported or for the life of the upgrade, if shorter. PJM states that 
guideline (3) is generally consistent with its current rules, but notes 
that its rules for term lengths are slightly different from the 
proposed guideline, as discussed below.
    188. New York ISO states that its tariff provides for the creation 
of incremental Transmission Congestion Contracts (TCCs) for upgrades. 
However, LIPA argues that NYISO has not finalized its process for 
awarding expansion rights, and that this has a negative impact on 
parties that construct additional transmission capacity.
    189. As discussed above, Cinergy takes issues with what it argues 
is the Commission's overly broad reading of section 217(b)(4) of the 
FPA. Cinergy urges the Commission to ``provide a clear distinction 
between rights associated with transmission expansion and those for 
other long-term uses'' and

[[Page 43586]]

adopt a shorter term for long-term firm transmission rights over 
existing capacity, to provide a trial period to assess impacts on the 
system.\78\ Similarly, NSTAR argues that only customers who finance 
transmission capacity expansion are entitled to long-term rights.
---------------------------------------------------------------------------

    \78\ Comments of Cinergy at 8. Cinergy states that this approach 
would involve adopting guidelines (1), (6) and (8) without 
modification, and guidelines (3) and (4) with modifications 
(discussed below).
---------------------------------------------------------------------------

    190. Conversely, New England Public Systems and NRECA seek 
clarification that load serving entities that are not directly paying 
for upgrades or expansion are not prevented from obtaining long-term 
rights.
Scope of Guideline 3
    191. Many commenters ask that the scope of guideline (3) be 
clarified. In particular, commenters sought clarification of the types 
of transmission expansions the guideline was describing.
    192. IPL and Midwest ISO argue that the long-term rights awarded 
for expansions should be subject to the same rules that will apply to 
other long-term rights. IPL proposes that guideline (3) be modified to 
emphasize that rights are awarded subject to the transmission 
organization's annual allocation metholodogies. Midwest ISO argues that 
rights for expansions should have no more or less certainty in terms of 
MW quantity or funding than any other long-term financial instrument.
    193. Cinergy requests that guideline (3) make clear that entities 
who fund upgrades or expansions should ``enjoy the same rights to 
compensation and the same access to existing transmission capacity 
whether or not they are LSEs.'' Cinergy also asks for clarification 
that long-term rights for expansion are to be made available only to 
entities that make an upgrade for the purposes of transmission service 
from generation to load, and that such rights should not be available 
for upgrades that are undertaken through the transmission organization 
planning process for pool facilities.
    194. Similarly, SDG&E requests that the Commission clarify that the 
recipients of long-term rights are those that actually pay the revenue 
requirements associated with the expansion or upgrade. In particular, 
SDG&E is concerned that third-party transmission sponsors that seek 
revenue recovery through rate base are not awarded transmission rights. 
E.ON argues that load serving entities that request transmission 
upgrades but do not fund such upgrades nor purchase a long-term 
transmission contract should not be eligible for long-term rights.
    195. Several commenters, including Industrial Consumers and TANC, 
seek clarification that long-term rights will not be awarded to 
transmission projects that are subsequently rolled into rates.
    196. A number of commenters raised questions about the relationship 
of guideline (3) and cost allocation methods for transmission upgrades 
and expansion. National Grid requests confirmation that guideline (3) 
does not require regions to revise their prevailing cost allocation 
methods. National Grid infers that guideline (3) refers to a model of 
participant funding and requests clarification that regions that have 
not adopted participant funding do not need to revise their methods. 
PJM also argues that the Commission should not disturb existing cost 
allocation methodologies by addressing the issue of participant funding 
versus socialization of costs.
    197. TAPS requests that the Commission make clear that guideline 
(3) does not tie the availability of long-term rights from new 
transmission capacity to participant funding. TAPS asks that at a 
minimum, the guideline should make clear that where transmission 
organizations have moved to other methods of funding upgrades, long-
term rights should be available from that capacity.
    198. AEP cautions that because transmission upgrades are lumpy in 
nature, it is often difficult to assign properly the costs of 
transmission additions to those parties that receive the benefits. AEP 
notes that due to the difficulties in assigning such costs, there may 
be free-riders. Consequently, the transmission organization should 
conduct a regional planning process that identifies the upgrades and 
expansions that provide the greatest benefit to the region and funds 
this capacity through regional rate design.
Term of Rights for Upgrades and Expansion
    199. Commenters differed over guideline (3)'s provision that long-
term firm transmission rights allocated to the builders of new 
transmission facilities should be for the life of the facility. AF&PA 
and NRECA supported the proposal. However, other commenters argued for 
a fixed term of a long period rather than life of facility, which could 
be difficult to define. PJM currently offers rights for a maximum of 30 
years and argues that this places a realistic term on the life of the 
facility and balances the rights of the party paying for the upgrade 
with market efficiency. Midwest ISO and Xcel similarly argue that 
awards should be of fixed terms and not facility life. PJM Public Power 
Coalition supports the PJM term of 30 years, but urges that holders of 
such rights should be given the opportunity to refuse the rights on an 
annual basis. CAISO notes that once a transmission project is built and 
energized, the responsibility for its maintenance may be transferred to 
a transmission owner separate from the merchant sponsor. Hence, CAISO 
recommends that the Commission consider allowing transmission 
organizations to develop standardized terms of long-term transmission 
rights to be allocated to merchant transmission projects, rather than 
require allocation for the life of the facility.
    200. Several commenters, including EEI, National Grid and PG&E, 
suggest that the transmission planning horizon presented a natural 
limit to at least the initial term of rights awarded for new 
facilities. National Grid argues that awards of rights for the life of 
facility are impractical because transmission plans currently are only 
5-10 years in length and hence any awards beyond the planning horizon 
are ``speculative.'' Instead, rights should be granted for the duration 
of the planning horizon and as they expire, new rights can be 
reconfigured and allocated based on the capacity conditions and 
relative cost contributions prevailing at the time. Similarly, EEI and 
PG&E argue that based on the planning horizon, the terms of awarded 
rights should be the shorter of the expected feasibility of the 
transmission rights or the expected lifetime of the new facility.
    201. In reply comments, APPA, NRECA and TAPS oppose arguments to 
shorten the term of rights awarded for expansion to the term of the 
planning horizon of the organized market. APPA notes that planning 
horizons could be much shorter than the life of the transmission 
facility for which the long-term rights holder has paid or the duration 
of a long-term power supply arrangement.
    202. Cinergy argues that section 217(b)(4) does not specify awards 
of rights for the life of new transmission facilities and suggests 
instead that long-term rights should be awarded for the repayment 
period of the initial investment. At the end of this period, according 
to Cinergy, the investor will have recovered its investment and the 
transmission expansion will be rolled into the transmission charges 
paid by transmission users. Cinergy also suggests retiring the long-
term rights on a schedule that reflects the repayment of the invested 
capital.

[[Page 43587]]

Incremental Upgrades and Use of Existing Capacity
    203. In response to our question in the NOPR regarding whether 
rights for upgrades would require rights to the existing transmission 
system to make a long-term firm transmission right feasible and whether 
specific rules were necessary to accommodate such needs, a number of 
commenters argued that the Commission misunderstood the procedures for 
awarding incremental rights for expansion. For example, NYISO notes 
that any awards for new transmission facilities are evaluated in terms 
of their incremental transmission capacity, under which existing rights 
will be simultaneously feasible with the new rights. NYISO urges that 
the Final Rule clarify that new firm transmission rights can be awarded 
for increasing transfer capacity that is feasible and that does not 
render existing rights infeasible. Similarly, Ameren and Cinergy argue 
that for transmission expansion, the default rule should be that the 
entity that pays for the expansion should be entitled only to 
incremental rights. Such entities could obtain rights to existing 
capacity through subsequent reconfiguration auctions.
    204. Reliant states that entities that fund expansions should 
unambiguously receive the full allocation of rights associated with the 
expansion and the same non-discriminatory access to obtain rights to 
existing capacity as all other market participants. Further, Reliant 
states that to the extent an expansion needs access to the existing 
capacity, each region should have the flexibility to develop procedures 
to account for how existing capacity can be utilized to facilitate new 
investment.
    205. Some commenters have other questions about the relationship of 
rights awarded for expansions and those assigned on existing 
transmission capacity. CPUC questions whether awards for expansions 
might interfere adversely with rights to existing capacity awarded 
based on service obligations. PG&E and SoCal Edison request that the 
Commission clarify that under guideline (3), parties that fund 
transmission upgrades or expansions do not obtain priority to existing 
transmission capacity. Further, the final rule should clarify the 
method for determining the amount of rights made feasible by the 
upgrade.
Other Issues
    206. CAISO requests that the Commission make clear within this 
rulemaking that transmission organizations have the responsibility and 
authority for determining, based on their own engineering studies, the 
incremental transfer capacity added to the grid by a merchant 
transmission project.
    207. OMS reads guideline (3) as applying to cases where a load 
serving entity requests a new or changed designated network resource 
and is required by the ISO to make transmission upgrades. The OMS 
notes, referring to Midwest ISO, that such upgrades are based on zonal 
deliverability and not on the ability to grant transmission rights from 
the resource to load. OMS argues that if the generator is located 
distantly from load, and the potential transmission rights for the 
required upgrade are valuable, then the entity eligible for those 
transmission rights may nominate them in early tiers of the nomination 
and thus take up transmission capability that others may need. That is, 
the process of awarding transmission rights for capacity deliverability 
upgrades may create a result inconsistent with the goal of allocating 
transmission rights on a priority basis to parties that are seeking to 
serve load. TAPS similarly argues that the Commission must recognize 
that transmission planning based on point-to-point transmission rights 
is ``at odds'' with the increasing reliance on the aggregate 
deliverability standard for network resource designation in Midwest 
ISO. In reply comments, Midwest ISO argues that deliverability upgrades 
are related to the ability to meet supply adequacy requirements and not 
to guarantee the ability to receive FTRs from point to point.
    208. Midwest ISO argues that care must be taken such that parties 
that fund upgrades are not given the opportunity to seek awards of 
rights in excess of the actual change in transmission capability.
    209. APPA argues that load serving entities that funded 
transmission upgrades should be given the opportunity to own the 
facilities (in addition to collecting transmission rights). CMUA also 
supports joint ownership, but notes that in California, such ownership 
may require long-term rights of different kinds over the same facility.
Commission Conclusion
    210. We will modify guideline (3) in the Final Rule to remove the 
proposed requirement that transmission rights be granted for the life 
of a new transmission facility (the last sentence of the proposed 
guideline). The revised guideline will now read:

    Long-term firm transmission rights made feasible by transmission 
upgrades or expansions must be available upon request to any party 
that pays for such upgrades or expansions in accordance with the 
transmission organization's prevailing cost allocation methods for 
upgrades or expansions.
Scope of Guideline (3)
    211. Our intention in guideline (3) was to address transmission 
rights awarded to entities that fund transmission upgrades and 
expansions through direct cost assignment. Our subsequent discussion in 
this section applies only to such upgrades or expansions. All 
transmission organizations now allow transmission customers to fund 
capacity expansions and receive the transmission rights that are made 
possible by those expansions, although some of these transmission 
organizations have yet to develop exact term lengths and rules for 
awarding such rights. Guideline (3) does not address the award of 
transmission rights made possible by transmission upgrades that are 
rolled into transmission rates. When such transmission upgrades come 
into service, the transmission rights that result from such investments 
will be made available as rights from ``existing capacity'' and are 
thus addressed in guideline (4). Prevailing cost allocation rules will 
apply.
Term of Rights for Upgrades and Expansion
    212. As noted, we will modify guideline (3) by removing the last 
sentence, which requires that the term of a long-term transmission 
right awarded for an upgrade or expansion is equal to life of facility. 
Based on the comments of PJM and other parties on the difficulty of 
defining life of facility, we will let transmission organizations and 
stakeholders determine the appropriate terms. However, we encourage 
transmission organizations to harmonize the terms for long-term rights 
to existing transmission capacity and new transmission capacity as much 
as possible.
    213. Some commenters, such as National Grid, PG&E and EEI, argue 
that the term of rights to new transmission capacity should be 
shortened from the terms offered currently (e.g., PJM currently offers 
30 year fixed terms) because transmission planning horizons are only 5-
10 years. We believe that this change would unnecessarily introduce 
uncertainty into the development of merchant funded transmission 
facilities and, in most cases, it would not allow the funding party to 
receive the full benefits of its investment. Since the rights awarded 
for expansion are incremental rights, there is less

[[Page 43588]]

possibility that they will be made infeasible by changes in the 
allocated set of rights to the remainder of the grid.
    214. In response to LIPA's concern that New York ISO has not 
finished its rules for awards of long-term rights for transmission 
expansion, this guideline will require that transmission organizations 
develop and file tariff sheets and rate schedules for long-term rights 
for the types of expansions discussed in this section by the time that 
they award long-term rights for existing capacity.
Incremental Upgrades and Use of Existing Capacity
    215. We clarify that under guideline (3), parties that fund 
transmission upgrades and expansions will be eligible for incremental 
transmission rights and not entitled to obtain transmission rights to 
existing transmission capacity held by others. However, each 
transmission organization will need to establish rules by which 
interconnection customers that construct new generation facilities and 
are eligible for long-term firm transmission rights can obtain rights 
to existing transmission capacity, as per guidelines (4) and (5).
Other Issues
    216. We agree with OMS that rights awarded for transmission 
expansions made to support deliverability requirements for generator 
interconnection are not necessarily consistent with rights to hedge 
congestion charges associated with delivering power from the generator 
to load. This distinction between upgrades to support reliability 
(e.g., to qualify as a capacity resource) and those made to support 
transmission usage has been long-standing in the transmission 
organizations with organized electricity markets. However, we do not 
believe that the allocation of such transmission rights to support 
deliverability upgrades should interfere with the allocation of rights 
to others, since the rights would be incremental. Therefore, we will 
not address the rules for awards of such rights here.
Guideline (4)--Term of Rights Must be Sufficient to Hedge Long-Term 
Power Supply Arrangements
    217. As proposed in the NOPR, guideline (4) stated that long-term 
firm transmission rights must be made available with term lengths (and/
or rights to renewal) that are sufficient to meet the needs of load 
serving entities to hedge long-term power supply arrangements made or 
planned to satisfy a service obligation. The length of term of renewals 
may be different from the original term. The discussion of guideline 
(4) emphasized that term lengths and/or rights to renewal should be 
sufficient to meet the needs of transmission customers seeking to hedge 
congestion charges associated with long-term power supply arrangements 
made or planned to satisfy a service obligation.
    218. The NOPR sought comment on the appropriate lengths of terms, 
whether regional flexibility in setting term lengths is needed, or 
whether a more specific set of terms (i.e., standardized, such as 10 
years) should be established by this rule. The NOPR also sought comment 
on the relationship between the term of the long-term rights and the 
transmission organization's planning cycle and whether the planning 
cycles should be modified to accommodate the issuance of long-term 
rights. On the issue of rights to renewal, the NOPR allowed that 
transmission organizations may propose reasonable criteria regarding 
the availability of renewal rights and the price for renewal. Further, 
we proposed that the transmission organization may require minimum 
notice periods for initiation, renewal, cancellation or conversion that 
accommodate the transmission organization's planning cycle or other 
administrative considerations. The NOPR further sought comments on the 
relationship between rights to renew and transmission planning.
Comments
    219. Many commenters requested that the Commission allow regional 
flexibility when establishing the rules for long-term firm transmission 
rights to existing transmission capacity.\79\ However, as discussed 
below, some of these parties made suggestions for minimum terms and 
rules for renewal rights.
---------------------------------------------------------------------------

    \79\ See, e.g., Ameren, BPA, CAISO, Cinegy, EEI, IPL, KY PSC, 
Medwest ISO, NARUC, NRECA, NYISO, New York Transmision Owners, NU, 
OMS, PJM, Reliant, SDG&E, SoCal Edison, Strategic, and Wisconsin 
Electric.
---------------------------------------------------------------------------

    220. Several of the transmission organizations cautioned against 
the Commission mandating term lengths. Midwest ISO states that the 
transmission organization must have sufficient flexibility to define 
and allocate long-term FTRs of different terms. OMS argues that the 
coordination of the term of the rights with the planning process must 
be left to each transmission organization. CAISO also argued that many 
different combinations of term lengths and renewal rights could be 
implemented that would meet the objectives of Section 217(b)(4). Each 
transmission organization should be allowed to examine the appropriate 
rules with its stakeholders.
    221. In contrast, Santa Clara argues that load serving entities 
should set the terms that they need, and that transmission 
organizations should be required to accommodate those terms.
    222. ISO-NE argues that guideline (4) presents a number of 
concerns, including the difficulty in analyzing the feasibility of the 
rights, uncertainty over how to evaluate load serving entities' 
arrangements ``planned'' to satisfy a service obligation, necessity for 
administrative arrangements to review long-term power supply 
arrangements that qualify a load serving entity for long-term rights 
and to monitor for manipulation, and accounting for potential 
terminations of and modifications to such arrangements. ISO-NE asks 
that because of the difficulties in determining feasibility of long-
term rights, the Commission should ``avoid specifying excessive terms 
lengths,'' rather letting transmission organizations and stakeholders 
develop appropriate proposals.
    223. Reliant suggests that if the stakeholder process is 
ineffective in determining term lengths, then the Commission may find 
it appropriate to develop a more specific set of terms.
    224. Cinergy argues that guideline (4) goes beyond the intent of 
Section 217(b)(4), which it argues is directed exclusively toward 
transmission expansion. However, Cinergy agrees that transmission 
organizations should individually develop long-term rights. Cinergy 
also objects to the notion that the Section 217(b)(4) requires 
providing load serving entities with hedges.
Comments on Specific Term Lengths
    225. Some commenters propose specific term lengths, ranging from 
shorter to longer terms. Beginning with proposals for shorter terms, 
Midwest ISO asks that the definition of ``long-term'' be redefined to 
include terms of one year to offer the transmission organization 
maximum flexibility to establish rights of short durations but with 
renewal options that may suit participants in retail choice states. DC 
Energy proposes adding one year to the term of FTRs each year to allow 
the market to develop in an orderly and incremental fashion. Strategic 
Energy supports terms of two years as a starting point.
    226. CAISO discusses, for purposes of illustration, the possibility 
of two year rights with priority for renewal over

[[Page 43589]]

requests for new rights. SDG&E recommends that one year CRRs are 
implemented for the first year of the CAISO MRTU project (``Release 
1''), with longer-term CRRs reserved for the next phase of the market 
(``Release 2'').
    227. CAISO further argues that because transmission owners have the 
ability to withdraw from the ISO with a two-year exit notice, duration 
of transmission rights longer than two years is ``potentially 
questionable coverage as the CAISO will not be capable of enforcing 
such instruments upon a transmission owners' exit.'' \80\ CAISO asks 
that the Commission consider this issue. In reply comments, SMUD notes 
that CAISO has signed 20 year firm transmission agreements with WAPA on 
the Pacific intertie. SMUD suggests that CAISO condition exit of a 
transmission owner on honoring existing contracts. It also notes that 
since transmission organization membership is voluntary, there is no 
long-term rights construct that does not involve the risk of exit.
---------------------------------------------------------------------------

    \80\ Comments of CAISO at 13.
---------------------------------------------------------------------------

    228. NYISO argues that it is ``quite possible that one-year, two-
year or five-year rights'' will be sufficient to meet the needs of 
transmission customers with long-term power supply arrangements. NYISO 
notes that it has previously offered 2 and 5 year Transmission 
Congestion Contracts, but that market participant interest is limited, 
due in part to the retail competition in New York state. Coral Power 
also supports terms in the one to five year range. IPL supports terms 
of no longer than three years, at least for an initial period to gain 
market experience. Similarly, Cinergy proposes an initial trial period 
of rights with terms from 2-5 years. Morgan Stanley proposes terms 
ranging from three to five years. It argues that terms shorter than 
three years are not likely to be sufficient for investor certainty, 
while terms longer than five years will fail to create sufficient 
liquidity to attract buyers and increase the risk of revenue 
insufficiency.
    229. A number of commenters suggested minimum terms. BPA suggested 
a minimum term of 5 years to support stability in transmission system 
planning. Other commenters suggested a 10 year term, including AEP, 
APPA, CMUA, PJM Public Power Coalition, NCPA and TAPS. APPA suggests a 
minimum term of 10 years outside of retail access environments, and 
also supports longer terms for transmission rights to support new 
baseload and renewable generation resources. PJM Public Power Coalition 
also states that ideally, terms would span 20 to 30 years or more, 
reflecting the terms of financing.
    230. PG&E supports fixed terms and/or renewal rights that provide 
coverage of 5 to 30 years, consistent with the term and quantity of the 
service obligation. PG&E further states that transmission organizations 
should have the flexibility to propose more granular rights to ease 
administration and transfer when appropriate as well as potentially to 
increase the availability of short-term rights during the effective 
term.
    231. NRECA states that long-term rights should have maximum periods 
that match the term of the long-term power supply arrangement. Central 
Vermont, NYAPP, Redding, Santa Clara, SMUD and Wisconsin Electric 
present similar views.
    232. A number of commenters emphasized that the term of the long-
term rights should be commensurate with, or at least not exceed, the 
transmission planning horizon.\81\ For some commenters, such as 
Industrial Consumers, this would be a maximum term length with no 
opportunities for renewal. For others, this would be the basic term 
length with renewal rights. Some observers, such as Industrial 
Consumers, note approvingly that some transmission organizations are 
considering extending the planning horizon from 5 years to 10 years. 
National Grid requests that the Commission clarify that the 
``sufficiency'' standard under guideline (4) ``means nothing more than 
a term based on rational planning studies.'' \82\ National Grid argues 
that terms beyond such planning studies would make the associated 
rights ``purely speculative.'' NU argues that rights with terms 
extending beyond the planning horizon would ``unreasonably transfer 
risk of congestion to participants who are not in a position to control 
that risk.'' \83\
---------------------------------------------------------------------------

    \81\ See, e.g., Allegheny, Cinergy, DTE, EEI, National Grid, 
NRECA, NU and Xcel.
    \82\ Comments of National Grid at 21.
    \83\ Reply Comments of NU at 4.
---------------------------------------------------------------------------

    233. NRECA argues that the transmission planning cycle should be at 
least 10 years to provide adequate support for infrastructure 
investment. AEP and Allegheny support the alignment of the term of 
long-term firm transmission rights with the 10-year transmission 
planning cycle that is being developed by PJM. PJM Public Power 
Coalition argues that transmission planning cycles should be modified 
to account for the terms of transmission rights that extend beyond 
current cycles.
    234. EEI supports the concepts of long-term transmission rights 
with terms commensurate with the length of the planning horizon, but 
states that the planning horizons are just one of a number of issues 
that might be considered in determining term length. Other factors 
could include whether the system is constrained, the length of time it 
reasonably takes to expand the system, existing uses of the system, and 
the demand for long-term and short-term rights on the system. Further, 
stakeholders may consider the volume of grandfathered rights and their 
expiration dates, expected generation retirements, and the nature of 
renewal rights.
    235. In contrast, CAISO does not see a compelling reason for tying 
the terms of transmission rights to the transmission planning cycle. 
CAISO argues that financial transmission rights do not carry physical 
characteristics. Hence, the problem of insuring their value over the 
long-term is fundamentally a cost allocation issue and is only one of 
many factors to be taken into account in assessing particular 
transmission projects. CAISO thus asks that the Commission allow 
transmission organizations to consider the issue of term length as a 
matter both of market design and transmission planning without imposing 
any specific linkage between the two.
    236. New England Public Systems similarly argues that the creation 
of long-term rights should not in and of itself change the transmission 
organization's planning cycle. In its reply comments, New England 
Public Systems argues that long-term rights should be integrated into 
the planning process, becoming part of the baseline for each planning 
cycle. In that sense, it contends, the planning cycle should not be a 
constraint on the term of the rights.
    237. Similarly, IPL argues that planning cycles can not be designed 
to support financial transmission rights because of the large number of 
variables that determine a feasible allocation and the likelihood of 
changes in those variables over time. Hence, regardless of whether the 
terms of the long-term rights are linked to transmission planning 
cycles, there will be a need to periodically re-examine the feasibility 
of particular allocations of rights and make corresponding 
modifications in the allocation if needed. IPL further argues that this 
periodic evaluation and revision of the rights would still allow the 
holder an ``adequate hedge.'' IPL supports this position by arguing 
that the load serving entity is entitled only to a reasonable hedge, 
not an absolute guarantee that it will never bear

[[Page 43590]]

congestion costs. IPL proposes that guideline (4) be revised to link 
term length to the concept of a ``reasonable'' hedge and to limit the 
potential for revenue shortfalls.\84\
---------------------------------------------------------------------------

    \84\ Comments of IPL at 12.
---------------------------------------------------------------------------

    238. PG&E argues that the relevant issue in determining the length 
of the term is not the planning horizon but rather the term of the 
service obligation. PG&E notes that ``the Commission has approved many 
contracts with terms beyond ten years, and has never suggested that 
such obligations should be limited to the planning horizon.'' 
Similarly, TAPS argues that the transmission organization's planning 
horizon cannot be a basis for restricting terms, including renewals, to 
a period shorter than the load serving entity's resource commitment.
    239. Finally, PG&E argues that the effectiveness of long-term 
transmission rights will be best served if the terms have sufficient 
granularity, such as peak and off-peak periods in the day, the week, 
the month or season.
Renewal Rights, Minimum Notice Periods and Termination
    240. A number of commenters argue that renewal rights can be used 
to extend the period covered by long-term transmission rights. Ameren 
suggests that rather than prescribe a single term length for all long-
term rights, transmission organizations should focus on providing 
renewal rights. For example, Ameren argues that FTRs with annual 
rollover rights would be far more flexible than long-term FTRs with set 
terms. Ameren proposes that a load serving entity with a power supply 
arrangement of longer than one year be given the option to roll over 
the FTR each year subject to verification that the power supply 
arrangement will be in effect for the next year and the load serving 
entity is nominating no more than its forecast load for the subsequent 
year. Ameren points out that this approach is consistent with the 
auction requirements in states with retail choice, where load serving 
entities will need access to long-term rights even though their power 
supply contracts will only be one-year in length.
    241. Similarly, Cinergy argues that one-year transmission rights 
with renewal rights would ``provide a measure of long-term benefit 
while still preserving the ability to modify the underlying rights 
themselves on an annual basis.'' \85\ Cinergy is also concerned that 
entities with long-term transmission rights not simply be able to 
cancel the rights unilaterally. Instead, the ``rights must be 
relinquished in a manner than allows the market to value and ration 
them appropriately.'' \86\
---------------------------------------------------------------------------

    \85\ Comments of Cinergy at 33.
    \86\ Id. at 35.
---------------------------------------------------------------------------

    242. TAPS supports Ameren's proposal for one-year rights with 
assured rollover rights (but offers also its own proposal for rolling 
10-year terms, discussed below). TAPS suggests that such regional 
variations might be acceptable as long as load serving entities can 
achieve long-term price stability for the full duration of their long-
term resource commitments. Similarly, New England Public Systems argues 
that the combination of term lengths, renewal rights and cancellation 
rights must be ``sufficiently flexible'' to enable load serving 
entities to tailor their long-term rights coverage to their specific 
needs. It is willing to support rights of short duration ``so long as 
LTTR renewal rights [are] sufficiently robust to ensure the 
continuation by [load serving entities] of needed rights.'' \87\
---------------------------------------------------------------------------

    \87\ Reply Comments of New England Public Systems at 20.
---------------------------------------------------------------------------

    243. TAPS, Industrial Consumers and New England Public Systems 
support a rolling 10-year term that affords the holder unconditional 
renewal rights. For example, in the first year, the holder of the 10-
year right would inform the transmission organization whether it wanted 
the right in year 11, in year two whether it wanted the right in year 
12, etc. Industrial Consumers states that there is a critical need that 
investors for new base-load generation perceive that firm transmission 
rights and renewal rights are available for up to 20 years or longer. 
Xcel similarly argues that at the end of the initial term of long-term 
rights, which could be up to the length of the planning horizon, 
renewal would take place on a one year basis as long as the obligation 
to serve still exists.
    244. Other commenters were concerned that reliance on renewal 
rights would erode the durability of long-term rights. CMUA states that 
renewal rights introduce uncertainty over issues such as changes in 
rates, changes in the simultaneous feasibility test, and the 
incorporation of other changes since the long-term right was granted.
    245. Industrial Consumers argues that renewal rights should be 
limited to load serving entities that can demonstrate that the renewal 
is needed to support a long-term power supply arrangement. Similarly, 
BPA supports the principle that renewal rights may be subject to 
limitations that tie the long-term transmission service to long-term 
power supply arrangements, to ensure that renewal rights are not over-
allocated.
    246. National Grid argues than any renewal right should be 
``narrowly tailored,'' as any renewal beyond the applicable planning 
horizons would be ``just as speculative'' as a long-term right with an 
initial term beyond such horizons.\88\ Instead, renewals would have to 
be subject to evaluation and reconfigured to reflect system conditions 
through the renewal term.
---------------------------------------------------------------------------

    \88\ Comments of National Grid at 22.
---------------------------------------------------------------------------

    247. NSTAR argues that renewal rights for long-term rights are 
discriminatory because the ``guidelines do not allow direct access load 
served under short-term contracts to qualify for long-term rights on a 
renewal basis, even though the contracts under which they are served 
will be extended into the future or will be replaced by new 
contracts.'' \89\ For example, under some interpretations the 
guidelines could allow a load serving entity with a 2-year right to 
extend the right indefinitely while the holder of a one-year right 
would not be eligible for such renewals.
---------------------------------------------------------------------------

    \89\ Reply Comments of NSTAR AT 9.
---------------------------------------------------------------------------

    248. NYISO argues that the Commission should allow auction-based 
renewal systems, such as that offered by NYISO. NYISO argues that 
renewal of rights without market pricing would be ``inimical to the 
design of auction-based systems that are meant to fairly re-allocate 
rights based on economics and the interests of end-users.'' \90\ 
Moreover, renewals without market pricing would likely reduce the 
availability of transmission rights because holders of the rights could 
retain them indefinitely. Another issue is that through the annual 
auctions, counterflow transmission rights are purchased, making 
additional transmission rights feasible. If the counterflow rights were 
not renewed, then at least some of the long-term renewal rights would 
be rendered infeasible. NYISO further argues that the concept of a set 
``price'' for renewal may also be antithetical to the market auction 
model that it employs, because such prices may not be consistent with 
the auction outcomes.
---------------------------------------------------------------------------

    \90\ Comments of NYISO at 18.
---------------------------------------------------------------------------

    249. In contrast, TAPS argues that renewals should be at no 
additional cost. TAPS argues that firm delivery and long-term rights 
are part of the ``core responsibility'' of the transmission provider 
and not an additional cost. TAPS states that at an absolute minimum, 
any renewal charges should be fixed and fully disclosed by the 
transmission organization before the initial term begins.

[[Page 43591]]

    250. SMUD argues that rather than renewal rights, the Commission 
should allow holders of long-term rights the ability ``to apply the 
right of first refusal protections accorded OATT customers under Order 
No. 888.'' \91\
---------------------------------------------------------------------------

    \91\ Comments of SMUD at 24.
---------------------------------------------------------------------------

    251. Regarding minimum notice periods for renewal or cancellation. 
APPA supports an ``appropriate'' notice period. BPA argues that the 
minimum notice period for exercising a right to renew should be one 
year. Cinergy is concerned that holders of the rights should not be 
able to cancel them ``unilaterally.'' \92\ Rather, the rights must be 
relinquished in a manner that allows the market to value and ration 
them appropriately. Wisconsin Electric states that any long-term 
protection should terminate when a unit is taken out of service or the 
agreements are terminated, even if that is prior to the expected life 
or term of the agreement.
---------------------------------------------------------------------------

    \92\ Comments of Cinergy at 34.
---------------------------------------------------------------------------

Other Issues
    252. There was some concern among commenters regarding the seams 
implications of different term lengths among organized markets. NRECA 
expresses concern that adjoining regions may assign different terms for 
long-term rights that this will cause seams problems. NRECA requests 
the Commission require coordination between adjoining transmission 
organizations to ensure that the rights are not ``illogically matched'' 
to their supply arrangement.\93\
---------------------------------------------------------------------------

    \93\ NRECA invokes the ``affected systems'' approach of the 
Commission's generator interconnection policies as the basis for 
this requirement. Comments of NRECA AT 13.
---------------------------------------------------------------------------

    253. A number of commenters emphasized the need for short-term 
transmission rights to co-exist with long-term rights. Allegheny stated 
that the final rule should preserve the ability of market participants 
to obtain allocations of shorter-term rights, including first priority 
FTR allocations to historic resources. Cinergy is concerned that in 
states with retail choice, load serving entities would often have to 
overcome state regulatory obstacles to make long-term power supply 
arrangements, needed to acquire long-term transmission rights. This 
would leave such entities limited to a ``second-tier'' allocation.
    254. EEI proposes specific revisions for guideline (4) to reflect 
consideration of existing uses of the system. It suggests that the 
availability of long-term rights should be limited ``to the extent 
reasonable in light of the existing uses of the system.'' \94\ In 
addition, it argues that the term ``should'' should be substituted for 
``must'' with respect to provision of the rights. Finally, it suggests 
modifying the last sentence of the guideline as follows (additions 
underlined): ``The length and conditions under which the term of 
renewals is offered may be different than the original term.'' APPA and 
NRECA oppose EEI's proposed modifications to guideline (4). Both 
commenters are concerned with the substitution of the term ``should'' 
for ``must'', which they argue is intended to weaken the requirement.
---------------------------------------------------------------------------

    \94\ Comments of EEI at 21.
---------------------------------------------------------------------------

Commission Conclusion
    255. We will adopt guideline (4) with a modification to indicate a 
10-year minimum term that transmission organizations must be able to 
offer. Transmission organizations and stakeholders will have 
substantial latitude to determine how to achieve long-term coverage 
through combinations of transmission rights of specific terms and 
renewal rights along with transmission planning and expansion 
procedures that support long-term rights.
    256. The revised guideline (4) reads as follows:

    Long-term firm transmission rights must be made available with 
term lengths (and/or rights to renewal) that are sufficient to meet 
the needs of load serving entities to hedge long-term power supply 
arrangements made or planned to satisfy a service obligation. The 
length of term of renewals may be different from the original term. 
Transmission organizations may propose rules specifying the length 
of terms and use of renewal rights to provide long-term coverage, 
but must be able to offer firm coverage for at least a 10-year 
period.
Term Lengths for Rights to Existing Capacity
    257. We agree with those commenters, including most transmission 
organizations, who state that this guideline should not mandate a 
standard term length for long-term firm transmission rights. Given that 
there is little experience with long-term transmission rights in 
organized electricity markets, and that different regions may find that 
different combinations of terms lengths and/or renewal rights best fit 
their stakeholder interests and pre-existing rules for transmission 
rights, we will allow regional flexibility in defining the terms of 
long-term transmission rights that are offered. However, section 
217(b)(4) of the FPA makes clear that long-term transmission rights 
should be made available to allow load serving entities to hedge 
congestion charges associated with deliveries from long-term power 
supply arrangements. Hence, term lengths must be sufficient to achieve 
that objective, either alone or in concert with renewal rights.
    258. While we allow regional flexibility in defining the terms of 
long-term firm transmission rights, we will require that transmission 
organizations make available transmission rights and renewal rights 
that provide coverage for a period of at least 10-years. This will 
ensure that transmission rights are offered that meet the reasonable 
needs of load serving entities to obtain transmission service for long-
term power supply arrangements used to meet service obligations while 
allowing transmission organizations and their stakeholders flexibility 
in designing rights that suit regional needs. Transmission 
organizations can offer this 10-year coverage through any mix of term 
lengths and renewals that stakeholders agree to, as long as the 
coverage is ``firm'', meaning that the quantity of the rights allocated 
is fixed over the 10 year period and that the rights are fully funded. 
Renewal rights may be subject to provisions, such as adequate notice, 
that address the transmission organization's planning needs and 
adequate hedging of the load serving entity's long-term power supply 
arrangements.
    259. A number of commenters urged that the term of rights remain 
relatively short, for example, two to three years, for at least an 
interim phase. Again, our requirement for a minimum 10-year coverage 
does not necessarily require 10-year transmission rights if no load 
serving entity requests such rights. Other commenters argued that the 
rights should be of sufficient length, such as a minimum of 5 years, to 
assist in transmission planning. The 10-year coverage period that we 
require here will assist such planning, but we leave it up to 
transmission organizations and stakeholders to determine how best to 
harmonize the long-term firm transmission rights and transmission 
planning cycles.
    260. Further, as we note above with regard to the proposed 
definition of long-term power supply arrangements, APPA, PJM and TAPS 
generally argue that long-term power supply arrangements should be 
considered those with a minimum term of at least 10 years. This Final 
Rule focuses primarily on providing long-term firm transmission rights 
to cover power supply arrangements with those lengths of terms. 
Nonetheless, in different transmission organizations, the accommodation 
of other lengths of power supply arrangements might be considered 
important. Here, however,

[[Page 43592]]

our focus is providing load serving entities with long-term power 
supply arrangements to meet their service obligations with the 
opportunity to obtain long-term firm transmission rights that will 
support the financing and construction of new infrastructure. 
Therefore, we find that setting a 10-year minimum term as a benchmark 
is appropriate, while also leaving the transmission organizations with 
sufficient flexibility to offer terms of other lengths.
    261. We emphasize that the 10-year minimum term in this guideline 
is a benchmark. The fundamental requirement of this guideline is that 
transmission organizations offer rights with terms that are sufficient 
to hedge long-term power supply arrangements. In regions where such 
rights are typically longer than this benchmark, transmission 
organizations may need to offer longer terms and/or renewal rights 
beyond the initial term. Hence, we expect that most transmission 
organizations will develop rules to either begin new 10-year coverage 
terms at the end of each 10-year period or to provide renewals on a 
rolling basis to support long-term power supply arrangements. We 
understand from the comments that because of the likelihood that 
transmission system changes will take place over the 10-year period, 
stakeholders may have to agree to some reasonable process for 
modifications of holdings of transmission rights in between allocation 
periods. We will consider proposals that address such issues in the 
individual transmission organization compliance filings.
    262. PG&E urged sufficient granularity in the terms of long-term 
rights, such as monthly rights, daily peak and off-peak rights, etc. We 
agree that more granularity assists in creating transmission rights 
terms that can better fit actual transmission usage patterns, and thus 
improves market efficiency. Stakeholders and transmission organizations 
must determine how much granularity is desirable at the introduction of 
long-term rights; increased granularity can be introduced over time.
    263. In answer to NYISO's concern that entities in its service 
territory may not desire long-term rights, we reiterate that such 
rights must be offered and available to load serving entities. As we 
discuss above, EPAct 2005 mandates that such rights be available.
    264. While we recognize CAISO's concern that load serving entities 
awarded long-term rights could withdraw from the ISO's market before 
the termination of the right, we do not see this as a limitation on 
granting rights with terms greater than the notice period for 
withdrawal. A transmission organization may establish rules for 
disposition and possible termination of allocated rights in the event 
of a withdrawal.
Other Issues With Renewal Rights, Minimum Notice Periods and 
Termination
    265. Currently, load serving entities in most organized electricity 
markets are generally eligible to nominate financial transmission 
rights or auction revenue rights up to their peak load if they pay 
transmission access charges. The eligibility to nominate rights (or to 
renew a load serving entity's rights) is currently long-term; it is 
available each year to entities that serve load and pay the access 
charges, but is subject to the simultaneous feasibility test for 
nominations or the results of an auction. These latter requirements 
help ensure revenue adequacy but introduce some uncertainty into the 
actual year-to-year awards of transmission rights that this rule seeks 
to stabilize for some percentage of eligible rights. Also, as discussed 
in guideline (2), there may not be full funding of the annual rights, 
which adds further uncertainty as to their value.
    266. Some commenters suggest additional restrictions or eligibility 
requirements on renewal rights. Under guideline (2), we discuss that 
full funding of the rights may require, for example, a premium payment. 
However, to renew the rights for new terms, there is not an obvious 
need for new conditions. Given the current rules for short-term rights, 
there should be little to change in the renewal process when long-term 
rights are offered as long as the transmission system is being planned 
and upgraded to accommodate the rights. As suggested by APPA, to renew 
allocated long-term rights, load serving entities should be required to 
commit to paying the transmission access charges for the period of the 
allocated right, whether an auction revenue right or a financial 
transmission right.
    267. In response to NSTAR's concern that renewal rights for long-
term firm transmission rights are discriminatory with respect to short-
term rights, as we note above, short-term transmission rights are 
renewable each year for an annual term.
    268. We agree with commenters that a minimum notice period should 
be required for renewing a long-term right. In general, the longer the 
term of the right, the longer should be the minimum notice period. We 
will allow transmission organizations and stakeholders to determine the 
specific notice periods they will propose to apply, however.
Other Issues
    269. As noted above, several commenters stated in response to the 
proposed definition of long-term power supply arrangements that the 
Commission should require that such arrangements have certain specific 
characteristics, including specific designation of generating 
resources. The Commission will decline to adopt specific criteria for 
long-term power supply arrangements. First, as discussed in more detail 
below, we are removing from guideline (5) the requirement that a load 
serving entity must hold ``long-term power supply arrangements'' to 
receive an allocation priority, which should alleviate concerns 
regarding the difficulties associated with the validation of such 
arrangements by transmission organizations. Moreover, the comments 
suggest that long-term power supply arrangements may have different 
characteristics in different regions based on the prevailing practices 
of load serving entities in those areas. Accordingly, to the extent 
transmission organizations and their stakeholders believe that 
specification of criteria for long-term power supply arrangements 
remains necessary to comply with the Final Rule, we will allow the 
regions the flexibility to develop such specifications and propose them 
in compliance filings to this rule.
    270. In response to NRECA's concern with seams issues, we discuss 
these issues above with regard to regional flexibility.
    271. Several commenters seek to revise guideline (4) to include 
restrictions on the quantity of long-term rights that can be obtained. 
We discuss such restrictions under guideline (5).
    272. With regard to EEI's proposed modifications of guideline (4), 
we agree with APPA and NRECA that the substitution of the word 
``should'' for the word ``must'' in the first sentence of the guideline 
would weaken the requirement. Hence, we will not adopt that 
modification.
Guideline (5)--Load Serving Entities with Long-Term Power Supply 
Arrangements Have Priority to the Existing System
    273. As proposed in the NOPR, guideline (5) stated that load 
serving entities with long-term power supply arrangements to meet a 
service obligation must have priority to existing transmission capacity 
that supports long-term firm transmission rights requested to hedge 
such arrangements.

[[Page 43593]]

In the NOPR, the Commission noted that, while section 217 does not 
require that long-term firm transmission rights be made available only 
to load serving entities with service obligations, the Commission 
interprets that section to require that load serving entities with 
long-term power supply arrangements to satisfy a service obligation be 
given a preference in securing long-term firm transmission rights. 
Therefore, the NOPR proposed that when rights requested by eligible 
parties with priority (or parties without priority that are being 
accommodated) are not simultaneously feasible given existing 
transmission capacity, the transmission organization may adopt methods 
to allocate the requested rights to the parties prior to granting such 
rights. The NOPR asked for comments on such methods, and on whether 
section 1233 of EPAct 2005 and new section 217(b)(4) of the FPA support 
placing reasonable limits on the award of long-term rights. Section 
217(b)(4) states that the Commission must exercise its authority to 
meet the ``reasonable needs'' of load serving entities to satisfy their 
service obligations.
    274. Also, the NOPR noted that, in making available long-term firm 
transmission rights, the transmission organization may have to 
incorporate estimates of load growth into the award of such rights. 
This raises the concern that if the load growth assumptions are 
overstated some load serving entities could be awarded more long-term 
firm transmission rights than needed, and the associated transmission 
capacity would not be available for allocation of transmission rights 
to others. The NOPR asked for comment on this issue and any rules or 
other safeguards that address it.
Comments
General Arguments For and Against the Proposed Priority
    275. A number of commenters support the proposal to give priority 
to load serving entities with long-term power supply arrangements to 
meet a service obligation.\95\ For example, APPA states that load 
serving entities that are willing to make a long-term commitment to pay 
their allocated share of the RTO's fixed transmission system costs 
(including the costs of transmission upgrades allocated to customers 
under that RTO's Commission-approved transmission cost allocation 
mechanism) should have a priority claim on the transmission facilities 
for which they are obligated to pay. FirstEnergy argues that the 
Commission's guidelines should grant preferential access to load 
serving entities with long-term power supply arrangements in order to 
promote development of generation and transmission infrastructure, and 
to dampen price volatility.
---------------------------------------------------------------------------

    \95\ See, e.g., SoCal Edison, Minnesota Power, CMUA, 
FirstEnergy, APPA, Central Vermont, Redding and SMUD.
---------------------------------------------------------------------------

    276. However, many commenters oppose the priority granted in 
proposed guideline (5),\96\ with some claiming that the proposed 
priority would be unduly discriminatory.\97\
---------------------------------------------------------------------------

    \96\ See, e.g., Cinergy, Allegheny, Reliant, CAISO and NSTAR.
    \97\ See, e.g., AF&PA, Xcel, Allegheny, EEI, NARUC, Morgan 
Stanley, BP Energy, Strategic Energy, ISO-NE, NYISO, EPSA, SDG&E, 
Midwest ISO, NYDPS and Constellation.
---------------------------------------------------------------------------

    277. Cinergy states that FPA section 217 does not require the 
Commission to grant preferential rights to load serving entities, and 
SDG&E states that there is absolutely no statutory support for the 
``preference'' or ``priority'' language of guideline (5). According to 
SDG&E, a much more faithful and economically sound reading of the 
``meets the reasonable needs'' language of the EPAct 2005 is that long-
term purchasers of power should be accommodated by the new guidelines 
by providing opportunities for them to secure long-term firm 
transmission rights, but they should not be able to acquire such rights 
at the expense of holders of power supply arrangements of a shorter 
duration. Morgan Stanley asserts that the Commission has a fundamental 
duty to prevent unduly discriminatory practices in transmission access, 
and allowing for a preference-based allocation approach as part of the 
Final Rule would run counter to such a duty. Moreover, NYISO states 
that interpreting section 217 to grant preferences to certain classes 
of load serving entities would contradict section 206 of the Federal 
Power Act, as well as Commission precedent and policy against undue 
discrimination and preferences in a competitive marketplace.
    278. Allegheny recommends that, consistent with the process 
currently used in PJM, firm transmission rights should be allocated 
based on load and be available to all load serving entities serving 
that load. It believes that no preference should be given in the firm 
transmission right allocation process to load serving entities with 
longer-term power supply contracts to serve the same load or to load 
serving entities that were serving load first. BP Energy states that, 
as currently written, guideline (5) might be interpreted to permit a 
load serving entity to displace an existing holder simply because the 
existing holder's power supply arrangements last for a shorter period 
of time.
    279. Reliant states that, among the unintended consequences of the 
Commission's proposal are that such a preference: (1) Encourages load 
serving entities to enter into sham long-term agreements and other 
gaming, (2) distorts the competitive playing field in a manner that 
undermines and complicates progressive retail choice models, (3) forces 
load serving entities to hold long-term rights to avoid being 
shortchanged in the short-term allocation processes, and (4) 
discourages independent generation investment.
    280. NSTAR states that the deficiencies of the proposed rule can be 
corrected by following the statutory language. According to NSTAR, this 
would be accomplished by redefining ``long-term power supply 
arrangements'' as contained in proposed section 41.1(a)(5) by deleting 
``or'' and by adding at the end of that provision the following phrase: 
``or other arrangements for the purpose of meeting a service obligation 
on a long-term basis.''
    281. With regard to the argument that a load serving entity with a 
long-term commitment to pay its allocated share of the RTO's fixed 
transmission costs is deserving of priority access to long-term firm 
transmission rights, BP Energy claims that the argument is flawed 
because all electric consumers end up paying their allocated share, 
whether they receive service underlain by long-term or shorter-term 
supply arrangements. Also, National Grid argues that establishing 
priorities to any new long-term transmission rights based on the length 
of terms of supply transactions makes little economic or operational 
sense. From the standpoint of fundamental fairness, National Grid 
believes that the allocation of transmission rights should be based on 
the relative contributions of the customers to the costs of the 
transmission system at the time the rights are made available. Coral 
Power believes that creating a perpetual preference for remaining 
capacity based on the theory that customers have paid for some type of 
service in the past is unreasonable.
    282. Cinergy believes that if the Commission permits load serving 
entities to secure long-term transmission rights to existing 
transmission capacity on the basis of existing long-term contracts, 
then it will not only separate load serving entities as a favored class 
above other transmission customers, it will also create a favored class 
among load serving entities themselves.

[[Page 43594]]

    283. Several commenters, however, express the view that there is 
nothing inherently unduly discriminatory about the priority set forth 
in proposed guideline (5).\98\ For example, NRECA states that it is not 
discriminatory to grant a higher priority to longer-term transmission 
service; Order No. 888 has done that for years. In any event, NRECA 
argues that new section 217(b)(4) of the FPA requires that the 
Commission regulate under the FPA in a manner that enables load serving 
entities to obtain long-term transmission rights for their long-term 
power supply arrangements; so the priority for long-term power-supply 
arrangements is built into the statute, and there is no undue 
discrimination, as section 217(k) makes clear.
---------------------------------------------------------------------------

    \98\ See, e.g., NRECA, TAPS, APPA, SMUD, Redding, TANC and New 
England Public Systems.
---------------------------------------------------------------------------

    284. APPA states that assuming that a situation were to arise in 
which the RTO had insufficient rights available to grant both full 
long-term firm transmission right and firm transmission right 
allotments, APPA does not believe that it would constitute an ``undue 
preference'' to fulfill the needs of long-term firm transmission right 
holders first. New England Public Systems states that what is unduly 
discriminatory is the status quo, in which current market rules provide 
those who enter into short-term transactions the tools with which to 
hedge their risks but deprives load serving entities with longer-term 
power supply arrangements of the tools they need to hedge the risks 
they face. According to New England Public Systems, rectifying this 
situation cures undue discrimination; it does not create it.
Limits on Long-Term Firm Transmission Rights
    285. A number of commenters that either support, or do not oppose, 
the priority for load serving entities as proposed in guideline (5), 
state that it may be reasonable to place limits on the amount of 
capacity that can be allocated as long-term firm transmission 
rights.\99\ However, New England Public Systems submits that the 
specific nature and terms of any such mechanisms are best left to 
negotiation among the affected stakeholders prior to the transmission 
organizations' compliance filings.
---------------------------------------------------------------------------

    \99\ See, e.g., New England Public Systems, AEP, PJM, BPA, PJM 
Public Power Coalition and TAPS.
---------------------------------------------------------------------------

    286. TAPS states that ``reasonable needs'' of load serving entities 
in organized markets must at least include the long-term firm 
transmission rights needed to support investment in baseload and 
renewable resources. While TAPS believes that long-term firm 
transmission right coverage for peaking resources is not necessary, it 
states that intermediate resources are a closer question. PJM argues 
that at some baseline level of usage of the transmission system it is 
reasonable to expect long-term transmission rights to be fully funded 
(absent significant transmission system outages), as the transmission 
system should be designed and constructed to meet the baseline 
requirements of all of its users.
    287. E.ON believes that priority firm transmission rights that 
would otherwise fail the simultaneous feasibility analysis should be 
allocated on an equitably reduced basis to all qualified load serving 
entities. However, BPA states that, for a new transmission organization 
forming in the Pacific Northwest's unique hydro-based system, it 
supports granting long-term transmission rights to all existing rights 
holders, even if those rights are not simultaneously feasible under the 
most conservative assumptions possible.
    288. Several commenters, including some that do not support the 
priority of guideline (5), state that, if the priority is adopted, 
limits should be placed on the amount of transmission capacity 
allocated to long-term firm transmission rights in order to protect 
those entities that rely on short-term rights.\100\ For example, DTE 
states that it expects the introduction of long-term firm transmission 
rights to reduce the availability of short-term firm transmission 
rights, and care should be taken to ensure that current users of short-
term firm transmission rights are not negatively affected. It argues 
that allocations to other load serving entities should be made only 
after distribution utilities have been assured sufficient long-term 
firm transmission rights to meet their current and future native load 
requirements.
---------------------------------------------------------------------------

    \100\ See, e.g., OMS, DTE, EEI, IPL, Reliant, Strategic Energy 
and Xcel.
---------------------------------------------------------------------------

    289. Xcel proposes that no more than 50% of an entity's peak load 
be eligible for a long-term financial transmission right. Xcel states 
that this value should be static (i.e. should not allow for load 
growth) based on a historical reference year such as the year preceding 
the first allocation. Strategic Energy suggests that an RTO might limit 
long-term hedges to the lowest daily system peak over the previous 
planning period.
    290. Some commenters do not agree with proposals to limit the 
amount of transmission capacity that is available for long-term firm 
transmission rights.\101\ NRECA states that it does not understand how 
such an approach does not run afoul of the language of new FPA section 
217. Ameren states that the preference that EPAct 2005 gives to load 
serving entities with long-term power supply arrangements to meet their 
service obligations reflects Congress' judgment that load serving 
entities engaging in long-term contracting and investment to meet their 
service obligations should be supported with access to long-term firm 
transmission rights; therefore, Ameren submits that this preference 
should not be undermined by limiting capacity available for long-term 
firm transmission rights. TANC states that the Commission should not 
allow transmission organizations the ability to limit the amount of 
transmission capacity available to support long-term firm transmission 
rights, but should instead require transmission organizations to 
actively manage the level of long-term firm transmission rights 
necessary to meet entities' current native load obligations, including 
load growth estimates.
---------------------------------------------------------------------------

    \101\ See, e.g., NRECA, Ameren, Public Power Council and TANC.
---------------------------------------------------------------------------

Rules for Determining Priority
    291. Some commenters offer specific recommendations concerning the 
rules for determining when an entity is entitled to receive priority 
with respect to long-term firm transmission rights.\102\ For example, 
Public Power Council recommends that, pursuant to section 217(d), the 
transmission rights not used to meet service obligations may be applied 
to other uses of the system. According to Public Power Council, this 
necessarily means that the transmission rights must first be offered to 
load serving entities and after their needs are met, they are released 
to others.
---------------------------------------------------------------------------

    \102\ See, e.g., Santa Clara, Public Power Council, PG&E, 
National Grid, Morgan Stanley, DC Energy, Cinergy, BP Energy and 
Wisconsin Electric.
---------------------------------------------------------------------------

    292. PG&E argues that the preference, at least with respect to 
initial allocations, should be in accordance with the term and quantity 
of the service obligation, reflected as load share in the future term. 
For those transmission organizations that adopt auctions to follow 
initial allocations, PG&E recommends that stakeholders should address 
the issue of whether shortage of available long-term firm transmission 
rights relative to demand should trigger a validation procedure such 
that load serving entities seeking to meet long-term service 
obligations are given preference, or whether the auction price should 
determine priority.

[[Page 43595]]

    293. Morgan Stanley states that it is not necessarily opposed to 
the auction revenue right allocation methodologies that are based on 
the amount of load served by a party. However, in Morgan Stanley's 
view, it is crucial that any auction revenue right grants be 
independent of the status of the organization, i.e., whether it is a 
load serving entity.
    294. As to the definition of a ``Long-term Power Supply 
Arrangement'' that would be eligible for the long-term protections, DC 
Energy states that the power supply agreement must be firm for its term 
and must provide for energy from one or more specific generators in 
specific amounts. Wisconsin Electric believes that a key eligibility 
criterion is whether such arrangement includes not just energy, but 
energy and capacity. It claims that an energy only transaction does not 
indicate long-term control of the unit. Cinergy believes that 
preferential access to existing transmission capacity that is secured 
on the basis of long-term power supply arrangements should be limited 
to new long-term power supply arrangements for new generation.
Using Long-Term Firm Transmission Rights to Grandfather Existing Uses
    295. A number of commenters address the issue of whether or not 
historical uses of the transmission system should be given priority for 
granting long-term firm transmission rights.\103\ FirstEnergy states 
that the Commission's proposal is a reasonable response to the 
legislative mandate so long as ``a preference'' means that current 
supply arrangements are given a priority over past or historical supply 
patterns no longer in place. Coral Power states that the guidelines are 
not being proposed against a clean slate, noting that many ISOs have 
already established grandfathered arrangements. Coral Power is 
concerned that a preference could be used to needlessly expand 
grandfather rights that were allocated to electric utilities when the 
RTO/ISOs were formed.
---------------------------------------------------------------------------

    \103\ See, e.g., FirstEnergy, Coral Power, NYAPP, NRECA, PJM, 
Santa Clara, Redding and Suez Energy.
---------------------------------------------------------------------------

    296. PJM states that, while it believes it is fair to establish a 
historical load/long-term firm transmission rights preference, it also 
recognizes the need to create a process to accommodate new long-term 
rights to cover load growth and new long-term contracts. PJM notes that 
its long-term firm transmission right proposal will address these 
issues.
Eligibility Issues
    297. A number of commenters offer recommendations with respect to 
the rules for determining which entities should be eligible to receive 
priority in the allocation of long-term firm transmission rights.\104\ 
For example, Manitoba Hydro submits that the Commission should ensure 
that the guidelines provide that if a market participant other than a 
load serving entity has a contractual obligation to a load serving 
entity to provide transmission rights and to take associated congestion 
risk, it should have priority to long-term transmission rights in the 
same manner as would the load serving entity.
---------------------------------------------------------------------------

    \104\ See, e.g., Manitoba Hydro, Coral Power, CMUA, ISO-NE, New 
England Public Systems, PPM Energy, Midwest ISO, NRECA, IPL, PJM and 
LIPA.
---------------------------------------------------------------------------

    298. ISO-NE contends that generators may need these firm 
transmission rights as much as load serving entities, because 
generators' bilateral contracts with load can place the congestion risk 
on the generator. In reply, New England Public Systems states that if 
load serving entities with service obligations and long-term power 
supply arrangements are given a priority in obtaining long-term firm 
transmission rights, contracts will be structured or restructured in 
order to place the congestion risk on the party that can most 
effectively hedge it. NRECA states that, if a load serving entity 
wishes to sell its long-term firm transmission rights for a period of 
years to a power supplier that is also the transmission customer, NRECA 
believes it should be able to do so.
    299. LIPA contends that the guidelines in proposed section 40.1(d) 
do not specifically incorporate the standards of FPA section 217(b)(4) 
or make clear that long-term firm transmission rights must be available 
to all market participants consistent with a transmission 
organization's individual market design. LIPA states that, while the 
availability of long-term firm transmission rights to all participants 
could be implied within the rule, and while certain guidelines address 
necessary elements of long-term firm transmission rights to promote use 
of such rights by load serving entities, the existing ambiguity can be 
removed by modification of the general rule.
    300. Some customers argue that the priority for long-term firm 
transmission rights should extend to customers that are outside the 
transmission organization's control area. E.ON claims that, as 
currently proposed, utilities that either do not belong to an RTO, or 
have no organized electricity market in which they can participate, 
cannot expect any priority in the allocation of long-term firm 
transmission rights into or out of an organized market. E.ON urges the 
Commission to consider granting priority to a load serving entity that 
satisfies the provisions of FPA section 217(a), either owns or has firm 
rights to the output of a capacity resource located within the 
boundaries of an adjacent RTO, and has acquired from that RTO 
transmission service necessary to deliver energy to the load serving 
entity's load located outside of the adjacent RTO. TANC states that 
long-term firm transmission rights should be provided first to entities 
with native load service obligations that contribute to the embedded 
cost of the transmission systems, including entities that may not be 
within the transmission organization's control area.
    301. Industrial Consumers argues that load serving entities in 
trust for loads, or loads directly, should be allocated short-term and 
long-term transmission rights on a pro rata basis as necessary to serve 
the total load. Alcoa states that priority also should be extended 
without discrimination to end users that act as their own load serving 
entities. CMUA adds that entities eligible in California for long-term 
firm transmission rights should include California's large state and 
local water agencies, which represent a significant portion of the 
state's energy usage, and are part of wholesale markets, but which do 
not serve retail load.
Retail Access Issues
    302. Many commenters claim that the proposed priority would 
undermine state-mandated retail access programs and harm competitive 
retail suppliers.\105\ Allegheny submits that the Commission should not 
create a situation in which load serving entities that participate in 
state-mandated supply procurement programs will be given a lower 
priority in long-term firm transmission right allocations. 
Constellation claims that the preference for longer-term supply 
resources would discriminate against competitive retail suppliers with 
service obligations in two respects. First, vertically integrated 
utilities with long-term resources could receive a priority with 
respect to capacity, blocking smaller retail providers from gaining 
access or entry to markets to compete effectively. Second, a preference 
for longer-term

[[Page 43596]]

firm transmission rights would discriminate against the shorter-term 
firm transmission rights that allow competitive retail providers with 
service obligations to more closely match shifts in their load, which, 
according to Constellation, can occur frequently, even daily.
---------------------------------------------------------------------------

    \105\ See, e.g., Allegheny, Cinergy, Constellation, Coral Power, 
Midwest ISO, Exelon, NARUC, OMS, Suez Energy, NEPOOL, National Grid, 
NU and NSTAR.
---------------------------------------------------------------------------

    303. Exelon notes that, in New Jersey and Illinois, the state 
commissions have determined that the public utilities should procure 
customers' requirements through a competitive auction procedure 
approved by the Commission. Exelon states that the rules of the auction 
preclude the utilities from entering into contracts of more than a few 
years' duration.
    304. Regarding the effect of long-term firm transmission rights on 
retail access, Redding, APPA and TAPS take a different view. APPA 
states that the desire of retail suppliers like Constellation and the 
members of EPSA for flexibility has to date prevented load serving 
entities in retail choice regions that wish to hedge transmission 
congestion associated with their long-term base load and renewable 
resources from doing so. APPA asserts that, while suppliers in retail 
choice areas may value flexibility, the associated short-term 
arrangements do not support the substantial new investments in 
generation needed to meet resource adequacy or fuel diversification 
needs. Similarly, TAPS states that is bad policy to force all load 
serving entities in all states to share that fate (i.e., denying all 
consumers the benefits of low cost energy) simply because some states 
may have concluded that is the right decision for those serving retail 
load within their state.
Obtaining Long-Term Firm Transmission Rights through Capacity 
Expansions
    305. Some commenters argue that the long-term needs of load serving 
entities should be met through the transmission organization's planning 
and expansion process, not by granting priority access to long-term 
firm transmission rights supported by existing capacity.\106\
---------------------------------------------------------------------------

    \106\ See, e.g., E.ON, Constellation, EPSA, NYISO and Strategic 
Energy.
---------------------------------------------------------------------------

    306. Constellation states that section 217(b)(4) requires the 
Commission to be proactive in ensuring that the needs of all load 
serving entities with a service obligation (regardless of the duration 
of that service obligation) are met through planning and expansion of 
transmission facilities and enabling load serving entities to secure 
firm transmission rights on a long-term basis, not to extend an undue 
preference for existing transmission capacity to load serving entities 
with long-term supply arrangements at the expense of other load serving 
entities with service obligations. NRECA agrees that the Commission 
does have an obligation under section 217 to facilitate transmission 
planning and expansion so as to support long-term power-supply and 
transmission arrangements. However, NRECA asserts that the Commission 
also has a specific duty to act in a manner that ``enables load serving 
entities to secure firm transmission rights * * * on a long-term basis 
for long-term power supply arrangements.''
Market, Efficiency and Gaming Issues
    307. A number of commenters argue that the proposed priority will 
impede the development of competitive markets and create inefficient 
economic incentives.\107\ For example, EEI states that long-term firm 
transmission right holders will have the incentive to resist 
infrastructure enhancements to the system that adversely affect the 
value of their long-term firm transmission rights. Also, SDG&E contends 
that, on transmission paths that are expected to have relatively higher 
levels of congestion, e.g., where the transmission rights are expected 
to be more valuable, an incentive is created to enter into long-term 
commodity transactions in order to secure the priority. According to 
SDG&E, such incentives are misplaced and could distort efficient 
contracting decisions. NYISO believes that rather than having an 
incentive to contract for the least cost resources to meet their load, 
load serving entities would have an incentive to enter into contracts 
on the ``wrong'' side of binding transmission constraints, because they 
would receive valuable transmission rights as a reward for executing 
such contracts.
---------------------------------------------------------------------------

    \107\ See, e.g., EEI, EPSA, Reliant, Exelon, Constellation, 
SDG&E, NYISO and Midwest ISO.
---------------------------------------------------------------------------

    308. Other commenters take the opposite view, arguing that the 
proposed priority would lead to more efficient investment decisions and 
lower costs in the long run.\108\ FirstEnergy states that the 
availability of long-term service is needed to facilitate investment in 
new generation capacity and transmission infrastructure.
---------------------------------------------------------------------------

    \108\ See, e.g., APPA, NYAPP, NRECA, DWR, CMUA, FirstEnergy and 
New England Public Systems.
---------------------------------------------------------------------------

    309. APPA argues that the primary role of long-term firm 
transmission rights would be to support base load and renewable 
generation resources needed to support load serving entity service 
obligations. Those resources are not sited based on whether they are on 
the ``right'' or ``wrong'' side of a constraint, but on a myriad of 
factors, including proximity to fuel sources, access to rail 
transportation and availability of renewable resources (e.g., wind or 
geothermal). APPA states that the failure of RTOs to offer long-term 
firm transmission rights is stifling investment in base load and 
renewable generation resources, and in the associated transmission 
facilities needed to bring these resources to loads.
    310. Several commenters express concern that the proposed priority 
would create an incentive for load serving entities to acquire excess 
long-term firm transmission rights in order to sell the excess at a 
profit, and could lead parties to enter into ``sham'' contracts.\109\
---------------------------------------------------------------------------

    \109\ See, e.g., ISO-NE, Midwest ISO, NYISO, Coral Power, APPA 
and CPUC.
---------------------------------------------------------------------------

    311. ISO-NE contends that a direct, costless allocation of LT-firm 
transmission rights, or an auction in which only load serving entities 
may purchase LT-firm transmission rights, would amount to a wealth 
transfer to the load serving entities at the expense of other market 
participants. According to ISO-NE, this is because the load serving 
entities would acquire the LT-firm transmission rights at a price below 
their value and have every incentive to resell them on the secondary 
market for a profit. Midwest ISO states that this guideline may give 
parties an incentive to enter into ``sham'' contracts intended to 
accomplish nothing but establishing rights to valuable long-term firm 
transmission rights.
    312. Ameren believes that the concern that load serving entities 
will nominate excessive amounts of long-term firm transmission rights 
is easily addressed by limiting the amount of long-term firm 
transmission rights allocable to a load serving entity based on its 
expected load, including load growth, during the upcoming year and 
using state regulatory processes to police nominations. APPA states 
that the RTO can take the matter up with the load serving entity on a 
case-by-case basis if it believes that the long-term firm transmission 
right allocation of the load serving entity does not appropriately 
reflect load growth.
    313. PG&E notes that the EPAct 2005's focus on the ``long-term 
service obligation,'' its predication of the threshold amount of 
Transmission Rights on those ``power supply arrangements'' that 
constitute ``reasonable needs,'' as well as the EPAct 2005's provisions 
for shifting long-term Transmission Rights in

[[Page 43597]]

parallel with load migration, provides ample opportunity for protection 
against ``sham contracts'' and the possibility of windfall to load 
serving entities, so long as the statutory terms are well defined. APPA 
states that it and its members are willing to agree to reasonable 
limitations on long-term firm transmission rights, including 
restrictions on resale and requirements that holders actually have 
generation resource arrangements covering the specified sources and 
sinks, to avoid creating such perverse financial incentives. Also, New 
England Public Systems notes that TAPS has proposed dispatch-contingent 
option long-term firm transmission rights that only generate a payment 
to the load serving entity when the resource at issue is run and do not 
require payment by the load serving entity when congestion is reversed. 
Alternatively, New England Public Systems states that long-term firm 
transmission right settlements could be subject to true up at year end 
based on actual load levels.
Allowing for Load Growth in Long-Term Firm Transmission Rights and the 
Need for Accurate Load Forecasts
    314. Some commenters argue that priority in the allocation of long-
term firm transmission rights should extend to provisions for load 
growth and unforeseen changes in the need for long-term rights.\110\ 
Public Power Council argues that the preference should require RTOs and 
ISOs to set aside future rights for the load growth of these entities 
and the Commission should ensure that the transmission system is 
planned and expanded to accommodate growth.
---------------------------------------------------------------------------

    \110\ See, e.g., Public Power Council, Allegheny, AEP, 
Industrial Consumers, PJM Public Power Coalition, Alcoa and 
FirstEnergy.
---------------------------------------------------------------------------

    315. Allegheny argues that incremental firm transmission rights to 
cover increases in generation capacity resources, load growth or other 
factors should also be granted as part of the long-term firm 
transmission right allocation process, but only to the extent that the 
underlying transmission system can support the feasibility of such 
additional firm transmission rights. AEP believes it is inappropriate 
for auction revenue right allocations to be locked into a configuration 
that may bear no resemblance in year 10 to the simultaneous feasibility 
tests run in year one. Industrial Consumers believes that the load 
serving entity or a load that is serving itself should have access to 
additional capacity rights for unforeseen load growth, and similarly, 
the load serving entity or load serving itself should be required to 
surrender that portion of its rights for the amount of any permanent 
load reduction.
    316. PJM Public Power Coalition argues that if, during the roll-
over term of the long-term transmission rights, a load serving entity's 
load is reduced below the level of its long-term transmission rights, 
that entity's roll-over right should be reduced to its then current 
load level, so that the entity does not have priority to transmission 
capacity it will not use to serve its load.
Administrative Burden
    317. Midwest ISO states that the Commission's requirement that 
transmission organizations provide load serving entities priority to 
existing transmission capacity is problematic for several reasons. 
First, transmission organizations will have to undertake extensive, 
burdensome, and costly administrative processes in order to evaluate 
contracts to determine whether they satisfy the criteria applicable and 
ensure that the power supply contracts are in fact necessary to serve 
load and are long-term. Midwest ISO argues that the transmission 
organizations should not be placed in the position of evaluating long-
term contracts to ensure they legitimately qualify for priority of the 
transmission capacity. In response, APPA notes that many Regional 
Reliability Councils have long undertaken auditing of load serving 
entity power supply portfolios to determine if their regions have 
adequate generation resources. APPA claims that the term of power 
supply agreements is usually relatively easy to ascertain, and annual 
reporting by the load serving entities on their generation resource 
portfolios, plus oversight and investigation by the RTO's Market 
Monitor if gaming is suspected, should be sufficient to keep load 
serving entities honest. APPA also notes that, under section 30 of the 
Order No. 888 OATT, Network Customers have to designate new resources 
by providing the required information to the Transmission Provider. 
Hence, in APPA's view, Network Customers are accustomed to having to 
verify their claimed generation resources.
Commission Conclusion
    318. We will adopt guideline (5) with revisions to eliminate the 
preference for load serving entities with long-term power supply 
arrangements and replace it with a general preference for load serving 
entities vis-a-vis non-load serving entities. Also, as discussed below, 
we will revise guideline (5) to allow the transmission organization to 
place reasonable limits on the amount of existing transmission capacity 
that it will make available for long-term firm transmission rights.
    319. Although we believe section 217(b)(4) of the FPA would support 
a preference for load serving entities with long-term power supply 
arrangements, we agree with those commenters, such as SDG&E, that claim 
that EPAct 2005 should not be construed to require that a preference be 
given to this class of load serving entities at the expense of load 
serving entities that prefer short-term power supply arrangements. In 
our view, a broader preference for load serving entities in general 
vis-a-vis non-load serving entities is fully supported by the statute 
and indeed better meets the needs of today's organized electricity 
markets.
    320. The overall thrust of new section 217 of the FPA, read in its 
entirety, is the protection of transmission rights used to satisfy 
native load service obligations.\111\ Given the reality that 
transmission capacity is limited, and that the amount that can 
reasonably be made available for long-term transmission rights may be 
lesser still, we believe that section 217 of the FPA provides a general 
``due'' preference for load serving entities to obtain long-term firm 
transmission service. Moreover, section 217(d), which provides that the 
Commission may make transmission rights that are not used to meet a 
load serving entity's service available to other entities, strongly 
indicates that Congress intended for load serving entities to be 
``first in line'' for long-term transmission rights that are made 
available.
---------------------------------------------------------------------------

    \111\ As noted above, 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).
---------------------------------------------------------------------------

    321. An important advantage of revising guideline (5) in this 
manner is that, in most cases, the transmission organization will be 
able to apply the same basic principles for allocating long-term firm 
transmission rights that it currently uses for the initial allocation 
of short-term firm transmission rights, or auction revenue rights. To 
explain, we note that most transmission organizations now use 
straightforward methods to allocate firm transmission rights (or 
auction revenue rights) annually to all load serving entities that 
support the embedded costs of the transmission system. Some of these 
methods take explicit account of the load serving entity's current or 
historical power supply arrangements in determining its allocation 
priority. However, as revised, guideline (5)

[[Page 43598]]

neither requires nor prohibits the consideration of power supply 
arrangements in determining this priority. Guideline (5), as revised, 
only requires that load serving entities have priority over non-load 
serving entities in the allocation of long-term firm transmission 
rights. This means that, in most cases, load serving entities can 
continue to receive the same allocation of firm transmission rights (or 
auction revenue rights) that they have received in the past. In 
addition, by eliminating from guideline (5) the priority for load 
serving entities with long-term power supply arrangements, we are 
making it possible for the transmission organization to propose an 
allocation method that eliminates any obligation on the part of either 
the transmission organization or the load serving entity to demonstrate 
or verify that the load serving entity holds a qualifying long-term 
power supply arrangement.
    322. In addition, revising the guideline in this manner effectively 
addresses the objections of most commenters that oppose guideline (5) 
as proposed in the NOPR. Importantly, it largely eliminates the 
potential for load serving entities that prefer short-term power supply 
arrangements, or are precluded from entering into long-term 
arrangements, to be disadvantaged in the allocation of firm 
transmission rights. In particular, load serving entities in retail 
access states can continue to receive and use their allocated firm 
transmission rights as short-term instruments, if that best suits their 
business model. Also, load serving entities that prefer short-term firm 
transmission rights (or are limited to them by law) will not feel 
compelled to request long-term firm transmission rights (or enter into 
sham contracts) out of fear that they might otherwise lose out in the 
firm transmission right allocation process. We do not believe that 
Congress intended these results when it enacted section 217 of the FPA, 
particularly given the statute's overall focus on protecting the 
transmission rights of load serving entities with service obligations. 
Finally, the transmission organization will not face the administrative 
burden of having to evaluate power supply contracts to determine if 
they qualify for the preference.
    323. In the NOPR, we asked for comments on whether section 1233 of 
EPAct 2005 and new section 217(b)(4) of the FPA support placing 
reasonable limits on the award of long-term rights. Because of 
uncertainty regarding load growth, changes in power flows and other 
factors, the Commission expects that the transmission organization may 
be reluctant to commit all of its existing capacity to long-term firm 
transmission rights, especially in light of guideline (2)'s full 
funding requirement. Also, commenters claim that the principal need for 
long-term firm transmission rights is to support long-term power supply 
arrangements only for base load generation, not peaking or intermediate 
generation. Therefore, we conclude that the transmission organization 
and its stakeholders should be given flexibility to determine the level 
at which a load serving entity may nominate long-term firm transmission 
rights as long as that level does not fall below the ``reasonable 
needs'' of the load serving entity. This level can be expressed in a 
variety of ways, for example as a straightforward measure of load, such 
as minimum daily peak load or 50 percent of maximum daily peak load. In 
this regard, we note that some commenters argue that the allocation of 
long-term firm transmission rights should include provisions for load 
growth, to include the loss of long-term firm transmission rights when 
load declines. Rather than specify an approach here, we will provide 
the transmission organization and its stakeholders with flexibility to 
propose an approach for incorporating load growth in the allocation 
process, if it is incorporated at all.
    324. The Commission emphasizes that revising guideline (5) in this 
manner should not significantly reduce the access to long-term firm 
transmission rights that a load serving entity with long-term power 
supply arrangements would have had under guideline (5) as originally 
proposed. Under that proposal, load serving entities with power supply 
arrangements of more than one year (per our proposed definition of 
long-term power supply arrangements) would have qualified for an 
allocation preference; our revision only expands the preference to 
include load serving entities that have power supply arrangements of 
less than one year. Moreover, most supporters of proposed guideline (5) 
agree that a transmission organization will have valid reasons to place 
a limit on the amount of system capacity that it makes available to 
support long-term firm transmission rights. Also, most of the 
commenters that support guideline (5) as proposed do not include among 
the reasons for their support the need to link the award of long-term 
firm transmission rights to long-term power supply arrangements. 
Rather, their comments are principally directed against any notion that 
load serving entities with short-term firm transmission rights should 
receive special consideration in the allocation process. Finally, the 
other guidelines adopted here ensure that the long-term firm 
transmission rights will support long-term power supply arrangements, 
as Congress intended.
    325. Our decision to make explicit the transmission organization's 
right to propose reasonable limits on the amount of capacity made 
available for long-term firm transmission rights, as well as to provide 
the more limited preference that we are adopting in the Final Rule, 
requires that we revise guideline (5) to read as follows:

    Guideline (5): Load serving entities must have priority over 
non-load serving entities in the allocation of long-term firm 
transmission rights that are supported by existing transmission 
capacity. The transmission organization may propose reasonable 
limits on the amount of existing transmission capacity used to 
support long-term firm transmission rights.

    326. Commenters such as Manitoba Hydro and ISO-NE argue that the 
preference should extend to certain entities that do not meet the 
strict definition of load serving entity, such as generators that have 
a contractual obligation to a load serving entity.\112\ The Commission 
disagrees. Extending the preference to entities that do not meet the 
definition of load serving entity, as clarified in this Final Rule, 
would likely defeat the purpose of providing the preference. Once load 
serving entities have received their allocated firm transmission 
rights, those firm transmission rights and any additional firm 
transmission rights available from remaining system capacity can be 
offered to non-load serving entities (as well as other load serving 
entities) through a secondary auction, bilateral trades or another 
method of allocation. This is consistent with section 217(d) of the 
FPA. Also, as noted by New England Public Systems, a load serving 
entity that has a contractual arrangement with a generator or other 
entity that allocates congestion risk in a particular way can structure 
its contract with that entity as necessary to achieve the desired risk 
sharing.
---------------------------------------------------------------------------

    \112\ See also our discussion of the definition of load serving 
entity in section II.A. above.
---------------------------------------------------------------------------

    327. Industrial Consumers, Alcoa and CMUA state that certain end 
users should receive the preference provided by guideline (5). As we 
stated above in our clarification of the definition of load serving 
entity, any end user, such as an industrial consumer or a large water 
agency, that is allowed under state law and regulation to participate 
in wholesale markets as a power purchaser

[[Page 43599]]

should be construed as a load serving entity under the Final Rule and, 
accordingly, should receive all of the rights and obligations of a load 
serving entity.
    328. E.ON asks that a load serving entity outside of a transmission 
organization's boundaries be given priority, under certain conditions, 
to long-term firm transmission rights on the transmission 
organization's transmission system. On this matter, the Commission 
agrees with TANC that long-term firm transmission rights should be made 
available first to those entities that have an obligation to serve load 
within the transmission organization's service territory and are 
required to contribute to the embedded cost of the transmission 
organization's transmission system. Any entity that has neither an 
obligation to serve load on the transmission organization's 
transmission system, nor an obligation to pay the embedded costs of 
that system, should not be given a preference to acquire long-term firm 
transmission rights supported by the system's existing capacity.
    329. LIPA states that the proposed guidelines do not specifically 
incorporate the standards of FPA section 217(b)(4), or make clear that 
long-term firm transmission rights must be available to all market 
participants, and therefore should be revised. We do not believe that 
any revision is necessary. The guidelines, taken as a whole, are 
designed to implement the relevant requirements of EPAct 2005, 
including the provisions of FPA section 217(b)(4). We believe that the 
guidelines as revised in this Final Rule provide the clarity that LIPA 
seeks. Further, we have made clear both in the NOPR and in this Final 
Rule that long-term firm transmission rights must be available to all 
market participants; this guideline serves only as a ``tiebreaker'' 
between load serving entities and non-load serving entities when 
existing transmission capacity is limited.
    330. Finally, we note that several commenters express concern that 
the preference as proposed in guideline (5) will lead market 
participants to resist infrastructure enhancements, enter into sham 
contracts, or make inefficient investment decisions. We conclude that, 
by eliminating the priority for load serving entities with long-term 
power supply arrangements, and by allowing limits to be placed on the 
amount of capacity available for long-term firm transmission rights, 
the Final Rule should virtually eliminate any incentive that a load 
serving entity might otherwise have to hoard long-term firm 
transmission rights, enter into sham agreements or resort to other 
types of gaming and inefficient decision-making. Indeed, the Commission 
agrees with APPA that a likely greater source of inefficiency is the 
unavailability of long-term firm transmission rights in organized 
electricity markets, which may be impeding needed investments in 
generation resources and transmission upgrades. Nevertheless, if a 
transmission organization and its stakeholders conclude that additional 
steps must be taken to avert such problems, the transmission 
organization may propose appropriate measures as part of its compliance 
filing.
Guideline (6)--Rights are Reassignable to Follow Load
    331. As proposed in the NOPR, guideline (6) stated that a long-term 
transmission right held by a load serving entity to support a service 
obligation should be re-assignable to another entity that acquires that 
service obligation. The NOPR stated that a successor load serving 
entity should assume any cost responsibility that holding the long-term 
transmission right entails. We stated that this proposal is consistent 
with section 217(b)(3)(A) of the FPA, which requires that transmission 
rights held by a load serving entity as of the date of enactment of 
EPAct 2005 for the purpose of delivering energy it has purchased or 
generated to meet a service obligation be transferred to a successor 
load serving entity. The NOPR noted that the short-term transmission 
rights currently offered by transmission organizations are generally 
reassignable to successor load serving entities. The NOPR also noted 
that a transfer of a service obligation might occur pursuant to a state 
commission order, or might occur in a state with retail competition if 
load chooses a new supplier.
    332. The NOPR asked for comments regarding whether reassignability 
should apply to all long-term firm transmission rights, regardless of 
how those rights were obtained, and whether a holder of long-term 
rights should receive compensation when its rights are reassigned.
    333. Also, the NOPR noted that section 217(b)(4) of the FPA does 
not discuss whether long-term firm transmission rights should be fully 
tradable among market participants. We stated that allowing such rights 
to be fully tradable could raise issues of equity, since a load serving 
entity that acquired the rights through a preference could then 
possibly sell or trade the rights at a profit. This might give load 
serving entities the incentive to acquire excess long-term firm 
transmission rights in order to take advantage of profit opportunities. 
However, the NOPR noted that full tradability may bring benefits to the 
market, and allow those that could not obtain long-term rights in the 
initial allocation to obtain such rights later. The NOPR asked for 
comments on these issues.
Comments
General Support for Guideline (6)
    334. Many commenters express strong support for proposed guideline 
(6).\113\ AEP states that a transmission right to support a service 
obligation should stay with the load and, therefore, be re-assignable 
to another entity that may acquire the service obligation. APPA 
supports guideline (6) and states that such assignability should be 
required regardless of how those rights were obtained.
---------------------------------------------------------------------------

    \113\ See, e.g., PJM, NRECA, CMUA, Santa Clara, Xcel, Allegheny, 
Public Power Council, AEP, APPA, AF&PA, Minnesota Power, BPA, 
Strategic Energy, Coral Power and PJM Public Power Coalition.
---------------------------------------------------------------------------

    335. Cinergy supports the adoption of guideline (6) in principle 
because it believes that market liquidity provides for more efficient 
economic outcomes and that the problems associated with other 
guidelines may be mitigated to some degree by directing that long-term 
transmission rights be re-assignable. BPA states that this policy 
should accommodate other open access policies where the long-term 
transmission rights of the original load serving entity would transfer 
(1) to other load serving entities that successfully compete to serve 
loads under state retail access programs, or (2) to wholesale power 
suppliers that successfully compete to meet load serving entity service 
obligations.
Need for Flexibility
    336. Some commenters urge the Commission to permit flexibility in 
the way transmission organizations implement this guideline. Reliant 
states that the Commission should permit organized electricity markets 
and their stakeholders to best determine the reassignment of long-term 
transmission rights. EEI states that flexibility is important in the 
application of this guideline because it will present administrative 
burdens with respect to tracking reassignments on a frequent basis. 
CMUA states that, given the different retail choice regimes in 
different regions, or the lack of retail choice in some, implementation 
is best left to the relevant regions.

[[Page 43600]]

Should Reassignment be Optional or Mandatory?
    337. NYISO states that this proposal is reasonable provided that 
the rights may be reassigned, not that they automatically be 
reassigned, at least in the case of transmission organizations with 
grandfathered auction based systems under FPA section 217(b) (3). 
Similarly, Xcel states that reassignment itself must not be mandated; 
the reassignment should be at the option of the holder of the right and 
the entity to which the service obligation transfers. PJM Public Power 
Coalition states that because these long-term rights can become a 
liability under certain circumstances, entities should be able to 
trade, transfer, or decline to exercise the rights.
    338. Suez Energy states that guideline (6) might be interpreted in 
a way that destroys retail competition because incumbents might argue 
that long-term firm transmission rights are merely re-assignable at the 
choice of the incumbent supplier, and that the incumbent should be 
allowed to retain valuable long-term firm transmission rights for 
existing network service. Conversely, Suez Energy is concerned that an 
incumbent supplier that invested badly could argue that the financial 
burden of a now burdensome investment in transmission infrastructure is 
reassignable to a new supplier.
    339. ISO-NE believes that the Commission should examine proposals 
for mandatory re-assignment carefully where the load serving entity 
picking up the service obligation has a different set of long-term 
supply arrangements that may not correspond with the path for the 
existing long-term firm transmission right, or if the successor load 
serving entity may not wish to utilize a long-term supply strategy at 
all.
Rules Governing Reassignment
    340. Several commenters offered proposals for rules that would 
govern the reassignment of long-term firm transmission rights in 
specific instances.\114\ The CAISO asks the Commission to clarify 
guideline (6) to state that the transmission organization should adopt 
provisions to require that either allocated long-term firm transmission 
rights or their equivalent financial value be transferred from one load 
serving entity to another to reflect transfers of load serving 
obligation. The CAISO believes that by allowing load serving entities 
to transfer the financial value of long-term firm transmission rights 
when their load serving obligation migrates, instead of insisting on 
the transfer of the actual long-term firm transmission rights, the 
underlying principle that the allocated long-term firm transmission 
rights are the property of the end-use customers can be maintained 
without precluding the trading of allocated long-term firm transmission 
rights by load serving entities.
---------------------------------------------------------------------------

    \114\ See, e.g., CAISO, SoCal Edison, PG&E, APPA, Redding, CMUA, 
Strategic Energy, Midwest ISO, SDG&E, BPA, TAPS and Alcoa.
---------------------------------------------------------------------------

    341. SoCal Edison recommends that the only circumstances in which 
long-term rights should be reassigned are if: (1) The original right 
was allocated (i.e. any rights purchased bilaterally or in an auction 
would not be transferred regardless of any load migration); and (2) the 
load-gaining entity has the ability to utilize the same source/sink 
pair that was used to allocate the long-term right to the load-losing 
entity; and (3) the load losing entity can no longer use the entire 
long-term transmission right for the output/load upon which the long-
term right was initially awarded to the load-losing entity. PG&E agrees 
that no transfer should occur until such time as a load serving 
entity's remaining service obligation is less than the megawatt 
quantity of its long-term firm transmission rights. Also, PG&E believes 
that the statutory intent to link long-term transmission rights to 
long-term power supply arrangements would be realized if transmission 
rights or equivalent payments are made only to those load serving 
entities that gain long-term service obligations and that also obtain 
commensurate long-term power supply arrangements. However, APPA claims 
that SoCal Edison's condition (2) seems unnecessarily stringent and 
asserts that, if the transmission organization can reconfigure the 
long-term firm transmission rights at the time of transfer, then this 
should be permitted.
    342. Redding contends that when the Commission raises the issue of 
assignability it implicitly raises the question of portfolio strategy. 
Redding argues that, if the load serving entity has long-term 
transmission rights and long-term supply arrangements that were not 
utilized to serve the customer with retail choice, then the customer's 
decision to change providers should not result in the reassignment of a 
long-term transmission right. Redding contends that there would be an 
argument for transfer of the transmission right only if the customer 
can demonstrate that it either directly or indirectly had a liability 
that transferred to the new provider or remained with the customer.
    343. Midwest ISO states that the entity that acquires the service 
obligation may not want the particular long-term firm transmission 
right, but may prefer a different firm transmission right with a source 
that matches the supply portfolio of the new load serving entity. 
Moreover, the firm transmission right may have negative value and the 
new load serving entity may not want it at all. To the extent the 
Commission permits such re-assignment, Midwest ISO recommends that 
reasonable restrictions be imposed. For example, Midwest ISO states 
that the Final Rule should limit the impact of this issue by (1) 
limiting the amount of long-term firm transmission rights to a small 
proportion of load serving entity's load, and (2) limiting the term of 
the firm transmission right. In response, APPA states that it prefers 
its proposed suggestions of minimum hold times, minimum periods for any 
resale, or a requirement that the new holders have generation resources 
and loads for the points specified in the long-term firm transmission 
rights, or the Commission's suggestion that long-term firm transmission 
right holders only be able to return their long-term firm transmission 
rights to the transmission organization.
    344. SDG&E states that any reassignment mechanism that links 
specific long-term firm transmission rights to individual loads will 
become administratively burdensome if the switching of load between 
load serving entities is active, with the transmission organization 
potentially forced to track thousands of long-term firm transmission 
rights that are reduced to fractions of megawatts.
    345. Alcoa states that an end user that acts as its own load 
serving entity must be afforded the same opportunity as a load serving 
entity to reassign its long-term transmission rights to another entity 
that acquires a service obligation for its load.
Compensation Issues
    346. Some commenters provided recommendations concerning what, if 
any, compensation should be paid when a long-term firm transmission 
right is reassigned to a successor load serving entity.\115\ APPA 
states that compensation is a matter to be dealt with by the transferee 
and transferor load serving entities. BPA states that all of the costs 
and liabilities associated with the transferred rights should follow to 
the new load serving entity. However, BPA recommends that limitations 
on re-assignment, particularly issues relating

[[Page 43601]]

to compensation pricing policy, be left to the regions to resolve.
---------------------------------------------------------------------------

    \115\ See, e.g., APPA, Allegheny, BPA, CAISO, Ameren, AF&PA, 
Santa Clara, Cinergy and OMS.
---------------------------------------------------------------------------

    347. The CAISO submits that the load serving entity that has lost a 
portion of its service obligation should not be compensated for any 
long-term firm transmission rights it transferred to another load 
serving entity for that load. AF&PA states that, if long-term firm 
transmission rights are paid for by the holder at fair market value, 
they should be property of the holder, and should be assignable by the 
holder for value or otherwise in its discretion. Ameren recommends that 
there be no compensation for firm transmission rights returned to the 
transmission organization by a load serving entity. Santa Clara states 
that if the holder is carrying the risk that the congestion cost could 
increase and create more value or decrease and make it less valuable, 
the holder should not be forced to return the rights at the cost at 
which they were allocated to them.
Trading
    348. A number of comments focused on the question of whether or not 
long-term firm transmission rights should be tradable.\116\ AEP 
supports the concept of trading long-term transmission rights as an 
appropriate way to facilitate risk management by load serving entities. 
TANC argues that, if after meeting its native load obligations an 
entity has surplus transmission rights, the market is enhanced by the 
availability of such surplus rights. Cinergy believes that long-term 
transmission rights acquired under FPA section 217(b)(4) should be 
fully tradable. Also, Cinergy encourages the Commission to allow market 
participants that acquire long-term transmission rights by investing in 
transmission upgrades to trade those rights for a profit, as that 
provides even greater incentive to build transmission improvements.
---------------------------------------------------------------------------

    \116\ See, e.g., AEP, Midwest ISO, TANC, Cinergy, SMUD, NRECA, 
OMS, Ameren, PG&E, Allegheny, IPL and Public Power Council.
---------------------------------------------------------------------------

    349. In SMUD's view, giving customers the right to assign their 
unused physical transmission rights temporarily will reduce the 
likelihood of hoarding and will serve as a congestion management tool. 
In NRECA's view, allowing long-term rights to be tradable would allow 
load serving entities a way to reconfigure their portfolios of long-
term firm transmission rights as their situations change.
    350. Ameren states that making long-term firm transmission rights 
fully tradable among market participants would enhance the efficiency 
of the congestion management program, as it would enable the firm 
transmission rights to go to those parties that value them most highly. 
It also would allow entities that are not load serving entities to 
obtain long-term firm transmission rights, assuming they value them 
highly enough to win them in the market.
    351. PG&E states that, because shifts in service obligations may be 
temporary and may be reversed, reassignment of long-term firm 
transmission rights with shifts in service obligations and power supply 
arrangements should be conditioned on assurances that future shifts of 
such service obligations and power supply arrangements are accompanied 
by a return of the accompanying long-term firm transmission right. PG&E 
argues that, while it would be appropriate to allow trading or transfer 
of the long-term firm transmission right for interim periods, the long-
term firm transmission right itself should remain attached to the 
service obligation and not be separately transferable.
    352. IPL argues that there should not be a requirement that long-
term rights are tradable, and recommends that the Commission allow the 
transmission organizations flexibility to specify the general terms of 
reassignments related to load shifts. Public Power Council claims that 
making the rights fully tradable raises fairness questions if the 
seller received a preference due to the use of the right to meet a 
service obligation and the buyer did not. If the rights were sold to 
another load serving entity for the purpose of meeting that other 
entity's service obligations, however, Public Power Council believes 
that the fairness issue would be avoided.
Gaming and Arbitrage
    353. A number of commenters express concern that, if the long-term 
firm transmission rights are reassignable and tradable, a load serving 
entity might have an incentive to acquire excess long-term firm 
transmission rights for financial gain.\117\ EPSA states that it would 
be inappropriate for the Commission to allow utilities to profit from 
the sale of any long-term firm transmission rights that are obtained 
via a preferential priority. EPSA claims that vertically-integrated 
utilities with long-term contracts could hoard long-term firm 
transmission rights, blocking smaller retail providers from gaining 
access or entry to markets and competing effectively.
---------------------------------------------------------------------------

    \117\ See, e.g., EPSA, Santa Clara, OMS, Ameren, APPA, CMUA, 
Minnesota Power, Cinergy and TAPS.
---------------------------------------------------------------------------

    354. Ameren claims that concerns about possible arbitrage are 
addressed by its proposal to place a limitation on firm transmission 
right nominations based on a load serving entity's load. APPA 
recommends that load serving entities holding long-term firm 
transmission rights must have in their generation portfolios actual 
resources (owned or contracted for) and loads corresponding to the 
receipt and delivery points that the long-term firm transmission rights 
cover. APPA also suggests restrictions on the resale of long-term firm 
transmission rights in the form of minimum hold periods and minimum 
periods for resale of any right. However, APPA states that any such 
restrictions would have to be balanced against the need to ``recycle'' 
long-term firm transmission rights to ensure the most efficient use of 
the transmission rights. APPA states that a reasonable approach would 
be the Commission's suggestion that holders of long-term firm 
transmission rights be permitted only to return their long-term firm 
transmission rights to the RTO, and not to earn any profit on their 
direct sale to another market participant. TAPS claims that its 
recommended dispatch-contingent firm transmission rights would have 
very limited appeal for market participants interested in firm 
transmission right speculation.
    355. Minnesota Power urges the Commission not to allow creation of 
a large secondary market in which market participants are able to 
inflate the price of long-term transmission rights or to use the long-
term transmission rights as an economic position in the market. 
Minnesota Power suggests that the long-term transmission rights should 
be directly linked to, and tradable only with, the underlying 
generation rights or long-term purchase rights.
Commission Conclusion
    356. The Commission will adopt guideline (6) as proposed in the 
NOPR, but will provide transmission organizations and their 
stakeholders with flexibility to determine specific rules for 
reassignment of long-term firm transmission rights. We note that most, 
if not all, transmission organizations now have rules governing the 
reassignment of firm transmission rights when load migrates from one 
load serving entity to another. The introduction of long-term firm 
transmission rights should not in itself require a change in the basic 
structure of these rules. In at least some transmission organizations, 
reassignment is achieved through a

[[Page 43602]]

reallocation of auction revenue rights, with a provision to allow the 
auction revenue rights to be converted into firm transmission rights.
    357. In general, the issue of reassignment should arise only in the 
context of firm transmission rights (short-term or long-term) that are 
allocated preferentially to a load serving entity in accordance with 
guideline (5). If a load serving entity acquires firm transmission 
rights through an auction or as a result of funding a transmission 
upgrade, it should not be required to reassign such rights because any 
entity is free to acquire firm transmission rights in this manner. 
Also, a load serving entity that acquires long-term firm transmission 
rights to support the financing of a new generating facility should 
not, in general, be required to give up those rights simply because 
some of its load migrates to another load serving entity. However, a 
possible exception may arise if the original load serving entity were 
to lose so much of its load that the total of its long-term firm 
transmission rights exceeds its remaining load. In this case, as noted 
by PG&E, some mandatory reassignment may be justified.
    358. The Commission believes that all long-term firm transmission 
rights should be tradable. Allowing tradability provides the load 
serving entity with flexibility to manage its transmission rights 
portfolio and helps to ensure that long-term firm transmission rights 
go to the market participants that value them most highly. 
Reassignments may be temporary. However, long-term firm transmission 
rights that the load serving entity obtains preferentially through an 
allocation process should be tradable only with the proviso that any 
trades may be subject to recall if load migrates to another load 
serving entity. Making the long-term firm transmission rights subject 
to recall ensures that they can be reassigned if necessary to follow 
migrating load, consistent with section 217(b)(3)(A) of the FPA. We 
note, however, in a transmission organization where reassignment is 
accomplished through a reallocation of auction revenue rights, rather 
than the firm transmission rights themselves, there may be no need for 
such a proviso. In this case, reassignment would be accomplished 
through a financial transfer, allowing the actual long-term firm 
transmission rights to remain with the original load serving entity. 
This should satisfy the CAISO's request that the Commission permit 
either the allocated long-term firm transmission rights or their 
equivalent financial value to be transferred from one load serving 
entity to another to reflect a transfer of load serving obligation. In 
addition, allocating auction revenue rights would also eliminate any 
need to place restrictions on reassignments, such as requiring the 
successor load serving entity to hold a supply contract that uses the 
same source/sink pair used by the original load serving entity.
    359. Also, when reassignment of auction revenue rights or firm 
transmission rights is mandated due to a shift in load serving 
responsibility, any cost responsibilities associated with the holding 
of such rights, such as payment of transmission access charges, should 
shift from the original load serving entity to the successor load 
serving entity. No other compensation should be required. Again, the 
specific rules for accomplishing this should be left to the 
transmission organization and its stakeholders. With regard to firm 
transmission rights or long-term firm transmission rights that are 
acquired by auction or as a result of funding a transmission upgrade, 
the Commission believes (as noted above) that in general there should 
be no restrictions on trading such rights. Transfers should be 
permitted to occur at prices negotiated by the buyer and seller.
    360. In response to Alcoa, the Commission notes that an end user 
that is permitted under state law to participate in wholesale markets 
may acquire, trade and reassign long-term firm transmission rights in 
accordance with guideline (6) in the same manner as other load serving 
entities, as discussed above under guideline (5).
Guideline (7)--Auction Not Required
    361. As proposed in the NOPR, guideline (7) stated that the initial 
allocation of the long-term firm transmission rights shall not require 
recipients to participate in an auction. The Commission noted that, 
currently, most transmission organizations either allocate transmission 
rights directly to eligible parties, or allocate auction revenue rights 
directly and then conduct a transmission rights auction in which 
parties with and without allocated rights can participate. If an 
auction model is adopted or continued by the transmission organization, 
the Commission proposed to require that any long-term rights allocated 
as auction revenue rights be capable of being directly converted to 
transmission rights without participation in the auction. This was to 
allow any party that feels uncertain about valuing its rights 
commercially to have them allocated directly. This guideline did not 
preclude interested parties with long-term rights from participating in 
the auction if they choose.
Comments
General Support for Guideline (7)
    362. Many commenters express strong support for proposed guideline 
(7).\118\ For example, APPA states that the long-term firm transmission 
right allocation called for under guideline (7) is appropriate because 
it comports with section 217(b)(4) of EPAct 2005. Also, APPA believes 
that it at least partially restores the transmission rights that APPA 
members in transmission organization regions lost when full LMP-based 
markets were implemented.
---------------------------------------------------------------------------

    \118\ See, e.g., Xcel, PJM, TAPS, SoCal Edison, SMUD, Alcoa, 
PJM-PPC Members, APPA, AEP, BPA, NRECA, PG&E, New England Public 
Systems, Public Power Council, Ameren, TANC, CMUA and Central 
Vermont.
---------------------------------------------------------------------------

    363. NRECA claims that, because load serving entities pay the 
largest share of the existing and future transmission system costs, 
they should not have to bid for the right to use a system that they 
paid for and that was planned and built to serve their needs. However, 
NRECA states that it is not opposed to the use of auctions for residual 
or secondary rights and for voluntary dispositions of primary rights, 
consistent with current practice. PG&E recommends that, if any 
additional long-term firm transmission rights remain after the initial 
allocation process, such firm transmission rights should be made 
available for auction. PG&E states that, as experience with long-term 
firm transmission rights in LMP environments shows them to be 
functioning in an efficient and predictable manner, auctions could 
increasingly be used for long-term firm transmission right issuance 
without detracting from the goals of EPAct 2005. Public Power Council 
states that it does not endorse the use of an auction, but if an 
auction is used to allocate scarce rights, the Commission should permit 
only entities with a preference to participate in the auction in order 
to ensure that the price is not artificially inflated.
    364. Central Vermont states that guideline (7) must be modified to 
provide parties with certainty concerning the value of their directly-
allocated long-term transmission rights. Specifically, parties will not 
have certainty about the value of their long-term transmission rights 
if the initial allocation of rights also includes exposure to negative 
congestion charges between points, which are unavoidable and very 
difficult to assess in value.
    365. In reply comments, APPA and New England Public Systems 
disagree with the contention of some commenters that FPA section 
217(b)(4)

[[Page 43603]]

permits the Commission to make a load serving entity's ability to 
obtain a long-term firm transmission right, or the financial equivalent 
thereof, turn on whether the load serving entity is willing to pay more 
than other bidders. New England Public Systems states that transmission 
customers were not required to outbid other potential customers for 
firm transmission rights under the Order No. 888 regime in place prior 
to the advent of LMP-based markets, and load serving entities with 
service obligations met through long-term power supply arrangements 
should not be required to do so now.
    366. TAPS notes that Midwest ISO argues that it would be difficult 
for a transmission organization to value the congestion hedge provided 
by a long-term right. TAPS argues that, by advocating allocation 
through auction, a transmission organization essentially assigns this 
same task to load serving entities that have far less information or 
control over the planning and expansion process.
Support for the Use of an Auction
    367. Many commenters express strong support for the use of an 
auction mechanism for allocating long-term firm transmission rights and 
object to what they view as guideline (7)'s prohibition on using an 
auction for that purpose.\119\ For example, IPL states that the 
guidelines should not preclude rights allocated by auction because 
transmission organizations and stakeholders should be allowed to 
determine whether an auction mechanism is the most equitable and 
efficient way to allocate rights. IPL contends that EPAct 2005 does not 
preclude auctions, does not specify a particular allocation 
methodology, and does not require that load serving entities receive 
rights for free. IPL argues that EPAct 2005 merely requires that load 
serving entities be able to acquire and use such rights and therefore 
the guidelines should not eliminate this flexibility. Also, Cinergy 
states that it strongly opposes guideline (7), claiming that there is 
no support in FPA section 217 for the notion that auctions should be 
foreclosed. Cinergy argues that auctions are the best available means 
of determining the initial value of transmission rights and it makes no 
sense for the Commission to exempt load serving entities from 
participating in them when that is the mechanism other market 
participants use. In Cinergy's view, guideline (7) ensures that no 
market mechanism will be available to address the unduly discriminatory 
free-rider problem caused when only some load serving entities obtain 
long-term rights.
---------------------------------------------------------------------------

    \119\ See, e.g., Cinergy, DC Energy, Coral Power, Morgan 
Stanley, EEI, IPL, DTE, National Grid, SDG&E, Midwest ISO, AF&PA, 
EPSA and Reliant.
---------------------------------------------------------------------------

    368. DC Energy believes that, to the maximum extent possible, 
market-based solutions should be used to allocate and to establish 
prices for firm transmission rights. DC Energy asserts that robust 
auctions will maximize the value of firm transmission rights and 
increase overall market efficiency by allowing the parties that value 
firm transmission rights the most to acquire them. It believes that 
transmission users that acquire firm transmission rights outside of an 
auction process may pay less for firm transmission rights than those 
who would bid on them, resulting in a decrease in auction revenues 
which translates into an increase in transmission costs. Furthermore, 
DC Energy argues that transmission customers that hold firm 
transmission rights without having to pay fair market value for them 
will not utilize generation resources in the most efficient manner and 
will cause a sub-optimal dispatch due to indifference over supply 
options.
    369. In reply to APPA's argument that longer-term transactions 
should be favored because they will send the proper economic signals 
for transmission facilities construction based on long-term power 
supply commitments, Coral Power argues that appropriate economic 
signals cannot be established under a system that does not auction 
rights on a non-discriminatory basis. It claims that transmission paths 
that are valued highly in successive short-term auctions are candidates 
for upgrades or for other solutions that might be more economic, such 
as the siting of local generation. Coral Power argues that a system 
that combines preferential allocations in long-term firm transmission 
rights with short-term competitive auctions for available transmission 
rights will only distort the market.
    370. Morgan Stanley states that the Final Rule must not allow for 
the allocation of long-term firm transmission rights without the use of 
an auction mechanism based on sound market principles and uniform 
credit eligibility standards. Morgan Stanley argues that allocation of 
long-term firm transmission rights through a non-discriminatory 
auction, for terms that can be liquidly traded, will generate needed 
price signals for market participants. Conversely, in Morgan Stanley's 
view, preferential allocation of long-term firm transmission rights 
likely would: (1) Reduce the amount of capacity available to the 
market; (2) result in a barrier to competitive entry; (3) cause price 
signals to be blunted; (4) facilitate hoarding, and (5) create an 
increased bias in favor of regulatory outcomes as opposed to a market-
based solution.
    371. DTE recommends that, once auction revenue rights or long-term 
firm transmission rights are allocated to market participants, the 
regional stakeholder process should determine under what future 
conditions, if any, long-term firm transmission rights may be auctioned 
or traded. It states that this is a long-term market development issue 
that will be unique to each region.
    372. National Grid states that, to the extent that there are 
uncertainties as to a customer's ability to obtain such rights in an 
auction, the regions can address that concern through consideration of 
rights of first refusal or other auction rules. National Grid adds that 
nothing prevents the holder of auction revenue rights from bidding for 
the underlying transmission rights and/or trading the auction revenue 
rights for transmission rights. National Grid states that, in keeping 
with the Commission's general approach to allow regions the flexibility 
to achieve consensus, the Commission should strike guideline (7) or 
revise it to allow for the possibility of mandatory auctions and the 
assignment of auction revenue rights if the regions deem these features 
to be appropriate.
    373. EPSA states that in markets with allocation of auction revenue 
rights or similar rights, regions may choose to continue to allocate 
such rights without the use of an auction. However, EPSA states that 
auction revenue rights are not the same as financial transmission 
rights and stakeholders may or may not include them in long-term firm 
transmission right programs. EPSA submits that the guidelines should be 
clear on what they assume will be included as baseline requirements or 
elements for the rules that will underpin all long-term firm 
transmission right programs in organized markets, and should not 
preclude a region from requiring an auction process to transparently 
value all firm transmission rights, including long-term firm 
transmission rights. AEP states that a load serving entity should 
always have the right to directly convert auction revenue rights into 
firm transmission rights through the auction process, and would be 
comfortable with such a conversion taking place outside of the auction 
process.
    374. SDG&E states that load serving entities that have both long-
term and short-term power supply agreements have ``reasonable needs,'' 
and the

[[Page 43604]]

statute does not value the ``needs'' of one more than the other. SDG&E 
believes firm transmission right auctions are useful because they allow 
all load serving entities to seek whatever mix of firm transmission 
rights they believe would he most valuable in terms of hedging their 
power supply portfolios, thereby enhancing the load serving entity's 
attractiveness to potential loads. AF&PA recommends that, in the 
absence of permitting auctions, the Commission should clearly provide 
guidance as to the appropriate methodology for determining the value of 
such long-term hedges.
    375. Reliant proposes that guideline (7) be modified to state: 
``Guideline (7): The initial allocation of the long-term firm 
transmission rights shall provide for a non-discriminatory and 
transparent auction but not require recipients to sell their rights 
into that auction.'' APPA, however, states that it opposes this 
language because it is too vague.
ISO-NE's Auction Mechanism
    376. ISO-NE strongly urges the Commission to provide transmission 
organizations and their stakeholders with the flexibility to consider 
allocating long-term firm transmission rights by auction, consistent 
with existing New England practices. ISO-NE argues that the economic 
benefits of auction-based allocation are well understood and have been 
accepted by the Commission in its orders on New England's current 
market design and in other proceedings. According to ISO-NE, entities 
such as PJM that initially allocated firm transmission rights directly 
to load have shifted to an auction-based allocation for compelling 
reasons. ISO-NE adds that, if the Commission were to preclude an 
allocation by auction, it is unclear how the long-term firm 
transmission right acquired by a load serving entity auction revenue 
right holder would be valued.
    377. NEPOOL states that a requirement that long-term firm 
transmission rights be directly allocated to load serving entities has 
the potential to be especially disruptive to an organized market such 
as in New England, where there is a mature auction mechanism in place 
that allocates one hundred percent of the firm transmission rights. 
According to NEPOOL, that same auction mechanism could be used to 
allocate long-term firm transmission rights, along with all other firm 
transmission rights, while still ensuring that load serving entities 
are able to acquire the long-term firm transmission rights they need. 
This protection of load serving entities could be assured, for example, 
through a tie-breaker mechanism, under which, if a load serving entity 
with a long-term commitment and another market participant are bidding 
the same price for a long-term firm transmission right, the load 
serving entity would have priority and would get the long-term firm 
transmission right. NEPOOL states that, in New England, load serving 
entities receive a direct allocation of auction revenue rights and 
would be able to use their auction revenue right revenues to bid into 
the auction for long-term firm transmission rights, thus providing them 
the ability, combined with a tie-breaker mechanism, to acquire the 
long-term firm transmission rights they need. Also, Morgan Stanley 
states that it supports this direct allocation of auction revenue 
rights so long as such direct allocation remains independent from the 
allocation of long-term firm transmission rights.
    378. New England Public Systems counters that the auction revenue 
right/firm transmission right structure in New England is inadequate to 
hedge congestion risk and is not equivalent to firm transmission even 
on a short-term basis; thus, simply extending the term of such products 
cannot satisfy the statute's requirements. According to New England 
Public Systems, most auction revenue rights in New England are 
allocated among congestion-paying load serving entities on a zonal load 
ratio share basis. In effect, each such load serving entity is paid the 
auction clearing price of an average firm transmission right in the 
zone times the ratio of its peak load to the zonal peak load. New 
England Public Systems argues that there is no assurance that revenues 
thus received will be sufficient to enable the load serving entity to 
acquire a specific firm transmission right across a particularly 
congested path. New England Public Systems asserts that auction revenue 
rights that (a) do not necessarily cover the cost of transmission 
congestion at a specific location, and (b) cannot be converted directly 
to long-term firm transmission rights that do hedge the risk of 
transmission congestion at a specific location are not the 
``equivalent'' of the firm transmission rights that section 217(b)(4) 
requires.
    379. Also, New England Public Systems states that an auction 
revenue right in itself is not the financial equivalent of a firm 
transmission right, because auction revenue right revenues generally 
are socialized and distributed on the basis of zonal load ratio share. 
According to New England Public Systems, if a load serving entity is 
outbid for a valuable firm transmission right, it receives only a 
fraction of the auction revenue generated by the winning bid yet 
remains exposed to congestion along the associated path. New England 
Public Systems states that, aside from the socialization issue, even 
path-specific long-term auction revenue rights could leave their 
holders exposed to significant congestion costs unless there is a right 
to convert long-term auction revenue rights to long-term firm 
transmission rights.
    380. Finally, in reply comments, New England Public Systems notes 
that ISO New England argues that entities such as PJM that initially 
allocated firm transmission rights directly to load have shifted to an 
auction-based allocation for compelling reasons. However, New England 
Public Systems contends that PJM's auction is not the exclusive means 
of acquiring firm transmission rights in that region. It notes that PJM 
permits self-scheduling of firm transmission rights (in essence, 
allowing an auction revenue right holder to convert its auction revenue 
right into an firm transmission right) under some circumstances, but 
requires that the self-scheduled firm transmission right have exactly 
the same source and sink points as the auction revenue right. According 
to New England Public Systems, these aspects of PJM's existing system 
for allocation of short-term transmission rights fatally undercut ISO 
New England's attempt to rely on the PJM precedent as support for 
extending the New England approach (which lacks direct conversion 
rights) to long-term firm transmission rights.
NYISO's Auction Mechanism
    381. NYISO argues that the guideline (7) proposal does not apply to 
it because it has already engaged in an allocation process that 
assigned the rights to transmission congestion contract auction 
revenues to the New York transmission owners. NYISO claims that the 
same allocation would apply to any longer-term transmission congestion 
contracts that are issued as a result of this proceeding. NYISO states 
that its transmission congestion contract auction and allocation rules 
have already been approved by the Commission and are grandfathered 
under section 217(c) of the FPA. Therefore, according to NYISO, it does 
not appear that Proposed guideline (7) is at odds with existing NYISO 
rules. NYISO states that, in any event, the Commission should clarify 
that Proposed guideline (7) is not intended to discourage auctions for 
long-term

[[Page 43605]]

firm transmission rights beyond the initial allocation of revenue 
rights.
    382. In response to NYISO, NYAPP states that section 217(c) of 
EPAct 2005 does not serve to ``grandfather'' any RTO allocation 
mechanisms under section 217(b)(4), only subsections (b)(1), (b)(2), 
and (b)(3). The Commission's authority to modify a transmission 
organization's current methods for allocation of transmission rights is 
specifically preserved for the implementation of section 217(b)(4). In 
NYAPP's view, NYISO should still have to comply with guideline (7).
PJM's Auction Mechanism
    383. Reliant states that any allocation of long-term rights should 
include a transparent auction process that allows participants to 
evaluate the value of such rights, and that the existing PJM auction 
revenue rights process is a good market example that meets the varied 
needs of all market participants.
    384. Strategic Energy argues that any allocation of transmission 
hedges should be provided via auction revenue right, with the option, 
but not the obligation, to convert the auction revenue right to a firm 
transmission right on a concurrent source/sink path, as is the current 
PJM practice. Strategic Energy claims that the auction revenue right 
facilitates load migrations and the equitable migration of the value of 
transmission hedges with the load. However, Strategic Energy states 
that its support of the auction revenue right/firm transmission right 
allocation and auction model is mitigated by concern that initial 
allocation of auction revenue rights should not be provided to long-
term uses to the detriment of short-term uses, such as annual or 
shorter-term hedging frequently employed by competitive retail 
suppliers.
Commission Conclusion
    385. We will adopt guideline (7) as proposed in the NOPR. However, 
as we explain below, we clarify that guideline (7) does not preclude a 
transmission organization from using an auction to allocate long-term 
firm transmission rights; it only precludes requiring a load serving 
entity to submit a winning bid in an auction in order to acquire long-
term firm transmission rights.
    386. The Commission agrees with commenters such as APPA, NRECA and 
CMUA that argue that load serving entities that are obligated to pay 
the embedded costs of the transmission system should be able to receive 
an equitable share of long-term firm transmission rights without having 
to submit a competitive bid for those rights. As APPA points out, 
guideline (7) provides the load serving entity with transmission rights 
that are more akin to long-term network and point-to-point service 
rights of Order No. 888 than to the short-term rights offered in 
today's organized electricity markets. Also, the Commission does not 
interpret EPAct 2005 as requiring the use of an auction to allocate 
long-term firm transmission rights, or as preventing the Commission 
from modifying the allocation method currently used by any transmission 
organization. As we have noted elsewhere in this preamble, section 
217(b)(4) of the FPA is not included in the list of subsections that 
section 217(c) states shall not affect existing or future transmission 
organization allocation methodologies.
    387. Nevertheless, the Commission agrees with those commenters that 
point out the many benefits that auctions can bring to the allocation 
process. As DC Energy notes, auctions can maximize the value of 
transmission rights and increase overall market efficiency by allowing 
the parties that value firm transmission rights the most to acquire 
them. Also, as Coral Power notes, transmission paths that are valued 
highly in successive short-term auctions are candidates for upgrades or 
for other solutions that might be more economic, such as the siting of 
local generation. We note, however, that some of these commenters 
interpret guideline (7) as precluding the use of an auction to allocate 
long-term firm transmission rights. For example, Cinergy asserts that 
guideline (7) ensures that no market mechanism will be available. 
Further, Cinergy states that there is no support in FPA section 217 for 
the notion that auctions should be foreclosed and that it makes no 
sense for the Commission to exempt load serving entities from 
participating in them when that is the mechanism other market 
participants use.
    388. The Commission clarifies that we do not intend for guideline 
(7) to foreclose all transmission right auctions. Indeed, the 
Commission believes that an auction can be an integral part of a 
process for the fair and efficient allocation of long-term firm 
transmission rights that also satisfies the fundamental requirement of 
guideline (7). For example, one such allocation process is the method 
now used by PJM to allocate annual firm transmission rights. As noted 
by New England Public Systems, PJM uses a process that first allocates 
auction revenue rights to load serving entities and then allows each 
load serving entity the option to convert its auction revenue rights 
directly into annual firm transmission rights with identical sources 
and sinks. In effect, each load serving entity in PJM may, at its 
option, bid the value of its auction revenue rights into the auction as 
a ``price-taker'' knowing that it will win the bid for the firm 
transmission rights that correspond to the sources and sinks of its 
respective auction revenue rights. As a price-taker, the load serving 
entity will not know in advance the price it must pay for the firm 
transmission rights that it acquires, but it is secure in the knowledge 
that the value of its auction revenue rights will cover exactly the 
cost of the firm transmission rights. Such a process could be readily 
adapted to the allocation of long-term firm transmission rights.
    389. The principal advantage of this approach is that, consistent 
with guideline (7), it allows the load serving entity to obtain its 
long-term firm transmission rights without having to submit an explicit 
price bid in an auction, yet at the same time it exposes the load 
serving entity to a competitive auction price signal that will promote 
efficient-decision making. Of course, as long as the load serving 
entity desires long-term firm transmission rights with the same source 
and sink points as its allocated auction revenue rights, it may simply 
bid the value of those auction revenue rights into the auction and 
receive those rights. However, because it is exposed to the auction 
price signal, the load serving entity acquires information that may 
cause it to adopt a different bidding strategy in subsequent auctions. 
For example, if the auction clearing price for the long-term firm 
transmission rights that correspond to a load serving entity's auction 
revenue rights is very high, while the clearing price for other long-
term firm transmission rights is low, the load serving entity may 
determine that it would prefer to submit an explicit price bid for the 
lower-priced rights and forego the opportunity to convert its auction 
revenue rights into the corresponding long-term firm transmission 
rights. In this way, the load serving entity obtains valuable, albeit 
lower-priced, rights and also receives auction revenues equal to the 
difference between the value of its auction revenue rights and the 
total amount it must pay for the lower-priced rights. In addition, the 
higher-priced rights that correspond to the load serving entity's 
auction revenue rights are now made available to other auction 
participants that value them more highly, thus achieving the goal 
identified by DC Energy.
    390. In this regard, we note that DC Energy is concerned that 
transmission customers that obtain firm transmission rights without 
having to pay fair market

[[Page 43606]]

value for them will not utilize generation resources in the most 
efficient manner, and Coral Power argues that this could result in a 
highly inefficient generation siting decision. Similarly, Morgan 
Stanley is concerned that guideline (7) will lead to competitive entry 
barriers, hoarding and blunted price signals. We disagree. Even when a 
load serving entity holds auction revenue rights with a direct 
conversion right, it can be expected to behave in an economically 
rational manner because it always has an incentive to forego its 
conversion right if it stands to gain financially from submitting a 
price bid for alternative rights in the long-term firm transmission 
rights auction.
    391. EPSA notes that in markets with allocation of auction revenue 
rights, regions may choose to continue to allocate such rights without 
the use of an auction. However, EPSA states that auction revenue rights 
are not the same as firm transmission rights and wants the guidelines 
to be clear on what elements must be included in all long-term firm 
transmission rights programs. Also, Strategic Energy states that 
initial allocation of auction revenue rights should not be provided to 
long-term uses to the detriment of short-term uses. Although the 
Commission believes that allocation methods that combine a direct 
allocation of auction revenue rights with a transmission rights auction 
offer many advantages, we will not prescribe here the process by which 
a transmission organization must allocate auction revenue rights, or 
ultimately long-term firm transmission rights, to a load serving entity 
or other market participant. We recognize that, today, transmission 
organizations use a variety of allocation methods, but no one method 
has emerged as being clearly superior to all others. We, therefore, 
will provide each transmission organization and its stakeholders with 
the flexibility to propose an approach that meets regional needs and 
satisfies each of the guidelines in this Final Rule, subject to 
Commission approval.
    392. A number of comments were directed specifically at the auction 
mechanisms currently used by ISO-NE and NYISO. Based on the comments of 
New England Public Systems, it appears that the allocation process now 
used by ISO-NE does not permit a direct conversion of auction revenue 
rights into corresponding firm transmission rights. If so, the process 
does not meet the requirements of guideline (7) for allocating long-
term firm transmission rights and must be modified. Also, with respect 
to NYISO's auction mechanism, NYAPP is correct in noting that section 
217(c) of EPAct 2005 does not prevent the Commission from modifying the 
allocation processes of any transmission organization under section 
217(b)(4). Therefore, contrary to the view of NYISO, guideline (7) 
applies to its allocation process in the same way that it applies to 
the allocation processes of all other transmission organizations.
    393. Finally, Central Vermont states that guideline (7) must be 
modified to provide market participants with certainty concerning the 
value of their long-term transmission rights if the initial allocation 
of rights includes exposure to negative congestion charges. We will not 
modify guideline (7) to address this concern. However, we will provide 
the transmission organization and its stakeholders with flexibility to 
include, within the proposed allocation process, specific rules to 
address such matters should they arise.
Guideline (8)--Balance Adverse Economic Impacts
    394. As proposed in the NOPR, guideline (8) stated that the 
allocation of long-term firm transmission rights should balance any 
adverse economic impact between participants receiving and not 
receiving the right. The NOPR noted that, to the extent that the 
capacity of the transmission system is encumbered by entities holding 
long-term firm transmission rights, entities that prefer short-term 
transmission rights, such as load serving entities operating in retail 
states, will have fewer rights available to them than they have under 
current annual allocation schemes. In addition, to the extent awarded 
long-term rights become infeasible due to unforeseen changes in the 
physical properties of the transmission system, the payment obligations 
to holders of long-term firm transmission rights would have to be 
funded by others.
    395. The NOPR stated that, in general, it should be possible for 
the transmission organization to introduce long-term firm transmission 
rights in a way that balances economic impacts, for example, by placing 
a limit on the amount of system capacity that is available to support 
long-term rights. Also, the NOPR stated that if the long-term right is 
an ``option'' right that encumbers more system capacity than an 
``obligation'' right, the holder of such a right could be required to 
assume greater cost responsibility.
    396. The NOPR noted that the transmission organization might 
provide for a secondary market or auction that would provide an 
opportunity for transmission customers to obtain long-term rights on 
either a long-term or short-term basis from those holding long-term 
rights. The NOPR proposed to allow the transmission organization 
flexibility to propose methods for pricing transmission rights and 
related services that are appropriate for its region and are the 
product of a stakeholder process.
    397. The NOPR asked for comments on any measures that should be 
adopted to protect against the impacts of a decision by a holder of an 
``obligation'' right to leave the transmission organization when the 
feasibility of other transmission rights depend on that holder's 
counterflows.
Comments
General Comments on the Need for Guideline (8)
    398. Several commenters argue that the principles embodied in 
guideline (8) are important, and some believe that they should be the 
primary focus in the allocation of long-term firm transmission 
rights.\120\ AF&PA states that principles embodied in guideline (8) 
should be seen as controlling the application of all the other 
guidelines. AF&PA states that the Commission must not return to a pre-
OATT world where certain entities claim the exclusive right to use the 
transmission system for their benefit, and all competing usage is 
viewed as incremental or marginal.
---------------------------------------------------------------------------

    \120\ See, e.g., AF&PA, EPSA, Midwest ISO, IPL, NYISO, CMUA and 
National Grid.
---------------------------------------------------------------------------

    399. Midwest ISO states that the nature and scope of financial 
hedging instruments for users of long-term transmission ultimately 
should be defined in well-functioning markets. Midwest ISO argues that 
any mandate that transmission organizations provide such instruments 
must carefully balance the potential benefits to some market 
participants against the potential costs to other market participants. 
IPL states that, as proposed, the guidelines are not balanced and do 
not meet this standard.
    400. NYISO believes that it is possible that long-term firm 
transmission rights can be introduced without inequities, particularly 
if transmission organizations are permitted to retain existing systems 
without major changes. CMUA also believes the equity concerns raised in 
guideline (8) may in practice not prove difficult to reconcile. 
Nevertheless, CMUA is concerned that transmission organizations and 
certain stakeholders might attempt to use guideline (8) to effectively 
eviscerate long-term firm transmission rights, in violation of FPA 
section 217(b)(4).

[[Page 43607]]

Comments Suggesting That Guideline (8) Is Not Needed
    401. Some commenters argue that guideline (8) is not needed or 
requires clarification.\121\ For example, BPA suggests that this 
guideline be deleted from the Final Rule, as the issues it raises can 
be addressed under other guidelines. Furthermore, BPA states that it is 
not appropriate to require transmission organizations to balance the 
adverse economic impacts between those receiving the right and those 
that do not.
---------------------------------------------------------------------------

    \121\ See, e.g., BPA, TAPS, Industrial Consumers and Alcoa.
---------------------------------------------------------------------------

    402. TAPS states that guideline (8) should be removed. However, if 
some ``reasonableness'' guideline is retained, it should be reworded as 
``avoidance of undue impacts,'' to recognize that some impacts are 
``due'' and reasonable. In addition, TAPS is concerned that guideline 
(8) establishes criteria that are not called for by section 217(b)(4) 
and could be used to undermine Congress's clear directive. In response, 
Midwest ISO agrees with TAPS that section 217(b)(4) does not expressly 
require that a balance be struck between those that receive long-term 
firm transmission rights and those that do not. However, Midwest ISO 
claims that section 217(b)(4) also does not expressly require the 
Commission to provide load serving entities unlimited and fully-funded 
long-term firm transmission rights to hedge congestion costs associated 
with long-term power supply arrangements.
    403. In addition, TAPS notes that the NOPR describes as an adverse 
impact the potential that the long-term rights will result in the 
availability of fewer rights for entities that prefer short-term 
rights. TAPS states that this has always been the case under the Order 
888 OATT. TAPS claims that a transmission provider is not entitled to 
turn down a long-term firm request to keep capacity available for those 
who wish to make short-term or non-firm use of the system.
    404. Industrial Consumers argues that, if the total available 
rights (short- and long-term) are insufficient to meet the needs of 
end-use customers (an indication that the owners of the transmission 
system are mismanaging the maintenance and planning of their assets) it 
may be necessary to ration the rights, but still preserve the 
preference to holders of long-term rights. In Industrial Consumers' 
view, the real issue here is not that economic interests are not 
appropriately balanced, but that transmission owners have abrogated 
their responsibilities.
    405. Alcoa states that it is not clear whether the Commission 
intends that there will be a redistribution of costs and benefits 
between those entities holding firm transmission rights and those that 
do not.
Conflicts Between Guideline (8) and Other Guidelines
    406. Cinergy states that it completely agrees with guideline (8), 
but claims that this guideline is not achievable in light of the other 
guidelines proposed by the Commission. Midwest ISO maintains that, 
while the implementation of this guideline is essential, the 
implementation would be difficult because it is in direct conflict with 
the requirement for full funding of long-term firm transmission rights 
(guideline (2)) and the priority extended to long-term firm 
transmission right holders (guideline (5)). NYISO states that the same 
problem applies to proposed guideline (4) to the extent that the 
Commission interprets it to require non-market based renewal rights for 
long-term transmission rights. National Grid recommends that the 
Commission treat these conflicting guidelines more as goals rather than 
minimum requirements.
Need for Regional Flexibility in the Application of Guideline (8)
    407. SoCal Edison states that, because issues of balance are 
intricate and require both judgment and familiarity with the local 
market and system issues, the Commission should leave the specifics of 
such a balance to the transmission organizations. Similarly, IPL urges 
the Commission to allow the transmission organization the flexibility 
to develop certain long-term transmission rights parameters such as 
pricing and availability.
Importance of Protecting the Status Quo
    408. Some commenters recommend that guideline (8) be implemented in 
a way that protects existing short-term rights holders and market 
rules.\122\ For example, Constellation states that the Commission 
should not adopt policies that harm the existing competitive wholesale 
and retail markets. Constellation asserts that a policy that 
articulates a preference for long-term supply arrangements is such a 
policy. Constellation states that, if the Commission decides to unwind 
the current, competitive market structure by setting aside existing 
transmission capability for long-term uses, then guideline (8) must be 
a critical factor in the Commission's approval of any long-term firm 
transmission right proposal so that the Commission can ensure that 
there are no adverse impacts on other market participants. In 
Constellation's view, any long-term firm transmission right proposal 
must identify harm that will be caused by its implementation, such as 
the reduction of hedging opportunities for shorter-term uses, and 
propose mitigation for such adverse consequences.
---------------------------------------------------------------------------

    \122\ See, e.g., Coral Power, Constellation, Strategic Energy, 
and EEI.
---------------------------------------------------------------------------

    409. EEI argues that since load serving entities and other 
transmission customers in PJM, Midwest ISO, NYISO and ISO-NE have made 
supply and investment decisions in reliance on Commission-approved 
allocations, the Commission should not reverse its prior decisions by 
changing these allocations and market structures. EEI argues that it 
would be disruptive and unfair to require any changes to the underlying 
agreements and understandings that formed the design of these four 
transmission organizations. In response, APPA argues that the equities 
cut both ways. APPA claims that during the transition to ``Day Two'' 
transmission organization markets, many public power load serving 
entities lost valuable Order No. 888 OATT and grandfathered 
transmission rights, leaving their power supply arrangements subject to 
unanticipated transmission congestion charges. According to APPA, these 
entities have since been attempting to conduct business under a 
construct of locational marginal pricing and firm transmission rights 
that is essentially hostile to their business model. In addition, APPA 
argues that Congress contemplated that making long-term firm 
transmission rights available to load serving entities under section 
217(b)(4) might indeed require revisiting the prior allocation of firm 
transmission rights in RTO regions. Further, NRECA claims that Congress 
has already issued the mandate and determined the appropriate balance 
of costs and benefits; it has not authorized the Commission or 
transmission organizations to undertake a cost/benefit analysis of 
whether the statutory mandate is justified or the balance struck by 
statute appropriate.
Issues Regarding Cost Shifting
    410. Several commenters express concern that requiring transmission 
organizations to make available long-term firm transmission rights 
could harm market performance and shift costs unnecessarily or unfairly 
among

[[Page 43608]]

market participants.\123\ For example, Strategic Energy submits that 
introduction of multi-year rights will cause cost shifts if holders of 
such rights are allocated congestion risk coverage greater than that 
accorded to other parties.
---------------------------------------------------------------------------

    \123\ See, e.g., EEI, Strategic Energy, Suez Energy, BP Energy, 
ISO-NE and Midwest ISO.
---------------------------------------------------------------------------

    411. BP Energy states that to ensure the balancing of any adverse 
economic impacts, guideline (8) should be modified to state explicitly 
that the allocation of incremental long-term firm transmission rights 
to one party can not result in subsidization of those rights by other 
parties, i.e., there can be no significant shifting of generation 
redispatch costs or fixed transmission costs as the result of new 
supply arrangements entered into by load serving entities receiving 
long-term rights to parties not subject to those agreements.
    412. BP Energy also argues that, if parties seeking long-term 
rights are able to shift congestion costs to others, they will have no 
disincentive to enter into supply arrangements that reduce (because of 
their relative location on the grid) the absolute amount of 
transmission rights that an organized market can allocate while 
maintaining revenue sufficiency. Similarly, in ISO-NE's view, 
allocation of free long-term firm transmission rights to load serving 
entities versus an auction of long-term firm transmission rights to 
generators, traders and other entities creates equity and distortion 
issues.
    413. Some commenters address the problem of balancing adverse 
impacts in light of the NOPR's proposed requirement for full funding of 
long-term firm transmission rights.\124\ For example, IPL argues that 
the adverse economic impact of a long-term financial transmission 
rights allocation stems in large part from the shortfall funding 
obligation. IPL urges the Commission not to require entities to share 
this obligation to the extent those entities do not receive benefits 
from the allocation and do not bear direct responsibility for 
congestion costs. According to Midwest ISO, the Commission's proposal 
to guarantee load serving entities priority of existing transmission 
capacity with fully-funded long-term firm transmission rights for the 
entire capacity of their supply contracts may result in significant 
costs on other market participants, increase the costs of transmission 
organization membership, and significantly reduce the availability of 
firm transmission rights to meet short-term firm transmission right 
holders' requests.
---------------------------------------------------------------------------

    \124\ See, e.g., IPL, PJM, PJM Public Power Coalition and BP 
Energy.
---------------------------------------------------------------------------

Pricing and Cost Responsibility for Long-Term Firm Transmission Rights
    414. Some commenters state that they agree with the NOPR's 
statement that ``to the extent that the long-term right relieves the 
holder of the obligation to pay congestion costs, the value of that 
congestion hedge should be reflected in the price of the long-term 
right, insofar as possible.'' \125\ In this regard, BP Energy argues 
that two scenarios are apparent. First, where the same or electrically 
similar (mutually exclusive) rights are sought by multiple parties, the 
party willing to pay the most might acquire them through a competitive 
process, such as an auction. Alternatively, the party seeking such 
long-term rights can, consistent with guideline (3), pay for the 
necessary ``transmission upgrades and expansions'' to receive the 
``rights made feasible'' by that expenditure. In the case where 
existing capacity is sought by multiple parties, and auctions are not 
available, BP Energy argues that the only equitable and reasonable 
method of capacity allocation, consistent with the Commission's holding 
that ``the value of that congestion hedge should be reflected in the 
price of the long-term right'' is to honor existing rights allocations, 
while expediting capacity upgrades and expansions to meet needs 
exceeding available transmission capacity.
---------------------------------------------------------------------------

    \125\ See, e.g., Midwest TOs and BP Energy.
---------------------------------------------------------------------------

    415. Midwest ISO states that the notion that the price of the long-
term right should reflect the value of the congestion hedge is 
problematic because it is unclear how transmission organizations would 
reflect the value of the congestion hedge in the price of the long-term 
firm transmission right. Midwest ISO argues that the best way to 
determine the value of such a congestion hedge would be through a 
market mechanism such as an auction, which would be inconsistent with 
guideline (7).
    416. Some commenters argue that long-term firm transmission rights 
holders should not, in general, be allocated a cost differential.\126\ 
Ameren states that load serving entities that are allocated long-term 
firm transmission rights are providing the steady, long-term revenue 
stream to transmission owners that allows them to invest in upgrades 
and expansions to the system, and thus, should not be assessed a 
premium charge. TAPS states that if long-term rights are limited to 
base load and renewable resources for which the grid should be planned 
in any event, it is unreasonable to impose an additional cost burden on 
long-term right holders. TAPS states that the Commission should make 
clear that it will not accept proposals that would defeat the purpose 
of long-term rights by pricing them out of the reach of load serving 
entities. Also, TAPS supports the Commission's proposal to leave the 
pricing associated with long-term rights to RTO compliance filings. 
However, TAPS believes that the transmission organization compliance 
process will go more smoothly if the Final Rule includes a new 
guideline providing that the pricing of long-term rights should support 
and not frustrate section 217(b)(4)'s directive to enable load serving 
entities to secure such rights.
---------------------------------------------------------------------------

    \126\ See, e.g., TANC, NRECA, TAPS, Ameren, CMUA, NCPA and APPA.
---------------------------------------------------------------------------

    417. With respect to firm transmission right options, Strategic 
Energy states that to the extent that firm transmission right options 
can be accommodated, they should be offered, subject to the recognition 
that such products encumber substantially more system capacity than 
obligations, and therefore should be valued accordingly. Also, TAPS and 
OMS agree that those wanting long-term firm transmission right options 
should be willing to pay for the additional cost of providing such an 
instrument. OMS submits that one possible way of doing this is to first 
allocate long-term firm transmission right obligations, and then allow 
those receiving long-term firm transmission right obligations the 
option of converting the firm transmission right obligation to a firm 
transmission right option.
Proposals to Limit the Adverse Impact of Long-Term Firm Transmission 
Rights
    418. NSTAR and CAISO argue that some of the concerns the Commission 
raises under guideline (8) can be addressed by making long-term firm 
transmmission rights identical to short-term rights in every way but 
duration. In NSTAR's view, section 217(b)(4) does not require 
differences between long-term firm transmission right characteristics 
and firm transmission right/auction revenue right characteristics 
except for duration. NSTAR argues that failure to harmonize any future 
long-term firm transmission rights with the current market and 
transmission tariff would be disruptive of existing arrangements and 
destabilize power supply planning.
    419. Some commenters argue that the balance that the Commission 
seeks under guideline (8) can be achieved with the aid of secondary 
auctions and

[[Page 43609]]

other market mechanisms.\127\ For example, NRECA recommends using a 
voluntary secondary auction in order to allow reconfiguration of long-
term firm transmission rights. NRECA states that this would allow 
shorter term rights that are unused to be auctioned to load serving 
entities without longer term service obligations, which could mitigate 
any potential adverse effect experienced by those that do not receive 
long-term firm transmission rights.
---------------------------------------------------------------------------

    \127\  See, e.g., NRECA, SMUD, Midwest ISO, Reliant, AF&PA, 
Strategic Energy and BPA.
---------------------------------------------------------------------------

    420. Several commenters suggest that adverse impacts associated 
with the introduction of long-term firm transmission rights can be 
reduced by limiting the amount of transmission capacity that is made 
available for those rights.\128 \For example, Reliant supports placing 
a limit on the amount of system capacity available to support long-term 
rights as this would reduce the likelihood that the rights may become 
infeasible, which in turn would reduce the possibility that the burden 
of funding the allocated rights would eventually fall onto other market 
participants.
---------------------------------------------------------------------------

    \128\ See, e.g., Reliant, Kentucky PSC, PJM, Santa Clara, SoCal 
Edison, AEP, CAISO, ISO-NE, Midwest ISO, OMS, NU, PG&E, APPA, TAPS 
and Wisconsin Electric.
---------------------------------------------------------------------------

    421. APPA states that it is amenable to discussion of mechanisms 
that transmission organizations could use to minimize to the extent 
possible the adverse impacts of long-term firm transmission right 
allocations on the firm transmission rights available to other 
transmission customers. APPA proposes therefore that the Commission 
reformulate guideline (8) to reflect this approach: ``Long-term firm 
transmission rights should be allocated in a manner that minimizes, to 
the extent possible, adverse impacts on participants not receiving such 
rights.'' APPA states that any such mechanisms would have to be 
specific to each transmission organization and could include some 
combination of: (1) Restrictions on the overall portion of the existing 
transmission system that could be allocated to support long-term firm 
transmission rights and (2) limits on each load serving entity's own 
long-term firm transmission right holdings, based on some percentage of 
the load serving entity's own loads.
    422. In response, PJM states that the APPA rewrite of guideline (8) 
may go too far and potentially eliminate the ability of transmission 
organizations to preserve their existing priorities for short-term firm 
transmission rights with the new long-term firm transmission rights. As 
a result, PJM asks that guideline (8) not be amended. Rather, PJM urges 
the Commission to examine whether the appropriate balance called for in 
guideline (8) has been addressed in individual transmission 
organization filings.
Rules for Withdrawing From Membership in an RTO
    423. With regard to whether measures are needed to address events 
such as the departure of long-term firm transmission right holders from 
the transmission organization, APPA states that the transmission 
organization will likely have to handle such events on a case-by-case 
basis. Ameren states that covering the impact of exit on long-term firm 
transmission rights may require additional language in transmission 
organization tariffs and/or members' agreements.
    424. TAPS argues that transmission dependent utilities have no 
control over whether their host transmission owner seeks to withdraw 
from an RTO or switch RTOs. In TAPS's view, transmission dependent 
utilities therefore should be held harmless from such decisions. If, 
upon withdrawal, the host transmission owner reverts to a physical 
rights regime, TAPS states that the transmission dependent utility's 
long-term right should be adapted to that regimen. If the host 
transmission owner switches transmission organizations, TAPS states 
that the new transmission organization should be required to honor the 
transmission dependent utilities' long-term rights.
Commission Conclusion
    425. The Commission will delete guideline (8) in the Final Rule. 
Commenters make a strong case that guideline (8) is not needed. Our 
principal purpose in including guideline (8) was to ensure that the 
requirements of section 217(b)(4) of the FPA are implemented in a 
manner that is just and reasonable and not unduly discriminatory, which 
is our legal duty under the FPA. Neither we nor, in our view, Congress 
intended to require long-term firm transmission right proposals to meet 
a different or higher standard. Indeed, as noted by APPA, TAPS, CMUA 
and others, opponents of long-term firm transmission rights could 
attempt to interpret guideline (8) in a way that would effectively 
eviscerate long-term firm transmission right proposals. Also, we agree 
with BPA's statement that the issues raised by guideline (8) can be 
effectively addressed through the application of other guidelines. 
Nevertheless, while we are deleting guideline (8), we believe that 
meeting our obligation under the FPA to ensure that rates are just and 
reasonable and not unduly discriminatory will still require that we 
assess the impact of long-term rights proposals on those not receiving 
the rights.
    426. We note that several commenters overstate the adverse effects 
of introducing long-term firm transmission rights, particularly in 
light of the revised guidelines that we are adopting herein. For 
example, Midwest ISO states that providing load serving entities with 
priority to receive, from existing transmission capacity, fully-funded 
long-term firm transmission rights to support the full amount of their 
supply contracts may place significant costs on other market 
participants, increase the costs of transmission organization 
membership, and significantly reduce the availability of firm 
transmission rights to meet short-term firm transmission right holders' 
requests. However, by (1) expanding the priority of guideline (5) to 
all load serving entities and (2) allowing limits to be placed on the 
amount of existing transmission system capacity that is made available 
for long-term firm transmission rights, the Commission is taking 
important steps in this Final Rule to reduce, if not eliminate, 
problems associated with cost shifting and the reduced availability of 
short-term transmission rights to load serving entities that prefer 
them. As we explained in the discussion of guideline (5) above, as a 
result of these changes, the transmission organization should be able 
to design a comprehensive allocation process for short-term and long-
term transmission rights that largely replicates the equitable 
distribution of short-term rights that occurred in the past for those 
entities that still want them. Indeed, to the extent that long-term 
rights and short-term rights have the same properties except for 
duration, as suggested by NSTAR and CAISO, even the full-funding 
requirement should not lead to significant cost shifting among classes 
of rights holders if all rights holders are given similar full-funding 
protections.\129 \In any event, as noted by Reliant, placing a limit on 
the amount of system capacity available to support long-term rights 
will reduce the likelihood that the rights may become infeasible, which 
in turn will reduce the possibility that the funding burden will 
eventually fall onto other market participants.
---------------------------------------------------------------------------

    \129\ See the discussion of these issues under guideline (2), 
above.
---------------------------------------------------------------------------

    427. Also, BP Energy states that if long-term rights holders are 
able to shift

[[Page 43610]]

generation redispatch and other congestion costs to others, they will 
have no incentive to enter into supply arrangements that maximize the 
number of transmission rights that can be allocated while maintaining 
revenue sufficiency. Similarly, ISO-NE argues that allocation of free 
long-term firm transmission rights to load serving entities versus an 
auction of such rights to all entities creates equity and distortion 
issues. We disagree. Well designed long-term firm transmission rights 
should result in no significant equity issues or economic distortions. 
As noted, cost shifting and equity issues are largely addressed by our 
revisions to guideline (5). As to economic distortions, these largely 
can be avoided by making firm transmission rights available through a 
process that combines a direct allocation of auction revenue rights 
with an auction of firm transmission rights, as explained in our 
discussion of guideline (7). Also, as NRECA notes, the availability of 
a voluntary secondary auction would allow reconfiguration of long-term 
firm transmission rights and make available shorter-term rights to 
entities that were not able to obtain long-term firm transmission 
rights.
    428. Finally, with regard to whether measures need to be adopted to 
address events such as the departure of long-term firm transmission 
right holders from the transmission organization, the Commission agrees 
with APPA and Ameren that issues related to the withdrawal of an entity 
from a transmission organization are best addressed in the transmission 
organization's members' agreement's terms for exit and should be 
reviewed on a case-by-case basis. As Ameren notes, the addition of 
long-term firm transmission rights may require additional language in 
transmission organization tariffs or members' agreements. The 
Commission encourages transmission organizations and their stakeholders 
to consider the need for such language and to include any proposed 
revisions in their compliance filings.

F. Transmission Planning and Expansion

    429. In the NOPR, the Commission noted that section 217(b)(4) of 
the FPA requires the Commission to exercise its authority ``in a manner 
that facilitates the planning and expansion of transmission facilities 
to meet the reasonable needs of load serving entities to satisfy the 
service obligations of the load serving entities.'' Accordingly, the 
Commission proposed to require that transmission organizations ensure 
that the long-term firm transmission rights they offer remain viable 
and are not modified or curtailed over their entire term. The 
Commission noted that, because the proposed guidelines would require 
that transmission organizations guarantee the financial coverage of the 
long-term firm transmission rights, transmission organizations would 
need to have an effective planning regime in place, and might need to 
expand the system to ensure that the long-term firm transmission rights 
can be accommodated over their entire term.
    430. The Commission stated that it would not propose specific 
planning and expansion procedures in the NOPR, but rather each 
transmission organization and its stakeholders should develop 
appropriate methods for ensuring that long-term firm transmission 
rights are supported by adequate planning and expansion procedures. The 
Commission encouraged transmission organizations to propose such 
procedures as part of their filings in compliance with the Final Rule, 
and stated that it will consider them in light of the direction in 
section 217(b)(4) of the FPA that the Commission exercise its FPA 
authority to facilitate the planning and expansion of transmission 
facilities. The Commission asked for comments on whether it should 
require that transmission organizations file their transmission 
planning and expansion procedures and specific plans. It also sought 
comment on whether, alternatively, the Commission should require that 
transmission organizations file the plans and procedures for 
informational purposes to allow the Commission to monitor their 
adequacy for ensuring the viability of the long-term firm transmission 
rights.
    431. The Commission noted that the pro forma OATT adopted by the 
Commission in Order No. 888 requires transmission providers to expand 
capacity, if necessary, to satisfy the needs of network and point-to-
point transmission service customers. The Commission also noted that 
its Notice of Inquiry concerning the pro forma OATT sought responses 
from interested parties on specific questions relating to this 
requirement, including: (1) whether this provision has met transmission 
customers' needs, and (2) whether public utility transmission providers 
have fulfilled these obligations.\130 \In the NOPR, the Commission 
asked for comments addressing these questions in the specific context 
of the transmission organizations with organized electricity markets 
that are the subject of this rulemaking.
---------------------------------------------------------------------------

    \130\ Since the issuance of the NOPR in this proceeding, the 
Commission has issued a NOPR concerning revisions of the Order No. 
888 OATT in Docket Nos. RM05-25-000 and RM05-17-000.
---------------------------------------------------------------------------

    432. Finally, in the NOPR, the Commission asked for comments on 
whether the definition of native load service obligation in section 
1233 of EPAct 2005 is the same as the approach the Commission took in 
Order No. 888, with particular emphasis on how the native load 
preference has been applied in the organized electricity markets that 
are the subject of this rulemaking.
Comments
Need for Transmission Planning--General
    433. A number of commenters assert that the need for long-term 
transmission planning and expansion goes well beyond the need to 
provide for long-term firm transmission rights.\131\ AEP states that 
proper planning of a robust transmission system is imperative to 
meeting long-term economic and reliability needs, which is a much 
bigger issue than hedging long-term transmission risks.
---------------------------------------------------------------------------

    \131\ See, e.g., AEP, Constellation, Redding and MSATs.
---------------------------------------------------------------------------

    434. NCPA recommends that all transmission planning processes 
include the following: (1) Needs defined on a comparable basis, based 
on analysis of all projected load serving entity loads and resources, 
and published, consistently-applied standards; (2) opportunities for 
all TDUs to participate in the joint planning process, and to validate 
and gain confidence in transmission planning models; (3) colorblind 
selection of plans to be implemented; (4) a dispute resolution process; 
and (5) plans and inputs that are transparent.
Transmission Organization's Responsibility for Transmission Planning
    435. A number of comments address the role of the transmission 
organization in the transmission planning process.\132\ AEP believes 
that the transmission organization should conduct regional transmission 
planning and be the primary driver of providing long-term connections 
between economic power sources and load centers. AEP argues that the 
transmission organization should provide for a mechanism that links the 
granting of any long-term transmission rights and the construction of 
transmission to make those rights feasible. Constellation asserts that 
this will provide a mechanism to ensure that

[[Page 43611]]

the system is not overbuilt to ensure long-term firm transmission 
rights.
---------------------------------------------------------------------------

    \132\ See, e.g., AEP, Constellation, TAPS, Midwest, TDUs and 
NCPA.
---------------------------------------------------------------------------

    436. TAPS believes that transmission organizations must be held 
accountable for planning and expanding the grid to ensure load-specific 
deliverability sufficient to support the continued simultaneous 
feasibility of all long-term rights issued, taking into account other 
rights that require preservation. TAPS states that RTOs (and 
transmission owners, if RTOs aggregate the transmission plans of their 
member transmission owners) should be required to have an inclusive 
joint planning process that meets the needs of TDUs on the same basis 
that TOs' similar needs are met. In TAPS's view, to meet the needs of 
new organized electricity markets, RTOs must be able to deliver crucial 
transmission upgrades, not just assemble consolidated lists of 
projects.
Transmission Planning To Accommodate Long-Term Firm Transmission Rights
    437. A number of commenters stress that the transmission 
organization's planning and expansion protocols must take into 
consideration the long-term firm transmission rights that are 
issued.\133\ For example, Ameren submits that the parameters of long-
term firm transmission right elections must be embedded in the RTO's 
planning process. Ameren states that this will require the RTO to 
identify for its transmission owners the term of each long-term power 
supply arrangement associated with each firm transmission right on each 
transmission owner's system, so that the expansion plans the 
transmission owners submit to the RTO incorporate any expansions 
necessitated by the long-term supply arrangements. Ameren asserts that 
ensuring load serving entities' priority access to long-term firm 
transmission rights will give load serving entities the same rights and 
ability to ``lock in'' long-term firm transmission to support their 
long-term power supply arrangements that they enjoyed under Order No. 
888 before RTOs and RTOs' organized electricity markets. MSATs states 
that it agrees with such observations but also believes that long-term 
firm transmission rights should not become the principal driver of the 
transmission planning and expansion process.
---------------------------------------------------------------------------

    \133\ See, e.g., OMS, Ameren, SMUD, EPSA, IPL, PJM, MSATs, 
Midwest ISO, NRECA and TAPS.
---------------------------------------------------------------------------

    438. MSATs argues that distinguishing between reliability and 
economic projects in the context of transmission planning is 
inconsistent with the concept of long-term firm transmission rights. 
MSATs asserts that firm transmission rights are economic rights that 
are intended to insulate holders from the economic consequences of 
congestion, and building and maintaining the transmission capacity 
needed to honor multi-year firm transmission rights may or may not be 
necessary to meet applicable reliability criteria. MSATs adds that, 
conversely, planning and constructing transmission facilities based 
solely on reliability criteria may not ensure the transmission capacity 
needed to honor long-term firm transmission rights. Thus, MSATs states 
that the distinction between economic and reliability projects is 
directly at odds with the type of transmission planning that is needed 
to honor long-term firm transmission rights.
    439. Similarly, IPL states that the Commission should separately 
address physical delivery risk and financial risks stemming from 
congestion charges because the two risks are substantially different 
and efforts to address these risks that do not distinguish between them 
are likely to be counterproductive. IPL states that the Commission 
should not attempt to use financial transmission rights to provide an 
incentive toward investment by transmission owners because the 
Commission's goal of ensuring that necessary upgrades are performed is 
better addressed separately from congestion charge hedging. In IPL's 
view, congestion charge hedging is the singular legitimate purpose of a 
financial transmission rights mechanism.
    440. IPL states that the Commission and the transmission 
organizations are undertaking a number of efforts to ensure that 
delivery risk is mitigated through proper transmission planning and 
expansion. IPL states that these efforts, which have no direct 
connection with allocations of long-term financial transmission rights, 
are the appropriate fora in which to address mitigating delivery risk 
by making sure adequate transmission infrastructure is available to 
meet the reasonable delivery needs of load serving entities and others.
    441. Midwest ISO states that transmission upgrades and expansion 
should be dictated by the transmission planning studies that ensure 
deliverability of generation to serve load, not participants' firm 
transmission right nominations. However, in response, APPA states that 
long-term firm transmission rights are intended to ensure exactly that: 
deliverability of generation to serve load on a specific resource-to-
load basis, and at a reasonably ascertainable transmission cost that is 
not subject to volatile transmission congestion. According to APPA, 
since transmission planning and long-term firm transmission rights are 
both intended to ensure deliverability of generation to load, it is 
absolutely appropriate to take account of long-term firm transmission 
rights in an RTO's transmission planning process. In addition, NRECA 
states that it is impossible to square Midwest ISO's comment with the 
terms of FPA section 217(b)(4). According to NRECA, if that section 
means anything, it is that public utility transmission providers must 
plan and expand the transmission grid so as to enable load serving 
entities to obtain long-term firm transmission rights.

EPAct 2005 Requirements for Transmission Planning and Expansion

    442. Some commenters argue that EPAct 2005 requires the Commission 
to adopt specific transmission planning procedures as part of this 
rulemaking or another proceeding.\134\ For example, National Grid 
claims that EPAct 2005 section 1233(b) requires the Commission to 
address how it intends to implement section FPA 217(b)(4) and not just 
the portions of FPA section 217 (b)(4) that speak to long-term 
transmission rights. To fulfill its statutory obligation, National Grid 
submits that the Commission should adopt a set of clear guidelines for 
transmission planning and expansion along with its proposed guidelines 
for long-term transmission rights. If the Commission does not adopt 
planning guidelines in its Final Rule in this proceeding, National Grid 
recommends that the Commission state how it intends to discharge its 
obligations under the first sentence of FPA section 217(b)(4) and EPAct 
2005 section 1233(b) to assure adequate planning. According to NRECA, 
FPA section 217(b)(4) does not merely require the provision of long-
term firm transmission rights; it requires the Commission to facilitate 
the planning and expansion of transmission facilities. In this regard, 
NRECA states that public utility transmission providers should be 
required to conduct open joint transmission planning processes that 
allow all load serving entities to participate on a comparable basis to 
public utility transmission providers. NRECA adds that these planning 
processes should accommodate both reliability and economic needs.
---------------------------------------------------------------------------

    \134\ See, e.g., National Grid, NRECA, MSATs, TANC and Reliant.
---------------------------------------------------------------------------

    443. In its reply comments, MSATs states that the Commission should 
identify key attributes that should be

[[Page 43612]]

incorporated into the RTO's planning process.
    444. Reliant recommends that the Commission undertake a parallel 
rulemaking to address the long-term needs of customers outside of 
organized markets. If the Commission chooses not to proceed with such a 
separate rulemaking, Reliant urges the Commission to utilize Docket No. 
RM05-25-000, Preventing Undue Discrimination and Preference in 
Transmission Services.
    445. Taking a contrary view, NYISO states that section 217(b)(4) 
should not be interpreted as mandating the overhaul of existing ISO/RTO 
transmission planning and expansion processes. NYISO notes that, with 
respect to New York, the Commission has approved a robust and 
transparent planning process that calls for stakeholder participation 
and input, and the NYISO's Comprehensive Reliability Planning Process 
is undertaking its first comprehensive review of the reliability needs 
of the New York bulk power system. NYISO asserts that making wholesale 
changes to this process would be premature and unnecessary.
Requirement for Filing Transmission Plans
    446. Some commenters state that the Commission should require 
transmission organizations to file their transmission planning 
protocols and their most recent transmission plans as part of their 
compliance filings in this proceeding.\135\ APPA states that they 
should be required to explain in their long-term firm transmission 
right filings how those protocols and plans will take into account the 
need to accommodate the allocated long-term firm transmission rights 
for their full terms and will ensure the construction of any 
transmission facilities required to support them. APPA argues that if 
the Commission believes that this showing is not persuasive, then the 
transmission organization should be required to take action to revise 
its transmission planning protocol. However, APPA recommends that such 
action be undertaken in a separate proceeding so as not to delay 
initial implementation of long-term firm transmission rights. Also, 
TAPS and NCPA submit that for those transmission organizations that use 
transmission owner transmission plans as inputs for the transmission 
organization's plan, the transmission owners should be required to make 
a similar filing. However, in response to APPA, MSATs states that the 
type of review contemplated by the APPA would be administratively 
burdensome and unlikely to prove beneficial. Also, Midwest ISO notes 
that such plans are already available as public documents.
---------------------------------------------------------------------------

    \135\ See, e.g., APPA, TAPS, NCPA, BPA and SMUD.
---------------------------------------------------------------------------

    447. BPA expresses support for the principle that transmission 
organizations should file their planning and expansion procedures and 
specific plans for informational purposes with the Commission. BPA 
believes that doing so helps assure that information on planning is 
widely available to interested persons. However, BPA states that 
Commission approval of such informational filings should not be 
required.
    448. Many commenters argue strongly that the Commission should not 
impose additional filing requirements on the transmission 
organizations.\136\ For example, SDG&E argues that unless Commission-
jurisdictional entities have an opportunity to review the similar plans 
and procedures of non-jurisdictional transmission entities, the latter 
entities could obtain an unfair competitive advantage over the former 
entities. Moreover, SDG&E states that transmission planning is 
resource-intensive, and the effort required to plan, site, design and 
build new transmission is enormous. SDG&E asserts that the resources 
allocated to those efforts should not be diverted to further regulatory 
review that is not proven to be needed to ensure the viability of long-
term firm transmission rights associated with the planned transmission 
lines.
---------------------------------------------------------------------------

    \136\ See, e.g., SDG&E, MSATs, Midwest ISO, IPL, NYISO, CAISO, 
SoCal Edison, PG&E, ISO-NE and PJM.
---------------------------------------------------------------------------

    449. ISO-NE views a requirement to file its system expansion plans 
as a significant departure from past Commission practice. ISO-NE argues 
that similar types of highly technical studies generally have not been 
subject to a filing requirement. For example, ISO-NE points out that 
although interconnection studies represent a type of study akin to the 
core of system expansion plans, they have never been filed with the 
Commission.
    450. PJM states that it currently is required to file the proposed 
cost allocations resulting from its regional transmission expansion 
plan with the Commission, and the proposed allocations are subject to 
Commission approval. PJM recommends that the Commission not require 
filing of the entire plan absent being presented with a legitimate 
issue. In reply comments, NRECA urges the Commission to require that 
such plans be filed, even if only for informational purposes, to 
monitor compliance with the Final Rule in this proceeding and section 
217(b)(4).
Meeting Native Load Requirements
    451. In response to the request for comments in the NOPR on whether 
the definition of native load service obligation in section 1233 of 
EPAct 2005 is the same as the approach the Commission took in Order No. 
888, some commenters addressed the subject of how that preference has 
been applied in organized electricity markets.\137\ APPA states that 
application of the native load preference set out in new FPA sections 
217(b)(1) and (2) to the various RTO regions is governed by new FPA 
sections 217(c) and (f). APPA asserts that these sections were hard-
fought and carefully negotiated as to each RTO region, and states that 
the Commission should honor the legislative compromises embodied in 
those sections.
---------------------------------------------------------------------------

    \137\ See, e.g., APPA, PJM, AEP, Midwest TOs and Santa Clara.
---------------------------------------------------------------------------

    452. PJM states that, within PJM, native load receives a preference 
to system capacity by virtue of being allocated auction revenue rights, 
which can be converted to firm transmission rights at the discretion of 
the holder of transmission rights, Midwest TOs believes the NOPR may 
result in reduced firm transmission rights for native load customers 
who receive firm transmission rights in the annual assignment process 
currently used by the Midwest ISO. Midwest TOs recommends that the 
Commission clarify that it intends for all load serving entities, 
including vertically integrated utilities that are just using existing 
generation to serve their loads, to be eligible to seek long-term firm 
transmission rights. According to Midwest TOs, to do otherwise would be 
to discriminate against the native load of vertically integrated 
companies.
Commission Conclusion
    453. The Commission will require that each transmission 
organization with an organized electricity market implement a 
transmission system planning process that will accommodate the long-
term transmission rights that are awarded by ensuring that they remain 
feasible over their entire term. FPA section 217(b)(4) requires the 
Commission to exercise its authority under the FPA in a manner that 
facilitates the planning and expansion of transmission facilities, and 
to enable load serving entities to obtain long-term firm transmission 
rights. To implement that section in a transmission organization with 
an organized

[[Page 43613]]

electricity market, as required by section 1233(b) of EPAct 2005, we 
believe that the transmission organization must plan its system to 
ensure that allocated or awarded long-term firm transmission rights are 
feasible.\138\ FPA section 217(b)(4) itself, by including both the 
requirement to facilitate planning and expansion and the requirement to 
provide long-term transmission rights, supports the Commission's 
authority to impose this requirement. Moreover, given the full funding 
requirement of guideline 2, appropriate planning for long-term firm 
transmission rights is essential to ensure that any charges to other 
market participants to cover revenue shortfalls do not become unjust, 
unreasonable or unduly discriminatory.
---------------------------------------------------------------------------

    \138\ This is not to suggest that we are requiring any 
``obligation to build'' or other obligation that does not already 
exist under Order No. 888.
---------------------------------------------------------------------------

    454. To implement this requirement, we will require each 
transmission organization to include in its compliance filing an 
explicit statement of how its planning and expansion practices will 
take into account the need to accommodate allocated or awarded long-
term firm transmission rights for their full terms, including the 
construction of transmission facilities (as well as a basis for 
allocating cost responsibility) that may be needed to support them. We 
will also require that each transmission organization make its planning 
and expansion practices and procedures publicly available, including 
both the actual plans and any underlying information used to develop 
the plans. Also, any holder of long-term firm transmission rights that 
believes that the transmission organization is not fulfilling its 
obligation to ensure the adequacy of the long-term firm transmission 
rights over their full term can seek relief through the transmission 
organization's internal complaint procedures or by filing a complaint 
with the Commission. The Commission will address problems on a case-by-
case basis, and if necessary, require the transmission organization to 
revise its planning and expansion practices to better accommodate long-
term firm transmission rights.
    455. The Commission notes that, to meet the requirements that we 
are imposing here, as well as the full-funding requirements of 
guideline (2), a transmission organization must plan its system such 
that a long-term firm transmission right, once awarded, remains viable 
throughout its full term without requiring the long-term firm 
transmission right holder to pay directly for any additional 
transmission upgrades that may be required to maintain the feasibility 
of the right over its term. Accordingly, the transmission organization 
must include, along with upgrades needed for system reliability, any 
upgrades needed to support the long-term firm transmission right over 
its full term in its base plan for system expansion. While this may 
require changes in the transmission organization's planning protocols, 
we disagree with MSATs that it requires the transmission organization 
to draw a distinction between economic and reliability projects that is 
incompatible with transmission planning. Indeed, the transmission 
organization may choose to make no distinction between reliability 
upgrades and those needed to maintain the feasibility of long-term firm 
transmission rights.
    456. In addition, we note that when a transmission customer enters 
into a long-term power supply arrangement and is willing to pay for any 
transmission expansion or upgrades which may be necessary in order to 
make long-term firm transmission rights feasible over the entire term 
of the contract, that expansion or upgrade must be incorporated into 
the transmission organization's planning process. This will require 
that the expansion plans that transmission owners submit to the 
transmission organization incorporate any expansions necessitated by 
such long-term supply arrangements. We believe that it is important for 
the regional planning process to take account of any upgrades or 
expansions of the transmission system that may be required to ensure 
FTRs needed to support long-term power supply arrangements are 
available.
    457. The Commission agrees with commenters such as NRECA that 
observe that FPA section 217(b)(4) does not merely require the 
provision of long-term firm transmission rights; it requires the 
Commission to facilitate the planning and expansion of transmission 
facilities. However, the Commission is considering issues concerning 
its broader mandate to exercise its FPA authority to facilitate 
planning and expansion (which applies to all regions) to Docket No. 
RM05-25-000, the Order No. 888 OATT reform rulemaking.

G. Alternative Designs for Long-Term Firm Transmission Rights

    458. We noted in the NOPR that FPA Section 217(b)(4) recognizes 
that there may be alternative designs for long-term firm transmission 
rights. The NOPR noted that for most transmission organizations, the 
most straightforward design for long-term transmission rights is likely 
to be an extension of their existing design for allocation of auction 
revenue rights or FTRs, perhaps with some modifications of certain 
rules and procedures (such as creditworthiness standards and 
transmission planning). The NOPR discussed, and we did not preclude, 
alternative designs for such rights, including departures from the 
existing market designs.
Comments
Clarification of Terms
    459. Several commenters argue that the Commission is unclear about 
its use of the terms ``firm transmission rights'' and ``financial 
transmission rights.'' IPL states that section 217(b)(4) uses the term 
``firm'' to mean physical rights, and financial to refer to purely 
financial rights. In contrast, the NOPR appears to use the terms 
interchangeably. IPL states that ``resolution of this confusion is 
critical because the NOPR dually implies that it is (a) proposing 
certain modifications to an existing financial transmission rights 
paradigm, and (b) that it is imposing a physical rights structure in 
organized electricity markets where that concept is anathema to 
[LMP].'' \139\ National Grid also states that the NOPR is unclear as to 
the status of whether firm means solely physical rights and asks for 
clarification that the Commission is not implying a preference for 
physical rights. Reliant asks that the Commission clarify that by firm 
transmission rights, it does not mean physical rights, but rather that 
financial rights in LMP markets are equivalent to firm rights.
---------------------------------------------------------------------------

    \139\ Reply Comments of IPL at 5.
---------------------------------------------------------------------------

    460. In contrast, TANC argues that the firm transmission rights 
cited in section 217(b)(4) were intended to be physical rights and that 
even though the statute recognizes financial transmission rights, 
Congress sought to determine that it favors another methodology, namely 
physical transmission rights.
Physical versus Financial Rights
    461. In addition, a number of commenters also had views on whether 
long-term firm transmission rights should be physical or financial 
rights. Most commenters assumed that the rights under consideration in 
most organized markets are financial rights without having to make the 
requirement explicit, as reflected in their comments on auction revenue 
rights and FTRs. However, a number of parties, including CAISO, EEI, 
IPL, National Grid, NEPOOL, NU, NSTAR, NYISO, Reliant, SDG&E and SoCal 
Edison asked that the Commission be more explicit that the rights under 
consideration should be financial rights only, in particular in

[[Page 43614]]

markets that currently have financial rights.
    462. These commenters argue that physical rights would have 
deleterious effects on the LMP markets. For example, ISO-NE argues that 
introducing physical scheduling rights would create an economic loss 
for the region because of less efficient dispatch of resources, 
significant administrative burdens for system users and the ISO, and 
new seams with the ISO's region. National Grid observes that holders of 
physical rights would be insulated from redispatch costs, which would 
be inequitably shifted to holders of financial rights or to 
transmission owners.
    463. PG&E argues that while it supported a financial rights model 
for CAISO, the approach of the Final Rule should allow, but not 
require, alternative designs to recognize that stakeholders in 
different markets may prefer different cost-benefit balances. PJM 
similarly urges that the Final Rule clarify that respective regions 
should determine the nature of the transmission right, whether physical 
or financial.
    464. Several commenters supporting financial rights are also 
concerned that the Final Rule does not establish a mix of physical and 
financial rights.\140\ NU argues that a ``carve-out'' for physical 
long-term rights would reduce available capacity for shorter-term FTRs 
and distort the auction market for them. NYISO argues that ``financial 
rights models can bring as much certainty as physical rights while 
allowing for a fuller and more efficient utilitization of transmission 
capacity.'' \141\ PJM, while supporting regional flexibility to design 
physical or financial rights, urges that, with the exception of 
approved grandfathered agreements, there should not be a mix of 
physical and financial rights as a bifurcated system would be 
unworkable. EEI cautions that a move toward long-term physical rights 
for some market participants would undermine the competitive markets.
---------------------------------------------------------------------------

    \140\ These include BP Energy, ISO-NE, NU, NYISO, and PJM.
    \141\ Reply Comments of NYISO at 7.
---------------------------------------------------------------------------

    465. NYTOs suggested that the Commission establish a regulatory 
definition of long-term transmission right that clarifies that such a 
right encompasses both physical and financial rights to the use of the 
transmission system. Such a definition should state that in organized 
electricity markets, market participants have the physical right to 
schedule but then receive financial rights to hedge congestion charges.
    466. Several parties, including LADWP, Modesto, NRECA, Redding, 
SMUD, Santa Clara, and TANC, argue that long-term rights should be 
physical rights or rights with some characteristics of physical rights. 
For example, LADWP states that the rights should have certain 
characteristics, including the following: the right to schedule power 
up to the holder's share of the transmission facility rating; the 
ability to market non-scheduled transmission capacity to others; a 
fixed charge responsibility not otherwise dependent on operating 
conditions; losses provided for as in the project agreement; and not 
subject to rules set by non-participants. LADWP argues that these 
assurances along with proper planning and investment are necessary to 
provide the certainty necessary for transmission investment.
    467. Santa Clara states that no financial instrument can achieve a 
truly effective hedge against congestion costs, and that only explicit 
physical rights (denominated solely in terms of MW of capacity) can 
secure a load serving entity against transmission costs. Santa Clara 
thus proposes that long-term firm transmission rights are physical 
rights. SMUD argues that physical rights coupled with resale and 
assignment rights (akin to the gas pipeline open access model) could 
capture most of the efficiencies of the financial rights/LMP model. In 
the west, Redding and SMUD argue that CAISO's pending implementation of 
a financial rights market make it the only entity in the region to use 
that model and will create seams that diminish trade with the rest of 
the region.
    468. Santa Clara and TANC argue that physical transmission rights 
that mirror OATT rights have more stable pricing and allow holders to 
hedge the risk of fluctuating congestion charges. Hence, they will 
facilitate planning and construction of new generation facilities and 
other long-term supply arrangements.
    469. In contrast to some comments noted above, several supporters 
of physical rights argued that systems that mix physical and financial 
rights are necessary. LADWP supports the co-existence of financial and 
physical rights, such as the CAISO's MRTU proposal to reserve capacity 
on its interties for Existing Transmission Contracts and Transmission 
Ownership Rights. LADWP also proposes that holders of such rights would 
be insulated from congestion costs when prices reverse direction. TANC 
argues that physical transmission rights of various types are already 
accommodated in several transmission organization markets that have 
financial rights, for example, as grandfathered rights.
    470. Some commenters noted that in some organized markets, some 
degree of long-term physical rights have already been grandfathered. 
Coral Power is concerned that the scope of grandfathered rights could 
be ``needlessly'' expanded. DC Energy argues that in New York ISO, such 
rights have already accommodated those with the greatest contractual 
rights to long-term transmission service.
Alternative Types of Financial Rights
    471. Several commenters, including Allegheny, Constellation, EEI, 
Kentucky PSC, and PG&E, stress that FTR option rights should not be 
available in the allocation of long-term firm transmission rights. This 
is because such option rights encumber too much transmission capacity, 
resulting in a reduction in the quantity of rights available. Instead, 
the long-term transmission rights should be specified as FTR obligation 
rights. Some of these commenters would be willing to accommodate 
options at a later date. NEPOOL states that the Commission should 
neither require nor preclude options.
    472. APPA agrees that FTR option rights would likely be unworkable, 
but proposes instead its concept of a ``hybrid long-term transmission 
right'' that would only provide congestion revenues in the hours that 
the holder of the right schedules transmission and up to the quantity 
scheduled. Such a right would also not require obligation payments in 
the event that the prices at the locations specified in the right 
change direction (that is, a higher price at the injection point than 
at the withdrawal point). TAPS proposes that long-term rights are 
``dispatch-contingent'' FTRs, which would only pay revenues when the 
generation resource is dispatched. In all other hours, the FTR would 
not pay revenues, nor require obligation payments.
Commission Conclusion
Clarification of Definitions and Choice Between Financial and Physical 
Rights
    473. As noted elsewhere in the Final Rule, we interpret Section 
217(b)(4) to require that load serving entities be able to obtain long-
term firm rights, whether as physical rights or as equivalent financial 
rights. In the discussion of guideline (2), we interpreted the firmness 
requirement in the financial rights context to include a fixed (MW) 
quantity over the life of the right and stability in the revenue stream 
from the right through full funding. This roughly

[[Page 43615]]

parallels the quantity and financial stability of long-term physical 
transmission contracts. Because we believe that under our guidelines 
financial rights are as firm as physical rights outside organized 
electricity markets, we have used the terms firm and financial 
interchangeably at times. We have not used the term firm to imply a 
preference for physical rights.
    474. We will not require that long-term firm transmission rights in 
organized electricity markets be physical or financial rights. However, 
we also will not require that transmission organizations with existing 
or approved designs for financial transmission rights create a new 
long-term physical right, such as an Order No. 888 network service 
right, upon request of a load serving entity. Instead, as discussed in 
our guidelines, we have sought to provide guarantees of financial 
``firmness'' alongside the existing physical firmness of transmission 
scheduling in the organized electricity markets (that is, decreased 
frequency of TLRs).
Alternative Types of Financial Rights
    475. While many commenters have warned against allowing allocation 
of long-term option financial rights, no commenter has requested such 
rights. We agree with commenters that allocation of long-term financial 
transmission option rights would present severe equity problems in most 
organized electricity markets. At best, if all eligible parties 
requested option rights, the set of allocated rights would be greatly 
reduced compared to an allocation of obligation rights. An alternative 
approach to obtaining options would be to allocate long-term auction 
revenue rights as obligations and let entities purchase option rights 
through an auction.
    476. Schedule-contingent or dispatch-contingent financial 
transmission rights could present similar equity problems to options in 
allocation and, unlike option FTRs, possibly create poor scheduling or 
dispatch incentives.\142\ These types of contingent rights could 
present revenue adequacy problems because while they are not paid when 
they do not schedule or dispatch, if they are base-load plants this 
will likely only take place when the prices at the injection and 
withdrawal locations are reversed. That is, the unit will not be 
scheduled when it is needed to make counterflow payments to support the 
revenue adequacy of other transmission rights. As a result, the 
transmission organization would either have to model the rights as 
options in the allocation of transmission rights or make arbitrary 
decisions to limit the quantity of rights it allocates. Further, 
dispatch-contingent rights could have incentives for inefficient 
dispatch, since the right is only paid when a source generator produces 
output. In that case, the holder of the right will have less 
flexibility to purchase cheaper power from the spot market in the 
presence of congestion because it will lose the revenues from its 
rights.
---------------------------------------------------------------------------

    \142\ A ``contingent'' financial transmission right for the 
purposes of this Final Rule is a right that only collects revenues 
or owes payments (corresponding to the source and sink points and 
quantities specified in the right) under certain conditions. These 
rights differ from obligation FTRs in the following ways. A 
schedule-contingent right would only be eligible to collect revenues 
or obliged to make payments if it was scheduled in the day-ahead 
market of the transmission organization. A dispatch-contingent right 
would only be eligible to collect revenues or obliged to make 
payments if it produced energy in real-time (i.e., was dispatched). 
For further discussion see, e.g., Comments of TAPS.
---------------------------------------------------------------------------

H. Miscellaneous Comments

    477. SMUD states that the uncertainty associated with marginal loss 
charges is at least as big a hedging problem as that posed by 
congestion charges. SMUD argues that marginal loss pricing is not 
required under the locational marginal pricing model. CMUA, Santa Clara 
and SMUD urge the Commission to direct that transmission organizations 
either eliminate marginal loss charges or offer transmission customers 
with long-term rights the same full hedge against loss charges as 
against congestion charges.
Commission Conclusion
    478. We do not interpret section 217(b)(4) as addressing marginal 
loss charges. Each transmission organization operating an organized 
electricity market has established methods for refunds of marginal loss 
surplus based on stakeholder discussion. We will not overturn those 
decisions here.

I. Implementation of the Final Rule and Compliance Issues

    479. In the NOPR, the Commission proposed to direct each public 
utility that is a transmission organization with an organized 
electricity market, within 180 days of the publication of a Final Rule 
in the Federal Register, to either: (1) File with the Commission tariff 
sheets and rate schedules that make available long-term firm 
transmission rights that are consistent with the guidelines set forth 
in section (d) of the Final Rule; or (2) file with the Commission an 
explanation of how its current tariff and rate schedules already 
provide for long-term firm transmission rights that are consistent with 
the guidelines set forth in paragraph (d) of the Final Rule. We stated 
our intent that during this 180-day period, transmission organizations 
subject to the rule will work with their stakeholders (through their 
usual stakeholder process) to develop a long-term firm transmission 
right that will harmonize prevailing market design with the guidelines 
set forth in the Final Rule. For any transmission organization that is 
approved by the Commission after the 180-day time period, the 
Commission proposed that the transmission organization be required to 
satisfy the requirements of the Final Rule prior to commencing 
operation.
Comments
    480. APPA, New England Public Systems, and Vermont DPS all support 
the Commission's proposed implementation procedures. New England Public 
Systems states that if any transmission organization determines that it 
will not be able to meet the 180-day timetable, the Commission should 
require that it submit a detailed explanation of the cause of the delay 
and a detailed schedule for completing and submitting its compliance 
filing. PG&E supports the compliance filing timeline, and suggests that 
those deadlines be expanded to address due dates that would follow the 
future adoption of market-based congestion management programs by a 
transmission organization. PG&E also recommends that a parallel rule be 
adopted for long-term firm transmission rights in markets that do not 
use market-based congestion management systems.
    481. SMUD argues that the Commission's proposed compliance 
procedures contain an insufficient directive to ensure timely 
compliance, particularly because it would allow transmission 
organizations to submit proposed tariffs with no proposed effective 
dates. Accordingly, SMUD states that the Commission should issue a 
Final Rule by August 8, 2006, and clarify that compliance tariffs and 
rate schedules must be effective 60 days after their filing, to ensure 
that long-term firm transmission rights are available within about a 
year.
    482. Several commenters, including AF&PA, IPL, ISO-NE, NEPOOL and 
OMS, argue that the 180-day deadline proposed in the NOPR for 
transmission organizations to make filings in compliance with the Final 
Rule is ``unrealistic'' given the complexity of the issues involved and 
the transmission organizations' other ongoing projects. IPL suggests 
that the Commission lengthen the time for stakeholder procedures and 
compliance filings to 365 days, followed by an additional 365-day 
period during which

[[Page 43616]]

the transmission organizations will implement their long-term rights 
mechanism. IPL also suggests that the Commission allow transmission 
organizations to phase in long-term rights over time. OMS requests that 
the Commission permit transmission organizations to report on the 
status of their stakeholder procedures in 180 days, and then set a 
specific filing date for tariff changes based on that status report.
    483. ISO-NE also requests that the Commission lengthen the 180-day 
time period for developing and filing a proposal to comply with the 
Final Rule, stating that a strict requirement to formulate a long-term 
firm transmission right design within that time frame could present 
insurmountable challenges since it is also in the process of developing 
other important market reforms as part of its Wholesale Market Plan.
    484. NYISO states that it will likely be able to meet the proposed 
180-day deadline, provided the Commission's Final Rule clarifies that 
only limited changes to the current market design need to be 
considered. It explains that it may need additional time, however, if 
the Final Rule requires more modifications of existing systems. New 
York Transmission Owners suggest that if changes to the NYISO market 
are required, the Commission should allow it to develop a procedure to 
phase in such changes to avoid market disruptions that could affect the 
availability of short-term and intermediate transmission rights.
    485. CAISO notes in its initial comments that it faces unique 
challenges in implementing long-term firm transmission rights because 
it is in the process of implementing a complete market redesign, which 
includes a transition to LMP.\143\ To implement this redesign by 
November 2007, CAISO states that it will be difficult, if not 
impossible, to expand the scope of the initial market design. According 
to CAISO, to adopt long-term transmission rights before the start of 
the new market it would be necessary to develop a ``hybrid'' instrument 
that could be used in both the current market and new market. 
Developing this instrument, it states, would divert resources from its 
effort to implement the new market. Accordingly, CAISO asks that it not 
be required to implement, prior to the start of its redesigned market, 
any ``hybrid'' long-term transmission rights product.
---------------------------------------------------------------------------

    \143\ This proposed market redesign was filed on February 9, 
2006 in Docket No. ER06-615-000.
---------------------------------------------------------------------------

    486. Furthermore, given its current process and timeline for 
implementing the market redesign, CAISO states that it most likely 
would not be able to fulfill the requirements of the Final Rule under 
the proposed compliance schedule. Accordingly, it states that the 
Commission should not require it to have long-term FTRs in place until 
at least one year after the start of its new markets. CAISO notes that 
its market participants lack experience with short-term financial 
rights. As a result, it contends that it could not have a meaningful 
stakeholder debate on the design and implementation of long-term 
rights, and urges the Commission to allow it the same opportunity to 
gain experience with LMP that other transmission organizations have 
had. Furthermore, it argues that it is important that market 
participants have a sufficient demonstration of the financial rights 
they will be able to receive under the market redesign before long-term 
rights are implemented.\144\ As a result, CAISO seeks sufficient time 
for stakeholder discussions on alternate designs, and asks that it not 
be required to implement long-term financial rights before having at 
least one year of experience with LMP markets.
---------------------------------------------------------------------------

    \144\ CAISO notes that it has conducted studies of the financial 
rights allocation, but that a dry run with market participants under 
the allocation rules filed with the Commission would be more 
accurate. It does not expect to complete such a dry run before the 
first quarter of 2007.
---------------------------------------------------------------------------

    487. SoCal Edison, noting the same concerns regarding the timing of 
CAISO's market redesign, argues that the Commission should revise its 
proposed compliance procedures to require a transmission organization 
that has filed a complete redesign of its organized electricity market 
to make a proposal for implementing long-term firm transmission rights 
after the revised market becomes effective, instead of within 180 days 
of the final rule. CPUC and SDG&E also express concerns with regard to 
the timing of CAISO's implementation of long-term firm transmission 
rights. CPUC agrees with CAISO that it should be given a period of time 
to gain experience with LMP before implementing long-term rights, while 
SDG&E states that the Commission should, in the Final Rule, require 
CAISO to include long-term rights in its planned second release of the 
market redesign.
    488. Conversely, CMUA, APPA and NCPA all suggest that accommodating 
long-term rights should be more easily accomplished in CAISO because it 
is not an established LMP market, and that it would be easier and less 
expensive to incorporate long-term rights into the market design rather 
than retrofit the market later. Nevertheless, CMUA opposes blanket 
application of the 180-day timeline to CAISO, and (along with TANC) 
urges the Commission to address CAISO's implementation schedule for 
long-term firm transmission rights as part of its consideration of 
CAISO's market redesign filing in Docket No. ER06-615-000.\145\
---------------------------------------------------------------------------

    \145\ APPA states that it defers to this proposal.
---------------------------------------------------------------------------

    489. Several commenters, including PG&E, SMUD, and Transmission 
Agency of Northern California, oppose CAISO's request for deferral and 
argue that the Final Rule should apply to California upon its 
implementation of LMP as part of its market redesign. PG&E argues that 
CAISO's reasoning that delaying deferral because it has not relied on 
short-term rights for as long as other transmission organizations 
``stands * * * EPAct on its head'' and perpetuates the problem driving 
Congress to enact section 217(b)(4) of the FPA and section 1233(b) of 
EPAct 2005.\146\ SMUD (and others) note that CAISO was directed by the 
Commission to develop a long-term firm transmission service more than 
eight years ago, and has not yet proposed such an option (including in 
its recent market redesign filing).\147\ To avoid further delay, SMUD 
states that if a transmission organization cannot provide a long-term 
financial transmission right product within 180 days, it should be 
required to offer physical path arrangements until it can develop a 
financial product that meets the requirements of section 217(b)(4) and 
the Commission's guidelines.\148\ SMUD also asserts that CAISO wrongly 
assumes both that implementing long-term rights will cause a delay in 
the start of its redesigned markets, and that there is urgency in 
implementing the market redesign.
---------------------------------------------------------------------------

    \146\ Reply Comments of PG&E at 17.
    \147\ See, e.g., Comments of SMUD at 40-41; Reply Comments of 
CMUA at 3, citing Pacific Gas and Electric Company, et al., 80 FERC 
] 61,128 at 61,427 (1997).
    \148\ According to SMUD, CAISO can implement physical long-term 
rights immediately, and in fact has done so for the Western Area 
Power Administration.
---------------------------------------------------------------------------

Commission Conclusion
    490. The Commission will adopt the implementation timetable 
proposed in the NOPR. We clarify what we expect transmission 
organizations subject to this Final Rule to file compliance proposals 
within 180 days of its effective date. Specifically, they must file 
proposed tariff sheets and rate schedules that would make available 
long-term firm transmission rights that satisfy each of the guidelines 
in the

[[Page 43617]]

Final Rule. We recognize that the implementation of long-term firm 
transmission rights presents difficult issues, and that significant 
effort will be required to file compliance proposals within 180 days. 
Congress directed the Commission to act quickly, however, requiring in 
section 1233(b) of EPAct 2005 that we issue this Final Rule within one 
year of the legislation's passage. We believe that this directive shows 
Congress's intent that long-term firm transmission rights be made 
available as soon as possible.
    491. Commenters (particularly ISO-NE) express concern that 
implementing long-term firm transmission rights on the proposed 
compliance timetable could negatively impact the ability of 
transmission organizations to complete work on other initiatives. We 
encourage transmission organizations to explore ways to reorder their 
priorities to ensure that this important Congressional directive is 
fulfilled. We will not rule out at this time the possibility that 
transmission organizations may seek permission from the Commission to 
reorder its schedule for market design changes, tariff changes or other 
projects that were directed by the Commission.
    492. Some commenters suggest that the Commission permit 
transmission organizations to phase in tariff and market rule changes 
to introduce long-term firm transmission rights. We cannot decide here 
whether any particular proposal to phase-in long-term firm transmission 
would be just and reasonable. We remind transmission organizations 
again, however, that Congress intended the implementation of long-term 
firm transmission rights to occur as soon as possible. Any proposal to 
phase-in long-term firm transmission rights will be considered in light 
of this statutory directive.
    493. We note that the final regulations require transmission 
organizations to file tariff sheets and rate schedules that make 
available long-term firm transmission rights that satisfy each of the 
guidelines within the 180-day timeframe. While SMUD asks us to specify 
that such tariff sheets and rate schedules be effective 60 days after 
filing, we do not believe it would be appropriate to prescribe 
effective dates now. Transmission organizations may need to synchronize 
the availability of long-term firm transmission rights with their 
existing allocation schedules. They may also need to take additional 
steps, such as making necessary software or procedural changes, to 
implement the rights after the Commission acts on their compliance 
proposals. As a result, we will consider effective dates on a case-by-
case basis, again in light of Congress's intent that long-term firm 
transmission be implemented as soon as possible.
    494. Additionally, we clarify that for transmission organizations 
with organized electricity markets that are formed after the effective 
date of this Final Rule, we intend that such organizations will provide 
long-term firm transmission rights satisfying the guidelines in the 
regulations. We have made revisions to the proposed regulatory text to 
clarify that transmission organizations approved by the Commission in 
the future will be required to satisfy this Final Rule.
    495. The Commission will require that all existing transmission 
organizations, including CAISO, make proposals to comply with the Final 
Rule on the same timetable. While we understand CAISO's concerns 
regarding its pending market redesign efforts, we cannot address in 
this rulemaking of general applicability any possible plans for the 
phase-in or delayed implementation of long-term firm transmission 
rights. Even if we could, CAISO has not provided any timetable in its 
comments for implementing long-term firm transmission rights as 
required by section 217(b)(4) of the FPA and section 1233(b) of EPAct 
2005. Therefore, CAISO must work with its stakeholders to develop and 
submit a compliance filing within the timetable prescribed in this 
Final Rule, and the Commission will consider any issues specific to 
CAISO or any proposals offered in its compliance filing for 
implementing long-term firm transmission rights in CAISO. Once again, 
we remind transmission organizations and their stakeholders, including 
CAISO, that Congress intends that the introduction of such rights occur 
as soon as possible.

III. Information Collection Statement

    496. The Office of Management and Budget (OMB) regulations require 
approval of certain information collection requirements imposed by 
agency rules. Upon approval of a collection(s) of information, OMB will 
assign an OMB control number and an expiration date. Respondents 
subject to the filing requirements of this rule will not be penalized 
for failing to respond to these collections of information unless the 
collections of information display a valid OMB control number. This 
Final Rule amends the Commission's regulations to implement some of the 
statutory provisions of section 1233 of EPAct 2005. Particularly, 
section 1233 of EPAct 2005 enacts a new section 217 of the FPA. New 
section 217(b)(4) requires the Commission to exercise its authority in 
a manner that facilitates the planning and expansion of transmission 
facilities to meet the reasonable needs of load serving entities to 
satisfy their service obligations, and enables load serving entities to 
secure long-term firm transmission rights to meet their service 
obligations. Section 1233(b) of EPAct 2005 directs that Commission to, 
by rule or order, implement this new provision in the FPA. This Final 
Rule requires transmission organizations with organized electricity 
markets to either file tariff sheets making long-term firm transmission 
rights available that are consistent with guidelines established by the 
Commission, or to make a filing explaining how their existing tariffs 
already provide long-term firm transmission rights that are consistent 
with the guidelines. Such filings will be made under Part 35 of the 
Commission's regulations. The information provided for under Part 35 is 
identified as FERC-516.
    497. The Commission \149\ submitted these reporting requirements to 
OMB for its review and approval under section 3507(d) of the Paperwork 
Reduction Act.\150\ In the NOPR, comments were solicited on the 
Commission's need for this information, whether the information will 
have practical utility, the accuracy of provided burden estimates, ways 
to enhance the quality, utility, and clarity of the information to be 
collected, and any suggested methods for minimizing the respondent's 
burden, including the use of automated information techniques. No 
comments were received on these issues. Therefore, the Commission is 
retaining the estimates provided in the NOPR.
---------------------------------------------------------------------------

    \149\ CFR 1320.13 (2005).
    \150\ 44 U.S.C. 3507(d) (2000).
---------------------------------------------------------------------------

    Burden Estimate: The Public Reporting burden for the requirements 
contained in the Final Rule is as follows:

[[Page 43618]]

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

    Total Annual hours for Collection: (Reporting + recordkeeping, (if 
appropriate) = 7,080 hours.
    Information Collection Costs: The Commission seeks comments on the 
costs to comply with these requirements. It has projected the average 
annualized cost to be the total annual hours of 7,080 times $150 = 
$1,062,000.
    Title: FERC-516 ``Electric Rate Schedule Filings.''
    Action: Proposed Collections.
    OMB Control No: 1902-0096.
    Respondents: Business or other for profit, and/or not for profit 
institutions.
    Frequency of Responses: One time to initially comply with the rule, 
and then on occasion as needed to revise or modify.
    Necessity of the Information: This Final Rule implements the 
Congressional mandate of the Energy Policy Act of 2005 to make long-
term transmission rights available in transmission organizations with 
organized electricity markets. This mandate addresses an identified 
need for transmission organizations with organized electricity markets 
to provide longer-term transmission rights that can aid load serving 
entities in financing long-term power supply arrangements to meet their 
service obligations. Making long-term firm transmission rights 
available will also provide increased certainty regarding the long-term 
costs of transmission service in organized electricity markets. As a 
result, long-term firm transmission rights will allow load serving 
entities to more effectively plan their power supply portfolios, and 
encourage load serving entities and other participants in organized 
electricity markets to make long-term investments in power supply 
arrangements.
    Internal review: The Commission has reviewed the requirements 
pertaining to transmission organizations with organized electricity 
markets and determined the proposed requirements are necessary to meet 
the statutory provisions of the Energy Policy Act of 2005.
    498. These requirements conform to the Commission's plan for 
efficient information collection, communication and management within 
the energy industry. The Commission has assured itself, by means of 
internal review, that there is specific, objective support for the 
burden estimates associated with the information requirements.
    499. Interested persons may obtain information on the reporting 
requirements by contacting: Federal Energy Regulatory Commission, 888 
First Street, NE., Washington, DC 20426 [Attention: Michael Miller, 
Office of the Executive Director, Phone: (202) 502-8415, fax: (202) 
273-0873, e-mail: michael.miller@ferc.gov]. Comments on the 
requirements of the Final Rule may also be sent to the Office of 
Information and Regulatory Affairs, Office of Management and Budget, 
Washington, DC 20503 [Attention: Desk Officer for the Federal Energy 
Regulatory Commission], e-mail: oira_submission@omb.eop.gov.

IV. Environmental Analysis

    500. The Commission is required to prepare an Environmental 
Assessment or an Environmental Impact Statement for any action that may 
have a significant adverse effect on the human environment.\151\ As we 
stated in the NOPR, the Commission has categorically excluded certain 
actions from this requirement as not having a significant effect on the 
human environment. Included in the exclusion are rules that do not 
substantially change the effect of legislation.\152\ This Final Rule 
falls within this categorical exemption because it implements the 
requirements of EPAct 2005 relating to long-term firm transmission 
rights in organized electricity markets. Accordingly, neither an 
environmental impact statement nor environmental assessment is 
required.
---------------------------------------------------------------------------

    \151\ Regulations Implementing the National Environmental Policy 
Act, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs. 
Preambles 1986-1990 ] 30,783 (1987).
    \152\ 18 CFR 380.4(2)(ii) (2005).
---------------------------------------------------------------------------

V. Regulatory Flexibility Act Certification

    501. The Regulatory Flexibility Act of 1980 \153\ generally 
requires a description and analysis of rules that will have significant 
economic impact on a substantial number of small entities. Most, if not 
all, of the transmission organizations to which the requirements of 
this Final Rule apply do not fall within the definition of small 
entities.\154\ Therefore, the Commission certifies that this Final Rule 
will not have a significant economic impact on a substantial number of 
small entities. Accordingly, no regulatory flexibility analysis is 
required.
---------------------------------------------------------------------------

    \153\ 5 U.S.C. 601-12 (2000).
    \154\ The RFA definition of ``small entity'' refers to the 
definition provided in the Small Business Act, which defines a 
``small business concern'' as a business that is independently owned 
and operated and that is not dominant in its field of operation. See 
15 U.S.C. 632 (2000).
---------------------------------------------------------------------------

VI. Document Availability

    502. In addition to publishing the full text of this document in 
the Federal Register, the Commission provides all interested persons an 
opportunity to view and/or print the contents of this document via the 
Internet through the Commission's Home Page (http://www.ferc.gov) and 

in the Commission's Public Reference Room during normal business hours 
(8:30 a.m. to 5 p.m. Eastern time) at 888 First Street, NE., Room 2A, 
Washington, DC 20426.
    503. From the Commission's Home Page on the Internet, this 
information is available in the Commission's document management 
system, eLibrary. The full text of this document is available on 
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or 
downloading. To access this document in eLibrary, type the docket 
number excluding the last three digits of this document in the docket 
number field.
    504. User assistance is available for eLibrary and the Commission's 
Web site during normal business hours. For assistance, please contact 
FERC Online Support at 1-866-208-3676 (toll free) or (202) 502-8222 (e-
mail at FERCOnlineSupport@FERC.gov), or the Public Reference Room at 
(202) 502-8371, TTY (202) 502-8659 (e-mail at 
public.referenceroom@ferc.gov).

VII. Effective Date and Congressional Notification

    505. This Final Rule will be effective August 31, 2006. The 
Commission has determined, with the concurrence of the Administrator of 
the Office of Information and Regulatory Affairs of OMB, that this rule 
is not a ``major rule'' as defined in section 351 of the Small Business 
Regulatory Enforcement Fairness Act of 1996.\155\ The Commission will 
submit the Final Rule to both houses of Congress and the Government 
Accountability Office.
---------------------------------------------------------------------------

    \155\ See 5 U.S.C. 804(2) (2000).
---------------------------------------------------------------------------

List of Subjects in 18 CFR Part 42

    Electric power rates; Electric utilities.

[[Page 43619]]

    By the Commission.
Magalie R. Salas,
Secretary.

0
In consideration of the foregoing, the Commission amends Subchapter B, 
Chapter I, Title 18, Code of Federal Regulations, by adding a new part 
42 as follows:
* * * * *

SUBCHAPTER B--REGULATIONS UNDER THE FEDERAL POWER ACT

* * * * *

PART 42--LONG-TERM FIRM TRANSMISSION RIGHTS IN ORGANIZED 
ELECTRICITY MARKETS

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

    Authority: 16 U.S.C. 791a-825r and section 217 of the Federal 
Power Act, 16 U.S.C. 824q.

Sec.  42.1  Requirement that Transmission Organizations with Organized 
Electricity Markets Offer Long-Term Firm Transmission Rights.

    (a) Purpose. This section requires a transmission organization with 
one or more organized electricity markets (administered either by it or 
by another entity) to make available long-term firm transmission 
rights, pursuant to section 217(b)(4) of the Federal Power Act, that 
satisfy each of the guidelines set forth in paragraph (d) of this 
section. This section does not require that a specific type of long-
term firm transmission right be made available, and is intended to 
permit transmission organizations flexibility in satisfying the 
guidelines set forth in paragraph (d) of this section.
    (b) Definitions. As used in this section:
    (1) Transmission Organization means a Regional Transmission 
Organization, Independent System Operator, independent transmission 
provider, or other independent transmission organization finally 
approved by the Commission for the operation of transmission 
facilities.
    (2) Load serving entity means a distribution utility or an electric 
utility that has a service obligation.
    (3) Service obligation means a requirement applicable to, or the 
exercise of authority granted to, an electric utility under Federal, 
State, or local law or under long-term contracts to provide electric 
service to end-users or to a distribution utility.
    (4) Organized Electricity Market means an auction-based day ahead 
and real time wholesale 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.
    (c) General rule.
    (1) Every public utility that is a transmission organization and 
that owns, operates or controls facilities used for the transmission of 
electric energy in interstate commerce and has one or more organized 
electricity markets (administered either by it or by another entity) 
must file with the Commission, no later than January 29, 2007, one of 
the following:
    (i) Tariff sheets and rate schedules that make available long-term 
firm transmission rights that satisfy each of the guidelines set forth 
in paragraph (d) of this section; or
    (ii) An explanation of how its current tariff and rate schedules 
already provide for long-term firm transmission rights that satisfy 
each of the guidelines set forth in paragraph (d) of this section.
    (2) Any transmission organization approved by the Commission for 
operation after January 29, 2007 that has one or more organized 
electricity markets (administered either by it or by another entity) 
will be required to satisfy this general rule.
    (3) Filings made in compliance with this paragraph (c) must explain 
how the transmission organization's transmission planning and expansion 
procedures will accommodate long-term firm transmission rights, 
including but not limited to how the transmission organization will 
ensure that allocated long-term firm transmission rights remain 
feasible over their entire term.
    (4) Each transmission organization subject to this general rule 
must also make its transmission planning and expansion procedures and 
plans publicly available, including (but not limited to) both the 
actual plans and any underlying information used to develop the plans.
    (d) Guidelines for Design and Administration of Long-term Firm 
Transmission Rights. Transmission organizations subject to paragraph 
(c) of this section must make available long-term firm transmission 
rights that satisfy the following guidelines:
    (1) The long-term firm transmission right should specify a source 
(injection node or nodes) and sink (withdrawal node or nodes), and a 
quantity (MW).
    (2) The long-term firm transmission right must provide a hedge 
against day-ahead locational marginal pricing congestion charges or 
other direct assignment of congestion costs for the period covered and 
quantity specified. Once allocated, the financial coverage provided by 
a financial long-term right should not be modified during its term (the 
``full funding'' requirement) except in the case of extraordinary 
circumstances or through voluntary agreement of both the holder of the 
right and the transmission organization.
    (3) Long-term firm transmission rights made feasible by 
transmission upgrades or expansions must be available upon request to 
any party that pays for such upgrades or expansions in accordance with 
the transmission organization's prevailing cost allocation methods for 
upgrades or expansions.
    (4) Long-term firm transmission rights must be made available with 
term lengths (and/or rights to renewal) that are sufficient to meet the 
needs of load serving entities to hedge long-term power supply 
arrangements made or planned to satisfy a service obligation. The 
length of term of renewals may be different from the original term. 
Transmission organizations may propose rules specifying the length of 
terms and use of renewal rights to provide long-term coverage, but must 
be able to offer firm coverage for at least a 10 year period.
    (5) Load serving entities must have priority over non-load serving 
entities in the allocation of long-term firm transmission rights that 
are supported by existing capacity. The transmission organization may 
propose reasonable limits on the amount of existing capacity used to 
support long-term firm transmission rights.
    (6) A long-term transmission right held by a load serving entity to 
support a service obligation should be re-assignable to another entity 
that acquires that service obligation.
    (7) The initial allocation of the long-term firm transmission 
rights shall not require recipients to participate in an auction.

    Note: The following appendix will not appear in the Code of 
Federal Regulations.

Appendix A--List of Commenters and Acronyms

Alcoa Inc.--Alcoa
Allegheny Energy Companies--Allegheny
Allete, Inc. (dba Minnesota Power)--Minnesota Power
Ameren Energy Companies--Ameren
American Electric Power Service Corporation--AEP
American Forest and Paper Association--AF&PA
American Public Power Association--APPA
Arizona Consumer-Owned Electric Systems--Arizona Systems
Arkansas Municipal Power Association--AMPA

[[Page 43620]]

Bonneville Power Administration--BPA
Borough of Chambersburg, Pennsylvania--Chambersburg
BP Energy Company--BP Energy
California Department of Water Resources, State Water Project--DWR
California Municipal Utilities Association--CMUA
California Independent System Operator Corporation--CAISO
Public Utilities Commission of the State of California--CPUC
Central Hudson Gas & Electric Corporation, Consolidated Edison 
Company of New York, Inc., LIPA, New York Power Authority, New York 
State Electric and Gas Corporation, Orange and Rockland Utilities, 
Inc., and Rochester Gas and Electric Corporation--New York 
Transmission Owners
Central Vermont Public Service Corporation--Central Vermont
Cinergy Services, Inc.--Cinergy
City of Redding, California--Redding
City of Santa Clara, California, Silicon Valley Power--Santa Clara
Constellation Energy Group, Inc.--Constellation
Coral Power, L.L.C.--Coral Power
DC Energy, L.L.C.--DC Energy
Dominion Resources, Inc.--Dominion
DTE Energy Company--DTE
Duquesne Light Company--Duquesne
Edison Electric Institute--EEI
E.ON U.S.--E.ON
Electricity Consumers Resource Council, American Iron and Steel 
Institute, Association of Businesses Advocating Tariff Equity, and 
Coalition of Midwest Transmission Customers--Industrial Consumers
Electric Power Supply Association--EPSA
Energy Producers and Users Coalition and Cogeneration Association of 
California--Energy Producers and Users/Cogeneration Association
Exelon Corporation--Exelon
FirstEnergy Service Company--FirstEnergy
Illinois Municipal Electric Agency--IMEA
Indianapolis Power & Light Company--IPL
ISO New England, Inc.--ISO-NE
Kentucky Public Service Commission--Kentucky PSC
Long Island Power Authority and LIPA--LIPA
Los Angeles Department of Water and Power--LADWP
Manitoba Hydro--Manitoba
Metropolitan Water District of Southern California--MWD
MidAmerican Energy Company--MidAmerican
Midwest Stand-Alone Transmission Companies--MSATs
Midwest Independent Transmission System Operator, Inc.--Midwest ISO
Midwest Transmission Owners--Midwest TOs
Modesto Irrigation District--Modesto
Morgan Stanley Capital Group Inc.--Morgan Stanley
National Association of Regulatory Utility Commissioners--NARUC
National Grid USA--National Grid
National Rural Electric Cooperative Association--NRECA
New England Power Pool Participants Committee--NEPOOL
New England Public Systems--New England Public Systems
New York Association of Public Power--NYAPP
New York Independent System Operator, Inc.--NYISO
New York Power Authority--NYPA
Public Service Commission of New York--New York PSC
Northeast Utilities--NU
Northern California Power Agency--NCPA
NSTAR Electric & Gas Corporation--NSTAR
Organization of MISO States--OMS
Pacific Gas and Electric Company--PG&E
PJM Interconnection, L.L.C.--PJM
Old Dominion Electric Cooperative, North Carolina Electric 
Membership Corporation, Delaware Municipal Electric Corporation, 
Southern Maryland Electric Cooperative, and Allegheny Electric 
Cooperative--PJM Public Power Coalition
PPM Energy, Inc.--PPM Energy
Public Power Council--Public Power Council
Reliant Energy, Inc.--Reliant
Sacramento Municipal Utility District--SMUD
San Diego Gas & Electric Company--SDG&E
City of Santa Clara, California, Silicon Valley Power--Santa Clara
Southern California Edison Company--SoCal Edison
Strategic Energy, L.L.C.--Strategic Energy
Suez Energy North America, Inc.--Suez Energy
Transmission Access Policy Study Group--TAPS
Transmission Agency of Northern California--TANC
Vermont Public Service Board and Vermont Department of Public 
Service--Vermont Agencies
Wisconsin Electric Power Company--Wisconsin Electric
Xcel Energy Services Inc.--Xcel

[FR Doc. 06-6494 Filed 7-31-06; 8:45 am]

BILLING CODE 6717-01-P