Long-Term Firm Transmission Rights in Organized Electricity Markets, 43564-43620 [06-6494]

Agencies

• DEPARTMENT OF ENERGY
• Federal Energy Regulatory Commission

[Federal Register Volume 71, Number 147 (Tuesday, August 1, 2006)]
[Rules and Regulations]
[Pages 43564-43620]
From the Federal Register Online via the Government Printing Office [www.gpo.gov]
[FR Doc No: 06-6494]



[[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

Federal Register / Vol. 71, No. 147 / Tuesday, August 1, 2006 / Rules 
and Regulations

[[Page 43564]]


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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 l