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

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

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

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

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

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

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

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.

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

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

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

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.

    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,

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.

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.

    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.
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    \99\ See, e.g., New England Public Systems, AEP, PJM, BPA, PJM
Public Power Coalition and TAPS.
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    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.
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    \100\ See, e.g., OMS, DTE, EEI, IPL, Reliant, Strategic Energy
and Xcel.
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    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.
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    \101\ See, e.g., NRECA, Ameren, Public Power Council and TANC.
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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.
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    \102\ See, e.g., Santa Clara, Public Power Council, PG&E,
National Grid, Morgan Stanley, DC Energy, Cinergy, BP Energy and
Wisconsin Electric.
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    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.

    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.
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    \103\ See, e.g., FirstEnergy, Coral Power, NYAPP, NRECA, PJM,
Santa Clara, Redding and Suez Energy.
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    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.
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    \104\ See, e.g., Manitoba Hydro, Coral Power, CMUA, ISO-NE, New
England Public Systems, PPM Energy, Midwest ISO, NRECA, IPL, PJM and
LIPA.
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    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