that leads to the delineation of regions. NRECA asserts that regions
should be large enough to minimize the potential for seams problems for
LSEs in multiple control areas. At a minimum, NRECA argues that the
Commission should ensure that all public utility transmission providers
coordinate with their adjoining systems to ensure that the needs of
LSEs with loads and resources in different systems' areas are met.
    506. TDU Systems support mandatory regional planning and believe
that the Commission should specify the criteria for determining
regions, rather than prescribe regional boundaries. In TDU Systems'
view, ``regional'' planning at a minimum means something more than
planning on an individual control area basis.\295\ TDU Systems stress
that the existence of sub-regional planning must not diminish the
obligation to plan on a broader, more regional level. TDU Systems also
believe that more than coordination is required; rather, transmission
providers should be required to conduct planning on an integrated basis
with, at a minimum, first-tier, adjacent interconnected systems. If a
transmission provider refuses to do so, TDU Systems believe that should
be considered an exercise of vertical market power and the transmission
provider should lose its market-based rate authority. TDU Systems also
urge the Commission to require regional planning for both reliability
and economic upgrades, in order to ensure that competitive market
development is not retarded by inappropriate seams at the borders of
utility systems.\296\ In its reply, NRECA argues that regional
participation must be mandatory, because uncoordinated, unilateral
planning by transmission providers severely handicaps LSEs' assembly of
competitive power suppliers for their customers.
---------------------------------------------------------------------------

    \295\ TAPS believes joint planning should include at least two
transmission providers and be no smaller than a State. TAPS suggests
that the transmission providers' compliance filings identify those
other providers it proposes to include in its regular regional
planning process.
    \296\ NRECA's comments on regional planning are consistent with
those of TDU Systems.
---------------------------------------------------------------------------

    507. PJM states that transmission providers bordering RTOs should
be required to participate in the RTO planning process, but MidAmerican
opposes such a requirement and believes it already happens in MISO
anyway. MAPP also opposes such mandatory participation, pointing out
that comparability would then require that transmission providers in
RTOs participate in the planning processes of non-RTO providers on
their borders as well.\297\ MAPP believes that currently-existing
regions should have the opportunity to adjust their planning processes
to meet the Commission's guidelines for regional transmission planning.
---------------------------------------------------------------------------

    \297\ See also MidAmerican Reply.
---------------------------------------------------------------------------

    508. Indianapolis Power emphasizes that the regional scope of a
transmission provider's planning process should consider grid topology
and historical usage to avoid regions that are too broad or unwieldy.
Indianapolis Power believes that the current MISO region may be an
example of a region that is too large, but nevertheless asserts that
MISO should have the primary role in coordination, with regional
councils in supporting roles. AWEA recommends nine planning regions
that coincide with the nine regions being established for Regional
Triennial Reviews in the market-based rate rulemaking in Docket No.
RM04-7-000: \298\ PJM, New York, New England, Midwest, SPP, Southeast,
California, Northwest, and Southwest.
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    \298\ See Market-Based Rates for Wholesale Sales of Electric
Energy, Capacity and Ancillary Services by Public Utilities, Notice
of Proposed Rulemaking, 71 FR 33102 (Jun. 7, 2006), FERC Stats. &
Regs. ] 32,602 (2006).
---------------------------------------------------------------------------

    509. LDWP and Salt River suggest that continued participation in
existing regional and sub-regional groups should satisfy the
expectation that municipally-owned transmission providers participate
in open and transparent regional planning processes. Other commenters
express a similar concern that the Commission not mandate any
procedures that would interfere with the processes the West has already
established.\299\ New Mexico Attorney General believes that those
already engaged in a planning process should be allowed a waiver.
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    \299\ E.g., California Commission, Imperial, and Salt River.
---------------------------------------------------------------------------

    510. NARUC urges the Commission to clarify that planning proposals
should not interfere with or undermine existing regional planning
efforts, such as those conducted by RTOs and in non-RTO areas.\300\
Project for Sustainable FERC Energy Policy recommends that the
Commission use the Bonneville and PJM planning processes as models for
evaluating transmission provider compliance. Arkansas Commission
believes that the active involvement of states can be a catalyst for
regional planning.
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    \300\ See also NC Transmission Planning Participants Reply and
North Carolina Commission Reply. Also, in its reply, North Carolina
Commission urges the Commission not to be overly prescriptive with
respect to the details of regional transmission planning.
---------------------------------------------------------------------------

    511. National Grid believes the principles of coordination,
openness, and transparency should extend to inter-regional planning and
requests clarification that this is the Commission's intent for
neighboring regions in a single interconnect.
Existing Institutions
    512. Regarding the Commission's request for comment on whether
there are existing institutions that are well-situated to coordinate
regional participation, commenters express differing views regarding
the identity of the regional coordinator and the size of the region
over which entities should be required to coordinate. Some transmission
provider commenters cite NERC regions and regional councils as well-
suited for coordinating regional participation.\301\ Taking an opposite
view, ISO/RTO Council maintains that RTOs and ISOs are the best models
for

regional participation, because regional reliability organizations do
not have mandates or authority to ensure that adequate system expansion
occurs on a coordinated basis.
---------------------------------------------------------------------------

    \301\ E.g., Allegheny, Constellation, and Duke.
---------------------------------------------------------------------------

    513. MISO is concerned the Commission intends to shift transmission
planning responsibility from RTOs to the Regional Entities under the
ERO, arguing that these entities have neither a sufficient level of
independence nor a track record in transmission planning. TDU Systems
suggest that RTOs, where they exist, should perform the regional
planning function, although in some other instances it may be the
regional reliability organizations. Although CAISO states that a larger
regional entity with the authority to order expansion has some appeal,
it contends there are too many hurdles to creating such an entity in
the West. TAPS suggests a ``Regional Joint Planning Committee'' that is
not dominated by transmission providers, which would direct the study
process and be responsible for the development of uniform planning
criteria, assumptions for base and changed cases, and transmission
plans.
Existing Regional Planning Processes
The West
    514. Transmission provider commenters in the West (outside
California) generally recommend the Western Electricity Coordinating
Council (WECC) \302\ as a successful institution and an appropriate
model for designating regions and developing a plan for the
interconnection.\303\ Many public power entities and others in the West
also support WECC and suggest that it should be a primary focus when
deciding which institution can provide independent regional review and
coordination of grid planning in the West.\304\ For example, California
Commission notes that WECC's Transmission Expansion Planning Policy
Committee allows for the consolidated needs of all the system operators
in the Western Interconnection to be considered in the planning process
and considers both reliability and economic transmission planning.
California Commission also stresses that the processes in the West have
resulted in transmission being built. Utah Municipals, however, are
critical of the WECC process, and in reply, assert that the WECC
process does not allow for effective stakeholder input, but merely
review of transmission plans once they are formed. Utah Municipals also
believe that sub-regional groups in its area (e.g., the Southwest
Transmission Expansion Plan (STEP)) are more effective and urges the
Commission to focus on the effective implementation of joint
plans.\305\
---------------------------------------------------------------------------

    \302\ In general, WECC and its sub-regional groups have adopted
an overall division of labor whereby WECC has undertaken
facilitation of interstate, commercial transmission projects and the
sub-regional groups have facilitated the planning of their member
providers.
    \303\ E.g., ColumbiaGrid, MidAmerican, Nevada Companies,
NorthWestern, Pinnacle, and Xcel.
    \304\ E.g., Anaheim, APPA, California Commission, Imperial,
LDWP, NCPA, PGP, Public Power Council, CREPC, Salt River, Santa
Clara, Seattle, TANC, WAPA, and Western Governors. APPA notes,
however, that not all of its members that support the WECC planning
process support those within California.
    \305\ Public Power Council does not support expansion of WECC's
role in coordinating planning beyond its current activities, as it
believes WECC's strength lies in the area of reliability and not
planning and, therefore, that WECC would be best served by focusing
on reliability and standards enforcement, rather than as a
participant (as a facilitator or otherwise) in commercial matters.
---------------------------------------------------------------------------

    515. Other commenters support the sub-regional planning processes
in the West as well, and generally believe the Commission should look
to each sub-region's existing processes and institutions.\306\ For
example, commenters in the Southwest and California also support the
sub-regional groups located in that region (e.g., STEP and the
Southwest Area Transmission Expansion Planning group (SWAT)).\307\
California Commission also supports the CAISO planning process and
states that CAISO works closely with stakeholders to proactively
identify needed, cost effective transmission solutions through an open,
non-discriminatory process that has resulted in $1.8 billion in
transmission being constructed.\308\ In its reply, NCPA emphasizes that
the Commission should not equate the CAISO planning process with a
California-wide process, because not all transmission providers in
California are members of CAISO. However, California Commission notes
that California, with the support of WECC, has begun the work of
creating a California-wide sub-regional planning group that includes
the large, unregulated municipal utilities that do not participate in
CAISO.
---------------------------------------------------------------------------

    \306\ WAPA points out that certain broad functions related to
planning can be coordinated at the regional level, but that sub-
regional planning is necessary in an expansive regional area, such
as WAPA's service territory, in order to provide focus and detail.
    \307\ E.g., LDWP, New Mexico Attorney General, and Salt River.
LDWP also cites its involvement in the Public Power Initiative of
the West, CAISO, and the Western Arizona Transmission System group.
    \308\ Anaheim believes that the CAISO process does not currently
proactively evaluate the adequacy of the system or itself propose
projects that will enhance reliability or efficiency and is based
entirely upon plans presented to it by transmission owners. It
notes, however, that CAISO has proposed reforms to address these
issues. See also Anaheim Reply.
---------------------------------------------------------------------------

Northeast
    516. PJM, NYISO, and ISO New England all have transmission planning
processes that have been approved by the Commission. ISO/RTO Council
cites billions of dollars of transmission investment in the Northeast
as an example of the success of these transmission planning processes
and argues that these processes all satisfy the Commission's principles
for coordinated, open, and transparent planning. PJM maintains that its
Regional Transmission Expansion Planning Protocol is a successful and
comprehensive regional planning paradigm. ISO New England also argues
that its transmission planning meets the principles and further points
to the Northeastern ISO/RTO Planning Coordination Protocol as providing
coordinated planning across the entire Northeast region.
    517. Utilities in the Northeast are generally supportive of the
transmission planning in the Northeast RTOs. Designated NY Transmission
Owners contend that the NYISO Comprehensive Reliability Planning
Process is fully open, coordinated, and transparent and meets or
exceeds each of the eight principles in the NOPR. PSEG believes the PJM
planning process embodies the NOPR principles. Constellation cites the
planning processes in PJM and the NYISO as examples of planning
processes that, while not perfect, should serve as models for
compliance filings by others. Old Dominion, however, expresses concern
over continuing domination of transmission planning by transmission
owners, but nevertheless commends PJM for recent efforts to include
more stakeholder input in the planning process. National Grid is
generally supportive of ISO New England's planning process.
Northwest
    518. Several commenters in the Northwest generally support the
Northwest Power Pool and the ColumbiaGrid process (which will provide
for a biennial transmission expansion plan for certain entities in the
Northwest).\309\ Also, two groups in the Northwest are forming to
address sub-regional planning in that region--the ColumbiaGrid group
and the Northern Tier Transmission Group--but it is not

yet clear how such groups intend to coordinate with each other.
---------------------------------------------------------------------------

    \309\ E.g., Bonneville, ColumbiaGrid, PGP, Public Power Council,
and Seattle. APPA also notes its members' support for the sub-
regional processes in the Northwest.
---------------------------------------------------------------------------

Southeast
    519. The public power commenters in the Southeast were not as
supportive of the existing regional and sub-regional planning processes
in their region. TVA and Santee Cooper generally support the process
conducted by the Southeast Electric Reliability Council (SERC), and
Santee Cooper notes that it has had a formal joint planning process
with its largest wholesale customer for more than 25 years. APPA,
however, notes that its members did not generally endorse existing
regional entities in the Southeast. APPA states that SERC, for example,
just ``rolls up'' the transmission plans of the transmission providers,
and some working groups currently exclude non-transmission owners.\310\
---------------------------------------------------------------------------

    \310\ See also TDU Systems Reply.
---------------------------------------------------------------------------

North Carolina
    520. NCEMC points to the North Carolina Transmission Planning
Collaborative (NC Transmission Planning), a joint planning process with
an independent facilitator, in North Carolina. NCEMC emphasizes that
more than regional coordination is required and that regional planning
needs to be more than mere stakeholder review and must allow for full
participation of LSEs in planning. NCEMC stresses that effective
regional planning requires participation on a sufficient scale to
encompass all LSEs within a natural market area in order to properly
address seams issues and impacts on neighboring systems. Fayetteville
does not believe NC Transmission Planning complies with the planning
principles outlined in the NOPR.
Midwest
    521. MISO believes its current transmission planning process
represents industry best practices, arguing that it is open and
inclusive and provides multiple opportunities for entities to
participate. MISO Transmission Owners endorse the existing MISO
transmission planning process and believe that the process already
provides for regional planning and an open process with stakeholder
involvement. Ohio Power Siting Board, however, claims that MISO's
transmission planning process should not be regarded as best practices,
stating that it is not sufficiently open and transparent. It also
suggests that RTOs merely ``rubber stamp'' investor-owned utility
plans. Additionally, FMPA \311\ notes that MidAmerican has recently
made efforts to engage in more proactive planning and has offered joint
transmission investment opportunities. FMPA also points to its
membership in CAPX 2020, a consortium of Upper Midwest utilities, which
are jointly studying and planning for the needs of regional
transmission. However, FMPA makes clear that it believes smaller
customers nevertheless need a tariff requirement for planning to ensure
that their needs are addressed.
---------------------------------------------------------------------------

    \311\ We note that FMPA filed joint comments on behalf of itself
and the Midwest Municipal Transmission Group.
---------------------------------------------------------------------------

Florida
    522. While the Florida Commission believes that the planning
process conducted by the Florida Reliability Coordinating Council
(FRCC) is adequate, others, such as FMPA, do not.\312\ Florida
Commission states that the FRCC has instituted a transparent and
inclusive planning process whereby utilities, generators, and marketers
participate in joint transmission planning studies and evaluate
impediments to transfer capability and determine solutions to
congestion in order to enhance the reliability of the FRCC system.
---------------------------------------------------------------------------

    \312\ See also Seminole Reply.
---------------------------------------------------------------------------

Commission Determination
    523. We adopt the NOPR's proposal to include a regional
participation principle as a component of the Final Rule's transmission
planning process. Accordingly, in addition to preparing a system plan
for its own control area on an open and nondiscriminatory basis, each
transmission provider will be required to coordinate with
interconnected systems to (1) Share system plans to ensure that they
are simultaneously feasible and otherwise use consistent assumptions
and data and (2) identify system enhancements that could relieve
congestion or integrate new resources (discussed further below).\313\
---------------------------------------------------------------------------

    \313\ As provided for above, transmission providers will be
required to file a ``strawman'' proposal for compliance with the
Final Rule's planning process within 75 days after publication of
the Final Rule in the Federal Register that includes, among other
things, a specification of the broader region in which they propose
to conduct coordinated regional planning. The Commission will then
convene technical conferences in several broad regions around the
country to assist the participants in developing the appropriate
regional planning groups to the extent they do not already exist.
---------------------------------------------------------------------------

    524. As discussed earlier in this Final Rule, since the advent of
open access, power markets have become regional in almost every area of
the country. These regional markets provide opportunities for wholesale
customers to access competitive sources of supply, rather than relying
exclusively on local generation, including resources owned by their
local transmission provider. However, as discussed above, it is not in
the economic self-interest of transmission providers to expand the grid
to permit access to competing sources of supply. A transmission
provider has little incentive to upgrade its transmission capacity with
its interconnected neighbors if doing so would allow competing
suppliers to serve the customers of the transmission provider. We
therefore find, as discussed in greater detail above, that greater
coordination and openness in transmission planning is required, on both
a local and regional level, to remedy undue discrimination. The
coordination of planning on a regional basis will also increase
efficiency through the coordination of transmission upgrades that have
region-wide benefits, as opposed to pursuing transmission expansion on
a piecemeal basis. The specific features of the regional planning
effort should take account of and accommodate, where appropriate,
existing institutions, as well as physical characteristics of the
region and historical practices.
    525. The Commission is encouraged that a number of voluntary
coordinated and regional planning efforts have been developed
throughout the country, including those administered by RTOs and ISOs
and in certain sub-regions of the West and Southeast. For example, each
of the Commission-approved RTOs in the Northeast, Midwest, and
Southwest, as well as CAISO, provide for a coordinated and regional
planning process with stakeholder input from each industry segment.
There are several other promising efforts to establish voluntary
coordinated and regional planning efforts around the country as noted
in our discussion above of existing regional planning processes.
    526. The Commission fully supports these existing efforts and
believes some of them are consistent in significant respects with the
nature of the reforms adopted in this Final Rule. In those regions and
sub-regions that already have adopted significant reforms, the
Commission's planning reforms may require only modest changes, while
other regions and sub-regions may need to undertake more significant
changes to the way in which transmission currently is planned. The
Commission will not in this Final Rule opine on the characteristics of
existing regional planning processes or their consistency with the
reforms we adopt today.

Rather, each process will be addressed in the context of the relevant
compliance filing. In general, however, the Commission urges
participants in existing regional planning processes to closely examine
whether improvements may be implemented to ensure that each regional
planning process is fully consistent with the requirements of this
Final Rule.
    527. Finally, the Commission acknowledges the importance of
identifying the appropriate size and scope of the regions over which
regional planning will be performed. We agree that transmission
providers, customers, affected State authorities, and other
stakeholders should be involved in developing those regions. We decline
to mandate the geographic scope of particular planning regions at this
time. The scope of a particular planning region should be governed by
the integrated nature of the regional power grid and the particular
reliability and resource issues affecting individual regions and sub-
regions. In very large regions, there may well be both sub-regional and
regional processes. For example, in the West there are various sub-
regional processes in addition to a WECC regional planning process. We
believe that such an approach can work, provided that there is adequate
scope to the sub-regional processes and adequate coordination between
sub-regions. We expect sub-regions to coordinate as necessary to share
data, information and assumptions as necessary to maintain reliability
and allow customers to consider resource options that span the sub-
regions.
    528. In response to the commenters that indicate that regional
planning already occurs today as part of the NERC planning process, we
support any such processes, but reiterate that, if they are to meet the
requirements of the Final Rule, they must be open and inclusive and
address both reliability and economic considerations. As we discuss
elsewhere in this section, customers must be allowed to request that
economic upgrades be studied and, therefore, we will require
transmission providers to coordinate on these issues as necessary in
sub-regional or regional planning processes. To the extent the NERC
processes are not considered appropriate for such economic issues,
individual regions or sub-regions may develop alternative processes.
h. Economic Planning Studies
    529. In the NOPR, the Commission proposed to require transmission
providers to prepare studies identifying ``significant and recurring''
congestion and post such studies on their OASIS. The Commission
explained that the studies should analyze and report on (1) The
location and magnitude of the congestion, (2) possible remedies for the
elimination of the congestion, in whole or in part, (3) the associated
costs of congestion, and (4) the cost associated with relieving
congestion through system enhancements (or other means). The Commission
sought comment on how to define ``significant and recurring''
congestion, such as by reference to generation redispatch, repeated
denials of service requests, zero ATC, frequent curtailments or a
combination of these factors. The Commission noted that the required
congestion studies would address both ``local'' congestion (i.e.,
within the transmission provider's system) and congestion between
control areas and sub-regions. The Commission stated that the purpose
of this requirement is to ensure that affected market participants,
State commissions, and the Commission understand both the costs of
recurring transmission congestion and the alternatives for relieving
it. The Commission sought comment on how this information should be
used by transmission providers and market participants to address
significant and recurring congestion.
Comments
Need for Congestion Studies
    530. The Commission's proposal regarding congestion studies gave
rise to a wide range of comments. Some commenters generally support
requiring congestion studies.\314\ East Texas Cooperatives asserts that
congestion studies will greatly assist in the development of
transmission plans, enable planning participants to focus on key
elements of the system and assist in the preparation of the congestion
studies conducted by DOE. NRECA also supports requiring congestion
studies, but urges the Commission not to be prescriptive.
---------------------------------------------------------------------------

    \314\ E.g., APPA, Arkansas Commission, California Commission,
East Texas Cooperatives, Entegra, NCPA, CREPC, Southwestern Coop,
TDU Systems, and WIRES.
---------------------------------------------------------------------------

    531. Other commenters recommend eliminating the requirement.\315\
Southern, for example, argues that congestion studies could be
misleading because they can imply that all congestion needs to be
remedied.\316\ Duke, South Carolina E&G, and Southern agree that
separate studies of congestion, beyond studies performed to meet
service requests, should not be required. Rather than mandating
congestion studies, Southern argues that the Commission should allow
participants to determine which types of transmission studies have
merit. Other commenters believe that, if congestion studies are
required, they should be performed at a regional level rather than by
each transmission provider individually.\317\
---------------------------------------------------------------------------

    \315\ E.g., American Transmission, EEI, Progress Energy, and
Southern.
    \316\ Entegra, however, replied to Southern's assertion that
congestion studies can be misleading, stating that congestion
studies did not need to be misleading, and were, on the contrary,
necessary for customers to assess the costs of managing versus
eliminating congestion.
    \317\ E.g., Imperial, MidAmerican, Nevada Companies,
NorthWestern, Pinnacle, Salt River, SWAT, WestConnect, and Xcel.
---------------------------------------------------------------------------

    532. The EEI position is representative of entities calling for
elimination of the congestion study principle. EEI asserts that these
studies in large part would be duplicative of the studies being
performed by DOE pursuant to EPAct 2005.\318\ EEI also argues that
these studies would be costly and time-consuming and that transmission
providers generally do not have access to information needed for cost
impact analysis and consequently cannot assess the cost of
constraints.\319\ TDU Systems assert on reply that it is difficult to
imagine that providers do not have the information needed or means to
determine the location and magnitude of congestion on their systems,
since they perform this function for themselves already. TDU Systems
add that customers will readily provide any information needed for
congestion studies, as it is in their interest to do so. APPA believes
that customers should be expressly required to produce information to
help determine the cost of congestion (e.g., the additional cost to
them of running or purchasing more expensive generation). TDU Systems
also argues that the distinction between economic and reliability
upgrades is a fiction and should be disregarded.
---------------------------------------------------------------------------

    \318\ Others assert that the DOE studies will be useful but not
necessarily duplicative of the congestion study principle. E.g.,
APPA and Salt River.
    \319\ Bonneville agrees that the costs of congestion itself are
not readily available to transmission providers and that customers
are better positioned to determine this.
---------------------------------------------------------------------------

    533. In the Western Interconnection, entities maintain that WECC
will be performing congestion studies that should meet the requirement.
As a result, they assert that this principle should not be applied to
individual transmission providers in the West, but that these providers
should be permitted to meet the principle through the interconnection-
wide congestion studies conducted by WECC. Tacoma notes that
ColumbiaGrid is considering the

services it can offer in congestion assessment at the sub-regional
level in the Northwest. Other commenters, such as California
Commission, Salt River, and Seattle, support a congestion studies
requirement but believe it should not be required annually but rather
biennially or triennially.
    534. In the Eastern Interconnection, RTOs and ISOs, and entities in
RTOs and ISOs, believe congestion studies are not needed where LMP
markets are in place or are satisfied by RTO or ISO studies.\320\
Entergy argues that the congestion studies that will be performed by
its independent coordinator of transmission should meet this
requirement.
---------------------------------------------------------------------------

    \320\ E.g., Allegheny, FirstEnergy, Indianapolis Power, and
PSEG.
---------------------------------------------------------------------------

Determining ``Significant and Recurring'' Congestion
    535. A variety of commenters provide suggestions as to what
constitutes ``significant and recurring'' congestion. TDU Systems
believe that there should be a presumption of congestion if a
transmission provider posts zero ATC. TDU Systems, APPA, and Bonneville
believe that other indications of significant and recurring congestion
include the need for frequent generation redispatch, frequent
curtailments for reasons other than force majeure, and repeated denials
of requests for firm transmission service. California Commission and
CREPC suggest a similar approach based on a comparison of ATC and
schedules with historical flows and an assessment of denied requests,
but emphasize that the process should be forward-looking as well.
    536. APPA suggests the use of metrics to measure congestion (e.g.,
reporting on all congestion costs that exceed five percent of base
energy costs and five percent of the hours in a season). California
Commission also suggests the use of metrics, but cautions that there
may be East-West differences. Sacramento stresses that such metrics
should depend on whether the system being studied uses LMP or physical
rights. In its view, financial metrics are most useful in LMP markets,
while congestion in physical markets should be determined by paths that
have been derated by a material percent of their nominal rating over a
certain number of hours in a season.
    537. Santa Clara suggests that significant and recurring congestion
exists when congestion costs over a given path during the high use
season approach or exceed the depreciation plus other fixed costs on
the new facilities that would eliminate congestion on the path.
Additionally, Santa Clara emphasizes that if, redispatch is necessary
on an ongoing basis, this should be taken as an indication that new
facilities need to be built.
    538. New York Commission urges the Commission to utilize NYISO's
process for measuring historical congestion--defined as the short-run
production (i.e., dispatch) costs that could be avoided by system
enhancements, as this represents the savings to society compared to the
cost to society of investing in the system enhancement. New York
Commission also cautions the Commission against using analyses focused
on the impacts of transmission investments on wholesale energy prices,
because these energy price impacts may be temporary and offset by
changes in generation investments. TDU Systems and Old Dominion stress
that in PJM significant and recurring congestion should be based on
total gross congestion and not the much smaller and unrealistic measure
of unhedgeable congestion, as this masks the economic reality that
congestion itself has an economic cost.\321\
---------------------------------------------------------------------------

    \321\ See also Indicated Parties Reply.
---------------------------------------------------------------------------

    539. The Organizations of MISO and PJM States do not believe the
Final Rule should address criteria for determining significant and
recurring congestion, but should require each transmission provider to
file criteria for inclusion and cost responsibility for upgrades that
are included in the transmission plan to remedy congestion.
    540. Seattle asserts that current OASIS standards do not support
consistent tracking of service denials and that this inhibits the
evaluation of congestion. Seattle also points out that the costs of
congestion may be difficult to quantify because reliability dispatch is
a reactive tool used only after service requests have been denied and
prescheduled limits imposed and, therefore, foregone transactions will
not be known to the transmission provider.
    541. Ohio Power Siting Board asserts that distributed generation,
demand response, and new technologies should be available to relieve
congestion until longer-term solutions can be implemented.
Commission Determination
    542. The Commission adopts the NOPR proposal and retains a
congestion study principle as part of the Final Rule's transmission
planning process; however, we modify and clarify the principle in
certain important respects in response to the comments received. At the
outset, we wish to clarify that our primary objective in adopting this
principle is to ensure that the transmission planning process
encompasses more than reliability considerations. Although planning to
maintain reliability is a critical priority, it is not the only one.
Planning involves both reliability and economic considerations. When
planning to serve native load customers, a prudent vertically
integrated transmission provider will plan not only to maintain
reliability, but also consider whether transmission upgrades or other
investments can reduce the overall costs of serving native load. Such
upgrades can, for example, reduce congestion (redispatch) costs or
integrate efficient new resources (including demand resources) and new
or growing loads. Thus, to represent good utility practice and provide
comparable service, the transmission planning process under the pro
forma OATT must consider both reliability and economic considerations.
The purpose of this principle is to ensure that the latter is
considered adequately in the transmission planning process.
    543. Some commenters argue that economic upgrades should be
considered only in the context of individual requests for service under
the pro forma OATT. The Commission disagrees. The process for
addressing individual requests for service under the pro forma OATT is
adequate for customers who request specific transmission rights to
purchase power from a particular resource in a particular location
during a defined time period. However, it does not provide an
opportunity for customers to consider whether potential upgrades or
other investments could reduce congestion costs or otherwise integrate
new resources on an aggregated or regional basis outside of a specific
request for interconnection or transmission service. It thus limits,
for example, groups of customers from considering more comprehensive
solutions to transmission congestion, including investment in demand
response. It also limits multiple LSEs from considering, on a more
aggregated basis, whether particular upgrades may represent the most
economic means of integrating new generation resources (e.g., wind
resources) located in a common area that could be accessed by many
customers. The Commission believes such coordinated studies can, for
system planning purposes, be more beneficial than studies performed on
a request-by-request basis. We also find that they are consistent with
the requirement to provide comparable service.

Transmission providers are not limited, in serving native load
customers, to studying potential transmission upgrades only in the
context of specific requests for service under the pro forma OATT.
    544. Some transmission providers appear to object to this principle
because they fear that an obligation to study potential upgrades is
equivalent to an obligation to fund or build such upgrades. We clarify
that this is not the intent of this principle. There is a difference
between a planning process that is coordinated and open and one that
dictates construction and cost responsibility. Both considerations are
important, but, as we explain above, they are distinct. The purpose of
this principle is to ensure that customers may request studies that
evaluate potential upgrades or other investments that could reduce
congestion or integrate new resources and loads on an aggregated or
regional basis (e.g., wind developers), not to assign cost
responsibility for those investments or otherwise determine whether
they should be implemented. The issue of cost allocation is addressed
in Principle No. 9 below.
    545. The Commission also disagrees with the contentions of certain
RTOs or ISOs that they need not comply with this principle. Although
RTO and ISO planning processes tend to be more open and coordinated
than the processes used by vertically-integrated transmission
providers, this does not mean that RTO or ISO processes adequately
address, in all circumstances, investments that are primarily economic
in nature. When many RTO and ISO planning processes were created, they
focused primarily on system enhancements necessary to maintain
reliability. However, in recent years, as congestion has increased and
generation reserve margins have declined, many RTOs and ISOs have taken
increasingly progressive steps to identify investments that could
reduce congestion and/or integrate new resources. For example, we
recently approved a proposal by PJM to significantly enhance its RTEP
planning process.\322\ We applaud these efforts as consistent with the
direction of the reforms adopted herein. However, we decline to provide
a blanket exception for RTOs and ISOs. Each RTO or ISO must show that
its planning process is consistent with or superior to the requirements
of the Final Rule in all respects.
---------------------------------------------------------------------------

    \322\ See PJM Interconnection, L.L.C., 117 FERC ] 61,218 (2006),
reh'g pending.
---------------------------------------------------------------------------

    546. Some commenters express concern that this principle may result
in costly congestion studies that are of little interest or value to
customers. Our intent is not to impose a costly study requirement that
is unrelated to the real-world concerns of consumers. In the NOPR, we
sought comment on whether specific metrics (e.g., zero ATC or TLR
frequency) should be used to trigger the congestion study requirement.
After considering the comments on this topic, we do not believe that
any single metric, or group of metrics, is adequate for that purpose.
Relying on discrete metrics in this instance would risk both over- and
under-inclusiveness--i.e., triggering too many studies, thereby
imposing cost burdens on transmission providers that are not
appropriate, or triggering too few studies, thereby omitting important
studies that could help customers identify cost-effective solutions to
congestion. Additionally, we direct transmission providers, in
consultation with their stakeholders during development of their
Attachment K compliance filings (as discussed above), to develop a
means to allow the transmission provider and stakeholders to cluster or
batch requests for economic planning studies so that the transmission
provider may perform the studies in the most efficient manner. We will
also require the requests for economic planning studies, as well as the
responses to the requests, be posted on the transmission provider's
OASIS or Web site, subject to confidentiality requirements.
    547. The Commission will modify the principle to allow customers to
choose the studies that are of the greatest value to them.
Specifically, we are modifying the principle to require that
stakeholders be given the right to request a defined number of high
priority studies annually (e.g., five to ten studies) \323\ to address
congestion and/or the integration of new resources or loads. The intent
of this approach is to allow customers, not the transmission provider,
to identify those portions of the transmission system where they have
encountered transmission problems due to congestion or whether they
believe upgrades and other investments may be necessary to reduce
congestion and to integrate new resources. The customers should be able
to request that the transmission provider study enhancements that could
reduce such congestion or integrate new resources on an aggregated or
regional basis without having to submit a specific request for service.
This approach ensures that the economic studies required under this
principle are focused on customer needs and concerns, not
administratively determined metrics that may bear no necessary relation
to those concerns. Once such studies are requested, the transmission
provider would conduct the studies, including appropriate sensitivity
analyses, in a manner that is open and coordinated with the affected
stakeholders. The cost of the defined number of high priority studies
would be recovered as part of the overall pro forma OATT cost of
service.\324\ By limiting this principle to a defined number of high
priority studies annually, we are not precluding stakeholders from
requesting additional studies. However, to provide appropriate
financial incentives, the stakeholder(s) requesting these additional
studies would be responsible for paying the cost of such studies.
---------------------------------------------------------------------------

    \323\ The example of five to ten studies mentioned in this Final
Rule is merely illustrative. We recognize that the facts of each
case will be used to determine the number of high priority studies
allowed under a transmission plan.
    \324\ This cost recovery mechanism is comparable and
nondiscriminatory because the transmission provider already has the
ability to include in its pro forma OATT rates the cost of service
associated with studies performed on behalf of native load
customers.
---------------------------------------------------------------------------

    548. We also will modify this principle with respect to the scope
of the studies being performed. The Commission proposed in the NOPR
that the studies address ``significant and recurring congestion.''
However, the Commission also sought comment on whether, in addition,
the study process should address upgrades associated with new
generation resources and provide information needed to proactively
evaluate such resources. We discuss the comments on this proposal in
more detail below, but, as described therein, we agree that the study
process should incorporate such considerations. We therefore modify
Principle No. 8 to encompass the study of upgrades to integrate new
generation resources or loads on an aggregated or regional basis. This
is appropriate because congestion can limit both the efficient dispatch
of existing generation resources as well as inhibit the development of
new supply and demand resources. Moreover, many regions of the country
must make investments in the near future to meet load growth and,
accordingly, studies of the most economic means of making such
investments are critically important to consumers.
    549. By expanding the scope of this principle, we do not intend to
supplant the existing process for individual customers to integrate new
resources or loads through specific requests for

interconnection or transmission service under the pro forma OATT.
Rather, we contemplate that any such studies conducted pursuant to this
principle, as explained above, would be for purposes of planning for
the alleviation of congestion through integration of new supply and
demand resources into the regional transmission grid or expanding the
regional transmission grid in a manner that can benefit large numbers
of customers, such as by evaluating transmission upgrades necessary to
connect major new areas of generation resources (such as areas that can
support substantial wind generation). Specific requests for service
would continue to be studied pursuant to existing pro forma OATT
processes.
    550. With respect to studying the cost of congestion, several
transmission providers argue that they do not have access to
information regarding generation costs either from their merchant
function or unaffiliated customers. We agree that the transmission
provider should be obligated to study the cost of congestion only to
the extent it has information to do so. We make clear, however, that if
stakeholders request that a particular congested area be studied, they
must supply relevant data within their possession to enable the
transmission provider to calculate the level of congestion costs that
is occurring or is likely to occur in the near future. To the extent
that the transmission provider's merchant function possesses such
information (e.g., redispatch cost information), it must provide that
information to the extent necessary to conduct such studies. Providing
for confidential treatment and application of the Standards of Conduct,
as discussed above, will give assurance to customers that their cost
and other information will not be used improperly. To that end, we
direct transmission providers to clearly define the information sharing
obligations placed on customers in the planning attachment to their pro
forma OATT.
    551. In response to those commenters that argue that regional
congestion studies should be sufficient, we agree that regional
congestion studies can be used as part of regional transmission
planning processes required by this Final Rule. For example, to the
extent the DOE has extensively studied congestion in certain broad
areas, it is not necessary or appropriate for transmission providers to
duplicate these studies. However, regional studies typically provide
broad information on overall regional power flows and may not provide
sufficient detail on local system conditions and congestion, such as
detail on congested local facilities that may limit customer supply
options, or detail on local conditions where additional service could
be provided through redispatch. Moreover, although the DOE may identify
areas where congestion exists or new generation may be developed, the
purpose of DOE congestion studies is not to develop specific
transmission system plans to remedy such congestion or integrate such
resources. The DOE studies are therefore not a substitute for a more
open and coordinated planning process to address specific upgrades that
could reduce congestion or integrate new resources and loads. We
therefore require each transmission provider to comply with the revised
economic planning studies principle in this Final Rule both as to its
own transmission system and as to the regional planning process
described above.
i. Cost Allocation for New Projects
    552. In the NOPR, the Commission asked for comment on whether there
should be a requirement for public utilities to develop cost allocation
principles to address the recovery of costs associated with new
transmission projects. In particular, the Commission asked whether the
development of specific cost allocation principles would provide
greater certainty and hence support the construction of new
infrastructure or whether cost allocation is better handled on a case-
by-case basis.
Comments
    553. Several commenters express concern that the Final Rule not
reopen cost allocation principles in RTOs and ISOs or in the OATTs of
vertically integrated transmission providers.\325\ Duke argues that the
Final Rule should not address cost allocation for new transmission at
all, stating that transmission pricing should be evaluated in a
separate proceeding. Other commenters agree that cost allocation issues
should be handled on a case-by-case basis.\326\
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    \325\ E.g., Duke, EEI, ELCON, ISO/RTO Council, MISO Transmission
Owners, SCE, and Southern.
    \326\ E.g., APPA, Arkansas Commission, PGP, Santee Cooper,
Southwestern Coop, and Sacramento.
---------------------------------------------------------------------------

    554. Some commenters urge the Commission to define cost allocation
principles in this proceeding.\327\ For example, E.ON believes that the
cost of upgrades should be directly allocated to parties benefiting
from an expansion and proposes that the host transmission owner should
coordinate and be responsible for obtaining funding. Many transmission
customers, however, support rolled-in cost recovery for network
upgrades.\328\ TDU Systems ask the Commission to clarify that direct
assignment of facility upgrade costs only applies to point-to-point
service, unless it is being used for the delivery of designated network
resources to serve network load. If direct assignment is retained, TDU
Systems suggest the Commission consider standardizing directly
assignable facilities on a regional basis and stress that the critical
factor is comparability. TAPS suggests ``regional'' cost-spreading for
backbone high voltage facilities and criticizes participant funding
because it encourages would-be beneficiaries to wait and hope that
others will step forward first.
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    \327\ E.g., E.ON, National Grid and WIRES.
    \328\ E.g., AWEA, NCEMC, NCPA, NRECA, Seattle, and TDU Systems.
---------------------------------------------------------------------------

    555. Old Dominion emphasizes the need for cross-border transmission
cost allocation mechanisms. In joint projects, Salt River emphasizes
that it is inconsistent with an open season approach to assign benefits
to a party and then assign cost responsibility beyond what the project
participant would voluntarily assume based on the subscription rights
received. Both Bonneville and TVA believe that cost allocation
principles should be based on a determination of beneficiaries and cost
causation. New Mexico Attorney General stresses that cost recovery for
construction of transmission intended for wholesale or market
transactions should not be allocated to native load. NCPA states that
it would expect some Commission deference to recovery of costs of
projects identified in a truly collaborative process.
    556. At the October 12 Technical Conference, PJM stated that the
Commission should provide generic guidance on what would be acceptable
regarding cost allocation, though Progress Energy did not favor putting
a cost allocation approach in the pro forma OATT, as modified by the
Final Rule. National Grid expressed the view that the Commission would
need to address cost allocation generally, arguing that cost allocation
solely on a project-by-project basis is inefficient.
Commission Determination
    557. The Commission finds, after considering the comments, that it
is appropriate to include a specific principle regarding cost
allocation. The manner in which the costs of new transmission are
allocated is critical to the development of new infrastructure.
Transmission providers and customers cannot be expected to support the

construction of new transmission unless they understand who will pay
the associated costs. We therefore find that, for a planning process to
comply with the Final Rule, it must address the allocation of costs of
new facilities.
    558. The Commission emphasizes, however, that we are not modifying
the existing mechanisms to allocate costs for projects that are
constructed by a single transmission owner and billed under existing
rate structures. Our intent is not to upset existing cost allocation
methods applicable to specific requests for interconnection or
transmission service under the pro forma OATT. The cost allocation
principle discussed herein is intended to apply to projects that do not
fit under the existing structure, such as regional projects involving
several transmission owners or economic projects that are identified
through the study process described above, rather than through
individual requests for service. We will not impose a particular
allocation method for such projects, but rather will permit
transmission providers and stakeholders to determine their own specific
criteria which best fit their own experience and regional needs. The
proposal should identify the types of new projects that are not covered
under existing cost allocation rules and, therefore, would be affected
by this cost allocation principle.
    559. Although the Commission does not prescribe any specific cost
allocation method in the Final Rule, we believe some overall guidance
is appropriate. Our decisions regarding transmission cost allocation
reflect the premise that ``[a]llocation of costs is not a matter for
the slide-rule. It involves judgment on a myriad of facts. It has no
claim to an exact science.'' \329\ We therefore allow regional
flexibility in cost allocation and, when considering a dispute over
cost allocation, exercise our judgment by weighing several factors.
First, we consider whether a cost allocation proposal fairly assigns
costs among participants, including those who cause them to be incurred
and those who otherwise benefit from them. Second, we consider whether
a cost allocation proposal provides adequate incentives to construct
new transmission. Third, we consider whether the proposal is generally
supported by State authorities and participants across the region.
---------------------------------------------------------------------------

    \329\ Colorado Interstate Gas Co. v. FPC, 324 U.S. 581, 589
(1945).
---------------------------------------------------------------------------

    560. These three factors are interrelated. For example, a cost
allocation proposal that has broad support across a region is more
likely to provide adequate incentives to construct new infrastructure
than one that does not. The states, which have primary transmission
siting authority, may be reluctant to site regional transmission
projects if they believe the costs are not being allocated fairly.
Similarly, a proposal that allocates costs fairly to participants who
benefit from them is more likely to support new investment than one
that does not. Adequate financial support for major new transmission
projects may not be obtained unless costs are assigned fairly to those
who benefit from the project.
    561. These factors are particularly important as applied to the
economic upgrades discussed above--e.g., upgrades to reduce congestion
or enable groups of customers to access new generation. As a general
matter, we believe that the beneficiaries of any such project should
agree to support the costs of such projects. However, we recognize that
there are free rider problems associated with new transmission
investment, such that customers who do not agree to support a
particular project may nonetheless receive substantial benefits from
it. In the past, different regions have attempted to address such
issues in a variety of ways, such as by assigning transmission rights
only to those who financially support a project or spreading a portion
of the cost of certain high-voltage projects more broadly than the
immediate beneficiary/supporters of the project. We believe that a
range of solutions to this problem are available. We therefore continue
to believe that regional solutions that garner the support of
stakeholders, including affected State authorities, are preferable.
Moreover, it is important that each region address these issues up
front, at least in principle, rather than having them relitigated each
time a project is proposed. Participants seeking to support new
transmission investment need some degree of certainty regarding cost
allocation to pursue such investments.
3. Additional Issues Relating to Planning Reform
a. Independent Third Party Coordinator
    562. In the NOPR, the Commission acknowledged that an independent
third party coordinator would provide benefits for transmission
planning, but did not propose to require independence. Noting that
independence could take many forms, the Commission sought comment on
the level of independence that could provide benefits and the
institutions that could offer such independence.
Comments
    563. Overall comments on the use of an independent third party to
oversee or coordinate the planning process range from those who believe
it is not needed to those who feel that it should be required rather
than merely encouraged. Arguing against the need for an independent
coordinator, South Carolina E&G does not believe an independent third
party is either necessary or desirable. Arguing in favor of an
independent coordinator, EPSA strongly supports independent oversight
and believes that third party oversight will be necessary in non-RTO
areas, particularly where transmission providers have conducted non-
transparent processes.\330\ Most commenters fall somewhere between
these two positions, finding potential benefits in independence but
concurring with the proposal not to mandate it.
---------------------------------------------------------------------------

    \330\ See also AWEA, Arkansas Commission, Old Dominion, and
Project for Sustainable FERC Energy Policy. Old Dominion stresses
that even in RTOs, the transmission owners may have the ability to
exercise market power and, therefore, the market monitoring unit
should have the requisite independence and authority to investigate
and address undue influence.
---------------------------------------------------------------------------

    564. Several public utility commenters acknowledge the potential
benefits of using an independent coordinator and believe the Commission
should encourage it.\331\ National Grid, for example, finds it
difficult to see how a non-independent transmission provider would be
able to manage confidential information in a manner fair to all
stakeholders and recommends finding independent administration of
planning ``superior to'' non-independent administration. Other
commenters note only that independence can be beneficial or suggest
that the Commission be open to independent third parties when
offered.\332\ Progress agrees there can be benefits, but does not
believe an independent coordinator is needed to ensure confidence.
---------------------------------------------------------------------------

    \331\ E.g., National Grid, PPL, Constellation, and Tacoma.
    \332\ E.g., APPA, Bonneville, California Commission, Duke,
Indianapolis Power, NCEMC, NorthWestern, Progress Energy, CREPC,
Sacramento, Seattle, and TDU Systems. Some public power entities,
such as APPA, NRECA, and TDU Systems are concerned with ensuring
that the costs of an independent coordinator do not outweigh the
benefits.
---------------------------------------------------------------------------

    565. EEI argues against an independence requirement, seeing no need
to require non-RTO/ISO transmission providers to engage independent
third parties to oversee the planning process.\333\ EEI believes the

planning processes proposed in the NOPR are adequate without third
party oversight and maintains that requiring third party coordination
could add another layer of administration, might encroach on State
authority, and could create the possibility that the transmission
provider would lose control of the transmission plan. EEI however also
notes that the Commission could require independent oversight in
circumstances where a transmission planner has failed to implement the
principles or has engaged in undue discrimination in planning for
customer needs.
---------------------------------------------------------------------------

    \333\ TVA believes that the levels of independence practiced in
NERC and NAESB and the implementation and administration of those
standards by the regional entitities (such as SERC) are adequate and
appropriate.
---------------------------------------------------------------------------

    566. The consensus at the October 12 Technical Conference was
generally supportive of the potential benefits of an independent
facilitator, but not supportive of a mandate. There was general support
for the idea that an independent facilitator can assist with handling
sensitive information and provide confidence that analysis of
information would be fair, although several participants stated that
sufficient trust and confidence could be obtained without an
independent facilitator.
Commission Determination
    567. The Commission adopts the NOPR proposal to not require the use
of an independent third party coordinator at this time. We agree that
there are benefits to be gained from independent third party oversight,
as cited by commenters, such as the ability to manage confidential
information and the ability to ensure equitable treatment of all
viewpoints in planning. We therefore encourage transmission providers
and their customers and other stakeholders to explore aspects of
planning where the use of an independent coordinator would be
beneficial and to incorporate those aspects in their planning process
compliance filings.
    568. It is, however, possible to comply with the principles without
the use of an independent third party. We expect the transmission plans
themselves to be developed under an open process that includes
coordination among each transmission provider, its customers, other
stakeholders, and its neighbors. A transmission provider will need to
demonstrate to us in a compliance filing that the plan meets the
principles, including providing a dispute resolution process. We
believe that an open, transparent planning process, with meaningful
coordination and dispute resolution, will provide a sufficient basis
for customers to identify and raise meaningful concerns if a plan does
not treat similarly-situated customers in a comparable manner, where
planning appears to be conducted in a discriminatory manner, or in
other instances where the independence of planning may be in question.
If disputes do arise in these areas and cannot be resolved
consensually, we are available to either encourage a consensual
resolution (e.g., by use of the Dispute Resolution Service) or resolve
them ourselves if a complaint is filed.
b. State Commission Participation
    569. In the NOPR, the Commission strongly encouraged the
participation of State commissions and other State agencies in the
coordinated planning process, particularly with regard to regional
planning. The Commission sought comment on how best to accommodate
effective State participation.
Comments
    570. All commenters addressing the question of State participation
agree that states have an important role in transmission planning, but
there were only limited comments recommending specific processes to
encourage State participation. Supporters of State participation
generally believe that it can assist in obtaining siting approval and
in cost recovery. ISO/RTO Council and individual RTOs and ISOs point to
their current processes for including states in their region in the
planning process. Noting the local benefits that can derive from
interstate transmission projects, American Transmission supports
collaborative efforts among states such as the Organization of MISO
States. However, American Transmission and other commenters suggest
that the Commission defer to the states to determine how they
participate in the planning process.\334\
---------------------------------------------------------------------------

    \334\ E.g., American Transmission, Duke, and Progress Energy.
---------------------------------------------------------------------------

    571. Allegheny believes it should be the responsibility of the
transmission provider to maintain good communication with State
commissions. Nevada Companies assert that the real question the
Commission should be posing is how to coordinate the State
jurisdictional role in transmission planning and construction and the
obligations imposed by the Commission on transmission providers, so
that the system of coordination does not put transmission providers in
the middle between conflicting State and Commission requirements.
Moreover, Santa Clara notes that some State commissions do not
represent all energy consumers, since they are charged only with
regulating public utilities, and could be conflicted and disinclined to
act in the best interests of entities not under their jurisdiction.
    572. NARUC supports active State commission participation in both
RTO and non-RTO markets.\335\ NARUC asks that the Commission clarify
that its planning proposals assume that the results of State commission
planning decisions relating to retail load will be incorporated into
the planning process rather than subject to further review. NARUC and
New Mexico Attorney General also ask for clarification that joint
planning will allow for communications between resource and
transmission planners for the purpose of developing State-required
resource plans and that this will not be considered a violation of the
Standards of Conduct. PNM-TNMP and Southern support the NARUC position
in their reply comments.
---------------------------------------------------------------------------

    \335\ Similar views are expressed by APPA, Arkansas Commission,
Bonneville, California Commission, NCEMC, NYAPP, and CREPC. NYAPP,
however, asks the Commission to be vigilant in not allowing State
commissions improper control over the planning process.
---------------------------------------------------------------------------

    573. New York Commission wants to ensure that the Commission's
planning responsibilities cover only transmission that serves a bulk
power system function.\336\ Florida Commission believes that it already
has direct oversight of grid planning and related issues, through among
other things its participation in the FRCC planning process and review
of the annual Ten Year Site Plan. Seattle does not believe that any
additional requirements are needed for State commission participation.
Other commenters are concerned that State policy goals, such as
California's Renewable Portfolio Standard, be included in the
coordinated planning required by the Final Rule.\337\ NARUC and
California Commission also discuss State staff and fiscal constraints
on participation, and California Commission suggests that the
Commission consider a tariff rider to fund State participation.
---------------------------------------------------------------------------

    \336\ NYAPP, on the other hand, urges the Commission to require
planning for all transmission facilities, not just bulk power
facilities.
    \337\ E.g., AWEA, California Commission, and Project for
Sustainable FERC Energy Policy.
---------------------------------------------------------------------------

Commission Determination
    574. The Commission strongly encourages State participation in the
transmission planning process and expects that all transmission
providers will respect states' concerns, such as retail resource needs,
in the planning

process.\338\ As with any other interested stakeholder, we emphasize
that planning must be coordinated with relevant State regulators
(including city councils, local siting boards, and other agencies) that
wish to participate in the transmission provider's planning process. We
will not prescribe a particular level of State participation, but
rather encourage states to determine their own level of participation,
consistent with applicable State law.\339\ We stress that State
determinations with respect to retail load will not be second-guessed,
but that once those determinations are incorporated into the
transmission plan, the transmission planning principles will apply
(e.g., for purposes of determining whether similarly-situated customers
are treated comparably).
---------------------------------------------------------------------------

    \338\ As noted above, we expect the concerns of NARUC and others
that the application of the Commission's Standards of Conduct are
inhibiting State resource planning will be addressed in the
rulemaking proceeding on the Standards of Conduct in Docket No.
RM01-7-000. See supra note 257.
    \339\ We also recognize that there are concerns about how State
regulators and other agencies will recover the costs associated with
their participation in the planning process. As discussed below, we
direct transmission providers to propose a mechanism for cost
recovery in their planning compliance filings. These proposals
should include relevant cost recovery for State regulators, to the
extent requested.
---------------------------------------------------------------------------

    575. Just as we intend to coordinate with State regulators and
other agencies, we also encourage those parties to collaborate amongst
themselves as well, particularly regionally, in order to reach
agreement on how best to review and approve new transmission facilities
that are the product of the coordinated and regional planning process
required by this Final Rule. We intend to defer to such agreements
between State regulators and other agencies in a given region as
appropriate. We are, moreover, sensitive to concerns, such as
Allegheny's, about the overlapping nature of regulatory jurisdiction
over planning matters. We believe the planning principles in this Final
Rule will help alleviate this concern by facilitating coordination
through open, transparent planning and enhanced exchange of
information. We also understand Santa Clara's concern that certain
State regulators do not represent all energy consumers in some states;
however, we do not believe this detracts from the significant interest
that State regulators and other agencies have with regard to
transmission planning for their State and region.
c. Flexibility in Implementation and Examples of Compliant Processes
    576. In the NOPR, the Commission sought comment on how much
flexibility the transmission provider should be given in implementing
the principles and requested examples of transmission planning
processes that comply with the proposed principles.
Comments
    577. Commenters generally favor flexibility and urge the Commission
not to be too prescriptive regarding how the planning processes must
satisfy the planning principles. Many entities in the Western
Interconnection cite the overall WECC process as largely compliant with
the principles. Nevada Companies notes that the WECC process works well
under the existing pro forma OATT, so that few changes should be
required to implement the proposal. In the East, Progress Energy and
Duke cite NC Transmission Planning as an example of an effective
planning process that generally meets the principles.
    578. Constellation agrees with providing flexibility, but believes
the Commission should strongly encourage transmission providers to
model their compliance filings after existing processes, such as those
in RTOs and ISOs. ISO/RTO Council and all individual RTOs and ISOs
argue that their processes are generally compliant and should not be
disturbed. Transmission providers in RTOs and ISOs generally support
this position.\340\
---------------------------------------------------------------------------

    \340\ E.g., Allegheny, Duke, and National Grid.
---------------------------------------------------------------------------

    579. Some entities believe that flexibility should be permitted in
order to deal with regional variations, but that individual
transmission providers should have limited flexibility in implementing
the planning process.\341\ Some commenters simply state that regional
flexibility should be permitted, without further elaboration.\342\
Other commenters urge the Commission to limit both regional and local
flexibility.\343\
---------------------------------------------------------------------------

    \341\ E.g., APPA, East Texas Cooperatives, Seattle, and TDU
Systems.
    \342\ E.g., Bonneville, Salt River, PJM, and TVA.
    \343\ E.g., Arkansas Municipal, Project for Sustainable FERC
Energy Policy, and Southwestern Coop.
---------------------------------------------------------------------------

    580. NRG argues that system planning models should reflect economic
dispatch to facilitate efficient utilization and also argues in favor
of requirements for specific criteria on the treatment of system
overloads and contingencies. AWEA proposes a specific regional planning
protocol patterned off the ``Collaborative Governance'' model developed
during mediation for the Southeast RTO in Docket No. RT01-100.
    581. In reply to commenters arguing in favor of less flexibility,
Indianapolis Power maintains that its experience in MISO shows that
flexibility is needed, citing the wide variations within the MISO
footprint and the difficulties experienced in planning for a single
large region. MidAmerican opposes the NRG proposal for regional
modeling standards, as well as the AWEA proposal for a regional
planning protocol, as too burdensome. Exelon expresses general
agreement with the EEI position on flexibility, but states that
planning processes outside RTOs do not presently meet the NOPR's
requirements. Exelon states planning processes outside RTOs should
follow the planning direction of RTOs like PJM.
Commission Determination
    582. Although we allow flexibility in the development of a
coordinated and regional planning process, the Commission will
carefully review transmission planning compliance filings to ensure
that each planning process is consistent with the planning principles
and other requirements in this Final Rule. We encourage transmission
providers to give consideration to existing planning processes, such as
those already implemented by ISOs or RTOs, or those proposed by AWEA,
as they work with their customers and other stakeholders to develop a
transmission planning process that complies with the Final Rule. The
Commission makes clear, however, that we do not endorse any specific
existing process as a model for all transmission providers.
d. Recovery of Planning Costs
    583. In the NOPR, the Commission recognized that participants in
the planning process must be assured of recovery of their costs
incurred in the planning process, as well as assured that the costs
will be borne equitably by all parties benefiting from the process. The
Commission also sought comment on whether there should be a principle
or requirement regarding cost recovery and allocation associated with
funding the regional planning requirement.
Comments
    584. Public utility commenters generally support the principle that
costs should be borne by the beneficiaries of the process. EEI agrees,
but argues that the Commission should not establish a specific cost
basis for recovery, and several other commenters concur.\344\
NorthWestern and PSEG support a cost causation principle for

allocation of costs of planning, and Southern argues that entities that
request any transmission sensitivity studies should bear the costs of
those studies.
---------------------------------------------------------------------------

    \344\ E.g., Duke, Indianapolis Power, MidAmerican, Progress
Energy, PSEG, South Carolina E&G, and SPP.
---------------------------------------------------------------------------

    585. There is general agreement with the principle that costs
should be recoverable, and some public utilities request that the
Commission clarify that all planning costs not directly assigned are
recoverable through transmission provider transmission rates.\345\
Other commenters believe that the parties in the planning process
should determine how planning costs should be allocated and funded.
APPA urges simplicity, the avoidance of double collecting (e.g., LSEs
should not have to pay through both transmission rates and
individually) and stresses the need to assess costs based on size and
assets. Other comments are consistent with equitable allocation of
planning costs.\346\
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    \345\ E.g., Southern and South Carolina E&G.
    \346\ E.g., Bonneville, NRECA, and CREPC.
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Commission Determination
    586. We will not propose a specific method for recovery and
allocation of planning costs in this Final Rule. We recognize, however,
the importance of planning cost recovery and will require transmission
planning processes to provide a mechanism for recovery of costs. We
direct transmission providers to work with other participants in the
planning process, as part of the collaborative process described above,
to develop their cost recovery proposals in order to determine whether
all relevant parties, including State agencies, have the ability to
recover the costs of participating in the planning process.
Transmission providers should also consider whether mechanisms for
regional cost recovery may be appropriate, such as through agreements
(formal or informal) to incur and allocate costs jointly. The
Commission will consider resulting cost recovery proposals, including
special riders to transmission rates, with an eye toward encouraging
the broadest participation in the planning process possible.
e. Open Season for Joint Ownership
    587. In the NOPR, the Commission expressed its belief that an open
season to allow market participants to participate in joint ownership,
particularly for large new transmission projects, could stimulate grid
investment and ensure that all customers have the ability to
participate in new projects on a nondiscriminatory basis. The
Commission sought comment on whether to include such a requirement and,
if so, what conditions or limitations should be associated with it.
Comments
    588. As a general matter, a number of commenters believe that the
planning process should include a mandate to construct identified
upgrades or otherwise hold transmission providers accountable for
carrying out the plan.\347\ EEI and others argue that such a mandate
would go beyond planning and result in providers giving up control of
their systems. In their replies, LPPC and Sacramento assert that the
decision to build facilities and to carry out transmission plans must
rest with transmission providers and State authorities and that, in any
event, it is unclear that the Commission has the authority to compel
construction pursuant to regional transmission plans. At the October 12
Technical Conference, there was considerable discussion of the
obligation to build and its relationship to the planning process
proposed in the NOPR.
---------------------------------------------------------------------------

    \347\ E.g., APPA, East Texas Cooperatives Reply, FMPA, NCPA,
TAPS, TDU Systems, Utah Municipals, and WIRES.
---------------------------------------------------------------------------

    589. While not necessarily opposed to voluntary joint ownership
arrangements in general, many commenters oppose the idea of mandated
open seasons.\348\ EEI provides a representative summary of the
arguments of those opposed to open seasons. First, EEI argues that the
Commission does not have the authority to order joint ownership and
that joint ownership could interfere with State siting authority. It
maintains that the instances where the Commission can order
transmission construction are very limited and do not extend to the
authority to order joint ownership.\349\ Second, EEI argues that joint
ownership will not provide the benefits cited by the Commission,
stating that there is ample evidence that joint ownership of
transmission lines is not needed to achieve economies of scale in
construction. In its view, the level of transmission investment is
currently increasing and joint ownership should not be expected to
create additional sources of transmission investment. Third, EEI
contends that prospective joint owners mistakenly believe they will not
be subject to the same requirements as Commission-jurisdictional owners
and urge the Commission to make clear that both jurisdictional and
nonjurisdictional owners would be subject to the same requirements for
service over jointly-owned facilities. If the Commission were to order
joint ownership, Duke argues that it must condition such ownership by a
nonjurisdictional entity on that entity filing a safe harbor OATT
ensuring reciprocal open access by that joint owner.
---------------------------------------------------------------------------

    \348\ E.g., Allegheny, American Transmission, Constellation, New
York Transmission Owners, MidAmerican, Duke, EEI, Entergy,
FirstEnergy, MISO, National Grid, Northeast Utilities, NorthWestern,
Progress Energy, PSEG, South Carolina E&G, SCE, Southern, SPP,
Tacoma, Tucson, and Xcel.
    \349\ APPA, FMPA, TAPS, and TDU Systems, however, point to
various sources of authority on which the Commission could rely to
mandate open seasons and joint ownership, such as: To remedy undue
discrimination under FPA sections 205 and 206; to carry out FPA
section 214(b)(4)'s requirement to facilitate the planning and
expansion of transmission facilities to satisfy the needs of load-
serving entities; as a condition of market-based rate authority, FPA
section 203 approval, or transmission rate incentives under FPA
section 219; and under the permitting regulations promulgated under
FPA section 216(c)(2)(B) dealing with backstop siting authority.
---------------------------------------------------------------------------

    590. Tacoma notes that ColumbiaGrid includes a mechanism for small
users to participate in transmission projects in the proposal it is
considering for its planning process. Xcel supports adopting the open
season concept as an option in joint planning requirements. Though it
does not completely oppose the principle, MidAmerican sees significant
practical problems in developing and implementing an open season
proposal and regards the open season idea as premature. Others
generally support allowing for open seasons and joint ownership, but
also do not believe they should be mandated.\350\
---------------------------------------------------------------------------

    \350\ E.g., Bonneville, California Commission, and CREPC.
Bonneville stresses that any jointly-owned facilities should have a
single operator.
---------------------------------------------------------------------------

    591. A number of other commenters, however, support requiring open
seasons as a method of ensuring that identified upgrades are
constructed. ELCON is strongly in favor, stating that open seasons for
joint ownership is an ``idea whose time has come'' and expressing
frustration that the Commission has not already acted on this proposal.
FMPA argues that joint ownership will aid in providing additional
capital for transmission projects. TDU Systems urge the Commission to
require transmission providers, including RTOs and ISOs, to hold open
seasons.\351\ Joined by Arkansas Commission, TDU Systems argue that
open seasons should not be limited to large projects. PGP supports open
seasons when providers do not voluntarily agree to add capacity based
on the results of the transmission plan. TDU Systems cite the Neptune
and

Cross-Sound Cable projects, where regulated utilities failed to provide
solutions despite the need for expansion of the system in those
regions. Seattle argues that voluntary joint ownership of projects
should not be contingent upon an open season requirement. TANC points
to current joint ownership arrangements in the Western Interconnection.
Sacramento likewise notes that the joint planning and ownership process
in the Western Interconnection has been a success, but asks the
Commission to make clear that physical rights set asides are available
in CAISO to accommodate non-LMP co-owners.
---------------------------------------------------------------------------

    \351\ Similar comments were made by APPA, Arkansas Commission,
FMPA (includes a legal analysis in an attachment), NCPA, MISO/PJM
States, Santa Clara, Southwestern Coop, TANC, and TAPS.
---------------------------------------------------------------------------

    592. On reply, EEI, Entergy, and Southern repeat arguments against
joint ownership and open seasons. EEI replies that FMPA's claim that
joint ownership will result in increased investment is not based on
fact and will not increase access. In its reply, TDU Systems states
that joint ownership would not, as argued by EEI, infringe on State
siting, as states would retain this authority over the jointly-
developed project. APPA also stresses that its members have fewer
difficulties obtaining service where joint ownership is permitted. In
their replies, Lassen, Santa Clara, and TANC argue that the Commission
should not, as suggested by Duke, condition the participation of a
nonjurisdictional entity in a jointly-owned project on that entity
filing a safe harbor OATT, as public power entities use the capacity
they need and sell the rest whether or not they have a safe harbor OATT
on file. However, TAPS asks on reply that access to jointly-owned
facilities be available through a pro forma OATT. Participants at the
October 12 Technical Conference expressed both support for joint
ownership, as well as caution. National Grid states that it has had
good success with joint ownership, but that jointly-owned projects are
more complicated and can take longer to develop.
Commission Determination
    593. The Commission believes there are benefits to joint ownership
of transmission facilities, particularly large backbone facilities,
both in terms of increasing opportunities for investment in the
transmission grid, as well as ensuring nondiscriminatory access to the
transmission grid by transmission customers. The comments received in
response to the NOPR support the notion that joint ownership can
provide these benefits in many cases. For example, as TDU Systems note,
the Neptune and Cross-Sound Cable projects have resulted in significant
amounts of new transmission capacity in regions facing chronic
constraints. We encourage joint ownership for other large backbone
transmission upgrades included in the transmission plan developed by
the planning process required by this Final Rule.\352\
---------------------------------------------------------------------------

    \352\ As the Commission stated in Order No. 679-A, ``[t]he
Commission will look favorably on incentive requests that include
public power joint ownership.'' Order No. 679-A at P 102.
---------------------------------------------------------------------------

    594. We acknowledge, however, that joint ownership can increase the
complexity of planning and developing a transmission project and are
sensitive to concerns that formal open seasons can add to that
complexity. We therefore do not mandate open season procedures to allow
market participants to participate in joint ownership. We recognize
that there may be reasons, given the complexity of the transmission
grid and changing conditions of supply and demand for power, why any
given facility identified in a transmission plan may not ultimately be
constructed. Consequently, our planning reforms do not include an
obligation to construct each facility identified in the plan, whether
individually or through joint ownership mechanisms. At the same time,
the Commission agrees that joint ownership may be useful in certain
situations and encourages transmission providers and customers alike to
consider the use of open seasons to realize construction of upgrades
identified in the planning studies. If a transmission provider declines
to construct an identified upgrade, we also encourage customers and
third parties to consider, either individually or jointly, development
and ownership of a project to the extent consistent with applicable
State law.
f. Specific Study Processes Beyond Reliability and Congestion Reduction
    595. In the NOPR, the Commission sought comment on whether there
should be a specific study process to identify opportunities to enhance
the grid for purposes beyond maintaining reliability or reducing
current congestion. Such a study process could allow interested
entities, including State resource agencies and others, to request the
transmission provider to model grid upgrades needed to accommodate the
construction of new resources and provide information needed to
proactively evaluate such resources. The Commission expected that such
studies would not conflict with State prerogatives, but rather would
provide states with better information to evaluate all relevant
resource options.
Comments
    596. Most transmission provider commenters favor providing for
study of some grid enhancement beyond reliability and congestion-
related needs, but believe the Final Rule should not mandate a specific
study process. Various commenters argue that the Commission should
allow planning participants to determine details such as the scope,
number, and cost responsibility for the studies.\353\ MISO states that
it is working on these issues, but enhancement beyond maintaining
reliability or reducing congestion is a complicated subject best left
to each RTO or ISO to decide.
---------------------------------------------------------------------------

    \353\ E.g., EEI, MISO, NorthWestern, PSEG, and Tacoma.
---------------------------------------------------------------------------

    597. Some commenters are more explicit or expansive in their
recommendations. CAISO recommends that the Commission develop a policy
to encourage construction of transmission lines necessary to connect
renewable resources,\354\ and Suez Energy NA provides similar comments
about new remote generation. PJM believes the planning process should
look at future congestion and building for resources not yet announced.
The New Jersey Board believes that demand-side management and other
solutions, such as distributed renewable generation, also should be
considered. WIRES and ELCON believe all credible proposals should be
studied. TAPS asserts that planning should study grid enhancements
needed for new potential resources.\355\ These views are consistent
with the views of many of the commenters that support additional study
processes.\356\ TDU Systems, however, point out that planning for
reliability and economics should be incorporated into the open and
inclusive planning process and, therefore, a special study process
should not be needed.
---------------------------------------------------------------------------

    \354\ Related to this, California Commission asserts that
regional planning processes need to be closely linked with the
resource adequacy planning processes and renewable energy portfolio
standards on the State level.
    \355\ EEI replies in opposition to TAPS' assertions that
planning should address transmission for potential resources,
arguing that such a requirement would be cost prohibitive and would
harm users.
    \356\ E.g., APPA, Arkansas Commission, AWEA, CREPC, Sacramento,
and Seattle.
---------------------------------------------------------------------------

    598. Other commenters are opposed to additional processes: South
Carolina E&G does not see a need for additional studies; Southern
believes additional study processes would be overly burdensome and
would divert attention away from the fundamentals of prudent planning;
and Bonneville notes that market participants often make requests

for expensive studies without following through on them. Santee Cooper
cautions the Commission against giving license to those who would
attempt to hijack the regional planning process in order to advance a
generation-related agenda, and notes that the Commission's authority
does not extend to generation resource adequacy.
Commission Determination
    599. We believe that development of a study process for identifying
opportunities for grid enhancement beyond reliability and congestion
reduction has the potential to provide useful information and would
generally benefit development of the transmission grid. We therefore
will include such study processes within the scope of Principle No. 8.
In the NOPR, that principle concerned only congestion studies, but, as
modified above, it now includes studies regarding upgrades that could
integrate new generation resources. We note that various commenters
argued for the consideration of demand resources in development of
enhancements to the transmission grid.\357\ As we explain above,
consideration of such resources falls within Principle No. 8, as
modified by the Final Rule.
---------------------------------------------------------------------------

    \357\ E.g., New Jersey Board, Ohio Power Siting Board, and
WIRES.
---------------------------------------------------------------------------

g. Level of Detail in the OATT
    600. In the NOPR, the Commission sought comment on the level of
detail to be required to be in the transmission provider's OATT
regarding its planning process.
Comments
    601. Several commenters argued that the details of the planning
process should be included in the transmission providers' OATTs.\358\
Seattle noted that the OATT should balance the need for detailed
planning requirements with the need for regional processes to evolve.
---------------------------------------------------------------------------

    \358\ E.g., APPA, NRECA, Old Dominion, and Seattle. APPA also
suggests OASIS posting.
---------------------------------------------------------------------------

Commission Determination
    602. The Commission agrees that the transmission planning
attachment to a transmission provider's OATT must include sufficient
detail to enable transmission customers to understand the transmission
provider's planning process. This new attachment must therefore
include:
    (a) The process for consulting with customers and neighboring
transmission providers;
    (b) The notice procedures and anticipated frequency of meetings or
planning-related communications;
    (c) A written description of the methodology, criteria, and
processes used to develop transmission plans;
    (d) The method of disclosure of transmission plans and related
studies and the criteria, assumptions and data underlying those plans
and studies;
    (e) The obligations of and methods for customers to submit data to
the transmission provider;
    (f) The dispute resolution process;
    (g) The transmission provider's study procedures for economic
upgrades to address congestion or the integration of new resources; and
    (h) the relevant cost allocation procedures or principles.
C. Transmission Pricing
1. General
    603. As the Commission explained in Order No. 888, the pro forma
OATT was designed to include primarily non-rate terms and conditions of
open access non-discriminatory transmission service. Transmission
providers first were required to adopt the non-rate terms and
conditions of the pro forma OATT and then, in a subsequent filing under
FPA section 205, to propose corresponding rates for service provided
under their OATTs. Consistent with the focus of Order No. 888 on the
non-rate terms and conditions of open access, the Commission did not
propose broad reform of transmission pricing policy through the NOPR.
Rather, the Commission identified in the NOPR several discrete pricing
rules that it considered part and parcel of OATT service that merit
reform, which we discuss in more detail later in this section. The
Commission also specifically noted in the NOPR that the purpose of this
rulemaking is to strengthen the pro forma OATT to remedy undue
discrimination and not to create new market structures.
    604. Despite the clear scope of this rulemaking, several commenters
contend that broader ratemaking reforms should be implemented in order
to remove obstacles to achieving competitive markets. Various
commenters assert that rate pancaking must be eliminated in this
reform, noting that the Commission has recognized in the past that
pancaked rates inhibit the development of competitive markets.\359\
Arkansas Municipal and TDU Systems contend that pancaked rates are
particularly burdensome for customers with loads and resources on
multiple transmission providers systems and those that sit essentially
at or on the boundaries. TDU Systems argue that the failure to
eliminate pancaked rates has caused many of the TDU Systems to spend
many millions of dollars to build transmission from generation to
interconnect with multiple control areas in order to avoid paying
multiple wheeling charges.
---------------------------------------------------------------------------

    \359\ E.g., Arkansas Municipal, AWEA, FMPA, and TDU Systems.
---------------------------------------------------------------------------

    605. Some of these commenters also advocate that the Commission
should move towards joint rates.\360\ Arkansas Municipal Power argues
that moving toward joint rates outside an RTO will not only eliminate
competitive barriers outside RTOs, but would reduce the disincentive to
formation of new and expanded RTOs. TAPS complains that the NOPR
requires regional planning, but has no provision requiring transmission
providers to build facilities to support regional needs, arguing that
joint rates would ease this problem. TDU Systems argue, however, that
any joint rate methodology should not shift costs to other network
customers, especially where surcharges are sought that might open the
door to potential over-recovery by transmission providers as argued in
the PJM/MISO proceedings. Old Dominion also contends that the
Commission should add a requirement in the pro forma OATT that regional
transmission costs be recovered through a single regional transmission
rate of a rolled-in nature. Relative to cost recovery, Old Dominion
believes that rolled-in zonal rates work for local facilities within a
single transmission owner footprint, but regional rolled-in rates would
be necessary for larger footprints.
---------------------------------------------------------------------------

    \360\ E.g., Arkansas Municipal, TAPS, and TDU Systems.
---------------------------------------------------------------------------

    606. Old Dominion also contends that the lack of periodic review by
the Commission of stated transmission rates sends a strong economic
signal to transmission owners to not invest in new transmission. Old
Dominion argues that the Commission should require periodic rate
reviews at least every five years or implement formula rates which
would remove economic incentives for failing to build transmission.
    607. EEI argues that the Commission should not address in this
proceeding TDU Systems' proposal to require transmission providers to
eliminate pancaked transmission rates in non-RTO regions because it
involves complex issues that are not easily resolved. EEI contends that
transmission providers should not be required to eliminate multiple
transmission rates across multiple systems simply to allow TDU members
to avoid the economic consequences of their decisions to

purchase energy from off-system resources.
    608. Other commenters ask the Commission to institute much broader
market reforms in this rulemaking, arguing that the Commission will not
be able to achieve its objectives of remedying undue discrimination and
developing competitive wholesale markets without a fundamental change
in market structures. Several commenters advocate changing the market
structure in non-RTO markets to allow transmission customers to access
the transmission provider's dispatch and redispatch options.\361\ Some
commenters \362\ go further to assert that the Commission require the
use of locational marginal pricing (LMP) as a part of OATT reform.
Other commenters \363\ assert that the Commission would not need to
adopt a full RTO market design to achieve its more limited objectives,
but contend that eliminating the fundamental inconsistency between the
OATT rules and actual operation of the grid would remove a major
obstacle to other reforms. Several commenters \364\ contend that
requiring use of a security constrained economic dispatch is a needed
part of this reform.
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    \361\ E.g., Chandley-Hogan, Constellation, and PJM.
    \362\ E.g., Morgan Stanley and Steel Manufacturers Associations.
    \363\ E.g., Chandley-Hogan and PJM.
    \364\ E.g., EPSA and Chandley-Hogan.
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    609. Chandley-Hogan contend that the key element to ensuring
transmission services are provided on a just, reasonable and not unduly
discriminatory basis is to provide open access to the security
constrained economic dispatch and the associated imbalance pricing that
arises from that dispatch. Chandley-Hogan state that using a security
constrained economic dispatch would also substantially reduce the
problems inherent in the pro forma OATT's reliance on contract paths
and ATC for transmission service scheduling.
    610. Chandley-Hogan contend that a viable path to Order No. 888
reform is to start from the premise that open access to the dispatch
(and redispatch) and marginal cost pricing for imbalances and
redispatch to accommodate transmission are keys to getting open, non-
discriminatory access to transmission. Chandley-Hogan argue that
dispatch is the essential transmission service and providing open
access to this dispatch is a path to achieving open, non-discriminatory
access to transmission. Chandley-Hogan contend that a third party
cannot effectively access the grid without accessing and closely
interacting with the system operator's dispatch, including determining
if transmission service is available, acquiring redispatch service to
allow its schedule to proceed without curtailment, and settling
imbalances from scheduled levels. Williams agrees with Chandley-Hogan
that a system allowing non-RTO utilities to deny and curtail service
requests whenever there is little ATC left and without offering
redispatch to a third party is completely flawed. Williams argues that
these same requests would be accommodated in an RTO through redispatch
as long as the RTO has sufficient offers to arrange a security
constrained economic dispatch.
    611. EPSA argues on reply that an all-inclusive, ``asset-blind''
administration of open dispatch is needed to fully eliminate undue
discrimination. EPSA states that security constrained dispatch will
provide reliable operation and efficient utilization of the
transmission grid by promoting the use of newer, cleaner and less
expensive power plants. EPSA urges that these issues should be explored
further here or in another policy proceeding. Project for Sustainable
FERC Energy Policy asserts that there is no assurance of non-
discriminatory access to transmission services and competitive
wholesale markets unless load and potential competitors of the control
area operators are treated comparably during dispatch. Project for
Sustainable FERC Energy Policy supports additional provisions to the
pro forma OATT requiring transparency and fairness in system dispatch
and redispatch such as either an ``open dispatch'' requirement or a
rule-based framework with standards of conduct and OASIS disclosure, as
well as reporting and auditing requirement to eliminate anticompetitive
incentives. Project for Sustainable FERC Energy Policy argues that
sufficient data to establish marginal system costs and permit
comparisons with the prices/costs of neighboring systems should be
disclosed on OASIS.
    612. PJM proposes open dispatch consisting of control of the
dispatch function by a disinterested entity and the institution of a
spot or balancing market to allow for the formation of real-time
prices. Project for Sustainable FERC Energy Policy encourages the
further separation of the system operator's dispatch functions from its
merchant functions, to include specific dispatch transparency and
comparability mandates as per PJM's and Transparent Dispatch Advocates'
request. Project for Sustainable FERC Energy Policy supports comparable
dispatch services through an independent entity. In its reply comments,
Williams supports the rules based dispatch service proposed by PJM and
states that it will reduce the opportunity for transmission providers
to levy unjust and unreasonable redispatch rates.
    613. PJM also contends that non-RTO/ISO systems have negative
impacts on RTO systems because of the respective treatment of import
transactions by non-RTOs/ISOs and RTOs/ISOs and the incidence of loop
flows in market environments. PJM argues that entities scheduling flows
through PJM that actually loop onto other systems nevertheless benefit
financially because they collect the difference between the relatively
high price at the interface where the energy is scheduled to enter the
PJM footprint and the lower price at the interface where the energy is
scheduled to leave the PJM footprint. When energy does not flow as
scheduled, PJM states that the otherwise expected, beneficial impact on
the transmission constraints are not realized, resulting in price
differentials between the affected interfaces. As a result, PJM
contends that such scheduled transactions only contribute to the FTR
revenue adequacy issues PJM has experienced over the last 12 months.
    614. PJM asserts that it is unduly preferential for a non-RTO/ISO
utility to take advantage of the benefits of the organized markets of a
bordering RTO/ISO without any obligation to bear any of the costs of
administering those markets. PJM contends that it is unduly
discriminatory and an impediment to the development of competitive
markets to permit a non-RTO/ISO utility adjacent to an RTO/ISO's
organized, transparent markets to accept the benefits of those markets
and the regional transmission planning process that sustains them,
while the same utility relies on non-market-based congestion management
and limits the access of its competitors, including those who are
members of the relevant RTO/ISO, to its dispatch sequence and wholesale
prices within its service area. PJM asks the Commission to declare that
it would not be unduly discriminatory for an RTO/ISO to include in its
tariff a provision that makes an external system operator's access to
those markets contingent on the external operator providing reciprocal
access to its dispatch and planning functions for RTO/ISO members, as
well as access to the external system's real-time marginal system cost
information.
    615. Transparent Dispatch Advocates propose on reply that the
Commission require the industry to develop inter-

control area coordination agreements to provide for reciprocal
redispatch to alleviate constraints at specified border flowgates.
Transparent Dispatch Advocates argue that redispatch over a larger area
provides transmission providers more options to extract the full
efficiency of their systems by allowing import/export transactions and
intra-control area flows to continue that would otherwise be curtailed
by providing redispatch of generation across a border at a lower cost
than would result had the transaction been curtailed. Transparent
Dispatch Advocates further propose that the Commission establish
principles in the Final Rule to guide the development of these
coordination agreements and require filing of the agreements within 12
months of the issuance of the Final Rule. Transparent Dispatch
Advocates suggest that technical conferences may need to be scheduled
to address any utility specific issues that arise.
    616. Morgan Stanley and Steel Manufacturers Association contend
that every control area should be moving toward LMP and that facing an
imbalance cost measured by full replacement value of redispatch
measured under LMP is the correct incentive to follow a schedule.
Entegra similarly argues that customers and State regulators would
benefit from more transparency regarding congestion on the transmission
system and that the most efficient way to provide this transparency is
to require transmission providers to apply LMP models to their systems
and to post the resulting modeled LMPs.
    617. Several commenters object to the proposal for a mandatory all-
inclusive redispatch using bid-based pricing.\365\ These commenters
generally argue that such a proposal could not lawfully be adopted in
the Final Rule because it dramatically departs from the scope of the
NOPR. They also argue that the proposal is bad policy because there is
no record showing that consumers would benefit from the costly and
disruptive implementation required for the proposal and that adoption
of the proposal would create controversy given that Congress and the
Commission have already rejected an LMP-based model of industry
restructuring. Sacramento adds that given the record of transmission
investment in RTOs, open redispatch might not meet the transmission
expansion goals of the NOPR.
---------------------------------------------------------------------------

    \365\ E.g., LPPC, Entergy, and Sacramento.
---------------------------------------------------------------------------

    618. Southern argues on reply that there is no legal basis for
claims that a lack of open dispatch results in undue discrimination.
Southern states that the entities at issue are not similarly situated
and that open dispatch concerns resource procurement, an area beyond
the scope of the Commission's jurisdiction. Southern further argues
that the open dispatch remedy proposed by PJM and others would require
radical restructuring and market reforms that are unfounded, lack a
legal basis and would result in political discord. Southern states that
open dispatch would violate FPA section 217 by threatening the ability
of LSEs to maintain access to transmission rights to serve native load.
In its reply comments, Entergy states that the open dispatch proposal
should be rejected because it is unnecessary to ensure open access
transmission service, is contrary to the Congressional intent in
passing EPAct 2005, exceeds the scope of the Commission's jurisdiction
by overriding State jurisdiction over sales to retail customers, and
would result in opposition that will delay other reforms and distract
the Commission with divisive litigation.
    619. Sacramento states that the proposals for mandatory redispatch,
the control of the dispatch by a disinterested entity, and the
institution of a spot or balancing market to allow for the formation of
real-time prices would undermine customers' objectives to receive
uninterrupted transmission service at a predictable price and ignore
transmission system operational limitations. Sacramento states that the
value of mandatory redispatch in the Western Grid is limited because
constraints often overlap and change from thermal to voltage to
stability constraints at differing load levels and redispatching large
amounts of generation to relieve constraints because of the distance
between loads and generation cannot be achieved in the timeframes
required to maintain reliability. Sacramento is concerned that PJM's
proposal would cause appropriation of generation built to serve a
transmission provider's native load in order to effectuate third-party
transmission transactions, strain the transmission provider's grid, and
cause additional curtailment of native load and firm transactions when
a force majeure event occurs.
    620. Entergy cites the approval of the ICT proposal as ample
evidence that the incremental approach proposed in the NOPR is a better
means of improving clarity, transparency and improvements in dispatch
efficiency than the Transparent Dispatch Advocates and PJM seek to
mandate. Entergy states that the arguments posed by PJM and Chandley-
Hogan do not target remedying discrimination or ensuring comparability,
but rather focus on what they believe are mechanisms for more efficient
use of the grid. Overall, Entergy does not support any changes to the
basic nature of the services available under the pro forma OATT or the
development of real-time markets to ensure comparable access.
    621. In its reply comments, Sacramento disagrees with PJM's claims
that TLRs are a discriminatory substitute for real-time redispatch and
PJM's proposal to eliminate such use of TLRs in favor of an expanded
redispatch obligation. Sacramento argues that firm customers under the
pro forma OATT do not expect TLRs, while those in Day 2 RTOs expect
that generation will be redispatched. Sacramento adds that TLRs affect
all loads, but that the nature of firm physical rights service is that
it will not be interrupted except in very narrow defined circumstances.
    622. Southern argues that customers selling between RTO and non-RTO
systems are treated equally since part of the transaction is under an
LMP treatment and the other part is under OATT treatment. In response
to PJM's allegations that loop flows are unduly discriminatory to its
customers, Southern states that loop flows are unavoidable consequences
of integrating electrical systems and that PJM itself imposes loop
flows on non-RTO systems, the effects of which are not compensated by
PJM. If PJM believes that entities are free-riding on its system or
manipulating its system, Southern argues that PJM could seek to
increase market participation charges or file a complaint with the
Commission. Sacramento agrees that this rulemaking is the wrong forum
for resolving seams issues given the stated scope of the NOPR.
Sacramento adds that border utilities do not ``free ride'' on RTO
markets because these markets impose significant costs on border
entities. Sacramento also disagrees that open redispatch would resolve
loop flow problems and suggests other mechanism for addressing loop
flow. Finally, Sacramento states that TLRs are an Eastern
Interconnection process that, although rare, occur in RTOs and non-RTO
areas.
Commission Determination
    623. As the Commission explained in the NOPR, we do not intend to
undertake a comprehensive overhaul of our transmission pricing policies
in this rulemaking. Instead, the Commission proposed a number of
specific reforms to discrete provisions in the pro forma OATT and a
clarification to our ``higher of'' policy for pricing of transmission
system expansions. Given the limited

scope of this proceeding, we do not believe it would be appropriate to
adopt the broader ratemaking proposals suggested by commenters. Issues
of rate pancaking, including joint rates, regional rolled-in rates and
rate reviews are beyond the scope of this proceeding.
    624. Similarly, the Commission made clear in the NOPR that the
purpose of the proposed rule is to strengthen the pro forma OATT to
remedy undue discrimination and not to impose any particular market
structure on the industry. The Commission's focus in this proceeding
was and remains the development of competitive wholesale markets
through the reduction of barriers to entry created through the control
of transmission assets. We continue to believe that the appropriate
focus of this rulemaking is to strengthen competitive wholesale markets
by adopting reforms to address remaining areas of undue discrimination
and issues of comparability rather than mandating a fundamental change
in the market structure.
    625. We therefore reject requests to institute systems that require
the real-time use of regional security constrained economic dispatch
and LMP for granting real-time transmission service and for the
settlement of imbalances or to otherwise require transmission providers
to use LMP-based modeling. We believe that LMP market designs can
provide significant benefits to customers through more efficient use of
the grid, but do not believe that such market designs are the only way
to remedy undue discrimination or achieve comparability. We continue to
support regional flexibility in market development, provided that the
market design implemented by the transmission providers provides other
transmission customers with comparable service to that which the
transmission providers provide to their own native loads and
affiliates.
    626. We also reject arguments regarding seams issues creating an
undue discrimination between market and non-market areas that must be
resolved in this proceeding. We note that there are currently processes
underway to address seams issues both in the Eastern and Western
Interconnections.\366\ We believe that such seams issues are beyond the
scope of this rule and are better addressed on a case-by-case basis or,
as appropriate, in the proceeding on RTO Border Utility Issues.\367\
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    \366\ See, e.g., RTO Border Utility Issues, Notice of Technical
Conference on Seams Issues for RTOs and ISOs in the Eastern
Interconnections, (Docket No. AD06-9-000) (issued Jan. 25, 2007).
    \367\ Id.
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2. Energy and Generation Imbalances
    627. In Order No. 888, the Commission concluded that six ancillary
services must be included in an OATT.\368\ One of those ancillary
services is energy imbalance service under Schedule 4 of the pro forma
OATT.\369\ Energy imbalance service is provided when the transmission
provider makes up for any difference that occurs over a single hour
between the scheduled and the actual delivery of energy to a load
located within its control area.\370\ The Commission recognized, in
general, that the amount of energy taken by load in an hour is variable
and not subject to the control of either a wholesale seller or a
wholesale requirements buyer.\371\
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    \368\ Order No. 888 at 31,703.
    \369\ Id.
    \370\ See Id. at 31,960.
    \371\ Order No. 888-A at 30,230.
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    628. The Commission found that energy imbalance service should have
an energy deviation band appropriate for load variations and a price
for exceeding the deviation band that is appropriate for excessive load
variations.\372\ The Commission established an hourly deviation band of
+/-1.5 percent (with a minimum of 2 MW) for energy imbalance. The
Commission explained that this deviation band promotes good scheduling
practices by transmission customers, which ensures that the
implementation of one scheduled transaction does not overly burden
another.\373\
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    \372\ Id.
    \373\ Id. at 30,232.
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    629. With respect to compensation associated with the hourly energy
deviation band, the Commission explained that, for energy imbalances
within the deviation band, the transmission customer may make up the
difference within 30 days (or other reasonable period generally
accepted in the region) by adjusting its energy deliveries to eliminate
the imbalance (i.e., return energy in kind within 30 days).\374\ In
addition, the Commission explained that the transmission customer must
compensate the transmission provider for each imbalance that exceeds
the hourly deviation band and for accumulated minor imbalances that are
not made-up within 30 days.\375\ With respect to the price of energy
imbalance service, the Commission explained that it intentionally did
not provide detailed pricing requirements.\376\ Instead, the Commission
required transmission providers to propose rates for energy imbalance
service.\377\
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    \374\ Id. at 30,229.
    \375\ Id. The Commission further stated that the pro forma OATT
permits schedule changes up to twenty minutes before the hour at no
charge, and that it would allow the transmission provider and the
customer to negotiate and file another deviation band more flexible
to the customer, if the same deviation band is made available on a
not unduly discriminatory basis. Id. at 30,232-33.
    \376\ Id. at 30,234
    \377\ Id.
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    630. Although transmission providers have different energy
imbalance charges, they typically require customers to correct energy
imbalances within the deviation band through return in kind or a
financial settlement that requires payment for underdeliveries of
energy equal to 100 percent of the transmission provider's system
incremental cost for the hour the deviation occurred. For energy
overdeliveries, the transmission customer would receive a payment equal
to 100 percent of the transmission provider's decremental cost for the
hour the deviation occurred.\378\ Outside the deviation band,
transmission providers either charge the transmission customer (1) A
percentage of the utility's system cost, such as 110 percent of
incremental costs for underscheduling or 90 percent of decremental
costs for overscheduling or (2) the greater of a percentage of system
costs or a fixed charge, such as $100 per MWh.\379\
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    \378\ See, e.g., Arizona Public Service Co., FERC Electric
Tariff, Twelfth Revised Volume No. 2, Schedule 4 (Energy Imbalance
Charge), accepted in Arizona Public Service Co., Docket No. ER04-
442-003 (Sep. 30, 2004) (unpublished letter order); Public Service
Company of New Mexico, FERC Electric Tariff, Second Revised Volume
No. 4., Schedule 4 (Energy Imbalance Charge), accepted in Public
Service Co. of New Mexico, Docket No. ER04-416-002 (Sep. 30, 2004)
(unpublished letter order).
    \379\ See Idaho Power Co., 102 FERC ] 61,351 (2003); Duke
Electric Transmission FERC Electric Tariff, Third Revised Volume 4,
Original Sheet No. 120 accepted in Duke Energy Corp., Docket No.
ER04-812-001 (Jul. 2, 2004) (unpublished letter order).
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    631. While the Commission found in Order No. 888 that energy
imbalance was an ancillary service, it also recognized that another
imbalance may arise for differences between energy scheduled for
delivery from a generator and the amount of energy actually generated
in an hour,\380\ commonly called generator imbalance. The Commission
concluded, however, that a generator should be able to deliver its
scheduled hourly energy with precision and expressed concern that
allowing a generator to deviate from its schedule by 1.5 percent
without penalty, so long as

it returned the energy in kind at another time, would discourage good
generator operating practices.\381\ The Commission stated that a
generator's interconnection agreement with its transmission provider or
control area operator should specify the requirements for the generator