avoid addressing Mobile-Sierra issues with regard to any particular
jurisdictional agreement, the Commission erred in requiring generically
in this proceeding a modification that it cannot require specifically
for each jurisdictional agreement without determining that the
retention of such a right in the particular agreement is against the
public interest, unjust, unreasonable, or unduly discriminatory or
preferential, or otherwise anticompetitive. MISO further argues that
with respect to the public interest standard, the Commission cannot
make a generic finding as a substitute for the specific finding it must
make before declaring that the provisions of a particular agreement are
contrary to the public interest.
---------------------------------------------------------------------------

    \470\ Ameren at 16 (citing Agreement of Transmission Facilities
Owners to Organize the Midwest Independent Transmission System
Operator, Inc., A Delaware Non-Stock Corporation, Third Revised Rate
Schedule FERC No. 1); MISO; MISO Transmission Owners Group 2.
---------------------------------------------------------------------------

    386. In addition, PSEG Companies disagree with the statement in
Order No. 1000 that this issue can be deferred until the compliance
stage of this proceeding. Specifically, they take issue with the
Commission's conclusion that the record was insufficient to address
National Grid's comment regarding Mobile-Sierra and the ISO-NE
operating agreement, stating that if the Commission had serious
evidence of harm to the public interest then it should have had no
difficulty in articulating it in Order No. 1000. PSEG Companies assert
that it is ironic that while the Commission chose to engage in
nationwide abrogation of individual contracts in a generic rulemaking,
it seeks to avoid the required analysis on the ground that a rulemaking
proceeding is an inappropriate vehicle for such an analysis. They also
argue that the Commission's decision to defer review of the Mobile-
Sierra protections to the compliance stage has no basis in law,
explaining that the Commission is bound by law to apply the standard
before abrogating any contracts. PSEG Companies state that the
compliance stage is not the appropriate procedural stage to address
this issue because under Mobile-Sierra the Commission has the burden to
make its public interest finding and it is not the contracting parties'
burden to defend the provisions that the Commission seeks to
modify.\471\
---------------------------------------------------------------------------

    \471\ PSEG Companies at 13 (citing Wisconsin Public Power, Inc.
v. FERC, 493 F.3d 239 (D.C. Cir. 2007)).
---------------------------------------------------------------------------

    387. Sunflower, Mid-Kansas, and Western Farmers request a partial
stay of Order No. 1000's effectiveness, at least for RTOs that have
limited federal rights of first refusal, if the Commission does not
grant their requests for rehearing and clarification, so that RTOs are
not required to remove any federal right of first refusal provisions
until Order No. 1000 is final and non-appealable. They argue that it is
highly likely that Order No. 1000 will be appealed and that the
rehearing and appeals process may span several years. Sunflower, Mid-
Kansas, and Western Farmers assert that stakeholders will be
irreparably harmed if this portion of Order No. 1000 is effective
before the appeals process is complete, citing the time and resources
needed to modify existing tariffs and, more important, the loss of SPP
transmission owners' rights that cannot be restored if the courts rule
against the Commission on this issue.
(a) Commission Determination
    388. The Commission affirms its decision in Order No. 1000 to
address arguments that an individual contract contains a federal right
of first refusal that is protected by a Mobile-Sierra provision when it
reviews the compliance filings made by public utility transmission
providers. We continue to find that the record in this rulemaking
proceeding is not sufficient to address the specific issues raised
regarding individual agreements. Accordingly, we reject arguments that
the Commission must address in this generic rulemaking proceeding
whether any particular agreement is protected by a Mobile-Sierra
provision. Furthermore, in response to PSEG Companies, the Commission
decided in Order No. 1000 when it will address the issue of whether a
federal right of first refusal provision is protected by Mobile-Sierra;
it did not and cannot shift the burden to defend such provisions to
contracting parties.
    389. As the Commission explained in Order No. 1000, a public
utility transmission provider that considers its contract to be
protected by a Mobile-Sierra provision may present its arguments as
part of its compliance filing. We clarify, however, that any such
compliance filing must include the revisions to any Commission-
jurisdictional tariffs and agreements necessary to comply with Order
No. 1000 as well as the Mobile-Sierra provision arguments. The
Commission will first decide, based on a more complete record,
including the viewpoints of other interested parties, whether the
agreement is protected by a Mobile-Sierra provision, and if so, whether
the Commission has met the applicable standard of review such that it
can require the modification of the particular provisions.\472\ If the
Commission determines that the agreement is protected by a Mobile-
Sierra provision and that it cannot meet the applicable standard of
review, then the Commission will not consider whether the revisions
submitted to the Commission-jurisdictional tariffs and agreements
comply with Order No. 1000. However, if the Commission determines that
the agreement is not protected by a Mobile-Sierra provision or that the
Commission has met the applicable standard of review, then the
Commission will decide whether the revisions to the Commission-
jurisdictional tariffs and agreements comply with Order No. 1000 and,
if such tariffs and agreements are accepted, would become effective
consistent with the approved effective date. As a result, the
Commission is not requiring public utility transmission providers to
eliminate a federal right of first refusal before the Commission makes
a determination regarding whether an agreement is protected by a
Mobile-Sierra provision and whether the Commission has met the
applicable standard of review, while at the same time the Commission is
ensuring that the Order No. 1000 compliance process proceeds
expeditiously and efficiently.
---------------------------------------------------------------------------

    \472\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 292.
---------------------------------------------------------------------------

    390. We also deny Sunflower, Mid-Kansas, and Western Farmers'
request for a partial stay of the requirement to remove a federal right
of first refusal from Commission-jurisdictional tariffs and agreements.
In considering requests for a stay, the Commission has applied the
standards set forth in section 705 of

the Administrative Procedure Act,\473\ and has granted a stay ``when
justice so requires.'' \474\ In deciding whether justice requires a
stay, the Commission considers several factors, including: (1) Whether
the party requesting the stay will suffer irreparable injury without a
stay; (2) whether issuing the stay may substantially harm other
parties; and (3) whether a stay is in the public interest.\475\ The
Commission's general policy is to refrain from granting stays of its
orders to assure definiteness and finality in Commission
proceedings.\476\ If the party requesting the stay is unable to
demonstrate that it will suffer irreparable harm absent a stay, the
Commission need not examine the other factors.\477\ As the D.C. Circuit
has explained, a harm must be both certain and actual rather than
theoretical, and ``mere injuries, however substantial, in terms of
money, time and energy necessarily expended in the absence of a stay
are not enough.''\478\
---------------------------------------------------------------------------

    \473\ 5 U.S.C. 705 (2006).
    \474\ Id.
    \475\ See, e.g., CMS Midland, Inc., 56 FERC ] 61,177 at P 61,631
(1991), aff'd sub nom. Mich. Mun. Coop. Group v. FERC, 990 F.2d 1377
(D.C. Cir.), cert. denied, 510 U.S. 990 (1993).
    \476\ Id.
    \477\ Id.
    \478\ Wisconsin Gas Co. v. FERC, 785 F.2d 699, 674 (D.C. Cir.
1985).
---------------------------------------------------------------------------

    391. Sunflower, Mid-Kansas, and Western Farmers' request for stay
fails to meet the first criterion, which requires it to show that it
will suffer irreparable injury without a stay of the requirement to
eliminate a federal right of first refusal. They argue that they must
spend time and resources to modify existing tariffs. However, we find
that this type of economic loss is not sufficient to warrant a stay.
Furthermore, while Sunflower, Mid-Kansas and Western Farmers may lose
the opportunity to exercise a federal right of first refusal, it
amounts to speculation to assert that this will necessarily cause
Sunflower, Mid-Kansas and Western Farmers to lose the opportunity to
build a transmission project that they could have exercised a federal
right of first refusal to build. They also will still have the
opportunity to submit projects for evaluation and potential selection
in the regional transmission plan for purposes of cost allocation as
well as to build local transmission projects.\479\ Thus, the harm that
Sunflower, Mid-Kansas and Western Farmers argue that they will suffer
is speculative because Sunflower, Mid-Kansas and Western Farmers cannot
point to a specific transmission project that they will lose the right
to construct and own at this time, or in the immediate future.
Accordingly, we find that Sunflower, Mid-Kansas and Western Farmers
have not shown that they will suffer irreparable harm absent a stay of
the nonincumbent transmission developer reforms in Order No. 1000.\480\
---------------------------------------------------------------------------

    \479\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 318.
    \480\ Moreover, though unnecessary to support our denial of this
motion for stay, we note that issuing a stay here may substantially
harm other parties, thereby violating the second factor the
Commission considers in whether to grant a stay. As the Commission
has explained, greater participation by transmission developers in
the transmission planning process may lower the cost of new
transmission facilities for transmission customers, enabling more
efficient or cost-effective solutions to regional transmission
needs. Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 291.
Accordingly, because the removal of a federal right of first refusal
applies only to new transmission facilities selected in a regional
transmission plan for purposes of cost allocation, granting a stay
of the requirement to eliminate a federal right of first refusal
would delay these potential cost-saving and efficiency benefits for
all entities in the region for the duration of the stay.
---------------------------------------------------------------------------

2. Requirement To Remove a Federal Right of First Refusal From
Commission-Jurisdictional Tariffs and Agreements, and Limits on the
Applicability of That Requirement
a. Final Rule
    392. In Order No. 1000, the Commission directed public utility
transmission providers to eliminate provisions in Commission-
jurisdictional tariffs and agreements that establish a federal right of
first refusal for an incumbent transmission provider with respect to
transmission facilities selected in a regional transmission plan for
purposes of cost allocation.\481\ However, Order No. 1000 also limited
the applicability of that elimination requirement in important ways.
The Commission stated that its focus was on the set of transmission
facilities that are evaluated at the regional level and selected in the
regional transmission plan for purposes of cost allocation, and that it
was not requiring removal from Commission-jurisdictional tariffs and
agreements of federal rights of first refusal as applicable to a local
transmission facility.\482\ Additionally, the Commission explained that
the reforms do not affect the right of an incumbent transmission
provider to build, own, and recover costs for upgrades to its own
transmission facilities, such as in the case of tower change outs or
reconductoring, regardless of whether an upgrade has been selected in a
regional transmission plan for purposes of cost allocation.\483\ The
Commission further noted that the reforms are not intended to alter an
incumbent transmission provider's use and control of its existing
rights-of-way, the retention, modification, or transfer of which remain
subject to the relevant law or regulation that granted the right-of-
way.\484\
---------------------------------------------------------------------------

    \481\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 313.
    \482\ Id. P 318.
    \483\ Id. P 319.
    \484\ Id.
---------------------------------------------------------------------------

    393. In a separate section of Order No. 1000, the Commission stated
that for purposes of Order No. 1000, ``nonincumbent transmission
developer'' refers to two categories of transmission developer: ``(1) A
transmission developer that does not have a retail distribution service
territory or footprint; and (2) a public utility transmission provider
that proposes a transmission project outside of its existing retail
distribution service territory or footprint, where it is not the
incumbent for purposes of that project.'' By contrast, the Commission
explained that an ```incumbent transmission developer/provider' is an
entity that develops a transmission project within its own retail
distribution service territory or footprint.'' \485\
---------------------------------------------------------------------------

    \485\ Id. P 225.
---------------------------------------------------------------------------

    394. The Commission also distinguished between a transmission
facility in a regional transmission plan and a transmission facility
selected in a regional transmission plan for purposes of cost
allocation.\486\ The Commission also defined the term ``local
transmission facility,'' which it stated is a transmission facility
located solely within a public utility's retail distribution service
territory or footprint that is not selected in the regional
transmission plan for purposes of cost allocation.\487\
---------------------------------------------------------------------------

    \486\ Id. PP 63-66.
    \487\ Id. PP 63-64.
---------------------------------------------------------------------------

b. Requests for Rehearing and Clarification
    395. Several petitioners seek rehearing or clarification regarding
the implementation of the removal of a federal right of first refusal
for projects that are selected in the regional transmission plan for
purposes of cost allocation.\488\ Northern Tier Transmission Group
requests that the Commission clarify the types of Commission-
jurisdictional agreements that are subject to Order No. 1000's federal
right of first refusal prohibition as well as the types of provisions
that constitute federal rights of first refusal. Northern Tier
Transmission Group asserts that these clarifications are necessary to
determine which bilateral

agreements are affected by the rule and the types of provisions that
are prohibited in future contracts. In addition, Northern Tier
Transmission Group argues that the modification of bilateral agreements
undermines the balance of the agreements, and therefore must be
accomplished in accordance with relevant Commission precedent.
---------------------------------------------------------------------------

    \488\ See, e.g., Northern Tier Transmission Group; Duke; AEP;
AEP; Sunflower, Mid-Kansas, and Western Farmers; and Dayton Power
and Light.
---------------------------------------------------------------------------

    396. Some petitioners seek clarification of what Order No. 1000
intends when referring to ``nonincumbent transmission developer'' and
``incumbent transmission developer/provider.'' \489\ Transmission
Access Policy Study Group and APPA state that the definitions of
nonincumbent transmission developer and incumbent transmission
developer/provider would exclude most municipal electric systems and
electric cooperatives, as well as other public power entities. For
example, Transmission Access Policy Study Group and APPA argue that
because most non-public utility transmission developers have retail
distribution service territories, they would not qualify as
nonincumbent transmission developers under the first part of the
definition. They also argue that non-public utility transmission
providers, as defined in section 201(f) of the FPA, are not public
utilities under FPA section 201(e); thus they would not qualify as
nonincumbent transmission developers under the second part of the
definition. Transmission Access Policy Study Group believes that this
limitation was inadvertent and that the Commission should correct this
error while at the same time keeping in mind that some references to
``nonincumbent transmission developer'' may in fact be intended to
apply only to jurisdictional entities.
---------------------------------------------------------------------------

    \489\ See, e.g., Transmission Access Policy Study Group; and
APPA.
---------------------------------------------------------------------------

    397. APPA notes that Order No. 1000 at P 227 requires incumbent
transmission developers/providers to develop a framework that includes
provisions regarding how best to address participation by nonincumbent
transmission developers. Therefore, APPA and Transmission Access Policy
Study Group are concerned that, if non-public entities do not qualify
as nonincumbent transmission developers, incumbent transmission
providers will not include provisions to address their participation.
Accordingly, they ask the Commission to make clear that non-public
utility transmission developers can be considered nonincumbent
transmission developers.
    398. APPA also argues that, given these definitions, incumbent
transmission developers/providers may develop a framework that prevents
public power utilities from participating in joint ownership of
regional transmission projects. On rehearing, APPA requests that the
Commission clarify that this result was not intended and that the
Commission revise the relevant definitions to allow for participation
by public power entities in transmission projects.Otherwise, APPA
requests rehearing of this issue on the grounds that the definitions
are unduly discriminatory as applied to public power utilities and
preferential as applied to public utilities and other for-profit
entities, in violation of sections 205 and 206 of the FPA.
    399. Some petitioners seek guidance or clarification regarding the
term ``footprint'' as it is used in the definitions of a ``local
transmission facility'' and ``incumbent transmission developer.'' \490\
American Transmission and ITC Companies interpret the term footprint to
be directed at entities, such as transmission-only companies, that do
not have retail distribution service territories, and thus expands the
definitions of an incumbent and a local transmission facility instead
of further defining retail distribution service territory. If the
Commission instead clarifies that the term is intended to further
define retail distribution service territory, then American
Transmission seeks rehearing of the definition of incumbent
transmission developer, arguing that it is arbitrary and capricious and
discriminatory to exclude transmission-only companies from the
definition.It argues that it should be considered an incumbent because
it is subject to the mandatory NERC reliability standards for its
facilities. As for the definition of a local transmission facility, ITC
Companies state that they have no local transmission plans and that all
transmission projects they propose are evaluated and included under the
MISO or SPP Transmission Expansion Plans and are not ``merely rolled
up.'' However, ITC Companies state that these projects may be located
solely within the footprint of one or more of the ITC Companies.
---------------------------------------------------------------------------

    \490\ See, e.g., ITC Companies; LS Power; American Transmission;
Wisconsin PSC; and Edison Electric Institute.
---------------------------------------------------------------------------

    400. Wisconsin PSC adds that American Transmission, for example, is
effectively an incumbent transmission provider with a footprint
equivalent to the aggregate franchise territories of its wholesale
load-serving entity customers. Wisconsin PSC asserts that categorizing
American Transmission as a nonincumbent transmission developer would
treat it as a merchant transmission developer in its home territory of
the last ten years and compel it to double up on the essentially local
planning processes as if it was a merchant, even though it currently
conducts regional planning in coordination with MISO's regional
planning.Wisconsin PSC asserts that the extra costs from such
duplicative planning would be unjust and unreasonable and therefore it
requests that the Commission clarify the categorization of nonincumbent
transmission developer to exclude transmission-only entities.
    401. Duke seeks confirmation that a nonincumbent transmission
developer either becomes an incumbent transmission developer/provider
when its project is energized, if not sooner, or that the provisions of
paragraph 319 of Order No. 1000, relating to upgrades and use of
rights-of-way, apply to nonincumbents that construct projects. Also,
according to Duke, the term ``retail distribution,'' as used in the
definitions of nonincumbent transmission developer and incumbent
transmission developer/provider, modifies ``service territory'' but not
``footprint.''Thus, Duke contends that, under this interpretation, the
nonincumbent developer of an actual project will eventually have a
footprint and thus become an incumbent as to that limited footprint.
However, if the Commission clarifies that nonincumbents never become
incumbents, then it requests that the Commission nonetheless grant
nonincumbents the same rights described in paragraph 319 of Order No.
1000 as to its own facilities and rights of way and describe when those
rights would exist. It recommends that a nonincumbent obtains a federal
right of first refusal no later than energization of its facilities.At
a minimum, Duke requests detailed clarification on this issue so as to
avoid litigation on compliance.
    402. Edison Electric Institute seeks clarification that public
utility transmission providers constructing new facilities in their
``footprint'' pursuant to service obligations imposed on them under
federal, state, or local law or under long-term contracts are included
in the definition of incumbent transmission providers. It notes that
some transmission facility-owning public utilities may lack a retail
distribution service territory, and that other transmission facility-
owning public utilities with retail distribution service territories
may need to construct new transmission facilities that are not fully
contained within those retail

distribution territories. Thus, it seeks clarification that both kinds
of transmission facility-owning public utilities continue to have the
same right to construct reliability projects not subject to regional
cost allocation where necessary to meet their reliability needs or
service obligations. It also seeks confirmation that the use of the
term ``footprint'' is intended to capture new facility construction
that may be separate from a retail distribution service territory but
is nonetheless being constructed by an incumbent transmission owning
utility to meet reliability or service obligation needs, adding that
this clarification would tie the right of an incumbent transmission
provider to choose to build facilities not submitted for regional cost
allocation to the existence of a service obligation under federal,
state, or local law or under long-term contracts. To the extent that
the Commission intended to grant this right in favor of some public
utility transmission provider service obligations and not others,
Edison Electric Institute argues that the Commission is required to
explain and justify its decision.
    403. Other petitioners request clarification or rehearing as to how
to determine whether a project is considered a regional or local
project.\491\ For instance, LS Power requests clarification of how the
Commission intends to apply this local exemption. LS Power states that
the Commission did not explain how a footprint might differ from a
retail distribution area, which may have a different meaning in
different states. Also, LS Power states that while a retail
distribution area is a familiar concept, it does not provide a
geographic-based definition.For example, a utility may own a
transmission line that geographically extends beyond its retail service
area that it may believe should be part of its footprint, but that line
may cross into another transmission provider's geographical retail
distribution area which the other transmission provider considers to be
part of its footprint. LS Power also states that joint ownership of a
substation or transmission line is common, where several entities all
have rights to use the capacity of the line. LS Power also claims that
it is unclear how this definition would be applied in the context of an
RTO, where the transmission provider's footprint covers the entire
region.
---------------------------------------------------------------------------

    \491\ See, e.g., Duke; and AEP.
---------------------------------------------------------------------------

    404. Accordingly, LS Power requests clarification that within and
outside an RTO, a ``local transmission facility'' is one that is
located within the geographical boundaries of the retail distribution
service territory served by the public utility transmission provider as
of the effective date of Order No. 1000 and interconnecting solely to
the public utility transmission provider's existing facilities. LS
Power continues that where there are affiliated public utility
transmission providers located in adjacent and electrically connected
geographic areas, they may be treated as a single transmission owner
only if, as of the date Order No. 1000 became effective, the affiliates
have, in the past, conducted joint planning and maintained a single
transmission rate applicable to service provided by all such affiliates
regardless of the customer's location within the retail distribution
area of a single affiliate and, where located in a RTO, proffered a
single local plan to the RTO and participated in RTO affairs as a
single transmission owner (e.g., voting rights under all jurisdictional
agreements). LS Power further states that any projects connecting, in
whole or in part, to facilities owned by another transmission owner or
to jointly owned facilities would not constitute local facilities.
Last, it argues that ``local'' should be defined as of the effective
date of Order No. 1000, because the area in which an incumbent
transmission owner can claim an exemption to the elimination of the
federal right of first refusal should not be the subject of corporate
structuring.
    405. Duke asserts that the primary difficulty in differentiating
regional and local projects is that there are many ways to interpret
the phrase ``transmission facilities selected in a regional
transmission plan for purposes of cost allocation.'' According to Duke,
many RTOs have adopted cost allocation approaches for all types of
projects and that even local projects ultimately are included in the
``regional plan.'' In addition, Duke asserts that a pricing zone that
consists of the retail distribution service territory of a single load-
serving entity that was also a transmission provider is an anomaly, and
that it is more likely that a typical pricing zone will consist of a
public utility transmission provider and more than one retail load-
serving entity with a service territory, such as, for instance, a non-
jurisdictional distribution and/or transmission company. Accordingly,
Duke seeks clarification that, under a zonal approach to cost
allocation, a facility whose costs are allocated under an RTO tariff to
a single RTO pricing zone, and which is located in that pricing zone,
be deemed a local facility.
    406. Duke also adds that, under a non-RTO model or dominant
provider model, all the load in a single zone would be network load of
the public utility transmission provider, with any other transmission
owners receiving credits for their integrated transmission facilities.
Accordingly, Duke requests clarification that the Commission intended
that single zone facilities may be classified as local facilities, as
long as the general construct under a non-RTO model, or dominant
provider model, is met. Duke adds that any proposals for `re-zoning'
meant to evade the impact of the removal of a federal right of first
refusal can be addressed on compliance. If the Commission clarifies
that a single zone facility under no circumstances can be a local
facility, then Duke asserts that the Commission would effectively
obliterate the federal right of first refusal in virtually every ISO
and RTO, which could cause significant exoduses from ISOs and RTOs or
cause ISOs and RTOs to completely overhaul their entire cost allocation
processes.
    407. Petitioners also seek clarification that a project that is
selected in the plan, but for which the costs are assigned to a single
utility, is considered a local facility for purposes of the
applicability of the requirement to remove the federal right of first
refusal.\492\ Specifically, Duke asks whether the focus is on the
result of a cost allocation method or the area over which the method is
applied such as an entire region. Duke urges the Commission to adopt
the results approach, and clarify that if any cost allocation approach
results in a single zone being allocated the costs of a facility, then
an RTO should be permitted to deem the facility as local and therefore,
apply a federal right of first refusal. Duke seeks clarification that
facilities that have any costs allocated outside a single zone, even if
such facilities are physically in a single zone, will be presumed to be
regional, unless they are an upgrade to existing facilities.
---------------------------------------------------------------------------

    \492\ See, e.g., Duke; AEP; and Dayton Power and Light.
---------------------------------------------------------------------------

    408. Dayton Power and Light also asserts that the Commission should
clarify that when all of a facility's costs are assigned to a single
utility zone, the tariff could continue to permit a federal right of
first refusal. However, Dayton Power and Light also seeks clarification
as to whether a facility that is allocated solely to one utility zone
using a regional cost allocation method should be treated differently
for purposes of a federal right of first refusal from a facility that
is allocated predominately to one utility zone, and if so, where the
break-point should be. Sunflower, Mid-

Kansas, and Western Farmers seek clarification (or, alternatively,
rehearing) that the definition of ``regionally funded'' excludes
projects where costs allocated to a region are not at least a majority
of the total costs.
    409. In addition, ITC Companies and Xcel request clarification of
``selected in a regional transmission plan for purposes of cost
allocation'' as it applies to the transmission facilities that are
approved by MISO under its MISO Transmission Expansion Plan or by SPP
under its SPP Transmission Expansion Plan.\493\ Xcel states that Order
No. 1000 creates ambiguity by assuming that the cost allocation for
local zone projects, such as in MISO and SPP, is not identified in the
regional RTO tariff process.\494\ Xcel states that it believes that,
under Order No. 1000, the costs for a project selected in the MTEP or
STEP may permissibly be assigned to a single zone, whether that zone
includes the facilities of a single transmission owner or whether a
transmission owner has facilities that are included in other zones,
through a regional cost allocation method, and that such an allocation
is not precluded by Order No. 1000.
---------------------------------------------------------------------------

    \493\ ITC Companies; Xcel at 20 (citing Order No. 1000, FERC
Stats. & Regs. ] 31,323 at n.299).
    \494\ Xcel at 20 (citing Order No. 1000, FERC Stats. & Regs. ]
31,323 at n.299).
---------------------------------------------------------------------------

    410. ITC Companies argue that MISO cost allocation methods fall
along a continuum that on one end includes 100 percent allocation on a
systemwide basis for multi-value projects, and on the other end are
participant funded projects assumed by project sponsors. They state
that in SPP 100 percent of the costs of Base Plan Upgrades 300kV and
above are allocated to a regionwide annual transmission revenue
requirement and recovered through a regionwide charge. They thus assert
that it is unclear whether certain projects would be considered
``transmission facilities selected * * * for purposes of cost
allocation'' under Order No. 1000.\495\ ITC Companies request
clarification that this term means those projects approved in a
regional transmission plan and which are also approved for 100 percent
regional cost allocation.They argue that if the Commission does not
clarify this term, if a project becomes ineligible for federal rights
of first refusal when any of the costs of that project are borne by
customers beyond the local zone or footprint in which that project is
located, the construction of more efficient, cost-effective multi-
purpose projects with broad regional benefits will be discouraged. They
maintain that incumbent transmission owners will oppose projects with
broader benefits in favor of less efficient projects for which their
rights of first refusal are preserved. They assert that projects will
be designed to avoid minor enhancements that would benefit a region,
but which would not justify a stand-alone, purely economic project.
---------------------------------------------------------------------------

    \495\ ITC Companies specifically ask about the following: (1)
MISO Baseline Reliability Projects eligible for 20 percent regional
cost allocation but whose costs can be 100 percent allocated to the
host zone pursuant to power flow modeling; (2) MISO Market
Efficiency Projects eligible for 20 percent regional cost
allocation; and (3) SPP Base Plan Upgrades eligible for 33 percent
regional cost allocation.
---------------------------------------------------------------------------

    411. On the other hand, Western Independent Transmission Group
argues that the Commission failed to provide a reasoned explanation of
why it did not remove the federal right of first refusal for local
transmission facilities, and why it is not unduly discriminatory or
preferential to uphold the federal right of first refusal for
facilities not in a plan for purposes of cost allocation. Western
Independent Transmission Group also argues that Order No. 1000 did not
address in adequate detail the boundary between transmission projects
for which independent transmission developers have a right to compete,
and those projects that are reserved solely to the incumbent
transmission provider. According to Western Independent Transmission
Group, the most obvious instance where the Commission's failure to
address the subject may have significant competitive impacts on
transmission planning is the distinction between public policy projects
and transmission projects initiated through the generation
interconnection process. Western Independent Transmission Group argues
that, particularly in California, where the vast majority of approved
transmission projects in the most recent 2010/2011 planning cycle were
initiated through the generator interconnection process, the
Commission's unwillingness to address this issue effectively left
incumbent utilities with a total monopoly over the transmission built
in response to renewable energy development.
    412. Petitioners also seek clarification of what is to be
considered an upgrade to an existing transmission facility such that
the elimination of the federal right of first refusal does not apply.
For example, Duke seeks clarification that if an incumbent transmission
owner cuts into its own existing transmission line to construct a new
345 kV substation that is needed for stability due to local growth on
its system, such a substation, even if a share of its costs are
allocated to all pricing zones in a region, would be covered by the
federal right of first refusal under the ``upgrades to its own
transmission facilities'' carve out. If not, then Duke asserts that a
region should be able to take this policy into account in implementing
Order No. 1000, such that a region could alter its cost allocation
method so that the type of project described above is not subject to
any regional cost allocation if the region decides such projects merit
a federal right of first refusal.
    413. Similarly, ITC Companies seek clarification that the
prohibition on a federal right of first refusal does not apply to a
transmission upgrade that requires expansion of an existing right-of-
way in order to be expanded. ITC Companies argue that retaining a
federal right of first refusal for upgrades that require an expansion
of an existing right of way is necessary to avoid unintended and
adverse consequences that would undermine the optimal and cost-
effective development of the grid.
    414. Finally, petitioners also request rehearing of the
Commission's decision to eliminate incumbent utility transmission
providers' existing rights to construct reliability projects.\496\ Xcel
believes that incumbent transmission providers, particularly franchised
utilities with an obligation to serve, should retain the right to
construct transmission projects necessary for the utility to provide
reliable service to their native load customers and to comply with NERC
mandatory reliability standards. Xcel asserts that this federal right
of first refusal does not need to be unlimited and supports the
inclusion of a 90-day election period during which the incumbent
transmission provider would be required to indicate its decision to
move forward with the designated project. Xcel contends that the
Commission's attempt to address utility providers' concerns by
eliminating certain penalty responsibilities fails to recognize that
utilities have an obligation to serve and are not merely worried about
financial penalties.
---------------------------------------------------------------------------

    \496\ See, e.g., Xcel; and Edison Electric Institute.
---------------------------------------------------------------------------

c. Commission Determination
    415. We affirm the decision in Order No. 1000 to require the
elimination of a federal right of first refusal from Commission-
jurisdictional tariffs and agreements for transmission facilities
selected in a regional transmission plan for purposes of cost
allocation. In response to Northern Tier Transmission Group, the phrase
``a federal right of first refusal'' refers only to rights of first
refusal that are created by provisions in

Commission-jurisdictional tariffs or agreements.\497\
---------------------------------------------------------------------------

    \497\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 253
n.231.
---------------------------------------------------------------------------

    416. In response to petitioners' concerns, we also clarify several
of the terms used in Order No. 1000, starting with the term
``nonincumbent transmission developer.'' In doing so, we first affirm
the definition of incumbent transmission developer/provider as ``an
entity that develops a transmission project within its own retail
distribution service territory or footprint.'' \498\ Given this
definition, we clarify that a ``nonincumbent transmission developer''
is any entity that is not an incumbent transmission developer/provider.
We believe that this clarification, along with the others made in this
order, addresses the concerns expressed by Transmission Access Policy
Study Group and APPA that the definitions of nonincumbent transmission
developer and incumbent transmission developer/provider in Order No.
1000 would exclude certain municipal electric systems and electric
cooperatives, as well as other public power entities.
---------------------------------------------------------------------------

    \498\ Id. P 225.
---------------------------------------------------------------------------

    417. However, as discussed more fully below, we find that in order
for a non-public utility to be considered a nonincumbent transmission
developer, it must satisfy the enrollment requirement if it or an
affiliate has load in the transmission planning region where it
proposes a transmission project for selection in the regional
transmission plan for purposes of cost allocation as would any other
potential transmission developer.\499\ As an initial matter, we note
that the Commission did not intend through its definition of
nonincumbent transmission developer in Order No. 1000 to exclude any
transmission developer, including a non-public utility transmission
developer, from being able to propose transmission projects and have
them evaluated and selected by a regional transmission planning process
for purposes of cost allocation, so long as that transmission developer
abides by the same requirements as those imposed on public utility
transmission providers. Allowing entities, such as non-public utility
transmission developers, the opportunity to potentially propose a
transmission project as a nonincumbent transmission developer furthers
the Commission's goal in Order No. 1000 of ensuring that all
transmission developers have a comparable opportunity to incumbent
transmission developers/providers to propose a transmission project for
selection in the regional transmission plan for purposes of cost
allocation.
---------------------------------------------------------------------------

    \499\ We refer to non-public utility entities that seek to
propose projects in a regional transmission planning process as
``non-public utility transmission developers,'' which may include
both non-public utility transmission providers that already own and
operate transmission facilities and transmission-dependent non-
public utilities that may wish to develop, construct, or own
transmission facilities in the future.
---------------------------------------------------------------------------

    418. However, we also recognize that it would be fundamentally
unfair and thereby may lead to an unjust and unreasonable or unduly
discriminatory or preferential result to allow a transmission
developer, whether it is a public utility transmission developer or a
non-public utility transmission developer, to seek regional cost
allocation for a proposed transmission project in a transmission
planning region in which it or an affiliate has load, but where neither
it, nor that affiliate, has enrolled in that region where its load is
located. Such a result would permit a transmission developer to
allocate the costs of its project to other entities in the region
pursuant to that region's cost allocation method--without first
enrolling itself or its affiliate in the transmission planning region
in which its load is located and potentially being allocated costs for
other transmission projects for which it is found to be a
beneficiary.\500\
---------------------------------------------------------------------------

    \500\ For discussion of enrolling in a transmission planning
region, see the Regional Transmission Planning Requirements section.
See discussion supra at section III.A.2.c.
---------------------------------------------------------------------------

    419. Therefore, Order No. 1000's reforms regarding the submission
and evaluation of proposals for potential selection in a regional
transmission plan for purposes of cost allocation will apply to a
transmission developer that has load or an affiliate within an area
that would normally be considered a geographic part of a transmission
planning region if the transmission developer or its affiliate
transmission provider in that area enrolls in the transmission planning
region in which that load is located. We believe that in most cases, it
should be clear where an entity's load is located and therefore the
region in which it would be expected to enroll. However, should
disputes arise over the choice of a region, we will address them on a
case-by-case basis utilizing the standard found in Order No. 890 and
Order No. 1000, which provides that ``the scope of a transmission
planning region should be governed by the integrated nature of the
regional power grid and the particular reliability and resource issues
affecting individual regions.'' \501\ We emphasize that an entity,
including a non-public utility transmission developer, that does not
have load within a transmission planning region may propose a
transmission project for evaluation and potential selection in that
region's transmission plan for purposes of cost allocation without
enrolling in that region, as long as it satisfies the transmission
planning region's other requirements for doing so, such as meeting the
qualification criteria for proposing projects found in Order No. 1000.
---------------------------------------------------------------------------

    \501\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 160
(citing Order No. 890, FERC Stats. & Regs. ] 31,241 at P 527).
---------------------------------------------------------------------------

    420. Turning to other terms used in Order No. 1000, we also clarify
that the phrase ``retail distribution,'' as used in the definitions of
incumbent transmission developer/provider, nonincumbent transmission
developer and local transmission facility, does not modify footprint.
Instead, the term ``footprint,'' as used in these definitions was
intended to include, but not be limited to, the location of the
transmission facilities of a transmission-only company that owns and/or
controls the transmission facilities of formerly vertically-integrated
utilities, as well as the location of the transmission facilities of
any other transmission-only company.
    421. In response to Duke, we agree that a nonincumbent transmission
developer will have a footprint at the time that its transmission
facility is energized. As such, we clarify that a nonincumbent
transmission developer will then become an incumbent transmission
developer/provider for that energized transmission facility and will
thereafter have all the rights and obligations that accrue to such
entities under Order No. 1000, such as being able to maintain a federal
right of first refusal for local transmission facilities and upgrades
to those transmission facilities.
    422. In response to Edison Electric Institute, we note that there
are a great variety of fact patterns that may fall under its request.
For example, Edison Electric Institute does not explain whether the new
transmission facility would go through the retail distribution service
territory of the incumbent transmission owning utility, that of another
entity, or an ``unassigned'' territory. Thus, we decline to find
generically that any particular transmission facility, whether it is
needed to meet a reliability, economic, or transmission need driven by
a Public Policy Requirement, developed outside of an existing retail
distribution service territory or footprint, should be considered a
part of that entity's footprint.

    423. We clarify that Order No. 1000 does not require elimination of
a federal right of first refusal for a new transmission facility if the
regional cost allocation method results in 100% of the facility's cost
being allocated to the public utility transmission provider in whose
retail distribution service territory or footprint the facility is to
be located. Accordingly, we clarify that the term ``selected in a
regional transmission plan for purposes of cost allocation'' excludes a
new transmission facility if the costs of that facility are borne
entirely by the public utility transmission provider in whose retail
distribution service territory or footprint that new transmission
facility is to be located. Although public utility transmission
providers in a transmission planning region may determine, based on
non-discriminatory evaluation criteria, that a proposed transmission
facility is likely to have regional benefits so that the transmission
facility's costs should be allocated regionally, it is not until the
cost allocation method is applied that the beneficiaries are
identified.
    424. Petitioners request clarification about whether a transmission
facility is a local transmission facility if it is selected in a
regional transmission plan for purposes of cost allocation and the
costs are allocated to a single pricing zone in which the proposed
transmission facility is to be located, and that zone consists of more
than one transmission provider. In general, any regional allocation of
the cost of a new transmission facility outside a single transmission
provider's retail distribution service territory or footprint,
including an allocation to a ``zone'' consisting of more than one
transmission provider, is an application of the regional cost
allocation method and that new transmission facility is not a local
transmission facility. For example, transmission-owning members of an
RTO may not retain a federal right of first refusal by dividing the RTO
into East and West multi-utility zones and allocating costs just within
one zone consisting of more than one transmission provider. However, we
recognize in response to Duke's request that special consideration is
needed when a small transmission provider is located within the
footprint of another transmission provider. For instance, a regional
cost allocation method might allocate costs to an area consisting of
one transmission provider that has within its borders one or more
smaller utilities that largely depend on its transmission system but
nevertheless own a little transmission of their own, so that they too
are transmission providers. This situation is not necessarily ``a zone
consisting of more than one transmission provider'' as this term is
used in this order. If the cost of a new transmission facility is
allocated entirely to an area consisting of one transmission provider
that has one or more smaller transmission providers within its borders,
this might qualify as a local cost allocation, not a regional cost
allocation. However, as petitioners point out, there may be a continuum
of examples that range from (i) one small municipality with a single
small transmission facility located within a transmission provider's
footprint, to (ii) a ``zone'' consisting of many public utility and
nonpublic utility transmission providers. Accordingly, we will address
whether a cost allocation to a multi-transmission provider zone is
regional on a case-by-case basis based on the specific facts presented.
Specific situations may be included in a compliance filing along with
the filed regional cost allocation method or methods.
    425. We disagree with Western Independent Transmission Group's
assertion that the Commission failed to provide a reasoned explanation
of its decision not to require the elimination of a federal right of
first refusal for local transmission facilities. In Order No. 1000, the
Commission recognized that incumbent transmission providers may have
reliability needs or service obligations.\502\ Accordingly, Order No.
1000 does not prevent an incumbent transmission provider from meeting
its reliability needs or service obligations by choosing to build new
transmission facilities that are located solely within its retail
distribution service territory or footprint and that are not selected
in a regional transmission plan for purposes of cost allocation.\503\
Thus, we affirm the decision in Order No. 1000 not to require
elimination from Commission-jurisdictional tariffs and agreements a
federal right of first for a local transmission facility.\504\ We also
note in response to Western Independent Transmission Group that the
Commission found that issues related to the generator interconnection
process and to interconnection cost recovery were outside the scope of
Order No. 1000.\505\ Order No. 1000 did not establish any new
requirements with respect to the generator interconnection process, and
we are not persuaded to address the generator interconnection process
on rehearing.
---------------------------------------------------------------------------

    \502\ Id. P 262. The Commission defined a local transmission
facility as a transmission facility located solely within a public
utility transmission provider's retail distribution service
territory or footprint that is not selected in a regional
transmission plan for purposes of cost allocation. An incumbent
transmission provider would retain the option of meeting its local
reliability needs or obligations to serve by building a transmission
facility in its retail distribution service territory or footprint.
Id. at P 63.
    \503\ Id. In P 262 of Order No. 1000, the Commission used the
term ``submitted for regional cost allocation'' where we intended
``selected in a regional transmission plan for purposes of cost
allocation.'' We provide that clarification here.
    \504\ Id. P 318.
    \505\ Id. P 760.
---------------------------------------------------------------------------

    426. In response to requests for clarification regarding what the
Commission considers to be an upgrade, we note that in Order No. 1000,
the term upgrade means an improvement to, addition to, or replacement
of a part of, an existing transmission facility. The term upgrades does
not refer to an entirely new transmission facility. The concept is that
there should not be a federally established monopoly over the
development of an entirely new transmission facility that is selected
in a regional transmission plan for purposes of cost allocation to
others. However, neither is the Commission eliminating the right of an
owner of a transmission facility to improve its own existing
transmission facility by allowing a third-party transmission developer
to, for example, propose to replace the towers or the conductors of a
transmission line owned by another entity.\506\ It is not feasible,
however, to list every type of improvement or addition, or name all the
parts of lines, towers and other equipment that may be replaced or
otherwise upgrades, and we will not do so here.
---------------------------------------------------------------------------

    \506\ Id. P 319.
---------------------------------------------------------------------------

    427. In response to ITC Companies, we clarify that the requirement
to eliminate a federal right of first refusal does not apply to any
upgrade, even where the upgrade requires the expansion of an existing
right-of-way. The issue is not whether the upgrade would be located in
an existing right-of-way, but whether the new transmission facility is
an upgrade to an incumbent transmission provider's own facilities.
Furthermore, the Commission reiterates that the nonincumbent
transmission developer reforms were not intended to alter an incumbent
transmission provider's use and control of its existing rights-of-way
under state law.\507\
---------------------------------------------------------------------------

    \507\ Id.
---------------------------------------------------------------------------

    428. We affirm the decision in Order No. 1000 to require the
elimination of a federal right of first refusal for reliability
projects. Allowing incumbent transmission providers to maintain a
federal right of first refusal, even with a limited 90-day election
period as proposed by Xcel, would discourage

transmission developers from proposing transmission projects that may
be a more efficient or cost-effective solution to meet regional
transmission needs, resulting in rates for jurisdictional transmission
services that are unjust and unreasonable or unduly discriminatory or
preferential. The fact that a particular transmission facility is
intended to meet a reliability need does not change our responsibility
to eliminate practices that result in unjust and unreasonable or unduly
discriminatory or preferential rates. Furthermore, Order No. 1000
includes several reforms that ensure that incumbent transmission
providers will be able to satisfy their reliability needs and service
obligations, even when they are relying on a nonincumbent transmission
developer's project to meet a reliability need. Specifically, Order No.
1000 includes a reevaluation requirement that requires public utility
transmission providers in a region to have procedures in place to
identify when delays in the development of a transmission facility
selected in a regional transmission plan for purposes of cost
allocation require evaluation of alternative solutions to ensure that
an incumbent transmission provider can meets its reliability needs or
service obligations.\508\ Moreover, we note again that Order No. 1000
continues to permit an incumbent transmission provider to meet its
reliability needs or service obligations by choosing to build new
transmission facilities that are located solely within its retail
distribution service territory or footprint and that are not selected
in a regional transmission plan for purposes of cost allocation.\509\
Accordingly, we disagree with petitioners that argue that a federal
right of first refusal for reliability project is necessary for
incumbent transmission providers to meet reliability needs or service
obligations.
---------------------------------------------------------------------------

    \508\ Id. P 329.
    \509\ Id. P 262.
---------------------------------------------------------------------------

    429. In response to LS Power's concerns regarding the definition of
a local transmission facility, we clarify that a local transmission
facility is one that is located within the geographical boundaries of a
public utility transmission provider's retail distribution service
territory, if it has one, otherwise the area is defined by the public
utility transmission provider's footprint. Thus, if the public utility
transmission provider has a retail distribution service territory and/
or footprint, then only a transmission facility that it decides to
build within that retail distribution service territory or footprint,
and that is not selected in a regional transmission plan for purposes
of cost allocation, may be considered a local transmission facility. In
the case of an RTO or ISO whose footprint covers the entire region, we
clarify that local transmission facilities are defined by reference to
the retail distribution service territories or footprints of its
underlying transmission owing members. We also clarify that the extent
of a public utility transmission provider's retail distribution service
territory or footprint is not to be measured as of the effective date
of Order No. 1000, but is the retail distribution service territory or
footprint in existence during the regional transmission planning cycle.
We decline to provide any of the further clarifications regarding the
definition of a local transmission facility as requested by LS Power
and will address such matters during the compliance process based on a
more complete record.
    430. Finally, in response to petitioners' concerns over which
facilities are selected in a regional transmission plan for purposes of
cost allocation, and for which a federal right of first refusal must
therefore be eliminated, we clarify that if any costs of a new
transmission facility are allocated regionally or outside of a public
utility transmission provider's retail distribution service territory
or footprint, then there can be no federal right of first refusal
associated with such transmission facility, except as provided in this
order.
3. Framework To Evaluate Transmission Projects Submitted for Selection
in the Regional Plan for Purposes of Cost Allocation
    431. In Order No. 1000, the Commission required each public utility
transmission provider to revise its OATT to describe the features of an
acceptable framework for project identification and selection. The
Commission required that this framework include: (1) Qualification
criteria to submit a transmission project for selection in the regional
transmission plan for purposes of cost allocation; (2) specification of
the information that must be submitted by a prospective transmission
developer in support of the transmission project it proposes in the
regional transmission planning process and the date by which such
information must be submitted to be considered in a given transmission
planning cycle; (3) a description of a transparent and not unduly
discriminatory process for evaluating whether to select a proposed
transmission facility in the regional transmission plan for purposes of
cost allocation; and (4) provisions allowing a nonincumbent
transmission developer to have the same eligibility as an incumbent
transmission provider to use a regional cost allocation method or
methods for any sponsored transmission facility selected in the
regional transmission plan for purposes of cost allocation. Last, the
Commission declined to require public utility transmission providers to
revise their OATTs to provide a transmission developer a right to
construct and own a transmission facility and also declined to allow a
transmission developer to maintain for a defined period of time its
right to build and own a transmission project that it proposed but that
is not selected.\510\
---------------------------------------------------------------------------

    \510\ Id. PP 323-40.
---------------------------------------------------------------------------

a. Qualification Criteria To Submit a Transmission Project for
Selection in the Regional Transmission Plan for Purposes of Cost
Allocation
i. Final Rule
    432. The Commission required each public utility transmission
provider to revise its OATT to demonstrate that the regional
transmission planning process in which it participates has established
qualification criteria that are not unduly discriminatory or
preferential for determining an entity's eligibility to propose a
transmission project for selection in the regional transmission plan
for purposes of cost allocation, whether that entity is an incumbent
transmission provider or a nonincumbent transmission developer.\511\
The Commission explained that the criteria must provide each potential
transmission developer the opportunity to demonstrate that it has the
necessary financial resources and technical expertise to develop,
construct, own, operate, and maintain transmission facilities.\512\ The
Commission found that one-size-fits-all qualification criteria would
not be appropriate, and that it is important for each transmission
planning region to have the flexibility to formulate qualification
criteria that best fits its transmission planning processes and
addresses the particular needs of the region, so long as the criteria
are fair and not unreasonably stringent when applied to either the
incumbent transmission provider or a nonincumbent transmission
developer.\513\
---------------------------------------------------------------------------

    \511\ Id. P 323.
    \512\ Id.
    \513\ Id. P 324.

---------------------------------------------------------------------------

ii. Requests for Rehearing and Clarification
    433. Several petitioners seek rehearing of the Commission's
requirement that the regional planning process develop qualification
criteria.\514\ They assert that Order No. 1000 creates an unreasonable
disparity between who establishes the criteria for a nonincumbent to be
deemed qualified to propose and construct a transmission project and
who bears the risk if such nonincumbent does not perform.\515\ They
state that each incumbent transmission provider remains responsible for
meeting its reliability and system security obligations in the event
that the nonincumbent fails to perform, but must rely on qualification
criteria developed by the region planning process. They state that this
disparity is unreasonable, arbitrary and capricious, and should be
revised to be more consistent with the model provided for in Order No.
890-A, which allows the transmission provider to establish reasonable
credit criteria.\516\ They also believe this would allow each incumbent
transmission provider that bears the greatest risk of non-performance
of a nonincumbent to better manage such risk.\517\
---------------------------------------------------------------------------

    \514\ See, e.g., Ad Hoc Coalition of Southeastern Utilities; and
Southern Companies.
    \515\ See, e.g., Ad Hoc Coalition of Southeastern Utilities; and
Southern Companies.
    \516\ Ad Hoc Coalition of Southeastern Utilities at 62 (citing
Order No. 890-A, Attachment L (Creditworthiness Procedures) to Pro
Forma OATT; Order No. 890 at P 1659); Southern Companies at 63
(citing Preventing Undue Discrimination and Preference in
Transmission Serv., Order No. 890-A, 121 FERC ] 61,297, Attachment L
(2007)).
    \517\ See, e.g., Ad Hoc Coalition of Southeastern Utilities; and
Southern Companies.
---------------------------------------------------------------------------

    434. Other petitioners request that the Commission standardize the
qualification criteria or otherwise clarify that certain criteria are
impermissible.\518\ NextEra argues that there should be a standardized
qualification requirement rather than the flexible approach adopted in
Order No. 1000 because it believes that such flexibility could permit
incumbents to devise qualification criteria that create barriers to
entry. NextEra states that, unlike other areas of Order No. 1000 that
endorse flexibility, there is no reason to believe that financial and
technical qualification criteria for new transmission entrants should
vary by region. NextEra points to the Commission's actions in
standardizing generator interconnection procedures under Order No. 2003
and credit reform rules under Order No. 741. NextEra also suggests that
the Commission look to the qualification criteria established by ERCOT
and CAISO as examples. Alternatively, NextEra states that the
Commission should initiate a negotiated rulemaking to develop consensus
criteria, which it states is the course the Commission followed in
developing Order No. 2003.
---------------------------------------------------------------------------

    \518\ See, e.g., NextEra; LS Power; and New York Transmission
Owners.
---------------------------------------------------------------------------

    435. LS Power requests that the Commission clarify that the
qualification criteria for entities that want to propose a project in
the regional transmission planning process are limited to financial and
technical matters. It also asks that the qualification criteria not
operate as a barrier to entry and should not include a qualification
that a new entrant be an existing public utility under state law or
have upfront siting authority. It contends that a new entrant would not
be able to achieve state public utility status at the assignment stage
because it is most often granted after the assignment of the
transmission project. LS Power similarly argues that the selection
criteria used to evaluate a project also should not require that a
project sponsor be an existing public utility under state law or have
upfront siting authority before it can be assigned a project. LS Power
contends that such selection criteria would also act as a barrier to
entry in that states most often grant public utility status and eminent
domain authority after the assignment of the transmission project.
    436. APPA requests that the Commission require that the minimum
participation criteria developed by incumbent transmission developers/
providers be fair and not unreasonably stringent as applied to public
power utilities.
    437. Transmission Access Policy Study Group seeks clarification
that the qualification criteria facilitate transmission dependent
utility joint ownership, and states that qualification criteria
designed for proposals submitted by a single entity could
unintentionally and needlessly foreclose beneficial project
participation by multiple joint owners.
    438. New York Transmission Owners request that transmission
planning regions be permitted to require NERC registration for
nonincumbent transmission developers as a precondition to being
assigned a reliability project.
iii. Commission Determination
    439. We affirm Order No. 1000's requirement that the public utility
transmission providers in each transmission planning region must
establish, in consultation with stakeholders, appropriate qualification
criteria for determining an entity's eligibility to propose a
transmission project for selection in the regional transmission plan
for purposes of cost allocation. As required under Order No. 1000,
these qualification criteria must not be unduly discriminatory or
preferential and must provide each potential transmission developer the
opportunity to demonstrate that it has the necessary financial
resources and technical expertise to develop, construct, own, operate,
and maintain transmission facilities.\519\ We disagree with petitioners
that this approach creates an unreasonable disparity between who
establishes the criteria for a nonincumbent transmission developer to
be deemed qualified to propose and construct a transmission project and
who bears the risk if such nonincumbent transmission developer does not
perform. Order No. 1000 makes clear that it is public utility
transmission providers themselves, in consultation with stakeholders,
that are responsible for complying with Order No. 1000 and that must
develop the qualification criteria for review by the Commission on
compliance.\520\
---------------------------------------------------------------------------

    \519\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 323.
    \520\ We reiterate that ``the qualification criteria required
[in Order No. 1000] should not be applied to an entity proposing a
transmission project for consideration in the regional transmission
planning process if that entity does not intend to develop the
proposed transmission project. The Order No. 890 transmission
planning requirements allow any stakeholder to request that the
transmission provider perform an economic planning study or
otherwise suggest consideration of a particular transmission
solution in the regional transmission planning process.'' Id. P 324
n.304.
---------------------------------------------------------------------------

    440. The Commission declines to adopt standardized qualification
criteria, as urged by NextEra. While the Commission's acknowledges
NextEra's concern that qualification criteria could act as a barrier to
entry, the Commission believes that there may be legitimate differences
between regions that may justify differences in the qualification
criteria. Each region is faced with its own set of challenges in
building new transmission facilities, and regions should be permitted
to account for those differences in their qualification criteria. For
this same reason, the Commission will not adopt certain minimum
qualification criteria. Regarding LS Power's petition that the
qualification criteria be limited to financial and technical matters,
we point out that Order No. 1000 states that ``[t]he qualification
criteria must provide each potential transmission developer the
opportunity to demonstrate that it has the necessary financial
resources and technical expertise to develop,

construct, own, operate and maintain transmission facilities,'' but
also permits each transmission planning region flexibility to formulate
qualification criteria that best fit its transmission planning
processes and addresses the particular needs of the region.\521\
---------------------------------------------------------------------------

    \521\ Id. PP 323-24.
---------------------------------------------------------------------------

    441. We clarify in response to LS Power that it would be an
impermissible barrier to entry to require, as part of the qualification
criteria, that a transmission developer demonstrate that it either has,
or can obtain, state approvals necessary to operate in a state,
including state public utility status and the right to eminent domain,
to be eligible to propose a transmission facility. As the Commission
emphasized in Order No. 1000, and reiterates here, the qualification
criteria must be fair and not unreasonably stringent when applied to an
incumbent transmission provider and a nonincumbent transmission
developer.\522\ The Commission will review on compliance whether any
proposed qualification criterion is unreasonably stringent when applied
to nonincumbent transmission developers such that the criteria act as
an unreasonable barrier to entry.\523\
---------------------------------------------------------------------------

    \522\ Id. P 324.
    \523\ Importantly, Order No. 1000 did not provide transmission
developers with a right to construct; rather, it required ``that a
nonincumbent transmission developer must have the same eligibility
as an incumbent transmission developer to use a regional cost
allocation method or methods for any sponsored transmission facility
selected in the regional transmission plan for purposes of cost
allocation.'' See id. P 332.
---------------------------------------------------------------------------

    442. If a transmission facility is selected in the regional
transmission plan for purposes of cost allocation, the Commission
clarifies that the transmission developer of that transmission facility
must submit a development schedule that indicates the required steps,
such as the granting of state approvals, necessary to develop and
construct the transmission facility such that it meets the transmission
needs of the region. As part of the ongoing monitoring of the progress
of the transmission project once it is selected, the public utility
transmission providers in a transmission planning region must establish
a date by which state approvals to construct must have been achieved
that is tied to when construction must begin to timely meet the need
that the project is selected to address. If such critical steps have
not been achieved by that date, then the public utility transmission
providers in a transmission planning region may remove the transmission
project from the selected category and proceed with reevaluating the
regional transmission plan to seek an alternative solution.
    443. We believe that there are a number of benefits to this
approach. First, it ensures that transmission developers that have the
technical and financial capability to build a transmission facility,
and meet other nondiscriminatory and non-preferential criteria, are
eligible to propose a transmission facility for evaluation and
selection, thereby increasing the universe of potential facilities
evaluated and selected to meet a region's transmission needs. Second,
it gives a nonincumbent transmission developer the opportunity to
propose a transmission facility while it seeks to obtain necessary
state approvals or otherwise seeks to comply with applicable state law
or regulation. Third, it provides the public utility transmission
providers in a transmission planning region with the ability to monitor
the development of a transmission facility selected in the regional
transmission plan for purposes of cost allocation, as well as the
ability to remove that new transmission facility if its developer is
unable to meet an established date by which the critical development
step of obtaining necessary state approvals must be achieved.
    444. We also deny New York Transmission Owners' request that the
public utility transmission providers in a transmission planning region
be permitted to require a transmission developer to demonstrate that it
has registered with NERC as a precondition to being assigned a
reliability project. As the Commission explained in Order No. 1000, all
entities that are users, owners or operators of the electric bulk power
system must register with NERC for performance of applicable
reliability functions.\524\ The procedures for registering as a
Functional Entity are set by NERC and approved-by the Commission under
section 215,\525\ and it is not appropriate for the Commission to amend
or interpret those procedures here under a section 206 action by
requiring all public utility transmission providers to revise their
tariffs to provide that a potential transmission developer must
register with NERC if not otherwise required under the NERC procedures,
merely to be eligible to propose a transmission project for selection
in the regional transmission plan for purposes of cost allocation.
---------------------------------------------------------------------------

    \524\ Id. P 342.
    \525\ NERC, Rules of Procedures (effective March 15, 2012),
available at http://www.nerc.com/files/NERC_ROP_Effective_20120315.pdf.
---------------------------------------------------------------------------

b. Evaluation of Proposals for Selection in the Regional Transmission
Plan for Purposes of Cost Allocation
i. Final Rule
    445. The Commission required each public utility transmission
provider to amend its OATT to describe a transparent and not unduly
discriminatory process for evaluating whether to select a proposed
transmission facility in the regional transmission plan for purposes of
cost allocation.\526\ The Commission explained that this process must
comply with the Order No. 890 transmission planning principles,
ensuring transparency, and the opportunity for stakeholder
coordination. The Commission further explained that the evaluation
process must culminate in a determination that is sufficiently detailed
for stakeholders to understand why a particular transmission project
was selected or not selected in the regional transmission plan for
purposes of cost allocation.\527\ Finally, the Commission declined to
require public utility transmission providers to revise their OATTs to
provide a right to construct and own a transmission facility and also
declined to allow a transmission developer to maintain for a defined
period of time its right to build and own a transmission project that
it proposed but that was not selected.\528\
---------------------------------------------------------------------------

    \526\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 328.
    \527\ Id.
    \528\ Id. P 338.
---------------------------------------------------------------------------

ii. Requests for Rehearing and Clarification
    446. Western Independent Transmission Group seeks rehearing of the
Commission's rejection of its proposal to require the use of an
independent third party observer to oversee evaluation and selection of
competing transmission projects to ensure that the process is being
managed fairly and efficiently.
    447. Illinois Commerce Commission argues that it is necessary for
the Commission to provide more specificity regarding the practical
means by which transmission providers can facilitate competition
between alternative proposals. It suggests that the transmission
provider identify the planning needs to be met and then solicit
developers to submit alternative plans to address those needs. Illinois
Commerce Commission explains that this formalized process would provide
a non-discriminatory and objective method for the transmission provider
to

evaluate alternative proposals, and argues that the Commission erred in
not requiring such a process.
    448. Similarly, FirstEnergy Service Company seeks clarification
that regional transmission planning processes need only consider
proposals that respond to identified needs, such that a ``needs first''
approach is acceptable. In support, FirstEnergy Service Company argues
that a planning model that requires the regional planning process to
analyze every individual proposal would render the process less
manageable, timely, and effective. FirstEnergy Service Company also
argues that, through Order No. 890, the Commission already has put in
place the mechanisms necessary to encourage innovative transmission
proposals.
    449. LS Power requests that the Commission affirmatively clarify on
rehearing that, if a region uses a sponsorship model for the assignment
of projects, the regions must treat an application for a project by a
nonincumbent transmission owner no differently from any other
applicant, and that sponsors that meet nondiscriminatory sponsorship
criteria are to be assigned construction and ownership of the projects
they sponsor unless the regional planning entity adequately justifies
assignment of the project to another entity, as PJM was required to do
in the Primary Power case.\529\ It states that without this explicit
statement, some will attempt to assign projects to non-sponsor
incumbent transmission owners on the basis of an inaccurate reading of
paragraph 338, where the Commission declined to adopt any right to
construct or ongoing sponsorship rights.
---------------------------------------------------------------------------

    \529\ LS Power at 6 (Primary Power, LLC, 131 FERC ] 61,015, at P
65 (2010)).
---------------------------------------------------------------------------

    450. LS Power also requests that the Commission clarify that in a
region using a sponsorship model rather than a competitive bidding
model, the process established by each public utility transmission
provider must include a specific mechanism to select, in a
nondiscriminatory manner, among competing qualified sponsors of
identical projects, or, as a backstop if no mechanism is agreed upon,
to assign such projects equally among qualified entities that have
sponsored identical projects. It explains that to the extent that only
one of the sponsors has sponsored the same project in an immediately
prior planning cycle, that the entity should have preference over those
entities newly sponsoring the project. LS Power further suggests that
the Commission should include a provision for ongoing sponsorship
rights, with some recognition or benefit to an entity for continuing to
advocate viable projects, at least between the continuing sponsor and
new sponsors of the same project. Additionally, LS Power states that
another mechanism to select among multiple sponsors of identical
projects is to select the entity that is willing to guarantee the
lowest net present value of its annual revenue requirement.
    451. In addition, LS Power requests that the Commission clarify
that to meet the ``not unduly discriminatory process'' requirement, the
selection criteria must meet certain minimum standards. It states that
the Commission should clarify that when cost estimates are part of
selection criteria, costs must be scrutinized in an equal manner
whether the project is sponsored by an incumbent or independent.
iii. Commission Determination
    452. The Commission affirms the decision in Order No. 1000 to
require each public utility transmission provider to amend its OATT to
describe a transparent and not unduly discriminatory process for
evaluating whether to select a proposed transmission facility in a
regional transmission plan for purposes of cost allocation.\530\ We
also affirm the Commission's decision not to require public utility
transmission providers to use an independent third party observer to
oversee the evaluation and selection of competing transmission
projects. In Order No. 1000, the Commission encouraged public utility
transmission providers to consider ways to minimize disputes, such as
through additional transparency mechanisms.\531\ However, the
Commission did not mandate any particular approach, and is not
persuaded now that an independent third party observer is necessary or
appropriate in all regions. Moreover, the Commission noted that the
requirements of the dispute resolution principle of Order No. 890 apply
to the regional transmission planning process.\532\ Thus, if a dispute
cannot be resolved by public utility transmission providers in the
regional transmission planning process, entities may take advantage of
that transmission planning region's dispute resolution provision.
Additionally, as noted in Order No. 1000, public utility transmission
providers in consultation with other stakeholders in a region may, if
they choose, propose to use an independent third-party observer and we
will review any such proposal on compliance.\533\
---------------------------------------------------------------------------

    \530\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 328.
    \531\ Id. P 330.
    \532\ Id. P 330 n.306.
    \533\ Order No. 1000, FERC Stats. & Regs. ] 31,323.
---------------------------------------------------------------------------

    453. While Order No. 1000 permits the public utility transmission
providers in a region to adopt a ``needs first'' approach to
transmission planning such as that advocated by the Illinois Commerce
Commission and FirstEnergy Service Company, the Commission declined to
adopt a one-size-fits-all approach to transmission planning. The
Commission believes that there are many different approaches to
transmission planning and requires only that the transmission planning
process adopted by a transmission planning region satisfy the
transmission planning principles discussed in Order No. 1000 and this
order. Thus, we decline to rule in the abstract in advance of the
compliance filings whether any particular transmission planning process
is the only appropriate process for all regions.
    454. The Commission clarifies that the public utility transmission
providers in a transmission planning region must use the same process
to evaluate a new transmission facility proposed by a nonincumbent
transmission developer as it does for a transmission facility proposed
by an incumbent transmission developer. In Order No. 1000, the
Commission required each public utility transmission provider to adopt
a transparent and not unduly discriminatory evaluation process that
complies with the Order No. 890 transmission planning principles.\534\
However, this requirement does not preclude public utility transmission
providers in regional transmission planning processes from taking into
consideration the particular strengths of either an incumbent
transmission provider or a nonincumbent transmission developer during
its evaluation.\535\
---------------------------------------------------------------------------

    \534\ Id. P 328.
    \535\ See id. P 260 (``An incumbent public utility transmission
provider is free to highlight its strengths to support transmission
project(s) in the regional transmission plan, or in bids to
undertake transmission projects in regions that choose to use
solicitation processes.'').
---------------------------------------------------------------------------

    455. The Commission denies LS Power's other requests for rehearing
regarding the selection of a transmission developer. The Commission
declined to address the selection of a transmission developer in Order
No. 1000. Aside from requiring the public utility transmission
providers in a region to establish criteria to assess a transmission
developer's qualifications to have its proposed transmission project
considered for selection in a

regional transmission plan for purposes of cost allocation, Order No.
1000 also requires public utility transmission providers in a region to
adopt transparent and not unduly discriminatory criteria for selecting
a new transmission project in a regional transmission plan for purposes
of cost allocation. We decline to set certain minimum standards for the
criteria used to select a transmission facility in a regional
transmission plan for purposes of cost allocation other than to require
that these selection criteria be transparent and not unduly
discriminatory. We also find that this purpose is met adequately by the
transmission planning principles of Order No. 890. We also anticipate
that selection criteria will vary from transmission planning region to
transmission planning region in accordance with each transmission
planning region's needs, just as other aspects of regional transmission
planning processes will vary, and LS Power has not persuaded us that
such flexibility is inappropriate. However, we clarify that when cost
estimates are part of the selection criteria, the regional transmission
planning process must scrutinize costs in the same manner whether the
transmission project is sponsored by an incumbent or nonincumbent
transmission developer.
    456. If a transmission project is selected in a regional
transmission plan for purposes of cost allocation, Order No. 1000
requires that the transmission developer of that transmission facility
(whether incumbent or nonincumbent) must be able to rely on the
relevant cost allocation method or methods within the region should it
move forward with its transmission project.\536\ We are not persuaded
to change this approach on rehearing. Further, we reiterate that we do
not require public utility transmission providers in a region to adopt
a provision for ongoing sponsorship rights, for the reasons set out in
Order No. 1000. The Commission concluded that granting transmission
developers an ongoing right to build sponsored transmission projects
could adversely impact the regional transmission planning process.\537\
We are not persuaded to reverse our decisions on the selection of
transmission developers. While we acknowledge LS Power's concerns, we
do not believe they warrant any revision of the selection of
transmission developers at this time given the diversity of methods for
selecting transmission developers used around the nation.
---------------------------------------------------------------------------

    \536\ Id. P 339.
    \537\ Id.
---------------------------------------------------------------------------

c. Reevaluation of Regional Transmission Plans When There Is a Project
Delay and Reliability Compliance Obligations of Transmission Developers
i. Final Rule
    457. In Order No. 1000, the Commission required each public utility
transmission provider to amend its OATT to describe the circumstances
and procedures under which public utility transmission providers in the
regional transmission planning process will reevaluate the regional
transmission plan to determine if delays in the development of a
transmission facility selected in a regional transmission plan for
purposes of cost allocation require evaluation of alternative
solutions, including those proposed by the incumbent transmission
provider, to ensure the incumbent transmission provider can meet its
reliability needs or service obligations.\538\
---------------------------------------------------------------------------

    \538\ Id. P 329.
---------------------------------------------------------------------------

    458. The Commission also explained that if a violation of a NERC
reliability standard by an incumbent would result from a nonincumbent
transmission developer's decision to abandon a transmission facility
meant to address such a violation, the incumbent transmission provider
does not have the obligation to construct the nonincumbent's
project.\539\ Rather, the incumbent transmission provider must identify
the specific NERC reliability standard(s) that would be violated and
submit a mitigation plan to address the violation.\540\ The Commission
explained that if the incumbent public utility transmission provider
follows the NERC-approved mitigation plan, the Commission will not
subject it to enforcement action for the specific NERC reliability
standard violation(s) caused by a nonincumbent transmission developer's
decision to abandon a transmission facility.\541\
---------------------------------------------------------------------------

    \539\ Id. P 344.
    \540\ Id.
    \541\ Id.
---------------------------------------------------------------------------

    459. The Commission also noted that, when a nonincumbent
transmission developer becomes subject to the requirements of FPA
section 215 and the regulations thereunder, it will be required to
comply with all applicable reliability obligations, including
registering with NERC for performance of applicable reliability
functions.\542\ The Commission stated that if there are concerns about
when compliance with NERC registration and reliability standards would
be triggered, the appropriate forum to raise these questions and
request clarification is the NERC process.\543\
---------------------------------------------------------------------------

    \542\ Id. P 342.
    \543\ Id. P 343.
---------------------------------------------------------------------------

ii. Requests for Rehearing and Clarification
    460. Some petitioners question whether the reevaluation requirement
set forth in Order No. 1000 are sufficient to protect incumbent
transmission providers from the repercussions related to a
nonincumbent's failure to build a project in time.\544\ For instance,
these petitioners argue that the Commission failed to protect incumbent
transmission providers from the increased risk of violations of state
reliability or resource adequacy requirements, and other state service
obligations.\545\ MISO Transmission Owners Group 2 also adds that the
incumbent utility could face civil liability, state regulatory
sanctions, and financial harm resulting from damage to its own
facilities or the facilities of another entity caused by the action of
the nonincumbent.
---------------------------------------------------------------------------

    \544\ See, e.g., Southern Companies; Edison Electric Institute;
MISO Transmission Owners Group 2; and Xcel.
    \545\ See, e.g., Edison Electric Institute; and MISO
Transmission Owners Group 2.
---------------------------------------------------------------------------

    461. Some commenters argue that incumbent developers should not be
burdened with monitoring the status of a nonincumbent developer's
progress. Specifically, if the reevaluation requirement would obligate
incumbents to discover or address nonincumbent delays prior to being
notified by the nonincumbent, Southern Companies request rehearing of
this requirement in Order No. 1000.\546\ Southern Companies also
request rehearing of the reevaluation requirement to the extent it
could inhibit, prevent or slow an incumbent's decision to address a
delay or the implementation of its corrective plan. Similarly, Southern
California Edison requests that the Commission require regional
transmission planning entities to develop protocols for how such
transmission planning entities will: (1) Be kept apprised by
nonincumbent developers of the status of their projects; and (2) notify
the applicable incumbent transmission owner that it needs to develop a
mitigation plan because a project has been delayed or abandoned by a
nonincumbent developer. In addition, Southern Companies contend that
each incumbent transmission provider and planning authority should be
permitted

to reevaluate its own local transmission plan to determine whether a
nonincumbent's delay in constructing a regional facility will adversely
impact reliability on the incumbent's system. In addition, Southern
Companies argue that because the reevaluation requirement does not
protect against the need to implement operational adjustments, Order
No. 1000 fails to protect against service reliability problems and
fails to weigh the adverse impacts against the benefits that the
Commission foresees.
---------------------------------------------------------------------------

    \546\ Southern Companies at 78 (citing McElroy Electronics Corp.
v. FCC, 990 F.2d 1351, 1358 (D.C. Cir. 1993)).
---------------------------------------------------------------------------

    462. Ad Hoc Coalition of Southeastern Utilities and Large Public
Power Council also assert that there is no substantial evidence for
concluding, as the Commission does in paragraph 263 of Order No. 1000,
that the potential costs associated with a delayed or abandoned
nonincumbent transmission facility are remediable by a reevaluation of
the regional plan. For example, Large Public Power Council explains
that by the time construction delays place a system at risk, the damage
will have been done, since such delays will postdate the planning that
contemplated the facilities at issue, often by several years. As such,
it maintains that even if the incumbent utility can step in with
sufficient lead-time so that reliability is not threatened, and the
cost of this activity is recoverable, there is little that can be done
to save ratepayers from the associated costs, and there is no basis to
conclude that nonincumbent participation in the transmission
development process will therefore be worth it.
    463. Several petitioners seek rehearing and clarification of the
Commission's decision to allow incumbent transmission providers to
implement a NERC mitigation plan to avoid an enforcement action if a
nonincumbent transmission developer abandons a project needed to meet a
reliability need. For example, Xcel asserts that Order No. 1000's
discussion of a NERC mitigation plan may involve interrupting load
under certain conditions, or implementing rolling outages. Xcel argues
that this degradation of service to end use customers is contrary to
the fundamental purposes of FPA section 215 and would also result in a
loss of revenues to the utility.
    464. Transmission Dependent Utility Systems argue that Order No.
1000 sheds no light on whether its mitigation plan solution is
realistic or available and does not address who will be responsible for
maintaining power if neither the incumbent nor the nonincumbent
transmission provider can be held accountable for completion or
maintenance of reliability-driven projects. Similarly, PSEG Companies
argue that the problem of abandonment by a nonincumbent of a project
needed for reliability cannot be fixed by reliability standards or by
mitigation plans submitted in ``compliance'' with those standards. They
state that the Commission failed to recognize that NERC reliability
standards will not be applicable to a nonincumbent developer unless and
until the project is constructed and in-service.
    465. Petitioners point out possible difficulties that may arise
because similar terms have distinct meanings in a public utility
transmission provider's OATT under FPA 205 and the reliability
standards under FPA 215. Several petitioners argue that it is not
always a public utility transmission provider that is responsible for
conducting a reevaluation or developing a mitigation plan.\547\ For
instance, Southern Companies argue that public utility transmission
providers do not conduct transmission planning or evaluate or
reevaluate transmission plans. Instead, Southern Companies argue that
planning authorities and transmission planners are the appropriate
entities to determine the impacts of a delay on local plans and are
responsible for meeting reliability and service obligations, including
the state-mandated duty to serve native load. Southern Companies argue
that the Commission cannot remove or dilute that responsibility by
delegating it to another entity without preempting state law. Southern
Companies state that if Order No. 1000 does not intend the term
``public utility transmission provider'' to mean Transmission Service
Provider under the NERC Functional Model, the Commission must grant
rehearing to determine what category of Registered Entity is meant, or
extend the commencement of the 12-month compliance window until NERC
has determined which category of Registered Entity is appropriate to
conduct the activities required by Order No. 1000.\548\ Furthermore,
Edison Electric Institute seeks clarification that an incumbent
transmission provider need not have a retail distribution service
territory and need not construct the new facilities entirely within its
retail distribution service territory to qualify for protection from an
enforcement action as described in paragraph 344 of Order No. 1000.
---------------------------------------------------------------------------

    \547\ See, e.g., PSEG Companies; and Southern Companies.
    \548\ We note that the capitalized terms refer to specific terms
used in the NERC Reliability Standards.
---------------------------------------------------------------------------

    466. In addition, PSEG Companies argue that using the term
``transmission provider'' creates confusion because, under the NERC
Functional Model, the term could apply to a number of different
functions, and these different functions are very different even if in
ISO/RTO regions the ``transmission provider'' is the ISO/RTO. PSEG
Companies argue that the Commission erred by seeking to impose the
responsibility to develop a ``mitigation plan'' onto incumbent
transmission owners, and that this requirement demonstrates that the
Commission misunderstands the NERC process. Thus, according to PSEG
Companies, the process for addressing nonincumbents' abandonment of
facilities would not work as envisioned, at least in the ISO/RTO
context where the transmission owner is not responsible for planning
the system and would not be responsible for filing a mitigation plan in
the event of abandonment.
    467. Other petitioners request clarification regarding the scope of
the waiver. Edison Electric Institute recommends that the Commission
use NERC terminology to clarify the scope of the waiver. Other
petitioners argue that if the waiver applies only to the incumbent
transmission provider as defined in Order No. 1000, the application is
too narrow.\549\ In addition to the incumbent transmission provider,
Edison Electric Institute argues that the protection from an
enforcement action should extend to other entities that might be found
in violation of a reliability standard, such as balancing authorities
and reliability coordinators. APPA agrees and adds that all of the
transmission providers will be adversely affected to at least some
extent due to the interconnected nature of the transmission network.
Transmission Dependent Utility Systems add that third parties with NERC
reliability obligations for certain transmission facilities, such as
municipal utilities and rural electric cooperatives, also should be
held harmless from penalties and NERC enforcement actions if a
nonincumbent transmission developer abandons or fails to maintain a
project needed to address reliability concerns. For example, even
though Southern California Edison considers CAISO to be the
transmission provider, Southern California Edison asserts that it
develops and implements NERC mitigation plans as the NERC registered

transmission owner and therefore should be entitled to protection.
---------------------------------------------------------------------------

    \549\ See, e.g., Edison Electric Institute; Southern California
Edison; and APPA.
---------------------------------------------------------------------------

    468. Southern Companies also request rehearing of Order No. 1000's
failure to explain its departure from existing policy and regulations
regarding mitigation plans. Southern Companies argue that requiring an
incumbent to submit a mitigation plan for a nonincumbent's abandonment
of necessary facilities would bestow upon the incumbent the impossible
task of ensuring that another entity will not make poor business
decisions, go bankrupt, or otherwise abandon or cancel its projects.
Furthermore, Southern Companies state that Order No. 1000 indicates the
incumbent may need to construct redundant and duplicate facilities to
guard against the potential of nonincumbent delay or abandonment of its
project. In addition, Southern Companies request rehearing to the
extent incumbents are required to propose a corrective action for
review by the regional process because such a requirement would impair
service reliability.\550\ Southern Companies also request clarification
that the costs of the delayed regional facility will not be allocated
to an incumbent that constructs a local transmission solution to meet
its reliability or service needs in the face of delay.
---------------------------------------------------------------------------

    \550\ Southern Companies at 81-82 (citing Motor Vehicle Mfrs.
Assoc. of the United States, Inc. v. State Farm Mutual Auto. Ins.
Co., 463 U.S. 29, 43 (1983)).
---------------------------------------------------------------------------

    469. Petitioners also argue that the protection from an enforcement
action should be applicable to any project that an incumbent relies on
to satisfy its reliability obligations, including reliability, public
policy or economic-based projects.\551\ Southern California Edison
points out that a project intended to address a NERC violation or other
reliability concerns may be dependent on another transmission project
being completed first, including a public policy or economic project.
Ameren argues that such other projects, which may have received
regional cost allocation, will almost certainly have some measure of
reliability effect because the grid is interconnected and that the
failure of any such project could cause a blackout.
---------------------------------------------------------------------------

    \551\ See, e.g., Southern California Edison; Xcel; Ameren; and
Edison Electric Institute.
---------------------------------------------------------------------------

    470. Some petitioners seek clarification that the protections found
in paragraph 344 will prevent the Commission, NERC, or a Regional
Entity from considering a violation that is covered by this protection,
or a mitigation plan developed to address such a violation, as a prior
violation when determining the penalty for a new violation.\552\
Moreover, Edison Electric Institute seeks clarification that the
protections described in paragraph 344 will apply to any Reliability
Standard violation, including an operationally-focused violation,
resulting from abandonment of a project by a nonincumbent transmission
developer. Edison Electric Institute asserts that it is unfair to
provide protection only for violations specifically envisioned at the
time the project was conceived. Finally, Edison Electric Institute
seeks clarification that the safe harbor provision will prevent the
Commission, NERC, or a Regional Entity from considering a violation
that is covered by this safe harbor protection or a mitigation plan
developed to address such a violation as a prior violation when
determining the penalty for a new violation.
---------------------------------------------------------------------------

    \552\ See, e.g., Edison Electric Institute; and Southern
California Edison.
---------------------------------------------------------------------------

    471. Southern California Edison requests that the Commission
clarify that an incumbent transmission owner will not be subject to an
enforcement action or any other sanction or penalty if it cannot follow
or implement an approved mitigation plan for reasons beyond its
control. It states that after Order No. 1000, a transmission owner may
be asked to develop a mitigation plan without much of the key
information, which means an incumbent transmission owner may not be
able to develop an infallible mitigation plan and should not be
penalized if implementation of its plan is delayed or if the plan needs
to be revised to reflect new information that becomes known to the
incumbent when the mitigation efforts are underway.
    472. In addition, Southern California Edison requests that the
Commission clarify that penalties, sanctions, or enforcement actions
also will not be levied against an incumbent transmission owner for
reliability problems that arise from the actions of a nonincumbent
transmission developer in connection with delays of a transmission
facility, or the operation or maintenance thereof.
    473. Southern California Edison also argues that the Commission
should clarify that, as long as the incumbent transmission owner
submits its mitigation plan to an appropriate regional entity, the
transmission owner should not face any enforcement actions, penalties
or sanctions while the mitigation plan is pending approval. Southern
California Edison states that it does not submit mitigation plans
directly to NERC, but instead initially submits its plan for approval
to the Regional Entity. Therefore, Southern California Edison states
that there will be some inevitable delay between the time that a
transmission owner submits a mitigation plan and the time that the plan
is approved by NERC, and argues that it should not be penalized for
such inevitable delay.
    474. Some petitioners argue that the Commission's reevaluation and
enforcement provisions in Order No. 1000 are inconsistent with section
215 of the FPA, and fail to adequately protect incumbents.\553\ For
example, Edison Electric Institute asserts that if an incumbent
transmission provider violates state resource adequacy or reliability
requirements, it may be subject to significant monetary penalties and
other sanctions, which the Commission's grant of protection from a
section 215 enforcement action has no effect on and cannot preempt.
Edison Electric Institute argues that the Commission failed to discuss
these implications and has thus engaged in arbitrary and capricious
decision-making and should grant rehearing to remove the right of first
refusal for reliability projects.
---------------------------------------------------------------------------

    \553\ See, e.g., Xcel; Southern Companies; and MISO Transmission
Owners Group 2.
---------------------------------------------------------------------------

    475. Xcel argues that Order No. 1000 ignores the substantial record
evidence that the policies adopted are inconsistent with the objectives
of section 215 of the FPA and the Commission's initiatives to improve
electric system reliability through mandatory standards. Xcel contends
that forcing utility transmission providers to rely on a third party to
fulfill section 215 obligations does not constitute reasoned decision-
making. Southern Companies add that Order No. 1000's nonincumbent
requirements pose threats to reliability and economic service by
forcing disintegration of the transmission network. MISO Transmission
Owners Group 2 argues that nothing in EPAct 2005 authorizes the
Commission to provide blanket waivers of critical reliability standards
for the purposes of achieving some policy preference unrelated to the
enforcement of mandatory reliability standards.
    476. Southern Companies also argue that the Commission
impermissibly uses section 206 to impose reliability requirements
instead of using its section 215 authority. Southern Companies argue
that this action violates the Whole Act Rule by making section 215's
goal of protecting reliability subservient to section 206.\554\
Accordingly, Southern

Companies assert that the Commission should have gone through the
Commission-approved NERC standards and enforcement processes
established pursuant to section 215 of the FPA, the Commission's
regulations, and Commission precedent, rather than unilaterally
developing these reliability-related reevaluation and enforcement
protections and imposing their requirements onto users, owners, and
operators of the bulk-power system. Southern Companies argue the
enforcement action waiver is inconsistent with, and may conflict with
existing NERC Reliability Standards.
---------------------------------------------------------------------------

    \554\ Southern Companies at 77 n.251 (citing 5 U.S.C. 706).
---------------------------------------------------------------------------

iii. Commission Determination
    477. The Commission affirms its decision to require each public
utility transmission provider to amend its OATT to describe the
circumstances and procedures under which public utility transmission
providers in the regional transmission planning process will reevaluate
the regional transmission plan to determine if delays in the
development of a transmission facility selected in a regional
transmission plan for purposes of cost allocation require evaluation of
alternative solutions, including those proposed by the incumbent
transmission provider, to ensure the incumbent transmission provider
can meet its reliability needs or service obligations.\555\ As the
Commission explained in Order No. 1000, the focus here is on ensuring
that adequate processes are in place to determine whether delays
associated with completion of a transmission facility selected in a
regional transmission plan for purposes of cost allocation have the
potential to adversely affect an incumbent transmission provider's
ability to fulfill its reliability needs or service obligations. We
believe that if these processes are followed, incumbent transmission
providers should be able to meet reliability related requirements.
---------------------------------------------------------------------------

    \555\ Order 1000, FERC Stats. & Regs. ] 31,323 at P 329.
---------------------------------------------------------------------------

    478. In response to Xcel's and Southern Companies' argument that
the reevaluation requirement does not protect against the need to
implement operational adjustments, the present operationally-focused
NERC reliability standards require Functional Entities to operate so
that the portion of the system that is in service at that time will be
capable of delivering the output of generation to firm demand and
transfers within the applicable performance criteria. Accordingly, a
Functional Entity must prepare its system to operate regardless of
whether a transmission project is delayed or abandoned. Thus, the
Commission concludes that there is no need to set requirements in
addition to those already established in the applicable NERC
reliability standards.
    479. In response to those petitioners concerned that they must
individually monitor the status of a nonincumbent transmission
developer's progress in developing its transmission facility selected
in the regional transmission plan for purposes of cost allocation, we
note that transmission planners and transmission developers already
routinely communicate regarding the status of the construction of a
transmission project. Consistent with applicable NERC Reliability
Standards, a Functional Entity remains responsible for complying with
all applicable Reliability Standards, such as studying performance of
its system and deciding when it must develop corrective plans to ensure
that its system responds reliably as prescribed by those
standards.\556\ As such, we emphasize that Order No. 1000 does not
change any obligations an incumbent transmission provider, as a
Functional Entity, may have under the NERC Reliability Standards to
monitor a nonincumbent transmission developer's progress in developing
its transmission facility selected in the regional transmission plan
for purposes of cost allocation. Furthermore, Order No. 1000 left it to
public utility transmission providers in a transmission planning region
to adopt procedures in their OATTs for reevaluating transmission
facilities selected in the regional transmission plan for purposes of
cost allocation. We continue to believe this approach is appropriate.
---------------------------------------------------------------------------

    \556\ NERC Reliability Standards in the Facility Connection and
Transmission Planning series ensure evaluation of the reliability
impact of the new facilities connections, and coordination and
results sharing by the entities involved, as well as development of
corrective plans if reliability requirements are not met when
projects are delayed or abandon.
---------------------------------------------------------------------------

    480. The Commission also affirms, with certain clarifications, its
decision in Order No. 1000 to not subject an incumbent public utility
transmission provider to a penalty for a violation of a NERC
reliability standard caused by a nonincumbent transmission developer's
decision to abandon a transmission facility if the incumbent public
utility transmission provider has identified the violation and
submitted a NERC mitigation plan to address it.\557\ The Commission
used ``enforcement action'' in Order No. 1000, but is not using this
term here because ``enforcement action'' also could imply that
Registered Entities are not going to be required to mitigate any NERC
reliability standards violations. The Commission clarifies that,
although it will not seek penalties, it will ensure that Registered
Entities implement appropriate mitigation plans.
---------------------------------------------------------------------------

    \557\ Order 1000, FERC Stats. & Regs. ] 31,323 at P 344.
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    481. The Commission agrees with petitioners that argue that
entities other than incumbent public utility transmission providers may
violate a NERC reliability standard in the event that a nonincumbent
transmission developer abandons a transmission facility. In some
regions, the incumbent public utility transmission provider may not be
the entity responsible for complying with the NERC reliability
standards implicated by the abandonment of a nonincumbent transmission
developer's project. We also agree with Ameren and other petitioners
that argue that the abandonment of a nonincumbent transmission project
that is designed to meet economic needs or transmission needs driven by
a Public Policy Requirement could impact reliability. Therefore, we
clarify that the Commission will not subject a Registered Entity \558\
to a penalty for a violation of a NERC reliability standard caused by a
nonincumbent transmission developer's decision to abandon any type of
transmission facility selected in the regional transmission plan for
purposes of cost allocation if, on a timely basis, that Registered
Entity identifies the violation and complies with all of its
obligations under the NERC reliability standards to address it.
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    \558\ We use the term Registered Entity to refer an owner,
operator, or user of the Bulk Power System, or the entity registered
as its designee for the purpose of compliance, that is included in
the NERC Compliance Registry. See, North American Electric
Reliability Corporation, Compliance Monitoring and Enforcement
Program, Appendix 4C to the Rules of Procedures (effective Jan. 31,
2012), available at: http://www.nerc.com/files/Appendix_4C_CMEP_20120131.pdf.
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    482. The remaining requests for rehearing or clarification posit
enforcement situations that are uncertain or speculative. We decline to
rule on these requests for rehearing or clarification because we find
that they are premature. We believe that, with the clarifications
granted above, entities have sufficient information to understand when
the Commission will not subject a Registered Entity to enforcement
action for a violation of a NERC reliability standard caused by a
nonincumbent transmission developer's decision to abandon a
transmission facility. Furthermore, many of these petitions in effect
argue that the Commission should not have required

public utility transmission providers to eliminate a federal right of
first refusal from Commission jurisdictional-tariffs and agreements in
Order No. 1000. The Commission has adequately explained in Order No.
1000 and in this order the need for eliminating a federal right of
first refusal.
    483. Finally, contrary to arguments by petitioners, the Commission
was not required to use its section 215 authority to adopt the
reevaluation requirements or to state the circumstances under which it
would exercise its enforcement discretion. Rather, the reevaluation
requirement is a tariff obligation not a reliability obligation under
section 215. Furthermore, in stating the circumstances under which the
Commission would exercise its enforcement discretion, the Commission
did not create new, or modify existing, NERC reliability standards. Had
the Commission done so, it would be required to adopt a reliability
standard through its authority set out in section 215. Instead, the
Commission appropriately exercised its discretion under section 215
enforcement authority to set forth a particular circumstance when it
will not e penalize a Registered Entity.
d. Recovery of Abandoned Plant Costs and Backstop Authority
i. Final Rule
    484. In Order No. 1000, the Commission found that when an incumbent
transmission provider is called upon to complete a transmission project
that it did not sponsor, there would be a basis for the incumbent
transmission provider to be granted abandoned plant recovery for that
transmission facility, upon the filing of a petition for declaratory
order requesting such rate treatment or a request under section 205 of
the FPA.\559\
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    \559\ Order No. 1000, FERC Stats. & Regs. ] 31,323 at P 267.
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ii. Requests for Rehearing
    485. APPA and Transmission Access Policy Study Group question the
Commission's decision to grant abandoned plant cost recovery to an
incumbent transmission provider in certain circumstances. Transmission
Access Policy Study Group and APPA argue that granting incumbent
transmission providers abandoned cost recovery under Order No. 1000 is
an unjustified deviation from Order No. 679's case-by-case approach.
Transmission Access Policy Study Group raises several questions that it
asserts highlight the need for the Commission to look at the facts of
each request for abandoned plant recovery rather than committing the
public in all circumstances to pay for unfinished projects. APPA argues
that abandoned plant cost recovery is an incentive that should be
granted on a case-by-case basis where the granting of such an incentive
is shown to be necessary and appropriate.
    486. Southern California Edison also notes that Order No. 1000
states in paragraph 344 that the incumbent transmission owner does not
have an obligation to construct a transmission facility intended to
address a possible NERC violation, but then states in paragraph 267
that there may be circumstances when an incumbent may be called upon to
complete a project that it did not sponsor. Southern California Edison
requests that the Commission clarify: (1) How the statements in
paragraphs 267 and 344 should be reconciled so that they are
consistently interpreted and implemented; (2) in which situations a
transmission provider may be required to complete a transmission
facility it did not sponsor; and (3) what that completion obligation
entails.
    487. Southern California Edison also seeks clarification that Order
No. 1000 does not preclude regions from applying backstop transmission
development obligations to all participating transmission owners in the
region and allows regions that impose backstop obligations to apply
them on an equivalent basis among incumbents and nonincumbents.
Southern California Edison argues that to require only incumbents to
serve as the safety-net for all nonincumbent projects would impose a
burden upon incumbents that could impede their ability to compete for
projects. On the other hand, Xcel recommends that tariffs incorporate a
backstop that reflects the incumbent utility's obligation as provider
of last resort to build transmission needed for reliability even if the
incumbent does not exercise a right of first refusal and no one else
offers to build it.
    488. Southern California Edison requests clarification that the
incumbent transmission owner will be fully compensated for mitigation
costs through ``grid-wide'' rates to offset the substantial burden of
developing and implementing mitigation plans. In addition, Edison
Electric Institute seeks clarification that an incumbent transmission
provider that steps in to complete an abandoned reliability project in
the circumstances discussed in paragraph 344 of Order No. 1000, it has
no obligation to purchase the facilities, materials, or any other
assets related to the abandoned project, at cost or otherwise. It
argues that such a requirement would provide unwarranted financial
protections for nonincumbent transmission developers, and remove one of