result, we find that commenters have provided sufficient evidence that
the use of pre-1994 total transfer capability values for paths within
WECC does not exempt those paths from the total transfer capability
requirement in the Rated System Path Methodology. We are further
satisfied that ratings for existing paths with pre-1994 total transfer
capability values are not incorrectly based on stale assumptions
because the existing path ratings must be adjusted for seasonal
variances.
---------------------------------------------------------------------------

    \118\ See WECC, Overview of Polices and Procedures for Regional
Planning Project Review, Project Rating Review, and Progress Reports
(Revised April 2005), Sect. 2.3 Paths Subject To This Procedure,
available at: http://www.wecc.biz/library/WECC%20Documents/
Miscellaneous%20Operating%20and%20Planning%20Policies%20and%20Procedu
res/
Overview%20Policies%20Procedures%20RegionalPlanning%20ProjectReview%2
0ProjectRating%20ProgressReports--07-05.pdf.
---------------------------------------------------------------------------

    244. Although Requirement R2.7 appears to have been crafted to
accommodate existing practices within WECC, the Commission points out
that MOD-029-1 is a national Reliability Standard. Thus, the
requirement is equally binding upon transmission operators and
transmission service providers using the Rated System Path Methodology
to calculate total transfer capabilities or available transfer
capabilities for path outside of WECC. The Commission therefore
clarifies that any transmission operator or transmission service
provider operating outside of WECC that uses the Rated System Path
Methodology must demonstrate to the ERO and the Commission a similar
need to implement Requirement R2.7.
b. Counterschedules
Comment
    245. Puget Sound comments that counterflows are a mandatory
component of the available transfer capability formula but contends
that it is common practice in the Western Interconnection to
incorporate counterschedules into non-firm available transfer
capability calculations, instead of counterflows as defined in the
formula. Puget Sound therefore requests that the Commission clarify in
the Final Rule that using counterschedules will not be considered a
violation of MOD-029-1. In addition, Puget Sound asks the Commission to
clarify that counterflows and counterschedules are interchangeable
terms, consistent with Western Interconnection practices.

Commission Determination
    246. Puget Sound's request is reasonable, and insofar as
calculating non-firm available transfer capability using
counterschedules as opposed to counterflows achieves substantially
equivalent results, using them will not be considered a violation.
However, we do not have enough information to determine that the terms
are generally interchangeable in all circumstances. The ERO should
consider Puget Sound's concerns on this issue when making future
modifications to the Reliability Standards.
6. MOD-030-2, Flowgate Methodology
    247. In the NOPR, the Commission proposed to approve MOD-030-2
without modification. Because MOD-030-2 wholly superseded MOD-030-1,
NERC proposed to make the Reliability Standard effective on the same
date upon which MOD-030-1 would have become effective. Thus, the
Commission proposed to approve MOD-030-2 with an effective date set as
the first day of the first quarter no sooner than one calendar year
after approval of the Reliability Standard and its related three
standards (MOD-001-1, MOD-028-1, and MOD-29-1).
a. MOD-030-2, Requirements R2.4 and R2.5
NOPR Proposal
    248. In the NOPR, the Commission proposed to approve MOD-030-2,
including sub-requirements R2.4 and R2.5. Sub-requirement R2.4 provides
that the transmission operator shall, at a minimum, establish the total
flowgate capability of each of the defined flowgates as equal to: (1)
For thermal limits, the system operating limit, of the flowgate; and
(2) for voltage or stability limits, the flow that will respect the
system operating limit of the flowgate. Sub-requirement R2.5 provides
that the transmission operator shall, at a minimum, establish the total
flowgate capability once per calendar year.
Comments
    249. Entergy states that it interprets sub-requirements R2.4 and
R2.5 as requiring an annual reevaluation to confirm the total flowgate
capability of a defined flowgate is correctly set at the system
operating limit of the flowgate based on thermal limits or the
appropriate flow that will respect the system operating limit of the
flowgate based on voltage or stability limits. Entergy contends that,
when considered with sub-requirement R2.4, sub-requirement R2.5 could
create confusions as to whether, as part of the annual ``re-
establishment'' of the total flowgate capability, the transmission
operators must first re-establish the system operating limit of each
defined flowgate. Entergy states that the studies and tests that must
be performed to establish the system operating limit of a set of
transmission facilities typically require significant time and
resources, and it is unlikely that they could be completed for all
flowgates within one year. Accordingly, Entergy requests clarification
that, as part of the annual establishment of the total flowgate
capability of a flowgate, the transmission operator is not required to
re-rate transmission facilities on an annual basis.
Commission Determination
    250. The Commission finds that, under sub-requirements R2.4 and
R2.5, transmission operators are not required to update system
operating limits of each flowgate when establishing the annual total
flowgate capability. However, as per sub-requirement R2.5.1, the
transmission operator should update the total flowgate capability
within seven calendar days of the notification if it is notified of a
change in the rating by the transmission owner that would affect the
total flowgate capability of a flowgate used in the available flowgate
capability process.
b. MOD-030-2, Requirements R3 and R10
NOPR Proposal
    251. The Commission proposed, in the NOPR, to approve MOD-030-2
including Requirements R3 and R10. Requirement R3 requires the
transmission operator to make available to the transmission service
provider a transmission model to determine available flowgate
capability that meets the criteria provided in the sub-requirements.
Requirement R10, and its sub-requirements, provides that each
transmission service provider shall recalculate available flowgate
capability, utilizing the updated models described in sub-requirements
R3.2, R3.3 and Requirement R5, at a minimum on the following frequency
unless none of the calculated values identified in the available
flowgate capability equation have changed: For hourly availability
flowgate capability, once per hour; for daily availability flowgate
capability, once per day; and for monthly availability flowgate
capability, once per week. Sub-requirements R3.2 and R3.3 require that
the transmission operator make available to the transmission service
provider a transmission model for determination of availability
flowgate capability that is: Updated at least once per day for
availability flowgate capability for intra-day, next day, and days two
through thirty; and updated at least once per month for availability
flowgate capability calculations for months two through thirteen.
Requirement R5 addresses further requirements for data included in the
models.
Comment
    252. Entergy states that it understands sub-requirements R3.2 and
R3.3 as establishing a requirement that the transmission model used by
the transmission service provider must be updated, or resolved, with a
frequency of once a day and/or once per month, according to the
applicable availability flowgate capability calculation. On the other
hand, Entergy notes, Requirement R10 establishes requirements that the
transmission service provider recalculates availability flowgate
capability by algebraically decrementing or incrementing availability
flowgate capability values as appropriate, using the most recently
updated transmission model on a more frequent basis. Entergy requests
clarification that the transmission model used in the available
flowgate capability calculations does not need to be updated more
frequently than under the timelines set forth in sub-requirements R3.2
and R3.3, i.e., that the transmission model itself does not need to be
updated according to the timelines in Requirement R10, which would only
apply to the recalculation of availability flowgate capability values.
Commission Determination
    253. The Commission finds that sub-requirements R3.2 and R3.3 set
the frequency by which the transmission model used in the available
flowgate capability calculations needs to be updated. Transmission
operators are not required to update the transmission model more
frequently than prescribed in these sub-requirements. Under requirement
R10, transmission service providers must use the transmission models
provided by transmission operators to recalculate available flowgate
capability on a more frequent basis, i.e., hourly, once per hour;
daily, once per day; and, monthly, once per week. A transmission
service provider's obligations under Requirement R10 should not require
transmission operators to update transmission models any more
frequently than required in sub-requirements R3.2 and R3.3.

c. MOD-030-2, Existing Transmission Commitments, Requirement R6
NOPR Proposal
    254. In the NOPR, the Commission proposed to approve MOD-030-2,
including Requirement R6, which sets variables to use in calculating
the impact of existing transmission commitments for firm commitments.
These variables include: The impact of all firm network integration
transmission service including native load and network service load,
the impact of all confirmed firm point-to-point transmission service
expected to be scheduled including roll-over rights, the impact of any
grandfathered firm obligation expected to be scheduled, the impact of
other firm services determined by the transmission service provider.
Requirement R7 requires the transmission service provider to consider
similar variables when calculating the impact of existing transmission
commitments for non-firm commitments.
Comments
    255. Cottonwood states that, during the stakeholder process, it
informed NERC that the existing transmission commitment calculation
procedures in Requirement R6 were insufficiently detailed, and
particularly failed to ensure that transmission service providers do
not overstate the capacity set aside for existing transmission
commitment purposes. Although NERC responded that the responsible
Reliability Standard drafting team has required the use of dispatch
modeling information to determine these impacts, Cottonwood states NERC
also clarified that the processes used to calculate existing
transmission commitments should be included in the available transfer
capability implementation documents. Cottonwood expresses concern that
the NERC standards drafting team did not adequately address its
concerns.
    256. Cottonwood contends that overstatement of existing
transmission commitments is a serious problem for transmission
customers because it understates the available transfer capability/
available flowgate capability identified in the models, even though the
system could actually carry additional service. Cottonwood further
contends that overstatement of existing transmission commitments also
can lead to the appearance of phantom congestion and base case
overloads in the models, which effectively means that the existing
transmission commitment impacts on certain flowgates is greater than
the flowgates' capacity, and, thus, these flowgates are overloaded in
the available transfer capability power flow models, and access to the
transmission system is reduced. To address these concerns, Cottonwood
asks the Commission to direct the ERO to modify MOD-030-2 to include
requirements that ensure that the generation dispatch model
incorporates the way generating units actually are dispatched in daily
operation, and any and all operating procedures used to maintain flows
within limits. Cottonwood further suggests that impacts from
neighboring systems should be taken into account and properly modeled.
    257. Entegra contends that NERC's proposal does not comply with the
Commission's directives in Order Nos. 693 and 890. Entegra states that
the proposed existing transmission commitments calculation is loose and
unclear and the proposed requirements do not prevent transmission
service providers from overstating the flowgate capacity set aside for
existing transmission purposes, which leads to base case contingency
overloads. Accordingly, Entegra asks the Commission to direct the ERO
to modify the Reliability Standard to require transmission providers to
use an accurate and realistic dispatch model and to benchmark existing
transmission commitment calculations against real-time flows to ensure
that these values are not being overstated. In addition, Entegra
contends that transmission service providers should be required to
identify and report to NERC, on a periodic basis, all base case
congestion overloads over five percent and chronic base case congestion
overloads for further investigation and action.
Commission Determination
    258. In Order No. 890, the Commission determined that existing
transmission commitments should be defined to include committed uses of
the transmission system, including: (1) Native load commitments
(including network service); (2) grandfathered transmission rights; (3)
appropriate point-to-point reservations; (4) rollover rights associated
with long-term firm service; and (5) other uses identified through the
NERC process.\119\ Further, the Commission decided that existing
transmission commitments should not be used to set aside transfer
capability for any type of planning or contingency reserve, which are
instead addressed through capacity benefit margin and transfer
reliability margin calculations.\120\ We find that, as written, the
ERO's definition of existing transmission capacity satisfies the
Commission's directions in Order No. 890.
---------------------------------------------------------------------------

    \119\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 244.
    \120\ Id.
---------------------------------------------------------------------------

    259. Under Requirements R6 and R7 of MOD-030-2, a transmission
provider must sum the impact of certain defined transmission
commitments as well as other firm and non-firm services determined by
the TSP. Relevant impact is undefined as are ``other'' firm and non-
firm services. Thus, there is potential for a transmission service
provider to overstate or understate existing transmission commitments.
However, this concern is mitigated by fact that, under MOD-001-1
Requirement R2, transmission service providers must recalculate
available transfer capability or available flowgate capability (which
include existing transmission commitments) for specific time periods.
Entities are also required to make their assumptions available. In
addition, in measures M13 and M14 of MOD-030-2, NERC states that a
recalculated existing transmission commitment value that is within 15
percent or 15 MW, whichever is greater, of the originally calculated
values, is evidence that the transmission service provider used the
requirements defined in R6 and R7. We therefore decline to direct the
modifications proposed.
d. MOD-030-2, Power Transfer and Outage Transfer Distribution Factors
NOPR Proposal
    260. Requirement R2 of MOD-030-2 provides that, in determining
which flowgates to use in the available flowgate capability process the
transmission operator must use, at a minimum, certain criteria as
enumerated in the sub-requirements. Requirement R2.1.1 requires
transmission operators to consider the results of a first contingency
transfer analysis from all adjacent balancing authority source and sink
combinations up to the path capability such that at a minimum the first
three limiting elements and their worst associated contingency
combinations with an outage transfer distribution factor of at least 5
percent and within the transmission operator's system are included in
the flowgates unless the interface between such adjacent balancing
authorities is accounted for using another available transfer
capability. Requirement R2.1.4 requires transmission operators to
consider any limiting element or contingency where the coordination of
the limiting

element/contingency combination is not addressed through a different
methodology, and, among other things, any generator within the
transmission service provider's area has at least a 5 percent power
distribution factor or outage transfer distribution factor impact on
the flowgate when delivered to the aggregate load of its own area.
Comments
    261. Entegra states that NERC's proposal gives transmission
operators the discretion to use arbitrarily small distribution factors,
without requiring any justification or explanation as to why the chosen
value is appropriate. Entegra also states that the use of lower
distribution factors may affect reliability insofar as it conflicts
with other Reliability Standards, e.g., the transmission loading relief
procedure, that uses a five percent distribution factor. Accordingly,
Entegra asks the Commission to direct the ERO to modify the Reliability
Standard to set a five percent default value for both the power
transfer and outage transfer distribution factors. Entegra states that
the revised Reliability Standard should require transmission operators
to justify their choice of distribution factors if less than five
percent. In addition, Entegra states that NERC should require
transmission operators using a lower value to develop appropriate
procedures to address any conflicts between the distribution factor
values chosen for available transfer capability purposes and those used
for other purposes, such as the transmission loading relief procedure.
Commission Determination
    262. In the NOPR, the Commission stated that it is appropriate for
transmission service providers to retain some level of discretion in
the calculation of available transfer capability or available flowgate
capability. Requiring absolute uniformity in criteria and assumptions
across all transmission service providers would preclude transmission
service providers from calculating available transfer capability or
available flowgate capability in a way that accommodates the operation
of their particular systems. Similarly, the Commission believes that it
is appropriate for transmission operators to retain some discretion.
Accordingly, the Commission will not direct the ERO to set a specific
default value for both the power transfer and outage transfer
distribution factors. Moreover, transmission service providers are
required to include in their available flowgate capability
implementation documents the criteria used by the transmission operator
to identify sets of transmission facilities as flowgates that are to be
considered in the available flowgate capability calculations. Thus, we
are satisfied by the transparency achieved in the Reliability Standard
as written.
e. MOD-030-2, Treatment of Adjacent Systems
NOPR Proposal
    263. In the NOPR, the Commission proposed to approve MOD-030-2
including sub-requirements R3.5, R5.2 and R5.3. Sub-requirement R3.5
requires transmission operators to make available to the transmission
service provider a transmission model to determine available flowgate
capability that meets and contains modeling data and system topology
(or equivalent representation) for immediately adjacent and beyond
reliability coordination areas. When calculation available flowgate
capabilities, sub-requirement R5.2 requires transmission service
providers to include in the transmission model expected generation and
transmission outages, additions, and retirements within the scope of
the model as specified in the implementation document and in effect
during the applicable period of the calculation for the transmission
service provider's area, all adjacent transmission service providers,
and any transmission service providers with which coordination
agreements have been executed. In addition, under sub-requirement R5.3,
transmission service providers must, for external flowgates, use the
available flowgate capability provided by the transmission service
provider that calculates available flowgate capability for that
flowgate.
Comments
    264. Entegra states that the proposed requirements for MOD-030-2,
specifically sub-requirements R3.5, R5.2, and R5.3, do not require a
transmission service provider to represent adjacent systems in a
realistic manner or to update its representations of adjacent systems
at the same frequency as the transmission service provider's models of
its own system. Entegra states that the requirements also do not have a
measure to assess the validity of a transmission service provider's
representation of adjacent systems. Accordingly, Entegra asks the
Commission to direct the ERO to modify MOD-030-2 to require
transmission service providers to exchange all model data (e.g., load,
generation profile, net interchange, transactions, outages, and
discrete transmission and generation elements) necessary to provide an
accurate representation of adjacent systems and that transmission
service providers update the model data with the same frequency that
the transmission service provider updates models of its own system.
Entegra also suggests that the revised Reliability Standard should
require transmission service providers to benchmark and update their
representations of adjacent systems on an on-going basis.
Commission Determination
    265. All modeling data used by a transmission service provider to
represent conditions of adjacent systems should reflect actual system
operations and the models developed should be based on sound
engineering principles. The Commission finds that the exchange of data
provided under these Reliability Standards should provide transmission
service providers with sufficient data to make realistic estimations of
available flowgate capability on adjacent systems. Under Requirement R9
of MOD-001-1, a transmission service provider must respond to requests
for data even when they are made more frequently than the transmission
service provider updates its available transfer or flowgate capability
models. Thus, transmission service providers should have access to the
most current data available for adjacent systems. In light of these
existing requirements, we deny Entegra's request to direct the ERO to
modify the standard to require transmission service providers to update
their representations of adjacent systems on an on-going basis.
    266. Pursuant to the modifications to MOD-001-1 directed above,
transmission service providers will be required to benchmark and update
their available transfer or flowgate capability calculations. This
benchmarked data should provide a sufficient basis to determine whether
transmission service providers are modeling adjacent systems in a
realistic manner. The Commission will address concerns of unrealistic
modeling of adjacent systems on a case-by-case basis if, for example,
the matter is raised in a complaint before the Commission. Thus, the
Commission declines to direct the modification proposed here.
f. MOD-030-2, Effective Date
Comment
    267. Entergy supports NERC's implementation plan with respect to
MOD-030-2, which would require compliance one calendar year after
approval of MOD-030-2 and its related three standards (MOD-001-1, MOD-

028-1, and MOD-029-1) by all appropriate regulatory authorities.
Because MOD-030-2 requires information from neighboring reliability
entities for use in the development of its available transfer
capability and available flowgate capability values and some of that
information may not be available until MOD-028-1 and MOD-29-1 become
effective, Entergy agrees with NERC that it is essential that all three
methodologies and MOD-001-1 become effective at the same time.
    268. Entergy also asks clarification regarding the stated effective
date. Entergy contends that defining the effective date of MOD-030-2
with reference to a detail in an earlier version of the Reliability
Standard that is proposed to be superseded creates a lack of clarity.
Accordingly, Entergy recommends that NERC revise MOD-030-2 to
incorporate the same effective date language used in MOD-001-1, MOD-
028-1, and MOD-029-1.
Commission Determination
    269. As noted above, the Commission approves the proposal to make
these Reliability Standards effective on the first day of the first
calendar quarter that is twelve months beyond the date that the
Reliability Standards are approved by all applicable regulatory
authorities. Although MOD-030-2 defines its effective date with
reference to the effective date of MOD-030-1, the Commission finds that
this direction is sufficiently clear in the context of the current
proceeding. To the extent necessary, we clarify MOD-030-2 shall become
effective on the first day of the first calendar quarter that is twelve
months beyond the date that the Reliability Standards are approved by
all applicable regulatory authorities. The Commission also directs the
ERO to make explicit such detail in any future version of this or any
other Reliability Standard.

C. Violation Risk Factors and Violation Severity Levels

NOPR Proposal
    270. The Commission proposed to accept NERC's commitment to file
violation severity levels and violation risk factors at a later time.
The Commission noted that the Violation Severity Level Order was issued
after NERC developed the violation severity level assignments for the
Reliability Standards at issue in this proceeding.\121\ The Commission
acknowledged that, as a result, NERC was unable to evaluate and modify
the proposed violation severity levels to comply with the Commission's
guidelines prior to filing the proposed Reliability Standards. The
Commission therefore proposed to direct the ERO to reevaluate the
violation severity levels associated with all of the proposed
Reliability Standards based on the Commission's guidelines outlined in
the Violation Severity Level Order and prepare appropriate revisions.
In addition, the Commission proposed to accept NERC's proposal to allow
NERC staff to review the violation risk factors through an open
stakeholder process to ensure that they are consistent with the intent
of the violation risk factor definition and guidance provided in the
Violation Risk Factor Order and the Violation Risk Factor Rehearing
Order.\122\ The Commission proposed to direct NERC to file revised
violation severity levels and violation risk factors no later than 120
days before the Reliability Standards become effective.
---------------------------------------------------------------------------

    \121\ NOPR, FERC Stats. & Regs. ] 32,641 at P 123, citing North
American Electric Reliability Corp., 123 FERC ] 61,284, at P 20-35
(2008) (Violation Severity Level Order).
    \122\ North American Electric Reliability Corp., 119 FERC ]
61,145, at P 9 (Violation Risk Factor Order), order on reh'g, 120
FERC ] 61,145 (2007).
---------------------------------------------------------------------------

Comments
    271. Puget Sound states that it supports the Commission's proposal
that NERC not file violation risk factors and violation severity levels
at this time. Puget Sound also states that it supports the Commission's
proposal to allow NERC staff time to review the violation risk factors
through an open stakeholder process to ensure that they are consistent
with Commission precedent. Puget Sound also contends that no
requirement of the proposed MOD Reliability Standards should be
assigned a violation risk factor exceeding ``Lower'' because the
potential violations of these standards would not directly affect the
electrical state or the capability of the Bulk-Power System, or the
ability to effectively monitor and control the Bulk-Power System.\123\
For the same reason, Puget Sound also contends that the MOD Reliability
Standards should not be assigned violation severity levels greater than
``Lower.''
---------------------------------------------------------------------------

    \123\ Citing Violation Risk Factor Order, 119 FERC ] 61,145 at P
9.
---------------------------------------------------------------------------

    272. The Joint Municipals also argue that the Commission should
direct NERC to assign low violation risk factors to the Reliability
Standards approved here. The Joint Municipals point out, as the
Commission did in the NOPR, that the NERC Reliability Standards
drafting team adjusted the violation risk factors to ``lower'' from
``medium,'' in view of what appears to be the consensus that the
available transfer capability-related Reliability Standards are not
critical to system reliability.
    273. By contrast, Midwest ISO contends that the original set of
violation risk factors assigned by the Reliability Standard drafting
team and submitted to industry vote are valid. Midwest ISO states that
the violation risk factors already have been through an open
stakeholder process in which the proposed Reliability Standards were
commented on and voted upon multiple times. Further, Midwest ISO
contends that continued delay in filing the violation risk factors
contravenes NERC's earlier commitment to file in a timely manner.
Commission Determination
    274. The Commission adopts the NOPR proposal and directs the ERO to
reevaluate the violation risk factors and violation severity levels
associated with all of the proposed MOD Reliability Standards based on
the Commission's precedent and to prepare appropriate revisions. The
Commission notes that in Order No. 722, the Commission encouraged the
ERO to develop a new and comprehensive approach that would better
facilitate the assignment of violation severity levels and violation
risk factors both prospectively and to approved Reliability
Standards.\124\ NERC responded by making an informational filing
proposing a new method for assigning violation risk factors and
violation severity levels. Although the Commission reserves judgment of
the merits of the ERO's proposals presented in the informational
filing, the Commission accepts the ERO's commitment to reevaluate the
violation risk factors and violation severity levels associated with
these MOD Reliability Standards through an open stakeholder process to
ensure that they are consistent with the intent of violation risk
factor definitions and Commission precedent. The Commission hereby
directs the ERO to file revised violation severity levels and violation
risk factors no later than 120 days before the Reliability Standards
become effective. In light of this reevaluation of the violation
severity levels and violation risk factors, we find the arguments
raised by Puget Sound and the Joint Municipals to be premature.
---------------------------------------------------------------------------

    \124\ Version Two Facilities Design, Connections and Maintenance
Reliability Standards, Order No. 722, 126 FERC ] 61,255, at P 45
(2009).

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

D. Disposition of Other Reliability Standards

1. MOD-010-1 through MOD-025-1
NOPR Proposal
    275. In the NOPR, the Commission proposed to allow NERC to address
revisions to MOD-010 through MOD-025 to incorporate a requirement for
periodic review and modification of models for (1) load flow base cases
with contingency, subsystem, and monitoring files, (2) short circuit
data, and (3) transient and dynamic stability simulation data, in order
to ensure that they are up to date. These Reliability Standards are
generally intended to establish consistent data requirements, reporting
procedures and system models for use in reliability analysis. As such,
the Commission proposed to find that NERC is correct that these
Reliability Standards were not a part of the available transfer
capability modifications required in Order Nos. 890 and 693.
Commission Determination
    276. The Commission hereby adopts its NOPR proposal and will allow
NERC to address revisions to MOD-010 through MOD-025 through a separate
project. In Order No. 693, the Commission identified nine Reliability
Standards as the core of the available transfer capability initiative
directed in Order No. 890.\125\ None of the Reliability Standards MOD-
010 through MOD-025 were identified as part of that initiative.
---------------------------------------------------------------------------

    \125\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 206.
---------------------------------------------------------------------------

2. Reliability Standards To Be Retired or Withdrawn
NOPR Proposal
    277. In the NOPR, the Commission proposed to approve NERC's request
to retire MOD-006-0 and MOD-007-0 and to withdraw its request for
approval of MOD-001-0, MOD-002-0, MOD-003-0, MOD-004-0, MOD-005-0, MOD-
008-0, and MOD-009-0. The Commission also proposed to find that MOD-
001-0, MOD-002-0, MOD-003-0, MOD-004-0, MOD-005-0, MOD-008-0, and MOD-
009-0 are all superseded by the available transfer capability
calculations required by the proposed MOD Reliability Standards in this
proceeding are, upon the effectiveness of the proposed MOD Reliability
Standards, no longer necessary.
    278. The Commission also proposed to not grant NERC's request to
withdraw FAC-012-1, nor approve the retirement of FAC-013-1.\126\ With
respect to these two Reliability Standards, the Commission disagreed
with NERC that they are wholly superseded by the MOD Reliability
Standards addressed in these proceeding. The Commission noted that,
under FAC-012-1, reliability coordinators and planning authorities
would be required to document the methodology used to establish inter-
regional and intra-regional transfer capabilities and to state whether
the methodology is applicable to the planning horizon or the operating
horizon. The Commission also noted that, under FAC-013-1, reliability
coordinators and planning authorities are required to establish a set
of inter-regional and intra-regional transfer capabilities that are
consistent with the methodology documented under FAC-012-1, which could
require the calculation of transfer capabilities for both the planning
horizon and the operating horizon. The Commission posited that these
FAC Reliability Standards were necessary because the proposed MOD
Reliability Standards provide only for the calculation of available
transfer capability and its components, including total transfer
capability, in the operating horizon.\127\ Thus, the Commission stated,
the proposed MOD Reliability Standards do not govern the calculation of
transfer capabilities in the planning horizon, i.e., beyond 13 months
in the future.
---------------------------------------------------------------------------

    \126\ NOPR, FERC Stats. & Regs. ] 32,641 at P 138.
    \127\ See MOD-001-1, Requirement R2.3.
---------------------------------------------------------------------------

    279. In Order No. 693, the Commission approved FAC-013-1, but
declined to approve or remand FAC-012-1. The Commission expressed
concern that FAC-012-1 merely required the documentation of a transfer
capability methodology without providing a framework for that
methodology including data inputs and modeling assumptions.\128\ The
Commission also expressed concern that the criteria used to calculate
transfer capabilities for use in determining available transfer
capability must be identical to those used in planning and operating
the system.\129\ The Commission directed the ERO to modify FAC-012-1 to
provide a framework for the transfer capability calculation methodology
that takes account of the need for consistency in the criteria used to
calculate transfer capabilities.\130\
---------------------------------------------------------------------------

    \128\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 777.
    \129\ Id. P 782.
    \130\ Id. P 779, 782.
---------------------------------------------------------------------------

Comments
    280. NERC does not object to the Commission proposal to retain FAC-
012-1 and FAC-013-1 but asks the Commission for additional time to make
the appropriate revisions. Instead of directing NERC to file the
proposed modifications within 120 days prior to the effective date of
the available transfer capability-related MOD Reliability Standards,
NERC proposes that the Commission instead require that these changes be
filed 60 days before the Reliability Standards become effective. NERC
states that this will provide it with additional time to develop these
changes in accordance with the Reliability Standards development
process, and minimize the probability that special exceptions to the
process be granted in order to meet the Commission's proposed deadline.
In addition, NERC states that this delay will help ensure that these
changes do not take undue precedence ahead of other issues currently
prioritizes and being addressed in the NERC standards development work
plan.
    281. EEI, Duke, First Energy, FPL and Puget Sound object to the
Commission's proposal to retain FAC-012-1 and FAC-013-1. EEI states
that although the NOPR defined the operating horizon to include the
next twelve months (i.e., months 2-13), Order No. 890 defined the
operating horizon as ``day-ahead and pre-schedule'' and the planning
horizon as ``beyond the operating horizon.''\131\ Thus, EEI argues that
the proposed MOD Reliability Standards provide for the calculation of
available transfer capability during part of the planning of horizon
even though they do not address the calculation of available transfer
capability beyond month 13.
---------------------------------------------------------------------------

    \131\ Citing Order No. 890, FERC Stats. & Regs. ] 31,241 at P
323 and Attachment C.
---------------------------------------------------------------------------

    282. EEI further contends that there is no reliability concern
created by retiring FAC-012-1 and FAC-013-1 just as there are no
reliability benefits obtained by complying with them. EEI contends that
this is particularly true in the Eastern Interconnection where the
Eastern Interconnection Reliability Assessment Group exists as a forum
for organizing reliability-related modeling and planning activities by
defining various studies and cases, as well as common assumptions, for
the long-term planning horizon. Thus, EEI contends, the Commission
should not view the retiring of FAC-012-1 and FAC-013-1 as creating a
vacuum; rather, the proposed MOD Reliability Standards have ``wholly
superseded'' them by replacing their only useful components.

In the alternative, if the Commission decides to retain FAC-012-1, EEI
suggests that the Commission direct NERC to consider moving the
substantive content of FAC-012-1 into a technical guidance document and
have the document appended to an approved FAC Reliability Standard.
    283. Duke states that it supports NERC's proposal to retire FAC-
013-1 when the MOD Reliability Standards become effective and to
withdraw its request for approval of FAC-012-1. Duke states that it
does not believe that available transfer capability calculations made
past a 13 month period are sufficient to support reliable long-term
transmission service and so supports EEI's comments related to
calculations made past month 13. Duke also contends that, in the
Eastern Interconnect region, regional assessments and planning are
occurring for transfer capabilities in the planning horizon (i.e.,
period of time after 13 months) in various forums such as Southeastern
Electric Reliability Council's long-term study group and the Eastern
Interconnection Reliability Assessment Group. Duke states that other
efforts exist in response to Order No. 890's regional planning
requirements such as the Southeast Inter-Regional Participation Process
and the North Carolina Transmission Planning Collaborative. Duke
contends that these and other regional planning efforts will
effectively ensure that levels of transfer capability are maintained to
meet regional and interconnection wide reliability requirements in the
planning horizon.
    284. If the Commission adopts FAC-012-1 and retains FAC-013-1, then
Duke requests that the Commission require FAC-012-1 to be revised to
focus on the development of a methodology for calculation inter-
regional and intra-regional transfer capabilities for use in assessing
the ability of the Bulk-Power System to support potentially large,
diverse regional transfers of power in a reliable manner, rather than
calculation of total transfer capabilities or available transfer
capabilities for evaluation of service requests. Duke contends that
there is no Commission requirement for the posting of total transfer
capabilities and/or available transfer capabilities beyond 13 months.
Further, if the Commission approves FAC-012-1, Duke requests that it be
made applicable to just the planning coordinator, and not the
reliability coordinator, since the Reliability Standard would focus on
the planning timeframe. Similarly, Duke recommends that the Commission
direct the ERO to modify FAC-013-1 to establish and communicate the
transfer capabilities developed using the methodology specified in FAC-
012-1.
    285. FirstEnergy agrees that the MOD-001-1 addresses the
scheduling, operating and planning horizons, as those terms were
described in Order No. 693.\132\ However, if the Commission chooses to
direct the ERO to retain FAC-012-1 and FAC-013-1, FirstEnergy asks the
Commission to limit the FAC standards to the use of transmission
capability for transmission planning and remove redundant provisions
for the calculation of transfer capability addressed elsewhere in the
MOD Reliability Standards, especially for other purposes such as the
calculation of available transfer capability. FirstEnergy states that
the FAC and the MOD Reliability Standards each address the calculation
of transfer capability in the operational time-period. To eliminate
this redundancy, FirstEnergy suggests that the Commission direct the
ERO to assign the treatment of operational transfer capability to the
MOD Reliability Standards and eliminate the reference to the use of
transfer capability in the operational horizon in the operational
standards. FirstEnergy further contends that the FAC Reliability
Standards are ambiguous since they require the calculation of a
parameter, transfer capability in the planning horizon, for which the
purpose is not described or specified. Nevertheless, FirstEnergy states
that it strongly supports the standard drafting team's conclusion that
the best method for addressing total transfer capability accurately and
clearly is within the MOD Reliability Standards.
---------------------------------------------------------------------------

    \132\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 1047.
---------------------------------------------------------------------------

    286. FPL contends that the elimination of FAC-012-1 and FAC-013-1
would not create a void. FPL states that the total transfer capability
and available transfer capability in the long-term planning horizon are
not tied to a specific path for posting purposes, but instead look at
the transmission network limits for which expansion projects would be
initiated to meet the long-term needs for firm transmission service.
Although the MOD Reliability Standards do not require the posting of
transfer capabilities beyond 13 months, FPL states that this is only a
minimum requirement that reflects the impractical nature of pre-
determined transfer capability calculations for the planning horizon
after the 13th month. FPL contends that the study of transmission
service requests beyond the 13th month of the planning horizon requires
specific knowledge and assumptions, and such requests could not be
granted based on pre-determined calculations alone. For these reasons
FPL agrees with NERC's recommendation to withdraw Reliability Standard
FAC-012-1 and retire FAC-013-1.
    287. Pacific Northwest contends that MOD-003-0 should not be
retired or withdrawn. Pacific Northwest states that MOD-030-2 requires
regional reliability organizations to develop and document procedures
that allow transmission service customers to inquire about calculations
of total transfer capability and available transfer capability,
timeframes for response and posting requirements applicable to the
regional reliability organization. Pacific Northwest contends that this
procedure fills gaps in the current NAESB business practice in that the
procedure facilitates the provision of information about available
transfer capability and total transfer capability calculations for
transmission paths with multiple owners but with one available transfer
capability rating and one seasonal operating transfer capability
rating.
Commission Determination
    288. The Commission hereby adopts the NOPR proposal and approves
NERC's request to retire MOD-006-0 and MOD-007-0 and to withdraw its
request for approval of MOD-001-0, MOD-002-0, MOD-003-0, MOD-004-0,
MOD-005-0, MOD-008-0, and MOD-009-0. The Commission also finds that
MOD-001-0, MOD-002-0, MOD-003-0, MOD-004-0, MOD-005-0, MOD-008-0, and
MOD-009-0 are all superseded by the available transfer capability
calculations required by the proposed MOD Reliability Standards in this
proceeding are, upon the effectiveness of the proposed MOD Reliability
Standards, no longer necessary.
    289. Consistent with its NOPR proposal, the Commission finds that
NERC has not addressed the requirements of Order No. 693 with regard to
the calculation of transfer capabilities in the planning horizon. In
Order No. 693 the Commission expressed concern that the criteria used
to calculate transfer capabilities for use in determining available
transfer capability must be identical to those used in planning and
operating the system.\133\ As EEI observes, in Order No. 890, the
Commission offered, as an example, a possible definition of the
operating horizon as the day-ahead and pre-scheduling periods and the

planning horizon as anything beyond the operating horizon.\134\
However, NERC has already defined the near-term planning horizon as
years one through five in sub-requirement R1.2 of TPL-005. The
Commission believes that this definition should be consistent
throughout the Reliability Standards.
---------------------------------------------------------------------------

    \133\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 782.
    \134\ Order No. 890, FERC Stats. & Regs. ] 31,241 at P 323.
---------------------------------------------------------------------------

    290. The Commission recognizes that the calculation of transfer
capabilities in the planning horizon (years one through five) may not
be so accurate to support long-term scheduling of the transmission
system but we do believe that such forecasts will be useful for long-
term planning, in general, by measuring sufficient long-term capacity
needed to ensure the reliable operation of the Bulk-Power System.
Although regional planning authorities have developed similar efforts
in response to Order No. 890, we believe that the requirements imposed
by FAC-012 and FAC-013 need not be duplicative of those existing
efforts and, by contrast, should be focused on improving the long-term
reliability of the Bulk-Power System pursuant to the ERO's Reliability
Standards. We believe that these responsibilities would be
appropriately assigned to the planning coordinator and not the
reliability coordinator.
    291. The Commission hereby adopts its NOPR proposal to deny NERC's
request to withdraw FAC-012-1 and retire FAC-013-1. Instead, pursuant
to section 215(d)(5) of the FPA and section 39.5(f) of our regulations,
the Commission directs the ERO to develop modifications to FAC-012-1
and FAC-013-1 to comply with the relevant directives of Order No. 693
\135\ and, as otherwise necessary, to make the requirements of those
Reliability Standards consistent with those of the MOD Reliability
Standards approved herein as well as this Final Rule. These
modifications should also remove redundant provisions for the
calculation of transfer capability addressed elsewhere in the MOD
Reliability Standards. In making these revisions, the ERO should
consider the development of a methodology for calculation of inter-
regional and intra-regional transfer capabilities. The Commission
accepts the ERO's request for additional time to prepare the
modifications and so directs the ERO to submit the modifications to
FAC-012-1 and FAC-013-1 no later than 60 days before the MOD
Reliability Standards become effective.
---------------------------------------------------------------------------

    \135\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 779, 782.
---------------------------------------------------------------------------

E. Applicability

Comments
    292. Supported by Austin, ERCOT requests that the Commission act to
ensure the proposed Reliability Standards are not applied to the ERCOT
region. ERCOT contends that the proposed Reliability Standards have no
value in the ERCOT region because ERCOT does not have a transmission
market and it manages congestion by employing a security constrained
economic dispatch. ERCOT further contends that the proposed MOD
Reliability Standards are actually counter-productive to the efficient
operation of the ERCOT grid and markets. ERCOT states that there are
two primary concerns associated with available transfer capability,
underutilization and oversubscription of the grid. ERCOT contends that
these concerns only apply in regions that have transmission markets,
and primarily physical markets, where the available transfer capability
calculation can actually be performed because there are transmission
obligations that can be netted against total transfer capability. ERCOT
further contends that neither concern arises in the ERCOT region
because there is no transmission market.
    293. Similarly, ERCOT contends that capacity benefit margin has no
relevance in ERCOT because there is no transmission market and all
energy schedules are respected inside ERCOT without the need for
transmission reservations. ERCOT further argues that requiring ERCOT to
set aside transmission capacity to meet the proposed capacity benefit
margin obligation would actually be counter-productive because it would
inhibit efficient dispatch of the system, thereby creating artificial
congestion to respect the reserved capacity benefit margin. ERCOT also
contends that transfer reliability margin is irrelevant in the ERCOT
region because ERCOT manages all operational issues through re-
dispatch. Furthermore, because available transfer capability is
undefined in the ERCOT region, ERCOT argues that the Reliability
Standards establishing the calculation methodologies are also
irrelevant with the region.
    294. NYISO asks the Commission to clarify that the MOD Reliability
Standards should be interpreted with a reasonable degree of flexibility
to accommodate the special characteristics of ISOs and RTOs. NYISO
contends that the MOD Reliability Standards were written to accommodate
physical reservation transmission systems and do not include provisions
that accommodate the special characteristics of NYISO's financial
reservation model. NYISO states that it has reached an informal
agreement with NERC through which NYISO believes it could comply with
the requirements of MOD-029-1 as written. NYISO also asks the
Commission to indicate that it will entertain a future NYISO request
for confirmation that it is in compliance with the NERC Reliability
Standards. NYISO further asks the Commission to clarify that it expects
NERC and the regional entities to accommodate financial transmission
rights based open access market designs when evaluating the compliance
of the NYISO, and to the extent relevant, other ISOs and RTOs, with the
proposed MOD Reliability Standards.
    295. Entergy requests clarification whether entities that use a
value of zero for transfer reliability margin and capacity benefit
margin are technically maintaining transfer reliability margin or
capacity benefit margin and, if not, whether MOD-004-1 and MOD-008-1
apply to those entities. Entergy contends that if the transfer
reliability margin and capacity benefit margin Reliability Standards do
apply to entities that maintain a value of zero, the Reliability
Standards should only require that the transmission reserve margin and
capacity benefit margin implementation documents state that no capacity
benefit margin or transfer reliability margin set-aside exists. In
addition, Entergy requests clarification whether MOD-008-1 applies to
entities that only use transfer reliability margin in system impact
studies when evaluating long-term firm transmission service requests
and whether such entities would be required to maintain a transfer
reliability margin implementation document.
Commission Determination
    296. In Order No. 693, the Commission found that a Reliability
Standard must provide for the Reliable Operation of the Bulk-Power
System facilities and may impose a requirement on any user, owner or
operator of such facilities.\136\ The Commission went on to say that a
Reliability Standard should be a single standard that applies across
the North American Bulk-Power System to the maximum extent this is
achievable taking into account physical differences in grid
characteristics and regional Reliability Standards that result

in more stringent practices.\137\ A Reliability Standard can also
account for regional variations in the organizational and corporate
structures of transmission owners and operators, variations in
generation fuel type and ownership patterns, and regional variations in
market design if these affect the proposed Reliability Standard. In
addition, a Reliability Standard should have no undue negative effect
on competition. Following these principles, the Commission finds that
the applicability of these Reliability Standards should take into
consideration regional differences such as those highlighted by
commenters.
---------------------------------------------------------------------------

    \136\ Order No. 693, FERC Stats. & Regs. ] 31,242 at P 5.
    \137\ Id. P 6.
---------------------------------------------------------------------------

    297. With respect to the enforcement of these Reliability
Standards, the Commission finds that their requirements are
sufficiently clear so that an entity should be aware of what it must do
to comply.\138\ The Commission believes that an entity is able to
comply with these Reliability Standards even if there are physical
differences in grid characteristics or variations in market design that
create challenges. To the extent that a transmission provider, an ISO
or RTO has a concern regarding the enforcement of these Reliability
Standards, the Commission believes that this is a compliance issue best
addressed on a case-by-case basis in the context of a compliance
proceeding. For this same reason, the Commission declines to offer its
opinion as to whether NYISO is in compliance with the Reliability
Standards. As the ERO for North America, NERC is uniquely qualified to
enforce its own Reliability Standards.
---------------------------------------------------------------------------

    \138\ See id. P 254.
---------------------------------------------------------------------------

    298. In response to Entergy's comment, the Commission notes that
MOD-008-1 is applicable only to transmission operators that maintain
transmission reliability margin. Although MOD-004-1 is not as explicit
with regard to its applicability, we believe that its applicability is
implicitly reserved to those entities that maintain capacity benefit
margin. Thus, it does not appear that Entergy, or any other entity,
would be in violation of MOD-004-1 or MOD-008-1 if it does not maintain
transmission reliability margin or capacity benefit margin. Similarly,
in response to ERCOT, we believe that it is appropriate to exempt
entities within ERCOT from complying with these Reliability Standards.
We agree that, due to physical differences of ERCOT's transmission
system, the MOD Reliability Standards approved herein would not provide
any reliability benefit within ERCOT.

F. Definitions

NOPR Proposal
    299. NERC proposed to modify its Glossary of Terms to add twenty
definitions that are used in the five proposed Reliability Standards,
including the following definitions of ``ATC Path'', ``Business
Practices'', and ``Postback'':

    ATC Path: Any combination of Point of Receipt (POR) and Point of
Delivery (POD) for which Available Transfer Capability (ATC) is
calculated; and any Posted Path.\139\
---------------------------------------------------------------------------

    \139\ See 18 CFR 37.6(b)(1).
---------------------------------------------------------------------------

    Business Practices: Those business rules contained in the
Transmission Service Provider's applicable tariff, rules, or
procedures; associated Regional Reliability Organization or Regional
Entity business practices; or North American Energy Standards Board
(NAESB) Business Practices.
    Postback: Positive adjustments to Available Transfer Capability
(ATC) or Available Flowgate Capability (AFC) as defined in Business
Practices. Such Business Practices may include processing of
redirects and unscheduled service.

    300. In the NOPR, the Commission proposed to approve the addition
of these terms to the NERC Glossary. The Commission also proposed to
direct NERC to modify the definition of Postback to eliminate its
reference to Business Practices, another defined term. The Commission
observed that the definition of Business Practices includes a reference
to the ``regional reliability organization.'' The Commission stated
that, in Order No. 693, the Commission directed NERC to eliminate
references to regional reliability organizations as responsible
entities in the Reliability Standards because such entities are not
users, owners or operators of the Bulk-Power System. Accordingly the
Commission proposed to direct NERC to remove from the proposed
definition of Business Practices, the reference to regional reliability
organizations and replace it with the term Regional Entity. The
Commission noted, however, that Regional Entity is not currently
defined in the NERC Glossary. The Commission therefore proposed to
direct NERC to develop a definition of Regional Entity consistent with
section 215(a) of the FPA \140\ and 18 CFR 39.1 (2008), to be included
in the NERC Glossary.
---------------------------------------------------------------------------

    \140\ 16 U.S.C. 824o.
---------------------------------------------------------------------------

Comments
    301. Puget Sound states that it agrees with the Commission that the
term ``Postback'' is not fully determinative and requests that the
Commission reject the definition as redundant and unnecessary. Puget
Sound states that for a particular point of receipt/point of delivery
combination, the existing transmission capacity component includes
confirmed reservations utilized on that particular point of receipt/
point of delivery combination. Puget Sound states that processing firm
redirects or annulments to the confirmed reservation reduces the
existing commitment component, which in turn increases the resultant
available transfer capability, achieving the same result as the desired
effect of the Postback term. Puget Sound further contends that
requiring a Postback component assumes that once a reservation is
confirmed on a particular point of reservation/point of receipt
combination the impact of the confirmed reservation will always be
present in the available transfer capability calculation, regardless of
future redirects, annulments, or recalls that are processed. Puget
Sound contends that accepting the Postback definition would add an
unnecessary component to the available transfer capability formula,
increasing the recordkeeping and documentation burden for applicable
entities.
    302. SMUD and Salt River ask the Commission to clarify that the
proposed definition of ``ATC Path'' does not limit a transmission
provider's flexibility to treat multiple parallel interconnections
between balancing authorities as a single path. NERC proposes to define
``ATC Path'' as: ``Any combination of Point of Receipt and Point of
Delivery for which [available transfer capability] is calculated; and
any Posted Path.'' SMUD and Salt River note that this definition
references the definition of ``Posted Path'' in the Commission's
regulations, 18 CFR Sec.  37.6(b)(1), which defines ``Posted Path'' as
any control area to control area interconnection and any path for which
a customer requests to have available transfer capability and total
transfer capability posted. They contend that one possible way to
interpret ``control area to control area interconnection'' would be to
treat each physical interconnection between Balancing Authorities as
creating a separate available transfer capability path. They argue that
the Commission should clarify the definition so as to recognize that
available transfer capability paths may or should be comprised of
multiple, parallel interconnections between Balancing Authorities as
reliability interests determine.
    303. SMUD and Salt River also ask the Commission to direct the ERO
to modify the definition of ``ATC Path'' to remove reference to the
Commission's regulations. They argue that the reference is
inappropriate as applied to

them because SMUD and Salt River are not subject to the Commission's
regulations. They also contend that confusion could arise if the
Commission revises its definition of Posted Path and thereby
effectively modifies the Reliability Standards.
Commission Determination
    304. The Commission believes that the definition of Postback is not
fully determinative. NERC should be able to define this term without
reference to the Business Practices, another defined term. Accordingly,
the Commission adopts its NOPR proposal and directs the ERO to develop
a modification to the definition of Postback to eliminate the reference
to Business Practices. Although we are sensitive to Puget Sound's
concern that the required Postback component may increase the
recordkeeping burden on some entities, in other regions the component
may be critical. We disagree that the term's existence assumes that
once a reservation is confirmed on a particular point of reservation/
point of receipt combination the impact of the confirmed reservation
will always be present in the available transfer capability
calculation. However, we would consider suggestions that would allow
entities to comply with the requirements as efficiently as possible,
such as a regional difference through the ERO's standards development
procedure.
    305. The Commission also adopts its NOPR proposal to direct the ERO
to develop a modification to the definition of Business Practices that
would remove the reference to regional reliability organizations and
replace it with the term Regional Entity. We also direct the ERO to
develop a definition of the term Regional Entity to be included in the
NERC Glossary.
    306. We agree with SMUD and Salt River that the definition of ``ATC
Path'' should not limit a transmission provider's flexibility to treat
multiple parallel interconnections between balancing authorities as a
single path, and that available transfer capability paths may comprise
multiple, parallel interconnections between Balancing Authorities when
such treatment is appropriate to maintain reliability. We also agree
that the definition should not reference the Commission's regulations.
The Commission's regulations are not applicable to all registered
entities and are subject to change. We therefore direct the ERO to
develop a modification to the definition of ``ATC Path'' that does not
reference the Commission's regulations.

IV. Information Collection Statement

    307. The following collections of information contained in this
final rule have been submitted to the Office of Management and Budget
(OMB) for review under section 3507(d) of the Paperwork Reduction Act
of 1995.\141\ OMB's regulations require OMB to approve certain
information collection requirements imposed by agency rule.\142\
---------------------------------------------------------------------------

    \141\ 44 U.S.C. 3507(d).
    \142\ 5 CFR 1320.11.
---------------------------------------------------------------------------

    308. The Commission solicited comments on the need for and the
purpose of the information contained in these Mandatory Reliability
Standards and the corresponding burden to implement them. The
Commission did receive comments on specific requirements in the
Reliability Standards and how their impact would be burdensome. We have
addressed those concerns elsewhere in this Final Rule. However, we did
not receive comments on our reporting burden estimates. The Commission
has updated the burden requirements to be consistent with our
directions in this Final Rule.
    Burden Estimate: The public reporting and records retention burdens
for the proposed reporting requirements and the records retention
requirement are as follows.\143\
---------------------------------------------------------------------------

    \143\ These burden estimates apply only to this Final Rule and
do not reflect upon all of FERC-516 or FERC-717.

----------------------------------------------------------------------------------------------------------------
                                                     Number of       Number of       Hours per     Total annual
                 Data collection                    respondents      responses       response          hours
----------------------------------------------------------------------------------------------------------------
Mandatory data exchanges........................             137               1              80          10,960
Explanation of change of ATC values.............             137               1             100          13,700
Recordkeeping...................................             137               1              30           3,480
----------------------------------------------------------------------------------------------------------------

    Total Annual Hours for Collection:

Reporting + recordkeeping hours = 3,480 + 24,660 = 28,140 hours.

    Cost to Comply:
Reporting = $2,811,240
    24,660 hours @ $114 an hour (average cost of attorney ($200 per
hour), consultant ($150), technical ($80), and administrative support
($25))

Recordkeeping = $185,875 (same as below)
    Labor (file/record clerk @ $17 an hour) 3,480 hours @ $17/hour =
$59,150
    Storage 137 respondents @ 8,000 sq. ft. x $925 (off site storage) =
$126,725

Total costs = $2,997,115
    Labor $ ($2,811,240 + $59,150) + Recordkeeping Storage Costs
($126,725)

    309. OMB's regulations require it to approve certain information
collection requirements imposed by an agency rule. The Commission is
submitting notification of this Final Rule to OMB. If the proposed
requirements are adopted they will be mandatory requirements.
    Title: Mandatory Reliability Standards for the Calculation of
Available Transfer Capability, Capacity Benefit Margins, Transmission
Reliability Margins, Total Transfer Capability, and Existing
Transmission Commitments and Mandatory Reliability Standards for the
Bulk-Power System.
    Action: Final Rule.
    OMB Control No.: 1902-0244.
    Respondents: Business or other for profit.
    Frequency of responses: On occasion.
    Necessity of the Information:
    310. Internal Review: The Commission has reviewed the approved
reliability standards and made a determination that these requirements
are necessary to implement section 215 of the Energy Policy Act of
2005. These requirements conform to the Commission's plan for efficient
information collection, communication and management within the energy
industry. The Commission has to assure itself, by means of internal
review, that there is specific, objective support for the burden
estimates associated with the information requirements.
    311. Interested persons may obtain information on the reporting
requirements by contacting the following: Federal Energy Regulatory
Commission, 888 First Street, NE., Washington, DC 20426 [Attention:
Michael Miller, Office of the Executive

Director, Phone:<PHONE_NUMBER>, fax:<PHONE_NUMBER>, e-mail:
<EMAIL_ADDRESS>    312. For submitting comments concerning the collection(s) of
information and the associated burden estimate(s), please send your
comments to the contact listed above and to the Office of Information
and Regulatory Affairs, Office of Information and Regulatory Affairs,
Washington, DC 20503 [Attention: Desk Officer for the Federal Energy
Regulatory Commission, phone<PHONE_NUMBER>, fax:<PHONE_NUMBER>, e-
mail<EMAIL_ADDRESS>
V. Environmental Analysis

    313. The Commission is required to prepare an Environmental
Assessment or an Environmental Impact Statement for any action that may
have a significant adverse effect on the human environment.\144\ The
actions proposed here fall within the categorical exclusion in the
Commission's regulations for rules that are clarifying, corrective or
procedural, for information gathering, analysis, and
dissemination.\145\
---------------------------------------------------------------------------

    \144\ Regulations Implementing the National Environmental Policy
Act of 1969, Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats.
& Regs. ] 30,783 (1987).
    \145\ 18 CFR 380.4(a)(5).
---------------------------------------------------------------------------

VI. Regulatory Flexibility Act

    314. The Regulatory Flexibility Act of 1980 (RFA) \146\ generally
requires a description and analysis of final rules that will have
significant economic impact on a substantial number of small entities.
The MOD Reliability Standards apply to transmission service providers
and transmission operators. Transmission service providers and
transmission operators are entities responsible for the reliability of
a transmission system. They operate or direct the operations of the
transmission facilities or control facilities used for the transmission
of electric energy in interstate commerce. Accordingly, these entities
do not fall typically within the definition of a small entity.\147\
---------------------------------------------------------------------------

    \146\ 5 U.S.C. 601-612.
    \147\ The definition of ``small entity'' under the Regulatory
Flexibility Act refers to the definition provided in the Small
Business Act, which defines a ``small business concern'' as a
business that is independently owned and operated and that is not
dominant in its field of operation. See 15 U.S.C. 632 (2000).
---------------------------------------------------------------------------

    315. Section 215(d)(2) of the FPA provides that the Commission may
approve, by rule or order, a proposed Reliability Standard or
modification to a proposed Reliability Standard if it meets the
statutory standard for approval, giving due weight to the technical
expertise of the ERO. Alternatively, the Commission may remand a
Reliability Standard pursuant to section 215(d)(4) of the FPA. Further,
the Commission may order the ERO to submit to the Commission a proposed
Reliability Standard or a modification to a Reliability Standard that
addresses a specific matter if the Commission considers such a new or
modified Reliability Standard appropriate to ``carry out'' section 215
of the FPA. The Commission's action in this final rule is based on its
authority pursuant to section 215 of the FPA.
    316. As indicated above, approximately 137 entities will be
responsible for compliance with the three new Reliability Standards. Of
these only six, or less than five percent, have output of four million
MWh or less per year.\148\ The Commission does not consider this a
substantial number. Based on this understanding, the Commission
certifies that this Final Rule will not have a significant economic
impact on a substantial number of small entities. Accordingly, no
regulatory flexibility analysis is required.
---------------------------------------------------------------------------

    \148\ Id.
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VII. Document Availability

    317. In addition to publishing the full text of this document in
the Federal Register, the Commission provides all interested persons an
opportunity to view and/or print the contents of this document via the
Internet through FERC's Home Page (http://www.ferc.gov) and in FERC's
Public Reference Room during normal business hours (8:30 a.m. to 5 p.m.
Eastern time) at 888 First Street, NE., Room 2A, Washington, DC 20426.
    318. From FERC's Home Page on the Internet, this information is
available on eLibrary. The full text of this document is available on
eLibrary in PDF and Microsoft Word format for viewing, printing, and/or
downloading. To access this document in eLibrary, type the docket
number excluding the last three digits of this document in the docket
number field.
    319. User assistance is available for eLibrary and the FERC's Web
site during normal business hours from FERC Online Support at 202-502-
6652 (toll free at 1-866-208-3676) or e-mail at
<EMAIL_ADDRESS>or the Public Reference Room at (202) 502-
8371, TTY<PHONE_NUMBER>. E-mail the Public Reference Room at
<EMAIL_ADDRESS>
VIII. Effective Date and Congressional Notification

    320. These regulations are effective February 8, 2010. The
Commission notes that although the determinations made in this Final
Rule are effective February 8, 2010, the MOD Reliability Standards
approved herein will not become effective until the first day of the
first quarter no sooner than one calendar year after approval by all
appropriate regulatory authorities where approval is required. The
Commission has determined, with the concurrence of the Administrator of
the Office of Information and Regulatory Affairs of OMB, that this Rule
is not a ``major rule'' as defined in section 351 of the Small Business
Regulatory Enforcement Fairness Act of 1996.

    By the Commission.
Nathaniel J. Davis, Sr.,
Deputy Secretary.

Appendix A: Commenting Party Acronyms

------------------------------------------------------------------------
                   Abbreviation                        Commenter name
------------------------------------------------------------------------
APPA..............................................  American Public
                                                     Power Association.
Austin............................................  Austin, City of.
Avista............................................  Avista Corporation.
Bonneville........................................  Bonneville Power
                                                     Administration.
ColumbiaGrid......................................  ColumbiaGrid.
Cottonwood........................................  Cottonwood Energy
                                                     Company.
Duke..............................................  Duke Energy
                                                     Carolinas, LLC.
EEI...............................................  Edison Electric
                                                     Institute.
EPSA..............................................  Electric Power
                                                     Supply Corporation.
ERCOT.............................................  Electric Reliability
                                                     Council of Texas,
                                                     Inc.
Entegra...........................................  Entegra Power Group
                                                     LLC.

Entergy...........................................  Entergy Services
                                                     Inc.
FirstEnergy.......................................  FirstEnergy Service
                                                     Company.
FPL...............................................  Florida Power &
                                                     Light Company.
Georgia...........................................  Georgia Transmission
                                                     Corporation.
ISO/RTO Council...................................  ISO/RTO Council.
ITC Companies.....................................  International
                                                     Transmission
                                                     Company, Michigan
                                                     Electric
                                                     Transmission
                                                     Company, LLC, and
                                                     ITC Midwest LLC.
LADWP.............................................  Los Angeles Dept. of
                                                     Water and Power.
MISO..............................................  Midwest ISO.
Modesto...........................................  Modesto Irrigation
                                                     District.
Nevada Companies..................................  Nevada Power Company
                                                     and Sierra Pacific
                                                     Power
                                                    Company.
NYISO.............................................  New York ISO.
NERC..............................................  North American
                                                     Electric
                                                     Reliability Corp.
Northwest Utilities...............................  Northwest
                                                     Requirements
                                                     Utilities.
Northwestern......................................  Northwestern
                                                     Corporation.
Pacific Northwest.................................  Pacific Northwest
                                                     Generating
                                                     Cooperative.
PacifiCorp........................................  PacifiCorp.
Public Power Council..............................  Public Power
                                                     Council.
Snohomish.........................................  Public Utility
                                                     District No. 1 of
                                                     Snohomish County.
Puget Sound.......................................  Puget Sound Energy,
                                                     Inc.
SMUD..............................................  Sacramento Municipal
                                                     Utility District.
Salt River........................................  Salt River Project.
Joint Municipals..................................  South Carolina
                                                     Public Service
                                                     Authority,
                                                     Sacramento
                                                     Municipal Utility
                                                     District and MEAG
                                                     Power.
SWAT..............................................  Southwest Area
                                                     Transmission Sub-
                                                     Regional Planning
                                                     Group.
TAPS..............................................  Transmission Access
                                                     Policy Study Group.
TANC..............................................  Transmission Agency
                                                     of Northern
                                                     California.
Tucson............................................  Tucson Electric
                                                     Power Company.
------------------------------------------------------------------------

[FR Doc. E9-28620 Filed 12-7-09; 8:45 am]


[Federal Register Volume 83, Number 200 (Tuesday, October 16, 2018)]
[Notices]
[Page 52272]
[FR Doc No: 2018-22433]

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SECURITIES AND EXCHANGE COMMISSION

[Release No. 34-84397; File No. SR-PEARL-2018-16]

Self-Regulatory Organizations; MIAX PEARL, LLC; Notice of
Withdrawal of a Proposed Rule Change To Amend the Fee Schedule
Regarding Connectivity Fees for Members and Non-Members

October 10, 2018.
    On July 31, 2018, MIAX PEARL, LLC (``MIAX PEARL'' or the
``Exchange'') filed with the Securities and Exchange Commission
(``Commission''), pursuant to Section 19(b)(1) of the Securities
Exchange Act of 1934 (``Act''),\1\ and Rule 19b-4 thereunder,\2\ a
proposed rule change to amend the MIAX PEARL Fee Schedule to increase
certain connectivity fees. The proposed rule change was immediately
effective upon filing with the Commission pursuant to Section
19(b)(3)(A) of the Act.\3\ The proposed rule change was published for
comment in the Federal Register on August 13, 2018.\4\ The Commission
received one comment letter on the proposal.\5\ On September 17, 2018,
pursuant to Section 19(b)(3)(C) of the Act, the Commission: (1)
Temporarily suspended the proposed rule change; and (2) instituted
proceedings to determine whether to approve or disapprove the
proposal.\6\ On October 5, 2018, the Exchange withdrew the proposed
rule change (SR-PEARL-2018-16).
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    \1\ 15 U.S.C. 78s(b)(1).
    \2\ 17 CFR 240.19b-4.
    \3\ 15 U.S.C. 78s(b)(3)(A).
    \4\ See Securities Exchange Act Release No. 83785 (August 7,
2018), 83 FR 40101.
    \5\ See Letter from Tyler Gellasch, Executive Director, The
Healthy Markets Association, to Brent J. Fields, Secretary,
Commission, dated September 4, 2018.
    \6\ See Securities Exchange Act Release No. 84177, 83 FR 47953
(September 21, 2018).

    For the Commission, by the Division of Trading and Markets,
pursuant to delegated authority.\7\
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    \7\ 17 CFR 200.30-3(a)(12).
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Eduardo A. Aleman,
Assistant Secretary.
[FR Doc. 2018-22433 Filed 10-15-18; 8:45 am]
 BILLING CODE 8011-01-P